20230201Garbarino Exhibit 16 Schedule 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]
[e-mail]

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION ) CASE NO. AVU-E-23-01
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 ) MARCUS J. GARBARINO

FOR AVISTA CORPORATION

(ELECTRIC ONLY)

AVISTA UTILITIES
AVERAGE PRODUCTION AND TRANSMISSION COST
IDAHO ELECTRIC
TWELVE MONTHS ENDED JUNE 30, 2022
Line Column Description of Adjustment (000's)Revenue Expense Plant Acc Depreciation Deferred D/C Deferred Tax
1 1.00 Per Results Report 85,095 203,986 867,124 (327,054) (22,221) (98,757)
2 1.01 Accumulated Deferred FIT Rate Base - -- - - (1,420)
3 1.02 Deferred Debits, Credits & Reg Amortizations - 56 - - - -
5 1.03 Working Capital - -- - - -
4 1.04 Restate Capital 06.2022 EOP - -30,515 (8,791) - (546)
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 - (6,820)- - - -
13 2.08 Miscellaneous Restating - -- - - -
14 2.09 Restate Incentives - -- - - -
15 2.10 ID PCA - (1,702)- - - -
16 2.11 Nez Perce Settlement Adjustment - (34)- - - -
17 2.12 Colstrip / CS2 Maintenance - (130)- - - -
18 2.13 Restate Debt Interes - -- - - -
19 3.00P Pro Forma Power Supply 2,241 1,899 - - - -
20 3.00T Pro Forma Transmission Rev/Exp 1,792 -- - - -
21 3.01 Pro Forma Labor Non-Exec - 980 - - - -
22 3.02 Pro Forma Labor Exec - -- - - -
23 3.03 Pro Forma Employee Benefits - (46)- - - -
24 3.04 Pro Forma IS/IT Costs - -- - - -
25 3.05 Pro Forma Property Tax - (282)- - - -
26 3.06 Pro Forma Insurance Expense - -- - - -
27 3.07 Pro Forma EDIT (RSGM)- -- - - -
28 3.08 Planned Capital Add 12.2022 EOP - 463 16,673 (6,095) - (103)
29 3.09 Planned Capital Add 08.2023 EOP - 796 15,280 (13,532) - (293)
30 3.10 Depreciation Study - 198 - - - -
31 3.11 Planned Capital Add 08.2024 AMA - 697 16,454 (9,885) - (102)
32 3.12 Pro Forma Revenue & O&M Offsets - (14)- - - -
33 3.13 Pro Forma Fee Free Amortization - -- - - -
34 3.14 Pro Forma Regulatory Amortizations - -- - - -
35 3.15 Pro Forma Misc. O&M Expense - 1,762 - - - -
36 3.16 Pro Forma Wildfire Plan Expenses - (12)- - - -
37 3.17 Pro Forma Colstrip Capital Add & Amortizati - -2,450 - - -
38 Rate Year September 1, 2023 - August 31, 2024 89,128 201,798 948,496 (365,357) (22,221) (101,221)
39 24.00P Pro Forma Power Supply 2,753 7,305 - - - -
40 24.00T Pro Forma Transmission Rev/Exp (335) -- - - -
41 24.01 Planned Capital Add 08.2024 EOP - -12,014 (10,529) - (12)
42 24.02 Planned Capital Add 08.2025 AMA - 612 14,258 (9,430) - 1
43 24.03 Pro Forma Property Tax - 454 - - - -
44 24.04 Pro Forma Labor Non-Exec - 391 - - - -
45 24.05 Pro Forma Fee Free Amortization - -- - - -
46 24.06 Pro Forma Revenue & O&M Offsets - (93)- - - -
47 24.07 Pro Forma Misc. O&M Expense - 812 - - - -
48 24.08 Pro Forma Employee Benefits - 94 - - - -
49 24.09 Pro Forma Colstrip/CS2 Maintenance - 246 - - - -
50 Rate Year September 1, 2024 - August 31, 2025 91,546 211,619 974,768 (385,316) (22,221) (101,232)
