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Home My WebLink About20150601Knox Exhibit 13.pdf DAVID J. MEYER VICE PRESIDENT AND CHIEF COUNSEL FOR REGULATORY & GOVERNMENTAL AFFAIRS AVISTA CORPORATION P.O. BOX 3727 1411 EAST MISSION AVENUE SPOKANE, WASHINGTON 99220-3727 TELEPHONE: (509) 495-4316 FACSIMILE: (509) 495-8851 DAVID.MEYER@AVISTACORP.COM BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION IN THE MATTER OF THE APPLICATION ) CASE NO. AVU-E-15-05 OF AVISTA CORPORATION FOR THE ) AUTHORITY TO INCREASE ITS RATES ) AND CHARGES FOR ELECTRIC AND ) NATURAL GAS SERVICE TO ELECTRIC ) EXHIBIT NO. 13 AND NATURAL GAS CUSTOMERS IN THE ) STATE OF IDAHO ) TARA L. KNOX ) FOR AVISTA CORPORATION (ELECTRIC ONLY) AVISTA UTILITIES AVERAGE PRODUCTION AND TRANSMISSION COST IDAHO ELECTRIC TWELVE MONTHS ENDED DECEMBER 31, 2014 Line Column Description of Adjustment (000's)Revenue Expense Plant Accumulated Depreciation Deferred Debits/Credits Deferred Tax 1 1.00 Per Results Report 91,039 188,083 644,423 (248,128) 896 (62,349)2 1.01 Deferred FIT Rate Base - - - - - (5,200)3 1.02 Deferred Debits and Credits - (352) - - (545) - 4 1.03 Restate Capital 2014 EOP - - 15,958 (3,060) - (15,546) 5 1.04 Working Capital - - - - - - 6 2.01 Eliminate B & O Taxes - - - - - - 7 2.02 Uncollectible Expense - - - - - - 8 2.03 Regulatory Expense - - - - - - 9 2.04 Injuries and Damages - - - - - - 10 2.05 FIT/DFIT ITC/PTC Expense - - - - - - 11 2.06 SIT/SITC Expense - - - - - - 12 2.07 Revenue Normalization - 5,041 - - - - 13 2.08 Miscellaneous Restating - - - - - - 14 2.09 Restate Incentives - - - - - - 15 2.10 ID PCA - 3,862 - - - - 16 2.11 Nez Perce Settlement Adjustment - (13) - - - - 17 2.12 CS2 Levelized - (409) - - - - 18 2.13 Colstrip / CS2 Maintenance - 2,758 - - - - 19 2.14 Restate Debt Interest - - - - - - 20 3.01 Pro Forma Power Supply (60,860) (66,200) - - - - 21 3.02 Pro Forma Transmission Rev/Exp 118 149 - - - - 23 3.03 Pro Forma Labor Non-Exec - 436 - - - - 24 3.04 Pro Forma Labor Exec - (8) - - - - 25 3.05 Pro Forma Employee Benefits - 632 - - - - 26 3.06 Pro Forma Insurance - - - - - - 27 3.07 Pro Forma Property Tax - 1,054 - - - - 28 3.08 Pro Forma IS/IT Costs - - - - - - 29 3.09 Planned Capital Add 2015 EOP - 1,277 53,240 (7,978) - (1,630) 30 3.10 Planned Capital Add 2016 AMA - 160 8,052 (4,850) - (1,358) 31 3.11 Pro Forma O&M Offsets - 64 - - - - 32 3.12 Pro Forma Lake Spokane 2-Yr Amort - 237 - - - - 33 3.13 Pro Forma Colstrip Settlement - (200) - - - - 34 3.14 Pro Forma Project Compass Deferral Amorts - - - - - - 35 2016 Pro Forma Total 30,297 136,571 721,673 (264,016) 351 (86,083) Production / Transmission Exhibit No. 13 Case No. AVU-E-15-05 T. Knox, Avista Schedule 1, p. 1 of 4 AVISTA UTILITIES AVERAGE PRODUCTION AND TRANSMISSION COST IDAHO ELECTRIC TWELVE MONTHS ENDED DECEMBER 31, 2014 Line ($000's) Debt Cost 1 Prod/Trans Pro Forma Rate Base 371,925 2 Cost of Capital Proposed Rate of Return 7.620% 2.67% 3 Rate Base Net Operating Income Requirement $28,341 4 Tax Effect Net Operating Income Requirement ($3,476) (Rate Base x Debt Cost x -35%) 5 Net Expense Net Operating Income Requirement 106,274 (Expense - Revenue) 6 Tax Effect Net Operating Income Requirement ($37,196) (Net Expense x -.35%) 7 Total Prod/Trans Net Operating Income Requirement $93,943 8 1 - Tax Rate Conversion Factor (Excl. Rev. Rel. Exp.) 0.65 9 Prod/Trans Revenue Requirement $144,528 10 Test Year WA Normalized Retail Load MWh 3,072,989 11 Prod/Trans Rev Requirement per kWh 0.04703$ 12 Cost of Service Energy Classified Production/Transmission Costs $76,005 Company Case at Unity AVU-E-15-05 13 Cost of Service Total Production/Transmission Costs $149,021 Company Case at Unity AVU-E-15-05 14 Load Change Adjustment Rate per kWh (Line 11 * Line 12 / Line 13)0.02399$ 2016 Pro Forma Calculation of Load Change Adjustment Rate Proposed Production and Transmission Revenue Requirement Exhibit No. 13 Case No. AVU-E-15-05 T. Knox, Avista Schedule 1, p. 2 of 4 AVISTA UTILITIES AVERAGE PRODUCTION AND TRANSMISSION COST IDAHO ELECTRIC TWELVE MONTHS ENDED DECEMBER 31, 2014 Line Column Description of Adjustment (000's)Revenue Expense Plant Accumulated Depreciation Deferred Debits/Credits Deferred Tax 1 1.00 Per Results Report 91,039 188,083 644,423 (248,128) 896 (62,349) 2 1.01 Deferred FIT Rate Base - - - - - (5,200) 3 1.02 Deferred Debits and Credits - (352) - - (545) - 4 1.03 Restate Capital 2014 EOP - - 15,958 (3,060) - (15,546) 5 1.04 Working Capital - - - - - - 6 2.01 Eliminate B & O Taxes - - - - - - 7 2.02 Uncollectible Expense - - - - - - 8 2.03 Regulatory Expense - - - - - - 9 2.04 Injuries and Damages - - - - - - 10 2.05 FIT/DFIT ITC/PTC Expense - - - - - - 11 2.06 SIT/SITC Expense - - - - - - 12 2.07 Revenue Normalization - 5,041 - - - - 13 2.08 Miscellaneous Restating - - - - - - 14 2.09 Restate Incentives - - - - - - 15 2.10 ID PCA - 3,862 - - - - 16 2.11 Nez Perce Settlement Adjustment - (13) - - - - 17 2.12 CS2 Levelized - (409) - - - - 18 2.13 Colstrip / CS2 Maintenance - 2,758 - - - - 19 2.14 Restate Debt Interest - - - - - - 20 3.01 Pro Forma Power Supply (60,860) (66,200) - - - - 21 3.02 Pro Forma Transmission Rev/Exp 118 149 - - - - 23 3.03 Pro Forma Labor Non-Exec - 436 - - - - 24 3.04 Pro Forma Labor Exec - (8) - - - - 25 3.05 Pro Forma Employee Benefits - 632 - - - - 26 3.06 Pro Forma Insurance - - - - - - 27 3.07 Pro Forma Property Tax - 1,054 - - - - 28 3.08 Pro Forma IS/IT Costs - - - - - - 29 3.09 Planned Capital Add 2015 EOP - 1,277 53,240 (7,978) - (1,630) 30 3.10 Planned Capital Add 2016 AMA - 160 8,052 (4,850) - (1,358) 31 3.11 Pro Forma O&M Offsets - 64 - - - - 32 3.12 Pro Forma Lake Spokane 2-Yr Amort - 237 - - - - 33 3.13 Pro Forma Colstrip Settlement - (200) - - - - 34 3.14 Pro Forma Project Compass Deferral Amorts - - - - - - 35 17.01 Pro Forma Power Supply (5,489) 3,287 - - - - 36 17.02 Pro Forma Transmission Rev/Exp - 69 - - - - 37 17.03 Pro Forma Labor Non-Exec - 225 - - - - 38 17.04 Pro Forma Property Tax - 624 - - - - 39 17.05 Planned Capital Add 2017 AMA - 573 29,879 (9,921) - (2,239) 40 2017 Pro Forma Total 24,808 141,349 751,552 (273,937) 351 (88,322) Production / Transmission Exhibit No. 13 Case