20040209knox Exhibits.pdf

DAVIDJ. MEYER
SENIOR VICE PRESIDENT AND GENERAL COUNSEL
A VISTA CORPORATION
O. BOX 3727
1411 EAST MISSION AVENUE
SPOKANE, WASHINGTON 99220-3727
TELEPHONE: [phone]
FACSIMILE: [phone]
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICA nON
OF A VISTA CORPORATION FOR THE
AUTHORITY TO INCREASE ITS RATES
AND CHARGES FOR ELECTRIC AND
NATURAL GAS SERVICE TO ELECTRIC AND
NATURAL GAS CUSTOMERS IN THE ST ATEOF IDAHO
CASE NO. A VU-04-
EXHIBIT NO. 16
TARA L. KNOX
FOR A VISTA CORPORATION
(ELECTRIC)
SCHEDULE NO
SCHEDULE
SCHEDULE 2
PART
PART 2
PART 3
SCHEDULE 3
CASE NO. A VU-O4-
EXHIBIT NO. 16
TABLE OF CONTENTS
DESCRIPTION
COST OF SERVICE PROCESS DESCRIPTION
Description
Methodology Matrix
ELECTRIC BASE CASE COST OF SERVICE STUDY
SUMMARIES
Basic Summary
Revenue to Cost by Function
Revenue to Cost by Classification
COST OF SERVICE MODEL
Calculation Model
Allocation Factors
Classification Tables
PRO FORMA RESULTS SEGREGATION
Operating Expenses
Rate Base
AL TERNA TE SCENARIO SUMMARIES
Comparison to Base Case
Basic Summary
Revenue to Cost by Function
Revenue to Cost by Classification
PAGE
1 - 6
7 -
31- 33
34 - 35
36 - 50
51 - 59
ELECTRIC COST OF SERVICE
A cost of service study is an engineering-economic study, which apportions the revenue
expenses, and rate base associated with providing electric service to designated groups of
customers. It indicates whether the revenue provided by the customers recovers the cost to serve
those customers. The study results are used as a guide in determining the appropriate rate spread
among the groups of customers.
There are three basic steps involved in a cost of servIce study: functionalization
. classification, and allocation. See flow chart.
First, the expenses and rate base associated with the electric system under study are
assigned to functional categories. The uniform system of accounts provides the basic segregation
into production, transmission, and distribution.Traditionally customer accounting, customer
information, and sales expenses are included in the distribution function and administrative and
general expenses and general plant rate base are allocated to all functions. In this study I have
created a separate functional category for common costs. Administrative and general costs that
cannot be directly assigned to the other functions have been placed in this category.
Second, the expenses and rate base items that cannot be directly assigned to customer
groups are classified into three primary cost components: energy, demand or customer related.
Energy related costs are allocated based on each rate schedule s share of commodity consumption.
Demand (capacity) related costs are allocated to rate schedules on the basis of each schedule
contribution to peak. demand. Customer related items are allocated to rate schedules based on the
number of customers within each schedule. The number of customers may be weighted by
appropriate factors such as relative cost of metering equipment. In addition to these three cost
components, any revenue related expense is allocated based on the proportion of revenues by rate
schedule.
Exhibit No. 16, Schedule I
T. Knox
~yis!3: Corporation
Page I of9
ELECTRIC COST OF SERVICE STUDY FLOWCHART
Pro Forma
Results of
Operations
Functionalization
Production Transmission
Distribution and
Customer
Relations Common
Energy
Commodity
Related
Demand
Capacity Related
Customer
Related
Direct Assignment
Generation Level mWh'
Customer Level mWh'
Residential Small General Extra Large
General
Pumping Street Area
Lights
Pro Forma Results of Operations by Customer Group
Exhibit No. 16, Schedule 1
T. Knox
A vista Corporation
Page 2 of9
The final step is allocation of the costs to the various rate schedules utilizing the allocation
factors selected for each specific cost item. These factors are derived from usage and customer
information associated with the test period results of operations.
BASE CASE COST OF SERVICE STUDY
Production and Transmission Classification (Peak Credit)
This study utilizes a Peak Credit methodology to classify production and transmission costs
into demand and energy classifications. The Peak Credit method acknowledges that baseload
production facilities provide energy throughout the year as well as capacity during system peaks
and likewise the transmission system is built not only for peak use, but also for everyday delivery
of energy. The demand/energy ratio is determined by the relationship of the current replacement
cost per kW generating capacity of the Company s peaking units to the current replacement cost
per kW generating capacity of the Company s thermal or hydro plant. The 2002 peak credit ratio
for thermal plant is 35.57% to demand and 64.43% to energy. The 2002 peak credit ratio for hydro
plant is 30.96% to demand and 69.04% to energy. The new plants included in pro forma results
have been incorporated in the 2002 calculations. Coyote Springs II has been included with the
thermal plant costs. Boulder Park and Kettle Falls CT have been included with the peaking units.
Transmission costs are classified by fifty-fifty weighting of the thermal and hydro peak
credit ratios resulting in the transmission peak credit ratio of 33.26% to demand and 66.74% to
energy. Fuel and load dispatching expenses are classified entirely to energy. Peaking plant related
costs are classified entirely to demand. Purchased Power and Other Power Supply expenses are
classified to demand and energy by the relative amounts of assigned and allocated Production Plant
in Service.
Exhibit No. 16, Schedule I
T. Knox
A vista Corporation
Page 3 of9
Production and Transmission Allocation
Production and transmission demand related costs are allocated to the customer classes by
class contribution to the average of the twelve monthly system coincident peak loads. Although
the Company is usually technically a winter peaking utility, it experiences high summer peaks and
careful management of capacity requirements is required throughout the year. The use of the
average of twelve monthly peaks recognizes that customer capacity needs are not limited to the
heating season.
Energy related costs are allocated to class by pro forma annual kilowatthour sales adjusted
for losses to reflect generation level consumption.
Distribution Facilities Classification (Basic Customer)
The Basic Customer method considers only services and meters and directly assigned
Street Lighting apparatus (FERC Accounts 369, 370, and 373 respectively) to be customer related
distribution plant. All other distribution plant is then considered demand related. This division
delineates plant which benefits an individual customer from plant which is part of the system. The
basic customer method provides a reasonable, clearly definable division between plant that
provides service only to individual customers from plant that is part of the interconnected
distribution network.
Customer Relations Distribution Cost Classification
Customer service, customer information and sales expenses are the core of the customer
relations functional unit which is included with the distribution cost category. For the most part
they are classified as customer related. Exceptions are sales expenses which are classified as
energy related and uncollectible accounts expense which is considered separately as a revenue
conversion item.Demand Side Management expenses recorded in Account 908 are also
considered separately from the other customer information costs.
Exhibit No. 16, Schedule 1
T. Knox
A vista Corporation
Page 4 of9
The demand side management investment and amortization are classified implicitly to
demand and energy by the sum of production plant in service, then allocated to rate schedules by
coincident peak demand and energy consumption respectively.
Distribution Cost Allocation
Distribution demand related costs which cannot be directly assigned are allocated to
customer class by the average of the twelve monthly non-coincident peaks for each class.
Distribution facilities that serve only secondary voltage customers are allocated by the non-
coincident peak excluding primary voltage customers. This includes line transformers, services
and secondary voltage overhead or underground conductors and devices. The Potlatch Lewiston
plant has been excluded from demand allocations of primary voltage overhead or underground
conductors and devices. This customer receives primary voltage power at the 115 kV substation
dedicated to them.
Most customer costs are allocated by average number of customers. Weighted customer
allocators have been developed using typical current cost of meters, estimated meter reading time
and direct assignment of billing costs for hand-billed customers. Street and area light customers
are excluded from metering and meter reading expenses as their service is not metered.
Administrative and General Costs
Administrative and general costs which are directly associated with production
transmission, distribution, or customer relations functions are directly assigned to those functions
and allocated to customer class by the relevant plant or number of customers. The remainder of
administrative and general costs are considered common costs, and have been left in their own
functional category. These common costs are classified by the implicit relationship of energy,
demand and customer within the four-factor allocator applied to them. The four-factor allocator
consists of a 25% weighting of each of the following: all operating & maintenance expenses
Exhibit No. 16, Schedule I
T. Knox
A vista Corporation
Page 5 of9
excluding administrative and general expenses; operating and maintenance labor expenses
excluding administrative and general labor expenses; net production, transmission, and distribution
plant; and number of customers. The use of this four-factor allocator is the only deviation from the
methodology accepted by the Idaho Public Utilities Commission for Avista in Case No. WWP-
98-11.
Revenue Conversion Items
In this study uncollectible accounts and commission fees have been classified as revenue
related and are allocated by pro forma revenue. These items vary with revenue and are included in
the calculation of the revenue conversion factor. Income tax expense items are allocated to
schedules by net income before income tax.
The following matrix outlines the methodology applied in the Company Base Case cost of
service study.
Exhibit No. 16, Schedule 1
T. Knox
Avista Corporation
Page 6 of 9
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o

