20210129Knox Exhibit 16 Schedules 1-3.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-21-01
OF AVISTA CORPORATION FOR THE )
AUTHORITY TO INCREASE ITS RATES )
AND CHARGES FOR ELECTRIC SERVICE ) EXHIBIT NO. 16
TO ELECTRIC CUSTOMERS IN THE )
STATE OF IDAHO ) TARA L. KNOX

FOR AVISTA CORPORATION

(ELECTRIC)
AVISTA UTILITIES
AVERAGE PRODUCTION AND TRANSMISSION COST
IDAHO ELECTRIC
TWELVE MONTHS ENDED DECEMBER 31, 2019
2021 and 2022 Pro Forma Study
Line Column Description of Adjustment (000's)Revenue Expense Plant
Accumulated
Depreciation
Deferred
Debits/Credits
Accumulated
Deferred Tax
1 1.00 Per Results Report 53,368 162,832 788,042 (283,689) (3,353) (102,386)
2 1.01 Deferred FIT Rate Base - - - - - (3,020)
3 1.02 Deferred Debits, Credits & Reg Amortizations - (142) - - (63) -
5 1.03 Working Capital - - - - - -
4 1.04 Restate Capital 2019 EOP - 473 11,398 (8,201) - (531)
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 - (7,305) - - - -
13 2.08 Miscellaneous Restating - - - - - -
14 2.09 Restate Incentives - - - - - -
15 2.10 ID PCA - 7,886 - - - -
16 2.11 Nez Perce Settlement Adjustment - (35) - - - -
17 2.12 Colstrip / CS2 Maintenance - 908 - - - -
18 2.13 Restate Debt Interest - - - - - -
19 3.00P Pro Forma Power Supply (16,502) (20,203) - - - -
20 3.00T Pro Forma Transmission Rev/Exp (765) (234) - - - -
21 3.01 Pro Forma Labor Non-Exec - 614 - - - -
22 3.02 Pro Forma Labor Exec - - - - - -
23 3.03 Pro Forma Employee Benefits - (38) - - - -
24 3.04 Pro Forma IS/IT Costs - - - - - -
25 3.05 Pro Forma Property Tax - 478 - - - -
26 3.06 Pro Forma Insurance Expense - - - - - -
27 3.07 Pro Forma ARAM DFIT - - - - - -
28 3.08 Planned Capital Add 2020 EOP - 1,573 28,938 (14,788) - (44)
29 3.09 Planned Capital Add 08.2021 EOP - 630 12,623 (9,350) - 96
30 3.10 Planned Capital Add 08.2022 AMA - (66) 27,647 (7,655) - (105)
31 3.11 Pro Forma O&M Offsets - (9) - - - -
32 3.12 Pro Forma Fee Free Amortization - - - - - -
33 3.13 Restate 2019 ADFIT - - - - - (8,612)
34 3.14 Pro Forma Colstrip Amortization - 3 5,452 - - -
35 Rate Year September 1, 2021 - August 31, 2022 36,101 147,365 874,100 (323,682) (3,416) (114,602)
36 22.01 Planned Capital Add 08.2022 EOP - 1,080 19,995 (8,200) - (302)
37 22.02 Planned Capital Add 08.2023 AMA - (119) 25,715 (8,534) - (175)
38 22.03 Pro Forma Property Tax - 515 - - - -
39 22.04 Pro Forma Labor Non-Exec - 291 - - - -
40 22.06 PF Colstrip / CS2 Maintenance - 379 - - - -
41 22.08 Pro Forma Wildfire Expenses - 37 - - - -
42 Rate Year September 1, 2022 - August 31, 2023 36,101 149,548 919,809 (340,416) (3,416) (115,079)
Production / Transmission
Exhibit No. 16
Case No. AVU-E-21-01
T. Knox, Avista
Schedule 1, p. 1 of 2
AVISTA UTILITIES
AVERAGE PRODUCTION AND TRANSMISSION COST
IDAHO ELECTRIC
TWELVE MONTHS ENDED DECEMBER 31, 2019
Rate Year 09.2021 - 08.2022 Rate Year 09.2022 - 08.2023
Line ($000's) Debt Cost ($000's) Debt Cost
1 Prod/Trans Pro Forma Rate Base 432,399 460,898
2 Cost of Capital Proposed Rate of Return 7.300% 2.35% 7.30% 2.35%
3 Rate Base Net Operating Income Requirement $31,565 $33,646
4 Tax Effect Net Operating Income Requirement ($2,134) ($2,275)
(Rate Base x Debt Cost x -21%)
5 Net Expense Net Operating Income Requirement 111,264 113,447
(Expense - Revenue)
6 Tax Effect Net Operating Income Requirement ($23,365) ($23,824)
