20170612Knox Exhibit 14.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: [phone]
FACSIMILE: [phone]
[e-mail]

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION ) CASE NO. AVU-E-17-01
OF AVISTA CORPORATION FOR THE )
AUTHORITY TO INCREASE ITS RATES )
AND CHARGES FOR ELECTRIC AND )
NATURAL GAS SERVICE TO ELECTRIC ) EXHIBIT NO. 14
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, 2016
2018 Pro Forma Study
Line Column Description of Adjustment (000's)Revenue Expense Plant
Accumulated
Depreciation
Deferred
Debits/Credits
Deferred
Tax
1 1.00 Per Results Report 75,333 171,109 692,802 (257,787) 220 (93,326)
2 1.01 Deferred FIT Rate Base - - - - - (806)
3 1.02 Deferred Debits, Credits & Reg Amortizations - (48) - - (149) -
4 1.03 Restate Capital 2016 EOP - - 29,597 2,130 - (6,126)
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 - 305 - - - -
13 2.08 Miscellaneous Restating - (1) - - - -
14 2.09 Restate Incentives - - - - - -
15 2.10 ID PCA - (2,409) - - - -
16 2.11 Nez Perce Settlement Adjustment - (36) - - - -
17 2.12 Colstrip / CS2 Maintenance - (209) - - - -
18 2.13 2015 Storm 3-year Amortization - - - - - -
19 2.14 Restate Debt Interest - - - - - -
20 3.01 Pro Forma Power Supply (55,833) (46,531) - - - -
21 3.02 Pro Forma Transmission Rev/Exp (741) 76 - - - -
22 3.03 Pro Forma Labor Non-Exec - 433 - - - -
23 3.04 Pro Forma Labor Exec - - - - - -
24 3.05 Pro Forma Employee Benefits - (67) - - - -
25 3.06 Pro Forma IS/IT Costs - - - - - -
26 3.07 Pro Forma Property Tax - 868 - - - -
27 3.08 Planned Capital Add 2017 EOP - 1,211 39,921 (10,836) - (7,586)
28 3.09 Pro Forma O&M Offsets - - - - - -
29 3.10 Pro Forma Underground Equip Inspection - - - - - -
30 2018 Pro Forma Total 18,759 124,701 762,320 (266,493) 71 (107,844)
Production / Transmission
Exhibit No. 14
Case No. AVU-E-17-01
T. Knox, Avista
Schedule 1, p. 1 of 4
AVISTA UTILITIES
AVERAGE PRODUCTION AND TRANSMISSION COST
IDAHO ELECTRIC
TWELVE MONTHS ENDED DECEMBER 31, 2016
Line ($000's)Debt Cost
1 Prod/Trans Pro Forma Rate Base 388,054
2 Cost of Capital Proposed Rate of Return 7.810%2.86%
3 Rate Base Net Operating Income Requirement $30,307
4 Tax Effect Net Operating Income Requirement ($3,884)
(Rate Base x Debt Cost x -35%)
5 Net Expense Net Operating Income Requirement 105,942
(Expense - Revenue)
6 Tax Effect Net Operating Income Requirement ($37,080)
(Net Expense x -.35%)
7 Total Prod/Trans Net Operating Income Requirement $95,285
8 1 - Tax Rate Conversion Factor (Excl. Rev. Rel. Exp.)0.65
9 Prod/Trans Revenue Requirement $146,592
10 Test Year WA Normalized Retail Load MWh 2,953,031
11 Prod/Trans Rev Requirement per kWh 0.04964$
12 Cost of Service Energy Classified Production/Transmission Costs $74,866 Company Case at Unity AVU-E-17-01
13 Cost of Service Total Production/Transmission Costs $149,289 Company Case at Unity AVU-E-17-01
14 2018 Load Change Adjustment Rate per kWh (Line 11 * Line 12 / Line 13)0.02489$
2018 Pro Forma Study
Calculation of Load Change Adjustment Rate
Proposed Production and Transmission Revenue Requirement
Exhibit No. 14
Case No. AVU-E-17-01
T. Knox, Avista
Schedule 1, p. 2 of 4
AVISTA UTILITIES
AVERAGE PRODUCTION AND TRANSMISSION COST
IDAHO ELECTRIC
TWELVE MONTHS ENDED DECEMBER 31, 2016
2019 Pro Forma Study
Line Column Description of Adjustment (000's)Revenue Expense Plant
Accumulated
Depreciation
Deferred
Debits/Credits
Deferred
Tax
1 1.00 Per Results Report 75,333 171,109 692,802 (257,787) 220 (93,326)
2 1.01 Deferred FIT Rate Base - - - - - (806)
3 1.02 Deferred Debits, Credits & Reg Amortizations - (48) - - (149) -
4 1.03 Restate Capital 2016 EOP - - 29,597 2,130 - (6,126)
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 - 305 - - - -
13 2.08 Miscellaneous Restating - (1) - - - -
14 2.09 Restate Incentives - - - - - -
15 2.10 ID PCA - (2,409) - - - -
16 2.11 Nez Perce Settlement Adjustment - (36) - - - -
17 2.12 Colstrip / CS2 Maintenance - (209) - - - -
18 2.13 2015 Storm 3-year Amortization - - - - - -
19 2.14 Restate Debt Interest - - - - - -