P
e
a
k

C
r
e
d
i
t
DO

1
/
E
0
2

Co
i
n
c
i
d
e
n
t

P
e
a
k

D
e
m
a
n
d
/
A
n
n
u
a
l

G
e
n
e
r
a
t
i
o
n

L
e
v
e
l

C
o
n
s
u
m
p
t
i
o
n
DO
I
/
E
0
2

Co
i
n
c
i
d
e
n
t

P
e
a
k

D
e
m
a
n
d
/
A
n
n
u
a
l

G
e
n
e
r
a
t
i
o
n

L
e
v
e
l

C
o
n
s
u
m
p
t
i
o
n
DO
I
/
E
0
2

Co
i
n
c
i
d
e
n
t

P
e
a
k

D
e
m
a
n
d
/
A
n
n
u
a
l

G
e
n
e
r
a
t
i
o
n

L
e
v
e
l

C
o
n
s
u
m
p
t
i
o
n
DO
l

Co
i
n
c
i
d
e
n
t

P
e
a
k

D
e
m
a
n
d
DO
I
/
E
0
2
Co
i
n
c
i
d
e
n
t

P
e
a
k

D
e
m
a
n
d
/
A
n
n
u
a
l

G
e
n
e
r
a
t
i
o
n

L
e
v
e
l

C
o
n
s
u
m
p
t
i
o
n
00
2

No
n
-
c
o
i
n
c
i
d
e
n
t

P
e
a
k

D
e
m
a
n
d
00
3
1
0
0
4
1
0
0
5

Di
r
e
c
t

A
s
s
i
g
n

L
a
r
g
e

No
n
-
c
o
i
n
c
i
d
e
n
t

P
e
a
k

D
e
m
a
n
d

E
x
c
l

D
A
00
3
/
0
0
4
/
0
0
5

Di
r
e
c
t

A
s
s
i
g
n

L
a
r
g
e

No
n
-
c
o
i
n
c
i
d
e
n
t

P
e
a
k

D
e
m
a
n
d

E
x
c
l

D
A
00
6
/
0
0
7
/
0
0
8

N
o
n
-
c
o
i
n
c
i
d
e
n
t

Pe
a
k

D
e
m
a
n
d

P
r
i
m
a
r
y

Se
c
o
n
d
a
r
y

/

D
i
r
e
c
t

A
s
s
i
g
n

L
i
g
h
t
s
00
6
/
0
0
8

No
n
-
c
o
i
n
c
i
d
e
n
t

P
e
a
k

D
e
m
a
n
d

P
r
i
m
a
r
y

Se
c
o
n
d
a
r
y
00
6
/
0
0
8

No
n
-
c
o
i
n
c
i
d
e
n
t

P
e
a
k

D
e
m
a
n
d

P
r
i
m
a
r
y

/

S
e
c
o
n
d
a
r
y
00
6
/
0
0
8

No
n
-
c
o
i
n
c
i
d
e
n
t

P
e
a
k

D
e
m
a
n
d

P
r
i
m
a
r
y

Se
c
o
n
d
a
r
y
00
6

No
n
-
c
o
i
n
c
i
d
e
n
t

P
e
a
k

D
e
m
a
n
d

S
e
c
o
n
d
a
r
y
CO
2

Se
c
o
n
d
a
r
y

C
u
s
t
o
m
e
r
s

u
n
w
e
i
g
h
t
e
d

E
x
c
l

L
i
g
h
t
i
n
g
C0
4

Cu
s
t
o
m
e
r
s

w
e
i
g
h
t
e
d

b
y

C
u
r
r
e
n
t

T
y
p
i
c
a
l

M
e
t
e
r

C
o
s
t
C0
5

Di
r
e
c
t

A
s
s
i
g
n
m
e
n
t

t
o

S
t
r
e
e
t

a
n
d

A
r
e
a

L
i
g
h
t
s
S2
3

2
5
%

d
i
r
e
c
t

O
&
M
,

2
5
%

d
i
r
e
c
t

l
a
b
o
r
,

2
5
%

n
e
t

d
i
r
e
c
t

p
l
a
n
t
, 2
5
%

n
u
m
b
e
r

o
f

c
u
s
t
o
m
e
r
s
S2
3

2
5
%

d
i
r
e
c
t

O
&
M
, 2
5
%

d
i
r
e
c
t

l
a
b
o
r
,
2
5
%

n
e
t

d
i
r
e
c
t

p
l
a
n
t
,
2
5
%

n
u
m
b
e
r

o
f

c
u
s
t
o
m
e
r
s
DO
I
/
E
0
2

Co
i
n
c
i
d
e
n
t

P
e
a
k

D
e
m
a
n
d
/
A
n
n
u
a
l

G
e
n
e
r
a
t
i
o
n

L
e
v
e
l

C
o
n
s
u
m
p
t
i
o
n
DO
I
/
E
0
2

Co
i
n
c
i
d
e
n
t

P
e
a
k

D
e
m
a
n
d
/
A
n
n
u
a
l

G
e
n
e
r
a
t
i
o
n

L
e
v
e
l

C
o
n
s
u
m
p
t
i
o
n
S2
3

2
5
%

d
i
r
e
c
t

O
&
M
,

2
5
%

d
i
r
e
c
t

l
a
b
o
r
, 2
5
%

n
e
t

d
i
r
e
c
t

p
l
a
n
t
,

2
5
%

n
u
m
b
e
r

o
f

c
u
s
t
o
m
e
r
s
SO
I
/
S
0
2
/
S
2
3

Su
m

o
f

P
r
o
d
u
c
t
i
o
n

P
l
a
n
t

/

S
u
m

o
f

T
r
a
n
s
m
i
s
s
i
o
n

P
l
a
n
t

/

C
o
r
p

C
o
s
t

A
l
l
o
c
a
t
o
r
DO
I
/
E
0
2

Co
i
n
c
i
d
e
n
t

P
e
a
k

D
e
m
a
n
d
/
A
n
n
u
a
l

G
e
n
e
r
a
t
i
o
n

L
e
v
e
l

C
o
n
s
u
m
p
t
i
o
n
DO
I
/
E
0
2

Co
i
n
c
i
d
e
n
t

P
e
a
k

D
e
m
a
n
d
/
A
n
n
u
a
l

G
e
n
e
r
a
t
i
o
n

L
e
v
e
l

C
o
n
s
u
m
p
t
i
o
n
D0
2
/
O
0
3
/
O
0
4
/
O
0
5
/
O
0
6
/
O
O
7
/
O
0
8
/
C
0
2
/
C
0
4
/
C
0
5

-
S
e
e

R
e
l
a
t
e
d

P
l
a
n
t
S2
3

2
5
%

d
i
r
e
c
t

O
&
M
, 2
5
%

d
i
r
e
c
t

l
a
b
o
r
,

2
5
%

n
e
t

d
i
r
e
c
t

p
l
a
n
t
, 2
5
%

n
u
m
b
e
r

o
f

c
u
s
t
o
m
e
r
s
S
1
3

S
u
m

o
f

A
c
c
o
u
n
t

36
9

S
e
r
v
i
c
e
s

P
l
a
n
t
SO
I
l
S
0
2
/
S
0
3
/
S
0
4

Su
m
s

o
f

P
r
o
d
u
c
t
i
o
n

Tr
a
n
s
m
i
s
s
i
o
n

Dis
t
r
i
b
u
t
i
o
n

Ge
n
e
r
a
l

P
l
a
n
t
S2
3

2
5
%

d
i
r
e
c
t

O
&
M
,
2
5
%

d
i
r
e
c
t

l
a
b
o
r
.

2
5
%

n
e
t

d
i
r
e
c
t

p
l
a
n
t
.
2
5
%

n
u
m
b
e
r

o
f

c
u
s
t
o
m
e
r
s
SO