No. AVU-E-15-05 T. Knox, Avista Schedule 1, p. 3 of 4 AVISTA UTILITIES AVERAGE PRODUCTION AND TRANSMISSION COST IDAHO ELECTRIC TWELVE MONTHS ENDED DECEMBER 31, 2014 2017 Pro Forma Line ($000's) Debt Cost 1 Prod/Trans Pro Forma Rate Base 389,644 2 Cost of Capital Proposed Rate of Return 7.620% 2.67% 3 Rate Base Net Operating Income Requirement $29,691 4 Tax Effect Net Operating Income Requirement ($3,641) (Rate Base x Debt Cost x -35%) 5 Net Expense Net Operating Income Requirement 116,541 (Expense - Revenue) 6 Tax Effect Net Operating Income Requirement ($40,789) (Net Expense x -.35%) 7 Total Prod/Trans Net Operating Income Requirement $101,801 8 1 - Tax Rate Conversion Factor (Excl. Rev. Rel. Exp.) 0.65 9 Prod/Trans Revenue Requirement $156,618 10 Test Year WA Normalized Retail Load MWh 3,072,989 11 Prod/Trans Rev Requirement per kWh 0.05097$ 12 Cost of Service Energy Classified Production/Transmission Costs $76,005 Company Case at Unity AVU-E-15-05 13 Cost of Service Total Production/Transmission Costs $149,021 Company Case at Unity AVU-E-15-05 14 Load Change Adjustment Rate per kWh (Line 11 * Line 12 / Line 13) - 2017 0.02599$ Proposed Production and Transmission Revenue Requirement Calculation of Load Change Adjustment Rate Exhibit No. 13 Case No. AVU-E-15-05 T. Knox, Avista Schedule 1, p. 4 of 4 1. ELECTRIC COST OF SERVICE 1 A cost of service study is an engineering-economic study, which apportions the revenue, 2 expenses, and rate base associated with providing electric service to designated groups of 3 customers. It indicates whether the revenue provided by customers recovers the cost to serve those 4 customers. The study results are used as a guide in determining the appropriate rate spread among 5 the groups of customers. 6 There are three basic steps involved in a cost of service study: functionalization, 7 classification, and allocation. See flow chart below. 8 First, the expenses and rate base associated with the electric system under study are 9 assigned to functional categories. The uniform system of accounts provides the basic segregation 10 into production, transmission, and distribution. Traditionally customer accounting, customer 11 information, and sales expenses are included in the distribution function, and administrative and 12 general expenses and general plant rate base are allocated to all functions. This study includes a 13 separate functional category for common costs. Administrative and general costs that cannot be 14 directly assigned to the other functions have been placed in this category. 15 Second, the expenses and rate base items that cannot be directly assigned to customer 16 groups are classified into three primary cost components: energy, demand or customer related. 17 Energy related costs are allocated based on each rate schedule’s share of commodity consumption. 18 Demand (capacity) related costs are allocated to rate schedules on the basis of each schedule’s 19 contribution to peak demand. Customer related items are allocated to rate schedules based on the 20 number of customers within each schedule. The number of customers may be weighted by 21 appropriate factors such as relative cost of metering equipment. In addition to these three cost 22 components, any revenue related expense is allocated based on the proportion of revenues by rate 23 schedule. 24 Exhibit No. 13 Case No. AVU-E-15-05 T. Knox, Avista Schedule 2, p. 1 of 9 1 * Customer classes shown in this flowchart are illustrative and may not match the Company’s actual rate schedules. Pro Forma Results of Operations by Customer Group TransmissionProduction Common Energy / Commodity Related Customer Related Demand / Capacity Related Residential Small General Large General Extra Large General *Pumping Street & Area Lights Allocation Pro Forma Results of Operations Functionalization Distribution and Customer Relations Classification Direct Assignment Number of Customers Weighted Number of Customers Direct Assignment Coincident Peak Non-Coincident Peak Direct Assignment Generation Level mWh's Customer Level mWh's Exhibit No. 13 Case No. AVU-E-15-05 T. Knox, Avista Schedule 2, p. 2 of 9 The final step is allocation of the costs to the various rate schedules utilizing the allocation factors 1 selected for each specific cost item. These factors are derived from usage and customer 2 information associated with the test period results of operations. 3 4 BASE CASE COST OF SERVICE STUDY 5 Production Classification (Load Factor Peak Credit) 6 This study utilizes a Peak Credit methodology to classify production costs into demand and 7 energy classifications. The Peak Credit method acknowledges that all energy production costs 8 contain both capacity and energy components as they provide energy throughout the year as well as 9 capacity during system peaks. The peak credit ratio (the proportion of total production cost that is 10 capacity related) is determined using the electric system load factor inherent in the test year. The 11 share of production costs attributable to demand is one minus the load factor1 which is 37.93% for 12 the 2014 test year. The same classification ratio is applied to all production costs. 13 Production Allocation 14 Production demand related costs are allocated to the customer classes by class contribution 15 to the average of the twelve monthly system coincident peak loads. Although the Company is 16 usually a winter peaking utility, it experiences high summer peaks and careful management of 17 capacity requirements is required throughout the year. The use of the average of twelve monthly 18 peaks recognizes that customer capacity needs are not limited to the heating season. Energy related 19 costs are allocated to class by pro forma annual kilowatt-hour sales adjusted for losses to reflect 20 generation level consumption. 21 22 1 1 – (average MW÷ peak MW). Exhibit No. 13 Case No. AVU-E-15-05 T. Knox, Avista Schedule 2, p. 3 of 9 Transmission Classification and Allocation 1 Transmission costs are classified as 100% demand related due in part to the fact that the 2 facilities are designed to meet system peak loads. These costs are then allocated to the customer 3 classes by class contribution to the average of the twelve monthly system coincident peak loads 4 (12CP). The use of the average of twelve monthly peaks recognizes that customer capacity needs 5 are not limited to the heating season. 