(Net Expense x -.21%)
7 Total Prod/Trans Net Operating Income Requirement $117,330 $120,994
8 1 - Tax Rate Conversion Factor (Excl. Rev. Rel. Exp.) 0.79 0.79
9 Prod/Trans Revenue Requirement $148,519 $153,157
10 Test Year WA Normalized Retail Load MWh 2,966,810 2,966,810
11 Prod/Trans Rev Requirement per kWh 0.05006$ 0.05162$
12 Cost of Service Energy Classified Production/Transmission Costs $77,086 $77,086 Company Case at Unity AVU-E-21-01
13 Cost of Service Total Production/Transmission Costs $150,038 $150,038 Company Case at Unity AVU-E-21-01
14 Load Change Adjustment Rate per kWh (Line 11 * Line 12 / Line 13)0.02572$ 0.02652$
2021 and 2022 Pro Forma Study
Calculation of Load Change Adjustment Rate
Proposed Production and Transmission Revenue Requirement
Exhibit No. 16
Case No. AVU-E-21-01
T. Knox, Avista
Schedule 1, p. 2 of 2
Exhibit No. 16
Case No. AVU-E-21-01
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
25
Exhibit No. 16
Case No. AVU-E-21-01
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. 16
Case No. AVU-E-21-01
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 8
contain both capacity and energy components as they provide energy throughout the year as well 9
as capacity during system peaks. The peak credit ratio (the proportion of total production cost that 10
is capacity related) is determined using the electric system load factor inherent in the test year. 11
The share of production costs attributable to demand is one minus the load factor1 which is 34.13% 12
for the 2019 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
22
1 1 – (average MW÷ peak MW).
Exhibit No. 16
Case No. AVU-E-21-01
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 8
Street 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 18
be classified implicitly to demand and energy by the sum of production plant in service, then 19
allocated to rate schedules by coincident peak demand and energy consumption, respectively. At 20
this point in time, the Company’s demand side management investments in base rates have been 21
fully amortized except for some minor outstanding loan balances that will remain on the books 22
until satisfied. All current demand side management costs are managed through the Schedule 91 23
Public Purpose Tariff Rider balancing account which is not included in this cost study. 24
Exhibit No. 16
Case No. AVU-E-21-01
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
demand and customer within the four-factor allocator applied to them. The four-factor allocator 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. 16
Case No. AVU-E-21-01
T. Knox, Avista
Schedule 2, p. 6 of 9

consists of a 25% weighting of each of the following: 1) operating & maintenance expenses 1
excluding resource costs, labor expenses, and administrative and general expenses; 2) operating 2
and maintenance labor expenses excluding administrative and general labor expenses; 3) net 3
production, transmission, and distribution plant; and 4) number of customers. 4
Revenue Conversion Items 5
In this study, uncollectible accounts and commission fees have been classified as revenue-6
related and are allocated by pro forma revenue. These items vary with revenue and are included in 7
the calculation of the revenue conversion factor. Income tax expense items are allocated to 8