20 3.01 Pro Forma Power Supply (55,833) (46,531) - - - -
21 3.02 Pro Forma Transmission Rev/Exp (741) 76 - - - -
22 3.03 Pro Forma Labor Non-Exec - 433 - - - -
23 3.04 Pro Forma Labor Exec - - - - - -
24 3.05 Pro Forma Employee Benefits - (67) - - - -
25 3.06 Pro Forma IS/IT Costs - - - - - -
26 3.07 Pro Forma Property Tax - 868 - - - -
27 3.08 Planned Capital Add 2017 EOP - 1,211 39,921 (10,836) - (7,586)
28 3.09 Pro Forma O&M Offsets - - - - - -
29 3.10 Pro Forma Underground Equip Inspection - - - - - -
30 19.01 Planned Capital Add 2018 AMA - 179 9,431 (6,097) - (3,350)
31 19.02 Planned Capital Add 2018 EOP - 464 24,768 (6,097) - (3,350)
32 19.03 Planned Capital Add 2019 AMA - 130 6,735 (6,191) - (4,165)
33 19.04 Pro Forma Property Tax - 410 - - - -
34 19.05 Pro Forma Labor Non-Exec - 244 - - - -
35 2019 Pro Forma Total 18,759 126,128 803,254 (284,878) 71 (118,709)
Production / Transmission
Exhibit No. 14
Case No. AVU-E-17-01
T. Knox, Avista
Schedule 1, p. 3 of 4
AVISTA UTILITIES
AVERAGE PRODUCTION AND TRANSMISSION COST
IDAHO ELECTRIC
TWELVE MONTHS ENDED DECEMBER 31, 2016
Line ($000's)Debt Cost
1 Prod/Trans Pro Forma Rate Base 399,738
2 Cost of Capital Proposed Rate of Return 7.810%2.86%
3 Rate Base Net Operating Income Requirement $31,220
4 Tax Effect Net Operating Income Requirement ($4,001)
(Rate Base x Debt Cost x -35%)
5 Net Expense Net Operating Income Requirement 107,369
(Expense - Revenue)
6 Tax Effect Net Operating Income Requirement ($37,579)
(Net Expense x -.35%)
7 Total Prod/Trans Net Operating Income Requirement $97,008
8 1 - Tax Rate Conversion Factor (Excl. Rev. Rel. Exp.)0.65
9 Prod/Trans Revenue Requirement $149,243
10 Test Year WA Normalized Retail Load MWh 2,953,031
11 Prod/Trans Rev Requirement per kWh 0.05054$
12 Cost of Service Energy Classified Production/Transmission Costs $74,866 Company Case at Unity AVU-E-17-01
13 Cost of Service Total Production/Transmission Costs $149,289 Company Case at Unity AVU-E-17-01
14 2019 Load Change Adjustment Rate per kWh (Line 11 * Line 12 / Line 13)0.02534$
Proposed Production and Transmission Revenue Requirement
2019 Pro Forma Study
Calculation of Load Change Adjustment Rate
Exhibit No. 14
Case No. AVU-E-17-01
T. Knox, Avista
Schedule 1, p. 4 of 4
Exhibit No. 14
Case No. AVU-E-17-01
T. Knox, Avista
Schedule 2, p. 1 of 9

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
As shown in the flow chart below, there are three basic steps involved in a cost of service 7
study: functionalization, classification, and allocation. 8
First, the expenses and rate base associated with the electric system under study are 9
assigned to functional categories. The FERC uniform system of accounts provides the basic 10
segregation into production, transmission, and distribution. Traditionally, customer accounting, 11
customer information, and sales expenses are included in the distribution function, and 12
administrative and general expenses and general plant rate base are allocated to all functions. This 13
study includes a separate functional category for common costs. Administrative and general costs 14
that cannot be 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 (capacity), or customer- 17
related. Energy-related costs are allocated based on each rate schedule’s share of commodity 18
consumption. Demand-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. 14
Case No. AVU-E-17-01
T. Knox, Avista
Schedule 2, p. 2 of 9

* 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. 14
Case No. AVU-E-17-01
T. Knox, Avista
Schedule 2, p. 3 of 9

The final step is allocation of the costs to the various rate schedules utilizing the allocation 1
factors 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 energy production costs contain 8
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 37.65% for 12
the 2016 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-19
related costs are allocated to class by pro forma annual kilowatt-hour sales adjusted for losses to 20
reflect generation level consumption. 21

1 1 – (average MW÷ peak MW).
