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HomeMy WebLinkAbout20150601Kinney Exhibit 4.pdfDAVID J. MEYER VICE PRESIDENT AND CHIEF COUNSEL FOR REGULATORY & GOVERNMENTAL AFFAIRS AVISTA CORPORATION P.O. BOX 3727 1411 EAST MISSION AVENUE SPOKANE, WASHINGTON 99220-3727 TELEPHONE: (509) 495-4316 FACSIMILE: (509) 495-8851 DAVID.MEYER@AVISTACORP.COM BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION IN THE MATTER OF THE APPLICATION ) CASE NO. AVU-E-15-05 OF AVISTA CORPORATION FOR THE ) AUTHORITY TO INCREASE ITS RATES ) AND CHARGES FOR ELECTRIC AND ) NATURAL GAS SERVICE TO ELECTRIC ) EXHIBIT NO. 4 AND NATURAL GAS CUSTOMERS IN THE ) STATE OF IDAHO ) SCOTT J. KINNEY ) FOR AVISTA CORPORATION (ELECTRIC ONLY) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1 of 1125 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 2 of 1125 Safe Harbor Statement This document contains forward-looking statements. Such statements are subject to a variety of risks, uncertainties and other factors, most of which are beyond the Company’s control, and many of which could have a significant impact on the Company’s operations, results of operations and financial condition, and could cause actual results to differ materially from those anticipated. For a further discussion of these factors and other important factors, please refer to the Company’s reports filed with the Securities and Exchange Commission. The forward-looking statements contained in this document speak only as of the date hereof. The Company undertakes no obligation to update any forward- looking statement or statements to reflect events or circumstances that occur after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of such factors, nor can it assess the impact of each such factor on the Company’s business or the extent to which any such factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 3 of 1125 Acronym List AC: Alternating Current aMW: Average Megawatt AFUDC: Allowance for Funds Used During Construction ARIMA: Auto Regressive Integrated Moving Average BART: Best Available Retrofit Technology BPA: Bonneville Power Administration Btu: British Thermal Unit CAA: Clean Air Act CDD: Cooling Degree Days CFL: Compact Fluorescent Light CPA: Conservation Potential Assessment CO2: Carbon Dioxide COB: California Oregon Boarder CT: Combustion Turbine CCCT: Combined-Cycle Combustion Turbine CPU: Central Processing Unit DC: Direct Current DLC: Direct Load Control EIA: Energy Independence Act EPA: Environmental Protection Agency FERC: Federal Energy Regulatory Commission FIPs: Federal Implementation Plans GDP: Gross Domestic Product HAPs: Hazardous Air Pollutants Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 4 of 1125 HDD: Heating Degree Days HRSG: Heat Recovery Steam Generator HVAC: Heating, Ventilation, and Air Conditioning IGCC: Integrated Gasification Combined-Cycle IMHR: Implied Market Heat Rate IPPs: Independent Power Producers IPUC: Idaho Public Utilities Commission IRP: Integrated Resource Plan ITC: Investment Tax Credit kV: Kilovolt LGIR: Large Generator Interconnection Request LNG: Liquid Natural Gas LOLE: Loss of Load Expectation LOLH: Loss of Load Hours LOLP: Loss of Load Probability LRC: Least Resource Cost MATS: Mercury Air Toxic Standards MSA: Metropolitan Statistical Area MW: Megawatt MWh: Megawatt Hours NEEA: Northwest Energy Efficiency Alliance NERC: North American Reliability Corporation NOx: Nitrous Oxides NPCC: Northwest Power and Conservation Council NREL: National Renewable Energy Laboratory NTTG: Northern Tier Transmission Group Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 5 of 1125 NWPP: Northwest Power Pool O&M: Operations and Maintenance OATT: Open Access Transmission Tariff OTC: Once Through Cooling PNCA: Pacific Northwest Coordination Agreement PRiSM: Preferred Resource Strategy Linear Programming Model PRS: Preferred Resource Strategy PSD: Prevention of Significant Deterioration PM: Planning Margin PTC: Production Tax Credit PUDs: Public Utility Districts RPS: Renewable Portfolio Standard SCCT: Simple Cycle Combustion Turbine SGDP: Smart Grid Demonstration Project TAC: Technical Advisory Committee TPC: Transmission Planning Committee TRC: Total Resource Cost UPC: Use-per-customer UTC: Washington Utilities and Transportation Commission WAC: Washington Administrative Code WCI: Western Climate Initiative WECC: Western Electricity Coordinating Council WNP-3: Washington Nuclear Plant No. 3 WNU: Weather Normalized Usage WSU: Washington State University Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 6 of 1125 Table of Contents Avista Corp 2013 Electric IRP i Table of Contents Executive Summary ....................................................................................................................... i Resource Needs ............................................................................................................................ i Modeling and Results .................................................................................................................. iii Electricity and Natural Gas Market Forecasts ............................................................................. iii Energy Efficiency Acquisition ...................................................................................................... iv Preferred Resource Strategy ....................................................................................................... v Greenhouse Gas Emissions ..................................................................................................... viii Action Items .................................................................................................................................. x 1. Introduction and Stakeholder Involvement ................................................................ 1-1 IRP Process ............................................................................................................................. 1-1 2013 IRP Outline ...................................................................................................................... 1-4 Regulatory Requirements ........................................................................................................ 1-5 2. Loads & Resources ....................................................................................................... 2-1 Introduction & Highlights .......................................................................................................... 2-1 Economic Characteristics of Avista’s Service Territory ............................................................ 2-1 Customer and Load Forecast Assumptions ............................................................................. 2-5 Native Load Forecast ............................................................................................................. 2-15 Peak Demand Forecast.......................................................................................................... 2-16 High and Low Load Growth Cases ........................................................................................ 2-18 Voluntary Renewable Energy Program (Buck-A-Block) ......................................................... 2-19 Customer-Owned Generation ................................................................................................ 2-20 Avista Resources and Contracts ............................................................................................ 2-22 Spokane River Hydroelectric Developments ......................................................................... 2-23 Clark Fork River Hydroelectric Developments ....................................................................... 2-24 Total Hydroelectric Generation .............................................................................................. 2-24 Thermal Resources ................................................................................................................ 2-25 Power Purchase and Sale Contracts ..................................................................................... 2-27 Reserve Margins .................................................................................................................... 2-30 Avista’s Loss of Load Analysis ............................................................................................... 2-32 Balancing Loads and Resources ........................................................................................... 2-34 Washington State Renewable Portfolio Standard .................................................................. 2-36 Resource Requirements ........................................................................................................ 2-37 3. Energy Efficiency .......................................................................................................... 3-1 Introduction ............................................................................................................................... 3-1 Conservation Potential Assessment Approach ........................................................................ 3-2 Overview of Energy Efficiency Potentials................................................................................. 3-5 Conservation Targets ............................................................................................................... 3-8 Comparison with the Sixth Power Plan Methodology .............................................................. 3-9 Avoided Cost Sensitivities ...................................................................................................... 3-10 Energy Efficiency-Related Financial Impacts ......................................................................... 3-12 Integrating Results into Business Planning and Operations .................................................. 3-13 Demand Response ................................................................................................................. 3-16 4. Policy Considerations ................................................................................................... 4-1 Environmental Issues ............................................................................................................... 4-1 Avista’s Climate Change Policy Efforts .................................................................................... 4-3 State and Federal Environmental Policy Considerations ......................................................... 4-4 EPA Regulations ...................................................................................................................... 4-5 5. Transmission & Distribution ........................................................................................ 5-1 Introduction ............................................................................................................................... 5-1 FERC Planning Requirements and Processes ........................................................................ 5-2 Regional Transmission System ................................................................................................ 5-4 Avista’s Transmission System ................................................................................................. 5-4 Transmission System Information for the 2013 IRP ................................................................ 5-5 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 7 of 1125 Table of Contents Avista Corp 2013 Electric IRP ii Distribution System Efficiencies ............................................................................................... 5-8 6. Generation Resource Options...................................................................................... 6-1 Introduction ............................................................................................................................... 6-1 Assumptions ............................................................................................................................. 6-1 Gas-Fired Combined Cycle Combustion Turbine .................................................................... 6-3 Hydroelectric Project Upgrades and Options ......................................................................... 6-15 Thermal Resource Upgrade Options ..................................................................................... 6-18 7. Market Analysis ............................................................................................................. 7-1 Introduction ............................................................................................................................... 7-1 Marketplace .............................................................................................................................. 7-2 Fuel Prices and Conditions ...................................................................................................... 7-7 Greenhouse Gas Emissions .................................................................................................. 7-12 Risk Analysis .......................................................................................................................... 7-12 Market Price Forecast ............................................................................................................ 7-19 Scenario Analysis ................................................................................................................... 7-24 High and Low Natural Gas Price Scenarios ........................................................................... 7-28 8. Preferred Resource Strategy ........................................................................................ 8-1 Introduction ............................................................................................................................... 8-1 Supply-Side Resource Acquisitions ......................................................................................... 8-1 Resource Deficiencies.............................................................................................................. 8-5 Preferred Resource Strategy ................................................................................................... 8-8 Efficient Frontier Analysis ....................................................................................................... 8-16 Determining the Avoided Costs of Energy Efficiency ............................................................. 8-19 Determining the Avoided Cost of New Generation Options ................................................... 8-20 Efficient Frontier Comparison of Greenhouse Gas Policies ................................................... 8-21 Energy Efficiency Scenarios .................................................................................................. 8-23 Colstrip ................................................................................................................................... 8-26 Other Portfolio Scenarios ....................................................................................................... 8-31 9. Action Items ................................................................................................................... 9-1 Summary of the 2011 IRP Action Plan..................................................................................... 9-1 2013 IRP Action Plan ............................................................................................................... 9-5 Production Credits .................................................................................................................... 9-7 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 8 of 1125 Table of Contents Avista Corp 2013 Electric IRP iii Table of Figures Figure 1: Load-Resource Balance—Winter 18 Hour Capacity .......................................................... i Figure 2: Load-Resource Balance—Summer 18 Hour Capacity ..................................................... ii Figure 3: Load-Resource Balance—Energy ..................................................................................... ii Figure 4: Average Mid-Columbia Electricity Price Forecast ............................................................ iii Figure 5: Stanfield Natural Gas Price Forecast ............................................................................... iv Figure 6: Cumulative Energy Efficiency Acquisitions ....................................................................... v Figure 7: Efficient Frontier ............................................................................................................... vi Figure 8: Avista’s Qualifying Renewables for Washington State’s EIA ......................................... viii Figure 8: Avista Owned and Controlled Resource’s Greenhouse Gas Emissions ......................... ix Figure 9: U.S. Western Interconnect Greenhouse Gas Emissions ................................................. ix Figure 2.1: Avista’s Service Territory............................................................................................ 2-2 Figure 2.2: Population Levels 1970 – 2011 .................................................................................. 2-2 Figure 2.3: Population Growth and U.S. Recessions, 1971-2011 ................................................ 2-3 Figure 2.4: Employment Breakdown by Major Sector, 2011 ........................................................ 2-4 Figure 2.5: Post Recession Employment Growth, June 2009-December 2012 ........................... 2-4 Figure 2.6: Personal Income Breakdown by Major Source, 2011 ................................................ 2-5 Figure 2.7: Population Forecast, 2013-2035 ................................................................................ 2-7 Figure 2.8: House Start History and Forecast (2000-2035) ......................................................... 2-8 Figure 2.9: Annual Growth in Use per Customer 2006 - 2012 ................................................... 2-10 Figure 2.10: Area Average Household Size, Historical and Forecast 1990-2035 ...................... 2-12 Figure 2.11: Residential Use per Customer, 2006-2035 ............................................................ 2-14 Figure 2.12: Avista’s Customer Growth, 1997-2033 .................................................................. 2-15 Figure 2.13: Native Load History and Forecast, 1997-2035 ...................................................... 2-16 Figure 2.14: Winter and Summer Peak Demand, 1997-2035 .................................................... 2-18 Figure 2.15: Load Growth Scenarios, 2014-2035 ...................................................................... 2-19 Figure 2.16: 15 kW Photovoltaic Installation in Rathdrum, ID .................................................... 2-20 Figure 2.17: Buck-A-Block Customer and Demand Growth ....................................................... 2-20 Figure 2.18: Net Metering Customers ........................................................................................ 2-21 Figure 2.19: Solar Energy Transfer Payments ........................................................................... 2-22 Figure 2.20: 2020 Market Reliance & Capacity Cost Tradeoffs to Achieve 5 Percent LOLP .... 2-33 Figure 2.21: Winter 1 Hour Capacity Load and Resources ........................................................ 2-34 Figure 2.22: Summer 18-Hour Capacity Load and Resources .................................................. 2-35 Figure 2.23: Annual Average Energy Load and Resources ....................................................... 2-36 Figure 3.1: Historical and Forecast Conservation Acquisition (system) ....................................... 3-2 Figure 3.2: Analysis Approach Overview ..................................................................................... 3-4 Figure 3.3: Cumulative Conservation Potentials, Selected Years ................................................ 3-7 Figure 5.1: Avista Transmission Map ........................................................................................... 5-5 Figure 5.2: Spokane’s 9th and Central Feeder (9CE12F4) Outage History ................................ 5-10 Figure 6.1: Solar’s Effect on California Load ................................................................................ 6-7 Figure 6.2: New Resource Levelized Costs (first 20 Years) ...................................................... 6-14 Figure 6.3: Historical and Planned Hydro Upgrades .................................................................. 6-16 Figure 7.1: NERC Interconnection Map ....................................................................................... 7-2 Figure 7.2: 20-Year Annual Average Western Interconnect Energy ............................................ 7-3 Figure 7.3: Resource Retirements (Nameplate Capacity) ........................................................... 7-5 Figure 7.4: Cumulative Generation Resource Additions (Nameplate Capacity) .......................... 7-6 Figure 7.5: Henry Hub Natural Gas Price Forecast ...................................................................... 7-8 Figure 7.6: Northwest Expected Energy ..................................................................................... 7-11 Figure 7.7: Regional Wind Expected Capacity Factors .............................................................. 7-12 Figure 7.8: Historical Stanfield Natural Gas Prices (2004-2012) ............................................... 7-13 Figure 7.9: Stanfield Annual Average Natural Gas Price Distribution ........................................ 7-14 Figure 7.10: Stanfield Natural Gas Distributions ........................................................................ 7-14 Figure 7.11: Wind Model Output for the Northwest Region ....................................................... 7-18 Figure 7.12: 2012 Actual Wind Output BPA Balancing Authority ............................................... 7-19 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 9 of 1125 Table of Contents Avista Corp 2013 Electric IRP iv Figure 7.13: Mid-Columbia Electric Price Forecast Range ........................................................ 7-21 Figure 7.14: Western States Greenhouse Gas Emissions ......................................................... 7-23 Figure 7.15: Base Case Western Interconnect Resource Mix ................................................... 7-24 Figure 7.16: Mid-Columbia Prices Comparison with and without Coal Plant Retirements ........ 7-25 Figure 7.17: Western U.S. Carbon Emissions Comparison ....................................................... 7-26 Figure 7.18: Greenhouse Gas Pricing Scenarios ....................................................................... 7-27 Figure 7.19: Nominal Mid-Columbia Prices for Alternative Greenhouse Gas Policies .............. 7-27 Figure 7.20: Annual Greenhouse Gas Emissions for Alternative Greenhouse Gas Policies ..... 7-28 Figure 7.21: Annual Natural Gas Price Forecast Scenarios ...................................................... 7-29 Figure 7.22: Natural Gas Price Scenario’s Mid-Columbia Price Forecasts................................ 7-29 Figure 7.23: Implied Market Heat Rate Changes ....................................................................... 7-30 Figure 7.24: Changes to Mid-Columbia Prices and Western US Greenhouse Gas Levels ....... 7-31 Figure 8.1: Resource Acquisition History ..................................................................................... 8-2 Figure 8.2: Conceptual Efficient Frontier Curve ........................................................................... 8-4 Figure 8.3: Physical Resource Positions (Includes Energy Efficiency) ........................................ 8-6 Figure 8.4: REC Requirements vs. Qualifying RECs for Washington State EIA ......................... 8-7 Figure 8.5: Energy Efficiency Annual Expected Acquisition ....................................................... 8-10 Figure 8.6: Load Forecast with/without Energy Efficiency.......................................................... 8-10 Figure 8.7: Avista Owned and Controlled Resource’s Greenhouse Gas Emissions ................. 8-12 Figure 8.8: Power Supply Expense Range ................................................................................ 8-14 Figure 8.9: Real Power Supply Expected Rate Growth Index $/MWh (2012 = 100) ................. 8-15 Figure 8.10: Expected Case Efficient Frontier ............................................................................ 8-18 Figure 8.11: Efficient Frontier Comparison ................................................................................. 8-23 Figure 8.12: Efficient Frontier Comparison ................................................................................. 8-25 Figure 8.13: 2018-33 Power Supply Costs with and without Colstrip Units 3 and 4 .................. 8-27 Figure 8.14: Greenhouse Gas Emissions without Colstrip Units 3 and 4 .................................. 8-28 Figure 8.15: Change to Power Supply Cost without Colstrip ..................................................... 8-28 Figure 8.16: Change to Power Supply Cost without Colstrip ..................................................... 8-29 Figure 8.17: Annual Levelized Cost (2027-33) of Colstrip Scenarios ........................................ 8-31 Figure 8.18: Load Growth Scenario’s Cost/Risk Comparison .................................................... 8-35 Figure 8.19: Resource Specific Scenarios ................................................................................. 8-37 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 10 of 1125 Table of Contents Avista Corp 2013 Electric IRP v Table of Tables Table 1: The 2013 Preferred Resource Strategy ............................................................................. v Table 2: The 2011 Preferred Resource Strategy ........................................................................... vii Table 1.1: TAC Meeting Dates and Agenda Items ....................................................................... 1-2 Table 1.2: External Technical Advisory Committee Participating Organizations ......................... 1-3 Table 1.3 Idaho IRP Requirements .............................................................................................. 1-6 Table 1.4 Washington IRP Rules and Requirements ................................................................... 1-6 Table 2.1: U.S. Long-run Baseline Forecast Assumptions, 2013-2035 ....................................... 2-6 Table 2.2: Avista WA-ID MSAs Baseline Forecast Assumptions, 2013-2035 ............................. 2-6 Table 2.3: Customer Growth Correlations, January 2006-December 2012 ............................... 2-14 Table 2.4: Average Day Spokane Temperatures 1890-2012 (Degrees Fahrenheit) ................. 2-17 Table 2.5: Avista-Owned Hydro Resources ............................................................................... 2-25 Table 2.6: Avista-Owned Thermal Resources ............................................................................ 2-27 Table 2.7: Mid-Columbia Capacity and Energy Contracts ......................................................... 2-28 Table 2.8: PURPA Agreements .................................................................................................. 2-29 Table 2.9: Other Contractual Rights and Obligations ................................................................. 2-30 Table 2.10: Regional Load & Resource Balance ....................................................................... 2-32 Table 2.11: Washington State RPS Detail (aMW) ...................................................................... 2-38 Table 2.12: Winter 18-Hour Capacity Position (MW) ................................................................. 2-39 Table 2.13: Summer 18-Hour Capacity Position (MW) .............................................................. 2-40 Table 2.14: Average Annual Energy Position (aMW) ................................................................. 2-41 Table 3.1: Cumulative Potential Savings (Across All Sectors for Selected Years) ..................... 3-7 Table 3.2: Annual Achievable Potential Energy Efficiency (aMW) ............................................... 3-8 Table 5.1: IRP Requested Transmission Upgrade Studies .......................................................... 5-7 Table 5.2: Third-Party Large Generation Interconnection Requests ............................................ 5-8 Table 5.3: Completed Feeder Rebuilds ........................................................................................ 5-9 Table 5.4: Planned Feeder Rebuilds .......................................................................................... 5-10 Table 6.1: Natural Gas Fired Plant Cost and Operational Characteristics ................................... 6-5 Table 6.2: Natural Gas-Fired Plant Levelized Costs per MWh .................................................... 6-5 Table 6.4: Northwest Wind Project Levelized Costs per MWh ..................................................... 6-6 Table 6.4: Solar Nominal Levelized Cost ($/MWh) ...................................................................... 6-8 Table 6.5: Coal Capital Costs ....................................................................................................... 6-9 Table 6.6: Coal Project Levelized Cost per MWh ......................................................................... 6-9 Table 6.7: Other Resource Options Levelized Costs ($/MWh) .................................................. 6-13 Table 6.8: New Resource Levelized Costs Considered in PRS Analysis .................................. 6-15 Table 6.9: New Resource Levelized Costs Not Considered in PRS Analysis ........................... 6-15 Table 6.10: Hydro Upgrade Option Costs and Benefits ............................................................. 6-18 Table 7.1: AURORAXMP Zones ..................................................................................................... 7-2 Table 7.2: Western Interconnect Transmission Upgrades Included in Analysis .......................... 7-4 Table 7.3: Natural Gas Price Basin Differentials from Henry Hub ............................................... 7-9 Table 7.4: Monthly Price Differentials for Stanfield from Henry Hub ............................................ 7-9 Table 7.5: January through June Load Area Correlations ......................................................... 7-15 Table 7.6: July through December Load Area Correlations ....................................................... 7-16 Table 7.7: Area Load Coefficient of Determination (Standard Deviation/Mean) ........................ 7-16 Table 7.8: Area Load Coefficient of Determination (Standard Deviation/Mean) ........................ 7-16 Table 7.9: Expected Capacity factor by Region ......................................................................... 7-18 Table 7.10: Annual Average Mid-Columbia Electric Prices ($/MWh) ......................................... 7-22 Table 8.1: Qualifying Washington EIA Resources ....................................................................... 8-7 Table 8.2: 2013 Preferred Resource Strategy .............................................................................. 8-8 Table 8.3: 2011 Preferred Resource Strategy .............................................................................. 8-9 Table 8.4: PRS Rate Base Additions from Capital Expenditures ............................................... 8-13 Table 8.5: Avista Medium-Term Winter Peak Hour Capacity Tabulation ................................... 8-16 Table 8.6: Avista Medium-Term Summer 18-Hour Sustained Peak Capacity Tabulation ......... 8-16 Table 8.7: Efficient Frontier Sample Resource Mixes ................................................................ 8-18 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 11 of 1125 Table of Contents Avista Corp 2013 Electric IRP vi Table 8.8: Nominal Levelized Avoided Costs of the PRS ($/MWh) ........................................... 8-20 Table 8.9: Updated Annual Avoided Costs ($/MWh).................................................................. 8-21 Table 8.10: Alternative PRS with National Climate Change Legislation .................................... 8-22 Table 8.11: Preferred Portfolio Cost and Risk Comparison (Millions $) ..................................... 8-23 Table 8.12: Preferred Portfolio Cost and Risk Comparison for Avoided Cost Studies .............. 8-25 Table 8.13: No Colstrip Resource Strategy Scenario................................................................. 8-26 Table 8.14: Policy Portfolio Scenarios ........................................................................................ 8-33 Table 8.15: Load Growth Sensitivities ........................................................................................ 8-35 Table 8.16: Winter 1 Hour Capacity Position (MW) with New Resources.................................. 8-38 Table 8.16: Summer 18-Hour Capacity Position (MW) with New Resources ............................ 8-39 Table 8.17: Average Annual Energy Position (aMW) With New Resources .............................. 8-40 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 12 of 1125 2013 Electric IRP Introduction Avista has a long tradition of innovation as a provider of a safe, reliable, low-cost, and clean, mix of generation resources. The 2013 Integrated Resource Plan (IRP) continues this legacy by looking into the future energy needs of our customers. The IRP analyzes and outlines a strategy to meet projected demand and renewable portfolio standards through energy efficiency and a careful mix of new renewable and traditional energy resources. Avista currently projects having adequate resources, between owned and contractually controlled generation, to meet our customers’ needs until 2020. Plant upgrades, energy efficiency measures and in the longer term additional natural gas-fired generation are integral parts of Avista’s 2013 IRP resource strategy. Two significant changes from the 2011 IRP should be noted: The 2011 IRP recommendations for new renewable resources have been met with a 30-year purchased power agreement with Palouse Wind, and the Kettle Falls Generating Station being qualified as a renewable energy resource under Washington state’s Energy Independence Act; and Load growth is expected to be at just over 1 percent, a decline from the growth of 1.6 percent forecast in 2011. This delays the need for a new natural gas-fired resource by one year. Each IRP is a thoroughly researched and data-driven document to guide responsible resource planning for the company. The IRP is updated every two years and looks 20 years into the future. This plan is developed by Avista’s professional energy analysts using sophisticated modeling tools and with input from interested community, educational and state utility commission stakeholders. The plan’s Preferred Resource Strategy (PRS) section covers Avista’s projected resource acquisitions over the next 20 years. Some highlights of the 2013 PRS include: Demand response (temporarily reducing the demand for energy) is included in the PRS for the first time and could provide 19 MW of peak energy reduction in the 2022 – 2027 timeframe. Energy efficiency (using less energy to perform activities) reduces load growth by 42 percent over the next 20 years. 486 MW of additional clean-burning natural gas-fired generation facilities are required between 2020 and 2033. Transmission upgrades will be needed to carry the output from new generation. Avista will continue to participate in regional efforts to expand the region’s transmission system. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 13 of 1125 This document is mostly technical in nature. The IRP has an Executive Summary and chapter highlights at the beginning of each section to help guide the reader. Avista expects to begin developing the 2015 IRP in early 2014. Stakeholder involvement is encouraged and interested parties may contact John Lyons at 509-495-8515 or john.lyons@avistacorp.com for more information on participating in the IRP process. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 14 of 1125 Executive Summary Avista Corp 2013 Electric IRP Executive Summary Avista Corporation’s 2013 Electric Integrated Resource Plan (IRP) guides its resource strategy over the next two years and directs resource procurements over the 20-year plan. It provides a snapshot of Avista’s resources and loads and guides future resource acquisitions over a range of expected and possible future conditions. The 2013 Preferred Resource Strategy (PRS) includes energy efficiency, upgrades at existing generation and distribution facilities, demand response and new gas-fired generation. The PRS balances cost, reliability, rate volatility, and renewable resource requirements. Avista’s management and the Technical Advisory Committee (TAC) guide the development of the PRS and the IRP by providing significant input on modeling and planning assumptions. TAC members include customers, commission staff, the Northwest Power and Conservation Council, consumer advocates, academics, utility peers, government agencies, and interested internal parties. Resource Needs Avista’s peak planning methodology includes operating reserves, regulation, load following, wind integration and a planning margin. Avista currently projects having adequate resources between owned and contractually controlled generation to meet annual physical energy and capacity needs until 2020. Chapter 2 explains the peak planning methodology. See Figures 1 – 3 for Avista’s physical resource positions for winter capacity, summer capacity, and annual energy load and resource balances. Figure 1: Load-Resource Balance—Winter 18 Hour Capacity -500 0 500 1,000 1,500 2,000 2,500 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 me g a w a t t s Net Firm Contracts Peaking ThermalsBaseload Thermals HydroLoad Forecast Load Forecast + PM/Reserves Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 15 of 1125 Executive Summary Avista Corp 2013 Electric IRP Figure 2: Load-Resource Balance—Summer 18 Hour Capacity Figure 3: Load-Resource Balance—Energy -500 0 500 1,000 1,500 2,000 2,500 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 me g a w a t t s Net Firm Contracts Peaking ThermalsBaseload Thermals HydroLoad Forecast + PM/Reserves 0 500 1,000 1,500 2,000 2,500 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 av e r a g e m e g a w a t t s Net Firm Contracts Peaking Thermals Baseload Thermals Hydro Load Forecast Load Forecast + Contingency Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 16 of 1125 Executive Summary Avista Corp 2013 Electric IRP Figures 1 – 3 include the effects of new energy efficiency programs on the load forecast. Absent energy efficiency, Avista would be resource deficient earlier. The region has a significant summer capacity surplus; Avista plans to meet all summer capacity needs with term purchases. A short-term capacity need exists in the winters of 2014/15 and 2015/16. This capacity need is short-lived because a 150 MW capacity sale contract ends in 2016. Avista expects to address these short-term deficits with market purchases; therefore, the first long-term capacity deficit begins in 2020. Modeling and Results Avista uses a multiple-step approach to develop its PRS. It begins by identifying and quantifying potential new generation resources to serve projected electricity demand across the West. A Western Interconnect-wide study explains the impact of regional markets on the Northwest electricity marketplace. Avista then maps its existing resources to the present transmission grid configuration in a model simulating hourly operations for the Western Interconnect from 2014 to 2033. The model adds cost- effective new resources and transmission across the Western Interconnect to meet overall projected loads. Monte Carlo-style analysis varies hydroelectric and wind generation, loads, forced outages and natural gas price data over 500 iterations of potential future market conditions. The simulation estimates Mid-Columbia electricity market prices by iteration and the results of the 500 iterations form the Expected Case. Electricity and Natural Gas Market Forecasts Figure 4 shows the 2013 IRP electricity price forecast for the Expected Case, including the price range over the 500 Monte Carlo iterations. The forecasted levelized average Mid-Columbia market price is $44.08 per MWh in nominal dollars over 20 years. Figure 4: Average Mid-Columbia Electricity Price Forecast $0 $20 $40 $60 $80 $100 $120 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 1 4 -33 do l l a r s p e r M W h Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 17 of 1125 Executive Summary Avista Corp 2013 Electric IRP Electricity and natural gas prices are highly correlated because natural gas fuels marginal generation in the Northwest during most of the year. Figure 5 presents nominal levelized Expected Case natural gas prices at the Stanfield trading hub, located in northeastern Oregon, as well as the forecast range from the 500 Monte Carlo iterations performed for the case. The average is $5.40 per dekatherm over the next 20 years. See Chapter 7 for details on the company’s natural gas price forecast. Figure 5: Stanfield Natural Gas Price Forecast Energy Efficiency Acquisition Avista commissioned a 20-year Conservation Potential Assessment in 2013. The study analyzed over 4,300 energy efficiency equipment and measure options for residential, commercial, and industrial applications. Data from this study formed the basis of the IRP conservation potential evaluations. Figure 6 shows how historical efforts in energy efficiency decrease Avista’s energy requirements by 125 aMW, or approximately ten percent. By 2033, energy efficiency reduces load by 164 aMW. More detail about Avista’s energy efficiency programs is contained in Chapter 3. $0.00 $2.00 $4.00 $6.00 $8.00 $10.00 $12.00 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 do l l a r s p e r d e k a t h e r m Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 18 of 1125 Executive Summary Avista Corp 2013 Electric IRP Figure 6: Cumulative Energy Efficiency Acquisitions Preferred Resource Strategy The PRS includes careful consideration by Avista’s management and the TAC of the information gathered and analyzed in the IRP process. It meets future load growth with efficiency upgrades at existing generation and distribution facilities, conservation, wind, and natural gas-fired technologies as shown in Table 1. Table 1: The 2013 Preferred Resource Strategy Resource By the End of Year Nameplate (MW) Energy (aMW) Simple Cycle CT 2019 83 76 Simple Cycle CT 2023 83 76 Combined Cycle CT 2026 270 248 Rathdrum CT Upgrade 2028 6 5 Simple Cycle CT 2032 50 46 Total 492 451 Efficiency Improvements Acquisition Range Peak Reduction Energy (aMW) Energy Efficiency 2014-2033 221 164 Demand Response 2022-2027 19 0 Distribution Efficiencies 2014-2017 <1 <1 Total 240 164 The 2013 PRS describes a reasonable low-cost plan along the efficient frontier of potential resource portfolios accounting for fuel supply risk and price risk. Major changes from the 2011 PRS include reduced contributions from conservation, wind, and 0 60 120 180 240 300 360 420 480 540 600 0 2 4 6 8 10 12 14 16 18 20 19 7 8 19 8 0 19 8 2 19 8 4 19 8 6 19 8 8 19 9 0 19 9 2 19 9 4 19 9 6 19 9 8 20 0 0 20 0 2 20 0 4 20 0 6 20 0 8 20 1 0 20 1 2 20 1 4 20 1 6 20 1 8 20 2 0 20 2 2 20 2 4 20 2 6 20 2 8 20 3 0 20 3 2 cu m u l a t i v e s a v i n g s ( a M W ) an n u a l s a v i n g s ( a M W ) Cumulative Online Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 19 of 1125 Executive Summary Avista Corp 2013 Electric IRP natural gas-fired resources. For the first time the PRS includes a modest contribution from demand response. Each new resource and energy efficiency option is valued against the Expected Case Mid-Columbia electricity market to identify its future value to Avista, as well as its inherent risk measured by year-to-year portfolio cost volatility. These values, and their associated capital and fixed operation and maintenance (O&M) costs, form the input into Avista’s Preferred Resource Strategy Linear Programming Model (PRiSM). PRiSM assists Avista by developing optimal mixes of new resources along an efficient frontier. Chapter 8 provides a detailed discussion of the efficient frontier concept. The PRS provides a “least reasonable cost” portfolio that minimizes future costs and risks given actual or expected environmental constraints. An efficient frontier helps determine the tradeoffs between risk and cost. The approach is similar to finding an optimal mix of risk and return in an investment portfolio. As expected returns increase, so do risks. Reducing risk reduces overall returns. There is a trade-off between power supply costs and power supply cost variability. Figure 7 presents the change in cost and risk from the PRS on the Efficient Frontier. Lower power cost variability comes from investments in more expensive, but less risky, resources. The PRS selection is the location on the efficient frontier where reduced risk justifies the increased cost. Figure 7: Efficient Frontier $20 Mil $30 Mil $40 Mil $50 Mil $60 Mil $70 Mil $80 Mil $325 Mil $350 Mil $375 Mil $400 Mil $425 Mil $450 Mil 20 2 8 p o w e r s u p p l y c o s t s t d e v 20 yr levelized annual power supply rev. req. Market Only Least Cost Least Risk Preferred Resource Strategy Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 20 of 1125 Executive Summary Avista Corp 2013 Electric IRP The IRP includes several scenarios to identify tipping points where the PRS could change under conditions alternative to the Expected Case. Chapter 8 includes scenarios for load growth, capital costs, higher energy efficiency acquisitions, and greenhouse gas policies. The 2013 PRS is significantly different from the 2011 IRP resource strategy; the 2011 PRS is in Table 2. Since the prior plan, Avista’s renewable and capacity needs have changed. Adding Palouse Wind to Avista’s resource mix in December 2012 satisfied the 2012 Northwest Wind component of the 2011 PRS. Changes in the Washington State Energy Independence Act (EIA) eliminated the need for a 2019/2020 wind resource. The amendment under SB 5575 adds the Kettle Falls Generating Station, and other legacy biomass plants, as EIA qualifying resources beginning in 2016. The 2011 IRP forecast 1.6 percent annual load growth, while this IRP forecasts just over 1 percent growth (see Chapter 2). Lower expected load growth delays the first natural gas-fired resource need by one year and eliminates the need for a combined cycle combustion turbine in 2023. Table 2: The 2011 Preferred Resource Strategy Resource By the End of Year Nameplate (MW) Energy (aMW) Northwest Wind 2012 120 35 Simple Cycle CT 2018 83 75 Existing Thermal Resource Upgrades 2019 4 3 Northwest Wind 2019-2020 120 35 Simple Cycle CT 2020 83 75 Combined Cycle CT 2023 270 237 Combined Cycle CT 2026 270 237 Simple Cycle CT 2029 46 42 Total 996 739 Efficiency Improvements Acquisition Range Peak Reduction (MW) Energy (aMW) Distribution Efficiencies 2012-2031 28 13 Energy Efficiency 2012-2031 419 310 Total 447 323 Washington voters approved the EIA through Initiative 937 in the November 2006 general election. The EIA requires utilities with over 25,000 customers to meet 3 percent of retail load from qualified renewable resources by 2012, 9 percent by 2016, and 15 percent by 2020. The initiative also requires utilities to acquire all cost-effective conservation and energy efficiency measures. Avista expects to meet or exceed its renewable energy requirements through the 20-year plan with a combination of qualifying hydroelectric upgrades, the Palouse Wind project, the Kettle Falls Generating Station and selective renewable energy certificate (REC) purchases. A list of the qualifying generation projects and the associated Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 21 of 1125 Executive Summary Avista Corp 2013 Electric IRP expected output is in Table 8 below. The flexibility of I-937 to use RECs from the current year, from the previous year, or from the following year for compliance helps Avista mitigate year-to-year variability in the output of qualifying renewable resources. Figure 8: Avista’s Qualifying Renewables for Washington State’s EIA Greenhouse Gas Emissions Forecasts of greenhouse gas emissions costs have been included as part of Avista’s Expected Case since the 2007 IRP. Based on current legislative priorities and the President’s Climate Action Plan, a national greenhouse gas cap-and-trade system or tax is no longer likely. Therefore, the Expected Case does not include a market or tax solution to reduce emissions. Instead, because the states and the EPA are implementing regulatory models limiting emissions for new facilities, and requiring current facilities to either implement best available control technologies or shut down, this IRP forecasts significant numbers of plant retirements to meet these environmental rules. Figure 9 shows projected greenhouse gas emissions for existing and new Avista generation assets, but it does not account for emissions from market purchases or sales. While Avista’s emissions increase modestly, western region emissions fall from historic levels as less-cost-effective coal and older natural gas-fired plants retire (see Figure 10). Avista does not follow this overall trajectory because the carbon intensity of its portfolio already is relatively low. More details about state and federal greenhouse gas policies are in chapter 4. 0 20 40 60 80 100 120 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 av e r a g e m e g a w a t t s Qualifying Hydro Upgrades Qualifying ResourcesPurchased RECs Available Bank Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 22 of 1125 Executive Summary Avista Corp 2013 Electric IRP Figure 9: Avista Owned and Controlled Resource’s Greenhouse Gas Emissions Figure 10: U.S. Western Interconnect Greenhouse Gas Emissions 0.00 0.10 0.20 0.30 0.40 0.50 Mil 1 Mil 2 Mil 3 Mil 4 Mil 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 me t r i c t o n s p e r M W h me t r i c t o n s Total Tons per MWh of Load 0 50 100 150 200 250 300 350 19 9 0 19 9 2 19 9 4 19 9 6 19 9 8 20 0 0 20 0 2 20 0 4 20 0 6 20 0 8 20 1 0 20 1 2 20 1 4 20 1 6 20 1 8 20 2 0 20 2 2 20 2 4 20 2 6 20 2 8 20 3 0 20 3 2 mi l l i o n m e t r i c t o n s C O 2 Historical Expected Case 10th Percentile 90th Percentile Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 23 of 1125 Executive Summary Avista Corp 2013 Electric IRP Action Items The 2013 Action Plan updates progress on the 2011 Action Items and outlines activities Avista intends to perform for the 2015 IRP. It includes input from Commission Staff, Avista’s management team, and the TAC. Action Item categories include resource additions and analysis, demand side management, environmental policy, modeling and forecasting enhancements, and transmission planning. Chapter 9 and discusses the new Action Items. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 24 of 1125 Chapter 1- Introduction and Stakeholder Involvement Avista Corp 2013 Electric IRP 1. Introduction and Stakeholder Involvement Avista submits an IRP to the Idaho and Washington public utility commissions biennially.1 The 2013 IRP is Avista’s thirteenth plan. It identifies and describes a PRS for meeting load growth while balancing cost and risk measures with environmental mandates. Avista is statutorily obligated to provide reliable electricity service to its customers at rates, terms, and conditions that are fair, just, reasonable, and sufficient. Avista assesses different resource acquisition strategies and business plans to acquire resources to meet resource adequacy requirements and optimize the value of its current resource portfolio. The IRP is a resource evaluation tool rather than a plan for acquiring a particular set of assets. The 2013 IRP continues refining Avista’s resource acquisition efforts. IRP Process The 2013 IRP is developed and written with the aid of a public process. Avista actively seeks input for its IRPs from a variety of constituents through the TAC. The TAC is 75 participants including Commission Staff from Idaho and Washington, customers, academics, government agencies, consultants, utilities, and other interested parties who accepted an invitation to join, or had asked to be involved in, the planning process. Avista sponsored six TAC meetings for the 2013 IRP. The first meeting was on May 23, 2012, and the last was on June 19, 2013. TAC meetings cover different aspects of the 2013 IRP planning activities and solicited contributions to, and assessments of, modeling assumptions, modeling processes, and results. Table 1.1 contains a list of TAC meeting dates and the agenda items covered in each meeting. Agendas and presentations from the TAC meetings are in Appendix A and on Avista’s website at http://www.avistautilities.com/inside/resources/irp/electric. Past IRPs and TAC presentations are also here. 1 Washington IRP requirements are contained in WAC 480-100-238 Integrated Resource Planning. Idaho IRP requirements are in Case No. U-1500-165 Order No. 22299, Case No. GNR-E-93-1, Order No. 24729, and Case No. GNR-E-93-3, Order No. 25260. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 25 of 1125 Chapter 1- Introduction and Stakeholder Involvement Avista Corp 2013 Electric IRP Table 1.1: TAC Meeting Dates and Agenda Items Meeting Date Agenda Items TAC 1 – May 23, 2012 Powering our Future Game 2011 Renewable RFP Palouse Wind Project Update 2011 IRP Acknowledgement Energy Independence Act Compliance and Forecast Work Plan TAC 2 – September 4 and 5, 2012 Palouse Wind Project Tour Avista REC Planning Methods Energy and Economic Forecast Shared Value Report Generation Options Spokane River Assessment TAC 3 – November 7, 2012 Electricity Market Modeling Colstrip Discussion Energy Efficiency Peak Load Forecast Reliability Planning Energy Storage TAC 4 – February 6, 2013 Natural Gas Price Forecast Electric Price Forecast Transmission Planning Resource Needs Assessment Market & Portfolio Scenario Development TAC 5 – March 20, 2013 Market Forecast Scenario Results Conservation Avoided Costs Demand Response Draft 2013 IRP Preferred Resource Strategy Portfolio Scenarios TAC 6 – June 19, 2013 2013 Final Preferred Resource Strategy Portfolio Scenario Analysis Net Metering and Buck-A-Block Action Plan 2013 IRP Document Introduction Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 26 of 1125 Chapter 1- Introduction and Stakeholder Involvement Avista Corp 2013 Electric IRP Avista wishes to acknowledge and thank all of the organizations identified in Table 1.2 who participated in the TAC process. Table 1.2: External Technical Advisory Committee Participating Organizations Organization AES Corporation Alexander Boats, LLC Ameresco Quantum City of Spokane Clearwater Paper Eastern Washington University EnerNOC Utility Solutions Eugene Water & Electric Board First Wind GE Energy Gonzaga University Grant PUD Greater Spokane Incorporated Idaho Power Idaho Public Utilities Commission Inland Power & Light Puget Sound Energy Residential and Small Commercial Customers Sierra Club TransAlta Washington Department of Enterprise Services Washington State Legislature Washington Utilities and Transportation Commission Winfiniti Issue Specific Public Involvement Activities In addition to the TAC meetings, Avista sponsors and participates in several other collaborative processes involving a range of public interests. External Energy Efficiency (“Triple E”) Board The Triple E Board, formed in 1995, provides stakeholders and public groups biannual opportunities to discuss Avista’s energy efficiency efforts. The Triple E Board grew out of the DSM Issues group. FERC Hydro Relicensing – Clark Fork and Spokane River Projects Over 50 stakeholder groups participated in the Clark Fork hydro-relicensing process beginning in 1993. This led to the first all-party settlement filed with a FERC relicensing application, and eventual issuance of a 45-year FERC operating license in February 2003. This collaborative process continues in the implementation of the license and Clark Fork Settlement Agreement, with stakeholders participating in various protection, mitigation, and enhancement efforts. More recently, Avista received a 50-year license for the Spokane River Project following a multi-year collaborative process involving Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 27 of 1125 Chapter 1- Introduction and Stakeholder Involvement Avista Corp 2013 Electric IRP several hundred stakeholders. Implementation began in 2009 with a variety of collaborating parties. Low Income Rate Assistance Program This program is coordinated with four community action agencies in Avista’s Washington service territory. The program began in 2001 and reviews administrative issues and needs on a quarterly basis. Regional Planning The Pacific Northwest’s generation and transmission system operates in a coordinated fashion. Avista participates in the efforts of many organization’s planning processes. Information from this participation supplements Avista’s IRP process. Some of the organizations that Avista participates in are: Western Electricity Coordinating Council Northwest Power and Conservation Council Northwest Power Pool Pacific Northwest Utilities Conference Committee ColumbiaGrid Northwest Transmission Assessment Committee North American Electric Reliability Council Future Public Involvement As previously explained, Avista actively solicits input from interested parties to enhance its IRP process. We continue to expand TAC membership and diversity, and maintain the TAC meetings as an open public process. 2013 IRP Outline The 2013 IRP consists of nine chapters plus an executive summary and this introduction. A series of technical appendices supplement this report. Executive Summary This chapter summarizes the overall results and highlights of the 2013 IRP. Chapter 1: Introduction and Stakeholder Involvement This chapter introduces the IRP and details public participation and involvement in the integrated resource planning process. Chapter 2: Loads and Resources The first half of this chapter covers Avista’s load forecast and related local economic forecasts. The last half describes Avista’s owned generating resources, major contractual rights and obligations, capacity, energy and renewable energy credit tabulations, and reserve obligations. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 28 of 1125 Chapter 1- Introduction and Stakeholder Involvement Avista Corp 2013 Electric IRP Chapter 3: Energy Efficiency This chapter discusses Avista’s energy efficiency programs. It provides an overview of the conservation potential assessment and summarizes the energy efficiency modeling results for the 2013 IRP. Chapter 4: Policy Considerations This chapter focuses on some of the major policy issues for resource planning, including state and federal greenhouse gas policies and environmental regulations. Chapter 5: Transmission & Distribution This chapter discusses Avista’s distribution and transmission systems, as well as regional transmission planning issues. It includes detail on transmission cost studies used in the IRP modeling and a summary of the 10-year Transmission Plan. The chapter finishes with a discussion of Avista’s distribution efficiency and grid modernization projects. Chapter 6: Generation Resource Options This chapter covers the costs and operating characteristics of the generation resource options modeled for the 2013 IRP. Chapter 7: Market Analysis This chapter details Avista’s IRP modeling and analysis of the various wholesale markets applicable to the 2013 IRP. Chapter 8: Preferred Resource Strategy This chapter details Avista’s 2013 Preferred Resource Strategy (PRS) and explains how the PRS could change in response to scenarios differing from the Expected Case. Chapter 9: Action Items This chapter discusses progress made on Action Items from the 2011 IRP. It details new Action Items for the 2015 IRP. Regulatory Requirements The IRP process for Idaho has several requirements documented in IPUC Orders Nos. 22299 and 24729. Table 1.3 summarizes the applicable IRP requirements. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 29 of 1125 Chapter 1- Introduction and Stakeholder Involvement Avista Corp 2013 Electric IRP Table 1.3 Idaho IRP Requirements Requirement Plan Citation Identify and list relevant operating characteristics of existing resources by categories including: hydroelectric, coal-fired, oil or gas-fired, PURPA (by type), exchanges, contracts, transmission resources, and others. Chapter 2- Loads & Resources Identify and discuss the 20-year load forecast plus scenarios for the different customer classes. Identify the assumptions and models used to develop the load forecast. Chapter 2- Loads & Resources Chapter 8- Preferred Resource Strategy Identify the utility’s plan to meet load over the 20- year planning horizon. Include costs and risks of the plan under a range of plausible scenarios. Chapter 8- Preferred Resource Strategy Identify energy efficiency resources and costs. Chapter 3- Energy Efficiency Provide opportunities for public participation and involvement.Chapter 1- Introduction and Stakeholder Involvement The IRP process for Washington has several requirements documented in Washington Administrative Code (WAC). Table 1.4 summarizes where within the IRP the applicable WACs are addressed. Table 1.4 Washington IRP Rules and Requirements Rule and Requirement Plan Citation Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 30 of 1125 Chapter 1- Introduction and Stakeholder Involvement Avista Corp 2013 Electric IRP WAC 480-100-238(2)(b) – LRC analysis considers resource effect on system operation. Chapter 7- Market Analysis Chapter 8- Preferred Resource Strategy WAC 480-100-238(2)(b) – LRC analysis considers risks imposed on ratepayers. Chapter 4- Policy Considerations Chapter 6- Generation Resource Options Chapter 7- Market Analysis Chapter 8- Preferred Resource Strategy WAC 480-100-238(2)(b) – LRC analysis considers public policies regarding resource preference adopted by Washington state or federal government. Chapter 2- Loads & Resources Chapter 4- Policy Considerations Chapter 8- Preferred Resource Strategy WAC 480-100-238(2)(b) – LRC analysis considers cost of risks associated with environmental effects including emissions of carbon dioxide. Chapter 4- Policy Considerations Chapter 8- Preferred Resource Strategy WAC 480-100-238(2)(c) – Plan defines conservation as any reduction in electric power consumption that results from increases in the efficiency of energy use, production, or distribution. Chapter 3- Energy Efficiency Chapter 8- Preferred Resource Strategy WAC 480-100-238(3)(a) – Plan includes a range of forecasts of future demand. Chapter 2- Loads & Resources Chapter 8- Preferred Resource Strategy WAC 480-100-238(3)(a) – Plan develops forecasts using methods that examine the effect of economic forces on the consumption of electricity. Chapter 2- Loads & Resources Chapter 5- Transmission & Distribution Chapter 8- Preferred Resource Strategy WAC 480-100-238-(3)(a) – Plan develops forecasts using methods that address changes in the number, type and efficiency of end-uses. Chapter 2- Loads & Resources Chapter 3- Energy Efficiency Chapter 5- Transmission & Distribution WAC 480-100-238(3)(b) – Plan includes an assessment of commercially available conservation, including load management. Chapter 3- Energy Efficiency Chapter 5- Transmission & Distribution WAC 480-100-238(3)(b) – Plan includes an assessment of currently employed and new policies and programs needed to obtain the conservation improvements. Chapter 3- Energy Efficiency Chapter 5- Transmission & Distribution WAC 480-100-238(3)(c) – Plan includes an assessment of a wide range of conventional and commercially available nonconventional generating technologies. Chapter 6- Generator Resource Options Chapter 8- Preferred Resource Strategy WAC 480-100-238(3)(d) – Plan includes an assessment of transmission system capability and reliability (as allowed by current law). Chapter 5- Transmission & Distribution WAC 480-100-238(3)(e) – Plan includes a comparative evaluation of energy supply resources (including transmission and distribution) and improvements in conservation using LRC. Chapter 3- Energy Efficiency Chapter 5- Transmission & Distribution WAC-480-100-238(3)(f) – Demand forecasts and resource evaluations are integrated into the long range plan for resource acquisition. Chapter 3- Energy Efficiency Chapter 5- Transmission & Distribution Chapter 6- Generator Resource Options Chapter 8- Preferred Resource Strategy Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 31 of 1125 Chapter 1- Introduction and Stakeholder Involvement Avista Corp 2013 Electric IRP WAC 480-100-238(3)(g) – Plan includes a two- year action plan that implements the long range plan. Chapter 9- Action Items WAC 480-100-238(3)(h) – Plan includes a progress report on the implementation of the previously filed plan. Chapter 9- Action Items WAC 480-100-238(5) – Plan includes description of consultation with commission staff. (Description not required) Chapter 1- Introduction and Stakeholder Involvement WAC 480-100-238(5) – Plan includes description of work plan. (Description not required) Appendix B WAC 480-107-015(3) – Proposed request for proposals for new capacity needed within three years of the IRP. Chapter 8- Preferred Resource Strategy Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 32 of 1125 Chapter 2: Loads & Resources Avista Corp 2013 Electric IRP 2-1 2. Loads & Resources Introduction & Highlights An explanation and quantification of Avista’s loads and resources are integral to the IRP. The load section of this chapter summarizes customer and load forecasts, load growth scenarios, and enhancements to forecasting models and processes. The resource section of the chapter covers Avista’s current resource mix, including descriptions of owned and operated generation, as well as long-term power purchase contracts. The combination of the load forecast and current generation mix show the future resource need to meet energy, peak demand, and renewable energy requirements. Economic Characteristics of Avista’s Service Territory Avista serves electricity customers in most of the urban and suburban areas of 24 counties of eastern Washington and northern Idaho. Figure 2.1 shows Avista’s electricity and natural gas service territories. Over 80 percent of Avista’s customers are located in three Metropolitan Statistical Areas (MSAs): Spokane MSA (Spokane County, WA), Coeur d’Alene MSA (Kootenai County, ID), and Lewiston, ID-WA MSA (Nez Perce County, ID and Asotin County, WA). The load portion of this chapter focuses on population, employment and personal income for the three MSAs combined. The 2013 IRP energy forecast grows 1.0 percent per year, replacing the 1.4 percent annual growth rate in the 2011 IRP. Peak load growth is slower than energy growth, at 0.84 percent in the winter and 0.90 percent in the summer. Avista’s first long-term capacity deficit is in 2020; the first energy deficit is in 2026. Palouse Wind became operational December 13, 2012. Kettle Falls qualifies for the Washington State Energy Independence Act (EIA) beginning in 2016. This IRP meets all EIA mandates over the next 20 years with a combination of qualifying hydro upgrades, Palouse Wind, and Kettle Falls. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 33 of 1125 Chapter 2: Loads & Resources Avista Corp 2013 Electric IRP 2-2 Figure 2.1: Avista’s Service Territory Population across the three MSAs is approximately 680,000. Since 1970, average annual population growth is about 1 percent. Figure 2.2 shows population in the three main MSAs. The Coeur d’Alene MSA has enjoyed the most rapid population growth since the early 1990s, increasing its share of service area population from 15 percent in 1990 to over 20 percent today. Figure 2.2: Population Levels 1970 – 2011 0 100,000 200,000 300,000 400,000 500,000 600,000 700,000 800,000 19 7 0 19 7 2 19 7 4 19 7 6 19 7 8 19 8 0 19 8 2 19 8 4 19 8 6 19 8 8 19 9 0 19 9 2 19 9 4 19 9 6 19 9 8 20 0 0 20 0 2 20 0 4 20 0 6 20 0 8 20 1 0 to t a l p o p u l a t i o n Spokane MSA Coeur d'Alene MSA Lewiston, ID-WA MSA Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 34 of 1125 Chapter 2: Loads & Resources Avista Corp 2013 Electric IRP 2-3 Population growth is a function of both regional and national employment growth. The regional business cycle follows the U.S. business cycle, meaning regional economic expansions or contractions follow national trends. A study done by Eastern Washington University’s Institute for Public Policy and Economic Analysis documents this correlation between the regional and national business cycles.1 Econometric analysis shows that when regional employment growth is stronger than U.S. growth (see Equation 2.2) over expansionary periods; regional population growth tends to accelerate. The reverse also holds true. Figure 2.3 shows annual population growth since 1971. In the deep economic downturns of the mid-1970s, early 1980s and the recent Great Recession, reduced population growth rates in Avista’s service territory led to lower load growth. The Great Recession reduced population growth from nearly 2 percent in 2007 to less than 1 percent from 2010-2012. Figure 2.3: Population Growth and U.S. Recessions, 1971-2011 The Inland Northwest has transitioned from a natural resources-based manufacturing economy to a services-based economy. Figure 2.4 shows the breakdown of employment for all three MSAs. Just over 70 percent of employment is in private services, followed by government (15 percent) and private goods-producing sectors (13 percent). Government employment in the three MSAs is notably higher than in the Portland and Puget Sound MSAs. Farming now accounts for one percent of employment. 1 An Exploration of Similarities between National and Regional Economic Activity in the Inland Northwest, Monograph No. 11, May 2006. http://www.ewu.edu/cbpa/centers-and-institutes/ippea/monograph-series.xml. -0.5% 0.0% 0.5% 1.0% 1.5% 2.0% 2.5% 3.0% 3.5% 19 7 1 19 7 3 19 7 5 19 7 7 19 7 9 19 8 1 19 8 3 19 8 5 19 8 7 19 8 9 19 9 1 19 9 3 19 9 5 19 9 7 19 9 9 20 0 1 20 0 3 20 0 5 20 0 7 20 0 9 20 1 1 po p u l a t i o n p e r c e n t c h a n g e ShadedAreas = Recessions Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 35 of 1125 Chapter 2: Loads & Resources Avista Corp 2013 Electric IRP 2-4 Figure 2.4: Employment Breakdown by Major Sector, 2011 Between 1990 and 2007, non-farm employment growth averaged 2.5 percent per year. However, Figure 2.5 shows that since the end of the Great Recession in 2009, there has been no regional economic growth, and a significant regional lag relative to national employment recovery over the same period. Regional employment growth did not materialize until the second half of 2012, when services employment started to grow. Prior to this, reductions in federal, state, and local government offset employment gains in the goods producing sector. Figure 2.5: Post Recession Employment Growth, June 2009-December 2012 On a brighter economic note, the Spokane and Coeur d’Alene MSAs have emerged as major providers of health and higher education services to the Inland Northwest. A Non-Farm Private Good Producing, 13% Non-Farm Private Service Producing, 71% Government (Federal, State, Local), 15% Farm, 1% 88 90 92 94 96 98 100 102 De c -07 Fe b -08 Ap r -08 Ju n -08 Au g -08 Oc t -08 De c -08 Fe b -09 Ap r -09 Ju n -09 Au g -09 Oc t -09 De c -09 Fe b -10 Ap r -10 Ju n -10 Au g -10 Oc t -10 De c -10 Fe b -11 Ap r -11 Ju n -11 Au g -11 Oc t -11 De c -11 Fe b -12 Ap r -12 Ju n -12 Au g -12 Oc t -12 De c -12 in d e x o f n o n -fa r m e m p l o y m e n t , d e c . 20 0 7 = 1 0 0 Index Avista WA-ID MSAs Index U.S. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 36 of 1125 Chapter 2: Loads & Resources Avista Corp 2013 Electric IRP 2-5 recent addition to these sectors is a new University of Washington medical school branch located in the City of Spokane. Public and private universities and the regional medical system will support the new medical school. Finally, Figure 2.6 shows the distribution of personal income, a broad measure of both earned income and transfer payments, for Avista’s Washington-Idaho MSAs. Regular income consists of net earnings from employment and investment income in the form of dividends interest and rent. Personal current transfer payments include money income and in-kind transfers received through unemployment benefits, low-income food assistance, Social Security, Medicare and Medicaid. Figure 2.6: Personal Income Breakdown by Major Source, 2011 Although roughly 60 percent of personal income is from net earnings, transfer payments account for 23 percent, or more than one in every five dollars of personal income. Transfer payments have been the fastest growing component of personal income in the region. This reflects an aging regional population, a surge of military veterans, and the Great Recession, which significantly increased payments from unemployment insurance and other low-income assistance programs. In 1970, the share of net earnings and transfer payments in WA-ID MSAs accounted for 64 percent and 12 percent, respectively. The income share of transfer payments has nearly doubled over the last 40 years. The relatively high regional dependence on government employment and transfer payments means continued fiscal consolidation at the federal level would be an economic drag on future growth. Customer and Load Forecast Assumptions The customer and load forecasts use: (1) forecasts of U.S. and county-level economic growth; (2) forecasts of heating and cooling degree-days; and (3) forecasts of use-per-customer trends. Topics discussed below provide background to the final customer and load forecasts. Net Earnings, 59% Other Transfer Payments, 4% Retirement Transfer Payments, 19% Dividends, Interest, and Rent, 18% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 37 of 1125 Chapter 2: Loads & Resources Avista Corp 2013 Electric IRP 2-6 Avista’s load forecasting methodology is undergoing significant restructuring. The restructuring involves using an Auto Regressive Integrated Moving Average (ARIMA) technique. ARIMA improves the modeling of economic drivers involving population, industrial production, income levels and energy prices to predict long-term energy demand. This new methodology will improve forecasts used in the 2015 IRP. Assumptions for U.S. and County-level Economic Growth The forecast used for this IRP, finalized July 2012, relies on national and county-level forecasts from multiple sources. However, forecasts developed ―in-house‖ and from Global Insight are the principle forecast sources. Avista purchases forecasts from Global Insight, an internationally recognized economic forecasting consulting firm. Table 2.1 presents key U.S. forecast assumptions. Table 2.1: U.S. Long-run Baseline Forecast Assumptions, 2013-2035 Assumption Average (%) Source Gross Domestic Product 2.5 Global Insight, Federal Reserve, Bloomberg Consensus Forecasts, Energy Information Administration, and Avista Forecasts Consumer Inflation 2.0 Federal Reserve Worker Productivity 2.0 Global Insight Employment Growth 0.9 Global Insight Industrial Production 2.3 Global Insight Population Growth 0.9 Global Insight Long-run gross domestic product (GDP) growth reflects an average of multiple forecast sources, including Avista’s own in-house forecasts. In theory, long-run GDP growth should be the sum of productivity growth plus population growth—2.9 percent using the numbers above. However, the forecast sources above generally assume fiscal consolidation (reducing the size of government deficits and debt accumulation) in the U.S. and other developing countries. Fiscal consolidation, along with less consumer credit, will keep U.S. GDP growth under 2.9 percent over the next 20-years. Prior to the Great Recession, U.S. long-run GDP growth was around 3 percent. Consumer inflation reflects the U.S. Federal Reserve’s implied anchor for long-run inflation. Table 2.2 presents key assumptions for the Spokane, Coeur d’Alene and Lewiston, ID- WA MSAs. These three areas comprise more than 80 percent of Avista’s service area economy. Table 2.2: Avista WA-ID MSAs Baseline Forecast Assumptions, 2013-2035 Assumption Average Source Employment Growth 0.8% Global Insight and Avista Forecasts Housing Starts 4,200 per yr. Global Insight Population Growth 1.1% Global Insight and Avista Forecasts Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 38 of 1125 Chapter 2: Loads & Resources Avista Corp 2013 Electric IRP 2-7 Employment growth and housing starts are key predictors of customer and population growth. Modest forecasts in these areas translate into modest customer growth forecasts. Long-run population growth in Avista’s service area is nearly identical to long-run growth rates of total customers over the same period. Therefore, population growth forecasts are a proxy for long-run customer growth, especially for the residential and commercial customer classes. In addition to Global Insight’s population forecasts for the major MSAs, Avista uses two other in-house methods for generating customer growth forecasts. Both methods provide a baseline reasonableness test of Global Insight’s population forecasts, which forms the basis of Avista’s long-run customer forecasts. Figure 2.7 shows Global Insight’s population forecasts. Figure 2.7: Population Forecast, 2013-2035 While one method uses Global Insight’s annual housing forecasts to project annual changes in residential and commercial customers in the MSAs, the second forecast method uses the following simple time-series regression estimated from historical data: Equation 2.1: Conservation Avoided Costs ∆Ct = α0 + α1Mt-1 + εt Where: α0 = Intercept value of the estimated equation. ∆Ct = Change in Avista’s total residential electric customers from year t to year t-1 (annual numbers are 12 month averages). 0 100,000 200,000 300,000 400,000 500,000 600,000 700,000 800,000 900,000 1,000,000 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 20 3 5 to t a l p o p u a l t i o n Spokane MSA Coeur d'Alene MSA Lewiston, ID-WA MSA Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 39 of 1125 Chapter 2: Loads & Resources Avista Corp 2013 Electric IRP 2-8 Mt-1 = The number of housing starts (single family homes and multi-family units) reported at time t-1 for Avista’s three combined WA-ID MSAs. εt = Random error term. Figure 2.8 shows housing start forecasts to the end of the IRP period using the Global Insight forecasts. Figure 2.8: House Start History and Forecast (2000-2035) Annual regional and U.S. employment growth is used to forecast annual population growth in the MSAs. The population forecast uses the simple time-series regression model estimated from historical data in Equation 2.2. Equation 2.2: Population Forecast Pt = α0 + α1Et-1,MSA + α2Et-1,US + α3D2002, + εt, Where: α0 = Intercept value of the estimated equation. Pt = Population growth rate in year t in Avista’s WA-ID MSAs. Et-1,MSA = Growth rate in non-farm employment in year t-1 in Avista’s WA- ID MSAs. Et-1,US = U.S. growth in non-farm employment in year t-1. D2002 = Dummy for 2002 outlier. εt = Random error term. Avista’s forecast uses Global Insight’s forecasts for U.S. employment growth and in- house forecasts for local employment growth. This approach reflects the statistically 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 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 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 ho u s i n g s t a r t s Spokane MSA Coeur d'Alene MSA Lewiston, ID-WA MSA Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 40 of 1125 Chapter 2: Loads & Resources Avista Corp 2013 Electric IRP 2-9 significant one-year lag between regional and U.S. employment and local population growth rates. Higher or lower employment growth in Avista’s service area relative to the U.S. in time t-1 is associated with higher or lower population growth in time t. The in-house employment forecasts developed using Equation 2.2 are generated through a time-series model linking regional employment growth (the dependent variable) to national GDP growth (the independent variable). As discussed below, this modeling approach can generate high- and low-growth cases for load by altering assumptions about future local employment growth. Weather Forecasts The load forecast uses 30-year monthly temperature averages recorded at the Spokane International Airport weather station through 2012. Several other weather stations are located in Avista’s service territory, but their data is available for much shorter durations and they are highly correlated with the Spokane International Airport data. Avista uses heating degree-days (HDD) to measure cold-weather load sensitivity and cooling degree-days (CDD) to measure hot-weather load sensitivity. The weather normalization process uses regressions of the following form: Equation 2.3: Weather Normalization kWh/Ct,y,s = α0 + α1HDDt,y,s + α2QHDDt,y,s + α3CDDt,y,s + εt,y,s for month t, year y, schedule s Where: kWh/Ct,y,s = Weather normalization. α = Marginal effect of each degree-day type. HDDt,y,s = The HDDs for month t, year y and schedule s. QHDDt,y,s = The coldest HDD months, December through March. CDDt,y,s = The CDDs for month t, year y and schedule s. εt,y,s = Random error term. The estimated regressions are used to produce two predicted values of kWh/Ct,y,s. One estimate uses the actual data to produce kWh/Ct,y,s, measuring usage driven by weather conditions in month ―t‖. This represents the weather-predicted value of usage per customer for month t in year y. The second estimate, kWh/Ct,y,s, reflects the predicted usage per customer for month t in year y, based on the 30-year National Oceanic and Atmospheric Administration average. The difference between the two estimates reflects the deviation of month t weather-driven usage from the usage predicted by long-run degree-days: Equation 2.4: Weather Normalization Adjustment Factor Tt,y,s = Usage predicted by normal weather – Usage predicted by actual weather The deviation Tt,y,s is then added to the actual value of kWh/Ct,y,s to obtain weather normalized usage (WNU). Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 41 of 1125 Chapter 2: Loads & Resources Avista Corp 2013 Electric IRP 2-10 Equation 2.5: Weather Normalized Amount (kWh/Ct,y,s)WNU = kWh/C t,y,s + Tt,y,s Where: (kWh/Ct,y,s)WNU = Weather normalized usage in kWh. kWh/C t,y,s = Actual usage that was observed. Tt,y,s = Weather normalization adjustment factor. If weather conditions in month t are hotter than average (more CDD than average), then the adjustment factor will be negative. When added to kWh/Ct,y,s, WNU will be lower, reflecting an adjustment back to what usage should have been with ―average‖ weather. Use per Customer Projections A database of monthly electricity sales and customer numbers by rate schedule forms the basis of use-per-customer (UPC) forecasts by rate schedule, customer class and state. Historical data is weather-normalized to remove the impact of HDD and CDD deviations from expected normal values, as discussed above. Weather normalized UPC forecasts multiplied by tariff schedule customer forecasts result in a total load forecast. Historical data for Avista’s service area shows that weather normalized UPC in the service area is declining. Figure 2.9 shows annual growth in UPC since 2006. Over this period, the average annual rate of decline in UPC was about 0.5 percent and largely reflected a declining trend in the residential sector. The key factors influencing long-run UPC are: (1) own-price and cross-price elasticity; (2) income elasticity as related to consumer purchases of energy-related goods; (3) conservation programs; and (4) changes in household size. Figure 2.9: Annual Growth in Use per Customer 2006 - 2012 -0.3%-0.4% -1.6%-1.7% 2.3% -0.1% -1.8% -3.0% -2.0% -1.0% 0.0% 1.0% 2.0% 3.0% 2006 2007 2008 2009 2010 2011 2012 pe r c e n t c h a n g e i n u s e p e r cu s t o m e r Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 42 of 1125 Chapter 2: Loads & Resources Avista Corp 2013 Electric IRP 2-11 Retail electricity price increases reduce electricity UPC. Own-price elasticity is an important consideration in any electricity demand forecast because it measures the sensitivity of quantity demanded for a given change in price. A consumer who is sensitive to a price change has a relatively elastic demand profile. A customer who is unresponsive to price changes has a relatively inelastic demand profile. During the 2000-01 Energy Crisis customers displayed increasing price sensitivity and subsequently reduced electricity usage in response to relatively large price changes. Recent research shows that the more in-home information consumers have about electricity usage and costs, the more price sensitive they become.2 Cross-price elasticity measures the relationship between the quantity of electricity demanded and the quantity of potential substitutes (e.g., propane or natural gas for heat) when the price of electricity increases relative to the price of the substitute. A positive cross elasticity coefficient indicates cross-price elasticity between electricity and the substitute. A negative coefficient indicates the absence of cross-price elasticity, and that considered product is not a substitute for electricity, but is instead complementary to it. An increase in the price of electricity increases the use of the complementary good, and a decrease in the price of electricity decreases the use of the complementary good. The principal application of cross elasticity impact in the IRP is its substitutability by natural gas in some applications, including water and space heating. The correlation between retail electricity prices and the commodity cost of natural gas has increased as the industry relies on more natural gas-fired generation to meet loads. This increased positive correlation has reduced the net effect of cross price elasticity between retail natural gas and electricity prices. Income elasticity measures the relationship between a change in consumer income and the change in consumer demand for electricity. As incomes rise, the ability of a consumer to pay for more electricity increases. The ability to afford electricity-related products also increases. As incomes rise, consumers are more likely to purchase more electricity-consuming products that increase UPC, such as larger dwellings, mobile electronic devices, high definition televisions and electric vehicles. However, it also enables them to buy more energy efficient products reducing UPC, including more energy efficient windows and appliances, in addition to rooftop solar photovoltaic cells. Although elasticity plays a key role in customer behavior, estimating elasticity is problematic. Currently Avista lacks sufficient data to estimate elasticity values for its service area. National estimates of elasticity exist; however, for a variety of reasons, there is no guarantee they reflect regional consumer behavior. Elasticity comes in two forms: short-run and long-run. In terms of own-price elasticity, quantity responses are less sensitive to price increases in the short-run because consumers lack sufficient time to implement efficiency programs or find lower cost 2 Jessoe and Rapson (2012), The Short-run and Long-run Effects of Behavioral Interventions: Experimental Evidence from Energy Conservation, NBER working paper 18492. Allcot and Rogers (2012), Knowledge is (Less) Power: Experimental Evidence from Residential Energy Use, NBER work paper 18344. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 43 of 1125 Chapter 2: Loads & Resources Avista Corp 2013 Electric IRP 2-12 substitutes. This is not the case in the long-run, so elasticity should increase as the time for adjustment increases. For example, the Energy Information Administration currently uses a value of -0.3 for short-run own-price elasticity for residential electricity, accounting for the ―…successful deployment of smart grid projects funded under the American Recovery and Reinvestment Act of 2009.‖3 However, the Energy Information Administration estimates long-run elasticity ranges from -0.04 to -1.45.4 Recent research (Arimura, Li, Newell, and Palmer, 2011) indicates that conservation programs reduce long-run residential usage.5 However, empirical problems arise when estimating the impact of energy efficiency on load. These programs affect historical data; therefore, the forecast already contains the impacts of existing conservation levels. However, Avista is currently working with the EnerNOC consulting group to estimate energy efficiency savings. Future IRPs will address a more concrete empirical estimate on the impact of energy efficiency programs to avoid double counting. Figure 2.10 shows average household size in Avista’s electric service area since 1990. The size has fallen to 2.5 people per household or about 2 percent smaller than in 1990. The forecast is for average household size to stay below the current level through 2035. Figure 2.10: Area Average Household Size, Historical and Forecast 1990-2035 3 See U.S. Energy Information Administration, Assumptions to the Annual Energy Outlook 2012, Residential Demand Module, p. 32. 4 See U.S. Energy Information Administration, Working Memorandum from George Lady, NEMS Price Elasticities of Demand for Residential and Commercial Energy Use, Table 2, p. 4. 5 Arimura, Li, Newell, and Palmer (2011), Cost-effectiveness of Electricity Energy Efficiency Programs, NBER working paper 17556. 2.42 2.44 2.46 2.48 2.50 2.52 2.54 2.56 2.58 2.60 19 9 0 19 9 2 19 9 4 19 9 6 19 9 8 20 0 0 20 0 2 20 0 4 20 0 6 20 0 8 20 1 0 20 1 2 20 1 4 20 1 6 20 1 8 20 2 0 20 2 2 20 2 4 20 2 6 20 2 8 20 3 0 20 3 2 20 3 4 av e r a g e h o u s e h o l d S i z e Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 44 of 1125 Chapter 2: Loads & Resources Avista Corp 2013 Electric IRP 2-13 Residential use accounts for 88 percent of customers and 40 percent of load, the factors discussed above impact the long-run trend UPC as follows: Equation 2.6: Use per Customer UPC Trend = ƒ(long- and short-run price and income elasticity, conservation programs, household size, long-run weather factors) Rather than modeling each piece on the right side of Equation 2.6, the forecast attempts to model the long-run UPC trend as a whole using historical UPC data. An analysis of data since 2005 shows the UPC can be modeled using a linear trend in the residential forecast. This trend is alongside other explanatory variables related to heating and cooling degree-days. Future forecast models will explicitly include variables that influence UPC trends, such as household size, price and consumer income. Besides long-run potential climate change, the only individual component related in Equation 2.6 explicitly considered is the adoption of electric vehicles in Avista’s service area. The 2013 IRP electric vehicle adoption scenario is half of the 2011 IRP forecast. This revision reflects evidence indicating the adoption of electric vehicles is occurring at a slower pace than previously expected. The electric vehicle fleet is a combination of plug-in hybrids and electric-only passenger vehicles. The 2011 IRP forecast of electric vehicles utilized the Northwest Power and Conservation Council’s (NPCCs) forecast from the Sixth Northwest Conservation and Power Plan.6 The slow rate of electric vehicle adoption in Avista’s service area likely coincides to the service area’s post- recession employment recovery (discussed above), including a 10 percent decline in inflation-adjusted median household income since 2007, and the continued high price of electric vehicles relative to traditional alternatives. One forecast shown in Figure 2.11 assumes the long-run UPC will continue to decline until 2028 when it could slowly increase due to electric vehicle adoption. The other forecast is the no-electric vehicle case where they are not widely adopted. Here, UPC continues to decline, but more slowly after 2028. Given current electric vehicle adoption rates, the no-electric vehicle case seems more likely. 6 http://www.nwcouncil.org/energy/powerplan/6/plan/ Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 45 of 1125 Chapter 2: Loads & Resources Avista Corp 2013 Electric IRP 2-14 Figure 2.11: Residential Use per Customer, 2006-2035 Customer Forecast Table 2.3 shows the historical correlation of year-over-year customer growth across the four main customer groups: residential, commercial, industrial and streetlights. The correlation between residential and commercial is high, meaning forecasted growth rates should behave similarly. As a result, both the residential and commercial groups correlate to population growth. Industrial and streetlights change very slowly; so these forecasts use simple trending and smoothing methods. Table 2.3: Customer Growth Correlations, January 2006-December 2012 Customer Class (Year-over-Year) Residential, Year-over- Year Commercial, Year-over- Year Industrial, Year-over- Year Streetlights, Year-over- Year Residential 1 Commercial 0.899 1 Industrial -0.320 -0.169 1 Streetlights -0.246 -0.205 0.280 1 To reproduce the high correlation between residential and commercial customers in the forecast, the residential customer forecast is used as a driver for the commercial forecast. This is done by regressing past commercial customer changes against past residential customer changes, as shown in Equation 2.7. Using the estimated equation, 8,000 9,000 10,000 11,000 12,000 13,000 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 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 20 3 5 ki l o w a t t -ho u r s Residential UPC, with Electric Vehicles Residential UPC, without Electric Vehicles Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 46 of 1125 Chapter 2: Loads & Resources Avista Corp 2013 Electric IRP 2-15 forecasted customer changes are inserted to generate the forecasted change in commercial customers. Equation 2.7: Customer Forecast ∆Ct,commerical = α0 + α1∆Ct,residential + εt, Where: α0 = Intercept value of the estimated equation. ∆Ct,commerical = Change in Avista’s total commercial electric customers from year t to year t-1 (annual numbers are 12-month averages). ∆Ct,residential = Change in Avista’s total residential electric customers from year t to year t-1 (annual numbers are 12-month averages). εt = Random error term. In aggregate, average annual customer growth is 1.1 percent out to 2035, with residential and commercial driving most of the growth at 1.1 percent annually. Industrial growth is 0.3 percent annually. The aggregate growth forecast is considerably below the pre-Great Recession growth rate of 1.6 percent. See Figure 2.12. Figure 2.12: Avista’s Customer Growth, 1997-2033 Native Load Forecast Retail sales provide the data used to project future loads. Retail sales translate into average megawatt hours (aMW) using a regression model ensuring monthly load shapes conform to history. The load forecast is a retail sales forecast combined with line 200,000 250,000 300,000 350,000 400,000 450,000 500,000 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 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 to t a l c u s t o m e r s Street Lights Industrial Commerical Residential Average Annual Growth 1997-2007 = 1.6% Average Annual Growth 2007- 2012 = 0.8% Average Annual Growth 2012- 2035= 1.1% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 47 of 1125 Chapter 2: Loads & Resources Avista Corp 2013 Electric IRP 2-16 losses incurred in the delivery of electricity across Avista’s transmission and distribution systems. Figure 2.13 presents annual net native load growth. Note the significant drop in the 2000-01 Western Energy Crisis and smaller declines in the Great Recession. Annual growth averages 1 percent through 2035. Figure 2.13: Native Load History and Forecast, 1997-2035 Peak Demand Forecast The energy or load forecast is important to the development of the IRP because retail sales growth drives many future system costs. When planning to meet the needs of all of Avista’s customers, a forecast of peak demand is also crucial to determine the need for new capacity. In other words, Avista must not only meet the energy needs of its customers, but also have enough capacity to meet demands in its highest load hour. Avista’s typical peak hour is in the winter months, between November and early February. Recent warm winters, hot summers and added air conditioning load have created some summer months where loads were higher than the winter. This phenomenon has transformed Avista into a dual peaking utility. Even though summer peaks may be higher than winter, Avista still expects to have its highest electricity load in the winter. Avista’s peak load forecast began by normalizing historical data to set a base peak level adjusted for temperatures. After the adjustment, peak loads trend with economic factors similar to the energy forecast. Normalizing base peak loads begins with adjusting the 2012 peak for temperature variation from normal. Using daily peak load data for 24 months an econometric model isolates the relationship between load and temperatures, 600 800 1,000 1,200 1,400 1,600 19 9 7 19 9 9 20 0 1 20 0 3 20 0 5 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 20 2 7 20 2 9 20 3 1 20 3 3 20 3 5 En e r g y ( a M W ) Average Annual Growth 2012- 2035 = 1% Average Annual Growth 1997- 2007= 1.6% Average Annual Growth 2007- 2012 = 0% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 48 of 1125 Chapter 2: Loads & Resources Avista Corp 2013 Electric IRP 2-17 day of the week, holidays, school days, season and other factors. These relationships are normalized using a 123-year average of historical Spokane temperatures. For the winter forecast, the coldest day of each year is averaged to determine the base planning temperature.7 For the summer, the same process is used but for the hottest day. In the winter the average coldest day is 3.9 degrees Fahrenheit, the coldest temperature on record was -17 degrees on December 30, 1968. Avista last saw an extreme winter peak temperature in 2004 with a -9 degrees day average. For summer peak planning, the average hottest day (average of daily high and low temperature) is 82.3 degrees. The hottest average day on record is 90 degrees on July 27, 1928. Avista’s last extreme summer temperature was 86 degrees in 2008. See Table 2.4 for details. One caution using the average of extreme annual temperatures is the extreme temperature may land on a Friday, weekend, or on a holiday, the extreme temperature is not going to have a large impact on peak load these days. This base forecast weights the days of the week to reflect the average temperature given extreme temperatures can happen on any given day. Table 2.4: Average Day Spokane Temperatures 1890-2012 (Degrees Fahrenheit) Customer Class Coldest Day Hottest Day Extreme -17.0 90.0 Average 3.9 82.3 Standard Deviation 8.9 2.8 90th Percentile -8.8 86.0 Recent Extreme Temperatures 2004: -9.0 2008: 86.0 Using the normalized base peak levels from 2012, the peak load forecast uses an econometric model relying on GDP growth as its primary driver, similar to the energy forecast. With this regression relationship, peak load growth is simulated using assumptions about future GDP growth. GDP growth out to 2017 was set at the average of multiple forecast sources.8 Using this average shapes the near term impacts of the business cycle on peak load growth. From 2018-35 the long-run GDP growth was 2.5 percent. This analysis resulted in a 20-year peak growth rate of 0.84 percent in the winter and a 0.90 percent growth rate in the summer. Figure 2.14 illustrates these growth levels compared to historical peaks for both summer and winter (other monthly peaks are developed but not shown). Avista’s all-time native load peak was in 2009 with peak loads at 1,821 MW, on this day the average temperature reached -7 degrees. The historical summer peak occurred in July 2006 when average temperatures reached 87 degrees. The historical winter and summer annual average growth rates between 1997 and 2012 were 0.85 and 1.0 percent, respectively. The forecast peaks represent an 7 The coldest day based on the average of daily high and low temperatures. 8 The forecast sources are the U.S. Federal Reserve, Bloomberg’s survey of forecasters, Reuter’s survey of forecasters, The Economist’s survey of forecasters, Global Insight, Economy.com, Blue Chip consensus forecast. Averaging these sources reduces the systematic forecast error that can arise from using a single source forecast. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 49 of 1125 Chapter 2: Loads & Resources Avista Corp 2013 Electric IRP 2-18 expected peak level given average extreme temperatures; actual peak loads are expected to deviate from this forecast. Avista resources meet the deviated peak loads first, and market purchases meet the remaining peak loads.9 Figure 2.14: Winter and Summer Peak Demand, 1997-2035 High and Low Load Growth Cases Avista produces high and low load forecasts to test the PRS. These forecasts are very difficult to create because many factors influence the outcome. In past IRPs, Avista used ranges from the NPCC’s Sixth Power Plan as a guide. This IRP relies on this basic relationship to derive the high and low load growth rates: Equation 2.8: Long Run Load to Customer Relationship % change in load ≈ % change in customers + % change in UPC.10 Recalling the discussion above, population growth approximates long-run customer growth, and population growth approximates employment growth. Therefore using Equation 2.2 to simulate population growth should be under differing assumptions of regional employment growth, holding U.S. employment and UPC growth rates constant. Avista uses this method to forecast alternative load growth cases. The low case 9 Avista maintains a 14 percent planning margin above these peak levels, and operating reserves. 10 Since UPC = load/customers, calculus shows that the annual percentage change UPC ≈ percentage change in load - percentage change in customers. Rearranging terms, we have, the annual percentage change in load ≈ percentage change in customers + percentage change in UPC. - 500 1,000 1,500 2,000 2,500 19 9 7 19 9 9 20 0 1 20 0 3 20 0 5 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 20 2 7 20 2 9 20 3 1 20 3 3 20 3 5 me g a w a t t s Winter Summer Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 50 of 1125 Chapter 2: Loads & Resources Avista Corp 2013 Electric IRP 2-19 assumes regional employment growth averages 0.5 percent out to 2035; the high- growth case assumes 2.5 percent. Figure 2.15 shows the results of these assumptions. Figure 2.15 also shows the U.S. baseline forecast from the Energy Information Administration and a low-medium forecast uses Global Insight’s base-line forecasts for employment growth to forecast population growth. Figure 2.15: Load Growth Scenarios, 2014-2035 Voluntary Renewable Energy Program (Buck-A-Block) Since 2002, Avista has offered customers the opportunity to purchase renewable energy voluntarily as part of their utility billing process. Customers currently can purchase 300 kWh blocks for $1.00 to meet their personal renewable energy goals. This program is rate neutral and funded by participating customers. Avista’s 35 MW share of the Stateline Wind project supplies most of the program through March 2014. Along with the wind energy, the purchase agreement includes renewable energy credits. The current mix of renewable credits used by Buck-A-Block customers is 85 percent from wind, 14.8 percent from biomass and the remaining 0.2 percent from the 15 kW Rathdrum Solar project (see Figure 2.16). Since inception, participants purchased an average of 8.1 aMW of renewable energy through the Buck-A-Block program. Figure 2.17 shows the growth of customers and purchased energy in the program. After initial growth in the program, purchases leveled off in 2008 at just over 8.0 aMW per year. 0.0% 0.4% 0.8% 1.2% 1.6% 2.0% 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 20 3 5 lo a d g r o w t h p e r c e n t c h a n g e Low Growth High Growth Medium-Low EIA Forecast Expected Growth Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 51 of 1125 Chapter 2: Loads & Resources Avista Corp 2013 Electric IRP 2-20 Figure 2.16: 15 kW Photovoltaic Installation in Rathdrum, ID Figure 2.17: Buck-A-Block Customer and Demand Growth Customer-Owned Generation A small but growing number of customers continue to install their own generation at an increasing pace. In 2007 and 2008, the average new net-metering customers were 10, and between 2009 and 2012, the average increased to 38 per year, likely in response to generous federal and state tax incentives. These projects qualify for the federal government’s 30 percent tax credit and in the state of Washington, customer-owned projects can qualify for additional tax incentives of up to $5,000 per year. The quantity of generation each year through 2020 determines the amount of incentives paid. The Washington state utility taxes credit finances the incentives. Solar projects can qualify for total incentives worth up to $0.54 per kWh with solar panels and inverters manufactured in Washington. All other customer-owned generation receives a minimum 0.7 2.9 5.8 6.4 7.6 8.1 8.1 8.2 8.6 8.3 0 1,000 2,000 3,000 4,000 5,000 0.0 2.0 4.0 6.0 8.0 10.0 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 cu s t o m e r s av e r a g e m e g a w a t t s aMW Customers Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 52 of 1125 Chapter 2: Loads & Resources Avista Corp 2013 Electric IRP 2-21 payment of $0.12 per kWh, increasing depending upon the manufacturing location of the installed equipment. At this time, 190 customers have installed net-metered generation equipment for a total of 1.1 MW of capacity. This level equals approximately 0.5 percent of Avista’s generation capacity. Eighty percent of the installations are in Washington, with most in Spokane County. Figure 2.18 shows annual net metering customer additions. Solar is 83 percent of net metered technology; the remaining is a mix of wind, combined solar and wind systems, and biogas. The average annual capacity factor of the solar facilities is 13 percent. Small wind turbines typically produce less than a 10 percent capacity factor depending on location. At current tax incentive levels, the number of new net- metered systems will continue at their current pace or may even increase. Where tax subsidies end without a significant reduction in technology cost, the interest in net metering likely will return to pre-tax incentive levels. If the number of net-metering customers continues to increase, Avista may need to adjust rate structures for customers who rely on the utility’s infrastructure but do not contribute financially for infrastructure costs. Figure 2.18: Net Metering Customers The reason for increased interest in customer-owned generation may have more to do with economics than environmental benefits. Figure 2.19 shows how current government subsidies make solar energy attractive to customers. This example uses a 0.0 0.3 0.6 0.9 1.2 1.5 0 10 20 30 40 50 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 cu m u l a t i v e c a p a c i t y ( M W ) an n u a l n e w c u s t o m e r s ID WA Cumulative Capacity (MW) 290 customers through first quarter 2013 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 53 of 1125 Chapter 2: Loads & Resources Avista Corp 2013 Electric IRP 2-22 5 kW system at $7,000 per kW, or a $35,000 total installation cost.11 The cost without government assistance is 80 cents per kWh, roughly ten times Avista’s retail electricity rate. The federal tax Investment Tax Credit (ITC) and favorable federal depreciation rules transfers up to 42 cents per kWh from the system owner to taxpayers. Washington state picks up an additional 12 to 54 cents per KWh. With combined federal and state subsidies, a customer has the potential to install ―made in Washington‖ panels and inverters and have not only its entire costs paid for, but also make a profit and receive free energy. Given these generous incentives, the potential exists for additional net metering customers on Avista’s system, especially where present funding is limited under RCW 82.16.130 to the lesser of 0.5 percent of taxable power sales or $100,000. Figure 2.19: Solar Energy Transfer Payments Avista Resources and Contracts Avista relies on a diverse portfolio of generating assets to meet customer loads, including owning and operating eight hydroelectric developments located on the Spokane and Clark Fork rivers. Avista’s thermal assets include partial ownership of two coal-fired units in Montana, five natural gas-fired projects, and a biomass plant located near Kettle Falls, Washington. 11 A higher cost of solar is used to represent the costs of panels and inverters manufactured in Washington with typically higher installation costs to illustrate the costs/benefits of the ―made in Washington‖ Renewable Energy Systems Cost Recovery Incentive Payments. ProfitState Incentive State Incentive Federal Depr Federal Depr Federal Depr Federal ITC Federal ITC Federal ITC Cost Cost Cost -125 ¢/kWh -100 ¢/kWh -75 ¢/kWh -50 ¢/kWh -25 ¢/kWh ¢/kWh 25 ¢/kWh 50 ¢/kWh 75 ¢/kWh 100 ¢/kWh No Subsidies With Fed. Incentives With Fed. and WA State Incentives (Low) With Fed. and WA State Incentives (High) 0 Avista Retail Rate Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 54 of 1125 Chapter 2: Loads & Resources Avista Corp 2013 Electric IRP 2-23 Spokane River Hydroelectric Developments Avista owns and operates six hydroelectric developments on the Spokane River. Five of these developments received a new 50-year FERC operating license in June 2009. The following section describes the Spokane River developments and provides the maximum on-peak capacity and nameplate capacity ratings for each plant. The maximum on-peak capacity of a generating unit is the total amount of electricity a plant can safely generate. This is often higher than the nameplate rating for hydroelectric developments. The nameplate, or installed capacity, is the capacity of a plant as rated by the manufacturer. All six of the hydroelectric developments on the Spokane River connect to Avista’s transmission system. Post Falls Post Falls is the most upstream hydroelectricity facility on the Spokane River. It is located several miles east of the Washington/Idaho border. The development began operating in 1906, and during summer months maintains the elevation of Lake Coeur d’Alene. The development has six units, with the last unit added in 1980. Post Falls has a 14.75 MW nameplate rating and is capable of producing 18.0 MW. Upper Falls The Upper Falls development began generating in 1922 in downtown Spokane, and now is within the boundaries of Riverfront Park. This project is comprised of a single 10.0 MW nameplate unit with a 10.26 MW maximum capacity rating. Monroe Street Monroe Street was Avista’s first generation development. It began serving customers in 1890 near what is now Riverfront Park. Rebuilt in 1992, the single generating unit has a 14.8 MW nameplate rating and a 15.0 MW maximum capacity rating. Nine Mile A private developer built the Nine Mile development in 1908 near Nine Mile Falls, Washington, nine miles northwest of Spokane. Avista (then Washington Water Power) purchased the project in 1925 from the Spokane & Inland Empire Railroad Company. Its four units have a 26.4 MW nameplate rating and 17.6 MW maximum capacity rating.12 A new hydraulic control system was installed in 2010, replacing the original flashboard system that maintained full pool conditions seasonally. Nine Mile is currently undergoing substantial multi-year upgrades. Nine Mile Units 1 and 2 upgrades to two 8 MW generators/turbines, replace both existing 3 MW units. Once operational in 2016, the new units will add 1.4 aMW of energy beyond the original configuration and 6.4 MW of capacity above current generation levels. In addition to these capacity upgrades, the facility will receive upgrades to the hydraulic governors, static excitation system, switchgear, station service, control and protection packages, ventilation upgrades, rehabilitation of intake gates and sediment bypass system, and 12 This is the de-rated capacity considering the outage of Nine Mile Unit 1 and de-rate of Unit 2. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 55 of 1125 Chapter 2: Loads & Resources Avista Corp 2013 Electric IRP 2-24 other investments. The fall 2013 Unit 4 overhaul includes new turbine runners, thrust bearings, and operating system. Avista plans to overhaul Unit 3 in 2018-19. Long Lake The Long Lake development is located northwest of Spokane and maintains the Lake Spokane reservoir, also known as Long Lake. The plant received new runners in the 1990s, adding 2.2 aMW of additional energy. The project’s four units have an 81.6 MW nameplate rating and provide 88.0 MW of combined capacity. Little Falls The Little Falls development, completed in 1910 near Ford, Washington, is the furthest downstream hydro facility on the Spokane River. A new runner upgrade in 2001 generates 0.6 aMW more energy. The facility’s four units generate 35.2 MW of on-peak capacity and have a 32.0 MW nameplate rating. Avista is carrying out a series of upgrades to the Little Falls development. Much of the new electrical equipment and the installation of a new generator excitation system are complete. Current projects include replacing station service equipment, updating the powerhouse crane, and developing new control schemes and panels. After the preliminary work is completed, replacing generators, turbines, and unit protection and control systems on the four units will start. Clark Fork River Hydroelectric Developments The Clark Fork River Developments includes hydroelectric projects located near Clark Fork, Idaho, and Noxon, Montana, 70 miles south of the Canadian border. The plants operate under a FERC license through 2046. Both hydroelectric projects on the Clark Fork River connect to Avista’s transmission system. Cabinet Gorge The Cabinet Gorge development started generating power in 1952 with two units. The plant added two additional generators the following year. The current maximum on-peak capacity of the plant is 270.5 MW; it has a nameplate rating of 265.2 MW. Upgrades at this project began with the replacement of the Unit 1 turbine in 1994. Unit 3 received an upgrade in 2001. Unit 2 received an upgrade in 2004. Unit 4 received a turbine runner upgrade in 2007. Noxon Rapids The Noxon Rapids development includes four generators installed between 1959 and 1960, and a fifth unit added in 1977. Avista recently completed a major turbine upgrade, with Units 1 through 4 receiving new runners between 2009 and 2012. The upgrades increased the capacity of each unit from 105 MW to 112.5 MW and added a total of 6.6 aMW of EIA qualified energy. Total Hydroelectric Generation In total, Avista’s hydroelectric plants have 1,065.4 MW of on-peak capacity. Table 2.5 summarizes the location and operational capacities of Avista’s hydroelectric projects. This table includes the expected energy output of each facility based on the 70-year hydrologic record for the year ending 2012. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 56 of 1125 Chapter 2: Loads & Resources Avista Corp 2013 Electric IRP 2-25 Table 2.5: Avista-Owned Hydro Resources Project Name River System Location Nameplate Capacity (MW) Maximum Capability (MW) Expected Energy (aMW) Monroe Street Spokane Spokane, WA 14.8 15.0 11.6 Post Falls Spokane Post Falls, ID 14.8 18.0 10.0 Nine Mile Spokane Nine Mile Falls, WA 26.0 17.5 12.5 Little Falls Spokane Ford, WA 32.0 35.2 22.1 Long Lake Spokane Ford, WA 81.6 89.0 53.4 Upper Falls Spokane Spokane, WA 10.0 10.2 7.5 Cabinet Gorge Clark Fork Clark Fork, ID 265.2 270.5 124.8 Noxon Rapids Clark Fork Noxon, MT 518.0 610.0 198.3 Total 962.4 1,065.4 440.2 Thermal Resources Avista owns seven thermal generation assets located across the Northwest. Based on IRP analysis, Avista expects each plant to continue operation through the 20-year IRP planning horizon. The resources provide dependable energy and capacity to serve base loads and provide peak load-serving capabilities. A summary of Avista thermal resources is in Table 2.6. Colstrip Units 3 and 4 The Colstrip plant, located in Eastern Montana, consists of four coal-fired steam plants connected to the double circuit 500 kV BPA transmission line under a long-term wheeling agreement. PPL Global operates the facilities on behalf of the six owners. Avista owns 15 percent of Units 3 and 4. Unit 3 began operating in 1984 and Unit 4 was finished in 1986. Avista’s share of Colstrip Units 3 and 4 has a maximum net capacity of 111.0 MW, and a nameplate rating of 123.5 MW per unit. Avista has no ownership interests in Colstrip Unites 1 and 2. Rathdrum Rathdrum consists of two simple-cycle combustion turbine units. This natural gas-fired plant is located near Rathdrum, Idaho and connects to Avista’s transmission system. It entered service in 1995 and has a maximum capacity of 178.0 MW in the winter and 126.0 MW in the summer. The nameplate rating is 166.5 MW. Northeast The Northeast plant, located in Spokane, is two aero-derivative simple-cycle units completed in 1978 and connects to Avista’s transmission system. The plant is capable of burning natural gas or fuel oil, but current air permits preclude the use of fuel oil. The combined maximum capacity of the units is 68.0 MW in the winter and 42.0 MW in the summer, with a nameplate rating of 61.2 MW. The plant is currently limited to run no more than approximately 550 hours per year. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 57 of 1125 Chapter 2: Loads & Resources Avista Corp 2013 Electric IRP 2-26 Boulder Park The Boulder Park project entered service in Spokane Valley in 2002 and connects to Avista’s transmission system. The site uses six natural gas-fired internal combustion reciprocating engines to produce a combined maximum capacity and nameplate rating of 24.6 MW. Coyote Springs 2 Coyote Springs 2 is a natural gas-fired combined cycle combustion turbine located near Boardman, Oregon. This plant connects to BPA’s 500 kV transmission system under a long-term transmission agreement. The plant began service in 2003. Its maximum capacity is 274 MW in the winter and 221 MW in the summer with a duct burner providing additional capacity of up to 28 MW. The plant’s nameplate rating is 287.3 MW. Avista is in the process of upgrading Coyote Springs 2. Upgrades include cooling optimization and cold day controls. The 2011 IRP process studied both of these updates. The cold day controls remove firing temperature suppression that occurs when ambient temperatures are below 60 degrees. The upgrade improves the heat rate by 0.5 percent and output by approximately 2.0 MW during cold temperature operations. The cooling optimization package improves compressor and natural gas turbine efficiency, resulting in an overall increase in plant output of 2.0 MW. In addition to these upgrades, Coyote Springs 2 now has a Mark VIe control upgrade, a new digital front end on the EX2100 gas turbine exciter, and model-based control with enhanced transient capability. Each of these projects allows Avista to maintain high reliability, reduce future O&M costs, improve our ability to maintain compliance with WECC reliability standards, and help prevent damage that might occur to the machine when electrical system disturbances occur. Kettle Falls Generation Station and Kettle Falls Combustion Turbine The Kettle Falls Generating Station, a biomass facility, entered service in 1983 near Kettle Falls, Washington. It is among the largest biomass plants in North America and connects to Avista’s 115 kV transmission system. The open-loop biomass steam plant uses waste wood products from area mills and forest slash, but can also burn natural gas. A combustion turbine (CT), added to the facility in 2002, burns natural gas and increases overall plant efficiency by sending exhaust heat to the wood boiler. The wood-fired portion of the plant has a maximum capacity of approximately 50.0 MW, and its nameplate rating is 50.7 MW. The plant typically operates between 45 and 47 MW because of fuel conditions. The plant’s capacity increases to 57.0 MW when operated in combined-cycle mode with the CT. The CT produces 8 MW of peaking capability in the summer and 11 MW in the winter. The CT resource is limited in winter when the natural gas pipeline is capacity constrained; for IRP modeling, the CT does not run when temperatures fall below zero and natural gas pipeline capacity is assumed to serve local natural gas distribution demand. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 58 of 1125 Chapter 2: Loads & Resources Avista Corp 2013 Electric IRP 2-27 Table 2.6: Avista-Owned Thermal Resources Colstrip 3 (15%) Colstrip, MT Coal 1984 111.0 111.0 123.5 Colstrip 4 (15%) Colstrip, MT Coal 1986 111.0 111.0 123.5 Rathdrum Rathdrum, ID Gas 1995 178.0 126.0 166.5 Northeast Spokane, WA Gas 1978 68.0 42.0 61.2 Boulder Park Spokane, WA Gas 2002 24.6 24.6 24.6 Coyote Springs 2 Boardman, OR Gas 2003 312.0 251.0 290.0 Kettle Falls Kettle Falls, WA Wood 1983 47.0 47.0 50.7 Kettle Falls CT13 Kettle Falls, WA Gas 2002 11.0 8.0 7.5 Power Purchase and Sale Contracts Avista utilizes power supply purchase and sale arrangements of varying lengths to meet a portion of its load requirements. This chapter describes the contracts in effect during the scope of the 2013 IRP. Contracts provide many benefits, including environmentally low-impact and low-cost hydro and wind power. A 2012 annual summary of Avista’s large contracts is in Table 2.7. Mid-Columbia Hydroelectric Contracts During the 1950s and 1960s, Public Utility Districts (PUDs) in central Washington developed hydroelectric projects on the Columbia River. Each plant was large when compared to loads then served by the PUDs. Long-term contracts with public, municipal, and investor-owned utilities throughout the Northwest assisted with project financing, and ensured a market for the surplus power. The contract terms obligate the PUDs to deliver power to Avista points of interconnection. Avista entered into long-term contracts for the output of four of these projects ―at cost.‖ Later, Avista competed in capacity auctions in 2009 through 2013 to purchase new short-term contracts at market-based prices. The Mid-Columbia contracts in Table 2.7 provide energy, capacity, and reserve capabilities; in 2014, the contracts provide approximately 127 MW of capacity and 76 aMW of energy. Over the next 20 years the Douglas PUD (2018) and Chelan PUD (2014) contracts will expire. Avista may extend these contracts or even gain additional capacity in auctions; however, we have no assurance that we will successfully extend our contract rights. Due to this uncertainty around future availability and cost, the IRP does not include these contracts in the resource mix beyond their expiration dates. The timing of the power received from the Mid-Columbia projects is also a result of agreements including the Columbia River Treaty signed in 1961 and the Pacific 13 The Kettle Falls CT numbers include output of the gas turbine plus the benefit of its steam to the main unit’s boiler. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 59 of 1125 Chapter 2: Loads & Resources Avista Corp 2013 Electric IRP 2-28 Northwest Coordination Agreement (PNCA) signed in 1964. Both agreements optimize hydro project operations in the Northwest United States and Canada. In return for these benefits, Canada receives return energy (Canadian Entitlement). The Columbia River Treaty and the PNCA call for storage water in upstream reservoirs for coordinated flood control and power generation optimization. On September 16, 2024, given a minimum of 10 years written advance notice, the Columbia River Treaty may end. Studies are underway by U.S. and Canadian entities to determine possible post-2024 Columbia River operations. Federal agencies are soliciting feedback from stakeholders and soon negotiations will begin in earnest to decide whether the current treaty will continue, should be ended, or if a new agreement will be struck. This IRP does not model potential alternative outcomes regarding the treaty negotiation, as it is not expected to impact long-term resource acquisition and we cannot speculate on future wholesale electricity market impacts of the treaty. Table 2.7: Mid-Columbia Capacity and Energy Contracts Counter Party Project(s) Percent Share (%) Start Date End Date Estimated On-Peak Capability (MW) Annual Energy (aMW) Grant PUD Priest Rapids 3.7 Dec-01 Dec-52 28.2 16.7 Grant PUD Wanapum 3.7 Dec-01 Dec-52 31.0 17.9 Chelan PUD Rocky Reach 3.0 Jul-11 Dec-14 34.5 21.0 Chelan PUD Rock Island 3.0 Jul-11 Dec-14 13.9 10.7 Douglas PUD Wells 3.3 Feb-65 Aug-18 27.9 14.7 Canadian Entitlement -8.1 -4.6 2014 Total Net Contracted Capacity and Energy 127.4 76.4 2015 Total Net Contracted Capacity and Energy 81.9 46.3 Lancaster Power Purchase Agreement Avista acquired the output rights to the Lancaster combined-cycle generating station, located in Rathdrum, Idaho, as part of the sale of Avista Energy in 2007. Lancaster presently connects to the BPA transmission system under a long-term wheeling agreement, but Avista is working with the federal agency to interconnect the plant directly with Avista’s transmission system at the BPA Lancaster substation. Avista has the sole right to dispatch the plant, and is responsible for providing fuel and energy and capacity payments, under a tolling contract expiring in October 2026. Public Utility Regulatory Policies Act (PURPA) In 1978, Congress passed PURPA requiring utilities to purchase power from Independent Power Producers (IPPs) meeting certain criteria depending on their size and fuel source. Over the years, Avista has entered into many such contracts. Current PURPA contracts are in Table 2.8. Avista will renegotiate many of these contracts after the term of the current contract has ended. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 60 of 1125 Chapter 2: Loads & Resources Avista Corp 2013 Electric IRP 2-29 Table 2.8: PURPA Agreements Contract Owner Fuel Source Location End Date Size (MW) Annual Energy (aMW) Meyers Falls Hydro Technology Systems Inc Hydro Kettle Falls, WA 12/2013 1.30 1.05 Fighting Creek Landfill Gas to Energy Station Kootenai Electric Cooperative Municipal Waste Coeur d’Alene, ID 12/2013 3.20 1.31 Spokane Waste to Energy City of Spokane Municipal Waste Spokane, WA 11/2014 18.00 16.00 Spokane County Digester Spokane County Municipal Waste Spokane, WA 8/2016 0.26 0.14 Plummer Saw Mill Stimson Lumber Wood Waste Plummer, ID 11/2016 5.80 4.00 Deep Creek Deep Creek Energy Hydro Northpoint, WA 12/2016 0.41 0.23 Clark Fork Hydro James White Hydro Clark Fork, ID 12/2017 0.22 0.12 Upriver Dam14 City of Spokane Hydro Spokane, WA 12/2019 17.60 6.17 Sheep Creek Hydro Sheep Creek Hydro Inc Hydro Northpoint, WA 6/2021 1.40 0.79 Ford Hydro LP Ford Hydro Ltd Partnership Hydro Weippe, ID 6/2022 1.41 0.39 John Day Hydro David Cereghino Hydro Lucille, ID 9/2022 0.90 0.25 Phillips Ranch Glenn Phillips Hydro Northpoint, WA n/a 0.02 0.01 Total 50.52 30.45 Bonneville Power Administration – WNP-3 Settlement Avista signed settlement agreements with BPA and Energy Northwest on September 17, 1985, ending construction delay claims against both parties. The settlement provides an energy exchange through June 30, 2019, with an agreement to reimburse Avista for WPPSS – Washington Nuclear Plant No. 3 (WNP-3) preservation costs and an irrevocable offer of WNP-3 capability under the Regional Power Act. The energy exchange portion of the settlement contains two basic provisions. The first provision provides approximately 42 aMW of energy to Avista from BPA through 2019, subject to a contract minimum of 5.8 million megawatt-hours. Avista is obligated to pay BPA operating and maintenance costs associated with the energy exchange as determined by a formula that ranges from $16 to $29 per megawatt-hour in 1987-year constant dollars. 14 Energy estimate is net of pumping load. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 61 of 1125 Chapter 2: Loads & Resources Avista Corp 2013 Electric IRP 2-30 The second provision provides BPA approximately 32 aMW of return energy at a cost equal to the actual operating cost of Avista’s highest-cost resource. A further discussion of this obligation, and how Avista plans to account for it, is under the Energy Planning section. Palouse Wind – Power Purchase Agreement Avista signed a 30-year power purchase agreement in 2011 with Palouse Wind for the entire output of the 105 MW project. Avista has the option to purchase the project after year 10 of the contract. Commercial operation began in December 2012. The project is EIA qualified and directly connected to Avista’s transmission system. Table 2.9: Other Contractual Rights and Obligations Contract Type Fuel Source End Date Winter Capacity (MW) Summer Capacity (MW) Annual Energy (aMW) Stateline Purchase Wind 3/2014 0 0 9 Sacramento Municipal Utility District Sale System 12/2014 -50 -50 -50 PGE Capacity Exchange Exchange System 12/2016 -150 -150 0 Douglas Settlement Purchase Hydro 9/2018 2 2 3 WNP-3 Purchase System 6/2019 82 0 42 Lancaster Purchase Natural Gas 10/2026 290 249 222 Palouse Wind Purchase Wind 12/2042 0 0 40 Nichols Pumping Sale System n/a -1 -1 -1 Total 173 50 265 Reserve Margins Planning reserves accommodate situations when loads exceed and/or resource outputs are below expectations due to adverse weather, forced outages, poor water conditions, or other contingencies. There are disagreements within the industry on reserve margin levels utilities should carry. Many disagreements stem from system differences, such as resource mix, system size, and transmission interconnections. Reserve margins, on average, increase customer rates when compared to resource portfolios without reserves because of the additional cost of carrying additional generating capacity that is rarely used. Reserve resources have the physical capability to generate electricity, but high operating costs limit their economic dispatch and revenues. Avista Planning Margin Avista retains two planning margin targets—capacity and energy. Capacity planning is the traditional metric ensuring utilities can meet peak loads at times of system strain, and cover variability inherent in their generation resources with unpredictable fuel supplies, such as wind and hydro, and varying loads. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 62 of 1125 Chapter 2: Loads & Resources Avista Corp 2013 Electric IRP 2-31 Capacity Planning Utility capacity planning begins with regional planning. Resource and load positions of the region as a whole affect individual utility resource acquisition decisions. The Pacific Northwest has a history of being capacity surplus and energy deficit. The 2000-01 energy crisis led to the rapid development of 3,425 MW of natural gas-fired generation in the Northwest. Over the following 10 years, the Northwest added 2,000 MW of natural gas-fired generation. During this same time, Oregon and Washington added 6,000 MW of wind. With recent wind additions, and their lack of capacity contribution, the region is approaching a capacity balance with loads; but the region remains long on energy due to the quantity of wind generation added to the system. In recognition of these regional changes, the NPCC has done a considerable amount of analytical work to understand and develop methodologies to identify capacity needs in the region. Based on their work, the Northwest begins to fail a five percent Loss of Load Probability (LOLP) test in the winter of 2017-18.15 Five percent LOLP means utilities meet all customer demand in 19 of 20 years, or one loss of load event permitted on a planning basis in 20 years due to insufficient generation. The NPCC identifies a need of 350 MW of new capacity, or 300 aMW of peak load reduction, to eliminate potential 2017-18 resource shortfall. The identified regional problem months are in the winter, with a small change of problems in the summer months. The NPCC also studied load growth and market availability scenarios. In the event of higher loads or reduced market availability, the NPCC study indicated that the region should add 2,850 MW of new capacity by 2017. Because Avista often relies on the Northwest market to serve a portion of its peak load needs, it requested additional data from the NPCC to develop regional load and resource balance reports to understand the regional load and resource system balance. With the NPCC data, Avista developed the information shown in Table 2.10. This table illustrates the region’s substantial summer surplus and dwindling winter supplies. The table also illustrates the resource capability based on the length of the peak event. The table shows one, four, and ten-hour peaks, illustrating the unique impact that hydro has on the Northwest’s ability to meet peak loads. These regional balances do not include wind capacity. In January 2018, the one hour implied planning margin is 24.3 percent, but with regional IPPs included, the margin improves to 34.3 percent. During a one-hour event the system has 8,050 excess MW or 11,374 with the IPPs. The real problem lies in a ten- hour event, where only a 4.3 percent planning margin exists absent the IPPs, and a 15 percent margin with them. This translates into modest surpluses of 1,334 MW and 4,658 MW, respectively. The region is long by more than 11,000 MW without, and over 14,000 MW with, the IPPs in the summer. The main concern during a summer peak load event is that excess power may be scheduled outside of the region on a pre-schedule basis, leaving limited 15 John Fazio, NPCC, ―Adequacy Assessment of the 2017 Pacific Northwest Power Supply‖, NW Resource Adequacy Forum Steering Committee Meeting, October 26, 2012 in Portland, OR. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 63 of 1125 Chapter 2: Loads & Resources Avista Corp 2013 Electric IRP 2-32 resource available for the Northwest. The maximum regional export to California is estimated to be up to 7,980 MW absent any transmission derates. Power could also be exported east through Idaho, but the limit east is 2,250 MW.16 The Northwest region has options to import power from British Columbia and Montana. The NPCC believes the region has sufficient capacity in the summer, but lacks capacity beginning in 2017 in the winter. Table 2.10: Regional Load & Resource Balance January 2018 August 2018 1 Hour 4 Hour 10 Hour 1 Hour 4 Hour 10 Hour Implied Planning Margin (PM) 24.3% 11.7% 4.3% 44.7% 46.4% 49.3% w/ IPP Implied PM 34.3% 21.9% 15.0% 56.6% 58.6% 62.0% Length (MW) 8,050 3,789 1,334 11,687 11,894 12,113 w/ IPP Length (MW) 11,374 7,112 4,658 14,804 15,010 15,229 January 2025 August 2025 1 Hour 4 Hour 10 Hour 1 Hour 4 Hour 10 Hour Implied Planning Margin (PM) 12.5% -1.5% -12.0% 30.7% 29.3% 28.7% w/ IPP Implied PM 19.1% 5.2% -5.0% 38.4% 37.1% 36.8% Length (MW) 4,489 -533 -4,042 8,706 8,141 7,631 w/ IPP Length (MW) 6,853 1,831 -1,679 10,862 10,297 9,788 Avista’s Loss of Load Analysis In the Northwest, reliability matrices can help address the issue of how much planning margin is required. Typical results of these models are LOLP, Loss of Load Hours (LOLH), and Loss of Load Expectation (LOLE) measures. A reliable system is typically defined as having no more than one interruption event in twenty years, or a five percent LOLP. These analyses can be helpful, but usually have an inherent flaw due to the need to assume how much out-of-area imported generation is available for the study. Avista developed its LOLP model to simulate reliability events caused by to poor hydro runoff, forced outages, and extreme weather conditions on its system, finding that forced outages are the main driver of reliability events and/or the need for imported power. Avista is well positioned to import power. It has adequate transmission capabilities to import power from the wholesale energy markets, but the amount of generation actually available for purchase from third parties at times of system peak is difficult to estimate. To address this concern, a sophisticated regional model must estimate required regional planning margins. As discussed above, the NPCC has performed this regional assessment. The challenge, even at the regional level, is modeling market imports into or exports from the region. To address this shortfall the NPCC and Avista use scenario analyses.17 The results of Avista’s LOLP study are in Figure 2.20. The results use scenario analyses to illustrate potential planning margins using a test year of 2020. The scenarios change the amount of market reliance compared with new resource 16 Ibid. 17 Ibid. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 64 of 1125 Chapter 2: Loads & Resources Avista Corp 2013 Electric IRP 2-33 acquisitions by Avista. This chart indicates that with a 12 percent planning margin Avista would rely on 275 MW from the market to meet a 5 percent LOLP metric. To eliminate market reliance, Avista would require a 31 percent planning margin at an additional power supply cost of $40 million per year. Figure 2.20: 2020 Market Reliance & Capacity Cost Tradeoffs to Achieve 5 Percent LOLP While scenario analysis helps management understand the tradeoffs between imports and new plant construction, it does not help identify the actual planning margin. For this IRP, Avista chose a 14 percent basic planning margin. The addition of operating reserves and other ancillary services results in a total planning margin of 22 percent. This level is similar to the planning margin used in the 2011 IRP and is similar to other utilities. Further, the planning margin is similar to NPCC’s 23 percent recommendation for the region.18 The 14 percent planning margin implies Avista will rely on 240 MW of market power in some peak events. In addition to understanding the level of imports Avista will depend on during extreme peak events, it considers the regional resource position before deciding to procure new resources. Based on the current regional surplus shown in Table 2.10, Avista does not believe it is necessary procure new resources for future summer deficits. During summer months, the regional resource position is longer than the winter position. As a dual-peaking utility, Avista is concerned with summer reliability, but with the regional resource length described above, the addition of new resources likely is unnecessary. 18 The NPCC does not consider operating reserves and ancillary services separately from the planning margin, but instead combines them together into one figure. 0 5 10 15 20 25 30 35 40 45 - 50 100 150 200 250 300 12%13%15%16%18%19%21%22%24%25%27%28%30%31% in c r e m e n t a l c o s t ( $ M i l l / Y r ) ma r k e t c o n t r i b u t i o n ( M W ) planning margin MW Annual Cost Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 65 of 1125 Chapter 2: Loads & Resources Avista Corp 2013 Electric IRP 2-34 Where the region shows signs of becoming resource deficient in the future, Avista will re-evaluate its positions. Balancing Loads and Resources Both the single-hour and sustained-peak requirements compare future projections of utility loads and resources. The single peak hour is more of a concern in the winter than the three-day sustained 18-hour peak. During winter months, the hydro system is able to sustain generation levels for longer periods than in the summer months due to higher inflows. Figure 2.21 illustrates the winter balance of loads and resources; the first year Avista identifies a significant winter capacity deficit is January 2020. Avista has small deficits in 2015 and 2016, but regional surplus and the expiration of the 150 MW capacity contract with Portland General Electric at the end of 2016 suggests the utility should rely on the short-term marketplace to meet these deficits. A detailed table of Avista’s annual loads and resources is at the end of this chapter in Tables 2.12 through 2.14. Figure 2.21: Winter 1 Hour Capacity Load and Resources The 2013 IRP does not anticipate meeting summer capacity deficits with new resources, because of the significant regional surplus in the summer. Similar to the region, Avista’s generation additions to meet winter peaks will substantially eliminate summer deficits. Avista’s summer resource balance is in Figure 2.22. This chart differs from the winter load and resource balance by using an 18-hour sustained peak rather than the single hour peak. The sustained peak is more constraining in the summer months due to reservoir restrictions and lower river flows reducing the amount of continuous hydro -500 0 500 1,000 1,500 2,000 2,500 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 me g a w a t t s Net Firm Contracts Peaking ThermalsBaseload Thermals HydroLoad Forecast Load Forecast + PM/Reserves Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 66 of 1125 Chapter 2: Loads & Resources Avista Corp 2013 Electric IRP 2-35 generation available to meet load. This chart also differs from the winter because Avista is not adding a planning margin to the summer due to expected regional surpluses. See Table 2.13 for more details. Figure 2.22: Summer 18-Hour Capacity Load and Resources Energy Planning For energy planning, resources must be adequate to meet customer requirements even when loads are high for extended periods or an outage limits the output of a resource. Where generation capability is not adequate to meet these variations, customers and the utility must rely on the volatile short-term electricity market. In addition to load variability, planning margins accounts for variations in hydroelectric generation. As with capacity planning, there are differences in regional opinion on the proper method for establishing energy-planning margins. Many utilities in the Northwest base their planning on the amount of energy available during the critical water period of 1936/37.19 The critical water year of 1936/37 was low on an annual basis, but it was not necessarily low in every month. The IRP could target resource development to reach a 99 percent confidence level on being able to deliver energy to its customers, and it would significantly decrease the frequency of its market purchases. However, this strategy requires investments in approximately 200 MW of generation in addition to the margins included in Expected Case of the IRP. Expenditures to support this high level of reliability would put upward pressure on retail rates for a modest benefit. Avista instead plans to the 90th percentile for hydro. There is a 10 percent chance of needing to purchase energy from the market in any given month over the IRP timeframe, but in 19 The critical water year represents the lowest historical generation level in the streamflow record. -500 0 500 1,000 1,500 2,000 2,500 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 me g a w a t t s Net Firm Contracts Peaking ThermalsBaseload Thermals HydroLoad Forecast + PM/Reserves Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 67 of 1125 Chapter 2: Loads & Resources Avista Corp 2013 Electric IRP 2-36 nine of ten years, Avista would meet all of its energy requirements and sell surplus electricity into the marketplace. Beyond load and hydroelectricity variability, Avista’s WNP-3 contract with BPA contains supply risk. The contract includes a return energy provision in favor of BPA that can equal 32 aMW annually. Under adverse market conditions, BPA almost certainly would exercise this right, as it did during the 2001 Energy Crisis. To account for contract risk, the energy contingency is increased by 32 aMW until the contract expires in 2019. With the addition of WNP-3 to load and hydroelectricity variability, the total energy contingency equals 228 aMW in 2014. See Figure 2.23 for the summary of the annual average energy load and resource net position. Figure 2.23: Annual Average Energy Load and Resources Washington State Renewable Portfolio Standard In the November 2006 general election, Washington voters approved the EIA. The EIA requires utilities with more than 25,000 customers to source 3 percent of their energy from qualified non-hydroelectric renewables by 2012, 9 percent by 2016, and 15 percent by 2020. Utilities also must acquire all cost effective conservation and energy efficiency measures. In 2011, Avista acquired the Palouse Wind project through a 30-year power purchase agreement to help meet the renewable goal. In 2012, an amendment to the EIA allowed biomass facilities built prior to 1999 to qualify under the law beginning in 2016. This amendment allows Avista’s 50 MW Kettle Falls project to qualify and further help the company meet EIA requirements. Table 2.11 shows the forecast amount of RECs required to meet Washington state law, and the amount of qualifying resources already in Avista’s generation portfolio. The sales forecast uses the Washington portion of the current load forecast. It illustrates how Avista will maintain a modest surplus of 0 500 1,000 1,500 2,000 2,500 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 av e r a g e m e g a w a t t s Net Firm Contracts Peaking Thermals Baseload Thermals HydroLoad Forecast Load Forecast + Contingency Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 68 of 1125 Chapter 2: Loads & Resources Avista Corp 2013 Electric IRP 2-37 approximately 10 aMW in 2016 to account for annual generation variability at its EIA- qualifying plants. Resource Requirements The resource requirements discussed in this section do not include energy efficiency acquisitions beyond what is contained in the load forecast. The PRS chapter discusses conservation beyond assumptions contained in the load forecast. The following tables present loads and resources to illustrate future resource requirements. During winter peak periods (Table 2.12), surplus capacity exists through 2019 after taking into account market purchases.20 Without these purchases, a capacity deficit would exist in 2012. Avista believes that the present market can meet these minor winter capacity shortfalls and therefore will optimize its portfolio to postpone new resource investments for winter capacity until 2020. The summer peak projection in Table 2.13shows lower loads than in winter, but resource capabilities are also lower due to lower hydroelectricity output and reduced capacity at natural gas-fired resources. The IRP shows persistent summer deficits throughout the 20-year timeframe, but regional surpluses are adequate to fill in these gaps. Many near-term deficits are from decreased hydroelectricity capacity during periods of planned maintenance and upgrades. Taking into account regional surpluses, the load and resource balance is 54 MW short only in 2016. After 2016, when the Portland General Electricity capacity sale contract expires, the next capacity need is in 2019 at 98 MW. The traditional measure of resource need in the region is the annual average energy position. Table 2.14 shows the energy position. There is enough energy on an annual average basis to meet customer requirements until 2020, when the utility is short 49 aMW. Avista will require 112 aMW of new energy by 2025, and 475 aMW in 2031. 20 Avista relied on work by the NPCC in its Resource Adequacy Forum exercises to determine the level of surplus summer energy and capacity. Reliance is limited to Avista’s prorated share of regional load. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 69 of 1125 Chapter 2: Loads & Resources Avista Corp 2013 Electric IRP 2-38 Table 2.11: Washington State RPS Detail (aMW) On - l i n e Ye a r Ap p r e n t i c e La b o r Cr e d i t En e r g y 20 1 2 2 0 1 3 2 0 1 4 2 0 1 5 2 0 1 6 2 0 1 7 2 0 1 8 2 0 1 9 2 0 2 0 2 0 2 1 2 0 2 2 2 0 2 3 2 0 2 4 2 0 2 5 2 0 2 6 2 0 2 7 2 0 2 8 2 0 2 9 2 0 3 0 2 0 3 1 2 0 3 2 2 0 3 3 WA S t a t e R e t a i l S a l e s F o r e c a s t 62 8 63 3 64 0 64 6 65 0 65 8 66 5 66 8 67 1 67 6 68 0 68 4 68 7 69 4 69 8 70 2 70 4 71 1 71 6 72 2 72 6 73 5 RP S % 3% 3 % 3 % 3 % 9 % 9 % 9 % 9 % 1 5 % 1 5 % 1 5 % 1 5 % 1 5 % 1 5 % 1 5 % 1 5 % 1 5 % 1 5 % 1 5 % 1 5 % 1 5 % 1 5 % RE Q U I R E D R E N E W A B L E E N E R G Y 19 . 0 1 9 . 0 1 8 . 9 1 9 . 1 5 7 . 9 5 8 . 3 5 8 . 9 5 9 . 5 1 0 0 . 0 1 0 0 . 5 1 0 1 . 0 1 0 1 . 7 1 0 2 . 2 1 0 2 . 8 1 0 3 . 6 1 0 4 . 4 1 0 5 . 0 1 0 5 . 4 1 0 6 . 1 1 0 7 . 0 1 0 7 . 9 1 0 8 . 6 In c r e m e n t a l H y d r o Lo n g L a k e 3 19 9 9 1. 0 1 . 6 1 . 6 1 . 6 1 . 6 1 . 6 1 . 6 1 . 6 1 . 6 1 . 6 1 . 6 1 . 6 1 . 6 1 . 6 1 . 6 1 . 6 1 . 6 1 . 6 1 . 6 1 . 6 1 . 6 1 . 6 1 . 6 1 . 6 Li t t l e F a l l s 4 20 0 1 1. 0 0 . 6 0 . 6 0 . 6 0 . 6 0 . 6 0 . 6 0 . 6 0 . 6 0 . 6 0 . 6 0 . 6 0 . 6 0 . 6 0 . 6 0 . 6 0 . 6 0 . 6 0 . 6 0 . 6 0 . 6 0 . 6 0 . 6 0 . 6 Ca b i n e t 2 20 0 4 1. 0 3 . 3 3 . 3 3 . 3 3 . 3 3 . 3 3 . 3 3 . 3 3 . 3 3 . 3 3 . 3 3 . 3 3 . 3 3 . 3 3 . 3 3 . 3 3 . 3 3 . 3 3 . 3 3 . 3 3 . 3 3 . 3 3 . 3 3 . 3 Ca b i n e t 3 20 0 1 1. 0 5 . 2 5 . 2 5 . 2 5 . 2 5 . 2 5 . 2 5 . 2 5 . 2 5 . 2 5 . 2 5 . 2 5 . 2 5 . 2 5 . 2 5 . 2 5 . 2 5 . 2 5 . 2 5 . 2 5 . 2 5 . 2 5 . 2 5 . 2 Ca b i n e t 4 20 0 7 1. 0 2 . 3 2 . 3 2 . 3 2 . 3 2 . 3 2 . 3 2 . 3 2 . 3 2 . 3 2 . 3 2 . 3 2 . 3 2 . 3 2 . 3 2 . 3 2 . 3 2 . 3 2 . 3 2 . 3 2 . 3 2 . 3 2 . 3 2 . 3 No x o n 1 20 0 9 1. 0 2 . 4 2 . 4 2 . 4 2 . 4 2 . 4 2 . 4 2 . 4 2 . 4 2 . 4 2 . 4 2 . 4 2 . 4 2 . 4 2 . 4 2 . 4 2 . 4 2 . 4 2 . 4 2 . 4 2 . 4 2 . 4 2 . 4 2 . 4 No x o n 3 20 1 0 1. 0 1 . 7 1 . 7 1 . 7 1 . 7 1 . 7 1 . 7 1 . 7 1 . 7 1 . 7 1 . 7 1 . 7 1 . 7 1 . 7 1 . 7 1 . 7 1 . 7 1 . 7 1 . 7 1 . 7 1 . 7 1 . 7 1 . 7 1 . 7 No x o n 2 20 1 1 1. 0 0 . 9 0 . 9 0 . 9 0 . 9 0 . 9 0 . 9 0 . 9 0 . 9 0 . 9 0 . 9 0 . 9 0 . 9 0 . 9 0 . 9 0 . 9 0 . 9 0 . 9 0 . 9 0 . 9 0 . 9 0 . 9 0 . 9 0 . 9 No x o n 4 20 1 2 1. 0 1 . 4 0 . 7 1 . 4 1 . 4 1 . 4 1 . 4 1 . 4 1 . 4 1 . 4 1 . 4 1 . 4 1 . 4 1 . 4 1 . 4 1 . 4 1 . 4 1 . 4 1 . 4 1 . 4 1 . 4 1 . 4 1 . 4 1 . 4 Nin e M i l e 20 1 5 1. 0 1 . 4 0 . 0 1 . 4 1 . 4 1 . 4 1 . 4 1 . 4 1 . 4 1 . 4 1 . 4 1 . 4 1 . 4 1 . 4 1 . 4 1 . 4 1 . 4 1 . 4 1 . 4 1 . 4 1 . 4 1 . 4 1 . 4 1 . 4 Wa n a p u m F i s h B y p a s s 20 0 8 1. 0 2. 5 2 . 5 2 . 4 2 . 4 2 . 4 2 . 4 2 . 4 2 . 4 2 . 4 2 . 4 2 . 4 2 . 4 2 . 4 2 . 4 2 . 4 2 . 4 2 . 4 2 . 4 2 . 4 2 . 4 2 . 4 2 . 4 To t a l Q u a l i f y i n g R e s o u r c e s 21 . 3 2 3 . 3 2 3 . 2 2 3 . 2 2 3 . 2 2 3 . 2 2 3 . 2 2 3 . 2 2 3 . 2 2 3 . 2 2 3 . 2 2 3 . 2 2 3 . 2 2 3 . 2 2 3 . 2 2 3 . 2 2 3 . 2 2 3 . 2 2 3 . 2 2 3 . 2 2 3 . 2 2 3 . 2 RE C P O S I T I O N N E T O F I N C R E M E N T A L H Y D R O 0. 0 0 . 0 0 . 0 0 . 0 - 3 4 . 7 - 3 5 . 2 - 3 5 . 7 - 3 6 . 4 - 7 6 . 8 - 7 7 . 3 - 7 7 . 9 - 7 8 . 5 - 7 9 . 1 - 7 9 . 6 - 8 0 . 4 - 8 1 . 2 - 8 1 . 8 - 8 2 . 2 - 8 2 . 9 - 8 3 . 8 - 8 4 . 7 - 8 5 . 5 Qu a l i f y i n g R e n e w a b l e R e s o u r c e s / R E C s Pu r c h a s e d R E C s 0. 0 0 . 0 0 . 0 5 . 7 0 . 0 0 . 0 0 . 0 0 . 0 0 . 0 0 . 0 0 . 0 0 . 0 0 . 0 0 . 0 0 . 0 0 . 0 0 . 0 0 . 0 0 . 0 0 . 0 0 . 0 0 . 0 Ke t t l e F a l l s 19 8 3 1. 0 0. 0 0 . 0 0 . 0 0 . 0 3 2 . 5 3 2 . 1 3 1 . 9 3 2 . 5 3 2 . 4 3 3 . 2 3 1 . 8 3 2 . 5 3 1 . 8 3 2 . 5 3 1 . 8 3 2 . 5 3 1 . 8 3 2 . 5 3 1 . 8 3 2 . 5 3 1 . 8 3 1 . 8 Pa l o u s e W i n d 20 1 2 1. 2 3 9 . 9 0 . 0 4 7 . 9 4 7 . 9 4 7 . 9 4 7 . 9 4 7 . 9 4 7 . 9 4 7 . 9 4 7 . 9 4 7 . 9 4 7 . 9 4 7 . 9 4 7 . 9 4 7 . 9 4 7 . 9 4 7 . 9 4 7 . 9 4 7 . 9 4 7 . 9 4 7 . 9 4 7 . 9 4 7 . 9 To t a l Q u a l i f y i n g R e s o u r c e s 0. 0 4 7 . 9 4 7 . 9 5 3 . 6 8 0 . 4 8 0 . 0 7 9 . 9 8 0 . 4 8 0 . 3 8 1 . 2 7 9 . 7 8 0 . 4 7 9 . 7 8 0 . 4 7 9 . 7 8 0 . 4 7 9 . 7 8 0 . 4 7 9 . 7 8 0 . 4 7 9 . 7 7 9 . 7 NE T R E C P O S I T I O N B E F O R E B A N K I N G & R E S E R V E S 0 . 0 4 7 . 9 4 7 . 9 5 3 . 6 4 5 . 7 4 4 . 8 4 4 . 2 4 4 . 1 3 . 5 3 . 9 1 . 8 1 . 9 0 . 6 0 . 8 - 0 . 7 - 0 . 8 - 2 . 1 - 1 . 8 - 3 . 2 - 3 . 4 - 5 . 0 - 5 . 8 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 70 of 1125 Chapter 2: Loads & Resources Avista Corp 2013 Electric IRP 2-39 Table 2.12: Winter 18-Hour Capacity Position (MW) 20 1 4 2 0 1 5 2 0 1 6 2 0 1 7 2 0 1 8 2 0 1 9 2 0 2 0 2 0 2 1 2 0 2 2 2 0 2 3 2 0 2 4 2 0 2 5 2 0 2 6 2 0 2 7 2 0 2 8 2 0 2 9 2 0 3 0 2 0 3 1 2 0 3 2 2 0 3 3 RE Q U I R E M E N T S Na t i v e L o a d -1 , 6 6 5 - 1 , 6 8 3 - 1 , 7 0 0 - 1 , 7 1 3 - 1 , 7 2 7 - 1 , 7 4 1 - 1 , 7 5 5 - 1 , 7 6 9 - 1 , 7 8 3 - 1 , 7 9 8 - 1 , 8 1 2 - 1 , 8 2 7 - 1 , 8 4 2 - 1 , 8 5 6 - 1 , 8 7 1 - 1 , 8 8 7 - 1 , 9 0 2 - 1 , 9 1 7 - 1 , 9 3 3 - 1 , 9 4 8 Fi r m P o w e r S a l e s -2 1 1 - 1 5 8 - 1 5 8 -8 - 8 - 6 - 6 - 6 - 6 - 6 - 6 - 6 - 6 - 6 - 6 - 6 - 6 - 6 - 6 - 6 To t a l R e q u i r e m e n t s -1 , 8 7 5 - 1 , 8 4 1 - 1 , 8 5 7 - 1 , 7 2 1 - 1 , 7 3 5 - 1 , 7 4 7 - 1 , 7 6 1 - 1 , 7 7 5 - 1 , 7 8 9 - 1 , 8 0 4 - 1 , 8 1 8 - 1 , 8 3 3 - 1 , 8 4 8 - 1 , 8 6 3 - 1 , 8 7 8 - 1 , 8 9 3 - 1 , 9 0 8 - 1 , 9 2 3 - 1 , 9 3 9 - 1 , 9 5 4 RE S O U R C E S Fi r m P o w e r P u r c h a s e s 11 7 1 1 7 1 1 7 1 1 7 1 1 7 1 1 6 3 4 3 4 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 Hy d r o R e s o u r c e s 99 8 8 8 8 8 8 9 9 5 5 9 5 5 9 1 9 9 2 4 9 2 0 9 2 0 9 2 8 9 2 0 9 2 0 9 2 8 9 2 0 9 2 0 9 2 8 9 2 0 9 2 0 9 2 8 9 2 0 Ba s e L o a d T h e r m a l s 89 5 8 9 5 8 9 5 8 9 5 8 9 5 8 9 5 8 9 5 8 9 5 8 9 5 8 9 5 8 9 5 8 9 5 8 9 5 6 1 7 6 1 7 6 1 7 6 1 7 6 1 7 6 1 7 6 1 7 Wi n d R e s o u r c e s 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Pe a k i n g U n i t s 24 2 2 4 2 2 4 2 2 4 2 2 4 2 2 4 2 2 4 2 2 4 2 2 4 2 2 4 2 2 4 2 2 4 2 2 4 2 2 4 2 2 4 2 2 4 2 2 4 2 2 4 2 2 4 2 2 4 2 To t a l R e s o u r c e s 2,2 5 2 2 , 1 4 3 2 , 1 4 3 2 , 2 1 0 2 , 2 1 0 2 , 1 7 2 2 , 0 9 5 2 , 0 9 1 2 , 0 9 1 2 , 0 9 8 2 , 0 9 0 2 , 0 9 0 2 , 0 9 8 1 , 8 1 1 1 , 8 1 1 1 , 8 1 9 1 , 8 1 1 1 , 8 1 1 1 , 8 1 9 1 , 8 1 1 Pe a k P o s i t i o n B e f o r e R e s e r v e P l a n n i n g 37 7 3 0 2 2 8 6 4 8 9 4 7 5 4 2 5 3 3 4 3 1 6 3 0 1 2 9 4 2 7 2 2 5 7 2 5 0 -5 1 - 6 6 - 7 4 - 9 7 - 1 1 2 - 1 2 0 - 1 4 3 RE S E R V E P L A N N I N G Pl a n n i n g M a r g i n -2 3 3 - 2 3 6 - 2 3 8 - 2 4 0 - 2 4 2 - 2 4 4 - 2 4 6 - 2 4 8 - 2 5 0 - 2 5 2 - 2 5 4 - 2 5 6 - 2 5 8 - 2 6 0 - 2 6 2 - 2 6 4 - 2 6 6 - 2 6 8 - 2 7 1 - 2 7 3 To t a l A n c i l l a r y S e r v i c e s R e q u i r e d - 1 3 9 - 1 3 6 - 1 3 7 - 1 2 8 - 1 2 9 - 1 3 1 - 1 3 6 - 1 3 7 - 1 3 8 - 1 3 9 - 1 4 1 - 1 4 2 - 1 4 3 - 1 3 9 - 1 3 9 - 1 4 0 - 1 4 0 - 1 4 0 - 1 4 0 - 1 4 0 Re s e r v e & C o n t i n g e n c y A v a i l a b i l i t y 13 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 De m a n d R e s p o n s e 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 To t a l R e s e r v e P l a n n i n g -3 5 9 - 3 6 6 - 3 6 9 - 3 6 2 - 3 6 6 - 3 6 9 - 3 7 6 - 3 7 9 - 3 8 2 - 3 8 6 - 3 8 9 - 3 9 2 - 3 9 5 - 3 9 3 - 3 9 6 - 3 9 8 - 4 0 0 - 4 0 3 - 4 0 6 - 4 0 8 Pe a k P o s i t i o n w / R e s e r v e P l a n n i n g 17 -6 4 - 8 4 12 6 1 1 0 5 6 -4 2 - 6 4 - 8 1 - 9 2 - 1 1 7 - 1 3 5 - 1 4 5 - 4 4 5 - 4 6 2 - 4 7 2 - 4 9 7 - 5 1 5 - 5 2 5 - 5 5 1 Im p l i e d P l a n n i n g M a r g i n 21 % 1 7 % 1 6 % 2 9 % 2 8 % 2 5 % 1 9 % 1 8 % 1 7 % 1 7 % 1 5 % 1 4 % 1 4 % -2 % - 3 % - 4 % - 5 % - 6 % - 6 % - 7 % Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 71 of 1125 Chapter 2: Loads & Resources Avista Corp 2013 Electric IRP 2-40 Table 2.13: Summer 18-Hour Capacity Position (MW) 20 1 4 2 0 1 5 2 0 1 6 2 0 1 7 2 0 1 8 2 0 1 9 2 0 2 0 2 0 2 1 2 0 2 2 2 0 2 3 2 0 2 4 2 0 2 5 2 0 2 6 2 0 2 7 2 0 2 8 2 0 2 9 2 0 3 0 2 0 3 1 2 0 3 2 2 0 3 3 RE Q U I R E M E N T S Na t i v e L o a d -1 , 4 6 5 - 1 , 4 8 2 - 1 , 4 9 8 - 1 , 5 1 0 - 1 , 5 2 3 - 1 , 5 3 6 - 1 , 5 5 0 - 1 , 5 6 3 - 1 , 5 7 6 - 1 , 5 9 0 - 1 , 6 0 4 - 1 , 6 1 8 - 1 , 6 3 1 - 1 , 6 4 6 - 1 , 6 6 0 - 1 , 6 7 4 - 1 , 6 8 9 - 1 , 7 0 3 - 1 , 7 1 8 - 1 , 7 3 3 Fi r m P o w e r S a l e s -2 1 2 - 1 5 9 - 1 5 9 -9 - 9 - 8 - 8 - 7 - 7 - 7 - 7 - 7 - 7 - 7 - 7 - 7 - 7 - 7 - 7 - 7 To t a l R e q u i r e m e n t s -1 , 6 7 7 - 1 , 6 4 1 - 1 , 6 5 7 - 1 , 5 1 9 - 1 , 5 3 2 - 1 , 5 4 4 - 1 , 5 5 7 - 1 , 5 7 0 - 1 , 5 8 4 - 1 , 5 9 7 - 1 , 6 1 1 - 1 , 6 2 5 - 1 , 6 3 9 - 1 , 6 5 3 - 1 , 6 6 7 - 1 , 6 8 1 - 1 , 6 9 6 - 1 , 7 1 0 - 1 , 7 2 5 - 1 , 7 4 0 RE S O U R C E S Fi r m P o w e r P u r c h a s e s 29 2 9 2 9 2 9 2 9 2 6 2 6 2 6 2 6 2 5 2 5 2 5 2 5 2 5 2 5 2 5 2 5 2 5 2 5 2 5 Hy d r o R e s o u r c e s 70 1 7 0 7 6 6 3 6 3 1 6 3 8 5 8 3 5 8 0 6 2 2 6 2 4 6 2 2 6 2 2 6 2 4 6 2 2 6 2 2 6 2 4 6 2 2 6 2 2 6 2 4 6 2 2 6 2 2 Ba s e L o a d T h e r m a l s 78 5 7 8 5 7 8 5 7 8 5 7 8 5 7 8 5 7 8 5 7 8 5 7 8 5 7 8 5 7 8 5 7 8 5 7 8 5 5 5 6 5 5 6 5 5 6 5 5 6 5 5 6 5 5 6 5 5 6 Wi n d R e s o u r c e s 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Pe a k i n g U n i t s 17 6 1 7 6 1 7 6 1 7 6 1 7 6 1 7 6 1 7 6 1 7 6 1 7 6 1 7 6 1 7 6 1 7 6 1 7 6 1 7 6 1 7 6 1 7 6 1 7 6 1 7 6 1 7 6 1 7 6 To t a l R e s o u r c e s 1, 6 9 1 1 , 6 9 8 1 , 6 5 3 1 , 6 2 1 1 , 6 2 8 1 , 5 7 1 1 , 5 6 8 1 , 6 0 9 1 , 6 1 1 1 , 6 0 9 1 , 6 0 9 1 , 6 1 1 1 , 6 0 9 1 , 3 7 9 1 , 3 8 1 1 , 3 7 9 1 , 3 7 9 1 , 3 8 1 1 , 3 7 9 1 , 3 7 9 Pe a k P o s i t i o n B e f o r e R e s e r v e P l a n n i n g 14 5 7 -3 10 2 9 6 2 7 1 1 3 9 2 7 1 1 -2 -1 4 - 3 0 - 2 7 4 - 2 8 6 - 3 0 2 - 3 1 7 - 3 3 0 - 3 4 6 - 3 6 1 RE S E R V E P L A N N I N G Pl a n n i n g M a r g i n 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 To t a l A n c i l l a r y S e r v i c e s R e q u i r e d - 1 7 7 - 1 7 6 - 1 7 7 - 1 7 0 - 1 7 2 - 1 7 3 - 1 7 5 - 1 7 6 - 1 7 7 - 1 7 9 - 1 8 0 - 1 8 1 - 1 8 2 - 1 6 6 - 1 6 7 - 1 6 7 - 1 6 8 - 1 6 9 - 1 6 9 - 1 7 0 Re s e r v e & C o n t i n g e n c y A v a i l a b i l i t y 17 7 1 7 6 1 7 7 1 7 0 1 7 2 1 7 3 1 7 5 1 7 6 1 7 7 1 7 9 1 8 0 1 8 1 1 8 2 1 6 6 1 6 7 1 6 7 1 6 8 1 6 9 1 6 9 1 7 0 De m a n d R e s p o n s e 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 To t a l R e s e r v e P l a n n i n g 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Pe a k P o s i t i o n w / R e s e r v e P l a n n i n g 14 5 7 -3 10 2 9 6 2 7 1 1 3 9 2 7 1 1 -2 -1 4 - 3 0 - 2 7 4 - 2 8 6 - 3 0 2 - 3 1 7 - 3 3 0 - 3 4 6 - 3 6 1 Im p l i e d P l a n n i n g M a r g i n 11 % 1 4 % 1 0 % 1 8 % 1 7 % 1 3 % 1 2 % 1 4 % 1 3 % 1 2 % 1 1 % 1 0 % 9 % -7 % - 7 % - 8 % - 9 % - 9 % - 1 0 % - 1 1 % Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 72 of 1125 Chapter 2: Loads & Resources Avista Corp 2013 Electric IRP 2-41 Table 2.14: Average Annual Energy Position (aMW) 20 1 4 2 0 1 5 2 0 1 6 2 0 1 7 2 0 1 8 2 0 1 9 2 0 2 0 2 0 2 1 2 0 2 2 2 0 2 3 2 0 2 4 2 0 2 5 2 0 2 6 2 0 2 7 2 0 2 8 2 0 2 9 2 0 3 0 2 0 3 1 2 0 3 2 2 0 3 3 RE Q U I R E M E N T S Na t i v e L o a d -1 , 0 5 4 - 1 , 0 6 7 - 1 , 0 7 9 - 1 , 0 9 3 - 1 , 1 0 5 - 1 , 1 1 4 - 1 , 1 2 5 - 1 , 1 3 5 - 1 , 1 4 5 - 1 , 1 5 5 - 1 , 1 6 7 - 1 , 1 8 0 - 1 , 1 9 0 - 1 , 2 0 1 - 1 , 2 1 2 - 1 , 2 2 5 - 1 , 2 3 9 - 1 , 2 5 4 - 1 , 2 7 0 - 1 , 2 8 5 Fi r m P o w e r S a l e s -1 0 9 - 5 8 - 5 8 -6 - 6 - 5 - 5 - 5 - 5 - 5 - 5 - 5 - 5 - 5 - 5 - 5 - 5 - 5 - 5 - 5 To t a l R e q u i r e m e n t s -1 , 1 6 3 - 1 , 1 2 5 - 1 , 1 3 7 - 1 , 0 9 9 - 1 , 1 1 1 - 1 , 1 1 9 - 1 , 1 3 0 - 1 , 1 4 0 - 1 , 1 5 0 - 1 , 1 6 0 - 1 , 1 7 2 - 1 , 1 8 5 - 1 , 1 9 5 - 1 , 2 0 6 - 1 , 2 1 7 - 1 , 2 3 0 - 1 , 2 4 4 - 1 , 2 5 9 - 1 , 2 7 4 - 1 , 2 9 0 RE S O U R C E S Fi r m P o w e r P u r c h a s e s 12 8 1 2 9 1 2 8 7 6 7 6 5 6 3 1 3 0 3 0 2 9 2 9 2 9 2 9 2 9 2 9 2 9 2 9 2 9 2 9 2 9 Hy d r o R e s o u r c e s 52 7 4 9 5 4 9 5 4 9 5 4 9 0 4 8 1 4 8 1 4 8 1 4 8 1 4 8 1 4 8 1 4 8 1 4 8 1 4 8 1 4 8 1 4 8 1 4 8 1 4 8 1 4 8 1 4 8 1 Ba s e L o a d T h e r m a l s 72 3 7 2 5 7 1 8 7 1 5 7 3 2 7 1 1 7 2 4 7 3 6 7 1 3 7 1 7 7 1 4 7 1 9 6 7 3 5 0 6 5 0 4 5 0 6 5 0 4 5 0 6 5 0 4 5 0 6 Wi n d R e s o u r c e s 42 4 0 4 0 4 0 4 0 4 0 4 0 4 0 4 0 4 0 4 0 4 0 4 0 4 0 4 0 4 0 4 0 4 0 4 0 4 0 Pe a k i n g U n i t s 15 3 1 3 9 1 5 4 1 5 3 1 5 3 1 5 3 1 4 7 1 5 1 1 5 2 1 5 3 1 5 2 1 5 3 1 5 2 1 5 3 1 5 2 1 5 3 1 5 2 1 5 3 1 5 2 1 5 3 To t a l R e s o u r c e s 1,5 7 3 1 , 5 2 8 1 , 5 3 5 1 , 4 7 9 1 , 4 9 0 1 , 4 4 0 1 , 4 2 2 1 , 4 3 8 1 , 4 1 6 1 , 4 2 0 1 , 4 1 5 1 , 4 2 1 1 , 3 7 4 1 , 2 0 8 1 , 2 0 6 1 , 2 0 8 1 , 2 0 6 1 , 2 0 8 1 , 2 0 6 1 , 2 0 8 Pe a k P o s i t i o n B e f o r e R e s e r v e P l a n n i n g 41 0 4 0 4 3 9 8 3 8 0 3 7 9 3 2 1 2 9 2 2 9 9 2 6 6 2 5 9 2 4 3 2 3 7 1 7 9 2 -1 2 - 2 2 - 3 9 - 5 1 - 6 9 - 8 2 RE S E R V E P L A N N I N G Co n t i n g e n c y -2 2 8 - 2 3 1 - 2 3 1 - 2 3 2 - 2 3 2 - 2 1 4 - 1 9 5 - 1 9 6 - 1 9 6 - 1 9 7 - 1 9 7 - 1 9 8 - 1 9 8 - 1 9 9 - 1 9 9 - 2 0 0 - 2 0 0 - 2 0 1 - 2 0 2 - 2 0 2 Pe a k P o s i t i o n w / R e s e r v e P l a n n i n g 18 2 1 7 3 1 6 7 1 4 8 1 4 7 1 0 6 9 6 1 0 3 7 0 6 3 4 6 3 9 -1 9 - 1 9 7 - 2 1 1 - 2 2 1 - 2 3 9 - 2 5 2 - 2 7 0 - 2 8 4 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 73 of 1125 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 74 of 1125 Chapter 3–Energy Efficiency Avista Corp 2013 Electric IRP 3. Energy Efficiency Introduction Avista began offering energy efficiency programs to customers in 1978. Notable efficiency achievements include the Energy Exchanger program (1992 to 1994) converting approximately 20,000 homes from electricity to natural gas space and/or water heat. Avista pioneered the country’s first system benefit charge for energy efficiency in 1995. In response to the 2001 Western Energy Crisis, Avista acquired over three times the annual acquisition at only double the cost over a six-month period. During the summer of 2011, Avista distributed 2.3 million compact fluorescent lights (CFLs) to residential and commercial customers for an estimated energy savings of 39,005 MWh. Conservation programs regularly meet or exceed regional shares of energy efficiency gains as outlined by the NPCC. Figure 3.1 illustrates Avista’s historical electricity conservation acquisitions. Avista has acquired 168 aMW of energy efficiency since 1978; however, the 18-year average life of the conservation portfolio means some measures have reached the end of their useful lives and are no longer reducing loads. The 18-year assumed measure life accounts for the difference between the Cumulative and Online lines in Figure 3.1. Section Highlights This IRP includes a Conservation Potential Assessment of Avista’s Idaho and Washington service territories. Current Avista-sponsored conservation reduces retail loads by nearly 10 percent, or 115 aMW. Avista evaluated over 3,000 equipment options, and over 1,700 measure options covering all major end use equipment, as well as devices and actions to reduce energy consumption for this IRP. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 75 of 1125 Chapter 3–Energy Efficiency Avista Corp 2013 Electric IRP Figure 3.1: Historical and Forecast Conservation Acquisition (system) Avista’s energy efficiency programs provide a range of conservation and education options to residential, low income, commercial, and industrial customer segments. The programs are either prescriptive or site-specific. Prescriptive programs, or standard offerings, provide cash incentives for standardized products such as the installation of specified high-efficiency heating equipment. Prescriptive programs are suitable in situations where uniform products or offerings are applicable for large groups of homogeneous customers and primarily offered to residential and small commercial customers. Site-specific programs, or customized offerings, provide cash incentives for any cost-effective energy saving measure or equipment with an economic payback greater than one year and less than eight years for non-LED lighting projects, or less than 13 years for all other end uses and technologies. Efficiency programs with economic paybacks of less than one year are ineligible for incentives, although Avista assists in educating and informing customers about these types of efficiency measures. Site-specific programs require customized services for commercial and industrial customers because of the unique characteristics of each of their premises and processes. In some cases, Avista uses a prescriptive approach where similar applications of energy efficiency measures result in reasonably consistent savings estimates in conjunction with a high achievable savings potential. An example is prescriptive lighting for commercial and industrial applications. Conservation Potential Assessment Approach The EIA obligates Avista to complete an independent Conservation Potential Assessment (CPA) biennially.1 This study forms the basis for the conservation portion of 1 See WAC 480-109 and RCW 19.285 0 60 120 180 240 300 360 420 480 540 600 0 2 4 6 8 10 12 14 16 18 20 19 7 8 19 8 0 19 8 2 19 8 4 19 8 6 19 8 8 19 9 0 19 9 2 19 9 4 19 9 6 19 9 8 20 0 0 20 0 2 20 0 4 20 0 6 20 0 8 20 1 0 20 1 2 20 1 4 20 1 6 20 1 8 20 2 0 20 2 2 20 2 4 20 2 6 20 2 8 20 3 0 20 3 2 cu m u l a t i v e s a v i n g s ( a M W ) an n u a l s a v i n g s ( a M W ) Cumulative Online Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 76 of 1125 Chapter 3–Energy Efficiency Avista Corp 2013 Electric IRP this IRP. In 2010, Avista retained Global Energy Partners to conduct this study for its Idaho and Washington electric service territories. EnerNOC acquired the company in 2011 and updated the previous study for this IRP. The CPA identifies the 20-year potential for energy efficiency and provides data on resources specific to Avista’s service territory for use in the 2013 IRP, in accordance with the EIA energy efficiency goals. The energy efficiency potential considers the impacts of existing programs, the influence of known building codes and standards, technology developments and innovations, changes to the economic influences, and energy prices. EnerNOC took the following steps to assess and analyze energy efficiency and potential within Avista’s service territory. Figure 3.2 illustrates the steps of the analysis. 1. Market Assessment: Categorizes energy consumption in the residential (including low-income customers), commercial, and industrial sectors. This assessment uses utility and secondary data to characterize customers’ electric usage behavior in Avista’s service territory. EnerNOC uses this assessment to develop energy market profiles describing energy consumption by market segment, vintage (existing or new construction), end use, and technology. 2. Demand Forecast: Develops a demand forecast absent the effects of future conservation program by sector and by end use for the entire study period. 3. Program Assessment: Identifies energy-efficiency measures appropriate for Avista’s service territory, including regional savings from energy efficiency measures acquired through Northwest Energy Efficiency Alliance (NEEA) efforts. 4. Potential: Analyzes programs to identify the technical, economic and achievable potential. Technical potential chooses the most efficient measure, regardless of cost. Economic potential chooses the most efficient cost-effective measure. Achievable potential adjusts economic potential to account for factors other than pure economics, such as consumer behavior or market penetration rates. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 77 of 1125 Chapter 3–Energy Efficiency Avista Corp 2013 Electric IRP Figure 3.2: Analysis Approach Overview Market Segmentation The CPA segments Avista customers by state and rate schedule, translating to residential, commercial and industrial general, commercial and industrial large general, extra large commercial, and extra large industrial services. The residential class segments include single family, multi-family, manufactured home and low-income customers. The low-income threshold for this study is 200 percent of the federal poverty level2. Pumping represents only about 2 percent of total utility loads; the energy savings projected for the pumping customer classification by the NPCC calculator is approximately 4 percent of total savings potential. Within each segment, energy use is characterized by end use, such as space heating, cooling, lighting, water heat or motors and by technology including heat pump, resistance heating and furnace for space heating. The baseline projection is the “business as usual” metric without future utility conservation programs. It indicates annual electricity consumption and peak demand by customer segment and end use absent future efficiency programs. The baseline projection includes projected impacts of known building codes and energy efficiency standards as of 2012 when the study began. Codes and standards have direct bearing on the amount of energy efficiency potential that exists beyond the impact of these efforts. The baseline projection accounts for market changes including: customer and market growth; income growth; retail rates forecasts; 2 Available from census data and the American Community Survey data. Avista data Avista data/ secondary data Develop prototypes and perform energy analysis Forecast assumptions: Customer growth Price forecast Purchase shares Codes and standards Energy efficiency measure list measure costs and savings analysis Base-year energy consumption by state, fuel, and sector Energy market profiles by end use, fuel, segment, and vintage Baseline forecast by end use Energy efficiency potential Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 78 of 1125 Chapter 3–Energy Efficiency Avista Corp 2013 Electric IRP trends in end use and technology saturations; equipment purchase decisions; consumer price elasticity; income; and persons per household. For each customer segment, a robust list of electrical energy efficiency measures and equipment is compiled, drawing upon the NPCC’s Sixth Power Plan, the Regional Technical Forum, and other measures applicable to Avista. This list of energy efficiency equipment and measures includes 3,076 equipment and 1,774 measure options, representing a wide variety of end use applications, as well as devices and actions able to reduce customer energy consumption. A comprehensive list of equipment and measure options is available in Appendix C. Measure cost, savings, estimated useful life, and other performance factors identified for the list of measures and economic screening performed on each measure for every year of the study to develop the economic potential. Many measures initially do not pass the economic screen using current avoided costs, but some measures may become part of the energy efficiency program as contributing factors evolve during the 20-year planning horizon. Avista supplements its energy efficiency activities by including potentials for distribution efficiency measures for consistency with the EIA conservation targets and the NPCC Sixth Power Plan. Details about the distribution efficiency projects are in the Transmission and Distribution chapter of this IRP. Overview of Energy Efficiency Potentials EnerNOC utilized an approach adhering to the conventions outlined in the National Action Plan for Energy Efficiency Guide for Conducting Potential Studies.3 The guide represents the most credible and comprehensive national industry standard practice for specifying energy efficiency potential. Specifically, three types of potentials are in this study, as discussed below. Technical Potential Technical conservation potential uses the most efficient option commercially available to each purchase decision, regardless of cost. This theoretical case provides the broadest and highest definition of savings potentials because it quantifies savings that would result if all current equipment, processes, and practices in all market sectors were replaced by the most efficient and feasible technology. Technical potential does not take into account the cost-effectiveness of the measures. Technical potential is defined as “phase-in technical potential” assuming only that the portion of the current equipment stock that has reached the end of its useful life and is due for turnover is changed out by the most efficient measures available. Non-equipment measures, such as controls and other devices (e.g., programmable thermostats) phase-in over time, just like the equipment measures. 3 National Action Plan for Energy Efficiency (2007). National Action Plan for Energy Efficiency Vision for 2025: Developing a Framework for Change. www.epa.gov/eeactionplan. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 79 of 1125 Chapter 3–Energy Efficiency Avista Corp 2013 Electric IRP Economic Potential Economic potential conservation includes the purchase of the most efficient cost- effective option available for each given equipment or non-equipment measure.4 Cost effectiveness is determined by applying the Total Resource Cost (TRC) test using all quantifiable costs and benefits regardless of who accrues them and inclusive of non-energy benefits as identified by the NPCC.5 Measures that pass the economic screen represent aggregate economic potential. As with technical potential, economic potential calculations use a phased-in approach. Economic potential is a hypothetical upper-boundary of savings potential representing only economic measures; it does not consider customer acceptance and other factors. Achievable Potential Achievable potential refines economic potential by taking into account expected program participation, customer preferences, and budget constraints. This level of potential estimates the achievable savings that could be attained through Avista’s energy efficiency programs when considering market maturity and barriers, customer willingness to adopt new technologies, incentive levels, as well as whether the program is mature or represents the addition of a new program. During this stage, EnerNOC applied market acceptance rates based upon NPCC-defined ramp rates from the Sixth Power Plan taking into account market barriers and measure lives. However, EnerNOC adjusted the ramp rates for the measures and equipment to reflect Avista’s market-specific conditions and program history. In some cases, Avista’s ramp rates exceed the Council’s, illustrating a mature energy efficiency program reaching a greater percentage of the market than estimated by the NPCC’s Sixth Power Plan. In other cases, where a program does not currently exist, a ramp rate could be less than the NPCC’s ramp rate, acknowledging additional design and implementation time is necessary to launch a new program. Other examples of changes to ramp rates include measures or equipment where the regional market shows lower adoption rates than estimated by the NPCC, such as heat pump water heaters. The CPA forecasts incremental annual achievable potential for all sectors at 6.0 aMW (52,657 MWh) in 2014, increasing to cumulative savings of 156.1 aMW (1,367,490 MWh) by 2033. Table 3.1 and Figure 3.3 show the CPA results for technical, economic, and achievable potentials. The projected baseline electricity consumption forecast increases 44 percent during the 20-year planning horizon. Figure 3.3 compares the technical, economic, achievable potentials, and cumulative first-year savings, for selected years. 4 The Industry definition of economic potential and the definition of economic potential referred to in this document are consistent with the definition of “realizable potential for all realistically achievable units”. 5 There are other tests to represent economic potential from the perspective of stakeholders (e.g., Participant or Utility Cost), but the TRC is generally accepted as the most appropriate representation of economic potential because it tends to represent the net benefits of energy efficiency to society. The economic screen uses the TRC as a proxy for moving forward and representing achievable energy efficiency savings potential for measures that are most cost-effective. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 80 of 1125 Chapter 3–Energy Efficiency Avista Corp 2013 Electric IRP Table 3.1: Cumulative Potential Savings (Across All Sectors for Selected Years6) 2014 2015 2018 2023 2028 2033 Cumulative Annual Savings (MWh) Achievable Potential 52,657 104,806 337,150 648,778 991,979 1,367,490 Economic Potential 316,722 480,967 1,091,669 1,670,165 2,274,053 2,667,367 Technical Potential 1,163,373 1,372,283 2,251,749 3,188,349 3,899,655 4,355,152 Cumulative Annual Savings (aMW) Achievable Potential 6.0 12.0 38.5 74.1 113.2 156.1 Economic Potential 36.2 54.9 124.6 190.7 259.6 304.5 Technical Potential 132.8 156.7 257.0 364.0 445.2 497.2 Figure 3.3: Cumulative Conservation Potentials, Selected Years 6 Projections include pumping as derived from the Sixth Power Plan’s calculator as well as Schedule 25P being modeled separately based on that customer’s historical program participation. The decision to model Schedule 25P separately was due to this rate schedule being one large industrial customer and this method seemed more accurate than treating and modeling this customer as a generic industrial customer. 0 100 200 300 400 500 600 2014 2015 2018 2023 2028 2033 en e r g y s a v i n g s ( a M W ) Technical Potential Economic Potential Achievable Potential Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 81 of 1125 Chapter 3–Energy Efficiency Avista Corp 2013 Electric IRP Conservation Targets This IRP process provides a biennial conservation target for the EIA Biennial Conservation Plan. Other components, such as conservation from distribution and transmission efficiency improvements, combined with the energy efficiency target to arrive at the full Biennial Conservation Plan target for Washington comparable to what is included in the NPCC Sixth Power Plan target. Based on first year incremental savings, Table 3.2 illustrates Avista’s achievable potential for 2014-2015, as well as a comparison with the Sixth Power Plan’s calculator option 1. The Sixth Power Plan includes components other than conservation such as distribution system efficiencies. Table 3.2 compares the CPA results with the calculator’s energy efficiency portion, excluding distribution efficiency. Table 3.2: Annual Achievable Potential Energy Efficiency (aMW) 2014 2015 NPCC Sixth Power Plan Target Idaho 5.92 6.13 Washington 9.47 9.81 Total 15.39 15.94 Less Distribution Efficiency from the Sixth Power Plan Idaho (0.33) (0.45) Washington (0.69) (0.96) Total (1.02) (1.42) Sixth Power Plan Conservation Target Idaho 5.59 5.68 Washington 8.78 8.84 Total 14.37 14.52 Achievable Potential (i.e. Target), net of conversions Idaho 1.75 1.57 Washington 3.80 3.87 Total 5.55 5.44 The 2014-15 Biennial Conservation Plan compliance period targets are below those from the Sixth Power Plan for several reasons. First, the calculator provides an approximation of the level of conservation utilities should pursue using regional assumptions; these assumptions may differ from the specifics of a utility’s service territory. Avista’s CPA study employs a methodology consistent with the NPCC while incorporating Avista-specific assumptions to develop an estimate of savings potential for acquisition through energy efficiency programs. Second, the Sixth Power Plan is relatively dated and was developed prior to the Great Recession. It thus contains assumptions of higher growth than observed in recent years. Lower growth reduces potential savings. The Sixth Power Plan does not incorporate the effects of various residential appliance equipment standards promulgated after the Sixth Power Plan. Further, the higher than projected 2010-11 conservation acquisition results decreased Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 82 of 1125 Chapter 3–Energy Efficiency Avista Corp 2013 Electric IRP baseline use, thereby diminishing future conservation potential since Avista had already captured those savings. Finally, avoided costs are significantly lower than projected when the Sixth Power Plan was developed. Electricity to Natural Gas Fuel Switching While fuel efficiency is not included in the NPCC Sixth Power Plan, Avista has a history of fuel switching from electricity to natural gas, and continues to target natural gas direct use as the most efficient resource option when available. Incremental to the targets listed above are energy savings potential attributable to space and water heat electric to natural gas conversions. Table 3.3 illustrates energy savings potentials from converting electric furnaces and water heaters to natural gas. Nearly all savings are in the residential sector. Conversions ramp up slowly, but because it removes most of the electricity use from two of the largest residential end uses (water and space heating). Space and water heating conversions account for approximately 19 percent of the residential savings during the 20-year IRP period. Table 3.3: Cumulative Achievable Savings from Conversion to Natural Gas (MWh) Washington Conversion Potential 2014 2015 2018 2023 2033 Water heater - convert to gas potential 825 1,586 4,112 9,924 20,221 Furnace - convert to gas potential 2,322 5,047 12,715 25,105 55,787 Total Washington conversion potential 3,147 6.633 16,827 35,028 76,009 Idaho Conversion Potential 2014 2015 2018 2023 2033 Water heater - convert to gas potential 47 121 602 4,264 16,451 Furnace - convert to gas potential 837 1,792 4,460 8,698 19,598 Total Idaho conversion potential 884 1,913 5,062 12,961 36,049 Total Service Territory Savings 4,031 1,920 21,889 47,989 112,058 Comparison with the Sixth Power Plan Methodology As required by Washington Administrative Code (WAC) Chapter 480-109-010 (3)(c), this section describes the technologies, data collection, processes, procedures and assumptions used to develop its biennial targets, along with changes in assumptions or methodologies used in Avista’s IRP or the NPCC Sixth Power Plan. WAC Chapter 480-109-010 (4)(c) requires the Washington Utilities and Transportation Commission’s (UTC) approval, approval with modifications, or rejection of the targets. EnerNOC worked with the NPCC staff to compare methodologies and approaches to ensure methodological consistency. The CPA methodology is consistent with the Sixth Power Plan in several key ways. Both the Sixth Power Plan and EnerNOC’s approaches utilized end use models employing a bottom-up approach. The models draw on appliance stock, saturation levels and efficiencies information to construct future load requirements. EnerNOC conducted a thorough review of baseline and measure assumptions used by the NPCC and developed a baseline energy- use projection absent any additional energy efficiency measures while including the impact of known codes and standards currently approved at the time of this study. The study reviewed and incorporated NPCC assumptions when Avista-specific or more updated data was not available. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 83 of 1125 Chapter 3–Energy Efficiency Avista Corp 2013 Electric IRP The CPA study developed a comprehensive list of energy-efficiency technologies and end use measures, including those in the Sixth Power Plan. Since the efficiency measures, equipment, and other data used in the Sixth Power Plan are somewhat dated, information from the latest Regional Technical Forum workbooks were used, as well as additional information on measures and equipment specific to Avista. EnerNOC developed equipment saturations, measure costs, savings, estimated useful lives and other parameters based on data from the Sixth Power Plan Conservation Supply Curve workbook databases, the Regional Technical Forum, Avista’s Technical Reference Manual, NEEA reports, and other data sources. Similar to the Sixth Power Plan, the study accounts for the difference between lost and non-lost opportunities, and how this affects the rate at which energy efficiency measures penetrate the market. The study used the TRC test as the measure for judging cost-effectiveness. For a more detailed discussion of measures and equipment evaluated within the potential study, please refer to the CPA report prepared by EnerNOC in Appendix C. After screening measures for cost-effectiveness, the CPA applied a series of factors to evaluate realistic market acceptance rates and program implementation considerations. The resulting achievable potential reflects the realistic deployment rates of energy efficiency measures in Avista’s service territory. These factors account for market barriers, customer acceptance, and the time required to implement programs. To develop these factors, EnerNOC reviewed the ramp rates used in the Sixth Power Plan Conservation Supply Curve workbooks and considered Avista’s experience. The Sixth Power Plan assessed a 20-year period beginning in 2010, while this CPA study begins in 2014. Where the Sixth Power Plan relied on average regional data, the CPA utilized data from Avista’s service territory, as well as current economic data. Therefore, an allocation of regional potential based on sales, as applied in the Sixth Power Plan, would not necessarily account for Avista’s unique service territory characteristics such as customer mix, use per customer, end use saturations, fuel shares, current measure saturations, and expected customer and economic growth. In addition, some industries included in the Sixth Power Plan may not exist in Avista’s service territory. While the Sixth Power Plan incorporates distribution system efficiencies, the Avista CPA includes only energy efficiency from energy conservation while distribution system efficiencies and thermal system efficiencies are part of Avista’s targets from other sources. A detailed discussion of Avista’s distribution feeder program is in Chapter 5, Transmission & Distribution. Avoided Cost Sensitivities EnerNOC modeled several scenarios with varying avoided costs assumptions in addition to the Expected Case used for the 2013 IRP to test sensitivity to changes in avoided costs. The scenarios included 150 percent, 125 percent, 100 percent, and 75 percent of the avoided costs relative to the 110 percent level used in the Expected Case. Figure 3.4 illustrates the avoided cost scenarios. Overall, energy efficiency proved to be sensitive to avoided cost assumptions. In particular, acquiring incremental energy efficiency becomes increasingly expensive, so increases in avoided costs do not provide equivalent percentage increases in achievable potential. The Expected Case achievable potential is approximately 154 aMW by 2033, excluding savings from Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 84 of 1125 Chapter 3–Energy Efficiency Avista Corp 2013 Electric IRP distribution line losses. With the 150 percent avoided cost case, cumulative achievable potential increases by 23 percent compared with the Expected Case reference scenario, while the 125 percent, 100 percent, and the 75 percent avoided cost cases yielded achievable potential equal to 85 percent, 94 percent and 113 percent of the reference scenario, respectively. Table 3.4 shows achievable potential under the five avoided cost scenarios and the cost impact over the IRP timeframe. Table 3.4: Achievable Potential with Varying Avoided Costs 75% AC 100% AC Expected Case 125% AC 150% AC Cumulative energy savings (aMW) 131 145 154 174 189 Savings percentage change compared to Expected Case -15% -6% 0% 13% 23% 20-Year Nominal Spending (millions) $459 $560 $711 $949 $1,150 Cost percentage change compared to Expected Case -35% -21% 0% 34% 62% In 2014, 41 percent of the projected achievable potential is from residential class measures. This roughly 40/60 allocation between residential and nonresidential savings is consistent with a finding from the previous CPA that the nonresidential sector is becoming the source of a larger share of savings potential. This shift is occurring because many low-cost residential measures are implemented and residential equipment codes and standards are capturing savings previously incented through utility programs. Approximately 48 percent of residential projected savings come from lighting in 2018, followed by water and space heating. In subsequent years, the percentage of residential savings from lighting decreases as lighting codes and standards are enacted. As a result, space and water heating measures provide greater relative savings potential in the later years of the study. In the commercial and industrial sectors, lighting accounts for approximately 64 percent of savings potential in 2018 followed by office equipment, heating, ventilation and air conditioning (HVAC), refrigeration, and machine drives. Similar to the residential sector, the savings potential from lighting decreases to about one-third of cumulative potential in 2033, with HVAC, water heating and industrial measures gaining an increasing share of long-term potential. Heat pump water heater measures in the Sixth Power Plan were projected to replace the CFLs contribution (i.e. significant savings at relatively low costs) in earlier plans. The CPA found heat pump water heaters begin to pass the cost-effectiveness screen in 2014. However, because they are unsuitable for installation in conditioned spaces, the CPA assumes they are not applicable in multifamily and mobile homes. The market for this technology remains immature, limiting the number of near-term installations. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 85 of 1125 Chapter 3–Energy Efficiency Avista Corp 2013 Electric IRP Figure 3.4 shows supply curves composed of the stacked measures and equipment for the IRP time horizon in ascending order of avoided cost. Since there is a gap in the cost of the energy efficiency measures moving up the supply curve, the measures with a very high cost cause a rapid sloping of the curve. The shift of the supply curve toward the right as avoided costs increase is a consequence of increasing amounts of cost-effective potential, but the average cost of acquiring that potential is increasing. Figure 3.4: Conservation Supply Curve (2033- No Fuel Switching, Pumping and Losses) Energy Efficiency-Related Financial Impacts The EIA requires utilities with over 25,000 customers to obtain a fixed percentage of their electricity from qualifying renewable resources and to acquire all cost-effective and achievable energy conservation.7 For the first 24-month period under the law (2010-11), this equaled a ramped-in share of the regional 10-year target identified in the Sixth Power Plan. Penalties of at least $50 per MWh exist for utilities not achieving Washington targets for conservation resource acquisition. Regional discussions were under way regarding the definition of “pro-rata” during the 2009 IRP. Avista proposed ramping the 10-year targets identified in the Sixth Power Plan instead of acquiring 20 percent of the first 10-year target identified in the Sixth Power Plan. The “pro-rata” amount would have created drastic ramping challenges, especially in the early years. Due to inconsistencies between the 2009 IRP and the Council’s methodology, Avista elected to use Option 1 of the Sixth Power Plan to establish its conservation acquisition target, adjusted to include electric-to-natural gas space and water heating fuel conversions. The acquisition target was 11 percent 7 The EIA defines cost effective as 10 percent higher than the cost a utility would otherwise spend on energy acquisition. $0 $100 $200 $300 $400 $500 0 50 100 150 200 $ p e r M W h average megawatts Conservation Supply Curve Expected Case Conservation Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 86 of 1125 Chapter 3–Energy Efficiency Avista Corp 2013 Electric IRP greater than Avista’s IRP energy efficiency target for the same period. In April 2010, the UTC approved Avista’s 10-year Achievable Potential and Biennial Conservation Target Report in Docket UE-100176. The EIA requirement to acquire all cost-effective and achievable conservation may pose significant financial implications for Washington customers. Based on the CPA results, the projected 2014 cost to electric customers is $12.6 million (1.7 percent of total electric revenue requirement) with approximately $9 million of that projected to be for Washington. This annual amount grows to $22.2 million by the tenth year, representing a total of $215.8 million over this 10-year period for electric customers. Figure 3.5 shows the annual cost (in millions of nominal dollars) for the utility to acquire the projected electric achievable potential. Figure 3.5: Existing & Future Energy Efficiency Costs and Energy Savings Integrating Results into Business Planning and Operations The CPA and IRP energy efficiency evaluation processes provide high-level estimates of cost-effective conservation acquisition opportunities. While results of the IRP analyses establish baseline goals for continued development and enhancement of energy efficiency programs, the results are not detailed enough to form an acquisition plan. Avista uses both CPA and IRP evaluation results to establish a budget for energy efficiency measures, to help determine the size and skill sets necessary for future operations, and for identifying general target markets for energy efficiency programs. This section provides an overview of recent operations of the individual sectors as well as energy efficiency business planning. 0 10 20 30 40 50 60 70 80 90 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 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 Energy Savings (aMW) Spending (millions $) Levelized Cost ($/MWh) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 87 of 1125 Chapter 3–Energy Efficiency Avista Corp 2013 Electric IRP Avista retained EnerNOC to develop an independent conservation potential assessment study for its Washington and Idaho electric service territory. This study is useful for the implementation of energy efficiency programs in the following ways. Identify conservation resource potential by sector, segment, end use and measure of where energy savings may come from. The energy efficiency implementation staff can use CPA results to determine the segments and end uses/measures to target. Identify the measures with the highest TRC benefit-cost ratios, resulting in the lowest cost resources with the greatest benefit. Identify measures with great adoption barriers based on the economic versus achievable results by measure. With this information, staff can develop effective programs for measures with slow adoption or significant barriers. Improve the design of current program offerings. Staff can review the measure level results by sector and compare the savings with the largest-saving measures currently offered. This analysis may lead to the addition or elimination of programs. Consideration for lost opportunities, and whether to target one particular measure over another measure, are made. One possibility may be to offer higher incentives on measures with higher benefits and lower incentives on measures with lower benefits. The CPA study illustrates potential markets and provides a list of cost-effective measures to analyze through the on-going energy efficiency business planning process. This review of residential and non-residential program concepts and their sensitivity to more detailed assumptions will feed into program plans for target markets. Potential measures not currently considered at the time of the CPA may develop in the future will be evaluated for possible inclusion in Avista’s Business Plan. Residential Sector Overview Avista offers most residential energy efficiency programs through prescriptive or standard offer programs targeting a range of end uses. Programs offered through this prescriptive approach during 2012 included space and water heating conversions, ENERGY STAR® appliances, ENERGY STAR® homes, space and water equipment upgrades and home weatherization. The ENERGY STAR® appliance program phases out in 2013 due to results of a Cadmus net-to-gross study indicating market transformation to a point that incentives are no longer required. Avista offers its remaining residential energy efficiency programs through other channels. For example, a third-party administer, JACO, operates the refrigerator/freezer recycling program. UCONS administers a manufactured home duct-sealing program. CFL and specialty CFL buy-downs at the manufacturer level provide customers access to lower-priced lamps. Home energy audits, subsidized by a grant from the American Recovery and Reinvestment Act (ARRA), ended in 2012. This program offered home inspections including numerous diagnostic tests and provided a leave-behind kit containing CFLs and weatherization materials. Avista provides educational tips and CFLs at various rural and urban events in an effort to reach all areas within its service Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 88 of 1125 Chapter 3–Energy Efficiency Avista Corp 2013 Electric IRP territory. Avista processed 14,300 energy efficiency rebates in 2012, benefiting approximately 14,000 households. Over $2.3 million of rebates offset the cost of implementing energy efficiency upgrades for our customers. Third-party contractors implemented a second appliance-recycling program and a manufactured home duct- sealing program. Avista participated in a regional upstream buy-down program called Simple Steps Smart Savings where lighting and showerheads were provided through participating retailers at a reduced amount for customers. Finally, Avista distributed over 26,000 CFLs at various community events throughout the service territory. Residential programs contributed 17,744 MWh and 341,187 therms of energy savings. Low Income Sector Overview Six Community Action Agencies administer low-income programs. During 2012 these programs targeted a range of end uses including space and water heating conversions, ENERGY STAR® refrigerators, space and water heating equipment upgrades, and weatherization offered site-specifically through individualized home audits. Avista also funds health and human safety investments considered necessary to ensure habitability of homes and protect investments in energy efficiency, as well as administrative fees enabling Community Action Agencies to continue to deliver these programs. The Community Action Agencies had 2012 budgets of $2.0 million for Washington and $940,000 for Idaho as well as an additional $50,000 for conservation education in Idaho. Avista processed approximately 1,400 rebates, benefitting 400 households. During 2012, Avista paid $2.6 million in rebates to the Community Action Agencies to provide fully-subsidized energy efficiency upgrades, health and human safety, and administrative costs for the agencies to administer these programs. The agencies spent nearly $394,000 on health and human safety or 13 percent of their total expenditures and within their 15 percent allowance for this spending category. Low-income energy efficiency programs contributed 1,111 MWh of electricity savings and 33,029 therms of natural gas savings. Non-Residential Sector Overview For the non-residential sectors (commercial, industrial and multi-family applications), energy efficiency programs are offered on a site-specific or custom basis. Avista offers a more prescriptive approach when treatments result in similar savings and the technical potential is high. An example is the prescriptive lighting program. The applications are not purely prescriptive in the traditional sense, such as with residential applications where homogenous programs are provided for all residential customers; however, a more prescriptive approach can be applied for these similar applications. Non-residential prescriptive programs offered by Avista include, but are not limited to, space and water heating conversions, space and water heating equipment upgrades, appliance upgrades, cooking equipment upgrades, personal computer network controls, commercial clothes washers, lighting, motors, refrigerated warehouses, traffic signals, and vending controls. Also included are residential program offerings such as multi- family and multi-family market transformation since these projects are implemented site- specifically unlike other residential programs. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 89 of 1125 Chapter 3–Energy Efficiency Avista Corp 2013 Electric IRP During 2012, Avista processed 4,167 energy efficiency projects resulting in the payment of over $13.5 million in rebates paid directly to customers to offset the cost of their energy efficiency projects. These projects contributed 58,756 MWh of electricity and 399,733 therms of natural gas savings. Energy Smart Grocer is a regional, turnkey program administrated through PECI. This program has been operating for several years. This program will approach saturation levels during the early part of this 20-year planning horizon. The programs highlighted by the recently completed CPA study will be reviewed for the development of target marketing and the creation of new energy efficiency programs. All electric-efficiency measures with a simple payback exceeding one year and less than eight years for lighting measures or thirteen years for other measures automatically qualify for the non-residential portfolio. The IRP provides account executives, program managers/coordinators and energy efficiency engineers with valuable information regarding potentially cost-effective target markets. However, the unique and specific characteristics of a customer’s facility override any high-level program prioritization for non-residential customers. Demand Response Over the past decade, demand response has gained attention in the industry as an alternative method to meet peak load growth instead of constructing new generation. Demand response cuts load to specific customers during peak demand use. Typically, customers enroll in programs allowing the utility to change its usage in exchange for discounts. National attention focuses on residential programs to control water heaters, space heating and air conditioners. Past and Current Programs Avista’s experience with demand response or load management dates back to the 2001 Energy Crisis. Avista responded with an All-Customer Buy-Back program, an Irrigation Buy-Back program and bi-lateral agreements with large industrial customers. These methods along with commercial and residential enhanced energy efficiency programs were effective and enabled Avista to reduce its need for purchases in a very high cost Western energy market. Experience was gained in July 2006 when a multi-day heat wave required Avista to invoke immediate demand response through a media request for customers to conserve and a large customer reduction, Avista was able to reduce same day load by an estimated 50 MW. Avista conducted a two-year residential load control pilot between 2007 and 2009 to study specific technologies, examine cost-effectiveness and customer acceptance. The intent of this pilot was to be scalable with Direct Load Control (DLC) devices installed in approximately 100 volunteer households in Sandpoint and Moscow, Idaho. This small sample allowed Avista to test the product and systems with the same benefits as if this were a larger scale project, but in a controlled and customer-friendly manner. DLC devices were installed on heat pumps, water heaters, electric forced-air furnaces and air conditioners to control operation during 10 scheduled events at peak times ranging from two hours to four hours. A separate group within those communities participated in an Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 90 of 1125 Chapter 3–Energy Efficiency Avista Corp 2013 Electric IRP In-Home-Display device study as part of this pilot. The program intended to gain customer experience with “near-real time” energy usage feedback equipment. Information gained from the pilot is detailed in the report filed with the Idaho Public Utilities Commission (IPUC). Avista is engaged in a new demand response program as part of the Northwest Regional Smart Grid Demonstration Project (SGDP) with Washington State University (WSU) and approximately 70 residential customers in the Pullman and Albion, Washington communities. Residential customer assets include a forced-air electric furnace, heat pump, and central air-conditioning with enabling control technology of a Smart Communicating Thermostat provided and installed by Avista. The control approach is non-traditional in several ways. First, the demand response “events” are not prescheduled, but assets are directly controlled by predefined customer preferences (no more than a 2 degree offset for the residential customers, and an energy management system at WSU with a consol operator) at anytime the regional Transactive signal needs the curtailment. More importantly, the technology used in this demand response portion of the SGDP predicts if equipment is available for participation in the control event. Lastly, value quantification extends beyond demand and energy savings and explores bill management options for customers with whole house usage data analyzed in conjunction with smart thermostat data. Inefficient homes identified through this analysis prompt customer engagement. Experiences from the both residential DLC pilots (North Idaho Pilot and the SGDP) show participating customer engagement is high; however, recruiting participants is challenging. Avista’s service territory has a high penetration of natural gas for both typical DLC appliance types of space heat and water heat. Customers who have interest may not have qualifying equipment making them ineligible for participation in the Program. Secondly, customers initially are not interested enough in DLC programs. Supporting evidence of this second aspect is in recent regional DLC programs conducted by the BPA. Lastly, Avista is unable at this time to offer pricing strategies other then direct incentives to compensate customers for participation in the program, which limits customer interest. The amount of demand and energy reductions per household is lower than a commercial and/or industrial DLC program. Consequently, many households are required to yield significant peak reduction savings, which is why residential DLC programs are commonly mass-market programs. Mass-market scale is needed for program cost effectiveness. Rather than focusing on residential demand response, Avista will focus its Demand Response studies towards commercial and industrial customers. Fewer but larger loads are anticipated to yield adequate acquisition. For this IRP, Avista assumes a potential of five MW per year for a 20 MW total acquisition, assuming a cost of $120 per kW-year (2012 dollars). As an Action Item, Avista will need to complete an assessment of potential demand response in its commercial and industrial customers, including, a measure of peak reduction, flexibility capability (i.e. spinning reserves) and costs to implement programs. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 91 of 1125 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 92 of 1125 Chapter 4–Policy Considerations Avista Corp 2013 Electric IRP 4. Policy Considerations Public policy can significantly affect Avista’s current generation resources and the types of resources Avista pursues. The political and regulatory environments have changed significantly since publication of the last IRP. Prospects for implementing a federal cap and trade program to reduce greenhouse gases have greatly diminished. At the same time, a range of regulatory measures pursued by the Environmental Protection Agency (EPA), coupled with political and legal efforts initiated by environmental groups and others, has increased pressures on thermal generation – specifically coal-fired generation. New regulations have particular implications for coal generation, as they involve regional haze, coal ash disposal, mercury emissions, water quality, and greenhouse gas emissions. This chapter provides an overview and discussion about some of the more pertinent public policy issues relevant to the IRP. Environmental Issues Environmental concerns present unique resource planning challenges due to the continuously evolving nature of environmental regulation. If avoiding certain air emissions were the only issue faced by electric utilities, resource planning would only require a determination of the amounts and types of renewable generating technology and energy efficiency to acquire. However, the need to maintain system reliability, acquire resources at least cost, mitigate price volatility, meet renewable generation requirements, manage financial risks, and meet environmental laws complicates utility planning. Each generating resource has distinctive operating characteristics, cost structures, and environmental regulatory challenges. Traditional thermal generation technologies, like coal-fired and natural gas-fired plants, are reliable and provide capacity along with energy. Coal-fired units have high capital costs, long permitting and construction lead times, and relatively low and stable fuel costs. New coal plants are currently difficult, if not impossible, to site due to state and federal laws and regulations, local opposition, and environmental concerns ranging from the impacts of coal mining to power plant emissions. Remote mine locations increase costs from either the transportation of coal to the plant or the transportation of the generated electricity to load centers. By comparison, natural gas-fired plants have relatively low capital costs compared to coal, can typically be located near load centers, can be constructed in relatively short time frames, emit less than half the greenhouse gases emitted by coal, and are the only utility-scale baseload resource that can be developed in many locations. Higher fuel price volatility has historically affected the Chapter Highlights Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 93 of 1125 Chapter 4–Policy Considerations Avista Corp 2013 Electric IRP economics of natural gas-fired plants. Their performance also decreases in hot weather conditions, it is increasingly difficult to secure sufficient water rights for their efficient operation, and they emit significant greenhouse gases relative to renewable resources. Renewable energy technologies such as wind, biomass, and solar generation have different challenges. Renewable resources are attractive because they have low or no fuel costs and few, if any, direct emissions. However, solar- and wind-based renewable generation has limited or no capacity value for the operation of Avista’s system, and their variable output presents integration challenges requiring additional non-variable capacity investments. Renewable projects also draw the attention of environmental groups interested in protecting visual aspects of landscapes and wildlife populations. Similar to coal plants, renewable resource projects are located near their fuel sources rather than load centers. The need to site renewable resources in remote locations often requires significant investments in transmission interconnection and capacity expansion, as well as mitigating possible wildlife and aesthetic issues. Unlike coal or natural gas-fired plants, the fuel for non-biomass renewable resources may not be transportable from one location to another to utilize existing transmission facilities or to minimize opposition to project development. Dependence on the health of the forest products industry and access to biomass materials, often located in publicly owned forests, poses challenges to biomass facilities. The long-term economic viability of renewable resources is uncertain for at least two important reasons. First, federal investment and production tax credits will begin expiring for projects beginning construction after 2013. The continuation of credits and grants cannot be relied upon in light of the impact such subsidies have on the finances of the federal government, and the relative maturity of wind and solar technology development. Second, many relatively unpredictable factors affect the costs of renewable technologies, such as renewable portfolio standard mandates, material prices and currency exchange rates. Capital costs for wind and solar have decreased since the 2011 IRP, but future costs remain uncertain. Even though there appears to be very little, if any, chance of a national greenhouse gas cap and trade program, uncertainty still exists about greenhouse gas regulation at this IRP’s writing. There are pockets of strong regional and national support to address climate change, but little political will at the national level to implement significant new laws to reduce greenhouse gas emissions. However, since the 2011 IRP publication, changes in the approach to greenhouse gas emissions regulation have occurred, including: The EPA has commenced actions to regulate greenhouse gas emissions under the Federal Clean Air Act, although some of these efforts have been delayed and most of these initiatives are being legally challenged; and California has established economy-wide cap and trade regulation. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 94 of 1125 Chapter 4–Policy Considerations Avista Corp 2013 Electric IRP Avista’s Climate Change Policy Efforts Avista’s Climate Policy Council is an interdisciplinary team of management and non-management employees that: Facilitates internal and external communications regarding climate change issues; Analyzes policy impacts, anticipates opportunities and evaluates strategies for Avista Corporation; and Develops recommendations on climate related policy positions and action plans. The core team of the Climate Policy Council includes members from Environmental Affairs, Government Relations, External Communications, Engineering, Energy Solutions and Resource Planning groups. Other areas of Avista participate as needed to provide input on certain topics. The monthly meetings for this group include work divided into immediate and long-term concerns. The immediate concerns include reviewing and analyzing proposed or pending state and federal legislation, reviewing corporate climate change policy, and responding to internal and external data requests about climate change issues. Longer-term issues involve emissions tracking and certification, considering the merits of different greenhouse gas policies, actively participating in the development of legislation, and benchmarking climate change policies and activities against other organizations. Membership in the Edison Electric Institute is Avista’s vehicle to engage in federal-level climate change dialog. Avista participates in discussions about hydroelectric and biomass issues through membership in national hydroelectric and biomass associations. Greenhouse Gas Emissions Concerns for Resource Planning Resource planning in the context of greenhouse gas emissions regulation raises concerns about the balance between Avista’s obligations for environmental stewardship, and cost implications for its customers. Resource planning must consider the cost effectiveness of resource decisions, as well as the need to mitigate the financial impact of potential future emissions risks. Although some parties would advocate for the immediate reduction or elimination of certain resource technologies, such as coal or even natural gas-fired plants, there are economic and reliability limitations and other concerns related to pursuing this type of policy. Technologically, it is possible to replace fossil-fueled generation with renewables, but the increased prices to customers and the challenges of obtaining enough renewable generation while maintaining system reliability are daunting. Complying with greenhouse gas regulations, particularly in the form of a cap and trade mechanism, involves at least two approaches: ensuring Avista maintains sufficient allowances and/or offsets to correspond with its emissions during a compliance period, and undertaking measures to reduce Avista’s future emissions. Enabling emission reductions on a utility-wide basis could entail any or all of the following: Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 95 of 1125 Chapter 4–Policy Considerations Avista Corp 2013 Electric IRP Increasing the efficiency of existing fossil-fueled generation resources; Reducing emissions from existing fossil-fueled generation through fuel displacement including co-firing with biomass or biofuels; Permanently decreasing the output from existing fossil-fueled resources and substituting resources with lower greenhouse gas emissions; Decommissioning or divesting of a fossil-fueled generation and substituting with lower-emitting resources; Reducing exposure to market purchases of fossil-fueled generation, particularly during periods of diminished hydropower production, by establishing larger reserves based on lower-emitting technologies; and Increasing investments in energy efficiency measures, thereby displacing future resource needs. With the exception of Avista’s commitment to energy efficiency, the specific costs and risks of the actions listed above cannot be adequately evaluated until greenhouse gas emission regulations are established. After a regulatory regime has been implemented the economic effects can be modeled. A specific reduction strategy in a future IRP may occur when greater regulatory clarity and better modeling parameters exist. In the meantime, greenhouse gas emissions reductions in this IRP rely upon EPA and state regulations, established renewable portfolio policies, and established state level greenhouse gas emissions laws. State and Federal Environmental Policy Considerations The direction of federal greenhouse gas emissions policies has changed significantly since the 2011 IRP. In the prior plan, Avista based greenhouse gas emissions costs on a weighted average of four different reduction policies that included various levels of state and federal cap and trade programs and carbon taxes. The state of political discourse during the development of this IRP indicates there is no imminent federal cap and trade or carbon tax. Even though there is no national greenhouse gas emissions cost in the Expected Case, this IRP includes a greenhouse gas reduction scenario, with high and low prices for offset/taxes as a proxy to model the possible impacts of future regulation. Chapter 7, Market Analysis, describes the greenhouse gas scenarios and the modeling results. The President’s Climate Action Plan was released on June 25, 2013, after the modeling for this IRP was completed. The plan outlines the Obama administration’s three pillars of executive action regarding climate change, which include the following: Reduce U.S. carbon emissions; Make infrastructure preparations to mitigate the impacts of climate change; and Work on efforts to reduce international greenhouse gas emissions and prepare for the impacts of climate change. A presidential memo was also sent to the Administrator of the EPA on the same day as the Climate Action Plan with several climate change related policy targets. The memo directed the EPA to do the following: Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 96 of 1125 Chapter 4–Policy Considerations Avista Corp 2013 Electric IRP Issue new proposed greenhouse gas emissions standards for new electric generation resources by September 30, 2013. Issue new proposed standards for existing and modified sources by June 1, 2014, final standards by June 1, 2015, and require State implementation plans by June 30, 2016. The federal Production Tax Credit (PTC), Investment Tax Credit (ITC), and Treasury grant programs are key federal policy considerations for incenting the development of renewable generation. The current PTC and ITC programs are available for projects that begin construction before the end of 2013. The date is 2016 for solar projects. We did not model an extension of these tax incentives because of the uncertainty of their continuation due to the current federal budget deficit situation. Extension of the PTC may accelerate the development of some regional renewable energy projects. This may affect the development of renewable projects in the Western Interconnect, but not necessarily for Avista, because the current resource mix and low projected load growth do not necessitate the development of new renewables in this IRP. EPA Regulations The EPA regulations that directly, or indirectly, affect electricity generation include the Clean Air Act, along with its various components, such as the Acid Rain Program, National Ambient Air Quality Standard, Hazardous Air Pollutant rules and the Regional Haze Programs. The U.S. Supreme Court ruled the EPA has authority under the Clean Air Act to regulate greenhouse gas emissions from new motor vehicles and has issued such regulations. When these regulations became effective, carbon dioxide and other greenhouse gases became regulated pollutants under the Prevention of Significant Deterioration (PSD) preconstruction permit program and the Title V operating permit program. Both of these programs apply to power plants and other commercial and industrial facilities. In 2010, the EPA issued a final rule, known as the Tailoring Rule, governing the application of these programs to stationary sources, such as power plants. Most recently, EPA proposed a rule in early 2012 setting standards of performance for greenhouse gas emissions from new and modified fossil-fuel-fired electric generating units and announced plans to issue greenhouse gas guidelines for existing sources. Promulgated PSD permit rules may affect Avista’s thermal generation facilities in the future. These rules can affect the amount of time it takes to obtain permits for new generation and major modifications to existing generating units and the final limitations contained in permits. The promulgated and proposed greenhouse gas rulemakings mentioned above have been legally challenged in multiple venues so we cannot fully anticipate the outcome or extent our facilities may be impacted, nor the timing of rule finalization. Clean Air Act The Clean Air Act (CAA), originally adopted in 1970 and modified significantly since, intends to control covered air pollutants to protect and improve air quality. Avista complies with the requirements under the CAA in operating our thermal generating plants. The CAA currently requires a Title V operating permit for Colstrip Units 3 and 4 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 97 of 1125 Chapter 4–Policy Considerations Avista Corp 2013 Electric IRP (expires in 2017), Coyote Springs 2 (renewal expected in 2013), the Kettle Falls GS (renewal expected in 2013), and the Rathdrum CT (expires in 2016). Boulder Park, Northeast CT, and other small activities only require minor source operating or registration permits based on their limited operation and emissions. Title V operating permits renewals occur every five years and typically update all applicable CAA requirements for each facility. Discussion of some major CAA programs follows. Acid Rain Program The Acid Rain Program is an emission-trading program for reducing nitrous dioxide by two million tons and sulfur dioxide by 10 million tons below 1980 levels from electric generation facilities. Avista manages annual emissions under this program for Colstrip Units 3 and 4, Coyote Springs 2, and Rathdrum Generating Stations. National Ambient Air Quality Standards EPA sets National Ambient Air Quality Standards for pollutants considered harmful to public health and the environment. The CAA requires regular court-mandated updates to occur in June 2013 for nitrogen dioxide, ozone, and particulate matter. Avista does not anticipate any material impacts on its generation facilities from the revised standards at this time. Hazardous Air Pollutants (HAPs) HAPs, often known as toxic air pollutants or air toxics, are those pollutants that may cause cancer or other serious health effects. EPA regulates toxic air pollutants from a published list of industrial sources referred to as "source categories". These pollutants must meet control technology requirements if they emit one or more of the pollutants in significant quantities. EPA recently finalized the Mercury Air Toxic Standards (MATS) for the coal and oil-fired source category. Colstrip Units 3 and 4’s existing emission control systems should be sufficient to meet mercury limits. For the remaining portion of the rule that specifically addresses air toxics (including metals and acid gases), the joint owners of Colstrip are currently evaluating what type of new emission control systems will be required to meet MATS compliance in 2015. Avista is unable to determine to what extent, or if there will be any, material impact to Colstrip Units 3 and 4 at this time. Regional Haze Program EPA set a national goal to eliminate man-made visibility degradation in Class I areas by the year 2064. Individual states are to take actions to make “reasonable progress” through 10-year plans, including application of Best Available Retrofit Technology (BART) requirements. BART is a retrofit program applied to large emission sources, including electric generating units built between 1962 and 1977. In the absence of state programs, EPA may adopt Federal Implementation Plans (FIPs). On September 18, 2012, EPA finalized the Regional Haze FIP for Montana. The FIP includes both emission limitations and pollution controls for Colstrip Units 1 and 2. Colstrip Units 3 and 4 are not currently affected, although the units will be evaluated for Reasonable Progress at the next review period in September 2017. Avista does not anticipate any material impacts on Colstrip Units 3 and 4 at this time. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 98 of 1125 Chapter 4–Policy Considerations Avista Corp 2013 Electric IRP EPA Mandatory Reporting Rule Any facility emitting over 25,000 metric tons of greenhouse gases per year must report its emissions to EPA. Colstrip Units 3 and 4, Coyote Springs 2, and Rathdrum CT are currently reporting under this requirement. The Mandatory Reporting Rule also requires greenhouse gas reporting for natural gas distribution system throughput, fugitive emissions from electric power transmission and distribution systems, fugitive emissions from natural gas distribution systems, and from natural gas storage facilities. Avista reported the applicable greenhouse gas emissions in 2012. The State of Washington requires mandatory greenhouse gas emissions reporting similar to the EPA requirements. Oregon has similar reporting requirements. State and Regional Level Policy Considerations The lack of a comprehensive federal greenhouse gas policy encouraged several states, such as California, to develop their own climate change laws and regulations. Climate change legislation can take many forms, including economy-wide regulation in the form of a cap and trade system, tax or emissions performance standards for power plants. Comprehensive climate change policy can have multiple individual components, such as renewable portfolio standards, energy efficiency standards, and emission performance standards. Washington enacted all of these components, but other jurisdictions where Avista operates have not. Individual state actions produce a patchwork of competing rules and regulations for utilities to follow, and may be particularly problematic for multi-jurisdictional utilities such as Avista. There are 29 states, plus the District of Columbia, with active renewable portfolio standards, and eight additional states have adopted voluntary standards.1 The Western Regional Climate Action Initiative, otherwise known as the Western Climate Initiative (WCI), began with a February 26, 2007, agreement to reduce greenhouse gas emissions through a regional reduction goal and market-based trading system. This agreement included the following signatory jurisdictions: Arizona, British Columbia, California, Manitoba, Montana, New Mexico, Oregon, Utah, Quebec and Washington. In July 2010, the WCI released its Final Design for a regional cap and trade regulatory system to cover 90 percent of the societal greenhouse gas emissions within the region by 2015. Arizona, Montana, New Mexico, Oregon, Utah and Washington formally left WCI in November 2011.2 The only remaining WCI members are British Columbia, California, Manitoba, Ontario, and Quebec. Idaho Policy Considerations Idaho currently does not regulate greenhouse gases or have a renewable portfolio standard (RPS). There is no indication that Idaho is moving toward the active regulation of greenhouse gas emissions. However, the Idaho Department of Environmental Quality would administer greenhouse gas standards under its CAA delegation from the EPA. Montana Policy Considerations Montana has a non-statutory goal to reduce greenhouse gas emissions to 1990 levels by 2020. Montana’s RPS law, enacted through Senate Bill 415 in 2005, requires utilities 1 http://www.dsireusa.org/rpsdata/index.cfm 2 http://www.platts.com/RSSFeedDetailedNews/RSSFeed/ElectricPower/6695863 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 99 of 1125 Chapter 4–Policy Considerations Avista Corp 2013 Electric IRP to meet 10 percent of their load with qualified renewables from 2010 through 2014, and 15 percent beginning in 2015. Avista is exempt from the Montana RPS and its reporting requirements beginning on January 2, 2013, with the passage of SB 164 and its signature by the Governor. Montana implemented a mercury emission standard under Rule 17.8.771 in 2009. The standard exceeds the most recently adopted federal mercury limit. Avista’s generation at Colstrip Units 3 and 4 have emissions controls meeting Montana’s mercury emissions goal. Oregon Policy Considerations The State of Oregon has a history of considering greenhouse gas emissions and renewable portfolio standards legislation. The Legislature enacted House Bill 3543 in 2007, calling for, but not requiring, reductions of greenhouse gas emissions to 10 percent below 1990 levels by 2020, and 75 percent below 1990 levels by 2050. Compliance is expected through a combination of the RPS and other complementary policies, like low carbon fuel standards and energy efficiency measures. The state has not adopted any comprehensive requirements. These reduction goals are in addition to a 1997 regulation requiring fossil-fueled generation developers to offset carbon dioxide (CO2) emissions exceeding 83 percent of the emissions of a state-of-the-art gas-fired combined cycle combustion turbine by paying into the Climate Trust of Oregon. Senate Bill 838 created a renewable portfolio standard requiring large electric utilities to generate 25 percent of annual electricity sales with renewable resources by 2025. Intermediate term goals include five percent by 2011, 15 percent by 2015, and 20 percent by 2020. Oregon ceased being an active member in the Western Climate Initiative in November 2011. The Boardman coal plant is the only active coal-fired generation facility in Oregon; by 2020, it will cease burning coal. The decision by Portland General Electric to make near-term investments to control emissions from the facility and to discontinue the use of coal, serves as an example of how regulatory, environmental, political and economic pressures can culminate in an agreement that results in the early closure of a coal-fired power plant. Washington State Policy Considerations Similar circumstances leading to the closure of the Boardman facility in Oregon encouraged TransAlta, the owner of the Centralia Coal Plant, to agree to shut down one unit at the facility by December 31, 2020, and the other unit by December 31, 2025. The confluence of regulatory, environmental, political and economic pressures brought about the scheduled closure of the Centralia Plant. The State of Washington enacted several measures concerning fossil-fueled generation emissions and generation resource diversification. A 2004 law requires new fossil-fueled thermal electric generating facilities of more than 25 MW of generation capacity to mitigate CO2 emissions through third-party mitigation, purchased carbon credits, or cogeneration. Washington’s EIA, passed in the November 2006 general election, established a requirement for utilities with more than 25,000 retail customers to use qualified renewable energy or renewable energy credits to serve 3 percent of retail load by 2012, 9 percent by 2016 and 15 percent by 2020. Failure to meet these RPS requirements results in at least a $50 per MWh fine. The initiative also requires utilities to acquire all cost effective conservation and energy efficiency measures up to 110 percent of Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 100 of 1125 Chapter 4–Policy Considerations Avista Corp 2013 Electric IRP avoided cost. Additional details about the energy efficiency portion of the EIA are in Chapter 3. A utility can also comply with the renewable energy standard by investing in at least 4 percent of its total annual retail revenue requirement on the incremental costs of renewable energy resources and/or renewable energy credits. In 2012, Senate Bill 5575 amended the EIA to define Kettle Falls Generating Station and other legacy biomass facilities that commenced operation before March 31, 1999, as EIA qualified resources beginning in 2016. A 2013 amendment allows multistate utilities to import RECs from outside the Pacific Northwest to meet renewable goals and allows utilities to acquire output from the Centralia coal plant without jeopardizing alternative compliance methods. Avista will meet or exceed its renewable requirements in this IRP planning period through a combination of qualified hydroelectric upgrades, wind generation from the Palouse Wind PPA, and output from Kettle Falls beginning in 2016. The 2013 IRP Expected Case ensures that Avista meets all EIA RPS goals. Former Governor Christine Gregoire signed Executive Order 07-02 in February 2007 establishing the following GHG emissions goals: 1990 levels by 2020; 25 percent below 1990 levels by 2035; 50 percent below 1990 levels by 2050 or 70 percent below Washington’s expected emissions in 2050; Increase clean energy jobs to 25,000 by 2020; and Reduce statewide fuel imports by 20 percent. Washington state's Department of Ecology has adopted regulations to ensure that its State Implementation Plan comports with the requirements of the EPA's regulation of greenhouse gas emissions. We will continue to monitor actions by the Department as it may proceed to adopt additional regulations under its CAA authorities. In 2007, Senate Bill 6001 prohibited electric utilities from entering into long-term financial commitments beyond five years duration for fossil-fueled generation creating 1,100 pounds per MWh or more of greenhouse gases. Beginning in 2013, the emissions performance standard is lowered every five-years to reflect the emissions profile of the latest commercially available CCCT. The emissions performance standard effectively prevents utilities from developing new coal-fired generation and expanding the generation capacity of existing coal-fired generation unless they can sequester emissions from the facility. The Legislature amended Senate Bill 6001 in 2009 to prohibit contractual long-term financial commitments for electricity deliveries that include more than 12 percent of the total power from unspecified sources. The Department of Commerce (Commerce) has commenced a process expected to result in the adoption of a lower emissions performance standard in 2013; a new standard would not be applicable until at least Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 101 of 1125 Chapter 4–Policy Considerations Avista Corp 2013 Electric IRP 2017. Commerce filed a final rule with 970 pounds per MWh for greenhouse gas emissions on March 6, 2013, with rules becoming effective on April 6, 2013.3 Washington Governor Inslee signed the Climate Action bill (Senate Bill 5802) on April 2, 2013. This law established an independent evaluation of the costs and benefits of established greenhouse gas emissions reductions programs. Results of this study are due by October 15, 2013 and will help inform development of a climate strategy to meet Washington’s greenhouse gas reduction goals. 3 http://www.commerce.wa.gov/Programs/Energy/Office/Utilities/Pages/EmissionPerfStandards.aspx Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 102 of 1125 Chapter 5 – Transmission & Distribution Avista Corp 2013 Electric IRP 5-1 5. Transmission & Distribution Introduction Avista delivers electricity from generators to customer meters through a network of conductors, or links and stations, or nodes. The network system is operated at higher voltages where the energy must travel longer distances to reduce current losses across the system. A common rule to determine efficient energy delivery is one kV per mile. For example, a 115 kV power system commonly transfers energy over a distance of 115 miles, while 13 kV power systems are generally limited to delivering energy within 13 miles. Avista categorizes its energy delivery systems between transmission and distribution voltages. Avista’s transmission system operates at 230 kV and 115 kV nominal voltages; the distribution system operates between 4.16 kV and 34.5 kV, but typically at 13.2 kV in its urban service centers. In addition to voltages, the transmission system operates distinctly from the distribution system. For example, the transmission system is a network linking multiple sources with multiple loads, while the distribution system configuration uses radial feeders to link a single source to multiple loads. Coordinating transmission system operations and planning activities with regional transmission providers maintains a reliable and economic transmission service for our customers. Transmission providers and interested stakeholders coordinate the region’s approach to planning, constructing, and operating the transmission system under Federal Energy Regulatory Commission (FERC) rules and state and local agency guidance. This chapter complies with Avista’s FERC Standards of Conduct compliance program governing communications between Avista merchant and transmission functions. This chapter describes Avista’s completed and planned distribution upgrade feeder program, the transmission system, completed and planned upgrades, and estimated costs and issues of new generation resource integration. Chapter Highlights Avista continues to participate in regional transmission planning forums. The Spokane Valley Reinforcement Project includes both station update and conductor upgrades. A large upgrade project is under construction at the Moscow substation to maintain adequate load service and a Noxon substation rebuild project is in the design phase. Five distribution feeder rebuilds are complete since the last IRP, six additional feeders rebuilds are planned for 2014. Significant generation interconnection study work around Thornton and Lind substations continues. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 103 of 1125 Chapter 5 – Transmission & Distribution Avista Corp 2013 Electric IRP 5-2 FERC Planning Requirements and Processes FERC provides guidance to both regional and local area transmission planning. This section describes several of its requirements and processes important to Avista transmission planning. FERC Tariff Attachment K Avista’s Open Access Transmission Tariff (OATT) includes Attachment K, satisfying nine transmission planning principles outlined in FERC Order 890. Avista’s Attachment K process ensures open and transparent coordination of local, regional, and sub-regional transmission planning. Avista develops a biannual Local Planning Report (in coordination with Avista's five- and ten-year Transmission Plans). Avista encourages participation by interconnected utilities, transmission customers, and other stakeholders in the Local Planning Process. Avista satisfies its sub-regional and regional FERC transmission planning requirements through its membership in ColumbiaGrid. Avista also participates in the Northern Tier Transmission Group and several Western Electricity Coordinating Council (WECC) processes and groups. Participation in these efforts supports regional coordination of Avista's transmission projects. Western Electricity Coordinating Council WECC coordinates and promotes electric system reliability in the Western Interconnection. It supports training in power system operations and scheduling functions, and coordinated transmission planning activities throughout the Western Interconnection. Avista participates in WECC’s Planning Coordination, Operations, Transmission Expansion Planning Policy and Market Interface Committees, as well as sub groups and other processes such as the Transmission Coordination Work Group. Northwest Power Pool Avista is a member of the Northwest Power Pool (NWPP). Formed in 1942 when the federal government directed utilities to coordinate operations in support of wartime production, NWPP committees include the Operating Committee, the Reserve Sharing Group Committee, the Pacific Northwest Coordination Agreement (PNCA) Coordinating Group, and the Transmission Planning Committee (TPC). The TPC exists as a forum addressing northwest electric planning issues and concerns, including a structured interface with external stakeholders. The NWPP serves as an electricity reliability forum, helping to coordinate present and future industry restructuring, promoting member cooperation to achieve reliable system operation, coordinating power system planning, and assisting the transmission planning process. NWPP membership is voluntary and includes the major generating utilities serving the Northwestern U.S., British Columbia and Alberta. Smaller, principally non- generating utilities participate in an indirect manner through their member systems, such as the BPA. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 104 of 1125 Chapter 5 – Transmission & Distribution Avista Corp 2013 Electric IRP 5-3 ColumbiaGrid ColumbiaGrid formed on March 31, 2006, and its membership includes Avista, BPA, Chelan County PUD, Grant County PUD, Puget Sound Energy, Seattle City Light, Snohomish County PUD, and Tacoma Power. ColumbiaGrid was formed to enhance and improve the operational efficiency, reliability, and planned expansion of the Pacific Northwest transmission grid. Consistent with FERC requirements issued in Orders 890 and 1000, ColumbiaGrid develops sub-regional transmission plans, assesses transmission alternatives (including non-wires alternatives), and provides a decision-making forum and cost-allocation methodology for new transmission projects. Northern Tier Transmission Group The Northern Tier Transmission Group (NTTG) formed on August 10, 2007. NTTG members include Deseret Power Electric Cooperative, Idaho Power, Northwestern Energy, PacifiCorp, Portland General Electric, and Utah Associated Municipal Power Systems. These members rely upon the NTTG committee structure to meet FERC’s coordinated transmission planning requirements. Avista’s transmission network has a number of strong interconnections with three of the six NTTG member systems. Due to the geographical and electrical positions of Avista’s transmission network related to NTTG members, Avista participates in the NTTG planning process to foster collaborative relationships with our interconnected utilities. Transmission Coordination Work Group The Transmission Coordination Work Group is a joint effort between Avista, BPA, Idaho Power, Pacific Gas and Electric, PacifiCorp, Portland General Electric, Sea Breeze Pacific-RTS, and TransCanada to coordinate transmission project developments expected to interconnect at or near a proposed Northeast Oregon station near Boardman, Oregon. These projects follow WECC Regional Planning and Project Rating Guidelines. Detailed information on projects presently under consideration is available at www.nwpp.org/tcwg. Many of the projects from this effort are on hold or have been terminated. Avista Transmission Reliability and Operations Avista plans and operates its transmission system pursuant to applicable criteria established by the North American Electric Reliability Corporation (NERC), WECC, and NWPP. Through involvement in WECC and NWPP standing committees and sub-committees, Avista participates in developing new and revised criteria while coordinating transmission system planning and operation with neighboring systems. Mandatory reliability standards promulgated through FERC and NERC subject Avista to periodic performance audits through these regional organizations. Avista’s transmission system is constructed for the primary purposes of providing reliable and efficient transmission service from the company’s portfolio of power resources to its retail native load customers. Portions of Avista’s transmission system are fully subscribed for retail load service. Transmission capacity that is not reserved and scheduled for native load service is made available to third parties pursuant to FERC regulations and the terms and conditions of Avista’s OATT. Such surplus transmission capacity that is not sold on a long-term (greater than one year) basis is Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 105 of 1125 Chapter 5 – Transmission & Distribution Avista Corp 2013 Electric IRP 5-4 marketed on a short-term basis to third parties and used by Avista for short-term resource optimization. Regional Transmission System BPA owns and operates over 15,000 miles of transmission-level facilities, and it owns the largest portion of the region’s high voltage (230 kV or higher) transmission grid. Avista uses BPA transmission to transfer output from its remote generation sources to Avista’s transmission system, including its share in Colstrip Units 3 and 4, Coyote Springs 2, Lancaster, and its WNP-3 settlement contract. Avista also contracts with BPA for Network Integration Transmission Service to transfer power to several delivery points on the BPA system to serve portions of Avista’s retail load, and to sell power surplus to its needs to other parties in the region. Avista participates in BPA transmission rate case processes, and in BPA’s Business Practices Technical Forum, to ensure charges remain reasonable and support system reliability and access. Avista also works with BPA and other regional utilities to coordinate major transmission facility outages. Future electricity grid expansion will likely require new transmission assets by federal and other entities. BPA is developing several transmission projects in the Interstate-5 corridor, as well as projects in southern Washington necessary for integrating wind generation resources located in the Columbia Gorge. Each project has the potential to increase BPA transmission rates and thereby affect Avista’s costs. Avista’s Transmission System Avista owns and operates a system of over 2,200 miles of electric transmission facilities. This includes approximately 685 miles of 230 kV line and 1,527 miles of 115 kV line. Figure 5.1 illustrates Avista’s transmission system. Avista owns an 11 percent interest in 495 miles of double circuit 500 kV lines between Colstrip and Townsend, Montana. The transmission system includes switching stations and high-voltage substations with transformers, monitoring and metering devices, and other system operation-related equipment. The system transfers power from Avista’s generation resources to its retail load centers. Avista also has network interconnections with the following utilities: BPA Chelan County PUD Grant County PUD Idaho Power Company NorthWestern Energy PacifiCorp Pend Oreille County PUD Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 106 of 1125 Chapter 5 – Transmission & Distribution Avista Corp 2013 Electric IRP 5-5 Figure 5.1: Avista Transmission Map Transmission System Information for the 2013 IRP Since the 2011 IRP, Avista completed transmission projects to support new generation, increase reliability, and provide system voltage support including; Thornton 230 kV switching station Garden Springs to Hallet & White section of South Fairchild 115 kV Tap Irvin – Opportunity 115 kV line Burke Substation to Montana border section of Burke – Thompson Falls A&B 115 kV lines Southern half of Bronx – Cabinet Gorge 115 kV line Capacitor bank installed at the Lind 115 kV switching station. Lancaster Integration Avista has evaluated and proposed an interconnection with BPA at its Lancaster 230 kV Switching Station. Avista and BPA have determined the preferred alternative is to loop the Avista Boulder-Rathdrum 230 kV line into the BPA Lancaster 230 kV station. This interconnection allows Avista to eliminate or offset BPA wheeling charges for moving the output from Lancaster to Avista’s system. Besides reducing transmission payments to BPA by Avista, the interconnection benefits both Avista and the BPA by increasing Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 107 of 1125 Chapter 5 – Transmission & Distribution Avista Corp 2013 Electric IRP 5-6 system reliability, decreasing losses, and delaying the need for additional transformation at BPA’s Bell Substation. Studies indicate this project may allow more transfer capability across the combined transmission interconnections of Avista and BPA. This project, in conjunction with other Avista upgrades, also supports increasing the Montana-to- Northwest path rating by as much as 800 MW. Avista has worked collaboratively with BPA and the Lancaster 230 kV interconnection project is planned for completion by the end of 2013. South Spokane 230 kV Reinforcement Transmission studies continue to support the need for an additional 230 kV line to the south and west of Spokane. Avista currently has no 230 kV source in these areas and instead relies on its 115 kV system for load service and bulk power flows through the area. The project scope is under development, and preliminary studies indicate the need for the following (or similar) projects: A new 230/115 kV station near Garden Springs. Property acquisition for the Garden Springs station and preliminary geo-technical station design work has commenced; Tap of the Benewah-Boulder 230 kV line southwest of the Liberty Lake area and construction of a new 230 kV switching station (for later development of a 230/115 kV substation); alternatively, reconstruction of the 115 kV circuits between Beacon and Ninth & Central, and the installation of a 230/115 kV station at that site could be pursued; Connecting the Liberty Lake 230 kV station with the Garden Springs 230 kV station; alternatively, connecting the Ninth & Central station to the Garden Springs station; Construction of a new 230 kV line from Garden Springs to Westside; and Origination and termination of the 115 kV lines from the new Spokane area 230/115 kV station(s). The South Spokane 230 kV Reinforcement project was scoped at the end of 2012 with a planned in-service date by the end of 2018. The project is planned to enter service in a staged fashion beginning in 2014. Avista Station Upgrades As reported in the 2011 IRP, Avista planned to upgrade its Moscow, Noxon, and Westside 230 kV substations. These upgrades improve reliability, add capacity, and update aging components. The Moscow station upgrades, scheduled for completion in 2014, will result in a new facility with a single 250 MVA 230/115 kV station doubling the current station capacity over the next five to 10 years. Further upgrades or rebuilds are planned at the following substations: Irvin 115 kV Switching Station [Spokane Valley Reinforcement] (2016) Millwood 115 kV Distribution Substation [Spokane Valley Reinforcement] (2013) North Lewiston 115 kV Distribution Substation (2014) Moscow 230/115 kV Substation (2011-2014) Stratford 115 kV Switching Station (2014) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 108 of 1125 Chapter 5 – Transmission & Distribution Avista Corp 2013 Electric IRP 5-7 Blue Creek 115 kV Distribution Substation (2014) Harrington 115 kV Distribution Substation (2014) Noxon 230 kV Switching Station (2013-2016) 9th & Central 115 kV Distribution Substation (2015) Greenacres 115 kV Distribution Substation (2014) Beacon 230/115 kV Station Partial Rebuild (2017+) Avista Transmission Upgrades Avista plans to complete several 115 kV reconductor projects throughout its transmission system over the next decade. These projects focus on replacing decades-old small conductor with conductor capable of greater load-carrying capability and provide more efficient (i.e., fewer electrical losses) service. The following list gives an example of planned transmission projects: Spokane Valley Reinforcement Project (2011-2016) Bronx – Cabinet Gorge 115 kV (2011-2015) Burke – Pine Creek 115 kV (2012-2014) Benton – Othello 115 kV (2014-2016) Devils Gap – Lind 115 kV (2014-2016) Coeur d’Alene – Pine Creek 115 kV (2014-2017) Generation Interconnection Requests Avista’s Power Supply Department requested generator interconnection studies in several areas of Avista’s transmission system for the 2013 IRP. Developers have also requested studies through Avista’s Large Generation Interconnection Request (LGIR) process. Table 5.1 states the projects and cost information for each of the IRP-related studies. The study results for each project, including cost and integration options, may be found in Appendix D. These studies are a high level view of the generation interconnect request similar to what would be performed as a feasibility study for a third party under the LGIR process. Table 5.1: IRP Requested Transmission Upgrade Studies Project Size (MW) Cost1 Nine Mile 60 No cost Long Lake 68 $9.9 million Monroe Street 80 No cost2 Upper Falls 40 No cost3 Post Falls 16 No cost Cabinet Gorge 60 No cost Thornton 200 $4 million Benewah to Boulder 300 $7-$15 million Rathdrum 300 $7-$30+ million 1 Cost estimates are in 2013 dollars and use engineering judgment with a 50 percent margin for error. 2 An upgrade to the College & Walnut substation may require upgrades. 3 Ibid. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 109 of 1125 Chapter 5 – Transmission & Distribution Avista Corp 2013 Electric IRP 5-8 Large Generation Interconnection Requests Third-party generation companies or independent power producers may make requests for transmission studies to understand the cost and timelines for integrating potential new generation projects. These types of projects follow a strict FERC process and include three study steps to estimate the feasibility, system impact, and facility requirement costs for project integration. Each of these studies provides the requester with a different level of project costs, and the studies are typically complete over at least a one-year period. After this process is completed a contract can be offered to integrate the project and negotiations can begin to enter into a transmission agreement if necessary. Each of the proposed projects are made public to some degree (customer names remain anonymous). Below Table 5.2 lists the current projects remaining in Avista’s transmission queue. Table 5.2: Third-Party Large Generation Interconnection Requests Project # Size (MW) Type Interconnection #33 400 Wind Lind 115 kV Substation #35 200 CT Thornton 230 kV Switching Station #36 105 Wind Thornton 230 kV Switching Station Distribution System Efficiencies In 2008, an Avista system efficiencies team of operational, engineering, and planning staff developed a plan to evaluate potential energy savings from Transmission and Distribution system upgrades. The first phase summarized potential energy savings from distribution feeder upgrades. The second phase, beginning in the summer of 2009, combined transmission system topologies with “right sizing” distribution feeders to reduce system losses, improve system reliability, and meet future load growth. The system efficiencies team evaluated several efficiency programs to improve both urban and rural distribution feeders. The programs consisted of the following system enhancements:  Conductor losses;  Distribution transformers;  Secondary districts; and  Volt-ampere reactive compensation. The energy losses, capital investments, and reductions in operations and maintenance (O&M) costs resulting from the individual efficiency programs under consideration were combined on a per feeder basis. This approach provided a means to rank and compare the energy savings and net resource costs for each feeder. Feeder Upgrade Program Avista’s distribution system consists of approximately 330 feeders covering 30,000 square miles, ranging in length from three to 73 miles. For rural distribution, feeder Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 110 of 1125 Chapter 5 – Transmission & Distribution Avista Corp 2013 Electric IRP 5-9 lengths vary widely to meet the electrical loads resulting from the startup and shutdown business swings of the timber, mining and agriculture industries. The Feeder Upgrade Program’s charter criterion has grown to include a more holistic approach to the way Avista addresses each project. This vital program integrates work performed under various operational initiatives in Avista including the Wood Pole Management Program, the Transformer Change-out Program, the Vegetation Management Program and the Feeder Automation Program. The work of the Feeder Upgrade Program includes the replacement of undersized and deteriorating conductors, replacement of failed and end-of-life infrastructure materials including wood poles, cross arms, fuses and insulators. Inaccessible pole alignment, right-away, undergrounding and clear zone compliance issues are addressed for each feeder section as well as regular maintenance work such as leaning poles, guy anchors, unauthorized attachments and joint-use management. This systematic overview enables Avista to cost-effectively deliver a modernized and robust electric distribution system that is more efficient, easier to maintain and more reliable for our customers. Figure 5.2 illustrates the reliability advantages and reasons for the program. Prior to the 2009 feeder rebuild pilot program, outages were increasing at up to 13 outages per year. After the project, outages declined significantly. In the past two years, only one outage was recorded. The program is in its second year of regular funding and its intended purpose of capturing energy savings through reduced losses, increased reliability and decreased O&M costs is being realized. The feeders addressed through this program to date are shown in Table 5.3. The total energy savings, from both re- conductor and transformer efficiencies for all of these feeders, is approximately 4,869 MWh annually. Table 5.3: Completed Feeder Rebuilds Feeder Area Year Complete Annual Energy Savings (MWh) 9CE12F4 Spokane, WA (9th & Central) 2009 601 BEA12F1 Spokane, WA (Beacon) 2012 972 F&C12F2 Spokane, WA (Francis & Cedar) 2012 570 BEA12F5 Spokane, WA (Beacon) 2013 885 WIL12F2 Wilbur, WA 2013 1,403 CDA121 Coeur d’Alene, ID 2013 438 Total 4,869 The additional benefits ascertained through the work performed through the Feeder Upgrade Program are just now coming to fruition and will require a multi-year study to verify all of the planned benefits. Table 5.4 includes the working plan for feeder rebuilds over the next several years. The additional energy savings is anticipated to reach 1,626 MWh per year. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 111 of 1125 Chapter 5 – Transmission & Distribution Avista Corp 2013 Electric IRP 5-10 Figure 5.2: Spokane’s 9th and Central Feeder (9CE12F4) Outage History Table 5.4: Planned Feeder Rebuilds Feeder Area Planned Year Annual Energy Savings (MWh) NE12F3 Spokane, WA 2014 115 RAT231 Rathdrum, ID 2014 91 OTH502 Othello, WA 2014 21 M23621 Moscow, ID 2014 151 DVP12F2 Davenport, WA 2014 35 HAR4F1 Harrington, WA 2014 69 BEA12F3 Spokane, WA 2015 167 FWT12F3 Spokane, WA 2015 121 TEN1255 Lewiston, ID/Clarkston, WA 2015 249 ROS12F1 Spokane, WA 2016 267 SPI12F1 Northport, WA 2016 162 TUR112 Pullman, WA 2016 101 TUR113 Pullman, WA 2017-2018 76 Total 1,626 1 6 5 6 5 13 13 8 11 7 0 1 0 2 4 6 8 10 12 14 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 ou t a g e s Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 112 of 1125 Chapter 6- Generation Resource Options Avista Corp 2013 Electric IRP 6. Generation Resource Options Introduction Several generating resource options are available to meet future load growth. Avista can upgrade existing resources, build new facilities, or contract with other energy companies for future delivery. This section describes resources Avista considered in the 2013 IRP to meet future needs. The new resources described in this chapter are mostly generic. Actual resources may differ in size, cost, and operating characteristics due to siting or engineering requirements. Assumptions For the PRS analyses, Avista only considers commercially available resources with well-known costs, availability and generation profiles. These resources include gas-fired combined cycle combustion turbines (CCCT), simple cycle combustion turbines (SCCT), large-scale wind, storage, hydro upgrades, and certain solar technologies proven on a large-scale commercial basis. Several other resource options described later in the chapter were not included in the PRS analysis, but their costs were estimated for comparative analysis. Potential contractual arrangements with other energy companies are not an option for this plan, but are an option when Avista seeks new resources through a RFP. Levelized costs referred to throughout this section are at the generation busbar. The nominal discount rate used in the analyses is 6.67 percent based on Avista’s weighted average cost of capital approved by the states of Idaho and Washington. Nominal levelized costs result from discounting nominal cash flows at the rate of general inflation. All costs in this section are in 2014 nominal dollars unless otherwise noted. Section Highlights Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 113 of 1125 Chapter 6- Generation Resource Options Avista Corp 2013 Electric IRP Certain renewable resources receive federal and state tax incentives today and into the near future. Solar tax benefits fall by two-thirds after 2016 and all other renewable benefits end in 20131. These incentives are included in IRP modeling. Levelized resource costs presented in this chapter use the maximum available energy for each year, not expected generation. For example, wind generation assumes 34 percent availability, CCCT generation assumes 90 percent availability, and SCCT generation assumes 91 percent availability. Wind resources typically operate at or near assumed availability because the fuel is free, but CCCT or SCCT plants operate at levels well below their availability factors because their output will be displaced when lower-cost wholesale market power is available. Costs are levelized for the first 20 years of the project life using longer useful-life depreciation schedules. The following are definitions for the levelized cost components used in this chapter: Capital Recovery and Taxes: Depreciation, return of and on capital, federal and state income taxes, property taxes, insurance, and miscellaneous charges such as uncollectible accounts and state taxes for each of these items pertaining to a generation asset investment. Allowance for Funds Used During Construction (AFUDC): The cost of money associated with construction payments made on a generation asset during construction. Federal Tax Incentives: The estimated federal tax incentive (per MWh) in the form of a PTC, a cash grant, or an ITC, attributable to qualified generation options. Fuel Costs: The average cost of fuel such as natural gas, coal, or wood, per MWh of generation. Additional fuel prices details are included in the Market Analysis section. Fuel Transport: The cost to transport fuel to the plant, including pipeline capacity charges. Fixed Operations and Maintenance (O&M): Costs related to operating the plant such as labor, parts, and other maintenance services that are not based on generation levels. Variable O&M: Costs per MWh related to incremental generation. Transmission: Includes depreciation, return on capital, income taxes, property taxes, insurance, and miscellaneous charges such as uncollectible accounts and state taxes for each of these items pertaining to transmission asset investments needed to interconnect the generator and/or third party transmission charges. Other Overheads: Includes miscellaneous charges for non-capital expenses such as uncollectibles, excise taxes and commission fees. The tables at the end of this section show incremental capacity, heat rates, generation capital costs, fixed O&M, variable costs, and peak credits for each resource option.2 1 After completion of the modeling for this IRP, the PTC for wind was expanded to allow any project under construction by the end of 2013 might qualify upon its completion. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 114 of 1125 Chapter 6- Generation Resource Options Avista Corp 2013 Electric IRP Figure 6.2 compares the levelized costs of different resource types. Avista relies on a variety of sources including the NPCC, press releases, regulatory filings, internal analysis, and Avista’s experiences with certain technologies for its resource assumptions. Gas-Fired Combined Cycle Combustion Turbine Gas-fired CCCT plants provide a reliable source of both capacity and energy for a relatively modest capital investment. The main disadvantage is generation cost volatility due to reliance on natural gas, unless the fuel price is hedged. CCCTs in this IRP are “one-on-one” (1x1) configurations, using air-cooling technology. The 1x1 configuration consists of a single gas turbine, a single heat recovery steam generator (HRSG), and a duct burner to gain more generation from the HRSG. The plants have nameplate ratings between 250 MW and 330 MW each depending on configuration and location. A 2x1 CCCT plant configuration is possible with two turbines and one HRSG, generating up to 600 MW. Avista would need to share the plant with one or more utilities to take advantage of the modest economies of scale and efficiency of a 2x1 plant configuration due to its large size relative to our needs. Water cooling technology could be an option for CCCT development, depending on the plant location; however, this IRP assumes air-cooled technology because of the difficulties in obtaining new water rights. Where water-cooling technology is available, the plant may require a lower capital investment and have a better heat rate relative to air-cooled technology. The most likely CCCT configuration for Avista is a 270-300 MW air-cooled plant located in the Idaho portion of Avista’s service territory, mainly due to Idaho’s lack of an excise tax on natural gas consumed for power generation, a lower sales tax rate relative to Washington, and no fees on carbon dioxide emissions.3 Potential combined cycle plant sites would likely be on the Avista transmission system to avoid third-party wheeling rates. Another advantage of siting a CCCT resource in Avista’s service territory in Idaho is access to low-cost natural gas on the GTN pipeline. Cost and operational estimates for CCCTs modeled in the IRP use data from Avista’s internal engineering analyses. The heat rate modeled for an air-cooled CCCT resource is 6,832 Btu/kWh in 2014. The projected CCCT heat rate falls by 0.5 percent annually to reflect anticipated technological improvements. The plants include duct firing for 7 percent of rated capacity at a heat rate of 8,910 Btu/kWh. If Avista were able to site a water-cooled plant, the heat rate would likely be 2 percent lower and net plant output might increase by five MW. The IRP includes a 6 percent forced outage rate for CCCTs, and 14 days of annual plant maintenance. The plants are capable of backing down to 50 percent of nameplate 2 Peak credit is the amount of capacity a resource contributes at the time of system peak load. 3 Washington state applies an excise tax on all fuel consumed for wholesale power generation, the same as it does for retail natural gas service, at approximately 3.875 percent. Washington also has higher sales taxes and has carbon dioxide mitigation fees. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 115 of 1125 Chapter 6- Generation Resource Options Avista Corp 2013 Electric IRP capacity, and ramping from zero to full load in four hours. Carbon dioxide emissions are 117 pounds per dekatherm of fuel burned. The maximum capability of each plant is highly dependent on ambient temperature and plant elevation. The anticipated capital cost for an air-cooled CCCT located in Idaho on Avista’s transmission system, with AFUDC, is $1,279 per kW in 2014; $345 million for a 270 MW plant. Table 6.1 shows the overnight costs for an air-cooled CCCT resource in nominal dollars; Table 6.2 shows levelized costs. The costs include firm natural gas transportation. At this time, excess pipeline capacity exists on the major pipelines near all potential siting locations to supply firm natural gas service. Natural Gas-Fired Peakers Natural gas-fired CTs and reciprocating engines, or peaking resources, provide low-cost capacity and are capable of providing energy as needed. Technological advances allow the plants to start and ramp quickly, providing regulation services and reserves for load following and to integrate variable resources such as wind and solar. The IRP models four peaking resource options: Frame (GE 7EA), hybrid aero-derivative or intercooled (GE LMS 100), reciprocating engines (Wartsila 18V34), and aero-derivative (Pratt FT8). The different peaking technologies range in their abilities to follow load, costs, generating capabilities, and energy-conversion efficiencies. Table 6.1 shows cost and operational estimates based on Avista’s internal engineering estimates. All peaking plants assume 0.5 percent annual real dollar cost decrease and forced outage and maintenance rates. The levelized cost for each of the technologies is in Table 6.2. Firm fuel transportation has become an electric reliability issue with FERC, and is being discussed at several regional and extra-regional forums. For this IRP, Avista continues to assume it will not procure firm natural gas transportation for its peaking resources. Firm transportation could be necessary where pipeline capacity becomes scarce during utility peak hours; however, pipelines near potential sites being modeled by Avista in the IRP are not currently subscribed or expected to be subscribed in the near future to levels high enough to warrant the additional costs of having firm supply. Avista continues to monitor natural gas transportation options for its portfolio. Where non-firm natural gas transportation options become inadequate for system reliability, three options exist: contracting for firm natural gas transportation rights, or on-site oil or natural gas storage. The lowest-cost peaking resource, as measured by production cost in Table 6.2, is hybrid technology. However, this comparison is misleading, as a peaking resource does not operate at its theoretical maximum operating levels. Peaking resources generally operate only a small number of hours in the year. Therefore, lower capacity-cost resources may be more cost-effective for the portfolio in relation to hybrid technology when considering the number of expected operating hours in the broader IRP modeling process. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 116 of 1125 Chapter 6- Generation Resource Options Avista Corp 2013 Electric IRP Table 6.1: Natural Gas Fired Plant Cost and Operational Characteristics Item Air Cooled CCCT Frame Hybrid Recip. Engines Aero- Derivative Capital Cost with AFUDC ($/kW) $1,279 $910 $1,199 $1,141 $1,185 Fixed O&M ($/kW- yr) $22.70 $11.48 $16.07 $18.78 $13.56 Heat Rate (Btu/kWh) 6,832 11,286 8,712 8,712 9,802 Variable O&M ($/MWh) $1.77 $3.13 $5.22 $6.26 $4.17 Units Assumed at Site 1 2 1 6 2 Unit Size (MW) 270 83 92 19 50 Total Project Size (MW) 270 166 92 114 100 Total Cost for Segment Size (millions) $345 $151 $110 $128 $119 Table 6.2: Natural Gas-Fired Plant Levelized Costs per MWh Item Air Cooled CCCT Frame Hybrid Recip. Engines Aero- Derivative Capital Recovery & Taxes 18.69 13.79 18.17 16.83 17.96 AFUDC 2.02 0.58 0.76 0.70 0.75 Fuel Costs4 41.43 59.68 46.07 46.07 51.83 Fixed O&M 3.72 1.83 2.57 2.92 2.17 Variable O&M 2.25 3.97 6.62 7.94 5.29 Transmission 1.07 0.40 0.72 0.58 0.67 Other Overheads 1.44 1.96 1.67 1.71 1.78 Total Cost 70.62 82.21 76.57 76.75 80.45 Wind Generation Concerns over the environmental impact of carbon-based generation technologies have increased demand for wind generation. Governments are promoting wind generation with tax credits, renewable portfolio standards, carbon emission restrictions, and stricter controls on existing non-renewable resources. The 2013 “Fiscal Cliff” deal in the U.S. Congress extended the PTC for wind through December 31, 2013, with provisions allowing projects to qualify after 2013 so long as construction begins in 2013. This IRP does not assume the PTC extends beyond this term, but does assume the preferential 5-year tax depreciation remains. The IRP considers two wind generation resources located both on- and off-system. Both resources assume similar capital costs and wind patterns. On-system projects pay only transmission interconnection costs, whereas off-system projects must pay both interconnection and third-party wheeling costs. 4 The Air-Cooled CCCT technologies fuel cost includes a charge for fuel transport to reserve capacity on a major pipeline. The levelized cost of the charge is estimated to be $5.04 per MWh. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 117 of 1125 Chapter 6- Generation Resource Options Avista Corp 2013 Electric IRP Wind resources benefit from having no emissions profile or fuel costs, but they are not dispatchable, and have high capital and labor costs on a per-MWh basis when compared to most other resource options. Wind capital costs in 2014, including AFUDC and transmission interconnection, are $2,340 per kW, with annual fixed O&M costs of $46 per kW-yr. Fixed O&M includes indirect charges to account for the inherent variation in wind generation, oftentimes referred to as “wind integration.” The cost of wind integration depends on the penetration of wind in Avista’s portfolio, and the market price of power; for this IRP, wind integration is $4 per kW-year in 2014. These estimates come from Avista’s experience in the wind market at the time of the IRP, and results from Avista’s Wind Integration Study. The wind capacity factors in the Northwest vary depending on project location, with capacity factors roughly ranging between 25 and 40 percent. This plan assumes Northwest wind has a 33 percent average capacity factor; on-system wind projects have a 34 percent capacity factor. A statistical method, based on regional wind studies, derives a range of annual capacity factors depending on the wind regime in each year (see stochastic modeling assumptions for more details). The expected capacity factor can have a dramatic impact on the levelized cost of a wind project. For example, a 30 percent capacity factor site could be $30 per MWh higher than a 40 percent capacity factor site holding all other assumptions equal. Levelized costs, using these expected capacity factors, capital, and operating costs, are in Table 6.4. Actual wind resource costs vary depending on a project’s capacity factor, interconnection point, and the amount of tax related subsidies available. Further, this plan assumes wind resources selected in the PRS include the 20 percent REC apprenticeship adder for Washington state renewable portfolio standard eligible renewable resources. This adder applies only for Washington state compliance with the EIA, requiring 15 percent of the construction labor to be from apprentices through a state-certified apprenticeship program to qualify. Table 6.3: Northwest Wind Project Levelized Costs per MWh Item On-System Off-System Capital Recovery & Taxes 80.68 83.12 AFUDC 4.73 4.87 Fuel Costs 0.00 0.00 Fixed O&M 19.81 20.41 Variable O&M 2.65 2.65 Transmission 1.77 9.99 Other Overheads 0.72 0.98 Total Cost 110.36 122.02 Solar Photovoltaic Solar photovoltaic generation technology costs have fallen substantially in the last several years partly due to low-cost imports, and from renewable portfolio standards and government tax incentives, both inside and outside of the United States. Even with these large cost reductions, Avista’s analysis shows that solar still is uneconomic for Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 118 of 1125 Chapter 6- Generation Resource Options Avista Corp 2013 Electric IRP winter-peaking utilities in the Northwest when compared to other generation resource options, both renewable and non-renewable. This is due to solar’s low capacity factor, its lack of on-peak output during cold winter peak periods, and relatively high capital cost. Solar does provide predictable daytime generation complementing the loads of summer-peaking utilities, though fixed panels typically do not produce full output at system peak. In the Northwest solar provides no wintertime on-peak capability. If a substantial amount of solar is added to a summer peaking utility (e.g., in the desert Southwest), the peak hour recorded prior to the solar installation will be reduced, but the peak will simply be shifted toward sundown when the solar facility witnesses a substantial output reduction. Figure 6.1 presents an example based on California Independent System Operator Daily Renewables output data for August 14, 2012. To better illustrate solar generation’s impact, the figure shows a ten-fold increase to actual solar output. Assuming 10,000 MW of alternating current (AC) nameplate solar lowers the peak by 5,662 MW from the actual peak of 45,227, and shifts the overall system peak by two hours.5 The example shows a net 56 percent peak credit for solar because solar’s output falls off drastically in the later hours of the day. Figure 6.1: Solar’s Effect on California Load Utility-scale photovoltaic generation can be optimally located for the best solar radiation, albeit at the expense of lower overall generation levels. Solar thermal technologies can 5 Solar output generally is quoted on a direct current (DC) basis; however, for an alternating current system output is reduced by approximately 15-23 percent to account for DC-AC conversion and other on-site losses. The actual capacity of the solar generation profile is unknown, it is likely between 1,000 and 1,500 MW. 0 10,000 20,000 30,000 40,000 50,000 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 me g a w a t t s hour Net Load Load Solar Output Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 119 of 1125 Chapter 6- Generation Resource Options Avista Corp 2013 Electric IRP produce higher capacity factors than photovoltaic solar projects by as much as 30 percent, and can store energy for several hours for later use in reducing peak loads. Utility-scale solar capital costs in the IRP, including AFUDC, are $3,403 per kW for photovoltaic and $6,587 for solar-thermal or concentrating solar projects. A well-placed utility-scale photovoltaic system located in the Pacific Northwest would achieve a capacity factor of less than 18 percent; the IRP uses a 15 percent capacity factor. Only utility-scale photovoltaic was included as an option for the PRS. Avista does not believe solar-thermal is an economically viable option in Avista’s service territory given our modest solar resource and the relatively higher capital costs when compared to photovoltaic projects. Table 6.4 shows the levelized costs of solar resources, including federal incentives. Even with declining prices, solar will continue to struggle as a cost-competitive resource in the Northwest because of its high installation costs and because the technology cannot meet winter peak system requirements. One advantage given to solar in the state of Washington is if the total plant is less than five megawatts it counts as two RECs towards Washington’s EIA. Washington state also offers substantial financial incentives for consumer-owned solar. This IRP does not explicitly consider consumer-owned solar, as the overall incentives are not available to utilities and would otherwise be capped at a level that would not affect this plan. Consumer-owned solar continues to be accounted for through reductions in Avista’s retail load forecast. Table 6.4: Solar Nominal Levelized Cost ($/MWh) Item Photovoltaic Solar Capital Recovery &Taxes 293.32 AFUDC 9.56 Fuel Costs 0.00 Fixed O&M 48.32 Variable O&M 0.00 Transmission 21.61 Other Overheads 2.08 Total Cost (without federal tax incentive) 374.89 Total Cost (with federal tax incentive) 283.58 Coal Generation The coal generation industry is at a crossroads. In many states, like Washington, new coal-fired plants are unlikely due to emission performance standards. Coal remains a viable option in other parts of the country, but the risks associated with future carbon legislation make investments in this technology challenging. The EPA has proposed a greenhouse gas emission performance standard average of 1,000 lbs per MWh (averaged over a 30-year period). This proposed rule effectively eliminates new coal- fired generation without carbon sequestration, as non-sequestered coal options generate between 1,760 and 1,825 lbs of carbon dioxide per MWh. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 120 of 1125 Chapter 6- Generation Resource Options Avista Corp 2013 Electric IRP Avista does not plan to build or participate in any new coal-fired generation resources in the future due to the risk of future national carbon mitigation legislation and the effective prohibition contained in Washington state law. Technologies reducing or capturing greenhouse gas emissions in coal-fired resources might enable coal to become a viable technology in the future, but the technology is not commercially available. Though Avista will not pursue coal in this plan, three coal technologies are shown to illustrate their costs: super critical pulverized, integrated gasification combined cycle (IGCC), and IGCC with sequestration. IGCC plants gasify coal, thereby creating a more efficient use of the fuel, lowering carbon emissions and removing other toxic substances before combustion. Sequestration technologies, if they become commercially available, might potentially sequester 90 percent of CO2 emissions. Table 6.6 shows the costs, heat rates, and CO2 emissions of the three coal-fired technologies based on estimates from the NPCC’s Sixth Power plan and adjusted for Avista’s projected inflation rates. Table 6.7 shows the nominal levelized cost per MWh based on the capital costs and plant efficiencies shown in Table 6.6. Table 6.5: Coal Capital Costs Item Super- Critical IGCC IGCC w/ Sequestration Capital Costs ($/kW includes AFUDC) $3,683 $4,895 $7,342 Typical Size 600 600 550 Cost per Unit (Millions) $2,210 $2,937 $4,038 Heat Rate (Btu/kWh) 8,910 8,594 10,652 CO2 (lbs per MWh) 1,827 1,762 218 Table 6.6: Coal Project Levelized Cost per MWh Item Super- Critical IGCC IGCC w/ Sequestration Capital Recovery & Taxes 54.90 72.26 108.38 AFUDC 8.25 13.35 20.02 Fuel Costs 14.52 14.00 17.36 Fixed O&M 7.24 11.07 11.07 Variable O&M 3.64 8.34 11.25 Transmission 9.47 9.62 4.38 Other Overheads 1.04 1.28 1.31 Total Cost 99.06 129.92 173.77 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 121 of 1125 Chapter 6- Generation Resource Options Avista Corp 2013 Electric IRP Energy Storage Increasing amounts of solar and wind generation on the electric grid makes energy storage technologies attractive from an operational perspective. The technologies could be an ideal way to smooth out renewable generation variability and assist in load following and regulation needs. The technology also could meet peak demand, provide voltage support, relieve transmission congestion, take power during over supply events, and supply other non-energy needs for the system. Over time, storage may become an important part of the nation’s grid. Several storage technologies currently exist, including; pumped hydro, traditional and chemical batteries, flywheels, and compressed air. There are many challenges with storage technology. First, existing technologies consume a significant amount of electricity relative to their output through conversion losses. Second, the cost of storage is high, at near $4,000 per kW. This cost is nearly four times the initial cost of a natural gas-fired peaking plant that can provide many, but not all, of the same capabilities without the electricity consumption characteristics of storage. Storage costs are forecast to decline over time, and Avista continues to monitor the technologies as part of the IRP process. Third, the current scale of most storage projects is small, limiting their applicability to utility-scale deployment. Fourth, early adoption of technology can be risky, with many industry examples of battery fires and bankruptcy. The Northwest might be slower in adopting storage technology relative to other regions in the country. The Northwest hydro system already contains a significant amount of storage relative to the rest of the country. However, as more capacity consuming renewables are added to the grid, new storage technologies might play a significant role in meeting the need for additional operational flexibility where upfront capital costs and operational losses fall. One of the biggest obstacles to energy storage is quantifying and properly valuing its benefits. At a minimum, the value of storage is the spread or difference between the value of energy in on versus off-peak hours (load factoring), minus the losses. Since the technology can meet regulation, load following, and operating reserves, there is value beyond load factoring. Valuing these benefits requires new system modeling tools. Presently there are no adequate tools available in the marketplace. Avista is developing a tool it believes will enable detailed valuations of storage (and other) technologies within our existing mix of flexible hydro and thermal system. The results of these studies are not available for this plan, but should be available in the next IRP. Other Generation Resource Options A thorough IRP considers generation resources not readily available in large quantities or commercially or economically ready for utility-scale development. Today a number of emerging technologies, like energy storage, are attractive from an operational or environmental perspective, but are significantly higher-cost than other technologies providing substantially similar capabilities at lower cost. Avista analyzed several of these technologies for the IRP using estimates from the NPCC’s Sixth Power Plan, Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 122 of 1125 Chapter 6- Generation Resource Options Avista Corp 2013 Electric IRP publically available data, and Avista internal engineering analysis. The resources include biomass, geothermal, co-generation, nuclear, landfill gas, and anaerobic digesters. Table 6.7 shows the expected cost of these options. Their costs vary depending on site-specific conditions. All prices shown are utility-scale estimates with no federal tax incentives. However, given the lack of utility-scale development, cost could be substantially higher than shown. Failure to be included in the PRS is not the last opportunity for technologies to be in Avista’s portfolio. The resources will compete with those included in the PRS through Avista’s RFP processes. RFP processes identify competitive technologies that might displace resources otherwise included in the IRP strategy. Another possibility is acquisition through federal PURPA law mandates. PURPA provides non-utility developers the ability to sell qualifying power to Avista at guaranteed prices and terms.6 Since the 2011 IRP, Avista has acquired three renewable energy projects under PURPA. Woody Biomass Generation Woody biomass generation projects use waste wood from lumber or forest restoration process. The generation process is similar to a coal plant: a turbine converts boiler-created steam into electricity. A substantial amount of wood fuel is required for utility- scale generation. Avista’s 50 MW Kettle Falls Generation Station consumes over 350,000 tons of wood waste annually, or 48 semi-truck loads of wood chips per day. It typically takes 1.5 tons of wood to make one MWh of electricity; the ratio varies seasonally with the moisture content of the fuel. The viability of another Avista biomass projects depends significantly on the availability and cost of the fuel supply. Many announced biomass projects fail due to lack of a long-term fuel source. If an RFP identifies a potential project, Avista will consider it for a future acquisition. A 25 MW utility scale biomass plant would cost approximately $111 million in initial capital expenditure ($4,436 per kW), with fuel and O&M costs increasing the total cost to an amount approaching $160 per MWh. Geothermal Generation Northwest utilities have shown increased interest in geothermal energy over the past several years. It provides predictable electrical capacity and energy with minimal carbon dioxide emissions (zero to 200 pounds per MWh). The technology typically involves injecting water into deep wells; hot earth temperatures heat water and spin turbines for power generation. In recent years, a few projects were built in the Northwest. Due to the geologic conditions of Avista’s service territory, no geothermal projects are likely to be developed. For Avista to add this technology to its portfolio, it would require a third-party transmission wheel and be acquired through an RFP process. Geothermal energy struggles to compete due to high development costs stemming from having to drill several holes thousands of feet below the earth’s crust; each hole can cost over $3 million. Ongoing geothermal costs are low, but the capital required to locate and prove a viable site is significant. Costs shown in this section do not account 6 Rates, terms, and conditions are at www.avistautilities.com under Schedule 62. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 123 of 1125 Chapter 6- Generation Resource Options Avista Corp 2013 Electric IRP for dry-hole risk associated with sites that do not prove to be viable after drilling has taken place. Recent construction estimates for a 15 MW facility are $71.5 million ($4,767 per kW). The levelized cost of geothermal power is $104 per MWh. Landfill Gas Generation Landfill gas projects generally use reciprocating engines to burn methane gas collected at landfills. The Northwest has successfully developed many landfill gas resources. The costs of a landfill gas project will depend greatly on the site specifics of a landfill. The Spokane area had a project on one of its landfills, but it was retired after the fuel source depleted to an unsustainable level. The Spokane area no longer landfills its waste and instead uses its Municipal Waste Incinerator. Nearby in Kootenai County, Idaho, the Kootenai Electric Cooperative has developed a 3.2 MW Fighting Creek Project. It is currently under a PURPA contract with Avista. Using publically available costs and the NPCC estimates, landfill gas resources are economically promising, but are limited in their size, quantity, and location. Cost estimates in Table 6.7 assume a 3.2 MW unit with a capital cost of $8.5 million ($2,654 per kW including AFUDC). At an 88 percent capacity factor, a landfill gas project could cost up to $106 per MWh. Anaerobic Digesters (Manure/Wastewater Treatment) The number of anaerobic digesters is increasing in the Northwest. These plants typically capture methane from agricultural waste, such as manure or plant residuals, and burn the gas in reciprocating engines to power generators. These facilities tend to be significantly smaller than utility-scale generation projects (less than five MW). Most facilities are located in large dairies or feedlots. A survey of Avista’s service territory found no large-scale livestock operations capable of implementing this technology. Wastewater treatment facilities can also host anaerobic digesting technology. Digesters installed when a facility is initially constructed helps the economics of a project greatly, though costs range greatly depending on the system configuration. Retrofits to existing wastewater treatment facilities are possible, but tend to have higher costs. Many of these projects offset energy needs of the facility, so there may be little, if any, surplus generation capability. Avista currently has a 260 kW waste water system under a PURPA contract with a Spokane County facility. Typical digester projects are 200 kW to five MW. Current estimates are $4,775 per kW for utility development, or $24 million in capital for a five MW project. The actual cost of the technology depends on the fuel source, site specifics, and subsidies available for the project. For example, many digesters qualify for agricultural loans and/or grants. Fuel costs vary based on feedstock prices and transportation costs to move fuel to the digester. The cost of the technology is $110 per MWh without fuel charges. Small Cogeneration Avista has few industrial customers capable of developing cost-effective cogeneration projects. If an interested customer was inclined to develop a small cogeneration project, it could provide benefits including reduced transmission and distribution losses, shared fuel, capital, and emissions costs, and credit toward Washington’s EIA targets. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 124 of 1125 Chapter 6- Generation Resource Options Avista Corp 2013 Electric IRP Another potentially promising option is natural gas pipeline cogeneration. This technology uses waste-heat from large natural gas pipeline compressor stations. In Avista’s service territory few compressor stations exist, but the existing compressors in our service territory have potential for this generation technology. Avista has discussed adding cogeneration with pipeline owners. A big challenge in developing any new cogeneration project is aligning the needs of the cogenerator and the utility’s need for power. The optimal time to add cogeneration is when an industrial process is being retrofitted, but oftentimes the utility does not need the new capacity at this time. Another challenge to cogeneration within an IRP is estimating costs when host operations drive costs for a particular project. Nuclear Avista does not include nuclear plants as a resource option in the IRP given the uncertainty of their economics, the apparent lack of regional political support for the technology, U.S. nuclear waste handling policies, and Avista’s modest needs relative to the size of modern nuclear plants. Nuclear resources could be in Avista’s future only if other utilities in the Western Interconnect incorporate nuclear power in their resource mix and offer Avista an ownership share. The viability of nuclear power could change as national policy priorities focus attention on de-carbonizing the nation’s energy supply. The lack of newly completed nuclear facility construction experience in the United States makes estimating construction costs difficult. Cost projections in the IRP are from industry studies, recent nuclear plant license proposals, and a small number of projects currently under development. New smaller, and more modular, nuclear design could increase the potential for nuclear by shortening the permitting and construction phase (lower AFUDC costs), and make these traditionally large projects better fit the needs of smaller utilities. Table 6.7’s nuclear cost estimate is for a 1,100 MW facility. This assumes a capital cost of $9,125 per kW (including AFUDC). At this cost, a large facility could easily cost $10 billion to build and cost $173 per MWh over the first 20 years of project life. Table 6.7: Other Resource Options Levelized Costs ($/MWh) Landfill Gas Manure Digester Wood Biomass Geothermal Nuclear Capital Recovery & Taxes 36.35 65.43 60.09 57.12 114.25 AFUDC 1.01 1.03 4.43 8.78 29.93 Fuel Costs 33.60 33.60 56.40 0.00 10.83 Fixed O&M 4.45 7.70 31.84 29.43 15.41 Variable O&M 25.14 31.75 4.90 5.95 1.98 Transmission 4.67 4.13 1.41 4.08 4.13 Other Overheads 2.02 2.30 2.81 1.17 0.96 Total Cost 107.24 145.95 161.88 106.53 177.50 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 125 of 1125 Chapter 6- Generation Resource Options Avista Corp 2013 Electric IRP New Resources Cost Summary Avista has several resource alternatives for this IRP. Each alternative provides different benefits, costs and risks. The IRP identifies the relevant characteristics and chooses a set of resources that are actionable, meet energy and capacity needs, balance renewable requirements, and minimize costs. Figure 6.2 shows comparative cost per MWh of each new resource alternative over the first 20 years of project life using nominal levelized costs. Tables 6.8 and 6.9 provide detailed assumptions for each type of resource. The ultimate resource selection goes beyond simple levelized cost analyses and considers the capacity contribution of each resource, among other items discussed in the IRP. Figure 6.2: New Resource Levelized Costs (first 20 Years) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 126 of 1125 Chapter 6- Generation Resource Options Avista Corp 2013 Electric IRP Table 6.8: New Resource Levelized Costs Considered in PRS Analysis Resource Size (MW) Heat Rate (Btu/ kWh) Capital Cost ($/kW) Fixed O&M ($/kW-yr) Variable O&M ($/MWh) Peak Credit (Winter/ Summer) CCCT (air cooled) 270 6,832 1,279 22.7 1.77 104/94 Frame CT 83 11,286 910 11.5 3.13 104/94 Hybrid CT 92 8,712 1,199 16.1 5.22 104/94 Reciprocating Engines 114 8,712 1,141 18.8 6.26 100/100 Aero CT 100 9,802 1,185 13.6 4.17 104/94 Wind 100 n/a 2,340 53.0 2.09 0/0 Storage 5 n/a 3,889 52.2 0.00 100/100 Solar (photovoltaic) 5 n/a 3,403 53.0 0.00 0/62 Table 6.9: New Resource Levelized Costs Not Considered in PRS Analysis Resource Size (MW) Heat Rate (Btu/ kWh) Capital Cost ($/kW) Fixed O&M ($/kW-yr) Variable O&M ($/MWh) Peak Credit (Winter/ Summer) Pulverized Coal 600 8,910 3,683 41.73 2.87 100/100 IGCC Coal 600 8,594 4,895 62.60 6.57 100/100 IGCC Coal w/ Seq. 550 10,652 7,342 62.60 8.87 100/100 Woody Biomass 25 13,500 4,436 187.80 3.86 100/100 Geothermal 15 n/a 4,767 182.59 4.70 100/100 Landfill Gas 3.2 10,500 2,654 27.13 19.82 100/100 Anaerobic Digester 1 10,500 4,721 46.95 25.04 100/100 Nuclear 1100 10,400 9,125 93.90 1.57 100/100 Hydroelectric Project Upgrades and Options Avista continues to upgrade many of its hydroelectric facilities. The latest hydroelectric upgrade added nine megawatts to the Noxon Rapids Development in April 2012. Figure 6.3 shows the history of upgrades to Avista’s hydroelectric system by year and cumulatively. Avista added 40.1 aMW of incremental hydroelectric energy between 1992 and 2012. Upgrades completed after 1999 qualify for the EIA, thereby reducing the need for additional higher-cost renewable energy options. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 127 of 1125 Chapter 6- Generation Resource Options Avista Corp 2013 Electric IRP Figure 6.3: Historical and Planned Hydro Upgrades Avista’s next upgrade is at Nine Mile, replacing two of the four project units. Avista is currently removing the old equipment on units one and two, and replacing the 105-year old technology with new turbines, runners, generators, and other electrical equipment. The project is scheduled for completion in 2016. The Spokane River developments were built in the late 1800s and early 1900s, when the priority was to meet then-current loads. They do not to capture a majority of the river flow. In 2012, Avista re-assessed its Spokane River developments. The goal was to develop a long-term strategy and prioritize potential facility upgrades. Avista evaluated five of the six Spokane River developments and estimated costs for generation upgrade options at each. Each upgrade option should qualify for the EIA, meeting the Washington state renewable energy goal. These studies were part of the 2011 IRP Action Plan and are discussed below. Each of these upgrades would be a major engineering project, taking several years to complete, and require major changes to the FERC licenses and project water rights. Long Lake Second Powerhouse Avista studied adding a second powerhouse at Long Lake over 20 years ago by using a small arch dam (Saddle Dam) located on the south end of the project site. This project 0 10 20 30 40 50 0 2 4 6 8 10 19 9 2 - Mo n r o e S t r e e t U n i t 1 19 9 4 - Ni n e M i l e U n i t s 3 & 4 19 9 4 - Ca b i n e t U n i t 1 19 9 4 - Lo n g L a k e U n i t 4 19 9 4 - Li t t l e F a l l s U n i t 3 19 9 6 - Lo n g L a k e U n i t 1 19 9 7 - Lo n g L a k e U n i t 2 19 9 9 - Lo n g L a k e U n i t 3 20 0 1 - Ca b i n e t U n i t 3 20 0 1 - Li t t l e F a l l s U n i t 4 20 0 4 - Ca b i n e t U n i t 2 20 0 7 - Ca b i n e t U n i t 4 20 0 9 - No x o n U n i t 1 20 1 0 - No x o n U n i t 2 20 1 1 - No x o n U n i t 3 20 1 2 - No x o n U n i t 4 20 1 6 - Ni n e M i l e U n i t s 1 & 2 cu m u l a t i v e a v e r a g e m e g a w a t t s av e r a g e m e g a w a t t s Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 128 of 1125 Chapter 6- Generation Resource Options Avista Corp 2013 Electric IRP would be a major undertaking and require several years to complete, including major changes to the Spokane River license and water rights. In addition to providing customers with a clean energy source, this project could help reduce total dissolved gas concerns by reducing spill at the project and provide incremental capacity to meet peak load growth. The study focused on three alternatives. The first replaces the existing four-unit powerhouse with four larger units to total 120 MW, increasing capability by 32 MW. The other two alternatives develop a second powerhouse with a penstock beginning from a new intake near the existing saddle dam. One powerhouse option was a single 68 MW turbine project. The second was a two-unit 152 MW project. The best alternative in the study was the single 68 MW option. Table 6.10 shows upgrade costs and characteristics. Post Falls Refurbishment The Post Falls hydroelectric development is 108 years old. Three alternatives could increase the existing capacity from 18 MW up to 40 MW. The first option is a new two- unit 40 MW powerhouse on the south channel that removes the existing powerhouse. Alternative 2 retrofits the existing powerhouse with five 8.0 MW units (40 MW total). The last alternative retrofits the existing powerhouse with six 5.6-MW units (33.6 MW total). The cost differences between developing a new powerhouse in the south channel and the smaller plant refurbishment is small. Over the next decade, these alternatives will continue to be studied to address the aging infrastructure of the plant. Monroe Street/Upper Falls Second Power House Avista replaced the powerhouse at its Monroe Street project on the Spokane River in 1992. There are three options to increase its capability. Each would be a major undertaking requiring substantial cooperation with the City of Spokane to mitigate disruption in Riverfront Park and downtown Spokane during construction. The upgrade could increase capability by up to 80 MW. To minimize impacts on the downtown area and the park, a tunnel on the east side of Canada Island could be drilled, avoiding most above ground excavation of the south channel. A smaller option would be to add a second 40 MW Upper Falls powerhouse, but this option would require south channel excavation. The least cost option is an 80 MW upgrade adjacent to the existing Upper Falls facility. Cabinet Gorge Second Powerhouse Avista is exploring the addition of a second powerhouse at the Cabinet Gorge development site to mitigate total dissolved gas and produce additional electricity. A new powerhouse would benefit from an existing diversion tube around the dam and could range in size between 55 and 110 MW. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 129 of 1125 Chapter 6- Generation Resource Options Avista Corp 2013 Electric IRP Table 6.10: Hydro Upgrade Option Costs and Benefits Resource Inc. Capacity (MW) Inc. Energy (MWh) Inc. Energy (aMW) Peak Credit (Winter/ Summer) Capital Cost ($ Mill) Levelized Cost ($/MWh) Post Falls 22 90,122 10.3 24/0 $110 158.60 Monroe St/Upper Falls 80 237,352 27.1 31/0 $153 87.50 Long Lake 68 202,592 23.1 100/100 $141 97.45 Cabinet Gorge 55 80,963 9.2 0/0 $116 192.56 Thermal Resource Upgrade Options The 2011 IRP identified several thermal upgrade options for Avista’s fleet. Since then Avista has negotiated with the turbine servicers to have some of the upgrades completed as part of an enhancement package during the 2013 maintenance cycle for Coyote Springs 2. The upgrades include Mark Vie controls, digital front end on the EX2100 gas turbine exciter, and model based controls with enhanced transient capability. These enhancements will improve reliability of the plant, reduce future O&M costs, improve our ability to maintain compliance with WECC reliability standards, and help prevent damage to the machine if electrical system disturbances occur. Installation of cold day controls and cooling optimization will occur after permitting is complete. In addition to the upgrades at Coyote Springs 2, there are options at the Rathdrum CT site. Other Avista-owned project sites were reviewed, but based on economics none of the options were included for the 2013 IRP. Rathdrum CT to CCCT Conversion The Rathdrum CT has two GE 7EA units in simple cycle configuration built in 1995 with an approximate 160 MW of combined output used to serve customers in peak load conditions. It is possible to convert this peaking facility to a combined cycle plant by adding 80 MW of steam-turbine capacity (depending upon temperature), and increasing operating efficiency from a heat rate of 11,612 Btu/kWh, in its existing configuration, to a heat rate of about 8,000 Btu/kWh. A major issue with this conversion, besides overall cost, is noise. Residential development at the site since the plant’s construction adds complexity to a project that would shift from occasional use during peak periods to more of a base-load configuration. Rathdrum CT Water Demineralizer Another identified upgrade at Rathdrum is the addition of a water demineralizer to allow summertime inlet fogging. Fogging increases peak output during hot summer load periods. The plant utilized a leased demineralizer in the past, but high leasing costs moved Avista to end the program. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 130 of 1125 Chapter 7- Market Analysis Avista Corp 2013 Electric IRP 7. Market Analysis Introduction This section describes the electricity and natural gas market environment developed for the 2013 IRP. It contains pricing risks Avista considers to meet customer demands at the lowest reasonable cost. The analytical foundation for the 2013 IRP is a fundamentals-based electricity model of the entire Western Interconnect. The market analysis evaluates potential resource options on their net value when operated in the wholesale marketplace, rather than on the simple summation of their installation, operation, maintenance, and fuel costs. The PRS analysis uses these net values when selecting future resource portfolios. Understanding market conditions in the geographic areas of the Western Interconnect is important, because regional markets are highly correlated by large transmission linkages between load centers. This IRP builds on prior analytical work by maintaining the relationships between the various sub-markets within the Western Interconnect, and the changing values of company-owned and contracted-for resources. The backbone of the analysis is AURORAXMP, an electric market model that emulates the dispatch of resources to loads across the Western Interconnect given fuel prices, hydroelectric conditions, and transmission and resource constraints. The model’s primary outputs are electricity prices at key market hubs (e.g., Mid-Columbia), resource dispatch costs and values, and greenhouse gas emissions. Section Highlights Natural gas and wind resources dominate new generation additions in the West. Shale gas continues to lower natural gas and electricity price forecasts. A growing Northwest wind fleet reduces springtime market prices below zero in many hours. Federal greenhouse gas policy remains uncertain, but new EPA policies point toward a regulatory model rather than a cap-and-trade system. Lower natural gas prices and lower loads have reduced greenhouse gas emissions from the U.S. power industry by 11 percent since 2007. The Expected Case forecasts a continuing reduction to Western Interconnect greenhouse gas emissions due to coal plant shut downs brought on by EPA regulations. Coal plant shut downs have similar carbon reduction results as a cap-and- trade market scheme, but have the advantage of not causing wholesale market price disruptions. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 131 of 1125 Chapter 7- Market Analysis Avista Corp 2013 Electric IRP Marketplace AURORAXMP is a fundamentals-based modeling tool used by Avista to simulate the Western Interconnect electricity market. The Western Interconnect includes the states west of the Rocky Mountains, the Canadian provinces of British Columbia and Alberta, and the Baja region of Mexico as shown in Figure 7.1. The modeled area has an installed resource base of approximately 240,000 MW. Figure 7.1: NERC Interconnection Map The Western Interconnect is separated from the Eastern and ERCOT interconnects to the east by eight DC inverter stations. It follows operation and reliability guidelines administered by WECC. Avista modeled the electric system as 17 zones based on load concentrations and transmission constraints. After extensive study in prior IRPs, Avista now models the Northwest region as a single zone because this configuration dispatches resources in a manner more reflective of historical operations. Table 7.1 describes the specific zones modeled in this IRP. Table 7.1: AURORAXMP Zones Northwest- OR/WA/ID/MT Southern Idaho COB- OR/CA Border Wyoming Eastern Montana Southern California Northern California Arizona Central California New Mexico Colorado Alberta British Columbia South Nevada North Nevada Baja, Mexico Utah Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 132 of 1125 Chapter 7- Market Analysis Avista Corp 2013 Electric IRP Western Interconnect Loads The 2013 IRP relies on a load forecast for each zone of the Western Interconnect. Avista uses other utilities’ resource plans to quantify load growth across the west. These estimates include energy efficiency and demand reduction caused by current and potential emissions legislation, and associated price increases also expected to reduce load growth rates from their present trajectory. Regional load growth estimates are in Figure 7.2. Avista forecasts overall Western Interconnect loads will rise nearly 1 percent annually over the next 20 years. This is a significant reduction in expected energy growth from the 2011 IRP’s 1.65 percent load growth assumption. Between 2008 and 2011, actual Western U.S. electricity demand declined by approximately 1 percent. However, loads did recover from their 2010 low of 2.6 percent below 2008 levels. The reduced energy growth projection is due to lower estimates of economic growth combined with energy efficiency gains that have reducing energy use. On a regional basis, the West Coast and Rocky Mountain states forecasts lower than 1 percent growth, while the desert Southwest region continues to expect growth in the 1 to 2 percent range. The strongest projected growth area in the region comes from Alberta at 2.5 percent. From a system reliability perspective, Avista expects peak loads to grow at a slower pace than the last IRP. Northwest peak load growth rates average 0.93 percent annually. In California, demand response and high end-use solar penetration should reduce its system peak by 0.26 percent per year. Remaining regions should have growth rates similar to their energy forecast. Figure 7.2: 20-Year Annual Average Western Interconnect Energy California Northwest Desert SW Rocky Mountains Canada - 20,000 40,000 60,000 80,000 100,000 120,000 140,000 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 av e r a g e m e g a w a t t s Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 133 of 1125 Chapter 7- Market Analysis Avista Corp 2013 Electric IRP Transmission In past IRP’s, expansion to the region’s transmission system was expected to occur in the middle of the 20-year planning horizon. Due to changes in the marketplace, such as lower natural gas prices and the significant reduction in the cost of solar, many transmission projects expected in the 2011 IRP are on hold or cancelled. Remaining transmission projects are smaller or delayed. Table 7.2 shows the regional transmission upgrades included in this IRP. Only upgrades between modeled zones are shown, as transmission upgrades within AURORAXMP zones are not explicitly in the model; they do not affect power transactions between zones. Table 7.2: Western Interconnect Transmission Upgrades Included in Analysis Project From To Year Available Capacity MW Eastern Nevada Intertie North Nevada South Nevada 2016 1,000 Gateway South Wyoming Utah 2015 3,000 Gateway Central Idaho Utah 2015 1,350 Gateway West Wyoming Idaho 2016 1,500 SunZia/Navajo Transmission Arizona New Mexico 2017 3,000 Wyoming – Colorado Intertie Wyoming Colorado 2014 900 Hemingway to Boardman Idaho Northwest 2020 1,400 Resource Retirements Since filing the 2011 IRP, new attention across western states is being directed to retire aging power plants, specifically plants with larger environmental impacts, such as once-through-cooling (OTC) in California and older coal technology throughout North America. Recently various states, encouraged by environmentally-focused groups, are developing rules to eliminate certain generation technologies. In California, all OTC facilities require retrofitting to eliminate OTC technology, or must retire. Over 14,200 MW of OTC natural gas-fired generators in California are forecast to be retired and replaced in the IRP timeframe. Remaining OTC natural gas-fired and nuclear facilities with more favorable fundamentals are expected to be retrofitted with other cooling technology. Many OTC plants have identified shutdown dates from their utility owners’ IRPs, and company news releases. The remaining plants are assumed to shut down between 2017 and 2024; this retirement schedule is similar to WECC studies (see Figure 7.3 for the retirement schedule assumed in the 2013 IRP). Elimination of OTC plants in California will eliminate older technology presently used for reserves and high demand hours. While replacements will be expensive for California customers, they will be served by a more modern generation fleet. Coal-fired facilities are also under increasing regulatory scrutiny. In the Northwest, the Centralia and Boardman coal plants are scheduled to retire in 2020 and 2025 respectively, a reduction of 1,961 megawatts. Other coal-fired plants throughout the Western Interconnect have announced plant closures, including Four Corners, Carbon, Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 134 of 1125 Chapter 7- Market Analysis Avista Corp 2013 Electric IRP Arapahoe, San Juan, and Corette. Due to recent EPA standards, the IRP forecasts additional coal-fired facility retrofits or retirements.1 Plant retirements are based on Avista analyses, considering each plant’s location, their unit sizes and fuel costs, and their current emission control technology. Based on these factors, Avista judges whether the plant is likely to face enough regulatory burdens to make the plant uneconomic. It is not the intent of the IRP to include a perfect coal retirement forecast, as this would be impossible. Instead, such analyses help Avista understand the potential effects a reduction in coal output in the West will have on pricing and the benefit of future resource investments by Avista. The analysis found that 12,300 MW of coal generation might shut down over the 20-year planning horizon. A graphical representation of the retirement is in Figure 7.3. Figure 7.3: Resource Retirements (Nameplate Capacity) New Resource Additions New resource capacity is required to meet future load growth and replace retiring power plants over the next 20 years. To fill the gap, resources are added to each region to sustain a 5 percent Loss of Load Probability (LOLP), or in other words, all system demand must be met in 95 percent of simulated forecasts. The generation additions must meet capacity, energy, ancillary services, and renewable portfolio mandates. To meet future requirements, natural gas-fired CCCT or SCCT, solar, wind, coal IGCC with sequestration, and nuclear options were considered.2 The IRP does not include new 1 A recently passed Nevada law allows NV Energy to retire its coal plants. 2 Based on analysis in Chapter 6, Generation Resource Options, solar generation in the southern states receives a 56 percent capacity factor, while in the Northwest it would receive no peak credit. Wind - 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 cu m u l a t i v e m e g a w a t t s me g a w a t t s Natural Gas Coal Cumulative Retirements Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 135 of 1125 Chapter 7- Market Analysis Avista Corp 2013 Electric IRP non-sequestered pulverized coal plants over the forecast horizon, consistent with recent EPA new source performance standard issued in late 2012. Many states have RPS requirements promoting renewable generation to reduce greenhouse gas emissions, provide jobs, and diversify their energy mix. RPS legislation generally requires utilities to meet a portion of their load with qualified renewable resources. No federal RPS mandate exists presently; therefore, each state defines RPS obligations differently. AURORAXMP cannot model RPS levels explicitly. Instead, Avista inputs RPS requirements into the model at levels sufficient to satisfy state laws. Figure 7.4 illustrates new capacity and RPS additions made in the modeling process. Wind and solar facilities meet most renewable energy requirements. Geothermal, biomass, and hydroelectric resources provide limited RPS contributions. Renewable resource choices differ depending on state laws and the local availability of renewable resources. For example, the Southwest will meet RPS requirements with solar and wind given policy choices by those states. The Northwest will use a combination of wind and hydroelectric upgrades because the costs of these resources are the lowest. Rocky Mountain states will predominately meet RPS requirements with wind. Figure 7.4: Cumulative Generation Resource Additions (Nameplate Capacity) With lower load growth, and even with 26 GW in resource retirements, the forecast for new resource capacity additions is lower than prior IRPs. Compared to the 2011 IRP, receives a 5 percent capacity credit on a regional basis, but receives no capacity credit for meeting Avista’s balancing authority requirements. 0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 me g a w a t t s Other Wind Solar SCCT CCCT Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 136 of 1125 Chapter 7- Market Analysis Avista Corp 2013 Electric IRP future natural gas capacity is down 5 GW, wind is lower by 10 GW, other renewables are slightly lower, and solar maintains similar additions. The Northwest market will need new capacity beginning in 2017 with the addition of combined- or simple-cycle CTs. Based on market simulation results, a 21 percent regional planning margin (including operating reserves) is necessary. The Northwest likely will continue to develop wind to meet RPS requirements, with small contributions from other renewable resources. Over the 20-year forecast, six gigawatts of new natural gas capacity is projected, along with over seven gigawatts of new wind capacity and one gigawatt of other renewable including solar, biomass, geothermal, and hydro. Fuel Prices and Conditions Fuel cost and availability are some of the most important drivers of the overall wholesale marketplace and resource values. Some resources, including geothermal and biomass, have limited fuel options or sources, while coal and natural gas have more potential. Hydro, wind, and solar benefit from free fuel, but are highly dependent on weather and limited siting opportunities. Natural Gas The fuel of choice for new base-load and peaking capability continues to be natural gas. Natural gas in past years was subject to significant price volatility. Unconventional sources have since reduced overall price levels and volatility, although it unknown how much volatility will exist in the future market as technology plays out against regulatory pressures and the potential for new demand created by falling prices. Avista uses forward market prices and a combination of two December 2012 forecasts from prominent energy industry consultants to develop its natural gas price forecast for this IRP. The levelized nominal price is $5.62 per dekatherm at Henry Hub (shown in Figure 7.5 as the gray bars). For the first year of the forecast, forward prices are used. After the first year, a 50/50 average of the consultant forecasts combines with the forward market to transition from a forward pricing methodology to a fundamental price forecast, as follows: 2015: 75 percent market, 25 percent consultant average; 2016: 50 percent market, 50 percent consultant average; and 2017-19: 25 percent market, 75 percent consultant average. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 137 of 1125 Chapter 7- Market Analysis Avista Corp 2013 Electric IRP Figure 7.5: Henry Hub Natural Gas Price Forecast Natural gas market transformation has brought consultant assumptions closer together. In previous forecasts, the Alaskan natural gas pipeline was included in many forecasts, but is no longer included in either forecast. Growth in the residential, commercial, and industrial markets is flat. Carbon legislation used to be included early and robust in both forecasts, but it is now delayed and less robust. The forecast from one consultant has muted demand growth through 2015. As domestic and global GDP growth rates improve, demand growth begins to materialize. This growth is led by natural gas utilized for power generation in support of renewable energy, and by coal plant retirements caused by new EPA regulations. Additionally, widespread adoption of natural gas for transportation and LNG exports increase demand in later years of the forecast. The forecast from one of the consultants has growth driven almost entirely by natural gas generation. LNG exports are also included in this forecast at a very modest level beginning in 2018. Price differences across North America depend on demand at the trading hubs and the pipeline constraints between them. Many pipeline projects are in the works in the Northwest and the West to access historically cheaper natural gas supplies located in the Rocky Mountains. Table 7.3 presents western natural gas basin differentials from Henry Hub prices. Prices converge over the course of the study as new pipelines and sources of natural gas materialize. To illustrate the seasonality of natural gas prices, monthly Stanfield price shapes in Table 7.4 show selected forecast years. $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 $8.00 $9.00 $10.00 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 do l l a r s p e r d e k a t h e r m Forecast Consultant 1 Consultant 2 Forwards (Nov 2012) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 138 of 1125 Chapter 7- Market Analysis Avista Corp 2013 Electric IRP Table 7.3: Natural Gas Price Basin Differentials from Henry Hub Basin 2015 2020 2025 2030 Stanfield 101% 95% 94% 96% Malin 102% 97% 95% 98% Sumas 96% 94% 93% 95% AECO 90% 87% 85% 87% Rockies 100% 92% 86% 85% Southern CA 106% 102% 103% 106% Table 7.4: Monthly Price Differentials for Stanfield from Henry Hub Month 2015 2020 2025 2030 Jan 103.3% 95.3% 93.3% 94.2% Feb 102.6% 96.1% 93.1% 94.4% Mar 103.1% 97.8% 96.7% 98.6% Apr 101.7% 96.8% 93.4% 96.0% May 98.8% 94.5% 91.9% 93.9% Jun 98.6% 94.0% 92.0% 92.9% Jul 98.6% 93.9% 91.8% 94.4% Aug 98.3% 93.6% 92.9% 95.1% Sep 97.7% 93.7% 92.7% 95.2% Oct 99.1% 94.7% 93.6% 95.9% Nov 103.2% 98.2% 97.3% 99.0% Dec 102.5% 96.7% 94.6% 98.1% Unconventional Natural Gas Supplies Shale natural gas production has game-changing impacts on the natural gas industry, dramatically revising the amount of economical natural gas production. Shale gas can cost less than conventional natural gas production because of economies of scale, near elimination of exploration risks, standardization, and sophisticated production techniques that streamline costs and minimize the time from drilling to market delivery. Shale gas will continue to be a major factor in the natural gas marketplace, holding down both prices and volatility over the long run as production responds to changing market conditions. This in turn leads to numerous ripple effects, including longer-term bilateral hedging transactions, new financing structures including cost index pricing, and/or vertical integration by utilities choosing to limit their exposure to natural gas price increases and volatility. Shale gas is not without controversy. Concerns about water, air, noise, and seismic impacts arise from unconventional extraction techniques. Water issues include availability, chemical mixing, groundwater contamination, and disposal. Air quality concerns stem from methane leaks during production and processing. Mitigating excessive noise in urban drilling and potential elevated seismic activity near drilling sites are also concerns. State and federal agencies are reviewing the environmental impacts of this production method. As a result, unconventional natural gas production has Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 139 of 1125 Chapter 7- Market Analysis Avista Corp 2013 Electric IRP stopped in some areas. Increased environmental protections might change costs and environmental uncertainty could precipitate increased price volatility. Shale gas production influences the U.S. liquid natural gas (LNG) market. It has broken the link between North American natural gas and global LNG prices. Numerous planned re-gasification terminals are on hold or cancelled. Some facilities are seeking approvals to become LNG exporters rather than importers. These changes appear to affect natural gas storage and transportation infrastructure. For example, the Kitimat LNG export terminal in northern British Columbia, if built, will export significant LNG quantities to Asian markets. These exports will affect overall market conditions for natural gas in the United States and the Pacific Northwest, as British Columbia traditionally has provided significant natural gas supplies to the northwest United States. Coal This IRP models no new coal plants in the Western Interconnect, so coal price forecasts affect only existing facilities. The average annual price increase over the IRP timeframe is 2.9 percent based on Energy Information Administration estimates for Wyoming Coal Prices. For Colstrip Units 3 and 4, Avista used escalation rates based on expectations from existing contracts. Hydroelectric The Northwest U.S., British Columbia, and California have substantial hydroelectric generation capacity. A favorable characteristic of hydroelectric power is its ability to provide near-instantaneous generation up to and potentially beyond its nameplate rating. This characteristic is valuable for meeting peak load, following general intra-day load trends, shaping energy for sale during higher-valued hours, and integrating variable generation resources. The key drawback to hydroelectricity is its variable and limited fuel supply. This IRP uses an 80-year hydro record from the 2014 BPA rate case. The study provides monthly energy levels for the region over an 80-year hydrological record spanning 1928 to 2009. This IRP also includes BPA hydro estimates for the 80-year record for British Columbia and California. The 80-year record is less than 1 percent lower than the 70-year record used in previous IRPs. Many IRP analyses use an average of the 80-year hydroelectric record; whereas stochastic studies randomly draw from the 80-year record, as the historical distribution of hydroelectric generation is not normally distributed. Avista does both. Figure 7.6 shows the average hydroelectric energy of 15,706 aMW in Washington, Oregon, Idaho, and western Montana. The chart also shows the range in potential energy used in the stochastic study, with a 10th percentile water year of 12,370 aMW (-21 percent), and a 90th percentile water year of 18,475 aMW (+18 percent). AURORAXMP maps each hydroelectric plant to a load zone, creating a similar energy shape for all hydro projects in a load zone. For Avista hydroelectric plants, AURORAXMP uses the output from proprietary software with a better representation of operating Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 140 of 1125 Chapter 7- Market Analysis Avista Corp 2013 Electric IRP characteristics and capabilities. For modeling, AURORAXMP represents hydroelectric plants using annual and monthly capacity factors, minimum and maximum generation levels, and sustained peaking generation capabilities. The model’s objective, subject to constraints, is to move hydroelectric generation into peak hours to follow daily load changes; this maximizes the value of the system consistent with actual operations. Figure 7.6: Northwest Expected Energy Wind Additional wind resources are necessary to satisfy renewable portfolio standards. These additions mean significant competition for the remaining higher-quality wind sites. The capacity factors in Figure 7.7 present average generation for the entire area, not for specific projects. The IRP uses capacity factors from a review of the BPA and the National Renewable Energy Laboratory (NREL) wind data. 0% 2% 4% 6% 8% 10% 12% 12 , 0 0 0 12 , 5 0 0 13 , 0 0 0 13 , 5 0 0 14 , 0 0 0 14 , 5 0 0 15 , 0 0 0 15 , 5 0 0 16 , 0 0 0 16 , 5 0 0 17 , 0 0 0 17 , 5 0 0 18 , 0 0 0 18 , 5 0 0 19 , 0 0 0 19 , 5 0 0 20 , 0 0 0 20 , 5 0 0 pe r c e n t o f w a t e r y e a r s average megawatts Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 141 of 1125 Chapter 7- Market Analysis Avista Corp 2013 Electric IRP Figure 7.7: Regional Wind Expected Capacity Factors Greenhouse Gas Emissions Greenhouse gas regulation is a significant risk for the electricity marketplace today because of the industry’s heavy reliance on carbon-emitting thermal power generation. Reducing carbon emissions at existing power plants, and the construction of low- and non-carbon-emitting technologies, changes the resource mix over time. Since 2007, carbon emissions from electric generation have fallen from highs by nearly 11 percent due to reduced loads and lower coal generation levels. Future carbon emissions could continue to fall due to fundamental market changes. To accelerate the reductions, national legislation would be required, but this plan assumes that no federal cap and trade regulations or carbon tax will constrain greenhouse emissions in the IRP timeframe. However, EPA regulations aimed at reducing air pollutants such as NOX and SO2 will have some marginal impacts on the generation fleet profile. In the interim, California and some Canadian provinces have greenhouse reduction goals and costs on greenhouse gas emissions. Within the Expected Case’s market price forecast of this IRP, only existing greenhouse gas regulations and a forecast of expected plant closures based on current EPA regulations affect the market. No national cap and trade or carbon tax is included with the exception of a carbon- pricing scenario discussed later in this chapter. Environmental regulations decrease or maintain existing greenhouse gas emissions levels, instead of the cap and trade or tax mechanisms used in Avista’s earlier IRPs. Risk Analysis To account for future electricity price uncertainty, a stochastic study is preformed using the variables discussed earlier in this chapter. It is better to represent the electricity 32.0%33.5%34.5% 30.7% 37.2%38.5% 28.8%29.0% 32.3% 0% 10% 20% 30% 40% 50% NW BC AB CA MT WY SW UT CO ca p a c i t y f a c t o r Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 142 of 1125 Chapter 7- Market Analysis Avista Corp 2013 Electric IRP price forecast as a range instead of a point estimate, as point estimates are unlikely to forecast underlying assumptions perfectly. Stochastic price forecasts develop a more robust resource strategy by accounting for tail risk. This IRP developed 500 20-year market futures to provide a distribution of the marketplace and illustrate potential tail risk outcomes. The next several pages discuss the input variables driving market prices, and describe the methodology and the range in inputs used in the modeling process. Natural Gas Natural gas prices are among the most volatile of any traded commodity. Daily Stanfield prices ranged between $1.72 and $13.69 per dekatherm between 2004 and 2012. Average Stanfield monthly prices since January 2004 are in Figure 7.8. Prices retreated from 2008 highs to a monthly price of $1.87 per dekatherm in April 2012. Figure 7.8: Historical Stanfield Natural Gas Prices (2004-2012) There are several methods to stochastically model natural gas prices. This IRP retains the 2011 IRP method with the mean prices discussed in Figure 7.5 as the starting point. Prices vary using historical month-to-month volatility and a lognormal distribution. Figure 7.9 shows Stanfield natural gas price duration curves for 2014, 2020, 2026 and 2032. The chart illustrates a larger price range in later years, reflecting a growing distribution. Shorter-term prices are more certain due to additional market information and the quantity of near term natural gas trading. Another view of the forecast is in Figure 7.10. The mean price in 2014 is $3.95 per dekatherm, represented by the horizontal bar; the median level is $3.89 per dekatherm. The bottom and top of the bars represent the 10th and 90th percentiles. The bar length indicates price uncertainty. $0.00 $2.00 $4.00 $6.00 $8.00 $10.00 $12.00 Ja n -04 Ju n -04 No v -04 Ap r -05 Se p -05 Fe b -06 Ju l -06 De c -06 Ma y -07 Oc t -07 Ma r -08 Au g -08 Ja n -09 Ju n -09 No v -09 Ap r -10 Se p -10 Fe b -11 Ju l -11 De c -11 Ma y -12 Oc t -12 do l l a r s p e r d e k a t h e r m Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 143 of 1125 Chapter 7- Market Analysis Avista Corp 2013 Electric IRP Figure 7.9: Stanfield Annual Average Natural Gas Price Distribution Figure 7.10: Stanfield Natural Gas Distributions 0 100 200 300 400 500 $2 . 0 0 $3 . 0 0 $4 . 0 0 $5 . 0 0 $6 . 0 0 $7 . 0 0 $8 . 0 0 $9 . 0 0 $1 0 . 0 0 $1 1 . 0 0 $1 2 . 0 0 $1 3 . 0 0 it e r a t i o n dollars per dekatherm 2014 2020 2026 2032 $0.00 $2.00 $4.00 $6.00 $8.00 $10.00 $12.00 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 do l l a r s p e r d e k a t h e r m Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 144 of 1125 Chapter 7- Market Analysis Avista Corp 2013 Electric IRP Regional Load Variation Several factors drive load uncertainty. The largest short-run driver is weather. Over the long-run economic conditions, such as the Great Recession, tend to have a more significant effect on the load forecast. IRP loads increase on average at the levels discussed earlier in this chapter, but risk analyses emulate varying weather conditions and base load impacts. Avista continues to use a method it first adopted for its 2003 IRP to model weather variation. FERC Form 714 data for the years 2007 through 2011 for the Western Interconnect form the basis for the analysis. Correlations between the Northwest and other Western Interconnect load areas represent how loads change together across the larger system. This method avoids oversimplifying the Western Interconnect load picture. Absent the use of correlation, stochastic models will offset changes in one variable with changes in another, thereby virtually eliminating the possibility of modeling correlated excursions actually experienced by a system. Given the high degree of interdependency across the Western Interconnect created by significant intertie connections, the additional accuracy from modeling loads in this matter is crucial for understanding variation in wholesale electricity market prices. It is also crucial for understanding the value of peaking resources and heir use in meeting system variation. Tables 7.5 and 7.6 present the load correlations used for the 2013 IRP. Statistics are relative to the Northwest load area (Oregon, Washington and Idaho). ―NotSig‖ in the table indicates that no statistically valid correlation exists in the evaluated load data. ―Mix‖ indicates the relationship was not consistent across the 2007 to 2011 period. For regions and periods with NotSig and Mix results, no correlations are modeled. Tables 7.7 and 7.8 provide the coefficient of determination values for each zone.3 Table 7.5: January through June Load Area Correlations Area Jan Feb Mar Apr May Jun Alberta Not Sig 17% 25% 8% Mix Mix Arizona 8% 42% Mix Not Sig Mix Not Sig Avista 89% 85% 84% 83% 47% 53% British Columbia 91% 88% 71% 77% 52% 61% California Not Sig Not Sig Mix Mix 17% 32% CO-UT-WY -7% Mix Mix -20% -3% -17% Montana 27% 30% 72% 63% 10% 18% New Mexico Not Sig Not Sig Mix Not Sig Mix Mix North Nevada 62% 27% Not Sig Not Sig Mix 18% South Idaho 84% 79% 68% Not Sig Not Sig 29% South Nevada 17% 56% Mix Not Sig Mix Not Sig 3 The coefficient of determination is the standard deviation divided by the average. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 145 of 1125 Chapter 7- Market Analysis Avista Corp 2013 Electric IRP Table 7.6: July through December Load Area Correlations Area Jul Aug Sep Oct Nov Dec Alberta Not Sig Mix 16% Not Sig 50% Not Sig Arizona Not Sig Not Sig Mix Not Sig Mix Not Sig Avista 66% 77% 68% 77% 93% 91% British Columbia 70% 38% 19% 79% 90% 81% California 10% Not Sig Not Sig -11% Mix Not Sig CO-UT-WY -10% -2% -5% Not Sig 22% Mix Montana Mix 8% 8% Not Sig 77% 73% New Mexico Mix Mix Mix -9% Not Sig Not Sig North Nevada 52% 44% 26% Not Sig 77% 52% South Idaho 51% 64% Not Sig Mix 86% 89% South Nevada Not Sig 25% Mix -8% Mix 56% Table 7.7: Area Load Coefficient of Determination (Standard Deviation/Mean) Area Jan Feb Mar Apr May Jun Alberta 2.9% 2.5% 3.1% 2.6% 2.7% 3.0% Arizona 5.1% 5.0% 3.5% 5.8% 8.6% 10.3% Avista 6.9% 5.4% 6.3% 5.9% 5.2% 5.7% British Columbia 4.8% 4.4% 5.1% 5.3% 5.2% 3.9% California 5.4% 5.1% 5.3% 5.9% 7.4% 8.1% CO-UT-WY 4.6% 4.6% 4.4% 3.7% 4.8% 7.9% Montana 5.5% 4.4% 4.2% 4.3% 3.7% 5.9% New Mexico 4.5% 5.0% 4.3% 4.6% 6.9% 6.7% Northern Nevada 2.8% 3.0% 3.2% 3.2% 4.3% 5.5% Pacific Northwest 6.7% 6.0% 5.6% 5.8% 4.7% 4.3% South Idaho 6.0% 5.6% 5.1% 6.1% 8.3% 14.7% South Nevada 5.0% 4.1% 3.5% 6.5% 10.7% 12.7% Baja Mexico 5.4% 5.1% 5.3% 5.9% 7.4% 8.1% Table 7.8: Area Load Coefficient of Determination (Standard Deviation/Mean) Area Jul Aug Sep Oct Nov Dec Alberta 3.1% 3.2% 2.7% 2.7% 2.9% 3.1% Arizona 6.5% 6.7% 7.8% 9.2% 4.0% 5.0% Avista 6.2% 7.2% 5.3% 5.4% 7.0% 6.8% British Columbia 4.8% 4.4% 4.2% 5.0% 7.0% 5.8% California 7.0% 7.6% 9.1% 6.7% 5.7% 5.4% CO-UT-WY 6.7% 5.7% 5.7% 4.1% 4.6% 4.4% Montana 5.0% 5.0% 3.6% 3.9% 5.1% 5.1% New Mexico 5.9% 5.4% 6.0% 5.6% 4.6% 4.6% Northern Nevada 4.7% 4.8% 4.6% 2.8% 3.7% 3.5% Pacific Northwest 5.5% 5.6% 4.4% 5.1% 7.2% 8.0% South Idaho 5.1% 7.0% 8.9% 5.7% 7.0% 6.1% South Nevada 6.6% 7.2% 10.0% 8.7% 3.6% 4.2% Baja Mexico 7.0% 7.6% 9.1% 6.7% 5.7% 5.4% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 146 of 1125 Chapter 7- Market Analysis Avista Corp 2013 Electric IRP Hydroelectric Variation Hydroelectric generation is the most commonly modeled stochastic variable in the Northwest because it has a large impact on regional electricity prices than other variables. The IRP uses an 80-year hydro record starting with the 1928/29 water year. Every iteration starts with a randomly drawn water year from the historical record, so each water year is selected approximately 125 times in the study (500 scenarios x 20 years / 80 water year records). There is some debate in the Northwest over whether the hydroelectric record has year-to-year correlation. Avista did not model year-to-year correlation after finding a modest 35 percent correlation over the 80-year record. Wind Variation Wind has the most volatile short-term generation profile of any large-scale resource presently available to utilities. Storage, apart from some integration with hydroelectric projects, is not a financially viable alternative at this time. This makes it necessary to capture wind volatility in the power supply model to determine its value in the wholesale power market. Accurately modeling wind resources requires hourly and intra-hour generation shapes. For regional market modeling, the representation is similar to how AURORAXMP models hydroelectric resources. A single wind generation shape represents all wind resources in each load area. This shape is smoother than it would be for an individual wind plant, but it closely represents the diversity that a large number of wind farms located across a zone would create. This simplified wind methodology works well for forecasting electricity prices across a large market, but it does not accurately represent the volatility of specific wind resources Avista might select as part of its Preferred Resource Strategy. Therefore individual wind farm shapes form the basis of wind resource options for Avista. Ten potential 8,760-hour annual wind shapes represent each geographic region or facility. Each year contains a wind shape drawn from these 10 representations. The IRP relies on two data sources for the wind shapes. The first is BPA balancing area wind data. The second is NREL-modeled data between 2004 and 2006. Avista believes that an accurate representation of a wind shape across the West requires meeting several conditions: 1. The data is correlated between areas and reflective of history. 2. Data within load areas is auto-correlated.4 3. The average and standard deviation of each load area’s wind capacity factor is consistent with the expected amount of energy for a particular area in the year and month. 4. The relationship between on- and off-peak wind energy is consistent with historic wind conditions. For example, more energy in off-peak hours than on-peak hours where this has been experienced historically. 4 Adjoining hours or groups of hours are correlated to each other. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 147 of 1125 Chapter 7- Market Analysis Avista Corp 2013 Electric IRP 5. Hourly capacity factors for a diversified wind region are never be greater than about 90 percent due to turbine outages and wind diversity within-area. Absent meeting these conditions, it is unlikely any wind study provides a level of accuracy adequate for planning efforts. The methodology developed for the 2013 IRP attempts to adhere to the five requirements by first using a regression model based on historic data for each region. The independent variables used in the analysis were month, hour type (night or day), and generation levels from the prior two hours. To reflect correlation between regions, a capacity factor adjustment reflects historic regional correlation using an assumed normal distribution with the historic correlation as the mean. After this adjustment, a capacity factor adjustment takes account of those hours with generation levels exceeding a 90 percent capacity factor. The resulting capacity factors for each region are in Table 7.9. A Northwest region example of an 8,760-hour wind generation profile is in Figure 7.11. This example, shown in blue, has a 33 percent capacity factor. Figure 7.12 shows actual 2012 generation recorded by BPA Transmission; in 2012, the average wind fleet in BPA’s balancing authority had a 26.2 percent capacity factor. Table 7.9: Expected Capacity factor by Region Region Capacity Factor Region Capacity Factor Northwest 32.0% Southwest 28.9% California 30.9% Utah 28.8% Montana 37.2% Colorado 32.2% Wyoming 38.5% British Columbia 33.4% Eastern Washington 30.7% Alberta 34.5% Figure 7.11: Wind Model Output for the Northwest Region 0% 20% 40% 60% 80% 100% 1 877 1,753 2,629 3,505 4,381 5,257 6,133 7,009 7,885 ca p a c i t y f a c t o r hours Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 148 of 1125 Chapter 7- Market Analysis Avista Corp 2013 Electric IRP Figure 7.12: 2012 Actual Wind Output BPA Balancing Authority5 There is speculation that correlation exists between wind and hydro, especially outside of the winter months where storm events bring both rain to the river system and wind to the wind farms. This IRP does not correlate wind and hydro due to a lack of historical wind data to test this hypothesis. Where correlation exists, it would be optimal to run the model 80 historical wind years with matching historical water years. Forced Outages Generator forced outages are represented by a simple average reduction to maximum capability in most deterministic market modeling studies. This over simplification generally represents expected values well; however, it is better to represent the system more accurately in stochastic modeling by randomly placing non-hydro units out of service based on a mean time to repair and an average forced outage rate. Internal studies show that this level of modeling detail is necessary only for natural gas-fired, coal, and nuclear plants with generating capacities in excess of 100 MW. Plants on forced outage smaller than 100 MW do not have a material impact on market prices and therefore are not modeled. Forced outage rates and mean time to repair data for the larger units in the WECC come from analyzing the North American Electric Reliability Corporation’s Generating Availability Data System database. Market Price Forecast An optimal resource portfolio cannot ignore the extrinsic value inherent in its resource choices. The 2013 IRP simulation compares each resource’s expected hourly output using forecasted Mid-Columbia hourly prices over 500 iterations of Monte Carlo-style scenario analysis. 5 Chart data is from the BPA at: http://transmission.bpa.gov/Business/Operations/Wind/default.aspx. 0% 20% 40% 60% 80% 100% 1 877 1,753 2,629 3,505 4,381 5,257 6,133 7,009 7,885 ca p a c i t y f a c t o r hours Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 149 of 1125 Chapter 7- Market Analysis Avista Corp 2013 Electric IRP Hourly zonal electricity prices are equal to either the operating cost of the marginal unit in the modeled zone, or the economic cost to generate and move power from one zone to another. A forecast of available future resources helps create an electricity market price projection. The IRP uses regional planning margins to set minimum capacity requirements rather than simply summing of the capacity needs of individual utilities in the region. This reflects the fact that Western regions can have resource surpluses even where individual utilities are deficit. This imbalance can be due in part to ownership of regional generation by independent power producers, and possible differences in planning methodologies used by utilities in the region. AURORAXMP assigns market values to each resource alternative available to the PRS, but the model does not itself select PRS resources. Several market price forecasts determine the value and volatility of a resource portfolio. As Avista does not know what will happen in the future, it relies on risk analyses to help determine an optimal resource strategy. Risk analysis uses several market price forecasts with assumptions differing from the expected case, or changes the underlying statistics of a study. The modeling splits alternate cases into stochastic and deterministic studies. A stochastic study uses Monte Carlo analysis to quantify the variability in future market prices. These analyses include 500 iterations of varying natural gas prices, loads, hydroelectric generation, thermal outages, and wind generation shapes. The IRP includes two stochastic studies—an Expected Case and a case with greenhouse gas emissions pricing. All remaining studies were deterministic; modifying one or more key input assumptions and using average values for the remaining variables. Mid-Columbia Price Forecast The Mid-Columbia is Avista’s primary electricity trading hub. The Western Interconnect also has trading hubs at the California/Oregon Border (COB), Four Corners (corner of northwestern New Mexico), Palo Verde (central Arizona), SP15 (southern California), NP15 (northern California) and Mead (southern Nevada). The Mid-Columbia market is usually the lowest cost because of the hubs dominant hydroelectric generation assets, though other markets can be less expensive when Rocky Mountain-area natural gas prices are low and natural gas-fired generation is setting marginal power prices. Fundamentals-based market analysis is critical to understanding the power industry environment. The Expected Case includes two studies. The first is a deterministic market view using expected levels for the key assumptions discussed in the first part of this chapter. The second is a risk or stochastic study with 500 unique scenarios based on different underlining assumptions for natural gas prices, load, wind generation, hydroelectric generation, forced outages, and others. Each study simulates the entire Western Interconnect hourly between 2014 and 2033. The analysis used 25 central processing units (CPUs) linked to a SQL server, creating over 45 GB of data in 3,000 CPU-hours. The stochastic market average prices are similar to the results from the deterministic model. Figure 7.13 shows the stochastic market price results as horizontal bars Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 150 of 1125 Chapter 7- Market Analysis Avista Corp 2013 Electric IRP represent the 10th to 90th percentile range for annual prices, the circle shows the average prices, while the triangle represents the 95th percentile. The 20-year nominal levelized price is $44.08 per MWh. The levelized deterministic price is $0.10 per MWh higher than the levelized stochastic price presented in Figure 7.14. Figure 7.13: Mid-Columbia Electric Price Forecast Range The annual averages of the stochastic case on-peak, off-peak, and levelized prices are in Table 7.10. Spreads between on- and off-peak prices average $9.76 per MWh over 20 years. The 2011 IRP annual average nominal price was $70.50 per MWh. The reduction in pricing is a result of lower natural gas prices, lower loads, higher percentages of new low-heat-rate natural gas plants, and the elimination of direct carbon pricing. $0 $20 $40 $60 $80 $100 $120 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 1 4 -33 do l l a r s p e r M W h Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 151 of 1125 Chapter 7- Market Analysis Avista Corp 2013 Electric IRP Table 7.10: Annual Average Mid-Columbia Electric Prices ($/MWh) Year Flat Off- Peak On- Peak 2014 31.02 25.63 35.18 2015 33.06 27.57 37.17 2016 33.91 28.52 37.93 2017 34.14 28.78 38.21 2018 36.18 30.90 40.16 2019 38.29 32.99 42.17 2020 41.34 36.15 45.06 2021 43.72 38.34 47.65 2022 46.06 40.49 50.04 2023 48.85 43.29 52.92 2024 49.52 43.78 53.64 2025 49.35 43.59 53.57 2026 52.04 46.31 56.16 2027 53.37 47.60 57.70 2028 55.65 49.77 59.79 2029 57.94 51.94 62.27 2030 61.39 55.12 66.06 2031 63.06 56.48 67.96 2032 65.65 59.02 70.57 2033 66.97 60.25 71.94 Levelized 44.08 38.46 48.22 Greenhouse Gas Emission Levels Greenhouse gas levels could increase over the study period absent regulatory policies reversing the trend. This IRP does not include a legislative mandate to reduce greenhouse gases in the Expected Case, such as a cap and trade program or a carbon tax. Rather the forecast includes cap-and-trade pricing in California and power plant shut downs due to EPA and state regulations. This IRP models the California and Canadian carbon laws. Further discussion of carbon policy is in Chapter 4, Policy Considerations. Figure 7.14 shows historic and expected greenhouse gas emissions for the Western Interconnect. Greenhouse gas emissions from electric generation decrease 10.8 percent between 2010 and 2033. The figure also includes the 10th and 90th percentile statistics from the 500-iteration dataset. The reduction drivers are a lower load forecast when compared to prior IRPs, lower natural gas prices, renewable portfolio standards, and forecasted coal-fired generation retirements. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 152 of 1125 Chapter 7- Market Analysis Avista Corp 2013 Electric IRP Figure 7.14: Western States Greenhouse Gas Emissions Resource Dispatch State-level RPS goals and greenhouse gas legislation changes resource dispatch decisions and affect future power prices. The Northwest already is witnessing the market-changing effects of more than an 8,500 MW wind fleet. Figure 7.15 illustrates how natural gas will increase its contribution as a percentage of Western Interconnect generation, from 24 percent in 2014 to 41 percent 2033. The increase offsets coal-fired generation; coal drops from 28 percent in 2014 to 15 percent in 2034. Utility-owned solar and wind increase from 8 percent in 2014 to 11 percent by 2033. New renewable generation sources also reduce coal generation, but natural gas is the primary resource meeting load growth. Public policy changes encouraging renewable energy development reduce greenhouse gas emissions, but they also change electricity marketplace fundamentals. On the present trajectory, policy changes are likely to move the generation fleet toward natural gas, with its currently low but historically volatile prices. These policies will displace low- cost coal-fired generation with higher-cost renewables and natural gas-fired generation having lower capacity factors (wind) and higher marginal costs (natural gas). If history is our guide, regulated utilities will recover their stranded coal plant investments from customers, requiring customers to pay more. Further, wholesale prices likely will increase with the effects of the changing resource dispatch driven by carbon emission limits and renewable generation integration. New environmental policy driven investments, combined with higher market prices, will necessarily lead to retail rates that are higher than they otherwise would be absent greenhouse gas reduction policies. 0 50 100 150 200 250 300 350 19 9 0 19 9 2 19 9 4 19 9 6 19 9 8 20 0 0 20 0 2 20 0 4 20 0 6 20 0 8 20 1 0 20 1 2 20 1 4 20 1 6 20 1 8 20 2 0 20 2 2 20 2 4 20 2 6 20 2 8 20 3 0 20 3 2 mi l l i o n m e t r i c t o n s C O 2 Historical Expected Case 10th Percentile 90th Percentile Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 153 of 1125 Chapter 7- Market Analysis Avista Corp 2013 Electric IRP Figure 7.15: Base Case Western Interconnect Resource Mix Scenario Analysis Scenario analysis evaluates the impact of specific changes in underlying assumptions on the market, Avista’s generation portfolio, and new generation resource options’ values. In addition to the Expected Case, a stochastic greenhouse gas reduction case was studied: the Carbon Pricing Scenario. The case is similar to the 2011 IRP Expected Case. In addition to stochastic market scenarios, deterministic scenarios explain the impacts of lower and higher natural gas prices and higher state RPS. Prior IRPs used market scenarios to stress test the PRS. Since the PRS accounts for a range of possible outcomes in its risk analysis, the market scenario section is more limited in this IRP. Additional scenarios illustrate impacts potential future policies might have on the industry, and how Avista could respond. No Coal Retirement Scenario The Expected Case price forecast includes speculative coal plant retirements based on how Avista understands state and federal environmental policies, and the effect on power generation in the Western Interconnect. The No Coal Retirement scenario models the impact coal retirements might have on market prices, greenhouse gas emissions, and the costs to meet customer load growth. In the event coal plants are not retired, the impact on wholesale power prices is minimal. The levelized prices of power over the 20-year period is $1.25 per MWh lower than the Expected Case (see Figure 7.16), with the largest annual price difference being 4.4 percent. Hydro NuclearOther Coal WindSolar Natural Gas 0 20 40 60 80 100 120 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 av e r a g e g i g a w a t t s Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 154 of 1125 Chapter 7- Market Analysis Avista Corp 2013 Electric IRP Figure 7.16: Mid-Columbia Prices Comparison with and without Coal Plant Retirements Figure 7.17 illustrates the difference between greenhouse gas emissions with and without the coal plant retirements. Based on the model results and assumptions, emissions would be nearly 9 percent higher in 2033 without the assumed coal plant retirements. The coal plant retirements due to regulations has a similar greenhouse gas reduction as a carbon tax or cap and trade scheme, but does not have a substantial impact on market prices. With forced earlier retirement, coal plant owners will face replacement costs up front rather the delayed until carbon prices make coal uneconomic. As regulations continue to force coal plants to improve their environmental footprint, lower compliance costs could take shape as engineers focus on solutions to meet stricter guidelines to reduce air emissions. The No Coal Retirement scenario allows an estimate of the short-term (20-year) cost of greenhouse gas reduction. This estimate takes into account the changes to the Western Interconnect resources’ fuel and variable O&M costs. The analysis also takes into account capital cost changes reflecting investments in new capacity and its associated fixed O&M costs. Based on cost changes and carbon emission reductions, the implied 2019-2033 levelized price paid to reduce carbon emissions is $95.33 per metric ton (2014$) for the Western Interconnect. $0 $10 $20 $30 $40 $50 $60 $70 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 do l l e r s p e r M W h No Coal Retirements Expected Case Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 155 of 1125 Chapter 7- Market Analysis Avista Corp 2013 Electric IRP Figure 7.17: Western U.S. Carbon Emissions Comparison Carbon Pricing Scenario In Avista’s recent IRPs, the Expected Case has included explicit costs for greenhouse gas emissions. The Expected Case in this IRP does not include these costs explicitly. The political climate in the last several IRPs was more amenable to national greenhouse gas policies. To understand the costs and ramifications of a national greenhouse gas reduction policy, this scenario quantifies the potential outcomes. It considers four potential carbon mitigation alternatives. Figure 7.18 shows each alternative modeled as a cap and trade mechanism. Figure 7.19 shows the levelized electric market price results of these alternatives compared to the Expected case. The levelized costs are not substantially higher than the Expected Case, as the levelization methodology discounts later periods where carbon policies are expected; therefore, levelization masks future higher market prices for utility customers. Figure 7.20 shows the annual expected greenhouse gas emissions levels for each of the policies. The four potential outcomes represent a range of futures under different forms of greenhouse gas emissions legislation. Over the last nine years of this study the weighted average levelized price is $22.36 per metric ton, the high case is $55.06 and the low case is $19.15 per metric ton. 0 50 100 150 200 250 300 350 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 mi l l i o n m e t r i c t o n s C O 2 Expected Case No Coal Retirements Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 156 of 1125 Chapter 7- Market Analysis Avista Corp 2013 Electric IRP Figure 7.18: Greenhouse Gas Pricing Scenarios Figure 7.19: Nominal Mid-Columbia Prices for Alternative Greenhouse Gas Policies $0 $10 $20 $30 $40 $50 $60 $70 $80 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 do l l a r s p e r m e t r i c t o n Weighted Average Expected Case 2020 High GHG Pricing Case 2020 Low GHG Pricing Case 2025 High GHG Pricing Case 2025 Low GHG Pricing Case $44.60 $42.93 $49.22 $52.00 $46.51 $56.99 $47.19 $0 $10 $20 $30 $40 $50 $60 $70 Expected Case No Coal Retirements Weighted Average 2025 High 2025 Low 2020 High 2020 Low Carbon Pricing Scenario Carbon Pricing Scenario Carbon Pricing Scenario Carbon Pricing Scenario Carbon Pricing Scenario do l l a r s p e r M W h Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 157 of 1125 Chapter 7- Market Analysis Avista Corp 2013 Electric IRP Figure 7.20: Annual Greenhouse Gas Emissions for Alternative Greenhouse Gas Policies High and Low Natural Gas Price Scenarios The high and low natural gas price scenarios provide important information about how a potential resource strategy might change if the natural gas prices vary substantially from the Expected Case. They also provide an overview of how the energy market behaves when natural gas prices vary. Over the past several years, as natural gas prices have fallen, certain resources, such as coal, are dispatching differently. For this IRP, Avista completed two natural gas pricing scenarios in addition to the stochastic cases. The stochastic cases’ 500 natural gas scenarios are considered a better method to consider the risk of price changes, but these two scenarios are useful in understanding the fundamental market changes. The high and low price scenarios assume prices either rise or decline up to 35 percent relative to the Expected Case over time. The Expected Case assumes a levelized price of $5.62 per dekatherm, while the high price scenario is $7.48. The low price scenario is $3.97 per dekatherm. Figure 7.21 shows the resultant annual prices. The electricity price forecast follows the general tendencies of the change in natural gas in Figure 7.22. Important to note, the implied market heat rate (IMHR) shown in Figure 7.23 changes significantly with natural gas prices. The IMHR divides natural gas prices by electric prices and is illustrative of the market point in which a heat rate of a natural gas facility is profitable. For example, the approximate heat rate of a CCCT is 7,000 Btu/kWh. Lower natural gas prices make operating gas plants more frequently a better option. - 50 100 150 200 250 300 350 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 mi l l i o n m e t r i c t o n s C O 2 Expected Case No Coal Retirements 2025 High GHG Pricing Case 2025 Low GHG Pricing Case 2020 High GHG Pricing Case 2020 Low GHG Pricing Case Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 158 of 1125 Chapter 7- Market Analysis Avista Corp 2013 Electric IRP Figure 7.21: Annual Natural Gas Price Forecast Scenarios Figure 7.22: Natural Gas Price Scenario’s Mid-Columbia Price Forecasts $0 $2 $4 $6 $8 $10 $12 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 do l l a r s p e r d e k a t h e r m Expected Case High Natural Gas Prices Low Natural Gas Prices $44.18 $55.97 $33.86 $0 $10 $20 $30 $40 $50 $60 Expected Case High Natural Gas Prices Low Natural Gas Prices do l l a r s p e r m e g a w a t t Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 159 of 1125 Chapter 7- Market Analysis Avista Corp 2013 Electric IRP Figure 7.23: Implied Market Heat Rate Changes Increased State Renewable Portfolio Standards Many western states have RPS requirements. As utilities reach their mandated levels of renewables, some states have increased the goals for reasons of further reducing energy risk, creating green jobs, and lowering carbon emissions. This scenario attempts to address the impact of RPS legislation on the Northwest energy market. If the only goal of the RPS is to lower carbon emissions, this method can be costly. This IRP does not attempt to address these costs for the existing RPS rules, but rather discusses what the costs and benefits are from additional rules. This scenario is speculative in many ways, such as from which states an increase in RPS levels will come from, and the type of technology used to meet the increased goals. For this analysis, the renewable requirement increases after 2025, and focuses on states where existing standards stop increasing in 2020. For example, this scenario assumes Washington state increases from 15 percent to 25 percent in 2025, and California’s increases from 33 percent to 50 percent by 2030. Other states’ increases include Colorado, Nevada, New Mexico, and Arizona. Solar will meet much of the need in states with increased requirements that have strong solar potential; additions beyond the current standard could strain existing transmission systems and produce low capacity factors. For this analysis, 7,000 MW of wind, 29,000 MW of solar and 1,000 MW of other renewable technology is added to meet the assumed higher standards of this scenario. The net added cost to the West for these assumed law changes is $120 billion (2012$). This compares to the estimated $17 billion spent on renewable energy investments in the Northwest to date.6 6This scenario assumes 8,500 MW of Northwest wind using an average cost of $2,000 per kW. 5,000 6,000 7,000 8,000 9,000 10,000 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 im p l i e d m a r k e t h e a t r a t e Expected Case High Natural Gas Prices Low Natural Gas Prices Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 160 of 1125 Chapter 7- Market Analysis Avista Corp 2013 Electric IRP The market and greenhouse gas reduction benefits of the increased RPS scenario are shown in Figure 7.24 for the years 2025 to 2033. As more solar and wind generation are added to the system wholesale market prices are expected to decline; this scenario shows wholesale price reductions of 3 percent to 4 percent. Overall system costs of the Western Interconnect will not fall due to the large investment levels. The added renewables reduce greenhouse gas emissions from the Expected Case by up to 9 percent toward the end of the study. As with the forced coal plant retirements in the Expected Case, an assumption included in this RPS scenario as well, the higher RPS results in an implied price for carbon. The implied cost of reduced carbon emissions for this increased RPS scenario is $198 per metric ton. For further information on this calculation, refer to the Expected Case analysis described on page 7.27. While added renewables can reduce fuel costs, the incremental investments in new renewable generation greatly overwhelms the fuel cost savings. Figure 7.24: Changes to Mid-Columbia Prices and Western US Greenhouse Gas Levels 0% 2% 4% 6% 8% 10% 2025 2026 2027 2028 2029 2030 2031 2032 2033 pe r c e n t r e d u c t i o n Reduction in Electric Market Prices Reduction in Greenhouse Gas Emissions Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 161 of 1125 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 162 of 1125 Chapter 8 – Preferred Resource Strategy Avista Corp 2013 Electric IRP 8-1 8. Preferred Resource Strategy Introduction The PRS chapter describes potential costs and financial risks of various resource acquisition strategies. Further, the chapter details planning and resource decision methods and strategies, the impact of climate change policies, and provides an overview of alternative resource strategies. The 2013 PRS describes a reasonable low-cost plan along the efficient frontier of potential resource portfolios accounting for fuel supply and price risks. Major changes from the 2011 plan include reduced energy efficiency, wind, and natural gas-fired fired resources and, for the first time, a modest contribution from demand response. The plan no longer calls for new renewable resources due to the recent acquisition of the 105 MW Palouse Wind Project and the recent law change allowing the Kettle Falls Generation Station to qualify for Washington’s EIA beginning in 2016. The strategy’s lower energy efficiency level is due to lower avoided costs, increased codes and standards supplanting the need for utility-sponsored acquisition, and rising implementation and verification costs associated with utility-sponsored energy efficiency programs. The reduction in natural gas-fired resources results primarily from a lower retail load forecast. Demand response is included because lower energy prices increase the value of resources providing on-peak capacity. Supply-Side Resource Acquisitions Avista began its shift away from coal-fired resources with the sale of its 210 MW share of the Centralia coal plant in 2000, and its replacement with natural gas-fired generation projects. See Figure 8.1. Since the Centralia sale, Avista has made several generation acquisitions and upgrades, including: 25 MW Boulder Park natural gas-fired reciprocating engines (2002); Section Highlights Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 163 of 1125 Chapter 8 – Preferred Resource Strategy Avista Corp 2013 Electric IRP 8-2 7 MW Kettle Falls gas-fired CT (2002); 35 MW Stateline wind power purchase agreement (2004); 56 MW (total) hydroelectric upgrades (through 2012); 270 MW natural gas-fired Lancaster Generation Station power purchase agreement (2010); and 105 MW Palouse Wind power purchase agreement (2012). Figure 8.1: Resource Acquisition History Resource Selection Process Avista uses several decision support systems to develop its resource strategy, including AURORAXMP and Avista’s PRiSM model. The AURORAXMP model, discussed in detail in the Market Analysis chapter, calculates the operating margin (value) of every resource option considered in each of the 500 Monte Carlo simulations of the Expected Case, as well as Avista’s existing portfolio of generation assets. The PRiSM model helps make resource decisions. Its objective is to meet resource deficits while accounting for overall cost, risk, capacity, energy, renewable energy requirements, and other constraints. PRiSM evaluates resource values by combining operating margins with capital and fixed operating costs. The model creates an efficient frontier of resources, or the least cost portfolios, given a certain level of risk and constraints. Avista’s management selects a resource strategy using this efficient frontier to meet all capacity, energy, RPS, and other requirements. PRiSM Avista staff developed the first version of its PRiSM model in 2002 to support resource decision making. PRiSM uses a linear programming routine to support complex decision 1,100 1,300 1,500 1,700 1,900 2,100 2,300 2,500 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 me g a w a t t c a p a c i t y Ra t h d r u m Ce n t r a l i a S a l e BP & K F C T 1/ 2 C S 2 St a t e l i n e Hydro Upgrades La n c a s t e r 1/ 2 C S 2 Pa l o u s e Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 164 of 1125 Chapter 8 – Preferred Resource Strategy Avista Corp 2013 Electric IRP 8-3 making with multiple objectives. Linear programming tools provide optimal values for variables, given system constraints. Overview of the PRiSM model The PRiSM model requires a number of inputs: 1. Expected future deficiencies o Greater of summer 1- or 18-hour capacity o Greater of winter 1- or 18-hour capacity o Annual energy o I-937 RPS requirements 2. Costs to serve future retail loads 3. Existing resource contributions o Operating margins o Fixed operating costs 4. Resource Options o Fixed operating costs o Return on capital o Interest expense o Taxes o Generation levels o Emission levels 5. Constraints o The level of Market reliance (surplus/deficit limits on energy, capacity and RPS) o Resources quantities available to meet future deficits PRiSM uses these inputs to develop an optimal resource mix over time at varying levels of risk. It weights the first twenty years more heavily than the later years to highlight the importance of nearer-term decisions. A simplified view of the PRiSM linear programming objective function is below. Equation 8.1: PRiSM Objective Function Minimize: (X1 * NPV2014-2033) + (X2 * NPV2014-2063) Where: X1 = Weight of net costs over the first 20 years (95 percent) X2 = Weight of net costs over the next 50 years (5 percent) NPV is the net present value of total system cost.1 An efficient frontier captures the optimal resource mix graphically given varying levels of cost and risk. Figure 8.2 illustrates the efficient frontier concept. As you attempt to lower risk, costs increase. The optimal point on the efficient frontier depends on the level of risk Avista and its customers are willing to accept. The best point on the curve could be 1 Total system cost is the existing resource marginal costs, all future resource fixed and variable costs, and all future energy efficiency costs and the net short-term market sales/purchases. