20160526Knox Exhibit 12.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-16-03
OF AVISTA CORPORATION FOR THE )
AUTHORITY TO INCREASE ITS RATES )
AND CHARGES FOR ELECTRIC SERVICE ) EXHIBIT NO. 12
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, 2015
Line Column Description of Adjustment (000's)Revenue Expense Plant
Accumulated
Depreciation
Deferred
Debits/Credits
Deferred
Tax
1 1.00 Per Results Report 81,847 183,805 653,106 (250,980) 748 (78,260)
2 1.01 Deferred FIT Rate Base - - - - - (6,802)
3 1.02 Deferred Debits, Credits & Reg Amortizations - (497) - - (581) -
4 1.03 Restate Capital 2015 EOP - - 13,600 (4,378) - (4,050)
5 1.04 Working Capital - - - - - -
6 1.05 Plant Held For Future Use - - - - - -
7 2.01 Eliminate B & O Taxes - - - - - -
8 2.02 Uncollectible Expense - - - - - -
9 2.03 Regulatory Expense - - - - - -
10 2.04 Injuries and Damages - - - - - -
11 2.05 FIT/DFIT ITC/PTC Expense - - - - - -
12 2.06 SIT/SITC Expense - - - - - -
13 2.07 Revenue Normalization - 2,801 - - - -
14 2.08 Miscellaneous Restating - - - - - -
15 2.09 Restate Incentives - (7) - - - -
16 2.10 ID PCA - (7,757) - - - -
17 2.11 Nez Perce Settlement Adjustment - (31) - - - -
18 2.12 Colstrip / CS2 Maintenance - 2,426 - - - -
19 2.13 Restate Debt Interest - - - - - -
20 3.01 Pro Forma Power Supply (58,168) (55,277) - - - -
21 3.02 Pro Forma Transmission Rev/Exp (38) 125 - - - -
22 3.03 Pro Forma Labor Non-Exec - 433 - - - -
23 3.04 Pro Forma Employee Benefits - (32) - - - -
24 3.05 Pro Forma Property Tax - 993 - - - -
25 3.06 Planned Capital Add 2016 EOP - 1,602 72,214 (9,939) - (13,735)
26 3.07 Planned Capital Add 2017 AMA - 190 9,705 (5,363) - (3,911)
27 2017 Pro Forma Total 23,641 128,774 748,625 (270,660) 167 (106,758)
Production / Transmission
Exhibit No. 12
Case No. AVU-E-16-03
T. Knox, Avista
Schedule 1, p. 1 of 2
AVISTA UTILITIES
AVERAGE PRODUCTION AND TRANSMISSION COST
IDAHO ELECTRIC
TWELVE MONTHS ENDED DECEMBER 31, 2015
Line ($000's) Debt Cost
1 Prod/Trans Pro Forma Rate Base 371,374
2 Cost of Capital Proposed Rate of Return 7.780% 2.83%
3 Rate Base Net Operating Income Requirement $28,893
4 Tax Effect Net Operating Income Requirement ($3,678)
(Rate Base x Debt Cost x -35%)
5 Net Expense Net Operating Income Requirement 105,133
(Expense - Revenue)
6 Tax Effect Net Operating Income Requirement ($36,797)
(Net Expense x -.35%)
7 Total Prod/Trans Net Operating Income Requirement $93,551
8 1 - Tax Rate Conversion Factor (Excl. Rev. Rel. Exp.) 0.65
9 Prod/Trans Revenue Requirement $143,924
10 Test Year WA Normalized Retail Load MWh 3,011,312
11 Prod/Trans Rev Requirement per kWh 0.04779$
12 Cost of Service Energy Classified Production/Transmission Costs $77,203 Company Case at Unity AVU-E-16-03
13 Cost of Service Total Production/Transmission Costs $147,851 Company Case at Unity AVU-E-16-03
14 Load Change Adjustment Rate per kWh (Line 11 * Line 12 / Line 13)0.02496$
2017 Pro Forma
Calculation of Load Change Adjustment Rate
Proposed Production and Transmission Revenue Requirement
Exhibit No. 12
Case No. AVU-E-16-03
T. Knox, Avista
Schedule 1, p. 2 of 2
Exhibit No. 12
Case No. AVU-E-16-03
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
There are three basic steps involved in a cost of service study: functionalization, 7
classification, and allocation. See flow chart below. 8
First, the expenses and rate base associated with the electric system under study are 9
assigned to functional categories. The uniform system of accounts provides the basic segregation 10
into production, transmission, and distribution. Traditionally customer accounting, customer 11
information, and sales expenses are included in the distribution function, and administrative and 12
general expenses and general plant rate base are allocated to all functions. This study includes a 13
separate functional category for common costs. Administrative and general costs that cannot be 14
directly assigned to the other functions have been placed in this category. 15
Second, the expenses and rate base items that cannot be directly assigned to customer 16
groups are classified into three primary cost components: energy, demand or customer related. 17
Energy related costs are allocated based on each rate schedule’s share of commodity consumption. 18
Demand (capacity) related costs are allocated to rate schedules on the basis of each schedule’s 19
contribution to peak demand. Customer related items are allocated to rate schedules based on the 20
number of customers within each schedule. The number of customers may be weighted by 21
appropriate factors such as relative cost of metering equipment. In addition to these three cost 22
components, any revenue related expense is allocated based on the proportion of revenues by rate 23
schedule. 24
Exhibit No. 12
Case No. AVU-E-16-03
T. Knox, Avista
Schedule 2, p. 2 of 9

1
* Customer classes shown in this flowchart are illustrative and may not match the Company’s actual rate schedules.