Exhibit No. 14
Case No. AVU-E-17-01
T. Knox, Avista
Schedule 2, p. 4 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. 10
Customer Relations Distribution Cost Classification 11
Customer service, customer information and sales expenses are the core of the customer 12
relations functional unit which is included with the distribution cost category. For the most part 13
they are classified as customer-related. Exceptions are sales expenses which are classified as 14
energy-related and uncollectible accounts expense which is considered separately as a revenue 15
conversion item. Demand Side Management expenses (if any) recorded in Account 908 would be 16
considered separately from the other customer information costs. 17
Any demand side management investment and amortization included in base rates would be 18
classified implicitly to demand and energy by the sum of production plant in service, then allocated 19
to rate schedules by coincident peak demand and energy consumption, respectively. At this point 20
in time, the Company’s demand side management investments in base rates have been fully 21
amortized except for some minor outstanding loan balances that will remain on the books until 22
satisfied. All current demand side management costs are managed through the Schedule 91 Public 23
Purpose Tariff Rider balancing account which is not included in this cost study. 24
Exhibit No. 14
Case No. AVU-E-17-01
T. Knox, Avista
Schedule 2, p. 5 of 9

Distribution Cost Allocation 1
Distribution demand-related costs, which cannot be directly assigned, are allocated to 2
customer class by the average of the twelve monthly non-coincident peaks for each class. 3
Distribution facilities that serve only secondary voltage customers are either allocated by the non-4
coincident peaks of secondary voltage customers (excludes demand from customers receiving 5
service at primary voltage)2, or by the average number of secondary voltage customers. This 6
includes secondary voltage overhead or underground conductors and devices, line transformers, 7
and service lines to the customer’s premises. The costs of specific substations and related primary 8
voltage distribution facilities are directly assigned to Extra Large General Service customers 9
(Schedule 25 and 25P) based on their load ratio share of the substation capacity from which they 10
receive service. 11
Most customer costs are allocated by average number of customers. Weighted customer 12
allocators have been developed using typical current cost of meters, estimated meter reading time, 13
and direct assignment of billing costs for hand-billed customers. Street and area light customers 14
(Schedules 41 – 49) are excluded from metering and meter reading expenses as their service is not 15
metered. 16
Administrative and General Costs 17
Administrative and general costs which are directly associated with production, 18
transmission, distribution, or customer relations functions are directly assigned to those functions 19
and allocated to customer class by the relevant plant or number of customers. The remainder of 20
administrative and general costs are considered common costs, and have been left in their own 21
functional category. These common costs are classified by the implicit relationship of energy, 22

2 Customers taking service below 11 kV are secondary voltage customers, customers taking service at greater than 11kV
are primary voltage customers.
Exhibit No. 14
Case No. AVU-E-17-01
T. Knox, Avista
Schedule 2, p. 6 of 9

demand and customer within the four-factor allocator applied to them. The four-factor allocator 1
consists of a 25% weighting of each of the following: 1) operating & maintenance expenses 2
excluding resource costs, labor expenses, and administrative and general expenses; 2) operating 3
and maintenance labor expenses excluding administrative and general labor expenses; 3) net 4
production, transmission, and distribution plant; and 4) number of customers. 5
Revenue Conversion Items 6
In this study, uncollectible accounts and commission fees have been classified as revenue-7
related and are allocated by pro forma revenue. These items vary with revenue and are included in 8
the calculation of the revenue conversion factor. Income tax expense items are allocated to 9
schedules by net income before income tax adjusted by interest expense. 10
For the functional summaries on pages 2 and 3 of the cost of service study, these items are 11
