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HomeMy WebLinkAbout20160901Avista 2016 IRP Appendices.pdf 2016 Natural Gas Integrated Resource Plan Appendices August 31, 2016 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 risks, uncertainties and other 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. 2016 Natural Gas IRP Appendices TABLE OF CONTENTS: APPENDICES Appendix 0.1 TAC Member List ............................................................................. Page 1 0.2 Comments and Responses to the 2014 IRP ............................................. 2 Appendix 1.1 Avista Corporation 2014 Natural Gas IRP Work Plan ................................ 4 1.2 IRP Guideline Compliance Summaries ..................................................... 7 Appendix 2.1 Economic Outlook and Customer Count Forecast ................................... 22 2.2 Customer Forecasts by Region ............................................................... 39 2.3 Demand Coefficient Calculations ............................................................ 69 2.4 Heating Degree Day Data ....................................................................... 75 2.5 Demand Sensitivities and Demand Scenarios ......................................... 80 2.6 Demand Forecast Sensitivities and Scenarios Descriptions .................... 82 2.7 Annual Demand, Avg Day Demand & Peak Day Demand (Net of DSM) . 85 2.8 Demand Before and After DSM ............................................................... 89 2.9 Detailed Demand Data ............................................................................ 93 Appendix 3.1 Avista Gas CPA Report Final 4/23/2014 ............................................... 103 3.2 Environmental Externalities ................................................................... 164 Appendix 4.1 Current Transportation/Storage Rates and Assumptions ...................... 167 4.2 Alternate Supply Scenarios ................................................................... 168 Appendix 5.1 Monthly Price Data by Basin ................................................................. 169 5.2 Weighted Average Cost of Capital ........................................................ 175 5.3 Supply Side Resource Options ............................................................. 176 5.4 Avoided Costs Detail ............................................................................. 177 Appendix 6.1 High Case Demand and Resources Selected Graphs ........................... 192 6.2 Other Scenario Peak Day Demand Table ............................................. 194 Appendix 7.1 Distribution System Modeling ............................................................... 198 7.2 Oregon Capital Projects ........................................................................ 202 Appendix 8.1 TAC Meeting #1 ................................................................................ 214 8.2 TAC Meeting #2 ................................................................................ 299 8.3 TAC Meeting #3 ................................................................................ 396 8.4 TAC Meeting #4 ................................................................................ 533 APPENDIX - CHAPTER 0 APPENDIX 0.1: TAC MEMBER LIST ORGANIZATION REPRESENTATIVES Applied Energy Group Bridget Kester Avista Terrence Browne Mike Dillon Leslie Filer Ryan Finesilver Grant Forsyth James Gall Alison Kenyon John Lyons David Machado Joe Miller Jody Morehouse Tom Pardee Karen Schuh Kaylene Schultz Eric Scott Kerry Shroy Debbie Simock Erik Soreng Cascade Natural Gas Company Chris Robbins Brian Robertson Mark Sellers- Vaughn Idaho Public Utility Commission Johanna Bell Terri Carlock Stacey Donohue Matt Elam Kevin Keyt Rick Sterling Northwest Gas Association Dan Kirschner Connor Reiten Northwest Industrial Gas Users Ed Finklea Chad Stokes Northwest Natural Gas Ryan Bracken Tammy Linver Steve Storm Oregon Citizens Utility Board Nadine Hanhan Jaime McGovern Oregon Public Utility Commission Erik Colville Lisa Gorsuch Max St. Brown Puget Sound Energy Kacee Chandler TransCanada Jay Story David White Washington Utilities and Transportation Commission Chris McGuire Williams Northwest Pipeline Mike Rasmuson Ray Warner Avista Corp 2016 Natural Gas IRP Appendices 1 APPENDIX - CHAPTER 0 APPENDIX 0.2: COMMENTS AND RESPONSES TO 2016 DRAFT INTEGRATED RESOURCE PLAN The following table summarizes the significant comments on our DRAFT as submitted by TAC members and Avista’s responses. These comments are those not directly incorporated into the primary document. The planning environment in this IRP cycle was especially challenging given some of the most challenging economic volatility seen in decades coupled with industry changing dynamics in natural gas production. We continued our robust, flexible demand forecasting methodology that captured a broad range of demand forecasts fully vetted with our TAC. This IRP produced reduced forecasted demand scenarios and no near term resource needs even in our most robust demand scenario. We appreciate the time and effort invested by all our TAC members throughout the IRP process. Many good suggestions have been made and we have incorporated those that enhance the document. Document Reference[1] Comment/Question Avista Response 4 – SUPPLY SIDE RESOURCES Page 13, first paragraph – The peak day is listed in Table 2 Executive Summary as being 362,000 Dth/day. Suggest adding text describing why Jackson Prairie deliverability of 492,232 Dth/day (398,667 plus the additional 95,565) is considerably greater than the peak day. Avista has the ability to withdraw 401,290 from Jackson Prairie. 398,667 is Avista's owned storage capacity withdrawal amount. 95,565 is Avista's leased capacity from NWP with 2,623 of withdrawal. This does not represent the take away or transportation capacity from the facility to Avista's service territories. Please also refer to comment above. In order for Avista to maintain it's 1/3 ownership of Jackson Prairie the agreement has the three partners (Northwest Pipeline, Puget Sound Energy and Avista) and each will bear 1/3 of the operating costs as well as obtain 1/3 of the storage capacity both future and current. 6 – Alternate Scenarios, Portfolios and Stochastic Analysis A problem from Avista’s 2014 IRP remains in this draft 2016 IRP. While this problem will remedy itself in the future when a resource deficiency is found, Staff is concerned the integrity of past IRP analyses will be impugned when the problem is remedied. To avoid that result, Staff again suggests the portfolio evaluation/analysis and selection process description be revised to eliminate that problem The Sendout model was loaded with the list of potential resources found in Chapter 6 Scenarios, Portfolios, Stochastic Analysis. The model would choose a different resource if given the opportunity to provide demand at lowest cost. If a new resource had been chosen a separate portfolio would have been created to compare the ability to serve demand via less cost and comparing against a total PVRR. Alternate scenarios have been added to Chapter 6 to address this concern with accompanying text to explain the logic Avista Corp 2016 Natural Gas IRP Appendices 2 APPENDIX - CHAPTER 0 6 – Alternate Scenarios, Portfolios and Stochastic Analysis The upsized compressor and increased operating pressure selected by the model are not mentioned in Chapter 7 Distribution Planning. This is a compressor on the GTN pipeline not internal distribution as a fix to push more gas down the Medford Lateral from the GTN mainline. 7 – ALTERNATE SCENARIOS 1. Expand the text to comply with Order No. 16-109 in Docket UG 288, in which the Commission provided its expectations related to justification of distribution system projects, as follows: “Finally, as part of the IRP-vetting process and subsequent rate proceedings, we expect that Avista conduct and present comprehensive analyses of its system upgrades. Such analyses should provide: (1) a comprehensive cost-benefit analysis of whether and when the investment should be built; (2) evaluation of a range of alternative build dates and the impact on reliability and customer rates; (3) credible evidence on the likelihood of disruptions based on historical experience; (4) evidence on the range of possible reliability incidents; (5) evidence about projected loads and customers in the area; and (6) adequate consideration of alternatives, including the use of interruptibility or increased demand- side measures to improve reliability and system resiliency.” The distribution planning section of the IRP contains only a subset of all capital investment in Avista’s gas distribution systems. This is a planning document and the distribution projects included are projects that are planned over a relatively longer time horizon. Other capital investments may be driven by regulation, system maintenance, leak repair, franchise/right-of-way agreements, etc. These investments are not addressed in this section. 7 – DISTRIBUTION PLANNING Page 8 Table 7.2 – suggest adding text to communicate that “Cost” is a planning level value that will likely change as the projects approach the time of implementation. Also suggest that estimating contingencies be included in derivation of the “Cost” to minimize instances where the values need to be revised. In addition to estimating contingencies, suggest adding text to discuss the sensitivity of distribution system project evaluation to changes in “Cost.” “These projects are preliminary estimates of timing and costs of City Gate Station Upgrades…” Because all of the Gate Station projects are scheduled for 2019+ and have no cost assigned, contingencies to cost cannot be included. 8 – ACTION PLAN 2. Page 1, 2015-2016 Action Plan Review – the two Action Items listed were not Action Items but rather were ongoing activities. Please correct the text. Action items addressed in 2015-2016 Action Plan Review are taken directly from the final Natural Gas IRP document filed in each commission on August 29, 2016. These actions are called out so Avista prefers to address them as actions. Avista Corp 2016 Natural Gas IRP Appendices 3 APPENDIX - CHAPTER 1 APPENDIX 1.1: AVISTA CORPORATION 2016 NATURAL GAS INTEGRATED RESOURCE PLAN WORK PLAN IRP WORK PLAN REQUIREMENTS Section 480-90-238 (4), of the natural gas Integrated Resource Plan (“IRP”) rules, specify requirements for the IRP Work Plan: Not later than twelve months prior to the due date of a plan, the utility must provide a work plan for informal commission review. The work plan must outline the content of the integrated resource plan to be developed by the utility and the method for assessing potential resources. Additionally, Section 480-90-238 (5) of the WAC states: The work plan must outline the timing and extent of public participation. OVERVIEW This Work Plan outlines the process Avista will follow to complete its 2016 Natural Gas IRP by August 31, 2016. Avista uses a public process to obtain technical expertise and guidance throughout the planning period via Technical Advisory Committee (TAC) meetings. The TAC will be providing input into assumptions, scenarios, and modeling techniques. PROCESS The 2016 IRP process will be similar to that used to produce the previously published plan. Avista will use SENDOUT® (a PC based linear programming model widely used to solve natural gas supply and transportation optimization questions) to develop the risk adjusted least-cost resource mix for the 20 year planning period. This plan will continue to include demand analysis, demand side management and avoided cost determination, existing and potential supply-side resource analysis, resource integration and alternative sensitivities and scenario analysis. Additionally, Avista intends to incorporate action plan items identified in the 2018 Natural Gas IRP including more detailed demand analysis regarding use per customer, demand side management results and possible price elastic responses to evolving economic conditions, an updated assessment of conservation potential in our service territories, consideration of alternate forecasting methodologies, and the changing landscape of natural gas supply (i.e. shale gas, Canadian exports, and US LNG exports) and its implications to the planning process. Further details about Avista’s process for determining the risk adjusted least-cost resource mix is shown in Exhibit 1. Avista Corp 2016 Natural Gas IRP Appendices 4 APPENDIX - CHAPTER 1 TIMELINE The following is Avista’s TENTATIVE 2018 Natural Gas IRP timeline: subject to change Avista Corp 2016 Natural Gas IRP Appendices 5 APPENDIX - CHAPTER 1 EXHIBIT 1: AVISTA’S 2018 NATURAL GAS IRP MODELING PROCESS Demand Forecast by Area and Class Customer counts Use per customer Elasticity Basis differential Volatility Seasonal Spreads Costs Operational Characteristics  Assess DSM resource options Integrate DSM in resource portfolio 20-year NOAA average by area plus SENDOUT® Optimization Run Identify when and where deficiencies occur in the 20- Enter all Future Resource Options: Demand-Side Supply-Side Optimization Run Solve for deficiencies and incorporate those into the least costs resource mix for Determine Base Case Scenario Avoided Cost Determination Compile Data and Write the IRP Document. Key Considerations Resource Cost Peak vs. Base Load Lead Time Requirements Resource Usefulness “Lumpiness” of Resource Options Analysis Customer Counts Use per customer DSM Monte Carlo Etc. Price Curve Analysis Gate Station Analysis Planning Standard Review Avista Corp 2016 Natural Gas IRP Appendices 6 APPENDIX - CHAPTER 1 APPENDIX 1.2: WASHINGTON PUBLIC UTILITY COMMISSION IRP POLICIES AND GUIDELINES – WAC 480-90-238 Rule Requirement Plan Citation WAC 480-90-238(4) Work plan filed no later than 12 months before next IRP due date. Work plan submitted to the WUTC on August 31, 2015, See attachment to this Appendix 1.1. WAC 480-90-238(4) Work plan outlines content of IRP. See work plan attached to this Appendix 0.1. WAC 480-90-238(4) Work plan outlines method for assessing potential resources. (See LRC analysis below) See Appendix 1.1. WAC 480-90-238(5) Work plan outlines timing and extent of public participation. See Appendix 1.1. WAC 480-90-238(4) Integrated resource plan submitted within two years of previous plan. Last Integrated Resource Plan was submitted on August 31, 2014 WAC 480-90-238(5) Commission issues notice of public hearing after company files plan for review. TBD WAC 480-90-238(5) Commission holds public hearing. TBD WAC 480-90-238(2)(a) Plan describes mix of natural gas supply resources. See Chapter 4 on Supply Side Resources WAC 480-90-238(2)(a) Plan describes conservation supply. See Chapter 3 on Demand Side Resources WAC 480-90-238(2)(a) Plan addresses supply in terms of current and future needs of utility and ratepayers. See Chapter 4 on Supply Side Resources and Chapter 5 Integrated Resource Portfolio WAC 480-90- 238(2)(a)&(b) Plan uses lowest reasonable cost (LRC) analysis to select mix of resources. See Chapters 3 and 4 for Demand and Supply Side Resources. Chapters 5 and 6 details how Demand and Supply come together to select the least cost/best risk portfolio for ratepayers. WAC 480-90-238(2)(b) LRC analysis considers resource costs. See Chapters 3 and 4 for Demand and Supply Side Resources. Chapters 5 and 6 details how Demand and Supply come together to select the least cost/best risk portfolio for ratepayers. WAC 480-90-238(2)(b) LRC analysis considers market- volatility risks. See Chapter 4 on Supply Side Resources WAC 480-90-238(2)(b) LRC analysis considers demand side uncertainties. See Chapter 2 Demand Forecasting WAC 480-90-238(2)(b) LRC analysis considers resource effect on system operation. See Chapter 4 and Chapter 5 WAC 480-90-238(2)(b) LRC analysis considers risks imposed on ratepayers. See Chapter 4 procurement plan section. We seek to minimize but cannot eliminate price risk for our customers. WAC 480-90-238(2)(b) LRC analysis considers public policies regarding resource preference See Chapter 2 demand scenarios Avista Corp 2016 Natural Gas IRP Appendices 7 APPENDIX - CHAPTER 1 adopted by Washington state or federal government. WAC 480-90-238(2)(b) LRC analysis considers cost of risks associated with environmental effects including emissions of carbon dioxide. See Chapters 2 and 5 on demand scenarios and Integrated Resource Portfolio WAC 480-90-238(2)(b) LRC analysis considers need for security of supply. See Chapter 4 on Supply Side Resources Rule Requirement Plan Citation WAC 480-90-238(2)(c) Plan defines conservation as any reduction in natural gas consumption that results from increases in the efficiency of energy use or distribution. See Chapter 3 on Demand Side Resources WAC 480-90-238(3)(a) Plan includes a range of forecasts of future demand. See Chapter 2 on Demand Forecast WAC 480-90-238(3)(a) Plan develops forecasts using methods that examine the effect of economic forces on the consumption of natural gas. See Chapter 2 on Demand Forecast WAC 480-90-238(3)(a) Plan develops forecasts using methods that address changes in the number, type and efficiency of natural gas end-uses. See Chapter 2 on Demand Forecast WAC 480-90-238(3)(b) Plan includes an assessment of commercially available conservation, including load management. See Chapter 3 on Demand Side Management including demand response section. WAC 480-90-238(3)(b) Plan includes an assessment of currently employed and new policies and programs needed to obtain the conservation improvements. See Chapter 3 and Appendix 3.1. WAC 480-90-238(3)(c) Plan includes an assessment of conventional and commercially available nonconventional gas supplies. See Chapter 4 on Supply Side Resources WAC 480-90-238(3)(d) Plan includes an assessment of opportunities for using company- owned or contracted storage. See Chapter 4 on Supply Side Resources WAC 480-90-238(3)(e) Plan includes an assessment of pipeline transmission capability and reliability and opportunities for additional pipeline transmission resources. See Chapter 4 on Supply Side Resources WAC 480-90-238(3)(f) Plan includes a comparative evaluation of the cost of natural gas purchasing strategies, storage options, delivery resources, and improvements in conservation using a consistent method to calculate cost-effectiveness. See Chapter 3 on Demand Side Resources and Chapter 4 on Supply Side Resources WAC 480-90-238(3)(g) Plan includes at least a 10 year long- range planning horizon. Our plan is a comprehensive 20 year plan. WAC 480-90-238(3)(g) Demand forecasts and resource evaluations are integrated into the long range plan for resource acquisition. Chapter 5 Integrated Resource Portfolio details how demand and supply come together to form the least cost/best risk portfolio. WAC 480-90-238(3)(h) Plan includes a two-year action plan that implements the long range plan. See Section 8 Action Plan Avista Corp 2016 Natural Gas IRP Appendices 8 APPENDIX - CHAPTER 1 WAC 480-90-238(3)(i) Plan includes a progress report on the implementation of the previously filed plan. See Section 8 Action Plan WAC 480-90-238(5) Plan includes description of consultation with commission staff. (Description not required) See Section 0 Introduction WAC 480-90-238(5) Plan includes description of completion of work plan. (Description not required) See Appendix 1.1. Avista Corp 2016 Natural Gas IRP Appendices 9 APPENDIX - CHAPTER 1 APPENDIX 1.2: IDAHO PUBLIC UTILITY COMMISSION IRP POLICIES AND GUIDELINES – ORDER NO. 2534 DESCRIPTION OF REQUIREMENT FULLFILLMENT OF REQUIREMENT 1 Purpose and Process. Each gas utility regulated by the Idaho Public Utilities Commission with retail sales of more than 10,000,000,000 cubic feet in a calendar year (except gas utilities doing business in Idaho that are regulated by contract with a regulatory commission of another State) has the responsibility to meet system demand at least cost to the utility and its ratepayers. Therefore, an ‘‘integrated resource plan’’ shall be developed by each gas utility subject to this rule. Avista prepares a comprehensive 20 year Integrated Resource Plan every two years. Avista will be filing its 2016 IRP on or before August 31, 2016. 2 Definition. Integrated resource planning. ‘‘Integrated resource planning’’ means planning by the use of any standard, regulation, practice, or policy to undertake a systematic comparison between demand-side management measures and the supply of gas by a gas utility to minimize life- cycle costs of adequate and reliable utility services to gas customers. Integrated resource planning shall take into account necessary features for system operation such as diversity, reliability, dispatchability, and other factors of risk and shall treat demand and supply to gas consumers on a consistent and integrated basis. Avista's IRP brings together dynamic demand forecasts and matches them against demand-side and supply-side resources in order to evaluate the least cost/best risk portfolio for its core customers. While the primary focus has been to ensure customer's needs are met under peak or design weather conditions, this process also evaluates the resource portfolio under normal/average operating conditions. The IRP provides the framework and methodology for evaluating Avista's natural gas demand and resources. 3 Elements of Plan. Each gas utility shall submit to the Commission on a biennial basis an integrated resource plan that shall include: 2016 IRP to be filed on or before August 31, 2016. The last IRP was filed on August 31, 2014. A range of forecasts of future gas demand in firm and interruptible markets for each customer class for one, five, and twenty years using methods that examine the effect of economic forces on the consumption of gas and that address changes in the number, type and efficiency of gas end-uses. See Chapter 2 - Demand Forecasts and Appendix 2 et.al. for a detailed discussion of how demand was forecasted for this IRP. An assessment for each customer class of the technically feasible improvements in the efficient use of gas, including load management, as well as the policies and programs needed to obtain the efficiency improvements. See Chapter 3 - Demand Side Management and DSM Appendices 3 et.al. for detailed information on the DSM potential evaluated and selected for this IRP and the operational implementation process. Avista Corp 2016 Natural Gas IRP Appendices 10 APPENDIX - CHAPTER 1 An analysis for each customer class of gas supply options, including: (1) a projection of spot market versus long-term purchases for both firm and interruptible markets; (2) an evaluation of the opportunities for using company-owned or contracted storage or production; (3) an analysis of prospects for company participation in a gas futures market; and (4) an assessment of opportunities for access to multiple pipeline suppliers or direct purchases from producers. See Chapter 4 - Supply-Side Resources for details about the market, storage, and pipeline transportation as well as other resource options considered in this IRP. See also the procurement plan section in this same chapter for supply procurement strategies. A comparative evaluation of gas purchasing options and improvements in the efficient use of gas based on a consistent method for calculating cost-effectiveness. See Methodology section of Chapter 3 - Demand-Side Resources where we describe our process on how demand-side and supply-side resources are compared on par with each other in the SENDOUT® model. Chapter 3 also includes how results from the IRP are then utilized to create operational business plans. Operational implementation may differ from IRP results due to modeling assumptions. The integration of the demand forecast and resource evaluations into a long-range (e.g., twenty-year) integrated resource plan describing the strategies designed to meet current and future needs at the lowest cost to the utility and its ratepayers. See Chapter 5 - Integrated Resource Portfolio for details on how we model demand and supply coming together to provide the least cost/best risk portfolio of resources. A short-term (e.g., two-year) plan outlining the specific actions to be taken by the utility in implementing the integrated resource plan. See Chapter 8 - Action Plan for actions to be taken in implementing the IRP. 4 Relationship Between Plans. All plans following the initial integrated resource plan shall include a progress report that relates the new plan to the previously filed plan. Avista strives to meet at least bi-annually with Staff and/or Commissioners to discuss the state of the market, procurement planning practices, and any other issues that may impact resource needs or other analysis within the IRP. 5 Plans to Be Considered in Rate Cases. The integrated resource plan will be considered with other available information to evaluate the performance of the utility in rate proceedings before the Commission. We prepare and file our plan in part to establish a public record of our plan. 6 Public Participation. In formulating its plan, the gas utility must provide an opportunity for public participation and comment and must provide methods that will be available to the public of validating predicted performance. Avista held four Technical Advisory Committee meetings beginning in January and ending in April. See Chapter 0 - Introduction for more detail about public participation in the IRP process. Avista Corp 2016 Natural Gas IRP Appendices 11 APPENDIX - CHAPTER 1 7 Legal Effect of Plan. The plan constitutes the base line against which the utility's performance will ordinarily be measured. The requirement for implementation of a plan does not mean that the plan must be followed without deviation. The requirement of implementation of a plan means that a gas utility, having made an integrated resource plan to provide adequate and reliable service to its gas customers at the lowest system cost, may and should deviate from that plan when presented with responsible, reliable opportunities to further lower its planned system cost not anticipated or identified in existing or earlier plans and not undermining the utility's reliability. See section titled "Avista's Procurement Plan" in Chapter 4 - Supply-Side Resources. Among other details we discuss plan revisions in response to changing market conditions. In order to encourage prudent planning and prudent deviation from past planning when presented with opportunities for improving upon a plan, a gas utility's plan must be on file with the Commission and available for public inspection. But the filing of a plan does not constitute approval or disapproval of the plan having the force and effect of law, and deviation from the plan would not constitute violation of the Commission's Orders or rules. The prudence of a utility's plan and the utility's prudence in following or not following a plan are matters that may be considered in a general rate proceeding or other proceedings in which those issues have been noticed. See also section titled "Alternate Supply-Side Scenarios" in Chapter 5 - Integrated Resource Portfolio where we discuss different supply portfolios that are responsive to changing assumptions about resource alternatives. Avista Corp 2016 Natural Gas IRP Appendices 12 APPENDIX - CHAPTER 1 APPENDIX 1.2: OREGON PUBLIC UTILITY COMMISSION IRP STANDARD AND GUIDELINES – ORDER 07- 002 Guideline 1: Substantive Requirements 1.a.1 All resources must be evaluated on a consistent and comparable basis. All resource options considered, including demand- side and supply-side are modeled in SENDOUT® utilizing the same common general assumptions, approach and methodology. 1.a.2 All known resources for meeting the utility’s load should be considered, including supply-side options which focus on the generation, purchase and transmission of power – or gas purchases, transportation, and storage – and demand-side options which focus on conservation and demand response. Avista considered a range of resources including demand-side management, distribution system enhancements, capacity release recalls, interstate pipeline transportation, interruptible customer supply, and storage options including liquefied natural gas. Chapter 3 and Appendix 3.1 documents Avista’s demand-side management resources considered. Chapter 4 and Appendix 5.3 documents supply-side resources. Chapter 5 and 6 documents how Avista developed and assessed each of these resources. 1.a.3 Utilities should compare different resource fuel types, technologies, lead times, in-service dates, durations and locations in portfolio risk modeling. Avista considered various combinations of technologies, lead times, in-service dates, durations, and locations. Chapter 5 provides details about the modeling methodology and results. Chapter 4 describes resource attributes and Appendix 5.3 summarizes the resources’ lead times, in-service dates and locations. 1.a.4 Consistent assumptions and methods should be used for evaluation of all resources. Appendix 5.2 documents general assumptions used in Avista’s SENDOUT® modeling software. All portfolio resources both demand and supply-side were evaluated within SENDOUT® using the same sets of inputs. 1.a.5 The after-tax marginal weighted- average cost of capital (WACC) should be used to discount all future resource costs. Avista applied its after-tax WACC of 4.34% to discount all future resource costs. (See general assumptions at Appendix 5.2) 1.b.1 Risk and uncertainty must be considered. Electric utilities only Not Applicable 1.b.2 Risk and uncertainty must be considered. Natural gas utilities should consider demand (peak, swing and base-load), commodity supply and price, transportation availability and price, and costs to comply with any regulation of greenhouse gas (GHG) emissions. Risk and uncertainty are key considerations in long term planning. In order to address risk and uncertainties a wide range of sensitivity, scenario and portfolio analysis is completed. A description of risk associated with each scenario is included in Appendix 2.6. One of the key risks is the “flat demand” risk as described in Chapter 1. Avista performed 15 sensitivities on demand. From there five demand scenarios were developed (Table 1.1) for SENDOUT® modeling purposes. Monthly demand coefficients were developed for base, heating demand while peak demand was contemplated through modeling a weather planning standard of the coldest day on record (see heating degree day data in Appendix 2.4). Avista Corp 2016 Natural Gas IRP Appendices 13 APPENDIX - CHAPTER 1 Avista evaluated several price forecasts and selected high, medium and low price scenarios for modeling purposes. The annual average prices are then weighted by month using fundamental forecast data. Additionally, the Henry Hub price forecasts are basis adjusted using the same fundamental forecast data. Four supply scenarios were also evaluated, see Table 4.3. These supply scenarios were combined with demand scenarios in order to establish portfolios for evaluation. Ultimately 9 portfolios were evaluated (See Table 6.3 for the PVRR results). Avista stochastic modeling techniques for price and weather variables to analyze weather sensitivity and to quantify the risk to customers under varying price environments. While there continues to be some uncertainty around GHG emission, Avista considered GHG emissions regulatory compliance costs in Appendix 3.2. As currently modeled, we include a carbon adder to our price curve to capture the costs of emission regulation. Utilities should identify in their plans any additional sources of risk and uncertainty. Avista evaluated additional risks and uncertainties. Risks associated with the planning environment are detailed in Chapter 0 Introduction. Avista also analyzed demand risk which is detailed in Chapter 2. Chapter 3 discusses the uncertainty around how much DSM is achievable. Supply-side resource risks are discussed in Chapter 4. Chapter 5 and 6 discusses the variables modeled for scenario and stochastic risk analysis. 1c The primary goal must be the selection of a portfolio of resources with the best combination of expected costs and associated risks and uncertainties for the utility and its customers. Avista evaluated cost/risk tradeoffs for each of the risk analysis portfolios considered. See Chapter 5 and 6 plus supporting information in Appendix 2.6 for Avista’s portfolio risk analysis and determination of the preferred portfolio. The planning horizon for analyzing resource choices should be at least 20 years and account for end effects. Utilities should consider all costs with a reasonable likelihood of being included in rates over the long term, which extends beyond the planning horizon and the life of the resource. Avista used a 20-year study period for portfolio modeling. Avista contemplated possible costs beyond the planning period that could affect rates including end effects such as infrastructure decommission costs and concluded there were no significant costs reasonably likely to impact rates under different resource selection scenarios. Utilities should use present value of revenue requirement (PVRR) as the key cost metric. The plan should include analysis of current and estimated future costs of all long- lived resources such as power plants, gas storage facilities and pipelines, as well as all short-lived Avista’s SENDOUT® modeling software utilizes a PVRR cost metric methodology applied to both long and short-lived resources. Avista Corp 2016 Natural Gas IRP Appendices 14 APPENDIX - CHAPTER 1 resources such as gas supply and short-term power purchases. To address risk, the plan should include at a minimum: 1) Two measures of PVRR risk: one that measures the variability of costs and one that measures the severity of bad outcomes. 2) Discussion of the proposed use and impact on costs and risks of physical and financial hedging. Avista, through its stochastic analysis, modeled 200 scenarios around varying gas price inputs via Monte Carlo iterations developing a distribution of Total 20 year cost estimates utilizing SENDOUT®’s PVRR methodology. Chapter 6 further describes this analysis. The variability of costs is plotted against the Expected Case while the scenarios beyond the 95th percentile capture the severity of outcomes. Chapter 4 discusses Avista’s physical and financial hedging methodology. The utility should explain in its plan how its resource choices appropriately balance cost and risk. Chapter 4, 5, and 6 describe various specific resource considerations and related risks, and describes what criteria we used to determine what resource combinations provide an appropriate balance between cost and risk. 1d The plan must be consistent with the long-run public interest as expressed in Oregon and federal energy policies. Avista considered current and expected state and federal energy policies in portfolio modeling. Chapter 5 describes the decision process used to derive portfolios, which includes consideration of state resource policy directions. Guideline 2: Procedural Requirements 2a The public, including other utilities, should be allowed significant involvement in the preparation of the IRP. Involvement includes opportunities to contribute information and ideas, as well as to receive information. Parties must have an opportunity to make relevant inquiries of the utility formulating the plan. Chapter 0 provides an overview of the public process and documents the details on public meetings held for the 2016 IRP. Avista encourages participation in the development of the plan, as each party brings a unique perspective and the ability to exchange information and ideas makes for a more robust plan. While confidential information must be protected, the utility should make public, in its plan, any non- confidential information that is relevant to its resource evaluation and action plan. The entire IRP, as well as the TAC process, includes all of the non-confidential information the company used for portfolio evaluation and selection. Avista also provided stakeholders with non-confidential information to support public meeting discussions via email. The document and appendices will be available on the company website for viewing. The utility must provide a draft IRP for public review and comment prior to filing a final plan with the Commission. Avista distributed a draft IRP document for external review to all TAC members on May 27, 2016 and requested comments by June 30, 2016. Guideline 3: Plan Filing, Review and Updates 3a Utility must file an IRP within two years of its previous IRP acknowledgement order. This Plan complies with this requirement as the 2014 Natural Gas IRP was acknowledged on March 2, 2015. 3b Utility must present the results of its filed plan to the Commission at a public meeting prior to the deadline for written public comment. Avista will work with Staff to fulfill this guideline following filing of the IRP. 3c Commission staff and parties should complete their comments and Pending Avista Corp 2016 Natural Gas IRP Appendices 15 APPENDIX - CHAPTER 1 recommendations within six months of IRP filing 3d The Commission will consider comments and recommendations on a utility’s plan at a public meeting before issuing an order on acknowledgment. The Commission may provide the utility an opportunity to revise the plan before issuing an acknowledgment order Pending 3e The Commission may provide direction to a utility regarding any additional analyses or actions that the utility should undertake in its next IRP. Pending 3f Each utility must submit an annual update on its most recently acknowledged plan. The update is due on or before the acknowledgment order anniversary date. Once a utility anticipates a significant deviation from its acknowledged IRP, it must file an update with the Commission, unless the utility is within six months of filing its next IRP. The utility must summarize the update at a Commission public meeting. The utility may request acknowledgment of changes in proposed actions identified in an update The annual update was submitted on March 1, 2016. The filing was primarily an informational filing only as Avista intends to file an updated IRP by August 31, 2016. In addition to the filing, Avista has provided updates and comparisons to its 2014 IRP during its 2016 IRP TAC meetings held on January 21, 2016, February 18, 2016, March 30, 2016, and April 21, 2016, in which Commission Staff and other TAC members were present. In addition the Company provided an update during its Natural Gas Quarterly update meeting held on March 3, 2016. No request for acknowledgement was required as no significant deviation from the 2014 IRP was anticipated. 3g Unless the utility requests acknowledgement of changes in proposed actions, the annual update is an informational filing that:  Describes what actions the utility has taken to implement the plan;  Provides an assessment of what has changed since the acknowledgment order that affects the action plan, including changes in such factors as load, expiration of resource contracts, supply-side and demand-side resource acquisitions, resource costs, and transmission availability; and  Justifies any deviations from the acknowledged action plan. The updates described in 3f above explained changes since acknowledgment of the 2014 IRP and an update of emerging planning issues. The updates did not request acknowledgement of any changes. Guideline 4: Plan Components At a minimum, the plan must include the following elements: Avista Corp 2016 Natural Gas IRP Appendices 16 APPENDIX - CHAPTER 1 4a An explanation of how the utility met each of the substantive and procedural requirements. This table summarizes guideline compliance by providing an overview of how Avista met each of the substantive and procedural requirements for a natural gas IRP. 4b Analysis of high and low load growth scenarios in addition to stochastic load risk analysis with an explanation of major assumptions. Avista developed six demand growth forecasts for scenario analysis. Stochastic variability of demand was also captured in the risk analysis. Chapter 1 describes the demand forecast data and Chapter 5 provides the scenario and risk analysis results. Appendix 5 details major assumptions. 4c For electric utilities only Not Applicable 4d A determination of the peaking, swing and base-load gas supply and associated transportation and storage expected for each year of the plan, given existing resources; and identification of gas supplies (peak, swing and base-load), transportation and storage needed to bridge the gap between expected loads and resources. Figures 6, 7, and 8 summarize graphically projected annual peak day demand and the existing and selected resources by year to meet demand for the expected case. Appendix 6.1 and 6.2 summarizes the peak day demand for the other demand scenarios. 4e Identification and estimated costs of all supply-side and demand-side resource options, taking into account anticipated advances in technology Chapter 3 and Appendix 3.1 identify the demand-side potential included in this IRP. Chapter 4 and 5 and Appendix 5.3 identify the supply-side resources. 4f Analysis of measures the utility intends to take to provide reliable service, including cost-risk tradeoffs. Chapter 5, 6, and 7 discusses the modeling tools, customer growth forecasting and cost-risk considerations used to maintain and plan a reliable gas delivery system. These Chapters also capture a summary of the reliability analysis process demonstrated at the second TAC meeting. Chapter 4 discusses the diversified infrastructure and multiple supply basin approach that acts to mitigate certain reliability risks. Appendix 2.6 highlights key risks associated with each portfolio. 4g Identification of key assumptions about the future (e.g. fuel prices and environmental compliance costs) and alternative scenarios considered. Appendix 5 and Chapter 5 describe the key assumptions and alternative scenarios used in this IRP. 4h Construction of a representative set of resource portfolios to test various operating characteristics, resource types, fuels and sources, technologies, lead times, in-service dates, durations and general locations - system-wide or delivered to a specific portion of the system. This Plan documents the development and results for portfolios evaluated in this IRP (see Table 4.3 for supply scenarios considered). 4i Evaluation of the performance of the candidate portfolios over the range of identified risks and uncertainties. We evaluated our candidate portfolio by performing stochastic analysis using SENDOUT® varying price under 200 different scenarios. Additionally, we test the portfolio of options with the use of SENDOUT® under deterministic scenarios where demand and price vary. For resources selected, we assess other risk factors such as varying lead times required and Avista Corp 2016 Natural Gas IRP Appendices 17 APPENDIX - CHAPTER 1 potential for cost overruns outside of the amounts included in the modeling assumptions. 4j Results of testing and rank ordering of the portfolios by cost and risk metric, and interpretation of those results. Avista’s four distinct geographic Oregon service territories limit many resource option synergies which inherently reduces available portfolio options. Feasibility uncertainty, lead time variability and uncertain cost escalation around certain resource options also reduce reasonably viable options. Chapter 4 describes resource options reviewed including discussion on uncertainties in lead times and costs as well as viability and resource availability (e.g. LNG). Appendix 5.3 summarizes the potential resource options identifying investment and variable costs, asset availability and lead time requirements while results of resources selected are identified in Table 5.5 as well as graphically presented in Figure 5.18 and 5.19 for the Expected Case and Appendix 6.1 for the High Growth case. 4k Analysis of the uncertainties associated with each portfolio evaluated See the responses to 1.b above. 4l Selection of a portfolio that represents the best combination of cost and risk for the utility and its customers Avista evaluated cost/risk tradeoffs for each of the risk analysis portfolios considered. Chapter 5 and Appendix 2.6 show the company’s portfolio risk analysis, as well as the process and determination of the preferred portfolio. 4m Identification and explanation of any inconsistencies of the selected portfolio with any state and federal energy policies that may affect a utility's plan and any barriers to implementation This IRP is presumed to have no inconsistencies. 4n An action plan with resource activities the utility intends to undertake over the next two to four years to acquire the identified resources, regardless of whether the activity was acknowledged in a previous IRP, with the key attributes of each resource specified as in portfolio testing. Chapter 8 presents the IRP Action Plan with focus on the following areas:  Modeling  Supply/capacity  Forecasting  Regulatory communication  DSM Guideline 5: Transmission 5 Portfolio analysis should include costs to the utility for the fuel transportation and electric transmission required for each resource being considered. In addition, utilities should consider fuel transportation and electric transmission facilities as resource options, taking into account their value for making additional purchases and sales, accessing less costly resources in remote Not applicable to Avista’s gas utility operations. Avista Corp 2016 Natural Gas IRP Appendices 18 APPENDIX - CHAPTER 1 locations, acquiring alternative fuel supplies, and improving reliability. Guideline 6: Conservation 6a Each utility should ensure that a conservation potential study is conducted periodically for its entire service territory. AEG performed a conservation potential assessment study for our 2016 IRP. A discussion of the study is included in Chapter 3. The full study document is in Appendix 3.1. Avista incorporates a comprehensive assessment of the potential for utility acquisition of energy-efficiency resources into the regularly- scheduled Integrated Resource Planning process. 6b To the extent that a utility controls the level of funding for conservation programs in its service territory, the utility should include in its action plan all best cost/risk portfolio conservation resources for meeting projected resource needs, specifying annual savings targets. A discussion on the treatment of conservation programs is included in Chapter 3 while selection methodology is documented in Chapter 5. The action plan details conservation targets, if any, as developed through the operational business planning process. These targets are updated annually, with the most current avoided costs. Given the challenge of the low cost environment, current operational planning and program evaluation is still underway and targets for Oregon have not yet been set. 6c To the extent that an outside party administers conservation programs in a utility's service territory at a level of funding that is beyond the utility's control, the utility should: 1) determine the amount of conservation resources in the best cost/ risk portfolio without regard to any limits on funding of conservation programs; and 2) identify the preferred portfolio and action plan consistent with the outside party's projection of conservation acquisition. Not applicable. See the response for 5.b above. Guideline 7: Demand Response 7 Plans should evaluate demand response resources, including voluntary rate programs, on par with other options for meeting energy, capacity, and transmission needs (for electric utilities) or gas supply and transportation needs (for natural gas utilities). Avista has periodically evaluated conceptual approaches to meeting capacity constraints using demand-response and similar voluntary programs. Technology, customer characteristics and cost issues are hurdles for developing effective programs. See Chapter 3 Demand Response section for more discussion. Guideline 8: Environmental Costs 8 Utilities should include, in their base-case analyses, the regulatory compliance costs they expect for CO2, NOx, SO2, and Hg emissions. Utilities should analyze the range of potential CO2 regulatory costs in Order No. 93- 695, from $0 - $40 (1990$). In addition, utilities should perform sensitivity analysis on a range of reasonably possible cost adders for NOx, SO2, and Hg, if applicable. Avista’s current direct gas distribution system infrastructure does not result in any CO2, NOx, SO2, or Hg emissions. Upstream gas system infrastructure (pipelines, storage facilities, and gathering systems) do produce CO2 emissions via compressors Avista Corp 2016 Natural Gas IRP Appendices 19 APPENDIX - CHAPTER 1 used to pressurize and move gas throughout the system. The Environmental Externalities discussion in Appendix 3.2 describes our analysis performed. See also the guidelines addendum reflecting revised guidance for environmental costs per Order 08-339. Guideline 9: Direct Access Loads 9 An electric utility's load-resource balance should exclude customer loads that are effectively committed to service by an alternative electricity supplier. Not applicable to Avista’s gas utility operations. Guideline 10: Multi-state utilities 10 Multi-state utilities should plan their generation and transmission systems, or gas supply and delivery, on an integrated-system basis that achieves a best cost/risk portfolio for all their retail customers. The 2014 IRP conforms to the multi-state planning approach. Guideline 11: Reliability 11 Electric utilities should analyze reliability within the risk modeling of the actual portfolios being considered. Loss of load probability, expected planning reserve margin, and expected and worst-case unserved energy should be determined by year for top-performing portfolios. Natural gas utilities should analyze, on an integrated basis, gas supply, transportation, and storage, along with demand-side resources, to reliably meet peak, swing, and base-load system requirements. Electric and natural gas utility plans should demonstrate that the utility’s chosen portfolio achieves its stated reliability, cost and risk objectives. Avista’s storage and transport resources while planned around meeting a peak day planning standard, also provides opportunities to capture off season pricing while providing system flexibility to meet swing and base-load requirements. Diversity in our transport options enables at least dual fuel source options in event of a transport disruption. For areas with only one fuel source option the cost of duplicative infrastructure is not feasible relative to the risk of generally high reliability infrastructure. Guideline 12: Distributed Generation 12 Electric utilities should evaluate distributed generation technologies on par with other supply-side resources and should consider, and quantify where possible, the additional benefits of distributed generation. Not applicable to Avista’s gas utility operations. Guideline 13: Resource Acquisition 13a An electric utility should: identify its proposed acquisition strategy for each resource in its action plan; Assess the advantages and disadvantages of owning a resource instead of purchasing power from another party; identify any Benchmark Resources it plans to consider in competitive bidding. Not applicable to Avista’s gas utility operations. Avista Corp 2016 Natural Gas IRP Appendices 20 APPENDIX - CHAPTER 1 13b Natural gas utilities should either describe in the IRP their bidding practices for gas supply and transportation, or provide a description of those practices following IRP acknowledgment. A discussion of Avista’s procurement practices is detailed in Chapter 4. Guideline 8: Environmental Costs a. BASE CASE AND OTHER COMPLIANCE SCENARIOS: The utility should construct a base-case scenario to reflect what it considers to be the most likely regulatory compliance future for carbon dioxide (CO2), nitrogen oxides, sulfur oxides, and mercury emissions. The utility also should develop several compliance scenarios ranging from the present CO2 regulatory level to the upper reaches of credible proposals by governing entities. Each compliance scenario should include a time profile of CO2 compliance requirements. The utility should identify whether the basis of those requirements, or “costs”, would be CO2 taxes, a ban on certain types of resources, or CO2 caps (with or without flexibility mechanisms such as allowance or credit trading or a safety valve). The analysis should recognize significant and important upstream emissions that would likely have a significant impact on its resource decisions. Each compliance scenario should maintain logical consistency, to the extent practicable, between the CO2 regulatory requirements and other key inputs. Avista’s current direct gas distribution system infrastructure does not result in any CO2, NOx, SO2, or Hg emissions. Upstream gas system infrastructure (pipelines, storage facilities, and gathering systems) do produce CO2 emissions via compressors used to pressurize and move gas throughout the system. The Environmental Externalities discussion in Appendix 3.2 describes our process for addressing these costs. b. TESTING ALTERNATIVE PORTFOLIOS AGAINST THE COMPLIANCE SCENARIOS: The utility should estimate, under each of the compliance scenarios, the present value of revenue requirement (PVRR) costs and risk measures, over at least 20 years, for a set of reasonable alternative portfolios from which the preferred portfolio is selected. The utility should incorporate end- effect considerations in the analyses to allow for comparisons of portfolios containing resources with economic or physical lives that extend beyond the planning period. The utility should also modify projected lifetimes as necessary to be consistent with the compliance scenario under analysis. In addition, the utility should include, if material, sensitivity analyses on a range of reasonably possible regulatory futures for nitrogen oxides, sulfur oxides, and mercury to further inform the preferred portfolio selection. The Environmental Externalities discussion in Appendix 3.2 describes our process for addressing these costs. Avista Corp 2016 Natural Gas IRP Appendices 21 APPENDIX - CHAPTER 2 APPENDIX 2.1: ECONOMIC OUTLOOK AND CUSTOMER COUNT FORECAST I. Service Area Economic Performance and Outlook Avista’s core service area for natural gas includes Eastern Washington, Northern Idaho, and Southwest Oregon. Smaller service islands are also located in rural South-Central Washington and Northeast Oregon. Our service area is dominated by four metropolitan statistical areas (MSAs): the Spokane-Spokane Valley, WA MSA (Spokane- Stevens counties); the Coeur d’Alene, ID MSA (Kootenai County); the Lewiston-Clarkson ID-WA, MSA (Nez Perce- Asotin counties); and the Medford, OR MSA (Jackson County). These four MSAs represent the primary demand for Avista’s natural gas and account for 75% of both customers (i.e., meters) and load. The remaining 25% of customers and load are spread over low density rural areas in all three states. Figure 1: Employment and Population Recovery, December 2007- December 2015 Data source: Employment from the BLS; population from the U.S. Census. In the wake of the Great Recession, our service area recovered more slowly than the U.S. Although the U.S. recession officially ended in June 2009 (dated by the National Bureau of Economic Research), our service area did not start a significant employment recovery until the second half of 2012 (Figure 1, top and bottom graph). -7% -6% -5% -4% -3% -2% -1% 0% 1% 2% 3% 4% De c - 0 7 Ma r - 0 8 Ju n - 0 8 Se p - 0 8 De c - 0 8 Ma r - 0 9 Ju n - 0 9 Se p - 0 9 De c - 0 9 Ma r - 1 0 Ju n - 1 0 Se p - 1 0 De c - 1 0 Ma r - 1 1 Ju n - 1 1 Se p - 1 1 De c - 1 1 Ma r - 1 2 Ju n - 1 2 Se p - 1 2 De c - 1 2 Ma r - 1 3 Ju n - 1 3 Se p - 1 3 De c - 1 3 Ma r - 1 4 Ju n - 1 4 Se p - 1 4 De c - 1 4 Ma r - 1 5 Ju n - 1 5 Se p - 1 5 De c - 1 5 Ye a r -ov e r -Ye a r , S a m e M o n t h S e a s o n a l l y A d j . Non-Farm Employment Growth (Dashed Shaded Box = Recession Period) Avista WA-ID-OR MSAs U.S. 90 92 94 96 98 100 102 104 106 De c - 0 7 Ma r - 0 8 Ju n - 0 8 Se p - 0 8 De c - 0 8 Ma r - 0 9 Ju n - 0 9 Se p - 0 9 De c - 0 9 Ma r - 1 0 Ju n - 1 0 Se p - 1 0 De c - 1 0 Ma r - 1 1 Ju n - 1 1 Se p - 1 1 De c - 1 1 Ma r - 1 2 Ju n - 1 2 Se p - 1 2 De c - 1 2 Ma r - 1 3 Ju n - 1 3 Se p - 1 3 De c - 1 3 Ma r - 1 4 Ju n - 1 4 Se p - 1 4 De c - 1 4 Ma r - 1 5 Ju n - 1 5 Se p - 1 5 De c - 1 5 No n -Fa r m E m p l o y m e n t D e c 2 0 0 7 = 1 0 0 Non-Farm Employment Level (Dashed Shaded Box = Recession Period) Avista WA-ID-OR MSAs U.S. Avista Corp 2016 Natural Gas IRP Appendices 22 APPENDIX - CHAPTER 2 However, by the start of 2015, year-over-year employment growth slightly exceeded U.S. growth and employment levels returned to pre-recession levels. As a result, service area population growth, which is significantly influenced by in-migration through employment opportunities, also improved in 2014 and 2015 (Figure 2). Figure 2: Avista MSA Annual Population Growth, 2005-2015 In 2011, Avista’s MSA population growth fell to around 0.6%, the lowest since the late 1980s, but has increased to around 1% by 2014. This is important because population growth is a significant contributor to overall customer growth. Figure 3 shows that compared to forecasted customer growth in the 2014 IRP, actual average customer growth over the 2014-2015 period has been slightly higher, reflecting stronger than expected service area growth. Given the improving economy and increased population growth, this IRP, compared to the 2014 IRP, shows an upward revision of approximately 5,500 forecasted customers in WA-ID and 7,000 in OR by 2035 (Figure 4). System-wide, this is an upward revision of approximately 12,500 customers. Table 1 shows the change in the customer forecast by class between the 2016 and 2014 IRPs for WA-ID, OR, and system-wide. 1.6%1.7%1.7% 1.3% 1.0% 0.7% 0.6%0.6% 0.8% 1.1% 1.0% 0.0% 0.2% 0.4% 0.6% 0.8% 1.0% 1.2% 1.4% 1.6% 1.8% 2.0% 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 Avista Corp 2016 Natural Gas IRP Appendices 23 APPENDIX - CHAPTER 2 Figure 3: Comparison of 2014-IRP Customer Growth Forecasts to Actuals, 2014-2015 Data source: Company data. Table 1: Change in Forecast between the 2016 IRP and 2014 IRP in 2035 WA-ID +7,394 -1,928 +30 +5,496 OR +6,980 +38 -1 +7,017 System +14,374 -1,890 +29 +12,513 This upward revision in residential customers reflects two factors. First, the recent economic and population recovery has resulted in a higher population forecast, which is a significant forecast driver of residential customer growth. That is, population growth is a proxy for new household formation. Second, the forecast methodology for residential customers has been improved so that growth through retrofitting is better captured. In this context, retrofitting means existing households adding natural gas as an energy source. Therefore, new customers are generated through new households that build-in gas as an energy source and older households retrofitting with gas. This can be seen in Figure 5 (top graph WA-ID; bottom graph OR). Excluding the weak post-recession recovery period (2009-2011), annual residential customer growth exceeds population growth. The convergence of customer and population growth in the 2009-2011 period reflects a decline in retrofitting due to lower 1.11%1.18%1.15%1.15% 1.29%1.22% 0.0% 0.2% 0.4% 0.6% 0.8% 1.0% 1.2% 1.4% 2014 2015 2014-2015 Average WA-ID Forecasted vs. Actual Customer Growth Rates WA-ID 2014 IRP Forecast WA-ID Actual 0.86% 0.78%0.82%0.78% 1.09% 0.94% 0.0% 0.2% 0.4% 0.6% 0.8% 1.0% 1.2% 2014 2015 2014-2015 Average OR Forecasted vs. Actual Customer Growth Rates OR 2014 IRP Forecast OR Actual Avista Corp 2016 Natural Gas IRP Appendices 24 APPENDIX - CHAPTER 2 discretionary spending by households. From 2005 to 2015, the average customer-population growth spread in WA-ID and OR was 0.5%. Figure 4: Comparison IRP Forecasted Customer Growth in WA-ID and OR, 2016-2035 Data source: Company data. Again referring to Table 1, although the improving economic conditions increased the forecast for residential customers, this is not the case for commercial customers in WA-ID. The current modeling approach for the majority of commercial customers assumes that residential customer growth is a driver of commercial customer growth. The use of residential customers as forecast driver for commercial customers reflects the historically high correlation between residential and commercial customer growth rates. However, in the case of WA-ID, the relative ratio of annual (firm) commercial customer growth to firm residential growth has been on a downward trend since 2009. This ratio is shown in Figure 6 for the 2005-2015 period and includes OR for comparison. Note that the ratios for both areas declined following the start of the great recession. 300,000 320,000 340,000 360,000 380,000 400,000 420,000 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 WA-ID-OR-Base 2014 IRP WA-ID-OR-Base 2016 IRP Avista Corp 2016 Natural Gas IRP Appendices 25 APPENDIX - CHAPTER 2 Figure 5: Customer and Population Growth, 2005-2015 Data source: Company data. OR’s fell fairly dramatically, but rebounded starting in 2012. In contrast, WA-ID’s continued its downward trend after a brief rebound in 2012. For an econometric forecasting perspective, this means a given increase in WA-ID residential customers is associated with a smaller change in commercial customers compared to the pre-Great Recession period. As a result, the upward revision in residential customers in WA-ID did not result in an upward revision in commercial customers. 0.0% 0.5% 1.0% 1.5% 2.0% 2.5% 3.0% 3.5% 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 OR Population Growth vs. Residential Customer Growth OR Customer Growth OR Population Growth 0.0% 0.5% 1.0% 1.5% 2.0% 2.5% 3.0% 3.5% 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 WA-ID Population Growth vs. Residential Customer Growth WA-ID Customer Growth WA-ID Population Growth Avista Corp 2016 Natural Gas IRP Appendices 26 APPENDIX - CHAPTER 2 Figure 6: Ratio of Commercial Customer Growth to Residential Customer Growth, 2005-2015 Data source: Company data. The forecast for system-wide industrial customers is slightly higher than the 2014 IRP. This reflects an increase in the WA-ID forecast; as of 2015, approximately 90% of industrial customers are in WA-ID. Figure 7 (top graph) shows total system-wide firm industrial customers since 2004. Following a sharp drop over the 2004-2006 period, firm industrial customers have remained stable at around 260. Separating out WA-ID and OR (middle graph), the number of firm customers in WA-ID continuously fell over the 2004-2011 period. In contrast, OR customers increased over the 2004-2011 period (bottom graph). However, since 2011 the customer counts in both regions have been relatively flat. That is, over the last five years there has been no appreciable change in firm industrial customers our service area. Therefore, in contrast to the 2014 IRP, the current forecast shows flat rather than declining industrial customers. -0.4 -0.2 0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 WA-ID Growth Ratio OR Growth Ratio Avista Corp 2016 Natural Gas IRP Appendices 27 APPENDIX - CHAPTER 2 Figure 7: Industrial Customer Count, 2004-2015 Data source: Company data. 240 245 250 255 260 265 270 275 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 WA-ID-OR Firm Industrial Customers 200 210 220 230 240 250 260 270 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 WA-ID Firm Industrial Customers 0 5 10 15 20 25 30 35 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 OR Firm Industrial Customers Avista Corp 2016 Natural Gas IRP Appendices 28 APPENDIX - CHAPTER 2 II. IRP Forecast Process and Methodology The customer forecasts are generated from forecasting models that are either regression models with ARIMA error corrections or simple smoothing models. The ARIMA error correction models are estimated using SAS/ETS software. The customer forecasts are used as input into Sendout® to generate the IRP load forecasts. Population growth is the key driver for the residential and commercial customer forecasts. Other variables include (1) seasonal dummy variables and (2) outlier dummy variables that control for extreme customer counts associated with double billing, software conversions, and customer movements from one billing schedule to another. Population growth forecast is the key driver behind the customer forecast for residential schedules 101 in WA-ID and 410 in OR. These two schedules represent the majority of customers and, therefore, drive overall residential customer growth. Because of their size and growth potential, a multi-step forecasting process has been developed for the Spokane-Spokane Valley, Coeur d’Alene, and Medford MSAs. The process for forecasting population growth starts with an intermediate forecast horizon (six years). This intermediate forecast is typically used for the annual financial forecast. However, during IRP years, this intermediate forecast horizon is augmented with third party forecasts that cover the next twenty years. Starting with Figure 8, the six-year population forecast is a multi-step process that begins with a GDP forecast that drives the regional employment forecast, which in turn, drives a six year population forecast. Figure 8: Forecasting Population Growth, 2016-2021 The forecasting models for regional employment growth are: [1] 𝐺𝐸𝑀𝑃𝑦,𝑆𝑃𝐾= 𝜗0 + 𝜗1𝐺𝐺𝐷𝑃𝑦,𝑈𝑆+ 𝜗2𝐺𝐺𝐷𝑃𝑦−1,𝑈𝑆+ 𝜗3𝐺𝐺𝐷𝑃𝑦−2,𝑈𝑆+ 𝜔𝑆𝐶𝐷𝐾𝐶,1998−2000=1+ 𝜔𝑆𝐶𝐷𝐻𝐵,2005−2007=1 + 𝜖𝑡,𝑦 [2] 𝐺𝐸𝑀𝑃𝑦,𝐾𝑂𝑂𝑇= 𝛿0 + 𝛿1𝐺𝐺𝐷𝑃𝑦,𝑈𝑆+ 𝛿2𝐺𝐺𝐷𝑃𝑦−1,𝑈𝑆+ 𝛿3𝐺𝐺𝐷𝑃𝑦−2,𝑈𝑆+ 𝜔𝑂𝐿𝐷1994=1+ 𝜔𝑂𝐿𝐷2009=1 + 𝜔𝑆𝐶𝐷𝐻𝐵,2005−2007=1 + 𝜖𝑡,𝑦 [3] 𝐺𝐸𝑀𝑃𝑦,𝐽𝐴𝐶𝐾= 𝜙0 + 𝜙1𝐺𝐺𝐷𝑃𝑦,𝑈𝑆+ 𝜙2𝐺𝐺𝐷𝑃𝑦−1,𝑈𝑆+ 𝜙3𝐺𝐺𝐷𝑃𝑦−2,𝑈𝑆+ 𝜔𝑆𝐶𝐷𝐻𝐵,2004−2005=1 + 𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (1,0,0)(0,0,0)12 SPK is Spokane, WA (Spokane MSA), KOOT is Kootenai, ID (Coeur d’Alene MSA), and JACK is for Jackson County, OR (Medford MSA). GEMPy is employment growth in year y, GGDPy,US is U.S. real GDP growth in year y. DKC is a dummy variable for the collapse of Kaiser Aluminum in Spokane, and DHB, is a dummy for the housing bubble, specific to each region. The average GDP forecasts are used in the estimated model to generate five-year employment growth forecasts. The employment forecasts are then averaged with GI’s forecasts for the same counties so that: [4] 𝐹𝐴𝑣𝑔(𝐺𝐸𝑀𝑃𝑦,𝑆𝑃𝐾) = 𝐹(𝐺𝐸𝑀𝑃𝑦,𝑆𝑃𝐾)+𝐹(𝐺𝐺𝐼𝐸𝑀𝑃)𝑦,𝑆𝑃𝐾) 2 [5] 𝐹𝐴𝑣𝑔(𝐺𝐸𝑀𝑃𝑦,𝐾𝑂𝑂𝑇) = 𝐹(𝐺𝐸𝑀𝑃𝑦,𝐾𝑂𝑂𝑇 )+𝐹(𝐺𝐺𝐼𝐸𝑀𝑃𝑦,𝐾𝑂𝑂𝑇) 2 Average GDP Growth Forecasts: FOMC, Bloomberg, Wall Street Journal, etc. Average forecasts out 5-yrs. Growth Model: Model links year y, y-1, and y-2 GDP growth to year y regional employment growth. Forecast out 6-yrs. Averaged with GI  Model links regional, U.S., and CA year y-1 employment growth to year y county population growth. Forecast out 6-yrs for Spokane, WA; Kootenai, ID; and Jackson, OR. Averaged with IHS forecasts for ID and OR and OFM forecasts for WA. Growth rates used to generate population forecasts for customer forecasts for residential schedules 1, 101, and 410. EMP GDP Avista Corp 2016 Natural Gas IRP Appendices 29 APPENDIX - CHAPTER 2 [6] 𝐹𝐴𝑣𝑔(𝐺𝐸𝑀𝑃𝑦,𝐽𝐴𝐶𝐾) = 𝐹(𝐺𝐸𝑀𝑃𝑦,𝐽𝐴𝐶𝐾 )+𝐹(𝐺𝐺𝐼𝐸𝑀𝑃𝑦,𝐽𝐴𝐶𝐾) 2 Averaging reduces the systematic errors of a single-source forecast. The averages [8.4] through [8.6] are used to generate the population growth forecasts, which are described next. The forecasting models for regional population growth are: [7] 𝐺𝑃𝑂𝑃𝑦,𝑆𝑃𝐾= 𝜅0 + 𝜅1𝐺𝐸𝑀𝑃𝑦−1,𝑆𝑃𝐾+ 𝜅2𝐺𝐸𝑀𝑃𝑦−2,𝑈𝑆+ 𝜔𝑂𝐿𝐷2001=1+𝜖𝑡,𝑦 [8] 𝐺𝑃𝑂𝑃𝑦,𝐾𝑂𝑂𝑇= 𝛼0 + 𝛼1𝐺𝐸𝑀𝑃𝑦−1,𝐾𝑂𝑂𝑇+ 𝛼2𝐺𝐸𝑀𝑃𝑦−2,𝑈𝑆+ 𝜔𝑂𝐿𝐷1994=1 + 𝜔𝑂𝐿𝐷2002=1+ 𝜔𝑆𝐶𝐷𝐻𝐵,2007↑=1 + 𝜖𝑡,𝑦 [9] 𝐺𝑃𝑂𝑃𝑦,𝐽𝐴𝐶𝐾= 𝜓0 + 𝜓1𝐺𝐸𝑀𝑃𝑦−1,𝐽𝐴𝐶𝐾+ 𝜓2𝐺𝐸𝑀𝑃𝑦−2,𝐶𝐴+ 𝜔𝑂𝐿𝐷1991=1+ 𝜔𝑆𝐶𝐷𝐻𝐵,2004−2006=1 + 𝜖𝑡,𝑦 D2001=1 and D1991=1 are a dummy variables for recession impacts. GEMPy-1,US is U.S. employment growth in year y-1 and GEMPy-2, and CA is California Employment growth in year y-1. Because of its close proximity to CA, CA employment growth is better predictor of Jackson, OR employment growth than U.S. growth. The averages [4] through [6] are used in [7] through [9] to generate population growth forecasts. These forecasts are combined with IHS’s forecasts for Kootenai, ID and Jackson, OR and the Office for Financial Management (OFM) for Spokane, WA in the form of a simple average: [10] 𝐹𝐴𝑣𝑔(𝐺𝑃𝑂𝑃𝑦,𝑆𝑃𝐾) = 𝐹(𝐺𝑃𝑂𝑃𝑦,𝑆𝑃𝐾)+𝐹(𝐺𝑂𝐹𝑀𝑃𝑂𝑃𝑦,𝑆𝑃𝐾) 2 [11] 𝐹𝐴𝑣𝑔(𝐺𝑃𝑂𝑃𝑦,𝐾𝑂𝑂𝑇) = 𝐹(𝐺𝑃𝑂𝑃𝑦,𝐾𝑂𝑂𝑇 )+𝐹(𝐺𝐺𝐼𝑃𝑂𝑃𝑦,𝐾𝑂𝑂𝑇) 2 [12] 𝐹𝐴𝑣𝑔(𝐺𝑃𝑂𝑃𝑦,𝐽𝐴𝐶𝐾) = 𝐹(𝐺𝑃𝑂𝑃𝑦,𝐽𝐴𝐶𝐾 )+𝐹(𝐺𝐺𝐼𝑃𝑂𝑃𝑦,𝐽𝐴𝐶𝐾) 2 Here, FAvg(GPOPy) is used to forecast population to forecast residential customers in schedules 101 (WA-ID) and 410 (OR) for the Spokane, Kootenai, and Medford areas. In the case of Spokane, OFM forecasts are used because the IHS’s forecasts exhibit a level and time-path that is inconsistent with recent population behavior. The population growth forecasts for the Douglas (Roseburg), Klamath (Klamath Falls); and Union (La Grande) counties come directly from IHS. Since all forecasted growth rates are annualized, they are converted to monthly rates as FAvg(GPOPt,y)= [1+ FAvg(GPOPy)]1/12 – 1. By way of example, the following is regression model for residential 101 customers for the Spokane region: 𝐶𝑡,𝑦,𝑊𝐴101.𝑟= 𝛼0 + 𝜏𝑃𝑂𝑃𝑡,𝑦,𝑆𝑃𝐾+𝝎𝑺𝑫𝑫𝒕,𝒚+ 𝜔𝑆𝐶𝐷𝐽𝑎𝑛 2007↑=1 + 𝛾𝑅𝐴𝑀𝑃𝑇𝐽𝑎𝑛 2007 + 𝜔𝑂𝐿𝐷𝐴𝑢𝑔 2010=1 + 𝜔𝑂𝐿𝐷𝑆𝑒𝑝𝑡 2012=1 + 𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2015=1 + 𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2015=1 + 𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (9,1,0)(0,0,0)12 Where: POPt,y,SPK =  is the coefficient to be estimated and POPt,y,SPK is the interpolated population level in month t, in year y, for Spokane. The monthly interpolation of historical data assumes that between years, population accumulates following the standard population growth model: POPy,SPK = POPy-1,SPKer. SDDt,y = SD is a vector of seasonal dummy (SD) coefficients to be estimated and Dt,y is a vector monthly seasonal dummies to account of customer seasonality. Dt,y = 1 for the relevant month. SCDJan 2007↑=1 + RampTJan 2007 = structural change (SC) and trend (Ramp) coefficients and variables that control for the sharp fall in residential customer growth that cannot be fully accounted for by the population variable. This reflects the impact of the housing bubble collapse and the subsequent Great Recession. DJan 2007↑=1 takes a value of 1 over both the estimation and forecast period starting in January 2007, and TJan 2007 is a linear time-trend that starts in January 2007 and continues over the estimation and forecast period. Avista Corp 2016 Natural Gas IRP Appendices 30 APPENDIX - CHAPTER 2 OLDAug 2010=1 = OL outlier (OL) coefficient to be estimated and D is a dummy that equals 1 for August 2010. There are three additional outlier dummies that follow August 2010. ARIMAt,y(9,1,0)(0,0,0)12 = is the error correction applied to the model’s initial error structure. This term follows the following from ARIMAt,y (p,d,q)(pk,dk,qk)k. The term p is the autoregressive (AR) order, d is the differencing order, and q is the moving average (MA) order. The term pk is the order of seasonal AR terms, dk is the order of seasonal differencing, and qk is the seasonal order of MA terms. The seasonal values are related to “k,” which is the frequency of the data. With the current data set, k = 12. The customer forecast is generated by inputting forecasted values of POPt,y,SPK into the model estimated with historical data. All customer forecast equations are shown in the last section. The above describes the population forecast for the annual six-year forecast. For IRP years, the customer forecast needs to be extended out an additional 15 years beyond the five-year forecast. This is done using the IHS population forecast for Kootenai, Jackson, Douglas, Klamath, and Union counties. That is, IHS is the sole source for forecasted population growth beyond the six-year time horizon generated by [10] through [12]. In the case of Spokane County, the forecast from Washington’s Office of Financial Management (OFM) is instead of IHS’s. The choice to use OFM’s forecasts reflects the unusually sharp changes that have occurred in the IHS forecasts for the Spokane MSA over a short period of time. Figure 9 shows how much these forecasts have changed in level and shape since June 2012. Between the October 2015 and March 2016 forecasts, there was as significant change for the 2015-2019 period. There is no clear rational for why IHS’s forecasts can change so significantly between 2012 and 2016. Figure 10: Spokane MSA Forecast Comparison Data source: IHS, Washington State of Office of Financial Management, and U.S. Census. 0.0% 0.2% 0.4% 0.6% 0.8% 1.0% 1.2% 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 IHS June 2012 Forecast IHS October 2015 Forecast IHS March 2016 Forecast OFM 2012 Actual Avista Corp 2016 Natural Gas IRP Appendices 31 APPENDIX - CHAPTER 2 Figure 10: Annual Customer Growth for the Three Rate Classes, 2005-2015 Data source: Company data. Figure 10 demonstrates that residential and commercial growth rates are highly correlated and maintain similar levels over the long-run—both classes’ growth rates averaged about 1% over this period. This growth is slightly higher than population growth because of the housing boom and existing households retrofitting with natural gas. However, by 2009, with the collapse of the housing bubble and increased natural gas saturation, customer growth moved closer to population growth. In contrast, the behavior of Industrial customer growth looks quite different. Customer growth is both lower and more volatile. The average growth rate since 2005 is -1.0%, reflecting a trend of nearly flat or slowly declining customers, depending on the jurisdiction. In addition, the standard deviation of year-over-year growth is 2.1% compared to 0.9% for residential and 0.7% for commercial growth. The current IRP forecast reflects this historical trend of weak growth. Some energy industry analysts believe the U.S.’s increased supply of natural gas and oil will attract industrial production back from overseas locations. However, in this IRP, we do not assume plentiful energy supplies in the U.S. will alter long-run trends in industrial customer growth in our service area. Establishing High-Low Cases for IRP Customer Forecast The customer forecasts for this IRP include high and low cases that set the expected bounds around the base-case. Table 2 shows the base, low, and high customer forecasts along with the underlying population growth assumption. The underlying population forecast is the primary driver for each of the three cases. Table 2: Alternative Growth Cases WA-ID: WA-ID Customers 0.6% 1.1% 1.5% WA Population 0.4% 0.8% 1.2% ID Population 1.0% 1.5% 2.0% OR: OR Customers 0.7% 1.2% 1.6% OR Population 0.4% 0.8% 1.3% System: System Customers 0.7% 1.1% 1.5% System Population 0.5% 0.9% 1.3% -5% -4% -3% -2% -1% 0% 1% 2% 3% 4% 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 Residential Commercial Industrial Avista Corp 2016 Natural Gas IRP Appendices 32 APPENDIX - CHAPTER 2 III. IRP Customer Forecast Equations 1. Washington and Idaho Residential Forecasting Models by Schedule WA residential customer forecasts: [13] 𝐶𝑡,𝑦,𝑊𝐴101.𝑟= 𝛼0 + 𝜏𝑃𝑂𝑃𝑡,𝑦,𝑆𝑃𝐾+𝝎𝑺𝑫𝑫𝒕,𝒚+ 𝜔𝑆𝐶𝐷𝐽𝑎𝑛 2007↑=1 + 𝛾𝑅𝐴𝑀𝑃𝑇𝐽𝑎𝑛 2007 + 𝜔𝑂𝐿𝐷𝐴𝑢𝑔 2010=1 + 𝜔𝑂𝐿𝐷𝑆𝑒𝑝𝑡 2012=1 + 𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2015=1 + 𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2015=1 + 𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (9,1,0)(0,0,0)12 [13] Model notes: 1. SC dummy and ramping time trend control for a change in the time-path of customer growth staring in January 2007. [14] 𝐶𝑡,𝑦,𝑊𝐴111.𝑟= 𝛼0 + 𝛾𝑅𝐴𝑀𝑃𝑇𝑆𝑒𝑝𝑡 2010 + 𝜔𝑆𝐶𝐷𝑂𝑐𝑡 2011↑=1 + 𝜔𝑆𝐶𝐷𝑂𝑐𝑡 2013↑=1 + 𝜔𝑂𝐿𝐷𝑀𝑎𝑟 2005=1 + 𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2006=1 + 𝜔𝑂𝐿𝐷𝐽𝑎𝑛 2007=1 + 𝜔𝑂𝐿𝐷𝑆𝑒𝑝𝑡 2007=1 + 𝜔𝑂𝐿𝐷𝑁𝑜𝑣 2007=1 + 𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2011=1 + 𝜔𝑂𝐿𝐷𝐽𝑎𝑛 2015=1 + 𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2015=1 + 𝜔𝑂𝐿𝐷𝐴𝑝𝑟 2015=1 + 𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2015=1 + 𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (1,1,0)(0,0,0)12 𝑓𝑜𝑟 𝑡,𝑦 = 𝐹𝑒𝑏 2007 ↑ [14] Model notes: 1. Ramping time trend controls for a change in the time-path of customer growth staring in the September 2010. 2. SC dummies control for a step-up in customers starting in October 2011 and October 2013. 3. Model is restricted to February 2007  because of a large step-up in customers. Similarly for ID: [15] 𝐶𝑡,𝑦,𝐼𝐷101.𝑟= 𝛽0 + 𝜏𝑃𝑂𝑃𝑡,𝑦,𝐾𝑂𝑂𝑇+𝝎𝑺𝑫𝑫𝒕,𝒚+𝜔𝑆𝐶𝐷𝐽𝑎𝑛 2007↑=1 + 𝛾𝑅𝐴𝑀𝑃𝑇𝐽𝑎𝑛 2007 + 𝜔𝑂𝐿𝐷𝑀𝑎𝑦 2005=1 + 𝜔𝑂𝐿𝐷𝐽𝑢𝑙 2005=1 + 𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2005=1 + 𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2005=1+𝜔𝑂𝐿𝐷𝐽𝑢𝑛 2006=1 + 𝜔𝑂𝐿𝐷𝐽𝑎𝑛 2006=1 + 𝜔𝑂𝐿𝐷𝐽𝑢𝑛 2007=1 + 𝜔𝑂𝐿𝐷𝑁𝑜𝑣 2007=1 + 𝜔𝑂𝐿𝐷𝐴𝑢𝑔 2009=1 + 𝜔𝑂𝐿𝐷𝐴𝑢𝑔 2011=1 + 𝜔𝑂𝐿𝐷𝑆𝑒𝑝𝑡 2011=1 + 𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2015=1 + 𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (2,1,0)(0,0,0)12 [15] Model notes: 1. SC dummy and ramping time trend control for a change in the time-path of customer growth staring in January 2007. [16] 𝐶𝑡,𝑦,𝐼𝐷111.𝑟= 𝛽0+𝜔𝑆𝐶𝐷𝐷𝑒𝑐 2008↑=1+𝜔𝑆𝐶𝐷𝐷𝑒𝑐 2011↑=1 + 𝜔𝑂𝐿𝐷𝑁𝑜𝑣 2008=1 + 𝜔𝑂𝐿𝐷𝑀𝑎𝑟 2010=1 + 𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2011=1 + 𝜔𝑂𝐿𝐷𝑁𝑜𝑣 2011=1 + 𝜔𝑂𝐿𝐷𝑀𝑎𝑟 2015=1 + 𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (9,1,0)(0,0,0)12 [16] Model notes: 1. SC dummies control for a step-up in customers starting in December 2008 and December 2011. 