l

S
u
m

of

P
r
o
d
u
c
t
i
o
n

P
l
a
n
t
DO
l

Co
i
n
c
i
d
e
n
t

P
e
a
k

D
e
m
a
n
d
DO
I
/
E
0
2

Co
i
n
c
i
d
e
n
t

P
e
a
k

D
e
m
a
n
d
/
A
n
n
u
a
l

G
e
n
e
r
a
t
i
o
n

L
e
v
e
l

C
o
n
s
u
m
p
t
i
o
n
E0
2

An
n
u
a
l

G
e
n
e
r
a
t
i
o
n

L
e
v
e
l

C
o
n
s
u
m
p
t
i
o
n
DO
I
/
E
0
2

Co
i
n
c
i
d
e
n
t

P
e
a
k

D
e
m
a
n
d
/
A
n
n
u
a
l

G
e
n
e
r
a
t
i
o
n

L
e
v
e
l

C
o
n
s
u
m
p
t
i
o
n
Ex
h
i
b
i
t

N
o
,
16
,

S
c
h
e
d
u
l
e

I

Pa
g
e

7

o
f

9
T,

K
n
o
x
Av
i
s
t
a

C
o
r
p
o
r
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t
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o
n
IP
U
C

C
a
s
e

N
o
,

A
,

J
4
-
1 M
e
t
h
o
d
o
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o
g
y

M
a
t
r
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x
Av
i
s
t
a

U
t
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t
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e
s

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d
a
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o

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u
r
i
s
d
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o
n
El
e
c
t
r
i
c

C
o
s
t

o
f

S
e
I
V
i
c
e

M
e
t
h
o
d
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l
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g
y
Ac
c
o
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t
Pr
o
d
u
c
t
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o
n

O
&
M

(
c
o
n
t
i
n
u
e
d
)
Wa
t
e
r

f
o
r

P
o
w
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r

(
5
3
6
)
Ot
h
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r

(
C
o
y
o
t
e

S
p
r
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n
g
s
)
Ot
h
e
r

F
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l

(
5
4
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)
Ot
h
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r
Pu
r
c
h
a
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e
d

P
o
w
e
r

a
n
d

O
t
h
e
r

E
x
p
e
n
s
e
s

(
5
5
5

a
n
d

5
5
7
)
Sy
s
t
e
m

C
o
n
t
T
o
l

&

M
i
s
c

(
5
5
6

)
Tr
a
n
s
m
i
s
s
i
o
n

O
&
M
Al
l

T
r
a
n
s
m
i
s
s
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o
n
Di
s
t
r
i
b
u
t
i
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n

O
&
M
58
0

O
P

S
u
p
e
r

&

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n
g
i
n
e
e
r
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n
g
58
1

L
o
a
d

D
i
s
p
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t
c
h
i
n
g
58
2

S
t
a
t
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o
n

E
x
p
e
n
s
e
s
58
3

O
v
e
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a
d

L
i
n
e
s
58
4

U
n
d
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r
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u
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d

L
i
n
e
s
58
5

S
t
T
e
e
t

L
i
g
h
t
s
58
6

M
e
t
e
r
s
58
7

C
u
s
t
o
m
e
r

I
n
s
t
a
l
l
a
t
i
o
n
s
58
8

M
i
s
c

O
p
e
r
a
t
i
n
g

E
x
p
e
n
s
e
58
9

R
e
n
t
s
59
0

M
T

S
u
p
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r

&

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n
g
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n
e
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r
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n
g
59
1