assigned to component cost categories. The revenue-related expense items have been reduced to a 12
percent of all other costs and loaded onto each cost category by that ratio. Similarly, income tax 13
items have been reduced to a percent of net income before tax then assigned to cost categories by 14
relative rate base (as is net income). 15
The following matrix outlines the methodology applied in the Company Base Case cost of 16
service study. 17
IPUC Case No. AVU-E-17-01 Methodology Matrix
Avista Utilities Idaho Jurisdiction
Electric Cost of Service Methodology
Line Account Functional Category Classification Allocation
Production Plant
1 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 Consumption
4 Other Production P = Production Demand/Energy by Load Factor Peak Credit D01/E02 Coincident Peak Demand/Annual Generation Level Consumption
Transmission Plant
5 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 DA
8 362 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 Secondary
11 366 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 Secondary
14 369 Services D = Distribution Customer C02 Secondary Customers unweighted Excl Lighting
15 370 Meters D = Distribution Customer C04 Customers weighted by Current Typical Meter Cost
16 373 Street and Area Lighting Systems D = Distribution Customer C05 Direct Assignment to Street and Area Lights
General Plant
17 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 Plant
18 301 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/Amortization
22 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 Consumption
24 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 Plant
28 282/190 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 Plant
31 Working Capital P/T/D/G Demand/Energy/Customer as in related Plant S06 Sum of Production, Transmission, Distribution, and General Plant
Exhibit No. 14
Case No. AVU-E-17-01
T. Knox, Avista
Schedule 2, p. 7 of 9
IPUC Case No. AVU-E-17-01 Methodology Matrix
Avista 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 Consumption
2 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 Consumption
5 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 Consumption
7 Other P = Production Demand/Energy by Load Factor Peak Credit D01/E02 Coincident Peak Demand/Annual Generation Level Consumption
8 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 Expenses
12 581 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 Conductors
15 584 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 Systems
17 586 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 Expenses
20 589 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 Expenses
22 591 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 Conductors
25 594 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 Transformers
27 596 MT of Street Lights D = Distribution Customer S15 Sum of Account 373 Street Light and Signal Systems
28 597 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 Uncollectibles
31 902 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 Revenue
34 905 Misc Cust Accounts C = Customer Relations Customer C01 All Customers unweighted
Customer Service & Info Expenses
35 907 Supervision C = Customer Relations Customer C01 All Customers unweighted
36 908 Customer Assistance C = Customer Relations Customer C01 All Customers unweighted
37 908 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. 14
Case No. AVU-E-17-01
T. Knox, Avista
Schedule 2, p. 8 of 9
IPUC Case No. AVU-E-17-01 Methodology Matrix
Avista 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 Plant
3 920 - 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 customers
6 928 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 Alloctor
9 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 Plant
12 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
Taxes
13 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 Consumption
16 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 Expense
18 Federal Income Tax R = Revenue Conversion Revenue R03 Revenue less Expenses Before Income Taxes less Interest Expense
19 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
22 Storm Cost Amortization D=Distribution Demand/Customer from Distribution Plant S03 Sum of Distribution Plant
Operating Revenues
23 Sales of Electricity- Retail R = Revenue from Rates Revenue Input Pro Forma Revenue per Revenue Study
24 Sales for Resale (447)P = Production Demand/Energy from Production Plant S01 Sum of Production Plant