6 Distribution Facilities Classification (Basic Customer) 7 The Basic Customer method considers only services and meters and directly assigned Street 8 Lighting apparatus (FERC Accounts 369, 370, and 373 respectively) to be customer related 9 distribution plant. All other distribution plant is then considered demand related. This division 10 delineates plant installed solely for an individual customer from plant which is part of the broader 11 system. The basic customer method provides a clearly definable division between plant that 12 provides service only to individual customers, from plant that is part of the interconnected 13 distribution network. 14 Customer Relations Distribution Cost Classification 15 Customer service, customer information and sales expenses are the core of the customer 16 relations functional unit which is included with the distribution cost category. For the most part 17 they are classified as customer related. Exceptions are sales expenses which are classified as 18 energy related and uncollectible accounts expense which is considered separately as a revenue 19 conversion item. Demand Side Management expenses (if any) recorded in Account 908 would be 20 considered separately from the other customer information costs. 21 22 Exhibit No. 13 Case No. AVU-E-15-05 T. Knox, Avista Schedule 2, p. 4 of 9 Any demand side management investment and amortization included in base rates would be 1 classified implicitly to demand and energy by the sum of production plant in service, then allocated 2 to rate schedules by coincident peak demand and energy consumption respectively. At this point in 3 time, the Company’s demand side management investments in base rates have been fully 4 amortized except for some minor outstanding loan balances that will remain on the books until 5 satisfied. All current demand side management costs are managed through the Schedule 91 Public 6 Purpose Tariff Rider balancing account which is not included in this cost study. 7 Distribution Cost Allocation 8 Distribution demand related costs, which cannot be directly assigned, are allocated to 9 customer class by the average of the twelve monthly non-coincident peaks for each class. 10 Distribution facilities that serve only secondary voltage customers are either allocated by the non-11 coincident peaks of secondary voltage customers (excludes demand from customers receiving 12 service at primary voltage)2, or by the average number of secondary voltage customers. This 13 includes secondary voltage overhead or underground conductors and devices, line transformers, 14 and service lines to the customer’s premises. The costs of specific substations and related primary 15 voltage distribution facilities are directly assigned to Extra Large General Service customers 16 (Schedule 25 and 25P) based on their load ratio share of the substation capacity from which they 17 receive service. 18 Most customer costs are allocated by average number of customers. Weighted customer 19 allocators have been developed using typical current cost of meters, estimated meter reading time, 20 and direct assignment of billing costs for hand-billed customers. Street and area light customers 21 are excluded from metering and meter reading expenses as their service is not metered. 22 23 2 Customers taking service below 11 kV are secondary voltage customers, customers taking service at greater than 11kV are primary voltage customers. Exhibit No. 13 Case No. AVU-E-15-05 T. Knox, Avista Schedule 2, p. 5 of 9 Administrative and General Costs 1 Administrative and general costs which are directly associated with production, 2 transmission, distribution, or customer relations functions are directly assigned to those functions 3 and allocated to customer class by the relevant plant or number of customers. The remainder of 4 administrative and general costs are considered common costs, and have been left in their own 5 functional category. These common costs are classified by the implicit relationship of energy, 6 demand and customer within the four-factor allocator applied to them. The four-factor allocator 7 consists of a 25% weighting of each of the following: 1) operating & maintenance expenses 8 excluding resource costs, labor expenses, and administrative and general expenses; 2) operating 9 and maintenance labor expenses excluding administrative and general labor expenses; 3) net 10 production, transmission, and distribution plant; and 4) number of customers. 11 Revenue Conversion Items 12 In this study uncollectible accounts and commission fees have been classified as revenue 13 related and are allocated by pro forma revenue. These items vary with revenue and are included in 14 the calculation of the revenue conversion factor. Income tax expense items are allocated to 15 schedules by net income before income tax adjusted by interest expense. 16 For the functional summaries on pages 2 and 3 of the cost of service study, these items are 17 assigned to component cost categories. The revenue related expense items have been reduced to a 18 percent of all other costs and loaded onto each cost category by that ratio. Similarly, income tax 19 items have been reduced to a percent of net income before tax then assigned to cost categories by 20 relative rate base (as is net income). 21 The following matrix outlines the methodology applied in the Company Base Case cost of 22 service study. 