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 165 of 1125 Chapter 8 – Preferred Resource Strategy Avista Corp 2013 Electric IRP 8-4 where you can make small incremental cost additions for large reductions in risk. Portfolios to the left of the curve would be more optimal, but do not meet the planning requirements or resource constraints. Examples of these constraints are environmental legislation cost, regulation, and the availability of commercially viable technologies greatly limit utility-scale resource options. Further, portfolios to the right of the curve are less efficient as they have higher costs than a portfolio with the same level of risk. The model does not meet deficits with market purchases, or allow the construction of resources in any incremental size.2 Instead, it uses market purchases to fill short-term gaps and “constructs” resources in block sizes equal to the project sizes Avista could build. Figure 8.2: Conceptual Efficient Frontier Curve Constraints As discussed earlier in this chapter, reflecting real-world constraints in the model is necessary to create a more realistic representation of the future. Some constraints are physical and others are societal. The major resource constraints are capacity and energy needs, Washington’s RPS, and greenhouse gas emissions performance standard. The PRiSM model selects from combined- and simple-cycle natural gas-fired combustion turbines, natural gas-fired reciprocating engines, wind, solar, storage batteries, carbon-sequestered coal, and upgrades to existing thermal and hydro resources. Energy efficiency is a fixed input derived from an iterative process of 2 Market reliance, as identified in Section 2, is determined prior to PRiSM’s optimization. ri s k cost Least Cost Least Risk Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 166 of 1125 Chapter 8 – Preferred Resource Strategy Avista Corp 2013 Electric IRP 8-5 developing avoided costs using PRiSM. Further, scenarios illustrate energy efficiencies’ impact on resource selections. Non-sequestered coal plants are not an option in this IRP because Washington’s emissions performance standard bans them.3 Washington’s EIA or RPS fundamentally changed how Avista meets future loads. Before the addition of an RPS obligation, the efficient frontier contained a least-cost strategy on one axis, the least-risk strategy on the other axis, and all of the points in between. Management used the efficient frontier to help determine where they wanted to be on the cost-risk continuum. The least cost strategy typically consisted of natural gas-fired peaking resources. Portfolios with less risk generally replaced some of the natural gas-fired peaking resources with wind generation, other renewables, combined cycle natural gas-fired plants, or coal-fired resources. Past IRPs identified resource strategies including all of these risk-reducing resources. Added environmental and legislative constraints reduce the ability of resource choices to positively impact future costs and/or risks, at least in the traditional sense, and the requirement to procure renewable generation resources previously were included only in lower-risk and higher- cost portfolios. Further, these laws increase customer costs by obligating the utility to pay for energy efficiency levels above their direct financial benefit. Resource Deficiencies Avista uses a single-hour and a three-day, 18-hour (6 hours each day), peak event methodology to measure resource adequacy. The three-day 18-hour, methodology assures our energy-limited hydro resources can meet a multiday extreme weather event. Avista considers the regional power surpluses consistent with the NPCC’s forecast, and does not plan to acquire long-term generation assets while the region is significantly surplus. Avista’s peak planning methodology includes operating reserves, regulation, load following, wind integration and a planning margin. Even with this planning methodology, Avista currently projects having adequate resources between owned and contractually controlled generation to meet physical energy and capacity needs until 2020.4 See Figure 8.3 for Avista’s physical resource positions for annual energy, summer capacity, and winter capacity. This figure accounts for the effects of new energy efficiency programs on the load forecast. Absent energy efficiency, Avista would be deficient earlier. Figure 8.3 illustrates short-term capacity needs in the winter of 2014/15 and 2015/16. This period is short-lived because a 150 MW capacity sale contract ends in 2016. Avista expects to address these short-term deficits with market purchases; therefore, the first long-term capacity deficit begins 2020. If Avista uses a similar planning margin in the summer as winter (14 percent plus reserves); Avista would be deficit in the summer of 2025. Given the region has a capacity surplus in the summer; 3 See RCW 80.80. 4 See Chapter 2 for further details on this peak planning methodology. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 167 of 1125 Chapter 8 – Preferred Resource Strategy Avista Corp 2013 Electric IRP 8-6 Avista will meet its ancillary service needs from its own portfolio, but rely on term purchases to meet other deficits. PRiSM selects new resources to fill capacity and energy deficits, although the model may over- or under-build where economics support it. Because of acquisitions driven by capacity RPS compliance, large energy surpluses result. Figure 8.3: Physical Resource Positions (Includes Energy Efficiency) Renewable Portfolio Standards Washington voters approved the EIA in the November 2006 general election. The EIA requires utilities with over 25,000 customers to meet 3 percent of retail load from qualified renewable resources by 2012, 9 percent by 2016, and 15 percent by 2020. The initiative also requires utilities to acquire all cost-effective energy efficiency and energy efficiency. Avista participates in the UTC’s Renewable Portfolio Standard Workgroup to help interpret application of this law. Avista expects to meet or exceed its EIA requirements through the 20-year plan with a combination of qualifying hydroelectric upgrades, the Palouse Wind project, the Kettle Falls Generating Station and selective REC purchases. A list of the qualifying generation projects and the associated expected output is in Table 8.1 below. The forecast REC positions are in Figure 8.4. The flexibility included in the EIA to use RECs from the current year, from the previous year, or from the following year for compliance helps mitigate year-to-year variability in the output of qualifying renewable resources. -600 -500 -400 -300 -200 -100 0 100 200 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 me g a w a t t s / a v e r a g e m e g a w a t t s January 1 Hour Peak (MW) August 18 Hour Peak (MW) Energy (aMW) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 168 of 1125 Chapter 8 – Preferred Resource Strategy Avista Corp 2013 Electric IRP 8-7 Table 8.1: Qualifying Washington EIA Resources Kettle Falls GS5 Biomass 1983 47.0 374,824 281,118 32.1 Long Lake 3 Hydro 1999 4.5 14,197 14,197 1.6 Little Falls 4 Hydro 2001 4.5 4,862 4,862 0.6 Cabinet Gorge 3 Hydro 2001 17.0 45,808 45,808 5.2 Cabinet Gorge 2 Hydro 2004 17.0 29,008 29,008 3.3 Cabinet Gorge 4 Hydro 2007 9.0 20,517 20,517 2.3 Wanapum Hydro 2008 0.0 22,206 22,206 2.5 Noxon Rapids 1 Hydro 2009 7.0 21,435 21,435 2.4 Noxon Rapids 2 Hydro 2010 7.0 7,709 7,709 0.9 Noxon Rapids 3 Hydro 2011 7.0 14,529 14,529 1.7 Noxon Rapids 4 Hydro 2012 7.0 12,024 12,024 1.4 Palouse Wind Wind 2012 105.0 349,726 419,671 47.9 Nine Mile 1 & 2 Hydro 2016 4.0 11,826 11,826 1.4 Figure 8.4: REC Requirements vs. Qualifying RECs for Washington State EIA 5 The Kettle Falls Generation Station becomes EIA qualified beginning in 2016. Clarification is required to determine the amount of energy to qualify for the law (75 percent qualifying is currently assumed). 0 20 40 60 80 100 120 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 av e r a g e m e g a w a t t s Qualifying Hydro Upgrades Qualifying Resources Purchased RECs Available Bank Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 169 of 1125 Chapter 8 – Preferred Resource Strategy Avista Corp 2013 Electric IRP 8-8 Preferred Resource Strategy The 2013 PRS consists of existing thermal resource upgrades, energy efficiency, demand response, and natural gas-fired simple- and combined-cycle gas turbines. A list of forecast acquisitions is in Table 8.2. The first resource acquisition is 83 MW of natural gas-fired peaking technology by the end of 2019. This resource acquisition fills the capacity deficit created by the expiration of the WNP-3 contract with the BPA (82 MW), the expiration of the Douglas County PUD contract for a portion of the Wells hydroelectric facility (28 MW) and load growth. In this IRP evaluation, frame technology SCCTs are preferred. Given the relatively small cost differences between the evaluated natural gas-fired peaker technologies, the ultimate technology selection will be made in a future RFP. Further, technological changes in efficiency and flexibility may mean the Avista will need to revisit this resource choice closer to the actual need. Since the need is six years out, Avista will not release an RFP in the next two years, but will begin a process to evaluate technologies, and potential site locations prior, to a RFP release, likely following the 2015 IRP. Table 8.2: 2013 Preferred Resource Strategy Resource By the End of Year Nameplate (MW) Energy (aMW) Simple Cycle CT 2019 83 76 Simple Cycle CT 2023 83 76 Combined Cycle CT 2026 270 248 Rathdrum CT Upgrade 2028 6 5 Simple Cycle CT 2032 50 46 Total 492 453 Efficiency Improvements Acquisition Range Peak Reduction Energy (aMW) Energy Efficiency 2014-2033 221 164 Demand Response 2022-2027 19 0 Distribution Efficiencies 2014-2017 <1 <1 Total 240 164 The next resource acquisition is another natural gas-fired peaking technology by the end of 2023. The 2019 acquisition could increase in size to accommodate the 2023 unit, or the 2019 site could be designed to add a second unit later. Given the length in time for this decision, more studies will occur in the next IRP. The proposed 270 MW CCCT is to replace the Lancaster tolling agreement expiring in October 2026. Avista could renegotiate the current PPA or find other mutual terms to retain the plant for customers. If Avista is not able to retain Lancaster generation, Avista would need to build or procure a similar-sized natural gas-fired unit. The new plant size could meet future load growth needs and could delay or eliminate the need for later two additional resource acquisitions in this plan. Due to the uncertainty surrounding replacing Lancaster, this IRP assumes the replacement is a new facility of similar size. As 2026 approaches, more information and costs will be known and discussed in future IRPs. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 170 of 1125 Chapter 8 – Preferred Resource Strategy Avista Corp 2013 Electric IRP 8-9 The 2013 PRS is significantly different from the 2011 IRP resource strategy. The 2011 PRS is in Table 8.3. Since the prior plan, Avista’s renewable and capacity needs have changed. First, the 2012 NW Wind need was met with the acquisition of the Palouse Wind PPA and its subsequent commercial operation date of December 2012. Changes in the EIA eliminated the 2019/2020 wind resource acquisition. The amendment under SB 5575 allows the Kettle Falls Generating Station and other legacy biomass resources to be counted as qualifying resources beginning in 2016. Previously, the EIA excluded Kettle Falls due to its age. Another significant change from the 2011 PRS is a lower load growth projection. Loads were expected to grow at 1.6 percent per year in the 2011 IRP. This IRP forecasts 1 percent growth (see Chapter 2, Loads and Resources). This change in load growth delays the first natural gas-fired resource acquisition by one year and eliminates the need for a CCCT in 2023. Table 8.3: 2011 Preferred Resource Strategy Resource By the End of Year Nameplate (MW) Energy (aMW) NW Wind 2012 120 35 Simple Cycle CT 2018 83 75 Existing Thermal Resource Upgrades 2019 4 3 NW Wind 2019-2020 120 35 Simple Cycle CT 2020 83 75 Combined Cycle CT 2023 270 237 Combined Cycle CT 2026 270 237 Simple Cycle CT 2029 46 42 Total 996 739 Efficiency Improvements Acquisition Range Peak Reduction (MW) Energy (aMW) Distribution Efficiencies 2012-2031 28 13 Energy Efficiency 2012-2031 419 310 Total 447 323 Energy Efficiency Energy efficiency is an integral part of the IRP analytical process. It also is a critical component of the EIA, where the law requires utilities to obtain all cost effective energy efficiency at below 110 percent of generation alternatives. Avista developed avoided energy costs and compared those figures against a energy efficiency supply curve developed by EnerNOC. The 20-year forecast of energy efficiency acquisitions is in Figure 8.5. Avista plans to acquire 77 aMW of energy efficiency over the next 10 years and 164 aMW over 20 years.6 These acquisitions will reduce system peak, shaving 104 MW from peak needs by 2023, and 221 MW by 2033. To illustrate the benefits of energy efficiency, the before and after load forecast is shown in Figure 8.6. Prior to energy efficiency, loads would increase at 1.7 percent per year; with energy efficiency loads growth at 1.07 percent per year. Energy efficiency reduces load growth by 43 6 Includes savings with system losses; at the customer’s meter savings are 154 aMW. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 171 of 1125 Chapter 8 – Preferred Resource Strategy Avista Corp 2013 Electric IRP 8-10 percent over the 20-year plan. Please refer to Chapter 3 for a more detailed discussion of energy efficiency resources. Figure 8.5: Energy Efficiency Annual Expected Acquisition Figure 8.6: Load Forecast with/without Energy Efficiency 0 20 40 60 80 100 120 140 160 180 0 2 4 6 8 10 12 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 av e r a g e m e g a w a t t s av e r a g e m e g a w a t t s Annual Cumulative 0 200 400 600 800 1,000 1,200 1,400 1,600 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 av e r a g e m e g a w a t t s Expected Case Without Conservation Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 172 of 1125 Chapter 8 – Preferred Resource Strategy Avista Corp 2013 Electric IRP 8-11 Demand Response For the first time in an Avista IRP, demand response is a selected resource option in the PRS. Demand response is selected beginning in 2022 and continuing through 2027. Demand response could also offset part of the 2019 simple cycle resource, depending on its achievable potential and the actual costs incurred to procure it. Demand response will likely come from industrial and commercial customers with flexible processes; given Avista’s limited experience with this resource, demand response research is included as an action item for the IRP. Distribution Feeder Upgrades Distribution feeder upgrades entered the PRS for the first time in the 2009 IRP. The upgrade process began with our Ninth and Central Streets feeder in Spokane. The decision to rebuild a feeder considers energy, operation and maintenance savings, the age of existing equipment, reliability indexes, and the number of customers on the feeder. The driver for pursuing a feeder rebuild generally is not energy savings, but rather system reliability. Since the 2011 IRP, several additional feeders were rebuilt. Avista plans to rebuild 13 feeders over the next four years. A broader discussion of our feeder rebuild program is in Chapter 5. Simple Cycle Combustion Turbines Avista plans to identify potential sites for new natural gas-fired generation capacity within its service territory ahead of an anticipated need. Avista’s service territory has areas with different combinations of benefits and costs. Locations in Washington have higher generation costs because of natural gas fuel taxes and carbon mitigation fees. However, there are other potential benefits of a Washington location, including proximity to natural gas pipelines and Avista’s transmission system, lower project elevations providing higher on-peak capacity contributions per investment dollar, and potential for water to cool the facility. In Idaho, lower taxes and fees decrease the cost of a potential facility, but fewer locations exist to site a facility near natural gas pipelines, fewer low cost transmission interconnection points are available, and fewer sites have available cooling water. The identification and procurement of a natural gas project site option will again be an action item for this IRP. Further siting factors for consideration include proximity to neighbors, environmental review, transmission access, pipeline access, elevation, and water availability. Avista is not specifying a preferred peaking technology until an RFP is completed. Given current assumptions, the resource strategy would select a Frame CT machine. Tradeoffs will occur between capital costs, operating efficiency and flexibility. Frame CT machines are a lower capital cost option, but have higher operating costs and less flexibility, while the hybrid technology has higher capital costs, lower operating costs, and more operational flexibility. Given the hours of operating, the lowest cost option is the less efficient and less flexible Frame CT. Increased flexibility requirements and greenhouse gas emissions costs could make a hybrid machine preferable. If Avista needs regulation or reserve capacity, a hybrid machine may be selected over the Frame CT if no other opportunities were available. If greenhouse gas reductions were identified as the only reason to choose hybrid technology, the emissions reductions would cost Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 173 of 1125 Chapter 8 – Preferred Resource Strategy Avista Corp 2013 Electric IRP 8-12 $147 per reduced metric ton of greenhouse gas emissions. The emissions reductions will not be realized by the owning utility, but rather the power system as a whole. If Avista selected hybrid technology over a Frame CT, the unit would run substantially more hours than the Frame CT causing utility emissions to increase, but regional emissions to slightly decrease because of the higher efficiency of the hybrid machine. Avista plans to study the tradeoffs of peaking technology in the next IRP. Greenhouse Gas Emissions Chapter 7, Market Analysis, discusses how greenhouse gas emissions decrease due to coal plant closures because of EPA and state regulations. Avista’s resource mix does not include any retirements due to current or proposed environmental regulations. The only significant lost resource with carbon emissions is the expiration of the Lancaster PPA in 2026, but it will be replaced to maintain system reliability and stabilize rates. Figure 8.7 presents Avista’s expected greenhouse gas emissions (excluding Kettle Falls Generating Station) with the addition of PRS resources. Emissions should not change significantly prior to 2019 other than from year-to-year fluctuations resulting from periodic maintenance outages, market fluctuations, and regional hydroelectric generation levels. Beginning in 2019 additional emissions will occur from new peaking resources, but these resources will not affect overall emissions levels much due to low projected runtime hours. The estimates in Figure 8.6 do not include emissions from purchased power or a reduction in emissions for off-system sales. Avista expects its greenhouse gas emissions intensity from owned and controlled generation to fall from 0.35 short tons per MWh to 0.32 short tons per MWh with the current resource mix and the new generation identified in the PRS. Figure 8.7: Avista Owned and Controlled Resource’s Greenhouse Gas Emissions 0.00 0.10 0.20 0.30 0.40 0.50 Mil 1 Mil 2 Mil 3 Mil 4 Mil 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 me t r i c t o n s p e r M W h me t r i c t o n s Total Tons per MWh of Load Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 174 of 1125 Chapter 8 – Preferred Resource Strategy Avista Corp 2013 Electric IRP 8-13 Capital Spending Requirements One of the major assumptions in this IRP is Avista will finance and own all new resources. Using this assumption, and the resources identified in the 2013 PRS, the first capital addition to rate base is in 2020 for the first natural gas-fired peaker. The development is likely to begin multiple years earlier but would likely enter rate base January 1, 2020. Avista may begin making major capital investments for the addition in 2017. The capital cash flows in Table 8.4 include AFUDC, transmission investments for generation, and account for tax incentives, and sales taxes. Over the 20-year IRP timeframe, a total of $782 million (nominal) in generation and related transmission expenditure is required to support the PRS. The capital investment projection does not include any capital to exercise the Palouse Wind PPA purchase option. Table 8.4: PRS Rate Base Additions from Capital Expenditures (Millions of Dollars) Year Investment Year Investment 2014 0.0 2024 91.6 2015 0.0 2025 0.0 2016 0.0 2026 0.0 2017 0.0 2027 421.7 2018 0.0 2028 97.0 2019 0.0 2029 2.4 2020 85.8 2030 0.0 2021 0.0 2031 0.0 2022 0.0 2032 0.0 2023 0.0 2033 83.6 2014-23 Total 85.8 2024-33 Totals 696.2 Annual Power Supply Expenses and Volatility PRS variance analysis tracks fuel, variable O&M, emissions, and market transaction costs for the existing resource portfolio for each of the 500 Monte Carlo iterations of the Expected Case risk analysis. In addition to existing portfolio costs, new resource capital, fuel, O&M, emissions, and other costs are tracked to provide a range of potential costs to serve future loads. Figure 8.8 shows expected PRS costs through 2033 as the blue bar (nominal dollars). In 2014, costs are expected to be $24 per MWh. The chart shows costs with a range of two sigma. The lower range is represented by yellow diamonds ($19 per MWh in 2014) and the upper range is shown with orange dots ($28 per MWh in 2014). The main driver increasing power supply costs and volatility in future years is natural gas prices and weather (hydro and load variability), Avista increases the volatility assumption of natural gas prices in the future as the commodity price has many unknown future risks and has a history of volatility. A common IRP question is what will be the change to power supply costs over the time horizon of the plan. Figure 8.9 shows total portfolio costs, but does not account for future load growth that would offset much of the increase as viewed from a customer bill Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 175 of 1125 Chapter 8 – Preferred Resource Strategy Avista Corp 2013 Electric IRP 8-14 perspective. Figure 8.9 illustrates expected PRS power supply cost changes compared to historical power supply costs, and provides a representation more correlated to future customer bills. Power supply costs, on a per-MWh basis, have increased 2.3 percent per year over inflation between 2002 and 2012. In the next 10 years power supply costs are forecast to fall from 2012 levels if expected energy prices come to fruition along with cost reductions from increased renewable energy credit sales, reduced energy efficiency costs, and consideration of 23 months of increased revenues from a power sale contract with Portland General Electric.7 Figure 8.8: Power Supply Expense Range 7 Since 1998, the capacity payments paid by Portland General Electric to Avista were monetized. Beginning February 2014, the capacity payments will be paid to Avista and reduce power supply costs. $0 $10 $20 $30 $40 $50 $60 $70 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 do l l a r s p e r M W h ( n o m i n a l ) Expected Cost Two Sigma Low Two Sigma High Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 176 of 1125 Chapter 8 – Preferred Resource Strategy Avista Corp 2013 Electric IRP 8-15 Figure 8.9: Real Power Supply Expected Rate Growth Index $/MWh (2012 = 100) Near Term Load and Resource Balance Under Washington regulation (WAC 480-107-15), utilities having supply deficits within three years of an IRP filing must file a RFP with the WUTC. The RFP is due to the WUTC no later than 135 days after the IRP filing. After WUTC approval, bids to meet the anticipated capacity shortfall must be solicited within 30 days. Tables 8.16 and 8.17, shown later in this section, detail Avista’s capacity position over the IRP timeframe. With a portion of loads met by Avista’s share of the regional capacity surplus, Avista does not require winter capacity until 2019. Simplified summaries for the near-term are displayed below in Tables 8.5 and 8.6. They show short-term capacity deficits met by market transactions in 2015 and 2016. Avista’s short positions are short lived as a 150 MW capacity sale to Portland General Electric expires at the end of 2016. As part of the IRP Action Items, Avista will develop a short-term capacity position report to monitor capacity requirements. 0 20 40 60 80 100 120 140 160 180 200 19 9 9 20 0 1 20 0 3 20 0 5 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 20 2 7 20 2 9 20 3 1 20 3 3 po w e r s u p p l y c o s t i n d e x Historical Forecast Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 177 of 1125 Chapter 8 – Preferred Resource Strategy Avista Corp 2013 Electric IRP 8-16 Table 8.5: Avista Medium-Term Winter Peak Hour Capacity Tabulation 2014 2015 2016 2017 Load Obligations 1,665 1,683 1,700 1,713 Other Firm Requirements 211 158 158 8 Reserves Planning 359 366 369 362 Total Obligations 2,235 2,206 2,227 2,084 Firm Power Purchases 117 117 117 117 Owned & Contracted Hydro 998 888 889 955 Thermal Resources 1,137 1,137 1,137 1,137 Wind (at Peak) 0 0 0 0 Total Resources 2,252 2,143 2,143 2,210 Net Position 17 -64 -84 126 Short Term Market Purchase 0 75 100 0 Net Position 17 11 16 126 Table 8.6: Avista Medium-Term Summer 18-Hour Sustained Peak Capacity Tabulation 2014 2015 2016 2017 Load Obligations 1,465 1,482 1,498 1,510 Other Firm Requirements 212 159 159 9 Reserves Planning8 0 0 0 0 Total Obligations 1,677 1,641 1,657 1,519 Firm Power Purchases 29 29 29 29 Owned & Contracted Hydro 701 707 663 631 Thermal Resources 961 961 961 961 Wind (at Peak) 0 0 0 0 Total Resources 1,691 1,698 1,653 1,621 Net Position 14 57 -3 102 Short Term Market Purchase 0 0 25 0 Net Position 14 57 22 102 Efficient Frontier Analysis Efficient frontier analysis is the backbone of the PRS. The PRiSM model develops the efficient frontier by simulating the costs and risks of resource portfolios using a mixed-integer linear program. PRiSM finds an optimized least cost portfolio for a full range of risk levels. The PRS analyses examined the following portfolios. 8 Due to the sustained peak planning methodology, hydroelectric capacity exceeding sustained maximum capability is used for operating and control area reserves. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 178 of 1125 Chapter 8 – Preferred Resource Strategy Avista Corp 2013 Electric IRP 8-17 Market Only: Meets all resource deficits with spot market purchases. The portfolio is least cost from a long-term financial perspective, but has the highest level of risk. The strategy fails to meet capacity, energy, and RPS requirements with Avista-controlled assets. Least Cost: Meets all capacity, energy and RPS requirements with the least-cost resource options. This portfolio ignores power supply expense volatility in favor of lowest-cost resources. Least Risk: Meets all capacity, energy and RPS requirements with the least-risk mix of resources. This portfolio ignores the overall cost of the selected portfolio in favor of minimizing portfolio volatility (risk). Efficient Frontier: Meets all capacity, energy and RPS requirements met with sets of intermediate portfolios between the least risk and least cost options. Given the resource assumptions, no resource portfolio can be at a better cost and risk combination than these portfolios. Preferred Resource Strategy: Meets all capacity, energy and RPS requirements while recognizing both the overall cost and risk inherent in the portfolio. Avista’s management chose this portfolio as the most reasonable path to follow given current information. Figure 8.10 presents the Efficient Frontier. The x-axis is the levelized nominal cost per year for the power supply portfolio, including capital recovery, operating costs, and fuel expense; the y-axis displays the standard deviation of power supply costs in 2028. The year 2028 is far enough out to account for the risk tradeoffs of several resource decisions. If a near term year was selected to measure risk, there would be too few new resource decisions available to distinguish between portfolios. It is necessary to move far enough into the future so load growth provides PRiSM the opportunity to make new resource decisions. By choosing a year later in the planning horizon, relevant resource decisions can be studied. Avista is not choosing to pursue the least cost strategy, as it relies exclusively on natural gas-fired peaking facilities. This strategy would include more market risk than exists in the portfolio today because the portfolio would trade the Lancaster (CCCT plant) for a SCCT. The PRS instead diversifies Avista’s resource mix with peaking and combined-cycle natural gas-fired plants. Further, based on an analysis of the efficient frontier, the additional cost of this strategy is near zero (0.1 percent) on an NPV basis and reduces market risk by 11 percent. Table 8.7 shows a sampling of portfolios along the efficient frontier with the costs, risks, and carbon emissions described. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 179 of 1125 Chapter 8 – Preferred Resource Strategy Avista Corp 2013 Electric IRP 8-18 Figure 8.10: Expected Case Efficient Frontier Table 8.7: Efficient Frontier Sample Resource Mixes Nameplate (MW) PRS Low Cost Medium High Risk Medium Risk Medium Low Risk Low Risk Combined Cycle CT 270 - 270 270 540 540 Natural Gas-Fired Peaker 299 566 296 216 100 68 Wind - - - 30 50 350 Solar - - - - - - Biomass - - - - - 50 Coal (sequestered) - - - - - - Hydro Upgrade - - - - - - Thermal Upgrade 6 6 6 85 85 80 Demand Response 19 20 20 8 12 17 Total (excluded efficiency) 594 592 592 609 788 1,104 Power Supply Revenue Requirement Cost Metrics (Millions) 20-yr Levelized Cost $358.4 $357.9 $357.9 $362.3 $367.0 $396.0 2028 Power Supply Std Dev $65.7 $74.0 $64.4 $60.5 $54.1 $40.2 2033 GHG Emissions (millions of metric tons) 3.2 2.9 3.4 3.4 3.9 3.8 $20 Mil $30 Mil $40 Mil $50 Mil $60 Mil $70 Mil $80 Mil $325 Mil $350 Mil $375 Mil $400 Mil $425 Mil $450 Mil 20 2 8 p o w e r s u p p l y c o s t s t d e v 20 yr levelized annual power supply rev. req. Market Only Least Cost Least Risk Preferred Resource Strategy Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 180 of 1125 Chapter 8 – Preferred Resource Strategy Avista Corp 2013 Electric IRP 8-19 Determining the Avoided Costs of Energy Efficiency The efficient frontier methodology determines the avoided cost of the new resource additions included in the PRS. There are two avoided cost calculations for this IRP: one for energy efficiency and one for new generation resources. The energy efficiency avoided cost is higher because it includes various benefits beyond generation resource value, as detailed in Table 8.8. Avoided Cost of Energy Efficiency Three portfolios are required to derive the supply-side cost components of the avoided cost for energy efficiency calculations. The differences between each portfolio sum to the avoided cost of energy efficiency: Commodity Energy (Market Only): This resource portfolio includes no new resource additions and the incremental cost of new power supply is the cost to buy power from the short-term market. These prices used are determined from the long-term energy price forecast discussed in Chapter 7. Capacity: This resource portfolio builds a least-cost strategy to meet peak demand. The difference between the Commodity Energy and Capacity strategies equals the capacity value of the new resources. This estimate typically shows the incremental cost divided by the incremental kilowatts of installed capacity. For this example the $/kW adder is translated to $/MWh assuming a flat energy delivery. Pre-Preferred Resource Strategy: This resource portfolio is similar to the PRS resource mix, but it assumes Avista does no further energy efficiency. The avoided cost of energy efficiency includes the various components of avoided cost only in those periods where Avista is deficit. For example, the avoided costs of energy efficiency programs only include a capacity value in the years where Avista has capacity needs. Further, the commodity component applies to each energy efficiency program depending on the expected timing of its energy delivery. For example, an air conditioning program receives an energy value based on expected savings in the summer months when actual energy savings occur. The EIA requires avoided costs used for energy efficiency to be increased by 10 percent to incent energy efficiency acquisition in the IRP. Additionally, reduced transmission and distribution losses, and operations and maintenance are credited in the avoided cost of energy efficiency. The following formula details the avoided cost for energy efficiency measures. Equation 8.2: Energy Efficiency Avoided Costs {(E + PC + R) + (E * L) + DC)} * (1 + P) Where: E = Market energy price. The price calculated with AURORAXMP is $44.08 per MWh. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 181 of 1125 Chapter 8 – Preferred Resource Strategy Avista Corp 2013 Electric IRP 8-20 PC = New resource capacity savings. This value is calculated using PRiSM and is estimated to be $11.74 per MWh. R = Risk premium to account for RPS and rate volatility reductions. This PRiSM-calculated value is $1.89 per MWh. P = Power Act preference premium. This is the additional 10 percent premium given as a preference towards energy efficiency measures. L = Transmission and distribution losses. This component is 6.1 percent based on Avista’s estimated system average losses. DC = Distribution capacity savings. This value is approximately $10/kW- year or $1.35 per MWh. Table 8.8 estimates the levelized avoided cost for a theoretical energy efficiency program reducing load by one megawatt each hour of the year: Table 8.8: Nominal Levelized Avoided Costs of the PRS ($/MWh) 2014-2033 Energy Forecast 44.08 Capacity Value 11.74 Risk Premium 1.89 Transmission & Distribution Losses 2.69 Distribution Capacity Savings 1.35 Power Act Premium 6.17 Total 67.92 Determining the Avoided Cost of New Generation Options Avoided costs change as new information becomes available, including changes to market prices, loads, and resources. Therefore, the estimates in Table 8.9 must be updated at the time a new resource is evaluated. Table 8.9 shows the avoided costs derived from the Preferred Resource Strategy. These prices represent the value of energy from a project making equal deliveries over the year in all hours. In this case, a new resource (such as PURPA qualifying project) would not qualify for capacity payments until 2020, because Avista does not need capacity resources until then. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 182 of 1125 Chapter 8 – Preferred Resource Strategy Avista Corp 2013 Electric IRP 8-21 Table 8.9: Updated Annual Avoided Costs ($/MWh) Year Energy Capacity Risk Total 2014 31.02 0.00 0.00 31.02 2015 33.06 0.00 0.00 33.06 2016 33.91 0.00 0.00 33.91 2017 34.14 0.00 0.00 34.14 2018 36.18 0.00 0.00 36.18 2019 38.29 0.00 0.00 38.29 2020 41.34 15.15 0.56 57.06 2021 43.72 15.77 0.59 60.08 2022 46.06 16.41 0.61 63.09 2023 48.85 17.08 0.64 66.57 2024 49.52 17.78 0.66 67.96 2025 49.35 18.50 0.69 68.54 2026 52.04 19.26 0.72 72.01 2027 53.37 20.04 0.75 74.16 2028 55.65 20.86 0.78 77.29 2029 57.94 21.71 0.81 80.46 2030 61.39 22.59 0.84 84.82 2031 63.06 23.51 0.87 87.44 2032 65.65 24.47 0.91 91.03 2033 66.97 25.47 0.95 93.38 Efficient Frontier Comparison of Greenhouse Gas Policies In addition to the stochastic Expected Case, Avista evaluated a National Climate Change policy scenario. Several hypothetical climate change policies are included in the 500 Monte Carlo market futures to capture the range of policy alternatives (see Chapter 7, Market Analysis for further detail). Given the higher market prices resulting from climate legislation, 20.5 aMW of additional energy efficiency would be acquired over the IRP period, a 12.5 percent increase. The cost of this incremental energy efficiency is 37 percent higher than in the Expected Case. Except for increased energy efficiency, the PRS under the National Climate Change policy remains similar to the Expected Case’s strategy. Somewhat surprisingly, this scenario increases the total resource build, but natural gas-fired frame peaking resources are replaced with hybrid CTs. This change reflects the increasing margin of lower heat rate machines. A detail of the Least Cost strategy, and the likely PRS, under a National Climate Change policy is in Table 8.10. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 183 of 1125 Chapter 8 – Preferred Resource Strategy Avista Corp 2013 Electric IRP 8-22 Table 8.10: Alternative PRS with National Climate Change Legislation Resource By the End of Year Nameplate (MW) Energy (aMW) Simple Cycle CT 2019 92 85 Simple Cycle CT 2024 92 85 Combined Cycle CT 2026 270 248 Rathdrum CT Upgrade 2024 6 5 Simple Cycle CT 2032 92 85 Total 552 508 Efficiency Improvements By the End of Year Peak Reduction Energy (aMW) Energy Efficiency 2014-2033 249 185 Demand Response 2022-2027 5 0 Distribution Efficiencies 2014-2017 <1 <1 Total 254 185 Figure 8.11 illustrates the efficient frontier in the Expected Case and a case with National Climate Change legislation. With climate change legislation, the cost curve moves to the right, showing increased customer costs. The curve also shows lower risk, because higher risk resources, such as frame CTs, are no longer the least cost resource. The most cost effective resource shifts from frame CTs to hybrid CTs. A carbon-pricing regime would also increase the amount of energy efficiency pursued by Avista. Figure 8.11 shows this efficient frontier in orange. The higher avoided cost of the national climate change policy increases the amount of energy efficiency, thereby reducing risk through lower loads, but with increased costs. The lesson learned from this scenario is the utility’s cost and financial risk increases. If climate policies were enacted, Avista likely would acquire more energy efficiency. This additional energy efficiency would reduce risk, but at overall higher costs. In reality, if this legislation is passed, a new portfolio would be developed to select resources better suited to a carbon-restricted environment; in this case, Frame CT’s are traded for hybrid CTs, lowering risk and lowering cost. Table 8.11 summarizes these cost and risk changes. Since Avista’s resource need is at the end of the decade, Avista is able to postpone its technology decision until closer to the time of need. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 184 of 1125 Chapter 8 – Preferred Resource Strategy Avista Corp 2013 Electric IRP 8-23 Figure 8.11: Efficient Frontier Comparison Table 8.11: Preferred Portfolio Cost and Risk Comparison (Millions $) Portfolio 20-Yr Power Supply Levelized Cost Expected Case Carbon Pricing Scenario PRS 358.4 367.3 PRS w/ Higher Efficiency 365.0 377.8 Climate Scenario- PRS 364.7 374.5 Portfolio 2028 Power Supply Cost Standard Deviation Expected Case Carbon Pricing Scenario PRS 65.7 72.6 PRS w/ Higher Efficiency 63.9 70.3 Climate Scenario- PRS 61.0 63.6 Energy Efficiency Scenarios Due to the complexities introduced by EIA, energy efficiency is not directly modeled in PRiSM. Instead, it is separately modeled using the avoided costs discussed above. Avista has found this method of determining energy efficiency investments is robust. $25 Mil $50 Mil $75 Mil $100 Mil $300 Mil $350 Mil $400 Mil $450 Mil $500 Mil 20 2 8 p o w e r s u p p l y s t d e v 20 yr levelized annual power supply rev. req. Expected Case Carbon Pricing Scenario Carbon Pricing Scenario (Inc Conservation) PRS (Expected Case) PRS-(Carbon Pricing) PRS-Higher Conservation (Carbon Pricing) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 185 of 1125 Chapter 8 – Preferred Resource Strategy Avista Corp 2013 Electric IRP 8-24 Refer to Figure 8.12 for an illustration of this point. This figure demonstrates the changes in risk and cost from the point of view of the PRS and the efficient frontier. Under current Washington rules, Avista must acquire all cost effective energy efficiency up to 110 percent of the avoided cost. Energy efficiency resources are oversubscribed compared to alternative generating resource options. To illustrate this concept, a portfolio acquiring energy efficiency up to 100 percent of avoided costs is shown as a “light blue dot”. This portfolio adds 154 aMW of energy efficiency (rather than the 168 aMW from the PRS shown as the “green diamond”). This portfolio illustrates power supply costs would be 2.7 percent lower and risk would be 0.3 percent higher if the utility could select this portfolio. This portfolio does not appear on the efficient frontier and is considered more optimal than any portfolio on the efficient frontier as it is to the left of the valid portfolio options, but is an invalid option due to the EIA requirement to over-invest in energy efficiency. A scenario acquiring energy efficiency to a level more consistent with its true contribution to the portfolio likely would lower costs. If Avista did not acquire any energy efficiency, total power supply costs and risks would increase. This portfolio, shown as a dark orange dot, is 8.6 percent more expensive than the PRS and has 20 percent more risk. This confirms energy efficiency is an effective tool to lower costs and risks, but must be properly balanced to achieve optimal benefits for customers. Three additional studies illustrating the effect of acquiring energy efficiency beyond 110 percent of cost effectiveness. These portfolios are shown as an orange dot for 125 percent of avoided costs and as a light orange dot for 150 percent of avoided cost in Figure 8.12. These options add 3.6 percent and 8.6 percent to the power supply costs and reduce volatility by 2.9 percent and 5.0 percent respectively. The light blue dot shows the 100 percent of avoided costs case. The efficient frontier illustrates these risk reductions are achievable at lower cost by acquiring generation instead of energy efficiency resources. Further information on the energy efficiency analysis is in Chapter 3, Energy Efficiency. Table 8.12 captures the resource selection of each of these portfolios, the costs, risks and carbon emissions. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 186 of 1125 Chapter 8 – Preferred Resource Strategy Avista Corp 2013 Electric IRP 8-25 Figure 8.12: Efficient Frontier Comparison Table 8.12: Preferred Portfolio Cost and Risk Comparison for Avoided Cost Studies Nameplate (MW) 75% 100% PRS 125% 150% 0% Combined Cycle CT 270 270 270 270 270 270 Natural Gas-Fired Peaker 313 316 299 271 228 481 Wind - - - - - - Solar - - - - - - Biomass - - - - - - Coal (sequestered) - - - - - - Hydro Upgrade - - - - - 68 Thermal Upgrade 6 - 6 6 6 - Energy Efficiency (aMW) 139 154 164 185 201 - Demand Response 20 19 19 20 20 20 Total 748 748 758 752 725 839 20-year Levelized Cost (millions) $346.1 $349.5 $354.8 $363.7 $371.3 $389.1 2028 Power Supply Stdev (millions) $67.7 $66.0 $65.7 $63.8 $62.4 $79.2 2033 Greenhouse Gas Emissions (millions of metric tons) 3.2 3.2 3.3 3.2 3.1 3.2 -70% -60% -50% -40% -30% -20% -10% 0% 10% 20% 30% -5%0%5%10%15%20%25% pe r c e n t c h a n g e f r o m P R S - ri s k percent change from PRS-cost Efficient FrontierPRS75% AC100% AC 125% AC 150% AC No Conservation Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 187 of 1125 Chapter 8 – Preferred Resource Strategy Avista Corp 2013 Electric IRP 8-26 Colstrip Coal-fired generation has been the target of increased regulatory and legal attention. Colstrip is a four unit coal-fired plant jointly owned by Avista, NorthWestern Energy, PacifiCorp, PPL- Montana, Portland General Electric, and Puget Sound Energy. Avista’s share of the plant is 15 percent of Units 3 and 4, or 222 MW. Units 3 and 4 are newer and larger technology than Units 1 and 2. Avista has no ownership interest in Units 1 or 2 at Colstrip. As part of the 2011 IRP acknowledgement, the UTC requested that Avista study two Colstrip scenarios. The first scenario is a cost and utility impact if Colstrip is not part of Avista’s resource portfolio. The second case examines the costs and utility impacts on Colstrip (Units 3 and 4) from additional environmental controls to meet potential new rules from the EPA. These portfolio scenarios are studied in the Expected Case and the Carbon Pricing scenarios. No Colstrip Resource Strategy Scenario In the scenario where Colstrip Units 3 and 4 are no longer resources for Avista customers, Colstrip exits the portfolio at the end of 2017. This case focuses on the costs and risk to replace its capacity and energy, not the revenues from a sale of the asset or the cost of reclamation. Table 8.13 shows an alternative PRS excluding Colstrip Units 3 and 4. The major difference between a portfolio with and without Colstrip is the addition of a CCCT to replace Colstrip Units 3 and 4 in 2017; the remaining portfolio is very similar to the Expected Case PRS. Table 8.13: No Colstrip Resource Strategy Scenario Resource By the End of Year Nameplate (MW) Energy (aMW) Combined Cycle CT 2017 270 248 Simple Cycle CT 2020 50 46 Simple Cycle CT 2023 50 46 Combined Cycle CT 2026 270 248 Simple Cycle CT 2026 51 47 Simple Cycle CT 2029 55 51 Simple Cycle CT 2032 50 46 Total 797 733 Efficiency Improvements By the End of Year Peak Reduction Energy (aMW) (MW) Energy Efficiency 2014-2033 221 164 Demand Response 2022-2027 20 0 Distribution Efficiencies 2014-2017 <1 <1 Total 241 164 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 188 of 1125 Chapter 8 – Preferred Resource Strategy Avista Corp 2013 Electric IRP 8-27 Removing Colstrip Units 3 and 4 from Avista’s resource portfolio has a large impact on portfolio costs. Figure 8.13 illustrates the cost impact. In the Expected Case, the present value of added cost is $505 million or $52.4 million per year levelized. This is 12.8 percent higher than the PRS (includes Avista’s Colstrip generation). Greenhouse gases decrease by 1.2 million short tons in 2018 and one million tons on average over the 16 years of the study, as shown in Figure 8.14.9 The average greenhouse gas reduction cost Avista customers is $45 per metric ton (levelized). Using the carbon-pricing scenario, levelized costs increase by $47.2 million or 10.9 percent per year. In any case evaluated, removing Colstrip Units 3 and 4 from Avista’s resource portfolio creates significantly higher customer costs. To understand the annual impact to power supply expense and risk, Figure 8.15 shows the Expected Case cost difference without Colstrip, and two-sigma tail risk. In the first year, Power Supply Costs are expected to be over $60 million higher than with the plant, and slowly fall as the substitute plant is depreciated. Another way to look at the increased costs without Colstrip Units 3 and 4 is in Figure 8.16. This figure shows the power supply cost index from earlier in this chapter and includes the no-Colstrip scenario. Figure 8.13: 2018-33 Power Supply Costs with and without Colstrip Units 3 and 4 9 This figure does not include the carbon neutral emissions from Kettle Falls. $482 $435 $460 $408 $0 Mil $100 Mil $200 Mil $300 Mil $400 Mil $500 Mil $600 Mil Carbon Pricing Scenario-RS w/o Colstrip Carbon Pricing Scenario-LC RS w/ Colstrip Expected Case-No Colstrip RS Expected Case-PRS le v e l i z e d p o w e r s u p p l y c o s t Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 189 of 1125 Chapter 8 – Preferred Resource Strategy Avista Corp 2013 Electric IRP 8-28 Figure 8.14: Greenhouse Gas Emissions without Colstrip Units 3 and 4 Figure 8.15: Change to Power Supply Cost without Colstrip - 0.10 0.20 0.30 0.40 0.50 Mil 1 Mil 2 Mil 3 Mil 4 Mil 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 me t r i c t o n s p e r M W h me t r i c t o n s Colstrip Reduction Other Resources Tons per MWh (Without Colstrip) Tons per MWh with Colstrip $0 $10 $20 $30 $40 $50 $60 $70 $80 $90 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 Ch a n g e t o A n n u a l P o w e r S u p p l y Ex p e n s e Expected Case Expected Case (Two Sigma Risk) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 190 of 1125 Chapter 8 – Preferred Resource Strategy Avista Corp 2013 Electric IRP 8-29 Figure 8.16: Change to Power Supply Cost without Colstrip Environmental Control Review There are potential costly regulations Colstrip Units 3 and 4 could face over the next 20 years of this resource plan if state or federal agencies promulgate new coal-fired generation environmental regulations. This section identifies anticipated regulations the EPA could establish over the time horizon of this plan based on information available during the development of this plan. The President’s Climate Action Plan was released after the analysis for this IRP was completed, but details about the plan are in Chapter 4, Policy Considerations. Avista will monitor and review implications of the plan as they develop. This discussion is speculative unless otherwise noted and only pertain to Colstrip Units 3 and 4. The following section discusses four main areas of possible new environmental regulations. Hazardous Air Pollutants MATS is for the coal and oil-fired source category. For Colstrip Units 3 and 4, existing emission control systems should be sufficient to meet MATS limitations. Coal Ash Management/Disposal Avista does not anticipate a significant change in operation at Colstrip Units 3 and 4 due to coal ash management or disposal issues at this time. 0 20 40 60 80 100 120 140 160 180 200 19 9 9 20 0 1 20 0 3 20 0 5 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 20 2 7 20 2 9 20 3 1 20 3 3 po w e r s u p p l y c o s t i n d e x Historical Forecast Forecast without Colstrip Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 191 of 1125 Chapter 8 – Preferred Resource Strategy Avista Corp 2013 Electric IRP 8-30 Effluent Discharge Guidelines Avista does not anticipate a significant change in operation at Colstrip Units 3 and 4 due to coal ash management or disposal issues at this time because it is a zero discharge facility managing wastewater onsite. Regional Haze Program Colstrip Units 3 and 4 will be evaluated for reasonable progress on approximately 10- year intervals going forward. Avista anticipates Nitrous Oxides (NOX) emission controls could be required in 2027. The cost to comply with this potential regulation is unknown due to technology changes potentially on the horizon to reduce NOX emissions. In order to understand this regulation if imposed on Colstrip Units 3 and 4 using existing technology, a study was completed and submitted to EPA in 2010. This study evaluates whether or not the cost of installing this existing technology would have an impact on the ongoing operations of the Colstrip Units 3 and 4. The study estimated the cost of a SCR NOX control to be $280 million per unit (2011 dollars); Avista chose to increase these estimates by 25 percent to account for potential retrofit costs. Further, Avista believes these control costs are on the high end of the cost range. In this case, Avista’s share of this cost for both units would be $105 million in capital, and about $560,000 in annual O&M (2014$). Over the life of this technology, the levelized cost of the controls is $8.39 per MWh (2014 dollars nominal). Further analysis is in Figure 8.17. This chart illustrates three scenarios for the two market price forecasts (Expected Case and Carbon Pricing Scenario). The results shown in the Expected Case’s removal of Colstrip Units 3 and 4 from the portfolio adds $34 million or (6.1 percent) to power supply costs compared to installing the SCR controls scenario. In the Carbon Pricing Scenario, $25 million per year is added or 4.3 percent per year without Colstrip Units 3 and 4 compared to installing the SCR. Based on this study using high cost to comply with potential regional haze regulation costs, Colstrip Units 3 and 4 remain a viable and cost-effective resource for Avista’s customers. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 192 of 1125 Chapter 8 – Preferred Resource Strategy Avista Corp 2013 Electric IRP 8-31 Figure 8.17: Annual Levelized Cost (2027-33) of Colstrip Scenarios Other Portfolio Scenarios Avista examined a number of possible policy outcomes affecting future resource selection. These scenarios review how Avista’s resource strategy might change in response to new policies Higher Washington RPS Avista’s current resource mix fully meets the EIA, but it is possible new legislation or a citizen’s initiative could increase the renewable goals further. This scenario contemplates this change to understand the resulting cost, risk, and emissions impacts. The scenario assumes an additional step in the renewable goal of 25 percent of Washington retail sales to be from qualified renewables. Such a goal would require Avista to add 77 aMW of qualified renewables beyond the present plan. The PRiSM model found the most cost-effective method to meet this requirement, with a similar risk profile to the PRS would be Spokane River hydroelectric upgrades. Both Long Lake (68 MW) and Monroe Street (55 MW) second powerhouse additions would meet the renewable requirement if they were certified as EIA-qualifying resources. The addition of these upgrades would prevent the final natural gas peaking resource from being required in the PRS. While the 20-year levelized cost is slightly higher than the PRS, the costs between 2025 and 2033 are $18 million levelized higher, or 3.5 percent. $549 $574 $608 $587 $612 $637 $400 Mil $500 Mil $600 Mil $700 Mil PRS PRS_SCR No Colstrip LC LC_SCR No Colstrip Expected Case Expected Case Expected Case Carbon Pricing Scenario Carbon Pricing Scenario Carbon Pricing Scenario le v e l i z e d c o s t Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 193 of 1125 Chapter 8 – Preferred Resource Strategy Avista Corp 2013 Electric IRP 8-32 National RPS Over the past several years, several bills have proposed national RPS legislation. This legislation has not been enacted, but is a potential future scenario to understand. Differences in the proposals have ranged from the type of resources qualifying for the RPS, percentages and timing of renewables required, and hydroelectric netting.10 For the National RPS scenario, Avista assumes a 20 percent renewable standard with hydroelectric generation (existing or new) netted from load. Given these assumptions, 78 aMW of renewables would be required by the end of this plan. The hydro netting provision would have an impact on how Avista would meet this potential law. As shown in the higher Washington RPS scenario hydro upgrades were selected in the national RPS scenario. If the hydro netting provision counted hydro upgrades as a load reduction rather than a qualifying renewable resource, the hydro upgrades would need to be replaced by new wind generation. Higher Capacity Planning Margins This IRP uses a 14 percent planning margin (plus operating reserves) above the winter peak load forecast. Planning margins are not necessarily a precise target and there is no universally accepted standard. To increase reliability, and to protect Avista’s customers from the potential of regional power shortages, a higher planning margin standard could be implemented. This scenario increases the planning margin to 20 percent, or an additional 117 MW by the end of plan. In addition to requiring more capacity on the planning horizon, Avista’s first-year deficit would occur earlier in 2016. 2011 IRP Preferred Resource Strategy This scenario illustrates the impacts of changes since the 2011 IRP. Since then, load growth has fallen from 1.6 percent to 1.0 percent per year, reducing Avista’s need for new capacity. In addition to load growth changes, the Washington RPS was amended to include Kettle Falls and other legacy biomass projects as a qualifying renewable resource beginning in 2016. These changes eliminate the need for new resources following Avista’s recent acquisition of output from the Palouse Wind project. 10 Hydroelectric netting subtracts a utility’s hydroelectric generation from the amount of load that the utility would have their RPS based on. For example, a utility with 1,000,000 MWh of load and 300,000 MWh of hydroelectric generation would only have an RPS requirement based on 700,000 MWh of load. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 194 of 1125 Chapter 8 – Preferred Resource Strategy Avista Corp 2013 Electric IRP 8-33 Table 8.14: Policy Portfolio Scenarios Nameplate (MW) PRS Higher WA St. RPS National RPS Higher Capacity Margins 2011 PRS CCCT 270 270 270 270 540 Natural Gas-Fired Peaker 299 249 296 435 187 Wind - - 203 - 120 Solar - - - - - Biomass - - - - - Coal (sequestered) - - - - - Hydro Upgrade - 148 - - - Thermal Upgrade 6 6 6 6 - Demand Response 19 10 20 8 - Total 594 683 795 718 847 20-year Levelized Cost (millions) $354.8 $360.3 $365.3 $364.2 $373.9 2028 Power Supply Stdev (millions) $65.7 $64.8 $63.6 $65.8 $54.0 2033 Greenhouse Gas Emissions (millions of metric tons) 3.2 3.2 3.3 3.4 3.7 Resource Tipping Point Analysis In many resource plans, a PRS is presented with a comparison to other portfolios to help illustrate cost and risk trade-offs. This IRP extends the portfolio analysis beyond this exercise by focusing on how the portfolio might change if key assumptions changed. This section identifies assumptions that could alter the PRS, such as changes to load growth, varying resource capital costs, the emergence of other non-wind and non-solar renewable options, or an expansion of the region’s nuclear generation fleet. Solar Capital Costs Sensitivity For the past several years, photovoltaic solar generation costs have decreased and more solar generation installed. Solar has benefited from the federal 30 percent ITC, accelerated depreciation, and lucrative state incentives. Solar price decreases have allowed the technology (with government subsidies) to be cost effective compared with retail utility rates in some parts of the western US. After a review of solar potential in the Northwest, and the needs of our system, solar is not a good fit. As discussed throughout this document, Avista and the Northwest require new capacity for winter peak periods. Avista (and the region) experience winter peaks between 6:00 am and 8:00 am or between 5:00 pm and 6:00 pm. In December and January, the months most likely for a peak to occur, these hours have very little or no sunlight. Adding solar to Avista’s resource mix will not delay or remove the need for other resource options. Solar costs would have to fall by a further 88 percent to be cost effective compared to other options. Nuclear Capital Cost Sensitivity Nuclear power has made a small resurgence on the U.S. energy-planning horizon, with several large East Coast utilities planning construction of the multi-billion dollar projects. Nuclear’s resurgence is driven by a search for low greenhouse gas emitting base-load Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 195 of 1125 Chapter 8 – Preferred Resource Strategy Avista Corp 2013 Electric IRP 8-34 power. Avista is not large enough, nor does Avista have the load requirements, to construct a large-scale nuclear plant. It is possible that a group of utilities could co-develop a large project, but the failure of the past regional attempt in the 1980s makes that option unlikely. New research has begun on smaller scale nuclear facilities to make the technology more readily available to smaller utilities. This sensitivity study reduces nuclear capital costs until it was picked as a resource in the PRiSM model. Selection by PRiSM indicates lower cost than other options. The model selected nuclear when its capital costs decreased by 70 percent. IGCC Coal with Sequestration Capital Cost Sensitivity Like nuclear facilities, much attention has been given to coal gasification along with the sequestration of CO2 emissions. Also like nuclear power, this technology is expensive, has long lead times, and requires large project scale. The plant is beyond Avista’s needs, but a group of utilities could jointly develop a sequestered coal plant. In order to be selected by the PRiSM model, and compete economically with other options, sequestered IGCC capital costs would need to decrease 87 percent from present estimates. Like nuclear plants, the technology has high O&M costs. The O&M costs are nearly as much as the total cost of natural gas CTs including fuel. Load Forecast Alternatives An important test in an IRP is to understand how the plan should change with alternative load growth sensitivities. Since Avista’s first new resource need is not until the end of 2019, Avista has time to change its resource needs if loads grow faster or slower than predicted. In order to be nimble Avista must have resource options available to quickly add capacity. Three different resource positions based on varying load growth scenarios, along with the Expected Case, are shown below in Figure 8.18. Chapter 2 discusses the economic drivers of these forecasts. The Low Load Growth scenario changes Avista’s first deficit year, but the High caseload Growth scenario increases the need from 42 MW to 88 MW. The Low Load Growth and the Medium Load Growth cases push the need to 2024 or 2022 respectively. Toward the end of the plan, the range in resource need is 267 MW between the High and Low Load Growth cases. Table 8.15 shows the generation resource strategies meeting the load growth alternatives. These strategies are designed to have similar resource portfolios and risk levels as the PRS. Energy efficiency levels also change, reflecting the expected achievable cost effective levels given the changes to new construction assumed in the load forecast scenarios. Energy efficiency levels will differ depending on the amount of existing structures versus new structures, because new structures are built with more efficient building codes. Energy efficiency for existing structures should remain relatively unchanged, but as economic activity changes, the amount of energy efficiency from new construction will vary. Since 87 percent of energy efficiency is from existing structures, the levels of energy efficiency in the Low Load to High Load Growth forecasts do not materially change. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 196 of 1125 Chapter 8 – Preferred Resource Strategy Avista Corp 2013 Electric IRP 8-35 Figure 8.18: Load Growth Scenario’s Cost/Risk Comparison Table 8.15: Load Growth Sensitivities Year PRS Low Load Growth Medium Low Load Growth High Load Growth 2019 83 MW SCCT 150 MW SCCT 2020 2021 2022 6 MW Upgrade 92 MW SCCT 2023 83 MW SCCT 90 MW SCCT 2024 2025 2026 270 MW CCCT 270 MW CCCT 270 MW CCCT 270 MW CCCT 2027 50 MW SCCT 92 MW SCCT 2028 6 MW Upgrade 2029 6 MW Upgrade 50 MW SCCT 2030 2031 2032 2033 50 MW SCCT 50 MW SCCT Demand Res. (MW) 19 1 20 20 Efficiency (aMW) 164 142 147 175 (900) (600) (300) - 300 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 me g a w a t t s Low Growth Medium Low Growth Expected Case High Growth Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 197 of 1125 Chapter 8 – Preferred Resource Strategy Avista Corp 2013 Electric IRP 8-36 Resource-Specific Scenarios As part of an IRP, resource specific scenarios are helpful to gain understanding of specific resource decisions. This section covers four resource specific scenarios. This exercise illustrates the changes in cost and risk with selective resource decision making. The scenarios evaluate different resource decision such as more renewables, or switching from CTs to CCCTs. Figure 8.19 shows the results of the four scenarios outlined below 200 MW Wind and CTs: 200 MW of new wind is added to the portfolio, 100 MW in 2020 and another 100 MW in 2025. This scenario meets capacity needs with Frame CT’s and Demand Response. In the case, costs are 5.5 percent higher and risk 5 percent higher than the PRS. Further, this portfolio lays to the right of the efficient frontier indicating there are more optimal portfolios to meet capacity objectives. 200 MW Solar and CTs: 10 MW of solar is added each year totaling 200 MW over the 20-year planning horizon. Since solar does not provide any capacity benefit to Avista in the winter, Frame CT’s are added along with a demand response to meet capacity needs. This scenario results in power supply costs 8 percent higher and risk is 8.5 percent higher Hydro Upgrades and CTs: The Spokane River hydro upgrades (Post Falls, Monroe Street 2, and Long Lake 2) and Cabinet Gorge upgrades are included in this scenario beginning in 2024 and adding an upgrade each year through 2027. This scenario also fills in remaining capacity needs with CT’s, in this portfolio costs and risks are also increased as compared to the PRS. Costs are 5 percent higher and risk is 13 percent higher. Two CCCTs: The first capacity need in 2019 replaces the SCCT with a CCCT, creating a short-term resource surplus. This scenario then uses another CCCT in 2027 to replace Lancaster (similar to the PRS). The portfolio is on the efficient frontier and reduces power supply volatility. This case lowers risk by 13 percent, but costs increase 2 percent. An RFP would evaluate this portfolio option prior to selecting a new resource in 2020. The risk is higher in all renewable scenarios, compared to the PRS, because of increased dependence on the energy market. The PRS includes a combination of CCCT and CT plants. CCCT plants reduce market risk as hedges against short-term market shortages. Figure 8.19 shows that the combination of CTs and renewable resources do not outperform the PRS from a risk measure, this illustrates the CCCT plan reduces market risk more than renewables. Renewables help lower risk, this is shown by comparing the portfolio point to the upper most black dot (CT only portfolio). Renewables do not significantly reduce risk because all of the energy is excess to load needs and the energy is sold on the market, where as the CCCT plant is used to meet capacity and energy needs. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 198 of 1125 Chapter 8 – Preferred Resource Strategy Avista Corp 2013 Electric IRP 8-37 Figure 8.19: Resource Specific Scenarios -60% -50% -40% -30% -20% -10% 0% 10% 20% -5%0%5%10%15%20%25% pe r c e n t c h a n g e f r o m P R S - ri s k percent change from PRS-cost Efficient Frontier PRS 200 MW Wind (CT) 200 MW Solar (CT) Hydro Upgrades (CT) Two CCCTs Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 199 of 1125 Chapter 8 – Preferred Resource Strategy Avista Corp 2013 Electric IRP 8-38 Table 8.16: Winter 1 Hour Capacity Position (MW) with New Resources 20 1 4 2 0 1 5 2 0 1 6 2 0 1 7 2 0 1 8 2 0 1 9 2 0 2 0 2 0 2 1 2 0 2 2 2 0 2 3 2 0 2 4 2 0 2 5 2 0 2 6 2 0 2 7 2 0 2 8 2 0 2 9 2 0 3 0 2 0 3 1 2 0 3 2 2 0 3 3 TO T A L L O A D O B L I G A T I O N S Na t i v e L o a d F o r e c a s t 1,6 7 3 1 , 6 9 9 1 , 7 2 7 1 , 7 5 3 1 , 7 8 0 1 , 8 0 9 1 , 8 3 0 1 , 8 5 3 1 , 8 7 8 1 , 9 0 1 1 , 9 2 4 1 , 9 5 1 1 , 9 7 8 2 , 0 0 4 2 , 0 3 1 2 , 0 5 6 2 , 0 8 2 2 , 1 0 9 2 , 1 3 9 2 , 1 7 0 Co n s e r v a t i o n F o r e c a s t 8 16 2 7 3 9 5 3 6 8 7 5 8 4 9 5 1 0 4 1 1 2 1 2 4 1 3 6 1 4 8 1 6 0 1 7 0 1 8 0 1 9 2 2 0 6 2 2 1 Ne t N a t i v e L o a d F o r e c a s t 1,6 6 5 1 , 6 8 3 1 , 7 0 0 1 , 7 1 3 1 , 7 2 7 1 , 7 4 1 1 , 7 5 5 1 , 7 6 9 1 , 7 8 3 1 , 7 9 8 1 , 8 1 2 1 , 8 2 7 1 , 8 4 2 1 , 8 5 6 1 , 8 7 1 1 , 8 8 7 1 , 9 0 2 1 , 9 1 7 1 , 9 3 3 1 , 9 4 8 Fi r m P o w e r S a l e s 21 1 1 5 8 1 5 8 8 8 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 To t a l R e q u i r e m e n t s 1,8 7 5 1 , 8 4 1 1 , 8 5 7 1 , 7 2 1 1 , 7 3 5 1 , 7 4 7 1 , 7 6 1 1 , 7 7 5 1 , 7 8 9 1 , 8 0 4 1 , 8 1 8 1 , 8 3 3 1 , 8 4 8 1 , 8 6 3 1 , 8 7 8 1 , 8 9 3 1 , 9 0 8 1 , 9 2 3 1 , 9 3 9 1 , 9 5 4 RE S O U R C E S Fi r m P o w e r P u r c h a s e s 11 7 1 1 7 1 1 7 1 1 7 1 1 7 1 1 6 3 4 3 4 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 Hy d r o R e s o u r c e s 99 8 8 8 8 8 8 9 9 5 5 9 5 5 9 1 9 9 2 4 9 2 0 9 2 0 9 2 8 9 2 0 9 2 0 9 2 8 9 2 0 9 2 0 9 2 8 9 2 0 9 2 0 9 2 8 9 2 0 Ba s e L o a d T h e r m a l s 89 5 8 9 5 8 9 5 8 9 5 8 9 5 8 9 5 8 9 5 8 9 5 8 9 5 8 9 5 8 9 5 8 9 5 8 9 5 6 1 7 6 1 7 6 1 7 6 1 7 6 1 7 6 1 7 6 1 7 Win d R e s o u r c e s 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Pe a k i n g U n i t s 24 2 2 4 2 2 4 2 2 4 2 2 4 2 2 4 2 2 4 2 2 4 2 2 4 2 2 4 2 2 4 2 2 4 2 2 4 2 2 4 2 2 4 2 2 4 2 2 4 2 2 4 2 2 4 2 2 4 2 To t a l R e s o u r c e s 2,2 5 2 2 , 1 4 3 2 , 1 4 3 2 , 2 1 0 2 , 2 1 0 2 , 1 7 2 2 , 0 9 5 2 , 0 9 1 2 , 0 9 1 2 , 0 9 8 2 , 0 9 0 2 , 0 9 0 2 , 0 9 8 1 , 8 1 1 1 , 8 1 1 1 , 8 1 9 1 , 8 1 1 1 , 8 1 1 1 , 8 1 9 1 , 8 1 1 Pe a k P o s i t i o n B e f o r e R e s e r v e P l a n n i n g 37 7 3 0 2 2 8 6 4 8 9 4 7 5 4 2 5 3 3 4 3 1 6 3 0 1 2 9 4 2 7 2 2 5 7 2 5 0 -5 1 - 6 6 - 7 4 - 9 7 - 1 1 2 - 1 2 0 - 1 4 3 RE S E R V E P L A N N I N G Pla n n i n g M a r g i n -2 3 3 - 2 3 6 - 2 3 8 - 2 4 0 - 2 4 2 - 2 4 4 - 2 4 6 - 2 4 8 - 2 5 0 - 2 5 2 - 2 5 4 - 2 5 6 - 2 5 8 - 2 6 0 - 2 6 2 - 2 6 4 - 2 6 6 - 2 6 8 - 2 7 1 - 2 7 3 To t a l A n c i l l a r y S e r v i c e s R e q u i r e d -1 3 9 - 1 3 6 - 1 3 7 - 1 2 8 - 1 2 9 - 1 3 1 - 1 3 6 - 1 3 7 - 1 3 8 - 1 3 9 - 1 4 1 - 1 4 2 - 1 4 3 - 1 3 9 - 1 3 9 - 1 4 0 - 1 4 0 - 1 4 0 - 1 4 0 - 1 4 0 Re s e r v e & C o n t i n g e n c y A v a i l a b i l i t y m e t b y H y d r o 13 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 De m a n d R e s p o n s e 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 To t a l R e s e r v e P l a n n i n g -3 5 9 - 3 6 6 - 3 6 9 - 3 6 2 - 3 6 6 - 3 6 9 - 3 7 6 - 3 7 9 - 3 8 2 - 3 8 6 - 3 8 9 - 3 9 2 - 3 9 5 - 3 9 3 - 3 9 6 - 3 9 8 - 4 0 0 - 4 0 3 - 4 0 6 - 4 0 8 Pe a k P o s i t i o n w / C o n t i n g e n c y 17 -6 4 - 8 4 12 6 1 1 0 5 6 -4 2 - 6 4 - 8 1 - 9 2 - 1 1 7 - 1 3 5 - 1 4 5 - 4 4 5 - 4 6 2 - 4 7 2 - 4 9 7 - 5 1 5 - 5 2 5 - 5 5 1 Pl a n n i n g M a r g i n 20 % 1 6 % 1 5 % 2 8 % 2 7 % 2 4 % 1 9 % 1 8 % 1 7 % 1 6 % 1 5 % 1 4 % 1 4 % -3 % - 4 % - 4 % - 5 % - 6 % - 6 % - 7 % NE W R E S O U R C E S Sh o r t - T e r m M a r k e t P u r c h a s e 0 75 1 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Ne w N G F i r e d P e a k e r s 0 0 0 0 0 0 80 8 0 8 0 8 0 1 6 0 1 6 0 1 6 0 1 6 0 2 4 0 2 4 0 2 4 0 2 4 0 2 4 0 2 8 8 Ne w C o m b i n e d C y c l e C T 0 0 0 0 0 0 0 0 0 0 0 0 0 26 0 2 6 0 2 6 0 2 6 0 2 6 0 2 6 0 2 6 0 Th e r m a l R e s o u r c e U p g r a d e s 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 2 2 2 2 2 De m a n d R e s p o n s e 0 0 0 0 0 0 0 0 1 6 6 10 1 5 2 0 2 0 2 0 2 0 2 0 2 0 2 0 To t a l N e w R e s o u r c e s 0 75 1 0 0 0 0 0 80 8 0 8 1 8 6 1 6 6 1 6 9 1 7 5 4 4 0 5 2 0 5 2 2 5 2 2 5 2 2 5 2 2 5 7 0 Pe a k P o s i t i o n w i t h N e w R e s o u r c e s 17 1 1 1 6 1 2 6 1 1 0 5 6 3 8 1 6 0 -5 49 3 4 3 0 -5 58 5 0 2 5 7 -4 19 Pl a n n i n g M a r g i n w i t h N e w R e s o u r c e s 20 % 2 0 % 2 1 % 2 8 % 2 7 % 2 4 % 2 3 % 2 2 % 2 1 % 2 1 % 2 4 % 2 3 % 2 3 % 2 1 % 2 4 % 2 4 % 2 2 % 2 1 % 2 1 % 2 2 % Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 200 of 1125 Chapter 8 – Preferred Resource Strategy Avista Corp 2013 Electric IRP 8-39 Table 8.17: Summer 18-Hour Capacity Position (MW) with New Resources 20 1 4 2 0 1 5 2 0 1 6 2 0 1 7 2 0 1 8 2 0 1 9 2 0 2 0 2 0 2 1 2 0 2 2 2 0 2 3 2 0 2 4 2 0 2 5 2 0 2 6 2 0 2 7 2 0 2 8 2 0 2 9 2 0 3 0 2 0 3 1 2 0 3 2 2 0 3 3 TO T A L L O A D O B L I G A T I O N S Na t i v e L o a d F o r e c a s t 1, 4 7 4 1 , 5 0 0 1 , 5 2 7 1 , 5 5 3 1 , 5 8 1 1 , 6 1 1 1 , 6 3 1 1 , 6 5 5 1 , 6 7 9 1 , 7 0 3 1 , 7 2 6 1 , 7 5 3 1 , 7 8 0 1 , 8 0 6 1 , 8 3 4 1 , 8 5 9 1 , 8 8 5 1 , 9 1 2 1 , 9 4 3 1 , 9 7 4 Co n s e r v a t i o n F o r e c a s t 9 18 3 0 4 3 5 8 7 4 8 2 9 2 1 0 3 1 1 3 1 2 2 1 3 5 1 4 8 1 6 1 1 7 4 1 8 5 1 9 6 2 0 9 2 2 5 2 4 1 Ne t N a t i v e L o a d F o r e c a s t 1, 4 6 5 1 , 4 8 2 1 , 4 9 8 1 , 5 1 0 1 , 5 2 3 1 , 5 3 6 1 , 5 5 0 1 , 5 6 3 1 , 5 7 6 1 , 5 9 0 1 , 6 0 4 1 , 6 1 8 1 , 6 3 1 1 , 6 4 6 1 , 6 6 0 1 , 6 7 4 1 , 6 8 9 1 , 7 0 3 1 , 7 1 8 1 , 7 3 3 Fi r m P o w e r S a l e s 21 2 1 5 9 1 5 9 9 9 8 8 7 7 7 7 7 7 7 7 7 7 7 7 7 To t a l R e q u i r e m e n t s 1, 6 7 7 1 , 6 4 1 1 , 6 5 7 1 , 5 1 9 1 , 5 3 2 1 , 5 4 4 1 , 5 5 7 1 , 5 7 0 1 , 5 8 4 1 , 5 9 7 1 , 6 1 1 1 , 6 2 5 1 , 6 3 9 1 , 6 5 3 1 , 6 6 7 1 , 6 8 1 1 , 6 9 6 1 , 7 1 0 1 , 7 2 5 1 , 7 4 0 RE S O U R C E S Fi r m P o w e r P u r c h a s e s 29 2 9 2 9 2 9 2 9 2 6 2 6 2 6 2 6 2 5 2 5 2 5 2 5 2 5 2 5 2 5 2 5 2 5 2 5 2 5 Hy d r o R e s o u r c e s 70 1 7 0 7 6 6 3 6 3 1 6 3 8 5 8 3 5 8 0 6 2 2 6 2 4 6 2 2 6 2 2 6 2 4 6 2 2 6 2 2 6 2 4 6 2 2 6 2 2 6 2 4 6 2 2 6 2 2 Ba s e L o a d T h e r m a l s 78 5 7 8 5 7 8 5 7 8 5 7 8 5 7 8 5 7 8 5 7 8 5 7 8 5 7 8 5 7 8 5 7 8 5 7 8 5 5 5 6 5 5 6 5 5 6 5 5 6 5 5 6 5 5 6 5 5 6 Wi n d R e s o u r c e s 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Pe a k i n g U n i t s 17 6 1 7 6 1 7 6 1 7 6 1 7 6 1 7 6 1 7 6 1 7 6 1 7 6 1 7 6 1 7 6 1 7 6 1 7 6 1 7 6 1 7 6 1 7 6 1 7 6 1 7 6 1 7 6 1 7 6 To t a l R e s o u r c e s 1, 6 9 1 1 , 6 9 8 1 , 6 5 3 1 , 6 2 1 1 , 6 2 8 1 , 5 7 1 1 , 5 6 8 1 , 6 0 9 1 , 6 1 1 1 , 6 0 9 1 , 6 0 9 1 , 6 1 1 1 , 6 0 9 1 , 3 7 9 1 , 3 8 1 1 , 3 7 9 1 , 3 7 9 1 , 3 8 1 1 , 3 7 9 1 , 3 7 9 Pe a k P o s i t i o n B e f o r e R e s e r v e P l a n n i n g 14 5 7 -3 10 2 9 6 2 7 1 1 3 9 2 7 1 1 -2 -1 4 - 3 0 - 2 7 4 - 2 8 6 - 3 0 2 - 3 1 7 - 3 3 0 - 3 4 6 - 3 6 1 RE S E R V E P L A N N I N G Pl a n n i n g M a r g i n 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 To t a l A n c i l l a r y S e r v i c e s R e q u i r e d -1 7 7 - 1 7 6 - 1 7 7 - 1 7 0 - 1 7 2 - 1 7 3 - 1 7 5 - 1 7 6 - 1 7 7 - 1 7 9 - 1 8 0 - 1 8 1 - 1 8 2 - 1 6 6 - 1 6 7 - 1 6 7 - 1 6 8 - 1 6 9 - 1 6 9 - 1 7 0 Re s e r v e & C o n t i n g e n c y A v a i l a b i l i t y m e t b y H y d r o 17 7 1 7 6 1 7 7 1 7 0 1 7 2 1 7 3 1 7 5 1 7 6 1 7 7 1 7 9 1 8 0 1 8 1 1 8 2 1 6 6 1 6 7 1 6 7 1 6 8 1 6 9 1 6 9 1 7 0 De m a n d R e s p o n s e 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 To t a l R e s e r v e P l a n n i n g 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Pe a k P o s i t i o n w / C o n t i n g e n c y 14 5 7 -3 10 2 9 6 2 7 1 1 3 9 2 7 1 1 -2 -1 4 - 3 0 - 2 7 4 - 2 8 6 - 3 0 2 - 3 1 7 - 3 3 0 - 3 4 6 - 3 6 1 Pl a n n i n g M a r g i n 1% 3 % 0 % 7 % 6 % 2 % 1 % 2 % 2 % 1 % 0 % -1 % - 2 % - 1 7 % - 1 7 % - 1 8 % - 1 9 % - 1 9 % - 2 0 % - 2 1 % NE W R E S O U R C E S Sh o r t - T e r m M a r k e t P u r c h a s e 0 0 25 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Ne w N G F i r e d P e a k e r s 0 0 0 0 0 0 72 7 2 7 2 7 2 1 4 4 1 4 4 1 4 4 1 4 4 2 1 7 2 1 7 2 1 7 2 1 7 2 1 7 2 6 0 Ne w C o m b i n e d C y c l e C T 0 0 0 0 0 0 0 0 0 0 0 0 0 23 5 2 3 5 2 3 5 2 3 5 2 3 5 2 3 5 2 3 5 Th e r m a l R e s o u r c e U p g r a d e s 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 5 5 5 5 5 De m a n d R e s p o n s e 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 To t a l N e w R e s o u r c e s 0 0 25 0 0 0 72 7 2 7 2 7 2 1 4 4 1 4 4 1 4 4 3 7 9 4 5 1 4 5 7 4 5 7 4 5 7 4 5 7 5 0 0 Pe a k P o s i t i o n w i t h N e w R e s o u r c e s 14 5 7 2 2 1 0 2 9 6 2 7 8 3 1 1 1 9 9 8 4 1 4 2 1 3 0 1 1 4 1 0 5 1 6 5 1 5 4 1 4 0 1 2 7 1 1 1 1 3 9 Pl a n n i n g M a r g i n w i t h N e w R e s o u r c e s 1% 3 % 1 % 7 % 6 % 2 % 5 % 7 % 6 % 5 % 9 % 8 % 7 % 6 % 1 0 % 9 % 8 % 7 % 6 % 8 % Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 201 of 1125 Chapter 8 – Preferred Resource Strategy Avista Corp 2013 Electric IRP 8-40 Table 8.18: Average Annual Energy Position (aMW) With New Resources 20 1 4 2 0 1 5 2 0 1 6 2 0 1 7 2 0 1 8 2 0 1 9 2 0 2 0 2 0 2 1 2 0 2 2 2 0 2 3 2 0 2 4 2 0 2 5 2 0 2 6 2 0 2 7 2 0 2 8 2 0 2 9 2 0 3 0 2 0 3 1 2 0 3 2 2 0 3 3 TO T A L L O A D O B L I G A T I O N S Na t i v e L o a d F o r e c a s t 1, 0 6 0 1 , 0 7 9 1 , 1 0 0 1 , 1 2 3 1 , 1 4 4 1 , 1 6 5 1 , 1 8 1 1 , 1 9 7 1 , 2 1 5 1 , 2 3 2 1 , 2 5 0 1 , 2 7 2 1 , 2 9 1 1 , 3 1 1 1 , 3 3 1 1 , 3 5 1 1 , 3 7 3 1 , 3 9 6 1 , 4 2 2 1 , 4 4 9 Co n s e r v a t i o n F o r e c a s t 6 12 2 0 2 9 3 9 5 1 5 5 6 2 7 0 7 7 8 3 9 2 1 0 1 1 0 9 1 1 8 1 2 6 1 3 4 1 4 2 1 5 3 1 6 4 Ne t N a t i v e L o a d F o r e c a s t 1, 0 5 4 1 , 0 6 7 1 , 0 7 9 1 , 0 9 3 1 , 1 0 5 1 , 1 1 4 1 , 1 2 5 1 , 1 3 5 1 , 1 4 5 1 , 1 5 5 1 , 1 6 7 1 , 1 8 0 1 , 1 9 0 1 , 2 0 1 1 , 2 1 2 1 , 2 2 5 1 , 2 3 9 1 , 2 5 4 1 , 2 7 0 1 , 2 8 5 Fi r m P o w e r S a l e s 10 9 5 8 5 8 6 6 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 To t a l R e q u i r e m e n t s 1, 1 6 3 1 , 1 2 5 1 , 1 3 7 1 , 0 9 9 1 , 1 1 1 1 , 1 1 9 1 , 1 3 0 1 , 1 4 0 1 , 1 5 0 1 , 1 6 0 1 , 1 7 2 1 , 1 8 5 1 , 1 9 5 1 , 2 0 6 1 , 2 1 7 1 , 2 3 0 1 , 2 4 4 1 , 2 5 9 1 , 2 7 4 1 , 2 9 0 RE S O U R C E S Fi r m P o w e r P u r c h a s e s 12 8 1 2 9 1 2 8 7 6 7 6 5 6 3 1 3 0 3 0 2 9 2 9 2 9 2 9 2 9 2 9 2 9 2 9 2 9 2 9 2 9 Hy d r o R e s o u r c e s 52 7 4 9 5 4 9 5 4 9 5 4 9 0 4 8 1 4 8 1 4 8 1 4 8 1 4 8 1 4 8 1 4 8 1 4 8 1 4 8 1 4 8 1 4 8 1 4 8 1 4 8 1 4 8 1 4 8 1 Ba s e L o a d T h e r m a l s 72 3 7 2 5 7 1 8 7 1 5 7 3 2 7 1 1 7 2 4 7 3 6 7 1 3 7 1 7 7 1 4 7 1 9 6 7 3 5 0 6 5 0 4 5 0 6 5 0 4 5 0 6 5 0 4 5 0 6 Wi n d R e s o u r c e s 42 4 0 4 0 4 0 4 0 4 0 4 0 4 0 4 0 4 0 4 0 4 0 4 0 4 0 4 0 4 0 4 0 4 0 4 0 4 0 Pe a k i n g U n i t s 15 3 1 3 9 1 5 4 1 5 3 1 5 3 1 5 3 1 4 7 1 5 1 1 5 2 1 5 3 1 5 2 1 5 3 1 5 2 1 5 3 1 5 2 1 5 3 1 5 2 1 5 3 1 5 2 1 5 3 To t a l R e s o u r c e s 1, 5 7 3 1 , 5 2 8 1 , 5 3 5 1 , 4 7 9 1 , 4 9 0 1 , 4 4 0 1 , 4 2 2 1 , 4 3 8 1 , 4 1 6 1 , 4 2 0 1 , 4 1 5 1 , 4 2 1 1 , 3 7 4 1 , 2 0 8 1 , 2 0 6 1 , 2 0 8 1 , 2 0 6 1 , 2 0 8 1 , 2 0 6 1 , 2 0 8 En e r g y P o s i t i o n B e f o r e R e s e r v e P l a n n i n g 41 0 4 0 4 3 9 8 3 8 0 3 7 9 3 2 1 2 9 2 2 9 9 2 6 6 2 5 9 2 4 3 2 3 7 1 7 9 2 - 1 2 - 2 2 - 3 9 - 5 1 - 6 9 - 8 2 RE S E R V E P L A N N I N G Co n t i n g e n c y -2 2 8 - 2 3 1 - 2 3 1 - 2 3 2 - 2 3 2 - 2 1 4 - 1 9 5 - 1 9 6 - 1 9 6 - 1 9 7 - 1 9 7 - 1 9 8 - 1 9 8 - 1 9 9 - 1 9 9 - 2 0 0 - 2 0 0 - 2 0 1 - 2 0 2 - 2 0 2 En e r g y P o s i t i o n w / C o n t i n g e n c y 18 2 1 7 3 1 6 7 1 4 8 1 4 7 1 0 6 9 6 1 0 3 7 0 6 3 4 6 3 9 -1 9 - 1 9 7 - 2 1 1 - 2 2 1 - 2 3 9 - 2 5 2 - 2 7 0 - 2 8 4 NE W R E S O U R C E S Sh o r t - T e r m M a r k e t P u r c h a s e 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Ne w N G F i r e d P e a k e r s 0 0 0 0 0 0 68 6 8 6 8 6 8 1 3 5 1 3 5 1 3 5 1 3 5 2 0 4 2 0 4 2 0 4 2 0 4 2 0 4 2 4 9 Ne w C o m b i n e d C y c l e C T 0 0 0 0 0 0 0 0 0 0 0 0 0 24 5 2 4 5 2 4 5 2 4 5 2 4 5 2 4 5 2 4 5 Th e r m a l R e s o u r c e U p g r a d e s 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 5 5 5 5 5 De m a n d R e s p o n s e 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 To t a l N e w R e s o u r c e s 0 0 0 0 0 0 68 6 8 6 8 6 8 1 3 5 1 3 5 1 3 5 3 8 0 4 4 9 4 5 4 4 5 4 4 5 4 4 5 4 5 0 0 En e r g y P o s i t i o n w i t h N e w R e s o u r c e s 18 2 1 7 3 1 6 7 1 4 8 1 4 7 1 0 6 1 6 4 1 7 0 1 3 7 1 3 0 1 8 1 1 7 4 1 1 6 1 8 4 2 3 8 2 3 3 2 1 5 2 0 3 1 8 4 2 1 6 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 202 of 1125 Chapter 9–Action Items Avista Corp 2013 Electric IRP 9. Action Items The IRP is an ongoing and iterative process balancing regular publication timelines with pursuing the best 20-year resource strategies. The biennial publication date provides opportunities to document ongoing improvements to the modeling and forecasting procedures and tools, as well as enhance the process with new research as the planning environment changes. This section provides an overview of the progress made on the 2011 IRP Action Plan and provides the 2013 Action Plan. Summary of the 2011 IRP Action Plan The 2011 Action Plan included five separate categories: resource additions and analysis, energy efficiency, environmental policies, modeling and forecasting enhancements, and transmission planning. 2011 Action Plan and Progress Report – Resource Additions and Analysis Continue to explore and follow potential new resource opportunities. o Over the past two years, Avista began investigating sites for future peaking-capable generation. This process consisted of interconnection feasibility studies, site visits, and permitting and environmental evaluation. Avista will continue this effort over the next several years prior to releasing an RFP for new peaking capacity. o Avista is ending studies on wind resource development with the passage of SB 5575 in Washington and the subsequent lack of need for renewables in this IRP. This includes ceasing development at the Reardan Wind site. Continue studies on the costs, energy, capacity and environmental benefits of hydro upgrades at both Spokane and Clark Fork River projects. o During 2012, Avista studied upgrade options to the Spokane River Project. The assessment included an engineering screening of several upgrade options for the five upper Spokane River developments and concluded with a recommendation to rehabilitate the Nine Mile Falls project rather building or rebuilding the powerhouse. The assessment provided perspectives on the river system’s potential for meeting future load requirements, and options to add renewable energy at a price competitive with other renewables. Details on Spokane River upgrade opportunities are in Chapter 6, Generation Resource Options. o Avista completed high-level studies for the Cabinet Gorge hydroelectric development. The review evaluated options to add a fifth unit in the original bypass tunnel for additional capacity and to reduce total dissolved gases. This alternative was uneconomic compared to other utility alternatives. Study potential locations for the natural gas-fired resource identified to be online by the end of 2018. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 203 of 1125 Chapter 9–Action Items Avista Corp 2013 Electric IRP o Avista has begun its efforts to identify a site for a new natural gas-fired peaker. A small cross-function team is investigating potential sites within the service territory. Site selection considers proximity to natural gas pipelines, transmission, and distance away from population centers or locations with potential environmental liabilities. Avista has initiated transmission studies for potential areas discussed in Chapter 5. Continue participation in regional IRP processes and, where agreeable, find opportunities to meet resource requirements on a collaborative basis with other utilities. o Avista monitors and attends when appropriate other northwest utility’s IRP processes. With Avista’s needs toward the beginning of the next decade, and for smaller unit sizes, the potential for resource collaboration is unlikely. Collaboration works best on developing large projects where economies of scale benefits smaller off-takers. Given the PRS’s first identified resource is for a small peaker, collaborating on a project would be unlikely. o Avista’s staff continues to participate in regional processes including the development of the Seventh Power Plan, PNUCC studies, and work done by the Western Governors Association. Provide an update on the Little Falls and Nine Mile hydroelectric project upgrades. o The Nine Mile hydro facility is undergoing rehabilitation. Units 1 and 2 have been removed and engineering work is complete. A status update will be included in the next IRP; the project is scheduled for completion in 2016. o At Little Falls, new electrical equipment and generator excitation systems are installed. Avista is replacing station service, updating the powerhouse crane, and developing new control systems on each of the units. Study potential for demand response projects with industrial customers. o Avista has begun preliminary investigation into demand response from industrial and commercial customers. For this IRP Avista identified 20 MW of commercial demand response. Avista intends to conduct a market assessment study during the next IRP process, and begin preliminary discussion with large industrial customers. Continue to monitor regional surplus capacity and Avista’s reliance on this surplus for near- and medium-term needs. o Avista participates in the NPCC Resource Adequacy Forum. On January 23, 2013, the NPCC released a resource adequacy study. The study found that the Northwest has sufficient resources until a small regional deficit (350 MW) begins in 2017. o Avista has short-term winter peaking needs in 2015 and 2016; thereafter a 150 MW return of the PGE capacity sale will provide sufficient capacity through 2019. The Resource Adequacy forum studies provide evidence Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 204 of 1125 Chapter 9–Action Items Avista Corp 2013 Electric IRP that Avista can rely on for market capacity during this period. Further, the report identifies the regional summer peak periods to be surplus into the future, and that Avista can lower its planning margin requirements during summer months. 2011 Action Plan and Progress Report – Energy Efficiency Study and quantify transmission and distribution efficiency projects as they apply to the Washington RPS goals. o Avista continues to update its transmission and distribution system since the 2011 IRP; it has completed several distribution feeder upgrades and installed smart grid technology in Pullman and Spokane. In the 2010/2011 conservation target report Avista reported 3,512 MWh of savings. In the upcoming 2012/2013 report Avista plans on filing 32,387 MWh of savings. Update processes and protocols for conservation, measurement, evaluation and verification. o Avista is continuing to work through the process of updating and documenting its processes and procedures for the conservation programs offered through the utility. For evaluation, measurement and verification, Avista is guided by its framework and is committed to revisiting with stakeholders as necessary with the intent of updating and editing it as circumstances warrant. Continue to determine the potential impacts and costs of load management options. o Avista is participating in the Northwest Regional Smart Grid Demonstration Project to help understand the costs and benefits of load management programs. In the past, Avista has sponsored a pilot in Idaho as a way to understand how these programs could work and understand the costs and benefits. In the future, Avista will focus more on commercial and industrial opportunities by studying the potential and costs of such a programs. 2011 Action Plan and Progress Report – Environmental Policy Continue studies of state and federal climate change policies. o Avista actively engages in reviewing and participating in state and federal discussions about climate change policies related to electric generation and natural gas distribution. Details about the issues covered are in Chapter 4, Policy Considerations. Continue and report on the work of Avista’s Climate Policy Council. o Avista’s Climate Policy Council and the Resource Planning team actively analyze state and federal greenhouse gas legislation. This work will continue until final rules are established and laws passed. The focus will then shift to mitigating the costs of meeting the applicable laws and regulations. Avista has quantified its greenhouse gas emissions using the World Resources Initiative–World Business Council for Sustainable Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 205 of 1125 Chapter 9–Action Items Avista Corp 2013 Electric IRP Development inventory protocol in anticipation of state and federal greenhouse gas reporting mandates. Details about Climate Policy Council efforts are in Chapter 4, Policy Considerations. 2011 Action Plan and Progress Report – Modeling and Forecasting Continue following regional reliability processes and develop Avista-centric modeling for possible inclusion in the 2013 IRP. o Avista has developed, with support from NPCC staff, an Avista view of the northwest load and resource balance (see Chapter 2). Given today’s assumptions, the region has enough capacity to meet Northwest winter needs to 2017, and summer capacity needs indefinitely where the larger winter capacity needs are met. o Since the 2011, IRP Avista updated and added logic and reporting enhancements to Avista’s LOLP model per NPCC staff recommendations. The results of this discussion and analysis led Avista to rely on the mixture of new resources and market purchases to meet a 5 percent LOLP reliability target. See Chapter 2, Loads & Resources, for a discussion of this study. Continue studying the impacts of climate change on retail loads. o The load forecast includes changes in Spokane temperatures away from the 30-year normal to include fewer heating degree days and more cooling degree days per a 2008 University of Washington study. The study anticipates there will not be a large effect on retail loads from potential climate change activities. Avista investigated studies regarding changing water conditions from climate change and found there is no evidence of changing annual average conditions, but rather higher flows earlier in the year. The higher flows indirectly benefit customers as increased flow periods coincide with higher loads. Refine the stochastic model for cost-driver relationships, including further analyzing year-to-year hydro correlation and the correlation between wind, load, and hydro. o Quality regional wind output data is available from the BPA website only back to 2007. Given this short term dataset, correlating to load and hydro data will provide statistically insignificant results. The best way to estimate these correlations is to fund a long-term weather consultant study; the NPCC’s Seventh Power Plan would benefit from such a study. Avista will be participating in this planning process and will recommend a study based on long-term data. 2011 Action Plan and Progress Report – Transmission and Distribution Planning Work to maintain Avista’s existing transmission rights, under applicable FERC policies, for transmission service to bundled retail native load. o Avista has maintained its existing transmission rights to meet native customer load. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 206 of 1125 Chapter 9–Action Items Avista Corp 2013 Electric IRP Continue to participate in BPA transmission processes and rate proceedings to minimize the costs of integrating existing resources outside of Avista’s service area. o Avista is actively participating in the BPA transmission rate proceedings. Continue to participate in regional and sub-regional efforts to establish new regional transmission structures to facilitate long-term expansion of the regional transmission system. o Avista staff participate in and lead many regional transmission efforts including Columbia Grid and the Transmission Coordination Work Group (TCWG). Evaluate costs to integrate new resources across Avista’s service territory and from regions outside of the Northwest. o Avista’s Transmission group performed seven studies of potential generation upgrades and new facilities, these studies are in Appendix D and Chapter 5. Study and implement distribution feeder rebuilds to reduce system losses. o Since the 2011 IRP, Avista has completed two feeder rebuilds. These rebuilds reduce losses by 1,542 MWh, improve reliability, and decrease future operation and maintenance costs. Continue to study other potential areas to implement Smart Grid projects to other areas of the service territory. o With the completion of the Spokane and Pullman Smart Grid projects, Avista put all such future projects on hold. Additional projects will be evaluated on a case-by-case basis for cost effectiveness and increased reliability. Study transmission reconfigurations that economically reduce system losses. o Avista’s transmission department continues to review potential projects to increase reliability and reduce system losses. Chapter 5, Transmission & distribution, discusses projects meeting this objective. 2013 IRP Action Plan Avista’s 2013 PRS provides direction and guidance for the type, timing and size of future resource acquisitions. The 2013 IRP Action Plan highlights the activities planned for possible inclusion in the 2015 IRP. Progress and results for the 2013 Action Plan items are reported to the TAC and the results will be included in Avista’s 2015 IRP. The 2013 Action Plan includes input from Commission Staff, Avista’s management team, and the TAC. Generation Resource Related Analysis Consider Spokane and Clark Fork River hydro upgrade options in the next IRP as potential resource options to meet energy, capacity and environmental requirements. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 207 of 1125 Chapter 9–Action Items Avista Corp 2013 Electric IRP Continue to evaluate potential locations for the natural gas-fired resource identified to be online by the end of 2019, including environmental reviews, transmission studies, and potential land acquisition. Continue participation in regional IRP and regional planning processes and monitor regional surplus capacity and continue to participate in regional capacity planning processes. Commission a demand response potential and cost assessment of commercial and industrial customers per its inclusion in the middle of the PRS action plan. Continue monitoring state and federal climate change policies and report work from Avista’s Climate Change Council. Review and update the energy forecast methodology to better integrate economic, regional, and weather drivers of energy use. Evaluate the benefits of a short-term (up to 24-months) capacity position report. Evaluate options to integrate intermittent resources. Energy Efficiency Work with NPCC, the UTC, and others to resolve adjusted market baseline issues for setting energy efficiency target setting and acquisition claims in Washington. Study and quantify transmission and distribution efficiency projects as they apply to EIA goals. Update processes and protocols for conservation measurement, evaluation and verification. Assess energy efficiency potential on Avista’s generation facilities. Transmission and Distribution Planning Work to maintain Avista’s existing transmission rights, under applicable FERC policies, for transmission service to bundled retail native load. Continue to participate in BPA transmission processes and rate proceedings to minimize costs of integrating existing resources outside of Avista’s service area. Continue to participate in regional and sub-regional efforts to establish new regional transmission structures to facilitate long-term expansion of the regional transmission system. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 208 of 1125 Chapter 9–Action Items Avista Corp 2013 Electric IRP Production Credits Primary Avista 2013 Electric IRP Team Individual Title Contribution Clint Kalich Manager of Resource Planning & Analysis Project Manager James Gall Senior Power Supply Analyst Analysis/Author John Lyons Senior Resource Policy Analyst Research/Author/Editor Grant Forsyth Senior Forecaster & Economist Load Forecast Lori Hermanson Utility Resource Analyst Energy Efficiency Richard Maguire System Planning Engineer Transmission & Distribution 2013 Electric IRP Contributors Name Title Shawn Bonfield Regulatory Policy Analyst Troy Dehnel Feeder Upgrade Project Coordinator Thomas Dempsey Manager, Generation Joint Projects Leona Doege DSM Program ManagerMike Gonnella Manager of Generation Substation Support Kelly Irvine Manager of Natural Gas Planning Jon Powell Partnership Solutions Manager Dave Schwall Senior Engineer Darrell Soyars Manager of Corporate Environmental ComplianceXin Shane Power Supply Analyst Steve Wenke Chief Generation Engineer Jessie Wuerst Senior External Communications Manager Contact contributors via email by placing their names in this email address format: first.last@avistacorp.com Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 209 of 1125 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 210 of 1125 2013 Electric Integrated Resource Plan Appendices Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 211 of 1125 Table of Contents Appendix A – Technical Advisory Committee Presentations (Page 1) Technical Advisory Committee Meeting 1 (Page 1) Technical Advisory Committee Meeting 2 (Page 73) Technical Advisory Committee Meeting 3 (Page 146) Technical Advisory Committee Meeting 4 (Page 257) Technical Advisory Committee Meeting 5 (Page 416) Technical Advisory Committee Meeting 6 (Page 518) Appendix B – 2013 Work Plan (Page 572) Appendix C – Conservation Potential Assessment Study (Page 579) Appendix D – Transmission Studies (Page 872) Appendix E – New Resource Table for Transmission (Page 910) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 212 of 1125 2013 Electric Integrated Resource Plan Appendix A – 2013 Electric IRP Technical Advisory Committee Presentations Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 213 of 1125 Avista’s 2013 Electric Integrated Resource Plan Technical Advisory Committee Meeting No. 1 Agenda Wednesday, May 23, 2012 Conference Room 130 Topic Time Staff 1. Introduction 8:30 Kalich 2. Powering Our Future Game 8:35 Silkworth 3. 2011 Renewable RFP 10:30 Silkworth 4. Palouse Wind Project Update 11:00 First Wind 5. Lunch 12:00 6. 2011 IRP Acknowledgement 12:45 Kalich 7. Energy Independence Act Compliance 1:45 Lyons/Gall & Forecast 8. Work Plan 2:15 Lyons 9. Adjourn 3:00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 214 of 1125 Powering Our Future Game Steve Silkworth, Manager of Wholesale Marketing & Contracts Anna Scarlett, Communications Manager First Technical Advisory Committee Meeting 2013 Electric Integrated Resource Plan May 23, 2012 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 215 of 1125 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 216 of 1125 You’re the power planner Meet demand Meet renewable portfolio standards Tomorrow - 2030 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 217 of 1125 Wash. Renewable Portfolio Standards 2012 - 3% of energy delivered to Washington customers *Dam upgrades, purchased renewable energy 2016 - 9% *Palouse Wind *Kettle Falls 2020 (and beyond) - 15%  Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 218 of 1125 Today’s Energy Generation Capability 42.5% 12.7% 34.0% 0.5% 2.8% 7.5% Gas Coal Hydro Wind Biomass Conservation Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 219 of 1125 Natural Gas Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 220 of 1125 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 221 of 1125 8 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 222 of 1125 1.Review the materials at your table. 2.Choose a note taker and a spokesperson from your table. 3.Write table # on your worksheet. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 223 of 1125 Round 1 Using your blocks, choose any mix you like, placing them on the corresponding spaces on your game board. Each block signifies 10 percent of your total new resources and you may only use a total of 10 blocks (or 100%). You can use any combination you like, and you can even use one resource for all your new energy if you like. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 224 of 1125 Round 1 Conclusion 1.Record your ‘resource mix’ on the worksheet. 2.Give your worksheet to a facilitator when you are finished. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 225 of 1125 Group discussion 12 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 226 of 1125 •Wind •Solar •Natural Gas •Coal •Nuclear •Biomass •Hydropower Meets Wash. Renewable Portfolio Standards Dependable/can be generated on demand to meet peak demand Conservation 13 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 227 of 1125 Round 2 Meet electric demand. Meet renewable portfolio requirements over the next 20 years. Consider customers’ bills, carbon emissions, and your ability to generate enough power to serve all your customers during peak demand times. 14 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 228 of 1125 Meets Wash. Renewable Portfolio Mandates Meets customer needs during peak demand Relative Cost Conservation/Energy Efficiency*  $-$$$ Natural Gas  $ Wind  $$ Hydroelectric**   $$ Biomass***   $$$ Coal  $$$ Nuclear  $$$$ Solar  $$$$$ * Energy efficiency programs cost more as the amount of energy that is saved increases. ** Only new hydroelectric plants and the additional energy produced with upgrades performed after 1999 qualify as renewable under Washington State Renewable Portfolio Standards. ***Only biomass plants built after 1999 qualify as renewable under Washington State Renewable Portfolio Standards. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 229 of 1125 Round 2 Using your blocks, choose any mix you like, placing them on the corresponding spaces on your game board. Each block signifies 10 percent of your total new resources and you may only use a total of 10 blocks (or 100%). Use a combination of resources that meet Renewable Portfolio Mandates and resources that are considered dependable and will meet peak demand. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 230 of 1125 Round 2 Conclusion 1.Record your ‘resource mix’ on the worksheet. 2.Give your worksheet to a facilitator when you are finished. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 231 of 1125 Group Discussion Discussion of impact to emissions, costs, risk Meet demand at peak times? Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 232 of 1125 Conclusion Were there any surprises? What did you learn? What questions do you have? Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 233 of 1125 2011 Renewable RFP Steve Silkworth, Manager of Wholesale Marketing & Contracts First Technical Advisory Committee Meeting 2013 Electric Integrated Resource Plan May 23, 2012 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 234 of 1125 2 •2009 IRP: identified the need for 48 aMW RECs by 2016 to meet the 9% renewable goal in Washington state • Over supply of turbines. Turbine prices declined to 2004 levels • ITC/PTC expires in 2012 • Washington state 75% sales tax exemption through June 2013 • Levelized costs were estimated to result in 30% to 40% lower cost than the 2009 RFP of 14 months prior • REC demand will increase in the next few years as the 2016 tranche approaches Why Issue a Renewables RFP in 2011? Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 235 of 1125 3 • RFP Issued: February 22, 2011 • Quantity: up to 35 aMW of I-937 qualifying renewable power including all renewable energy attributes • Delivery Start: on or before 12/31/2012 • Term: 20+ years • Avista requested competitive bids for projects or project output at the most favorable price available. Expected Delivered Price: $62 per MWh (20 yr) levelized Renewable Resource RFP Overview Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 236 of 1125 4 • Received proposals from 11 bidders with 17 options. • Technologies submitted o Wind – Approximately 769 MW o Landfill gas – 5 MW • Pricing was very competitive and reflected the current down-turn in the renewable energy market. • Comparable projects proposed through the 2009 RFP (approximately 15 months prior) were now up to 30% to 40% less expensive in the 2011 solicitation. Renewable Resource RFP Overview Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 237 of 1125 5 Montana Wind Wind Palouse Wind Wind Wind Wind Land Fill Gas Wind Wind Wind Wind Bid Project Locations Received bids totaling 774 MW (769 MW wind, 5 MW landfill gas) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 238 of 1125 6 Evaluation Criteria 1.Risk Management (30%) – Financing ability/experience 2.Net Price (40%) – Expected benefit - expected cost 3.Price Risk (10%) – Pricing type, O&M, generation quality, and optionality 4.Electric Factors (10%) – Transmission, procurement process and equipment 5.Environmental/Community (10%) – Permits process and location Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 239 of 1125 7 Palouse Wind • Approximately 105 MW • Near Oakesdale, WA (35 miles south of Spokane) • Interconnected directly to Avista system • Developed by First Wind • Commercial operation by 12/31/2012 • Vestas 1.8 MW turbines – 100M Rotors • Net capacity factor – expected: 37.5% • Developer will take advantage of expiring tax incentives Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 240 of 1125 Palouse Wind - 2013 Avista IRP TAC Meeting Spokane, WA – May 23, 2012 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 241 of 1125 Overview •Founded in 2002 and headquartered in Boston with 200+ employees at offices and project sites around the U.S. •Focused on renewable energy, natural gas, energy storage and transmission development in core markets, such as the Northeast, West and Hawaii •Wind projects range from 15 – 205 MW, situated on private, state and federal lands •Vertically integrated to develop projects from conception through operations bringing stable, long-term contracts to utilities and customers in high-demand markets •Successfully raised over $6 billion to convert development projects into operating assets 2 Milford Wind – 306 MW in Utah Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 242 of 1125 First Wind Projects •Own and Operate: 12 projects, 750 MW •Operate: 1 project, 45 MW •In Construction: 4 projects, 230 MW 3 Mars Hill 42 MW Stetson I 57 MW Stetson II 26 MW Steel Winds I 20 MW Sheffield 40 MW Rollins 60 MW Cohocton 125 MW Milford I 204 MW Milford II 102 MW KWP I 30 MW KWP II 21 MW Kahuku 30 MW Steel Winds II 15 MW Palouse 105 MW Kawailoa 69 MW Kahuku, HI KWP, HI Milford I & II, UT Cohocton, NY Mars Hill, ME Power County 45 MW Projects we Own and Operate Projects Under Construction Development Areas First Wind Office Operating Projects Steel Winds, NY Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 243 of 1125 A Company of Firsts Consistently demonstrated leadership in Innovation, Environmental Stewardship, and Community Engagement 4 Siting •Steel Winds (20 MW) – Development on EPA Brownfield Site Environmental •KWP (30 MW) – Development with Habitat Conservation Plan Power Sales •Stetson Phase II (26 MW) – Unique PPA off- take with Harvard University Transmission Engineering •Milford (204+ MW) – Developed 88-mile Generator Lead Technology •Kahuku (30 MW) – Integrated 15 MW Battery Energy Storage System Our first-in-the-state Sheffield Wind project required considerable environmental innovations in Vermont. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 244 of 1125 Track Record •Asset Conversion: Since its founding, First Wind has raised over $6 billion to convert development projects into operating assets 5 $0 $1,000 $2,000 $3,000 $4,000 $5,000 $6,000 $7,000 2005 2006 2007 2008 2009 2010 2011 Mi l l i o n s PPA Prepayment Turbine Supply Loan Corporate Debt ITC Grant Tax Equity Project Debt Select Partners Sources of capital by year Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 245 of 1125 Palouse Wind 6 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 246 of 1125 •Located on ridges between State Route 195 and the town of Oakesdale in Whitman County •Strong winter peaking wind resource, complimentary to regional spring hydro resource •Utilizing 58 Vestas V100 wind turbines, with total capacity of 105 MW •30-year PPA with Avista, and interconnection to their new Benewah to Shawnee 230kV line •$210 million capital raise from private sector •Will be largest energy facility in Whitman County, producing renewable energy for 30,000 homes •40 farmers involved Palouse Wind Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 247 of 1125 Phases of Developing a Palouse Wind • 3 years of wind data from 4 tower locations • Third party wind validation Wind Resource Assessment Transmission Analysis Development Permitting/ Public Involvement Power Purchase Agreement • Transmission • Gen-tie routing • Site design • Landowner Relations • Community Involvement • Envr. Studies • Public Meetings • EIS and CUP Hearing 2007 2008 2009 2010 2011 • Avista PPA signed • Interconnection Agreement • Financing Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 248 of 1125 Thorough Environmental Review •First EIS in Whitman County – ever •All areas of the built and natural environment were evaluated per state law •Over 250 Comments received during EIS process •164 conditions to consider during construction and operations Important Conditions 1.County CUP Compliance Package. Preconstruction micrositing surveys 2.Habitat Mitigation. WDFW and Palouse Prairie impacts 3.Avian fatality monitoring 4.Technical Advisory Committee 5.Decommissioning Requirements Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 249 of 1125 Successful Financing •First Wind has secured $210 Million to finance the Palouse Wind project •Key Bank-Joint lead arranger and administrative agent •Norddeutsche Landesbank Girozentrale, CoBank ACB, Banco Santander served as joint lead arrangers “We applaud First Wind’s dedication that brings significant investment to Eastern Washington. The financing of Palouse Wind demonstrates the solid fundamentals of the wind project that will provide an excellent source of renewable power for Washington ratepayers.” - Andrew Redinger KeyBanc Director Utility &Renewable Energy Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 250 of 1125 Palouse Wind represents a Major Investment in Whitman County •Construction will support 150 - 250 jobs •Approximately $30 million of spending with local businesses in Whitman County and the Inland Northwest •15 full-time operations jobs, and ongoing contracting with local businesses •Property Tax and Sales Tax Revenue •Over $700,000 per year generated in tax revenue Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 251 of 1125 Construction of Palouse Wind •Construction meets the standards of County CUP conditions •40 permanent acres impacted, 5 acres CRP/grassland •RMT, Inc selected as General Contractor •Approximately 50 workers on site since October, increasing to 250 this summer •Civil work on roads and turbine pads •Avista switchyard construction 12 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 252 of 1125 Inland NW Jobs Contractors to-date include •Busch Distributors, Oakesdale •Pearson Fence, Colfax •Wheatland Inn, Colfax •Crossets Market, Oakesdale •Brass Rail, Rosaila •Plateau Archeology, Pullman •Stewart Title, Pullman •Schweitzer Engineering, Pullman •Memorable Events, Colfax •Goodfellow Brothers, Wenatchee •Lydig Construction, Spokane •Garco Construction, Spokane •STRATA, Pullman •Taylor Engineering, Pullman •Atlas Sand and Gravel, Clarkston (local gravel pit) •Landau Associates, Colfax •Gallatin, Spokane •Henkles & McCoy, Vancouver •Ch2MHill, Spokane Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 253 of 1125 Long Term Commitment on the Palouse •First Wind Scholarship Program •Palouse Empire Fair, Lentil Fest •High School boosters •4H and FFA Clubs •Fishing Kids •Bikes for Books •Youth sports sponsorship Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 254 of 1125 What to expect in 2012 April May June July August Sept Oct Nov Dec Mob all construction units Transmission Line Foundations Turbine Installation Substation Commercial Operation Hire Operations Staff Collector System Turbine Commissioning O&M Building Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 255 of 1125 Ben Fairbanks Director, Business Development p – 971.998.1411 bfairbanks@firstwind.com Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 256 of 1125 2011 Electric Integrated Resource Plan Acknowledgement Review Clint Kalich, Manager of Resource Planning and Analysis First Technical Advisory Committee Meeting 2013 Electric Integrated Resource Plan May 23, 2012 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 257 of 1125 Acknowledgements Idaho Public Utilities Commission (IPUC) Case No. AVU-E-11-04, ORDER NO. 32444 acknowledged Avista’s 2011 IRP. Washington Utilities and Transportation Commission (UTC) Docket No. UE-101482 acknowledged Avista’s IRP on January 12, 2012. Acknowledgement is not a pre-approval of the Preferred Resource Strategy or the IRP itself. Future acquisitions obtain a prudence determination in general rate cases. IPUC encouraged Avista to make continued efforts to include more public involvement in the TAC. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 258 of 1125 Public Comments No public comments received in Washington jurisdiction. Two public comments in Idaho jurisdiction: An individual commenter thought the Company should not receive any public money or rate increases for wind generation. Benewah County, Idaho was concerned that the potential federal greenhouse gas policies in the IRP would lead to increased rates and negatively impact the County, and the polices were not supported by the science. They advocated for Avista to develop alternative policies to benefit the environment and the County. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 259 of 1125 Resource Needs IPUC believes the capacity planning assumptions are reasonable given the Company’s access to and the availability of markets if resource deficits are higher than predicted. UTC: The 14% summer and 15% winter planning margin above operating reserves are appropriate for planning for peak loads and are consistent with other regional utilities. This is an improvement over the 2009 IRP methodology. UTC: Continue involvement in the NPCC Resource Adequacy Forum. UTC: Continue to analyze planning margin to determine the most cost-effective way to reliably meet resource adequacy needs. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 260 of 1125 Load Forecasts IPUC supports the inclusion of projected electric vehicle consumption. IPUC believes the load forecast assumptions to be reasonable. UTC requested a range of load forecasts in the 2009 IRP acknowledgement. 2011 IRP included a high growth case (2.33%) and a low growth case (0.93%). This is expected to continue in future IRPs. UTC: the Global Insights forecasts on Table 2.1, p. 2-4. GDP growth (2.7%), unemployment (5%), 1.58 million housing starts per year, and 4.75% federal funds rate may be too optimistic given the current state of the economy. Need to continue to monitor and test models under more conservative growth assumptions. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 261 of 1125 Energy Efficiency IPUC has concerns that the Company “…may not pursue “all” cost- effective conservation if it adheres to certain conservation-potential limitations expressed in the IRP” (maximum versus realistic achievable potential). The 2007 and draft 2012 Idaho State Energy Plans direct the IPUC to encourage utilities to pursue “all cost effective conservation.” UTC: Considers the Conservation Potential Assessment (CPA) done for the 2011 IRP to be sound and includes a reasonable range of forecast assumptions. UTC: Finds the CPA sensitivity analysis regarding changes to avoided cost “… to be useful in identifying both the potential achievable over this time horizon, but also for identifying higher costs along the supply curves.” Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 262 of 1125 Renewable Portfolio Standard IPUC: Early acquisition of wind to meet RPS requirements ahead of need will be will be scrutinized in a future rate case, but the early acquisition allows for the use of tax incentives and lower wind costs. UTC: The Company needs to more clearly describe the method used to calculate REC reserve requirements and how the reserves are used for RPS compliance. UTC: Need to provide clear analysis of how the Company specifically (new resources, RECs or banking) plans to meet the higher RPS goals from 2016 and beyond. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 263 of 1125 Transmission & Distribution IPUC: Staff is encouraged by efforts to include distribution savings and supports continued involvement with regional transmission groups. UTC: Estimated costs for the integration of new resources are useful. UTC: Want to see continued cooperation with BPA on the direct interconnection of Lancaster to ensure completion of the project by the end of 2012. UTC: Continue to refine the analysis of feeder upgrades as they are completed and track actual loss savings in the 2013 IRP. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 264 of 1125 Generation Resource Options UTC would like to see a discussion and analysis of electric storage technologies for “firming intermittent generation resources or for meeting peaks in load.” This should include cost-effectiveness, commercial availability, and where this resource would fit in relation to other generating resources. UTC wants “… an explicit discussion of the future costs and liabilities of operating Colstrip over the 20 year planning horizon” including costs of anticipated EPA regulations because it is a significant resource and the Company’s only coal-fired asset. UTC: Model a scenario for the 2013 IRP without Colstrip in the Company’s resource portfolio and show “… estimates of the impact on Net Present Value (cost) of its portfolio and rates”. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 265 of 1125 Modeling Approach UTC: Finds the efficient frontier analysis to be informative in highlighting the tradeoff between risk and cost when choosing resources. UTC: Support the continued improvement of modeling for the IRP “… and urge the Company to explore its thinking and strategy with the TAC (technical advisory committee) at an early date.” Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 266 of 1125 Preferred Resource Strategy IPUC: Supports increased levels of energy efficiency. Should also include analysis and consideration of cost-effective demand response in the next IRP. IPUC: Tipping point analysis is beneficial to test how robust the PRS is and to point out which variables are most important to the PRS. UTC: Sensitivity analyses were informative. High and low load growth cases (50% of expected load growth) is too improbable as a tipping point. Want to see this refined. Should include “… load growth variances that result in incremental changes to the PRS, such as the delaying the acquisition of the 2018 SCCT.” Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 267 of 1125 Action Plan IPUC: The Company made progress on the 2009 IRP Action Items and the 2011 Action Items should enhance the 2013 IRP. UTC: 2011 Action Plan is presented well and is well grounded in the modeling and analysis. UTC: encourages close monitoring of actual load growth and changes in the market which may require changes to the PRS and the Action Plan. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 268 of 1125 Energy Independence Act Compliance & Forecast John Lyons, Power Supply Analyst James Gall, Senior Power Supply Analyst First Technical Advisory Committee Meeting 2013 Electric Integrated Resource Plan May 23, 2012 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 269 of 1125 Energy Independence Act RCW 19.285 – The Energy Independence Act is also known as Initiative Measure No. 937 (I-937) Requires utilities with more than 25,000 customers to obtain fifteen percent of their electricity from qualified renewable resources by 2020. Also requires the acquisition of all cost-effective energy conservation. I-937 approved by Washington voters on November 6, 2006. 2 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 270 of 1125 Reporting Requirements Annual compliance report, per WAC 480-109-040, is due on or before June 1st beginning in 2012 and must include the following: Utility’s annual Washington load for the prior two years, Amount of eligible renewable resources and/or renewable resource credits needed to meet annual goal by January 1 of the target year, Amount and cost of each type of eligible resource used, Amount and cost of any renewable energy credits acquired, Type and cost of the least-cost substitute non-eligible resources available, Incremental cost of eligible renewable resources and renewable energy credits, and The ratio of this investment relative to the utility's total annual retail revenue requirement. 3 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 271 of 1125 Renewable Energy Requirements Based on a percentage of Washington state retail sales using two year rolling average 3% of sales by January 1, 2012 9% of sales by January 1, 2016 15% of sales by January 1, 2020 4 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 272 of 1125 2012 Legislative Modifications SB 6414: Review Process for Electric Generation Project or Conservation Review SB 5575: Biomass Bill Avista’s 50 MW Kettle Falls plant becomes a “qualified renewable resource” beginning January 1, 2016 for the Energy Independence Act 5 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 273 of 1125 2012 Projected Compliance aMW Required Renewable Energy 18.9 Spokane River Long Lake #3 1.6 Little Falls #4 0.6 Clark Fork River Cabinet Gorge 2-4 10.8 Noxon Rapids 1-4 5.8 Wanapum Fish Bypass 2.0 Total Hydro Upgrades 20.8 Palouse Wind (2012) TBD 6 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 274 of 1125 Long-Term Renewable Energy Requirements & Compliance Forecast 0 20 40 60 80 100 120 140 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 av e r a g e m e g a w a t t s Qualifying Hydro Upgrades Kettle Falls Palouse Wind Purchased RECs Potential Banking Requirement & Contingency Requirement 7 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 275 of 1125 Work Plan John Lyons, Power Supply Analyst First Technical Advisory Committee Meeting 2013 Electric Integrated Resource Plan May 23, 2012 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 276 of 1125 Technical Advisory Committee Meetings May 23, 2012: Powering Our Future Game, 2011 Renewable RFP, Palouse Wind Project Update, 2011 IRP Acknowledgements, Energy Independence Act Compliance & Forecast, and 2013 Work Plan. September 2012: Two day TAC meeting. Day 1: Plant tour. Day 2: new resource assumptions, Spokane River assessment, and energy efficiency. November 2012: Load & resource forecast, reliability planning, stochastic assumptions, and transmission cost studies. January 2013: Environmental policy update, electric and gas price forecasts, scenario development. March 2013: Draft Preferred Resource Strategy (PRS), energy efficiency, review of scenarios and futures, and portfolio analysis. April 2013: Review of the final PRS and action items. June 2013: Review of the Draft 2013 IRP. 2 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 277 of 1125 2013 Draft Electric IRP Timeline Preferred Resource Strategy (PRS) Tasks Target Date Finalize load forecast July 2012 Identify regional resource options for electric market price forecast September 2012 Identify Avista’s supply & conservation resource options September 2012 Update AURORAxmp database for electric market price forecast October 2012 Finalize data sets/statistics variables for risk studies October 2012 Draft transmission study due October 2012 Energy efficiency load shapes input into AURORAxmp October 2012 Final transmission study due November 2012 Select natural gas price forecast December 2012 Finalize deterministic base case December 2012 Base case stochastic study complete January 2013 Finalize PRiSM 3.0 model January 2013 Develop efficient frontier and PRS January 2013 Simulation of risk studies “futures’ complete February 2013 Simulate market scenarios in AURORAxmp February 2013 Evaluate resource strategies against market and future scenarios March 2013 Present preliminary study and PRS to TAC March 2013 3 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 278 of 1125 2013 Draft Electric IRP Timeline Writing Tasks Target Date File 2013 IRP Work Plan August 2012 Prepare report and appendix outline September 2012 Prepare text drafts April 2013 Prepare charts and tables April 2013 Internal drafts released at Avista May 2013 External draft released to the TAC June 2013 Final editing and printing August 2013 Final IRP submission to Commissions and distribution to TAC August 31, 2013 4 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 279 of 1125 2013 Integrated Resource Plan Modeling Process Preferred Resource Strategy AURORA “Wholesale Electric Market” 500 Simulations PRiSM “Avista Portfolio” Efficient Frontier Fuel Prices Fuel Availability Resource Availability Demand Emission Pricing Existing Resources Resource Options Transmission Resource & Portfolio Margins Conservation Trends Existing Resources Avista Load Forecast Energy, Capacity, & RPS Balances New Resource Options & Costs Cost Effective T&D Projects/Costs Cost Effective Conservation Measures/Costs Mid-Columbia Prices Stochastic Inputs Deterministic Inputs Capacity Value Avoided Costs 5 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 280 of 1125 2013 Electric IRP Draft Outline Executive Summary Introduction and Stakeholder Involvement Loads and Resources Economic Conditions Avista Load Forecast Load Forecast Scenarios Avista Resources and Contracts Reserve Margins Resource Requirements 6 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 281 of 1125 2013 Electric IRP Draft Outline Energy Efficiency and Demand Response Conservation Potential Assessment Overview of Energy Efficiency Potentials Sensitivity of Potential to Customer and Economic Growth Avoided Cost Sensitivities Energy Efficiency Related Financial Impacts Integrating Results into Business Planning and Operations Policy Considerations Environmental Concerns Greenhouse Gas Issues State and Regional Level Policies 7 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 282 of 1125 2013 Electric IRP Draft Outline Transmission & Distribution Avista’s Transmission System Regional Transmission Issues Transmission Construction Costs Integration of Resources on the Avista Transmission System Distribution Efficiencies Generation Resource Options Assumptions New Resources Hydroelectric and Thermal Plant Upgrades 8 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 283 of 1125 2013 Electric IRP Draft Outline Market Analysis Assumptions and Fuel Prices Market Price Forecasts Scenario Analysis Preferred Resource Strategy Resource Selection Process Preferred Resource Strategy Efficient Frontier Analysis Avoided Costs Portfolio Scenarios Action Items 9 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 284 of 1125 Avista’s 2013 Electric Integrated Resource Plan Technical Advisory Committee Meeting No. 2 Agenda Wednesday, September 5, 2012 Conference Room 328 Topic Time Staff 1. Introduction 8:30 Storro 2. Avista REC Planning Methods 8:35 Gall 3. Energy and Economic Forecasts 9:00 Forsyth 4. Break 10:30 5. Shared Value Report 10:45 Wuerst 6. Lunch 11:30 7. Generation Options 12:30 Lyons 8. Break 1:30 9. Spokane River Assessment 1:45 Schwall 10. Adjourn 3:00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 285 of 1125 Avista REC Planning Methods James Gall, Senior Power Supply Analyst Second Technical Advisory Committee Meeting 2013 Electric Integrated Resource Plan September 5, 2012 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 286 of 1125 Energy Independence Act - Refresher RCW 19.285 – The Energy Independence Act is also known as Initiative Measure No. 937 (I-937) Requires utilities with more than 25,000 customers to obtain fifteen percent of their electricity from qualified renewable resources by 2020. Also requires the acquisition of all cost-effective energy conservation. I-937 approved by Washington voters on November 6, 2006. 2 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 287 of 1125 Renewable Energy Requirements - Refresher Based on a percentage of Washington state retail sales using two year rolling average 3% of sales by January 1, 2012 9% of sales by January 1, 2016 15% of sales by January 1, 2020 3 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 288 of 1125 2011 IRP Planning Margin Requirements In past IRP’s Avista included a REC planning margin for the variability of load and generation due to weather for compliance of the EIA. The 2011 IRP included a planning margin of 7 to 8 aMW between 2012 and 2016 and 23+ aMW after 2016 to account for wind variability This planning margin was a threshold for the minimum amount of additional REC’s to hold over the expected requirement. 4 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 289 of 1125 What Has Changed Since 2011 IRP Load forecast is lower Signed 105 MW PPA for Palouse Wind Washington SB 5575 counts Kettle Falls as “renewable” beginning in 2016 Hydro upgrades may use long-term average incremental energy rather than estimated actual incremental energy for compliance 5 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 290 of 1125 What Planning Margin Do We Need Now? Develop risk model of REC compliance o Simulates future loads and qualifying wind, hydro, and biomass output o Accounts for actual and potential REC purchases and sales o Simulates 100 future outcomes Model allows RECs to be “Rolled” over to future years o Does not allow bring RECs back from future years o Pulling REC’s from future years is allowed but creates a short position that would be needed to be filled Tested several REC scenarios and the effects of policy choices Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 291 of 1125 Risk Assumptions Load: Expected Forecast with Standard Deviation of 4.2% of Mean with a normal distribution Hydro: 1986 to 2011 upgrade estimated energy savings (random draw) Palouse: 1990 to 2010 estimates provided by First Wind (random draw) Kettle Falls: Expected to run 10 out of 12 months with standard deviation at 5% of mean with a normal distribution. Assumes 75% of fuel counts as renewable Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 292 of 1125 REC Planning Margin Over Time 2015 (aMW) 2020 aMW Scenario Expected REC Position 5th Confidence Level REC Position Implied Planning Margin Expected 2020 REC Position (aMW) 2009 Status Higher load forecast, no Palouse or Kettle Falls, Hydro is variable, no EWEB purchase, no Wanapum RECs -3.1 -9.6 6.5 91.3 2009 with “Hydro Methodology 3”: Same study as above with 10 year historical hydro -0.9 -1.9 1.0 89.0 Today’s expectations Lower load forecast, Palouse signed, Kettle Falls Counts, Hydro is flat, EWEB sold through 2014. Long Long Zero Zero Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 293 of 1125 2013 IRP Implications REC surplus exceeds potential planning margin requirements No REC planning margin will be included for this IRP to meet the EIA Planning margins will be taken into account when selling excess RECs Without Kettle Falls we would have a 9.9+ aMW Planning Margin for Load/Wind Variation (assumes hydro is fixed) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 294 of 1125 Commerce REC Filing Handout: http://www.commerce.wa.gov/site/1001/default.aspx Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 295 of 1125 TAC Economic Outlook September 5, 2012 Grant D. Forsyth, Ph.D. Chief Economist 509-495-2765 Grant.Forsyth@avistacorp.com Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 296 of 1125 Goals of Update Highlight national and regional economic conditions that impact customer and usage forecasts. Highlight long-run issues related long-run growth and fiscal consolidation. Review most recent electric load forecast. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 297 of 1125 National GDP Growth and Inflation: Recent Global Insight (GI) Forecasts Data Source: BEA, Global Insight, and author’s calculations.  Modest growth with increasing downside risks to growth in 2012 and 2013: Europe, Asia, and Congress (aka “Fiscal Cliff”).  Housing market appears to be stabilizing. 2.9 2.8 3.3 2.6 2.2 2.4 3.4 2.6 2.1 1.8 2.8 2.6 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 2012 Forecast 2013 Forecast 2014 Forecast Long-Run Average Forecast 2015-2041 Re a l G D P G r o w t h ( % ) Comparison of Global Insight Forecasts for U.S. GDP Growth May 2011 GI Forecast June 2012 GI Forecast August 2012 GI Forecast Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 298 of 1125 SA Employment Index in Key MSAs, June 2009-July 2012 Data Source: BLS and author’s calculations.  Employment levels similar to late 2009. Employment is growing in big metro areas. Holding down service area population growth and household formation. 94 96 98 100 102 104 106 Ju n e 2 0 0 9 = 1 0 0 Nez Perce+Asotin ID-WA Jackson, OR Spokane+Kootenai WA-ID Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 299 of 1125 SA Employment Index for Avista’s Service Area, June 2009-July 2012 Data Source: BLS and author’s calculations. 94 95 96 97 98 99 100 101 102 103 Ju n e 2 0 0 9 = 1 0 0 U.S.Avista MSAs Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 300 of 1125 Unemployment Rate for July, 2009-2012 Data Source: BLS and author’s calculations.  Jackson, OR (Medford MSA) has fallen the most, rates still high.  Some of the declines reflect a falling labor force from discourage workers “dropping out.”  Expect unemployment rates to remain elevated for rest of 2012 and into 2013. 0% 2% 4% 6% 8% 10% 12% 14% Nez Perce+Asotin ID-WA Spokane+Kootenai WA-ID Whitman, WA 6-Border WA-ID Jackson, OR Ju l y U n e m p l o y m e n t R a t e Jul-09 Jul-10 Jul-11 Jul-12 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 301 of 1125 Spokane+Kootenai Leading Indicator, 2011-2012 Data Source: Global Insight and author’s calculations.  Highly correlated with employment changes 12 to 15 months in advance. Signaling very slow employment growth for the rest of 2012 and through the first half of 2013. 74 76 78 80 82 84 86 88 90 92 Spokane-Kootenai Regional Leading Index, March 2004 = 100 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 302 of 1125 Old vs. New Long-Run: Annualized Employment and Population Growth in Spokane+Kootenai 1990 2007 2011 +2.7% -1.6% Data Source: BLS and author’s calculations. +1.5% to +1.8% Population Growth Regional Population Growth = (U.S. Employ. Growth, Regional Employ. Growth) (-) (+) +1.1% to +1.3% 2021 Employment Growth = (U.S. Real GDP Growth) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 303 of 1125 The Potential Drag of Fiscal Consolidation: Government Transfer Payments to Total Personal Income, 2007 and 2010 Data Source: BEA and author’s calculations. Message: Be careful what you ask for in terms of smaller government when government is an important part of your economy. 12% 32% 27%26% 20% 23% 16% 18% 8% 17% 38% 35% 33% 24% 26% 18% 22% 11% 0% 5% 10% 15% 20% 25% 30% 35% 40% Washington Ferry Pend Oreille Stevens Adams Lincoln Whitman Spokane King Re l a t i v e S h a r e Share of Government Payments for Selected Counties, 2007 and 2010 2007 Gov. Transfer Payments/Personal Income 2010 Gov. Transfer Payments/Personal Income Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 304 of 1125 The Potential Drag of Fiscal Consolidation: Government Employment as a Share of Total Employment, 2007 and 2010 Data Source: BEA and author’s calculations. 16% 37% 35% 21%22% 35% 44% 14% 11% 17% 40%39% 23%22% 33% 43% 15% 12% 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% Washington Ferry Pend Oreille Stevens Adams Lincoln Whitman Spokane King Re l a t i v e S h a r e Share of Government Employment for Selected Counties, 2007 and 2010 2007 Government Emp./Non-Farm Emp.2010 Government Emp./Non-Farm Emp. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 305 of 1125 Looking Forward: Other Issues Potentially Impacting Growth • Aerospace firms have shown robust growth. This should continue given Boeing’s order book. Potential new 737 plant not in forecast. •Air force is moving ahead with the evaluations of bases for refueling tankers. The 10 finalists will be chosen by late summer 2012. Those chosen for expansion will be announced at year-end. • Changes in the price of natural gas. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 306 of 1125 Native Load Forecast Lower 900 1,000 1,100 1,200 1,300 1,400 1,500 1,600 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 Av e r a g e M W i n c l u d i n g l o s s e s Avista Combined Native Load Washington and Idaho F2013 F2012 F2011 F2010 F2008 Forecast 2013-2023 (adjusted for EVs) Actual to May 2012 Forecast Native Load Growth Rates from 2013 5 yr = 1.04% 10 yr = 0.95% 22 yr = 1.01% Forecast Customer Growth Rates from 2013 5 yr = 1.3% 10 yr = 1.2% 22 yr = 1.1% 1997-2000 3.0% p.a. 2001-2008 2.0% p.a. 2009-2011 0.6% p.a. 1.3% p.a. 1.0% p.a. Reflects weaker sales to commercial and industrial customers. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 307 of 1125 Annual Residental Use Per Customer, 1997-2035 7,000 8,000 9,000 10,000 11,000 12,000 13,000 14,000 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 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 20 3 5 An n u a l k W h R e s i d e n t i a l Electric Average Use per Average Customer Weather Adjusted Residential Residential w/o PEV Electric Car Impact Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 308 of 1125 “Together We Will Build Shared Value” Avista’s 2012 report on our performance Technical Advisory Committee Sept. 5, 2012 Jessie Wuerst, Sr. Communications Manager Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 309 of 1125 Cross-Company Shared Value Action Team Consumer Affairs Customer Service Electric Operations Energy Solutions/DSM Environmental Facilities Gas Operations Generation & Production Health & Safety Human Resources Rates Resource Planning Supply Chain Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 310 of 1125 The business case for reporting • Increase opportunities to build understanding of Avista’s operations for all stakeholders • Provide information that stakeholder groups want to know about • Create opportunities for discussing partnerships with stakeholders that bring value to all • Enhance transparency of Avista as a business to build trust and two-way communication Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 311 of 1125 The “Shared Value” Pyramid Creating Shared Value Customers, Shareholders, Communities, Employees Sustainability Protect the future Compliance Laws, Licenses, Codes of Conduct, Philanthropy Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 312 of 1125 Shared Value – Changing Business Practices “The principle of shared value…involves creating economic value in a way that also creates value for society by addressing its needs and challenges. Businesses must reconnect company success with social progress. Shared value is not social responsibility, philanthropy, or even sustainability, but a new way to achieve economic success.” Harvard Business Review – Jan. 2011 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 313 of 1125 Shared Value – An Opportunity Shared value opportunities are core to Avista’s vision: “Delivering reliable energy service and the choices that matter most to you” Avista operations, programs, people Underlying community/society issues Avista strategic plans A snapshot in time of what Avista does well that grows our business and at the same time provides “social” value Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 314 of 1125 • Customer Engagement • Improvement and innovation • Safe & reliable infrastructure • Responsible resources • Regulatory outcomes • People and culture • Community partnership • Financial strength Shared Value reporting should focus on: Linking business strategic priorities and what we know is of interest/concern to customers, media, investors and other stakeholders • Customer Satisfaction • Power quality & Reliability • Corporate Citizenship – Philanthropy Community involvement Environmental stewardship • Energy Efficiency programs • Communications Shared Value Opportunities Avista Strategic Priorities External Priorities Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 315 of 1125 How can we most effectively share this information with stakeholders? Segment stakeholders, identify current points of contact with each group and insert messaging throughout the year… Bill insert Newsletter Social Media Website Community presentations (RBMs etc.) Employees e.g. account executives Employee communications: quarterly meetings, eview, View Editorial board meetings News releases Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 316 of 1125 An integrated family of reports Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 317 of 1125 Materiality Matters Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 318 of 1125 Questions or Comments? Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 319 of 1125 Generation Options John Lyons, Senior Resource Policy Analyst Second Technical Advisory Committee Meeting 2013 Electric Integrated Resource Plan September 5, 2012 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 320 of 1125 Supply Side Resource Data Sources • Northwest Power and Conservation Council – 6th Northwest Power Plan • Internally developed resource lists from: • Trade journals • Press releases from other companies • Engineering studies and other models • State commission announcements • Proposals from developers • Consulting firms and reports • State and federal resource studies and publications • Data sources are used to check and refine generic resource assumptions 2 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 321 of 1125 Natural Gas-Fired Resources 3 Resource Type First Year Size (MW) Levelized Overnight Costs (2012 $/MWh) * Capital Cost Excludes AFUDC (2012$) SCCT (aero) 2015 100 $79 $1,101/kW SCCT (frame EA) 2015 166 $81 $845/kW SCCT (frame FA) 2015 175 $70 $728/kW Hybrid SCCT 2015 92 $75 $1,114/kW CCCT (air) 2017 270 $70 $1,117/kW Reciprocating Engine 2015 113 $76 $1,060 /kW * Prices are based on a preliminary natural gas price forecast Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 322 of 1125 Other Thermal Resources 4 Resource Type First Year Size (MW) Levelized Overnight Costs (2012 $/MWh) Capital Cost Excludes AFUDC (2012$) Coal (Super-critical) 2018 300 $97 $3,100/kW Coal (IGCC) 2014 300 $127 $4,000/kW Coal (IGCC w/sequestration) 2018 250 $170 $6,000/kW Nuclear 2023 100* $173 $7,000/kW Small Scale Nuclear 2023 25 $107 $4,000/kW * This represents a 100 MW of a 1,100 MW plant. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 323 of 1125 Renewable and Storage Resources 5 Resource Type First Year Size (MW) Levelized Overnight Costs (2012 $/MWh) Capital Cost Excludes AFUDC (Nominal 2012) Wind (On System) 2013 100 $115 $2,140/kW Wind (Off System) 2013 100 $123 $2,140/kW Geothermal 2017 15 $104 $4,000/kW Wood Biomass 2015 25 $160 $4,000/kW Landfill Gas 2014 3.2 $106 $2,500/kW Manure Digester 2013 0.85 $144 $4,500/kW Waste Water Treatment 2014 0.85 $109 $4,500/kW Solar Photovoltaic 2014 5 $312 $3,500/kW Solar Thermal 2014 50 $414 $6,500/kW Battery Storage 2015 5 $126 $4,000/kW Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 324 of 1125 Avista Upgrade Alternatives • Avista thermal upgrades • Rathdrum CT • Coyote Springs 2 • Avista hydroelectric upgrades • Spokane River Project • Clark Fork River Project 6 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 325 of 1125 7 $414 $312 $173 $170 $160 $144 $127 $126 $123 $115 $109 $107 $106 $104 $97 $81 $79 $76 $75 $70 $70 $0 $100 $200 $300 $400 $500 Solar Thermal Solar Photovoltaic Nuclear Coal (IGCC w/ Seq) Wood Biomass Manure Digester Coal (IGCC) Battery Storage Wind Off System Wind On System Waste Water Treatment Small Scale Nuclear Landfill Gas Geothermal Coal (Super-Critical) Frame EA CT Aero CT Reciprocating Engine Intercooled CT Frame FA CT CCCT (1x1) w/ duct burner (air) New Resource Options Levelized Costs ($/MWh) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 326 of 1125 Hydro Modernization Initiative Modernize Avista’s existing fleet of hydro resources to: Generate incremental energy to meet load growth Produce RECs to meet renewable portfolio standards Increase plant efficiency through utilization of new technology Reduce risk through improved reliability and environmental mitigation Clean Resources Develop long-term strategy to assess and prioritize Spokane River plant opportunities, and study Cabinet Gorge modifications to mitigate total dissolved gas issues Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 327 of 1125 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 328 of 1125 Value Proposition Improve reliability by replacing aging equipment Improve performance (energy and capacity) through technology advancements Produce renewable energy credits to meet RPS requirements Take advantage of favorable tax treatment Possible resolution of total dissolved gas issues Clean Resources Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 329 of 1125 Spokane River Project Clean Resources •Spokane River was built out in the late 1800’s and early 1900’s to meet the growing demands of the Spokane region. •Undersized by today’s design standards for hydro development capturing 30% – 60% of available water Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 330 of 1125 Spokane River Project Clean Resources Original Monroe Street Powerhouse Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 331 of 1125 Current Spokane River Project Clean Resources Facility Year Built Generation Capability (MW) Net Energy Output (MWh) Post Falls 1906 14.8 90,000 Upper Falls 1922 10.0 71,000 Monroe St 1992 14.8 106,000 Nine Mile 1908 26.4 101,000 Long Lake 1915 78.0 480,000 Little Falls 1910 32.0 201,000 Total 176.0 1049,000 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 332 of 1125 Spokane River Project Flow Duration Curve Clean Resources Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 333 of 1125 Spokane River Assessment Clean Resources Goals of the Spokane River Assessment: •Fully develop the Spokane River - Capture 70% - 80% •Provide cost effective generation alternatives to meet resource needs • Increase plant efficiency and reliability •Address environmental and regulatory considerations Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 334 of 1125 0 50 100 150 200 250 300 350 400 450 0 10 20 30 40 50 60 70 80 Mo n r o e S t r e e t U n i t 1 Ni n e M i l e U n i t s 3 & 4 Ca b i n e t U n i t 1 Lo n g L a k e U n i t 4 Lit t l e F a l l s U n i t 3 Lo n g L a k e U n i t 1 Lo n g L a k e U n i t 2 Lo n g L a k e U n i t 3 Ca b i n e t U n i t 3 Lit t l e F a l l s U n i t 4 Ca b i n e t U n i t 2 Ca b i n e t U n i t 4 No x o n U n i t 1 No x o n U n i t 3 No x o n U n i t 2 No x o n U n i t 4 Ni n e M i l e U n i t s 1 & 2 Lit t l e F a l l s U n i t 1 Lit t l e F a l l s U n i t 2 Up p e r F a l l s 2 n d P o w e r h o u s e Nin e M i l e N e w P h s e Lo n g L a k e 2 n d P h s e Ca b i n e t G o r g e 2 n d P h s e Po s t F a l l s R e d e v e l o p Mo n r o e S t r e e t 2 n d P h s e 1992 1994 1994 1994 1994 1996 1997 1999 2001 2001 2004 2007 2009 2010 2011 2012 2015 2015 2016 Cu m u l a t i v e C a p a c i t y ( M W ) In c r e m e n t a l C a p a c i t y ( M W ) Planned 12 MW Clean Resources A History of Hydro Upgrades Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 335 of 1125 A History of Hydro Upgrades Clean Resources - 200.0 400.0 600.0 800.0 1,000.0 1,200.0 0 20 40 60 80 100 120 140 160 180 Mo n r o e S t r e e t U n i t 1 Ni n e M i l e U n i t s 3 & 4 Ca b i n e t U n i t 1 Lo n g L a k e U n i t 4 Li t t l e F a l l s U n i t 3 Lo n g L a k e U n i t 1 Lo n g L a k e U n i t 2 Lo n g L a k e U n i t 3 Ca b i n e t U n i t 3 Li t t l e F a l l s U n i t 4 Ca b i n e t U n i t 2 Ca b i n e t U n i t 4 No x o n U n i t 1 No x o n U n i t 3 No x o n U n i t 2 No x o n U n i t 4 Ni n e M i l e U n i t s 1 & 2 Li t t l e F a l l s U n i t 1 Li t t l e F a l l s U n i t 2 Up p e r F a l l s 2 n d P o w e r h o u s e Ni n e M i l e N e w P h s e Lo n g L a k e 2 n d P h s e Ca b i n e t G o r g e 2 n d P h s e Po s t F a l l s R e d e v e l o p Mo n r o e S t r e e t 2 n d P h s e 1992 1994 1994 1994 1994 1996 1997 1999 2001 2001 2004 2007 2009 2010 2011 2012 2015 2015 2016 Cu m u l a t i v e E n e r g y G W h In c r e m e n t a l E n e r g y G W h Future Study 600 GWh Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 336 of 1125 Post Falls Possible Modifications Clean Resources New Powerhouse in the South Channel - 40 MW (2x20) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 337 of 1125 Post Falls Possible Modifications Clean Resources Replace Existing Powerhouse - 40 MW (5x8) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 338 of 1125 Post Falls Possible Modifications Clean Resources Rebuild Existing Powerhouse Turbine Generators - 33.6 MW (6x5.6) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 339 of 1125 Upper Falls Possible Modifications Clean Resources Second Powerhouse with Channel Excavation – 40 MW Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 340 of 1125 Monroe Street Possible Modifications Clean Resources Second Powerhouse – with Channel Excavation 80 MW Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 341 of 1125 Monroe Street Possible Modifications Clean Resources Second Powerhouse – with Tunnel 80 MW Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 342 of 1125 Monroe Street Possible Modifications Clean Resources Second Powerhouse – From Monroe Street Dam 44 MW Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 343 of 1125 Nine Mile Possible Modifications Clean Resources Existing Powerhouse Upgrade Units 1 and 2 – 32MW (4x8) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 344 of 1125 Nine Mile Possible Modifications Clean Resources New Powerhouse Downstream Left Bank – 60 MW (3x20) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 345 of 1125 Nine Mile Possible Modifications Clean Resources New Powerhouse Downstream Left Bank – 60 MW (5x12) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 346 of 1125 Nine Mile Possible Modifications Clean Resources New Powerhouse Existing Location – 60 MW (5x12) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 347 of 1125 Long Lake Possible Modifications Clean Resources Replace Turbine Generators 120 MW (4x30) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 348 of 1125 Long Lake Possible Modifications Clean Resources Section View - Replace Turbine Generators 120 MW (4x30) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 349 of 1125 Long Lake Possible Modifications Clean Resources Second Powerhouse from Saddle Dam - 68MW Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 350 of 1125 Little Falls Powerhouse Rebuild Clean Resources • Replace Generators • Replace Turbines • Replace Generator Breakers • Replace Excitation Systems • New Modern Control System • New Powerhouse Crane Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 351 of 1125 Spokane River Project Potential Clean Resources Facility Year Built Generation Capability (MW) Net Energy Output (MWh) Upgraded Capability (MW) Upgraded Energy (MWh) Post Falls 1906 14.8 90,000 33.6 142,500 Upper Falls 1922 10.0 71,000 50.0 184,200 Monroe St 1992 14.8 106,000 58.8 223,600 Nine Mile 1908 26.4 101,000 60.0 221,500 Long Lake 1915 78.0 480,000 146.0 619,800 Little Falls 1910 32.0 201,000 32.0 201,000 Total 176.0 1049,000 380.4 1,592,600 Percent Increase 116% 52% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 352 of 1125 Clark Fork River Project Clean Resources •Clark Fork River Project was built in the 1950’s and 1960’s to meet the growing demands of the Spokane region. •Cabinet Gorge completed in 1952 •Noxon Rapids completed in 1960 •5th Unit was added in 1978 •Improvements to date include •New Turbines - efficiency upgrades •New Generators and rewinds •New Generator Step-Up Transformers Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 353 of 1125 Cabinet Gorge HED Refurbishment : •Replaced 4 turbine runners & rebuilt generators •Refurbished other turbine generator parts to like new condition •Upgraded plant from 220 MW to 270 MW •Environmentally friendly features – greaseless bearings and more efficient turbines •Upgrade costs $5 to $12M, total $40M •Complete in 2004 Clean Resources Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 354 of 1125 Clean Resources Noxon Rapids HED Refurbishment • Replaced Units 1- 4 turbine runners & rebuilt generators • Replaced Unit 5 generator • Refurbish other turbine generator parts to like new condition • Replaced GSU Transformers • Upgraded plant from 548 MW to 598 MW • Environmentally friendly features – greaseless bearings and more efficient turbines • Upgrade costs $9 to $17M, total $77M • Completed in May2012 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 355 of 1125 Cabinet Gorge Possible Modifications Clean Resources Second Powerhouse in Tunnel Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 356 of 1125 Cabinet Gorge Possible Modifications Clean Resources •Increased plant capacity will reduce Spring spillway flows, and thus reduce contributions to total dissolved gas (TDG) •Could increase plant capacity by 55 - 110 MW •Range of plant configurations under study Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 357 of 1125 Avista’s 2013 Electric Integrated Resource Plan Technical Advisory Committee Meeting No. 3 Agenda Wednesday, November 7, 2012 Conference Room 328 Topic Time Staff 1. Introduction 8:30 Storro 2. Modeling 8:35 Gall 3. Colstrip Discussion 9:15 Lyons 4. Energy Efficiency 10:00 Borstein 5. Lunch 11:30 6. Peak Load Forecast 12:30 Gall/Forsyth 7. Reliability Planning 1:15 Gall 8. Break 2:00 9. Energy Storage 2:15 Lyons Adjourn 3:00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 358 of 1125 Materiality Ratings Avista’s 2013 Electric Integrated Resource Plan Technical Advisory Committee Weighted score – number of responses x rated importance/relevance September 2012 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 359 of 1125 2013 IRP Modeling Approach James Gall, Senior Power Supply Analyst Third Technical Advisory Committee Meeting 2013 Electric Integrated Resource Plan November 7, 2012 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 360 of 1125 2013 IRP Modeling Process Preferred Resource Strategy AURORA “Wholesale Electric Market” 500 Simulations PRiSM “Avista Portfolio” Efficient Frontier Fuel Prices Fuel Availability Resource Availability Demand Environmental Considerations Existing Resources Resource Options Transmission Resource & Portfolio Margins Conservation Trends Existing Resources Avista Load Forecast Energy, Capacity, & RPS Balances New Resource Options & Costs Cost Effective T&D Projects/Costs Cost Effective Conservation Measures/Costs Mid-Columbia Prices Stochastic Inputs Deterministic Inputs Capacity Value Avoided Costs Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 361 of 1125 3rd party software- EPIS, Inc. Electric market fundamentals- production cost model Simulates generation dispatch to meet load Outputs: – Market prices – Regional energy mix – Transmission usage – Greenhouse gas emissions – Power plant margins, generation levels, fuel costs – Avista’s variable power supply costs Electric Market Modeling Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 362 of 1125 PRiSM- Preferred Resource Strategy Model Internally developed using Excel based linear program model (What’s Best) Selects new resources to meet Avista’s capacity, energy, and renewable energy requirements Outputs: – Power supply costs (variable and fixed) – Power supply costs variation – New resource selection – Emissions – Capital requirements Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 363 of 1125 AURORA Inputs Regional loads Natural gas & coal prices Hydro levels Wind variation Environmental resolutions Resource availability Transmission Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 364 of 1125 Regional Loads Forecast load growth for all regions in the Western Interconnect Consider both peak and energy Use regional published studies and public IRP’s Stochastic modeling simulates load changes due to weather and considers regional correlation of weather patterns Load changes due to economic reasons are difficult to quantify and are usually picked up as IRP’s are published every two years Peak load is becoming more difficult to quantify as “Demand Response” programs my cause data integrity issues Energy demand forecasts need to be net of conservation Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 365 of 1125 California Northwest Desert SW Rocky Mountains Canada 0 50,000 100,000 150,000 200,000 250,000 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 20 3 5 MW Western Interconnect Peak Load Forecast Energy & Peak Forecast (draft) Energy AAGR Canada 1.91% Rocky Mtns. 0.69% Desert SW 1.64% California 0.48% Northwest 0.90% Peak AAGR Canada 1.80% Rocky Mtns. 0.98% Desert SW 1.71% California -0.26% Northwest 0.93% California Northwest Desert SWRocky Mountains Canada 0 50,000 100,000 150,000 200,000 250,000 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 20 3 5 Av e r a g e M W Western Interconnect Energy Forecast Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 366 of 1125 Electric Vehicles (PHEV) A potential change in customer load shapes could be a result of PHEV To address this- a load adder will be applied to reflect new demand with a majority of load added in off peak hours In the 2011 IRP electric vehicle demand was estimated to be 1,370 MW (off-peak) for 2020 (western interconnect) The load forecasts from other IRP’s typically include PHEV assumptions PHEV load will be pullout out of the forecast and modeled as load with an alternative load shape to reflect typical charging patterns Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 367 of 1125 Natural Gas Prices Natural gas prices are one of the most difficult inputs to quantify A combination of forward prices and consultant studies will be used as the “Base Case” for this IRP. This work should be complete by December 2012 500 different prices using an auto regressive technique will be modeled, the mean value of the 500 simulations will be equal to the “Base Case” forecast A controversial input for these prices is the amount of variance within the 500 simulation. – Historically prices we highly volatile, recent history is more stable – Final variance estimates will look at current market volatility and implied variance from options contracts Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 368 of 1125 Natural Gas Prices $0.00 $2.00 $4.00 $6.00 $8.00 $10.00 $12.00 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 $ p e r D t h 2011 IRP Forwards (6/1/12) Forwards (10/30/12) Actual Avista-Mid 2012 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 369 of 1125 Coal Prices With lower natural prices and EPA regulations the demand for US based coal is lower, but potential exports may stabilize the industry Western US coal plants typically have long-term contracts and many are mine mouth Rail coal projects are subject to diesel price risk Prices will be based on review of coal plant publically available prices and EIA mine mouth and rail forecasts Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 370 of 1125 Hydro 70 year average hydro conditions are used for the Northwest states, British Columbia and California provided by BPA – Hydro levels change monthly – AURORA dispatches the monthly hydro based on whether its run-of-river or storage. For stochastic studies the hydro levels will be randomly drawn from the 70 year record A new Columbia River Treaty could change regional hydro patterns, but until there is resolution, no changes will be considered Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 371 of 1125 Northwest Hydro Variability - 5,000 10,000 15,000 20,000 25,000 El Niño Neutral La Niña All Data Av e r a g e M e g a w a t t s Mean 2 Stdev High 2 Stdev Low Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 372 of 1125 Wind Wind generation in the Northwest’s is the fastest growing resource type RECs and PTC’s have caused wind facilities to economically generate in oversupply periods in the Northwest- particularly in the spring months Wind is modeled using an autoregressive technique to simulate output in similar to reported data available from BPA, CAISO, and other publically available data sources- also considers correlation between regions For stochastic studies several wind curves will be drawn from to simulate variation in wind output each year Will pursue temperature/wind correlation for stochastic study Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 373 of 1125 Wind Generation Profile (First week of January 2007-12) 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 1 7 13 19 25 31 37 43 49 55 61 67 73 79 85 91 97 10 3 10 9 11 5 12 1 12 7 13 3 13 9 14 5 15 1 15 7 16 3 Ca p a c i t y F a c t o r Hour of January Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 374 of 1125 Jan Feb Mar Apr May Jun Jul Aug 2011 8 10 4 31 39 85 25 0 2012 0 0 8 60 84 260 137 3 0 50 100 150 200 250 300 Mi d -Co l u m b i a P r i c e H o u r s B e l o w Z e r o Hours Mid-Columbia Prices Were Less Than $0/MWh 2011: 202 Hrs 2012: 552 Hrs Source: Powerdex daily average prices- substantially more hours had trades with negative pricing Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 375 of 1125 Greenhouse Emission Reduction Scheme Currently no eminent national climate change legislation Alternative methods for reducing greenhouse gases are more likely than a national cap-and-trade mechanism; such as early retirement of coal plants and regional greenhouse gas limits This IRP will model the CO2 tax in British Columbia and an expected market clearing price for CO2 in California Rather than use a cap & trade or tax method in the IRP base case the model will rather consider all announced coal plants retirements and determine future coal/natural gas plants likely to be retired due to environmental or economic reasons This method will show reductions to greenhouse gases in the western US without causing price shocks to the wholesale power markets Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 376 of 1125 Coal Retirements 0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 5,000 0 200 400 600 800 1,000 1,200 1,400 1,600 1,800 2,000 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 Cu m u l a t i v e C o a l M W t o b e R e t i r e d An n u a l C o a l M W T o B e R e t i r e d Announced Coal Plant Retirements Annual Cumulative Announced retirements of 13% of coal plant capacity in the west Avista will review all Western Interconnect coal plants and retire plants for modeling purposes. This method is to estimate likely EPA/State related retirements Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 377 of 1125 Water Issues Once-through cooling – California plants with this cooling technology must be converted to alternative cooling methods or retired – For modeling purposes: older natural gas units will be retired and Nuclear plants will be considered retrofitted – San Onofre? Traditional water cooling – New NG resources are finding it more difficult to use water cooling- for new resources air cooling will be assumed Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 378 of 1125 Once-Through Cooling Affect 13,500 MW of natural gas plants in California could be affected by once-through-cooling rules- nearly 4,000 MW announced retirement Represents 27% of California’s natural gas fleet 0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 0 200 400 600 800 1,000 1,200 1,400 1,600 1,800 2,000 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 Cu m u l a t i v e C o a l M W t o b e R e t i r e d An n u a l C o a l M W T o B e R e t i r e d Announced Natural Gas Plant Retirements Annual Cumulative Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 379 of 1125 Western State’s Renewable Portfolio Standards Nine western states have renewable portfolio standards (RPS) – A majority of qualifying projects will not be selected in AURORA due to economics, therefore renewable resources are added based likely resource types up to the RPS requirement Challenges are with California – What renewable quantity will CA allow for import- 25%? – How much behind the meter solar will be developed? Will state RPS’s change- easier or more stringent? – Washington recently allowed legacy biomass – Colorado increased its requirement from 10% to 30% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 380 of 1125 Transmission Expansion Regional transmission expansion plans have been discussed much of the last decade- with little to show for it! For modeling purposes- a review of the expansion opportunities will be discussed and projects that are in advanced stages of development will be included Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 381 of 1125 PRiSM Find optimal resource strategy to meet resource deficits over planning horizon Model selects its resources to reduce cost, risk, or both. Objective Function: – Minimize: Total Power Supply Cost on NPV basis (2014- 2054)- Focus on first 10 years of the plan – Subject to: •Risk level •Capacity need +/- deviation •Energy need +/- deviation •Renewable portfolio standards •Resource limitations, sizes, and timing Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 382 of 1125 Efficient Frontier  Demonstrates the trade off of cost and risk  Avoided Cost Calculation Ri s k Least Cost Portfolio Least Risk Portfolio Find least cost portfolio at a given level of risk Short-Term Market Market + Capacity + RPS = Avoided Cost Capacity Need + Risk Cost Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 383 of 1125 Colstrip Discussion John Lyons, Senior Resource Policy Analyst Third Technical Advisory Committee Meeting 2013 Electric Integrated Resource Plan November 7, 2012 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 384 of 1125 Future of Colstrip – Planning • Scenarios about the future of Colstrip will be modeled in this IRP • Washington Commission acknowledgement of the 2011 IRP: • “The Company should conduct a broad examination of the cost of continuing the operation of Colstrip over the 20-year planning horizon, including a range of anticipated costs associated with potential U.S. Environmental Protection Agency regulations on coal-fired generation.” • “The Company should model a scenario without Colstrip that includes results showing how Avista would choose to meet its load obligations without Colstrip in its portfolio, and estimates of the impact on Net Present Value (cost) of its portfolio and rates.” (Docket UE-101482) 2 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 385 of 1125 Colstrip Ownership Information 3 Colstrip Basic Data Colstrip Ownership Percentages Colstrip Unit # Size (MW) Year Online Avista NorthWestern Energy, LLC PacifiCorp Portland General Electric PPL Montana, LLC Puget Sound Energy Unit #1 307 1975 0% 0% 0% 0% 50% 50% Unit #2 307 1976 0% 0% 0% 0% 50% 50% Unit #3 740 1984 15% 0% 10% 20% 30% 25% Unit #4 740 1986 15% 30% 10% 20% 0% 25% Total 2,094 11% 11% 7% 14% 25% 32% Colstrip Units #1 – 4 use about one rail car (110 tons) of coal for every five minutes of operation – the whole project uses about 10 million tons of coal per year Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 386 of 1125 Colstrip Economic Benefits • The plant employs 360 people and the mine has 373 employees • $104 million in annual Montana state and local taxes (4.5% of all state revenue collections) • 3,740 additional jobs and 7,700 more residents in Montana • $360 million in additional personal income • $638 million more in additional Montana output Data from The Economic Contribution of Colstrip Steam Electric Station Units 1-4, November 2010. 4 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 387 of 1125 Colstrip – Importance as a Resource • Colstrip provides 222 MW of capacity for Avista • 1,416,000 MWh in 2011 (162 aMW) 5 Other includes: full load surge pond variable costs, environmental air pollution taxes, paste plant, coal handling, coal handling dust suppression, bottom ash handling, bottom ash hauling contract and coal conditioning costs. Coal, 80% Mercury Control, 5% Lime, 3% Gen/Wet Tax, 3% Scrubbers, 2%Water Treatment Chemicals, 1% Other, 5% Other, 20% 2013 Colstrip Units #3 & 4 Projected Full Load Variable Costs Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 388 of 1125 Colstrip Fuel Supply • Avista’s total annual fuel use at Colstrip is approximately 980,000 tons • Mine mouth facility • Current fuel contract expires at the end of 2019 • Currently negotiating a fuel supply extension 6 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 389 of 1125 Colstrip Modeling in the 2013 IRP Base Case: •Colstrip Units #3 – 4 kept in service through IRP modeling period •Will comply with current and future environmental regulations Colstrip Scenarios: •How many scenarios are needed? •What date or dates should be used to model a shut down of the plant? •Other assumptions? 