M
T

o
f

S
t
r
u
c
t
u
r
e
s
59
2

M
T

o
f

S
t
a
t
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o
n

E
q
u
i
p
m
e
n
t
59
3

M
T

o
f

O
v
e
r
h
e
a
d

L
i
n
e
s
59
4

M
T

o
f

U
n
d
e
r
g
r
o
u
n
d

L
i
n
e
s
59
5

M
T

o
f

L
i
n
e

T
r
a
n
s
f
o
n
n
e
r
s
59
6

M
T

o
f

S
t
T
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e
t

L
i
g
h
t
s
59
7

M
T

o
f

M
e
t
e
r
s
59
8

M
i
s
c

M
a
i
n
t
e
n
a
n
c
e

E
x
p
e
n
s
e
Cu
s
t
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m
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r

A
c
c
o
u
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t
s

E
x
p
e
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s
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s
90

I

S
u
p
e
I
V
i
s
i
o
n
90
2

M
e
t
e
r

R
e
a
d
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g
90
3

C
u
s
t
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r

R
e
c
o
r
d
s

&

C
o
l
l
e
c
t
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o
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s
90
4

U
n
c
o
l
l
e
c
t
i
b
l
e

A
c
c
o
u
n
t
s
90
5

M
i
s
c

C
u
s
t

A
c
c
o
u
n
t
s
Cu
s
t
o
m
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r

S
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r
v
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e

&

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n
f
o

E
x
p
e
n
s
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s
90
7

S
u
p
e
I
V
i
s
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n
90
8

C
u
s
t
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m
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r

A
s
s
i
s
t
a
n
c
e
90
8

D
S
M

A
m
o
r
t
i
z
a
t
i
o
n

E
x
p
e
n
s
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s
90
9

A
d
v
e
r
t
i
s
i
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g
91
0

M
i
s
c

C
u
s
t

S
e
I
V
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c
e

&

I
n
f
o
Sa
l
e
s

E
x
p
e
n
s
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s
91
1

-
91
6
Fu
n
c
t
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a
l

C
a
t
e
g
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y
P
=

P
r
o
d
u
c
t
i
o
n
P
=

P
r
o
d
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c
t
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P
=

P
r
o
d
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c
t
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n
P
=