Pro Forma Results of Operations by Customer Group
TransmissionProduction Common
Energy /
Commodity
Related
Customer
Related
Demand /
Capacity Related
Residential Small General Large
General
Extra Large
General *
Pumping Street & Area
Lights
Allocation
Pro Forma
Results of
Operations
Functionalization
Distribution and
Customer
Relations
Classification
Direct Assignment
Number of Customers
Weighted Number of
Customers
Direct Assignment
Coincident Peak
Non-Coincident Peak
Direct Assignment
Generation Level mWh's
Customer Level mWh's
Exhibit No. 12
Case No. AVU-E-16-03
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 factors 1
selected for each specific cost item. These factors are derived from usage and customer 2
information associated with the test period results of operations. 3
4
BASE CASE COST OF SERVICE STUDY 5
Production Classification (Load Factor Peak Credit) 6
This study utilizes a Peak Credit methodology to classify production costs into demand and 7
energy classifications. The Peak Credit method acknowledges that 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 36.10% 12
for the 2015 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. 12
Case No. AVU-E-16-03
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. This division 10
delineates plant installed solely for an individual customer from plant which is part of the broader 11
system. The basic customer method provides a clearly definable division between plant that 12
provides service only to individual customers, from plant that is part of the interconnected system. 13
Customer Relations Distribution Cost Classification 14
Customer service, customer information and sales expenses are the core of the customer 15
relations functional unit which is included with the distribution cost category. For the most part 16
they are classified as customer related. Exceptions are sales expenses which are classified as 17
energy related and uncollectible accounts expense which is considered separately as a revenue 18
conversion item. Demand Side Management expenses (if any) recorded in Account 908 would be 19
considered separately from the other customer information costs. 20
21
Exhibit No. 12
Case No. AVU-E-16-03
T. Knox, Avista
Schedule 2, p. 5 of 9

Any demand side management investment and amortization included in base rates would 1
be classified implicitly to demand and energy by the sum of production plant in service, then 2
allocated to rate schedules by coincident peak demand and energy consumption, respectively. At 3
this point in time, the Company’s demand side management investments in base rates have been 4
fully amortized except for some minor outstanding loan balances that will remain on the books 5
until satisfied. All current demand side management costs are managed through the Schedule 91 6
Public Purpose Tariff Rider balancing account which is not included in this cost study. 7
Distribution Cost Allocation 8
Distribution demand related costs, which cannot be directly assigned, are allocated to 9
customer class by the average of the twelve monthly non-coincident peaks for each class. 10
Distribution facilities that serve only secondary voltage customers are either allocated by the non-11
coincident peaks of secondary voltage customers (excludes demand from customers receiving 12
service at primary voltage)2, or by the average number of secondary voltage customers. This 13
includes secondary voltage overhead or underground conductors and devices, line transformers, 14
and service lines to the customer’s premises. The costs of specific substations and related primary 15
voltage distribution facilities are directly assigned to Extra Large General Service customers 16
(Schedule 25 and 25P) based on their load ratio share of the substation capacity from which they 17
receive service. 18
Most customer costs are allocated by average number of customers. Weighted customer 19
allocators have been developed using typical current cost of meters, estimated meter reading time, 20
and direct assignment of billing costs for hand-billed customers. Street and area light customers 21
are excluded from metering and meter reading expenses as their service is not metered. 22
23

2 Customers taking service below 11 kV are secondary voltage customers, customers taking service at greater than 11kV
are primary voltage customers.
Exhibit No. 12
Case No. AVU-E-16-03
T. Knox, Avista
Schedule 2, p. 6 of 9

Administrative and General Costs 1
Administrative and general costs which are directly associated with production, 2
transmission, distribution, or customer relations functions are directly assigned to those functions 3
and allocated to customer class by the relevant plant or number of customers. The remainder of 4