7 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 390 of 1125 Avista Utilities Conservation Potential Assessment Approach for 2013 Update November 7, 2012 Jan Borstein Project Manager, Energy Analysis and Planning Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 391 of 1125 2 Outline CPA objectives Analysis approach – Update 2010 study – Changes in approach Project schedule Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 392 of 1125 3 CPA Objectives Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 393 of 1125 4 CPA objectives Assess and analyze 20-year cost-effective conservation potential Meet Washington I-937 Conservation Potential Assessment requirements – Biennium target for 2014-2015 Support Avista IRP development Provide information to support Business Plan development Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 394 of 1125 5 Analysis Approach Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 395 of 1125 6 CPA considerations The CPA approach accounts for the following factors Impacts of existing programs Impacts of codes and standards Technology developments and innovation Economic conditions Customer growth trends Energy prices Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 396 of 1125 7 Develop three levels of potential Potential studies identify future opportunities for EE that can be achieved through programs Technical EE Potential Theoretical upper limit of EE, where all efficiency measures are phased in regardless of cost Economic EE Potential EE potential, which includes measures that are cost-effective Achievable EE Potential EE potential that can be realistically achieved by utilities, accounting for customer adoption rates and how quickly programs can be implemented Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 397 of 1125 8 Consistency with Sixth Plan End-use model — bottom-up Building characteristics Fuel and equipment saturations Measure life Stock accounting Existing and new vintage Lost- and non-lost opportunities Measure saturation and applicability Measure savings, including contribution to peak Codes and standards Ramp rates to model market acceptance and program implementation Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 398 of 1125 9 Consistency with Sixth Plan (cont.) Measures Include nearly all in Sixth Plan Others also, e.g., conversion of electric water heaters and furnaces to natural gas Sources for measure characterization – Avista Technical Reference Manual (TRM ) – RTF measure workbooks – EnerNOC databases, some of same sources used in Sixth Plan Economic potential, total resource cost (TRC) test Considers non-energy benefits Achievable potential – ramp rates Based on Council Sixth Plan ramps rates Modified to reflect Avista program history Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 399 of 1125 10 Avista-specific items End-use model Building characteristics, fuel shares, and equipment saturations are Avista-specific Calibrated to Avista 2009 sales by sector Update with newly available RBSA data, e.g., information on measure saturation Measure savings, including contribution to peak Building codes and appliance standards updated as of 2012 Avista-specific customer growth forecasts Avista retail rate and avoided cost forecasts Ramp rates adjusted to match Avista program history Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 400 of 1125 11 Potential study analysis framework EE measure data Utility data Engineering analysis Secondary data Market segmentation and characterization Customer participation rates Technical and economic potential forecasts Achievable potential forecast Utility data Customer surveys Secondary data Base-year energy use by fuel, segment Baseline forecasting Supply curves Scenario analyses Custom analyses Project report End-use forecast by segment Prototypes and energy analysis Program results Survey data Secondary data Forecast data Synthesis / analysis Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 401 of 1125 12 LoadMAPTM analysis tool LoadMAP stands for Load Management, Analysis and Planning LoadMAP modeling features: – Embodies principles of rigorous end-use models (like REEPS and COMMEND) – Uses stock-accounting – Isolates new construction – Uses a simple decision logic – Models customized by end use From user’s perspective: – Excel-based model – Easy to update assumptions – Enables sensitivity analysis – Answers what-if questions Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 402 of 1125 13 Base-year energy consumption Base year is 2009 At start of past study in summer 2010, 2009 was most recent year with complete sales and customer data 2009 was also base year for Avista load research study, which provides peak data We will calibrate the first few years of the forecast to sales history Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 403 of 1125 14 Market segmentation by rate class Used 2009 base year sales data to develop control totals Number of customers, annual use, and peak load by sector Sector Rate Schedule(s) Number of meters (customers) 2009 Electricity sales (MWh) Peak demand (MW) Residential 001 299,714 3,634,086 993 General Service 011, 012 46,387 738,505 125 Large General Service 021, 022 4,808 2,256,882 347 Extra Large General Service 025, 025P 32 1,145,277 174 Extra Large GS Potlatch 025P 1 892,291 101 Pumping 031, 032 3,673 194,884 14 Total 354,615 8,861,961 1,753 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 404 of 1125 15 Market characterization Sector Segment Vintage End Use Space heating Air-source heat pump Geothermal heat pump Electric furnace Electric resistance Air-source heat pump SEER 13 SEER 14 SEER 15 SEER 16 Ductless Minisplit Technology Efficiency options Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 405 of 1125 16 Market characterization by segment Sector Customers 2009 Electricity sales (GWh) Residential 299,714 3,634,086 General Service 46,387 738,505 Large General Service 4,808 2,256,882 Extra Large GS 32 1,145,277 Extra Large GS Potlatch 1 892 Pumping 3,673 194,884 Total 354,615 8,861,961 Residential Segment Number of Customers Intensity (kWh/HH) Electricity Sales (GWh) Single family 168,339 14,250 2,398,874 Multi family 23,456 8,613 202,032 Mobile/Manufactured 10,022 12,724 127,523 Limited Income 97,896 9,251 905,656 Total 299,714 12,125 3,634,086 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 406 of 1125 17 Energy Market Profiles Market profiles – a snapshot of how customers use energy by end use and technology – Number of customers – Saturations – Unit energy consumption (UEC) or energy use intensity (EUI) – Peak factors — fraction of annual electricity use coincident with the system peak Existing (average) buildings and new construction Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 407 of 1125 18 Energy Market Profiles (continued) Sample for residential sector, all segments UEC Intensity Usage (kWh) (kWh/HH) (GWh) Cooling Central AC 29%1,613 470 141 Cooling Room AC 20% 643 131 39 Combined Heating/Cooling Air Source Heat Pump 14%5,051 699 209 Combined Heating/Cooling Geothermal Heat Pump 0%3,715 15 4 Space Heating Electric Resistance 18%6,114 1,119 335 Space Heating Electric Furnace 22%6,779 1,492 447 Space Heating Supplemental 9% 83 8 2 Water Heating Water Heater 66%2,796 1,834 550 Interior Lighting Screw-in 100%1,144 1,144 343 Interior Lighting Linear Fluorescent 66% 121 80 24 Interior Lighting Pin-based 92% 59 55 16 Exterior Lighting Screw-in 70% 301 211 63 Exterior Lighting High Intensity/Flood 2% 116 2 1 Appliances Clothes Washer 84% 105 88 26 Appliances Clothes Dryer 80% 621 498 149 Appliances Dishwasher 86% 185 160 48 Appliances Refrigerator 100% 746 746 224 Appliances Freezer 62% 760 474 142 Appliances Second Refrigerator 35% 787 277 83 Appliances Stove 86% 299 257 77 Appliances Microwave 95% 144 137 41 Electronics Personal Computers 121% 263 317 95 Electronics TVs 222% 311 688 206 Electronics Devices and Gadgets 100% 48 48 14 Miscellaneous Pool Pump 10%1,328 130 39 Miscellaneous Furnace Fan 26% 404 107 32 Miscellaneous Miscellaneous 100% 940 940 282 12,125 3,634 - Average Market Profile - Residential Sector End Use Technology Saturation Total Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 408 of 1125 19 Baseline forecasting Model equipment choices for replacement or new construction Define equipment efficiency options, up to 10 per technology Define baseline purchase shares —begin with Annual Energy Outlook shipments data and modified for Avista service territory or local data Building codes and appliance standards Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 409 of 1125 20 Baseline forecasting Air source heat pump example Efficiency Level Relative Energy Use Lifetime Standards Status 2011 Baseline Purchase Shares 2015 Baseline Purchase Shares E1 − SEER 13 100.0% 15 Baseline until 2014 78% 0% E2 − SEER 14 (ENERGY STAR) 91.7% 15 Baseline after 2014 0% 78% E3 − SEER 15 (CEE Tier 2) 88.6% 15 15% 15% E4 − SEER 16 (CEE Tier 3) 86.1% 15 7% 7% E5− Ductless Mini-split System 75.0% 15 0% 0% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 410 of 1125 21 Baseline forecasting Market size / customer growth Income growth Avista retail rates forecast Trends in end-use/technology saturations Equipment purchase decisions Cooling and heating degree day values Persons/household and physical home size Elasticities by end use for each variable (from client or default values based on EPRI REEPS and COMMEND models) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 411 of 1125 22 Baseline forecast – Residential Use per Household Use per household End Use 2009 (MWh) 2012 (MWh) 2017 (MWh) 2022 (MWh) 2027 (MWh) 2032 (MWh) % Change ('09–'32) Avg. growth rate Cooling 180,022 164,872 197,096 239,735 293,189 357,837 99% 3.0% Space Heating 784,854 783,258 906,261 1,051,822 1,210,093 1,383,665 76% 2.5% Heat & Cool 213,860 201,414 229,351 259,524 296,812 343,830 61% 2.1% Water Heating 549,606 557,026 611,989 675,078 748,532 830,990 51% 1.8% Appliances 790,377 776,522 796,390 837,724 899,380 996,282 26% 1.0% Interior Lighting 383,305 375,894 335,220 397,188 465,499 543,171 42% 1.5% Exterior Lighting 63,864 62,362 61,507 71,895 84,283 98,404 54% 1.9% Electronics 315,599 336,232 404,126 484,986 570,101 669,577 112% 3.3% Miscellaneous 352,599 374,582 448,055 540,785 650,016 779,045 121% 3.4% Total 3,634,086 3,632,162 3,989,994 4,558,738 5,217,905 6,002,803 65% 2.2% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 412 of 1125 23 Baseline forecast – Commercial & Industrial Total growth of 27.1% over forecast period Average annual growth of 1.04% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 413 of 1125 24 Baseline forecast summary — previous CPA Overall 48% growth in electricity use Average annual growth rate of 1.7% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 414 of 1125 25 Develop measure list using – Existing programs – RTF data – EnerNOC databases Characterization – Description – Costs – Savings – Applicability – Lifetime Update measure data – Avista TRM – RTF measure databases – BEST simulations – EnerNOC databases Measure identification & characterization Water heating measures Conventional (EF 0.95) Heat pump water heater (EF 2.3) Solar water heater Low-flow showerheads Timer / Thermostat setback Tank blanket Drainwater heat recovery Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 415 of 1125 26 Technical potential Technical potential Hypothetical case Most efficient option taken, regardless of cost Equipment is replaced at time of failure Other devices are phased in over time using a diffusion curve – Slope of curve varies according to complexity of measure and cost Label Water Heater Technology Relative Energy Use Off Market E1 EF 0.9 100.0% 2014 E2 EF 0.95 94.0% E3 EF 2.3 (HPWH) 39.1% E4 Solar 38.2% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 416 of 1125 27 Economic potential Assumptions Avoided costs forecasts for energy and capacity T&D line losses Administrative cost adders Total Resource Cost test for B/C ratio ≥ 1.0 Most efficient cost-effective option is selected Screening performed for every year Label Water Heater Technologies Relative Energy Use Off Market B/C Ratio 2012 B/C Ratio 2017 E1 EF 0.9 100.0% 2014 1.00 - E2 EF 0.95 94.0% 1.03 1.00 E3 EF 2.3 (HPWH) 39.1% 1.05 1.08 E4 Solar 38.2% 0.68 0.70 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 417 of 1125 28 Estimate achievable potential Requires assumptions about customer acceptance, market barriers, and market maturity Model applies series of factors to economic potential Savings may be acquired through a variety of means Utility incentive programs Utility educational programs Market transformation, including NEEA Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 418 of 1125 29 Sample potential results from previous CPA 2012 2013 2017 2021 2022 2027 2032 8,805,759 9,000,280 9,600,889 10,425,853 10,646,717 11,876,679 13,310,674 Achievable 52,188 116,482 465,933 917,085 1,069,455 1,765,226 2,493,450 Economic 250,938 520,969 1,627,739 2,454,017 2,632,030 3,259,492 3,813,122 Technical 336,303 702,900 2,224,063 3,411,428 3,664,844 4,590,026 5,311,276 Achievable 0.6% 1.3% 4.9% 8.8% 10.0% 14.9% 18.7% Economic 2.8% 5.8% 17.0% 23.5% 24.7% 27.4% 28.6% Technical 3.8% 7.8% 23.2% 32.7% 34.4% 38.6% 39.9% Cumulative Energy Savings (% of Baseline) Cumulative Energy Savings (MWh) Baseline Forecast (MWh) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 419 of 1125 30 Sample potential results (continued) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 420 of 1125 31 Project Schedule Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 421 of 1125 32 Project Schedule Present project approach to the TAC on November 7, 2012 Deliver preliminary results in January 2013 Deliver final results mid-February 2013 Present final study results to TAC and draft report in March, 2013 Support the filing in August 2013 with a complete CPA report (including appendices) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 422 of 1125 33 Jan Borstein jborstein@enernoc.com 303-530-5195 Ingrid Rohmund irohmund@enernoc.com 760-943-1532 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 423 of 1125 Peak Load Forecast James Gall, Senior Power Supply Analyst Grant Forsyth, Senior Forecaster & Economist Third Technical Advisory Committee Meeting 2013 Electric Integrated Resource Plan November 7, 2012 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 424 of 1125 Peak Load History y = 13.637x + 1501.3 R² = 0.2915 y = 15.266x + 1370.4 R² = 0.6058 1,000 1,100 1,200 1,300 1,400 1,500 1,600 1,700 1,800 1,900 2,000 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 Me g a W a t t s Winter Summer Linear (Winter)Linear (Summer) Winter: 0.85% AAGR Summer: 1.0% AAGR Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 425 of 1125 Forecast Methodology Use multi-variable regression analysis to identify the 2011/2012 weather adjusted peak load Use two years of daily load data as the sample data Remove large industrial loads and focus on weather related load Variables include: Heating degree days set at 55°, 45°, and 15° Cooling degree days set at 65° and 70° Prior day cooling degree days set at 65° for past two days Summer sunlight percentage NERC and school holidays Number of industrial & residential customers Day of week and month of year Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 426 of 1125 Forecast Methodology (continued) Peak load data was adjusted to the natural log to better estimate peak load hours Resulting r2: is 0.94 Standard error: 36 MW or 3.3% Durbin-Watson: 1.475(d-1), 1.973(d-2) Weather adjustment includes 123 years of historical Spokane temperatures and four weekday combinations Peak forecast is 1 in 2 peak on a weekday LOLP analysis will consider probability of weekend extreme temperatures and will consider it in the planning margin L&R will use three day average peak and single hour peak Peak forecast includes existing conservation programs- additional programs could further lower the forecast Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 427 of 1125 Historical Average Day Temperatures 1890-2012 0% 2% 4% 6% 8% 10% 12% 14% 16% -20 -17 -14 -11 -8 -5 -2 1 4 7 10 13 16 19 22 25 28 31 Fr e q u e n c y Day Average Temperature Winter Temperature Variation 0% 2% 4% 6% 8% 10% 12% 14% 16% 74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89 90 91 Fr e q u e n c y Day Average Temperature Summer Temperature Variation Coldest Day Hottest Day Extreme -17° 90° Average 3.9° 82.3° Standard Deviation 8.9° 2.8° 90th Percentile -8.8° 86° Last Tail Event 2004: -9° 2008: 86° Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 428 of 1125 1,000 1,100 1,200 1,300 1,400 1,500 1,600 1,700 1,800 1,900 2,000 100%90%80%70%60%50%40%30%20%10% Me g a W a t t s Percentile December July 2011/2012 Weather Adjusted Peak Loads Jan 2012: 1,554 Aug 2012: 1,579 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 429 of 1125 - 500 1,000 1,500 2,000 2,500 19 9 7 19 9 9 20 0 1 20 0 3 20 0 5 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 20 2 7 20 2 9 20 3 1 20 3 3 20 3 5 Me g a w a t t s Winter Summer 2013 IRP Peak Load Forecast Annual Growth Winter Summer 5 Year 1.02% 1.09% 10 Year 0.90% 0.96% 20 Year 0.84% 0.90% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 430 of 1125 Linking Peak Load Growth to GDP Growth Peak loads are not constant over time. Controlling for weather and other seasonal factors, the long-run trend is towards increasing peaks Monthly Peak = f(weather, non-weather seasonal factors, economic factors) If we account for weather and non-weather seasonal factors, then changes in the peak load, we assume, are due to economic factors Since we cannot easily identify specific economic factors, we use GDP growth as a catch-all proxy Econometric evidence suggests that Avista’s load growth, excluding weather and seasonal effects, is significantly, positively correlated with GDP growth. Weather and Seasonal Adjusted Peak Growth = f(GDP Growth) is a relationship estimated with historical data If we have forecasts of GDP growth we can estimated what peak load growth under the assumption that the future GDP/load relationship will not be materially different than what it was in the past Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 431 of 1125 Linking Peak Load Growth to GDP Growth (Cont) There is growing evidence that winter peak load growth is slower than summer peak load growth Could be a function of increased use of air conditioning on new and existing homes Weather and Seasonal Adjusted Peak Growth = f(GDP Growth) is estimated for winter peaks and summer peaks. The estimation does produced a slightly higher growth rate for the summer peak Where do the forecasts for GDP growth come from? 5-year forecasts are obtained by averaging GDP forecasts across multiple sources: Bloomberg survey of forecasters, The Economist poll of forecasters, WSJ survey of forecasters, Global Insight, Economy.com, and several others From this set of forecasts have an average, a high, and a low forecast out five years. This gives us some sense of how the business cycle will impact peak growth Beyond five years we assume a long-rung GDP growth rate of 2.5% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 432 of 1125 IRP Peak Forecast Changes 1,000 1,250 1,500 1,750 2,000 2,250 2,500 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 Me g a w a t t s Winter Peak 2009 IRP 2011 IRP 2013 IRP 1,000 1,250 1,500 1,750 2,000 2,250 2,500 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 Me g a w a t t s Summer Peak 2009 IRP 2011 IRP 2013 IRP Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 433 of 1125 Weather Variation (1 in 20) - 500 1,000 1,500 2,000 2,500 19 9 7 19 9 9 20 0 1 20 0 3 20 0 5 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 20 2 7 20 2 9 20 3 1 20 3 3 20 3 5 Me g a w a t t s Winter Summer Winter-High Winter-Low Summer-High Summer-Low Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 434 of 1125 Reliability Planning James Gall, Senior Power Supply Analyst Third Technical Advisory Committee Meeting 2013 Electric Integrated Resource Plan November 7, 2012 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 435 of 1125 What is Reliability Planning? Assessment of resource adequacy Estimate probability of failing to serve all load Used to estimate the planning margin to apply to the peak load forecast Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 436 of 1125 0 200 400 600 800 1,000 1,200 1,400 1,600 1,800 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Transfers Clark Fork Spokane RiverNatural Gas Mid-Columbia WindBiomassCoalLoad + Ancillary ServicesLoad Peak Day Example- August 7, 2012 - 80° day with peak load 1,579 MW - 11.1% resource margin Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 437 of 1125 The Tool Excel based model with linear program to optimize resource generation to meet load and reserve requires taking into account potential market purchases and sales Focus on year 2020 Simulates 1,000 future scenarios Temperatures, Hydro Availability, Forced Outages, Wind Generation Attempts to correlate interaction between variables Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 438 of 1125 Load Forced Outage Rates Historical Temperatures Thermal Availability Maintenance Schedules Wind Randomization Model Hydro Availability Wind Output Demand Response Operating Reserves Net Power Contracts Thermal Capacity Curves Historical Water Conditions Reliability Model Data Work Flow Diagram Customer Appeal Other DR Programs Long-Term Contracts + Short Term Contract Limits Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 439 of 1125 Loads Load shapes are derived from historic daily high and low temperatures Uses 120+ years of Spokane temperatures The average load and the average of the seasonal peak load of the 1,000 scenarios are designed to match the long-term energy & peak forecasts Two years of historical hourly loads (netted of large industrials) were used as the dependant variable of a regression analysis 303 independent variables were considered including: temperature, holidays, day of week, month, and hour Resulted in a 94% R2 and 5.3% standard error Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 440 of 1125 Hydro Randomly selects a hydro year between 1928 and 1999 Each hydro year includes monthly energy averages Run-of-river facilities – Monthly energy average is used for all hours of the month – No shaping or reserves are assumed to be available Storage facilities – Monthly average generation equals the “drawn” hydro level – In case of planned/forced outage, water can be spilled – Linear program moves energy into hours needed to meet load – Reservoir min and max levels, ramping rates, and daily limits are enforced – Unused capacity is held as operating reserves Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 441 of 1125 Thermal Temperature dependency –Gas-fired facilities use capacity based upon location temperatures – Temperatures are randomly drawn and are the same as the temperatures used in the load and wind calculation Forced outages – Input forced outage rate and mean-time-to-repair – Outages occur randomly using a frequency and duration method – Ramp rates are used following outages Maintenance schedules – Planned maintenance schedules are assumed – Typical outages are in April though June Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 442 of 1125 Wind In 2020, only one wind project is expected to be on-line- The 105 MW Palouse Wind Farm The project is expected to be on-line by the end of 2012 Little generation data is available at this time- only a few years of wind speed at a few locations To simulate wind generation a regression analysis was used to create a algorithm adjusting generation based on month, temperature, daytime vs nighttime and previous hour(s) generation. Method creates realistic generation profile, but due to lack of historical data- scenarios will done to understand the variability of wind during high or low temperatures. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 443 of 1125 Demand Curtailment Customer appeal – Public appeal to all customers to conserve energy, radio/TV broadcasts – Base case includes 25 MW reductions up to two times per year for hours across the peak Industrial process – Not included in base case – Designed to shift load from peak hours Sensitivities studies can help determine value of programs Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 444 of 1125 Reserves Operating Reserves: – 5% hydro, 7% thermal, 5% wind generation Regulating Margin: – 1.6% of average hourly load level (based on historical average of max load within hour versus average load) Intermediate (Wind) Resource Regulation: – Lesser of 10% of nameplate capacity or generation amount Reserves are met by excess hydro capacity (for spin & non-spin) and thermal generation not running may be used for non-spin. In the event a unit trips- the model will call on regional reserves for 1 hour Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 445 of 1125 Contracts & Market Long-term contracts are included as hourly fixed power coming into the system Short-term system balancing transaction are allowed with limits: – On Peak: 500 MW – Off Peak: 1000 MW – On Peak Constrained: 0 MW – Off Peak Constrained: 500 MW Hourly market is modeled dynamically adjusting for regional temperatures and hydro conditions (future enhancement would be to include wind correlation) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 446 of 1125 Objective Function Load Serving - Load [SM] + Thermal commitment [RM] + Hydro commitment [LP] + Wind generation [SM/RM] +/- LT Contracts + Demand curtailment (optional) [LP] +/- Market transactions >= 0 or event triggered Operating Reserves - Operating Reserve Requirement - Intra-hour load regulation - Wind regulation + Available thermal non-spin capability + Unused hydro capability (spin & non-spin) >= 0 or event triggered SM: Stochastic Model RM: Randomization Model LP: Linear Program What should the penalty be for curtailing load? Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 447 of 1125 Metrics Monthly and Annual Data Loss of Load Probability (LOLP): percent of iterations with a reserve or load loss – Calculation: iterations with event / # of iterations – Metric: 5% or less Loss of Load Hour (LOLH): expected number of hours each year with a load loss – Calculation: total hours with event / (# of iterations) – Metric: 0.24 (24 hours per 10 years) Loss of Load Expectation (LOLE): expected number of days each year with a load loss – Calculation: Days with event / # of iterations – Metric: 1 day in 10 years or 0.10 or less [or do we want 0.05, 1 in 20?] Equivalent Unserved Energy (EUE): average MWh of lost load over a year Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 448 of 1125 Planning Margin Approach Simulate system by adding new resources and/or market reliance until the 5% LOLP threshold is met Estimate annual power supply costs for each case Management must decide on the acceptable level of market reliance given the cost of new generation Year 2020 is used to estimate planning margin for other years Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 449 of 1125 2020 Position Forecast (Draft) 3 day x 6 hour Sustained Peak Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Peak Load -1,786 -1,639 -1,518 -1,362 -1,238 -1,369 -1,665 -1,636 -1,332 -1,418 -1,651 -1,814 Contracts Sales -6 -6 -6 -6 -7 -7 -8 -8 -7 -6 -6 -6 Total Peak Obligation -1,793 -1,646 -1,524 -1,368 -1,245 -1,376 -1,673 -1,644 -1,339 -1,424 -1,657 -1,820 Contract Purchases 92 94 96 96 97 95 88 85 85 87 89 92 Hydro 881 823 749 1,052 1,050 1,045 883 840 763 857 878 890 Thermal 884 881 874 755 450 499 775 780 797 865 873 882 Wind 0 0 0 0 0 0 0 0 0 0 0 0 Peaking 242 236 230 222 182 180 172 176 114 92 232 240 Total Resouarces 2,100 2,034 1,950 2,125 1,778 1,818 1,919 1,881 1,759 1,901 2,072 2,105 Position 307 389 426 757 534 443 246 237 421 477 415 284 Net Reserve Requirement -40 -61 -153 -140 -130 -139 -30 -31 0 0 -21 -41 Position Net Reserves 267 328 273 617 404 304 216 206 421 477 394 243 Implied Planning Margin 15% 20% 18% 45% 32% 22% 13% 13% 31% 33% 24% 13% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 450 of 1125 2020 Probabilistic Capacity Requirements (No Additions or Market Availability) 0 50 100 150 200 250 300 350 400 0%5% 10 % 15 % 20 % 25 % 30 % 35 % 40 % 45 % 50 % 55 % 60 % 65 % 70 % 75 % 80 % 85 % 90 % 95 % Ca p a c i t y S h o r t f a l l ( a M W ) Percent of Iterations Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 451 of 1125 2020 Measure of Hours and Shortfall aMW 0 50 100 150 200 250 300 350 400 0 10 20 30 40 50 60 70 80 Sh o r t f a l l ( a M W ) Shortfall Hours Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 452 of 1125 0% 10% 20% 30% 40% 50% 60% 70% Zero 100 200 250 275 285 300 400 LO L P Market Reliance Market Reliance Affect to LOLP in 2020 Target LOLP 5% 28 0 M W = 5 % L O L P Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 453 of 1125 2020 LOLP Monthly Results Market Reliance Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Annual Zero 10% 3% 1% 0% 0% 0% 27% 23% 0% 0% 2% 10% 58.2% 100 5% 1% 0% 0% 0% 0% 14% 12% 0% 0% 1% 5% 32.9% 200 2% 0% 0% 0% 0% 0% 6% 4% 0% 0% 0% 1% 12.4% 250 1% 0% 0% 0% 0% 0% 3% 2% 0% 0% 0% 1% 7.3% 275 1% 0% 0% 0% 0% 0% 2% 2% 0% 0% 0% 1% 5.4% 285 0% 0% 0% 0% 0% 0% 2% 2% 0% 0% 0% 0% 4.6% 300 1% 0% 0% 0% 0% 0% 2% 1% 0% 0% 0% 1% 4.1% 400 0% 0% 0% 0% 0% 0% 1% 0% 0% 0% 0% 0% 1.0% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 454 of 1125 2020 LOLH Monthly Results Market Reliance Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Annual Zero 0.86 0.22 0.07 - - - 1.94 1.28 0.03 0.01 0.32 0.78 5.50 100 0.46 0.06 0.00 - - - 0.82 0.51 0.04 0.00 0.10 0.26 2.26 200 0.08 0.02 0.00 - - - 0.28 0.15 0.00 - 0.01 0.08 0.62 250 0.04 0.02 - - - - 0.16 0.09 - - 0.02 0.02 0.35 275 0.03 0.01 - - - - 0.12 0.06 - - 0.02 0.01 0.24 285 0.02 0.01 - - - - 0.10 0.06 - - 0.01 0.01 0.21 300 0.04 - 0.00 - - - 0.10 0.03 - - 0.01 0.03 0.20 0.24 on an annual basis is considered a “reliable” system Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 455 of 1125 Unit Size Affect to LOLP in 2020 Measure Definition Goal 300 MW Market 3- 100 MW Units 2- 150 MW Units 1- 300 MW Unit LOLP Probability 5% 4.1% 7.5% 8.4% 10.8% LOLH Hrs/Yr 0.24 0.20 0.30 0.38 0.45 EUE aMW N/A 16 22 30 37 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 456 of 1125 Resource allocation to get to 5% LOLP goal 0 5 10 15 20 25 30 35 40 45 - 50 100 150 200 250 300 0 25 50 75 100 125 150 175 200 225 250 275 300 325 In c r e m e n t a l C o s t ( $ M i l l / Y r ) Ma r k e t D e p e n d a n c e ( M W ) New Capacity MW Annual Cost 34% 30% 21% 18% 28% 25% 16% 14% Winter PM Summer PM Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 457 of 1125 Energy Storage Technologies John Lyons, Senior Resource Policy Analyst Third Technical Advisory Committee Meeting 2013 Electric Integrated Resource Plan November 7, 2012 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 458 of 1125 Types of Energy Storage Pumped Hydro Batteries Flywheel Compressed Air 2 http://www.electricitystorage.org/images/uploads/static_content/technology/technology_resources/ratings_large.gif Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 459 of 1125 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 460 of 1125 Energy Storage Applications Electric Supply • Electric energy time-shift • Electric supply capacity Ancillary Services • Load following • Area regulation • Electric supply reserve capacity • Voltage support 4 Grid System • Transmission support • Transmission congestion relief • Transmission and distribution upgrade deferral • Substation on-site power Eyer, J. and Corey, G. (2010) Energy Storage for the Electricity Grid: Benefits and Market Potential Assessment Guide. Sandia National Laboratory. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 461 of 1125 Energy Storage Applications 5 End User/Utility Customer • Time-of-use energy cost management • Demand charge management • Electric service reliability • Electric service power quality Renewables Integration • Renewables energy time-shift • Renewables capacity firming • Wind generation grid integration Eyer, J. and Corey, G. (2010) Energy Storage for the Electricity Grid: Benefits and Market Potential Assessment Guide. Sandia National Laboratory. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 462 of 1125 Pumped Hydro Storage • Works by pumping water between two reservoirs with different elevations during off peak periods • Largest share of current energy storage in the US – over 20 GW capacity with 31 GW proposed 6 http://en.wikipedia.org/wiki/File:Raccoon_Mountain_Pumped-Storage_Plant.svg • Tend to be long lead time resources with unique licensing and siting issues • Avista has pumped storage potential at Long Lake and Noxon Rapids Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 463 of 1125 Batteries • Charge off-peak, or during periods of excess variable generation, for later use • Several different types available: • Litium-ion • Sodium-sulfur • Redox flow • Zinc bromine 7 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 464 of 1125 Flywheels • Converts electric energy into rotational energy, which can be called on quickly to convert back to electricity • Uses: grid energy storage, short-term storage of excess wind generation and providing regulation services • Stephentown, NY – 20 MW (5 MWh over 15 minutes) 8 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 465 of 1125 Compressed Air • Technology based on compressing air and pumping it into geological storage in off-peak periods for use in subsequent periods. • Ongoing projects •1978 – 290 MW Huntorf in Germany (salt dome) •1991 – 110 MW McIntosh, Alabama (salt cavern) • Scheduled projects •2016 – 300 MW (10 hours) PG&E in Kern County, California •2013 – 200 MW ADELE facility in Germany •2016 – 317 MW Bethel Energy Center in Anderson County, Texas 9 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 466 of 1125 Energy Storage Federal and State Policies • No real federal policies requiring the development of energy storage • Many federal proposals for tax benefits and proposed and actual funding of pilot projects • Many proposals at the state level, but few implemented 10 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 467 of 1125 Economic Issues • High cost of installation • Low differentials between on and off peak prices • 2013 IRP = $4,000/kW for 5 MW in 2015 11 http://www.electricitystorage.org/images/uploads/static_content/technology/technology_resources/cycle_large.gif Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 468 of 1125 Avista’s 2013 Electric Integrated Resource Plan Technical Advisory Committee Meeting No. 4 Agenda Wednesday, February 6, 2013 Conference Room 428 Topic Time Staff 1. Introduction 8:30 2. Natural Gas Price Forecast 8:35 Irvine 3. Electric Price Forecast 9:45 Gall 4. Break 10:45 5. Transmission Planning 11:00 Maguire 6. Lunch 12:00 7. Resource Needs Assessment 1:00 Kalich 8. Break 2:00 9. Market & Portfolio Scenario Development 2:15 Lyons 10. Adjourn 3:00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 469 of 1125 Avista Electric IRP Natural Gas Price Forecast Technical Advisory Committee Meeting February 6, 2013 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 470 of 1125 Agenda • Natural Gas 101 • Pacific Northwest Supply and Infrastructure • Natural Gas Price Fundamentals • Short Term • Long Term • Fracking Facts and the Future of Shale Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 471 of 1125 A Brief History ... 3 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 472 of 1125 The Natural Gas System My House Pipeline Receipt Point Delivery Point/ Gate Station Storage Gathering System Local Distribution System Producer Supply 4 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 473 of 1125 Pipelines Offered a Bundled Service – “One Call, That’s All™” Producer Pipeline $$$ Supply Utility/Thermal Generation $$$ 5 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 474 of 1125 Pipeline FERC ORDER 436 Pushed the Pipelines Out of the Supply Business 6 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 475 of 1125 Avista Utilities Puget Sound Energy Shell BP Boeing Gonzaga Marketer B Example of Contracting on a Pipeline 7 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 476 of 1125 Now Services are Unbundled – You Control the Price for Each Component Supply $ Basin 1 Marketer $ Supply $ Basin 3 Hedge Fund $ Pipeline $ Supply $ Basin 2 Producer $ Pipeline $ Utility/Thermal Generation $$$ 8 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 477 of 1125 Natural Gas Infrastructure in the Pacific Northwest Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 478 of 1125 10 Pacific Northwest Supply and Infrastructure AECO Canadian gas coming out of Alberta, Canada Rockies U.S. domestic gas coming from Wyoming and Colorado Sumas Canadian gas coming out of British Columbia, Canada Malin South central at the Oregon and California border Stanfield Intersection of two major pipelines in North Central Oregon Williams Northwest Pipeline TransCanada Gas Transmission Northwest TransCanada Foothills TransCanada Alberta Spectra Energy Ruby Pipeline Jackson Prairie Storage Mist Storage SU P P L Y PI P E L I N E S ST O R A G E Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 479 of 1125 Types of Pipeline Contracts Firm Transport • Contractual rights to: • Receive • Transport • Deliver • From point A to point B Interruptible Transport • Contractual rights to: • Receive • Transport • Deliver • From point A to Point B AFTER FIRM TRANSPORT HAS BEEN SCHEDULED Seasonal Transport • Firm service available for limited periods (Nov-Mar) or for a limited amount (TF2 on NWP) Alternate Firm Transport • The use of firm transport outside of the primary path • Priority rights below firm • Priority rights above interruptible 11 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 480 of 1125 Pipeline Rate Structure • Pipeline charges a higher demand charge and a lower variable or commodity charge Straight Fixed Variable (SFV) • Pipeline charges a lower demand charge and a higher variable or commodity charge Enhanced fixed variable • Pay the same demand and variable costs regardless of how far the gas is transported Postage Stamp Rate • Pay a variable and demand charge based on how far the gas is transported Mileage Based Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 481 of 1125 Straight Fixed Variable Costs vs. Enhanced Fixed Variable Demand Charge: Paid whether transport is used or not Commodity or variable charge: Only paid when gas is actually transported Commodity $.05 Commodity $.01 Demand $.40 Demand $.44 EFV SFV Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 482 of 1125 TransCanada Gas Transmission Northwest (GTN) • Mileage Based • Point to Point • Alternate firm allowed in path • Mostly – demand based with a couple Nomination based points •Demand based refers to gas that will be taken off the pipeline based on the demand behind the delivery point. •Nomination based refers to the pipeline only delivering what was nominated (requested). • Usually requires upstream transportation Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 483 of 1125 Mileage Base: Pay based on how far you move the gas Jackson Prairie Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 484 of 1125 Williams Northwest Pipeline (NWP) • Postage Stamp Based • Point to Point •Delivery to „zones‟ allowed • Alternate firm allowed in and out of path • Demand based delivery •Demand based refers to gas that will be taken off the pipeline based on the demand behind the delivery point. •Nomination based refers to the pipeline only delivering what was nominated (requested). • May or may not require upstream transportation • Enhanced fixed variable structure Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 485 of 1125 Postage Stamp: Same costs regardless of distance or locations Jackson Prairie Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 486 of 1125 Gas Fields Williams NW Pipeline Connecting Pipelines Seattle Jackson Prairie British Columbia Alberta Jackson Prairie Natural Gas Storage Chehalis, Washington Mist Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 487 of 1125 The Facility • Jackson Prairie is a series of deep, underground reservoirs – basically thick, porous sandstone deposits. • The sand layers lie approximately 1,000 to 3,000 feet below the ground surface. • Large compressors and pipelines are employed to both inject and withdraw natural gas at 54 wells spread across the 3,200 acre facility. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 488 of 1125 1.2 Bcf per day (energy equivalent) 10 coal trains with 100 - 50 ton cars each 29 - 500 MW gas-fired power plants 13 Hanford-sized nuclear power plants 2 Grand Coulee-sized hydro plants (biggest in US) 46 Bcf of stored gas 12” pipeline 11,000,000 miles long (226,000 miles to the moon) 1,400 Safeco Fields (Baseball Stadiums) Average flow of the Columbia River for 2 days Cube - 3,550 feet on a side Jackson Prairie Interesting Energy Comparisons 20 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 489 of 1125 Natural Gas Pricing Fundamentals Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 490 of 1125 What Drives the Natural Gas Market? Natural Gas Spot Prices (Henry Hub) 22 Supply – Type: Conventional vs. Non-conventional – Location – Cost Demand – Residential/Commercial/Industrial – Power Generation – Natural Gas Vehicles Legislation – Environmental Energy Correlations – Oil vs. Gas – Coal vs. Gas – Natural Gas Liquids Weather Storage Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 491 of 1125 $0 $2 $4 $6 $8 $10 $12 $14 Jan-00 Jan-01 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 Jan-13 no m i n a l $ / m m b t u Henry Hub: History & Forecast Source: Wood Mackenzie, ICE The Evolving Trend in Henry Hub Pricing ??? Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 492 of 1125 Short Term Market Perspective $0.00 $2.00 $4.00 $6.00 $8.00 $10.00 $12.00 $14.00 1-Jan 1-Feb 1-Mar 1-Apr 1-May 1-Jun 1-Jul 1-Aug 1-Sep 1-Oct 1-Nov 1-Dec $/ D t h Spot Henry Hub Price Five Year Range (2007 -2011) 2012 2013 Source: EIA Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 493 of 1125 Short Term Market Perspective 0 10 20 30 40 50 60 70 80 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Bc f / d Dry Gas Production Five Year Range (2006 -2010) 2011 2012 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 494 of 1125 Short Term Market Perspective Storage (as of January 25, 2013) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 495 of 1125 The Short Term Fundamentals Bulls • Weather – Normal is now bullish. • Dwindling rig counts. • Economic recovery. • Coal/Nuke displacement. Bears • Production is high. • Demand is weak. • Storage is full. • Oh yeah, production is high. • Did I mention, production is high. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 496 of 1125 28 $- $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 $8.00 $9.00 $10.00 $11.00 $12.00 $13.00 $14.00 $/ D e k a t h e r m Fundamental Forecasts vs. Actual Prices Henry Hub Consultant 1 -Dec 2012 Consultant 2 -Dec 2012 NYMEX -Jan 9, 2013 EIA -Jan 2013 Actuals Forecast Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 497 of 1125 Forecasted Long Term Natural Gas Production Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 498 of 1125 1316 429 0 10 20 30 40 50 60 70 80 0 200 400 600 800 1,000 1,200 1,400 1,600 Fe b ' 0 9 Ma r Ap r Ma y Ju n Ju l Au g Se p Oc t No v De c Ja n ' 1 0 Fe b Ma r Ap r Ma y Ju n Ju l Au g Se p Oc t No v De c Ja n ' 1 1 Fe b Ma r Ap r Ma y Ju n Ju l Au g Se p Oc t No v De c Ja n ' 1 2 Fe b Ma r Ap r Ma y Ju n e Ju l y Au g Se p Oc t No v De c Ja n ' 1 3 Bc f / d # o f R i g s Production Oil Gas Forecast The Link Between Rig Counts and Production It ain’t what it used to be. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 499 of 1125 North American Pipeline Infrastructure 31 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 500 of 1125 Shale Changed Everything If shale were a country ... it would be the third-largest gas producer! 32 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 501 of 1125 The Evolving Flow Dynamics 33 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 502 of 1125 The Decoupling of Crude Oil vs. Natural Gas Prices Old rules don‟t apply! Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 503 of 1125 NGL’s Impact on the Cost to Produce 35 Natural Gas Liquids (NGL‟s) include ethane, propane, normal butane, isobutane, pentane, natural gasoline, and sulphur. They are a bi-product of natural gas production and have many uses and great value. • Ethane – is used to create etheleyne a feedstock in petrochemical production. • Propane - used as a fuel source. Can be used in cigarette lighters, motor vehicle fuel, portable stoves and lamps, and heating fuel. • Normal butane and Isobutane – used in refinery akylation • Natural gasoline – used in refinery feedstock, crude dilutent, and chemical applications. • Sulphur – used in agricultural fertilizers and industrial feedstock. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 504 of 1125 NGL’s Impact on the Cost to Produce cont. 36 NGL‟s enhance the production economics for producers. NGL‟s are a main contributor to understanding why gas production companies continue to produce even with gas prices at very low levels. The following table illustrates how the economics can improve with a credit for NGL‟s. Shale Play Cost to Produce without NGL’s Credit Cost to Produce including NGL’s Credit Marcellus $4.81 $2.83 Montney $3.85 $0.57 Barnett $5.39 $2.41 Note: This information is from one of our consultants. These costs are indicative of the impact. The costs can vary from play to play and company to company. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 505 of 1125 Canada Dry vs. Canada Not Dry Why won’t Canada be dry? • Tons of JV money • IP rates are proving to be better than anticipated. • Horn River IP rates have increased 150% • Economics are pretty good too. • Duverney in particular is liquids rich. • New discoveries = Liard Basin Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 506 of 1125 LNG Export is the New Import Source: Federal Energy Regulatory Commission Source: Geology.com LNG traditionally flows to North America after other higher-priced markets receive their share Source: Apache LNG Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 507 of 1125  Declining rig counts  “Fracking” bans and/or legislation  Any economic recovery  Power generation  Carbon legislation  LNG exports “The Best Indicator Of Future Behavior Is Past Behavior?”  Production levels continue to remain higher than expected  Slow economic recovery  Moderation in weather How low can you go? Seems more upside risk? Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 508 of 1125 Long Term Gas Price Drivers •Economy = Demand •Recession, Depression, Inflation, etc. •Industrial Demand •Demand for Power Generation •US Natural Gas Production •LNG Exports/Imports – Global Dynamics •North American Storage Capacity •Correlation (or lack thereof) with other energy products •The Environment •Carbon Legislation •Renewable Portfolio Standards •The “F” Word - FRACKING Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 509 of 1125 IRP Natural Gas Price Forecast Methodology 1.Two fundamental forecasts (Consultant #1 & Consultant #2) 2.Forward prices 3.Carbon legislation adder beginning in 2023 ($14/ton grows to $22/ton) 4.Year 1 forward price only 5.Year 2 75% forward price / 25% average consultant forecasts 6.Year 3 50% forward price / 50% average consultant forecasts 7.Year 4 – 6 25% forward price / 75% average consultant forecasts 8.Year 7 50% average consultant without CO2 / 50% average consultant with CO2 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 510 of 1125 Henry Hub Price Forecasts Nominal $/Dth $- $2.00 $4.00 $6.00 $8.00 $10.00 $12.00 $14.00 $16.00 $18.00 $20.00 $22.00 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 20 2 7 20 2 8 20 2 9 20 3 0 $/ D t h Consult1 Consult2 AEO NYMEX NPCC Low NPCC Medium NPCC High 2009 IRP Forecasted Prices Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 511 of 1125 Natural Gas Price Forecasts Nominal $/Dth $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 $8.00 $9.00 $10.00 Consultant 1 Consultant 2 Consultant Avg Forwards (11/30/12) Consultant Avg w/o CO2 Leg. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 512 of 1125 Forecasted Levelized Henry Hub Price (2013 – 2033) Nominal $/Dth 5.46 4.59 4.95 - 3.00 6.00 9.00 $/ D t h Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 513 of 1125 Selected Basin Forecasted Prices Nominal $/Dth $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 $8.00 $9.00 $10.00 AECO Stanfield Malin Henry Hub Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 514 of 1125 Forecasted Levelized Selected Basin Prices (2013 – 2033) Nominal $/Dth 5.46 $4.78 $5.24 $5.33 $0.00 $3.00 $6.00 $9.00 $/ D t h Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 515 of 1125 Fracking Facts and the Future of Shale Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 516 of 1125 What is Shale Gas? Shale gas refers to natural gas that is trapped within shale formations. Shales are fine-grained sedimentary rocks that can be rich sources of petroleum and natural gas. Over the past decade, the combination of horizontal drilling and hydraulic fracturing has allowed access to large volumes of shale gas that were previously uneconomical to produce. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 517 of 1125 Fracking “Facts” Make Headlines “Insiders Sound an Alarm Amid a Natural Gas Rush” “Shale plays are just giant Ponzi schemes” – New York Times “Because it’s releasing gases, they’re not able to trap it as much, it’s coming right through the ground.” ” – John Krasinski “The Late Show with David Letterman” “Fracking Shale Gas Emissions Far Worse Than Coal” – Cornell Chronicle Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 518 of 1125 The “F” Word What is “Fracking”? Hydraulic fracturing (HF or “fracking”) is a process for producing oil and natural gas. A mixture of water, chemicals and a “proppant” (usually sand) is pumped into a well at extremely high pressures to fracture rock and allow natural gas to escape. An estimated 11,000 new wells are fractured each year; and estimates show another 1,400 existing wells are re-fractured to stimulate production or to produce natural gas from a different production zone. HF has been around for well over 60 years. This process has been used on over one million producing oil and gas wells. Federal, state and other regulatory bodies have had regulations in place for over 50 years. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 519 of 1125 What Are Some Of The Issues? Of the many allegations made in the headlines, recent press has focused its attention on the volumes, costs, and environmental impacts of shale gas production. Issue #1: Shale resources are overestimated. Issue #2: Shale gas is uneconomic to produce. Issue #3: Hydraulic fracturing pollutes the air, contaminates water, and causes earthquakes. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 520 of 1125 What Are The Facts? Fact: Many independent organizations, companies, and governments have examined and assessed data in order to develop estimated shale gas resource figures. All have concluded that the reserve base is much greater than previously anticipated. A recently released MIT study states: “In the US, despite their relative maturity, natural gas resources continue to grow, and the development of low-cost and abundant unconventional gas resources, particularly shale gas has a material impact on future availability and price.” Ernest Moniz, MIT Professor at a hearing before the Senate Energy and Natural Resources Committee. Issue #1: Shale resources are overestimated. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 521 of 1125 Who Estimates The Reserve Base? One of the most widely used estimate is from the Potential Gas Committee. Shale had its first noticeable impact in 2006, nobody questioned it. In 2008, as more data becomes available another adjustment is made, nobody questioned it. Now, with even more data a modest increase in shale reserves is made, and now the questioning begins. Who is the Potential Gas Committee? 100 Volunteer Geoscientists & Petroleum Engineers Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 522 of 1125 What Are The Facts? Fact: It is true that current gas prices have fallen to low levels making the economics of some wells challenging. However, there are several factors that are helping to make the economics work. • Natural Gas Liquids – many of the shale plays are liquids rich. These liquids can be sold at prices which are linked to higher priced oil. The liquids revenue helps to offset costs. • Drilling effectiveness – producers are showing increases in: • Wells per year per rig • Lateral length • 30 day average production rate. It‟s only math: Costs/Volume (Costs / Volumes ) Issue #2: Shale gas is uneconomic to produce. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 523 of 1125 What Are The Facts? Fact: Water contamination – Contamination of water could occur in a couple of ways, one is by factures seeping gas and oil into the water table. Secondarily, much water is used in the HF process. This water is mixed with other things and could be spilled and be absorbed into the water table. Issue #3: “Hydraulic fracturing contaminates ground water, pollutes the air, and causes earthquakes.” FracFocus.org – Public registry created and managed by state regulators Searchable public database with well-by-well information and glossary of chemicals More than 10,000 wells and over 100 participating companies; several states using as tool for compliance reporting Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 524 of 1125 Hydraulic Fracturing and the Water Table Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 525 of 1125 How much is 5 Million gallons of water? It is equivalent to the amount of water consumed by: • New York City in about seven (7) minutes • A 500 megawatt coal- fired power plant in 1 day • A golf course in 25 days • 10 acres of cotton in a season While these represent continuing consumption, the water used for a gas well is a one-time use. How Much Water Is Used in Hydraulic Fracturing? Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 526 of 1125 What Are The Facts? Fact: Pollution – as with most industrial activities there the issue of pollution must be addressed. Most concerning in natural gas processing is the release of volatile organic compounds (VOC) or carcinogens and methane. Most of the air pollutants at gas sites occurs during the completion phase of processing. The EPA just established rules that will curtail the amount of air pollution caused by gas and oil production. Companies have until 2015 to comply with the new rules, however over half of the companies currently use the required technology. Issue #3 cont.: “Hydraulic fracturing contaminates ground water, pollutes the air, and causes earthquakes.” Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 527 of 1125 What Are The Facts? Fact: Earthquakes – It was reported that a recent study conducted by the US Geological Survey appeared to indicate increased seismic activity due to HF. "USGS's studies do not suggest that hydraulic fracturing, commonly known as 'fracking,' causes the increased rate of earthquakes," Hayes wrote. "USGS's scientists have found, however, that at some locations the increase in seismicity coincides with the injection of wastewater in deep disposal wells.“ – DOI Deputy Secretary David Hayes Issue #3 cont.: “Hydraulic fracturing contaminates ground water, pollutes the air, and causes earthquakes.” Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 528 of 1125 Bottom Line: Many benefits can be realized: • Providing jobs • Rejuvenating the chemical, manufacturing, and steel industry • Bridge fuel to a renewable energy future • Reduce dependence on foreign oil However, there are important environmental issues that will need to continue to be addressed. Industry and regulators should continue to work together to ensure safe development of this vital resource. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 529 of 1125 Electric Price Forecast James Gall Fourth Technical Advisory Committee Meeting 2013 Electric Integrated Resource Plan February 6, 2013 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 530 of 1125 Historical Mid-Columbia Prices- What year is it? 13.40 23.06 23.62 122.13 129.51 22.33 38.09 42.44 58.89 45.76 51.85 59.48 32.86 32.99 24.18 19.58 $0 $20 $40 $60 $80 $100 $120 $140 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 $ p e r M W h Energy Crisis Natural Gas Market Tightens Shale Development Cheap Natural Gas, good hydro Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 531 of 1125 Historic Mid-Columbia and Stanfield Prices - 10.00 20.00 30.00 40.00 50.00 60.00 70.00 2004 2005 2006 2007 2008 2009 2010 2011 2012 $ p e r M W h Mid Columbia Firm Electric Prices - 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 9.00 2004 2005 2006 2007 2008 2009 2010 2011 2012 $ p e r D T H Stanfield Natural Gas Prices Strong tie between natural gas and electric market Increased natural gas supply/ lower prices causing price declines at the Mid-Columbia Are prices now at a new normal? Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 532 of 1125 Pricing Relationships - 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 2004 2005 2006 2007 2008 2009 2010 2011 2012 IM H R : M i d C / S t a n f i e l d Annual Implied Market Heat Rate (4.00) (2.00) - 2.00 4.00 6.00 8.00 2004 2005 2006 2007 2008 2009 2010 2011 2012 (M i d C - St a n f i e l d * 7 ) Spark Spread Implied Market Heat Rate illustrates new wind supply contributing to lowering market prices Spark Spread shows margin opportunities for Combined Cycle Resources 2011’s above average hydro reduced prices further Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 533 of 1125 The Ghost of IRP’s Past $0 $20 $40 $60 $80 $100 $120 $140 $160 $180 $200 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 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 $ p e r M W h Index 2003 2005 2007 2009 2011 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 534 of 1125 2013 IRP Modeling Process Preferred Resource Strategy AURORA “Wholesale Electric Market” 500 Simulations PRiSM “Avista Portfolio” Efficient Frontier Fuel Prices Fuel Availability Resource Availability Demand Environmental Considerations Existing Resources Resource Options Transmission Resource & Portfolio Margins Conservation Trends Existing Resources Avista Load Forecast Energy, Capacity, & RPS Balances New Resource Options & Costs Cost Effective T&D Projects/Costs Cost Effective Conservation Measures/Costs Mid-Columbia Prices Stochastic Inputs Deterministic Inputs Capacity Value Avoided Costs Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 535 of 1125 Retail Sales by Western State - 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 90,000 2004 2005 2006 2007 2008 2009 2010 2011 Av e r a g e M W NV UT AZ NM CO WY MT ID OR WA CA WA14% OR7%ID3%MT2% WY2%CO8% NM3% AZ11% CA41% UT4% NV5% Source: SNL 1.2% annual growth Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 536 of 1125 0 100 200 300 400 500 600 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 Av e r a g e G i g a w a t t s Other Wind Oil Natural Gas Coal Nuclear Hydro National Historic Power Generation Source: SNL Coal 43% Natural Gas24% Nuclear19% Oil 1% Hydro 8% Wind3%Other2% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 537 of 1125 -4 -2 0 2 4 6 8 10 12 14 Natural Gas Nuclear Oil Hydro Wind Other Lost Load Av e r a g e G i g a w a t t s US Coal Generation Displacement Between 2007 and 2011, Coal Generation decreased 32 aGW Source: SNL Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 538 of 1125 US Western Interconnect Generation by Fuel Type Source: SNL 2004 2005 2006 2007 2008 2009 2010 2011 Other 3 3 3 3 3 3 3 3 Wind 1 1 1 1 2 2 3 4 Hydro 19 20 23 20 19 19 19 25 Oil 0 0 0 0 0 0 0 0 Nuclear 8 8 7 8 8 8 8 8 Natural Gas 21 21 23 26 27 26 24 20 Coal 27 27 25 26 26 25 25 24 Total 79 80 84 85 86 84 83 84 - 10 20 30 40 50 60 70 80 90 100 Av e r a g e G i g a w a t t s Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 539 of 1125 US Western Interconnect Energy Versus Capacity Coal 16% Natural Gas 42%Nuclear 5% Oil 0% Hydro 27% Wind 7% Other 3% Coal 29% Natural Gas 23%Nuclear 10% Oil 0% Hydro 30% Wind 4% Other 4% 2011 Energy 84 aGW 2011 Capacity 204 GW Source: SNL Actual coincident peak was 128.7 GW (8/25/2011) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 540 of 1125 Historic US Greenhouse Gas Emissions Source: EIA - 1,000 2,000 3,000 4,000 5,000 6,000 7,000 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 Mi l l i o n M e t r i c T o n s Residential Commercial Industrial Electric Power Transportation -1.0%-0.5%0.0%0.5%1.0%1.5% Commercial Industrial Residential Transportation Electric Power Total Annual Average Emissions Growth (1990-2010) Electric power in 2011 is 4.6% below 2010, A total of 11% reduction since 2007 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 541 of 1125 Western Electric Generation Greenhouse Gas Emissions Source: EIA 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 Delta AAGR WY 40 39 43 41 43 40 41 41 44 42 44 44 42 43 44 43 43 43 44 41 42 2.3 0.3% WA 8 8 10 10 12 8 11 9 12 11 14 14 11 14 14 14 9 12 13 13 13 5.5 2.8% UT 29 28 30 30 31 29 30 31 31 32 33 32 33 34 34 35 35 37 38 35 34 4.9 0.8% OR 2 4 5 4 5 3 3 3 6 6 7 9 6 8 8 8 6 10 10 9 10 7.8 8.8% NV 17 18 19 18 20 18 20 19 21 21 25 24 21 23 25 26 17 17 18 18 17 -0.1 0.0% NM 27 23 26 27 28 27 28 29 29 30 31 30 28 30 30 32 32 31 30 32 29 1.7 0.3% MT 16 17 18 15 18 17 14 16 18 18 17 18 16 18 19 19 19 20 20 17 20 3.7 1.1% ID 0 0 0 0 0 0 0 0 0 0 0 1 0 1 1 1 1 1 1 1 1 0.7 41.1% CO 31 31 32 32 33 33 34 34 35 35 39 41 40 40 40 40 41 42 41 38 39 8.1 1.2% CA 40 38 46 42 49 37 33 36 39 43 53 58 44 43 46 42 46 50 51 48 43 3.2 0.4% AZ 33 33 35 37 38 32 32 35 37 39 44 45 45 46 51 50 52 55 57 52 54 21.4 2.6% TOTAL 242 238 263 256 278 245 245 253 273 278 306 315 286 299 312 310 302 316 321 303 301 59.2 1.1% 0 50 100 150 200 250 300 350 Mi l l i o n M e t r i c T o n s Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 542 of 1125 3rd party software- EPIS, Inc. Electric market fundamentals- production cost model Simulates generation dispatch to meet load Outputs: – Market prices – Regional energy mix – Transmission usage – Greenhouse gas emissions – Power plant margins, generation levels, fuel costs – Avista’s variable power supply costs Electric Market Modeling Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 543 of 1125 Stochastic Approach Simulate Western Electric market hourly for next 20 years (2014-33) – That is 175,248 hours for each study Model 500 potential outcomes – Variables include fuel prices, loads, wind, hydro, outages, inflation – Simulating 87.6 million hours Run time is about 5 days on 27 processors Why do we do this? – Allows for complete financial evaluation of resource alternatives – Without stochastic prices we cannot account for tail risk Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 544 of 1125 Aurora Pricing Example- Supply/Demand Curve -$100 -$50 $0 $50 $100 $150 $200 $250 $300 $350 0 10,000 20,000 30,000 40,000 50,000 $ p e r M W h Capability (MW) Hydro (Must Run for Negative Pricing) CCCT Peakers Demand Hydro Availability Fu e l P r i c e s / V a r i a b l e O & M Other Resource Availability Nuclear/ Co-Gen/ Coal/ Other Wind (Net PTC/REC) Market Price Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 545 of 1125 Modeled Western Interconnect Topology Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 546 of 1125 Greenhouse Gas Emissions Modeling No national greenhouse gas tax or cap & trade is modeled California, Alberta, and British Columbia greenhouse gas reduction schemes are modeled Assumes some coal plants will retire due to EPA regulations Plants were selected for retirement based on fuel costs, emission control technology and its location Assume certain natural gas once-through-cooling plants in California will be retired over time State RPS requirements met mostly by wind & solar Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 547 of 1125 Forecasted Resource Retirements - 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 Cu m u l a t i v e M e g a w a t t s Me g a w a t t s Oil NG Coal Cumulative Retirements Natural Gas retirements are related to lost generation from once-through-cooling technology phase out in California Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 548 of 1125 New Resource Alternatives Western Interconnect Resource alternatives to meet Renewable Portfolio Standards – Wind – Solar – Biomass – Geothermal – Hydro Upgrades Resource alternatives to meet regional capacity requirements – Combined Cycle – Simple Cycle (Aero, Frame, Hybrid) – Solar – Wind (non RPS states) – Nuclear – Coal IGCC with Sequestration – Energy Storage (not modeled) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 549 of 1125 Resource Additions (Western Interconnect) 0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 Cu m u l a t i v e M W An n u a l M W Hydro Geothermal Biomass Wind Solar SCCT CCCT Cumulative Capacity Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 550 of 1125 Resource Additions (Northwest)- Maintain 5% LOLP 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 0 500 1,000 1,500 2,000 2,500 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 Cu m u l a t i v e M W An n u a l M W Hydro Geothermal Biomass Wind Solar SCCT CCCT Cumulative Capacity Will policy makers want more renewables? Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 551 of 1125 US Western Interconnect Resource Forecasted Output DRAFT 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 Other 6 6 7 7 7 7 8 8 8 8 9 9 9 9 9 9 9 9 9 9 Wind 6 6 6 7 7 7 7 7 8 8 8 8 8 8 8 8 8 8 8 8 Oil 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Natural Gas 21 23 24 25 25 26 26 28 29 30 32 33 34 36 37 39 40 43 44 45 Coal 25 23 21 21 21 20 20 20 19 19 19 19 18 18 18 17 17 16 16 16 Nuclear 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 Hydro 23 23 24 23 23 24 23 24 24 24 23 23 24 23 23 24 23 23 23 23 Total 89 89 89 90 91 92 93 94 95 97 98 99 100 101 103 105 106 107 109 110 0 20 40 60 80 100 120 Av e r a g e G i g a w a t t s Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 552 of 1125 Stanfield Natural Gas Price Forecast $0 $2 $4 $6 $8 $10 $12 $14 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 $ p e r M W h Mean Median 5th Percentile 95th Percentile Levelized Price: $5.38/Dth 5th Percentile: $4.14/Dth 95th Percentile: $7.12/Dth Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 553 of 1125 $0 $10 $20 $30 $40 $50 $60 $70 $80 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 $ p e r M W h Flat Off-Peak On-Peak Mid-Columbia Annual Average Forecast Levelized Price: $44.60/MWh DRAFT Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 554 of 1125 $0 $20 $40 $60 $80 $100 $120 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 $ p e r M W h Mean Median 5th Percentile 95th Percentile Mid-Columbia Electric Prices: Stochastic Results Levelized Price: $44.60/MWh 5th Percentile: $36.00/MWh 95th Percentile: $57.15/MWh DRAFT Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 555 of 1125 Implied Market Heat Rate (Mid-C / Stanfield x 1,000) 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 Mi d -C/ S t a n f i e l d x 1 0 0 0 Mean 5th Percentile 95th Percentile DRAFT Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 556 of 1125 Mid-Columbia Negative Electric Pricing 0 500 1,000 1,500 2,000 2,500 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 Ho u r s w i t h N e g a t i v e P r i c e s Mean Median 5th Percentile 95th Percentile 2011 had 202 hours and 2012 had 552 according to Powerdex hourly index Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 557 of 1125 Western US Greenhouse Gas Emissions Forecast DRAFT 0 50 100 150 200 250 300 350 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 Mi l l i o n s M e t r i c T o n s Mean 5th Percentile 95th Percentile Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 558 of 1125 $0 $20 $40 $60 $80 $100 $120 $140 $160 $180 $200 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 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 $ p e r M W h Index 2003 2005 2007 2009 2011 2013 IRP Electric Price Forecast Comparison 2007-2011 IRP expected case forecasts included carbon reduction schemes increasing market prices Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 559 of 1125 IRP Price Forecast Comparison (No CO2 Pricing) $0 $10 $20 $30 $40 $50 $60 $70 $80 $90 $100 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 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 $ p e r M W h Index20032005 2007*2009* 2011*2013Forwards Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 560 of 1125 TAC PRESENTATION New Resource Integration – Transmission SYSTEM PLANNING Prepared by Richard Maguire and the Avista System Planning Group February 6, 2013 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 561 of 1125 Federal Standards of Conduct 1.No non-public transmission information can be shared with the Avista Merchant Function 2.There are Avista Merchant Function personnel in attendance 3.We can’t share non-public transmission information today Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 562 of 1125 Agenda •Introduction to Avista System Planning •Engineering of Local Generation Requests •Recent Avista Projects •Large Generation Interconnection Agreement (LGIA) Queue •Integrated Resource Plan (IRP) Generation Requests •Future Transmission Planning Initiatives Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 563 of 1125 Introduction to Avista System Planning Broad Scope of What We Care About: •Avista System Performance •Federal, Regional, and State Compliance •Regional Transmission System Coordination Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 564 of 1125 Introduction to Avista System Planning Regional Coordination WECC NWPP CG NTTG etc. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 565 of 1125 Introduction to Avista System Planning We also spend our time: •Developing internal standards and processes •Engineering the transmission system •Engineering the distribution system •Managing Avista assets •Projecting future loads and resources •Engineering local generation requests Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 566 of 1125 Agenda •Introduction to Avista System Planning •Engineering of Local Generation Requests •Recent Avista Projects •Large Generation Interconnection Request (LGIR) Queue •Integrated Resource Plan (IRP) Generation Requests •Future Transmission Planning Initiatives Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 567 of 1125 Engineering of Local Generation Requests Typical Process for Generation Requests •We generally get requests via two sources: •Internal via the IRP requests •External and Internal via LGIA requests •We hold a scoping meeting to discuss particulars •We outline a study plan •We augment WECC approved cases for our studies •We analyze the system against the standards •We publish our findings and recommendations Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 568 of 1125 Engineering of Local Generation Requests Case Development Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 569 of 1125 Engineering of Local Generation Requests Case Analysis Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 570 of 1125 Engineering of Local Generation Requests Mandatory Federal Standards Include: No overloads all lines and equipment in service (N-0) No overloads or loss of load for one element out of service (N-1) Some relaxation of the above for two elements out (N-2) Standards are “Request Agnostic” Potential Sanctions: Up to $1M Per Day Per Occurrence Mitigation Plan must be provided and progress demonstrated Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 571 of 1125 Engineering of Local Generation Requests Publish Results www.oasis.oati.com/avat/index.html Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 572 of 1125 Agenda •Introduction to Avista System Planning •Engineering of Local Generation Requests •Recent Avista Projects •Large Generation Interconnection Request (LGIR) Queue •Integrated Resource Plan (IRP) Generation Requests •Future Transmission Planning Initiatives Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 573 of 1125 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 574 of 1125 Recent Avista Projects Palouse Wind: 58 turbines 105 MW Thornton 230 kV Substation $4.35M Benewah – Shawnee 230 kV Transmission Line Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 575 of 1125 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 576 of 1125 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 577 of 1125 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 578 of 1125 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 579 of 1125 Recent Avista Projects Lind Capacitor Bank ~$750K Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 580 of 1125 Recent Avista Projects Idaho Road 115 kV Substation Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 581 of 1125 Recent Avista Projects Turner 115 kV Substation Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 582 of 1125 Recent Avista Projects 115 kV Transmission Lines $2.5M Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 583 of 1125 Agenda •Introduction to Avista System Planning •Engineering of Local Generation Requests •Recent Avista Projects •Large Generation Interconnection Request (LGIR) Queue •Integrated Resource Plan (IRP) Generation Requests •Future Transmission Planning Initiatives Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 584 of 1125 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 585 of 1125 Avista Non-IRP Generation Queue Project # 08: 75 MW with Facility Study completed $6.6M 230 kV switching station and tap $5.6M 115 kV breaker position and reconductor Project # 26: 42MW with System Impact Study completed Project # 33: 400 MW in Feasibility Study stage Project # 35: 200 MW in System Impact Study stage Project # 36: 105 MW in Feasibility Study stage http://www.oasis.oati.com/AVAT Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 586 of 1125 Agenda •Introduction to Avista System Planning •Engineering of Local Generation Requests •Recent Avista Projects •Large Generation Interconnection Request (LGIR) Queue •Integrated Resource Plan (IRP) Generation Requests •Future Transmission Planning Initiatives Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 587 of 1125 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 588 of 1125 Avista Non-IRP Generation Queue Nine Mile HED: 60 MW total Long Lake HED: 68 MW additional (156 MW total) Studied coincident with Nine Mile IRP request $9.9M for 115 kV Transmission Line reconductoring Monroe Street HED: 80 MW additional (95 MW total) Upper Falls HED: 40 MW additional (50.26 MW total) Post Falls HED: 33.5 MW total Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 589 of 1125 Avista Non-IRP Generation Queue Cabinet Gorge HED: 60 MW additional (330.5 MW total) No capacity available today during Heavy Summer loading Considering RAS or potential Transmission System upgrades Benewah – Boulder: 300 MW project currently under study Rathdrum: 300 MW $7M for new breaker position at Rathdrum 230 kV Substation Rosalia: 200 MW $4M for new breaker position at Thornton 230 kV Substation Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 590 of 1125 Agenda •Introduction to Avista System Planning •Engineering of Local Generation Requests •Recent Avista Projects •Large Generation Interconnection Request (LGIR) Queue •Integrated Resource Plan (IRP) Generation Requests •Future Transmission Planning Initiatives Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 591 of 1125 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 592 of 1125 Examples of Future Construction Required to Meet NERC / WECC Reliability Standards Moscow Station: 250 MVA transformer Increases capacity to the Moscow / Pullman area and relieves loading on the Shawnee transformer Westside Station: Two 250 MVA transformers Increases capacity and security to the West Plains area of Spokane County, and relieves heavy loading on large transformers in the central Spokane area Irvin 115 kV and Associated 115 kV Reconductoring: 115 kV Switching Station and other upgrades to meet additional load growth in the Spokane Valley Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 593 of 1125 Recent Avista Projects Moscow Station Construction Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 594 of 1125 Future Work? Generic Break Point Studies for IRP / 3rd Party Developers: “How many MW can we integrate where for about what $$?” Main Grid 230 kV Stations. Select 115 kV Stations. Potential Open Seasons: “Does anyone want to get to the Mid Columbia?” “Does anyone want to get out of Montana?” “Does anyone want to get to PAC or IPC?” Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 595 of 1125 Questions? Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 596 of 1125 Resource Needs Assessment Clint Kalich Fourth Technical Advisory Committee Meeting 2013 Electric Integrated Resource Plan February 6, 2013 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 597 of 1125 Power Supply Reliability Key Terms Peak Demand Winter and Summer single hour view to verify the utility can meet its highest expected load hour in a given year Sustained Peak Demand Winter and summer multi-day event (3 day x 6 hour) view to verify the utility can meet its highest expected load hour in a given year  Energy On an annual basis the utility has enough energy to meet load plus contingencies (e.g., load and hydro variability) Operating Reserves System capacity “reserved” to meet unanticipated generation outages; 5% of wind and hydro, and 7% of thermal, plants Regulation to cover moment-to-moment load and generation variability Loss of Load Probability (LOLP) Number of modeling exercises where system resources are inadequate to meet needs; 1-in-20 (5%) is deemed adequate Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 598 of 1125 Historical Avista Planning Margin Targets 1979: 6% (single hour, hydro only); 15 to 20% with thermal units Somewhere in between 1979 and 1986: 13.4% to 18.7% 1986 to 2007: 10% + 90 MW (single hour peak) 2009: 15% 2011: Move to an 18-hour sustained peak per NPCC Winter: 14% + Operating Reserves Summer: 15% + Operating Reserves Equivalent to NPCC 23/24% planning criteria for the Northwest Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 599 of 1125 Adequacy Assessment for the 2017 Pacific Northwest Power Supply Steering Committee Meeting October 26, 2012 Portland, Oregon 4 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 600 of 1125 NW Adequacy Standard Metric: Loss-of-load probability (LOLP) Threshold: Maximum of 5 percent LOLP is the probability that extraordinary actions would have to be taken in a future year to avoid curtailment of electricity service Calculated assuming existing resources only and expected efficiency savings 5 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 601 of 1125 Major Assumptions Existing resources (sited and licensed) 6th Power Plan conservation Market supplies –NW: 3,450 MW winter, 1,000 MW summer –SW on-peak: 1,700 MW winter, none summer –SW off-peak: 3,000 MW year round Council’s medium load forecast 6 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 602 of 1125 Major Uncertainties Explicitly modeled –Water supply –Temperature load variation –Wind –Forced outages Not modeled explicitly –Economic load growth –Uncertainty in SW market 7 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 603 of 1125 2017 Assessment The expected LOLP is 6.6% January, February and August most critical months Interpretation: Relying only on existing resources and expected efficiency savings yields a power supply in 2017 whose likelihood of curtailment exceeds our agreed upon threshold 8 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 604 of 1125 Actions to Alleviate Inadequacy 350 MW of new generating resource capacity drops the expected LOLP to 5% Equivalently, 300 average megawatts of additional energy efficiency does the same Demand response measures could help This is consistent with utility plans and the Council’s resource strategy 9 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 605 of 1125 2017 Monthly LOLP 10 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 606 of 1125 Effects of Uncertainties 11 Load SW Winter Market LOLP Low High 2.8% Low None 8.4% High High 7.8% High None 16.8% Expected Expected 6.6% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 607 of 1125 Illustration of LOLP Probability 12 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 608 of 1125 Effects of Adding Resources 13 350 MW of new resource moved the reference case LOLP of 6.6% down to 5.0% 2,850 MW of new resource moved a high LOLP of 13.3% down to 5.0% Sum of utility planned* resources exceeds 3,000 MW *In this context “planned” means request for proposals or RFPs. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 609 of 1125 Variation in LOLP due to Load and Market 14 Load change in percent from medium >>>> Market -2.50 -2.25 -2.00 -1.75 -1.50 -1.25 -1.00 -0.75 -0.50 -0.25 0.00 0.25 0.50 0.75 1.00 1.25 1.50 1.75 2.00 2.25 2.50 0 8.4 11.8 16.8 100 13.2 200 13.3 300 13.2 400 13.2 500 600 700 800 900 6.3 10.4 1000 5.1 1100 4.8 1200 1300 5.4 1400 1500 1600 1700 3.7 4.5 6.6 9.8 1800 1900 2000 2100 2200 2300 2400 2500 3.8 7.2 2600 2700 2800 2900 3000 3100 3200 2.8 5.0 7.8 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 610 of 1125 Thermal derate schedules 15 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 611 of 1125 Thermal derate schedules 16 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 612 of 1125 How much CT gets you to 5% 17 Add a CT resource that will bring study cases with >5.0% LOLP down to 5.0% Study Summary LOLP Pk LOLP E LOLP A EUSR CVaRE CVaRPk EUE LOLH Study Case Load Dev. Mkt. Add CT (%) (%) (%) (%) (MWh) (MW) (MWh (Hr/sYr) Reference Case 0.00%1700 350 5.0 1.5 5.0 7.3 76466 3410 3851 2.1 High Load, High Market 2.50%3200 750 5.0 0.9 5.0 7.9 43510 2913 2197 1.4 High Load, Low Market 2.50% 0 4800 5.0 0.8 5.0 6.2 43007 2645 2162 1.4 Low Load, High Market -2.50%3200 NA Low Load, Low Market -2.50% 0 1155 5.0 1.5 5.0 6.5 76118 2593 3829 2.4 Med-High Load, Med-High Mkt 1.50%2500 525 5.0 1.1 5.0 8.0 58041 3165 2923 1.7 Med-High Load, Med-Low Mkt 1.50%900 1950 5.0 1.3 5.0 6.8 61092 2866 3071 1.9 Med-Low Load, Med-High Mkt -1.50%2500 NA Med-Low Load, Med-Low Mkt -1.50%900 450 5.0 1.5 5.0 6.7 80421 3184 4033 2.3 Reference Load, High Market 0.00%3200 NA Reference Load, Low Market 0.00% 0 2750 5.0 0.8 5.0 6.3 53995 2443 2717 1.9 High Load, Reference Market 2.50%1700 1200 5.0 1.5 5.0 7.7 75020 3400 3778 2.1 Low Load, Reference Market -2.50%1700 NA High Case within likely region 1.25%200 2850 5.0 1.0 5.0 6.6 56369 2587 2836 1.9 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 613 of 1125 Regional Position (2016/17- Peak Hour) 2016 2016 2016 2017 2017 2017 2017 2017 2017 2017 2017 2017 10 11 12 1 2 3 4 5 6 7 8 9 Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep 1-Hr Peak Avg Load 24,458 28,593 31,838 33,143 29,949 27,929 25,454 23,596 25,078 26,773 26,151 23,589 Hydro 25,059 25,857 26,675 27,944 26,400 25,773 25,388 25,852 27,271 26,394 25,232 25,198 Hydro Ind.299 299 299 299 299 299 299 299 299 299 299 299 Total Non-Hydro 25,358 26,155 26,974 28,242 26,699 26,072 25,687 26,151 27,569 26,692 25,531 25,497 Small Renewables 109 109 109 109 109 109 109 109 109 109 109 109 Nuclear 1,130 1,130 1,130 1,130 1,130 1,130 1,130 1,130 1,130 1,130 1,130 1,130 Coal 4,708 4,708 4,708 4,708 4,708 4,708 4,708 4,708 4,708 4,708 4,708 4,708 CCCT 4,868 4,961 5,151 5,151 5,054 4,961 4,868 4,775 4,678 4,678 4,678 4,775 Peakers 1,751 1,784 1,853 1,853 1,817 1,784 1,751 1,717 1,682 1,682 1,682 1,717 Total Non-Hydro 12,566 12,692 12,951 12,951 12,819 12,692 12,566 12,440 12,307 12,307 12,307 12,440 Total Generation 37,924 38,848 39,925 41,194 39,518 38,764 38,253 38,591 39,877 39,000 37,838 37,937 Physicial Position 13,466 10,255 8,087 8,050 9,568 10,836 12,799 14,995 14,798 12,227 11,687 14,348 Implied Planning Margin 55% 36% 25% 24% 32% 39% 50% 64% 59% 46% 45% 61% IPP Generation 3,200 3,240 3,324 3,324 3,281 3,240 3,200 3,159 3,116 3,116 3,116 3,159 Physicial Position w/ IPP 16,666 13,495 11,410 11,374 12,849 14,076 15,999 18,154 17,915 15,343 14,804 17,507 W/ IPP Implied Plannin Margin 68% 47% 36% 34% 43% 50% 63% 77% 71% 57% 57% 74% Data provided by Northwest Power & Conservation Council Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 614 of 1125 Regional Position (2016/17- 10 Hour Peak) 2016 2016 2016 2017 2017 2017 2017 2017 2017 2017 2017 2017 10 11 12 1 2 3 4 5 6 7 8 9 Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep 10-Hr Peak Avg Load 22,991 26,878 29,928 31,155 28,152 26,253 23,926 22,181 23,574 25,166 24,582 22,174 Hydro West 3,107 3,656 2,862 2,711 2,597 3,443 3,548 3,736 3,640 3,282 3,366 3,160 Hydro East 21,090 21,564 19,414 16,178 15,722 17,375 19,708 21,239 20,835 19,884 20,723 19,824 Hydro Ind.299 299 299 299 299 299 299 299 299 299 299 299 Total Hydro 24,496 25,518 22,574 19,188 18,617 21,117 23,554 25,273 24,774 23,464 24,387 23,283 Small Renewables 109 109 109 109 109 109 109 109 109 109 109 109 Nuclear 1,130 1,130 1,130 1,130 1,130 1,130 1,130 1,130 1,130 1,130 1,130 1,130 Coal 4,708 4,708 4,708 4,708 4,708 4,708 4,708 4,708 4,708 4,708 4,708 4,708 CCCT 4,868 4,961 5,151 5,151 5,054 4,961 4,868 4,775 4,678 4,678 4,678 4,775 Peakers 1,751 1,784 1,853 2,203 1,817 1,784 1,751 1,717 1,682 1,682 1,682 1,717 Total Non-Hydro 12,566 12,692 12,951 13,301 12,819 12,692 12,566 12,440 12,307 12,307 12,307 12,440 Total Generation 37,062 38,211 35,525 32,489 31,436 33,809 36,121 37,713 37,081 35,771 36,695 35,723 Physicial Position 14,072 11,333 5,598 1,334 3,283 7,556 12,194 15,533 13,507 10,605 12,113 13,549 Implied Planning Margin 61% 42% 19% 4% 12% 29% 51% 70% 57% 42% 49% 61% IPP Generation 3,200 3,240 3,324 3,324 3,281 3,240 3,200 3,159 3,116 3,116 3,116 3,159 Physicial Position w/ IPP 17,271 14,573 8,921 4,658 6,564 10,796 15,394 18,692 16,624 13,721 15,229 16,708 W/ IPP Implied Plannin Margin 75% 54% 30% 15% 23% 41% 64% 84% 71% 55% 62% 75% Data provided by Northwest Power & Conservation Council Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 615 of 1125 Translating the Regional Position to Avista NPCC indicates region will be short capacity in the 2016/7 winter timeframe With region in surplus, utility can rely on market in peak conditions Changes in load growth or out-of-region transfers can change adequacy results Summer adequacy is strong for the region With regional summer length- dual peaking utilities can rely on system for summer peaks Future build-outs for winter peaks likely will ensure adequate regional summer capacity Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 616 of 1125 Resource allocation to get Avista to 5% LOLP goal 0 5 10 15 20 25 30 35 40 45 - 50 100 150 200 250 300 0 25 50 75 100 125 150 175 200 225 250 275 300 325 In c r e m e n t a l C o s t ( $ M i l l / Y r ) Ma r k e t D e p e n d a n c e ( M W ) New Capacity MW Annual Cost 34% 30% 21% 18% 28% 25% 16% 14% Winter PM Summer PM Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 617 of 1125 Avista’s Peak Planning Criteria Winter Peak 14% planning margin above load, plus operating reserves If Avista is deficit prior to 2016/17, and where the NW market has been shown adequately surplus, market purchases will meet deficit needs Summer Peak Avista operating reserves are the planning requirement, unless region’s “natural” deficit shifts to summer If utility is deficit, market purchases will meet deficit needs However, as with the region, building to meet winter peak generally addresses our summer need Both sustained- and single-hour peak positions are considered Wind and solar provide no winter peaking capability Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 618 of 1125 January: 18 Hour Peak Position Forecast 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 REQUIREMENTS 1 Native Load -1,596 -1,613 -1,629 -1,643 -1,656 -1,669 -1,683 -1,696 -1,710 -1,724 -1,738 -1,752 -1,766 -1,780 -1,794 -1,809 -1,824 -1,838 -1,853 -1,8682 Firm Power Sales -211 -158 -158 -8 -8 -6 -6 -6 -6 -6 -6 -6 -6 -6 -6 -6 -6 -6 -6 -6 3 Total Requirements -1,807 -1,771 -1,787 -1,650 -1,663 -1,675 -1,689 -1,702 -1,716 -1,730 -1,744 -1,758 -1,772 -1,786 -1,801 -1,815 -1,830 -1,844 -1,859 -1,874 RESOURCES 4 Firm Power Purchases 117 117 117 117 117 116 34 34 33 33 33 33 33 33 33 33 33 33 33 33 5 Hydro Resources 973 866 867 932 932 896 900 896 896 904 896 896 904 896 896 904 896 896 904 896 6 Base Load Thermals 895 895 895 895 895 895 895 895 895 895 895 895 895 617 617 617 617 617 617 617 7 Wind Resources 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 08 Peaking Units 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242 9 Total Resources 2,227 2,121 2,122 2,187 2,186 2,149 2,071 2,068 2,067 2,074 2,067 2,067 2,074 1,788 1,788 1,796 1,788 1,788 1,796 1,788 10 PEAK POSITION 421 350 334 536 523 473 383 365 351 345 323 309 303 2 -13 -19 -42 -57 -64 -86 RESERVE PLANNING 11 Planning Margin -223 -226 -228 -230 -232 -234 -236 -237 -239 -241 -243 -245 -247 -249 -251 -253 -255 -257 -259 -262 12 Total Ancillary Services Required -186 -184 -185 -177 -179 -180 -186 -187 -189 -191 -192 -193 -194 -195 -196 -197 -197 -198 -199 -19913Reserve & Contingency Availability 25 9 9 17 17 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 14 Demand Response 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 15 Total Reserve Planning -385 -401 -405 -390 -394 -398 -405 -409 -412 -416 -419 -422 -425 -428 -431 -434 -436 -439 -442 -444 16 Peak Position w/ Contingency 36 -51 -70 146 129 76 -22 -43 -61 -71 -96 -113 -123 -426 -443 -453 -478 -495 -506 -531 17 Implied Planning Margin 25% 20% 19% 33% 32% 29% 24% 22% 21% 21% 19% 18% 18% 1% 0% 0%-1% -2% -3% -4% 18 NPCC Market Adjustment 0 51 70 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 19 Peak Position Net Market 36 0 0 146 129 76 (22) (43) (61) (71) (96) (113) (123) (426) (443) (453) (478) (495) (506) (531) 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 Winter 1 Hour 17 0 0 126 110 56 (42) (64) (81) (92) (117) (135) (145) (445) (462) (472) (497) (515) (525) (551)Winter 18 Hour 36 0 0 146 129 76 (22) (43) (61) (71) (96) (113) (123) (426) (443) (453) (478) (495) (506) (531) Delta 19 0 0 19 19 20 20 20 20 21 21 22 22 18 19 19 19 19 20 20 18 Hour to 1 Hour Comparison Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 619 of 1125 August: 18 Hour Peak Position Forecast 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 REQUIREMENTS 1 Native Load -1,465 -1,482 -1,498 -1,510 -1,523 -1,536 -1,550 -1,563 -1,576 -1,590 -1,604 -1,618 -1,631 -1,646 -1,660 -1,674 -1,689 -1,703 -1,718 -1,7332 Firm Power Sales -212 -159 -159 -9 -9 -8 -8 -7 -7 -7 -7 -7 -7 -7 -7 -7 -7 -7 -7 -7 3 Total Requirements -1,677 -1,641 -1,657 -1,519 -1,532 -1,544 -1,557 -1,570 -1,584 -1,597 -1,611 -1,625 -1,639 -1,653 -1,667 -1,681 -1,696 -1,710 -1,725 -1,740 RESOURCES 4 Firm Power Purchases 29 29 29 29 29 26 26 26 26 25 25 25 25 25 25 25 25 25 25 25 5 Hydro Resources 701 707 663 631 638 583 580 622 624 622 622 624 622 622 624 622 622 624 622 622 6 Base Load Thermals 785 785 785 785 785 785 785 785 785 785 785 785 785 556 556 556 556 556 556 556 7 Wind Resources 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 08 Peaking Units 176 176 176 176 176 176 176 176 176 176 176 176 176 176 176 176 176 176 176 176 9 Total Resources 1,691 1,698 1,653 1,621 1,628 1,571 1,568 1,609 1,611 1,609 1,609 1,611 1,609 1,379 1,381 1,379 1,379 1,381 1,379 1,379 10 PEAK POSITION 14 57 -3 102 96 27 11 39 27 11 -2 -14 -30 -274 -286 -302 -317 -330 -346 -361 RESERVE PLANNING 11 Planning Margin 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 12 Total Ancillary Services Required -177 -176 -177 -170 -172 -173 -175 -176 -177 -179 -180 -181 -182 -166 -167 -167 -168 -169 -169 -17013Reserve & Contingency Availability 177 176 177 170 172 173 175 176 177 179 180 181 182 166 167 167 168 169 169 170 14 Demand Response 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 15 Total Reserve Planning 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 16 Peak Position w/ Contingency 14 57 -3 102 96 27 11 39 27 11 -2 -14 -30 -274 -286 -302 -317 -330 -346 -361 17 Implied Planning Margin 11% 14% 10% 18% 17% 13% 12% 14% 13% 12% 11% 10% 9%-7% -7% -8% -9% -9% -10% -11% 18 NPCC Market Adjustment 0 0 3 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 19 Peak Position Net Market 14 57 0 102 96 27 11 39 27 11 (2) (14) (30) (274) (286) (302) (317) (330) (346) (361) 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 Summer 1 Hour 114 159 85 193 185 113 95 125 112 94 79 65 48 (191) (204) (221) (236) (249) (267) (282)Summer 18 Hour 14 57 0 102 96 27 11 39 27 11 (2) (14) (30) (274) (286) (302) (317) (330) (346) (361) Delta (100) (102) (85) (91) (89) (86) (84) (87) (85) (83) (81) (80) (78) (83) (83) (82) (81) (80) (79) (79) 18 Hour to 1 Hour Comparison Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 620 of 1125 Market and Portfolio Scenario Development John Lyons, Senior Resource Policy Analyst Fourth Technical Advisory Committee Meeting 2013 Electric Integrated Resource Plan February 6, 2013 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 621 of 1125 Scenarios in the 2013 IRP Scenarios provide details about potential impacts of different critical planning assumptions that could have a major impact on resource choices, such as technological, regulatory or environmental changes. Scenarios will be developed for: • Avista’s current load and resource portfolio • Preferred Resource Strategy (PRS) • Wholesale electric market • Different resource options 2 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 622 of 1125 2013 IRP Scenario Types 3 1.Deterministic Market Scenarios: use expected input levels (natural gas prices, hydro, loads, wind, and thermal outages) 2.Stochastic Market Scenarios: use a Monte Carlo analysis 3.Portfolio Scenarios: show alternative portfolios to highlight the cost differences from the PRS Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 623 of 1125 Deterministic Market Scenarios 4 Deterministic scenarios test the PRS across several fundamentally different futures: • Low and High Natural Gas Prices • Carbon Pricing • No Coal Retirements • High Storage Technology Penetration • Increasing RPS Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 624 of 1125 Stochastic Market Scenarios 5 • Expected Case: assumes average levels of hydro, loads, gas prices, wind, emissions prices and forced outages • Carbon Pricing Scenario: various pricing trajectories similar to the 2011 IRP expected case Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 625 of 1125 Portfolio Scenarios 6 • Market reliance only •CO2 credit allocations • 2011 PRS • Increased Washington RPS – 25% by 2025 • National renewable energy standard – 20% with and without hydro netting • Alternative Planning Margins • CT and CCCT tipping points • Solar cost tipping point • Nuclear cost tipping point • Coal sequestration cost tipping point Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 626 of 1125 Colstrip Scenarios 7 • 2017 Retirement Date • 2022 Retirement Date • Incremental Pollution Controls • Carbon Sequestration • Railed Coal Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 627 of 1125 Avista’s 2013 Electric Integrated Resource Plan Technical Advisory Committee Meeting No. 5 Agenda Wednesday, March 20, 2013 Conference Room 428 Topic Time Staff 1. Introduction 9:00 2. Market Forecast Scenario Results 9:05 Gall and Conservation Avoided Costs 3. Conservation Results 9:30 Borstein 4. Break 11:00 5. Demand Response 11:15 Doege 6. Lunch 12:00 7. 2013 IRP Preferred Resource Strategy 1:00 Gall 8. Break 2:00 9. Portfolio Scenarios 2:15 Gall 10. Adjourn 3:00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 628 of 1125 Electric Price Forecast Scenario Analysis James Gall Fifth Technical Advisory Committee Meeting 2013 Electric Integrated Resource Plan March 20, 2013 1 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 629 of 1125 Scenario Planning This IRP reviews two types of market scenarios to help understand how market forces can impact Avista’s resource strategy 1.Deterministic studies- point forecast of future major assumptions 2.Stochastic studies- Monte-Carlo style analysis using 500 iterations for major assumptions 2 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 630 of 1125 $0 $10 $20 $30 $40 $50 $60 $70 $80 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 $ p e r M W h Flat Off -Peak On-Peak Expected Case Refresher Levelized Price: $44.08/MWh stochastic case 3 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 631 of 1125 Greenhouse Gas Pricing Scenario Developed to understand the ramifications of national greenhouse gas reduction legislation to Avista’s resource strategy This scenario uses 500 iterations with different potential CO2 pricing schemes using a cap-and-trade market mechanism Five weighted potential pricing structures were developed to create a wide range of potential futures (2014 $) Expected Case- $0/ton (33.3%) 2020 High- $30/ton (16.7%), 2025 High- $40/ton (16.7%) 2020 Low- $10/ton (16.7%), 2025 Low- $15/ton (16.7%) 4 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 632 of 1125 Greenhouse Gas Pricing Scenario Price Assumptions $0 $10 $20 $30 $40 $50 $60 $70 $80 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 $ p e r S h o r t T o n Weighted Average Expected Case 2025 High GHG Pricing Case 2025 Low GHG Pricing Case 2020 High GHG Pricing Case 2020 Low GHG Pricing Case 5 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 633 of 1125 Greenhouse Gas Scenario Market Prices $0 $20 $40 $60 $80 $100 $120 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 $ p e r M W h Weighted Avg GHG Case 2025 High GHG Pricing Case 2025 Low GHG Pricing Case 2020 High GHG Pricing Case 2020 Low GHG Pricing Case Expected Case deterministic case 6 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 634 of 1125 20-Year Levelized Greenhouse Gas Scenario Prices deterministic case $44.18 $49.22 $52.00 $46.51 $56.99 $47.19 $0 $10 $20 $30 $40 $50 $60 $70 $80 Expected Case Weighted Avg GHG Case 2025 High GHG Pricing Case 2025 Low GHG Pricing Case 2020 High GHG Pricing Case 2020 Low GHG Pricing Case $ p e r M W h 7 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 635 of 1125 0% 10% 20% 30% 40% 50% 60% Weighted Avg GHG Case 2025 High GHG Pricing Case 2025 Low GHG Pricing Case 2020 High GHG Pricing Case 2020 Low GHG Pricing Case Pe r c e n t I n c r e a s e The Real Increase to Electric Market Prices Average increase to market prices between 2025-2033, as compared to the Expected Case 8 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 636 of 1125 Greenhouse Gas Scenario Reductions - 50 100 150 200 250 300 350 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 Mi l l i o n s o f M e t r i c T o n s 2025 High GHG Pricing Case 2025 Low GHG Pricing Case 2020 High GHG Pricing Case 2020 Low GHG Pricing Case Weighted Avg GHG Case Expected Case 1990 Levels deterministic case 9 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 637 of 1125 $0 $10 $20 $30 $40 $50 $60 $70 $80 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 $ p e r M W h No Coal Retirements Expected Case No Coal Plant Retirement Scenario Expected Case: $44.18/MWh levelized No Coal Retirements: $42.93/MWh levelized - Retains 12,000 MW of coal generation for the duration of the forecast deterministic case 10 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 638 of 1125 - 50 100 150 200 250 300 350 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 Mi l l i o n s o f M e t r i c T o n s No Coal Retirements Expected Case Greenhouse Gas Emissions Increase Without Coal Retirements US Western Interconnect GHG emissions are reduced by 8 percent. This is an effective cost of $87 per short ton of GHG in 2014 dollars deterministic case 11 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 639 of 1125 State RPS’s Increased Scenario -Assumes in beginning in 2025, states with lower RPS begin new higher standards 0%10%20%30%40%50%60% Arizona California Colorado Idaho Montana New Mexico Nevada Oregon Utah Washington Wyoming Renewable Energy Goal Expected Case RPS Scenario Adds Wind: 7,000 MW Solar: 29,000 MW Other: 1,000 MW Cost: $80 billion (2012$) 12 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 640 of 1125 Changes to Market Prices and GHG Emissions 0% 2% 4% 6% 8% 10% 2025 2026 2027 2028 2029 2030 2031 2032 2033 Pe r c e n t R e d u c t i o n Reduction in Market Prices Reduction in GHG Added cost of RPS is equivalent to a GHG cost of $180 per short ton (2014 dollars) 13 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 641 of 1125 Conservation Avoided Costs James Gall Fifth Technical Advisory Committee Meeting 2013 Electric Integrated Resource Plan March 20, 2013 14 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 642 of 1125 How to Value Conservation {(E + PC + R) * (1 + P)} * (1 + L) + DC * (1 + L) Where: E = market energy price (calculated by Aurora, including forecasted CO2 mitigation) PC = new resource capacity savings (calculated by PRiSM) R = Risk premium to account for RPS and rate volatility reduction (calculated by PRiSM) P = Power Act preference premium (10% assumption) DC = distribution capacity savings (~$10/kW-year based on Heritage Project calculation) L = transmission and distribution losses (6.1% assumption based on Avista’s system average losses) 15 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 643 of 1125 Efficient Frontier Approach Assumes no additional Conservation Resources Portfolio Cost Po r t f o l i o R i s k Market $44.63/ MWh Capacity $107 kW-Yr Risk 0.29/ MWh Market Only PRS Mix Efficient Frontier 16 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 644 of 1125 Avoided Cost Calculation For 1 MW Measure with Flat Delivery Item $/MWh Energy Price 44.63 Capacity Savings 13.33 Risk Premium 0.29 Subtotal 58.26 Item $/MWh 10% Preference 6.19 Distribution Capacity Savings 0.88 T&D losses 2.72 Subtotal 9.79 Avoided Cost: $68.05 per MWh 2011 IRP was $104.39/MWh Analysis based on earlier draft of Market Prices 17 Converts $107/kW-yr to $/MWh Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 645 of 1125 Avista Conservation Potential Assessment – 2013 Update Overview of Approach and Analysis Results March 20, 2013 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 646 of 1125 2 Agenda • Introductions • Study objectives • Analysis approach • Summary of results • Consistency with NWPCC Methodology Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 647 of 1125 3 Introductions Ingrid Rohmund Practice Lead, Energy Analysis and Planning Jan Borstein Project Manager Various analysts EnerNOC Team EnerNOC Utility Solutions Consulting • Previously Global Energy Partners, and before that a part of EPRI • Practice areas: • Energy Analysis & Planning • Program Evaluation and Load Analysis • Engineering Services • 30 full-time consultants • Economists/statisticians • Engineers Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 648 of 1125 4 EnerNOC experience with potential studies Northwest: Avista Utilities* Idaho Power Seattle City Light* Portland GE* BPA Inland P&L* Cowlitz PUD* OTECC Southwest: LADWP State of NM State of HI National/Regional: EPRI National DSM Study FERC Nat’l Assessment of DR IEE Analysis of Codes and Standards* Midwest ISO EE and DR Assessment International: Manitoba Hydro ECRA (Saudi Arabia) ElectraNet (Australia) KERI (Korea)* Midwest : Ameren Missouri* Ameren Illinois Indianapolis P&L Citizens Energy Vectren Iowa TVA Northeast: Con Edison of NY PECO Energy New Jersey BPU Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 649 of 1125 5 Study objectives • Study continues Avista’s process of updating estimates of conservation potential on a regular basis • Specific objectives: •Provide credible and transparent estimates of conservation potential •Assess savings by measure or bundled measure and sector •Support Avista’s IRP development •Establish 2014-2015 biennial target per requirements of Washington I-937 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 650 of 1125 6 Analysis Approach Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 651 of 1125 7 Study objectives Characterize the Market Base-year energy use by segment Prototypes and energy analysis (BEST) Avista Forecast data Codes and standards RTF data Secondary data Project the Baseline End-use projection by segment Screen Measures and Options Measure descriptions Avista program data, TRM Avoided costs NWPCC/RTF workbooks Technical and economic potential Establish Customer Acceptance Program results Other studies Market acceptance rates Achievable potential Synthesize Review Annual Business Plans Sensitivity analysis Study results Avista billing data Program data Energy Market Profiles RBSA and other saturation surveys Secondary data Previous study results Study approach Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 652 of 1125 8 Market segmentation by rate class, 2009 Sector Rate Schedule(s) Number of meters (customers) 2009 Electricity sales (MWh) Residential 001 299,714 3,634,086 General Service 011, 012 46,387 738,505 Large General Service 021, 022 4,808 2,256,882 Extra Large GS – Comm. 025 12 336,047 Extra Large GS – Ind* 19 809,298 Pumping 031, 032 3,673 194,884 Total 354,613 7,969,701 * Idaho 25P was included in previous CPA but for the 2013 study it has been analyzed separately from other large industrial customers. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 653 of 1125 9 Residential market characterization, 2009 • Market segmentation developed using U.S. Census American Community Survey data • Limited Income is defined as customers with annual income approximately two times the poverty level Segment Annual Use (1000 MWh) Number of Customers Intensity (kWh/HH) % of Total Usage Single Family 2,399 168,339 14,250 66% Multi Family 202 23,456 8,613 6% Mobile Home 128 10,022 12,724 4% Limited Income 906 97,896 9,251 25% Total 3,634 299,714 12,125 100% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 654 of 1125 10 Residential market profile, 2009 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 655 of 1125 11 Baseline projection •Model equipment choices for replacement or new construction •Define baseline purchase shares —begin with Annual Energy Outlook shipments data and modify for Avista data and program history •Incorporates building codes and appliance standards currently enacted •In some cases, this eliminates potential future savings, as higher efficiency option becomes the baseline, least efficient option Today's Efficiency or Standard Assumption 1st Standard (relative to today's standard) 2nd Standard (relative to today's standard) End Use Technology 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Central AC Room AC Cooling/Heating Heat Pump Water Heater (<=55 gallons)Water Heater (>55 gallons) Screw-in/Pin Lamps Linear Fluorescent Refrigerator/2nd RefrigeratorFreezer Dishwasher Clothes Washer Clothes Dryer Cooling SEER 13 SEER 14 EER 9.8 EER 11.0 SEER 13.0/HSPF 7.7 SEER 14.0/HSPF 8.0 Water Heating EF 0.90 EF 0.95 EF 0.90 Heat Pump Water Heater NAECA Standard 25% more efficient NAECA Standard 25% more efficient Appliances Lighting Incandescent Advanced Incandescent - tier 1 Advanced Incandescent - tier 2 T8 Conventional (355 kWh/yr) 14% more efficient (307 kWh/yr) Conventional (MEF 1.26 for top loader)MEF 1.72 for top loader MEF 2.0 for top loader Conventional (EF 3.01)5% more efficient (EF 3.17) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 656 of 1125 12 Baseline projection •Drivers • Market size / customer growth • Income growth • Avista retail rates forecast • Trends in end-use/technology saturations • Equipment purchase decisions • Cooling and heating degree days • Persons/household and physical home size • Elasticities by end use for each forecast driver •Calibrated model to align with 2010-2012 sales and conservation program history • Began with Sixth Power Plan measure ramp rates and adjusted to program achievements • Baseline projection aligns with sales + program achievements Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 657 of 1125 13 The baseline projection (absent future conservation) • The metric against which savings are measured. It includes: •Current saturations of appliances, equipment, and legacy measures •Assumptions about customer and economic growth •Trends in fuel shares and appliance/equipment saturations •Exogenous variables including electricity prices, income, etc. Sample Residential Projection (Use per Household ) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 658 of 1125 14 Develop three levels of potential Potential studies identify future opportunities for EE that can be achieved through programs Technical Potential Theoretical upper limit of conservation, where all efficiency measures are phased in regardless of cost Economic Potential Conservation potential that includes measures that are cost-effective Achievable Potential Conservation potential that can be realistically achieved, accounting for customer adoption rates and how quickly programs can be implemented Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 659 of 1125 15 Economic screen Measure characterization Conservation measure assessment approach Measure descriptions Energy savings Costs Lifetime Applicability EnerNOC universal measure list Building simulations EnerNOC measure data library NWPCC Client measure data library (RTF, TRMs, evaluation reports, etc.) Avoided costs, discount rate, delivery losses Client review / feedback Inputs Process Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 660 of 1125 16 Potential Results Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 661 of 1125 17 All sectors potential • Cumulative achievable savings potential in 2014 is 4.4 aMW • Cumulative achievable savings potential in 2015 is 8.7 aMW 2014 2015 2018 2023 2028 2033 Cumulative Savings (MWh) Achievable Potential 38,726 76,352 300,112 610,600 928,320 1,271,323 Economic Potential 272,830 446,842 1,127,376 1,723,424 2,312,719 2,675,318 Technical Potential 1,173,173 1,392,531 2,374,256 3,366,522 4,122,161 4,604,718 Cumulative Savings (aMW) Achievable Potential 4.4 8.7 34.3 69.7 106.0 145.1 Economic Potential 31.1 51.0 128.7 196.7 264.0 305.4 Technical Potential 133.9 159.0 271.0 384.3 470.6 525.7 0 50 100 150 200 250 300 350 400 450 500 2015 2018 2023 2028 En e r g y S a v i n g s ( a M W ) Achievable Potential Economic Potential Technical Potential Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 662 of 1125 18 All sectors potential 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 En e r g y C o n s u m p t i o n ( 1 , 0 0 0 M W h ) Baseline Forecast Achievable Potential Economic Potential Technical Potential Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 663 of 1125 19 All sectors potential - 20 40 60 80 100 120 140 160 180 Cu m u l a t i v e A c h i e v a b l e P o t e n t i a l S a v i n g s ( a M W ) ID Pumping ID C&I ID Res WA Pumping WA C&I WA Res Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 664 of 1125 20 Residential potential • Cumulative achievable savings potential is 1.9 aMW in 2014 • Grow to 3.4 aMW in 2015 2014 2015 2018 2023 2028 2033 Cumulative Savings (MWh) Achievable Potential 16,247 30,197 124,161 202,569 319,277 503,671 Economic Potential 206,661 322,861 781,184 1,051,855 1,430,505 1,643,220 Technical Potential 987,175 1,070,490 1,415,574 1,557,797 1,870,448 2,071,698 Cumulative Savings (aMW) Achievable Potential 1.9 3.4 14.2 23.1 36.4 57.5 Economic Potential 23.6 36.9 89.2 120.1 163.3 187.6 Technical Potential 112.7 122.2 161.6 177.8 213.5 236.5 0 50 100 150 200 250 2015 2018 2023 2028 En e r g y S a v i n g s ( a M W ) Achievable Potential Economic Potential Technical Potential Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 665 of 1125 21 Residential achievable savings potential – top measures • Lighting – largely CFLs (including specialty lamps), with LEDs starting to pass the cost- effectiveness test in 2015 • Space heating savings from conversion to gas and ductless heat pumps as well as new programs for duct sealing and shell/infiltration measures • Water heating savings from conversion to gas; also low-flow fixtures, tank/pipe insulation • Refrigerator and freezer recycling • Programmable thermostats • ENERGY STAR homes and new construction efficiency Cumulative Achievable Potential in 2018 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 666 of 1125 22 Commercial & Industrial potential • Cumulative potential in 2015 is 5.3 aMW 2014 2015 2018 2023 2028 2033 Cumulative Savings (MWh) Achievable Potential 22,478 46,155 175,951 400,188 609,043 767,651 Economic Potential 66,170 123,981 346,193 627,462 1,474,041 1,032,097 Technical Potential 185,998 322,041 958,683 1,782,838 2,251,713 2,533,019 Cumulative Savings (aMW) Achievable Potential 2.6 5.3 20.1 45.7 69.5 87.6 Economic Potential 7.6 14.2 39.5 71.6 168.3 117.8 Technical Potential 21.2 36.8 109.4 203.5 257.0 289.2 0 50 100 150 200 250 300 2015 2018 2023 2028 En e r g y S a v i n g s ( a M W ) Achievable Potential Economic Potential Technical Potential Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 667 of 1125 23 C&I Conservation potential – top measures • Lighting – mix of lamps including LEDs, various controls • HVAC – controls, economizers, variable air volume (VAV) ventilation • Machine drive and process – 6% from various measures for air compressors, fans, and pumps • Also low-flow fixtures, tank/pipe insulation • Office equipment – efficient servers, desktop computers, and printers Achievable Potential in 2018 Cooling 2%Space Heating 0% Ventilation 6%Water Heating 6% Interior Lighting 47% Exterior Lighting 8% Refrigeration 5% Food Preparation 1% Office Equipment 19% Process 2% Machine Drive 4% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 668 of 1125 24 Conservation potential – sensitivity to avoided costs - 200,000 400,000 600,000 800,000 1,000,000 1,200,000 1,400,000 1,600,000 1,800,000 Re s , C & I C u m u l a t i v e A c h i e v a b l e P o t e n t i a l S a v i n g s (M W h ) Reference Case Avoided Costs 150% of Reference Case 125% of Reference Case 75% of Reference Case Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 669 of 1125 25 Supply curve for 2015 – cumulative savings • Nearly 35 GWh of savings are low- or no-cost. $0.00 $0.05 $0.10 $0.15 $0.20 $0.25 $0.30 $0.35 $0.40 0 10 20 30 40 50 60 70 80 Co s t o f C o n s e r v e d En e r g y ($ / k W h ) Savings (GWh) Levelized Cost/kWh for Measures in 2015 Levelized Cost/kWh Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 670 of 1125 26 Supply curves for 2020 – avoided costs scenarios $- $0.10 $0.20 $0.30 $0.40 $0.50 $0.60 $0.70 -100 200 300 400 500 600 Co s t p e r k W h s a v e d ( 2 0 0 9 $ ) Cumulative Savings (GWh) Reference case 100% avoided costs 75% avoided costs scenario 125% avoided costs scenario 150% avoided costs scenario ∆ Portfolio average cost Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 671 of 1125 27 Annual and cumulative savings 0 60 120 180 240 300 360 420 480 540 600 0 2 4 6 8 10 12 14 16 18 20 19 7 8 19 8 0 19 8 2 19 8 4 19 8 6 19 8 8 19 9 0 19 9 2 19 9 4 19 9 6 19 9 8 20 0 0 20 0 2 20 0 4 20 0 6 20 0 8 20 1 0 20 1 2 20 1 4 20 1 6 20 1 8 20 2 0 20 2 2 20 2 4 20 2 6 20 2 8 20 3 0 cu m u l a t i v e s a v i n g s ( a M W ) an n u a l s a v i n g s ( a M W ) Cumulative Online Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 672 of 1125 28 Consistency with the NWPCC Methodology Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 673 of 1125 29 Initiative 937 Conservation Provisions • Washington Initiative 937 approved by voters in 2006 • Requires that utilities estimate 10-year potentials •Utility Analysis Option must be consistent with the methodology of the Northwest Power and Conservation Council’s most recent Power Plan •Used to set a two-year biennium conservation target •Must be repeated every two years Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 674 of 1125 30 Consistency with Council Methodology • End-use model — bottom-up •Building characteristics •Fuel and equipment saturations •Stock accounting based on measure life •Codes and standards •Existing and new vintage •Lost- and non-lost opportunities •Measure saturation and applicability •Measure savings, including HVAC interactions and contribution to peak •Ramp rates to model market acceptance and program implementation Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 675 of 1125 31 Consistency with Council Methodology (cont.) • Measures •Include nearly all in Sixth Power Plan •Plus others. e.g., conversion of electric water heaters / furnaces to gas •Sources for measure characterization • RTF measure workbooks • Avista Technical Reference Manual (TRM ) • EnerNOC databases, which draw upon same sources used by RTF • Economic potential, total resource cost (TRC) test •Considers non-energy benefits •Considers HVAC interactions •Include 10% credit based on Conservation Act • Achievable potential – ramp rates •Based on Council Sixth Power Plan ramps rates •Modified to reflect Avista program history Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 676 of 1125 32 Avista-specific items • Avista customer characteristics •Calibrated to Avista 2009 sales by sector •Average use per customer based on actual billing data •Equipment saturations and unit energy consumption calibrated to match usage •Updated with newly available NW Residential Building Stock Assessment data, e.g., information on measure saturation • Building codes and appliance standards updated as of 2012 • Avista-specific customer growth forecasts • Avista retail rate and avoided cost forecasts • Ramp rates adjusted to match Avista program history Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 677 of 1125 33 Measure reconciliation • Develop comprehensive measure list using •Avista existing programs and business plan •RTF Unit Energy Savings workbooks •Sixth Power Plan •Previous Avista CPA •Recent EnerNOC studies Water heating measures Conventional (EF 0.95) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 678 of 1125 34 Measure reconciliation (cont.) • Characterization •Description •Costs •Savings •Applicability •Lifetime • Measure data sources •RTF UES measure databases •Sixth Power Plan Workbooks •Avista TRM •SEEM data •BEST simulations •EnerNOC databases • Convert to LoadMAP format •Savings as % of baseline use •Per household, scaled to match Avista calibration •Per sq. ft. for C&I •Remove non-applicable adjustments such as storage rate Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 679 of 1125 35 Market adoption rates for achievable potential •Achievable potential requires assumptions about customer acceptance and market maturity •Northwest Power & Conservation Council’s Sixth Power Plan Lost Opportunity ramp rates used to develop market acceptance factors •It is most important to focus on near-term ramp rates because studies are updated every two years Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 680 of 1125 36 Market adoption rates for achievable potential (cont.) •Calibrated ramp rates to actual program achievements for Lighting and HVAC measures •Acceptance different from Sixth Power Plan rates 0% 10% 20% 30% 40% 50% 60% 70% 80% 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Ma r k e t A c c e p t a n c e R a t e s Year Lighting Acceptance Rates Lighting CFL and LED LostOp_5yr 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Ma r k e t A c c e p t a n c e R a t e s Year HVAC Equipment Acceptance Rates Res HVAC mature program LostOp_20yr Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 681 of 1125 37 Study schedule •Presented project approach to the TAC on November 7, 2012 •Delivered preliminary results in late-February 2013 •Present final study results to TAC March 20, 2013 •Fine-tune analysis •Draft report in April, 2013 •Support the filing in August 2013 with a complete CPA report Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 682 of 1125 Ingrid Rohmund Practice Lead 760.943.1532 irohmund@enernoc.com Jan Borstein Project Manager 303.530.5195 jborstein@enernoc.com www.enernoc.com Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 683 of 1125 Demand Response Technical Advisory Committee #5 March 20th, 2013 Leona Doege Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 684 of 1125 What is Demand Response Passive: Pricing programs…. Time-of-Use, Critical Peak Pricing, Peak Time Rebate Active: Direct Load Control Combination programs…… Pricing program with enabling technology Purpose: Reduce or shift load at certain times Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 685 of 1125 Passive Demand Response Supporting Dynamic Pricing: • Avista’s Billing System doesn’t allow for dynamic rates • Q3 2014, New Billing System will be capable. • Metering and its infrastructure would need to be upgraded in many areas. • Merit to the inverted tail block rate structure currently used. “Inclining block rates can reduce energy consumption by 6 percent in the near term and more over the long haul” (used in contrast to a flat rate structure, Ahmad Faroqui, “Inclining toward Energy Efficiency,” Public Utilities Fortnightly, August 2008 (http://www.fortnightly.com/exclusive.cfm?o_id=94 ) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 686 of 1125 Direct Load Control Mass Market: Residential loads, electric space heat, central air-conditioning, electric water heating, pool pumps. Commercial Programs: Irrigation, variety of commercial/industrial processes. Often a 3rd party aggregator is used. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 687 of 1125 Avista’s Direct Load Control Programs North Idaho Pilot • 2007-2009: • 50 DLC Thermostats, 50 DLC Switches • 10 Events called ranging from 2 to 4 hours each, in both the summer and winter seasons. • Heat Pumps, Water Heaters, Electric Forced Air Furnaces, Air Conditioning Smart Grid Demonstration Project Smart Thermostat Pilot Program • June 2012 – Dec 31st, 2014 • 69 Thermostats, capable of 1500 • Events are automatic ranging from 10 minutes to 24 hours, temp off-set of 2 degrees. • Currently in testing mode, ready for real dispatch summer season 2013. • Heat Pumps, Electric Forced Air Furnaces, Air Conditioning Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 688 of 1125 Other Avista DR Activities 2001 Western Energy Crisis Nickel Buy Back Program Operational issues of July 2006 Public Plea Bi-Lateral Agreement with Industrial Customers Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 689 of 1125 Knowledge Gained DR Works as Designed DR Builds Customer Engagement DLC Value lies in Capacity High Penetration of Natural Gas in Avista service area Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 690 of 1125 Demand Response Costs (Regional Estimates from NPCC) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 691 of 1125 What’s Next ? Discussion of DR Options Q&A Thank you for your time! Leona Doege DSM Program Manager (509) 495-4289 leona.doege@avistacorp.com Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 692 of 1125 Draft 2013 Preferred Resource Strategy James Gall Fifth Technical Advisory Committee Meeting 2013 Electric Integrated Resource Plan March 20, 2013 1 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 693 of 1125 DRAFT 2013 IRP Modeling Process Preferred Resource Strategy AURORA “Wholesale Electric Market” 500 Simulations PRiSM “Avista Portfolio” Efficient Frontier Fuel Prices Fuel Availability Resource Availability Demand Environmental Considerations Existing Resources Resource Options Transmission Resource & Portfolio Margins Conservation Trends Existing Resources Avista Load Forecast Energy, Capacity, & RPS Balances New Resource Options & Costs Cost Effective T&D Projects/Costs Cost Effective Conservation Measures/Costs Mid-Columbia Prices Stochastic Inputs Deterministic Inputs Capacity Value Avoided Costs 2 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 694 of 1125 DRAFT 2011 Preferred Resource Strategy Year Ending Resource 2012 Wind (~ 42 aMW REC) 2018 Simple Cycle CT(~ 83 MW) 2020 Simple Cycle CT (~ 83 MW) 2018-2019 Thermal Upgrades (~ 7 MW) 2018-2019 Wind (~ 43 aMW REC) 2023 Combined Cycle CT (~ 270 MW) 2026/27 Combined Cycle CT (~ 270 MW) 2029 Simple Cycle CT (~ 46 MW) 2012+ Distribution Feeder Upgrades (13 aMW by 2031) 2012+ Conservation (310 aMW by 2031) Palouse Wind 8.9 aMW in 2012* Smart Grid/Feeder Rebuilds * Early estimate to be verified by third party and does not include regional savings from NEEA 3 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 695 of 1125 DRAFT Annual Energy Position 0 200 400 600 800 1,000 1,200 1,400 1,600 1,800 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 av e r a g e m e g a w a t t s Hydro Resources Base/Intermediate Resources Net Firm Contracts Peaking Resources Wind Resources Load Load + Contingency Planning 4 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 696 of 1125 DRAFT Winter Single Hour Peak Position 0 500 1,000 1,500 2,000 2,500 3,000 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 me g a w a t t s Hydro Resources Base/Intermediate Resources Net Firm Contracts Peaking Resources Load Load + Contingency Planning 5 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 697 of 1125 DRAFT Summer Single Hour Peak Position 0 500 1,000 1,500 2,000 2,500 3,000 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 me g a w a t t s Hydro Resources Base/Intermediate Resources Net Firm Contracts Peaking Resources Load Load + Contingency Planning 6 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 698 of 1125 DRAFT Washington Energy Independence Act Compliance 0 20 40 60 80 100 120 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 Av e r a g e M W Purchases Prior Year RECs New Resources Palouse Wind Kettle Falls Hydro Upgrades Requirement Assumes conservative estimate of Kettle Falls with 75 percent capacity factor 7 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 699 of 1125 DRAFT Load Forecast Scenarios - 200 400 600 800 1,000 1,200 1,400 1,600 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 av e r a g e m e g a w a t t s Expected Case Low Growth Case High Growth Case Low-Medium Case 8 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 700 of 1125 DRAFT PRiSM Objective Function Linear program solving for the optimal resource strategy to meet resource deficits over the planning horizon. Model selects its resources to reduce cost, risk, or both. Minimize: Total Power Supply Cost on NPV basis (2014-2054 with emphasis on the first 14 years of the plan) Subject to: Risk Level Capacity Need +/- deviation Energy Need +/- deviation Renewable Portfolio Standards Resource Limitations and Timing 9 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 701 of 1125 DRAFT Efficient Frontier  Demonstrates the trade off between cost and risk  Avoided Cost Calculation Ri s k Least Cost Portfolio Least Risk Portfolio Find least cost portfolio at a given level of risk Short-Term Market Market + Capacity + RPS = Avoided Cost Capacity Need + Risk Cost 10 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 702 of 1125 DRAFT Natural Gas Turbines Cost/Risk Tradeoffs Frame CT Recip. Engines CCCT Ri s k Cost Aero CT Ignoring size constraints Hybrid CT All gas peaking turbines are “nearly” the same cost/risk and will have to be compared in an RFP process near acquisition 11 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 703 of 1125 DRAFT Natural Gas Turbines Cost/Risk Tradeoffs Frame CT Recip. Engines CCCT Ri s k Cost Aero CT Includes size constraints Hybrid CT 12 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 704 of 1125 DRAFT $- $10 $20 $30 $40 $50 $60 $70 $80 $90 $100 $400 $420 $440 $460 $480 $500 $520 $540 $560 $580 20 2 8 S t d e v Expected Levelized Cost (2014-2033) (2013$) Efficient Frontier ($millions) Least Cost Market Only Preferred Resource Strategy Least Risk 13 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 705 of 1125 DRAFT Efficient Frontier- Percent Change -70.0% -60.0% -50.0% -40.0% -30.0% -20.0% -10.0% 0.0% 0.0%5.0%10.0%15.0%20.0%25.0%30.0% De c r e m e n t a l R i s k Incremental Cost 14 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 706 of 1125 DRAFT Draft 2013 Preferred Resource Strategy 0 100 200 300 400 500 600 700 800 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 Na m e p l a t e M e g a w a t t s Demand Response Plant Upgrade Market Other Coal Other Renewables Solar Wind SCCT CCCT Conservation 15 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 707 of 1125 DRAFT Draft 2013 Preferred Resource Strategy Resource By the End of Year Winter Peak (MW) Energy Capability (aMW) SCCT 2019 88 69 Rathdrum CT Upgrade 2021 2 6 SCCT 2023 46 40 SCCT 2026 78 62 CCCT 2026 281 245 SCCT 2029-32 79 69 Generation Total 574 491 Conservation 2014-33 199 147 Demand Response 2022-30 20 0 Distribution Efficiencies 2014-16 <1 <1 16 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 708 of 1125 DRAFT Conservation Forecast 0 40 80 120 160 200 0 3 6 9 12 15 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 Cu m u l a t i v e ( a M W ) an n u a l ( a M W ) Energy (annual) Energy (cumulative) 17 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 709 of 1125 DRAFT Cost of Conservation $0 $20 $40 $60 $80 $100 $120 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 Cost (Millions) Levelized $/MWh 18 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 710 of 1125 DRAFT Avista Greenhouse Gas Emissions 19 - 0.05 0.10 0.15 0.20 0.25 0.30 0.35 0.40 0.45 0.50 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 Sh o r t T o n s p e r M W h Sh o r t T o n s ( M i l l i o n s ) Short Tons (Avg) Short Tons per MWh Includes generating resources under Avista control Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 711 of 1125 DRAFT Draft 2013 PRS Capital Requirements (and Conservation Expense) $0 $200 $400 $600 $800 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 Mi l l i o n s ( A n n u a l ) Capital (Millions) Conservation (annual) Cumulative (Millions) Conservation (Cumulative) 20 Blue bars and Red line is generation capital investment White bars and Red line is cost effective conservation Chart illustrates comparison of generation to conservation investment Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 712 of 1125 DRAFT Power Supply Cost Forecast (Range) 0 200 400 600 800 1,000 1,200 1,400 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 Mi l l i o n s ( N o m i n a l ) Expected Cost 2 Sigma Low 2 Sigma High Max 21 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 713 of 1125 DRAFT Power Supply Cost Forecast Index ($/MWh) 0 20 40 60 80 100 120 140 160 180 200 19 9 9 20 0 1 20 0 3 20 0 5 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 20 2 7 20 2 9 20 3 1 20 3 3 po w e r s u p p l y c o s t i n d e x ( 2 0 1 2 = 1 0 0 ) DRAFT 22 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 714 of 1125 Resource Strategy Scenarios James Gall Fifth Technical Advisory Committee Meeting 2013 Electric Integrated Resource Plan March 20, 2013 1 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 715 of 1125 DRAFT Scenario Modeling Status Update Scenarios still in progress Conservation Stochastic carbon pricing (and other CO2 related scenarios) Colstrip scenarios These will be presented at the Sixth TAC meeting on June 19, 2013 2 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 716 of 1125 DRAFT $- $10 $20 $30 $40 $50 $60 $70 $80 $90 $100 $400 $420 $440 $460 $480 $500 $520 $540 $560 $580 20 2 8 S t d e v Expected Levelized Cost (2014-2033) (2013$) Efficient Frontier ($millions) Least Cost Market Only Preferred Resource Strategy Least Risk 3 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 717 of 1125 DRAFT Portfolios Along the Efficient Frontier Risk Level Nameplate (MW) PRS High Medium High Medium Medium Low Low CCCT 270 - 270 540 270 270 SCCT 278 549 251 190 149 51 Wind - - - 165 99 350 Solar - - - - - - Other Renewables - - - - - 50 Coal (sequestered) - - - - 250 295 Other - - - - - - Market - - - - - - Plant Upgrade 6 6 85 - 80 80 Demand Response 20 20 20 - 10 15 Total 574 575 626 895 857 1,110 Change in Cost (2028) -1.0% 1.4% 21.3% 75.8% 109.6% Change in Risk (2028) 11.0% -3.5% -19.4% -35.9% -53.1% 4 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 718 of 1125 DRAFT 2011 PRS Scenario Year Ending Resource 2012 Wind (~ 42 aMW REC) 2018 Simple Cycle CT(~ 83 MW) 2020 Simple Cycle CT (~ 83 MW) 2018-2019 Thermal Upgrades (~ 7 MW) 2018-2019 Wind (~ 43 aMW REC) 2023 Combined Cycle CT (~ 270 MW) 2026/27 Combined Cycle CT (~ 270 MW) 2029 Simple Cycle CT (~ 46 MW) 2012+ Distribution Feeder Upgrades (13 aMW by 2031) 2012+ Conservation (310 aMW by 2031) 5 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 719 of 1125 DRAFT 2011 IRP PRS With a lower load forecast and the passage of the biomass bill in Washington, the 2011 PRS overbuilds the needs for the 2013 IRP timeframe The adjusted 2011 PRS portfolio is 5.7% higher NPV and lowers power supply risk by 14%- the higher cost is due to overbuilding the expected demand requirements 6 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 720 of 1125 DRAFT 25% Washington RPS by 2025 Scenario The Washington Energy Independence Act (I-937) requires 15% of Washington retail sales to be from renewables by 2020 This scenario evaluates the costs and benefits if the goal is changed to 25% by 2025 0 20 40 60 80 100 120 140 160 180 200 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 Av e r a g e M W Palouse Wind Kettle Falls Hydro Upgrades Requirement 77 aMW Need 7 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 721 of 1125 DRAFT 0 20 40 60 80 100 120 140 160 180 200 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 Av e r a g e M W Purchases Prior Year RECs New Resources Palouse Wind Kettle Falls Hydro Upgrades Requirement 25% Washington RPS in 2025 – Scenario Results Hydro upgrades to Long Lake and Monroe Street (148 MW) could meet most of the incremental RPS requirement Assuming these resources provide winter capability and summer needs are met by market, this strategy would lower SCCT needs need by 93 MW The 2028 cost is 3.7% higher than PRS and risk is 1.8% lower Hydro upgrades 8 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 722 of 1125 DRAFT National Renewable Portfolio Standard Scenario If the federal government passed legislation requiring renewable generation (i.e. National RPS), this scenario addresses the change in resource strategy and potential costs This scenario assumes 10% of load is met by renewables by 2020, then 15% by 2025, and 20% by 2030 All Avista owned hydro generation would be netted from load to reduce the required quantity of “RECs” – any hydro upgrades would be netted against load rather than receive a REC credit For modeling purposes, no banking is assumed and average hydro is used for “hydro netting” 9 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 723 of 1125 DRAFT National RPS Scenario Renewable Requirements (aMW) 2015 2020 2025 2030 2033 Average Load 1,067 1,125 1,180 1,239 1,285 Average Hydro 495 481 481 481 481 Net Load 572 644 699 759 805 RPS % 0% 10% 15% 20% 20% RPS Required 0 64 105 152 161 Palouse Wind 40 40 40 40 40 Kettle Falls 42 43 43 42 43 Total Existing RECs 82 83 83 82 83 RECs Required 0 0 22 69 78 10 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 724 of 1125 DRAFT National RPS Scenario Portfolio Results Will require 230 MW of new wind capacity Hydro upgrades are not economic without a REC credit No other resources change within the Expected Case 20 year NPV increases 3.4% over the Expected Case 2028 Power Supply Costs are 4% higher and risk is 2.8% lower 11 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 725 of 1125 DRAFT Load Forecast Scenarios Impact to Net Position (800) (700) (600) (500) (400) (300) (200) (100) - 100 200 300 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 me g a w a t t s Winter Single Hour Peak Low Medium Low Expected Case High 12 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 726 of 1125 DRAFT Load Scenario Results Load Forecast Nameplate (MW) PRS Low Medium Low High CCCT 270 270 270 270 SCCT 278 32 91 408 Wind - 0 0 0 Solar - 0 0 0 Other Renewables - 0 0 0 Coal (seq) - 0 0 0 Other - 0 0 0 Market - 0 0 0 Plant Upgrade 6 6 6 6 Demand Response 20 15 20 20 Total 574 323 387 704 Change in Cost (2028) -5.3% -3.7% 3.4% Change in Risk (2028) -0.1% -0.5% -0.4% 13 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 727 of 1125 DRAFT High Planning Margin Study (Less Market Dependence) This scenario adds more capacity resource need earlier in the study horizon and at a higher quantity, similar to a high load growth scenario New resources would be required by the end of 2016 rather then the end of 2019 Requires 117 MW of additional capacity to be built (assumes met with peaking natural gas resource) Result 2.9% higher NPV, 2028 cost is 3.5% higher, risk level is similar to the PRS 14 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 728 of 1125 DRAFT Tipping Point Analyses Assumes no government incentives Find capital cost where resource would join a similar risk portfolio structure as the PRS Solar: $430 per kW ($3,500 per kW modeled) Solar suffers from providing no winter peak capacity, thus competes on an energy basis only (with little energy) IGCC Coal w/ sequestration: $750 per kW ($6,000 per kW modeled) Nuclear: $2,150 per kW ($7,000 per kW modeled) Nuclear and Coal has high O&M cost, if those costs were lowered a higher capital cost could be afforded 15 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 729 of 1125 Avista’s 2013 Electric Integrated Resource Plan Technical Advisory Committee Meeting No. 6 Agenda Wednesday, June 19, 2013 Conference Room 428 Topic Time Staff 1. Introduction 9:30 2. 2013 Final Preferred Resource Strategy 9:35 Gall 3. Break 10:15 4. Portfolio Scenario Analysis 10:30 Gall 5. Lunch 12:00 6. Net Metering and Buck-a-Block 1:00 Kalich 7. Break 1:30 8. Action Plan 1:45 Lyons 9. 2013 IRP Document Introduction 2:15 Kalich 10. Adjourn 3:00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 730 of 1125 2013 Preferred Resource Strategy James Gall, Senior Power Supply Analyst Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 731 of 1125 Reliability Needs -600 -500 -400 -300 -200 -100 0 100 200 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 me g a w a t t s / a v e r a g e m e g a w a t t s January 1 Hour Peak August 18 Hour Peak Energy 2 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 732 of 1125 Renewable Requirements Met 0 20 40 60 80 100 120 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 av e r a g e m e g a w a t t s Qualifying Hydro Upgrades Qualifying Resources Purchased RECs Available Bank3 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 733 of 1125 Efficient Frontier Analysis $20 Mil $30 Mil $40 Mil $50 Mil $60 Mil $70 Mil $80 Mil $325 Mil $350 Mil $375 Mil $400 Mil $425 Mil $450 Mil 20 2 8 p o w e r s u p p l y c o s t s t d e v 20 yr levelized annual power supply rev. req. Market Only Least Cost Least Risk Preferred Resource Strategy 4 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 734 of 1125 Preferred Resource Strategy Resource By the End of Year Nameplate (MW) Energy (aMW) Simple Cycle CT 2019 83 76 Simple Cycle CT 2023 83 76 Combined Cycle CT 2026 270 248 Rathdrum CT Upgrade 2028 6 5 Simple Cycle CT 2032 50 46 Total 492 453 Peak Reduction (MW) Energy Efficiency 2014-2033 221 164 Demand Response 2022-2027 19 0 Distribution Efficiencies 2014-2017 <1 <1 Total 240 164 Efficiency Improvements By the End of Year Energy (aMW) 5 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 735 of 1125 Resource Capital Requirements Year Investment Year Investment 2014 0.0 2024 91.6 2015 0.0 2025 0.0 2016 0.0 2026 0.0 2017 0.0 2027 421.7 2018 0.0 2028 97.0 2019 0.0 2029 2.4 2020 85.8 2030 0.0 2021 0.0 2031 0.0 2022 0.0 2032 0.0 2023 0.0 2033 83.6 2014-23 Total 85.8 2024-33 Totals 696.2 6 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 736 of 1125 Conservation Meets 42% of Load Growth 0 200 400 600 800 1,000 1,200 1,400 1,600 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 av e r a g e m e g a w a t t s Expected Case Without Conservation 1.71% 1.07% 7 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 737 of 1125 Past and Future Conservation 0 60 120 180 240 300 360 420 480 540 600 0 2 4 6 8 10 12 14 16 18 20 19 7 8 19 8 0 19 8 2 19 8 4 19 8 6 19 8 8 19 9 0 19 9 2 19 9 4 19 9 6 19 9 8 20 0 0 20 0 2 20 0 4 20 0 6 20 0 8 20 1 0 20 1 2 20 1 4 20 1 6 20 1 8 20 2 0 20 2 2 20 2 4 20 2 6 20 2 8 20 3 0 20 3 2 cu m u l a t i v e s a v i n g s ( a M W ) an n u a l s a v i n g s ( a M W ) Cumulative Online 8 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 738 of 1125 Conservation Supply Curve $0 $100 $200 $300 $400 $500 0 50 100 150 200 $ p e r M W h average megawatts Conservation Supply Curve Expected Case Conservation Note: excludes fuel switching and pumping programs; not grossed up for line-losses. 9 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 739 of 1125 Cost of Conservation 0 10 20 30 40 50 60 70 80 90 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 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 Energy Savings (aMW) Spending (millions $) Levelized Cost ($/MWh) Years Energy Savings (aMW) Avg Spending (millions $) Levelized Cost ($/MWh) 1997-2007 6.12 $7.58 $14.32 2008-2012 10.22 $19.89 $21.92 2014-2023 7.41 $21.58 $32.18 2024-2033 8.20 $49.51 $66.93 10 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 740 of 1125 Greenhouse Gas Emission Forecast 0.00 0.10 0.20 0.30 0.40 0.50 Mil 1 Mil 2 Mil 3 Mil 4 Mil 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 me t r i c t o n s p e r M W h me t r i c t o n s Total Tons per MWh of Load 11 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 741 of 1125 Power Supply Cost Index Forecast (2012$) 0 20 40 60 80 100 120 140 160 180 200 19 9 9 20 0 1 20 0 3 20 0 5 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 20 2 7 20 2 9 20 3 1 20 3 3 po w e r s u p p l y c o s t i n d e x Historical Forecast Includes: conservation spending, power/REC market transactions, fuel expense, power plant operations and maintenance costs, plant depreciation, cost of money, taxes, and other miscellaneous expenses. 12 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 742 of 1125 Portfolio Scenario Analysis James Gall, Senior Power Supply Analyst Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 743 of 1125 Scenarios • Efficient Frontier Analysis • Carbon Pricing • Conservation • Load Growth • Resource & Policy Specific Portfolios • Colstrip 2 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 744 of 1125 Efficient Frontier $20 Mil $30 Mil $40 Mil $50 Mil $60 Mil $70 Mil $80 Mil $325 Mil $350 Mil $375 Mil $400 Mil $425 Mil $450 Mil 20 2 8 p o w e r s u p p l y c o s t s t d e v 20 yr levelized annual power supply rev. req. Market Only Least Cost Least Risk Preferred Resource Strategy What are these portfolios? 3 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 745 of 1125 Portfolio Mix at Alternative Risk Levels Nameplate (MW) PRS High Risk Medium High Risk Medium Risk Medium Low Risk Low Risk CCCT 270 - 270 270 540 540 SCCT 299 566 296 216 100 68 Wind - - - 30 50 350 Solar - - - - - - Biomass - - - - - 50 Coal (seq) - - - - - - Hydro Upgrade - - - - - - Thermal Upgrade 6 6 6 85 85 80 Demand Response 19 20 20 8 12 17 Total (excluded DSM) 594 592 592 609 788 1,104 20-yr Levelized Cost (mill) $358.4 $357.9 $357.9 $362.3 $367.0 $396.0 2028 Power Supply Stdev (mill) $65.7 $74.0 $64.4 $60.5 $54.1 $40.2 2033 Greenhouse Gas Emissions (millions of metric tons) 3.2 2.9 3.4 3.4 3.9 3.8 4 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 746 of 1125 Carbon Pricing Effect to Efficient Frontier $25 Mil $50 Mil $75 Mil $100 Mil $300 Mil $350 Mil $400 Mil $450 Mil $500 Mil 20 2 8 p o w e r s u p p l y s t d e v 20 yr levelized annual power supply rev. req. Expected Case Carbon Pricing Scenario Carbon Pricing Scenario (Inc Conservation) PRS (Expected Case) PRS-(Carbon Pricing) PRS-Higher Conservation (Carbon Pricing) 5 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 747 of 1125 Carbon Pricing Scenario- Least Cost Strategy Peaking Technology Switches to Higher Efficient Turbines Portfolio 20-Yr Power Supply Levelized Cost Expected Case Carbon Pricing Scenario PRS $358.4 $367.3 PRS w/ Higher Conservation $365.0 $377.8 Carbon Pricing Scenario- LC RS $364.7 $374.5 Portfolio 2028 Power Supply Cost Standard Deviation Expected Case Carbon Pricing Scenario PRS $65.7 $72.6 PRS w/ Higher Conservation $63.9 $70.3 Carbon Pricing Scenario- LC RS $61.0 $63.6 6 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 748 of 1125 Conservation Avoided Cost Scenarios • Change cost effective point of conservation • 20 Year Avoided Cost for Conservation is $67.91/MWh Avoided Cost Percentage 20 Year aMW Delta aMW 75% 139 -25 100% 154 -10 Expected Case (110%) 164 0 125% 184 +20 150% 201 +37 7 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 749 of 1125 Conservation Avoided Cost Scenarios -70% -60% -50% -40% -30% -20% -10% 0% 10% 20% 30% -5%0%5%10%15%20%25% pe r c e n t c h a n g e f r o m P R S - ri s k percent change from PRS-cost Efficient FrontierPRS 75% AC 100% AC 125% AC 150% AC No Conservation 8 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 750 of 1125 Load Growth Sensitivities Winter Peak Position (900) (600) (300) - 300 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 me g a w a t t s Low Growth Medium Low Growth Expected Case High Growth 9 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 751 of 1125 Load Growth Scenarios: Resource Selection Year PRS Low Growth Medium Low Growth High Growth 2014 2015 2016 2017 2018 2019 83 MW SCCT 150 MW SCCT 2020 2021 2022 6 MW Upgrade 92 MW SCCT 2023 83 MW SCCT 90 MW SCCT 2024 2025 2026 270 MW CCCT 270 MW CCCT 270 MW CCCT 270 MW CCCT 2027 50 MW SCCT 92 MW SCCT 2028 6 MW Upgrade 2029 6 MW Upgrade 50 MW SCCT 2030 2031 2032 2033 50 MW SCCT 50 MW SCCT Demand Response (MW) 19 1 20 20 Conservation (aMW) 164 142 147 175 10 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 752 of 1125 Resource Strategies from Policy Changes Nameplate (MW) PRS Higher WA St. RPS National RPS Higher Capacity Margins 2011 PRS CCCT 270 270 270 270 540 NG Peaker 299 249 296 435 187 Wind - - 203 - 120 Solar - - - - - Biomass - - - - - Coal (seq) - - - - - Hydro Upgrade - 148 - - - Thermal Upgrade 6 6 6 6 - Demand Response 19 10 20 8 - Total (Excluding Conservation) 594 683 795 718 847 20-yr Levelized Cost (millions) $354.8 $360.3 $365.3 $364.2 $373.9 2028 Power Supply Stdev (millions) $65.7 $64.8 $63.6 $65.8 $54.0 2033 Greenhouse Gas Emissions (millions of metric tons) 3.2 3.2 3.3 3.4 3.7 11 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 753 of 1125 Resource Specific Portfolios -60% -50% -40% -30% -20% -10% 0% 10% 20% -5%0%5%10%15%20%25% pe r c e n t c h a n g e f r o m P R S - ri s k percent change from PRS-cost Efficient Frontier PRS 200 MW Wind (CT) 200 MW Solar (CT) Hydro Upgrades (CT) Two CCCTs Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 754 of 1125 Colstrip Scenarios • No Colstrip Resource Strategy Scenario – Colstrip is removed from portfolio beginning in 2018 – No costs/benefits included due to its removal • Regional Haze Program Scenario – Assumes Colstrip #3 & #4 must install SCR or shut down in 2027 – SCR costs are expected to be $105 million (Avista share) plus $560k each year in O&M or $8.39/MWh total cost levelized Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 755 of 1125 Resource Strategy Without Colstrip Resource By the End of Year Nameplate (MW) Energy (aMW) Combined Cycle CT 2017 270 248 Simple Cycle CT 2020 50 46 Simple Cycle CT 2023 50 46 Combined Cycle CT 2026 270 248 Simple Cycle CT 2026 51 47 Simple Cycle CT 2029 55 51 Simple Cycle CT 2032 50 46 Total 797 733 Peak Reduction (MW) Energy Efficiency 2014-2033 221 164 Demand Response 2022-2027 20 0 Distribution Efficiencies 2014-2017 <1 <1 Total 241 164 Efficiency Improvements By the End of Year Energy (aMW) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 756 of 1125 Colstrip Scenarios: Levelized Cost Comparison $482 $435 $460 $408 $0 Mil $100 Mil $200 Mil $300 Mil $400 Mil $500 Mil $600 Mil Carbon Pricing Scenario-RS w/o Colstrip Carbon Pricing Scenario-LC RS w/ Colstrip Expected Case- No Colstrip RS Expected Case- PRS le v e l i z e d p o w e r s u p p l y c o s t 15 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 757 of 1125 Greenhouse Gas Emissions without Colstrip - 0.10 0.20 0.30 0.40 0.50 Mil 1 Mil 2 Mil 3 Mil 4 Mil 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 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 me t r i c t o n s p e r M W h me t r i c t o n s Colstrip Reduction Other Resources Tons per MWh (Without Colstrip) Tons per MWh with Colstrip 16 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 758 of 1125 Power Supply Cost Index Comparison 0 20 40 60 80 100 120 140 160 180 200 19 9 9 20 0 1 20 0 3 20 0 5 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 20 2 7 20 2 9 20 3 1 20 3 3 po w e r s u p p l y c o s t i n d e x Historical Forecast Forecast without Colstrip 17 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 759 of 1125 2027-33 Colstrip SCR Analysis $549 $574 $608 $587 $612 $637 $400 Mil $500 Mil $600 Mil $700 Mil PRS PRS_SCR No Colstrip LC LC_SCR No Colstrip Expected Case Expected Case Expected Case Carbon Pricing Scenario Carbon Pricing Scenario Carbon Pricing Scenario le v e l i z e d c o s t 18 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 760 of 1125 Net Metering and Buck-A-Block Clint Kalich Sixth Technical Advisory Committee Meeting 2013 Electric Integrated Resource Plan June 19, 2013 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 761 of 1125 Avista’s Net Metering Customers 0.0 0.3 0.6 0.9 1.2 1.5 0 10 20 30 40 50 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 cu m u l a t i v e c a p a c i t y ( M W ) an n u a l n e w c u s t o m e r s ID WA Cumulative Capacity (MW) 2 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 762 of 1125 Avista Buck-A-Block Program 0.7 2.9 5.8 6.4 7.6 8.1 8.1 8.2 8.6 8.3 0 1,000 2,000 3,000 4,000 5,000 0.0 2.0 4.0 6.0 8.0 10.0 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 cu s t o m e r s av e r a g e m e g a w a t t s aMW Customers 3 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 763 of 1125 Solar Energy Subsidies ProfitState Incentive State Incentive Federal Depr Federal Depr Federal Depr Federal ITC Federal ITC Federal ITC Cost Cost Cost -125 ¢/kWh -100 ¢/kWh -75 ¢/kWh -50 ¢/kWh -25 ¢/kWh ¢/kWh 25 ¢/kWh 50 ¢/kWh 75 ¢/kWh 100 ¢/kWh No Subsidies With Fed. Incentives With Fed. and WA State Incentives (Low) With Fed. and WA State Incentives (High) 0 Avista Retail Rate 4 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 764 of 1125 13 16 44 95 198 0 50 100 150 200 Low Carbon Price Medium Carbon Price High Carbon Price Mandatory Coal Retirements Increased RPS * $/metric ton GHG Reduction Option Costs ($/Ton) Renewable Portfolio Standards are Least Efficient, by Far 5 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 765 of 1125 2013 IRP Action Plan John Lyons Sixth Technical Advisory Committee Meeting 2013 Electric Integrated Resource Plan June 19, 2013 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 766 of 1125 Generation Resource Related Analysis • Spokane and Clark Fork River hydro upgrade options in the 2015 IRP. • Evaluate potential locations for the natural gas-fired resource for 2019, including environmental reviews, transmission studies, and potential land acquisition. • Continue participation in regional IRP and regional planning processes and monitor regional surplus capacity and continue to participate in regional capacity planning processes. • Provide status update on the Little Falls and Nine Mile hydroelectric project upgrade progress. 2 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 767 of 1125 Generation Resource Related Analysis • Commission a demand response potential and cost assessment of commercial and industrial customers. • Continue monitoring state and federal climate change policies and report work from Avista’s Climate Change Council. • Review and update the energy forecast methodology to better integrate economic, regional, and weather drivers of energy use. • Develop short-term (up to 24-months) capacity position report. 3 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 768 of 1125 Energy Efficiency • Work with NPCC, the Washington Utilities and Transportation Commission, and others to resolve adjusted market baseline issues for setting energy efficiency target setting and acquisition claims in Washington. • Study and quantify transmission and distribution efficiency projects as they apply to I-937 goals. • Update processes and protocols for conservation measurement, evaluation and verification. 4 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 769 of 1125 Transmission and Distribution Planning • Work to maintain the Company’s existing transmission rights, under applicable FERC policies, for transmission service to bundled retail native load. • Continue to participate in BPA transmission processes and rate proceedings to minimize costs of integrating existing resources outside of Avista’s service area. • Continue to participate in regional and sub-regional efforts to establish new regional transmission structures to facilitate long-term expansion of the regional transmission system. 5 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 770 of 1125 2013 IRP Overview Clint Kalich Sixth Technical Advisory Committee Meeting 2013 Electric Integrated Resource Plan June 19, 2013 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 771 of 1125 Executive Summary 2 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 772 of 1125 2013 IRP Chapters • Executive Summary • Introduction and Stakeholder Involvement • Loads & Resources • Energy Efficiency • Policy Considerations • Transmission & Distribution • Generation Resource Options • Market Analysis • Preferred Resource Strategy • Action Items 3 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 773 of 1125 Loads & Resources •The 2013 IRP energy forecast grows 1.0 percent per year, replacing the 1.4 percent annual growth rate from the last IRP. • Peak load growth is slower than energy growth at, at 0.84 percent in the winter and 0.90 percent in the summer. • Avista’s first long-term capacity deficit is in 2020; the first energy deficit is in 2026. • Palouse Wind became operational December 13, 2012. • Kettle Falls qualifies for the Washington State Energy Independence Act beginning in 2016. • This IRP meets all I-937 mandates over the next 20 years with a combination of qualifying hydro upgrades, Palouse Wind and Kettle Falls. 4 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 774 of 1125 Energy Efficiency • This IRP includes a Conservation Potential Assessment of the Company’s Idaho and Washington service territories. • Current Company-sponsored conservation reduces retail loads by nearly 10 percent, or 115 aMW. • Avista evaluated over 3,000 equipment options, and over 1,700 measure options covering all major end use equipment, as well as devices and actions to reduce energy consumption for this IRP. 5 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 775 of 1125 Policy Considerations • The 2013 IRP does not include a federal cap and trade or greenhouse gas emissions tax in its Expected Case because there is no policy development underway in a regulatory context. • The impact of potential greenhouse gas policies are addressed through scenario analyses. • The plan anticipates specific regulatory policies to reduce greenhouse gas emissions. 6 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 776 of 1125 Transmission & Distribution • Avista continues to participate in regional planning forums. • The Spokane Valley Reinforcement Project includes both station update and conductor upgrades. • A large upgrade project is under construction at the Moscow substation to maintain adequate load service and a Noxon substation rebuild project is in the design phase. • Five distribution feeder rebuilds are complete since the last IRP; six additional rebuilds are planned for 2014. • Significant generation interconnection study work at Thornton and Lind stations continues. 7 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 777 of 1125 Generation Resource Options • Only resources with well-defined costs and operating histories are in the PRS analysis. • Wind, solar, and hydro upgrades represent renewable options available to the Company; future RFPs might identify competing renewable technologies. • Renewable resource costs assume no extensions of state and federal incentives. • This IRP models battery storage technology as a resource option for the first time in an Avista IRP. • Upgrades to Avista’s Spokane and Clark Fork River facilities are included as resource options. 8 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 778 of 1125 Market Analysis • Gas and wind resources dominate new generation additions in the West. • Shale gas continues to lower gas and electricity price forecasts. • A growing Northwest wind fleet reduces springtime market prices below zero in many hours. • Federal greenhouse gas policy remains uncertain, but new EPA policies point towards a regulatory model rather than a cap-and-trade system. • Lower natural gas prices and lower loads have reduced greenhouse gas emissions from the US power industry by 11 percent since 2007. 9 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 779 of 1125 Market Analysis continued • The Expected Case forecasts a continuing reduction to Western Interconnect greenhouse gas emissions due to coal plant shut downs brought on by EPA regulations. • Coal plant shut downs have similar carbon reduction results as a cap-and-trade market scheme, but have the advantage of not causing wholesale market price disruptions. 10 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 780 of 1125 Preferred Resource Strategy • Avista’s first anticipated resource acquisition is a natural gas fired peaker by the end of 2019 to replace expiring contracts and growing loads. • A combined cycle combustion turbine replaces the Lancaster Facility when its contract ends in 2026. • The selection of natural gas-fired peaking units is due primarily to their smaller size better fitting Avista’s modest resource deficits. • The Preferred Resource Strategy includes demand response programs for the first time. • Conservation offsets projected load growth by 42 percent through the 20-year IRP timeframe. 11 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 781 of 1125 Preferred Resource Strategy continued • Conservation spending ($711 million) exceeds new generation resource capital spending ($696 million) over the 20-year plan. • The Colstrip coal plant remains a viable and cost- effective resource throughout the planning horizon, even under scenarios most adverse to the plant. 12 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 782 of 1125 Remaining 2013 IRP Schedule • June 23 TAC • May 2013 – internal draft released at Avista • June 2013 – external draft released to the TAC • August 2013 – final editing and printing • August 31, 2013 – final IRP submission to Commissions and distribution to TAC • June 19, 2013 TAC meeting • June 21, 2013 Management review of Internal Draft 2013 IRP complete • June 26, 2013 distribution of Draft 2013 IRP to TAC participants • July 24, 2013: External review by TAC complete • August 30, 2013: 2013 IRP documents sent to the Idaho and Washington Commissions • August 31, 2013: 2013 IRP available to public, including publication on the Company’s web site 13 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 783 of 1125 2013 Electric Integrated Resource Plan Appendix B – 2013 Electric IRP Work Plan Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 784 of 1125 Work Plan for Avista’s 2013 Electric Integrated Resource Plan For the Washington Utilities and Transportation Commission August 30, 2012 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 785 of 1125 2 | P a g e 2013 Integrated Resource Planning Work Plan This Work Plan is submitted in compliance with the Washington Utilities and Transportation Commission’s (UTC) Integrated Resource Planning (IRP) rules (WAC 480-100-238). It outlines the process Avista will follow to develop its 2013 Electric IRP. The Company’s 2013 Electric IRP will be filed with Washington and Idaho Commissions by August 31, 2013. Avista uses a public process to solicit technical expertise and feedback throughout the development of the IRP through a series of public Technical Advisory Committee (TAC) meetings. Avista held the first TAC meeting for the 2013 IRP on May 23, 2012. The 2013 IRP process will be similar to those used to produce the previous four published plans. AURORAxmp will be used for electric market price forecasting, resource valuation, and for conducting Monte-Carlo style risk analyses. AURORAxmp modeling results will be used to select the Preferred Resource Strategy (PRS) using Avista’s proprietary PRiSM model. This tool is used to determine how to fill future capacity and energy (physical/renewable) deficits with new resources using an efficient frontier approach to evaluate quantitative portfolio risk versus portfolio cost while accounting for environmental laws and regulations. Qualitative risks will be evaluated in separate analyses. The process timeline is shown in Exhibit 1 and the process to identify the PRS is shown in Exhibit 2. Avista intends to use both detailed site-specific and generic resource assumptions in its development of the 2013 IRP. The assumptions are based on a combination of Avista’s research of similar technologies, engineering studies, and the Northwest Power and Conservation Council’s Sixth Power Plan. This plan will study renewable portfolio standards, energy storage, environmental costs, sustained peaking requirements and resource adequacy, energy efficiency programs, and demand response. The IRP will develop a strategy that meets or exceeds both the renewable portfolio standards and greenhouse gas emissions regulations. Avista intends to test the PRS against several scenarios and potential futures. The TAC meetings will be an important factor to determine the underlying assumptions used in the scenarios and futures. The IRP process is very technical and data intensive; public comments are welcome, however input and participation will be needed in a timely manner for appropriate inclusion into the process so the plan can be submitted according to the tentative schedule outlined in this Work Plan. Topics and meeting times may change depending on the availability of Company staff and requests for additional topics from the TAC members. The tentative timeline and agenda items for Technical Advisory Committee meetings follows: • TAC 1 – May 23, 2012: Powering Our Future game, 2011 Renewable RFP, Palouse Wind Project update, 2011 IRP acknowledgement, Energy Independence Act compliance and forecast, and 2013 IRP Work Plan discussion. • TAC 2 (Day 1) – September 4, 2012: Palouse Wind Project tour. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 786 of 1125 3 | P a g e • TAC 2 (Day 2) – September 5, 2012: Avista renewable energy credit planning methods, energy and economic forecasts, 2012 Shared Value Report, generation options, and Spokane River Assessment. • TAC 3 – November 7, 2012: Peak load forecast, reliability planning, Colstrip discussion, energy storage technologies, modeling, and energy efficiency. • TAC 4 – February 6, 2013: Electric and natural gas price forecasts, transmission planning, resource needs assessment, and market and portfolio scenario development. • TAC 5 – March 20, 2013: Draft PRS, review of scenarios and futures, and portfolio analysis • TAC 6 – June 19, 2013: Review of final PRS and action items. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 787 of 1125 4 | P a g e 2013 Electric IRP Draft Outline This section provides a draft outline of the major sections in the 2013 Electric IRP. This outline will be updated as IRP studies are completed and input from the Technical Advisory Committee has been received. 1. Executive Summary 2. Introduction and Stakeholder Involvement 3. Loads and Resources a. Economic Conditions b. Avista Energy & Peak Load Forecast c. Load Forecast Scenarios d. Avista’s Resources and Contracts e. Reliability Planning and Reserve Margins f. Resource Requirements 4. Energy Efficiency and Demand Response a. Conservation Potential Assessment b. Demand Response Opportunities c. Washington State Energy Independence Act 5. Policy Considerations a. Environmental Concerns b. State and Federal Policies 6. Transmission Planning a. Avista’s Transmission System b. Future Upgrades and Interconnections c. Transmission Construction Costs and Integration d. Efficiencies 7. Generation Resource Options a. New Resource Options b. Avista Plant Upgrades 8. Market Analysis a. Marketplace b. Fuel Price Forecasts c. Market Price Forecast d. Scenario Analysis 9. Preferred Resource Strategy a. Resource Selection Process b. Preferred Resource Strategy c. Efficient Frontier Analysis d. Avoided Costs e. Portfolio Scenarios f. Tipping Point Analysis 10. Action Plan a. 2011 Action Plan Summary b. 2013 Action Plan Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 788 of 1125 5 | P a g e Exhibit 1: 2013 Electric IRP Timeline Task Target Date Preferred Resource Strategy (PRS) xmp xmp xmp Writing Tasks Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 789 of 1125 Exhibit 2: 2013 Electric IRP Modeling Process Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 790 of 1125 2013 Electric Integrated Resource Plan Appendix C – 2013 Electric IRP Avista Electric Conservation Potential Assessment Study Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 791 of 1125 Avista Electric Conservation Potential Assessment Study Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 792 of 1125 This report was prepared by EnerNOC Utility Solutions 500 Ygnacio Valley Blvd., Suite 450 Walnut Creek, CA 94596 Project Director: I. Rohmund Project Manager: J. Borstein Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 793 of 1125 EnerNOC Utility Solutions Consulting iii EXECUTIVE SUMMARY Avista Corporation (Avista) engaged EnerNOC Utility Solutions (EnerNOC) to conduct a Conservation Potential Assessment (CPA). The CPA is a 20-year conservation potential study to provide data on conservation resources for developing Avista’s 2013 Integrated Resource Plan (IRP), and in accordance with Washington Initiative 937 (I-937). The study updates Avista’s last CPA, which EnerNOC performed in 2011. The 2011 CPA used 2009, the first year for which complete billing data was available at the time, as the base year. This update kept 2009 as the base year for the analysis, and calibrated the model used for the assessment to align with actual sales and conservation program achievements for the years 2010–2012. Study Objectives The study objectives included: Conduct a conservation potential study for electricity for Washington and Idaho. The study accounted for: o Impacts of existing Avista conservation programs o Impacts of codes and standards o Technology developments and innovation o The economy and energy prices Assess and analyze cost-effective conservation potentials in accordance with the Northwest Power and Conservation Council's (NPPC) Sixth Power Plan methodology and Washington I- 937 requirements. Obtain supply curves showing the incremental costs associated with achieving higher levels of conservation and stacking efficiency resources by cost of conserved energy. Analyze various market penetration rates associated with technical, economic, and achievable potential estimates. Definitions of Potential Technical potential is defined as the theoretical upper limit of conservation potential. It assumes that customers adopt all feasible measures regardless of their cost. At the time of existing equipment failure, customers replace their equipment with the most efficient optio n available. In new construction, customers and developers also choose the most efficient equipment option. Examples of measures that make up technical potential for electricity in the residential sector include: o High-efficiency heat pumps for homes with ducts o Ductless mini-split heat pumps for homes without ducts o Heat pump water heaters o LED lighting Technical potential also assumes the adoption of every other available measure, where applicable. For example, it includes installation of high-efficiency windows in all new construction opportunities and furnace maintenance in all existing buildings with furnace systems. These retrofit measures are phased in over a number of years, which is longer for higher-cost and complex measures. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 794 of 1125 Executive Summary iv enernoc.com Economic potential represents the adoption of all cost-effective conservation measures. In this analysis, cost-effectiveness is measured by the total resource cost (TRC) test, which compares lifetime energy and capacity benefits to the incremental cost of the measure. If the benefits outweigh the costs (that is, if the TRC ratio is greater than 1.0), a given measure is considered in the economic potential. Customers are then assumed to purchase the most cost-effective option applicable to them at any decision juncture. Achievable potential takes into account market maturity, customer preferences for energy-efficient technologies, and expected program participation. Achievable potential establishes a realistic target for the conservation savings that a utility can hope to achieve through its programs. It is determined by applying a series of annual market adoption factors to the economic potential for each conservation measure. These factors represent the ramp rates at which technologies will penetrate the market. To develop these factors, the project team reviewed Avista’s past conservation program achievements and program history over the last five years, as well as the Northwest Power and Conservation Council (NPCC) ramp rates used in the Sixth Plan. Details regarding the market adoption factors appear in Appendix D. Study Approach To execute this project, EnerNOC used a bottom-up analysis approach as shown in Figure ES-1. The analysis involved the following steps. 1. Held a meeting with the client project team to refine the objectives. 2. Performed a market characterization to describe sector-level electricity use for the residential and non-residential (commercial and industrial) sectors for the base year, 2009. This step drew upon the market characterization from the 2011 CPA, but updated the characterization to incorporate new information from the Northwest Energy Efficiency Alliance (NEEA) 2012 Residential Building Stock Assessment (RBSA), EnerNOC’s own databases and tools, and other secondary data sources such as the American Community Survey (ACS), Northwest Power and Conservation Council (NPCC), and the Energy Information Administration (EIA). 3. Developed a baseline electricity use projection by sector, segment, and end use for 2009 through 2033. The baseline projection is the ―business as usual‖ metric, without new utility conservation programs, against which energy savings from conservation measures are compared. The baseline projection includes the impacts of known codes and standards, as of 2012 when the study was conducted, including the Energy Independence and Security Act (EISA) lighting standards, which phase in during 2012–2014, and the 2010 appliance standards. This baseline projection process incorporates the changes in market conditions such as customer and market growth, income growth, Avista’s retail rates forecast, trends in end-use and technology saturations, equipment purchase decisions, consumer price elasticity, and income and persons per household. 4. Identified and characterized conservation measures. Measures to include and data to characterize them were drawn from the Regional Technical Forum measure workbooks, the Sixth Plan, Avista’s business plan, its technical reference manual, and EnerNOC’s own measure database. 5. Estimated three levels of conservation potential: Technical, Economic, and Achievable. We used EnerNOC’s Load Management Analysis and Planning tool (LoadMAPTM) version 3.0 to develop both the baseline projection and the estimates of conservation potential. EnerNOC developed LoadMAP in 2007 and has enhanced it over time, using it for the EPRI National Potential Study and numerous utility-specific forecasting and potential studies. Details of the approach as well as the data sources used in the study appear in Chapter 2. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 795 of 1125 Executive Summary EnerNOC Utility Solutions Consulting v Figure ES-1 Overview of Analysis Approach Market Characterization During 2009, Avista served 354,615 residential, commercial, industrial, and pumping customers with a combined electricity use of approximately 8,862 GWh. The study segmented these customers by state and rate class as shown in Table ES-1 and Table ES-2. In addition, the residential class was segmented by housing type and income (single family, multi-family, mobile home, and low income). The low-income threshold for purposes of this study was defined as 200% of the Federal poverty level. For this study, the project team decided not to explicitly model the conservation potential for pumping customers, which represent 2% of load, but instead to use the NPCC Sixth Plan calculator to estimate pumping potential. Results of that calculation appear in Chapter 4. Potential for rate class 25P was also estimated outside of the LoadMAP framework, and thus 25P sales are not included in Table ES-2. Table ES-1 Electricity Sales and Peak Demand by Rate Class, Washington 2009 Sector / Rate Class Rate Schedule(s) Number of meters (customers) 2009 Electricity Sales (GWh) 2009 Peak Demand (MW) Residential 001 200,134 2,452 710 General Service 011, 012 27,142 416 64 Large General Service 021, 022 3,352 1,557 232 Extra Large Commercial 025C 9 266 134 Extra Large Industrial 025I 13 614 Pumping 031, 032 2,361 136 10 Total 233,011 5,440 1,150 EE measure data Utility data Engineering analysis Secondary data Market segmentation and characterization Customer participation rates Technical and economic potential projections Achievable potential projection Utility data Customer surveys Secondary data Base-year energy use by fuel, segment Baseline Supply curves Scenario analyses Custom analyses Project report End-use projection by segment Prototypes and energy analysis Program results Survey data Secondary data Forecast data Synthesis / analysis Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 796 of 1125 Executive Summary vi enernoc.com Table ES-2 Electricity Sales and Peak Demand by Rate Class, Idaho 2009 Sector / Rate Class Rate Schedule(s) Number of meters (customers) 2009 Electricity Sales (MWh) 2009 Peak Demand (MW) Residential 001 99,580 1,182 283 General Service 011, 012 19,245 323 61 Large General Service 021, 022 1,456 700 115 Extra Large Commercial 025C 3 70 140 Extra Large Industrial 025I 6 196 Pumping 031, 032 1,312 59 4 Total 121,602 2,530 603 Note: Excludes sales to rate class 25P. Within each segment, energy use was characterized by end-use (e.g., space heating, cooling, lighting, water heat, motors, etc.) and by technology (e.g., heat pump, resistance heating, furnace for space heating). Figure ES-2 presents the residential end-use breakout in terms of intensity, kWh/household-year, by segment for Washington and Idaho combined. Space heating is the largest single use in all housing types, accounting for 29% of residential use overall. In three of the four segments, appliances are the second largest energy consumer, followed by water heating and then interior lighting. The exception is multi family housing, where water heating is the second largest end use while appliances are the third largest end use, due to a high saturation of electric water heating compared with the other segments. Across all housing types, interior and exterior lighting combined represents 14% of electricity use in 2009. Electronics, which includes personal computers, televisions, home audio, video game consoles, etc., is 8% of residential electricity usage. The miscellaneous end use includes such devices as furnace fans, pool pumps, and other plug loads (hair dryers, power tools, coffee makers, etc.). Figure ES-2 Residential Intensity by End Use and Segment (kWh/household, 2009) Figure 3-6 displays the breakdown of energy use by segment within the C&I sector. Lighting is the largest single energy use across all of the commercial buildings, accounting for 34% of energy use, followed by HVAC with 27% of use. For the extra large industrial customers, machine drive and process loads dominate, together accounting for 64% of energy use. 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 Single Family Multi Family Mobile Home Low Income All Homes In t e n s i t y ( k W h / H H / y r ) Cooling Heating Water Heating Interior Lighting Exterior Lighting Appliances Electronics Miscellaneous Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 797 of 1125 Executive Summary EnerNOC Utility Solutions Consulting vii Figure ES-3 C&I Electricity Consumption by End Use and Segment (2009) This market characterization is further detailed in Chapter 3. Conservation Potential Results All results below show cumulative potential, indicating how a measure installed in one year continues to provide savings in subsequent years through the end of its useful measure life. Incremental annual results appear in Appendix E. Figure ES-4 and Table ES-3 summarize the achievable potential. The C&I sector accounts for the about 55% of the savings initially, and over time its share of savings grows to around 60%. Figure ES-4 Cumulative Achievable Potential by Sector (MWh) 0 500 1000 1500 2000 2500 Small/Medium Commercial Large Commercial Extra Large Commercial Extra Large Industrial An n u a l U s e ( 1 , 0 0 0 0 M W h ) Cooling Space Heating Ventilation Water Heating Interior Lighting Exterior Lighting Refrigeration Food Preparation Office Equipment Miscellaneous Process Machine Drive - 200,000 400,000 600,000 800,000 1,000,000 1,200,000 1,400,000 1,600,000 Cu m u l a t i v e S a v i n g s ( M W h ) 25P Cumulative Savings (MWh) WA and ID Irrigation Cumulative Savings (MWh) C&I Cumulative Savings (MWh) Residential Cumulative Savings (MWh) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 798 of 1125 Executive Summary viii enernoc.com Table ES-3 Cumulative Achievable Potential by State and Sector (MWh) 2014 2015 2018 2023 2028 2033 Washington Achievable Cumulative Savings (MWh) Residential 15,091 29,603 100,792 172,576 266,751 369,293 C&I 19,927 40,930 123,755 256,653 392,186 543,380 Pumping 1,402 3,237 8,742 10,535 10,535 10,535 Total 36,420 73,770 233,289 439,764 669,472 923,208 Washington Achievable Cumulative Savings (aMW) Residential 1.7 3.4 11.5 19.7 30.5 42.2 C&I 2.3 4.7 14.1 29.3 44.8 62.0 Pumping 0.2 0.4 1.0 1.2 1.2 1.2 Total 4.2 8.4 26.6 50.2 76.4 105.4 2014 2015 2018 2023 2028 2033 Idaho Achievable Cumulative Savings (MWh) Residential 6,757 13,183 46,795 79,385 125,347 177,826 C&I 8,863 16,427 53,214 124,987 192,518 261,813 Pumping 618 1,426 3,852 4,642 4,642 4,642 Total 16,238 31,036 103,861 209,014 322,507 444,281 Idaho Achievable Cumulative Savings (aMW) Residential 0.8 1.5 5.3 9.1 14.3 20.3 C&I 1.0 1.9 6.1 14.3 22.0 29.9 Pumping 0.1 0.2 0.4 0.5 0.5 0.5 Total 1.9 3.5 11.9 23.9 36.8 50.7 2014 2015 2018 2023 2028 2033 Washington and Idaho Achievable Cumulative Savings (MWh) Residential 21,848 42,786 147,588 251,961 392,098 547,119 C&I 28,790 57,357 176,969 381,640 584,703 805,193 Pumping 2,020 4,663 12,593 15,177 15,177 15,177 Total 52,657 104,806 337,150 648,778 991,979 1,367,490 Washington and Idaho Achievable Cumulative Savings (aMW) Residential 2.5 4.9 16.8 28.8 44.8 62.5 C&I 3.3 6.5 20.2 43.6 66.7 91.9 Pumping 0.2 0.5 1.4 1.7 1.7 1.7 Total 6.0 12.0 38.5 74.1 113.2 156.1 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 799 of 1125 Executive Summary EnerNOC Utility Solutions Consulting ix Figure ES-5 presents the residential cumulative achievable potential in 2018 by end use. We note the following: Lighting, primarily the conversion of both interior and exterior lamps to compact fluorescent lamps in the first few years, followed by LEDs for exterior lighting stating in 2015 and for interior lighting starting in 2017, represents 70,446 MWh or 47% of savings. Utility programs and other market transformation programs have made customers accepting of new lighting technologies, and thus these technologies are relatively well accepted by consumers. Water heating is the next highest source of achievable potential. As discussed above, water heating provides the largest economic potential, but the market for heat pump water heaters remains immature, and thus the uptake of this technology is limited in the near term. Although conversion to gas water heating is a mature technology and readily accepted, customers may be unable to convert at the time of replacement due to timing issues or other considerations. Space heating provides 20% of achievable potential mainly due to electric furnaces being converted to gas units, and resistance heating being displaced by ductless heat pumps. Figure ES-5 Residential Cumulative Achievable Potential by End Use in 2018 As shown in Figure ES-6, the primary sources of C&I sector achievable savings in 2018 are as follows: Interior and exterior lighting, comprising lamps, fixtures, and controls, account for 64% of C&I sector achievable potential. Not only is economic potential high for lighting measures, but they are more readily accepted and implemented in the market than many other, higher cost and more complex measures. Office Equipment, which is the second largest portion of this sector’s achievable potential (11%) Water heating and Ventilation each provides 6% of the total savings Cooling 3% Space Heating 20% Water Heating 24% Interior Lighting 38% Exterior Lighting 9% Appliances 3% Electronics 6% Miscellaneous 1% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 800 of 1125 Executive Summary x enernoc.com Figure ES-6 C&I Cumulative Achievable Potential Cumulative Savings by End Use in 2018 (percentage of total) Cooling 2% Space Heating 1%Ventilation 6% Water Heating 6% Food Preparation 1% Refrigeration 5% Interior Lighting 57% Exterior Lighting 7% Office Equipment 11% Machine Drive 2% Process 2% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 801 of 1125 Executive Summary EnerNOC Utility Solutions Consulting xi Table ES-4 summarizes the potential, by state and for the overall service territory, for selected years. For pumping and rate class 25P, only achievable potential was calculated. Economic and technical potential for these two relatively small rate classes were assumed to be equal to achievable potential. Figure ES -7 presents this information graphically. Key findings related to cumulative conservation potentials are as follows. Achievable potential, for the residential, commercial, and industrial sectors is 100,143 MWh or 11.4 aMW for the 2014–2015 biennium. With the addition of pumping, achievable potential is 12.0 aMW for the 2014-2015 biennium and increases to 156.1 aMW by 2033. Washington provides approximately 70% of the potential in most years. Over the 2014–2033 period, the achievable potential forecast offsets 39% of the overall growth in the residential and C&I combined baseline projections. Economic potential, which reflects the savings when all cost-effective measures are taken, is 480,967 MWh or 54.9 aMW for2014–2015. By 2033, economic potential reaches 304.5 aMW. Technical potential, which reflects the adoption of all conservation measures regardless of cost-effectiveness, is a theoretical upper bound on savings. For 2014–2015, technical potential savings are 1,372,283 MWh or 156.7 aMW. By 2033, technical potential reaches 497.2 aMW. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 802 of 1125 Executive Summary xii enernoc.com Table ES-4 Summary of Cumulative Conservation Potential 2014 2015 2018 2023 2028 2033 Washington Cumulative Savings (MWh) Achievable Potential 36,420 73,770 233,289 439,764 669,472 923,208 Economic Potential 214,944 329,262 741,547 1,131,761 1,539,860 1,807,576 Technical Potential 794,447 941,497 1,550,783 2,212,885 2,704,067 3,024,259 Washington Cumulative Savings (aMW) Achievable Potential 4.2 8.4 26.6 50.2 76.4 105.4 Economic Potential 24.5 37.6 84.7 129.2 175.8 206.3 Technical Potential 90.7 107.5 177.0 252.6 308.7 345.2 Idaho Cumulative Savings (MWh) Achievable Potential 16,238 31,036 103,861 209,014 322,507 444,281 Economic Potential 101,779 151,705 350,121 538,404 734,193 859,791 Technical Potential 368,926 430,787 700,966 975,464 1,195,587 1,330,893 Idaho Cumulative Savings (aMW) Achievable Potential 1.9 3.5 11.9 23.9 36.8 50.7 Economic Potential 11.6 17.3 40.0 61.5 83.8 98.1 Technical Potential 42.1 49.2 80.0 111.4 136.5 151.9 Total Washington and Idaho Cumulative Savings (MWh) Achievable Potential 52,657 104,806 337,150 648,778 991,979 1,367,490 Economic Potential 316,722 480,967 1,091,669 1,670,165 2,274,053 2,667,367 Technical Potential 1,163,373 1,372,283 2,251,749 3,188,349 3,899,655 4,355,152 Total Washington and Idaho Cumulative Savings (aMW) Achievable Potential 6.0 12.0 38.5 74.1 113.2 156.1 Economic Potential 36.2 54.9 124.6 190.7 259.6 304.5 Technical Potential 132.8 156.7 257.0 364.0 445.2 497.2 Note: For pumping and rate class 25P, only achievable potential was calculated and thus economic and technical potential were assumed to be equal to achievable potential for these two rate classes. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 803 of 1125 Executive Summary EnerNOC Utility Solutions Consulting xiii Figure ES -7 Summary of Cumulative Energy Savings, Residential and C&I Note: Excludes pumping and 25P. Chapter 4 provides additional detail by sector and segment. Sensitivity of Potential to Avoided Cost Similar to the 2011 CPA, EnerNOC modeled several scenarios with varying levels of avoided costs in addition to the reference case. For this study’s purposes, we have included a case where the 10% adder per NW Power and Conservation Act is removed. The other scenarios included 150%, 125%, and 75% of the avoided costs used in the reference case. Figure ES-8 and Table ES-5 show how achievable potential varies under the four scenarios. The reference case achievable potential reaches approximately at 1,352,291 MWh by 2033. Removing the 10% adder from the avoided costs decreased this achievable potential to 1,272,206 MWh, 6% reduction. With the 150% avoided cost case, achievable potential increased to 1,657,741 MWh (23% increase from reference) while the 125% avoided cost case and the 75% avoided cost case yielded achievable potential equal to 1,521,856 (13% increase) and 1,146,105 MWh (15% decrease) respectively. While the changes are significant, the relationship between avoided cost and achievable potential is not linear and increases in avoided costs do not provide equivalent percentage increases in achievable potential. Technical potential imposes a limit on the amount of additional conservation and each incremental unit of DSM becomes increasingly expensive. 0 100 200 300 400 500 600 2014 2015 2018 2023 2028 2033 En e r g y S a v i n g s ( a M W ) Achievable Potential Economic Potential Technical Potential Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 804 of 1125 Executive Summary xiv enernoc.com Figure ES-8 Energy Savings, Cumulative Achievable Potential by Avoided Costs Scenario (MWh) Note: Excludes pumping and 25P. Table ES-5 Achievable Potential with Varying Avoided Costs End Use Reference Scenario Remove 10% adder 75% of avoided costs 125% of avoided costs 150% of avoided costs Achievable potential savings 2033 (MWh) 1,352,291 1,272,206 1,146,105 1,521,856 1,657,741 Percentage change in savings vs. 100% avoided cost Scenario -6% -15% 13% 23% Note: Excludes pumping and 25P. Supply Curves The project also developed supply curves for each year to support the IRP process. At Avista’s request, the supply curves did not consider economic screening based on Avista’s avoided costs. Instead, all measures were included and the amount of savings from each measure in each year was limited by the ramp rates used for achievable potential. The supply curves do not include the savings from electricity to natural gas fuel switching, discussed above. A sample supply curve for one year is shown in Figure ES-9. This supply curve is created by stacking measures and equipment over the 20-year planning horizon in ascending order of cost. As expected, this stacking of conservation resources produces a traditional upward-sloping supply curve. Because there is a gap in the cost of the energy efficiency measures as you move up the supply curve, the measures with a very high cost cause a rapid sloping of the supply curve. The supply curve also shows that substantial savings are available at low- or no-cost. - 200,000 400,000 600,000 800,000 1,000,000 1,200,000 1,400,000 1,600,000 1,800,000 2,000,000 Cu m u l a t i v e S a v i n g s ( M W h ) 100% of reference case avoided costs 150% of avoided costs 125% of avoided costs Reference case without 10% adder 75% of avoided costs Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 805 of 1125 Executive Summary EnerNOC Utility Solutions Consulting xv Figure ES-9 Supply Curves for Evaluated EE Measures and Avoided Cost Scenarios Note: Excludes pumping and 25P. Washington Potential Excluding Conversions to Natural Gas Avista has a history of fuel switching from electricity to natural gas and continues to target direct use as the most efficient resource option when available. The conservation potential reported above includes savings potential attributable to conversion of electric space and water heating to natural gas. However, fuel efficiency is not considered in the NPCC Sixth Plan, and thus potential due to fuel conversions is not included in Avista’s conservation target consistent with Washington I-937. Washington potential consistent with the NPCC Conservation Plan methodology appears in Table ES -6. The energy efficiency target illustrated in Table ES-6, in addition to Avista’s distribution efficiency target, make up the I-397 target that will be filed in Avista upcoming Biennial Conservation Plan for the 2014–2015 biennium. Table ES -6 Washington Cumulative Potential Consistent with Conservation Plan Methodology 2014 2015 2018 2023 Cumulative Savings (MWh) Residential 15,091 29,603 100,792 172,576 Commercial and Industrial 19,927 40,930 123,755 256,653 Pumping 1,402 3,237 8,742 0 Conversions to Natural Gas (3,148) (6,633) (16,827) (35,028) Total 33,272 67,137 216,462 394,200 Cumulative Savings (aMW) Residential 1.72 3.38 11.51 19.70 Commercial and Industrial 2.27 4.67 14.13 29.30 Pumping 0.16 0.37 1.00 0.00 Conversions to Natural Gas (0.36) (0.76) (1.92) (4.00) Total 3.80 7.66 24.71 45.00 $- $0.10 $0.20 $0.30 $0.40 $0.50 $0.60 $0.70 $0.80 $0.90 $1.00 -100 200 300 400 500 600 700 800 Co s t o f Co n s e v e d En e r g y ( 2 0 0 9 $ / k W h ) Cumulative Savings 2020 (GWh) Cost/kWh Avoided Cost ($0.0489kWh) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 806 of 1125 Executive Summary xvi enernoc.com Additional details on potential by sector and segment appear in Chapter 4. A second volume provides appendices with supporting information and additional results. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 807 of 1125 EnerNOC Utility Solutions Consulting xvii CONTENTS 1 INTRODUCTION .................................................................................................... 1-1 Abbreviations and Acronyms ........................................................................................... 1-2 2 ANALYSIS APPROACH AND DATA DEVELOPMENT ................................................ 2-1 Analysis Approach .......................................................................................................... 2-1 LoadMAP Model ................................................................................................. 2-2 Market Characterization ...................................................................................... 2-3 Market Profiles ................................................................................................... 2-6 Baseline Projection ............................................................................................. 2-6 Conservation Measure Analysis ........................................................................... 2-6 Conservation Potential ...................................................................................... 2-10 Data Development ....................................................................................................... 2-11 Data Sources ................................................................................................... 2-11 Data Application ............................................................................................... 2-13 3 MARKET CHARACTERIZATION AND MARKET PROFILES ...................................... 3-1 Energy Use Summary ..................................................................................................... 3-1 Residential Sector .......................................................................................................... 3-3 C&I Sector ..................................................................................................................... 3-8 4 CONSERVATION POTENTIAL ................................................................................ 4-1 Overall Potential ............................................................................................................ 4-1 Residential Sector .......................................................................................................... 4-4 Residential Potential by End Use, Technology, and Measure Type ......................... 4-6 Residential Potential by Market Segment ........................................................... 4-10 C&I Sector Potential ..................................................................................................... 4-12 C&I Potential by End Use, Technology, and Measure Type.................................. 4-14 C&I Potential by Market Segment ...................................................................... 4-19 Sensitivity of Potential to Avoided Cost .......................................................................... 4-20 Electricity to Natural Gas Fuel Switching ........................................................................ 4-21 Supply Curves .............................................................................................................. 4-22 Pumping Potential ........................................................................................................ 4-23 Washington Potential Excluding Conversions to Natural Gas ........................................... 4-24 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 808 of 1125 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 809 of 1125 EnerNOC Utility Solutions Consulting xix LIST OF FIGURES Figure ES-1 Overview of Analysis Approach ................................................................................. v Figure ES-2 Residential Intensity by End Use and Segment (kWh/household, 2009) ...................... vi Figure ES-3 C&I Electricity Consumption by End Use and Segment (2009) .................................. vii Figure ES-4 Cumulative Achievable Potential by Sector (MWh) .................................................... vii Figure ES-5 Residential Cumulative Achievable Potential by End Use in 2018 ................................ ix Figure ES-6 C&I Cumulative Achievable Potential Cumulative Savings by End Use in 2018 (percentage of total) ................................................................................................ x Figure ES -7 Summary of Cumulative Energy Savings, Residential and C&I ................................... xii Figure ES-8 Energy Savings, Cumulative Achievable Potential by Avoided Costs Scenario (MWh) .. xiii Figure ES-9 Supply Curves for Evaluated EE Measures and Avoided Cost Scenarios..................... xiv Figure 2-1 Overview of Analysis Approach .............................................................................. 2-1 Figure 2-2 LoadMAP Analysis Framework ................................................................................ 2-3 Figure 2-3 Approach for Measure Assessment ......................................................................... 2-7 Figure 2-4 Avoided Costs ..................................................................................................... 2-20 Figure 3-1 Electricity Sales by Rate Class, 2009 ...................................................................... 3-2 Figure 3-2 Electricity Sales by Rate Class, Idaho 2009 ............................................................. 3-2 Figure 3-3 Percentage of Residential Electricity Use by End Use and Segment (2009) ............... 3-7 Figure 3-4 Residential Intensity by End Use and Segment (kWh/household, 2009) .................... 3-8 Figure 3-5 Commercial and Industrial Electricity Consumption by Segment 2009 ...................... 3-9 Figure 3-6 C&I Electricity Consumption by End Use, 2009 ..................................................... 3-11 Figure 3-7 C&I Electricity Consumption by End Use and Segment (2009) ............................... 3-12 Figure 4-1 Cumulative Achievable Potential by Sector (MWh) ................................................... 4-1 Figure 4-2 Summary of Cumulative Energy Savings, Residential and C&I .................................. 4-4 Figure 4-4 Residential Cumulative Savings by Potential Case ................................................... 4-5 Figure 4-5 Residential Cumulative Achievable Potential by End Use in 2018 .............................. 4-8 Figure 4-6 C&I Cumulative Savings by Potential Case ............................................................ 4-13 Figure 4-7 C&I Cumulative Achievable Potential Cumulative Savings by End Use in 2018 (percentage of total) ........................................................................................... 4-18 Figure 4-8 C&I Cumulative Achievable Savings in 2018 by End Use and Building Type ............ 4-20 Figure 4-9 Energy Savings, Cumulative Achievable Potential by Avoided Costs Scenario (MWh)4-21 Figure 4-10 Supply Curves for Evaluated EE Measures and Avoided Cost Scenarios................... 4-23 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 810 of 1125 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 811 of 1125 EnerNOC Utility Solutions Consulting xxi LIST OF TABLES Table ES-1 Electricity Sales and Peak Demand by Rate Class, Washington 2009 ........................... v Table ES-2 Electricity Sales and Peak Demand by Rate Class, Idaho 2009 ................................... vi Table ES-3 Cumulative Achievable Potential by State and Sector (MWh) .................................... viii Table ES-4 Summary of Cumulative Conservation Potential ........................................................ xi Table ES-5 Achievable Potential with Varying Avoided Costs ...................................................... xiii Table ES -6 Washington Cumulative Potential Consistent with Conservation Plan Methodology .... xiv Table 1-1 Explanation of Abbreviations and Acronyms ............................................................ 1-3 Table 2-1 Overview of Segmentation Scheme for Potentials Modeling ..................................... 2-3 Table 2-2 Residential Electric End Uses and Technologies ...................................................... 2-4 Table 2-3 C&I Electric End Uses and Technologies ................................................................. 2-5 Table 2-4 Number of Measures Evaluated ............................................................................. 2-8 Table 2-5 Example Equipment Measures for Air-Source Heat Pump – Single Family Home ........ 2-9 Table 2-6 Example Non-Equipment Measures – Single Family Home, Existing .......................... 2-9 Table 2-7 Economic Screen Results for Selected Single Family Equipment Measures .............. 2-10 Table 2-8 Data Applied for the Market Profiles ..................................................................... 2-14 Table 2-9 Data Needs for the Baseline Projection and Potentials Estimation in LoadMAP ........ 2-15 Table 2-10 Residential Electric Equipment Standards Applicable to Avista ................................ 2-16 Table 2-11 Commercial Electric Equipment Standards Applicable to Avista .............................. 2-17 Table 2-12 Industrial Electric Equipment Standards Applicable to Avista .................................. 2-18 Table 2-13 Data Needs for the Measure Characteristics in LoadMAP ....................................... 2-19 Table 3-1 Electricity Sales and Peak Demand by Rate Class, Washington 2009 ........................ 3-1 Table 3-2 Electricity Sales and Peak Demand by Rate Class, Idaho 2009 ................................. 3-1 Table 3-3 Residential Sector Allocation by Segments, 2009 .................................................... 3-3 Table 3-4 Residential Electricity Usage and Intensity by Segment and State, 2009 ................... 3-4 Table 3-5 Average Residential Sector Market Profile, Washington ........................................... 3-5 Table 3-6 Average Residential Sector Market Profile, Idaho .................................................... 3-6 Table 3-7 Residential Electricity Use by End Use and Segment (kWh/HH/year, 2009) ............... 3-7 Table 3-8 Commercial and Industrial Sector Market Characterization Results, Washington 20093-9 Table 3-9 Commercial and Industrial Sector Market Characterization Results, Idaho 2009 ........ 3-9 Table 3-10 Large Commercial Segment Market Profile, Washington, 2009 ............................... 3-10 Table 3-11 C&I Electricity Consumption by End Use and Segment (GWh, 2009) ..................... 3-11 Table 4-1 Cumulative Achievable Potential by State and Sector (MWh) ................................... 4-2 Table 4-2 Summary of Cumulative Conservation Potential ...................................................... 4-3 Table 4-4 Residential Cumulative Savings by End Use and Potential Type (MWh)..................... 4-6 Table 4-5 Residential Cumulative Achievable Potential for Equipment Measures (MWh) ............ 4-9 Table 4-6 Residential Cumulative Achievable Potential by Market Segment ............................ 4-11 Table 4-7 Residential Cumulative Achievable Potential by End Use and Market Segment, 2018 (MWh) ............................................................................................................... 4-11 Table 4-8 Residential Cumulative Achievable Potential by End Use and Market Segment, 2018 (MWh) ............................................................................................................... 4-12 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 812 of 1125 xxii enernoc.com Table 4-9 Cumulative Conservation Potential for the C&I Sector ........................................... 4-12 Table 4-10 C&I Cumulative Potential by End Use and Potential Type (MWh) ........................... 4-14 Table 4-11 C&I Cumulative Achievable Savings for Equipment Measures (MWh) ...................... 4-16 Table 4-12 C&I Cumulative Achievable Savings for Non-equipment Measures (MWh) ............... 4-17 Table 4-13 C&I Cumulative Potential by Market Segment, 2018 .............................................. 4-19 Table 4-14 C&I Cumulative Achievable Savings in 2018 by End Use and Rate Class(MWh) ....... 4-19 Table 4-15 Achievable Potential with Varying Avoided Costs ................................................... 4-21 Table 4-16 Cumulative Achievable Potential from Conversion to Natural Gas (MWh) ................ 4-22 Table 4-17 Pumping Rate Classes, Electricity Sales and Peak Demand 2009 ............................ 4-23 Table 4-18 Sixth Plan Calculator Agriculture Incremental Annual Potential, 2014–2019 (MWh) . 4-24 Table 4-19 Washington Cumulative Potential Consistent with Conservation Plan Methodology .. 4-24 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 813 of 1125 EnerNOC Utility Solutions Consulting 1-1 INTRODUCTION Background Avista Corporation (Avista) engaged EnerNOC Utility Solutions (EnerNOC) to conduct a Conservation Potential Assessment (CPA). The CPA is a 20-year conservation potential study to provide data on conservation resources for developing Avista’s 2013 Integrated Resource Plan (IRP), and in accordance with Washington Initiative 937 (I-937). The study updates Avista’s last CPA, which EnerNOC performed in 2011. The 2011 CPA used 2009, the first year for which complete billing data was available at the time, as the base year. This update kept 2009 as the base year for the analysis, and calibrated the model used for the assessment to align with actual sales and conservation program achievements for the years 2010–2012. Report Organization This remainder of this report is presented in three chapters as outlined below. Chapter 2 — Analysis Approach and Data Development Chapter 3 — Market Characterization and Market Profiles Chapter 4 — Conservation Potential Definition of Potential In this study, we estimate the potential for conservation savings. The savings estimates represent gross savings developed into three types of potential: technical potential, economic potential, and achievable potential. Technical and economic potential are both theoretical limits to conservation savings. Achievable potential embodies a set of assumptions about the decisions consumers make regarding the efficiency of the equipment they purchase, the maintenance activities they undertake, the controls they use for energy-consuming equipment, and the elements of building construction. The various levels are described below. Technical potential is defined as the theoretical upper limit of conservation potential. It assumes that customers adopt all feasible measures regardless of their cost. At the time of existing equipment failure, customers replace their equipment with the most efficient option available. In new construction, customers and developers also choose the most efficient equipment option. Examples of measures that make up technical potential for electricity in the residential sector include: o High-efficiency heat pumps for homes with ducts o Ductless mini-split heat pumps for homes without ducts o Heat pump water heaters o LED lighting Technical potential also assumes the adoption of every other available measure, where applicable. For example, it includes installation of high-efficiency windows in all new construction opportunities and furnace maintenance in all existing buildings with furnace systems. These retrofit measures are phased in over a number of years, which is longer for higher-cost and complex measures. Economic potential represents the adoption of all cost-effective conservation measures. In this analysis, cost-effectiveness is measured by the total resource cost (TRC) test, which compares lifetime energy and capacity benefits to the incremental cost of the measure. If the benefits outweigh the costs (that is, if the TRC ratio is greater than 1.0), a given measure is CHAPTER 1 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 814 of 1125 Introduction 1-2 www.enernoc.com considered in the economic potential. Customers are then assumed to purchase the most cost-effective option applicable to them at any decision juncture. Achievable potential takes into account market maturity, customer preferences for energy-efficient technologies, and expected program participation. Achievable potential establishes a realistic target for the conservation savings that a utility can hope to achieve through its programs. It is determined by applying a series of annual market adoption factors to the economic potential for each conservation measure. These factors represent the ramp rates at which technologies will penetrate the market. To develop these factors, the project team reviewed Avista’s past conservation program achievements and program history over the last five years, as well as the Northwest Power and Conservation Council (NPCC) ramp rates used in the Sixth Plan. Details regarding the market adoption factors appear in Appendix D. Abbreviations and Acronyms Throughout the report we use several abbreviations and acronyms. Table 1-1 shows the abbreviation or acronym, along with an explanation. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 815 of 1125 Introduction EnerNOC Utility Solutions Consulting 1-3 Table 1-1 Explanation of Abbreviations and Acronyms Acronym Explanation ACS American Community Survey AEO Annual Energy Outlook forecast developed annual by the Energy Information Administration of the DOE B/C Ratio Benefit to cost ratio BEST EnerNOC’s Building Energy Simulation Tool CAC Central air conditioning C&I Commercial and industrial CBECS Commercial Building Energy Consumption Survey (prepared by EIA) CBSA NEAA Commercial Building Stock Assessment CFL Compact fluorescent lamp DEEM EnerNOC’s Database of Energy Efficiency Measures DEER State of California Database for Energy-Efficient Resources DSM Demand side management EE Energy efficiency EIA Energy Information Administration EISA Energy Efficiency and Security Act of 2007 EPACT Energy Policy Act of 2005 EPRI Electric Power Research Institute EUI Energy-use index HH Household HID High intensity discharge lamps HPWH Heat pump water heater IRP Integrated Resource Plan LED Light emitting diode lamp LoadMAP EnerNOC’s Load Management Analysis and PlanningTM tool MECS Manufacturing Energy Consumption Survey (prepared by EIA) NEEA Northwest Energy Efficiency Alliance NPCC Northwest Power and Conservation Council RTF Regional Technical Forum RASS California Residential Appliance Saturation Survey CEUS California Commercial End-Use Survey REEPS EPRI Residential End-use Energy Planning System COMMEND EPRI COMMercial END-use planning system RBSA NEAA Residential Building Stock Assessment RECS Residential Energy Consumption Survey (prepared by EIA) RTU Roof top unit Sq. ft. Square feet TRM Technical Reference Manual TRC Total resource cost UEC Unit energy consumption UES Unit energy savings (as defined in RTF measure workbooks) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 816 of 1125 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 817 of 1125 EnerNOC Utility Solutions Consulting 2-1 ANALYSIS APPROACH AND DATA DEVELOPMENT This section describes the analysis approach taken for the study and the data sources used to develop the potential estimates. Analysis Approach To perform the conservation potential analysis, EnerNOC used a bottom-up analysis approach as shown in Figure 2-1. Figure 2-1 Overview of Analysis Approach The analysis involved the following steps. 1. Held a meeting with the client project team to refine the objectives of the project in detail. This resulted in a work plan for the study. 2. Performed a market characterization to describe sector-level electricity use for the residential and non-residential (commercial and industrial) sectors for the base year, 2009. This step drew upon the market characterization from the 2011 CPA, but updated the characterization to incorporate new information from the Northwest Energy Efficiency Alliance (NEEA) 2012 Residential Building Stock Assessment (RBSA), EnerNOC’s own databases and tools, and other secondary data sources such as the American Community Survey (ACS), Northwest Power and Conservation Council (NPCC), and the Energy Information Administration (EIA). 3. Developed a baseline electricity use projection by sector, segment, and end use for 2009 through 2033. EE measure data Utility data Engineering analysis Secondary data Market segmentation and characterization Customer participation rates Technical and economic potential projections Achievable potential projection Utility data Customer surveys Secondary data Base-year energy use by fuel, segment Baseline Supply curves Scenario analyses Custom analyses Project report End-use projection by segment Prototypes and energy analysis Program results Survey data Secondary data Forecast data Synthesis / analysis CHAPTER 2 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 818 of 1125 Analysis Approach and Data Development 2-2 www.enernoc.com 4. Identified and characterized conservation measures. 5. Estimated three levels of conservation potential: measure-level conservation potential: Technical, Economic, and Achievable. The analysis approach for all these steps is described in further detail throughout the remainder of this chapter. LoadMAP Model We used EnerNOC’s Load Management Analysis and Planning tool (LoadMAPTM) version 3.0 to develop both the baseline forecast and the estimates of conservation potential. EnerNOC developed LoadMAP in 2007 and has enhanced it over time, using it for the EPRI National Potential Study and numerous utility-specific forecasting and potential studies. Built in Excel, the LoadMAP framework, illustrated in Figure 2-1, is both accessible and transparent and has the following key features. Embodies the basic principles of rigorous end-use models (such as EPRI’s REEPS and COMMEND) but in a more simplified, accessible form. Includes stock-accounting algorithms that treat older, less efficient appliance/equipment stock separately from newer, more efficient equipment. Equipment is replaced according to the measure life and appliance vintage distributions defined by the user. Balances the competing needs of simplicity and robustness by incorporating important modeling details related to equipment saturations, efficiencies, vintage, and the like, where market data are available, and treats end uses separately to account for varying importance and availability of data resources. Isolates new construction from existing equipment and buildings and treats purchase decisions for new construction and existing buildings separately. Uses a simple logic for appliance and equipment decisions. LoadMAP allows the user to drive the appliance and equipment choices year by year directly in the model. This flexible approach allows users to import the results from diffusion models or to input individual assumptions. The framework also facilitates sensitivity analysis. Includes appliance and equipment models customized by end use. For example, the logic for lighting is distinct from refrigerators and freezers. Can accommodate various levels of segmentation. Analysis can be performed at the sector level (e.g., total residential) or for customized segments within sectors (e.g., housing type or income level). Consistent with the segmentation scheme and the market profiles we describe below, the LoadMAP model provides projections of baseline energy use by sector, segment, end use, and technology for existing and new buildings. It also provides projections of total energy use and conservation savings associated with the three types of potential.1 1 The model computes energy and peak-demand forecasts for each type of potential for each end use as an intermediate calculation. Annual-energy and peak-demand savings are calculated as the difference between the value in the baseline forecast and the value in the potential forecast (e.g., the technical potential forecast). Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 819 of 1125 Analysis Approach and Data Development EnerNOC Utility Solutions Consulting 2-3 Figure 2-2 LoadMAP Analysis Framework Market Characterization In order to estimate the savings potential from conservation measures, it is necessary to understand how much energy is used today and what equipment is currently being used. This characterization begins with a segmentation of Avista’s energy footprint to quantify energy use by sector, segment, fuel, end-use application, and the current set of technologies used. We incorporate information from the secondary research sources to advise the market characterization. Segmentation for Modeling Purposes The market assessment first defined the market segments (building types, end uses and other dimensions) that are relevant in the Avista service territory. The segmentation scheme for this project is presented in Table 2-1, and is the same as that used in the 2011 CPA. Table 2-1 Overview of Segmentation Scheme for Potentials Modeling Market Dimension Segmentation Variable Dimension Examples 1 Sector Residential, commercial and industrial 2 Building type Residential (single family, multi family, mobile home, low income) Commercial and Industrial (small/medium commercial, large commercial, extra large commercial, extra large industrial) 3 Vintage Existing and new construction 4 Fuel Electricity 5 End uses Cooling, space heating, lighting, water heat, motors, etc. (as appropriate by sector) 6 Appliances/end uses and technologies Technologies such as lamp type, air conditioning equipment, motors by application, etc. 7 Equipment efficiency levels for new purchases Baseline and higher-efficiency options as appropriate for each technology Market Profiles Market size Equipment saturationFuel sharesTechnology shares Vintage distribution Unit energy consumptionCoincident demand Base-year Energy Consumption by technology, end use, segment, vintage & sector Economic DataCustomer growthEnergy prices Exogenous factors Elasticities Energy-efficiency analysis List of measuresSaturationsAdoption ratesAvoided costs Cost-effectiveness screening Baseline Projection Savings Estimates(Annual & peak)Technical potential Economic potentialAchievable potential Customer segmentation Energy-efficiency Projection:TechnicalEconomic Achievable Technology Data Efficiency optionsCodes and standards Purchase shares Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 820 of 1125 Analysis Approach and Data Development 2-4 www.enernoc.com Following this scheme, the residential sector was segmented as described below, starting with customer segments by building type: Single family Multi family Mobile home Low income In addition to segmentation by housing type, we identified the set of end uses and technologies that are appropriate for Avista’s residential sector. These are shown in Table 2-2. Table 2-2 Residential Electric End Uses and Technologies End Use Technology Cooling Central Air Conditioning (CAC) Cooling Room Air Conditioning (RAC) Cooling/Space Heating Air-Source Heat Pump Cooling/Space Heating Geothermal Heat Pump Space Heating Electric Resistance Space Heating Electric Furnace Space Heating Supplemental Water Heating Water Heater <= 55 gal Water Heating Water Heater > 55 gal Interior Lighting Screw-in Lamps Interior Lighting Linear Fluorescent Lamps Interior Lighting Specialty Exterior Lighting Screw-in Lamps Appliances Clothes Washer Appliances Clothes Dryer Appliances Dishwasher Appliances Refrigerator Appliances Freezer Appliances Second Refrigerator Appliances Stove Appliances Microwaves Electronics Personal Computers Electronics TVs Electronics Set-top Boxes/DVR Electronics Devices and Gadgets Miscellaneous Pool Pump Miscellaneous Furnace Fan Miscellaneous Miscellaneous Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 821 of 1125 Analysis Approach and Data Development EnerNOC Utility Solutions Consulting 2-5 For the commercial and industrial sector (C&I), we segmented the market based on Avista’s rate classes, using the following segments. Small/medium Commercial Large Commercial Extra Large Commercial Extra Large Industrial The set of end uses and technologies for the C&I sector appear in Table 2-3. Table 2-3 C&I Electric End Uses and Technologies End Use Technology Cooling Central Chiller Cooling Roof top AC Cooling/Heating Heat Pump Space Heating Electric Resistance Space Heating Electric Furnace Ventilation Ventilation Water Heating Water Heater Interior Lighting Screw-in Interior Lighting High-Bay Fixtures Interior Lighting Linear Fluorescent Exterior Lighting Exterior Screw-in Exterior Lighting HID Refrigeration Walk-in Refrigerator Refrigeration Reach-in Refrigerator Refrigeration Glass Door Display Refrigeration Open Display Case Refrigeration Icemaker Refrigeration Vending Machine Food Preparation Oven Food Preparation Fryer Food Preparation Dishwasher Food Preparation Hot Food Container Office Equipment Desktop Computer Office Equipment Laptop Computer Office Equipment Server Office Equipment Monitor Office Equipment Printer/Copier/Fax Office Equipment POS Terminal Process Process Cooling/Refrigeration Process Process Heating Process Electrochemical Process Machine Drive Less than 5 HP Machine Drive 5 - 24 HP Machine Drive 25 - 99 HP Machine Drive 100 - 249 HP Machine Drive 250 – 499 HP Machine Drive 500 and more HP Miscellaneous Non-HVAC Motors Miscellaneous Miscellaneous Miscellaneous Other Miscellaneous Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 822 of 1125 Analysis Approach and Data Development 2-6 www.enernoc.com For the 2011 study, we performed a high-level market characterization of electricity sales in the 2009 base year to allocate sales to each customer segment. We used Avista billing data by rate class as well as various secondary data sources to identify the annual sales in each customer segment, as well as the market size for each segment. This information provided control totals at a sector level for calibrating the LoadMAP model to known data for the base-year and was used for this CPA update as well. Market Profiles The next step was to develop market profiles for each sector, customer segment, end use, and technology. A market profile includes the following elements: Market size is a representation of the number of customers in the segment. For the residential sector, it is number of households. In the commercial and industrial sector, it is floor space measured in square feet. Saturations define the fraction of homes or C&I square feet with the various technologies. (e.g., homes with electric space heating). UEC (unit energy consumption) or EUI (energy-use index) describes the amount of energy consumed in 2009 by a specific technology in buildings that have the technology. UECs are expressed in kWh/household for the residential sector, while EUIs are expressed in kWh/square foot for C&I. Intensity for the residential sector represents the average energy use for the technology across all homes in 2009. It is computed as the product of the saturation and the UEC and is defined as kWh/household for electricity. For the commercial and industrial sectors, intensity, computed as the product of the saturation and the EUI, represents the average use for the technology across all floor space in 2009. Usage is the annual energy use by an end use technology in the segment. It is the product of the market size and intensity and is quantified in GWh. The market assessment results and the market profiles are presented in Chapter 3. Baseline Projection The next step was to develop the baseline projection of annual electricity usage for 2009 through 2033 by customer segment and end use without new utility programs or naturally occurring efficiency. The end-use projection does include the relatively certain impacts of codes and standards that will unfold over the study timeframe. All such mandates that were defined as of January 2012 are included in the baseline. The baseline projection is the foundation for the analysis of savings from future conservation efforts as well as the metric against which potential savings are measured. Inputs to the baseline projection include: Avista historic sales data and conservation program achievements for 2009 through 2012 Current economic growth forecasts (i.e., customer growth, income growth) Electricity price forecasts Trends in fuel shares and equipment saturations Existing and approved changes to building codes and equipment standards Conservation Measure Analysis This section describes the framework used to assess the savings, costs, and other attributes of conservation measures. These characteristics form the basis for measure-level cost-effectiveness analyses as well as for determining measure-level savings. For all measures, EnerNOC assembled information to reflect equipment performance, incremental costs, and equipment lifetimes. We used this information, along with Avista’s avoided costs data, in the economic screen to Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 823 of 1125 Analysis Approach and Data Development EnerNOC Utility Solutions Consulting 2-7 determine economically feasible measures. Figure 2-3 outlines the framework for measure analysis. Figure 2-3 Approach for Measure Assessment The framework for assessing savings, costs, and other attributes of conservation measures involves identifying the list of conservation measures to include in the analysis, determining their applicability to each market sector and segment, fully characterizing each measure, and performing cost-effectiveness screening. The first step of the conservation measure analysis was to identify the list of all relevant conservation measures that should be considered for the Avista potential assessment. EnerNOC prepared a preliminary list of measures that compared the list of measures included in Avista’s previous CPA with those in its business plan, its technical reference manual, the Sixth Plan, the RTF measure workbooks, and EnerNOC’s own measure database in order to reconcile the various measure lists and provide the widest possible list of measures. This universal list of conservation measures covers all major types of end-use equipment, as well as devices and actions to reduce energy consumption. If considered today, some of these measures would not pass the economic screens initially, but may pass in future years as a result of lower projected equipment costs or higher avoided costs. After receiving feedback from Avista, we finalized the measures list. The selected measures are categorized into two types according to the LoadMAP taxonomy: equipment measures and non-equipment measures. Equipment measures are efficient energy-consuming pieces of equipment that save energy by providing the same service with a lower energy requirement than a standard unit. An example is an ENERGY STAR refrigerator that replaces a standard efficiency refrigerator. For equipment measures, many efficiency levels may be available for a given technology, ranging Economic screen Measure characterization Measure descriptions Energy savings Costs Lifetime Applicability EnerNOC universal measure list Building simulations EnerNOC measure data library NWPCC Client measure data library (NWPCC, TRMs, evaluation reports, etc.) Avoided costs, discount rate, delivery losses Client review / feedback Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 824 of 1125 Analysis Approach and Data Development 2-8 www.enernoc.com from the baseline unit (often determined by code or standard) up to the most efficient product commercially available. For instance, in the case of central air conditioners, this list begins with the current federal standard SEER 13 unit and spans a broad spectrum up to a maximum efficiency of a SEER 21 unit. Non-equipment measures save energy by reducing the need for delivered energy, but do not involve replacement or purchase of major end-use equipment (such as a refrigerator or air conditioner). An example would be a programmable thermostat that is pre-set to run heating and cooling systems only when people are home. Non-equipment measures can apply to more than one end use. For instance, addition of wall insulation will affect the energy use of both space heating and cooling. Non-equipment measures typically fall into one of the following categories: Building shell (windows, insulation, roofing material) Equipment controls (thermostat, energy management system) Equipment maintenance (air conditioning and heat pump maintenance, changing setpoints) Whole-building design (building orientation, passive solar lighting) Lighting retrofits (included as a non-equipment measure because retrofits are performed prior to the equipment’s normal end of life) Displacement measures (ceiling fan to reduce use of central air conditioners) Commissioning and retrocommissioning Table 2-4 summarizes the number of equipment and non-equipment measures evaluated for each segment within each sector. Table 2-4 Number of Measures Evaluated Residential C&I Total Number of Measures Equipment Measures Evaluated 1,536 1540 3,076 Non-Equipment Measures Evaluated 860 914 1,774 Total Measures Evaluated 2,396 2454 4,850 Once we assembled the list of conservation measures, the project team assessed their energy- saving characteristics. For each measure we also characterized incremental cost, service life, and other performance factors. Following the measure characterization, we performed an economic screening of each measure, which serves as the basis for developing the economic and achievable potential. The residential and C&I measures are listed and described in Appendix B and Appendix C respectively. Representative Measure Data Inputs To provide an example of the measure data, Table 2-5 and Table 2-6 present examples of the detailed data inputs behind both equipment and non-equipment measures, respectively, for the case of heat pumps in single-family homes. Table 2-6 displays the various efficiency levels available as equipment measures, as well as the corresponding useful life, energy usage, and cost estimates. The columns labeled On Market and Off Market reflect equipment availability due to codes and standards or the entry of new products to the market. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 825 of 1125 Analysis Approach and Data Development EnerNOC Utility Solutions Consulting 2-9 Table 2-5 Example Equipment Measures for Air-Source Heat Pump – Single Family Home Efficiency Level Useful Life Equipment Cost Energy Usage(kWh/yr) On Market Off Market SEER 13 15 $5,700 857 2009 2014 SEER 14 (Energy Star) 15 $5,767 771 2009 n/a SEER 15 (CEE Tier 2) 15 $8,018 760 2009 n/a SEER 16 (CEE Tier 3) 15 $9,205 737 2009 n/a Table 2-6 lists some of the non-equipment measures applicable to space heating in an existing single-family home. All measures are evaluated for cost-effectiveness based on the lifetime benefits relative to the cost of the measure. The total savings and costs are calculated for each year of the study and depend on the base year saturation of the measure, the applicability2 of the measure, and the savings as a percentage of the relevant energy end uses. Table 2-6 Example Non-Equipment Measures – Single Family Home, Existing End Use Measure Saturation in 20093 Applicability Lifetime (yrs) Measure Installed Cost Energy Savings (%) Space Heating Insulation - Ducting 15% 59% 18 $500 5% Space Heating Repair and Sealing - Ducting 12% 100% 20 $571 23% Space Heating Thermostat - Clock/Programmable 72% 75% 15 $249 6% Space Heating Doors - Storm and Thermal 38% 100% 12 $320 1% Space Heating Insulation - Infiltration Control 46% 100% 25 $306 9% Space Heating Insulation - Ceiling 76% 75% 25 $630 10% Space Heating Insulation - Radiant Barrier 5% 100% 12 $923 6% Space Heating Windows - High Efficiency/ENERGY STAR 78% 100% 25 $5,201 30% Space Heating Behavioral Measures 20% 50% 1 $12 1% Screening Measures for Cost-Effectiveness Only measures that are cost-effective are included in economic and achievable potential. Therefore, for each individual measure, LoadMAP performs an economic screen. This study uses the TRC test that compares the lifetime energy and peak demand benefits, as well as well as any non-energy benefits included in the RTF measure database, with the measure’s incremental installed cost, including material and labor. The lifetime benefits are calculated by multiplying the annual energy and demand savings for each measure by all appropriate avoided costs for each year, and discounting the dollar savings to the present value equivalent. The analysis uses each measure’s values for savings, costs, and lifetimes that were developed as part of the measure 2 The applicability factors take into account whether the measure is applicable to a particular building type and whether it is feasible to install the measure. For instance, attic fans are not applicable to homes where there is insufficient space in the attic or there is no attic at all. 3 Note that saturation levels reflected for the base year change over time as more measures are adopted. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 826 of 1125 Analysis Approach and Data Development 2-10 www.enernoc.com characterization process described above. The analysis also accounts for transmission and distribution losses, and for program administration costs. The LoadMAP model performs this screening dynamically, taking into account changing savings and cost data over time. Thus, some measures pass the economic screen for some — but not all — of the years in the study period. It is important to note the following about the economic screen: The economic evaluation of every measure in the screen is conducted relative to a baseline condition. For instance, in order to determine the kilowatt-hour (kWh) savings potential of a measure, kWh consumption with the measure applied must be compared to the kWh consumption of a baseline condition. The economic screening was conducted only for measures that are applicable to each building type and vintage; thus if a measure is deemed to be irrelevant to a particular building type and vintage, it is excluded from the respective economic screen. If the measure passes the screen (has a B/C ratio greater than or equal to 1), the measure is included in economic potential. Otherwise, it is screened out for that year. If multiple equipment measures have B/C ratios greater than or equal to 1.0, the most efficient technology is selected by the economic screen. Table 2-7 shows the results of the economic screen for selected measures, indicating how the economic unit for a given technology may vary over time. For example, CFLs are initially the economical unit for interior screw-in lighting, but as the price of LEDs decreases, they become the economical unit for single family homes starting in 2017. For exterior lighting, due to longer hours of operation, LEDs are cost-effective starting in 2015. Table 2-7 Economic Screen Results for Selected Single Family Equipment Measures Technology 2014 2015 2016 2017 2018 2019 Interior Screw-in Lighting CFL CFL CFL LED LED LED Exterior Screw-in Lighting CFL LED LED LED LED LED Conservation Potential The approach we used for this study adheres to the approaches and conventions outlined in the National Action Plan for Energy-Efficiency (NAPEE) Guide for Conducting Potential Studies (November 2007).4 The NAPEE Guide represents the most credible and comprehensive industry practice for specifying energy-efficiency potential. As described in Chapter 1, three types of potentials were developed as part of this effort: Technical potential, Economic potential, and Achievable potential. Technical potential is a theoretical construct that assumes the highest efficiency measures that are technically feasible to install are adopted by customers, regardless of cost or customer preferences. Thus, determining the technical potential is relatively straightforward. LoadMAP selects the most efficient equipment options for each technology at the time of equipment replacement. In addition, it installs all relevant non-equipment measures for each technology to calculate savings. For example, for a central heat pump, as shown in Table 2- 5, the most efficient option is a SEER 16 system. The multiple non-equipment measures shown in Table 2-6 are then applied to the energy used by the ductless mini-split system to further reduce space conditioning energy use. LoadMAP applies the savings due to the non- equipment measures one-by-one to avoid double counting of savings. The measures are evaluated in order of their B/C ratio, with the measure with the highest B/C ratio applied 4 National Action Plan for Energy Efficiency (2007). National Action Plan for Energy Efficiency Vision for 2025: Developing a Framework for Change. www.epa.gov/eeactionplan. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 827 of 1125 Analysis Approach and Data Development EnerNOC Utility Solutions Consulting 2-11 first. Each time a measure is applied, the baseline energy use for the end use is reduced and the percentage savings for the next measure is applied to the revised (lower) usage. Economic potential results from the purchase of the most efficient cost-effective option available for a given equipment or non-equipment measure as determined in the cost- effectiveness screening process described above. As with technical potential, economic potential is a phased-in approach. Economic potential is still a hypothetical upper-boundary of savings potential as it represents only measures that are economic but does not yet consider customer acceptance and other factors. Achievable potential defines the range of savings that is very likely to occur. It accounts for customers’ awareness of efficiency options, any barriers to customer adoption, limits to program design, and other factors that influence the rate at which conservation measures penetrate the market. The calculation of technical and economic potential is straightforward as described above. To develop estimates for achievable potential, we specify market adoption rates for each measure and each year. For Avista, the project team began with the ramp rates specified in the Sixth Plan conservation workbooks, but modified these to match Avista program history and service territory specifics. For specific measures, we examined historic program results for the four-year period of 2009 through 2012. We then adjusted the 2009–2013 market acceptance rates so that the achievable potential for these measures aligned with the historical results. This provided a starting point for the ramp rates in 2014. For future years, we increased the potential factors to model increasing market acceptance and program improvements. For measures not currently included in Avista programs, we relied upon the Sixth Plan ramp rates and recent EnerNOC potential studies to create market adoption rates. The market adoption rates for each measure appear in Appendix D. Results of all the potentials analysis are presented in Chapter 4. Data Development This section details the data sources used in this study, followed by a discussion of how these sources were applied. In general, data were adapted to local conditions, for example, by using local sources for measure data and local weather for building simulations. Data Sources The data sources are organized into the following categories: Avista data NPCC and RTF data EnerNOC’s databases and analysis tools Other secondary data and reports Avista Data Our highest priority data sources for this study were those that were specific to Avista. Avista customer data: Avista provided number of customers and total electric usage by sector from the customer billing database. Avista Business Plan and program implementation and evaluation data: Data that outlines the details of conservation programs, program goals, and achievements to date. Avista Technical Resources Manual: provides collection of UES for prescriptive programs delivered by Avista as informed by its most recent impact evaluation efforts. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 828 of 1125 Analysis Approach and Data Development 2-12 www.enernoc.com Northwest Power and Conservation Council Data Northwest Power and Conservation Council Sixth Plan Conservation Supply Curve Workbooks, 2010. To develop its Power Plan, the Council used workbooks with detailed information about measures, available at http://www.nwcouncil.org/energy/powerplan/6/supplycurves/default.htm . Regional Technical Forum Deemed Measures. The NWPCC Regional Technical Forum maintains databases of deemed measure savings data, available at http://www.nwcouncil.org/energy/rtf/measures/Default.asp . Regional Technical Forum Residential SEEM modeling results http://rtf.nwcouncil.org/measures/support/Default.asp EnerNOC Databases, Analysis Tools, and Reports EnerNOC maintains several databases and modeling tools that we use for forecasting and potential studies. EnerNOC Energy Market Profiles: For more than 10 years, EnerNOC staff have maintained profiles of end-use consumption for the residential, commercial, and industrial sectors. These profiles include market size, fuel shares, unit consumption estimates, and annual energy use by fuel (electricity and natural gas), customer segment and end use for 10 regions in the U.S. The Energy Information Administration surveys (RECS, CBECS and MECS) as well as state-level statistics and local customer research provide the foundation for these regional profiles. Building Energy Simulation Tool (BEST). EnerNOC’s BEST is a derivative of the DOE 2.2 building simulation model, used to estimate base-year UECs and EUIs, as well as measure savings for the HVAC-related measures. EnerNOC’s EnergyShape™: This database of load shapes includes the following: Residential – electric load shapes for 10 regions, 3 housing types, 13 end uses; Commercial – electric load shapes for 9 regions, 54 building types, 10 end uses; Industrial – electric load shapes, whole facility only, 19 2-digit SIC codes, as well as various 3-digit and 4-digit SIC codes EnerNOC’s Database of Energy Efficiency Measures (DEEM): EnerNOC maintains an extensive database of measure data for our studies. Our database draws upon reliable sources including the California Database for Energy Efficient Resources (DEER), the EIA Technology Forecast Updates – Residential and Commercial Building Technologies – Reference Case, RS Means cost data, and Grainger Catalog Cost data. Recent studies. EnerNOC has conducted numerous studies of conservation potential in the last five years. We checked our input assumptions and analysis results against the results from these other studies, which include Idaho Power, and Seattle City Light. In addition, we used the information about impacts of building codes and appliance standards from a recent report for the Institute for Energy Efficiency.5 Other Secondary Data and Reports Finally, a variety of secondary data sources and reports were used for this study. The main sources are identified below. Residential Building Stock Assessment: NEEA’s 2011 Residential Building Stock Assessment (RBSA) provides results of a regional study of 1,404 homes, of which 27 are located within Avista’s service territory. Due to the relatively low number of customers, 27, within Avista’s service territory, we used the results for 113 homes in eastern Washington 5 ―Assessment of Electricity Savings in the U.S. Achievable through New Appliance/Equipment Efficiency Standards and Building Efficiency Codes (2010 – 2025).‖ Global Energy Partners, LLC for the Institute for Electric Efficiency, May 2011. http://www.edisonfoundation.net/iee/reports/IEE_CodesandStandardsAssessment_2010-2025_UPDATE.pdf Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 829 of 1125 Analysis Approach and Data Development EnerNOC Utility Solutions Consulting 2-13 and 52 homes in northern Idaho as proxies for Avista’s Washington and Idaho service territories respectively. This information allowed us to update the single family home market profiles from the 2011 CPA. At the time of the 2013 CPA, the RBSA results for mobile and multifamily homes had not yet been released. http://neea.org/docs/reports/residential-building-stock-assessment-single-family- characteristics-and-energy-use.pdf?sfvrsn=6 Commercial Building Stock Assessment: NEEA’s Commercial Building Stock Assessment (CBSA) provides data on regional commercial buildings. As of the most recent update in 2009, the database contains site-specific information for 2,061 buildings. http://neea.org/resource-center/regional-data-resources/commercial-building-stock- assessment American Community Survey: The US Census American Community Survey is an ongoing survey that provides data every year on household characteristics. http://www.census.gov/acs/www/ Residential Energy Consumption Survey (RECS). http://www.eia.gov/consumption/residential/data/2009/ Annual Energy Outlook. The Annual Energy Outlook (AEO), conducted each year by the U.S. Energy Information Administration (EIA), presents yearly projections and analysis of energy topics. For this study, we used data from the 2011 AEO. California Statewide Surveys. The Residential Appliance Saturation Survey (RASS) and the Commercial End Use Survey (CEUS) are comprehensive market research studies conducted by the California Energy Commission. These databases provide a wealth of information on appliance use in homes and businesses. RASS is based on information from almost 25,000 homes and CEUS is based on information from a stratified random sample of almost 3,000 businesses in California. Electric Power Research Institute – Assessment of Achievable Potential from Energy Efficiency and Demand Response Programs in the U.S., also known as the EPRI National Potential Study (2009). In 2009, EPRI hired EnerNOC to conduct an assessment of the national potential for energy efficiency, with estimates derived for the four DOE regions. EPRI End-Use Models (REEPS and COMMEND). These models provide the elasticities we apply to electricity prices, household income, home size and heating and cooling. Database for Energy Efficient Resources (DEER). The California Energy Commission and California Public Utilities Commission (CPUC) sponsor this database, which is designed to provide well-documented estimates of energy and peak demand savings values, measure costs, and effective useful life (EUL) for the state of California. We used the DEER database to cross check the measure savings we developed using BEST and DEEM. Northwest Power and Conservation Council Sixth Plan workbooks. To develop its Power Plan, the Council maintains workbooks with detailed information about measures. Other relevant regional sources. These include reports from the Consortium for Energy Efficiency, the EPA, and the American Council for an Energy-Efficient Economy. Data Application We now discuss how the data sources described above were used for each step of the study. Data Application for Market Characterization To construct the high-level market characterization of electricity use and households/floor space for the residential, commercial, and industrial sectors, we applied the following data sources: Avista internal data, RECS 2009 and the American Community Survey to allocate residential customers by housing type Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 830 of 1125 Analysis Approach and Data Development 2-14 www.enernoc.com Data Application for Market Profiles The specific data elements for the market profiles, together with the key data sources, are shown in Table 2-8. This CPA update began with the market profiles previously developed for the 2011 CPA, but we incorporated new residential sector data from the RBSA as described above. The C&I market profiles were largely unchanged because no significant additional data was available regarding Avista’s C&I customers. To develop the market profiles for each segment, we used the following approach: 1. Developed control totals for each segment. These include market size, segment-level annual electricity use, and annual intensity. 2. Used NEEA reports including the recently released RBSA Single Family report, the Inland Power & Light survey of its residential customers, and RECS to provide information about market size for customer segments, appliance and equipment saturations, appliance and equipment characteristics, UECs, building characteristics, customer behavior, operating characteristics, and energy-efficiency actions already taken. 3. Incorporated secondary data sources to supplement and corroborate the data from items 1 and 2 above. 4. Compared and cross-checked with regional data obtained as part of the EPRI National Potential Study and with the Energy Market Profiles Database. 5. Ensured calibration to control totals for annual electricity sales in each sector and segment. 6. Worked with Avista staff to vet the data against their knowledge and experience. Table 2-8 Data Applied for the Market Profiles Model Inputs Description Key Sources Market size Base-year residential dwellings and C&I floor space Avista billing data, NEEA Reports, NPCC data Annual intensity Residential: Annual energy use (kWh/household) C&I: Annual energy use Energy Market Profiles , NEEA reports, AEO, Inland Power & Light 2009 Conservation Potential Assessment, previous studies Appliance/equipment saturations Fraction of dwellings with an appliance/technology; Percentage of C&I floor space with equipment/technology NEAA reports, Inland Power & Light residential saturation survey, RECS, and other secondary data UEC/EUI for each end- use technology UEC: Annual electricity use for a technology in dwellings that have the technology EUI: Annual electricity use per square foot/employee for a technology in floor space that has the technology NEAA reports, RASS, CEUS, engineering analysis, prototype simulations, engineering analysis Appliance/equipment vintage distribution Age distribution for each technology NEEA reports, RASS, CEUS, secondary data (DEEM, EIA, EPRI, DEER, etc.) Efficiency options for each technology List of available efficiency options and annual energy use for each technology Prototype simulations, engineering analysis, appliance/equipment standards, secondary data (DEEM, EIA, EPRI, DEER, etc.) Peak factors Share of technology energy use that occurs during the peak hour Avista data; EnerNOC’s EnergyShape database Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 831 of 1125 Analysis Approach and Data Development EnerNOC Utility Solutions Consulting 2-15 Data Application for Baseline Projection Table 2-9 summarizes the LoadMAP model inputs requirements. These inputs are required for each segment within each sector, as well as for new construction and existing dwellings/buildings. Table 2-9 Data Needs for the Baseline Projection and Potentials Estimation in LoadMAP Model Inputs Description Key Sources Customer growth forecasts Forecasts of new construction in residential and C&I sectors AEO 2011 growth forecast US BLS Equipment purchase shares for baseline projection For each equipment/technology, purchase shares for each efficiency level; specified separately for existing equipment replacement and new construction Shipments data from AEO AEO 2011 regional forecast assumptions6 Appliance/efficiency standards analysis Avista program results and evaluation reports Electricity prices Forecast of average energy and capacity avoided costs and retail prices Avista projections AEO 2011 Utilization model parameters Price elasticities, elasticities for other variables (income, weather) EPRI’s REEPS and COMMEND models AEO 2011 Avista’s historical data for normal cooling & heating degree days. In addition, we implemented assumptions for known future equipment standards as of January, 2012, as shown in the tables below. 6 We developed baseline purchase decisions using the Energy Information Agency’s Annual Energy Outlook report (2011), which utilizes the National Energy Modeling System (NEMS) to produce a self-consistent supply and demand economic model. We calibrated equipment purchase options to match manufacturer shipment data for recent years and then held values constant for the study period. This removes any effects of naturally occurring conservation or effects of future DSM programs that may be embedded in the AEO forecasts. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 832 of 1125 Analysis Approach and Data Development 2-16 www.enernoc.com Table 2-10 Residential Electric Equipment Standards Applicable to Avista Today's Efficiency or Standard Assumption 1st Standard (relative to today's standard) 2nd Standard (relative to today's standard) End Use Technology 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Central AC Room AC Cooling/Heating Heat Pump Water Heater (<=55 gallons) Water Heater (>55 gallons) Screw-in/Pin Lamps Linear Fluorescent Refrigerator/2nd Refrigerator Freezer Dishwasher Clothes Washer Clothes Dryer Range/Oven Microwave Cooling SEER 13 SEER 14 EER 9.8 EER 11.0 SEER 13.0/HSPF 7.7 SEER 14.0/HSPF 8.0 Water Heating EF 0.90 EF 0.95 EF 0.90 Heat Pump Water Heater Appliances NAECA Standard 25% more efficient NAECA Standard 25% more efficient Conventional Conventional Conventional (355 kWh/yr)14% more efficient (307 kWh/yr) Conventional (MEF 1.26 for top loader)MEF 1.72 for top loader MEF 2.0 for top loader Conventional (EF 3.01)5% more efficient (EF 3.17) Lighting Incandescent Advanced Incandescent - tier 1 Advanced Incandescent - tier 2 T8 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 833 of 1125 Analysis Approach and Data Development EnerNOC Utility Solutions Consulting 2-17 Table 2-11 Commercial Electric Equipment Standards Applicable to Avista Today's Efficiency or Standard Assumption 1st Standard (relative to today's standard) 2nd Standard (relative to today's standard) End Use Technology 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Chillers Roof Top Units Packaged Terminal AC/HP EER 9.8 Screw-in/Pin Lamps Linear Fluorescent T12 High Intensity Discharge Walk-in Refrigerator/Freezer Reach-in Refrigerator Glass Door Display EPACT 2005 Standard Open Display Case EPACT 2005 Standard Vending Machines EPACT 2005 Standard Icemaker Non-HVAC Motors Commercial Laundry Cooling 2007 ASHRAE 90.1 EER 11.0/11.2 EER 11.0 Lighting Incandescent Advanced Incandescent - tier 1 Advanced Incandescent - tier 2 T8 Metal Halide Refrigeration EISA 2007 Standard EPACT 2005 Standard 42% more efficient 18% more efficient 33% more efficient 2010 Standard Miscellaneous 62.3% Efficiency 70% Efficiency MEF 1.26 MEF 1.6 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 834 of 1125 Analysis Approach and Data Development 2-18 www.enernoc.com Table 2-12 Industrial Electric Equipment Standards Applicable to Avista Today's Efficiency or Standard Assumption 1st Standard (relative to today's standard) 2nd Standard (relative to today's standard) End Use Technology 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Chillers Roof Top Units Packaged Terminal AC/HP EER 9.8 Screw-in/Pin Lamps Linear Fluorescent T12 High Intensity Discharge Less than 5 HP 5-24 HP 25-99 HP 100-249 HP 250-499 HP 500 or more HP Cooling 2007 ASHRAE 90.1 EER 11.0/11.2 EER 11.0 Lighting Incandescent Advanced Incandescent - tier 1 Advanced Incandescent - tier 2 T8 Metal Halide Machine Drive 62.3% Efficiency 70% Efficiency EISA 2007 Standards EISA 2007 Standards EISA 2007 Standards EISA 2007 Standards EISA 2007 Standards Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 835 of 1125 Analysis Approach and Data Development EnerNOC Utility Solutions Consulting 2-19 Conservation Measure Data Application Table 2-13 details the data sources used for measure characterization. Table 2-13 Data Needs for the Measure Characteristics in LoadMAP Model Inputs Description Key Sources Energy Impacts The annual reduction in consumption attributable to each specific measure. Savings were developed as a percentage of the energy end use that the measure affects. Avista program results and evaluation reports BEST DEEM DEER NPCC workbooks Other secondary sources Peak Demand Impacts Savings during the peak demand periods are specified for each electric measure. These impacts relate to the energy savings and depend on the extent to which each measure is coincident with the system peak. Avista program results and evaluation reports BEST EnergyShape Costs Equipment Measures: Includes the full cost of purchasing and installing the equipment on a per- household, per-square-foot, or per employee basis for the residential, commercial, and industrial sectors, respectively. Non-equipment measures: Existing buildings – full installed cost. New Construction - the costs may be either the full cost of the measure, or as appropriate, it may be the incremental cost of upgrading from a standard level to a higher efficiency level. Avista program results and evaluation reports DEEM DEER NPCC workbooks RS Means Other secondary sources Measure Lifetimes Estimates derived from the technical data and secondary data sources that support the measure demand and energy savings analysis. Avista program results and evaluation reports DEEM DEER NPCC workbooks Other secondary sources Applicability Estimate of the percentage of either dwellings in the residential sector or square feet/employment in the C&I sector where the measure is applicable and where it is technically feasible to implement. DEEM DEER NPCC workbooks Other secondary sources On Market and Off Market Availability Expressed as years for equipment measures to reflect when the equipment technology is available or no longer available in the market. EnerNOC appliance standards and building codes analysis Data Application for Cost-effectiveness Screening To perform the cost-effectiveness screening, the following information was needed: Preliminary avoided cost of energy and capacity provided by Avista and based on 2013 IRP planning assumptions, shown in Figure 2-4; note that Avista does not expect to incur any avoided cost for capacity until 2019. Line losses of 6.12%, provided by Avista Discount rate of 4%, provided by Avista (real) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 836 of 1125 Analysis Approach and Data Development 2-20 www.enernoc.com Program administration costs. Program administration costs can typically vary between 5– 50% of total program costs. For this study, we used values of 30% that were provided by Avista, based on its program history. Figure 2-4 Avoided Costs Achievable Potential Estimation To estimate potentials, two sets of parameters were required. Adoption rates for non-equipment measures. Equipment is assumed to be replaced at the end of its useful life, but for non-equipment measures, a set of factors is required to model the gradual implementation over time. Rather than installing all non-equipment measures in the first year of the forecast (instantaneous potential), they are phased in according to adoption schedules that vary based on equipment cost and measure complexity. The adoption rates for the Avista study were based on ramp rate curves specified in the NPCC Sixth Power Plan, but modified to reflect Avista’s program history. These adoption rates are used within LoadMAP to generate the technical and economic potentials. Market acceptance rates (MARs). These factors are applied to Economic potential to estimate Achievable potential. These rates were developed by beginning with the Northwest Power and Conservation Council ramp rates but then adjusting those rates to reflect Avista’s DSM program history. Ramp rates and MARs are discussed in Appendix D. 0 50 100 150 200 250 - 10 20 30 40 50 60 Av o i d e d C a p a c i t y C o s t s ( $ / k W ) Av o i d e d E n e r g y C o s t , $ / M W h Avoided Energy Cost, $/MWh Avoided Capacity Cost ($/kW) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 837 of 1125 EnerNOC Utility Solutions Consulting 3-1 CHAPTER 3 MARKET CHARACTERIZATION AND MARKET PROFILES Avista Utilities, headquartered in Spokane, Washington, is an investor-owned utility with annual revenues of more than $1.6 billion. Avista provides electric and natural gas service to about 680,000 customers in a service territory of more than 30,000 square miles. Avista uses a mix of hydro, natural gas, coal and biomass generation. Avista currently operates a portfolio of electric and natural gas conservation programs in Washington, Idaho, and Oregon for residential, low income, and non-residential customers that is funded by a non-bypassable systems benefits charge. This study addresses electricity conservation potential in Washington and Idaho only. This chapter characterizes the electricity use patterns of Avista’s customers. Energy Use Summary Table 3-1 and Table 3-2 provide 2009 customer counts and weather-normalized electricity use by sector for Washington and Idaho, respectively. For this study, the NPCC Sixth Plan calculator to estimate conservation potential for pumping. Results of that calculation appear in Chapter 4. Potential for rate class 25P was also estimated outside of the LoadMAP framework, and thus 25P sales are not included in Table 3-2. Table 3-1 Electricity Sales and Peak Demand by Rate Class, Washington 2009 Sector / Rate Class Rate Schedule(s) Number of meters (customers) 2009 Electricity Sales (GWh) 2009 Peak Demand (MW) Residential 001 200,134 2,452 710 General Service 011, 012 27,142 416 64 Large General Service 021, 022 3,352 1,557 232 Extra Large Commercial 025C 9 266 134 Extra Large Industrial 025I 13 614 Pumping 031, 032 2,361 136 10 Total 233,011 5,440 1,150 Table 3-2 Electricity Sales and Peak Demand by Rate Class, Idaho 2009 Sector / Rate Class Rate Schedule(s) Number of meters (customers) 2009 Electricity Sales (MWh) 2009 Peak Demand (MW) Residential 001 99,580 1,182 283 General Service 011, 012 19,245 323 61 Large General Service 021, 022 1,456 700 115 Extra Large Commercial 025C 3 70 140 Extra Large Industrial 025I 6 196 Pumping 031, 032 1,312 59 4 Total 121,602 2,530 603 Note: Excludes sales to rate class 25P. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 838 of 1125 Market Characterization and Market Profiles 3-2 www.enernoc.com After excluding pumping and 25 P, the distribution among the sectors in Washington and Idaho is similar, with the largest sector, residential, accounting for 46% of Washington sales and 48% of Idaho sales as shown in Figure 3-1 and Figure 3-2. Figure 3-1 Electricity Sales by Rate Class, 2009 Figure 3-2 Electricity Sales by Rate Class, Idaho 2009 Note: Excludes sales to rate class 25P. Residential 46% General Service 8% Large General Service 29% Extra Large Commercial 5%Extra Large Industrial 12% Residential 48% General Service 13% Large General Service 28% Extra Large Commercial 3% Extra Large Industrial 8% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 839 of 1125 Market Characterization and Market Profiles EnerNOC Utility Solutions Consulting 3-3 Residential Sector The total number of households and electric sales for the service territory were obtained from Avista’s financial reporting database. In 2009, there were 200,134 households in Washington and 99,580 in Idaho. We allocated these totals into the four residential segments for each segment based on housing type and level of income: Single family, multi family, mobile home, and low income. The single family segment includes single-family detached homes, townhouses, and duplexes or row houses. The multi family segment includes apartments or condos in buildings with more than two units. The mobile homes segment includes mobile homes and other manufactured housing. The low income segment is composed of all three of the housing types: single-family homes, multi-family homes, and mobile homes. Table 3-3 shows how customers were allocated to segments. Because Avista does not maintain information on housing type or income level, we relied on a variety of survey and demographic sources for segmenting the residential market, including the U.S. Census American Community Survey 2006-2008, and a 2009 Inland Power customer survey. Avista defines the low-income category as those customers with annual income less than or equal to two times the poverty level. For an average household size of 2.5 persons, two times the poverty level is $32,880. For the purpose of our analysis, we used a slightly higher income level cutoff of $35,000 to define this segment, which allowed us to take advantage of the data sources listed above. Table 3-3 Residential Sector Allocation by Segments, 2009 Washington Idaho Segment Allocation of Customers % of Total Allocation of Customers % of Total Single Family 109,134 54% 59,205 59% Multi Family 18,219 9% 5,237 5% Mobile Home 5,248 3% 4,774 5% Low Income 67,533 34% 30,363 31% Total 200,134 100% 99,580 100% Next, to determine the residential whole building energy intensity (kWh/household) by segment, we drew upon data from the Energy Information Agency, the NEEA 2012 RBSA, previous NEEA residential reports, and the Inland Power & Light 2009 Conservation Potential Assessment. Based on these sources, we developed the segment level energy intensities shown in Table 3-4. The selected energy intensity values multiplied by the number of households equal the annual sales for each segment. These values sum to the total annual energy use for the residential sector in each state. The single-family segment used roughly two-thirds of the total 2009 residential sector electricity sales. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 840 of 1125 Market Characterization and Market Profiles 3-4 www.enernoc.com Table 3-4 Residential Electricity Usage and Intensity by Segment and State, 2009 Washington Segment No. of Households Intensity (kWh/HH) % of Customers 2009 Electricity Use (GWh) % of Sales Single Family 109,134 14,547 54% 1,588 65% Multi Family 18,219 8,728 9% 159 6% Mobile Home 5,248 13,092 3% 69 3% Low Income 67,533 9,424 34% 636 26% Total 200,134 12,250 100% 2,452 100% Idaho Segment No. of Households Intensity (kWh/HH) % of Customers 2009 Electricity Use (GWh) % of Sales Single Family 59,205 13,703 59% 811 69% Multi Family 5,237 8,213 5% 43 4% Mobile Home 4,774 12,320 5% 59 5% Low Income 30,363 8,868 31% 269 23% Total 99,580 11,874 100% 1,182 100% As we describe in the previous chapter, the market profiles provide the foundation upon which we develop the baseline projection. For each segment, we created a market profile, which includes the following elements: Market size represents the number of customers in the segment Saturations embody the fraction of homes with the electric technologies. (e.g., homes with electric space heating). We developed these using a combination of data from sources including Avista TRM and Business Plan data, NEEA’s RBSA and other NEEA reports, Inland Power & Light, NPCC, and AEO data. UEC (unit energy consumption) describes the amount of electricity consumed in 2009 by a specific technology in homes that have the technology (in kWh/household). As above, we used data from Avista, NEEA, Inland Power & Light, NPCC, and AEO. We also used data from various utility potential studies that EnerNOC has recently completed. As needed, minor adjustments were made to calibrate to whole-building intensities. Intensity represents the average use for the technology across all homes in 2009. It is computed as the product of the saturation and the UEC and is defined as kWh/household. Usage is the annual electricity use by a technology/end use in the segment. It is the product of the number of households and intensity and is quantified in GWh. Table 3-5 and Table 3-6 present the average existing home market profile for all residential segments in Washington and Idaho combined. The existing-home profile represents all the housing stock in 2009. Market profiles for each of the residential segments in Washington and Idaho appear in Appendix A. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 841 of 1125 Market Characterization and Market Profiles EnerNOC Utility Solutions Consulting 3-5 Table 3-5 Average Residential Sector Market Profile, Washington UEC Intensity Usage (kWh) (kWh/HH) (GWh) Cooling Central AC 28.6% 1,150 330 66 Cooling Room AC 20.7%360 75 15 Cooling Air Source Heat Pump 16.3%735 120 24 Cooling Geothermal Heat Pump 0.2%730 2 0 Space Heating Electric Resistance 20.4% 6,624 1,350 270 Space Heating Electric Furnace 10.7% 9,173 980 196 Space Heating Air Source Heat Pump 16.3% 7,498 1,222 245 Space Heating Geothermal Heat Pump 0.2% 4,833 11 2 Space Heating Supplemental 7.8%260 20 4 Water Heating Water Heater <= 55 Gal 66.3% 3,074 2,038 408 Water Heating Water Heater > 55 Gal 3.1% 4,552 140 28 Interior Lighting Screw-in 100.0% 1,060 1,060 212 Interior Lighting Linear Fluorescent 100.0%107 107 21 Interior Lighting Specialty 100.0%275 275 55 Exterior Lighting Screw-in 100.0%254 254 51 Appliances Clothes Washer 82.7%114 94 19 Appliances Clothes Dryer 78.8%493 389 78 Appliances Dishwasher 85.6%386 330 66 Appliances Refrigerator 100.0%694 694 139 Appliances Freezer 56.1%774 434 87 Appliances Second Refrigerator 25.9%977 253 51 Appliances Stove 87.7%386 338 68 Appliances Microwave 95.6%114 109 22 Electronics Personal Computers 119.0%205 244 49 Electronics TVs 204.4%221 452 90 Electronics Set-top Boxes/DVR 155.2%128 198 40 Electronics Devices and Gadgets 100.0%55 55 11 Miscellaneous Pool Pump 3.6% 1,415 52 10 Miscellaneous Furnace Fan 43.7%577 252 50 Miscellaneous Miscellaneous 100.0%373 373 75 12,250 2,452 End Use Technology Average Market Profiles - Washington Total Saturation Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 842 of 1125 Market Characterization and Market Profiles 3-6 www.enernoc.com Table 3-6 Average Residential Sector Market Profile, Idaho Table 3-7 and Figure 3-3 present the end-use shares of electricity use by housing type. Space heating is the largest single use in all housing types, accounting for 29% of residential use overall. In the single family, mobile home, and low income segments, appliances are the second largest energy consumer, followed by water heating and then interior lighting. In the case of multi-family housing, water heating is the second largest end use while appliances are the third largest end use, due to a high saturation of electric water heating compared with the other segments. Across all housing types, interior and exterior lighting combined represents 14% of electricity use in 2009. The electronics end use, which includes personal computers, televisions, home audio, video game consoles, etc., is 8% of residential electricity usage across all housing types. The miscellaneous end use includes such devices as furnace fans, pool pumps, and other plug loads (hair dryers, power tools, coffee makers, etc.). UEC Intensity Usage (kWh) (kWh/HH) (GWh) Cooling Central AC 22.0%945 207 21 Cooling Room AC 19.7%297 58 6 Cooling Air Source Heat Pump 12.9%609 79 8 Cooling Geothermal Heat Pump 0.7%657 5 0 Space Heating Electric Resistance 20.8% 7,481 1,556 155 Space Heating Electric Furnace 9.7% 8,401 815 81 Space Heating Air Source Heat Pump 12.9% 7,415 959 95 Space Heating Geothermal Heat Pump 0.7% 5,075 35 3 Space Heating Supplemental 7.5%258 19 2 Water Heating Water Heater <= 55 Gal 60.8% 3,127 1,901 189 Water Heating Water Heater > 55 Gal 3.4% 4,779 160 16 Interior Lighting Screw-in 100.0% 1,109 1,109 110 Interior Lighting Linear Fluorescent 100.0%111 111 11 Interior Lighting Specialty 100.0%293 293 29 Exterior Lighting Screw-in 100.0%280 280 28 Appliances Clothes Washer 85.8%113 97 10 Appliances Clothes Dryer 81.9%490 402 40 Appliances Dishwasher 87.0%384 334 33 Appliances Refrigerator 100.0%690 690 69 Appliances Freezer 57.8%768 444 44 Appliances Second Refrigerator 23.0%954 219 22 Appliances Stove 80.9%379 306 31 Appliances Microwave 96.0%114 109 11 Electronics Personal Computers 122.5%204 250 25 Electronics TVs 207.5%219 454 45 Electronics Set-top Boxes/DVR 146.1%125 182 18 Electronics Devices and Gadgets 100.0%54 54 5 Miscellaneous Pool Pump 5.1% 1,422 73 7 Miscellaneous Furnace Fan 44.0%593 261 26 Miscellaneous Miscellaneous 100.0%410 410 41 11,874 1,182 Average Market Profiles - Idaho Total SaturationEnd Use Technology Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 843 of 1125 Market Characterization and Market Profiles EnerNOC Utility Solutions Consulting 3-7 Table 3-7 Residential Electricity Use by End Use and Segment (kWh/HH/year, 2009) End Use Single Family Multi Family Mobile Home Low Income Total Residential Cooling 652 112 259 256 467 Space Heating 3,739 3,312 5,224 3,009 3,517 Water Heating 2,341 1,628 1,928 1,937 2,139 Interior Lighting 1,810 1,002 1,351 998 1,466 Exterior Lighting 370 21 276 135 263 Appliances 3,163 1,540 2,197 2,013 2,628 Electronics 1,163 726 887 630 945 Miscellaneous 1,013 271 602 272 699 Total 14,250 8,613 12,724 9,251 12,125 Figure 3-3 Percentage of Residential Electricity Use by End Use and Segment (2009) Figure 3-4 presents the end-use breakout in terms of intensity, kWh/household-year, by segment for both states combined. 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Single Family Multi Family Mobile Home Low Income All Homes % o f T o t a l E n e r g y U s e Cooling Heating Water Heating Interior Lighting Exterior Lighting Appliances Electronics Miscellaneous Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 844 of 1125 Market Characterization and Market Profiles 3-8 www.enernoc.com Figure 3-4 Residential Intensity by End Use and Segment (kWh/household, 2009) C&I Sector The approach we used for the C&I sectors is analogous to the residential sector. It begins with segmentation, then defines market size and annual electricity use, and concludes with market profiles. We developed the nonresidential energy use by segment using Avista 2009 billing data by rate class. Table 3-7 and Table 3-8 present the results for the market characterization for Washington and Idaho respectively. Although the General Service 011 and Large General Service 021 rate classes include a small percentage of industrial customers, we chose to model these as primarily commercial building types. For the General Service segment, we assumed facilities were small to medium buildings, dominated by retail facilities. For the Large General Service segment, we assumed the typical facility was an office building. When developing the market profiles, as further described below, we began with these assumed prototypical building types, but adjusted them to account for the diversity in each segment. For the Extra Large General Service rate class 025, we divided customers into separate commercial and industrial segments. This grouping enabled better modeling of the industrial customers. Note that potential for Idaho rate class 025P was determined outside of the LoadMAP modeling framework because it was more appropriate to treat this one large customer separately as opposed to modeling it as a generic C&I customer. Figure 3-5 shows the relative energy use of each segment as a percentage of C&I sector energy sales. 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 Single Family Multi Family Mobile Home Low Income All Homes In t e n s i t y ( k W h / H H / y r ) Cooling Heating Water Heating Interior Lighting Exterior Lighting Appliances Electronics Miscellaneous Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 845 of 1125 Market Characterization and Market Profiles EnerNOC Utility Solutions Consulting 3-9 Table 3-8 Commercial and Industrial Sector Market Characterization Results, Washington 2009 Segment Electricity Use (GWh) Intensity (kWh/SqFt) Floor Space (million SqFt) Small/Medium Commercial 416 18 24 Large Commercial 1,557 17 93 Extra Large Commercial 266 14 19 Extra Large Industrial 614 40 15 Total 2,852 19 151 Table 3-9 Commercial and Industrial Sector Market Characterization Results, Idaho 2009 Segment Electricity Use (GWh) Intensity (kWh/SqFt) Floor Space (million SqFt) Small/Medium Commercial 323 18 18 Large Commercial 700 17 42 Extra Large Commercial 70 14 5 Extra Large Industrial 196 40 5 Total 1,289 18 70 Note: Excludes sales to rate class 25P. Figure 3-5 Commercial and Industrial Electricity Consumption by Segment 2009 We used data from NEEA reports including the 2009 CBSA, the California Commercial End Use Study (CEUS), and recently completed EnerNOC studies to estimate floor space and annual intensities (in kWh/square foot) for each segment. Because of the heterogeneous nature of the Small/Medium Commercial 18% Large Commercial 54% Extra Large Commercial 8% Extra Large Industrial 20% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 846 of 1125 Market Characterization and Market Profiles 3-10 www.enernoc.com C&I sectors and the wide variation in customer size (compared to residential homes), floor space is used as the unit of measure to quantify energy use and equipment inventories on a per- square-foot basis. Note that we are not concerned with absolute square footage, as the purpose of this study is not to estimate C&I floor space, but with the relative size of each segment and its growth over time. We then developed market profiles for each non-residential segment in each state. Table 3-10 shows an example commercial average base year market profile, in this case for the Washington Small/Medium Commercial Segment. The market profiles for each of the Washington and Idaho C&I segments are shown in Appendix A. Table 3-10 Large Commercial Segment Market Profile, Washington, 2009 EUI Intensity Usage (kWh) (kWh/Sqft.) (GWh) Cooling Central Chiller 24.7% 2.1 0.5 49 Cooling RTU 37.8% 2.5 1.0 89 Cooling Heat Pump 9.1% 3.5 0.3 30 Space Heating Heat Pump 9.1% 2.3 0.2 20 Space Heating Electric Resistance 5.9% 3.6 0.2 20 Space Heating Furnace 12.7% 4.7 0.6 55 Ventilation Ventilation 75.1% 1.7 1.2 116 Interior Lighting Interior Screw-in 100.0% 0.9 0.9 88 Interior Lighting High Bay Fixtures 100.0% 0.7 0.7 66 Interior Lighting Linear Fluorescent 100.0% 3.3 3.3 307 Exterior Lighting Exterior Screw-in 100.0% 0.1 0.1 9 Exterior Lighting HID 100.0% 0.7 0.7 65 Water Heating Water Heater 54.2% 2.3 1.3 117 Food Preparation Fryer 18.4% 0.4 0.1 6 Food Preparation Oven 18.4% 1.9 0.3 32 Food Preparation Dishwasher 18.4% 0.2 0.0 3 Food Preparation Hot Food Container 18.4% 0.3 0.1 5 Food Preparation Food Prep 18.4% 0.0 0.0 0 Refrigeration Walk in Refrigeration 39.1% 0.5 0.2 17 Refrigeration Glass Door Display 39.1% 0.4 0.1 13 Refrigeration Reach-in Refrigerator 39.1% 0.8 0.3 28 Refrigeration Open Display Case 39.1% 0.3 0.1 10 Refrigeration Vending Machine 39.1% 0.4 0.1 13 Refrigeration Icemaker 39.1% 0.7 0.3 24 Office Equipment Desktop Computer 98.4% 0.9 0.9 82 Office Equipment Laptop Computer 98.4% 0.1 0.1 6 Office Equipment Server 98.4% 0.4 0.4 38 Office Equipment Monitor 98.4% 0.2 0.2 19 Office Equipment Printer/copier/fax 98.4% 0.2 0.2 19 Office Equipment POS Terminal 98.4% 0.1 0.1 6 Miscellaneous Non-HVAC Motor 57.7% 1.4 0.8 75 Miscellaneous Other Miscellaneous 100.0% 1.4 1.4 127 16.7 1,557 Total End Use Technology Saturation Average Market Profiles Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 847 of 1125 Market Characterization and Market Profiles EnerNOC Utility Solutions Consulting 3-11 Figure 3-6 displays the breakdown of energy use by end use for all C&I segments combined. This information is further detailed in Table 3-11 and Figure 3-7, which present the end-use shares of electricity use by segment. Figure 3-6 C&I Electricity Consumption by End Use, 2009 Table 3-11 C&I Electricity Consumption by End Use and Segment (GWh, 2009) End Use Small/Medium Commercial Large Commercial Extra Large Commercial Extra Large Industrial Total C&I Cooling 87 244 43 48 421 Space Heating 68 168 42 68 347 Ventilation 53 169 24 - 246 Water Heating 213 668 93 50 1,024 Interior Lighting 39 108 22 5 174 Exterior Lighting 36 153 14 - 204 Refrigeration 16 68 8 - 92 Food Preparation 70 248 26 - 344 Office Equipment 81 293 37 99 510 Miscellaneous 75 138 28 25 266 Process - - - 162 162 Machine Drive - - - 352 352 Total 739 2,257 336 809 4,141 Cooling 10% Space Heating 7% Ventilation 8% Water Heating 6% Interior Lighting 25% Exterior Lighting 4% Refrigeration 5% Food Preparation 2% Office Equipment 8% Miscellaneous 12% Process 4% Machine Drive 9% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 848 of 1125 Market Characterization and Market Profiles 3-12 www.enernoc.com Figure 3-7 C&I Electricity Consumption by End Use and Segment (2009) Observations include the following: Commercial buildings, including Small/Medium, Large, and Extra Large o Lighting is the largest single energy use across all of the commercial buildings, accounting for 34% of energy use. o Space conditioning, including space heating, cooling, and ventilation, is close behind with 27% of energy use. o Miscellaneous, which includes non-HVAC motors, vertical transport (e.g. elevators, escalators), medical equipment, telecommunications equipment, and various other loads, is the next largest energy use at 12%. o Office equipment, with 10% of use, is the fourth largest end use. o Water heating, refrigeration, and food preparation are only a small portion of energy use in the commercial sector overall, though they are more significant in specific building types (supermarkets, restaurants, hospitals, lodging). Extra Large Industrial facilities o Machine drive and process loads dominate in this segment, together accounting for 64% of energy use. o HVAC and interior lighting consume 17% and 7% of energy respectively. 0 500 1000 1500 2000 2500 Small/Medium Commercial Large Commercial Extra Large Commercial Extra Large Industrial An n u a l U s e ( 1 , 0 0 0 0 M W h ) Cooling Space Heating Ventilation Water Heating Interior Lighting Exterior Lighting Refrigeration Food Preparation Office Equipment Miscellaneous Process Machine Drive Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 849 of 1125 EnerNOC Utility Solutions Consulting 4-1 CHAPTER 4 CONSERVATION POTENTIAL This chapter presents the results of the potential analysis, beginning with overall potential, followed by details for each sector. All results show cumulative potential, indicating how a measure installed in one year continues to provide savings in subsequent years through the end of its useful measure life. Incremental annual results appear in Appendix E. Overall Potential Figure 4-1 and Table 4-1 summarize the achievable potential across all sectors. The C&I sector accounts for the about 55% of the savings initially, and over time its share of savings grows to around 60%. Figure 4-1 Cumulative Achievable Potential by Sector (MWh) - 200,000 400,000 600,000 800,000 1,000,000 1,200,000 1,400,000 1,600,000 Cu m u l a t i v e S a v i n g s ( M W h ) Irrigation Cumulative Savings (MWh) C&I Cumulative Savings (MWh) Residential Cumulative Savings (MWh) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 850 of 1125 Conservation Potential 4-2 www.enernoc.com Table 4-1 Cumulative Achievable Potential by State and Sector (MWh) 2014 2015 2018 2023 2028 2033 Washington Achievable Cumulative Savings (MWh) Residential 15,091 29,603 100,792 172,576 266,751 369,293 C&I 19,927 40,930 123,755 256,653 392,186 543,380 Pumping 1,402 3,237 8,742 10,535 10,535 10,535 Total 36,420 73,770 233,289 439,764 669,472 923,208 Washington Achievable Cumulative Savings (aMW) Residential 1.7 3.4 11.5 19.7 30.5 42.2 C&I 2.3 4.7 14.1 29.3 44.8 62.0 Pumping 0.2 0.4 1.0 1.2 1.2 1.2 Total 4.2 8.4 26.6 50.2 76.4 105.4 2014 2015 2018 2023 2028 2033 Idaho Achievable Cumulative Savings (MWh) Residential 6,757 13,183 46,795 79,385 125,347 177,826 C&I 8,863 16,427 53,214 124,987 192,518 261,813 Pumping 618 1,426 3,852 4,642 4,642 4,642 Total 16,238 31,036 103,861 209,014 322,507 444,281 Idaho Achievable Cumulative Savings (aMW) Residential 0.8 1.5 5.3 9.1 14.3 20.3 C&I 1.0 1.9 6.1 14.3 22.0 29.9 Pumping 0.1 0.2 0.4 0.5 0.5 0.5 Total 1.9 3.5 11.9 23.9 36.8 50.7 2014 2015 2018 2023 2028 2033 Washington and Idaho Achievable Cumulative Savings (MWh) Residential 21,848 42,786 147,588 251,961 392,098 547,119 C&I 28,790 57,357 176,969 381,640 584,703 805,193 Pumping 2,020 4,663 12,593 15,177 15,177 15,177 Total 52,657 104,806 337,150 648,778 991,979 1,367,490 Washington and Idaho Achievable Cumulative Savings (aMW) Residential 2.5 4.9 16.8 28.8 44.8 62.5 C&I 3.3 6.5 20.2 43.6 66.7 91.9 Pumping 0.2 0.5 1.4 1.7 1.7 1.7 Total 6.0 12.0 38.5 74.1 113.2 156.1 Table 4-2 summarizes the three levels of conservation potential, by state and for the overall service territory, for selected years. For rate class 25P and pumping customers, only achievable potential was assessed; economic and technical potential for these two small rate classes are assumed to be equal to achievable potential. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 851 of 1125 Conservation Potential EnerNOC Utility Solutions Consulting 4-3 Table 4-2 Summary of Cumulative Conservation Potential 2014 2015 2018 2023 2028 2033 Washington Cumulative Savings (MWh) Achievable Potential 36,420 73,770 233,289 439,764 669,472 923,208 Economic Potential 214,944 329,262 741,547 1,131,761 1,539,860 1,807,576 Technical Potential 794,447 941,497 1,550,783 2,212,885 2,704,067 3,024,259 Washington Cumulative Savings (aMW) Achievable Potential 4.2 8.4 26.6 50.2 76.4 105.4 Economic Potential 24.5 37.6 84.7 129.2 175.8 206.3 Technical Potential 90.7 107.5 177.0 252.6 308.7 345.2 Idaho Cumulative Savings (MWh) Achievable Potential 16,238 31,036 103,861 209,014 322,507 444,281 Economic Potential 101,779 151,705 350,121 538,404 734,193 859,791 Technical Potential 368,926 430,787 700,966 975,464 1,195,587 1,330,893 Idaho Cumulative Savings (aMW) Achievable Potential 1.9 3.5 11.9 23.9 36.8 50.7 Economic Potential 11.6 17.3 40.0 61.5 83.8 98.1 Technical Potential 42.1 49.2 80.0 111.4 136.5 151.9 Total Washington and Idaho Cumulative Savings (MWh) Achievable Potential 52,657 104,806 337,150 648,778 991,979 1,367,490 Economic Potential 316,722 480,967 1,091,669 1,670,165 2,274,053 2,667,367 Technical Potential 1,163,373 1,372,283 2,251,749 3,188,349 3,899,655 4,355,152 Total Washington and Idaho Cumulative Savings (aMW) Achievable Potential 6.0 12.0 38.5 74.1 113.2 156.1 Economic Potential 36.2 54.9 124.6 190.7 259.6 304.5 Technical Potential 132.8 156.7 257.0 364.0 445.2 497.2 Note: For pumping and rate class 25P, only achievable potential was calculated and thus economic and technical potential were assumed to be equal to achievable potential for these two rate classes. Key findings related to cumulative conservation potentials are as follows. Achievable potential, for the residential, commercial, and industrial sectors is 100,143 MWh or 11.4 aMW for the 2014–2015 biennium. With the addition of pumping, achievable potential is 12.0 aMW for the 2014-2015 biennium and increases to 156.1 aMW by 2033. Washington provides approximately 70% of the potential in most years. Washington provides approximately 70% of the potential in most years. Over the 2014–2033 period, the achievable potential forecast offsets 39% of the overall growth in the residential and C&I combined baseline projections. Economic potential, which reflects the savings when all cost-effective measures are taken, is 480,967 MWh or 54.9 aMW for2014-2015. By 2033, economic potential reaches 304.5 aMW. Technical potential, which reflects the adoption of all conservation measures regardless of cost-effectiveness, is a theoretical upper bound on savings. For 2014–2015, technical potential savings are 1, 372,283 MWh or 156.7 aMW. By 2033, technical potential reaches 497.2 aMW. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 852 of 1125 Conservation Potential 4-4 www.enernoc.com Error! Not a valid bookmark self-reference. presents the three levels of potential for Residential and C&I graphically. Figure 4-2 Summary of Cumulative Energy Savings, Residential and C&I Note: Excludes pumping and rate class 25P. Residential Sector Table 4-3 presents estimates for the three types of potential for the residential sector. Table 4-3 Conservation Potential for the Residential Sector 2014 2015 2018 2023 2028 2033 Cumulative Savings (MWh) Achievable Potential 21,848 42,786 147,588 251,961 392,098 547,119 Economic Potential 231,078 335,111 744,684 1,041,719 1,390,377 1,549,252 Technical Potential 963,411 1,037,905 1,338,457 1,473,324 1,727,383 1,911,746 Energy Savings (aMW) Achievable Potential 2.5 4.9 16.8 28.8 44.8 62.5 Economic Potential 26.4 38.3 85.0 118.9 158.7 176.9 Technical Potential 110.0 118.5 152.8 168.2 197.2 218.2 We note the following: Achievable potential for the 2014-2015 biennium is 42,786 MWh, or approximately 4.9 aMW. By 2033, the cumulative achievable projection savings are 62.5 aMW. Economic potential, which reflects the savings when all cost-effective measures are taken, is 335,111 MWh for 2014-2015. By 2033, economic potential reaches 176.9 aMW. 0 100 200 300 400 500 600 2014 2015 2018 2023 2028 2033 En e r g y S a v i n g s ( a M W ) Achievable Potential Economic Potential Technical Potential Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 853 of 1125 Conservation Potential EnerNOC Utility Solutions Consulting 4-5 Technical potential in the residential sector is substantial, because measures such as LED lamps, heat pump water heaters, and solar water heating could cut energy use dramatically. The 2014–2015 technical potential is 1,037,905 MWh. By 2033, technical potential reaches 218.2 aMW. The relatively wide gap between technical and economic potential reflects the fact that Avista’s long-running residential conservation programs have already achieved much of the conservation that is cost-effective. In addition, avoided costs are lower than in the past CPA. As a result, additional conservation measures are becoming relatively more costly, and many do not pass the cost-effectiveness screen based on Avista’s current avoided costs. Figure 4-3 depicts the potential energy savings estimates graphically. Figure 4-3 Residential Cumulative Savings by Potential Case 0 50 100 150 200 250 2014 2015 2018 2023 2028 2033 En e r g y S a v i n g s ( a M W ) Achievable Potential Economic Potential Technical Potential Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 854 of 1125 Conservation Potential 4-6 www.enernoc.com Residential Potential by End Use, Technology, and Measure Type Table 4-4 provides estimates of savings for each end use and type of potential. Table 4-4 Residential Cumulative Savings by End Use and Potential Type (MWh) End Use Potential Case 2014 2015 2018 2023 2028 2033 Cooling Achievable 620 1,206 3,955 8,711 13,826 16,615 Economic 1,968 2,742 8,812 14,724 19,958 23,154 Technical 80,951 84,487 96,347 115,936 138,315 155,998 Space Heating Achievable 3,984 8,769 29,422 72,188 126,808 178,884 Economic 33,250 59,904 165,564 317,802 479,738 572,297 Technical 426,183 437,898 485,931 568,938 690,804 784,960 Water Heating Achievable 3,409 9,111 35,322 88,903 146,861 201,703 Economic 139,048 174,837 285,037 498,268 694,979 750,037 Technical 205,283 224,051 279,694 387,782 492,126 528,826 Interior Lighting Achievable 9,112 15,439 56,325 50,856 61,722 77,434 Economic 36,447 61,757 193,632 121,765 101,412 89,845 Technical 69,443 97,468 237,734 172,522 159,744 176,303 Exterior Lighting Achievable 3,121 5,340 14,121 7,568 1,767 4,771 Economic 12,486 21,361 56,554 18,869 4,680 5,178 Technical 29,639 37,425 63,855 27,506 18,316 19,975 Appliances Achievable 1,210 1,979 4,746 11,476 15,137 22,253 Economic 2,171 3,494 7,934 23,758 26,088 31,776 Technical 110,903 106,754 97,381 96,098 99,364 99,247 Electronics Achievable 269 635 2,466 8,038 16,469 27,134 Economic 4,242 8,047 19,593 31,158 39,062 44,050 Technical 38,001 44,875 66,641 83,650 96,504 106,895 Misc. Achievable 122 307 1,232 4,220 9,509 18,325 Economic 1,465 2,969 7,558 15,375 24,460 32,915 Technical 3,009 4,947 10,872 20,892 32,212 39,542 5Total Achievable 21,848 42,786 147,588 251,961 392,098 547,119 Economic 231,078 335,111 744,684 1,041,719 1,390,377 1,549,252 Technical 963,411 1,037,905 1,338,457 1,473,324 1,727,383 1,911,746 Focusing first on technical and economic potential, there are significant savings that are both possible and economic in numerous end uses: Space heating offers the highest technical potential, which would be achieved if all electric furnaces were replaced with SEER 16 air-source heat pumps (either when furnaces fail or by installing a heat pump in lieu of a furnace during new construction) and all electric resistance heat was converted to ductless mini-split systems. Note that conversion to gas is not included in the technical potential because it does not result in the least energy use at the site level.7 On the other hand, conversion to gas furnaces is cost-effective and is thus included in the economic potential. In addition, replacing electric resistance heat with 7 Based on multiplying site-level electricity use in kWh by 3.412 to convert to equivalent kBTU for comparison with natural gas use. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 855 of 1125 Conservation Potential EnerNOC Utility Solutions Consulting 4-7 ductless heat pumps, selected shell measures, and thermostats also contribute to economic potential. By 2018, space heating is the third highest contributor to economic potential. Water heating offers the second-highest technical potential savings in 2014, which reflects the across-the-board installation of heat pump water heaters and solar water heating. Although solar water heating does not pass the TRC B/C screening, HPWH are found to be cost-effective for water heaters in single family homes.8 As with furnaces, conversion to gas is not included in technical potential, but does feature in economic potential. Consequently, economic potential actually grows more rapidly than technical potential. By 2018, water heating is projected to be the largest contributor to economic potential. Appliances offer the third-highest technical potential in the near term. This reflects both the replacement of failed white-goods appliances with the highest-efficiency option and removal of second refrigerators in appliance recycling programs. However, once the new appliance standards take effect in 2015, relative savings in this category diminish and therefore many technologies no longer pass the economic screen, yielding economic potential that is relatively small. Interior and Exterior Lighting combine to provide the fourth largest source of technical potential. Initially, economic potential is substantial as well, due to CFLs and high-efficiency linear fluorescent options. By 2018, LEDs have become the cost-effective option in many segments, and thus economic potential grows substantially, making lighting the second highest source of economic potential, behind only water heating. Cooling also offer substantial technical potential savings opportunities which would be achieved if all air conditioning systems were converted to the highest efficiency units. However, standards again diminish savings relative to the base case and lower cost- effectiveness such that cooling measures are eliminated from economic potential. Electronics provides substantial technical potential as well, but most alternatives for higher efficiency are not cost effective, largely because the baseline case already incorporates relatively high efficiency equipment, as a result of successful market transformation efforts to date. Figure 4-4 presents the residential cumulative achievable potential in 2018. This reflects the application of market acceptance rate factor to economic potential, to model how factors including market barriers, customer acceptance, and program maturity affect how quickly measures are implemented. As discussed in Chapter 2, market acceptance rates were developed based on the Sixth Plan ramp rates with adjustments to match Avista program history. We note the following: Lighting, primarily the conversion of both interior and exterior lamps to compact fluorescent lamps in the first few years, followed by LEDs starting in 2017, represents 70,446 MWh or 47% of savings. Utility programs and other market transformation programs have made customers accepting of new lighting technologies, and thus these technologies are relatively well accepted by consumers. Water heating is the next highest source of achievable potential. As discussed above, water heating provides the largest economic potential, but the market for heat pump water heaters remains immature, and thus the uptake of this technology is limited in the near term. Although conversion to gas water heating is a mature technology and readily accepted, customers may be unable to convert at the time of replacement due to timing issues or other considerations. Space heating provides 20% of achievable potential mainly due to electric furnaces being converted to gas units, and resistance heating being displaced by ductless heat pumps. 8 HPWH become the baseline technology for water heaters ≥55 gallons beginning in 2016 due to a standards change, and thus the larger water heaters do not contribute to potential after 2016. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 856 of 1125 Conservation Potential 4-8 www.enernoc.com Figure 4-4 Residential Cumulative Achievable Potential by End Use in 2018 As described in Chapter 2, using our LoadMAP model, we develop separate estimates of potential for equipment and non-equipment measures. Table 4-5 presents results for equipment achievable potential at the technology level and Table 4-6 presents non-equipment measures for those measures that passed the cost-effectiveness screening. Initially, the majority of the savings come from the equipment measures, with lighting leading the way. Water heating, space heating, appliances and electronics, mainly televisions, provide savings as well. Over time, non- equipment measures, which are phased into the market more slowly but produce long-lasting savings (e.g., controls, water-saving fixtures, shell measures), produce a greater share of savings. In the non-equipment category, tank blanket installation, pipe insulation and thermostat setbacks for water heaters provide the greatest savings. Cooling 3% Space Heating 20% Water Heating 24% Interior Lighting 38% Exterior Lighting 9% Appliances 3% Electronics 6% Miscellaneous 1% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 857 of 1125 Conservation Potential EnerNOC Utility Solutions Consulting 4-9 Table 4-5 Residential Cumulative Achievable Potential for Equipment Measures (MWh) End Use Technology 2014 2015 2018 2023 2028 2033 Cooling Central AC 500 1,014 2,687 5,462 8,714 10,055 Room AC - - - - - - Air Source Heat Pump 93 94 95 96 97 205 Geothermal Heat Pump - - - - - - Space Heating Electric Resistance 348 837 3,738 13,323 31,336 52,036 Electric Furnace 3,159 6,839 17,175 33,802 56,037 75,385 Air Source Heat Pump 256 257 261 264 267 3,561 Geothermal Heat Pump - - - - - - Water Heating Water Heater <= 55 Gal 1,604 3,654 11,129 38,369 82,577 136,249 Water Heater > 55 Gal 119 166 331 810 1,387 1,944 Interior Lighting Screw-in 6,268 9,722 39,805 18,279 7,524 15 Linear Fluorescent 5 10 36 8 - 21 Specialty 2,838 5,707 16,484 32,296 53,577 76,495 Exterior Lighting Screw-in 3,121 5,340 14,121 7,568 1,767 4,771 Appliances Clothes Washer 548 546 542 533 53 12 Clothes Dryer - - - - - - Dishwasher - - - 80 288 601 Refrigerator 383 775 2,187 4,655 5,854 9,371 Freezer 34 172 789 1,527 2,647 4,219 Second Refrigerator 131 259 668 1,413 1,851 3,151 Stove 114 227 560 1,296 2,109 2,470 Microwave - - - - - - Electronics Personal Computers 106 260 1,111 3,079 5,678 9,692 TVs 74 187 745 2,543 5,118 7,419 Set-top boxes/DVR 89 188 610 2,417 5,673 10,023 Devices and Gadgets - - - - - - Miscellaneous Pool Pump 6 15 62 241 968 2,961 Furnace Fan 116 291 1,170 3,979 8,541 15,364 Miscellaneous - - - - - - Grand Total 19,915 36,560 114,306 172,041 282,064 426,022 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 858 of 1125 Conservation Potential 4-10 www.enernoc.com Table 4-6 Residential Cumulative Achievable Savings for Non-equipment Measures (MWh), continued Measure 2014 2015 2018 2023 2028 2033 Insulation - Ceiling - - 53 174 308 606 Insulation - Foundation - - 791 2,225 4,753 7,090 Insulation - Infiltration Control - - 1,692 9,543 16,408 20,226 Insulation - Wall Cavity 5 18 101 399 1,025 2,887 Refrigerator - Remove Second Unit - - - 1,973 2,335 2,429 Thermostat - Clock/Programmable 243 917 6,783 14,483 18,457 18,619 Water Heater - Faucet Aerators 238 807 3,244 6,411 7,897 7,706 Water Heater - Pipe Insulation 335 1,129 4,790 9,307 11,296 10,828 Water Heater - Low Flow Showerheads 203 606 5,885 14,759 17,448 17,087 Water Heater - Tank Blanket/Insulation 575 1,909 7,317 13,150 14,736 12,937 Water Heater - Thermostat Setback 334 841 2,626 6,097 11,519 14,951 Advanced New Construction Designs - - - - 1,079 1,801 Behavioral Measures - - - 1,400 2,773 3,930 Total 1,933 6,226 33,281 79,920 110,034 121,098 Residential Potential by Market Segment Single-family homes were slightly more than half of Avista’s residential customers and represented 66% of the sector’s energy use in 2009. Furthermore, potential savings are generally higher in single family homes, which have larger saturations of equipment beyond the basics of space heating, water heating, and appliances. Thus, single-family homes account for the largest share of potential savings by segment, representing approximately 73% of achievable potential across the study period as indicated in Table 4-6. Table 4-7 shows the three potential cases by housing type in 2018. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 859 of 1125 Conservation Potential EnerNOC Utility Solutions Consulting 4-11 Table 4-6 Residential Cumulative Achievable Potential by Market Segment 2014 2015 2018 2023 2028 2033 Achievable Savings (MWh) Single Family 15,922 30,820 102,461 174,454 268,519 370,353 Multi Family 765 1,551 6,307 11,114 17,841 26,271 Mobile Home 619 1,259 4,131 6,589 10,014 13,837 Low Income 4,541 9,156 34,688 59,803 95,724 136,659 Total 21,848 42,786 147,588 251,961 392,098 547,119 Achievable - % of Savings Single Family 73% 72% 69% 69% 68% 68% Multi Family 4% 4% 4% 4% 5% 5% Mobile Home 3% 3% 3% 3% 3% 3% Low Income 21% 21% 24% 24% 24% 25% Total 100% 100% 100% 100% 100% 100% Table 4-7 Residential Cumulative Achievable Potential by End Use and Market Segment, 2018 (MWh) Single Family Multi Family Mobile Home Low Income Energy Savings (MWh) Achievable Potential 102,461 6,307 4,131 34,688 Economic Potential 464,782 37,980 31,907 210,015 Technical Potential 1,434,368 173,515 131,221 909,267 Energy Savings (aMW) Achievable Potential 4% 3% 3% 4% Economic Potential 20% 20% 26% 24% Technical Potential 61% 90% 106% 105% Table 4-8 shows the savings by end use and market segment in 2018. Across all housing types, as discussed previous, lighting is the single largest opportunity, followed by water heating, and space heating. In mobile homes and low income, however, the potential for space heating is higher than for water heating, due to the higher saturation of electric heat, as well as less efficient building shells. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 860 of 1125 Conservation Potential 4-12 www.enernoc.com Table 4-8 Residential Cumulative Achievable Potential by End Use and Market Segment, 2018 (MWh) End Use Single Family Multi Family Mobile Home Low Income All Homes Cooling 3,029 31 57 838 3,955 Space Heating 17,689 982 1,117 9,634 29,422 Water Heating 25,266 1,761 490 7,805 35,322 Interior Lighting 39,315 3,053 1,728 12,228 56,325 Exterior Lighting 11,190 87 488 2,355 14,121 Appliances 3,276 228 131 1,112 4,746 Electronics 1,698 142 75 550 2,466 Miscellaneous 998 23 45 167 1,232 Total 102,461 6,307 4,131 34,688 147,588 C&I Sector Potential The baseline projection for the commercial sector grows steadily during the projection period as the region emerges from the economic downturn. As a result, opportunities for energy-efficiency savings are significant for the C&I sector. Achievable potential for the 2014-2015 biennium is 57,354 MWh, or approximately 6.5 aMW. By 2033, the cumulative achievable projection savings are 91.9 aMW. Potential for rate class 25P was separately assessed, outside the LoadMAP model, at approximately 1 MWh annually. Economic potential is 141,191 MWh for 2014-2015. By 2033, economic potential reaches 125.9 aMW. Technical potential for 2014–2015 potential is 329,713 MWh. By 2033, technical potential reaches 277.2 aMW. Table 4-9 and Note: Excludes rate class 25P. Figure 4-5 present the savings associated with each level of potential. Table 4-9 Cumulative Conservation Potential for the C&I Sector 2014 2015 2018 2023 2028 2033 Cumulative Savings (MWh) Achievable Potential 28,789 57,354 176,964 381,630 584,687 805,172 Economic Potential 83,624 141,191 334,386 613,258 868,483 1,102,916 Technical Potential 197,941 329,713 900,694 1,699,836 2,157,078 2,428,207 Cumulative Savings (aMW) Achievable Potential 3.3 6.5 20.2 43.6 66.7 91.9 Economic Potential 9.5 16.1 38.2 70.0 165.7 125.9 Technical Potential 22.6 37.6 102.8 194.0 246.2 277.2 Note: Excludes rate class 25P. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 861 of 1125 Conservation Potential EnerNOC Utility Solutions Consulting 4-13 Figure 4-5 C&I Cumulative Savings by Potential Case Note: Excludes rate class 25P. 0 50 100 150 200 250 300 2014 2015 2018 2023 2028 2033 En e r g y S a v i n g s ( a M W ) Achievable Potential Economic Potential Technical Potential Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 862 of 1125 Conservation Potential 4-14 www.enernoc.com C&I Potential by End Use, Technology, and Measure Type Table 4-10 presents the commercial and industrial sector savings by end use and potential type. Table 4-10 C&I Cumulative Potential by End Use and Potential Type (MWh) End Use Potential 2014 2015 2018 2023 2028 2033 Cooling Achievable Potential 868 1,376 4,173 16,795 34,853 49,278 Economic Potential 1,691 2,488 7,079 27,350 53,462 72,875 Technical Potential 19,454 29,736 97,875 196,371 253,620 294,929 Space Heating Achievable Potential 519 715 1,803 6,917 15,359 23,827 Economic Potential 1,288 1,733 4,283 14,806 29,018 41,719 Technical Potential 11,159 16,184 44,222 108,389 148,257 173,675 Ventilation Achievable Potential 963 2,239 10,061 31,438 55,099 77,805 Economic Potential 1,133 2,739 12,553 38,972 66,375 92,514 Technical Potential 12,706 22,200 83,691 184,710 226,874 241,650 Water Heating Achievable Potential 1,597 3,270 10,777 32,637 78,331 126,429 Economic Potential 11,899 22,573 57,844 122,614 211,538 238,809 Technical Potential 15,102 29,004 80,484 159,912 266,475 297,971 Interior Lighting Achievable Potential 17,099 34,790 99,910 159,448 196,299 274,184 Economic Potential 44,373 71,064 145,394 208,161 247,368 342,873 Technical Potential 77,989 127,519 332,806 565,237 668,438 745,387 Exterior Lighting Achievable Potential 1,891 3,353 12,231 33,437 48,284 52,775 Economic Potential 7,402 11,324 33,083 53,407 58,412 60,364 Technical Potential 12,582 17,733 42,800 75,475 84,874 93,215 Food Preparation Achievable Potential 1,658 3,354 9,246 20,001 28,341 35,406 Economic Potential 2,127 4,265 11,312 24,224 34,077 42,363 Technical Potential 3,928 7,015 17,911 40,248 58,963 73,609 Refrigeration Achievable Potential 93 343 1,833 4,922 12,431 28,158 Economic Potential 186 603 2,490 6,123 14,718 33,143 Technical Potential 3,663 7,396 19,377 40,458 56,695 65,200 Office Equipment Achievable Potential 3,000 5,894 19,718 46,832 67,723 76,351 Economic Potential 11,327 20,590 48,337 73,793 83,277 91,979 Technical Potential 29,051 51,981 104,158 128,436 143,820 158,781 Machine Drive Achievable Potential 4 8 40 165 300 439 Economic Potential 8 15 73 295 512 713 Technical Potential 188 695 2,625 6,418 10,018 11,764 Process Achievable Potential 426 766 3,337 13,761 26,438 35,254 Economic Potential 862 1,501 6,179 23,952 43,702 54,818 Technical Potential 10,272 17,192 66,674 169,003 205,886 233,266 Miscellaneous Achievable Potential 670 1,248 3,835 15,277 21,229 25,265 Economic Potential 1,329 2,295 5,758 19,561 26,024 30,744 Technical Potential 1,848 3,057 8,070 25,178 33,157 38,761 Total Achievable Potential 28,789 57,354 176,964 381,630 584,687 805,172 Economic Potential 83,624 141,191 334,386 613,258 868,483 1,102,916 Technical Potential 197,941 329,713 900,694 1,699,836 2,157,078 2,428,207 Note: Excludes rate class 25P. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 863 of 1125 Conservation Potential EnerNOC Utility Solutions Consulting 4-15 The end uses with the highest technical and economic potential are: Interior lighting, as a result of LED lighting that is now commercially available, has the highest technical potential at 332,806 MWh in 2018. LEDs are found to be cost-effective in all applications beginning in either 2014 or 2015, as a result of longer hours of operation in commercial buildings. In addition, super T8s for linear fluorescent systems, T5s for high-bay fixtures, and control systems also contribute to lighting economic potential. Therefore, economic potential is highest for lighting as well, at 145,394 MWh in 2018, which is roughly 44% of the lighting technical potential and 43% of total economic potential in 2018. HVAC end uses collectively comprise 25% of technical potential or 225,778 MWh. However, relatively few measures pass the economic screen, so that economic potential is only 23,915 MWh, or about one tenth of the technical potential. Office equipment has significant technical potential of 101,158 MWh in 2018, and economic potential of 48,337 MWh Water heating technical potential comes next, with 80,484 MWh, and because measures such as HPWH and water saving devices are cost-effective, economic potential is 57,844 MWh. Table 4-11 and Table 4-12 present achievable potential savings for equipment measures and non-equipment measures, respectively. Table 4-12 presents only measures that passed the cost- effectiveness test. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 864 of 1125 Conservation Potential 4-16 www.enernoc.com Table 4-11 C&I Cumulative Achievable Savings for Equipment Measures (MWh) End Use Technology 2014 2015 2018 2023 2028 2033 Cooling Central Chiller 350 670 2,231 6,803 12,639 17,307 RTU - - - - - - Heat Pump - - - - - - Space Heating Heat Pump - - - - - - Electric Resistance - - - - - - Furnace - - - - - - Ventilation Ventilation 963 2,072 8,768 26,596 49,646 72,087 Water Heating Water Heater 1,311 2,844 9,464 26,736 64,973 107,400 Interior Lighting Linear Fluorescent 93 141 5,268 29,001 44,645 68,240 Interior Screw-in 10,160 19,861 42,656 29,637 12,498 42,051 High Bay Fixtures 6,482 14,295 48,666 77,212 85,244 94,133 Exterior Lighting HID 1,140 2,519 8,105 27,952 41,884 47,529 Exterior Screw-in 678 708 3,507 2,823 2,075 - Refrigeration Reach-in Refrigerator 409 839 2,364 5,026 7,600 10,224 Glass Door Display 462 946 2,614 5,502 8,266 10,964 Open Display Case - - - - - - Icemaker 291 589 1,595 3,648 4,865 5,399 Vending Machine 452 921 2,520 5,382 6,822 7,744 Walk in Refrigerator - - - - - - Food Preparation Oven - 137 944 2,673 8,844 23,982 Fryer 93 207 670 1,532 2,303 2,660 Dishwasher - - - - - - Hot Food Container - - 220 717 1,284 1,516 Other Food Prep - - - - - - Office Equipment Desktop Computers 1,381 2,607 6,968 13,526 20,092 22,514 Server 1,095 2,340 7,192 16,419 23,871 26,404 Monitor 121 229 1,979 4,709 6,994 7,837 Printer/copier/fax - - 395 3,452 5,311 6,242 POS Terminal - - 381 956 1,425 1,613 Laptop Computer 96 182 487 945 1,403 1,573 Miscellaneous Non-HVAC Motor Other Miscellaneous - - - - - - Process Process Cooling/Refrigeration 301 574 1,810 8,290 11,076 12,927 Process Heating - - - - - - Electrochemical Process 293 558 1,614 5,791 8,190 9,645 Machine Drive Less than 5 HP 3 27 122 241 640 851 5-24 HP 7 14 41 160 212 247 25-99 HP 19 36 104 405 537 623 100-249 HP 11 20 59 230 305 353 250-499 HP 3 6 32 287 343 392 500 and more HP 6 12 60 543 649 742 Grand Total 26,202 53,316 160,683 306,133 433,342 601,609 Note: Excludes rate class 25P. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 865 of 1125 Conservation Potential EnerNOC Utility Solutions Consulting 4-17 Table 4-12 C&I Cumulative Achievable Savings for Non-equipment Measures (MWh) Measure 2014 2015 2018 2023 2028 2033 Energy Management System 1,142 1,525 3,673 15,912 39,422 63,759 Exterior Lighting - Daylighting Controls 0 0 5 58 271 482 Interior Lighting - Occupancy Sensors 0 0 9 58 113 160 Thermostat - Clock/Programmable 213 296 754 2,471 4,822 6,948 Heat Pump - Maintenance 41 69 277 918 1,387 1,634 Water Heater - Faucet Aerators/Low Flow Nozzles - - - - - 411 Water Heater - High Efficiency Circulation Pump 285 425 1,313 5,900 13,358 18,617 Retrocommissioning - Lighting - - 1,689 17,461 38,207 43,900 Air-Cooled Chiller - Cond. Water Temperature Reset 0 0 87 761 1,218 1,689 Chiller - Chilled Water Reset - - - - 17 63 Chiller - Chilled Water Variable-Flow System 0 0 3 16 40 64 Chiller - High Efficiency Cooling Tower Fans 0 0 6 37 69 103 Cooling - Economizer Installation - - 168 1,916 4,085 4,999 Fans - Energy Efficient Motors - 161 720 2,249 2,533 2,293 Interior Lighting - Time Clocks and Timers - - - 21 92 140 Refrigeration - Strip Curtain 43 59 149 415 710 920 LED Exit Lighting 4 20 483 599 771 748 Refrigeration - High Efficiency Case Lighting - 1 5 29 78 153 Exterior Lighting - Cold Cathode Lighting 72 125 507 1,442 1,703 1,989 Laundry - High Efficiency Clothes Washer 4 7 35 115 157 192 Interior Lighting - Skylights - - 7 108 279 469 Office Equipment - Smart Power Strips 305 536 2,316 6,826 8,626 10,168 Ventilation - Demand Control Ventilation 0 5 571 2,576 2,875 3,349 Strategic Energy Management 5 7 62 434 1,163 1,968 Refrigeration - System Controls 28 38 85 192 297 350 Refrigeration - System Maintenance 28 44 169 482 665 829 Refrigeration - System Optimization 17 29 116 252 285 298 Motors - Variable Frequency Drive 6 13 197 1,167 2,159 3,207 Motors - Magnetic Adjustable Speed Drives 222 380 1,489 3,821 4,690 5,921 Compressed Air - System Optimization and Improvements 7 14 196 2,992 9,116 11,744 Compressed Air - Compressor Replacement 100 172 655 2,485 5,571 8,169 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 866 of 1125 Conservation Potential 4-18 www.enernoc.com Measure 2014 2015 2018 2023 2028 2033 Fan System - Controls 3 6 27 89 126 160 Fan System - Optimization 17 29 113 291 350 382 Fan System - Maintenance 0 0 1 8 14 20 Pumping System - Controls 21 37 228 975 1,610 2,275 Pumping System - Maintenance 0 1 13 67 117 169 Total 2,566 4,001 16,130 74,436 150,049 202,076 Note: Excludes rate class 25P. As shown in Figure 4-6, the primary sources of C&I sector achievable savings in 2018 are as follows: Interior and exterior lighting, comprising lamps, fixtures, and controls, account for 64% of C&I sector achievable potential. Not only is economic potential high for lighting measures, but they are more readily accepted and implemented in the market than many other, higher cost and more complex measures. Office Equipment, which is the second largest portion of this sector’s achievable potential (11%) Water heating and Ventilation each provides 6% of the total savings Figure 4-6 C&I Cumulative Achievable Potential Cumulative Savings by End Use in 2018 (percentage of total) Note: Excludes rate class 25P. Cooling 2% Space Heating 1%Ventilation 6% Water Heating 6% Food Preparation 1% Refrigeration 5% Interior Lighting 57% Exterior Lighting 7% Office Equipment 11% Machine Drive 2% Process 2% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 867 of 1125 Conservation Potential EnerNOC Utility Solutions Consulting 4-19 C&I Potential by Market Segment Table 4-13 shows potential estimates by segment in 2018. The large commercial segment has the largest achievable conservation potential of 201,247 MWh, roughly 58% of the overall commercial achievable potential. The small/medium segment follows with a large gap at 64,655 MWh. Table 4-13 C&I Cumulative Potential by Market Segment, 2018 Energy Savings (MWh) Achievable Potential Economic Potential Technical Potential Small/Med. Commercial 34,044 64,655 174,575 Large Commercial 101,745 201,247 529,133 Extra Large Commercial 16,950 31,634 79,582 Extra Large Industrial 24,224 36,850 117,403 Total 176,964 334,386 900,694 Note: Excludes rate class 25P. Figure 4-7 presents the achievable potential in 2018 by end use and building type. Lighting measures are key measure across all buildings. Table 4-14 C&I Cumulative Achievable Savings in 2018 by End Use and Rate Class(MWh) End Use Small/Medium Commercial Large Commercial Extra Large Commercial Extra Large Industrial Total Cooling 835 1,305 665 1,368 4,173 Space Heating 717 163 296 627 1,803 Ventilation 1,740 1,124 1,165 6,031 10,061 Water Heating 1,990 7,772 1,016 - 10,777 Interior Lighting 20,429 61,213 9,566 8,702 99,910 Exterior Lighting 2,967 7,669 1,276 318 12,231 Refrigeration 2,211 6,457 578 - 9,246 Food Preparation 220 639 975 - 1,833 Office Equipment 2,928 15,379 1,411 - 19,718 Miscellaneous 8 24 2 5 40 Process - - - 3,835 3,835 Machine Drive - - - 3,337 3,337 Total 34,044 101,745 16,950 24,224 176,964 Note: Excludes rate class 25P. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 868 of 1125 Conservation Potential 4-20 www.enernoc.com Figure 4-7 C&I Cumulative Achievable Savings in 2018 by End Use and Building Type Note: Excludes rate class 25P. Sensitivity of Potential to Avoided Cost Similar to the 2011 CPA, EnerNOC modeled several scenarios with varying levels of avoided costs in addition to the reference case. For this study’s purposes, we have included a case where the 10% adder per NW Power and Conservation Act is removed. The other scenarios included 150%, 125%, and 75% of the avoided costs used in the reference case. Figure 4-8 and Table 4-15 show how achievable potential varies under the four scenarios. The reference case achievable potential reaches approximately at 1,352,291 MWh by 2033. Removing the 10% adder from the avoided costs decreased this achievable potential to 1,272,206 MWh, 6% reduction. With the 150% avoided cost case, achievable potential increased to 1,657,741 MWh while the 125% avoided cost case and the 75% avoided cost case yielded achievable potential equal to 1,521,856 and 1,146,105 MWh respectively. While the changes are significant, the relationship between avoided cost and achievable potential is not linear and increases in avoided costs do not provide equivalent percentage increases in achievable potential. Technical potential imposes a limit on the amount of additional conservation and each incremental unit of DSM becomes increasingly expensive. 0 20,000 40,000 60,000 80,000 100,000 120,000 Small/Medium Commercial Large Commercial Extra Large Commercial Extra Large Industrial Ac h i e v a b l e P o t e n t i a l S a v i n g s ( M W h ) Cooling Space Heating Ventilation Water Heating Interior Lighting Exterior Lighting Refrigeration Food Preparation Office Equipment Miscellaneous Machine Drive Process Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 869 of 1125 Conservation Potential EnerNOC Utility Solutions Consulting 4-21 Figure 4-8 Energy Savings, Cumulative Achievable Potential by Avoided Costs Scenario (MWh) Note: Excludes pumping and rate class 25P. Table 4-15 Achievable Potential with Varying Avoided Costs End Use Reference Scenario Remove 10% adder 75% of avoided costs 125% of avoided costs 150% of avoided costs Achievable potential savings 2033 (MWh) 1,352,291 1,272,206 1,146,105 1,521,856 1,657,741 Percentage change in savings vs. 100% avoided cost Scenario -6% -15% 13% 23% Note: Excludes pumping and rate class 25P. Electricity to Natural Gas Fuel Switching While fuel efficiency is not considered in the NPCC Sixth Plan, Avista has a history of fuel switching from electricity to natural gas and continues to target direct use as the most efficient resource option when available. The conservation potential modeled above includes savings potential attributable to conversion of electric space and water heating to natural gas. Table 4-16 displays savings potential from converting electric furnaces and water heaters to natural gas. Within LoadMAP, we modeled savings for these measures in the residential sector only, but because we calibrated the level of expected conversions to Avista’s recent program history that includes small commercial building conversions as well, this potential may reflect a small percentage of commercial section conversions. Because conversions remove most of the electricity use from two of the largest residential end uses (water and space heating), it accounts for 8.3% of combined residential, commercial and industrial savings by 2033. For water heating, about one-fifth of the savings from gas conversions occurs in new construction. For furnaces, new construction accounts for roughly 27% of the total. - 200,000 400,000 600,000 800,000 1,000,000 1,200,000 1,400,000 1,600,000 1,800,000 2,000,000 Cu m u l a t i v e S a v i n g s ( M W h ) 100% of reference case avoided costs 150% of avoided costs 125% of avoided costs Reference case without 10% adder 75% of avoided costs Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 870 of 1125 Conservation Potential 4-22 www.enernoc.com Table 4-16 Cumulative Achievable Potential from Conversion to Natural Gas (MWh) 2014 2015 2018 2023 2028 2033 Washington Cumulative Savings (MWh) Furnace Conversions 2,322 5,047 12,715 25,105 41,493 55,787 Water Heating Conversions 825 1,586 4,112 9,924 14,362 20,221 Total Conversions 3,148 6,633 16,827 35,028 55,855 76,009 Idaho Cumulative Savings (MWh) Furnace Conversions 837 1,792 4,460 8,698 14,544 19,598 Water Heating Conversions 47 121 602 4,264 10,085 16,451 Total Conversions 884 1,913 5,062 12,961 24,629 36,049 Total Washington and Idaho Cumulative Savings (MWh) Furnace Conversions 3,159 6,839 17,175 33,802 56,037 75,385 Water Heating Conversions 873 1,707 4,714 14,187 24,447 36,673 Total Conversions 4,032 8,546 21,889 47,990 80,484 112,058 Supply Curves The project also developed supply curves for each year to support the IRP process. At Avista’s request, the supply curves did not consider economic screening based on Avista’s avoided costs. Instead, all measures were included and the amount of savings from each measure in each year was limited by the ramp rates used for achievable potential. The supply curves do not include the savings from electricity to natural gas fuel switching, discussed above. A sample supply curve for one year is shown in Figure 4-9. This supply curve is created by stacking measures and equipment over the 20-year planning horizon in ascending order of cost. As expected, this stacking of conservation resources produces a traditional upward-sloping supply curve. Because there is a gap in the cost of the energy efficiency measures as you move up the supply curve, the measures with a very high cost cause a rapid sloping of the supply curve. The supply curve also shows that substantial savings are available at low- or no-cost. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 871 of 1125 Conservation Potential EnerNOC Utility Solutions Consulting 4-23 Figure 4-9 Supply Curves for Evaluated EE Measures and Avoided Cost Scenarios Note: Excludes pumping and rate class 25P. Pumping Potential Table 4-18 displays the 2009 electricity sales and peak demand of Avista’s pumping customers. These customers include mostly municipal water systems and some irrigation customers. The pumping accounts represent 2.4% of total electricity sales and 0.8% of peak demand (see Table 3-1 and Table 3-2). Because pumping represents a relatively small percentage of Avista’s total sales, the project team decided to estimate achievable potential for pumping based on the Sixth Plan calculator agriculture sector, option 3.9 Table 4-17 Pumping Rate Classes, Electricity Sales and Peak Demand 2009 Sector Rate Schedule (s) Number of meters (customers) 2009 Electricity Sales (MWh) Peak demand (MW) Pumping, Washington 031, 032 2,361 135,999 10 Pumping, Idaho 031, 032 1,312 58,885 4 Pumping, Total 3,673 194,884 14 Percentage of System Total 2.4% 0.8% The Sixth Plan Calculator estimates agricultural conservation targets based on 2007 sales. It provides annual conservation targets through 2019. Table 4-18 displays incremental annual savings potential for 2014–2019. 9 Available on the NWPCC website at http://www.nwcouncil.org/energy/powerplan/6/assessmentmethodology/. $- $0.10 $0.20 $0.30 $0.40 $0.50 $0.60 $0.70 $0.80 $0.90 $1.00 -100 200 300 400 500 600 700 800 Co s t o f Co n s e v e d En e r g y ( 2 0 0 9 $ / k W h ) Cumulative Savings 2020 (GWh) Cost/kWh Avoided Cost ($0.0489kWh) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 872 of 1125 Conservation Potential 4-24 www.enernoc.com Table 4-18 Sixth Plan Calculator Agriculture Incremental Annual Potential, 2014–2019 (MWh) Segment 2014 2015 2016 2017 2018 2019 Pumping, Washington 1,402 1,835 1,856 1,835 1,814 1,794 Pumping, Idaho 618 809 818 809 799 790 Pumping, Total 2,020 2,643 2,673 2,643 2,614 2,584 Washington Potential Excluding Conversions to Natural Gas Based on the modeling described above, Washington potential consistent with the NPCC Conservation Plan methodology is as shown in Table 4-19. Table 4-19 Washington Cumulative Potential Consistent with Conservation Plan Methodology 2014 2015 2018 2023 Cumulative Savings (MWh) Residential 15,091 29,603 100,792 172,576 Commercial and Industrial 19,927 40,930 123,755 256,653 Pumping 1,402 3,237 8,742 0 Conversions to Natural Gas (3,148) (6,633) (16,827) (35,028) Total 33,272 67,137 216,462 394,200 Cumulative Savings (aMW) Residential 1.72 3.38 11.51 19.70 Commercial and Industrial 2.27 4.67 14.13 29.30 Pumping 0.16 0.37 1.00 0.00 Conversions to Natural Gas (0.36) (0.76) (1.92) (4.00) Total 3.80 7.66 24.71 45.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 873 of 1125 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 874 of 1125 EnerNOC Utility Solutions Consulting 500 Ygnacio Valley Road, Suite 450 Walnut Creek, CA 94596 P: 925.482.2000 F: 925.284.3147 About EnerNOC EnerNOC’s Utility Solutions Consulting team is part of EnerNOC’s Utility Solutions, which provides a comprehensive suite of demand-side management (DSM) services to utilities and grid operators worldwide. Hundreds of utilities have leveraged our technology, our people, and our proven processes to make their energy efficiency (EE) and demand response (DR) initiatives a success. Utilities trust EnerNOC to work with them at every stage of the DSM program lifecycle – assessing market potential, designing effective programs, implementing those programs, and measuring program results. EnerNOC’s Utility Solutions deliver value to our utility clients through two separate practice areas – Implementation and Consulting. • Our Implementation team leverages EnerNOC’s deep ―behind-the-meter expertise‖ and world-class technology platform to help utilities create and manage DR and EE programs that deliver reliable and cost-effective energy savings. We focus exclusively on the commercial and industrial (C&I) customer segments, with a track record of successful partnerships that spans more than a decade. Through a focus on high quality, measurable savings, EnerNOC has successfully delivered hundreds of thousands of MWh of energy efficiency for our utility clients, and we have thousands of MW of demand response capacity under management. • The Consulting team provides expertise and analysis to support a broad range of utility DSM activities, including: potential assessments; end-use forecasts; integrated resource planning; EE, DR, and smart grid pilot and program design and administration; load research; technology assessments and demonstrations; evaluation, measurement and verification; and regulatory support. The team has decades of combined experience in the utility DSM industry. The staff is comprised of professional electrical, mechanical, chemical, civil, industrial, and environmental engineers as well as economists, business planners, project managers, market researchers, load research professionals, and statisticians. Utilities view EnerNOC’s experts as trusted advisors, and we work together collaboratively to make any DSM initiative a success. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 875 of 1125 Avista Electric Conservation Potential Assessment Study Appendices Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 876 of 1125 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 877 of 1125 EnerNOC Utility Solutions Consulting iii This report was prepared by EnerNOC Utility Solutions Consulting 500 Ygnacio Valley Blvd., Suite 450 Walnut Creek, CA 94596 Project Director: I. Rohmund Project Manager: J. Borstein Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 878 of 1125 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 879 of 1125 EnerNOC Utility Solutions Consulting v CONTENTS A MARKET PROFILES ............................................................................................... A-1 B RESIDENTIAL ENERGY EFFICIENCY EQUIPMENT AND MEASURE DATA .............. B-1 C C&I ENERGY EFFICIENCY EQUIPMENT AND MEASURE DATA .............................. C-1 D MARKET ADOPTION FACTORS .............................................................................. D-1 E ANNUAL SAVINGS ................................................................................................. E-1 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 880 of 1125 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 881 of 1125 EnerNOC Utility Solutions Consulting vii CONTENTS LIST OF TABLES Table A-1 Single Family Electric Market Profile, Washington 2009 .......................................... A-2 Table A-2 Multi Family Electric Market Profile, Washington 2009 ............................................ A-3 Table A-3 Mobile Home Electric Market Profile, Washington 2009 .......................................... A-4 Table A-4 Low Income Electric Market Profile, Washington 2009 ............................................ A-5 Table A-5 Single Family Electric Market Profile, Idaho 2009 ................................................... A-6 Table A-6 Multi Family Electric Market Profile, Idaho 2009 ..................................................... A-7 Table A-7 Mobile Home Electric Market Profile, Idaho 2009 ................................................... A-8 Table A-8 Low income Electric Market Profile, Idaho 2009 ..................................................... A-9 Table A-9 Small/Medium Commercial Electric Market Profile, Washington 2009 ...................... A-10 Table A-10 Large Commercial Electric Market Profile, Washington 2009 .................................. A-11 Table A-11 Extra Large Commercial Electric Market Profile, Washington 2009 .......................... A-12 Table A-12 Extra Large Industrial Electric Market Profile, Washington 2009 ............................. A-13 Table A-13 Small/Medium Commercial Electric Market Profile, Idaho 2009............................... A-14 Table A-14 Large Commercial Electric Market Profile, Idaho 2009 ........................................... A-15 Table A-15 Extra Large Commercial Electric Market Profile, Idaho 2009 .................................. A-16 Table A-16 Extra Large Industrial Electric Market Profile, Idaho 2009 ...................................... A-17 Table B-1 Residential Energy Efficiency Equipment Measure Descriptions ................................B-2 Table B-2 Residential Energy Efficiency Non-Equipment Measure Descriptions .........................B-6 Table B-3 Energy Efficiency Equipment Data, Electric—Single Family, Existing Vintage, Washington ........................................................................................................ B-10 Table B-4 Energy Efficiency Equipment Data, Electric—Single Family, New Vintage, WashingtonB-13 Table B-5 Energy Efficiency Equipment Data, Electric—Single Family, Existing Vintage, Idaho B-16 Table B-6 Energy Efficiency Equipment Data, Electric—Single Family, New Vintage, Idaho ..... B-19 Table B-7 Energy Efficiency Equipment Data, Electric—Multi Family, Existing Vintage, WashingtonB-22 Table B-8 Energy EfficiencyEquipment Data, Electric—Multi Family, New Vintage, Washington B-25 Table B-9 Energy Efficiency Equipment Data, Electric—Multi Family, Existing Vintage, Idaho .. B-28 Table B-10 Energy Efficiency Equipment Data, Electric—Multi Family, New Vintage, Idaho ....... B-31 Table B-11 Energy Efficiency Equipment Data, Electric—Mobile Home, Existing Vintage, Washington ........................................................................................................ B-34 Table B-12 Energy Efficiency Equipment Data, Electric—Mobile Home, New Vintage, WashingtonB-37 Table B-13 Energy Efficiency Equipment Data, Electric—Mobile Home, Existing Vintage, Idaho . B-40 Table B-14 Energy Efficiency Equipment Data, Electric—Mobile Home, New Vintage, Idaho ...... B-43 Table B-15 Energy Efficiency Equipment Data, Electric—Low income, Existing Vintage, WashingtonB-46 Table B-16 Energy Efficiency Equipment Data, Electric—Low Income, New Vintage, WashingtonB-49 Table B-17 Energy Efficiency Equipment Data, Electric—Low Income, Existing Vintage, Idaho .. B-52 Table B-18 Energy Efficiency Equipment Data, Electric—Low income, New Vintage, Idaho ....... B-55 Table B-19 Energy Efficiency Non-Equipment Data, Electric—Single Family, Existing Vintage, Washington ........................................................................................................ B-58 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 882 of 1125 viii www.enernoc.com Table B-20 Energy Efficiency Non-Equipment Data, Electric—Single Family, New Vintage, Washington ........................................................................................................ B-59 Table B-21 Energy Efficiency Non-Equipment Data, Electric—Single Family, Existing Vintage, IdahoB-60 Table B-22 Energy Efficiency Non-Equipment Data, Electric—Single Family, New Vintage, IdahoB-61 Table B-23 Energy Efficiency Non-Equipment Data, Electric—Multi Family, Existing Vintage, Washington ........................................................................................................ B-62 Table B-24 Energy Efficiency Non-Equipment Data, Electric—Multi Family, New Vintage, Washington ........................................................................................................ B-63 Table B-25 Energy Efficiency Non-Equipment Data, Electric—Multi Family, Existing Vintage, IdahoB-64 Table B-26 Energy Efficiency Non-Equipment Data, Electric—Multi Family, New Vintage, Idaho B-65 Table B-27 Energy Efficiency Non-Equipment Data, Electric—Mobile Home, Existing Vintage, Washington ........................................................................................................ B-66 Table B-28 Energy Efficiency Non-Equipment Data, Electric—Mobile Home, New Vintage, Washington ........................................................................................................ B-67 Table B-29 Energy Efficiency Non-Equipment Data, Electric—Mobile Home, Existing Vintage, IdahoB-68 Table B-30 Energy Efficiency Non-Equipment Data, Electric—Mobile Home, New Vintage, IdahoB-69 Table B-31 Energy Efficiency Non-Equipment Data, Electric—Low income, Existing Vintage, Washington ........................................................................................................ B-70 Table B-32 Energy Efficiency Non-Equipment Data, Electric—Low income, New Vintage, Washington ........................................................................................................ B-71 Table B-33 Energy Efficiency Non-Equipment Data, Electric—Low income, Existing Vintage, IdahoB-72 Table B-34 Energy Efficiency Non-Equipment Data, Electric—Low income, New Vintage, Idaho B-73 Table C-1 C&I Energy Efficiency Equipment Measure Descriptions .......................................... C-2 Table C-2 Commercial and Industrial Energy Efficiency Non-Equipment Measure Descriptions . C-5 Table C-3 Energy Efficiency Equipment Data, Electric—Small/Medium Commercial, Existing Vintage, Washington ........................................................................................... C-11 Table C-4 Energy Efficiency Equipment Data, Electric—Small/Medium Commercial, New Vintage, Washington ........................................................................................................ C-14 Table C-5 Energy Efficiency Equipment Data, Small/Medium Commercial, Existing Vintage, IdahoC-17 Table C-6 Energy Efficiency Equipment Data, Electric— Small/Medium Commercial, New Vintage, Idaho ................................................................................................................. C-20 Table C-7 Energy Efficiency Equipment Data, Electric—Large Commercial, Existing Vintage, Washington ........................................................................................................ C-23 Table C-8 Energy Efficiency Equipment Data, Electric— Large Commercial, New Vintage, Washington ........................................................................................................ C-26 Table C-9 Energy Efficiency Equipment Data, Electric—Large Commercial, Existing Vintage, IdahoC-29 Table C-10 Energy Efficiency Equipment Data, Electric— Large Commercial, New Vintage, IdahoC-32 Table C-11 Energy Efficiency Equipment Data, Electric—Extra Large Commercial, Existing Vintage, Washington ........................................................................................................ C-35 Table C-12 Energy Efficiency Equipment Data, Electric— Extra Large Commercial, New Vintage, Washington ........................................................................................................ C-38 Table C-13 Energy Efficiency Equipment Data, Electric—Extra Large Commercial, Existing Vintage, Idaho ................................................................................................................. C-41 Table C-14 Energy Efficiency Equipment Data, Electric— Extra Large Commercial, New Vintage, Idaho ................................................................................................................. C-44 Table C-15 Energy Efficiency Equipment Data, Electric—Extra Large Industrial, Existing Vintage, Washington ........................................................................................................ C-47 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 883 of 1125 EnerNOC Utility Solutions Consulting ix Table C-16 Energy Efficiency Equipment Data, Electric— Extra Large Industrial, New Vintage, Washington ........................................................................................................ C-50 Table C-17 Energy Efficiency Equipment Data, Electric—Extra Large Industrial, Existing Vintage, Idaho ................................................................................................................. C-53 Table C-18 Energy Efficiency Equipment Data, Electric— Extra Large Industrial, New Vintage, Idaho ................................................................................................................. C-56 Table C-19 Energy Efficiency Non-Equipment Data—Small/Medium Commercial, Existing Vintage, Washington ........................................................................................................ C-59 Table C-20 Energy Efficiency Non-Equipment Data— Small/ Medium Commercial, New Vintage, Washington ........................................................................................................ C-61 Table C-21 Energy Efficiency Non-Equipment Data— Small/Medium Commercial, Existing Vintage, Idaho ................................................................................................................. C-63 Table C-22 Energy Efficiency Non-Equipment Data— Small/ Medium Commercial, New Vintage, Idaho ................................................................................................................. C-65 Table C-23 Energy Efficiency Non-Equipment Data— Large Commercial, Existing Vintage, Washington ........................................................................................................ C-67 Table C-24 Energy Efficiency Non-Equipment Data— Large Commercial, New Vintage, WashingtonC-69 Table C-25 Energy Efficiency Non-Equipment Data— Large Commercial, Existing Vintage, IdahoC-71 Table C-26 Energy Efficiency Non-Equipment Data— Large Commercial, New Vintage, Idaho ... C-73 Table C-27 Energy Efficiency Non-Equipment Data— Extra Large Commercial, Existing Vintage, Washington ........................................................................................................ C-75 Table C-28 Energy Efficiency Non-Equipment Data— Extra Large Commercial, New Vintage, Washington ........................................................................................................ C-77 Table C-29 Energy Efficiency Non-Equipment Data— Extra Large Commercial, Existing Vintage, Idaho ................................................................................................................. C-79 Table C-30 Energy Efficiency Non-Equipment Data— Extra Large Commercial, New Vintage, IdahoC-81 Table C-31 Energy Efficiency Non-Equipment Data— Extra Large Industrial, Existing Vintage, Washington ........................................................................................................ C-83 Table C-32 Energy Efficiency Non-Equipment Data— Extra Large Industrial, New Vintage, Washington ........................................................................................................ C-85 Table C-33 Energy Efficiency Non-Equipment Data— Extra Large Industrial, Existing Vintage, IdahoC-87 Table C-34 Energy Efficiency Non-Equipment Data— Extra Large Industrial, New Vintage, IdahoC-89 Table D-1 Residential Equipment Measures—Achievable Potential Market Adoption Factors ..... D-2 Table D-2 Residential Non-Equipment Measures— Achievable Potential Market Adoption FactorsD-3 Table D-3 C/I Equipment Measures — Achievable Potential Market Adoption Factors ............... D-4 Table D-4 C/I Non-Equipment Measures — Achievable Potential Market Adoption Factors ........ D-6 Table E-1 Annual Electric Energy Savings, All Sectors (1,000 MWh) ........................................ E-1 Table E-2 Annual Electric Energy Savings, All Sectors (1,000 MWh) (continued) ...................... E-2 Table E-3 Annual Electric Energy Savings, Residential (1,000 MWh) ........................................ E-3 Table E-4 Annual Electric Energy Savings, Residential (1,000 MWh) (continued) ...................... E-4 Table E-5 Annual Electric Energy Savings, C/I (1,000 MWh) ................................................... E-5 Table E-6 Annual Electric Energy Savings, C/I (1,000 MWh) (continued) ................................. E-6 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 884 of 1125 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 885 of 1125 EnerNOC Utility Solutions Consulting A-1 APPENDIX A MARKET PROFILES Market profiles describe electricity use by sector, segment, end use and technology in the base year of the study (2009). The market profiles are given for average buildings and new vintages. As explained in Chapter 2 of the Avista Conservation Potential Assessment (CPA) report , a market profile includes the following elements: Market size is a representation of the number of customers in the segment. For the residential sector, it is number of households. In the commercial and industrial sector, it is floor space measured in square feet. Saturations define the fraction of buildings with the specific technologies. (e.g., homes with electric space heating). UEC (unit energy consumption) or EUI (energy-use index) describes the amount of energy consumed in the base year by a specific technology in buildings that have the technology. We use UECs expressed in kWh/household for the residential sector, and EUIs expressed in kWh/square foot for the commercial and industrial sectors. Intensity for the residential sector represents the average energy use for the technology across all households in the base year. It is computed as the product of the saturation and the UEC and is defined as kWh/household for electricity. For the commercial and industrial sector, intensity, computed as the product of the saturation and the EUI, represents the average use for the technology across all floor space. Usage is the annual energy use by a technology/end use in the segment. It is the product of the market size and intensity and is quantified in GWh for electricity. This appendix presents the following market profiles: Residential market profiles by housing type and state (Table A-1 through Table A-8) C&I by rate class and state (Table A-9 through Table A-16) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 886 of 1125 Market Profiles A-2 www.enernoc.com Table A-1 Single Family Electric Market Profile, Washington 2009 Average Market Profile New Units End Use Technology Saturation UEC (kWh) Intensity (kWh/HH) Usage (GWh) Saturation UEC (kWh) Intensity (kWh/HH) Compared to Average Cooling Central AC 36.8% 1,393 513 56 66.1% 1,601 1,058 15.0% Cooling Room AC 10.8% 512 55 6 8.7% 589 51 15.0% Cooling Air Source Heat Pump 22.2% 833 185 20 23.3% 958 223 15.0% Cooling Geothermal Heat Pump 0.4% 730 3 0 0.4% 840 4 15.0% Cooling Ductless HP 0.0% 456 - - 0.0% 524 - 15.0% Space Heating Electric Resistance 7.7% 10,302 792 86 3.8% 11,847 455 15.0% Space Heating Electric Furnace 9.8% 11,757 1,157 126 8.9% 13,521 1,198 15.0% Space Heating Supplemental 3.3% 117 4 0 3.3% 134 4 15.0% Space Heating Air Source Heat Pump 22.2% 8,561 1,903 208 22.2% 9,845 2,188 15.0% Space Heating Geothermal Heat Pump 0.4% 4,833 20 2 0.4% 5,558 23 15.0% Space Heating Ductless HP 0.0% 4,000 - - 0.0% 4,600 - 15.0% Water Heating Water Heater <= 55 Gal 53.2% 4,031 2,143 234 48.6% 3,684 1,790 -8.6% Water Heating Water Heater > 55 Gal 5.6% 4,552 257 28 5.2% 4,157 214 -8.7% Interior Lighting Screw-in 100.0% 1,295 1,295 141 100.0% 1,425 1,425 10.0% Interior Lighting Linear Fluorescent 100.0% 128 128 14 100.0% 141 141 10.0% Interior Lighting Specialty 100.0% 356 356 39 100.0% 409 409 15.0% Exterior Lighting Screw-in 100.0% 363 363 40 100.0% 400 400 10.0% Appliances Clothes Washer 98.0% 126 124 13 99.8% 95 94 -25.0% Appliances Clothes Dryer 92.8% 549 509 56 97.4% 466 454 -15.0% Appliances Dishwasher 93.9% 434 407 44 98.6% 369 364 -15.0% Appliances Refrigerator 100.0% 793 793 87 100.0% 539 539 -32.0% Appliances Freezer 59.9% 881 528 58 69.4% 554 384 -37.1% Appliances Second Refrigerator 31.3% 1,083 339 37 31.3% 693 217 -36.0% Appliances Stove 85.1% 443 377 41 82.1% 443 364 0.0% Appliances Microwave 98.5% 130 128 14 98.5% 134 132 3.0% Electronics Personal Computers 140.0% 227 317 35 154.0% 227 349 0.0% Electronics TVs 234.0% 240 562 61 245.7% 240 590 0.0% Electronics Set-top boxes/DVR 171.7% 136 234 26 188.8% 136 257 0.0% Electronics Devices and Gadgets 100.0% 60 60 7 105.0% 67 70 10.0% Miscellaneous Pool Pump 5.0% 1,500 75 8 5.3% 1,526 80 1.7% Miscellaneous Furnace Fan 59.4% 622 370 40 62.4% 622 388 0.0% Miscellaneous Miscellaneous 100.0% 549 549 60 100.0% 604 604 10.0% Total 14,547 1,588 14,471 -0.5% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 887 of 1125 Market Profiles EnerNOC Utility Solutions Consulting A-3 Table A-2 Multi Family Electric Market Profile, Washington 2009 Average Market Profile New Units End Use Technology Saturation UEC (kWh) Intensity (kWh/HH) Usage (GWh) Saturation UEC (kWh) Intensity (kWh/HH) Compared to Average Cooling Central AC 5.0% 464 23 0 15.0% 534 80 15.0% Cooling Room AC 25.0% 355 89 2 18.9% 409 77 15.0% Cooling Air Source Heat Pump 1.0% 429 4 0 1.1% 493 5 15.0% Cooling Geothermal Heat Pump 0.0% 444 - - 0.2% 511 1 15.0% Cooling Ductless HP 0.0% 229 - - 0.0% 263 - 15.0% Space Heating Electric Resistance 59.0% 5,180 3,056 56 47.2% 5,957 2,812 15.0% Space Heating Electric Furnace 5.0% 5,162 258 5 6.0% 5,936 356 15.0% Space Heating Supplemental 18.0% 61 11 0 18.0% 70 13 15.0% Space Heating Air Source Heat Pump 1.0% 3,220 32 1 1.0% 3,703 37 15.0% Space Heating Geothermal Heat Pump 0.0% 2,898 - - 0.0% 3,333 - 15.0% Space Heating Ductless HP 0.0% 2,011 - - 0.0% 2,313 - 15.0% Water Heating Water Heater <= 55 Gal 77.0% 2,142 1,650 30 75.0% 1,958 1,469 -8.6% Water Heating Water Heater > 55 Gal 0.0% 3,142 - - 0.0% 2,870 - -8.7% Interior Lighting Screw-in 100.0% 784 784 14 100.0% 863 863 10.0% Interior Lighting Linear Fluorescent 100.0% 89 89 2 100.0% 98 98 10.0% Interior Lighting Specialty 100.0% 143 143 3 100.0% 164 164 15.0% Exterior Lighting Screw-in 100.0% 21 21 0 100.0% 23 23 10.0% Appliances Clothes Washer 32.0% 101 32 1 48.0% 76 36 -25.0% Appliances Clothes Dryer 30.7% 439 135 2 46.1% 373 172 -15.0% Appliances Dishwasher 64.0% 347 222 4 96.0% 295 283 -15.0% Appliances Refrigerator 100.0% 634 634 12 100.0% 431 431 -32.0% Appliances Freezer 8.4% 705 59 1 8.9% 443 39 -37.1% Appliances Second Refrigerator 5.0% 866 43 1 5.0% 554 28 -36.0% Appliances Stove 96.4% 354 342 6 96.4% 354 342 0.0% Appliances Microwave 90.0% 104 94 2 90.0% 107 96 3.0% Electronics Personal Computers 63.0% 181 114 2 69.3% 181 126 0.0% Electronics TVs 165.0% 216 357 7 173.3% 216 375 0.0% Electronics Set-top boxes/DVR 154.5% 136 211 4 170.0% 136 232 0.0% Electronics Devices and Gadgets 100.0% 54 54 1 105.0% 60 63 10.0% Miscellaneous Pool Pump 0.0% 1,500 - - 0.0% 1,526 - 1.7% Miscellaneous Furnace Fan 13.0% 498 65 1 13.7% 498 68 0.0% Miscellaneous Miscellaneous 100.0% 206 206 4 100.0% 226 226 10.0% Total 8,728 159 8,514 -2.5% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 888 of 1125 Market Profiles A-4 www.enernoc.com Table A-3 Mobile Home Electric Market Profile, Washington 2009 Average Market Profile New Units End Use Technology Saturation UEC (kWh) Intensity (kWh/HH) Usage (GWh) Saturation UEC (kWh) Intensity (kWh/HH) Compared to Average Cooling Central AC 23.2% 553 128 1 39.4% 594 234 7.5% Cooling Room AC 23.2% 305 71 0 22.0% 328 72 7.5% Cooling Air Source Heat Pump 21.7% 361 79 0 22.8% 388 89 7.5% Cooling Geothermal Heat Pump 0.0% 325 - - 0.0% 349 - 7.5% Cooling Ductless HP 0.0% 302 - - 0.0% 324 - 7.5% Space Heating Electric Resistance 1.2% 6,823 81 0 1.1% 7,335 83 7.5% Space Heating Electric Furnace 57.6% 7,321 4,214 22 57.6% 7,870 4,530 7.5% Space Heating Supplemental 1.4% 3,780 54 0 1.5% 4,064 61 7.5% Space Heating Air Source Heat Pump 21.7% 4,667 1,015 5 22.8% 5,017 1,146 7.5% Space Heating Geothermal Heat Pump 0.0% 4,200 - - 0.2% 4,515 9 7.5% Space Heating Ductless HP 0.0% 2,649 - - 0.0% 2,848 - 7.5% Water Heating Water Heater <= 55 Gal 75.6% 2,620 1,980 10 75.6% 2,508 1,895 -4.3% Water Heating Water Heater > 55 Gal 0.0% 2,959 - - 0.0% 2,831 - -4.3% Interior Lighting Screw-in 100.0% 1,010 1,010 5 100.0% 1,061 1,061 5.0% Interior Lighting Linear Fluorescent 100.0% 100 100 1 100.0% 105 105 5.0% Interior Lighting Specialty 100.0% 278 278 1 100.0% 298 298 7.5% Exterior Lighting Screw-in 100.0% 283 283 1 100.0% 298 298 5.0% Appliances Clothes Washer 86.7% 98 85 0 86.7% 86 75 -12.5% Appliances Clothes Dryer 88.9% 428 380 2 88.9% 396 352 -7.5% Appliances Dishwasher 80.1% 338 271 1 84.1% 313 263 -7.5% Appliances Refrigerator 100.0% 618 618 3 100.0% 520 520 -16.0% Appliances Freezer 53.3% 687 366 2 53.3% 559 298 -18.6% Appliances Second Refrigerator 17.6% 845 148 1 17.6% 693 122 -18.0% Appliances Stove 84.5% 345 292 2 84.5% 345 292 0.0% Appliances Microwave 93.6% 101 95 0 93.6% 103 96 1.5% Electronics Personal Computers 104.8% 193 202 1 110.1% 193 212 0.0% Electronics TVs 234.0% 204 478 3 234.0% 204 478 0.0% Electronics Set-top boxes/DVR 154.5% 116 179 1 170.0% 116 197 0.0% Electronics Devices and Gadgets 100.0% 51 51 0 100.0% 54 54 5.0% Miscellaneous Pool Pump 5.6% 1,125 63 0 5.8% 1,135 66 0.8% Miscellaneous Furnace Fan 63.3% 467 296 2 63.3% 467 296 0.0% Miscellaneous Miscellaneous 100.0% 274 274 1 100.0% 288 288 5.0% Total 13,092 69 13,488 3.0% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 889 of 1125 Market Profiles EnerNOC Utility Solutions Consulting A-5 Table A-4 Low Income Electric Market Profile, Washington 2009 Average Market Profile New Units End Use Technology Saturation UEC (kWh) Intensity (kWh/HH) Usage (GWh) Saturation UEC (kWh) Intensity (kWh/HH) Compared to Average Cooling Central AC 22.2% 591 131 9 28.7% 635 182 7.5% Cooling Room AC 35.4% 289 102 7 18.0% 311 56 7.5% Cooling Air Source Heat Pump 10.4% 467 49 3 10.4% 502 52 7.5% Cooling Geothermal Heat Pump 0.0% 437 - - 0.5% 470 2 7.5% Cooling Ductless HP 0.0% 262 - - 0.0% 281 - 7.5% Space Heating Electric Resistance 32.0% 5,914 1,891 128 28.8% 6,358 1,830 7.5% Space Heating Electric Furnace 9.9% 6,413 637 43 8.9% 6,894 614 7.5% Space Heating Supplemental 12.7% 364 46 3 13.4% 392 52 7.5% Space Heating Air Source Heat Pump 10.4% 4,401 459 31 10.4% 4,731 493 7.5% Space Heating Geothermal Heat Pump 0.0% 3,042 - - 0.0% 3,270 - 7.5% Space Heating Ductless HP 0.0% 2,296 - - 0.0% 2,468 - 7.5% Water Heating Water Heater <= 55 Gal 83.9% 2,357 1,977 133 83.9% 2,255 1,892 -4.3% Water Heating Water Heater > 55 Gal 0.0% 2,950 - - 0.0% 2,822 - -4.3% Interior Lighting Screw-in 100.0% 758 758 51 100.0% 796 796 5.0% Interior Lighting Linear Fluorescent 100.0% 79 79 5 100.0% 83 83 5.0% Interior Lighting Specialty 100.0% 181 181 12 100.0% 195 195 7.5% Exterior Lighting Screw-in 100.0% 138 138 9 100.0% 145 145 5.0% Appliances Clothes Washer 71.3% 89 63 4 78.4% 78 61 -12.5% Appliances Clothes Dryer 68.6% 385 264 18 75.4% 356 269 -7.5% Appliances Dishwasher 78.5% 305 239 16 86.3% 282 243 -7.5% Appliances Refrigerator 100.0% 557 557 38 100.0% 468 468 -16.0% Appliances Freezer 63.0% 619 390 26 63.0% 504 317 -18.6% Appliances Second Refrigerator 23.4% 761 178 12 23.4% 624 146 -18.0% Appliances Stove 89.7% 311 279 19 89.7% 311 279 0.0% Appliances Microwave 92.6% 91 85 6 92.6% 93 86 1.5% Electronics Personal Computers 101.4% 160 163 11 106.5% 160 171 0.0% Electronics TVs 165.0% 180 297 20 165.0% 180 297 0.0% Electronics Set-top boxes/DVR 128.8% 107 138 9 141.6% 107 152 0.0% Electronics Devices and Gadgets 100.0% 45 45 3 105.0% 48 50 5.0% Miscellaneous Pool Pump 2.3% 1,170 27 2 2.3% 1,180 27 0.8% Miscellaneous Furnace Fan 25.2% 436 110 7 25.2% 436 110 0.0% Miscellaneous Miscellaneous 100.0% 140 140 9 100.0% 147 147 5.0% Total 9,424 636 9,215 -2.2% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 890 of 1125 Market Profiles A-6 www.enernoc.com Table A-5 Single Family Electric Market Profile, Idaho 2009 Average Market Profile New Units End Use Technology Saturation UEC (kWh) Intensity (kWh/HH) Usage (GWh) Saturation UEC (kWh) Intensity (kWh/HH) Compared to Average Cooling Central AC 23.2% 1,253 291 17 66.1% 1,441 952 15.0% Cooling Room AC 10.8% 461 50 3 8.7% 530 46 15.0% Cooling Air Source Heat Pump 14.6% 750 109 6 15.3% 862 132 15.0% Cooling Geothermal Heat Pump 1.2% 657 8 0 0.8% 756 6 15.0% Cooling Ductless HP 0.0% 478 - - 0.0% 550 - 15.0% Space Heating Electric Resistance 13.3% 10,817 1,436 85 6.6% 12,440 825 15.0% Space Heating Electric Furnace 5.5% 12,345 679 40 4.9% 14,197 702 15.0% Space Heating Supplemental 4.4% 111 5 0 4.4% 128 6 15.0% Space Heating Air Source Heat Pump 14.6% 8,989 1,310 78 14.6% 10,338 1,506 15.0% Space Heating Geothermal Heat Pump 1.2% 5,075 58 3 1.2% 5,836 67 15.0% Space Heating Ductless HP 0.0% 4,200 - - 0.0% 4,830 - 15.0% Water Heating Water Heater <= 55 Gal 46.4% 4,233 1,962 116 42.4% 3,869 1,639 -8.6% Water Heating Water Heater > 55 Gal 5.6% 4,779 270 16 5.2% 4,365 225 -8.7% Interior Lighting Screw-in 100.0% 1,360 1,360 81 100.0% 1,496 1,496 10.0% Interior Lighting Linear Fluorescent 100.0% 134 134 8 100.0% 148 148 10.0% Interior Lighting Specialty 100.0% 374 374 22 100.0% 430 430 15.0% Exterior Lighting Screw-in 100.0% 381 381 23 100.0% 420 420 10.0% Appliances Clothes Washer 98.0% 126 124 7 99.8% 95 94 -25.0% Appliances Clothes Dryer 92.8% 549 509 30 97.4% 466 454 -15.0% Appliances Dishwasher 93.9% 434 407 24 98.6% 369 364 -15.0% Appliances Refrigerator 100.0% 793 793 47 100.0% 539 539 -32.0% Appliances Freezer 59.8% 881 527 31 69.4% 554 384 -37.1% Appliances Second Refrigerator 24.8% 1,083 269 16 24.8% 693 172 -36.0% Appliances Stove 74.8% 443 331 20 82.1% 487 400 10.0% Appliances Microwave 98.5% 130 128 8 98.5% 134 132 3.0% Electronics Personal Computers 140.0% 227 317 19 154.0% 227 349 0.0% Electronics TVs 231.0% 240 555 33 242.6% 240 583 0.0% Electronics Set-top boxes/DVR 153.5% 136 209 12 168.9% 136 230 0.0% Electronics Devices and Gadgets 100.0% 60 60 4 105.0% 67 70 10.0% Miscellaneous Pool Pump 7.0% 1,500 105 6 7.4% 1,526 112 1.7% Miscellaneous Furnace Fan 54.9% 654 359 21 57.7% 654 377 0.0% Miscellaneous Miscellaneous 100.0% 584 584 35 100.0% 642 642 10.0% Total 1,253 13,703 811 13,502 -1.5% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 891 of 1125 Market Profiles EnerNOC Utility Solutions Consulting A-7 Table A-6 Multi Family Electric Market Profile, Idaho 2009 Average Market Profile New Units End Use Technology Saturation UEC (kWh) Intensity (kWh/HH) Usage (GWh) Saturation UEC (kWh) Intensity (kWh/HH) Compared to Average Cooling Central AC 5.0% 395 20 0 15.0% 454 68 15.0% Cooling Room AC 25.0% 302 75 0 18.9% 347 66 15.0% Cooling Air Source Heat Pump 1.0% 365 4 0 1.1% 419 4 15.0% Cooling Geothermal Heat Pump 0.0% 377 - - 0.2% 434 1 15.0% Cooling Ductless HP 0.0% 215 - - 0.0% 248 - 15.0% Space Heating Electric Resistance 59.0% 4,869 2,873 15 47.2% 5,599 2,643 15.0% Space Heating Electric Furnace 5.0% 4,852 243 1 6.0% 5,580 335 15.0% Space Heating Supplemental 18.0% 58 10 0 18.0% 66 12 15.0% Space Heating Air Source Heat Pump 1.0% 3,027 30 0 1.0% 3,481 35 15.0% Space Heating Geothermal Heat Pump 0.0% 2,724 - - 0.0% 3,133 - 15.0% Space Heating Ductless HP 0.0% 1,890 - - 0.0% 2,174 - 15.0% Water Heating Water Heater <= 55 Gal 77.0% 2,014 1,551 8 75.0% 1,841 1,380 -8.6% Water Heating Water Heater > 55 Gal 0.0% 2,954 - - 0.0% 2,698 - -8.7% Interior Lighting Screw-in 100.0% 737 737 4 100.0% 811 811 10.0% Interior Lighting Linear Fluorescent 100.0% 84 84 0 100.0% 92 92 10.0% Interior Lighting Specialty 100.0% 134 134 1 100.0% 154 154 15.0% Exterior Lighting Screw-in 100.0% 20 20 0 100.0% 22 22 10.0% Appliances Clothes Washer 32.0% 95 30 0 48.0% 71 34 -25.0% Appliances Clothes Dryer 30.7% 412 127 1 46.1% 351 161 -15.0% Appliances Dishwasher 64.0% 326 209 1 96.0% 277 266 -15.0% Appliances Refrigerator 100.0% 596 596 3 100.0% 405 405 -32.0% Appliances Freezer 8.4% 662 56 0 8.9% 416 37 -37.1% Appliances Second Refrigerator 5.0% 814 41 0 5.0% 521 26 -36.0% Appliances Stove 96.4% 333 321 2 96.4% 333 321 0.0% Appliances Microwave 90.0% 98 88 0 90.0% 101 91 3.0% Electronics Personal Computers 63.0% 170 107 1 69.3% 170 118 0.0% Electronics TVs 165.0% 203 335 2 173.3% 203 352 0.0% Electronics Set-top boxes/DVR 154.5% 128 198 1 170.0% 128 218 0.0% Electronics Devices and Gadgets 100.0% 51 51 0 105.0% 56 59 10.0% Miscellaneous Pool Pump 0.0% 1,410 - - 0.0% 1,434 - 1.7% Miscellaneous Furnace Fan 13.0% 468 61 0 13.7% 468 64 0.0% Miscellaneous Miscellaneous 100.0% 213 213 1 100.0% 234 234 10.0% Total 8,213 43 8,010 -2.5% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 892 of 1125 Market Profiles A-8 www.enernoc.com Table A-7 Mobile Home Electric Market Profile, Idaho 2009 Average Market Profile New Units End Use Technology Saturation UEC (kWh) Intensity (kWh/HH) Usage (GWh) Saturation UEC (kWh) Intensity (kWh/HH) Compared to Average Cooling Central AC 23.2% 475 110 1 39.4% 511 201 7.5% Cooling Room AC 23.2% 262 61 0 22.0% 282 62 7.5% Cooling Air Source Heat Pump 21.7% 311 68 0 22.8% 334 76 7.5% Cooling Geothermal Heat Pump 0.0% 280 - - 0.0% 300 - 7.5% Cooling Ductless HP 0.0% 285 - - 0.0% 307 - 7.5% Space Heating Electric Resistance 1.2% 6,448 77 0 1.1% 6,931 78 7.5% Space Heating Electric Furnace 57.6% 6,918 3,982 19 57.6% 7,437 4,281 7.5% Space Heating Supplemental 1.4% 3,572 51 0 1.5% 3,840 58 7.5% Space Heating Air Source Heat Pump 21.7% 4,410 959 5 22.8% 4,741 1,083 7.5% Space Heating Geothermal Heat Pump 0.0% 3,969 - - 0.0% 4,267 - 7.5% Space Heating Ductless HP 0.0% 2,503 - - 0.0% 2,691 - 7.5% Water Heating Water Heater <= 55 Gal 75.6% 2,476 1,871 9 75.6% 2,370 1,791 -4.3% Water Heating Water Heater > 55 Gal 0.0% 2,796 - - 0.0% 2,675 - -4.3% Interior Lighting Screw-in 100.0% 955 955 5 100.0% 1,003 1,003 5.0% Interior Lighting Linear Fluorescent 100.0% 94 94 0 100.0% 99 99 5.0% Interior Lighting Specialty 100.0% 262 262 1 100.0% 282 282 7.5% Exterior Lighting Screw-in 100.0% 268 268 1 100.0% 281 281 5.0% Appliances Clothes Washer 86.7% 93 81 0 86.7% 81 71 -12.5% Appliances Clothes Dryer 88.9% 404 359 2 88.9% 374 332 -7.5% Appliances Dishwasher 80.1% 320 256 1 84.1% 296 249 -7.5% Appliances Refrigerator 100.0% 584 584 3 100.0% 491 491 -16.0% Appliances Freezer 53.3% 649 346 2 53.3% 529 282 -18.6% Appliances Second Refrigerator 17.6% 798 140 1 17.6% 655 115 -18.0% Appliances Stove 84.5% 326 276 1 84.5% 326 276 0.0% Appliances Microwave 93.6% 96 90 0 93.6% 97 91 1.5% Electronics Personal Computers 104.8% 182 191 1 110.1% 182 200 0.0% Electronics TVs 234.0% 193 452 2 234.0% 193 452 0.0% Electronics Set-top boxes/DVR 154.5% 110 169 1 170.0% 110 186 0.0% Electronics Devices and Gadgets 100.0% 49 49 0 100.0% 51 51 5.0% Miscellaneous Pool Pump 5.6% 1,063 59 0 5.8% 1,072 63 0.8% Miscellaneous Furnace Fan 63.3% 441 279 1 63.3% 441 279 0.0% Miscellaneous Miscellaneous 100.0% 230 230 1 100.0% 242 242 5.0% Total 12,320 59 12,674 2.9% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 893 of 1125 Market Profiles EnerNOC Utility Solutions Consulting A-9 Table A-8 Low income Electric Market Profile, Idaho 2009 Average Market Profile New Units End Use Technology Saturation UEC (kWh) Intensity (kWh/HH) Usage (GWh) Saturation UEC (kWh) Intensity (kWh/HH) Compared to Average Cooling Central AC 22.2% 414 92 3 28.7% 445 128 7.5% Cooling Room AC 35.4% 202 72 2 18.0% 218 39 7.5% Cooling Air Source Heat Pump 10.4% 327 34 1 10.4% 351 37 7.5% Cooling Geothermal Heat Pump 0.0% 306 - - 0.5% 329 2 7.5% Cooling Ductless HP 0.0% 249 - - 0.0% 267 - 7.5% Space Heating Electric Resistance 32.0% 5,619 1,797 55 28.8% 6,040 1,738 7.5% Space Heating Electric Furnace 11.2% 6,092 680 21 10.0% 6,549 655 7.5% Space Heating Supplemental 12.7% 346 44 1 13.4% 372 50 7.5% Space Heating Air Source Heat Pump 10.4% 4,181 436 13 10.4% 4,494 468 7.5% Space Heating Geothermal Heat Pump 0.0% 2,890 - - 0.0% 3,107 - 7.5% Space Heating Ductless HP 0.0% 2,181 - - 0.0% 2,345 - 7.5% Water Heating Water Heater <= 55 Gal 83.9% 2,203 1,848 56 83.9% 2,109 1,769 -4.3% Water Heating Water Heater > 55 Gal 0.0% 2,758 - - 0.0% 2,639 - -4.3% Interior Lighting Screw-in 100.0% 709 709 22 100.0% 745 745 5.0% Interior Lighting Linear Fluorescent 100.0% 74 74 2 100.0% 78 78 5.0% Interior Lighting Specialty 100.0% 169 169 5 100.0% 182 182 7.5% Exterior Lighting Screw-in 100.0% 129 129 4 100.0% 136 136 5.0% Appliances Clothes Washer 71.3% 83 59 2 78.4% 72 57 -12.5% Appliances Clothes Dryer 68.6% 360 247 7 75.4% 333 251 -7.5% Appliances Dishwasher 78.5% 285 224 7 86.3% 263 227 -7.5% Appliances Refrigerator 100.0% 521 521 16 100.0% 437 437 -16.0% Appliances Freezer 63.0% 578 364 11 63.0% 471 297 -18.6% Appliances Second Refrigerator 23.4% 711 167 5 23.4% 583 137 -18.0% Appliances Stove 89.7% 291 261 8 89.7% 291 261 0.0% Appliances Microwave 92.6% 85 79 2 92.6% 87 80 1.5% Electronics Personal Computers 101.4% 150 152 5 106.5% 150 160 0.0% Electronics TVs 165.0% 168 277 8 165.0% 168 277 0.0% Electronics Set-top boxes/DVR 128.8% 100 129 4 141.6% 100 142 0.0% Electronics Devices and Gadgets 100.0% 42 42 1 105.0% 44 47 5.0% Miscellaneous Pool Pump 2.3% 1,094 25 1 2.3% 1,103 25 0.8% Miscellaneous Furnace Fan 25.2% 407 103 3 25.2% 407 103 0.0% Miscellaneous Miscellaneous 100.0% 133 133 4 100.0% 140 140 5.0% Total 8,868 269 8,666 -2.3% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 894 of 1125 Market Profiles A-10 www.enernoc.com Table A-9 Small/Medium Commercial Electric Market Profile, Washington 2009 Average Market Profile New Units End Use Technology Saturation UEC (kWh) Intensity (kWh/HH) Usage (GWh) Saturation UEC (kWh) Intensity (kWh/HH) Compared to Average Cooling Central Chiller 13.8% 2 0 8 13.8% 2 0 -13.6% Cooling RTU 63.1% 2 2 37 63.1% 2 1 -15.9% Cooling Heat Pump 3.6% 5 0 4 3.6% 4 0 -15.9% Space Heating Electric Resistance 5.9% 7 0 9 5.9% 6 0 -5.0% Space Heating Furnace 17.7% 7 1 30 17.7% 7 1 -5.0% Space Heating Heat Pump 3.6% 4 0 3 3.6% 3 0 -6.8% Ventilation Ventilation 76.9% 2 2 38 76.9% 2 1 -14.8% Interior Lighting Interior Screw-in 100.0% 1 1 24 100.0% 1 1 -1.2% Interior Lighting High Bay Fixtures 100.0% 1 1 16 100.0% 1 1 -20.0% Interior Lighting Linear Fluorescent 100.0% 3 3 80 100.0% 3 3 -12.7% Exterior Lighting Exterior Screw-in 100.0% 0 0 4 100.0% 0 0 -26.0% Exterior Lighting HID 100.0% 1 1 18 100.0% 1 1 -26.4% Water Heating Water Heater 63.0% 2 1 30 63.0% 2 1 -6.0% Food Preparation Fryer 25.8% 0 0 1 30.8% 0 0 -0.6% Food Preparation Oven 25.8% 1 0 6 35.8% 1 0 -1.2% Food Preparation Dishwasher 25.8% 0 0 0 35.8% 0 0 -24.1% Food Preparation Hot Food Container 25.8% 0 0 2 35.8% 0 0 -20.0% Food Preparation Food Prep 25.8% 0 0 0 35.8% 0 0 -20.0% Refrigeration Walk in Refrigeration 52.4% - - - 62.4% - - 0.0% Refrigeration Glass Door Display 52.4% 0 0 6 57.4% 0 0 -8.8% Refrigeration Reach-in Refrigerator 52.4% 1 0 6 57.4% 0 0 -30.0% Refrigeration Open Display Case 52.4% 0 0 1 57.4% 0 0 -8.4% Refrigeration Vending Machine 52.4% 0 0 4 57.4% 0 0 -12.8% Refrigeration Icemaker 52.4% 0 0 4 57.4% 0 0 -11.9% Office Equipment Desktop Computer 99.9% 0 0 11 104.9% 0 1 -0.7% Office Equipment Laptop Computer 99.9% 0 0 1 104.9% 0 0 -0.7% Office Equipment Server 99.9% 0 0 9 104.9% 0 0 -4.7% Office Equipment Monitor 99.9% 0 0 6 104.9% 0 0 -2.8% Office Equipment Printer/copier/fax 99.9% 0 0 6 104.9% 0 0 -6.1% Office Equipment POS Terminal 99.9% 0 0 7 104.9% 0 0 -15.6% Miscellaneous Non-HVAC Motor 40.2% 1 0 12 40.2% 1 1 5.1% Miscellaneous Other Miscellaneous 100.0% 1 1 34 100.0% 2 2 20.0% Total 18 416 16 -6.9% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 895 of 1125 Market Profiles EnerNOC Utility Solutions Consulting A-11 Table A-10 Large Commercial Electric Market Profile, Washington 2009 Average Market Profile New Units End Use Technology Saturation UEC (kWh) Intensity (kWh/HH) Usage (GWh) Saturation UEC (kWh) Intensity (kWh/HH) Compared to Average Cooling Central Chiller 24.7% 2 1 49 24.7% 2 0 -16.9% Cooling RTU 37.8% 3 1 89 37.8% 2 1 -17.4% Cooling Heat Pump 9.1% 4 0 30 9.1% 3 0 -16.9% Space Heating Electric Resistance 5.9% 4 0 20 5.9% 3 0 -12.6% Space Heating Furnace 12.7% 5 1 55 12.7% 4 1 -12.6% Space Heating Heat Pump 9.1% 2 0 20 9.1% 2 0 -3.5% Ventilation Ventilation 75.1% 2 1 116 75.1% 1 1 -14.8% Interior Lighting Interior Screw-in 100.0% 1 1 88 100.0% 1 1 -1.4% Interior Lighting High Bay Fixtures 100.0% 1 1 66 100.0% 1 1 -20.0% Interior Lighting Linear Fluorescent 100.0% 3 3 307 100.0% 3 3 -13.6% Exterior Lighting Exterior Screw-in 100.0% 0 0 9 100.0% 0 0 -18.1% Exterior Lighting HID 100.0% 1 1 65 100.0% 1 1 -26.4% Water Heating Water Heater 54.2% 2 1 117 54.2% 2 1 -4.0% Food Preparation Fryer 18.4% 0 0 6 23.4% 0 0 -0.6% Food Preparation Oven 18.4% 2 0 32 28.4% 2 1 -1.2% Food Preparation Dishwasher 18.4% 0 0 3 28.4% 0 0 -24.1% Food Preparation Hot Food Container 18.4% 0 0 5 28.4% 0 0 -39.9% Food Preparation Food Prep 18.4% 0 0 0 28.4% 0 0 -20.0% Refrigeration Walk in Refrigeration 39.1% 0 0 17 49.1% 0 0 -30.0% Refrigeration Glass Door Display 39.1% 0 0 13 44.1% 0 0 -9.7% Refrigeration Reach-in Refrigerator 39.1% 1 0 28 44.1% 1 0 -30.0% Refrigeration Open Display Case 39.1% 0 0 10 44.1% 0 0 -9.3% Refrigeration Vending Machine 39.1% 0 0 13 44.1% 0 0 -12.8% Refrigeration Icemaker 39.1% 1 0 24 44.1% 1 0 -12.2% Office Equipment Desktop Computer 98.4% 1 1 82 103.4% 1 1 -0.7% Office Equipment Laptop Computer 98.4% 0 0 6 103.4% 0 0 -0.7% Office Equipment Server 98.4% 0 0 38 103.4% 0 0 -4.7% Office Equipment Monitor 98.4% 0 0 19 103.4% 0 0 -2.8% Office Equipment Printer/copier/fax 98.4% 0 0 19 103.4% 0 0 -6.1% Office Equipment POS Terminal 98.4% 0 0 6 103.4% 0 0 -15.6% Miscellaneous Non-HVAC Motor 57.7% 1 1 75 57.7% 1 1 5.1% Miscellaneous Other Miscellaneous 100.0% 1 1 127 100.0% 2 2 10.0% Total 17 1,557 16 -6.8% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 896 of 1125 Market Profiles A-12 www.enernoc.com Table A-11 Extra Large Commercial Electric Market Profile, Washington 2009 Average Market Profile New Units End Use Technology Saturation UEC (kWh) Intensity (kWh/HH) Usage (GWh) Saturation UEC (kWh) Intensity (kWh/HH) Compared to Average Cooling Central Chiller 52.2% 2 1 21 52.2% 2 1 -14.7% Cooling RTU 24.7% 2 1 10 24.7% 2 0 -16.7% Cooling Heat Pump 4.4% 2 0 2 4.4% 2 0 -26.2% Space Heating Electric Resistance 15.8% 4 1 13 15.8% 4 1 -13.1% Space Heating Furnace 5.6% 6 0 6 5.6% 5 0 -13.1% Space Heating Heat Pump 90.2% 2 2 33 90.2% 2 2 -12.1% Ventilation Ventilation 100.0% 1 1 26 100.0% 1 1 -2.7% Interior Lighting Interior Screw-in 100.0% 0 0 6 100.0% 0 0 -20.0% Interior Lighting High Bay Fixtures 100.0% 2 2 42 100.0% 2 2 -8.3% Interior Lighting Linear Fluorescent 100.0% 0 0 1 100.0% 0 0 -51.9% Exterior Lighting Exterior Screw-in 100.0% 1 1 17 100.0% 1 1 -26.4% Exterior Lighting HID 26.3% 4 1 19 26.3% 4 1 -2.0% Water Heating Water Heater 13.8% 0 0 0 18.8% 0 0 -0.6% Food Preparation Fryer 13.8% 2 0 6 23.8% 2 0 -1.2% Food Preparation Oven 13.8% 0 0 0 23.8% 0 0 -24.1% Food Preparation Dishwasher 13.8% 0 0 0 23.8% 0 0 -39.9% Food Preparation Hot Food Container 13.8% 0 0 0 23.8% 0 0 0.0% Food Preparation Food Prep 26.6% 0 0 1 36.6% 0 0 -30.0% Refrigeration Walk in Refrigeration 26.6% 0 0 1 31.6% 0 0 -9.7% Refrigeration Glass Door Display 26.6% 1 0 4 31.6% 0 0 -30.0% Refrigeration Reach-in Refrigerator 26.6% 0 0 3 31.6% 0 0 -9.3% Refrigeration Open Display Case 26.6% 0 0 2 31.6% 0 0 -27.9% Refrigeration Vending Machine 26.6% 0 0 2 31.6% 0 0 -11.4% Refrigeration Icemaker 100.0% 1 1 12 105.0% 1 1 -0.7% Office Equipment Desktop Computer 100.0% 0 0 1 105.0% 0 0 -0.7% Office Equipment Laptop Computer 100.0% 0 0 3 105.0% 0 0 -4.7% Office Equipment Server 100.0% 0 0 2 105.0% 0 0 -2.8% Office Equipment Monitor 100.0% 0 0 1 105.0% 0 0 -6.1% Office Equipment Printer/copier/fax 100.0% 0 0 0 105.0% 0 0 -15.6% Office Equipment POS Terminal 88.8% 1 1 14 88.8% 1 1 5.1% Miscellaneous Non-HVAC Motor 100.0% 1 1 15 100.0% 1 1 10.0% Miscellaneous Other Miscellaneous 4.4% 3 0 3 4.4% 3 0 -3.1% Total 14 266 13 -6.0% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 897 of 1125 Market Profiles EnerNOC Utility Solutions Consulting A-13 Table A-12 Extra Large Industrial Electric Market Profile, Washington 2009 Average Market Profile New Units End Use Technology Saturation UEC (kWh) Intensity (kWh/HH) Usage (GWh) Saturation UEC (kWh) Intensity (kWh/HH) Compared to Average Cooling Central Chiller 14.4% 8 1 18 14.4% 7 1 -11.7% Cooling RTU 17.1% 6 1 17 17.1% 6 1 -12.3% Cooling Heat Pump 2.7% 5 0 2 2.7% 4 0 -20.9% Space Heating Electric Resistance 10.8% 9 1 14 10.8% 8 1 -5.0% Space Heating Furnace 2.0% 9 0 3 2.0% 9 0 0.0% Space Heating Heat Pump 2.7% 4 0 2 2.7% 4 0 -4.9% Ventilation Ventilation 27.4% 12 3 52 27.4% 10 3 -15.0% Interior Lighting Interior Screw-in 100.0% 0 0 5 100.0% 0 0 -5.0% Interior Lighting High Bay Fixtures 100.0% 1 1 16 100.0% 1 1 -12.7% Interior Lighting Linear Fluorescent 100.0% 1 1 17 100.0% 1 1 -26.0% Exterior Lighting Exterior Screw-in 100.0% 0 0 0 100.0% 0 0 -26.4% Exterior Lighting HID 100.0% 0 0 4 100.0% 0 0 -26.4% Process Process Cooling/Refrigeration 2.4% 100 2 37 2.5% 100 3 0.0% Process Process Heating 26.2% 14 4 55 27.5% 14 4 0.0% Process Electrochemical Process 2.6% 77 2 31 2.7% 77 2 0.0% Machine Drive Less than 5 HP 90.5% 1 1 13 95.0% 1 1 0.0% Machine Drive 5-24 HP 80.1% 2 2 28 84.1% 2 2 0.0% Machine Drive 25-99 HP 72.4% 6 4 68 76.0% 6 5 0.0% Machine Drive 100-249 HP 65.3% 4 3 38 68.6% 4 3 0.0% Machine Drive 250-499 HP 23.7% 12 3 42 24.9% 12 3 0.0% Machine Drive 500 and more HP 26.1% 20 5 78 27.4% 20 5 0.0% Miscellaneous Miscellaneous 100.0% 5 5 75 103.0% 5 5 0.0% Total 40 614 40 0.2% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 898 of 1125 Market Profiles A-14 www.enernoc.com Table A-13 Small/Medium Commercial Electric Market Profile, Idaho 2009 Average Market Profile New Units End Use Technology Saturation UEC (kWh) Intensity (kWh/HH) Usage (GWh) Saturation UEC (kWh) Intensity (kWh/HH) Compared to Average Cooling Central Chiller 13.8% 2 0 6 13.8% 2 0 -13.6% Cooling RTU 63.1% 2 2 29 63.1% 2 1 -15.9% Cooling Heat Pump 3.6% 5 0 3 3.6% 4 0 -15.9% Space Heating Electric Resistance 5.9% 7 0 7 5.9% 6 0 -5.0% Space Heating Furnace 17.7% 7 1 23 17.7% 7 1 -5.0% Space Heating Heat Pump 3.6% 4 0 2 3.6% 3 0 -6.8% Ventilation Ventilation 76.9% 2 2 30 76.9% 2 1 -14.8% Interior Lighting Interior Screw-in 100.0% 1 1 18 100.0% 1 1 -1.2% Interior Lighting High Bay Fixtures 100.0% 1 1 13 100.0% 1 1 -20.0% Interior Lighting Linear Fluorescent 100.0% 3 3 62 100.0% 3 3 -12.7% Exterior Lighting Exterior Screw-in 100.0% 0 0 4 100.0% 0 0 -26.0% Exterior Lighting HID 100.0% 1 1 13 100.0% 1 1 -26.4% Water Heating Water Heater 63.0% 2 1 23 63.0% 2 1 -6.0% Food Preparation Fryer 25.8% 0 0 1 30.8% 0 0 -0.6% Food Preparation Oven 25.8% 1 0 5 35.8% 1 0 -1.2% Food Preparation Dishwasher 25.8% 0 0 0 35.8% 0 0 -24.1% Food Preparation Hot Food Container 25.8% 0 0 1 35.8% 0 0 -20.0% Food Preparation Food Prep 25.8% 0 0 0 35.8% 0 0 -20.0% Refrigeration Walk in Refrigeration 52.4% - - - 62.4% - - 0.0% Refrigeration Glass Door Display 52.4% 0 0 4 57.4% 0 0 -8.8% Refrigeration Reach-in Refrigerator 52.4% 1 0 5 57.4% 0 0 -30.0% Refrigeration Open Display Case 52.4% 0 0 0 57.4% 0 0 -8.4% Refrigeration Vending Machine 52.4% 0 0 3 57.4% 0 0 -12.8% Refrigeration Icemaker 52.4% 0 0 3 57.4% 0 0 -11.9% Office Equipment Desktop Computer 99.9% 0 0 9 104.9% 0 1 -0.7% Office Equipment Laptop Computer 99.9% 0 0 1 104.9% 0 0 -0.7% Office Equipment Server 99.9% 0 0 7 104.9% 0 0 -4.7% Office Equipment Monitor 99.9% 0 0 5 104.9% 0 0 -2.8% Office Equipment Printer/copier/fax 99.9% 0 0 4 104.9% 0 0 -6.1% Office Equipment POS Terminal 99.9% 0 0 5 104.9% 0 0 -15.6% Miscellaneous Non-HVAC Motor 40.2% 1 0 9 40.2% 1 1 5.1% Miscellaneous Other Miscellaneous 100.0% 1 1 26 100.0% 2 2 20.0% Total 18 323 16 -6.9% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 899 of 1125 Market Profiles EnerNOC Utility Solutions Consulting A-15 Table A-14 Large Commercial Electric Market Profile, Idaho 2009 Average Market Profile New Units End Use Technology Saturation UEC (kWh) Intensity (kWh/HH) Usage (GWh) Saturation UEC (kWh) Intensity (kWh/HH) Compared to Average Cooling Central Chiller 24.7% 2 1 22 24.7% 2 0 -16.9% Cooling RTU 37.8% 3 1 40 37.8% 2 1 -17.4% Cooling Heat Pump 9.1% 4 0 14 9.1% 3 0 -16.9% Space Heating Electric Resistance 5.9% 4 0 9 5.9% 3 0 -12.6% Space Heating Furnace 12.7% 5 1 25 12.7% 4 1 -12.6% Space Heating Heat Pump 9.1% 2 0 9 9.1% 2 0 -3.5% Ventilation Ventilation 75.1% 2 1 52 75.1% 1 1 -14.8% Interior Lighting Interior Screw-in 100.0% 1 1 39 100.0% 1 1 -1.4% Interior Lighting High Bay Fixtures 100.0% 1 1 30 100.0% 1 1 -20.0% Interior Lighting Linear Fluorescent 100.0% 3 3 138 100.0% 3 3 -13.6% Exterior Lighting Exterior Screw-in 100.0% 0 0 4 100.0% 0 0 -18.1% Exterior Lighting HID 100.0% 1 1 29 100.0% 1 1 -26.4% Water Heating Water Heater 54.2% 2 1 53 54.2% 2 1 -4.0% Food Preparation Fryer 18.4% 0 0 3 23.4% 0 0 -0.6% Food Preparation Oven 18.4% 2 0 14 28.4% 2 1 -1.2% Food Preparation Dishwasher 18.4% 0 0 1 28.4% 0 0 -24.1% Food Preparation Hot Food Container 18.4% 0 0 2 28.4% 0 0 -39.9% Food Preparation Food Prep 18.4% 0 0 0 28.4% 0 0 -20.0% Refrigeration Walk in Refrigeration 39.1% 0 0 8 49.1% 0 0 -30.0% Refrigeration Glass Door Display 39.1% 0 0 6 44.1% 0 0 -9.7% Refrigeration Reach-in Refrigerator 39.1% 1 0 13 44.1% 1 0 -30.0% Refrigeration Open Display Case 39.1% 0 0 4 44.1% 0 0 -9.3% Refrigeration Vending Machine 39.1% 0 0 6 44.1% 0 0 -12.8% Refrigeration Icemaker 39.1% 1 0 11 44.1% 1 0 -12.2% Office Equipment Desktop Computer 98.4% 1 1 37 103.4% 1 1 -0.7% Office Equipment Laptop Computer 98.4% 0 0 3 103.4% 0 0 -0.7% Office Equipment Server 98.4% 0 0 17 103.4% 0 0 -4.7% Office Equipment Monitor 98.4% 0 0 9 103.4% 0 0 -2.8% Office Equipment Printer/copier/fax 98.4% 0 0 9 103.4% 0 0 -6.1% Office Equipment POS Terminal 98.4% 0 0 3 103.4% 0 0 -15.6% Miscellaneous Non-HVAC Motor 57.7% 1 1 34 57.7% 1 1 5.1% Miscellaneous Other Miscellaneous 100.0% 1 1 57 100.0% 2 2 10.0% Total 17 700 16 -6.8% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 900 of 1125 Market Profiles A-16 www.enernoc.com Table A-15 Extra Large Commercial Electric Market Profile, Idaho 2009 Average Market Profile New Units End Use Technology Saturation UEC (kWh) Intensity (kWh/HH) Usage (GWh) Saturation UEC (kWh) Intensity (kWh/HH) Compared to Average Cooling Central Chiller 52.2% 2 1 6 52.2% 2 1 -14.7% Cooling RTU 24.7% 2 1 3 24.7% 2 0 -16.7% Cooling Heat Pump 4.4% 2 0 0 4.4% 2 0 -26.2% Space Heating Electric Resistance 15.8% 4 1 4 15.8% 4 1 -13.1% Space Heating Furnace 5.6% 6 0 2 5.6% 5 0 -13.1% Space Heating Heat Pump 90.2% 2 2 9 90.2% 2 2 -12.1% Ventilation Ventilation 100.0% 1 1 7 100.0% 1 1 -2.7% Interior Lighting Interior Screw-in 100.0% 0 0 1 100.0% 0 0 -20.0% Interior Lighting High Bay Fixtures 100.0% 2 2 11 100.0% 2 2 -8.3% Interior Lighting Linear Fluorescent 100.0% 0 0 0 100.0% 0 0 -51.9% Exterior Lighting Exterior Screw-in 100.0% 1 1 4 100.0% 1 1 -26.4% Exterior Lighting HID 26.3% 4 1 5 26.3% 4 1 -2.0% Water Heating Water Heater 13.8% 0 0 0 23.8% 0 0 -0.6% Food Preparation Fryer 13.8% 2 0 1 23.8% 2 0 -1.2% Food Preparation Oven 13.8% 0 0 0 23.8% 0 0 -24.1% Food Preparation Dishwasher 13.8% 0 0 0 23.8% 0 0 -39.9% Food Preparation Hot Food Container 13.8% 0 0 0 23.8% 0 0 0.0% Food Preparation Food Prep 26.6% 0 0 0 31.6% 0 0 -30.0% Refrigeration Walk in Refrigeration 26.6% 0 0 0 31.6% 0 0 -9.7% Refrigeration Glass Door Display 26.6% 1 0 1 31.6% 0 0 -30.0% Refrigeration Reach-in Refrigerator 26.6% 0 0 1 31.6% 0 0 -9.3% Refrigeration Open Display Case 26.6% 0 0 1 31.6% 0 0 -27.9% Refrigeration Vending Machine 26.6% 0 0 0 31.6% 0 0 -11.4% Refrigeration Icemaker 100.0% 1 1 3 105.0% 1 1 -0.7% Office Equipment Desktop Computer 100.0% 0 0 0 105.0% 0 0 -0.7% Office Equipment Laptop Computer 100.0% 0 0 1 105.0% 0 0 -4.7% Office Equipment Server 100.0% 0 0 1 105.0% 0 0 -2.8% Office Equipment Monitor 100.0% 0 0 0 105.0% 0 0 -6.1% Office Equipment Printer/copier/fax 100.0% 0 0 0 100.0% 0 0 -15.6% Office Equipment POS Terminal 88.8% 1 1 4 88.8% 1 1 5.1% Miscellaneous Non-HVAC Motor 100.0% 1 1 4 100.0% 1 1 10.0% Miscellaneous Other Miscellaneous 4.4% 3 0 1 4.4% 3 0 -3.1% Total 14 70 13 -6.0% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 901 of 1125 Market Profiles EnerNOC Utility Solutions Consulting A-17 Table A-16 Extra Large Industrial Electric Market Profile, Idaho 2009 Average Market Profile New Units End Use Technology Saturation UEC (kWh) Intensity (kWh/HH) Usage (GWh) Saturation UEC (kWh) Intensity (kWh/HH) Compared to Average Cooling Central Chiller 14.4% 8 1 6 14.4% 7 1 -11.7% Cooling RTU 17.1% 6 1 5 17.1% 6 1 -12.3% Cooling Heat Pump 2.7% 4 0 0 2.7% 3 0 -20.9% Space Heating Electric Resistance 10.8% 9 1 5 10.8% 8 1 -5.0% Space Heating Furnace 2.0% 9 0 1 2.0% 9 0 0.0% Space Heating Heat Pump 27.4% 12 3 17 27.4% 10 3 -15.0% Ventilation Ventilation 100.0% 0 0 2 100.0% 0 0 -5.0% Interior Lighting Interior Screw-in 100.0% 1 1 5 100.0% 1 1 -12.7% Interior Lighting High Bay Fixtures 100.0% 1 1 5 100.0% 1 1 -26.0% Interior Lighting Linear Fluorescent 100.0% 0 0 0 100.0% 0 0 -26.4% Exterior Lighting Exterior Screw-in 100.0% 0 0 1 100.0% 0 0 -26.4% Exterior Lighting HID 2.4% 100 2 12 2.5% 100 3 0.0% Process Process Cooling/Refrigeration 26.2% 14 4 18 27.5% 14 4 0.0% Process Process Heating 2.6% 77 2 10 2.7% 77 2 0.0% Process Electrochemical Process 90.5% 1 1 4 95.0% 1 1 0.0% Machine Drive Less than 5 HP 80.1% 2 2 9 84.1% 2 2 0.0% Machine Drive 5-24 HP 72.4% 6 4 22 76.0% 6 5 0.0% Machine Drive 25-99 HP 65.3% 4 3 12 68.6% 4 3 0.0% Machine Drive 100-249 HP 23.7% 12 3 13 24.9% 12 3 0.0% Machine Drive 250-499 HP 26.1% 20 5 25 27.4% 20 5 0.0% Machine Drive 500 and more HP 100.0% 5 5 24 103.0% 5 5 0.0% Miscellaneous Miscellaneous 2.7% 5 0 1 2.7% 5 0 -4.9% Total 40 196 40 0.2% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 902 of 1125 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 903 of 1125 EnerNOC Utility Solutions Consulting B-1 APPENDIX B RESIDENTIAL ENERGY EFFICIENCY EQUIPMENT AND MEASURE DATA This appendix presents detailed information for all energy-efficiency measures (equipment and non-equipment measures per the LoadMAP taxonomy) that were evaluated as part of this study. Several sets of tables are provided. Measure Descriptions Table B-1 and Table B-2 provide brief descriptions for all equipment and non-equipment measures that were assessed for potential. Equipment Measure Data Table B-3 through Table B-18 list the detailed unit-level data of Washington and Idaho for the equipment measures for each of the housing type segments — Single Family, Multi Family, Mobile Home, and Low income for existing and new construction, respectively. Savings are in annual kWh per household, and incremental costs are in $/household ($/HH), unless noted otherwise. The BC ratio shown in the tables are for the first year of the potential analysis (2014), although the B/C ratio is calculated within LoadMAP for each year of the forecast. The B/C ratio in the tables is 1.00 if the measure represents the baseline technology, and zero if the technology is not available in 2014. The final data item in these tables is the levelized cost of conserved energy, which is defined as the cost of the measure divided by the cumulative amount of energy savings accrued over the measure’s lifetime ($/kWh). Non-Equipment Measure Data Table B-19 through Table B-34 list the detailed unit-level data of Washington and Idaho for the non-equipment energy efficiency measures for each of the housing type segments and for existing and new construction, respectively. Because these measures can produce energy-use savings for multiple end-use loads (e.g., insulation affects heating and cooling energy use) savings are expressed as a net percentage of all the relevant, combined end-use loads. Base saturation indicates the percentage of homes in which the measure is already installed. Applicability is a factor that account for whether the measure is applicable to the building. Cost is expressed in $/household. The detailed measure-level tables present the results of the benefit/cost (B/C) analysis for the first year of the potential analysis (2014) although the B/C ratio is calculated within LoadMAP for each year of the forecast. These tables also contain the levelized cost of conserved energy, which is defined as the cost of the measure divided by the cumulative amount of energy savings accrued over the measure’s lifetime, given in terms of $/kWh. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 904 of 1125 Residential Energy Efficiency Equipment and Measure Data B-2 www.enernoc.com Table B-1 Residential Energy Efficiency Equipment Measure Descriptions End Use Technology Measure Description Cooling Central AC Central air conditioners consist of a refrigeration system using a direct expansion cycle. Equipment includes a compressor, an air-cooled condenser (located outdoors), an expansion valve, and an evaporator coil. A supply fan near the evaporator coil distributes supply air through air ducts to the building. Cooling efficiencies vary based on materials used, equipment size, condenser type, and system configuration. CACs may be unitary (all components housed in a factory-built assembly) or split system (an outdoor condenser section and an indoor evaporator section connected by refrigerant lines and with the compressor either indoors or outdoors). Energy efficiency is rated according to the size of the unit using the Seasonal Energy Efficiency Rating (SEER). Ductless systems with Variable Refrigerant Flow further improve the operating efficiency. Cooling Room AC Room air conditioners are designed to cool a single room or space. They incorporate a complete air-cooled refrigeration and air-handling system in an individual package. Room air conditioners come in several forms, including window, split-type, and packaged terminal units. Energy efficiency is rated according to the size of the unit using the Energy Efficiency Rating (EER). Cooling/ Space Heating Ductless Heat Pump Ductless heat pumps systems are similar to convential air-source heat pumps in that they use electricity to transfer heat between outdoor and indoor air via a vapor compression cycle. They can thus provide both heating and colling. However, they are mounted though a wall and thus can be retrofitted in homes that use electric zonal baseboard, wall, or ceiling units and as a result do not have ducts. They may also be suitable in new construction, where one or more systems can be installed. Cooling/ Space Heating Air-Source Heat Pump A central heat pump consists of components similar to a CAC system, but is usually designed to function both as a heat pump and an air conditioner. It consists of a refrigeration system using a direct expansion (DX) cycle. Equipment includes a compressor, an air-cooled condenser (located outdoors), an expansion valve, and an evaporator coil (located in the supply air duct near the supply fan) and a reversing valve to change the DX cycle from cooling to heating when required. The cooling and heating efficiencies vary based on the materials used, equipment size, condenser type, and system configuration. Heat pumps may be unitary (all components housed in a factory-built assembly) or a split system (an outdoor condenser section and an indoor evaporator section connected by refrigerant lines, with either outdoors or indoors. A high-efficiency option for a ductless mini-split system is also analyzed. Cooling/ Space Heating Geothermal Heat Pump Geothermal heat pumps are similar to air-source heat pumps, but use the ground or groundwater instead of outside air to provide a heat source/sink. A geothermal heat pump system generally consists of three major subsystems or parts: a geothermal heat pump to move heat between the building and the fluid in the earth connection, an earth connection for transferring heat between the fluid and the earth, and a distribution subsystem for delivering heating or cooling to the building. The system may also have a desuperheater to supplement the building's water heater, or a full-demand water heater to meet all of the building's hot water needs. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 905 of 1125 Residential Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting B-3 End Use Technology Measure Description Space Heating Electric Resistance Resistive heating elements are used to convert electricity directly to heat. Conductive fins surrounding the element or another mechanism is used to deliver the heat directly to the surrounding room or area. These are typically either baseboard or wall-mounted units. Space Heating Electric Furnace Furnaces heat air and distribute the heated air through the building using ducts. Efficiency improvements can include: exhaust fan controls, electronic ignition (no pilot light), compact size and lighter weight to reduce cycling losses, smaller-diameter flue pipe, and sealed combustion. Very high efficiency units, or condensing units, condense the water vapor produced in the combustion process and also use the heat from this condensation. Water Heating Water Heater For electric hot water heating, the most common type is a storage heater, which incorporates an electric heating element, storage tank, outer jacket, insulation, and controls in a single unit. Efficient units are characterized by a high recovery or thermal efficiency and low standby losses (the ratio of heat lost per hour to the content of the stored water). A further efficiency gain is available through a heat pump water heater (HPWH), which uses a vapor-compression thermodynamic cycle similar to that found in an air-conditioner or refrigerator to extract heat from an available source (e.g., air) and reject that heat to a higher temperature sink, in this case, the water in the water heater. Electric instantaneous water heaters are available, but are excluded from this study due to potentially high instantaneous demand concerns. For natural gas hot water heating, the most common type is a storage heater, which incorporates a burner, storage tank, outer jacket, insulation, and controls in a single unit. Efficient units are characterized by a high recovery or thermal efficiency and low standby losses (the ratio of heat lost per hour to the content of the stored water). A further efficiency gain is available in condensing units, which condense the water vapor produced in the combustion process and also use the heat from this condensation. Interior Lighting Screw-in Infrared halogen lamps are designed to be a replacement for standards incandescent lamps. Also referred to as advanced incandescent lamps, these products meet the Energy Independence and Security Act (EISA) lighting standards and are phased in as the baseline technology screw-in lamp technology to reflect the timeline over which the EISA lighting standards take effect. Compact fluorescent lamps are designed to be a replacement for standard incandescent lamps and use about 25% of the energy used by standard incandescent lamps to produce the same lumen output. They can use either electronic or magnetic ballasts. Integral compact fluorescent lamps have the ballast integrated into the base of the lamp and have a standard screw-in base that permits installation into existing incandescent fixtures. Light-emitting diode (LED) lighting has seen recent penetration in specific applications such as traffic lights and exit signs. With the potential for extremely high efficiency, LEDs show promise to provide general-use lighting for interior spaces. Current models commercially available have efficacies comparable to CFLs. However, theoretical efficiencies are significantly higher. LED models under development are expected to provide improved efficacies. Interior Lighting Linear Fluorescent T8 fluorescent lamps are smaller in diameter than standard T12 lamps, resulting in greater light output per watt. T8 lamps also operate at a lower current and wattage, which increases the efficiency of the ballast Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 906 of 1125 Residential Energy Efficiency Equipment and Measure Data B-4 www.enernoc.com End Use Technology Measure Description but requires the lamps to be compatible with the ballast. Fluorescent lamp fixtures can include a reflector that increases the light output from the fixture, and thus make it possible to use a fewer number of lamps in each fixture. T5 lamps further increase efficiency by reducing the lamp diameter to 5/8”. Light-emitting diode (LED) lighting has seen recent penetration in specific applications such as traffic lights and exit signs. With the potential for extremely high efficiency, LEDs show promise to provide general-use lighting for interior spaces. Current models commercially available have efficacies comparable to CFLs. However, theoretical efficiencies are significantly higher. LED models under development are expected to provide improved efficacies. Interior Lighting Specialty Lighting Bulbs that the DOE does not consider conventional and are not covered by federal efficiency standards. These include: appliance bulbs, heavy- duty bulbs, dimmable bulbs, three-way bulbs, G shape (globe) lamps, candelabra base, and others. Exterior Lighting Screw-in Infrared halogen lamps are designed to be a replacement for standards incandescent lamps. Also referred to as advanced incandescent lamps, these products meet the Energy Independence and Security Act (EISA) lighting standards and are phased in as the baseline technology screw-in lamp technology to reflect the timeline over which the EISA lighting standards take effect. Compact fluorescent lamps are designed to be a replacement for standard incandescent lamps and use about 25% of the energy used by standard incandescent lamps to produce the same lumen output. They can use either electronic or magnetic ballasts. Integral compact fluorescent lamps have the ballast integrated into the base of the lamp and have a standard screw-in base that permits installation into existing incandescent fixtures. Light-emitting diode (LED) lighting has seen recent penetration in specific applications such as traffic lights and exit signs. With the potential for extremely high efficiency, LEDs show promise to provide general-use lighting for interior spaces. Current models commercially available have efficacies comparable to CFLs. However, theoretical efficiencies are significantly higher. LED models under development are expected to provide improved efficacies. Appliances Refrigerator Energy-efficient refrigerators/freezers incorporate features such as improved cabinet insulation, more efficient compressors and evaporator fans, defrost controls, mullion heaters, oversized condenser coils, and improved door seals. Further efficiency increases can be obtained by reducing the volume of refrigerated space, or adding multiple compartments to reduce losses from opening doors. Appliances Second Refrigerator Energy-efficient refrigerators/freezers incorporate features such as improved cabinet insulation, more efficient compressors and evaporator fans, defrost controls, mullion heaters, oversized condenser coils, and improved door seals. Further efficiency increases can be obtained by reducing the volume of refrigerated space, or adding multiple compartments to reduce losses from opening doors. Appliances Freezer Energy-efficient refrigerators/freezers incorporate features such as improved cabinet insulation, more efficient compressors and evaporator fans, defrost controls, mullion heaters, oversized condenser coils, and improved door seals. Further efficiency increases can be obtained by reducing the volume of refrigerated space, or adding multiple compartments to reduce losses from opening doors. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 907 of 1125 Residential Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting B-5 End Use Technology Measure Description Appliances Clothes Washer High efficiency clothes washers use superior designs that require less water. Sensors match the hot water needs to the size and soil level of the load, preventing energy waste. Further energy and water savings can be achieved through advanced technologies such as inverter-drive or combination washer-dryer units. MEF is the official energy efficiency metric used to compare relative efficiencies of different clothes washers. MEF considers the energy used to run the washer, heat the water, and run the dryer. The higher the MEF, the more efficient the clothes washer. Appliances Clothes Dryer An energy-efficient clothes dryer has a moisture-sensing device to terminate the drying cycle rather than using a timer and an energy- efficient motor is used for spinning the dryer tub. Application of a heat pump cycle for extracting the moisture from clothes leads to additional energy savings. Appliances Dishwasher High efficiency dishwashers save by using both improved technology for the primary wash cycle, and by using less hot water. Construction includes more effective washing action, energy-efficient motors, and other advanced technology such as sensors that determine the length of the wash cycle and the temperature of the water necessary to clean the dishes. Appliances Stove These products have additional insulation in the oven compartment and tighter-fitting oven door gaskets and hinges to save energy. Conventional ovens must first heat up about 35 pounds of steel and a large amount of air before they heat up the food. Higher efficiency options include convection ovens, halogen burners, and induction burners. Appliances Microwave No high efficiency option is modeled. Electronics Personal Computers Improved power management can significantly reduce the annual energy consumption of PCs and monitors in both standby and normal operation. ENERGY STAR and Climate Savers labeled products provide increasing level of energy efficiency. Electronics TVs In the average home, TVs consume significant energy, even when they are turned off, to maintain features like clocks, remote control, and channel/station memory. ENERGY STAR labeled consumer electronics can drastically reduce consumption during standby mode, in addition to saving energy through advanced power management during normal use. Electronics Devices and Gadgets High efficiency electronics can use efficient components and employ sleep/powersave modes. Electronics Set-top Boxes/DVR High efficiency electronics can use efficient components and employ sleep/powersave modes. Miscellaneous Pool Pump High-efficiency motors and two-speed pumps provide improved energy efficiency for this load. Miscellaneous Furnace Fan In homes heated by a furnace, there is still substantial energy use by the fan responsible for moving the hot air throughout the ductwork. Application of an Electronically Commutating Motor (ECM) ensures that motor speed matches the heating requirements of the system and saves energy when compared to a continuously operating standard motor. Miscellaneous Miscellaneous Improvement of miscellaneous electricity uses. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 908 of 1125 Residential Energy Efficiency Equipment and Measure Data B-6 www.enernoc.com Table B-2 Residential Energy Efficiency Non-Equipment Measure Descriptions End Use Measure Description HVAC (All) Insulation - Ceiling Thermal insulation is material or combinations of materials that are used to inhibit the flow of heat energy by conductive, convective, and radiative transfer modes. Thus, thermal insulation above ceilings can conserve energy by reducing the heat loss or gain into attics and/or through roofs. The type of building construction defines insulating possibilities. Typical insulating materials include: loose-fill (blown) cellulose, loose-fill (blown) fiberglass, and rigid polystyrene. Cooling Insulation - Ducting Air distribution ducts can be insulated to reduce heating or cooling losses. Best results can be achieved by covering the entire surface area with insulation. Several types of ducts and duct insulation are available, including flexible duct, pre-insulated duct, duct board, duct wrap, tacked, or glued rigid insulation, and waterproof hard shell materials for exterior ducts. This analysis assumes that installing duct insulation can reduce the temperature drop/gain in ducts by 50%. HVAC (All) Insulation - Foundation Thermal insulation is material or combinations of materials that are used to inhibit the flow of heat energy by conductive, convective, and radiative transfer modes. Thus, thermal insulation can conserve energy by reducing heat loss or gain from a building. The type of building construction defines insulating possibilities. Typical insulating materials include: loose-fill (blown) cellulose, loose-fill (blown) fiberglass, and rigid polystyrene. Foundation insulation is modeled for new construction / major retrofits only. HVAC (All) Insulation - Infiltration Control Lowering the air infiltration rate by caulking small leaks and weather-stripping around window frames, doorframes, power outlets, plumbing, and wall corners can provide significant energy savings. Weather-stripping doors and windows will create a tight seal and further reduce air infiltration. HVAC (All) Insulation - Radiant Barrier Radiant barriers are materials installed to reduce the heat gain in buildings. Radiant barriers are made from materials that are highly reflective and have low emissivity like aluminum. The closer the emissivity is to 0 the better they will perform. Radiant barriers can be placed above the insulation or on the roof rafters. HVAC (All) Insulation - Wall Cavity Thermal insulation is material or combinations of materials that are used to inhibit the flow of heat energy by conductive, convective, and radiative transfer modes. Thus, thermal insulation can conserve energy by reducing heat loss or gain from a building. The type of building construction defines insulating possibilities. Typical insulating materials include: loose-fill (blown) cellulose, loose-fill (blown) fiberglass, and rigid polystyrene. Wall insulation is modeled for new construction / major retrofits only. HVAC (All) Insulation - Wall Sheathing Thermal insulation is material or combinations of materials that are used to inhibit the flow of heat energy by conductive, convective, and radiative transfer modes. Thus, thermal insulation can conserve energy by reducing heat loss or gain from a building. The type of building construction defines insulating possibilities. Typical insulating materials include: loose-fill (blown) cellulose, loose-fill (blown) fiberglass, and rigid polystyrene. Wall sheathing is modeled for new construction / major retrofits only. Cooling Ducting - Repair and Sealing Leakage in unsealed ducts varies considerably because of the differences in fabricating machinery used, the methods for assembly, installation workmanship, and age of the ductwork. Air leaks from the system to the outdoors result in a direct loss proportional to the amount of leakage and the difference in enthalpy between the outdoor air and the conditioned air. To seal ducts, a wide variety of sealing methods and products exist. Each has a relatively short shelf life, and no documented research has identified the aging characteristics of sealant applications. HVAC (All) Windows - High Efficiency/ENERGY STAR High-efficiency windows, such as those labeled under the ENERGY STAR Program, are designed to reduce energy use and increase occupant comfort. High-efficiency windows reduce the amount of heat transfer through the Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 909 of 1125 Residential Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting B-7 End Use Measure Description glazing surface. For example, some windows have a low-E coating, a thin film of metallic oxide coating on the glass surface that allows passage of short-wave solar energy through glass and prevents long-wave energy from escaping. Another example is double-pane glass that reduces conductive and convective heat transfer. Some double-pane windows are gas-filled (usually argon) to further increase the insulating properties of the window. HVAC (All) Windows - Install Reflective Film Reflective films applied to the window interior help reduce solar gain into the space and thus lower cooling energy use. HVAC (All) Doors - Storm and Thermal Like other components of the shell, doors are subject to several types of heat loss: conduction, infiltration, and radiant losses. Similar to a storm window, a storm door creates an insulating air space between the storm and primary doors. A tight fitting storm door can also help reduce air leakage or infiltration. Thermal doors have exceptional thermal insulation properties and also are provided with weather-stripping on the doorframe to reduce air leakage. HVAC (All) Roofs - High Reflectivity The color and material of a building structure surface will determine the amount of solar radiation absorbed by that surface and subsequently transferred into a building. This is called solar absorptance. By using a living roof or a roofing material with a light color (and a lower solar absorptance), the roof will absorb less solar radiation and consequently reduce the cooling load. Living roofs also reduce stormwater runoff. HVAC (All) Attic Fan - Installation Attic fans can reduce the need for AC by reducing heat transfer from the attic through the ceiling of the house. A well-ventilated attic can be several degrees cooler than a comparable, unventilated attic. An option for an attic fan equipped with a small solar photovoltaic generator is also modeled. HVAC (All) Attic Fan - Photovoltaic - Installation Attic fans can reduce the need for AC by reducing heat transfer from the attic through the ceiling of the house. A well-ventilated attic can be several degrees cooler than a comparable, unventilated attic. An option for an attic fan equipped with a small solar photovoltaic generator is also modeled. HVAC (All) Whole-House Fan - Installation Whole-house fans can reduce the need for AC on moderate-weather days or on cool evenings. The fan facilitates a quick air change throughout the entire house. Several windows must be open to achieve the best results. The fan is mounted on the top floor of the house, usually in a hallway ceiling. HVAC (All) Ceiling Fan - Installation Ceiling fans can reduce the need for air conditioning. However, the house occupants must also select a ceiling fan with a high-efficiency motor and either shutoff the AC system or setup the thermostat temperature of the air conditioning system to realize the potential energy savings. Some ceiling fans also come with lamps. In this analysis, it is assumed that there are no lamps, and installing a ceiling fan will allow occupants to increase the thermostat cooling setpoint up by 2°F. HVAC (All) Thermostat - Clock/Programmable A programmable thermostat can be added to most heating/cooling systems. They are typically used during winter to lower temperatures at night and in summer to increase temperatures during the afternoon. The energy savings from this type of thermostat are identical to those of a "setback" strategy with standard thermostats, but the convenience of a programmable thermostat makes it a much more attractive option. In this analysis, the baseline is assumed to have no thermostat setback. HVAC (All) Home Energy Management System A centralized home energy management system can be used to control and schedule cooling, space heating, lighting, and possibly appliances as well. Some designs also allow the homeowner to remotely control loads via the Internet. Cooling Central AC - Early Replacement CAC systems currently on the market are significantly more efficient that older units, due to technology improvement and stricter appliance standards. This measure incents homeowners to replace an aging but still working unit with a new, higher-efficiency one. Cooling Central AC - Maintenance and Tune-Up An air conditioner's filters, coils, and fins require regular cleaning and maintenance for the unit to function effectively and efficiently throughout its life. Neglecting necessary maintenance leads to a steady decline in Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 910 of 1125 Residential Energy Efficiency Equipment and Measure Data B-8 www.enernoc.com End Use Measure Description performance, requiring the AC unit to use more energy for the same cooling load. Cooling / Space Heating Central Heat Pump - Maintenance A heat pump's filters, coils, and fins require regular cleaning and maintenance for the unit to function effectively and efficiently throughout its life. Neglecting necessary maintenance ensures a steady decline in performance while energy use steadily increases. Cooling Room AC - Removal of Second Unit Homeowners may have a second room AC unit that is extremely inefficient. This measure incents homeowners to recycle the second unit and thus also eliminates associated electricity use. Water Heating Water Heater - Drainwater Heat Recovery Drainwater Heat Recovery is a system in which drain water is used to preheat cold water entering the water heater. While these systems themselves are relatively inexpensive, upgrading an existing system could be unreasonable because of demolition costs. Thus they are modeled for new vintage only. Water Heating Water Heater - Faucet Aerators Water faucet aerators are threaded screens that attach to existing faucets. They reduce the volume of water coming out of faucets while introducing air into the water stream. This measure provides energy saving by reducing hot water use, as well as water conservation for both hot and cold water. Water Heating Water Heater - Low- Flow Showerheads Similar to faucet aerators, low-flow showerheads reduce the consumption of hot water, which in turn decreases water heating energy use. Water Heating Water Heater - Pipe Insulation Insulating hot water pipes decreases energy losses from piping that distributes hot water throughout the building. It also results in quicker delivery of hot water and may allow the lowering of the hot water set point, which saves energy. The most common insulation materials for this purpose are polyethylene and neoprene. Water Heating Water Heater - Timer These measures use either a programmable thermostat or a timer to adjust the water heater setpoint at times of low usage, typically when a home is unoccupied. Water Heating Water Heater - Desuperheater A desuperheater can be added to an existing geothermal heat pump system (typically installed with the primary function of space heating and cooling) in order to draw off a portion of the geothermal heat for water heating purposes. The system can either supplement the building's water heater, or be a full- demand water heater that meets all of the building's hot water needs. Water Heating Water Heater - Solar System Solar water heating systems can be used in residential buildings that have an appropriate near-south-facing roof or nearby unshaded grounds for installing a collector. Although system types vary, in general these systems use a solar absorber surface within a solar collector or an actual storage tank. Either a heat-transfer fluid or the actual potable water flows through tubes attached to the absorber and transfers heat from it. (Systems with a separate heat- transfer-fluid loop include a heat exchanger that then heats the potable water.) The heated water is stored in a separate preheat tank or a conventional water heater tank. If additional heat is needed, it is provided by a conventional water-heating system. Water Heating Tank Blanket Insulation Many water heaters have a high factory-set temperature, at 140 degrees F or higher, but most users operate comfortably with the thermostat at 120 degrees F. Reducing the water heater temperature by as little as 10 degrees can save between 3-5% in energy costs. Water Heating Thermostat Setback Many water heaters have a high factory-set temperature, at 140 degrees F or higher, but most users operate comfortably with the thermostat at 125 degrees F. Reducing the water heater temperature by as little as 10 degrees can save between 3-5% in energy costs. Interior Lighting Interior Lighting - Occupancy Sensors Occupancy sensors turn lights off when a space is unoccupied. They are appropriate for areas with intermittent use, such as bathrooms or storage areas. Exterior Lighting Exterior Lighting - Photosensor Control Photosensor controls turn exterior lighting on or off based on ambient lighting levels. Compared with manual operation, this can reduce the operation of Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 911 of 1125 Residential Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting B-9 End Use Measure Description exterior lighting during daylight hours. Exterior Lighting Exterior Lighting - Photovoltaic Installation Solar photovoltaic generation may be used to power exterior lighting and thus eliminate all or part of the electrical energy use. Exterior Lighting Exterior Lighting - Timeclock Installation Lighting timers turn exterior lighting on or off based on a preset schedule. Compared with manual operation, this can reduce the operation of exterior lighting during daylight hours. Appliances Refrigerator - Early Replacement Refrigerators/freezers currently on the market are significantly more efficient that older units, due to technology improvement and stricter appliance standards. This measure incents homeowners to replace an aging but still working unit with a new, higher-efficiency one. Appliances Refrigerator - Remove Second Unit Homeowners may have a second refrigerator or freezer that is not used to full capacity and that, because of its age, is extremely inefficient. This measure incents homeowners to recycle the second unit and thus also eliminates associated electricity use. Appliances Freezer - Remove Second Unit Homeowners may have a second refrigerator or freezer that is not used to full capacity and that, because of its age, is extremely inefficient. This measure incents homeowners to recycle the second unit and thus also eliminates associated electricity use. Appliances Freezer - Early Replacement Refrigerators/freezers currently on the market are significantly more efficient that older units, due to technology improvement and stricter appliance standards. This measure incents homeowners to replace an aging but still working unit with a new, higher-efficiency one. Electronics Reduce Standby Wattage - Smart Power Strips Representing a growing portion of home electricity consumption, plug-in electronics such as set-top boxes, DVD players, gaming systems, digital video recorders, and even battery chargers for mobile phones and laptop computers are often designed to supply a set voltage. When the units are not in use, this voltage could be dropped significantly (~1 W) and thereby generate a significant energy savings, assumed for this analysis to be between 4-5% on average. These savings are in excess of the measures already discussed for computers and televisions. Miscellaneous Pool Pump - Timer A pool pump timer allows the pump to turn off automatically, eliminating the wasted energy associated with unnecessary pumping. Miscellaneous Behavioral Measures The behavioral measure models the wide range of options for providing homeowners with ongoing information on their energy use, for example via a web portal. These tools are based on the premise that homeowners will reduce energy use if they better understand how they use energy and the associated costs. The level of assumed savings is based on isolated behavioral effects and excludes the technology effects of all other measures listed here. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 912 of 1125 Residential Energy Efficiency Equipment and Measure Data B-10 www.enernoc.com Table B-3 Energy Efficiency Equipment Data, Electric—Single Family, Existing Vintage, Washington End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Cooling Central AC SEER 13 - $0.00 15 - $0.00 Cooling Central AC SEER 14 (Energy Star) 116.70 $277.86 15 1.40 $0.21 Cooling Central AC SEER 15 (CEE Tier 2) 160.13 $555.71 15 0.95 $0.30 Cooling Central AC SEER 16 (CEE Tier 3) 196.50 $833.57 15 0.90 $0.37 Cooling Central AC Ductless Mini-Split System 352.42 $4,399.48 20 0.64 $0.88 Cooling Room AC EER 9.8 - $0.00 10 1.00 $0.00 Cooling Room AC EER 10.8 (Energy Star) 46.56 $104.04 10 0.84 $0.26 Cooling Room AC EER 11 54.94 $282.26 10 0.64 $0.61 Cooling Room AC EER 11.5 74.37 $625.50 10 0.44 $1.00 Cooling Air Source Heat Pump SEER 13 - $0.00 15 - $0.00 Cooling Air Source Heat Pump SEER 14 (Energy Star) 85.84 $0.00 15 1.30 $0.00 Cooling Air Source Heat Pump SEER 15 (CEE Tier 2) 97.34 $0.00 15 0.89 $0.00 Cooling Air Source Heat Pump SEER 16 (CEE Tier 3) 119.45 $0.00 15 0.83 $0.00 Cooling Air Source Heat Pump Ductless Mini-Split System 214.24 $0.00 20 0.83 $0.00 Cooling Geothermal Heat Pump Standard - $0.00 15 1.00 $0.00 Cooling Geothermal Heat Pump High Efficiency 104.84 $0.00 15 0.91 $0.00 Cooling Ductless HP Ductless Mini-Split System - $0.00 20 1.00 $0.00 Space Heating Electric Resistance Electric Resistance - $0.00 20 1.00 $0.00 Space Heating Electric Resistance Ductless Mini-Split System 3,605.70 $156.87 20 1.34 $0.00 Space Heating Electric Furnace 3400 BTU/KW - $0.00 15 1.00 $0.00 Space Heating Supplemental Supplemental - $0.00 5 1.00 $0.00 Space Heating Air Source Heat Pump SEER 13 - $0.00 15 - $0.00 Space Heating Air Source Heat Pump SEER 14 (Energy Star) 126.61 $67.05 15 1.30 $0.05 Space Heating Air Source Heat Pump SEER 15 (CEE Tier 2) 998.92 $2,318.20 15 0.89 $0.20 Space Heating Air Source Heat Pump SEER 16 (CEE Tier 3) 1,225.79 $3,504.51 15 0.83 $0.25 Space Heating Air Source Heat Pump Ductless Mini-Split System 2,198.46 $5,655.04 20 0.83 $0.18 Space Heating Geothermal Heat Pump Standard - $0.00 15 1.00 $0.00 Space Heating Geothermal Heat Pump High Efficiency 693.85 $1,500.00 15 0.91 $0.19 Space Heating Ductless HP Ductless Mini-Split System - $0.00 20 1.00 $0.00 Water Heating Water Heater <= 55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00 Water Heating Water Heater <= 55 Gal High Efficiency (EF=0.95) 207.44 $77.11 15 1.03 $0.03 Water Heating Water Heater <= 55 Gal EF 2.3 (HP) 1,999.65 $1,761.86 15 0.91 $0.08 Water Heating Water Heater <= 55 Gal Solar 2,791.58 $6,214.86 15 0.47 $0.19 Water Heating Water Heater > 55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00 Water Heating Water Heater > High Efficiency 264.15 $97.23 15 1.03 $0.03 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 913 of 1125 Residential Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting B-11 End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) 55 Gal (EF=0.95) Water Heating Water Heater > 55 Gal EF 2.3 (HP) 2,000.81 $1,691.15 15 0.93 $0.07 Water Heating Water Heater > 55 Gal Solar 3,154.00 $6,144.15 15 0.52 $0.17 Interior Lighting Screw-in Incandescent - $0.00 4 - $0.00 Interior Lighting Screw-in Infrared Halogen 269.42 $188.19 5 1.00 $0.15 Interior Lighting Screw-in CFL 855.57 $33.82 6 2.54 $0.01 Interior Lighting Screw-in LED 1,169.35 $1,937.55 12 - $0.17 Interior Lighting Screw-in LED 1,169.35 $1,937.55 12 - $0.17 Interior Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00 Interior Lighting Linear Fluorescent T8 11.21 -$3.65 6 1.14 -$0.06 Interior Lighting Linear Fluorescent Super T8 33.57 $29.17 6 0.70 $0.16 Interior Lighting Linear Fluorescent T5 34.89 $49.41 6 0.55 $0.26 Interior Lighting Linear Fluorescent LED 36.60 $433.68 10 0.19 $1.40 Interior Lighting Specialty Halogen - $0.00 4 1.00 $0.00 Interior Lighting Specialty CFL 263.66 $1.92 7 1.91 $0.00 Interior Lighting Specialty LED 277.40 $522.52 12 0.29 $0.19 Exterior Lighting Screw-in Incandescent - $0.00 4 - $0.00 Exterior Lighting Screw-in Infrared Halogen 92.90 $51.30 5 1.00 $0.12 Exterior Lighting Screw-in CFL 315.29 -$1.24 3 4.38 $0.00 Exterior Lighting Screw-in LED 365.98 $757.28 12 - $0.21 Exterior Lighting Screw-in LED 365.98 $757.28 12 - $0.21 Appliances Clothes Washer Baseline - $0.00 14 - $0.00 Appliances Clothes Washer Energy Star (MEF > 1.8) 51.92 $69.81 14 - $0.12 Appliances Clothes Washer Horizontal Axis 71.68 $150.80 14 1.00 $0.19 Appliances Clothes Dryer Baseline - $0.00 13 - $0.00 Appliances Clothes Dryer Moisture Detection 76.97 $48.40 13 1.00 $0.06 Appliances Dishwasher Baseline - $0.00 15 1.00 $0.00 Appliances Dishwasher Energy Star 64.27 $460.95 9 - $0.93 Appliances Dishwasher Energy Star (2011) 8.42 $5.61 15 1.00 $0.06 Appliances Refrigerator Baseline - $0.00 20 - $0.00 Appliances Refrigerator Energy Star 55.03 $20.67 20 - $0.03 Appliances Refrigerator Baseline (2014) 100.80 $0.00 13 1.00 $0.00 Appliances Refrigerator Energy Star (2014) 161.28 $88.71 13 1.02 $0.05 Appliances Freezer Baseline - $0.00 22 - $0.00 Appliances Freezer Energy Star 44.98 $3.98 22 - $0.01 Appliances Freezer Baseline (2014) 104.39 -$145.00 11 1.00 -$0.15 Appliances Freezer Energy Star (2014) 167.03 -$112.83 11 1.00 -$0.07 Appliances Second Refrigerator Baseline - $0.00 20 - $0.00 Appliances Second Refrigerator Energy Star 75.16 $20.67 20 - $0.02 Appliances Second Refrigerator Baseline (2014) 137.68 $0.00 13 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 914 of 1125 Residential Energy Efficiency Equipment and Measure Data B-12 www.enernoc.com End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Appliances Second Refrigerator Energy Star (2014) 220.29 $88.71 13 1.01 $0.04 Appliances Stove Baseline - $0.00 13 1.00 $0.00 Appliances Stove Convection Oven 10.67 $1.86 13 1.00 $0.02 Appliances Stove Induction (High Efficiency) 53.33 $1,432.20 13 0.39 $2.59 Appliances Microwave Baseline - $0.00 9 1.00 $0.00 Electronics Personal Computers Baseline - $0.00 5 1.00 $0.00 Electronics Personal Computers Energy Star 89.47 $1.20 5 1.01 $0.00 Electronics Personal Computers Climate Savers 127.82 $175.49 5 0.85 $0.30 Electronics TVs Baseline - $0.00 11 1.00 $0.00 Electronics TVs Energy Star 52.12 $0.56 10 0.95 $0.00 Electronics Set-top boxes/DVR Baseline - $0.00 11 1.00 $0.00 Electronics Set-top boxes/DVR Energy Star 31.55 $0.56 11 1.01 $0.00 Electronics Devices and Gadgets Devices and Gadgets - $0.00 5 1.00 $0.00 Miscellaneous Pool Pump Baseline Pump - $0.00 15 1.00 $0.00 Miscellaneous Pool Pump High Efficiency Pump 137.76 $85.00 15 1.00 $0.05 Miscellaneous Pool Pump Two-Speed Pump 551.02 $579.00 15 0.83 $0.09 Miscellaneous Furnace Fan Baseline - $0.00 18 1.00 $0.00 Miscellaneous Furnace Fan Furnace Fan with ECM 157.58 $0.64 18 1.28 $0.00 Miscellaneous Miscellaneous Miscellaneous - $0.00 5 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 915 of 1125 Residential Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting B-13 Table B-4 Energy Efficiency Equipment Data, Electric—Single Family, New Vintage, Washington End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Cooling Central AC SEER 13 - $0.00 15 - $0.00 Cooling Central AC SEER 14 (Energy Star) 148.36 $277.86 15 1.40 $0.16 Cooling Central AC SEER 15 (CEE Tier 2) 197.61 $555.71 15 0.95 $0.24 Cooling Central AC SEER 16 (CEE Tier 3) 238.95 $833.57 15 0.90 $0.30 Cooling Central AC Ductless Mini-Split System 448.12 $4,399.48 20 0.65 $0.69 Cooling Room AC EER 9.8 - $0.00 10 1.00 $0.00 Cooling Room AC EER 10.8 (Energy Star) 57.89 $104.04 10 0.85 $0.21 Cooling Room AC EER 11 68.22 $282.26 10 0.65 $0.49 Cooling Room AC EER 11.5 92.51 $625.50 10 0.45 $0.80 Cooling Air Source Heat Pump SEER 13 - $0.00 15 - $0.00 Cooling Air Source Heat Pump SEER 14 (Energy Star) 109.44 $67.05 15 1.30 $0.05 Cooling Air Source Heat Pump SEER 15 (CEE Tier 2) 120.45 $2,318.20 15 0.91 $1.66 Cooling Air Source Heat Pump SEER 16 (CEE Tier 3) 145.65 $3,504.51 15 0.85 $2.08 Cooling Air Source Heat Pump Ductless Mini-Split System 273.14 $5,655.04 20 0.87 $1.46 Cooling Geothermal Heat Pump Standard - $0.00 15 1.00 $0.00 Cooling Geothermal Heat Pump High Efficiency 124.81 $1,500.00 15 0.92 $1.04 Cooling Ductless HP Ductless Mini-Split System - $0.00 20 1.00 $0.00 Space Heating Electric Resistance Electric Resistance - $0.00 20 1.00 $0.00 Space Heating Electric Resistance Ductless Mini-Split System 4,146.56 $156.87 20 1.35 $0.00 Space Heating Electric Furnace 3400 BTU/KW - $0.00 15 1.00 $0.00 Space Heating Supplemental Supplemental - $0.00 5 1.00 $0.00 Space Heating Air Source Heat Pump SEER 13 - $0.00 15 - $0.00 Space Heating Air Source Heat Pump SEER 14 (Energy Star) 161.42 $67.05 15 1.30 $0.04 Space Heating Air Source Heat Pump SEER 15 (CEE Tier 2) 1,236.03 $2,318.20 15 0.91 $0.16 Space Heating Air Source Heat Pump SEER 16 (CEE Tier 3) 1,494.65 $3,504.51 15 0.85 $0.20 Space Heating Air Source Heat Pump Ductless Mini-Split System 2,802.94 $5,655.04 20 0.87 $0.14 Space Heating Geothermal Heat Pump Standard - $0.00 15 1.00 $0.00 Space Heating Geothermal Heat Pump High Efficiency 826.07 $1,500.00 15 0.92 $0.16 Space Heating Ductless HP Ductless Mini-Split System - $0.00 20 1.00 $0.00 Water Heating Water Heater <= 55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00 Water Heating Water Heater <= 55 Gal High Efficiency (EF=0.95) 207.44 $77.11 15 1.03 $0.03 Water Heating Water Heater <= 55 Gal EF 2.3 (HP) 1,999.65 $1,761.86 15 0.91 $0.08 Water Heating Water Heater <= 55 Gal Solar 2,791.58 $6,214.86 15 0.47 $0.19 Water Heating Water Heater > 55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00 Water Heating Water Heater > High Efficiency 264.15 $97.23 15 1.03 $0.03 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 916 of 1125 Residential Energy Efficiency Equipment and Measure Data B-14 www.enernoc.com End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) 55 Gal (EF=0.95) Water Heating Water Heater > 55 Gal EF 2.3 (HP) 2,000.81 $1,691.15 15 0.93 $0.07 Water Heating Water Heater > 55 Gal Solar 3,154.00 $6,144.15 15 0.52 $0.17 Interior Lighting Screw-in Incandescent - $0.00 4 - $0.00 Interior Lighting Screw-in Infrared Halogen 307.59 $188.19 5 1.00 $0.13 Interior Lighting Screw-in CFL 976.77 $33.82 6 2.46 $0.01 Interior Lighting Screw-in LED 1,334.99 $1,937.55 12 - $0.15 Interior Lighting Screw-in LED 1,334.99 $1,937.55 12 - $0.15 Interior Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00 Interior Lighting Linear Fluorescent T8 13.19 -$3.65 6 1.13 -$0.05 Interior Lighting Linear Fluorescent Super T8 39.53 $29.17 6 0.73 $0.14 Interior Lighting Linear Fluorescent T5 41.09 $49.41 6 0.58 $0.22 Interior Lighting Linear Fluorescent LED 43.10 $433.68 10 0.21 $1.19 Interior Lighting Specialty Halogen - $0.00 4 1.00 $0.00 Interior Lighting Specialty CFL 303.20 -$6.90 7 2.33 $0.00 Interior Lighting Specialty LED 319.01 $163.55 12 0.76 $0.05 Exterior Lighting Screw-in Incandescent - $0.00 4 - $0.00 Exterior Lighting Screw-in Infrared Halogen 168.10 $20.17 5 1.00 $0.03 Exterior Lighting Screw-in CFL 473.06 $0.00 3 4.21 $0.00 Exterior Lighting Screw-in LED 599.29 $88.71 12 - $0.02 Exterior Lighting Screw-in LED 599.29 $88.71 12 - $0.02 Appliances Clothes Washer Baseline - $0.00 14 - $0.00 Appliances Clothes Washer Energy Star (MEF > 1.8) 100.07 $3.98 14 - $0.00 Appliances Clothes Washer Horizontal Axis 183.40 -$145.00 14 1.00 -$0.07 Appliances Clothes Dryer Baseline - $0.00 13 - $0.00 Appliances Clothes Dryer Moisture Detection 76.97 $48.40 13 1.00 $0.06 Appliances Dishwasher Baseline - $0.00 15 1.00 $0.00 Appliances Dishwasher Energy Star 64.52 $460.95 9 - $0.92 Appliances Dishwasher Energy Star (2011) 8.45 $5.61 15 1.00 $0.06 Appliances Refrigerator Baseline - $0.00 20 - $0.00 Appliances Refrigerator Energy Star 62.37 $20.17 20 - $0.02 Appliances Refrigerator Baseline (2014) 114.24 $0.00 13 1.00 $0.00 Appliances Refrigerator Energy Star (2014) 182.79 $88.71 13 1.02 $0.05 Appliances Freezer Baseline - $0.00 22 - $0.00 Appliances Freezer Energy Star 48.14 $3.98 22 - $0.01 Appliances Freezer Baseline (2014) 111.72 -$145.00 11 1.00 -$0.14 Appliances Freezer Energy Star (2014) 178.76 -$112.83 11 1.01 -$0.07 Appliances Second Refrigerator Baseline - $0.00 20 - $0.00 Appliances Second Refrigerator Energy Star 80.17 $20.67 20 - $0.02 Appliances Second Refrigerator Baseline (2014) 146.86 $0.00 13 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 917 of 1125 Residential Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting B-15 End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Appliances Second Refrigerator Energy Star (2014) 234.98 $88.71 13 1.01 $0.04 Appliances Stove Baseline - $0.00 13 1.00 $0.00 Appliances Stove Convection Oven 10.66 $1.86 13 1.00 $0.02 Appliances Stove Induction (High Efficiency) 53.32 $1,432.20 13 0.39 $2.59 Appliances Microwave Baseline - $0.00 9 1.00 $0.00 Electronics Personal Computers Baseline - $0.00 5 1.00 $0.00 Electronics Personal Computers Energy Star 87.57 $1.20 5 1.01 $0.00 Electronics Personal Computers Climate Savers 125.09 $175.49 5 0.85 $0.30 Electronics TVs Baseline - $0.00 11 1.00 $0.00 Electronics TVs Energy Star 57.91 $0.56 11 1.02 $0.00 Electronics Set-top boxes/DVR Baseline - $0.00 11 1.00 $0.00 Electronics Set-top boxes/DVR Energy Star 31.55 $0.56 11 1.01 $0.00 Electronics Devices and Gadgets Devices and Gadgets - $0.00 5 1.00 $0.00 Miscellaneous Pool Pump Baseline Pump - $0.00 15 1.00 $0.00 Miscellaneous Pool Pump High Efficiency Pump 155.66 $85.00 15 1.01 $0.05 Miscellaneous Pool Pump Two-Speed Pump 622.65 $579.00 15 0.88 $0.08 Miscellaneous Furnace Fan Baseline - $0.00 18 1.00 $0.00 Miscellaneous Furnace Fan Furnace Fan with ECM 157.58 $0.64 18 1.28 $0.00 Miscellaneous Miscellaneous Miscellaneous - $0.00 5 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 918 of 1125 Residential Energy Efficiency Equipment and Measure Data B-16 www.enernoc.com Table B-5 Energy Efficiency Equipment Data, Electric—Single Family, Existing Vintage, Idaho End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Cooling Central AC SEER 13 - $0.00 15 - $0.00 Cooling Central AC SEER 14 (Energy Star) 105.03 $277.86 15 1.40 $0.23 Cooling Central AC SEER 15 (CEE Tier 2) 144.12 $555.71 15 0.94 $0.33 Cooling Central AC SEER 16 (CEE Tier 3) 176.85 $833.57 15 0.89 $0.41 Cooling Central AC Ductless Mini-Split System 317.18 $4,399.48 20 0.64 $0.98 Cooling Room AC EER 9.8 - $0.00 10 1.00 $0.00 Cooling Room AC EER 10.8 (Energy Star) 41.90 $104.04 10 0.83 $0.29 Cooling Room AC EER 11 49.45 $282.26 10 0.63 $0.68 Cooling Room AC EER 11.5 66.94 $625.50 10 0.43 $1.11 Cooling Air Source Heat Pump SEER 13 - $0.00 15 - $0.00 Cooling Air Source Heat Pump SEER 14 (Energy Star) 77.25 $0.00 15 1.30 $0.00 Cooling Air Source Heat Pump SEER 15 (CEE Tier 2) 87.61 $0.00 15 0.89 $0.00 Cooling Air Source Heat Pump SEER 16 (CEE Tier 3) 107.51 $0.00 15 0.84 $0.00 Cooling Air Source Heat Pump Ductless Mini-Split System 192.81 $0.00 20 0.85 $0.00 Cooling Geothermal Heat Pump Standard - $0.00 15 1.00 $0.00 Cooling Geothermal Heat Pump High Efficiency 94.35 $0.00 15 0.91 $0.00 Cooling Ductless HP Ductless Mini-Split System - $0.00 20 1.00 $0.00 Space Heating Electric Resistance Electric Resistance - $0.00 20 1.00 $0.00 Space Heating Electric Resistance Ductless Mini-Split System 3,785.99 $156.87 20 1.35 $0.00 Space Heating Electric Furnace 3400 BTU/KW - $0.00 15 1.00 $0.00 Space Heating Supplemental Supplemental - $0.00 5 1.00 $0.00 Space Heating Air Source Heat Pump SEER 13 - $0.00 15 - $0.00 Space Heating Air Source Heat Pump SEER 14 (Energy Star) 132.94 $67.05 15 1.30 $0.04 Space Heating Air Source Heat Pump SEER 15 (CEE Tier 2) 1,048.86 $2,318.20 15 0.89 $0.19 Space Heating Air Source Heat Pump SEER 16 (CEE Tier 3) 1,287.08 $3,504.51 15 0.84 $0.24 Space Heating Air Source Heat Pump Ductless Mini-Split System 2,308.39 $5,655.04 20 0.85 $0.17 Space Heating Geothermal Heat Pump Standard - $0.00 15 1.00 $0.00 Space Heating Geothermal Heat Pump High Efficiency 728.55 $1,500.00 15 0.91 $0.18 Space Heating Ductless HP Ductless Mini-Split System - $0.00 20 1.00 $0.00 Water Heating Water Heater <= 55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00 Water Heating Water Heater <= 55 Gal High Efficiency (EF=0.95) 217.82 $77.11 15 1.03 $0.03 Water Heating Water Heater <= 55 Gal EF 2.3 (HP) 2,099.63 $1,761.86 15 0.87 $0.07 Water Heating Water Heater <= 55 Gal Solar 2,931.16 $6,214.86 15 0.44 $0.18 Water Heating Water Heater > 55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00 Water Heating Water Heater > 55 Gal High Efficiency (EF=0.95) 277.36 $97.23 15 1.03 $0.03 Water Heating Water Heater > EF 2.3 (HP) 2,100.85 $1,691.15 15 0.90 $0.07 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 919 of 1125 Residential Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting B-17 End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) 55 Gal Water Heating Water Heater > 55 Gal Solar 1,877.26 $6,144.15 15 0.43 $0.28 Interior Lighting Screw-in Incandescent - $0.00 4 - $0.00 Interior Lighting Screw-in Infrared Halogen 282.89 $188.19 5 1.00 $0.14 Interior Lighting Screw-in CFL 898.35 $33.82 6 2.59 $0.01 Interior Lighting Screw-in LED 1,227.82 $1,937.55 12 - $0.16 Interior Lighting Screw-in LED 1,227.82 $1,937.55 12 - $0.16 Interior Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00 Interior Lighting Linear Fluorescent T8 11.77 -$3.50 6 1.14 -$0.05 Interior Lighting Linear Fluorescent Super T8 35.25 $28.01 6 0.71 $0.15 Interior Lighting Linear Fluorescent T5 36.64 $47.43 6 0.56 $0.24 Interior Lighting Linear Fluorescent LED 38.43 $416.33 10 0.20 $1.28 Interior Lighting Specialty Halogen - $0.00 4 1.00 $0.00 Interior Lighting Specialty CFL 276.84 $1.92 7 1.93 $0.00 Interior Lighting Specialty LED 291.27 $522.52 12 0.30 $0.18 Exterior Lighting Screw-in Incandescent - $0.00 4 - $0.00 Exterior Lighting Screw-in Infrared Halogen 97.55 $49.25 5 1.00 $0.11 Exterior Lighting Screw-in CFL 331.06 -$1.19 3 4.38 $0.00 Exterior Lighting Screw-in LED 384.28 $726.99 12 - $0.19 Exterior Lighting Screw-in LED 384.28 $726.99 12 - $0.19 Appliances Clothes Washer Baseline - $0.00 14 - $0.00 Appliances Clothes Washer Energy Star (MEF > 1.8) 51.92 $69.81 14 - $0.12 Appliances Clothes Washer Horizontal Axis 71.68 $150.80 14 1.00 $0.19 Appliances Clothes Dryer Baseline - $0.00 13 - $0.00 Appliances Clothes Dryer Moisture Detection 76.97 $48.40 13 1.00 $0.06 Appliances Dishwasher Baseline - $0.00 15 1.00 $0.00 Appliances Dishwasher Energy Star 64.27 $460.95 9 - $0.93 Appliances Dishwasher Energy Star (2011) 8.42 $5.61 15 1.00 $0.06 Appliances Refrigerator Baseline - $0.00 20 - $0.00 Appliances Refrigerator Energy Star 55.03 $20.17 20 - $0.03 Appliances Refrigerator Baseline (2014) 100.80 $0.00 13 1.00 $0.00 Appliances Refrigerator Energy Star (2014) 161.28 $88.71 13 1.01 $0.05 Appliances Freezer Baseline - $0.00 22 - $0.00 Appliances Freezer Energy Star 44.98 $3.98 22 - $0.01 Appliances Freezer Baseline (2014) 104.39 -$145.00 11 1.00 -$0.15 Appliances Freezer Energy Star (2014) 167.03 -$112.83 11 1.00 -$0.07 Appliances Second Refrigerator Baseline - $0.00 20 - $0.00 Appliances Second Refrigerator Energy Star 75.16 $20.67 20 - $0.02 Appliances Second Refrigerator Baseline (2014) 137.68 $0.00 13 1.00 $0.00 Appliances Second Refrigerator Energy Star (2014) 220.29 $88.71 13 1.01 $0.04 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 920 of 1125 Residential Energy Efficiency Equipment and Measure Data B-18 www.enernoc.com End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Appliances Stove Baseline - $0.00 13 1.00 $0.00 Appliances Stove Convection Oven 10.67 $1.86 13 1.00 $0.02 Appliances Stove Induction (High Efficiency) 53.33 $1,432.20 13 0.38 $2.59 Appliances Microwave Baseline - $0.00 9 1.00 $0.00 Electronics Personal Computers Baseline - $0.00 5 1.00 $0.00 Electronics Personal Computers Energy Star 89.47 $1.20 5 1.01 $0.00 Electronics Personal Computers Climate Savers 127.82 $175.49 5 0.85 $0.30 Electronics TVs Baseline - $0.00 11 1.00 $0.00 Electronics TVs Energy Star 52.12 $0.56 11 1.02 $0.00 Electronics Set-top boxes/DVR Baseline - $0.00 11 1.00 $0.00 Electronics Set-top boxes/DVR Energy Star 31.55 $0.56 11 1.01 $0.00 Electronics Devices and Gadgets Devices and Gadgets - $0.00 5 1.00 $0.00 Miscellaneous Pool Pump Baseline Pump - $0.00 15 1.00 $0.00 Miscellaneous Pool Pump High Efficiency Pump 137.76 $85.00 15 1.00 $0.05 Miscellaneous Pool Pump Two-Speed Pump 551.02 $579.00 15 0.83 $0.09 Miscellaneous Furnace Fan Baseline - $0.00 18 1.00 $0.00 Miscellaneous Furnace Fan Furnace Fan with ECM 165.46 $0.64 18 1.29 $0.00 Miscellaneous Miscellaneous Miscellaneous - $0.00 5 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 921 of 1125 Residential Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting B-19 Table B-6 Energy Efficiency Equipment Data, Electric—Single Family, New Vintage, Idaho End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Cooling Central AC SEER 13 - $0.00 15 - $0.00 Cooling Central AC SEER 14 (Energy Star) 133.52 $277.86 15 1.40 $0.18 Cooling Central AC SEER 15 (CEE Tier 2) 177.85 $555.71 15 0.95 $0.27 Cooling Central AC SEER 16 (CEE Tier 3) 215.06 $833.57 15 0.90 $0.34 Cooling Central AC Ductless Mini-Split System 403.30 $4,399.48 20 0.64 $0.77 Cooling Room AC EER 9.8 - $0.00 10 1.00 $0.00 Cooling Room AC EER 10.8 (Energy Star) 52.10 $104.04 10 0.84 $0.24 Cooling Room AC EER 11 61.40 $282.26 10 0.64 $0.55 Cooling Room AC EER 11.5 83.26 $625.50 10 0.44 $0.89 Cooling Air Source Heat Pump SEER 13 - $0.00 15 - $0.00 Cooling Air Source Heat Pump SEER 14 (Energy Star) 98.49 $67.05 15 1.30 $0.06 Cooling Air Source Heat Pump SEER 15 (CEE Tier 2) 108.40 $2,318.20 15 0.92 $1.85 Cooling Air Source Heat Pump SEER 16 (CEE Tier 3) 131.09 $3,504.51 15 0.87 $2.31 Cooling Air Source Heat Pump Ductless Mini-Split System 245.83 $5,655.04 20 0.88 $1.63 Cooling Geothermal Heat Pump Standard - $0.00 15 1.00 $0.00 Cooling Geothermal Heat Pump High Efficiency 112.33 $1,500.00 15 0.92 $1.15 Cooling Ductless HP Ductless Mini-Split System - $0.00 20 1.00 $0.00 Space Heating Electric Resistance Electric Resistance - $0.00 20 1.00 $0.00 Space Heating Electric Resistance Ductless Mini-Split System 4,353.88 $156.87 20 1.37 $0.00 Space Heating Electric Furnace 3400 BTU/KW - $0.00 15 1.00 $0.00 Space Heating Supplemental Supplemental - $0.00 5 1.00 $0.00 Space Heating Air Source Heat Pump SEER 13 - $0.00 15 - $0.00 Space Heating Air Source Heat Pump SEER 14 (Energy Star) 169.49 $67.05 15 1.30 $0.03 Space Heating Air Source Heat Pump SEER 15 (CEE Tier 2) 1,297.83 $2,318.20 15 0.92 $0.15 Space Heating Air Source Heat Pump SEER 16 (CEE Tier 3) 1,569.38 $3,504.51 15 0.87 $0.19 Space Heating Air Source Heat Pump Ductless Mini-Split System 2,943.09 $5,655.04 20 0.88 $0.14 Space Heating Geothermal Heat Pump Standard - $0.00 15 1.00 $0.00 Space Heating Geothermal Heat Pump High Efficiency 867.38 $1,500.00 15 0.92 $0.15 Space Heating Ductless HP Ductless Mini-Split System - $0.00 20 1.00 $0.00 Water Heating Water Heater <= 55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00 Water Heating Water Heater <= 55 Gal High Efficiency (EF=0.95) 217.82 $77.11 15 1.03 $0.03 Water Heating Water Heater <= 55 Gal EF 2.3 (HP) 2,099.63 $1,761.86 15 0.87 $0.07 Water Heating Water Heater <= 55 Gal Solar 2,931.16 $6,214.86 15 0.44 $0.18 Water Heating Water Heater > 55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00 Water Heating Water Heater > 55 Gal High Efficiency (EF=0.95) 277.36 $97.23 15 1.03 $0.03 Water Heating Water Heater > EF 2.3 (HP) 2,100.85 $1,691.15 15 0.90 $0.07 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 922 of 1125 Residential Energy Efficiency Equipment and Measure Data B-20 www.enernoc.com End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) 55 Gal Water Heating Water Heater > 55 Gal Solar 1,877.26 $6,144.15 15 0.43 $0.28 Interior Lighting Screw-in Incandescent - $0.00 4 - $0.00 Interior Lighting Screw-in Infrared Halogen 322.96 $188.19 5 1.00 $0.13 Interior Lighting Screw-in CFL 1,025.61 $33.82 6 2.51 $0.01 Interior Lighting Screw-in LED 1,401.74 $1,937.55 12 - $0.14 Interior Lighting Screw-in LED 1,401.74 $1,937.55 12 - $0.14 Interior Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00 Interior Lighting Linear Fluorescent T8 13.85 -$3.50 6 1.13 -$0.05 Interior Lighting Linear Fluorescent Super T8 41.50 $28.01 6 0.74 $0.12 Interior Lighting Linear Fluorescent T5 43.14 $47.43 6 0.59 $0.20 Interior Lighting Linear Fluorescent LED 45.26 $416.33 10 0.21 $1.09 Interior Lighting Specialty Halogen - $0.00 4 1.00 $0.00 Interior Lighting Specialty CFL 318.36 -$6.40 7 2.32 $0.00 Interior Lighting Specialty LED 334.96 $164.04 12 0.77 $0.05 Exterior Lighting Screw-in Incandescent - $0.00 4 - $0.00 Exterior Lighting Screw-in Infrared Halogen 173.38 $20.17 5 1.00 $0.03 Exterior Lighting Screw-in CFL 491.00 $0.00 3 4.30 $0.00 Exterior Lighting Screw-in LED 620.11 $88.71 12 - $0.01 Exterior Lighting Screw-in LED 620.11 $88.71 12 - $0.01 Appliances Clothes Washer Baseline - $0.00 14 - $0.00 Appliances Clothes Washer Energy Star (MEF > 1.8) 100.07 $3.98 14 - $0.00 Appliances Clothes Washer Horizontal Axis 183.40 -$145.00 14 1.00 -$0.07 Appliances Clothes Dryer Baseline - $0.00 13 - $0.00 Appliances Clothes Dryer Moisture Detection 76.97 $48.40 13 1.00 $0.06 Appliances Dishwasher Baseline - $0.00 15 1.00 $0.00 Appliances Dishwasher Energy Star 64.52 $460.95 9 - $0.92 Appliances Dishwasher Energy Star (2011) 8.45 $5.61 15 1.00 $0.06 Appliances Refrigerator Baseline - $0.00 20 - $0.00 Appliances Refrigerator Energy Star 62.37 $20.17 20 - $0.02 Appliances Refrigerator Baseline (2014) 114.24 $0.00 13 1.00 $0.00 Appliances Refrigerator Energy Star (2014) 182.79 $88.71 13 1.02 $0.05 Appliances Freezer Baseline - $0.00 22 - $0.00 Appliances Freezer Energy Star 48.14 $3.98 22 - $0.01 Appliances Freezer Baseline (2014) 111.72 -$145.00 11 1.00 -$0.14 Appliances Freezer Energy Star (2014) 178.76 -$112.83 11 1.00 -$0.07 Appliances Second Refrigerator Baseline - $0.00 20 - $0.00 Appliances Second Refrigerator Energy Star 80.17 $20.67 20 - $0.02 Appliances Second Refrigerator Baseline (2014) 146.86 $0.00 13 1.00 $0.00 Appliances Second Refrigerator Energy Star (2014) 234.98 $88.71 13 1.01 $0.04 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 923 of 1125 Residential Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting B-21 End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Appliances Stove Baseline - $0.00 13 1.00 $0.00 Appliances Stove Convection Oven 11.73 $1.86 13 1.00 $0.02 Appliances Stove Induction (High Efficiency) 58.65 $1,432.20 13 0.38 $2.35 Appliances Microwave Baseline - $0.00 9 1.00 $0.00 Electronics Personal Computers Baseline - $0.00 5 1.00 $0.00 Electronics Personal Computers Energy Star 87.57 $1.20 5 1.01 $0.00 Electronics Personal Computers Climate Savers 125.09 $175.49 5 0.85 $0.30 Electronics TVs Baseline - $0.00 11 1.00 $0.00 Electronics TVs Energy Star 57.91 $0.56 11 1.02 $0.00 Electronics Set-top boxes/DVR Baseline - $0.00 11 1.00 $0.00 Electronics Set-top boxes/DVR Energy Star 31.55 $0.56 11 1.01 $0.00 Electronics Devices and Gadgets Devices and Gadgets - $0.00 5 1.00 $0.00 Miscellaneous Pool Pump Baseline Pump - $0.00 15 1.00 $0.00 Miscellaneous Pool Pump High Efficiency Pump 155.66 $85.00 15 1.01 $0.05 Miscellaneous Pool Pump Two-Speed Pump 622.65 $579.00 15 0.87 $0.08 Miscellaneous Furnace Fan Baseline - $0.00 18 1.00 $0.00 Miscellaneous Furnace Fan Furnace Fan with ECM 165.46 $0.64 18 1.29 $0.00 Miscellaneous Miscellaneous Miscellaneous - $0.00 5 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 924 of 1125 Residential Energy Efficiency Equipment and Measure Data B-22 www.enernoc.com Table B-7 Energy Efficiency Equipment Data, Electric—Multi Family, Existing Vintage, Washington End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Cooling Central AC SEER 13 - $0.00 15 - $0.00 Cooling Central AC SEER 14 (Energy Star) 41.57 $92.62 15 1.40 $0.19 Cooling Central AC SEER 15 (CEE Tier 2) 81.72 $185.24 15 0.96 $0.20 Cooling Central AC SEER 16 (CEE Tier 3) 115.28 $277.86 15 0.93 $0.21 Cooling Central AC Ductless Mini-Split System 150.88 $2,012.28 20 0.62 $0.94 Cooling Room AC EER 9.8 - $0.00 10 1.00 $0.00 Cooling Room AC EER 10.8 (Energy Star) 32.61 $52.02 10 0.86 $0.19 Cooling Room AC EER 11 38.42 $141.13 10 0.66 $0.44 Cooling Room AC EER 11.5 52.05 $312.75 10 0.46 $0.71 Cooling Air Source Heat Pump SEER 13 - $0.00 15 - $0.00 Cooling Air Source Heat Pump SEER 14 (Energy Star) 44.14 $1,245.78 15 1.30 $2.44 Cooling Air Source Heat Pump SEER 15 (CEE Tier 2) 71.87 $2,315.13 15 0.92 $2.79 Cooling Air Source Heat Pump SEER 16 (CEE Tier 3) 101.38 $3,277.48 15 0.85 $2.80 Cooling Air Source Heat Pump Ductless Mini-Split System 132.69 $5,022.03 20 0.85 $2.68 Cooling Geothermal Heat Pump Standard - $0.00 15 1.00 $0.00 Cooling Geothermal Heat Pump High Efficiency 63.75 $1,500.00 15 0.89 $2.03 Cooling Ductless HP Ductless Mini-Split System - $0.00 20 1.00 $0.00 Space Heating Electric Resistance Electric Resistance - $0.00 20 1.00 $0.00 Space Heating Electric Resistance Ductless Mini-Split System 1,812.94 $156.87 20 1.27 $0.01 Space Heating Electric Furnace 3400 BTU/KW - $0.00 15 1.00 $0.00 Space Heating Supplemental Supplemental - $0.00 5 1.00 $0.00 Space Heating Air Source Heat Pump SEER 13 - $0.00 15 - $0.00 Space Heating Air Source Heat Pump SEER 14 (Energy Star) 172.19 $1,245.78 15 1.30 $0.63 Space Heating Air Source Heat Pump SEER 15 (CEE Tier 2) 538.74 $2,315.13 15 0.92 $0.37 Space Heating Air Source Heat Pump SEER 16 (CEE Tier 3) 760.01 $3,277.48 15 0.85 $0.37 Space Heating Air Source Heat Pump Ductless Mini-Split System 994.66 $5,022.03 20 0.85 $0.36 Space Heating Geothermal Heat Pump Standard - $0.00 15 1.00 $0.00 Space Heating Geothermal Heat Pump High Efficiency 416.01 $1,500.00 15 0.89 $0.31 Space Heating Ductless HP Ductless Mini-Split System - $0.00 20 1.00 $0.00 Water Heating Water Heater <= 55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00 Water Heating Water Heater <= 55 Gal High Efficiency (EF=0.95) 110.09 $77.11 15 1.01 $0.06 Water Heating Water Heater <= 55 Gal EF 2.3 (HP) 1,061.19 $1,761.86 15 0.64 $0.14 Water Heating Water Heater <= 55 Gal Solar 1,202.35 $6,214.86 15 0.27 $0.45 Water Heating Water Heater > 55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00 Water Heating Water Heater > High Efficiency 182.05 $97.23 15 1.02 $0.05 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 925 of 1125 Residential Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting B-23 End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) 55 Gal (EF=0.95) Water Heating Water Heater > 55 Gal EF 2.3 (HP) 1,378.92 $1,691.15 15 0.78 $0.11 Water Heating Water Heater > 55 Gal Solar 1,231.85 $6,144.15 15 0.35 $0.43 Interior Lighting Screw-in Incandescent - $0.00 4 - $0.00 Interior Lighting Screw-in Infrared Halogen 163.13 $134.14 5 1.00 $0.18 Interior Lighting Screw-in CFL 518.03 $12.45 6 2.94 $0.00 Interior Lighting Screw-in LED 708.02 $1,161.45 12 - $0.17 Interior Lighting Screw-in LED 708.02 $1,161.45 12 - $0.17 Interior Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00 Interior Lighting Linear Fluorescent T8 7.79 -$1.83 6 1.13 -$0.04 Interior Lighting Linear Fluorescent Super T8 23.35 $14.59 6 0.76 $0.11 Interior Lighting Linear Fluorescent T5 24.27 $24.70 6 0.61 $0.19 Interior Lighting Linear Fluorescent LED 25.46 $216.84 10 0.23 $1.01 Interior Lighting Specialty Halogen - $0.00 4 1.00 $0.00 Interior Lighting Specialty CFL 105.71 $0.77 7 1.91 $0.00 Interior Lighting Specialty LED 111.22 $209.01 12 0.29 $0.19 Exterior Lighting Screw-in Incandescent - $0.00 4 - $0.00 Exterior Lighting Screw-in Infrared Halogen 5.39 $5.08 5 1.00 $0.20 Exterior Lighting Screw-in CFL 18.28 -$0.32 3 5.74 -$0.01 Exterior Lighting Screw-in LED 21.22 $1,167.57 12 - $5.64 Exterior Lighting Screw-in LED 21.22 $1,167.57 12 - $5.64 Appliances Clothes Washer Baseline - $0.00 14 - $0.00 Appliances Clothes Washer Energy Star (MEF > 1.8) 41.54 $69.81 14 - $0.15 Appliances Clothes Washer Horizontal Axis 57.34 $150.80 14 1.00 $0.24 Appliances Clothes Dryer Baseline - $0.00 13 - $0.00 Appliances Clothes Dryer Moisture Detection 61.35 $48.40 13 1.00 $0.08 Appliances Dishwasher Baseline - $0.00 15 1.00 $0.00 Appliances Dishwasher Energy Star 51.42 $460.95 15 - $0.78 Appliances Dishwasher Energy Star (2011) 6.74 $5.61 15 1.00 $0.07 Appliances Refrigerator Baseline - $0.00 20 - $0.00 Appliances Refrigerator Energy Star 44.02 $20.17 20 - $0.03 Appliances Refrigerator Baseline (2014) 80.64 $0.00 13 1.00 $0.00 Appliances Refrigerator Energy Star (2014) 129.03 $88.71 13 1.01 $0.07 Appliances Freezer Baseline - $0.00 22 - $0.00 Appliances Freezer Energy Star 35.99 $3.98 22 - $0.01 Appliances Freezer Baseline (2014) 83.52 -$145.00 11 1.00 -$0.19 Appliances Freezer Energy Star (2014) 133.62 -$112.83 11 0.99 -$0.09 Appliances Second Refrigerator Baseline - $0.00 20 - $0.00 Appliances Second Refrigerator Energy Star 60.13 $20.67 20 - $0.02 Appliances Second Refrigerator Baseline (2014) 110.14 $0.00 13 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 926 of 1125 Residential Energy Efficiency Equipment and Measure Data B-24 www.enernoc.com End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Appliances Second Refrigerator Energy Star (2014) 176.23 $88.71 13 1.01 $0.05 Appliances Stove Baseline - $0.00 13 1.00 $0.00 Appliances Stove Convection Oven 8.53 $1.86 13 1.00 $0.02 Appliances Stove Induction (High Efficiency) 42.66 $1,432.20 13 0.38 $3.23 Appliances Microwave Baseline - $0.00 9 1.00 $0.00 Electronics Personal Computers Baseline - $0.00 5 1.00 $0.00 Electronics Personal Computers Energy Star 71.58 $1.20 5 1.01 $0.00 Electronics Personal Computers Climate Savers 102.26 $175.49 5 0.85 $0.37 Electronics TVs Baseline - $0.00 11 1.00 $0.00 Electronics TVs Energy Star 46.91 $0.56 11 1.02 $0.00 Electronics Set-top boxes/DVR Baseline - $0.00 11 1.00 $0.00 Electronics Set-top boxes/DVR Energy Star 31.55 $0.56 11 1.01 $0.00 Electronics Devices and Gadgets Devices and Gadgets - $0.00 5 1.00 $0.00 Miscellaneous Pool Pump Baseline Pump - $0.00 15 1.00 $0.00 Miscellaneous Pool Pump High Efficiency Pump 137.76 $85.00 15 1.00 $0.05 Miscellaneous Pool Pump Two-Speed Pump 551.02 $579.00 15 0.83 $0.09 Miscellaneous Furnace Fan Baseline - $0.00 18 1.00 $0.00 Miscellaneous Furnace Fan Furnace Fan with ECM 126.06 $0.00 18 1.27 $0.00 Miscellaneous Miscellaneous Miscellaneous - $0.00 5 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 927 of 1125 Residential Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting B-25 Table B-8 Energy EfficiencyEquipment Data, Electric—Multi Family, New Vintage, Washington End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Cooling Central AC SEER 13 - $0.00 15 - $0.00 Cooling Central AC SEER 14 (Energy Star) 53.20 $92.62 15 1.40 $0.15 Cooling Central AC SEER 15 (CEE Tier 2) 103.85 $185.24 15 0.97 $0.15 Cooling Central AC SEER 16 (CEE Tier 3) 146.35 $277.86 15 0.93 $0.16 Cooling Central AC Ductless Mini-Split System 192.62 $2,012.28 20 0.63 $0.74 Cooling Room AC EER 9.8 - $0.00 10 1.00 $0.00 Cooling Room AC EER 10.8 (Energy Star) 40.50 $52.02 10 0.87 $0.15 Cooling Room AC EER 11 47.72 $141.13 10 0.69 $0.35 Cooling Room AC EER 11.5 64.71 $312.75 10 0.49 $0.57 Cooling Air Source Heat Pump SEER 13 - $0.00 15 - $0.00 Cooling Air Source Heat Pump SEER 14 (Energy Star) 56.37 $1,245.78 15 1.30 $1.91 Cooling Air Source Heat Pump SEER 15 (CEE Tier 2) 91.36 $2,315.13 15 0.94 $2.19 Cooling Air Source Heat Pump SEER 16 (CEE Tier 3) 128.74 $3,277.48 15 0.88 $2.20 Cooling Air Source Heat Pump Ductless Mini-Split System 169.45 $5,022.03 20 0.87 $2.10 Cooling Geothermal Heat Pump Standard - $0.00 15 1.00 $0.00 Cooling Geothermal Heat Pump High Efficiency 75.90 $1,500.00 15 0.90 $1.71 Cooling Ductless HP Ductless Mini-Split System - $0.00 20 1.00 $0.00 Space Heating Electric Resistance Electric Resistance - $0.00 20 1.00 $0.00 Space Heating Electric Resistance Ductless Mini-Split System 2,084.88 $156.87 20 1.29 $0.01 Space Heating Electric Furnace 3400 BTU/KW - $0.00 15 1.00 $0.00 Space Heating Supplemental Supplemental - $0.00 5 1.00 $0.00 Space Heating Air Source Heat Pump SEER 13 - $0.00 15 - $0.00 Space Heating Air Source Heat Pump SEER 14 (Energy Star) 219.90 $1,245.78 15 1.30 $0.49 Space Heating Air Source Heat Pump SEER 15 (CEE Tier 2) 684.88 $2,315.13 15 0.94 $0.29 Space Heating Air Source Heat Pump SEER 16 (CEE Tier 3) 965.10 $3,277.48 15 0.88 $0.29 Space Heating Air Source Heat Pump Ductless Mini-Split System 1,270.27 $5,022.03 20 0.87 $0.28 Space Heating Geothermal Heat Pump Standard - $0.00 15 1.00 $0.00 Space Heating Geothermal Heat Pump High Efficiency 495.28 $1,500.00 15 0.90 $0.26 Space Heating Ductless HP Ductless Mini-Split System - $0.00 20 1.00 $0.00 Water Heating Water Heater <= 55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00 Water Heating Water Heater <= 55 Gal High Efficiency (EF=0.95) 110.09 $77.11 15 1.01 $0.06 Water Heating Water Heater <= 55 Gal EF 2.3 (HP) 1,061.19 $1,761.86 15 0.64 $0.14 Water Heating Water Heater <= 55 Gal Solar 1,202.35 $6,214.86 15 0.27 $0.45 Water Heating Water Heater > 55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00 Water Heating Water Heater > 55 Gal High Efficiency (EF=0.95) 182.05 $97.23 15 1.02 $0.05 Water Heating Water Heater > EF 2.3 (HP) 1,378.92 $1,691.15 15 0.78 $0.11 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 928 of 1125 Residential Energy Efficiency Equipment and Measure Data B-26 www.enernoc.com End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) 55 Gal Water Heating Water Heater > 55 Gal Solar 1,231.85 $6,144.15 15 0.35 $0.43 Interior Lighting Screw-in Incandescent - $0.00 4 - $0.00 Interior Lighting Screw-in Infrared Halogen 186.22 $134.14 5 1.00 $0.16 Interior Lighting Screw-in CFL 591.38 $12.45 6 2.81 $0.00 Interior Lighting Screw-in LED 808.26 $1,381.00 12 - $0.18 Interior Lighting Screw-in LED 808.26 $1,381.00 12 - $0.18 Interior Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00 Interior Lighting Linear Fluorescent T8 9.18 -$1.83 6 1.13 -$0.04 Interior Lighting Linear Fluorescent Super T8 27.49 $14.59 6 0.80 $0.10 Interior Lighting Linear Fluorescent T5 28.58 $24.70 6 0.65 $0.16 Interior Lighting Linear Fluorescent LED 29.98 $216.84 10 0.24 $0.86 Interior Lighting Specialty Halogen - $0.00 4 1.00 $0.00 Interior Lighting Specialty CFL 121.57 -$13.05 7 3.30 -$0.02 Interior Lighting Specialty LED 127.91 $62.12 12 1.02 $0.05 Exterior Lighting Screw-in Incandescent - $0.00 4 - $0.00 Exterior Lighting Screw-in Infrared Halogen 6.13 $5.08 5 1.00 $0.18 Exterior Lighting Screw-in CFL 20.80 -$0.32 3 5.55 -$0.01 Exterior Lighting Screw-in LED 24.14 $75.05 12 - $0.32 Exterior Lighting Screw-in LED 24.14 $75.05 12 - $0.32 Appliances Clothes Washer Baseline - $0.00 14 - $0.00 Appliances Clothes Washer Energy Star (MEF > 1.8) 41.54 $69.81 14 - $0.15 Appliances Clothes Washer Horizontal Axis 57.34 $150.80 14 1.00 $0.24 Appliances Clothes Dryer Baseline - $0.00 13 - $0.00 Appliances Clothes Dryer Moisture Detection 61.35 $48.40 13 1.00 $0.08 Appliances Dishwasher Baseline - $0.00 15 1.00 $0.00 Appliances Dishwasher Energy Star 51.61 $460.95 9 - $1.15 Appliances Dishwasher Energy Star (2011) 6.76 $5.61 15 1.00 $0.07 Appliances Refrigerator Baseline - $0.00 20 - $0.00 Appliances Refrigerator Energy Star 49.89 $20.17 20 - $0.03 Appliances Refrigerator Baseline (2014) 91.39 $0.00 13 1.00 $0.00 Appliances Refrigerator Energy Star (2014) 146.23 $88.71 13 1.01 $0.06 Appliances Freezer Baseline - $0.00 22 - $0.00 Appliances Freezer Energy Star 38.51 $3.98 22 - $0.01 Appliances Freezer Baseline (2014) 89.38 -$145.00 11 1.00 -$0.18 Appliances Freezer Energy Star (2014) 143.01 -$112.83 11 1.00 -$0.09 Appliances Second Refrigerator Baseline - $0.00 13 - $0.00 Appliances Second Refrigerator Energy Star 64.14 $20.67 20 - $0.02 Appliances Second Refrigerator Baseline (2014) 117.49 $0.00 13 1.00 $0.00 Appliances Second Refrigerator Energy Star (2014) 187.98 $88.71 13 1.01 $0.05 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 929 of 1125 Residential Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting B-27 End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Appliances Stove Baseline - $0.00 13 1.00 $0.00 Appliances Stove Convection Oven 8.53 $1.86 13 1.00 $0.02 Appliances Stove Induction (High Efficiency) 42.66 $1,432.20 13 0.38 $3.23 Appliances Microwave Baseline - $0.00 9 1.00 $0.00 Electronics Personal Computers Baseline - $0.00 5 1.00 $0.00 Electronics Personal Computers Energy Star 70.05 $1.20 5 1.01 $0.00 Electronics Personal Computers Climate Savers 100.08 $175.49 5 0.85 $0.38 Electronics TVs Baseline - $0.00 11 1.00 $0.00 Electronics TVs Energy Star 52.12 $0.56 11 1.02 $0.00 Electronics Set-top boxes/DVR Baseline - $0.00 11 1.00 $0.00 Electronics Set-top boxes/DVR Energy Star 31.55 $0.56 11 1.01 $0.00 Electronics Devices and Gadgets Devices and Gadgets - $0.00 5 1.00 $0.00 Miscellaneous Pool Pump Baseline Pump - $0.00 15 1.00 $0.00 Miscellaneous Pool Pump High Efficiency Pump 155.66 $85.00 15 1.01 $0.05 Miscellaneous Pool Pump Two-Speed Pump 622.65 $579.00 15 0.88 $0.08 Miscellaneous Furnace Fan Baseline - $0.00 18 1.00 $0.00 Miscellaneous Furnace Fan Furnace Fan with ECM 126.06 $0.64 18 1.27 $0.00 Miscellaneous Miscellaneous Miscellaneous - $0.00 5 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 930 of 1125 Residential Energy Efficiency Equipment and Measure Data B-28 www.enernoc.com Table B-9 Energy Efficiency Equipment Data, Electric—Multi Family, Existing Vintage, Idaho End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Cooling Central AC SEER 13 - $0.00 15 - $0.00 Cooling Central AC SEER 14 (Energy Star) 35.49 $92.62 15 1.40 $0.23 Cooling Central AC SEER 15 (CEE Tier 2) 69.76 $185.24 15 0.96 $0.23 Cooling Central AC SEER 16 (CEE Tier 3) 98.42 $277.86 15 0.92 $0.24 Cooling Central AC Ductless Mini-Split System 128.81 $2,012.28 20 0.62 $1.11 Cooling Room AC EER 9.8 - $0.00 10 1.00 $0.00 Cooling Room AC EER 10.8 (Energy Star) 27.73 $52.02 10 0.84 $0.22 Cooling Room AC EER 11 32.67 $141.13 10 0.65 $0.51 Cooling Room AC EER 11.5 44.26 $312.75 10 0.45 $0.84 Cooling Air Source Heat Pump SEER 13 - $0.00 15 - $0.00 Cooling Air Source Heat Pump SEER 14 (Energy Star) 37.52 $1,245.78 15 1.30 $2.87 Cooling Air Source Heat Pump SEER 15 (CEE Tier 2) 61.09 $2,315.13 15 0.92 $3.28 Cooling Air Source Heat Pump SEER 16 (CEE Tier 3) 86.18 $3,277.48 15 0.85 $3.29 Cooling Air Source Heat Pump Ductless Mini-Split System 112.78 $5,022.03 20 0.84 $3.15 Cooling Geothermal Heat Pump Standard - $0.00 15 1.00 $0.00 Cooling Geothermal Heat Pump High Efficiency 54.19 $1,500.00 15 0.87 $2.39 Cooling Ductless HP Ductless Mini-Split System - $0.00 20 1.00 $0.00 Space Heating Electric Resistance Electric Resistance - $0.00 20 1.00 $0.00 Space Heating Electric Resistance Ductless Mini-Split System 1,704.17 $156.87 20 1.27 $0.01 Space Heating Electric Furnace 3400 BTU/KW - $0.00 15 1.00 $0.00 Space Heating Supplemental Supplemental - $0.00 5 1.00 $0.00 Space Heating Air Source Heat Pump SEER 13 - $0.00 15 - $0.00 Space Heating Air Source Heat Pump SEER 14 (Energy Star) 161.86 $1,245.78 15 1.30 $0.67 Space Heating Air Source Heat Pump SEER 15 (CEE Tier 2) 506.41 $2,315.13 15 0.92 $0.40 Space Heating Air Source Heat Pump SEER 16 (CEE Tier 3) 714.41 $3,277.48 15 0.85 $0.40 Space Heating Air Source Heat Pump Ductless Mini-Split System 934.98 $5,022.03 20 0.84 $0.38 Space Heating Geothermal Heat Pump Standard - $0.00 15 1.00 $0.00 Space Heating Geothermal Heat Pump High Efficiency 391.05 $1,500.00 15 0.87 $0.33 Space Heating Ductless HP Ductless Mini-Split System - $0.00 20 1.00 $0.00 Water Heating Water Heater <= 55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00 Water Heating Water Heater <= 55 Gal High Efficiency (EF=0.95) 103.48 $77.11 15 1.00 $0.06 Water Heating Water Heater <= 55 Gal EF 2.3 (HP) 997.52 $1,761.86 15 0.57 $0.15 Water Heating Water Heater <= 55 Gal Solar 1,130.20 $6,214.86 15 0.24 $0.48 Water Heating Water Heater > 55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00 Water Heating Water Heater > 55 Gal High Efficiency (EF=0.95) 171.13 $97.23 15 1.01 $0.05 Water Heating Water Heater > EF 2.3 (HP) 1,296.19 $1,691.15 15 0.71 $0.11 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 931 of 1125 Residential Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting B-29 End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) 55 Gal Water Heating Water Heater > 55 Gal Solar 1,158.24 $6,144.15 15 0.31 $0.46 Interior Lighting Screw-in Incandescent - $0.00 4 - $0.00 Interior Lighting Screw-in Infrared Halogen 153.34 $134.14 5 1.00 $0.19 Interior Lighting Screw-in CFL 486.95 $12.45 6 3.12 $0.00 Interior Lighting Screw-in LED 665.53 $1,161.45 12 - $0.18 Interior Lighting Screw-in LED 665.53 $1,161.45 12 - $0.18 Interior Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00 Interior Lighting Linear Fluorescent T8 7.33 -$1.83 6 1.13 -$0.05 Interior Lighting Linear Fluorescent Super T8 21.95 $14.59 6 0.75 $0.12 Interior Lighting Linear Fluorescent T5 22.81 $24.70 6 0.60 $0.20 Interior Lighting Linear Fluorescent LED 23.93 $216.84 10 0.22 $1.07 Interior Lighting Specialty Halogen - $0.00 4 1.00 $0.00 Interior Lighting Specialty CFL 99.37 $0.77 7 1.91 $0.00 Interior Lighting Specialty LED 104.55 $209.01 12 0.28 $0.20 Exterior Lighting Screw-in Incandescent - $0.00 4 - $0.00 Exterior Lighting Screw-in Infrared Halogen 5.06 $5.08 5 1.00 $0.22 Exterior Lighting Screw-in CFL 17.18 -$0.32 3 5.89 -$0.01 Exterior Lighting Screw-in LED 19.94 $1,167.57 12 - $6.00 Exterior Lighting Screw-in LED 19.94 $1,167.57 12 - $6.00 Appliances Clothes Washer Baseline - $0.00 14 - $0.00 Appliances Clothes Washer Energy Star (MEF > 1.8) 39.05 $69.81 14 - $0.16 Appliances Clothes Washer Horizontal Axis 53.90 $150.80 14 1.00 $0.25 Appliances Clothes Dryer Baseline - $0.00 13 - $0.00 Appliances Clothes Dryer Moisture Detection 57.67 $48.40 13 1.00 $0.08 Appliances Dishwasher Baseline - $0.00 15 1.00 $0.00 Appliances Dishwasher Energy Star 48.33 $460.95 9 - $1.23 Appliances Dishwasher Energy Star (2011) 6.33 $5.61 15 0.99 $0.08 Appliances Refrigerator Baseline - $0.00 20 - $0.00 Appliances Refrigerator Energy Star 41.38 $20.17 20 - $0.03 Appliances Refrigerator Baseline (2014) 75.80 $0.00 13 1.00 $0.00 Appliances Refrigerator Energy Star (2014) 121.28 $88.71 13 1.01 $0.07 Appliances Freezer Baseline - $0.00 22 - $0.00 Appliances Freezer Energy Star 33.83 $3.98 22 - $0.01 Appliances Freezer Baseline (2014) 78.50 -$145.00 11 1.00 -$0.20 Appliances Freezer Energy Star (2014) 125.61 -$112.83 11 0.99 -$0.10 Appliances Second Refrigerator Baseline - $0.00 20 - $0.00 Appliances Second Refrigerator Energy Star 56.52 $20.67 20 - $0.03 Appliances Second Refrigerator Baseline (2014) 103.54 $0.00 13 1.00 $0.00 Appliances Second Refrigerator Energy Star (2014) 165.66 $88.71 13 1.00 $0.05 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 932 of 1125 Residential Energy Efficiency Equipment and Measure Data B-30 www.enernoc.com End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Appliances Stove Baseline - $0.00 13 1.00 $0.00 Appliances Stove Convection Oven 8.02 $1.86 13 1.00 $0.02 Appliances Stove Induction (High Efficiency) 40.10 $1,432.20 13 0.37 $3.44 Appliances Microwave Baseline - $0.00 9 1.00 $0.00 Electronics Personal Computers Baseline - $0.00 5 1.00 $0.00 Electronics Personal Computers Energy Star 67.28 $1.20 5 1.01 $0.00 Electronics Personal Computers Climate Savers 96.12 $175.49 5 0.85 $0.39 Electronics TVs Baseline - $0.00 11 1.00 $0.00 Electronics TVs Energy Star 44.09 $0.56 11 1.02 $0.00 Electronics Set-top boxes/DVR Baseline - $0.00 11 1.00 $0.00 Electronics Set-top boxes/DVR Energy Star 29.65 $0.56 11 1.01 $0.00 Electronics Devices and Gadgets Devices and Gadgets - $0.00 5 1.00 $0.00 Miscellaneous Pool Pump Baseline Pump - $0.00 15 1.00 $0.00 Miscellaneous Pool Pump High Efficiency Pump 129.49 $85.00 15 1.00 $0.06 Miscellaneous Pool Pump Two-Speed Pump 517.96 $579.00 15 0.81 $0.10 Miscellaneous Furnace Fan Baseline - $0.00 18 1.00 $0.00 Miscellaneous Furnace Fan Furnace Fan with ECM 118.50 $0.00 18 1.27 $0.00 Miscellaneous Miscellaneous Miscellaneous - $0.00 5 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 933 of 1125 Residential Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting B-31 Table B-10 Energy Efficiency Equipment Data, Electric—Multi Family, New Vintage, Idaho End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Cooling Central AC SEER 13 - $0.00 15 - $0.00 Cooling Central AC SEER 14 (Energy Star) 45.42 $92.62 15 1.40 $0.18 Cooling Central AC SEER 15 (CEE Tier 2) 88.66 $185.24 15 0.96 $0.18 Cooling Central AC SEER 16 (CEE Tier 3) 124.94 $277.86 15 0.93 $0.19 Cooling Central AC Ductless Mini-Split System 164.44 $2,012.28 20 0.63 $0.87 Cooling Room AC EER 9.8 - $0.00 10 1.00 $0.00 Cooling Room AC EER 10.8 (Energy Star) 34.44 $52.02 10 0.86 $0.18 Cooling Room AC EER 11 40.58 $141.13 10 0.67 $0.41 Cooling Room AC EER 11.5 55.03 $312.75 10 0.47 $0.67 Cooling Air Source Heat Pump SEER 13 - $0.00 15 - $0.00 Cooling Air Source Heat Pump SEER 14 (Energy Star) 47.92 $1,245.78 15 1.30 $2.25 Cooling Air Source Heat Pump SEER 15 (CEE Tier 2) 77.66 $2,315.13 15 0.93 $2.58 Cooling Air Source Heat Pump SEER 16 (CEE Tier 3) 109.43 $3,277.48 15 0.87 $2.59 Cooling Air Source Heat Pump Ductless Mini-Split System 144.03 $5,022.03 20 0.86 $2.47 Cooling Geothermal Heat Pump Standard - $0.00 15 1.00 $0.00 Cooling Geothermal Heat Pump High Efficiency 64.51 $1,500.00 15 0.87 $2.01 Cooling Ductless HP Ductless Mini-Split System - $0.00 20 1.00 $0.00 Space Heating Electric Resistance Electric Resistance - $0.00 20 1.00 $0.00 Space Heating Electric Resistance Ductless Mini-Split System 1,959.79 $156.87 20 1.29 $0.01 Space Heating Electric Furnace 3400 BTU/KW - $0.00 15 1.00 $0.00 Space Heating Supplemental Supplemental - $0.00 5 1.00 $0.00 Space Heating Air Source Heat Pump SEER 13 - $0.00 15 - $0.00 Space Heating Air Source Heat Pump SEER 14 (Energy Star) 206.71 $1,245.78 15 1.30 $0.52 Space Heating Air Source Heat Pump SEER 15 (CEE Tier 2) 643.79 $2,315.13 15 0.93 $0.31 Space Heating Air Source Heat Pump SEER 16 (CEE Tier 3) 907.19 $3,277.48 15 0.87 $0.31 Space Heating Air Source Heat Pump Ductless Mini-Split System 1,194.05 $5,022.03 20 0.86 $0.30 Space Heating Geothermal Heat Pump Standard - $0.00 15 1.00 $0.00 Space Heating Geothermal Heat Pump High Efficiency 465.56 $1,500.00 15 0.87 $0.28 Space Heating Ductless HP Ductless Mini-Split System - $0.00 20 1.00 $0.00 Water Heating Water Heater <= 55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00 Water Heating Water Heater <= 55 Gal High Efficiency (EF=0.95) 103.48 $77.11 15 1.00 $0.06 Water Heating Water Heater <= 55 Gal EF 2.3 (HP) 997.52 $1,761.86 15 0.57 $0.15 Water Heating Water Heater <= 55 Gal Solar 1,130.20 $6,214.86 15 0.24 $0.48 Water Heating Water Heater > 55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00 Water Heating Water Heater > 55 Gal High Efficiency (EF=0.95) 171.13 $97.23 15 1.01 $0.05 Water Heating Water Heater > EF 2.3 (HP) 1,296.19 $1,691.15 15 0.71 $0.11 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 934 of 1125 Residential Energy Efficiency Equipment and Measure Data B-32 www.enernoc.com End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) 55 Gal Water Heating Water Heater > 55 Gal Solar 1,158.24 $6,144.15 15 0.31 $0.46 Interior Lighting Screw-in Incandescent - $0.00 4 - $0.00 Interior Lighting Screw-in Infrared Halogen 175.05 $134.14 5 1.00 $0.17 Interior Lighting Screw-in CFL 555.89 $12.45 6 2.98 $0.00 Interior Lighting Screw-in LED 759.76 $1,381.00 12 - $0.19 Interior Lighting Screw-in LED 759.76 $1,381.00 12 - $0.19 Interior Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00 Interior Lighting Linear Fluorescent T8 8.63 -$1.83 6 1.13 -$0.04 Interior Lighting Linear Fluorescent Super T8 25.84 $14.59 6 0.78 $0.10 Interior Lighting Linear Fluorescent T5 26.86 $24.70 6 0.63 $0.17 Interior Lighting Linear Fluorescent LED 28.18 $216.84 10 0.23 $0.91 Interior Lighting Specialty Halogen - $0.00 4 1.00 $0.00 Interior Lighting Specialty CFL 114.28 -$13.07 7 3.40 -$0.02 Interior Lighting Specialty LED 120.23 $61.68 12 1.01 $0.05 Exterior Lighting Screw-in Incandescent - $0.00 4 - $0.00 Exterior Lighting Screw-in Infrared Halogen 5.76 $5.08 5 1.00 $0.19 Exterior Lighting Screw-in CFL 19.55 -$0.34 3 5.79 -$0.01 Exterior Lighting Screw-in LED 22.70 $75.05 12 - $0.34 Exterior Lighting Screw-in LED 22.70 $75.05 12 - $0.34 Appliances Clothes Washer Baseline - $0.00 14 - $0.00 Appliances Clothes Washer Energy Star (MEF > 1.8) 39.05 $69.81 14 - $0.16 Appliances Clothes Washer Horizontal Axis 53.90 $150.80 14 1.00 $0.25 Appliances Clothes Dryer Baseline - $0.00 13 - $0.00 Appliances Clothes Dryer Moisture Detection 57.67 $48.40 13 1.00 $0.08 Appliances Dishwasher Baseline - $0.00 15 1.00 $0.00 Appliances Dishwasher Energy Star 48.52 $460.95 9 - $1.23 Appliances Dishwasher Energy Star (2011) 6.36 $5.61 15 0.99 $0.08 Appliances Refrigerator Baseline - $0.00 20 - $0.00 Appliances Refrigerator Energy Star 46.90 $20.17 20 - $0.03 Appliances Refrigerator Baseline (2014) 85.91 $0.00 13 1.00 $0.00 Appliances Refrigerator Energy Star (2014) 137.46 $88.71 13 1.01 $0.06 Appliances Freezer Baseline - $0.00 22 - $0.00 Appliances Freezer Energy Star 36.20 $3.98 22 - $0.01 Appliances Freezer Baseline (2014) 84.02 -$145.00 11 1.00 -$0.19 Appliances Freezer Energy Star (2014) 134.43 -$112.83 11 0.99 -$0.09 Appliances Second Refrigerator Baseline - $0.00 20 - $0.00 Appliances Second Refrigerator Energy Star 60.29 $20.67 20 - $0.02 Appliances Second Refrigerator Baseline (2014) 110.44 $0.00 13 1.00 $0.00 Appliances Second Refrigerator Energy Star (2014) 176.70 $88.71 13 1.00 $0.05 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 935 of 1125 Residential Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting B-33 End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Appliances Stove Baseline - $0.00 13 1.00 $0.00 Appliances Stove Convection Oven 8.02 $1.86 13 1.00 $0.02 Appliances Stove Induction (High Efficiency) 40.10 $1,432.20 13 0.37 $3.44 Appliances Microwave Baseline - $0.00 9 1.00 $0.00 Electronics Personal Computers Baseline - $0.00 5 1.00 $0.00 Electronics Personal Computers Energy Star 65.85 $1.20 5 1.01 $0.00 Electronics Personal Computers Climate Savers 94.07 $175.49 5 0.85 $0.40 Electronics TVs Baseline - $0.00 11 1.00 $0.00 Electronics TVs Energy Star 48.99 $0.56 11 1.02 $0.00 Electronics Set-top boxes/DVR Baseline - $0.00 11 1.00 $0.00 Electronics Set-top boxes/DVR Energy Star 29.65 $0.56 11 1.01 $0.00 Electronics Devices and Gadgets Devices and Gadgets - $0.00 5 1.00 $0.00 Miscellaneous Pool Pump Baseline Pump - $0.00 15 1.00 $0.00 Miscellaneous Pool Pump High Efficiency Pump 146.32 $85.00 15 1.01 $0.05 Miscellaneous Pool Pump Two-Speed Pump 585.29 $579.00 15 0.85 $0.09 Miscellaneous Furnace Fan Baseline - $0.00 18 1.00 $0.00 Miscellaneous Furnace Fan Furnace Fan with ECM 118.50 $0.64 18 1.27 $0.00 Miscellaneous Miscellaneous Miscellaneous - $0.00 5 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 936 of 1125 Residential Energy Efficiency Equipment and Measure Data B-34 www.enernoc.com Table B-11 Energy Efficiency Equipment Data, Electric—Mobile Home, Existing Vintage, Washington End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Cooling Central AC SEER 13 - $0.00 15 - $0.00 Cooling Central AC SEER 14 (Energy Star) 46.32 $277.86 20 1.40 $0.42 Cooling Central AC SEER 15 (CEE Tier 2) 63.55 $555.71 15 0.78 $0.76 Cooling Central AC SEER 16 (CEE Tier 3) 77.99 $833.57 15 0.73 $0.92 Cooling Central AC Ductless Mini-Split System 139.87 $4,399.48 20 0.51 $2.23 Cooling Room AC EER 9.8 - $0.00 10 1.00 $0.00 Cooling Room AC EER 10.8 (Energy Star) 27.99 $52.02 10 0.85 $0.22 Cooling Room AC EER 11 33.03 $141.13 10 0.65 $0.51 Cooling Room AC EER 11.5 44.72 $312.75 10 0.45 $0.83 Cooling Air Source Heat Pump SEER 13 - $0.00 15 - $0.00 Cooling Air Source Heat Pump SEER 14 (Energy Star) 43.49 $1,720.87 15 1.30 $3.42 Cooling Air Source Heat Pump SEER 15 (CEE Tier 2) 40.94 $2,315.13 15 0.96 $4.89 Cooling Air Source Heat Pump SEER 16 (CEE Tier 3) 50.24 $3,277.48 15 0.88 $5.64 Cooling Air Source Heat Pump Ductless Mini-Split System 90.11 $5,022.03 20 0.89 $3.94 Cooling Geothermal Heat Pump Standard - $0.00 15 1.00 $0.00 Cooling Geothermal Heat Pump High Efficiency 46.66 $1,500.00 15 0.90 $2.78 Cooling Ductless HP Ductless Mini-Split System - $0.00 20 1.00 $0.00 Space Heating Electric Resistance Electric Resistance - $0.00 20 1.00 $0.00 Space Heating Electric Resistance Ductless Mini-Split System 2,388.11 $156.87 20 1.28 $0.00 Space Heating Electric Furnace 3400 BTU/KW - $0.00 15 1.00 $0.00 Space Heating Supplemental Supplemental - $0.00 5 1.00 $0.00 Space Heating Air Source Heat Pump SEER 13 - $0.00 15 - $0.00 Space Heating Air Source Heat Pump SEER 14 (Energy Star) 239.45 $1,720.87 15 1.30 $0.62 Space Heating Air Source Heat Pump SEER 15 (CEE Tier 2) 528.37 $2,315.13 15 0.96 $0.38 Space Heating Air Source Heat Pump SEER 16 (CEE Tier 3) 648.37 $3,277.48 15 0.88 $0.44 Space Heating Air Source Heat Pump Ductless Mini-Split System 1,162.86 $5,022.03 20 0.89 $0.31 Space Heating Geothermal Heat Pump Standard - $0.00 15 1.00 $0.00 Space Heating Geothermal Heat Pump High Efficiency 813.13 $188.19 15 0.90 $0.02 Space Heating Ductless HP Ductless Mini-Split System - $0.00 20 1.00 $0.00 Water Heating Water Heater <= 55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00 Water Heating Water Heater <= 55 Gal High Efficiency (EF=0.95) 134.84 $77.11 15 1.01 $0.05 Water Heating Water Heater <= 55 Gal EF 2.3 (HP) 1,299.77 $1,761.86 15 0.72 $0.12 Water Heating Water Heater <= 55 Gal Solar 1,472.84 $6,214.86 15 0.32 $0.36 Water Heating Water Heater > 55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00 Water Heating Water Heater > High Efficiency 171.70 $97.23 15 1.02 $0.05 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 937 of 1125 Residential Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting B-35 End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) 55 Gal (EF=0.95) Water Heating Water Heater > 55 Gal EF 2.3 (HP) 1,300.53 $1,691.15 15 0.76 $0.11 Water Heating Water Heater > 55 Gal Solar 1,162.12 $6,144.15 15 0.34 $0.46 Interior Lighting Screw-in Incandescent - $0.00 4 - $0.00 Interior Lighting Screw-in Infrared Halogen 210.16 $188.19 5 1.00 $0.19 Interior Lighting Screw-in CFL 667.39 $28.57 6 2.81 $0.01 Interior Lighting Screw-in LED 912.15 $1,353.42 12 - $0.15 Interior Lighting Screw-in LED 912.15 $1,353.42 12 - $0.15 Interior Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00 Interior Lighting Linear Fluorescent T8 8.74 -$3.65 6 1.14 -$0.08 Interior Lighting Linear Fluorescent Super T8 26.18 $29.17 6 0.65 $0.20 Interior Lighting Linear Fluorescent T5 27.22 $49.41 6 0.51 $0.33 Interior Lighting Linear Fluorescent LED 28.55 $433.68 10 0.17 $1.80 Interior Lighting Specialty Halogen - $0.00 4 1.00 $0.00 Interior Lighting Specialty CFL 205.65 $1.34 7 1.92 $0.00 Interior Lighting Specialty LED 216.37 $365.76 12 0.31 $0.17 Exterior Lighting Screw-in Incandescent - $0.00 4 - $0.00 Exterior Lighting Screw-in Infrared Halogen 72.47 $51.30 5 1.00 $0.15 Exterior Lighting Screw-in CFL 245.95 -$1.81 3 4.75 $0.00 Exterior Lighting Screw-in LED 285.49 $1,356.06 12 - $0.49 Exterior Lighting Screw-in LED 285.49 $1,356.06 12 - $0.49 Appliances Clothes Washer Baseline - $0.00 14 - $0.00 Appliances Clothes Washer Energy Star (MEF > 1.8) 40.50 $69.81 14 - $0.16 Appliances Clothes Washer Horizontal Axis 55.91 $150.80 14 1.00 $0.25 Appliances Clothes Dryer Baseline - $0.00 13 - $0.00 Appliances Clothes Dryer Moisture Detection 60.29 $48.40 13 1.00 $0.08 Appliances Dishwasher Baseline - $0.00 15 1.00 $0.00 Appliances Dishwasher Energy Star 50.13 $460.95 9 - $1.19 Appliances Dishwasher Energy Star (2011) 6.57 $5.61 15 1.00 $0.07 Appliances Refrigerator Baseline - $0.00 20 - $0.00 Appliances Refrigerator Energy Star 42.92 $20.17 20 - $0.03 Appliances Refrigerator Baseline (2014) 78.63 $0.00 13 1.00 $0.00 Appliances Refrigerator Energy Star (2014) 125.80 $88.71 13 1.01 $0.07 Appliances Freezer Baseline - $0.00 22 - $0.00 Appliances Freezer Energy Star 35.09 $3.98 22 - $0.01 Appliances Freezer Baseline (2014) 81.43 -$145.00 11 1.00 -$0.20 Appliances Freezer Energy Star (2014) 130.28 -$112.83 11 0.99 -$0.10 Appliances Second Refrigerator Baseline - $0.00 20 - $0.00 Appliances Second Refrigerator Energy Star 58.63 $20.67 20 - $0.02 Appliances Second Refrigerator Baseline (2014) 107.39 $0.00 13 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 938 of 1125 Residential Energy Efficiency Equipment and Measure Data B-36 www.enernoc.com End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Appliances Second Refrigerator Energy Star (2014) 171.83 $88.71 13 1.01 $0.05 Appliances Stove Baseline - $0.00 13 1.00 $0.00 Appliances Stove Convection Oven 8.32 $1.86 13 1.00 $0.02 Appliances Stove Induction (High Efficiency) 41.60 $1,432.20 13 0.37 $3.32 Appliances Microwave Baseline - $0.00 9 1.00 $0.00 Electronics Personal Computers Baseline - $0.00 5 1.00 $0.00 Electronics Personal Computers Energy Star 76.05 $1.20 5 1.01 $0.00 Electronics Personal Computers Climate Savers 108.65 $175.49 5 0.85 $0.35 Electronics TVs Baseline - $0.00 11 1.00 $0.00 Electronics TVs Energy Star 44.30 $0.56 11 1.02 $0.00 Electronics Set-top boxes/DVR Baseline - $0.00 11 1.00 $0.00 Electronics Set-top boxes/DVR Energy Star 26.81 $0.56 11 1.01 $0.00 Electronics Devices and Gadgets Devices and Gadgets - $0.00 5 1.00 $0.00 Miscellaneous Pool Pump Baseline Pump - $0.00 15 1.00 $0.00 Miscellaneous Pool Pump High Efficiency Pump 103.32 $85.00 15 0.98 $0.07 Miscellaneous Pool Pump Two-Speed Pump 413.27 $579.00 15 0.74 $0.12 Miscellaneous Furnace Fan Baseline - $0.00 18 1.00 $0.00 Miscellaneous Furnace Fan Furnace Fan with ECM 118.18 $0.64 18 1.27 $0.00 Miscellaneous Miscellaneous Miscellaneous - $0.00 5 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 939 of 1125 Residential Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting B-37 Table B-12 Energy Efficiency Equipment Data, Electric—Mobile Home, New Vintage, Washington End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Cooling Central AC SEER 13 - $0.00 15 - $0.00 Cooling Central AC SEER 14 (Energy Star) 55.05 $277.86 15 1.40 $0.44 Cooling Central AC SEER 15 (CEE Tier 2) 73.33 $555.71 15 0.94 $0.66 Cooling Central AC SEER 16 (CEE Tier 3) 88.67 $833.57 15 0.89 $0.81 Cooling Central AC Ductless Mini-Split System 166.28 $4,399.48 20 0.62 $1.87 Cooling Room AC EER 9.8 - $0.00 10 1.00 $0.00 Cooling Room AC EER 10.8 (Energy Star) 32.54 $52.02 10 0.86 $0.19 Cooling Room AC EER 11 38.34 $141.13 10 0.66 $0.44 Cooling Room AC EER 11.5 51.99 $312.75 10 0.46 $0.71 Cooling Air Source Heat Pump SEER 13 - $0.00 15 - $0.00 Cooling Air Source Heat Pump SEER 14 (Energy Star) 51.74 $1,720.87 15 1.30 $2.88 Cooling Air Source Heat Pump SEER 15 (CEE Tier 2) 47.26 $2,315.13 15 0.97 $4.24 Cooling Air Source Heat Pump SEER 16 (CEE Tier 3) 57.15 $3,277.48 15 0.89 $4.96 Cooling Air Source Heat Pump Ductless Mini-Split System 107.18 $5,022.03 20 0.90 $3.32 Cooling Geothermal Heat Pump Standard - $0.00 15 1.00 $0.00 Cooling Geothermal Heat Pump High Efficiency 51.93 $1,500.00 15 0.91 $2.50 Cooling Ductless HP Ductless Mini-Split System - $0.00 20 1.00 $0.00 Space Heating Electric Resistance Electric Resistance - $0.00 20 1.00 $0.00 Space Heating Electric Resistance Ductless Mini-Split System 2,567.22 $156.87 20 1.29 $0.00 Space Heating Electric Furnace 3400 BTU/KW - $0.00 15 1.00 $0.00 Space Heating Supplemental Supplemental - $0.00 5 1.00 $0.00 Space Heating Air Source Heat Pump SEER 13 - $0.00 15 - $0.00 Space Heating Air Source Heat Pump SEER 14 (Energy Star) 284.83 $1,720.87 15 1.30 $0.52 Space Heating Air Source Heat Pump SEER 15 (CEE Tier 2) 609.96 $2,315.13 15 0.97 $0.33 Space Heating Air Source Heat Pump SEER 16 (CEE Tier 3) 737.59 $3,277.48 15 0.89 $0.38 Space Heating Air Source Heat Pump Ductless Mini-Split System 1,383.21 $5,022.03 20 0.90 $0.26 Space Heating Geothermal Heat Pump Standard - $0.00 15 1.00 $0.00 Space Heating Geothermal Heat Pump High Efficiency 671.05 $1,500.00 15 0.91 $0.19 Space Heating Ductless HP Ductless Mini-Split System - $0.00 20 1.00 $0.00 Water Heating Water Heater <= 55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00 Water Heating Water Heater <= 55 Gal High Efficiency (EF=0.95) 141.18 $77.11 15 1.02 $0.05 Water Heating Water Heater <= 55 Gal EF 2.3 (HP) 1,360.93 $1,761.86 15 0.73 $0.11 Water Heating Water Heater <= 55 Gal Solar 1,542.14 $6,214.86 15 0.33 $0.35 Water Heating Water Heater > 55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00 Water Heating Water Heater > High Efficiency 179.84 $97.23 15 1.02 $0.05 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 940 of 1125 Residential Energy Efficiency Equipment and Measure Data B-38 www.enernoc.com End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) 55 Gal (EF=0.95) Water Heating Water Heater > 55 Gal EF 2.3 (HP) 1,362.23 $1,691.15 15 0.77 $0.11 Water Heating Water Heater > 55 Gal Solar 1,217.25 $6,144.15 15 0.35 $0.44 Interior Lighting Screw-in Incandescent - $0.00 4 - $0.00 Interior Lighting Screw-in Infrared Halogen 229.01 $188.19 5 1.00 $0.18 Interior Lighting Screw-in CFL 727.25 $28.57 6 2.74 $0.01 Interior Lighting Screw-in LED 993.96 $1,937.55 12 - $0.20 Interior Lighting Screw-in LED 993.96 $1,937.55 12 - $0.20 Interior Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00 Interior Lighting Linear Fluorescent T8 9.82 -$3.65 6 1.14 -$0.07 Interior Lighting Linear Fluorescent Super T8 29.43 $29.17 6 0.67 $0.18 Interior Lighting Linear Fluorescent T5 30.59 $49.41 6 0.53 $0.30 Interior Lighting Linear Fluorescent LED 32.09 $433.68 10 0.18 $1.60 Interior Lighting Specialty Halogen - $0.00 4 1.00 $0.00 Interior Lighting Specialty CFL 221.07 -$7.66 7 2.45 -$0.01 Interior Lighting Specialty LED 232.60 $134.50 12 0.74 $0.06 Exterior Lighting Screw-in Incandescent - $0.00 4 - $0.00 Exterior Lighting Screw-in Infrared Halogen 78.72 $51.30 5 1.00 $0.14 Exterior Lighting Screw-in CFL 267.15 -$2.04 3 4.76 $0.00 Exterior Lighting Screw-in LED 310.10 $757.28 12 - $0.25 Exterior Lighting Screw-in LED 310.10 $757.28 12 - $0.25 Appliances Clothes Washer Baseline - $0.00 14 - $0.00 Appliances Clothes Washer Energy Star (MEF > 1.8) 47.25 $69.81 14 - $0.13 Appliances Clothes Washer Horizontal Axis 65.23 $150.80 14 1.00 $0.21 Appliances Clothes Dryer Baseline - $0.00 13 - $0.00 Appliances Clothes Dryer Moisture Detection 65.61 $48.40 13 1.00 $0.07 Appliances Dishwasher Baseline - $0.00 15 1.00 $0.00 Appliances Dishwasher Energy Star 54.76 $460.95 9 - $1.09 Appliances Dishwasher Energy Star (2011) 7.17 $5.61 15 1.00 $0.07 Appliances Refrigerator Baseline - $0.00 20 - $0.00 Appliances Refrigerator Energy Star 60.09 $20.17 20 - $0.02 Appliances Refrigerator Baseline (2014) 110.08 $0.00 13 1.00 $0.00 Appliances Refrigerator Energy Star (2014) 176.12 $88.71 13 1.02 $0.05 Appliances Freezer Baseline - $0.00 22 - $0.00 Appliances Freezer Energy Star 48.64 $3.98 22 - $0.01 Appliances Freezer Baseline (2014) 112.87 -$145.00 11 1.00 -$0.14 Appliances Freezer Energy Star (2014) 180.59 -$112.83 11 1.01 -$0.07 Appliances Second Refrigerator Baseline - $0.00 20 - $0.00 Appliances Second Refrigerator Energy Star 80.12 $20.67 20 - $0.02 Appliances Second Refrigerator Baseline (2014) 146.77 $0.00 13 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 941 of 1125 Residential Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting B-39 End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Appliances Second Refrigerator Energy Star (2014) 234.83 $88.71 13 1.01 $0.04 Appliances Stove Baseline - $0.00 13 1.00 $0.00 Appliances Stove Convection Oven 35.13 $0.56 13 1.00 $0.00 Appliances Stove Induction (High Efficiency) 41.59 $0.00 13 0.37 $0.00 Appliances Microwave Baseline - $0.00 9 1.00 $0.00 Electronics Personal Computers Baseline - $0.00 5 1.00 $0.00 Electronics Personal Computers Energy Star 74.43 $1.20 5 1.01 $0.00 Electronics Personal Computers Climate Savers 106.33 $175.49 5 0.85 $0.36 Electronics TVs Baseline - $0.00 11 1.00 $0.00 Electronics TVs Energy Star 49.22 $0.56 11 1.02 $0.00 Electronics Set-top boxes/DVR Baseline - $0.00 11 1.00 $0.00 Electronics Set-top boxes/DVR Energy Star 26.81 $0.56 11 1.01 $0.00 Electronics Devices and Gadgets Devices and Gadgets - $0.00 5 1.00 $0.00 Miscellaneous Pool Pump Baseline Pump - $0.00 15 1.00 $0.00 Miscellaneous Pool Pump High Efficiency Pump 115.77 $85.00 15 0.99 $0.06 Miscellaneous Pool Pump Two-Speed Pump 463.09 $579.00 15 0.78 $0.11 Miscellaneous Furnace Fan Baseline - $0.00 18 1.00 $0.00 Miscellaneous Furnace Fan Furnace Fan with ECM 118.18 $0.64 18 1.27 $0.00 Miscellaneous Miscellaneous Miscellaneous - $0.00 5 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 942 of 1125 Residential Energy Efficiency Equipment and Measure Data B-40 www.enernoc.com Table B-13 Energy Efficiency Equipment Data, Electric—Mobile Home, Existing Vintage, Idaho End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Cooling Central AC SEER 13 - $0.00 15 - $0.00 Cooling Central AC SEER 14 (Energy Star) 39.83 $277.86 15 1.40 $0.60 Cooling Central AC SEER 15 (CEE Tier 2) 54.66 $555.71 15 0.94 $0.88 Cooling Central AC SEER 16 (CEE Tier 3) 67.07 $833.57 15 0.89 $1.07 Cooling Central AC Ductless Mini-Split System 120.29 $4,399.48 20 0.62 $2.59 Cooling Room AC EER 9.8 - $0.00 10 1.00 $0.00 Cooling Room AC EER 10.8 (Energy Star) 24.07 $52.02 10 0.84 $0.26 Cooling Room AC EER 11 28.41 $141.13 10 0.64 $0.59 Cooling Room AC EER 11.5 38.46 $312.75 10 0.44 $0.96 Cooling Air Source Heat Pump SEER 13 - $0.00 15 - $0.00 Cooling Air Source Heat Pump SEER 14 (Energy Star) 37.41 $1,720.87 15 1.30 $3.98 Cooling Air Source Heat Pump SEER 15 (CEE Tier 2) 35.21 $2,315.13 15 0.96 $5.69 Cooling Air Source Heat Pump SEER 16 (CEE Tier 3) 43.21 $3,277.48 15 0.88 $6.56 Cooling Air Source Heat Pump Ductless Mini-Split System 77.49 $5,022.03 20 0.88 $4.59 Cooling Geothermal Heat Pump Standard - $0.00 15 1.00 $0.00 Cooling Geothermal Heat Pump High Efficiency 40.13 $1,500.00 15 0.89 $3.23 Cooling Ductless HP Ductless Mini-Split System - $0.00 20 1.00 $0.00 Space Heating Electric Resistance Electric Resistance - $0.00 20 1.00 $0.00 Space Heating Electric Resistance Ductless Mini-Split System 2,256.76 $156.87 20 1.27 $0.00 Space Heating Electric Furnace 3400 BTU/KW - $0.00 15 1.00 $0.00 Space Heating Supplemental Supplemental - $0.00 5 1.00 $0.00 Space Heating Air Source Heat Pump SEER 13 - $0.00 15 - $0.00 Space Heating Air Source Heat Pump SEER 14 (Energy Star) 226.28 $1,720.87 15 1.30 $0.66 Space Heating Air Source Heat Pump SEER 15 (CEE Tier 2) 499.31 $2,315.13 15 0.96 $0.40 Space Heating Air Source Heat Pump SEER 16 (CEE Tier 3) 612.71 $3,277.48 15 0.88 $0.46 Space Heating Air Source Heat Pump Ductless Mini-Split System 1,098.90 $5,022.03 20 0.88 $0.32 Space Heating Geothermal Heat Pump Standard - $0.00 15 1.00 $0.00 Space Heating Geothermal Heat Pump High Efficiency 768.40 $188.19 15 0.89 $0.02 Space Heating Ductless HP Ductless Mini-Split System - $0.00 20 1.00 $0.00 Water Heating Water Heater <= 55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00 Water Heating Water Heater <= 55 Gal High Efficiency (EF=0.95) 127.42 $77.11 15 1.01 $0.05 Water Heating Water Heater <= 55 Gal EF 2.3 (HP) 1,228.29 $1,761.86 15 0.64 $0.12 Water Heating Water Heater <= 55 Gal Solar 1,391.83 $6,214.86 15 0.27 $0.39 Water Heating Water Heater > 55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00 Water Heating Water Heater > 55 Gal High Efficiency (EF=0.95) 162.25 $97.23 15 1.01 $0.05 Water Heating Water Heater > EF 2.3 (HP) 1,229.00 $1,691.15 15 0.68 $0.12 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 943 of 1125 Residential Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting B-41 End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) 55 Gal Water Heating Water Heater > 55 Gal Solar 1,098.20 $6,144.15 15 0.30 $0.48 Interior Lighting Screw-in Incandescent - $0.00 4 - $0.00 Interior Lighting Screw-in Infrared Halogen 198.60 $188.19 5 1.00 $0.20 Interior Lighting Screw-in CFL 630.68 $28.57 6 2.95 $0.01 Interior Lighting Screw-in LED 861.98 $1,353.42 12 - $0.16 Interior Lighting Screw-in LED 861.98 $1,353.42 12 - $0.16 Interior Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00 Interior Lighting Linear Fluorescent T8 8.26 -$3.50 6 1.14 -$0.08 Interior Lighting Linear Fluorescent Super T8 24.74 $28.01 6 0.65 $0.21 Interior Lighting Linear Fluorescent T5 25.72 $47.43 6 0.50 $0.34 Interior Lighting Linear Fluorescent LED 26.98 $416.33 10 0.17 $1.83 Interior Lighting Specialty Halogen - $0.00 4 1.00 $0.00 Interior Lighting Specialty CFL 194.34 $1.34 7 1.93 $0.00 Interior Lighting Specialty LED 204.47 $365.76 12 0.30 $0.18 Exterior Lighting Screw-in Incandescent - $0.00 4 - $0.00 Exterior Lighting Screw-in Infrared Halogen 68.48 $49.25 5 1.00 $0.16 Exterior Lighting Screw-in CFL 232.42 -$1.53 3 4.76 $0.00 Exterior Lighting Screw-in LED 269.78 $1,356.33 12 - $0.52 Exterior Lighting Screw-in LED 269.78 $1,356.33 12 - $0.52 Appliances Clothes Washer Baseline - $0.00 14 - $0.00 Appliances Clothes Washer Energy Star (MEF > 1.8) 38.27 $69.81 14 - $0.17 Appliances Clothes Washer Horizontal Axis 52.83 $150.80 14 1.00 $0.26 Appliances Clothes Dryer Baseline - $0.00 13 - $0.00 Appliances Clothes Dryer Moisture Detection 56.98 $48.40 13 1.00 $0.08 Appliances Dishwasher Baseline - $0.00 15 1.00 $0.00 Appliances Dishwasher Energy Star 47.38 $460.95 9 - $1.26 Appliances Dishwasher Energy Star (2011) 6.21 $5.61 15 0.99 $0.08 Appliances Refrigerator Baseline - $0.00 20 - $0.00 Appliances Refrigerator Energy Star 40.56 $20.17 20 - $0.04 Appliances Refrigerator Baseline (2014) 74.30 $0.00 13 1.00 $0.00 Appliances Refrigerator Energy Star (2014) 118.88 $88.71 13 1.01 $0.07 Appliances Freezer Baseline - $0.00 22 - $0.00 Appliances Freezer Energy Star 33.16 $3.98 22 - $0.01 Appliances Freezer Baseline (2014) 76.95 -$145.00 11 1.00 -$0.21 Appliances Freezer Energy Star (2014) 123.12 -$112.83 11 0.99 -$0.10 Appliances Second Refrigerator Baseline - $0.00 20 - $0.00 Appliances Second Refrigerator Energy Star 55.40 $20.67 20 - $0.03 Appliances Second Refrigerator Baseline (2014) 101.48 $0.00 13 1.00 $0.00 Appliances Second Refrigerator Energy Star (2014) 162.38 $88.71 13 1.00 $0.05 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 944 of 1125 Residential Energy Efficiency Equipment and Measure Data B-42 www.enernoc.com End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Appliances Stove Baseline - $0.00 13 1.00 $0.00 Appliances Stove Convection Oven 7.86 $1.86 13 1.00 $0.02 Appliances Stove Induction (High Efficiency) 39.31 $1,432.20 13 0.37 $3.51 Appliances Microwave Baseline - $0.00 9 1.00 $0.00 Electronics Personal Computers Baseline - $0.00 5 1.00 $0.00 Electronics Personal Computers Energy Star 71.87 $1.20 5 1.01 $0.00 Electronics Personal Computers Climate Savers 102.67 $175.49 5 0.85 $0.37 Electronics TVs Baseline - $0.00 11 1.00 $0.00 Electronics TVs Energy Star 41.87 $0.56 11 1.02 $0.00 Electronics Set-top boxes/DVR Baseline - $0.00 11 1.00 $0.00 Electronics Set-top boxes/DVR Energy Star 25.34 $0.56 11 1.01 $0.00 Electronics Devices and Gadgets Devices and Gadgets - $0.00 5 1.00 $0.00 Miscellaneous Pool Pump Baseline Pump - $0.00 15 1.00 $0.00 Miscellaneous Pool Pump High Efficiency Pump 97.63 $85.00 15 0.97 $0.08 Miscellaneous Pool Pump Two-Speed Pump 390.54 $579.00 15 0.71 $0.13 Miscellaneous Furnace Fan Baseline - $0.00 18 1.00 $0.00 Miscellaneous Furnace Fan Furnace Fan with ECM 111.68 $0.64 18 1.26 $0.00 Miscellaneous Miscellaneous Miscellaneous - $0.00 5 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 945 of 1125 Residential Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting B-43 Table B-14 Energy Efficiency Equipment Data, Electric—Mobile Home, New Vintage, Idaho End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Cooling Central AC SEER 13 - $0.00 15 - $0.00 Cooling Central AC SEER 14 (Energy Star) 47.34 $277.86 15 1.40 $0.51 Cooling Central AC SEER 15 (CEE Tier 2) 63.06 $555.71 15 0.94 $0.76 Cooling Central AC SEER 16 (CEE Tier 3) 76.25 $833.57 15 0.89 $0.95 Cooling Central AC Ductless Mini-Split System 143.00 $4,399.48 20 0.62 $2.18 Cooling Room AC EER 9.8 - $0.00 10 1.00 $0.00 Cooling Room AC EER 10.8 (Energy Star) 27.98 $52.02 10 0.85 $0.22 Cooling Room AC EER 11 32.97 $141.13 10 0.65 $0.51 Cooling Room AC EER 11.5 44.72 $312.75 10 0.45 $0.83 Cooling Air Source Heat Pump SEER 13 - $0.00 15 - $0.00 Cooling Air Source Heat Pump SEER 14 (Energy Star) 44.49 $1,720.87 15 1.30 $3.34 Cooling Air Source Heat Pump SEER 15 (CEE Tier 2) 40.65 $2,315.13 15 0.97 $4.93 Cooling Air Source Heat Pump SEER 16 (CEE Tier 3) 49.15 $3,277.48 15 0.89 $5.77 Cooling Air Source Heat Pump Ductless Mini-Split System 92.17 $5,022.03 20 0.90 $3.85 Cooling Geothermal Heat Pump Standard - $0.00 15 1.00 $0.00 Cooling Geothermal Heat Pump High Efficiency 44.66 $1,500.00 15 0.90 $2.90 Cooling Ductless HP Ductless Mini-Split System - $0.00 20 1.00 $0.00 Space Heating Electric Resistance Electric Resistance - $0.00 20 1.00 $0.00 Space Heating Electric Resistance Ductless Mini-Split System 2,426.02 $156.87 20 1.29 $0.00 Space Heating Electric Furnace 3400 BTU/KW - $0.00 15 1.00 $0.00 Space Heating Supplemental Supplemental - $0.00 5 1.00 $0.00 Space Heating Air Source Heat Pump SEER 13 - $0.00 15 - $0.00 Space Heating Air Source Heat Pump SEER 14 (Energy Star) 269.16 $1,720.87 15 1.30 $0.55 Space Heating Air Source Heat Pump SEER 15 (CEE Tier 2) 576.42 $2,315.13 15 0.97 $0.35 Space Heating Air Source Heat Pump SEER 16 (CEE Tier 3) 697.02 $3,277.48 15 0.89 $0.41 Space Heating Air Source Heat Pump Ductless Mini-Split System 1,307.13 $5,022.03 20 0.90 $0.27 Space Heating Geothermal Heat Pump Standard - $0.00 15 1.00 $0.00 Space Heating Geothermal Heat Pump High Efficiency 634.14 $1,500.00 15 0.90 $0.20 Space Heating Ductless HP Ductless Mini-Split System - $0.00 20 1.00 $0.00 Water Heating Water Heater <= 55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00 Water Heating Water Heater <= 55 Gal High Efficiency (EF=0.95) 133.42 $77.11 15 1.01 $0.05 Water Heating Water Heater <= 55 Gal EF 2.3 (HP) 1,286.08 $1,761.86 15 0.66 $0.12 Water Heating Water Heater <= 55 Gal Solar 1,457.32 $6,214.86 15 0.29 $0.37 Water Heating Water Heater > 55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00 Water Heating Water Heater > 55 Gal High Efficiency (EF=0.95) 169.95 $97.23 15 1.01 $0.05 Water Heating Water Heater > EF 2.3 (HP) 1,287.31 $1,691.15 15 0.71 $0.11 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 946 of 1125 Residential Energy Efficiency Equipment and Measure Data B-44 www.enernoc.com End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) 55 Gal Water Heating Water Heater > 55 Gal Solar 1,150.30 $6,144.15 15 0.31 $0.46 Interior Lighting Screw-in Incandescent - $0.00 4 - $0.00 Interior Lighting Screw-in Infrared Halogen 216.42 $188.19 5 1.00 $0.19 Interior Lighting Screw-in CFL 687.25 $28.57 6 2.88 $0.01 Interior Lighting Screw-in LED 939.30 $1,937.55 12 - $0.21 Interior Lighting Screw-in LED 939.30 $1,937.55 12 - $0.21 Interior Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00 Interior Lighting Linear Fluorescent T8 9.28 -$3.50 6 1.14 -$0.07 Interior Lighting Linear Fluorescent Super T8 27.81 $28.01 6 0.67 $0.18 Interior Lighting Linear Fluorescent T5 28.91 $47.43 6 0.52 $0.30 Interior Lighting Linear Fluorescent LED 30.33 $416.33 10 0.18 $1.63 Interior Lighting Specialty Halogen - $0.00 4 1.00 $0.00 Interior Lighting Specialty CFL 208.91 -$7.12 7 2.46 -$0.01 Interior Lighting Specialty LED 219.80 $140.97 12 0.70 $0.07 Exterior Lighting Screw-in Incandescent - $0.00 4 - $0.00 Exterior Lighting Screw-in Infrared Halogen 74.39 $49.25 5 1.00 $0.14 Exterior Lighting Screw-in CFL 252.46 -$1.76 3 4.76 $0.00 Exterior Lighting Screw-in LED 293.05 $726.99 12 - $0.25 Exterior Lighting Screw-in LED 293.05 $726.99 12 - $0.25 Appliances Clothes Washer Baseline - $0.00 14 - $0.00 Appliances Clothes Washer Energy Star (MEF > 1.8) 44.65 $69.81 14 - $0.14 Appliances Clothes Washer Horizontal Axis 61.64 $150.80 14 1.00 $0.22 Appliances Clothes Dryer Baseline - $0.00 13 - $0.00 Appliances Clothes Dryer Moisture Detection 62.00 $48.40 13 1.00 $0.08 Appliances Dishwasher Baseline - $0.00 15 1.00 $0.00 Appliances Dishwasher Energy Star 51.75 $460.95 9 - $1.15 Appliances Dishwasher Energy Star (2011) 6.78 $5.61 15 0.99 $0.07 Appliances Refrigerator Baseline - $0.00 20 - $0.00 Appliances Refrigerator Energy Star 56.79 $20.17 20 - $0.03 Appliances Refrigerator Baseline (2014) 104.02 $0.00 13 1.00 $0.00 Appliances Refrigerator Energy Star (2014) 166.43 $88.71 13 1.02 $0.05 Appliances Freezer Baseline - $0.00 22 - $0.00 Appliances Freezer Energy Star 45.96 $3.98 22 - $0.01 Appliances Freezer Baseline (2014) 106.66 -$145.00 11 1.00 -$0.15 Appliances Freezer Energy Star (2014) 170.66 -$112.83 11 1.00 -$0.07 Appliances Second Refrigerator Baseline - $0.00 20 - $0.00 Appliances Second Refrigerator Energy Star 75.71 $20.67 20 - $0.02 Appliances Second Refrigerator Baseline (2014) 138.70 $0.00 13 1.00 $0.00 Appliances Second Refrigerator Energy Star (2014) 221.91 $88.71 13 1.01 $0.04 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 947 of 1125 Residential Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting B-45 End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Appliances Stove Baseline - $0.00 13 1.00 $0.00 Appliances Stove Convection Oven 33.20 $0.56 13 1.00 $0.00 Appliances Stove Induction (High Efficiency) 39.30 $0.00 13 0.36 $0.00 Appliances Microwave Baseline - $0.00 9 1.00 $0.00 Electronics Personal Computers Baseline - $0.00 5 1.00 $0.00 Electronics Personal Computers Energy Star 70.34 $1.20 5 1.01 $0.00 Electronics Personal Computers Climate Savers 100.48 $175.49 5 0.85 $0.38 Electronics TVs Baseline - $0.00 11 1.00 $0.00 Electronics TVs Energy Star 46.52 $0.56 11 1.02 $0.00 Electronics Set-top boxes/DVR Baseline - $0.00 11 1.00 $0.00 Electronics Set-top boxes/DVR Energy Star 25.34 $0.56 11 1.01 $0.00 Electronics Devices and Gadgets Devices and Gadgets - $0.00 5 1.00 $0.00 Miscellaneous Pool Pump Baseline Pump - $0.00 15 1.00 $0.00 Miscellaneous Pool Pump High Efficiency Pump 109.40 $85.00 15 0.99 $0.07 Miscellaneous Pool Pump Two-Speed Pump 437.62 $579.00 15 0.76 $0.11 Miscellaneous Furnace Fan Baseline - $0.00 18 1.00 $0.00 Miscellaneous Furnace Fan Furnace Fan with ECM 111.68 $0.64 18 1.27 $0.00 Miscellaneous Miscellaneous Miscellaneous - $0.00 5 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 948 of 1125 Residential Energy Efficiency Equipment and Measure Data B-46 www.enernoc.com Table B-15 Energy Efficiency Equipment Data, Electric—Low income, Existing Vintage, Washington End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Cooling Central AC SEER 13 - $0.00 15 - $0.00 Cooling Central AC SEER 14 (Energy Star) 49.41 $185.24 15 1.40 $0.32 Cooling Central AC SEER 15 (CEE Tier 2) 67.79 $370.47 15 0.93 $0.47 Cooling Central AC SEER 16 (CEE Tier 3) 83.19 $555.71 15 0.87 $0.58 Cooling Central AC Ductless Mini-Split System 149.20 $2,394.23 20 0.64 $1.14 Cooling Room AC EER 9.8 - $0.00 10 1.00 $0.00 Cooling Room AC EER 10.8 (Energy Star) 26.53 $104.04 10 0.81 $0.46 Cooling Room AC EER 11 31.30 $282.26 10 0.60 $1.07 Cooling Room AC EER 11.5 42.38 $625.50 10 0.40 $1.75 Cooling Air Source Heat Pump SEER 13 - $0.00 15 - $0.00 Cooling Air Source Heat Pump SEER 14 (Energy Star) 37.76 $1,245.78 15 1.30 $2.85 Cooling Air Source Heat Pump SEER 15 (CEE Tier 2) 51.80 $2,315.13 15 0.91 $3.86 Cooling Air Source Heat Pump SEER 16 (CEE Tier 3) 63.57 $3,277.48 15 0.84 $4.46 Cooling Air Source Heat Pump Ductless Mini-Split System 114.01 $5,022.03 20 0.84 $3.12 Cooling Geothermal Heat Pump Standard - $0.00 15 1.00 $0.00 Cooling Geothermal Heat Pump High Efficiency 62.78 $1,500.00 15 0.89 $2.07 Cooling Ductless HP Ductless Mini-Split System - $0.00 20 1.00 $0.00 Space Heating Electric Resistance Electric Resistance - $0.00 20 1.00 $0.00 Space Heating Electric Resistance Ductless Mini-Split System 2,070.05 $156.87 20 1.29 $0.01 Space Heating Electric Furnace 3400 BTU/KW - $0.00 15 1.00 $0.00 Space Heating Supplemental Supplemental - $0.00 5 1.00 $0.00 Space Heating Air Source Heat Pump SEER 13 - $0.00 15 - $0.00 Space Heating Air Source Heat Pump SEER 14 (Energy Star) 355.79 $1,245.78 15 1.30 $0.30 Space Heating Air Source Heat Pump SEER 15 (CEE Tier 2) 488.18 $2,315.13 15 0.91 $0.41 Space Heating Air Source Heat Pump SEER 16 (CEE Tier 3) 599.06 $3,277.48 15 0.84 $0.47 Space Heating Air Source Heat Pump Ductless Mini-Split System 1,074.41 $5,022.03 20 0.84 $0.33 Space Heating Geothermal Heat Pump Standard - $0.00 15 1.00 $0.00 Space Heating Geothermal Heat Pump High Efficiency 436.67 $1,500.00 15 0.89 $0.30 Space Heating Ductless HP Ductless Mini-Split System - $0.00 20 1.00 $0.00 Water Heating Water Heater <= 55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00 Water Heating Water Heater <= 55 Gal High Efficiency (EF=0.95) 121.27 $77.11 15 1.01 $0.05 Water Heating Water Heater <= 55 Gal EF 2.3 (HP) 1,168.96 $1,761.86 15 0.67 $0.13 Water Heating Water Heater <= 55 Gal Solar 1,324.61 $6,214.86 15 0.29 $0.41 Water Heating Water Heater > 55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00 Water Heating Water Heater > High Efficiency 171.20 $97.23 15 1.02 $0.05 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 949 of 1125 Residential Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting B-47 End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) 55 Gal (EF=0.95) Water Heating Water Heater > 55 Gal EF 2.3 (HP) 1,296.77 $1,691.15 15 0.76 $0.11 Water Heating Water Heater > 55 Gal Solar 1,158.76 $6,144.15 15 0.34 $0.46 Interior Lighting Screw-in Incandescent - $0.00 4 - $0.00 Interior Lighting Screw-in Infrared Halogen 157.77 $98.38 5 1.00 $0.13 Interior Lighting Screw-in CFL 501.00 $17.84 6 2.46 $0.01 Interior Lighting Screw-in LED 684.74 $1,012.85 12 - $0.15 Interior Lighting Screw-in LED 684.74 $1,012.85 12 - $0.15 Interior Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00 Interior Lighting Linear Fluorescent T8 6.94 -$1.79 6 1.13 -$0.05 Interior Lighting Linear Fluorescent Super T8 20.79 $14.30 6 0.74 $0.13 Interior Lighting Linear Fluorescent T5 21.61 $24.22 6 0.59 $0.21 Interior Lighting Linear Fluorescent LED 22.67 $212.60 10 0.21 $1.11 Interior Lighting Specialty Halogen - $0.00 4 1.00 $0.00 Interior Lighting Specialty CFL 134.16 $0.96 7 1.91 $0.00 Interior Lighting Specialty LED 141.16 $261.26 12 0.29 $0.19 Exterior Lighting Screw-in Incandescent - $0.00 4 - $0.00 Exterior Lighting Screw-in Infrared Halogen 35.33 $9.82 5 1.00 $0.06 Exterior Lighting Screw-in CFL 119.89 -$0.47 3 4.15 $0.00 Exterior Lighting Screw-in LED 139.17 $1,016.52 12 - $0.75 Exterior Lighting Screw-in LED 139.17 $1,016.52 12 - $0.75 Appliances Clothes Washer Baseline - $0.00 14 - $0.00 Appliances Clothes Washer Energy Star (MEF > 1.8) 36.47 $69.81 14 - $0.17 Appliances Clothes Washer Horizontal Axis 50.35 $150.80 14 1.00 $0.27 Appliances Clothes Dryer Baseline - $0.00 13 - $0.00 Appliances Clothes Dryer Moisture Detection 53.87 $48.40 13 1.00 $0.09 Appliances Dishwasher Baseline - $0.00 15 1.00 $0.00 Appliances Dishwasher Energy Star 45.15 $460.95 9 - $1.32 Appliances Dishwasher Energy Star (2011) 5.91 $5.61 15 0.99 $0.08 Appliances Refrigerator Baseline - $0.00 20 - $0.00 Appliances Refrigerator Energy Star 38.65 $20.17 20 - $0.04 Appliances Refrigerator Baseline (2014) 70.80 $0.00 13 1.00 $0.00 Appliances Refrigerator Energy Star (2014) 113.29 $88.71 13 1.01 $0.08 Appliances Freezer Baseline - $0.00 22 - $0.00 Appliances Freezer Energy Star 31.60 $3.98 22 - $0.01 Appliances Freezer Baseline (2014) 73.33 -$145.00 11 1.00 -$0.22 Appliances Freezer Energy Star (2014) 117.32 -$112.83 11 0.99 -$0.11 Appliances Second Refrigerator Baseline - $0.00 13 - $0.00 Appliances Second Refrigerator Energy Star 52.79 $20.67 20 - $0.03 Appliances Second Refrigerator Baseline (2014) 96.71 $0.00 13 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 950 of 1125 Residential Energy Efficiency Equipment and Measure Data B-48 www.enernoc.com End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Appliances Second Refrigerator Energy Star (2014) 154.73 $88.71 13 1.00 $0.06 Appliances Stove Baseline - $0.00 13 1.00 $0.00 Appliances Stove Convection Oven 7.49 $1.86 13 1.00 $0.02 Appliances Stove Induction (High Efficiency) 37.46 $1,432.20 13 0.37 $3.68 Appliances Microwave Baseline - $0.00 9 1.00 $0.00 Electronics Personal Computers Baseline - $0.00 5 1.00 $0.00 Electronics Personal Computers Energy Star 63.35 $1.20 5 1.01 $0.00 Electronics Personal Computers Climate Savers 90.50 $175.49 5 0.85 $0.42 Electronics TVs Baseline - $0.00 11 1.00 $0.00 Electronics TVs Energy Star 38.99 $0.56 11 1.02 $0.00 Electronics Set-top boxes/DVR Baseline - $0.00 11 1.00 $0.00 Electronics Set-top boxes/DVR Energy Star 24.86 $0.56 11 1.01 $0.00 Electronics Devices and Gadgets Devices and Gadgets - $0.00 5 1.00 $0.00 Miscellaneous Pool Pump Baseline Pump - $0.00 15 1.00 $0.00 Miscellaneous Pool Pump High Efficiency Pump 107.45 $85.00 15 0.99 $0.07 Miscellaneous Pool Pump Two-Speed Pump 429.80 $579.00 15 0.75 $0.12 Miscellaneous Furnace Fan Baseline - $0.00 18 1.00 $0.00 Miscellaneous Furnace Fan Furnace Fan with ECM 110.30 $0.64 18 1.27 $0.00 Miscellaneous Miscellaneous Miscellaneous - $0.00 5 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 951 of 1125 Residential Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting B-49 Table B-16 Energy Efficiency Equipment Data, Electric—Low Income, New Vintage, Washington End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Cooling Central AC SEER 13 - $0.00 15 - $0.00 Cooling Central AC SEER 14 (Energy Star) 58.73 $185.24 15 1.40 $0.27 Cooling Central AC SEER 15 (CEE Tier 2) 78.22 $370.47 15 0.93 $0.41 Cooling Central AC SEER 16 (CEE Tier 3) 94.59 $555.71 15 0.87 $0.51 Cooling Central AC Ductless Mini-Split System 177.38 $2,394.23 20 0.65 $0.95 Cooling Room AC EER 9.8 - $0.00 10 1.00 $0.00 Cooling Room AC EER 10.8 (Energy Star) 30.83 $104.04 10 0.82 $0.40 Cooling Room AC EER 11 36.33 $282.26 10 0.61 $0.92 Cooling Room AC EER 11.5 49.27 $625.50 10 0.41 $1.50 Cooling Air Source Heat Pump SEER 13 - $0.00 15 - $0.00 Cooling Air Source Heat Pump SEER 14 (Energy Star) 44.94 $0.00 15 1.30 $0.00 Cooling Air Source Heat Pump SEER 15 (CEE Tier 2) 59.86 $0.00 15 0.91 $0.00 Cooling Air Source Heat Pump SEER 16 (CEE Tier 3) 72.38 $0.00 15 0.85 $0.00 Cooling Air Source Heat Pump Ductless Mini-Split System 135.74 $0.00 20 0.86 $0.00 Cooling Geothermal Heat Pump Standard - $0.00 15 1.00 $0.00 Cooling Geothermal Heat Pump High Efficiency 69.87 $0.00 15 0.89 $0.00 Cooling Ductless HP Ductless Mini-Split System - $0.00 20 1.00 $0.00 Space Heating Electric Resistance Electric Resistance - $0.00 20 1.00 $0.00 Space Heating Electric Resistance Ductless Mini-Split System 2,225.30 $156.87 20 1.30 $0.00 Space Heating Electric Furnace 3400 BTU/KW - $0.00 15 1.00 $0.00 Space Heating Supplemental Supplemental - $0.00 5 1.00 $0.00 Space Heating Air Source Heat Pump SEER 13 - $0.00 15 - $0.00 Space Heating Air Source Heat Pump SEER 14 (Energy Star) 423.49 $1,245.78 15 1.30 $0.25 Space Heating Air Source Heat Pump SEER 15 (CEE Tier 2) 564.08 $2,315.13 15 0.91 $0.35 Space Heating Air Source Heat Pump SEER 16 (CEE Tier 3) 682.10 $3,277.48 15 0.85 $0.42 Space Heating Air Source Heat Pump Ductless Mini-Split System 1,279.15 $5,022.03 20 0.86 $0.28 Space Heating Geothermal Heat Pump Standard - $0.00 15 1.00 $0.00 Space Heating Geothermal Heat Pump High Efficiency 485.98 $1,500.00 15 0.89 $0.27 Space Heating Ductless HP Ductless Mini-Split System - $0.00 20 1.00 $0.00 Water Heating Water Heater <= 55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00 Water Heating Water Heater <= 55 Gal High Efficiency (EF=0.95) 126.97 $77.11 15 1.01 $0.05 Water Heating Water Heater <= 55 Gal EF 2.3 (HP) 1,223.96 $1,761.86 15 0.69 $0.12 Water Heating Water Heater <= 55 Gal Solar 1,386.93 $6,214.86 15 0.30 $0.39 Water Heating Water Heater > 55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00 Water Heating Water Heater > High Efficiency 179.32 $97.23 15 1.02 $0.05 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 952 of 1125 Residential Energy Efficiency Equipment and Measure Data B-50 www.enernoc.com End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) 55 Gal (EF=0.95) Water Heating Water Heater > 55 Gal EF 2.3 (HP) 1,358.29 $1,691.15 15 0.77 $0.11 Water Heating Water Heater > 55 Gal Solar 1,213.73 $6,144.15 15 0.35 $0.44 Interior Lighting Screw-in Incandescent - $0.00 4 - $0.00 Interior Lighting Screw-in Infrared Halogen 171.92 $98.38 5 1.00 $0.12 Interior Lighting Screw-in CFL 545.94 $17.84 6 2.41 $0.01 Interior Lighting Screw-in LED 746.16 $1,012.85 12 - $0.14 Interior Lighting Screw-in LED 746.16 $1,012.85 12 - $0.14 Interior Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00 Interior Lighting Linear Fluorescent T8 7.80 -$1.79 6 1.13 -$0.04 Interior Lighting Linear Fluorescent Super T8 23.37 $14.30 6 0.77 $0.11 Interior Lighting Linear Fluorescent T5 24.29 $24.22 6 0.62 $0.18 Interior Lighting Linear Fluorescent LED 25.48 $212.60 10 0.23 $0.99 Interior Lighting Specialty Halogen - $0.00 4 1.00 $0.00 Interior Lighting Specialty CFL 144.22 -$9.74 7 2.86 -$0.01 Interior Lighting Specialty LED 151.74 $67.71 12 0.95 $0.05 Exterior Lighting Screw-in Incandescent - $0.00 4 - $0.00 Exterior Lighting Screw-in Infrared Halogen 38.38 $9.82 5 1.00 $0.06 Exterior Lighting Screw-in CFL 130.23 -$0.51 3 4.13 $0.00 Exterior Lighting Screw-in LED 151.17 $144.92 12 - $0.10 Exterior Lighting Screw-in LED 151.17 $144.92 12 - $0.10 Appliances Clothes Washer Baseline - $0.00 14 - $0.00 Appliances Clothes Washer Energy Star (MEF > 1.8) 42.55 $69.81 14 - $0.15 Appliances Clothes Washer Horizontal Axis 58.74 $150.80 14 1.00 $0.23 Appliances Clothes Dryer Baseline - $0.00 13 - $0.00 Appliances Clothes Dryer Moisture Detection 58.62 $48.40 13 1.00 $0.08 Appliances Dishwasher Baseline - $0.00 15 1.00 $0.00 Appliances Dishwasher Energy Star 49.31 $460.95 9 - $1.21 Appliances Dishwasher Energy Star (2011) 6.46 $5.61 15 0.99 $0.08 Appliances Refrigerator Baseline - $0.00 20 - $0.00 Appliances Refrigerator Energy Star 54.11 $20.17 20 - $0.03 Appliances Refrigerator Baseline (2014) 99.12 $0.00 13 1.00 $0.00 Appliances Refrigerator Energy Star (2014) 158.60 $88.71 13 1.02 $0.05 Appliances Freezer Baseline - $0.00 22 - $0.00 Appliances Freezer Energy Star 43.80 $3.98 22 - $0.01 Appliances Freezer Baseline (2014) 101.64 -$145.00 11 1.00 -$0.16 Appliances Freezer Energy Star (2014) 162.63 -$112.83 11 1.00 -$0.08 Appliances Second Refrigerator Baseline - $0.00 20 - $0.00 Appliances Second Refrigerator Energy Star 72.15 $20.67 20 - $0.02 Appliances Second Refrigerator Baseline (2014) 132.17 $0.00 13 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 953 of 1125 Residential Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting B-51 End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Appliances Second Refrigerator Energy Star (2014) 211.47 $88.71 13 1.01 $0.04 Appliances Stove Baseline - $0.00 13 1.00 $0.00 Appliances Stove Convection Oven 7.49 $1.86 13 1.00 $0.02 Appliances Stove Induction (High Efficiency) 37.45 $1,432.20 13 0.37 $3.68 Appliances Microwave Baseline - $0.00 9 1.00 $0.00 Electronics Personal Computers Baseline - $0.00 5 1.00 $0.00 Electronics Personal Computers Energy Star 62.00 $1.20 5 1.01 $0.00 Electronics Personal Computers Climate Savers 88.57 $175.49 5 0.85 $0.43 Electronics TVs Baseline - $0.00 11 1.00 $0.00 Electronics TVs Energy Star 43.32 $0.56 11 1.02 $0.00 Electronics Set-top boxes/DVR Baseline - $0.00 11 1.00 $0.00 Electronics Set-top boxes/DVR Energy Star 24.86 $0.56 11 1.01 $0.00 Electronics Devices and Gadgets Devices and Gadgets - $0.00 5 1.00 $0.00 Miscellaneous Pool Pump Baseline Pump - $0.00 15 1.00 $0.00 Miscellaneous Pool Pump High Efficiency Pump 120.40 $85.00 15 0.99 $0.06 Miscellaneous Pool Pump Two-Speed Pump 481.61 $579.00 15 0.79 $0.10 Miscellaneous Furnace Fan Baseline - $0.00 18 1.00 $0.00 Miscellaneous Furnace Fan Furnace Fan with ECM 110.30 $0.64 18 1.27 $0.00 Miscellaneous Miscellaneous Miscellaneous - $0.00 5 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 954 of 1125 Residential Energy Efficiency Equipment and Measure Data B-52 www.enernoc.com Table B-17 Energy Efficiency Equipment Data, Electric—Low Income, Existing Vintage, Idaho End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Cooling Central AC SEER 13 - $0.00 15 - $0.00 Cooling Central AC SEER 14 (Energy Star) 34.58 $185.24 15 1.40 $0.46 Cooling Central AC SEER 15 (CEE Tier 2) 47.45 $370.47 15 0.93 $0.68 Cooling Central AC SEER 16 (CEE Tier 3) 58.23 $555.71 15 0.87 $0.83 Cooling Central AC Ductless Mini-Split System 104.44 $2,394.23 20 0.63 $1.62 Cooling Room AC EER 9.8 - $0.00 10 1.00 $0.00 Cooling Room AC EER 10.8 (Energy Star) 18.57 $104.04 10 0.80 $0.66 Cooling Room AC EER 11 21.91 $282.26 10 0.59 $1.53 Cooling Room AC EER 11.5 29.66 $625.50 10 0.39 $2.50 Cooling Air Source Heat Pump SEER 13 - $0.00 15 - $0.00 Cooling Air Source Heat Pump SEER 14 (Energy Star) 26.43 $1,245.78 15 1.30 $4.08 Cooling Air Source Heat Pump SEER 15 (CEE Tier 2) 36.26 $2,315.13 15 0.91 $5.52 Cooling Air Source Heat Pump SEER 16 (CEE Tier 3) 44.50 $3,277.48 15 0.83 $6.37 Cooling Air Source Heat Pump Ductless Mini-Split System 79.81 $5,022.03 20 0.84 $4.45 Cooling Geothermal Heat Pump Standard - $0.00 15 1.00 $0.00 Cooling Geothermal Heat Pump High Efficiency 43.95 $1,500.00 15 0.87 $2.95 Cooling Ductless HP Ductless Mini-Split System - $0.00 20 1.00 $0.00 Space Heating Electric Resistance Electric Resistance - $0.00 20 1.00 $0.00 Space Heating Electric Resistance Ductless Mini-Split System 1,966.55 $156.87 20 1.29 $0.01 Space Heating Electric Furnace 3400 BTU/KW - $0.00 15 1.00 $0.00 Space Heating Supplemental Supplemental - $0.00 5 1.00 $0.00 Space Heating Air Source Heat Pump SEER 13 - $0.00 15 - $0.00 Space Heating Air Source Heat Pump SEER 14 (Energy Star) 338.00 $1,245.78 15 1.30 $0.32 Space Heating Air Source Heat Pump SEER 15 (CEE Tier 2) 463.77 $2,315.13 15 0.91 $0.43 Space Heating Air Source Heat Pump SEER 16 (CEE Tier 3) 569.10 $3,277.48 15 0.83 $0.50 Space Heating Air Source Heat Pump Ductless Mini-Split System 1,020.69 $5,022.03 20 0.84 $0.35 Space Heating Geothermal Heat Pump Standard - $0.00 15 1.00 $0.00 Space Heating Geothermal Heat Pump High Efficiency 414.84 $1,500.00 15 0.87 $0.31 Space Heating Ductless HP Ductless Mini-Split System - $0.00 20 1.00 $0.00 Water Heating Water Heater <= 55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00 Water Heating Water Heater <= 55 Gal High Efficiency (EF=0.95) 113.39 $77.11 15 1.00 $0.06 Water Heating Water Heater <= 55 Gal EF 2.3 (HP) 1,092.98 $1,761.86 15 0.60 $0.14 Water Heating Water Heater <= 55 Gal Solar 1,238.51 $6,214.86 15 0.26 $0.43 Water Heating Water Heater > 55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00 Water Heating Water Heater > 55 Gal High Efficiency (EF=0.95) 160.07 $97.23 15 1.01 $0.05 Water Heating Water Heater > EF 2.3 (HP) 1,212.48 $1,691.15 15 0.68 $0.12 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 955 of 1125 Residential Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting B-53 End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) 55 Gal Water Heating Water Heater > 55 Gal Solar 1,083.44 $6,144.15 15 0.30 $0.49 Interior Lighting Screw-in Incandescent - $0.00 4 - $0.00 Interior Lighting Screw-in Infrared Halogen 147.51 $98.38 5 1.00 $0.14 Interior Lighting Screw-in CFL 468.44 $17.84 6 2.59 $0.01 Interior Lighting Screw-in LED 640.24 $1,012.85 12 - $0.16 Interior Lighting Screw-in LED 640.24 $1,012.85 12 - $0.16 Interior Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00 Interior Lighting Linear Fluorescent T8 6.49 -$1.79 6 1.13 -$0.05 Interior Lighting Linear Fluorescent Super T8 19.44 $14.30 6 0.73 $0.13 Interior Lighting Linear Fluorescent T5 20.21 $24.22 6 0.57 $0.22 Interior Lighting Linear Fluorescent LED 21.20 $212.60 10 0.21 $1.19 Interior Lighting Specialty Halogen - $0.00 4 1.00 $0.00 Interior Lighting Specialty CFL 125.44 $0.96 7 1.91 $0.00 Interior Lighting Specialty LED 131.98 $261.26 12 0.28 $0.20 Exterior Lighting Screw-in Incandescent - $0.00 4 - $0.00 Exterior Lighting Screw-in Infrared Halogen 33.03 $9.82 5 1.00 $0.06 Exterior Lighting Screw-in CFL 112.10 -$0.47 3 4.28 $0.00 Exterior Lighting Screw-in LED 130.12 $1,016.52 12 - $0.80 Exterior Lighting Screw-in LED 130.12 $1,016.52 12 - $0.80 Appliances Clothes Washer Baseline - $0.00 14 - $0.00 Appliances Clothes Washer Energy Star (MEF > 1.8) 34.10 $69.81 14 - $0.19 Appliances Clothes Washer Horizontal Axis 47.07 $150.80 14 1.00 $0.29 Appliances Clothes Dryer Baseline - $0.00 13 - $0.00 Appliances Clothes Dryer Moisture Detection 50.36 $48.40 13 1.00 $0.09 Appliances Dishwasher Baseline - $0.00 15 1.00 $0.00 Appliances Dishwasher Energy Star 42.21 $460.95 9 - $1.41 Appliances Dishwasher Energy Star (2011) 5.53 $5.61 15 0.99 $0.09 Appliances Refrigerator Baseline - $0.00 20 - $0.00 Appliances Refrigerator Energy Star 36.14 $20.17 20 - $0.04 Appliances Refrigerator Baseline (2014) 66.20 $0.00 13 1.00 $0.00 Appliances Refrigerator Energy Star (2014) 105.92 $88.71 13 1.00 $0.08 Appliances Freezer Baseline - $0.00 22 - $0.00 Appliances Freezer Energy Star 29.54 $3.98 22 - $0.01 Appliances Freezer Baseline (2014) 68.56 -$145.00 11 1.00 -$0.23 Appliances Freezer Energy Star (2014) 109.70 -$112.83 11 0.98 -$0.11 Appliances Second Refrigerator Baseline - $0.00 20 - $0.00 Appliances Second Refrigerator Energy Star 49.36 $20.67 20 - $0.03 Appliances Second Refrigerator Baseline (2014) 90.42 $0.00 13 1.00 $0.00 Appliances Second Refrigerator Energy Star (2014) 144.67 $88.71 13 1.00 $0.06 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 956 of 1125 Residential Energy Efficiency Equipment and Measure Data B-54 www.enernoc.com End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Appliances Stove Baseline - $0.00 13 1.00 $0.00 Appliances Stove Convection Oven 7.00 $1.86 13 1.00 $0.03 Appliances Stove Induction (High Efficiency) 35.02 $1,432.20 13 0.36 $3.94 Appliances Microwave Baseline - $0.00 9 1.00 $0.00 Electronics Personal Computers Baseline - $0.00 5 1.00 $0.00 Electronics Personal Computers Energy Star 59.23 $1.20 5 1.01 $0.00 Electronics Personal Computers Climate Savers 84.61 $175.49 5 0.85 $0.45 Electronics TVs Baseline - $0.00 11 1.00 $0.00 Electronics TVs Energy Star 36.45 $0.56 11 1.01 $0.00 Electronics Set-top boxes/DVR Baseline - $0.00 11 1.00 $0.00 Electronics Set-top boxes/DVR Energy Star 23.24 $0.56 11 1.01 $0.00 Electronics Devices and Gadgets Devices and Gadgets - $0.00 5 1.00 $0.00 Miscellaneous Pool Pump Baseline Pump - $0.00 15 1.00 $0.00 Miscellaneous Pool Pump High Efficiency Pump 100.46 $85.00 15 0.98 $0.07 Miscellaneous Pool Pump Two-Speed Pump 401.86 $579.00 15 0.73 $0.12 Miscellaneous Furnace Fan Baseline - $0.00 18 1.00 $0.00 Miscellaneous Furnace Fan Furnace Fan with ECM 103.13 $0.64 18 1.26 $0.00 Miscellaneous Miscellaneous Miscellaneous - $0.00 5 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 957 of 1125 Residential Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting B-55 Table B-18 Energy Efficiency Equipment Data, Electric—Low income, New Vintage, Idaho End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Cooling Central AC SEER 13 - $0.00 15 - $0.00 Cooling Central AC SEER 14 (Energy Star) 41.11 $185.24 15 1.40 $0.39 Cooling Central AC SEER 15 (CEE Tier 2) 54.76 $370.47 15 0.93 $0.59 Cooling Central AC SEER 16 (CEE Tier 3) 66.21 $555.71 15 0.87 $0.73 Cooling Central AC Ductless Mini-Split System 124.17 $2,394.23 20 0.64 $1.36 Cooling Room AC EER 9.8 - $0.00 10 1.00 $0.00 Cooling Room AC EER 10.8 (Energy Star) 21.58 $104.04 10 0.80 $0.57 Cooling Room AC EER 11 25.43 $282.26 10 0.59 $1.32 Cooling Room AC EER 11.5 34.49 $625.50 10 0.39 $2.15 Cooling Air Source Heat Pump SEER 13 - $0.00 15 - $0.00 Cooling Air Source Heat Pump SEER 14 (Energy Star) 31.46 $0.00 15 1.30 $0.00 Cooling Air Source Heat Pump SEER 15 (CEE Tier 2) 41.90 $0.00 15 0.91 $0.00 Cooling Air Source Heat Pump SEER 16 (CEE Tier 3) 50.67 $0.00 15 0.85 $0.00 Cooling Air Source Heat Pump Ductless Mini-Split System 95.02 $0.00 20 0.85 $0.00 Cooling Geothermal Heat Pump Standard - $0.00 15 1.00 $0.00 Cooling Geothermal Heat Pump High Efficiency 48.91 $0.00 15 0.87 $0.00 Cooling Ductless HP Ductless Mini-Split System - $0.00 20 1.00 $0.00 Space Heating Electric Resistance Electric Resistance - $0.00 20 1.00 $0.00 Space Heating Electric Resistance Ductless Mini-Split System 2,114.04 $156.87 20 1.30 $0.01 Space Heating Electric Furnace 3400 BTU/KW - $0.00 15 1.00 $0.00 Space Heating Supplemental Supplemental - $0.00 5 1.00 $0.00 Space Heating Air Source Heat Pump SEER 13 - $0.00 15 - $0.00 Space Heating Air Source Heat Pump SEER 14 (Energy Star) 402.32 $1,245.78 15 1.30 $0.27 Space Heating Air Source Heat Pump SEER 15 (CEE Tier 2) 535.87 $2,315.13 15 0.91 $0.37 Space Heating Air Source Heat Pump SEER 16 (CEE Tier 3) 647.99 $3,277.48 15 0.85 $0.44 Space Heating Air Source Heat Pump Ductless Mini-Split System 1,215.19 $5,022.03 20 0.85 $0.29 Space Heating Geothermal Heat Pump Standard - $0.00 15 1.00 $0.00 Space Heating Geothermal Heat Pump High Efficiency 461.68 $1,500.00 15 0.87 $0.28 Space Heating Ductless HP Ductless Mini-Split System - $0.00 20 1.00 $0.00 Water Heating Water Heater <= 55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00 Water Heating Water Heater <= 55 Gal High Efficiency (EF=0.95) 118.72 $77.11 15 1.00 $0.06 Water Heating Water Heater <= 55 Gal EF 2.3 (HP) 1,144.40 $1,761.86 15 0.62 $0.13 Water Heating Water Heater <= 55 Gal Solar 1,296.78 $6,214.86 15 0.26 $0.41 Water Heating Water Heater > 55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00 Water Heating Water Heater > 55 Gal High Efficiency (EF=0.95) 167.67 $97.23 15 1.01 $0.05 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 958 of 1125 Residential Energy Efficiency Equipment and Measure Data B-56 www.enernoc.com End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Water Heating Water Heater > 55 Gal EF 2.3 (HP) 1,270.00 $1,691.15 15 0.70 $0.12 Water Heating Water Heater > 55 Gal Solar 1,134.84 $6,144.15 15 0.31 $0.47 Interior Lighting Screw-in Incandescent - $0.00 4 - $0.00 Interior Lighting Screw-in Infrared Halogen 160.74 $98.38 5 1.00 $0.13 Interior Lighting Screw-in CFL 510.45 $17.84 6 2.54 $0.01 Interior Lighting Screw-in LED 697.66 $1,012.85 12 - $0.15 Interior Lighting Screw-in LED 697.66 $1,012.85 12 - $0.15 Interior Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00 Interior Lighting Linear Fluorescent T8 7.29 -$1.79 6 1.13 -$0.05 Interior Lighting Linear Fluorescent Super T8 21.85 $14.30 6 0.75 $0.12 Interior Lighting Linear Fluorescent T5 22.71 $24.22 6 0.60 $0.20 Interior Lighting Linear Fluorescent LED 23.82 $212.60 10 0.22 $1.06 Interior Lighting Specialty Halogen - $0.00 4 1.00 $0.00 Interior Lighting Specialty CFL 134.85 -$9.64 7 2.92 -$0.01 Interior Lighting Specialty LED 141.88 $71.04 12 0.91 $0.05 Exterior Lighting Screw-in Incandescent - $0.00 4 - $0.00 Exterior Lighting Screw-in Infrared Halogen 35.88 $9.82 5 1.00 $0.06 Exterior Lighting Screw-in CFL 121.77 -$0.51 3 4.25 $0.00 Exterior Lighting Screw-in LED 141.35 $144.92 12 - $0.11 Exterior Lighting Screw-in LED 141.35 $144.92 12 - $0.11 Appliances Clothes Washer Baseline - $0.00 14 - $0.00 Appliances Clothes Washer Energy Star (MEF > 1.8) 39.78 $69.81 14 - $0.16 Appliances Clothes Washer Horizontal Axis 54.92 $150.80 14 1.00 $0.25 Appliances Clothes Dryer Baseline - $0.00 13 - $0.00 Appliances Clothes Dryer Moisture Detection 54.81 $48.40 13 1.00 $0.09 Appliances Dishwasher Baseline - $0.00 15 1.00 $0.00 Appliances Dishwasher Energy Star 46.11 $460.95 9 - $1.29 Appliances Dishwasher Energy Star (2011) 6.04 $5.61 15 0.99 $0.08 Appliances Refrigerator Baseline - $0.00 20 - $0.00 Appliances Refrigerator Energy Star 50.60 $20.17 20 - $0.03 Appliances Refrigerator Baseline (2014) 92.68 $0.00 13 1.00 $0.00 Appliances Refrigerator Energy Star (2014) 148.29 $88.71 13 1.01 $0.06 Appliances Freezer Baseline - $0.00 22 - $0.00 Appliances Freezer Energy Star 40.95 $3.98 22 - $0.01 Appliances Freezer Baseline (2014) 95.04 -$145.00 11 1.00 -$0.17 Appliances Freezer Energy Star (2014) 152.06 -$112.83 11 1.00 -$0.08 Appliances Second Refrigerator Baseline - $0.00 20 - $0.00 Appliances Second Refrigerator Energy Star 67.46 $20.67 20 - $0.02 Appliances Second Refrigerator Baseline (2014) 123.58 $0.00 13 1.00 $0.00 Appliances Second Energy Star (2014) 197.72 $88.71 13 1.01 $0.04 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 959 of 1125 Residential Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting B-57 End Use Technology Eff. Definition Savings (kWh/HH/yr) Incremental Cost ($/HH) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Refrigerator Appliances Stove Baseline - $0.00 13 1.00 $0.00 Appliances Stove Convection Oven 7.00 $1.86 13 1.00 $0.03 Appliances Stove Induction (High Efficiency) 35.02 $1,432.20 13 0.36 $3.94 Appliances Microwave Baseline - $0.00 9 1.00 $0.00 Electronics Personal Computers Baseline - $0.00 5 1.00 $0.00 Electronics Personal Computers Energy Star 57.97 $1.20 5 1.01 $0.00 Electronics Personal Computers Climate Savers 82.81 $175.49 5 0.85 $0.46 Electronics TVs Baseline - $0.00 11 1.00 $0.00 Electronics TVs Energy Star 40.50 $0.56 11 1.02 $0.00 Electronics Set-top boxes/DVR Baseline - $0.00 11 1.00 $0.00 Electronics Set-top boxes/DVR Energy Star 23.24 $0.56 11 1.01 $0.00 Electronics Devices and Gadgets Devices and Gadgets - $0.00 5 1.00 $0.00 Miscellaneous Pool Pump Baseline Pump - $0.00 15 1.00 $0.00 Miscellaneous Pool Pump High Efficiency Pump 112.58 $85.00 15 0.99 $0.07 Miscellaneous Pool Pump Two-Speed Pump 450.31 $579.00 15 0.77 $0.11 Miscellaneous Furnace Fan Baseline - $0.00 18 1.00 $0.00 Miscellaneous Furnace Fan Furnace Fan with ECM 103.13 $0.64 18 1.26 $0.00 Miscellaneous Miscellaneous Miscellaneous - $0.00 5 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 960 of 1125 Residential Energy Efficiency Equipment and Measure Data B-58 www.enernoc.com Table B-19 Energy Efficiency Non-Equipment Data, Electric—Single Family, Existing Vintage, Washington Measure Base Saturation Applicability Lifetime (Years) Cost ($/HH) Savings (kWh) BC Ratio Levelized Cost ($/kWh) Central AC - Early Replacement 0.0% 80.0% 15 $2,895.00 139.3 0.00 $2.133 Central AC - Maintenance and Tune-Up 41.0% 100.0% 4 $125.00 137.4 0.06 $0.251 Room AC - Removal of Second Unit 0.0% 100.0% 5 $75.00 512.4 0.42 $0.033 Attic Fan - Installation 12.0% 50.0% 18 $115.80 6.2 0.00 $1.736 Attic Fan - Photovoltaic - Installation 13.0% 100.0% 19 $350.00 6.2 0.00 $5.107 Ceiling Fan - Installation 51.0% 100.0% 15 $160.00 108.8 0.06 $0.151 Whole-House Fan - Installation 6.9% 25.0% 18 $200.00 174.6 0.08 $0.106 Air Source Heat Pump - Maintenance 37.8% 100.0% 4 $125.00 926.7 0.42 $0.037 Insulation - Ducting 15.0% 59.4% 18 $500.00 483.1 0.09 $0.096 Repair and Sealing - Ducting 12.3% 100.0% 20 $571.38 2,111.0 0.35 $0.024 Thermostat - Clock/Programmable 71.8% 75.0% 15 $249.47 587.7 0.49 $0.044 Doors - Storm and Thermal 38.0% 100.0% 12 $320.00 116.9 0.05 $0.322 Insulation - Infiltration Control 46.0% 100.0% 25 $306.11 876.6 0.48 $0.028 Insulation - Ceiling 76.4% 75.0% 25 $630.45 991.9 0.18 $0.051 Insulation - Radiant Barrier 5.0% 100.0% 12 $922.68 571.9 0.09 $0.190 Roofs - High Reflectivity 5.0% 100.0% 15 $1,549.61 82.7 0.00 $1.923 Windows - Reflective Film 5.0% 50.0% 10 $266.67 369.6 0.12 $0.096 Windows - High Efficiency/Energy Star 77.6% 100.0% 25 $5,200.97 4,270.5 0.11 $0.098 Interior Lighting - Occupancy Sensor 23.5% 50.0% 15 $750.00 444.7 0.05 $0.173 Exterior Lighting - Photovoltaic Installation 10.0% 100.0% 15 $2,975.00 53.8 0.00 $5.679 Exterior Lighting - Photosensor Control 23.5% 100.0% 8 $90.00 36.3 0.03 $0.388 Exterior Lighting - Timeclock Installation 10.0% 100.0% 8 $72.00 36.3 0.04 $0.310 Water Heater - Faucet Aerators 53.2% 100.0% 25 $24.00 275.8 1.23 $0.007 Water Heater - Pipe Insulation 17.0% 100.0% 13 $15.00 242.9 1.94 $0.007 Water Heater - Low Flow Showerheads 75.5% 100.0% 10 $25.48 354.0 1.87 $0.010 Water Heater - Tank Blanket/Insulation 54.0% 100.0% 10 $15.00 781.1 4.19 $0.003 Water Heater - Thermostat Setback 17.0% 100.0% 5 $40.00 781.1 1.23 $0.012 Electronics - Reduce Standby Wattage 5.0% 100.0% 8 $20.00 117.4 0.47 $0.027 Refrigerator - Early Replacement 10.0% 85.0% 7 $109.00 319.9 0.16 $0.059 Refrigerator - Remove Second Unit 17.3% 85.0% 7 $109.00 437.0 0.83 $0.043 Freezer - Early Replacement 10.0% 85.0% 5 $109.00 355.4 0.14 $0.070 Freezer - Remove Second Unit 17.3% 85.0% 5 $109.00 384.9 0.75 $0.065 Behavioral Measures 20.0% 50.0% 1 $12.00 125.0 0.20 $0.096 Pool - Pump Timer 58.8% 100.0% 15 $160.00 194.3 0.12 $0.085 Insulation - Foundation 25.9% 39.0% 25 $750.53 521.1 0.19 $0.116 Insulation - Wall Cavity 88.4% 100.0% 25 $1,415.87 2,186.1 0.17 $0.052 Insulation - Wall Sheathing 64.4% 100.0% 20 $300.00 276.9 0.14 $0.096 Water Heater - Solar System 5.0% 25.0% 20 $6,500.00 6,437.3 0.11 $0.089 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 961 of 1125 Residential Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting B-59 Table B-20 Energy Efficiency Non-Equipment Data, Electric—Single Family, New Vintage, Washington Measure Base Saturation Applicability Lifetime (Years) Cost ($/HH) Savings (kWh) BC Ratio Levelized Cost ($/kWh) Central AC - Maintenance and Tune-Up 41.0% 100.0% 4 $125.00 158.0 0.07 $0.218 Attic Fan - Installation 12.6% 50.0% 18 $96.50 8.7 0.01 $1.027 Attic Fan - Photovoltaic - Installation 4.0% 25.0% 19 $200.00 8.7 0.00 $2.072 Ceiling Fan - Installation 52.6% 100.0% 15 $160.00 174.2 0.10 $0.094 Whole-House Fan - Installation 4.0% 25.0% 18 $200.00 239.6 0.12 $0.078 Air Source Heat Pump - Maintenance 37.8% 100.0% 4 $125.00 1,065.7 0.53 $0.032 Insulation - Ducting 50.0% 59.4% 18 $250.00 553.3 0.22 $0.042 Thermostat - Clock/Programmable 90.6% 95.0% 15 $249.47 608.2 0.41 $0.042 Doors - Storm and Thermal 13.0% 100.0% 12 $180.00 203.5 0.16 $0.104 Insulation - Ceiling 81.8% 75.0% 20 $634.00 549.5 0.13 $0.102 Insulation - Radiant Barrier 25.0% 100.0% 12 $922.68 193.4 0.03 $0.561 Roofs - High Reflectivity 5.0% 100.0% 15 $516.54 129.8 0.02 $0.408 Windows - Reflective Film 2.0% 50.0% 10 $266.67 338.0 0.11 $0.105 Windows - High Efficiency/Energy Star 95.5% 100.0% 25 $2,200.00 3,037.6 0.22 $0.058 Interior Lighting - Occupancy Sensor 23.5% 30.0% 15 $500.00 493.6 0.10 $0.104 Exterior Lighting - Photovoltaic Installation 10.0% 100.0% 15 $2,975.00 60.1 0.00 $5.076 Exterior Lighting - Photosensor Control 13.2% 100.0% 8 $90.00 40.0 0.05 $0.352 Exterior Lighting - Timeclock Installation 16.0% 100.0% 8 $72.00 40.0 0.06 $0.282 Water Heater - Faucet Aerators 38.3% 100.0% 25 $24.00 251.6 1.13 $0.008 Water Heater - Pipe Insulation 8.0% 100.0% 13 $15.00 221.9 1.78 $0.008 Water Heater - Low Flow Showerheads 89.8% 100.0% 10 $25.48 354.0 1.81 $0.010 Water Heater - Tank Blanket/Insulation 0.0% 0.0% 10 $15.00 713.6 3.82 $0.003 Water Heater - Thermostat Setback 5.0% 100.0% 5 $40.00 713.6 1.13 $0.013 Electronics - Reduce Standby Wattage 5.0% 100.0% 8 $20.00 126.7 0.53 $0.025 Behavioral Measures 20.0% 75.0% 1 $12.00 142.7 0.24 $0.084 Pool - Pump Timer 55.0% 100.0% 15 $160.00 200.1 0.14 $0.082 Insulation - Foundation 54.8% 63.6% 20 $358.00 744.7 0.49 $0.042 Insulation - Wall Cavity 91.1% 100.0% 25 $236.00 558.7 0.38 $0.034 Insulation - Wall Sheathing 64.4% 100.0% 20 $300.00 315.7 0.17 $0.084 Water Heater - Drainwater Heat Reocvery 1.0% 100.0% 25 $899.00 1,176.3 0.14 $0.061 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 962 of 1125 Residential Energy Efficiency Equipment and Measure Data B-60 www.enernoc.com Table B-21 Energy Efficiency Non-Equipment Data, Electric—Single Family, Existing Vintage, Idaho Measure Base Saturation Applicability Lifetime (Years) Cost ($/HH) Savings (kWh) BC Ratio Levelized Cost ($/kWh) Central AC - Early Replacement 0.0% 80.0% 15 $2,895.00 139.3 0.00 $2.133 Central AC - Maintenance and Tune-Up 41.0% 100.0% 4 $125.00 137.4 0.06 $0.251 Room AC - Removal of Second Unit 0.0% 100.0% 5 $75.00 512.4 0.42 $0.033 Attic Fan - Installation 12.0% 50.0% 18 $115.80 6.2 0.00 $1.736 Attic Fan - Photovoltaic - Installation 13.0% 100.0% 19 $350.00 6.2 0.00 $5.107 Ceiling Fan - Installation 51.0% 100.0% 15 $160.00 108.8 0.06 $0.151 Whole-House Fan - Installation 6.9% 25.0% 18 $200.00 174.6 0.08 $0.106 Air Source Heat Pump - Maintenance 37.8% 100.0% 4 $125.00 926.7 0.42 $0.037 Insulation - Ducting 15.0% 59.4% 18 $500.00 483.1 0.09 $0.096 Repair and Sealing - Ducting 12.3% 100.0% 20 $571.38 2,111.0 0.35 $0.024 Thermostat - Clock/Programmable 71.8% 75.0% 15 $249.47 587.7 0.49 $0.044 Doors - Storm and Thermal 38.0% 100.0% 12 $320.00 116.9 0.05 $0.322 Insulation - Infiltration Control 46.0% 100.0% 25 $306.11 876.6 0.48 $0.028 Insulation - Ceiling 76.4% 75.0% 25 $630.45 991.9 0.18 $0.051 Insulation - Radiant Barrier 5.0% 100.0% 12 $922.68 571.9 0.09 $0.190 Roofs - High Reflectivity 5.0% 100.0% 15 $1,549.61 82.7 0.00 $1.923 Windows - Reflective Film 5.0% 50.0% 10 $266.67 369.6 0.12 $0.096 Windows - High Efficiency/Energy Star 77.6% 100.0% 25 $5,200.97 4,270.5 0.11 $0.098 Interior Lighting - Occupancy Sensor 23.5% 50.0% 15 $750.00 444.7 0.05 $0.173 Exterior Lighting - Photovoltaic Installation 10.0% 100.0% 15 $2,975.00 53.8 0.00 $5.679 Exterior Lighting - Photosensor Control 23.5% 100.0% 8 $90.00 36.3 0.03 $0.388 Exterior Lighting - Timeclock Installation 10.0% 100.0% 8 $72.00 36.3 0.04 $0.310 Water Heater - Faucet Aerators 53.2% 100.0% 25 $24.00 275.8 1.23 $0.007 Water Heater - Pipe Insulation 17.0% 100.0% 13 $15.00 242.9 1.94 $0.007 Water Heater - Low Flow Showerheads 75.5% 100.0% 10 $25.48 354.0 1.87 $0.010 Water Heater - Tank Blanket/Insulation 54.0% 100.0% 10 $15.00 781.1 4.19 $0.003 Water Heater - Thermostat Setback 17.0% 100.0% 5 $40.00 781.1 1.23 $0.012 Electronics - Reduce Standby Wattage 5.0% 100.0% 8 $20.00 117.4 0.47 $0.027 Refrigerator - Early Replacement 10.0% 85.0% 7 $109.00 319.9 0.16 $0.059 Refrigerator - Remove Second Unit 17.3% 85.0% 7 $109.00 437.0 0.83 $0.043 Freezer - Early Replacement 10.0% 85.0% 5 $109.00 355.4 0.14 $0.070 Freezer - Remove Second Unit 17.3% 85.0% 5 $109.00 384.9 0.75 $0.065 Behavioral Measures 20.0% 50.0% 1 $12.00 125.0 0.20 $0.096 Pool - Pump Timer 58.8% 100.0% 15 $160.00 194.3 0.12 $0.085 Insulation - Foundation 25.9% 39.0% 25 $750.53 521.1 0.19 $0.116 Insulation - Wall Cavity 88.4% 100.0% 25 $1,415.87 2,186.1 0.17 $0.052 Insulation - Wall Sheathing 64.4% 100.0% 20 $300.00 276.9 0.14 $0.096 Water Heater - Solar System 5.0% 25.0% 20 $6,500.00 6,437.3 0.11 $0.089 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 963 of 1125 Residential Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting B-61 Table B-22 Energy Efficiency Non-Equipment Data, Electric—Single Family, New Vintage, Idaho Measure Base Saturation Applicability Lifetime (Years) Cost ($/HH) Savings (kWh) BC Ratio Levelized Cost ($/kWh) Central AC - Maintenance and Tune-Up 41.0% 100.0% 4 $125.00 158.0 0.07 $0.218 Attic Fan - Installation 12.6% 50.0% 18 $96.50 8.7 0.01 $1.027 Attic Fan - Photovoltaic - Installation 4.0% 25.0% 19 $200.00 8.7 0.00 $2.072 Ceiling Fan - Installation 52.6% 100.0% 15 $160.00 174.2 0.10 $0.094 Whole-House Fan - Installation 4.0% 25.0% 18 $200.00 239.6 0.12 $0.078 Air Source Heat Pump - Maintenance 37.8% 100.0% 4 $125.00 1,065.7 0.53 $0.032 Insulation - Ducting 50.0% 59.4% 18 $250.00 553.3 0.22 $0.042 Thermostat - Clock/Programmable 90.6% 95.0% 15 $249.47 608.2 0.41 $0.042 Doors - Storm and Thermal 13.0% 100.0% 12 $180.00 203.5 0.16 $0.104 Insulation - Ceiling 81.8% 75.0% 20 $634.00 549.5 0.13 $0.102 Insulation - Radiant Barrier 25.0% 100.0% 12 $922.68 193.4 0.03 $0.561 Roofs - High Reflectivity 5.0% 100.0% 15 $516.54 129.8 0.02 $0.408 Windows - Reflective Film 2.0% 50.0% 10 $266.67 338.0 0.11 $0.105 Windows - High Efficiency/Energy Star 95.5% 100.0% 25 $2,200.00 3,037.6 0.22 $0.058 Interior Lighting - Occupancy Sensor 23.5% 30.0% 15 $500.00 493.6 0.10 $0.104 Exterior Lighting - Photovoltaic Installation 10.0% 100.0% 15 $2,975.00 60.1 0.00 $5.076 Exterior Lighting - Photosensor Control 13.2% 100.0% 8 $90.00 40.0 0.05 $0.352 Exterior Lighting - Timeclock Installation 16.0% 100.0% 8 $72.00 40.0 0.06 $0.282 Water Heater - Faucet Aerators 38.3% 100.0% 25 $24.00 251.6 1.13 $0.008 Water Heater - Pipe Insulation 8.0% 100.0% 13 $15.00 221.9 1.78 $0.008 Water Heater - Low Flow Showerheads 89.8% 100.0% 10 $25.48 354.0 1.81 $0.010 Water Heater - Tank Blanket/Insulation 0.0% 0.0% 10 $15.00 713.6 3.82 $0.003 Water Heater - Thermostat Setback 5.0% 100.0% 5 $40.00 713.6 1.13 $0.013 Electronics - Reduce Standby Wattage 5.0% 100.0% 8 $20.00 126.7 0.53 $0.025 Behavioral Measures 20.0% 75.0% 1 $12.00 142.7 0.24 $0.084 Pool - Pump Timer 55.0% 100.0% 15 $160.00 200.1 0.14 $0.082 Insulation - Foundation 54.8% 63.6% 20 $358.00 744.7 0.49 $0.042 Insulation - Wall Cavity 91.1% 100.0% 25 $236.00 558.7 0.38 $0.034 Insulation - Wall Sheathing 64.4% 100.0% 20 $300.00 315.7 0.17 $0.084 Water Heater - Drainwater Heat Reocvery 1.0% 100.0% 25 $899.00 1,176.3 0.14 $0.061 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 964 of 1125 Residential Energy Efficiency Equipment and Measure Data B-62 www.enernoc.com Table B-23 Energy Efficiency Non-Equipment Data, Electric—Multi Family, Existing Vintage, Washington Measure Base Saturation Applicability Lifetime (Years) Cost ($/HH) Savings (kWh) BC Ratio Levelized Cost ($/kWh) Central AC - Early Replacement 0.0% 80.0% 15 $2,895.00 46.4 0.00 $6.400 Central AC - Maintenance and Tune-Up 32.8% 100.0% 4 $100.00 45.8 0.03 $0.602 Room AC - Removal of Second Unit 0.0% 100.0% 5 $75.00 355.3 0.29 $0.048 Ceiling Fan - Installation 32.4% 100.0% 15 $80.00 37.9 0.04 $0.216 Air Source Heat Pump - Maintenance 25.0% 100.0% 4 $100.00 360.1 0.21 $0.077 Insulation - Ducting 13.0% 13.0% 18 $375.00 7.0 0.00 $4.945 Repair and Sealing - Ducting 11.8% 100.0% 18 $500.00 720.5 0.13 $0.064 Thermostat - Clock/Programmable 27.0% 75.0% 15 $114.42 315.1 0.35 $0.037 Doors - Storm and Thermal 17.0% 100.0% 12 $320.00 - - $0.000 Insulation - Infiltration Control 19.0% 100.0% 12 $266.00 283.6 0.17 $0.110 Insulation - Ceiling 30.0% 40.0% 20 $215.00 277.6 0.17 $0.068 Insulation - Radiant Barrier 5.0% 100.0% 12 $922.68 433.3 0.06 $0.251 Roofs - High Reflectivity 3.0% 100.0% 15 $1,549.61 39.3 0.00 $4.045 Windows - Reflective Film 5.0% 50.0% 10 $166.67 112.4 0.06 $0.197 Windows - High Efficiency/Energy Star 70.4% 100.0% 25 $2,500.00 1,020.7 0.05 $0.196 Interior Lighting - Occupancy Sensor 5.6% 20.0% 15 $256.00 253.9 0.08 $0.103 Exterior Lighting - Photovoltaic Installation 10.0% 100.0% 15 $2,975.00 5.5 0.00 $55.926 Exterior Lighting - Photosensor Control 7.1% 100.0% 8 $90.00 2.1 0.00 $6.688 Exterior Lighting - Timeclock Installation 6.0% 100.0% 8 $72.00 2.1 0.00 $5.350 Water Heater - Faucet Aerators 43.2% 100.0% 25 $24.00 237.5 1.05 $0.008 Water Heater - Pipe Insulation 6.0% 100.0% 13 $15.00 149.6 0.90 $0.011 Water Heater - Low Flow Showerheads 71.6% 100.0% 10 $25.48 282.0 1.11 $0.012 Water Heater - Tank Blanket/Insulation 54.0% 100.0% 10 $15.00 480.9 2.25 $0.004 Water Heater - Thermostat Setback 17.0% 100.0% 5 $40.00 480.9 0.67 $0.019 Electronics - Reduce Standby Wattage 5.0% 100.0% 8 $20.00 73.6 0.31 $0.043 Refrigerator - Early Replacement 10.0% 85.0% 7 $109.00 255.9 0.13 $0.074 Refrigerator - Remove Second Unit 17.3% 85.0% 7 $109.00 437.0 0.83 $0.043 Freezer - Early Replacement 10.0% 85.0% 5 $109.00 307.9 0.12 $0.081 Freezer - Remove Second Unit 17.3% 85.0% 5 $109.00 384.9 0.75 $0.065 Behavioral Measures 5.0% 25.0% 1 $12.00 65.5 0.10 $0.183 Insulation - Wall Cavity 80.0% 100.0% 25 $707.94 522.3 0.09 $0.109 Insulation - Wall Sheathing 55.1% 100.0% 20 $210.00 356.6 0.22 $0.052 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 965 of 1125 Residential Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting B-63 Table B-24 Energy Efficiency Non-Equipment Data, Electric—Multi Family, New Vintage, Washington Measure Base Saturation Applicability Lifetime (Years) Cost ($/HH) Savings (kWh) BC Ratio Levelized Cost ($/kWh) Central AC - Maintenance and Tune-Up 32.8% 100.0% 4 $100.00 52.7 0.03 $0.524 Ceiling Fan - Installation 17.6% 100.0% 15 $80.00 59.7 0.07 $0.138 Air Source Heat Pump - Maintenance 25.0% 100.0% 4 $100.00 414.1 0.27 $0.067 Insulation - Ducting 13.0% 13.0% 18 $200.00 7.3 0.00 $2.531 Thermostat - Clock/Programmable 77.0% 80.0% 15 $114.42 364.1 0.36 $0.032 Doors - Storm and Thermal 19.0% 100.0% 12 $180.00 - - $0.000 Insulation - Ceiling 30.7% 50.0% 20 $152.00 430.5 0.37 $0.031 Insulation - Radiant Barrier 5.0% 100.0% 12 $922.68 160.5 0.02 $0.677 Roofs - High Reflectivity 0.0% 100.0% 15 $516.54 35.4 0.01 $1.498 Windows - Reflective Film 2.0% 50.0% 10 $166.67 129.5 0.07 $0.171 Windows - High Efficiency/Energy Star 89.2% 100.0% 25 $2,200.00 2,298.8 0.14 $0.077 Interior Lighting - Occupancy Sensor 5.6% 10.0% 15 $256.00 281.1 0.11 $0.093 Exterior Lighting - Photovoltaic Installation 10.0% 100.0% 15 $2,975.00 6.3 0.00 $48.646 Exterior Lighting - Photosensor Control 0.7% 100.0% 8 $90.00 2.3 0.00 $6.080 Exterior Lighting - Timeclock Installation 11.0% 100.0% 8 $72.00 2.3 0.01 $4.864 Water Heater - Faucet Aerators 11.0% 100.0% 25 $24.00 217.0 1.04 $0.009 Water Heater - Pipe Insulation 0.0% 100.0% 13 $15.00 136.6 1.11 $0.012 Water Heater - Low Flow Showerheads 66.2% 100.0% 10 $25.48 282.0 1.42 $0.012 Water Heater - Tank Blanket/Insulation 0.0% 0.0% 10 $15.00 439.3 2.67 $0.005 Water Heater - Thermostat Setback 5.0% 100.0% 5 $40.00 439.3 0.76 $0.021 Electronics - Reduce Standby Wattage 5.0% 100.0% 8 $20.00 79.5 0.35 $0.039 Behavioral Measures 5.0% 75.0% 1 $12.00 75.1 0.13 $0.160 Insulation - Wall Cavity 91.1% 100.0% 25 $62.50 478.4 1.03 $0.010 Insulation - Wall Sheathing 55.1% 100.0% 20 $210.00 410.2 0.26 $0.045 Water Heater - Drainwater Heat Reocvery 1.0% 100.0% 25 $899.00 724.2 0.09 $0.100 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 966 of 1125 Residential Energy Efficiency Equipment and Measure Data B-64 www.enernoc.com Table B-25 Energy Efficiency Non-Equipment Data, Electric—Multi Family, Existing Vintage, Idaho Measure Base Saturation Applicability Lifetime (Years) Cost ($/HH) Savings (kWh) BC Ratio Levelized Cost ($/kWh) Central AC - Early Replacement 0.0% 80.0% 15 $2,895.00 46.4 0.00 $6.400 Central AC - Maintenance and Tune-Up 32.8% 100.0% 4 $100.00 45.8 0.03 $0.602 Room AC - Removal of Second Unit 0.0% 100.0% 5 $75.00 355.3 0.29 $0.048 Ceiling Fan - Installation 32.4% 100.0% 15 $80.00 37.9 0.04 $0.216 Air Source Heat Pump - Maintenance 25.0% 100.0% 4 $100.00 360.1 0.21 $0.077 Insulation - Ducting 13.0% 13.0% 18 $375.00 7.0 0.00 $4.945 Repair and Sealing - Ducting 11.8% 100.0% 18 $500.00 720.5 0.13 $0.064 Thermostat - Clock/Programmable 27.0% 75.0% 15 $114.42 315.1 0.35 $0.037 Doors - Storm and Thermal 17.0% 100.0% 12 $320.00 - - $0.000 Insulation - Infiltration Control 19.0% 100.0% 12 $266.00 283.6 0.17 $0.110 Insulation - Ceiling 30.0% 40.0% 20 $215.00 277.6 0.17 $0.068 Insulation - Radiant Barrier 5.0% 100.0% 12 $922.68 433.3 0.06 $0.251 Roofs - High Reflectivity 3.0% 100.0% 15 $1,549.61 39.3 0.00 $4.045 Windows - Reflective Film 5.0% 50.0% 10 $166.67 112.4 0.06 $0.197 Windows - High Efficiency/Energy Star 70.4% 100.0% 25 $2,500.00 1,020.7 0.05 $0.196 Interior Lighting - Occupancy Sensor 5.6% 20.0% 15 $256.00 253.9 0.08 $0.103 Exterior Lighting - Photovoltaic Installation 10.0% 100.0% 15 $2,975.00 5.5 0.00 $55.926 Exterior Lighting - Photosensor Control 7.1% 100.0% 8 $90.00 2.1 0.00 $6.688 Exterior Lighting - Timeclock Installation 6.0% 100.0% 8 $72.00 2.1 0.00 $5.350 Water Heater - Faucet Aerators 43.2% 100.0% 25 $24.00 237.5 1.05 $0.008 Water Heater - Pipe Insulation 6.0% 100.0% 13 $15.00 149.6 0.90 $0.011 Water Heater - Low Flow Showerheads 71.6% 100.0% 10 $25.48 282.0 1.11 $0.012 Water Heater - Tank Blanket/Insulation 54.0% 100.0% 10 $15.00 480.9 2.25 $0.004 Water Heater - Thermostat Setback 17.0% 100.0% 5 $40.00 480.9 0.67 $0.019 Electronics - Reduce Standby Wattage 5.0% 100.0% 8 $20.00 73.6 0.31 $0.043 Refrigerator - Early Replacement 10.0% 85.0% 7 $109.00 255.9 0.13 $0.074 Refrigerator - Remove Second Unit 17.3% 85.0% 7 $109.00 437.0 0.83 $0.043 Freezer - Early Replacement 10.0% 85.0% 5 $109.00 307.9 0.12 $0.081 Freezer - Remove Second Unit 17.3% 85.0% 5 $109.00 384.9 0.75 $0.065 Behavioral Measures 5.0% 25.0% 1 $12.00 65.5 0.10 $0.183 Insulation - Wall Cavity 80.0% 100.0% 25 $707.94 522.3 0.09 $0.109 Insulation - Wall Sheathing 55.1% 100.0% 20 $210.00 356.6 0.22 $0.052 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 967 of 1125 Residential Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting B-65 Table B-26 Energy Efficiency Non-Equipment Data, Electric—Multi Family, New Vintage, Idaho Measure Base Saturation Applicability Lifetime (Years) Cost ($/HH) Savings (kWh) BC Ratio Levelized Cost ($/kWh) Central AC - Maintenance and Tune-Up 32.8% 100.0% 4 $100.00 52.7 0.03 $0.524 Ceiling Fan - Installation 17.6% 100.0% 15 $80.00 59.7 0.07 $0.138 Air Source Heat Pump - Maintenance 25.0% 100.0% 4 $100.00 414.1 0.27 $0.067 Insulation - Ducting 13.0% 13.0% 18 $200.00 7.3 0.00 $2.531 Thermostat - Clock/Programmable 77.0% 80.0% 15 $114.42 364.1 0.36 $0.032 Doors - Storm and Thermal 19.0% 100.0% 12 $180.00 - - $0.000 Insulation - Ceiling 30.7% 50.0% 20 $152.00 430.5 0.37 $0.031 Insulation - Radiant Barrier 5.0% 100.0% 12 $922.68 160.5 0.02 $0.677 Roofs - High Reflectivity 0.0% 100.0% 15 $516.54 35.4 0.01 $1.498 Windows - Reflective Film 2.0% 50.0% 10 $166.67 129.5 0.07 $0.171 Windows - High Efficiency/Energy Star 89.2% 100.0% 25 $2,200.00 2,298.8 0.14 $0.077 Interior Lighting - Occupancy Sensor 5.6% 10.0% 15 $256.00 281.1 0.11 $0.093 Exterior Lighting - Photovoltaic Installation 10.0% 100.0% 15 $2,975.00 6.3 0.00 $48.646 Exterior Lighting - Photosensor Control 0.7% 100.0% 8 $90.00 2.3 0.00 $6.080 Exterior Lighting - Timeclock Installation 11.0% 100.0% 8 $72.00 2.3 0.01 $4.864 Water Heater - Faucet Aerators 11.0% 100.0% 25 $24.00 217.0 1.04 $0.009 Water Heater - Pipe Insulation 0.0% 100.0% 13 $15.00 136.6 1.11 $0.012 Water Heater - Low Flow Showerheads 66.2% 100.0% 10 $25.48 282.0 1.42 $0.012 Water Heater - Tank Blanket/Insulation 0.0% 0.0% 10 $15.00 439.3 2.67 $0.005 Water Heater - Thermostat Setback 5.0% 100.0% 5 $40.00 439.3 0.76 $0.021 Electronics - Reduce Standby Wattage 5.0% 100.0% 8 $20.00 79.5 0.35 $0.039 Behavioral Measures 5.0% 75.0% 1 $12.00 75.1 0.13 $0.160 Insulation - Wall Cavity 91.1% 100.0% 25 $62.50 478.4 1.03 $0.010 Insulation - Wall Sheathing 55.1% 100.0% 20 $210.00 410.2 0.26 $0.045 Water Heater - Drainwater Heat Reocvery 1.0% 100.0% 25 $899.00 724.2 0.09 $0.100 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 968 of 1125 Residential Energy Efficiency Equipment and Measure Data B-66 www.enernoc.com Table B-27 Energy Efficiency Non-Equipment Data, Electric—Mobile Home, Existing Vintage, Washington Measure Base Saturation Applicability Lifetime (Years) Cost ($/HH) Savings (kWh) BC Ratio Levelized Cost ($/kWh) Central AC - Early Replacement 0.0% 80.0% 15 $2,895.00 55.3 0.00 $5.373 Central AC - Maintenance and Tune-Up 58.9% 100.0% 4 $100.00 54.5 0.03 $0.506 Room AC - Removal of Second Unit 0.0% 100.0% 5 $75.00 305.2 0.25 $0.056 Ceiling Fan - Installation 60.0% 100.0% 15 $80.00 41.2 0.05 $0.199 Whole-House Fan - Installation 5.2% 25.0% 18 $150.00 66.1 0.04 $0.211 Air Source Heat Pump - Maintenance 25.0% 100.0% 4 $125.00 496.0 0.22 $0.070 Insulation - Ducting 15.0% 65.0% 18 $375.00 320.3 0.08 $0.109 Repair and Sealing - Ducting 12.3% 100.0% 18 $398.09 2,477.4 0.59 $0.015 Thermostat - Clock/Programmable 51.0% 75.0% 15 $114.42 513.2 0.94 $0.023 Doors - Storm and Thermal 38.0% 100.0% 12 $320.00 79.1 0.04 $0.476 Insulation - Infiltration Control 46.0% 100.0% 25 $208.70 364.9 0.42 $0.046 Insulation - Ceiling 46.2% 85.0% 25 $276.18 355.8 0.18 $0.062 Insulation - Radiant Barrier 5.0% 100.0% 12 $922.68 387.5 0.07 $0.280 Roofs - High Reflectivity 5.0% 100.0% 15 $1,549.61 31.3 0.00 $5.080 Windows - Reflective Film 5.0% 50.0% 10 $166.67 139.9 0.07 $0.159 Windows - High Efficiency/Energy Star 52.4% 100.0% 25 $3,171.89 4,053.4 0.16 $0.063 Interior Lighting - Occupancy Sensor 66.6% 80.0% 15 $750.00 346.9 0.04 $0.222 Exterior Lighting - Photovoltaic Installation 10.0% 100.0% 15 $2,975.00 41.9 0.00 $7.281 Exterior Lighting - Photosensor Control 23.4% 100.0% 8 $90.00 28.3 0.02 $0.497 Exterior Lighting - Timeclock Installation 10.0% 100.0% 8 $72.00 28.3 0.03 $0.398 Water Heater - Faucet Aerators 78.9% 100.0% 25 $24.00 179.3 1.02 $0.011 Water Heater - Pipe Insulation 17.0% 100.0% 13 $15.00 157.9 1.14 $0.011 Water Heater - Low Flow Showerheads 92.1% 100.0% 10 $25.48 816.8 2.74 $0.004 Water Heater - Tank Blanket/Insulation 54.0% 100.0% 10 $15.00 507.7 2.43 $0.004 Water Heater - Thermostat Setback 17.0% 100.0% 5 $40.00 507.7 0.72 $0.018 Electronics - Reduce Standby Wattage 5.0% 100.0% 8 $20.00 91.0 0.37 $0.034 Refrigerator - Early Replacement 10.0% 85.0% 7 $109.00 249.5 0.12 $0.076 Refrigerator - Remove Second Unit 17.3% 85.0% 7 $109.00 437.0 0.83 $0.043 Freezer - Early Replacement 10.0% 85.0% 5 $109.00 300.2 0.12 $0.083 Freezer - Remove Second Unit 17.3% 85.0% 5 $109.00 384.9 0.75 $0.065 Behavioral Measures 20.0% 50.0% 1 $12.00 84.5 0.14 $0.142 Pool - Pump Timer 50.0% 100.0% 15 $160.00 145.7 0.09 $0.113 Insulation - Wall Cavity 81.8% 100.0% 25 $707.94 1,004.5 0.17 $0.057 Insulation - Wall Sheathing 64.4% 100.0% 20 $300.00 187.2 0.11 $0.141 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 969 of 1125 Residential Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting B-67 Table B-28 Energy Efficiency Non-Equipment Data, Electric—Mobile Home, New Vintage, Washington Measure Base Saturation Applicability Lifetime (Years) Cost ($/HH) Savings (kWh) BC Ratio Levelized Cost ($/kWh) Central AC - Maintenance and Tune-Up 58.9% 100.0% 4 $100.00 58.6 0.03 $0.471 Ceiling Fan - Installation 57.0% 100.0% 15 $80.00 60.2 0.07 $0.136 Whole-House Fan - Installation 4.0% 25.0% 18 $150.00 82.8 0.05 $0.168 Air Source Heat Pump - Maintenance 25.0% 100.0% 4 $125.00 533.2 0.26 $0.065 Insulation - Ducting 55.0% 65.0% 18 $200.00 344.0 0.17 $0.054 Thermostat - Clock/Programmable 57.0% 75.0% 15 $114.42 552.4 0.77 $0.021 Doors - Storm and Thermal 13.0% 100.0% 12 $180.00 126.6 0.11 $0.167 Insulation - Ceiling 46.2% 85.0% 20 $176.00 341.1 0.32 $0.046 Insulation - Radiant Barrier 25.0% 100.0% 12 $922.68 115.6 0.02 $0.939 Roofs - High Reflectivity 5.0% 100.0% 15 $516.54 44.8 0.01 $1.183 Windows - Reflective Film 2.0% 50.0% 10 $166.67 116.7 0.06 $0.190 Windows - High Efficiency/Energy Star 95.5% 100.0% 25 $2,200.00 1,916.5 0.15 $0.092 Interior Lighting - Occupancy Sensor 66.6% 80.0% 15 $500.00 366.0 0.08 $0.140 Exterior Lighting - Photovoltaic Installation 10.0% 100.0% 15 $2,975.00 44.8 0.00 $6.818 Exterior Lighting - Photosensor Control 13.2% 100.0% 8 $90.00 29.8 0.04 $0.473 Exterior Lighting - Timeclock Installation 16.0% 100.0% 8 $72.00 29.8 0.05 $0.379 Water Heater - Faucet Aerators 56.6% 100.0% 25 $24.00 171.3 1.01 $0.011 Water Heater - Pipe Insulation 8.0% 100.0% 13 $15.00 151.1 1.43 $0.011 Water Heater - Low Flow Showerheads 92.1% 100.0% 10 $25.48 781.8 3.37 $0.004 Water Heater - Tank Blanket/Insulation 0.0% 0.0% 10 $15.00 485.8 2.95 $0.004 Water Heater - Thermostat Setback 5.0% 100.0% 5 $40.00 485.8 0.84 $0.019 Electronics - Reduce Standby Wattage 5.0% 100.0% 8 $20.00 94.1 0.40 $0.033 Behavioral Measures 20.0% 75.0% 1 $12.00 90.5 0.15 $0.133 Pool - Pump Timer 35.0% 100.0% 15 $160.00 148.8 0.10 $0.110 Insulation - Wall Cavity 64.5% 100.0% 25 $197.06 356.6 0.31 $0.044 Insulation - Wall Sheathing 64.4% 100.0% 20 $300.00 200.7 0.11 $0.132 Water Heater - Drainwater Heat Reocvery 1.0% 100.0% 25 $899.00 800.7 0.11 $0.090 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 970 of 1125 Residential Energy Efficiency Equipment and Measure Data B-68 www.enernoc.com Table B-29 Energy Efficiency Non-Equipment Data, Electric—Mobile Home, Existing Vintage, Idaho Measure Base Saturation Applicability Lifetime (Years) Cost ($/HH) Savings (kWh) BC Ratio Levelized Cost ($/kWh) Central AC - Early Replacement 0.0% 80.0% 15 $2,895.00 55.3 0.00 $5.373 Central AC - Maintenance and Tune-Up 58.9% 100.0% 4 $100.00 54.5 0.03 $0.506 Room AC - Removal of Second Unit 0.0% 100.0% 5 $75.00 305.2 0.25 $0.056 Ceiling Fan - Installation 60.0% 100.0% 15 $80.00 41.2 0.05 $0.199 Whole-House Fan - Installation 5.2% 25.0% 18 $150.00 66.1 0.04 $0.211 Air Source Heat Pump - Maintenance 25.0% 100.0% 4 $125.00 496.0 0.22 $0.070 Insulation - Ducting 15.0% 65.0% 18 $375.00 320.3 0.08 $0.109 Repair and Sealing - Ducting 12.3% 100.0% 18 $398.09 2,477.4 0.59 $0.015 Thermostat - Clock/Programmable 51.0% 75.0% 15 $114.42 513.2 0.94 $0.023 Doors - Storm and Thermal 38.0% 100.0% 12 $320.00 79.1 0.04 $0.476 Insulation - Infiltration Control 46.0% 100.0% 25 $208.70 364.9 0.42 $0.046 Insulation - Ceiling 46.2% 85.0% 25 $276.18 355.8 0.18 $0.062 Insulation - Radiant Barrier 5.0% 100.0% 12 $922.68 387.5 0.07 $0.280 Roofs - High Reflectivity 5.0% 100.0% 15 $1,549.61 31.3 0.00 $5.080 Windows - Reflective Film 5.0% 50.0% 10 $166.67 139.9 0.07 $0.159 Windows - High Efficiency/Energy Star 52.4% 100.0% 25 $3,171.89 4,053.4 0.16 $0.063 Interior Lighting - Occupancy Sensor 66.6% 80.0% 15 $750.00 346.9 0.04 $0.222 Exterior Lighting - Photovoltaic Installation 10.0% 100.0% 15 $2,975.00 41.9 0.00 $7.281 Exterior Lighting - Photosensor Control 23.4% 100.0% 8 $90.00 28.3 0.02 $0.497 Exterior Lighting - Timeclock Installation 10.0% 100.0% 8 $72.00 28.3 0.03 $0.398 Water Heater - Faucet Aerators 78.9% 100.0% 25 $24.00 179.3 1.02 $0.011 Water Heater - Pipe Insulation 17.0% 100.0% 13 $15.00 157.9 1.14 $0.011 Water Heater - Low Flow Showerheads 92.1% 100.0% 10 $25.48 816.8 2.74 $0.004 Water Heater - Tank Blanket/Insulation 54.0% 100.0% 10 $15.00 507.7 2.43 $0.004 Water Heater - Thermostat Setback 17.0% 100.0% 5 $40.00 507.7 0.72 $0.018 Electronics - Reduce Standby Wattage 5.0% 100.0% 8 $20.00 91.0 0.37 $0.034 Refrigerator - Early Replacement 10.0% 85.0% 7 $109.00 249.5 0.12 $0.076 Refrigerator - Remove Second Unit 17.3% 85.0% 7 $109.00 437.0 0.83 $0.043 Freezer - Early Replacement 10.0% 85.0% 5 $109.00 300.2 0.12 $0.083 Freezer - Remove Second Unit 17.3% 85.0% 5 $109.00 384.9 0.75 $0.065 Behavioral Measures 20.0% 50.0% 1 $12.00 84.5 0.14 $0.142 Pool - Pump Timer 50.0% 100.0% 15 $160.00 145.7 0.09 $0.113 Insulation - Wall Cavity 81.8% 100.0% 25 $707.94 1,004.5 0.17 $0.057 Insulation - Wall Sheathing 64.4% 100.0% 20 $300.00 187.2 0.11 $0.141 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 971 of 1125 Residential Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting B-69 Table B-30 Energy Efficiency Non-Equipment Data, Electric—Mobile Home, New Vintage, Idaho Measure Base Saturation Applicability Lifetime (Years) Cost ($/HH) Savings (kWh) BC Ratio Levelized Cost ($/kWh) Central AC - Maintenance and Tune-Up 58.9% 100.0% 4 $100.00 58.6 0.03 $0.471 Ceiling Fan - Installation 57.0% 100.0% 15 $80.00 60.2 0.07 $0.136 Whole-House Fan - Installation 4.0% 25.0% 18 $150.00 82.8 0.05 $0.168 Air Source Heat Pump - Maintenance 25.0% 100.0% 4 $125.00 533.2 0.26 $0.065 Insulation - Ducting 55.0% 65.0% 18 $200.00 344.0 0.17 $0.054 Thermostat - Clock/Programmable 57.0% 75.0% 15 $114.42 552.4 0.77 $0.021 Doors - Storm and Thermal 13.0% 100.0% 12 $180.00 126.6 0.11 $0.167 Insulation - Ceiling 46.2% 85.0% 20 $176.00 341.1 0.32 $0.046 Insulation - Radiant Barrier 25.0% 100.0% 12 $922.68 115.6 0.02 $0.939 Roofs - High Reflectivity 5.0% 100.0% 15 $516.54 44.8 0.01 $1.183 Windows - Reflective Film 2.0% 50.0% 10 $166.67 116.7 0.06 $0.190 Windows - High Efficiency/Energy Star 95.5% 100.0% 25 $2,200.00 1,916.5 0.15 $0.092 Interior Lighting - Occupancy Sensor 66.6% 80.0% 15 $500.00 366.0 0.08 $0.140 Exterior Lighting - Photovoltaic Installation 10.0% 100.0% 15 $2,975.00 44.8 0.00 $6.818 Exterior Lighting - Photosensor Control 13.2% 100.0% 8 $90.00 29.8 0.04 $0.473 Exterior Lighting - Timeclock Installation 16.0% 100.0% 8 $72.00 29.8 0.05 $0.379 Water Heater - Faucet Aerators 56.6% 100.0% 25 $24.00 171.3 1.01 $0.011 Water Heater - Pipe Insulation 8.0% 100.0% 13 $15.00 151.1 1.43 $0.011 Water Heater - Low Flow Showerheads 92.1% 100.0% 10 $25.48 781.8 3.37 $0.004 Water Heater - Tank Blanket/Insulation 0.0% 0.0% 10 $15.00 485.8 2.95 $0.004 Water Heater - Thermostat Setback 5.0% 100.0% 5 $40.00 485.8 0.84 $0.019 Electronics - Reduce Standby Wattage 5.0% 100.0% 8 $20.00 94.1 0.40 $0.033 Behavioral Measures 20.0% 75.0% 1 $12.00 90.5 0.15 $0.133 Pool - Pump Timer 35.0% 100.0% 15 $160.00 148.8 0.10 $0.110 Insulation - Wall Cavity 64.5% 100.0% 25 $197.06 356.6 0.31 $0.044 Insulation - Wall Sheathing 64.4% 100.0% 20 $300.00 200.7 0.11 $0.132 Water Heater - Drainwater Heat Reocvery 1.0% 100.0% 25 $899.00 800.7 0.11 $0.090 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 972 of 1125 Residential Energy Efficiency Equipment and Measure Data B-70 www.enernoc.com Table B-31 Energy Efficiency Non-Equipment Data, Electric—Low income, Existing Vintage, Washington Measure Base Saturation Applicability Lifetime (Years) Cost ($/HH) Savings (kWh) BC Ratio Levelized Cost ($/kWh) Central AC - Early Replacement 0.0% 80.0% 15 $2,895.00 59.1 0.00 $5.026 Central AC - Maintenance and Tune-Up 24.6% 100.0% 4 $100.00 58.3 0.43 $0.473 Room AC - Removal of Second Unit 0.0% 100.0% 5 $75.00 289.2 0.24 $0.059 Attic Fan - Installation 2.9% 50.0% 18 $115.80 2.4 0.00 $4.502 Attic Fan - Photovoltaic - Installation 2.0% 25.0% 19 $350.00 2.4 0.00 $13.244 Ceiling Fan - Installation 40.8% 100.0% 15 $80.00 42.0 0.05 $0.196 Whole-House Fan - Installation 5.3% 25.0% 18 $150.00 67.3 0.04 $0.207 Air Source Heat Pump - Maintenance 25.0% 100.0% 4 $125.00 480.2 0.62 $0.072 Insulation - Ducting 13.0% 25.0% 18 $395.00 279.5 0.37 $0.131 Repair and Sealing - Ducting 11.8% 100.0% 18 $500.00 837.0 0.46 $0.056 Thermostat - Clock/Programmable 35.9% 75.0% 15 $114.42 450.0 1.19 $0.026 Doors - Storm and Thermal 17.0% 100.0% 12 $320.00 68.7 0.04 $0.548 Insulation - Infiltration Control 19.0% 100.0% 12 $266.00 522.9 0.64 $0.060 Insulation - Ceiling 39.3% 55.0% 20 $215.00 170.6 0.45 $0.111 Insulation - Radiant Barrier 5.0% 100.0% 12 $922.68 336.6 0.36 $0.323 Roofs - High Reflectivity 3.0% 100.0% 15 $1,549.61 31.9 0.00 $4.987 Windows - Reflective Film 5.0% 50.0% 10 $166.67 142.5 0.07 $0.156 Windows - High Efficiency/Energy Star 71.3% 100.0% 25 $2,500.00 1,226.3 0.40 $0.163 Interior Lighting - Occupancy Sensor 8.2% 20.0% 15 $256.00 254.7 0.09 $0.103 Exterior Lighting - Photovoltaic Installation 10.0% 100.0% 15 $2,975.00 20.4 0.00 $14.935 Exterior Lighting - Photosensor Control 8.4% 100.0% 8 $90.00 13.8 0.01 $1.020 Exterior Lighting - Timeclock Installation 6.0% 100.0% 8 $72.00 13.8 0.02 $0.816 Water Heater - Faucet Aerators 45.5% 100.0% 25 $24.00 170.6 1.00 $0.011 Water Heater - Pipe Insulation 6.0% 100.0% 13 $15.00 150.2 1.22 $0.011 Water Heater - Low Flow Showerheads 73.8% 100.0% 10 $25.48 777.0 2.77 $0.004 Water Heater - Tank Blanket/Insulation 54.0% 100.0% 10 $15.00 482.9 2.29 $0.004 Water Heater - Thermostat Setback 17.0% 100.0% 5 $40.00 482.9 0.68 $0.019 Electronics - Reduce Standby Wattage 5.0% 100.0% 8 $20.00 64.3 0.27 $0.049 Refrigerator - Early Replacement 10.0% 85.0% 7 $109.00 224.7 0.11 $0.084 Refrigerator - Remove Second Unit 17.3% 85.0% 7 $109.00 437.0 0.83 $0.043 Freezer - Early Replacement 10.0% 85.0% 5 $109.00 270.4 0.10 $0.092 Freezer - Remove Second Unit 17.3% 85.0% 5 $109.00 384.9 0.75 $0.065 Behavioral Measures 5.0% 25.0% 1 $12.00 71.9 0.11 $0.167 Pool - Pump Timer 50.0% 100.0% 15 $160.00 151.5 0.10 $0.108 Insulation - Foundation 13.0% 40.0% 20 $358.00 361.5 0.63 $0.087 Insulation - Wall Cavity 44.2% 100.0% 25 $1,415.87 870.1 0.38 $0.130 Insulation - Wall Sheathing 58.8% 100.0% 20 $210.00 162.6 0.44 $0.114 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 973 of 1125 Residential Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting B-71 Table B-32 Energy Efficiency Non-Equipment Data, Electric—Low income, New Vintage, Washington Measure Base Saturation Applicability Lifetime (Years) Cost ($/HH) Savings (kWh) BC Ratio Levelized Cost ($/kWh) Central AC - Maintenance and Tune-Up 24.6% 100.0% 4 $100.00 62.7 0.44 $0.440 Attic Fan - Installation 15.0% 50.0% 18 $96.50 3.3 0.00 $2.739 Attic Fan - Photovoltaic - Installation 5.0% 25.0% 19 $200.00 3.3 0.00 $5.524 Ceiling Fan - Installation 33.0% 100.0% 15 $80.00 65.4 0.08 $0.126 Whole-House Fan - Installation 4.0% 25.0% 18 $150.00 89.9 0.06 $0.155 Air Source Heat Pump - Maintenance 37.8% 100.0% 4 $125.00 516.2 0.65 $0.067 Insulation - Ducting 25.0% 25.0% 18 $210.00 303.0 0.44 $0.064 Thermostat - Clock/Programmable 45.3% 75.0% 15 $114.42 490.0 1.05 $0.024 Doors - Storm and Thermal 19.0% 100.0% 12 $180.00 111.5 0.10 $0.190 Insulation - Ceiling 39.0% 50.0% 20 $152.00 300.6 0.67 $0.045 Insulation - Radiant Barrier 5.0% 100.0% 12 $922.68 103.0 0.32 $1.054 Roofs - High Reflectivity 0.0% 100.0% 15 $516.54 48.7 0.01 $1.089 Windows - Reflective Film 2.0% 50.0% 10 $166.67 126.8 0.07 $0.175 Windows - High Efficiency/Energy Star 80.2% 100.0% 25 $2,200.00 1,681.0 0.44 $0.105 Interior Lighting - Occupancy Sensor 8.2% 10.0% 15 $256.00 268.5 0.12 $0.098 Exterior Lighting - Photovoltaic Installation 10.0% 100.0% 15 $2,975.00 21.8 0.00 $13.986 Exterior Lighting - Photosensor Control 0.0% 100.0% 8 $90.00 14.5 0.02 $0.971 Exterior Lighting - Timeclock Installation 11.0% 100.0% 8 $72.00 14.5 0.02 $0.777 Water Heater - Faucet Aerators 10.6% 100.0% 25 $24.00 162.9 1.04 $0.012 Water Heater - Pipe Insulation 0.0% 100.0% 13 $15.00 143.7 1.56 $0.012 Water Heater - Low Flow Showerheads 66.2% 100.0% 10 $25.48 743.6 3.45 $0.005 Water Heater - Tank Blanket/Insulation 0.0% 0.0% 10 $15.00 462.1 2.80 $0.004 Water Heater - Thermostat Setback 5.0% 100.0% 5 $40.00 462.1 0.80 $0.020 Electronics - Reduce Standby Wattage 5.0% 100.0% 8 $20.00 66.9 0.29 $0.047 Behavioral Measures 5.0% 75.0% 1 $12.00 77.7 0.13 $0.154 Pool - Pump Timer 35.0% 100.0% 15 $160.00 154.7 0.11 $0.106 Insulation - Foundation 27.4% 40.0% 20 $358.00 395.1 0.65 $0.080 Insulation - Wall Cavity 45.6% 100.0% 25 $62.50 311.7 1.25 $0.016 Insulation - Wall Sheathing 58.8% 100.0% 20 $210.00 175.7 0.46 $0.105 Water Heater - Drainwater Heat Reocvery 1.0% 100.0% 25 $899.00 761.6 0.12 $0.095 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 974 of 1125 Residential Energy Efficiency Equipment and Measure Data B-72 www.enernoc.com Table B-33 Energy Efficiency Non-Equipment Data, Electric—Low income, Existing Vintage, Idaho Measure Base Saturation Applicability Lifetime (Years) Cost ($/HH) Savings (kWh) BC Ratio Levelized Cost ($/kWh) Central AC - Early Replacement 0.0% 80.0% 15 $2,895.00 59.1 0.00 $5.026 Central AC - Maintenance and Tune-Up 24.6% 100.0% 4 $100.00 58.3 0.43 $0.473 Room AC - Removal of Second Unit 0.0% 100.0% 5 $75.00 289.2 0.24 $0.059 Attic Fan - Installation 2.9% 50.0% 18 $115.80 2.4 0.00 $4.502 Attic Fan - Photovoltaic - Installation 2.0% 25.0% 19 $350.00 2.4 0.00 $13.244 Ceiling Fan - Installation 40.8% 100.0% 15 $80.00 42.0 0.05 $0.196 Whole-House Fan - Installation 5.3% 25.0% 18 $150.00 67.3 0.04 $0.207 Air Source Heat Pump - Maintenance 25.0% 100.0% 4 $125.00 480.2 0.62 $0.072 Insulation - Ducting 13.0% 25.0% 18 $395.00 279.5 0.37 $0.131 Repair and Sealing - Ducting 11.8% 100.0% 18 $500.00 837.0 0.46 $0.056 Thermostat - Clock/Programmable 35.9% 75.0% 15 $114.42 450.0 1.19 $0.026 Doors - Storm and Thermal 17.0% 100.0% 12 $320.00 68.7 0.04 $0.548 Insulation - Infiltration Control 19.0% 100.0% 12 $266.00 522.9 0.64 $0.060 Insulation - Ceiling 39.3% 55.0% 20 $215.00 170.6 0.45 $0.111 Insulation - Radiant Barrier 5.0% 100.0% 12 $922.68 336.6 0.36 $0.323 Roofs - High Reflectivity 3.0% 100.0% 15 $1,549.61 31.9 0.00 $4.987 Windows - Reflective Film 5.0% 50.0% 10 $166.67 142.5 0.07 $0.156 Windows - High Efficiency/Energy Star 71.3% 100.0% 25 $2,500.00 1,226.3 0.40 $0.163 Interior Lighting - Occupancy Sensor 8.2% 20.0% 15 $256.00 254.7 0.09 $0.103 Exterior Lighting - Photovoltaic Installation 10.0% 100.0% 15 $2,975.00 20.4 0.00 $14.935 Exterior Lighting - Photosensor Control 8.4% 100.0% 8 $90.00 13.8 0.01 $1.020 Exterior Lighting - Timeclock Installation 6.0% 100.0% 8 $72.00 13.8 0.02 $0.816 Water Heater - Faucet Aerators 45.5% 100.0% 25 $24.00 170.6 1.00 $0.011 Water Heater - Pipe Insulation 6.0% 100.0% 13 $15.00 150.2 1.22 $0.011 Water Heater - Low Flow Showerheads 73.8% 100.0% 10 $25.48 777.0 2.77 $0.004 Water Heater - Tank Blanket/Insulation 54.0% 100.0% 10 $15.00 482.9 2.29 $0.004 Water Heater - Thermostat Setback 17.0% 100.0% 5 $40.00 482.9 0.68 $0.019 Electronics - Reduce Standby Wattage 5.0% 100.0% 8 $20.00 64.3 0.27 $0.049 Refrigerator - Early Replacement 10.0% 85.0% 7 $109.00 224.7 0.11 $0.084 Refrigerator - Remove Second Unit 17.3% 85.0% 7 $109.00 437.0 0.83 $0.043 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 975 of 1125 Residential Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting B-73 Table B-34 Energy Efficiency Non-Equipment Data, Electric—Low income, New Vintage, Idaho Measure Base Saturation Applicability Lifetime (Years) Cost ($/HH) Savings (kWh) BC Ratio Levelized Cost ($/kWh) Central AC - Maintenance and Tune-Up 24.6% 100.0% 4 $100.00 62.7 0.44 $0.440 Attic Fan - Installation 15.0% 50.0% 18 $96.50 3.3 0.00 $2.739 Attic Fan - Photovoltaic - Installation 5.0% 25.0% 19 $200.00 3.3 0.00 $5.524 Ceiling Fan - Installation 33.0% 100.0% 15 $80.00 65.4 0.08 $0.126 Whole-House Fan - Installation 4.0% 25.0% 18 $150.00 89.9 0.06 $0.155 Air Source Heat Pump - Maintenance 37.8% 100.0% 4 $125.00 516.2 0.65 $0.067 Insulation - Ducting 25.0% 25.0% 18 $210.00 303.0 0.44 $0.064 Thermostat - Clock/Programmable 45.3% 75.0% 15 $114.42 490.0 1.05 $0.024 Doors - Storm and Thermal 19.0% 100.0% 12 $180.00 111.5 0.10 $0.190 Insulation - Ceiling 39.0% 50.0% 20 $152.00 300.6 0.67 $0.045 Insulation - Radiant Barrier 5.0% 100.0% 12 $922.68 103.0 0.32 $1.054 Roofs - High Reflectivity 0.0% 100.0% 15 $516.54 48.7 0.01 $1.089 Windows - Reflective Film 2.0% 50.0% 10 $166.67 126.8 0.07 $0.175 Windows - High Efficiency/Energy Star 80.2% 100.0% 25 $2,200.00 1,681.0 0.44 $0.105 Interior Lighting - Occupancy Sensor 8.2% 10.0% 15 $256.00 268.5 0.12 $0.098 Exterior Lighting - Photovoltaic Installation 10.0% 100.0% 15 $2,975.00 21.8 0.00 $13.986 Exterior Lighting - Photosensor Control 0.0% 100.0% 8 $90.00 14.5 0.02 $0.971 Exterior Lighting - Timeclock Installation 11.0% 100.0% 8 $72.00 14.5 0.02 $0.777 Water Heater - Faucet Aerators 10.6% 100.0% 25 $24.00 162.9 1.04 $0.012 Water Heater - Pipe Insulation 0.0% 100.0% 13 $15.00 143.7 1.56 $0.012 Water Heater - Low Flow Showerheads 66.2% 100.0% 10 $25.48 743.6 3.45 $0.005 Water Heater - Tank Blanket/Insulation 0.0% 0.0% 10 $15.00 462.1 2.80 $0.004 Water Heater - Thermostat Setback 5.0% 100.0% 5 $40.00 462.1 0.80 $0.020 Electronics - Reduce Standby Wattage 5.0% 100.0% 8 $20.00 66.9 0.29 $0.047 Behavioral Measures 5.0% 75.0% 1 $12.00 77.7 0.13 $0.154 Pool - Pump Timer 35.0% 100.0% 15 $160.00 154.7 0.11 $0.106 Insulation - Foundation 27.4% 40.0% 20 $358.00 395.1 0.65 $0.080 Insulation - Wall Cavity 45.6% 100.0% 25 $62.50 311.7 1.25 $0.016 Insulation - Wall Sheathing 58.8% 100.0% 20 $210.00 175.7 0.46 $0.105 Water Heater - Drainwater Heat Reocvery 1.0% 100.0% 25 $899.00 761.6 0.12 $0.095 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 976 of 1125 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 977 of 1125 EnerNOC Utility Solutions Consulting C-1 APPENDIX C C&I ENERGY EFFICIENCY EQUIPMENT AND MEASURE DATA This appendix presents detailed information for all commercial energy-efficiency measures (equipment and non-equipment measures per the LoadMAP taxonomy) that were evaluated in this study. Table C-1 and Table C-2 provide brief narrative descriptions for all equipment and non- equipment measures that were assessed for potential. Table C-3 through Table C-18 list the detailed unit-level data (including economic screen results) for commercial equipment measures in existing and new buildings. The column headings and units are the same as described for the corresponding residential sector tables above. Table C-19 through Table C-34 list the detailed unit-level data (including economic screen results) for commercial non-equipment measures in existing and new construction. The column headings and units are the same as described for the corresponding residential sector tables above. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 978 of 1125 C&I Energy Efficiency Equipment and Measure Data C-2 www.enernoc.com Table C-1 C&I Energy Efficiency Equipment Measure Descriptions End Use Technology Measure Description Cooling Air-Cooled Chiller A central chiller plant creates chilled water for distribution throughout the facility. Because of the wide variety of system types and sizes, savings and cost values for efficiency improvements represent an average over screw, reciprocating, and centrifugal technologies. Under this simplified approach, each central system is characterized by an aggregate efficiency value (inclusive of chiller, pumps, and motors), in kW/ton with a further efficiency upgrade through the application of variable refrigerant flow technology. Cooling Water-Cooled Chiller A central chiller plant creates chilled water for distribution throughout the facility. Water source chillers include heat rejection via a condenser loop and cooling tower. Because of the wide variety of system types and sizes, savings and cost values for efficiency improvements represent an average over screw, reciprocating, and centrifugal technologies. Under this simplified approach, each central system is characterized by an aggregate efficiency value (inclusive of chiller, pumps, motors, and condenser loop equipment), in kW/ton with a further efficiency upgrade through the application of variable refrigerant flow technology. Cooling Roof Top AC Packaged cooling systems, such as rooftop units (RTUs), are simple to install and maintain, and are commonly used in small and medium-sized commercial buildings. Applications range from a single supply system with air intake filters, supply fan, and cooling coil, or can become more complex with the addition of a return air duct, return air fan, and various controls to optimize performance. For packaged RTUs, varying Energy Efficiency Ratios (EER) are modeled, as well as a ductless mini-split system. Cooling / Space Heating Air-Source Heat Pump For heat pumps, units with increasing EER and COP levels are evaluated, as well as a ductless mini-split system. Cooling / Space Heating Geothermal Heat Pump For heat pumps, units with increasing EER and COP levels are evaluated. Space Heating Electric Furnace Resistive heating elements are used to convert electricity directly to heat. The heat is then delivered by a supply fan and duct system to the regions that require heating. Space Heating Electric Resistance Resistive heating elements are used to convert electricity directly to heat. Conductive fins surrounding the element or another mechanism is used to deliver the heat directly to the surrounding room or area. These are typically either baseboard or wall-mounted units. Ventilation Ventilation A variable air volume ventilation system modulates the air flow rate as needed based on the interior conditions of the building to reduce fan load, improve dehumidification, and reduce energy usage. Water Heating Water Heater Efficient electric water heaters are characterized by a high recovery or thermal efficiency (percentage of delivered electric energy which is transferred to the water) and low standby losses (the ratio of heat lost per hour to the content of the stored water). Included in the savings associated with high-efficiency electric water heaters are timers that allow temperature setpoints to change with hot water demand patterns. For example, the heating element could be shut off throughout the night, increasing the overall energy factor of the unit. In addition, tank and pipe insulation reduces standby losses and therefore reduces the demands on the water heater. This analysis considers conventional electric water heaters and heat pump water heaters. Interior Lighting Screw-in This measure evaluates higher-efficiency alternatives for screw-in interior lamps including halogen, CFL, and LED. Interior Lighting High-Bay Fixtures With the exception of screw-in lighting, commercial and industrial lighting efficiency changes typically require more than the simple purchase and installation of an alternative lamp Restrictions regarding ballasts, fixtures, and circuitry limit the potential for direct substitution of one lamp type for another. Also, during the buildout for a leased office space, management could decide Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 979 of 1125 C&I Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting C-3 End Use Technology Measure Description to replace all lamps, ballasts, and fixtures with different configurations. This type of decision-making is modeled on a stock turnover basis because of the time between opportunities for upgrades. For High-Bay fixtures, alternatives include mercury vapor, metal halides, T5 fluorescent high output, and high- pressure sodium. Interior Lighting Linear Fluorescent With the exception of screw-in lighting, commercial and industrial lighting efficiency changes typically require more than the simple purchase and installation of an alternative lamp. Restrictions regarding ballasts, fixtures, and circuitry limit the potential for direct substitution of one lamp type for another. Also, during the buildout for a leased office space, management could decide to replace all lamps, ballasts, and fixtures with different configurations. This type of decision-making is modeled on a stock turnover basis because of the time between opportunities for upgrades. For linear fluorescent fixtures, alternatives include T12, T8, Super T8, T5, and LED. Exterior Lighting Screw-in This measure evaluates higher-efficiency alternatives for screw-in interior lamps including halogen, CFL, and LED. Exterior Lighting HID Alternatives modeled include metal halides, T8 and T5 high output, high pressure sodium, and LEDs Exterior Lighting Linear Fluorescent For linear fluorescent fixtures, alternatives include T12, T8, Super T8, T5, and LED. Refrigeration Walk-in Refrigerator These refrigerators can be designed to perform at higher efficiency through a combination of compressor equipment upgrades, default temperature settings, and defrost patterns. Standard refrigeration compressors typically operate at approximately 65% efficiency. High-efficiency models are available that can improve compressor efficiency by 15%. Analysis assumes unit with: 140 square feet, Cooling capacity of 26,230 BTU/hr. Refrigeration Reach-in Refrigerator A significant amount of energy in the commercial sector can be attributed to "reach-in" units. These stand-alone appliances can range from a residential- style refrigerator/freezer unit in an office kitchen or the breakroom of a retail store, to the larger reach-in units in foodservice applications. As in the case of residential units, these refrigerators can be designed to perform at higher efficiency through a combination of compressor equipment upgrades, default temperature settings, and defrost patterns. Analysis assumes unit with: 48 cubic feet, Cooling capacity of 3000 BTU/hr. Refrigeration Glass Door Display, Open Display Case These refrigerators can be designed to perform at higher efficiency through a combination of compressor equipment upgrades, default temperature settings, and defrost patterns. Standard refrigeration compressors typically operate at approximately 65% efficiency. High-efficiency models are available that can improve compressor efficiency by 15%. Analysis assumes unit with: Cooling capacity of 20,000 BTU/hr Refrigeration Icemaker By optimizing the timing of ice production and the type of output to the specific application, icemakers are assumed to deliver electricity savings. Refrigeration Vending Machine High-efficiency vending machines incorporate more efficient compressors and lighting. Food Preparation Ovens,Fryers, Hot Food Containers, Dishwashers This set of measures includes high-efficiency fryers, ovens, dishwashers, and hot food containers. Less common equipment, such as broilers and steamers, and assumed to be modeled with the other more common equipment types. Office Equipment Desktop Computer, Laptop, Monitors ENERGY STAR labeled computers automatically power down to 15 watts or less when not in use and may actually last longer than conventional products because they spend a large portion of time in a low-power sleep mode. ENERGY STAR labeled computers also generate less heat than conventional models. Office Equipment Server In addition to the "sleep" mode a reductions, servers have additional energy- saving opportunities through "virtualization" and other architecture solutions that involve optimal matching of computation tasks to hardware requirements Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 980 of 1125 C&I Energy Efficiency Equipment and Measure Data C-4 www.enernoc.com End Use Technology Measure Description Office Equipment Printer/Copier/Fax ENERGY STAR labeled office equipment saves energy by powering down and "going to sleep" when not in use. ENERGY STAR labeled copiers are equipped with a feature that allows them to automatically turn off after a period of inactivity. Office Equipment POS Terminal Point-of-sale terminals in retail and supermarket facilities are always on. Efficient models incorporate a high-efficiency power supply to reduce energy use. Miscellaneous Non-HVAC Motors Includes motors for a variety of non-HVAC uses including vertical transportation. Premium efficiency motors can provide savings of 0.5% to 3% over standard motors. The savings results from the fact that energy efficient motors run cooler than their standard counterparts, resulting in an increase in the life of the motor insulation and bearing. In general, an efficient motor is a more reliable motor because there are fewer winding failures, longer periods between needed maintenance, and fewer forced outages. For example, using copper instead of aluminum in the windings, and increasing conductor cross- sectional area, lowers a motor’s I2R losses. Miscellaneous Miscellaneous Improvement of miscellaneous electricity uses Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 981 of 1125 C&I Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting C-5 Table C-2 Commercial and Industrial Energy Efficiency Non-Equipment Measure Descriptions End Use Measure Description HVAC (All) Insulation - Ceiling Thermal insulation is material or combinations of materials that are used to inhibit the flow of heat energy by conductive, convective, and radiative transfer modes. Thus, thermal insulation can conserve energy by reducing the heat loss or gain of a building. The type of building construction defines insulating possibilities. Typical insulating materials include: loose-fill (blown) cellulose; loose-fill (blown) fiberglass; and rigid polystyrene. HVAC (All) Insulation - Ducting Air distribution ducts can be insulated to reduce heating or cooling losses. Best results can be achieved by covering the entire surface area with insulation. Insulation material inhibits the transfer of heat through the air-supply duct. Several types of ducts and duct insulation are available, including flexible duct, pre-insulated duct, duct board, duct wrap, tacked, or glued rigid insulation, and waterproof hard shell materials for exterior ducts. HVAC (All) Insulation - Radiant Barrier Radiant barriers are materials installed to reduce the heat gain in buildings. Radiant barriers are made from materials that are highly reflective and have low emissivity like aluminum. The closer the emissivity is to 0 the better they will perform. Radiant barriers can be placed above the insulation or on the roof rafters. HVAC (All) Insulation - Wall Cavity Thermal insulation is material or combinations of materials that are used to inhibit the flow of heat energy by conductive, convective, and radiative transfer modes. Thus, thermal insulation can conserve energy by reducing the heat loss or gain of a building. The type of building construction defines insulating possibilities. Typical insulating materials include: loose-fill (blown) cellulose; loose-fill (blown) fiberglass; and rigid polystyrene. HVAC (All) Ducting - Repair and Sealing Leakage in unsealed ducts varies considerably because of the differences in fabricating machinery used, the methods for assembly, installation workmanship, and age of the ductwork. Air leaks from the system to the outdoors result in a direct loss proportional to the amount of leakage and the difference in enthalpy between the outdoor air and the conditioned air. To seal ducts, a wide variety of sealing methods and products exist. Each has a relatively short shelf life, and no documented research has identified the aging characteristics of sealant applications. HVAC (All) Windows - High Efficiency High-efficiency windows, such as those labeled under the ENERGY STAR Program, are designed to reduce a building's energy bill while increasing comfort for the occupants at the same time. High-efficiency windows have reducing properties that reduce the amount of heat transfer through the glazing surface. For example, some windows have a low-E coating, which is a thin film of metallic oxide coating on the glass surface that allows passage of short-wave solar energy through glass and prevents long-wave energy from escaping. Another example is double-pane glass that reduces conductive and convective heat transfer. There are also double-pane glasses that are gas-filled (usually argon) to further increase the insulating properties of the window. HVAC (All) Roof - High Reflectivity The color and material of a building structure surface will determine the amount of solar radiation absorbed by that surface and subsequently transferred into a building. This is called solar absorptance. By using a living roof or a roofing material with a light color (and a lower solar absorptance), the roof will absorb less solar radiation and consequently reduce the cooling load. Living roofs also reduce stormwater runoff. HVAC (All) Roofs - Green A green roof covers a section or the entire building roof with a waterproof membrane and vegetative material. Like cool roofs, green roofs can reduce solar absorptance and they can also provide insulation. They also provide non- energy benefits by absorbing rainwater and thus reducing storm water run-off, providing wildlife habitat, and reducing so-called urban heat island effects. Cooling Chiller - Condenser Water Temperature Reset Resetting the condenser water temperature to the lowest possible setting allows the cooling tower to generate cooler water whenever possible and decreases the temperature lift between the condenser and the evaporator. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 982 of 1125 C&I Energy Efficiency Equipment and Measure Data C-6 www.enernoc.com End Use Measure Description This will generally increase chiller part-load efficiency, though it may require increased tower fan energy use. Cooling Chiller - Economizer Economizers allow outside air (when it is cool and dry enough) to be brought into the building space to meet cooling loads instead of using mechanically cooled interior air. A dual enthalpy economizer consists of indoor and outdoor temperature and humidity sensors, dampers, motors, and motor controls. Economizers are most applicable to temperate climates and savings will be smaller in extremely hot or humid areas. Cooling Chiller - VSD on Fans Variable speed drives, which reduce chiller energy use under part load, are modeled for both air-cooled and water-cooled chillers. Cooling Chiller - Chilled Water Reset Chilled water reset controls save energy by improving chiller performance through increasing the supply chilled water temperature, which allows increased suction pressure during low load periods. Raising the chilled water temperature also reduces chilled water piping losses. However, the primary savings from the chilled water reset measure results from chiller efficiency improvement. This is due partly to the smaller temperature difference between chilled water and ambient air, and partly due to the sensitivity of chiller performance to suction temperature. Cooling Chiller - Chilled Water Variable-Flow System The part-load efficiency of chilled water loops can be improved substantially by varying the flow speed of the delivered water with the building demand for cooling. Cooling Chiller - High Efficiency Cooling Tower Fans High-efficiency cooling fans utilize efficient components and variable frequency drives that improve fan performance by adjusting fan speed and rotation as conditions change. Cooling RTU - Evaporative Precooler Evaporative precooling can improve the performance of air conditioning systems, most commonly RTUs. These systems typically use indirect evaporative cooling as a first stage to pre-cool outside air. If the evaporative system cannot meet the full cooling load, the air steam is further cooled with conventional refrigerative air conditioning technology. Cooling RTU - Maintenance Regular cleaning and maintenance enables a roof top unit to function effectively and efficiently throughout its years of service. Neglecting necessary maintenance leads to a steady decline in performance while energy use increases. Maintenance can increase the efficiency of poorly performing equipment by as much as 10%. Cooling / Space Heating Heat Pump - Maintenance Regular cleaning and maintenance enables a heat pump to function effectively and efficiently throughout its years of service. Neglecting necessary maintenance leads to a steady decline in performance while energy use increases. Maintenance can increase the efficiency of poorly performing equipment by as much as 10%. Ventilation Ventilation - Demand Control Ventilation Also known as CO2 Controlled, this measure uses carbon dioxide (CO2) levels to indicate the level of occupancy in a space. Sensors monitor CO2 levels so that air handling controls can adjust the amount of outside air intake. Ventilation rates are thereby controlled based on occupancy, rather than a fixed rate, thus saving HVAC energy use. Ventilation Fans – Energy Efficient Motors High-efficiency motors are essentially interchangeable with standard motors, but differences in construction make them more efficient. Energy-efficient motors achieve their improved efficiency by reducing the losses that occur in the conversion of electrical energy to mechanical energy. This analysis assumes that the efficiency of supply fans is increased by 5% due to installing energy-efficient motors. Water Heating Water Heater - Faucet Aerators/Low Flow Nozzles A faucet aerator or low flow nozzle spreads the stream from a faucet helping to reduce water usage. The amount of water passing through the aerator is measured in gallons per minute (GPM) and the lower the GPM the more water the aerator conserves. Water Heating Water Heater - High Efficiency Circulation A high efficiency circulation pump uses an electronically commutated motor (ECM) to improve motor efficiency over a larger range of partial loads. In Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 983 of 1125 C&I Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting C-7 End Use Measure Description Pump addition, an ECM allows for improved low RPM performance with greater torque and smaller pump dimensions. Water Heating Water Heater - Pipe Insulation Insulating hot water pipes decreases the amount of energy lost during distribution of hot water throughout the building. Insulating pipes will result in quicker delivery of hot water and allows lowering the water heating set point. There are several different types of insulation, the most common being polyethylene and neoprene. Water Heating Water Heater - Tank Blanket/Insulation Insulation levels on hot water heaters can be increased by installing a fiberglass blanket on the outside of the tank. This increase in insulation reduces standby losses and thus saves energy. Water heater insulation is available either by the blanket or by square foot of fiberglass insulation with R-values ranging from 5 to 14. Water Heating Thermostat setback Installing a setback thermostat on the water heater can lead to significant energy savings during periods when there is no one in the building. Interior Lighting Interior Lighting – Central Lighting Controls Daylighting controls use a photosensor to detect ambient light and adjust or turn off electric lights accordingly. Interior Lighting Photocell controlled T8 dimming ballasts Photocells, in concert with dimming ballasts, can detect when adequate daylighting is available and dim or turn off lights to reduce electricity consumption. Usually one photocell is used to control a group of fixtures, a zone, or a circuit. Interior Lighting LED Exit Lighting The lamps inside exit signs represent a significant energy end-use, since they usually operate 24 hours per day. Many old exit signs use incandescent lamps, which consume approximately 40 watts per sign. The incandescent lamps can be replaced with LED lamps that are specially designed for this specific purpose. In comparison, the LED lamps consume approximately 2-5 watts. Interior Lighting Interior Lighting - Occupancy Sensors The installation of occupancy sensors allows lights to be turned off during periods when a space is unoccupied, virtually eliminating the wasted energy due to lights being left on. There are several types of occupancy sensors in the market. Interior Lighting Interior Lighting - Timeclocks and Timers In many cases lighting remains on at night and during weekends. A simple timer can set a schedule for turning lights off to reduce operating hours. Interior Lighting Interior Screw-in - Task Lighting Individual work areas can use task lighting instead of brightly lighting the entire area. Significant energy savings can be realized by focusing light directly where it is needed and lowering the general lighting level. An example of task lighting is the common desk lamp. A 25W desk lamp can be installed in place of a typical lamp in a fixture. Interior Lighting Interior Lighting – Hotel Guestroom Controls Hotel guestrooms can be fitted with occupancy controls that turn off energy- using equipment when the guest is not using the room. The occupancy controls comes in several forms, but this analysis assumes the simplest kind, which is a simple switch near the room’s entry where the guest can deposit their room key or card. If the key or card is present, then lights, TV, and air conditioning can receive power and operate. When the guest leaves and takes the key, all equipment shuts off. Interior Lighting Interior Lighting - Skylights Addition of transparent windows/fixtures in the roof to allow daylight to enter and reduce the need for powered lighting. Applies to new construction only. Interior Lighting Interior Fluorescent - Bi-Level Fixture Bi-level fixtures have the ability to reduce light output to a lower level, given a control strategy that is based on a timer, occupancy sensor, motion sensor, or manual switch. Interior Lighting Interior Fluorescent – High Bay Fixtures Fluorescent fixtures designed for high-bay applications have several advantages over similar HID fixtures: lower energy consumption, lower lumen depreciation rates, better dimming options, faster start-up and restrike, better color rendition, more pupil lumens, and reduced glare. Exterior Exterior Lighting - Daylighting controls use a photosensor to detect ambient light and adjust or Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 984 of 1125 C&I Energy Efficiency Equipment and Measure Data C-8 www.enernoc.com End Use Measure Description Lighting Daylighting Controls turn off electric lights accordingly. Exterior Lighting Exterior Lighting - Photovoltaic Installation Solar photovoltaic generation may be used to power exterior lighting and thus eliminate all or part of the electrical energy use. Exterior Lighting Exterior Lighting – Cold Cathode Lighting Cold cathode lighting does not use an external heat source to provide thermionic emission of electrons. Cold cathode lighting is typically used for exterior signage or where temperatures are likely to drop below freezing. Food Preparation Cooking Exhaust hood with sensor control Improved exhaust hoods involve installing variable-speed controls on commercial kitchen hoods. These controls provide ventilation based on actual cooking loads. When grills, broilers, stoves, fryers or other kitchen appliances are not being used, the controls automatically sense the reduced load and decrease the fan speed accordingly. This results in lower energy consumption because the system is only running as needed rather than at 100% capacity at all times. Refrigeration Refrigerator - Anti- Sweat Heater/ Auto Door Closer Anti-sweat heaters are used in virtually all low-temperature display cases and many medium-temperature cases to control humidity and prevent the condensation of water vapor on the sides and doors and on the products contained in the cases. Typically, these heaters stay on all the time, even though they only need to be on about half the time. Anti-sweat heater controls can come in the form of humidity sensors or time clocks. Refrigeration Refrigerator - Door Gasket Replacement This measure involves replacing aging door gaskets that no longer adequately seal reach-in refrigerators or glass door display cases. Refrigeration Refrigerator - Floating Head Pressure Floating head pressure control allows the pressure in the condenser to "float" with ambient temperatures. This method reduces refrigeration compression ratios, improves system efficiency and extends the compressor life. The greatest savings with a floating head pressure approach occurs when the ambient temperatures are low, such as in the winter season. Floating head pressure control is most practical for new installations. However, retrofits installation can be completed with some existing refrigeration systems. Installing floating head pressure control increases the capacity of the compressor when temperatures are low, which may lead to short cycling. Refrigeration Refrigerator - Strip Curtain Strip curtains at the entrances to large walk-in coolers or freezers, such as those used in supermarkets, reduce air transfer between the refrigerated space and the surrounding space. Refrigeration (All) Insulation - Bare suction lines Suction lines deliver refrigerant fluid from to the inlet or suction side of a compressor. Insulating these lines prevents ambient air from heating the fluid in the line, and thus improves efficiency. Refrigeration Refrigerator - High Efficiency Case Lighting High-efficiency case lightin, usually with LEDs, reduces waste heat from lighting that must be removed from refrigeratied display cases. Refrigeration Refrigerator – Night Covers Night covers can be used on open refrigeration cases when a facility is closed or few customers are in the store. Refrigeration Vending Machine - Controller Cold beverage vending machines usually operate 24 hours a day regardless of whether the surrounding area is occupied or not. The result is that the vending machine consumes energy unnecessarily, because it will operate all night to keep the beverage cold even when there would be no customer until the next morning. A vending machine controller can reduce energy consumption without compromising the temperature of the vended product. The controller uses an infrared sensor to monitor the surrounding area’s occupancy and will power down the vending machine when the area is unoccupied. It will also monitor the room’s temperature and will re -power the machine at one to three hour intervals independent of occupancy to ensure that the product stays cold. Office Equipment Office Equipment – Smart Power Strips These power strips encorporate motion sensing to power down office equipment when not in use. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 985 of 1125 C&I Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting C-9 End Use Measure Description Micellaneous Laundry – High Efficiency Clothes Washer High efficiency clothes washers use designs that require less water. These machines use sensors to match the hot water needs to the load, preventing energy waste. There are two designs: top-loading and front-loading. Further energy and water savings can be achieved through advanced technologies such as inverter-drive or combination washer-dryer units. Micellaneous Micellaneous – ENERGY STAR Washer Cooler An ENERGY STAR water cooler has more insulation and improved chilling mechanisms, resulting in about half the energy use of a standard cooler. Micellaneous Pumps - Variable Speed Control The part-load efficiency of drive systems can be improved by varying the speed of the motor drive. An additional benefit of variable-speed controls is the ability to start and stop the motor and process gradually, thus extending the life of the motor and associated machinery. Machine Drive Motors – Variable Frequency Drive In addition to energy savings, VFDs increase motor and system life and provide a greater degree of control over the motor system. Especially for motor systems handling fluids, VFDs can efficiently respond to changing operating conditions. Machine Drive Motors – Magnetic Adjustable Speed Drives To allow for adjustable speed operation, this technology uses magnetic induction to couple a drive to its load. Varying the magnetic slip within the coupling controls the speed of the output shaft. Magnetic drives perform best at the upper end of the speed range due to the energy consumed by the slip. Unlike traditional ASDs, magnetically coupled ASDs create no power distortion on the electrical system. However, magnetically coupled ASD efficiency is best when power needs are greatest. VFDs may show greater efficiency when the average load speed is below 90% of the motor speed, however this occurs when power demands are reduced. Machine Drive Compressed Air – System Controls, Optimization and Imrovements, Maintenance Controls for compressed air systems can shift load from two partially loaded compressors to one compressor in order to maximize compression efficiency and may also involve the addition of VFDs. Improvements include installing high-efficiency motors. Maintenance includes fixing air leaks and replacing air filters. Machine Drive Fan Systems – Controls, Optimization and Improvements, Maintenance Controls for compressed air systems can shift load from two partially loaded compressors to one compressor in order to maximize compression efficiency and may also involve the addition of VFDs. Improvements include installing high-efficiency motors. Maintenance includes fixing air leaks and replacing air filters. Machine Drive Pumping Systems – Controls, Optimization and Maintenance Pumping systems optimization includes installing VFDs, correctly resizing the motors, and installing timers and automated on-off controls. Maintenance includes repairing diaphragms and fixing piping leaks. Machine Drive Motors - Synchronous Belts Synchronous belts offer higher efficiency compared with standard belts due to reduced slipping, as well as less maintenance and retensioning. Process Refrigeration – System Controls, Maintenance, and Optimization Because refrigeration equipment performance degrades over time and control settings are frequently overridden, these measures account for savings that can be achieved through system maintenance and controls optimization. HVAC (All) Energy Management System An energy management system (EMS) allows managers/owners to monitor and control the major energy-consuming systems within a commercial building. At the minimum, the EMS can be used to monitor and record energy consumption of the different end-uses in a building, and can control operation schedules of the HVAC and lighting systems. The monitoring function helps building managers/owners to identify systems that are operating inefficiently so that actions can be taken to correct the problem. The EMS can also provide preventive maintenance scheduling that will reduce the cost of operations and maintenance in the long run. The control functionality of the EMS allows the building manager/owner to operate building systems from one central location. The operation schedules set via the EMS help to prevent building Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 986 of 1125 C&I Energy Efficiency Equipment and Measure Data C-10 www.enernoc.com End Use Measure Description systems from operating during unwanted or unoccupied periods. This analysis assumes that this measure is limited to buildings with a central HVAC system. HVAC (All) Thermostat - Clock/Programmable A programmable thermostat can be added to most heating/cooling systems. They are typically used during winter to lower temperatures at night and in summer to increase temperatures during the afternoon. There are two-setting models, and well as models that allow separate programming for each day of the week. The energy savings from this type of thermostat are identical to those of a "setback" strategy with standard thermostats, but the convenience of a programmable thermostat makes it a much more attractive option. In this analysis, the baseline is assumed to have no thermostat setback. HVAC (All) Advanced New Construction Designs Advanced new construction designs use an integrated approach to the design of new buildings to account for the interaction of building systems. Designs may specify the building orientation, building shell, proper sizing of equipment and systems, and controls strategies with the goal of optimizing building energy efficiency and comfort. Options that may be evaluated and incorporated include passive solar strategies, increased thermal mass, natural ventilation, energy recovery ventilation, daylighting strategies, and shading strategies. This measure is modeled for new vintage only. HVAC, Lighting Commissioning - HVAC, Lighting, Comprehensive For new construction and major renovations, commissioning ensures that building systems are properly designed, specified, and installed to meet the design intent and provide high-efficiency performance. As the names suggests, HVAC Commissioning and Lighting Commissioning focus only on HVAC and lighting equipment and controls. Comprehensive commissioning addresses these systems but usually begins earlier in the design process, and may also address domestic hot water, non-HVAC fans, vertical transport, telecommunications, fire protection, and other building systems. HVAC, Lighting Retrocommissioning - HVAC, Lighting In existing buildings, the retrocommissioning process identifies low-cost or no cost measures, including controls adjustments, to improve building performance and reduce operating costs. Retrocommissioning addresses HVAC, lighting, DHW, and other major building systems. All Transformer All electric power passes through one or more transformers on its way to service equipment, lighting, and other loads. Currently available materials and designs can considerably reduce both load and no-load losses. The new NEMA TP-1 standard is used as the reference definition for energy -efficient products. Tier-1 represents TP-1 dry-type transformers while Tier-2 reflects a switch to liquid immersed TP-1 products. More efficient transformers with attractive payback periods are estimated to save 40 to 50 percent of the energy lost by a "typical" transformer, which translates into a one to three percent reduction in electric bills for commercial and industrial customers. All Strategic Energy Management Strategic Energy Management is a systematic approach to integrating energy management into an organization’s business practices and creating lasting energy management processes that produce reliable energy savings. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 987 of 1125 C&I Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting C-11 Table C-3 Energy Efficiency Equipment Data, Electric—Small/Medium Commercial, Existing Vintage, Washington End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Cooling Central Chiller 1.5 kw/ton, COP 2.3 - $0.00 20 - $0.00 Cooling Central Chiller 1.3 kw/ton, COP 2.7 0.31 $0.39 20 1.10 $0.09 Cooling Central Chiller 1.26 kw/ton, COP 2.8 0.38 $0.50 20 0.96 $0.09 Cooling Central Chiller 1.0 kw/ton, COP 3.5 0.79 $0.62 20 0.99 $0.06 Cooling Central Chiller 0.97 kw/ton, COP 3.6 0.83 $0.74 20 0.95 $0.06 Cooling Central Chiller Variable Refrigerant Flow 1.09 $11.57 20 0.18 $0.75 Cooling RTU EER 9.2 - $0.00 16 - $0.00 Cooling RTU EER 10.1 0.21 $0.18 16 - $0.07 Cooling RTU EER 11.2 0.42 $0.35 16 1.00 $0.07 Cooling RTU EER 12.0 0.55 $0.58 16 0.91 $0.09 Cooling RTU Ductless VRF 0.68 $5.12 16 0.28 $0.62 Cooling Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00 Cooling Heat Pump EER 10.3, COP 3.2 0.42 $0.39 15 - $0.08 Cooling Heat Pump EER 11.0, COP 3.3 0.66 $1.18 15 1.00 $0.15 Cooling Heat Pump EER 11.7, COP 3.4 0.88 $1.57 15 0.97 $0.15 Cooling Heat Pump EER 12, COP 3.4 0.97 $1.96 15 0.93 $0.18 Cooling Heat Pump Ductless Mini-Split System 1.07 $11.50 20 0.52 $0.76 Space Heating Electric Resistance Standard - $0.00 25 1.00 $0.00 Space Heating Furnace Standard - $0.00 18 1.00 $0.00 Ventilation Ventilation Constant Volume - $0.00 15 1.00 $0.00 Ventilation Ventilation Variable Air Volume 1.37 $1.22 15 0.92 $0.08 Interior Lighting Interior Screw-in Incandescents - $0.00 1 - $0.00 Interior Lighting Interior Screw-in Infrared Halogen 0.47 $0.09 1 1.00 $0.18 Interior Lighting Interior Screw-in CFL 1.96 $0.03 4 5.64 $0.00 Interior Lighting Interior Screw-in LED 2.17 $1.18 12 - $0.06 Interior Lighting High Bay Fixtures Metal Halides - $0.00 6 1.00 $0.00 Interior Lighting High Bay Fixtures High Pressure Sodium 0.25 -$0.07 9 2.04 -$0.04 Interior Lighting High Bay Fixtures T8 0.25 -$0.15 6 4.03 -$0.11 Interior Lighting High Bay Fixtures T5 0.32 -$0.15 6 4.81 -$0.08 Interior Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00 Interior Lighting Linear Fluorescent T8 0.34 -$0.03 6 1.11 -$0.02 Interior Lighting Linear Fluorescent Super T8 1.03 $0.25 6 0.94 $0.04 Interior Lighting Linear Fluorescent T5 1.07 $0.43 6 0.81 $0.07 Interior Lighting Linear Fluorescent LED 1.12 $3.74 15 - $0.29 Exterior Lighting Exterior Screw-in Incandescent - $0.00 1 - $0.00 Exterior Lighting Exterior Screw-in Infrared Halogen 0.09 $0.05 1 1.00 $0.50 Exterior Lighting Exterior Screw-in CFL 0.38 $0.02 4 6.92 $0.01 Exterior Lighting Exterior Screw-in Metal Halides 0.39 $0.05 4 3.30 $0.04 Exterior Lighting Exterior Screw-in LED 0.43 $0.64 12 - $0.15 Exterior HID Metal Halides - $0.00 6 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 988 of 1125 C&I Energy Efficiency Equipment and Measure Data C-12 www.enernoc.com End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Lighting Exterior Lighting HID High Pressure Sodium 0.17 -$0.13 9 2.08 -$0.10 Exterior Lighting HID Low Pressure Sodium 0.18 $0.55 9 0.57 $0.40 Water Heating Water Heater Baseline (EF=0.90) - $0.00 15 1.00 $0.00 Water Heating Water Heater High Efficiency (EF=0.95) 0.11 $0.02 15 1.02 $0.02 Water Heating Water Heater EF 2.0 1.07 -$0.48 15 2.84 -$0.04 Water Heating Water Heater EF 2.3 1.20 -$0.47 15 3.25 -$0.03 Water Heating Water Heater EF 2.4 1.24 -$0.47 15 3.38 -$0.03 Water Heating Water Heater Geothermal Heat Pump 1.42 $3.53 15 0.38 $0.21 Water Heating Water Heater Solar 1.56 $3.03 15 0.44 $0.17 Food Preparation Fryer Standard - $0.00 12 1.00 $0.00 Food Preparation Fryer Efficient 0.03 $0.04 12 0.87 $0.12 Food Preparation Oven Standard - $0.00 12 1.00 $0.00 Food Preparation Oven Efficient 0.39 $0.36 12 0.92 $0.10 Food Preparation Dishwasher Standard - $0.00 12 1.00 $0.00 Food Preparation Dishwasher Efficient 0.02 $0.05 12 0.87 $0.28 Food Preparation Hot Food Container Standard - $0.00 12 1.00 $0.00 Food Preparation Hot Food Container Efficient 0.32 $0.16 12 0.96 $0.05 Food Preparation Food Prep Standard - $0.00 12 1.00 $0.00 Food Preparation Food Prep Efficient 0.00 $0.03 12 0.88 $1.40 Refrigeration Walk in Refrigeration Standard - $0.00 18 1.00 $0.00 Refrigeration Walk in Refrigeration Efficient - $0.09 18 0.90 $0.00 Refrigeration Glass Door Display Standard - $0.00 18 1.00 $0.00 Refrigeration Glass Door Display Efficient 0.16 $0.00 18 1.36 $0.00 Refrigeration Reach-in Refrigerator Standard - $0.00 18 1.00 $0.00 Refrigeration Reach-in Refrigerator Efficient 0.15 $0.02 18 1.15 $0.01 Refrigeration Open Display Case Standard - $0.00 18 1.00 $0.00 Refrigeration Open Display Case Efficient 0.00 $0.00 18 0.92 $0.33 Refrigeration Vending Machine Base - $0.00 10 - $0.00 Refrigeration Vending Machine Base (2012) 0.09 $0.00 10 1.00 $0.00 Refrigeration Vending Machine High Efficiency 0.11 $0.00 10 - $0.00 Refrigeration Vending Machine High Efficiency (2012) 0.17 $0.00 10 1.18 $0.00 Refrigeration Icemaker Standard - $0.00 12 1.00 $0.00 Refrigeration Icemaker Efficient 0.05 $0.00 12 1.11 $0.01 Office Equipment Desktop Computer Baseline - $0.00 4 1.00 $0.00 Office Equipment Desktop Computer Energy Star 0.21 $0.00 4 1.01 $0.00 Office Equipment Desktop Computer Climate Savers 0.30 $0.36 4 0.85 $0.32 Office Equipment Laptop Computer Baseline - $0.00 4 1.00 $0.00 Office Equipment Laptop Computer Energy Star 0.02 $0.00 4 1.00 $0.01 Office Equipment Laptop Computer Climate Savers 0.04 $0.12 4 0.84 $0.87 Office Server Standard - $0.00 3 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 989 of 1125 C&I Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting C-13 End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Equipment Office Equipment Server Energy Star 0.11 $0.01 3 0.99 $0.04 Office Equipment Monitor Standard - $0.00 4 1.00 $0.00 Office Equipment Monitor Energy Star 0.06 $0.00 4 1.03 $0.01 Office Equipment Printer/copier/fax Standard - $0.00 6 1.00 $0.00 Office Equipment Printer/copier/fax Energy Star 0.08 $0.04 6 0.95 $0.09 Office Equipment POS Terminal Standard - $0.00 4 1.00 $0.00 Office Equipment POS Terminal Energy Star 0.02 $0.00 4 1.00 $0.03 Miscellaneous Non-HVAC Motor Standard - $0.00 15 - $0.00 Miscellaneous Non-HVAC Motor Standard (2015) 0.01 $0.06 15 - $0.71 Miscellaneous Non-HVAC Motor High Efficiency 0.01 $0.00 15 1.00 $0.00 Miscellaneous Non-HVAC Motor High Efficiency (2015) 0.06 $0.06 15 0.98 $0.08 Miscellaneous Non-HVAC Motor Premium - $0.00 0 - $0.00 Miscellaneous Non-HVAC Motor Premium (2015) - $0.00 0 - $0.00 Miscellaneous Other Miscellaneous Miscellaneous - $0.00 5 - $0.00 Miscellaneous Other Miscellaneous Miscellaneous (2013) 0.00 $0.00 5 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 990 of 1125 C&I Energy Efficiency Equipment and Measure Data C-14 www.enernoc.com Table C-4 Energy Efficiency Equipment Data, Electric—Small/Medium Commercial, New Vintage, Washington End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Cooling Central Chiller 1.5 kw/ton, COP 2.3 - $0.00 20 - $0.00 Cooling Central Chiller 1.3 kw/ton, COP 2.7 0.28 $0.39 20 1.10 $0.10 Cooling Central Chiller 1.26 kw/ton, COP 2.8 0.34 $0.50 20 0.96 $0.11 Cooling Central Chiller 1.0 kw/ton, COP 3.5 0.70 $0.62 20 0.98 $0.06 Cooling Central Chiller 0.97 kw/ton, COP 3.6 0.74 $0.74 20 0.94 $0.07 Cooling Central Chiller Variable Refrigerant Flow 0.97 $11.57 20 0.18 $0.84 Cooling RTU EER 9.2 - $0.00 16 - $0.00 Cooling RTU EER 10.1 0.20 $0.18 16 - $0.08 Cooling RTU EER 11.2 0.41 $0.35 16 1.00 $0.07 Cooling RTU EER 12.0 0.53 $0.58 16 0.91 $0.09 Cooling RTU Ductless VRF 0.65 $5.12 16 0.28 $0.65 Cooling Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00 Cooling Heat Pump EER 10.3, COP 3.2 0.40 $0.39 15 - $0.08 Cooling Heat Pump EER 11.0, COP 3.3 0.63 $1.18 15 1.00 $0.16 Cooling Heat Pump EER 11.7, COP 3.4 0.84 $1.57 15 0.97 $0.16 Cooling Heat Pump EER 12, COP 3.4 0.93 $1.96 15 0.93 $0.18 Cooling Heat Pump Ductless Mini-Split System 1.03 $11.50 20 0.52 $0.79 Space Heating Electric Resistance Standard - $0.00 25 1.00 $0.00 Space Heating Furnace Standard - $0.00 18 1.00 $0.00 Ventilation Ventilation Constant Volume - $0.00 15 1.00 $0.00 Ventilation Ventilation Variable Air Volume 1.89 $1.22 15 1.01 $0.06 Interior Lighting Interior Screw-in Incandescents - $0.00 1 - $0.00 Interior Lighting Interior Screw-in Infrared Halogen 0.65 $0.09 1 1.00 $0.13 Interior Lighting Interior Screw-in CFL 2.67 $0.03 4 5.27 $0.00 Interior Lighting Interior Screw-in LED 2.96 $1.18 12 - $0.04 Interior Lighting High Bay Fixtures Metal Halides - $0.00 6 1.00 $0.00 Interior Lighting High Bay Fixtures High Pressure Sodium 0.24 -$0.07 9 2.06 -$0.04 Interior Lighting High Bay Fixtures T8 0.24 -$0.15 6 4.16 -$0.11 Interior Lighting High Bay Fixtures T5 0.30 -$0.15 6 4.95 -$0.09 Interior Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00 Interior Lighting Linear Fluorescent T8 0.32 -$0.03 6 1.11 -$0.02 Interior Lighting Linear Fluorescent Super T8 0.96 $0.25 6 0.93 $0.05 Interior Lighting Linear Fluorescent T5 1.00 $0.43 6 0.79 $0.08 Interior Lighting Linear Fluorescent LED 1.05 $3.74 15 - $0.31 Exterior Lighting Exterior Screw-in Incandescent - $0.00 1 - $0.00 Exterior Lighting Exterior Screw-in Infrared Halogen 0.08 $0.05 1 1.00 $0.60 Exterior Lighting Exterior Screw-in CFL 0.32 $0.02 4 7.11 $0.02 Exterior Lighting Exterior Screw-in Metal Halides 0.32 $0.05 4 3.29 $0.04 Exterior Lighting Exterior Screw-in LED 0.36 $0.64 12 - $0.18 Exterior HID Metal Halides - $0.00 6 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 991 of 1125 C&I Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting C-15 End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Lighting Exterior Lighting HID High Pressure Sodium 0.17 -$0.13 9 2.08 -$0.10 Exterior Lighting HID Low Pressure Sodium 0.18 $0.55 9 0.57 $0.40 Water Heating Water Heater Baseline (EF=0.90) - $0.00 15 1.00 $0.00 Water Heating Water Heater High Efficiency (EF=0.95) 0.11 $0.02 15 1.02 $0.02 Water Heating Water Heater EF 2.0 1.05 -$0.48 15 2.86 -$0.04 Water Heating Water Heater EF 2.3 1.18 -$0.47 15 3.27 -$0.03 Water Heating Water Heater EF 2.4 1.22 -$0.47 15 3.40 -$0.03 Water Heating Water Heater Geothermal Heat Pump 1.39 $3.53 15 0.38 $0.22 Water Heating Water Heater Solar 1.53 $3.03 15 0.43 $0.17 Food Preparation Fryer Standard - $0.00 12 1.00 $0.00 Food Preparation Fryer Efficient 0.03 $0.04 12 0.87 $0.12 Food Preparation Oven Standard - $0.00 12 1.00 $0.00 Food Preparation Oven Efficient 0.39 $0.36 12 0.92 $0.10 Food Preparation Dishwasher Standard - $0.00 12 1.00 $0.00 Food Preparation Dishwasher Efficient 0.02 $0.05 12 0.87 $0.28 Food Preparation Hot Food Container Standard - $0.00 12 1.00 $0.00 Food Preparation Hot Food Container Efficient 0.32 $0.16 12 0.96 $0.05 Food Preparation Food Prep Standard - $0.00 12 1.00 $0.00 Food Preparation Food Prep Efficient 0.00 $0.03 12 0.87 $1.73 Refrigeration Walk in Refrigeration Standard - $0.00 18 1.00 $0.00 Refrigeration Walk in Refrigeration Efficient - $0.09 18 0.90 $0.00 Refrigeration Glass Door Display Standard - $0.00 18 1.00 $0.00 Refrigeration Glass Door Display Efficient 0.16 $0.00 18 1.36 $0.00 Refrigeration Reach-in Refrigerator Standard - $0.00 18 1.00 $0.00 Refrigeration Reach-in Refrigerator Efficient 0.15 $0.02 18 1.15 $0.01 Refrigeration Open Display Case Standard - $0.00 18 1.00 $0.00 Refrigeration Open Display Case Efficient 0.00 $0.00 18 0.91 $0.35 Refrigeration Vending Machine Base - $0.00 10 - $0.00 Refrigeration Vending Machine Base (2012) 0.09 $0.00 10 1.00 $0.00 Refrigeration Vending Machine High Efficiency 0.11 $0.00 10 - $0.00 Refrigeration Vending Machine High Efficiency (2012) 0.17 $0.00 10 1.18 $0.00 Refrigeration Icemaker Standard - $0.00 12 1.00 $0.00 Refrigeration Icemaker Efficient 0.05 $0.00 12 1.11 $0.01 Office Equipment Desktop Computer Baseline - $0.00 4 1.00 $0.00 Office Equipment Desktop Computer Energy Star 0.21 $0.00 4 1.01 $0.00 Office Equipment Desktop Computer Climate Savers 0.30 $0.36 4 0.85 $0.32 Office Equipment Laptop Computer Baseline - $0.00 4 1.00 $0.00 Office Equipment Laptop Computer Energy Star 0.02 $0.00 4 1.00 $0.01 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 992 of 1125 C&I Energy Efficiency Equipment and Measure Data C-16 www.enernoc.com End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Office Equipment Laptop Computer Climate Savers 0.04 $0.12 4 0.84 $0.87 Office Equipment Server Standard - $0.00 3 1.00 $0.00 Office Equipment Server Energy Star 0.11 $0.01 3 0.99 $0.04 Office Equipment Monitor Standard - $0.00 4 1.00 $0.00 Office Equipment Monitor Energy Star 0.06 $0.00 4 1.03 $0.01 Office Equipment Printer/copier/fax Standard - $0.00 6 1.00 $0.00 Office Equipment Printer/copier/fax Energy Star 0.08 $0.04 6 0.95 $0.09 Office Equipment POS Terminal Standard - $0.00 4 1.00 $0.00 Office Equipment POS Terminal Energy Star 0.02 $0.00 4 1.00 $0.03 Miscellaneous Non-HVAC Motor Standard - $0.00 15 - $0.00 Miscellaneous Non-HVAC Motor Standard (2015) 0.01 $0.06 15 - $0.71 Miscellaneous Non-HVAC Motor High Efficiency 0.01 $0.00 15 1.00 $0.00 Miscellaneous Non-HVAC Motor High Efficiency (2015) 0.06 $0.06 15 0.98 $0.08 Miscellaneous Non-HVAC Motor Premium - $0.00 0 - $0.00 Miscellaneous Non-HVAC Motor Premium (2015) - $0.00 0 - $0.00 Miscellaneous Other Miscellaneous Miscellaneous - $0.00 5 - $0.00 Miscellaneous Other Miscellaneous Miscellaneous (2013) 0.00 $0.00 5 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 993 of 1125 C&I Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting C-17 Table C-5 Energy Efficiency Equipment Data, Small/Medium Commercial, Existing Vintage, Idaho End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Cooling Central Chiller 1.5 kw/ton, COP 2.3 - $0.00 20 - $0.00 Cooling Central Chiller 1.3 kw/ton, COP 2.7 0.31 $0.39 20 1.10 $0.09 Cooling Central Chiller 1.26 kw/ton, COP 2.8 0.38 $0.50 20 0.96 $0.09 Cooling Central Chiller 1.0 kw/ton, COP 3.5 0.79 $0.62 20 0.99 $0.06 Cooling Central Chiller 0.97 kw/ton, COP 3.6 0.83 $0.74 20 0.95 $0.06 Cooling Central Chiller Variable Refrigerant Flow 1.09 $11.57 20 0.18 $0.75 Cooling RTU EER 9.2 - $0.00 16 - $0.00 Cooling RTU EER 10.1 0.21 $0.18 16 - $0.07 Cooling RTU EER 11.2 0.42 $0.35 16 1.00 $0.07 Cooling RTU EER 12.0 0.55 $0.58 16 0.91 $0.09 Cooling RTU Ductless VRF 0.68 $5.12 16 0.28 $0.62 Cooling Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00 Cooling Heat Pump EER 10.3, COP 3.2 0.42 $0.39 15 - $0.08 Cooling Heat Pump EER 11.0, COP 3.3 0.66 $1.18 15 1.00 $0.15 Cooling Heat Pump EER 11.7, COP 3.4 0.88 $1.57 15 0.97 $0.15 Cooling Heat Pump EER 12, COP 3.4 0.97 $1.96 15 0.93 $0.18 Cooling Heat Pump Ductless Mini-Split System 1.07 $11.50 20 0.51 $0.76 Space Heating Electric Resistance Standard - $0.00 25 1.00 $0.00 Space Heating Furnace Standard - $0.00 18 1.00 $0.00 Ventilation Ventilation Constant Volume - $0.00 15 1.00 $0.00 Ventilation Ventilation Variable Air Volume 1.37 $1.22 15 0.93 $0.08 Interior Lighting Interior Screw-in Incandescents - $0.00 1 - $0.00 Interior Lighting Interior Screw-in Infrared Halogen 0.47 $0.09 1 1.00 $0.18 Interior Lighting Interior Screw-in CFL 1.96 $0.03 4 5.64 $0.00 Interior Lighting Interior Screw-in LED 2.17 $1.18 12 - $0.06 Interior Lighting High Bay Fixtures Metal Halides - $0.00 6 1.00 $0.00 Interior Lighting High Bay Fixtures High Pressure Sodium 0.25 -$0.07 9 2.01 -$0.04 Interior Lighting High Bay Fixtures T8 0.25 -$0.15 6 3.95 -$0.11 Interior Lighting High Bay Fixtures T5 0.32 -$0.15 6 4.72 -$0.08 Interior Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00 Interior Lighting Linear Fluorescent T8 0.34 -$0.03 6 1.11 -$0.02 Interior Lighting Linear Fluorescent Super T8 1.03 $0.25 6 0.95 $0.04 Interior Lighting Linear Fluorescent T5 1.07 $0.43 6 0.82 $0.07 Interior Lighting Linear Fluorescent LED 1.12 $3.74 15 - $0.29 Exterior Lighting Exterior Screw-in Incandescent - $0.00 1 - $0.00 Exterior Lighting Exterior Screw-in Infrared Halogen 0.13 $0.05 1 1.00 $0.37 Exterior Lighting Exterior Screw-in CFL 0.52 $0.02 4 6.55 $0.01 Exterior Lighting Exterior Screw-in Metal Halides 0.52 $0.05 4 3.32 $0.03 Exterior Lighting Exterior Screw-in LED 0.58 $0.64 12 - $0.11 Exterior HID Metal Halides - $0.00 6 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 994 of 1125 C&I Energy Efficiency Equipment and Measure Data C-18 www.enernoc.com End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Lighting Exterior Lighting HID High Pressure Sodium 0.15 -$0.13 9 2.09 -$0.11 Exterior Lighting HID Low Pressure Sodium 0.16 $0.55 9 0.57 $0.43 Water Heating Water Heater Baseline (EF=0.90) - $0.00 15 1.00 $0.00 Water Heating Water Heater High Efficiency (EF=0.95) 0.11 $0.02 15 1.03 $0.02 Water Heating Water Heater EF 2.0 1.07 -$0.48 15 2.79 -$0.04 Water Heating Water Heater EF 2.3 1.20 -$0.47 15 3.19 -$0.03 Water Heating Water Heater EF 2.4 1.24 -$0.47 15 3.32 -$0.03 Water Heating Water Heater Geothermal Heat Pump 1.42 $3.53 15 0.40 $0.21 Water Heating Water Heater Solar 1.56 $3.03 15 0.46 $0.17 Food Preparation Fryer Standard - $0.00 12 1.00 $0.00 Food Preparation Fryer Efficient 0.03 $0.04 12 0.88 $0.12 Food Preparation Oven Standard - $0.00 12 1.00 $0.00 Food Preparation Oven Efficient 0.39 $0.36 12 0.93 $0.10 Food Preparation Dishwasher Standard - $0.00 12 1.00 $0.00 Food Preparation Dishwasher Efficient 0.02 $0.05 12 0.87 $0.28 Food Preparation Hot Food Container Standard - $0.00 12 1.00 $0.00 Food Preparation Hot Food Container Efficient 0.32 $0.16 12 0.98 $0.05 Food Preparation Food Prep Standard - $0.00 12 1.00 $0.00 Food Preparation Food Prep Efficient 0.00 $0.03 12 0.87 $1.73 Refrigeration Walk in Refrigeration Standard - $0.00 18 1.00 $0.00 Refrigeration Walk in Refrigeration Efficient - $0.09 18 0.90 $0.00 Refrigeration Glass Door Display Standard - $0.00 18 1.00 $0.00 Refrigeration Glass Door Display Efficient 0.16 $0.00 18 1.37 $0.00 Refrigeration Reach-in Refrigerator Standard - $0.00 18 1.00 $0.00 Refrigeration Reach-in Refrigerator Efficient 0.15 $0.02 18 1.16 $0.01 Refrigeration Open Display Case Standard - $0.00 18 1.00 $0.00 Refrigeration Open Display Case Efficient 0.00 $0.00 18 0.92 $0.33 Refrigeration Vending Machine Base - $0.00 10 - $0.00 Refrigeration Vending Machine Base (2012) 0.09 $0.00 10 1.00 $0.00 Refrigeration Vending Machine High Efficiency 0.11 $0.00 10 - $0.00 Refrigeration Vending Machine High Efficiency (2012) 0.17 $0.00 10 1.19 $0.00 Refrigeration Icemaker Standard - $0.00 12 1.00 $0.00 Refrigeration Icemaker Efficient 0.05 $0.00 12 1.11 $0.01 Office Equipment Desktop Computer Baseline - $0.00 4 1.00 $0.00 Office Equipment Desktop Computer Energy Star 0.21 $0.00 4 1.01 $0.00 Office Equipment Desktop Computer Climate Savers 0.30 $0.36 4 0.85 $0.32 Office Equipment Laptop Computer Baseline - $0.00 4 1.00 $0.00 Office Equipment Laptop Computer Energy Star 0.02 $0.00 4 1.00 $0.01 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 995 of 1125 C&I Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting C-19 End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Office Equipment Laptop Computer Climate Savers 0.04 $0.12 4 0.84 $0.87 Office Equipment Server Standard - $0.00 3 1.00 $0.00 Office Equipment Server Energy Star 0.11 $0.01 3 0.99 $0.04 Office Equipment Monitor Standard - $0.00 4 1.00 $0.00 Office Equipment Monitor Energy Star 0.06 $0.00 4 1.03 $0.01 Office Equipment Printer/copier/fax Standard - $0.00 6 1.00 $0.00 Office Equipment Printer/copier/fax Energy Star 0.08 $0.04 6 0.95 $0.09 Office Equipment POS Terminal Standard - $0.00 4 1.00 $0.00 Office Equipment POS Terminal Energy Star 0.02 $0.00 4 1.00 $0.03 Miscellaneous Non-HVAC Motor Standard - $0.00 15 - $0.00 Miscellaneous Non-HVAC Motor Standard (2015) 0.01 $0.06 15 - $0.71 Miscellaneous Non-HVAC Motor High Efficiency 0.01 $0.00 15 1.00 $0.00 Miscellaneous Non-HVAC Motor High Efficiency (2015) 0.06 $0.06 15 0.98 $0.08 Miscellaneous Non-HVAC Motor Premium - $0.00 0 - $0.00 Miscellaneous Non-HVAC Motor Premium (2015) - $0.00 0 - $0.00 Miscellaneous Other Miscellaneous Miscellaneous - $0.00 5 - $0.00 Miscellaneous Other Miscellaneous Miscellaneous (2013) 0.00 $0.00 5 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 996 of 1125 C&I Energy Efficiency Equipment and Measure Data C-20 www.enernoc.com Table C-6 Energy Efficiency Equipment Data, Electric— Small/Medium Commercial, New Vintage, Idaho End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Cooling Central Chiller 1.5 kw/ton, COP 2.3 - $0.00 20 - $0.00 Cooling Central Chiller 1.3 kw/ton, COP 2.7 0.28 $0.39 20 1.10 $0.10 Cooling Central Chiller 1.26 kw/ton, COP 2.8 0.34 $0.50 20 0.96 $0.11 Cooling Central Chiller 1.0 kw/ton, COP 3.5 0.70 $0.62 20 0.98 $0.06 Cooling Central Chiller 0.97 kw/ton, COP 3.6 0.74 $0.74 20 0.94 $0.07 Cooling Central Chiller Variable Refrigerant Flow 0.97 $11.57 20 0.18 $0.84 Cooling RTU EER 9.2 - $0.00 16 - $0.00 Cooling RTU EER 10.1 0.20 $0.18 16 - $0.08 Cooling RTU EER 11.2 0.41 $0.35 16 1.00 $0.07 Cooling RTU EER 12.0 0.53 $0.58 16 0.91 $0.09 Cooling RTU Ductless VRF 0.65 $5.12 16 0.28 $0.65 Cooling Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00 Cooling Heat Pump EER 10.3, COP 3.2 0.40 $0.39 15 - $0.08 Cooling Heat Pump EER 11.0, COP 3.3 0.63 $1.18 15 1.00 $0.16 Cooling Heat Pump EER 11.7, COP 3.4 0.84 $1.57 15 0.97 $0.16 Cooling Heat Pump EER 12, COP 3.4 0.93 $1.96 15 0.93 $0.18 Cooling Heat Pump Ductless Mini-Split System 1.03 $11.50 20 0.51 $0.79 Space Heating Electric Resistance Standard - $0.00 25 1.00 $0.00 Space Heating Furnace Standard - $0.00 18 1.00 $0.00 Ventilation Ventilation Constant Volume - $0.00 15 1.00 $0.00 Ventilation Ventilation Variable Air Volume 1.89 $1.22 15 1.02 $0.06 Interior Lighting Interior Screw-in Incandescents - $0.00 1 - $0.00 Interior Lighting Interior Screw-in Infrared Halogen 0.65 $0.09 1 1.00 $0.13 Interior Lighting Interior Screw-in CFL 2.67 $0.03 4 5.28 $0.00 Interior Lighting Interior Screw-in LED 2.96 $1.18 12 - $0.04 Interior Lighting High Bay Fixtures Metal Halides - $0.00 6 1.00 $0.00 Interior Lighting High Bay Fixtures High Pressure Sodium 0.24 -$0.07 9 2.03 -$0.04 Interior Lighting High Bay Fixtures T8 0.24 -$0.15 6 4.08 -$0.11 Interior Lighting High Bay Fixtures T5 0.30 -$0.15 6 4.86 -$0.09 Interior Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00 Interior Lighting Linear Fluorescent T8 0.32 -$0.03 6 1.11 -$0.02 Interior Lighting Linear Fluorescent Super T8 0.96 $0.25 6 0.94 $0.05 Interior Lighting Linear Fluorescent T5 1.00 $0.43 6 0.80 $0.08 Interior Lighting Linear Fluorescent LED 1.05 $3.74 15 - $0.31 Exterior Lighting Exterior Screw-in Incandescent - $0.00 1 - $0.00 Exterior Lighting Exterior Screw-in Infrared Halogen 0.11 $0.05 1 1.00 $0.44 Exterior Lighting Exterior Screw-in CFL 0.44 $0.02 4 6.76 $0.01 Exterior Lighting Exterior Screw-in Metal Halides 0.44 $0.05 4 3.31 $0.03 Exterior Lighting Exterior Screw-in LED 0.48 $0.64 12 - $0.14 Exterior HID Metal Halides - $0.00 6 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 997 of 1125 C&I Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting C-21 End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Lighting Exterior Lighting HID High Pressure Sodium 0.15 -$0.13 9 2.09 -$0.11 Exterior Lighting HID Low Pressure Sodium 0.16 $0.55 9 0.57 $0.43 Water Heating Water Heater Baseline (EF=0.90) - $0.00 15 1.00 $0.00 Water Heating Water Heater High Efficiency (EF=0.95) 0.11 $0.02 15 1.03 $0.02 Water Heating Water Heater EF 2.0 1.05 -$0.48 15 2.80 -$0.04 Water Heating Water Heater EF 2.3 1.18 -$0.47 15 3.20 -$0.03 Water Heating Water Heater EF 2.4 1.22 -$0.47 15 3.33 -$0.03 Water Heating Water Heater Geothermal Heat Pump 1.39 $3.53 15 0.39 $0.22 Water Heating Water Heater Solar 1.53 $3.03 15 0.45 $0.17 Food Preparation Fryer Standard - $0.00 12 1.00 $0.00 Food Preparation Fryer Efficient 0.03 $0.04 12 0.88 $0.12 Food Preparation Oven Standard - $0.00 12 1.00 $0.00 Food Preparation Oven Efficient 0.39 $0.36 12 0.93 $0.10 Food Preparation Dishwasher Standard - $0.00 12 1.00 $0.00 Food Preparation Dishwasher Efficient 0.02 $0.05 12 0.87 $0.28 Food Preparation Hot Food Container Standard - $0.00 12 1.00 $0.00 Food Preparation Hot Food Container Efficient 0.32 $0.16 12 0.98 $0.05 Food Preparation Food Prep Standard - $0.00 12 1.00 $0.00 Food Preparation Food Prep Efficient 0.00 $0.03 12 0.87 $1.73 Refrigeration Walk in Refrigeration Standard - $0.00 18 1.00 $0.00 Refrigeration Walk in Refrigeration Efficient - $0.09 18 0.90 $0.00 Refrigeration Glass Door Display Standard - $0.00 18 1.00 $0.00 Refrigeration Glass Door Display Efficient 0.16 $0.00 18 1.37 $0.00 Refrigeration Reach-in Refrigerator Standard - $0.00 18 1.00 $0.00 Refrigeration Reach-in Refrigerator Efficient 0.15 $0.02 18 1.16 $0.01 Refrigeration Open Display Case Standard - $0.00 18 1.00 $0.00 Refrigeration Open Display Case Efficient 0.00 $0.00 18 0.92 $0.35 Refrigeration Vending Machine Base - $0.00 10 - $0.00 Refrigeration Vending Machine Base (2012) 0.09 $0.00 10 1.00 $0.00 Refrigeration Vending Machine High Efficiency 0.11 $0.00 10 - $0.00 Refrigeration Vending Machine High Efficiency (2012) 0.17 $0.00 10 1.19 $0.00 Refrigeration Icemaker Standard - $0.00 12 1.00 $0.00 Refrigeration Icemaker Efficient 0.05 $0.00 12 1.11 $0.01 Office Equipment Desktop Computer Baseline - $0.00 4 1.00 $0.00 Office Equipment Desktop Computer Energy Star 0.21 $0.00 4 1.01 $0.00 Office Equipment Desktop Computer Climate Savers 0.30 $0.36 4 0.85 $0.32 Office Equipment Laptop Computer Baseline - $0.00 4 1.00 $0.00 Office Equipment Laptop Computer Energy Star 0.02 $0.00 4 1.00 $0.01 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 998 of 1125 C&I Energy Efficiency Equipment and Measure Data C-22 www.enernoc.com End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Office Equipment Laptop Computer Climate Savers 0.04 $0.12 4 0.84 $0.87 Office Equipment Server Standard - $0.00 3 1.00 $0.00 Office Equipment Server Energy Star 0.11 $0.01 3 0.99 $0.04 Office Equipment Monitor Standard - $0.00 4 1.00 $0.00 Office Equipment Monitor Energy Star 0.06 $0.00 4 1.03 $0.01 Office Equipment Printer/copier/fax Standard - $0.00 6 1.00 $0.00 Office Equipment Printer/copier/fax Energy Star 0.08 $0.04 6 0.95 $0.09 Office Equipment POS Terminal Standard - $0.00 4 1.00 $0.00 Office Equipment POS Terminal Energy Star 0.02 $0.00 4 1.00 $0.03 Miscellaneous Non-HVAC Motor Standard - $0.00 15 - $0.00 Miscellaneous Non-HVAC Motor Standard (2015) 0.01 $0.06 15 - $0.71 Miscellaneous Non-HVAC Motor High Efficiency 0.01 $0.00 15 1.00 $0.00 Miscellaneous Non-HVAC Motor High Efficiency (2015) 0.06 $0.06 15 0.98 $0.08 Miscellaneous Non-HVAC Motor Premium - $0.00 0 - $0.00 Miscellaneous Non-HVAC Motor Premium (2015) - $0.00 0 - $0.00 Miscellaneous Other Miscellaneous Miscellaneous - $0.00 5 - $0.00 Miscellaneous Other Miscellaneous Miscellaneous (2013) 0.00 $0.00 5 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 999 of 1125 C&I Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting C-23 Table C-7 Energy Efficiency Equipment Data, Electric—Large Commercial, Existing Vintage, Washington End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Cooling Central Chiller 1.5 kw/ton, COP 2.3 - $0.00 20 - $0.00 Cooling Central Chiller 1.3 kw/ton, COP 2.7 0.29 $0.26 20 1.10 $0.06 Cooling Central Chiller 1.26 kw/ton, COP 2.8 0.34 $0.33 20 0.97 $0.07 Cooling Central Chiller 1.0 kw/ton, COP 3.5 0.71 $0.41 20 1.02 $0.04 Cooling Central Chiller 0.97 kw/ton, COP 3.6 0.76 $0.49 20 0.99 $0.05 Cooling Central Chiller Variable Refrigerant Flow 0.99 $7.63 20 0.21 $0.54 Cooling RTU EER 9.2 - $0.00 16 - $0.00 Cooling RTU EER 10.1 0.22 $0.13 16 - $0.05 Cooling RTU EER 11.2 0.44 $0.25 16 1.00 $0.05 Cooling RTU EER 12.0 0.57 $0.41 16 0.93 $0.06 Cooling RTU Ductless VRF 0.70 $3.67 16 0.32 $0.43 Cooling Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00 Cooling Heat Pump EER 10.3, COP 3.2 0.29 $0.18 15 - $0.06 Cooling Heat Pump EER 11.0, COP 3.3 0.45 $0.55 15 1.00 $0.10 Cooling Heat Pump EER 11.7, COP 3.4 0.61 $0.73 15 0.98 $0.10 Cooling Heat Pump EER 12, COP 3.4 0.66 $0.91 15 0.95 $0.12 Cooling Heat Pump Ductless Mini-Split System 0.74 $5.35 20 0.56 $0.51 Space Heating Electric Resistance Standard - $0.00 25 1.00 $0.00 Space Heating Furnace Standard - $0.00 18 1.00 $0.00 Ventilation Ventilation Constant Volume - $0.00 15 1.00 $0.00 Ventilation Ventilation Variable Air Volume 1.39 $1.22 15 0.91 $0.08 Interior Lighting Interior Screw-in Incandescents - $0.00 1 - $0.00 Interior Lighting Interior Screw-in Infrared Halogen 0.49 $0.08 1 1.00 $0.16 Interior Lighting Interior Screw-in CFL 2.03 $0.03 4 5.52 $0.00 Interior Lighting Interior Screw-in LED 2.24 $1.11 12 - $0.05 Interior Lighting High Bay Fixtures Metal Halides - $0.00 6 1.00 $0.00 Interior Lighting High Bay Fixtures High Pressure Sodium 0.24 -$0.08 9 2.10 -$0.04 Interior Lighting High Bay Fixtures T8 0.24 -$0.16 6 4.40 -$0.12 Interior Lighting High Bay Fixtures T5 0.31 -$0.16 6 5.23 -$0.10 Interior Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00 Interior Lighting Linear Fluorescent T8 0.34 -$0.03 6 1.11 -$0.02 Interior Lighting Linear Fluorescent Super T8 1.03 $0.25 6 0.94 $0.04 Interior Lighting Linear Fluorescent T5 1.07 $0.42 6 0.81 $0.07 Interior Lighting Linear Fluorescent LED 1.12 $3.67 15 - $0.28 Exterior Lighting Exterior Screw-in Incandescent - $0.00 1 - $0.00 Exterior Lighting Exterior Screw-in Infrared Halogen 0.05 $0.01 1 1.00 $0.26 Exterior Lighting Exterior Screw-in CFL 0.22 $0.01 4 6.10 $0.01 Exterior Lighting Exterior Screw-in Metal Halides 0.22 $0.02 4 3.35 $0.02 Exterior Lighting Exterior Screw-in LED 0.24 $0.19 12 - $0.08 Exterior HID Metal Halides - $0.00 6 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1000 of 1125 C&I Energy Efficiency Equipment and Measure Data C-24 www.enernoc.com End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Lighting Exterior Lighting HID High Pressure Sodium 0.15 -$0.11 9 2.03 -$0.09 Exterior Lighting HID Low Pressure Sodium 0.16 $0.45 9 0.58 $0.36 Water Heating Water Heater Baseline (EF=0.90) - $0.00 15 1.00 $0.00 Water Heating Water Heater High Efficiency (EF=0.95) 0.13 $0.02 15 1.03 $0.01 Water Heating Water Heater EF 2.0 1.26 -$0.48 15 2.78 -$0.03 Water Heating Water Heater EF 2.3 1.42 -$0.47 15 3.18 -$0.03 Water Heating Water Heater EF 2.4 1.46 -$0.47 15 3.30 -$0.03 Water Heating Water Heater Geothermal Heat Pump 1.67 $3.53 15 0.40 $0.18 Water Heating Water Heater Solar 1.84 $3.03 15 0.46 $0.14 Food Preparation Fryer Standard - $0.00 12 1.00 $0.00 Food Preparation Fryer Efficient 0.07 $0.02 12 1.07 $0.03 Food Preparation Oven Standard - $0.00 12 1.00 $0.00 Food Preparation Oven Efficient 0.74 $0.46 12 0.95 $0.06 Food Preparation Dishwasher Standard - $0.00 12 1.00 $0.00 Food Preparation Dishwasher Efficient 0.06 $0.10 12 0.89 $0.16 Food Preparation Hot Food Container Standard - $0.00 12 1.00 $0.00 Food Preparation Hot Food Container Efficient 0.21 $0.30 12 0.70 $0.15 Food Preparation Food Prep Standard - $0.00 12 1.00 $0.00 Food Preparation Food Prep Efficient 0.01 $0.03 12 0.88 $0.46 Refrigeration Walk in Refrigeration Standard - $0.00 18 1.00 $0.00 Refrigeration Walk in Refrigeration Efficient 0.11 $1.26 18 0.88 $0.87 Refrigeration Glass Door Display Standard - $0.00 18 1.00 $0.00 Refrigeration Glass Door Display Efficient 0.13 $0.01 18 1.25 $0.00 Refrigeration Reach-in Refrigerator Standard - $0.00 18 1.00 $0.00 Refrigeration Reach-in Refrigerator Efficient 0.16 $0.08 18 1.01 $0.04 Refrigeration Open Display Case Standard - $0.00 18 1.00 $0.00 Refrigeration Open Display Case Efficient 0.00 $0.04 18 0.88 $0.55 Refrigeration Vending Machine Base - $0.00 10 - $0.00 Refrigeration Vending Machine Base (2012) 0.11 $0.00 10 1.00 $0.00 Refrigeration Vending Machine High Efficiency 0.13 $0.00 10 - $0.00 Refrigeration Vending Machine High Efficiency (2012) 0.20 $0.00 10 1.09 $0.00 Refrigeration Icemaker Standard - $0.00 12 1.00 $0.00 Refrigeration Icemaker Efficient 0.10 $0.02 12 1.06 $0.02 Office Equipment Desktop Computer Baseline - $0.00 4 1.00 $0.00 Office Equipment Desktop Computer Energy Star 0.39 $0.00 4 1.02 $0.00 Office Equipment Desktop Computer Climate Savers 0.55 $0.32 4 0.87 $0.15 Office Equipment Laptop Computer Baseline - $0.00 4 1.00 $0.00 Office Equipment Laptop Computer Energy Star 0.02 $0.00 4 1.01 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1001 of 1125 C&I Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting C-25 End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Office Equipment Laptop Computer Climate Savers 0.04 $0.06 4 0.85 $0.42 Office Equipment Server Standard - $0.00 3 1.00 $0.00 Office Equipment Server Energy Star 0.13 $0.01 3 1.02 $0.02 Office Equipment Monitor Standard - $0.00 4 1.00 $0.00 Office Equipment Monitor Energy Star 0.05 $0.01 4 1.00 $0.03 Office Equipment Printer/copier/fax Standard - $0.00 6 1.00 $0.00 Office Equipment Printer/copier/fax Energy Star 0.07 $0.02 6 0.98 $0.04 Office Equipment POS Terminal Standard - $0.00 4 1.00 $0.00 Office Equipment POS Terminal Energy Star 0.01 $0.00 4 1.00 $0.03 Miscellaneous Non-HVAC Motor Standard - $0.00 15 - $0.00 Miscellaneous Non-HVAC Motor Standard (2015) 0.01 $0.06 15 - $0.63 Miscellaneous Non-HVAC Motor High Efficiency 0.01 $0.00 15 1.00 $0.00 Miscellaneous Non-HVAC Motor High Efficiency (2015) 0.07 $0.06 15 0.98 $0.07 Miscellaneous Non-HVAC Motor Premium - $0.00 0 - $0.00 Miscellaneous Non-HVAC Motor Premium (2015) - $0.00 0 - $0.00 Miscellaneous Other Miscellaneous Miscellaneous - $0.00 5 - $0.00 Miscellaneous Other Miscellaneous Miscellaneous (2013) 0.00 $0.00 5 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1002 of 1125 C&I Energy Efficiency Equipment and Measure Data C-26 www.enernoc.com Table C-8 Energy Efficiency Equipment Data, Electric— Large Commercial, New Vintage, Washington End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Cooling Central Chiller 1.5 kw/ton, COP 2.3 - $0.00 20 - $0.00 Cooling Central Chiller 1.3 kw/ton, COP 2.7 0.26 $0.24 20 1.10 $0.07 Cooling Central Chiller 1.26 kw/ton, COP 2.8 0.31 $0.31 20 0.97 $0.07 Cooling Central Chiller 1.0 kw/ton, COP 3.5 0.64 $0.38 20 1.02 $0.04 Cooling Central Chiller 0.97 kw/ton, COP 3.6 0.68 $0.45 20 0.99 $0.05 Cooling Central Chiller Variable Refrigerant Flow 0.89 $7.06 20 0.21 $0.56 Cooling RTU EER 9.2 - $0.00 16 - $0.00 Cooling RTU EER 10.1 0.21 $0.13 16 - $0.05 Cooling RTU EER 11.2 0.41 $0.25 16 1.00 $0.05 Cooling RTU EER 12.0 0.54 $0.41 16 0.93 $0.06 Cooling RTU Ductless VRF 0.66 $3.67 16 0.32 $0.46 Cooling Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00 Cooling Heat Pump EER 10.3, COP 3.2 0.31 $0.18 15 - $0.05 Cooling Heat Pump EER 11.0, COP 3.3 0.50 $0.55 15 1.00 $0.10 Cooling Heat Pump EER 11.7, COP 3.4 0.66 $0.73 15 0.98 $0.10 Cooling Heat Pump EER 12, COP 3.4 0.73 $0.91 15 0.96 $0.11 Cooling Heat Pump Ductless Mini-Split System 0.81 $5.35 20 0.57 $0.47 Space Heating Electric Resistance Standard - $0.00 25 1.00 $0.00 Space Heating Furnace Standard - $0.00 18 1.00 $0.00 Ventilation Ventilation Constant Volume - $0.00 15 1.00 $0.00 Ventilation Ventilation Variable Air Volume 1.79 $1.22 15 0.99 $0.06 Interior Lighting Interior Screw-in Incandescents - $0.00 1 - $0.00 Interior Lighting Interior Screw-in Infrared Halogen 0.61 $0.08 1 1.00 $0.13 Interior Lighting Interior Screw-in CFL 2.52 $0.03 4 5.27 $0.00 Interior Lighting Interior Screw-in LED 2.78 $1.11 12 - $0.04 Interior Lighting High Bay Fixtures Metal Halides - $0.00 6 1.00 $0.00 Interior Lighting High Bay Fixtures High Pressure Sodium 0.25 -$0.08 9 2.09 -$0.04 Interior Lighting High Bay Fixtures T8 0.25 -$0.16 6 4.36 -$0.12 Interior Lighting High Bay Fixtures T5 0.31 -$0.16 6 5.19 -$0.09 Interior Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00 Interior Lighting Linear Fluorescent T8 0.31 -$0.03 6 1.11 -$0.02 Interior Lighting Linear Fluorescent Super T8 0.93 $0.25 6 0.92 $0.05 Interior Lighting Linear Fluorescent T5 0.97 $0.42 6 0.78 $0.08 Interior Lighting Linear Fluorescent LED 1.02 $3.67 15 - $0.31 Exterior Lighting Exterior Screw-in Incandescent - $0.00 1 - $0.00 Exterior Lighting Exterior Screw-in Infrared Halogen 0.05 $0.01 1 1.00 $0.26 Exterior Lighting Exterior Screw-in CFL 0.22 $0.01 4 6.10 $0.01 Exterior Lighting Exterior Screw-in Metal Halides 0.22 $0.02 4 3.35 $0.02 Exterior Lighting Exterior Screw-in LED 0.24 $0.19 12 - $0.08 Exterior HID Metal Halides - $0.00 6 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1003 of 1125 C&I Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting C-27 End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Lighting Exterior Lighting HID High Pressure Sodium 0.15 -$0.11 9 2.03 -$0.09 Exterior Lighting HID Low Pressure Sodium 0.16 $0.45 9 0.58 $0.36 Water Heating Water Heater Baseline (EF=0.90) - $0.00 15 1.00 $0.00 Water Heating Water Heater High Efficiency (EF=0.95) 0.12 $0.02 15 1.03 $0.02 Water Heating Water Heater EF 2.0 1.21 -$0.48 15 2.81 -$0.03 Water Heating Water Heater EF 2.3 1.35 -$0.47 15 3.21 -$0.03 Water Heating Water Heater EF 2.4 1.39 -$0.47 15 3.34 -$0.03 Water Heating Water Heater Geothermal Heat Pump 1.60 $3.53 15 0.39 $0.19 Water Heating Water Heater Solar 1.76 $3.03 15 0.45 $0.15 Food Preparation Fryer Standard - $0.00 12 1.00 $0.00 Food Preparation Fryer Efficient 0.07 $0.02 12 1.07 $0.03 Food Preparation Oven Standard - $0.00 12 1.00 $0.00 Food Preparation Oven Efficient 0.74 $0.46 12 0.95 $0.06 Food Preparation Dishwasher Standard - $0.00 12 1.00 $0.00 Food Preparation Dishwasher Efficient 0.06 $0.10 12 0.89 $0.16 Food Preparation Hot Food Container Standard - $0.00 12 1.00 $0.00 Food Preparation Hot Food Container Efficient 0.21 $0.30 12 0.70 $0.15 Food Preparation Food Prep Standard - $0.00 12 1.00 $0.00 Food Preparation Food Prep Efficient 0.01 $0.03 12 0.88 $0.46 Refrigeration Walk in Refrigeration Standard - $0.00 18 1.00 $0.00 Refrigeration Walk in Refrigeration Efficient 0.11 $1.26 18 0.88 $0.88 Refrigeration Glass Door Display Standard - $0.00 18 1.00 $0.00 Refrigeration Glass Door Display Efficient 0.13 $0.01 18 1.25 $0.00 Refrigeration Reach-in Refrigerator Standard - $0.00 18 1.00 $0.00 Refrigeration Reach-in Refrigerator Efficient 0.23 $0.08 18 1.05 $0.03 Refrigeration Open Display Case Standard - $0.00 18 1.00 $0.00 Refrigeration Open Display Case Efficient 0.00 $0.04 18 0.88 $0.55 Refrigeration Vending Machine Base - $0.00 10 - $0.00 Refrigeration Vending Machine Base (2012) 0.11 $0.00 10 1.00 $0.00 Refrigeration Vending Machine High Efficiency 0.13 $0.00 10 - $0.00 Refrigeration Vending Machine High Efficiency (2012) 0.20 $0.00 10 1.09 $0.00 Refrigeration Icemaker Standard - $0.00 12 1.00 $0.00 Refrigeration Icemaker Efficient 0.09 $0.02 12 1.06 $0.02 Office Equipment Desktop Computer Baseline - $0.00 4 1.00 $0.00 Office Equipment Desktop Computer Energy Star 0.39 $0.00 4 1.02 $0.00 Office Equipment Desktop Computer Climate Savers 0.55 $0.32 4 0.87 $0.15 Office Equipment Laptop Computer Baseline - $0.00 4 1.00 $0.00 Office Equipment Laptop Computer Energy Star 0.02 $0.00 4 1.01 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1004 of 1125 C&I Energy Efficiency Equipment and Measure Data C-28 www.enernoc.com End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Office Equipment Laptop Computer Climate Savers 0.04 $0.06 4 0.85 $0.42 Office Equipment Server Standard - $0.00 3 1.00 $0.00 Office Equipment Server Energy Star 0.13 $0.01 3 1.02 $0.02 Office Equipment Monitor Standard - $0.00 4 1.00 $0.00 Office Equipment Monitor Energy Star 0.05 $0.01 4 1.00 $0.03 Office Equipment Printer/copier/fax Standard - $0.00 6 1.00 $0.00 Office Equipment Printer/copier/fax Energy Star 0.07 $0.02 6 0.98 $0.04 Office Equipment POS Terminal Standard - $0.00 4 1.00 $0.00 Office Equipment POS Terminal Energy Star 0.01 $0.00 4 1.00 $0.03 Miscellaneous Non-HVAC Motor Standard - $0.00 15 - $0.00 Miscellaneous Non-HVAC Motor Standard (2015) 0.01 $0.06 15 - $0.63 Miscellaneous Non-HVAC Motor High Efficiency 0.01 $0.00 15 1.00 $0.00 Miscellaneous Non-HVAC Motor High Efficiency (2015) 0.07 $0.06 15 0.98 $0.07 Miscellaneous Non-HVAC Motor Premium - $0.00 0 - $0.00 Miscellaneous Non-HVAC Motor Premium (2015) - $0.00 0 - $0.00 Miscellaneous Other Miscellaneous Miscellaneous - $0.00 5 - $0.00 Miscellaneous Other Miscellaneous Miscellaneous (2013) 0.00 $0.00 5 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1005 of 1125 C&I Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting C-29 Table C-9 Energy Efficiency Equipment Data, Electric—Large Commercial, Existing Vintage, Idaho End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Cooling Central Chiller 1.5 kw/ton, COP 2.3 - $0.00 20 - $0.00 Cooling Central Chiller 1.3 kw/ton, COP 2.7 0.29 $0.26 20 1.10 $0.06 Cooling Central Chiller 1.26 kw/ton, COP 2.8 0.34 $0.33 20 0.97 $0.07 Cooling Central Chiller 1.0 kw/ton, COP 3.5 0.71 $0.41 20 1.02 $0.04 Cooling Central Chiller 0.97 kw/ton, COP 3.6 0.76 $0.49 20 0.99 $0.05 Cooling Central Chiller Variable Refrigerant Flow 0.99 $7.63 20 0.21 $0.54 Cooling RTU EER 9.2 - $0.00 16 - $0.00 Cooling RTU EER 10.1 0.22 $0.13 16 - $0.05 Cooling RTU EER 11.2 0.44 $0.25 16 1.00 $0.05 Cooling RTU EER 12.0 0.57 $0.41 16 0.93 $0.06 Cooling RTU Ductless VRF 0.70 $3.67 16 0.32 $0.43 Cooling Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00 Cooling Heat Pump EER 10.3, COP 3.2 0.29 $0.18 15 - $0.06 Cooling Heat Pump EER 11.0, COP 3.3 0.45 $0.55 15 1.00 $0.10 Cooling Heat Pump EER 11.7, COP 3.4 0.61 $0.73 15 0.98 $0.10 Cooling Heat Pump EER 12, COP 3.4 0.66 $0.91 15 0.95 $0.12 Cooling Heat Pump Ductless Mini-Split System 0.74 $5.35 20 0.56 $0.51 Space Heating Electric Resistance Standard - $0.00 25 1.00 $0.00 Space Heating Furnace Standard - $0.00 18 1.00 $0.00 Ventilation Ventilation Constant Volume - $0.00 15 1.00 $0.00 Ventilation Ventilation Variable Air Volume 1.39 $1.22 15 0.92 $0.08 Interior Lighting Interior Screw-in Incandescents - $0.00 1 - $0.00 Interior Lighting Interior Screw-in Infrared Halogen 0.49 $0.08 1 1.00 $0.16 Interior Lighting Interior Screw-in CFL 2.03 $0.03 4 5.53 $0.00 Interior Lighting Interior Screw-in LED 2.24 $1.11 12 - $0.05 Interior Lighting High Bay Fixtures Metal Halides - $0.00 6 1.00 $0.00 Interior Lighting High Bay Fixtures High Pressure Sodium 0.24 -$0.08 9 2.09 -$0.04 Interior Lighting High Bay Fixtures T8 0.24 -$0.16 6 4.37 -$0.12 Interior Lighting High Bay Fixtures T5 0.31 -$0.16 6 5.20 -$0.10 Interior Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00 Interior Lighting Linear Fluorescent T8 0.34 -$0.03 6 1.11 -$0.02 Interior Lighting Linear Fluorescent Super T8 1.03 $0.25 6 0.95 $0.04 Interior Lighting Linear Fluorescent T5 1.07 $0.42 6 0.81 $0.07 Interior Lighting Linear Fluorescent LED 1.12 $3.67 15 - $0.28 Exterior Lighting Exterior Screw-in Incandescent - $0.00 1 - $0.00 Exterior Lighting Exterior Screw-in Infrared Halogen 0.05 $0.01 1 1.00 $0.26 Exterior Lighting Exterior Screw-in CFL 0.22 $0.01 4 6.10 $0.01 Exterior Lighting Exterior Screw-in Metal Halides 0.22 $0.02 4 3.35 $0.02 Exterior Lighting Exterior Screw-in LED 0.24 $0.19 12 - $0.08 Exterior HID Metal Halides - $0.00 6 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1006 of 1125 C&I Energy Efficiency Equipment and Measure Data C-30 www.enernoc.com End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Lighting Exterior Lighting HID High Pressure Sodium 0.15 -$0.11 9 2.02 -$0.09 Exterior Lighting HID Low Pressure Sodium 0.16 $0.45 9 0.58 $0.36 Water Heating Water Heater Baseline (EF=0.90) - $0.00 15 1.00 $0.00 Water Heating Water Heater High Efficiency (EF=0.95) 0.13 $0.02 15 1.03 $0.01 Water Heating Water Heater EF 2.0 1.26 -$0.48 15 2.76 -$0.03 Water Heating Water Heater EF 2.3 1.42 -$0.47 15 3.16 -$0.03 Water Heating Water Heater EF 2.4 1.46 -$0.47 15 3.29 -$0.03 Water Heating Water Heater Geothermal Heat Pump 1.67 $3.53 15 0.41 $0.18 Water Heating Water Heater Solar 1.84 $3.03 15 0.47 $0.14 Food Preparation Fryer Standard - $0.00 12 1.00 $0.00 Food Preparation Fryer Efficient 0.07 $0.02 12 1.07 $0.03 Food Preparation Oven Standard - $0.00 12 1.00 $0.00 Food Preparation Oven Efficient 0.74 $0.46 12 0.96 $0.06 Food Preparation Dishwasher Standard - $0.00 12 1.00 $0.00 Food Preparation Dishwasher Efficient 0.06 $0.10 12 0.89 $0.16 Food Preparation Hot Food Container Standard - $0.00 12 1.00 $0.00 Food Preparation Hot Food Container Efficient 0.21 $0.30 12 0.70 $0.15 Food Preparation Food Prep Standard - $0.00 12 1.00 $0.00 Food Preparation Food Prep Efficient 0.01 $0.03 12 0.88 $0.46 Refrigeration Walk in Refrigeration Standard - $0.00 18 1.00 $0.00 Refrigeration Walk in Refrigeration Efficient 0.11 $1.26 18 0.88 $0.87 Refrigeration Glass Door Display Standard - $0.00 18 1.00 $0.00 Refrigeration Glass Door Display Efficient 0.13 $0.01 18 1.26 $0.00 Refrigeration Reach-in Refrigerator Standard - $0.00 18 1.00 $0.00 Refrigeration Reach-in Refrigerator Efficient 0.16 $0.08 18 1.02 $0.04 Refrigeration Open Display Case Standard - $0.00 18 1.00 $0.00 Refrigeration Open Display Case Efficient 0.00 $0.04 18 0.88 $0.55 Refrigeration Vending Machine Base - $0.00 10 - $0.00 Refrigeration Vending Machine Base (2012) 0.11 $0.00 10 1.00 $0.00 Refrigeration Vending Machine High Efficiency 0.13 $0.00 10 - $0.00 Refrigeration Vending Machine High Efficiency (2012) 0.20 $0.00 10 1.09 $0.00 Refrigeration Icemaker Standard - $0.00 12 1.00 $0.00 Refrigeration Icemaker Efficient 0.10 $0.02 12 1.06 $0.02 Office Equipment Desktop Computer Baseline - $0.00 4 1.00 $0.00 Office Equipment Desktop Computer Energy Star 0.39 $0.00 4 1.02 $0.00 Office Equipment Desktop Computer Climate Savers 0.55 $0.32 4 0.87 $0.15 Office Equipment Laptop Computer Baseline - $0.00 4 1.00 $0.00 Office Equipment Laptop Computer Energy Star 0.02 $0.00 4 1.01 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1007 of 1125 C&I Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting C-31 End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Office Equipment Laptop Computer Climate Savers 0.04 $0.06 4 0.85 $0.42 Office Equipment Server Standard - $0.00 3 1.00 $0.00 Office Equipment Server Energy Star 0.13 $0.01 3 1.01 $0.02 Office Equipment Monitor Standard - $0.00 4 1.00 $0.00 Office Equipment Monitor Energy Star 0.05 $0.01 4 1.00 $0.03 Office Equipment Printer/copier/fax Standard - $0.00 6 1.00 $0.00 Office Equipment Printer/copier/fax Energy Star 0.07 $0.02 6 0.98 $0.04 Office Equipment POS Terminal Standard - $0.00 4 1.00 $0.00 Office Equipment POS Terminal Energy Star 0.01 $0.00 4 1.00 $0.03 Miscellaneous Non-HVAC Motor Standard - $0.00 15 - $0.00 Miscellaneous Non-HVAC Motor Standard (2015) 0.01 $0.06 15 - $0.63 Miscellaneous Non-HVAC Motor High Efficiency 0.01 $0.00 15 1.00 $0.00 Miscellaneous Non-HVAC Motor High Efficiency (2015) 0.07 $0.06 15 0.98 $0.07 Miscellaneous Non-HVAC Motor Premium - $0.00 0 - $0.00 Miscellaneous Non-HVAC Motor Premium (2015) - $0.00 0 - $0.00 Miscellaneous Other Miscellaneous Miscellaneous - $0.00 5 - $0.00 Miscellaneous Other Miscellaneous Miscellaneous (2013) 0.00 $0.00 5 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1008 of 1125 C&I Energy Efficiency Equipment and Measure Data C-32 www.enernoc.com Table C-10 Energy Efficiency Equipment Data, Electric— Large Commercial, New Vintage, Idaho End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Cooling Central Chiller 1.5 kw/ton, COP 2.3 - $0.00 20 - $0.00 Cooling Central Chiller 1.3 kw/ton, COP 2.7 0.26 $0.24 20 1.10 $0.07 Cooling Central Chiller 1.26 kw/ton, COP 2.8 0.31 $0.31 20 0.97 $0.07 Cooling Central Chiller 1.0 kw/ton, COP 3.5 0.64 $0.38 20 1.02 $0.04 Cooling Central Chiller 0.97 kw/ton, COP 3.6 0.68 $0.45 20 0.99 $0.05 Cooling Central Chiller Variable Refrigerant Flow 0.89 $7.06 20 0.21 $0.56 Cooling RTU EER 9.2 - $0.00 16 - $0.00 Cooling RTU EER 10.1 0.21 $0.13 16 - $0.05 Cooling RTU EER 11.2 0.41 $0.25 16 1.00 $0.05 Cooling RTU EER 12.0 0.54 $0.41 16 0.93 $0.06 Cooling RTU Ductless VRF 0.66 $3.67 16 0.32 $0.46 Cooling Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00 Cooling Heat Pump EER 10.3, COP 3.2 0.31 $0.18 15 - $0.05 Cooling Heat Pump EER 11.0, COP 3.3 0.50 $0.55 15 1.00 $0.10 Cooling Heat Pump EER 11.7, COP 3.4 0.66 $0.73 15 0.98 $0.10 Cooling Heat Pump EER 12, COP 3.4 0.73 $0.91 15 0.95 $0.11 Cooling Heat Pump Ductless Mini-Split System 0.81 $5.35 20 0.57 $0.47 Space Heating Electric Resistance Standard - $0.00 25 1.00 $0.00 Space Heating Furnace Standard - $0.00 18 1.00 $0.00 Ventilation Ventilation Constant Volume - $0.00 15 1.00 $0.00 Ventilation Ventilation Variable Air Volume 1.79 $1.22 15 1.00 $0.06 Interior Lighting Interior Screw-in Incandescents - $0.00 1 - $0.00 Interior Lighting Interior Screw-in Infrared Halogen 0.61 $0.08 1 1.00 $0.13 Interior Lighting Interior Screw-in CFL 2.52 $0.03 4 5.28 $0.00 Interior Lighting Interior Screw-in LED 2.78 $1.11 12 - $0.04 Interior Lighting High Bay Fixtures Metal Halides - $0.00 6 1.00 $0.00 Interior Lighting High Bay Fixtures High Pressure Sodium 0.25 -$0.08 9 2.08 -$0.04 Interior Lighting High Bay Fixtures T8 0.25 -$0.16 6 4.34 -$0.12 Interior Lighting High Bay Fixtures T5 0.31 -$0.16 6 5.16 -$0.09 Interior Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00 Interior Lighting Linear Fluorescent T8 0.31 -$0.03 6 1.11 -$0.02 Interior Lighting Linear Fluorescent Super T8 0.93 $0.25 6 0.92 $0.05 Interior Lighting Linear Fluorescent T5 0.97 $0.42 6 0.79 $0.08 Interior Lighting Linear Fluorescent LED 1.02 $3.67 15 - $0.31 Exterior Lighting Exterior Screw-in Incandescent - $0.00 1 - $0.00 Exterior Lighting Exterior Screw-in Infrared Halogen 0.05 $0.01 1 1.00 $0.26 Exterior Lighting Exterior Screw-in CFL 0.22 $0.01 4 6.10 $0.01 Exterior Lighting Exterior Screw-in Metal Halides 0.22 $0.02 4 3.35 $0.02 Exterior Lighting Exterior Screw-in LED 0.24 $0.19 12 - $0.08 Exterior HID Metal Halides - $0.00 6 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1009 of 1125 C&I Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting C-33 End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Lighting Exterior Lighting HID High Pressure Sodium 0.15 -$0.11 9 2.02 -$0.09 Exterior Lighting HID Low Pressure Sodium 0.16 $0.45 9 0.58 $0.36 Water Heating Water Heater Baseline (EF=0.90) - $0.00 15 1.00 $0.00 Water Heating Water Heater High Efficiency (EF=0.95) 0.12 $0.02 15 1.03 $0.02 Water Heating Water Heater EF 2.0 1.21 -$0.48 15 2.79 -$0.03 Water Heating Water Heater EF 2.3 1.35 -$0.47 15 3.19 -$0.03 Water Heating Water Heater EF 2.4 1.39 -$0.47 15 3.32 -$0.03 Water Heating Water Heater Geothermal Heat Pump 1.60 $3.53 15 0.40 $0.19 Water Heating Water Heater Solar 1.76 $3.03 15 0.46 $0.15 Food Preparation Fryer Standard - $0.00 12 1.00 $0.00 Food Preparation Fryer Efficient 0.07 $0.02 12 1.07 $0.03 Food Preparation Oven Standard - $0.00 12 1.00 $0.00 Food Preparation Oven Efficient 0.74 $0.46 12 0.96 $0.06 Food Preparation Dishwasher Standard - $0.00 12 1.00 $0.00 Food Preparation Dishwasher Efficient 0.06 $0.10 12 0.89 $0.16 Food Preparation Hot Food Container Standard - $0.00 12 1.00 $0.00 Food Preparation Hot Food Container Efficient 0.21 $0.30 12 0.70 $0.15 Food Preparation Food Prep Standard - $0.00 12 1.00 $0.00 Food Preparation Food Prep Efficient 0.01 $0.03 12 0.88 $0.46 Refrigeration Walk in Refrigeration Standard - $0.00 18 1.00 $0.00 Refrigeration Walk in Refrigeration Efficient 0.11 $1.26 18 0.88 $0.88 Refrigeration Glass Door Display Standard - $0.00 18 1.00 $0.00 Refrigeration Glass Door Display Efficient 0.13 $0.01 18 1.26 $0.00 Refrigeration Reach-in Refrigerator Standard - $0.00 18 1.00 $0.00 Refrigeration Reach-in Refrigerator Efficient 0.23 $0.08 18 1.05 $0.03 Refrigeration Open Display Case Standard - $0.00 18 1.00 $0.00 Refrigeration Open Display Case Efficient 0.00 $0.04 18 0.88 $0.55 Refrigeration Vending Machine Base - $0.00 10 - $0.00 Refrigeration Vending Machine Base (2012) 0.11 $0.00 10 1.00 $0.00 Refrigeration Vending Machine High Efficiency 0.13 $0.00 10 - $0.00 Refrigeration Vending Machine High Efficiency (2012) 0.20 $0.00 10 1.09 $0.00 Refrigeration Icemaker Standard - $0.00 12 1.00 $0.00 Refrigeration Icemaker Efficient 0.09 $0.02 12 1.06 $0.02 Office Equipment Desktop Computer Baseline - $0.00 4 1.00 $0.00 Office Equipment Desktop Computer Energy Star 0.39 $0.00 4 1.02 $0.00 Office Equipment Desktop Computer Climate Savers 0.55 $0.32 4 0.87 $0.15 Office Equipment Laptop Computer Baseline - $0.00 4 1.00 $0.00 Office Equipment Laptop Computer Energy Star 0.02 $0.00 4 1.01 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1010 of 1125 C&I Energy Efficiency Equipment and Measure Data C-34 www.enernoc.com End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Office Equipment Laptop Computer Climate Savers 0.04 $0.06 4 0.85 $0.42 Office Equipment Server Standard - $0.00 3 1.00 $0.00 Office Equipment Server Energy Star 0.13 $0.01 3 1.01 $0.02 Office Equipment Monitor Standard - $0.00 4 1.00 $0.00 Office Equipment Monitor Energy Star 0.05 $0.01 4 1.00 $0.03 Office Equipment Printer/copier/fax Standard - $0.00 6 1.00 $0.00 Office Equipment Printer/copier/fax Energy Star 0.07 $0.02 6 0.98 $0.04 Office Equipment POS Terminal Standard - $0.00 4 1.00 $0.00 Office Equipment POS Terminal Energy Star 0.01 $0.00 4 1.00 $0.03 Miscellaneous Non-HVAC Motor Standard - $0.00 15 - $0.00 Miscellaneous Non-HVAC Motor Standard (2015) 0.01 $0.06 15 - $0.63 Miscellaneous Non-HVAC Motor High Efficiency 0.01 $0.00 15 1.00 $0.00 Miscellaneous Non-HVAC Motor High Efficiency (2015) 0.07 $0.06 15 0.98 $0.07 Miscellaneous Non-HVAC Motor Premium - $0.00 0 - $0.00 Miscellaneous Non-HVAC Motor Premium (2015) - $0.00 0 - $0.00 Miscellaneous Other Miscellaneous Miscellaneous - $0.00 5 - $0.00 Miscellaneous Other Miscellaneous Miscellaneous (2013) 0.00 $0.00 5 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1011 of 1125 C&I Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting C-35 Table C-11 Energy Efficiency Equipment Data, Electric—Extra Large Commercial, Existing Vintage, Washington End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Cooling Central Chiller Variable Refrigerant Flow 1.08 $10.92 20 0.15 $0.71 Cooling RTU EER 9.2 - $0.00 16 - $0.00 Cooling RTU EER 10.1 0.20 $0.24 16 - $0.10 Cooling RTU EER 11.2 0.40 $0.45 16 1.00 $0.09 Cooling RTU EER 12.0 0.52 $0.75 16 0.89 $0.12 Cooling RTU Ductless VRF 0.63 $6.64 16 0.26 $0.87 Cooling Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00 Cooling Heat Pump EER 10.3, COP 3.2 0.20 $0.24 15 - $0.11 Cooling Heat Pump EER 11.0, COP 3.3 0.31 $0.73 15 1.00 $0.20 Cooling Heat Pump EER 11.7, COP 3.4 0.42 $0.97 15 0.97 $0.20 Cooling Heat Pump EER 12, COP 3.4 0.46 $1.21 15 0.94 $0.23 Cooling Heat Pump Ductless Mini-Split System 0.51 $7.10 20 0.54 $0.99 Space Heating Electric Resistance Standard - $0.00 25 1.00 $0.00 Space Heating Furnace Standard - $0.00 18 1.00 $0.00 Ventilation Ventilation Constant Volume - $0.00 15 1.00 $0.00 Ventilation Ventilation Variable Air Volume 2.10 $1.22 15 1.04 $0.05 Interior Lighting Interior Screw-in Incandescents - $0.00 1 - $0.00 Interior Lighting Interior Screw-in Infrared Halogen 0.79 $0.14 1 1.00 $0.18 Interior Lighting Interior Screw-in CFL 3.25 $0.06 4 5.60 $0.00 Interior Lighting Interior Screw-in LED 3.59 $1.90 12 - $0.05 Interior Lighting High Bay Fixtures Metal Halides - $0.00 6 1.00 $0.00 Interior Lighting High Bay Fixtures High Pressure Sodium 0.10 -$0.05 9 2.23 -$0.07 Interior Lighting High Bay Fixtures T8 0.10 -$0.11 6 5.65 -$0.19 Interior Lighting High Bay Fixtures T5 0.13 -$0.10 6 6.21 -$0.15 Interior Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00 Interior Lighting Linear Fluorescent T8 0.23 -$0.03 6 1.12 -$0.02 Interior Lighting Linear Fluorescent Super T8 0.69 $0.21 6 0.89 $0.06 Interior Lighting Linear Fluorescent T5 0.71 $0.35 6 0.75 $0.09 Interior Lighting Linear Fluorescent LED 0.75 $3.08 15 - $0.36 Exterior Lighting Exterior Screw-in Incandescent - $0.00 1 - $0.00 Exterior Lighting Exterior Screw-in Infrared Halogen 0.02 $0.00 1 1.00 $0.22 Exterior Lighting Exterior Screw-in CFL 0.07 $0.00 4 5.89 $0.01 Exterior Lighting Exterior Screw-in Metal Halides 0.07 $0.00 4 3.36 $0.02 Exterior Lighting Exterior Screw-in LED 0.07 $0.05 12 - $0.07 Exterior Lighting HID Metal Halides - $0.00 6 1.00 $0.00 Exterior Lighting HID High Pressure Sodium 0.19 -$0.16 9 2.08 -$0.10 Exterior Lighting HID Low Pressure Sodium 0.21 $0.64 9 0.57 $0.40 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1012 of 1125 C&I Energy Efficiency Equipment and Measure Data C-36 www.enernoc.com End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Water Heating Water Heater Baseline (EF=0.90) - $0.00 15 1.00 $0.00 Water Heating Water Heater High Efficiency (EF=0.95) 0.20 $0.02 15 1.04 $0.01 Water Heating Water Heater EF 2.0 1.95 -$0.48 15 2.49 -$0.02 Water Heating Water Heater EF 2.3 2.19 -$0.47 15 2.86 -$0.02 Water Heating Water Heater EF 2.4 2.26 -$0.47 15 2.98 -$0.02 Water Heating Water Heater Geothermal Heat Pump 2.59 $3.53 15 0.56 $0.12 Water Heating Water Heater Solar 2.84 $3.03 15 0.65 $0.09 Food Preparation Fryer Standard - $0.00 12 1.00 $0.00 Food Preparation Fryer Efficient 0.03 $0.00 12 1.13 $0.02 Food Preparation Oven Standard - $0.00 12 1.00 $0.00 Food Preparation Oven Efficient 0.84 $0.38 12 1.00 $0.05 Food Preparation Dishwasher Standard - $0.00 12 1.00 $0.00 Food Preparation Dishwasher Efficient 0.03 $0.04 12 0.89 $0.18 Food Preparation Hot Food Container Standard - $0.00 12 1.00 $0.00 Food Preparation Hot Food Container Efficient 0.10 $0.22 12 0.66 $0.22 Food Preparation Food Prep Standard - $0.00 12 1.00 $0.00 Food Preparation Food Prep Efficient 0.00 $0.03 12 0.88 $0.77 Refrigeration Walk in Refrigeration Standard - $0.00 18 1.00 $0.00 Refrigeration Walk in Refrigeration Efficient 0.04 $0.05 18 0.95 $0.08 Refrigeration Glass Door Display Standard - $0.00 18 1.00 $0.00 Refrigeration Glass Door Display Efficient 0.04 $0.00 18 1.39 $0.00 Refrigeration Reach-in Refrigerator Standard - $0.00 18 1.00 $0.00 Refrigeration Reach-in Refrigerator Efficient 0.21 $0.02 18 1.19 $0.01 Refrigeration Open Display Case Standard - $0.00 18 1.00 $0.00 Refrigeration Open Display Case Efficient 0.01 $0.03 18 0.93 $0.25 Refrigeration Vending Machine Base - $0.00 10 - $0.00 Refrigeration Vending Machine Base (2012) 0.12 $0.00 10 1.00 $0.00 Refrigeration Vending Machine High Efficiency 0.14 $0.00 10 - $0.00 Refrigeration Vending Machine High Efficiency (2012) 0.21 $0.00 10 1.24 $0.00 Refrigeration Icemaker Standard - $0.00 12 1.00 $0.00 Refrigeration Icemaker Efficient 0.04 $0.00 12 1.12 $0.01 Office Equipment Desktop Computer Baseline - $0.00 4 1.00 $0.00 Office Equipment Desktop Computer Energy Star 0.28 $0.00 4 1.02 $0.00 Office Equipment Desktop Computer Climate Savers 0.39 $0.33 4 0.86 $0.22 Office Equipment Laptop Computer Baseline - $0.00 4 1.00 $0.00 Office Equipment Laptop Computer Energy Star 0.03 $0.00 4 1.00 $0.01 Office Equipment Laptop Computer Climate Savers 0.04 $0.10 4 0.84 $0.61 Office Equipment Server Standard - $0.00 3 1.00 $0.00 Office Server Energy Star 0.05 $0.00 3 1.00 $0.03 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1013 of 1125 C&I Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting C-37 End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Equipment Office Equipment Monitor Standard - $0.00 4 1.00 $0.00 Office Equipment Monitor Energy Star 0.03 $0.01 4 0.99 $0.04 Office Equipment Printer/copier/fax Standard - $0.00 6 1.00 $0.00 Office Equipment Printer/copier/fax Energy Star 0.02 $0.01 6 0.96 $0.06 Office Equipment POS Terminal Standard - $0.00 4 1.00 $0.00 Office Equipment POS Terminal Energy Star 0.00 $0.00 4 0.99 $0.05 Miscellaneous Non-HVAC Motor Standard - $0.00 15 - $0.00 Miscellaneous Non-HVAC Motor Standard (2015) 0.00 $0.06 15 - $1.06 Miscellaneous Non-HVAC Motor High Efficiency 0.01 $0.00 15 1.00 $0.00 Miscellaneous Non-HVAC Motor High Efficiency (2015) 0.04 $0.06 15 0.97 $0.12 Miscellaneous Non-HVAC Motor Premium - $0.00 0 - $0.00 Miscellaneous Non-HVAC Motor Premium (2015) - $0.00 0 - $0.00 Miscellaneous Other Miscellaneous Miscellaneous - $0.00 5 - $0.00 Miscellaneous Other Miscellaneous Miscellaneous (2013) 0.00 $0.00 5 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1014 of 1125 C&I Energy Efficiency Equipment and Measure Data C-38 www.enernoc.com Table C-12 Energy Efficiency Equipment Data, Electric— Extra Large Commercial, New Vintage, Washington End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Cooling Central Chiller Variable Refrigerant Flow 1.01 $10.92 20 0.15 $0.77 Cooling RTU EER 9.2 - $0.00 16 - $0.00 Cooling RTU EER 10.1 0.19 $0.24 16 - $0.10 Cooling RTU EER 11.2 0.38 $0.44 16 1.00 $0.10 Cooling RTU EER 12.0 0.49 $0.73 16 0.89 $0.12 Cooling RTU Ductless VRF 0.60 $6.51 16 0.26 $0.90 Cooling Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00 Cooling Heat Pump EER 10.3, COP 3.2 0.17 $0.24 15 - $0.12 Cooling Heat Pump EER 11.0, COP 3.3 0.28 $0.73 15 1.00 $0.23 Cooling Heat Pump EER 11.7, COP 3.4 0.37 $0.97 15 0.97 $0.23 Cooling Heat Pump EER 12, COP 3.4 0.41 $1.21 15 0.94 $0.26 Cooling Heat Pump Ductless Mini-Split System 0.45 $7.10 20 0.54 $1.12 Space Heating Electric Resistance Standard - $0.00 25 1.00 $0.00 Space Heating Furnace Standard - $0.00 18 1.00 $0.00 Ventilation Ventilation Constant Volume - $0.00 15 1.00 $0.00 Ventilation Ventilation Variable Air Volume 2.23 $1.22 15 1.06 $0.05 Interior Lighting Interior Screw-in Incandescents - $0.00 1 - $0.00 Interior Lighting Interior Screw-in Infrared Halogen 0.87 $0.14 1 1.00 $0.16 Interior Lighting Interior Screw-in CFL 3.61 $0.06 4 5.48 $0.00 Interior Lighting Interior Screw-in LED 3.99 $1.90 12 - $0.05 Interior Lighting High Bay Fixtures Metal Halides - $0.00 6 1.00 $0.00 Interior Lighting High Bay Fixtures High Pressure Sodium 0.10 -$0.05 9 2.23 -$0.07 Interior Lighting High Bay Fixtures T8 0.10 -$0.11 6 5.65 -$0.19 Interior Lighting High Bay Fixtures T5 0.13 -$0.10 6 6.21 -$0.15 Interior Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00 Interior Lighting Linear Fluorescent T8 0.22 -$0.03 6 1.12 -$0.02 Interior Lighting Linear Fluorescent Super T8 0.66 $0.21 6 0.88 $0.06 Interior Lighting Linear Fluorescent T5 0.68 $0.35 6 0.74 $0.09 Interior Lighting Linear Fluorescent LED 0.72 $3.08 15 - $0.37 Exterior Lighting Exterior Screw-in Incandescent - $0.00 1 - $0.00 Exterior Lighting Exterior Screw-in Infrared Halogen 0.01 $0.00 1 1.00 $0.38 Exterior Lighting Exterior Screw-in CFL 0.04 $0.00 4 6.57 $0.01 Exterior Lighting Exterior Screw-in Metal Halides 0.04 $0.00 4 3.32 $0.03 Exterior Lighting Exterior Screw-in LED 0.04 $0.05 12 - $0.12 Exterior Lighting HID Metal Halides - $0.00 6 1.00 $0.00 Exterior Lighting HID High Pressure Sodium 0.19 -$0.16 9 2.08 -$0.10 Exterior Lighting HID Low Pressure Sodium 0.21 $0.64 9 0.57 $0.40 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1015 of 1125 C&I Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting C-39 End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Water Heating Water Heater Baseline (EF=0.90) - $0.00 15 1.00 $0.00 Water Heating Water Heater High Efficiency (EF=0.95) 0.20 $0.02 15 1.04 $0.01 Water Heating Water Heater EF 2.0 1.98 -$0.48 15 2.49 -$0.02 Water Heating Water Heater EF 2.3 2.22 -$0.47 15 2.85 -$0.02 Water Heating Water Heater EF 2.4 2.29 -$0.47 15 2.97 -$0.02 Water Heating Water Heater Geothermal Heat Pump 2.62 $3.53 15 0.57 $0.12 Water Heating Water Heater Solar 2.88 $3.03 15 0.66 $0.09 Food Preparation Fryer Standard - $0.00 12 1.00 $0.00 Food Preparation Fryer Efficient 0.03 $0.00 12 1.13 $0.02 Food Preparation Oven Standard - $0.00 12 1.00 $0.00 Food Preparation Oven Efficient 0.84 $0.38 12 1.00 $0.05 Food Preparation Dishwasher Standard - $0.00 12 1.00 $0.00 Food Preparation Dishwasher Efficient 0.03 $0.04 12 0.89 $0.18 Food Preparation Hot Food Container Standard - $0.00 12 1.00 $0.00 Food Preparation Hot Food Container Efficient 0.10 $0.22 12 0.66 $0.22 Food Preparation Food Prep Standard - $0.00 12 1.00 $0.00 Food Preparation Food Prep Efficient 0.00 $0.03 12 0.88 $0.62 Refrigeration Walk in Refrigeration Standard - $0.00 18 1.00 $0.00 Refrigeration Walk in Refrigeration Efficient 0.04 $0.05 18 0.95 $0.08 Refrigeration Glass Door Display Standard - $0.00 18 1.00 $0.00 Refrigeration Glass Door Display Efficient 0.04 $0.00 18 1.39 $0.00 Refrigeration Reach-in Refrigerator Standard - $0.00 18 1.00 $0.00 Refrigeration Reach-in Refrigerator Efficient 0.21 $0.02 18 1.20 $0.01 Refrigeration Open Display Case Standard - $0.00 18 1.00 $0.00 Refrigeration Open Display Case Efficient 0.01 $0.03 18 0.93 $0.25 Refrigeration Vending Machine Base - $0.00 10 - $0.00 Refrigeration Vending Machine Base (2012) 0.10 $0.00 10 1.00 $0.00 Refrigeration Vending Machine High Efficiency 0.12 $0.00 10 - $0.00 Refrigeration Vending Machine High Efficiency (2012) 0.18 $0.00 10 1.21 $0.00 Refrigeration Icemaker Standard - $0.00 12 1.00 $0.00 Refrigeration Icemaker Efficient 0.04 $0.00 12 1.12 $0.01 Office Equipment Desktop Computer Baseline - $0.00 4 1.00 $0.00 Office Equipment Desktop Computer Energy Star 0.28 $0.00 4 1.02 $0.00 Office Equipment Desktop Computer Climate Savers 0.39 $0.33 4 0.86 $0.22 Office Equipment Laptop Computer Baseline - $0.00 4 1.00 $0.00 Office Equipment Laptop Computer Energy Star 0.03 $0.00 4 1.00 $0.01 Office Equipment Laptop Computer Climate Savers 0.04 $0.10 4 0.84 $0.61 Office Equipment Server Standard - $0.00 3 1.00 $0.00 Office Server Energy Star 0.05 $0.00 3 1.00 $0.03 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1016 of 1125 C&I Energy Efficiency Equipment and Measure Data C-40 www.enernoc.com End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Equipment Office Equipment Monitor Standard - $0.00 4 1.00 $0.00 Office Equipment Monitor Energy Star 0.03 $0.01 4 0.99 $0.04 Office Equipment Printer/copier/fax Standard - $0.00 6 1.00 $0.00 Office Equipment Printer/copier/fax Energy Star 0.02 $0.01 6 0.96 $0.06 Office Equipment POS Terminal Standard - $0.00 4 1.00 $0.00 Office Equipment POS Terminal Energy Star 0.00 $0.00 4 0.99 $0.05 Miscellaneous Non-HVAC Motor Standard - $0.00 15 - $0.00 Miscellaneous Non-HVAC Motor Standard (2015) 0.00 $0.06 15 - $1.06 Miscellaneous Non-HVAC Motor High Efficiency 0.01 $0.00 15 1.00 $0.00 Miscellaneous Non-HVAC Motor High Efficiency (2015) 0.04 $0.06 15 0.97 $0.12 Miscellaneous Non-HVAC Motor Premium - $0.00 0 - $0.00 Miscellaneous Non-HVAC Motor Premium (2015) - $0.00 0 - $0.00 Miscellaneous Other Miscellaneous Miscellaneous - $0.00 5 - $0.00 Miscellaneous Other Miscellaneous Miscellaneous (2013) 0.00 $0.00 5 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1017 of 1125 C&I Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting C-41 Table C-13 Energy Efficiency Equipment Data, Electric—Extra Large Commercial, Existing Vintage, Idaho End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Cooling Central Chiller Variable Refrigerant Flow 1.08 $10.92 20 0.16 $0.71 Cooling RTU EER 9.2 - $0.00 16 - $0.00 Cooling RTU EER 10.1 0.20 $0.24 16 - $0.10 Cooling RTU EER 11.2 0.40 $0.45 16 1.00 $0.09 Cooling RTU EER 12.0 0.52 $0.75 16 0.89 $0.12 Cooling RTU Ductless VRF 0.63 $6.64 16 0.26 $0.87 Cooling Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00 Cooling Heat Pump EER 10.3, COP 3.2 0.20 $0.24 15 - $0.11 Cooling Heat Pump EER 11.0, COP 3.3 0.31 $0.73 15 1.00 $0.20 Cooling Heat Pump EER 11.7, COP 3.4 0.42 $0.97 15 0.97 $0.20 Cooling Heat Pump EER 12, COP 3.4 0.46 $1.21 15 0.94 $0.23 Cooling Heat Pump Ductless Mini-Split System 0.51 $7.10 20 0.53 $0.99 Space Heating Electric Resistance Standard - $0.00 25 1.00 $0.00 Space Heating Furnace Standard - $0.00 18 1.00 $0.00 Ventilation Ventilation Constant Volume - $0.00 15 1.00 $0.00 Ventilation Ventilation Variable Air Volume 2.10 $1.22 15 1.02 $0.05 Interior Lighting Interior Screw-in Incandescents - $0.00 1 - $0.00 Interior Lighting Interior Screw-in Infrared Halogen 0.79 $0.14 1 1.00 $0.18 Interior Lighting Interior Screw-in CFL 3.25 $0.06 4 5.61 $0.00 Interior Lighting Interior Screw-in LED 3.59 $1.90 12 - $0.05 Interior Lighting High Bay Fixtures Metal Halides - $0.00 6 1.00 $0.00 Interior Lighting High Bay Fixtures High Pressure Sodium 0.10 -$0.05 9 2.26 -$0.07 Interior Lighting High Bay Fixtures T8 0.10 -$0.11 6 5.77 -$0.19 Interior Lighting High Bay Fixtures T5 0.13 -$0.10 6 6.31 -$0.15 Interior Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00 Interior Lighting Linear Fluorescent T8 0.23 -$0.03 6 1.12 -$0.02 Interior Lighting Linear Fluorescent Super T8 0.69 $0.21 6 0.88 $0.06 Interior Lighting Linear Fluorescent T5 0.71 $0.35 6 0.74 $0.09 Interior Lighting Linear Fluorescent LED 0.75 $3.08 15 - $0.36 Exterior Lighting Exterior Screw-in Incandescent - $0.00 1 - $0.00 Exterior Lighting Exterior Screw-in Infrared Halogen 0.02 $0.00 1 1.00 $0.22 Exterior Lighting Exterior Screw-in CFL 0.07 $0.00 4 5.90 $0.01 Exterior Lighting Exterior Screw-in Metal Halides 0.07 $0.00 4 3.36 $0.02 Exterior Lighting Exterior Screw-in LED 0.07 $0.05 12 - $0.07 Exterior Lighting HID Metal Halides - $0.00 6 1.00 $0.00 Exterior Lighting HID High Pressure Sodium 0.19 -$0.16 9 2.09 -$0.10 Exterior Lighting HID Low Pressure Sodium 0.21 $0.64 9 0.57 $0.40 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1018 of 1125 C&I Energy Efficiency Equipment and Measure Data C-42 www.enernoc.com End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Water Heating Water Heater Baseline (EF=0.90) - $0.00 15 1.00 $0.00 Water Heating Water Heater High Efficiency (EF=0.95) 0.20 $0.02 15 1.03 $0.01 Water Heating Water Heater EF 2.0 1.95 -$0.48 15 2.55 -$0.02 Water Heating Water Heater EF 2.3 2.19 -$0.47 15 2.92 -$0.02 Water Heating Water Heater EF 2.4 2.26 -$0.47 15 3.04 -$0.02 Water Heating Water Heater Geothermal Heat Pump 2.59 $3.53 15 0.52 $0.12 Water Heating Water Heater Solar 2.84 $3.03 15 0.60 $0.09 Food Preparation Fryer Standard - $0.00 12 1.00 $0.00 Food Preparation Fryer Efficient 0.03 $0.00 12 1.11 $0.02 Food Preparation Oven Standard - $0.00 12 1.00 $0.00 Food Preparation Oven Efficient 0.84 $0.38 12 0.99 $0.05 Food Preparation Dishwasher Standard - $0.00 12 1.00 $0.00 Food Preparation Dishwasher Efficient 0.03 $0.04 12 0.88 $0.18 Food Preparation Hot Food Container Standard - $0.00 12 1.00 $0.00 Food Preparation Hot Food Container Efficient 0.10 $0.22 12 0.65 $0.22 Food Preparation Food Prep Standard - $0.00 12 1.00 $0.00 Food Preparation Food Prep Efficient 0.00 $0.03 12 0.88 $0.77 Refrigeration Walk in Refrigeration Standard - $0.00 18 1.00 $0.00 Refrigeration Walk in Refrigeration Efficient 0.04 $0.05 18 0.95 $0.08 Refrigeration Glass Door Display Standard - $0.00 18 1.00 $0.00 Refrigeration Glass Door Display Efficient 0.04 $0.00 18 1.39 $0.00 Refrigeration Reach-in Refrigerator Standard - $0.00 18 1.00 $0.00 Refrigeration Reach-in Refrigerator Efficient 0.21 $0.02 18 1.18 $0.01 Refrigeration Open Display Case Standard - $0.00 18 1.00 $0.00 Refrigeration Open Display Case Efficient 0.01 $0.03 18 0.93 $0.25 Refrigeration Vending Machine Base - $0.00 10 - $0.00 Refrigeration Vending Machine Base (2012) 0.12 $0.00 10 1.00 $0.00 Refrigeration Vending Machine High Efficiency 0.14 $0.00 10 - $0.00 Refrigeration Vending Machine High Efficiency (2012) 0.21 $0.00 10 1.23 $0.00 Refrigeration Icemaker Standard - $0.00 12 1.00 $0.00 Refrigeration Icemaker Efficient 0.04 $0.00 12 1.12 $0.01 Office Equipment Desktop Computer Baseline - $0.00 4 1.00 $0.00 Office Equipment Desktop Computer Energy Star 0.28 $0.00 4 1.02 $0.00 Office Equipment Desktop Computer Climate Savers 0.39 $0.33 4 0.86 $0.22 Office Equipment Laptop Computer Baseline - $0.00 4 1.00 $0.00 Office Equipment Laptop Computer Energy Star 0.03 $0.00 4 1.00 $0.01 Office Equipment Laptop Computer Climate Savers 0.04 $0.10 4 0.84 $0.61 Office Equipment Server Standard - $0.00 3 1.00 $0.00 Office Server Energy Star 0.05 $0.00 3 1.00 $0.03 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1019 of 1125 C&I Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting C-43 End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Equipment Office Equipment Monitor Standard - $0.00 4 1.00 $0.00 Office Equipment Monitor Energy Star 0.03 $0.01 4 0.99 $0.04 Office Equipment Printer/copier/fax Standard - $0.00 6 1.00 $0.00 Office Equipment Printer/copier/fax Energy Star 0.02 $0.01 6 0.96 $0.06 Office Equipment POS Terminal Standard - $0.00 4 1.00 $0.00 Office Equipment POS Terminal Energy Star 0.00 $0.00 4 0.99 $0.05 Miscellaneous Non-HVAC Motor Standard - $0.00 15 - $0.00 Miscellaneous Non-HVAC Motor Standard (2015) 0.00 $0.06 15 - $1.06 Miscellaneous Non-HVAC Motor High Efficiency 0.01 $0.00 15 1.00 $0.00 Miscellaneous Non-HVAC Motor High Efficiency (2015) 0.04 $0.06 15 0.97 $0.12 Miscellaneous Non-HVAC Motor Premium - $0.00 0 - $0.00 Miscellaneous Non-HVAC Motor Premium (2015) - $0.00 0 - $0.00 Miscellaneous Other Miscellaneous Miscellaneous - $0.00 5 - $0.00 Miscellaneous Other Miscellaneous Miscellaneous (2013) 0.00 $0.00 5 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1020 of 1125 C&I Energy Efficiency Equipment and Measure Data C-44 www.enernoc.com Table C-14 Energy Efficiency Equipment Data, Electric— Extra Large Commercial, New Vintage, Idaho End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Cooling Central Chiller Variable Refrigerant Flow 1.01 $10.92 20 0.15 $0.77 Cooling RTU EER 9.2 - $0.00 16 - $0.00 Cooling RTU EER 10.1 0.19 $0.24 16 - $0.10 Cooling RTU EER 11.2 0.38 $0.44 16 1.00 $0.10 Cooling RTU EER 12.0 0.49 $0.73 16 0.89 $0.12 Cooling RTU Ductless VRF 0.60 $6.51 16 0.26 $0.90 Cooling Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00 Cooling Heat Pump EER 10.3, COP 3.2 0.17 $0.24 15 - $0.12 Cooling Heat Pump EER 11.0, COP 3.3 0.28 $0.73 15 1.00 $0.23 Cooling Heat Pump EER 11.7, COP 3.4 0.37 $0.97 15 0.97 $0.23 Cooling Heat Pump EER 12, COP 3.4 0.41 $1.21 15 0.94 $0.26 Cooling Heat Pump Ductless Mini-Split System 0.45 $7.10 20 0.53 $1.12 Space Heating Electric Resistance Standard - $0.00 25 1.00 $0.00 Space Heating Furnace Standard - $0.00 18 1.00 $0.00 Ventilation Ventilation Constant Volume - $0.00 15 1.00 $0.00 Ventilation Ventilation Variable Air Volume 2.23 $1.22 15 1.05 $0.05 Interior Lighting Interior Screw-in Incandescents - $0.00 1 - $0.00 Interior Lighting Interior Screw-in Infrared Halogen 0.87 $0.14 1 1.00 $0.16 Interior Lighting Interior Screw-in CFL 3.61 $0.06 4 5.48 $0.00 Interior Lighting Interior Screw-in LED 3.99 $1.90 12 - $0.05 Interior Lighting High Bay Fixtures Metal Halides - $0.00 6 1.00 $0.00 Interior Lighting High Bay Fixtures High Pressure Sodium 0.10 -$0.05 9 2.26 -$0.07 Interior Lighting High Bay Fixtures T8 0.10 -$0.11 6 5.77 -$0.19 Interior Lighting High Bay Fixtures T5 0.13 -$0.10 6 6.31 -$0.15 Interior Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00 Interior Lighting Linear Fluorescent T8 0.22 -$0.03 6 1.12 -$0.02 Interior Lighting Linear Fluorescent Super T8 0.66 $0.21 6 0.87 $0.06 Interior Lighting Linear Fluorescent T5 0.68 $0.35 6 0.73 $0.09 Interior Lighting Linear Fluorescent LED 0.72 $3.08 15 - $0.37 Exterior Lighting Exterior Screw-in Incandescent - $0.00 1 - $0.00 Exterior Lighting Exterior Screw-in Infrared Halogen 0.01 $0.00 1 1.00 $0.38 Exterior Lighting Exterior Screw-in CFL 0.04 $0.00 4 6.58 $0.01 Exterior Lighting Exterior Screw-in Metal Halides 0.04 $0.00 4 3.32 $0.03 Exterior Lighting Exterior Screw-in LED 0.04 $0.05 12 - $0.12 Exterior Lighting HID Metal Halides - $0.00 6 1.00 $0.00 Exterior Lighting HID High Pressure Sodium 0.19 -$0.16 9 2.09 -$0.10 Exterior Lighting HID Low Pressure Sodium 0.21 $0.64 9 0.57 $0.40 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1021 of 1125 C&I Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting C-45 End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Water Heating Water Heater Baseline (EF=0.90) - $0.00 15 1.00 $0.00 Water Heating Water Heater High Efficiency (EF=0.95) 0.20 $0.02 15 1.03 $0.01 Water Heating Water Heater EF 2.0 1.98 -$0.48 15 2.54 -$0.02 Water Heating Water Heater EF 2.3 2.22 -$0.47 15 2.92 -$0.02 Water Heating Water Heater EF 2.4 2.29 -$0.47 15 3.04 -$0.02 Water Heating Water Heater Geothermal Heat Pump 2.62 $3.53 15 0.52 $0.12 Water Heating Water Heater Solar 2.88 $3.03 15 0.60 $0.09 Food Preparation Fryer Standard - $0.00 12 1.00 $0.00 Food Preparation Fryer Efficient 0.03 $0.00 12 1.11 $0.02 Food Preparation Oven Standard - $0.00 12 1.00 $0.00 Food Preparation Oven Efficient 0.84 $0.38 12 0.99 $0.05 Food Preparation Dishwasher Standard - $0.00 12 1.00 $0.00 Food Preparation Dishwasher Efficient 0.03 $0.04 12 0.88 $0.18 Food Preparation Hot Food Container Standard - $0.00 12 1.00 $0.00 Food Preparation Hot Food Container Efficient 0.10 $0.22 12 0.65 $0.22 Food Preparation Food Prep Standard - $0.00 12 1.00 $0.00 Food Preparation Food Prep Efficient 0.00 $0.03 12 0.88 $0.62 Refrigeration Walk in Refrigeration Standard - $0.00 18 1.00 $0.00 Refrigeration Walk in Refrigeration Efficient 0.04 $0.05 18 0.95 $0.08 Refrigeration Glass Door Display Standard - $0.00 18 1.00 $0.00 Refrigeration Glass Door Display Efficient 0.04 $0.00 18 1.39 $0.00 Refrigeration Reach-in Refrigerator Standard - $0.00 18 1.00 $0.00 Refrigeration Reach-in Refrigerator Efficient 0.21 $0.02 18 1.19 $0.01 Refrigeration Open Display Case Standard - $0.00 18 1.00 $0.00 Refrigeration Open Display Case Efficient 0.01 $0.03 18 0.93 $0.25 Refrigeration Vending Machine Base - $0.00 10 - $0.00 Refrigeration Vending Machine Base (2012) 0.10 $0.00 10 1.00 $0.00 Refrigeration Vending Machine High Efficiency 0.12 $0.00 10 - $0.00 Refrigeration Vending Machine High Efficiency (2012) 0.18 $0.00 10 1.20 $0.00 Refrigeration Icemaker Standard - $0.00 12 1.00 $0.00 Refrigeration Icemaker Efficient 0.04 $0.00 12 1.12 $0.01 Office Equipment Desktop Computer Baseline - $0.00 4 1.00 $0.00 Office Equipment Desktop Computer Energy Star 0.28 $0.00 4 1.02 $0.00 Office Equipment Desktop Computer Climate Savers 0.39 $0.33 4 0.86 $0.22 Office Equipment Laptop Computer Baseline - $0.00 4 1.00 $0.00 Office Equipment Laptop Computer Energy Star 0.03 $0.00 4 1.00 $0.01 Office Equipment Laptop Computer Climate Savers 0.04 $0.10 4 0.84 $0.61 Office Equipment Server Standard - $0.00 3 1.00 $0.00 Office Server Energy Star 0.05 $0.00 3 1.00 $0.03 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1022 of 1125 C&I Energy Efficiency Equipment and Measure Data C-46 www.enernoc.com End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Equipment Office Equipment Monitor Standard - $0.00 4 1.00 $0.00 Office Equipment Monitor Energy Star 0.03 $0.01 4 0.99 $0.04 Office Equipment Printer/copier/fax Standard - $0.00 6 1.00 $0.00 Office Equipment Printer/copier/fax Energy Star 0.02 $0.01 6 0.96 $0.06 Office Equipment POS Terminal Standard - $0.00 4 1.00 $0.00 Office Equipment POS Terminal Energy Star 0.00 $0.00 4 0.99 $0.05 Miscellaneous Non-HVAC Motor Standard - $0.00 15 - $0.00 Miscellaneous Non-HVAC Motor Standard (2015) 0.00 $0.06 15 - $1.06 Miscellaneous Non-HVAC Motor High Efficiency 0.01 $0.00 15 1.00 $0.00 Miscellaneous Non-HVAC Motor High Efficiency (2015) 0.04 $0.06 15 0.97 $0.12 Miscellaneous Non-HVAC Motor Premium - $0.00 0 - $0.00 Miscellaneous Non-HVAC Motor Premium (2015) - $0.00 0 - $0.00 Miscellaneous Other Miscellaneous Miscellaneous - $0.00 5 - $0.00 Miscellaneous Other Miscellaneous Miscellaneous (2013) 0.00 $0.00 5 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1023 of 1125 C&I Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting C-47 Table C-15 Energy Efficiency Equipment Data, Electric—Extra Large Industrial, Existing Vintage, Washington End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Cooling Central Chiller 0.75 kw/ton, COP 4.7 - $0.00 20 - $0.00 Cooling Central Chiller 0.60 kw/ton, COP 5.9 1.69 $0.33 20 1.10 $0.01 Cooling Central Chiller 0.58 kw/ton, COP 6.1 1.91 $0.66 20 0.97 $0.02 Cooling Central Chiller 0.55 kw/Ton, COP 6.4 2.25 $0.93 20 0.95 $0.03 Cooling Central Chiller 0.51 kw/ton, COP 6.9 2.70 $1.59 20 0.90 $0.04 Cooling Central Chiller 0.50 kw/Ton, COP 7.0 2.81 $1.92 20 0.87 $0.05 Cooling Central Chiller 0.48 kw/ton, COP 7.3 3.04 $2.25 20 0.84 $0.05 Cooling Central Chiller Variable Refrigerant Flow 3.92 $39.62 20 0.15 $0.72 Cooling RTU EER 9.2 - $0.00 16 - $0.00 Cooling RTU EER 10.1 0.56 $0.39 16 - $0.06 Cooling RTU EER 11.2 1.12 $0.73 16 1.00 $0.05 Cooling RTU EER 12.0 1.47 $1.22 16 0.92 $0.07 Cooling RTU Ductless VRF 1.79 $10.83 16 0.31 $0.50 Cooling Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00 Cooling Heat Pump EER 10.3, COP 3.2 0.41 $0.92 15 - $0.19 Cooling Heat Pump EER 11.0, COP 3.3 0.65 $2.75 15 1.00 $0.36 Cooling Heat Pump EER 11.7, COP 3.4 0.87 $3.66 15 0.95 $0.36 Cooling Heat Pump EER 12, COP 3.4 0.95 $4.58 15 0.90 $0.42 Cooling Heat Pump Ductless Mini-Split System 1.06 $26.86 20 0.45 $1.80 Space Heating Electric Resistance Standard - $0.00 25 1.00 $0.00 Space Heating Furnace Standard - $0.00 18 1.00 $0.00 Space Heating Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00 Space Heating Heat Pump EER 10.3, COP 3.2 0.13 $0.92 15 - $0.61 Space Heating Heat Pump EER 11.0, COP 3.3 0.25 $2.75 15 1.00 $0.95 Space Heating Heat Pump EER 11.7, COP 3.4 0.37 $3.66 15 0.95 $0.87 Space Heating Heat Pump EER 12, COP 3.4 0.47 $4.58 15 0.90 $0.84 Space Heating Heat Pump Ductless Mini-Split System 1.04 $26.86 20 0.45 $1.83 Space Heating Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00 Space Heating Heat Pump EER 10.3, COP 3.2 0.13 $0.92 15 - $0.61 Space Heating Heat Pump EER 11.0, COP 3.3 0.25 $2.75 15 1.00 $0.95 Space Heating Heat Pump EER 11.7, COP 3.4 0.37 $3.66 15 0.95 $0.87 Space Heating Heat Pump EER 12, COP 3.4 0.47 $4.58 15 0.90 $0.84 Space Heating Heat Pump Ductless Mini-Split System 1.04 $26.86 20 0.45 $1.83 Ventilation Ventilation Constant Volume - $0.00 15 1.00 $0.00 Ventilation Ventilation Variable Air Volume 8.88 $1.22 15 1.46 $0.01 Interior Lighting Interior Screw-in Incandescents - $0.00 1 - $0.00 Interior Lighting Interior Screw-in Infrared Halogen 0.18 $0.04 1 1.00 $0.20 Interior Lighting Interior Screw-in CFL 0.76 $0.02 4 5.79 $0.01 Interior Lighting Interior Screw-in LED 0.84 $0.52 12 - $0.06 Interior Lighting High Bay Fixtures Metal Halides - $0.00 6 1.00 $0.00 Interior Lighting High Bay Fixtures High Pressure Sodium 0.40 -$0.14 9 2.11 -$0.04 Interior Lighting High Bay Fixtures T8 0.40 -$0.28 6 4.58 -$0.13 Interior Lighting High Bay Fixtures T5 0.51 -$0.28 6 5.58 -$0.10 Interior Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00 Interior Lighting Linear Fluorescent T8 0.09 -$0.01 6 1.12 -$0.02 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1024 of 1125 C&I Energy Efficiency Equipment and Measure Data C-48 www.enernoc.com End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Interior Lighting Linear Fluorescent Super T8 0.26 $0.08 6 0.88 $0.06 Interior Lighting Linear Fluorescent T5 0.27 $0.14 6 0.74 $0.09 Interior Lighting Linear Fluorescent LED 0.29 $1.21 15 - $0.37 Exterior Lighting Exterior Screw-in Incandescent - $0.00 1 - $0.00 Exterior Lighting Exterior Screw-in Infrared Halogen 0.01 $0.00 1 1.00 $0.24 Exterior Lighting Exterior Screw-in CFL 0.04 $0.00 4 6.00 $0.01 Exterior Lighting Exterior Screw-in Metal Halides 0.04 $0.00 4 3.36 $0.02 Exterior Lighting Exterior Screw-in LED 0.04 $0.03 12 - $0.07 Exterior Lighting HID Metal Halides - $0.00 6 1.00 $0.00 Exterior Lighting HID High Pressure Sodium 0.05 -$0.04 9 2.10 -$0.11 Exterior Lighting HID Low Pressure Sodium 0.06 $0.18 9 0.57 $0.42 Process Process Cooling/Refrigeration Standard - $0.00 10 1.00 $0.00 Process Process Cooling/Refrigeration Efficient 18.88 $5.59 10 1.23 $0.04 Process Process Heating Standard - $0.00 10 1.00 $0.00 Process Electrochemical Process Standard - $0.00 10 1.00 $0.00 Process Electrochemical Process Efficient 13.16 $2.64 10 1.20 $0.02 Machine Drive Less than 5 HP Standard - $0.00 15 - $0.00 Machine Drive Less than 5 HP High Efficiency 0.00 $0.06 15 - $0.99 Machine Drive Less than 5 HP Standard (2015) 0.01 $0.00 15 1.00 $0.00 Machine Drive Less than 5 HP Premium 0.04 $0.06 15 1.04 $0.11 Machine Drive Less than 5 HP High Efficiency (2015) - $0.00 0 - $0.00 Machine Drive Less than 5 HP Premium (2015) - $0.00 0 - $0.00 Machine Drive 5-24 HP Standard - $0.00 10 1.00 $0.00 Machine Drive 5-24 HP High 0.01 $0.02 10 1.01 $0.17 Machine Drive 5-24 HP Premium - $0.00 0 - $0.00 Machine Drive 25-99 HP Standard - $0.00 10 1.00 $0.00 Machine Drive 25-99 HP High 0.03 $0.02 10 1.01 $0.06 Machine Drive 25-99 HP Premium - $0.00 0 - $0.00 Machine Drive 100-249 HP Standard - $0.00 10 1.00 $0.00 Machine Drive 100-249 HP High 0.02 $0.02 10 1.01 $0.10 Machine Drive 100-249 HP Premium - $0.00 0 - $0.00 Machine Drive 250-499 HP Standard - $0.00 10 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1025 of 1125 C&I Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting C-49 End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Machine Drive 250-499 HP High 0.06 $0.02 10 1.01 $0.03 Machine Drive 250-499 HP Premium - $0.00 0 - $0.00 Machine Drive 500 and more HP Standard - $0.00 10 1.00 $0.00 Machine Drive 500 and more HP High 0.10 $0.02 10 1.01 $0.02 Machine Drive 500 and more HP Premium - $0.00 0 - $0.00 Miscellaneous Miscellaneous Miscellaneous - $0.00 5 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1026 of 1125 C&I Energy Efficiency Equipment and Measure Data C-50 www.enernoc.com Table C-16 Energy Efficiency Equipment Data, Electric— Extra Large Industrial, New Vintage, Washington End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Cooling Central Chiller 0.75 kw/ton, COP 4.7 - $0.00 20 - $0.00 Cooling Central Chiller 0.60 kw/ton, COP 5.9 1.58 $0.33 20 1.10 $0.01 Cooling Central Chiller 0.58 kw/ton, COP 6.1 1.79 $0.66 20 0.97 $0.03 Cooling Central Chiller 0.55 kw/Ton, COP 6.4 2.11 $0.93 20 0.95 $0.03 Cooling Central Chiller 0.51 kw/ton, COP 6.9 2.53 $1.59 20 0.89 $0.04 Cooling Central Chiller 0.50 kw/Ton, COP 7.0 2.63 $1.92 20 0.86 $0.05 Cooling Central Chiller 0.48 kw/ton, COP 7.3 2.84 $2.25 20 0.83 $0.06 Cooling Central Chiller Variable Refrigerant Flow 3.67 $39.62 20 0.15 $0.76 Cooling RTU EER 9.2 - $0.00 16 - $0.00 Cooling RTU EER 10.1 0.56 $0.39 16 - $0.06 Cooling RTU EER 11.2 1.12 $0.74 16 1.00 $0.05 Cooling RTU EER 12.0 1.47 $1.23 16 0.92 $0.07 Cooling RTU Ductless VRF 1.79 $10.88 16 0.30 $0.50 Cooling Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00 Cooling Heat Pump EER 10.3, COP 3.2 0.39 $0.92 15 - $0.20 Cooling Heat Pump EER 11.0, COP 3.3 0.62 $2.75 15 1.00 $0.38 Cooling Heat Pump EER 11.7, COP 3.4 0.83 $3.66 15 0.95 $0.38 Cooling Heat Pump EER 12, COP 3.4 0.91 $4.58 15 0.90 $0.43 Cooling Heat Pump Ductless Mini-Split System 1.01 $26.86 20 0.45 $1.88 Space Heating Electric Resistance Standard - $0.00 25 1.00 $0.00 Space Heating Furnace Standard - $0.00 18 1.00 $0.00 Space Heating Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00 Space Heating Heat Pump EER 10.3, COP 3.2 0.13 $0.92 15 - $0.62 Space Heating Heat Pump EER 11.0, COP 3.3 0.25 $2.75 15 1.00 $0.96 Space Heating Heat Pump EER 11.7, COP 3.4 0.36 $3.66 15 0.95 $0.88 Space Heating Heat Pump EER 12, COP 3.4 0.47 $4.58 15 0.90 $0.85 Space Heating Heat Pump Ductless Mini-Split System 1.02 $26.86 20 0.45 $1.86 Space Heating Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00 Space Heating Heat Pump EER 10.3, COP 3.2 0.13 $0.92 15 - $0.62 Space Heating Heat Pump EER 11.0, COP 3.3 0.25 $2.75 15 1.00 $0.96 Space Heating Heat Pump EER 11.7, COP 3.4 0.36 $3.66 15 0.95 $0.88 Space Heating Heat Pump EER 12, COP 3.4 0.47 $4.58 15 0.90 $0.85 Space Heating Heat Pump Ductless Mini-Split System 1.02 $26.86 20 0.45 $1.86 Ventilation Ventilation Constant Volume - $0.00 15 1.00 $0.00 Ventilation Ventilation Variable Air Volume 13.69 $1.22 15 1.63 $0.01 Interior Lighting Interior Screw-in Incandescents - $0.00 1 - $0.00 Interior Lighting Interior Screw-in Infrared Halogen 0.21 $0.04 1 1.00 $0.18 Interior Lighting Interior Screw-in CFL 0.85 $0.02 4 5.65 $0.00 Interior Lighting Interior Screw-in LED 0.94 $0.52 12 - $0.06 Interior Lighting High Bay Fixtures Metal Halides - $0.00 6 1.00 $0.00 Interior Lighting High Bay Fixtures High Pressure Sodium 0.40 -$0.14 9 2.11 -$0.04 Interior Lighting High Bay Fixtures T8 0.40 -$0.28 6 4.58 -$0.13 Interior Lighting High Bay Fixtures T5 0.51 -$0.28 6 5.58 -$0.10 Interior Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00 Interior Lighting Linear Fluorescent T8 0.09 -$0.01 6 1.12 -$0.02 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1027 of 1125 C&I Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting C-51 End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Interior Lighting Linear Fluorescent Super T8 0.27 $0.08 6 0.89 $0.06 Interior Lighting Linear Fluorescent T5 0.28 $0.14 6 0.75 $0.09 Interior Lighting Linear Fluorescent LED 0.29 $1.21 15 - $0.36 Exterior Lighting Exterior Screw-in Incandescent - $0.00 1 - $0.00 Exterior Lighting Exterior Screw-in Infrared Halogen 0.01 $0.00 1 1.00 $0.24 Exterior Lighting Exterior Screw-in CFL 0.04 $0.00 4 6.00 $0.01 Exterior Lighting Exterior Screw-in Metal Halides 0.04 $0.00 4 3.36 $0.02 Exterior Lighting Exterior Screw-in LED 0.04 $0.03 12 - $0.07 Exterior Lighting HID Metal Halides - $0.00 6 1.00 $0.00 Exterior Lighting HID High Pressure Sodium 0.05 -$0.04 9 2.10 -$0.11 Exterior Lighting HID Low Pressure Sodium 0.06 $0.18 9 0.57 $0.42 Process Process Cooling/Refrigeration Standard - $0.00 10 1.00 $0.00 Process Process Cooling/Refrigeration Efficient 18.88 $5.59 10 1.23 $0.04 Process Process Heating Standard - $0.00 10 1.00 $0.00 Process Electrochemical Process Standard - $0.00 10 1.00 $0.00 Process Electrochemical Process Efficient 13.16 $2.64 10 1.20 $0.02 Machine Drive Less than 5 HP Standard - $0.00 15 - $0.00 Machine Drive Less than 5 HP High Efficiency 0.00 $0.06 15 - $0.99 Machine Drive Less than 5 HP Standard (2015) 0.01 $0.00 15 1.00 $0.00 Machine Drive Less than 5 HP Premium 0.04 $0.06 15 1.04 $0.11 Machine Drive Less than 5 HP High Efficiency (2015) - $0.00 0 - $0.00 Machine Drive Less than 5 HP Premium (2015) - $0.00 0 - $0.00 Machine Drive 5-24 HP Standard - $0.00 10 1.00 $0.00 Machine Drive 5-24 HP High 0.01 $0.02 10 1.01 $0.17 Machine Drive 5-24 HP Premium - $0.00 0 - $0.00 Machine Drive 25-99 HP Standard - $0.00 10 1.00 $0.00 Machine Drive 25-99 HP High 0.03 $0.02 10 1.01 $0.06 Machine Drive 25-99 HP Premium - $0.00 0 - $0.00 Machine Drive 100-249 HP Standard - $0.00 10 1.00 $0.00 Machine Drive 100-249 HP High 0.02 $0.02 10 1.01 $0.10 Machine Drive 100-249 HP Premium - $0.00 0 - $0.00 Machine Drive 250-499 HP Standard - $0.00 10 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1028 of 1125 C&I Energy Efficiency Equipment and Measure Data C-52 www.enernoc.com End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Machine Drive 250-499 HP High 0.06 $0.02 10 1.01 $0.03 Machine Drive 250-499 HP Premium - $0.00 0 - $0.00 Machine Drive 500 and more HP Standard - $0.00 10 1.00 $0.00 Machine Drive 500 and more HP High 0.10 $0.02 10 1.01 $0.02 Machine Drive 500 and more HP Premium - $0.00 0 - $0.00 Miscellaneous Miscellaneous Miscellaneous - $0.00 5 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1029 of 1125 C&I Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting C-53 Table C-17 Energy Efficiency Equipment Data, Electric—Extra Large Industrial, Existing Vintage, Idaho End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Cooling Central Chiller 0.75 kw/ton, COP 4.7 - $0.00 20 - $0.00 Cooling Central Chiller 0.60 kw/ton, COP 5.9 1.69 $0.33 20 1.10 $0.01 Cooling Central Chiller 0.58 kw/ton, COP 6.1 1.91 $0.66 20 0.97 $0.02 Cooling Central Chiller 0.55 kw/Ton, COP 6.4 2.25 $0.93 20 0.95 $0.03 Cooling Central Chiller 0.51 kw/ton, COP 6.9 2.70 $1.59 20 0.90 $0.04 Cooling Central Chiller 0.50 kw/Ton, COP 7.0 2.81 $1.92 20 0.87 $0.05 Cooling Central Chiller 0.48 kw/ton, COP 7.3 3.04 $2.25 20 0.84 $0.05 Cooling Central Chiller Variable Refrigerant Flow 3.92 $39.62 20 0.15 $0.72 Cooling RTU EER 9.2 - $0.00 16 - $0.00 Cooling RTU EER 10.1 0.56 $0.39 16 - $0.06 Cooling RTU EER 11.2 1.12 $0.73 16 1.00 $0.05 Cooling RTU EER 12.0 1.47 $1.22 16 0.92 $0.07 Cooling RTU Ductless VRF 1.79 $10.83 16 0.31 $0.50 Cooling Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00 Cooling Heat Pump EER 10.3, COP 3.2 0.41 $0.92 15 - $0.19 Cooling Heat Pump EER 11.0, COP 3.3 0.65 $2.75 15 1.00 $0.36 Cooling Heat Pump EER 11.7, COP 3.4 0.87 $3.66 15 0.95 $0.36 Cooling Heat Pump EER 12, COP 3.4 0.95 $4.58 15 0.90 $0.42 Cooling Heat Pump Ductless Mini-Split System 1.06 $26.86 20 0.45 $1.80 Space Heating Electric Resistance Standard - $0.00 25 1.00 $0.00 Space Heating Furnace Standard - $0.00 18 1.00 $0.00 Space Heating Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00 Space Heating Heat Pump EER 10.3, COP 3.2 0.13 $0.92 15 - $0.61 Space Heating Heat Pump EER 11.0, COP 3.3 0.25 $2.75 15 1.00 $0.95 Space Heating Heat Pump EER 11.7, COP 3.4 0.37 $3.66 15 0.95 $0.87 Space Heating Heat Pump EER 12, COP 3.4 0.47 $4.58 15 0.90 $0.84 Space Heating Heat Pump Ductless Mini-Split System 1.04 $26.86 20 0.45 $1.83 Space Heating Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00 Space Heating Heat Pump EER 10.3, COP 3.2 0.13 $0.92 15 - $0.61 Space Heating Heat Pump EER 11.0, COP 3.3 0.25 $2.75 15 1.00 $0.95 Space Heating Heat Pump EER 11.7, COP 3.4 0.37 $3.66 15 0.95 $0.87 Space Heating Heat Pump EER 12, COP 3.4 0.47 $4.58 15 0.90 $0.84 Space Heating Heat Pump Ductless Mini-Split System 1.04 $26.86 20 0.45 $1.83 Ventilation Ventilation Constant Volume - $0.00 15 1.00 $0.00 Ventilation Ventilation Variable Air Volume 8.88 $1.22 15 1.46 $0.01 Interior Lighting Interior Screw-in Incandescents - $0.00 1 - $0.00 Interior Lighting Interior Screw-in Infrared Halogen 0.18 $0.04 1 1.00 $0.20 Interior Lighting Interior Screw-in CFL 0.76 $0.02 4 5.79 $0.01 Interior Lighting Interior Screw-in LED 0.84 $0.52 12 - $0.06 Interior Lighting High Bay Fixtures Metal Halides - $0.00 6 1.00 $0.00 Interior Lighting High Bay Fixtures High Pressure Sodium 0.40 -$0.14 9 2.11 -$0.04 Interior Lighting High Bay Fixtures T8 0.40 -$0.28 6 4.58 -$0.13 Interior Lighting High Bay Fixtures T5 0.51 -$0.28 6 5.58 -$0.10 Interior Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00 Interior Lighting Linear Fluorescent T8 0.09 -$0.01 6 1.12 -$0.02 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1030 of 1125 C&I Energy Efficiency Equipment and Measure Data C-54 www.enernoc.com End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Interior Lighting Linear Fluorescent Super T8 0.26 $0.08 6 0.88 $0.06 Interior Lighting Linear Fluorescent T5 0.27 $0.14 6 0.74 $0.09 Interior Lighting Linear Fluorescent LED 0.29 $1.21 15 - $0.37 Exterior Lighting Exterior Screw-in Incandescent - $0.00 1 - $0.00 Exterior Lighting Exterior Screw-in Infrared Halogen 0.01 $0.00 1 1.00 $0.24 Exterior Lighting Exterior Screw-in CFL 0.04 $0.00 4 6.00 $0.01 Exterior Lighting Exterior Screw-in Metal Halides 0.04 $0.00 4 3.36 $0.02 Exterior Lighting Exterior Screw-in LED 0.04 $0.03 12 - $0.07 Exterior Lighting HID Metal Halides - $0.00 6 1.00 $0.00 Exterior Lighting HID High Pressure Sodium 0.05 -$0.04 9 2.10 -$0.11 Exterior Lighting HID Low Pressure Sodium 0.06 $0.18 9 0.57 $0.42 Process Process Cooling/Refrigeration Standard - $0.00 10 1.00 $0.00 Process Process Cooling/Refrigeration Efficient 18.88 $5.59 10 1.23 $0.04 Process Process Heating Standard - $0.00 10 1.00 $0.00 Process Electrochemical Process Standard - $0.00 10 1.00 $0.00 Process Electrochemical Process Efficient 13.16 $2.64 10 1.20 $0.02 Machine Drive Less than 5 HP Standard - $0.00 15 - $0.00 Machine Drive Less than 5 HP High Efficiency 0.00 $0.06 15 - $0.99 Machine Drive Less than 5 HP Standard (2015) 0.01 $0.00 15 1.00 $0.00 Machine Drive Less than 5 HP Premium 0.04 $0.06 15 1.04 $0.11 Machine Drive Less than 5 HP High Efficiency (2015) - $0.00 0 - $0.00 Machine Drive Less than 5 HP Premium (2015) - $0.00 0 - $0.00 Machine Drive 5-24 HP Standard - $0.00 10 1.00 $0.00 Machine Drive 5-24 HP High 0.01 $0.02 10 1.01 $0.17 Machine Drive 5-24 HP Premium - $0.00 0 - $0.00 Machine Drive 25-99 HP Standard - $0.00 10 1.00 $0.00 Machine Drive 25-99 HP High 0.03 $0.02 10 1.01 $0.06 Machine Drive 25-99 HP Premium - $0.00 0 - $0.00 Machine Drive 100-249 HP Standard - $0.00 10 1.00 $0.00 Machine Drive 100-249 HP High 0.02 $0.02 10 1.01 $0.10 Machine Drive 100-249 HP Premium - $0.00 0 - $0.00 Machine Drive 250-499 HP Standard - $0.00 10 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1031 of 1125 C&I Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting C-55 End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Machine Drive 250-499 HP High 0.06 $0.02 10 1.01 $0.03 Machine Drive 250-499 HP Premium - $0.00 0 - $0.00 Machine Drive 500 and more HP Standard - $0.00 10 1.00 $0.00 Machine Drive 500 and more HP High 0.10 $0.02 10 1.01 $0.02 Machine Drive 500 and more HP Premium - $0.00 0 - $0.00 Miscellaneous Miscellaneous Miscellaneous - $0.00 5 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1032 of 1125 C&I Energy Efficiency Equipment and Measure Data C-56 www.enernoc.com Table C-18 Energy Efficiency Equipment Data, Electric— Extra Large Industrial, New Vintage, Idaho End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Cooling Central Chiller 0.75 kw/ton, COP 4.7 - $0.00 20 - $0.00 Cooling Central Chiller 0.60 kw/ton, COP 5.9 1.58 $0.33 20 1.10 $0.01 Cooling Central Chiller 0.58 kw/ton, COP 6.1 1.79 $0.66 20 0.97 $0.03 Cooling Central Chiller 0.55 kw/Ton, COP 6.4 2.11 $0.93 20 0.95 $0.03 Cooling Central Chiller 0.51 kw/ton, COP 6.9 2.53 $1.59 20 0.89 $0.04 Cooling Central Chiller 0.50 kw/Ton, COP 7.0 2.63 $1.92 20 0.86 $0.05 Cooling Central Chiller 0.48 kw/ton, COP 7.3 2.84 $2.25 20 0.83 $0.06 Cooling Central Chiller Variable Refrigerant Flow 3.67 $39.62 20 0.15 $0.76 Cooling RTU EER 9.2 - $0.00 16 - $0.00 Cooling RTU EER 10.1 0.56 $0.39 16 - $0.06 Cooling RTU EER 11.2 1.12 $0.74 16 1.00 $0.05 Cooling RTU EER 12.0 1.47 $1.23 16 0.92 $0.07 Cooling RTU Ductless VRF 1.79 $10.88 16 0.30 $0.50 Cooling Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00 Cooling Heat Pump EER 10.3, COP 3.2 0.39 $0.92 15 - $0.20 Cooling Heat Pump EER 11.0, COP 3.3 0.62 $2.75 15 1.00 $0.38 Cooling Heat Pump EER 11.7, COP 3.4 0.83 $3.66 15 0.95 $0.38 Cooling Heat Pump EER 12, COP 3.4 0.91 $4.58 15 0.90 $0.43 Cooling Heat Pump Ductless Mini-Split System 1.01 $26.86 20 0.45 $1.88 Space Heating Electric Resistance Standard - $0.00 25 1.00 $0.00 Space Heating Furnace Standard - $0.00 18 1.00 $0.00 Space Heating Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00 Space Heating Heat Pump EER 10.3, COP 3.2 0.13 $0.92 15 - $0.62 Space Heating Heat Pump EER 11.0, COP 3.3 0.25 $2.75 15 1.00 $0.96 Space Heating Heat Pump EER 11.7, COP 3.4 0.36 $3.66 15 0.95 $0.88 Space Heating Heat Pump EER 12, COP 3.4 0.47 $4.58 15 0.90 $0.85 Space Heating Heat Pump Ductless Mini-Split System 1.02 $26.86 20 0.45 $1.86 Space Heating Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00 Space Heating Heat Pump EER 10.3, COP 3.2 0.13 $0.92 15 - $0.62 Space Heating Heat Pump EER 11.0, COP 3.3 0.25 $2.75 15 1.00 $0.96 Space Heating Heat Pump EER 11.7, COP 3.4 0.36 $3.66 15 0.95 $0.88 Space Heating Heat Pump EER 12, COP 3.4 0.47 $4.58 15 0.90 $0.85 Space Heating Heat Pump Ductless Mini-Split System 1.02 $26.86 20 0.45 $1.86 Ventilation Ventilation Constant Volume - $0.00 15 1.00 $0.00 Ventilation Ventilation Variable Air Volume 13.69 $1.22 15 1.63 $0.01 Interior Lighting Interior Screw-in Incandescents - $0.00 1 - $0.00 Interior Lighting Interior Screw-in Infrared Halogen 0.21 $0.04 1 1.00 $0.18 Interior Lighting Interior Screw-in CFL 0.85 $0.02 4 5.65 $0.00 Interior Lighting Interior Screw-in LED 0.94 $0.52 12 - $0.06 Interior Lighting High Bay Fixtures Metal Halides - $0.00 6 1.00 $0.00 Interior Lighting High Bay Fixtures High Pressure Sodium 0.40 -$0.14 9 2.11 -$0.04 Interior Lighting High Bay Fixtures T8 0.40 -$0.28 6 4.58 -$0.13 Interior Lighting High Bay Fixtures T5 0.51 -$0.28 6 5.58 -$0.10 Interior Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00 Interior Lighting Linear Fluorescent T8 0.09 -$0.01 6 1.12 -$0.02 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1033 of 1125 C&I Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting C-57 End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Interior Lighting Linear Fluorescent Super T8 0.27 $0.08 6 0.89 $0.06 Interior Lighting Linear Fluorescent T5 0.28 $0.14 6 0.75 $0.09 Interior Lighting Linear Fluorescent LED 0.29 $1.21 15 - $0.36 Exterior Lighting Exterior Screw-in Incandescent - $0.00 1 - $0.00 Exterior Lighting Exterior Screw-in Infrared Halogen 0.01 $0.00 1 1.00 $0.24 Exterior Lighting Exterior Screw-in CFL 0.04 $0.00 4 6.00 $0.01 Exterior Lighting Exterior Screw-in Metal Halides 0.04 $0.00 4 3.36 $0.02 Exterior Lighting Exterior Screw-in LED 0.04 $0.03 12 - $0.07 Exterior Lighting HID Metal Halides - $0.00 6 1.00 $0.00 Exterior Lighting HID High Pressure Sodium 0.05 -$0.04 9 2.10 -$0.11 Exterior Lighting HID Low Pressure Sodium 0.06 $0.18 9 0.57 $0.42 Process Process Cooling/Refrigeration Standard - $0.00 10 1.00 $0.00 Process Process Cooling/Refrigeration Efficient 18.88 $5.59 10 1.23 $0.04 Process Process Heating Standard - $0.00 10 1.00 $0.00 Process Electrochemical Process Standard - $0.00 10 1.00 $0.00 Process Electrochemical Process Efficient 13.16 $2.64 10 1.20 $0.02 Machine Drive Less than 5 HP Standard - $0.00 15 - $0.00 Machine Drive Less than 5 HP High Efficiency 0.00 $0.06 15 - $0.99 Machine Drive Less than 5 HP Standard (2015) 0.01 $0.00 15 1.00 $0.00 Machine Drive Less than 5 HP Premium 0.04 $0.06 15 1.04 $0.11 Machine Drive Less than 5 HP High Efficiency (2015) - $0.00 0 - $0.00 Machine Drive Less than 5 HP Premium (2015) - $0.00 0 - $0.00 Machine Drive 5-24 HP Standard - $0.00 10 1.00 $0.00 Machine Drive 5-24 HP High 0.01 $0.02 10 1.01 $0.17 Machine Drive 5-24 HP Premium - $0.00 0 - $0.00 Machine Drive 25-99 HP Standard - $0.00 10 1.00 $0.00 Machine Drive 25-99 HP High 0.03 $0.02 10 1.01 $0.06 Machine Drive 25-99 HP Premium - $0.00 0 - $0.00 Machine Drive 100-249 HP Standard - $0.00 10 1.00 $0.00 Machine Drive 100-249 HP High 0.02 $0.02 10 1.01 $0.10 Machine Drive 100-249 HP Premium - $0.00 0 - $0.00 Machine Drive 250-499 HP Standard - $0.00 10 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1034 of 1125 C&I Energy Efficiency Equipment and Measure Data C-58 www.enernoc.com End Use Technology Efficiency Definition Savings (kWh/SQ FT/yr) Incremental Cost ($/SQ FT) Lifetime (Years) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Machine Drive 250-499 HP High 0.06 $0.02 10 1.01 $0.03 Machine Drive 250-499 HP Premium - $0.00 0 - $0.00 Machine Drive 500 and more HP Standard - $0.00 10 1.00 $0.00 Machine Drive 500 and more HP High 0.10 $0.02 10 1.01 $0.02 Machine Drive 500 and more HP Premium - $0.00 0 - $0.00 Miscellaneous Miscellaneous Miscellaneous - $0.00 5 1.00 $0.00 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1035 of 1125 C&I Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting C-59 Table C-19 Energy Efficiency Non-Equipment Data—Small/Medium Commercial, Existing Vintage, Washington Measure Base Saturation Applicability Lifetime (Years) Incremental Cost ($/SqFt) Savings (kWh/Sq Ft) BC Ratio (2015) Levelized Cost of Energy ($/kWh) RTU - Maintenance 14.0% 100.0% 4 $0.08 0.4 0.22 $0.060 RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 1.2 0.21 $0.061 Chiller - Chilled Water Reset 0.0% 0.0% 4 $0.86 0.4 0.03 $0.529 Chiller - Chilled Water Variable-Flow System 0.0% 0.0% 10 $0.86 0.1 0.02 $1.018 Chiller - VSD 0.0% 0.0% 20 $1.17 0.8 0.11 $0.105 Chiller - High Efficiency Cooling Tower Fans 0.0% 0.0% 10 $0.04 0.0 0.00 $10.961 Chiller - Condenser Water Temprature Reset 0.0% 0.0% 14 $0.87 0.4 0.07 $0.206 Cooling - Economizer Installation 51.8% 65.0% 15 $0.15 0.6 0.64 $0.020 Heat Pump - Maintenance 28.1% 100.0% 4 $0.03 0.9 1.42 $0.009 Insulation - Ducting 9.0% 100.0% 20 $0.41 0.2 0.36 $0.136 Repair and Sealing - Ducting 5.0% 50.0% 15 $0.38 0.7 0.47 $0.048 Energy Management System 34.8% 100.0% 14 $0.35 0.8 0.37 $0.040 Cooking - Exhaust Hoods with Sensor Control 1.0% 20.0% 10 $0.04 - - $0.000 Fans - Energy Efficient Motors 11.0% 100.0% 10 $0.05 0.1 0.25 $0.057 Fans - Variable Speed Control 10.9% 100.0% 10 $0.20 0.7 0.32 $0.033 Retrocommissioning - HVAC 15.0% 100.0% 4 $0.60 0.6 0.35 $0.280 Pumps - Variable Speed Control 0.0% 45.0% 10 $0.44 0.0 0.00 $5.336 Thermostat - Clock/Programmable 38.7% 50.0% 11 $0.11 0.3 0.32 $0.044 Insulation - Ceiling 19.0% 90.0% 20 $0.64 0.7 0.43 $0.066 Insulation - Radiant Barrier 10.3% 25.0% 20 $0.26 0.4 0.45 $0.050 Roofs - High Reflectivity 3.3% 100.0% 15 $0.18 0.2 0.21 $0.063 Windows - High Efficiency 66.1% 100.0% 20 $0.44 1.0 0.52 $0.032 Interior Lighting - Central Lighting Controls 81.2% 100.0% 8 $0.65 0.2 0.02 $0.581 Interior Lighting - Photocell Controlled T8 Dimming Ballasts 0.9% 60.0% 8 $0.50 0.8 0.14 $0.085 Exterior Lighting - Daylighting Controls 1.6% 100.0% 8 $0.11 0.5 0.28 $0.029 Interior Fluorescent - Bi-Level Fixture w/Occupancy Sensor 10.0% 30.0% 8 $0.50 0.3 0.06 $0.212 Interior Fluorescent - High Bay Fixtures 10.0% 30.0% 11 $0.70 1.7 0.21 $0.046 Interior Lighting - Occupancy Sensors 7.1% 60.0% 8 $0.20 0.2 0.14 $0.179 Exterior Lighting - Photovoltaic Installation 5.0% 25.0% 5 $0.92 0.6 0.03 $0.307 Interior Screw-in - Task Lighting 25.0% 100.0% 5 $0.24 0.1 0.02 $0.500 Interior Lighting - Time Clocks and Timers 9.1% 75.0% 8 $0.20 0.1 0.07 $0.357 Water Heater - Faucet Aerators/Low Flow Nozzles 50.5% 100.0% 9 $0.01 0.1 0.68 $0.016 Water Heater - Pipe Insulation 45.6% 100.0% 15 $0.28 0.1 0.04 $0.216 Water Heater - High Efficiency Circulation Pump 0.0% 0.0% 10 $0.11 1.4 1.11 $0.009 Water Heater - Tank Blanket/Insulation 68.0% 100.0% 10 $0.02 0.1 0.44 $0.024 Water Heater - Thermostat Setback 5.0% 100.0% 10 $0.11 0.1 0.06 $0.163 Refrigeration - Anti-Sweat Heater/Auto Door Closer 0.0% 100.0% 16 $0.20 0.1 0.03 $0.264 Refrigeration - Floating Head Pressure 17.9% 50.0% 16 $0.35 0.0 0.01 $1.061 Refrigeration - Door Gasket Replacement 5.0% 100.0% 8 $0.10 0.0 0.01 $0.710 Insulation - Bare Suction Lines 5.0% 100.0% 8 $0.10 0.0 0.02 $0.525 Refrigeration - Night Covers 5.0% 100.0% 8 $0.05 0.0 0.02 $2.859 Refrigeration - Strip Curtain 5.0% 56.3% 4 $0.00 - - $0.000 Vending Machine - Controller 2.0% 10.0% 10 $0.27 0.0 0.01 $0.701 LED Exit Lighting 46.9% 90.0% 10 $0.00 0.0 4.04 $0.006 Retrocommissioning - Lighting 5.0% 100.0% 5 $0.10 0.3 0.15 $0.081 Refrigeration - High Efficiency Case 12.0% 56.0% 6 $0.04 0.0 0.01 $1.656 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1036 of 1125 C&I Energy Efficiency Equipment and Measure Data C-60 www.enernoc.com Measure Base Saturation Applicability Lifetime (Years) Incremental Cost ($/SqFt) Savings (kWh/Sq Ft) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Lighting Exterior Lighting - Cold Cathode Lighting 14.6% 50.0% 5 $0.00 0.4 16.94 $0.001 Laundry - High Efficiency Clothes Washer 6.9% 10.0% 10 $0.00 0.0 4.82 $0.002 Interior Lighting - Hotel Guestroom Controls 0.0% 0.0% 8 $0.14 0.1 0.04 $0.211 Miscellaneous - Energy Star Water Cooler 5.0% 100.0% 8 $0.00 0.0 0.27 $0.044 Interior Lighting - Skylights 0.0% 0.0% 0 $0.00 0.2 1.00 $0.000 Ventilation - Demand Control Ventilation 6.4% 20.0% 10 $0.04 0.1 0.52 $0.065 Office Equipment - Smart Power Strips 15.4% 30.0% 7 $0.00 0.4 286.03 $0.000 Strategic Energy Management 0.0% 0.0% 3 $0.00 - 6.00 $0.000 Refrigeration - Multiplex - Floating section Pressure - Air-cooled Cond. 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Refrigeration - Multiplex Controls - Floating section Pressure - Evap. Cond. 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Refrigeration - Multiplex - Eff. Air- cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Refrigeration - Multiplex - Eff. Water- cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000 RTU - Maintenance 14.0% 100.0% 4 $0.08 0.4 0.22 $0.060 RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 1.2 0.21 $0.061 Chiller - Chilled Water Reset 0.0% 0.0% 4 $0.86 0.4 0.03 $0.529 Chiller - Chilled Water Variable-Flow System 0.0% 0.0% 10 $0.86 0.1 0.02 $1.018 Chiller - VSD 0.0% 0.0% 20 $1.17 0.8 0.11 $0.105 Chiller - High Efficiency Cooling Tower Fans 0.0% 0.0% 10 $0.04 0.0 0.00 $10.961 Chiller - Condenser Water Temprature Reset 0.0% 0.0% 14 $0.87 0.4 0.07 $0.206 Cooling - Economizer Installation 51.8% 65.0% 15 $0.15 0.6 0.64 $0.020 Heat Pump - Maintenance 28.1% 100.0% 4 $0.03 0.9 1.42 $0.009 Insulation - Ducting 9.0% 100.0% 20 $0.41 0.2 0.36 $0.136 Repair and Sealing - Ducting 5.0% 50.0% 15 $0.38 0.7 0.47 $0.048 Energy Management System 34.8% 100.0% 14 $0.35 0.8 0.37 $0.040 Cooking - Exhaust Hoods with Sensor Control 1.0% 20.0% 10 $0.04 - - $0.000 Fans - Energy Efficient Motors 11.0% 100.0% 10 $0.05 0.1 0.25 $0.057 Fans - Variable Speed Control 10.9% 100.0% 10 $0.20 0.7 0.32 $0.033 Retrocommissioning - HVAC 15.0% 100.0% 4 $0.60 0.6 0.35 $0.280 Pumps - Variable Speed Control 0.0% 45.0% 10 $0.44 0.0 0.00 $5.336 Thermostat - Clock/Programmable 38.7% 50.0% 11 $0.11 0.3 0.32 $0.044 Insulation - Ceiling 19.0% 90.0% 20 $0.64 0.7 0.43 $0.066 Insulation - Radiant Barrier 10.3% 25.0% 20 $0.26 0.4 0.45 $0.050 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1037 of 1125 C&I Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting C-61 Table C-20 Energy Efficiency Non-Equipment Data— Small/ Medium Commercial, New Vintage, Washington Measure Base Saturation Applicability Lifetime (Years) Incremental Cost ($/SqFt) Savings (kWh/SqFt) BC Ratio (2015) Levelized Cost of Energy ($/kWh) RTU - Maintenance 14.0% 100.0% 4 $0.08 0.2 0.14 $0.102 RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 1.0 0.18 $0.073 Chiller - Chilled Water Reset 0.0% 0.0% 4 $0.86 0.4 0.02 $0.641 Chiller - Chilled Water Variable-Flow System 0.0% 0.0% 10 $0.86 0.1 0.02 $0.823 Chiller - VSD 0.0% 0.0% 20 $1.17 0.7 0.10 $0.122 Chiller - High Efficiency Cooling Tower Fans 0.0% 0.0% 10 $0.04 0.0 0.00 $8.973 Chiller - Condenser Water Temprature Reset 0.0% 0.0% 14 $0.87 0.3 0.06 $0.247 Cooling - Economizer Installation 51.8% 65.0% 15 $0.15 - 0.28 $0.000 Heat Pump - Maintenance 28.1% 100.0% 4 $0.03 0.5 0.96 $0.015 Insulation - Ducting 9.0% 50.0% 20 $0.41 - 0.32 $0.000 Energy Management System 27.7% 100.0% 14 $0.35 1.9 0.63 $0.017 Cooking - Exhaust Hoods with Sensor Control 1.0% 20.0% 10 $0.04 - - $0.000 Fans - Energy Efficient Motors 11.0% 100.0% 10 $0.05 0.1 0.17 $0.067 Fans - Variable Speed Control 8.0% 100.0% 10 $0.20 0.5 0.25 $0.044 Pumps - Variable Speed Control 5.0% 45.0% 10 $0.44 0.0 0.00 $5.075 Thermostat - Clock/Programmable 34.0% 50.0% 11 $0.11 1.0 0.86 $0.012 Insulation - Ceiling 15.3% 90.0% 20 $0.16 - 0.38 $0.000 Insulation - Radiant Barrier 7.0% 25.0% 20 $0.26 - 0.30 $0.000 Roofs - High Reflectivity 5.0% 100.0% 15 $0.09 - 0.07 $0.000 Windows - High Efficiency 60.5% 100.0% 20 $0.35 - 0.31 $0.000 Interior Lighting - Central Lighting Controls 81.2% 100.0% 8 $0.65 - - $0.000 Interior Lighting - Photocell Controlled T8 Dimming Ballasts 0.9% 60.0% 8 $0.38 0.7 0.16 $0.074 Exterior Lighting - Daylighting Controls 10.0% 100.0% 8 $0.09 - 0.00 $0.000 Interior Fluorescent - Bi-Level Fixture w/Occupancy Sensor 10.0% 30.0% 8 $0.50 0.3 0.05 $0.243 Interior Fluorescent - High Bay Fixtures 10.0% 30.0% 11 $0.70 1.5 0.20 $0.052 Interior Lighting - Occupancy Sensors 7.1% 60.0% 8 $0.20 - 0.07 $0.000 Exterior Lighting - Photovoltaic Installation 5.0% 25.0% 5 $0.92 - - $0.000 Interior Screw-in - Task Lighting 25.0% 100.0% 5 $0.24 0.1 0.03 $0.507 Interior Lighting - Time Clocks and Timers 9.1% 75.0% 8 $0.20 - 0.05 $0.000 Water Heater - Faucet Aerators/Low Flow Nozzles 50.5% 100.0% 9 $0.01 0.1 0.67 $0.017 Water Heater - Pipe Insulation 45.6% 100.0% 15 $0.28 0.1 0.04 $0.227 Water Heater - High Efficiency Circulation Pump 0.0% 0.0% 10 $0.11 1.3 1.09 $0.010 Water Heater - Tank Blanket/Insulation 40.4% 100.0% 10 $0.02 0.0 0.21 $0.051 Water Heater - Thermostat Setback 10.0% 100.0% 10 $0.11 0.1 0.06 $0.174 Refrigeration - Anti-Sweat Heater/Auto Door Closer 0.0% 100.0% 16 $0.20 0.1 0.03 $0.289 Refrigeration - Floating Head Pressure 17.9% 50.0% 16 $0.35 - 0.00 $0.000 Refrigeration - Door Gasket Replacement 5.0% 100.0% 8 $0.10 0.0 0.01 $1.014 Insulation - Bare Suction Lines 5.0% 100.0% 8 $0.10 - - $0.000 Refrigeration - Night Covers 5.0% 100.0% 8 $0.05 0.0 0.02 $3.122 Refrigeration - Strip Curtain 5.0% 56.3% 4 $0.00 - - $0.000 Vending Machine - Controller 2.0% 10.0% 10 $0.27 0.0 0.01 $0.804 LED Exit Lighting 91.2% 90.0% 10 $0.00 0.0 5.42 $0.006 Refrigeration - High Efficiency Case 26.1% 56.0% 6 $0.02 0.0 0.38 $0.559 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1038 of 1125 C&I Energy Efficiency Equipment and Measure Data C-62 www.enernoc.com Measure Base Saturation Applicability Lifetime (Years) Incremental Cost ($/SqFt) Savings (kWh/SqFt) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Lighting Exterior Lighting - Cold Cathode Lighting 14.6% 50.0% 5 $0.00 0.3 20.03 $0.001 Laundry - High Efficiency Clothes Washer 6.9% 10.0% 10 $0.00 0.0 5.78 $0.002 Interior Lighting - Hotel Guestroom Controls 0.0% 0.0% 8 $0.14 0.1 0.06 $0.213 Miscellaneous - Energy Star Water Cooler 5.0% 100.0% 8 $0.00 0.0 0.33 $0.037 Interior Lighting - Skylights 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Ventilation - Demand Control Ventilation 12.9% 20.0% 10 $0.04 - 0.38 $0.000 Office Equipment - Smart Power Strips 15.4% 30.0% 7 $0.00 0.5 393.51 $0.000 Strategic Energy Management 0.0% 0.0% 3 $0.00 - 6.00 $0.000 Refrigeration - Multiplex - Floating section Pressure - Air-cooled Cond. 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Refrigeration - Multiplex Controls - Floating section Pressure - Evap. Cond. 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Refrigeration - Multiplex - Eff. Air- cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Refrigeration - Multiplex - Eff. Water-cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000 RTU - Maintenance 14.0% 100.0% 4 $0.08 0.2 0.14 $0.102 RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 1.0 0.18 $0.073 Chiller - Chilled Water Reset 0.0% 0.0% 4 $0.86 0.4 0.02 $0.641 Chiller - Chilled Water Variable-Flow System 0.0% 0.0% 10 $0.86 0.1 0.02 $0.823 Chiller - VSD 0.0% 0.0% 20 $1.17 0.7 0.10 $0.122 Chiller - High Efficiency Cooling Tower Fans 0.0% 0.0% 10 $0.04 0.0 0.00 $8.973 Chiller - Condenser Water Temprature Reset 0.0% 0.0% 14 $0.87 0.3 0.06 $0.247 Cooling - Economizer Installation 51.8% 65.0% 15 $0.15 - 0.28 $0.000 Heat Pump - Maintenance 28.1% 100.0% 4 $0.03 0.5 0.96 $0.015 Insulation - Ducting 9.0% 50.0% 20 $0.41 - 0.32 $0.000 Energy Management System 27.7% 100.0% 14 $0.35 1.9 0.63 $0.017 Cooking - Exhaust Hoods with Sensor Control 1.0% 20.0% 10 $0.04 - - $0.000 Fans - Energy Efficient Motors 11.0% 100.0% 10 $0.05 0.1 0.17 $0.067 Fans - Variable Speed Control 8.0% 100.0% 10 $0.20 0.5 0.25 $0.044 Pumps - Variable Speed Control 5.0% 45.0% 10 $0.44 0.0 0.00 $5.075 Thermostat - Clock/Programmable 34.0% 50.0% 11 $0.11 1.0 0.86 $0.012 Insulation - Ceiling 15.3% 90.0% 20 $0.16 - 0.38 $0.000 Insulation - Radiant Barrier 7.0% 25.0% 20 $0.26 - 0.30 $0.000 Roofs - High Reflectivity 5.0% 100.0% 15 $0.09 - 0.07 $0.000 Windows - High Efficiency 60.5% 100.0% 20 $0.35 - 0.31 $0.000 Interior Lighting - Central Lighting Controls 81.2% 100.0% 8 $0.65 - - $0.000 Interior Lighting - Photocell Controlled T8 Dimming Ballasts 0.9% 60.0% 8 $0.38 0.7 0.16 $0.074 Exterior Lighting - Daylighting Controls 10.0% 100.0% 8 $0.09 - 0.00 $0.000 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1039 of 1125 C&I Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting C-63 Table C-21 Energy Efficiency Non-Equipment Data— Small/Medium Commercial, Existing Vintage, Idaho Measure Base Saturation Applicability Lifetime (Years) Incremental Cost ($/SqFt) Savings (kWh/SqFt) BC Ratio (2015) Levelized Cost of Energy ($/kWh) RTU - Maintenance 31.3% 100.0% 4 $0.08 0.4 0.22 $0.060 RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 1.2 0.21 $0.061 Chiller - Chilled Water Reset 0.0% 0.0% 4 $0.86 0.4 0.03 $0.529 Chiller - Chilled Water Variable-Flow System 0.0% 0.0% 10 $0.86 0.1 0.02 $1.018 Chiller - VSD 0.0% 0.0% 20 $1.17 0.8 0.11 $0.105 Chiller - High Efficiency Cooling Tower Fans 0.0% 0.0% 10 $0.04 0.0 0.00 $10.961 Chiller - Condenser Water Temprature Reset 0.0% 0.0% 14 $0.87 0.4 0.07 $0.206 Cooling - Economizer Installation 51.8% 65.0% 15 $0.15 0.1 0.36 $0.140 Heat Pump - Maintenance 28.1% 100.0% 4 $0.03 0.9 1.41 $0.009 Insulation - Ducting 9.0% 100.0% 20 $0.41 0.0 0.31 $1.480 Repair and Sealing - Ducting 5.0% 50.0% 15 $0.38 0.1 0.32 $0.586 Energy Management System 34.8% 100.0% 14 $0.35 4.4 1.28 $0.007 Cooking - Exhaust Hoods with Sensor Control 1.0% 20.0% 10 $0.04 - - $0.000 Fans - Energy Efficient Motors 28.9% 100.0% 10 $0.05 0.5 0.98 $0.011 Fans - Variable Speed Control 26.5% 100.0% 10 $0.20 0.7 0.31 $0.033 Retrocommissioning - HVAC 15.0% 100.0% 4 $0.60 0.1 0.31 $1.917 Pumps - Variable Speed Control 0.0% 45.0% 10 $0.44 0.0 0.00 $5.336 Thermostat - Clock/Programmable 38.7% 50.0% 11 $0.11 2.8 2.30 $0.004 Insulation - Ceiling 10.0% 90.0% 20 $0.64 0.1 0.35 $0.580 Insulation - Radiant Barrier 7.0% 25.0% 20 $0.26 0.0 0.33 $0.567 Roofs - High Reflectivity 4.5% 100.0% 15 $0.18 0.0 0.12 $0.434 Windows - High Efficiency 60.5% 100.0% 20 $0.44 0.1 0.33 $0.392 Interior Lighting - Central Lighting Controls 81.2% 100.0% 8 $0.65 0.1 0.01 $1.389 Interior Lighting - Photocell Controlled T8 Dimming Ballasts 0.9% 60.0% 8 $0.50 0.8 0.14 $0.085 Exterior Lighting - Daylighting Controls 1.6% 100.0% 8 $0.11 0.1 0.07 $0.121 Interior Fluorescent - Bi-Level Fixture w/Occupancy Sensor 10.0% 30.0% 8 $0.50 0.3 0.06 $0.212 Interior Fluorescent - High Bay Fixtures 15.4% 30.0% 11 $0.70 1.7 0.21 $0.046 Interior Lighting - Occupancy Sensors 18.3% 60.0% 8 $0.20 0.1 0.10 $0.427 Exterior Lighting - Photovoltaic Installation 5.0% 25.0% 5 $0.92 0.2 0.01 $1.278 Interior Screw-in - Task Lighting 25.0% 100.0% 5 $0.24 0.1 0.02 $0.500 Interior Lighting - Time Clocks and Timers 9.1% 75.0% 8 $0.20 0.0 0.05 $0.855 Water Heater - Faucet Aerators/Low Flow Nozzles 50.5% 100.0% 9 $0.01 0.1 0.67 $0.016 Water Heater - Pipe Insulation 45.6% 100.0% 15 $0.28 0.1 0.04 $0.216 Water Heater - High Efficiency Circulation Pump 0.0% 0.0% 10 $0.11 1.4 1.10 $0.009 Water Heater - Tank Blanket/Insulation 68.0% 100.0% 10 $0.02 0.1 0.43 $0.024 Water Heater - Thermostat Setback 5.0% 100.0% 10 $0.11 0.1 0.06 $0.163 Refrigeration - Anti-Sweat Heater/Auto Door Closer 0.0% 100.0% 16 $0.20 0.1 0.03 $0.264 Refrigeration - Floating Head Pressure 17.9% 50.0% 16 $0.35 - 0.00 $0.000 Refrigeration - Door Gasket Replacement 5.0% 100.0% 8 $0.10 0.0 0.01 $0.710 Insulation - Bare Suction Lines 5.0% 100.0% 8 $0.10 - - $0.000 Refrigeration - Night Covers 5.0% 100.0% 8 $0.05 0.0 0.02 $2.859 Refrigeration - Strip Curtain 5.0% 56.3% 4 $0.00 - - $0.000 Vending Machine - Controller 2.0% 10.0% 10 $0.27 0.0 0.01 $0.701 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1040 of 1125 C&I Energy Efficiency Equipment and Measure Data C-64 www.enernoc.com Measure Base Saturation Applicability Lifetime (Years) Incremental Cost ($/SqFt) Savings (kWh/SqFt) BC Ratio (2015) Levelized Cost of Energy ($/kWh) LED Exit Lighting 46.9% 90.0% 10 $0.00 0.0 3.34 $0.006 Retrocommissioning - Lighting 24.1% 100.0% 5 $0.10 0.1 0.05 $0.233 Refrigeration - High Efficiency Case Lighting 12.0% 56.0% 6 $0.04 0.0 0.01 $1.909 Exterior Lighting - Cold Cathode Lighting 14.6% 50.0% 5 $0.00 0.3 15.57 $0.001 Laundry - High Efficiency Clothes Washer 6.9% 10.0% 10 $0.00 0.0 4.79 $0.002 Interior Lighting - Hotel Guestroom Controls 0.0% 0.0% 8 $0.14 0.1 0.03 $0.211 Miscellaneous - Energy Star Water Cooler 24.1% 100.0% 8 $0.00 0.0 0.27 $0.044 Interior Lighting - Skylights 0.0% 0.0% 0 $0.00 0.1 1.00 $0.000 Ventilation - Demand Control Ventilation 10.2% 20.0% 10 $0.04 0.0 0.42 $0.134 Office Equipment - Smart Power Strips 15.4% 30.0% 7 $0.00 0.4 285.77 $0.000 Strategic Energy Management 0.0% 0.0% 3 $0.00 - 6.00 $0.000 Refrigeration - Multiplex - Floating section Pressure - Air-cooled Cond. 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Refrigeration - Multiplex Controls - Floating section Pressure - Evap. Cond. 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Refrigeration - Multiplex - Eff. Air- cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Refrigeration - Multiplex - Eff. Water-cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000 RTU - Maintenance 31.3% 100.0% 4 $0.08 0.4 0.22 $0.060 RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 1.2 0.21 $0.061 Chiller - Chilled Water Reset 0.0% 0.0% 4 $0.86 0.4 0.03 $0.529 Chiller - Chilled Water Variable-Flow System 0.0% 0.0% 10 $0.86 0.1 0.02 $1.018 Chiller - VSD 0.0% 0.0% 20 $1.17 0.8 0.11 $0.105 Chiller - High Efficiency Cooling Tower Fans 0.0% 0.0% 10 $0.04 0.0 0.00 $10.961 Chiller - Condenser Water Temprature Reset 0.0% 0.0% 14 $0.87 0.4 0.07 $0.206 Cooling - Economizer Installation 51.8% 65.0% 15 $0.15 0.1 0.36 $0.140 Heat Pump - Maintenance 28.1% 100.0% 4 $0.03 0.9 1.41 $0.009 Insulation - Ducting 9.0% 100.0% 20 $0.41 0.0 0.31 $1.480 Repair and Sealing - Ducting 5.0% 50.0% 15 $0.38 0.1 0.32 $0.586 Energy Management System 34.8% 100.0% 14 $0.35 4.4 1.28 $0.007 Cooking - Exhaust Hoods with Sensor Control 1.0% 20.0% 10 $0.04 - - $0.000 Fans - Energy Efficient Motors 28.9% 100.0% 10 $0.05 0.5 0.98 $0.011 Fans - Variable Speed Control 26.5% 100.0% 10 $0.20 0.7 0.31 $0.033 Retrocommissioning - HVAC 15.0% 100.0% 4 $0.60 0.1 0.31 $1.917 Pumps - Variable Speed Control 0.0% 45.0% 10 $0.44 0.0 0.00 $5.336 Thermostat - Clock/Programmable 38.7% 50.0% 11 $0.11 2.8 2.30 $0.004 Insulation - Ceiling 10.0% 90.0% 20 $0.64 0.1 0.35 $0.580 Insulation - Radiant Barrier 7.0% 25.0% 20 $0.26 0.0 0.33 $0.567 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1041 of 1125 C&I Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting C-65 Table C-22 Energy Efficiency Non-Equipment Data— Small/ Medium Commercial, New Vintage, Idaho Measure Base Saturation Applicability Lifetime (Years) Incremental Cost ($/SqFt) Savings (kWh/SqFt) BC Ratio (2015) Levelized Cost of Energy ($/kWh) RTU - Maintenance 21.4% 100.0% 4 $0.08 0.2 0.14 $0.102 RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 1.0 0.18 $0.073 Chiller - Chilled Water Reset 0.0% 0.0% 4 $0.86 0.4 0.02 $0.641 Chiller - Chilled Water Variable-Flow System 0.0% 0.0% 10 $0.86 0.1 0.02 $0.823 Chiller - VSD 0.0% 0.0% 20 $1.17 0.7 0.09 $0.122 Chiller - High Efficiency Cooling Tower Fans 0.0% 0.0% 10 $0.04 0.0 0.00 $8.973 Chiller - Condenser Water Temprature Reset 0.0% 0.0% 14 $0.87 0.3 0.06 $0.247 Cooling - Economizer Installation 51.8% 65.0% 15 $0.15 - 0.28 $0.000 Heat Pump - Maintenance 28.1% 100.0% 4 $0.03 0.5 0.96 $0.015 Insulation - Ducting 9.0% 50.0% 20 $0.41 - 0.32 $0.000 Energy Management System 34.8% 100.0% 14 $0.35 2.2 0.73 $0.014 Cooking - Exhaust Hoods with Sensor Control 1.0% 20.0% 10 $0.04 - - $0.000 Fans - Energy Efficient Motors 28.9% 100.0% 10 $0.05 0.1 0.21 $0.067 Fans - Variable Speed Control 50.5% 100.0% 10 $0.20 0.5 0.25 $0.044 Pumps - Variable Speed Control 5.0% 45.0% 10 $0.44 0.0 0.00 $5.075 Thermostat - Clock/Programmable 34.0% 50.0% 11 $0.11 1.4 1.19 $0.009 Insulation - Ceiling 21.5% 90.0% 20 $0.16 - 0.38 $0.000 Insulation - Radiant Barrier 7.0% 25.0% 20 $0.26 - 0.30 $0.000 Roofs - High Reflectivity 5.0% 100.0% 15 $0.09 - 0.07 $0.000 Windows - High Efficiency 60.5% 100.0% 20 $0.35 - 0.31 $0.000 Interior Lighting - Central Lighting Controls 81.2% 100.0% 8 $0.65 - - $0.000 Interior Lighting - Photocell Controlled T8 Dimming Ballasts 0.9% 60.0% 8 $0.38 0.7 0.16 $0.074 Exterior Lighting - Daylighting Controls 10.0% 100.0% 8 $0.09 - 0.00 $0.000 Interior Fluorescent - Bi-Level Fixture w/Occupancy Sensor 10.0% 30.0% 8 $0.50 0.3 0.05 $0.243 Interior Fluorescent - High Bay Fixtures 13.7% 30.0% 11 $0.70 1.5 0.19 $0.052 Interior Lighting - Occupancy Sensors 11.9% 60.0% 8 $0.20 - 0.07 $0.000 Exterior Lighting - Photovoltaic Installation 5.0% 25.0% 5 $0.92 - - $0.000 Interior Screw-in - Task Lighting 25.0% 100.0% 5 $0.24 0.1 0.03 $0.507 Interior Lighting - Time Clocks and Timers 9.1% 75.0% 8 $0.20 - 0.05 $0.000 Water Heater - Faucet Aerators/Low Flow Nozzles 50.5% 100.0% 9 $0.01 0.1 0.66 $0.017 Water Heater - Pipe Insulation 45.6% 100.0% 15 $0.28 0.1 0.04 $0.227 Water Heater - High Efficiency Circulation Pump 0.0% 0.0% 10 $0.11 1.3 1.08 $0.010 Water Heater - Tank Blanket/Insulation 68.0% 100.0% 10 $0.02 0.0 0.21 $0.051 Water Heater - Thermostat Setback 10.0% 100.0% 10 $0.11 0.1 0.06 $0.174 Refrigeration - Anti-Sweat Heater/Auto Door Closer 0.0% 100.0% 16 $0.20 0.1 0.03 $0.289 Refrigeration - Floating Head Pressure 17.9% 50.0% 16 $0.35 0.1 0.03 $0.323 Refrigeration - Door Gasket Replacement 5.0% 100.0% 8 $0.10 0.0 0.01 $1.014 Insulation - Bare Suction Lines 5.0% 100.0% 8 $0.10 0.1 0.08 $0.160 Refrigeration - Night Covers 5.0% 100.0% 8 $0.05 0.0 0.02 $3.122 Refrigeration - Strip Curtain 5.0% 56.3% 4 $0.00 - - $0.000 Vending Machine - Controller 2.0% 10.0% 10 $0.27 0.0 0.01 $0.804 LED Exit Lighting 91.2% 90.0% 10 $0.00 0.0 5.18 $0.006 Refrigeration - High Efficiency Case 30.0% 56.0% 6 $0.02 0.0 0.32 $0.292 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1042 of 1125 C&I Energy Efficiency Equipment and Measure Data C-66 www.enernoc.com Measure Base Saturation Applicability Lifetime (Years) Incremental Cost ($/SqFt) Savings (kWh/SqFt) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Lighting Exterior Lighting - Cold Cathode Lighting 14.6% 50.0% 5 $0.00 0.3 18.13 $0.001 Laundry - High Efficiency Clothes Washer 6.9% 10.0% 10 $0.00 0.0 5.75 $0.002 Interior Lighting - Hotel Guestroom Controls 0.0% 0.0% 8 $0.14 0.1 0.05 $0.213 Miscellaneous - Energy Star Water Cooler 11.9% 100.0% 8 $0.00 0.0 0.33 $0.037 Interior Lighting - Skylights 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Ventilation - Demand Control Ventilation 19.7% 20.0% 10 $0.04 - 0.38 $0.000 Office Equipment - Smart Power Strips 15.4% 30.0% 7 $0.00 0.3 215.34 $0.000 Strategic Energy Management 0.0% 0.0% 3 $0.00 - 6.00 $0.000 Refrigeration - Multiplex - Floating section Pressure - Air-cooled Cond. 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Refrigeration - Multiplex Controls - Floating section Pressure - Evap. Cond. 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Refrigeration - Multiplex - Eff. Air- cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Refrigeration - Multiplex - Eff. Water-cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000 RTU - Maintenance 21.4% 100.0% 4 $0.08 0.2 0.14 $0.102 RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 1.0 0.18 $0.073 Chiller - Chilled Water Reset 0.0% 0.0% 4 $0.86 0.4 0.02 $0.641 Chiller - Chilled Water Variable-Flow System 0.0% 0.0% 10 $0.86 0.1 0.02 $0.823 Chiller - VSD 0.0% 0.0% 20 $1.17 0.7 0.09 $0.122 Chiller - High Efficiency Cooling Tower Fans 0.0% 0.0% 10 $0.04 0.0 0.00 $8.973 Chiller - Condenser Water Temprature Reset 0.0% 0.0% 14 $0.87 0.3 0.06 $0.247 Cooling - Economizer Installation 51.8% 65.0% 15 $0.15 - 0.28 $0.000 Heat Pump - Maintenance 28.1% 100.0% 4 $0.03 0.5 0.96 $0.015 Insulation - Ducting 9.0% 50.0% 20 $0.41 - 0.32 $0.000 Energy Management System 34.8% 100.0% 14 $0.35 2.2 0.73 $0.014 Cooking - Exhaust Hoods with Sensor Control 1.0% 20.0% 10 $0.04 - - $0.000 Fans - Energy Efficient Motors 28.9% 100.0% 10 $0.05 0.1 0.21 $0.067 Fans - Variable Speed Control 50.5% 100.0% 10 $0.20 0.5 0.25 $0.044 Pumps - Variable Speed Control 5.0% 45.0% 10 $0.44 0.0 0.00 $5.075 Thermostat - Clock/Programmable 34.0% 50.0% 11 $0.11 1.4 1.19 $0.009 Insulation - Ceiling 21.5% 90.0% 20 $0.16 - 0.38 $0.000 Insulation - Radiant Barrier 7.0% 25.0% 20 $0.26 - 0.30 $0.000 Roofs - High Reflectivity 5.0% 100.0% 15 $0.09 - 0.07 $0.000 Windows - High Efficiency 60.5% 100.0% 20 $0.35 - 0.31 $0.000 Interior Lighting - Central Lighting Controls 81.2% 100.0% 8 $0.65 - - $0.000 Interior Lighting - Photocell Controlled T8 Dimming Ballasts 0.9% 60.0% 8 $0.38 0.7 0.16 $0.074 Exterior Lighting - Daylighting Controls 10.0% 100.0% 8 $0.09 - 0.00 $0.000 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1043 of 1125 C&I Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting C-67 Table C-23 Energy Efficiency Non-Equipment Data— Large Commercial, Existing Vintage, Washington Measure Base Saturation Applicability Lifetime (Years) Incremental Cost ($/SqFt) Savings (kWh/SqFt) BC Ratio (2015) Levelized Cost of Energy ($/kWh) RTU - Maintenance 27.0% 100.0% 4 $0.06 0.4 0.30 $0.044 RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 1.3 0.12 $0.060 Chiller - Chilled Water Reset 15.0% 100.0% 4 $0.18 0.4 0.11 $0.120 Chiller - Chilled Water Variable-Flow System 30.0% 45.0% 10 $0.18 0.1 0.04 $0.226 Chiller - VSD 15.0% 88.2% 20 $1.17 0.7 0.05 $0.117 Chiller - High Efficiency Cooling Tower Fans 15.0% 43.5% 10 $0.04 0.0 0.00 $11.820 Chiller - Condenser Water Temprature Reset 5.0% 100.0% 14 $0.18 0.4 0.17 $0.046 Cooling - Economizer Installation 51.6% 65.0% 15 $0.15 0.8 0.47 $0.015 Heat Pump - Maintenance 28.1% 100.0% 4 $0.06 0.8 0.61 $0.021 Insulation - Ducting 8.0% 100.0% 20 $0.41 0.0 0.31 $1.046 Repair and Sealing - Ducting 5.0% 50.0% 15 $0.38 0.1 0.32 $0.421 Energy Management System 44.0% 100.0% 14 $0.35 2.5 0.68 $0.013 Cooking - Exhaust Hoods with Sensor Control 1.0% 15.0% 10 $0.04 - - $0.000 Fans - Energy Efficient Motors 11.0% 100.0% 10 $0.05 0.1 0.17 $0.072 Fans - Variable Speed Control 2.0% 100.0% 10 $0.20 0.6 0.27 $0.040 Retrocommissioning - HVAC 15.0% 100.0% 4 $0.30 0.4 0.37 $0.216 Pumps - Variable Speed Control 0.0% 45.0% 10 $0.13 0.0 0.01 $1.381 Thermostat - Clock/Programmable 33.0% 50.0% 11 $0.11 0.8 0.65 $0.015 Insulation - Ceiling 9.0% 40.0% 20 $0.85 0.4 0.34 $0.152 Insulation - Radiant Barrier 7.0% 25.0% 20 $0.26 0.0 0.31 $0.521 Roofs - High Reflectivity 1.5% 100.0% 15 $0.08 0.1 0.07 $0.109 Windows - High Efficiency 71.9% 100.0% 20 $0.88 0.2 0.32 $0.385 Interior Lighting - Central Lighting Controls 85.7% 100.0% 8 $0.65 0.2 0.03 $0.384 Interior Lighting - Photocell Controlled T8 Dimming Ballasts 0.9% 60.0% 8 $0.45 0.8 0.15 $0.078 Exterior Lighting - Daylighting Controls 1.6% 25.0% 8 $0.29 0.1 0.02 $0.549 Interior Fluorescent - Bi-Level Fixture w/Occupancy Sensor 10.0% 30.0% 8 $0.40 0.3 0.07 $0.173 Interior Fluorescent - High Bay Fixtures 10.0% 30.0% 11 $0.63 1.6 0.24 $0.042 Interior Lighting - Occupancy Sensors 12.6% 60.0% 8 $0.20 0.2 0.16 $0.118 Exterior Lighting - Photovoltaic Installation 5.0% 25.0% 5 $0.92 0.1 0.00 $2.235 Interior Screw-in - Task Lighting 10.0% 100.0% 5 $0.24 0.1 0.02 $0.531 Interior Lighting - Time Clocks and Timers 9.3% 75.0% 8 $0.20 0.1 0.09 $0.236 Water Heater - Faucet Aerators/Low Flow Nozzles 3.0% 100.0% 9 $0.03 0.1 0.27 $0.042 Water Heater - Pipe Insulation 0.0% 0.0% 15 $0.28 0.1 0.04 $0.185 Water Heater - High Efficiency Circulation Pump 0.6% 25.0% 10 $0.11 1.6 1.31 $0.008 Water Heater - Tank Blanket/Insulation 0.0% 0.0% 10 $0.04 0.1 0.26 $0.041 Water Heater - Thermostat Setback 0.0% 0.0% 10 $0.11 0.1 0.07 $0.141 Refrigeration - Anti-Sweat Heater/Auto Door Closer 0.0% 100.0% 16 $0.20 0.1 0.02 $0.321 Refrigeration - Floating Head Pressure 38.0% 60.0% 16 $0.35 0.0 0.00 $1.320 Refrigeration - Door Gasket Replacement 5.0% 100.0% 8 $0.10 0.0 0.02 $0.463 Insulation - Bare Suction Lines 5.0% 100.0% 8 $0.10 0.0 0.02 $0.653 Refrigeration - Night Covers 5.0% 100.0% 8 $0.05 0.0 0.04 $0.449 Refrigeration - Strip Curtain 12.6% 56.3% 4 $0.00 0.0 19.02 $0.001 Vending Machine - Controller 2.0% 10.0% 10 $0.27 0.1 0.01 $0.596 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1044 of 1125 C&I Energy Efficiency Equipment and Measure Data C-68 www.enernoc.com Measure Base Saturation Applicability Lifetime (Years) Incremental Cost ($/SqFt) Savings (kWh/SqFt) BC Ratio (2015) Levelized Cost of Energy ($/kWh) LED Exit Lighting 46.9% 90.0% 10 $0.00 0.0 3.74 $0.006 Retrocommissioning - Lighting 5.0% 100.0% 5 $0.05 0.3 0.31 $0.042 Refrigeration - High Efficiency Case Lighting 12.0% 56.0% 6 $0.04 - - $0.000 Exterior Lighting - Cold Cathode Lighting 14.6% 50.0% 5 $0.00 0.3 15.65 $0.001 Laundry - High Efficiency Clothes Washer 6.9% 10.0% 10 $0.00 0.0 4.60 $0.002 Interior Lighting - Hotel Guestroom Controls 1.0% 2.0% 8 $0.14 0.1 0.04 $0.224 Miscellaneous - Energy Star Water Cooler 5.0% 100.0% 8 $0.00 0.0 0.26 $0.047 Interior Lighting - Skylights 0.0% 0.0% 0 $0.00 0.4 1.00 $0.000 Ventilation - Demand Control Ventilation 7.9% 15.0% 10 $0.04 0.2 0.88 $0.029 Office Equipment - Smart Power Strips 15.4% 30.0% 7 $0.00 0.3 208.80 $0.000 Strategic Energy Management 0.0% 0.0% 3 $0.00 - 6.00 $0.000 Refrigeration - Multiplex - Floating section Pressure - Air-cooled Cond. 