23 Exhibit No. 13 Case No. AVU-E-15-05 T. Knox, Avista Schedule 2, p. 6 of 9 IPUC Case No. AVU-E-15-05 Methodology MatrixAvista Utilities Idaho Jurisdiction Electric Cost of Service Methodology Line Account Functional Category Classification Allocation Production Plant1 Thermal Production P = Production Demand/Energy by Load Factor Peak Credit D01/E02 Coincident Peak Demand/Annual Generation Level Consumption 2 Hydro Production P = Production Demand/Energy by Load Factor Peak Credit D01/E02 Coincident Peak Demand/Annual Generation Level Consumption 3 Other Production (Coyote Springs) P = Production Demand/Energy by Load Factor Peak Credit D01/E02 Coincident Peak Demand/Annual Generation Level Consumption4 Other Production P = Production Demand/Energy by Load Factor Peak Credit D01/E02 Coincident Peak Demand/Annual Generation Level Consumption Transmission Plant5 All Transmission T = Transmission Demand D01 Coincident Peak Demand (12CP) Distribution Plant 6 360 Land D = Distribution Demand D03 Non-coincident Peak Demand (NCP) 7 361 Structures D = Distribution Demand D04/D05/D06 Direct Assign Large / Non-coincident Peak Demand Excl DA8 362 Station Equipment D = Distribution Demand D04/D05/D06 Direct Assign Large / Non-coincident Peak Demand Excl DA 9 364 Poles Towers & Fixtures D = Distribution Demand D04/D05/D07/D08 Direct Assign Large & Lights / NCP Excl DA / NCP Secondary 10 365 Overhead Conductors & Devices D = Distribution Demand D04/D05/D07 Direct Assign Large / NCP Excl DA / NCP Secondary11 366 Underground Conduit D = Distribution Demand D04/D05/D07 Direct Assign Large / NCP Excl DA / NCP Secondary 12 367 Underground Conductors & Devices D = Distribution Demand D04/D05/D07 Direct Assign Large / NCP Excl DA / NCP Secondary 13 368 Line Transformers D = Distribution Demand D07 Non-coincident Peak Demand Secondary14 369 Services D = Distribution Customer C02 Secondary Customers unweighted Excl Lighting 15 370 Meters D = Distribution Customer C04 Customers weighted by Current Typical Meter Cost16 373 Street and Area Lighting Systems D = Distribution Customer C05 Direct Assignment to Street and Area Lights General Plant17 All General O=Other Demand/Energy/Customer by Corp Cost Allocator S23 25% direct O&M, 25% direct labor, 25% net direct plant, 25% number of customers Intangible Plant18 301 Organization O=Other Energy/Customer by Corp Cost Allocator S23 25% direct O&M, 25% direct labor, 25% net direct plant, 25% number of customers 19 302 Franchises & Consents - Hydro Relicensing P = Production Demand/Energy by Load Factor Peak Credit D01/E02 Coincident Peak Demand/Annual Generation Level Consumption 20 303 Misc Intangible Plant - Transmission Agreements T = Transmission Demand D01 Coincident Peak Demand (12CP)21 303 Misc Intangible Plant - Software O=Other Demand/Energy/Customer by Corp Cost Allocator S23 25% direct O&M, 25% direct labor, 25% net direct plant, 25% number of customers Reserve for Depreciation/Amortization22 Intangible P/T/O Follows Related Plant S01/S02/S23 Sum of Production Plant / Sum of Transmission Plant / Corp Cost Allocator 23 Production P = Production Follows Related Plant D01/E02 Coincident Peak Demand/Annual Generation Level Consumption24 Transmission T = Transmission Follows Related Plant D01 Coincident Peak Demand (12CP) 25 Distribution D = Distribution Follows Related Plant D03/D04/D05/D06/D07/D08/C02/C04/C05 - See Related Plant 26 General O=Other Follows Related Plant S23 25% direct O&M, 25% direct labor, 25% net direct plant, 25% number of customers Other Rate Base 27 252 Customer Advances for Construction D = Distribution Customer S13 Sum of Account 369 Services Plant28 282/190 Accumulated Deferred Income Tax P/T/D/O Per Functional Analysis S01/S02/S03/S04 Sums of Production / Transmission / Distribution / General Plant 29 Hydro Relicensing Related Settlements P = Production Demand/Energy by Load Factor Peak Credit D01/E02 Coincident Peak Demand/Annual Generation Level Consumption 30 Demand Side Management Investment DSM Demand/Energy by Load Factor Peak Credit S01 Sum of Production Plant31 Working Capital P/T/D/G Demand/Energy/Customer as in related Plant S06 Sum of Production, Transmission, Distribution, and General Plant Exhibit No. 13Case No. AVU-E-15-05 T. Knox, Avista Schedule 2, p. 7 of 9 IPUC Case No. AVU-E-15-05 Methodology MatrixAvista Utilities Idaho Jurisdiction Electric Cost of Service Methodology Line Account Functional Category Classification Allocation Production O&M 1 Thermal P = Production Demand/Energy by Load Factor Peak Credit D01/E02 Coincident Peak Demand/Annual Generation Level Consumption2 Thermal Fuel (501) P = Production Demand/Energy by Load Factor Peak Credit D01/E02 Coincident Peak Demand/Annual Generation Level Consumption 3 Hydro P = Production Demand/Energy by Load Factor Peak Credit D01/E02 Coincident Peak Demand/Annual Generation Level Consumption 4 Water for Power (536) P = Production Demand/Energy by Load Factor Peak Credit D01/E02 Coincident Peak Demand/Annual Generation Level Consumption5 Other (Coyote Springs) P = Production Demand/Energy by Load Factor Peak Credit D01/E02 Coincident Peak Demand/Annual Generation Level Consumption 6 Other Fuel (547) P = Production Demand/Energy by Load Factor Peak Credit D01/E02 Coincident Peak Demand/Annual Generation Level Consumption7 Other P = Production Demand/Energy by Load Factor Peak Credit D01/E02 Coincident Peak Demand/Annual Generation Level Consumption8 Purchased Power and Other Expenses (555 and 557) P = Production Demand/Energy by Load Factor Peak Credit S01 Sum of Production Plant 9 System Control & Misc (556 ) P = Production Demand/Energy by Load Factor Peak Credit D01/E02 Coincident Peak Demand/Annual Generation Level Consumption Transmission O&M 10 All Transmission T = Transmission Demand D01 Coincident Peak Demand (12CP) Distribution O&M 11 580 OP Super & Engineering D = Distribution Demand/Customer from Other Dist Op Exp S16 Sum of Other Distribution Operating Expenses12 581 Load Dispatching D = Distribution Demand D03 Non-coincident Peak Demand 13 582 Station Expenses D = Distribution Demand S09 Sum of Account 362 Station Equipment 14 583 Overhead Lines D = Distribution Demand S10 Sum of Accounts 364 and 365 Poles, Towers, Fixtures & Overhead Conductors15 584 Underground Lines D = Distribution Demand S11 Sum of Accounts 366 and 367 Underground Conduit & Underground Conductors 16 585 Street Lights D = Distribution Customer S15 Sum of Account 373 Street Light and Signal Systems17 586 Meters D = Distribution Customer S14 Sum of Account 370 Meters 18 587 Customer Installations D = Distribution Customer S13 Sum of Account 369 Services 19 588 Misc Operating Expense D = Distribution Demand/Customer