2. Washington and Idaho Commercial Forecasting Models by Schedule Commercial customer baseline forecasts are a mix of simple ARIMA and smoothing models. The WA models are: [17] 𝐶𝑡,𝑦,𝑊𝐴101.𝑐= 𝛼0 + 𝛼1𝐶𝑡,𝑦,𝑊𝐴101.𝑟+ 𝝎𝑺𝑫𝑫𝒕,𝒚+ 𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2015=1 + 𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (1,1,0)(0,0,0)12 [17] Model notes: 1. Ct,y,WA101.r are residential customers from residential schedule 101. They are being used as a forecast driver because of the historical positive correlation between residential and commercial customer growth. [18] 𝐶𝑡,𝑦,𝑊𝐴111.𝑐= 𝛼0 + 𝝎𝑺𝑫𝑫𝒕,𝒚+ 𝜔𝑂𝐿𝐷𝐽𝑎𝑛 2007=1 + 𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2013=1 + 𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2015=1 + 𝜔𝑂𝐿𝐷𝐴𝑝𝑟 2015=1 + 𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2015=1 + 𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (2,1,0)(0,0,0)12 [18] Model notes: 1. Distribution of error terms not quite normal; however, they do pass the white-noise test. [19] 𝐶𝑡,𝑦,𝑊𝐴121+122.𝑐= 1 12 ∑𝐶𝑡−𝑗12𝑗=1 [19] Model notes: Avista Corp 2016 Natural Gas IRP Appendices 33 APPENDIX - CHAPTER 2 1. Customer count is around 25 without any clear trend or seasonality. For unknown reasons, customer county volatility fell substantially in January 2012. 2. Due to the Compass software conversion, February 2015 is excluded from the historical data. The conversion resulted in a double counting of customers in February 2015. Therefore, including this month leads to a significant over-forecast of customers. [20] 𝐶𝑡,𝑦,𝑊𝐴132.𝑐= 𝐶𝑡−1 [20] Model notes: 1. Stable customer count; no econometric model required. Customer count has been at 2 since December 2012. Similarly for ID: [21] 𝐶𝑡,𝑦,𝐼𝐷101.𝑐= 𝛽0 + 𝛽1𝐶𝑡,𝑦,𝐼𝐷101.𝑟+ 𝝎𝑺𝑫𝑫𝒕,𝒚+𝜔𝑆𝐶𝐷𝑁𝑜𝑣 2005↑=1+𝜔𝑆𝐶𝐷𝑆𝑒𝑝 2006↑=1+𝜔𝑆𝐶𝐷𝑁𝑜𝑣 2007↑=1 + 𝜔𝑂𝐿𝐷𝑀𝑎𝑟 2005=1 + 𝜔𝑂𝐿𝐷𝐽𝑢𝑛 2005=1 + 𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2005=1 + 𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2005=1 + 𝜔𝑂𝐿𝐷𝑀𝑎𝑟 2007=1 + 𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2015=1 + +𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (0,1,0)(2,0,0)12 [21] Model notes: 1. Ct,y,ID101.r are residential customers from residential schedule 101. They are being used as a forecast driver because of the historical positive correlation between residential and commercial customer growth. 2. SC dummies control for a step-up in customers in November 2005, September 2006, and November 2007. [22] 𝐶𝑡,𝑦,𝐼𝐷111.𝑐= 𝑊𝑖𝑛𝑡𝑒𝑟′𝑠 𝑀𝑒𝑡ℎ𝑜𝑑− 𝐴𝑑𝑑𝑖𝑡𝑖𝑣𝑒 [23] 𝐶𝑡,𝑦,𝐼𝐷132.𝑐=1 12∑𝐶𝑡−𝑗12𝑗=1 3. Washington and Idaho Industrial Forecasting Models by Schedule Customer forecasts for WA: [24] 𝐶𝑡,𝑦,𝑊𝐴101.𝑖= 𝛼0 + 𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2006=1 + 𝜔𝑂𝐿𝐷𝐽𝑎𝑛 2007=1+ 𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2007=1+ 𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2013=1+ 𝜔𝑂𝐿𝐷𝐽𝑎𝑛 2014=1+ 𝜔𝑂𝐿𝐷𝐽𝑎𝑛 2015=1+ 𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2015=1 + 𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (2,0,0)(0,0,0)12 [25] 𝐶𝑡,𝑦,𝑊𝐴111.𝑖= 𝛼0 + 𝜔𝑂𝐿𝐷𝑆𝑒𝑝𝑡 2005=1+ 𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2006=1 + 𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2006=1+ 𝜔𝑂𝐿𝐷𝐽𝑎𝑛 2007=1+ 𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2007=1 + 𝜔𝑂𝐿𝐷𝑀𝑎𝑟 2008=1+ 𝜔𝑂𝐿𝐷𝐽𝑢𝑛𝑒 2014=1 + 𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2015=1+ 𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2015=1 + 𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (1,0,0)(0,0,0)12 [26] 𝐶𝑡,𝑦,𝑊𝐴121+122.𝑖=1 12∑𝐶𝑡−𝑗12𝑗=1 [26] Model notes: 1. Customer count for schedule 122 fell to zero in 2012. Schedule 121 customers fluctuate between 2 and 4 customers without any clear trend or seasonality. Similarly for ID: [27] 𝐶𝑡,𝑦,𝐼𝐷101.𝑖= 𝛽0 + 𝜔𝑆𝐶𝐷𝐷𝑒𝑐 2010↑=1+ 𝜔𝑆𝐶𝐷𝑁𝑜𝑣 2011↑=1+ 𝜔𝑂𝐿𝐷𝑀𝑎𝑟 2005=1 + 𝜔𝑂𝐿𝐷𝐴𝑢𝑔 2005=1+ 𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2005=1 + 𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2006=1 + 𝜔𝑂𝐿𝐷𝑀𝑎𝑟 2007=1+ 𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2008=1 + 𝜔𝑂𝐿𝐷𝐴𝑢𝑔 2011=1+ 𝜔𝑂𝐿𝐷𝐽𝑢𝑙𝑦 2014=1 + 𝜔𝑂𝐿𝐷𝐽𝑎𝑛 2015=1+ 𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2015=1 + 𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (4,0,0)(0,0,0)12 [27] Model notes: 1. SC dummies control for step-downs in customers. [28] 𝐶𝑡,𝑦,𝐼𝐷111.𝑖= 1 12 ∑𝐶𝑡−𝑗12𝑗=1 ,𝑟𝑒𝑠𝑡𝑟𝑖𝑐𝑡 𝑡𝑜 𝑑𝑎𝑡𝑎 𝑡,𝑦 = 𝐴𝑢𝑔𝑢𝑠𝑡 2009 ↑ [28] Model notes: 1. Period of restriction reflects the restriction on the UPC model for this schedule. Avista Corp 2016 Natural Gas IRP Appendices 34 APPENDIX - CHAPTER 2 2. Due to the Compass software conversion, February 2015 is excluded from the historical data. The conversion resulted in a double counting of customers in February 2015. Therefore, including this month leads to a significant over-forecast of customers. [29] 𝐶𝑡,𝑦,𝐼𝐷112.𝑖= 1 12∑𝐶𝑡−𝑗12𝑗=1 4. Medford, OR Forecasting Models The forecasting models for the Medford region (Jackson County) are given below for the residential, commercial, and industrial sectors: Residential Sector, Customers: [30] 𝐶𝑡,𝑦,𝑀𝐸𝐷410.𝑟= 𝛼0 + 𝛼1𝑃𝑂𝑃𝑡,𝑦,𝐽𝐴𝐶𝐾𝑆𝑂𝑁+𝝎𝑺𝑫𝑫𝒕,𝒚+ 𝜔𝑆𝐶𝐷𝐽𝑎𝑛 2008↑ =1 + 𝛾𝑅𝐴𝑀𝑃𝑇𝐽𝑎𝑛 2008 + 𝜔𝑂𝐿𝐷𝑁𝑜𝑣 2004 =1 + 𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2004 =1 + 𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2005 =1 + 𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2015 =1 + 𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (11,1,0)(0,0,0)12 [30] Model notes: 1. SC dummy and ramping time trend control for a change in the time-path of customer growth staring in January 2008. Commercial Sector, Customers: [31] 𝐶𝑡,𝑦,𝑀𝐸𝐷420.𝑐= 𝛼0 +𝛼1𝐶𝑡,𝑦,𝑀𝐸𝐷410.𝑟 + 𝝎𝑺𝑫𝑫𝒕,𝒚+ 𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2004=1 + 𝜔𝑂𝐿𝐷𝑆𝑒𝑝𝑡 2005 =1 + 𝜔𝑂𝐿𝐷𝑁𝑜𝑣 2009 =1 + 𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2015 =1 +𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (3,1,0)(1,0,0)12 [31] Model notes: 1. Ct,y,MED410.r are residential customers from residential schedule 410. They are being used as a forecast driver because of the historical positive correlation between residential and commercial customer growth. [32] 𝐶𝑡,𝑦,𝑀𝐸𝐷424.𝑐= 𝐶𝑡,𝑦−1 + 1 [32] Model notes: 1. Schedule adds about one customer per year. 2. Due to the Compass software conversion, February 2015 is excluded from the historical data. The conversion resulted in a double counting of customers in February 2015. Therefore, including this month leads to a significant over-forecast of customers. [33] 𝐶𝑡,𝑦,𝑀𝐸𝐷444.𝑐= 1 𝑖𝑓 (𝑇𝐻𝑀/𝐶𝑡,𝑦)𝑀𝐸𝐷,440.𝑐> 0 [33] Model notes: 1. There is typically only one customer served by this schedule. Therefore, the customer forecast is automatically set to one whenever the load forecast is greater than zero. Industrial Sector, Customers: [34] 𝐶𝑡,𝑦,𝑀𝐸𝐷420.𝑖= 1 12 ∑𝐶𝑡−𝑗12𝑗=1 [34] Model notes: 1. Data starts November 2006. Excluding outliers in November 2006, November 2009, and February 2011, the customer count fluctuates between 9 and 16 without any clear trend or seasonality. Changes in the customer count occur in steps between prolonged periods of stability. [35] 𝐶𝑡,𝑦,𝑀𝐸𝐷424.𝑖=1 12 ∑𝐶𝑡−𝑗12𝑗=1 [35] Model notes: 1. Data starts January 2009. Excluding a January 2009 outlier, the customer count fluctuates between 1 and 3 without any clear trend or seasonality. Customer count is most frequently reported as 2. 5. Roseburg, OR Forecasting Models Avista Corp 2016 Natural Gas IRP Appendices 35 APPENDIX - CHAPTER 2 The forecasting models for the Roseburg region (Douglas County) are given below for the residential, commercial, and industrial sectors: Residential Sector, Customers: [36] 𝐶𝑡,𝑦,𝑅𝑂𝑆410.𝑟= 𝜑0+𝜑1𝑃𝑂𝑃𝑡,𝑦,𝐷𝑂𝑈𝐺𝐿𝐴𝑆+ 𝝎𝑺𝑫𝑫𝒕,𝒚+ 𝜔𝑆𝐶𝐷𝐷𝑒𝑐 2004 =1 + 𝜔𝑂𝐿𝐷𝑁𝑜𝑣 2004 =1 + 𝜔𝑂𝐿𝐷𝐽𝑎𝑛 2005 =1 + 𝜔𝑂𝐿𝐷𝑁𝑜𝑣 2005 =1 + 𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2005 =1 + 𝜔𝑂𝐿𝐷𝑁𝑜𝑣 2006 =1 + 𝜔𝑂𝐿𝐷𝑀𝑎𝑟 2007 =1 + 𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2007 =1 + 𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2008 =1 + 𝜔𝑂𝐿𝐷𝑁𝑜𝑣 2009 =1 + 𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2015 =1 + 𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (11,1,0)(0,0,0)12 [36] Model notes: 1. POP is population for Douglas County, OR. 2. SC dummy controls for a step-up in customers starting in January 2004. Commercial Sector, Customers: [37] 𝐶𝑡,𝑦,𝑅𝑂𝑆420.𝑐= 𝜑0 + 𝝎𝑺𝑫𝑫𝒕,𝒚+ 𝜔𝑆𝐶𝐷𝐷𝑒𝑐 2004↑ =1 + 𝜔𝑂𝐿𝐷𝑁𝑜𝑣 2004 =1 + 𝜔𝑂𝐿𝐷𝐽𝑎𝑛 2008 =1 + 𝜔𝑂𝐿𝐷𝑀𝑎𝑟 2009=1 + 𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2015=1 + 𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (12,1,0)(0,0,0)12 [37] Model notes: 1. Model does not use schedule 410 customers as driver. This reflects the lack of correlation between residential 410 and commercial 420 customer growth. 2. The lack of correlation noted in Point 1 could reflect Roseburg’s position between larger cities that offer a range of commercial activities. Competition from these cities may be inhibiting commercial growth in Roseburg. 3. SC dummy controls for a significant step-up in customers starting in December 2004. [38] 𝐶𝑡,𝑦,𝑅𝑂𝑆424.𝑐= 1 12∑𝐶𝑡−𝑗12𝑗=1 Industrial Sector, Customers: [39] 𝐶𝑡,𝑦,𝑅𝑂𝑆420.𝑖= 1 12 ∑𝐶𝑡−𝑗12𝑗=1 [39] Model notes: 1. Due to the Compass software conversion, February 2015 is excluded from the historical data. The conversion resulted in a double counting of customers in February 2015. Therefore, including this month leads to a significant over-forecast of customers. [40] 𝐶𝑡,𝑦,𝑅𝑂𝑆424.𝑖= 1 12 ∑𝐶𝑡−𝑗12𝑗=1 [40] Model notes: 1. Schedule appears to have died. No customers are currently being reported. 6. Klamath Falls, OR Forecasting Models The forecasting models for the Klamath Falls region (Klamath County) are given below for the residential, commercial, and industrial sectors: Residential Sector, Customers: [41] 𝐶𝑡,𝑦,𝐾𝐿𝑀410.𝑟= 𝛽0 + 𝛽1𝑃𝑂𝑃𝑡,𝑦,𝐾𝐿𝐴𝑀𝐴𝑇𝐻+ 𝝎𝑺𝑫𝑫𝒕,𝒚 +𝜔𝑂𝐿𝐷𝑁𝑜𝑣 2004=1+ 𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2015 =1+ 𝜔𝑂𝐿𝐷𝐴𝑝𝑟 2015 =1 + 𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (7,1,0)(0,0,0)12 [41] Model notes: 1. POP is population for Klamath County. Commercial Sector, Customers: Avista Corp 2016 Natural Gas IRP Appendices 36 APPENDIX - CHAPTER 2 [42] 𝐶𝑡,𝑦,𝐾𝐿𝑀420.𝑐= 𝛽0 + 𝛽1𝐶𝑡,𝑦,𝐾𝐿𝑀410.𝑟+ 𝝎𝑺𝑫𝑫𝒕,𝒚 + 𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2005=1 + 𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2006=1 + 𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (11,1,0)(2,0,0)12 [42] Model notes: 1. Ct,y,KLM410.r are residential customers from residential schedule 410. They are being used as a forecast driver because of the historical positive correlation between residential and commercial customer growth. [43] 𝐶𝑡,𝑦,𝐾𝐿𝑀424.𝑐= 1 12∑𝐶𝑡−𝑗12𝑗=1 [43] Model notes: 1. Data starts January 2004. From January 2004 to March 2010, the customer count fluctuated between 19 and 24. Afterwards, the customer count has dropped to fluctuate between 11 and 16. There is no clear trend or seasonality. Industrial Sector, Customers: [44] 𝐶𝑡,𝑦,𝐾𝐿𝑀420.𝑖= 1 12 ∑𝐶𝑡−𝑗12𝑗=1 [44] Model notes: 1. Data starts December 2006. The customer count fluctuates between 4 and 9 without any clear trend or seasonality. [45] 𝐶𝑡,𝑦,𝐾𝐿𝑀424.𝑖= 1 12∑𝐶𝑡−𝑗12𝑗=1 [45] Model notes: 1. Data starts April 2009. The customer count fluctuates between 1 and 4 without any clear trend or seasonality. 7. La Grande, OR Forecasting Models The forecasting models for the La Grande region (Union County) are given below for the residential, commercial, and industrial sectors: Residential Sector, Customers: [46] 𝐶𝑡,𝑦,𝐿𝑎𝐺410.𝑟= 𝜃0 + 𝜃1𝑃𝑂𝑃𝑡,𝑦,𝑈𝑁𝐼𝑂𝑁+ 𝝎𝑺𝑫𝑫𝒕,𝒚+ 𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2004=1 + 𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2009=1+ 𝜔𝑂𝐿𝐷𝐽𝑢𝑙 2006=1+ 𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2015=1 + 𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (9,1,0)(1,0,0)12 [46] Model notes: 1. POP is population for Douglas County. Commercial Sector, Customers: [47] 𝐶𝑡,𝑦,𝐿𝑎𝐺420.𝑐= 𝜃0 + 𝜃1𝐶𝑡,𝑦,𝐿𝑎𝐺410.𝑟+ 𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2008 =1 + 𝜔𝑂𝐿𝐷𝑀𝑎𝑟 2011 =1 + 𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (12,1,0)(0,0,0)12 [47] Model notes: 1. Ct,y,LaG410.r are residential customers from residential schedule 410. They are being used as a forecast driver because of the historical positive correlation between residential and commercial customer growth. [48] 𝐶𝑡,𝑦,𝐿𝑎𝐺424.𝑐= 1 12∑𝐶𝑡−𝑗12𝑗=1 [48] Model notes: 1. Data starts January 2007. The customer count fluctuates between 2 and 4 without any clear trend or seasonality. Changes in the customer count appear as steps after prolonged periods of stability. [49] 𝐶𝑡,𝑦,𝐿𝑎𝐺444.𝑐= 𝛼 𝑖𝑓 (𝑇𝐻𝑀/𝐶𝑡,𝑦)𝐿𝑎𝑔,444.𝑐> 0 [49] Model notes: Avista Corp 2016 Natural Gas IRP Appendices 37 APPENDIX - CHAPTER 2 1. Data starts September 2011. The customer forecast is a derivative of the schedule’s load forecast. 2. α = the average historical customer count when THM/C > 0. The value of α is usually slighter greater than one. Industrial Sector, Customers: [50] 𝑪𝒕,𝒚,𝑳𝒂𝑮𝟒𝟒𝟒.𝒊= 𝜽𝟎 + 𝝎𝑺𝑫𝑫𝒕,𝒚+ 𝝎𝑶𝑳𝑫𝑨𝒖𝒈 𝟐𝟎𝟎𝟕=𝟏+ 𝝎𝑶𝑳𝑫𝑺𝒆𝒑𝒕 𝟐𝟎𝟎𝟖 =𝟏+ 𝝎𝑶𝑳𝑫𝑵𝒐𝒗 𝟐𝟎𝟎𝟗 =𝟏+ 𝝎𝑶𝑳𝑫𝑱𝒂𝒏 𝟐𝟎𝟏𝟎 =𝟏+ + 𝝎𝑶𝑳𝑫𝑵𝒐𝒗 𝟐𝟎𝟏𝟎=𝟏+ 𝝎𝑶𝑳𝑫𝑨𝒖𝒈 𝟐𝟎𝟏𝟏 =𝟏+ 𝝎𝑶𝑳𝑫𝑨𝒖𝒈 𝟐𝟎𝟏𝟐 =𝟏+ 𝝎𝑶𝑳𝑫𝑵𝒐𝒗 𝟐𝟎𝟏𝟐 =𝟏+ 𝝎𝑶𝑳𝑫𝑫𝒆𝒄 𝟐𝟎𝟏𝟐=𝟏+ 𝝎𝑶𝑳𝑫𝑱𝒂𝒏 𝟐𝟎𝟏𝟑 =𝟏+ 𝝎𝑶𝑳𝑫𝑭𝒆𝒃 𝟐𝟎𝟏𝟑 =𝟏+ 𝝎𝑶𝑳𝑫𝑱𝒂𝒏 𝟐𝟎𝟏𝟒 =𝟏+ 𝑨𝑹𝑰𝑴𝑨𝝐𝒕,𝒚 (𝟗,𝟎,𝟎)(𝟎,𝟎,𝟎)𝟏𝟐 Avista Corp 2016 Natural Gas IRP Appendices 38 APPENDIX - CHAPTER 2 APPENDIX 2.2: CUSTOMER FORECASTS BY REGION WASHINGTON AND IDAHO Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Nov-15 210,786 22,852 231 210,786 22,852 231 210,786 22,852 231 Dec-15 211,651 23,321 227 211,651 23,321 227 211,651 23,321 227 Jan-16 211,372 22,931 235 211,963 22,995 235 210,732 22,861 235 Feb-16 211,351 22,981 236 212,027 23,055 236 210,620 22,901 236 Mar-16 211,222 22,941 235 211,982 23,024 235 210,400 22,852 235 Apr-16 211,153 22,944 235 211,997 23,037 236 210,240 22,845 235 May-16 211,150 22,917 235 212,079 23,019 236 210,146 22,808 235 Jun-16 210,930 22,920 236 211,942 23,031 236 209,836 22,801 235 Jul-16 211,207 22,924 236 212,301 23,044 236 210,025 22,796 235 Aug-16 211,369 22,923 236 212,544 23,052 236 210,099 22,785 235 Sep-16 211,864 22,915 236 213,122 23,052 236 210,504 22,768 235 Oct-16 212,439 22,922 236 213,783 23,068 236 210,989 22,765 235 Nov-16 213,174 22,992 236 214,604 23,148 236 211,632 22,826 235 Dec-16 213,881 23,065 236 215,396 23,230 237 212,246 22,889 235 Jan-17 214,171 23,085 236 215,770 23,259 237 212,446 22,899 235 Feb-17 214,131 23,135 236 215,812 23,318 237 212,319 22,939 235 Mar-17 214,043 23,108 236 215,805 23,300 237 212,144 22,903 235 Apr-17 213,929 23,106 236 215,772 23,307 237 211,944 22,891 235 May-17 213,886 23,085 236 215,810 23,294 237 211,814 22,861 235 Jun-17 213,657 23,074 236 215,661 23,292 237 211,500 22,841 235 Jul-17 213,893 23,063 236 215,985 23,290 237 211,642 22,820 235 Aug-17 214,062 23,055 236 216,242 23,291 237 211,718 22,802 235 Sep-17 214,541 23,063 236 216,812 23,309 237 212,101 22,800 235 Oct-17 215,132 23,075 236 217,495 23,330 237 212,592 22,802 235 Nov-17 215,893 23,141 236 218,351 23,406 237 213,252 22,858 235 Dec-17 216,618 23,240 236 219,171 23,516 238 213,876 22,946 235 Jan-18 216,950 23,256 236 219,595 23,541 238 214,112 22,952 235 Feb-18 216,923 23,303 236 219,655 23,598 238 213,993 22,988 235 Mar-18 216,857 23,279 236 219,675 23,583 238 213,835 22,954 235 Apr-18 216,755 23,263 236 219,658 23,577 238 213,642 22,929 235 May-18 216,715 23,236 236 219,705 23,559 238 213,510 22,892 235 Jun-18 216,492 23,235 236 219,566 23,567 238 213,199 22,881 235 Jul-18 216,718 23,229 236 219,884 23,570 238 213,328 22,865 235 Aug-18 216,885 23,228 236 220,142 23,579 238 213,399 22,854 235 Sep-18 217,360 23,238 236 220,713 23,599 238 213,774 22,854 235 Oct-18 217,954 23,244 236 221,404 23,614 238 214,263 22,850 235 Nov-18 218,721 23,308 236 222,273 23,689 238 214,924 22,903 235 Dec-18 219,455 23,395 236 223,109 23,787 238 215,551 22,979 235 Jan-19 219,797 23,408 237 223,546 23,809 239 215,793 22,981 234 Feb-19 219,780 23,456 237 223,619 23,868 239 215,682 23,018 234 Washington and Idaho - High Growth Washington and Idaho - Low Growth Washington and Idaho - Expected Growth Avista Corp 2016 Natural Gas IRP Appendices 39 APPENDIX - CHAPTER 2 APPENDIX 2.2: CUSTOMER FORECASTS BY REGION WASHINGTON AND IDAHO Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Mar-19 219,724 23,428 237 223,651 23,849 239 215,532 22,981 234 Apr-19 219,628 23,417 237 223,643 23,847 239 215,344 22,960 234 May-19 219,592 23,390 237 223,697 23,830 239 215,215 22,923 234 Jun-19 219,371 23,393 237 223,562 23,842 239 214,904 22,916 234 Jul-19 219,600 23,390 237 223,887 23,849 239 215,033 22,903 234 Aug-19 219,771 23,390 237 224,154 23,859 239 215,104 22,893 234 Sep-19 220,251 23,392 237 224,735 23,871 239 215,476 22,885 234 Oct-19 220,849 23,399 237 225,438 23,888 239 215,965 22,881 234 Nov-19 221,624 23,465 237 226,323 23,965 239 216,626 22,935 234 Dec-19 222,365 23,546 237 227,173 24,058 239 217,253 23,004 234 Jan-20 222,716 23,563 237 227,626 24,085 239 217,499 23,011 234 Feb-20 222,708 23,612 237 227,711 24,145 239 217,394 23,048 234 Mar-20 222,661 23,585 237 227,756 24,127 239 217,250 23,012 234 Apr-20 222,572 23,579 237 227,759 24,131 239 217,066 22,995 234 May-20 222,544 23,554 237 227,824 24,116 240 216,942 22,961 234 Jun-20 222,331 23,551 237 227,700 24,122 240 216,638 22,947 234 Jul-20 222,565 23,546 237 228,035 24,128 240 216,767 22,932 234 Aug-20 222,741 23,542 237 228,310 24,134 240 216,839 22,918 234 Sep-20 223,225 23,546 237 228,903 24,148 240 217,212 22,911 234 Oct-20 223,829 23,555 237 229,618 24,167 240 217,701 22,910 234 Nov-20 224,608 23,623 237 230,514 24,247 240 218,359 22,965 233 Dec-20 225,356 23,710 237 231,379 24,347 240 218,987 23,039 233 Jan-21 225,714 23,727 237 231,844 24,374 240 219,235 23,045 233 Feb-21 225,712 23,775 237 231,938 24,434 240 219,133 23,081 233 Mar-21 225,671 23,751 237 231,993 24,420 240 218,993 23,048 233 Apr-21 225,590 23,741 237 232,007 24,420 240 218,815 23,027 233 May-21 225,567 23,716 237 232,081 24,404 240 218,694 22,993 233 Jun-21 225,359 23,714 237 231,964 24,412 240 218,393 22,980 233 Jul-21 225,574 23,706 237 232,272 24,413 240 218,513 22,963 233 Aug-21 225,731 23,703 237 232,519 24,419 240 218,577 22,951 233 Sep-21 226,195 23,709 237 233,084 24,435 240 218,938 22,947 233 Oct-21 226,778 23,718 237 233,771 24,453 241 219,414 22,947 233 Nov-21 227,537 23,784 237 234,641 24,530 241 220,060 23,001 233 Dec-21 228,265 23,871 237 235,480 24,629 241 220,675 23,076 233 Jan-22 228,603 23,885 237 235,916 24,653 241 220,913 23,080 233 Feb-22 228,582 23,934 237 235,981 24,713 241 220,803 23,118 233 Mar-22 228,521 23,907 237 236,006 24,694 241 220,656 23,083 233 Apr-22 228,419 23,897 237 235,988 24,693 241 220,468 23,064 233 May-22 228,377 23,869 237 236,033 24,673 241 220,339 23,028 233 Jun-22 228,150 23,868 237 235,886 24,681 241 220,032 23,017 233 Washington and Idaho - High Growth Washington and Idaho - Low Growth Washington and Idaho - Expected Growth Avista Corp 2016 Natural Gas IRP Appendices 40 APPENDIX - CHAPTER 2 APPENDIX 2.2: CUSTOMER FORECASTS BY REGION WASHINGTON AND IDAHO Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Jul-22 228,362 23,864 237 236,190 24,686 241 220,149 23,004 232 Aug-22 228,515 23,862 237 236,434 24,693 241 220,210 22,993 232 Sep-22 228,978 23,867 237 237,000 24,707 241 220,570 22,989 232 Oct-22 229,558 23,873 237 237,686 24,723 241 221,042 22,986 232 Nov-22 230,315 23,940 237 238,556 24,801 241 221,684 23,041 232 Dec-22 231,041 24,023 237 239,396 24,896 241 222,295 23,112 232 Jan-23 231,378 24,040 237 239,831 24,923 241 222,531 23,119 232 Feb-23 231,353 24,088 237 239,892 24,982 241 222,420 23,156 232 Mar-23 231,289 24,060 237 239,913 24,962 241 222,272 23,120 232 Apr-23 231,186 24,051 237 239,893 24,961 242 222,086 23,103 232 May-23 231,141 24,024 237 239,933 24,943 242 221,955 23,067 232 Jun-23 230,911 24,024 237 239,782 24,952 242 221,647 23,058 232 Jul-23 231,122 24,017 237 240,085 24,953 242 221,764 23,043 232 Aug-23 231,272 24,016 237 240,326 24,961 242 221,824 23,033 232 Sep-23 231,732 24,018 237 240,889 24,972 242 222,180 23,026 232 Oct-23 232,309 24,026 237 241,574 24,989 242 222,648 23,025 232 Nov-23 233,064 24,092 237 242,445 25,067 242 223,287 23,079 232 Dec-23 233,787 24,178 237 243,282 25,165 242 223,893 23,153 232 Jan-24 234,120 24,193 237 243,715 25,190 242 224,126 23,158 232 Feb-24 234,093 24,243 237 243,773 25,251 242 224,015 23,197 231 Mar-24 234,027 24,214 237 243,790 25,229 242 223,867 23,161 231 Apr-24 233,920 24,205 237 243,765 25,229 242 223,679 23,143 231 May-24 233,873 24,179 237 243,802 25,211 242 223,549 23,109 231 Jun-24 233,642 24,177 237 243,647 25,218 242 223,242 23,099 231 Jul-24 233,851 24,171 237 243,950 25,220 242 223,357 23,084 231 Aug-24 234,001 24,169 237 244,192 25,227 242 223,416 23,073 231 Sep-24 234,460 24,173 237 244,757 25,240 242 223,770 23,068 231 Oct-24 235,037 24,181 237 245,444 25,257 243 224,236 23,067 231 Nov-24 235,792 24,247 237 246,319 25,335 243 224,872 23,122 231 Dec-24 236,514 24,332 237 247,159 25,433 243 225,474 23,194 231 Jan-25 236,847 24,349 237 247,593 25,460 243 225,706 23,201 231 Feb-25 236,820 24,397 237 247,651 25,519 243 225,595 23,238 231 Mar-25 236,753 24,369 237 247,668 25,498 243 225,447 23,203 231 Apr-25 236,646 24,360 237 247,642 25,498 243 225,260 23,185 231 May-25 236,600 24,333 237 247,681 25,478 243 225,131 23,151 231 Jun-25 236,367 24,331 237 247,523 25,485 243 224,824 23,140 231 Jul-25 236,571 24,324 237 247,819 25,487 243 224,936 23,125 231 Aug-25 236,715 24,323 237 248,053 25,494 243 224,992 23,116 230 Sep-25 237,168 24,327 237 248,611 25,507 243 225,342 23,111 230 Oct-25 237,740 24,335 237 249,293 25,524 243 225,804 23,111 230 Washington and Idaho - High Growth Washington and Idaho - Low Growth Washington and Idaho - Expected Growth Avista Corp 2016 Natural Gas IRP Appendices 41 APPENDIX - CHAPTER 2 APPENDIX 2.2: CUSTOMER FORECASTS BY REGION WASHINGTON AND IDAHO Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Nov-25 238,490 24,400 237 250,162 25,600 243 226,434 23,164 230 Dec-25 239,206 24,485 237 250,997 25,698 243 227,032 23,236 230 Jan-26 239,532 24,500 237 251,423 25,723 243 227,259 23,242 230 Feb-26 239,500 24,549 237 251,474 25,783 243 227,147 23,280 230 Mar-26 239,427 24,520 237 251,481 25,761 243 226,996 23,244 230 Apr-26 239,315 24,511 237 251,447 25,760 243 226,808 23,227 230 May-26 239,262 24,486 237 251,474 25,742 244 226,675 23,195 230 Jun-26 239,023 24,483 237 251,308 25,748 244 226,367 23,184 230 Jul-26 239,225 24,477 237 251,602 25,750 244 226,479 23,170 230 Aug-26 239,367 24,475 237 251,834 25,756 244 226,533 23,160 230 Sep-26 239,819 24,479 237 252,392 25,769 244 226,881 23,155 230 Oct-26 240,388 24,486 237 253,073 25,785 244 227,340 23,154 230 Nov-26 241,136 24,551 237 253,942 25,861 244 227,966 23,207 230 Dec-26 241,850 24,637 237 254,778 25,961 244 228,560 23,280 230 Jan-27 242,175 24,653 237 255,204 25,986 244 228,787 23,287 230 Feb-27 242,140 24,701 237 255,250 26,045 244 228,673 23,324 230 Mar-27 242,065 24,673 237 255,254 26,024 244 228,522 23,290 229 Apr-27 241,951 24,664 237 255,216 26,023 244 228,333 23,273 229 May-27 241,897 24,637 237 255,243 26,003 244 228,202 23,239 229 Jun-27 241,656 24,635 237 255,072 26,009 244 227,894 23,229 229 Jul-27 241,855 24,630 237 255,364 26,013 244 228,003 23,216 229 Aug-27 241,995 24,626 237 255,593 26,017 244 228,057 23,204 229 Sep-27 242,444 24,630 237 256,149 26,029 244 228,401 23,200 229 Oct-27 243,013 24,638 237 256,831 26,046 244 228,858 23,200 229 Nov-27 243,757 24,703 237 257,699 26,123 245 229,480 23,253 229 Dec-27 244,469 24,788 237 258,535 26,221 245 230,071 23,325 229 Jan-28 244,792 24,803 237 258,959 26,245 245 230,295 23,331 229 Feb-28 244,755 24,852 237 259,003 26,306 245 230,182 23,369 229 Mar-28 244,678 24,824 237 259,004 26,284 245 230,030 23,335 229 Apr-28 244,563 24,815 237 258,964 26,283 245 229,842 23,318 229 May-28 244,506 24,788 237 258,986 26,263 245 229,710 23,285 229 Jun-28 244,262 24,786 237 258,810 26,269 245 229,401 23,275 229 Jul-28 244,459 24,779 237 259,100 26,270 245 229,509 23,260 229 Aug-28 244,597 24,777 237 259,327 26,276 245 229,562 23,251 229 Sep-28 245,044 24,781 237 259,882 26,289 245 229,904 23,246 228 Oct-28 245,611 24,788 237 260,563 26,304 245 230,358 23,245 228 Nov-28 246,353 24,854 237 261,431 26,383 245 230,977 23,299 228 Dec-28 247,063 24,939 237 262,267 26,481 245 231,565 23,371 228 Jan-29 247,383 24,954 237 262,688 26,505 245 231,787 23,377 228 Feb-29 247,343 25,003 237 262,728 26,565 245 231,672 23,415 228 Washington and Idaho - High Growth Washington and Idaho - Low Growth Washington and Idaho - Expected Growth Avista Corp 2016 Natural Gas IRP Appendices 42 APPENDIX - CHAPTER 2 APPENDIX 2.2: CUSTOMER FORECASTS BY REGION WASHINGTON AND IDAHO Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Mar-29 247,265 24,975 237 262,725 26,544 245 231,521 23,381 228 Apr-29 247,146 24,965 237 262,681 26,542 245 231,332 23,364 228 May-29 247,086 24,938 237 262,699 26,521 245 231,198 23,331 228 Jun-29 246,841 24,935 237 262,520 26,526 246 230,891 23,320 228 Jul-29 247,036 24,930 237 262,808 26,529 246 230,998 23,308 228 Aug-29 247,170 24,928 237 263,030 26,535 246 231,048 23,298 228 Sep-29 247,615 24,932 237 263,583 26,547 246 231,388 23,294 228 Oct-29 248,178 24,938 237 264,261 26,562 246 231,839 23,292 228 Nov-29 248,918 25,004 237 265,129 26,640 246 232,455 23,347 228 Dec-29 249,625 25,088 237 265,964 26,738 246 233,038 23,417 228 Jan-30 249,942 25,104 237 266,382 26,763 246 233,258 23,425 228 Feb-30 249,900 25,152 237 266,418 26,822 246 233,143 23,462 228 Mar-30 249,819 25,124 237 266,411 26,800 246 232,991 23,428 228 Apr-30 249,697 25,114 237 266,362 26,798 246 232,801 23,411 227 May-30 249,635 25,087 237 266,376 26,777 246 232,668 23,378 227 Jun-30 249,387 25,086 237 266,193 26,784 246 232,361 23,370 227 Jul-30 249,579 25,078 237 266,476 26,784 246 232,466 23,355 227 Aug-30 249,713 25,076 237 266,697 26,789 246 232,516 23,345 227 Sep-30 250,153 25,079 237 267,246 26,801 246 232,852 23,341 227 Oct-30 250,713 25,087 237 267,922 26,817 246 233,300 23,341 227 Nov-30 251,450 25,152 237 268,788 26,894 246 233,913 23,394 227 Dec-30 252,154 25,238 237 269,621 26,994 247 234,493 23,466 227 Jan-31 252,469 25,252 237 270,038 27,017 247 234,711 23,472 227 Feb-31 252,425 25,301 237 270,069 27,077 247 234,596 23,510 227 Mar-31 252,340 25,273 237 270,058 27,055 247 234,443 23,477 227 Apr-31 252,216 25,263 237 270,004 27,053 247 234,254 23,460 227 May-31 252,151 25,236 237 270,014 27,032 247 234,119 23,427 227 Jun-31 251,899 25,233 237 269,824 27,037 247 233,811 23,417 227 Jul-31 252,091 25,228 237 270,109 27,039 247 233,916 23,405 227 Aug-31 252,225 25,225 237 270,331 27,044 247 233,966 23,395 227 Sep-31 252,666 25,229 237 270,883 27,056 247 234,302 23,391 227 Oct-31 253,226 25,236 237 271,562 27,072 247 234,748 23,390 226 Nov-31 253,963 25,300 237 272,431 27,148 247 235,358 23,442 226 Dec-31 254,667 25,385 237 273,267 27,247 247 235,936 23,514 226 Jan-32 254,983 25,402 237 273,686 27,273 247 236,155 23,522 226 Feb-32 254,938 25,448 237 273,717 27,331 247 236,038 23,557 226 Mar-32 254,854 25,422 237 273,706 27,311 247 235,887 23,526 226 Apr-32 254,730 25,411 237 273,653 27,307 247 235,698 23,508 226 May-32 254,665 25,384 237 273,663 27,286 247 235,564 23,476 226 Jun-32 254,414 25,383 237 273,474 27,293 248 235,258 23,468 226 Jul-32 254,606 25,375 237 273,758 27,292 248 235,363 23,453 226 Washington and Idaho - High Growth Washington and Idaho - Low Growth Washington and Idaho - Expected Growth Avista Corp 2016 Natural Gas IRP Appendices 43 APPENDIX - CHAPTER 2 APPENDIX 2.2: CUSTOMER FORECASTS BY REGION WASHINGTON AND IDAHO Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Aug-32 254,737 25,371 237 273,977 27,296 248 235,412 23,442 226 Sep-32 255,176 25,376 237 274,528 27,309 248 235,745 23,439 226 Oct-32 255,735 25,384 237 275,207 27,325 248 236,190 23,439 226 Nov-32 256,470 25,447 237 276,076 27,401 248 236,797 23,490 226 Dec-32 257,172 25,533 237 276,912 27,501 248 237,371 23,563 226 Jan-33 257,487 25,548 237 277,330 27,525 248 237,588 23,569 226 Feb-33 257,440 25,597 237 277,358 27,586 248 237,472 23,607 226 Mar-33 257,354 25,569 237 277,345 27,563 248 237,321 23,574 226 Apr-33 257,228 25,558 237 277,288 27,559 248 237,132 23,557 226 May-33 257,161 25,532 237 277,295 27,539 248 236,998 23,526 225 Jun-33 256,909 25,530 237 277,104 27,545 248 236,692 23,517 225 Jul-33 257,099 25,524 237 277,386 27,547 248 236,795 23,504 225 Aug-33 257,230 25,520 237 277,605 27,550 248 236,845 23,493 225 Sep-33 257,668 25,524 237 278,157 27,562 248 237,176 23,490 225 Oct-33 258,225 25,531 237 278,836 27,577 248 237,618 23,489 225 Nov-33 258,960 25,595 237 279,707 27,654 248 238,224 23,541 225 Dec-33 259,662 25,681 237 280,545 27,755 248 238,796 23,613 225 Jan-34 259,974 25,696 237 280,961 27,779 249 239,011 23,619 225 Feb-34 259,927 25,743 237 280,989 27,837 249 238,896 23,656 225 Mar-34 259,839 25,717 237 280,973 27,817 249 238,743 23,625 225 Apr-34 259,712 25,706 237 280,914 27,813 249 238,555 23,607 225 May-34 259,645 25,679 237 280,921 27,792 249 238,422 23,575 225 Jun-34 259,392 25,677 237 280,726 27,797 249 238,117 23,566 225 Jul-34 259,580 25,670 237 281,008 27,798 249 238,219 23,553 225 Aug-34 259,709 25,667 237 281,225 27,802 249 238,267 23,543 225 Sep-34 260,146 25,670 237 281,777 27,813 249 238,597 23,539 225 Oct-34 260,703 25,678 237 282,457 27,829 249 239,038 23,539 225 Nov-34 261,436 25,744 237 283,329 27,908 249 239,640 23,593 224 Dec-34 262,137 25,828 237 284,168 28,007 249 240,209 23,663 224 Jan-35 262,449 25,842 237 284,585 28,030 249 240,424 23,669 224 Feb-35 262,400 25,890 237 284,610 28,090 249 240,308 23,706 224 Mar-35 262,312 25,863 237 284,594 28,068 249 240,157 23,674 224 Apr-35 262,184 25,853 237 284,533 28,065 249 239,969 23,658 224 May-35 262,115 25,826 237 284,537 28,044 249 239,835 23,626 224 Jun-35 261,861 25,824 237 284,340 28,049 249 239,530 23,617 224 Jul-35 262,049 25,816 237 284,622 28,048 250 239,632 23,603 224 Aug-35 262,177 25,813 237 284,839 28,053 250 239,680 23,593 224 Sep-35 262,615 25,818 237 285,394 28,066 250 240,010 23,591 224 Oct-35 263,171 25,825 237 286,075 28,081 250 240,449 23,590 224 Nov-35 263,904 25,890 237 286,948 28,159 250 241,048 23,643 224 Dec-35 264,605 25,975 237 287,791 28,259 250 241,617 23,714 224 Washington and Idaho - High Growth Washington and Idaho - Low Growth Washington and Idaho - Expected Growth Avista Corp 2016 Natural Gas IRP Appendices 44 APPENDIX - CHAPTER 2 APPENDIX 2.2: CUSTOMER FORECASTS BY REGION MEDFORD Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Nov-15 52,922 6,658 15 52,922 6,658 15 52,922 6,658 15 Dec-15 53,276 6,675 15 53,276 6,675 15 53,276 6,675 15 Jan-16 53,448 6,720 16 53,632 6,743 16 53,247 6,695 16 Feb-16 53,447 6,748 16 53,658 6,775 16 53,218 6,719 16 Mar-16 53,523 6,747 16 53,761 6,777 16 53,265 6,714 16 Apr-16 53,613 6,725 16 53,877 6,758 16 53,325 6,688 16 May-16 53,668 6,739 16 53,959 6,776 17 53,351 6,699 16 Jun-16 53,657 6,737 16 53,975 6,777 17 53,312 6,694 16 Jul-16 53,552 6,717 16 53,895 6,760 17 53,180 6,670 16 Aug-16 53,460 6,709 16 53,827 6,755 16 53,061 6,659 16 Sep-16 53,356 6,686 16 53,748 6,735 17 52,931 6,633 16 Oct-16 53,517 6,689 16 53,936 6,741 17 53,063 6,632 16 Nov-16 53,818 6,725 16 54,265 6,781 17 53,334 6,664 16 Dec-16 54,124 6,774 16 54,599 6,833 17 53,609 6,710 16 Jan-17 54,379 6,796 16 54,882 6,859 17 53,834 6,728 16 Feb-17 54,432 6,825 16 54,962 6,891 17 53,859 6,753 16 Mar-17 54,533 6,819 16 55,090 6,889 17 53,931 6,744 16 Apr-17 54,648 6,817 16 55,232 6,889 17 54,016 6,738 16 May-17 54,660 6,812 16 55,271 6,888 17 54,000 6,730 16 Jun-17 54,586 6,801 16 55,222 6,880 17 53,899 6,715 16 Jul-17 54,432 6,784 16 55,093 6,866 17 53,719 6,695 16 Aug-17 54,288 6,771 16 54,973 6,856 17 53,549 6,679 16 Sep-17 54,194 6,752 16 54,904 6,840 17 53,428 6,657 16 Oct-17 54,367 6,761 16 55,106 6,853 17 53,571 6,662 16 Nov-17 54,705 6,804 16 55,475 6,900 17 53,875 6,701 16 Dec-17 55,072 6,854 16 55,874 6,954 17 54,208 6,747 16 Jan-18 55,382 6,885 16 56,216 6,989 17 54,485 6,773 16 Feb-18 55,467 6,917 16 56,329 7,024 17 54,540 6,801 16 Mar-18 55,580 6,914 16 56,471 7,025 17 54,622 6,795 16 Apr-18 55,668 6,904 16 56,587 7,018 17 54,680 6,781 16 May-18 55,639 6,902 16 56,585 7,019 17 54,623 6,776 16 Jun-18 55,527 6,890 16 56,498 7,011 17 54,485 6,761 16 Jul-18 55,338 6,868 16 56,333 6,992 17 54,270 6,736 16 Aug-18 55,184 6,855 16 56,204 6,982 17 54,091 6,719 16 Sep-18 55,103 6,836 16 56,148 6,966 17 53,983 6,697 16 Oct-18 55,307 6,845 16 56,383 6,978 17 54,154 6,702 16 Nov-18 55,693 6,890 16 56,805 7,028 17 54,503 6,743 16 Dec-18 56,104 6,944 16 57,251 7,086 17 54,876 6,792 16 Jan-19 56,440 6,974 16 57,622 7,120 17 55,176 6,818 16 Feb-19 56,532 7,007 16 57,744 7,157 17 55,236 6,846 16 Medford - Expected Growth Medford - Low Growth Medford - High Growth Avista Corp 2016 Natural Gas IRP Appendices 45 APPENDIX - CHAPTER 2 APPENDIX 2.2: CUSTOMER FORECASTS BY REGION MEDFORD Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Mar-19 56,629 7,002 16 57,871 7,156 17 55,302 6,838 16 Apr-19 56,686 6,992 16 57,958 7,148 17 55,328 6,824 16 May-19 56,624 6,986 16 57,922 7,146 17 55,238 6,815 16 Jun-19 56,484 6,971 16 57,807 7,134 17 55,073 6,797 16 Jul-19 56,282 6,950 16 57,628 7,116 17 54,847 6,773 16 Aug-19 56,136 6,937 16 57,506 7,106 17 54,676 6,757 16 Sep-19 56,080 6,919 16 57,477 7,091 17 54,592 6,735 16 Oct-19 56,320 6,932 16 57,750 7,108 17 54,797 6,745 16 Nov-19 56,739 6,979 16 58,208 7,160 17 55,176 6,787 16 Dec-19 57,170 7,034 16 58,678 7,220 17 55,566 6,837 16 Jan-20 57,511 7,066 16 59,057 7,256 17 55,868 6,864 16 Feb-20 57,586 7,097 16 59,162 7,291 17 55,911 6,891 16 Mar-20 57,661 7,091 16 59,268 7,289 17 55,954 6,881 16 Apr-20 57,690 7,079 16 59,326 7,279 17 55,953 6,865 16 May-20 57,604 7,071 16 59,267 7,275 17 55,840 6,854 16 Jun-20 57,453 7,056 16 59,140 7,263 17 55,664 6,836 16 Jul-20 57,258 7,035 16 58,967 7,245 17 55,446 6,812 16 Aug-20 57,133 7,024 16 58,867 7,237 17 55,296 6,798 16 Sep-20 57,105 7,008 16 58,867 7,224 17 55,240 6,779 16 Oct-20 57,373 7,022 16 59,172 7,242 17 55,470 6,789 16 Nov-20 57,811 7,071 16 59,652 7,296 17 55,864 6,833 16 Dec-20 58,248 7,126 16 60,132 7,357 17 56,256 6,882 16 Jan-21 58,581 7,157 16 60,505 7,392 17 56,548 6,909 16 Feb-21 58,641 7,187 16 60,596 7,427 17 56,576 6,934 16 Mar-21 58,690 7,180 16 60,676 7,423 17 56,593 6,923 16 Apr-21 58,700 7,166 16 60,716 7,412 17 56,573 6,906 16 May-21 58,606 7,158 16 60,648 7,407 17 56,453 6,895 16 Jun-21 58,460 7,143 16 60,526 7,395 17 56,282 6,877 16 Jul-21 58,264 7,122 16 60,349 7,377 17 56,068 6,854 16 Aug-21 58,143 7,111 16 60,248 7,368 17 55,926 6,840 16 Sep-21 58,120 7,095 16 60,250 7,355 17 55,878 6,821 16 Oct-21 58,386 7,110 16 60,551 7,374 17 56,108 6,833 16 Nov-21 58,812 7,157 16 61,018 7,425 17 56,492 6,875 16 Dec-21 59,225 7,211 16 61,472 7,485 17 56,863 6,923 15 Jan-22 59,526 7,240 16 61,810 7,518 17 57,126 6,948 15 Feb-22 59,550 7,268 16 61,861 7,550 17 57,123 6,972 15 Mar-22 59,567 7,258 16 61,905 7,543 17 57,113 6,959 15 Apr-22 59,552 7,242 16 61,915 7,529 17 57,072 6,940 15 May-22 59,443 7,233 16 61,827 7,523 17 56,942 6,929 15 Jun-22 59,292 7,218 16 61,696 7,511 17 56,771 6,911 15 Medford - Expected Growth Medford - Low Growth Medford - High Growth Avista Corp 2016 Natural Gas IRP Appendices 46 APPENDIX - CHAPTER 2 APPENDIX 2.2: CUSTOMER FORECASTS BY REGION MEDFORD Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Jul-22 59,108 7,198 16 61,529 7,493 17 56,571 6,889 15 Aug-22 58,999 7,187 16 61,440 7,484 17 56,442 6,876 15 Sep-22 58,984 7,173 16 61,449 7,473 17 56,403 6,859 15 Oct-22 59,249 7,187 16 61,749 7,490 17 56,632 6,870 15 Nov-22 59,664 7,234 16 62,207 7,542 17 57,004 6,911 15 Dec-22 60,061 7,287 16 62,645 7,601 17 57,358 6,959 15 Jan-23 60,341 7,314 16 62,962 7,632 17 57,601 6,982 15 Feb-23 60,348 7,340 16 62,995 7,662 17 57,583 7,004 15 Mar-23 60,352 7,330 16 63,024 7,655 17 57,561 6,991 15 Apr-23 60,333 7,314 16 63,029 7,640 17 57,518 6,972 15 May-23 60,229 7,305 16 62,945 7,634 18 57,394 6,961 15 Jun-23 60,086 7,291 16 62,821 7,623 18 57,233 6,945 15 Jul-23 59,915 7,271 16 62,667 7,605 18 57,046 6,923 15 Aug-23 59,817 7,261 16 62,589 7,597 18 56,928 6,910 15 Sep-23 59,804 7,247 16 62,600 7,586 18 56,891 6,894 15 Oct-23 60,065 7,261 16 62,898 7,603 18 57,115 6,904 15 Nov-23 60,471 7,307 16 63,348 7,655 18 57,477 6,945 15 Dec-23 60,855 7,359 16 63,775 7,712 18 57,817 6,992 15 Jan-24 61,124 7,386 16 64,082 7,743 18 58,048 7,014 15 Feb-24 61,124 7,411 16 64,107 7,773 18 58,023 7,035 15 Mar-24 61,129 7,401 16 64,138 7,765 18 58,003 7,022 15 Apr-24 61,116 7,385 16 64,149 7,751 18 57,965 7,004 15 May-24 61,022 7,377 16 64,076 7,746 18 57,851 6,994 15 Jun-24 60,890 7,364 16 63,962 7,736 18 57,702 6,978 15 Jul-24 60,728 7,345 16 63,817 7,719 18 57,523 6,957 15 Aug-24 60,634 7,335 16 63,743 7,711 18 57,410 6,945 15 Sep-24 60,619 7,321 16 63,752 7,699 18 57,371 6,929 15 Oct-24 60,873 7,334 16 64,045 7,716 18 57,587 6,938 15 Nov-24 61,270 7,380 16 64,487 7,768 18 57,938 6,979 15 Dec-24 61,646 7,431 16 64,909 7,824 18 58,268 7,024 15 Jan-25 61,911 7,458 16 65,213 7,856 18 58,494 7,046 15 Feb-25 61,912 7,483 16 65,240 7,885 18 58,470 7,067 15 Mar-25 61,922 7,473 16 65,276 7,878 18 58,454 7,054 15 Apr-25 61,919 7,458 16 65,298 7,865 18 58,426 7,037 15 May-25 61,834 7,451 16 65,234 7,861 18 58,321 7,028 15 Jun-25 61,710 7,438 16 65,129 7,850 18 58,179 7,012 15 Jul-25 61,550 7,419 16 64,985 7,833 18 58,004 6,992 15 Aug-25 61,453 7,409 16 64,908 7,826 18 57,888 6,979 15 Sep-25 61,432 7,394 16 64,911 7,813 18 57,844 6,962 15 Oct-25 61,677 7,407 16 65,195 7,829 18 58,050 6,971 15 Medford - Expected Growth Medford - Low Growth Medford - High Growth Avista Corp 2016 Natural Gas IRP Appendices 47 APPENDIX - CHAPTER 2 APPENDIX 2.2: CUSTOMER FORECASTS BY REGION MEDFORD Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Nov-25 62,066 7,453 16 65,631 7,881 18 58,392 7,012 15 Dec-25 62,436 7,503 16 66,048 7,937 18 58,715 7,056 15 Jan-26 62,700 7,530 16 66,353 7,969 18 58,939 7,078 15 Feb-26 62,704 7,556 16 66,382 7,999 18 58,918 7,100 15 Mar-26 62,720 7,546 16 66,425 7,992 18 58,908 7,087 15 Apr-26 62,723 7,531 16 66,454 7,978 18 58,886 7,070 15 May-26 62,643 7,524 16 66,394 7,975 18 58,786 7,061 15 Jun-26 62,520 7,511 16 66,290 7,964 18 58,646 7,046 15 Jul-26 62,358 7,492 16 66,143 7,947 18 58,470 7,025 15 Aug-26 62,255 7,482 16 66,059 7,939 18 58,349 7,013 15 Sep-26 62,227 7,467 16 66,054 7,926 18 58,299 6,996 15 Oct-26 62,466 7,479 16 66,333 7,942 18 58,499 7,004 15 Nov-26 62,849 7,524 16 66,765 7,993 18 58,833 7,043 15 Dec-26 63,219 7,575 16 67,183 8,050 18 59,155 7,088 15 Jan-27 63,484 7,601 16 67,490 8,081 18 59,379 7,109 15 Feb-27 63,492 7,628 16 67,524 8,112 18 59,361 7,132 15 Mar-27 63,513 7,618 16 67,572 8,105 18 59,357 7,119 15 Apr-27 63,519 7,604 16 67,604 8,092 18 59,338 7,103 15 May-27 63,440 7,597 16 67,545 8,089 18 59,239 7,094 15 Jun-27 63,316 7,584 16 67,439 8,078 18 59,099 7,079 15 Jul-27 63,148 7,564 16 67,285 8,059 18 58,919 7,057 15 Aug-27 63,038 7,554 16 67,192 8,052 18 58,793 7,045 15 Sep-27 63,003 7,538 16 67,179 8,038 18 58,736 7,028 15 Oct-27 63,237 7,550 16 67,454 8,053 18 58,931 7,036 15 Nov-27 63,618 7,595 16 67,885 8,104 18 59,262 7,075 15 Dec-27 63,987 7,646 16 68,304 8,162 18 59,582 7,120 15 Jan-28 64,255 7,672 16 68,615 8,193 18 59,808 7,141 15 Feb-28 64,265 7,699 16 68,651 8,224 18 59,793 7,163 15 Mar-28 64,288 7,690 16 68,701 8,218 18 59,790 7,152 15 Apr-28 64,294 7,675 16 68,733 8,204 18 59,772 7,135 15 May-28 64,212 7,668 16 68,670 8,200 18 59,672 7,126 15 Jun-28 64,083 7,655 16 68,557 8,189 18 59,528 7,111 15 Jul-28 63,908 7,635 16 68,394 8,171 18 59,343 7,090 15 Aug-28 63,792 7,624 16 68,294 8,162 18 59,212 7,077 14 Sep-28 63,752 7,607 16 68,276 8,147 18 59,152 7,058 14 Oct-28 63,982 7,619 16 68,546 8,163 18 59,342 7,067 14 Nov-28 64,362 7,664 16 68,978 8,214 18 59,672 7,106 14 Dec-28 64,731 7,715 16 69,398 8,271 18 59,991 7,150 14 Jan-29 65,000 7,741 16 69,711 8,302 18 60,217 7,171 14 Feb-29 65,010 7,768 16 69,747 8,334 18 60,203 7,194 14 Medford - Expected Growth Medford - Low Growth Medford - High Growth Avista Corp 2016 Natural Gas IRP Appendices 48 APPENDIX - CHAPTER 2 APPENDIX 2.2: CUSTOMER FORECASTS BY REGION MEDFORD Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Mar-29 65,031 7,758 16 69,794 8,326 18 60,199 7,182 14 Apr-29 65,034 7,744 16 69,822 8,314 18 60,178 7,165 14 May-29 64,948 7,736 16 69,754 8,308 18 60,076 7,156 14 Jun-29 64,813 7,723 16 69,634 8,297 18 59,927 7,141 14 Jul-29 64,633 7,702 16 69,464 8,278 18 59,739 7,119 14 Aug-29 64,512 7,691 16 69,358 8,269 18 59,604 7,106 14 Sep-29 64,469 7,675 16 69,336 8,254 18 59,542 7,088 14 Oct-29 64,699 7,687 16 69,607 8,270 18 59,732 7,097 14 Nov-29 65,079 7,731 16 70,040 8,320 18 60,061 7,135 14 Dec-29 65,450 7,782 16 70,463 8,378 18 60,380 7,179 14 Jan-30 65,718 7,809 16 70,776 8,410 19 60,605 7,201 14 Feb-30 65,728 7,835 16 70,811 8,441 19 60,591 7,223 14 Mar-30 65,747 7,826 16 70,856 8,434 19 60,586 7,212 14 Apr-30 65,746 7,811 16 70,880 8,420 19 60,562 7,195 14 May-30 65,655 7,803 16 70,806 8,415 19 60,456 7,185 14 Jun-30 65,515 7,789 16 70,679 8,403 19 60,304 7,169 14 Jul-30 65,331 7,768 16 70,504 8,383 19 60,113 7,148 14 Aug-30 65,206 7,757 16 70,392 8,374 19 59,977 7,135 14 Sep-30 65,161 7,740 16 70,367 8,358 19 59,914 7,117 14 Oct-30 65,389 7,752 16 70,636 8,374 19 60,102 7,125 14 Nov-30 65,768 7,796 16 71,069 8,424 19 60,428 7,163 14 Dec-30 66,137 7,847 16 71,492 8,482 19 60,745 7,207 14 Jan-31 66,404 7,874 16 71,804 8,514 19 60,969 7,230 14 Feb-31 66,410 7,900 16 71,834 8,545 19 60,952 7,251 14 Mar-31 66,425 7,890 16 71,874 8,537 19 60,944 7,239 14 Apr-31 66,419 7,875 16 71,891 8,523 19 60,917 7,222 14 May-31 66,322 7,867 16 71,810 8,518 19 60,806 7,213 14 Jun-31 66,177 7,852 16 71,676 8,505 19 60,651 7,196 14 Jul-31 65,990 7,831 16 71,497 8,484 19 60,459 7,175 14 Aug-31 65,863 7,820 16 71,382 8,475 19 60,322 7,162 14 Sep-31 65,816 7,803 16 71,353 8,459 19 60,258 7,144 14 Oct-31 66,043 7,815 16 71,622 8,475 19 60,445 7,153 14 Nov-31 66,421 7,859 16 72,055 8,526 19 60,770 7,190 14 Dec-31 66,788 7,910 16 72,476 8,584 19 61,084 7,234 14 Jan-32 67,052 7,936 16 72,786 8,615 19 61,304 7,256 14 Feb-32 67,054 7,962 16 72,811 8,646 19 61,285 7,277 14 Mar-32 67,064 7,952 16 72,845 8,637 19 61,273 7,265 14 Apr-32 67,053 7,936 16 72,856 8,622 19 61,242 7,248 14 May-32 66,953 7,928 16 72,770 8,617 19 61,129 7,238 14 Jun-32 66,805 7,913 16 72,633 8,603 19 60,973 7,222 14 Jul-32 66,615 7,892 16 72,448 8,583 19 60,779 7,201 14 Medford - Expected Growth Medford - Low Growth Medford - High Growth Avista Corp 2016 Natural Gas IRP Appendices 49 APPENDIX - CHAPTER 2 APPENDIX 2.2: CUSTOMER FORECASTS BY REGION MEDFORD Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Aug-32 66,487 7,881 16 72,331 8,574 19 60,642 7,188 14 Sep-32 66,439 7,864 16 72,301 8,558 19 60,578 7,170 14 Oct-32 66,665 7,875 16 72,569 8,572 19 60,764 7,178 14 Nov-32 67,041 7,920 16 73,001 8,624 19 61,086 7,217 14 Dec-32 67,406 7,970 16 73,421 8,681 19 61,398 7,260 14 Jan-33 67,667 7,996 16 73,728 8,712 19 61,615 7,281 14 Feb-33 67,666 8,022 16 73,749 8,743 19 61,594 7,302 14 Mar-33 67,672 8,012 16 73,778 8,735 19 61,579 7,291 14 Apr-33 67,658 7,996 16 73,786 8,720 19 61,545 7,273 14 May-33 67,554 7,987 16 73,695 8,713 19 61,430 7,263 14 Jun-33 67,404 7,972 16 73,554 8,699 19 61,273 7,247 14 Jul-33 67,213 7,951 16 73,367 8,679 19 61,080 7,225 14 Aug-33 67,084 7,940 16 73,248 8,670 19 60,943 7,213 14 Sep-33 67,035 7,923 16 73,216 8,654 19 60,879 7,195 14 Oct-33 67,259 7,934 16 73,483 8,668 19 61,062 7,203 14 Nov-33 67,634 7,978 16 73,915 8,719 19 61,383 7,241 14 Dec-33 67,996 8,029 16 74,332 8,777 19 61,692 7,285 14 Jan-34 68,253 8,054 16 74,635 8,807 19 61,905 7,305 14 Feb-34 68,249 8,080 16 74,653 8,838 19 61,881 7,326 14 Mar-34 68,252 8,069 16 74,679 8,829 19 61,864 7,314 14 Apr-34 68,235 8,054 16 74,682 8,814 19 61,828 7,297 14 May-34 68,130 8,045 16 74,589 8,808 19 61,713 7,287 14 Jun-34 67,978 8,030 16 74,445 8,794 19 61,555 7,271 14 Jul-34 67,786 8,009 16 74,256 8,773 19 61,362 7,250 14 Aug-34 67,655 7,997 16 74,134 8,763 19 61,225 7,237 14 Sep-34 67,605 7,980 16 74,100 8,747 19 61,160 7,219 14 Oct-34 67,827 7,991 16 74,365 8,761 19 61,342 7,227 14 Nov-34 68,199 8,035 16 74,795 8,812 19 61,659 7,264 14 Dec-34 68,558 8,085 16 75,210 8,869 19 61,964 7,307 14 Jan-35 68,813 8,111 16 75,511 8,901 19 62,175 7,329 14 Feb-35 68,806 8,136 16 75,525 8,931 19 62,149 7,349 14 Mar-35 68,806 8,125 16 75,547 8,921 19 62,130 7,337 14 Apr-35 68,788 8,109 16 75,549 8,905 19 62,094 7,319 13 May-35 68,680 8,101 16 75,452 8,900 19 61,977 7,310 13 Jun-35 68,527 8,085 16 75,306 8,885 19 61,820 7,294 13 Jul-35 68,335 8,064 16 75,116 8,864 19 61,627 7,272 13 Aug-35 68,205 8,053 16 74,994 8,855 19 61,491 7,260 13 Sep-35 68,154 8,035 16 74,959 8,837 19 61,426 7,242 13 Oct-35 68,375 8,047 16 75,224 8,853 19 61,606 7,250 13 Nov-35 68,746 8,091 16 75,653 8,904 19 61,921 7,288 13 Dec-35 69,104 8,141 16 76,069 8,962 19 62,225 7,331 13 Medford - Expected Growth Medford - Low Growth Medford - High Growth Avista Corp 2016 Natural Gas IRP Appendices 50 APPENDIX - CHAPTER 2 APPENDIX 2.2: CUSTOMER FORECASTS BY REGION ROSEBURG Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Nov-15 13,361 2,132 2 13,361 2,132 2 13,361 2,132 2 Dec-15 13,503 2,159 2 13,503 2,159 2 13,503 2,159 2 Jan-16 13,582 2,157 2 13,603 2,161 2 13,565 2,154 2 Feb-16 13,555 2,163 2 13,579 2,167 2 13,536 2,160 2 Mar-16 13,559 2,173 2 13,586 2,178 2 13,537 2,170 2 Apr-16 13,544 2,154 2 13,574 2,159 2 13,520 2,150 2 May-16 13,515 2,154 2 13,548 2,159 2 13,488 2,150 2 Jun-16 13,445 2,146 2 13,481 2,152 2 13,416 2,142 2 Jul-16 13,386 2,141 2 13,425 2,147 2 13,355 2,136 2 Aug-16 13,333 2,130 2 13,376 2,137 2 13,299 2,125 2 Sep-16 13,329 2,130 2 13,375 2,138 2 13,292 2,124 2 Oct-16 13,422 2,135 2 13,472 2,143 2 13,382 2,129 2 Nov-16 13,579 2,144 2 13,633 2,153 2 13,536 2,137 2 Dec-16 13,693 2,162 2 13,751 2,171 2 13,647 2,155 2 Jan-17 13,726 2,162 2 13,788 2,172 2 13,677 2,154 2 Feb-17 13,707 2,166 2 13,772 2,176 2 13,655 2,158 2 Mar-17 13,705 2,176 2 13,774 2,187 2 13,650 2,167 2 Apr-17 13,698 2,162 2 13,770 2,174 2 13,641 2,153 2 May-17 13,657 2,159 2 13,732 2,171 2 13,597 2,150 2 Jun-17 13,588 2,155 2 13,666 2,168 2 13,525 2,145 2 Jul-17 13,533 2,145 2 13,615 2,158 2 13,468 2,135 2 Aug-17 13,464 2,138 2 13,550 2,152 2 13,396 2,127 2 Sep-17 13,471 2,138 2 13,560 2,152 2 13,400 2,127 2 Oct-17 13,565 2,137 2 13,659 2,152 2 13,490 2,125 2 Nov-17 13,712 2,152 2 13,811 2,168 2 13,633 2,140 2 Dec-17 13,840 2,167 2 13,944 2,183 2 13,757 2,154 2 Jan-18 13,874 2,164 2 13,982 2,181 2 13,788 2,151 2 Feb-18 13,859 2,171 2 13,971 2,189 2 13,770 2,157 2 Mar-18 13,861 2,178 2 13,977 2,196 2 13,769 2,164 2 Apr-18 13,848 2,166 2 13,968 2,185 2 13,753 2,151 2 May-18 13,814 2,163 2 13,938 2,183 2 13,716 2,148 2 Jun-18 13,741 2,158 2 13,868 2,178 2 13,640 2,142 2 Jul-18 13,682 2,151 2 13,813 2,172 2 13,578 2,135 2 Aug-18 13,620 2,141 2 13,754 2,162 2 13,513 2,124 2 Sep-18 13,623 2,144 2 13,761 2,166 2 13,513 2,127 2 Oct-18 13,715 2,143 2 13,858 2,166 2 13,601 2,125 2 Nov-18 13,865 2,155 2 14,014 2,178 2 13,746 2,137 2 Dec-18 13,992 2,173 2 14,147 2,197 2 13,869 2,154 2 Jan-19 14,030 2,169 2 14,190 2,194 2 13,903 2,150 2 Feb-19 14,016 2,176 2 14,180 2,202 2 13,886 2,156 2 Roseburg - Expected Growth Roseburg - Low Growth Roseburg - High Growth Avista Corp 2016 Natural Gas IRP Appendices 51 APPENDIX - CHAPTER 2 APPENDIX 2.2: CUSTOMER FORECASTS BY REGION ROSEBURG Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Mar-19 14,017 2,184 2 14,185 2,210 2 13,884 2,163 2 Apr-19 14,008 2,170 2 14,180 2,197 2 13,872 2,149 2 May-19 13,970 2,168 2 14,146 2,195 2 13,831 2,147 2 Jun-19 13,898 2,163 2 14,077 2,191 2 13,756 2,141 2 Jul-19 13,842 2,155 2 14,025 2,184 2 13,697 2,133 2 Aug-19 13,777 2,147 2 13,963 2,176 2 13,629 2,124 2 Sep-19 13,781 2,147 2 13,972 2,177 2 13,630 2,124 2 Oct-19 13,873 2,148 2 14,069 2,179 2 13,717 2,124 2 Nov-19 14,023 2,160 2 14,226 2,191 2 13,862 2,135 2 Dec-19 14,153 2,177 2 14,362 2,209 2 13,987 2,152 2 Jan-20 14,190 2,174 2 14,405 2,207 2 14,020 2,148 2 Feb-20 14,177 2,180 2 14,396 2,214 2 14,004 2,154 2 Mar-20 14,180 2,189 2 14,403 2,224 2 14,003 2,162 2 Apr-20 14,169 2,175 2 14,397 2,210 2 13,989 2,148 2 May-20 14,133 2,173 2 14,365 2,209 2 13,950 2,145 2 Jun-20 14,062 2,168 2 14,297 2,204 2 13,876 2,140 2 Jul-20 14,005 2,160 2 14,244 2,197 2 13,816 2,131 2 Aug-20 13,941 2,151 2 14,183 2,189 2 13,750 2,122 2 Sep-20 13,945 2,152 2 14,192 2,190 2 13,750 2,122 2 Oct-20 14,037 2,152 2 14,290 2,191 2 13,837 2,122 2 Nov-20 14,188 2,165 2 14,449 2,205 2 13,982 2,134 2 Dec-20 14,318 2,182 2 14,586 2,223 2 14,107 2,150 2 Jan-21 14,357 2,179 2 14,630 2,221 2 14,141 2,146 2 Feb-21 14,344 2,185 2 14,622 2,228 2 14,125 2,152 2 Mar-21 14,347 2,193 2 14,630 2,236 2 14,124 2,159 2 Apr-21 14,337 2,180 2 14,624 2,224 2 14,110 2,146 2 May-21 14,301 2,177 2 14,592 2,222 2 14,071 2,142 2 Jun-21 14,230 2,172 2 14,525 2,217 2 13,998 2,137 2 Jul-21 14,174 2,165 2 14,472 2,211 2 13,939 2,129 2 Aug-21 14,110 2,156 2 14,412 2,202 2 13,872 2,120 2 Sep-21 14,113 2,157 2 14,420 2,204 2 13,872 2,120 2 Oct-21 14,206 2,157 2 14,519 2,205 2 13,959 2,120 2 Nov-21 14,357 2,170 2 14,679 2,219 2 14,104 2,132 2 Dec-21 14,487 2,187 2 14,816 2,237 2 14,228 2,148 2 Jan-22 14,526 2,183 2 14,861 2,234 2 14,263 2,144 2 Feb-22 14,514 2,190 2 14,854 2,241 2 14,247 2,150 2 Mar-22 14,516 2,198 2 14,861 2,250 2 14,245 2,157 2 Apr-22 14,507 2,184 2 14,856 2,237 2 14,233 2,143 2 May-22 14,471 2,182 2 14,825 2,235 2 14,193 2,140 2 Jun-22 14,400 2,177 2 14,757 2,231 2 14,120 2,135 2 Roseburg - Expected Growth Roseburg - Low Growth Roseburg - High Growth Avista Corp 2016 Natural Gas IRP Appendices 52 APPENDIX - CHAPTER 2 APPENDIX 2.2: CUSTOMER FORECASTS BY REGION ROSEBURG Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Jul-22 14,344 2,169 2 14,704 2,224 2 14,061 2,126 2 Aug-22 14,280 2,161 2 14,643 2,216 2 13,995 2,118 2 Sep-22 14,284 2,162 2 14,652 2,218 2 13,995 2,118 2 Oct-22 14,377 2,162 2 14,753 2,219 2 14,082 2,118 2 Nov-22 14,528 2,174 2 14,913 2,232 2 14,227 2,129 2 Dec-22 14,658 2,191 2 15,051 2,250 2 14,350 2,145 2 Jan-23 14,698 2,188 2 15,097 2,248 2 14,385 2,142 2 Feb-23 14,685 2,195 2 15,089 2,256 2 14,369 2,148 2 Mar-23 14,688 2,203 2 15,097 2,265 2 14,368 2,155 2 Apr-23 14,679 2,189 2 15,093 2,251 2 14,355 2,141 2 May-23 14,643 2,187 2 15,061 2,250 2 14,316 2,138 2 Jun-23 14,573 2,182 2 14,994 2,245 2 14,244 2,133 2 Jul-23 14,516 2,174 2 14,940 2,238 2 14,184 2,125 2 Aug-23 14,452 2,165 2 14,879 2,229 2 14,118 2,115 2 Sep-23 14,456 2,166 2 14,888 2,231 2 14,119 2,116 2 Oct-23 14,548 2,167 2 14,987 2,233 2 14,205 2,116 2 Nov-23 14,699 2,179 2 15,148 2,246 2 14,348 2,127 2 Dec-23 14,829 2,196 2 15,287 2,264 2 14,472 2,143 2 Jan-24 14,868 2,193 2 15,332 2,262 2 14,506 2,140 2 Feb-24 14,856 2,200 2 15,324 2,270 2 14,490 2,146 2 Mar-24 14,858 2,208 2 15,331 2,279 2 14,489 2,153 2 Apr-24 14,849 2,194 2 15,327 2,265 2 14,476 2,139 2 May-24 14,813 2,192 2 15,295 2,263 2 14,437 2,137 2 Jun-24 14,742 2,186 2 15,226 2,258 2 14,364 2,130 2 Jul-24 14,685 2,179 2 15,172 2,251 2 14,305 2,123 2 Aug-24 14,621 2,170 2 15,111 2,243 2 14,239 2,114 2 Sep-24 14,624 2,171 2 15,119 2,245 2 14,239 2,114 2 Oct-24 14,716 2,171 2 15,218 2,245 2 14,325 2,113 2 Nov-24 14,867 2,184 2 15,379 2,259 2 14,468 2,126 2 Dec-24 14,996 2,201 2 15,518 2,278 2 14,590 2,142 2 Jan-25 15,035 2,198 2 15,563 2,275 2 14,625 2,138 2 Feb-25 15,022 2,204 2 15,554 2,282 2 14,608 2,143 2 Mar-25 15,024 2,212 2 15,561 2,291 2 14,607 2,151 2 Apr-25 15,015 2,199 2 15,556 2,278 2 14,594 2,138 2 May-25 14,978 2,196 2 15,523 2,276 2 14,555 2,134 2 Jun-25 14,907 2,191 2 15,454 2,272 2 14,482 2,129 2 Jul-25 14,850 2,184 2 15,399 2,265 2 14,423 2,121 2 Aug-25 14,785 2,175 2 15,337 2,256 2 14,357 2,112 2 Sep-25 14,788 2,176 2 15,344 2,258 2 14,356 2,113 2 Oct-25 14,880 2,176 2 15,444 2,259 2 14,442 2,112 2 Roseburg - Expected Growth Roseburg - Low Growth Roseburg - High Growth Avista Corp 2016 Natural Gas IRP Appendices 53 APPENDIX - CHAPTER 2 APPENDIX 2.2: CUSTOMER FORECASTS BY REGION ROSEBURG Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Nov-25 15,030 2,189 2 15,605 2,273 2 14,584 2,124 2 Dec-25 15,160 2,206 2 15,744 2,291 3 14,707 2,140 2 Jan-26 15,198 2,202 2 15,789 2,288 3 14,740 2,136 1 Feb-26 15,185 2,209 2 15,780 2,296 3 14,724 2,142 1 Mar-26 15,187 2,217 2 15,786 2,305 3 14,722 2,149 1 Apr-26 15,177 2,203 2 15,781 2,291 3 14,709 2,135 1 May-26 15,140 2,201 2 15,747 2,289 3 14,670 2,133 1 Jun-26 15,069 2,196 2 15,678 2,285 3 14,598 2,127 1 Jul-26 15,012 2,188 2 15,623 2,277 3 14,539 2,119 1 Aug-26 14,948 2,180 2 15,561 2,270 3 14,473 2,111 1 Sep-26 14,951 2,181 2 15,569 2,271 3 14,473 2,111 1 Oct-26 15,044 2,181 2 15,671 2,272 3 14,559 2,111 1 Nov-26 15,194 2,193 2 15,832 2,285 3 14,701 2,122 1 Dec-26 15,324 2,210 2 15,973 2,304 3 14,823 2,138 1 Jan-27 15,363 2,207 2 16,018 2,301 3 14,857 2,134 1 Feb-27 15,350 2,214 2 16,009 2,309 3 14,841 2,141 1 Mar-27 15,353 2,222 2 16,018 2,318 3 14,840 2,148 1 Apr-27 15,343 2,208 2 16,012 2,304 3 14,826 2,134 1 May-27 15,307 2,206 2 15,979 2,303 3 14,788 2,131 1 Jun-27 15,235 2,201 2 15,909 2,299 3 14,715 2,126 1 Jul-27 15,179 2,193 2 15,855 2,291 3 14,657 2,118 1 Aug-27 15,114 2,184 2 15,792 2,282 3 14,591 2,109 1 Sep-27 15,117 2,185 2 15,800 2,284 3 14,590 2,109 1 Oct-27 15,210 2,186 2 15,902 2,286 3 14,676 2,109 1 Nov-27 15,360 2,198 2 16,064 2,299 3 14,818 2,121 1 Dec-27 15,490 2,215 2 16,205 2,317 3 14,939 2,136 1 Jan-28 15,529 2,212 2 16,251 2,315 3 14,973 2,133 1 Feb-28 15,516 2,218 2 16,242 2,322 3 14,957 2,138 1 Mar-28 15,518 2,226 2 16,249 2,331 3 14,955 2,145 1 Apr-28 15,508 2,213 2 16,243 2,318 3 14,942 2,132 1 May-28 15,472 2,211 2 16,210 2,317 3 14,904 2,130 1 Jun-28 15,401 2,205 2 16,141 2,311 3 14,832 2,124 1 Jul-28 15,344 2,198 2 16,086 2,304 3 14,773 2,116 1 Aug-28 15,279 2,189 2 16,022 2,296 3 14,707 2,107 1 Sep-28 15,282 2,190 2 16,030 2,297 3 14,707 2,108 1 Oct-28 15,374 2,190 2 16,131 2,298 3 14,792 2,107 1 Nov-28 15,524 2,203 2 16,294 2,312 3 14,933 2,119 1 Dec-28 15,654 2,220 2 16,435 2,331 3 15,054 2,135 1 Jan-29 15,692 2,216 2 16,480 2,327 3 15,087 2,131 1 Feb-29 15,679 2,223 2 16,471 2,335 3 15,071 2,137 1 Roseburg - Expected Growth Roseburg - Low Growth Roseburg - High Growth Avista Corp 2016 Natural Gas IRP Appendices 54 APPENDIX - CHAPTER 2 APPENDIX 2.2: CUSTOMER FORECASTS BY REGION ROSEBURG Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Mar-29 15,681 2,231 2 16,478 2,345 3 15,070 2,144 1 Apr-29 15,671 2,217 2 16,472 2,330 3 15,057 2,130 1 May-29 15,635 2,215 2 16,439 2,329 3 15,019 2,128 1 Jun-29 15,563 2,210 2 16,368 2,324 3 14,946 2,123 1 Jul-29 15,506 2,203 2 16,312 2,318 3 14,888 2,115 1 Aug-29 15,441 2,194 2 16,249 2,309 3 14,822 2,106 1 Sep-29 15,443 2,195 2 16,255 2,311 3 14,821 2,107 1 Oct-29 15,535 2,195 2 16,357 2,311 3 14,906 2,106 1 Nov-29 15,685 2,208 2 16,519 2,326 3 15,046 2,118 1 Dec-29 15,814 2,224 2 16,660 2,343 3 15,167 2,133 1 Jan-30 15,852 2,221 2 16,704 2,341 3 15,200 2,130 1 Feb-30 15,838 2,228 2 16,694 2,349 3 15,183 2,136 1 Mar-30 15,840 2,236 2 16,701 2,358 3 15,181 2,143 1 Apr-30 15,830 2,222 2 16,695 2,344 3 15,168 2,129 1 May-30 15,793 2,220 2 16,661 2,342 3 15,130 2,127 1 Jun-30 15,721 2,215 2 16,589 2,338 3 15,057 2,122 1 Jul-30 15,663 2,207 2 16,532 2,330 3 14,999 2,114 1 Aug-30 15,596 2,198 2 16,465 2,321 3 14,932 2,105 1 Sep-30 15,598 2,200 2 16,471 2,323 3 14,931 2,106 1 Oct-30 15,688 2,200 2 16,570 2,324 3 15,014 2,106 1 Nov-30 15,837 2,212 2 16,732 2,337 3 15,154 2,117 1 Dec-30 15,965 2,229 2 16,871 2,356 3 15,273 2,133 1 Jan-31 16,002 2,226 2 16,914 2,353 3 15,306 2,129 1 Feb-31 15,987 2,233 2 16,903 2,361 3 15,288 2,136 1 Mar-31 15,988 2,241 2 16,908 2,370 3 15,286 2,143 1 Apr-31 15,976 2,227 2 16,899 2,356 3 15,272 2,129 1 May-31 15,938 2,225 2 16,863 2,354 3 15,233 2,127 1 Jun-31 15,865 2,220 2 16,790 2,350 3 15,160 2,122 1 Jul-31 15,807 2,212 2 16,732 2,342 3 15,102 2,113 1 Aug-31 15,740 2,203 2 16,665 2,333 3 15,035 2,105 1 Sep-31 15,741 2,204 2 16,670 2,334 3 15,033 2,105 1 Oct-31 15,831 2,205 2 16,769 2,336 3 15,116 2,106 1 Nov-31 15,980 2,217 2 16,931 2,349 3 15,256 2,117 1 Dec-31 16,108 2,234 2 17,070 2,368 3 15,375 2,133 1 Jan-32 16,144 2,231 2 17,112 2,365 3 15,407 2,129 1 Feb-32 16,129 2,237 2 17,100 2,372 3 15,390 2,135 1 Mar-32 16,129 2,245 2 17,104 2,381 3 15,387 2,142 1 Apr-32 16,118 2,232 2 17,096 2,368 3 15,374 2,129 1 May-32 16,079 2,229 2 17,059 2,365 3 15,334 2,126 1 Jun-32 16,006 2,224 2 16,985 2,360 3 15,261 2,121 1 Jul-32 15,947 2,217 2 16,927 2,353 3 15,202 2,114 1 Roseburg - Expected Growth Roseburg - Low Growth Roseburg - High Growth Avista Corp 2016 Natural Gas IRP Appendices 55 APPENDIX - CHAPTER 2 APPENDIX 2.2: CUSTOMER FORECASTS BY REGION ROSEBURG Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Aug-32 15,880 2,208 2 16,859 2,344 3 15,136 2,105 1 Sep-32 15,881 2,209 2 16,864 2,346 3 15,134 2,105 1 Oct-32 15,971 2,209 2 16,963 2,346 3 15,217 2,105 1 Nov-32 16,119 2,222 2 17,124 2,361 3 15,355 2,117 1 Dec-32 16,247 2,239 2 17,264 2,379 3 15,474 2,133 1 Jan-33 16,283 2,235 2 17,306 2,376 3 15,506 2,129 1 Feb-33 16,268 2,242 2 17,294 2,384 3 15,489 2,135 1 Mar-33 16,268 2,250 2 17,298 2,393 3 15,486 2,142 1 Apr-33 16,256 2,236 2 17,289 2,378 3 15,472 2,128 1 May-33 16,218 2,234 2 17,252 2,377 3 15,433 2,126 1 Jun-33 16,144 2,229 2 17,177 2,372 3 15,360 2,121 1 Jul-33 16,085 2,221 2 17,118 2,364 3 15,301 2,113 1 Aug-33 16,018 2,213 2 17,051 2,356 3 15,235 2,105 1 Sep-33 16,019 2,214 2 17,056 2,357 3 15,233 2,106 1 Oct-33 16,109 2,214 2 17,155 2,358 3 15,316 2,105 1 Nov-33 16,257 2,226 2 17,316 2,371 3 15,454 2,116 1 Dec-33 16,384 2,243 2 17,455 2,390 3 15,572 2,132 1 Jan-34 16,421 2,240 2 17,499 2,387 3 15,605 2,129 1 Feb-34 16,405 2,247 2 17,485 2,395 3 15,587 2,135 1 Mar-34 16,405 2,255 2 17,489 2,404 3 15,584 2,142 1 Apr-34 16,393 2,241 2 17,480 2,390 3 15,570 2,129 1 May-34 16,354 2,239 2 17,442 2,388 3 15,530 2,126 1 Jun-34 16,281 2,234 2 17,368 2,383 3 15,458 2,121 1 Jul-34 16,221 2,226 2 17,308 2,375 3 15,399 2,113 1 Aug-34 16,155 2,217 2 17,241 2,366 3 15,333 2,104 1 Sep-34 16,155 2,218 2 17,245 2,368 3 15,331 2,105 1 Oct-34 16,245 2,219 2 17,344 2,369 3 15,414 2,106 1 Nov-34 16,393 2,231 2 17,506 2,383 3 15,551 2,117 1 Dec-34 16,520 2,248 2 17,645 2,401 3 15,669 2,132 1 Jan-35 16,556 2,245 2 17,688 2,399 3 15,701 2,129 1 Feb-35 16,541 2,251 2 17,675 2,406 3 15,684 2,135 1 Mar-35 16,541 2,260 2 17,679 2,416 3 15,681 2,143 1 Apr-35 16,528 2,246 2 17,669 2,401 3 15,666 2,129 1 May-35 16,490 2,244 2 17,632 2,400 3 15,628 2,127 1 Jun-35 16,416 2,238 2 17,557 2,394 3 15,555 2,121 1 Jul-35 16,357 2,231 2 17,497 2,387 3 15,496 2,114 1 Aug-35 16,290 2,222 2 17,429 2,378 3 15,430 2,105 1 Sep-35 16,290 2,223 2 17,433 2,379 3 15,428 2,105 1 Oct-35 16,380 2,223 2 17,533 2,380 3 15,510 2,105 1 Nov-35 16,528 2,236 2 17,695 2,394 3 15,648 2,117 1 Dec-35 16,655 2,253 2 17,834 2,413 3 15,766 2,133 1 Roseburg - Expected Growth Roseburg - Low Growth Roseburg - High Growth Avista Corp 2016 Natural Gas IRP Appendices 56 APPENDIX - CHAPTER 2 APPENDIX 2.2: CUSTOMER FORECASTS BY REGION KLAMATH FALLS Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Nov-15 14,242 1,689 7 14,242 1,689 7 14,242 1,689 7 Dec-15 14,380 1,707 7 14,380 1,707 7 14,380 1,707 7 Jan-16 14,409 1,708 8 14,409 1,708 8 14,409 1,708 8 Feb-16 14,448 1,720 8 14,448 1,720 8 14,448 1,720 8 Mar-16 14,438 1,715 8 14,438 1,715 8 14,438 1,715 8 Apr-16 14,445 1,707 8 14,445 1,707 8 14,445 1,707 8 May-16 14,427 1,701 8 14,427 1,701 8 14,427 1,701 8 Jun-16 14,333 1,700 8 14,333 1,700 8 14,333 1,700 8 Jul-16 14,255 1,695 8 14,259 1,695 8 14,251 1,694 8 Aug-16 14,172 1,690 8 14,180 1,690 8 14,163 1,688 8 Sep-16 14,165 1,688 8 14,177 1,689 8 14,152 1,686 8 Oct-16 14,302 1,688 8 14,318 1,689 8 14,284 1,685 8 Nov-16 14,440 1,703 8 14,460 1,705 8 14,417 1,700 8 Dec-16 14,560 1,715 8 14,584 1,717 8 14,532 1,711 8 Jan-17 14,630 1,728 8 14,658 1,731 8 14,598 1,724 8 Feb-17 14,657 1,730 8 14,689 1,733 8 14,620 1,725 8 Mar-17 14,654 1,727 8 14,690 1,731 8 14,612 1,722 8 Apr-17 14,634 1,721 8 14,674 1,725 8 14,588 1,715 8 May-17 14,599 1,719 8 14,643 1,724 8 14,548 1,713 8 Jun-17 14,510 1,715 8 14,558 1,720 8 14,455 1,708 8 Jul-17 14,425 1,708 8 14,477 1,714 8 14,365 1,700 8 Aug-17 14,348 1,702 8 14,404 1,708 8 14,284 1,694 8 Sep-17 14,352 1,700 8 14,413 1,707 8 14,282 1,691 8 Oct-17 14,499 1,705 8 14,565 1,712 8 14,423 1,696 8 Nov-17 14,649 1,719 8 14,721 1,727 8 14,567 1,709 8 Dec-17 14,772 1,729 8 14,849 1,738 8 14,684 1,718 8 Jan-18 14,842 1,742 8 14,924 1,751 8 14,749 1,731 8 Feb-18 14,868 1,744 8 14,955 1,754 8 14,769 1,732 8 Mar-18 14,860 1,743 8 14,951 1,753 8 14,756 1,730 8 Apr-18 14,835 1,741 8 14,931 1,752 8 14,726 1,728 8 May-18 14,798 1,735 8 14,898 1,746 8 14,684 1,721 8 Jun-18 14,708 1,729 8 14,812 1,741 8 14,589 1,715 8 Jul-18 14,625 1,722 8 14,734 1,734 8 14,501 1,707 8 Aug-18 14,552 1,716 8 14,665 1,729 8 14,423 1,700 8 Sep-18 14,560 1,717 8 14,678 1,730 8 14,426 1,701 8 Oct-18 14,711 1,726 8 14,835 1,740 8 14,570 1,709 8 Nov-18 14,863 1,737 8 14,993 1,752 8 14,715 1,719 8 Dec-18 14,986 1,747 8 15,123 1,762 8 14,831 1,728 8 Jan-19 15,056 1,762 8 15,198 1,778 8 14,895 1,743 8 Feb-19 15,080 1,766 8 15,228 1,783 8 14,913 1,746 8 Klamath Falls - Low Growth Klamath Falls - High Growth Klamath Falls - Expected Growth Avista Corp 2016 Natural Gas IRP Appendices 57 APPENDIX - CHAPTER 2 APPENDIX 2.2: CUSTOMER FORECASTS BY REGION KLAMATH FALLS Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Mar-19 15,071 1,763 8 15,223 1,780 8 14,898 1,742 8 Apr-19 15,045 1,758 8 15,202 1,776 8 14,867 1,737 8 May-19 15,008 1,753 8 15,170 1,771 8 14,824 1,731 8 Jun-19 14,919 1,748 8 15,085 1,767 8 14,731 1,725 8 Jul-19 14,838 1,741 8 15,008 1,761 8 14,645 1,718 8 Aug-19 14,766 1,735 8 14,941 1,755 8 14,568 1,711 8 Sep-19 14,775 1,735 8 14,955 1,756 8 14,571 1,711 8 Oct-19 14,927 1,743 8 15,114 1,764 8 14,715 1,718 8 Nov-19 15,080 1,756 8 15,275 1,778 9 14,860 1,730 8 Dec-19 15,204 1,767 8 15,405 1,790 9 14,976 1,740 8 Jan-20 15,273 1,780 8 15,481 1,804 9 15,038 1,752 8 Feb-20 15,298 1,784 8 15,512 1,808 9 15,057 1,755 8 Mar-20 15,288 1,781 8 15,507 1,806 9 15,041 1,752 8 Apr-20 15,263 1,776 8 15,487 1,802 9 15,010 1,746 8 May-20 15,226 1,771 8 15,455 1,797 9 14,968 1,740 8 Jun-20 15,138 1,767 8 15,371 1,794 9 14,875 1,736 8 Jul-20 15,058 1,760 8 15,295 1,787 9 14,790 1,728 8 Aug-20 14,987 1,754 8 15,229 1,782 9 14,714 1,722 8 Sep-20 14,997 1,754 8 15,245 1,782 9 14,718 1,721 8 Oct-20 15,150 1,761 8 15,406 1,790 9 14,862 1,727 8 Nov-20 15,303 1,774 8 15,567 1,804 9 15,006 1,739 8 Dec-20 15,427 1,785 8 15,699 1,816 9 15,121 1,749 8 Jan-21 15,497 1,799 8 15,776 1,831 9 15,183 1,762 8 Feb-21 15,522 1,801 8 15,807 1,834 9 15,201 1,763 8 Mar-21 15,513 1,800 8 15,804 1,833 9 15,186 1,762 8 Apr-21 15,488 1,795 8 15,784 1,829 9 15,155 1,756 8 May-21 15,452 1,790 8 15,753 1,824 9 15,113 1,750 8 Jun-21 15,365 1,785 8 15,670 1,820 9 15,022 1,745 8 Jul-21 15,285 1,778 8 15,594 1,814 9 14,937 1,737 8 Aug-21 15,214 1,773 8 15,528 1,809 9 14,862 1,731 8 Sep-21 15,224 1,773 8 15,544 1,810 9 14,865 1,731 8 Oct-21 15,377 1,780 8 15,706 1,818 9 15,008 1,737 8 Nov-21 15,531 1,793 8 15,869 1,832 9 15,152 1,749 8 Dec-21 15,654 1,804 8 16,001 1,843 9 15,266 1,759 8 Jan-22 15,724 1,818 8 16,078 1,858 9 15,327 1,772 8 Feb-22 15,749 1,821 8 16,110 1,862 9 15,345 1,774 7 Mar-22 15,740 1,819 8 16,106 1,861 9 15,330 1,771 7 Apr-22 15,716 1,814 8 16,088 1,856 9 15,300 1,766 7 May-22 15,680 1,809 8 16,057 1,852 9 15,259 1,760 7 Jun-22 15,593 1,804 8 15,974 1,848 9 15,167 1,754 7 Klamath Falls - Low Growth Klamath Falls - High Growth Klamath Falls - Expected Growth Avista Corp 2016 Natural Gas IRP Appendices 58 APPENDIX - CHAPTER 2 APPENDIX 2.2: CUSTOMER FORECASTS BY REGION KLAMATH FALLS Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Jul-22 15,513 1,797 8 15,898 1,841 9 15,083 1,747 7 Aug-22 15,443 1,792 8 15,832 1,837 9 15,009 1,741 7 Sep-22 15,453 1,792 8 15,848 1,837 9 15,012 1,740 7 Oct-22 15,606 1,799 8 16,011 1,845 9 15,154 1,746 7 Nov-22 15,760 1,812 8 16,175 1,859 9 15,297 1,758 7 Dec-22 15,884 1,823 8 16,308 1,871 9 15,411 1,768 7 Jan-23 15,954 1,837 8 16,386 1,886 9 15,472 1,781 7 Feb-23 15,979 1,840 8 16,418 1,890 9 15,489 1,783 7 Mar-23 15,971 1,838 8 16,416 1,889 9 15,475 1,780 7 Apr-23 15,946 1,833 8 16,397 1,884 9 15,444 1,775 7 May-23 15,911 1,828 8 16,367 1,880 9 15,404 1,769 7 Jun-23 15,824 1,823 8 16,283 1,875 9 15,313 1,764 7 Jul-23 15,744 1,817 8 16,207 1,870 9 15,229 1,757 7 Aug-23 15,673 1,811 8 16,140 1,864 9 15,154 1,751 7 Sep-23 15,684 1,811 8 16,157 1,865 9 15,158 1,750 7 Oct-23 15,836 1,819 8 16,319 1,874 9 15,299 1,757 7 Nov-23 15,990 1,831 8 16,484 1,887 9 15,441 1,768 7 Dec-23 16,114 1,842 8 16,618 1,899 9 15,554 1,778 7 Jan-24 16,183 1,856 8 16,695 1,914 9 15,614 1,790 7 Feb-24 16,208 1,859 8 16,727 1,918 9 15,632 1,792 7 Mar-24 16,200 1,857 8 16,725 1,917 9 15,618 1,790 7 Apr-24 16,175 1,852 8 16,705 1,912 9 15,587 1,784 7 May-24 16,139 1,847 8 16,674 1,908 9 15,546 1,779 7 Jun-24 16,052 1,842 8 16,591 1,903 9 15,456 1,773 7 Jul-24 15,972 1,836 8 16,514 1,898 9 15,372 1,767 7 Aug-24 15,901 1,830 8 16,446 1,892 9 15,298 1,760 7 Sep-24 15,911 1,830 8 16,462 1,893 9 15,301 1,759 7 Oct-24 16,063 1,838 8 16,625 1,902 9 15,441 1,766 7 Nov-24 16,216 1,850 8 16,789 1,915 9 15,582 1,777 7 Dec-24 16,339 1,861 8 16,923 1,927 9 15,694 1,787 7 Jan-25 16,409 1,875 8 17,001 1,942 9 15,755 1,800 7 Feb-25 16,433 1,878 8 17,032 1,946 9 15,772 1,802 7 Mar-25 16,424 1,876 8 17,028 1,945 9 15,757 1,799 7 Apr-25 16,399 1,871 8 17,008 1,940 9 15,727 1,794 7 May-25 16,363 1,866 8 16,977 1,936 9 15,686 1,788 7 Jun-25 16,276 1,861 8 16,893 1,931 9 15,596 1,783 7 Jul-25 16,195 1,854 8 16,814 1,924 9 15,513 1,775 7 Aug-25 16,123 1,849 8 16,745 1,920 9 15,438 1,770 7 Sep-25 16,133 1,849 8 16,761 1,920 9 15,441 1,769 7 Oct-25 16,285 1,856 8 16,925 1,928 9 15,581 1,775 7 Klamath Falls - Low Growth Klamath Falls - High Growth Klamath Falls - Expected Growth Avista Corp 2016 Natural Gas IRP Appendices 59 APPENDIX - CHAPTER 2 APPENDIX 2.2: CUSTOMER FORECASTS BY REGION KLAMATH FALLS Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Nov-25 16,437 1,869 8 17,088 1,943 9 15,720 1,787 7 Dec-25 16,560 1,880 8 17,222 1,955 9 15,832 1,797 7 Jan-26 16,629 1,893 8 17,299 1,969 9 15,892 1,809 7 Feb-26 16,654 1,896 8 17,331 1,973 9 15,909 1,811 7 Mar-26 16,644 1,894 8 17,327 1,971 9 15,894 1,808 7 Apr-26 16,618 1,889 8 17,305 1,967 9 15,863 1,803 7 May-26 16,582 1,884 8 17,274 1,962 9 15,822 1,797 7 Jun-26 16,494 1,879 8 17,188 1,958 9 15,732 1,792 7 Jul-26 16,413 1,873 8 17,109 1,952 9 15,649 1,785 7 Aug-26 16,342 1,867 8 17,040 1,946 9 15,576 1,779 7 Sep-26 16,351 1,867 8 17,055 1,947 9 15,579 1,778 7 Oct-26 16,502 1,874 8 17,218 1,955 9 15,717 1,784 7 Nov-26 16,655 1,887 8 17,383 1,969 9 15,857 1,796 7 Dec-26 16,777 1,898 8 17,516 1,981 9 15,967 1,806 7 Jan-27 16,846 1,911 8 17,594 1,995 9 16,027 1,818 7 Feb-27 16,870 1,915 8 17,625 2,000 9 16,044 1,821 7 Mar-27 16,860 1,913 8 17,620 1,999 9 16,028 1,818 7 Apr-27 16,834 1,907 8 17,598 1,993 9 15,998 1,812 7 May-27 16,797 1,902 8 17,565 1,989 9 15,957 1,806 7 Jun-27 16,709 1,897 8 17,479 1,984 9 15,867 1,801 7 Jul-27 16,627 1,890 8 17,399 1,977 9 15,784 1,794 7 Aug-27 16,556 1,885 8 17,330 1,973 9 15,711 1,788 7 Sep-27 16,564 1,885 8 17,343 1,973 9 15,713 1,788 7 Oct-27 16,716 1,892 8 17,508 1,981 9 15,851 1,794 7 Nov-27 16,868 1,905 8 17,673 1,995 9 15,990 1,805 7 Dec-27 16,990 1,916 8 17,806 2,008 9 16,100 1,815 7 Jan-28 17,058 1,929 8 17,883 2,022 9 16,158 1,827 7 Feb-28 17,082 1,932 8 17,913 2,026 9 16,175 1,829 7 Mar-28 17,072 1,930 8 17,908 2,024 9 16,160 1,826 7 Apr-28 17,045 1,925 8 17,886 2,019 9 16,129 1,821 7 May-28 17,008 1,920 8 17,852 2,015 9 16,088 1,816 7 Jun-28 16,920 1,915 8 17,765 2,010 9 15,999 1,810 7 Jul-28 16,838 1,908 8 17,684 2,003 9 15,917 1,803 7 Aug-28 16,765 1,902 8 17,613 1,998 9 15,843 1,797 7 Sep-28 16,773 1,902 8 17,626 1,998 9 15,845 1,796 7 Oct-28 16,923 1,910 8 17,789 2,007 9 15,981 1,803 7 Nov-28 17,075 1,922 8 17,953 2,020 9 16,120 1,814 7 Dec-28 17,196 1,933 8 18,086 2,033 9 16,229 1,824 7 Jan-29 17,264 1,946 8 18,162 2,047 9 16,288 1,836 7 Feb-29 17,287 1,949 8 18,192 2,051 9 16,304 1,838 7 Klamath Falls - Low Growth Klamath Falls - High Growth Klamath Falls - Expected Growth Avista Corp 2016 Natural Gas IRP Appendices 60 APPENDIX - CHAPTER 2 APPENDIX 2.2: CUSTOMER FORECASTS BY REGION KLAMATH FALLS Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Mar-29 17,276 1,947 8 18,185 2,049 9 16,289 1,835 7 Apr-29 17,249 1,942 8 18,162 2,044 9 16,258 1,830 7 May-29 17,211 1,937 8 18,127 2,040 9 16,217 1,825 7 Jun-29 17,122 1,932 8 18,038 2,035 9 16,128 1,819 7 Jul-29 17,038 1,925 8 17,954 2,028 9 16,044 1,812 7 Aug-29 16,965 1,919 8 17,882 2,022 9 15,970 1,806 7 Sep-29 16,972 1,919 8 17,894 2,023 9 15,972 1,806 7 Oct-29 17,122 1,926 8 18,057 2,031 9 16,109 1,812 7 Nov-29 17,273 1,939 8 18,221 2,045 10 16,246 1,823 7 Dec-29 17,393 1,949 8 18,352 2,056 10 16,354 1,832 7 Jan-30 17,460 1,963 8 18,427 2,071 10 16,412 1,845 7 Feb-30 17,482 1,966 8 18,455 2,075 10 16,428 1,847 7 Mar-30 17,470 1,964 8 18,447 2,073 10 16,412 1,845 7 Apr-30 17,443 1,958 8 18,424 2,068 10 16,382 1,838 7 May-30 17,404 1,953 8 18,387 2,063 10 16,341 1,833 7 Jun-30 17,314 1,948 8 18,297 2,058 10 16,251 1,828 7 Jul-30 17,231 1,941 8 18,214 2,051 10 16,169 1,821 7 Aug-30 17,157 1,935 8 18,140 2,045 10 16,095 1,815 7 Sep-30 17,164 1,935 8 18,152 2,046 10 16,097 1,814 7 Oct-30 17,314 1,942 8 18,315 2,054 10 16,233 1,820 7 Nov-30 17,464 1,955 8 18,478 2,068 10 16,369 1,832 7 Dec-30 17,585 1,966 8 18,611 2,080 10 16,477 1,842 7 Jan-31 17,652 1,979 8 18,686 2,094 10 16,535 1,853 7 Feb-31 17,673 1,982 8 18,713 2,098 10 16,550 1,856 7 Mar-31 17,662 1,980 8 18,706 2,097 10 16,535 1,853 7 Apr-31 17,634 1,975 8 18,681 2,092 10 16,504 1,848 7 May-31 17,595 1,969 8 18,645 2,086 10 16,463 1,842 7 Jun-31 17,505 1,964 8 18,554 2,081 10 16,374 1,837 7 Jul-31 17,422 1,957 8 18,471 2,074 10 16,292 1,830 7 Aug-31 17,349 1,952 8 18,398 2,070 10 16,219 1,824 7 Sep-31 17,356 1,951 8 18,410 2,069 10 16,221 1,823 7 Oct-31 17,506 1,959 8 18,574 2,078 10 16,356 1,830 7 Nov-31 17,657 1,971 8 18,739 2,091 10 16,492 1,841 7 Dec-31 17,777 1,982 8 18,871 2,104 10 16,599 1,850 7 Jan-32 17,844 1,995 8 18,947 2,118 10 16,657 1,862 7 Feb-32 17,867 1,998 8 18,977 2,122 10 16,674 1,864 6 Mar-32 17,855 1,996 8 18,969 2,120 10 16,657 1,862 6 Apr-32 17,827 1,991 8 18,944 2,115 10 16,626 1,856 6 May-32 17,789 1,986 8 18,909 2,110 10 16,586 1,851 6 Jun-32 17,699 1,981 8 18,818 2,106 10 16,497 1,846 6 Jul-32 17,616 1,973 8 18,734 2,098 10 16,415 1,838 6 Klamath Falls - Low Growth Klamath Falls - High Growth Klamath Falls - Expected Growth Avista Corp 2016 Natural Gas IRP Appendices 61 APPENDIX - CHAPTER 2 APPENDIX 2.2: CUSTOMER FORECASTS BY REGION KLAMATH FALLS Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Aug-32 17,543 1,968 8 18,662 2,093 10 16,342 1,833 6 Sep-32 17,551 1,968 8 18,675 2,094 10 16,345 1,832 6 Oct-32 17,700 1,975 8 18,838 2,102 10 16,479 1,838 6 Nov-32 17,851 1,987 8 19,004 2,115 10 16,614 1,849 6 Dec-32 17,972 1,998 8 19,138 2,127 10 16,722 1,859 6 Jan-33 18,039 2,012 8 19,214 2,143 10 16,779 1,871 6 Feb-33 18,061 2,014 8 19,243 2,145 10 16,795 1,872 6 Mar-33 18,050 2,012 8 19,236 2,144 10 16,779 1,870 6 Apr-33 18,022 2,007 8 19,211 2,139 10 16,748 1,865 6 May-33 17,984 2,002 8 19,175 2,134 10 16,708 1,860 6 Jun-33 17,894 1,997 8 19,084 2,129 10 16,619 1,854 6 Jul-33 17,812 1,990 8 19,002 2,122 10 16,538 1,847 6 Aug-33 17,739 1,984 8 18,929 2,117 10 16,466 1,841 6 Sep-33 17,746 1,984 8 18,941 2,117 10 16,467 1,841 6 Oct-33 17,896 1,991 8 19,107 2,125 10 16,601 1,847 6 Nov-33 18,047 2,004 8 19,273 2,140 10 16,736 1,858 6 Dec-33 18,168 2,015 8 19,407 2,152 10 16,844 1,868 6 Jan-34 18,235 2,028 8 19,484 2,166 10 16,901 1,879 6 Feb-34 18,258 2,031 8 19,513 2,170 10 16,917 1,881 6 Mar-34 18,246 2,029 8 19,506 2,169 10 16,901 1,879 6 Apr-34 18,219 2,024 8 19,482 2,164 10 16,871 1,874 6 May-34 18,180 2,019 8 19,445 2,159 10 16,830 1,869 6 Jun-34 18,091 2,013 8 19,355 2,153 10 16,742 1,862 6 Jul-34 18,008 2,006 8 19,271 2,146 10 16,660 1,855 6 Aug-34 17,935 2,001 8 19,198 2,141 10 16,588 1,850 6 Sep-34 17,942 2,000 8 19,210 2,141 10 16,590 1,849 6 Oct-34 18,092 2,008 8 19,376 2,150 10 16,723 1,856 6 Nov-34 18,243 2,020 8 19,543 2,163 10 16,858 1,866 6 Dec-34 18,364 2,031 8 19,677 2,176 10 16,965 1,876 6 Jan-35 18,431 2,044 8 19,754 2,190 10 17,022 1,887 6 Feb-35 18,453 2,047 8 19,783 2,194 10 17,037 1,890 6 Mar-35 18,441 2,045 8 19,775 2,192 10 17,021 1,887 6 Apr-35 18,414 2,040 8 19,751 2,188 10 16,991 1,882 6 May-35 18,375 2,035 8 19,714 2,183 10 16,950 1,877 6 Jun-35 18,285 2,030 8 19,623 2,178 10 16,862 1,872 6 Jul-35 18,202 2,023 8 19,539 2,171 10 16,781 1,865 6 Aug-35 18,129 2,017 8 19,465 2,165 10 16,709 1,859 6 Sep-35 18,136 2,017 8 19,477 2,166 10 16,711 1,858 6 Oct-35 18,286 2,024 8 19,643 2,174 10 16,844 1,864 6 Nov-35 18,436 2,037 8 19,810 2,188 10 16,977 1,875 6 Dec-35 18,557 2,047 8 19,945 2,200 10 17,084 1,884 6 Klamath Falls - Low Growth Klamath Falls - High Growth Klamath Falls - Expected Growth Avista Corp 2016 Natural Gas IRP Appendices 62 APPENDIX - CHAPTER 2 APPENDIX 2.2: CUSTOMER FORECASTS BY REGION LA GRANDE Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Nov-15 6,571 905 2 6,571 905 2 6,571 905 2 Dec-15 6,623 915 2 6,623 915 2 6,623 915 2 Jan-16 6,680 909 1 6,689 910 1 6,673 908 1 Feb-16 6,666 911 2 6,676 912 2 6,658 910 2 Mar-16 6,651 912 1 6,662 913 1 6,642 910 1 Apr-16 6,642 910 1 6,655 911 1 6,632 908 1 May-16 6,634 907 1 6,648 909 1 6,623 905 1 Jun-16 6,620 904 1 6,635 906 1 6,608 902 1 Jul-16 6,589 903 1 6,606 905 1 6,576 901 1 Aug-16 6,556 901 3 6,574 904 3 6,542 899 3 Sep-16 6,545 899 7 6,565 902 7 6,530 897 7 Oct-16 6,579 901 7 6,600 903 7 6,562 898 6 Nov-16 6,654 901 3 6,677 904 3 6,636 898 3 Dec-16 6,695 909 2 6,720 912 2 6,676 906 2 Jan-17 6,714 911 1 6,741 914 1 6,693 908 1 Feb-17 6,711 913 2 6,739 917 2 6,689 910 2 Mar-17 6,694 913 1 6,724 918 1 6,671 910 1 Apr-17 6,681 913 1 6,713 918 1 6,657 910 1 May-17 6,677 911 1 6,710 916 1 6,651 908 1 Jun-17 6,651 907 1 6,686 912 1 6,624 904 1 Jul-17 6,609 906 1 6,645 911 2 6,581 902 1 Aug-17 6,581 905 3 6,619 910 3 6,551 901 3 Sep-17 6,574 903 7 6,614 908 7 6,543 899 7 Oct-17 6,619 905 6 6,661 910 7 6,586 900 6 Nov-17 6,691 904 3 6,736 910 3 6,656 899 3 Dec-17 6,737 912 2 6,784 919 2 6,701 907 2 Jan-18 6,758 915 1 6,807 921 1 6,720 910 1 Feb-18 6,755 917 2 6,806 924 2 6,716 911 2 Mar-18 6,741 917 1 6,794 924 1 6,700 911 1 Apr-18 6,726 917 1 6,781 924 1 6,684 911 1 May-18 6,715 915 1 6,771 922 1 6,671 909 1 Jun-18 6,684 911 1 6,742 919 1 6,639 905 1 Jul-18 6,640 910 1 6,700 918 2 6,594 903 1 Aug-18 6,614 908 3 6,676 917 3 6,566 902 2 Sep-18 6,606 906 7 6,670 915 7 6,557 900 7 Oct-18 6,656 908 6 6,722 917 7 6,605 901 6 Nov-18 6,731 908 3 6,800 917 3 6,678 901 3 Dec-18 6,778 916 2 6,849 925 2 6,723 908 2 Jan-19 6,802 918 1 6,876 928 1 6,745 910 1 Feb-19 6,800 920 2 6,876 931 2 6,741 912 2 La Grande - Low Growth La Grande - High Growth La Grande - Expected Growth Avista Corp 2016 Natural Gas IRP Appendices 63 APPENDIX - CHAPTER 2 APPENDIX 2.2: CUSTOMER FORECASTS BY REGION LA GRANDE Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Mar-19 6,785 921 1 6,863 931 1 6,725 912 1 Apr-19 6,768 920 1 6,848 931 1 6,706 912 1 May-19 6,754 918 1 6,836 929 1 6,691 909 1 Jun-19 6,721 914 1 6,804 926 1 6,657 906 1 Jul-19 6,676 913 1 6,761 925 2 6,610 904 1 Aug-19 6,650 912 3 6,737 924 3 6,583 903 2 Sep-19 6,642 910 7 6,731 922 7 6,573 900 7 Oct-19 6,694 912 6 6,786 924 7 6,623 902 6 Nov-19 6,770 911 3 6,865 924 3 6,697 901 3 Dec-19 6,819 919 2 6,917 932 2 6,744 909 2 Jan-20 6,844 922 1 6,945 935 1 6,767 911 1 Feb-20 6,843 924 2 6,946 938 2 6,764 913 2 Mar-20 6,828 924 1 6,933 938 1 6,747 913 1 Apr-20 6,810 924 1 6,917 938 1 6,728 912 1 May-20 6,795 922 1 6,904 936 1 6,711 910 1 Jun-20 6,760 918 1 6,871 933 1 6,675 906 1 Jul-20 6,714 917 1 6,826 932 2 6,628 905 1 Aug-20 6,688 915 3 6,802 931 3 6,600 903 2 Sep-20 6,680 913 7 6,796 929 7 6,591 901 6 Oct-20 6,733 915 6 6,852 931 7 6,641 903 6 Nov-20 6,811 915 3 6,934 931 3 6,716 902 3 Dec-20 6,861 923 2 6,987 940 2 6,764 910 2 Jan-21 6,886 925 1 7,015 942 2 6,787 912 1 Feb-21 6,886 927 2 7,018 945 2 6,785 914 2 Mar-21 6,870 927 1 7,004 946 1 6,767 914 1 Apr-21 6,852 927 1 6,988 945 2 6,748 913 1 May-21 6,836 925 1 6,974 944 1 6,730 911 1 Jun-21 6,801 921 1 6,941 940 1 6,694 907 1 Jul-21 6,754 920 1 6,895 939 2 6,646 905 1 Aug-21 6,727 919 3 6,870 938 3 6,618 904 2 Sep-21 6,720 917 7 6,865 937 7 6,609 902 6 Oct-21 6,773 919 6 6,921 939 7 6,659 903 6 Nov-21 6,851 918 3 7,004 939 3 6,734 903 3 Dec-21 6,902 926 2 7,058 947 2 6,783 910 2 Jan-22 6,928 929 1 7,087 950 2 6,806 912 1 Feb-22 6,928 931 2 7,090 952 2 6,805 914 1 Mar-22 6,912 931 1 7,076 953 1 6,787 914 1 Apr-22 6,894 931 1 7,060 953 2 6,768 913 1 May-22 6,877 929 1 7,045 951 1 6,749 911 1 Jun-22 6,842 925 1 7,011 948 2 6,713 907 1 La Grande - Low Growth La Grande - High Growth La Grande - Expected Growth Avista Corp 2016 Natural Gas IRP Appendices 64 APPENDIX - CHAPTER 2 APPENDIX 2.2: CUSTOMER FORECASTS BY REGION LA GRANDE Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Jul-22 6,794 924 1 6,964 947 2 6,664 906 1 Aug-22 6,767 922 3 6,939 946 3 6,636 904 2 Sep-22 6,760 920 7 6,934 944 7 6,627 902 6 Oct-22 6,814 922 6 6,992 946 7 6,678 904 6 Nov-22 6,892 922 3 7,074 946 3 6,753 903 3 Dec-22 6,943 930 2 7,129 955 2 6,801 911 2 Jan-23 6,969 932 1 7,158 957 2 6,825 913 1 Feb-23 6,969 934 2 7,161 960 2 6,823 915 1 Mar-23 6,954 934 1 7,148 961 1 6,806 915 1 Apr-23 6,935 934 1 7,131 960 2 6,786 914 1 May-23 6,918 932 1 7,116 959 1 6,767 912 1 Jun-23 6,883 928 1 7,082 955 2 6,731 908 1 Jul-23 6,835 927 1 7,035 954 2 6,683 906 1 Aug-23 6,808 926 3 7,009 953 3 6,655 905 2 Sep-23 6,800 924 7 7,003 951 7 6,646 903 6 Oct-23 6,854 925 6 7,061 953 7 6,697 904 6 Nov-23 6,932 925 3 7,143 953 3 6,772 904 3 Dec-23 6,983 933 2 7,198 962 2 6,820 911 2 