Production / Transmission
2023 ID Electric RR Model / PCA LCAR Calc-23-24
Exhibit No. 16 Case No. AVU-E-23-01
M. Garbarino, AvistaSchedule 1, Page 1 of 2
AVISTA UTILITIES
AVERAGE PRODUCTION AND TRANSMISSION COST
IDAHO ELECTRIC
TWELVE MONTHS ENDED JUNE 30, 2022
Twelve Months Ended June 30, 2022 Pro Forma
Rate Year 09.2023 - 08.2024 Rate Year 09.2024 - 08.2025
Line ($000's) Debt Cost ($000's) Debt Cost
1 Prod/Trans Pro Forma Rate Base 459,697 465,999
2 Cost of Capital Proposed Rate of Return 7.59% 2.46%7.59%2.46%
3 Rate Base Net Operating Income Requirement $34,891 $35,369
4 Tax Effect Net Operating Income Requirement ($2,375)($2,407)
(Rate Base x Debt Cost x -21%)
5 Net Expense Net Operating Income Requirement 112,670 120,073
(Expense - Revenue)
6 Tax Effect Net Operating Income Requirement ($23,661)($25,215)
(Net Expense x -21%)
7 Total Prod/Trans Net Operating Income Requirement $121,525 $127,820
8 1 - Tax Rate Conversion Factor (Excl. Rev. Rel. Exp.)0.79 0.79
9 Prod/Trans Revenue Requirement $153,829 $161,797
10 Test Year WA Normalized Retail Load MWh 3,082,930 3,082,930
11 Prod/Trans Rev Requirement per kWh 0.04990$ 0.05248$
12 Cost of Service Energy Classified Production/Transmission Costs $78,973 $78,973 Company Case at Unity AVU-E-23-01
13 Cost of Service Total Production/Transmission Costs $156,177 $156,177 Company Case at Unity AVU-E-23-01
14 Load Change Adjustment Rate per kWh (Line 11 * Line 12 / Line 13)0.02523$ 0.02654$
Proposed Production and Transmission Revenue Requirement
Calculation of Load Change Adjustment Rate
2023 ID Electric RR Model/ PCA LCAR Calc-23-24
Exhibit No. 16 Case No. AVU-E-23-01
M. Garbarino, AvistaSchedule 1, Page 2 of 2
Exhibit No. 16
Case No. AVU-E-23-01
M. Garbarino, 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-23-01
M. Garbarino, Avista
Schedule 2, p. 2 of 9

1
2
* 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-23-01
M. Garbarino, 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 year 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 36.35% 12
for the twelve-months-ended June 30, 2022 test year. The same classification ratio is applied to all 13
production costs. 14
Production Allocation 15
Production demand-related costs are allocated to the customer classes by class contribution 16
to the average of the twelve monthly system coincident peak loads. Although the Company is 17
usually a winter peaking utility, it experiences high summer peaks and careful management of 18
capacity requirements is required throughout the year. The use of the average of twelve monthly 19
peaks recognizes that customer capacity needs are not limited to the heating season. Energy-20
related costs are allocated to class by pro forma annual kilowatt-hour sales adjusted for losses to 21
reflect generation level consumption. 22
23

1 1 – (average MW÷ peak MW).