schedules by net income before income tax adjusted by interest expense. 9
For the functional summaries on pages 2 and 3 of the cost of service study, these items are 10
assigned to component cost categories. The revenue-related expense items have been reduced to a 11
percent of all other costs and loaded onto each cost category by that ratio. Similarly, income tax 12
items have been reduced to a percent of net income before tax then assigned to cost categories by 13
relative rate base (as is net income). 14
The following matrix outlines the methodology applied in the Company Base Case cost of 15
service study. 16
IPUC Case No. AVU-E-21-01 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 AMI/MDM Software D = Distribution Customer C01 All Customers unweighted
22 303 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
23 Intangible P/T/D/O Follows Related Plant S01/S02/C01/S23 Sum of Prod. Plant / Sum of Trans. Plant / All Cust. / Corp Cost Allocator
24 Production P = Production Follows Related Plant D01/E02 Coincident Peak Demand/Annual Generation Level Consumption
25 Transmission T = Transmission Follows Related Plant D01 Coincident Peak Demand (12CP)
26 Distribution D = Distribution Follows Related Plant D03/D04/D05/D06/D07/D08/C02/C04/C05 - See Related Plant
27 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
28 252 Customer Advances for Construction D = Distribution Customer S13 Sum of Account 369 Services Plant
29 282/190 Accumulated Deferred Income Tax P/T/D/O Per Functional Analysis S01/S02/S03/S04 Sums of Production / Transmission / Distribution / General Plant
30 Hydro Relicensing Related Settlements P = Production Demand/Energy by Load Factor Peak Credit D01/E02 Coincident Peak Demand/Annual Generation Level Consumption
31 Regultory Asset AFUDC P/T/D/G Demand/Energy/Customer as in related Plant S06 Sum of Production, Transmission, Distribution, and General Plant
32 Colstrip Deferred Amortization P = Production Demand/Energy by Load Factor Peak Credit D01/E02 Coincident Peak Demand/Annual Generation Level Consumption
33 Demand Side Management Investment DSM Demand/Energy by Load Factor Peak Credit S01 Sum of Production Plant
34 Working Capital P/T/D/G Demand/Energy/Customer as in related Plant S06 Sum of Production, Transmission, Distribution, and General Plant
Exhibit No. 16
Case No. AVU-E-21-01
T. Knox, Avista
Schedule 2, p. 7 of 9
IPUC Case No. AVU-E-21-01 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. 16
Case No. AVU-E-21-01
T. Knox, Avista
Schedule 2, p. 8 of 9
IPUC Case No. AVU-E-21-01 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
8 928 Intervenor Funding C = Customer Relations Customer C07/C08 Direct Assign to Residential and Small Commercial per IPUC Order
Depreciation & Amortization Expense
9 Intangible P/T/D/O Follows Related Plant S01/S02/C01/S23 Sum of Prod. Plant / Sum of Trans. Plant / All Cust. / Corp Cost Allocator
10 Production P = Production Demand/Energy by Peak Credit as in related Plant D01/E02 Coincident Peak Demand/Annual Generation Level Consumption
11 Transmission T = Transmission Demand D01 Coincident Peak Demand (12CP)
12 Distribution D = Distribution Demand/Customer as in related Plant D03/D04/D05/D06/D07/D08/C02/C04/C05 - See Related Plant