from Other Dist Op Exp S16 Sum of Other Distribution Operating Expenses20 589 Rents D = Distribution Demand D03 Non-coincident Peak Demand 21 590 MT Super & Engineering D = Distribution Demand/Customer from Other Dist Mt Exp S17 Sum of Other Distribution Maintenance Expenses22 591 MT of Structures D = Distribution Demand S08 Sum of Account 361 Structures & Improvements 23 592 MT of Station Equipment D = Distribution Demand S09 Sum of Account 362 Station Equipment 24 593 MT of Overhead Lines D = Distribution Demand S10 Sum of Accounts 364 and 365 Poles, Towers, Fixtures & Overhead Conductors25 594 MT of Underground Lines D = Distribution Demand S11 Sum of Accounts 366 and 367 Underground Conduit & Underground Conductors 26 595 MT of Line Transformers D = Distribution Demand S12 Sum of Account 368 Line Transformers27 596 MT of Street Lights D = Distribution Customer S15 Sum of Account 373 Street Light and Signal Systems28 597 MT of Meters D = Distribution Customer S14 Sum of Account 370 Meters 29 598 Misc Maintenance Expense D = Distribution Demand/Customer from Other Dist Mt Exp S17 Sum of Other Distribution Maintenance Expenses Customer Accounts Expenses 30 901 Supervision C = Customer Relations Customer S18 Sum of Other Customer Accounts Expenses Excluding Uncollectibles31 902 Meter Reading C = Customer Relations Customer C03/C06 Customers Weighted by Est. Meter Reading Time/Direct Assign Handbilled Cust 32 903 Customer Records & Collections C = Customer Relations Customer C01/C06 All Customers unweighted / Direct Assign Handbilled Cust 33 904 Uncollectible Accounts R = Revenue Conversion Revenue R01 Retail Sales Revenue34 905 Misc Cust Accounts C = Customer Relations Customer C01 All Customers unweighted Customer Service & Info Expenses35 907 Supervision C = Customer Relations Customer C01 All Customers unweighted 36 908 Customer Assistance C = Customer Relations Customer C01 All Customers unweighted37 908 DSM Amortization Expenses DSM Demand/Energy from Production Plant S01 Sum of Production Plant 38 909 Advertising C = Customer Relations Customer C01 All Customers unweighted 39 910 Misc Cust Service & Info C = Customer Relations Customer C01 All Customers unweighted Sales Expenses 40 911 - 916 C = Customer Relations Energy E02 Annual Generation Level Consumption Exhibit No. 13Case No. AVU-E-15-05 T. Knox, Avista Schedule 2, p. 8 of 9 IPUC Case No. AVU-E-15-05 Methodology MatrixAvista Utilities Idaho Jurisdiction Electric Cost of Service Methodology Line Account Functional Category Classification Allocation Admin & General Expenses 1 920 - 927 & 930 -935 Assigned to Production P = Production Demand/Energy from Production Plant S01 Sum of Production Plant 2 920 - 927 & 930 -935 Assigned to Transmission T = Transmission Demand/Energy from Transmission Plant S02 Sum of Transmission Plant3 920 - 927 & 930 - 935 Assigned to Distribution D = Distribution Demand/Customer from Distribution Plant S03 Sum of Distribution Plant 4 920 - 927 & 930 - 935 Assigned to Customer Relations C = Customer Relations Customer C01 All Customers unweighted 5 920 - 935 Assigned to Other O=Other Demand/Energy/Customer by Corp Cost Allocator S23 25% direct O&M, 25% direct labor, 25% net direct plant, 25% number of customers6 928 FERC Commission Fees P = Production Energy E02 Annual Generation Level Consumption 7 928 IPUC Commission Fees R = Revenue Conversion Revenue R01 Retail Sales Revenue Depreciation & Amortization Expense 8 Intangible P/T/O Demand/Energy/Customer as in related Plant S01/S02/S23 Sum of Production Plant / Sum of Transmission Plant / Corp Cost Alloctor9 Production P = Production Demand/Energy by Peak Credit as in related Plant D01/E02 Coincident Peak Demand/Annual Generation Level Consumption 10 Transmission T = Transmission Demand D01 Coincident Peak Demand (12CP) 11 Distribution D = Distribution Demand/Customer as in related Plant D03/D04/D05/D06/D07/D08/C02/C04/C05 - See Related Plant12 General O=Other Demand/Energy/Customer by Corp Cost Allocator S23 25% direct O&M, 25% direct labor, 25% net direct plant, 25% number of customers Taxes13 Property Tax P/T/D/O Demand/Energy/Customer from related Plant S01/S02/S03/S04 Sums of Production / Transmission / Distribution / General Plant 14 State kWh Generation Taxes P = Production Demand/Energy by Load Factor Peak Credit D01/E02 Coincident Peak Demand/Annual Generation Level Consumption 15 Misc Production Taxes P = Production Demand/Energy by Load Factor Peak Credit D01/E02 Coincident Peak Demand/Annual Generation Level Consumption16 Misc Distribution Taxes D = Distribution Demand/Customer from Distribution Plant S03 Sum of Distribution Plant 17 Idaho State Income Tax R = Revenue Conversion Revenue R03 Revenue less Expenses Before Income Taxes less Interest Expense18 Federal Income Tax R = Revenue Conversion Revenue R03 Revenue less Expenses Before Income Taxes less Interest Expense19 Deferred FIT R = Revenue Conversion Revenue R03 Revenue less Expenses Before Income Taxes less Interest Expense Other Income Related Items 20 Boulder Write-off Amort & Misc Renewable Items P = Production Demand/Energy by Load Factor Peak Credit D01/E02 Coincident Peak Demand/Annual Generation Level Consumption 21 Compass Deferral Amortization O=Other Demand/Energy/Customer by Corp Cost Allocator S23 25% direct O&M, 25% direct labor, 25% net direct plant, 25% number of customers Operating Revenues 22 Sales of Electricity- Retail R = Revenue from Rates Revenue Input Pro Forma Revenue per Revenue Study23 Sales for Resale (447) P = Production Demand/Energy from Production Plant S01 Sum of Production Plant 24 Misc Service Revenue (451) D = Distribution Demand/Customer from Distribution Plant S03 Sum of Distribution Plant 25 Sales of Water & Water Power (453) P = Production Demand/Energy from Production Plant S01 Sum of Production Plant26 Rent from Production Property (454) P = Production Demand/Energy from Production Plant S01 Sum of Production Plant 27 Rent from Transmission Property (454) T = Transmission Demand/Energy from Transmission Plant S02 Sum of Transmission Plant28 Rent from Distribution Property (454) D = Distribution Demand/Customer from Distribution