administrative and general costs are considered common costs, and have been left in their own 5
functional category. These common costs are classified by the implicit relationship of energy, 6
demand and customer within the four-factor allocator applied to them. The four-factor allocator 7
consists of a 25% weighting of each of the following: 1) operating & maintenance expenses 8
excluding resource costs, labor expenses, and administrative and general expenses; 2) operating 9
and maintenance labor expenses excluding administrative and general labor expenses; 3) net 10
production, transmission, and distribution plant; and 4) number of customers. 11
Revenue Conversion Items 12
In this study uncollectible accounts and commission fees have been classified as revenue 13
related and are allocated by pro forma revenue. These items vary with revenue and are included in 14
the calculation of the revenue conversion factor. Income tax expense items are allocated to 15
schedules by net income before income tax adjusted by interest expense. 16
For the functional summaries on pages 2 and 3 of the cost of service study, these items are 17
assigned to component cost categories. The revenue related expense items have been reduced to a 18
percent of all other costs and loaded onto each cost category by that ratio. Similarly, income tax 19
items have been reduced to a percent of net income before tax then assigned to cost categories by 20
relative rate base (as is net income). 21
The following matrix outlines the methodology applied in the Company Base Case cost of 22
service study. 23
IPUC Case No. AVU-E-16-03 Methodology Matrix
Avista Utilities Idaho Jurisdiction
Electric Cost of Service Methodology
Line Account Functional Category Classification Allocation
Production Plant
1 Thermal Production P = Production Demand/Energy by Load Factor Peak Credit D01/E02 Coincident Peak Demand/Annual Generation Level Consumption
2 Hydro Production P = Production Demand/Energy by Load Factor Peak Credit D01/E02 Coincident Peak Demand/Annual Generation Level Consumption
3 Other Production (Coyote Springs) P = Production Demand/Energy by Load Factor Peak Credit D01/E02 Coincident Peak Demand/Annual Generation Level Consumption
4 Other Production P = Production Demand/Energy by Load Factor Peak Credit D01/E02 Coincident Peak Demand/Annual Generation Level Consumption
Transmission Plant
5 All Transmission T = Transmission Demand D01 Coincident Peak Demand (12CP)
Distribution Plant
6 360 Land D = Distribution Demand D03 Non-coincident Peak Demand (NCP)
7 361 Structures D = Distribution Demand D04/D05/D06 Direct Assign Large / Non-coincident Peak Demand Excl DA
8 362 Station Equipment D = Distribution Demand D04/D05/D06 Direct Assign Large / Non-coincident Peak Demand Excl DA
9 364 Poles Towers & Fixtures D = Distribution Demand D04/D05/D07/D08 Direct Assign Large & Lights / NCP Excl DA / NCP Secondary
10 365 Overhead Conductors & Devices D = Distribution Demand D04/D05/D07 Direct Assign Large / NCP Excl DA / NCP Secondary
11 366 Underground Conduit D = Distribution Demand D04/D05/D07 Direct Assign Large / NCP Excl DA / NCP Secondary
12 367 Underground Conductors & Devices D = Distribution Demand D04/D05/D07 Direct Assign Large / NCP Excl DA / NCP Secondary
13 368 Line Transformers D = Distribution Demand D07 Non-coincident Peak Demand Secondary
14 369 Services D = Distribution Customer C02 Secondary Customers unweighted Excl Lighting
15 370 Meters D = Distribution Customer C04 Customers weighted by Current Typical Meter Cost
16 373 Street and Area Lighting Systems D = Distribution Customer C05 Direct Assignment to Street and Area Lights
General Plant
17 All General O=Other Demand/Energy/Customer by Corp Cost Allocator S23 25% direct O&M, 25% direct labor, 25% net direct plant, 25% number of customers
Intangible Plant
18 301 Organization O=Other Energy/Customer by Corp Cost Allocator S23 25% direct O&M, 25% direct labor, 25% net direct plant, 25% number of customers
19 302 Franchises & Consents - Hydro Relicensing P = Production Demand/Energy by Load Factor Peak Credit D01/E02 Coincident Peak Demand/Annual Generation Level Consumption
20 303 Misc Intangible Plant - Transmission Agreements T = Transmission Demand D01 Coincident Peak Demand (12CP)
21 303 Misc Intangible Plant - Software O=Other Demand/Energy/Customer by Corp Cost Allocator S23 25% direct O&M, 25% direct labor, 25% net direct plant, 25% number of customers
Reserve for Depreciation/Amortization
22 Intangible P/T/O Follows Related Plant S01/S02/S23 Sum of Production Plant / Sum of Transmission Plant / Corp Cost Allocator