Exhibit No. 16
Case No. AVU-E-23-01
M. Garbarino, 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-23-01
M. Garbarino, 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-23-01
M. Garbarino, 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-23-01 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 Regultory Asset AFUDC P/T/D/G Demand/Energy/Customer as in related Plant S06 Sum of Production, Transmission, Distribution, and General Plant
31 Colstrip Deferred Amortization P = Production Demand/Energy by Load Factor Peak Credit D01/E02 Coincident Peak Demand/Annual Generation Level Consumption
32 Demand Side Management Investment DSM Demand/Energy by Load Factor Peak Credit S01 Sum of Production Plant
33 Working Capital P/T/D/G Demand/Energy/Customer as in related Plant S06 Sum of Production, Transmission, Distribution, and General Plant
34 Tax Reform Rate Base Adjustment 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-23-01
M. Garbarino, Avista
Schedule 2, p. 7 of 9
IPUC Case No. AVU-E-23-01 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 Customers Weighted by Est. Meter Reading Time
32 903 Customer Records & Collections C = Customer Relations Customer C01 All Customers unweighted
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-23-01
M. Garbarino, Avista
Schedule 2, p. 8 of 9
IPUC Case No. AVU-E-23-01 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-23-01
M. Garbarino, Avista
Schedule 2, p. 9 of 9
AVISTA UTILITIES -- Base Case
Cost of Service General Summary
ID Electric
A B C D E F G H I J
594
595
596 Total Sch 1 Sch 11-12 Sch 21-22 Sch 25 Sch 25P Sch 31-32 Sch 41-49
597 Plant In Service
598 Production Plant 559,658,000 245,460,274 80,330,112 106,202,091 57,156,587 58,381,442 10,752,428 1,375,066
599 Transmission Plant 361,980,000 172,554,502 51,110,139 72,061,603 30,883,544 28,975,633 6,099,845 294,735
600 Distribution Plant 801,874,000 430,960,880 131,049,672 145,450,111 25,838,005 3,182,866 29,720,261 35,672,206
601 Intangible Plant 118,780,000 66,135,617 18,233,744 17,128,371 7,362,861 6,663,057 2,442,331 814,020
602 General Plant 168,687,000 98,340,103 26,440,234 22,932,151 8,653,395 7,083,147 3,713,291 1,524,678
603 Total Plant In Service 2,010,979,000 1,013,451,375 307,163,901 363,774,326 129,894,391 104,286,145 52,728,156 39,680,706
604
605 Accum Depreciation
606 Production Plant -264,664,000 -116,078,923 -37,988,359 -50,223,297 -27,029,527 -27,608,765 -5,084,856 -650,273
607 Transmission Plant -100,966,000 -48,130,112 -14,255,998 -20,099,928 -8,614,255 -8,082,087 -1,701,412 -82,209
608 Distribution Plant -296,376,000 -163,614,551 -49,714,587 -50,921,827 -7,929,275 -857,925 -10,770,681 -12,567,153
609 Intangible Plant -58,885,000 -34,046,392 -9,166,504 -8,020,371 -3,192,186 -2,734,819 -1,246,915 -477,812
610 General Plant -68,908,000 -40,171,559 -10,800,735 -9,367,697 -3,534,879 -2,893,439 -1,516,865 -622,825
611 Total Accumulated Depreciation -789,799,000 -402,041,537 -121,926,184 -138,633,120 -50,300,122 -42,177,035 -20,320,729 -14,400,273
612
613 Net Plant 1,221,180,000 611,409,838 185,237,716 225,141,206 79,594,270 62,109,110 32,407,427 25,280,433