13 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 AFUDC Regulatory Deferral/Amortization P/T/D/G Demand/Energy/Customer as in related Plant S06 Sum of Production, Transmission, Distribution, and General Plant
22 FISERVE (Fee Free) Deferral/Amortization D = Distribution Customer C07 Direct Assign Residential
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. 16
Case No. AVU-E-21-01
T. Knox, Avista
Schedule 2, p. 9 of 9
Sumcost AVISTA UTILITIES Idaho Jurisdiction Filed
Scenario: AVU-E-21-01 Company Base Case Cost of Service Basic Summary Electric Utility 01/29/21
Load Factor Peak Credit For the Twelve Months Ended December 31, 2019
Transmission by Demand
(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 01 Sch 11-12 Sch 21-22 Sch 25 Sch 25P Sch 31-32 Sch 41-49
Plant In Service
1 Production Plant 520,389,000 218,009,144 68,106,556 108,986,679 53,086,894 61,076,540 9,622,574 1,500,614
2 Transmission Plant 326,847,000 150,467,273 42,918,674 68,140,630 29,784,469 30,290,300 4,841,524 404,129
3 Distribution Plant 656,851,000 343,933,575 98,972,601 136,380,070 20,945,469 3,050,218 23,621,054 29,948,013
4 Intangible Plant 104,175,000 56,003,260 14,835,493 16,749,189 6,871,630 7,063,588 1,992,600 659,242
5 General Plant 144,323,000 82,092,651 21,097,515 21,740,831 7,900,847 7,325,500 2,948,257 1,217,400
6 Total Plant In Service 1,752,585,000 850,505,903 245,930,839 351,997,399 118,589,308 108,806,145 43,026,008 33,729,398
Accum Depreciation
7 Production Plant (236,976,000)(99,277,531)(31,014,528)(49,630,617)(24,174,838)(27,813,182)(4,381,951)(683,353)
8 Transmission Plant (88,090,000)(40,553,109)(11,567,204)(18,364,887)(8,027,346)(8,163,675)(1,304,861)(108,919)
9 Distribution Plant (263,227,000)(141,573,294)(40,685,218)(52,221,683)(7,075,420)(826,795)(9,311,619)(11,532,971)
10 Intangible Plant (40,825,000)(22,802,737)(5,912,242)(6,267,232)(2,398,954)(2,329,942)(808,582)(305,311)
11 General Plant (55,835,000)(31,759,617)(8,162,107)(8,410,990)(3,056,642)(2,834,055)(1,140,608)(470,982)
12 Total Accumulated Depreciation (684,953,000)(335,966,288)(97,341,299)(134,895,408)(44,733,200)(41,967,649)(16,947,621)(13,101,536)
13 Net Plant 1,067,632,000 514,539,615 148,589,540 217,101,990 73,856,108 66,838,497 26,078,387 20,627,862
14 Accumulated Deferred FIT (219,885,000)(105,878,506)(30,777,247)(44,480,552)(15,139,031)(14,018,071)(5,394,962)(4,196,631)
15 Miscellaneous Rate Base 16,419,000 7,706,558 2,301,520 3,551,327 1,090,599 920,447 444,456 404,093
16 Total Rate Base 864,166,000 416,367,667 120,113,813 176,172,765 59,807,676 53,740,873 21,127,881 16,835,324
17 Revenue From Retail Rates 244,590,000 113,042,000 36,636,000 47,822,000 17,876,000 19,991,000 5,527,000 3,696,000
18 Other Operating Revenues 38,736,000 16,722,965 5,124,082 8,102,789 3,709,238 4,118,645 742,807 215,474
19 Total Revenues 283,326,000 129,764,965 41,760,082 55,924,789 21,585,238 24,109,645 6,269,807 3,911,474
Operating Expenses
20 Production Expenses 105,562,000 44,223,612 13,815,558 22,108,176 10,768,788 12,389,504 1,951,959 304,403
21 Transmission Expenses 11,562,000 5,322,682 1,518,220 2,410,430 1,053,606 1,071,500 171,266 14,296
22 Distribution Expenses 13,978,000 7,318,811 2,179,931 3,119,571 586,867 79,859 532,274 160,688
23 Customer Accounting Expenses 4,840,000 3,702,813 771,168 130,501 117,912 48,442 56,643 12,520