23 Production P = Production Follows Related Plant D01/E02 Coincident Peak Demand/Annual Generation Level Consumption
24 Transmission T = Transmission Follows Related Plant D01 Coincident Peak Demand (12CP)
25 Distribution D = Distribution Follows Related Plant D03/D04/D05/D06/D07/D08/C02/C04/C05 - See Related Plant
26 General O=Other Follows Related Plant S23 25% direct O&M, 25% direct labor, 25% net direct plant, 25% number of customers
Other Rate Base
27 252 Customer Advances for Construction D = Distribution Customer S13 Sum of Account 369 Services Plant
28 282/190 Accumulated Deferred Income Tax P/T/D/O Per Functional Analysis S01/S02/S03/S04 Sums of Production / Transmission / Distribution / General Plant
29 Hydro Relicensing Related Settlements P = Production Demand/Energy by Load Factor Peak Credit D01/E02 Coincident Peak Demand/Annual Generation Level Consumption
30 Demand Side Management Investment DSM Demand/Energy by Load Factor Peak Credit S01 Sum of Production Plant
31 Working Capital P/T/D/G Demand/Energy/Customer as in related Plant S06 Sum of Production, Transmission, Distribution, and General Plant
Exhibit No. 12
Case No. AVU-E-16-03
T. Knox, Avist
Schedule 2, p. 7 of 9
IPUC Case No. AVU-E-16-03 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. 12
Case No. AVU-E-16-03
T. Knox, Avist
Schedule 2, p. 8 of 9
IPUC Case No. AVU-E-16-03 Methodology Matrix
Avista Utilities Idaho Jurisdiction
Electric Cost of Service Methodology
Line Account Functional Category Classification Allocation
Admin & General Expenses
1 920 - 927 & 930 -935 Assigned to Production P = Production Demand/Energy from Production Plant S01 Sum of Production Plant
2 920 - 927 & 930 -935 Assigned to Transmission T = Transmission Demand/Energy from Transmission Plant S02 Sum of Transmission Plant
3 920 - 927 & 930 - 935 Assigned to Distribution D = Distribution Demand/Customer from Distribution Plant S03 Sum of Distribution Plant
4 920 - 927 & 930 - 935 Assigned to Customer Relations C = Customer Relations Customer C01 All Customers unweighted
5 920 - 935 Assigned to Other O=Other Demand/Energy/Customer by Corp Cost Allocator S23 25% direct O&M, 25% direct labor, 25% net direct plant, 25% number of customers
6 928 FERC Commission Fees P = Production Energy E02 Annual Generation Level Consumption
7 928 IPUC Commission Fees R = Revenue Conversion Revenue R01 Retail Sales Revenue
Depreciation & Amortization Expense
8 Intangible P/T/O Demand/Energy/Customer as in related Plant S01/S02/S23 Sum of Production Plant / Sum of Transmission Plant / Corp Cost Alloctor
9 Production P = Production Demand/Energy by Peak Credit as in related Plant D01/E02 Coincident Peak Demand/Annual Generation Level Consumption
10 Transmission T = Transmission Demand D01 Coincident Peak Demand (12CP)
11 Distribution D = Distribution Demand/Customer as in related Plant D03/D04/D05/D06/D07/D08/C02/C04/C05 - See Related Plant
12 General O=Other Demand/Energy/Customer by Corp Cost Allocator S23 25% direct O&M, 25% direct labor, 25% net direct plant, 25% number of customers
Taxes
13 Property Tax P/T/D/O Demand/Energy/Customer from related Plant S01/S02/S03/S04 Sums of Production / Transmission / Distribution / General Plant
14 State kWh Generation Taxes P = Production Demand/Energy by Load Factor Peak Credit D01/E02 Coincident Peak Demand/Annual Generation Level Consumption
15 Misc Production Taxes P = Production Demand/Energy by Load Factor Peak Credit D01/E02 Coincident Peak Demand/Annual Generation Level Consumption
16 Misc Distribution Taxes D = Distribution Demand/Customer from Distribution Plant S03 Sum of Distribution Plant
17 Idaho State Income Tax R = Revenue Conversion Revenue R03 Revenue less Expenses Before Income Taxes less Interest Expense
18 Federal Income Tax R = Revenue Conversion Revenue R03 Revenue less Expenses Before Income Taxes less Interest Expense
19 Deferred FIT R = Revenue Conversion Revenue R03 Revenue less Expenses Before Income Taxes less Interest Expense
Other Income Related Items
20 Boulder Write-off Amort & Misc Renewable Items P = Production Demand/Energy by Load Factor Peak Credit D01/E02 Coincident Peak Demand/Annual Generation Level Consumption
21 Compass Deferral Amortization O=Other Demand/Energy/Customer by Corp Cost Allocator S23 25% direct O&M, 25% direct labor, 25% net direct plant, 25% number of customers
Operating Revenues
22 Sales of Electricity- Retail R = Revenue from Rates Revenue Input Pro Forma Revenue per Revenue Study
23 Sales for Resale (447) P = Production Demand/Energy from Production Plant S01 Sum of Production Plant
24 Misc Service Revenue (451) D = Distribution Demand/Customer from Distribution Plant S03 Sum of Distribution Plant