Jan-24 7,010 935 1 7,228 965 2 6,845 913 1 Feb-24 7,010 938 2 7,230 967 2 6,843 915 1 Mar-24 6,994 938 1 7,216 968 1 6,826 915 1 Apr-24 6,975 938 1 7,198 968 2 6,806 915 1 May-24 6,958 936 1 7,183 966 1 6,788 913 1 Jun-24 6,922 932 1 7,148 962 2 6,751 909 1 Jul-24 6,874 931 1 7,100 961 2 6,703 907 1 Aug-24 6,847 929 3 7,074 960 3 6,675 906 2 Sep-24 6,839 927 7 7,068 958 7 6,666 904 6 Oct-24 6,893 929 6 7,125 960 7 6,717 905 6 Nov-24 6,971 929 3 7,208 960 3 6,792 905 3 Dec-24 7,022 937 2 7,262 969 2 6,840 912 2 Jan-25 7,049 939 1 7,292 971 2 6,865 914 1 Feb-25 7,049 941 2 7,294 974 2 6,863 916 1 Mar-25 7,032 941 1 7,279 974 1 6,845 916 0 Apr-25 7,014 941 1 7,262 974 2 6,827 916 1 May-25 6,996 939 1 7,245 972 1 6,808 914 0 Jun-25 6,960 935 1 7,210 969 2 6,771 910 1 Jul-25 6,912 934 1 7,162 968 2 6,723 909 1 Aug-25 6,885 933 3 7,136 967 3 6,696 907 2 Sep-25 6,877 931 7 7,129 965 7 6,687 905 6 Oct-25 6,931 932 6 7,187 967 7 6,738 906 6 La Grande - Low Growth La Grande - High Growth La Grande - Expected Growth Avista Corp 2016 Natural Gas IRP Appendices 65 APPENDIX - CHAPTER 2 APPENDIX 2.2: CUSTOMER FORECASTS BY REGION LA GRANDE Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Nov-25 7,009 932 3 7,269 967 3 6,812 906 2 Dec-25 7,060 940 2 7,324 975 2 6,861 914 1 Jan-26 7,087 942 1 7,354 978 2 6,886 916 1 Feb-26 7,086 945 2 7,354 980 2 6,883 918 1 Mar-26 7,070 945 1 7,340 981 1 6,867 918 0 Apr-26 7,051 945 1 7,322 981 2 6,847 917 1 May-26 7,034 942 1 7,306 979 1 6,829 915 0 Jun-26 6,998 939 1 7,270 975 2 6,793 911 1 Jul-26 6,950 938 1 7,223 974 2 6,745 910 1 Aug-26 6,923 936 3 7,197 973 3 6,717 908 2 Sep-26 6,915 934 7 7,191 971 7 6,707 906 6 Oct-26 6,969 936 6 7,249 974 7 6,758 908 6 Nov-26 7,048 936 3 7,334 974 3 6,833 907 2 Dec-26 7,099 944 2 7,389 982 2 6,881 915 1 Jan-27 7,126 946 1 7,420 985 2 6,905 917 1 Feb-27 7,126 948 2 7,422 987 2 6,903 918 1 Mar-27 7,110 948 1 7,408 988 1 6,886 919 0 Apr-27 7,091 948 1 7,390 988 2 6,866 918 1 May-27 7,074 946 1 7,375 986 1 6,848 916 0 Jun-27 7,038 942 1 7,340 983 2 6,811 912 1 Jul-27 6,990 941 1 7,293 982 2 6,763 910 1 Aug-27 6,964 940 3 7,268 981 3 6,735 909 2 Sep-27 6,957 938 7 7,264 979 7 6,726 907 6 Oct-27 7,011 939 6 7,324 981 7 6,776 908 6 Nov-27 7,090 939 3 7,409 981 4 6,851 907 2 Dec-27 7,141 947 2 7,466 990 3 6,898 915 1 Jan-28 7,168 949 1 7,497 993 2 6,921 917 1 Feb-28 7,169 952 2 7,501 996 2 6,920 919 1 Mar-28 7,153 952 1 7,487 996 2 6,902 919 0 Apr-28 7,135 951 1 7,472 996 2 6,883 918 1 May-28 7,118 949 1 7,457 995 2 6,864 916 0 Jun-28 7,082 946 1 7,422 991 2 6,827 912 1 Jul-28 7,035 945 1 7,377 990 2 6,780 910 1 Aug-28 7,008 943 3 7,352 990 3 6,751 909 2 Sep-28 7,001 941 7 7,348 988 7 6,742 906 6 Oct-28 7,055 943 6 7,408 990 7 6,791 908 6 Nov-28 7,134 943 3 7,494 990 4 6,865 907 2 Dec-28 7,186 951 2 7,552 999 3 6,913 914 1 Jan-29 7,213 953 1 7,584 1,002 2 6,936 916 1 Feb-29 7,214 955 2 7,589 1,005 2 6,934 918 1 La Grande - Low Growth La Grande - High Growth La Grande - Expected Growth Avista Corp 2016 Natural Gas IRP Appendices 66 APPENDIX - CHAPTER 2 APPENDIX 2.2: CUSTOMER FORECASTS BY REGION LA GRANDE Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Mar-29 7,198 955 1 7,576 1,005 2 6,917 918 0 Apr-29 7,180 955 1 7,560 1,006 2 6,897 917 1 May-29 7,164 953 1 7,547 1,004 2 6,879 915 0 Jun-29 7,128 949 1 7,512 1,000 2 6,842 911 1 Jul-29 7,080 948 1 7,465 1,000 2 6,794 910 1 Aug-29 7,054 947 3 7,441 999 3 6,766 908 2 Sep-29 7,046 945 7 7,435 997 7 6,756 906 6 Oct-29 7,101 946 6 7,496 999 7 6,807 907 6 Nov-29 7,180 946 3 7,583 999 4 6,880 907 2 Dec-29 7,231 954 2 7,640 1,008 3 6,927 914 1 Jan-30 7,258 956 1 7,672 1,011 2 6,951 916 1 Feb-30 7,259 959 2 7,676 1,014 2 6,949 918 1 Mar-30 7,243 959 1 7,662 1,014 2 6,932 918 0 Apr-30 7,225 958 1 7,647 1,014 2 6,912 917 1 May-30 7,208 956 1 7,632 1,013 2 6,894 915 0 Jun-30 7,172 953 1 7,597 1,009 2 6,857 911 1 Jul-30 7,124 951 1 7,549 1,008 2 6,809 909 1 Aug-30 7,098 950 3 7,524 1,007 3 6,782 908 2 Sep-30 7,090 948 7 7,518 1,005 7 6,773 906 6 Oct-30 7,144 950 6 7,578 1,008 7 6,823 907 6 Nov-30 7,223 950 3 7,665 1,008 4 6,896 907 2 Dec-30 7,274 957 2 7,722 1,016 3 6,943 914 1 Jan-31 7,301 960 1 7,753 1,019 2 6,967 916 1 Feb-31 7,302 962 2 7,757 1,022 2 6,966 918 1 Mar-31 7,286 962 1 7,743 1,023 2 6,948 918 0 Apr-31 7,267 962 1 7,725 1,023 2 6,928 917 1 May-31 7,250 960 1 7,710 1,021 2 6,910 915 0 Jun-31 7,215 956 1 7,676 1,017 2 6,875 911 1 Jul-31 7,167 955 1 7,627 1,016 2 6,827 910 1 Aug-31 7,140 954 3 7,601 1,015 3 6,800 908 2 Sep-31 7,132 952 7 7,595 1,013 7 6,790 906 6 Oct-31 7,186 953 6 7,655 1,016 7 6,840 907 6 Nov-31 7,265 953 3 7,742 1,016 4 6,913 907 2 Dec-31 7,316 961 2 7,799 1,024 3 6,960 914 1 Jan-32 7,343 963 1 7,830 1,027 2 6,984 916 1 Feb-32 7,343 966 2 7,833 1,030 3 6,982 918 1 Mar-32 7,327 966 1 7,818 1,031 2 6,965 918 0 Apr-32 7,309 965 1 7,801 1,030 2 6,946 918 1 May-32 7,292 963 1 7,786 1,029 2 6,929 915 0 Jun-32 7,256 960 1 7,750 1,025 2 6,893 912 0 Jul-32 7,208 958 1 7,701 1,024 2 6,845 910 1 La Grande - Low Growth La Grande - High Growth La Grande - Expected Growth Avista Corp 2016 Natural Gas IRP Appendices 67 APPENDIX - CHAPTER 2 APPENDIX 2.2: CUSTOMER FORECASTS BY REGION LA GRANDE Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Residential Customers Commercial Customers Industrial Customers Aug-32 7,181 957 3 7,674 1,023 3 6,818 909 2 Sep-32 7,173 955 7 7,668 1,021 8 6,809 907 6 Oct-32 7,227 957 6 7,728 1,023 7 6,859 908 6 Nov-32 7,305 957 3 7,814 1,023 4 6,931 908 2 Dec-32 7,356 964 2 7,871 1,032 3 6,978 915 1 Jan-33 7,383 967 1 7,902 1,035 2 7,002 917 0 Feb-33 7,383 969 2 7,904 1,037 3 7,000 919 1 Mar-33 7,367 969 1 7,889 1,038 2 6,984 919 0 Apr-33 7,349 969 1 7,872 1,038 2 6,965 918 0 May-33 7,331 967 1 7,855 1,036 2 6,946 916 0 Jun-33 7,296 963 1 7,820 1,032 2 6,912 912 0 Jul-33 7,247 962 1 7,769 1,031 2 6,864 911 1 Aug-33 7,220 961 3 7,742 1,030 4 6,837 910 2 Sep-33 7,212 959 7 7,735 1,028 8 6,828 908 6 Oct-33 7,266 960 6 7,795 1,030 7 6,878 909 6 Nov-33 7,344 960 3 7,881 1,030 4 6,951 909 2 Dec-33 7,395 968 2 7,937 1,039 3 6,998 916 1 Jan-34 7,422 970 1 7,968 1,042 2 7,022 918 0 Feb-34 7,422 973 2 7,970 1,044 3 7,021 920 1 Mar-34 7,406 973 1 7,955 1,045 2 7,004 920 0 Apr-34 7,387 972 1 7,936 1,045 2 6,985 919 0 May-34 7,369 970 1 7,919 1,043 2 6,967 917 0 Jun-34 7,333 967 1 7,882 1,039 2 6,931 914 0 Jul-34 7,285 965 1 7,832 1,038 2 6,885 912 1 Aug-34 7,258 964 3 7,805 1,037 4 6,858 911 2 Sep-34 7,250 962 7 7,798 1,035 8 6,849 909 6 Oct-34 7,303 964 6 7,857 1,037 7 6,898 910 6 Nov-34 7,382 964 3 7,944 1,037 4 6,972 910 2 Dec-34 7,433 971 2 8,000 1,046 3 7,018 917 1 Jan-35 7,459 974 1 8,030 1,048 2 7,042 919 0 Feb-35 7,459 976 2 8,032 1,051 3 7,040 921 1 Mar-35 7,443 976 1 8,017 1,052 2 7,024 921 0 Apr-35 7,424 976 1 7,998 1,051 2 7,005 921 0 May-35 7,407 974 1 7,981 1,049 2 6,988 919 0 Jun-35 7,371 970 1 7,944 1,046 2 6,952 915 0 Jul-35 7,322 969 1 7,893 1,045 2 6,905 914 1 Aug-35 7,295 968 3 7,866 1,043 4 6,878 912 2 Sep-35 7,287 966 7 7,859 1,041 8 6,870 910 6 Oct-35 7,341 967 6 7,919 1,043 7 6,919 912 6 Nov-35 7,419 967 3 8,005 1,043 4 6,992 911 2 Dec-35 7,470 975 2 8,062 1,052 3 7,039 919 1 La Grande - Low Growth La Grande - High Growth La Grande - Expected Growth Avista Corp 2016 Natural Gas IRP Appendices 68 APPENDIX - CHAPTER 2 APPENDIX 2.3: DEMAND COEFFICIENTS Avista Corp 2016 Natural Gas IRP Appendices 69 APPENDIX - CHAPTER 2 APPENDIX 2.3: WA/ID BASE COEFFICIENT CALCULATION Avista Corp 2016 Natural Gas IRP Appendices 70 APPENDIX - CHAPTER 2 APPENDIX 2.3: MEDFORD BASE COEFFICIENT CALCULATION Avista Corp 2016 Natural Gas IRP Appendices 71 APPENDIX - CHAPTER 2 APPENDIX 2.3: ROSEBURG BASE COEFFICIENT CALCULATION Avista Corp 2016 Natural Gas IRP Appendices 72 APPENDIX - CHAPTER 2 APPENDIX 2.3: KLAMATH FALLS BASE COEFFICIENT CALCULATION Avista Corp 2016 Natural Gas IRP Appendices 73 APPENDIX - CHAPTER 2 APPENDIX 2.3: LA GRANDE BASE COEFFICIENT CALCULATION Avista Corp 2016 Natural Gas IRP Appendices 74 APPENDIX - CHAPTER 2 APPENDIX 2.4: HEATING DEGREE DAY DATA MONTHLY TABLES Avista Corp 2016 Natural Gas IRP Appendices 75 APPENDIX - CHAPTER 2 APPENDIX 2.4: HEATING DEGREE DAY DATA MONTHLY TABLES Avista Corp 2016 Natural Gas IRP Appendices 76 APPENDIX - CHAPTER 2 APPENDIX 2.4: HEATING DEGREE DAILY MONTH BY AREA Avista Corp 2016 Natural Gas IRP Appendices 77 APPENDIX - CHAPTER 2 APPENDIX 2.4: HEATING DEGREE DAILY MONTH BY AREA Avista Corp 2016 Natural Gas IRP Appendices 78 APPENDIX - CHAPTER 2 APPENDIX 2.4: HEATING DEGREE DAILY MONTH BY AREA Avista Corp 2016 Natural Gas IRP Appendices 79 APPENDIX - CHAPTER 2 APPENDIX 2.5: DEMAND SENSITIVITIES SUMMARY OF ASSUMPTIONS – DEMAND SCENARIOS Avista Corp 2016 Natural Gas IRP Appendices 80 APPENDIX - CHAPTER 2 APPENDIX 2.5: DEMAND SCENARIOS PROPOSED SCENARIOS Proposed Scenarios Expected Expected High Growth Low Growth Cold Day 20yr INPUT ASSUMPTIONS Case - Low Prices Case & Low Prices & High Prices Weather Std Customer Growth Rate Reference Case Cust Growth Rates Reference Case Cust Growth Rates High Growth Rate Low Growth Rate Reference Case Cust Growth Rates Use per Customer 3 yr Flat +3 yr Flat +3 yr Flat +3 yr Flat +3 yr Flat + Price Elast.Price Elast.Price Elast. +Price Elast.Price Elast. CNG/NGV Demand Side Management Yes Yes Yes Yes Yes Weather Planning Standard Coldest Day Coldest Day Coldest Day Coldest Day Alternate Planning Standard Prices Price curve Low Expected Low High Expected Carbon Legislation ($/Ton)$9.89 - 19.93 $9.89 - 19.93 None $9.89 - 19.93 $9.89 - 19.93 First Gas Year Unserved WA/ID N/A N/A 2033 N/A N/A Medford N/A N/A 2027 N/A N/A Roseburg N/A N/A 2027 N/A N/A Klamath N/A N/A 2034 N/A N/A La Grande N/A N/A 2031 N/A N/A Evaluates the expected case attributes and combines it with the low price curve to determine whether low prices will drastically change case outcome. Most aggressive peak planning case utilizing Average Case assumptions as a starting point and layering in coldest weather on record. The likelihood of occurrence is low. Aggressive growth assumptions in order to evaluate when our earliest resource shortage could occur. Not likely to occur. Stagnant growth assumptions in order to evaluate if a shortage does occur. Not likely to occur. Evaluates adopting an alternate peak weather standard. Helps provide some bounds around our sensitivity to weather. Indirect influencers including elasticity and price are also important assumptions. The two go hand in hand, as price changes it will influence how much customers consume. If forecasted prices remain relatively stable over the planning horizon, our current elasticity assumption will not provide much decreased usage. However, price adders or an overall steepening of the price curve will trigger a greater decline in usage due to the price elastic response. The magnitude of the elasticity adjustment is also important. We are using a long run elasticity factor as calculated by the AGA. We continue to evaluate this assumption and are looking to update the study as part of our Action Plan. RESULTS Scenario Summary Risk Assessment Higher or lower customer growth rates, which are heavily based on economic recovery. Higher or lower growth rates will lead to accelerated or delayed unserved demand. Looking at various growth assumptions off the Expected Case allows us to capture the risk in terms of the change in demand linked to customer growth. Higher or lower use per customer will also lead to accelerated or delayed unserved demand. Use per customer can differ in many ways. Direct use per customer influencers, such as demand side management, NGV/CNG usage, and derivation of the use per customer starting point (i.e. one year, three year, etc.). Again, varying these assumptions under our forecasting methodology allows us to quantify the change each assumption has to our forecast. Weather volatility and predictability are a key risk. As the most correlated direct demand influencer, varying weather assumptions is key to understanding the weather related risks. Avista Corp 2016 Natural Gas IRP Appendices 81 APPENDIX - CHAPTER 2 APPENDIX 2.6: DEMAND FORECAST SENSITIVITIES AND SCENARIOS DESCRIPTIONS DEFINITIONS DYNAMIC DEMAND METHODOLOGY – Avista’s demand forecasting approach wherein we 1) identify key demand drivers behind natural gas consumption, 2) perform sensitivity analysis on each demand driver, and 3) combine demand drivers under various scenarios to develop alternative potential outcomes for forecasted demand. DEMAND INFLUENCING FACTORS – Factors that directly influence the volume of natural gas consumed by our core customers. PRICE INFLUENCING FACTORS – Factors that, through price elasticity response, indirectly influence the volume of natural gas consumed by our core customers. REFERENCE CASE – A baseline point of reference that captures the basic inputs for determining a demand forecast in SENDOUT® which includes number of customers, use per customer, average daily weather temperatures and expected natural gas prices. SENSITIVITIES – Focused analysis of a specific natural gas demand driver and its impact on forecasted demand relative to the Reference Case when underlying input assumptions are modified. SCENARIOS – Combination of natural gas demand drivers that make up a demand forecast. Avista evaluates each sensitivities impact. SENSITIVITIES The following Sensitivities were performed on identified demand drivers against the reference case for consideration in Scenario development. Note that Sensitivity assumptions reflect incremental adjustments we estimate are not captured in the underlying reference case forecast. Following are the Demand Influencing (Direct) Sensitivities we evaluated: REFERENCE CASE PLUS PEAK – Same assumptions as in the Reference Case with and adjustment made to normal weather to incorporate peak weather conditions. The peak weather data being the coldest day on record for each weather area. LOW & HIGH CUSTOMER GROWTH – Discussed in detail in Appendix 2.1: Economic Outlook and Customer Count Forecast. NATURAL GAS VEHICLES (NGV) AND/OR COMPRESSED NATURAL GAS (CNG) VEHICLES – NGV/CNG vehicles assumed to produce a 5% cumulative incremental demand over our 20 year planning horizon. Our assumption utilized market consumption estimates from an independent analysis on NGV/CNG vehicle viability. The analysis indicates significant challenges exist to widespread adoption but did provide a scenario for significant market penetration. Avista Corp 2016 Natural Gas IRP Appendices 82 APPENDIX - CHAPTER 2 ALTERNATE WEATHER STANDARD (COLDEST DAY 20 YRS) – Peak Day weather temperature reduced to coldest average daily temperature (HDDs) experienced in the most recent 20 years in each region. DSM – Reference case assumptions including the potential DSM identified by the Conservation Potential Assessment provided by Applied Energy Group. See Appendix 3.1 for full assessment report. PEAK PLUS DSM – Reference plus peak weather assumptions including the potential DSM identified by the Conservation Potential Assessment provided by Applied Energy Group. See Appendix 3.1 for the full assessment report. ALTERNATE USE PER CUSTOMER – Reference case use per customer was based upon three years of actual use per customer per heating degree day data. This sensitivity used five years of historical use per customer per heating degree day data. Following are the Price Influencing (Indirect) Sensitivities we evaluated: EXPECTED ELASTICITY – For our expected elasticity Sensitivity, we incorporate reduced consumption in response to higher natural gas prices utilizing a price elasticity study prepared by the American Gas Association. LOW & HIGH PRICES – To capture a wide band of alternative prices forecasts, a Monte Carlo simulation using historical daily cash price data at the Henry Hub trading point dating back to 2009 was developed. From this simulation, a high and low price were selected from the derived 500 draws. CARBON LEGISLATION LOW CASE – Assumes no carbon adder throughout the entire study horizon. CARBON LEGISLATION MEDIUM CASE –Utilizes carbon cost adders quantified by independent analysis from Consultant #1. They identify both an adder reflecting carbon allowances as well as an adder to capture the effect of increased natural gas demand as more gas turbines come online to replace coal plants and back up wind generation. The allowance adder escalates from $9.89/ton in 2018 to $19.93/ton by 2035. This is the expected carbon adder utilized in our carbon case sensitivities. CARBON LEGISLATION HIGH CASE – Utilizes carbon cost adders quantified by independent analysis from Consultant #1. They identify both an adder reflecting carbon allowances as well as an adder to capture the effect of increased natural gas demand as more gas turbines come online to replace coal plants and back up wind generation. The allowance adder escalates from $15/ton in 2018 to $43/ton by 2035. EXPORTED LNG – Beginning in 2019, we apply an estimate of $.25/mmbtu incremental adder each year to regional natural gas prices to capture upward price pressure because of exports of LNG to Asian and European counties. There is much uncertainty about the region price impact LNG will have. It is highly dependent on many things including which export facilities get built and the pipeline infrastructure used to serve them. There are several analyses that have been conducted where the price impact can be minimal to $1.00/mmbtu. SCENARIOS After identifying the above demand drivers and analyzing the various Sensitivities, we have developed the following demand forecast Scenarios: Avista Corp 2016 Natural Gas IRP Appendices 83 APPENDIX - CHAPTER 2 AVERAGE CASE – This Scenario we believe represents the most likely average demand forecast modeled. We assume service territory customer growth rates consistent with the reference case, rolling 20 year normal weather in each service territory, our expected natural gas price forecast (blend of two consultants, along with the NYMEX forward strip), expected price elasticity, the CO2 cost adders from our Carbon Legislation Medium Case Sensitivity, and DSM. The Scenario does not include incremental cost adders for declining Canadian imports or drilling restrictions beyond what is incorporated in the selected price forecast. EXPECTED CASE – This Scenario represents the peak demand forecast. We assume service territory customer growth rates consistent with the reference case, a weather standard of coldest day on record in each service territory, our expected natural gas price forecast (blend of two consultants, along with the NYMEX forward strip), expected price elasticity, DSM, and the CO2 cost adders from our Carbon Legislation Medium Case Sensitivity. HIGH GROWTH, LOW PRICE – This Scenario models a rapid return to robust growth in part spurred on by low energy prices. We assume higher customer growth rates than the reference case, coldest day on record weather standard, incremental demand from NGV/CNG, our low natural gas price forecast, expected price elasticity, DSM, and no CO2 adders. LOW GROWTH, HIGH PRICE – This Scenario models an extended period of slow economic growth in part resulting from high energy prices. We assume lower customer growth rates than the reference case, coldest day on record weather standard, our high natural gas price forecast, expected price elasticity, DSM, and CO2 adders from our Carbon Legislation Medium Case Sensitivity. ALTERNATE WEATHER STANDARD – This Scenario models all the same assumptions as the Expected Case Scenario, except for the change in the weather planning standard from coldest day on record to coldest day in 20 years for each service territory. As noted in the Sensitivity analysis, this change does not affect the Klamath Falls and La Grande service territories, which have each experienced their coldest day on record within the last 20 years. EXPECTED GROWTH, LOW PRICES – This Scenario models all the same assumptions as the Expected Case Scenario, except our low natural gas price forecast is used rather than our expected natural gas price forecast. A case incorporating Exported LNG was not included in this IRP’s scenario analysis. There is much uncertainty about the location and timing of exported LNG and its potential price impacts. The forecasters we subscribe to have incorporated some level of export LNG into their price forecasts and therefore our expected price curve does include an export LNG assumption. At this time, the effects of LNG are minimal given the robust North American supply picture. Avista will closely monitor developments with export LNG for the potential price and infrastructure impacts. Avista Corp 2016 Natural Gas IRP Appendices 84 APPENDIX - CHAPTER 2 APPENDIX 2.7: ANNUAL DEMAND, AVERAGE DAY DEMAND AND PEAK DAY DEMAND (NET OF DSM) – CASE AVERAGE Avista Corp 2016 Natural Gas IRP Appendices 85 APPENDIX - CHAPTER 2 APPENDIX 2.7: ANNUAL DEMAND, AVERAGE DAY DEMAND AND PEAK DAY DEMAND (NET OF DSM) – CASE HIGH Avista Corp 2016 Natural Gas IRP Appendices 86 APPENDIX - CHAPTER 2 APPENDIX 2.7: ANNUAL DEMAND, AVERAGE DAY DEMAND AND PEAK DAY DEMAND (NET OF DSM) – CASE LOW Avista Corp 2016 Natural Gas IRP Appendices 87 APPENDIX - CHAPTER 2 APPENDIX 2.7: ANNUAL DEMAND, AVERAGE DAY DEMAND AND PEAK DAY DEMAND (NET OF DSM) – CASE COLDEST IN 20 Avista Corp 2016 Natural Gas IRP Appendices 88 APPENDIX - CHAPTER 2 APPENDIX 2.8: PEAK DAY DEMAND BEFORE AND AFTER DSM WA/ID Avista Corp 2016 Natural Gas IRP Appendices 89 APPENDIX - CHAPTER 2 APPENDIX 2.8: PEAK DAY DEMAND BEFORE AND AFTER DSM MEDFORD/ROSEBURG Avista Corp 2016 Natural Gas IRP Appendices 90 APPENDIX - CHAPTER 2 APPENDIX 2.8: PEAK DAY DEMAND BEFORE AND AFTER DSM KLAMATH FALLS Avista Corp 2016 Natural Gas IRP Appendices 91 APPENDIX - CHAPTER 2 APPENDIX 2.8: PEAK DAY DEMAND BEFORE AND AFTER DSM LA GRANDE Avista Corp 2016 Natural Gas IRP Appendices 92 APPENDIX - CHAPTER 2 APPENDIX 2.9: DETAILED DEMAND DATA EXPECTED MIX Area 2015-2016: Residential 2015-2016: Commercial 2015-2016: Ind FirmSale 2015-2016 Total 2016-2017: Residential 2016-2017: Commercial 2016-2017: Ind FirmSale 2016-2017 Total 2017-2018: Residential 2017-2018: Commercial 2017-2018: Ind FirmSale 2017-2018 Total Klam Falls 878.84 456.42 13.31 1,348.57 883.84 455.69 13.71 1,353.23 895.19 458.09 13.70 1,366.98 La Grande 523.95 341.99 49.90 915.84 524.18 339.49 51.77 915.43 526.69 339.78 51.72 918.19 Medford GTN 2,179.41 1,398.52 18.60 3,596.53 2,201.01 1,403.03 18.92 3,622.96 2,237.36 1,416.04 18.92 3,672.31 Medford NWP 979.15 628.32 8.36 1,615.83 988.86 630.35 8.50 1,627.71 1,005.19 636.19 8.50 1,649.88 Roseburg 651.55 517.12 7.00 1,175.67 654.28 513.56 6.96 1,174.80 660.22 512.27 6.94 1,179.42 OR Sub-Total 5,212.90 3,342.37 97.17 8,652.43 5,252.16 3,342.11 99.86 8,694.13 5,324.64 3,362.37 99.77 8,786.79 Wa/Id Both 9,075.48 5,521.47 319.24 14,916.18 9,098.71 5,480.27 320.42 14,899.40 9,179.15 5,485.86 320.41 14,985.42 Wa/Id GTN 1,251.79 761.58 44.03 2,057.40 1,254.99 755.90 44.20 2,055.09 1,266.09 756.67 44.19 2,066.95 Wa/Id NWP 5,320.11 3,236.72 187.14 8,743.97 5,333.73 3,212.57 187.83 8,734.13 5,380.88 3,215.85 187.83 8,784.55 WA/ID Sub-Total 15,647.38 9,519.77 550.41 25,717.56 15,687.44 9,448.74 552.44 25,688.61 15,826.12 9,458.37 552.43 25,836.92 Case Total 20,860.28 12,862.14 647.57 34,369.99 20,939.60 12,790.85 652.30 34,382.74 21,150.75 12,820.75 652.21 34,623.71 Area 2018-2019: Residential 2018-2019: Commercial 2018-2019: Ind FirmSale 2018-2019 Total 2019-2020: Residential 2019-2020: Commercial 2019-2020: Ind FirmSale 2019-2020 Total 2020-2021: Residential 2020-2021: Commercial 2020-2021: Ind FirmSale 2020-2021 Total Klam Falls 906.72 461.25 13.69 1,381.66 922.88 466.18 13.72 1,402.79 930.50 466.70 13.68 1,410.88 La Grande 529.18 339.96 51.62 920.76 533.79 341.44 51.66 926.89 533.99 339.97 51.59 925.55 Medford GTN 2,275.51 1,428.93 18.91 3,723.35 2,323.97 1,447.29 18.94 3,790.20 2,352.68 1,453.80 18.88 3,825.37 Medford NWP 1,022.33 641.98 8.49 1,672.81 1,044.10 650.23 8.51 1,702.84 1,057.00 653.16 8.48 1,718.64 Roseburg 666.40 510.92 6.92 1,184.24 675.76 511.29 6.92 1,193.97 679.30 507.30 6.88 1,193.48 OR Sub-Total 5,400.13 3,383.05 99.63 8,882.82 5,500.50 3,416.43 99.76 9,016.69 5,553.47 3,420.93 99.52 9,073.92 Wa/Id Both 9,257.29 5,487.36 320.20 15,064.85 9,377.78 5,511.46 320.84 15,210.08 9,420.59 5,488.29 319.43 15,228.31 Wa/Id GTN 1,276.87 756.88 44.17 2,077.91 1,293.49 760.20 44.25 2,097.94 1,299.39 757.01 44.06 2,100.46 Wa/Id NWP 5,426.69 3,216.73 187.70 8,831.12 5,497.32 3,230.86 188.08 8,916.26 5,522.41 3,217.28 187.25 8,926.94 WA/ID Sub-Total 15,960.85 9,460.97 552.06 25,973.89 16,168.59 9,502.52 553.17 26,224.28 16,242.39 9,462.58 550.74 26,255.71 Case Total 21,360.98 12,844.02 651.70 34,856.70 21,669.09 12,918.95 652.93 35,240.97 21,795.87 12,883.51 650.26 35,329.63 Area 2021-2022: Residential 2021-2022: Commercial 2021-2022: Ind FirmSale 2021-2022 Total 2022-2023: Residential 2022-2023: Commercial 2022-2023: Ind FirmSale 2022-2023 Total 2023-2024: Residential 2023-2024: Commercial 2023-2024: Ind FirmSale 2023-2024 Total Klam Falls 942.55 469.32 13.67 1,425.54 954.61 471.70 13.66 1,439.97 971.13 476.10 13.69 1,460.92 La Grande 536.28 339.81 51.59 927.67 538.47 339.51 51.59 929.57 542.77 340.58 51.65 934.99 Medford GTN 2,385.62 1,463.65 18.87 3,868.14 2,413.83 1,471.44 18.86 3,904.14 2,451.23 1,484.50 18.90 3,954.64 Medford NWP 1,071.80 657.58 8.48 1,737.86 1,084.48 661.08 8.48 1,754.03 1,101.28 666.95 8.49 1,776.72 Roseburg 685.82 505.13 6.86 1,197.81 692.31 502.62 6.84 1,201.77 701.75 502.13 6.84 1,210.72 OR Sub-Total 5,622.07 3,435.48 99.47 9,157.02 5,683.69 3,446.36 99.43 9,229.48 5,768.15 3,470.26 99.58 9,337.99 Wa/Id Both 9,497.09 5,487.32 318.94 15,303.36 9,566.75 5,484.84 318.41 15,370.00 9,676.67 5,507.15 318.82 15,502.63 Wa/Id GTN 1,309.94 756.87 43.99 2,110.81 1,319.55 756.53 43.92 2,120.00 1,334.71 759.61 43.98 2,138.29 Wa/Id NWP 5,567.26 3,216.71 186.97 8,970.93 5,608.09 3,215.25 186.65 9,010.00 5,672.53 3,228.33 186.89 9,087.75 WA/ID Sub-Total 16,374.30 9,460.90 549.90 26,385.10 16,494.40 9,456.62 548.98 26,500.00 16,683.91 9,495.08 549.69 26,728.68 Case Total 21,996.37 12,896.38 649.37 35,542.12 22,178.09 12,902.98 648.41 35,729.48 22,452.06 12,965.34 649.26 36,066.67 Area 2024-2025: Residential 2024-2025: Commercial 2024-2025: Ind FirmSale 2024-2025 Total 2025-2026: Residential 2025-2026: Commercial 2025-2026: Ind FirmSale 2025-2026 Total 2026-2027: Residential 2026-2027: Commercial 2026-2027: Ind FirmSale 2026-2027 Total Klam Falls 977.72 476.11 13.64 1,467.47 988.49 478.03 13.64 1,480.16 998.86 479.88 13.63 1,492.37 La Grande 542.26 338.76 51.59 932.61 543.84 338.33 51.59 933.75 545.49 337.86 51.58 934.93 Medford GTN 2,467.10 1,485.67 18.84 3,971.61 2,492.86 1,492.53 18.83 4,004.22 2,517.84 1,499.09 18.82 4,035.75 Medford NWP 1,108.41 667.47 8.47 1,784.35 1,119.98 670.56 8.46 1,799.00 1,131.21 673.50 8.46 1,813.16 Roseburg 704.42 497.35 6.80 1,208.58 709.90 494.56 6.78 1,211.24 715.33 491.69 6.76 1,213.78 OR Sub-Total 5,799.91 3,465.36 99.34 9,364.62 5,855.07 3,474.01 99.30 9,428.37 5,908.72 3,482.02 99.25 9,489.99 Wa/Id Both 9,695.50 5,480.64 317.22 15,493.36 9,753.71 5,478.07 316.56 15,548.34 9,807.58 5,475.50 315.86 15,598.95 Wa/Id GTN 1,337.31 755.95 43.75 2,137.02 1,345.34 755.60 43.66 2,144.60 1,352.77 755.24 43.57 2,151.58 Wa/Id NWP 5,683.57 3,212.79 185.96 9,082.31 5,717.69 3,211.28 185.57 9,114.55 5,749.27 3,209.78 185.16 9,144.21 WA/ID Sub-Total 16,716.37 9,449.38 546.94 26,712.69 16,816.74 9,444.95 545.80 26,807.49 16,909.62 9,440.52 544.59 26,894.74 Case Total 22,516.29 12,914.74 646.28 36,077.31 22,671.80 12,918.96 645.10 36,235.86 22,818.35 12,922.54 643.84 36,384.73 Avista Corp 2016 Natural Gas IRP Appendices 93 APPENDIX - CHAPTER 2 APPENDIX 2.9: DETAILED DEMAND DATA EXPECTED MIX Area 2027-2028: Residential 2027-2028: Commercial 2027-2028: Ind FirmSale 2027-2028 Total 2028-2029: Residential 2028-2029: Commercial 2028-2029: Ind FirmSale 2028-2029 Total 2029-2030: Residential 2029-2030: Commercial 2029-2030: Ind FirmSale 2029-2030 Total Klam Falls 1,013.91 483.84 13.66 1,511.40 1,018.60 483.10 13.61 1,515.31 1,027.67 484.40 13.60 1,525.67 La Grande 549.70 338.84 51.65 940.18 549.43 336.92 51.58 937.93 551.45 336.40 51.58 939.44 Medford GTN 2,553.18 1,511.59 18.86 4,083.63 2,565.19 1,511.31 18.80 4,095.31 2,587.15 1,516.61 18.79 4,122.54 Medford NWP 1,147.08 679.12 8.47 1,834.68 1,152.48 679.00 8.45 1,839.92 1,162.34 681.37 8.44 1,852.16 Roseburg 724.07 490.92 6.76 1,221.75 726.08 485.95 6.72 1,218.75 731.18 482.97 6.70 1,220.85 OR Sub-Total 5,987.94 3,504.31 99.39 9,591.64 6,011.78 3,496.28 99.16 9,607.22 6,059.79 3,501.75 99.11 9,660.66 Wa/Id Both 9,905.61 5,498.42 316.14 15,720.17 10,157.79 5,964.84 272.10 16,394.73 9,956.47 5,469.60 313.66 15,739.72 Wa/Id GTN 1,366.29 758.40 43.60 2,168.30 1,401.07 822.74 37.53 2,261.34 1,373.31 754.43 43.26 2,171.00 Wa/Id NWP 5,806.74 3,223.21 185.32 9,215.27 5,954.56 3,496.63 159.51 9,610.70 5,836.55 3,206.32 183.87 9,226.73 WA/ID Sub-Total 17,078.65 9,480.04 545.06 27,103.75 17,513.42 10,284.21 469.14 28,266.77 17,166.33 9,430.34 540.79 27,137.45 Case Total 23,066.58 12,984.35 644.45 36,695.39 23,525.20 13,780.49 568.30 37,873.99 23,226.12 12,932.09 639.90 36,798.11 Area 2030-2031: Residential 2030-2031: Commercial 2030-2031: Ind FirmSale 2030-2031 Total 2031-2032: Residential 2031-2032: Commercial 2031-2032: Ind FirmSale 2031-2032 Total 2032-2033: Residential 2032-2033: Commercial 2032-2033: Ind FirmSale 2032-2033 Total Klam Falls 1,036.52 485.61 13.59 1,535.72 1,050.60 488.68 13.62 1,552.90 1,054.50 487.22 13.57 1,555.29 La Grande 553.32 335.84 51.58 940.75 557.45 336.53 51.65 945.62 556.72 334.33 51.58 942.63 Medford GTN 2,607.75 1,521.20 18.78 4,147.72 2,638.29 1,530.54 18.81 4,187.64 2,644.60 1,527.00 18.75 4,190.35 Medford NWP 1,171.60 683.44 8.44 1,863.47 1,185.32 687.63 8.45 1,881.40 1,188.15 686.04 8.43 1,882.62 Roseburg 735.80 479.95 6.68 1,222.42 743.49 478.46 6.68 1,228.62 744.20 472.89 6.64 1,223.73 OR Sub-Total 6,104.98 3,506.04 99.07 9,710.09 6,175.15 3,521.83 99.21 9,796.19 6,188.17 3,507.47 98.97 9,794.61 Wa/Id Both 10,001.73 5,468.16 312.88 15,782.77 10,093.08 5,491.61 312.93 15,897.62 10,087.42 5,463.91 310.97 15,862.30 Wa/Id GTN 1,379.55 754.23 43.16 2,176.93 1,392.15 757.46 43.16 2,192.78 1,391.37 753.64 42.89 2,187.90 Wa/Id NWP 5,863.08 3,205.47 183.41 9,251.97 5,916.63 3,219.22 183.44 9,319.29 5,913.32 3,202.98 182.29 9,298.59 WA/ID Sub-Total 17,244.37 9,427.86 539.44 27,211.67 17,401.87 9,468.28 539.54 27,409.69 17,392.10 9,420.53 536.16 27,348.79 Case Total 23,349.35 12,933.90 638.51 36,921.76 23,577.02 12,990.12 638.75 37,205.88 23,580.27 12,928.00 635.13 37,143.40 Area 2033-2034: Residential 2033-2034: Commercial 2033-2034: Ind FirmSale 2033-2034 Total 2034-2035: Residential 2034-2035: Commercial 2034-2035: Ind FirmSale 2034-2035 Total Klam Falls 1,063.67 488.25 13.56 1,565.49 1,075.10 491.99 13.56 1,580.65 La Grande 558.28 333.61 51.58 943.47 560.98 334.59 51.58 947.15 Medford GTN 2,661.38 1,529.49 18.74 4,209.60 2,682.89 1,539.57 18.74 4,241.20 Medford NWP 1,195.69 687.16 8.42 1,891.27 1,205.36 691.69 8.42 1,905.47 Roseburg 748.29 469.45 6.61 1,224.35 754.40 469.84 6.61 1,230.85 OR Sub-Total 6,227.31 3,507.95 98.92 9,834.19 6,278.73 3,527.68 98.92 9,905.32 Wa/Id Both 10,128.43 5,463.40 309.97 15,901.81 10,223.55 5,492.78 309.81 16,026.14 Wa/Id GTN 1,397.02 753.57 42.76 2,193.35 1,410.14 757.63 42.73 2,210.50 Wa/Id NWP 5,937.35 3,202.68 181.71 9,321.75 5,993.12 3,219.91 181.61 9,394.64 WA/ID Sub-Total 17,462.81 9,419.66 534.44 27,416.91 17,626.81 9,470.31 534.15 27,631.28 Case Total 23,690.12 12,927.61 633.36 37,251.10 23,905.54 12,997.99 633.07 37,536.60 Avista Corp 2016 Natural Gas IRP Appendices 94 APPENDIX - CHAPTER 2 APPENDIX 2.9: DETAILED DEMAND DATA LOW GROWTH HIGH PRICE Area 2015-2016: Residential 2015-2016: Commercial 2015-2016: Ind FirmSale 2015-2016 Total 2016-2017: Residential 2016-2017: Commercial 2016-2017: Ind FirmSale 2016-2017 Total 2017-2018: Residential 2017-2018: Commercial 2017-2018: Ind FirmSale 2017-2018 Total Klam Falls 878.73 456.34 13.25 1,348.33 784.79 413.85 12.94 1,211.58 785.84 411.79 12.74 1,210.37 La Grande 523.38 341.60 49.54 914.51 476.91 311.28 47.68 835.86 475.28 309.11 46.64 831.02 Medford GTN 2,171.64 1,392.98 18.54 3,583.15 1,954.24 1,271.50 17.93 3,243.67 1,960.80 1,268.08 17.71 3,246.59 Medford NWP 975.66 625.83 8.33 1,609.82 877.99 571.25 8.06 1,457.30 880.94 569.72 7.96 1,458.61 Roseburg 650.80 516.46 6.93 1,174.19 583.95 468.19 6.62 1,058.76 583.64 463.08 6.42 1,053.14 OR Sub-Total 5,200.21 3,333.21 96.59 8,630.00 4,677.88 3,036.07 93.22 7,807.17 4,686.50 3,021.76 91.47 7,799.73 Wa/Id Both 9,048.98 5,504.45 318.94 14,872.37 8,044.49 4,898.26 300.26 13,243.01 8,013.36 4,843.68 298.32 13,155.35 Wa/Id GTN 1,248.13 759.23 43.99 2,051.36 1,109.59 675.62 41.42 1,826.62 1,105.29 668.09 41.15 1,814.53 Wa/Id NWP 5,304.57 3,226.74 186.97 8,718.29 4,715.74 2,871.39 176.02 7,763.15 4,697.49 2,839.40 174.87 7,711.76 WA/ID Sub-Total 15,601.68 9,490.43 549.90 25,642.02 13,869.82 8,445.27 517.69 22,832.78 13,816.14 8,351.17 514.34 22,681.64 Case Total 20,801.89 12,823.64 646.49 34,272.02 18,547.70 11,481.34 610.92 30,639.96 18,502.63 11,372.93 605.81 30,481.37 Area 2018-2019: Residential 2018-2019: Commercial 2018-2019: Ind FirmSale 2018-2019 Total 2019-2020: Residential 2019-2020: Commercial 2019-2020: Ind FirmSale 2019-2020 Total 2020-2021: Residential 2020-2021: Commercial 2020-2021: Ind FirmSale 2020-2021 Total Klam Falls 783.45 408.90 12.53 1,204.88 793.17 410.93 12.39 1,216.48 795.15 408.89 12.19 1,216.22 La Grande 472.03 305.89 45.47 823.39 474.50 306.08 44.66 825.24 472.94 303.57 43.74 820.24 Medford GTN 1,960.85 1,260.45 17.47 3,238.77 1,988.78 1,267.45 17.34 3,273.57 1,999.20 1,263.80 17.12 3,280.12 Medford NWP 880.96 566.29 7.85 1,455.10 893.51 569.43 7.79 1,470.73 898.19 567.80 7.69 1,473.68 Roseburg 581.16 456.43 6.22 1,043.82 587.22 454.96 6.04 1,048.23 588.03 449.48 5.84 1,043.34 OR Sub-Total 4,678.46 2,997.96 89.54 7,765.95 4,737.18 3,008.85 88.22 7,834.26 4,753.50 2,993.53 86.56 7,833.60 Wa/Id Both 7,945.45 4,767.49 295.58 13,008.51 7,996.43 4,755.97 295.26 13,047.67 7,978.70 4,702.37 293.03 12,974.10 Wa/Id GTN 1,095.92 657.58 40.77 1,794.28 1,102.96 656.00 40.73 1,799.68 1,100.51 648.60 40.42 1,789.53 Wa/Id NWP 4,657.68 2,794.73 173.27 7,625.68 4,687.56 2,787.99 173.09 7,648.63 4,677.17 2,756.56 171.78 7,605.51 WA/ID Sub-Total 13,699.05 8,219.80 509.61 22,428.46 13,786.95 8,199.96 509.08 22,495.98 13,756.38 8,107.53 505.23 22,369.14 Case Total 18,377.50 11,217.77 599.15 30,194.42 18,524.13 11,208.81 597.30 30,330.24 18,509.88 11,101.06 591.80 30,202.73 Area 2021-2022: Residential 2021-2022: Commercial 2021-2022: Ind FirmSale 2021-2022 Total 2022-2023: Residential 2022-2023: Commercial 2022-2023: Ind FirmSale 2022-2023 Total 2023-2024: Residential 2023-2024: Commercial 2023-2024: Ind FirmSale 2023-2024 Total Klam Falls 801.00 408.70 12.02 1,221.72 806.22 408.03 11.84 1,226.10 815.60 409.27 11.71 1,236.58 La Grande 473.29 302.26 42.89 818.44 473.32 300.68 42.04 816.04 475.53 300.51 41.24 817.29 Medford GTN 2,014.60 1,263.93 16.94 3,295.47 2,025.55 1,262.12 16.76 3,304.43 2,045.26 1,265.36 16.63 3,327.25 Medford NWP 905.11 567.85 7.61 1,480.57 910.03 567.04 7.53 1,484.60 918.88 568.50 7.47 1,494.85 Roseburg 591.51 445.68 5.64 1,042.84 594.56 441.34 5.45 1,041.35 600.45 438.96 5.27 1,044.69 OR Sub-Total 4,785.51 2,988.43 85.10 7,859.04 4,809.69 2,979.20 83.62 7,872.52 4,855.73 2,982.60 82.32 7,920.65 Wa/Id Both 7,994.38 4,670.94 291.71 12,957.02 8,000.69 4,636.81 290.25 12,927.75 8,045.32 4,626.57 289.73 12,961.62 Wa/Id GTN 1,102.67 644.27 40.24 1,787.18 1,103.54 639.56 40.03 1,783.14 1,109.70 638.15 39.96 1,787.81 Wa/Id NWP 4,686.36 2,738.14 171.00 7,595.49 4,690.06 2,718.13 170.14 7,578.34 4,716.22 2,712.13 169.84 7,598.19 WA/ID Sub-Total 13,783.41 8,053.34 502.94 22,339.69 13,794.30 7,994.50 500.43 22,289.23 13,871.24 7,976.85 499.54 22,347.63 Case Total 18,568.92 11,041.77 588.04 30,198.73 18,604.00 10,973.70 584.05 30,161.74 18,726.97 10,959.45 581.86 30,268.28 Area 2024-2025: Residential 2024-2025: Commercial 2024-2025: Ind FirmSale 2024-2025 Total 2025-2026: Residential 2025-2026: Commercial 2025-2026: Ind FirmSale 2025-2026 Total 2026-2027: Residential 2026-2027: Commercial 2026-2027: Ind FirmSale 2026-2027 Total Klam Falls 812.99 405.29 11.49 1,229.77 817.28 404.38 11.32 1,232.98 821.70 403.61 11.15 1,236.45 La Grande 472.05 296.96 40.26 809.27 471.96 295.55 39.41 806.92 471.88 294.06 38.57 804.51 Medford GTN 2,038.17 1,254.11 16.38 3,308.67 2,046.96 1,251.60 16.20 3,314.76 2,055.95 1,249.30 16.03 3,321.29 Medford NWP 915.70 563.44 7.36 1,486.50 919.65 562.31 7.28 1,489.24 923.69 561.28 7.20 1,492.17 Roseburg 598.00 431.38 5.07 1,034.45 600.28 426.97 4.87 1,032.13 602.73 422.63 4.68 1,030.05 OR Sub-Total 4,836.91 2,951.19 80.56 7,868.66 4,856.13 2,940.80 79.09 7,876.02 4,875.96 2,930.89 77.63 7,884.47 Wa/Id Both 7,976.79 4,556.38 286.73 12,819.91 7,974.78 4,524.52 285.19 12,784.49 7,973.22 4,495.21 283.68 12,752.11 Wa/Id GTN 1,100.25 628.47 39.55 1,768.26 1,099.97 624.07 39.34 1,763.38 1,099.75 620.03 39.13 1,758.91 Wa/Id NWP 4,676.05 2,670.98 168.09 7,515.12 4,674.87 2,652.30 167.18 7,494.36 4,673.95 2,635.12 166.30 7,475.37 WA/ID Sub-Total 13,753.09 7,855.84 494.37 22,103.30 13,749.62 7,800.89 491.71 22,042.22 13,746.92 7,750.36 489.10 21,986.39 Case Total 18,590.01 10,807.03 574.93 29,971.96 18,605.76 10,741.69 570.80 29,918.24 18,622.88 10,681.25 566.73 29,870.86 Avista Corp 2016 Natural Gas IRP Appendices 95 APPENDIX - CHAPTER 2 APPENDIX 2.9: DETAILED DEMAND DATA LOW GROWTH HIGH PRICE Area 2027-2028: Residential 2027-2028: Commercial 2027-2028: Ind FirmSale 2027-2028 Total 2028-2029: Residential 2028-2029: Commercial 2028-2029: Ind FirmSale 2028-2029 Total 2029-2030: Residential 2029-2030: Commercial 2029-2030: Ind FirmSale 2029-2030 Total Klam Falls 829.89 404.59 11.01 1,245.50 827.03 400.66 10.79 1,238.49 829.81 399.28 10.62 1,239.71 La Grande 473.52 293.53 37.77 804.82 469.83 289.62 36.83 796.28 468.96 287.43 35.97 792.36 Medford GTN 2,073.14 1,251.89 15.89 3,340.92 2,065.09 1,240.80 15.66 3,321.55 2,069.47 1,236.51 15.48 3,321.46 Medford NWP 931.41 562.44 7.14 1,500.99 927.79 557.46 7.04 1,492.29 929.76 555.54 6.95 1,492.25 Roseburg 607.86 420.04 4.50 1,032.40 605.41 412.80 4.29 1,022.50 606.88 408.03 4.10 1,019.01 OR Sub-Total 4,915.82 2,932.50 76.31 7,924.63 4,895.16 2,901.35 74.61 7,871.11 4,904.89 2,886.80 73.12 7,864.80 Wa/Id Both 8,006.61 4,486.72 283.02 12,776.36 7,935.51 4,423.54 280.09 12,639.15 7,918.39 4,390.87 278.35 12,587.61 Wa/Id GTN 1,104.36 618.86 39.04 1,762.26 1,094.55 610.14 38.63 1,743.33 1,092.19 605.64 38.39 1,736.22 Wa/Id NWP 4,693.53 2,630.15 165.91 7,489.59 4,651.85 2,593.11 164.19 7,409.15 4,641.82 2,573.96 163.17 7,378.95 WA/ID Sub-Total 13,804.50 7,735.73 487.96 22,028.20 13,681.92 7,626.80 482.92 21,791.63 13,652.40 7,570.47 479.91 21,702.78 Case Total 18,720.33 10,668.23 564.28 29,952.83 18,577.07 10,528.14 557.53 29,662.75 18,557.29 10,457.26 553.03 29,567.58 Area 2030-2031: Residential 2030-2031: Commercial 2030-2031: Ind FirmSale 2030-2031 Total 2031-2032: Residential 2031-2032: Commercial 2031-2032: Ind FirmSale 2031-2032 Total 2032-2033: Residential 2032-2033: Commercial 2032-2033: Ind FirmSale 2032-2033 Total Klam Falls 831.73 397.56 10.44 1,239.73 838.13 397.40 10.30 1,245.82 837.66 394.06 10.10 1,241.82 La Grande 467.86 285.17 35.09 788.12 468.99 284.12 34.27 787.38 466.82 281.11 33.39 781.32 Medford GTN 2,071.20 1,230.91 15.29 3,317.41 2,081.92 1,229.56 15.15 3,326.63 2,076.84 1,219.53 14.93 3,311.30 Medford NWP 930.54 553.02 6.87 1,490.43 935.36 552.41 6.80 1,494.57 933.07 547.90 6.71 1,487.68 Roseburg 607.56 403.05 3.90 1,014.52 611.14 399.54 3.72 1,014.39 609.96 393.17 3.52 1,006.64 OR Sub-Total 4,908.90 2,869.71 71.60 7,850.21 4,935.54 2,863.02 70.24 7,868.80 4,924.35 2,835.76 68.65 7,828.76 Wa/Id Both 7,892.35 4,355.20 276.46 12,524.01 7,906.68 4,341.60 275.35 12,523.64 7,857.20 4,294.09 272.70 12,423.99 Wa/Id GTN 1,088.60 600.72 38.13 1,727.45 1,090.58 598.84 37.98 1,727.40 1,083.75 592.29 37.61 1,713.65 Wa/Id NWP 4,626.55 2,553.05 162.06 7,341.66 4,634.95 2,545.08 161.41 7,341.44 4,605.95 2,517.22 159.86 7,283.03 WA/ID Sub-Total 13,607.50 7,508.97 476.65 21,593.12 13,632.20 7,485.53 474.75 21,592.48 13,546.90 7,403.60 470.17 21,420.67 Case Total 18,516.40 10,378.68 548.25 29,443.33 18,567.74 10,348.55 544.98 29,461.27 18,471.25 10,239.37 538.81 29,249.43 Area 2033-2034: Residential 2033-2034: Commercial 2033-2034: Ind FirmSale 2033-2034 Total 2034-2035: Residential 2034-2035: Commercial 2034-2035: Ind FirmSale 2034-2035 Total Klam Falls 839.85 392.15 9.92 1,241.91 845.13 393.31 9.76 1,248.19 La Grande 466.13 279.12 32.53 777.78 467.06 279.09 31.68 777.83 Medford GTN 2,076.80 1,212.82 14.75 3,304.37 2,083.81 1,214.86 14.58 3,313.25 Medford NWP 933.05 544.89 6.62 1,484.57 936.21 545.81 6.55 1,488.56 Roseburg 610.56 388.05 3.32 1,001.92 613.78 387.10 3.15 1,004.03 OR Sub-Total 4,926.38 2,817.03 67.14 7,810.55 4,945.99 2,820.16 65.71 7,831.86 Wa/Id Both 7,830.22 4,261.56 270.65 12,362.43 7,865.82 4,263.33 269.57 12,398.72 Wa/Id GTN 1,080.03 587.80 37.33 1,705.16 1,084.94 588.05 37.18 1,710.17 Wa/Id NWP 4,590.13 2,498.16 158.65 7,246.94 4,611.00 2,499.19 158.02 7,268.21 WA/ID Sub-Total 13,500.38 7,347.52 466.63 21,314.53 13,561.77 7,350.57 464.77 21,377.10 Case Total 18,426.76 10,164.54 533.78 29,125.08 18,507.75 10,170.73 530.48 29,208.96 Avista Corp 2016 Natural Gas IRP Appendices 96 APPENDIX - CHAPTER 2 APPENDIX 2.9: DETAILED DEMAND DATA HIGH GROWTH LOW PRICE Area 2015-2016: Residential 2015-2016: Commercial 2015-2016: Ind FirmSale 2015-2016 Total 2016-2017: Residential 2016-2017: Commercial 2016-2017: Ind FirmSale 2016-2017 Total 2017-2018: Residential 2017-2018: Commercial 2017-2018: Ind FirmSale 2017-2018 Total Klam Falls 879.42 456.91 13.40 1,349.73 886.26 457.41 13.98 1,357.65 901.22 461.87 14.17 1,377.26 La Grande 525.19 342.86 50.38 918.43 527.22 341.59 53.30 922.11 531.92 343.36 54.32 929.60 Medford GTN 2,188.06 1,405.08 18.70 3,611.84 2,224.48 1,419.59 19.22 3,663.29 2,275.38 1,442.37 19.42 3,737.17 Medford NWP 983.04 631.27 8.40 1,622.71 999.40 637.79 8.63 1,645.83 1,022.27 648.02 8.72 1,679.02 Roseburg 652.93 518.47 7.08 1,178.48 657.86 516.88 7.23 1,181.97 666.35 517.78 7.40 1,191.53 OR Sub-Total 5,228.65 3,354.58 97.95 8,681.19 5,295.23 3,373.25 102.37 8,770.85 5,397.13 3,413.41 104.04 8,914.58 Wa/Id Both 9,105.46 5,541.59 319.99 14,967.04 9,176.71 5,530.67 322.39 15,029.77 9,305.69 5,566.49 323.70 15,195.88 Wa/Id GTN 1,255.93 764.36 44.14 2,064.42 1,265.75 762.85 44.47 2,073.07 1,283.54 767.79 44.65 2,095.98 Wa/Id NWP 5,337.68 3,248.52 187.58 8,773.78 5,379.45 3,242.12 188.99 8,810.56 5,455.06 3,263.11 189.76 8,907.93 WA/ID Sub-Total 15,699.06 9,554.47 551.71 25,805.24 15,821.92 9,535.64 555.84 25,913.40 16,044.29 9,597.39 558.10 26,199.79 Case Total 20,927.71 12,909.05 649.66 34,486.42 21,117.14 12,908.90 658.21 34,684.24 21,441.43 13,010.80 662.14 35,114.37 Area 2018-2019: Residential 2018-2019: Commercial 2018-2019: Ind FirmSale 2018-2019 Total 2019-2020: Residential 2019-2020: Commercial 2019-2020: Ind FirmSale 2019-2020 Total 2020-2021: Residential 2020-2021: Commercial 2020-2021: Ind FirmSale 2020-2021 Total Klam Falls 916.82 467.32 14.36 1,398.50 937.37 474.69 14.58 1,426.65 949.84 477.85 14.73 1,442.42 La Grande 536.84 345.16 55.30 937.30 544.04 348.34 56.43 948.81 547.02 348.70 57.44 953.16 Medford GTN 2,329.05 1,465.54 19.62 3,814.20 2,393.73 1,494.55 19.87 3,908.15 2,439.32 1,511.97 20.01 3,971.30 Medford NWP 1,046.38 658.43 8.81 1,713.63 1,075.45 671.46 8.93 1,755.84 1,095.93 679.29 8.99 1,784.21 Roseburg 675.36 518.80 7.58 1,201.74 687.75 521.64 7.77 1,217.15 694.56 520.25 7.93 1,222.74 OR Sub-Total 5,504.46 3,455.24 105.67 9,065.36 5,638.33 3,510.69 107.58 9,256.60 5,726.67 3,538.06 109.11 9,373.83 Wa/Id Both 9,435.79 5,599.81 324.82 15,360.42 9,610.88 5,656.98 326.81 15,594.66 9,711.36 5,668.18 326.75 15,706.29 Wa/Id GTN 1,301.49 772.39 44.80 2,118.68 1,325.64 780.27 45.08 2,150.99 1,339.50 781.82 45.07 2,166.39 Wa/Id NWP 5,531.32 3,282.65 190.41 9,004.39 5,633.96 3,316.16 191.58 9,141.70 5,692.87 3,322.73 191.54 9,207.14 WA/ID Sub-Total 16,268.60 9,654.85 560.04 26,483.49 16,570.48 9,753.41 563.46 26,887.34 16,743.73 9,772.72 563.36 27,079.81 Case Total 21,773.06 13,110.09 665.71 35,548.85 22,208.81 13,264.09 671.04 36,143.94 22,470.39 13,310.78 672.47 36,453.65 Area 2021-2022: Residential 2021-2022: Commercial 2021-2022: Ind FirmSale 2021-2022 Total 2022-2023: Residential 2022-2023: Commercial 2022-2023: Ind FirmSale 2022-2023 Total 2023-2024: Residential 2023-2024: Commercial 2023-2024: Ind FirmSale 2023-2024 Total Klam Falls 967.06 483.26 14.92 1,465.24 984.36 488.46 15.11 1,487.92 1,006.50 495.84 15.35 1,517.69 La Grande 552.21 350.44 58.53 961.18 557.28 352.02 59.62 968.93 564.42 354.93 60.80 980.15 Medford GTN 2,488.57 1,532.30 20.22 4,041.08 2,532.03 1,549.99 20.42 4,102.43 2,585.61 1,573.46 20.67 4,179.74 Medford NWP 1,118.05 688.42 9.08 1,815.56 1,137.58 696.37 9.17 1,843.12 1,161.65 706.91 9.29 1,877.86 Roseburg 704.56 520.79 8.10 1,233.46 714.55 520.98 8.28 1,243.81 727.72 523.29 8.48 1,259.48 OR Sub-Total 5,830.45 3,575.21 110.86 9,516.52 5,925.80 3,607.82 112.61 9,646.22 6,045.90 3,654.43 114.59 9,814.92 Wa/Id Both 9,844.66 5,700.76 327.64 15,873.05 9,968.46 5,730.12 328.46 16,027.04 10,135.92 5,785.90 330.28 16,252.10 Wa/Id GTN 1,357.88 786.31 45.19 2,189.39 1,374.96 790.36 45.30 2,210.63 1,398.06 798.06 45.56 2,241.67 Wa/Id NWP 5,771.01 3,341.82 192.06 9,304.89 5,843.58 3,359.04 192.54 9,395.16 5,941.75 3,391.74 193.61 9,527.10 WA/ID Sub-Total 16,973.55 9,828.89 564.89 27,367.33 17,187.00 9,879.52 566.31 27,632.83 17,475.72 9,975.70 569.45 28,020.87 Case Total 22,804.00 13,404.10 675.75 36,883.85 23,112.80 13,487.34 678.91 37,279.05 23,521.63 13,630.12 684.04 37,835.79 Area 2024-2025: Residential 2024-2025: Commercial 2024-2025: Ind FirmSale 2024-2025 Total 2025-2026: Residential 2025-2026: Commercial 2025-2026: Ind FirmSale 2025-2026 Total 2026-2027: Residential 2026-2027: Commercial 2026-2027: Ind FirmSale 2026-2027 Total Klam Falls 1,018.41 498.67 15.49 1,532.57 1,034.61 503.46 15.69 1,553.76 1,050.14 508.06 15.88 1,574.08 La Grande 566.40 354.73 61.83 982.95 570.42 355.88 62.93 989.23 574.79 357.17 64.04 996.00 Medford GTN 2,617.04 1,584.62 20.82 4,222.48 2,659.19 1,601.94 21.03 4,282.16 2,700.20 1,618.77 21.23 4,340.19 Medford NWP 1,175.77 711.93 9.35 1,897.06 1,194.71 719.71 9.45 1,923.87 1,213.13 727.27 9.54 1,949.94 Roseburg 733.89 521.11 8.64 1,263.63 742.95 520.94 8.82 1,272.70 751.91 520.64 9.00 1,281.55 OR Sub-Total 6,111.51 3,671.05 116.14 9,898.70 6,201.88 3,701.94 117.91 10,021.72 6,290.17 3,731.91 119.67 10,141.75 Wa/Id Both 10,209.33 5,790.84 330.04 16,330.21 10,323.85 5,820.46 330.77 16,475.09 10,431.66 5,848.64 331.43 16,611.73 Wa/Id GTN 1,408.18 798.74 45.52 2,252.44 1,423.98 802.82 45.62 2,272.43 1,438.85 806.71 45.71 2,291.27 Wa/Id NWP 5,984.78 3,394.63 193.47 9,572.88 6,051.91 3,411.99 193.90 9,657.81 6,115.11 3,428.51 194.29 9,737.91 WA/ID Sub-Total 17,602.29 9,984.21 569.04 28,155.54 17,799.75 10,035.28 570.30 28,405.32 17,985.62 10,083.86 571.43 28,640.91 Case Total 23,713.80 13,655.27 685.17 38,054.24 24,001.62 13,737.21 688.21 38,427.04 24,275.79 13,815.77 691.10 38,782.66 Avista Corp 2016 Natural Gas IRP Appendices 97 APPENDIX - CHAPTER 2 APPENDIX 2.9: DETAILED DEMAND DATA HIGH GROWTH LOW PRICE Area 2027-2028: Residential 2027-2028: Commercial 2027-2028: Ind FirmSale 2027-2028 Total 2028-2029: Residential 2028-2029: Commercial 2028-2029: Ind FirmSale 2028-2029 Total 2029-2030: Residential 2029-2030: Commercial 2029-2030: Ind FirmSale 2029-2030 Total Klam Falls 1,070.79 514.95 16.12 1,601.86 1,080.40 516.79 16.27 1,613.46 1,094.37 520.67 16.46 1,631.50 La Grande 582.64 360.48 65.23 1,008.35 586.26 361.03 66.27 1,013.56 592.25 363.01 67.39 1,022.65 Medford GTN 2,752.96 1,642.30 21.49 4,416.75 2,780.71 1,652.04 21.64 4,454.39 2,819.12 1,667.76 21.84 4,508.73 Medford NWP 1,236.84 737.85 9.65 1,984.34 1,249.31 742.22 9.72 2,001.25 1,266.56 749.28 9.81 2,025.66 Roseburg 764.61 522.67 9.20 1,296.48 770.23 520.24 9.36 1,299.82 779.05 519.84 9.54 1,308.43 OR Sub-Total 6,407.84 3,778.25 121.69 10,307.78 6,466.91 3,792.32 123.25 10,382.48 6,551.36 3,820.57 125.04 10,496.98 Wa/Id Both 10,589.01 5,905.03 333.15 16,827.19 10,646.38 5,908.17 332.78 16,887.33 10,750.43 5,937.95 333.43 17,021.81 Wa/Id GTN 1,460.55 814.49 45.95 2,320.99 1,468.47 814.92 45.90 2,329.29 1,482.82 819.03 45.99 2,347.84 Wa/Id NWP 6,207.35 3,461.57 195.29 9,864.21 6,240.98 3,463.41 195.08 9,899.47 6,301.98 3,480.86 195.46 9,978.30 WA/ID Sub-Total 18,256.92 10,181.08 574.39 29,012.39 18,355.83 10,186.49 573.76 29,116.08 18,535.23 10,237.84 574.88 29,347.94 Case Total 24,664.76 13,959.33 696.09 39,320.17 24,822.74 13,978.81 697.01 39,498.56 25,086.59 14,058.41 699.92 39,844.92 Area 2030-2031: Residential 2030-2031: Commercial 2030-2031: Ind FirmSale 2030-2031 Total 2031-2032: Residential 2031-2032: Commercial 2031-2032: Ind FirmSale 2031-2032 Total 2032-2033: Residential 2032-2033: Commercial 2032-2033: Ind FirmSale 2032-2033 Total Klam Falls 1,108.07 524.42 16.66 1,649.15 1,127.49 530.27 16.90 1,674.66 1,136.19 531.33 17.05 1,684.57 La Grande 597.76 364.75 68.51 1,031.03 605.46 367.67 69.73 1,042.87 607.68 367.33 70.77 1,045.79 Medford GTN 2,855.97 1,682.67 22.05 4,560.68 2,903.56 1,702.79 22.32 4,628.66 2,924.52 1,708.66 22.46 4,655.64 Medford NWP 1,283.12 755.98 9.91 2,049.00 1,304.50 765.02 10.03 2,079.54 1,313.91 767.66 10.09 2,091.67 Roseburg 787.15 519.22 9.72 1,316.09 798.39 520.17 9.93 1,328.49 802.16 516.68 10.09 1,328.93 OR Sub-Total 6,632.06 3,847.04 126.85 10,605.95 6,739.40 3,885.93 128.91 10,754.23 6,784.46 3,891.67 130.47 10,806.59 Wa/Id Both 10,852.38 5,967.92 334.06 17,154.37 11,004.70 6,024.98 335.59 17,365.27 11,052.65 6,026.60 334.98 17,414.23 Wa/Id GTN 1,496.88 823.16 46.08 2,366.12 1,517.89 831.03 46.29 2,395.21 1,524.50 831.26 46.20 2,401.96 Wa/Id NWP 6,361.74 3,498.44 195.83 10,056.01 6,451.03 3,531.89 196.73 10,179.64 6,479.14 3,532.83 196.37 10,208.34 WA/ID Sub-Total 18,711.01 10,289.53 575.97 29,576.50 18,973.62 10,387.90 578.61 29,940.13 19,056.30 10,390.69 577.55 30,024.54 Case Total 25,343.07 14,136.56 702.81 40,182.44 25,713.02 14,273.83 707.52 40,694.36 25,840.76 14,282.36 708.02 40,831.13 Area 2033-2034: Residential 2033-2034: Commercial 2033-2034: Ind FirmSale 2033-2034 Total 2034-2035: Residential 2034-2035: Commercial 2034-2035: Ind FirmSale 2034-2035 Total Klam Falls 1,150.68 535.13 17.24 1,703.05 1,167.40 541.60 17.45 1,726.45 La Grande 612.05 368.38 71.91 1,052.34 617.39 371.02 73.04 1,061.45 Medford GTN 2,956.89 1,721.12 22.67 4,700.69 2,993.61 1,740.99 22.89 4,757.49 Medford NWP 1,328.46 773.26 10.19 2,111.90 1,344.96 782.18 10.28 2,137.43 Roseburg 809.53 515.46 10.27 1,335.26 818.86 518.02 10.48 1,347.35 OR Sub-Total 6,857.62 3,913.34 132.28 10,903.25 6,942.22 3,953.81 134.15 11,030.17 Wa/Id Both 11,151.67 6,057.67 335.41 17,544.75 11,304.35 6,118.24 336.65 17,759.24 Wa/Id GTN 1,538.16 835.54 46.26 2,419.97 1,559.22 843.89 46.43 2,449.55 Wa/Id NWP 6,537.19 3,551.05 196.62 10,284.85 6,626.69 3,586.55 197.35 10,410.59 WA/ID Sub-Total 19,227.02 10,444.26 578.29 30,249.57 19,490.26 10,548.69 580.44 30,619.38 Case Total 26,084.64 14,357.61 710.57 41,152.82 26,432.47 14,502.49 714.58 41,649.55 Avista Corp 2016 Natural Gas IRP Appendices 98 APPENDIX - CHAPTER 2 APPENDIX 2.9: DETAILED DEMAND DATA AVERAGE MIX Area 2015-2016: Residential 2015-2016: Commercial 2015-2016: Ind FirmSale 2015-2016 Total 2016-2017: Residential 2016-2017: Commercial 2016-2017: Ind FirmSale 2016-2017 Total 2017-2018: Residential 2017-2018: Commercial 2017-2018: Ind FirmSale 2017-2018 Total Klam Falls 850.06 444.21 13.19 1,307.46 854.74 443.45 13.58 1,311.77 865.67 445.75 13.57 1,325.00 La Grande 505.58 330.86 49.79 886.23 505.70 328.40 51.66 885.75 508.09 328.65 51.60 888.34 Medford GTN 2,094.68 1,356.35 18.43 3,469.46 2,115.07 1,360.38 18.74 3,494.18 2,149.88 1,372.86 18.73 3,541.47 Medford NWP 941.09 609.38 8.28 1,558.74 950.25 611.18 8.42 1,569.85 965.89 616.79 8.41 1,591.10 Roseburg 621.74 497.82 6.98 1,126.54 624.15 494.28 6.94 1,125.37 629.75 492.94 6.92 1,129.62 OR Sub-Total 5,013.14 3,238.63 96.66 8,348.43 5,049.90 3,237.69 99.33 8,386.92 5,119.28 3,257.00 99.24 8,475.52 Wa/Id Both 8,762.08 5,348.54 314.56 14,425.18 8,782.21 5,307.62 315.68 14,405.51 8,858.55 5,311.94 315.67 14,486.15 Wa/Id GTN 1,208.56 737.73 43.39 1,989.68 1,211.34 732.09 43.54 1,986.97 1,221.87 732.68 43.54 1,998.09 Wa/Id NWP 5,136.39 3,135.35 184.40 8,456.14 5,148.19 3,111.36 185.05 8,444.61 5,192.94 3,113.90 185.05 8,491.88 WA/ID Sub-Total 15,107.03 9,221.63 542.34 24,871.00 15,141.75 9,151.07 544.27 24,837.09 15,273.36 9,158.52 544.25 24,976.13 Case Total 20,120.17 12,460.25 639.01 33,219.43 20,191.65 12,388.76 643.60 33,224.02 20,392.64 12,415.52 643.49 33,451.65 Area 2018-2019: Residential 2018-2019: Commercial 2018-2019: Ind FirmSale 2018-2019 Total 2019-2020: Residential 2019-2020: Commercial 2019-2020: Ind FirmSale 2019-2020 Total 2020-2021: Residential 2020-2021: Commercial 2020-2021: Ind FirmSale 2020-2021 Total Klam Falls 876.78 448.78 13.56 1,339.11 892.50 453.57 13.59 1,359.66 899.68 453.96 13.54 1,367.18 La Grande 510.46 328.79 51.51 890.76 514.96 330.22 51.55 896.72 515.04 328.71 51.47 895.22 Medford GTN 2,186.38 1,385.19 18.72 3,590.29 2,233.15 1,402.98 18.76 3,654.89 2,260.17 1,408.92 18.70 3,687.79 Medford NWP 982.29 622.33 8.41 1,613.03 1,003.30 630.32 8.43 1,642.05 1,015.44 632.99 8.40 1,656.83 Roseburg 635.60 491.55 6.90 1,134.05 644.61 491.88 6.90 1,143.39 647.78 487.84 6.86 1,142.49 OR Sub-Total 5,191.50 3,276.63 99.10 8,567.23 5,288.52 3,308.97 99.22 8,696.72 5,338.10 3,312.43 98.98 8,749.52 Wa/Id Both 8,932.48 5,312.30 315.45 14,560.22 9,048.65 5,335.24 316.09 14,699.98 9,087.02 5,310.86 314.68 14,712.55 Wa/Id GTN 1,232.07 732.73 43.51 2,008.31 1,248.09 735.90 43.60 2,027.58 1,253.38 732.53 43.40 2,029.32 Wa/Id NWP 5,236.28 3,114.11 184.92 8,535.30 5,304.38 3,127.56 185.29 8,617.23 5,326.87 3,113.26 184.47 8,624.60 WA/ID Sub-Total 15,400.82 9,159.14 543.87 25,103.84 15,601.12 9,198.70 544.98 25,344.79 15,667.27 9,156.65 542.55 25,366.47 Case Total 20,592.32 12,435.76 642.97 33,671.06 20,889.63 12,507.67 644.20 34,041.51 21,005.38 12,469.08 641.53 34,115.98 Area 2021-2022: Residential 2021-2022: Commercial 2021-2022: Ind FirmSale 2021-2022 Total 2022-2023: Residential 2022-2023: Commercial 2022-2023: Ind FirmSale 2022-2023 Total 2023-2024: Residential 2023-2024: Commercial 2023-2024: Ind FirmSale 2023-2024 Total Klam Falls 911.27 456.44 13.54 1,381.26 922.88 458.69 13.53 1,395.09 938.94 462.95 13.56 1,415.45 La Grande 517.21 328.51 51.47 897.19 519.29 328.17 51.47 898.93 523.47 329.19 51.53 904.20 Medford GTN 2,291.59 1,418.24 18.69 3,728.51 2,318.50 1,425.57 18.68 3,762.74 2,354.64 1,438.17 18.72 3,811.53 Medford NWP 1,029.56 637.18 8.40 1,675.13 1,041.64 640.47 8.39 1,690.51 1,057.88 646.14 8.41 1,712.43 Roseburg 653.93 485.63 6.84 1,146.41 660.04 483.08 6.83 1,149.95 669.11 482.55 6.82 1,158.48 OR Sub-Total 5,403.56 3,326.00 98.94 8,828.50 5,462.35 3,335.98 98.90 8,897.22 5,544.05 3,359.00 99.04 9,002.09 Wa/Id Both 9,159.26 5,308.69 314.19 14,782.14 9,224.82 5,305.07 313.65 14,843.54 9,330.68 5,326.21 314.06 14,970.96 Wa/Id GTN 1,263.35 732.23 43.34 2,038.92 1,272.39 731.73 43.26 2,047.38 1,286.99 734.65 43.32 2,064.96 Wa/Id NWP 5,369.22 3,111.99 184.18 8,665.39 5,407.65 3,109.87 183.87 8,701.38 5,469.71 3,122.26 184.11 8,776.08 WA/ID Sub-Total 15,791.83 9,152.92 541.70 25,486.45 15,904.86 9,146.66 540.78 25,592.30 16,087.38 9,183.13 541.49 25,812.00 Case Total 21,195.39 12,478.91 640.64 34,314.94 21,367.20 12,482.64 639.68 34,489.52 21,631.43 12,542.13 640.53 34,814.09 Area 2024-2025: Residential 2024-2025: Commercial 2024-2025: Ind FirmSale 2024-2025 Total 2025-2026: Residential 2025-2026: Commercial 2025-2026: Ind FirmSale 2025-2026 Total 2026-2027: Residential 2026-2027: Commercial 2026-2027: Ind FirmSale 2026-2027 Total Klam Falls 945.08 462.83 13.51 1,421.42 955.41 464.62 13.50 1,433.54 965.35 466.34 13.49 1,445.19 La Grande 522.86 327.33 51.47 901.67 524.33 326.85 51.47 902.66 525.87 326.35 51.47 903.69 Medford GTN 2,369.26 1,438.88 18.66 3,826.80 2,393.77 1,445.29 18.64 3,857.70 2,417.52 1,451.40 18.63 3,887.55 Medford NWP 1,064.45 646.46 8.38 1,719.29 1,075.46 649.33 8.38 1,733.17 1,086.13 652.08 8.37 1,746.58 Roseburg 671.41 477.73 6.79 1,155.93 676.53 474.89 6.77 1,158.19 681.60 471.98 6.74 1,160.33 OR Sub-Total 5,573.07 3,353.23 98.81 9,025.11 5,625.50 3,361.00 98.76 9,085.26 5,676.48 3,368.15 98.72 9,143.34 Wa/Id Both 9,345.48 5,298.56 312.47 14,956.50 9,399.72 5,294.85 311.81 15,006.38 9,449.72 5,291.16 311.11 15,051.99 Wa/Id GTN 1,289.03 730.84 43.10 2,062.97 1,296.51 730.32 43.01 2,069.85 1,303.41 729.82 42.91 2,076.14 Wa/Id NWP 5,478.38 3,106.05 183.17 8,767.60 5,510.18 3,103.88 182.78 8,796.84 5,539.49 3,101.72 182.37 8,823.58 WA/ID Sub-Total 16,112.89 9,135.44 538.74 25,787.07 16,206.41 9,129.05 537.60 25,873.06 16,292.62 9,122.69 536.40 25,951.71 Case Total 21,685.96 12,488.67 637.55 34,812.18 21,831.91 12,490.05 636.37 34,958.33 21,969.09 12,490.85 635.11 35,095.05 Avista Corp 2016 Natural Gas IRP Appendices 99 APPENDIX - CHAPTER 2 APPENDIX 2.9: DETAILED DEMAND DATA AVERAGE MIX Area 2027-2028: Residential 2027-2028: Commercial 2027-2028: Ind FirmSale 2027-2028 Total 2028-2029: Residential 2028-2029: Commercial 2028-2029: Ind FirmSale 2028-2029 Total 2029-2030: Residential 2029-2030: Commercial 2029-2030: Ind FirmSale 2029-2030 Total Klam Falls 979.97 470.17 13.52 1,463.67 984.26 469.31 13.48 1,467.05 992.93 470.50 13.47 1,476.90 La Grande 529.97 327.28 51.53 908.78 529.58 325.32 51.47 906.37 531.48 324.76 51.47 907.71 Medford GTN 2,451.63 1,463.47 18.67 3,933.77 2,462.47 1,462.75 18.61 3,943.83 2,483.29 1,467.62 18.60 3,969.51 Medford NWP 1,101.46 657.50 8.39 1,767.35 1,106.33 657.18 8.36 1,771.87 1,115.68 659.37 8.36 1,783.40 Roseburg 689.98 471.17 6.74 1,167.89 691.62 466.16 6.70 1,164.49 696.37 463.14 6.68 1,166.20 OR Sub-Total 5,753.01 3,389.59 98.86 9,241.46 5,774.25 3,380.72 98.63 9,253.60 5,819.75 3,385.38 98.58 9,303.71 Wa/Id Both 9,543.88 5,312.95 311.38 15,168.22 9,543.57 5,284.81 309.66 15,138.04 9,587.13 5,281.89 308.90 15,177.91 Wa/Id GTN 1,316.40 732.82 42.95 2,092.17 1,316.35 728.94 42.71 2,088.01 1,322.36 728.54 42.61 2,093.51 Wa/Id NWP 5,594.69 3,114.49 182.53 8,891.71 5,594.51 3,097.99 181.52 8,874.02 5,620.04 3,096.28 181.08 8,897.40 WA/ID Sub-Total 16,454.97 9,160.27 536.86 26,152.10 16,454.44 9,111.74 533.89 26,100.07 16,529.53 9,106.70 532.59 26,168.82 Case Total 22,207.99 12,549.85 635.72 35,393.56 22,228.69 12,492.46 632.52 35,353.67 22,349.28 12,492.09 631.17 35,472.53 Area 2030-2031: Residential 2030-2031: Commercial 2030-2031: Ind FirmSale 2030-2031 Total 2031-2032: Residential 2031-2032: Commercial 2031-2032: Ind FirmSale 2031-2032 Total 2032-2033: Residential 2032-2033: Commercial 2032-2033: Ind FirmSale 2032-2033 Total Klam Falls 1,001.41 471.58 13.46 1,486.45 1,015.11 474.54 13.49 1,503.13 1,018.61 472.97 13.44 1,505.02 La Grande 533.23 324.16 51.47 908.86 537.24 324.80 51.53 913.58 536.40 322.56 51.47 910.43 Medford GTN 2,502.79 1,471.81 18.59 3,993.19 2,532.31 1,480.75 18.63 4,031.69 2,537.64 1,476.83 18.57 4,033.04 Medford NWP 1,124.44 661.25 8.35 1,794.04 1,137.70 665.26 8.37 1,811.34 1,140.10 663.50 8.34 1,811.95 Roseburg 700.66 460.07 6.66 1,167.39 708.04 458.55 6.66 1,173.24 708.44 452.93 6.62 1,167.99 OR Sub-Total 5,862.54 3,388.87 98.53 9,349.94 5,930.40 3,403.90 98.67 9,432.98 5,941.20 3,388.79 98.44 9,428.43 Wa/Id Both 9,628.65 5,279.33 308.12 15,216.11 9,716.29 5,301.68 308.18 15,326.15 9,706.92 5,272.87 306.22 15,286.01 Wa/Id GTN 1,328.09 728.18 42.50 2,098.77 1,340.18 731.27 42.51 2,113.95 1,338.89 727.29 42.24 2,108.42 Wa/Id NWP 5,644.38 3,094.78 180.62 8,919.79 5,695.75 3,107.88 180.66 8,984.29 5,690.27 3,090.99 179.51 8,960.77 WA/ID Sub-Total 16,601.13 9,102.30 531.25 26,234.67 16,752.22 9,140.83 531.34 26,424.39 16,736.08 9,091.16 527.96 26,355.20 Case Total 22,463.66 12,491.17 629.78 35,584.61 22,682.62 12,544.73 630.01 35,857.37 22,677.27 12,479.96 626.40 35,783.62 Area 2033-2034: Residential 2033-2034: Commercial 2033-2034: Ind FirmSale 2033-2034 Total 2034-2035: Residential 2034-2035: Commercial 2034-2035: Ind FirmSale 2034-2035 Total Klam Falls 1,027.40 473.88 13.43 1,514.71 1,038.44 477.50 13.43 1,529.37 La Grande 537.85 321.80 51.47 911.12 540.45 322.73 51.47 914.65 Medford GTN 2,553.49 1,478.95 18.55 4,051.00 2,574.12 1,488.69 18.55 4,081.36 Medford NWP 1,147.22 664.46 8.34 1,820.01 1,156.49 668.83 8.34 1,833.65 Roseburg 712.23 449.45 6.60 1,168.28 718.04 449.80 6.59 1,174.43 OR Sub-Total 5,978.19 3,388.54 98.39 9,465.12 6,027.53 3,407.55 98.38 9,533.47 Wa/Id Both 9,744.26 5,271.27 305.22 15,320.75 9,835.72 5,299.55 305.05 15,440.33 Wa/Id GTN 1,344.04 727.07 42.10 2,113.21 1,356.65 730.97 42.08 2,129.70 Wa/Id NWP 5,712.15 3,090.06 178.92 8,981.13 5,765.77 3,106.64 178.82 9,051.23 WA/ID Sub-Total 16,800.44 9,088.40 526.24 26,415.08 16,958.14 9,137.16 525.95 26,621.25 Case Total 22,778.63 12,476.94 624.63 35,880.20 22,985.67 12,544.72 624.34 36,154.72 Avista Corp 2016 Natural Gas IRP Appendices 100 APPENDIX - CHAPTER 2 APPENDIX 2.9: DETAILED DEMAND DATA COLDEST IN 20 YEARS Area 2015-2016: Residential 2015-2016: Commercial 2015-2016: Ind FirmSale 2015-2016 Total 2016-2017: Residential 2016-2017: Commercial 2016-2017: Ind FirmSale 2016-2017 Total 2017-2018: Residential 2017-2018: Commercial 2017-2018: Ind FirmSale 2017-2018 Total Klam Falls 876.38 455.38 13.30 1,345.06 881.35 454.65 13.70 1,349.70 892.67 457.04 13.69 1,363.40 La Grande 523.11 341.47 49.79 914.36 523.33 338.97 51.66 913.95 525.83 339.26 51.60 916.70 Medford GTN 2,181.91 1,399.90 18.59 3,600.40 2,203.59 1,404.39 18.91 3,626.89 2,240.02 1,417.44 18.90 3,676.36 Medford NWP 980.28 628.94 8.35 1,617.57 990.02 630.96 8.50 1,629.47 1,006.38 636.82 8.49 1,651.70 Roseburg 647.79 514.41 6.99 1,169.19 650.46 510.85 6.95 1,168.27 656.36 509.55 6.94 1,172.84 OR Sub-Total 5,209.46 3,340.10 97.03 8,646.58 5,248.76 3,339.81 99.71 8,688.28 5,321.27 3,360.11 99.63 8,781.00 Wa/Id Both 9,047.29 5,505.91 318.84 14,872.04 9,070.21 5,464.64 320.02 14,854.88 9,150.28 5,470.12 320.02 14,940.41 Wa/Id GTN 1,247.90 759.44 43.98 2,051.32 1,251.06 753.74 44.14 2,048.95 1,262.11 754.50 44.14 2,060.75 Wa/Id NWP 5,303.58 3,227.60 186.91 8,718.09 5,317.02 3,203.41 187.60 8,708.03 5,363.95 3,206.62 187.60 8,758.17 WA/ID Sub-Total 15,598.77 9,492.95 549.73 25,641.45 15,638.30 9,421.80 551.76 25,611.86 15,776.34 9,431.24 551.76 25,759.33 Case Total 20,808.22 12,833.05 646.76 34,288.03 20,887.05 12,761.61 651.48 34,300.14 21,097.60 12,791.35 651.38 34,540.33 Area 2018-2019: Residential 2018-2019: Commercial 2018-2019: Ind FirmSale 2018-2019 Total 2019-2020: Residential 2019-2020: Commercial 2019-2020: Ind FirmSale 2019-2020 Total 2020-2021: Residential 2020-2021: Commercial 2020-2021: Ind FirmSale 2020-2021 Total Klam Falls 904.16 460.19 13.68 1,378.03 920.29 465.11 13.71 1,399.11 927.87 465.62 13.67 1,407.15 La Grande 528.32 339.44 51.51 919.27 532.93 340.91 51.55 925.39 533.12 339.44 51.47 924.04 Medford GTN 2,278.23 1,430.34 18.89 3,727.47 2,326.73 1,448.72 18.93 3,794.38 2,355.49 1,455.25 18.87 3,829.61 Medford NWP 1,023.55 642.62 8.49 1,674.66 1,045.34 650.87 8.51 1,704.72 1,058.26 653.81 8.48 1,720.55 Roseburg 662.50 508.20 6.92 1,177.61 671.82 508.56 6.92 1,187.30 675.31 504.56 6.88 1,186.75 OR Sub-Total 5,396.76 3,380.79 99.49 8,877.04 5,497.11 3,414.17 99.61 9,010.89 5,550.05 3,418.67 99.37 9,068.09 Wa/Id Both 9,228.04 5,471.52 319.80 15,019.37 9,348.14 5,495.51 320.45 15,164.10 9,390.55 5,472.24 319.04 15,181.82 Wa/Id GTN 1,272.83 754.69 44.11 2,071.64 1,289.40 758.00 44.20 2,091.60 1,295.25 754.79 44.01 2,094.04 Wa/Id NWP 5,409.54 3,207.44 187.47 8,804.46 5,479.94 3,221.51 187.85 8,889.30 5,504.80 3,207.86 187.02 8,899.69 WA/ID Sub-Total 15,910.42 9,433.66 551.39 25,895.46 16,117.48 9,475.02 552.50 26,145.00 16,190.60 9,434.89 550.06 26,175.55 Case Total 21,307.18 12,814.44 650.87 34,772.50 21,614.59 12,889.20 652.11 35,155.89 21,740.65 12,853.57 649.43 35,243.65 Area 2021-2022: Residential 2021-2022: Commercial 2021-2022: Ind FirmSale 2021-2022 Total 2022-2023: Residential 2022-2023: Commercial 2022-2023: Ind FirmSale 2022-2023 Total 2023-2024: Residential 2023-2024: Commercial 2023-2024: Ind FirmSale 2023-2024 Total Klam Falls 939.88 468.22 13.66 1,421.76 951.90 470.59 13.65 1,436.14 968.38 474.98 13.68 1,457.04 La Grande 535.41 339.28 51.47 926.16 537.59 338.98 51.47 928.04 541.88 340.05 51.53 933.46 Medford GTN 2,388.44 1,465.10 18.86 3,872.40 2,416.68 1,472.91 18.85 3,908.44 2,454.11 1,485.98 18.89 3,958.97 Medford NWP 1,073.07 658.23 8.47 1,739.78 1,085.75 661.74 8.47 1,755.97 1,102.57 667.61 8.49 1,778.67 Roseburg 681.79 502.39 6.86 1,191.03 688.22 499.88 6.84 1,194.94 697.62 499.38 6.84 1,203.83 OR Sub-Total 5,618.58 3,433.22 99.33 9,151.13 5,680.15 3,444.09 99.28 9,223.52 5,764.56 3,467.99 99.43 9,331.98 Wa/Id Both 9,466.67 5,471.16 318.55 15,256.38 9,535.96 5,468.57 318.01 15,322.55 9,645.51 5,490.78 318.43 15,454.71 Wa/Id GTN 1,305.75 754.64 43.94 2,104.33 1,315.30 754.29 43.86 2,113.45 1,330.42 757.35 43.92 2,131.68 Wa/Id NWP 5,549.43 3,207.23 186.74 8,943.39 5,590.04 3,205.72 186.42 8,982.18 5,654.26 3,218.73 186.66 9,059.66 WA/ID Sub-Total 16,321.84 9,433.03 549.22 26,304.10 16,441.31 9,428.57 548.30 26,418.18 16,630.19 9,466.86 549.01 26,646.05 Case Total 21,940.43 12,866.25 648.55 35,455.23 22,121.45 12,872.67 647.58 35,641.71 22,394.75 12,934.85 648.44 35,978.03 Area 2024-2025: Residential 2024-2025: Commercial 2024-2025: Ind FirmSale 2024-2025 Total 2025-2026: Residential 2025-2026: Commercial 2025-2026: Ind FirmSale 2025-2026 Total 2026-2027: Residential 2026-2027: Commercial 2026-2027: Ind FirmSale 2026-2027 Total Klam Falls 974.94 474.97 13.63 1,463.54 985.67 476.89 13.62 1,476.18 996.00 478.73 13.61 1,488.35 La Grande 541.37 338.23 51.47 931.07 542.95 337.79 51.47 932.21 544.59 337.32 51.47 933.38 Medford GTN 2,470.01 1,487.15 18.83 3,975.99 2,495.81 1,494.03 18.82 4,008.66 2,520.83 1,500.60 18.81 4,040.24 Medford NWP 1,109.71 668.14 8.46 1,786.32 1,121.30 671.23 8.46 1,800.99 1,132.55 674.18 8.45 1,815.18 Roseburg 700.24 494.60 6.80 1,201.64 705.67 491.80 6.78 1,204.25 711.06 488.92 6.76 1,206.73 OR Sub-Total 5,796.28 3,463.09 99.20 9,358.57 5,851.40 3,471.74 99.15 9,422.29 5,905.02 3,479.76 99.10 9,483.88 Wa/Id Both 9,663.98 5,464.16 316.83 15,444.97 9,721.83 5,461.49 316.17 15,499.49 9,775.36 5,458.82 315.47 15,549.65 Wa/Id GTN 1,332.96 753.68 43.70 2,130.34 1,340.94 753.31 43.61 2,137.86 1,348.33 752.94 43.51 2,144.78 Wa/Id NWP 5,665.09 3,203.13 185.73 9,053.95 5,699.00 3,201.56 185.34 9,085.91 5,730.38 3,200.00 184.93 9,115.31 WA/ID Sub-Total 16,662.03 9,420.97 546.26 26,629.26 16,761.78 9,416.36 545.12 26,723.26 16,854.07 9,411.76 543.91 26,809.74 Case Total 22,458.31 12,884.06 645.45 35,987.83 22,613.17 12,888.11 644.27 36,145.55 22,759.09 12,891.52 643.02 36,293.62 Avista Corp 2016 Natural Gas IRP Appendices 101 APPENDIX - CHAPTER 2 APPENDIX 2.9: DETAILED DEMAND DATA COLDEST IN 20 YEARS Area 2027-2028: Residential 2027-2028: Commercial 2027-2028: Ind FirmSale 2027-2028 Total 2028-2029: Residential 2028-2029: Commercial 2028-2029: Ind FirmSale 2028-2029 Total 2029-2030: Residential 2029-2030: Commercial 2029-2030: Ind FirmSale 2029-2030 Total Klam Falls 1,011.01 482.67 13.64 1,507.33 1,015.67 481.93 13.60 1,511.20 1,024.70 483.22 13.59 1,521.51 La Grande 548.79 338.30 51.53 938.62 548.52 336.38 51.47 936.37 550.54 335.85 51.47 937.86 Medford GTN 2,556.20 1,513.12 18.85 4,088.17 2,568.25 1,512.86 18.79 4,099.89 2,590.24 1,518.16 18.78 4,127.18 Medford NWP 1,148.44 679.81 8.47 1,836.72 1,153.85 679.69 8.44 1,841.98 1,163.73 682.07 8.44 1,854.24 Roseburg 719.76 488.14 6.76 1,214.65 721.71 483.17 6.72 1,211.60 726.77 480.19 6.70 1,213.65 OR Sub-Total 5,984.20 3,502.05 99.25 9,585.49 6,008.01 3,494.02 99.01 9,601.04 6,055.98 3,499.49 98.97 9,654.44 Wa/Id Both 9,873.04 5,481.64 315.74 15,670.43 9,876.22 5,454.52 314.02 15,644.76 9,923.21 5,452.61 313.26 15,689.09 Wa/Id GTN 1,361.80 756.09 43.55 2,161.44 1,362.24 752.35 43.31 2,157.90 1,368.72 752.08 43.21 2,164.01 Wa/Id NWP 5,787.65 3,213.38 185.09 9,186.11 5,789.51 3,197.48 184.08 9,171.06 5,817.06 3,196.36 183.64 9,197.05 WA/ID Sub-Total 17,022.49 9,451.11 544.38 27,017.97 17,027.96 9,404.34 541.41 26,973.72 17,108.99 9,401.05 540.11 27,050.15 Case Total 23,006.69 12,953.15 643.63 36,603.47 23,035.97 12,898.36 640.43 36,574.76 23,164.97 12,900.54 639.08 36,704.59 Area 2030-2031: Residential 2030-2031: Commercial 2030-2031: Ind FirmSale 2030-2031 Total 2031-2032: Residential 2031-2032: Commercial 2031-2032: Ind FirmSale 2031-2032 Total 2032-2033: Residential 2032-2033: Commercial 2032-2033: Ind FirmSale 2032-2033 Total Klam Falls 1,033.53 484.41 13.58 1,531.52 1,047.58 487.47 13.61 1,548.66 1,051.44 486.00 13.56 1,551.00 La Grande 552.40 335.30 51.47 939.17 556.53 335.98 51.53 944.04 555.79 333.78 51.47 941.03 Medford GTN 2,610.86 1,522.77 18.76 4,152.40 2,641.43 1,532.12 18.80 4,192.35 2,647.77 1,528.59 18.74 4,195.10 Medford NWP 1,173.00 684.14 8.43 1,865.57 1,186.73 688.34 8.45 1,883.52 1,189.58 686.76 8.42 1,884.75 Roseburg 731.35 477.15 6.67 1,215.17 739.00 475.66 6.67 1,221.33 739.67 470.09 6.63 1,216.39 OR Sub-Total 6,101.13 3,503.78 98.92 9,703.83 6,171.26 3,519.57 99.06 9,789.89 6,184.24 3,505.21 98.83 9,788.27 Wa/Id Both 9,968.14 5,451.07 312.48 15,731.70 10,059.16 5,474.42 312.54 15,846.11 10,053.16 5,446.62 310.58 15,810.36 Wa/Id GTN 1,374.92 751.87 43.10 2,169.89 1,387.47 755.09 43.11 2,185.67 1,386.64 751.26 42.84 2,180.74 Wa/Id NWP 5,843.39 3,195.46 183.18 9,222.03 5,896.75 3,209.14 183.21 9,289.10 5,893.23 3,192.85 182.06 9,268.14 WA/ID Sub-Total 17,186.45 9,398.40 538.77 27,123.62 17,343.37 9,438.65 538.86 27,320.89 17,333.03 9,390.73 535.48 27,259.24 Case Total 23,287.58 12,902.18 637.69 36,827.45 23,514.64 12,958.22 637.92 37,110.78 23,517.27 12,895.93 634.30 37,047.51 Area 2033-2034: Residential 2033-2034: Commercial 2033-2034: Ind FirmSale 2033-2034 Total 2034-2035: Residential 2034-2035: Commercial 2034-2035: Ind FirmSale 2034-2035 Total Klam Falls 1,060.58 487.03 13.55 1,561.16 1,071.98 490.75 13.55 1,576.28 La Grande 557.34 333.06 51.47 941.87 560.04 334.03 51.47 945.54 Medford GTN 2,664.57 1,531.08 18.73 4,214.39 2,686.11 1,541.18 18.73 4,246.02 Medford NWP 1,197.13 687.88 8.41 1,893.42 1,206.80 692.42 8.41 1,907.63 Roseburg 743.72 466.64 6.61 1,216.97 749.79 467.02 6.61 1,223.42 OR Sub-Total 6,223.34 3,505.68 98.78 9,827.80 6,274.72 3,525.40 98.77 9,898.89 Wa/Id Both 10,093.84 5,446.02 309.58 15,849.44 10,188.63 5,475.30 309.41 15,973.34 Wa/Id GTN 1,392.25 751.18 42.70 2,186.13 1,405.33 755.21 42.68 2,203.22 Wa/Id NWP 5,917.08 3,192.49 181.48 9,291.05 5,972.65 3,209.66 181.38 9,363.68 WA/ID Sub-Total 17,403.17 9,389.69 533.76 27,326.62 17,566.60 9,440.17 533.47 27,540.25 Case Total 23,626.51 12,895.37 632.54 37,154.42 23,841.33 12,965.57 632.24 37,439.14 Avista Corp 2016 Natural Gas IRP Appendices 102 APPENDIX 3.1: AVISTA GAS CPA REPORT 4/21/2016 Avista Corp 2016 Natural Gas IRP Appendices 103 Avista Natural Gas Conservation Potential Assessment Results April 21, 2016 Avista Corp 2016 Natural Gas IRP Appendices 104 ~ AEG ,,#,. ,,~ .. Ap pllied Energy Group -- - 2 Topics •Overview of analysis approach •Results for each state •Market characterization •Baseline projection •Conservation potential estimates Avista Corp 2016 Natural Gas IRP Appendices 105 3 Overview of Analysis Approach Develop energy market profiles and project the baseline Customer surveys (optional) Secondary data Forecast assumptions Prototypes and energy analysis Characterize the market Utility data Customer surveys (optional) Secondary data DSM measure list Measure description Avoided costs Perform measure screening Apply customer participation rates Recent program results Best-practices research Base-year energy use by fuel & segment Base-year profiles and baseline projection by fuel, segment & end use Technical and economic potential Achievable potential Input Data Analysis Steps Results Avista Corp 2016 Natural Gas IRP Appendices 106 4 Overview of Analysis Approach Dimension Segmentation Variable Description 1 State Washington, Idaho, Oregon 2 Sector Residential, commercial, industrial 3 Segment Residential: single family, multi family, mobile homes and low income Commercial: office, restaurant, retail, grocery, school, college, health, lodging, warehouse, miscellaneous Industrial: total 4 Vintage Existing and new construction 5 End uses Heating, water heat, process, etc. (as appropriate by sector) 6 Appliances/end uses and technologies Technologies such as furnaces, boilers, water heaters, etc. 7 Equipment efficiency levels for new purchases Baseline and higher-efficiency options as appropriate for each technology Avista Corp 2016 Natural Gas IRP Appendices 107 Washington Avista Corp 2016 Natural Gas IRP Appendices 108 _ AEG yGroup 7:. .... Appllied Energ ,,,,.,, -- -, 6 High-level Market Characterization -Washington 2015 Natural Gas Sales by Sector Segment Annual Sales (DTh)% of Sales Residential 9,188,898 60% Commercial 5,734,759 38% Industrial 268,452 2% Total 30,375 100% Avista Corp 2016 Natural Gas IRP Appendices 109 7 Residential Market Characterization -Washington Washington 2015 Sales (DTh)# of Customers Average Use per Household (Therms/HH) Single Family 6,016,941 85,875 701 Multifamily 349,141 7,909 441 Mobile Home 299,264 5,085 589 Low Income 2,523,553 42,372 596 Washington Total 9,188,898 141,241 651 Avista Corp 2016 Natural Gas IRP Appendices 110 8 Residential Market Profiles -Washington Base-year annual energy use by segment and end use Annual Intensity for Average Household Data Sources: •GenPOP Survey •RBSA •Utility billing data •AEG Market Profiles Database •Secondary data as needed to fill gaps Annual Use by End Use Avista Corp 2016 Natural Gas IRP Appendices 111 9 Residential Energy Market Profile -Washington •This market profile represents the residential sector as a whole. Individual segment market profiles are provided in the report. •Saturations were developed using the GenPOP residential survey as the primary data source. Washington Total Total Households: End Use Technology Saturation UEC Intensity Usage (Therms)(Therms/(DTh) Space Heating Furnace 88.2% 509.5 449.1 6,343,260 Space Heating Boiler 2.3% 609.8 13.8 194,390 Space Heating Other Heating 9.6% 488.4 46.8 661,509 Water Heating Water Heater 56.6% 211.0 119.4 1,686,433 Appliances Clothes Dryer 9.9% 27.3 2.7 38,181 Appliances Stove/Oven 8.5% 57.3 4.9 68,899 Miscellaneous Pool Heater 0.7% 217.5 1.6 22,019 Miscellaneous Miscellaneous 100.0% 12.3 12.3 174,206 650.6 9,188,898 141,241 DTh 9,188,898 Total Avista Corp 2016 Natural Gas IRP Appendices 112 10 Residential Baseline Projection -Washington •Baseline projection provides foundation for estimating potential future savings from conservation initiatives and reflects •Household growth and electricity price forecasts (from Avista) •Appliance standards in place at end of 2015 (AEG database) •Frozen efficiency •Does not include future utility programs •Baseline projection increases 38% between 2015 and 2036, or an average of 1.5% per year Residential Baseline Energy Projection (DTh) Avista Corp 2016 Natural Gas IRP Appendices 113 11 Residential Savings Potential -Washington From 2017 to 2018, cumulative achievable potential energy savings are 62,492 DTh or 0.6% of the baseline. By 2036, cumulative savings are almost 10% of the baseline projection, or about 0.5% per year. Uses the UCT cost effectiveness test 2017 2018 2021 2026 2036 Baseline Projection (DTh)10,067,567 10,191,025 10,534,588 11,198,918 12,661,346 Cumulative Savings (DTh) Achievable Potential 27,598 62,492 207,653 497,074 1,226,734 Economic Potential 132,960 267,157 678,668 1,382,067 2,721,626 Technical Potential 187,192 377,121 956,051 1,951,370 3,828,466 Energy Savings (% of Baseline) Achievable Potential 0.3%0.6%2.0%4.4%9.7% Economic Potential 1.3%2.6%6.4%12.3%21.5% Technical Potential 1.9%3.7%9.1%17.4%30.2% Avista Corp 2016 Natural Gas IRP Appendices 114 12 Residential Savings Potential -Washington Cumulative achievable potential in 2018 Cumulative Achievable Potential (DTh) Cumulative Achievable Potential in 2018 Rank Measure / Technology 2018 Achievable Savings (Cum. DTh) % of Total 1 Windows -High Efficiency 20,516 32.8% 2 Heating –Furnace (EF 0.98)19,873 31.8% 3 Furnace -Maintenance 4,025 6.4% 4 Water Heater -Low-Flow Showerheads 3,270 5.2% 5 Water Heater -Temperature Setback 2,983 4.8% 6 Insulation -Ceiling 2,914 4.7% 7 Ducting -Repair and Sealing 2,243 3.6% 8 Water Heating -Water Heater (EF 0.67)1,831 2.9% 9 Thermostat -Programmable/Interactive 1,797 2.9% 10 Water Heater -Pipe Insulation 1,582 2.5% 11 Heating –Boiler (EF 0.98)527 0.8% 12 Water Heater -Faucet Aerators 484 0.8% 13 Boiler -Maintenance 248 0.4% 14 Boiler -Pipe Insulation 199 0.3% 15 Insulation -Wall Sheathing 1 0.0% Total 62,492 100% Avista Corp 2016 Natural Gas IRP Appendices 115 13 Commercial Market Characterization -Washington Washington 2015 Sales (DTh) Floor Space (sq. ft.) Intensity (therms/sqft) Office 608,320 23,532,683 0.26 Restaurant 357,257 1,615,817 2.21 Retail 609,276 20,141,347 0.30 Grocery 253,760 4,311,977 0.59 School 472,964 11,620,730 0.41 College 439,038 5,467,474 0.80 Health 648,945 9,103,062 0.71 Lodging 353,904 6,773,279 0.52 Warehouse 272,231 13,377,462 0.20 Miscellaneous 1,719,065 32,222,397 0.53 Washington Total 5,734,759 128,166,227 0.45 Avista Corp 2016 Natural Gas IRP Appendices 116 14 Commercial Market Profiles -Washington