614 Accumulated Deferred FIT -200,382,000 -100,172,954 -30,495,469 -36,503,457 -13,330,335 -10,900,490 -5,188,407 -3,790,888
615 Miscellaneous Rate Base 14,140,000 6,331,490 2,124,277 3,001,884 1,075,994 863,988 409,836 332,531
616 Total Rate Base 1,034,938,000 517,568,374 156,866,524 191,639,633 67,339,929 52,072,609 27,628,856 21,822,075
617
618 Revenue From Retail Rates 275,654,000 134,665,000 43,855,000 47,036,000 20,704,000 19,143,000 6,208,000 4,043,000
619 Other Operating Revenues 95,228,000 42,769,075 13,765,347 18,117,328 9,122,472 9,066,862 1,913,719 473,197
620 Total Revenues 370,882,000 177,434,075 57,620,347 65,153,328 29,826,472 28,209,862 8,121,719 4,516,197
621
622 Operating Expenses
623 Production Expenses 159,700,000 70,042,786 22,922,426 30,305,068 16,309,794 16,659,310 3,068,236 392,379
624 Transmission Expenses 11,853,000 5,650,280 1,673,597 2,359,650 1,011,279 948,804 199,739 9,651
625 Distribution Expenses 17,720,000 9,720,366 3,036,500 3,287,709 706,820 128,463 677,921 162,221
626 Customer Accounting Expenses 4,089,000 3,165,610 676,577 109,224 39,185 35,998 50,447 11,960
627 Customer Information Expenses 452,000 368,625 75,200 2,637 35 3 4,908 591
628 Sales Expenses 0 0 0 0 0 0 0 0
629 Admin & General Expenses 42,758,000 23,868,575 6,644,081 6,377,747 2,373,715 1,946,652 992,897 554,332
630 Total O&M Expenses 236,572,000 112,816,242 35,028,381 42,442,035 20,440,828 19,719,232 4,994,148 1,131,134
631
632 Taxes Other Than Income Taxes 14,074,000 6,964,481 2,119,537 2,531,922 1,022,260 897,412 337,416 200,973
633 Other Income Related Items 1,463,000 1,090,815 234,172 121,603 -8,357 -42,773 37,435 30,104
634 Depreciation Expense
635 Production Plant Depreciation 14,985,000 6,572,268 2,150,861 2,843,591 1,530,384 1,563,179 287,899 36,818
636 Transmission Plant Depreciation 8,342,000 3,976,600 1,177,857 1,660,694 711,726 667,757 140,574 6,792
637 Distribution Plant Depreciation 19,745,000 10,719,421 3,376,881 3,386,891 589,174 70,389 725,678 876,565
638 General Plant Depreciation 8,764,000 5,109,182 1,373,682 1,191,422 449,580 367,999 192,921 79,213
639 Amortization Expense 15,525,000 8,107,735 2,378,805 2,631,916 958,424 783,742 386,132 278,246
640 Total Depreciation Expense 67,361,000 34,485,206 10,458,086 11,714,513 4,239,288 3,453,067 1,733,204 1,277,635
641 Income Tax 2,343,000 843,688 534,569 327,622 223,523 261,985 30,682 120,932
642 Total Operating Expenses 321,813,000 156,200,433 48,374,744 57,137,695 25,917,542 24,288,922 7,132,885 2,760,778
643
644 Net Operating Income 49,069,000 21,233,641 9,245,602 8,015,633 3,908,930 3,920,940 988,834 1,755,419
645 Rate of Return 4.74%4.10% 5.89% 4.18% 5.80% 7.53% 3.58% 8.04%
646 Return Ratio 1.00 0.87 1.24 0.88 1.22 1.59 0.75 1.70
647
648 Interest Expense 25,459,000 12,731,945 3,858,845 4,714,247 1,656,531 1,280,962 679,657 536,813
IDElec COS Case AVU-E-23-01.xlsm Summary
Exhibit No. 16 Case No. AVU-E-23-01 M. Garbarino, Avista
Schedule 3, Page 1 of 4
AVISTA UTILITIES -- Base Case
Cost of Service General Summary
ID Electric
A B C D E F G H I J
594
595
701 SUMMARY BY FUNCTION ANALYSIS
702
703 Total Sch 1 Sch 11-12 Sch 21-22 Sch 25 Sch 25P Sch 31-32 Sch 41-49
704 Functional Cost Components at Current Rates