24 Customer Information Expenses 676,000 551,828 110,709 5,326 52 5 7,218 863
25 Sales Expenses 0 0 0 0 0 0 0 0
26 Admin & General Expenses 27,358,000 15,250,800 3,984,970 4,295,274 1,536,375 1,432,485 576,224 281,873
27 Total O&M Expenses 163,976,000 76,370,546 22,380,555 32,069,278 14,063,599 15,021,794 3,295,585 774,642
28 Taxes Other Than Income Taxes 12,555,000 5,713,611 1,712,159 2,621,056 1,015,111 1,030,113 283,790 179,161
29 Other Income Related Items (418,000)31,550 (60,388)(159,524)(100,870)(129,787)(6,944)7,963
Depreciation Expense
30 Production Plant Depreciation 13,895,000 5,821,101 1,818,525 2,910,073 1,417,483 1,630,816 256,934 40,068
31 Transmission Plant Depreciation 7,135,000 3,284,668 936,905 1,487,495 650,189 661,231 105,689 8,822
32 Distribution Plant Depreciation 17,782,000 9,414,763 2,828,795 3,503,000 524,911 64,016 636,681 809,834
33 General Plant Depreciation 7,952,000 4,523,193 1,162,444 1,197,890 435,326 403,625 162,445 67,077
34 Amortization Expense 13,395,000 6,545,563 1,874,917 2,616,559 929,468 890,721 312,573 225,200
35 Total Depreciation Expense 60,159,000 29,589,289 8,621,587 11,715,017 3,957,375 3,650,408 1,474,323 1,151,001
36 Income Tax 2,550,000 788,977 599,076 528,084 118,656 312,167 69,270 133,771
37 Total Operating Expenses 238,822,000 112,493,972 33,252,989 46,773,912 19,053,871 19,884,695 5,116,023 2,246,538
38 Net Income 44,504,000 17,270,992 8,507,093 9,150,877 2,531,367 4,224,950 1,153,784 1,664,936
39 Rate of Return 5.15%4.15%7.08%5.19%4.23%7.86%5.46%9.89%
40 Return Ratio 1.00 0.81 1.38 1.01 0.82 1.53 1.06 1.92
41 Interest Expense 20,308,000 9,784,688 2,822,688 4,140,080 1,405,487 1,262,917 496,508 395,632
42 Revenue Related Operating Expenses 1,176,000 543,511 176,148 229,930 85,949 96,118 26,574 17,771
Exhibit No. 16
Case No. AVU-E-21-01
T. Knox, Avista
Schedule 3, p. 1 of 4
Sumcost AVISTA UTILITIES Idaho Jurisdiction Filed
Scenario: AVU-E-21-01 Company Base Case Revenue to Cost by Functional Component Summary Electric Utility 01/29/21
Load Factor Peak Credit For the Twelve Months Ended December 31, 2019
Transmission by Demand
(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 01 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 110,630,031 45,177,900 15,098,134 23,146,910 11,023,260 13,774,106 2,056,311 353,411
2 Transmission 27,183,964 11,502,124 4,143,779 5,697,336 2,294,049 3,086,230 413,654 46,791
3 Distribution 57,909,065 30,278,911 9,942,776 10,923,868 1,779,538 320,926 1,991,238 2,671,808
4 Common 48,866,940 26,083,064 7,451,311 8,053,886 2,779,153 2,809,738 1,065,797 623,990
5 Total Current Rate Revenue 244,590,000 113,042,000 36,636,000 47,822,000 17,876,000 19,991,000 5,527,000 3,696,000
Expressed as $/kWh
6 Production $0.03729 $0.03843 $0.03907 $0.03725 $0.03420 $0.03534 $0.03409 $0.03198
7 Transmission $0.00916 $0.00978 $0.01072 $0.00917 $0.00712 $0.00792 $0.00686 $0.00423
8 Distribution $0.01952 $0.02576 $0.02573 $0.01758 $0.00552 $0.00082 $0.03301 $0.24174
9 Common $0.01647 $0.02219 $0.01928 $0.01296 $0.00862 $0.00721 $0.01767 $0.05646
10 Total Current Melded Rates $0.08244 $0.09616 $0.09481 $0.07695 $0.05546 $0.05129 $0.09162 $0.33440
Functional Cost Components at Uniform Current Return
11 Production 110,408,115 46,253,819 14,449,799 23,123,113 11,263,159 12,958,279 2,041,569 318,377