25 Misc Service Revenue (451)D = Distribution Demand/Customer from Distribution Plant S03 Sum of Distribution Plant
26 Sales of Water & Water Power (453)P = Production Demand/Energy from Production Plant S01 Sum of Production Plant
27 Rent from Production Property (454)P = Production Demand/Energy from Production Plant S01 Sum of Production Plant
28 Rent from Transmission Property (454)T = Transmission Demand/Energy from Transmission Plant S02 Sum of Transmission Plant
29 Rent from Distribution Property (454)D = Distribution Demand/Customer from Distribution Plant S03 Sum of Distribution Plant
30 Other Electric Revenues - Generation (456)P = Production Demand/Energy from Production Plant S01 Sum of Production Plant
31 Other Electric Revenues - Wheeling (456)T = Transmission Demand/Energy from Transmission Plant S02 Sum of Transmission Plant
32 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
33 Production Total P = Production Demand/Energy from Production Plant S01 Sum of Production Plant
34 Transmission Total T = Transmission Demand/Energy from Transmission Plant S02 Sum of Transmission Plant
35 Distribution Total D = Distribution Demand/Customer from Distribution Plant S03 Sum of Distribution Plant
36 Customer Accounts Total C = Customer Relations Customer S18 Sum of Other Customer Accounts Expenses Excluding Uncollectibles
37 Customer Service Total C = Customer Relations Customer C01 All Customers unweighted
38 Sales Total C = Customer Relations Energy E02 Annual Generation Level Consumption
39 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
40 Interest Expense (allocation factor input)R = Revenue Conversion Demand/Energy/Customer from Rate Base components S07 Total Rate Base
Exhibit No. 14
Case No. AVU-E-17-01
T. Knox, Avista
Schedule 2, p. 9 of 9
Sumcost AVISTA UTILITIES Idaho Jurisdiction
Scenario: AVU-E-17-01 Company Case Cost of Service Basic Summary Electric Utility 06/09/17
Load Factor Peak Credit For the Twelve Months Ended December 31, 2016
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 Area 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 480,244,000 197,473,909 58,140,608 104,522,472 53,855,677 55,510,682 9,019,849 1,720,803
2 Transmission Plant 251,948,000 112,611,439 29,185,706 53,642,606 25,212,607 26,796,571 3,995,633 503,439
3 Distribution Plant 557,747,000 281,521,386 81,436,351 122,639,659 18,493,633 2,838,141 20,976,158 29,841,672
4 Intangible Plant 94,523,000 47,868,656 12,557,058 16,835,030 7,379,463 7,137,696 1,889,315 855,782
5 General Plant 127,102,000 71,470,557 17,824,792 19,525,473 7,456,807 6,685,021 2,628,498 1,510,852
6 Total Plant In Service 1,511,564,000 710,945,948 199,144,515 317,165,240 112,398,187 98,968,110 38,509,453 34,432,548
Accum Depreciation
7 Production Plant (193,329,000)(79,495,909)(23,405,322)(42,076,996)(21,680,363)(22,346,608)(3,631,068)(692,734)
8 Transmission Plant (73,831,000)(32,999,727)(8,552,598)(15,719,463)(7,388,318)(7,852,484)(1,170,883)(147,528)
9 Distribution Plant (204,995,000)(105,213,826)(30,096,047)(43,663,546)(5,722,966)(729,059)(7,577,970)(11,991,586)
10 Intangible Plant (21,030,000)(11,172,163)(2,861,228)(3,512,864)(1,465,237)(1,381,361)(424,925)(212,222)
11 General Plant (44,726,000)(25,149,818)(6,272,377)(6,870,831)(2,623,980)(2,352,396)(924,944)(531,655)
12 Total Accumulated Depreciation (537,911,000)(254,031,443)(71,187,571)(111,843,701)(38,880,864)(34,661,908)(13,729,789)(13,575,724)
13 Net Plant 973,653,000 456,914,505 127,956,943 205,321,539 73,517,323 64,306,202 24,779,663 20,856,824
14 Accumulated Deferred FIT (206,421,000)(96,908,122)(27,121,695)(43,240,418)(15,579,356)(13,851,401)(5,191,407)(4,528,601)
15 Miscellaneous Rate Base 29,377,000 13,221,458 3,819,527 6,530,647 2,290,281 2,003,701 781,037 730,349
16 Total Rate Base 796,609,000 373,227,841 104,654,776 168,611,768 60,228,248 52,458,502 20,369,293 17,058,572
17 Revenue From Retail Rates 246,583,000 108,991,000 37,312,000 52,070,000 19,946,000 19,145,000 5,494,000 3,625,000
18 Other Operating Revenues 20,780,000 8,899,571 2,541,872 4,505,215 2,114,756 2,135,888 414,754 167,944
19 Total Revenues 267,363,000 117,890,571 39,853,872 56,575,215 22,060,756 21,280,888 5,908,754 3,792,944
Operating Expenses
20 Production Expenses 88,064,000 36,211,472 10,661,444 19,166,647 9,875,701 10,179,185 1,654,001 315,550
21 Transmission Expenses 10,865,000 4,856,253 1,258,604 2,313,283 1,087,268 1,155,575 172,308 21,710