705 Production 115,295,839 49,577,759 16,947,343 21,493,260 12,032,815 12,796,219 2,143,500 304,942
706 Transmission 24,020,748 10,638,202 3,782,282 4,482,478 2,266,477 2,471,086 354,042 26,181
707 Distribution 64,119,950 34,857,087 11,661,677 10,202,765 2,242,511 361,702 2,057,249 2,736,959
708 Common 72,217,464 39,591,952 11,463,698 10,857,497 4,162,197 3,513,992 1,653,208 974,918
709 Total Current Rate Revenue 275,654,000 134,665,000 43,855,000 47,036,000 20,704,000 19,143,000 6,208,000 4,043,000
710
711
712
713 Expressed as $/kWh
714 Production $0.03740 $0.03871 $0.03807 $0.03788 $0.03459 $0.03477 $0.03393 $0.02923
715 Transmission $0.00779 $0.00831 $0.00850 $0.00790 $0.00652 $0.00671 $0.00560 $0.00251
716 Distribution $0.02080 $0.02721 $0.02620 $0.01798 $0.00645 $0.00098 $0.03256 $0.26234
717 Common $0.02342 $0.03091 $0.02575 $0.01914 $0.01196 $0.00955 $0.02617 $0.09345
718 Total Current Rate Revenue $0.08941 $0.10513 $0.09851 $0.08290 $0.05952 $0.05202 $0.09826 $0.38752
719
720 Functional Cost Components at Uniform Current Return
721 Production 114,833,344 50,364,730 16,482,522 21,791,060 11,727,666 11,978,988 2,206,235 282,143
722 Transmission 23,910,548 11,398,068 3,376,074 4,760,021 2,040,009 1,913,982 402,925 19,469
723 Distribution 64,586,127 36,458,489 10,783,918 10,699,357 2,061,440 299,402 2,263,874 2,019,646
724 Common 72,323,981 40,085,339 11,220,492 10,964,872 4,085,900 3,350,961 1,688,732 927,685
725 Total Uniform Current Cost 275,654,000 138,306,627 41,863,007 48,215,311 19,915,015 17,543,332 6,561,766 3,248,943
726
727
728
729 Expressed as $/kWh
730 Production $0.03725 $0.03932 $0.03702 $0.03841 $0.03371 $0.03255 $0.03492 $0.02704
731 Transmission $0.00776 $0.00890 $0.00758 $0.00839 $0.00586 $0.00520 $0.00638 $0.00187
732 Distribution $0.02095 $0.02846 $0.02422 $0.01886 $0.00593 $0.00081 $0.03583 $0.19358
733 Common $0.02346 $0.03130 $0.02520 $0.01933 $0.01175 $0.00911 $0.02673 $0.08892
734 Total Current Rate Revenue $0.08941 $0.10798 $0.09404 $0.08498 $0.05725 $0.04767 $0.10385 $0.31141
735
736 Revnue to Cost Ratio at Current Rates 1.00 0.97 1.05 0.98 1.04 1.09 0.95 1.24
737
738
739 Functional Cost Components at Proposed Return by Schedule
740 Production 124,847,235 53,535,839 18,339,485 23,109,715 13,121,762 14,126,272 2,293,402 320,760
741 Transmission 32,387,035 14,452,866 4,996,775 5,986,012 3,073,374 3,376,589 470,594 30,825
742 Distribution 79,212,864 42,898,782 14,286,697 12,893,372 2,887,740 462,979 2,550,014 3,233,280
743 Common 76,668,710 42,075,069 12,192,595 11,440,918 4,434,692 3,779,512 1,738,174 1,007,751
744 Total Proposed Rate Revenue 313,115,844 152,962,556 49,815,553 53,430,018 23,517,567 21,745,351 7,052,184 4,592,616
745
746
747
748 Expressed as $/kWh
749 Production $0.04050 $0.04180 $0.04120 $0.04073 $0.03772 $0.03839 $0.03630 $0.03074
750 Transmission $0.01051 $0.01128 $0.01122 $0.01055 $0.00883 $0.00918 $0.00745 $0.00295
751 Distribution $0.02569 $0.03349 $0.03209 $0.02272 $0.00830 $0.00126 $0.04036 $0.30991
752 Common $0.02487 $0.03285 $0.02739 $0.02016 $0.01275 $0.01027 $0.02751 $0.09659
753 Total Proposed Melded Rates $0.10156 $0.11942 $0.11190 $0.09417 $0.06760 $0.05909 $0.11162 $0.44020