Plant S03 Sum of Distribution Plant 29 Other Electric Revenues - Generation (456) P = Production Demand/Energy from Production Plant S01 Sum of Production Plant 30 Other Electric Revenues - Wheeling (456) T = Transmission Demand/Energy from Transmission Plant S02 Sum of Transmission Plant31 Other Electric Revenues - Energy Delivery (456) D = Distribution Demand/Customer from Distribution Plant S03 Sum of Distribution Plant Salaries & Wages (allocation factor input)Operation & Maintenance Expenses 32 Production Total P = Production Demand/Energy from Production Plant S01 Sum of Production Plant 33 Transmission Total T = Transmission Demand/Energy from Transmission Plant S02 Sum of Transmission Plant34 Distribution Total D = Distribution Demand/Customer from Distribution Plant S03 Sum of Distribution Plant 35 Customer Accounts Total C = Customer Relations Customer S18 Sum of Other Customer Accounts Expenses Excluding Uncollectibles36 Customer Service Total C = Customer Relations Customer C01 All Customers unweighted37 Sales Total C = Customer Relations Energy E02 Annual Generation Level Consumption 38 Admin & General Total O=Other Energy/Customer by Corp Cost Allocator S23 25% direct O&M, 25% direct labor, 25% net direct plant, 25% number of customers 39 Interest Expense (allocation factor input) R = Revenue Conversion Demand/Energy/Customer from Rate Base components S07 Total Rate Base Exhibit No. 13Case No. AVU-E-15-05 T. Knox, Avista Schedule 2, p. 9 of 9 Sumcost VISTA UTILITIES Idaho Jurisdiction Scenario: AVU-E-15-05 Company Cas Cost of Service Basic Summary Electric Utility 06/01/15 Load Factor Peak Credi For the Twelve Months Ended December 31, 2014 Transmission By Demand 12 CP (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l) (m) Residential General Large Gen Extra Large Extra Large Pumping Street & System Service Service Service Gen Service Service CP Service rea Lights Description Total Sch 1 Sch 11-12 Sch 21-22 Sch 25 Sch 25P Sch 31-32 Sch 41-49 Plant In Service 1 Production Plant 462,520,000 185,601,024 56,795,187 104,760,947 44,014,350 61,798,348 7,964,545 1,585,598 2 Transmission Plant 228,650,000 101,336,136 29,553,862 51,177,090 19,435,547 23,591,167 3,154,266 401,933 3 Distribution Plant 518,091,000 268,384,769 74,768,105 116,239,045 13,824,308 2,904,536 17,395,138 24,575,100 4 Intangible Plant 81,039,000 39,578,104 10,794,232 15,483,668 5,618,743 7,324,154 1,478,734 761,365 5 General Plant 108,516,000 60,756,256 15,349,881 17,332,673 5,269,692 6,202,298 2,081,470 1,523,730 6 Total Plant In Service 1,398,816,000 655,656,288 187,261,267 304,993,422 88,162,640 101,820,504 32,074,153 28,847,725 ccum Depreciation 7 Production Plant (195,006,000) (78,252,429) (23,945,780) (44,168,929) (18,557,170) (26,055,195) (3,357,983) (668,514) 8 Transmission Plant (70,554,000) (31,269,056) (9,119,367) (15,791,596) (5,997,182) (7,279,472) (973,305) (124,023) 9 Distribution Plant (184,500,000) (95,938,435) (26,215,650) (39,999,659) (4,181,922) (714,960) (6,040,197) (11,409,177) 10 Intangible Plant (17,698,000) (9,350,629) (2,438,313) (3,067,175) (1,024,217) (1,276,958) (331,155) (209,552) 11 General Plant (38,026,000) (21,290,108) (5,378,880) (6,073,687) (1,846,597) (2,173,399) (729,385) (533,943) 12 Total Accumulated Depreciation (505,784,000) (236,100,657) (67,097,991) (109,101,046) (31,607,088) (37,499,983) (11,432,024) (12,945,210) 13 Net Plant 893,032,000 419,555,631 120,163,276 195,892,376 56,555,551 64,320,521 20,642,129 15,902,515 14 ccumulated Deferred FIT (165,948,000) (77,937,157) (22,214,442) (35,994,813) (10,488,286) (12,178,639) (3,778,127) (3,356,534) 15 Miscellaneous Rate Base 22,141,000 9,980,398 2,933,204 5,082,482 1,456,704 1,671,657 525,617 490,938 16 Total Rate Base 749,225,000 351,598,872 100,882,038 164,980,044 47,523,969 53,813,539 17,389,618 13,036,920 17 Revenue From Retail Rates 244,977,000 104,939,000 36,296,000 54,364,000 17,152,500 23,458,500 5,277,000 3,490,000 18 Other Operating Revenues 32,379,000 13,468,504 4,056,599 7,314,573 2,882,234 3,890,874 572,708 193,508 19 Total Revenues 277,356,000 118,407,504 40,352,599 61,678,573 20,034,734 27,349,374 5,849,708 3,683,508 Operating Expenses 20 Production Expenses 100,829,000 40,460,879 12,381,307 22,837,805 9,595,094 13,471,992 1,736,265 345,659 21 Transmission Expenses 10,691,000 4,738,179 1,381,851 2,392,890 908,749 1,103,053 147,484 18,793 22 Distribution Expenses 11,953,000 6,014,349 1,748,809 2,646,810 371,538 78,334 399,468 693,693 23 Customer Accounting Expenses 4,427,000 3,268,783 704,988 219,817 77,293 82,842 57,483 15,794 24 Customer Information Expenses 606,000 494,408 98,625 5,531 43 5 6,684 704 25 Sales Expenses 0 0 0 0 0 0 0 0 26 Admin & General Expenses 23,830,000 13,017,034 3,352,708 3,995,545 1,211,819 1,436,177 467,570 349,147 27 Total O&M Expenses 152,336,000 67,993,632 19,668,289 32,098,398 12,164,536 16,172,402 2,814,954 1,423,790 28 Taxes Other Than Income Taxes 11,233,000 4,964,057 1,460,903 2,532,003 830,736 1,032,144 238,350 174,808 29 Other Income Related Items 1,223,000 701,548 174,974 188,265 54,451 61,797 23,667 18,298 Depreciation Expense 30 Production Plant Depreciation 9,929,000 3,984,331 1,219,233 2,248,922 944,864 1,326,636 170,976 34,038 31 Transmission Plant Depreciation 4,135,000 1,832,604 534,464 925,507 351,480 426,632 57,043 7,269 32 Distribution Plant Depreciation 15,729,000 8,304,311 2,406,094 3,409,076 374,078 50,083 533,362 651,995 33 General Plant Depreciation 12,432,000 6,960,465 1,758,540 1,985,696 603,716 710,559 238,461 174,564 34 Amortization Expense 3,143,000 1,273,999 388,011 710,797 294,220 409,179 54,311 12,483 35 Total Depreciation Expense 45,368,000 22,355,709 6,306,342 9,279,999 2,568,358 2,923,089 1,054,153 880,349 36 Income Tax 18,236,000 5,025,415 3,882,988 5,091,106 1,216,371 2,211,545 484,684 323,892 37 Total Operating Expenses 228,396,000 101,040,362 31,493,495 49,189,770 16,834,451 22,400,977 4,615,808 2,821,137 38 Net Income 48,960,000 17,367,142 8,859,104 12,488,803 3,200,282 4,948,397 1,233,901 862,371 39 Rate of Return 6.53% 4.94% 8.78% 7.57% 6.73% 9.20% 7.10% 6.61% 40 Return Ratio 1.00 0.76 1.34 1.16 1.03 1.41 1.09 1.01 41 Interest Expense 