25 Sales of Water & Water Power (453) P = Production Demand/Energy from Production Plant S01 Sum of Production Plant
26 Rent from Production Property (454) P = Production Demand/Energy from Production Plant S01 Sum of Production Plant
27 Rent from Transmission Property (454) T = Transmission Demand/Energy from Transmission Plant S02 Sum of Transmission Plant
28 Rent from Distribution Property (454) D = Distribution Demand/Customer from Distribution Plant S03 Sum of Distribution Plant
29 Other Electric Revenues - Generation (456) P = Production Demand/Energy from Production Plant S01 Sum of Production Plant
30 Other Electric Revenues - Wheeling (456) T = Transmission Demand/Energy from Transmission Plant S02 Sum of Transmission Plant
31 Other Electric Revenues - Energy Delivery (456) D = Distribution Demand/Customer from Distribution Plant S03 Sum of Distribution Plant
Salaries & Wages (allocation factor input)
Operation & Maintenance Expenses
32 Production Total P = Production Demand/Energy from Production Plant S01 Sum of Production Plant
33 Transmission Total T = Transmission Demand/Energy from Transmission Plant S02 Sum of Transmission Plant
34 Distribution Total D = Distribution Demand/Customer from Distribution Plant S03 Sum of Distribution Plant
35 Customer Accounts Total C = Customer Relations Customer S18 Sum of Other Customer Accounts Expenses Excluding Uncollectibles
36 Customer Service Total C = Customer Relations Customer C01 All Customers unweighted
37 Sales Total C = Customer Relations Energy E02 Annual Generation Level Consumption
38 Admin & General Total O=Other Energy/Customer by Corp Cost Allocator S23 25% direct O&M, 25% direct labor, 25% net direct plant, 25% number of customers
39 Interest Expense (allocation factor input) R = Revenue Conversion Demand/Energy/Customer from Rate Base components S07 Total Rate Base
Exhibit No. 12
Case No. AVU-E-16-03
T. Knox, Avist
Schedule 2, p. 9 of 9
Sumcost VISTA UTILITIES Idaho Jurisdiction
Scenario: AVU-E-16-03 Company Cas Cost of Service Basic Summary Electric Utility 05/26/16
Load Factor Peak Credi For the Twelve Months Ended December 31, 2015
Transmission By Demand 12 CP
(b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l) (m)
Residential General Large Gen Extra Large Extra Large Pumping Street &
System Service Service Service Gen Service Service CP Service rea Lights
Description Total Sch 1 Sch 11-12 Sch 21-22 Sch 25 Sch 25P Sch 31-32 Sch 41-49
Plant In Service
1 Production Plant 477,090,000 196,072,641 57,222,653 102,296,656 49,814,841 60,344,465 9,533,181 1,805,564
2 Transmission Plant 240,951,000 111,548,272 29,133,866 49,684,009 20,238,443 25,822,120 4,031,541 492,749
3 Distribution Plant 536,665,000 271,627,857 78,543,901 120,249,314 15,729,014 2,853,689 21,142,826 26,518,399
4 Intangible Plant 82,604,000 41,255,314 10,881,353 14,886,180 6,077,685 6,970,084 1,745,221 788,164
5 General Plant 121,432,000 68,567,219 17,085,521 18,591,742 6,289,870 6,584,144 2,670,560 1,642,944
6 Total Plant In Service 1,458,742,000 689,071,303 192,867,293 305,707,900 98,149,855 102,574,502 39,123,328 31,247,820
ccum Depreciation
7 Production Plant (198,732,000) (81,674,125) (23,836,115) (42,611,706) (20,750,389) (25,136,507) (3,971,050) (752,108)
8 Transmission Plant (72,992,000) (33,791,648) (8,825,608) (15,050,924) (6,130,892) (7,822,371) (1,221,287) (149,270)
9 Distribution Plant (198,312,000) (101,323,662) (28,855,308) (43,042,573) (4,992,941) (755,920) (7,647,027) (11,694,568)
10 Intangible Plant (18,279,000) (9,729,947) (2,489,313) (3,040,046) (1,148,129) (1,271,441) (392,531) (207,593)
11 General Plant (42,219,000) (23,839,181) (5,940,227) (6,463,904) (2,186,837) (2,289,149) (928,490) (571,212)
12 Total Accumulated Depreciation (530,534,000) (250,358,563) (69,946,572) (110,209,153) (35,209,188) (37,275,388) (14,160,384) (13,374,752)
13 Net Plant 928,208,000 438,712,740 122,920,721 195,498,747 62,940,666 65,299,113 24,962,944 17,873,068
14 ccumulated Deferred FIT (198,108,000) (93,222,166) (26,085,873) (41,456,242) (13,635,053) (14,427,762) (5,230,323) (4,050,581)
15 Miscellaneous Rate Base 24,536,000 11,065,654 3,200,813 5,466,879 1,736,861 1,804,577 688,466 572,749
16 Total Rate Base 754,636,000 356,556,229 100,035,661 159,509,384 51,042,474 52,675,929 20,421,087 14,395,236
17 Revenue From Retail Rates 243,599,000 105,522,000 36,021,000 52,133,000 19,419,000 21,247,000 5,742,000 3,515,000
18 Other Operating Revenues 25,414,000 10,913,437 3,106,854 5,425,112 2,392,942 2,866,380 529,890 179,384
19 Total Revenues 269,013,000 116,435,437 39,127,854 57,558,112 21,811,942 24,113,380 6,271,890 3,694,384
Operating Expenses
20 Production Expenses 92,268,000 37,919,953 11,066,716 19,783,915 9,634,064 11,670,467 1,843,693 349,191