12 Transmission 27,228,879 12,535,086 3,575,457 5,676,641 2,481,276 2,523,416 403,336 33,667
13 Distribution 57,934,108 32,091,701 8,941,707 10,890,782 1,894,329 265,201 1,951,822 1,898,567
14 Common 49,018,897 26,795,001 7,090,691 8,044,725 2,846,683 2,625,406 1,057,284 559,107
15 Total Uniform Current Cost 244,590,000 117,675,607 34,057,654 47,735,261 18,485,447 18,372,302 5,454,012 2,809,718
Expressed as $/kWh
16 Production $0.03721 $0.03935 $0.03740 $0.03721 $0.03495 $0.03325 $0.03384 $0.02881
17 Transmission $0.00918 $0.01066 $0.00925 $0.00913 $0.00770 $0.00647 $0.00669 $0.00305
18 Distribution $0.01953 $0.02730 $0.02314 $0.01752 $0.00588 $0.00068 $0.03236 $0.17178
19 Common $0.01652 $0.02279 $0.01835 $0.01294 $0.00883 $0.00674 $0.01753 $0.05059
20 Total Current Uniform Melded Rates $0.08244 $0.10011 $0.08814 $0.07681 $0.05736 $0.04714 $0.09041 $0.25422
21 Revenue to Cost Ratio at Current Rates 1.00 0.96 1.08 1.00 0.97 1.09 1.01 1.32
Functional Cost Components at Proposed Return by Schedule
22 Production 117,414,966 47,838,313 16,031,638 24,476,293 11,735,810 14,795,281 2,169,434 368,198
23 Transmission 33,056,662 14,055,742 4,961,911 6,853,242 2,850,038 3,790,590 492,809 52,329
24 Distribution 66,719,121 34,760,550 11,383,920 12,771,821 2,120,428 390,667 2,293,639 2,998,096
25 Common 52,182,251 27,843,395 7,970,530 8,565,645 2,979,724 3,040,462 1,131,118 651,377
26 Total Proposed Rate Revenue 269,373,000 124,498,000 40,348,000 52,667,000 19,686,000 22,017,000 6,087,000 4,070,000
Expressed as $/kWh
27 Production $0.03958 $0.04070 $0.04149 $0.03938 $0.03641 $0.03796 $0.03596 $0.03331
28 Transmission $0.01114 $0.01196 $0.01284 $0.01103 $0.00884 $0.00973 $0.00817 $0.00473
29 Distribution $0.02249 $0.02957 $0.02946 $0.02055 $0.00658 $0.00100 $0.03802 $0.27126
30 Common $0.01759 $0.02369 $0.02063 $0.01378 $0.00925 $0.00780 $0.01875 $0.05893
31 Total Proposed Melded Rates $0.09080 $0.10591 $0.10442 $0.08475 $0.06108 $0.05649 $0.10091 $0.36824
Functional Cost Components at Uniform Requested Return
32 Production 117,027,243 49,026,803 15,316,086 24,509,378 11,938,402 13,735,146 2,163,965 337,464
33 Transmission 33,010,646 15,196,780 4,334,668 6,882,016 3,008,149 3,059,237 488,981 40,816
34 Distribution 66,994,288 36,763,007 10,279,064 12,817,821 2,217,368 318,254 2,279,015 2,319,758
35 Common 52,340,823 28,629,821 7,572,523 8,578,382 3,036,751 2,800,930 1,127,959 594,457
36 Total Uniform Cost 269,373,000 129,616,411 37,502,341 52,787,597 20,200,670 19,913,567 6,059,919 3,292,495
Expressed as $/kWh
37 Production $0.03945 $0.04171 $0.03964 $0.03944 $0.03704 $0.03524 $0.03587 $0.03053
38 Transmission $0.01113 $0.01293 $0.01122 $0.01107 $0.00933 $0.00785 $0.00811 $0.00369
39 Distribution $0.02258 $0.03127 $0.02660 $0.02062 $0.00688 $0.00082 $0.03778 $0.20989
40 Common $0.01764 $0.02436 $0.01960 $0.01380 $0.00942 $0.00719 $0.01870 $0.05378
41 Total Uniform Melded Rates $0.09080 $0.11026 $0.09706 $0.08494 $0.06268 $0.05109 $0.10046 $0.29790
42 Revenue to Cost Ratio at Proposed Rates 1.00 0.96 1.08 1.00 0.97 1.11 1.00 1.24
43 Current Revenue to Proposed Cost Ratio 0.91 0.87 0.98 0.91 0.88 1.00 0.91 1.12
44 Target Revenue Increase 24,783,000 16,574,000 866,000 4,966,000 2,325,000 (77,000)533,000 (404,000)
Exhibit No. 16
Case No. AVU-E-21-01
T. Knox, Avista
Schedule 3, p. 2 of 4