754
755 Functional Cost Components at Uniform Proposed Return
756 Production 124,073,250 54,417,258 17,808,766 23,544,448 12,671,316 12,942,860 2,383,757 304,845
757 Transmission 32,104,150 15,303,928 4,532,979 6,391,172 2,739,074 2,569,860 540,998 26,140
758 Distribution 80,168,585 44,692,377 13,284,496 13,618,303 2,620,453 372,764 2,847,608 2,732,586
759 Common 76,769,858 42,627,670 11,914,910 11,597,665 4,322,065 3,543,429 1,789,338 974,781
760 Total Uniform Proposed Cost 313,115,844 157,041,232 47,541,149 55,151,588 22,352,908 19,428,914 7,561,701 4,038,352
761
762
763
764 Expressed as $/kWh
765 Production $0.04025 $0.04248 $0.04000 $0.04150 $0.03643 $0.03517 $0.03773 $0.02922
766 Transmission $0.01041 $0.01195 $0.01018 $0.01126 $0.00787 $0.00698 $0.00856 $0.00251
767 Distribution $0.02600 $0.03489 $0.02984 $0.02400 $0.00753 $0.00101 $0.04507 $0.26192
768 Common $0.02490 $0.03328 $0.02676 $0.02044 $0.01242 $0.00963 $0.02832 $0.09343
769 Total Uniform Melded Rates $0.10156 $0.12260 $0.10679 $0.09720 $0.06426 $0.05279 $0.11968 $0.38707
770
771 Revenue to Cost Ratio at Proposed Rates 1.00 0.97 1.05 0.97 1.05 1.12 0.93 1.14
772 Current Revenue to Proposed Cost Ratio 0.88 0.86 0.92 0.85 0.93 0.99 0.82 1.00
773
774 Target Revenue Change 37,462,000 22,376,000 3,686,000 8,116,000 1,649,000 286,000 1,354,000 -5,000
IDElec COS Case AVU-E-23-01.xlsm Summary
Exhibit No. 16 Case No. AVU-E-23-01 M. Garbarino, Avista
Schedule 3, Page 2 of 4
AVISTA UTILITIES -- Base Case
Cost of Service General Summary
ID Electric
A B C D E F G H I J
594
595
784 SUMMARY BY CLASSIFICATION WITH UNIT COST ANALYSIS
785
786 Total Sch 1 Sch 11-12 Sch 21-22 Sch 25 Sch 25P Sch 31-32 Sch 41-49
787 Cost by Classification at Curr. Return by Schedule
788 Energy 88,432,479 36,116,831 13,083,841 16,011,708 10,070,217 11,068,803 1,759,502 321,577
789 Demand 153,113,598 74,038,513 24,954,985 30,642,753 10,626,008 8,073,142 4,021,880 756,319
790 Customer 34,107,922 24,509,656 5,816,174 381,539 7,776 1,055 426,619 2,965,104
791 Total Current Rate Revenue 275,654,000 134,665,000 43,855,000 47,036,000 20,704,000 19,143,000 6,208,000 4,043,000
792
793 Revenue per kWh at Current Rates
794 Energy $0.02868 $0.02820 $0.02939 $0.02822 $0.02895 $0.03008 $0.02785 $0.03082
795 Demand $0.04966 $0.05780 $0.05606 $0.05401 $0.03055 $0.02194 $0.06366 $0.07249
796 Customer $0.01106 $0.01913 $0.01306 $0.00067 $0.00002 $0.00000 $0.00675 $0.28420
797 Total Revenue per kWh at Current Rates $0.08941 $0.10513 $0.09851 $0.08290 $0.05952 $0.05202 $0.09826 $0.38752
798
799 Cost per Unit at Current Rates
800 Energy $0.02868 $0.02820 $0.02939 $0.02822 $0.02895 $0.03008 $0.02785 $0.03082
801 Demand $11.18 $8.87 $13.13 $20.99 $14.29 $10.26 $9.28 $25.83
802 Customer $20.14 $17.74 $20.64 $38.61 $58.91 $87.90 $23.20 $1,338.04
803
804 Cost by Classification at Uniform Current Return
805 Energy 87,954,576 36,661,884 12,741,948 16,222,649 9,826,934 10,394,114 1,808,429 298,618
806 Demand 153,963,251 76,722,938 23,464,733 31,607,192 10,080,414 7,148,200 4,315,248 624,526
807 Customer 33,736,173 24,921,804 5,656,325 385,469 7,667 1,018 438,089 2,325,799