21 Transmission Expenses 10,474,000 4,848,939 1,266,432 2,159,735 879,753 1,122,473 175,249 21,420
22 Distribution Expenses 12,102,000 6,036,603 1,820,710 2,699,093 430,169 97,394 478,213 539,819
23 Customer Accounting Expenses 4,930,000 3,534,370 780,769 292,331 124,150 108,055 69,071 21,254
24 Customer Information Expenses 633,000 516,311 103,228 5,725 55 5 6,955 721
25 Sales Expenses 0 0 0 0 0 0 0 0
26 Admin & General Expenses 23,881,000 13,176,741 3,342,253 3,830,067 1,293,169 1,356,909 537,940 343,920
27 Total O&M Expenses 144,288,000 66,032,917 18,380,109 28,770,865 12,361,360 14,355,303 3,111,121 1,276,325
28 Taxes Other Than Income Taxes 11,775,000 5,290,490 1,508,910 2,541,811 917,199 1,014,572 297,853 204,165
29 Other Income Related Items 779,000 457,079 111,931 112,401 34,457 34,145 17,357 11,631
Depreciation Expense
30 Production Plant Depreciation 10,193,000 4,189,081 1,222,559 2,185,562 1,064,291 1,289,256 203,676 38,576
31 Transmission Plant Depreciation 4,342,000 2,010,129 525,000 895,319 364,702 465,321 72,649 8,879
32 Distribution Plant Depreciation 16,280,000 8,400,799 2,518,842 3,518,584 437,800 52,608 641,048 710,318
33 General Plant Depreciation 12,579,000 7,102,799 1,769,869 1,925,897 651,560 682,044 276,640 170,191
34 Amortization Expense 3,553,000 1,472,969 427,933 760,686 364,030 439,851 71,704 15,827
35 Total Depreciation Expense 46,947,000 23,175,776 6,464,203 9,286,048 2,882,384 2,929,080 1,265,718 943,791
36 Income Tax 15,969,000 4,145,769 3,578,981 4,489,475 1,518,727 1,561,504 364,727 309,817
37 Total Operating Expenses 219,758,000 99,102,030 30,044,133 45,200,601 17,714,127 19,894,604 5,056,775 2,745,730
38 Net Income 49,255,000 17,333,407 9,083,722 12,357,512 4,097,815 4,218,776 1,215,115 948,654
39 Rate of Return 6.53% 4.86% 9.08% 7.75% 8.03% 8.01% 5.95% 6.59%
40 Return Ratio 1.00 0.74 1.39 1.19 1.23 1.23 0.91 1.01
41 Interest Expense 21,356,000 10,090,447 2,830,983 4,514,074 1,444,489 1,490,715 577,911 407,381
42 Revenue Related Operating Expenses 1,827,000 791,418 270,159 390,999 145,643 159,353 43,065 26,363
Exhibit No. 12
Case No. AVU-E-16-03
T. Knox, Avista
Schedule 3, p. 1 of 4
Sumcost VISTA UTILITIES Idaho Jurisdiction
Scenario: AVU-E-16-03 Company Cas Revenue to Cost by Functional Component Summary Electric Utility 05/26/16
Load Factor Peak Credi For the Twelve Months Ended December 31, 2015
Transmission By Demand 12 CP
(b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l) (m)
Residential General Large Gen Extra Large Extra Large Pumping Street &
System Service Service Service Gen Service Service CP Service rea Lights
Description Total Sch 1 Sch 11-12 Sch 21-22 Sch 25 Sch 25P Sch 31-32 Sch 41-49
Functional Cost Components at Current Return by Schedul
1 Production 116,851,559 45,167,744 15,050,262 25,849,817 12,696,284 15,370,943 2,276,421 440,088
2 Transmission 24,353,162 9,524,397 3,601,992 5,542,146 2,309,124 2,941,676 384,031 49,796
3 Distribution 58,884,114 27,956,788 10,574,011 13,504,892 1,951,305 360,767 2,128,438 2,407,914
4 Common 43,510,166 22,873,071 6,794,736 7,236,145 2,462,287 2,573,614 953,111 617,202
5 Total Current Rate Revenue 243,599,000 105,522,000 36,021,000 52,133,000 19,419,000 21,247,000 5,742,000 3,515,000
Expressed as $/kWh
6 Production $0.03880 $0.03951 $0.04208 $0.03932 $0.03588 $0.03664 $0.03483 $0.03102
7 Transmission $0.00809 $0.00833 $0.01007 $0.00843 $0.00653 $0.00701 $0.00588 $0.00351
8 Distribution $0.01955 $0.02445 $0.02956 $0.02054 $0.00551 $0.00086 $0.03256 $0.16970
9 Common $0.01445 $0.02001 $0.01900 $0.01101 $0.00696 $0.00614 $0.01458 $0.04350
10 Total Current Melded Rates $0.08089 $0.09230 $0.10071 $0.07930 $0.05487 $0.05065 $0.08785 $0.24772
Functional Cost Components at Uniform Current Return
11 Production 116,053,088 47,695,059 13,919,524 24,883,864 12,117,559 14,678,911 2,318,965 439,207
12 Transmission 24,211,962 11,208,929 2,927,517 4,992,498 2,033,660 2,594,736 405,109 49,514
13 Distribution 59,480,435 31,504,005 8,979,518 12,309,924 1,743,697 319,913 2,226,885 2,396,494
14 Common 43,853,514 24,522,937 6,147,577 6,863,168 2,310,094 2,416,721 977,615 615,402
15 Total Uniform Current Cost 243,599,000 114,930,929 31,974,136 49,049,454 18,205,009 20,010,281 5,928,574 3,500,617
Expressed as $/kWh
16 Production $0.03854 $0.04172 $0.03892 $0.03785 $0.03424 $0.03499 $0.03548 $0.03095
17 Transmission $0.00804 $0.00980 $0.00818 $0.00759 $0.00575 $0.00619 $0.00620 $0.00349
18 Distribution $0.01975 $0.02756 $0.02510 $0.01872 $0.00493 $0.00076 $0.03407 $0.16890
19 Common $0.01456 $0.02145 $0.01719 $0.01044 $0.00653 $0.00576 $0.01496 $0.04337
20 Total Current Uniform Melded Rates $0.08089 $0.10053 $0.08939 $0.07461 $0.05144 $0.04770 $0.09070 $0.24671