22 Distribution Expenses 10,940,000 5,596,406 1,681,063 2,402,126 443,469 93,011 417,523 306,403
23 Customer Accounting Expenses 4,918,000 3,624,223 785,556 232,498 117,416 76,463 63,922 17,922
24 Customer Information Expenses 570,000 464,785 93,221 5,045 49 4 6,235 661
25 Sales Expenses 0 0 0 0 0 0 0 0
26 Admin & General Expenses 23,837,000 13,147,254 3,331,078 3,812,614 1,437,861 1,287,549 505,435 315,209
27 Total O&M Expenses 139,194,000 63,900,393 17,810,966 27,932,212 12,961,764 12,791,788 2,819,424 977,454
28 Taxes Other Than Income Taxes 12,110,000 5,382,896 1,541,234 2,633,062 1,057,312 995,859 286,399 213,238
29 Other Income Related Items 764,000 434,894 110,560 123,919 33,316 22,962 19,573 18,776
Depreciation Expense
30 Production Plant Depreciation 10,270,000 4,222,972 1,243,335 2,235,209 1,151,702 1,187,094 192,889 36,799
31 Transmission Plant Depreciation 4,526,000 2,022,955 524,293 963,637 452,920 481,374 71,778 9,044
32 Distribution Plant Depreciation 16,423,000 8,476,365 2,540,928 3,468,209 480,167 48,535 617,669 791,126
33 General Plant Depreciation 15,215,000 8,555,527 2,133,753 2,337,336 892,632 800,244 314,650 180,860
34 Amortization Expense 1,923,000 801,669 233,817 417,332 209,351 214,465 36,838 9,528
35 Total Depreciation Expense 48,357,000 24,079,488 6,676,125 9,421,723 3,186,771 2,731,713 1,233,823 1,027,357
36 Income Tax 16,103,000 4,893,661 3,910,183 4,245,753 1,130,207 1,180,967 352,648 389,581
37 Total Operating Expenses 216,528,000 98,691,332 30,049,068 44,356,669 18,369,369 17,723,289 4,711,867 2,626,406
38 Net Income 50,835,000 19,199,240 9,804,803 12,218,546 3,691,387 3,557,598 1,196,887 1,166,538
39 Rate of Return 6.38%5.14%9.37%7.25%6.13%6.78%5.88%6.84%
40 Return Ratio 1.00 0.81 1.47 1.14 0.96 1.06 0.92 1.07
41 Interest Expense 22,783,000 10,674,308 2,993,124 4,822,293 1,722,527 1,500,312 582,561 487,875
42 Revenue Related Operating Expenses 1,507,000 666,102 228,033 318,227 121,901 117,005 33,577 22,154
Exhibit No. 14
Case No. AVU-E-17-01
T. Knox, Avista
Schedule 3, p. 1 of 4
Sumcost AVISTA UTILITIES Idaho Jurisdiction
Scenario: AVU-E-17-01 Company Case Revenue to Cost by Functional Component Summary Electric Utility 06/09/17
Load Factor Peak Credit For the Twelve Months Ended December 31, 2016
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 Area 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 Schedule
1 Production 114,635,668 45,109,599 15,238,783 25,627,781 12,725,155 13,404,982 2,113,042 416,325
2 Transmission 25,784,512 10,259,619 3,789,987 5,921,695 2,524,804 2,843,866 390,850 53,691
3 Distribution 58,928,436 28,583,759 10,803,750 12,761,793 1,900,334 319,343 2,016,900 2,542,558
4 Common 47,234,384 25,038,023 7,479,479 7,758,730 2,795,707 2,576,809 973,209 612,426
5 Total Current Rate Revenue 246,583,000 108,991,000 37,312,000 52,070,000 19,946,000 19,145,000 5,494,000 3,625,000
Expressed as $/kWh
6 Production $0.03882 $0.03939 $0.04174 $0.03948 $0.03562 $0.03697 $0.03499 $0.03120
7 Transmission $0.00873 $0.00896 $0.01038 $0.00912 $0.00707 $0.00784 $0.00647 $0.00402
8 Distribution $0.01996 $0.02496 $0.02959 $0.01966 $0.00532 $0.00088 $0.03340 $0.19052
9 Common $0.01600 $0.02186 $0.02049 $0.01195 $0.00782 $0.00711 $0.01611 $0.04589
10 Total Current Melded Rates $0.08350 $0.09518 $0.10219 $0.08021 $0.05583 $0.05280 $0.09097 $0.27164
Functional Cost Components at Uniform Current Return
11 Production 114,439,416 47,056,910 13,854,576 24,907,111 12,833,502 13,227,880 2,149,379 410,058
12 Transmission 25,813,581 11,537,716 2,990,250 5,496,006 2,583,183 2,745,469 409,376 51,580
13 Distribution 58,876,824 31,296,565 8,887,942 11,898,600 1,941,784 308,273 2,102,163 2,441,497
14 Common 47,453,179 26,413,447 6,627,987 7,458,088 2,828,310 2,530,799 996,148 598,400
15 Total Uniform Current Cost 246,583,000 116,304,639 32,360,756 49,759,805 20,186,778 18,812,421 5,657,066 3,501,536
Expressed as $/kWh
16 Production $0.03875 $0.04109 $0.03795 $0.03837 $0.03592 $0.03648 $0.03559 $0.03073
17 Transmission $0.00874 $0.01008 $0.00819 $0.00847 $0.00723 $0.00757 $0.00678 $0.00387
18 Distribution $0.01994 $0.02733 $0.02434 $0.01833 $0.00543 $0.00085 $0.03481 $0.18295
19 Common $0.01607 $0.02307 $0.01815 $0.01149 $0.00792 $0.00698 $0.01649 $0.04484
20 Total Current Uniform Melded Rates $0.08350 $0.10156 $0.08863 $0.07665 $0.05650 $0.05189 $0.09367 $0.26238
21 Revenue to Cost Ratio at Current Rates 1.00 0.94 1.15 1.05 0.99 1.02 0.97 1.04