Sumcost AVISTA UTILITIES Idaho Jurisdiction Filed
Scenario: AVU-E-21-01 Company Base Case Revenue to Cost By Classification Summary Electric Utility 01/29/21
Load Factor Peak Credit For the Twelve Months Ended December 31, 2019
Transmission by Demand
(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 01 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 83,681,704 32,366,378 11,393,532 17,526,821 8,784,335 11,550,448 1,713,647 346,544
2 Demand 132,568,360 60,637,538 20,404,549 29,913,490 8,972,532 8,428,379 3,454,025 757,848
3 Customer 28,339,935 20,038,084 4,837,919 381,690 119,133 12,173 359,328 2,591,608
4 Total Current Rate Revenue 244,590,000 113,042,000 36,636,000 47,822,000 17,876,000 19,991,000 5,527,000 3,696,000
Expressed as Unit Cost
5 Energy $/kWh $0.02821 $0.02753 $0.02949 $0.02820 $0.02726 $0.02964 $0.02841 $0.03135
6 Demand $/kW/mo $10.28 $7.95 $12.50 $18.87 $12.58 $9.34 $8.58 $24.52
7 Customer $/Cust/mo $17.56 $15.21 $18.30 $30.01 $960.75 $1,014.41 $20.85 $1,258.06
Cost Classifications at Uniform Current Return
8 Energy 83,402,593 33,150,107 10,896,621 17,508,508 8,978,706 10,855,805 1,701,163 311,685
9 Demand 133,207,119 63,915,816 18,562,585 29,845,462 9,386,661 7,504,609 3,396,370 595,616
10 Customer 27,980,288 20,609,684 4,598,448 381,291 120,080 11,888 356,479 1,902,417
11 Total Uniform Current Cost 244,590,000 117,675,607 34,057,654 47,735,261 18,485,447 18,372,302 5,454,012 2,809,718
Expressed as Unit Cost
12 Energy $/kWh $0.02811 $0.02820 $0.02820 $0.02817 $0.02786 $0.02785 $0.02820 $0.02820
13 Demand $/kW/mo $10.33 $8.38 $11.37 $18.83 $13.16 $8.32 $8.43 $19.27
14 Customer $/Cust/mo $17.33 $15.64 $17.39 $29.98 $968.39 $990.68 $20.68 $923.50
15 Revenue to Cost Ratio at Current Rates 1.00 0.96 1.08 1.00 0.97 1.09 1.01 1.32
Cost Classifications at Proposed Return by Schedule
16 Energy 88,915,463 34,304,286 12,109,005 18,549,878 9,361,654 12,419,933 1,809,451 361,257
17 Demand 150,021,400 68,742,313 23,056,288 33,713,192 10,202,398 9,584,537 3,896,362 826,310
18 Customer 30,436,137 21,451,401 5,182,707 403,930 121,948 12,530 381,188 2,882,434
19 Total Proposed Rate Revenue 269,373,000 124,498,000 40,348,000 52,667,000 19,686,000 22,017,000 6,087,000 4,070,000
Expressed as Unit Cost
20 Energy $/kWh $0.02997 $0.02918 $0.03134 $0.02985 $0.02905 $0.03187 $0.03000 $0.03269
21 Demand $/kW/mo $11.64 $9.01 $14.12 $21.27 $14.30 $10.62 $9.67 $26.74
22 Customer $/Cust/mo $18.85 $16.28 $19.60 $31.76 $983.45 $1,044.13 $22.11 $1,399.24
Cost Classifications at Uniform Requested Return
23 Energy 88,484,495 35,170,015 11,560,576 18,575,339 9,525,798 11,517,272 1,804,818 330,677
24 Demand 150,689,939 72,363,591 21,023,357 33,807,773 10,552,125 8,384,135 3,874,970 683,989
25 Customer 30,198,565 22,082,806 4,918,408 404,484 122,748 12,159 380,131 2,277,829
26 Total Uniform Cost 269,373,000 129,616,411 37,502,341 52,787,597 20,200,670 19,913,567 6,059,919 3,292,495
Expressed as Unit Cost
27 Energy $/kWh $0.02982 $0.02992 $0.02992 $0.02989 $0.02956 $0.02955 $0.02992 $0.02992
28 Demand $/kW/mo $11.69 $9.49 $12.88 $21.33 $14.79 $9.29 $9.62 $22.13
29 Customer $/Cust/mo $18.71 $16.76 $18.60 $31.80 $989.90 $1,013.29 $22.05 $1,105.74
30 Revenue to Cost Ratio at Proposed Rates 1.00 0.96 1.08 1.00 0.97 1.11 1.00 1.24