808 Total Uniform Current Cost 275,654,000 138,306,627 41,863,007 48,215,311 19,915,015 17,543,332 6,561,766 3,248,943
809
810 Cost per kWh at Current Return
811 Energy $0.02853 $0.02862 $0.02862 $0.02859 $0.02825 $0.02824 $0.02862 $0.02862
812 Demand $0.04994 $0.05990 $0.05271 $0.05571 $0.02898 $0.01942 $0.06830 $0.05986
813 Customer $0.01094 $0.01946 $0.01271 $0.00068 $0.00002 $0.00000 $0.00693 $0.22293
814 Total Cost per kWh at Current Return $0.08941 $0.10798 $0.09404 $0.08498 $0.05725 $0.04767 $0.10385 $0.31141
815
816 Cost per Unit at Uniform Current Return
817 Energy $0.02853 $0.02862 $0.02862 $0.02859 $0.02825 $0.02824 $0.02862 $0.02862
818 Demand $11.24 $9.19 $12.35 $21.65 $13.56 $9.08 $9.95 $21.33
819 Customer $19.92 $18.04 $20.07 $39.01 $58.08 $84.85 $23.82 $1,049.55
820
821 Revenue to Cost Ratio at Current Rates 1.00 0.97 1.05 0.98 1.04 1.09 0.95 1.24
822
823
824 Cost by Classification at Proposed Return by Schedule
825 Energy 95,442,669 38,858,521 14,107,930 17,156,841 10,938,478 12,166,964 1,876,427 337,508
826 Demand 180,522,222 87,521,754 29,412,705 35,870,286 12,570,925 9,577,273 4,721,722 847,557
827 Customer 37,150,953 26,582,282 6,294,918 402,890 8,165 1,114 454,034 3,407,551
828 Total Proposed Rate Revenue 313,115,844 152,962,556 49,815,553 53,430,018 23,517,567 21,745,351 7,052,184 4,592,616
829
830 Revenue per kWh at Proposed Rates
831 Energy $0.03096 $0.03034 $0.03169 $0.03024 $0.03144 $0.03306 $0.02970 $0.03235
832 Demand $0.05856 $0.06833 $0.06607 $0.06322 $0.03614 $0.02602 $0.07473 $0.08124
833 Customer $0.01205 $0.02075 $0.01414 $0.00071 $0.00002 $0.00000 $0.00719 $0.32661
834 Total Revenue per kWh at Prop. Rates $0.10156 $0.11942 $0.11190 $0.09417 $0.06760 $0.05909 $0.11162 $0.44020
835
836 Cost per Unit at Proposed Rates
837 Energy $0.03096 $0.03034 $0.03169 $0.03024 $0.03144 $0.03306 $0.02970 $0.03235
838 Demand $13.18 $10.49 $15.48 $24.57 $16.91 $12.17 $10.89 $28.94
839 Customer $21.93 $19.24 $22.34 $40.77 $61.85 $92.86 $24.69 $1,537.70
840
841 Cost by Classification at Uniform Proposed Return
842 Energy 94,689,027 39,468,988 13,717,566 17,464,775 10,579,357 11,189,964 1,946,895 321,482
843 Demand 181,420,961 90,528,350 27,711,176 37,278,185 11,765,547 8,237,889 5,144,250 755,563
844 Customer 37,005,856 27,043,893 6,112,408 408,628 8,004 1,061 470,555 2,961,307
845 Total Uniform Proposed Cost 313,115,844 157,041,232 47,541,149 55,151,588 22,352,908 19,428,914 7,561,701 4,038,352
846
847 Cost per kWh at Proposed Return
848 Energy $0.03071 $0.03081 $0.03081 $0.03078 $0.03041 $0.03041 $0.03081 $0.03081
849 Demand $0.05885 $0.07068 $0.06225 $0.06570 $0.03382 $0.02238 $0.08142 $0.07242
850 Customer $0.01200 $0.02111 $0.01373 $0.00072 $0.00002 $0.00000 $0.00745 $0.28384
851 Total Cost per kWh at Proposed Return $0.10156 $0.12260 $0.10679 $0.09720 $0.06426 $0.05279 $0.11968 $0.38707
852
853 Cost per Unit at Uniform Proposed Return
854 Energy $0.03071 $0.03081 $0.03081 $0.03078 $0.03041 $0.03041 $0.03081 $0.03081
855 Demand $13.24 $10.85 $14.58 $25.53 $15.83 $10.47 $11.87 $25.80
856 Customer $21.85 $19.58 $21.69 $41.35 $60.64 $88.45 $25.58 $1,336.33
857
858 Revenue to Cost Ratio at Prop. Rates 1.00 0.97 1.05 0.97 1.05 1.12 0.93 1.14