Base-year annual energy use by segment and end use Annual Intensity per Square Foot Data Sources: •CBSA •Utility billing data •AEG Market Profiles Database •Secondary data as needed to fill gaps Annual Use by End Use Avista Corp 2016 Natural Gas IRP Appendices 117 15 Commercial Energy Market Profile -Washington •This market profile represents the Commercial sector as a whole. Individual segment market profiles are provided in the report. •Saturations were developed using the CBSA survey as the primary data source. EUI Intensity Usage (therm)(therm/Sqft)(DTh) Heating Furnace 54.3% 0.21 0.11 1,467,831 Heating Boiler 33.1% 0.48 0.16 2,030,710 Heating Unit Heater 4.7% 0.09 0.00 55,570 Water Heating Water Heater 68.7% 0.19 0.13 1,651,292 Food Preparation Oven 25.1% 0.02 0.00 56,768 Food Preparation Fryer 7.5% 0.12 0.01 114,766 Food Preparation Broiler 13.7% 0.04 0.01 67,939 Food Preparation Griddle 16.7% 0.03 0.00 61,216 Food Preparation Range 18.3% 0.03 0.01 69,753 Food Preparation Steamer 2.0% 0.03 0.00 8,759 Food Preparation Commercial Food Prep Other 0.1% 0.01 0.00 69 Miscellaneous Pool Heater 0.9% 0.00 0.00 356 Miscellaneous Other Miscellaneous 100.0% 0.01 0.01 149,731 0.45 5,734,759Total Gas Market Profiles End Use Technology Saturation Avista Corp 2016 Natural Gas IRP Appendices 118 16 Commercial Baseline Projection -Washington •Baseline projection provides foundation for estimating potential future savings from conservation initiatives and reflects •Customer growth (from Avista) •Building Codes and appliance standards in place at end of 2015 (AEG database) •Frozen efficiency •Does not include future utility programs •Baseline projection increases 23% between 2015 and 2036, or an average of 1% per year Commercial Baseline Energy Projection (DTh) Avista Corp 2016 Natural Gas IRP Appendices 119 17 Estimating Conservation Potential •The study analyzed 100 measures covering residential, commercial and industrial sectors. •Cost-effectiveness screening to estimate economic potential was done using utility cost test for Washington and Idaho, and using the TRC for Oregon •Customer adoption or “ramp rates” are needed to estimate achievable potential. The study used regional ramp rates to start and then calibrated based on Avista’s program history •The study uses AEG’s LoadMAP model to estimate potential Technical Potential Theoretical upper limit of EE, where all efficiency measures are phased in regardless of cost Economic Potential Also a theoretical upper limit of EE, but includes only cost-effective measures Achievable Potential EE potential that can be realistically achieved by utilities, accounting for customer adoption rates and how quickly programs can be implemented Avista Corp 2016 Natural Gas IRP Appendices 120 18 Commercial Savings Potential -Washington From 2017 to 2018, cumulative achievable potential energy savings are 53,246 DTh or 0.9% of the baseline. By 2036, cumulative savings are over 12% of the baseline projection, or about 0.7% per year. Uses the UCT cost effectiveness test 2017 2018 2021 2026 2036 Baseline Projection (DTh)6,220,478 6,236,027 6,305,231 6,490,547 7,066,197 Cumulative Savings (DTh) Achievable Potential 22,978 53,246 176,816 413,219 878,225 Economic Potential 70,810 140,765 339,275 637,762 1,124,744 Technical Potential 108,572 214,053 512,953 960,878 1,686,375 Energy Savings (% of Baseline) Achievable Potential 0.4%0.9%2.8%6.4%12.4% Economic Potential 1.1%2.3%5.4%9.8%15.9% Technical Potential 1.7%3.4%8.1%14.8%23.9% Avista Corp 2016 Natural Gas IRP Appendices 121 19 Commercial Savings Potential -Washington Cumulative achievable potential in 2018 Cumulative Achievable Potential (DTh) Cumulative Achievable Potential in 2018 Rank Measure / Technology 2018 Achievable Savings (Cum. DTh) % of Total 1 Retrocommissioning 13,476 25.3% 2 Heating –Boiler (EF 0.96)11,887 22.3% 3 Gas Boiler -Hot Water Reset 5,159 9.7% 4 Heating –Furnace (EF 0.96)4,102 7.7% 5 Insulation -Ceiling 3,360 6.3% 6 Water Heating -Water Heater (Tankless)2,826 5.3% 7 Water Heater -Faucet Aerators/Low Flow Nozzles 2,150 4.0% 8 Water Heater -Central Controls 1,979 3.7% 9 Strategic Energy Management 1,784 3.4% 10 Water Heater -Pre-Rinse Spray Valve 1,564 2.9% 11 Gas Boiler -Parallel Positioning Control 1,540 2.9% 12 Food Preparation –Fryer (ENERGY STAR)740 1.4% 13 Steam Trap Maintenance 657 1.2% 14 Food Preparation -Oven (ENERGY STAR)386 0.7% 15 HVAC -Shut Off Damper 304 0.6% 16 Food Preparation -Griddle (ENERGY STAR)235 0.4% 17 Windows -High Efficiency 223 0.4% 18 Water Heater -Pipe Insulation 204 0.4% 19 Food Preparation -Steamer (ENERGY STAR)184 0.3% 20 Heating -Unit Heater (Condensing)171 0.3% Total 52,933 99.4%Avista Corp 2016 Natural Gas IRP Appendices 122 20 Industrial Energy Market Profile -Washington •This market profile represents the Industrial sector as a whole. The industrial sector is not large enough to warrant further segmentation. EUI Intensity Usage (Therms)(Therms/sqft)(Dth) Space Heating Furnace 56.5%0.028 0.02 5,563 Space Heating Boiler 34.4%0.089 0.03 10,891 Space Heating Other Heating 4.9%0.014 0.00 239 Process Process Heating 100.0% 0.369 0.37 131,596 Process Process Boiler 100.0% 0.282 0.28 100,538 Process Process Cooling 100.0% 0.001 0.00 407 Process Other Process 100.0% 0.004 0.00 1,580 Other Other Uses 100.0% 0.049 0.05 17,638 0.75 268,452 Washington Industrial Total Sq Ft:3,567,948 DTh 268,452 Total End Use Technology Saturation Avista Corp 2016 Natural Gas IRP Appendices 123 21 Industrial Baseline Projection -Washington •Baseline projection provides foundation for estimating potential future savings from conservation initiatives and reflects •Customer growth (from Avista) •Building Codes and appliance standards in place at end of 2015 (AEG database) •Frozen efficiency •Does not include future utility programs •Baseline projection increases 35% between 2015 and 2036, or an average of 1.4% per year Industrial Baseline Energy Projection (DTh) Avista Corp 2016 Natural Gas IRP Appendices 124 22 Industrial Savings Potential -Washington From 2017 to 2018, cumulative achievable potential energy savings are 777 DTh or 0.3% of the baseline. By 2036, cumulative savings are 2.3% of the baseline projection, or about 0.1% per year. Uses the UCT cost effectiveness test 2017 2018 2021 2026 2036 Baseline Projection (DTh)283,824 287,571 298,345 318,546 363,144 Cumulative Savings (DTh) Achievable Potential 383 777 1,993 4,050 8,414 Economic Potential 876 1,757 4,413 8,941 18,457 Technical Potential 3,195 6,425 16,314 33,603 71,042 Energy Savings (% of Baseline) Achievable Potential 0.1%0.3%0.7%1.3%2.3% Economic Potential 0.3%0.6%1.5%2.8%5.1% Technical Potential 1.1%2.2%5.5%10.5%19.6% Avista Corp 2016 Natural Gas IRP Appendices 125 23 Industrial Savings Potential -Washington Cumulative achievable potential in 2018 Cumulative Achievable Potential (DTh) Cumulative Achievable Potential in 2018 Rank Measure / Technology 2018 Achievable Savings (Cum. DTh) % of Total 1 Custom 415 53.5% 2 Boiler -Hot Water Reset 205 26.4% 3 Boiler -Parallel Positioning Control 97 12.5% 4 Boiler -Maintenance 46 5.9% 5 Steam Trap Maintenance 11 1.5% 6 Gas Furnace -Maintenance 2 0.3% Total 777 100.0% Avista Corp 2016 Natural Gas IRP Appendices 126 Idaho Avista Corp 2016 Natural Gas IRP Appendices 127 _ AEG yGroup 7:. .... Appllied Energ ,,,,.,, -- -, 25 High-level Market Characterization -Idaho 2015 Natural Gas Sales by Sector Segment Annual Sales (DTh)% of Sales Residential 4,304,740 62% Commercial 2,456,621 35% Industrial 187,203 3% Total 6,948,564 100% Avista Corp 2016 Natural Gas IRP Appendices 128 26 Residential Market Characterization -Idaho Idaho 2015 Sales (DTh)# of Customers Average Use per Household (Therms/HH) Single Family 2,814,373 42,852 657 Multifamily 142,894 3,454 414 Mobile Home 174,973 3,172 552 Low Income 1,172,501 21,003 558 Idaho Total 4,304,740 70,481 611 Avista Corp 2016 Natural Gas IRP Appendices 129 27 Residential Market Profiles -Idaho Base-year annual energy use by segment and end use Annual Intensity for Average Household Data Sources: •GenPOP Survey •RBSA •Utility billing data •AEG Market Profiles Database •Secondary data as needed to fill gaps Annual Use by End Use Avista Corp 2016 Natural Gas IRP Appendices 130 28 Residential Energy Market Profile -Idaho •This market profile represents the residential sector as a whole. Individual segment market profiles are provided in the report. •Saturations were developed using the GenPOP residential survey as the primary data source. Idaho Total Total Households: End Use Technology Saturation UEC Intensity Usage (Therms)(Therms/(DTh) Space Heating Furnace 84.2% 484.5 407.8 2,873,917 Space Heating Boiler 2.0% 579.2 11.8 83,322 Space Heating Other Heating 13.8% 466.4 64.4 453,852 Water Heating Water Heater 54.3% 200.8 109.1 768,890 Appliances Clothes Dryer 9.2% 29.0 2.7 18,876 Appliances Stove/Oven 9.2% 60.1 5.5 39,043 Miscellaneous Pool Heater 0.3% 217.4 0.6 4,134 Miscellaneous Miscellaneous 100.0% 8.9 8.9 62,706 610.8 4,304,740 70,481 DTh 4,304,740 Total Avista Corp 2016 Natural Gas IRP Appendices 131 29 Residential Baseline Projection -Idaho •Baseline projection provides foundation for estimating potential future savings from conservation initiatives and reflects •Household growth and electricity price forecasts (from Avista) •Appliance standards in place at end of 2015 (AEG database) •Frozen efficiency •Does not include future utility programs •Baseline projection increases 44% between 2015 and 2036, or an average of 1.7% per year Residential Baseline Energy Projection (DTh) Avista Corp 2016 Natural Gas IRP Appendices 132 30 Residential Savings Potential -Idaho From 2017 to 2018, cumulative achievable potential energy savings are 62,492 DTh or 0.6% of the baseline. By 2036, cumulative savings are almost 10% of the baseline projection, or about 0.5% per year. Uses the UCT cost effectiveness test 2017 2018 2021 2026 2036 Baseline Projection (DTh)4,741,736 4,802,813 4,992,555 5,366,588 6,213,091 Cumulative Savings (DTh) Achievable Potential 11,138 25,406 85,812 208,875 536,817 Economic Potential 53,686 108,042 276,801 577,890 1,198,833 Technical Potential 82,162 165,579 422,556 873,781 1,776,196 Energy Savings (% of Baseline) Achievable Potential 0.2%0.5%1.7%3.9%8.6% Economic Potential 1.1%2.2%5.5%10.8%19.3% Technical Potential 1.7%3.4%8.5%16.3%28.6% Avista Corp 2016 Natural Gas IRP Appendices 133 31 Residential Savings Potential -Idaho Cumulative achievable potential in 2018 Cumulative Achievable Potential (DTh) Cumulative Achievable Potential in 2018 Rank Measure / Technology 2018 Achievable Savings (Cum. DTh) % of Total 1 Windows -High Efficiency 9,778 38.5% 2 Heating –Furnace (EF 0.98)6,692 26.3% 3 Furnace -Maintenance 1,821 7.2% 4 Water Heater -Low-Flow Showerheads 1,480 5.8% 5 Insulation -Ceiling 1,379 5.4% 6 Water Heater -Temperature Setback 1,365 5.4% 7 Thermostat -Programmable/Interactive 861 3.4% 8 Water Heater -Pipe Insulation 725 2.9% 9 Water Heating -Water Heater (EF 0.67)660 2.6% 10 Heating –Boiler (EF 0.98)235 0.9% 11 Water Heater -Faucet Aerators 219 0.9% 12 Boiler -Maintenance 106 0.4% 13 Boiler -Pipe Insulation 86 0.3% Total 25,406 100% Avista Corp 2016 Natural Gas IRP Appendices 134 32 Commercial Market Characterization -Idaho Idaho 2015 Sales (DTh) Floor Space (sq. ft.) Intensity (therms/sqft) Office 214,228 8,388,655 0.26 Restaurant 55,373 253,503 2.18 Retail 314,742 10,531,910 0.30 Grocery 97,810 1,682,340 0.58 School 387,333 9,633,126 0.40 College 360,160 4,540,014 0.79 Health 222,359 3,157,269 0.70 Lodging 135,614 2,627,216 0.52 Warehouse 110,269 5,484,890 0.20 Miscellaneous 558,735 10,601,048 0.53 Idaho Total 2,456,621 56,899,971 0.43 Avista Corp 2016 Natural Gas IRP Appendices 135 33 Commercial Market Profiles -Idaho Base-year annual energy use by segment and end use Annual Intensity per Square Foot Data Sources: •CBSA •Utility billing data •AEG Market Profiles Database •Secondary data as needed to fill gaps Annual Use by End Use Avista Corp 2016 Natural Gas IRP Appendices 136 34 Commercial Energy Market Profile -Idaho •This market profile represents the Commercial sector as a whole. Individual segment market profiles are provided in the report. •Saturations were developed using the CBSA survey as the primary data source. EUI Intensity Usage (therm)(therm/Sqft)(DTh) Heating Furnace 51.2% 0.20 0.10 588,380 Heating Boiler 36.0% 0.45 0.16 930,819 Heating Unit Heater 4.9% 0.09 0.00 25,385 Water Heating Water Heater 69.3% 0.19 0.13 734,648 Food Preparation Oven 24.5% 0.02 0.00 27,505 Food Preparation Fryer 7.7% 0.09 0.01 40,765 Food Preparation Broiler 14.0% 0.03 0.00 22,933 Food Preparation Griddle 16.3% 0.02 0.00 20,023 Food Preparation Range 18.3% 0.02 0.00 23,972 Food Preparation Steamer 3.0% 0.02 0.00 4,249 Food Preparation Commercial Food Prep Other 0.1% 0.00 0.00 29 Miscellaneous Pool Heater 0.8% 0.00 0.00 119 Miscellaneous Other Miscellaneous 100.0% 0.01 0.01 37,793 0.43 2,456,621 Gas Market Profiles End Use Technology Saturation Total Avista Corp 2016 Natural Gas IRP Appendices 137 35 Commercial Baseline Projection -Idaho •Baseline projection provides foundation for estimating potential future savings from conservation initiatives and reflects •Customer growth (from Avista) •Building Codes and appliance standards in place at end of 2015 (AEG database) •Frozen efficiency •Does not include future utility programs •Baseline projection increases 23% between 2015 and 2036, or an average of 1% per year Commercial Baseline Energy Projection (DTh) Avista Corp 2016 Natural Gas IRP Appendices 138 36 Commercial Savings Potential -Idaho From 2017 to 2018, cumulative achievable potential energy savings are 21,619 DTh or 0.8% of the baseline. By 2036, cumulative savings are almost 12% of the baseline projection, or about 0.6% per year. Uses the UCT cost effectiveness test 2017 2018 2021 2026 2036 Baseline Projection (DTh)2,656,853 2,664,007 2,695,763 2,776,753 3,021,253 Cumulative Savings (DTh) Achievable Potential 9,311 21,619 72,680 170,883 359,503 Economic Potential 29,135 58,035 140,114 263,474 459,135 Technical Potential 47,785 94,237 226,002 423,332 744,715 Energy Savings (% of Baseline) Achievable Potential 0.4%0.8%2.7%6.2%11.9% Economic Potential 1.1%2.2%5.2%9.5%15.2% Technical Potential 1.8%3.5%8.4%15.2%24.6% Avista Corp 2016 Natural Gas IRP Appendices 139 37 Commercial Savings Potential -Idaho Cumulative achievable potential in 2018 Cumulative Achievable Potential (DTh) Cumulative Achievable Potential in 2018 Rank Measure / Technology 2018 Achievable Savings (Cum. DTh) % of Total 1 Retrocommissioning 5,761 26.6% 2 Heating –Boiler (EF 0.96)4,812 22.3% 3 Gas Boiler -Hot Water Reset 2,364 10.9% 4 Heating –Furnace (EF 0.96)1,919 8.9% 5 Water Heating -Water Heater (Tankless)1,343 6.2% 6 Insulation -Ceiling 1,105 5.1% 7 Water Heater -Faucet Aerators/Low Flow Nozzles 955 4.4% 8 Water Heater -Central Controls 892 4.1% 9 Water Heater -Pre-Rinse Spray Valve 631 2.9% 10 Gas Boiler -Parallel Positioning Control 598 2.8% 11 Steam Trap Maintenance 294 1.4% 12 Food Preparation –Fryer (ENERGY STAR)264 1.2% 13 Food Preparation –Oven (ENERGY STAR)188 0.9% 14 Water Heater -Pipe Insulation 91 0.4% 15 Food Preparation -Steamer (ENERGY STAR)90 0.4% 16 Food Preparation -Griddle (ENERGY STAR)77 0.4% 17 Windows -High Efficiency 77 0.4% 18 Food Preparation -Broiler (ENERGY STAR)55 0.3% 19 Heating -Unit Heater (Condensing)47 0.2% 20 HVAC -Duct Repair and Sealing 27 0.1% Total 21,592 99.9%Avista Corp 2016 Natural Gas IRP Appendices 140 38 Industrial Energy Market Profile -Idaho •This market profile represents the Industrial sector as a whole. The industrial sector is not large enough to warrant further segmentation.EUI Intensity Usage (Therms)(Therms/sqft)(Dth) Space Heating Furnace 56.5% 0.026 0.01 3,879 Space Heating Boiler 34.4% 0.085 0.03 7,595 Space Heating Other Heating 4.9% 0.013 0.00 167 Process Process Heating 100.0% 0.353 0.35 91,768 Process Process Boiler 100.0% 0.270 0.27 70,109 Process Process Cooling 100.0% 0.001 0.00 284 Process Other Process 100.0% 0.004 0.00 1,102 Other Other Uses 100.0% 0.047 0.05 12,299 0.72 187,203 Idaho Industrial Total Sq Ft:2,596,257 DTh 187,203 Total End Use Technology Saturation Avista Corp 2016 Natural Gas IRP Appendices 141 39 Industrial Baseline Projection -Idaho •Baseline projection provides foundation for estimating potential future savings from conservation initiatives and reflects •Customer growth (from Avista) •Building Codes and appliance standards in place at end of 2015 (AEG database) •Frozen efficiency •Does not include future utility programs •Baseline projection increases 70% between 2015 and 2036, or an average of 2.5% per year Industrial Baseline Energy Projection (DTh) Avista Corp 2016 Natural Gas IRP Appendices 142 40 Industrial Savings Potential -Idaho From 2017 to 2018, cumulative achievable potential energy savings are 641 DTh or 0.3% of the baseline. By 2036, cumulative savings are 4.3% of the baseline projection, or about 0.1% per year. Uses the UCT cost effectiveness test 2017 2018 2021 2026 2036 Baseline Projection (DTh)211,629 216,490 229,739 256,083 318,182 Cumulative Savings (DTh) Achievable Potential 306 641 1,809 4,411 13,717 Economic Potential 700 1,450 4,005 9,723 29,846 Technical Potential 2,446 5,049 13,661 31,578 81,807 Energy Savings (% of Baseline) Achievable Potential 0.1%0.3%0.8%1.7%4.3% Economic Potential 0.3%0.7%1.7%3.8%9.4% Technical Potential 1.2%2.3%5.9%12.3%25.7% Avista Corp 2016 Natural Gas IRP Appendices 143 41 Industrial Savings Potential-Idaho Cumulative achievable potential in 2018 Cumulative Achievable Potential (DTh) Cumulative Achievable Potential in 2018 Rank Measure / Technology 2018 Achievable Savings (Cum. DTh) % of Total 1 Custom 338 52.7% 2 Boiler -Hot Water Reset 171 26.7% 3 Boiler -Parallel Positioning Control 81 12.7% 4 Boiler -Maintenance 39 6.0% 5 Steam Trap Maintenance 10 1.5% 6 Gas Furnace -Maintenance 2 0.3% Total 641 100.0% Avista Corp 2016 Natural Gas IRP Appendices 144 Oregon Avista Corp 2016 Natural Gas IRP Appendices 145 _ AEG yGroup 7:. .... Appllied Energ ,,,,.,, -- -, 43 High-level Market Characterization -Oregon 2015 Natural Gas Sales by Sector Segment Annual Sales (DTh)% of Sales Residential 4,303,206 61% Commercial 2,699,252 38% Industrial 51,369 1% Total 7,053,827 100% Avista Corp 2016 Natural Gas IRP Appendices 146 44 Residential Market Characterization -Oregon Oregon 2015 Sales (DTh)# of Customers Average Use per Household (Therms/HH) Single Family 2,811,856 53,617 524 Multifamily 81,940 2,480 330 Mobile Home 271,183 6,156 441 Low Income 1,138,226 25,534 446 Oregon Total 4,303,206 87,787 490 Avista Corp 2016 Natural Gas IRP Appendices 147 45 Residential Market Profiles -Oregon Base-year annual energy use by segment and end use Annual Intensity for Average Household Data Sources: •RBSA •Utility billing data •AEG Market Profiles Database •Secondary data as needed to fill gaps Annual Use by End Use Avista Corp 2016 Natural Gas IRP Appendices 148 46 Residential Energy Market Profile -Oregon •This market profile represents the residential sector as a whole. Individual segment market profiles are provided in the report. •Saturations were developed using the RBSA survey as the primary data source. Avista Corp 2016 Natural Gas IRP Appendices 149 47 Residential Baseline Projection -Oregon •Baseline projection provides foundation for estimating potential future savings from conservation initiatives and reflects •Household growth and electricity price forecasts (from Avista) •Appliance standards in place at end of 2015 (AEG database) •Frozen efficiency •Does not include future utility programs •Baseline projection increases 30% between 2015 and 2036, or an average of 1.2% per year Residential Baseline Energy Projection (DTh) Avista Corp 2016 Natural Gas IRP Appendices 150 48 Residential Savings Potential -Oregon From 2017 to 2018, cumulative achievable potential energy savings are 13,839 DTh or 0.3% of the baseline. By 2036, cumulative savings are almost 5% of the baseline projection, or about 0.2% per year. Uses the TRC cost effectiveness test 2017 2018 2021 2026 2036 Baseline Projection (DTh)4,808,069 4,852,168 4,931,394 5,137,402 5,588,507 Cumulative Savings (DTh) Achievable Potential 6,507 13,839 38,671 94,086 260,939 Economic Potential 21,867 44,161 111,658 228,569 483,538 Technical Potential 83,073 167,062 418,531 844,811 1,615,605 Energy Savings (% of Baseline) Achievable Potential 0.1%0.3%0.8%1.8%4.7% Economic Potential 0.5%0.9%2.3%4.4%8.7% Technical Potential 1.7%3.4%8.5%16.4%28.9% Avista Corp 2016 Natural Gas IRP Appendices 151 49 Residential Savings Potential -Oregon Cumulative achievable potential in 2018 Cumulative Achievable Potential (DTh) Cumulative Achievable Potential in 2018 Rank Measure / Technology 2018 Achievable Savings (Cum. DTh) % of Total 1 Heating -Furnace 7,400 53.5% 2 Water Heater -Low-Flow Showerheads 1,743 12.6% 3 Water Heater -Temperature Setback 1,640 11.9% 4 Furnace -Maintenance 1,477 10.7% 5 Water Heater -Pipe Insulation 871 6.3% 6 Water Heater -Faucet Aerators 257 1.9% 7 Windows -High Efficiency 235 1.7% 8 Boiler -Maintenance 108 0.8% 9 Boiler -Pipe Insulation 86 0.6% 10 Heating –Boiler (EF 0.98)22 0.2% Total 13,839 100% Avista Corp 2016 Natural Gas IRP Appendices 152 50 Commercial Market Characterization -Oregon Oregon 2015 Sales (DTh) Floor Space (sq. ft.) Intensity (therms/sqft) Office 406,757 8,388,655 0.16 Restaurant 302,349 253,503 1.39 Retail 401,181 10,531,910 0.19 Grocery 173,578 1,682,340 0.37 School 273,450 9,633,126 0.26 College 34,880 4,540,014 0.50 Health 401,052 3,157,269 0.45 Lodging 174,610 2,627,216 0.33 Warehouse 143,426 5,484,890 0.13 Miscellaneous 387,969 10,601,048 0.34 Oregon Total 2,699,252 56,899,971 0.27 Avista Corp 2016 Natural Gas IRP Appendices 153 51 Commercial Market Profiles -Oregon Base-year annual energy use by segment and end use Annual Intensity per Square Foot Data Sources: •CBSA •Utility billing data •AEG Market Profiles Database •Secondary data as needed to fill gaps Annual Use by End Use Avista Corp 2016 Natural Gas IRP Appendices 154 52 Commercial Energy Market Profile -Oregon •This market profile represents the Commercial sector as a whole. Individual segment market profiles are provided in the report. •Saturations were developed using the CBSA survey as the primary data source. Avista Corp 2016 Natural Gas IRP Appendices 155 53 Commercial Baseline Projection -Oregon •Baseline projection provides foundation for estimating potential future savings from conservation initiatives and reflects •Customer growth (from Avista) •Building Codes and appliance standards in place at end of 2015 (AEG database) •Frozen efficiency •Does not include future utility programs •Baseline projection increases 38% between 2015 and 2036, or an average of 1.5% per year Commercial Baseline Energy Projection (DTh) Avista Corp 2016 Natural Gas IRP Appendices 156 54 Commercial Savings Potential -Oregon From 2017 to 2018, cumulative achievable potential energy savings are 17,527 DTh or 0.5% of the baseline. By 2036, cumulative savings are almost 10% of the baseline projection, or about 0.5% per year. Uses the TRC cost effectiveness test 2017 2018 2021 2026 2036 Baseline Projection (DTh)3,215,033 3,219,537 3,264,933 3,383,711 3,729,054 Cumulative Savings (DTh) Achievable Potential 7,921 17,527 54,701 142,594 363,123 Economic Potential 22,299 44,184 110,800 228,191 470,854 Technical Potential 56,697 109,388 262,836 500,789 919,302 Energy Savings (% of Baseline) Achievable Potential 0.2%0.5%1.7%4.2%9.7% Economic Potential 0.7%1.4%3.4%6.7%12.6% Technical Potential 1.8%3.4%8.1%14.8%24.7% Avista Corp 2016 Natural Gas IRP Appendices 157 55 Commercial Savings Potential -Oregon Cumulative achievable potential in 2018 Cumulative Achievable Potential (DTh) Cumulative Achievable Potential in 2018 Rank Measure / Technology 2018 Achievable Savings (Cum. DTh) % of Total 1 Retrocommissioning 5,781 33.0% 2 Gas Boiler -Hot Water Reset 1,954 11.2% 3 Water Heater -Central Controls 1,711 9.8% 4 Heating -Boiler 1,700 9.7% 5 Water Heating -Water Heater 1,316 7.5% 6 Commissioning 1,162 6.6% 7 Water Heater -Faucet Aerators/Low Flow Nozzles 1,098 6.3% 8 Water Heater -Pre-Rinse Spray Valve 1,009 5.8% 9 Food Preparation -Fryer 519 3.0% 10 Steam Trap Maintenance 384 2.2% 11 Food Preparation -Oven 215 1.2% 12 Food Preparation -Griddle 160 0.9% 13 Windows -High Efficiency 144 0.8% 14 Food Preparation -Steamer 115 0.7% 15 Water Heater -Pipe Insulation 106 0.6% 16 Water Heater -Drainwater Heat Recovery 68 0.4% 17 HVAC -Duct Repair and Sealing 46 0.3% 18 Food Preparation -Broiler 37 0.2% 19 Gas Boiler -Parallel Positioning Control 2 0.0% 20 Food Preparation -Range 0 0.0% Total 17,527 100.0%Avista Corp 2016 Natural Gas IRP Appendices 158 56 Industrial Energy Market Profile -Oregon •This market profile represents the Industrial sector as a whole. The industrial sector is not large enough to warrant further segmentation. EUI Intensity Usage (Therms)(Therms/sqft)(Dth) Space Heating Furnace 56.5% 0.025 0.01 1,064 Space Heating Boiler 34.4% 0.081 0.03 2,084 Space Heating Other Heating 4.9% 0.013 0.00 46 Process Process Heating 100.0% 0.338 0.34 25,181 Process Process Boiler 100.0% 0.258 0.26 19,238 Process Process Cooling 100.0% 0.001 0.00 78 Process Other Process 100.0% 0.004 0.00 302 Other Other Uses 100.0% 0.045 0.05 3,375 0.69 51,369 Oregon Industrial 51,369 Total Sq Ft:744,804 DTh End Use Technology Saturation Total Avista Corp 2016 Natural Gas IRP Appendices 159 57 Industrial Baseline Projection -Oregon •Baseline projection provides foundation for estimating potential future savings from conservation initiatives and reflects •Customer growth (from Avista) •Building Codes and appliance standards in place at end of 2015 (AEG database) •Frozen efficiency •Does not include future utility programs •Baseline projection increases 31% between 2015 and 2036, or an average of 1.4% per year Industrial Baseline Energy Projection (DTh) Avista Corp 2016 Natural Gas IRP Appendices 160 58 Industrial Savings Potential -Oregon From 2017 to 2018, cumulative achievable potential energy savings are 641 DTh or 0.3% of the baseline. By 2036, cumulative savings are 4.3% of the baseline projection, or about 0.1% per year. Uses the TRC cost effectiveness test 2017 2018 2021 2026 2036 Baseline Projection (DTh)51,346 52,041 54,200 58,303 67,465 Cumulative Savings (DTh) Achievable Potential 73 147 379 773 1,622 Economic Potential 166 333 839 1,707 3,557 Technical Potential 602 1,209 3,078 6,371 13,602 Energy Savings (% of Baseline) Achievable Potential 0.0%0.1%0.2%0.3%0.5% Economic Potential 0.1%0.2%0.4%0.7%1.1% Technical Potential 0.3%0.6%1.3%2.5%4.3% Avista Corp 2016 Natural Gas IRP Appendices 161 59 Industrial Savings Potential-Oregon Cumulative achievable potential in 2018 Cumulative Achievable Potential (DTh) Cumulative Achievable Potential in 2018 Rank Measure / Technology 2018 Achievable Savings (Cum. DTh) % of Total 1 Custom 338 52.7% 2 Boiler -Hot Water Reset 171 26.7% 3 Boiler -Parallel Positioning Control 81 12.7% 4 Boiler -Maintenance 39 6.0% 5 Steam Trap Maintenance 10 1.5% 6 Gas Furnace -Maintenance 2 0.3% Total 641 100.0% Avista Corp 2016 Natural Gas IRP Appendices 162 Ingrid Rohmund irohmund@appliedenergygroup.com Bridget Kester bkester@appliedenergygroup.com Fuong Nguyen fnguyen@appliedenergygroup.com Joe Reilly jreilly@appliedenergygroup.com Thank You! Avista Corp 2016 Natural Gas IRP Appendices 163 APPENDIX – CHAPTER 3 APPENDIX 3.2: ENVIRONMENTAL EXTERNALITIES OVERVIEW (OREGON JURISDICTION ONLY) The methodology for determining avoided costs from reduced incremental natural gas usage considers commodity and variable transportation costs only. These avoided cost streams do not include environmental externality costs related to the gathering, transmission, distribution or end-use of natural gas. Per traditional economic theory and industry practice, an environmental externality factor is typically added to the avoided cost when there is an opportunity to displace traditional supply-side resources with an alternative resource with no adverse environmental impact. REGULATORY GUIDANCE The Oregon Public Utility Commission (OPUC) issued Order 93-965 (UM-424) to address how utilities should consider the impact of environmental externalities in planning for future energy resources. The Order required analysis on the potential natural gas cost impacts from emitting carbon dioxide (CO2) and nitric-oxide (NOx). The OPUC’s Order No. 07-002 in Docket UM 1056 (Investigation Into Integrated Resource Planning) established the following guideline for the treatment of environmental costs used by energy utilities that evaluate demand-side and supply-side energy choices: UM 1056, Guideline 8 - Environmental Costs “Utilities should include, in their base-case analyses, the regulatory compliance costs they expect for carbon dioxide (CO2), nitrogen oxides (NOx), sulfur oxides (SO2), and mercury (Hg) emissions. Utilities should analyze the range of potential CO2 regulatory costs in Order No. 93-695, from $0 - $40 (1990$). In addition, utilities should perform sensitivity analysis on a range of reasonably possible cost adders for nitrogen oxides (NOx), sulfur dioxide (SO2), and mercury (Hg), if applicable. In June 2008, the OPUC issued Order 08-338 (UM1302) which revised UM1056, Guideline 8. The revised guideline requires the utility should construct a base case portfolio to reflect what it considers to be the most likely regulatory compliance future for the various emissions. Additionally the guideline requires the utility to develop several compliance scenarios ranging from the present CO2 regulatory level to the upper reaches of credible proposals and each scenario should include a time profile of CO2 costs. The utility is also required to include a “trigger point” analysis in which the utility must determine at what level of carbon costs its selection of portfolio resources would be significantly different. ANALYSIS Unlike electric utilities, environmental cost issues rarely impact a natural gas utility's supply-side resource options. This is because the only supply-side energy resource is natural gas. The utility cannot choose between say "dirty" coal-fired generation and "clean" wind energy sources. The supply-side implication of environmental externalities generally relates to combustion of fuel to move or compress natural gas. Avista’s direct gas distribution system infrastructure relies solely on the upstream line pressure of the interstate pipeline transportation network to distribute natural gas to its customers and thus does not directly combust fuels that result in any CO2, NOx, SO2, or Hg emissions. Avista Corp 2016 Natural Gas IRP Appendices 164 APPENDIX – CHAPTER 3 Upstream gas system infrastructure (pipelines, storage facilities, and gathering systems), however, do produce CO2 emissions via compressors used to pressurize and move natural gas. Accessing CO2 emissions data on these upstream activities to perform detailed meaningful analysis is challenging. In the 2009 Natural Gas IRP there was significant momentum regarding GHG legislation and the movement towards the creation of carbon cap and trade markets or tax structure. Since then, the momentum has slowed significantly. Where there is still a focus on reducing GHG emissions and improving the nation’s carbon footprint, the timing of implementing a carbon cap and trade/tax framework has been delayed. Additionally, the pricing level of the framework has been greatly reduced.. Whichever structure ultimately gets implemented, Avista believes the cost pass through mechanisms for upstream gas system infrastructure will not make a difference in supply-side resource selection although the amount of cost pass through could differ widely. Table 3.2.1 summarizes a range of environmental cost adders we believe capture several compliance futures including our expected scenario. The CO2 cost adders reflect outlooks we obtained from one of our consultants, and following discussion and feedback from the TAC, have been incorporated into our Expected, Low Growth/High Price, and Alternate Planning Standard portfolios. The guidelines also call for a trigger point analysis that reflects a “turning point” at which an alternate resource portfolio would be selected at different carbon cost adders levels. Because natural gas is the only supply resource applicable to LDC’s any alternate resource portfolio selection would be a result of delivery methods of natural gas to customers. Conceptually, there could be differing levels of cost adders applicable to pipeline transported supply versus in service territory LNG storage gas. From a practical standpoint however, the differences in these relative cost adders would be very minor and would not change supply- side resource selection regardless of various carbon cost adder levels. We do acknowledge there is influence to the avoided costs which would impact the cost effectiveness of demand-side measures in the DSM business planning process. CONSERVATON COST ADVANTAGE For this IRP, we also incorporated a 10 percent environmental externality factor into our assessment of the cost-effectiveness of existing demand-side management programs. Our assessment of prospective demand- side management opportunities is based on an avoided cost stream that includes this 10 percent factor. Environmental externalities were evaluated in the IRP by adding the cost per therm equivalent of the externality cost values to supply-side resources as described in OPUC Order No. 93-965. Avista found that the environmental cost adders had no impact on the company’s supply-side choices, although they did impact the level of demand-side measures that could be cost-effective to acquire. REGULATORY FILING Avista will file revised cost-effectiveness limits (CELs) based upon the updated avoided costs available from this IRP process within the prescribed regulatory timetable. Avista Corp 2016 Natural Gas IRP Appendices 165 APPENDIX – CHAPTER 3 TABLE 3.2.1: ENVIRONMENTAL EXTERNALITIES COST ADDER ANALYSIS (2015$) 2020 2025 2030 2035 $/ton $ 2,500 $ 2,500 $ 2,500 $ 2,500 $/lb $ 1.25 $ 1.25 $ 1.25 $ 1.25 lbs/therm 0.008 0.008 0.008 0.008 NOx Adder $/therm $ 0.01 $ 0.01 $ 0.01 $ 0.01 $/ton $ 10.55 $ 11.71 $ 14.99 $ 19.93 $/lb $ 0.0053 $ 0.0059 $ 0.0075 $ 0.0100 lbs/therm 11.64 11.64 11.64 11.64 CO2 Adder $/therm $ 0.06 $ 0.07 $ 0.09 $ 0.12 To t a l Total Adders $/therm $ 0.07 $ 0.08 $ 0.10 $ 0.13 2020 2025 2030 2035 $/ton $ 2,500 $ 2,500 $ 2,500 $ 2,500 $/lb $ 1.25 $ 1.25 $ 1.25 $ 1.25 lbs/therm 0.008 0.008 0.008 0.008 NOx Adder $/therm $ 0.01 $ 0.01 $ 0.01 $ 0.01 $/ton $ 25.88 $ 30.73 $ 36.50 $ 43.35 $/lb $ 0.0129 $ 0.0154 $ 0.0182 $ 0.0217 lbs/therm 11.64 11.64 11.64 11.64 CO2 Adder $/therm $ 0.15 $ 0.18 $ 0.21 $ 0.25 To t a l Total Adders $/therm $ 0.16 $ 0.19 $ 0.22 $ 0.26 2020 2025 2030 2035 $/ton $ 500 $ 500 $ 500 $ 500 $/lb $ 0.25 $ 0.25 $ 0.25 $ 0.25 lbs/therm 0.008 0.008 0.008 0.008 NOx Adder $/therm $ 0.00 $ 0.00 $ 0.00 $ 0.00 $/ton $ - $ - $ - $ - $/lb $ - $ - $ - $ - lbs/therm 11.64 11.64 11.64 11.64 CO2 Adder $/therm $ - $ - $ - $ - To t a l Total Adders $/therm $ 0.00 $ 0.00 $ 0.00 $ 0.00 CO 2 NO x Lo w C a r b o n L o w N O x Ex p e c t e d C a r b o n C a s e NO x CO 2 Hi g h C a r b o n C a s e NO x CO 2 Avista Corp 2016 Natural Gas IRP Appendices 166 Appendix - Chapter 4 APPENDIX 4.1: CURRENT TRANSPORTATION/STORAGE RATES AND ASSUMPTIONS Reservation Commodity Fuel Rate TransCanada NGTL System Firm Rates (2) FT-D Demand Rate Alberta-B.C. Border $5.08CAD/GJ/month N/a N/a TransCanada Foothills BC System Firm Rates (3) FT A/BC to Kingsgate $2.48CAD/GJ/month N/a 1.60% GTN FTS-1 Rates Mileage Based - Representative Example Kingsgate to Spokane $0.081391/Dth/day $0.001733/Dth/day 0.0036% per Dth/mile Kingsgate to Malin $0.3/Dth/day $0.009799/Dth/day 0.0036% per Dth/mile Medford Lateral $0.247709/Dth/day $0.002291/Dth/day N/a Spectra Energy/Westcoast System Firms Rates (4) Postage Stamp Rates Station 2 to Huntingdon/Sumas $365.16CAD/103m3/month N/a N/a Williams NWP Postage Stamp Rates TF-1 $0.40888/Dth/day $0.03/Dth/day 1.19% TF-2 $0.40888/Dth/day $0.03/Dth/day 1.19% SGS-2F $0.01558/Dth/day $0.00057/Dth/day N/a (1) Rates and Fuel reported are from current tariffed rates in the established currency and energy units of each pipeline (2) Rate does not reflect current term-differentiation or Abandonment Surcharge (3) Rate does not include Abandonment Surcharge (4) Rate changes annually Current Tariff Rates (1) Avista Corp 2016 Natural Gas IRP Appendices 167 Appendix - Chapter 4 APPENDIX 4.2: ALTERNATE SUPPLY SCENARIOS Existing Resources Existing + Expected Available GTN Fully Subscribed Resources Currently contracted capacity net of long term releases Currently contracted capacity net of long term releases Currently contracted capacity net of long term releases Currently available GTN Capacity Release Recalls Capacity Release Recalls NWP Expansions NWP Expansions Satellite LNG Satellite LNG Rates Current Rates Current Rates Current Rates INPUT ASSUMPTIONS Avista Corp 2016 Natural Gas IRP Appendices 168 Appendix - Chapter 5 APPENDIX 5.1: MONTHLY PRICE DATA BY BASIN EXPECTED PRICE Scenario Index Gas Year Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Expected Case AECo 2015-2016 1.91$ 1.63$ 2.05$ 1.84$ 1.77$ 1.74$ 1.72$ 1.74$ 1.78$ 1.87$ 1.86$ 1.86$ Expected Case AECo 2016-2017 2.03$ 2.19$ 2.36$ 2.33$ 2.24$ 2.13$ 2.11$ 2.08$ 2.11$ 2.19$ 2.16$ 2.17$ Expected Case AECo 2017-2018 2.39$ 2.50$ 3.20$ 3.14$ 2.84$ 2.63$ 2.56$ 2.52$ 2.57$ 2.61$ 2.64$ 2.66$ Expected Case AECo 2018-2019 2.90$ 3.03$ 3.10$ 3.06$ 2.63$ 2.43$ 2.43$ 2.46$ 2.52$ 2.57$ 2.66$ 2.70$ Expected Case AECo 2019-2020 2.97$ 3.12$ 3.18$ 3.16$ 2.86$ 2.56$ 2.56$ 2.56$ 2.58$ 2.61$ 2.66$ 2.65$ Expected Case AECo 2020-2021 3.07$ 3.22$ 3.26$ 3.32$ 2.99$ 2.70$ 2.72$ 2.71$ 2.66$ 2.70$ 2.94$ 2.96$ Expected Case AECo 2021-2022 3.22$ 3.35$ 3.39$ 3.44$ 3.03$ 2.77$ 2.79$ 2.78$ 2.78$ 2.82$ 2.87$ 2.88$ Expected Case AECo 2022-2023 3.14$ 3.21$ 3.17$ 3.22$ 2.89$ 2.74$ 2.79$ 2.79$ 2.81$ 2.83$ 3.02$ 3.03$ Expected Case AECo 2023-2024 3.42$ 3.51$ 3.51$ 3.51$ 3.20$ 2.97$ 2.98$ 2.97$ 3.07$ 3.11$ 3.23$ 3.24$ Expected Case AECo 2024-2025 3.70$ 3.78$ 3.81$ 3.81$ 3.45$ 3.17$ 3.26$ 3.25$ 3.33$ 3.36$ 3.49$ 3.47$ Expected Case AECo 2025-2026 3.93$ 4.09$ 3.79$ 3.79$ 3.27$ 3.11$ 3.19$ 3.18$ 3.28$ 3.34$ 3.42$ 3.43$ Expected Case AECo 2026-2027 4.00$ 3.98$ 3.75$ 3.75$ 3.33$ 3.20$ 3.24$ 3.27$ 3.37$ 3.42$ 3.64$ 3.67$ Expected Case AECo 2027-2028 4.21$ 4.28$ 4.15$ 4.14$ 3.65$ 3.55$ 3.58$ 3.59$ 3.69$ 3.71$ 3.87$ 3.90$ Expected Case AECo 2028-2029 4.37$ 4.51$ 4.41$ 4.42$ 3.90$ 3.75$ 3.82$ 3.80$ 3.83$ 3.86$ 4.01$ 4.01$ Expected Case AECo 2029-2030 4.48$ 4.63$ 4.54$ 4.59$ 4.04$ 3.88$ 3.90$ 3.94$ 4.04$ 4.07$ 4.20$ 4.24$ Expected Case AECo 2030-2031 4.74$ 4.96$ 4.74$ 4.78$ 4.19$ 4.09$ 4.11$ 4.12$ 4.18$ 4.21$ 4.37$ 4.39$ Expected Case AECo 2031-2032 4.80$ 5.06$ 4.95$ 4.94$ 4.42$ 4.26$ 4.28$ 4.29$ 4.30$ 4.38$ 4.46$ 4.49$ Expected Case AECo 2032-2033 4.91$ 5.22$ 4.95$ 4.99$ 4.38$ 4.26$ 4.25$ 4.28$ 4.37$ 4.44$ 4.51$ 4.54$ Expected Case AECo 2033-2034 4.99$ 5.30$ 5.05$ 5.08$ 4.44$ 4.32$ 4.31$ 4.33$ 4.39$ 4.42$ 4.56$ 4.57$ Expected Case AECo 2034-2035 4.96$ 5.28$ 5.05$ 5.06$ 4.60$ 4.44$ 4.43$ 4.32$ 4.37$ 4.49$ 4.60$ 4.59$ Expected Case Malin 2015-2016 2.20$ 2.03$ 2.49$ 2.34$ 2.28$ 2.22$ 2.26$ 2.31$ 2.37$ 2.40$ 2.41$ 2.44$ Expected Case Malin 2016-2017 2.71$ 2.84$ 2.91$ 2.86$ 2.77$ 2.64$ 2.64$ 2.68$ 2.74$ 2.74$ 2.80$ 2.84$ Expected Case Malin 2017-2018 3.02$ 3.08$ 3.61$ 3.57$ 3.33$ 3.15$ 3.15$ 3.17$ 3.23$ 3.27$ 3.29$ 3.35$ Expected Case Malin 2018-2019 3.47$ 3.59$ 3.67$ 3.63$ 3.31$ 3.19$ 3.18$ 3.19$ 3.21$ 3.28$ 3.35$ 3.38$ Expected Case Malin 2019-2020 3.52$ 3.61$ 3.69$ 3.66$ 3.39$ 3.28$ 3.21$ 3.20$ 3.23$ 3.31$ 3.32$ 3.32$ Expected Case Malin 2020-2021 3.56$ 3.66$ 3.77$ 3.77$ 3.46$ 3.37$ 3.36$ 3.33$ 3.40$ 3.46$ 3.48$ 3.53$ Expected Case Malin 2021-2022 3.79$ 3.87$ 3.97$ 3.98$ 3.59$ 3.48$ 3.45$ 3.43$ 3.49$ 3.51$ 3.53$ 3.54$ Expected Case Malin 2022-2023 3.80$ 3.88$ 3.95$ 3.97$ 3.62$ 3.48$ 3.48$ 3.48$ 3.50$ 3.56$ 3.56$ 3.57$ Expected Case Malin 2023-2024 3.89$ 3.99$ 4.00$ 3.97$ 3.65$ 3.60$ 3.58$ 3.56$ 3.59$ 3.69$ 3.70$ 3.72$ Expected Case Malin 2024-2025 4.06$ 4.18$ 4.24$ 4.24$ 3.89$ 3.83$ 3.80$ 3.79$ 3.85$ 3.91$ 3.91$ 3.92$ Expected Case Malin 2025-2026 4.28$ 4.54$ 4.27$ 4.30$ 3.84$ 3.74$ 3.71$ 3.71$ 3.78$ 3.85$ 3.86$ 3.88$ Expected Case Malin 2026-2027 4.31$ 4.52$ 4.36$ 4.37$ 3.93$ 3.82$ 3.79$ 3.79$ 3.84$ 3.91$ 3.92$ 4.00$ Expected Case Malin 2027-2028 4.46$ 4.67$ 4.53$ 4.53$ 4.10$ 4.01$ 3.99$ 3.98$ 4.03$ 4.10$ 4.11$ 4.16$ Expected Case Malin 2028-2029 4.60$ 4.82$ 4.77$ 4.78$ 4.32$ 4.20$ 4.18$ 4.15$ 4.17$ 4.22$ 4.24$ 4.27$ Expected Case Malin 2029-2030 4.73$ 4.98$ 4.88$ 4.91$ 4.46$ 4.30$ 4.30$ 4.30$ 4.33$ 4.41$ 4.47$ 4.51$ Expected Case Malin 2030-2031 5.01$ 5.25$ 5.03$ 5.06$ 4.61$ 4.46$ 4.42$ 4.42$ 4.46$ 4.53$ 4.60$ 4.63$ Expected Case Malin 2031-2032 5.08$ 5.32$ 5.23$ 5.23$ 4.73$ 4.61$ 4.54$ 4.53$ 4.56$ 4.66$ 4.71$ 4.75$ Expected Case Malin 2032-2033 5.23$ 5.46$ 5.23$ 5.25$ 4.77$ 4.63$ 4.55$ 4.55$ 4.66$ 4.74$ 4.77$ 4.82$ Expected Case Malin 2033-2034 5.32$ 5.62$ 5.40$ 5.41$ 4.86$ 4.72$ 4.69$ 4.68$ 4.73$ 4.80$ 4.82$ 4.84$ Expected Case Malin 2034-2035 5.31$ 5.63$ 5.39$ 5.41$ 4.86$ 4.72$ 4.74$ 4.72$ 4.80$ 4.86$ 4.87$ 4.89$ Expected Case Rockies 2015-2016 2.01$ 1.81$ 2.32$ 2.21$ 2.17$ 2.16$ 2.18$ 2.22$ 2.27$ 2.34$ 2.37$ 2.42$ Expected Case Rockies 2016-2017 2.63$ 2.76$ 2.84$ 2.81$ 2.69$ 2.55$ 2.58$ 2.62$ 2.66$ 2.69$ 2.75$ 2.77$ Expected Case Rockies 2017-2018 2.91$ 3.01$ 3.57$ 3.53$ 3.28$ 3.11$ 3.09$ 3.11$ 3.15$ 3.20$ 3.25$ 3.26$ Expected Case Rockies 2018-2019 3.40$ 3.52$ 3.59$ 3.56$ 3.25$ 3.14$ 3.13$ 3.13$ 3.15$ 3.22$ 3.26$ 3.29$ Expected Case Rockies 2019-2020 3.44$ 3.53$ 3.61$ 3.59$ 3.33$ 3.22$ 3.17$ 3.17$ 3.18$ 3.25$ 3.27$ 3.25$ Expected Case Rockies 2020-2021 3.49$ 3.60$ 3.70$ 3.70$ 3.42$ 3.32$ 3.31$ 3.33$ 3.35$ 3.41$ 3.43$ 3.46$ Expected Case Rockies 2021-2022 3.71$ 3.82$ 3.90$ 3.90$ 3.54$ 3.43$ 3.42$ 3.42$ 3.43$ 3.46$ 3.47$ 3.47$ Expected Case Rockies 2022-2023 3.72$ 3.83$ 3.86$ 3.89$ 3.54$ 3.43$ 3.43$ 3.41$ 3.42$ 3.51$ 3.52$ 3.51$ Expected Case Rockies 2023-2024 3.81$ 3.93$ 3.90$ 3.88$ 3.60$ 3.55$ 3.54$ 3.52$ 3.55$ 3.65$ 3.66$ 3.68$ Expected Case Rockies 2024-2025 4.00$ 4.15$ 4.19$ 4.18$ 3.86$ 3.80$ 3.76$ 3.75$ 3.81$ 3.87$ 3.87$ 3.87$ Expected Case Rockies 2025-2026 4.20$ 4.49$ 4.23$ 4.24$ 3.80$ 3.71$ 3.67$ 3.68$ 3.73$ 3.81$ 3.81$ 3.82$ Expected Case Rockies 2026-2027 4.23$ 4.45$ 4.29$ 4.29$ 3.87$ 3.78$ 3.75$ 3.75$ 3.80$ 3.86$ 3.87$ 3.92$ Expected Case Rockies 2027-2028 4.35$ 4.59$ 4.45$ 4.45$ 4.03$ 3.96$ 3.94$ 3.92$ 3.97$ 4.04$ 4.05$ 4.08$ Expected Case Rockies 2028-2029 4.50$ 4.75$ 4.68$ 4.70$ 4.24$ 4.15$ 4.12$ 4.10$ 4.10$ 4.15$ 4.18$ 4.19$ Expected Case Rockies 2029-2030 4.66$ 4.89$ 4.80$ 4.82$ 4.38$ 4.27$ 4.25$ 4.25$ 4.27$ 4.36$ 4.39$ 4.45$ Expected Case Rockies 2030-2031 4.94$ 5.18$ 4.95$ 4.98$ 4.53$ 4.41$ 4.38$ 4.37$ 4.41$ 4.48$ 4.52$ 4.56$ Expected Case Rockies 2031-2032 5.01$ 5.24$ 5.15$ 5.15$ 4.66$ 4.57$ 4.49$ 4.47$ 4.50$ 4.59$ 4.62$ 4.67$ Expected Case Rockies 2032-2033 5.14$ 5.39$ 5.16$ 5.18$ 4.69$ 4.57$ 4.49$ 4.50$ 4.53$ 4.64$ 4.70$ 4.74$ Expected Case Rockies 2033-2034 5.22$ 5.49$ 5.26$ 5.27$ 4.79$ 4.67$ 4.62$ 4.60$ 4.61$ 4.71$ 4.76$ 4.76$ Expected Case Rockies 2034-2035 5.20$ 5.47$ 5.24$ 5.26$ 4.78$ 4.67$ 4.68$ 4.63$ 4.69$ 4.78$ 4.82$ 4.81$ 2014$ Avista Corp 2016 Natural Gas IRP Appendices 169 Appendix - Chapter 5 APPENDIX 5.1: MONTHLY PRICE DATA BY BASIN EXPECTED PRICE Expected Case Stanfield 2015-2016 2.17$ 1.98$ 2.42$ 2.27$ 2.19$ 2.15$ 2.19$ 2.23$ 2.27$ 2.34$ 2.34$ 2.37$ Expected Case Stanfield 2016-2017 2.63$ 2.76$ 2.88$ 2.85$ 2.72$ 2.58$ 2.58$ 2.64$ 2.67$ 2.68$ 2.73$ 2.78$ Expected Case Stanfield 2017-2018 2.94$ 3.03$ 3.58$ 3.54$ 3.29$ 3.14$ 3.09$ 3.12$ 3.15$ 3.20$ 3.25$ 3.27$ Expected Case Stanfield 2018-2019 3.39$ 3.50$ 3.58$ 3.54$ 3.24$ 3.11$ 3.11$ 3.10$ 3.13$ 3.20$ 3.26$ 3.29$ Expected Case Stanfield 2019-2020 3.43$ 3.51$ 3.59$ 3.56$ 3.29$ 3.21$ 3.14$ 3.11$ 3.16$ 3.23$ 3.25$ 3.24$ Expected Case Stanfield 2020-2021 3.47$ 3.56$ 3.67$ 3.67$ 3.37$ 3.30$ 3.28$ 3.25$ 3.32$ 3.38$ 3.39$ 3.44$ Expected Case Stanfield 2021-2022 3.70$ 3.78$ 3.87$ 3.88$ 3.50$ 3.41$ 3.38$ 3.36$ 3.41$ 3.43$ 3.42$ 3.44$ Expected Case Stanfield 2022-2023 3.70$ 3.78$ 3.84$ 3.87$ 3.53$ 3.41$ 3.40$ 3.39$ 3.42$ 3.48$ 3.49$ 3.48$ Expected Case Stanfield 2023-2024 3.80$ 3.89$ 3.95$ 3.86$ 3.58$ 3.55$ 3.52$ 3.49$ 3.52$ 3.61$ 3.62$ 3.67$ Expected Case Stanfield 2024-2025 4.00$ 4.12$ 4.16$ 4.17$ 3.83$ 3.79$ 3.75$ 3.74$ 3.78$ 3.85$ 3.84$ 3.86$ Expected Case Stanfield 2025-2026 4.23$ 4.48$ 4.21$ 4.24$ 3.79$ 3.69$ 3.66$ 3.66$ 3.71$ 3.80$ 3.81$ 3.83$ Expected Case Stanfield 2026-2027 4.26$ 4.47$ 4.30$ 4.30$ 3.88$ 3.78$ 3.76$ 3.76$ 3.81$ 3.87$ 3.88$ 3.95$ Expected Case Stanfield 2027-2028 4.42$ 4.62$ 4.46$ 4.47$ 4.04$ 3.97$ 3.95$ 3.93$ 3.98$ 4.04$ 4.05$ 4.10$ Expected Case Stanfield 2028-2029 4.55$ 4.75$ 4.68$ 4.71$ 4.25$ 4.16$ 4.14$ 4.11$ 4.10$ 4.16$ 4.17$ 4.20$ Expected Case Stanfield 2029-2030 4.67$ 4.90$ 4.81$ 4.84$ 4.39$ 4.27$ 4.26$ 4.26$ 4.29$ 4.35$ 4.42$ 4.44$ Expected Case Stanfield 2030-2031 4.93$ 5.18$ 4.96$ 4.99$ 4.56$ 4.42$ 4.39$ 4.38$ 4.43$ 4.49$ 4.54$ 4.55$ Expected Case Stanfield 2031-2032 5.02$ 5.25$ 5.16$ 5.16$ 4.66$ 4.57$ 4.48$ 4.49$ 4.52$ 4.62$ 4.65$ 4.69$ Expected Case Stanfield 2032-2033 5.17$ 5.40$ 5.15$ 5.18$ 4.71$ 4.60$ 4.51$ 4.51$ 4.62$ 4.69$ 4.69$ 4.75$ Expected Case Stanfield 2033-2034 5.25$ 5.55$ 5.32$ 5.34$ 4.80$ 4.68$ 4.65$ 4.64$ 4.68$ 4.74$ 4.75$ 4.77$ Expected Case Stanfield 2034-2035 5.24$ 5.55$ 5.31$ 5.34$ 4.80$ 4.65$ 4.69$ 4.67$ 4.73$ 4.78$ 4.79$ 4.83$ Expected Case Sumas 2015-2016 2.16$ 1.93$ 2.39$ 2.19$ 2.04$ 1.96$ 1.86$ 1.89$ 1.90$ 2.02$ 2.17$ 2.23$ Expected Case Sumas 2016-2017 2.49$ 2.80$ 2.84$ 2.78$ 2.66$ 2.50$ 2.48$ 2.44$ 2.49$ 2.55$ 2.62$ 2.60$ Expected Case Sumas 2017-2018 2.87$ 3.04$ 3.55$ 3.49$ 3.24$ 3.04$ 2.81$ 2.81$ 2.85$ 2.97$ 3.01$ 3.15$ Expected Case Sumas 2018-2019 3.29$ 3.44$ 3.54$ 3.51$ 3.15$ 2.94$ 2.86$ 2.80$ 2.87$ 3.00$ 3.08$ 3.17$ Expected Case Sumas 2019-2020 3.32$ 3.45$ 3.52$ 3.51$ 3.23$ 3.06$ 2.95$ 2.85$ 2.97$ 3.06$ 3.13$ 3.16$ Expected Case Sumas 2020-2021 3.39$ 3.50$ 3.62$ 3.66$ 3.35$ 3.19$ 3.12$ 3.04$ 3.15$ 3.23$ 3.32$ 3.36$ Expected Case Sumas 2021-2022 3.57$ 3.63$ 3.74$ 3.75$ 3.46$ 3.31$ 3.21$ 3.19$ 3.22$ 3.30$ 3.37$ 3.37$ Expected Case Sumas 2022-2023 3.60$ 3.63$ 3.70$ 3.76$ 3.48$ 3.33$ 3.24$ 3.24$ 3.26$ 3.37$ 3.41$ 3.40$ Expected Case Sumas 2023-2024 3.70$ 3.84$ 3.83$ 3.80$ 3.52$ 3.43$ 3.31$ 3.31$ 3.34$ 3.49$ 3.55$ 3.57$ Expected Case Sumas 2024-2025 3.89$ 3.94$ 4.07$ 4.10$ 3.78$ 3.66$ 3.55$ 3.51$ 3.58$ 3.71$ 3.75$ 3.75$ Expected Case Sumas 2025-2026 4.05$ 4.30$ 4.04$ 4.06$ 3.68$ 3.57$ 3.45$ 3.41$ 3.52$ 3.65$ 3.67$ 3.67$ Expected Case Sumas 2026-2027 4.09$ 4.29$ 4.12$ 4.13$ 3.78$ 3.64$ 3.59$ 3.54$ 3.63$ 3.71$ 3.77$ 3.89$ Expected Case Sumas 2027-2028 4.32$ 4.59$ 4.47$ 4.47$ 3.98$ 3.90$ 3.79$ 3.81$ 3.85$ 3.99$ 4.03$ 4.07$ Expected Case Sumas 2028-2029 4.55$ 4.76$ 4.71$ 4.73$ 4.25$ 4.11$ 4.00$ 3.98$ 4.00$ 4.12$ 4.14$ 4.18$ Expected Case Sumas 2029-2030 4.68$ 4.92$ 4.82$ 4.85$ 4.40$ 4.22$ 4.16$ 4.18$ 4.18$ 4.32$ 4.42$ 4.47$ Expected Case Sumas 2030-2031 4.96$ 5.20$ 4.97$ 5.01$ 4.56$ 4.37$ 4.30$ 4.31$ 4.32$ 4.45$ 4.55$ 4.58$ Expected Case Sumas 2031-2032 5.03$ 5.27$ 5.18$ 5.18$ 4.68$ 4.52$ 4.44$ 4.43$ 4.41$ 4.57$ 4.64$ 4.69$ Expected Case Sumas 2032-2033 5.17$ 5.41$ 5.17$ 5.19$ 4.71$ 4.54$ 4.42$ 4.42$ 4.46$ 4.63$ 4.69$ 4.78$ Expected Case Sumas 2033-2034 5.31$ 5.62$ 5.41$ 5.41$ 4.83$ 4.65$ 4.55$ 4.53$ 4.55$ 4.70$ 4.76$ 4.80$ Expected Case Sumas 2034-2035 5.30$ 5.63$ 5.41$ 5.43$ 4.84$ 4.68$ 4.65$ 4.59$ 4.65$ 4.77$ 4.82$ 4.85$ 2014$ Avista Corp 2016 Natural Gas IRP Appendices 170 Appendix - Chapter 5 APPENDIX 5.1: MONTHLY PRICE DATA BY BASIN HIGH GROWTH LOW PRICE Scenario Index Gas Year Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct High Growth & Low Prices AECo 2015-2016 1.91$ 1.63$ 1.82$ 1.88$ 1.50$ 1.22$ 1.43$ 1.48$ 1.98$ 1.87$ 1.29$ 1.56$ High Growth & Low Prices AECo 2016-2017 1.23$ 0.86$ 1.56$ 1.71$ 1.42$ 1.25$ 1.55$ 1.48$ 1.97$ 1.85$ 1.32$ 1.44$ High Growth & Low Prices AECo 2017-2018 1.35$ 0.96$ 1.71$ 1.84$ 1.47$ 1.23$ 1.42$ 1.42$ 1.93$ 1.75$ 1.30$ 1.35$ High Growth & Low Prices AECo 2018-2019 1.32$ 1.07$ 1.60$ 1.74$ 1.28$ 1.01$ 1.28$ 1.37$ 1.89$ 1.71$ 1.20$ 1.41$ High Growth & Low Prices AECo 2019-2020 1.33$ 0.99$ 1.61$ 1.75$ 1.41$ 1.03$ 1.30$ 1.36$ 1.87$ 1.70$ 1.40$ 1.37$ High Growth & Low Prices AECo 2020-2021 1.37$ 1.05$ 1.64$ 1.84$ 1.47$ 1.10$ 1.38$ 1.42$ 1.83$ 1.66$ 1.34$ 1.44$ High Growth & Low Prices AECo 2021-2022 1.36$ 1.02$ 1.56$ 1.76$ 1.40$ 1.06$ 1.35$ 1.40$ 1.89$ 1.73$ 1.32$ 1.43$ High Growth & Low Prices AECo 2022-2023 1.25$ 0.85$ 1.36$ 1.55$ 1.25$ 1.01$ 1.32$ 1.38$ 1.88$ 1.70$ 1.40$ 1.62$ High Growth & Low Prices AECo 2023-2024 1.58$ 1.03$ 1.63$ 1.80$ 1.50$ 1.12$ 1.39$ 1.44$ 2.02$ 1.85$ 1.51$ 1.53$ High Growth & Low Prices AECo 2024-2025 1.58$ 1.16$ 1.68$ 1.83$ 1.50$ 1.08$ 1.43$ 1.48$ 2.02$ 1.85$ 1.61$ 1.54$ High Growth & Low Prices AECo 2025-2026 1.51$ 1.03$ 1.61$ 1.75$ 1.37$ 1.10$ 1.43$ 1.47$ 2.03$ 1.88$ 1.50$ 1.54$ High Growth & Low Prices AECo 2026-2027 1.55$ 0.93$ 1.50$ 1.64$ 1.34$ 1.10$ 1.41$ 1.49$ 2.05$ 1.89$ 1.61$ 1.70$ High Growth & Low Prices AECo 2027-2028 1.64$ 1.10$ 1.74$ 1.87$ 1.50$ 1.27$ 1.56$ 1.63$ 2.18$ 1.99$ 1.50$ 1.74$ High Growth & Low Prices AECo 2028-2029 1.71$ 1.19$ 1.80$ 1.93$ 1.57$ 1.29$ 1.70$ 1.68$ 2.19$ 2.02$ 1.67$ 1.76$ High Growth & Low Prices AECo 2029-2030 1.66$ 1.40$ 1.81$ 1.99$ 1.59$ 1.32$ 1.60$ 1.70$ 2.24$ 2.06$ 1.81$ 1.78$ High Growth & Low Prices AECo 2030-2031 1.67$ 1.43$ 1.87$ 2.05$ 1.62$ 1.41$ 1.69$ 1.76$ 2.26$ 2.08$ 1.79$ 1.84$ High Growth & Low Prices AECo 2031-2032 1.80$ 1.28$ 1.88$ 2.04$ 1.72$ 1.46$ 1.82$ 1.80$ 2.27$ 2.15$ 1.77$ 1.84$ High Growth & Low Prices AECo 2032-2033 1.67$ 1.43$ 1.92$ 2.09$ 1.69$ 1.48$ 1.85$ 1.81$ 2.34$ 2.20$ 1.62$ 1.84$ High Growth & Low Prices AECo 2033-2034 1.90$ 1.32$ 1.92$ 2.09$ 1.64$ 1.43$ 1.70$ 1.78$ 2.29$ 2.12$ 1.96$ 1.85$ High Growth & Low Prices AECo 2034-2035 1.67$ 1.33$ 1.95$ 2.09$ 1.83$ 1.56$ 1.80$ 1.74$ 2.24$ 2.14$ 1.78$ 1.82$ High Growth & Low Prices Malin 2015-2016 2.20$ 2.03$ 2.26$ 2.38$ 2.01$ 1.70$ 1.97$ 2.05$ 2.57$ 2.40$ 1.84$ 2.14$ High Growth & Low Prices Malin 2016-2017 1.91$ 1.51$ 2.12$ 2.25$ 1.95$ 1.76$ 2.08$ 2.08$ 2.60$ 2.41$ 1.96$ 2.11$ High Growth & Low Prices Malin 2017-2018 1.98$ 1.54$ 2.12$ 2.27$ 1.97$ 1.75$ 2.01$ 2.07$ 2.59$ 2.41$ 1.94$ 2.04$ High Growth & Low Prices Malin 2018-2019 1.88$ 1.63$ 2.16$ 2.31$ 1.97$ 1.77$ 2.03$ 2.09$ 2.58$ 2.43$ 1.89$ 2.08$ High Growth & Low Prices Malin 2019-2020 1.88$ 1.48$ 2.11$ 2.25$ 1.93$ 1.74$ 1.94$ 2.00$ 2.52$ 2.40$ 2.05$ 2.03$ High Growth & Low Prices Malin 2020-2021 1.86$ 1.49$ 2.14$ 2.29$ 1.94$ 1.76$ 2.02$ 2.03$ 2.58$ 2.42$ 1.88$ 2.01$ High Growth & Low Prices Malin 2021-2022 1.92$ 1.55$ 2.14$ 2.30$ 1.96$ 1.76$ 2.01$ 2.05$ 2.59$ 2.42$ 1.97$ 2.10$ High Growth & Low Prices Malin 2022-2023 1.91$ 1.51$ 2.14$ 2.31$ 1.97$ 1.75$ 2.00$ 2.07$ 2.57$ 2.43$ 1.94$ 2.17$ High Growth & Low Prices Malin 2023-2024 2.04$ 1.50$ 2.13$ 2.26$ 1.94$ 1.74$ 1.99$ 2.03$ 2.54$ 2.43$ 1.97$ 2.02$ High Growth & Low Prices Malin 2024-2025 1.95$ 1.55$ 2.11$ 2.26$ 1.93$ 1.74$ 1.97$ 2.02$ 2.54$ 2.40$ 2.03$ 1.99$ High Growth & Low Prices Malin 2025-2026 1.86$ 1.47$ 2.09$ 2.26$ 1.94$ 1.73$ 1.95$ 2.01$ 2.53$ 2.39$ 1.94$ 1.99$ High Growth & Low Prices Malin 2026-2027 1.86$ 1.47$ 2.11$ 2.26$ 1.94$ 1.72$ 1.96$ 2.02$ 2.52$ 2.38$ 1.90$ 2.03$ High Growth & Low Prices Malin 2027-2028 1.89$ 1.50$ 2.11$ 2.27$ 1.95$ 1.73$ 1.97$ 2.02$ 2.52$ 2.38$ 1.74$ 2.01$ High Growth & Low Prices Malin 2028-2029 1.95$ 1.50$ 2.15$ 2.30$ 1.99$ 1.74$ 2.05$ 2.03$ 2.52$ 2.38$ 1.91$ 2.02$ High Growth & Low Prices Malin 2029-2030 1.91$ 1.74$ 2.15$ 2.31$ 2.02$ 1.75$ 2.00$ 2.05$ 2.53$ 2.41$ 2.07$ 2.05$ High Growth & Low Prices Malin 2030-2031 1.94$ 1.71$ 2.17$ 2.33$ 2.03$ 1.78$ 2.00$ 2.05$ 2.54$ 2.40$ 2.02$ 2.07$ High Growth & Low Prices Malin 2031-2032 2.09$ 1.53$ 2.17$ 2.33$ 2.03$ 1.80$ 2.08$ 2.04$ 2.53$ 2.43$ 2.01$ 2.10$ High Growth & Low Prices Malin 2032-2033 1.99$ 1.68$ 2.19$ 2.35$ 2.08$ 1.85$ 2.15$ 2.08$ 2.63$ 2.50$ 1.87$ 2.12$ High Growth & Low Prices Malin 2033-2034 2.22$ 1.64$ 2.27$ 2.42$ 2.07$ 1.84$ 2.08$ 2.13$ 2.63$ 2.50$ 2.23$ 2.12$ High Growth & Low Prices Malin 2034-2035 2.02$ 1.67$ 2.29$ 2.44$ 2.09$ 1.84$ 2.10$ 2.14$ 2.66$ 2.51$ 2.05$ 2.13$ High Growth & Low Prices Rockies 2015-2016 2.01$ 1.81$ 2.10$ 2.25$ 1.90$ 1.64$ 1.89$ 1.96$ 2.47$ 2.34$ 1.79$ 2.12$ High Growth & Low Prices Rockies 2016-2017 1.83$ 1.43$ 2.05$ 2.20$ 1.87$ 1.67$ 2.03$ 2.02$ 2.52$ 2.36$ 1.90$ 2.04$ High Growth & Low Prices Rockies 2017-2018 1.88$ 1.46$ 2.07$ 2.23$ 1.92$ 1.71$ 1.96$ 2.02$ 2.51$ 2.35$ 1.90$ 1.95$ High Growth & Low Prices Rockies 2018-2019 1.82$ 1.55$ 2.09$ 2.23$ 1.91$ 1.72$ 1.98$ 2.04$ 2.52$ 2.36$ 1.80$ 1.99$ High Growth & Low Prices Rockies 2019-2020 1.80$ 1.40$ 2.03$ 2.18$ 1.88$ 1.68$ 1.91$ 1.97$ 2.47$ 2.34$ 2.00$ 1.97$ High Growth & Low Prices Rockies 2020-2021 1.79$ 1.43$ 2.07$ 2.22$ 1.90$ 1.71$ 1.97$ 2.03$ 2.53$ 2.37$ 1.83$ 1.94$ High Growth & Low Prices Rockies 2021-2022 1.85$ 1.50$ 2.07$ 2.22$ 1.91$ 1.72$ 1.97$ 2.04$ 2.54$ 2.37$ 1.92$ 2.03$ High Growth & Low Prices Rockies 2022-2023 1.82$ 1.47$ 2.05$ 2.22$ 1.90$ 1.70$ 1.95$ 2.00$ 2.49$ 2.38$ 1.90$ 2.11$ High Growth & Low Prices Rockies 2023-2024 1.97$ 1.44$ 2.03$ 2.17$ 1.89$ 1.70$ 1.95$ 1.99$ 2.50$ 2.39$ 1.94$ 1.98$ High Growth & Low Prices Rockies 2024-2025 1.89$ 1.53$ 2.06$ 2.20$ 1.90$ 1.71$ 1.94$ 1.99$ 2.50$ 2.36$ 1.99$ 1.94$ High Growth & Low Prices Rockies 2025-2026 1.78$ 1.42$ 2.04$ 2.19$ 1.90$ 1.69$ 1.91$ 1.98$ 2.48$ 2.35$ 1.89$ 1.93$ High Growth & Low Prices Rockies 2026-2027 1.78$ 1.40$ 2.04$ 2.18$ 1.88$ 1.69$ 1.92$ 1.97$ 2.48$ 2.32$ 1.84$ 1.95$ High Growth & Low Prices Rockies 2027-2028 1.78$ 1.41$ 2.03$ 2.18$ 1.88$ 1.69$ 1.91$ 1.96$ 2.46$ 2.33$ 1.68$ 1.92$ High Growth & Low Prices Rockies 2028-2029 1.84$ 1.42$ 2.07$ 2.22$ 1.90$ 1.70$ 2.00$ 1.98$ 2.45$ 2.32$ 1.84$ 1.93$ High Growth & Low Prices Rockies 2029-2030 1.84$ 1.66$ 2.07$ 2.22$ 1.93$ 1.72$ 1.96$ 2.00$ 2.47$ 2.36$ 2.00$ 2.00$ High Growth & Low Prices Rockies 2030-2031 1.87$ 1.64$ 2.08$ 2.24$ 1.95$ 1.73$ 1.95$ 2.00$ 2.49$ 2.35$ 1.94$ 2.01$ High Growth & Low Prices Rockies 2031-2032 2.02$ 1.46$ 2.09$ 2.25$ 1.96$ 1.77$ 2.03$ 1.99$ 2.47$ 2.36$ 1.93$ 2.03$ High Growth & Low Prices Rockies 2032-2033 1.89$ 1.61$ 2.12$ 2.28$ 1.99$ 1.78$ 2.10$ 2.03$ 2.49$ 2.40$ 1.80$ 2.04$ High Growth & Low Prices Rockies 2033-2034 2.13$ 1.51$ 2.13$ 2.29$ 2.00$ 1.79$ 2.01$ 2.04$ 2.51$ 2.41$ 2.17$ 2.05$ High Growth & Low Prices Rockies 2034-2035 1.91$ 1.52$ 2.14$ 2.29$ 2.01$ 1.79$ 2.04$ 2.05$ 2.55$ 2.43$ 1.99$ 2.04$ 2014$ Avista Corp 2016 Natural Gas IRP Appendices 171 Appendix - Chapter 5 APPENDIX 5.1: MONTHLY PRICE DATA BY BASIN HIGH GROWTH LOW PRICE High Growth & Low Prices Stanfield 2015-2016 2.17$ 1.98$ 2.19$ 2.31$ 1.92$ 1.63$ 1.90$ 1.97$ 2.47$ 2.34$ 1.77$ 2.07$ High Growth & Low Prices Stanfield 2016-2017 1.84$ 1.43$ 2.09$ 2.23$ 1.91$ 1.71$ 2.02$ 2.04$ 2.52$ 2.34$ 1.89$ 2.05$ High Growth & Low Prices Stanfield 2017-2018 1.91$ 1.48$ 2.09$ 2.23$ 1.92$ 1.74$ 1.95$ 2.02$ 2.51$ 2.35$ 1.90$ 1.96$ High Growth & Low Prices Stanfield 2018-2019 1.81$ 1.54$ 2.07$ 2.22$ 1.89$ 1.70$ 1.96$ 2.01$ 2.50$ 2.34$ 1.80$ 2.00$ High Growth & Low Prices Stanfield 2019-2020 1.79$ 1.38$ 2.01$ 2.15$ 1.84$ 1.68$ 1.87$ 1.91$ 2.45$ 2.33$ 1.98$ 1.96$ High Growth & Low Prices Stanfield 2020-2021 1.78$ 1.40$ 2.05$ 2.18$ 1.86$ 1.69$ 1.94$ 1.96$ 2.50$ 2.34$ 1.78$ 1.92$ High Growth & Low Prices Stanfield 2021-2022 1.84$ 1.45$ 2.04$ 2.19$ 1.88$ 1.70$ 1.94$ 1.98$ 2.52$ 2.34$ 1.86$ 2.00$ High Growth & Low Prices Stanfield 2022-2023 1.81$ 1.41$ 2.04$ 2.20$ 1.88$ 1.68$ 1.93$ 1.98$ 2.49$ 2.36$ 1.87$ 2.08$ High Growth & Low Prices Stanfield 2023-2024 1.96$ 1.41$ 2.07$ 2.15$ 1.88$ 1.69$ 1.94$ 1.97$ 2.46$ 2.35$ 1.90$ 1.96$ High Growth & Low Prices Stanfield 2024-2025 1.89$ 1.50$ 2.04$ 2.19$ 1.88$ 1.70$ 1.93$ 1.98$ 2.47$ 2.34$ 1.96$ 1.93$ High Growth & Low Prices Stanfield 2025-2026 1.81$ 1.42$ 2.02$ 2.19$ 1.88$ 1.68$ 1.90$ 1.95$ 2.46$ 2.34$ 1.89$ 1.94$ High Growth & Low Prices Stanfield 2026-2027 1.81$ 1.41$ 2.05$ 2.19$ 1.89$ 1.69$ 1.93$ 1.99$ 2.48$ 2.34$ 1.85$ 1.98$ High Growth & Low Prices Stanfield 2027-2028 1.85$ 1.44$ 2.04$ 2.20$ 1.89$ 1.70$ 1.93$ 1.96$ 2.47$ 2.32$ 1.68$ 1.94$ High Growth & Low Prices Stanfield 2028-2029 1.89$ 1.42$ 2.07$ 2.23$ 1.92$ 1.71$ 2.02$ 1.99$ 2.45$ 2.32$ 1.83$ 1.95$ High Growth & Low Prices Stanfield 2029-2030 1.85$ 1.67$ 2.08$ 2.24$ 1.95$ 1.72$ 1.96$ 2.01$ 2.49$ 2.35$ 2.02$ 1.98$ High Growth & Low Prices Stanfield 2030-2031 1.86$ 1.65$ 2.10$ 2.26$ 1.98$ 1.74$ 1.96$ 2.02$ 2.50$ 2.36$ 1.97$ 2.00$ High Growth & Low Prices Stanfield 2031-2032 2.03$ 1.47$ 2.09$ 2.25$ 1.96$ 1.77$ 2.03$ 2.00$ 2.49$ 2.39$ 1.96$ 2.04$ High Growth & Low Prices Stanfield 2032-2033 1.92$ 1.61$ 2.11$ 2.28$ 2.01$ 1.81$ 2.11$ 2.04$ 2.58$ 2.45$ 1.80$ 2.05$ High Growth & Low Prices Stanfield 2033-2034 2.16$ 1.57$ 2.19$ 2.35$ 2.01$ 1.80$ 2.04$ 2.09$ 2.58$ 2.44$ 2.15$ 2.06$ High Growth & Low Prices Stanfield 2034-2035 1.95$ 1.60$ 2.20$ 2.36$ 2.02$ 1.78$ 2.06$ 2.09$ 2.59$ 2.43$ 1.97$ 2.06$ High Growth & Low Prices Sumas 2015-2016 2.16$ 1.93$ 2.16$ 2.23$ 1.76$ 1.44$ 1.57$ 1.63$ 2.10$ 2.02$ 1.60$ 1.93$ High Growth & Low Prices Sumas 2016-2017 1.70$ 1.47$ 2.05$ 2.16$ 1.84$ 1.63$ 1.92$ 1.84$ 2.35$ 2.21$ 1.78$ 1.87$ High Growth & Low Prices Sumas 2017-2018 1.84$ 1.49$ 2.05$ 2.19$ 1.88$ 1.64$ 1.67$ 1.72$ 2.21$ 2.12$ 1.66$ 1.84$ High Growth & Low Prices Sumas 2018-2019 1.70$ 1.48$ 2.04$ 2.19$ 1.80$ 1.52$ 1.71$ 1.71$ 2.24$ 2.14$ 1.62$ 1.87$ High Growth & Low Prices Sumas 2019-2020 1.68$ 1.32$ 1.94$ 2.10$ 1.78$ 1.52$ 1.68$ 1.65$ 2.25$ 2.15$ 1.86$ 1.88$ High Growth & Low Prices Sumas 2020-2021 1.69$ 1.33$ 2.00$ 2.17$ 1.83$ 1.58$ 1.78$ 1.74$ 2.33$ 2.19$ 1.71$ 1.84$ High Growth & Low Prices Sumas 2021-2022 1.71$ 1.31$ 1.91$ 2.06$ 1.83$ 1.60$ 1.77$ 1.81$ 2.32$ 2.21$ 1.82$ 1.92$ High Growth & Low Prices Sumas 2022-2023 1.71$ 1.27$ 1.89$ 2.09$ 1.84$ 1.61$ 1.77$ 1.83$ 2.33$ 2.25$ 1.79$ 2.00$ High Growth & Low Prices Sumas 2023-2024 1.86$ 1.36$ 1.96$ 2.09$ 1.82$ 1.58$ 1.72$ 1.79$ 2.28$ 2.23$ 1.82$ 1.86$ High Growth & Low Prices Sumas 2024-2025 1.77$ 1.32$ 1.94$ 2.12$ 1.82$ 1.57$ 1.72$ 1.75$ 2.27$ 2.19$ 1.87$ 1.82$ High Growth & Low Prices Sumas 2025-2026 1.63$ 1.23$ 1.85$ 2.02$ 1.78$ 1.56$ 1.69$ 1.71$ 2.27$ 2.19$ 1.74$ 1.78$ High Growth & Low Prices Sumas 2026-2027 1.64$ 1.23$ 1.87$ 2.02$ 1.79$ 1.55$ 1.76$ 1.77$ 2.31$ 2.18$ 1.74$ 1.92$ High Growth & Low Prices Sumas 2027-2028 1.75$ 1.41$ 2.05$ 2.21$ 1.83$ 1.63$ 1.77$ 1.84$ 2.34$ 2.27$ 1.66$ 1.92$ High Growth & Low Prices Sumas 2028-2029 1.90$ 1.44$ 2.09$ 2.25$ 1.92$ 1.65$ 1.87$ 1.86$ 2.35$ 2.29$ 1.80$ 1.93$ High Growth & Low Prices Sumas 2029-2030 1.86$ 1.68$ 2.09$ 2.25$ 1.96$ 1.67$ 1.87$ 1.94$ 2.39$ 2.31$ 2.02$ 2.01$ High Growth & Low Prices Sumas 2030-2031 1.89$ 1.66$ 2.11$ 2.27$ 1.98$ 1.69$ 1.88$ 1.94$ 2.39$ 2.32$ 1.97$ 2.02$ High Growth & Low Prices Sumas 2031-2032 2.04$ 1.49$ 2.12$ 2.28$ 1.98$ 1.72$ 1.98$ 1.95$ 2.38$ 2.34$ 1.95$ 2.04$ High Growth & Low Prices Sumas 2032-2033 1.93$ 1.62$ 2.14$ 2.29$ 2.02$ 1.76$ 2.02$ 1.95$ 2.43$ 2.39$ 1.80$ 2.08$ High Growth & Low Prices Sumas 2033-2034 2.21$ 1.64$ 2.28$ 2.42$ 2.03$ 1.77$ 1.94$ 1.98$ 2.45$ 2.40$ 2.17$ 2.08$ High Growth & Low Prices Sumas 2034-2035 2.01$ 1.68$ 2.31$ 2.45$ 2.07$ 1.81$ 2.01$ 2.01$ 2.52$ 2.42$ 2.00$ 2.08$ 2014$ Avista Corp 2016 Natural Gas IRP Appendices 172 Appendix - Chapter 5 APPENDIX 5.1: MONTHLY PRICE DATA BY BASIN LOW GROWTH HIGH PRICE Scenario Index Gas Year Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Low Growth_High Prices AECo 2015-2016 1.91$ 1.63$ 7.19$ 7.41$ 7.42$ 4.22$ 4.17$ 4.47$ 4.14$ 4.29$ 3.53$ 4.29$ Low Growth_High Prices AECo 2016-2017 3.78$ 5.33$ 6.93$ 7.25$ 7.01$ 4.25$ 4.22$ 4.48$ 4.13$ 4.28$ 3.48$ 4.26$ Low Growth_High Prices AECo 2017-2018 3.86$ 5.40$ 7.59$ 7.89$ 7.92$ 4.74$ 4.68$ 4.93$ 4.61$ 4.70$ 3.98$ 4.76$ Low Growth_High Prices AECo 2018-2019 4.43$ 5.96$ 7.50$ 7.81$ 7.58$ 4.54$ 4.56$ 4.90$ 4.59$ 4.68$ 3.99$ 4.79$ Low Growth_High Prices AECo 2019-2020 4.46$ 6.00$ 7.52$ 7.84$ 7.88$ 4.57$ 4.59$ 4.90$ 4.58$ 4.68$ 3.99$ 4.77$ Low Growth_High Prices AECo 2020-2021 4.51$ 6.07$ 7.56$ 7.94$ 7.26$ 4.65$ 4.68$ 4.98$ 4.56$ 4.65$ 4.12$ 4.91$ Low Growth_High Prices AECo 2021-2022 4.46$ 5.98$ 7.50$ 7.87$ 7.91$ 4.63$ 4.66$ 4.97$ 4.62$ 4.73$ 4.03$ 4.83$ Low Growth_High Prices AECo 2022-2023 4.38$ 5.85$ 7.31$ 7.67$ 6.32$ 4.59$ 4.65$ 4.97$ 4.62$ 4.71$ 4.15$ 4.96$ Low Growth_High Prices AECo 2023-2024 4.61$ 6.08$ 7.60$ 7.94$ 8.02$ 4.71$ 4.73$ 5.04$ 4.78$ 4.87$ 4.25$ 5.03$ Low Growth_High Prices AECo 2024-2025 4.69$ 6.13$ 7.66$ 7.97$ 8.03$ 4.69$ 4.78$ 5.09$ 4.79$ 4.88$ 4.27$ 5.05$ Low Growth_High Prices AECo 2025-2026 4.71$ 6.10$ 7.60$ 7.91$ 7.91$ 4.72$ 4.79$ 5.09$ 4.81$ 4.93$ 4.27$ 5.06$ Low Growth_High Prices AECo 2026-2027 4.77$ 6.01$ 7.53$ 7.83$ 7.32$ 4.76$ 4.81$ 5.15$ 4.87$ 4.97$ 4.44$ 5.23$ Low Growth_High Prices AECo 2027-2028 4.89$ 6.23$ 7.80$ 8.11$ 7.87$ 4.96$ 4.99$ 5.32$ 5.04$ 5.12$ 4.53$ 5.34$ Low Growth_High Prices AECo 2028-2029 4.95$ 6.35$ 7.90$ 8.21$ 7.78$ 5.03$ 5.10$ 5.41$ 5.09$ 5.18$ 4.59$ 5.40$ Low Growth_High Prices AECo 2029-2030 4.99$ 6.39$ 7.96$ 8.30$ 8.29$ 5.10$ 5.12$ 5.47$ 5.18$ 5.27$ 4.66$ 5.47$ Low Growth_High Prices AECo 2030-2031 5.04$ 6.50$ 8.07$ 8.41$ 8.37$ 5.24$ 5.26$ 5.58$ 5.25$ 5.34$ 4.75$ 5.56$ Low Growth_High Prices AECo 2031-2032 5.08$ 6.57$ 8.12$ 8.45$ 7.32$ 5.33$ 5.34$ 5.67$ 5.30$ 5.45$ 4.81$ 5.62$ Low Growth_High Prices AECo 2032-2033 5.14$ 6.67$ 8.21$ 8.55$ 7.50$ 5.40$ 5.40$ 5.73$ 5.43$ 5.55$ 4.88$ 5.67$ Low Growth_High Prices AECo 2033-2034 5.19$ 6.72$ 8.27$ 8.60$ 7.36$ 5.41$ 5.43$ 5.75$ 5.44$ 5.53$ 4.92$ 5.73$ Low Growth_High Prices AECo 2034-2035 5.23$ 6.78$ 8.36$ 8.67$ 8.22$ 5.60$ 5.58$ 5.78$ 5.44$ 5.61$ 4.98$ 5.76$ Low Growth_High Prices Malin 2015-2016 2.20$ 2.03$ 7.63$ 7.92$ 7.93$ 4.69$ 4.71$ 5.04$ 4.73$ 4.83$ 4.08$ 4.88$ Low Growth_High Prices Malin 2016-2017 4.46$ 5.98$ 7.48$ 7.78$ 7.54$ 4.76$ 4.74$ 5.08$ 4.76$ 4.83$ 4.11$ 4.93$ Low Growth_High Prices Malin 2017-2018 4.49$ 5.98$ 8.00$ 8.32$ 8.41$ 5.26$ 5.27$ 5.58$ 5.27$ 5.36$ 4.62$ 5.45$ Low Growth_High Prices Malin 2018-2019 4.99$ 6.52$ 8.07$ 8.38$ 8.27$ 5.30$ 5.31$ 5.63$ 5.28$ 5.39$ 4.67$ 5.47$ Low Growth_High Prices Malin 2019-2020 5.01$ 6.48$ 8.03$ 8.34$ 8.41$ 5.29$ 5.23$ 5.54$ 5.23$ 5.38$ 4.64$ 5.44$ Low Growth_High Prices Malin 2020-2021 5.01$ 6.51$ 8.07$ 8.39$ 7.74$ 5.32$ 5.32$ 5.59$ 5.30$ 5.41$ 4.66$ 5.48$ Low Growth_High Prices Malin 2021-2022 5.02$ 6.51$ 8.08$ 8.41$ 8.46$ 5.33$ 5.32$ 5.62$ 5.33$ 5.42$ 4.69$ 5.49$ Low Growth_High Prices Malin 2022-2023 5.04$ 6.51$ 8.09$ 8.43$ 7.04$ 5.33$ 5.33$ 5.65$ 5.31$ 5.45$ 4.70$ 5.50$ Low Growth_High Prices Malin 2023-2024 5.07$ 6.55$ 8.09$ 8.40$ 8.47$ 5.34$ 5.33$ 5.63$ 5.30$ 5.45$ 4.71$ 5.52$ Low Growth_High Prices Malin 2024-2025 5.06$ 6.53$ 8.09$ 8.40$ 8.47$ 5.35$ 5.33$ 5.63$ 5.31$ 5.43$ 4.69$ 5.51$ Low Growth_High Prices Malin 2025-2026 5.06$ 6.55$ 8.08$ 8.42$ 8.48$ 5.35$ 5.32$ 5.63$ 5.31$ 5.44$ 4.71$ 5.51$ Low Growth_High Prices Malin 2026-2027 5.07$ 6.56$ 8.13$ 8.45$ 7.92$ 5.38$ 5.36$ 5.67$ 5.34$ 5.46$ 4.72$ 5.57$ Low Growth_High Prices Malin 2027-2028 5.14$ 6.62$ 8.18$ 8.50$ 8.32$ 5.43$ 5.40$ 5.71$ 5.38$ 5.50$ 4.77$ 5.61$ Low Growth_High Prices Malin 2028-2029 5.18$ 6.66$ 8.26$ 8.57$ 8.19$ 5.48$ 5.46$ 5.76$ 5.42$ 5.55$ 4.83$ 5.66$ Low Growth_High Prices Malin 2029-2030 5.24$ 6.74$ 8.30$ 8.62$ 8.72$ 5.53$ 5.52$ 5.83$ 5.48$ 5.62$ 4.93$ 5.74$ Low Growth_High Prices Malin 2030-2031 5.31$ 6.78$ 8.36$ 8.69$ 8.78$ 5.60$ 5.57$ 5.88$ 5.53$ 5.66$ 4.97$ 5.80$ Low Growth_High Prices Malin 2031-2032 5.37$ 6.83$ 8.41$ 8.74$ 7.63$ 5.68$ 5.61$ 5.91$ 5.57$ 5.74$ 5.05$ 5.88$ Low Growth_High Prices Malin 2032-2033 5.46$ 6.91$ 8.49$ 8.82$ 7.89$ 5.78$ 5.70$ 6.00$ 5.72$ 5.85$ 5.13$ 5.94$ Low Growth_High Prices Malin 2033-2034 5.51$ 7.04$ 8.62$ 8.94$ 7.79$ 5.82$ 5.80$ 6.11$ 5.77$ 5.90$ 5.19$ 6.00$ Low Growth_High Prices Malin 2034-2035 5.58$ 7.12$ 8.69$ 9.02$ 8.48$ 5.88$ 5.88$ 6.18$ 5.86$ 5.98$ 5.25$ 6.07$ Low Growth_High Prices Rockies 2015-2016 2.01$ 1.81$ 7.46$ 7.78$ 7.82$ 4.64$ 4.63$ 4.96$ 4.63$ 4.77$ 4.03$ 4.86$ Low Growth_High Prices Rockies 2016-2017 4.38$ 5.89$ 7.41$ 7.74$ 7.46$ 4.67$ 4.69$ 5.02$ 4.68$ 4.78$ 4.06$ 4.86$ Low Growth_High Prices Rockies 2017-2018 4.39$ 5.90$ 7.95$ 8.28$ 8.36$ 5.22$ 5.21$ 5.53$ 5.18$ 5.29$ 4.58$ 5.37$ Low Growth_High Prices Rockies 2018-2019 4.92$ 6.44$ 7.99$ 8.31$ 8.20$ 5.26$ 5.26$ 5.57$ 5.22$ 5.33$ 4.58$ 5.38$ Low Growth_High Prices Rockies 2019-2020 4.93$ 6.40$ 7.94$ 8.27$ 8.36$ 5.23$ 5.20$ 5.51$ 5.18$ 5.32$ 4.59$ 5.37$ Low Growth_High Prices Rockies 2020-2021 4.93$ 6.44$ 8.00$ 8.32$ 7.69$ 5.27$ 5.28$ 5.59$ 5.25$ 5.36$ 4.61$ 5.41$ Low Growth_High Prices Rockies 2021-2022 4.94$ 6.46$ 8.01$ 8.33$ 8.41$ 5.29$ 5.29$ 5.61$ 5.27$ 5.37$ 4.63$ 5.42$ Low Growth_High Prices Rockies 2022-2023 4.95$ 6.47$ 8.00$ 8.34$ 6.97$ 5.28$ 5.28$ 5.58$ 5.24$ 5.40$ 4.66$ 5.44$ Low Growth_High Prices Rockies 2023-2024 4.99$ 6.49$ 7.99$ 8.31$ 8.42$ 5.30$ 5.29$ 5.59$ 5.25$ 5.42$ 4.68$ 5.48$ Low Growth_High Prices Rockies 2024-2025 5.00$ 6.50$ 8.04$ 8.35$ 8.44$ 5.32$ 5.29$ 5.60$ 5.27$ 5.39$ 4.65$ 5.45$ Low Growth_High Prices Rockies 2025-2026 4.98$ 6.50$ 8.03$ 8.35$ 8.44$ 5.31$ 5.28$ 5.60$ 5.26$ 5.40$ 4.65$ 5.46$ Low Growth_High Prices Rockies 2026-2027 4.99$ 6.49$ 8.06$ 8.38$ 7.87$ 5.34$ 5.32$ 5.63$ 5.30$ 5.41$ 4.67$ 5.48$ Low Growth_High Prices Rockies 2027-2028 5.03$ 6.54$ 8.09$ 8.42$ 8.25$ 5.38$ 5.35$ 5.65$ 5.32$ 5.45$ 4.71$ 5.52$ Low Growth_High Prices Rockies 2028-2029 5.07$ 6.58$ 8.18$ 8.49$ 8.11$ 5.43$ 5.40$ 5.72$ 5.35$ 5.48$ 4.76$ 5.57$ Low Growth_High Prices Rockies 2029-2030 5.17$ 6.65$ 8.22$ 8.54$ 8.63$ 5.49$ 5.48$ 5.78$ 5.42$ 5.57$ 4.85$ 5.68$ Low Growth_High Prices Rockies 2030-2031 5.24$ 6.71$ 8.28$ 8.61$ 8.71$ 5.56$ 5.52$ 5.83$ 5.48$ 5.60$ 4.90$ 5.73$ Low Growth_High Prices Rockies 2031-2032 5.30$ 6.75$ 8.33$ 8.66$ 7.56$ 5.64$ 5.56$ 5.86$ 5.51$ 5.66$ 4.97$ 5.80$ Low Growth_High Prices Rockies 2032-2033 5.36$ 6.84$ 8.42$ 8.74$ 7.81$ 5.71$ 5.64$ 5.95$ 5.58$ 5.76$ 5.06$ 5.87$ Low Growth_High Prices Rockies 2033-2034 5.42$ 6.90$ 8.48$ 8.80$ 7.71$ 5.77$ 5.73$ 6.02$ 5.65$ 5.82$ 5.13$ 5.93$ Low Growth_High Prices Rockies 2034-2035 5.47$ 6.96$ 8.54$ 8.87$ 8.40$ 5.83$ 5.82$ 6.09$ 5.75$ 5.89$ 5.20$ 5.98$ 2014$ Avista Corp 2016 Natural Gas IRP Appendices 173 Appendix - Chapter 5 APPENDIX 5.1: MONTHLY PRICE DATA BY BASIN LOW GROWTH HIGH PRICE Low Growth_High Prices Stanfield 2015-2016 2.17$ 1.98$ 7.56$ 7.84$ 7.84$ 4.63$ 4.64$ 4.97$ 4.63$ 4.77$ 4.01$ 4.80$ Low Growth_High Prices Stanfield 2016-2017 4.39$ 5.90$ 7.45$ 7.77$ 7.49$ 4.70$ 4.69$ 5.03$ 4.68$ 4.77$ 4.05$ 4.87$ Low Growth_High Prices Stanfield 2017-2018 4.42$ 5.92$ 7.97$ 8.29$ 8.37$ 5.25$ 5.21$ 5.53$ 5.18$ 5.29$ 4.58$ 5.37$ Low Growth_High Prices Stanfield 2018-2019 4.92$ 6.43$ 7.98$ 8.29$ 8.19$ 5.23$ 5.23$ 5.54$ 5.20$ 5.31$ 4.58$ 5.38$ Low Growth_High Prices Stanfield 2019-2020 4.92$ 6.39$ 7.93$ 8.24$ 8.32$ 5.22$ 5.16$ 5.46$ 5.16$ 5.30$ 4.57$ 5.36$ Low Growth_High Prices Stanfield 2020-2021 4.92$ 6.41$ 7.97$ 8.28$ 7.65$ 5.25$ 5.25$ 5.52$ 5.22$ 5.33$ 4.57$ 5.38$ Low Growth_High Prices Stanfield 2021-2022 4.93$ 6.41$ 7.98$ 8.30$ 8.38$ 5.27$ 5.25$ 5.55$ 5.25$ 5.34$ 4.58$ 5.39$ Low Growth_High Prices Stanfield 2022-2023 4.94$ 6.42$ 7.99$ 8.32$ 6.95$ 5.27$ 5.26$ 5.56$ 5.24$ 5.37$ 4.62$ 5.41$ Low Growth_High Prices Stanfield 2023-2024 4.98$ 6.46$ 8.04$ 8.29$ 8.40$ 5.29$ 5.27$ 5.56$ 5.22$ 5.38$ 4.64$ 5.46$ Low Growth_High Prices Stanfield 2024-2025 5.00$ 6.47$ 8.02$ 8.34$ 8.42$ 5.31$ 5.28$ 5.58$ 5.24$ 5.38$ 4.62$ 5.44$ Low Growth_High Prices Stanfield 2025-2026 5.01$ 6.49$ 8.01$ 8.35$ 8.43$ 5.30$ 5.26$ 5.57$ 5.25$ 5.39$ 4.66$ 5.46$ Low Growth_High Prices Stanfield 2026-2027 5.02$ 6.50$ 8.07$ 8.38$ 7.87$ 5.35$ 5.33$ 5.64$ 5.30$ 5.42$ 4.68$ 5.51$ Low Growth_High Prices Stanfield 2027-2028 5.10$ 6.57$ 8.11$ 8.44$ 8.26$ 5.39$ 5.37$ 5.66$ 5.33$ 5.45$ 4.71$ 5.54$ Low Growth_High Prices Stanfield 2028-2029 5.12$ 6.59$ 8.17$ 8.51$ 8.13$ 5.44$ 5.42$ 5.73$ 5.35$ 5.49$ 4.75$ 5.59$ Low Growth_High Prices Stanfield 2029-2030 5.18$ 6.67$ 8.23$ 8.56$ 8.65$ 5.49$ 5.49$ 5.79$ 5.44$ 5.56$ 4.88$ 5.66$ Low Growth_High Prices Stanfield 2030-2031 5.23$ 6.72$ 8.29$ 8.62$ 8.74$ 5.56$ 5.53$ 5.84$ 5.49$ 5.61$ 4.92$ 5.72$ Low Growth_High Prices Stanfield 2031-2032 5.31$ 6.77$ 8.33$ 8.67$ 7.57$ 5.64$ 5.55$ 5.88$ 5.53$ 5.69$ 5.00$ 5.82$ Low Growth_High Prices Stanfield 2032-2033 5.39$ 6.85$ 8.41$ 8.75$ 7.82$ 5.74$ 5.66$ 5.97$ 5.67$ 5.80$ 5.06$ 5.88$ Low Growth_High Prices Stanfield 2033-2034 5.45$ 6.97$ 8.54$ 8.87$ 7.72$ 5.77$ 5.76$ 6.07$ 5.72$ 5.85$ 5.11$ 5.94$ Low Growth_High Prices Stanfield 2034-2035 5.51$ 7.05$ 8.61$ 8.94$ 8.42$ 5.81$ 5.84$ 6.12$ 5.79$ 5.89$ 5.17$ 6.00$ Low Growth_High Prices Sumas 2015-2016 2.16$ 1.93$ 7.53$ 7.76$ 7.69$ 4.43$ 4.31$ 4.63$ 4.26$ 4.45$ 3.84$ 4.66$ Low Growth_High Prices Sumas 2016-2017 4.25$ 5.93$ 7.41$ 7.70$ 7.43$ 4.62$ 4.59$ 4.84$ 4.51$ 4.64$ 3.93$ 4.69$ Low Growth_High Prices Sumas 2017-2018 4.35$ 5.93$ 7.93$ 8.24$ 8.32$ 5.15$ 4.92$ 5.23$ 4.89$ 5.06$ 4.34$ 5.26$ Low Growth_High Prices Sumas 2018-2019 4.81$ 6.37$ 7.94$ 8.26$ 8.10$ 5.06$ 4.99$ 5.24$ 4.94$ 5.11$ 4.41$ 5.26$ Low Growth_High Prices Sumas 2019-2020 4.81$ 6.33$ 7.85$ 8.18$ 8.26$ 5.07$ 4.97$ 5.20$ 4.97$ 5.13$ 4.45$ 5.28$ Low Growth_High Prices Sumas 2020-2021 4.83$ 6.34$ 7.92$ 8.27$ 7.62$ 5.14$ 5.08$ 5.30$ 5.05$ 5.18$ 4.50$ 5.30$ Low Growth_High Prices Sumas 2021-2022 4.81$ 6.27$ 7.85$ 8.17$ 8.33$ 5.17$ 5.08$ 5.38$ 5.06$ 5.21$ 4.53$ 5.32$ Low Growth_High Prices Sumas 2022-2023 4.84$ 6.27$ 7.84$ 8.22$ 6.91$ 5.19$ 5.09$ 5.41$ 5.08$ 5.26$ 4.55$ 5.33$ Low Growth_High Prices Sumas 2023-2024 4.88$ 6.41$ 7.92$ 8.22$ 8.34$ 5.17$ 5.06$ 5.38$ 5.04$ 5.25$ 4.56$ 5.36$ Low Growth_High Prices Sumas 2024-2025 4.88$ 6.29$ 7.92$ 8.27$ 8.36$ 5.18$ 5.07$ 5.35$ 5.04$ 5.23$ 4.53$ 5.33$ Low Growth_High Prices Sumas 2025-2026 4.83$ 6.30$ 7.84$ 8.18$ 8.33$ 5.17$ 5.05$ 5.33$ 5.05$ 5.24$ 4.51$ 5.31$ Low Growth_High Prices Sumas 2026-2027 4.85$ 6.32$ 7.89$ 8.21$ 7.77$ 5.20$ 5.16$ 5.43$ 5.13$ 5.26$ 4.57$ 5.46$ Low Growth_High Prices Sumas 2027-2028 4.99$ 6.54$ 8.12$ 8.44$ 8.20$ 5.32$ 5.21$ 5.53$ 5.20$ 5.40$ 4.69$ 5.51$ Low Growth_High Prices Sumas 2028-2029 5.13$ 6.60$ 8.20$ 8.52$ 8.13$ 5.39$ 5.28$ 5.60$ 5.25$ 5.45$ 4.73$ 5.57$ Low Growth_High Prices Sumas 2029-2030 5.19$ 6.68$ 8.24$ 8.56$ 8.66$ 5.44$ 5.39$ 5.71$ 5.33$ 5.52$ 4.88$ 5.69$ Low Growth_High Prices Sumas 2030-2031 5.27$ 6.73$ 8.30$ 8.63$ 8.73$ 5.51$ 5.45$ 5.76$ 5.38$ 5.57$ 4.92$ 5.75$ Low Growth_High Prices Sumas 2031-2032 5.32$ 6.78$ 8.36$ 8.69$ 7.58$ 5.59$ 5.51$ 5.82$ 5.42$ 5.65$ 4.99$ 5.82$ Low Growth_High Prices Sumas 2032-2033 5.39$ 6.86$ 8.43$ 8.76$ 7.83$ 5.69$ 5.57$ 5.87$ 5.52$ 5.74$ 5.05$ 5.90$ Low Growth_High Prices Sumas 2033-2034 5.50$ 7.03$ 8.63$ 8.94$ 7.75$ 5.74$ 5.66$ 5.95$ 5.59$ 5.80$ 5.13$ 5.96$ Low Growth_High Prices Sumas 2034-2035 5.57$ 7.13$ 8.71$ 9.03$ 8.46$ 5.84$ 5.79$ 6.04$ 5.72$ 5.89$ 5.20$ 6.02$ 2014$ Avista Corp 2016 Natural Gas IRP Appendices 174 Appendix - Chapter 5 APPENDIX 5.2: WEIGHTED AVERAGE COST OF CAPITAL From 2015 Rate Case Settlement Cost of Capital Percent of Total Capital Cost Component After Tax L/T Debt 51.50% 5.20% 2.68% 1.74% Common Equity 48.50% 9.50% 4.61% 4.61% TOTAL 100.00%7.29% 6.35% Agreed-upon Cost of Capital Percent of Total Capital Cost Component L/T Debt 50.00% 5.34% 2.67% 1.74% Common Equity 50.00% 9.50% 4.75% 4.75% TOTAL 100.00%7.42% 6.49% Agreed-upon Cost of Capital Percent of Total Capital Cost Component L/T Debt 50.00% 5.52% 2.76% 1.79% Common Equity 50.00% 9.40% 4.70% 4.70% TOTAL 100.00%7.46% 6.49% 2015 Year End Gas Net Rate Base AMA WA 269,072$ 46% ID 126,932$ 22% OR 189,415$ 32% 585,419$ System Weighted Average Cost of Capital (Nominal)*6.42% GDP price deflator 2.00% Real After Tax WACC 4.34% WASHINGTON IDAHO Avista Corporation Captial Structure and Overall Rate of Return OREGON Avista Corp 2016 Natural Gas IRP Appendices 175 Appendix - Chapter 5 APPENDIX 5.3: POTENTIAL SUPPLY SIDE RESOURCE OPTIONS Avista Corp 2016 Natural Gas IRP Appendices 176 Appendix - Chapter 5 APPENDIX 5.4: EXPECTED CASE AVOIDED COST Scenario Gas Year Klam Falls La Grande Medford GTN Medford NWP Roseburg Wa/Id Both Wa/Id GTN Wa/Id NWP WA/ID Annual OR Annual Expected Case 2015-2016 1.88$ 2.17$ 1.88$ 1.88$ 1.88$ 1.88$ 1.84$ 2.16$ 1.96$ 1.94$ Expected Case 2016-2017 2.27$ 2.97$ 2.27$ 2.27$ 2.27$ 2.31$ 2.20$ 2.95$ 2.49$ 2.41$ Expected Case 2017-2018 2.79$ 3.45$ 2.79$ 2.79$ 2.79$ 2.79$ 2.72$ 3.44$ 2.99$ 2.92$ Expected Case 2018-2019 2.80$ 3.54$ 2.80$ 2.80$ 2.80$ 2.83$ 2.74$ 3.52$ 3.03$ 2.95$ Expected Case 2019-2020 2.88$ 3.62$ 2.88$ 2.88$ 2.88$ 2.93$ 2.83$ 3.61$ 3.12$ 3.03$ Expected Case 2020-2021 3.04$ 3.77$ 3.04$ 3.04$ 3.04$ 3.09$ 2.97$ 3.76$ 3.27$ 3.18$ Expected Case 2021-2022 3.15$ 3.90$ 3.15$ 3.15$ 3.15$ 3.16$ 3.05$ 3.87$ 3.36$ 3.30$ Expected Case 2022-2023 3.15$ 3.91$ 3.15$ 3.15$ 3.15$ 3.13$ 3.01$ 3.88$ 3.34$ 3.30$ Expected Case 2023-2024 3.35$ 3.97$ 3.35$ 3.35$ 3.35$ 3.38$ 3.27$ 3.95$ 3.53$ 3.48$ Expected Case 2024-2025 3.61$ 4.14$ 3.61$ 3.61$ 3.61$ 3.61$ 3.53$ 4.12$ 3.75$ 3.71$ Expected Case 2025-2026 3.59$ 4.10$ 3.59$ 3.59$ 3.59$ 3.58$ 3.53$ 4.06$ 3.72$ 3.69$ Expected Case 2026-2027 3.66$ 4.17$ 3.66$ 3.66$ 3.66$ 3.66$ 3.59$ 4.11$ 3.79$ 3.76$ Expected Case 2027-2028 3.97$ 4.38$ 3.97$ 3.97$ 3.97$ 3.95$ 3.91$ 4.34$ 4.06$ 4.05$ Expected Case 2028-2029 4.17$ 4.54$ 4.17$ 4.17$ 4.17$ 4.13$ 4.11$ 4.50$ 4.25$ 4.24$ Expected Case 2029-2030 4.33$ 4.73$ 4.33$ 4.33$ 4.33$ 4.30$ 4.26$ 4.70$ 4.42$ 4.41$ Expected Case 2030-2031 4.54$ 4.87$ 4.54$ 4.54$ 4.54$ 4.50$ 4.46$ 4.84$ 4.60$ 4.60$ Expected Case 2031-2032 4.68$ 4.97$ 4.68$ 4.68$ 4.68$ 4.64$ 4.61$ 4.94$ 4.73$ 4.73$ Expected Case 2032-2033 4.73$ 5.03$ 4.73$ 4.73$ 4.73$ 4.69$ 4.65$ 5.01$ 4.78$ 4.79$ Expected Case 2033-2034 4.78$ 5.15$ 4.78$ 4.78$ 4.78$ 4.75$ 4.70$ 5.13$ 4.86$ 4.86$ Expected Case 2034-2035 4.82$ 5.05$ 4.82$ 4.82$ 4.82$ 4.79$ 4.74$ 5.01$ 4.85$ 4.87$ Scenario Gas Year Klam Falls La Grande Medford GTN Medford NWP Roseburg Wa/Id Both Wa/Id GTN Wa/Id NWP WA/ID Winter OR Winter Expected Case 2015-2016 1.87$ 2.09$ 1.87$ 1.87$ 1.87$ 2.00$ 1.79$ 2.09$ 1.96$ 1.91$ Expected Case 2016-2017 2.31$ 2.97$ 2.31$ 2.31$ 2.31$ 2.42$ 2.14$ 2.94$ 2.50$ 2.44$ Expected Case 2017-2018 2.70$ 3.41$ 2.70$ 2.70$ 2.70$ 2.77$ 2.48$ 3.40$ 2.88$ 2.85$ Expected Case 2018-2019 3.15$ 3.55$ 3.15$ 3.15$ 3.15$ 3.26$ 3.01$ 3.51$ 3.26$ 3.23$ Expected Case 2019-2020 3.22$ 3.64$ 3.22$ 3.22$ 3.22$ 3.36$ 3.09$ 3.60$ 3.35$ 3.30$ Expected Case 2020-2021 3.33$ 3.78$ 3.33$ 3.33$ 3.33$ 3.49$ 3.19$ 3.75$ 3.48$ 3.42$ Expected Case 2021-2022 3.60$ 3.91$ 3.60$ 3.60$ 3.60$ 3.63$ 3.33$ 3.85$ 3.61$ 3.66$ Expected Case 2022-2023 3.58$ 3.93$ 3.58$ 3.58$ 3.58$ 3.54$ 3.22$ 3.86$ 3.54$ 3.65$ Expected Case 2023-2024 3.76$ 4.01$ 3.76$ 3.76$ 3.76$ 3.81$ 3.51$ 3.97$ 3.76$ 3.81$ Expected Case 2024-2025 3.98$ 4.18$ 3.98$ 3.98$ 3.98$ 4.01$ 3.79$ 4.12$ 3.97$ 4.02$ Expected Case 2025-2026 4.19$ 4.24$ 4.19$ 4.19$ 4.19$ 4.10$ 4.07$ 4.14$ 4.10$ 4.20$ Expected Case 2026-2027 4.18$ 4.30$ 4.18$ 4.18$ 4.18$ 4.11$ 4.04$ 4.13$ 4.09$ 4.20$ Expected Case 2027-2028 4.41$ 4.48$ 4.41$ 4.41$ 4.41$ 4.36$ 4.30$ 4.38$ 4.34$ 4.43$ Expected Case 2028-2029 4.60$ 4.67$ 4.60$ 4.60$ 4.60$ 4.54$ 4.50$ 4.58$ 4.54$ 4.61$ Expected Case 2029-2030 4.72$ 4.84$ 4.72$ 4.72$ 4.72$ 4.70$ 4.61$ 4.76$ 4.69$ 4.75$ Expected Case 2030-2031 5.02$ 5.09$ 5.02$ 5.02$ 5.02$ 4.94$ 4.91$ 4.99$ 4.95$ 5.03$ Expected Case 2031-2032 5.09$ 5.20$ 5.09$ 5.09$ 5.09$ 5.07$ 5.00$ 5.13$ 5.06$ 5.12$ Expected Case 2032-2033 5.23$ 5.33$ 5.23$ 5.23$ 5.23$ 5.18$ 5.13$ 5.24$ 5.19$ 5.25$ Expected Case 2033-2034 5.33$ 5.48$ 5.33$ 5.33$ 5.33$ 5.28$ 5.22$ 5.35$ 5.28$ 5.36$ Expected Case 2034-2035 5.32$ 5.46$ 5.32$ 5.32$ 5.32$ 5.25$ 5.19$ 5.32$ 5.25$ 5.35$ 1/ Avoided costs are before Environmental Externalities adder. Annual Avoided Costs 1/ 2014$ Winter Avoided Costs 1/ 2014$ Avista Corp 2016 Natural Gas IRP Appendices 177 Appendix - Chapter 5 APPENDIX 5.4: LOW GROWTH CASE AVOIDED COST Scenario Gas Year Klam Falls La Grande Medford GTN Medford NWP Roseburg Wa/Id Both Wa/Id GTN Wa/Id NWP WA/ID Annual OR Annual Low Growth & High Prices 2015-2016 4.68$ 5.03$ 4.68$ 4.68$ 4.68$ 4.63$ 4.61$ 4.98$ 4.74$ 4.75$ Low Growth & High Prices 2016-2017 5.09$ 5.72$ 5.08$ 5.08$ 5.08$ 4.99$ 5.00$ 5.70$ 5.23$ 5.21$ Low Growth & High Prices 2017-2018 5.57$ 6.20$ 5.57$ 5.57$ 5.57$ 5.46$ 5.48$ 6.16$ 5.70$ 5.69$ Low Growth & High Prices 2018-2019 5.59$ 6.27$ 5.58$ 5.58$ 5.58$ 5.49$ 5.50$ 6.24$ 5.75$ 5.72$ Low Growth & High Prices 2019-2020 5.63$ 6.27$ 5.63$ 5.63$ 5.63$ 5.52$ 5.55$ 6.23$ 5.77$ 5.76$ Low Growth & High Prices 2020-2021 5.63$ 6.26$ 5.62$ 5.62$ 5.62$ 5.53$ 5.55$ 6.25$ 5.78$ 5.75$ Low Growth & High Prices 2021-2022 5.66$ 6.35$ 5.66$ 5.66$ 5.66$ 5.55$ 5.58$ 6.31$ 5.81$ 5.80$ Low Growth & High Prices 2022-2023 5.50$ 6.22$ 5.49$ 5.49$ 5.49$ 5.33$ 5.41$ 6.15$ 5.63$ 5.64$ Low Growth & High Prices 2023-2024 5.79$ 6.34$ 5.79$ 5.79$ 5.79$ 5.68$ 5.71$ 6.31$ 5.90$ 5.90$ Low Growth & High Prices 2024-2025 5.82$ 6.29$ 5.82$ 5.82$ 5.82$ 5.71$ 5.73$ 6.27$ 5.90$ 5.91$ Low Growth & High Prices 2025-2026 5.81$ 6.25$ 5.81$ 5.81$ 5.81$ 5.70$ 5.72$ 6.23$ 5.88$ 5.89$ Low Growth & High Prices 2026-2027 5.79$ 6.20$ 5.78$ 5.78$ 5.78$ 5.69$ 5.70$ 6.21$ 5.87$ 5.87$ Low Growth & High Prices 2027-2028 6.01$ 6.34$ 6.00$ 6.00$ 6.00$ 5.91$ 5.92$ 6.35$ 6.06$ 6.07$ Low Growth & High Prices 2028-2029 6.07$ 6.37$ 6.06$ 6.06$ 6.06$ 5.97$ 5.98$ 6.38$ 6.11$ 6.12$ Low Growth & High Prices 2029-2030 6.18$ 6.48$ 6.17$ 6.17$ 6.17$ 6.06$ 6.09$ 6.47$ 6.21$ 6.23$ Low Growth & High Prices 2030-2031 6.27$ 6.53$ 6.27$ 6.27$ 6.27$ 6.16$ 6.18$ 6.53$ 6.29$ 6.32$ Low Growth & High Prices 2031-2032 6.25$ 6.48$ 6.24$ 6.24$ 6.24$ 6.15$ 6.16$ 6.48$ 6.26$ 6.29$ Low Growth & High Prices 2032-2033 6.33$ 6.56$ 6.32$ 6.32$ 6.32$ 6.12$ 6.25$ 6.45$ 6.27$ 6.37$ Low Growth & High Prices 2033-2034 6.35$ 6.64$ 6.35$ 6.35$ 6.35$ 6.12$ 6.26$ 6.51$ 6.30$ 6.41$ Low Growth & High