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Refrigeration - Multiplex Controls - Floating section Pressure - Evap. Cond. 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Refrigeration - Multiplex - Eff. Air- cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Refrigeration - Multiplex - Eff. Water-cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000 RTU - Maintenance 27.0% 100.0% 4 $0.06 0.4 0.30 $0.044 RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 1.3 0.12 $0.060 Chiller - Chilled Water Reset 15.0% 100.0% 4 $0.18 0.4 0.11 $0.120 Chiller - Chilled Water Variable-Flow System 30.0% 45.0% 10 $0.18 0.1 0.04 $0.226 Chiller - VSD 15.0% 88.2% 20 $1.17 0.7 0.05 $0.117 Chiller - High Efficiency Cooling Tower Fans 15.0% 43.5% 10 $0.04 0.0 0.00 $11.820 Chiller - Condenser Water Temprature Reset 5.0% 100.0% 14 $0.18 0.4 0.17 $0.046 Cooling - Economizer Installation 51.6% 65.0% 15 $0.15 0.8 0.47 $0.015 Heat Pump - Maintenance 28.1% 100.0% 4 $0.06 0.8 0.61 $0.021 Insulation - Ducting 8.0% 100.0% 20 $0.41 0.0 0.31 $1.046 Repair and Sealing - Ducting 5.0% 50.0% 15 $0.38 0.1 0.32 $0.421 Energy Management System 44.0% 100.0% 14 $0.35 2.5 0.68 $0.013 Cooking - Exhaust Hoods with Sensor Control 1.0% 15.0% 10 $0.04 - - $0.000 Fans - Energy Efficient Motors 11.0% 100.0% 10 $0.05 0.1 0.17 $0.072 Fans - Variable Speed Control 2.0% 100.0% 10 $0.20 0.6 0.27 $0.040 Retrocommissioning - HVAC 15.0% 100.0% 4 $0.30 0.4 0.37 $0.216 Pumps - Variable Speed Control 0.0% 45.0% 10 $0.13 0.0 0.01 $1.381 Thermostat - Clock/Programmable 33.0% 50.0% 11 $0.11 0.8 0.65 $0.015 Insulation - Ceiling 9.0% 40.0% 20 $0.85 0.4 0.34 $0.152 Insulation - Radiant Barrier 7.0% 25.0% 20 $0.26 0.0 0.31 $0.521 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1045 of 1125 C&I Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting C-69 Table C-24 Energy Efficiency Non-Equipment Data— Large Commercial, New Vintage, Washington Measure Base Saturation Applicability Lifetime (Years) Incremental Cost ($/SqFt) Savings (kWh/SqFt) BC Ratio (2015) Levelized Cost of Energy ($/kWh) RTU - Maintenance 27.0% 100.0% 4 $0.06 0.2 0.19 $0.076 RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 1.0 0.11 $0.073 Chiller - Chilled Water Reset 30.0% 100.0% 4 $0.18 0.3 0.09 $0.151 Chiller - Chilled Water Variable-Flow System 30.0% 45.0% 10 $0.18 0.1 0.06 $0.168 Chiller - VSD 15.0% 88.2% 20 $1.17 0.6 0.05 $0.141 Chiller - High Efficiency Cooling Tower Fans 15.0% 43.5% 10 $0.04 0.0 0.00 $10.716 Chiller - Condenser Water Temprature Reset 25.0% 100.0% 14 $0.18 0.3 0.14 $0.058 Cooling - Economizer Installation 44.3% 65.0% 15 $0.15 0.0 0.04 $0.517 Heat Pump - Maintenance 14.7% 100.0% 4 $0.06 0.5 0.44 $0.034 Insulation - Ducting 8.0% 50.0% 20 $0.41 0.0 0.30 $15.903 Energy Management System 48.5% 100.0% 14 $0.35 2.9 0.81 $0.011 Cooking - Exhaust Hoods with Sensor Control 1.0% 15.0% 10 $0.04 - - $0.000 Fans - Energy Efficient Motors 11.0% 100.0% 10 $0.05 0.1 0.19 $0.084 Fans - Variable Speed Control 2.0% 100.0% 10 $0.20 0.5 0.22 $0.051 Pumps - Variable Speed Control 5.0% 45.0% 10 $0.13 0.0 0.01 $1.313 Thermostat - Clock/Programmable 33.0% 50.0% 11 $0.11 1.4 1.14 $0.009 Insulation - Ceiling 75.0% 90.0% 20 $0.35 0.0 0.31 $2.770 Insulation - Radiant Barrier 7.0% 25.0% 20 $0.26 0.0 0.30 $29.882 Roofs - High Reflectivity 5.0% 100.0% 15 $0.05 0.0 0.01 $2.520 Windows - High Efficiency 71.9% 100.0% 20 $0.88 0.0 0.30 $17.807 Interior Lighting - Central Lighting Controls 85.7% 100.0% 8 $0.65 - - $0.000 Interior Lighting - Photocell Controlled T8 Dimming Ballasts 0.9% 60.0% 8 $0.34 0.7 0.18 $0.068 Exterior Lighting - Daylighting Controls 10.0% 25.0% 8 $0.19 - 0.00 $0.000 Interior Fluorescent - Bi-Level Fixture w/Occupancy Sensor 10.0% 30.0% 8 $0.40 0.3 0.06 $0.201 Interior Fluorescent - High Bay Fixtures 10.0% 30.0% 11 $0.63 1.4 0.21 $0.049 Interior Lighting - Occupancy Sensors 12.6% 60.0% 8 $0.20 - 0.06 $0.000 Exterior Lighting - Photovoltaic Installation 5.0% 25.0% 5 $0.92 - - $0.000 Interior Screw-in - Task Lighting 10.0% 100.0% 5 $0.24 0.1 0.03 $0.538 Interior Lighting - Time Clocks and Timers 9.3% 75.0% 8 $0.20 - 0.05 $0.000 Water Heater - Faucet Aerators/Low Flow Nozzles 3.0% 100.0% 9 $0.03 0.1 0.26 $0.044 Water Heater - Pipe Insulation 0.0% 0.0% 15 $0.28 0.1 0.03 $0.295 Water Heater - High Efficiency Circulation Pump 0.6% 25.0% 10 $0.11 1.6 1.30 $0.008 Water Heater - Tank Blanket/Insulation 0.0% 0.0% 10 $0.04 0.1 0.25 $0.043 Water Heater - Thermostat Setback 0.0% 0.0% 10 $0.11 0.1 0.07 $0.147 Refrigeration - Anti-Sweat Heater/Auto Door Closer 0.0% 100.0% 16 $0.20 0.0 0.03 $0.355 Refrigeration - Floating Head Pressure 38.0% 60.0% 16 $0.35 - 0.00 $0.000 Refrigeration - Door Gasket Replacement 5.0% 100.0% 8 $0.10 0.0 0.02 $0.662 Insulation - Bare Suction Lines 5.0% 100.0% 8 $0.10 - - $0.000 Refrigeration - Night Covers 5.0% 100.0% 8 $0.05 0.0 0.04 $0.495 Refrigeration - Strip Curtain 12.6% 56.3% 4 $0.00 0.0 15.67 $0.001 Vending Machine - Controller 2.0% 10.0% 10 $0.27 0.0 0.01 $0.684 LED Exit Lighting 91.2% 90.0% 10 $0.00 0.0 4.71 $0.006 Refrigeration - High Efficiency Case 24.0% 56.0% 6 $0.02 0.1 0.23 $0.061 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1046 of 1125 C&I Energy Efficiency Equipment and Measure Data C-70 www.enernoc.com Measure Base Saturation Applicability Lifetime (Years) Incremental Cost ($/SqFt) Savings (kWh/SqFt) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Lighting Exterior Lighting - Cold Cathode Lighting 14.6% 50.0% 5 $0.00 0.3 18.50 $0.001 Laundry - High Efficiency Clothes Washer 6.9% 10.0% 10 $0.00 0.0 5.06 $0.002 Interior Lighting - Hotel Guestroom Controls 1.0% 2.0% 8 $0.14 0.1 0.05 $0.227 Miscellaneous - Energy Star Water Cooler 5.0% 100.0% 8 $0.00 0.0 0.29 $0.042 Interior Lighting - Skylights 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Ventilation - Demand Control Ventilation 12.4% 15.0% 10 $0.04 - 0.53 $0.000 Office Equipment - Smart Power Strips 15.4% 30.0% 7 $0.00 0.3 221.56 $0.000 Strategic Energy Management 0.0% 0.0% 3 $0.00 - 6.00 $0.000 Refrigeration - Multiplex - Floating section Pressure - Air-cooled Cond. 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Refrigeration - Multiplex Controls - Floating section Pressure - Evap. Cond. 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Refrigeration - Multiplex - Eff. Air- cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Refrigeration - Multiplex - Eff. Water-cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000 RTU - Maintenance 27.0% 100.0% 4 $0.06 0.2 0.19 $0.076 RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 1.0 0.11 $0.073 Chiller - Chilled Water Reset 30.0% 100.0% 4 $0.18 0.3 0.09 $0.151 Chiller - Chilled Water Variable-Flow System 30.0% 45.0% 10 $0.18 0.1 0.06 $0.168 Chiller - VSD 15.0% 88.2% 20 $1.17 0.6 0.05 $0.141 Chiller - High Efficiency Cooling Tower Fans 15.0% 43.5% 10 $0.04 0.0 0.00 $10.716 Chiller - Condenser Water Temprature Reset 25.0% 100.0% 14 $0.18 0.3 0.14 $0.058 Cooling - Economizer Installation 44.3% 65.0% 15 $0.15 0.0 0.04 $0.517 Heat Pump - Maintenance 14.7% 100.0% 4 $0.06 0.5 0.44 $0.034 Insulation - Ducting 8.0% 50.0% 20 $0.41 0.0 0.30 $15.903 Energy Management System 48.5% 100.0% 14 $0.35 2.9 0.81 $0.011 Cooking - Exhaust Hoods with Sensor Control 1.0% 15.0% 10 $0.04 - - $0.000 Fans - Energy Efficient Motors 11.0% 100.0% 10 $0.05 0.1 0.19 $0.084 Fans - Variable Speed Control 2.0% 100.0% 10 $0.20 0.5 0.22 $0.051 Pumps - Variable Speed Control 5.0% 45.0% 10 $0.13 0.0 0.01 $1.313 Thermostat - Clock/Programmable 33.0% 50.0% 11 $0.11 1.4 1.14 $0.009 Insulation - Ceiling 75.0% 90.0% 20 $0.35 0.0 0.31 $2.770 Insulation - Radiant Barrier 7.0% 25.0% 20 $0.26 0.0 0.30 $29.882 Roofs - High Reflectivity 5.0% 100.0% 15 $0.05 0.0 0.01 $2.520 Windows - High Efficiency 71.9% 100.0% 20 $0.88 0.0 0.30 $17.807 Interior Lighting - Central Lighting Controls 85.7% 100.0% 8 $0.65 - - $0.000 Interior Lighting - Photocell Controlled T8 Dimming Ballasts 0.9% 60.0% 8 $0.34 0.7 0.18 $0.068 Exterior Lighting - Daylighting Controls 10.0% 25.0% 8 $0.19 - 0.00 $0.000 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1047 of 1125 C&I Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting C-71 Table C-25 Energy Efficiency Non-Equipment Data— Large Commercial, Existing Vintage, Idaho Measure Base Saturation Applicability Lifetime (Years) Incremental Cost ($/SqFt) Savings (kWh/SqFt) BC Ratio (2015) Levelized Cost of Energy ($/kWh) RTU - Maintenance 36.9% 100.0% 4 $0.06 0.4 0.30 $0.044 RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 1.3 0.12 $0.060 Chiller - Chilled Water Reset 15.0% 100.0% 4 $0.18 0.4 0.11 $0.120 Chiller - Chilled Water Variable-Flow System 30.0% 45.0% 10 $0.18 0.1 0.04 $0.226 Chiller - VSD 15.0% 88.2% 20 $1.17 0.7 0.05 $0.117 Chiller - High Efficiency Cooling Tower Fans 15.0% 43.5% 10 $0.04 0.0 0.00 $11.820 Chiller - Condenser Water Temprature Reset 18.5% 100.0% 14 $0.18 0.4 0.17 $0.046 Cooling - Economizer Installation 51.6% 65.0% 15 $0.15 0.2 0.14 $0.068 Heat Pump - Maintenance 28.1% 100.0% 4 $0.06 0.8 0.61 $0.021 Insulation - Ducting 8.0% 100.0% 20 $0.41 0.0 0.30 $2.323 Repair and Sealing - Ducting 5.0% 50.0% 15 $0.38 0.0 0.31 $0.792 Energy Management System 45.9% 100.0% 14 $0.35 1.7 0.47 $0.019 Cooking - Exhaust Hoods with Sensor Control 1.0% 15.0% 10 $0.04 - - $0.000 Fans - Energy Efficient Motors 11.0% 100.0% 10 $0.05 0.1 0.14 $0.072 Fans - Variable Speed Control 21.7% 100.0% 10 $0.20 0.6 0.27 $0.040 Retrocommissioning - HVAC 15.0% 100.0% 4 $0.30 0.1 0.31 $1.053 Pumps - Variable Speed Control 0.0% 45.0% 10 $0.13 0.0 0.01 $1.381 Thermostat - Clock/Programmable 33.0% 50.0% 11 $0.11 0.6 0.44 $0.022 Insulation - Ceiling 9.0% 40.0% 20 $0.85 0.1 0.31 $0.599 Insulation - Radiant Barrier 7.0% 25.0% 20 $0.26 0.0 0.30 $1.652 Roofs - High Reflectivity 1.5% 100.0% 15 $0.08 0.0 0.02 $0.482 Windows - High Efficiency 71.9% 100.0% 20 $0.88 0.1 0.31 $0.833 Interior Lighting - Central Lighting Controls 85.7% 100.0% 8 $0.65 0.3 0.03 $0.328 Interior Lighting - Photocell Controlled T8 Dimming Ballasts 0.9% 60.0% 8 $0.45 0.8 0.15 $0.078 Exterior Lighting - Daylighting Controls 1.6% 25.0% 8 $0.29 - 0.00 $0.000 Interior Fluorescent - Bi-Level Fixture w/Occupancy Sensor 10.0% 30.0% 8 $0.40 0.3 0.07 $0.173 Interior Fluorescent - High Bay Fixtures 15.4% 30.0% 11 $0.63 1.6 0.23 $0.042 Interior Lighting - Occupancy Sensors 23.2% 60.0% 8 $0.20 0.3 0.17 $0.101 Exterior Lighting - Photovoltaic Installation 5.0% 25.0% 5 $0.92 - - $0.000 Interior Screw-in - Task Lighting 10.0% 100.0% 5 $0.24 0.1 0.02 $0.531 Interior Lighting - Time Clocks and Timers 9.3% 75.0% 8 $0.20 0.1 0.09 $0.202 Water Heater - Faucet Aerators/Low Flow Nozzles 47.9% 100.0% 9 $0.03 0.1 0.26 $0.042 Water Heater - Pipe Insulation 0.0% 0.0% 15 $0.28 0.1 0.04 $0.185 Water Heater - High Efficiency Circulation Pump 0.6% 25.0% 10 $0.11 1.6 1.30 $0.008 Water Heater - Tank Blanket/Insulation 0.0% 0.0% 10 $0.04 0.1 0.26 $0.041 Water Heater - Thermostat Setback 0.0% 0.0% 10 $0.11 0.1 0.07 $0.141 Refrigeration - Anti-Sweat Heater/Auto Door Closer 0.0% 100.0% 16 $0.20 0.1 0.02 $0.321 Refrigeration - Floating Head Pressure 38.0% 60.0% 16 $0.35 - 0.00 $0.000 Refrigeration - Door Gasket Replacement 5.0% 100.0% 8 $0.10 0.0 0.02 $0.463 Insulation - Bare Suction Lines 5.0% 100.0% 8 $0.10 - - $0.000 Refrigeration - Night Covers 5.0% 100.0% 8 $0.05 0.0 0.04 $0.449 Refrigeration - Strip Curtain 12.6% 56.3% 4 $0.00 0.0 18.97 $0.001 Vending Machine - Controller 2.0% 10.0% 10 $0.27 0.1 0.01 $0.596 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1048 of 1125 C&I Energy Efficiency Equipment and Measure Data C-72 www.enernoc.com Measure Base Saturation Applicability Lifetime (Years) Incremental Cost ($/SqFt) Savings (kWh/SqFt) BC Ratio (2015) Levelized Cost of Energy ($/kWh) LED Exit Lighting 46.9% 90.0% 10 $0.00 0.0 3.00 $0.006 Retrocommissioning - Lighting 24.1% 100.0% 5 $0.05 0.3 0.33 $0.038 Refrigeration - High Efficiency Case Lighting 12.0% 56.0% 6 $0.04 0.0 0.00 $5.412 Exterior Lighting - Cold Cathode Lighting 14.6% 50.0% 5 $0.00 0.3 15.57 $0.001 Laundry - High Efficiency Clothes Washer 6.9% 10.0% 10 $0.00 0.0 4.57 $0.002 Interior Lighting - Hotel Guestroom Controls 1.0% 2.0% 8 $0.14 0.1 0.03 $0.224 Miscellaneous - Energy Star Water Cooler 24.1% 100.0% 8 $0.00 0.0 0.26 $0.047 Interior Lighting - Skylights 0.0% 0.0% 0 $0.00 0.4 1.00 $0.000 Ventilation - Demand Control Ventilation 7.9% 15.0% 10 $0.04 0.0 0.53 $0.315 Office Equipment - Smart Power Strips 15.4% 30.0% 7 $0.00 0.5 353.57 $0.000 Strategic Energy Management 0.0% 0.0% 3 $0.00 - 6.00 $0.000 Refrigeration - Multiplex - Floating section Pressure - Air-cooled Cond. 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Refrigeration - Multiplex Controls - Floating section Pressure - Evap. Cond. 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Refrigeration - Multiplex - Eff. Air- cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Refrigeration - Multiplex - Eff. Water-cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000 RTU - Maintenance 36.9% 100.0% 4 $0.06 0.4 0.30 $0.044 RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 1.3 0.12 $0.060 Chiller - Chilled Water Reset 15.0% 100.0% 4 $0.18 0.4 0.11 $0.120 Chiller - Chilled Water Variable-Flow System 30.0% 45.0% 10 $0.18 0.1 0.04 $0.226 Chiller - VSD 15.0% 88.2% 20 $1.17 0.7 0.05 $0.117 Chiller - High Efficiency Cooling Tower Fans 15.0% 43.5% 10 $0.04 0.0 0.00 $11.820 Chiller - Condenser Water Temprature Reset 18.5% 100.0% 14 $0.18 0.4 0.17 $0.046 Cooling - Economizer Installation 51.6% 65.0% 15 $0.15 0.2 0.14 $0.068 Heat Pump - Maintenance 28.1% 100.0% 4 $0.06 0.8 0.61 $0.021 Insulation - Ducting 8.0% 100.0% 20 $0.41 0.0 0.30 $2.323 Repair and Sealing - Ducting 5.0% 50.0% 15 $0.38 0.0 0.31 $0.792 Energy Management System 45.9% 100.0% 14 $0.35 1.7 0.47 $0.019 Cooking - Exhaust Hoods with Sensor Control 1.0% 15.0% 10 $0.04 - - $0.000 Fans - Energy Efficient Motors 11.0% 100.0% 10 $0.05 0.1 0.14 $0.072 Fans - Variable Speed Control 21.7% 100.0% 10 $0.20 0.6 0.27 $0.040 Retrocommissioning - HVAC 15.0% 100.0% 4 $0.30 0.1 0.31 $1.053 Pumps - Variable Speed Control 0.0% 45.0% 10 $0.13 0.0 0.01 $1.381 Thermostat - Clock/Programmable 33.0% 50.0% 11 $0.11 0.6 0.44 $0.022 Insulation - Ceiling 9.0% 40.0% 20 $0.85 0.1 0.31 $0.599 Insulation - Radiant Barrier 7.0% 25.0% 20 $0.26 0.0 0.30 $1.652 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1049 of 1125 C&I Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting C-73 Table C-26 Energy Efficiency Non-Equipment Data— Large Commercial, New Vintage, Idaho Measure Base Saturation Applicability Lifetime (Years) Incremental Cost ($/SqFt) Savings (kWh/SqFt) BC Ratio (2015) Levelized Cost of Energy ($/kWh) RTU - Maintenance 27.0% 100.0% 4 $0.06 0.2 0.19 $0.076 RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 1.0 0.11 $0.073 Chiller - Chilled Water Reset 30.0% 100.0% 4 $0.18 0.3 0.10 $0.151 Chiller - Chilled Water Variable-Flow System 30.0% 45.0% 10 $0.18 0.1 0.06 $0.168 Chiller - VSD 15.0% 88.2% 20 $1.17 0.6 0.05 $0.141 Chiller - High Efficiency Cooling Tower Fans 15.0% 43.5% 10 $0.04 0.0 0.00 $10.716 Chiller - Condenser Water Temprature Reset 31.4% 100.0% 14 $0.18 0.3 0.15 $0.058 Cooling - Economizer Installation 44.3% 65.0% 15 $0.15 - 0.03 $0.000 Heat Pump - Maintenance 28.1% 100.0% 4 $0.06 0.5 0.43 $0.034 Insulation - Ducting 8.0% 50.0% 20 $0.41 - 0.30 $0.000 Energy Management System 55.8% 100.0% 14 $0.35 1.6 0.47 $0.020 Cooking - Exhaust Hoods with Sensor Control 1.0% 15.0% 10 $0.04 - - $0.000 Fans - Energy Efficient Motors 28.9% 100.0% 10 $0.05 0.1 0.17 $0.084 Fans - Variable Speed Control 47.3% 100.0% 10 $0.20 0.5 0.23 $0.051 Pumps - Variable Speed Control 5.0% 45.0% 10 $0.13 0.0 0.01 $1.313 Thermostat - Clock/Programmable 33.0% 50.0% 11 $0.11 0.4 0.29 $0.033 Insulation - Ceiling 75.0% 90.0% 20 $0.35 - 0.30 $0.000 Insulation - Radiant Barrier 7.0% 25.0% 20 $0.26 - 0.30 $0.000 Roofs - High Reflectivity 5.0% 100.0% 15 $0.05 - 0.01 $0.000 Windows - High Efficiency 71.9% 100.0% 20 $0.88 - 0.30 $0.000 Interior Lighting - Central Lighting Controls 85.7% 100.0% 8 $0.65 0.4 0.06 $0.213 Interior Lighting - Photocell Controlled T8 Dimming Ballasts 0.9% 60.0% 8 $0.34 0.7 0.18 $0.068 Exterior Lighting - Daylighting Controls 14.5% 25.0% 8 $0.19 1.7 0.75 $0.016 Interior Fluorescent - Bi-Level Fixture w/Occupancy Sensor 10.0% 30.0% 8 $0.40 0.3 0.06 $0.201 Interior Fluorescent - High Bay Fixtures 15.4% 30.0% 11 $0.63 1.4 0.21 $0.049 Interior Lighting - Occupancy Sensors 23.2% 60.0% 8 $0.20 0.4 0.24 $0.066 Exterior Lighting - Photovoltaic Installation 5.0% 25.0% 5 $0.92 2.0 0.15 $0.100 Interior Screw-in - Task Lighting 10.0% 100.0% 5 $0.24 0.1 0.02 $0.538 Interior Lighting - Time Clocks and Timers 15.2% 75.0% 8 $0.20 0.2 0.14 $0.131 Water Heater - Faucet Aerators/Low Flow Nozzles 47.9% 100.0% 9 $0.03 0.1 0.26 $0.044 Water Heater - Pipe Insulation 0.0% 0.0% 15 $0.28 0.1 0.03 $0.295 Water Heater - High Efficiency Circulation Pump 0.6% 25.0% 10 $0.11 1.6 1.28 $0.008 Water Heater - Tank Blanket/Insulation 0.0% 0.0% 10 $0.04 0.1 0.25 $0.043 Water Heater - Thermostat Setback 0.0% 0.0% 10 $0.11 0.1 0.07 $0.147 Refrigeration - Anti-Sweat Heater/Auto Door Closer 0.0% 100.0% 16 $0.20 0.0 0.03 $0.355 Refrigeration - Floating Head Pressure 38.0% 60.0% 16 $0.35 0.1 0.02 $0.330 Refrigeration - Door Gasket Replacement 5.0% 100.0% 8 $0.10 0.0 0.02 $0.662 Insulation - Bare Suction Lines 5.0% 100.0% 8 $0.10 0.1 0.08 $0.163 Refrigeration - Night Covers 5.0% 100.0% 8 $0.05 0.0 0.04 $0.495 Refrigeration - Strip Curtain 29.7% 56.3% 4 $0.00 0.0 15.63 $0.001 Vending Machine - Controller 2.0% 10.0% 10 $0.27 0.0 0.01 $0.684 LED Exit Lighting 91.2% 90.0% 10 $0.00 0.0 4.50 $0.006 Refrigeration - High Efficiency Case 24.0% 56.0% 6 $0.02 0.0 0.14 $0.102 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1050 of 1125 C&I Energy Efficiency Equipment and Measure Data C-74 www.enernoc.com Measure Base Saturation Applicability Lifetime (Years) Incremental Cost ($/SqFt) Savings (kWh/SqFt) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Lighting Exterior Lighting - Cold Cathode Lighting 14.6% 50.0% 5 $0.00 0.3 18.13 $0.001 Laundry - High Efficiency Clothes Washer 6.9% 10.0% 10 $0.00 0.0 5.03 $0.002 Interior Lighting - Hotel Guestroom Controls 1.0% 2.0% 8 $0.14 0.1 0.05 $0.227 Miscellaneous - Energy Star Water Cooler 11.9% 100.0% 8 $0.00 0.0 0.29 $0.042 Interior Lighting - Skylights 0.0% 0.0% 0 $0.00 0.7 1.00 $0.000 Ventilation - Demand Control Ventilation 15.0% 15.0% 10 $0.04 - 0.54 $0.000 Office Equipment - Smart Power Strips 15.4% 30.0% 7 $0.00 0.3 219.97 $0.000 Strategic Energy Management 0.0% 0.0% 3 $0.00 - 6.00 $0.000 Refrigeration - Multiplex - Floating section Pressure - Air-cooled Cond. 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Refrigeration - Multiplex Controls - Floating section Pressure - Evap. Cond. 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Refrigeration - Multiplex - Eff. Air- cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Refrigeration - Multiplex - Eff. Water-cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000 RTU - Maintenance 27.0% 100.0% 4 $0.06 0.2 0.19 $0.076 RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 1.0 0.11 $0.073 Chiller - Chilled Water Reset 30.0% 100.0% 4 $0.18 0.3 0.10 $0.151 Chiller - Chilled Water Variable-Flow System 30.0% 45.0% 10 $0.18 0.1 0.06 $0.168 Chiller - VSD 15.0% 88.2% 20 $1.17 0.6 0.05 $0.141 Chiller - High Efficiency Cooling Tower Fans 15.0% 43.5% 10 $0.04 0.0 0.00 $10.716 Chiller - Condenser Water Temprature Reset 31.4% 100.0% 14 $0.18 0.3 0.15 $0.058 Cooling - Economizer Installation 44.3% 65.0% 15 $0.15 - 0.03 $0.000 Heat Pump - Maintenance 28.1% 100.0% 4 $0.06 0.5 0.43 $0.034 Insulation - Ducting 8.0% 50.0% 20 $0.41 - 0.30 $0.000 Energy Management System 55.8% 100.0% 14 $0.35 1.6 0.47 $0.020 Cooking - Exhaust Hoods with Sensor Control 1.0% 15.0% 10 $0.04 - - $0.000 Fans - Energy Efficient Motors 28.9% 100.0% 10 $0.05 0.1 0.17 $0.084 Fans - Variable Speed Control 47.3% 100.0% 10 $0.20 0.5 0.23 $0.051 Pumps - Variable Speed Control 5.0% 45.0% 10 $0.13 0.0 0.01 $1.313 Thermostat - Clock/Programmable 33.0% 50.0% 11 $0.11 0.4 0.29 $0.033 Insulation - Ceiling 75.0% 90.0% 20 $0.35 - 0.30 $0.000 Insulation - Radiant Barrier 7.0% 25.0% 20 $0.26 - 0.30 $0.000 Roofs - High Reflectivity 5.0% 100.0% 15 $0.05 - 0.01 $0.000 Windows - High Efficiency 71.9% 100.0% 20 $0.88 - 0.30 $0.000 Interior Lighting - Central Lighting Controls 85.7% 100.0% 8 $0.65 0.4 0.06 $0.213 Interior Lighting - Photocell Controlled T8 Dimming Ballasts 0.9% 60.0% 8 $0.34 0.7 0.18 $0.068 Exterior Lighting - Daylighting Controls 14.5% 25.0% 8 $0.19 1.7 0.75 $0.016 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1051 of 1125 C&I Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting C-75 Table C-27 Energy Efficiency Non-Equipment Data— Extra Large Commercial, Existing Vintage, Washington Measure Base Saturation Applicability Lifetime (Years) Incremental Cost ($/SqFt) Savings (kWh/SqFt) BC Ratio (2015) Levelized Cost of Energy ($/kWh) RTU - Maintenance 47.0% 100.0% 4 $0.06 0.3 0.27 $0.050 RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 1.1 0.12 $0.068 Chiller - Chilled Water Reset 30.0% 100.0% 4 $0.09 0.3 0.19 $0.072 Chiller - Chilled Water Variable-Flow System 30.0% 45.0% 10 $0.09 0.1 0.11 $0.097 Chiller - VSD 3.0% 100.0% 20 $1.17 0.7 0.07 $0.118 Chiller - High Efficiency Cooling Tower Fans 25.0% 73.7% 10 $0.04 0.0 0.00 $12.451 Chiller - Condenser Water Temprature Reset 31.4% 100.0% 14 $0.09 0.3 0.32 $0.024 Cooling - Economizer Installation 73.4% 90.0% 15 $0.15 0.0 0.03 $0.577 Heat Pump - Maintenance 5.0% 100.0% 4 $0.06 0.4 0.30 $0.043 Insulation - Ducting 2.0% 100.0% 20 $0.41 0.1 0.33 $0.274 Repair and Sealing - Ducting 5.0% 50.0% 15 $0.38 0.3 0.39 $0.099 Energy Management System 81.3% 100.0% 14 $0.35 4.1 1.10 $0.008 Cooking - Exhaust Hoods with Sensor Control 1.0% 10.0% 10 $0.04 0.0 0.10 $0.103 Fans - Energy Efficient Motors 11.0% 100.0% 10 $0.05 0.1 0.17 $0.061 Fans - Variable Speed Control 2.0% 100.0% 10 $0.20 0.6 0.29 $0.037 Retrocommissioning - HVAC 15.0% 100.0% 4 $0.20 0.2 0.36 $0.268 Pumps - Variable Speed Control 1.0% 45.0% 10 $0.44 0.0 0.00 $7.933 Thermostat - Clock/Programmable 25.0% 50.0% 11 $0.11 2.1 1.71 $0.006 Insulation - Ceiling 2.0% 90.0% 20 $0.85 0.2 0.33 $0.265 Insulation - Radiant Barrier 2.0% 25.0% 20 $0.26 0.0 0.32 $0.426 Roofs - High Reflectivity 0.0% 100.0% 15 $0.18 0.0 0.02 $0.687 Windows - High Efficiency 94.6% 100.0% 20 $2.10 0.1 0.30 $1.632 Interior Lighting - Central Lighting Controls 78.1% 100.0% 8 $0.65 0.0 0.00 $3.005 Interior Lighting - Photocell Controlled T8 Dimming Ballasts 2.5% 60.0% 8 $0.40 0.5 0.11 $0.105 Exterior Lighting - Daylighting Controls 1.6% 20.0% 8 $0.29 0.3 0.06 $0.135 Interior Fluorescent - Bi-Level Fixture w/Occupancy Sensor 10.0% 30.0% 8 $0.20 0.2 0.09 $0.131 Interior Fluorescent - High Bay Fixtures 10.0% 30.0% 11 $0.56 1.1 0.18 $0.056 Interior Lighting - Occupancy Sensors 41.7% 60.0% 8 $0.20 0.0 0.07 $0.925 Exterior Lighting - Photovoltaic Installation 5.0% 25.0% 5 $0.92 0.4 0.02 $0.549 Interior Screw-in - Task Lighting 5.0% 100.0% 5 $0.24 0.1 0.03 $0.366 Interior Lighting - Time Clocks and Timers 12.1% 75.0% 8 $0.20 0.0 0.05 $1.849 Water Heater - Faucet Aerators/Low Flow Nozzles 47.3% 100.0% 9 $0.03 0.1 0.43 $0.026 Water Heater - Pipe Insulation 0.0% 0.0% 15 $0.28 0.2 0.07 $0.115 Water Heater - High Efficiency Circulation Pump 0.6% 25.0% 10 $0.11 2.6 2.11 $0.005 Water Heater - Tank Blanket/Insulation 0.0% 0.0% 10 $0.04 0.2 0.41 $0.026 Water Heater - Thermostat Setback 0.0% 0.0% 10 $0.11 0.1 0.12 $0.088 Refrigeration - Anti-Sweat Heater/Auto Door Closer 10.0% 100.0% 16 $0.20 0.0 0.01 $1.098 Refrigeration - Floating Head Pressure 10.0% 50.0% 16 $0.35 0.0 0.00 $2.158 Refrigeration - Door Gasket Replacement 5.0% 100.0% 8 $0.10 0.0 0.02 $0.505 Insulation - Bare Suction Lines 5.0% 100.0% 8 $0.10 0.0 0.01 $1.067 Refrigeration - Night Covers 5.0% 100.0% 8 $0.05 0.0 0.06 $0.239 Refrigeration - Strip Curtain 12.6% 56.3% 4 $0.00 0.0 3.75 $0.004 Vending Machine - Controller 2.0% 10.0% 10 $0.27 0.1 0.01 $0.566 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1052 of 1125 C&I Energy Efficiency Equipment and Measure Data C-76 www.enernoc.com Measure Base Saturation Applicability Lifetime (Years) Incremental Cost ($/SqFt) Savings (kWh/SqFt) BC Ratio (2015) Levelized Cost of Energy ($/kWh) LED Exit Lighting 46.9% 90.0% 10 $0.00 0.0 4.54 $0.004 Retrocommissioning - Lighting 5.0% 100.0% 5 $0.05 0.1 0.09 $0.118 Refrigeration - High Efficiency Case Lighting 12.0% 56.0% 6 $0.04 0.2 0.34 $0.043 Exterior Lighting - Cold Cathode Lighting 14.6% 50.0% 5 $0.00 0.4 19.92 $0.000 Laundry - High Efficiency Clothes Washer 6.9% 10.0% 10 $0.00 0.0 2.68 $0.004 Interior Lighting - Hotel Guestroom Controls 0.0% 0.0% 8 $0.14 0.1 0.06 $0.154 Miscellaneous - Energy Star Water Cooler 5.0% 100.0% 8 $0.00 0.0 0.15 $0.080 Interior Lighting - Skylights 0.0% 0.0% 0 $0.00 0.0 1.00 $0.000 Ventilation - Demand Control Ventilation 1.0% 10.0% 10 $0.04 0.0 0.13 $0.415 Office Equipment - Smart Power Strips 15.4% 30.0% 7 $0.00 0.3 207.83 $0.000 Strategic Energy Management 0.0% 0.0% 3 $0.00 - 6.00 $0.000 Refrigeration - Multiplex - Floating section Pressure - Air-cooled Cond. 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Refrigeration - Multiplex Controls - Floating section Pressure - Evap. Cond. 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Refrigeration - Multiplex - Eff. Air- cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Refrigeration - Multiplex - Eff. Water-cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000 RTU - Maintenance 47.0% 100.0% 4 $0.06 0.3 0.27 $0.050 RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 1.1 0.12 $0.068 Chiller - Chilled Water Reset 30.0% 100.0% 4 $0.09 0.3 0.19 $0.072 Chiller - Chilled Water Variable-Flow System 30.0% 45.0% 10 $0.09 0.1 0.11 $0.097 Chiller - VSD 3.0% 100.0% 20 $1.17 0.7 0.07 $0.118 Chiller - High Efficiency Cooling Tower Fans 25.0% 73.7% 10 $0.04 0.0 0.00 $12.451 Chiller - Condenser Water Temprature Reset 31.4% 100.0% 14 $0.09 0.3 0.32 $0.024 Cooling - Economizer Installation 73.4% 90.0% 15 $0.15 0.0 0.03 $0.577 Heat Pump - Maintenance 5.0% 100.0% 4 $0.06 0.4 0.30 $0.043 Insulation - Ducting 2.0% 100.0% 20 $0.41 0.1 0.33 $0.274 Repair and Sealing - Ducting 5.0% 50.0% 15 $0.38 0.3 0.39 $0.099 Energy Management System 81.3% 100.0% 14 $0.35 4.1 1.10 $0.008 Cooking - Exhaust Hoods with Sensor Control 1.0% 10.0% 10 $0.04 0.0 0.10 $0.103 Fans - Energy Efficient Motors 11.0% 100.0% 10 $0.05 0.1 0.17 $0.061 Fans - Variable Speed Control 2.0% 100.0% 10 $0.20 0.6 0.29 $0.037 Retrocommissioning - HVAC 15.0% 100.0% 4 $0.20 0.2 0.36 $0.268 Pumps - Variable Speed Control 1.0% 45.0% 10 $0.44 0.0 0.00 $7.933 Thermostat - Clock/Programmable 25.0% 50.0% 11 $0.11 2.1 1.71 $0.006 Insulation - Ceiling 2.0% 90.0% 20 $0.85 0.2 0.33 $0.265 Insulation - Radiant Barrier 2.0% 25.0% 20 $0.26 0.0 0.32 $0.426 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1053 of 1125 C&I Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting C-77 Table C-28 Energy Efficiency Non-Equipment Data— Extra Large Commercial, New Vintage, Washington Measure Base Saturation Applicability Lifetime (Years) Incremental Cost ($/SqFt) Savings (kWh/SqFt) BC Ratio (2015) Levelized Cost of Energy ($/kWh) RTU - Maintenance 47.0% 100.0% 4 $0.06 0.2 0.17 $0.086 RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 0.9 0.11 $0.082 Chiller - Chilled Water Reset 60.0% 100.0% 4 $0.09 0.3 0.16 $0.091 Chiller - Chilled Water Variable-Flow System 30.0% 45.0% 10 $0.09 0.1 0.08 $0.127 Chiller - VSD 3.0% 100.0% 20 $1.17 0.6 0.06 $0.138 Chiller - High Efficiency Cooling Tower Fans 25.0% 73.7% 10 $0.04 0.0 0.00 $11.601 Chiller - Condenser Water Temprature Reset 57.1% 100.0% 14 $0.09 0.3 0.34 $0.030 Cooling - Economizer Installation 73.4% 90.0% 15 $0.15 - 0.02 $0.000 Heat Pump - Maintenance 5.0% 100.0% 4 $0.06 0.2 0.18 $0.082 Insulation - Ducting 2.0% 50.0% 20 $0.41 - 0.31 $0.000 Energy Management System 80.0% 100.0% 14 $0.35 2.7 0.78 $0.012 Cooking - Exhaust Hoods with Sensor Control 1.0% 10.0% 10 $0.04 0.0 0.10 $0.117 Fans - Energy Efficient Motors 11.0% 100.0% 10 $0.05 0.1 0.16 $0.070 Fans - Variable Speed Control 2.0% 100.0% 10 $0.20 0.6 0.31 $0.037 Pumps - Variable Speed Control 1.0% 45.0% 10 $0.44 0.0 0.00 $7.545 Thermostat - Clock/Programmable 25.0% 50.0% 11 $0.11 2.0 1.61 $0.006 Insulation - Ceiling 2.0% 90.0% 20 $0.35 - 0.31 $0.000 Insulation - Radiant Barrier 2.0% 25.0% 20 $0.26 - 0.30 $0.000 Roofs - High Reflectivity 5.0% 100.0% 15 $0.18 - 0.01 $0.000 Windows - High Efficiency 94.6% 100.0% 20 $1.69 - 0.30 $0.000 Interior Lighting - Central Lighting Controls 78.1% 100.0% 8 $0.65 - - $0.000 Interior Lighting - Photocell Controlled T8 Dimming Ballasts 2.5% 60.0% 8 $0.30 0.5 0.14 $0.086 Exterior Lighting - Daylighting Controls 10.0% 20.0% 8 $0.19 - 0.00 $0.000 Interior Fluorescent - Bi-Level Fixture w/Occupancy Sensor 10.0% 30.0% 8 $0.20 0.2 0.09 $0.143 Interior Fluorescent - High Bay Fixtures 10.0% 30.0% 11 $0.56 1.0 0.17 $0.061 Interior Lighting - Occupancy Sensors 41.7% 60.0% 8 $0.20 - 0.06 $0.000 Exterior Lighting - Photovoltaic Installation 5.0% 25.0% 5 $0.92 - - $0.000 Interior Screw-in - Task Lighting 25.0% 100.0% 5 $0.24 0.1 0.04 $0.376 Interior Lighting - Time Clocks and Timers 12.1% 75.0% 8 $0.20 - 0.04 $0.000 Water Heater - Faucet Aerators/Low Flow Nozzles 47.3% 100.0% 9 $0.03 0.1 0.43 $0.027 Water Heater - Pipe Insulation 0.0% 0.0% 15 $0.28 0.1 0.05 $0.180 Water Heater - High Efficiency Circulation Pump 0.6% 25.0% 10 $0.11 2.5 2.10 $0.005 Water Heater - Tank Blanket/Insulation 0.0% 0.0% 10 $0.04 0.1 0.21 $0.052 Water Heater - Thermostat Setback 0.0% 0.0% 10 $0.11 0.1 0.12 $0.090 Refrigeration - Anti-Sweat Heater/Auto Door Closer 10.0% 100.0% 16 $0.20 0.0 0.01 $1.217 Refrigeration - Floating Head Pressure 10.0% 50.0% 16 $0.35 0.2 0.04 $0.188 Refrigeration - Door Gasket Replacement 5.0% 100.0% 8 $0.10 0.0 0.02 $0.721 Insulation - Bare Suction Lines 5.0% 100.0% 8 $0.10 0.2 0.13 $0.093 Refrigeration - Night Covers 5.0% 100.0% 8 $0.05 0.0 0.06 $0.263 Refrigeration - Strip Curtain 29.7% 56.3% 4 $0.00 0.0 3.12 $0.005 Vending Machine - Controller 2.0% 10.0% 10 $0.27 0.0 0.01 $0.784 LED Exit Lighting 91.2% 90.0% 10 $0.00 0.0 5.08 $0.004 Refrigeration - High Efficiency Case 26.1% 56.0% 6 $0.02 0.1 0.87 $0.041 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1054 of 1125 C&I Energy Efficiency Equipment and Measure Data C-78 www.enernoc.com Measure Base Saturation Applicability Lifetime (Years) Incremental Cost ($/SqFt) Savings (kWh/SqFt) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Lighting Exterior Lighting - Cold Cathode Lighting 14.6% 50.0% 5 $0.00 0.3 22.34 $0.001 Laundry - High Efficiency Clothes Washer 6.9% 10.0% 10 $0.00 0.0 2.95 $0.004 Interior Lighting - Hotel Guestroom Controls 0.0% 0.0% 8 $0.14 0.1 0.07 $0.158 Miscellaneous - Energy Star Water Cooler 5.0% 100.0% 8 $0.00 0.0 0.17 $0.073 Interior Lighting - Skylights 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Ventilation - Demand Control Ventilation 5.9% 10.0% 10 $0.04 - 0.11 $0.000 Office Equipment - Smart Power Strips 15.4% 30.0% 7 $0.00 0.3 219.19 $0.000 Strategic Energy Management 0.0% 0.0% 3 $0.00 - 6.00 $0.000 Refrigeration - Multiplex - Floating section Pressure - Air-cooled Cond. 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Refrigeration - Multiplex Controls - Floating section Pressure - Evap. Cond. 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Refrigeration - Multiplex - Eff. Air- cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Refrigeration - Multiplex - Eff. Water-cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000 RTU - Maintenance 47.0% 100.0% 4 $0.06 0.2 0.17 $0.086 RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 0.9 0.11 $0.082 Chiller - Chilled Water Reset 60.0% 100.0% 4 $0.09 0.3 0.16 $0.091 Chiller - Chilled Water Variable-Flow System 30.0% 45.0% 10 $0.09 0.1 0.08 $0.127 Chiller - VSD 3.0% 100.0% 20 $1.17 0.6 0.06 $0.138 Chiller - High Efficiency Cooling Tower Fans 25.0% 73.7% 10 $0.04 0.0 0.00 $11.601 Chiller - Condenser Water Temprature Reset 57.1% 100.0% 14 $0.09 0.3 0.34 $0.030 Cooling - Economizer Installation 73.4% 90.0% 15 $0.15 - 0.02 $0.000 Heat Pump - Maintenance 5.0% 100.0% 4 $0.06 0.2 0.18 $0.082 Insulation - Ducting 2.0% 50.0% 20 $0.41 - 0.31 $0.000 Energy Management System 80.0% 100.0% 14 $0.35 2.7 0.78 $0.012 Cooking - Exhaust Hoods with Sensor Control 1.0% 10.0% 10 $0.04 0.0 0.10 $0.117 Fans - Energy Efficient Motors 11.0% 100.0% 10 $0.05 0.1 0.16 $0.070 Fans - Variable Speed Control 2.0% 100.0% 10 $0.20 0.6 0.31 $0.037 Pumps - Variable Speed Control 1.0% 45.0% 10 $0.44 0.0 0.00 $7.545 Thermostat - Clock/Programmable 25.0% 50.0% 11 $0.11 2.0 1.61 $0.006 Insulation - Ceiling 2.0% 90.0% 20 $0.35 - 0.31 $0.000 Insulation - Radiant Barrier 2.0% 25.0% 20 $0.26 - 0.30 $0.000 Roofs - High Reflectivity 5.0% 100.0% 15 $0.18 - 0.01 $0.000 Windows - High Efficiency 94.6% 100.0% 20 $1.69 - 0.30 $0.000 Interior Lighting - Central Lighting Controls 78.1% 100.0% 8 $0.65 - - $0.000 Interior Lighting - Photocell Controlled T8 Dimming Ballasts 2.5% 60.0% 8 $0.30 0.5 0.14 $0.086 Exterior Lighting - Daylighting Controls 10.0% 20.0% 8 $0.19 - 0.00 $0.000 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1055 of 1125 C&I Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting C-79 Table C-29 Energy Efficiency Non-Equipment Data— Extra Large Commercial, Existing Vintage, Idaho Measure Base Saturation Applicability Lifetime (Years) Incremental Cost ($/SqFt) Savings (kWh/SqFt) BC Ratio (2015) Levelized Cost of Energy ($/kWh) RTU - Maintenance 54.2% 100.0% 4 $0.06 0.3 0.26 $0.050 RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 1.1 0.12 $0.068 Chiller - Chilled Water Reset 36.0% 100.0% 4 $0.09 0.3 0.19 $0.072 Chiller - Chilled Water Variable-Flow System 30.0% 45.0% 10 $0.09 0.1 0.11 $0.097 Chiller - VSD 3.0% 100.0% 20 $1.17 0.7 0.06 $0.118 Chiller - High Efficiency Cooling Tower Fans 25.0% 73.7% 10 $0.04 0.0 0.00 $12.451 Chiller - Condenser Water Temprature Reset 31.4% 100.0% 14 $0.09 0.3 0.37 $0.025 Cooling - Economizer Installation 73.4% 90.0% 15 $0.15 0.0 0.02 $1.832 Heat Pump - Maintenance 24.1% 100.0% 4 $0.06 0.8 0.66 $0.021 Insulation - Ducting 2.0% 100.0% 20 $0.41 0.0 0.32 $0.695 Repair and Sealing - Ducting 5.0% 50.0% 15 $0.38 0.1 0.34 $0.240 Energy Management System 82.8% 100.0% 14 $0.35 2.9 0.78 $0.011 Cooking - Exhaust Hoods with Sensor Control 1.0% 10.0% 10 $0.04 0.0 0.11 $0.098 Fans - Energy Efficient Motors 11.0% 100.0% 10 $0.05 0.1 0.17 $0.061 Fans - Variable Speed Control 21.7% 100.0% 10 $0.20 0.6 0.29 $0.037 Retrocommissioning - HVAC 15.0% 100.0% 4 $0.20 0.1 0.32 $0.714 Pumps - Variable Speed Control 1.0% 45.0% 10 $0.44 0.0 0.00 $7.933 Thermostat - Clock/Programmable 25.0% 50.0% 11 $0.11 1.3 1.02 $0.010 Insulation - Ceiling 2.0% 90.0% 20 $0.85 0.1 0.32 $0.687 Insulation - Radiant Barrier 2.0% 25.0% 20 $0.26 0.0 0.31 $1.057 Roofs - High Reflectivity 0.0% 100.0% 15 $0.18 0.0 0.02 $2.179 Windows - High Efficiency 94.6% 100.0% 20 $2.10 0.0 0.30 $3.948 Interior Lighting - Central Lighting Controls 78.1% 100.0% 8 $0.65 - - $0.000 Interior Lighting - Photocell Controlled T8 Dimming Ballasts 2.5% 60.0% 8 $0.40 0.5 0.11 $0.105 Exterior Lighting - Daylighting Controls 1.6% 20.0% 8 $0.29 - 0.00 $0.000 Interior Fluorescent - Bi-Level Fixture w/Occupancy Sensor 10.0% 30.0% 8 $0.20 0.2 0.09 $0.131 Interior Fluorescent - High Bay Fixtures 11.4% 30.0% 11 $0.56 1.1 0.17 $0.056 Interior Lighting - Occupancy Sensors 43.5% 60.0% 8 $0.20 - 0.06 $0.000 Exterior Lighting - Photovoltaic Installation 0.0% 0.0% 0 $0.00 - - $0.000 Interior Screw-in - Task Lighting 0.0% 0.0% 0 $0.00 - - $0.000 Interior Lighting - Time Clocks and Timers 0.0% 0.0% 0 $0.00 - - $0.000 Water Heater - Faucet Aerators/Low Flow Nozzles 0.0% 0.0% 0 $0.00 - - $0.000 Water Heater - Pipe Insulation 0.0% 0.0% 0 $0.00 - - $0.000 Water Heater - High Efficiency Circulation Pump 0.0% 0.0% 0 $0.00 - - $0.000 Water Heater - Tank Blanket/Insulation 0.0% 0.0% 0 $0.00 - - $0.000 Water Heater - Thermostat Setback 0.0% 0.0% 0 $0.00 - - $0.000 Refrigeration - Anti-Sweat Heater/Auto Door Closer 0.0% 0.0% 0 $0.00 - - $0.000 Refrigeration - Floating Head Pressure 0.0% 0.0% 0 $0.00 - - $0.000 Refrigeration - Door Gasket Replacement 0.0% 0.0% 0 $0.00 - - $0.000 Insulation - Bare Suction Lines 0.0% 0.0% 0 $0.00 - - $0.000 Refrigeration - Night Covers 0.0% 0.0% 0 $0.00 - - $0.000 Refrigeration - Strip Curtain 0.0% 0.0% 0 $0.00 - - $0.000 Vending Machine - Controller 0.0% 0.0% 0 $0.00 - - $0.000 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1056 of 1125 C&I Energy Efficiency Equipment and Measure Data C-80 www.enernoc.com Measure Base Saturation Applicability Lifetime (Years) Incremental Cost ($/SqFt) Savings (kWh/SqFt) BC Ratio (2015) Levelized Cost of Energy ($/kWh) LED Exit Lighting 0.0% 0.0% 0 $0.00 - - $0.000 Retrocommissioning - Lighting 0.0% 0.0% 0 $0.00 - - $0.000 Refrigeration - High Efficiency Case Lighting 0.0% 0.0% 0 $0.00 - - $0.000 Exterior Lighting - Cold Cathode Lighting 0.0% 0.0% 0 $0.00 - - $0.000 Laundry - High Efficiency Clothes Washer 0.0% 0.0% 0 $0.00 - - $0.000 Interior Lighting - Hotel Guestroom Controls 0.0% 0.0% 0 $0.00 - - $0.000 Miscellaneous - Energy Star Water Cooler 0.0% 0.0% 0 $0.00 - - $0.000 Interior Lighting - Skylights 0.0% 0.0% 0 $0.00 - - $0.000 Ventilation - Demand Control Ventilation 0.0% 0.0% 0 $0.00 - - $0.000 Office Equipment - Smart Power Strips 0.0% 0.0% 0 $0.00 - - $0.000 Strategic Energy Management 0.0% 0.0% 0 $0.00 - - $0.000 Refrigeration - Multiplex - Floating section Pressure - Air-cooled Cond. 0.0% 0.0% 0 $0.00 - - $0.000 Refrigeration - Multiplex Controls - Floating section Pressure - Evap. Cond. 0.0% 0.0% 0 $0.00 - - $0.000 Refrigeration - Multiplex - Eff. Air- cooled Condenser 0.0% 0.0% 0 $0.00 - - $0.000 Refrigeration - Multiplex - Eff. Water-cooled Condenser 0.0% 0.0% 0 $0.00 - - $0.000 RTU - Maintenance 54.2% 100.0% 4 $0.06 0.3 0.26 $0.050 RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 1.1 0.12 $0.068 Chiller - Chilled Water Reset 36.0% 100.0% 4 $0.09 0.3 0.19 $0.072 Chiller - Chilled Water Variable-Flow System 30.0% 45.0% 10 $0.09 0.1 0.11 $0.097 Chiller - VSD 3.0% 100.0% 20 $1.17 0.7 0.06 $0.118 Chiller - High Efficiency Cooling Tower Fans 25.0% 73.7% 10 $0.04 0.0 0.00 $12.451 Chiller - Condenser Water Temprature Reset 31.4% 100.0% 14 $0.09 0.3 0.37 $0.025 Cooling - Economizer Installation 73.4% 90.0% 15 $0.15 0.0 0.02 $1.832 Heat Pump - Maintenance 24.1% 100.0% 4 $0.06 0.8 0.66 $0.021 Insulation - Ducting 2.0% 100.0% 20 $0.41 0.0 0.32 $0.695 Repair and Sealing - Ducting 5.0% 50.0% 15 $0.38 0.1 0.34 $0.240 Energy Management System 82.8% 100.0% 14 $0.35 2.9 0.78 $0.011 Cooking - Exhaust Hoods with Sensor Control 1.0% 10.0% 10 $0.04 0.0 0.11 $0.098 Fans - Energy Efficient Motors 11.0% 100.0% 10 $0.05 0.1 0.17 $0.061 Fans - Variable Speed Control 21.7% 100.0% 10 $0.20 0.6 0.29 $0.037 Retrocommissioning - HVAC 15.0% 100.0% 4 $0.20 0.1 0.32 $0.714 Pumps - Variable Speed Control 1.0% 45.0% 10 $0.44 0.0 0.00 $7.933 Thermostat - Clock/Programmable 25.0% 50.0% 11 $0.11 1.3 1.02 $0.010 Insulation - Ceiling 2.0% 90.0% 20 $0.85 0.1 0.32 $0.687 Insulation - Radiant Barrier 2.0% 25.0% 20 $0.26 0.0 0.31 $1.057 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1057 of 1125 C&I Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting C-81 Table C-30 Energy Efficiency Non-Equipment Data— Extra Large Commercial, New Vintage, Idaho Measure Base Saturation Applicability Lifetime (Years) Incremental Cost ($/SqFt) Savings (kWh/SqFt) BC Ratio (2015) Levelized Cost of Energy ($/kWh) RTU - Maintenance 48.7% 100.0% 4 $0.06 0.2 0.17 $0.086 RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 0.9 0.11 $0.082 Chiller - Chilled Water Reset 60.0% 100.0% 4 $0.09 0.3 0.17 $0.091 Chiller - Chilled Water Variable-Flow System 30.0% 45.0% 10 $0.09 0.1 0.09 $0.127 Chiller - VSD 3.0% 100.0% 20 $1.17 0.6 0.06 $0.138 Chiller - High Efficiency Cooling Tower Fans 25.0% 73.7% 10 $0.04 0.0 0.00 $11.601 Chiller - Condenser Water Temprature Reset 57.1% 100.0% 14 $0.09 0.3 0.37 $0.030 Cooling - Economizer Installation 73.4% 90.0% 15 $0.15 - 0.02 $0.000 Heat Pump - Maintenance 24.1% 100.0% 4 $0.06 0.6 0.58 $0.026 Insulation - Ducting 4.6% 50.0% 20 $0.41 0.3 0.38 $0.088 Energy Management System 82.8% 100.0% 14 $0.35 2.5 0.73 $0.013 Cooking - Exhaust Hoods with Sensor Control 1.0% 10.0% 10 $0.04 0.0 0.10 $0.111 Fans - Energy Efficient Motors 28.9% 100.0% 10 $0.05 0.1 0.18 $0.070 Fans - Variable Speed Control 47.3% 100.0% 10 $0.20 0.6 0.31 $0.037 Pumps - Variable Speed Control 1.0% 45.0% 10 $0.44 0.0 0.00 $7.545 Thermostat - Clock/Programmable 30.3% 50.0% 11 $0.11 1.6 1.33 $0.007 Insulation - Ceiling 14.5% 90.0% 20 $0.35 0.4 0.43 $0.056 Insulation - Radiant Barrier 5.5% 25.0% 20 $0.26 0.9 0.62 $0.021 Roofs - High Reflectivity 5.0% 100.0% 15 $0.18 - 0.01 $0.000 Windows - High Efficiency 94.6% 100.0% 20 $1.69 1.1 0.36 $0.106 Interior Lighting - Central Lighting Controls 82.5% 100.0% 8 $0.65 3.0 0.39 $0.031 Interior Lighting - Photocell Controlled T8 Dimming Ballasts 2.5% 60.0% 8 $0.30 0.5 0.14 $0.086 Exterior Lighting - Daylighting Controls 10.0% 20.0% 8 $0.19 0.3 0.16 $0.079 Interior Fluorescent - Bi-Level Fixture w/Occupancy Sensor 10.0% 30.0% 8 $0.20 0.2 0.09 $0.143 Interior Fluorescent - High Bay Fixtures 10.8% 30.0% 11 $0.56 1.0 0.17 $0.061 Interior Lighting - Occupancy Sensors 48.7% 60.0% 8 $0.20 3.0 1.32 $0.009 Exterior Lighting - Photovoltaic Installation 5.0% 25.0% 5 $0.92 0.4 0.03 $0.481 Interior Screw-in - Task Lighting 25.0% 100.0% 5 $0.24 0.1 0.04 $0.376 Interior Lighting - Time Clocks and Timers 25.4% 75.0% 8 $0.20 1.5 0.67 $0.019 Water Heater - Faucet Aerators/Low Flow Nozzles 47.3% 100.0% 9 $0.03 0.1 0.44 $0.027 Water Heater - Pipe Insulation 0.0% 0.0% 15 $0.28 0.1 0.05 $0.180 Water Heater - High Efficiency Circulation Pump 0.6% 25.0% 10 $0.11 2.5 2.16 $0.005 Water Heater - Tank Blanket/Insulation 0.0% 0.0% 10 $0.04 0.1 0.21 $0.052 Water Heater - Thermostat Setback 0.0% 0.0% 10 $0.11 0.1 0.12 $0.090 Refrigeration - Anti-Sweat Heater/Auto Door Closer 0.0% 100.0% 16 $0.20 0.0 0.01 $1.217 Refrigeration - Floating Head Pressure 10.0% 50.0% 16 $0.35 0.5 0.13 $0.063 Refrigeration - Door Gasket Replacement 5.0% 100.0% 8 $0.10 0.0 0.02 $0.721 Insulation - Bare Suction Lines 18.5% 100.0% 8 $0.10 0.5 0.39 $0.031 Refrigeration - Night Covers 5.0% 100.0% 8 $0.05 0.0 0.06 $0.263 Refrigeration - Strip Curtain 29.7% 56.3% 4 $0.00 0.0 3.11 $0.005 Vending Machine - Controller 2.0% 10.0% 10 $0.27 0.0 0.01 $0.784 LED Exit Lighting 91.2% 90.0% 10 $0.00 0.0 5.56 $0.004 Refrigeration - High Efficiency Case 24.0% 56.0% 6 $0.02 0.0 0.09 $0.170 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1058 of 1125 C&I Energy Efficiency Equipment and Measure Data C-82 www.enernoc.com Measure Base Saturation Applicability Lifetime (Years) Incremental Cost ($/SqFt) Savings (kWh/SqFt) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Lighting Exterior Lighting - Cold Cathode Lighting 14.6% 50.0% 5 $0.00 0.3 23.65 $0.001 Laundry - High Efficiency Clothes Washer 6.9% 10.0% 10 $0.00 0.0 2.93 $0.004 Interior Lighting - Hotel Guestroom Controls 1.0% 2.0% 8 $0.14 0.1 0.08 $0.158 Miscellaneous - Energy Star Water Cooler 5.0% 100.0% 8 $0.00 0.0 0.17 $0.073 Interior Lighting - Skylights 0.0% 0.0% 0 $0.00 4.5 1.00 $0.000 Ventilation - Demand Control Ventilation 10.2% 10.0% 10 $0.04 0.6 1.34 $0.009 Office Equipment - Smart Power Strips 15.4% 30.0% 7 $0.00 0.3 232.67 $0.000 Strategic Energy Management 0.0% 0.0% 3 $0.00 - 6.00 $0.000 Refrigeration - Multiplex - Floating section Pressure - Air-cooled Cond. 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Refrigeration - Multiplex Controls - Floating section Pressure - Evap. Cond. 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Refrigeration - Multiplex - Eff. Air- cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Refrigeration - Multiplex - Eff. Water-cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000 RTU - Maintenance 48.7% 100.0% 4 $0.06 0.2 0.17 $0.086 RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 0.9 0.11 $0.082 Chiller - Chilled Water Reset 60.0% 100.0% 4 $0.09 0.3 0.17 $0.091 Chiller - Chilled Water Variable-Flow System 30.0% 45.0% 10 $0.09 0.1 0.09 $0.127 Chiller - VSD 3.0% 100.0% 20 $1.17 0.6 0.06 $0.138 Chiller - High Efficiency Cooling Tower Fans 25.0% 73.7% 10 $0.04 0.0 0.00 $11.601 Chiller - Condenser Water Temprature Reset 57.1% 100.0% 14 $0.09 0.3 0.37 $0.030 Cooling - Economizer Installation 73.4% 90.0% 15 $0.15 - 0.02 $0.000 Heat Pump - Maintenance 24.1% 100.0% 4 $0.06 0.6 0.58 $0.026 Insulation - Ducting 4.6% 50.0% 20 $0.41 0.3 0.38 $0.088 Energy Management System 82.8% 100.0% 14 $0.35 2.5 0.73 $0.013 Cooking - Exhaust Hoods with Sensor Control 1.0% 10.0% 10 $0.04 0.0 0.10 $0.111 Fans - Energy Efficient Motors 28.9% 100.0% 10 $0.05 0.1 0.18 $0.070 Fans - Variable Speed Control 47.3% 100.0% 10 $0.20 0.6 0.31 $0.037 Pumps - Variable Speed Control 1.0% 45.0% 10 $0.44 0.0 0.00 $7.545 Thermostat - Clock/Programmable 30.3% 50.0% 11 $0.11 1.6 1.33 $0.007 Insulation - Ceiling 14.5% 90.0% 20 $0.35 0.4 0.43 $0.056 Insulation - Radiant Barrier 5.5% 25.0% 20 $0.26 0.9 0.62 $0.021 Roofs - High Reflectivity 5.0% 100.0% 15 $0.18 - 0.01 $0.000 Windows - High Efficiency 94.6% 100.0% 20 $1.69 1.1 0.36 $0.106 Interior Lighting - Central Lighting Controls 82.5% 100.0% 8 $0.65 3.0 0.39 $0.031 Interior Lighting - Photocell Controlled T8 Dimming Ballasts 2.5% 60.0% 8 $0.30 0.5 0.14 $0.086 Exterior Lighting - Daylighting Controls 10.0% 20.0% 8 $0.19 0.3 0.16 $0.079 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1059 of 1125 C&I Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting C-83 Table C-31 Energy Efficiency Non-Equipment Data— Extra Large Industrial, Existing Vintage, Washington Measure Base Saturation Applicability Lifetime (Years) Incremental Cost ($/SqFt) Savings (kWh/SqFt) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Refrigeration - System Controls 5.0% 45.0% 10 $0.40 0.2 0.06 $0.198 Refrigeration - System Maintenance 13.6% 45.0% 10 $0.00 0.1 7.74 $0.001 Refrigeration - System Optimization 5.0% 45.0% 10 $0.80 0.2 0.03 $0.396 Motors - Variable Frequency Drive 25.0% 50.0% 10 $0.10 - 0.00 $0.000 Motors - Magnetic Adjustable Speed Drives 20.0% 25.0% 10 $0.10 - 0.02 $0.000 Compressed Air - System Controls 0.0% 0.0% 15 $0.01 - 0.08 $0.000 Compressed Air - System Optimization and Improvements 35.0% 75.0% 10 $0.20 - 0.01 $0.000 Compressed Air - System Maintenance 0.0% 0.0% 3 $0.03 - - $0.000 Compressed Air - Compressor Replacement 14.6% 17.1% 10 $0.06 - 0.02 $0.000 Fan System - Controls 7.8% 8.2% 10 $0.01 0.0 0.37 $0.036 Fan System - Optimization 6.6% 8.9% 10 $0.13 0.2 0.15 $0.085 Fan System - Maintenance 3.0% 11.3% 3 $0.01 0.0 0.07 $0.251 Pumping System - Controls 6.9% 9.3% 10 $0.01 - 0.02 $0.000 Pumping System - Optimization 6.7% 9.0% 10 $0.28 - 0.01 $0.000 Pumping System - Maintenance 1.5% 10.1% 3 $0.02 - - $0.000 RTU - Maintenance 21.9% 100.0% 4 $0.06 0.4 0.29 $0.045 Chiller - Chilled Water Reset 30.0% 100.0% 4 $0.09 0.4 0.22 $0.062 Chiller - Chilled Water Variable-Flow System 30.0% 45.0% 10 $0.20 0.1 0.04 $0.236 Chiller - VSD 15.0% 89.0% 20 $1.17 0.8 0.06 $0.105 Chiller - High Efficiency Cooling Tower Fans 25.0% 100.0% 10 $0.04 0.0 0.00 $9.998 Chiller - Condenser Water Temprature Reset 0.0% 100.0% 14 $0.20 0.4 0.17 $0.045 Cooling - Economizer Installation 29.1% 45.0% 15 $0.15 0.1 0.03 $0.211 Heat Pump - Maintenance 21.7% 100.0% 4 $0.03 1.1 1.82 $0.007 Insulation - Ducting 11.8% 100.0% 20 $0.41 0.0 0.31 $4.048 Repair and Sealing - Ducting 5.0% 50.0% 15 $0.38 0.0 0.31 $1.794 Energy Management System 11.0% 100.0% 14 $0.35 4.3 1.10 $0.007 Fans - Energy Efficient Motors 0.0% 0.0% 10 $0.14 0.1 0.07 $0.159 Fans - Variable Speed Control 0.0% 0.0% 10 $0.20 0.4 0.17 $0.057 Retrocommissioning - HVAC 1.4% 93.3% 4 $0.25 0.0 0.31 $2.167 Pumps - Variable Speed Control 0.1% 0.0% 10 $0.44 - 0.00 $0.000 Thermostat - Clock/Programmable 59.0% 70.0% 11 $0.11 2.0 1.71 $0.006 Interior Lighting - Central Lighting Controls 83.7% 100.0% 8 $0.65 0.0 0.00 $22.297 Exterior Lighting - Daylighting Controls 1.6% 53.6% 8 $0.08 - 0.00 $0.000 Interior Fluorescent - High Bay Fixtures 19.1% 50.0% 11 $0.20 1.7 0.59 $0.013 LED Exit Lighting 46.9% 90.0% 10 $0.00 0.0 1.34 $0.006 Retrocommissioning - Lighting 9.0% 93.0% 5 $0.05 0.0 0.00 $2.594 Interior Lighting - Occupancy Sensors 14.7% 60.0% 8 $0.20 0.0 0.00 $6.861 Exterior Lighting - Photovoltaic Installation 5.0% 25.0% 5 $0.92 - - $0.000 Interior Screw-in - Task Lighting 10.0% 100.0% 5 $0.24 0.1 0.02 $0.500 Interior Lighting - Time Clocks and Timers 2.4% 75.0% 8 $0.20 0.0 0.04 $13.721 Exterior Lighting - Cold Cathode Lighting 14.6% 50.0% 5 $0.00 0.4 16.94 $0.001 Interior Lighting - Skylights 1.2% 40.6% 8 $0.29 0.0 0.00 $6.518 Ventilation - Demand Control Ventilation 1.0% 10.0% 10 $0.04 0.0 0.14 $0.103 Strategic Energy Management 0.0% 20.0% 3 $0.02 0.0 0.09 $0.173 Transformers 8.6% 9.4% 10 $0.13 0.0 0.04 $0.413 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1060 of 1125 C&I Energy Efficiency Equipment and Measure Data C-84 www.enernoc.com Measure Base Saturation Applicability Lifetime (Years) Incremental Cost ($/SqFt) Savings (kWh/SqFt) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Motors - Synchronous belts 17.3% 21.0% 10 $0.22 - 0.00 $0.000 Refrigeration - Multiplex - Floating section Pressure - Air-cooled Cond. 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Refrigeration - Multiplex Controls - Floating section Pressure - Evap. Cond. 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Refrigeration - Multiplex - Eff. Air- cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Refrigeration - Multiplex - Eff. Water-cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Refrigeration - System Controls 5.0% 45.0% 10 $0.40 0.2 0.06 $0.198 Refrigeration - System Maintenance 13.6% 45.0% 10 $0.00 0.1 7.74 $0.001 Refrigeration - System Optimization 5.0% 45.0% 10 $0.80 0.2 0.03 $0.396 Motors - Variable Frequency Drive 25.0% 50.0% 10 $0.10 - 0.00 $0.000 Motors - Magnetic Adjustable Speed Drives 20.0% 25.0% 10 $0.10 - 0.02 $0.000 Compressed Air - System Controls 0.0% 0.0% 15 $0.01 - 0.08 $0.000 Compressed Air - System Optimization and Improvements 35.0% 75.0% 10 $0.20 - 0.01 $0.000 Compressed Air - System Maintenance 0.0% 0.0% 3 $0.03 - - $0.000 Compressed Air - Compressor Replacement 14.6% 17.1% 10 $0.06 - 0.02 $0.000 Fan System - Controls 7.8% 8.2% 10 $0.01 0.0 0.37 $0.036 Fan System - Optimization 6.6% 8.9% 10 $0.13 0.2 0.15 $0.085 Fan System - Maintenance 3.0% 11.3% 3 $0.01 0.0 0.07 $0.251 Pumping System - Controls 6.9% 9.3% 10 $0.01 - 0.02 $0.000 Pumping System - Optimization 6.7% 9.0% 10 $0.28 - 0.01 $0.000 Pumping System - Maintenance 1.5% 10.1% 3 $0.02 - - $0.000 RTU - Maintenance 21.9% 100.0% 4 $0.06 0.4 0.29 $0.045 Chiller - Chilled Water Reset 30.0% 100.0% 4 $0.09 0.4 0.22 $0.062 Chiller - Chilled Water Variable-Flow System 30.0% 45.0% 10 $0.20 0.1 0.04 $0.236 Chiller - VSD 15.0% 89.0% 20 $1.17 0.8 0.06 $0.105 Chiller - High Efficiency Cooling Tower Fans 25.0% 100.0% 10 $0.04 0.0 0.00 $9.998 Chiller - Condenser Water Temprature Reset 0.0% 100.0% 14 $0.20 0.4 0.17 $0.045 Cooling - Economizer Installation 29.1% 45.0% 15 $0.15 0.1 0.03 $0.211 Heat Pump - Maintenance 21.7% 100.0% 4 $0.03 1.1 1.82 $0.007 Insulation - Ducting 11.8% 100.0% 20 $0.41 0.0 0.31 $4.048 Repair and Sealing - Ducting 5.0% 50.0% 15 $0.38 0.0 0.31 $1.794 Energy Management System 11.0% 100.0% 14 $0.35 4.3 1.10 $0.007 Fans - Energy Efficient Motors 0.0% 0.0% 10 $0.14 0.1 0.07 $0.159 Fans - Variable Speed Control 0.0% 0.0% 10 $0.20 0.4 0.17 $0.057 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1061 of 1125 C&I Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting C-85 Table C-32 Energy Efficiency Non-Equipment Data— Extra Large Industrial, New Vintage, Washington Measure Base Saturation Applicability Lifetime (Years) Incremental Cost ($/SqFt) Savings (kWh/SqFt) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Refrigeration - System Controls 5.0% 45.0% 10 $0.40 0.2 0.06 $0.198 Refrigeration - System Maintenance 13.6% 45.0% 10 $0.00 0.1 7.89 $0.001 Refrigeration - System Optimization 5.0% 45.0% 10 $0.80 0.2 0.03 $0.396 Motors - Variable Frequency Drive 25.0% 50.0% 10 $0.10 0.2 0.15 $0.072 Motors - Magnetic Adjustable Speed Drives 24.0% 25.0% 10 $0.10 0.7 0.65 $0.017 Compressed Air - System Controls 0.0% 0.0% 15 $0.01 0.3 2.98 $0.003 Compressed Air - System Optimization and Improvements 44.8% 75.0% 10 $0.20 0.8 0.38 $0.029 Compressed Air - System Maintenance 0.0% 0.0% 3 $0.03 0.1 0.10 $0.175 Compressed Air - Compressor Replacement 17.6% 17.1% 10 $0.06 0.6 0.84 $0.013 Fan System - Controls 7.8% 8.2% 10 $0.01 0.0 0.37 $0.036 Fan System - Optimization 6.6% 8.9% 10 $0.13 0.2 0.15 $0.085 Fan System - Maintenance 3.0% 11.3% 3 $0.01 0.0 0.07 $0.251 Pumping System - Controls 8.6% 9.3% 10 $0.01 0.1 1.04 $0.011 Pumping System - Optimization 6.7% 9.0% 10 $0.28 0.8 0.28 $0.040 Pumping System - Maintenance 1.5% 10.1% 3 $0.02 0.1 0.15 $0.117 RTU - Maintenance 21.9% 100.0% 4 $0.06 0.2 0.20 $0.073 Chiller - Chilled Water Reset 60.0% 100.0% 4 $0.09 0.3 0.19 $0.077 Chiller - Chilled Water Variable-Flow System 30.0% 45.0% 10 $0.20 0.1 0.06 $0.158 Chiller - VSD 25.0% 89.0% 20 $1.17 0.7 0.06 $0.119 Chiller - High Efficiency Cooling Tower Fans 25.0% 100.0% 10 $0.04 0.0 0.01 $1.019 Chiller - Condenser Water Temprature Reset 5.0% 100.0% 14 $0.20 0.4 0.16 $0.051 Cooling - Economizer Installation 29.1% 45.0% 15 $0.15 - - $0.000 Heat Pump - Maintenance 21.7% 100.0% 4 $0.03 0.6 1.07 $0.014 Insulation - Ducting 11.8% 50.0% 20 $0.41 - 0.31 $0.000 Energy Management System 23.6% 100.0% 14 $0.35 4.9 1.28 $0.007 Fans - Energy Efficient Motors 0.0% 0.0% 10 $0.14 0.1 0.06 $0.187 Fans - Variable Speed Control 0.0% 0.0% 10 $0.34 0.4 0.10 $0.114 Pumps - Variable Speed Control 0.1% 0.0% 10 $0.44 0.2 0.03 $0.316 Thermostat - Clock/Programmable 59.0% 70.0% 11 $0.11 1.7 1.41 $0.007 Interior Lighting - Central Lighting Controls 83.7% 100.0% 8 $0.65 1.4 0.18 $0.067 Exterior Lighting - Daylighting Controls 19.7% 53.6% 8 $0.08 1.4 1.52 $0.008 Interior Fluorescent - High Bay Fixtures 19.1% 50.0% 11 $0.20 1.2 0.58 $0.018 LED Exit Lighting 91.2% 90.0% 10 $0.00 0.0 1.62 $0.006 Interior Lighting - Occupancy Sensors 25.0% 60.0% 8 $0.20 1.4 0.58 $0.021 Exterior Lighting - Photovoltaic Installation 5.0% 25.0% 5 $0.92 2.7 0.21 $0.072 Interior Screw-in - Task Lighting 10.0% 100.0% 5 $0.24 0.1 0.03 $0.527 Interior Lighting - Time Clocks and Timers 2.4% 75.0% 8 $0.20 0.7 0.34 $0.041 Exterior Lighting - Cold Cathode Lighting 8.4% 50.0% 5 $0.00 0.3 19.87 $0.001 Interior Lighting - Skylights 5.3% 40.6% 8 $0.19 2.1 0.92 $0.013 Ventilation - Demand Control Ventilation 10.2% 10.0% 10 $0.04 0.2 0.55 $0.022 Strategic Energy Management 2.8% 20.0% 3 $0.02 1.9 4.54 $0.004 Transformers 8.6% 9.4% 10 $0.13 0.4 0.28 $0.040 Motors - Synchronous belts 17.3% 21.0% 10 $0.22 - 0.00 $0.000 Refrigeration - Multiplex - Floating section Pressure - Air-cooled Cond. 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Refrigeration - Multiplex Controls - 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1062 of 1125 C&I Energy Efficiency Equipment and Measure Data C-86 www.enernoc.com Measure Base Saturation Applicability Lifetime (Years) Incremental Cost ($/SqFt) Savings (kWh/SqFt) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Floating section Pressure - Evap. Cond. Refrigeration - Multiplex - Eff. Air- cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Refrigeration - Multiplex - Eff. Water-cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Commissioning - HVAC 60.0% 100.0% 25 $0.70 0.1 0.02 $0.481 Commissioning - Lighting 78.5% 100.0% 25 $0.10 2.2 2.28 $0.003 Advanced New Construction Designs 11.9% 100.0% 35 $2.00 3.5 0.17 $0.030 Refrigeration - System Controls 5.0% 45.0% 10 $0.40 0.2 0.06 $0.198 Refrigeration - System Maintenance 13.6% 45.0% 10 $0.00 0.1 7.89 $0.001 Refrigeration - System Optimization 5.0% 45.0% 10 $0.80 0.2 0.03 $0.396 Motors - Variable Frequency Drive 25.0% 50.0% 10 $0.10 0.2 0.15 $0.072 Motors - Magnetic Adjustable Speed Drives 24.0% 25.0% 10 $0.10 0.7 0.65 $0.017 Compressed Air - System Controls 0.0% 0.0% 15 $0.01 0.3 2.98 $0.003 Compressed Air - System Optimization and Improvements 44.8% 75.0% 10 $0.20 0.8 0.38 $0.029 Compressed Air - System Maintenance 0.0% 0.0% 3 $0.03 0.1 0.10 $0.175 Compressed Air - Compressor Replacement 17.6% 17.1% 10 $0.06 0.6 0.84 $0.013 Fan System - Controls 7.8% 8.2% 10 $0.01 0.0 0.37 $0.036 Fan System - Optimization 6.6% 8.9% 10 $0.13 0.2 0.15 $0.085 Fan System - Maintenance 3.0% 11.3% 3 $0.01 0.0 0.07 $0.251 Pumping System - Controls 8.6% 9.3% 10 $0.01 0.1 1.04 $0.011 Pumping System - Optimization 6.7% 9.0% 10 $0.28 0.8 0.28 $0.040 Pumping System - Maintenance 1.5% 10.1% 3 $0.02 0.1 0.15 $0.117 RTU - Maintenance 21.9% 100.0% 4 $0.06 0.2 0.20 $0.073 Chiller - Chilled Water Reset 60.0% 100.0% 4 $0.09 0.3 0.19 $0.077 Chiller - Chilled Water Variable-Flow System 30.0% 45.0% 10 $0.20 0.1 0.06 $0.158 Chiller - VSD 25.0% 89.0% 20 $1.17 0.7 0.06 $0.119 Chiller - High Efficiency Cooling Tower Fans 25.0% 100.0% 10 $0.04 0.0 0.01 $1.019 Chiller - Condenser Water Temprature Reset 5.0% 100.0% 14 $0.20 0.4 0.16 $0.051 Cooling - Economizer Installation 29.1% 45.0% 15 $0.15 - - $0.000 Heat Pump - Maintenance 21.7% 100.0% 4 $0.03 0.6 1.07 $0.014 Insulation - Ducting 11.8% 50.0% 20 $0.41 - 0.31 $0.000 Energy Management System 23.6% 100.0% 14 $0.35 4.9 1.28 $0.007 Fans - Energy Efficient Motors 0.0% 0.0% 10 $0.14 0.1 0.06 $0.187 Fans - Variable Speed Control 0.0% 0.0% 10 $0.34 0.4 0.10 $0.114 Pumps - Variable Speed Control 0.1% 0.0% 10 $0.44 0.2 0.03 $0.316 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1063 of 1125 C&I Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting C-87 Table C-33 Energy Efficiency Non-Equipment Data— Extra Large Industrial, Existing Vintage, Idaho Measure Base Saturation Applicability Lifetime (Years) Incremental Cost ($/SqFt) Savings (kWh/SqFt) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Refrigeration - System Controls 11.1% 45.0% 10 $0.40 12.0 2.67 $0.004 Refrigeration - System Maintenance 11.1% 45.0% 10 $0.00 4.0 356.66 $0.000 Refrigeration - System Optimization 13.6% 45.0% 10 $0.80 12.0 1.34 $0.008 Motors - Variable Frequency Drive 32.5% 50.0% 10 $0.10 0.4 0.33 $0.033 Motors - Magnetic Adjustable Speed Drives 24.0% 25.0% 10 $0.10 1.5 1.41 $0.008 Compressed Air - System Controls 0.0% 0.0% 15 $0.01 0.7 6.38 $0.001 Compressed Air - System Optimization and Improvements 44.8% 75.0% 10 $0.20 1.8 0.82 $0.013 Compressed Air - System Maintenance 0.0% 0.0% 3 $0.03 0.1 0.22 $0.081 Compressed Air - Compressor Replacement 17.6% 17.1% 10 $0.06 1.3 1.81 $0.006 Fan System - Controls 7.8% 8.2% 10 $0.01 0.3 2.66 $0.004 Fan System - Optimization 8.3% 8.9% 10 $0.13 1.6 1.12 $0.010 Fan System - Maintenance 5.2% 11.3% 3 $0.01 0.1 0.61 $0.029 Pumping System - Controls 8.6% 9.3% 10 $0.01 0.3 2.23 $0.005 Pumping System - Optimization 8.4% 9.0% 10 $0.28 1.8 0.60 $0.018 Pumping System - Maintenance 2.9% 10.1% 3 $0.02 0.1 0.33 $0.054 RTU - Maintenance 37.6% 100.0% 4 $0.06 0.9 0.73 $0.018 Chiller - Chilled Water Reset 39.9% 100.0% 4 $0.09 1.3 0.74 $0.019 Chiller - Chilled Water Variable-Flow System 30.0% 45.0% 10 $0.20 0.3 0.13 $0.071 Chiller - VSD 50.0% 89.0% 20 $1.17 2.6 0.19 $0.032 Chiller - High Efficiency Cooling Tower Fans 25.0% 100.0% 10 $0.04 0.0 0.00 $2.995 Chiller - Condenser Water Temprature Reset 14.2% 100.0% 14 $0.20 1.3 0.55 $0.014 Cooling - Economizer Installation 29.1% 45.0% 15 $0.15 - - $0.000 Heat Pump - Maintenance 21.7% 100.0% 4 $0.03 1.0 1.70 $0.008 Insulation - Ducting 11.8% 100.0% 20 $0.41 - 0.30 $0.000 Repair and Sealing - Ducting 5.0% 50.0% 15 $0.38 - 0.31 $0.000 Energy Management System 11.0% 100.0% 14 $0.35 4.7 1.23 $0.007 Fans - Energy Efficient Motors 0.0% 0.0% 10 $0.14 0.6 0.73 $0.027 Fans - Variable Speed Control 0.0% 0.0% 10 $0.34 2.5 0.59 $0.016 Retrocommissioning - HVAC 1.4% 93.3% 4 $0.25 - 0.30 $0.000 Pumps - Variable Speed Control 0.1% 0.0% 10 $0.44 0.4 0.08 $0.146 Thermostat - Clock/Programmable 59.0% 70.0% 11 $0.11 2.5 2.04 $0.005 Interior Lighting - Central Lighting Controls 83.7% 100.0% 8 $0.65 - - $0.000 Exterior Lighting - Daylighting Controls 1.6% 53.6% 8 $0.08 - 0.00 $0.000 Interior Fluorescent - High Bay Fixtures 19.1% 50.0% 11 $0.20 0.6 0.19 $0.040 LED Exit Lighting 46.9% 90.0% 10 $0.00 0.0 0.39 $0.018 Retrocommissioning - Lighting 9.0% 93.0% 5 $0.05 - - $0.000 Interior Lighting - Occupancy Sensors 14.7% 60.0% 8 $0.20 - 0.00 $0.000 Exterior Lighting - Photovoltaic Installation 5.0% 25.0% 5 $0.92 - - $0.000 Interior Screw-in - Task Lighting 10.0% 100.0% 5 $0.24 0.0 0.01 $1.514 Interior Lighting - Time Clocks and Timers 2.4% 75.0% 8 $0.20 - 0.00 $0.000 Exterior Lighting - Cold Cathode Lighting 14.6% 50.0% 5 $0.00 0.1 5.34 $0.002 Interior Lighting - Skylights 1.2% 40.6% 8 $0.29 - 0.00 $0.000 Ventilation - Demand Control Ventilation 1.0% 10.0% 10 $0.04 - - $0.000 Strategic Energy Management 2.8% 20.0% 3 $0.02 0.3 0.64 $0.026 Transformers 9.8% 9.4% 10 $0.13 0.3 0.18 $0.060 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1064 of 1125 C&I Energy Efficiency Equipment and Measure Data C-88 www.enernoc.com Measure Base Saturation Applicability Lifetime (Years) Incremental Cost ($/SqFt) Savings (kWh/SqFt) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Motors - Synchronous belts 17.3% 21.0% 10 $0.22 - 0.01 $0.000 Refrigeration - Multiplex - Floating section Pressure - Air-cooled Cond. 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Refrigeration - Multiplex Controls - Floating section Pressure - Evap. Cond. 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Refrigeration - Multiplex - Eff. Air- cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Refrigeration - Multiplex - Eff. Water-cooled Condenser 0.0% 0.0% 0 $0.00 12.0 1.00 $0.000 Refrigeration - System Controls 11.1% 45.0% 10 $0.40 12.0 2.67 $0.004 Refrigeration - System Maintenance 11.1% 45.0% 10 $0.00 4.0 356.66 $0.000 Refrigeration - System Optimization 13.6% 45.0% 10 $0.80 12.0 1.34 $0.008 Motors - Variable Frequency Drive 32.5% 50.0% 10 $0.10 0.4 0.33 $0.033 Motors - Magnetic Adjustable Speed Drives 24.0% 25.0% 10 $0.10 1.5 1.41 $0.008 Compressed Air - System Controls 0.0% 0.0% 15 $0.01 0.7 6.38 $0.001 Compressed Air - System Optimization and Improvements 44.8% 75.0% 10 $0.20 1.8 0.82 $0.013 Compressed Air - System Maintenance 0.0% 0.0% 3 $0.03 0.1 0.22 $0.081 Compressed Air - Compressor Replacement 17.6% 17.1% 10 $0.06 1.3 1.81 $0.006 Fan System - Controls 7.8% 8.2% 10 $0.01 0.3 2.66 $0.004 Fan System - Optimization 8.3% 8.9% 10 $0.13 1.6 1.12 $0.010 Fan System - Maintenance 5.2% 11.3% 3 $0.01 0.1 0.61 $0.029 Pumping System - Controls 8.6% 9.3% 10 $0.01 0.3 2.23 $0.005 Pumping System - Optimization 8.4% 9.0% 10 $0.28 1.8 0.60 $0.018 Pumping System - Maintenance 2.9% 10.1% 3 $0.02 0.1 0.33 $0.054 RTU - Maintenance 37.6% 100.0% 4 $0.06 0.9 0.73 $0.018 Chiller - Chilled Water Reset 39.9% 100.0% 4 $0.09 1.3 0.74 $0.019 Chiller - Chilled Water Variable-Flow System 30.0% 45.0% 10 $0.20 0.3 0.13 $0.071 Chiller - VSD 50.0% 89.0% 20 $1.17 2.6 0.19 $0.032 Chiller - High Efficiency Cooling Tower Fans 25.0% 100.0% 10 $0.04 0.0 0.00 $2.995 Chiller - Condenser Water Temprature Reset 14.2% 100.0% 14 $0.20 1.3 0.55 $0.014 Cooling - Economizer Installation 29.1% 45.0% 15 $0.15 - - $0.000 Heat Pump - Maintenance 21.7% 100.0% 4 $0.03 1.0 1.70 $0.008 Insulation - Ducting 11.8% 100.0% 20 $0.41 - 0.30 $0.000 Repair and Sealing - Ducting 5.0% 50.0% 15 $0.38 - 0.31 $0.000 Energy Management System 11.0% 100.0% 14 $0.35 4.7 1.23 $0.007 Fans - Energy Efficient Motors 0.0% 0.0% 10 $0.14 0.6 0.73 $0.027 Fans - Variable Speed Control 0.0% 0.0% 10 $0.34 2.5 0.59 $0.016 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1065 of 1125 C&I Energy Efficiency Equipment and Measure Data EnerNOC Utility Solutions Consulting C-89 Table C-34 Energy Efficiency Non-Equipment Data— Extra Large Industrial, New Vintage, Idaho Measure Base Saturation Applicability Lifetime (Years) Incrementa l Cost ($/SqFt) Savings (kWh/SqFt) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Refrigeration - System Controls 13.6% 45.0% 10 $0.40 4.0 0.91 $0.012 Refrigeration - System Maintenance 13.6% 45.0% 10 $0.00 12.0 1,086.05 $0.000 Refrigeration - System Optimization 5.0% 45.0% 10 $0.80 0.4 0.05 $0.215 Motors - Variable Frequency Drive 32.5% 50.0% 10 $0.10 1.9 1.72 $0.006 Motors - Magnetic Adjustable Speed Drives 24.0% 25.0% 10 $0.10 0.9 0.81 $0.013 Compressed Air - System Controls 0.0% 0.0% 15 $0.01 0.2 1.56 $0.005 Compressed Air - System Optimization and Improvements 44.8% 75.0% 10 $0.20 2.2 1.00 $0.011 Compressed Air - System Maintenance 0.0% 0.0% 3 $0.03 1.5 2.36 $0.007 Compressed Air - Compressor Replacement 14.6% 17.1% 10 $0.06 0.1 0.14 $0.082 Fan System - Controls 7.8% 8.2% 10 $0.01 0.7 5.80 $0.002 Fan System - Optimization 8.3% 8.9% 10 $0.13 1.2 0.81 $0.013 Fan System - Maintenance 5.2% 11.3% 3 $0.01 0.4 2.02 $0.009 Pumping System - Controls 8.6% 9.3% 10 $0.01 2.2 18.15 $0.001 Pumping System - Optimization 6.7% 9.0% 10 $0.28 0.2 0.06 $0.185 Pumping System - Maintenance 3.5% 10.1% 3 $0.02 0.6 1.26 $0.014 RTU - Maintenance 37.6% 100.0% 4 $0.06 1.0 0.94 $0.015 Chiller - Chilled Water Reset 63.4% 100.0% 4 $0.09 0.5 0.33 $0.048 Chiller - Chilled Water Variable-Flow System 34.5% 45.0% 10 $0.20 2.3 1.03 $0.010 Chiller - VSD 25.0% 89.0% 20 $1.17 0.0 0.00 $5.329 Chiller - High Efficiency Cooling Tower Fans 40.1% 100.0% 10 $0.04 1.2 2.65 $0.004 Chiller - Condenser Water Temprature Reset 5.0% 100.0% 14 $0.20 0.2 0.08 $0.103 Cooling - Economizer Installation 35.5% 45.0% 15 $0.15 0.5 0.29 $0.027 Heat Pump - Maintenance 21.7% 100.0% 4 $0.03 0.5 0.89 $0.017 Insulation - Ducting 11.8% 50.0% 20 $0.41 0.3 0.36 $0.114 Energy Management System 23.6% 100.0% 14 $0.35 4.7 1.26 $0.007 Fans - Energy Efficient Motors 0.0% 0.0% 10 $0.14 2.1 1.36 $0.008 Fans - Variable Speed Control 0.0% 0.0% 10 $0.34 0.1 0.03 $0.361 Pumps - Variable Speed Control 0.1% 0.0% 10 $0.44 0.1 0.01 $1.018 Thermostat - Clock/Programmable 63.1% 70.0% 11 $0.11 3.5 2.86 $0.003 Interior Lighting - Central Lighting Controls 83.7% 100.0% 8 $0.65 0.3 0.04 $0.283 Exterior Lighting - Daylighting Controls 19.7% 53.6% 8 $0.08 0.4 0.46 $0.028 Interior Fluorescent - High Bay Fixtures 10.0% 50.0% 11 $0.20 0.0 0.00 $3.499 LED Exit Lighting 91.2% 90.0% 10 $0.00 0.3 25.24 $0.000 Interior Lighting - Occupancy Sensors 25.0% 60.0% 8 $0.20 0.7 0.28 $0.044 Exterior Lighting - Photovoltaic Installation 5.0% 25.0% 5 $0.92 0.0 0.00 $6.107 Interior Screw-in - Task Lighting 10.0% 100.0% 5 $0.24 0.2 0.04 $0.315 Interior Lighting - Time Clocks and Timers 2.4% 75.0% 8 $0.20 0.1 0.04 $0.324 Exterior Lighting - Cold Cathode Lighting 8.4% 50.0% 5 $0.00 0.5 33.17 $0.000 Interior Lighting - Skylights 2.4% 40.6% 8 $0.19 0.1 0.06 $0.235 Ventilation - Demand Control Ventilation 6.0% 10.0% 10 $0.04 0.1 0.15 $0.082 Strategic Energy Management 2.8% 20.0% 3 $0.02 0.8 1.77 $0.010 Transformers 9.8% 9.4% 10 $0.13 0.3 0.23 $0.049 Motors - Synchronous belts 17.3% 21.0% 10 $0.22 0.0 0.01 $1.550 Refrigeration - Multiplex - Floating section Pressure - Air-cooled Cond. 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Refrigeration - Multiplex Controls - 0.0% 0.0% 0 $0.00 - 1.00 $0.000 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1066 of 1125 C&I Energy Efficiency Equipment and Measure Data C-90 www.enernoc.com Measure Base Saturation Applicability Lifetime (Years) Incrementa l Cost ($/SqFt) Savings (kWh/SqFt) BC Ratio (2015) Levelized Cost of Energy ($/kWh) Floating section Pressure - Evap. Cond. Refrigeration - Multiplex - Eff. Air- cooled Condenser 0.0% 0.0% 0 $0.00 0.3 1.00 $0.000 Refrigeration - Multiplex - Eff. Water-cooled Condenser 0.0% 0.0% 0 $0.00 0.2 1.00 $0.000 Commissioning - HVAC 78.5% 100.0% 25 $0.70 0.9 0.14 $0.046 Commissioning - Lighting 78.5% 100.0% 25 $0.10 0.5 0.57 $0.011 Advanced New Construction Designs 11.9% 100.0% 35 $2.00 2.9 0.14 $0.035 Refrigeration - System Controls 13.6% 45.0% 10 $0.40 4.0 0.91 $0.012 Refrigeration - System Maintenance 13.6% 45.0% 10 $0.00 12.0 1,086.05 $0.000 Refrigeration - System Optimization 5.0% 45.0% 10 $0.80 0.4 0.05 $0.215 Motors - Variable Frequency Drive 32.5% 50.0% 10 $0.10 1.9 1.72 $0.006 Motors - Magnetic Adjustable Speed Drives 24.0% 25.0% 10 $0.10 0.9 0.81 $0.013 Compressed Air - System Controls 0.0% 0.0% 15 $0.01 0.2 1.56 $0.005 Compressed Air - System Optimization and Improvements 44.8% 75.0% 10 $0.20 2.2 1.00 $0.011 Compressed Air - System Maintenance 0.0% 0.0% 3 $0.03 1.5 2.36 $0.007 Compressed Air - Compressor Replacement 14.6% 17.1% 10 $0.06 0.1 0.14 $0.082 Fan System - Controls 7.8% 8.2% 10 $0.01 0.7 5.80 $0.002 Fan System - Optimization 8.3% 8.9% 10 $0.13 1.2 0.81 $0.013 Fan System - Maintenance 5.2% 11.3% 3 $0.01 0.4 2.02 $0.009 Pumping System - Controls 8.6% 9.3% 10 $0.01 2.2 18.15 $0.001 Pumping System - Optimization 6.7% 9.0% 10 $0.28 0.2 0.06 $0.185 Pumping System - Maintenance 3.5% 10.1% 3 $0.02 0.6 1.26 $0.014 RTU - Maintenance 37.6% 100.0% 4 $0.06 1.0 0.94 $0.015 Chiller - Chilled Water Reset 63.4% 100.0% 4 $0.09 0.5 0.33 $0.048 Chiller - Chilled Water Variable-Flow System 34.5% 45.0% 10 $0.20 2.3 1.03 $0.010 Chiller - VSD 25.0% 89.0% 20 $1.17 0.0 0.00 $5.329 Chiller - High Efficiency Cooling Tower Fans 40.1% 100.0% 10 $0.04 1.2 2.65 $0.004 Chiller - Condenser Water Temprature Reset 5.0% 100.0% 14 $0.20 0.2 0.08 $0.103 Cooling - Economizer Installation 35.5% 45.0% 15 $0.15 0.5 0.29 $0.027 Heat Pump - Maintenance 21.7% 100.0% 4 $0.03 0.5 0.89 $0.017 Insulation - Ducting 11.8% 50.0% 20 $0.41 0.3 0.36 $0.114 Energy Management System 23.6% 100.0% 14 $0.35 4.7 1.26 $0.007 Fans - Energy Efficient Motors 0.0% 0.0% 10 $0.14 2.1 1.36 $0.008 Fans - Variable Speed Control 0.0% 0.0% 10 $0.34 0.1 0.03 $0.361 Pumps - Variable Speed Control 0.1% 0.0% 10 $0.44 0.1 0.01 $1.018 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1067 of 1125 EnerNOC Utility Solutions Consulting D-1 APPENDIX D MARKET ADOPTION FACTORS A set of market adoption factors are applied to Economic potential to estimate Achievable Potential. These estimate customer adoption of economic measures when delivered through efficiency programs under realistic market and customer preference conditions. They reflect expected program participation given barriers to customer acceptance and program implementation. These adoption rates generally increase over time, reflecting an increasing awareness and willingness to adopt energy-efficient measures. However, in some cases, where a new technology is introduced, the adoption rates drop to reflect that the new technology may not yet be accepted in the market. For mature measures, information channels are assumed to be established for marketing, educating consumers, and coordinating with trade allies and delivery partners. For evolving measures, this is not the case and thus the factors start at a lower level. The market adoption rates for the Avista study were developed using the ramp rates from the Northwest Power & Conservation Council’s Sixth Plan as a starting point. The ramp rates were then adjusted based on actual Avista program history and information from program evaluations. These adjustments mainly set the potential in the first years of the study to match with recent program achievements and thus show continuity of results. Table D-1 through Table D-2 present the Achievable Potential market adoption factors for the residential sector, first for equipment measures and then for non-equipment measures. Table D- 3 through Table D-4 present the market adoption factors for the commercial and industrial sector . Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1068 of 1125 EnerNOC Utility Solutions Consulting D-2 Table D-1 Residential Equipment Measures—Achievable Potential Market Adoption Factors End Use Fuel Technology 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 Cooling Electric Central AC 77% 78% 79% 80% 81% 82% 83% 84% 85% 85% 85% 85% 85% Cooling Electric Room AC 77% 78% 79% 80% 81% 82% 83% 84% 85% 85% 85% 85% 85% Cooling Electric Air Source Heat Pump 77% 78% 79% 80% 81% 82% 83% 84% 85% 85% 85% 85% 85% Cooling Electric Geothermal Heat Pump 77% 78% 79% 80% 81% 82% 83% 84% 85% 85% 85% 85% 85% Cooling Electric Ductless HP 56% 58% 59% 62% 66% 71% 76% 81% 83% 85% 85% 85% 85% Space Heating Electric Electric Resistance 6% 9% 11% 14% 17% 20% 23% 26% 28% 31% 34% 37% 40% Space Heating Electric Electric Furnace 60% 60% 60% 60% 60% 60% 60% 60% 60% 60% 60% 60% 60% Space Heating Electric Supplemental 11% 17% 23% 28% 34% 40% 45% 51% 57% 62% 68% 74% 79% Space Heating Electric Air Source Heat Pump 77% 78% 79% 80% 81% 82% 83% 84% 85% 85% 85% 85% 85% Space Heating Electric Geothermal Heat Pump 56% 58% 59% 62% 66% 71% 76% 81% 83% 85% 85% 85% 85% Space Heating Electric Ductless HP 28% 32% 37% 40% 43% 45% 46% 49% 52% 57% 62% 68% 73% Water Heating Electric Water Heater <= 55 Gal 5% 7% 9% 10% 12% 15% 20% 25% 30% 35% 40% 45% 50% Water Heating Electric Water Heater > 55 Gal 2% 3% 5% 8% 10% 12% 14% 34% 39% 45% 50% 50% 50% Interior Lighting Electric Screw-in 25% 25% 26% 27% 29% 31% 33% 35% 38% 41% 45% 50% 55% Interior Lighting Electric Linear Fluorescent 25% 25% 26% 27% 29% 31% 33% 35% 38% 41% 45% 50% 55% Interior Lighting Electric Specialty 25% 25% 26% 27% 29% 31% 33% 35% 38% 41% 45% 50% 55% Exterior Lighting Electric Screw-in 25% 25% 26% 27% 29% 31% 33% 35% 38% 41% 45% 50% 55% Appliances Electric Clothes Washer 56% 58% 59% 62% 66% 71% 76% 81% 83% 85% 85% 85% 85% Appliances Electric Clothes Dryer 56% 58% 59% 62% 66% 71% 76% 81% 83% 85% 85% 85% 85% Appliances Electric Dishwasher 56% 58% 59% 62% 66% 71% 76% 81% 83% 85% 85% 85% 85% Appliances Electric Refrigerator 56% 58% 59% 62% 66% 71% 76% 81% 83% 85% 85% 85% 85% Appliances Electric Freezer 56% 58% 59% 62% 66% 71% 76% 81% 83% 85% 85% 85% 85% Appliances Electric Second Refrigerator 56% 58% 59% 62% 66% 71% 76% 81% 83% 85% 85% 85% 85% Appliances Electric Stove 56% 58% 59% 62% 66% 71% 76% 81% 83% 85% 85% 85% 85% Appliances Electric Microwave 56% 58% 59% 62% 66% 71% 76% 81% 83% 85% 85% 85% 85% Electronics Electric Personal Computers 5% 8% 10% 13% 16% 19% 23% 26% 30% 33% 37% 40% 44% Electronics Electric TVs 11% 16% 21% 26% 31% 36% 41% 47% 52% 58% 63% 68% 72% Electronics Electric Set-top boxes/DVR 6% 9% 12% 15% 18% 22% 25% 29% 31% 34% 37% 40% 43% Electronics Electric Devices and Gadgets 6% 9% 12% 15% 18% 22% 25% 29% 31% 34% 37% 40% 43% Miscellaneous Electric Pool Pump 5% 8% 10% 13% 16% 19% 23% 26% 30% 33% 37% 40% 44% Miscellaneous Electric Furnace Fan 9% 13% 17% 21% 25% 29% 34% 39% 45% 49% 54% 57% 60% Miscellaneous Electric Miscellaneous 23% 31% 39% 47% 54% 62% 68% 73% 76% 78% 78% 78% 79% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1069 of 1125 Market Adoption Factors EnerNOC Utility Solutions Consulting D-3 Table D-2 Residential Non-Equipment Measures— Achievable Potential Market Adoption Factors Measures 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 Central AC - Early Replacement 1% 3% 5% 7% 9% 11% 14% 16% 19% 21% 24% 27% 30% Central AC - Maintenance and Tune-Up 5% 9% 13% 17% 20% 23% 26% 29% 31% 35% 38% 42% 46% Room AC - Removal of Second Unit 1% 3% 5% 7% 9% 11% 14% 16% 19% 21% 24% 27% 30% Attic Fan - Installation 5% 7% 9% 11% 14% 16% 18% 20% 23% 25% 27% 29% 32% Attic Fan - Photovoltaic - Installation 1% 3% 5% 7% 9% 11% 14% 16% 19% 21% 24% 27% 30% Ceiling Fan - Installation 6% 9% 9% 11% 14% 16% 18% 20% 23% 25% 27% 29% 32% Whole-House Fan - Installation 2% 8% 15% 22% 31% 39% 48% 57% 59% 62% 64% 67% 69% Air Source Heat Pump - Maintenance 3% 5% 7% 9% 10% 12% 13% 14% 16% 17% 18% 20% 22% Insulation - Ducting 1% 3% 5% 7% 9% 11% 14% 16% 19% 21% 24% 27% 30% Repair and Sealing - Ducting 2% 3% 6% 8% 10% 11% 12% 14% 15% 16% 18% 19% 21% Thermostat - Clock/Programmable 1% 3% 5% 7% 9% 11% 14% 16% 19% 21% 24% 27% 30% Doors - Storm and Thermal 5% 7% 9% 11% 14% 16% 18% 20% 23% 25% 27% 29% 32% Insulation - Infiltration Control 5% 9% 13% 17% 20% 23% 26% 29% 31% 35% 38% 42% 46% Insulation - Ceiling 12% 13% 14% 14% 15% 16% 17% 18% 19% 20% 21% 22% 23% Insulation - Radiant Barrier 5% 9% 15% 20% 24% 29% 34% 39% 44% 50% 56% 62% 69% Roofs - High Reflectivity 1% 3% 5% 7% 9% 11% 14% 16% 19% 21% 24% 27% 30% Windows - Reflective Film 5% 7% 9% 11% 14% 16% 18% 20% 23% 25% 27% 29% 32% Windows - High Efficiency/Energy Star 5% 7% 9% 11% 14% 16% 18% 20% 23% 25% 27% 29% 32% Interior Lighting - Occupancy Sensor 10% 19% 27% 35% 43% 51% 60% 68% 68% 68% 68% 68% 68% Exterior Lighting - Photovoltaic Installation 2% 8% 15% 22% 31% 39% 48% 57% 59% 62% 64% 67% 69% Exterior Lighting - Photosensor Control 1% 4% 10% 17% 24% 33% 41% 50% 59% 62% 64% 67% 69% Exterior Lighting - Timeclock Installation 2% 8% 15% 22% 31% 39% 48% 57% 59% 62% 64% 67% 69% Water Heater - Faucet Aerators 1% 3% 5% 7% 9% 11% 14% 16% 19% 21% 24% 27% 30% Water Heater - Pipe Insulation 1% 3% 5% 7% 9% 11% 14% 16% 19% 21% 24% 27% 30% Water Heater - Low Flow Showerheads 2% 3% 6% 8% 10% 11% 12% 14% 15% 16% 18% 19% 21% Water Heater - Tank Blanket/Insulation 3% 5% 7% 9% 10% 12% 13% 14% 16% 17% 18% 20% 22% Water Heater - Thermostat Setback 3% 5% 7% 9% 10% 12% 13% 14% 16% 17% 18% 20% 22% Electronics - Reduce Standby Wattage 3% 5% 7% 9% 10% 12% 13% 14% 16% 17% 18% 20% 22% Refrigerator - Early Replacement 3% 4% 6% 8% 11% 13% 16% 19% 23% 25% 27% 29% 32% Refrigerator - Remove Second Unit 3% 4% 6% 8% 11% 13% 16% 19% 23% 25% 27% 29% 32% Freezer - Early Replacement 3% 4% 6% 8% 11% 13% 16% 19% 23% 25% 27% 29% 32% Freezer - Remove Second Unit 3% 4% 6% 8% 11% 13% 16% 19% 23% 25% 27% 29% 32% Behavioral Measures 1% 3% 5% 7% 9% 11% 14% 16% 19% 21% 24% 27% 30% Pool - Pump Timer 3% 6% 9% 11% 14% 16% 19% 21% 24% 27% 30% 33% 37% Insulation - Foundation 3% 6% 9% 11% 14% 16% 19% 21% 24% 27% 30% 33% 37% Insulation - Wall Cavity 5% 9% 15% 20% 24% 29% 34% 39% 44% 50% 56% 62% 69% Insulation - Wall Sheathing 1% 3% 5% 7% 9% 11% 14% 16% 19% 21% 24% 27% 30% Water Heater - Drainwater Heat Reocvery 4% 6% 9% 11% 13% 15% 17% 19% 21% 23% 26% 28% 30% Advanced New Construction Designs 4% 6% 9% 11% 13% 15% 17% 19% 21% 23% 26% 28% 30% Energy Star Homes 9% 10% 14% 15% 20% 21% 26% 28% 34% 36% 40% 43% 45% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1070 of 1125 Market Adoption Factors D-4 www.enernoc.com Table D-3 C/I Equipment Measures — Achievable Potential Market Adoption Factors End Use Fuel Technology 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 Cooling Electric Central Chiller 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% Cooling Electric RTU 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% Cooling Electric PTAC 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% Cooling Electric Heat Pump 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% Space Heating Electric Electric Resistance 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% Space Heating Electric Furnace 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% Space Heating Electric Heat Pump 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% Ventilation Electric Ventilation 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% Interior Lighting Electric Interior Screw-in 33% 45% 54% 61% 66% 70% 73% 76% 78% 80% 81% 82% 82% Interior Lighting Electric High Bay Fixtures 50% 60% 70% 80% 85% 85% 85% 85% 85% 85% 85% 85% 85% Interior Lighting Electric Linear Fluorescent 61% 66% 70% 73% 76% 78% 80% 81% 82% 82% 83% 83% 84% Exterior Lighting Electric Exterior Screw-in 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% Exterior Lighting Electric HID 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% Water Heating Electric Water Heater 13% 15% 18% 20% 23% 25% 28% 30% 33% 35% 38% 40% 45% Food Preparation Electric Fryer 50% 60% 70% 80% 85% 85% 85% 85% 85% 85% 85% 85% 85% Food Preparation Electric Oven 50% 60% 70% 80% 85% 85% 85% 85% 85% 85% 85% 85% 85% Food Preparation Electric Dishwasher 50% 60% 70% 80% 85% 85% 85% 85% 85% 85% 85% 85% 85% Food Preparation Electric Hot Food Container 50% 60% 70% 80% 85% 85% 85% 85% 85% 85% 85% 85% 85% Food Preparation Electric Food Prep 50% 60% 70% 80% 85% 85% 85% 85% 85% 85% 85% 85% 85% Refrigeration Electric Walk in Refrigeration 80% 80% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% Refrigeration Electric Glass Door Display 80% 80% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% Refrigeration Electric Reach-in Refrigerator 80% 80% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% Refrigeration Electric Open Display Case 80% 80% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% Refrigeration Electric Vending Machine 80% 80% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% Refrigeration Electric Icemaker 80% 80% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% Office Equipment Electric Desktop Computer 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% Office Equipment Electric Laptop Computer 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% Office Equipment Electric Server 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% Office Equipment Electric Monitor 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% Office Equipment Electric Printer/copier/fax 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% Office Equipment Electric POS Terminal 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% Miscellaneous Electric Non-HVAC Motor 50% 60% 70% 80% 85% 85% 85% 85% 85% 85% 85% 85% 85% Miscellaneous Electric Other Miscellaneous 50% 60% 70% 80% 85% 85% 85% 85% 85% 85% 85% 85% 85% Process Electric Process Cooling/Refrigeration 50% 60% 70% 80% 85% 85% 85% 85% 85% 85% 85% 85% 85% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1071 of 1125 Market Adoption Factors EnerNOC Utility Solutions Consulting D-5 End Use Fuel Technology 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 Process Electric Process Heating 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% Process Electric Electrochemical Process 50% 60% 70% 80% 85% 85% 85% 85% 85% 85% 85% 85% 85% Machine Drive Electric Less than 5 HP 50% 60% 70% 80% 85% 85% 85% 85% 85% 85% 85% 85% 85% Machine Drive Electric 5-24 HP 50% 60% 70% 80% 85% 85% 85% 85% 85% 85% 85% 85% 85% Machine Drive Electric 25-99 HP 50% 60% 70% 80% 85% 85% 85% 85% 85% 85% 85% 85% 85% Machine Drive Electric 100-249 HP 43% 51% 60% 68% 72% 72% 72% 72% 72% 72% 72% 72% 72% Machine Drive Electric 250-499 HP 43% 51% 60% 68% 72% 72% 72% 72% 72% 72% 72% 72% 72% Machine Drive Electric 500 and more HP 43% 51% 60% 68% 72% 72% 72% 72% 72% 72% 72% 72% 72% Miscellaneous Electric Miscellaneous 21% 26% 30% 34% 38% 43% 47% 51% 55% 60% 64% 68% 72% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1072 of 1125 Market Adoption Factors D-6 www.enernoc.com Table D-4 C/I Non-Equipment Measures — Achievable Potential Market Adoption Factors Measures 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 RTU - Maintenance 8% 16% 24% 34% 43% 51% 60% 68% 68% 68% 68% 68% 68% RTU - Evaporative Precooler 8% 16% 24% 34% 43% 51% 60% 68% 68% 68% 68% 68% 68% Chiller - Chilled Water Reset 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50% Chiller - Chilled Water Variable-Flow System 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50% Chiller - VSD 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65% Chiller - High Efficiency Cooling Tower Fans 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65% Chiller - Condenser Water Temprature Reset 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50% Cooling - Economizer Installation 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65% Heat Pump - Maintenance 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65% Insulation - Ducting 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65% Repair and Sealing - Ducting 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65% Energy Management System 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50% Cooking - Exhaust Hoods with Sensor Control 4% 8% 12% 17% 21% 26% 30% 34% 38% 43% 47% 51% 55% Fans - Energy Efficient Motors 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65% Fans - Variable Speed Control 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65% Retrocommissioning - HVAC 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50% Pumps - Variable Speed Control 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65% Thermostat - Clock/Programmable 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50% Insulation - Ceiling 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50% Insulation - Radiant Barrier 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50% Roofs - High Reflectivity 20% 21% 23% 25% 26% 28% 30% 31% 33% 35% 37% 38% 40% Windows - High Efficiency 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50% Interior Lighting - Central Lighting Controls 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65% Interior Lighting - Photocell Controlled T8 Dimming Ballasts 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65% Exterior Lighting - Daylighting Controls 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65% Interior Fluorescent - Bi-Level Fixture w/Occupancy Sensor 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65% Interior Fluorescent - High Bay Fixtures 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65% Interior Lighting - Occupancy Sensors 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65% Exterior Lighting - Photovoltaic Installation 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65% Interior Screw-in - Task Lighting 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65% Interior Lighting - Time Clocks and Timers 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65% Water Heater - Faucet Aerators/Low Flow Nozzles 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65% Water Heater - Pipe Insulation 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65% Water Heater - High Efficiency Circulation Pump 20% 21% 23% 25% 26% 28% 30% 31% 33% 35% 37% 38% 40% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1073 of 1125 Market Adoption Factors EnerNOC Utility Solutions Consulting D-7 Measures 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 Water Heater - Tank Blanket/Insulation 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65% Water Heater - Thermostat Setback 20% 21% 23% 25% 26% 28% 30% 31% 33% 35% 37% 38% 40% Refrigeration - Anti-Sweat Heater/Auto Door Closer 20% 21% 23% 25% 26% 28% 30% 31% 33% 35% 37% 38% 40% Refrigeration - Floating Head Pressure 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50% Refrigeration - Door Gasket Replacement 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50% Insulation - Bare Suction Lines 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50% Refrigeration - Night Covers 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50% Refrigeration - Strip Curtain 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50% Vending Machine - Controller 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65% LED Exit Lighting 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65% Retrocommissioning - Lighting 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65% Refrigeration - High Efficiency Case Lighting 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50% Exterior Lighting - Cold Cathode Lighting 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65% Laundry - High Efficiency Clothes Washer 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65% Interior Lighting - Hotel Guestroom Controls 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65% Miscellaneous - Energy Star Water Cooler 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65% Commissioning - HVAC 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65% Commissioning - Comprehensive 20% 21% 23% 25% 26% 28% 30% 31% 33% 35% 37% 38% 40% Commissioning - Lighting 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65% Advanced New Construction Designs 20% 21% 23% 25% 26% 28% 30% 31% 33% 35% 37% 38% 40% Insulation - Wall Cavity 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65% Roofs - Green 20% 21% 23% 25% 26% 28% 30% 31% 33% 35% 37% 38% 40% Interior Lighting - Skylights 20% 21% 23% 25% 26% 28% 30% 31% 33% 35% 37% 38% 40% Ventilation - Demand Control Ventilation 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65% Office Equipment - Smart Power Strips 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65% Strategic Energy Management 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50% Refrigeration - Multiplex - Floating section Pressure - Air-cooled Cond. 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50% Refrigeration - Multiplex Controls - Floating section Pressure - Evap. Cond. 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50% Refrigeration - Multiplex - Eff. Air-cooled Condenser 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50% Refrigeration - Multiplex - Eff. Water-cooled Condenser 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50% Refrigeration - System Controls 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65% Refrigeration - System Maintenance 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65% Refrigeration - System Optimization 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65% Motors - Variable Frequency Drive 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65% Motors - Magnetic Adjustable Speed Drives 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65% Compressed Air - System Controls 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1074 of 1125 Market Adoption Factors D-8 www.enernoc.com Measures 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 Compressed Air - System Optimization and Improvements 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50% Compressed Air - System Maintenance 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50% Compressed Air - Compressor Replacement 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50% Fan System - Controls 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65% Fan System - Optimization 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65% Fan System - Maintenance 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65% Pumping System - Controls 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65% Pumping System - Optimization 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65% Pumping System - Maintenance 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65% Transformers 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50% Motors - Synchronous belts 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50% Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1075 of 1125 EnerNOC Utility Solutions Consulting E-1 APPENDIX E ANNUAL SAVINGS This section presents the estimates of annual savings. Selected years are shown in Chapter 4 of the CPA report. Table E-1 and Table E-2show the overall annual savings for all sectors combined. Table E-3 through Table E-6 show the annual savings for the individual sectors. Table E-1 Annual Electric Energy Savings, All Sectors (1,000 MWh) 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 Cumulative Savings (1,000 MWh) Achievable Potential 51 100 168 240 325 417 458 515 579 634 Economic Potential 315 476 679 881 1,079 1,284 1,361 1,447 1,552 1,655 Technical Potential 1,161 1,368 1,656 1,966 2,239 2,517 2,695 2,862 3,029 3,173 Incremental Savings (1,000 MWh) Achievable Potential 51 50 68 72 84 93 41 57 64 55 Economic Potential 315 162 202 203 198 204 78 86 104 103 Technical Potential 1,161 206 289 310 273 278 178 168 166 144 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1076 of 1125 Annual Savings E-2 www.enernoc.com Table E-2 Annual Electric Energy Savings, All Sectors (1,000 MWh) (continued) 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 Cumulative Savings (1,000 MWh) Achievable Potential 685 761 834 903 977 1,037 1,103 1,175 1,262 1,352 Economic Potential 1,751 1,896 2,020 2,138 2,259 2,315 2,388 2,468 2,561 2,652 Technical Potential 3,302 3,472 3,617 3,752 3,884 3,979 4,070 4,163 4,252 4,340 Incremental Savings (1,000 MWh) Achievable Potential 51 76 73 69 74 60 66 71 88 90 Economic Potential 96 145 124 118 121 56 74 79 93 91 Technical Potential 129 170 145 135 133 94 91 93 89 88 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1077 of 1125 Annual Savings EnerNOC Utility Solutions Consulting E-3 Table E-3 Annual Electric Energy Savings, Residential (1,000 MWh) 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 Cumulative Savings (1,000 MWh) Achievable Potential 22 43 75 110 148 189 209 224 241 252 Economic Potential 231 335 469 611 745 879 926 955 998 1,042 Technical Potential 963 1,038 1,154 1,266 1,338 1,409 1,430 1,433 1,454 1,473 Incremental Savings (1,000 MWh) Achievable Potential 22 21 32 35 37 42 19 16 16 11 Economic Potential 231 104 134 142 133 135 46 30 43 43 Technical Potential 963 74 116 112 73 70 22 3 20 20 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1078 of 1125 Annual Savings E-4 www.enernoc.com Table E-4 Annual Electric Energy Savings, Residential (1,000 MWh) (continued) 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 Cumulative Savings (1,000 MWh) Achievable Potential 263 293 324 357 392 419 447 477 510 547 Economic Potential 1,083 1,164 1,239 1,314 1,390 1,412 1,442 1,474 1,512 1,549 Technical Potential 1,492 1,553 1,611 1,669 1,727 1,765 1,802 1,840 1,876 1,912 Incremental Savings (1,000 MWh) Achievable Potential 11 30 31 32 35 27 28 30 34 37 Economic Potential 42 81 75 75 76 21 30 32 38 38 Technical Potential 19 61 58 58 59 37 38 38 36 35 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1079 of 1125 Annual Savings EnerNOC Utility Solutions Consulting E-5 Table E-5 Annual Electric Energy Savings, C/I (1,000 MWh) 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 Cumulative Savings (1,000 MWh) Achievable Potential 29 57 93 130 177 228 250 291 338 382 Economic Potential 84 141 210 270 334 404 436 492 554 613 Technical Potential 198 330 503 701 901 1,108 1,264 1,429 1,575 1,700 Incremental Savings (1,000 MWh) Achievable Potential 29 29 36 37 47 51 22 41 48 43 Economic Potential 84 58 69 60 64 70 31 57 61 60 Technical Potential 198 132 173 198 200 208 156 165 146 125 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1080 of 1125 Annual Savings E-6 www.enernoc.com Table E-6 Annual Electric Energy Savings, C/I (1,000 MWh) (continued) 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 Cumulative Savings (1,000 MWh) Achievable Potential 422 468 509 546 585 618 656 698 752 805 Economic Potential 668 732 781 824 868 903 946 994 1,049 1,103 Technical Potential 1,809 1,919 2,006 2,083 2,157 2,214 2,268 2,323 2,376 2,428 Incremental Savings (1,000 MWh) Achievable Potential 40 46 42 37 39 34 38 42 54 53 Economic Potential 54 64 49 43 45 34 43 47 56 53 Technical Potential 110 109 87 77 74 57 53 55 53 52 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1081 of 1125 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1082 of 1125 EnerNOC Utility Solutions Consulting 500 Ygnacio Valley Road, Suite 450 Walnut Creek, CA 94596 P: 925.482.2000 F: 925.284.3147 About EnerNOC Utility Solutions Consulting EnerNOC Utility Solutions Consulting is part of EnerNOC Utility Solutions group, which provides a comprehensive suite of demand-side management (DSM) services to utilities and grid operators worldwide. Hundreds of utilities have leveraged our technology, our people, and our proven processes to make their energy efficiency (EE) and demand response (DR) initiatives a success. Utilities trust EnerNOC to work with them at every stage of the DSM program lifecycle – assessing market potential, designing effective programs, implementing those programs, and measuring program results. EnerNOC Utility Solutions delivers value to our utility clients through two separate practice areas – Program Implementation and EnerNOC Utility Solutions Consulting. • Our Program Implementation team leverages EnerNOC’s deep ―behind-the-meter expertise‖ and world-class technology platform to help utilities create and manage DR and EE programs that deliver reliable and cost-effective energy savings. We focus exclusively on the commercial and industrial (C&I) customer segments, with a track record of successful partnerships that spans more than a decade. Through a focus on high quality, measurable savings, EnerNOC has successfully delivered hundreds of thousands of MWh of energy efficiency for our utility clients, and we have thousands of MW of demand response capacity under management. • The EnerNOC Utility Solutions Consulting team provides expertise and analysis to support a broad range of utility DSM activities, including: potential assessments; end-use forecasts; integrated resource planning; EE, DR, and smart grid pilot and program design and administration; load research; technology assessments and demonstrations; evaluation, measurement and verification; and regulatory support. The EnerNOC Utility Solutions Consulting team has decades of combined experience in the utility DSM industry. The staff is comprised of professional electrical, mechanical, chemical, civil, industrial, and environmental engineers as well as economists, business planners, project managers, market researchers, load research professionals, and statisticians. Utilities view our experts as trusted advisors, and we work together collaboratively to make any DSM initiative a success. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1083 of 1125 2013 Electric Integrated Resource Plan Appendix D – 2013 Electric IRP Transmission Studies Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1084 of 1125 Interoffice Memorandum System Planning MEMO: SP-2012-09 DATE: August 14, 2012 TO: Scott Waples FROM: Richard Maguire SUBJECT: 2013 IRP Generation Study – Nine Mile HED Introduction This study addresses a request from Avista’s Power Supply Department for the 2013 IRP regarding increasing the capacity of Nine Mile HED to 60 MW. The study addresses the following: Power flow impact to the transmission system Voltage level impact to the transmission system Transmission system upgrades necessary to deliver requested generation History The Nine Mile project was built by a private developer in 1908 near Nine Mile Falls, Washington, nine miles northwest of Spokane. The Company purchased the project in 1925 from the Spokane & Eastern Railway. Its four units have a 17.6 MW maximum capacity and a 26.4 MW nameplate rating. Currently Unit 1 provides no generation and Unit 2 is limited to half load and unit 4 failed in the spring of 2011. These units will be replaced, and the desired capacity of the plant upon replacement of the new units is 60 MW. Avista expects the new capacity will add incremental energy towards meeting Washington State Energy Independence Act goals. Study Methodology and Assumptions Avista’s five year planning horizon planning cases are used and modified with the following projects prior to transmission system analysis: Spokane Valley Transmission Reinforcement Project Moscow Transformer Replacement Project Lancaster Loop-In Project Palouse Wind Phase I (LGIP #5) Study Results Studies for this request confirm that Avista’s transmission system has adequate capacity to integrate the Nine Mile HED at a total plant output of 60 MW under all conditions studied. The limiting element is the Nine Mile – Indian Trail 115 kV transmission line, and figures showing the base case plus two limiting contingencies follow. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1085 of 1125 Figure 1. N-0, Avista Spring Case AVA-11ls1ae-16BA1328-WOH4140 Figure 2. Limiting Contingency: N-1: Airway Heights - Devils Gap 115 kV Open @ DGP Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1086 of 1125 Figure 3. Limiting Contingency: BF A180 Airway Heights 115 kV, Airway Heights - Devils Gap Distribution: S. Waples Sharepoint (System Planning) OASIS Posting Power Supply (J. Gall) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1087 of 1125 Interoffice Memorandum System Planning MEMO: SP-2013-04 DATE: January 14, 2013 TO: Scott Waples FROM: Richard Maguire SUBJECT: 2013 IRP Generation Study – Long Lake HED Introduction This study addresses a request from Avista’s Power Supply Department for the 2013 IRP regarding increasing the capacity of Long Lake HED by 68 MW. This preliminary study addresses the following: Power flow impact to the transmission system Voltage level impact to the transmission system Transmission System upgrades necessary to deliver requested generation History The Long Lake project is located northwest of Spokane and maintains the Lake Spokane reservoir, also known as Long Lake. The facility was the highest spillway dam with the largest turbines in the world when it was completed in 1915. The plant was upgraded with new runners in the 1990s, adding 2.2 aMW of additional energy. The project’s four units provide 88.0 MW of combined capacity and have an 81.6 MW nameplate rating. Study Methodology and Assumptions The five year planning horizon, Avista planning cases, as documented in SP-2011-03 – 2011 Planning Cases Summary Data are modified with the following projects and adjustments before system analysis: LGIR #5 Lind 115 kV Substation Reactive Support 2013 IRP Generation Request for Nine Mile HED (60 MW Total) Nine Mile HED and Little Falls HED set to maximum generation dispatch Increases in Long Lake generation are balanced by decrementing an injection group including all Avista generation with the exception of Long Lake HED, Nine Mile HED, and Little Falls HED. Western Montana Hydro is limited to 1650 MW West of Hatwai is limited to 4277 MW The most limiting case found during this study is the Light Summer with High West of Hatwai Flows (High Transfer Case) numbered AVA-11ls1ae-12BA1251-WOH4277. This is the primary case used in this study. Figure 1 below presents a high-level view of the Transmission System near Devil’s Gap with Long Lake HED generating an additional 68 MW. Note the loading on the Nine Mile – Westside 115 kV Transmission Line. Table 1 below shows regional power flows with the additional generation. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1088 of 1125 Figure 1: Avista Transmission System near Long Lake HED Table 1: Regional Power Flows used during system study Western Montana Hydro 1624.3 MW West of Hatwai (Path 6) 4231.3 MW Noxon Rapids (562MW) 483.0 MW Lolo-Oxbow 230kV 129.2 MW Cabinet Gorge (265MW) 221.3 MW Dry Creek-Walla Walla 230kV 176.8 MW Libby (605MW)540.0 MW Hungry Horse (430MW) 380.0 MW West of Cabinet 3301.6 MW Montana-Northwest (Path 8) 2065.1 MW Colstrip Total Colstrip 1 (330MW) 330.0 MW Idaho-Northwest (Path 14) 751.2 MW Colstrip 2 (330MW) 330.0 MW Midpoint-Summer Lake (Path 75) 819.6 MW Colstrip 3 (823MW) 787.5 MW Idaho-Montana (Path 18) -191.9 MW Colstrip 4 (823MW) 792.8 MW South of Boundary 963.5 MW Rathdrum Thermal (175MW) 130.0 MW North of John Day (Path 73) 4525.6 MW Lancaster Thermal (270MW) 249.0 MW TOT 4A (Path 37)454.4 MW Spokane River Hydro 291.8 MW Miles City DC 200.0 MW Boundary Hydro (1040MW) 975.0 MW Path C (Path 20)537.4 MW Lower Snake/N.F. Clearwater Borah West (Path 17)1578.2 MW Dworshak (458MW) 344.6 MW Bridger West (Path 19) 2104.2 MW Lower Granite (930MW) 155.0 MW Pacific AC Intertie (Path 66) 2855.0 MW Little Goose (930MW) 155.0 MW Pacific DC Intertie (Path 65) 1999.9 MW Lower Monumental (930MW) 273.5 MW Northwest Load 17796.4 MW Coulee Generation Idaho Load 2326.0 MW Coulee 500 kV 546.7 MW Montana Load 1339.5 MW Coulee 230 kV 125.0 MW Avista Native Load -837.0 MW Avista Balancing Area Load 1179.9 MW Clearwater Load 63.6 MW Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1089 of 1125 Study Results Thermal Performance during N-0 conditions This preliminary study indicates the Avista Transmission System has adequate capacity to integrate an additional 68 MW of generation at Long Lake HED with all lines in service. Thermal Performance during N-1 conditions Table 2 shows the results of a study using PowerWorld Simulator’s Available Transfer Capability tool for Long Lake HED. The table shows limiting transmission segments for contingencies in violation as generation at Long Lake is incremented. In order to incorporate 68 MW of additional generation at Long Lake HED while maintaining Transmission System thermal reliability under N-1 conditions, the following 115 kV Transmission Lines would need upgrades to at least 795 ACSS conductor: 1. Devils Gap – Long Lake #1 2. Devils Gap – Long Lake #2 3. Devils Gap – Ninemile 4. Ninemile – West Side 5. Airway Heights – Devils Gap 6. Airway Heights – Sunset An approximate cost to reconductor 57.54 miles of 115 kV transmission line would be $ 9.9M1. Table 2: Available Transfer Capability for Long Lake HED 1 All construction costs are in 2013-year dollars and are based on engineering judgment only with +/- 50% error Incremental Generation Limiting CTG From Name To Name 1.86 BF: A413 Westside 115 kV, Ninemile-Westside AIRWAYHT SUNSET 1.89 N-1: Airway Heights - Devils Gap 115 kV Open @ DGP INDTRAIL WEST 3.32 N-1: Airway Heights - Devils Gap 115 kV INDTRAIL WEST 4.05 PSF: Westside 115 kV AIRWAYHT SUNSET 4.12 BF: A180 Airway Heights 115 kV, Airway Heights-Devils Gap INDTRAIL WEST 4.19 PSF: Airway Heights 115 kV INDTRAIL WEST 4.52 N-1: Nine Mile - Westside 115 kV Open @ WES AIRWAYHT SUNSET 8.13 N-1: Airway Heights - Devils Gap 115 kV Open @ AIR INDTRAIL WEST 11.58 N-1: Nine Mile - Westside 115 kV Open @ NMS DEVILGPE W.PLAINS 11.8 N-1: Nine Mile - Westside 115 kV DEVILGPE W.PLAINS 15.03 BF: A413 Westside 115 kV, Ninemile-Westside DEVILGPE W.PLAINS 17.21 PSF: Westside 115 kV DEVILGPE W.PLAINS 17.29 N-1: Nine Mile - Westside 115 kV Open @ WES DEVILGPE W.PLAINS 20.54 N-1: Nine Mile - Westside 115 kV Open @ NMS AIRWAYHT W.PLAINS 20.75 N-1: Nine Mile - Westside 115 kV AIRWAYHT W.PLAINS 24.19 BF: A413 Westside 115 kV, Ninemile-Westside AIRWAYHT W.PLAINS 26.27 N-1: Nine Mile - Westside 115 kV Open @ WES AIRWAYHT W.PLAINS 26.36 PSF: Westside 115 kV AIRWAYHT W.PLAINS 35.57 N-1: Devils Gap - Long Lake #1 115 kV DEVILGPE LONGLAKW 45.31 N-1: Devils Gap - Long Lake #2 115 kV DEVILGPE LONGLAKE 68.26 N-1: Airway Heights - Devils Gap 115 kV Open @ DGP DEVILGPE NINEMILE 69.63 N-1: Airway Heights - Devils Gap 115 kV DEVILGPE NINEMILE 70.43 BF: A180 Airway Heights 115 kV, Airway Heights-Devils Gap DEVILGPE NINEMILE 70.43 PSF: Airway Heights 115 kV DEVILGPE NINEMILE 74.43 N-1: Airway Heights - Devils Gap 115 kV Open @ AIR DEVILGPE NINEMILE Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1090 of 1125 Voltage Stability Preliminary voltage studies show that 68 MW of additional generation at Long Lake HED does not introduce any new voltage issues on the Avista Transmission System. Conclusion This study indicates the requested new generation at Long Lake HED performs adequately on the local Transmission System with potential updates to several 115 kV Transmission Lines in the West Spokane area. Potential cost of upgrading Transmission Lines is $9.9 M, and further costs might be necessary to mitigate issues uncovered in more detailed thermal and transient stability studies. Distribution: Scott Waples SharePoint (System Planning) Avista OASIS Posting James Gall - Power Supply & Resource Planning Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1091 of 1125 Interoffice Memorandum System Planning MEMO: SP-2013-03 DATE: January 22, 2013 TO: Scott Waples FROM: Richard Maguire SUBJECT: 2013 IRP Generation Study – Monroe Street HED Introduction This study addresses a request from Avista’s Power Supply Department for the 2013 IRP regarding adding 80 MW of additional capacity to Monroe Street HED. This preliminary study addresses the following: Thermal impact to the transmission system Voltage stability impact to the transmission system Transmission System upgrades necessary to deliver requested generation History The Monroe Street facility was the Company’s first generating unit. It started service in 1890 near what is now Riverfront Park. Rebuilt in 1992, the single generating unit now has a 15.0 MW maximum capacity and a 14.8 MW nameplate rating. Study Methodology and Assumptions The five year planning horizon, Avista planning cases, as documented in SP-2011-03 – 2011 Planning Cases Summary Data are modified with the following projects and adjustments before system analysis: LGIR #5 LGIR #35 Lind 115 kV Substation Reactive Support Increases in Monroe Street generation are balanced by decrementing an injection group including all Avista generation with the exception of generation at Monroe Street HED and Upper Falls HED. Western Montana Hydro is limited to 1650 MW West of Hatwai is limited to 4277 MW The most limiting case found during this study is the Light Summer with High West of Hatwai Flows (Heavy Summer, High Hydro Case) numbered AVA-11ls1ae-12BA1251-WOH4277. This is the primary case used in this study. Figure 1 below presents a high-level view of the Transmission System near Monroe Street HED with the additional 80 MW of generation supplied by a study generator. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1092 of 1125 Figure 1: Avista Transmission System near Monroe Street HED Study Results Thermal Performance during N-0 This preliminary power flow study indicates the Avista Transmission System has adequate capacity to integrate 80 MW of additional generation at Monroe Street HED with all lines in service. Thermal Performance during N-1 This preliminary power flow study indicates the Avista Transmission System has adequate capacity to integrate 80 MW of additional generation at Monroe Street HED during N-1 contingency conditions. Table 1 shows the results of a study using PowerWorld Simulator’s Available Transfer Capability tool for Monroe Street HED. The study reveals the next closest N-1 contingency violation as an overload of the Post Street – Third and Hatch 115 kV transmission line during the PSF: Westside 115 kV contingency if the additional generation capacity at Monroe Street HED was 122.85 MW. Table 1: PowerWorld ATC results for Monroe Street HED Trans Lim From Name To Name Limiting CTG 122.85 POSTSTRT THIRHACH PSF: Westside 115 kV 132.47 POSTSTRT THIRHACH BF: A470 Westside 115 kV, College & Walnut-Westside 135.41 POSTSTRT THIRHACH BF: A410 Westside 115 kV, Sunset-Westside 139.77 POSTSTRT THIRHACH BF: A413 Westside 115 kV, Ninemile-Westside 142.54 POSTSTRT THIRHACH BUS: Westside 115 kV Voltage Stability Preliminary voltage studies show that 80 MW of additional generation at Monroe Street HED does not introduce any new voltage issues on the Avista Transmission System. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1093 of 1125 Conclusion This preliminary study indicates the requested generation at Monroe Street HED performs adequately on the local Transmission System pending any conditions revealed through further detailed thermal, voltage, and transient stability studies. Distribution: Scott Waples SharePoint (System Planning) Avista OASIS Posting James Gall – Power Supply & Resource Planning Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1094 of 1125 Interoffice Memorandum System Planning MEMO: SP-2013-05 DATE: January 22, 2013 TO: Scott Waples FROM: Richard Maguire SUBJECT: 2013 IRP Generation Study – Upper Falls HED Introduction This study addresses a request from Avista’s Power Supply Department for the 2013 IRP regarding adding 40 MW of additional capacity to Upper Falls HED. This study will be undertaken as a coincident generation request with the Monroe Street IRP request for three reasons: Upper Falls HED and Monroe Street HED connect to the Avista 115 kV Transmission System at the same bus The Monroe Street HED IRP request of 80 MW was found to require no transmission system modifications, thereby showing no individual study of the Upper Falls request would be necessary given the lesser requested capacity It would be useful to understand the overall impact to the transmission system if both Upper Falls HED and Monroe Street HED IRP requests are pursued This preliminary study addresses the following: Thermal impact to the transmission system Voltage stability impact to the transmission system Transmission system upgrades necessary to deliver requested generation History The Upper Falls project began generating in 1922 in downtown Spokane, and now is within the boundaries of Riverfront Park. This project is comprised of a single 10.0 MW unit with a 10.26 MW maximum capacity rating. Study Methodology and Assumptions The five year planning horizon, Avista planning cases, as documented in SP-2011-03 – 2011 Planning Cases Summary Data are modified with the following projects and adjustments before system analysis: LGIR #5 LGIR #35 2013 IRP Monroe Street Request Lind 115 kV Substation Reactive Support Increases in Upper Falls generation are balanced by decrementing an injection group including all Avista generation with the exception of generation at Monroe Street HED and Upper Falls HED. Western Montana Hydro is limited to 1650 MW West of Hatwai is limited to 4277 MW The most limiting case found during this study is the Light Summer with High West of Hatwai Flows (Heavy Summer, High Hydro Case) numbered AVA-11ls1ae-12BA1251-WOH4277. This is the primary case used in this study. Figure 1 below presents a high-level view of the Transmission System near Upper Falls HED with the additional 120 MW of coincidental generation supplied by a study generator. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1095 of 1125 Figure 1: Avista Transmission System near Upper Falls HED Study Results Thermal Performance during N-0 This preliminary power flow study indicates the Avista Transmission System has adequate capacity to integrate 40 MW of additional generation at Upper Falls HED with all lines in service. The closest N-0 violation occurs when attempting to integrate 47 MW of generation at Upper Falls which overloads the Post Street-Third & Hatch 115 kV Transmission Line. Thermal Performance during N-1 This preliminary power flow study indicates the Avista Transmission System has adequate capacity to integrate 40 MW of additional generation at Upper Falls HED during N-1 contingency conditions. Table 1 shows the results of a PowerWorld Simulator Available Transfer Capability analysis done for Upper Falls HED. The ATC study reveals the next closest N-1 contingency violation as an overload of the Post Street-Third & Hatch 115 kV Transmission Line during the PSF: Westside 115 kV contingency if the additional generation capacity at Upper Falls HED exceeds 49.49 MW. Table 1: ATC results for Upper Falls HED Incremental Generation Limiting CTG From Name To Name 49.49 PSF: Westside 115 kV POSTSTRT THIRHACH 58.69 BF: A470 Westside 115 kV, College & Walnut-Westside POSTSTRT THIRHACH 62.04 BF: A410 Westside 115 kV, Sunset-Westside POSTSTRT THIRHACH 65.93 BF: A413 Westside 115 kV, Ninemile-Westside POSTSTRT THIRHACH 68.98 BUS: Westside 115 kV POSTSTRT THIRHACH Voltage Stability Preliminary voltage studies show that 40 MW of additional generation at Upper Falls HED does not introduce any new voltage issues on the Avista Transmission System. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1096 of 1125 Conclusion This preliminary study indicates the requested generation at Upper Falls HED performs adequately on the local Transmission System pending any conditions revealed through further detailed thermal, voltage, and transient stability studies. Distribution: Scott Waples SharePoint (System Planning) Avista OASIS Posting James Gall - Power Supply & Resource Planning Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1097 of 1125 Interoffice Memorandum System Planning MEMO: SP-2013-02 DATE: January 22, 2013 TO: Scott Waples FROM: Richard Maguire SUBJECT: 2013 IRP Generation Study – Post Falls HED Introduction This study addresses a request from Avista’s Power Supply Department for the 2013 IRP regarding increasing the capacity of Post Falls HED to a total output of 33.5 MW. This preliminary study addresses the following: Thermal impact to the transmission system Voltage stability impact to the transmission system Transmission System upgrades necessary to deliver requested generation History Avista’s upper most hydroelectric facility on the Spokane River is the Post Falls project, located at its Idaho namesake near the Washington/Idaho border. The project began operation in 1906 and maintains lake elevation during the summer for Lake Coeur d’Alene. The project has six units, with the last unit added in 1980. The project is capable of producing 18.0 MW and has a 14.75 MW nameplate rating. Study Methodology and Assumptions The five year planning horizon, Avista planning cases, as documented in SP-2011-03 – 2011 Planning Cases Summary Data are modified with the following projects and adjustments before system analysis: LGIP #5 Lind 115 kV Substation Reactive Support Increases in Post Falls generation are balanced by decrementing an injection group including all Avista generation with the exception of Post Falls HED. Western Montana Hydro is limited to 1650 MW West of Hatwai is limited to 4277 MW The most limiting case found during this study is the Heavy Summer with High Local Hydro Generation (Heavy Summer, High Hydro Case) numbered AVA-11hs2a-12BA2085. This is the primary case used in this study. Figure 1 below presents a high-level view of the Transmission System near Post Falls HED. Note the relatively large amount of local load immediately connected to the Post Falls substation when compared to the requested 33.5 MW total plant output. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1098 of 1125 Figure 1: Avista Transmission System near Post Falls HED Study Results Thermal Performance during N-0 This preliminary power flow study indicates the Avista Transmission System has adequate capacity to integrate 33.5 MW of total generation at Post Falls HED with all lines in service. Thermal Performance during N-1 This preliminary power flow study indicates the Avista Transmission System has adequate capacity to integrate 33.5 MW of total generation at Post Falls HED during N-1 contingency conditions. Table 1 shows the results of a PowerWorld Simulator Available Transfer Capability analysis done for Post Falls HED. The ATC study reveals the next closest N-1 contingency violation as an overload of the Post Falls – Prairie B 115 kV Transmission Line during the N-1: Otis Orchards – Post Falls 115 kV Open @ PF contingency when the total generation capacity at Post Falls HED is 112.15 MW. Table 1: ATC study results for Post Falls HED Trans Lim From Name To Name Limiting CTG112.15 POST FLS PRAIRIEB N-1: Otis Orchards - Post Falls 115 kV Open @ PF 112.16 POST FLS PRAIRIEB BF: A642 Otis Orchards 115 kV, Otis Orchards-Post Falls 112.17 POST FLS PRAIRIEB N-1: Otis Orchards - Post Falls 115 kV 112.18 POST FLS PRAIRIEB PSF: Otis Orchards 115 kV138.87 EASTFARM POST FLS N-1: Post Falls - Ramsey 115 kV Open @ PF 139.68 EASTFARM POST FLS N-1: Post Falls - Ramsey 115 kV 139.68 EASTFARM POST FLS N-2: Post Falls - Ramsey 115 kV & Ramsey - Rathdrum #1 115 kV147.42 OTIS LIBTYLK SUB: Beacon 230 & 115 (AVA) 173.04 CLEARWTR N LEWIST N-2: Dry Creek - North Lewiston 230 kV and Dry Creek - North Lewiston 115 kV and North Lewiston - Tucannon River 115 kV 1638.3 POST FLS PRAIRIEB PSF: Post Falls 115 kV Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1099 of 1125 Voltage Stability Preliminary voltage studies show that 33.5 MW of total generation at Post Falls HED does not introduce any new voltage issues on the Avista Transmission System. Conclusion This preliminary study indicates the requested generation at Post Falls HED performs adequately on the local Transmission System pending any conditions revealed through further detailed thermal, voltage, and transient stability studies. Distribution: Scott Waples SharePoint (System Planning) Avista OASIS Posting James Gall – Power Supply & Resource Planning Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1100 of 1125 Interoffice Memorandum System Planning MEMO: SP-2012-14 DATE: October 4, 2012 TO: Scott Waples FROM: Richard Maguire SUBJECT: 2013 IRP Generation Study – Cabinet Gorge HED Introduction This brief study addresses a request from Avista’s Power Supply Department for the 2013 IRP regarding adding up to 110 MW of new generation capacity in the form of two new units to Cabinet Gorge HED. History The Cabinet Gorge project started generating power in 1952 with two units. The plant was expanded with two additional generators in the following year. The current maximum capacity of the plant is 270.5 MW; it has a nameplate rating of 265.2 MW. Upgrades at this project began with the replacement of the turbine for Unit 1 in 1994. Unit 3 was upgraded in 2001 and Unit 2 was upgraded in 2004. The final unit, Unit 4, received a $6 million turbine upgrade in 2007, increasing its generating capacity from 55 MW to 64 MW, and adding 2.1 aMW of additional energy.1 Study Methodology and Assumptions Two of Avista’s five year planning horizon cases are modified with the following projects prior to analysis: Spokane Valley Transmission Reinforcement Project Moscow Transformer Replacement Project Lancaster Loop-In Project Palouse Wind Phase I (LGIP #5) The two cases used in this study are: AVA-16hs2a-16BA2213; Heavy Summer High Hydro (HSHH) AVA-11ls1ae-16BS1328-WOH4140; Light Loading High Transfer (HT) These cases represent two seasonal times when maximum hydro generation is possible. Table 1 below shows the power flow values with an additional 110 MW of generation at Cabinet Gorge. All changes in generation are coupled with: Limiting Western Montana Hydro to 1650 MW by reducing outputs of Libby and Hungry Horse Limiting West of Hatwai to 4277 MW via control of off-system generation 1 Cabinet Gorge history taken from Avista 2011 Electric Integrated Resource Plan Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1101 of 1125 Table 1: Base Case Power Flow Summary Study Results Thermal Performance during N-0 conditions The study indicates that the Avista transmission system has enough capacity to integrate an additional 110 MW of generation at Cabinet Gorge HED with all lines in service during some, but not all, conditions. One example of a limiting condition occurs during hot summer months when the loading is high and full hydro generation is possible. During this heavy summer, high hydro scenario, the present Avista transmission system has just enough transmission capacity for existing generation. Figure 1 below shows the Avista system isolated from neighbor systems for the purpose of determining transmission capacity. This is a unique test for this study, and no other cases are evaluated with the system isolated in this way. The image represents flows in the 2016 heavy summer high hydro case with Cabinet Gorge and Noxon operating at maximum capacity. Note: This study uses existing line ratings. Avista has projects underway raising line ratings in the area, which will result in more transmission capacity once the projects are completed. Generation at Cabinet Gorge HED and Noxon Rapids HED could be governed within a nomogram to mitigate thermal overloads during summer conditions when electric loading is high. NOTE: these conclusions are contingent upon further detailed studies West of Hatwai (Path 6)813.1 MW West of Hatwai (Path 6)4275.0 MW Montana-Northwest (Path 8)758.7 MW Montana-Northwest (Path 8)2101.2 MW Western Montana Hydro 1650.0 MW Western Montana Hydro 1650.0 MW Noxon Rapids (562MW) 570.6 MW Noxon Rapids (562MW) 570.6 MW Cabinet Gorge (265MW) 397.0 MW Cabinet Gorge (265MW) 397.0 MW Libby (605MW)395.9 MW Libby (605MW)395.9 MW Hungry Horse (430MW) 286.5 MW Hungry Horse (430MW) 286.5 MW Colstrip 1 (330MW) 329.3 MW Colstrip 1 (330MW) 330.8 MW Colstrip 2 (330MW) 329.3 MW Colstrip 2 (330MW) 330.8 MW Colstrip 3 (823MW) 789.1 MW Colstrip 3 (823MW) 796.5 MW Colstrip 4 (823MW) 803.3 MW Colstrip 4 (823MW) 801.8 MW Rathdrum Thermal (175MW) 0.0 MW Rathdrum Thermal (175MW) 140.0 MW Lancaster Thermal (270MW) 248.4 MW Lancaster Thermal (270MW) 249.4 MW Spokane River Hydro 88.2 MW Spokane River Hydro 183.8 MW Boundary Hydro (1040MW) 633.6 MW Boundary Hydro (1040MW) 976.5 MW Northwest Load 26444.8 MW Northwest Load 17948.5 MW Idaho Load 4087.0 MW Idaho Load 2326.0 MW Montana Load 1940.3 MW Montana Load 1339.5 MW Avista Native Load -1701.7 MW Avista Native Load -959.6 MW Avista Balancing Area Load 1671.7 MW Avista Balancing Area Load 911.6 MW Clearwater Load 58.2 MW Clearwater Load 58.2 MW Heavy Summer High Hydro Light Spring High Transfer Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1102 of 1125 Figure 1: 2016 HSHH, all facilities in service, Cabinet Gorge @287MW Thermal Performance during N-1 conditions Given the current study reveals Cabinet Gorge HED must be limited to zero additional capacity when operating under conditions similar to those used in the Heavy Summer, High Hydro case, only the High Transfer case is used to consider N-1 contingency violations. All new N-1 contingency violations found during this study are in the immediate vicinity of the Cabinet Gorge HED. Figure 2 shows the most limiting contingency occuring when the Cabinet to Noxon 230 kV line overloads with a loss of the 230 kV line to Rathdrum for a failure of breaker R404.2 As noted in the notes above, Avista has transmission projects underway that lessen the severity of all of the N-1 contingency violations found in this study, and further detailed study will determine what, if any, N-1 violations still exist once the local projects are completed. Note: Reducing the new generation at Cabinet Gorge to values less than the requested 110 MW directly impacts the new limiting N-1 contingency violations. This behavior likely reduces the steady state nomogram discussed above. Figure 2: Cabinet-Noxon 230 kV overload during R404 breaker failure Voltage Stability With all lines in service, an addition of 110 MW at Cabinet Gorge does not introduce any new voltage violations during N-0 conditions. However, this study indicates several new voltage violations are present during N-1 conditions. The limiting contingency regarding voltage stability occurs at Bus 48057, the Cabinet Gorge 230 kV bus, during the N-1: Cabinet – Noxon 230 kV contingency. The voltage limit used is 1.015 pu, the initial value is 1.045 pu, and the value during contingency is 1.0049 pu. Figure 3 shows the violation. 2 BF: R404 Cabinet-Rathdrum, Rathdrum #2 230/115 Transformer Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1103 of 1125 All of the newly created voltage violations can be mitigated by reducing generation at Cabinet Gorge to levels above present values but below the requested 110 MW addition. Additionally, existing and planned projects on the Avista transmission system positively influence these new voltage violations. Further detailed studies are necessary to fully characterize voltage performance. Figure 3: 2016 HT, Voltage Limit Violation, N-1: Cabinet – Noxon 230 kV Transient Stability Preliminary studies indicate new generation at Cabinet Gorge adds stability violations during N-1 conditions, and additional generation exacerbates stability issues addressed by the existing Clark Fork remedial action scheme (i.e. RAS). Adding any new generation to the existing RAS scheme clears several of the new N-1 violations, but further studies are necessary to accurately assess solutions for the other violations. Possible solutions could be changes to the existing RAS, a nomogram as discussed above, and/or transmission projects to mitigate violations. Conclusions This study indicates the requested new generation at Cabinet Gorge performs adequately on the local transmission system with potential updates to the Clark Fork RAS and limits to Cabinet Gorge and Noxon combined output via a seasonally adjusted nomogram determined by further study. If operating Cabinet Gorge without limitation is desired, preliminary studies show this is possible via potential projects on one or more of the 230 kV transmission lines carrying power to the load center. Distribution: S. Waples Sharepoint (System Planning) OASIS Posting Power Supply (J. Gall) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1104 of 1125 500 MW of New Generation in the Rathdrum Area Page 1 Interoffice Memorandum System Planning MEMO: SP-2011-08 Rev A DATE: August 11, 2011 TO: James Gall, IRP Group FROM: Reuben Arts SUBJECT: 500 MW of New Generation in the Rathdrum Area Introduction Based on initial 2011 IRP analysis 200 MW of new capacity is required in 2019-2020 and an additional 300 MW of capacity in the 2022-2024 time period. North Idaho is one of several potential locations this capacity could be added, but requires further detail to understand its potential. Problem Statement The IRP group is specifically interested in the cost for both the point of integration (POI) station and associated system upgrades, to integrate the new generation with the following options: 1. Cabinet-Rathdrum 230 kV transmission line (assume 5 miles from Rathdrum) 2. Rathdrum-Boulder 230 kV transmission line (assume Lancaster looped in, and assume the generation is half way between Lancaster and Rathdrum) 3. Rathdrum-Beacon 230 kV transmission line (assume 1-2 miles from Rathdrum) 4. Double Tap, Rathdrum-Boulder and Rathdrum-Beacon 230 kV transmission lines (again assume Lancaster is looped in and that the new generation will tap between Lancaster and Rathdrum) 5. Mixed location. 300 MW at the least cost option (between 1 and 4) and an additional 200 MW on the Cabinet-Rathdrum 230 kV transmission line. 6. Other Transmission Alternatives Power Flow Analysis The case that was used to highlight the impacts of an additional 500 MW in the Rathdrum area was the WECC approved and Avista modified light summer high flow case (AVA-11ls1ae-12BA1251-WOH4277). The West of Hatwai path typically experiences high flows during light Avista load hours. High West of Hatwai flows tend to coincide with high Western Montana Hydro generation, high Boundary generation, high flows on Montana to Northwest, and light loads in Eastern Washington, North Idaho, and Montana. Existing Clark Fork RAS is in place, and assumed armed, since the Western Montana Hydro (WMH) complex is greater than 1450 MW. Since the New Project would require significant Avista system transmission changes, and RAS changes, the results are listed as though RAS were not armed. This does affect the results of some contingencies, but ultimately does not change the conclusions of this memo. Option 1 Perhaps one of the worst performing arrangements is option 1.This option immediately requires another line, or a line reconductor, from the 500 MW project back to Rathdrum. In order to stay within N-0 thermal limits the project can only be 175 MW without any system upgrades. In a high flow, N-0 scenario, the line segment from the project back to Rathdrum loads to around 163%, which is roughly 272 MW overloaded. There are a handful of N-1 and N-2 contingencies that cause significant thermal violations, the worst N-1 being the loss of the 230 kV transmission line from the new project to Rathdrum. See Figure 1 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1105 of 1125 500 MW of New Generation in the Rathdrum Area Page 2 Figure 1 – N-1 Contingency In addition to this worst case outage there are two N-2 scenarios that cause fairly significant problems as well. The Beacon-Rathdrum and Boulder-Lancaster-Rathdrum 230 kV transmission lines share a common structure for the majority of the line lengths. Losing both lines to the west of Lancaster causes the Bell S3- Lancaster 230 kV transmission line to overload. Losing both lines to the east of Lancaster, causes nearly the same scenario as shown in Figure 1. To alleviate these overloads three new 230 kV transmission lines, would need to be built. First the Rathdrum-New Project 230 kV transmission line must be reconductored at a cost of roughly $2.25M. Second, A 230 kV transmission line, with new right-of-way, must be built from the New Project to Lancaster. The estimated distance for this line is roughly 5 miles. The estimated loaded cost for this line, including a new line position at Lancaster and at the New Project, is roughly $9M. Finally, another 230 kV transmission line, again with new right-of-way, is required from Lancaster to Boulder. This line length is estimate at roughly 15 miles. The estimated loaded cost of the new line, including new line positions, is roughly $17M. New right-of-way in this area will be difficult to obtain, which would have the potential of more than doubling costs. RAS may be a viable solution. If at all possible RAS should be a last resort. Unlike improving our transmission system, RAS does not provide operational flexibility and in some cases can compound the impacts of future generation needs. However, it does represent the cheapest solution and is therefore listed as solution 1. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1106 of 1125 500 MW of New Generation in the Rathdrum Area Page 3 Option 1 N-0 Max. Output Facility Requirement1 Total2 ($000) Solution 1 500 MW Reconductor 230 kV transmission line from new station to Rathdrum, New 230 kV DB-DB Station and RAS3 13,250 Solution 2 500 MW Reconductor from Rathdrum-New Project. New line from Lancaster to New Project. New line from Lancaster to Boulder, New 230 kV DB-DB Station 36,250 Option 2 This option would tap the Rathdrum-Boulder, or what soon will be the Rathdrum-Lancaster-Boulder, 230 kV transmission line. This options has no N-0 issues at the full requested 500 MW. There are a handful of N-1 and N-2 contingencies that cause significant thermal violations, the worst being the loss of the Lancaster-Boulder & Rathdrum-Beacon 230 kV transmission lines. These lines share a common structure and therefore represent a credible N-2 scenario. This outage causes the Lancaster-Bell S3 230 kV transmission line to load to 189%, or roughly 450 MW above its thermal limit. See Figure 2. Figure 2 - N-2 Contingency To alleviate these overloads two new 230 kV transmission lines, would need to be built. A 230 kV transmission line, with new right-of-way, must be built from the New Project to Lancaster. The estimated distance for this line is roughly 3 miles. The estimated loaded cost for this line, including a new line position at Lancaster and at the New Project, is roughly $8M. Another 230 kV transmission line, again with new right-of-way, is required from Lancaster to Boulder. This line length is estimate at roughly 15 miles. The estimated loaded cost of the new line, including new line positions, is roughly $17M. New right-of-way in this area will be difficult to obtain, which would have the potential of more than doubling costs. 1 Cost estimates do not include costs of the radial line to the POI, the generator or generator station if applicable. 2 Total is for network and direct assigned costs, are in 2011 dollars, and is +/- 50%. 3 The RAS portion is a worst case scenario where another fiber loop is required. $3M allocated for RAS. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1107 of 1125 500 MW of New Generation in the Rathdrum Area Page 4 RAS may be a viable solution. If at all possible RAS should be a last resort. Unlike improving our transmission system, RAS does not provide operational flexibility and in some cases can compound the impacts of future generation needs. However, it does represent the cheapest solution and is therefore listed as solution 1. Option 2 N-0 Max. Output Facility Requirement4 Total5 ($000) Solution 1 500 MW New 230 kV DB-DB Station and RAS6 11,000 Solution 2 500 MW New line from Lancaster to New Project. New line from Lancaster to Boulder, New 230 kV DB-DB Station 33,000 Option 3 This option taps the Rathdrum-Beacon 230 kV transmission line. Again, this options has no N-0 issues at the full requested 500 MW. There are a handful of N-1 and N-2 contingencies that cause significant thermal violations, the worst being the loss of the Beacon-New Project & Rathdrum-Lancaster 230 kV transmission lines. These lines share a common structure and therefore represent a credible N-2 scenario. This outage forces the entire proposed 500 MW toward Cabinet and Noxon. This causes overloads on the Cabinet-Noxon and Pine Creek-Benewah 230 kV transmission lines. See Figure 3. Figure 3 - N-2 Contingency 4 Cost estimates do not include costs of the radial line to the POI, the generator or generator station if applicable. 5 Total is for network and direct assigned costs, are in 2011 dollars, and is +/- 50%. 6 The RAS portion is a worst case scenario where another fiber loop is required. $3M allocated for RAS. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1108 of 1125 500 MW of New Generation in the Rathdrum Area Page 5 To alleviate these overloads two new 230 kV transmission lines, would need to be built. A 230 kV transmission line, with new right-of-way, must be built from the New Project to Lancaster. The estimated distance for this line is roughly 3 miles. The estimated loaded cost for this line, including a new line position at Lancaster and at the New Project, is roughly $8M. Another 230 kV transmission line, again with new right-of-way, is required from Lancaster to Boulder. This line length is estimate at roughly 15 miles. The estimated loaded cost of the new line, including new line positions, is roughly $17M. New right-of-way in this area will be difficult to obtain, which would have the potential of more than doubling costs. RAS may be a viable solution. If at all possible RAS should be a last resort. Unlike improving our transmission system, RAS does not provide operational flexibility and in some cases can compound the impacts of future generation needs. However, it does represent the cheapest solution and is therefore listed as solution 1. Option 3 N-0 Max. Output Facility Requirement7 Total8 ($000) Solution 1 500 MW New 230 kV DB-DB Station and RAS9 11,000 Solution 2 500 MW New line from Lancaster to New Project. New line from Lancaster to Boulder, New 230 kV DB-DB Station 33,000 Option 4 This option taps the Rathdrum-Beacon & Rathdrum-Lancaster 230 kV transmission lines. This options has no N-0 issues at the full requested 500 MW. There are a handful of N-1 and N-2 contingencies that cause significant thermal violations, the worst being the loss of the Beacon-New Project & Lancaster-New Project 230 kV transmission lines. These lines share a common structure and therefore represent a credible N-2 scenario. This outage forces the entire proposed 500 MW toward Cabinet and Noxon. This causes overloads on the Cabinet-Noxon and Pine Creek-Benewah 230 kV transmission lines. (Very similar to Figure 3 on the previous page). To alleviate these overloads two new 230 kV transmission lines, would need to be built. A 230 kV transmission line, with new right-of-way, must be built from the New Project to Lancaster. The estimated distance for this line is roughly 3 miles. The estimated loaded cost for this line, including a new line position at Lancaster and at the New Project, is roughly $8M. Another 230 kV transmission line, again with new right-of-way, is required from Lancaster to Boulder. This line length is estimate at roughly 15 miles. The estimated loaded cost of the new line, including new line positions, is roughly $17M. New right-of-way in this area will be difficult to obtain, which would have the potential of more than doubling costs. RAS may be a viable solution. If at all possible RAS should be a last resort. Unlike improving our transmission system, RAS does not provide operational flexibility and in some cases can compound the impacts of future generation needs. However, it does represent the cheapest solution and is therefore listed as solution 1. Option 4 N-0 Max. Output Facility Requirement Total ($000) Solution 1 500 MW New 230 kV DB-DB Station and RAS 15,000 Solution 2 500 MW New line from Lancaster to New Project. New line from Lancaster to Boulder, New 230 kV DB-DB Station 37,000 7 Cost estimates do not include costs of the radial line to the POI, the generator or generator station if applicable. 8 Total is for network and direct assigned costs, are in 2011 dollars, and is +/- 50%. 9 The RAS portion is a worst case scenario where another fiber loop is required. $3M allocated for RAS. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1109 of 1125 500 MW of New Generation in the Rathdrum Area Page 6 Option 5 This option taps the Rathdrum-Beacon & Rathdrum-Cabinet 230 kV transmission lines. A new switching station is required for each tap. A 300 MW generating station would be on the Beacon-Rathdrum 230 kV transmission line and 200 MW would be on the Rathdrum-Cabinet 230 kV transmission line. This option has no N-0 issues at the full requested 500 MW. There are a handful of N-1 and N-2 contingencies that cause significant thermal violations, the worst being the loss of the Beacon-New Project & Lancaster-Rathdrum 230 kV transmission lines. These lines share a common structure and therefore represent a credible N-2 scenario. This outage forces the entire proposed 500 MW toward Cabinet and Noxon. This causes overloads on the Cabinet-Noxon and Pine Creek-Benewah 230 kV transmission lines. (Very similar to what was shown in Figure 3). To alleviate these overloads three new 230 kV transmission lines, would need to be built. A 230 kV transmission line, with new right-of-way, must be built from the New Project (300MW piece) to Lancaster. The estimated distance for this line is roughly 5 miles. The estimated loaded cost for this line, including a new line position at Lancaster and at the New Project, is roughly $9M. Another 230 kV transmission line, again with new right-of-way, is required from Lancaster to Boulder. This line length is estimate at roughly 15 miles. The estimated loaded cost of the new line, including new line positions, is roughly $17M. Finally, for the loss of the Rathdrum-New Project (200MW piece) 230 kV transmission line, causes the Cabinet-Noxon 230 kV transmission line to load to 117%. To alleviate this overload a new line, with new right-of-way must be built back to Rathdrum. The estimated loaded cost of this 5 mile line, along with associated line positions, is $9M. New right-of-way in this area will be difficult to obtain, which would have the potential of more than doubling costs. RAS may be a viable solution. If at all possible RAS should be a last resort. Unlike improving our transmission system, RAS does not provide operational flexibility and in some cases can compound the impacts of future generation needs. However, it does represent the cheapest solution and is therefore listed as solution 1. Option 5 N-0 Max. Output Facility Requirement10 Total11 ($000) Solution 1 500 MW Two New 230 kV DB-DB Stations and RAS12 22,000 Solution 2 500 MW Two New 230 kV DB-DB Stations, New line from Lancaster to New Project (300MW). New line from Lancaster to Boulder, New line from New Project (200MW) to Rathdrum 51,000 Option 6 – Other Transmission Alternatives In addition to the five options listed, there are a few more options that may seem to be intuitive interconnection points. These integration options are: a. Lancaster 230 kV (BPA) switching station b. Rathdrum 230/115/13.2 kV substation c. Cabinet-Rathdrum & Noxon-Lancaster 230 kV transmission lines d. Bell-Taft 500 kV transmission line Option 6a - Connecting to the Lancaster 230 kV switching station would save Avista the cost of a new switching station. It would also negate the need for a new transmission line, with associated right-of-way, from the new project to Lancaster. The estimated savings, adding the previously quoted loaded costs, less 10 Cost estimates do not include costs of the radial line to the POI, the generator or generator station if applicable. 11 Total is for network and direct assigned costs, are in 2011 dollars, and is +/- 50%. 12 The RAS portion is a worst case scenario where another fiber loop is required. $3M allocated for RAS. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1110 of 1125 500 MW of New Generation in the Rathdrum Area Page 7 the added cost of connecting to Lancaster, is $13M13. This does not take into account any fees associated with connecting to BPA. This option assumes there is room in the Lancaster substation to accept the new line position. If Lancaster substation cannot accommodate the new line position, the cost savings to interconnect at Lancaster may be negligible or non-existent. This option would still have all the contingency issues and associated upgrades similar to Option 2. Option 6b - Connecting to the Rathdrum substation saves the cost of building another switching station. All contingency results are nearly identical to connecting the project to option 2 or option 3. The estimated savings of this option is $4M14. This option assumes there is room in the Rathdrum substation to accept the new line position. If Rathdrum substation cannot accommodate the new line position, the cost savings to interconnect at Rathdrum may be negligible or non-existent. Option 6c – Tapping the Cabinet-Rathdrum & Noxon-Lancaster 230 kV transmission lines does improve the network performance, in comparison to tapping only the Cabinet-Rathdrum 230 kV transmission line. However, this option still requires all the same network upgrades that option 1 requires since it is still possible to have an N-2 situation where the generation of the New Project, Noxon and Cabinet is separated from the Coeur d’Alene/Spokane load. (See Figure 1). This option is listed for completeness. Option 6d - Connecting solely to the Bell-Taft 500 kV transmission line cannot be done without RAS and possibly some network upgrades on BPA’s system. In addition to the network upgrades that would likely be required on BPA’s system, Avista would also be financially liable to pay wheeling fees from the new project across BPA’s lines to Avista’s load. If the project is connected to both BPA’s Bell-Taft 500 kV transmission line and Avista’s Rathdrum area 230 kV system, effectively avoiding wheeling charges, both RAS and significant network upgrades will be required. Due to the cost of a new 500 kV substation, associated RAS and the potentially large cost of network upgrades on BPA’s 500 kV system, this option is not recommended. Conclusion Of the formally identified options, options 2 and 3 represent the least cost and best performing options. Of the other transmission alternatives, the Lancaster switching station, followed by the Rathdrum substation, interconnection options represent the least cost and best performing alternative options. The following favorable options are: Option 2: $11-33M (RAS only vs System Upgrades)15 Option 3: $11-33M (RAS only vs System Upgrades)15 Lancaster Alternative Option: $7-20M (RAS only vs System Upgrades) Rathdrum Alternative Option: $7-33M (RAS only vs System Upgrades) 13 Assumes a network upgrade solution would be pursued, instead of a RAS only solution. 14 This $4M savings would be for either a RAS only or a network upgrade solution. 15 If the new project is interconnected to the west of Lancaster, the Lancaster-New Project 230 kV transmission line is not needed. Hence the network upgrade cost would be reduced by $8M. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1111 of 1125 Interoffice Memorandum System Planning MEMO: SP-2013-07 DATE: February 15, 2012 TO: Scott Waples FROM: Richard Maguire SUBJECT: IRP Generation Study - Benewah to Boulder 230kV (BB-IRP) Introduction This study addresses a request from Avista’s Power Supply Department for the 2013 IRP regarding new generation on the Benewah - Boulder 230 kV Transmission Line at one of two capacity levels: 150 MW 300 MW The study presents information and discussion on the follow topics: Power flow impact to the transmission system Transmission system upgrades necessary to deliver requested generation Study Assumptions and Methodology The five year planning horizon Avista planning cases, as documented in SP-2011-03 – 2011 Planning Cases Summary Data, are modified with the following projects and adjustments prior to system analysis: LGIR #35 project (200 MW at Thornton 230 kV Substation) LGIR #36 project (105 MW at Thornton 230 kV Substation) BB-IRP topology: o Benewah – Boulder 230kV Transmission Line tapped 13.1 electrical miles North of Benewah 230 kV Substation o Generic generator installed on new BB-IRP 230 kV bus The following cases are used during this study: Avista Heavy Summer High Hydro (“HSHH”) case: AVA-11hs2a-12BA2085 o Table 1 shows power flows for this case Avista Heavy Summer Low Hydro (“HSLH”) case: AVA-11hs2a-12BA2085-LH o Table 2 shows power flows for this case Avista Light Summer with High West of Hatwai (High Transfers or “HT”)Flows: AVA-11ls1ae-12BA1251-WOH4277 o Table 3 shows power flows for this case with BB-IRP output = 300 MW Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1112 of 1125 Benewah – Boulder 2013 IRP Study Table 1: Regional Power Flows for Heavy Summer Case Table 2: Regional Power Flows for Light Summer Case Western Montana Hydro 1098.1 MW West of Hatwai (Path 6) 951.8 MW Noxon Rapids (562MW) 399.4 MW Lolo-Oxbow 230kV 296.0 MW Cabinet Gorge (265MW) 184.7 MW Dry Creek-Walla Walla 230kV 184.1 MW Libby (605MW)324.0 MW Hungry Horse (430MW) 190.0 MW West of Cabinet 1581.7 MW Montana-Northwest (Path 8) 979.0 MW Colstrip Total Colstrip 1 (330MW)330.0 MW Idaho-Northwest (Path 14) -585.4 MW Colstrip 2 (330MW)330.0 MW Midpoint-Summer Lake (Path 75) -48.9 MW Colstrip 3 (823MW)795.5 MW Idaho-Montana (Path 18) -296.3 MW Colstrip 4 (823MW)804.9 MW South of Boundary 582.9 MW Rathdrum Thermal (175MW) 0.0 MW North of John Day (Path 73) 7034.7 MW Lancaster Thermal (270MW) 249.0 MW TOT 4A (Path 37)407.0 MW Spokane River Hydro 88.3 MW Miles City DC 142.0 MW Boundary Hydro (1040MW) 635.0 MW Path C (Path 20)118.7 MW Lower Snake/N.F. Clearwater Borah West (Path 17)837.4 MW Dworshak (458MW)316.0 MW Bridger West (Path 19) 2191.6 MW Lower Granite (930MW) 554.2 MW Pacific AC Intertie (Path 66) 4430.9 MW Little Goose (930MW)555.5 MW Pacific DC Intertie (Path 65) 2980.0 MW Lower Monumental (930MW) 531.5 MW Northwest Load 25129.6 MW Coulee Generation Idaho Load 3702.5 MW Coulee 500 kV 2308.5 MW Montana Load 1836.8 MW Coulee 230 kV 1292.7 MW Avista Native Load -1594.3 MW Avista Balancing Area Load 1885.6 MW Clearwater Load 58.3 MW Western Montana Hydro 627.1 MW West of Hatwai (Path 6) 120.3 MW Noxon Rapids (562MW) 138.8 MW Lolo-Oxbow 230kV 277.0 MW Cabinet Gorge (265MW) 82.3 MW Dry Creek-Walla Walla 230kV 159.6 MW Libby (605MW)216.0 MW Hungry Horse (430MW) 190.0 MW West of Cabinet 1110.7 MW Montana-Northwest (Path 8) 970.1 MW Colstrip Total Colstrip 1 (330MW)330.0 MW Idaho-Northwest (Path 14) -585.9 MW Colstrip 2 (330MW)330.0 MW Midpoint-Summer Lake (Path 75) -76.0 MW Colstrip 3 (823MW)764.2 MW Idaho-Montana (Path 18) -274.8 MW Colstrip 4 (823MW)776.0 MW South of Boundary 299.4 MW Rathdrum Thermal (175MW) 0.0 MW North of John Day (Path 73) 6931.9 MW Lancaster Thermal (270MW) 249.0 MW TOT 4A (Path 37)399.6 MW Spokane River Hydro 58.1 MW Miles City DC 142.0 MW Boundary Hydro (1040MW) 310.0 MW Path C (Path 20)133.4 MW Lower Snake/N.F. Clearwater Borah West (Path 17)830.6 MW Dworshak (458MW)316.0 MW Bridger West (Path 19) 2188.8 MW Lower Granite (930MW) 554.2 MW Pacific AC Intertie (Path 66) 4222.6 MW Little Goose (930MW)555.5 MW Pacific DC Intertie (Path 65) 2980.0 MW Lower Monumental (930MW) 531.5 MW Northwest Load 25129.6 MW Coulee Generation Idaho Load 3702.5 MW Coulee 500 kV 3066.4 MW Montana Load 1836.8 MW Coulee 230 kV 1292.7 MW Avista Native Load -1594.3 MW Avista Balancing Area Load 1874.1 MW Clearwater Load 75.8 MW Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1113 of 1125 Benewah – Boulder 2013 IRP Study Table 3: Regional Power Flows for High Transfer Case Western Montana Hydro 1548.0 MW West of Hatwai (Path 6) 4251.2 MW Noxon Rapids (562MW) 432.2 MW Lolo-Oxbow 230kV 140.1 MW Cabinet Gorge (265MW) 195.8 MW Dry Creek-Walla Walla 230kV 189.5 MW Libby (605MW)540.0 MW Hungry Horse (430MW) 380.0 MW West of Cabinet 3204.5 MW Montana-Northwest (Path 8) 2040.8 MW Colstrip Total Colstrip 1 (330MW) 330.0 MW Idaho-Northwest (Path 14) 741.0 MW Colstrip 2 (330MW) 330.0 MW Midpoint-Summer Lake (Path 75) 831.7 MW Colstrip 3 (823MW) 777.6 MW Idaho-Montana (Path 18) -198.3 MW Colstrip 4 (823MW) 782.9 MW South of Boundary 961.8 MW Rathdrum Thermal (175MW) 116.4 MW North of John Day (Path 73) 4775.0 MW Lancaster Thermal (270MW) 118.1 MW TOT 4A (Path 37)448.4 MW Spokane River Hydro 152.4 MW Miles City DC 200.0 MW Boundary Hydro (1040MW) 975.0 MW Path C (Path 20)528.7 MW Lower Snake/N.F. Clearwater Borah West (Path 17)1570.2 MW Dworshak (458MW) 168.2 MW Bridger West (Path 19) 2098.0 MW Lower Granite (930MW) 0.0 MW Pacific AC Intertie (Path 66) 3136.7 MW Little Goose (930MW) 141.8 MW Pacific DC Intertie (Path 65) 1999.9 MW Lower Monumental (930MW) 310.0 MW Northwest Load 17796.4 MW Coulee Generation Idaho Load 2326.0 MW Coulee 500 kV 825.7 MW Montana Load 1339.5 MW Coulee 230 kV 125.0 MW Avista Native Load -837.0 MW Avista Balancing Area Load 680.3 MW Clearwater Load 71.1 MW Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1114 of 1125 Benewah – Boulder 2013 IRP Study Study Results Thermal Performance during Category A conditions1 This preliminary study indicates the Avista Transmission System has adequate capacity to integrate 300 MW at the proposed interconnection point during Category A all lines in service conditions. Thermal Performance during Category B and Category C conditions Table 4 shows preliminary results of a study using PowerWorld Simulator’s Available Transfer Capability (ATC) tool for generation injections at BB-IRP. This tool generates a list of facility thermal violations (From To) that arise under contingency conditions for incremental increases in generation output (BB WM). When the results for each case under study are collected and analyzed together with results from standard contingency analysis studies, this tool provides an idea of what facilities overload for rising levels of generation output. As the table shows, there are six facilities that come into violation for a requested BB-IRP output of 150 MW, and there are an additional five facilities that come into violation for a requested BB-IRP output of 300 MW. Table 4: Incremental generation analysis for BB-IRP IRP request2 1 Contingency category descriptions can be found at: http://www.nerc.com/files/TPL-001-0.pdf 2 BF = Breaker Failure; PSF = Protection System Failure; N-X contingencies refer to ‘X’ transmission element outages Case MW Output Limiting Contingency From Name To Name HSLH 27.11 BF: A470 Westside 115 kV, College & Walnut-Westside GLENTAP NINTHCNT HSHH 28.2 BUS: Westside 115 kV POSTSTRT THIRHACH HT 84.08 N-1: Hatwai - Moscow 230 230 kV MOSCOW MOSCOWX HSLH 106.34 BUS: Westside 115 kV ROSSPARK THIRHACH HSHH 106.63 BF: A413 Westside 115 kV, Ninemile-Westside POSTSTRT THIRHACH HSHH 112.15 BF: A689 Ninth & Central South 115 kV, Ninth & Central-Otis Orchards POSTSTRT THIRHACH HSLH 116.64 N-2: Bell - Westside 230 kV & Coulee - Westside 230 kV GLENTAP NINTHCNT HSLH 117.24 BUS: Westside 230 kV GLENTAP NINTHCNT HSLH 123.43 BF: A370 Bell S1 & S2 230 kV BEACON N BEACON N HSHH 160.37 N-1: Shawnee - Thornton 230 kV MOSCOW MOSCOWX HSHH 164.3 N-1: North Lewiston - Shawnee 230 kV TERRVIEW NPULLMAN HSHH 173.34 BUS: North Lewiston 230 kV TERRVIEW NPULLMAN HSLH 184.24 BF: A413 Westside 115 kV, Ninemile-Westside ROSSPARK THIRHACH HT 206.31 N-2: Beacon - Boulder 230 kV & Beacon - Rathdrum 230 kV BOULDERE IRVIN HT 215.35 BF: R427 Beacon North & South 230 kV BOULDERE IRVIN HT 215.68 N-2: Beacon - Boulder 230 kV & Beacon - Rathdrum 230 kV IRVIN MILLWOOD HT 223.63 BF: R427 Beacon North & South 230 kV IRVIN MILLWOOD HSHH 253.83 N-2: Shawnee - Thornton 230 kV & Lind - Shawnee 115 kV MOSCOW MOSCOWX HT 269.19 N-2: Beacon - Boulder 230 kV & Beacon - Rathdrum 230 kV BOULDERW SPKINDPK HT 271.24 BUS: Hatwai 230 kV MOSCOWX MOSCOW HSLH 272.76 BUS: Hatwai 230 kV MOSCOWX MOSCOW HSLH 275.44 PSF: Ninth & Central South 115 kV BEACON S NINTHCNT HSHH 275.67 BUS: Westside 230 kV POSTSTRT THIRHACH HSHH 275.84 N-2: Bell - Westside 230 kV & Coulee - Westside 230 kV POSTSTRT THIRHACH HT 280.08 BF: R427 Beacon North & South 230 kV BOULDERW SPKINDPK HSLH 298.33 BUS: North Lewiston 230 kV HATWAI LOLO HT 300.27 N-2: Bell - Taft 500 kV and Bell - Lancaster 230 kV BOULDER BB-IRP Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1115 of 1125 Benewah – Boulder 2013 IRP Study Notes regarding thermal performance: Avista has planned projects that mitigate some of the above mentioned facility violations. However, some of the planned projects also result in new facility thermal violations during contingencies. Further study of planned projects and potential options will be necessary. Preliminary studies indicate some reduction in the above thermal violations when Projects #35 and #36 are removed from study, but the reduction in thermal violations is confined mainly to limiting facilities south of BB-IRP. Without Projects #35 and #36, significant power continues to flow north through the Boulder 230 kV substation and onto the local 115 kV Transmission System in the Spokane and Spokane Valley areas. Voltage Performance Preliminary studies show voltage issues of a nature that can be addressed with properly sited reactive support. Further detailed studies can be used to determine the exact amount and location of any reactive support necessary to mitigate facility voltage violations. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1116 of 1125 Benewah – Boulder 2013 IRP Study Potential Solutions Options3 230 kV Switching station required for all options mentioned below: 4 position double bus double breaker ~ $4 M Option 1: Reconductor facilities brought into violation due to the requested generation 150 MW option would require: o $3.41 M of 115 kV upgrades 300 MW option would require an additional: o $1.9 M of 115 kV upgrades o $5.36 M of 230 kV upgrades Option 2: Complete currently planned projects and reconductor limiting facilities Currently Planned Projects: o Lancaster Interconnection o Spokane Valley Transmission Reinforcement o Moscow Transformer Replacement o Westside Transformer Replacement 150 MW option would require: o $2.4 M of 115 kV upgrades 300 MW option would require an additional: o $932 K of 115 kV upgrades o $5.36 M of 230 kV upgrades Conclusion This project is a feasible project based on the preliminary analysis performed. A summary of options and cost estimates is given in Table 3. 3 All construction costs are in 2013-year dollars and based on engineering judgment alone with +/- 50% accuracy Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1117 of 1125 500 MW of New Generation in the Rathdrum Area Page 1 Interoffice Memorandum System Planning MEMO: SP-2011-09 Rev B - Final DATE: January 13, 2012 TO: James Gall, IRP Group FROM: Reuben Arts SUBJECT: New Generation, 300 MW in the Rathdrum Area and 200 MW in the Rosalia Area Introduction Based on initial 2011 IRP analysis 200 MW of new capacity is required in 2019-2020 and an additional 300 MW of capacity in the 2022-2024 time period. North Idaho is one of several potential locations this capacity could be added, but requires further detail to understand its potential. Problem Statement As a follow up to the IRP informational request for 500 MW in N. Idaho, SP-2011-08, the IRP group requests the following additional cost studies. 1) Split the 500 MW into ~200 MW connecting at the Thornton substation by the end of 2018, then ~300 MW integrated at Lancaster substation by the end of 2023. 2) Split the 500 MW into ~200 MW connecting at the Thornton substation by the end of 2018, then ~300 MW integrated at the Boulder- Lancaster line by the end of 2023. 3) Split the 500 MW into ~200 MW connecting at the Thornton substation by the end of 2018, then ~300 MW integrated at the Rathdrum substation by the end of 2023. Power Flow Analysis The case that was used to highlight the impacts of an additional 300 MW in the Rathdrum area was the WECC approved and Avista modified light summer high flow case (AVA-11ls1ae-12BA1251-WOH4277). The West of Hatwai path typically experiences high flows during light Avista load hours. High West of Hatwai flows tend to coincide with high Western Montana Hydro generation, high Boundary generation, high flows on Montana to Northwest, and light loads in Eastern Washington, North Idaho, and Montana. Existing Clark Fork RAS is in place, and assumed armed, since the Western Montana Hydro (WMH) complex is greater than 1450 MW. Since the New Project would require significant Avista system transmission changes, and RAS changes, the results are listed as though RAS were not armed. This does affect the results of some contingencies, but ultimately does not change the conclusions of this memo. Option 1 300 MW of new generation in the Rathdrum area, near the BPA Lancaster substation and 200 MW in the Rosalia area is option 1. The 300 MW portion, assumes a new 230/13 kV Avista generator substation would be required. Several connection possibilities exist for connecting this substation to the 230 kV transmission system in this area. For simplification it will be assumed that the new substation will tap the to-be-constructed Rathdrum – Lancaster 230 kV transmission line. This option has no N-0 issues at the full 300 MW. There are a handful of N-1 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1118 of 1125 500 MW of New Generation in the Rathdrum Area Page 2 and N-2 contingencies that cause significant thermal violations, the worst being the loss of the Lancaster-Boulder & Rathdrum-Beacon 230 kV transmission lines. These lines share a common structure and therefore represent a credible N-2 scenario. This outage causes the Lancaster-Bell S3 230 kV transmission line to load to 164%, or roughly 320 MW above its thermal limit. See Figure 2. Figure 2 - N-2 Contingency To alleviate these overloads a new 230 kV transmission line, with new right-of-way, is required from Lancaster to Boulder. This line length is estimate at roughly 15 miles. The estimated loaded cost of the new line, including new line positions, is roughly $17M. New right-of-way in this area will be difficult to obtain, which would have the potential of more than doubling costs. RAS may be a viable solution. If at all possible RAS should be a last resort. Unlike improving our transmission system, RAS does not provide operational flexibility and in some cases can compound the impacts of future generation needs. However, it does represent the cheapest solution and is therefore listed as solution 1. A RAS solution would have to integrate with the existing Clark Fork RAS scheme and additionally trip all generation at Lancaster and the proposed new 300 MW facility. For the 200 MW option, to be located in Rosalia WA, it is assumed that the generation will interconnect at the new Thornton 230 kV switching station (scheduled to be finished in 2012). The steady state impacts from this additional 200 MW would be similar to previously studied LGIR #14 – which sought to connect 220 MW in the Colton WA area. No new transmission system upgrades, with the exception of the interconnection substation, were required. At this time, pending no new queue additions that could be considered senior to this proposed 200 MW, the results are expected to be similar to LGIR #14. Therefore the total cost of integrating 200 MW in the Rosalia area should be $4M, the cost of another breaker position at Thornton 230 kV switching station. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1119 of 1125 500 MW of New Generation in the Rathdrum Area Page 3 Option 1 N-0 Max. Output Facility Requirement1 Total2 ($000) Solution 1 500 MW New 230 kV DB-DB Station and RAS. New Breaker Position @ Thornton. 15,000 Solution 2 500 MW New line from Lancaster to New Project. New 230 kV DB- DB Station. New Breaker Position @ Thornton. 32,000 Option 2 This is essentially the same option as Option 1. Placing the new generation within 1 mile of Lancaster switching station will have roughly the same reliability performance. The major outage of concern is the simultaneous loss of the Rathdrum – Beacon and Rathdrum – Boulder (soon to be Lancaster – Boulder) 230 kV lines. This contingency will cause BPA’s Lancaster – Bell 230 kV transmission line to load to roughly 164% without RAS. There is no room in the Rathdrum area for 300 MW, without RAS or some major transmission upgrades, as outlined in the table below. Option 2 N-0 Max. Output Facility Requirement3 Total4 ($000) Option 3 300 MW of new generation in the Rathdrum area, near the BPA Lancaster substation and 200 MW in the Rosalia area is option 1. The 300 MW portion, assumes a new 230/13 kV Avista generator substation would be required. Several connection possibilities exist for connecting this substation to the 230 kV transmission system in this area. For simplification it will be assumed that the new substation will tap the to-be-constructed Rathdrum – Lancaster 230 kV transmission line. This option has no N-0 issues at the full 300 MW. There are a handful of N-1 and N-2 contingencies that cause significant thermal violations, the worst being the loss of the Lancaster-Boulder & Rathdrum-Beacon 230 kV transmission lines. The result is the same as with Option 1. Additionally there with Option 2, there is the opportunity for the Rathdrum-Beacon and the Rathdrum-Boulder (soon to be Rathdrum-Lancaster) 230 kV to be simultaneously lost, as they both share the same structure. This would cause the Cabinet – Noxon 230 kV transmission line to load to 123%. To alleviate these overloads a new 230 kV transmission line, with new right-of-way, is required from Lancaster to Boulder. This line length is estimate at roughly 15 miles. The estimated loaded cost of the new line, including new line positions, is roughly $17M. Another 230 kV transmission line, with new right-of-way, from Rathdrum to Lancaster 230 kV switching station, must be built. The loaded cost for this roughly 3 mile line is $4M. New right-of-way in this area will be difficult to obtain, which would have the potential of more than doubling costs. 1 Cost estimates do not include costs of the radial line to the POI, the generator or generator station if applicable. 2 Total is for network and direct assigned costs, are in 2011 dollars, and is +/- 50%. 3 Cost estimates do not include costs of the radial line to the POI, the generator or generator station if applicable. 4 Total is for network and direct assigned costs, are in 2011 dollars, and is +/- 50%. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1120 of 1125 500 MW of New Generation in the Rathdrum Area Page 4 RAS may be a viable solution. If at all possible RAS should be a last resort. Unlike improving our transmission system, RAS does not provide operational flexibility and in some cases can compound the impacts of future generation needs. However, it does represent the cheapest solution and is therefore listed as solution 1. A RAS solution would have to integrate with the existing Clark Fork RAS scheme and additionally trip all generation at Lancaster and the proposed new 300 MW facility. For the 200 MW option, to be located in Rosalia WA, it is assumed that the generation will interconnect at the new Thornton 230 kV switching station (scheduled to be finished in 2012). The steady state impacts from this additional 200 MW would be similar to previously studied LGIR #14 – which sought to connect 220 MW in the Colton WA area. No new transmission system upgrades, with the exception of the interconnection substation, were required. At this time, pending no new queue additions that could be considered senior to this proposed 200 MW, the results are expected to be similar to LGIR #14. Therefore the total cost of integrating 200 MW in the Rosalia area should be $4M, the cost of another breaker position at Thornton 230 kV switching station. Option 3 N-0 Max. Output Facility Requirement5 Total6 ($000) Conclusion All options are feasible and vary in cost by roughly $4M. There are not any great differences in price, reliability or future growth (MW) potential. Option 3 with RAS represents the cheapest option. There are no substantial reliability gains in putting the project closer to Lancaster. Connecting the project at Rathdrum represents a much cleaner solution that would not require Avista to add yet another substation in the Rathdrum – Lancaster area. 5 Cost estimates do not include costs of the radial line to the POI, the generator or generator station if applicable. 6 Total is for network and direct assigned costs, are in 2011 dollars, and is +/- 50%. Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1121 of 1125 2013 Electric Integrated Resource Plan Appendix E – 2013 Electric IRP New Resource Table for Transmission Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1122 of 1125 Resource POR Capacity Year Resource Location or Local Area POD Start Stop MW Total Coyote Springs 2 Boardman, OR Coyote Springs 2 AVA System 1/1/2014 Indefinite 10.0 Lancaster CCCT Rathdrum, ID Bell/Westside AVA System 1/1/2014 10/31/2026 125.0 Lancaster CCCT Rathdrum, ID Mid-C AVA System 1/1/2014 10/31/2026 150.0 285.0 Nine Mile Nine Mile Falls, WA Nine Mile AVA System 12/1/2015 Indefinite 7.6 7.6 SCCT TBD TBD AVA System 10/1/2019 Indefinite 83.0 83.0 CCCT TBD TBD AVA System 11/1/2026 Indefinite 270.0 270.0 Rathdrum CT Rathdrum, ID Rathdrum AVA System 5/1/2028 Indefinite 6.0 6.0 SCCT TBD TBD AVA System 10/1/2032 Indefinite 50.0 50.0 Total 702 702 2013 Avista Electric IRP New Resource Table For Transmission Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1123 of 1125 The following table replaces Table 1 “The 2013 Preferred Resource Strategy” in the Executive Summary referenced on page v, and Table 8.2 “Preferred Resource Strategy” in Chapter 8, referenced on page 8-8. Resource By the End of Year Nameplate (MW) Energy (aMW) Simple Cycle CT 2019 83 76 Simple Cycle CT 2023 83 76 Combined Cycle CT 2026 270 248 Simple Cycle CT 2027 83 76 Rathdrum CT Upgrade 2028 6 5 Simple Cycle CT 2032 50 46 Total 575 529 Efficiency Improvements By the End of Year Peak Reduction Energy (aMW) Energy Efficiency 2014-2033 221 164 Demand Response 2022-2027 19 0 Distribution Efficiencies 2014-2017 <1 <1 Total 240 164 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1124 of 1125 The following table replaces Table 8.15 “Load Growth Sensitivities” in Chapter 8 referenced on page 8-35. Year PRS Low Growth Medium Low Growth High Growth 2014 2015 2016 2017 2018 2019 83 MW SCCT 150 MW SCCT 2020 2021 2022 6 MW Upgrade 92 MW SCCT 2023 83 MW SCCT 90 MW SCCT 2024 2025 2026 270 MW CCCT 270 MW CCCT 270 MW CCCT 270 MW CCCT 2027 83 MW SCCT 50 MW SCCT 92 MW SCCT 2028 6 MW Upgrade 2029 6 MW Upgrade 50 MW SCCT 2030 2031 2032 2033 50 MW SCCT 50 MW SCCT Demand Response (MW)19 1 20 20 Conservation (aMW)0 0 0 0 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 1, Page 1125 of 1125 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 Energy Position 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 REQUIREMENTS1Native Load -1,054 -1,067 -1,079 -1,093 -1,105 -1,114 -1,125 -1,135 -1,145 -1,155 -1,167 -1,180 -1,190 -1,201 -1,212 -1,225 -1,239 -1,254 -1,270 -1,2852Firm Power Sales -109 -58 -58 -6 -6 -5 -5 -5 -5 -5 -5 -5 -5 -5 -5 -5 -5 -5 -5 -53Total Requirements -1,163 -1,125 -1,137 -1,099 -1,111 -1,119 -1,130 -1,140 -1,150 -1,160 -1,172 -1,185 -1,195 -1,206 -1,217 -1,230 -1,244 -1,259 -1,274 -1,290 RESOURCES4Firm Power Purchases 128 129 128 76 76 56 31 30 30 29 29 29 29 29 29 29 29 29 29 29 5 Hydro 527 495 495 495 490 481 481 481 481 481 481 481 481 481 481 481 481 481 481 4816Baseload/Intermediate Resources 723 725 718 715 732 711 724 736 713 717 714 719 673 506 504 506 504 506 504 506 7 Wind Resources 42 40 40 40 40 40 40 40 40 40 40 40 40 40 40 40 40 40 40 408Total Resources 1,420 1,390 1,382 1,327 1,337 1,288 1,275 1,287 1,264 1,267 1,263 1,269 1,222 1,056 1,054 1,056 1,054 1,056 1,054 1,056 9 POSITION 257 265 245 227 226 168 145 147 114 107 91 84 27 -150 -164 -174 -191 -203 -221 -234 CONTINGENCY PLANNING10Peaking Resources 153 139 154 153 153 153 147 151 152 153 152 153 152 153 152 153 152 153 152 15311Contingency-228 -231 -231 -232 -232 -214 -195 -196 -196 -197 -197 -198 -198 -199 -199 -200 -200 -201 -202 -202 12 CONTINGENCY NET POSITION 182 173 167 148 147 106 96 103 70 63 46 39 -19 -197 -211 -221 -239 -252 -270 -284 Energy Margin 22%24%22%21%20%15%13%13%10%9%8%7%2%-12%-13%-14%-15%-16%-17%-18% January Peak Position (1 Hour) 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 REQUIREMENTS131Native Load -1,665 -1,683 -1,700 -1,713 -1,727 -1,741 -1,755 -1,769 -1,783 -1,798 -1,812 -1,827 -1,842 -1,856 -1,871 -1,887 -1,902 -1,917 -1,933 -1,948 21 2 Firm Power Sales -211 -158 -158 -8 -8 -6 -6 -6 -6 -6 -6 -6 -6 -6 -6 -6 -6 -6 -6 -63Total Requirements -1,875 -1,841 -1,857 -1,721 -1,735 -1,747 -1,761 -1,775 -1,789 -1,804 -1,818 -1,833 -1,848 -1,863 -1,878 -1,893 -1,908 -1,923 -1,939 -1,954 RESOURCES344Firm Power Purchases 117 117 117 117 117 116 34 34 33 33 33 33 33 33 33 33 33 33 33 33 68 5 Hydro Resources 998 888 889 955 955 919 924 920 920 928 920 920 928 920 920 928 920 920 928 920876Base Load Thermals 895 895 895 895 895 895 895 895 895 895 895 895 895 617 617 617 617 617 617 617 95 7 Wind Resources 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 01068Peaking Units 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242 9 Total Resources 2,252 2,143 2,143 2,210 2,210 2,172 2,095 2,091 2,091 2,098 2,090 2,090 2,098 1,811 1,811 1,819 1,811 1,811 1,819 1,811 10 PEAK POSITION 377 302 286 489 475 425 334 316 301 294 272 257 250 -51 -66 -74 -97 -112 -120 -143 RESERVE PLANNING 111 11 Planning Margin -233 -236 -238 -240 -242 -244 -246 -248 -250 -252 -254 -256 -258 -260 -262 -264 -266 -268 -271 -27311212Total Ancillary Services Required -139 -136 -137 -128 -129 -131 -136 -137 -138 -139 -141 -142 -143 -139 -139 -140 -140 -140 -140 -14011313Reserve & Contingency Availability 13 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 114 14 Demand Response 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 015Total Reserve Planning -359 -366 -369 -362 -366 -369 -376 -379 -382 -386 -389 -392 -395 -393 -396 -398 -400 -403 -406 -408 16 Peak Position w/ Contingency 17 -64 -84 126 110 56 -42 -64 -81 -92 -117 -135 -145 -445 -462 -472 -497 -515 -525 -551 17 Implied Planning Margin 21%17%16%29%28%25%19%18%17%17%15%14%14%-2%-3%-4%-5%-6%-6%-7% 121 18 NPCC Market Adjustment 0 64 84 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 19 Peak Position Net Market 17 0 0 126 110 56 (42)(64)(81)(92)(117)(135)(145)(445)(462)(472)(497)(515)(525)(551) Load & Resources Annual Summary Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 2, p. 1 of 3 August Peak Position (1 Hour) 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 REQUIREMENTS131Native Load -1,528 -1,546 -1,562 -1,576 -1,589 -1,603 -1,617 -1,630 -1,644 -1,659 -1,673 -1,687 -1,702 -1,716 -1,731 -1,746 -1,761 -1,776 -1,792 -1,807212Firm Power Sales -212 -159 -159 -9 -9 -8 -8 -7 -7 -7 -7 -7 -7 -7 -7 -7 -7 -7 -7 -73Total Requirements -1,740 -1,705 -1,721 -1,585 -1,598 -1,610 -1,624 -1,638 -1,652 -1,666 -1,680 -1,695 -1,709 -1,724 -1,739 -1,753 -1,768 -1,784 -1,799 -1,814 RESOURCES 34 4 Firm Power Purchases 29 29 29 29 29 26 26 26 26 25 25 25 25 25 25 25 25 25 25 25 68 5 Hydro Resources 960 977 921 887 894 838 835 878 880 878 878 880 878 878 880 878 878 880 878 878 87 6 Base Load Thermals 785 785 785 785 785 785 785 785 785 785 785 785 785 556 556 556 556 556 556 556 95 7 Wind Resources 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 106 8 Peaking Units 176 176 176 176 176 176 176 176 176 176 176 176 176 176 176 176 176 176 176 176 9 Total Resources 1,950 1,968 1,912 1,877 1,884 1,826 1,823 1,865 1,867 1,865 1,865 1,867 1,865 1,635 1,637 1,635 1,635 1,637 1,635 1,635 10 PEAK POSITION 210 263 190 292 286 216 199 227 215 199 184 172 156 -89 -102 -119 -134 -147 -164 -180 RESERVE PLANNING11111Planning Margin 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 011212Total Ancillary Services Required -131 -128 -130 -121 -123 -125 -126 -126 -127 -129 -130 -131 -132 -126 -126 -126 -127 -127 -127 -12711313Reserve & Contingency Availability 35 24 24 22 22 22 22 24 24 24 24 24 24 24 24 24 24 24 24 24 114 14 Demand Response 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 15 Total Reserve Planning -96 -104 -106 -99 -101 -103 -104 -102 -103 -104 -105 -107 -108 -102 -102 -102 -102 -103 -103 -103 16 Peak Position w/ Contingency 114 159 85 193 185 113 95 125 112 94 79 65 48 -191 -204 -221 -236 -249 -267 -282 . 17 Implied Planning Margin 14%17%12%20%19%15%14%15%14%13%12%12%11%-4%-4%-5%-6%-7%-8%-9% 121 18 NPCC Market Adjustment 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 19 Peak Position Net Market 114 159 85 193 185 113 95 125 112 94 79 65 48 (191)(204)(221)(236)(249)(267)(282) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 2, p. 2 of 3 January Peak Position (18 Hour) 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 REQUIREMENTS 1 Native Load -1,596 -1,613 -1,629 -1,643 -1,656 -1,669 -1,683 -1,696 -1,710 -1,724 -1,738 -1,752 -1,766 -1,780 -1,794 -1,809 -1,824 -1,838 -1,853 2 Firm Power Sales -211 -158 -158 -8 -8 -6 -6 -6 -6 -6 -6 -6 -6 -6 -6 -6 -6 -6 -63Total Requirements -1,807 -1,771 -1,787 -1,650 -1,663 -1,675 -1,689 -1,702 -1,716 -1,730 -1,744 -1,758 -1,772 -1,786 -1,801 -1,815 -1,830 -1,844 -1,859 RESOURCES4Firm Power Purchases 117 117 117 117 117 116 34 34 33 33 33 33 33 33 33 33 33 33 335Hydro Resources 973 866 867 932 932 896 900 896 896 904 896 896 904 896 896 904 896 896 9046Base Load Thermals 895 895 895 895 895 895 895 895 895 895 895 895 895 617 617 617 617 617 6177Wind Resources 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 08Peaking Units 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242 9 Total Resources 2,227 2,121 2,122 2,187 2,186 2,149 2,071 2,068 2,067 2,074 2,067 2,067 2,074 1,788 1,788 1,796 1,788 1,788 1,796 10 PEAK POSITION 421 350 334 536 523 473 383 365 351 345 323 309 303 2 -13 -19 -42 -57 -64 RESERVE PLANNING 11 Planning Margin -223 -226 -228 -230 -232 -234 -236 -237 -239 -241 -243 -245 -247 -249 -251 -253 -255 -257 -259 12 Total Ancillary Services Required -186 -184 -185 -177 -179 -180 -186 -187 -189 -191 -192 -193 -194 -195 -196 -197 -197 -198 -19913Reserve & Contingency Availability 25 9 9 17 17 16 16 16 16 16 16 16 16 16 16 16 16 16 1614Demand Response 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 015Total Reserve Planning -385 -401 -405 -390 -394 -398 -405 -409 -412 -416 -419 -422 -425 -428 -431 -434 -436 -439 -442 16 Peak Position w/ Contingency 36 -51 -70 146 129 76 -22 -43 -61 -71 -96 -113 -123 -426 -443 -453 -478 -495 -506 17 Implied Planning Margin 25%20%19%33%32%29%24%22%21%21%19%18%18%1%0%0%-1%-2%-3% 18 NPCC Market Adjustment 0 51 70 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 19 Peak Position Net Market 36 0 0 146 129 76 (22)(43)(61)(71)(96)(113)(123)(426)(443)(453)(478)(495)(506) August Peak Position (18 Hour) 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 REQUIREMENTS1Native Load -1,465 -1,482 -1,498 -1,510 -1,523 -1,536 -1,550 -1,563 -1,576 -1,590 -1,604 -1,618 -1,631 -1,646 -1,660 -1,674 -1,689 -1,703 -1,7182Firm Power Sales -212 -159 -159 -9 -9 -8 -8 -7 -7 -7 -7 -7 -7 -7 -7 -7 -7 -7 -73Total Requirements -1,677 -1,641 -1,657 -1,519 -1,532 -1,544 -1,557 -1,570 -1,584 -1,597 -1,611 -1,625 -1,639 -1,653 -1,667 -1,681 -1,696 -1,710 -1,725 RESOURCES4Firm Power Purchases 29 29 29 29 29 26 26 26 26 25 25 25 25 25 25 25 25 25 25 5 Hydro Resources 701 707 663 631 638 583 580 622 624 622 622 624 622 622 624 622 622 624 622 6 Base Load Thermals 785 785 785 785 785 785 785 785 785 785 785 785 785 556 556 556 556 556 556 7 Wind Resources 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 8 Peaking Units 176 176 176 176 176 176 176 176 176 176 176 176 176 176 176 176 176 176 1769Total Resources 1,691 1,698 1,653 1,621 1,628 1,571 1,568 1,609 1,611 1,609 1,609 1,611 1,609 1,379 1,381 1,379 1,379 1,381 1,379 10 PEAK POSITION 14 57 -3 102 96 27 11 39 27 11 -2 -14 -30 -274 -286 -302 -317 -330 -346 RESERVE PLANNING11Planning Margin 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 012Total Ancillary Services Required -177 -176 -177 -170 -172 -173 -175 -176 -177 -179 -180 -181 -182 -166 -167 -167 -168 -169 -16913Reserve & Contingency Availability 177 176 177 170 172 173 175 176 177 179 180 181 182 166 167 167 168 169 16914Demand Response 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 015Total Reserve Planning 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 16 Peak Position w/ Contingency 14 57 -3 102 96 27 11 39 27 11 -2 -14 -30 -274 -286 -302 -317 -330 -346 17 Implied Planning Margin 11%14%10%18%17%13%12%14%13%12%11%10%9%-7%-7%-8%-9%-9%-10% 18 NPCC Market Adjustment 0 0 3 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 19 Peak Position Net Market 14 57 0 102 96 27 11 39 27 11 (2)(14)(30)(274)(286)(302)(317)(330)(346) Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 2, p. 3 of 3 CONFIDENTIAL subject to Attorney’s Certificate of Confidentiality Avista Utilities Energy Resources Risk Policy Pages 1 through 33 Exhibit No. 4 Case No. AVU-E-15-05 S. Kinney, Avista Schedule 3, p. 1 of 33