P
r
o
d
u
c
t
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n
P
=

P
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Sumcost AVISTA UTILrTlES Idaho Jurisdiction
Scenario: Company Base Case Cost of SelVice Basic Summary Electric Utility 01-21-
Last Idaho Method modified For The Twelve Months Ended December 31, 2002 5:37 Common Costs by 4-Factor
(b)(c)(d)(e)(I)
(g)
(h)(i)(k)(I)(m)
Residential General Large Gen Extra Large Potlatch Pumping Street &
System SelVice SelVice SelVice Gen SelVice Ex Lg Gen Svc SelVice Area UghtsDescriptionTola!Sch 1 Sch 11-Sch 21-Sch 25 Sch 25P Sch 31-Sch41-49Plant In SelVice
Production Plant 300,269 000 103,855,863 871 210 089,462 28,322636 527 729 560,417 041 683Transmission Plant 109,001 000 345,154 575 673 23,320 080 10,300,710 27,407 393 663 998 387 992
Distribution Plant 257643 000 124105,238 736 508 750,926 482,458 125.817 003 741 438.313
Intangible Plant 353 000 873,903 077 703 138,486 872,522 138,084 169,304 82,997General Plant 36,524 000 741 004 044 316 983,844 191 653 636,235 531 172 395Total Plant In SelVice 714790 000 288,921 161 305,411 162 282,798 169,979 110,835,257 928,631 346 762
Accum Depreciation
Production Plant (91 465,000)(31,590537)260,043)(19,529 251)(8,629 804)(22,746 584)390,227)(318,554)Transmission Plant (36,394 000)(12469,056)863,304)786268)(3,439 272)(9,150 968)(555587)(129,546)Distribution Plant (75640,000)(36,577375)422 128)(18,580254)(3.668 780)(546,491)458607)386,364). 10 Intangible Plant 893 000)(895714)(195,359)(332,276)(128 801)(295 660)(27,862)(17327)
General Plant (16,434 000)(8,432,528)819,743)(2,692,435)(986 136)(2,086.077)(239.001)(178080)Total Accumulated Depreciation (221 626 000)(89,965,210)(21 560,578)(48,920,484)(16,852 792)(34,825780)(3,671 285)(6,029871)
Net Plant 492964 000 198,955,952 744 833 113,362 314 40,317 187 76,009 477 257,346 316,891
Accumulated Deferred FIT (61 593,000)(24879,555)975,827)(14020,908)927 615)(9,509,603)029,678)249 815)Miscellaneous Rate Base 836,000 759 350 657 798 005,560 898,054 352,195 136,323 721Total Rate Base 440207 000 176835.747 42,426 805 101 346,966 36,287,625 68,852,070 363,992 093,797
Revenue From Retail Rates 146 248,000 648,000 212 000 804000 10,475,000 696,000 549,000 864 000Other Operating Revenues 677 000 581 432 1,750,744 658 197 022 208 226,957 332 207 105 256Total Revenues 167 925 000 60,229 432 962,744 462 197 12,497 208 922,957 881 207 969 256
Operating Expenses
Production Expenses 79,522 000 179,034 239 677 023454 518 503 20,060876 215,561 284,895Transmission Expenses 485 000 879,232 431 533 173,481 518338 379 158 83,733 19,524Distribution Expenses 495 000 827 125 875 891 724952 477 108 378 146,280 376,266Customer Accounting Expenses 296 000 174 073 712 481 196 952 870 96,200 053 370Customer Information Expenses 480 000 589 887 129 334 283641 124 152 326637 592 756Sales Expenses 421 000 134,538 672 91,568 311 115486 659 767Admin & General Expenses 888.000 836 014 941 128 118,583 126,716 378,876 266,972 219 712Total O&M Expenses 115 587,000 619,903 10,360 717 23,612 630 860,998 424611 791 851 916 290
Taxes Other Than Income Taxes 7,438,000 036 590 741 712 751 917 581 210 013,140 128 382 185 048Other Income Related Items
Depreciation Expense
Production Plant Depreciation 933 000 759,593 634 649 690,789 747420 953 357 120 107 085Transmission Plant Depreciation 532 000 867,496 199 206 541 706 239 277 636 650 653 013Distribution Plant Depreciation 670 000 695,437 696,191 1,413 966 299 955 654 108991 406,807General Plant Depreciation 892 000 997 043 430963 637,639 233 543 494 038 602 42,174Amortization Expense 367 000 134 172 004 216 225 83,910 401 073Total Depreciation Expense 394 000 8,453 740 992 012 361 315 554 419 216,609 329,754 486,151Income Tax 794 000 637 731 753707 507 372 77,499 660,861 97,725 105Total Operating Expenses 147 213,000 56,747 964 13,848 148 233 234 074 127 315,221 347 712 646594
Net Income 712 000 481 468 114596 228,962 423 081 607 736 533,495 322,661
Rate of Retum 71%1.97%70%12%1.17%24%24%55%Return Ratio 1.00 1.73Interest Expense 20,250 000 134,636 951 679 662 070 669 270 167270 338,752 326 322
Exhibit 16, Schedule 2
T. Knox
Avista Corporation
Page 1 of 59
Sumcost AVISTA UTilITIES Idaho Jurisdiction
Scenario: Company Base Case Revenue to Cost by Functional Component Summary Electric Utility 01-21-Last Idaho Method modified For The Twelve Months Ended December 31, 2002 5:37 PMCommon Costs by 4-Factor
(b)(c)(d)(e)(f)
(g)
(h)(i)(k)(I)(m)
Residential General Large Gen Extra Large Potlatch Pumping Street &
System Service Service Service Gen Service Ex 19 Gen Svc Service Area UghtsDescriptionTotalSch 1 Sch 11-12 Sch 21-Sch 25 Sch 25P Sch 31-Sch 41-49Funclional COSt Components at Current Relurn by Schedule
Production 85.030 709 26.937 592 561.501 825.853 287 948 729,421 385 361 303,033Transmission10.266 108 804366 102,389 743.178 716,319 678.128 185 670 36.058Distribution81558813,380998 282.818 946.702 368,641 830 327 689 197 316.905Common135.594 525044 265.292 288.267 102 091 458 124 288773 208.004Total Current Rate Revenue 146 248.000 648000 16.212 000 804000 10,475.000 696 000 549000 864 000
Expressed as $/kWh
Production $0,02722 $0,02725 $0,03356 $0,02941 $0,02400 $0,02497 $0,02832 $0,02334Transmission$0,00329 $0,00284 $0,00489 $0,00407 $0,00236 $0.00308 $0,00380 $0,00278Distribution$0,01019 $0,01354 $0,02345 $0,01327 $0,00451 $0,00095 $0,01409 $0,10143Common$0,00613 $0,00964 $0,01005 $0,00488 $0.00363 $0,00283 $0,00590 $0,01602Total Current Melded Rates $0,04682 $0,05327 $0,07195 $0,05162 $0,03449 $0,03183 $0,05210 $0,14357
Functional Cost Components at Uniform Current Return