Prices 2034-2035 6.50$ 6.65$ 6.49$ 6.49$ 6.49$ 6.37$ 6.40$ 6.59$ 6.46$ 6.52$ Scenario Gas Year Klam Falls La Grande Medford GTN Medford NWP Roseburg Wa/Id Both Wa/Id GTN Wa/Id NWP WA/ID Winter OR Winter Low Growth & High Prices 2015-2016 1.88$ 2.14$ 1.88$ 1.88$ 1.88$ 2.02$ 1.79$ 2.14$ 1.98$ 1.93$ Low Growth & High Prices 2016-2017 4.78$ 5.71$ 4.79$ 4.79$ 4.79$ 4.69$ 4.63$ 5.71$ 5.01$ 4.97$ Low Growth & High Prices 2017-2018 4.85$ 5.74$ 4.85$ 4.85$ 4.85$ 4.75$ 4.70$ 5.74$ 5.06$ 5.03$ Low Growth & High Prices 2018-2019 5.42$ 6.12$ 5.42$ 5.42$ 5.42$ 5.32$ 5.27$ 6.11$ 5.57$ 5.56$ Low Growth & High Prices 2019-2020 5.44$ 6.04$ 5.44$ 5.44$ 5.44$ 5.36$ 5.31$ 6.04$ 5.57$ 5.56$ Low Growth & High Prices 2020-2021 5.50$ 6.02$ 5.50$ 5.50$ 5.50$ 5.42$ 5.37$ 6.02$ 5.60$ 5.60$ Low Growth & High Prices 2021-2022 5.44$ 6.01$ 5.44$ 5.44$ 5.44$ 5.35$ 5.30$ 6.00$ 5.55$ 5.55$ Low Growth & High Prices 2022-2023 5.35$ 6.15$ 5.35$ 5.35$ 5.35$ 5.24$ 5.19$ 6.12$ 5.52$ 5.51$ Low Growth & High Prices 2023-2024 5.56$ 6.08$ 5.56$ 5.56$ 5.56$ 5.47$ 5.42$ 6.08$ 5.66$ 5.66$ Low Growth & High Prices 2024-2025 5.61$ 5.91$ 5.61$ 5.61$ 5.61$ 5.54$ 5.49$ 5.90$ 5.64$ 5.67$ Low Growth & High Prices 2025-2026 5.62$ 5.88$ 5.62$ 5.62$ 5.62$ 5.54$ 5.49$ 5.87$ 5.63$ 5.67$ Low Growth & High Prices 2026-2027 5.61$ 5.93$ 5.61$ 5.61$ 5.61$ 5.52$ 5.47$ 5.93$ 5.64$ 5.68$ Low Growth & High Prices 2027-2028 5.77$ 6.09$ 5.77$ 5.77$ 5.77$ 5.69$ 5.64$ 6.09$ 5.81$ 5.83$ Low Growth & High Prices 2028-2029 5.85$ 6.14$ 5.85$ 5.85$ 5.85$ 5.78$ 5.73$ 6.14$ 5.88$ 5.90$ Low Growth & High Prices 2029-2030 5.90$ 6.26$ 5.90$ 5.90$ 5.90$ 5.82$ 5.77$ 6.26$ 5.95$ 5.97$ Low Growth & High Prices 2030-2031 5.97$ 6.31$ 5.97$ 5.97$ 5.97$ 5.90$ 5.85$ 6.31$ 6.02$ 6.03$ Low Growth & High Prices 2031-2032 6.02$ 6.35$ 6.02$ 6.02$ 6.02$ 5.96$ 5.91$ 6.35$ 6.07$ 6.09$ Low Growth & High Prices 2032-2033 6.10$ 6.42$ 6.10$ 6.10$ 6.10$ 6.04$ 5.99$ 6.42$ 6.15$ 6.16$ Low Growth & High Prices 2033-2034 6.16$ 6.50$ 6.16$ 6.16$ 6.16$ 6.09$ 6.04$ 6.50$ 6.21$ 6.23$ Low Growth & High Prices 2034-2035 6.22$ 6.56$ 6.22$ 6.22$ 6.22$ 6.14$ 6.09$ 6.56$ 6.26$ 6.28$ 1/ Avoided costs are before Environmental Externalities adder. Annual Avoided Costs 1/ 2014$ Winter Avoided Costs 1/ 2014$ Avista Corp 2016 Natural Gas IRP Appendices 178 Appendix - Chapter 5 APPENDIX 5.4: HIGH GROWTH CASE AVOIDED COST Scenario Gas Year Klam Falls La Grande Medford GTN Medford NWP Roseburg Wa/Id Both Wa/Id GTN Wa/Id NWP WA/ID Annual OR Annual High Growth & Low Prices 2015-2016 1.69$ 2.02$ 1.69$ 1.69$ 1.69$ 1.70$ 1.65$ 2.01$ 1.79$ 1.75$ High Growth & Low Prices 2016-2017 1.57$ 2.13$ 1.57$ 1.57$ 1.57$ 1.60$ 1.49$ 2.12$ 1.74$ 1.68$ High Growth & Low Prices 2017-2018 1.57$ 2.14$ 1.57$ 1.57$ 1.57$ 1.59$ 1.50$ 2.13$ 1.74$ 1.69$ High Growth & Low Prices 2018-2019 1.53$ 2.15$ 1.53$ 1.53$ 1.53$ 1.55$ 1.42$ 2.13$ 1.70$ 1.65$ High Growth & Low Prices 2019-2020 1.55$ 2.14$ 1.55$ 1.55$ 1.55$ 1.57$ 1.44$ 2.12$ 1.71$ 1.67$ High Growth & Low Prices 2020-2021 1.59$ 2.15$ 1.59$ 1.59$ 1.59$ 1.60$ 1.48$ 2.12$ 1.73$ 1.70$ High Growth & Low Prices 2021-2022 1.59$ 2.23$ 1.59$ 1.59$ 1.59$ 1.59$ 1.46$ 2.20$ 1.75$ 1.72$ High Growth & Low Prices 2022-2023 1.58$ 2.26$ 1.58$ 1.58$ 1.58$ 1.54$ 1.40$ 2.22$ 1.72$ 1.72$ High Growth & Low Prices 2023-2024 1.68$ 2.20$ 1.68$ 1.68$ 1.68$ 1.69$ 1.55$ 2.17$ 1.80$ 1.78$ High Growth & Low Prices 2024-2025 1.68$ 2.13$ 1.68$ 1.68$ 1.68$ 1.71$ 1.58$ 2.10$ 1.80$ 1.77$ High Growth & Low Prices 2025-2026 1.64$ 2.08$ 1.64$ 1.64$ 1.64$ 1.67$ 1.54$ 2.04$ 1.75$ 1.73$ High Growth & Low Prices 2026-2027 1.67$ 2.11$ 1.67$ 1.67$ 1.67$ 1.68$ 1.54$ 2.05$ 1.75$ 1.76$ High Growth & Low Prices 2027-2028 1.77$ 2.09$ 7.23$ 7.23$ 7.23$ 1.78$ 1.67$ 2.09$ 1.84$ 5.11$ High Growth & Low Prices 2028-2029 1.83$ 2.12$ 7.30$ 7.30$ 7.30$ 1.84$ 1.73$ 2.10$ 1.89$ 5.17$ High Growth & Low Prices 2029-2030 1.87$ 2.19$ 7.35$ 7.35$ 7.35$ 1.88$ 1.77$ 2.18$ 1.94$ 5.22$ High Growth & Low Prices 2030-2031 1.91$ 7.66$ 12.86$ 12.86$ 12.86$ 1.92$ 1.81$ 2.18$ 1.97$ 9.63$ High Growth & Low Prices 2031-2032 1.94$ 7.64$ 12.86$ 12.86$ 12.86$ 7.41$ 1.84$ 7.63$ 5.63$ 9.63$ High Growth & Low Prices 2032-2033 1.95$ 7.67$ 12.89$ 12.89$ 12.89$ 7.43$ 1.85$ 7.67$ 5.65$ 9.66$ High Growth & Low Prices 2033-2034 1.97$ 7.72$ 12.92$ 12.92$ 12.92$ 7.44$ 1.86$ 7.71$ 5.67$ 9.69$ High Growth & Low Prices 2034-2035 7.45$ 7.67$ 12.92$ 12.92$ 12.92$ 7.44$ 1.85$ 7.66$ 5.65$ 10.77$ Scenario Gas Year Klam Falls La Grande Medford GTN Medford NWP Roseburg Wa/Id Both Wa/Id GTN Wa/Id NWP WA/ID Winter OR Winter High Growth & Low Prices 2015-2016 1.87$ 1.98$ 1.87$ 1.87$ 1.87$ 1.96$ 1.79$ 1.98$ 1.91$ 1.89$ High Growth & Low Prices 2016-2017 1.31$ 2.07$ 1.31$ 1.31$ 1.31$ 1.38$ 1.06$ 2.07$ 1.50$ 1.46$ High Growth & Low Prices 2017-2018 1.45$ 2.06$ 1.45$ 1.45$ 1.45$ 1.48$ 1.17$ 2.06$ 1.57$ 1.58$ High Growth & Low Prices 2018-2019 1.51$ 2.04$ 1.51$ 1.51$ 1.51$ 1.56$ 1.21$ 2.04$ 1.60$ 1.62$ High Growth & Low Prices 2019-2020 1.52$ 1.91$ 1.52$ 1.52$ 1.52$ 1.53$ 1.18$ 1.91$ 1.54$ 1.60$ High Growth & Low Prices 2020-2021 1.54$ 1.91$ 1.55$ 1.55$ 1.55$ 1.57$ 1.22$ 1.88$ 1.56$ 1.62$ High Growth & Low Prices 2021-2022 1.56$ 1.96$ 1.56$ 1.56$ 1.56$ 1.57$ 1.21$ 1.92$ 1.57$ 1.64$ High Growth & Low Prices 2022-2023 1.55$ 2.06$ 1.55$ 1.55$ 1.55$ 1.45$ 1.06$ 2.02$ 1.51$ 1.66$ High Growth & Low Prices 2023-2024 1.70$ 2.03$ 1.71$ 1.71$ 1.71$ 1.70$ 1.32$ 1.99$ 1.67$ 1.77$ High Growth & Low Prices 2024-2025 1.61$ 1.95$ 1.63$ 1.63$ 1.63$ 1.75$ 1.39$ 1.88$ 1.67$ 1.69$ High Growth & Low Prices 2025-2026 1.55$ 1.81$ 1.57$ 1.57$ 1.57$ 1.64$ 1.28$ 1.73$ 1.55$ 1.61$ High Growth & Low Prices 2026-2027 1.63$ 1.84$ 1.64$ 1.64$ 1.64$ 1.61$ 1.25$ 1.76$ 1.54$ 1.68$ High Growth & Low Prices 2027-2028 1.75$ 1.86$ 34.52$ 34.52$ 34.52$ 1.72$ 1.39$ 1.86$ 1.66$ 21.43$ High Growth & Low Prices 2028-2029 1.77$ 1.91$ 34.54$ 34.54$ 34.54$ 1.80$ 1.47$ 1.91$ 1.73$ 21.46$ High Growth & Low Prices 2029-2030 1.91$ 2.06$ 34.67$ 34.67$ 34.67$ 1.90$ 1.55$ 2.06$ 1.84$ 21.60$ High Growth & Low Prices 2030-2031 1.90$ 2.06$ 67.42$ 67.42$ 67.42$ 1.92$ 1.57$ 2.06$ 1.85$ 41.24$ High Growth & Low Prices 2031-2032 1.85$ 2.00$ 67.38$ 67.38$ 67.38$ 1.93$ 1.56$ 2.00$ 1.83$ 41.20$ High Growth & Low Prices 2032-2033 1.87$ 2.04$ 67.39$ 67.39$ 67.39$ 1.95$ 1.57$ 2.04$ 1.85$ 41.21$ High Growth & Low Prices 2033-2034 2.00$ 2.12$ 67.52$ 67.52$ 67.52$ 2.02$ 1.63$ 2.13$ 1.93$ 41.34$ High Growth & Low Prices 2034-2035 34.70$ 2.14$ 67.47$ 67.47$ 67.47$ 1.97$ 1.52$ 2.15$ 1.88$ 47.85$ 1/ Avoided costs are before Environmental Externalities adder. Annual Avoided Costs 1/ 2014$ Winter Avoided Costs 1/ 2014$ Avista Corp 2016 Natural Gas IRP Appendices 179 Appendix - Chapter 5 APPENDIX 5.4: CARBON LEGISLATION – MEDIUM CASE AVOIDED COST Scenario Gas Year Klam Falls La Grande Medford GTN Medford NWP Roseburg Wa/Id Both Wa/Id GTN Wa/Id NWP WA/ID Annual OR Annual Carbon Legislation - Medium Case 2015-2016 1.88$ 2.17$ 1.88$ 1.88$ 1.88$ 1.89$ 1.84$ 2.16$ 1.96$ 1.94$ Carbon Legislation - Medium Case 2016-2017 2.28$ 2.97$ 2.28$ 2.28$ 2.28$ 2.31$ 2.20$ 2.95$ 2.49$ 2.41$ Carbon Legislation - Medium Case 2017-2018 2.78$ 3.45$ 2.78$ 2.78$ 2.78$ 2.78$ 2.72$ 3.44$ 2.98$ 2.91$ Carbon Legislation - Medium Case 2018-2019 2.79$ 3.53$ 2.79$ 2.79$ 2.79$ 2.81$ 2.74$ 3.51$ 3.02$ 2.94$ Carbon Legislation - Medium Case 2019-2020 2.88$ 3.61$ 2.88$ 2.88$ 2.88$ 2.90$ 2.83$ 3.60$ 3.11$ 3.02$ Carbon Legislation - Medium Case 2020-2021 3.03$ 3.76$ 3.03$ 3.03$ 3.03$ 3.06$ 2.97$ 3.75$ 3.26$ 3.18$ Carbon Legislation - Medium Case 2021-2022 3.11$ 3.88$ 3.11$ 3.11$ 3.11$ 3.13$ 3.05$ 3.87$ 3.35$ 3.27$ Carbon Legislation - Medium Case 2022-2023 3.10$ 3.89$ 3.10$ 3.10$ 3.10$ 3.11$ 3.01$ 3.87$ 3.33$ 3.26$ Carbon Legislation - Medium Case 2023-2024 3.33$ 3.96$ 3.33$ 3.33$ 3.33$ 3.35$ 3.27$ 3.95$ 3.52$ 3.46$ Carbon Legislation - Medium Case 2024-2025 3.59$ 4.10$ 3.59$ 3.59$ 3.59$ 3.59$ 3.53$ 4.08$ 3.73$ 3.69$ Carbon Legislation - Medium Case 2025-2026 3.59$ 4.06$ 3.59$ 3.59$ 3.59$ 3.56$ 3.53$ 4.04$ 3.71$ 3.68$ Carbon Legislation - Medium Case 2026-2027 3.66$ 4.13$ 3.66$ 3.66$ 3.66$ 3.64$ 3.59$ 4.10$ 3.78$ 3.76$ Carbon Legislation - Medium Case 2027-2028 3.97$ 4.34$ 3.97$ 3.97$ 3.97$ 3.93$ 3.91$ 4.33$ 4.06$ 4.05$ Carbon Legislation - Medium Case 2028-2029 4.17$ 4.50$ 4.17$ 4.17$ 4.17$ 4.12$ 4.11$ 4.48$ 4.23$ 4.24$ Carbon Legislation - Medium Case 2029-2030 4.33$ 4.68$ 4.33$ 4.33$ 4.33$ 4.28$ 4.26$ 4.67$ 4.40$ 4.40$ Carbon Legislation - Medium Case 2030-2031 4.53$ 4.84$ 4.53$ 4.53$ 4.53$ 4.49$ 4.46$ 4.83$ 4.59$ 4.59$ Carbon Legislation - Medium Case 2031-2032 4.68$ 4.94$ 4.68$ 4.68$ 4.68$ 4.62$ 4.61$ 4.92$ 4.72$ 4.73$ Carbon Legislation - Medium Case 2032-2033 4.72$ 5.01$ 4.72$ 4.72$ 4.72$ 4.68$ 4.65$ 5.00$ 4.78$ 4.78$ Carbon Legislation - Medium Case 2033-2034 4.77$ 5.12$ 4.77$ 4.77$ 4.77$ 4.74$ 4.70$ 5.12$ 4.85$ 4.84$ Carbon Legislation - Medium Case 2034-2035 4.82$ 5.11$ 4.82$ 4.82$ 4.82$ 4.78$ 4.74$ 5.10$ 4.87$ 4.88$ Scenario Gas Year Klam Falls La Grande Medford GTN Medford NWP Roseburg Wa/Id Both Wa/Id GTN Wa/Id NWP WA/ID Annual OR Annual Carbon Legislation - Medium Case 2015-2016 1.87$ 2.09$ 1.87$ 1.87$ 1.87$ 2.01$ 1.79$ 2.09$ 1.96$ 1.91$ Carbon Legislation - Medium Case 2016-2017 2.32$ 2.97$ 2.32$ 2.32$ 2.32$ 2.42$ 2.14$ 2.94$ 2.50$ 2.45$ Carbon Legislation - Medium Case 2017-2018 2.61$ 3.41$ 2.61$ 2.61$ 2.61$ 2.74$ 2.48$ 3.40$ 2.87$ 2.77$ Carbon Legislation - Medium Case 2018-2019 3.12$ 3.54$ 3.12$ 3.12$ 3.12$ 3.22$ 3.01$ 3.49$ 3.24$ 3.20$ Carbon Legislation - Medium Case 2019-2020 3.19$ 3.62$ 3.19$ 3.19$ 3.19$ 3.31$ 3.09$ 3.59$ 3.33$ 3.28$ Carbon Legislation - Medium Case 2020-2021 3.30$ 3.77$ 3.30$ 3.30$ 3.30$ 3.42$ 3.19$ 3.75$ 3.45$ 3.39$ Carbon Legislation - Medium Case 2021-2022 3.47$ 3.89$ 3.47$ 3.47$ 3.47$ 3.56$ 3.33$ 3.85$ 3.58$ 3.55$ Carbon Legislation - Medium Case 2022-2023 3.42$ 3.91$ 3.42$ 3.42$ 3.42$ 3.48$ 3.22$ 3.86$ 3.52$ 3.52$ Carbon Legislation - Medium Case 2023-2024 3.63$ 3.99$ 3.63$ 3.63$ 3.63$ 3.75$ 3.51$ 3.95$ 3.74$ 3.70$ Carbon Legislation - Medium Case 2024-2025 3.91$ 4.12$ 3.91$ 3.91$ 3.91$ 3.94$ 3.79$ 4.08$ 3.94$ 3.95$ Carbon Legislation - Medium Case 2025-2026 4.19$ 4.20$ 4.19$ 4.19$ 4.19$ 4.07$ 4.07$ 4.11$ 4.08$ 4.19$ Carbon Legislation - Medium Case 2026-2027 4.18$ 4.19$ 4.18$ 4.18$ 4.18$ 4.09$ 4.04$ 4.10$ 4.08$ 4.18$ Carbon Legislation - Medium Case 2027-2028 4.41$ 4.41$ 4.41$ 4.41$ 4.41$ 4.33$ 4.30$ 4.34$ 4.32$ 4.41$ Carbon Legislation - Medium Case 2028-2029 4.60$ 4.60$ 4.60$ 4.60$ 4.60$ 4.51$ 4.50$ 4.53$ 4.51$ 4.60$ Carbon Legislation - Medium Case 2029-2030 4.72$ 4.74$ 4.72$ 4.72$ 4.72$ 4.64$ 4.61$ 4.68$ 4.64$ 4.73$ Carbon Legislation - Medium Case 2030-2031 5.02$ 5.05$ 5.02$ 5.02$ 5.02$ 4.93$ 4.91$ 4.98$ 4.94$ 5.02$ Carbon Legislation - Medium Case 2031-2032 5.09$ 5.14$ 5.09$ 5.09$ 5.09$ 5.02$ 5.00$ 5.08$ 5.03$ 5.10$ Carbon Legislation - Medium Case 2032-2033 5.23$ 5.30$ 5.23$ 5.23$ 5.23$ 5.16$ 5.13$ 5.24$ 5.18$ 5.24$ Carbon Legislation - Medium Case 2033-2034 5.33$ 5.39$ 5.33$ 5.33$ 5.33$ 5.25$ 5.22$ 5.32$ 5.26$ 5.34$ Carbon Legislation - Medium Case 2034-2035 5.32$ 5.38$ 5.32$ 5.32$ 5.32$ 5.22$ 5.19$ 5.30$ 5.24$ 5.33$ 1/ Avoided costs are before Environmental Externalities adder. Annual Avoided Costs 1/ 2014$ Winter Avoided Costs 1/ 2014$ Avista Corp 2016 Natural Gas IRP Appendices 180 Appendix - Chapter 5 APPENDIX 5.4: COLD DAY 20 YR WEATHER STANDARD AVOIDED COST Scenario Gas Year Klam Falls La Grande Medford GTN Medford NWP Roseburg Wa/Id Both Wa/Id GTN Wa/Id NWP WA/ID Annual OR Annual Cold Day 20yr Weather Std 2015-2016 1.88$ 2.17$ 1.88$ 1.88$ 1.88$ 1.88$ 1.84$ 2.16$ 1.96$ 1.94$ Cold Day 20yr Weather Std 2016-2017 2.27$ 2.96$ 2.27$ 2.27$ 2.27$ 2.31$ 2.20$ 2.95$ 2.49$ 2.41$ Cold Day 20yr Weather Std 2017-2018 2.80$ 3.45$ 2.80$ 2.80$ 2.80$ 2.79$ 2.72$ 3.44$ 2.99$ 2.93$ Cold Day 20yr Weather Std 2018-2019 2.80$ 3.54$ 2.80$ 2.80$ 2.80$ 2.83$ 2.74$ 3.52$ 3.03$ 2.95$ Cold Day 20yr Weather Std 2019-2020 2.88$ 3.62$ 2.88$ 2.88$ 2.88$ 2.93$ 2.83$ 3.60$ 3.12$ 3.03$ Cold Day 20yr Weather Std 2020-2021 3.04$ 3.77$ 3.04$ 3.04$ 3.04$ 3.08$ 2.97$ 3.75$ 3.27$ 3.18$ Cold Day 20yr Weather Std 2021-2022 3.13$ 3.89$ 3.13$ 3.13$ 3.13$ 3.16$ 3.05$ 3.87$ 3.36$ 3.29$ Cold Day 20yr Weather Std 2022-2023 3.15$ 3.91$ 3.15$ 3.15$ 3.15$ 3.13$ 3.01$ 3.87$ 3.34$ 3.30$ Cold Day 20yr Weather Std 2023-2024 3.36$ 3.97$ 3.36$ 3.36$ 3.36$ 3.38$ 3.27$ 3.95$ 3.53$ 3.48$ Cold Day 20yr Weather Std 2024-2025 3.61$ 4.14$ 3.61$ 3.61$ 3.61$ 3.61$ 3.53$ 4.12$ 3.75$ 3.72$ Cold Day 20yr Weather Std 2025-2026 3.59$ 4.09$ 3.59$ 3.59$ 3.59$ 3.58$ 3.53$ 4.06$ 3.72$ 3.69$ Cold Day 20yr Weather Std 2026-2027 3.66$ 4.16$ 3.66$ 3.66$ 3.66$ 3.66$ 3.59$ 4.11$ 3.79$ 3.76$ Cold Day 20yr Weather Std 2027-2028 3.97$ 4.38$ 3.97$ 3.97$ 3.97$ 3.95$ 3.91$ 4.34$ 4.06$ 4.05$ Cold Day 20yr Weather Std 2028-2029 4.17$ 4.54$ 4.17$ 4.17$ 4.17$ 4.13$ 4.11$ 4.50$ 4.25$ 4.24$ Cold Day 20yr Weather Std 2029-2030 4.33$ 4.71$ 4.33$ 4.33$ 4.33$ 4.30$ 4.26$ 4.69$ 4.41$ 4.41$ Cold Day 20yr Weather Std 2030-2031 4.54$ 4.87$ 4.54$ 4.54$ 4.54$ 4.50$ 4.46$ 4.84$ 4.60$ 4.60$ Cold Day 20yr Weather Std 2031-2032 4.68$ 4.97$ 4.68$ 4.68$ 4.68$ 4.64$ 4.61$ 4.94$ 4.73$ 4.74$ Cold Day 20yr Weather Std 2032-2033 4.73$ 5.03$ 4.73$ 4.73$ 4.73$ 4.69$ 4.65$ 5.01$ 4.78$ 4.79$ Cold Day 20yr Weather Std 2033-2034 4.79$ 5.15$ 4.79$ 4.79$ 4.79$ 4.75$ 4.70$ 5.12$ 4.86$ 4.86$ Cold Day 20yr Weather Std 2034-2035 4.83$ 5.05$ 4.83$ 4.83$ 4.83$ 4.79$ 4.74$ 5.01$ 4.85$ 4.87$ Scenario Gas Year Klam Falls La Grande Medford GTN Medford NWP Roseburg Wa/Id Both Wa/Id GTN Wa/Id NWP WA/ID Annual OR Annual Cold Day 20yr Weather Std 2015-2016 1.86$ 2.09$ 1.86$ 1.86$ 1.86$ 2.00$ 1.79$ 2.09$ 1.96$ 1.91$ Cold Day 20yr Weather Std 2016-2017 2.29$ 2.97$ 2.29$ 2.29$ 2.29$ 2.42$ 2.14$ 2.94$ 2.50$ 2.43$ Cold Day 20yr Weather Std 2017-2018 2.69$ 3.41$ 2.69$ 2.69$ 2.69$ 2.77$ 2.48$ 3.40$ 2.88$ 2.84$ Cold Day 20yr Weather Std 2018-2019 3.12$ 3.55$ 3.12$ 3.12$ 3.12$ 3.26$ 3.01$ 3.51$ 3.26$ 3.21$ Cold Day 20yr Weather Std 2019-2020 3.19$ 3.63$ 3.19$ 3.19$ 3.19$ 3.36$ 3.09$ 3.60$ 3.35$ 3.28$ Cold Day 20yr Weather Std 2020-2021 3.30$ 3.77$ 3.30$ 3.30$ 3.30$ 3.49$ 3.19$ 3.75$ 3.48$ 3.40$ Cold Day 20yr Weather Std 2021-2022 3.52$ 3.90$ 3.52$ 3.52$ 3.52$ 3.63$ 3.33$ 3.85$ 3.61$ 3.59$ Cold Day 20yr Weather Std 2022-2023 3.55$ 3.92$ 3.55$ 3.55$ 3.55$ 3.54$ 3.22$ 3.86$ 3.54$ 3.63$ Cold Day 20yr Weather Std 2023-2024 3.74$ 4.01$ 3.74$ 3.74$ 3.74$ 3.81$ 3.51$ 3.97$ 3.76$ 3.80$ Cold Day 20yr Weather Std 2024-2025 3.97$ 4.17$ 3.97$ 3.97$ 3.97$ 4.01$ 3.79$ 4.12$ 3.97$ 4.01$ Cold Day 20yr Weather Std 2025-2026 4.16$ 4.23$ 4.16$ 4.16$ 4.16$ 4.10$ 4.07$ 4.14$ 4.10$ 4.18$ Cold Day 20yr Weather Std 2026-2027 4.15$ 4.29$ 4.15$ 4.15$ 4.15$ 4.11$ 4.04$ 4.13$ 4.09$ 4.18$ Cold Day 20yr Weather Std 2027-2028 4.39$ 4.48$ 4.39$ 4.39$ 4.39$ 4.36$ 4.30$ 4.38$ 4.34$ 4.41$ Cold Day 20yr Weather Std 2028-2029 4.59$ 4.66$ 4.59$ 4.59$ 4.59$ 4.54$ 4.50$ 4.58$ 4.54$ 4.61$ Cold Day 20yr Weather Std 2029-2030 4.71$ 4.81$ 4.71$ 4.71$ 4.71$ 4.68$ 4.61$ 4.73$ 4.68$ 4.73$ Cold Day 20yr Weather Std 2030-2031 5.02$ 5.09$ 5.02$ 5.02$ 5.02$ 4.94$ 4.91$ 4.99$ 4.95$ 5.03$ Cold Day 20yr Weather Std 2031-2032 5.09$ 5.20$ 5.09$ 5.09$ 5.09$ 5.07$ 5.00$ 5.13$ 5.06$ 5.11$ Cold Day 20yr Weather Std 2032-2033 5.23$ 5.33$ 5.23$ 5.23$ 5.23$ 5.18$ 5.13$ 5.24$ 5.19$ 5.25$ Cold Day 20yr Weather Std 2033-2034 5.32$ 5.48$ 5.32$ 5.32$ 5.32$ 5.27$ 5.22$ 5.33$ 5.27$ 5.35$ Cold Day 20yr Weather Std 2034-2035 5.32$ 5.46$ 5.32$ 5.32$ 5.32$ 5.25$ 5.19$ 5.32$ 5.25$ 5.35$ 1/ Avoided costs are before Environmental Externalities adder. Annual Avoided Costs 1/ 2014$ Winter Avoided Costs 1/ 2014$ Avista Corp 2016 Natural Gas IRP Appendices 181 Appendix - Chapter 5 APPENDIX 5.4: WASHINGTON AND IDAHO AVOIDED COSTS - LOW GROWTH/HIGH PRICE CASE APPENDIX 5.4: NATURAL GAS OREGON AVOIDED COSTS - LOW GROWTH/HIGH PRICE CASE Avista Corp 2016 Natural Gas IRP Appendices 182 Appendix - Chapter 5 APPENDIX 5.4: LOW GROWTH – HIGH PRICE MONTHLY DETAIL Scenario Gas Year Month Klam Falls La Grande Medford GTN Medford NWP Roseburg Wa/Id Both Wa/Id GTN Wa/Id NWP WA/ID Annual OR Annual Low Growth_High Prices 2015-2016 Nov 1.96$ 2.16$ 1.96$ 1.96$ 1.96$ 1.93$ 1.93$ 2.16$ 2.01$ 2.00$ Low Growth_High Prices 2015-2016 Dec 1.80$ 2.11$ 1.80$ 1.80$ 1.80$ 2.10$ 1.65$ 2.11$ 1.95$ 1.86$ Low Growth_High Prices 2015-2016 Jan 7.38$ 7.41$ 7.38$ 7.38$ 7.38$ 7.28$ 7.28$ 7.28$ 7.28$ 7.38$ Low Growth_High Prices 2015-2016 Feb 7.60$ 7.72$ 7.60$ 7.60$ 7.60$ 7.35$ 7.50$ 7.35$ 7.40$ 7.63$ Low Growth_High Prices 2015-2016 Mar 7.62$ 7.71$ 7.62$ 7.62$ 7.62$ 7.46$ 7.52$ 7.59$ 7.52$ 7.64$ Low Growth_High Prices 2015-2016 Apr 4.33$ 4.73$ 4.33$ 4.33$ 4.33$ 4.27$ 4.27$ 4.73$ 4.42$ 4.41$ Low Growth_High Prices 2015-2016 May 4.29$ 4.70$ 4.29$ 4.29$ 4.29$ 4.23$ 4.23$ 4.70$ 4.38$ 4.37$ Low Growth_High Prices 2015-2016 Jun 4.59$ 4.70$ 4.59$ 4.59$ 4.59$ 4.53$ 4.53$ 4.70$ 4.58$ 4.61$ Low Growth_High Prices 2015-2016 Jul 4.25$ 4.70$ 4.25$ 4.25$ 4.25$ 4.19$ 4.19$ 4.70$ 4.36$ 4.34$ Low Growth_High Prices 2015-2016 Aug 4.41$ 4.70$ 4.41$ 4.41$ 4.41$ 4.35$ 4.35$ 4.70$ 4.46$ 4.47$ Low Growth_High Prices 2015-2016 Sep 3.63$ 4.63$ 3.63$ 3.63$ 3.63$ 3.57$ 3.57$ 4.70$ 3.95$ 3.83$ Low Growth_High Prices 2015-2016 Oct 4.41$ 5.13$ 4.41$ 4.41$ 4.41$ 4.35$ 4.35$ 5.13$ 4.61$ 4.55$ Low Growth_High Prices 2016-2017 Nov 3.88$ 4.81$ 3.88$ 3.88$ 3.88$ 3.83$ 3.83$ 4.81$ 4.15$ 4.07$ Low Growth_High Prices 2016-2017 Dec 5.66$ 6.58$ 5.66$ 5.66$ 5.66$ 5.52$ 5.40$ 6.58$ 5.83$ 5.84$ Low Growth_High Prices 2016-2017 Jan 7.11$ 7.11$ 7.11$ 7.11$ 7.11$ 7.02$ 7.02$ 7.02$ 7.02$ 7.11$ Low Growth_High Prices 2016-2017 Feb 7.44$ 7.55$ 7.29$ 7.29$ 7.29$ 7.07$ 7.34$ 7.07$ 7.16$ 7.37$ Low Growth_High Prices 2016-2017 Mar 7.19$ 7.35$ 7.19$ 7.19$ 7.19$ 7.08$ 7.10$ 7.27$ 7.15$ 7.22$ Low Growth_High Prices 2016-2017 Apr 4.36$ 5.08$ 4.36$ 4.36$ 4.36$ 4.30$ 4.30$ 5.08$ 4.56$ 4.51$ Low Growth_High Prices 2016-2017 May 4.33$ 5.08$ 4.33$ 4.33$ 4.33$ 4.27$ 4.27$ 5.08$ 4.54$ 4.48$ Low Growth_High Prices 2016-2017 Jun 4.60$ 5.09$ 4.60$ 4.60$ 4.60$ 4.53$ 4.53$ 5.09$ 4.72$ 4.69$ Low Growth_High Prices 2016-2017 Jul 4.24$ 5.09$ 4.24$ 4.24$ 4.24$ 4.18$ 4.18$ 5.09$ 4.48$ 4.41$ Low Growth_High Prices 2016-2017 Aug 4.39$ 5.09$ 4.39$ 4.39$ 4.39$ 4.33$ 4.33$ 5.09$ 4.58$ 4.53$ Low Growth_High Prices 2016-2017 Sep 3.57$ 4.73$ 3.57$ 3.57$ 3.57$ 3.52$ 3.52$ 5.09$ 4.04$ 3.80$ Low Growth_High Prices 2016-2017 Oct 4.38$ 5.21$ 4.38$ 4.38$ 4.38$ 4.32$ 4.32$ 5.21$ 4.61$ 4.54$ Low Growth_High Prices 2017-2018 Nov 3.97$ 4.93$ 3.97$ 3.97$ 3.97$ 3.91$ 3.91$ 4.93$ 4.25$ 4.16$ Low Growth_High Prices 2017-2018 Dec 5.71$ 6.53$ 5.71$ 5.71$ 5.71$ 5.57$ 5.47$ 6.53$ 5.85$ 5.87$ Low Growth_High Prices 2017-2018 Jan 7.78$ 7.78$ 7.78$ 7.78$ 7.78$ 7.68$ 7.68$ 7.68$ 7.68$ 7.78$ Low Growth_High Prices 2017-2018 Feb 8.09$ 8.19$ 8.06$ 8.06$ 8.06$ 7.74$ 7.99$ 7.74$ 7.82$ 8.09$ Low Growth_High Prices 2017-2018 Mar 8.12$ 8.15$ 8.11$ 8.11$ 8.11$ 7.90$ 8.01$ 7.96$ 7.96$ 8.12$ Low Growth_High Prices 2017-2018 Apr 4.87$ 5.66$ 4.87$ 4.87$ 4.87$ 4.80$ 4.80$ 5.66$ 5.09$ 5.02$ Low Growth_High Prices 2017-2018 May 4.80$ 5.52$ 4.80$ 4.80$ 4.80$ 4.74$ 4.74$ 5.52$ 5.00$ 4.95$ Low Growth_High Prices 2017-2018 Jun 5.06$ 5.52$ 5.06$ 5.06$ 5.06$ 4.99$ 4.99$ 5.52$ 5.17$ 5.15$ Low Growth_High Prices 2017-2018 Jul 4.73$ 5.52$ 4.73$ 4.73$ 4.73$ 4.66$ 4.66$ 5.52$ 4.95$ 4.89$ Low Growth_High Prices 2017-2018 Aug 4.82$ 5.52$ 4.82$ 4.82$ 4.82$ 4.75$ 4.75$ 5.52$ 5.01$ 4.96$ Low Growth_High Prices 2017-2018 Sep 4.09$ 5.29$ 4.09$ 4.09$ 4.09$ 4.03$ 4.03$ 5.52$ 4.53$ 4.33$ Low Growth_High Prices 2017-2018 Oct 4.89$ 5.85$ 4.89$ 4.89$ 4.89$ 4.82$ 4.82$ 5.85$ 5.17$ 5.08$ Low Growth_High Prices 2018-2019 Nov 4.55$ 5.29$ 4.55$ 4.55$ 4.55$ 4.48$ 4.48$ 5.29$ 4.75$ 4.69$ Low Growth_High Prices 2018-2019 Dec 6.26$ 6.92$ 6.26$ 6.26$ 6.26$ 6.13$ 6.03$ 6.91$ 6.36$ 6.39$ Low Growth_High Prices 2018-2019 Jan 7.69$ 7.69$ 7.69$ 7.69$ 7.69$ 7.59$ 7.59$ 7.59$ 7.59$ 7.69$ Low Growth_High Prices 2018-2019 Feb 8.01$ 8.12$ 7.84$ 7.84$ 7.84$ 7.65$ 7.91$ 7.65$ 7.74$ 7.93$ Low Growth_High Prices 2018-2019 Mar 7.78$ 7.93$ 7.78$ 7.78$ 7.78$ 7.66$ 7.68$ 7.85$ 7.73$ 7.81$ Low Growth_High Prices 2018-2019 Apr 4.67$ 5.67$ 4.67$ 4.67$ 4.67$ 4.60$ 4.60$ 5.67$ 4.96$ 4.87$ Low Growth_High Prices 2018-2019 May 4.68$ 5.64$ 4.68$ 4.68$ 4.68$ 4.62$ 4.62$ 5.64$ 4.96$ 4.87$ Low Growth_High Prices 2018-2019 Jun 5.03$ 5.64$ 5.03$ 5.03$ 5.03$ 4.97$ 4.97$ 5.64$ 5.19$ 5.15$ Low Growth_High Prices 2018-2019 Jul 4.71$ 5.64$ 4.71$ 4.71$ 4.71$ 4.65$ 4.65$ 5.64$ 4.98$ 4.90$ Low Growth_High Prices 2018-2019 Aug 4.80$ 5.64$ 4.80$ 4.80$ 4.80$ 4.74$ 4.74$ 5.64$ 5.04$ 4.97$ Low Growth_High Prices 2018-2019 Sep 4.09$ 5.27$ 4.09$ 4.09$ 4.09$ 4.04$ 4.04$ 5.64$ 4.57$ 4.33$ Low Growth_High Prices 2018-2019 Oct 4.92$ 5.83$ 4.92$ 4.92$ 4.92$ 4.85$ 4.85$ 5.83$ 5.18$ 5.10$ Low Growth_High Prices 2019-2020 Nov 4.58$ 5.26$ 4.58$ 4.58$ 4.58$ 4.52$ 4.52$ 5.26$ 4.76$ 4.72$ Low Growth_High Prices 2019-2020 Dec 6.27$ 6.80$ 6.27$ 6.27$ 6.27$ 6.17$ 6.07$ 6.79$ 6.35$ 6.38$ Low Growth_High Prices 2019-2020 Jan 7.72$ 7.72$ 7.72$ 7.72$ 7.72$ 7.62$ 7.62$ 7.62$ 7.62$ 7.72$ Low Growth_High Prices 2019-2020 Feb 8.04$ 8.15$ 8.01$ 8.01$ 8.01$ 7.67$ 7.93$ 7.67$ 7.76$ 8.05$ Low Growth_High Prices 2019-2020 Mar 8.09$ 8.10$ 8.08$ 8.08$ 8.08$ 7.84$ 7.98$ 7.88$ 7.90$ 8.09$ Low Growth_High Prices 2019-2020 Apr 4.70$ 5.66$ 4.70$ 4.70$ 4.70$ 4.63$ 4.63$ 5.66$ 4.97$ 4.89$ Low Growth_High Prices 2019-2020 May 4.71$ 5.60$ 4.71$ 4.71$ 4.71$ 4.65$ 4.65$ 5.60$ 4.96$ 4.89$ Low Growth_High Prices 2019-2020 Jun 5.04$ 5.60$ 5.04$ 5.04$ 5.04$ 4.97$ 4.97$ 5.60$ 5.18$ 5.15$ Low Growth_High Prices 2019-2020 Jul 4.70$ 5.60$ 4.70$ 4.70$ 4.70$ 4.64$ 4.64$ 5.60$ 4.96$ 4.88$ Low Growth_High Prices 2019-2020 Aug 4.80$ 5.60$ 4.80$ 4.80$ 4.80$ 4.74$ 4.74$ 5.60$ 5.03$ 4.96$ Low Growth_High Prices 2019-2020 Sep 4.09$ 5.28$ 4.09$ 4.09$ 4.09$ 4.04$ 4.04$ 5.60$ 4.56$ 4.33$ Low Growth_High Prices 2019-2020 Oct 4.90$ 5.90$ 4.90$ 4.90$ 4.90$ 4.83$ 4.83$ 5.90$ 5.19$ 5.10$ Low Growth_High Prices 2020-2021 Nov 4.63$ 5.25$ 4.63$ 4.63$ 4.63$ 4.57$ 4.57$ 5.25$ 4.80$ 4.76$ Low Growth_High Prices 2020-2021 Dec 6.33$ 6.77$ 6.33$ 6.33$ 6.33$ 6.24$ 6.14$ 6.77$ 6.38$ 6.42$ Low Growth_High Prices 2020-2021 Jan 7.76$ 7.76$ 7.76$ 7.76$ 7.76$ 7.66$ 7.66$ 7.66$ 7.66$ 7.76$ Low Growth_High Prices 2020-2021 Feb 8.14$ 8.23$ 7.98$ 7.98$ 7.98$ 7.73$ 8.04$ 7.73$ 7.83$ 8.06$ Low Growth_High Prices 2020-2021 Mar 7.45$ 7.58$ 7.45$ 7.45$ 7.45$ 7.36$ 7.36$ 7.52$ 7.41$ 7.48$ Low Growth_High Prices 2020-2021 Apr 4.78$ 5.72$ 4.78$ 4.78$ 4.78$ 4.71$ 4.71$ 5.72$ 5.05$ 4.97$ Low Growth_High Prices 2020-2021 May 4.80$ 5.72$ 4.80$ 4.80$ 4.80$ 4.74$ 4.74$ 5.72$ 5.06$ 4.99$ Low Growth_High Prices 2020-2021 Jun 5.11$ 5.72$ 5.11$ 5.11$ 5.11$ 5.04$ 5.04$ 5.72$ 5.27$ 5.23$ Low Growth_High Prices 2020-2021 Jul 4.68$ 5.72$ 4.68$ 4.68$ 4.68$ 4.61$ 4.61$ 5.72$ 4.98$ 4.89$ Low Growth_High Prices 2020-2021 Aug 4.77$ 5.72$ 4.77$ 4.77$ 4.77$ 4.71$ 4.71$ 5.72$ 5.04$ 4.96$ Low Growth_High Prices 2020-2021 Sep 4.23$ 5.20$ 4.23$ 4.23$ 4.23$ 4.17$ 4.17$ 5.72$ 4.69$ 4.42$ Low Growth_High Prices 2020-2021 Oct 5.04$ 5.80$ 5.04$ 5.04$ 5.04$ 4.97$ 4.97$ 5.80$ 5.25$ 5.19$ Low Growth_High Prices 2021-2022 Nov 4.58$ 5.25$ 4.58$ 4.58$ 4.58$ 4.51$ 4.51$ 5.25$ 4.76$ 4.71$ Low Growth_High Prices 2021-2022 Dec 6.27$ 6.74$ 6.27$ 6.27$ 6.27$ 6.15$ 6.06$ 6.72$ 6.31$ 6.37$ Low Growth_High Prices 2021-2022 Jan 7.70$ 7.70$ 7.70$ 7.70$ 7.70$ 7.59$ 7.59$ 7.59$ 7.59$ 7.70$ Low Growth_High Prices 2021-2022 Feb 8.07$ 8.20$ 8.04$ 8.04$ 8.04$ 7.66$ 7.96$ 7.66$ 7.76$ 8.08$ Low Growth_High Prices 2021-2022 Mar 8.11$ 8.13$ 8.10$ 8.10$ 8.10$ 7.82$ 8.00$ 7.86$ 7.89$ 8.11$ Low Growth_High Prices 2021-2022 Apr 4.75$ 5.81$ 4.75$ 4.75$ 4.75$ 4.69$ 4.69$ 5.81$ 5.06$ 4.97$ Low Growth_High Prices 2021-2022 May 4.79$ 5.79$ 4.79$ 4.79$ 4.79$ 4.72$ 4.72$ 5.79$ 5.08$ 4.99$ Low Growth_High Prices 2021-2022 Jun 5.10$ 5.79$ 5.10$ 5.10$ 5.10$ 5.03$ 5.03$ 5.79$ 5.29$ 5.24$ Low Growth_High Prices 2021-2022 Jul 4.74$ 5.79$ 4.74$ 4.74$ 4.74$ 4.68$ 4.68$ 5.79$ 5.05$ 4.95$ Low Growth_High Prices 2021-2022 Aug 4.85$ 5.79$ 4.85$ 4.85$ 4.85$ 4.79$ 4.79$ 5.79$ 5.12$ 5.04$ Low Growth_High Prices 2021-2022 Sep 4.14$ 5.33$ 4.14$ 4.14$ 4.14$ 4.08$ 4.08$ 5.79$ 4.65$ 4.38$ Low Growth_High Prices 2021-2022 Oct 4.96$ 5.91$ 4.96$ 4.96$ 4.96$ 4.89$ 4.89$ 5.91$ 5.23$ 5.15$ 1/ Avoided costs are before Environmental Externalities adder. Monthly Avoided Costs 1/ 2014$ Avista Corp 2016 Natural Gas IRP Appendices 183 Appendix - Chapter 5 APPENDIX 5.4: LOW GROWTH – HIGH PRICE MONTHLY DETAIL Scenario Gas Year Month Klam Falls La Grande Medford GTN Medford NWP Roseburg Wa/Id Both Wa/Id GTN Wa/Id NWP WA/ID Annual OR Annual Low Growth_High Prices 2022-2023 Nov 4.50$ 5.40$ 4.50$ 4.50$ 4.50$ 4.43$ 4.43$ 5.40$ 4.76$ 4.68$ Low Growth_High Prices 2022-2023 Dec 6.18$ 6.87$ 6.18$ 6.18$ 6.18$ 6.02$ 5.93$ 6.83$ 6.26$ 6.32$ Low Growth_High Prices 2022-2023 Jan 7.50$ 7.50$ 7.50$ 7.50$ 7.50$ 6.94$ 7.41$ 6.94$ 7.10$ 7.50$ Low Growth_High Prices 2022-2023 Feb 7.87$ 8.07$ 7.77$ 7.77$ 7.77$ 7.21$ 7.77$ 7.21$ 7.39$ 7.85$ Low Growth_High Prices 2022-2023 Mar 6.48$ 6.67$ 6.48$ 6.48$ 6.48$ 6.40$ 6.40$ 6.67$ 6.49$ 6.52$ Low Growth_High Prices 2022-2023 Apr 4.71$ 5.89$ 4.71$ 4.71$ 4.71$ 4.65$ 4.65$ 5.89$ 5.06$ 4.95$ Low Growth_High Prices 2022-2023 May 4.77$ 5.81$ 4.77$ 4.77$ 4.77$ 4.71$ 4.71$ 5.81$ 5.08$ 4.98$ Low Growth_High Prices 2022-2023 Jun 5.10$ 5.82$ 5.10$ 5.10$ 5.10$ 5.03$ 5.03$ 5.82$ 5.29$ 5.24$ Low Growth_High Prices 2022-2023 Jul 4.75$ 5.82$ 4.75$ 4.75$ 4.75$ 4.68$ 4.68$ 5.82$ 5.06$ 4.96$ Low Growth_High Prices 2022-2023 Aug 4.84$ 5.82$ 4.84$ 4.84$ 4.84$ 4.77$ 4.77$ 5.82$ 5.12$ 5.04$ Low Growth_High Prices 2022-2023 Sep 4.26$ 5.25$ 4.26$ 4.26$ 4.26$ 4.21$ 4.21$ 5.82$ 4.74$ 4.46$ Low Growth_High Prices 2022-2023 Oct 5.09$ 5.82$ 5.09$ 5.09$ 5.09$ 5.02$ 5.02$ 5.82$ 5.29$ 5.23$ Low Growth_High Prices 2023-2024 Nov 4.73$ 5.26$ 4.73$ 4.73$ 4.73$ 4.66$ 4.66$ 5.26$ 4.86$ 4.84$ Low Growth_High Prices 2023-2024 Dec 6.36$ 6.88$ 6.36$ 6.36$ 6.36$ 6.25$ 6.16$ 6.88$ 6.43$ 6.47$ Low Growth_High Prices 2023-2024 Jan 7.80$ 7.79$ 7.80$ 7.80$ 7.80$ 7.69$ 7.69$ 7.69$ 7.69$ 7.80$ Low Growth_High Prices 2023-2024 Feb 8.14$ 8.26$ 8.14$ 8.14$ 8.14$ 7.75$ 8.04$ 7.75$ 7.85$ 8.16$ Low Growth_High Prices 2023-2024 Mar 8.23$ 8.24$ 8.22$ 8.22$ 8.22$ 7.93$ 8.12$ 7.97$ 8.01$ 8.23$ Low Growth_High Prices 2023-2024 Apr 4.84$ 5.73$ 4.84$ 4.84$ 4.84$ 4.77$ 4.77$ 5.73$ 5.09$ 5.02$ Low Growth_High Prices 2023-2024 May 4.85$ 5.73$ 4.85$ 4.85$ 4.85$ 4.78$ 4.78$ 5.73$ 5.10$ 5.03$ Low Growth_High Prices 2023-2024 Jun 5.17$ 5.73$ 5.17$ 5.17$ 5.17$ 5.10$ 5.10$ 5.73$ 5.31$ 5.28$ Low Growth_High Prices 2023-2024 Jul 4.90$ 5.74$ 4.90$ 4.90$ 4.90$ 4.84$ 4.84$ 5.74$ 5.14$ 5.07$ Low Growth_High Prices 2023-2024 Aug 5.00$ 5.74$ 5.00$ 5.00$ 5.00$ 4.94$ 4.94$ 5.74$ 5.20$ 5.15$ Low Growth_High Prices 2023-2024 Sep 4.37$ 5.21$ 4.37$ 4.37$ 4.37$ 4.31$ 4.31$ 5.74$ 4.78$ 4.53$ Low Growth_High Prices 2023-2024 Oct 5.16$ 5.79$ 5.16$ 5.16$ 5.16$ 5.09$ 5.09$ 5.79$ 5.33$ 5.29$ Low Growth_High Prices 2024-2025 Nov 4.82$ 5.17$ 4.82$ 4.82$ 4.82$ 4.75$ 4.75$ 5.17$ 4.89$ 4.89$ Low Growth_High Prices 2024-2025 Dec 6.38$ 6.63$ 6.38$ 6.38$ 6.38$ 6.30$ 6.21$ 6.62$ 6.37$ 6.43$ Low Growth_High Prices 2024-2025 Jan 7.86$ 7.86$ 7.86$ 7.86$ 7.86$ 7.76$ 7.76$ 7.76$ 7.76$ 7.86$ Low Growth_High Prices 2024-2025 Feb 8.18$ 8.28$ 8.16$ 8.16$ 8.16$ 7.81$ 8.07$ 7.81$ 7.90$ 8.19$ Low Growth_High Prices 2024-2025 Mar 8.24$ 8.25$ 8.24$ 8.24$ 8.24$ 7.99$ 8.13$ 8.02$ 8.05$ 8.24$ Low Growth_High Prices 2024-2025 Apr 4.81$ 5.77$ 4.81$ 4.81$ 4.81$ 4.75$ 4.75$ 5.77$ 5.09$ 5.01$ Low Growth_High Prices 2024-2025 May 4.91$ 5.68$ 4.91$ 4.91$ 4.91$ 4.84$ 4.84$ 5.68$ 5.12$ 5.07$ Low Growth_High Prices 2024-2025 Jun 5.22$ 5.68$ 5.22$ 5.22$ 5.22$ 5.15$ 5.15$ 5.68$ 5.33$ 5.31$ Low Growth_High Prices 2024-2025 Jul 4.92$ 5.68$ 4.92$ 4.92$ 4.92$ 4.85$ 4.85$ 5.68$ 5.13$ 5.07$ Low Growth_High Prices 2024-2025 Aug 5.01$ 5.68$ 5.01$ 5.01$ 5.01$ 4.95$ 4.95$ 5.68$ 5.19$ 5.15$ Low Growth_High Prices 2024-2025 Sep 4.39$ 5.13$ 4.39$ 4.39$ 4.39$ 4.33$ 4.33$ 5.68$ 4.78$ 4.54$ Low Growth_High Prices 2024-2025 Oct 5.19$ 5.70$ 5.19$ 5.19$ 5.19$ 5.12$ 5.12$ 5.70$ 5.31$ 5.29$ Low Growth_High Prices 2025-2026 Nov 4.84$ 5.05$ 4.84$ 4.84$ 4.84$ 4.77$ 4.77$ 5.05$ 4.86$ 4.88$ Low Growth_High Prices 2025-2026 Dec 6.37$ 6.68$ 6.37$ 6.37$ 6.37$ 6.27$ 6.18$ 6.67$ 6.37$ 6.43$ Low Growth_High Prices 2025-2026 Jan 7.79$ 7.79$ 7.79$ 7.79$ 7.79$ 7.69$ 7.69$ 7.69$ 7.69$ 7.79$ Low Growth_High Prices 2025-2026 Feb 8.11$ 8.23$ 8.08$ 8.08$ 8.08$ 7.75$ 8.01$ 7.75$ 7.83$ 8.12$ Low Growth_High Prices 2025-2026 Mar 8.12$ 8.15$ 8.11$ 8.11$ 8.11$ 7.89$ 8.01$ 7.95$ 7.95$ 8.12$ Low Growth_High Prices 2025-2026 Apr 4.84$ 5.74$ 4.84$ 4.84$ 4.84$ 4.78$ 4.78$ 5.74$ 5.10$ 5.02$ Low Growth_High Prices 2025-2026 May 4.92$ 5.65$ 4.92$ 4.92$ 4.92$ 4.85$ 4.85$ 5.65$ 5.12$ 5.07$ Low Growth_High Prices 2025-2026 Jun 5.22$ 5.65$ 5.22$ 5.22$ 5.22$ 5.15$ 5.15$ 5.65$ 5.32$ 5.31$ Low Growth_High Prices 2025-2026 Jul 4.94$ 5.65$ 4.94$ 4.94$ 4.94$ 4.87$ 4.87$ 5.65$ 5.13$ 5.08$ Low Growth_High Prices 2025-2026 Aug 5.06$ 5.66$ 5.06$ 5.06$ 5.06$ 4.99$ 4.99$ 5.66$ 5.21$ 5.18$ Low Growth_High Prices 2025-2026 Sep 4.38$ 5.14$ 4.38$ 4.38$ 4.38$ 4.32$ 4.32$ 5.66$ 4.77$ 4.53$ Low Growth_High Prices 2025-2026 Oct 5.19$ 5.66$ 5.19$ 5.19$ 5.19$ 5.12$ 5.12$ 5.66$ 5.30$ 5.29$ Low Growth_High Prices 2026-2027 Nov 4.89$ 5.04$ 4.89$ 4.89$ 4.89$ 4.83$ 4.83$ 5.04$ 4.90$ 4.92$ Low Growth_High Prices 2026-2027 Dec 6.31$ 6.80$ 6.31$ 6.31$ 6.31$ 6.19$ 6.09$ 6.79$ 6.36$ 6.41$ Low Growth_High Prices 2026-2027 Jan 7.72$ 7.72$ 7.72$ 7.72$ 7.72$ 7.62$ 7.62$ 7.62$ 7.62$ 7.72$ Low Growth_High Prices 2026-2027 Feb 8.04$ 8.18$ 7.94$ 7.94$ 7.94$ 7.68$ 7.93$ 7.68$ 7.76$ 8.00$ Low Growth_High Prices 2026-2027 Mar 7.51$ 7.69$ 7.51$ 7.51$ 7.51$ 7.41$ 7.41$ 7.63$ 7.49$ 7.55$ Low Growth_High Prices 2026-2027 Apr 4.89$ 5.74$ 4.89$ 4.89$ 4.89$ 4.82$ 4.82$ 5.74$ 5.13$ 5.06$ Low Growth_High Prices 2026-2027 May 4.93$ 5.65$ 4.93$ 4.93$ 4.93$ 4.87$ 4.87$ 5.65$ 5.13$ 5.08$ Low Growth_High Prices 2026-2027 Jun 5.28$ 5.65$ 5.28$ 5.28$ 5.28$ 5.21$ 5.21$ 5.65$ 5.36$ 5.36$ Low Growth_High Prices 2026-2027 Jul 5.00$ 5.65$ 5.00$ 5.00$ 5.00$ 4.93$ 4.93$ 5.65$ 5.17$ 5.13$ Low Growth_High Prices 2026-2027 Aug 5.11$ 5.65$ 5.11$ 5.11$ 5.11$ 5.04$ 5.04$ 5.65$ 5.24$ 5.22$ Low Growth_High Prices 2026-2027 Sep 4.56$ 4.99$ 4.56$ 4.56$ 4.56$ 4.49$ 4.49$ 5.65$ 4.88$ 4.64$ Low Growth_High Prices 2026-2027 Oct 5.37$ 5.78$ 5.37$ 5.37$ 5.37$ 5.30$ 5.30$ 5.78$ 5.46$ 5.45$ Low Growth_High Prices 2027-2028 Nov 5.02$ 5.19$ 5.02$ 5.02$ 5.02$ 4.96$ 4.96$ 5.19$ 5.03$ 5.06$ Low Growth_High Prices 2027-2028 Dec 6.48$ 6.96$ 6.48$ 6.48$ 6.48$ 6.40$ 6.30$ 6.96$ 6.56$ 6.58$ Low Growth_High Prices 2027-2028 Jan 8.00$ 8.00$ 8.00$ 8.00$ 8.00$ 7.90$ 7.90$ 7.90$ 7.90$ 8.00$ Low Growth_High Prices 2027-2028 Feb 8.32$ 8.36$ 8.23$ 8.23$ 8.23$ 7.95$ 8.21$ 7.95$ 8.04$ 8.27$ Low Growth_High Prices 2027-2028 Mar 8.07$ 8.20$ 8.07$ 8.07$ 8.07$ 7.96$ 7.97$ 8.13$ 8.02$ 8.10$ Low Growth_High Prices 2027-2028 Apr 5.10$ 5.78$ 5.10$ 5.10$ 5.10$ 5.03$ 5.03$ 5.78$ 5.28$ 5.23$ Low Growth_High Prices 2027-2028 May 5.13$ 5.70$ 5.13$ 5.13$ 5.13$ 5.06$ 5.06$ 5.70$ 5.27$ 5.24$ Low Growth_High Prices 2027-2028 Jun 5.46$ 5.70$ 5.46$ 5.46$ 5.46$ 5.39$ 5.39$ 5.70$ 5.49$ 5.51$ Low Growth_High Prices 2027-2028 Jul 5.17$ 5.70$ 5.17$ 5.17$ 5.17$ 5.10$ 5.10$ 5.70$ 5.30$ 5.27$ Low Growth_High Prices 2027-2028 Aug 5.25$ 5.70$ 5.25$ 5.25$ 5.25$ 5.18$ 5.18$ 5.70$ 5.35$ 5.34$ Low Growth_High Prices 2027-2028 Sep 4.65$ 4.98$ 4.65$ 4.65$ 4.65$ 4.59$ 4.59$ 5.70$ 4.96$ 4.72$ Low Growth_High Prices 2027-2028 Oct 5.48$ 5.79$ 5.48$ 5.48$ 5.48$ 5.41$ 5.41$ 5.79$ 5.53$ 5.54$ Low Growth_High Prices 2028-2029 Nov 5.08$ 5.30$ 5.08$ 5.08$ 5.08$ 5.01$ 5.01$ 5.30$ 5.11$ 5.12$ Low Growth_High Prices 2028-2029 Dec 6.59$ 6.95$ 6.59$ 6.59$ 6.59$ 6.52$ 6.43$ 6.95$ 6.63$ 6.66$ Low Growth_High Prices 2028-2029 Jan 8.11$ 8.11$ 8.11$ 8.11$ 8.11$ 8.00$ 8.00$ 8.00$ 8.00$ 8.11$ Low Growth_High Prices 2028-2029 Feb 8.42$ 8.46$ 8.32$ 8.32$ 8.32$ 8.06$ 8.31$ 8.06$ 8.14$ 8.37$ Low Growth_High Prices 2028-2029 Mar 7.98$ 8.09$ 7.98$ 7.98$ 7.98$ 7.87$ 7.87$ 8.03$ 7.93$ 8.00$ Low Growth_High Prices 2028-2029 Apr 5.16$ 5.85$ 5.16$ 5.16$ 5.16$ 5.09$ 5.09$ 5.85$ 5.34$ 5.30$ Low Growth_High Prices 2028-2029 May 5.24$ 5.73$ 5.24$ 5.24$ 5.24$ 5.16$ 5.16$ 5.73$ 5.35$ 5.33$ Low Growth_High Prices 2028-2029 Jun 5.56$ 5.73$ 5.56$ 5.56$ 5.56$ 5.48$ 5.48$ 5.73$ 5.56$ 5.59$ Low Growth_High Prices 2028-2029 Jul 5.22$ 5.73$ 5.22$ 5.22$ 5.22$ 5.15$ 5.15$ 5.73$ 5.34$ 5.32$ Low Growth_High Prices 2028-2029 Aug 5.32$ 5.73$ 5.32$ 5.32$ 5.32$ 5.25$ 5.25$ 5.73$ 5.41$ 5.40$ Low Growth_High Prices 2028-2029 Sep 4.72$ 5.03$ 4.72$ 4.72$ 4.72$ 4.65$ 4.65$ 5.73$ 5.01$ 4.78$ Low Growth_High Prices 2028-2029 Oct 5.54$ 5.84$ 5.54$ 5.54$ 5.54$ 5.46$ 5.46$ 5.84$ 5.59$ 5.60$ 1/ Avoided costs are before Environmental Externalities adder. Monthly Avoided Costs 1/ 2014$ Avista Corp 2016 Natural Gas IRP Appendices 184 Appendix - Chapter 5 APPENDIX 5.4: LOW GROWTH – HIGH PRICE MONTHLY DETAIL Scenario Gas Year Month Klam Falls La Grande Medford GTN Medford NWP Roseburg Wa/Id Both Wa/Id GTN Wa/Id NWP WA/ID Annual OR Annual Low Growth_High Prices 2029-2030 Nov 5.13$ 5.45$ 5.13$ 5.13$ 5.13$ 5.06$ 5.06$ 5.45$ 5.19$ 5.19$ Low Growth_High Prices 2029-2030 Dec 6.64$ 7.04$ 6.64$ 6.64$ 6.64$ 6.57$ 6.47$ 7.04$ 6.69$ 6.72$ Low Growth_High Prices 2029-2030 Jan 8.16$ 8.16$ 8.16$ 8.16$ 8.16$ 8.06$ 8.06$ 8.06$ 8.06$ 8.16$ Low Growth_High Prices 2029-2030 Feb 8.52$ 8.56$ 8.49$ 8.49$ 8.49$ 8.12$ 8.41$ 8.12$ 8.22$ 8.51$ Low Growth_High Prices 2029-2030 Mar 8.51$ 8.53$ 8.50$ 8.50$ 8.50$ 8.28$ 8.40$ 8.33$ 8.34$ 8.51$ Low Growth_High Prices 2029-2030 Apr 5.24$ 5.89$ 5.24$ 5.24$ 5.24$ 5.17$ 5.17$ 5.89$ 5.41$ 5.37$ Low Growth_High Prices 2029-2030 May 5.26$ 5.76$ 5.26$ 5.26$ 5.26$ 5.19$ 5.19$ 5.76$ 5.38$ 5.36$ Low Growth_High Prices 2029-2030 Jun 5.62$ 5.77$ 5.62$ 5.62$ 5.62$ 5.54$ 5.54$ 5.77$ 5.62$ 5.65$ Low Growth_High Prices 2029-2030 Jul 5.32$ 5.75$ 5.32$ 5.32$ 5.32$ 5.25$ 5.25$ 5.77$ 5.42$ 5.41$ Low Growth_High Prices 2029-2030 Aug 5.41$ 5.77$ 5.41$ 5.41$ 5.41$ 5.33$ 5.33$ 5.77$ 5.48$ 5.48$ Low Growth_High Prices 2029-2030 Sep 4.79$ 5.18$ 4.79$ 4.79$ 4.79$ 4.72$ 4.72$ 5.77$ 5.07$ 4.87$ Low Growth_High Prices 2029-2030 Oct 5.61$ 5.99$ 5.61$ 5.61$ 5.61$ 5.54$ 5.54$ 5.99$ 5.69$ 5.69$ Low Growth_High Prices 2030-2031 Nov 5.17$ 5.54$ 5.17$ 5.17$ 5.17$ 5.10$ 5.10$ 5.54$ 5.25$ 5.25$ Low Growth_High Prices 2030-2031 Dec 6.73$ 7.04$ 6.74$ 6.74$ 6.74$ 6.68$ 6.58$ 7.04$ 6.77$ 6.80$ Low Growth_High Prices 2030-2031 Jan 8.28$ 8.28$ 8.28$ 8.28$ 8.28$ 8.17$ 8.17$ 8.17$ 8.17$ 8.28$ Low Growth_High Prices 2030-2031 Feb 8.63$ 8.65$ 8.60$ 8.60$ 8.60$ 8.23$ 8.52$ 8.23$ 8.33$ 8.61$ Low Growth_High Prices 2030-2031 Mar 8.59$ 8.61$ 8.58$ 8.58$ 8.58$ 8.38$ 8.48$ 8.44$ 8.43$ 8.59$ Low Growth_High Prices 2030-2031 Apr 5.38$ 5.90$ 5.38$ 5.38$ 5.38$ 5.30$ 5.30$ 5.90$ 5.50$ 5.48$ Low Growth_High Prices 2030-2031 May 5.40$ 5.81$ 5.40$ 5.40$ 5.40$ 5.33$ 5.33$ 5.81$ 5.49$ 5.48$ Low Growth_High Prices 2030-2031 Jun 5.73$ 5.81$ 5.73$ 5.73$ 5.73$ 5.65$ 5.65$ 5.81$ 5.70$ 5.74$ Low Growth_High Prices 2030-2031 Jul 5.39$ 5.81$ 5.39$ 5.39$ 5.39$ 5.31$ 5.31$ 5.81$ 5.48$ 5.47$ Low Growth_High Prices 2030-2031 Aug 5.48$ 5.81$ 5.48$ 5.48$ 5.48$ 5.40$ 5.40$ 5.81$ 5.54$ 5.54$ Low Growth_High Prices 2030-2031 Sep 4.87$ 5.20$ 4.87$ 4.87$ 4.87$ 4.81$ 4.81$ 5.81$ 5.14$ 4.94$ Low Growth_High Prices 2030-2031 Oct 5.71$ 6.01$ 5.71$ 5.71$ 5.71$ 5.63$ 5.63$ 6.01$ 5.76$ 5.77$ Low Growth_High Prices 2031-2032 Nov 5.22$ 5.61$ 5.22$ 5.22$ 5.22$ 5.15$ 5.15$ 5.61$ 5.30$ 5.30$ Low Growth_High Prices 2031-2032 Dec 6.80$ 7.06$ 6.80$ 6.80$ 6.80$ 6.75$ 6.66$ 7.06$ 6.82$ 6.85$ Low Growth_High Prices 2031-2032 Jan 8.33$ 8.33$ 8.33$ 8.33$ 8.33$ 8.22$ 8.22$ 8.22$ 8.22$ 8.33$ Low Growth_High Prices 2031-2032 Feb 8.67$ 8.70$ 8.60$ 8.60$ 8.60$ 8.28$ 8.56$ 8.28$ 8.37$ 8.63$ Low Growth_High Prices 2031-2032 Mar 7.51$ 7.58$ 7.51$ 7.51$ 7.51$ 7.41$ 7.41$ 7.52$ 7.45$ 7.52$ Low Growth_High Prices 2031-2032 Apr 5.47$ 5.96$ 5.47$ 5.47$ 5.47$ 5.40$ 5.40$ 5.96$ 5.58$ 5.57$ Low Growth_High Prices 2031-2032 May 5.48$ 5.81$ 5.48$ 5.48$ 5.48$ 5.41$ 5.41$ 5.81$ 5.54$ 5.55$ Low Growth_High Prices 2031-2032 Jun 5.82$ 5.81$ 5.81$ 5.81$ 5.81$ 5.74$ 5.74$ 5.81$ 5.76$ 5.81$ Low Growth_High Prices 2031-2032 Jul 5.45$ 5.81$ 5.45$ 5.45$ 5.45$ 5.37$ 5.37$ 5.81$ 5.52$ 5.52$ Low Growth_High Prices 2031-2032 Aug 5.59$ 5.81$ 5.59$ 5.59$ 5.59$ 5.52$ 5.52$ 5.81$ 5.62$ 5.64$ Low Growth_High Prices 2031-2032 Sep 4.93$ 5.26$ 4.93$ 4.93$ 4.93$ 4.87$ 4.87$ 5.81$ 5.18$ 5.00$ Low Growth_High Prices 2031-2032 Oct 5.76$ 6.10$ 5.76$ 5.76$ 5.76$ 5.69$ 5.69$ 6.10$ 5.82$ 5.83$ Low Growth_High Prices 2032-2033 Nov 5.27$ 5.68$ 5.27$ 5.27$ 5.27$ 5.20$ 5.20$ 5.68$ 5.36$ 5.36$ Low Growth_High Prices 2032-2033 Dec 6.89$ 7.14$ 6.89$ 6.89$ 6.89$ 6.84$ 6.75$ 7.14$ 6.91$ 6.94$ Low Growth_High Prices 2032-2033 Jan 8.43$ 8.43$ 8.43$ 8.43$ 8.43$ 7.59$ 8.32$ 7.59$ 7.83$ 8.43$ Low Growth_High Prices 2032-2033 Feb 8.77$ 8.79$ 8.69$ 8.69$ 8.69$ 7.78$ 8.66$ 7.78$ 8.07$ 8.73$ Low Growth_High Prices 2032-2033 Mar 7.69$ 7.78$ 7.69$ 7.69$ 7.69$ 7.59$ 7.59$ 7.72$ 7.64$ 7.71$ Low Growth_High Prices 2032-2033 Apr 5.54$ 6.08$ 5.54$ 5.54$ 5.54$ 5.47$ 5.47$ 6.08$ 5.67$ 5.65$ Low Growth_High Prices 2032-2033 May 5.54$ 5.85$ 5.54$ 5.54$ 5.54$ 5.46$ 5.46$ 5.85$ 5.59$ 5.60$ Low Growth_High Prices 2032-2033 Jun 5.88$ 5.85$ 5.85$ 5.85$ 5.85$ 5.80$ 5.80$ 5.85$ 5.82$ 5.85$ Low Growth_High Prices 2032-2033 Jul 5.57$ 5.85$ 5.57$ 5.57$ 5.57$ 5.50$ 5.50$ 5.85$ 5.61$ 5.63$ Low Growth_High Prices 2032-2033 Aug 5.70$ 5.85$ 5.70$ 5.70$ 5.70$ 5.62$ 5.62$ 5.85$ 5.70$ 5.73$ Low Growth_High Prices 2032-2033 Sep 5.01$ 5.34$ 5.01$ 5.01$ 5.01$ 4.94$ 4.94$ 5.85$ 5.24$ 5.07$ Low Growth_High Prices 2032-2033 Oct 5.82$ 6.18$ 5.82$ 5.82$ 5.82$ 5.74$ 5.74$ 6.18$ 5.89$ 5.89$ Low Growth_High Prices 2033-2034 Nov 5.33$ 5.75$ 5.33$ 5.33$ 5.33$ 5.25$ 5.25$ 5.75$ 5.42$ 5.41$ Low Growth_High Prices 2033-2034 Dec 6.97$ 7.23$ 6.97$ 6.97$ 6.97$ 6.90$ 6.80$ 7.23$ 6.98$ 7.02$ Low Growth_High Prices 2033-2034 Jan 8.48$ 8.48$ 8.48$ 8.48$ 8.48$ 7.48$ 8.37$ 7.48$ 7.78$ 8.48$ Low Growth_High Prices 2033-2034 Feb 8.83$ 8.85$ 8.75$ 8.75$ 8.75$ 7.70$ 8.71$ 7.70$ 8.04$ 8.79$ Low Growth_High Prices 2033-2034 Mar 7.55$ 7.71$ 7.55$ 7.55$ 7.55$ 7.45$ 7.45$ 7.65$ 7.52$ 7.58$ Low Growth_High Prices 2033-2034 Apr 5.55$ 6.18$ 5.55$ 5.55$ 5.55$ 5.48$ 5.48$ 6.18$ 5.71$ 5.68$ Low Growth_High Prices 2033-2034 May 5.57$ 5.99$ 5.57$ 5.57$ 5.57$ 5.49$ 5.49$ 5.99$ 5.66$ 5.65$ Low Growth_High Prices 2033-2034 Jun 5.91$ 5.99$ 5.91$ 5.91$ 5.91$ 5.83$ 5.83$ 5.99$ 5.88$ 5.92$ Low Growth_High Prices 2033-2034 Jul 5.58$ 5.96$ 5.58$ 5.58$ 5.58$ 5.50$ 5.50$ 5.99$ 5.67$ 5.66$ Low Growth_High Prices 2033-2034 Aug 5.67$ 6.00$ 5.67$ 5.67$ 5.67$ 5.60$ 5.60$ 6.00$ 5.73$ 5.74$ Low Growth_High Prices 2033-2034 Sep 5.05$ 5.44$ 5.05$ 5.05$ 5.05$ 4.99$ 4.99$ 6.00$ 5.32$ 5.13$ Low Growth_High Prices 2033-2034 Oct 5.88$ 6.24$ 5.88$ 5.88$ 5.88$ 5.80$ 5.80$ 6.24$ 5.95$ 5.95$ Low Growth_High Prices 2034-2035 Nov 5.37$ 5.82$ 5.37$ 5.37$ 5.37$ 5.30$ 5.30$ 5.82$ 5.47$ 5.46$ Low Growth_High Prices 2034-2035 Dec 7.03$ 7.27$ 7.03$ 7.03$ 7.03$ 6.96$ 6.86$ 7.27$ 7.03$ 7.08$ Low Growth_High Prices 2034-2035 Jan 8.57$ 8.57$ 8.57$ 8.57$ 8.57$ 8.32$ 8.46$ 8.32$ 8.37$ 8.57$ Low Growth_High Prices 2034-2035 Feb 8.89$ 8.90$ 8.79$ 8.79$ 8.79$ 8.42$ 8.77$ 8.42$ 8.54$ 8.83$ Low Growth_High Prices 2034-2035 Mar 8.43$ 8.49$ 8.43$ 8.43$ 8.43$ 8.32$ 8.32$ 8.43$ 8.36$ 8.44$ Low Growth_High Prices 2034-2035 Apr 5.75$ 6.17$ 5.75$ 5.75$ 5.75$ 5.67$ 5.67$ 6.17$ 5.84$ 5.83$ Low Growth_High Prices 2034-2035 May 5.72$ 5.93$ 5.72$ 5.72$ 5.72$ 5.65$ 5.65$ 5.93$ 5.74$ 5.76$ Low Growth_High Prices 2034-2035 Jun 5.93$ 5.93$ 5.93$ 5.93$ 5.93$ 5.85$ 5.85$ 5.93$ 5.87$ 5.93$ Low Growth_High Prices 2034-2035 Jul 5.58$ 5.73$ 5.58$ 5.58$ 5.58$ 5.51$ 5.51$ 5.73$ 5.58$ 5.61$ Low Growth_High Prices 2034-2035 Aug 5.75$ 5.73$ 5.73$ 5.73$ 5.73$ 5.68$ 5.68$ 5.73$ 5.69$ 5.74$ Low Growth_High Prices 2034-2035 Sep 5.11$ 5.11$ 5.11$ 5.11$ 5.11$ 5.04$ 5.04$ 5.11$ 5.07$ 5.11$ Low Growth_High Prices 2034-2035 Oct 5.91$ 6.31$ 5.91$ 5.91$ 5.91$ 5.83$ 5.83$ 6.31$ 5.99$ 5.99$ 1/ Avoided costs are before Environmental Externalities adder. Monthly Avoided Costs 1/ 2014$ Avista Corp 2016 Natural Gas IRP Appendices 185 Appendix - Chapter 5 APPENDIX 5.4: EXPECTED MONTHLY DETAIL Scenario Gas Year Month Klam Falls La Grande Medford GTN Medford NWP Roseburg Wa/Id Both Wa/Id GTN Wa/Id NWP WA/ID Annual OR Annual Expected Case 2015-2016 Nov 1.96$ 2.10$ 1.96$ 1.96$ 1.96$ 1.93$ 1.93$ 2.10$ 1.99$ 1.99$ Expected Case 2015-2016 Dec 1.78$ 2.07$ 1.78$ 1.78$ 1.78$ 2.07$ 1.65$ 2.07$ 1.93$ 1.84$ Expected Case 2015-2016 Jan 2.11$ 2.15$ 2.11$ 2.11$ 2.11$ 2.11$ 2.08$ 2.11$ 2.10$ 2.12$ Expected Case 2015-2016 Feb 1.92$ 2.20$ 1.92$ 1.92$ 1.92$ 1.96$ 1.86$ 2.13$ 1.98$ 1.98$ Expected Case 2015-2016 Mar 1.83$ 2.11$ 1.83$ 1.83$ 1.83$ 1.80$ 1.80$ 2.11$ 1.90$ 1.88$ Expected Case 2015-2016 Apr 1.79$ 2.22$ 1.79$ 1.79$ 1.79$ 1.76$ 1.76$ 2.22$ 1.92$ 1.88$ Expected Case 2015-2016 May 1.78$ 2.11$ 1.78$ 1.78$ 1.78$ 1.75$ 1.75$ 2.11$ 1.87$ 1.84$ Expected Case 2015-2016 Jun 1.79$ 2.11$ 1.79$ 1.79$ 1.79$ 1.76$ 1.76$ 2.11$ 1.88$ 1.85$ Expected Case 2015-2016 Jul 1.83$ 2.11$ 1.83$ 1.83$ 1.83$ 1.80$ 1.80$ 2.11$ 1.90$ 1.89$ Expected Case 2015-2016 Aug 1.92$ 2.11$ 1.92$ 1.92$ 1.92$ 1.89$ 1.89$ 2.11$ 1.96$ 1.96$ Expected Case 2015-2016 Sep 1.92$ 2.11$ 1.92$ 1.92$ 1.92$ 1.88$ 1.88$ 2.11$ 1.96$ 1.95$ Expected Case 2015-2016 Oct 1.91$ 2.66$ 1.91$ 1.91$ 1.91$ 1.88$ 1.88$ 2.66$ 2.14$ 2.06$ Expected Case 2016-2017 Nov 2.08$ 2.93$ 2.08$ 2.08$ 2.08$ 2.10$ 2.05$ 2.93$ 2.36$ 2.25$ Expected Case 2016-2017 Dec 2.53$ 3.01$ 2.53$ 2.53$ 2.53$ 2.72$ 2.22$ 2.95$ 2.63$ 2.63$ Expected Case 2016-2017 Jan 2.47$ 2.97$ 2.47$ 2.47$ 2.47$ 2.86$ 2.39$ 2.94$ 2.73$ 2.57$ Expected Case 2016-2017 Feb 2.48$ 3.02$ 2.48$ 2.48$ 2.48$ 2.61$ 2.36$ 2.95$ 2.64$ 2.59$ Expected Case 2016-2017 Mar 2.31$ 2.94$ 2.31$ 2.31$ 2.31$ 2.27$ 2.27$ 2.94$ 2.49$ 2.43$ Expected Case 2016-2017 Apr 2.19$ 2.94$ 2.19$ 2.19$ 2.19$ 2.16$ 2.16$ 2.94$ 2.42$ 2.34$ Expected Case 2016-2017 May 2.17$ 2.94$ 2.17$ 2.17$ 2.17$ 2.14$ 2.14$ 2.94$ 2.40$ 2.32$ Expected Case 2016-2017 Jun 2.14$ 2.94$ 2.14$ 2.14$ 2.14$ 2.11$ 2.11$ 2.94$ 2.39$ 2.30$ Expected Case 2016-2017 Jul 2.17$ 2.94$ 2.17$ 2.17$ 2.17$ 2.14$ 2.14$ 2.94$ 2.41$ 2.33$ Expected Case 2016-2017 Aug 2.25$ 2.94$ 2.25$ 2.25$ 2.25$ 2.22$ 2.22$ 2.94$ 2.46$ 2.39$ Expected Case 2016-2017 Sep 2.23$ 2.94$ 2.23$ 2.23$ 2.23$ 2.19$ 2.19$ 2.94$ 2.44$ 2.37$ Expected Case 2016-2017 Oct 2.23$ 3.09$ 2.23$ 2.23$ 2.23$ 2.20$ 2.20$ 3.09$ 2.50$ 2.40$ Expected Case 2017-2018 Nov 2.46$ 3.40$ 2.46$ 2.46$ 2.46$ 2.47$ 2.42$ 3.40$ 2.76$ 2.64$ Expected Case 2017-2018 Dec 2.94$ 3.43$ 2.94$ 2.94$ 2.94$ 3.06$ 2.54$ 3.41$ 3.00$ 3.04$ Expected Case 2017-2018 Jan 3.29$ 3.45$ 3.29$ 3.29$ 3.29$ 3.42$ 3.24$ 3.42$ 3.36$ 3.32$ Expected Case 2017-2018 Feb 3.23$ 3.51$ 3.23$ 3.23$ 3.23$ 3.31$ 3.18$ 3.42$ 3.30$ 3.28$ Expected Case 2017-2018 Mar 2.92$ 3.40$ 2.92$ 2.92$ 2.92$ 2.87$ 2.87$ 3.40$ 3.05$ 3.01$ Expected Case 2017-2018 Apr 2.70$ 3.52$ 2.70$ 2.70$ 2.70$ 2.66$ 2.66$ 3.52$ 2.95$ 2.87$ Expected Case 2017-2018 May 2.64$ 3.40$ 2.64$ 2.64$ 2.64$ 2.60$ 2.60$ 3.40$ 2.86$ 2.79$ Expected Case 2017-2018 Jun 2.59$ 3.40$ 2.59$ 2.59$ 2.59$ 2.55$ 2.55$ 3.40$ 2.83$ 2.75$ Expected Case 2017-2018 Jul 2.64$ 3.40$ 2.64$ 2.64$ 2.64$ 2.60$ 2.60$ 3.40$ 2.87$ 2.79$ Expected Case 2017-2018 Aug 2.68$ 3.40$ 2.68$ 2.68$ 2.68$ 2.64$ 2.64$ 3.40$ 2.89$ 2.82$ Expected Case 2017-2018 Sep 2.72$ 3.40$ 2.72$ 2.72$ 2.72$ 2.68$ 2.68$ 3.40$ 2.92$ 2.86$ Expected Case 2017-2018 Oct 2.73$ 3.72$ 2.73$ 2.73$ 2.73$ 2.69$ 2.69$ 3.72$ 3.03$ 2.93$ Expected Case 2018-2019 Nov 2.98$ 3.50$ 2.98$ 2.98$ 2.98$ 2.99$ 2.94$ 3.50$ 3.14$ 3.09$ Expected Case 2018-2019 Dec 3.31$ 3.61$ 3.31$ 3.31$ 3.31$ 3.53$ 3.07$ 3.53$ 3.38$ 3.37$ Expected Case 2018-2019 Jan 3.19$ 3.55$ 3.19$ 3.19$ 3.19$ 3.51$ 3.14$ 3.51$ 3.39$ 3.27$ Expected Case 2018-2019 Feb 3.16$ 3.61$ 3.16$ 3.16$ 3.16$ 3.30$ 3.10$ 3.51$ 3.30$ 3.25$ Expected Case 2018-2019 Mar 2.70$ 3.50$ 2.70$ 2.70$ 2.70$ 2.66$ 2.66$ 3.50$ 2.94$ 2.86$ Expected Case 2018-2019 Apr 2.50$ 3.52$ 2.50$ 2.50$ 2.50$ 2.46$ 2.46$ 3.52$ 2.81$ 2.70$ Expected Case 2018-2019 May 2.50$ 3.50$ 2.50$ 2.50$ 2.50$ 2.46$ 2.46$ 3.50$ 2.81$ 2.70$ Expected Case 2018-2019 Jun 2.53$ 3.50$ 2.53$ 2.53$ 2.53$ 2.50$ 2.50$ 3.50$ 2.83$ 2.73$ Expected Case 2018-2019 Jul 2.59$ 3.50$ 2.59$ 2.59$ 2.59$ 2.55$ 2.55$ 3.50$ 2.87$ 2.77$ Expected Case 2018-2019 Aug 2.64$ 3.50$ 2.64$ 2.64$ 2.64$ 2.60$ 2.60$ 3.50$ 2.90$ 2.81$ Expected Case 2018-2019 Sep 2.74$ 3.50$ 2.74$ 2.74$ 2.74$ 2.70$ 2.70$ 3.50$ 2.96$ 2.89$ Expected Case 2018-2019 Oct 2.78$ 3.71$ 2.78$ 2.78$ 2.78$ 2.73$ 2.73$ 3.71$ 3.06$ 2.96$ Expected Case 2019-2020 Nov 3.05$ 3.58$ 3.05$ 3.05$ 3.05$ 3.10$ 3.01$ 3.58$ 3.23$ 3.16$ Expected Case 2019-2020 Dec 3.38$ 3.70$ 3.38$ 3.38$ 3.38$ 3.61$ 3.16$ 3.62$ 3.46$ 3.44$ Expected Case 2019-2020 Jan 3.27$ 3.64$ 3.27$ 3.27$ 3.27$ 3.61$ 3.22$ 3.61$ 3.48$ 3.35$ Expected Case 2019-2020 Feb 3.25$ 3.69$ 3.25$ 3.25$ 3.25$ 3.49$ 3.20$ 3.61$ 3.43$ 3.33$ Expected Case 2019-2020 Mar 2.94$ 3.58$ 2.94$ 2.94$ 2.94$ 2.89$ 2.89$ 3.58$ 3.12$ 3.06$ Expected Case 2019-2020 Apr 2.64$ 3.62$ 2.64$ 2.64$ 2.64$ 2.60$ 2.60$ 3.62$ 2.94$ 2.83$ Expected Case 2019-2020 May 2.64$ 3.58$ 2.64$ 2.64$ 2.64$ 2.60$ 2.60$ 3.58$ 2.93$ 2.83$ Expected Case 2019-2020 Jun 2.63$ 3.58$ 2.63$ 2.63$ 2.63$ 2.59$ 2.59$ 3.58$ 2.92$ 2.82$ Expected Case 2019-2020 Jul 2.65$ 3.58$ 2.65$ 2.65$ 2.65$ 2.61$ 2.61$ 3.58$ 2.94$ 2.84$ Expected Case 2019-2020 Aug 2.68$ 3.58$ 2.68$ 2.68$ 2.68$ 2.64$ 2.64$ 3.58$ 2.96$ 2.86$ Expected Case 2019-2020 Sep 2.74$ 3.58$ 2.74$ 2.74$ 2.74$ 2.70$ 2.70$ 3.58$ 2.99$ 2.91$ Expected Case 2019-2020 Oct 2.73$ 3.75$ 2.73$ 2.73$ 2.73$ 2.69$ 2.69$ 3.75$ 3.04$ 2.93$ Expected Case 2020-2021 Nov 3.15$ 3.74$ 3.15$ 3.15$ 3.15$ 3.24$ 3.11$ 3.74$ 3.36$ 3.27$ Expected Case 2020-2021 Dec 3.50$ 3.81$ 3.50$ 3.50$ 3.50$ 3.73$ 3.26$ 3.75$ 3.58$ 3.56$ Expected Case 2020-2021 Jan 3.40$ 3.86$ 3.40$ 3.40$ 3.40$ 3.75$ 3.31$ 3.75$ 3.60$ 3.49$ Expected Case 2020-2021 Feb 3.42$ 3.83$ 3.42$ 3.42$ 3.42$ 3.66$ 3.37$ 3.77$ 3.60$ 3.50$ Expected Case 2020-2021 Mar 3.07$ 3.74$ 3.07$ 3.07$ 3.07$ 3.03$ 3.03$ 3.74$ 3.27$ 3.21$ Expected Case 2020-2021 Apr 2.78$ 3.74$ 2.78$ 2.78$ 2.78$ 2.74$ 2.74$ 3.74$ 3.07$ 2.97$ Expected Case 2020-2021 May 2.79$ 3.74$ 2.79$ 2.79$ 2.79$ 2.75$ 2.75$ 3.74$ 3.08$ 2.98$ Expected Case 2020-2021 Jun 2.79$ 3.74$ 2.79$ 2.79$ 2.79$ 2.75$ 2.75$ 3.74$ 3.08$ 2.98$ Expected Case 2020-2021 Jul 2.73$ 3.75$ 2.73$ 2.73$ 2.73$ 2.69$ 2.69$ 3.75$ 3.04$ 2.93$ Expected Case 2020-2021 Aug 2.77$ 3.75$ 2.77$ 2.77$ 2.77$ 2.73$ 2.73$ 3.75$ 3.07$ 2.97$ Expected Case 2020-2021 Sep 3.02$ 3.75$ 3.02$ 3.02$ 3.02$ 2.98$ 2.98$ 3.75$ 3.23$ 3.17$ Expected Case 2020-2021 Oct 3.04$ 3.83$ 3.04$ 3.04$ 3.04$ 3.00$ 3.00$ 3.83$ 3.28$ 3.20$ Expected Case 2021-2022 Nov 3.31$ 3.85$ 3.31$ 3.31$ 3.31$ 3.40$ 3.27$ 3.85$ 3.51$ 3.42$ Expected Case 2021-2022 Dec 3.88$ 3.97$ 3.88$ 3.88$ 3.88$ 3.86$ 3.39$ 3.86$ 3.70$ 3.90$ Expected Case 2021-2022 Jan 3.65$ 4.01$ 3.65$ 3.65$ 3.65$ 3.87$ 3.43$ 3.87$ 3.72$ 3.72$ Expected Case 2021-2022 Feb 3.56$ 3.98$ 3.56$ 3.56$ 3.56$ 3.78$ 3.48$ 3.88$ 3.71$ 3.64$ Expected Case 2021-2022 Mar 3.12$ 3.85$ 3.12$ 3.12$ 3.12$ 3.07$ 3.07$ 3.85$ 3.33$ 3.26$ Expected Case 2021-2022 Apr 2.85$ 3.93$ 2.85$ 2.85$ 2.85$ 2.81$ 2.81$ 3.93$ 3.18$ 3.07$ Expected Case 2021-2022 May 2.87$ 3.85$ 2.87$ 2.87$ 2.87$ 2.83$ 2.83$ 3.85$ 3.17$ 3.07$ Expected Case 2021-2022 Jun 2.86$ 3.85$ 2.86$ 2.86$ 2.86$ 2.82$ 2.82$ 3.85$ 3.16$ 3.06$ Expected Case 2021-2022 Jul 2.86$ 3.85$ 2.86$ 2.86$ 2.86$ 2.82$ 2.82$ 3.85$ 3.16$ 3.06$ Expected Case 2021-2022 Aug 2.90$ 3.85$ 2.90$ 2.90$ 2.90$ 2.85$ 2.85$ 3.85$ 3.19$ 3.09$ Expected Case 2021-2022 Sep 2.95$ 3.85$ 2.95$ 2.95$ 2.95$ 2.91$ 2.91$ 3.85$ 3.22$ 3.13$ Expected Case 2021-2022 Oct 2.96$ 3.94$ 2.96$ 2.96$ 2.96$ 2.91$ 2.91$ 3.94$ 3.25$ 3.15$ 1/ Avoided costs are before Environmental Externalities adder. Monthly Avoided Costs 1/ 2014$ Avista Corp 2016 Natural Gas IRP Appendices 186 Appendix - Chapter 5 APPENDIX 5.4: EXPECTED MONTHLY DETAIL Scenario Gas Year Month Klam Falls La Grande Medford GTN Medford NWP Roseburg Wa/Id Both Wa/Id GTN Wa/Id NWP WA/ID Annual OR Annual Expected Case 2022-2023 Nov 3.23$ 3.86$ 3.23$ 3.23$ 3.23$ 3.32$ 3.18$ 3.86$ 3.45$ 3.35$ Expected Case 2022-2023 Dec 3.91$ 4.01$ 3.91$ 3.91$ 3.91$ 3.75$ 3.25$ 3.87$ 3.62$ 3.93$ Expected Case 2022-2023 Jan 3.72$ 4.03$ 3.72$ 3.72$ 3.72$ 3.67$ 3.21$ 3.86$ 3.58$ 3.78$ Expected Case 2022-2023 Feb 3.39$ 4.03$ 3.39$ 3.39$ 3.39$ 3.65$ 3.26$ 3.90$ 3.60$ 3.52$ Expected Case 2022-2023 Mar 2.97$ 3.86$ 2.97$ 2.97$ 2.97$ 2.93$ 2.93$ 3.86$ 3.24$ 3.15$ Expected Case 2022-2023 Apr 2.81$ 4.01$ 2.81$ 2.81$ 2.81$ 2.77$ 2.77$ 4.01$ 3.19$ 3.05$ Expected Case 2022-2023 May 2.87$ 3.86$ 2.87$ 2.87$ 2.87$ 2.83$ 2.83$ 3.86$ 3.17$ 3.07$ Expected Case 2022-2023 Jun 2.87$ 3.86$ 2.87$ 2.87$ 2.87$ 2.83$ 2.83$ 3.86$ 3.17$ 3.07$ Expected Case 2022-2023 Jul 2.88$ 3.86$ 2.88$ 2.88$ 2.88$ 2.84$ 2.84$ 3.86$ 3.18$ 3.08$ Expected Case 2022-2023 Aug 2.91$ 3.86$ 2.91$ 2.91$ 2.91$ 2.86$ 2.86$ 3.86$ 3.20$ 3.10$ Expected Case 2022-2023 Sep 3.10$ 3.86$ 3.10$ 3.10$ 3.10$ 3.06$ 3.06$ 3.86$ 3.32$ 3.25$ Expected Case 2022-2023 Oct 3.11$ 3.86$ 3.11$ 3.11$ 3.11$ 3.06$ 3.06$ 3.86$ 3.33$ 3.26$ Expected Case 2023-2024 Nov 3.52$ 3.93$ 3.52$ 3.52$ 3.52$ 3.61$ 3.47$ 3.93$ 3.67$ 3.60$ Expected Case 2023-2024 Dec 4.00$ 4.09$ 4.00$ 4.00$ 4.00$ 4.00$ 3.56$ 4.00$ 3.85$ 4.02$ Expected Case 2023-2024 Jan 3.67$ 4.08$ 3.67$ 3.67$ 3.67$ 3.99$ 3.55$ 3.99$ 3.85$ 3.75$ Expected Case 2023-2024 Feb 3.62$ 4.02$ 3.62$ 3.62$ 3.62$ 3.86$ 3.56$ 3.96$ 3.79$ 3.70$ Expected Case 2023-2024 Mar 3.29$ 3.92$ 3.29$ 3.29$ 3.29$ 3.24$ 3.24$ 3.92$ 3.47$ 3.42$ Expected Case 2023-2024 Apr 3.05$ 3.97$ 3.05$ 3.05$ 3.05$ 3.01$ 3.01$ 3.97$ 3.33$ 3.23$ Expected Case 2023-2024 May 3.06$ 3.93$ 3.06$ 3.06$ 3.06$ 3.01$ 3.01$ 3.93$ 3.32$ 3.23$ Expected Case 2023-2024 Jun 3.05$ 3.94$ 3.05$ 3.05$ 3.05$ 3.01$ 3.01$ 3.94$ 3.32$ 3.23$ Expected Case 2023-2024 Jul 3.16$ 3.94$ 3.16$ 3.16$ 3.16$ 3.11$ 3.11$ 3.94$ 3.39$ 3.32$ Expected Case 2023-2024 Aug 3.20$ 3.94$ 3.20$ 3.20$ 3.20$ 3.15$ 3.15$ 3.94$ 3.41$ 3.34$ Expected Case 2023-2024 Sep 3.32$ 3.94$ 3.32$ 3.32$ 3.32$ 3.28$ 3.28$ 3.94$ 3.50$ 3.45$ Expected Case 2023-2024 Oct 3.33$ 3.98$ 3.33$ 3.33$ 3.33$ 3.28$ 3.28$ 3.98$ 3.51$ 3.46$ Expected Case 2024-2025 Nov 3.80$ 4.09$ 3.80$ 3.80$ 3.80$ 3.85$ 3.75$ 4.09$ 3.89$ 3.86$ Expected Case 2024-2025 Dec 4.16$ 4.26$ 4.16$ 4.16$ 4.16$ 4.16$ 3.83$ 4.16$ 4.05$ 4.18$ Expected Case 2024-2025 Jan 3.91$ 4.26$ 3.91$ 3.91$ 3.91$ 4.15$ 3.86$ 4.15$ 4.05$ 3.98$ Expected Case 2024-2025 Feb 3.92$ 4.21$ 3.92$ 3.92$ 3.92$ 4.08$ 3.86$ 4.13$ 4.02$ 3.97$ Expected Case 2024-2025 Mar 3.55$ 4.09$ 3.55$ 3.55$ 3.55$ 3.50$ 3.50$ 4.09$ 3.69$ 3.66$ Expected Case 2024-2025 Apr 3.26$ 4.24$ 3.26$ 3.26$ 3.26$ 3.21$ 3.21$ 4.24$ 3.55$ 3.45$ Expected Case 2024-2025 May 3.35$ 4.09$ 3.35$ 3.35$ 3.35$ 3.30$ 3.30$ 4.09$ 3.56$ 3.49$ Expected Case 2024-2025 Jun 3.34$ 4.09$ 3.34$ 3.34$ 3.34$ 3.29$ 3.29$ 4.09$ 3.56$ 3.49$ Expected Case 2024-2025 Jul 3.42$ 4.09$ 3.42$ 3.42$ 3.42$ 3.37$ 3.37$ 4.09$ 3.61$ 3.56$ Expected Case 2024-2025 Aug 3.45$ 4.09$ 3.45$ 3.45$ 3.45$ 3.40$ 3.40$ 4.09$ 3.63$ 3.58$ Expected Case 2024-2025 Sep 3.59$ 4.09$ 3.59$ 3.59$ 3.59$ 3.54$ 3.54$ 4.09$ 3.72$ 3.69$ Expected Case 2024-2025 Oct 3.57$ 4.10$ 3.57$ 3.57$ 3.57$ 3.52$ 3.52$ 4.10$ 3.71$ 3.67$ Expected Case 2025-2026 Nov 4.04$ 4.10$ 4.04$ 4.04$ 4.04$ 4.02$ 3.98$ 4.10$ 4.03$ 4.05$ Expected Case 2025-2026 Dec 4.33$ 4.38$ 4.33$ 4.33$ 4.33$ 4.18$ 4.15$ 4.18$ 4.17$ 4.34$ Expected Case 2025-2026 Jan 3.89$ 4.29$ 3.89$ 3.89$ 3.89$ 4.16$ 3.84$ 4.16$ 4.05$ 3.97$ Expected Case 2025-2026 Feb 3.90$ 4.22$ 3.90$ 3.90$ 3.90$ 4.07$ 3.84$ 4.13$ 4.01$ 3.96$ Expected Case 2025-2026 Mar 3.36$ 4.06$ 3.36$ 3.36$ 3.36$ 3.31$ 3.31$ 4.06$ 3.56$ 3.50$ Expected Case 2025-2026 Apr 3.20$ 4.11$ 3.20$ 3.20$ 3.20$ 3.15$ 3.15$ 4.11$ 3.47$ 3.38$ Expected Case 2025-2026 May 3.28$ 4.00$ 3.28$ 3.28$ 3.28$ 3.23$ 3.23$ 4.00$ 3.49$ 3.42$ Expected Case 2025-2026 Jun 3.26$ 4.00$ 3.26$ 3.26$ 3.26$ 3.22$ 3.22$ 4.00$ 3.48$ 3.41$ Expected Case 2025-2026 Jul 3.37$ 4.00$ 3.37$ 3.37$ 3.37$ 3.32$ 3.32$ 4.00$ 3.55$ 3.50$ Expected Case 2025-2026 Aug 3.43$ 4.00$ 3.43$ 3.43$ 3.43$ 3.38$ 3.38$ 4.00$ 3.59$ 3.54$ Expected Case 2025-2026 Sep 3.51$ 4.00$ 3.51$ 3.51$ 3.51$ 3.46$ 3.46$ 4.00$ 3.64$ 3.61$ Expected Case 2025-2026 Oct 3.52$ 4.00$ 3.52$ 3.52$ 3.52$ 3.47$ 3.47$ 4.00$ 3.65$ 3.62$ Expected Case 2026-2027 Nov 4.11$ 4.11$ 4.11$ 4.11$ 4.11$ 4.06$ 4.05$ 4.08$ 4.07$ 4.11$ Expected Case 2026-2027 Dec 4.24$ 4.49$ 4.24$ 4.24$ 4.24$ 4.17$ 4.03$ 4.17$ 4.12$ 4.29$ Expected Case 2026-2027 Jan 3.90$ 4.32$ 3.90$ 3.90$ 3.90$ 4.15$ 3.80$ 4.15$ 4.03$ 3.98$ Expected Case 2026-2027 Feb 3.86$ 4.26$ 3.86$ 3.86$ 3.86$ 4.06$ 3.79$ 4.13$ 4.00$ 3.94$ Expected Case 2026-2027 Mar 3.42$ 4.08$ 3.42$ 3.42$ 3.42$ 3.37$ 3.37$ 4.08$ 3.61$ 3.55$ Expected Case 2026-2027 Apr 3.28$ 4.16$ 3.28$ 3.28$ 3.28$ 3.24$ 3.24$ 4.16$ 3.54$ 3.46$ Expected Case 2026-2027 May 3.33$ 4.08$ 3.33$ 3.33$ 3.33$ 3.28$ 3.28$ 4.08$ 3.54$ 3.48$ Expected Case 2026-2027 Jun 3.36$ 4.08$ 3.36$ 3.36$ 3.36$ 3.31$ 3.31$ 4.08$ 3.56$ 3.50$ Expected Case 2026-2027 Jul 3.46$ 4.08$ 3.46$ 3.46$ 3.46$ 3.41$ 3.41$ 4.08$ 3.64$ 3.59$ Expected Case 2026-2027 Aug 3.52$ 4.08$ 3.52$ 3.52$ 3.52$ 3.47$ 3.47$ 4.08$ 3.67$ 3.63$ Expected Case 2026-2027 Sep 3.74$ 4.08$ 3.74$ 3.74$ 3.74$ 3.68$ 3.68$ 4.08$ 3.81$ 3.80$ Expected Case 2026-2027 Oct 3.77$ 4.20$ 3.77$ 3.77$ 3.77$ 3.72$ 3.72$ 4.20$ 3.88$ 3.85$ Expected Case 2027-2028 Nov 4.33$ 4.33$ 4.33$ 4.33$ 4.33$ 4.29$ 4.27$ 4.33$ 4.29$ 4.33$ Expected Case 2027-2028 Dec 4.50$ 4.64$ 4.50$ 4.50$ 4.50$ 4.43$ 4.33$ 4.43$ 4.39$ 4.53$ Expected Case 2027-2028 Jan 4.26$ 4.61$ 4.26$ 4.26$ 4.26$ 4.41$ 4.20$ 4.41$ 4.34$ 4.33$ Expected Case 2027-2028 Feb 4.25$ 4.43$ 4.25$ 4.25$ 4.25$ 4.34$ 4.19$ 4.37$ 4.30$ 4.29$ Expected Case 2027-2028 Mar 3.75$ 4.31$ 3.75$ 3.75$ 3.75$ 3.70$ 3.70$ 4.31$ 3.90$ 3.86$ Expected Case 2027-2028 Apr 3.64$ 4.35$ 3.64$ 3.64$ 3.64$ 3.59$ 3.59$ 4.35$ 3.84$ 3.78$ Expected Case 2027-2028 May 3.68$ 4.31$ 3.68$ 3.68$ 3.68$ 3.62$ 3.62$ 4.31$ 3.85$ 3.80$ Expected Case 2027-2028 Jun 3.69$ 4.31$ 3.69$ 3.69$ 3.69$ 3.64$ 3.64$ 4.31$ 3.86$ 3.82$ Expected Case 2027-2028 Jul 3.79$ 4.31$ 3.79$ 3.79$ 3.79$ 3.73$ 3.73$ 4.31$ 3.93$ 3.89$ Expected Case 2027-2028 Aug 3.81$ 4.31$ 3.81$ 3.81$ 3.81$ 3.76$ 3.76$ 4.31$ 3.94$ 3.91$ Expected Case 2027-2028 Sep 3.97$ 4.31$ 3.97$ 3.97$ 3.97$ 3.92$ 3.92$ 4.31$ 4.05$ 4.04$ Expected Case 2027-2028 Oct 4.00$ 4.33$ 4.00$ 4.00$ 4.00$ 3.95$ 3.95$ 4.33$ 4.07$ 4.07$ Expected Case 2028-2029 Nov 4.49$ 4.53$ 4.49$ 4.49$ 4.49$ 4.46$ 4.42$ 4.53$ 4.47$ 4.49$ Expected Case 2028-2029 Dec 4.71$ 4.81$ 4.71$ 4.71$ 4.71$ 4.63$ 4.57$ 4.63$ 4.61$ 4.73$ Expected Case 2028-2029 Jan 4.53$ 4.81$ 4.53$ 4.53$ 4.53$ 4.62$ 4.47$ 4.62$ 4.57$ 4.58$ Expected Case 2028-2029 Feb 4.53$ 4.65$ 4.53$ 4.53$ 4.53$ 4.57$ 4.47$ 4.58$ 4.54$ 4.56$ Expected Case 2028-2029 Mar 4.01$ 4.52$ 4.01$ 4.01$ 4.01$ 3.95$ 3.95$ 4.52$ 4.14$ 4.11$ Expected Case 2028-2029 Apr 3.85$ 4.56$ 3.85$ 3.85$ 3.85$ 3.79$ 3.79$ 4.56$ 4.05$ 3.99$ Expected Case 2028-2029 May 3.92$ 4.43$ 3.92$ 3.92$ 3.92$ 3.87$ 3.87$ 4.43$ 4.05$ 4.02$ Expected Case 2028-2029 Jun 3.90$ 4.43$ 3.90$ 3.90$ 3.90$ 3.85$ 3.85$ 4.43$ 4.04$ 4.01$ Expected Case 2028-2029 Jul 3.94$ 4.43$ 3.94$ 3.94$ 3.94$ 3.88$ 3.88$ 4.43$ 4.07$ 4.04$ Expected Case 2028-2029 Aug 3.96$ 4.43$ 3.96$ 3.96$ 3.96$ 3.91$ 3.91$ 4.43$ 4.08$ 4.06$ Expected Case 2028-2029 Sep 4.11$ 4.43$ 4.11$ 4.11$ 4.11$ 4.06$ 4.06$ 4.43$ 4.18$ 4.18$ Expected Case 2028-2029 Oct 4.12$ 4.43$ 4.12$ 4.12$ 4.12$ 4.06$ 4.06$ 4.43$ 4.18$ 4.18$ 1/ Avoided costs are before Environmental Externalities adder. Monthly Avoided Costs 1/ 2014$ Avista Corp 2016 Natural Gas IRP Appendices 187 Appendix - Chapter 5 APPENDIX 5.4: EXPECTED MONTHLY DETAIL Scenario Gas Year Month Klam Falls La Grande Medford GTN Medford NWP Roseburg Wa/Id Both Wa/Id GTN Wa/Id NWP WA/ID Annual OR Annual Expected Case 2029-2030 Nov 4.60$ 4.71$ 4.60$ 4.60$ 4.60$ 4.59$ 4.54$ 4.71$ 4.61$ 4.62$ Expected Case 2029-2030 Dec 4.84$ 4.97$ 4.84$ 4.84$ 4.84$ 4.81$ 4.69$ 4.81$ 4.77$ 4.87$ Expected Case 2029-2030 Jan 4.71$ 4.96$ 4.71$ 4.71$ 4.71$ 4.80$ 4.59$ 4.80$ 4.73$ 4.76$ Expected Case 2029-2030 Feb 4.71$ 4.81$ 4.71$ 4.71$ 4.71$ 4.76$ 4.65$ 4.76$ 4.72$ 4.73$ Expected Case 2029-2030 Mar 4.15$ 4.70$ 4.15$ 4.15$ 4.15$ 4.09$ 4.09$ 4.70$ 4.30$ 4.26$ Expected Case 2029-2030 Apr 3.98$ 4.64$ 3.98$ 3.98$ 3.98$ 3.92$ 3.92$ 4.64$ 4.16$ 4.11$ Expected Case 2029-2030 May 4.00$ 4.64$ 4.00$ 4.00$ 4.00$ 3.95$ 3.95$ 4.64$ 4.18$ 4.13$ Expected Case 2029-2030 Jun 4.05$ 4.64$ 4.05$ 4.05$ 4.05$ 3.99$ 3.99$ 4.64$ 4.21$ 4.17$ Expected Case 2029-2030 Jul 4.14$ 4.59$ 4.14$ 4.14$ 4.14$ 4.09$ 4.09$ 4.64$ 4.27$ 4.23$ Expected Case 2029-2030 Aug 4.18$ 4.64$ 4.18$ 4.18$ 4.18$ 4.12$ 4.12$ 4.64$ 4.29$ 4.27$ Expected Case 2029-2030 Sep 4.32$ 4.65$ 4.32$ 4.32$ 4.32$ 4.26$ 4.26$ 4.65$ 4.39$ 4.38$ Expected Case 2029-2030 Oct 4.36$ 4.75$ 4.36$ 4.36$ 4.36$ 4.30$ 4.30$ 4.75$ 4.45$ 4.44$ Expected Case 2030-2031 Nov 4.86$ 4.93$ 4.86$ 4.86$ 4.86$ 4.84$ 4.80$ 4.93$ 4.86$ 4.88$ Expected Case 2030-2031 Dec 5.17$ 5.25$ 5.17$ 5.17$ 5.17$ 5.04$ 5.03$ 5.04$ 5.04$ 5.18$ Expected Case 2030-2031 Jan 4.94$ 5.13$ 4.94$ 4.94$ 4.94$ 5.03$ 4.80$ 5.03$ 4.95$ 4.97$ Expected Case 2030-2031 Feb 4.91$ 5.01$ 4.91$ 4.91$ 4.91$ 4.97$ 4.85$ 4.97$ 4.93$ 4.93$ Expected Case 2030-2031 Mar 4.31$ 4.90$ 4.31$ 4.31$ 4.31$ 4.25$ 4.25$ 4.90$ 4.46$ 4.43$ Expected Case 2030-2031 Apr 4.20$ 4.74$ 4.20$ 4.20$ 4.20$ 4.15$ 4.15$ 4.74$ 4.34$ 4.31$ Expected Case 2030-2031 May 4.22$ 4.72$ 4.22$ 4.22$ 4.22$ 4.16$ 4.16$ 4.72$ 4.35$ 4.32$ Expected Case 2030-2031 Jun 4.24$ 4.71$ 4.24$ 4.24$ 4.24$ 4.18$ 4.18$ 4.73$ 4.36$ 4.33$ Expected Case 2030-2031 Jul 4.29$ 4.73$ 4.29$ 4.29$ 4.29$ 4.23$ 4.23$ 4.73$ 4.40$ 4.38$ Expected Case 2030-2031 Aug 4.33$ 4.73$ 4.33$ 4.33$ 4.33$ 4.27$ 4.27$ 4.73$ 4.42$ 4.41$ Expected Case 2030-2031 Sep 4.49$ 4.73$ 4.49$ 4.49$ 4.49$ 4.43$ 4.43$ 4.73$ 4.53$ 4.54$ Expected Case 2030-2031 Oct 4.51$ 4.82$ 4.51$ 4.51$ 4.51$ 4.45$ 4.45$ 4.82$ 4.57$ 4.57$ Expected Case 2031-2032 Nov 4.93$ 5.08$ 4.93$ 4.93$ 4.93$ 4.95$ 4.86$ 5.08$ 4.96$ 4.96$ Expected Case 2031-2032 Dec 5.26$ 5.32$ 5.26$ 5.26$ 5.26$ 5.18$ 5.13$ 5.18$ 5.16$ 5.27$ Expected Case 2031-2032 Jan 5.08$ 5.30$ 5.08$ 5.08$ 5.08$ 5.17$ 5.01$ 5.17$ 5.12$ 5.12$ Expected Case 2031-2032 Feb 5.08$ 5.16$ 5.08$ 5.08$ 5.08$ 5.11$ 5.01$ 5.11$ 5.08$ 5.09$ Expected Case 2031-2032 Mar 4.53$ 4.98$ 4.53$ 4.53$ 4.53$ 4.47$ 4.47$ 4.98$ 4.64$ 4.62$ Expected Case 2031-2032 Apr 4.37$ 4.88$ 4.37$ 4.37$ 4.37$ 4.31$ 4.31$ 4.88$ 4.50$ 4.47$ Expected Case 2031-2032 May 4.39$ 4.79$ 4.39$ 4.39$ 4.39$ 4.33$ 4.33$ 4.79$ 4.48$ 4.47$ Expected Case 2031-2032 Jun 4.40$ 4.75$ 4.40$ 4.40$ 4.40$ 4.34$ 4.34$ 4.79$ 4.49$ 4.47$ Expected Case 2031-2032 Jul 4.41$ 4.79$ 4.41$ 4.41$ 4.41$ 4.35$ 4.35$ 4.79$ 4.50$ 4.49$ Expected Case 2031-2032 Aug 4.50$ 4.79$ 4.50$ 4.50$ 4.50$ 4.43$ 4.43$ 4.79$ 4.55$ 4.55$ Expected Case 2031-2032 Sep 4.58$ 4.79$ 4.58$ 4.58$ 4.58$ 4.52$ 4.52$ 4.79$ 4.61$ 4.62$ Expected Case 2031-2032 Oct 4.61$ 4.96$ 4.61$ 4.61$ 4.61$ 4.54$ 4.54$ 4.96$ 4.68$ 4.68$ Expected Case 2032-2033 Nov 5.04$ 5.19$ 5.04$ 5.04$ 5.04$ 5.06$ 4.98$ 5.19$ 5.07$ 5.07$ Expected Case 2032-2033 Dec 5.41$ 5.48$ 5.41$ 5.41$ 5.41$ 5.30$ 5.28$ 5.30$ 5.29$ 5.42$ Expected Case 2032-2033 Jan 5.19$ 5.36$ 5.19$ 5.19$ 5.19$ 5.29$ 5.02$ 5.29$ 5.20$ 5.22$ Expected Case 2032-2033 Feb 5.12$ 5.24$ 5.12$ 5.12$ 5.12$ 5.22$ 5.05$ 5.22$ 5.16$ 5.14$ Expected Case 2032-2033 Mar 4.50$ 5.09$ 4.50$ 4.50$ 4.50$ 4.44$ 4.44$ 5.09$ 4.65$ 4.62$ Expected Case 2032-2033 Apr 4.37$ 4.93$ 4.37$ 4.37$ 4.37$ 4.31$ 4.31$ 4.93$ 4.52$ 4.48$ Expected Case 2032-2033 May 4.36$ 4.81$ 4.36$ 4.36$ 4.36$ 4.30$ 4.30$ 4.81$ 4.47$ 4.45$ Expected Case 2032-2033 Jun 4.40$ 4.81$ 4.40$ 4.40$ 4.40$ 4.33$ 4.33$ 4.81$ 4.49$ 4.48$ Expected Case 2032-2033 Jul 4.49$ 4.77$ 4.49$ 4.49$ 4.49$ 4.42$ 4.42$ 4.81$ 4.55$ 4.54$ Expected Case 2032-2033 Aug 4.56$ 4.81$ 4.56$ 4.56$ 4.56$ 4.49$ 4.49$ 4.81$ 4.60$ 4.61$ Expected Case 2032-2033 Sep 4.64$ 4.81$ 4.64$ 4.64$ 4.64$ 4.57$ 4.57$ 4.81$ 4.65$ 4.67$ Expected Case 2032-2033 Oct 4.67$ 5.04$ 4.67$ 4.67$ 4.67$ 4.60$ 4.60$ 5.04$ 4.75$ 4.74$ Expected Case 2033-2034 Nov 5.12$ 5.29$ 5.12$ 5.12$ 5.12$ 5.16$ 5.06$ 5.29$ 5.17$ 5.16$ Expected Case 2033-2034 Dec 5.53$ 5.67$ 5.53$ 5.53$ 5.53$ 5.40$ 5.37$ 5.40$ 5.39$ 5.55$ Expected Case 2033-2034 Jan 5.29$ 5.47$ 5.29$ 5.29$ 5.29$ 5.38$ 5.11$ 5.38$ 5.29$ 5.32$ Expected Case 2033-2034 Feb 5.21$ 5.34$ 5.21$ 5.21$ 5.21$ 5.32$ 5.14$ 5.32$ 5.26$ 5.24$ Expected Case 2033-2034 Mar 4.55$ 5.21$ 4.55$ 4.55$ 4.55$ 4.49$ 4.49$ 5.21$ 4.73$ 4.69$ Expected Case 2033-2034 Apr 4.43$ 5.07$ 4.43$ 4.43$ 4.43$ 4.37$ 4.37$ 5.07$ 4.60$ 4.56$ Expected Case 2033-2034 May 4.43$ 4.96$ 4.43$ 4.43$ 4.43$ 4.37$ 4.37$ 4.96$ 4.57$ 4.54$ Expected Case 2033-2034 Jun 4.45$ 4.96$ 4.45$ 4.45$ 4.45$ 4.38$ 4.38$ 4.96$ 4.58$ 4.55$ Expected Case 2033-2034 Jul 4.51$ 4.91$ 4.51$ 4.51$ 4.51$ 4.45$ 4.45$ 4.96$ 4.62$ 4.59$ Expected Case 2033-2034 Aug 4.54$ 4.96$ 4.54$ 4.54$ 4.54$ 4.48$ 4.48$ 4.96$ 4.64$ 4.62$ Expected Case 2033-2034 Sep 4.68$ 4.96$ 4.68$ 4.68$ 4.68$ 4.61$ 4.61$ 4.96$ 4.73$ 4.73$ Expected Case 2033-2034 Oct 4.69$ 5.06$ 4.69$ 4.69$ 4.69$ 4.62$ 4.62$ 5.06$ 4.77$ 4.76$ Expected Case 2034-2035 Nov 5.10$ 5.26$ 5.10$ 5.10$ 5.10$ 5.13$ 5.03$ 5.26$ 5.14$ 5.13$ Expected Case 2034-2035 Dec 5.54$ 5.66$ 5.54$ 5.54$ 5.54$ 5.37$ 5.35$ 5.37$ 5.36$ 5.57$ Expected Case 2034-2035 Jan 5.25$ 5.47$ 5.25$ 5.25$ 5.25$ 5.35$ 5.12$ 5.35$ 5.27$ 5.29$ Expected Case 2034-2035 Feb 5.20$ 5.41$ 5.20$ 5.20$ 5.20$ 5.39$ 5.13$ 5.39$ 5.30$ 5.24$ Expected Case 2034-2035 Mar 4.72$ 5.06$ 4.72$ 4.72$ 4.72$ 4.66$ 4.66$ 5.06$ 4.79$ 4.79$ Expected Case 2034-2035 Apr 4.56$ 4.99$ 4.56$ 4.56$ 4.56$ 4.50$ 4.50$ 4.99$ 4.66$ 4.65$ Expected Case 2034-2035 May 4.55$ 4.72$ 4.55$ 4.55$ 4.55$ 4.49$ 4.49$ 4.72$ 4.56$ 4.58$ Expected Case 2034-2035 Jun 4.43$ 4.72$ 4.43$ 4.43$ 4.43$ 4.37$ 4.37$ 4.72$ 4.49$ 4.49$ Expected Case 2034-2035 Jul 4.49$ 4.72$ 4.49$ 4.49$ 4.49$ 4.43$ 4.43$ 4.72$ 4.53$ 4.54$ Expected Case 2034-2035 Aug 4.61$ 4.72$ 4.61$ 4.61$ 4.61$ 4.55$ 4.55$ 4.72$ 4.61$ 4.63$ Expected Case 2034-2035 Sep 4.72$ 4.72$ 4.72$ 4.72$ 4.72$ 4.66$ 4.66$ 4.72$ 4.68$ 4.72$ Expected Case 2034-2035 Oct 4.71$ 5.12$ 4.71$ 4.71$ 4.71$ 4.65$ 4.65$ 5.12$ 4.80$ 4.79$ 1/ Avoided costs are before Environmental Externalities adder. Monthly Avoided Costs 1/ 2014$ Avista Corp 2016 Natural Gas IRP Appendices 188 Appendix - Chapter 5 APPENDIX 5.4: HIGH GROWTH – LOW PRICE MONTHLY DETAIL Scenario Gas Year Month Klam Falls La Grande Medford GTN Medford NWP Roseburg Wa/Id Both Wa/Id GTN Wa/Id NWP WA/ID Annual OR Annual High Growth_Low Prices 2015-2016 Nov 1.96$ 1.96$ 1.96$ 1.96$ 1.96$ 1.93$ 1.93$ 1.96$ 1.94$ 1.96$ High Growth_Low Prices 2015-2016 Dec 1.77$ 2.00$ 1.77$ 1.77$ 1.77$ 1.99$ 1.65$ 1.99$ 1.88$ 1.82$ High Growth_Low Prices 2015-2016 Jan 1.88$ 1.99$ 1.88$ 1.88$ 1.88$ 1.96$ 1.85$ 1.96$ 1.93$ 1.90$ High Growth_Low Prices 2015-2016 Feb 1.93$ 2.09$ 1.93$ 1.93$ 1.93$ 1.96$ 1.90$ 2.00$ 1.96$ 1.96$ High Growth_Low Prices 2015-2016 Mar 1.55$ 1.97$ 1.55$ 1.55$ 1.55$ 1.52$ 1.52$ 1.97$ 1.67$ 1.63$ High Growth_Low Prices 2015-2016 Apr 1.26$ 1.97$ 1.26$ 1.26$ 1.26$ 1.24$ 1.24$ 1.97$ 1.48$ 1.40$ High Growth_Low Prices 2015-2016 May 1.48$ 1.97$ 1.48$ 1.48$ 1.48$ 1.45$ 1.45$ 1.97$ 1.62$ 1.58$ High Growth_Low Prices 2015-2016 Jun 1.52$ 1.97$ 1.52$ 1.52$ 1.52$ 1.50$ 1.50$ 1.97$ 1.65$ 1.61$ High Growth_Low Prices 2015-2016 Jul 2.03$ 2.01$ 2.01$ 2.01$ 2.01$ 2.00$ 2.00$ 2.01$ 2.01$ 2.02$ High Growth_Low Prices 2015-2016 Aug 1.92$ 1.97$ 1.92$ 1.92$ 1.92$ 1.89$ 1.89$ 1.97$ 1.92$ 1.93$ High Growth_Low Prices 2015-2016 Sep 1.33$ 1.97$ 1.33$ 1.33$ 1.33$ 1.31$ 1.31$ 1.97$ 1.53$ 1.46$ High Growth_Low Prices 2015-2016 Oct 1.61$ 2.36$ 1.61$ 1.61$ 1.61$ 1.58$ 1.58$ 2.36$ 1.84$ 1.76$ High Growth_Low Prices 2016-2017 Nov 1.27$ 2.09$ 1.27$ 1.27$ 1.27$ 1.29$ 1.25$ 2.09$ 1.54$ 1.43$ High Growth_Low Prices 2016-2017 Dec 1.35$ 2.05$ 1.35$ 1.35$ 1.35$ 1.46$ 0.88$ 2.05$ 1.46$ 1.49$ High Growth_Low Prices 2016-2017 Jan 1.71$ 2.13$ 1.71$ 1.71$ 1.71$ 2.06$ 1.59$ 2.10$ 1.91$ 1.79$ High Growth_Low Prices 2016-2017 Feb 1.82$ 2.21$ 1.82$ 1.82$ 1.82$ 1.92$ 1.74$ 2.11$ 1.92$ 1.90$ High Growth_Low Prices 2016-2017 Mar 1.47$ 2.10$ 1.47$ 1.47$ 1.47$ 1.44$ 1.44$ 2.10$ 1.66$ 1.59$ High Growth_Low Prices 2016-2017 Apr 1.29$ 2.10$ 1.29$ 1.29$ 1.29$ 1.27$ 1.27$ 2.10$ 1.55$ 1.45$ High Growth_Low Prices 2016-2017 May 1.60$ 2.10$ 1.60$ 1.60$ 1.60$ 1.57$ 1.57$ 2.10$ 1.75$ 1.70$ High Growth_Low Prices 2016-2017 Jun 1.53$ 2.10$ 1.53$ 1.53$ 1.53$ 1.50$ 1.50$ 2.10$ 1.70$ 1.64$ High Growth_Low Prices 2016-2017 Jul 2.03$ 2.10$ 2.03$ 2.03$ 2.03$ 2.00$ 2.00$ 2.10$ 2.03$ 2.04$ High Growth_Low Prices 2016-2017 Aug 1.91$ 2.10$ 1.91$ 1.91$ 1.91$ 1.88$ 1.88$ 2.10$ 1.95$ 1.95$ High Growth_Low Prices 2016-2017 Sep 1.36$ 2.10$ 1.36$ 1.36$ 1.36$ 1.34$ 1.34$ 2.10$ 1.59$ 1.51$ High Growth_Low Prices 2016-2017 Oct 1.49$ 2.36$ 1.49$ 1.49$ 1.49$ 1.46$ 1.46$ 2.36$ 1.76$ 1.66$ High Growth_Low Prices 2017-2018 Nov 1.40$ 2.10$ 1.40$ 1.40$ 1.40$ 1.42$ 1.37$ 2.10$ 1.63$ 1.54$ High Growth_Low Prices 2017-2018 Dec 1.51$ 2.02$ 1.51$ 1.51$ 1.51$ 1.54$ 0.97$ 2.03$ 1.51$ 1.61$ High Growth_Low Prices 2017-2018 Jan 1.83$ 2.14$ 1.83$ 1.83$ 1.83$ 2.12$ 1.73$ 2.12$ 1.99$ 1.89$ High Growth_Low Prices 2017-2018 Feb 1.91$ 2.23$ 1.91$ 1.91$ 1.91$ 2.00$ 1.86$ 2.13$ 2.00$ 1.97$ High Growth_Low Prices 2017-2018 Mar 1.52$ 2.10$ 1.52$ 1.52$ 1.52$ 1.49$ 1.49$ 2.10$ 1.70$ 1.64$ High Growth_Low Prices 2017-2018 Apr 1.27$ 2.10$ 1.27$ 1.27$ 1.27$ 1.24$ 1.24$ 2.10$ 1.53$ 1.43$ High Growth_Low Prices 2017-2018 May 1.47$ 2.11$ 1.47$ 1.47$ 1.47$ 1.44$ 1.44$ 2.11$ 1.66$ 1.60$ High Growth_Low Prices 2017-2018 Jun 1.46$ 2.11$ 1.46$ 1.46$ 1.46$ 1.44$ 1.44$ 2.11$ 1.66$ 1.59$ High Growth_Low Prices 2017-2018 Jul 1.99$ 2.11$ 1.99$ 1.99$ 1.99$ 1.95$ 1.95$ 2.11$ 2.01$ 2.01$ High Growth_Low Prices 2017-2018 Aug 1.81$ 2.11$ 1.81$ 1.81$ 1.81$ 1.78$ 1.78$ 2.11$ 1.89$ 1.87$ High Growth_Low Prices 2017-2018 Sep 1.34$ 2.11$ 1.34$ 1.34$ 1.34$ 1.31$ 1.31$ 2.11$ 1.58$ 1.49$ High Growth_Low Prices 2017-2018 Oct 1.39$ 2.39$ 1.39$ 1.39$ 1.39$ 1.37$ 1.37$ 2.39$ 1.71$ 1.59$ High Growth_Low Prices 2018-2019 Nov 1.36$ 2.11$ 1.36$ 1.36$ 1.36$ 1.48$ 1.34$ 2.11$ 1.64$ 1.51$ High Growth_Low Prices 2018-2019 Dec 1.65$ 1.98$ 1.65$ 1.65$ 1.65$ 1.64$ 1.08$ 1.97$ 1.57$ 1.72$ High Growth_Low Prices 2018-2019 Jan 1.93$ 2.23$ 1.93$ 1.93$ 1.93$ 2.10$ 1.62$ 2.11$ 1.94$ 1.99$ High Growth_Low Prices 2018-2019 Feb 1.84$ 2.26$ 1.84$ 1.84$ 1.84$ 2.05$ 1.76$ 2.15$ 1.98$ 1.93$ High Growth_Low Prices 2018-2019 Mar 1.32$ 2.11$ 1.32$ 1.32$ 1.32$ 1.30$ 1.30$ 2.11$ 1.57$ 1.48$ High Growth_Low Prices 2018-2019 Apr 1.04$ 2.11$ 1.04$ 1.04$ 1.04$ 1.02$ 1.02$ 2.11$ 1.39$ 1.26$ High Growth_Low Prices 2018-2019 May 1.32$ 2.11$ 1.32$ 1.32$ 1.32$ 1.30$ 1.30$ 2.11$ 1.57$ 1.48$ High Growth_Low Prices 2018-2019 Jun 1.41$ 2.11$ 1.41$ 1.41$ 1.41$ 1.39$ 1.39$ 2.11$ 1.63$ 1.55$ High Growth_Low Prices 2018-2019 Jul 1.94$ 2.11$ 1.94$ 1.94$ 1.94$ 1.91$ 1.91$ 2.11$ 1.98$ 1.98$ High Growth_Low Prices 2018-2019 Aug 1.77$ 2.12$ 1.77$ 1.77$ 1.77$ 1.74$ 1.74$ 2.12$ 1.86$ 1.84$ High Growth_Low Prices 2018-2019 Sep 1.24$ 2.12$ 1.24$ 1.24$ 1.24$ 1.22$ 1.22$ 2.12$ 1.52$ 1.42$ High Growth_Low Prices 2018-2019 Oct 1.45$ 2.40$ 1.45$ 1.45$ 1.45$ 1.43$ 1.43$ 2.40$ 1.75$ 1.64$ High Growth_Low Prices 2019-2020 Nov 1.37$ 2.09$ 1.37$ 1.37$ 1.37$ 1.50$ 1.35$ 2.09$ 1.64$ 1.52$ High Growth_Low Prices 2019-2020 Dec 1.66$ 1.75$ 1.66$ 1.66$ 1.66$ 1.56$ 1.01$ 1.74$ 1.44$ 1.68$ High Growth_Low Prices 2019-2020 Jan 1.95$ 2.21$ 1.95$ 1.95$ 1.95$ 2.11$ 1.63$ 2.13$ 1.95$ 2.00$ High Growth_Low Prices 2019-2020 Feb 1.84$ 2.24$ 1.84$ 1.84$ 1.84$ 2.05$ 1.77$ 2.16$ 1.99$ 1.92$ High Growth_Low Prices 2019-2020 Mar 1.45$ 2.13$ 1.45$ 1.45$ 1.45$ 1.42$ 1.42$ 2.13$ 1.66$ 1.59$ High Growth_Low Prices 2019-2020 Apr 1.06$ 2.13$ 1.06$ 1.06$ 1.06$ 1.04$ 1.04$ 2.13$ 1.40$ 1.28$ High Growth_Low Prices 2019-2020 May 1.34$ 2.13$ 1.34$ 1.34$ 1.34$ 1.31$ 1.31$ 2.13$ 1.59$ 1.50$ High Growth_Low Prices 2019-2020 Jun 1.40$ 2.13$ 1.40$ 1.40$ 1.40$ 1.38$ 1.38$ 2.13$ 1.63$ 1.55$ High Growth_Low Prices 2019-2020 Jul 1.92$ 2.13$ 1.92$ 1.92$ 1.92$ 1.89$ 1.89$ 2.13$ 1.97$ 1.97$ High Growth_Low Prices 2019-2020 Aug 1.75$ 2.13$ 1.75$ 1.75$ 1.75$ 1.73$ 1.73$ 2.13$ 1.86$ 1.83$ High Growth_Low Prices 2019-2020 Sep 1.44$ 2.13$ 1.44$ 1.44$ 1.44$ 1.41$ 1.41$ 2.13$ 1.65$ 1.58$ High Growth_Low Prices 2019-2020 Oct 1.41$ 2.45$ 1.41$ 1.41$ 1.41$ 1.39$ 1.39$ 2.45$ 1.74$ 1.62$ High Growth_Low Prices 2020-2021 Nov 1.41$ 2.07$ 1.41$ 1.41$ 1.41$ 1.53$ 1.39$ 2.07$ 1.66$ 1.55$ High Growth_Low Prices 2020-2021 Dec 1.66$ 1.75$ 1.67$ 1.67$ 1.67$ 1.61$ 1.07$ 1.71$ 1.46$ 1.69$ High Growth_Low Prices 2020-2021 Jan 2.07$ 2.34$ 2.07$ 2.07$ 2.07$ 2.14$ 1.66$ 2.15$ 1.98$ 2.13$ High Growth_Low Prices 2020-2021 Feb 1.93$ 2.26$ 1.93$ 1.93$ 1.93$ 2.11$ 1.86$ 2.19$ 2.05$ 2.00$ High Growth_Low Prices 2020-2021 Mar 1.52$ 2.15$ 1.52$ 1.52$ 1.52$ 1.49$ 1.49$ 2.15$ 1.71$ 1.64$ High Growth_Low Prices 2020-2021 Apr 1.13$ 2.15$ 1.13$ 1.13$ 1.13$ 1.11$ 1.11$ 2.15$ 1.46$ 1.34$ High Growth_Low Prices 2020-2021 May 1.42$ 2.15$ 1.42$ 1.42$ 1.42$ 1.39$ 1.39$ 2.15$ 1.65$ 1.56$ High Growth_Low Prices 2020-2021 Jun 1.46$ 2.15$ 1.46$ 1.46$ 1.46$ 1.44$ 1.44$ 2.15$ 1.68$ 1.60$ High Growth_Low Prices 2020-2021 Jul 1.89$ 2.15$ 1.89$ 1.89$ 1.89$ 1.86$ 1.86$ 2.15$ 1.95$ 1.94$ High Growth_Low Prices 2020-2021 Aug 1.71$ 2.15$ 1.71$ 1.71$ 1.71$ 1.68$ 1.68$ 2.15$ 1.84$ 1.80$ High Growth_Low Prices 2020-2021 Sep 1.38$ 2.15$ 1.38$ 1.38$ 1.38$ 1.35$ 1.35$ 2.15$ 1.62$ 1.53$ High Growth_Low Prices 2020-2021 Oct 1.49$ 2.30$ 1.49$ 1.49$ 1.49$ 1.46$ 1.46$ 2.30$ 1.74$ 1.65$ High Growth_Low Prices 2021-2022 Nov 1.41$ 2.12$ 1.41$ 1.41$ 1.41$ 1.53$ 1.38$ 2.12$ 1.68$ 1.55$ High Growth_Low Prices 2021-2022 Dec 1.70$ 1.81$ 1.71$ 1.71$ 1.71$ 1.62$ 1.04$ 1.72$ 1.46$ 1.73$ High Growth_Low Prices 2021-2022 Jan 2.18$ 2.41$ 2.18$ 2.18$ 2.18$ 2.06$ 1.58$ 2.22$ 1.96$ 2.23$ High Growth_Low Prices 2021-2022 Feb 1.88$ 2.34$ 1.88$ 1.88$ 1.88$ 2.14$ 1.78$ 2.25$ 2.06$ 1.97$ High Growth_Low Prices 2021-2022 Mar 1.45$ 2.22$ 1.45$ 1.45$ 1.45$ 1.42$ 1.42$ 2.22$ 1.69$ 1.60$ High Growth_Low Prices 2021-2022 Apr 1.10$ 2.22$ 1.10$ 1.10$ 1.10$ 1.08$ 1.08$ 2.22$ 1.46$ 1.32$ High Growth_Low Prices 2021-2022 May 1.39$ 2.22$ 1.39$ 1.39$ 1.39$ 1.37$ 1.37$ 2.23$ 1.65$ 1.56$ High Growth_Low Prices 2021-2022 Jun 1.45$ 2.23$ 1.45$ 1.45$ 1.45$ 1.42$ 1.42$ 2.23$ 1.69$ 1.60$ High Growth_Low Prices 2021-2022 Jul 1.94$ 2.23$ 1.94$ 1.94$ 1.94$ 1.91$ 1.91$ 2.23$ 2.02$ 2.00$ High Growth_Low Prices 2021-2022 Aug 1.78$ 2.23$ 1.78$ 1.78$ 1.78$ 1.75$ 1.75$ 2.23$ 1.91$ 1.87$ High Growth_Low Prices 2021-2022 Sep 1.36$ 2.23$ 1.36$ 1.36$ 1.36$ 1.34$ 1.34$ 2.23$ 1.63$ 1.53$ High Growth_Low Prices 2021-2022 Oct 1.48$ 2.47$ 1.48$ 1.48$ 1.48$ 1.45$ 1.45$ 2.47$ 1.79$ 1.68$ 1/ Avoided costs are before Environmental Externalities adder. Monthly Avoided Costs 1/ 2014$ Avista Corp 2016 Natural Gas IRP Appendices 189 Appendix - Chapter 5 APPENDIX 5.4: HIGH GROWTH – LOW PRICE MONTHLY DETAIL Scenario Gas Year Month Klam Falls La Grande Medford GTN Medford NWP Roseburg Wa/Id Both Wa/Id GTN Wa/Id NWP WA/ID Annual OR Annual High Growth_Low Prices 2022-2023 Nov 1.29$ 2.23$ 1.29$ 1.29$ 1.29$ 1.41$ 1.27$ 2.23$ 1.64$ 1.48$ High Growth_Low Prices 2022-2023 Dec 1.81$ 1.90$ 1.81$ 1.81$ 1.81$ 1.48$ 0.86$ 1.81$ 1.38$ 1.83$ High Growth_Low Prices 2022-2023 Jan 2.23$ 2.49$ 2.23$ 2.23$ 2.23$ 1.86$ 1.38$ 2.23$ 1.82$ 2.28$ High Growth_Low Prices 2022-2023 Feb 1.71$ 2.39$ 1.71$ 1.71$ 1.71$ 2.08$ 1.57$ 2.27$ 1.97$ 1.84$ High Growth_Low Prices 2022-2023 Mar 1.29$ 2.23$ 1.29$ 1.29$ 1.29$ 1.27$ 1.27$ 2.23$ 1.59$ 1.48$ High Growth_Low Prices 2022-2023 Apr 1.04$ 2.26$ 1.04$ 1.04$ 1.04$ 1.02$ 1.02$ 2.26$ 1.44$ 1.29$ High Growth_Low Prices 2022-2023 May 1.36$ 2.23$ 1.36$ 1.36$ 1.36$ 1.34$ 1.34$ 2.23$ 1.64$ 1.54$ High Growth_Low Prices 2022-2023 Jun 1.43$ 2.23$ 1.43$ 1.43$ 1.43$ 1.40$ 1.40$ 2.23$ 1.68$ 1.59$ High Growth_Low Prices 2022-2023 Jul 1.93$ 2.23$ 1.93$ 1.93$ 1.93$ 1.90$ 1.90$ 2.23$ 2.01$ 1.99$ High Growth_Low Prices 2022-2023 Aug 1.75$ 2.24$ 1.75$ 1.75$ 1.75$ 1.72$ 1.72$ 2.24$ 1.90$ 1.85$ High Growth_Low Prices 2022-2023 Sep 1.44$ 2.24$ 1.44$ 1.44$ 1.44$ 1.42$ 1.42$ 2.24$ 1.69$ 1.60$ High Growth_Low Prices 2022-2023 Oct 1.67$ 2.44$ 1.67$ 1.67$ 1.67$ 1.64$ 1.64$ 2.44$ 1.91$ 1.82$ High Growth_Low Prices 2023-2024 Nov 1.63$ 2.20$ 1.63$ 1.63$ 1.63$ 1.79$ 1.60$ 2.20$ 1.87$ 1.74$ High Growth_Low Prices 2023-2024 Dec 1.78$ 1.87$ 1.79$ 1.79$ 1.79$ 1.61$ 1.04$ 1.79$ 1.48$ 1.80$ High Growth_Low Prices 2023-2024 Jan 2.09$ 2.40$ 2.09$ 2.09$ 2.09$ 2.13$ 1.66$ 2.24$ 2.01$ 2.15$ High Growth_Low Prices 2023-2024 Feb 1.90$ 2.30$ 1.90$ 1.90$ 1.90$ 2.22$ 1.83$ 2.26$ 2.10$ 1.98$ High Growth_Low Prices 2023-2024 Mar 1.54$ 2.19$ 1.54$ 1.54$ 1.54$ 1.52$ 1.52$ 2.19$ 1.74$ 1.67$ High Growth_Low Prices 2023-2024 Apr 1.15$ 2.19$ 1.15$ 1.15$ 1.15$ 1.13$ 1.13$ 2.19$ 1.48$ 1.36$ High Growth_Low Prices 2023-2024 May 1.43$ 2.19$ 1.43$ 1.43$ 1.43$ 1.40$ 1.40$ 2.19$ 1.67$ 1.58$ High Growth_Low Prices 2023-2024 Jun 1.49$ 2.19$ 1.49$ 1.49$ 1.49$ 1.46$ 1.46$ 2.19$ 1.70$ 1.63$ High Growth_Low Prices 2023-2024 Jul 2.08$ 2.19$ 2.08$ 2.08$ 2.08$ 2.04$ 2.04$ 2.19$ 2.09$ 2.10$ High Growth_Low Prices 2023-2024 Aug 1.91$ 2.19$ 1.91$ 1.91$ 1.91$ 1.87$ 1.87$ 2.19$ 1.98$ 1.96$ High Growth_Low Prices 2023-2024 Sep 1.56$ 2.19$ 1.56$ 1.56$ 1.56$ 1.53$ 1.53$ 2.19$ 1.75$ 1.68$ High Growth_Low Prices 2023-2024 Oct 1.58$ 2.25$ 1.58$ 1.58$ 1.58$ 1.55$ 1.55$ 2.25$ 1.78$ 1.71$ High Growth_Low Prices 2024-2025 Nov 1.63$ 2.02$ 1.63$ 1.63$ 1.63$ 1.77$ 1.61$ 2.02$ 1.80$ 1.71$ High Growth_Low Prices 2024-2025 Dec 1.59$ 1.89$ 1.62$ 1.62$ 1.62$ 1.74$ 1.18$ 1.75$ 1.56$ 1.67$ High Growth_Low Prices 2024-2025 Jan 2.07$ 2.39$ 2.07$ 2.07$ 2.07$ 2.18$ 1.71$ 2.19$ 2.03$ 2.13$ High Growth_Low Prices 2024-2025 Feb 1.92$ 2.28$ 1.92$ 1.92$ 1.92$ 2.20$ 1.85$ 2.22$ 2.09$ 1.99$ High Growth_Low Prices 2024-2025 Mar 1.54$ 2.16$ 1.54$ 1.54$ 1.54$ 1.52$ 1.52$ 2.16$ 1.73$ 1.67$ High Growth_Low Prices 2024-2025 Apr 1.12$ 2.12$ 1.12$ 1.12$ 1.12$ 1.10$ 1.10$ 2.12$ 1.44$ 1.32$ High Growth_Low Prices 2024-2025 May 1.48$ 2.12$ 1.48$ 1.48$ 1.48$ 1.45$ 1.45$ 2.12$ 1.68$ 1.61$ High Growth_Low Prices 2024-2025 Jun 1.53$ 2.12$ 1.53$ 1.53$ 1.53$ 1.50$ 1.50$ 2.12$ 1.71$ 1.65$ High Growth_Low Prices 2024-2025 Jul 2.08$ 2.12$ 2.08$ 2.08$ 2.08$ 2.05$ 2.05$ 2.12$ 2.07$ 2.09$ High Growth_Low Prices 2024-2025 Aug 1.90$ 2.12$ 1.90$ 1.90$ 1.90$ 1.87$ 1.87$ 2.12$ 1.96$ 1.95$ High Growth_Low Prices 2024-2025 Sep 1.66$ 2.12$ 1.66$ 1.66$ 1.66$ 1.63$ 1.63$ 2.12$ 1.80$ 1.75$ High Growth_Low Prices 2024-2025 Oct 1.59$ 2.14$ 1.59$ 1.59$ 1.59$ 1.56$ 1.56$ 2.14$ 1.76$ 1.70$ High Growth_Low Prices 2025-2026 Nov 1.56$ 1.83$ 1.56$ 1.56$ 1.56$ 1.66$ 1.53$ 1.83$ 1.67$ 1.61$ High Growth_Low Prices 2025-2026 Dec 1.55$ 1.79$ 1.57$ 1.57$ 1.57$ 1.61$ 1.04$ 1.63$ 1.43$ 1.61$ High Growth_Low Prices 2025-2026 Jan 2.00$ 2.40$ 2.00$ 2.00$ 2.00$ 2.11$ 1.63$ 2.13$ 1.95$ 2.08$ High Growth_Low Prices 2025-2026 Feb 1.85$ 2.28$ 1.85$ 1.85$ 1.85$ 2.18$ 1.78$ 2.18$ 2.05$ 1.93$ High Growth_Low Prices 2025-2026 Mar 1.41$ 2.13$ 1.41$ 1.41$ 1.41$ 1.40$ 1.38$ 2.13$ 1.64$ 1.55$ High Growth_Low Prices 2025-2026 Apr 1.13$ 2.08$ 1.13$ 1.13$ 1.13$ 1.11$ 1.11$ 2.08$ 1.44$ 1.32$ High Growth_Low Prices 2025-2026 May 1.48$ 2.08$ 1.48$ 1.48$ 1.48$ 1.45$ 1.45$ 2.08$ 1.66$ 1.60$ High Growth_Low Prices 2025-2026 Jun 1.52$ 2.08$ 1.52$ 1.52$ 1.52$ 1.49$ 1.49$ 2.08$ 1.69$ 1.63$ High Growth_Low Prices 2025-2026 Jul 2.09$ 2.08$ 2.09$ 2.09$ 2.09$ 2.05$ 2.05$ 2.09$ 2.06$ 2.09$ High Growth_Low Prices 2025-2026 Aug 1.93$ 2.09$ 1.93$ 1.93$ 1.93$ 1.90$ 1.90$ 2.09$ 1.96$ 1.96$ High Growth_Low Prices 2025-2026 Sep 1.55$ 2.09$ 1.55$ 1.55$ 1.55$ 1.52$ 1.52$ 2.09$ 1.71$ 1.65$ High Growth_Low Prices 2025-2026 Oct 1.58$ 2.09$ 1.58$ 1.58$ 1.58$ 1.56$ 1.56$ 2.09$ 1.73$ 1.69$ High Growth_Low Prices 2026-2027 Nov 1.60$ 1.81$ 1.60$ 1.60$ 1.60$ 1.68$ 1.57$ 1.81$ 1.69$ 1.64$ High Growth_Low Prices 2026-2027 Dec 1.66$ 1.86$ 1.67$ 1.67$ 1.67$ 1.53$ 0.94$ 1.71$ 1.39$ 1.71$ High Growth_Low Prices 2026-2027 Jan 2.04$ 2.56$ 2.04$ 2.04$ 2.04$ 2.00$ 1.52$ 2.09$ 1.87$ 2.14$ High Growth_Low Prices 2026-2027 Feb 1.77$ 2.27$ 1.77$ 1.77$ 1.77$ 2.14$ 1.68$ 2.14$ 1.98$ 1.87$ High Growth_Low Prices 2026-2027 Mar 1.38$ 2.09$ 1.38$ 1.38$ 1.38$ 1.37$ 1.36$ 2.09$ 1.61$ 1.53$ High Growth_Low Prices 2026-2027 Apr 1.14$ 2.09$ 1.14$ 1.14$ 1.14$ 1.12$ 1.12$ 2.09$ 1.44$ 1.33$ High Growth_Low Prices 2026-2027 May 1.45$ 2.09$ 1.45$ 1.45$ 1.45$ 1.42$ 1.42$ 2.09$ 1.65$ 1.58$ High Growth_Low Prices 2026-2027 Jun 1.54$ 2.09$ 1.54$ 1.54$ 1.54$ 1.51$ 1.51$ 2.09$ 1.71$ 1.65$ High Growth_Low Prices 2026-2027 Jul 2.11$ 2.09$ 2.09$ 2.09$ 2.09$ 2.08$ 2.08$ 2.09$ 2.08$ 2.10$ High Growth_Low Prices 2026-2027 Aug 1.95$ 2.09$ 1.95$ 1.95$ 1.95$ 1.92$ 1.92$ 2.09$ 1.97$ 1.98$ High Growth_Low Prices 2026-2027 Sep 1.66$ 2.09$ 1.66$ 1.66$ 1.66$ 1.63$ 1.63$ 2.09$ 1.79$ 1.75$ High Growth_Low Prices 2026-2027 Oct 1.75$ 2.20$ 1.75$ 1.75$ 1.75$ 1.72$ 1.72$ 2.20$ 1.88$ 1.84$ High Growth_Low Prices 2027-2028 Nov 1.71$ 1.91$ 1.71$ 1.71$ 1.71$ 1.78$ 1.67$ 1.91$ 1.79$ 1.75$ High Growth_Low Prices 2027-2028 Dec 1.79$ 1.81$ 66.26$ 66.26$ 66.26$ 1.67$ 1.12$ 1.81$ 1.53$ 40.48$ High Growth_Low Prices 2027-2028 Jan 2.03$ 2.36$ 2.03$ 2.03$ 2.03$ 2.16$ 1.76$ 2.16$ 2.02$ 2.10$ High Growth_Low Prices 2027-2028 Feb 1.96$ 2.23$ 1.96$ 1.96$ 1.96$ 2.18$ 1.90$ 2.18$ 2.09$ 2.01$ High Growth_Low Prices 2027-2028 Mar 1.55$ 2.10$ 1.55$ 1.55$ 1.55$ 1.53$ 1.52$ 2.10$ 1.72$ 1.66$ High Growth_Low Prices 2027-2028 Apr 1.31$ 2.10$ 1.31$ 1.31$ 1.31$ 1.29$ 1.29$ 2.10$ 1.56$ 1.47$ High Growth_Low Prices 2027-2028 May 1.60$ 2.10$ 1.60$ 1.60$ 1.60$ 1.58$ 1.58$ 2.10$ 1.75$ 1.70$ High Growth_Low Prices 2027-2028 Jun 1.68$ 2.10$ 1.68$ 1.68$ 1.68$ 1.65$ 1.65$ 2.10$ 1.80$ 1.76$ High Growth_Low Prices 2027-2028 Jul 2.24$ 2.22$ 2.22$ 2.22$ 2.22$ 2.21$ 2.21$ 2.22$ 2.21$ 2.22$ High Growth_Low Prices 2027-2028 Aug 2.05$ 2.10$ 2.05$ 2.05$ 2.05$ 2.02$ 2.02$ 2.10$ 2.05$ 2.06$ High Growth_Low Prices 2027-2028 Sep 1.55$ 1.92$ 1.55$ 1.55$ 1.55$ 1.52$ 1.52$ 2.10$ 1.72$ 1.62$ High Growth_Low Prices 2027-2028 Oct 1.79$ 2.14$ 1.79$ 1.79$ 1.79$ 1.76$ 1.76$ 2.14$ 1.89$ 1.86$ High Growth_Low Prices 2028-2029 Nov 1.80$ 2.04$ 1.80$ 1.80$ 1.80$ 1.86$ 1.74$ 2.04$ 1.88$ 1.84$ High Growth_Low Prices 2028-2029 Dec 1.74$ 1.79$ 66.24$ 66.24$ 66.24$ 1.75$ 1.20$ 1.79$ 1.58$ 40.45$ High Growth_Low Prices 2028-2029 Jan 