21 Revenue to Cost Ratio at Current Rates 1.00 0.92 1.13 1.06 1.07 1.06 0.97 1.00
Functional Cost Components at Proposed Return by Schedul
22 Production 121,537,987 47,376,329 15,510,677 26,775,086 13,136,731 15,905,296 2,375,831 458,037
23 Transmission 27,159,385 10,996,705 3,876,683 6,068,743 2,518,809 3,209,617 433,292 55,535
24 Distribution 64,430,844 31,057,030 11,223,373 14,649,729 2,109,336 392,317 2,358,505 2,640,555
25 Common 45,903,784 24,314,937 7,058,267 7,593,443 2,578,124 2,694,769 1,010,371 653,873
26 Total Proposed Rate Revenue 259,032,000 113,745,000 37,669,000 55,087,000 20,343,000 22,202,000 6,178,000 3,808,000
Expressed as $/kWh
27 Production $0.04036 $0.04144 $0.04336 $0.04073 $0.03712 $0.03792 $0.03635 $0.03228
28 Transmission $0.00902 $0.00962 $0.01084 $0.00923 $0.00712 $0.00765 $0.00663 $0.00391
29 Distribution $0.02140 $0.02717 $0.03138 $0.02228 $0.00596 $0.00094 $0.03608 $0.18610
30 Common $0.01524 $0.02127 $0.01973 $0.01155 $0.00729 $0.00642 $0.01546 $0.04608
31 Total Proposed Melded Rates $0.08602 $0.09949 $0.10531 $0.08379 $0.05749 $0.05293 $0.09452 $0.26837
Functional Cost Components at Uniform Requested Return
32 Production 120,818,534 49,653,543 14,491,096 25,905,661 12,615,138 15,281,665 2,414,188 457,242
33 Transmission 27,032,156 12,514,538 3,268,512 5,574,021 2,270,540 2,896,969 452,296 55,281
34 Distribution 64,968,259 34,253,219 9,785,626 13,574,174 1,922,223 355,502 2,447,263 2,630,253
35 Common 46,213,050 25,801,534 6,474,726 7,257,737 2,440,956 2,553,384 1,032,464 652,249
36 Total Uniform Cost 259,032,000 122,222,834 34,019,960 52,311,594 19,248,856 21,087,520 6,346,211 3,795,025
Expressed as $/kWh
37 Production $0.04012 $0.04343 $0.04051 $0.03940 $0.03565 $0.03643 $0.03693 $0.03222
38 Transmission $0.00898 $0.01095 $0.00914 $0.00848 $0.00642 $0.00691 $0.00692 $0.00390
39 Distribution $0.02157 $0.02996 $0.02736 $0.02065 $0.00543 $0.00085 $0.03744 $0.18537
40 Common $0.01535 $0.02257 $0.01810 $0.01104 $0.00690 $0.00609 $0.01580 $0.04597
41 Total Uniform Melded Rates $0.08602 $0.10691 $0.09511 $0.07957 $0.05439 $0.05027 $0.09709 $0.26746
42 Revenue to Cost Ratio at Proposed Rates 1.00 0.93 1.11 1.05 1.06 1.05 0.97 1.00
43 Current Revenue to Proposed Cost Ratio 0.94 0.86 1.06 1.00 1.01 1.01 0.90 0.93
44 Target Revenue Increase 15,433,000 16,700,000 (2,001,000) 179,000 (170,000) (159,000) 604,000 280,000
Exhibit No. 12
Case No. AVU-E-16-03
T. Knox, Avista
Schedule 3, p. 2 of 4
Sumcost VISTA UTILITIES Idaho Jurisdiction
Scenario: AVU-E-16-03 Company Cas Revenue to Cost By Classification Summary Electric Utility 05/26/16
Load Factor Peak Credi For the Twelve Months Ended December 31, 2015
Transmission By Demand 12 CP
(b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l) (m)
Residential General Large Gen Extra Large Extra Large Pumping Street &
System Service Service Service Gen Service Service CP Service rea Lights
Description Total Sch 1 Sch 11-12 Sch 21-22 Sch 25 Sch 25P Sch 31-32 Sch 41-49
Cost Classifications at Current Return by Schedul
1 Energ 84,102,238 30,028,997 10,780,683 18,976,884 10,134,211 12,001,444 1,782,214 397,805
2 Demand 131,136,857 55,312,644 19,803,858 32,648,620 9,233,514 9,240,423 3,562,974 1,334,824
3 Custome 28,359,906 20,180,359 5,436,460 507,496 51,275 5,132 396,812 1,782,371
4 Total Current Rate Revenue 243,599,000 105,522,000 36,021,000 52,133,000 19,419,000 21,247,000 5,742,000 3,515,000
Expressed as Unit Cos
5 Energ $/kWh $0.02793 $0.02627 $0.03014 $0.02886 $0.02864 $0.02861 $0.02727 $0.02804
6 Demand $/kW/mo $10.41 $7.71 $12.90 $18.18 $13.65 $9.85 $8.17 $33.64
7 Custome $/Cust/mo $18.56 $16.20 $21.82 $36.73 $388.45 $427.71 $23.64 $1,024.35
Cost Classifications at Uniform Current Return
8 Energ 83,271,618 31,777,603 9,942,002 18,241,550 9,655,349 11,441,308 1,816,828 396,978
9 Demand 131,145,628 61,638,343 17,083,999 30,325,480 8,499,634 8,563,984 3,705,490 1,328,698
10 Custome 29,181,754 21,514,983 4,948,134 482,423 50,026 4,989 406,256 1,774,941
11 Total Uniform Current Cost 243,599,000 114,930,929 31,974,136 49,049,454 18,205,009 20,010,281 5,928,574 3,500,617
Expressed as Unit Cos
12 Energ $/kWh $0.02765 $0.02780 $0.02780 $0.02775 $0.02728 $0.02728 $0.02780 $0.02798
13 Demand $/kW/mo $10.41 $8.59 $11.13 $16.89 $12.57 $9.13 $8.50 $33.48
14 Custome $/Cust/mo $19.10 $17.27 $19.86 $34.92 $378.99 $415.76 $24.20 $1,020.08
15 Revenue to Cost Ratio at Current Rates 1.00 0.92 1.13 1.06 1.07 1.06 0.97 1.00
Cost Classifications at Proposed Return by Schedule
16 Energ 87,570,893 31,557,092 11,122,182 19,681,256 10,498,659 12,433,958 1,863,094 414,652
17 Demand 141,537,506 60,841,200 20,911,510 34,874,231 9,792,116 9,762,799 3,896,025 1,459,626
18 Custome 29,923,602 21,346,707 5,635,308 531,514 52,225 5,243 418,881 1,933,722