Production 84.995.933 29,059.280 671 554 18.193 826 035535 432 482 299.010 304 247Transmission10.247 957 511 083 806.260 192486 968.443 576.763 156 444 36.478Distribution31.770.229 967035 083.325 148 181 845285 807 070 591.260 328 073Common19.233.881 869.188 129775 151.148 154.145 441 485 279,720 208,420Total Uniform Current Cost 146 248.000 58,406.586 690,913 30,685641 003.408 257,800 326 434 877 217
Expressed as $/kWh
Production $0.02721 $0,02940 $0.02961 $0,02699 $0,02646 $0.02463 $0,02655 $0,02343Transmission$0.00328 $0.00355 $0.00358 $0,00325 $0.00319 $0.00296 $0,00320 $0,00281Distribution$0,01017 $0,01615 $0,01812 $0,01060 $0,00608 $0,00093 $0,01209 $0,10229Common$0,00616 $0,00999 $0.00945 $0,00467 $0,00380 $0.00281 $0.00572 $0,01605Total Current Uniform Melded Rates $0.04682 $0.05909 $0,06076 $0,04552 $0,03952 $0.03133 $0.04755 $0,14459
Revenue to Cost Ralio al Current Rales 1.00 1.02
Functional Cost Components al Proposed Return by Schedule
Production 100 092428 072,414 818.163 23,112 922 691 711 431 302 616 977 348,940Transmission15,335.428 514 825 520,560 852 382 189 765 941 882 264,065 950Distribution45,261 090 19.639,911 976 641 569 282 263.699 120275 951 904 739.378Common20.781 054 10.357 851 2,456.637 564,414 199 825 665542 313053 223.732Total Proposed Rate Revenue 181,470000 66.585 000 19.772.000 43.099,000 13.345.000 33.159 000 146,000 364 000
Expressed as $/kWh
Production $0,03204 $0,03245 $0,03913 $0,03428 $0,02862 $0,02923 $0.03305 $0,02688Transmission$0,00491 $0,00457 $0,00675 $0,00571 $0,00392 $0,00453 $0,00540 $0,00400Distribution$0,01449 $0.01987 $0,03096 $0,01864 $0,00745 $0,00129 $0,01946 $0,13397Common$0,00665 $0,01048 $0,01090 $0,00529 $0,00395 $0.00306 $0,00640 $0.01723Total Proposed Melded Rates $0,05810 $0,06737 $0,08775 $0,06393 $0,04394 $0,03811 $0,06431 $0,18208
Funclional Cost Components at Uniform Requesled Return
Production 100.054 399 34,272 228 869 851 21,407 199 9,455 664 165,491 527 605 356.360Transmission15,316308 247 566 205 013 276.828 447 407 851 158 233 817 54.519Distribution217673321176698.494 689,565 750.099 459 850,541 807 662Common20.881 619 10.714 667 312,230 3,421 102 253.019 650.643 303,683 226.275Total Uniform Cost 181 470.000 555,636 085,588 38.794 695 906.867 766 751 915,646 444 816
Expressed as $/kWh
Production $0,03203 $0,03468 $0,03493 $0.03175 $0.03113 $0,02892 $0,03123 $0,02745Transmission$0,00490 $0,00531 $0.00535 $0,00486 $0,00477 $0,00443 $0,00478 $0,00420Distribution$0,01448 $0,02258 $0.02529 $0,01586 $0,00906 $0,00126 $0,01739 $0,13923Common$0,00669 $0,01084 $0.01026 $0,00507 $0,00413 $0,00305 $0,00621 $0,01743Total Uniform Melded Rates $0,05810 $0.07341 $0.07583 $0,05754 $0,04908 $0,03766 $0,05960 $0,18831
Revenue to Cosl Ralio at Proposed Rales 1.00 1.08
Exhibit 16, Schedule 2
T. Knox
Avisla Corporation
Page 2 of 59
Sumcost AVISTA UTILmES Idaho Jurisdiction
Scenario: Company Base Case Revenue to Cost By Classification Summary Electric Utility 01-21-
Last Idaho Method modified For The Twelve Months Ended December 31, 2002 5:37 PM
Common Costs by 4-Factor
(b)(c)(d)(e)(f)
(g)
(h)(i)(k)(I)(m)
Residential General Large Gen Extra Large Potlatch Pumping Street &
System Service Service Service Gen Service Ex Lg Gen Svc Service Area Ughts
Description Total Sch 1 Sch 11-Sch 21-Sch 25 Sch 25P Sch 31-Sch 4149
Cost Classifications at Current Return by Schedule
Energy 461 715 329 808 005,850 233035 234,867 20,130,814 225 176 302,164
Demand 771 862 908874 441 052 16.953258 198,434 549,781 103,945 616,518
Customer 15,014,423 409 318 765098 617707 698 405 219,879 945,318
Total Current Rate Revenue 146 248 000 648,000 16.212000 804000 10,475,000 696,000 549 000 864,000
Expressed as Unit Cost
Energy $/kWh $0.02320 $0.02158 $0.02665 $0,02556 $0,02053 $0.02314 $0,02504 $0,02327
Demand $/kW/mo $8,$7,$10,$9,$7,$5,$9,$15.
Customer $ICusVmo $11,$9,$14,$28,$248,283.$17,$634.
Cost Classifications at Uniform Current Return
Energy 72,300,675 104,938 267 397 15,725404 922 793 833 015 143 629 303,498
Demand 58,593,640 230,928 928 308 390017 037 271 409 441 975,161 622,513
Customer 353,665 070,720 2,495,208 570219 43,343 344 207 645 951 206
Total Unifo"" Currenl Cost 146,248,000 58,406,586 13,690,913 30,685641 12,003 408 27,257 800 326 434 877,217
Expressed as Unit Cost
Energy $/kWh $0,02315 $0.02338 $0,02338 $0,02333 $0,02279 $0,02279 $0.02338 $0,02338
Demand $/kW/mo $8,$9.$8,$7.$8.$5.$8,$15,
Customer $ICusVmo $12,$10,$12,$26,$258,278,$16,$638,
Revenue to Cost Ratio at Current Rates 1.18 1.13
Cost Classifications at Proposed Return by Schedule
Energy 86,110,679 25,625 923 048.596 20,269 570 526 611 23,843,437 443,911 352 631
Demand 008,115 949 091 577212 116,077 773,602 299,403 449,395 843,335
Customer 351 206 009.986 146,192 713,353 787 16,161 252,694 168033
Total Proposed Rate Revenue 181 470000 585000 772000 43,099,000 13,345 000 33,159,000 146,000 364,000
Expressed as Unit Cost
Energy $/kWh $0,02757 $0,02593 $0,03128 $0,03007 $0,02478 $0,02740 $0,02951 $0,02716
Demand $/kW/mo $10,$11.$13,$12,$9,$6,$12,$21,
Customer $ICusVmo $13.$11.44 $16,$33,$266,346,$20,$784,
Cost Classifications at Uniform Requested Return
Energy 948 754 466419 261 714 18,693,863 229 598 23,576,861 359,510 360 789
Demand 796,544 32,393,475 965,271 437 112 630,802 173,783 316,105 879 995
Customer 724 702 695.742 858,602 663,720 46,468 107 240 031 204 032
Total Unifo"" Cost 181,470,000 555,636 065,588 794 695 906,867 32,766,751 915,646 444 816
Expressed as Unit Cost
Energy $/kWh $0,02752 $0,02779 $0,02779 $0.02773 $0,02710 $0,02710 $0,02779 $0,02779
Demand $/kW/mo $10,$12,$11,$10.$11,$6,$11.09 $22,
Customer $ICusVmo $13,$12.$14,$30,$276,342,$19,$808.62
Revenue to Cost Ratio at Proposed Rates 1.00 1.11 1.08
Exhibit 16, Schedule 2
T, Knox
Avista Corporation
Page 3 of 59
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No
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7