2.07$ 2.37$ 2.07$ 2.07$ 2.07$ 2.16$ 1.82$ 2.16$ 2.05$ 2.13$ High Growth_Low Prices 2028-2029 Feb 2.03$ 2.26$ 2.03$ 2.03$ 2.03$ 2.20$ 1.98$ 2.20$ 2.12$ 2.08$ High Growth_Low Prices 2028-2029 Mar 1.62$ 2.11$ 1.62$ 1.62$ 1.62$ 1.64$ 1.59$ 2.11$ 1.78$ 1.72$ High Growth_Low Prices 2028-2029 Apr 1.33$ 2.11$ 1.33$ 1.33$ 1.33$ 1.31$ 1.31$ 2.11$ 1.57$ 1.49$ High Growth_Low Prices 2028-2029 May 1.75$ 2.11$ 1.75$ 1.75$ 1.75$ 1.72$ 1.72$ 2.11$ 1.85$ 1.82$ High Growth_Low Prices 2028-2029 Jun 1.73$ 2.11$ 1.73$ 1.73$ 1.73$ 1.70$ 1.70$ 2.11$ 1.84$ 1.80$ High Growth_Low Prices 2028-2029 Jul 2.25$ 2.23$ 2.23$ 2.23$ 2.23$ 2.22$ 2.22$ 2.23$ 2.22$ 2.23$ High Growth_Low Prices 2028-2029 Aug 2.08$ 2.11$ 2.08$ 2.08$ 2.08$ 2.05$ 2.05$ 2.11$ 2.07$ 2.09$ High Growth_Low Prices 2028-2029 Sep 1.72$ 2.07$ 1.72$ 1.72$ 1.72$ 1.69$ 1.69$ 2.11$ 1.83$ 1.79$ High Growth_Low Prices 2028-2029 Oct 1.81$ 2.15$ 1.81$ 1.81$ 1.81$ 1.78$ 1.78$ 2.15$ 1.90$ 1.88$ 1/ Avoided costs are before Environmental Externalities adder. Monthly Avoided Costs 1/ 2014$ Avista Corp 2016 Natural Gas IRP Appendices 190 Appendix - Chapter 5 APPENDIX 5.4: HIGH GROWTH – LOW PRICE MONTHLY DETAIL Scenario Gas Year Month Klam Falls La Grande Medford GTN Medford NWP Roseburg Wa/Id Both Wa/Id GTN Wa/Id NWP WA/ID Annual OR Annual High Growth_Low Prices 2029-2030 Nov 1.78$ 2.08$ 1.78$ 1.78$ 1.78$ 1.85$ 1.68$ 2.08$ 1.87$ 1.84$ High Growth_Low Prices 2029-2030 Dec 2.03$ 2.05$ 66.49$ 66.49$ 66.49$ 1.94$ 1.41$ 2.05$ 1.80$ 40.71$ High Growth_Low Prices 2029-2030 Jan 2.06$ 2.39$ 2.06$ 2.06$ 2.06$ 2.22$ 1.83$ 2.22$ 2.09$ 2.13$ High Growth_Low Prices 2029-2030 Feb 2.07$ 2.29$ 2.07$ 2.07$ 2.07$ 2.24$ 2.03$ 2.24$ 2.17$ 2.11$ High Growth_Low Prices 2029-2030 Mar 1.64$ 2.16$ 1.64$ 1.64$ 1.64$ 1.66$ 1.61$ 2.16$ 1.81$ 1.75$ High Growth_Low Prices 2029-2030 Apr 1.37$ 2.16$ 1.37$ 1.37$ 1.37$ 1.34$ 1.34$ 2.16$ 1.62$ 1.53$ High Growth_Low Prices 2029-2030 May 1.65$ 2.16$ 1.65$ 1.65$ 1.65$ 1.62$ 1.62$ 2.16$ 1.80$ 1.75$ High Growth_Low Prices 2029-2030 Jun 1.75$ 2.16$ 1.75$ 1.75$ 1.75$ 1.72$ 1.72$ 2.16$ 1.87$ 1.83$ High Growth_Low Prices 2029-2030 Jul 2.31$ 2.28$ 2.28$ 2.28$ 2.28$ 2.27$ 2.27$ 2.28$ 2.27$ 2.29$ High Growth_Low Prices 2029-2030 Aug 2.12$ 2.17$ 2.12$ 2.12$ 2.12$ 2.09$ 2.09$ 2.17$ 2.11$ 2.13$ High Growth_Low Prices 2029-2030 Sep 1.86$ 2.17$ 1.86$ 1.86$ 1.86$ 1.83$ 1.83$ 2.17$ 1.94$ 1.92$ High Growth_Low Prices 2029-2030 Oct 1.84$ 2.26$ 1.84$ 1.84$ 1.84$ 1.81$ 1.81$ 2.26$ 1.96$ 1.92$ High Growth_Low Prices 2030-2031 Nov 1.84$ 2.13$ 1.84$ 1.84$ 1.84$ 1.87$ 1.69$ 2.13$ 1.90$ 1.90$ High Growth_Low Prices 2030-2031 Dec 1.95$ 1.98$ 130.87$ 130.87$ 130.87$ 1.97$ 1.45$ 1.98$ 1.80$ 79.31$ High Growth_Low Prices 2030-2031 Jan 2.17$ 2.35$ 2.17$ 2.17$ 2.17$ 2.23$ 1.90$ 2.23$ 2.12$ 2.21$ High Growth_Low Prices 2030-2031 Feb 2.13$ 73.63$ 2.13$ 2.13$ 2.13$ 2.26$ 2.09$ 2.26$ 2.20$ 16.43$ High Growth_Low Prices 2030-2031 Mar 1.67$ 2.17$ 1.67$ 1.67$ 1.67$ 1.68$ 1.64$ 2.17$ 1.83$ 1.77$ High Growth_Low Prices 2030-2031 Apr 1.46$ 2.11$ 1.46$ 1.46$ 1.46$ 1.43$ 1.43$ 2.17$ 1.68$ 1.59$ High Growth_Low Prices 2030-2031 May 1.74$ 2.17$ 1.74$ 1.74$ 1.74$ 1.71$ 1.71$ 2.17$ 1.87$ 1.83$ High Growth_Low Prices 2030-2031 Jun 1.81$ 2.17$ 1.81$ 1.81$ 1.81$ 1.78$ 1.78$ 2.17$ 1.91$ 1.88$ High Growth_Low Prices 2030-2031 Jul 2.32$ 2.30$ 2.30$ 2.30$ 2.30$ 2.29$ 2.29$ 2.30$ 2.29$ 2.30$ High Growth_Low Prices 2030-2031 Aug 2.14$ 2.17$ 2.14$ 2.14$ 2.14$ 2.11$ 2.11$ 2.17$ 2.13$ 2.15$ High Growth_Low Prices 2030-2031 Sep 1.85$ 2.15$ 1.85$ 1.85$ 1.85$ 1.82$ 1.82$ 2.17$ 1.94$ 1.91$ High Growth_Low Prices 2030-2031 Oct 1.89$ 2.24$ 1.89$ 1.89$ 1.89$ 1.86$ 1.86$ 2.24$ 1.99$ 1.96$ High Growth_Low Prices 2031-2032 Nov 1.95$ 2.19$ 1.95$ 1.95$ 1.95$ 2.05$ 1.83$ 2.19$ 2.03$ 2.00$ High Growth_Low Prices 2031-2032 Dec 1.75$ 1.81$ 130.70$ 130.70$ 130.70$ 1.81$ 1.30$ 1.81$ 1.64$ 79.13$ High Growth_Low Prices 2031-2032 Jan 2.18$ 2.36$ 2.18$ 2.18$ 2.18$ 2.24$ 1.91$ 2.24$ 2.13$ 2.21$ High Growth_Low Prices 2031-2032 Feb 2.12$ 71.20$ 2.12$ 2.12$ 2.12$ 71.14$ 2.08$ 71.14$ 48.12$ 15.94$ High Growth_Low Prices 2031-2032 Mar 1.77$ 2.18$ 1.77$ 1.77$ 1.77$ 1.80$ 1.74$ 2.18$ 1.91$ 1.85$ High Growth_Low Prices 2031-2032 Apr 1.50$ 2.14$ 1.50$ 1.50$ 1.50$ 1.48$ 1.48$ 2.16$ 1.71$ 1.63$ High Growth_Low Prices 2031-2032 May 1.87$ 2.16$ 1.87$ 1.87$ 1.87$ 1.84$ 1.84$ 2.16$ 1.95$ 1.93$ High Growth_Low Prices 2031-2032 Jun 1.85$ 2.17$ 1.85$ 1.85$ 1.85$ 1.82$ 1.82$ 2.17$ 1.94$ 1.92$ High Growth_Low Prices 2031-2032 Jul 2.33$ 2.31$ 2.31$ 2.31$ 2.31$ 2.30$ 2.30$ 2.31$ 2.30$ 2.31$ High Growth_Low Prices 2031-2032 Aug 2.21$ 2.19$ 2.19$ 2.19$ 2.19$ 2.18$ 2.18$ 2.19$ 2.18$ 2.19$ High Growth_Low Prices 2031-2032 Sep 1.82$ 2.14$ 1.82$ 1.82$ 1.82$ 1.79$ 1.79$ 2.17$ 1.91$ 1.88$ High Growth_Low Prices 2031-2032 Oct 1.89$ 2.27$ 1.89$ 1.89$ 1.89$ 1.86$ 1.86$ 2.27$ 2.00$ 1.97$ High Growth_Low Prices 2032-2033 Nov 1.86$ 2.17$ 1.86$ 1.86$ 1.86$ 1.98$ 1.69$ 2.17$ 1.95$ 1.92$ High Growth_Low Prices 2032-2033 Dec 1.87$ 1.91$ 130.80$ 130.80$ 130.80$ 1.91$ 1.45$ 1.91$ 1.76$ 79.24$ High Growth_Low Prices 2032-2033 Jan 2.17$ 2.38$ 2.17$ 2.17$ 2.17$ 2.23$ 1.95$ 2.23$ 2.13$ 2.21$ High Growth_Low Prices 2032-2033 Feb 2.17$ 73.66$ 2.17$ 2.17$ 2.17$ 73.61$ 2.13$ 73.61$ 49.78$ 16.47$ High Growth_Low Prices 2032-2033 Mar 1.74$ 2.17$ 1.74$ 1.74$ 1.74$ 1.77$ 1.71$ 2.17$ 1.88$ 1.83$ High Growth_Low Prices 2032-2033 Apr 1.52$ 2.15$ 1.52$ 1.52$ 1.52$ 1.50$ 1.50$ 2.17$ 1.72$ 1.65$ High Growth_Low Prices 2032-2033 May 1.91$ 2.17$ 1.91$ 1.91$ 1.91$ 1.88$ 1.88$ 2.17$ 1.98$ 1.96$ High Growth_Low Prices 2032-2033 Jun 1.86$ 2.17$ 1.86$ 1.86$ 1.86$ 1.83$ 1.83$ 2.17$ 1.95$ 1.92$ High Growth_Low Prices 2032-2033 Jul 2.41$ 2.38$ 2.38$ 2.38$ 2.38$ 2.37$ 2.37$ 2.38$ 2.37$ 2.39$ High Growth_Low Prices 2032-2033 Aug 2.26$ 2.24$ 2.24$ 2.24$ 2.24$ 2.23$ 2.23$ 2.24$ 2.23$ 2.24$ High Growth_Low Prices 2032-2033 Sep 1.67$ 2.04$ 1.67$ 1.67$ 1.67$ 1.64$ 1.64$ 2.18$ 1.82$ 1.74$ High Growth_Low Prices 2032-2033 Oct 1.90$ 2.30$ 1.90$ 1.90$ 1.90$ 1.87$ 1.87$ 2.30$ 2.01$ 1.98$ High Growth_Low Prices 2033-2034 Nov 2.03$ 2.24$ 2.03$ 2.03$ 2.03$ 2.15$ 1.92$ 2.24$ 2.10$ 2.07$ High Growth_Low Prices 2033-2034 Dec 1.96$ 2.02$ 130.90$ 130.90$ 130.90$ 1.90$ 1.34$ 2.02$ 1.75$ 79.34$ High Growth_Low Prices 2033-2034 Jan 2.22$ 2.40$ 2.22$ 2.22$ 2.22$ 2.28$ 1.94$ 2.28$ 2.17$ 2.26$ High Growth_Low Prices 2033-2034 Feb 2.17$ 73.71$ 2.17$ 2.17$ 2.17$ 73.66$ 2.13$ 73.66$ 49.82$ 16.48$ High Growth_Low Prices 2033-2034 Mar 1.69$ 2.22$ 1.69$ 1.69$ 1.69$ 1.73$ 1.66$ 2.22$ 1.87$ 1.80$ High Growth_Low Prices 2033-2034 Apr 1.48$ 2.21$ 1.48$ 1.48$ 1.48$ 1.45$ 1.45$ 2.22$ 1.71$ 1.62$ High Growth_Low Prices 2033-2034 May 1.75$ 2.22$ 1.75$ 1.75$ 1.75$ 1.73$ 1.73$ 2.22$ 1.89$ 1.85$ High Growth_Low Prices 2033-2034 Jun 1.83$ 2.22$ 1.83$ 1.83$ 1.83$ 1.80$ 1.80$ 2.22$ 1.94$ 1.91$ High Growth_Low Prices 2033-2034 Jul 2.36$ 2.33$ 2.33$ 2.33$ 2.33$ 2.32$ 2.32$ 2.33$ 2.33$ 2.34$ High Growth_Low Prices 2033-2034 Aug 2.18$ 2.22$ 2.18$ 2.18$ 2.18$ 2.15$ 2.15$ 2.23$ 2.17$ 2.19$ High Growth_Low Prices 2033-2034 Sep 2.02$ 2.23$ 2.02$ 2.02$ 2.02$ 1.99$ 1.99$ 2.23$ 2.07$ 2.06$ High Growth_Low Prices 2033-2034 Oct 1.90$ 2.31$ 1.90$ 1.90$ 1.90$ 1.87$ 1.87$ 2.31$ 2.02$ 1.98$ High Growth_Low Prices 2034-2035 Nov 1.87$ 2.21$ 1.87$ 1.87$ 1.87$ 2.03$ 1.70$ 2.21$ 1.98$ 1.94$ High Growth_Low Prices 2034-2035 Dec 66.48$ 2.07$ 130.95$ 130.95$ 130.95$ 1.90$ 1.35$ 2.09$ 1.78$ 92.28$ High Growth_Low Prices 2034-2035 Jan 2.23$ 2.39$ 2.23$ 2.23$ 2.23$ 2.29$ 1.98$ 2.29$ 2.18$ 2.26$ High Growth_Low Prices 2034-2035 Feb 2.19$ 73.70$ 2.19$ 2.19$ 2.19$ 73.64$ 2.14$ 73.64$ 49.81$ 16.49$ High Growth_Low Prices 2034-2035 Mar 1.88$ 2.21$ 1.88$ 1.88$ 1.88$ 1.90$ 1.85$ 2.21$ 1.99$ 1.95$ High Growth_Low Prices 2034-2035 Apr 1.61$ 2.08$ 1.61$ 1.61$ 1.61$ 1.59$ 1.59$ 2.08$ 1.75$ 1.71$ High Growth_Low Prices 2034-2035 May 1.85$ 2.08$ 1.85$ 1.85$ 1.85$ 1.82$ 1.82$ 2.08$ 1.91$ 1.90$ High Growth_Low Prices 2034-2035 Jun 1.79$ 2.08$ 1.79$ 1.79$ 1.79$ 1.76$ 1.76$ 2.08$ 1.87$ 1.85$ High Growth_Low Prices 2034-2035 Jul 2.30$ 2.28$ 2.28$ 2.28$ 2.28$ 2.27$ 2.27$ 2.28$ 2.27$ 2.28$ High Growth_Low Prices 2034-2035 Aug 2.20$ 2.18$ 2.18$ 2.18$ 2.18$ 2.17$ 2.17$ 2.18$ 2.17$ 2.18$ High Growth_Low Prices 2034-2035 Sep 1.83$ 2.08$ 1.83$ 1.83$ 1.83$ 1.80$ 1.80$ 2.08$ 1.90$ 1.88$ High Growth_Low Prices 2034-2035 Oct 1.88$ 2.32$ 1.88$ 1.88$ 1.88$ 1.85$ 1.85$ 2.32$ 2.00$ 1.96$ 1/ Avoided costs are before Environmental Externalities adder. Monthly Avoided Costs 1/ 2014$ Avista Corp 2016 Natural Gas IRP Appendices 191 Appendix - Chapter 6 APPENDIX 6.1: HIGH GROWTH CASES SELECTED RESOURCES VS. PEAK DAY DEMAND EXISTING PLUS EXPECTED AVAILABLE Avista Corp 2016 Natural Gas IRP Appendices 192 Appendix - Chapter 6 APPENDIX 6.1: HIGH GROWTH CASES SELECTED RESOURCES VS. PEAK DAY DEMAND EXISTING PLUS EXPECTED AVAILABLE Avista Corp 2016 Natural Gas IRP Appendices 193 Appendix - Chapter 6 APPENDIX 6.2: PEAK DAY DEMAND TABLE HIGH GROWTH Scenario Gas Year LaGrande Served LaGrande Unserved LaGrande Total LaGrande % of Peak Day Served WA/ID Served WA/ID Unserved WA/ID Total WA/ID % of Peak Day Served High Growth_Low Prices 2015-2016 8.07 - 8.07 100%268.99 - 268.99 100% High Growth_Low Prices 2016-2017 8.10 - 8.10 100%271.70 - 271.70 100%High Growth_Low Prices 2017-2018 8.16 - 8.16 100%275.19 - 275.19 100% High Growth_Low Prices 2018-2019 8.23 - 8.23 100%278.70 - 278.70 100% High Growth_Low Prices 2019-2020 8.30 - 8.30 100%282.34 - 282.34 100%High Growth_Low Prices 2020-2021 8.37 - 8.37 100%286.10 - 286.10 100% High Growth_Low Prices 2021-2022 8.44 - 8.44 100%289.71 - 289.71 100% High Growth_Low Prices 2022-2023 8.50 - 8.50 100%293.10 - 293.10 100%High Growth_Low Prices 2023-2024 8.57 - 8.57 100%296.62 - 296.62 100% High Growth_Low Prices 2024-2025 8.62 - 8.62 100%299.85 - 299.85 100% High Growth_Low Prices 2025-2026 8.68 - 8.68 100%303.12 - 303.12 100%High Growth_Low Prices 2026-2027 8.73 - 8.73 100%306.24 - 306.24 100% High Growth_Low Prices 2027-2028 8.81 - 8.81 100%309.62 - 309.62 100% High Growth_Low Prices 2028-2029 8.89 - 8.89 100%312.57 - 312.57 100%High Growth_Low Prices 2029-2030 8.97 - 8.97 100%315.67 - 315.67 100% High Growth_Low Prices 2030-2031 8.98 0.06 9.04 99%318.74 - 318.74 100% High Growth_Low Prices 2031-2032 6.73 2.38 9.11 74%322.05 - 322.05 100% High Growth_Low Prices 2032-2033 6.51 2.66 9.17 71%322.02 2.78 324.80 99%High Growth_Low Prices 2033-2034 6.50 2.72 9.23 70%321.82 6.01 327.83 98% High Growth_Low Prices 2034-2035 8.95 0.35 9.30 96%319.61 12.14 331.75 96% Scenario Gas Year Klamath Falls Served Klamath Falls Unserved Klamath Falls Total Klamath Falls % of Peak Day Served Medford/Roseburg Served Medford/Roseburg Unserved Medford/Roseburg Total Medford/Roseburg % of Peak Day Served High Growth_Low Prices 2015-2016 13.32 - 13.32 100%71.97 - 71.97 100% High Growth_Low Prices 2016-2017 13.43 - 13.43 100%73.29 - 73.29 100% High Growth_Low Prices 2017-2018 13.63 - 13.63 100%74.61 - 74.61 100%High Growth_Low Prices 2018-2019 13.85 - 13.85 100%76.04 - 76.04 100% High Growth_Low Prices 2019-2020 14.07 - 14.07 100%77.51 - 77.51 100% High Growth_Low Prices 2020-2021 14.31 - 14.31 100%79.02 - 79.02 100%High Growth_Low Prices 2021-2022 14.54 - 14.54 100%80.43 - 80.43 100% High Growth_Low Prices 2022-2023 14.78 - 14.78 100%81.66 - 81.66 100% High Growth_Low Prices 2023-2024 15.02 - 15.02 100%82.86 - 82.86 100%High Growth_Low Prices 2024-2025 15.26 - 15.26 100%84.05 - 84.05 100% High Growth_Low Prices 2025-2026 15.49 - 15.49 100%85.23 - 85.23 100% High Growth_Low Prices 2026-2027 15.71 - 15.71 100%86.38 - 86.38 100% High Growth_Low Prices 2027-2028 15.93 - 15.93 100%87.18 0.37 87.55 100%High Growth_Low Prices 2028-2029 16.14 - 16.14 100%87.10 1.59 88.69 98% High Growth_Low Prices 2029-2030 16.34 - 16.34 100%87.02 2.77 89.79 97% High Growth_Low Prices 2030-2031 16.53 - 16.53 100%86.93 3.92 90.85 96%High Growth_Low Prices 2031-2032 16.72 - 16.72 100%86.85 5.01 91.85 95% High Growth_Low Prices 2032-2033 16.92 - 16.92 100%86.76 6.05 92.81 93% High Growth_Low Prices 2033-2034 17.12 - 17.12 100%86.68 7.06 93.74 92%High Growth_Low Prices 2034-2035 17.24 0.10 17.33 99%86.66 8.03 94.70 92% Peak Day Demand - Served and Unserved (MDth/d) Before Resource Additions & Net of DSM Savings Avista Corp 2016 Natural Gas IRP Appendices 194 Appendix - Chapter 6 APPENDIX 6.2: PEAK DAY DEMAND TABLE LOW GROWTH Scenario Gas Year LaGrande Served LaGrande Unserved LaGrande Total LaGrande % of Peak Day Served WA/ID Served WA/ID Unserved WA/ID Total WA/ID % of Peak Day Served Low Growth_High Prices 2015-2016 8.05 - 8.05 100%267.17 - 267.17 100% Low Growth_High Prices 2016-2017 7.05 - 7.05 100%232.26 - 232.26 100%Low Growth_High Prices 2017-2018 7.00 - 7.00 100%230.85 - 230.85 100% Low Growth_High Prices 2018-2019 6.92 - 6.92 100%228.16 - 228.16 100% Low Growth_High Prices 2019-2020 6.92 - 6.92 100%228.60 - 228.60 100%Low Growth_High Prices 2020-2021 6.92 - 6.92 100%228.86 - 228.86 100% Low Growth_High Prices 2021-2022 6.91 - 6.91 100%229.25 - 229.25 100% Low Growth_High Prices 2022-2023 6.90 - 6.90 100%229.40 - 229.40 100% Low Growth_High Prices 2023-2024 6.90 - 6.90 100%229.85 - 229.85 100%Low Growth_High Prices 2024-2025 6.86 - 6.86 100%228.67 - 228.67 100% Low Growth_High Prices 2025-2026 6.86 - 6.86 100%228.78 - 228.78 100% Low Growth_High Prices 2026-2027 6.85 - 6.85 100%228.99 - 228.99 100%Low Growth_High Prices 2027-2028 6.84 - 6.84 100%229.38 - 229.38 100% Low Growth_High Prices 2028-2029 6.80 - 6.80 100%228.35 - 228.35 100% Low Growth_High Prices 2029-2030 6.78 - 6.78 100%228.16 - 228.16 100%Low Growth_High Prices 2030-2031 6.75 - 6.75 100%227.70 - 227.70 100% Low Growth_High Prices 2031-2032 6.73 - 6.73 100%227.64 - 227.64 100% Low Growth_High Prices 2032-2033 6.72 - 6.72 100%227.47 - 227.47 100% Low Growth_High Prices 2033-2034 6.70 - 6.70 100%227.07 - 227.07 100%Low Growth_High Prices 2034-2035 6.71 - 6.71 100%227.90 - 227.90 100% Scenario Gas Year Klamath Falls Served Klamath Falls Unserved Klamath Falls Total Klamath Falls % of Peak Day Served Medford/Roseburg Served Medford/Roseburg Unserved Medford/Roseburg Total Medford/Roseburg % of Peak Day Served Low Growth_High Prices 2015-2016 13.32 - 13.32 100%71.95 - 71.95 100%Low Growth_High Prices 2016-2017 11.64 - 11.64 100%62.78 - 62.78 100% Low Growth_High Prices 2017-2018 11.63 - 11.63 100%62.67 - 62.67 100% Low Growth_High Prices 2018-2019 11.55 - 11.55 100%62.32 - 62.32 100% Low Growth_High Prices 2019-2020 11.63 - 11.63 100%62.78 - 62.78 100%Low Growth_High Prices 2020-2021 11.70 - 11.70 100%63.23 - 63.23 100% Low Growth_High Prices 2021-2022 11.77 - 11.77 100%63.63 - 63.63 100% Low Growth_High Prices 2022-2023 11.83 - 11.83 100%63.90 - 63.90 100%Low Growth_High Prices 2023-2024 11.90 - 11.90 100%64.18 - 64.18 100% Low Growth_High Prices 2024-2025 11.90 - 11.90 100%64.09 - 64.09 100% Low Growth_High Prices 2025-2026 11.96 - 11.96 100%64.31 - 64.31 100%Low Growth_High Prices 2026-2027 12.02 - 12.02 100%64.55 - 64.55 100% Low Growth_High Prices 2027-2028 12.07 - 12.07 100%64.78 - 64.78 100% Low Growth_High Prices 2028-2029 12.08 - 12.08 100%64.73 - 64.73 100% Low Growth_High Prices 2029-2030 12.11 - 12.11 100%64.83 - 64.83 100%Low Growth_High Prices 2030-2031 12.13 - 12.13 100%64.85 - 64.85 100% Low Growth_High Prices 2031-2032 12.16 - 12.16 100%64.88 - 64.88 100% Low Growth_High Prices 2032-2033 12.20 - 12.20 100%65.00 - 65.00 100%Low Growth_High Prices 2033-2034 12.22 - 12.22 100%64.98 - 64.98 100% Low Growth_High Prices 2034-2035 12.27 - 12.27 100%65.09 - 65.09 100% Peak Day Demand - Served and Unserved (MDth/d) Before Resource Additions & Net of DSM Savings Avista Corp 2016 Natural Gas IRP Appendices 195 Appendix - Chapter 6 APPENDIX 6.2: PEAK DAY DEMAND TABLE COLDEST IN 20 YEARS Scenario Gas Year LaGrande Served LaGrande Unserved LaGrande Total LaGrande % of Peak Day Served WA/ID Served WA/ID Unserved WA/ID Total WA/ID % of Peak Day Served Cold Day 20yr Weather Std 2015-2016 8.05 - 8.05 100%249.82 - 249.82 100% Cold Day 20yr Weather Std 2016-2017 8.07 - 8.07 100%251.31 - 251.31 100%Cold Day 20yr Weather Std 2017-2018 8.10 - 8.10 100%253.32 - 253.32 100% Cold Day 20yr Weather Std 2018-2019 8.14 - 8.14 100%255.25 - 255.25 100% Cold Day 20yr Weather Std 2019-2020 8.17 - 8.17 100%257.27 - 257.27 100%Cold Day 20yr Weather Std 2020-2021 8.20 - 8.20 100%259.27 - 259.27 100% Cold Day 20yr Weather Std 2021-2022 8.23 - 8.23 100%261.18 - 261.18 100% Cold Day 20yr Weather Std 2022-2023 8.25 - 8.25 100%262.96 - 262.96 100% Cold Day 20yr Weather Std 2023-2024 8.28 - 8.28 100%264.84 - 264.84 100%Cold Day 20yr Weather Std 2024-2025 8.30 - 8.30 100%266.42 - 266.42 100% Cold Day 20yr Weather Std 2025-2026 8.32 - 8.32 100%268.06 - 268.06 100% Cold Day 20yr Weather Std 2026-2027 8.35 - 8.35 100%269.63 - 269.63 100%Cold Day 20yr Weather Std 2027-2028 8.37 - 8.37 100%271.39 - 271.39 100% Cold Day 20yr Weather Std 2028-2029 8.40 - 8.40 100%272.72 - 272.72 100% Cold Day 20yr Weather Std 2029-2030 8.42 - 8.42 100%274.21 - 274.21 100%Cold Day 20yr Weather Std 2030-2031 8.45 - 8.45 100%275.68 - 275.68 100% Cold Day 20yr Weather Std 2031-2032 8.47 - 8.47 100%277.38 - 277.38 100% Cold Day 20yr Weather Std 2032-2033 8.49 - 8.49 100%278.54 - 278.54 100% Cold Day 20yr Weather Std 2033-2034 8.51 - 8.51 100%279.95 - 279.95 100%Cold Day 20yr Weather Std 2034-2035 8.55 - 8.55 100%282.29 - 282.29 100% Scenario Gas Year Klamath Falls Served Klamath Falls Unserved Klamath Falls Total Klamath Falls % of Peak Day Served Medford/Roseburg Served Medford/Roseburg Unserved Medford/Roseburg Total Medford/Roseburg % of Peak Day Served Cold Day 20yr Weather Std 2015-2016 13.32 - 13.32 100%64.18 - 64.18 100%Cold Day 20yr Weather Std 2016-2017 13.42 - 13.42 100%64.88 - 64.88 100% Cold Day 20yr Weather Std 2017-2018 13.57 - 13.57 100%65.70 - 65.70 100% Cold Day 20yr Weather Std 2018-2019 13.73 - 13.73 100%66.60 - 66.60 100% Cold Day 20yr Weather Std 2019-2020 13.90 - 13.90 100%67.51 - 67.51 100%Cold Day 20yr Weather Std 2020-2021 14.06 - 14.06 100%68.43 - 68.43 100% Cold Day 20yr Weather Std 2021-2022 14.23 - 14.23 100%69.26 - 69.26 100% Cold Day 20yr Weather Std 2022-2023 14.39 - 14.39 100%69.96 - 69.96 100%Cold Day 20yr Weather Std 2023-2024 14.56 - 14.56 100%70.63 - 70.63 100% Cold Day 20yr Weather Std 2024-2025 14.72 - 14.72 100%71.28 - 71.28 100% Cold Day 20yr Weather Std 2025-2026 14.88 - 14.88 100%71.92 - 71.92 100%Cold Day 20yr Weather Std 2026-2027 15.03 - 15.03 100%72.55 - 72.55 100% Cold Day 20yr Weather Std 2027-2028 15.17 - 15.17 100%73.17 - 73.17 100% Cold Day 20yr Weather Std 2028-2029 15.31 - 15.31 100%73.76 - 73.76 100% Cold Day 20yr Weather Std 2029-2030 15.44 - 15.44 100%74.33 - 74.33 100%Cold Day 20yr Weather Std 2030-2031 15.57 - 15.57 100%74.87 - 74.87 100% Cold Day 20yr Weather Std 2031-2032 15.70 - 15.70 100%75.37 - 75.37 100% Cold Day 20yr Weather Std 2032-2033 15.83 - 15.83 100%75.83 - 75.83 100%Cold Day 20yr Weather Std 2033-2034 15.96 - 15.96 100%76.28 - 76.28 100% Cold Day 20yr Weather Std 2034-2035 16.10 - 16.10 100%76.77 - 76.77 100% Peak Day Demand - Served and Unserved (MDth/d) Before Resource Additions & Net of DSM Savings Avista Corp 2016 Natural Gas IRP Appendices 196 Appendix - Chapter 6 APPENDIX 6.2: ALTERNATE SUPPLY RESOURCES Avista Corp 2016 Natural Gas IRP Appendices 197 APPENDIX 7.1: DISTRIBUTION SYSTEM MODELING OVERVIEW The primary goal of distribution system planning is to design for present needs and to plan for future expansion in order to serve demand growth. This allows Avista to satisfy current demand-serving requirements, while taking steps toward meeting future needs. Distribution system planning identifies potential problems and areas of the distribution system that require reinforcement. By knowing when and where pressure problems may occur, the necessary reinforcements can be incorporated into normal maintenance. Thus, more costly reactive and emergency solutions can be avoided. COMPUTER MODELING When designing new main extensions, computer modeling can help determine the optimum size facilities for present and future needs. Undersized facilities are costly to replace, and oversized facilities incur unnecessary expenses to Avista and its customers. THEORY AND APPLICATION OF STUDY Natural gas network load studies have evolved in the last decade to become a highly technical and useful means of analyzing the operation of a distribution system. Using a pipeline fluid flow formula, a specified parameter of each pipe element can be simultaneously solved. Through years of research, pipeline equations have been refined to the point where solutions obtained closely represent actual system behavior. Avista conducts network load studies using GL Noble Denton’s Synergi® 4.8.0 software. This computer- based modeling tool runs on a Windows operating system and allows users to analyze and interpret solutions graphically. CREATING A MODEL To properly study the distribution system, all natural gas main information is entered (length, pipe roughness and size) into the model. "Main" refers to all pipelines supplying services. Nodes are placed at all pipe intersections, beginnings and ends of mains, changes in pipe diameter/material, and to identify all large customers. A model element connects two nodes together. Therefore, a "to node" and a "from node" will represent an element between those two nodes. Almost all of the elements in a model are pipes. Regulators are treated like adjustable valves in which the downstream pressure is set to a known value. Although specific regulator types can be entered for realistic behavior, the expected flow passing through the actual regulator is determined and the modeled regulator is forced to accommodate such flows. FLUID MECHANICS OF THE MODEL Pipe flow equations are used to determine the relationships between flow, pressure drop, diameter and pipe length. For all models, the Fundamental Flow equation (FM) is used due to its demonstrated reliability. Efficiency factors are used to account for the equivalent resistance of valves, fittings and angle changes within the distribution system. Starting with a 95 percent factor, the efficiency can be changed to fine tune the model to match field results. Avista Corp 2016 Natural Gas IRP Appendices 198 Pipe roughness, along with flow conditions, creates a friction factor for all pipes within a system. Thus, each pipe may have a unique friction factor, minimizing computational errors associated with generalized friction values. LOAD DATA All studies are considered steady state; all natural gas entering the distribution system must equal the natural gas exiting the distribution system at any given time. Customer loads are obtained from Avista’s customer billing system and converted to an algebraic format so loads can be generated for various conditions. Customer Management Module (CMM), an add-on application for Synergi, processes customer usage history and generates a base load (non-temperature dependent) and heat load (varying with temperature) for each customer. In the event of a peak day or an extremely cold weather condition, it is assumed that all curtailable loads are interrupted. Therefore, the models will be conducted with only core loads. DETERMINING NATURAL GAS CUSTOMERS’ MAXIMUM HOURLY USAGE DETERMINING DESIGN PEAK HOURLY LOAD The design peak hourly load for a customer is estimated by adding the hourly base load and the hourly heat load for a design temperature. This estimate reflects highest system hourly demands, as shown in Table 1: This method differs from the approach that is used for IRP peak day load planning. The primary reason for this difference is due to the importance of responding to hourly peaking in the distribution system, while IRP resource planning focuses on peak day requirements to the city gate. APPLYING LOADS Having estimated the peak loads for all customers in a particular service area, the model can be loaded. The first step is to assign each load to the respective node or element. GENERATING LOADS Temperature-based and non-temperature-based loads are established for each node or element, thus loads can be varied based on any temperature (HDD). Such a tool is necessary to evaluate the difference in flow and pressure due to different weather conditions. GEOGRAPHIC INFORMATION SYSTEM (GIS) Several years ago Avista converted the natural gas facility maps to GIS. While the GIS can provide a variety of map products, the true power lies in the analytical capabilities. A GIS consists of three components: spatial operations, data association and map representation. A GIS allows analysts to conduct spatial operations (relating a feature or facility to another geographically). A spatial operation is possible if a facility displayed on a map maintains a relationship to other facilities. Spatial relationships allow analysts to perform a multitude of queries, including: Avista Corp 2016 Natural Gas IRP Appendices 199 number of customers assigned to particular pipes in Emergency Operating Procedure zones (geographical areas defined to aid in the safe isolation in the event of an emergency) -pressure pipeline proximity criteria The second component of the GIS is data association. This allows analysts to model relationships between facilities displayed on a map to tabular information in a database. Databases store facility information, such as pipe size, pipe material, pressure rating, or related information (e.g., customer databases, equipment databases and work management systems). Data association allows interactive queries within a map-like environment. Finally, the GIS provides a means to create maps of existing facilities in different scales, projections and displays. In addition, the results of a comparative or spatial analysis can be presented pictorially. This allows users to present complex analyses rapidly and in an easy-to-understand method. BUILDING SYNERGI® MODELS FROM A GIS The GIS can provide additional benefits through the ease of creation and maintenance of load studies. Avista can create load studies from the GIS based on tabular data (attributes) installed during the mapping process. MAINTENANCE USING A GIS The GIS helps maintain the existing distribution facility by allowing a design to be initiated on a GIS. Currently, design jobs for the company’s natural gas system are managed through Avista’s Maximo tool. Once jobs are completed, the as-built information is automatically updated on GIS, eliminating the need to convert physical maps to a GIS at a later date. Because the facility is updated, load studies can remain current by refreshing the analysis. DEVELOPING A PRESENT CASE LOAD STUDY In order for any model to have accuracy, a present case model has to be developed that reflects what the system was doing when downstream pressures and flows are known. To establish the present case, pressure recording instruments located throughout the distribution system are used. These field instruments record pressure and temperature throughout the winter season. Various locations recording simultaneously are used to validate the model. Customer loads on Synergi® are generated to correspond with actual temperatures recorded on the instruments. An accurate model’s downstream pressures will match the corresponding field instrument’s pressures. Efficiency factors are adjusted to further refine the model's pressures and better match the actual conditions. Since telemetry at the gate stations record hourly flow, temperature and pressure, these values are used to validate the model. All loads are representative of the average daily temperature and are defined as hourly flows. If the load generating method is truly accurate, all natural gas entering the actual system (physical) equals total natural gas demand solved by the simulated system (model). DEVELOPING A PEAK CASE LOAD STUDY Using the calculated peak loads, a model can be analyzed to identify the behavior during a peak day. The efficiency factors established in the present case are used throughout subsequent models. Avista Corp 2016 Natural Gas IRP Appendices 200 ANALYZING RESULTS After a model has been balanced, several features within the Synergi® model are used to interpret results. Color plots are generated to depict flow direction, pressure, and pipe diameter with specific break points. Reinforcements can be identified by visual inspection. When user edits are completed and the model is re- balanced, pressure changes can be visually displayed, helping identify optimum reinforcements. PLANNING CRITERIA In most instances, models resulting in node pressures below 15 psig indicate a likelihood of distribution low pressure, and therefore necessitate reinforcements. For most Avista distribution systems, a minimum of 15 psig will ensure deliverability as natural gas exits the distribution mains and travels through service pipelines to a customer’s meter. Some Avista distribution areas operate at lower pressures and are assigned a minimum pressure of 5 psig for model results. Given a lower operating pressure, service pipelines in such areas are sized accordingly to maintain reliability. DETERMINING MAXIMUM CAPACITY FOR A SYSTEM Using a peak day model, loads can be prorated at intervals until area pressures drop to 15 psig. At that point, the total amount of natural gas entering the system equals the maximum capacity before new construction is necessary. The difference between natural gas entering the system in this scenario and a peak day model is the maximum additional capacity that can be added to the system. Since the approximate natural gas usage for the average customer is known, it can be determined how many new customers can be added to the distribution system before necessitating system reinforcements. The above models and procedures are utilized with new construction proposals or pipe reinforcements to determine the potential increase in capacity. FIVE-YEAR FORECASTING The intent of the load study forecasting is to predict the system’s behavior and reinforcements necessary within the next five years. Various Avista personnel provide information to determine where and why certain areas may experience growth. By combining information from Avista’s demand forecast, IRP planning efforts, regional growth plans and area developments, proposals for pipeline reinforcements and expansions are evaluated with Synergi®. Avista Corp 2016 Natural Gas IRP Appendices 201 Appendix 7.2 Oregon Public Utility Commission Order No. 16-109 (the Order) included the following language: Finally, as part of the IRP-vetting process and subsequent rate proceedings, we expect that Avista conduct and present comprehensive analyses of its system upgrades. Such analyses should provide: (1) a comprehensive cost-benefit analysis of whether and when the investment should be built; (2) evaluation of a range of alternative build dates and the impact on reliability and customer rates; (3) credible evidence on the likelihood of disruptions based on historical experience; (4) evidence on the range of possible reliability incidents; (5) evidence about projected loads and customers in the area; and (6) adequate consideration of alternatives, including the use of interruptibility or increased demand-side measures to improve reliability and system resiliency. In order to address this portion of the Order, Avista has prepared this appendix, which includes documentation addressing the six points above for each of the natural gas distribution system enhancements included in the 2016 Natural Gas Integrated Resource Plan (IRP) for Avista’s Oregon service territory. Each of these three enhancement projects represents a significant, discrete project which is out of the ordinary course of business (that is to say, different from ongoing capital investment to address Federal or State regulatory requirements, relocation of pipe or facilities as requested by others, failed pipe or facilities, etc., all of which occur routinely over time and which are discussed below). The routine, ongoing capital investments can be loosely classified in the following categories (which are not mutually exclusive):  Safety – Ongoing safety related capital investment includes the repair or replacement of obsolete or failed pipe and facilities. This category includes, but is not necessarily limited to, investment to address deteriorated or isolated steel pipe, cathodic protection, and the replacement of pipeline which has been built over, as well as the remedy of shallow pipe or the repair or replacement of leaking pipe.  System Maintenance – Ongoing capital investment related to system maintenance includes replacement of facilities or pipe that has reached the end of their useful lives, as well as other general investment required to maintain Avista’s ability to reliably serve customers.  Relocation Requested by Others – Ongoing capital investment related to relocation requested by others falls primarily into two categories, relocation requested by other parties which is required under the terms of our franchise agreements (such as Avista Corp 2016 Natural Gas IRP Appendices 202 relocations required to accommodate road or highway construction or relocation), or relocation requested by customers or others (in which case the customer would be responsible for the cost of the immediate request, but in which case Avista may perform additional work, such as the replacement of a steel service with polyethylene to reduce future maintenance or cathodic protection requirements on that pipe).  Mandated System Investment – Ongoing capital investment in this category is driven by Federal or State regulatory requirements, such as investment that results from TIMP/DIMP programs, among other programs. Avista’s Aldyl-A replacement program has been addressed in substantial detail in Oregon Public Utility Commission Docket UG-246, Avista/500-501. Avista Corp 2016 Natural Gas IRP Appendices 203 ,o111~-~11ril1STA La Grande High Pressure Reinforcement 1. A comprehensive cost-benefit analysis of whether and when the investment should be built High pressure reinforcements are primarily driven by load studies, whereby an inability to reliably serve customers on a design day drives investment needs. (Evidence regarding the inability to reliably serve customers on a design day is given in #4, below.) Given this, the threshold consideration regarding a high pressure reinforcement is driven primarily by models indicating an inability to serve customers on a design day, rather than a strict application of cost-benefit analysis. Said differently, to a customer, the loss of natural gas service on a design day (74 HDD, or average daily temperature of -9° Fahrenheit, in La Grande) is not a question of cost-benefit, but rather of physical safety and comfort. 2. Evaluation of a range of alternative build dates and the impact on reliability and customer rates As discussed in #1, above, the identification of areas in need of reinforcement is the primary threshold consideration that establishes the need for and timing of planned completion. The number/scope of reinforcement projects that are completed in any given year may be constrained by such things as the availability of project management, skilled labor, and the need to complete other critical-path projects first in order to enable the functionality of the given project. Because of these constraints, the areas of concern within Avista’s natural gas distribution systems are risk-ranked against each other, to ensure that the areas of highest risk are corrected first. In the case of this La Grande High Pressure Reinforcement, there were a number of system capacity issues in the La Grande area, including gate station capacity constraints at both the La Grande city gate station (station #0815) and the Ladd Canyon gate station (station #0817), as well as low design day pressures identified for the cities of Elgin and Union, Oregon. In the evaluation of these capacity constraints and low design day pressures, three critical points were identified—the La Grande city gate station, the Ladd Canyon gate station, and the remaining system pressure at the end of the high pressure pipeline connecting Elgin to the distribution system (where a minimum design pressure of 100 psig is required to serve Elgin on a design day, but where the actual pressure on a design day was found to be 35 psig). The evaluation further identified that increasing the capacity of the La Grande gate station would alleviate the gate station constraint, but would not address the low pressure at Elgin. However, the evaluation found that replacement of the Ladd Canyon gate station and the investment in the La Grande High Pressure Reinforcement project would alleviate all three critical points, requiring only two projects. This analysis resulted in the lowest cost solution, given that this solution avoids the need to upsize the La Grande city gate station to address that gate station’s capacity constraint. Avista Corp 2016 Natural Gas IRP Appendices 204 Given the interrelated nature of these critical points and the two projects, the investment in the La Grande High Pressure Reinforcement could not occur until the new Ladd Canyon gate station (station #7080) was completed (this station was placed in service in December 2015). At existing rates, an incremental addition of $1 million to distribution gross plant would result in an increase in billed revenue to Oregon customers of approximately one-tenth of one percent of present billed revenue. 3. Credible evidence on the likelihood of disruptions based on historical experience As discussed in Chapter 7: Distribution Planning in the Natural Gas IRP, the distribution scenario decision-making process relies upon the analyses performed on each of Avista’s LDC systems under design day conditions to identify areas where potential outages may occur. Avista’s design heating degree day for distribution system modeling is determined using the coldest day on record for each given service area. This practice is consistent with the peak day demand forecast utilized in Avista’s natural gas Integrated Resource Plan, in the “Weather Forecast” section of Chapter 2, which explains the methodology for determining the peak day demand forecast as follows: The peak day demand forecast includes adjustments to average weather to reflect a five- day cold weather event. This consists of adjusting the middle day of the five-day cold weather event to the coldest temperature on record for a service territory…. The IRP, in the “Weather Forecast” section of Chapter 2, goes on to describe the coldest days on record for each of the Oregon service areas, stating the following: Medford experienced the coldest day on record, a 61 HDD, on Dec. 9, 1972. This is equal to an average daily temperature of 4 degrees Fahrenheit. Medford has experienced only one 61 HDD in the last 40 years; however, it has also experienced 59 and 58 HDD events on Dec. 8, 1972 and Dec. 21, 1990, respectively. The other three areas in Oregon have similar weather days. For Klamath Falls, a 72 HDD occurred on Dec. 8, 2013; in La Grande a 74 HDD occurred on Dec. 23, 1983; and a 55 HDD occurred in Roseburg on Dec. 22, 1990. As with Washington/Idaho and Medford, these days are the peak day weather standard for modeling purposes. The IRP also addresses the appropriateness of the use of the coldest day on record as the planning standard, stating, in the “Weather Forecast” section of Chapter 2: Utilizing a peak planning standard of the coldest temperature on record may seem aggressive given a temperature experienced rarely, or only once. Given the potential impacts of an extreme weather event on customers’ personal safety and property damage to customer appliances and Avista’s infrastructure, it is a prudent regionally Avista Corp 2016 Natural Gas IRP Appendices 205 ,o111~-~11ril1STA accepted planning standard. While remote, peak days do occur, as on Dec. 8, 2013, when Avista matched the previous peak HDD [72 HDD] in Klamath Falls. Prior to the December 8, 2013 design heating degree day in Klamath Falls, Oregon, the previous design heating degree day in Klamath Falls had occurred on December 21, 1990. Further, in the 20 years preceding the completion of Avista’s 2012 Natural Gas IRP, the coldest day in 20 years in Klamath Falls had been a 64 heating degree day. These factors, along with the recent December 8, 2013 design heating degree day, demonstrate that the absence of a design heating degree day in the past 20 years does not mean that a design heating degree day will not happen. In fact, this further confirms that the design heating degree day is a prudent planning standard. 4. Evidence on the range of possible reliability incidents The following pages illustrate the results of the Synergi™ study with regards to the aforementioned low pressure on a design day at Elgin, Oregon. As discussed in Avista testimony in Docket No. UG-288 (Avista/1500, Webb/20), the system pressure upon reaching Elgin is less than 35 psig on a design day, while the system design criteria dictate that the pressure should be 100 psig at this point in order to reliably serve Elgin. Given the substantial disparity between 35 psig and 100 psig, the low system pressure upon reaching Elgin is likely to persist at temperatures higher than the design day temperature (i.e., the probability of losing customers in this area is relatively higher). Similarly, given that the system demand on the La Grande gate station on a design day is modeled to be 158% of physical capacity (as shown in Appendix 7.1), the capacity shortfall at the La Grande gate station is likely to persist at higher temperatures than the design day temperature. Both of these factors contributed to the identification of this project as a high priority for completion. 5. Evidence about projected loads and customers in the area Given that the Synergi™ load studies used to determine the need for reinforcement or other remedy are based upon existing system load, this reinforcement investment determination was necessary to serve existing loads, irrespective of projected loads and customers in the area. While the determination that a project is necessary to support the distribution system is made irrespective of projected customer or load growth, as discussed in the materials included in Appendix 7.1, once a project need has been identified through the load studies, expected growth in load or customers in the area is considered (when available) in appropriately scoping the project in order to avoid the incremental cost of having to perform incremental reinforcement in a given area that would likely be required if this information were not considered. Avista Corp 2016 Natural Gas IRP Appendices 206 6. Adequate consideration of alternatives, including the use of interruptibility or increased demand-side measures to improve reliability and system resiliency As discussed in Avista testimony in Docket No. UG-288 (Avista/1500, Webb/20), while it is true that loads can be interrupted or curtailed in the event of supply or capacity shortfalls, the load studies performed to model the Company’s natural gas distribution system on design days consider only firm load. That is to say, Avista’s design heating degree day models presume that all interruptible customers have already been interrupted, and only firm loads are being served. Therefore, the capacity deficits shown in the previously discussed load studies could not be alleviated through interruption. Additionally, as discussed in the “Conservation Resources” section of Chapter 7 (Distribution Planning) of the IRP: The evaluation of distribution system constraints includes consideration of targeted conservation resources to reduce or delay distribution system enhancements. The consumer is still the ultimate decision-maker regarding the purchase of a conservation measure. Because of this, Avista attempts to influence conservation through the DSM measures discussed in Chapter 3 – Demand-Side Resources, but does not depend on estimates of peak day demand reductions from conservation to eliminate near-term distribution system constraints. Over the longer-term, targeted conservation programs may provide a cumulative benefit that could offset potential constraint areas and may be an effective strategy. Thus, while Avista certainly considers the importance of demand-side measures, and encourages such conservation programs, the conservation benefits accomplished by demand-side measures occur over a longer period than would be required to prudently address the existing, near-term distribution system constraints. Avista Corp 2016 Natural Gas IRP Appendices 207 Klamath Falls (#2703) Gate Station 1. A comprehensive cost-benefit analysis of whether and when the investment should be built Gate station upgrades are primarily driven by the City Gate Analysis (as discussed in the materials included in Appendix 7.1), whereby a capacity constraint impacting Avista’s ability to reliably serve customers drives investment needs. (Evidence regarding the inability to reliably serve customers on a design day is given in #4, below.) Given this, the threshold consideration regarding gate station investment is driven primarily by models indicating a capacity deficit on a design day, rather than a strict application of cost-benefit analysis. Said differently, to a customer, the loss of natural gas service on a design day (72 HDD, or average daily temperature of -7° Fahrenheit, in Klamath Falls) is not a question of cost-benefit, but rather of physical safety and comfort. 2. Evaluation of a range of alternative build dates and the impact on reliability and customer rates As discussed in #1, above, the identification of capacity shortfalls on a design day is the primary threshold consideration that establishes the need for and timing of planned completion. The number/scope of reinforcement projects that are completed in any given year may be constrained by such things as the availability of project management, skilled labor, and the need to complete other critical-path projects first in order to enable the functionality of the given project. Because of these constraints, the areas of concern within Avista’s natural gas distribution systems are risk-ranked against each other, to ensure that the areas of highest risk are corrected first. Given that the capacity constraint at the Klamath Falls gate station (Station #2703) was modeled to be 106% on a design day as of the most recent City Gate Analysis (a relatively small capacity constraint), and the relative risk ranking compared with other natural gas distribution projects, this project has been included in planning considerations, with planned completion slated for 2019 or later. The assessed capacity constraint will continue to be regularly evaluated, and an increase in the assessed shortfall might warrant acceleration of the project, while a reduction in demand that eliminates the shortfall would defer the project. At existing rates, an incremental addition of $1 million to distribution gross plant would result in an increase in billed revenue to Oregon customers of approximately one-tenth of one percent of present billed revenue. 3. Credible evidence on the likelihood of disruptions based on historical experience As discussed in Chapter 7: Distribution Planning in the Natural Gas IRP, the distribution scenario decision-making process relies upon the analyses performed on each of Avista’s LDC systems under design day conditions to identify areas where potential outages may occur. Avista Corp 2016 Natural Gas IRP Appendices 208 Avista’s design heating degree day for distribution system modeling is determined using the coldest day on record for each given service area. This practice is consistent with the peak day demand forecast utilized in Avista’s natural gas Integrated Resource Plan, in the “Weather Forecast” section of Chapter 2, which explains the methodology for determining the peak day demand forecast as follows: The peak day demand forecast includes adjustments to average weather to reflect a five- day cold weather event. This consists of adjusting the middle day of the five-day cold weather event to the coldest temperature on record for a service territory…. The IRP, in the “Weather Forecast” section of Chapter 2, goes on to describe the coldest days on record for each of the Oregon service areas, stating the following: Medford experienced the coldest day on record, a 61 HDD, on Dec. 9, 1972. This is equal to an average daily temperature of 4 degrees Fahrenheit. Medford has experienced only one 61 HDD in the last 40 years; however, it has also experienced 59 and 58 HDD events on Dec. 8, 1972 and Dec. 21, 1990, respectively. The other three areas in Oregon have similar weather days. For Klamath Falls, a 72 HDD occurred on Dec. 8, 2013; in La Grande a 74 HDD occurred on Dec. 23, 1983; and a 55 HDD occurred in Roseburg on Dec. 22, 1990. As with Washington/Idaho and Medford, these days are the peak day weather standard for modeling purposes. The IRP also addresses the appropriateness of the use of the coldest day on record as the planning standard, stating, in the “Weather Forecast” section of Chapter 2: Utilizing a peak planning standard of the coldest temperature on record may seem aggressive given a temperature experienced rarely, or only once. Given the potential impacts of an extreme weather event on customers’ personal safety and property damage to customer appliances and Avista’s infrastructure, it is a prudent regionally accepted planning standard. While remote, peak days do occur, as on Dec. 8, 2013, when Avista matched the previous peak HDD [72 HDD] in Klamath Falls. Prior to the December 8, 2013 design heating degree day in Klamath Falls, Oregon, the previous design heating degree day in Klamath Falls had occurred on December 21, 1990. Further, in the 20 years preceding the completion of Avista’s 2012 Natural Gas IRP, the coldest day in 20 years in Klamath Falls had been a 64 heating degree day. These factors, along with the recent December 8, 2013 design heating degree day, demonstrate that the absence of a design heating degree day in the past 20 years does not mean that a design heating degree day will not happen. In fact, this further confirms that the design heating degree day is a prudent planning standard. 4. Evidence on the range of possible reliability incidents Avista Corp 2016 Natural Gas IRP Appendices 209 ,o111~-~11ril1STA Given that the system demand on the Klamath Falls gate station on a design day is modeled to be 106% of physical capacity, the capacity shortfall at the Klamath Falls gate station primarily exists at temperatures near the design day temperature. (See TAC Meeting #3 materials, “City Gate Analysis Results,” for tables documenting the results of the most recent City Gate Analysis). 5. Evidence about projected loads and customers in the area Given that the City Gate Analysis used to determine the need for reinforcement or other remedy is based upon existing system load, gate station upgrade investment decisions are made upon the basis of existing customers, irrespective of projected loads and customers in the area. 6. Adequate consideration of alternatives, including the use of interruptibility or increased demand-side measures to improve reliability and system resiliency While it is true that loads can be interrupted or curtailed in the event of supply or capacity shortfalls, the City Gate Analysis performed to model gate station capacity deficits on design days consider only firm load. That is to say, Avista’s City Gate Analysis models presume that all interruptible customers have already been interrupted, and only firm loads are being served. Therefore, the capacity deficits shown in the City Gate Analysis could not be alleviated through interruption. Additionally, as discussed in the “Conservation Resources” section of Chapter 7 (Distribution Planning) of the IRP: The evaluation of distribution system constraints includes consideration of targeted conservation resources to reduce or delay distribution system enhancements. The consumer is still the ultimate decision-maker regarding the purchase of a conservation measure. Because of this, Avista attempts to influence conservation through the DSM measures discussed in Chapter 3 – Demand-Side Resources, but does not depend on estimates of peak day demand reductions from conservation to eliminate near-term distribution system constraints. Over the longer-term, targeted conservation programs may provide a cumulative benefit that could offset potential constraint areas and may be an effective strategy. Thus, while Avista certainly considers the importance of demand-side measures, and encourages such conservation programs, the conservation benefits accomplished by demand-side measures occur over a longer period than would be required to prudently address the existing, near-term gate station constraints. Avista Corp 2016 Natural Gas IRP Appendices 210 Sutherlin (#2626) Gate Station 1. A comprehensive cost-benefit analysis of whether and when the investment should be built Gate station upgrades are primarily driven by the City Gate Analysis (as discussed in the materials included in Appendix 7.1), whereby a capacity constraint impacting Avista’s ability to reliably serve customers drives investment needs. (Evidence regarding the inability to reliably serve customers on a design day is given in #4, below.) Given this, the threshold consideration regarding gate station investment is driven primarily by models indicating a capacity deficit on a design day, rather than a strict application of cost-benefit analysis. Said differently, to a customer, the loss of natural gas service on a design day (55 HDD, or average daily temperature of 10° Fahrenheit, in Roseburg) is not a question of cost-benefit, but rather of physical safety and comfort. 2. Evaluation of a range of alternative build dates and the impact on reliability and customer rates As discussed in #1, above, the identification of capacity shortfalls on a design day is the primary threshold consideration that establishes the need for and timing of planned completion. The number/scope of reinforcement projects that are completed in any given year may be constrained by such things as the availability of project management, skilled labor, and the need to complete other critical-path projects first in order to enable the functionality of the given project. Because of these constraints, the areas of concern within Avista’s natural gas distribution systems are risk-ranked against each other, to ensure that the areas of highest risk are corrected first. Given that the capacity constraint at the Sutherlin gate station (Station #2626) was modeled to be 102% on a design day as of the most recent City Gate Analysis (a relatively small capacity constraint), and the relative risk ranking compared with other natural gas distribution projects, this project has been included in planning considerations, with planned completion slated for 2019 or later. The assessed capacity constraint will continue to be regularly evaluated, and an increase in the assessed shortfall might warrant acceleration of the project, while a reduction in demand that eliminates the shortfall would defer the project. At existing rates, an incremental addition of $1 million to distribution gross plant would result in an increase in billed revenue to Oregon customers of approximately one-tenth of one percent of present billed revenue. 3. Credible evidence on the likelihood of disruptions based on historical experience As discussed in Chapter 7: Distribution Planning in the Natural Gas IRP, the distribution scenario decision-making process relies upon the analyses performed on each of Avista’s LDC systems under design day conditions to identify areas where potential outages may occur. Avista Corp 2016 Natural Gas IRP Appendices 211 Avista’s design heating degree day for distribution system modeling is determined using the coldest day on record for each given service area. This practice is consistent with the peak day demand forecast utilized in Avista’s natural gas Integrated Resource Plan, in the “Weather Forecast” section of Chapter 2, which explains the methodology for determining the peak day demand forecast as follows: The peak day demand forecast includes adjustments to average weather to reflect a five- day cold weather event. This consists of adjusting the middle day of the five-day cold weather event to the coldest temperature on record for a service territory…. The IRP, in the “Weather Forecast” section of Chapter 2, goes on to describe the coldest days on record for each of the Oregon service areas, stating the following: Medford experienced the coldest day on record, a 61 HDD, on Dec. 9, 1972. This is equal to an average daily temperature of 4 degrees Fahrenheit. Medford has experienced only one 61 HDD in the last 40 years; however, it has also experienced 59 and 58 HDD events on Dec. 8, 1972 and Dec. 21, 1990, respectively. The other three areas in Oregon have similar weather days. For Klamath Falls, a 72 HDD occurred on Dec. 8, 2013; in La Grande a 74 HDD occurred on Dec. 23, 1983; and a 55 HDD occurred in Roseburg on Dec. 22, 1990. As with Washington/Idaho and Medford, these days are the peak day weather standard for modeling purposes. The IRP also addresses the appropriateness of the use of the coldest day on record as the planning standard, stating, in the “Weather Forecast” section of Chapter 2: Utilizing a peak planning standard of the coldest temperature on record may seem aggressive given a temperature experienced rarely, or only once. Given the potential impacts of an extreme weather event on customers’ personal safety and property damage to customer appliances and Avista’s infrastructure, it is a prudent regionally accepted planning standard. While remote, peak days do occur, as on Dec. 8, 2013, when Avista matched the previous peak HDD [72 HDD] in Klamath Falls. Prior to the December 8, 2013 design heating degree day in Klamath Falls, Oregon, the previous design heating degree day in Klamath Falls had occurred on December 21, 1990. Further, in the 20 years preceding the completion of Avista’s 2012 Natural Gas IRP, the coldest day in 20 years in Klamath Falls had been a 64 heating degree day. These factors, along with the recent December 8, 2013 design heating degree day, demonstrate that the absence of a design heating degree day in the past 20 years does not mean that a design heating degree day will not happen. In fact, this further confirms that the design heating degree day is a prudent planning standard. 4. Evidence on the range of possible reliability incidents Avista Corp 2016 Natural Gas IRP Appendices 212 ,o111~-~11ril1STA Given that the system demand on the Sutherlin gate station on a design day is modeled to be 102% of physical capacity, the capacity shortfall at the Klamath Falls gate station primarily exists at temperatures near the design day temperature. (See TAC Meeting #3 materials, “City Gate Analysis Results,” for tables documenting the results of the most recent City Gate Analysis). 5. Evidence about projected loads and customers in the area Given that the City Gate Analysis used to determine the need for reinforcement or other remedy is based upon existing system load, gate station upgrade investment decisions are made upon the basis of existing customers, irrespective of projected loads and customers in the area. 6. Adequate consideration of alternatives, including the use of interruptibility or increased demand-side measures to improve reliability and system resiliency While it is true that loads can be interrupted or curtailed in the event of supply or capacity shortfalls, the City Gate Analysis performed to model gate station capacity deficits on design days consider only firm load. That is to say, Avista’s City Gate Analysis models presume that all interruptible customers have already been interrupted, and only firm loads are being served. Therefore, the capacity deficits shown in the City Gate Analysis could not be alleviated through interruption. Additionally, as discussed in the “Conservation Resources” section of Chapter 7 (Distribution Planning) of the IRP: The evaluation of distribution system constraints includes consideration of targeted conservation resources to reduce or delay distribution system enhancements. The consumer is still the ultimate decision-maker regarding the purchase of a conservation measure. Because of this, Avista attempts to influence conservation through the DSM measures discussed in Chapter 3 – Demand-Side Resources, but does not depend on estimates of peak day demand reductions from conservation to eliminate near-term distribution system constraints. Over the longer-term, targeted conservation programs may provide a cumulative benefit that could offset potential constraint areas and may be an effective strategy. Thus, while Avista certainly considers the importance of demand-side measures, and encourages such conservation programs, the conservation benefits accomplished by demand-side measures occur over a longer period than would be required to prudently address the existing, near-term gate station constraints. Avista Corp 2016 Natural Gas IRP Appendices 213 1 1 2016 Avista Natural Gas IRP Technical Advisory Committee Meeting January 21, 2016 Portland, Oregon St. Helens A Avista Corp 2016 Natural Gas IRP Appendices 214 2 2 Agenda •Introductions & Logistics •Purpose of IRP and Avista’s IRP Process •Avista’s Demand Overview and 2014 IRP Revisited •Economic Outlook and Customer Count Forecast •Demand Forecast Methodology •Dynamic Demand Forecasting •Demand Side Management •Questions/Wrap Up Avista Corp 2016 Natural Gas IRP Appendices 215-'II._ ,11fillSTA" 3 3 2016 IRP Timeline •August 31, 2015 –Work Plan filed with WUTC •January through April 2016 –Technical Advisory Committee meetings. Meeting topics will include: –Demand Forecast and Demand Side Management – January 21 –Supply/Infrastructure, Natural Gas Pricing, and Potential Case Discussion–February 18 –Distribution Planning, SENDOUT® Preliminary Output Results and Further Case Discussion –March 16 –SENDOUT® results –April 21 •May 30, 2016 –Draft of IRP document to TAC •June 30, 2016 –Comments on draft due back to Avista •July 2016 –TAC final review meeting (if necessary) •August 31, 2016 –File finalized IRP document Avista Corp 2016 Natural Gas IRP Appendices 216-'II._ ,11fillSTA" 4 4 Purpose of Gas Integrated Resource Planning •Comprehensive long-range resource planning tool •Fully integrates forecasted demand requirements with potential demand side and supply side resources •Process determines the least cost, risk adjusted means for meeting demand requirements for our firm residential, commercial and industrial customers •Responsive to Idaho, Oregon and Washington rules and/or orders Avista Corp 2016 Natural Gas IRP Appendices 217-'II._ ,11fillSTA" 5 5 Avista’s IRP Process •Comprehensive analysis bringing demand forecasting and existing and potential supply-side and demand-side resources together into a 20-year, risk adjusted least-cost plan •Considers: –Customer growth and usage –Weather planning standard –Demand-side management opportunities –Existing and potential supply-side resource options –Risk –Public participation through Technical Advisory Committee meetings (TAC) –Distribution upgrades •2014 IRP filed in all three jurisdictions on August 31, 2014 and acknowledgedAvista Corp 2016 Natural Gas IRP Appendices 218-'II._ ,11fillSTA" 6 6 Avista’s Demand Overview and 2014 IRP Re- Visited Tom Pardee Manager of Natural Gas Planning Avista Corp 2016 Natural Gas IRP Appendices 219 7 7 Avista’s Demand Overview Avista Corp 2016 Natural Gas IRP Appendices 220-'II._ ,11fillSTA" 8 8 –Population of service area 1.5 million 371,000 electric customers 330,000 natural gas customers •Has one of the smallest carbon footprints among America’s 100 largest investor-owned utilities •Committed to environmental stewardship and efficient use of resources Service Territory and Customer Overview •Serves electric and natural gas customers in eastern Washington and northern Idaho, and natural gas customers in southern and eastern Oregon State Total Customers % of Total Washington 156,000 46% Oregon 99,000 30% Idaho 79,000 24% Total 334,000 100%Avista Corp 2016 Natural Gas IRP Appendices 221 1010 2015 Customer Make Up and Demand Mix 88.44% 11.54%0.03% Customer Make Up Oregon 89.99% 9.91%0.10% Customer Make up WA-ID 62.9% 35.7% 1.4% Annual Demand WA-ID 64.2% 35.5% 0.3% Annual Demand Oregon Avista Corp 2016 Natural Gas IRP Appendices 222 1111 Historical Demand Mix 0% 20% 40% 60% 80% 100% 2015 2014 2013 2012 2011 2010 Industrial 1%2%1%1%2%2% Commercial 36%36%36%36%37%37% Residential 63%63%63%63%61%61% WA-ID 0% 20% 40% 60% 80% 100% 2015 2014 2013 2012 2011 2010 Industrial 0%0%0%0%0%0% Commercial 36%38%37%38%37%37% Residential 64%62%63%62%63%63% Medford/Roseburg 0% 20% 40% 60% 80% 100% 2015 2014 2013 2012 2011 2010 Industrial 1%1%1%1%0%0% Commercial 32%32%32%32%32%34% Residential 67%67%68%67%67%66% Klamath Falls 0% 20% 40% 60% 80% 100% 2015 2014 2013 2012 2011 2010 Industrial 0%0%0%0%0%0% Commercial 38%37%37%36%37%37% Residential 62%63%63%64%63%63% LaGrande Avista Corp 2016 Natural Gas IRP Appendices 223 1212 Seasonal Demand Profiles Avista Corp 2016 Natural Gas IRP Appendices 224 3,000,000 2,500,000 "'2,000,000 E .. Cl -; 1,500,000 _g c!! 1,000,000 500,000 160,000 140,000 120,000 "' 100,000 E .. Cl ~ 80,000 .. _g c!! 60,000 40,000 20,000 Washington/Idaho Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Klamath Falls Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec -Residential 600,000 500,000 "' 400,000 E .. Cl -; 300,000 _g c! 200,000 100,000 70,000 60,000 50,000 "' E 40,000 .. Cl ~ .. _g 30,000 c!! 20,000 10,000 Medford/Roseburg Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec LaGrande Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Commercial -Industr ial 1313 Daily Demand Profiles 0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 020406080100 De k a t h e r m s 2015 Average Temp (°F) Medford/Roseburg Avista Corp 2016 Natural Gas IRP Appendices 225 1414 Avista’s 2014 Natural Gas IRP Re-Visited Avista Corp 2016 Natural Gas IRP Appendices 226-'II._ ,11fillSTA" 1515 Avista Corp 2016 Natural Gas IRP Appendices 227 16 14 12 10 .. II E 0 .. "' ::I 8 u .. cf II :5 6 4 2 Washington/Idaho I RP Forecast vs. Actual (Residential Use per Customer and Customer Count) Nov-14 Dec-14 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep~lS Oct-15 Nov-15 Dec-15 -IRP customers -Actual 0Ustome1s IRP Foi"eca'5t -weather Hormaliz;ed -Actual u PC 210,000 180,000 150,000 .. C ::I 120,000 8 .. II E 0 -.. 90,0C:O ::I u 60,0C:O 30,0C:O 0 1616 Avista Corp 2016 Natural Gas IRP Appendices 228 14 12 10 ... 4;J 8 E 0 -... :, u ... t 4;J 6 :5 4 2 Oregon IRP Forecast vs. Actual (Residential Use per Customer and Customer Count) Nov-14 Dec-14 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec-15 -IRP customers -Actual customers I RP Forecast weather Normalized -Actual UPC 90,000 80,000 70,000 60,000 .. 50,000 C :, 8 ... &I E 0 .. 40,000 .. :, u 30,000 20,000 10,000 1717 Avista Corp 2016 Natural Gas IRP Appendices 229 80 70 60 50 .. 4J E 0 .. ... = 40 u .. ~ 4J ::S 30 20 10 Washington/Idaho IRP Forecast vs. Actual (Commercial Use per Customer and Customer Count) Nov-14 Dec-14 Jan-15 f eh-1 5 M ar-15 Apr-15 M ay-15 Jun-15 Jul-15 A ug-15 Sep-15 Oct-15 Nov-15 Dec-15 -IRP CUstomE'rS -Actual OUstomers I RP Forecast w eather r,iormalm!d -Actual UPC 25,000 20,000 15,000 .. C: = 8 .. ll E 0 .. .. = u 10,000 5,000 0 1818 Avista Corp 2016 Natural Gas IRP Appendices 230 60 50 40 .. 4J E 0 .. "' ::, 30 u .. .f 4J :S 20 10 Oregon IRP Forecast vs. Actua l (Commercial Use per Customer and Customer Count) Nov-14 Dec-14 Jan-15 Feb-15 M ar-15 Apr-15 May-1 5 Jun-15 Ju l-15 A ug-15 Sep-15 Oct-15 Nov-15 Dec-15 -IRP customers -Actu;al customers -~ IRP Forecast w ea t her Mormalized --Actual UPC 12,000 10,000 8,000 .. C ::, 8 6,000 .. 4J E 0 .. "' ::, u 4,000 2,000 1919 Avista Corp 2016 Natural Gas IRP Appendices 231 350 300 250 .. 4J 200 E 0 .. .. = u .. ~ 4J 150 ::S 100 50 Washington/Idaho IRP Forecast vs. Actual {Industrial Use per Customer and Customer Count) Nov-14 Dec-14 Jan-15 feh-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-1 5 Sep-15 Oct-15 Nov-15 Dec-15 -IRP OUstomers -Actual OUstomers I RP Foreca5t w eather r,iorrnalized -Actual u PC 200 .. C: = 8 150 .. ll E 0 .. "' = u 100 2020 Avista Corp 2016 Natural Gas IRP Appendices 232 450 400 350 300 .. Qj E 0 250 .. ... ::::t u .. .f 200 Qj :S 150 100 50 Oregon IRP Forecast vs. Actua l {Industrial Use per Customer and Customer Count) Nov-14 Dec-14 Ja n-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec-15 -IRP customers -Actual customers IRP Forecast We:ather t,1orm.alized --Actual UPC 40 35 30 25 .. C ::::t 8 20 .. Qj E 0 .. "' ::::t u 1 5 10 5 2121 Year First Unserved Scenario Comparisons Avista Corp 2016 Natural Gas IRP Appendices 233 2222 Best Cost/Risk Resources Expected Case –WA/ID 0 50,000 100,000 150,000 200,000 250,000 300,000 350,000 400,000 Dth Existing GTN Existing NWP Spokane Supply GTN Capacity Add Peak Day Demand Current Short Figure 1.10 - Expected Case - WA/ID Selected Resources vs. Peak Day Demand (Net of DSM ) FEB 15 Avista Corp 2016 Natural Gas IRP Appendices 234 2323 Best Cost/Risk Resources Expected Case –Medford/Roseburg Avista Corp 2016 Natural Gas IRP Appendices 235 2424 Best Cost/Risk Resources Expected Case –Klamath Falls Avista Corp 2016 Natural Gas IRP Appendices 236 2525 Our Biggest Risk Last IRP “Flat Demand” Risk Avista Corp 2016 Natural Gas IRP Appendices 237 2626 Near Term Action Items •Demand trend monitoring •Demand side management cost effectiveness and targets •Gate station analysis On-going Action Items •Price elasticity study inquiry •NGV/CNG and other demand potential •Supply side resource trends/availability •Meet regularly with Commission Staff Avista Corp 2016 Natural Gas IRP Appendices 238-'II._ ,11fillSTA" 2727 Avista Natural Gas Forecasting Grant D. Forsyth, Ph.D. Chief Economist Grant.Forsyth@avistacorp.com Avista Corp 2016 Natural Gas IRP Appendices 239 2828 Load Forecasts-Two Step Process •First, forecast customers (C) by month by schedule (s) by residential (r), commercial (c), industrial (i)—for example, Ct,y,s.r •Forecast use per customer (U) by month by schedule by class—for example, Ut,y,s.r •Load forecast (L) is the product of the two: Lt,y,s.r = Ct,y,s.r X Ut,y,s.r For weather sensitive schedules a 20-yr MA defines normal weather. Avista Corp 2016 Natural Gas IRP Appendices 240 2929 The Basic Forecast Approach Population Growth Forecast Residential Customer Forecast ARIMA Model Commercial Customer ARIMA Forecast Model Vary Population Growth Assumptions Firm Residential and Commercial Firm Industrial No Drivers Forecast of no Significant Growth Vary “No Growth” Assumption Avista Corp 2016 Natural Gas IRP Appendices 241 3030 System Industrial Customers, 2004-2015 260 280 300 320 340 360 380 400 Ja n -04 Ju l -04 Ja n -05 Ju l -05 Ja n -06 Ju l -06 Ja n -07 Ju l -07 Ja n -08 Ju l -08 Ja n -09 Ju l -09 Ja n -10 Ju l -10 Ja n -11 Ju l -11 Ja n -12 Ju l -12 Ja n -13 Ju l -13 Ja n -14 Ju l -14 Ja n -15 Ju l -15 No real change since January 2007 Avista Corp 2016 Natural Gas IRP Appendices 242 3131 Getting to Population as a Driver, 2016-2021 & 2022-2035 Average GDP Growth Forecasts: •IMF, FOMC, Bloomberg, etc. •Average forecasts out 5-yrs. Non-farm Employment Growth Model: •Model links year y, y-1, and y-2 GDP growth to year y regional employment growth. •Forecast out 5-yrs. •Averaged with GI forecasts. Regional Population Growth Models: •Model links regional, U.S., and CA year y-1 employment growth to year y county population growth. •Forecast out 6-yrs for Spokane, WA; Kootenai, ID; and Jackson, OR. •Averaged with IHS forecasts. •Growth rates used to generate population forecasts for customer forecasts for residential schedules 101 and 410. EMPGDP 2016-2021 For Spokane, WA; Kootenai, ID, and Jackson, OR counties OR Douglas, Klamath, and Douglas counties: IHS population growth forecasts for 2016-2035 Kootenai and Jackson: IHS population growth forecasts for 2022-2035 Spokane: OFM population growth forecasts for 2022-2035 Interpolation assumes: PN = P0erN Avista Corp 2016 Natural Gas IRP Appendices 243 3232 The Relationship Between Classes Customers Residential Commercial Industrial Load Residential Commercial Industrial Residential 1.00 Residential 1.00 Commercial 0.83 1.00 Commercial 0.94 1.00 Industrial -0.44 -0.35 1.00 Industrial 0.33 0.34 1.00 Year-over-year Growth, Gas Correlations by Class, Jan. 2006-May 2013 Residential customer growth is approximately equal to population growth in the long-run. Commercial customer growth is highly correlated with residential growth in the long-run. Industrial’s correlation to residential is lower and negative. Customer numbers stable or slightly declining. Avista Corp 2016 Natural Gas IRP Appendices 244 3333 WA-ID Region Firm Customers: 2016 IRP and 2014 IRP 210,000 220,000 230,000 240,000 250,000 260,000 270,000 280,000 290,000 300,000 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 WA-ID-Base 2014 WA-ID-Base +5,500 IRP Avg.Annual Growth 2016-2035 2014 1.0% 2016 1.1% Avista Corp 2016 Natural Gas IRP Appendices 245 3434 OR Region Firm Customers: 2016 IRP and 2014 IRP 80,000 85,000 90,000 95,000 100,000 105,000 110,000 115,000 120,000 125,000 130,000 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 OR-Base 2014 OR-Base IRP Avg.Annual Growth 2016-2035 2014 0.9% 2016 1.2% +7,000 Avista Corp 2016 Natural Gas IRP Appendices 246 3535 System Firm Customers: 2016 IRP and 2014 IRP 300,000 320,000 340,000 360,000 380,000 400,000 420,000 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 WA-ID-OR-Base 2014 WA-ID-OR-Base +12,500 IRP Avg.Annual Growth 2016-2035 2014 1.0% 2016 1.1% Avista Corp 2016 Natural Gas IRP Appendices 247 3636 WA-ID Region Firm Customer Range, 2016-2035 210,000 230,000 250,000 270,000 290,000 310,000 330,000 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 WA-ID-Base WA-ID-High WA-ID-Low Variable Low Growth Base Growth High Growth Customers 0.6%1.1%1.5% WA Population 0.4%0.8%1.2% ID Population 1.0%1.5%2.0% WA-ID Population 0.6%1.0%1.4% Avista Corp 2016 Natural Gas IRP Appendices 248 3737 OR Region Firm Customer Range, 2016-2035 80,000 90,000 100,000 110,000 120,000 130,000 140,000 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 OR-Base OR-High OR-Low Variable Low Growth Base Growth High Growth Customers 0.7%1.2%1.6% Population 0.4%0.8%1.3% Avista Corp 2016 Natural Gas IRP Appendices 249 3838 System Firm Customer Range, 2016-2035 300,000 320,000 340,000 360,000 380,000 400,000 420,000 440,000 460,000 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 WA-ID-OR-Base WA-ID-OR-High WA-ID-OR-Low Variable Low Growth Base Growth High Growth Customers 0.7%1.1%1.5% Population 0.5%0.9%1.3% Avista Corp 2016 Natural Gas IRP Appendices 250 3939 Summary of Growth Rates System Base-Case High Low Res 1.2%1.6%0.7% Com 0.7%1.1%0.2% Ind 0.0%0.4%-0.4% Total 1.1%1.5%0.7% WA Base-Case High Low Res 1.0%1.4%0.6% Com 0.7%1.1%0.3% Ind 0.0%0.3%-0.2% Total 1.0%1.4%0.6% ID Base-Case High Low Res 1.4%1.8%0.9% Com 0.4%0.9%-0.1% Ind 0.0%0.3%-0.3% Total 1.3%1.7%0.8% OR Base-Case High Low Res 1.2%1.6%0.8% Com 0.8%1.2%0.3% Ind 0.0%1.1%-1.4% Total 1.2%1.6%0.7% Avista Corp 2016 Natural Gas IRP Appendices 251 4040 Demand Forecast Methodology Tom Pardee Manager of Natural Gas Planning Avista Corp 2016 Natural Gas IRP Appendices 252 4141 Natural Gas Demand Forecasting Financial Planning and Analysis Resource Accounting Gas Supply Rates Regulatory Staff Industry Stakeholders Average Demand Procurement Planning PGA Corporate Budget IRP Peak Day Planning IRP Scenario Analysis Other Avista Corp 2016 Natural Gas IRP Appendices 253 4242 Natural Gas Demand Forecast Use per Customer Weather Forecast Customer Forecast What goes into the Natural Gas Demand Forecast? Avista Corp 2016 Natural Gas IRP Appendices 254 4343 Customer Forecast by Class Start with national economic forecasts then drill down to regional economies Population growth expectations and employment Company-specific knowledge about sub-regional construction activity, trends and historical data The Customer Forecast Avista Corp 2016 Natural Gas IRP Appendices 255 4444 Weather Forecast Most recent 20 year HDD’s Planning Standard Other The Weather Forecast Avista Corp 2016 Natural Gas IRP Appendices 256 4545 Weather •NOAA 20 year actual average daily HDD’s (1996- 2015) •Peak weather includes two winter storms (5 day duration), one in December and one in February •Planning Standard –coldest day on record •Sensitivity around planning standard including –Normal/Average –Coldest in 20 years –Monte Carlo simulation Avista Corp 2016 Natural Gas IRP Appendices 257-'II._ ,11fillSTA" 4646 Use per Customer Most recent year(s) of historical use: •“Big Meter” Data •5 Areas •Allocated based on “little meter” data Determine Base Demand Determine Heat Demand Determine “Super Peak” Demand The Use per Customer Forecast Avista Corp 2016 Natural Gas IRP Appendices 258 4747 The Use per Customer Forecast cont. •Historical data is used to determine initial base and heat coefficients. •Adjustments are made to incorporate DSM and price elastic responses. Avista Corp 2016 Natural Gas IRP Appendices 259 4848 Avista Corp 2016 Natural Gas IRP Appendices 260 u ise per Custom e1rper HDD WA ID Resident ial 0 .0 120 ~-----------~---------------------- 0 .0118 O.Ol.l.6 0 0 .011.4 Q ::c 8. 0 .0112 .. ~ 0 .0 110 0 .. U!j = u 0 .0 108 .. i ~ O.Ol.06 5 0 .0101 0 .0 102 0 .0 100 2006 2007 2008 2009 2010 2011 20 12 -A ct ual Use/Customer/HOD -5 Year Avg -3 Year Avg 2013 2014 Last Vear 2015 4949 Avista Corp 2016 Natural Gas IRP Appendices 261 0.0145 0.0140 0.0135 Q Q :c 0.0130 ... i ... 