19 Total Proposed Rate Revenue 259,032,000 113,745,000 37,669,000 55,087,000 20,343,000 22,202,000 6,178,000 3,808,000
Expressed as Unit Cos
20 Energ $/kWh $0.02908 $0.02760 $0.03109 $0.02994 $0.02967 $0.02964 $0.02850 $0.02922
21 Demand $/kW/mo $11.24 $8.48 $13.62 $19.42 $14.48 $10.41 $8.93 $36.78
22 Custome $/Cust/mo $19.59 $17.13 $22.62 $38.47 $395.65 $436.93 $24.96 $1,111.33
Cost Classifications at Uniform Requested Return
23 Energ 86,822,474 33,132,659 10,365,948 19,019,404 10,067,071 11,929,187 1,894,300 413,906
24 Demand 141,545,703 66,540,916 18,459,025 32,783,243 9,130,686 9,153,219 4,024,515 1,454,099
25 Custome 30,663,822 22,549,258 5,194,987 508,947 51,100 5,114 427,396 1,927,020
26 Total Uniform Cost 259,032,000 122,222,834 34,019,960 52,311,594 19,248,856 21,087,520 6,346,211 3,795,025
Expressed as Unit Cos
27 Energ $/kWh $0.02883 $0.02898 $0.02898 $0.02893 $0.02845 $0.02844 $0.02898 $0.02917
28 Demand $/kW/mo $11.24 $9.28 $12.02 $18.26 $13.50 $9.76 $9.23 $36.64
29 Custome $/Cust/mo $20.07 $18.10 $20.85 $36.84 $387.12 $426.16 $25.46 $1,107.48
30 Revenue to Cost Ratio at Proposed Rates 1.00 0.93 1.11 1.05 1.06 1.05 0.97 1.00
31 Current Revenue to Proposed Cost Ratio 0.94 0.86 1.06 1.00 1.01 1.01 0.90 0.93
32 nnual Consumption (mWh's) 3,011,312 1,143,267 357,685 657,454 353,879 419,474 65,364 14,189
33 Estimated Annual Billing Demand (kW) 12,593,635 7,172,180 1,535,420 1,795,626 676,382 938,250 436,092 39,685
34 Monthly Average Number of Customers 127,305 103,838 20,761 1,151 11 1 1,399 145
Exhibit No. 12
Case No. AVU-E-16-03
T. Knox, Avista
Schedule 3, p. 3 of 4
Sumcost VISTA UTILITIES Idaho Jurisdiction
Scenario: AVU-E-16-03 Company Cas Customer Cost Analysis Electric Utility 05/26/16
Load Factor Peak Credi For the Twelve Months Ended December 31, 2015
Transmission By Demand 12 CP
(b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l) (m)
Residential General Large Gen Extra Large Extra Large Pumping Street &
System Service Service Service Gen Service Service CP Service rea Lights
Description Total Sch 1 Sch 11-12 Sch 21-22 Sch 25 Sch 25P Sch 31-32 Sch 41-49
Rate Base
1 Services 51,737,000 42,260,767 8,449,366 457,591 0 0 569,276 0
2 Services Accum. Depr. (23,577,000) (19,258,598) (3,850,449) (208,528) 0 0 (259,424) 0
3 Total Services 28,160,000 23,002,169 4,598,916 249,063 0 0 309,852 0
4 Meters 22,152,000 14,228,811 5,860,337 1,298,419 25,926 4,411 734,096 0
5 Meters Accum. Depr. (6,906,000) (4,435,905) (1,826,990) (404,789) (8,083) (1,375) (228,858) 0
6 Total Meters 15,246,000 9,792,906 4,033,346 893,630 17,843 3,036 505,238 0
7 Total Rate Base 43,406,000 32,795,075 8,632,263 1,142,693 17,843 3,036 815,090 0
8 Return on Rate Base @ 7.78% 3,376,948 2,551,427 671,582 88,901 1,388 236 63,413 0
9 Tax Benefit of Interest (429,932) (324,832) (85,502) (11,318) (177) (30) (8,073) 0
10 Revenue Conversion Facto 0.61272 0.61272 0.61272 0.61272 0.61272 0.61272 0.61272 0.61272
11 Rate Base Revenue Requiremen 4,809,765 3,633,982 956,530 126,620 1,977 336 90,319 0
Expenses
12 Services Depr Exp 1,393,000 1,137,856 227,496 12,320 0 0 15,328 0
13 Meters Depr Exp 1,688,000 1,084,247 446,562 98,941 1,976 336 55,939 0
14 Services Operations Exp 280,000 228,715 45,728 2,476 0 0 3,081 0
15 Meters Operating Exp 399,000 256,288 105,556 23,387 467 79 13,222 0
16 Meters Maintenance Exp 6,000 3,854 1,587 352 7 1 199 0
17 Meter Reading 374,000 283,109 56,603 3,139 25,057 2,278 3,814 0
18 Billing 3,129,000 2,550,917 510,015 28,284 1,704 155 34,362 3,562
19 Total Expenses 7,269,000 5,544,986 1,393,548 168,899 29,211 2,850 125,944 3,562
20 Revenue Conversion Facto 0.992672 0.992672 0.992672 0.992672 0.992672 0.992672 0.992672 0.992672
21 Expense Revenue Requiremen 7,322,660 5,585,919 1,403,835 170,146 29,426 2,871 126,874 3,588
22 12,132,426 9,219,901 2,360,365 296,767 31,404 3,207 217,193 3,588
23 Total Customer Bills 1,527,664 1,246,051 249,128 13,816 132 12 16,785 1,740
24 Average Unit Cost per Month $7.94 $7.40 $9.47 $21.48 $237.91 $267.25 $12.94 $2.06
25 Total Customer Related Cost 30,663,822 22,549,258 5,194,987 508,947 51,100 5,114 427,396 1,927,020
26 Customer Related Unit Cost per Month $20.07 $18.10 $20.85 $36.84 $387.12 $426.16 $25.46 $1,107.48
27 Total Distribution Demand Related Cost 60,204,081 28,883,810 8,623,848 16,010,630 2,298,476 436,040 2,663,524 1,287,754
28 Dist Demand Related Unit Cost per Month $39.41 $23.18 $34.62 $1,158.85 $17,412.69 $36,336.64 $158.68 $740.09
29 Total Distribution Unit Cost per Month $59.48 $41.28 $55.47 $1,195.68 $17,799.81 $36,762.80 $184.15 $1,847.57
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. 12
Case No. AVU-E-16-03
T. Knox, Avista
Schedule 3, p. 4 of 4