D
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8

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2

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3
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3

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R
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4

W
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7
Pr
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37
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38
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38
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36
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38
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R
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39
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39
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40
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6

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a
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b
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In
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Pr
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9
AVISTA UTILITIES
Electric System . Idaho Jurisdiction
Alternate Scenario Summary Comparison
For The Twelve Months Ended December 31, 2002
Idaho Residential General large Gen Extra Large Potlatch PumPing Street &
Electric System Service Service Service Gen Service Ex Lg Gen Svc Service Area UghtsUne No Description Total Sch 1 Sch11-12 Sch 21.Sch 25 Sch 25P Sch 31.32 Sch 41-
Base Case Cost of Service Peak Credit Basic Customer Common 4-Factor
Production 85,030,709 937 592 561,501 19,825,853 287,948 729,421 385,361 303,033Transmission10,266 108 804 366 102 389 743,178 716,319 678,128 185,670 36,058Distribution815,588 380,998 282 818 946,702 368 641 830,327 689,197 316,905Common19,135 594 525,044 265,292 288 267 102 091 458,124 288,773 208,004Total Current Rate Revenue 146,248 000 648,000 16,212 000 804 000 10,475,000 696,000 549,000 864,000
Energy 72,461 715 21,329 808 005,850 17.233,035 234,867 130.814 225,176 302 164Demand77186220,908,874 7,441 052 953.258 198,434 549.781 103 945 616 518Customer01442310,409,318 765.098 617,707 698 15,405 219 879 945 318Total Current Rate Revenue 146,248,000 52,648.000 16.212.000 804 000 10,475 000 27.696.000 549 000 864 000
Rate Base 440,207,000 176,835,747 42,426.805 101 346 966 36.287,625 68.852 070 363.992 093.797Net Income 20,712 000 3,481,468 114 596 228 962 423.081 607.736 533,495 322.661
Rate of Return at Current Rates 71%1.97%70%12%17%24%24%55%Return Ratio 1.00 1.73 1.54
Alternate Scenario IPUC Case No, WWP.9B-11 last Case Method
Production 224 507 26,219,388 500,101 369,564 479 198 933,891 404 020 318346Transmission335,827 565,138 081 958 926,641 780 818 747 927 191 985 359Distribution756,649 505,608 200,061 545,880 490 578 846,342 710,360 457 821Common18,931 017 357 866 2.429,881 961 915 724.405 167 840 242,634 474Total Current Rate Revenue 146 248 000 648,000 16,212 000 34,804 000 10.475 000 27,696,000 549 000 864 000
Energy 137 582 21,134.260 057.578 18.045.329 551 983 20,759.048 264 672 324 713Demand345,868 17,200.956 627.613 16.071 654 888,378 928.006 016 344 612 918Customer19,764 550 312 784 526 809 687 018 639 946 267 984 926 370Total Current Rate Revenue 146.248,000 52,648.000 16,212.000 804 000 10,475,000 27,696 000 549,000 864.000
Rate Base 440 207000 179,025,294 602.643 958.332 35.854 395 68,532 638 314 442 919,256Net Income 712 000 866.344 984.888 253.290 742 654 843.365 570.046 451,411
Rate of Return at Current Rates 71%04%35%26%07%61%79%52%
Return Ratio 1.19 1.66 1.39
Change Alternative Case Less Base Case
Production 193798 (718204)(61 400)543 710 191 250 204.470 660 313Transmission719(239228)(20.431)183 463 64.499 799 315 301Distribution(58,939)(875,390)(82,757)599 178 121 937 014 163 140916Common(204 578)832 822 164,588 326,351)(377686)(290 284)(46.138)(161 530)Total Current Rate Revenue (0)(0)
Energy 675 867 (195.548)728 812 294 317,115 628,234 39.496 549Demand(6.425.994)(3,707,918)(813 439)(881.604)(310.056)(621 775)(87 601)(3,600)Customer 4,750,127 903,466 761,711 69.311 (7.059)(6.459)105 (18 949)Total Current Rate Revenue (0)(0)(0)(0)(0)(0)
Rate Base 189 548 175,838 388 633)(433,231)(319,432)(49 550)(174,540)Net Income (1,615,124)(129.708)024 328 319.573 235.629 36,551 128.750
Rate of Return at Current Rates 0.00%93%34%1.14%91%37%55%98%Return Ratio
Exhibit No, 16. Schedule 3
T. Knox
Avista Corporation
Page 1 of4
Sumcost AVISTA UTilITIES Idaho Jurisdiction Page 1 of 1
Scenario: Alternative Scenano Cost of Service Basic Summary Electric Utility 01-24-00
Case No WWP E-98.11 Method For The Twelve Months Ended December 31, 2002 8:56 PM
(b)(c)(d) (e)
(g)
(h)(i)(k)(I)(m)
Residential General Large Gen Extra Large Potlatch Pumping Street &
System Service Service Service Gen Service Ex 19 Gen Svc Service Area LightsDescriptionTotalSch 1 Sch 11-Sch 21-Sch 25 Sch 25P Sch 31-Sch 41-49Plant In Service
Production Plant 300,269,000 103,855,863 23,871 210 64,089,462 322 636 527,729 560,417 041,683
Transmission Plant 109,001,000 345,154 575,673 23,320 080 10,300,710 407 393 663,998 387,992Distribution Plant 257 643,000 124 105.238 31,736,508 66.750,926 15,482,458 125,817 003,741 12,438.313Intangible Plant 353,000 5,492.734 127,400 746,018 750,078 047,803 155,300 33,667
General Plant 36,524,000 623.872 356,142 521,290 1,423,377 069,766 443,301 86,253Total Plant In Service 714 790,000 293,422.860 666,934 159,427 775 279,259 110,178,507 11,826,757 13,987 908
Accum Depreciation
Production Plant (91,465.000)(31,590,537)(7,260.043)(19,529 251)629 804)(22 746,584)390,227)(318 554)
Transmission Plant (36,394,000)(12,469,056)(2.863,304)786 268)(3,439,272)(9,150,968)(555,587)(129,546)
Distribution Plant (75,640,000)(36,577 375)(9,422 128)(18,580,254)(3,668,780)(546,491)458,607)(5,386,364)Intangible Plant (1,893,000)(1,050,183)(207 764)(234,311)(98,237)(273,125)(24,367)(5,014)
General Plant (16,434,000)(10,179,627)960.049)584,407)(640449)(1.831 194)(199,464)(38,810)Total Accumulated Depreciation (221 826,000)(91,866,778)(21,713,289)(47,714,491)(16,476,542)(34,548,362)(3,628,252)(5,878,287)
13 Net Plant 492,964,000 201,556,083 47,953,645 111 713.284 39,802,717 75,630,146 198,505 109,62014 Accumulated Deferred FIT (61.593,000)(25.223,694)(6,003,464)(13 802,651)(4,859,523)(9,459,396)021,890)222,382)15 Miscellaneous Rate Base 836,000 692 906 652,462 047,699 911,200 361,888 137 827 017Total Rate Base 440,207 000 179,025,294 42,602,643 99,958 332 35,854 395 68,532,638 314,442 919,256
17 Revenue From Retail Rates 146,248,000 52,648,000 16,212,000 804,000 10,475,000 27,696,000 549,000 864,000
18 Other Operating Revenues 677 000 581,432 750,744 658,197 022,208 226 957 332 207 105,256Total Revenues 167 925 000 60,229,432 17,962,744 39,462 197 12,497 208 32,922 957 881,207 969,256
Operating Expenses
Production Expenses 79,522,000 179,034 239,677 023,454 518,503 20,060,876 215,561 284,895Transmission Expenses 5,485,000 879,232 431 533 173,481 518,338 379.158 83,733 19,524