0.0125 G,l E C .. Ill 0.0120 = u ... l 0.0115 G,l :5 0.0110 0.0105 0.0100 2005 2007 Ulse per Customer per HDID Medford Res idential 2008 2009 2010 2011 2012 -Act ual Use/Customer/HDD -5 Yie,ar Avg -3 Yie,ar Avg 2013 2014 2015 5050 Avista Corp 2016 Natural Gas IRP Appendices 262 0.019 O.Ol.8 0.017 1C rC O.Ol.6, % ~ 8. ~ 4;1 0.015 E 0 -"" = u O.Ol.4 ~ 8. -= 1i5 0 .013 0 .012 0 .011 O.Ol.O 2006 2007 Use pe r Cust o m e r per HDD Rosebu rg Resid e nt ia l 2008 2010 2011 20 12 -Actual U.se/Cu.stomer/HDD -s Year Av g -3 Year Avg 2013 2014 2015 La.st Year 5151 Avista Corp 2016 Natural Gas IRP Appendices 263 0 .0 1 7 0 .0 1 6 0 .0 1 5 0 0 0 .0 14 ::z: .. i .. G.,1 0 .0 1 3 E C -[I.I = 0 .0 1 2 u .. i -= 0 .0 1 1 5 0 .0 1 0 0 .009 0 .008 2006, 2007 Ulse per Customerper HDD LaGrande Residentia l 20 08 2009 2010 20:11 20 12 -A ctu al l.11.se/Cu.stomer/HDD -5 Ye ar Avg -3 Ye ar Avg 2013 2014 L ast Ye ar 2015 5252 Avista Corp 2016 Natural Gas IRP Appendices 264 C Q ::c .. l .. ~ E 0 -(I.I = u .. l .: Q u ise per Customer per HDD Klamath !Falls Reside nt ia l 0 .0108 -,----------------------------------- 0 .0101 ------------------------------- 0 .0100 0 .0096 0 .0092 0 .0088 0 .0084 0 .0080 2006 2007 2008 -Act ual lJlse/Cust.om er/HDD 2003 2010 2011 2012 --5 Year Avg -3 YearAvg 2013 2014 Last Vear 2015 5353 Demand Modeling Equation –a closer look SENDOUT® requires inputs expressed in the below format to compute daily demand in dekatherms. The base and weather sensitive usage (degree-day usage) factors are developed outside the model and capture a variety of demand usage assumptions. # of customers x Daily weather sensitive usage / customer # of customers x Daily base usage / customer Plus Table 3.2 Basic Demand Formula Avista Corp 2016 Natural Gas IRP Appendices 265 5454 1.Customer annual growth rates: 2.Use per customer coefficients –Flat all classes,5 year, 3 year or last year average use per HDD per customer 3.Weather planning standard –coldest day on record WA/ID 82; Medford 61; Roseburg 55; Klamath 72; La Grande 74 Developing a Reference Case Customer count forecast Use per customer coefficients Weather Reference Case Demand Avista Corp 2016 Natural Gas IRP Appendices 266 5555 Dynamic Demand Methodology Tom Pardee Manager of Natural Gas Planning Avista Corp 2016 Natural Gas IRP Appendices 267 5656 Dynamic Demand Methodology Demand Influencing –Conditions that DIRECTLY affect core customer volume consumed Price Influencing –PRICE SENSITIVE conditions that, through price elasticity, INDIRECTLY affect core customer volume consumed Avista Corp 2016 Natural Gas IRP Appendices 268 5757 Demand Customer Growth •New Construction •Conversion/Direct Use •Economy Customer Mix Shifts •Res/Com/Ind •Core vs. Transport •Interruptible Weather •Normal •Planning Standard •Other Technology •Increased efficiency/DSM •New Uses •Demand Response 3rd Party Demand Trends •Thermal Generation •Non-Core Customer •LNG Exports Supply Trends •Conventional vs. Unconventional •Canadian Imports •LNG Pipeline Trends •Regional Pipeline Projects •National Pipeline Projects •International Pipeline Projects Other •Storage •Climate Change Legislation •Energy Correlations (i.e. oil and gas) Demand Drivers Avista Corp 2016 Natural Gas IRP Appendices 269 5858 Customer Growth and Mix –Demand Influencing •Key driver in demand growth •Can change the timing and/or location of resource needs •Currently we model expected, high, and low growth scenarios •New construction vs. conversions •Residential/Commercial/Industrial vs. Transportation •New uses –CNG/NGV Avista Corp 2016 Natural Gas IRP Appendices 270-'II._ ,11fillSTA" 5959 Weather Standard –Demand Influencing •Has the potential to significantly change timing of resource needs •Significant qualitative considerations –No infrastructure response time if standard exceeded –Significant safety and property damage risks •Current Peak HDD Planning Standards –WA/ID 82 –Medford 61 –Roseburg 55 –Klamath 72 –La Grande 74 Avista Corp 2016 Natural Gas IRP Appendices 271-'II._ ,11fillSTA" 6060 Technology –Demand Influencing •Demand side management initiatives will reduce demand HOWEVER, it is dependent upon customers willingness/ability to participate. •Development of new uses for natural gas •CNG •NGV •LNG •???NG •Demand response (Smart Grid) •New technologies in Demand Side Management Avista Corp 2016 Natural Gas IRP Appendices 272-'II._ ,11fillSTA" 6161 Price Elasticity Factors Defined •Price elasticity is usually expressed as a numerical factor that defines the relationship of a consumer’s consumption change in response to price change. •Typically, the factor is a negative number as consumers normally reduce their consumption in response to higher prices or will increase their consumption in response to lower prices. •For example, a price elasticity factor of -0.13 means: –A 10% price increase will prompt a 1.3% consumption decrease –A 10% price decrease will prompt a 1.3% consumption increaseAvista Corp 2016 Natural Gas IRP Appendices 273-'II._ ,11fillSTA" 6262 Price Elasticity •Establishes factors for use in other price influencing scenarios •Very complex relationship –we use historical data however…… •Historical data has DSM, rate changes (PGA, general rate, etc.), economic conditions, technological changes, etc. •History is not necessarily the best predictor of future behavior Avista Corp 2016 Natural Gas IRP Appendices 274-'II._ ,11fillSTA" 6363 2007 AGA Study Results •American Gas Assn Study –National results •Short-run -0.09 •Long-run -0.18 –Pacific & Mtn Region results •Short-run -0.07 & -0.07 •long-run -0.12 & -0.10 –Min-Max range •Short-run +0.01 to - 0.13 •Long-run -.01 to -.29 •Avista Specific Results –Oregon •Short-run -0.08 •long-run -0.13 –Idaho •Short-run -0.05 •long-run -0.10 –Washington •Short-run -0.12 •long-run -0.14 Avista Corp 2016 Natural Gas IRP Appendices 275-'II._ ,11fillSTA" 6464 Price Elasticity Assumptions From 2014 IRP Elasticity Assumption Real Price annual increase within 30% High Negative .20 Expected Negative .15 Low No response Avista Corp 2016 Natural Gas IRP Appendices 276 6565 3rd Party Demand Trends –Price Influencing •Gas fired generation –the largest contributor to future growth •Coal plant retirements driving gas for power •CNG/NGV Transportation Fleets •Export LNG •Non-firm customer trends Avista Corp 2016 Natural Gas IRP Appendices 277-'II._ ,11fillSTA" 6666 Supply Trends –Price Influencing •Shale is Everywhere •LNG Export •Basis -Location, location, location Avista Corp 2016 Natural Gas IRP Appendices 278-'II._ ,11fillSTA" 6767 Pipeline Trends –Price Influencing •Regional Pipeline Proposals •N-Max/Palomar –cross Cascades pipeline (NWN, GTN and NWP) •Pacific Connector –from Jordan Cove LNG to various interconnects in the Pacific Northwest (Williams, Fort Chicago Energy Partners, and PG&E) •Trail West (GTN to NWP –Molalla area) •National Pipeline Proposals •International Pipeline Proposals (GTN to NWP Avista Corp 2016 Natural Gas IRP Appendices 279-'II._ ,11fillSTA" 6868 Other Supply Issues –Price Influencing •Storage •Climate Change and Carbon Legislation •Energy Correlations Avista Corp 2016 Natural Gas IRP Appendices 280-'II._ ,11fillSTA" 6969 Sensitivities, Scenarios, Portfolios Sensitivities Demand Supply Scenarios Group demand drivers into meaningful sets Group supply drivers into meaningful sets Portfolios Bringing together demand and supply scenarios Avista Corp 2016 Natural Gas IRP Appendices 281 7070 Demand Sensitivities from 2014 IRP What do we want to consider for 2016? Avista Corp 2016 Natural Gas IRP Appendices 282 Model Sensitivities DEMAND INFLUENCING -DIRECT PRICE INFLUENCING -INDIRECT Alterante Reference Peak plus Historical Reference Plus Peak LowCust High Cusl CNG/NGV Atternate DSM DSM UPC Expect Low High Carbon Exported INPUT ASSUMPTIONS Case Case Grov.1h Growth Vehicles Weather Ste Case Case Case Elasticity Prices Prices Legistlation LNG Customer Growth Rate Residential WA/ID Residential Medford Residential Roseburg Residential Klamath Residential La Grande Commercial WA/ID Commercial Medford Commercial Roseburg Commercial Klamath Commercial La Grande Use per Customer 3 Year 3Year 3Year 3Year 15% Growth 3Year 3Year 3Year 5Year 3Year 3Year 3Year 3 Year 3Year Historical Historical Historical Historical Cumulative Historical Historical Historical Historical Historical Historical Historical Historical Historical Weather 20 Year Coldest on Coldest on Coldest on Coldest on Coldest on Coldest on Coldest on Coldest on Coldest on Coldest on Coldest on Planning Standard Normal Record Record Record Record ~oldest 20yr. Normal Record Record Record Record Record Record Record Demand Side Management Programs I nclucled No No No No No No Expected Expected No No No No No No Prices Price curve Expected Expected Expected Expected Expected Expected Expected Expected Expected Expected Low High Expected Expected Price curve adder ($/Dth) None None None None None None None None None S.50 Adder After Syrs Elasticity None None None None None None None None None Expected Expected Expected Expected Expected Carbon Adder ($.IT on) None None None None None None None None None 7171 Mix and Match to Make Scenarios Avista Corp 2016 Natural Gas IRP Appendices 283 7272 The Goal –A Bunch of Meaningful Lines Avista Corp 2016 Natural Gas IRP Appendices 284 7373 Forecast Methodology Considerations •Know the goal –what is the purpose of the forecast? •Know your data –what you have, what you need •Is there sufficient quantitative data available? •Is the change small or large? •Is their conflict among decision makers? •Are the relationships among variable complicated? •Have there been similar situations? Avista Corp 2016 Natural Gas IRP Appendices 285-'II._ ,11fillSTA" 7474 Demand Side Management Mike Dillon DSM Planning and Analytics Manager Avista Corp 2016 Natural Gas IRP Appendices 286 7575 Agenda •DSM in the last IRP –Target/Acquisition •What’s happened since the last IRP •What’s different with avoided costs? •Proposed DSM modeling methodology •Business planning process Avista Corp 2016 Natural Gas IRP Appendices 287-'II._ ,11fillSTA" 7676 DSM in the 2014 IRP –Annual (WA/ID) Avista Corp 2016 Natural Gas IRP Appendices 288 7777 DSM in the 2014 IRP –Peak Day (WA/ID) Avista Corp 2016 Natural Gas IRP Appendices 289 7878 DSM in the 2014 IRP –Annual (OR) Avista Corp 2016 Natural Gas IRP Appendices 290 7979 DSM in the 2014 IRP –Peak Day (OR) Avista Corp 2016 Natural Gas IRP Appendices 291 8080 2014 IRP DSM Targets •2015 targets & (Unverified) acquisition (achievable potential) •OPUC established “minimum” target State Therms Target % Achieved Idaho --- Oregon 207,036 161,000 128.6% Washington 780,530 602,010 129.7% Avista Corp 2016 Natural Gas IRP Appendices 292 8181 Recap of Recent History •Relook at components of conservation avoided costs and compare with other gas utilities –Include total cost to deliver from well to meter (Schedule 150 Demand) –Estimated Carbon Tax in Washington (assumptions could already be dated) –Working with Natural Gas Planning on analyzing the value of conservation in deferring pipeline investments •Idaho –Schedule 190 resumed 1/1/16 •Oregon –As part of GRC, Oregon non-LI transition to ETO •Washington –Proposed Initiatives, Potential Legislation and Executive Orders… Oh My! Avista Corp 2016 Natural Gas IRP Appendices 293-'II._ ,11fillSTA" 8282 Henry Hub vs. Levelized Avoided Costs 0 2 4 6 8 10 12 14 16 Ja n - 0 5 Ma y - 0 5 Se p - 0 5 Ja n - 0 6 Ma y - 0 6 Se p - 0 6 Ja n - 0 7 Ma y - 0 7 Se p - 0 7 Ja n - 0 8 Ma y - 0 8 Se p - 0 8 Ja n - 0 9 Ma y - 0 9 Se p - 0 9 Ja n - 1 0 Ma y - 1 0 Se p - 1 0 Ja n - 1 1 Ma y - 1 1 Se p - 1 1 Ja n - 1 2 Ma y - 1 2 Se p - 1 2 Ja n - 1 3 Ma y - 1 3 Se p - 1 3 Ja n - 1 4 Ma y - 1 4 Se p - 1 4 Ja n - 1 5 Ma y - 1 5 Se p - 1 5 Monthly Henry Hub vs. Levelized IRP Avoided Costs Monthly Henry Hub Prices $/MMBTU 2014 Average IRP Levelized AC 2012 Average IRP Levelized AC 2009 Average IRP Levelized AC Avista Corp 2016 Natural Gas IRP Appendices 294 8383 Proposed DSM Modeling Methodology Initial Sendout Run (AVA) Preliminary Avoided Costs (AVA) Initial Loadmap Run (AEG) Initial CE Calcs (AEG) Initial DSM Potential (AEG) Feed new potential in SENDOUT (AVA) Iterate Sendout till Avoided Cost Convergence (AVA) Feed LoadMAP with final Avoided Costs (AEG) Final CE Calcs (AEG)DSM Potential Avista Corp 2016 Natural Gas IRP Appendices 295 8484 Business Planning Process •IRP generated target (CPA achievable potential) •Bottom-up evaluation of all measures regardless of cost-effectiveness •Forecast throughput for the following year •Add in non-incentive utility costs •Evaluate with final avoided costs •Update Business Plan Annually for through put, estimated budgets and cost-effectiveness by state and fuel. Avista Corp 2016 Natural Gas IRP Appendices 296-'II._ ,11fillSTA" 8585 2016 IRP Timeline •August 31, 2015 –Work Plan filed with WUTC •January through April 2016 –Technical Advisory Committee meetings. Meeting topics will include: –Demand Forecast and Demand Side Management –January 21 –Supply/Infrastructure, Natural Gas Pricing, and Potential Case Discussion–February 18 –Distribution Planning, SENDOUT® Preliminary Output Results and Further Case Discussion –March 16 –SENDOUT® results –April 21 •May 30, 2016 –Draft of IRP document to TAC •June 30, 2016 –Comments on draft due back to Avista •July 2016 –TAC final review meeting (if necessary) •August 31, 2016 –File finalized IRP document Avista Corp 2016 Natural Gas IRP Appendices 297-'II._ ,11fillSTA" 8686 Tentative Agenda for the Next TAC Meeting •Natural Gas Prices •Supply Side Resources (Current and Future) •Transportation •Storage •Other •Gate Station Analysis Avista Corp 2016 Natural Gas IRP Appendices 298-'II._ ,11fillSTA" 1 2016 Avista Natural Gas IRP Technical Advisory Committee Meeting February 18, 2016 Spokane, WA Avista Corp 2016 Natural Gas IRP Appendices 299 22 Agenda •Introductions & Logistics •Update from TransCanada and Williams •Regional and Avista’s Supply Side Resources •Storage and Transportation Optimization •Transport Modeling in Sendout •Solving Unserved Demand •Carbon Legislation 2 Avista Corp 2016 Natural Gas IRP Appendices 300-'II._ ,11fillSTA" 33 2016 IRP Timeline •August 31, 2015 –Work Plan filed with WUTC •January through April 2016 –Technical Advisory Committee meetings. Meeting topics will include: –Demand Forecast and Demand Side Management –January 21 –Supply/Infrastructure and Potential Case Discussion– February 18 –Distribution Planning, Natural Gas Pricing, SENDOUT® Preliminary Output Results and Further Case Discussion – March 30 –SENDOUT® results –April 21 •May 30, 2016 –Draft of IRP document to TAC •June 30, 2016 –Comments on draft due back to Avista •July 2016 –TAC final review meeting (if necessary) •August 31, 2016 –File finalized IRP document Avista Corp 2016 Natural Gas IRP Appendices 301-'II._ ,11fillSTA" 44 Avista Corp 2016 Natural Gas IRP Appendices 302 TransCanada Infrastructure Update Avista TAC 1 eeting Capacities1 Tolls, Projects February 18, 2016 ~ ran Canada 55 TransCanada Corporation (TSX/NYSE: TRP) •57,000 km (35,500 mi) of wholly owned natural gas pipeline •Interests in an additional 11,500 km (7,000 mi) of natural gas pipeline •250 Bcf of regulated natural gas storage capacity •Unparalleled connections from traditional and emerging basins to growing markets •Average daily volume of approximately 14 Bcf/d of North American demand 2 Avista Corp 2016 Natural Gas IRP Appendices 303 ,.:J 11 _ ....... J /Alaska ./ Pipeline __,_,...,, .. ,··· ... • North Baja r ~.; "\::---Ll~::,_,~c:::.::__(.,__ ________ ----, ~-' ~.\ = Natural Gas Pipelines Natural Gas Pipelines (Under Construction) Natural Gas Pipelines (In Development) Natural Gas Pipelines (Ptopos~) Gas Storage Mazatlan Guadalajar~ Tamazunchale .­...... .,, Tam zunchale E~ ensi9n t ~ TransCanada 66 NGTL System 3 WCSB Pacific NW /California BC / AlbertaDeliveries MidwesternUSA CBM DEEP BASIN CORDOVA HORN RIVER West CoastLNG Eastern Canada /Northeast USA Potential Mackenzie Delta Supply •32,000+ km of pipe –combined assets of NGTL and ATCO Pipelines •Over 1000 receipt and 1000 delivery points on system •Transports over 75% of WCSB production •Over 400 Tcf of WCSB supply •400+ Bcf of WCSB gas storage •50 to 70 Bcf/d of trading liquidity DUVERNAY MONTNEY PotentialAlaska Supply Avista Corp 2016 Natural Gas IRP Appendices 304 ,_ ---.... .... .. ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' SK (()) lraf\scanada MB 77 Prince Rupert Gas Transmission (Proposed) 4 Avista Corp 2016 Natural Gas IRP Appendices 305 Terrac ?.ltlmat f'T111ce R(lllert Gas TranSmlsson ~ Rupe'! Ga5 llllnsnl!i:5lln O'RG1) Pll>pcl5fd AD~ A 111Ual IIOlld c.amp,soor 5tlllCl1 A fUb!OUal ft!IU~ OJm.rl'5.SOf 51:JHOO Prince Rupert Gas Transmission Other • Proposal ""'* NlllthWt5a LNG fl\polt P.IOaJ (3nl panyl ll3nsCllnxb's Hfi:HA G.!s ll'an!mll55lon ltd. (NGT\J Exlslll:ig SJ'5ll!!OI _._ Proposed N°'*MJatney MallilOO Project 0 ~ • Olll!Sa:llCMns (( ~ TransCanada Prince Rupert Gas Transmission Project 88 Coastal Gas Link Pipeline (Proposed) 5 Avista Corp 2016 Natural Gas IRP Appendices 306 Coasl;II Gaslink Pipeline Project Other • ... .. Morice liver Nxth Arunate Route (RevA) • l'ropos«I LN~ tanada laellit! (;rd Pilf1Y) loastal tiastn t'1pelm.i t'rqa:t '.:>tud) lorndJr Transc.mda'sNOVA Gas nansnws.soo Ud. ;NGTO EXlsung S)'S(Ell • -Coasul GasWc Me:Mng l'J<lny CJ Hioj...., A ~ (Ul:l)i,I Ga)u• 0..111,11~1 & ~ll'liny F~ility • Citieso'ldTOWtls A. f\rtentiol rutureCoo:stal Goslillc COfl\)fl'SSioo roa1roes (TDD) · · ·~........ B Lak ~ t t .... • urns e .. '\'-'o. -• •-cw"'\,,)) Fraser Lake *Morice! RivC!r North Altemato rou1Q is 35 kms from Houston ~ ~ TransCanada Coastal Gaslink Pipeline Project 99 NGTL Mainline Facilities for Specific Area Requirements Proposed Compressor LEGEND: Proposed Pipe Proposed Facility Approved & Under Construction Applied-for To Be Applied-for 1 2 4 3 5 6 MAP I.D. PREVIOUSLY APPLIED FOR FACILITIES DESCRIPTION TARGET IN- SERVICE DATE CAPITAL COST ($Millions) 1 Medicine Hat Compressor Station 3.5 MW Apr-17 66 TOTAL 66 NEW FACILITIES 2 James River Interchange Modifications -Aug-16 6 3 ATCO Pipelines Inland Looping 19 km NPS 24 Nov-16 45 4 ATCO Pembina Expansion Phases 1 & 2 20.2 km NPS 24 Nov-16 60 5 Lodgepole Unit Addition 5.0 MW Nov-17 62 6 South Kirby Expansion Project 39 km NPS 24 Apr-18 137 7 Western Alberta Mainline Loop 33km NPS 42 Nov-18 240 TOTAL 550 Approved Applied-for To Be Applied-for7 Avista Corp 2016 Natural Gas IRP Appendices 307 1010 Western Alberta Mainline Loop Purpose of the facility: •To meet increasing design flow requirements underpinned by FT-D Group 1, 2, and 3 contracts FT-D Contracts: •Total FT-D Group 1: 61,669 103m3/d (2,331 TJ/d) Scope: •Western Alberta Mainline Loop–33 km NPS 42 Estimated Cost: •Total: ~$240 Million Capacity: •Expected Existing Capacity: ~60 106m3/d (2,118 mmcf/d) •Incremental Capacity: ~10 106m3/d (353 mmcf/d) Schedule: •NEB s.58 Application –Q4 2016 •In-service –Q4 2018 7 Contractual trigger and scope for Western Alberta Mainline Loop or facilities is contingent on renewals and results of upcoming open season Avista Corp 2016 Natural Gas IRP Appendices 308 11 e lin pe Pi t es hw rt No I D A H O A L B E R TA B R I T I S H C O L U M B I A MP-90 M O N TA N A Ya kim a STARBU CK C/S #7 I D A H O BEND C/S #12 BONANZA C/S #14 Sa c ra m ento NGTL System Kingsgate Foothills Pipeline MP-10 B O U N D A R Y MP-30 EASTP ORT C/S #3 Sea ttle Lancaster LLC Rathdrum CT Spokane B O N N E R MP-70 MP-110 SANDP OINT C/S #4 MP-50 ATHOL C/S #5 Coeur d 'Alene Ea st W ena tc hee W A S H I N G T O N S P O K A N E MP-130 K O O TE N A I MP-150 ROSALIA C/S #6 W H I T M A N Oregon LNG (Proposed) Jackson Prairie Storage Calpine HPP Hermiston Generating Coyote Spring I Coyote Spring II MP-210 WA LL A WA L LA MP-230 MP-250 MP-170 Palouse MP-190 C O L U M B I A Lewiston Mist Storage Carty Generating (Proposed) W ALLU LA C/S #8 MP-270 STANFIELD C/S GTN MAINLINE MILEPOSTS Stanfield U M A TI L L A Na m e Type M ilepost P ortla nd WA S C O S H E R M A N MP-370 G I L LI A M MP-310 IONE C/S #9 M O R R O W M oyie Springs Bonner’s Ferry Sc hweitzer Sa nd point Ta p Ta p Ta p Ta p 22 27.04 55.5 59.26 MP-390 JE FF E R S O N MP-410 KENT C/S #10 Athol Ra thd rum City Ra thd rum CT La nc a ster LCC Cha se Roa d Spoka ne (NPC) Ta p Ta p Ta p Ta p Ta p Interc onnec t 84.77 97.64 97.64 99.78 102 108.29 Jordon Cove Energy (Proposed) Coos Ba y Eugen e MP-430 MP-450 D E S C H U TE S MP-470 MP-490 MP-510 MP-530 M ADRAS C/S #11 C R O O K MALIN AREA TIE-IN DETAIL Spoka ne (Avista ) M ic a Spa ngle Rosa lia St. John Pa louse La c rosse Kosm os Fa rm Sta nfield Sta nfield City Ca lpine HPP South Herm iston Coyote Springs M a d ra s Ta p Ta p Ta p Ta p Ta p Interc onnec t Ta p Ta p Interc onnec t Ta p Ta p Ta p La tera l Ta p 108.29 121.15 134.18 145.71 158.89 172.07 182.79 271.66 277.37 282.76 282.82 289.83 304.25 410.16 Gra nts P a ss JA C K S O N Klamath Expansion K L A M AT H CHEM U LT C/S #13 MP-550 MP-570 Main Meter S tation M.P. 609.80 Turquois e Flats Prineville Red m ond Pronghorn North Bend Bend Ta p Ta p Ta p Ta p Ta p 426.8 438.3 445.8 450.28 454.51 M ed ford Medford Lateral Kla m a th Fa lls MP-590 Turquoise Flats M.P. 612.46 Ruby South Bend Stea rns La Pine Gilc hrist Ta p Ta p Ta p Ta p 457.5 469.19 483.9 500.97 Klamath Cogen MP-610 Malin Sapphire Mountain Oregan Califor nia Sapphire Mtn Chem ult Kla m a th Fa lls M ed ford Ta p Interc onnec t La tera l 519.44 599.2 599.2 See MALIN AREA TIE-IN DETAIL C A L I F O R N I A RADAR C/S LIKELY C/S Tusc a rora Turquoise Fla ts (Ruby) M a lin Interc onnec t Interc onnec t Interc onnec t 609.8 609.8 612.46 GTN LATERAL MILEPOSTS SHOETREE C/S GTN System 2015 La tera l Coyote Springs Coyote Springs M ed ford M ed ford M ed ford M ed ford Ta ps Coyote Springs I Coyote Springs II Kla m a th Cogen Kla m a th Expa nsion W est Kla m a th Phoenix M ilepo st 18.5 18.5 22.8 22.86 22.85 88.03 Reno Tracy 1 & 2 W ADSW ORTH (BOOSTER) C/S Na tura lGa s Tra nsm ission Gas Transmission Northwest Tuscarora Pipeline NGTL Sysytem Foothills Pipeline PIPELINE INTERCONNECTS (MMcf/d) Compressor Station Major Meter Station Interc onnec ts Kingsga te (Foothills) Spoka ne (Avista ) Spoka ne (W illia m s) Pa louse (W illia m s) Sta nfield (W illia m s) Delivery Rec eipt M a lin (Tusc a rora ) Turquoise Fla ts (Ruby) M a lin (P G&E) W in ter 2,745 65 300 40 680 240 228 1200 2,067 Sum m er 2,593 65 300 40 680 240 228 1200 1,970 0 50 0 Milepost (M.P.) Power Plant Interconnect GTN_System_Map_20150401.mxd - April 1 - Hao - TC Mapping 100 200 300 Kilometres 50 100 200 Miles GTN System Map Avista Corp 2016 Natural Gas IRP Appendices 309 1212 Currently Available GTN Capacity 9 Avista Corp 2016 Natural Gas IRP Appendices 310 (( ~ !~!!!!~~e~! da Available Firm Capacity System & Capacity MJnagement Data as of: 1115/2016 Un t of measurement Dth Assume ROFR Renell/al Kingsgate to Slanfield Stanfield to Malin Sianfield Reoejpl ~pacity Stanfield Delivery Capacity 17\ The figures below represent the seasonal minimum capacity available. For monthly \J,,/ details view Page 2. 1,110,914 1.035,257 1,110,914 954,898 972,948 996,898 972,948 214,560 .214,560 214,560 214,560 430,527 455,527 430,527 455.527 -%1 41§,1:fflt/¥ _______________________________ _ Kingsgate to Slanfield Stanfield to Malin Stanfield Reoeipt ~ acity Stanfield Delivery Capaclly 2015--16 1.041,357 958,4911 214,560 430,527 2016 I, 110,914 972 948 21-4,560 455 527 2016-17 2017 1,558,295 1,613,810 1.374,7~ 1,345,026 214,560 214.560 430,527 455,527 -3·11/111Jii#fii!Jt)f _______________________________ _ Th2s data repreSEnis information avalable al fhe time of production and is subject lo· chan,ge. As new in'armation becomes available updated capacities will be distributed~. ~ ~ TransCanada 1313 Historical GTN Rates 10 Avista Corp 2016 Natural Gas IRP Appendices 311 ~ ~ TransCanada fJ. P,OCllt to Pllint M.ui:nllllll Uait Rates {S pff Dlili)L ~files Dm"y Daily TobJU:llit Total ~ Sche.dule of Noc-~eage W e~e De'~ !B:1se !Rafe, • .\C.1.i\ Un.it lla~ Himl Resenratoon ilt,:,....;mra.tioo• (ci-d+e} Cf-v (a) (b) (c) (d) (e) (t) (g) (h) ITS ~Mll!n 611..::0 0.039216 0305005 (1.009799 0.354020 OJJOl400 O.J55-t20 ~Scan 11131 0Jl391J6 0.11&130 OJ)ll443S 0.1817.84 0.00 .::00 OJ'.83184 King-Spoi I0&.291 OJ139216 0.05392& 0.00!731 0.094877 0.00!400 OJ:@6277 :Kiqg-Tusc ro9Jl0 0.0>392 6 0303680 0.009757 0.352653 0.00.@ 0.354-063 Stn:-M.llin 335.00 O.Oi392Ui 0.16~7:5 0.005361 0.211452 0.00 .:;oo, 0..3128:52 PAL O.l7S.124 0..?7Sl24 ITSIS']F ~Mll!:n. ,:,, Peak 611.~ 0.491S86 0.00 .::00 0.491:Sls.6 Off Peak 611.46 0.3!l8]j9 0.00.400 0..)l)9769 ~'ii:a.n ,:,, Peilk 171.31 0.251657 0.00 .::00 0.254-067 Off Peak l 137 0.15&~49 0.001400 OJ59M9 Sm:.-Malm Peak 335.00 0.293821 0.00 . .:SOO OJSl5221 OefPeilk 335.09 0.184107 0.001400 OJ:85507 ITS -iE::mmioms Utdford M9d.-M:d E.,;t Mlr SS:JO 0.005498 O.JS9~.9 0.002291 O.l9163S 0.00!400 O.l!!003S 1\#....d-'Ql. Kh.lilu:h. Top ll.85 0.005498 0.075171 0.0005!l4 O.Oil :M9 0.00 . .::00, 0.082669 Coyote Springs CS-CSE."1"~ I s:.50 0.00142(11 0.020121 0.000000 0.021542 0.001400 0.02S'941 1414 Current GTN Rates (1/1/16 –12/31/19) 11 Avista Corp 2016 Natural Gas IRP Appendices 312 ~ ~ TransCanada Plurne 1 .SeJJlemenJ Raus EJfrem·e Ja_nuary 1, 101 ti ~files Dailly Daey Total Ullit Total Rate Sc~ of Noo-~fil.e11ge 1rli]~ 0-e~ Base Rafe AC.A Unit lute Haul lte:enration lte;enrati.oa• (c+d+ie) (f +~ (a) (b) (i:) (id) (e) (f) (g) (!i) FIS ~Mll!:n 611.46 0.034393 0.165SOS. 0.009 99 O.llOO!JO 0.001.;oo 0311~ ~San 11737 1).(134393 O.ll03J!ll 0.00'143S 0.159'210 0.00!@0 OJ,51)510 ~5pok IO:U!ll Q.(134393 0.046&9.S. 0.0!11731 0.0&3124 0.001.;oo O.DE45~4 Ki¥-Tusc 609.iO 0.034393 0.164653 0.009757 OJ~~l 0.001.:;&J 0.310201 S1m-J!IJA1in. 13:5,.09 0.034393 0.14542!ll 0.0053151 o.umu 0.0010::00 OJ:86583 PAL 0.143541 0.2AB541 ITSIS'IF3 ~~ Peak. 6ll~ 0.430l2S 0.001.:;&l 0.431 ~5 O:IPak 611.46 O.~I 0.001.;oo 0~71291 ~San Peak. l 737 0.121129 0.001,ffl,!) 0....1~9 Off Peak. 2 137 O.B85J6 0.001.::0,J 0.139!>36 Stm,.h-1,..un, Peilk: 335..09 0.157146 01>0!~ O.l5S546 O:f Peilk. l.35,.09 O.Uill6~ 0.001.::00 OJ6,l56l ITS -Enemioas Medford Md-Mai Est 1tnr SSJO 0.004641 0.243058: 0.0022!lll O.l500ll0 0.001.::00 0.151.;ocl M-s:.d-W. El?ml.th Th.p lli5 0.004641 0.0630!!3 0.0005~ O.M8l7S 0.001,ffl,!) 0.0S~iS Coyote Springs CS-CS E.~ Mm I 1150 0.0012&3 0.0'33717 O.OOOCIOO 0.025000 0.001.::00 0.fil6.;-0(I 1515 GTN Average Day System Throughput 1,992 1,893 1,882 1,901 1,883 1,984 1,751 1,924 1,893 1,897 1,815 1,946 0 500 1,000 1,500 2,000 2,500 3,000 Jan 2015 Feb 2015 Mar 2015 Apr 2015 May 2015 Jun 2015 Jul 2015 Aug 2015 Sep 2015 Oct 2015 Nov 2015 Dec 2015 MD t h / d a y Kingsgate Throughput CapacityAvista Corp 2016 Natural Gas IRP Appendices 313 1616 IDAHO WASHINGTON Victoria Sumas Portland Seattle Sandpoint Redmond Bend Salem Spokane Pasco Lewiston Walla Walla Yakima Northwest Pipeline Molalla Trail West Pipeline (Proposed) 13 •106 mile, 30 -36” pipeline •Receipt point from GTN mainline near Madras •Delivery points into NWN and NWP at Molalla •Compression-based expandability up to approximately 1Bcf/d •Open Season Q4 2016 •In-Service: Nov. 2021 Avista Corp 2016 Natural Gas IRP Appendices 314 ~ ~ TransCanada , ONtgon 17 NWP Presentation 17 Avista Corp 2016 Natural Gas IRP Appendices 315 18 Avista Corp 2016 Natural Gas IRP Appendices 316 Agenda 2 System Overview Collaboration Reliability Efforts Future Resources Rate Case \·\e ,nake energy l1appet1.™ ~ WIii/ams. ~ 19 Avista Corp 2016 Natural Gas IRP Appendices 317 3 20 Avista Corp 2016 Natural Gas IRP Appendices 318 Northwest Pipeline {NWP) Backbone of the Pacific Northwest gas delivery system s) > Prolific supply sources • Rockies, San Juan, Western Canadian Sedimentary Basin, emerging BC shales > Steady market growth along 1-5 > Long-term firm peak transportation capacity of 3.8 TBtu/d > Assets 4 • 3,900 miles of pipeline and 41 compressor stations • Jackson Pra1ne Storage (25 6 Bcf capacity with 1.1 Bcf1d withdrawa l capability) • NWP balancing 2.1 Bet of capacity • NWP balancing 104,000 Dth/d of w/d • Clay Basin Storage • NWP balancing 3.2 Bcf of capacity • Plymouth LNG Storage • Customers hold 2.4 Bet of capacity and withdrawal capability of 305,300 Dth/d BAKERSiFIEL 0 LEGEND e Major Interconnects • Storage Reference POlnts m~ make energy liappen ... +.+r- e!' r-.. -; --= ,.._ --- ~ WIii/ams. ~ 21 Avista Corp 2016 Natural Gas IRP Appendices 319 \·\c make energy lwppct1.- Bi-Di rectiona l Pipeli ne > Northwest is a bi-d irectional pipeline that relies on both physical and displacement capacity to meet its contractual commiitments > Benefits of a bi-directional pipeline: 5 > Provides access to the lowest priced supply basin in the region > Built-in redundancy > Lower transportation costs > Lower fuel rates ~ WIiiiams. ~ 22 Avista Corp 2016 Natural Gas IRP Appendices 320 Ten-Year Supply Trend 100% 90% 80% 70% 60% w C) <(50% i,-; z W40% (.) a:: w a..30% 20% 10% 0% Northwest Pipeline's 10-year Supply Diversity L 4~ 5~o oo 2005 2006 2007 2008 2009 2010 2011 2012 2013 c::=::J Alberta c:=::i British Columbia c::::J Storage ttc make energy happen.~ R 2014 2015 $9.00 $8.00 $7.00 $6.00 $5.00 en w $4.0~ a:: a.. $3.00 $2.00 $1.00 $0.00 c::=::J Domestic -Alberta/Stanfield Prices -British Columbia/Sumas Prices ~ WIii/ams. ~ 6 -Domestic/Opal Prices 23 Avista Corp 2016 Natural Gas IRP Appendices 321 l-\e ,nake energy lwpper,.~ 2015 Demand by Destination 7 On System Markets 71 % All Deliveries PowerGen 13% On system Markets LDC's 55% ~ WIiiiams. ~ 24 Avista Corp 2016 Natural Gas IRP Appendices 322 l\c make energy happen.- Capacity Utilization > Northw est is fully contracted at the maxim um tariff rates, with the exception of some small short-haul packages on the south-end of the system > Demand to bring on supply from Sumas flowing South through points such as Cheha lis, Roosevelt and Plymouth , has greatly increased over the past few years > Demand to bring on supply from the Rockies has decreased, how ever, continues to be healthy duri ng the winte r heating season 8 ~ WIii/ams. ~ 25 Avista Corp 2016 Natural Gas IRP Appendices 323 Chehalis 9 800,000 700,000 600,000 500,000 400,000 .c 0 300,000 200,000 100,000 (100 ,000) (200,000) -2010 -2011 v\e make energy happen.- Average Daily Chehalis Throughput (South Flow) 613,444 Dth Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2012 -2013 -2014 liiiil 2015 -Prior 5yr Avg -Design Capacity ~ WIiiiams. ~ 26 Avista Corp 2016 Natural Gas IRP Appendices 324 Roosevelt 10 700,000 600,000 500,000 400,000 300,000 .c: 200,000 .... C 100,000 0 (100,000) (200,000) (300 ,000) (400 ,000) -2010 -2011 t\e make e11ergy 1wpper1.~ Average Daily Roosevelt Throughput (West Flow) 546,000 0th Nov Dec 2012 -2013 -2014 -2015 -Prior 5yr Avg -Design Capacity ~ f!JJjms. 27 Avista Corp 2016 Natural Gas IRP Appendices 325 11 Plymouth 700,000 600,000 500,000 400,000 300,000 .s= 200,000 c 100,000 0 (100,000) (200 ,000) (300 ,000) (400 ,000) \.\e rnake e11ergy l1apper1.~ Average Da ily Plymouth South Th roughput (North Flow) 536,300 0th I.I • oJ Nov Dec -2010 -201 1 -2012 -2013 -2014 -2015 -Prior 5yr Avg -Design Capacity ~ WIiiiams~ ~ 28 Avista Corp 2016 Natural Gas IRP Appendices 326 Kemmerer 800,000 700,000 600,000 500,000 400,000 ~ 300,000 .... 0 200,000 100,000 0 (100,000) (200,000) (300,000) l\c make euerg)' f1appct1." Average Daily Kemmerer Th roughput (North Flow) 655,000 0th Jun Aug Oct Nov Dec -2010 -2011 -2012 -2013 -2014 -2015 -Prior 5yr Avg -Design Capacity 12 ~ WIiiiams. ~ 29 Avista Corp 2016 Natural Gas IRP Appendices 327 13 ~ ~ms. 30 Avista Corp 2016 Natural Gas IRP Appendices 328 \.\e make energy lwppen.~ Collaboration through Shipper Advisory Board (SAB) Meetings > Northwest has established a SAB that meets regularly > Purpose of the SAB -Inform customers of items that may impact facilities an d rates - Obtain support for tariff fi lings prior to filing them with the Commission -Develop positions on FERC NOPR's -Discuss industry trends 14 8/15113 ~ WIii/ams. ~ 31 Avista Corp 2016 Natural Gas IRP Appendices 329 Northwest Pipeline -Unique Solutions Through Collaboration He make energy l,appcr,.- Collaboration Results In Unique Solutions > Operational Flow Orders (OFOs) - Eliminate the need for faci lities to meet peak-day loads -Order of operational remed ies: (1) sched uling/entitlements, (2) contract specific, (3) realignment , then (4) must flow > Reliab ility Settlement - Established reservation credits iif outages exceed the threshold -OFOs limited to resolving displacement concerns -Additional mobile compression facilities added to enhance service reliability and flexibility > Displacement Settlement -Installation of new facilities to reduce Wyoming to Idaho north flow displace ment -New contract prohibition 15 8/15/13 ~ WIii/ams. ~ 32 Avista Corp 2016 Natural Gas IRP Appendices 330 \.\c make energy lwppcr,.- Collaboration through Customer Surveys > Northwest continues to incorporate feedbac k from its customer surveys to improve its processes. For exa mple: -In response to low customer survey scores in the mid-1990s, Northwest: 16 8115/13 • Adopted a single-point-of-contact business model; • Developed Passage to comport with the single-point-of-contact model by integrating contracting, capacity release, nominations, confirmations, scheduling, imbalance management, measurement, invoicing, etc. into one system ~ WIiiiams. ~ 33 Avista Corp 2016 Natural Gas IRP Appendices 331 \,\~ make ct1ergy happet1.~ Collaboration with Individual Customers > Avista has un ique contracti ng requi rements in order to meet its peak­ day demands in Wash ington , Oregon and Idaho > To meet these un ique requirements Avista holds capacity with excess MDDOs that provide delivery point flexibility to transport gas to various markets as needed > Northwest and Avista have w orked together to assist Avista in: > locki ng up segmented capacity for the long-term in order to: 17 > mitigate its transportation costs; and > maximize its excess MDDO flexibility > meeting projected peak-day capacity shortfalls w ithout adding additional facil iities; and > meeting an immediate new load by installing a mobile meter station until a permanent meter station cou ld be designed and placed into service. ~ WIii/ams. ~ 34 Avista Corp 2016 Natural Gas IRP Appendices 332 l\c make energy happen.~ Collaboration Works > In obtaining contract extensions 18 Cl) -~ Northwest Pipeline Average Remaining Contract Life History (Revenue Weighted) ~ 8 -+----- C) C: ·-c: E 6 (1) ~ C) > <( 4 "'C -~ 2 0 Jan 2006 Jan 2007 Jan 2008 Jan 2009 Jan 2010 Jan 201 1 J an 2012 Jan 201 3 J an 2014 Jan 2015 Jan 2016 ~ Avista's average contract life is 12.81 years ~ms. 35 Avista Corp 2016 Natural Gas IRP Appendices 333 Northwest Pipeline -Unique Solutions Through Collaboration \'\c make energy l,appcn.~ Collaboration Works > In settling rate cases Northw est and its customers were ablle to settle thie last two rate cases (2006 and 2013) in a timely and efficient manner due to collaboration and trust • Individual customer and SAS meetings were held to discuss impact of major expenditures prior to fi ling (e.g., Capacity Replacement and Rockies Expansion ) • Agreements were reached to handle unknown cost variances (e.g., integrity related costs and federal corporate income tax rate) • Strong and ongoing relationships with our customers has helped in building trust and mutual respect 19 8/15/13 - ' I ~ WIii/ams. ~ 36 Avista Corp 2016 Natural Gas IRP Appendices 334 Northwest Pipeline -Unique Solutions Through Collaboration l\e make energy happen.- Collaboration Works > In improving customer satisfaction 9.5 9 8.5 8 7.5 7 6.5 6 I 1996 1997 1998 1999 2000 2001 2002 2004 2006 2008 2010 2012 2014 20 8/15/13 ~ Wllllams. ~ 37 Avista Corp 2016 Natural Gas IRP Appendices 335 21 ~ WIii/ams~ ~ 38 Avista Corp 2016 Natural Gas IRP Appendices 336 Measuring Reliability 22 > This takes into account planned and unplanne·d outages. •!•2014 -99.90 percent •!•2015 -100 percent \.\-c make erzergy l,appcn.- ~ WIiiiams. ~ 39 Avista Corp 2016 Natural Gas IRP Appendices 337 \-\c make et1ergy happen.- Ways Northwest Mitigates Impacts > Work planning/scheduling > Communication w ith customers, markets and interconnects > Plann ing w ith individual customers at meter sites or laterals > Stopple and bypass for constructi on tie-in work w here redundant looping is not available > Util ize system balancing to the extent possib le 23 ~ WIiiiams. ~ 40 Avista Corp 2016 Natural Gas IRP Appendices 338 Total Miles of First Time Assessments 24 -ashougal ~ regon City B McMinnville £ Albany Eugene 0 Leaend • station --·completed ---Future Assessmenl ~-~"'° l~n:.e: u:.edfor d.Y12Y m:,k:ro ,ome Ire ,1ni~ eoc:rreaff. Sctrw! :hr. .»:.e:!r'ntt.Owoa.'1 ~"' n ff'1lP. o»., t.lZ-16 • ....,.,,,,.,.,., • .,,.~15'k=,,,_,ebtc~hU :!!ll~l'ml West Operating A rea Assessments through 2015 Total M iles of First Time Assessments Total Miles of HCA First Time Assessment i \e make euergy l1appen .... ~ WIiiiams. ~ 41 Avista Corp 2016 Natural Gas IRP Appendices 339 Reliability > Northwest Geotechnical Monitoring Program > Mobile Compression Program / Solar Agreement > Valve Automation 25 i\e make e,iergy lzappen:· WIii~ ~ 42 Avista Corp 2016 Natural Gas IRP Appendices 340 26 ~ WIii/ams~ ~ 43 Avista Corp 2016 Natural Gas IRP Appendices 341 Overview- > Pacific Connector > Grants Pass > Washington Expansion 27 m: make energy l,appen.~ ~ WIiiiams. ~ 44 Avista Corp 2016 Natural Gas IRP Appendices 342 Overview- > Pacific Connector > Grants Pass > Washington Expansion 27 lie make energy happer1." ~ '!!JJJJms. 45 Avista Corp 2016 Natural Gas IRP Appendices 343 28 \,\c make energy 1,appen.'" Pacific Connector Gas Pipeline Project {PCGP) 0 N A JORDAN COVE LNG TERMINAL 025 2S so 75 100 -· WASHINGTON CAL/FOkNIA KLANATH ' GTN.M/S Ruby MIS 0REG0N \ \ \ I PACIFIC CONNECTOR GAS PtPELINE PROPOSED ROU"TE A -~a"''""' II c-,.p--,, Sb1D't ,,~v R,.4)1 Pl,;t,l;ntt .,...,,, o.,..r. c.,.,n...;tM Q-." P1.:p-'"'"" /',./ """'"""""'' -"" c..,.. .. Jon ..-Paohc Ga aid ~ttki Con'l).in, /',./ 1\ooo,O,Q Flpo .... ,"V ..-,-y~ CJ ~rC1i•~ l=VADA '---··--·---...... _____ ,,....,_ '---·-· ~ WIii/ams ~ 46 Avista Corp 2016 Natural Gas IRP Appendices 344 m~ make energy lwpper1.~ PCGP Cont'd 29 > 232-mile 36-inch diameter pipeline with a 41 ,000 HP (I SO rated ) compressor station > Provides up to 1,060 ,000 Dekatherms per day (Dth/d) of fi rm transportation > Jointly owned 50/50 by Williams Partners Operating, LLC and Veresen Inc. > Estimated FERG filed capital cost of $1.74 billion > Target 1st Quarter 2016 to execute binding precedent agreements > Target 1st Quarter 2016 FERC certificate > 4th Quarter 2020 In-Service (for pipeline) 47 Avista Corp 2016 Natural Gas IRP Appendices 345 Grants Pass > Project Summary Grants Pass Clark Branch Interconnect capital cost $5-10 million > No./So. Bound capacity > In-Service 402020 > Design Compression station piping modifications Potential meter upgrades > Open Season 30 Tentative April PCGP open season Potential Summer Grants Pass open season m~ make energy lwpper1.~ Potential Increased Name Point ID# Milepo.st Throughput PCGP Washougal C/S 289,466 Clark 299 0.2 239,052 Camas JR 300 3.75 239.,052 Washougal 301 3.76 239,052 Revnolds Metals 302 3.8 239,052 Portland Northeast 303 7.26 239,052 Gresham 304 10.7 239,052 Johnson Creek 305 10.8 239,052 Sanely 306 15.85 239,052 Portland Southeast 307 19.56 239,052 Oregon City Compressor Station 308 21.06 239,052 Oregon City 309 28 239,052 Molalla#2 310 38.6 239,052 Molalla Receipt 672 38.63 239,052 Molalla 312 38.64 239,052 McMinnville Comoressor Station 316 53.09 51,900 Albany Compressor Station 328 83.46 51,900 Eu11ene Compressor Station 337 10.04 51,900 Wiochester Compressor Station 346 62.2 51,900 Wiochester Plvwood 347 62.29 51,900 Dr. Gamble Farm 348 64.16 51,900 Roseburg 351 69.3 51,900 Coos County Meter Station 670 72.11 51,900 Austin Williams 352 73.6 51,900 Winston -Dillard 353 74.61 51,900 Hasbareen Herman 354 76.1 51,900 Round Priarie (Roseburg lumber) 355 78.57 51,900 Garren Roy 356 79.51 51,900 Woods Elmer 357 80.3 51,900 Northflow Clarks Branch TBD SO.ti Weaver Gilbert 358 86.51 Myrtle Creek/Riddle 359 87.13 76,196 Canyonville 361 92.46 46,190 Glendale 701 106.88 23,931 Mer1in 365 126.95 111,660 Grants Pass 366 131.54 13,490 j ~-·-· Assumes no meter constraints and some small modifications to compressor station piping along the lateral .~ WJ/1,ams~ ~ 48 Avista Corp 2016 Natural Gas IRP Appendices 346 8.3 mile section 4.9 mile section 5.5 mile section 14.9 mile section { 11 .1 mile section 7 .1 mile section J 13.6 mile section Dr: 24.0 mile section p Chehalis 45.1 mile section =-0)/Mlti ~ ~ Oat,op Columbt::1 . \'\.. Skagit Sumner Piace \fr 11wkt· t'11crgy l,appc11. · Washington Expansion Project > FERC application filed 2013 (CP 13- 507) > 140 mi les of 36-inch diameter loop line w ith: - 750,000 Dth/d of firm transportation -89,620 incremental horsepower required along 1-5 > Estimated cost $1 .1 bil lion > Targeted in -service date November 20 19 -Potential regional loads w ith in­ service dates phased-in 49 Avista Corp 2016 Natural Gas IRP Appendices 347 l\c make energy happct1.~ Northwest Innovation Works Projects 32 Port of Ta coma Methanol Export Up to 525 MD'lh/d Tar; et ISO: 2020 Kalama Methanol Export Up to 320 MDth/d Tar et ISO: 2018 Portland Port Westward Methanol Export Up to 320 MDth/d Target ISO: 2021 \ I ' \, > Port of Tacoma Latera l -10-mile up to 30-inch diameter green-field delivery lateral > Port of Kalama Lateral -3.1-mi le 20-inch diameter pipel ine -Expecting FERC certificate Q2 20 16 > Latera ls interconnect with Northwest's existing main line 50 Avista Corp 2016 Natural Gas IRP Appendices 348 32 51 Avista Corp 2016 Natural Gas IRP Appendices 349 He make euergy !zapper,." Rate Case > Current Rate Case Settlement provides: -$466.5 m ill ion annual cost of service - Transportation rate of $0.44 / 0th -Allows NWP to file for new rates to be effective as ea rly as 1/1/2016 and requires NWP to file for new rates to be effective by 1/1/2018 > Upcoming Rate Case Pre-Filing Settlement schedule: 33 -April 22, 2015 --Shippers (22 of them) ind icated w illingness to participate in pre-filing settlement discuss ions - Third Quarter 20 16 --Deta iled pre-filing discussions commence -March 2017 --Settlement must be final or fi led rate case will be necessary ~ WIii/ams. ~ 52 Avista Corp 2016 Natural Gas IRP Appendices 350 \.\~ make energy happeu:· Rate Case Timeline Rate Case RPI 7-XXX Timeline (Custom er Discu ssion s, Per Previous Settlement) BEG BASE T BEG FORMAL NEWRAllS PRE FllJ .... ENDFORMAI. l SETTI.EMENT l'flE,f'lllNG DI,~ ~NT • • h~r ~ • :ii 11 :. = I l ~ !!I !!I :l :l !i !i !I !I !I !I !I !I !I l!I !i :!j l:. 0:. :: :. :: :: l:. :: i ~ !I t l !' i. ij ~ i f . 1 t .$ ~ ., i ,I, ! ~ i ~ i . t .i i " 1 .. ! i f lS t lS T ,c :II ,c I li FikE ,c l SAS SAIi c.5E MTG MTG FlUNG ENDIBASE FDl'.100 TEST em TEST PERIOD PERIOD SAB -Shipper Advisory Board 34 53 Regional and Avista’s Supply Side Resources Eric Scott Manager of Natural Gas Resources Avista Corp 2016 Natural Gas IRP Appendices 351 5454 Connecting Supply and Storage with Customers 54 Avista Corp 2016 Natural Gas IRP Appendices 352 WESTERN CANADIAN SEDIMENTARY BASIN ROCKIES BASIN 55 •TransCanada Alberta (NOVA) –Transporting gas out of Alberta, Canada •TransCanada BC (ANG) –Transporting gas through BC, Canada to US •Spectra Energy (WestCoast) –Transporting gas from western BC Canada to US •Gas Transmission Northwest (GTN) –Transporting gas from Canada/US border to CA •Williams Pipeline West (NWP) –Transporting gas from western BC and US Rockies •El Paso Ruby Pipeline –Transporting gas from the Rockies to Malin Regional Transportation Resources Source: NWGA55 Avista Corp 2016 Natural Gas IRP Appendices 353 5656 Interstate Pipeline Resources •The Integrated Resource Plan (IRP) brings together the various components necessary to ensure proper resource planning for reliable service to utility customers. •One of the key components for natural gas service is interstate pipeline transportation. Low prices, firm supply and storage resources are rendered meaningless to a utility customer without the ability to transport the gas reliably during cold weather events. •Acquiring firm interstate pipeline transportation provides the most reliable delivery of supply. 56 Avista Corp 2016 Natural Gas IRP Appendices 354-'II._ ,11fillSTA" 57 Pipeline Contracting Simply stated: The right to move (transport) a specified amount of gas from Point A to Point B A B 57 Avista Corp 2016 Natural Gas IRP Appendices 355 5858 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 transportedMileage Based 58 Avista Corp 2016 Natural Gas IRP Appendices 356 5959 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 –and can be BUMPED later! Seasonal Transport •Firm service available for limited periods (Nov-Mar) or for a limited amount (TF2 on NWP) •Usually matched, paired or utilized with storage. Alternate Firm Transport •The use of firm transport outside of the primary path •Priority rights below firm •Priority rights above interruptible 59 Avista Corp 2016 Natural Gas IRP Appendices 357 6060 Segmentation Primary Path: Sumas to CDA 10,000 Dth/day Guaranteed Delivery 60 Avista Corp 2016 Natural Gas IRP Appendices 358 6161 Segmentation Segment: Sumas to JP –FIRM 10,000 Dth/day JP to CDA –FIRM 10,000 Dth/day 61 Avista Corp 2016 Natural Gas IRP Appendices 359 6262 Contract Provisions -NWP 62 •Grandfathered Unilateral Evergreen (TF-1, TF-2, SGS-2F) –Roll-over 1 year –Shipper has sole option to extend or renew •Standard Unilateral Evergreen –Roll-over 1 year –5 year termination provision •Standard Bi-lateral Evergreen –Either transporter OR shipper may terminate Avista Corp 2016 Natural Gas IRP Appendices 360-'II._ ,11fillSTA" 6363 Contract Provisions -GTN 63 •Bilateral Evergreen –Either transporter OR shipper may terminate contract •Unilateral Evergreen –Shipper alone may terminate contract •Right of First Refusal (ROFR) –Provides “last look” Avista Corp 2016 Natural Gas IRP Appendices 361-'II._ ,11fillSTA" 6464 Capacity Releases 64 Example: AVA released 35,000 Dths/day at full tariff rate to Clark PUD until 10/31/2025 recapturing over $5.2mm annually all of which goes to customers. Avista Corp 2016 Natural Gas IRP Appendices 362 6565 Natural Gas Liquids -Extraction 65 •Wet natural gas from AB/BC has many liquid components that may be taken from stream. Each component is used in industrial processes and has value. •Avista negotiates with an extraction plant near Calgary to purchase these liquids components. Avista Corp 2016 Natural Gas IRP Appendices 363 6666 Natural Gas Liquids -Extraction 66 •Formula = [0.XX*{{Sum((72%xC3)+(12%*NC4)+(9%*IC4)+(7%x(WTI/42))-gas price) -$0.XX}}] 2013 2014 2015 Liquids revenue ($CAD)$2,323,000 $2,510,000 $840,000 All the revenue goes directly to reducing the price of natural gas for our customers in all of our service areas! Avista Corp 2016 Natural Gas IRP Appendices 364 6767 Natural Gas Liquids -Extraction 67 0.00 20.00 40.00 60.00 80.00 100.00 120.00 0.000 0.200 0.400 0.600 0.800 1.000 1.200 1.400 1.600 Au g - 1 3 Oc t - 1 3 De c - 1 3 Fe b - 1 4 Ap r - 1 4 Ju n - 1 4 Au g - 1 4 Oc t - 1 4 De c - 1 4 Fe b - 1 5 Ap r - 1 5 Ju n - 1 5 Au g - 1 5 Oc t - 1 5 De c - 1 5 Oil and Liquids Prices Propane Butane ISO WTI 0 50,000 100,000 150,000 200,000 250,000 300,000 350,000 0.000 0.200 0.400 0.600 0.800 1.000 1.200 1.400 1.600 Au g - 1 3 Oc t - 1 3 De c - 1 3 Fe b - 1 4 Ap r - 1 4 Ju n - 1 4 Au g - 1 4 Oc t - 1 4 De c - 1 4 Fe b - 1 5 Ap r - 1 5 Ju n - 1 5 Au g - 1 5 Oc t - 1 5 De c - 1 5 Oil Prices and Liquid Extraction Propane Butane ISO Revenue Avista Corp 2016 Natural Gas IRP Appendices 365 68 Storage and Transportation Optimization Leslie Filer Manager of Natural Gas Acquisition Avista Corp 2016 Natural Gas IRP Appendices 366 6969 Year First Unserved Scenario Comparisons Avista Corp 2016 Natural Gas IRP Appendices 367 7070 Storage –A valuable asset •Peaking resource •Improves reliability •Enables capture of price spreads between time periods •Enables efficient counter cyclical utilization of transportation (i.e. summer injections) •May require transportation to service territory •In-service territory storage offers most flexibility 70 Avista Corp 2016 Natural Gas IRP Appendices 368-'II._ ,11fillSTA" 7171 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. Avista Corp 2016 Natural Gas IRP Appendices 369 7272 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 72Avista Corp 2016 Natural Gas IRP Appendices 370 73 Washington and Idaho Owned Jackson Prairie •7.7 Bcf of Capacity with approximately 346,000 Dth/d of deliverability Oregon Owned Jackson Prairie •823,000 Dth of Capacity with approximately 52,000 Dth/d of deliverability Leased Jackson Prairie •95,565 Dth of Capacity with approximately 2,654 Dth/d of deliverability Avista’s Storage Resources 73 Avista Corp 2016 Natural Gas IRP Appendices 371-'II._ ,11fillSTA" 7474 Optimization •Optimization helps Avista to recover costs, for our customers, on assets when not in use for load. Avista Corp 2016 Natural Gas IRP Appendices 372 75 Buy 75,000 Dth & Inject Sell 2,500 Dth/Day In November& schedule the withdrawal Sell 77,500 Dth & withdraw Buy 2,500 Dth/Day In August& cancel scheduled withdrawal Cash To Forwards Forward To Cash Standard Apr $3.00 May $3.10 Jun $3.00 Jul $2.50 Aug $2.75 Sep $3.25 Oct 3.35 Nov $3.50 Dec $3.60 Jan $3.70 Feb $3.50 Mar $3.25 Today CASH $3.00 2 1 2 1 Example Storage Optimization Example of Storage Opt Deals Avista Corp 2016 Natural Gas IRP Appendices 373 7676 Transportation Optimization AECO to MALIN Demand $.45 Cost to transport .10 *AECO = $1.45 MALIN = $2.00 $.55 -$.10 = $.45 Lowered cost to ratepayers by $.45 This is referred to as a location spread. Malin AECO *2/10/16Avista Corp 2016 Natural Gas IRP Appendices 374 77 Optimization Overall •Combine all optimization to create more value •Optimization has the following effects on rates: –WA/ID For every $2.5M of optimization, rates decrease by ~1% –OR For every $1M of optimization, rates decrease by ~1% 77 Avista Corp 2016 Natural Gas IRP Appendices 375-'II._ ,11fillSTA" 78 Transportation Modeling in Sendout and solving unserved demand Tom Pardee Manager of Natural Gas Planning Avista Corp 2016 Natural Gas IRP Appendices 376 7979 Modeling Transportation In SENDOUT® •Start with a point in time look at each jurisdiction’s resources •Contracts –Receipt and Delivery Points •Rates •Contractual vs. Operational •Contractual can be overly restrictive •Operational can be overly flexible •Incorporating operational realities into our modeling can defer the need to acquire new resources. •Gas Supply’s job is to get gas from the supply basin to the pipeline citygate. •Gas Engineering/Distribution’s job is to take gas from the pipeline gate to our customers. •The major limiting factor is receipt quantity –how much can you bring into the system? 79 Avista Corp 2016 Natural Gas IRP Appendices 377-'II._ ,11fillSTA" 80 Modeling Challenges •Supply needs to get gas to the gate. •Contracts were created years ago, based on demand projections at that point in time. •Stuff happens (i.e. growth differs from forecast). •Sum of receipt quantity and aggregated delivery quantity don’t identify resource deficiency for quite some time however….. •The aggregated look can mask individual city gate issues, and the disaggregated look can create deficiencies where they don’t exist. •In many cases operational capacity is greater than contracted. •Transportation resources are interconnected (two pipes can serve one area). •WARNING –we need to be mindful of the modeling limitations. 80 Avista Corp 2016 Natural Gas IRP Appendices 378-'II._ ,11fillSTA" 8181 What is in SENDOUT®? Inside: •Demand forecasts at an aggregated level •Existing firm transportation resources and current rates •Receipt point to aggregated delivery points/“zone” •Jurisdictional considerations •Long term capacity releases •Potential resources, both supply and demand side 81 Avista Corp 2016 Natural Gas IRP Appendices 379-'II._ ,11fillSTA" 8282 What is outside SENDOUT®? Outside: •Gate station analysis •Forecasted demand behind the gate •Growth rates consistent with IRP assumptions •Actual hourly/daily city gate flow data •Gate station MDDO’s •Gate station operational capacities 82 Avista Corp 2016 Natural Gas IRP Appendices 380-'II._ ,11fillSTA" 83 CONFIDENTIAL –Do Not Distribute83 InterconnectSupply Storage Transport Demand Avista Corp 2016 Natural Gas IRP Appendices 381 84 Solving Unserved Demand Avista Corp 2016 Natural Gas IRP Appendices 382-'II._ ,11fillSTA" 85 When unserved demand does show up…… There are a few questions we need to ask: 1.Why is the demand unserved? 2.What is the magnitude of the short? (i.e Are we 1 Dth or 1000 Dth’s short?) 3.What are my options to meet it? 85 Avista Corp 2016 Natural Gas IRP Appendices 383-'II._ ,11fillSTA" 8686 When current resources don’t meet demand what do we consider? •Transport capacity release recalls •“Firm” backhauls •Contract for existing available transportation •Expansions of current pipelines •Peaking arrangements with other utilities (swaps/mutual assistance agreements) or marketers •In-service territory storage •Satellite/Micro LNG (storage inside service territory) •Large scale LNG with corresponding pipeline build into our service territory •Structured products/exchange agreements delivered to city gates •Biogas •Avista distribution system enhancements •Demand side management 86 Avista Corp 2016 Natural Gas IRP Appendices 384-'II._ ,11fillSTA" 8787 New Resource Risk Considerations •Does is get supply to the gate? •Is it reliable/firm? •Does it have a long lead time? •How much does it cost? •New build vs. depreciated cost •The rate pancake •Is it a base load resource or peaking? •How many dekatherms do I need? •What is the “shape” of resource? •Is it tried and true technology, new technology, or yet to be discovered? •Who else will be competing for the resource? 87 Avista Corp 2016 Natural Gas IRP Appendices 385-'II._ ,11fillSTA" 88 Demand and Supply Side Sensitivities Optimize Resource Portfolio Stochastic Cost/Risk Analysis Prices and Weather Highest Performing Portfolios selection Preferred Portfolio selection Core Cases Price Forecast Sensitivities, Scenarios, Portfolios Avista Corp 2016 Natural Gas IRP Appendices 386 89 Supply Scenarios for the 2016 IRP Supply Scenarios ????? ????? ????? ????? •Do they get gas to the gate? •Does this affect pricing at the basins? •Rank the risk of these scenarios. 89 Avista Corp 2016 Natural Gas IRP Appendices 387 90 2016 Natural Gas IRP Carbon Issues John Lyons, Ph.D. Second Technical Advisory Committee Meeting February , 2015 Avista Corp 2016 Natural Gas IRP Appendices 388 9191 Carbon Laws and Regulations •Mixed bag of federal and state laws and proposals •Regulatory mandates •Cap and trade programs •Carbon taxes •Focus tends to be on electric generation –Some proposals (Washington I-732) and laws (California AB32) directly impact the natural gas markets or the distribution companies 91 Avista Corp 2016 Natural Gas IRP Appendices 389-'II._ ,11fillSTA" 9292 Federal •Many past attempts, current focus under a regulatory model through the Clean Air Act (CAA) •Clean Power Plan (CPP) –reduce greenhouse gas emissions from covered existing power plants 32 percent below 2005 levels by 2030 under section 111(d) of the CAA through three building blocks: 1.Improve heat rate of coal plants 2.Increase utilization of natural gas-fired plants and reduce coal plant use 3.Increase use of renewable resources •CPP stayed by US Supreme Court on February 9, 2016 •Oral arguments June 2, 2016 at DC Circuit Court of Appeals 92 Avista Corp 2016 Natural Gas IRP Appendices 390-'II._ ,11fillSTA" 9393 Idaho •No active or proposed greenhouse gas legislation •Provided comments about the CPP and the federal implementation plan •Were working towards submitting a state implementation plan by September 2016 –no official word on the current plans with the stay from the Supreme Court. Will probably stop working on the plan until the outcome of the court case is known. 93 Avista Corp 2016 Natural Gas IRP Appendices 391-'II._ ,11fillSTA" 9494 Oregon •HB 4036: “Coal to Clean” bill voted out of committee –50 percent renewable by 2040 –Eliminate coal power in rates by 2030 –Compromise to a ballot measure •SB 1574: replace greenhouse gas emission goal with a cap and trade program for 2025. Probably dead for this session. •HB 4068: repeal greenhouse gas emissions goals and require Environmental Quality Commission to adopt goals for 2025 and limits for 2035 and 2050. Officially dead for this session 94 Avista Corp 2016 Natural Gas IRP Appendices 392-'II._ ,11fillSTA" 9595 Washington •I-732 Initiative to the Legislature –Revenue neutral $25 per metric ton tax escalating 3.5 percent per year plus inflation until $100 per ton in 2016 dollars –Taxes natural gas –Hearings held on I-732, but expected to go to the November ballot –Other proposals have been discussed for alternatives •Possible competing ballot initiative •Clean Air Rule proposal 95 Avista Corp 2016 Natural Gas IRP Appendices 393-'II._ ,11fillSTA" 96 Questions? Avista Corp 2016 Natural Gas IRP Appendices 394-'II._ ,11fillSTA" 9797 2016 IRP Timeline •August 31, 2015 –Work Plan filed with WUTC •January through April 2016 –Technical Advisory Committee meetings. Meeting topics will include: –Demand Forecast and Demand Side Management –January 21 –Supply/Infrastructure and Potential Case Discussion–February 18 –Distribution Planning, Natural Gas Pricing, SENDOUT® Preliminary Output Results and Further Case Discussion – March 30 –SENDOUT® results –April 21 •May 30, 2016 –Draft of IRP document to TAC •June 30, 2016 –Comments on draft due back to Avista •July 2016 –TAC final review meeting (if necessary) •August 31, 2016 –File finalized IRP document Avista Corp 2016 Natural Gas IRP Appendices 395-'II._ ,11fillSTA" 1 2016 Avista Natural Gas IRP Technical Advisory Committee Meeting March 30, 2016 Spokane, WA Avista Corp 2016 Natural Gas IRP Appendices 396 22 Agenda •Introductions & Logistics •CNG/NGV Initiatives •Distribution System Planning •Gate Station Analysis •Procurement Planning •Natural Gas Pricing •Preliminary Results and Scenario Discussion Following TAC #3 Meeting: •Sendout overview 2 Avista Corp 2016 Natural Gas IRP Appendices 397 33 2016 IRP Timeline •August 31, 2015 –Work Plan filed with WUTC •January through April 2016 –Technical Advisory Committee meetings. Meeting topics will include: –Demand Forecast and Demand Side Management –January 21 –Supply/Infrastructure and Potential Case Discussion–February 18 –Distribution Planning, Natural Gas Pricing, SENDOUT® Preliminary Output Results and Further Case Discussion – March 30 –SENDOUT® results –April 21 •May 30, 2016 –Draft of IRP document to TAC •June 30, 2016 –Comments on draft due back to Avista •July 2016 –TAC final review meeting (if necessary) •August 31, 2016 –File finalized IRP document 3 Avista Corp 2016 Natural Gas IRP Appendices 398-'II._ ,11fillSTA" 4 Compressed Natural Gas Services Marc Schaffner, Strategic Initiatives Manager Natural Gas Technical Advisory Committee March 30, 2016 Avista Corp 2016 Natural Gas IRP Appendices 399 5 Natural Gas Reserves and Utilization U.S. Natural Gas Reserves The U.S.’s total recoverable resource base at 2,515 trillion cubic feet Projected to meet total domestic demand over the next 100 years PGC’s year-end estimate for 2014 rose 5.5 percent from 2012 Source: Potential Gas Committee (PGC) Natural Gas Vehicles (NGV) Worldwide Estimated 15.2 million natural gas vehicles (NGVs) Asia and Middle East 8.8M, South America 4.3 M, Africa .16M and North America .14M The U.S. is number 17 in the world with less than 1 percent of the NGVs in use NGVs on U.S. Highways Estimated 150,000 NGVs on U.S. highways Estimated 15,000 NGVs were added to U.S. highways in 2012 Source: U.S. Department of Energy Avista Corp 2016 Natural Gas IRP Appendices 400 6 U.S. CNG Infrastructure About 1,620 Private and Public Refueling Stations Source: U.S. Department of Energy, February 2016 <5% in Washington, Oregon and Idaho Avista Corp 2016 Natural Gas IRP Appendices 401 7 U.S. CNG Infrastructure About 900 are Public Refueling Stations Source: U.S. Department of Energy, February 2016Avista Corp 2016 Natural Gas IRP Appendices 402 8 The Benefits of Compressed Natural Gas Environmentally responsible It’s clean and efficient 25% less greenhouse gas emissions than gasoline or diesel A vital part of an alternative transportation portfolio Cost effective Lowers fuel costs Tax credits and incentives Reduces dependency on imported fuel sources Natural gas is an abundant, domestic resource A clean fueling solution across an increasing range of NGV classes Aimed at extending benefits to commercial fleet operators Mobilizes safe and reliable CNG equipment 85 light duty NGVs CNG refueling infrastructure Avista Corp 2016 Natural Gas IRP Appendices 403 9 Over the past 25 years Avista has fueled light duty vehicles, service continuity equipment and fork lifts with CNG Ten of our gas operating centers have maintained private CNG refueling infrastructure over that time period 2011, we began devising plans to upgrade CNG infrastructure at our highest volume service centers in Washington and Idaho 2012, we completed construction of a new refueling station at our Mission Avenue service center in Spokane, WA 2013, we completed a second Spokane refueling station at our Dollar Road gas service center 2014, we finished construction of a new refueling station at our electric and gas operations center in Coeur d‘ Alene, ID Avista’s Investment in CNG Mission Avenue Refueling Station -Spokane Avista Corp 2016 Natural Gas IRP Appendices 404 10 Avista’s CNG Refueling Stations CNG Refueling Location Project Status Compression Capability Storage Capacity Mission Avenue SC Spokane, Wash.Completed 2012 125 HP Compressor 202 SCFM 280 GGE at 4500 psi Dollar Road SC Spokane, Wash.Completed 2013 125 HP Compressor 202 SCFM 280 GGE at 4500 psi Coeur d’Alene SC Coeur d’Alene, Idaho Completed 2014 (2) 50 HP Compressors 75 SCFM 280 GGE at 4500 psi Avista Corp 2016 Natural Gas IRP Appendices 405 11 Source: Clean Cities Alternative Fuel Price Report, October 2015 Avista Corp 2016 Natural Gas IRP Appendices 406 TABLE 2 National Average Retail Fuel Prices Conventional and Alternative Fuels, October 2015• Fuel Type" July 2015 10ctober Change in Price Units of 2015 July-October Measurement Gasol1ine $2.82 $2~35 -$0.47 per gallon (E1 0) Diesel $2.93 $2 .59 -$0.34 per gallon CNG $2.12 $2.09 ,..$0.03 per GGIE Ethanol (E8 5) $2.36 $2.18 -$0.18 per gallon Propane•• $2.90 $2..90 $0.00 per gallon Btodiesel (820) $2.93 $2 .66 -$0.27 per gallon EHodiesel (8 99/ $3.5S $3~40 -$0.1 5 per gallon B100} •includes public and private stat ions .. includes primary and secondary stat ions 12 Source: Clean Cities Alternative Fuel Price Report, October 2015Avista Corp 2016 Natural Gas IRP Appendices 407 $4.00 - $3.75 ....., tll $3.50 I.!) ~ ...., $3.25 .... Iii 1 $3.00 :, tr Ql C 0 ia a Ql C ~ Ill $1.SO !ti a ~ $2.25 Ql u 'C Q. $2.00 $1.50 I I I I I I I I JO JA JO J AJ I I I I 0 J A J I I I I I 0 J A J 0 I I I I I I I I I J A J O J A J O J I I I I I I I AJOJ AJO 2007 2008 2009 2010 2011 2012 2013 2014 2015 e Gasoline * Natural Gas (GGE) FIGURE 3 HISTORICAL COMPRESSED NATURAL GAS (CNG) PRICES VERSUS GASOLINE 13Source: Clean Cities Alternative Fuel Price Report, October 2015Avista Corp 2016 Natural Gas IRP Appendices 408 $4.75 $4.50 $4.25 • ""' w \!> $4.00 ~ ._, ..... $3.75 C CD J :i $3.50 er Cl) C $3.25 0 I "ii .,, $3.00 41 ~ t C. $2JS Cl) u $2.50 ,: a. $2.25 • e Diesel • Natural Gas (OGE) FIGURE 5 HISTORICAL COMPRESSED NATURAL GAS (CNG) PRICES VERSUS DIESEL 14 Natural Gas Vehicle Investment Recovery* Waste Hauling NGV Customer Investment $35,000 per vehicle Miles per gallon 3 Annual mileage 25,000 CNG per gallon $2.00 Diesel per gallon $4.00 Estimated payback 25 months Annual fuel savings $16,800 * Q1 2014 Avista Corp 2016 Natural Gas IRP Appendices 409 15 Natural Gas Vehicle Investment Recovery* Waste Hauling NGV Customer Investment $35,000 per vehicle Miles per gallon 3 Annual mileage 25,000 CNG per gallon $2.09 Diesel per gallon $2.59 Estimated payback 7.75 years Annual fuel savings $4,583 * Q4 2015 Avista Corp 2016 Natural Gas IRP Appendices 410 16 Avista CNG Services Tariffs •February 2015,we established a Compressed Natural Gas Service tariff (Schedule 441)in Oregon;which allows us to provide Company-owned CNG refueling infrastructure for transportation sited on the customer’s premise •We have secured (“non-tariffed”)authority,provided by WUTC staff,to serve NGV operators in the same way (as Schedule 441 Oregon)in Washington •Effective May 22,2015,we established a Backup and Supplemental Compressed Natural Gas Service tariff (Schedule 149)that allows Avista to fuel (under contract)NGV fleet operators Avista Corp 2016 Natural Gas IRP Appendices 411-'II._ ,11fillSTA" 17 Thank You Avista Corp 2016 Natural Gas IRP Appendices 412 18 Appendix Avista Corp 2016 Natural Gas IRP Appendices 413-'II._ ,11fillSTA" 19 Avista Contributors Energy Solutions Account Executives Customer Solutions Regional Business Managers Government Relations Lobbyists Legal Counsel Risk Real Estate Contract Administration Real Estate Legal Property Acquisition Regulatory Rates & Tariffs Treasury Billing Analysis Financial Planning & Analysis Facilities Project Management Fleet NGV Management CNG Infrastructure Maintenance Distribution Infrastructure Gas EngineeringAvista Corp 2016 Natural Gas IRP Appendices 414-'II._ ,11fillSTA" 20 Organizational Capability What are we learning? •The value of broad-based collaboration occurring across a dynamic natural gas for transportation marketplace. Private & public sector customers, industry associations, government, contractors and vendors What skills are we developing? •NGV acquisition and maintenance •CNG fueling infrastructure planning, construction and maintenance •CNG/NGV consultation What value does Avista’s CNG capability provide our employees, customers and business community? •A more robust portfolio of energy offerings •Enhanced revenue and cost saving opportunities for regional businesses •An innovative, sustainable way to positively affect environmental quality and energy independence Avista Corp 2016 Natural Gas IRP Appendices 415-'II._ ,11fillSTA" 21 Distribution System Planning Terrence Browne, Senior Gas Planning Engineer Natural Gas Technical Advisory Committee March 30, 2016 Avista Corp 2016 Natural Gas IRP Appendices 416 2222 Mission •Using technology to plan and design a safe, reliable, and economical distribution system 22 Avista Corp 2016 Natural Gas IRP Appendices 417 2323 Gas Distribution Planning Game Plan •Review •Scope of Gas Distribution Planning •SynerGi Load Study Tool •Planning Criteria •Interpreting Results •Long-term Planning Objectives •Historical Temperatures •Monitoring Our System •The (Customer) Forecast •Gate Station Capacity Review •Project Examples 23 Avista Corp 2016 Natural Gas IRP Appendices 418 24 –Population of service area 1.5 million 370,000 electric customers 330,000 natural gas customers Service Territory and Customer Overview •Serves electric and natural gas customers in eastern Washington and northern Idaho, and natural gas customers in southern and eastern Oregon 24 Avista Corp 2016 Natural Gas IRP Appendices 419 2525 Daily Demand Profiles 0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 020406080100 De k a t h e r m s 2015 Average Temp (°F) Medford/Roseburg 25 Avista Corp 2016 Natural Gas IRP Appendices 420 26 Seasonal Demand Profiles 26 Avista Corp 2016 Natural Gas IRP Appendices 421 3,000,000 2,500,000 "'2,000,000 E .. Cl -; 1,500,000 _g c!! 1,000,000 500,000 160,000 140,000 120,000 "' 100,000 E .. Cl ~ 80,000 .. _g c!! 60,000 40,000 20,000 Washington/Idaho Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Klamath Falls Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec -Residential 600,000 500,000 "' 400,000 E .. Cl -; 300,000 _g c! 200,000 100,000 70,000 60,000 50,000 "' E 40,000 .. Cl ~ .. _g 30,000 c!! 20,000 10,000 Medford/Roseburg Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec LaGrande Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Commercial -Industr ial 2727 Our Planning Models •122 cities •40 load study models 27 Avista Corp 2016 Natural Gas IRP Appendices 422 2828 __ Pup Pdown Q L || D __ 5 Variables for Any Given Pipe 28 Avista Corp 2016 Natural Gas IRP Appendices 423 2929 Scope of Gas Distribution Planning Supplier Pipeline High Pressure Main Reg. Distribution Main and Services Reg.Reg. Gate Sta. 29 Avista Corp 2016 Natural Gas IRP Appendices 424 3030 Scope of Gas Distrib. Planning cont. Gate Sta. Reg.Reg.Reg. Reg.Reg. Gate Sta. Gate Sta. 30 Avista Corp 2016 Natural Gas IRP Appendices 425 3131 SynerGi (SynerGEE, Stoner) Load Study •Simulate distribution behavior •Identify low pressure areas •Coordinate reinforcements with expansions •Measure reliability 31 Avista Corp 2016 Natural Gas IRP Appendices 426 32 35 DD 30’ F 32 Avista Corp 2016 Natural Gas IRP Appendices 427 33 Preparing a Load Study •Estimating Customer Usage •Creating a Pipeline Network •Join Customer Loads to Pipes •Convert to Load Study 33 Avista Corp 2016 Natural Gas IRP Appendices 428 3434 Estimating Customer Usage •Gathering Data –Days of service –Degree Days –Usage –Name, Address, Revenue Class, Rate Schedule… 34 Avista Corp 2016 Natural Gas IRP Appendices 429 3535 Estimating Customer Usage cont. •Degree Days –Heating (HDD) –Cooling (CDD) •Temperature -Usage Relationship –Load vs. HDD’s –Base Load (constant) –Heat Load (variable) –High correlation with residential Avg. Daily Heating Cooling Temperature Degree Days Degree Days ('Fahrenheit) (HDD) (CDD) 85 20 80 15 75 10 70 5 65 0 0 60 5 55 10 50 15 45 20 40 25 35 30 30 35 25 40 20 45 15 50 10 55 5 60 4 61 0 65 -5 70 -10 75 -15 80 -17 82 35 Avista Corp 2016 Natural Gas IRP Appendices 430 3636 Avista Corp 2016 Natural Gas IRP Appendices 431 E.ile ~dit ~iew Insert FQ.rmat Iools Qata ~indow t:1elp Ciiii; ~ ~ [9. ~ i ~ 8 '1d in .. ~ ~ ~ ~ ,.. 1 ! l ! !Mi • .fl 150% .. 00 .. 10 .. B I J1 I =-=- =-~ $ % +.o .oo +ii-+ii--.. ft.. .. A_ .. E:i::I O J .oo + .o =, =, <.;;, ----~ Kl l • = A B C D E F G H Begin Date Read Date RBC Dys Svc Deg Dys Usage Therm/Da) *DD/day mcfh/day 01-23-2002 02-22-2002 RR 30 971 2775 92 .5 32.36667 0.58 12-21-2001 01-23-2002 RR 33 11 95 2567 77.78788 36.21212 0.49 11-20-2001 12-21-2001 RR 31 1028 2547 82.16129 33.16129 0.51 10-24-2001 11-20-2001 RR 27 586 1379 51.07407 21 .7037 0.32 09-24-2001 10-24-2001 RR 30 491 1208 40.26667 16.36667 0.25 08-22-2001 09-24-2001 RR 33 67 715 21.66667 2.030303 0.14 07-24-2001 08-22-2001 RY 29 19 432 14.89655 0.655172 0.09 06-22-2001 07-24-2001 RR 32 41 611 19.09375 1.281 25 0.12 05-24-2001 06-22-2001 RR 29 219 736 25.37931 7.551724 0.1 6 04-23-2001 05-24-2001 RY 31 368 1301 41.96774 11.87097 0.26 03-23-2001 04-23-2001 RR 31 734 1913 61.70968 23.67742 0.39 02-22-2001 03-23-2001 RR 29 826 2538 87.51724 28.48276 0.55 01-24-2001 02-22-2001 RY 29 111 3 3153 108.7241 38.37931 0.68 12-1 9-2000 01-24-2001 RY 36 1347 3668 101.8889 37 .41667 0.64 11-1 6-2000 12-1 9-2000 RY 33 1340 3573 108 .2727 40.60606 0.68 10-1 8-2000 11-1 6-2000 RR 29 884 2424 83.58621 30.48276 0.52 09-20-2000 10-1 8-2000 RR 28 408 1738 62.07 143 14.57143 0.39 11 39 39 _27586 5 _82758i Q1ii Chartl l!J L ~" F\IIIMill- 37 Heat Base 37 Avista Corp 2016 Natural Gas IRP Appendices 432 3838 Estimating Customer Usage cont. •Peaking Factor –Peaking Factor = 6.25% of daily load –“Observed ratio” of greatest hourly flow to total daily flow at Gate Stations •Industrial Customers –Model maximum hourly usage per Contractual Agreement –Firm Transportation customers only –Low Temperature-Usage correlation 38 Avista Corp 2016 Natural Gas IRP Appendices 433-'II._ ,11fillSTA" 3939 Creating a Pipeline Model •Elements –Pipes, regulators, valves –Attributes: Length, internal diameter, roughness •Nodes –Sources, usage points, pipe ends –Attributes: Flow, pressure 39 Avista Corp 2016 Natural Gas IRP Appendices 434 4040 Avista Corp 2016 Natural Gas IRP Appendices 435 0 TERRENCE 1!10 £i file Job E.dit ~iew Iheme J:iraphics CAD ~indow J:lelp ~~~(g] ~~~[!!)~~ ~ Scale 1 j 19.724 G OTHER/ MISC· Moscow 1!10£1 _J G•s O evices Yi Oas Pipes _J Di•meter ,1nnot,1tion Dimension annotation Exst. D evioes Exst. Pipes _J Exst. Anno _J Exst. Oimension Anno ~ Mos cow Streets _J Whitm•n Co. Streets N _J Railroads (L•ta h Co.) A/ Railroads (ill/ hitman Co.) A/ ::J Hydro (Latah Co.) c:::::J _J Hydro (Whitman Co.) c:::::J 4141 Avista Corp 2016 Natural Gas IRP Appendices 436 0 TERRENCE 1!10 £i file Job E.dit ~iew Iheme J:iraphics CAD ~indow J:lelp ~~~(g] ~~~[!!)~~ ~ ~ ~QJ~ Scale 1 i 26,170 & OTHER/ MISC· Moscow 1!1~£1 _J G•s D a vices ~ Gas Pipes _J Di•matar .innoti1tion Dimension annotatio n _J Exst. D evioes _J Exst. Pipes _J Exst. Anno _J Exst. Dimens ion Anno ~ Mos cow Streets _J Whitm.in Co. S treets IV _J R•ilro•d• (L•t•h Co.) N Railroads CW hitman Co.) N ::J Hydro (Latah Co.) c::::J _J Hydro (Whitman Co.) c::::J 4242 Join Customer Loads to a Model •Residential and commercial loads are assigned to pipes •Industrial or other large loads are assigned to nodes 42 Avista Corp 2016 Natural Gas IRP Appendices 437 4343 Avista Corp 2016 Natural Gas IRP Appendices 438 0 TERRENCE 1!10 £i file Job E.dit ~iew Iheme J:iraphics CAD ~indow J:lelp ~~~(g] ~~~[!!)~~ ~ Scale 1 j 19.724 G OTHER/ MISC· Moscow 1!10£1 ~ Mos cgeocd _ cust_3-2Q-02 ... _J Gas Devices =i Gas Pipes _J C>iameter annotation =i Dimension annot.ation _J Exst. Devices =i Exst. Pipes _J Exst. Anno =i Exst. Dimension Anno ~ Mos cow Streets _J Whitman Co. Stroot. N R allro ads (Lala h Co.) IV =i R .ailro ads (IN hitm an Co.) IV _J Hydro (Latah Co.) c:::::J _J Hydro (Whitman Co.) c:::::J 4444 Avista Corp 2016 Natural Gas IRP Appendices 439 0 TERRENCE 1!10 £i file Job E.dit ~iew Iheme J:iraphics CAD ~indow J:lelp ~~~(g] ~~~[!!)~~ ~ /Jl)J<" G ! U OF I LIFE SCIENCE BLDG 'G ................ 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A/ _J Hydro (Latah Co.) c:::::J _J Hydro (W hitman Co.) c:::::J 4545 Avista Corp 2016 Natural Gas IRP Appendices 440 0 TERRENCE 1!10 £i file Job E.dit ~iew Iheme J:iraphics CAD ~indow J:lelp ~~~(g] ~~~[!!)