31 Current Revenue to Proposed Cost Ratio 0.91 0.87 0.98 0.91 0.88 1.00 0.91 1.12
32 Annual Consumption (mWh's)2,966,810 1,175,515 386,398 621,476 322,296 389,749 60,324 11,052
33 Estimated Annual Billing Demand (kW)12,893,861 7,627,031 1,632,488 1,585,042 713,235 902,420 402,738 30,907
34 Monthly Average Number of Customers 134,526 109,816 22,031 1,060 10 1 1,436 172
Exhibit No. 16
Case No. AVU-E-21-01
T. Knox, Avista
Schedule 3, p. 3 of 4
Sumcost AVISTA UTILITIES Idaho Jurisdiction Filed
Scenario: AVU-E-21-01 Company Base Case Customer Cost Analysis Electric Utility 01/29/21
Load Factor Peak Credit For the Twelve Months Ended December 31, 2019
Transmission by Demand
(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 01 Sch 11-12 Sch 21-22 Sch 25 Sch 25P Sch 31-32 Sch 41-49
Rate Base
1 Services 60,394,000 49,376,424 9,905,979 465,741 0 0 645,856 0
2 Services Accum. Depr.(30,433,000)(24,881,159)(4,991,699)(234,691)0 0 (325,452)0
3 Total Services 29,961,000 24,495,265 4,914,280 231,051 0 0 320,404 0
4 Meters 23,136,000 15,022,919 6,057,985 1,278,780 29,078 4,456 742,783 0
5 Meters Accum. Depr.(15,088,000)(9,797,104)(3,950,677)(833,949)(18,963)(2,906)(484,401)0
6 Total Meters 8,048,000 5,225,815 2,107,307 444,832 10,115 1,550 258,382 0
7 Total Rate Base 38,009,000 29,721,080 7,021,588 675,882 10,115 1,550 578,786 0
8 Return on Rate Base @ 7.30%2,774,652 2,169,635 512,575 49,339 738 113 42,251 0
9 Tax Benefit of Interest (312,626)(244,457)(57,753)(5,559)(83)(13)(4,761)0
10 Revenue Conversion Factor 0.749719 0.749719 0.749719 0.749719 0.749719 0.749719 0.749719 0.749719
11 Rate Base Revenue Requirement 3,283,930 2,567,864 606,656 58,395 874 134 50,006 0
Expenses
12 Services Depr Exp 1,341,000 1,096,364 219,954 10,341 0 0 14,341 0
13 Meters Depr Exp 2,009,000 1,304,506 526,041 111,042 2,525 387 64,499 0
14 Services Operations Exp 321,000 262,441 52,651 2,475 0 0 3,433 0
15 Meters Operating Exp 410,000 266,226 107,355 22,662 515 79 13,163 0
16 Meters Maintenance Exp 9,000 5,844 2,357 497 11 2 289 0
17 Meter Reading 398,000 255,041 51,167 2,461 78,407 7,588 3,336 0
18 Billing 3,805,000 3,104,520 622,834 29,962 2,027 196 40,608 4,853
19 Total Expenses 8,293,000 6,294,941 1,582,360 179,441 83,485 8,251 139,668 4,853
20 Revenue Conversion Factor 0.995006 0.995006 0.995006 0.995006 0.995006 0.995006 0.995006 0.995006
21 Expense Revenue Requirement 8,334,623 6,326,536 1,590,302 180,342 83,904 8,293 140,369 4,877
22 11,618,553 8,894,400 2,196,958 238,737 84,778 8,427 190,376 4,877
23 Total Customer Bills 1,614,317 1,317,789 264,377 12,718 124 12 17,237 2,060
24 Average Unit Cost per Month $7.20 $6.75 $8.31 $18.77 $683.69 $702.23 $11.04 $2.37
25 Total Customer Related Cost 30,198,565 22,082,806 4,918,408 404,484 122,748 12,159 380,131 2,277,829
26 Customer Related Unit Cost per Month $18.71 $16.76 $18.60 $31.80 $989.90 $1,013.29 $22.05 $1,105.74
27 Total Distribution Demand Related Cost 63,553,859 32,170,224 9,556,936 15,590,948 2,659,732 384,050 2,567,289 624,681
28 Dist Demand Related Unit Cost per Month $39.37 $24.41 $36.15 $1,225.90 $21,449.45 $32,004.20 $148.94 $303.24
29 Total Distribution Unit Cost per Month $58.08 $41.17 $54.75 $1,257.70 $22,439.35 $33,017.49 $170.99 $1,408.99
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. 16
Case No. AVU-E-21-01
T. Knox, Avista
Schedule 3, p. 4 of 4