IDElec COS Case AVU-E-23-01.xlsm Summary 1/31/2023
Exhibit No. 16 Case No. AVU-E-23-01 M. Garbarino, Avista
Schedule 3, Page 3 of 4
AVISTA UTILITIES
Average Customer Cost
ID Electric
A B C D E F G H I J
IDAHO ELECTRIC
Meter, Services, Meter Reading & Billing Costs by Schedule at Proposed Rate of Return
Residential General Large Gen Extra Large Extra Large Pumping Street &
System Service Service Service Gen Service Service CP Service Area Lights
Total Sch 1 Sch 11-12 Sch 21-22 Sch 25 Sch 25P Sch 31-32 Sch 41-49
1 Services 71,826,000$ 58,668,812$ 11,968,544$ 407,456$ -$ -$ 781,188$ -$
2 Services Accum. Depr.(33,192,000)$ (27,111,843)$ (5,530,865)$ (188,292)$ -$ -$ (361,000)$ -$
3 Total Services 38,634,000$ 31,556,970$ 6,437,679$ 219,164$ -$ -$ 420,188$ -$
4 Meters 24,698,000$ 16,227,694$ 6,432,749$ 1,217,790$ 31,953$ 4,599$ 783,215$ -$
5 Meters Accum. Depr.(18,983,000)$ (12,472,682)$ (4,944,241)$ (935,999)$ (24,560)$ (3,535)$ (601,983)$ -$
6 Total Meters 5,715,000$ 3,755,011$ 1,488,507$ 281,791$ 7,394$ 1,064$ 181,232$ -$
7 Total Rate Base 44,349,000$ 35,311,981$ 7,926,186$ 500,955$ 7,394$ 1,064$ 601,420$ -$
8 Return on Rate Base @ 7.59%3,366,089$ 2,680,179$ 601,598$ 38,022$ 561$ 81$ 45,648$ -$
9 Tax Benefit of Interest Expense (229,107)$ (182,422)$ (40,947)$ (2,588)$ (38)$ (5)$ (3,107)$ -$
10 Revenue Conversion Factor 0.78701 0.78701 0.78701 0.78701 0.78701 0.78701 0.78701 0.78701
11 Rate Base Revenue Requirement 3,985,970$ 3,173,747$ 712,385$ 45,024$ 665$ 96$ 54,054$ -$
12 Services Depr Exp 1,432,000$ 1,169,684$ 238,618$ 8,123$ -$ -$ 15,575$ -$
13 Meters Depr Exp 2,225,000$ 1,461,925$ 579,515$ 109,709$ 2,879$ 414$ 70,559$ -$
14 Services Exp 308,000$ 251,580$ 51,323$ 1,747$ -$ -$ 3,350$ -$
15 Meters Exp 344,000$ 226,023$ 89,597$ 16,962$ 445$ 64$ 10,909$ -$
16 Meters Exp 8,000$ 5,256$ 2,084$ 394$ 10$ 1$ 254$ -$
17 Meter Reading 233,000$ 190,270$ 38,815$ 1,361$ 18$ 2$ 2,533$ -$
18 Billing Exp 3,232,000$ 2,635,830$ 537,714$ 18,855$ 252$ 23$ 35,097$ 4,229$
19 Total Expenses 7,782,000$ 5,940,569$ 1,537,666$ 157,152$ 3,604$ 504$ 138,276$ 4,229$
20 Revenue Conversion Factor 0.99621 0.99621 0.99621 0.99621 0.99621 0.99621 0.99621 0.99621
21 Expense Revenue Requirement 7,811,606$ 5,963,170$ 1,543,516$ 157,750$ 3,618$ 506$ 138,802$ 4,245$
22 Total Customer Costs 11,797,576$ 9,136,917$ 2,255,900$ 202,774$ 4,282$ 602$ 192,856$ 4,245$
23 Total Customers Bills 1,693,693 1,381,277 281,783 9,881 132 12 18,392 2,216
24 Avg Unit Cost 6.97$ 6.61$ 8.01$ 20.52$ 32.44$ 50.16$ 10.49$ 1.92$
25 Total Customer Related Cost $37,150,953 $26,582,282 $6,294,918 $402,890 $8,165 $1,114 $454,034 $3,407,551
26 Customer Related Unit Cost per Month $21.93 $19.24 $22.34 $40.77 $61.85 $92.86 $24.69 $1,537.70
27 Distribution Demand Related Cost $62,803,837 32,929,005 10,417,759 13,363,429 2,614,641 371,623 2,603,829 503,552
28 Distribution Demand Cost per Customer/Mo $37.08 $23.84 $36.97 $1,352.44 $19,807.88 $30,968.58 $141.57 $227.23
29 Total Customer and Distribution Demand $59.02 $43.08 $59.31 $1,393.21 $19,869.74 $31,061.44 $166.26 $1,764.94
IDElec COS Case AVU-E-23-01 Avg Cust Unit Cost
Exhibit No. 16 Case No. AVU-E-23-01 M. Garbarino, Avista
Schedule 3, Page 4 of 4