~~ ~ Scale 1 j 19.724 2,510,954.41 ++ 534.865.49 t G OTHER/ MISC· Moscow 1!10£1 ~ Moscgeocd_cust_3,2Q,02 ... ~ Ga$ Pipes =i Gas Devices _J C>iameter annotation =i Dimension annot.ation _J Exst. Devices =i Exst. Pipes _J Exst. Anno =i Exst. Dimension Anno _J Mos cow Streets _J Whitman Co. Struts N R allro ads (Lala h Co.) IV =.J Railroads (IN hitm an Co.) IV _J Hydro (Latah Co.) c:::::J _J Hydro (Whitman Co.) c:::::J 4646 Avista Corp 2016 Natural Gas IRP Appendices 441 @ SynerGEE -[Schematic -Moscow) 1!10 El 4747 Balancing Model •Simulate system for any temperature –HDD’s •Solve for pressure at all nodes 47 Avista Corp 2016 Natural Gas IRP Appendices 442 48 35 DD 30˚F 48 Avista Corp 2016 Natural Gas IRP Appendices 443 4949 Validating Model •Simulate recorded condition •Pressure Recorders –Do calculated results match field data? •Gate Station Telemetry –Do calculated results match source data? •Possible Errors –Missing pipe –Source pressure changed –Industrial loads 49 Avista Corp 2016 Natural Gas IRP Appendices 444 50 41 psig Location: N. Orchard, Moscow ID Observation Date: Friday, March 1st Hi = 35˚ F Low = 25˚F Avg = 30˚F = 35 DD Validating Model cont. 50 Avista Corp 2016 Natural Gas IRP Appendices 445 51 35 DD 30˚F N. Orchard Moscow, ID 51 Avista Corp 2016 Natural Gas IRP Appendices 446 5252 •Reliability during design HDD –Spokane 82 HDD –Medford 61 HDD –Klamath Falls 72 HDD –La Grande 74 HDD –Roseburg 55 HDD •Maintain minimum of 15 psig in system at all times –5 psig in lower MAOP areas Planning Criteria 52 Avista Corp 2016 Natural Gas IRP Appendices 447-'II._ ,11fillSTA" 5353 •Reliability during design HDD –Spokane 82 HDD (avg. daily temp. -17’ F) –Medford 61 HDD (avg. daily temp. 4’ F) –Klamath Falls 72 HDD (avg. daily temp. -7’ F) –La Grande 74 HDD (avg. daily temp. -9’ F) –Roseburg 55 HDD (avg. daily temp. 10’ F) •Maintain minimum of 15 psig in system at all times –5 psig in lower MAOP areas Planning Criteria 53 Avista Corp 2016 Natural Gas IRP Appendices 448-'II._ ,11fillSTA" 54 35 DD 30˚F 54 Avista Corp 2016 Natural Gas IRP Appendices 449 55 50 DD 15˚F 55 Avista Corp 2016 Natural Gas IRP Appendices 450 56 65 DD 0˚F 56 Avista Corp 2016 Natural Gas IRP Appendices 451 5757 Interpreting Results •Identify Low Pressure Areas –Number of feeds –Proximity to source •Looking for Most Economical Solution –Length (minimize) –Construction obstacles (minimize) –Customer growth (maximize) 57 Avista Corp 2016 Natural Gas IRP Appendices 452 585858 Avista Corp 2016 Natural Gas IRP Appendices 453 , ,.,,;w,. eo1oray Prrm,n {,n~/ • 1)00 JS/111 0 J$()()•;1(100 .J/)(1(1-~00 Q 4$00-IOOO • •,000 595959 Avista Corp 2016 Natural Gas IRP Appendices 454 , -,<ffitffl ColortJy Prrn un{pu,J • 0#-.LSDt) a J$#-~Dt) • JOl19-,Z;jOl1 D .ut111-e"" • >IOOtl 60 65 DD 0’ F 60 Avista Corp 2016 Natural Gas IRP Appendices 455 61 65 DD 0’ F R 61 Avista Corp 2016 Natural Gas IRP Appendices 456 62 82 DD -17’ F R 62 Avista Corp 2016 Natural Gas IRP Appendices 457 6363 Long-term Planning Objectives •Future Growth/Expansion •Design Day Conditions •Facilitate Customer Installation Targets 63 Avista Corp 2016 Natural Gas IRP Appendices 458 6464 Historical Temperatures 64 Avista Corp 2016 Natural Gas IRP Appendices 459 6565 •Reliability during design HDD –Spokane 82 HDD (avg. daily temp. -17’ F) –Medford 61 HDD (avg. daily temp. 4’ F) –Klamath Falls 72 HDD (avg. daily temp. -7’ F) –La Grande 74 HDD (avg. daily temp. -9’ F) –Roseburg 55 HDD (avg. daily temp. 10’ F) Historical Temperatures 65 Avista Corp 2016 Natural Gas IRP Appendices 460-'II._ ,11fillSTA" 6666 •Reliability during design HDD –Spokane 82 HDD (avg. daily temp. -17’ F) •11/23/10: 64 HDD –Medford 61 HDD (avg. daily temp. 4’ F) –Klamath Falls 72 HDD (avg. daily temp. -7’ F) –La Grande 74 HDD (avg. daily temp. -9’ F) –Roseburg 55 HDD (avg. daily temp. 10’ F) Historical Temperatures 66 Avista Corp 2016 Natural Gas IRP Appendices 461 6767 •Reliability during design HDD –Spokane 82 HDD (avg. daily temp. -17’ F) •11/23/10: 64 HDD •12/6/13 and 12/8/13: 58 HDD –Medford 61 HDD (avg. daily temp. 4’ F) •12/8/13: 52 HDD –Klamath Falls 72 HDD (avg. daily temp. -7’ F) •12/8/13: 72 HDD –La Grande 74 HDD (avg. daily temp. -9’ F) •12/8/13: 65 HDD –Roseburg 55 HDD (avg. daily temp. 10’ F) •12/8/13: 44 HDD Historical Temperatures 67 Avista Corp 2016 Natural Gas IRP Appendices 462 6868 •Reliability during design HDD –Spokane 82 HDD (avg. daily temp. -17’ F) •11/23/10: 64 HDD •12/6/13 and 12/8/13: 58 HDD •1/1/16: 55 HDD –Medford 61 HDD (avg. daily temp. 4’ F) •12/8/13: 52 HDD –Klamath Falls 72 HDD (avg. daily temp. -7’ F) •12/8/13: 72 HDD •1/2/16: 62 HDD –La Grande 74 HDD (avg. daily temp. -9’ F) •12/8/13: 65 HDD –Roseburg 55 HDD (avg. daily temp. 10’ F) •12/8/13: 44 HDD Historical Temperatures 68 Avista Corp 2016 Natural Gas IRP Appendices 463 6969 Monitoring Our System 69 Avista Corp 2016 Natural Gas IRP Appendices 464 7070 Monitoring Our System •Validates our Load Studies •Mechanical >>> Electronic •Daily Feedback •Real time if necessary 70 Avista Corp 2016 Natural Gas IRP Appendices 465 71 Post Falls State Line 71 Avista Corp 2016 Natural Gas IRP Appendices 466 72 Hayden Lake 72 Avista Corp 2016 Natural Gas IRP Appendices 467 73 South Hayden Lake 73 Avista Corp 2016 Natural Gas IRP Appendices 468 7474 Real-time Pressure & Flow Monitoring 74 Avista Corp 2016 Natural Gas IRP Appendices 469 7575 One-line Diagrams •schematic •connectivity •hierarchy •framework •normal operations •emergencies 75 Avista Corp 2016 Natural Gas IRP Appendices 470 7676 Sprechen El Similar Lingua •Translating the Forecast •Gas Planning Layers •Gate Station Capacity Review 76 Avista Corp 2016 Natural Gas IRP Appendices 471 7777 WA-ID Region Firm Customers: 2016 IRP and 2014 IRP 210,000 220,000 230,000 240,000 250,000 260,000 270,000 280,000 290,000 300,000 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 WA-ID-Base 2014 WA-ID-Base +5,500 IRP Avg.Annual Growth 2016-2035 2014 1.0% 2016 1.1% 77 Avista Corp 2016 Natural Gas IRP Appendices 472 7878 OR Region Firm Customers: 2016 IRP and 2014 IRP 80,000 85,000 90,000 95,000 100,000 105,000 110,000 115,000 120,000 125,000 130,000 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 OR-Base 2014 OR-Base IRP Avg.Annual Growth 2016-2035 2014 0.9% 2016 1.2% +7,000 78 Avista Corp 2016 Natural Gas IRP Appendices 473 7979 System Firm Customers: 2016 IRP and 2014 IRP 300,000 320,000 340,000 360,000 380,000 400,000 420,000 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 WA-ID-OR-Base 2014 WA-ID-OR-Base +12,500 IRP Avg.Annual Growth 2016-2035 2014 1.0% 2016 1.1% 79 Avista Corp 2016 Natural Gas IRP Appendices 474 8080 Strategic Gas Growth Projects Project Name AREA STATUS Forecasted Connects (3yr) Forker Road Spokane Complete 15 Rolling Hills Estates Roseburg 5,000 ft constructed, 65% complete Est. Comp date Feb 2016 164 Connell -NW Davis St.Spokane Complete 15 Debbie Drive Klamath Falls Complete 27 West side of Kenwood St Roseburg Complete 5 Bonanza Klamath Falls In construction Est. Comp date April 2016 –River Crossing Permit 152 Ridge Road Spokane Complete 12 N Newport Hwy Spokane Waiting for Gas Engineering 3 Midland Rd Klamath Falls Complete 90 Austin Road -Phase I Spokane Complete 14 Austin Road -Phase II Spokane Complete 30 Austin Road -Phase III Spokane Starting December 15, 2015 21 Sunwest Airway Heights Starting Jan-Feb 2016 30 Santa Maria Estates Roseburg Est. start date mid March 2016 40 Linda Way Post Falls Complete 12 Kooken Estates Roseburg Est. start date June/July 2016 38 Round Lake Klamath Falls Est. start date June/July 2016 128 Neyland Rd Spokane Completed 8 Winch Rd –Wild Ridge Coeur ‘d Alene Complete 21 TOTAL 825 80 Avista Corp 2016 Natural Gas IRP Appendices 475 8181 22 Home Development in Warden, WA 81 Avista Corp 2016 Natural Gas IRP Appendices 476 8282 Gas Planning Layers •Gas Planning Proposals •Gas Planning AOI 82 Avista Corp 2016 Natural Gas IRP Appendices 477 8383 Gas Planning Proposals Add 4” 83 Avista Corp 2016 Natural Gas IRP Appendices 478 8484 Gas Planning AOI Low pressure Future Growth 84 Avista Corp 2016 Natural Gas IRP Appendices 479 85 City Gate Analysis Results Terrence Browne, Senior Gas Planning Engineer Natural Gas Technical Advisory Committee March 26, 2014 Avista Corp 2016 Natural Gas IRP Appendices 480 8686 City Gate Analysis Issues to Address •MDQ vs. MDDO •Our gate vs. Pipeline gate •Operational capacity vs. contracted capacity •Pipeline differences •Zonal vs. Point Specific •Laterals and Mainlines 86 Avista Corp 2016 Natural Gas IRP Appendices 481-'II._ ,11fillSTA" 87 Forecasting Demand Behind the Gate •Our IRP desire has always been to forecast to as granular a level as possible using the available data. •Attempts to forecast demand behind the gate using existing forecasting methodology has been challenging. •Revenue data does not have daily meter reads for core customers making regression analysis on a use per HDD per customer difficult. •DSM would become more burdensome than it already is. •Some towns can be served by multiple pipelines and the mix can change over time. 87 Avista Corp 2016 Natural Gas IRP Appendices 482-'II._ ,11fillSTA" 88 Forecasting Demand Behind the Gate cont. While there are challenges, there is modeling that we can do to help identify more granular city gate deficiencies. •Utilize daily/hourly pipeline flow data from each meter station to estimate what demand could be on a peak day or any heating degree day. •Apply growth factors to estimate what the demand could grow to consistent with IRP assumptions/methodology. 88 Avista Corp 2016 Natural Gas IRP Appendices 483-'II._ ,11fillSTA" 8989 Gate Station Capacity Review 89 Avista Corp 2016 Natural Gas IRP Appendices 484 ... 0 ' 1.81111 ---1-~~--=,w •1111-=-=------•-i --­------ ... _ =-- 11 . I 9090 Gate Station Capacity Review cont. Spokane, CDA Service Areas 90 Avista Corp 2016 Natural Gas IRP Appendices 485 9191 y = 0.1278x + 3.5481 R² = 0.64840 5 10 15 20 25 30 35 0 10 20 30 40 50 60 70 80 90 100 Fl o w ( m c f h ) HDDCity Gate Station # X Daily Peak Flow (mcfh) GTN Physical Capacity (31 mcfh) Design Day Peak Flow (14.0 mcfh; 82 HDD) Contractual Amount (21.9 mcfh, Diversity Factor = 1.5) Linear (Daily Peak Flow (mcfh)) 82 HDD Gate Station Capacity Review 91 Avista Corp 2016 Natural Gas IRP Appendices 486 9292 y = 2.1146x + 65.605 R² = 0.63080 50 100 150 200 250 300 0 10 20 30 40 50 60 70 80 90 100 Fl o w ( m c f h ) HDD City Gate Station # Y Daily Peak Flow (mcfh) NWP Physical Capacity (206.0 mcfh, Diversity Factor = 1.44) Design Day Peak Flow (239.0 mcfh; 82 HDD) Contractual Amount (121.8 mcfh, Diversity Factor = 1.44) Linear (Daily Peak Flow (mcfh)) 82 HDD Gate Station Capacity Review 92 Avista Corp 2016 Natural Gas IRP Appendices 487 9393 Gate Station Capacity Review: WA 106% 118% 120% 138% 0%20%40%60%80%100%120%140%160% Mica Pullman Sprague Colton DESIGN DAY DEMAND: % OF PHYSICAL CAPACITY 93 Avista Corp 2016 Natural Gas IRP Appendices 488 9494 Gate Station Capacity Review: OR 102% 106% 158% 0%20%40%60%80%100%120%140%160%180% Sutherlin Klamath Falls LaGrande DESIGN DAY DEMAND: % OF PHYSICAL CAPACITY 94 Avista Corp 2016 Natural Gas IRP Appendices 489 9595 Gate Station Capacity Review: ID 105% 106% 104%105%105%106%106%107% CDA East Bonners Ferry DESIGN DAY DEMAND: % OF PHYSICAL CAPACITY 95 Avista Corp 2016 Natural Gas IRP Appendices 490 96 Natural Gas Prices Tom Pardee Manager of Natural Gas Planning Avista Corp 2016 Natural Gas IRP Appendices 491 97 What Drives the Natural Gas Market? Natural Gas Spot Prices (AECO) Supply –Type: Conventional vs. Non-conventional –Location –Cost Demand –Residential/Commercial/I ndustrial –Power Generation –Natural Gas Vehicles Legislation –Environmental Energy Correlations –Oil vs. Gas –Coal vs. Gas –Natural Gas Liquids Weather Storage 97 Avista Corp 2016 Natural Gas IRP Appendices 492 98 Short Term Market Perspective 98 Avista Corp 2016 Natural Gas IRP Appendices 493 $10.00 $9.00 $8.00 $7.00 $6.00 ~ Q $5.00 ..... ..,,. $4.00 $3.00 $2.00 AECO W inter Forwards vs. Cash $1.00 $6.00 $0.00 Jan Feb .c S3.50 5 "' $3.00 S2.50 -·1~·11 -·11-'1& -1s-•19 -·1s-•20 -c.,,., Mar Apr -Min -Max AECO Gas Daily Prices May Jun --·5 Yr. Avg Jul Aug -2015 Sep Oct Nov Dec --2016 99 The Short Term Fundamentals Bulls Dwindling rig counts Economic recovery LNG & Methanol Plants Weather –Normal is now bullish Power Demand Bears Demand is weak Storage is full Oil Prices are near 10+ year lows Record Production Increased drilling efficiency Stealth/Ghost Wells 99 Avista Corp 2016 Natural Gas IRP Appendices 494 100100 The Long Term Fundamentals Demand •Economy (Recession, Depression, Inflation, etc.) •Industrial Demand •Power Generation •LNG, NGV, CNG US Natural Gas Supply and Production •Resource Base •Drilling Efficiency •Associated Gas Global Dynamics –LNG Imports and Exports North American Storage Capacity Correlation (or lack thereof) with other energy products The Environment •Carbon Legislation •Fracking •Renewable Portfolio Standards 100 Avista Corp 2016 Natural Gas IRP Appendices 495 101 The Changing the Flow Dynamics 101 Avista Corp 2016 Natural Gas IRP Appendices 496 102 Forecasted Natural Gas Production 102 Avista Corp 2016 Natural Gas IRP Appendices 497 Lower 48 supply outlook The Northeast will continue to fuel production growth through 2030 • The Marcellus and Utica will grow their share of US Lower 48 dry from 27% in 2015 to 44% by 2025 as infrastructure build-out allows for more resource to get to market. • Additionally, associated gas fuels 1 o bcfd of net growth between 2017 and 2024 once oil price recover late this decade 120 100 -"O -80 0 .D -C: 0 0 60 J "O 0 ... 40 Q. (/) CG C) ~ 20 "O co ,:t _. 0 ,.._'> ~ ""' ~ ~ ~ ,.._'b '\,~ ,...~ ~ ~ '\,~ n-" '\,~ n,'\, ~ n-"' '\,~ ~ '\,~ n,'> ~ n-"' '\,~ re, '\,~ n,'b ~ ~ ~ !',~ '\,~ • Vertical • Southern Marcellus • Northern Marcellus • Mid-Continent • Eagle Ford • Barnett • Fayetteville • Niobrara Three Forks •Utica •Wolfcamp •Bakken • Haynesville Bone Spring • Re-frac/EOR 103103 Canadian Production Source: “Canada’s Energy Future 2016”National Energy Board Outlook 103 Avista Corp 2016 Natural Gas IRP Appendices 498 104104 LNG Source: FERC 104 Avista Corp 2016 Natural Gas IRP Appendices 499 North American LNG Export Terminals Proposed US Jurisdiciion • FERC • MARAD/USCG As of March 22, 201 6 PROPOSED TO FERC Pen ding Applications: 1. Astoria, OR: 1.2!:> l::lctd (Oregon LNG) (CP09 6) 2. Elba Island, GA: 0.35 Bcfd (Southern LNG Company) (CP14-103) 3. lake Chartes, LA: 1 07 Rr:fd (Magnolia I NG) (CP14-347) 4. Sabine Pass, TX: 2.1 Dcfd (CxxonMobil -Golden Pass) (CP14-517) 6. Pascagoula, MS: 1.!> l::lctd (Gult LNG UquctoctJon) (Cl-'1!> !:>21) 6. Freeport, TX: 0.3'1 Bcfd (Freeport LNG Dev) (CP15-518) 7. Cameron Parish, LA: 1.4·1 Bdd (Vianluria Global Calcasiiau P«,s,s) (CP15-550) 8. Hackberry, LA: 1 4·t Rdd (SH111prr1 -C;;11mm>n I NG) (C:P·t !\-~O) Projects in Pre-filing: 9. Plaquemines Parish, LA: 1.0 / l::lctd (Ct I-LNG) (Pl-13 11) 10. Plaquemines Parish, LA: 0.30 Bcfd (Louisiana LNG) (PFH -17) 11. Robbinston, ME: 0.45 Bdd (Kia,:;lrial Eniaryy -Duwn1ac<sl LNG) (PF14-19) 12. Jacksonville, Fl: 0 07:, Rd/ct (FaglP. I NG PartnP.r,,;) (PF1:.-7) 13. Brownsv ille, TX: 0.54 Bcfd (Texas LNG Brownsville) (PF15-14) 14. Brownsv ille, TX: 0.94 l::lctd (/\nnovo LNG l::lrownsv1Jlc) (Pl-1!> 1!:>) 15. Port Arthur, TX: 1.4 Bcfd (Port Arthur LNG) (PF15-18) 16. Brownsville, TX: 3.6 Bdd (Rio Grdnde LNG -NexlDecade) (PF15-20) 17. Freeport, TX: 0.72 Dcfd (rreeport LNG Dev) (Pr15-25) 18. Corpus Christi, TX: 1.4 Bcfd (Chcnicrc Corpus Christi LNG) (PF15 26) 19. Plaquemines Parish, LA: 2.80 l::lctd (Venture Global LNG) (Pl-1!:>-2/) 20. Nlklskl, AK: 2.55 Bcfd (ExxonMobil, ConocoPhillips, BP, Transcanada and Alask« Ga,:;line) (PF·t4-21) 21 . Cameron Parish, LA: 1.04 Dcfd (G2 LNG) (Pr16-2) PROPOSED TO U.S.-MARADICOAST GUARD 22. Gulf of Mexico: 1.8 Bcfd (Delfin LNG) PROPOSED CANADIAN SITES 23. Kitimat, BC: 1.20 Dcfd (Apache Canada Ltd.) 24. Douglas Island, BC: 023 Bcfd (BC LNG Export Cooperative) 25. Prince Rupert Island, BC: 2./'I l::lctd (PaClhc Northwest LNG) 105105 Oil and Gas Rigs & Production 372 92 Avista Corp 2016 Natural Gas IRP Appendices 500 106106 US –Drilling efficiency •EIA DPR -7 most prolific areas in the US, which account for all natural gas production growth during 2011 -2014106 Avista Corp 2016 Natural Gas IRP Appendices 501 107107 How prices affect IRP Planning? •Major component of the total cost •Change in price can trigger price elastic response •THE major piece of avoided costs and therefore cost effectiveness of DSM •Can change resource selection based on basin differentials •Storage utilization 107 Avista Corp 2016 Natural Gas IRP Appendices 502-'II._ ,11fillSTA" 108 IRP Natural Gas Price Forecast Methodology 1.Two fundamental forecasts (Consultant #1 & Consultant #2) 2.Forward prices 3.Year 1 -forward price only 4.Year 2 -75% forward price / 25% average consultant forecasts 5.Year 3 -50% forward price / 50% average consultant forecasts 6.Year 4 –6 25% forward price / 75% average consultant forecasts 7.Year 7 -50% average consultant without CO2 / 50% average consultant with CO2 108 Avista Corp 2016 Natural Gas IRP Appendices 503-'II._ ,11fillSTA" 109109 Avista Corp 2016 Natural Gas IRP Appendices 504 Fundamental Forecasts vs. Actual Pri ces Henry Hub $14.00 $13.00 $12.00 $1 1.00 $10.00 $9.00 E $8.00 • i ~ $7.00 ~ .,. $6.00 $5.00 $4.00 $3.00 $2.00 $1 .00 Actuals Forecast $- -consultant 1 -Fa11 2015 Consu'ltant 2 -Dec2015 -NYMEX -Jan 07, 2016 -E IA -Mar 2016 110 2014 IRP Low –Med –High REAL 110 Avista Corp 2016 Natural Gas IRP Appendices 505 111 2016 IRP Low –Med –High REAL 111 Avista Corp 2016 Natural Gas IRP Appendices 506 112112 Carbon Adder –Expected •Includes carbon pricing from 2026-2035 from our consultant •Avista added pricing starting from 2018 to address incremental adders from legislation in our service territory jurisdictions. –We assume floor pricing the same as California’s cap and trade of $10 back at the programs initial auction in 2013. 112 Avista Corp 2016 Natural Gas IRP Appendices 507 113113 Carbon Prices Expected = 2 Sigma of “Likely Policy” & No carbon & i-732 @ equally distributed between remaining probability 2018 $9.89 $19.93 113 Avista Corp 2016 Natural Gas IRP Appendices 508 114114 Avista Corp 2016 Natural Gas IRP Appendices 509 ..c: ....., C) ..._ 1./} $7.50 $6.50 $5.50 $4.50 $3.50 $2.50 $1.50 IJ') \0 r-,.. 00 rl rl rl rl 0 0 0 0 N N N N e:::::J Base Price ······Likely Policy Base Price with carbon adders 0) 0 rl N 0 0 N N rl N 0 N N ("(') N N 0 0 N N s::t" N 0 N IJ') \0 N N 0 0 N N r-,.. 00 N N 0 0 N N 0) N 0 N 0 rl ("(') ("(') 0 0 N N N ("(') 0 N Expected -No Carbon Adder --2015 Electric IRP expected case --i-732 ("(') s::t" ("(') ("(') 0 0 N N 115 Regional Price Assumptions 115 Regional Price as a percent of Henry Hub Price AECO Sumas Rockies Malin Stanfield Consultant1 89.9%98.8%95.4%101.4%100.4%Forecast Average Consultant2 85.3%94.2%96.7%98.6%96.8%Forecast Average Historic Cash 86.8%97.2%97.1%99.6%97.5%Three Yr Average Prior IRP 82.5%90.8%88.9%94.5%92.1% Avista Corp 2016 Natural Gas IRP Appendices 510 116 Monthly Price Shape 116 Monthly Price as a percent of Average Price Jan Feb Mar Apr May Jun Consult1 113.2%113.8%92.8%90.7%91.5%92.0% Consult2 99.9%99.7%98.7%97.1%97.7%98.6% Prior IRP 102.9%102.9%99.2%97.4%97.7%98.4% Jul Aug Sep Oct Nov Dec Consult1 93.5%94.5%94.3%95.3%109.7%118.9% Consult2 100.5%101.7%102.1%102.1%100.6%101.3% Prior IRP 99.3%99.5%99.6%99.4%100.8%103.2% Avista Corp 2016 Natural Gas IRP Appendices 511 117 Procurement Planning Tom Pardee, Manager of Natural Gas Planning Natural Gas Technical Advisory Committee March 16, 2016 Avista Corp 2016 Natural Gas IRP Appendices 512 118118 Procurement Plan Philosophy •Mission •To provide a diversified portfolio of reliable supply and a level of price certainty in volatile markets. •We cannot accurately predict what natural gas prices will do, however we can use experience, market intelligence, and fundamental market analysis to structure and guide our procurement strategies. •Our goal is to develop a plan that utilizes customer resources (storage and transportation), layers in pricing over time for stability (time averaging), allows discretion to take advantage of pricing opportunities should they arise, and appropriately manages risk. 118 Avista Corp 2016 Natural Gas IRP Appendices 513-'II._ ,11fillSTA" 119 Review conducted with SOG includes: •Mission statement and approach •Current and future market dynamics •Hedge type and percentage •Resources available (i.e. storage and transportation) •Hedge windows (how many, how long) •Long term hedging approach •Storage utilization •Analysis (volatility, past performance, scenarios, etc.) •Market opportunities Comprehensive Review of Previous Plan 119 Avista Corp 2016 Natural Gas IRP Appendices 514 120120 A Thorough Evaluation of Risks Risk Assessment Load Volatility •Seasonal Swings Price •Cash vs. Forward Market Liquidity •Is there enough? Counterparty •Who can we transact with? Foreign Currency •What’s our exposure? Legislation •Does it impact our plan? 120 Avista Corp 2016 Natural Gas IRP Appendices 515 121121 Procurement Plan Structure •The procurement plan incorporates a portfolio approach that is diversified in terms of: –Components: The plan utilizes a mix of index, fixed price, and storage transactions. –Transaction Dates:Hedge windows are developed to distribute the transactions throughout the plan. –Supply Basins:Plan to primarily utilize AECO, execute at lowest price basis at the time. –Delivery Periods:Hedges are completed in annual and/or seasonal timeframes. Long-term hedges may be executed. •Transactions are executed pursuant to a plan and process; however, the procurement plan allows Avista to be flexible to market conditions and opportunistic when appropriate. 121 Avista Corp 2016 Natural Gas IRP Appendices 516-'II._ ,11fillSTA" 122122 Avista Corp 2016 Natural Gas IRP Appendices 517 PROCUREMENTPLAN MIX ALL JURISDICTIONS Index 52% Discretiona ry Hedges 9% 123 Preliminary Modeling Results Tom Pardee, Manager of Natural Gas Planning Natural Gas Technical Advisory Committee March 26, 2014 Avista Corp 2016 Natural Gas IRP Appendices 518 124124 1.Customer annual growth rates: 2.Use per customer coefficients –3 year average use per HDD per customer 3.Weather planning standard –coldest day on record WA/ID 82; Medford 61; Roseburg 55; Klamath 72; La Grande 74 Developing a Reference Case Customer count forecast Use per customer coefficients Weather Reference Case Demand 124 Avista Corp 2016 Natural Gas IRP Appendices 519 125 Reference Demand Case 125 Avista Corp 2016 Natural Gas IRP Appendices 520 Year 2014 1 33,249 I 2 33,538 I 3 33,996 I 4 34,174 I 5 34,520 I 6 34,850 I 7 35,335 I 8 35,513 I 9 35,849 I 10 36,189 I 11 36,693 I 12 36,878 I 13 37,228 I 14 37,582 I 15 38,106 I 16 38,300 I 17 38,664 I 18 39,032 I 19 39,577 I 20 39,779 'IS.OX> 40,n io 1r,,n10 :SO)>.» ?S.OJO • ' n n • l:i :! ,o,n,o 1:,p.JO 10.0X> 5,000 201b lot.:1 2016 Delta 33,368 0% 33,582 0% 33,958 0% 34,339 0% 34,881 1% 35,125 1% 35,501 0% 35,861 1% 36,376 1% 36,571 1% 36,921 1% 37,267 1% 37,775 1% 37,947 1% 38,279 0% 38,604 1% 39,098 1% 39,244 1% 39,558 0% 39,870 0% Reference Case Comparison in total l:i :. • " !7 .. • 7 • • a • .ss.oco ~----------=R-e-.f-e-re_n_c-e"""C,-a_s_e_C:::-o-m_p_a~ri's_o_n _____________ _ by Jurisdiction ?'i,()('0 ,n,oro 15,0CO lO,OCO ~ .. Ollll +------------------------------------ -2016 Klem ;rt"I Follls -W-2014 t:l.im Mh F.llb -2016 LcCr.,ncc -e-:.lUlb Mccford/l{o:r:>ure-2014 Mcdfo'c/ {o:;cb..ir:~2'.)lb WA V -:lUl.4 t/\'A IU I • p 11 ,. --' :.!Ul4 1·~t.:JI ~2'.)lbU{ ....,_:.!Ul4UH ~lOlb \VA IU -e-:Wl4WA IU 126 Demand Sensitivities 126 Avista Corp 2016 Natural Gas IRP Appendices 521 DEMAND INFLUENCING • DIRECT PRICE INFLUEtlCING -INDIRECT Reference Peak plus Alterante Reference Plus Peak Low Cust High Cust CNGINGV Alternate DSPA CSU Historical Expected Low High Carbon LNG/ Methanol INPUT ASSUMPTIONS Case Case Growth Growth Vehicles Weather Std Case Case Case Elasticity Prices Prices Legistlation Customer Growth Rate Low Growth High Growth Use per Customer 3 Year 3 Year 3 Year 3 Year 5% Growth 3Year 3Year 3 Year 5 Year 3 Year 3 Year 3Year 3 Year I listorical 3Year Historical Historical Historical Historical Cumulative Historical Historical Historical Historical Historical Historical Historical Historical Weather 20 Yeor Coldest on Coldest on Coldest on Coldest on Coldest in Coldest on Coldest on Coldest on Coldest on Co!dest on Co!dest on Planning Standard Normal Record Record Record Record 20yrs Normal Record Record Record Record Record Coldest on Record Record Demand Side Management Programs Included No No No No No No Expected Expected No No No No No No Prices Price curve Expected Expected Expected Expected Expected Expected Expected Expected Expecte,j Expected Low High High/Medium/1..ow Expected Price curve adder ($i 0th) None None None None None None None None None High/Medium/1..ow $.25Adder After 5vrs Elasticity None None None None None None None None None Expected Expected Expected Expected Expected 127 Demand Sensitivities-Preliminary Results 127 Avista Corp 2016 Natural Gas IRP Appendices 522 46,000 2016 Demand Sensitivities -Demand Influencing Direct Annual Demand-Total System 30,000 +---~--~-~~-~--~--~--~--~--~--~-~~-~--~--~--~--~--~--~-~~-~ 128 Mix and Match to Make Scenarios 128 Avista Corp 2016 Natural Gas IRP Appendices 523 129 Demand Scenarios –Proposed 129 Avista Corp 2016 Natural Gas IRP Appendices 524 130 Weather Modeling 130 Avista Corp 2016 Natural Gas IRP Appendices 525-'II._ ,11fillSTA" 131 Coldest on Record Dates WA/ID –December 30, 1968 Medford –December 9, 1972 Roseburg –December 22, 1990 Klamath Falls –December 8, 2013 La Grande –December 23,1983 Area Coldest in 20 Year HDD Coldest on Record HDD WA-ID 76 82 Klamath Falls 72 72 La Grande 74 74 Medford 54 61 Roseburg 48 55 Planning Standard Assumptions 131 Avista Corp 2016 Natural Gas IRP Appendices 526 132132*2016 Reference Plus “ “ sensitivity132 Avista Corp 2016 Natural Gas IRP Appendices 527 330 320 310 300 290 280 270 260 250 WA-ID 265.92 -WA/ID & 82 HOD -WA/ID & 81 HOD -WA/ID & 77 HOD 322.15 - 318.50 133133 *2016 Reference Plus “ “ sensitivity133 Avista Corp 2016 Natural Gas IRP Appendices 528 Medford 75 72.09 70 65 60 57.24 55 50 -Medford & 61 HOD -Medford & 60 HOD -Medford & 56 HOD 134*2016 Reference Plus “ “ sensitivity134 Avista Corp 2016 Natural Gas IRP Appendices 529 Roseburg 17.50 17.04 17.00 16.50 16.00 ...c: 15.50 +-' 0 ~ 15.60 15.00 14.50 14.66 14.00 13.50 13.66 13.00 -Roseburg & 55 HDD -Roseburg & 54 HDD -Roseburg & 50 HDD 135 *2016 Reference Plus “ “ sensitivity135 Avista Corp 2016 Natural Gas IRP Appendices 530 Klamath Falls 17.00 16.66 16.50 16.00 15.50 15.00 ~ ..., 14.50 a ~ 14.00 13.30 13.50 13.00 12.50 12.45 12.00 -Klamath Falls & 72 HOD -Klamath Falls & 71 HOD -Klamath Falls & 67 HOD 136 *2016 Reference Plus “ “ sensitivity136 Avista Corp 2016 Natural Gas IRP Appendices 531 La Grande 9.00 8.87 · 8.80 8.60 8.77 8.40 8.20 8.07 8.35 ..c +J 0 8.00 ~ 7.97 7.80 7.60 7.59 7.40 7.20 7.00 -La Grande & 74 HDD -La Grande & 73 HDD -La Grande & 69 HDD .J.\\Jv1sT11· 137137 2016 IRP Timeline •August 31, 2015 –Work Plan filed with WUTC •January through April 2016 –Technical Advisory Committee meetings. Meeting topics will include: –Demand Forecast and Demand Side Management –January 21 –Supply/Infrastructure and Potential Case Discussion–February 18 –Distribution Planning, Natural Gas Pricing, SENDOUT® Preliminary Output Results and Further Case Discussion – March 30 –SENDOUT® results –April 21 •May 30, 2016 –Draft of IRP document to TAC •June 30, 2016 –Comments on draft due back to Avista •July 2016 –TAC final review meeting (if necessary) •August 31, 2016 –File finalized IRP document 137 Avista Corp 2016 Natural Gas IRP Appendices 532-'II._ ,11fillSTA" 1 2016 Avista Natural Gas IRP Technical Advisory Committee Meeting April 21, 2016 Spokane, WA Avista Corp 2016 Natural Gas IRP Appendices 533 22 Agenda •Introductions & Logistics •Avista Natural Gas Conservation Potential Assessment Results •Assumptions Review •Demand Sensitivities and Scenarios Updates •Supply Side Resource Options •Stochastic Analysis •Key Issues & Document Discussion 2 Avista Corp 2016 Natural Gas IRP Appendices 534-'II._ ,11fillSTA" 33 2016 IRP Timeline •August 31, 2015 –Work Plan filed with WUTC •January through April 2016 –Technical Advisory Committee meetings. Meeting topics will include: –Demand Forecast and Demand Side Management –January 21 –Supply/Infrastructure and Potential Case Discussion–February 18 –Distribution Planning, Natural Gas Pricing, SENDOUT® Preliminary Output Results and Further Case Discussion – March 30 –SENDOUT® results –April 21 •May 30, 2016 –Draft of IRP document to TAC •June 30, 2016 –Comments on draft due back to Avista •July 2016 –TAC final review meeting (if necessary) •August 31, 2016 –File finalized IRP document 3 Avista Corp 2016 Natural Gas IRP Appendices 535-'II._ ,11fillSTA" 4 Avista Corp 2016 Natural Gas IRP Appendices 536 . . . . . . . . . . ........................................................................................................................ : ........... : ........... : ........... : ........... : ........... : ........... : ........ A .. ·· ... E .... G:.: .......... : .......... . . . . . . . . . . ' ' • ' ' ' ' ·______:_. ' I ' ' . . . . . . . . . . . . . . . . . . ' ·_ . . . . . . . . . . . : ... ,,,,.,~ :Applied En~rgy Group: . . . . . . . . ........................................................................................................................ . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . [ : : : : . : : : : 1 · · · · · · · · · · · 1 · · · · · · · · · · · 1 AV'i'st·a· · N·ati1· ral' ·Gas · Ccin1s·e·rva·t·i·ori · · · · · · · · · · · . . . . . . . . . . . . . . . . . . : : : P,otential : As,sessment Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . : April 21, :2016 5 Topics •Overview of analysis approach •Results for each state –Market characterization –Baseline projection –Conservation potential estimates 5 Avista Corp 2016 Natural Gas IRP Appendices 537 6 Overview of Analysis Approach Develop energy market profiles and project the baseline Customer surveys (optional) Secondary data Forecast assumptions Prototypes and energy analysis Characterize the market Utility data Customer surveys (optional) Secondary data DSM measure list Measure description Avoided costs Perform measure screening Apply customer participation rates Recent program results Best-practices research Base-year energy use by fuel & segment Base-year profiles and baseline projection by fuel, segment & end use Technical and economic potential Achievable potential Input Data Analysis Steps Results 6 Avista Corp 2016 Natural Gas IRP Appendices 538 7 Overview of Analysis Approach Dimension Segmentation Variable Description 1 State Washington, Idaho, Oregon 2 Sector Residential, commercial, industrial 3 Segment Residential: single family, multi family, mobile homes and low income Commercial: office, restaurant, retail, grocery, school, college, health, lodging, warehouse, miscellaneous Industrial: total 4 Vintage Existing and new construction 5 End uses Heating, water heat, process, etc. (as appropriate by sector) 6 Appliances/end uses and technologies Technologies such as furnaces, boilers, water heaters, etc. 7 Equipment efficiency levels for new purchases Baseline and higher-efficiency options as appropriate for each technology 7 Avista Corp 2016 Natural Gas IRP Appendices 539 Washington Avista Corp 2016 Natural Gas IRP Appendices 540 9 High-level Market Characterization - Washington 2015 Natural Gas Sales by Sector Segment Annual Sales (DTh)% of Sales Residential 9,188,898 60% Commercial 5,734,759 38% Industrial 268,452 2% Total 30,375 100% 9 Avista Corp 2016 Natural Gas IRP Appendices 541 10 Residential Market Characterization - Washington Washington 2015 Sales (DTh)# of Customers Average Use per Household (Therms/HH) Single Family 6,016,941 85,875 701 Multifamily 349,141 7,909 441 Mobile Home 299,264 5,085 589 Low Income 2,523,553 42,372 596 Washington Total 9,188,898 141,241 651 10 Avista Corp 2016 Natural Gas IRP Appendices 542 11 Residential Market Profiles -Washington Base-year annual energy use by segment and end use Annual Intensity for Average Household Data Sources: •GenPOP Survey •RBSA •Utility billing data •AEG Market Profiles Database •Secondary data as needed to fill gaps Annual Use by End Use 11 Avista Corp 2016 Natural Gas IRP Appendices 543 12 Residential Energy Market Profile - Washington •This market profile represents the residential sector as a whole. Individual segment market profiles are provided in the report. •Saturations were developed using the GenPOP residential survey as the primary data source. Washington Total Total Households: End Use Technology Saturation UEC Intensity Usage (Therms)(Therms/(DTh) Space Heating Furnace 88.2% 509.5 449.1 6,343,260 Space Heating Boiler 2.3% 609.8 13.8 194,390 Space Heating Other Heating 9.6% 488.4 46.8 661,509 Water Heating Water Heater 56.6% 211.0 119.4 1,686,433 Appliances Clothes Dryer 9.9% 27.3 2.7 38,181 Appliances Stove/Oven 8.5% 57.3 4.9 68,899 Miscellaneous Pool Heater 0.7% 217.5 1.6 22,019 Miscellaneous Miscellaneous 100.0% 12.3 12.3 174,206 650.6 9,188,898 141,241 DTh 9,188,898 Total 12 Avista Corp 2016 Natural Gas IRP Appendices 544 13 Residential Baseline Projection - Washington •Baseline projection provides foundation for estimating potential future savings from conservation initiatives and reflects –Household growth and electricity price forecasts (from Avista) –Appliance standards in place at end of 2015 (AEG database) –Frozen efficiency –Does not include future utility programs •Baseline projection increases 38% between 2015 and 2036, or an average of 1.5% per year Residential Baseline Energy Projection (DTh) 13 Avista Corp 2016 Natural Gas IRP Appendices 545 14 Residential Savings Potential - Washington From 2017 to 2018, cumulative achievable potential energy savings are 62,492 DTh or 0.6% of the baseline. By 2036, cumulative savings are almost 10% of the baseline projection, or about 0.5% per year. Uses the UCT cost effectiveness test 2017 2018 2021 2026 2036 Baseline Projection (DTh)10,067,567 10,191,025 10,534,588 11,198,918 12,661,346 Cumulative Savings (DTh) Achievable Potential 27,598 62,492 207,653 497,074 1,226,734 Economic Potential 132,960 267,157 678,668 1,382,067 2,721,626 Technical Potential 187,192 377,121 956,051 1,951,370 3,828,466 Energy Savings (% of Baseline) Achievable Potential 0.3%0.6%2.0%4.4%9.7% Economic Potential 1.3%2.6%6.4%12.3%21.5% Technical Potential 1.9%3.7%9.1%17.4%30.2% 14 Avista Corp 2016 Natural Gas IRP Appendices 546 15 Residential Savings Potential - Washington Cumulative achievable potential in 2018 Cumulative Achievable Potential (DTh) Cumulative Achievable Potential in 2018 Rank Measure / Technology 2018 Achievable Savings (Cum. DTh) % of Total 1 Windows -High Efficiency 20,516 32.8% 2 Heating –Furnace (EF 0.98)19,873 31.8% 3 Furnace -Maintenance 4,025 6.4% 4 Water Heater -Low-Flow Showerheads 3,270 5.2% 5 Water Heater -Temperature Setback 2,983 4.8% 6 Insulation -Ceiling 2,914 4.7% 7 Ducting -Repair and Sealing 2,243 3.6% 8 Water Heating -Water Heater (EF 0.67)1,831 2.9% 9 Thermostat -Programmable/Interactive 1,797 2.9% 10 Water Heater -Pipe Insulation 1,582 2.5% 11 Heating –Boiler (EF 0.98)527 0.8% 12 Water Heater -Faucet Aerators 484 0.8% 13 Boiler -Maintenance 248 0.4% 14 Boiler -Pipe Insulation 199 0.3% 15 Insulation -Wall Sheathing 1 0.0% Total 62,492 100% 15 Avista Corp 2016 Natural Gas IRP Appendices 547 16 Commercial Market Characterization - Washington Washington 2015 Sales (DTh) Floor Space (sq. ft.) Intensity (therms/sqft) Office 608,320 23,532,683 0.26 Restaurant 357,257 1,615,817 2.21 Retail 609,276 20,141,347 0.30 Grocery 253,760 4,311,977 0.59 School 472,964 11,620,730 0.41 College 439,038 5,467,474 0.80 Health 648,945 9,103,062 0.71 Lodging 353,904 6,773,279 0.52 Warehouse 272,231 13,377,462 0.20 Miscellaneous 1,719,065 32,222,397 0.53 Washington Total 5,734,759 128,166,227 0.45 16 Avista Corp 2016 Natural Gas IRP Appendices 548 17 Commercial Market Profiles -Washington Base-year annual energy use by segment and end use Annual Intensity per Square Foot Data Sources: •CBSA •Utility billing data •AEG Market Profiles Database •Secondary data as needed to fill gaps Annual Use by End Use 17 Avista Corp 2016 Natural Gas IRP Appendices 549 18 Commercial Energy Market Profile - Washington •This market profile represents the Commercial sector as a whole. Individual segment market profiles are provided in the report. •Saturations were developed using the CBSA survey as the primary data source. EUI Intensity Usage (therm)(therm/Sqft)(DTh) Heating Furnace 54.3% 0.21 0.11 1,467,831 Heating Boiler 33.1% 0.48 0.16 2,030,710 Heating Unit Heater 4.7% 0.09 0.00 55,570 Water Heating Water Heater 68.7% 0.19 0.13 1,651,292 Food Preparation Oven 25.1% 0.02 0.00 56,768 Food Preparation Fryer 7.5% 0.12 0.01 114,766 Food Preparation Broiler 13.7% 0.04 0.01 67,939 Food Preparation Griddle 16.7% 0.03 0.00 61,216 Food Preparation Range 18.3% 0.03 0.01 69,753 Food Preparation Steamer 2.0% 0.03 0.00 8,759 Food Preparation Commercial Food Prep Other 0.1% 0.01 0.00 69 Miscellaneous Pool Heater 0.9% 0.00 0.00 356 Miscellaneous Other Miscellaneous 100.0% 0.01 0.01 149,731 0.45 5,734,759Total Gas Market Profiles End Use Technology Saturation 18 Avista Corp 2016 Natural Gas IRP Appendices 550 19 Commercial Baseline Projection - Washington •Baseline projection provides foundation for estimating potential future savings from conservation initiatives and reflects –Customer growth (from Avista) –Building Codes and appliance standards in place at end of 2015 (AEG database) –Frozen efficiency –Does not include future utility programs •Baseline projection increases 23% between 2015 and 2036, or an average of 1% per year Commercial Baseline Energy Projection (DTh) 19 Avista Corp 2016 Natural Gas IRP Appendices 551 20 Estimating Conservation Potential •The study analyzed 100 measures covering residential, commercial and industrial sectors. •Cost-effectiveness screening to estimate economic potential was done using utility cost test for Washington and Idaho, and using the TRC for Oregon •Customer adoption or “ramp rates” are needed to estimate achievable potential. The study used regional ramp rates to start and then calibrated based on Avista’s program history •The study uses AEG’s LoadMAP model to estimate potential Technical Potential Theoretical upper limit of EE, where all efficiency measures are phased in regardless of cost Economic Potential Also a theoretical upper limit of EE, but includes only cost-effective measures Achievable Potential EE potential that can be realistically achieved by utilities, accounting for customer adoption rates and how quickly programs can be implemented 20 Avista Corp 2016 Natural Gas IRP Appendices 552 21 Commercial Savings Potential - Washington From 2017 to 2018, cumulative achievable potential energy savings are 53,246 DTh or 0.9% of the baseline. By 2036, cumulative savings are over 12% of the baseline projection, or about 0.7% per year. Uses the UCT cost effectiveness test 2017 2018 2021 2026 2036 Baseline Projection (DTh)6,220,478 6,236,027 6,305,231 6,490,547 7,066,197 Cumulative Savings (DTh) Achievable Potential 22,978 53,246 176,816 413,219 878,225 Economic Potential 70,810 140,765 339,275 637,762 1,124,744 Technical Potential 108,572 214,053 512,953 960,878 1,686,375 Energy Savings (% of Baseline) Achievable Potential 0.4%0.9%2.8%6.4%12.4% Economic Potential 1.1%2.3%5.4%9.8%15.9% Technical Potential 1.7%3.4%8.1%14.8%23.9% 21 Avista Corp 2016 Natural Gas IRP Appendices 553 22 Commercial Savings Potential - Washington Cumulative achievable potential in 2018 Cumulative Achievable Potential (DTh) Cumulative Achievable Potential in 2018 Rank Measure / Technology 2018 Achievable Savings (Cum. DTh) % of Total 1 Retrocommissioning 13,476 25.3% 2 Heating –Boiler (EF 0.96)11,887 22.3% 3 Gas Boiler -Hot Water Reset 5,159 9.7% 4 Heating –Furnace (EF 0.96)4,102 7.7% 5 Insulation -Ceiling 3,360 6.3% 6 Water Heating -Water Heater (Tankless)2,826 5.3% 7 Water Heater -Faucet Aerators/Low Flow Nozzles 2,150 4.0% 8 Water Heater -Central Controls 1,979 3.7% 9 Strategic Energy Management 1,784 3.4% 10 Water Heater -Pre-Rinse Spray Valve 1,564 2.9% 11 Gas Boiler -Parallel Positioning Control 1,540 2.9% 12 Food Preparation –Fryer (ENERGY STAR)740 1.4% 13 Steam Trap Maintenance 657 1.2% 14 Food Preparation -Oven (ENERGY STAR)386 0.7% 15 HVAC -Shut Off Damper 304 0.6% 16 Food Preparation -Griddle (ENERGY STAR)235 0.4% 17 Windows -High Efficiency 223 0.4% 18 Water Heater -Pipe Insulation 204 0.4% 19 Food Preparation -Steamer (ENERGY STAR)184 0.3% 20 Heating -Unit Heater (Condensing)171 0.3% Total 52,933 99.4%Avista Corp 2016 Natural Gas IRP Appendices 554 23 Industrial Energy Market Profile - Washington •This market profile represents the Industrial sector as a whole. The industrial sector is not large enough to warrant further segmentation. EUI Intensity Usage (Therms)(Therms/sqft)(Dth) Space Heating Furnace 56.5%0.028 0.02 5,563 Space Heating Boiler 34.4%0.089 0.03 10,891 Space Heating Other Heating 4.9%0.014 0.00 239 Process Process Heating 100.0% 0.369 0.37 131,596 Process Process Boiler 100.0% 0.282 0.28 100,538 Process Process Cooling 100.0% 0.001 0.00 407 Process Other Process 100.0% 0.004 0.00 1,580 Other Other Uses 100.0% 0.049 0.05 17,638 0.75 268,452 Washington Industrial Total Sq Ft:3,567,948 DTh 268,452 Total End Use Technology Saturation 23 Avista Corp 2016 Natural Gas IRP Appendices 555 24 Industrial Baseline Projection - Washington •Baseline projection provides foundation for estimating potential future savings from conservation initiatives and reflects –Customer growth (from Avista) –Building Codes and appliance standards in place at end of 2015 (AEG database) –Frozen efficiency –Does not include future utility programs •Baseline projection increases 35% between 2015 and 2036, or an average of 1.4% per year Industrial Baseline Energy Projection (DTh) 24 Avista Corp 2016 Natural Gas IRP Appendices 556 25 Industrial Savings Potential -Washington From 2017 to 2018, cumulative achievable potential energy savings are 777 DTh or 0.3% of the baseline. By 2036, cumulative savings are 2.3% of the baseline projection, or about 0.1% per year. Uses the UCT cost effectiveness test 2017 2018 2021 2026 2036 Baseline Projection (DTh)283,824 287,571 298,345 318,546 363,144 Cumulative Savings (DTh) Achievable Potential 383 777 1,993 4,050 8,414 Economic Potential 876 1,757 4,413 8,941 18,457 Technical Potential 3,195 6,425 16,314 33,603 71,042 Energy Savings (% of Baseline) Achievable Potential 0.1%0.3%0.7%1.3%2.3% Economic Potential 0.3%0.6%1.5%2.8%5.1% Technical Potential 1.1%2.2%5.5%10.5%19.6% 25 Avista Corp 2016 Natural Gas IRP Appendices 557 26 Industrial Savings Potential -Washington Cumulative achievable potential in 2018 Cumulative Achievable Potential (DTh) Cumulative Achievable Potential in 2018 Rank Measure / Technology 2018 Achievable Savings (Cum. DTh) % of Total 1 Custom 415 53.5% 2 Boiler -Hot Water Reset 205 26.4% 3 Boiler -Parallel Positioning Control 97 12.5% 4 Boiler -Maintenance 46 5.9% 5 Steam Trap Maintenance 11 1.5% 6 Gas Furnace -Maintenance 2 0.3% Total 777 100.0% 26 Avista Corp 2016 Natural Gas IRP Appendices 558 Idaho Avista Corp 2016 Natural Gas IRP Appendices 559 28 High-level Market Characterization - Idaho 2015 Natural Gas Sales by Sector Segment Annual Sales (DTh)% of Sales Residential 4,304,740 62% Commercial 2,456,621 35% Industrial 187,203 3% Total 6,948,564 100% 28 Avista Corp 2016 Natural Gas IRP Appendices 560 29 Residential Market Characterization - Idaho Idaho 2015 Sales (DTh)# of Customers Average Use per Household (Therms/HH) Single Family 2,814,373 42,852 657 Multifamily 142,894 3,454 414 Mobile Home 174,973 3,172 552 Low Income 1,172,501 21,003 558 Idaho Total 4,304,740 70,481 611 29 Avista Corp 2016 Natural Gas IRP Appendices 561 30 Residential Market Profiles -Idaho Base-year annual energy use by segment and end use Annual Intensity for Average Household Data Sources: •GenPOP Survey •RBSA •Utility billing data •AEG Market Profiles Database •Secondary data as needed to fill gaps Annual Use by End Use 30 Avista Corp 2016 Natural Gas IRP Appendices 562 31 Residential Energy Market Profile -Idaho •This market profile represents the residential sector as a whole. Individual segment market profiles are provided in the report. •Saturations were developed using the GenPOP residential survey as the primary data source. Idaho Total Total Households: End Use Technology Saturation UEC Intensity Usage (Therms)(Therms/(DTh) Space Heating Furnace 84.2% 484.5 407.8 2,873,917 Space Heating Boiler 2.0% 579.2 11.8 83,322 Space Heating Other Heating 13.8% 466.4 64.4 453,852 Water Heating Water Heater 54.3% 200.8 109.1 768,890 Appliances Clothes Dryer 9.2% 29.0 2.7 18,876 Appliances Stove/Oven 9.2% 60.1 5.5 39,043 Miscellaneous Pool Heater 0.3% 217.4 0.6 4,134 Miscellaneous Miscellaneous 100.0% 8.9 8.9 62,706 610.8 4,304,740 70,481 DTh 4,304,740 Total 31 Avista Corp 2016 Natural Gas IRP Appendices 563 32 Residential Baseline Projection -Idaho •Baseline projection provides foundation for estimating potential future savings from conservation initiatives and reflects –Household growth and electricity price forecasts (from Avista) –Appliance standards in place at end of 2015 (AEG database) –Frozen efficiency –Does not include future utility programs •Baseline projection increases 44% between 2015 and 2036, or an average of 1.7% per year Residential Baseline Energy Projection (DTh) 32 Avista Corp 2016 Natural Gas IRP Appendices 564 33 Residential Savings Potential -Idaho From 2017 to 2018, cumulative achievable potential energy savings are 62,492 DTh or 0.6% of the baseline. By 2036, cumulative savings are almost 10% of the baseline projection, or about 0.5% per year. Uses the UCT cost effectiveness test 2017 2018 2021 2026 2036 Baseline Projection (DTh)4,741,736 4,802,813 4,992,555 5,366,588 6,213,091 Cumulative Savings (DTh) Achievable Potential 11,138 25,406 85,812 208,875 536,817 Economic Potential 53,686 108,042 276,801 577,890 1,198,833 Technical Potential 82,162 165,579 422,556 873,781 1,776,196 Energy Savings (% of Baseline) Achievable Potential 0.2%0.5%1.7%3.9%8.6% Economic Potential 1.1%2.2%5.5%10.8%19.3% Technical Potential 1.7%3.4%8.5%16.3%28.6% 33 Avista Corp 2016 Natural Gas IRP Appendices 565 34 Residential Savings Potential -Idaho Cumulative achievable potential in 2018 Cumulative Achievable Potential (DTh) Cumulative Achievable Potential in 2018 Rank Measure / Technology 2018 Achievable Savings (Cum. DTh) % of Total 1 Windows -High Efficiency 9,778 38.5% 2 Heating –Furnace (EF 0.98)6,692 26.3% 3 Furnace -Maintenance 1,821 7.2% 4 Water Heater -Low-Flow Showerheads 1,480 5.8% 5 Insulation -Ceiling 1,379 5.4% 6 Water Heater -Temperature Setback 1,365 5.4% 7 Thermostat -Programmable/Interactive 861 3.4% 8 Water Heater -Pipe Insulation 725 2.9% 9 Water Heating -Water Heater (EF 0.67)660 2.6% 10 Heating –Boiler (EF 0.98)235 0.9% 11 Water Heater -Faucet Aerators 219 0.9% 12 Boiler -Maintenance 106 0.4% 13 Boiler -Pipe Insulation 86 0.3% Total 25,406 100% 34 Avista Corp 2016 Natural Gas IRP Appendices 566 35 Commercial Market Characterization - Idaho Idaho 2015 Sales (DTh) Floor Space (sq. ft.) Intensity (therms/sqft) Office 214,228 8,388,655 0.26 Restaurant 55,373 253,503 2.18 Retail 314,742 10,531,910 0.30 Grocery 97,810 1,682,340 0.58 School 387,333 9,633,126 0.40 College 360,160 4,540,014 0.79 Health 222,359 3,157,269 0.70 Lodging 135,614 2,627,216 0.52 Warehouse 110,269 5,484,890 0.20 Miscellaneous 558,735 10,601,048 0.53 Idaho Total 2,456,621 56,899,971 0.43 35 Avista Corp 2016 Natural Gas IRP Appendices 567 36 Commercial Market Profiles -Idaho Base-year annual energy use by segment and end use Annual Intensity per Square Foot Data Sources: •CBSA •Utility billing data •AEG Market Profiles Database •Secondary data as needed to fill gaps Annual Use by End Use 36 Avista Corp 2016 Natural Gas IRP Appendices 568 37 Commercial Energy Market Profile - Idaho •This market profile represents the Commercial sector as a whole. Individual segment market profiles are provided in the report. •Saturations were developed using the CBSA survey as the primary data source. EUI Intensity Usage (therm)(therm/Sqft)(DTh) Heating Furnace 51.2% 0.20 0.10 588,380 Heating Boiler 36.0% 0.45 0.16 930,819 Heating Unit Heater 4.9% 0.09 0.00 25,385 Water Heating Water Heater 69.3% 0.19 0.13 734,648 Food Preparation Oven 24.5% 0.02 0.00 27,505 Food Preparation Fryer 7.7% 0.09 0.01 40,765 Food Preparation Broiler 14.0% 0.03 0.00 22,933 Food Preparation Griddle 16.3% 0.02 0.00 20,023 Food Preparation Range 18.3% 0.02 0.00 23,972 Food Preparation Steamer 3.0% 0.02 0.00 4,249 Food Preparation Commercial Food Prep Other 0.1% 0.00 0.00 29 Miscellaneous Pool Heater 0.8% 0.00 0.00 119 Miscellaneous Other Miscellaneous 100.0% 0.01 0.01 37,793 0.43 2,456,621 Gas Market Profiles End Use Technology Saturation Total 37 Avista Corp 2016 Natural Gas IRP Appendices 569 38 Commercial Baseline Projection -Idaho •Baseline projection provides foundation for estimating potential future savings from conservation initiatives and reflects –Customer growth (from Avista) –Building Codes and appliance standards in place at end of 2015 (AEG database) –Frozen efficiency –Does not include future utility programs •Baseline projection increases 23% between 2015 and 2036, or an average of 1% per year Commercial Baseline Energy Projection (DTh) 38 Avista Corp 2016 Natural Gas IRP Appendices 570 39 Commercial Savings Potential -Idaho From 2017 to 2018, cumulative achievable potential energy savings are 21,619 DTh or 0.8% of the baseline. By 2036, cumulative savings are almost 12% of the baseline projection, or about 0.6% per year. Uses the UCT cost effectiveness test 2017 2018 2021 2026 2036 Baseline Projection (DTh)2,656,853 2,664,007 2,695,763 2,776,753 3,021,253 Cumulative Savings (DTh) Achievable Potential 9,311 21,619 72,680 170,883 359,503 Economic Potential 29,135 58,035 140,114 263,474 459,135 Technical Potential 47,785 94,237 226,002 423,332 744,715 Energy Savings (% of Baseline) Achievable Potential 0.4%0.8%2.7%6.2%11.9% Economic Potential 1.1%2.2%5.2%9.5%15.2% Technical Potential 1.8%3.5%8.4%15.2%24.6% 39 Avista Corp 2016 Natural Gas IRP Appendices 571 40 Commercial Savings Potential -Idaho Cumulative achievable potential in 2018 Cumulative Achievable Potential (DTh) Cumulative Achievable Potential in 2018 Rank Measure / Technology 2018 Achievable Savings (Cum. DTh) % of Total 1 Retrocommissioning 5,761 26.6% 2 Heating –Boiler (EF 0.96)4,812 22.3% 3 Gas Boiler -Hot Water Reset 2,364 10.9% 4 Heating –Furnace (EF 0.96)1,919 8.9% 5 Water Heating -Water Heater (Tankless)1,343 6.2% 6 Insulation -Ceiling 1,105 5.1% 7 Water Heater -Faucet Aerators/Low Flow Nozzles 955 4.4% 8 Water Heater -Central Controls 892 4.1% 9 Water Heater -Pre-Rinse Spray Valve 631 2.9% 10 Gas Boiler -Parallel Positioning Control 598 2.8% 11 Steam Trap Maintenance 294 1.4% 12 Food Preparation –Fryer (ENERGY STAR)264 1.2% 13 Food Preparation –Oven (ENERGY STAR)188 0.9% 14 Water Heater -Pipe Insulation 91 0.4% 15 Food Preparation -Steamer (ENERGY STAR)90 0.4% 16 Food Preparation -Griddle (ENERGY STAR)77 0.4% 17 Windows -High Efficiency 77 0.4% 18 Food Preparation -Broiler (ENERGY STAR)55 0.3% 19 Heating -Unit Heater (Condensing)47 0.2% 20 HVAC -Duct Repair and Sealing 27 0.1% Total 21,592 99.9% 40 Avista Corp 2016 Natural Gas IRP Appendices 572 41 Industrial Energy Market Profile -Idaho •This market profile represents the Industrial sector as a whole. The industrial sector is not large enough to warrant further segmentation.EUI Intensity Usage (Therms)(Therms/sqft)(Dth) Space Heating Furnace 56.5% 0.026 0.01 3,879 Space Heating Boiler 34.4% 0.085 0.03 7,595 Space Heating Other Heating 4.9% 0.013 0.00 167 Process Process Heating 100.0% 0.353 0.35 91,768 Process Process Boiler 100.0% 0.270 0.27 70,109 Process Process Cooling 100.0% 0.001 0.00 284 Process Other Process 100.0% 0.004 0.00 1,102 Other Other Uses 100.0% 0.047 0.05 12,299 0.72 187,203 Idaho Industrial Total Sq Ft:2,596,257 DTh 187,203 Total End Use Technology Saturation 41 Avista Corp 2016 Natural Gas IRP Appendices 573 42 Industrial Baseline Projection -Idaho •Baseline projection provides foundation for estimating potential future savings from conservation initiatives and reflects –Customer growth (from Avista) –Building Codes and appliance standards in place at end of 2015 (AEG database) –Frozen efficiency –Does not include future utility programs •Baseline projection increases 70% between 2015 and 2036, or an average of 2.5% per year Industrial Baseline Energy Projection (DTh) 42 Avista Corp 2016 Natural Gas IRP Appendices 574 43 Industrial Savings Potential -Idaho From 2017 to 2018, cumulative achievable potential energy savings are 641 DTh or 0.3% of the baseline. By 2036, cumulative savings are 4.3% of the baseline projection, or about 0.1% per year. Uses the UCT cost effectiveness test 2017 2018 2021 2026 2036 Baseline Projection (DTh)211,629 216,490 229,739 256,083 318,182 Cumulative Savings (DTh) Achievable Potential 306 641 1,809 4,411 13,717 Economic Potential 700 1,450 4,005 9,723 29,846 Technical Potential 2,446 5,049 13,661 31,578 81,807 Energy Savings (% of Baseline) Achievable Potential 0.1%0.3%0.8%1.7%4.3% Economic Potential 0.3%0.7%1.7%3.8%9.4% Technical Potential 1.2%2.3%5.9%12.3%25.7% 43 Avista Corp 2016 Natural Gas IRP Appendices 575 44 Industrial Savings Potential-Idaho Cumulative achievable potential in 2018 Cumulative Achievable Potential (DTh) Cumulative Achievable Potential in 2018 Rank Measure / Technology 2018 Achievable Savings (Cum. DTh) % of Total 1 Custom 338 52.7% 2 Boiler -Hot Water Reset 171 26.7% 3 Boiler -Parallel Positioning Control 81 12.7% 4 Boiler -Maintenance 39 6.0% 5 Steam Trap Maintenance 10 1.5% 6 Gas Furnace -Maintenance 2 0.3% Total 641 100.0% 44 Avista Corp 2016 Natural Gas IRP Appendices 576 Oregon Avista Corp 2016 Natural Gas IRP Appendices 577 ' -- - ~ AEG ,,,, .. ,~ .. Applied Energy Group 46 High-level Market Characterization - Oregon 2015 Natural Gas Sales by Sector Segment Annual Sales (DTh)% of Sales Residential 4,303,206 61% Commercial 2,699,252 38% Industrial 51,369 1% Total 7,053,827 100% 46 Avista Corp 2016 Natural Gas IRP Appendices 578 47 Residential Market Characterization - Oregon Oregon 2015 Sales (DTh)# of Customers Average Use per Household (Therms/HH) Single Family 2,811,856 53,617 524 Multifamily 81,940 2,480 330 Mobile Home 271,183 6,156 441 Low Income 1,138,226 25,534 446 Oregon Total 4,303,206 87,787 490 47 Avista Corp 2016 Natural Gas IRP Appendices 579 48 Residential Market Profiles -Oregon Base-year annual energy use by segment and end use Annual Intensity for Average Household Data Sources: •RBSA •Utility billing data •AEG Market Profiles Database •Secondary data as needed to fill gaps Annual Use by End Use 48 Avista Corp 2016 Natural Gas IRP Appendices 580 49 Residential Energy Market Profile - Oregon •This market profile represents the residential sector as a whole. Individual segment market profiles are provided in the report. •Saturations were developed using the RBSA survey as the primary data source. 49 Avista Corp 2016 Natural Gas IRP Appendices 581 50 Residential Baseline Projection -Oregon •Baseline projection provides foundation for estimating potential future savings from conservation initiatives and reflects –Household growth and electricity price forecasts (from Avista) –Appliance standards in place at end of 2015 (AEG database) –Frozen efficiency –Does not include future utility programs •Baseline projection increases 30% between 2015 and 2036, or an average of 1.2% per year Residential Baseline Energy Projection (DTh) 50 Avista Corp 2016 Natural Gas IRP Appendices 582 51 Residential Savings Potential -Oregon From 2017 to 2018, cumulative achievable potential energy savings are 13,839 DTh or 0.3% of the baseline. By 2036, cumulative savings are almost 5% of the baseline projection, or about 0.2% per year. Uses the TRC cost effectiveness test 2017 2018 2021 2026 2036 Baseline Projection (DTh)4,808,069 4,852,168 4,931,394 5,137,402 5,588,507 Cumulative Savings (DTh) Achievable Potential 6,507 13,839 38,671 94,086 260,939 Economic Potential 21,867 44,161 111,658 228,569 483,538 Technical Potential 83,073 167,062 418,531 844,811 1,615,605 Energy Savings (% of Baseline) Achievable Potential 0.1%0.3%0.8%1.8%4.7% Economic Potential 0.5%0.9%2.3%4.4%8.7% Technical Potential 1.7%3.4%8.5%16.4%28.9% 51 Avista Corp 2016 Natural Gas IRP Appendices 583 52 Residential Savings Potential -Oregon Cumulative achievable potential in 2018 Cumulative Achievable Potential (DTh) Cumulative Achievable Potential in 2018 Rank Measure / Technology 2018 Achievable Savings (Cum. DTh) % of Total 1 Heating -Furnace 7,400 53.5% 2 Water Heater -Low-Flow Showerheads 1,743 12.6% 3 Water Heater -Temperature Setback 1,640 11.9% 4 Furnace -Maintenance 1,477 10.7% 5 Water Heater -Pipe Insulation 871 6.3% 6 Water Heater -Faucet Aerators 257 1.9% 7 Windows -High Efficiency 235 1.7% 8 Boiler -Maintenance 108 0.8% 9 Boiler -Pipe Insulation 86 0.6% 10 Heating –Boiler (EF 0.98)22 0.2% Total 13,839 100% 52 Avista Corp 2016 Natural Gas IRP Appendices 584 53 Commercial Market Characterization - Oregon Oregon 2015 Sales (DTh) Floor Space (sq. ft.) Intensity (therms/sqft) Office 406,757 8,388,655 0.16 Restaurant 302,349 253,503 1.39 Retail 401,181 10,531,910 0.19 Grocery 173,578 1,682,340 0.37 School 273,450 9,633,126 0.26 College 34,880 4,540,014 0.50 Health 401,052 3,157,269 0.45 Lodging 174,610 2,627,216 0.33 Warehouse 143,426 5,484,890 0.13 Miscellaneous 387,969 10,601,048 0.34 Oregon Total 2,699,252 56,899,971 0.27 53 Avista Corp 2016 Natural Gas IRP Appendices 585 54 Commercial Market Profiles -Oregon Base-year annual energy use by segment and end use Annual Intensity per Square Foot Data Sources: •CBSA •Utility billing data •AEG Market Profiles Database •Secondary data as needed to fill gaps Annual Use by End Use 54 Avista Corp 2016 Natural Gas IRP Appendices 586 55 Commercial Energy Market Profile - Oregon •This market profile represents the Commercial sector as a whole. Individual segment market profiles are provided in the report. •Saturations were developed using the CBSA survey as the primary data source. 55 Avista Corp 2016 Natural Gas IRP Appendices 587 56 Commercial Baseline Projection - Oregon •Baseline projection provides foundation for estimating potential future savings from conservation initiatives and reflects –Customer growth (from Avista) –Building Codes and appliance standards in place at end of 2015 (AEG database) –Frozen efficiency –Does not include future utility programs •Baseline projection increases 38% between 2015 and 2036, or an average of 1.5% per year Commercial Baseline Energy Projection (DTh) 56 Avista Corp 2016 Natural Gas IRP Appendices 588 57 Commercial Savings Potential -Oregon From 2017 to 2018, cumulative achievable potential energy savings are 17,527 DTh or 0.5% of the baseline. By 2036, cumulative savings are almost 10% of the baseline projection, or about 0.5% per year. Uses the TRC cost effectiveness test 2017 2018 2021 2026 2036 Baseline Projection (DTh)3,215,033 3,219,537 3,264,933 3,383,711 3,729,054 Cumulative Savings (DTh) Achievable Potential 7,921 17,527 54,701 142,594 363,123 Economic Potential 22,299 44,184 110,800 228,191 470,854 Technical Potential 56,697 109,388 262,836 500,789 919,302 Energy Savings (% of Baseline) Achievable Potential 0.2%0.5%1.7%4.2%9.7% Economic Potential 0.7%1.4%3.4%6.7%12.6% Technical Potential 1.8%3.4%8.1%14.8%24.7% 57 Avista Corp 2016 Natural Gas IRP Appendices 589 58 Commercial Savings Potential -Oregon Cumulative achievable potential in 2018 Cumulative Achievable Potential (DTh) Cumulative Achievable Potential in 2018 Rank Measure / Technology 2018 Achievable Savings (Cum. DTh) % of Total 1 Retrocommissioning 5,781 33.0% 2 Gas Boiler -Hot Water Reset 1,954 11.2% 3 Water Heater -Central Controls 1,711 9.8% 4 Heating -Boiler 1,700 9.7% 5 Water Heating -Water Heater 1,316 7.5% 6 Commissioning 1,162 6.6% 7 Water Heater -Faucet Aerators/Low Flow Nozzles 1,098 6.3% 8 Water Heater -Pre-Rinse Spray Valve 1,009 5.8% 9 Food Preparation -Fryer 519 3.0% 10 Steam Trap Maintenance 384 2.2% 11 Food Preparation -Oven 215 1.2% 12 Food Preparation -Griddle 160 0.9% 13 Windows -High Efficiency 144 0.8% 14 Food Preparation -Steamer 115 0.7% 15 Water Heater -Pipe Insulation 106 0.6% 16 Water Heater -Drainwater Heat Recovery 68 0.4% 17 HVAC -Duct Repair and Sealing 46 0.3% 18 Food Preparation -Broiler 37 0.2% 19 Gas Boiler -Parallel Positioning Control 2 0.0% 20 Food Preparation -Range 0 0.0% Total 17,527 100.0% 58 Avista Corp 2016 Natural Gas IRP Appendices 590 59 Industrial Energy Market Profile -Oregon •This market profile represents the Industrial sector as a whole. The industrial sector is not large enough to warrant further segmentation. EUI Intensity Usage (Therms)(Therms/sqft)(Dth) Space Heating Furnace 56.5% 0.025 0.01 1,064 Space Heating Boiler 34.4% 0.081 0.03 2,084 Space Heating Other Heating 4.9% 0.013 0.00 46 Process Process Heating 100.0% 0.338 0.34 25,181 Process Process Boiler 100.0% 0.258 0.26 19,238 Process Process Cooling 100.0% 0.001 0.00 78 Process Other Process 100.0% 0.004 0.00 302 Other Other Uses 100.0% 0.045 0.05 3,375 0.69 51,369 Oregon Industrial 51,369 Total Sq Ft:744,804 DTh End Use Technology Saturation Total 59 Avista Corp 2016 Natural Gas IRP Appendices 591 60 Industrial Baseline Projection -Oregon •Baseline projection provides foundation for estimating potential future savings from conservation initiatives and reflects –Customer growth (from Avista) –Building Codes and appliance standards in place at end of 2015 (AEG database) –Frozen efficiency –Does not include future utility programs •Baseline projection increases 31% between 2015 and 2036, or an average of 1.4% per year Industrial Baseline Energy Projection (DTh) 60 Avista Corp 2016 Natural Gas IRP Appendices 592 61 Industrial Savings Potential -Oregon From 2017 to 2018, cumulative achievable potential energy savings are 641 DTh or 0.3% of the baseline. By 2036, cumulative savings are 4.3% of the baseline projection, or about 0.1% per year. Uses the TRC cost effectiveness test 2017 2018 2021 2026 2036 Baseline Projection (DTh)51,346 52,041 54,200 58,303 67,465 Cumulative Savings (DTh) Achievable Potential 73 147 379 773 1,622 Economic Potential 166 333 839 1,707 3,557 Technical Potential 602 1,209 3,078 6,371 13,602 Energy Savings (% of Baseline) Achievable Potential 0.0%0.1%0.2%0.3%0.5% Economic Potential 0.1%0.2%0.4%0.7%1.1% Technical Potential 0.3%0.6%1.3%2.5%4.3% 61 Avista Corp 2016 Natural Gas IRP Appendices 593 62 Industrial Savings Potential-Oregon Cumulative achievable potential in 2018 Cumulative Achievable Potential (DTh) Cumulative Achievable Potential in 2018 Rank Measure / Technology 2018 Achievable Savings (Cum. DTh) % of Total 1 Custom 338 52.7% 2 Boiler -Hot Water Reset 171 26.7% 3 Boiler -Parallel Positioning Control 81 12.7% 4 Boiler -Maintenance 39 6.0% 5 Steam Trap Maintenance 10 1.5% 6 Gas Furnace -Maintenance 2 0.3% Total 641 100.0% 62 Avista Corp 2016 Natural Gas IRP Appendices 594 Ingrid Rohmund irohmund@appliedenergygroup.com Bridget Kester bkester@appliedenergygroup.com Fuong Nguyen fnguyen@appliedenergygroup.com Joe Reilly jreilly@appliedenergygroup.com Thank You! Avista Corp 2016 Natural Gas IRP Appendices 595 64 Assumptions Review Avista Corp 2016 Natural Gas IRP Appendices 596 6565 1.Customer annual growth rates: 2.Use per customer coefficients –3 year average use per HDD per customer 3.Weather planning standard –coldest day on record WA/ID 82; Medford 61; Roseburg 55; Klamath 72; La Grande 74 Developing a Reference Case Customer count forecast Use per customer coefficients Weather Reference Case Demand 65 Avista Corp 2016 Natural Gas IRP Appendices 597 6666 WA-ID Region Firm Customers: 2016 IRP and 2014 IRP 210,000 220,000 230,000 240,000 250,000 260,000 270,000 280,000 290,000 300,000 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 WA-ID-Base 2014 WA-ID-Base +5,500 IRP Avg.Annual Growth 2016-2035 2014 1.0% 2016 1.1% 66 Avista Corp 2016 Natural Gas IRP Appendices 598 6767 OR Region Firm Customers: 2016 IRP and 2014 IRP 80,000 85,000 90,000 95,000 100,000 105,000 110,000 115,000 120,000 125,000 130,000 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 OR-Base 2014 OR-Base IRP Avg.Annual Growth 2016-2035 2014 0.9% 2016 1.2% +7,000 67 Avista Corp 2016 Natural Gas IRP Appendices 599 6868 System Firm Customers: 2016 IRP and 2014 IRP 300,000 320,000 340,000 360,000 380,000 400,000 420,000 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 WA-ID-OR-Base 2014 WA-ID-OR-Base +12,500 IRP Avg.Annual Growth 2016-2035 2014 1.0% 2016 1.1% 68 Avista Corp 2016 Natural Gas IRP Appendices 600 69 2016 IRP Low –Med –High REAL 69 Avista Corp 2016 Natural Gas IRP Appendices 601 70 Price Elasticity: What does the research show? 70 Avista Corp 2016 Natural Gas IRP Appendices 602 7171 Price Elasticity Proposed Assumptions •The data is a mixed bag at best: •8 of 9 super regions have statistically significant short and long run elasticity's. •At a state level only 10 of 50 show statistical significant elasticity's. •In some cases, the estimated elasticity's are positive. –We incorporated a -.15 price elastic response for our expected elasticity assumption. 71 Avista Corp 2016 Natural Gas IRP Appendices 603-'II._ ,11fillSTA" 7272 Carbon Adder –Expected •Includes carbon pricing from 2026-2035 from our consultant •Avista added pricing starting from 2018 to address incremental adders from legislation in our service territory jurisdictions. –We assume floor pricing the same as California’s cap and trade of $10 back at the programs initial auction in 2013. 72 Avista Corp 2016 Natural Gas IRP Appendices 604 73 Coldest on Record Dates WA/ID –December 30, 1968 Medford –December 9, 1972 Roseburg –December 22, 1990 Klamath Falls –December 21,1990 LaGrande –December 23,1983 Area Coldest in 20 Year HDD Coldest on Record HDD WA-ID 76 82 Klamath Falls 72 72 La Grande 74 74 Medford 54 61 Roseburg 48 55 73 Planning Standard Assumptions Avista Corp 2016 Natural Gas IRP Appendices 605 74 Demand Sensitivities & Scenarios Update Avista Corp 2016 Natural Gas IRP Appendices 606 75 Demand and Supply Side Sensitivities Optimize Resource Portfolio Stochastic Cost/Risk Analysis Prices and Weather Highest Performing Portfolios selection Preferred Portfolio selection Core Cases Price Forecast Sensitivities, Scenarios, Portfolios 75 Avista Corp 2016 Natural Gas IRP Appendices 607 76 Sensitivity Analysis 76 Avista Corp 2016 Natural Gas IRP Appendices 608-'II._ ,11fillSTA" 7777 Demand Sensitivity Analysis –DIRECT Avista Corp 2016 Natural Gas IRP Appendices 609 43 ,000 42,000 41 ,000 40 ,000 39,000 .c 38 ,000 -"C :ii: 37,000 36,000 35,000 34 ,000 33,000 2016 Demand Sensitivities -Demand Influencing Direct Annual Deman d -Total System -Reference Case -Reference Case -Plus Peak ...,._Alternate Historical UPC Case 787878 Demand Sensitivity Analysis –DIRECT Avista Corp 2016 Natural Gas IRP Appendices 610 2016 Demand Sensitivity Analysis -Direct Annual Demand -Reference Case -Reference Case -Plus Pea k -Low Cust Growth -High Ciust Grnwth -Alternate Weather Std -CNGJNGV 7979 Demand Sensitivity Analysis –DIRECT79 Avista Corp 2016 Natural Gas IRP Appendices 611 350 300 .... .... .... 250 200 150 100 50 0 .... Peak Day (Feb 15) -Deman d Sensitivities 3 Year Use per Customer vs. 5 Year Use per Customer WA/ID "" ... "" ... ... ... ... ... ... "" .... .... -Reference Case -Reference Case -Plus Peak -.,...Alternate Historical UPC Case .... .... .... 808080 Demand Sensitivity Analysis –DIRECT Avista Corp 2016 Natural Gas IRP Appendices 612 .c ..... Peak Day (Feb 15) -Demand Sensitivities 3 Year Use per Customer WA/ID 400 .....----------------------------------------------- 350 300 250 ~ 200 -+---------------------------------------------- 150 -+---------------------------------------------- 100 -------------------------------------------- 50 -------------------------------------------- 0 -+-----r------.---r---~-----.---.----,------.----,--.....------r-----r--...-----,-------.---,----,------,------.----, -!Reference Case -High Cust Growth ~Reference Case -Plus Peak -Alternate Weather Std -Low Cust Growth -CNG/NGV 818181 Demand Sensitivity Analysis –DIRECT Avista Corp 2016 Natural Gas IRP Appendices 613 100 90 80 -70 T" ~ 60 .c 50 -"C :1: 40 30 20 10 ,0 Peak Day (Dec 20) -Demand Sensitivities 3 Year Use per Customer vs. 5 Year Use per Customer Medford/Roseburg & & ~ ~ -Reference Case -Reference Case -Plus Pea k -.,...Alternate Historical UPC Case & ..... ~ ~ 828282 Demand Sensitivity Analysis –DIRECT Avista Corp 2016 Natural Gas IRP Appendices 614 Peak Day (Dec 20) -Demand Sensitivities 3 Year Use per Customer Medford/Roseburg 120 ~---------------------------------------------- 100 +------------------------------------------------ 80 :5 60 "C :1: 40 20 rQ +---~-~--~-~-~--~-~-~--~-~-~--~-~-~-~~-~-~-~~-~-~ -Reference Case H ig'h C ust Growth ~Reference Case -Plus Peak -Alternate Weather Std -Low Cust Gro'Vlfth -CNG/NGV 8383 Demand Sensitivity Analysis –INDIRECT Avista Corp 2016 Natural Gas IRP Appendices 615 320 300 280 .c -"C :1: 260 Peak Day (Feb 15) -Demand Sensitivities 3 Year Use per Customer WA/ID -+-Reference Case -P lus Peak ~Expected Elasticity -Likely Policy Carbon -High Prices -i-732 Carbon -Expected Carbo n -Low Prices -2015 Electric IRP Carbon LNG-Methanol 8484 Demand Sensitivity Analysis –INDIRECT Avista Corp 2016 Natural Gas IRP Appendices 616 90 85 80 .c -"C :1: 75 70 Peak Day (Dec 20) -Demand Sensitivities 3 Year Use per Customer Medford/Roseburg -+-Reference Case -Plus Peak ~ Expected Elasticity -Likely Policy Carbon -High Prices -i-732 Carbon -Ex ected Carbon Low Prices -2015 Electric IRP Carbon LNG-Metha nol 8585 Avista Corp 2016 Natural Gas IRP Appendices 617 2015 2016 2017 2018 2019 2020 "C 2021 G> > 2022 ... G> 0, 2023 C ::> 2024 "C C m 2025 E G> 2026 C ... 2027 m G> >-2028 .... 0, ... 2029 LL .2030 2031 2032 2033 2034 2035 IFirst Year Pea k Demand Not IMet with Existi ng Resources Sensitivity Com parisons WA/ID • Reference Plus Peak • Expected Elasticity •CNG/NGV Medford/Roseburg Klamath •Alternate Historical UPC Case High Prices LNG-Methanol •High Gust Growth •Alternate Weather Std La Grande • Low Prices • Low Gust Growth 86 Scenario Analysis 86 Avista Corp 2016 Natural Gas IRP Appendices 618-'II._ ,11fillSTA" 87 Proposed Scenarios 87 Avista Corp 2016 Natural Gas IRP Appendices 619 8888 Existing Resources vs. Peak Day Demand 88 Avista Corp 2016 Natural Gas IRP Appendices 620 8989 Existing Resources vs. Peak Day Demand Expected Case –Medford/Roseburg (DRAFT) 89 Avista Corp 2016 Natural Gas IRP Appendices 621 9090 Existing Resources vs. Peak Day Demand Expected Case –Klamath Falls (DRAFT) 90 Avista Corp 2016 Natural Gas IRP Appendices 622 9191 Existing Resources vs. Peak Day Demand Expected Case –La Grande (DRAFT) 91 Avista Corp 2016 Natural Gas IRP Appendices 623 9292 Avista Corp 2016 Natural Gas IRP Appendices 624 Mdth 400 350 300 250 200 100 50 -" '" Peak lDay (Feb 15) - 201 6 1RP Demand Scenarios WA/ID ~ -Expected Case -Low Prices -Low G rowtlil & High Prices -Expect ed Case -Gold Day 20yr Weather Std - High Growth & Low Prices Average Case - 9393 Avista Corp 2016 Natural Gas IRP Appendices 625 Mdth 80 - IPeak Day ,(Dec 20) -2016 IRP Demand Scenarios Medford/Roseburg - -Expected Case -Low Pirices -Low G rowtlil & High Prices -Expected Case -Gold Day 20yr Weather Std High Growth & Low Prices Average Case 9494 Avista Corp 2016 Natural Gas IRP Appendices 626 2(H5 2CH6 2017 2018 2019 ~ 2020 Q) 2021 > ... Q) 2022 {I) C: ::::> 2023 ~ C: 2024 to E Q) 2025 C ... to 2026 Q) >-2027 .... {I) ... u.. 2028 2029 2030 2031 2032 2033 2034 2035 First Year Peak Demand Not Met with Existing Resources Scenario Comparisons WN,10 Medford/Roseburg Klamath • Expected Case -Low Prices • Expected Case • Low Growth & High Prices • Cold Day 20yr Weather Std La Grande High Growth & Low Prices Av,erage Case 95 Resource Options for Meeting Unserved Demand 95 Avista Corp 2016 Natural Gas IRP Appendices 627-'II._ ,11fillSTA" 9696 Potential New Supply Resources Considerations •Availability –By Region –which region(s) can the resource be utilized? –Lead time considerations –when will it be available? •Type of Resource –Peak vs. Base load –Firm or Non-Firm –“Lumpiness” •Usefulness –Does it get the gas where we need it to be? –Last mile issues •Cost 96 Avista Corp 2016 Natural Gas IRP Appendices 628-'II._ ,11fillSTA" 9797 Supply Resources Available Additional Resource Size Cost/Rates Availability Notes Capacity Release Recall 27,000 Dth NWPL Rate 2018 Recall of previously released capacity Unsubscribed GTN Capacity Up to 50,000 Dth GTN Rate plus Upstream TCPL Now Currently available unsubscribed capacity from Kingsgate to Stanfield or Malin plus associated Alberta transport NWP Expansion Up to 50,000 Dth $0.74 / Dth 2018 Expansion from Sumas to JP Citygate Deliveries Variable Varies Now Represents the ability to buy a delivered product from another utility or marketer. Limited counterparties Satellite LNG 90,000 Dth w/30,000 Dth deliverability $7 Million capital cost plus $375K O&M 2018 Provides for peaking services and alleviates the need for costly pipeline expansions. 97 Avista Corp 2016 Natural Gas IRP Appendices 629 9898 Supply Resources Available Additional Resource Size Cost/Rates Availability Notes Medford Lateral Exp 50,000 Dth $10M / GTN Rate 2018 Additional compression to facilitate more gas to flow from mainline GTN to Medford. Malin Backhauls 50,000 GTN Rate Now Currently available 98 Avista Corp 2016 Natural Gas IRP Appendices 630 9999 Future Supply Resources Other Resources Considered Additional Resource Size Cost/Rates Availability Notes Co. Owned LNG 600,000 Dth w/ 150,000 of deliverability $75 Million plus $2 Million annual O&M 2022 On site, in service territory liquefaction and vaporization facility Various pipelines –Pacific Connector, Cross-Cascades, etc. Varies Precedent Agreement Rates 2020 Requires additional mainline capacity on NWPL or GTN to get to service territory Large Scale LNG Varies Commodity less Fuel 2020 Speculative, needs pipeline transport In Ground Storage Varies Varies Varies Requires additional mainline transport to get to service territory 99 Avista Corp 2016 Natural Gas IRP Appendices 631 100100 DSM Avoided Cost •Avoided cost determined by comparison to the marginal supply side resources to meet incremental demand, primarily commodity costs. •Preliminary avoided costs were provided to AEG for cost effectiveness testing and development of the DSM acquirable potential. •Potential is then input into SENDOUT® and avoided costs are re- evaluated. 100 Avista Corp 2016 Natural Gas IRP Appendices 632-'II._ ,11fillSTA" 101101 Avista Corp 2016 Natural Gas IRP Appendices 633 $0.00 o.n (0 ,_ CD CJ) Cl ..- 5 5 5 5 5 N N Cl Cl N N N N N N N -wA Annual -2016 Avoided Cost Compa rison 2014 IRP vs. 2016 IRP N (") ...,. o.n CD ,_ N N N N N N Cl C) C) C) C) C) N N N N N N CD N C) N OR Annual -.2016 -.-wA Annual -2014 0) Cl ..-N (") ...,. o.n N (") (") (") (") (") (") C) C) C) C) C) C) C) N N N N N N N -OR Annual -.2014 102 Stochastic Analysis Avista Corp 2016 Natural Gas IRP Appendices 634 103103 What is it? •Stochastic vs. Deterministic •Facilitates a statistical approach to analysis •Reiterative runs of SENDOUT (e.g. 200 “Draws”) •Utilizes statistically generated price curves and weather patterns derived from historical data •Develops a distribution of the “draws” results –Normal (Weather) and lognormal (Index) distribution 103 Avista Corp 2016 Natural Gas IRP Appendices 635-'II._ ,11fillSTA" 104104 Analytical Objectives •Weather –Validate reasonableness of our weather planning standard –Compare demand and unserved results –Quantify potential alternate weather planning standards via comparison of alternate aggregate NPV portfolio costs •Price –Substantiate preferred portfolio selection (commodity cost perspective) –Compare distribution of aggregate NPV cost to preferred portfolio 104 Avista Corp 2016 Natural Gas IRP Appendices 636-'II._ ,11fillSTA" 105105 Avistsa IRP Total 20 Year Cost 0 5 10 15 20 25 30 35 40 45 $9.2 8 $9.3 4 $9.4 0 $9.4 6 $9.5 1 $9.5 7 $9.6 3 $9.6 8 $9.7 4 $9.8 0 $9.8 5 $9.9 1 $9.9 7 $10. 0 2 $10. 0 8 $10. 1 4 $10. 1 9 $10. 2 5 $10. 3 1 $10. 3 7 $10. 4 2 $10. 4 8 $ Billions Fr e q u e n c y 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Cu m u l a t i v e Frequency Cumulative Mean 90th Percentile 95th Percentile 5% P(Cost>10.127)=5% 10% P(Cost>10.067)=10% Average: 9.854 StdDev: 0.169 Min: 9.285 90% percentile: 10.067 95% percentile: 10.127 Max: 10.422 VectorGas™ Reports EXAMPLE ONLY 105 Avista 20 Year Total Cost Avista Corp 2016 Natural Gas IRP Appendices 637 106106 Sample Weather Pattern Medford HDDs -Four example draws Medford Monte Carlo HDD Results 0 10 20 30 40 50 60 70 Nov- 0 9 Jan- 1 0 Mar-1 0 May- 1 0 Jul-1 0 Sep- 1 0 Nov- 1 0 Jan- 1 1 Mar-1 1 May- 1 1 Jul-1 1 Sep- 1 1 Nov- 1 1 Jan- 1 2 Mar-1 2 Da i l y H D D Draw 4 Draw 12 Draw 46 Draw 148 106 Avista Corp 2016 Natural Gas IRP Appendices 638 107 Key Issues / Document Discussion Avista Corp 2016 Natural Gas IRP Appendices 639 108108 Highlights of the 2016 IRP •No near-term resource needs under most scenarios. •Higher long term customer growth rates. •Updated DSM potential and resultant avoided costs. •Lower prices. 108 Avista Corp 2016 Natural Gas IRP Appendices 640-'II._ ,11fillSTA" 109109 2014 IRP Acknowledgement Comments •Include a section that discusses the ongoing management of Avista’s surplus capacity •Provide more detail on the distribution model results and analysis that identify specific distribution system needs •Provide the resource portfolio solution that fills any demand not served for each scenario •Ensure that the entity performing the Conservation Potential Assessment (CPA) evaluates the effect of the temporary operation under a Utility Cost Test (UCT) cost- effectiveness metric on near-term, achievable conservation potential, while maintaining the longer-term assumption that Avista will eventually be reverting back to a TRC test cost-effectiveness metric. •Evaluation of state-specific resource needs when a resource deficiency is identified •The appropriateness of using a 1 in 572 event for peak day planning •The need for stress-testing the Company’s storage resources during a peak event in a high-demand year 109 Avista Corp 2016 Natural Gas IRP Appendices 641-'II._ ,11fillSTA" 110110 2014 IRP Acknowledgement Comments •As part of its next IRP process, Avista must convene workshops with Staff and stakeholders to explore how best to model major resource acquisitions and major capital investments. •For the next IRP, Avista must work with Staff and stakeholders to resolve forecasting methodology concerns, and seek to identify the most reliable methodology so that future resource needs may be clearly identified. •In its next IRP, Avista must include a clear presentation of how Avista decides which distribution system projects to include in the IRP, and a clear description of the included projects, along with a justification for recommending or proceeding with the projects. •As part of its next IRP process, Avista must convene discussions with Staff and stakeholders to discuss potential impacts associated with: (1) new regulations to reduce methane emissions; and (2) potential increases in natural gas prices stemming from increased demand for natural gas for generation under Section 111 ( d) of the Clean Air Act. 110 Avista Corp 2016 Natural Gas IRP Appendices 642-'II._ ,11fillSTA" 111111 Key Questions •Low Demand? –What are the impacts on consumption? Temporary or permanent change? •Low Prices –Cheap gas for 20 years? •Environmental Impacts –Carbon Tax? –Hydraulic Fracturing Bans? •Market –Increasing production? –Increasing drilling efficiency? –Increasing demand from power? 111 Avista Corp 2016 Natural Gas IRP Appendices 643-'II._ ,11fillSTA" 112112 2016 IRP Timeline •August 31, 2015 –Work Plan filed with WUTC •January through April 2016 –Technical Advisory Committee meetings. Meeting topics will include: –Demand Forecast and Demand Side Management –January 21 –Supply/Infrastructure and Potential Case Discussion–February 18 –Distribution Planning, Natural Gas Pricing, SENDOUT® Preliminary Output Results and Further Case Discussion – March 30 –SENDOUT® results –April 21 –May 30, 2016 –Draft of IRP document to TAC •June 30, 2016 –Comments on draft due back to Avista •July 2016 –TAC final review meeting (if necessary) •August 31, 2016 –File finalized IRP document 112 Avista Corp 2016 Natural Gas IRP Appendices 644-'II._ ,11fillSTA"