Functional Cost Components at Proposed Return by Schedule
22 Production 120,307,023 47,365,508 15,988,277 26,890,510 13,351,062 14,064,209 2,217,325 430,132
23 Transmission 29,205,631 11,740,371 4,223,042 6,667,622 2,862,078 3,210,156 444,023 58,340
24 Distribution 65,369,327 31,726,668 11,841,142 14,274,347 2,139,803 360,555 2,261,609 2,765,203
25 Common 50,272,019 26,631,454 7,940,540 8,285,521 2,984,056 2,748,080 1,039,043 643,325
26 Total Proposed Rate Revenue 265,154,000 117,464,000 39,993,000 56,118,000 21,337,000 20,383,000 5,962,000 3,897,000
Expressed as $/kWh
27 Production $0.04074 $0.04136 $0.04379 $0.04142 $0.03737 $0.03879 $0.03672 $0.03223
28 Transmission $0.00989 $0.01025 $0.01157 $0.01027 $0.00801 $0.00885 $0.00735 $0.00437
29 Distribution $0.02214 $0.02771 $0.03243 $0.02199 $0.00599 $0.00099 $0.03745 $0.20721
30 Common $0.01702 $0.02326 $0.02175 $0.01276 $0.00835 $0.00758 $0.01720 $0.04821
31 Total Proposed Melded Rates $0.08979 $0.10258 $0.10954 $0.08644 $0.05972 $0.05622 $0.09872 $0.29202
Functional Cost Components at Uniform Requested Return
32 Production 120,073,209 49,373,498 14,536,630 26,133,275 13,465,288 13,879,082 2,255,192 430,245
33 Transmission 29,215,601 13,058,293 3,384,341 6,220,335 2,923,625 3,107,300 463,329 58,378
34 Distribution 65,373,329 34,524,006 9,831,995 13,367,357 2,183,503 348,982 2,350,461 2,767,024
35 Common 50,491,861 28,049,737 7,047,562 7,969,624 3,018,428 2,699,985 1,062,948 643,577
36 Total Uniform Cost 265,154,000 125,005,533 34,800,528 53,690,592 21,590,844 20,035,348 6,131,930 3,899,225
Expressed as $/kWh
37 Production $0.04066 $0.04312 $0.03981 $0.04026 $0.03769 $0.03828 $0.03734 $0.03224
38 Transmission $0.00989 $0.01140 $0.00927 $0.00958 $0.00818 $0.00857 $0.00767 $0.00437
39 Distribution $0.02214 $0.03015 $0.02693 $0.02059 $0.00611 $0.00096 $0.03892 $0.20734
40 Common $0.01710 $0.02449 $0.01930 $0.01228 $0.00845 $0.00745 $0.01760 $0.04823
41 Total Uniform Melded Rates $0.08979 $0.10916 $0.09531 $0.08270 $0.06043 $0.05526 $0.10153 $0.29218
42 Revenue to Cost Ratio at Proposed Rates 1.00 0.94 1.15 1.05 0.99 1.02 0.97 1.00
43 Current Revenue to Proposed Cost Ratio 0.93 0.87 1.07 0.97 0.92 0.96 0.90 0.93
44 Target Revenue Increase 18,571,000 16,014,000 (2,511,000)1,621,000 1,645,000 890,000 638,000 274,000
Exhibit No. 14
Case No. AVU-E-17-01
T. Knox, Avista
Schedule 3, p. 2 of 4
Sumcost AVISTA UTILITIES Idaho Jurisdiction
Scenario: AVU-E-17-01 Company Case Revenue to Cost By Classification Summary Electric Utility 06/09/17
Load Factor Peak Credit For the Twelve Months Ended December 31, 2016
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 Area 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 Schedule
1 Energy 81,602,941 30,328,970 11,155,245 18,477,459 9,630,304 9,993,684 1,642,061 375,218
2 Demand 135,017,624 57,183,030 20,433,259 33,095,991 10,243,225 9,144,227 3,445,939 1,471,953
3 Customer 29,962,435 21,479,000 5,723,496 496,550 72,472 7,088 406,000 1,777,829
4 Total Current Rate Revenue 246,583,000 108,991,000 37,312,000 52,070,000 19,946,000 19,145,000 5,494,000 3,625,000
Expressed as Unit Cost
5 Energy $/kWh $0.02763 $0.02649 $0.03055 $0.02846 $0.02695 $0.02756 $0.02719 $0.02812
6 Demand $/kW/mo $10.95 $8.17 $13.62 $19.83 $14.06 $9.29 $8.48 $39.58
7 Customer $/Cust/mo $19.42 $17.07 $22.68 $36.36 $549.03 $590.70 $24.05 $993.76
Cost Classifications at Uniform Current Return
8 Energy 81,348,717 31,693,170 10,105,101 17,937,603 9,715,621 9,856,422 1,671,453 369,346
9 Demand 134,893,230 62,089,071 17,122,054 31,342,856 10,398,396 8,948,960 3,571,295 1,420,599
10 Customer 30,341,053 22,522,398 5,133,601 479,346 72,761 7,039 414,318 1,711,590
11 Total Uniform Current Cost 246,583,000 116,304,639 32,360,756 49,759,805 20,186,778 18,812,421 5,657,066 3,501,536
Expressed as Unit Cost
12 Energy $/kWh $0.02755 $0.02768 $0.02768 $0.02763 $0.02719 $0.02718 $0.02768 $0.02768
13 Demand $/kW/mo $10.94 $8.87 $11.41 $18.78 $14.28 $9.09 $8.79 $38.20
14 Customer $/Cust/mo $19.66 $17.90 $20.34 $35.10 $551.22 $586.58 $24.55 $956.73
15 Revenue to Cost Ratio at Current Rates 1.00 0.94 1.15 1.05 0.99 1.02 0.97 1.04
Cost Classifications at Proposed Return by Schedule
16 Energy 85,798,968 31,909,367 11,723,858 19,423,377 10,123,179 10,504,621 1,726,413 388,154
17 Demand 147,662,622 62,866,869 22,226,236 36,167,929 11,139,679 9,871,107 3,805,714 1,585,089
18 Customer 31,692,410 22,687,764 6,042,906 526,695 74,142 7,273 429,873 1,923,757