20,004,000 9,387,546 2,693,509 4,404,899 1,268,870 1,436,799 464,296 348,080 42 Revenue Related Operating Expenses 1,435,000 614,700 212,611 318,448 100,474 137,413 30,911 20,443 Exhibit No. 13 Case No. AVU-E-15-05 T. Knox, Avista Schedule 3, p. 1 of 4 Sumcost VISTA UTILITIES Idaho Jurisdiction Scenario: AVU-E-15-05 Company Cas Revenue to Cost by Functional Component Summary Electric Utility 06/01/15 Load Factor Peak Credi For the Twelve Months Ended December 31, 2014 Transmission By Demand 12 CP (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l) (m) Residential General Large Gen Extra Large Extra Large Pumping Street & System Service Service Service Gen Service Service CP Service rea Lights Description Total Sch 1 Sch 11-12 Sch 21-22 Sch 25 Sch 25P Sch 31-32 Sch 41-49 Functional Cost Components at Current Return by Schedul 1 Production 119,247,384 44,960,305 15,595,938 27,698,214 11,327,318 17,185,169 2,073,970 406,470 2 Transmission 24,438,553 9,153,271 3,769,059 5,926,188 2,093,280 3,103,158 350,770 42,826 3 Distribution 58,402,753 28,313,907 10,308,388 13,393,271 1,583,557 393,699 1,995,088 2,414,843 4 Common 42,888,310 22,511,517 6,622,614 7,346,327 2,148,346 2,776,474 857,172 625,861 5 Total Current Rate Revenue 244,977,000 104,939,000 36,296,000 54,364,000 17,152,500 23,458,500 5,277,000 3,490,000 Expressed as $/kWh 6 Production $0.03881 $0.03918 $0.04296 $0.03964 $0.03583 $0.03618 $0.03516 $0.02991 7 Transmission $0.00795 $0.00798 $0.01038 $0.00848 $0.00662 $0.00653 $0.00595 $0.00315 8 Distribution $0.01901 $0.02468 $0.02840 $0.01917 $0.00501 $0.00083 $0.03382 $0.17772 9 Common $0.01396 $0.01962 $0.01824 $0.01051 $0.00679 $0.00584 $0.01453 $0.04606 10 Total Current Melded Rates $0.07972 $0.09146 $0.09999 $0.07780 $0.05425 $0.04938 $0.08946 $0.25684 Functional Cost Components at Uniform Current Return 11 Production 118,255,620 47,453,871 14,521,210 26,784,941 11,253,447 15,800,402 2,036,349 405,401 12 Transmission 24,185,192 10,718,714 3,126,026 5,413,198 2,055,773 2,495,329 333,639 42,514 13 Distribution 59,345,208 31,998,921 8,841,153 12,325,248 1,557,206 312,341 1,909,088 2,401,251 14 Common 43,190,979 23,962,769 6,091,594 7,040,927 2,130,810 2,503,131 838,031 623,718 15 Total Uniform Current Cost 244,977,000 114,134,274 32,579,983 51,564,314 16,997,236 21,111,202 5,117,107 3,472,884 Expressed as $/kWh 16 Production $0.03848 $0.04136 $0.04000 $0.03833 $0.03559 $0.03326 $0.03452 $0.02984 17 Transmission $0.00787 $0.00934 $0.00861 $0.00775 $0.00650 $0.00525 $0.00566 $0.00313 18 Distribution $0.01931 $0.02789 $0.02436 $0.01764 $0.00493 $0.00066 $0.03237 $0.17672 19 Common $0.01406 $0.02088 $0.01678 $0.01008 $0.00674 $0.00527 $0.01421 $0.04590 20 Total Current Uniform Melded Rates $0.07972 $0.09947 $0.08975 $0.07379 $0.05376 $0.04444 $0.08675 $0.25558 21 Revenue to Cost Ratio at Current Rates 1.00 0.92 1.11 1.05 1.01 1.11 1.03 1.00 Functional Cost Components at Proposed Return by Schedul 22 Production 123,319,900 46,953,104 15,982,878 28,534,220 11,717,438 17,570,381 2,141,727 420,152 23 Transmission 26,792,976 10,404,447 4,000,607 6,395,834 2,291,377 3,272,269 381,629 46,814 24 Distribution 63,344,676 31,259,105 10,836,708 14,371,046 1,722,731 416,335 2,149,996 2,588,754 25 Common 44,749,448 23,671,344 6,813,807 7,625,900 2,240,954 2,852,515 891,648 653,280 26 Total Proposed Rate Revenue 258,207,000 112,288,000 37,634,000 56,927,000 17,972,500 24,111,500 5,565,000 3,709,000 Expressed as $/kWh 27 Production $0.04013 $0.04092 $0.04403 $0.04083 $0.03706 $0.03699 $0.03631 $0.03092 28 Transmission $0.00872 $0.00907 $0.01102 $0.00915 $0.00725 $0.00689 $0.00647 $0.00345 29 Distribution $0.02061 $0.02724 $0.02985 $0.02057 $0.00545 $0.00088 $0.03645 $0.19052 30 Common $0.01456 $0.02063 $0.01877 $0.01091 $0.00709 $0.00600 $0.01512 $0.04808 31 Total Proposed Melded Rates $0.08402 $0.09786 $0.10368 $0.08146 $0.05684 $0.05076 $0.09434 $0.27296 Functional Cost Components at Uniform Requested Return 32 Production 122,451,054 49,137,423 15,036,389 27,735,208 11,652,693 16,360,963 2,108,594 419,783 33 Transmission 26,570,232 11,775,747 3,434,301 5,947,024 2,258,504 2,741,407 366,541 46,706 34 Distribution 64,171,541 34,487,113 9,544,547 13,436,645 1,699,635 345,279 2,074,255 2,584,067 35 Common 45,014,174 24,942,615 6,346,149 7,358,709 2,225,585 2,613,785 874,790 652,541 36 Total Uniform Cost 258,207,000 120,342,899 34,361,385 54,477,586 17,836,417 22,061,435 5,424,180 3,703,098 Expressed as $/kWh 37 Production $0.03985 $0.04283 $0.04142 $0.03969 $0.03685 $0.03444 $0.03575 $0.03089 38 Transmission $0.00865 $0.01026 $0.00946 $0.00851 $0.00714 $0.00577 $0.00621 $0.00344 39 Distribution $0.02088 $0.03006 $0.02629 $0.01923 $0.00538 $0.00073 $0.03517 $0.19017 40 Common $0.01465 $0.02174 $0.01748 $0.01053 $0.00704 $0.00550 $0.01483 $0.04802 41 Total Uniform Melded Rates $0.08402 $0.10488 $0.09466 $0.07796 $0.05641 $0.04644 $0.09196 $0.27253 42 Revenue to Cost Ratio at Proposed Rates 1.00 0.93 1.10 1.04 1.01 1.09 1.03 1.00 43 Current Revenue to Proposed Cost Ratio 0.95 0.87 1.06 1.00 0.96 1.06 0.97 0.94 44 Target Revenue Increase 13,230,000 15,404,000 (1,935,000)114,000 684,000 (1,397,000)147,000 213,000 Exhibit No. 13 Case No. AVU-E-15-05 T. Knox, Avista Schedule 3, p. 2 of 4 Sumcost VISTA UTILITIES Idaho Jurisdiction Scenario: AVU-E-15-05 Company Cas Revenue to Cost By Classification Summary Electric Utility 06/01/15 Load Factor Peak Credi For the Twelve Months Ended December 31, 2014 Transmission By Demand 12 CP (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l) (m) Residential General Large Gen Extra Large Extra Large Pumping Street & System Service Service Service Gen Service Service CP Service rea Lights Description Total Sch 1 Sch 11-12 Sch 21-22 Sch 25 Sch 25P Sch 31-32 Sch 41-49 Cost Classifications at Current Return by Schedul 1 Energ 83,297,726 29,272,301 10,529,372 19,443,695 8,404,276 13,660,177 1,620,539 367,365 2 Demand 133,789,480 55,814,981 20,457,257 34,415,079 8,713,778 9,793,921 3,243,502 1,350,962 3 Custome 27,889,794 19,851,718 5,309,371 505,227 34,446 4,401 412,958 1,771,673 4 Total Current Rate Revenue 244,977,000 104,939,000 36,296,000 54,364,000 17,152,500 23,458,500 5,277,000 3,490,000 Expressed as Unit Cos 5 Energ $/kWh $0.02711 $0.02551 $0.02901 $0.02782 $0.02658 $0.02876 $0.02747 $0.02704 6 Demand $/kW/mo $9.92 $7.01 $12.47 $18.18 $13.64 $10.71 $8.23 $32.29 7 Custome $/Cust/mo $18.42 $16.07 $21.55 $36.57 $318.95 $366.78 $24.73 $1,007.20 Cost Classifications at Uniform Current Return 8 Energ 82,352,327 30,937,377 9,787,437 18,787,576 8,348,148 12,534,968 1,590,445 366,376 9 Demand 133,928,115 62,056,769 17,923,752 32,294,490 8,614,767 8,572,069 3,123,364 1,342,905 10 Custome 28,696,558 21,140,128 4,868,794 482,248 34,321 4,165 403,298 1,763,603 11 Total Uniform Current Cost 244,977,000 114,134,274 32,579,983 51,564,314 16,997,236 21,111,202 5,117,107 3,472,884 Expressed as Unit Cos 12 Energ $/kWh $0.02680 $0.02696 $0.02696 $0.02689 $0.02640 $0.02639 $0.02696 $0.02696 13 Demand $/kW/mo $9.93 $7.79 $10.93 $17.06 $13.48 $9.37 $7.93 $32.10 14 Custome $/Cust/mo $18.96 $17.12 $19.76 $34.91 $317.78 $347.11 $24.15 $1,002.62 15 Revenue to Cost Ratio at Current Rates 1.00 0.92 1.11 1.05 1.01 1.11 1.03 1.00 Cost Classifications at Proposed Return by Schedule 16 Energ 86,172,451 30,602,995 10,796,497 20,044,305 8,700,695 13,973,187 1,674,743 380,030 17 Demand 142,814,030 60,803,601 21,369,503 36,356,432 9,236,698 10,133,846 3,459,899 1,454,052 18 Custome 29,220,519 20,881,405 5,468,001 526,263 35,108 4,467 430,358 1,874,918 19 Total Proposed Rate Revenue 258,207,000 112,288,000 37,634,000 56,927,000 17,972,500 24,111,500 5,565,000 3,709,000 Expressed as Unit Cos 20 Energ $/kWh $0.02804 $0.02667 $0.02974 $0.02868 $0.02752 $0.02941 $0.02839 $0.02797 21 Demand $/kW/mo $10.59 $7.63 $13.03 $19.21 $14.45 $11.08 $8.78 $34.76 22 Custome $/Cust/mo $19.30 $16.91 $22.19 $38.09 $325.07 $372.26 $25.77 $1,065.90 Cost Classifications at Uniform Requested Return 23 Energ 85,344,825 32,061,572 10,143,090 19,470,275 8,651,501 12,990,461 1,648,238 379,689 24 Demand 142,932,748 66,271,297 19,138,301 34,501,153 9,149,919 9,066,713 3,354,092 1,451,273 25 Custome 29,929,427 22,010,030 5,079,994 506,159 34,998 4,261 421,850 1,872,136 26 Total Uniform Cost 258,207,000 120,342,899 34,361,385 54,477,586 17,836,417 22,061,435 5,424,180 3,703,098 Expressed as Unit Cos 27 Energ $/kWh $0.02777 $0.02794 $0.02794 $0.02786 $0.02736 $0.02735 $0.02794 $0.02794 28 Demand $/kW/mo $10.60 $8.32 $11.67 $18.23 $14.32 $9.91 $8.51 $34.69 29 Custome $/Cust/mo $19.77 $17.82 $20.62 $36.64 $324.05 $355.07 $25.27 $1,064.32 30 Revenue to Cost Ratio at Proposed Rates 1.00 0.93 1.10 1.04 1.01 1.09 1.03 1.00 31 Current Revenue to Proposed Cost Ratio 0.95 0.87 1.06 1.00 0.96 1.06 0.97 0.94 32 nnual Consumption (mWh's) 3,072,989 1,147,395 362,993 698,804 316,177 475,047 58,986 13,588 33 Estimated Annual Billing Demand (kW) 13,489,000 7,966,469 1,640,110 1,892,799 639,000 914,862 393,923 41,837 34 Monthly Average Number of Customers 126,154 102,923 20,531 1,151 9 1 1,391 147 Exhibit No. 13 Case No. AVU-E-15-05 T. Knox, Avista Schedule 3, p. 3 of 4 Sumcost VISTA UTILITIES Idaho Jurisdiction Scenario: AVU-E-15-05 Company Cas Customer Cost Analysis Electric Utility 06/01/15 Load Factor Peak Credi For the Twelve Months Ended December 31, 2014 Transmission By Demand 12 CP (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l) (m) Residential General Large Gen Extra Large Extra Large Pumping Street & System Service Service Service Gen Service Service CP Service rea Lights Description Total Sch 1 Sch 11-12 Sch 21-22 Sch 25 Sch 25P Sch 31-32 Sch 41-49 Rate Base 1 Services 50,011,000 40,861,193 8,151,038 446,368 0 0 552,401 0 2 Services Accum. Depr. (22,180,000) (18,122,038) (3,615,005) (197,965) 0 0 (244,991) 0 3 Total Services 27,831,000 22,739,154 4,536,033 248,402 0 0 307,410 0 4 Meters 21,523,000 13,832,911 5,684,375 1,262,674 24,386 4,289 714,366 0 5 Meters Accum. Depr. (5,093,000) (3,273,290) (1,345,097) (298,787) (5,770) (1,015) (169,041) 0 6 Total Meters 16,430,000 10,559,621 4,339,278 963,887 18,615 3,274 545,325 0 7 Total Rate Base 44,261,000 33,298,776 8,875,311 1,212,289 18,615 3,274 852,735 0 8 Return on Rate Base @ 7.62% 3,372,691 2,537,369 676,299 92,377 1,418 249 64,978 0 9 Tax Benefit of Interest (413,613) (311,172) (82,939) (11,329) (174) (31) (7,969) 0 10 Revenue Conversion Facto 0.61459 0.61459 0.61459 0.61459 0.61459 0.61459 0.61459 0.61459 11 Rate Base Revenue Requiremen 4,814,696 3,622,229 965,453 131,872 2,025 356 92,760 0 Expenses 12 Services Depr Exp 1,349,000 1,102,192 219,867 12,040 0 0 14,901 0 13 Meters Depr Exp 1,640,000 1,054,034 433,135 96,213 1,858 327 54,433 0 14 Services Operations Exp 304,000 248,381 49,547 2,713 0 0 3,358 0 15 Meters Operating Exp 431,000 277,005 113,830 25,285 488 86 14,305 0 16 Meters Maintenance Exp 3,000 1,928 792 176 3 1 100 0 17 Meter Reading 324,000 251,412 50,152 2,812 14,602 1,622 3,399 0 18 Billing 3,065,000 2,498,095 498,323 27,945 2,977 331 33,772 3,558 19 Total Expenses 7,116,000 5,433,049 1,365,647 167,184 19,929 2,366 124,267 3,558 20 Revenue Conversion Facto 0.994222 0.994222 0.994222 0.994222 0.994222 0.994222 0.994222 0.994222 21 Expense Revenue Requiremen 7,157,355 5,464,624 1,373,584 168,156 20,045 2,380 124,989 3,578 22 11,972,052 9,086,853 2,339,037 300,028 22,070 2,736 217,749 3,578 23 Total Customer Bills 1,513,846 1,235,079 246,375 13,816 108 12 16,697 1,759 24 Average Unit Cost per Month $7.91 $7.36 $9.49 $21.72 $204.35 $228.03 $13.04 $2.03 25 Total Customer Related Cost 29,929,427 22,010,030 5,079,994 506,159 34,998 4,261 421,850 1,872,136 26 Customer Related Unit Cost per Month $19.77 $17.82 $20.62 $36.64 $324.05 $355.07 $25.27 $1,064.32 27 Total Distribution Demand Related Cost 59,101,272 29,117,754 8,302,771 15,737,755 2,024,135 417,326 2,197,623 1,303,910 28 Dist Demand Related Unit Cost per Month $39.04 $23.58 $33.70 $1,139.10 $18,741.99 $34,777.14 $131.62 $741.28 29 Total Distribution Unit Cost per Month $58.81 $41.40 $54.32 $1,175.73 $19,066.04 $35,132.21 $156.88 $1,805.60 Meter, Services, Meter Reading & Billing Costs by Schedule at Requested Rate of Return Distribution Fixed Costs per Customer Total Meter, Service, Meter Reading, and Billing Cost Exhibit No. 13 Case No. AVU-E-15-05 T. Knox, Avista Schedule 3, p. 4 of 4