19 Total Proposed Rate Revenue 265,154,000 117,464,000 39,993,000 56,118,000 21,337,000 20,383,000 5,962,000 3,897,000
Expressed as Unit Cost
20 Energy $/kWh $0.02905 $0.02787 $0.03211 $0.02992 $0.02833 $0.02897 $0.02859 $0.02909
21 Demand $/kW/mo $11.98 $8.98 $14.81 $21.67 $15.30 $10.03 $9.36 $42.62
22 Customer $/Cust/mo $20.54 $18.03 $23.95 $38.57 $561.68 $606.05 $25.47 $1,075.33
Cost Classifications at Uniform Requested Return
23 Energy 85,514,322 33,316,075 10,622,551 18,856,130 10,213,127 10,361,138 1,757,043 388,260
24 Demand 147,497,955 67,925,783 18,753,707 34,325,844 11,303,270 9,666,990 3,936,346 1,586,015
25 Customer 32,141,723 23,763,675 5,424,270 508,618 74,447 7,221 438,541 1,924,951
26 Total Uniform Cost 265,154,000 125,005,533 34,800,528 53,690,592 21,590,844 20,035,348 6,131,930 3,899,225
Expressed as Unit Cost
27 Energy $/kWh $0.02896 $0.02909 $0.02909 $0.02905 $0.02859 $0.02858 $0.02909 $0.02909
28 Demand $/kW/mo $11.96 $9.70 $12.50 $20.57 $15.52 $9.82 $9.68 $42.65
29 Customer $/Cust/mo $20.83 $18.89 $21.49 $37.24 $563.99 $601.74 $25.98 $1,075.99
30 Revenue to Cost Ratio at Proposed Rates 1.00 0.94 1.15 1.05 0.99 1.02 0.97 1.00
31 Current Revenue to Proposed Cost Ratio 0.93 0.87 1.07 0.97 0.92 0.96 0.90 0.93
32 Annual Consumption (mWh's)2,953,031 1,145,126 365,114 649,193 357,288 362,573 60,392 13,345
33 Estimated Annual Billing Demand (kW)12,328,719 7,002,866 1,500,584 1,668,724 728,287 984,630 406,438 37,190
34 Monthly Average Number of Customers 128,591 104,855 21,031 1,138 11 1 1,407 149
Exhibit No. 14
Case No. AVU-E-17-01
T. Knox, Avista
Schedule 3, p. 3 of 4
Sumcost AVISTA UTILITIES Idaho Jurisdiction
Scenario: AVU-E-17-01 Company Case Customer Cost Analysis Electric Utility 06/09/17
Load Factor Peak Credit For the Twelve Months Ended December 31, 2016
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 Area 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 53,388,000 43,596,354 8,744,023 462,796 0 0 584,827 0
2 Services Accum. Depr.(24,233,000)(19,788,538)(3,968,943)(210,065)0 0 (265,455)0
3 Total Services 29,155,000 23,807,816 4,775,081 252,731 0 0 319,372 0
4 Meters 22,603,000 14,525,276 5,972,269 1,324,309 26,468 4,504 750,174 0
5 Meters Accum. Depr.(8,495,000)(5,459,108)(2,244,588)(497,722)(9,948)(1,693)(281,942)0
6 Total Meters 14,108,000 9,066,168 3,727,681 826,587 16,521 2,811 468,232 0
7 Total Rate Base 43,263,000 32,873,984 8,502,762 1,079,318 16,521 2,811 787,604 0
8 Return on Rate Base @ 7.81%3,378,831 2,567,451 664,064 84,295 1,290 220 61,512 0
9 Tax Benefit of Interest (433,062)(329,068)(85,113)(10,804)(165)(28)(7,884)0
10 Revenue Conversion Factor 0.612771 0.612771 0.612771 0.612771 0.612771 0.612771 0.612771 0.612771
11 Rate Base Revenue Requirement 4,807,290 3,652,885 944,808 119,931 1,836 312 87,517 0
Expenses
12 Services Depr Exp 1,437,000 1,173,446 235,356 12,457 0 0 15,741 0
13 Meters Depr Exp 1,722,000 1,106,602 454,995 100,892 2,016 343 57,152 0
14 Services Operations Exp 326,000 266,210 53,393 2,826 0 0 3,571 0
15 Meters Operating Exp 410,000 263,477 108,332 24,022 480 82 13,608 0
16 Meters Maintenance Exp 9,000 5,784 2,378 527 11 2 299 0
17 Meter Reading 379,000 275,057 55,168 2,985 38,592 3,508 3,690 0
18 Billing 3,397,000 2,768,573 555,286 30,050 1,847 168 37,139 3,936
19 Total Expenses 7,680,000 5,859,148 1,464,908 173,759 42,947 4,103 131,199 3,936
20 Revenue Conversion Factor 0.993979 0.993979 0.993979 0.993979 0.993979 0.993979 0.993979 0.993979
21 Expense Revenue Requirement 7,726,521 5,894,640 1,473,781 174,812 43,207 4,128 131,994 3,960
22 12,533,811 9,547,525 2,418,590 294,743 45,043 4,440 219,511 3,960
23 Total Customer Bills 1,543,093 1,258,258 252,366 13,657 132 12 16,879 1,789
24 Average Unit Cost per Month $8.12 $7.59 $9.58 $21.58 $341.23 $370.01 $13.00 $2.21
25 Total Customer Related Cost 32,141,723 23,763,675 5,424,270 508,618 74,447 7,221 438,541 1,924,951
26 Customer Related Unit Cost per Month $20.83 $18.89 $21.49 $37.24 $563.99 $601.74 $25.98 $1,075.99
27 Total Distribution Demand Related Cost 60,647,087 29,106,657 8,692,885 15,834,303 2,612,045 429,745 2,558,982 1,412,471
28 Dist Demand Related Unit Cost per Month $39.30 $23.13 $34.45 $1,159.43 $19,788.22 $35,812.07 $151.61 $789.53
29 Total Distribution Unit Cost per Month $60.13 $42.02 $55.94 $1,196.67 $20,352.21 $36,413.81 $177.59 $1,865.52
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. 14
Case No. AVU-E-17-01
T. Knox, Avista
Schedule 3, p. 4 of 4