Distribution Expenses 6,495,000 827.125 875,891 724 952 477 108 67,378 146,280 376,266Customer Accounting Expenses 296,000 174,073 712,481 196,952 55,870 96,200 51,053 370Customer Information Expenses 1,480,000 589,887 129,334 283,641 124 152 326,637 592 756Sales Expenses 421,000 134,538 30,672 568 40,311 115,486 659 767Admin & General Expenses 888.000 10,333.129 061,359 169 097 830,492 160,463 233,092 100,369
Total O&M Expenses 115,587,000 46,117 018 10,480,948 22,663,145 564,774 206,198 757,970 796,947
28 Taxes Other Than Income Taxes 7,438,000 036,697 741 720 751,850 581 189 013,125 128,379 185,040
29 Other Income Related Items
Depreciation Expense
Production Plant Depreciation 933,000 759 593 634 649 690,789 747,420 953,357 120,107 27,085Transmission Plant Depreciation 532,000 867,496 199,206 541 706 239.277 636,650 38,653 013Distribution Plant Depreciation 670,000 695,437 696 191 1,413,966 299,955 48,654 108,991 406,807General Plant Depreciation 892 000 410,801 464,191 375,229 151,675 433,675 238 191Amortization Expense 367,000 1 34. 172 004 77,216 34,225 910 5,401 073Total Depreciation Expense 20,394 000 867,498 025,240 098,905 1,472,552 156,246 320,391 453,16836 Income Tax 794,000 341 875 729,947 695 007 136,039 704,023 104,420 82,689Total Operating Expenses 147,213,000 58,363,088 13,977.856 208,907 754 553 29,079,592 311 161 517 844
38 Net Income 20,712,000 866 344 984,888 253.290 742,654 843,365 570,046 451,411
39 Rate of Return 71%1.04%35%26%07%61%79%52%
40 Return Ratio 1.00 1.99 1.97 1.19 1.66 1.3941 Interest Expense 20,250,000 235,358 959,768 598,192 649,341 152,576 336,472 318293
Exhibh No, 16, Schedule 3
T. Knox
Avista Corporation
Page 2 of4
Sumcost
Scenario: Altemative Scenario
Case No WWP E-98-11 Method
AVISTA UTilITIES Idaho Jurisdiction
Revenue to Cost by Functional Component Sumr Electric Utility
For The Twelve Months Ended December 31, 2002
(b)(c)(d) (e)(ij
SystemDescription 0 0 Total
Functional Cost Components at Current Return by ScheduleProduction 85,224 507Transmission 10,335,827Distribution 31 756,6494 Common 18 931 017
Total Current Rate Revenue 146.248,000
Expressed as $IkWh
Production
Transmission
Distribution
9 Common10 Total Current Melded Rates
$0.02728
$0,00331
$0,01017
$0,00606
$0.04682
Functional Cost Components at Uniform Current Return
11 Production 84,995,93312 Transmission 10,247,957
13 Distribution 31 770,22914 Common 19,233 88115 Total Unfform Current Cost 146,248,000
Expressed as $IkWh
16 Production
17 Transmission
18 Distribution
19 Common20 Total Current Unfform Melded Rates
$0.02721
$0.00328
$0.01017
$0.00616
$0.04682
21 Revenue to Cost Ratio at Current Rates
(g)
Residential
Service
Sch 1
26,219,388
565,138
505,608
357,866
648,000
$0,02653
$0.00260
$0.01265
$0.01149
$0.05327
29,059,280
511,083
15,967,035
913,943
60,451 341
$0,02940
$0.00355
$0.01615
$0.01205
$0.06116
1.00
Functional Cost Components at Proposed Return by Schedule
22 Production 100,300 846 31,291.41423 Transmission 15,410,453 4,254,681
24 Distribution 45,193,541 18,687,98325 Common 20.565,160 12,350,92326 Total Proposed Rate Revenue 181 470.000 66,585,000
Expressed as $IkWh
27 Production
28 Transmission
29 Distribution
30 Common31 Total Proposed Melded Rates
$0.03211
$0.00493
$0.01447
$0,00658
$0,05810
Functional Cost Components at Uniform Requested Return
32 Production 100,054 39933 Transmission 15,316,308
34 Distribution 45,217,67335 Common 20,881,61936 Total Unfform Cost 181,470,000
Expressed as $IkWh
37 Production
38 Transmission
39 Distribution
40 Common41 Total Unfform Melded Rates
$0,03203
$0,00490
$0.01448
$0.00669
$0,05810
42 Revenue to Cost Ratio at Proposed Rates
$0,03166
$0,00430
$0,01891
$0.01250
$0.06737
272 228
247 566
22,321,176
12,934,593
775,562
$0,03468
$0.00531
$0,02258
$0.01309
$0.07565
1.00
(h)
General
Service
Sch11-12
500,101
081,958
200,061
429,881
16,212,000
$0.03329
$0,00480
$0.02308
$0.01078
$0.07195
671,554
806,260
083,325
293,985
13,855,124
$0.02961
$0.00358
$0.01812
$0,01018
$0.06149
751 576
1,498,403
886,893
635,128
19,772,000
$0,03884
$0,00665
$0,03056
$0,01169
$0.08775
869,851
205,013
698,494
2,490,508
17,263,866
$0.03493
$0,00535
$0.02529
$0,01105
$0,07662
(ij
large Gen
Service
Sch 21-
0) (k) (I)
Extra Large Potlatch Pumping
Gen Service Ex 19 Gen Svc Service
Sch 25 Sch 25P Sch 31-
20,369,564
926,641
545,880
961 915
804,000
$0,03021
$0.00434
$0.01416
$0.00291
$0,05162
18,193,826
192,486
148,181
854,344
29,388,837
$0.02699
$0,00325
$0.01060
$0.00275
$0.04359
23,702,293
051 252
13,218,779
126,677
43,099 000
$0.03516
$0,00601
$0.01961
$0.00315
$0.06393
407 199
276,828
10,689,565
013,203
386,796
$0.03175
$0,00486
$0,01586
$0,00299
$0,05546
1.15
7,479,198
780,818
1,490,578
724 405
10,475,000
$0,02463
$0,00257
$0,00491
$0,00239
$0.03449
035,535
968,443
845,285
749,563
11,598,827
$0.02646
$0,00319
$0,00608
$0.00247
$0.03819
1.18
899,921
259,984
396,449
788,646
13,345,000
$0,02930
$0,00415
$0,00789
$0.00260
$0,04394
9,455,664
447,407
750,777
813,777
14,467,626
$0,03113
$0,00477
$0.00906
$0.00268
$0.04764
1.15
21,933,891
747,927
846,342
167,840
27,696,000
$0.02521
$0.00316
$0.00097
$0,00249
$0.03183
21,432,482
576,763
807,070
143,177
26,959,492
$0.02463
$0.00296
$0,00093
$0,00246
$0.03098
25,653,025
017 570
137,640
350,764
33,159,000
$0.02948
$0,00462
$0,00131
$0,00270
$0,03811
25,165,491
851,158
099,459
326,780
32,442,887
$0.02892
$0.00443
$0,00126
$0,00267
$0.03729
1,404,020
191.985
710,360
242,634
549,000
$0.02870
$0.00392
$0.01452
$0.00496
$0.05210
299,010
156,444
591,260
233,447
280,161
$0.02655
$0.00320
$0.01209
$0,00477
$0,04661
1.03
637 206
270,912
974,847
263 035
146,000
$0.03347
$0.00554
$0.01993
$0.00538
$0,06431
527,605
233,817
850,541
253 446
865,409
$0,03123
$0.00478
$0.01739
$0.00518
$0,05857
Exhibn No, 16, Schedule 3
T. Knox
Avista Corporation
Page 1 of 1
01-24-
8:56 PM
(m)
Street &
Area Lights
Sch 41-49
318,346
41,359
1,457 821
46,474
864,000
$0,02452
$0.00319
$0,11229
$0,00358
$0,14357
304 247
36,478
328,073
45,422
714 219
$0,02343
$0,00281
$0,10229
$0.00350
$0.13204
1.12 1.09
365,411
652
890,949
49,989
364,000
$0,02815
$0,00444
$0,14565
$0.00385
$0.18208
356,360
519
807 662
49,313
267 854
$0.02745
$0,00420
$0,13923
$0,00380
$0,17468
1.04
Page 3 014
Sumcost AVISTA UTilITIES Idaho Jurisdiction Page 1 of 1
Scenario: Alternative Scenario Revenue to Cost By Classification Summary Electric Utility 01-24-00
Case No WWP E-96-11 Method For The Twelve Months Ended December 31,2002 6:56 PM
(b)(c)(d) (e)(I)
(g)
(h)(i)(k)(I)(m)
Residential General large Gen Extra Large Poflatch Pumping Street &
System Service Service Service Gen Service Ex 19 Gen Svc Service Area Lights
Description Total Sch 1 Sch11-Sch 21-Sch 25 Sch 25P Sch 31-32 Sch 41-
Cost Classifications at Current Return by Schedule
Energy 137 562 21,134,260 057,576 16,045,329 551 963 759,046 264,672 324 713
Demand 52,345,666 17,200,956 627,613 16,071,654 886,376 928,006 016,344 612 918
Customer 19,764,550 14,312,764 526,809 687,018 34,639 946 267,964 926,370
Total Current Rate Revenue 146,248,000 52,646,000 16,212,000 34.804,000 10.475,000 696,000 549,000 864 000
Expressed as Unh Cost
Energy $IkWh $0.02373 $0,02138 $0.02688 $0.02677 $0,02157 $0,02366 $0.02585 $0.02501
Demand $IkW/mo $7,$6.$9,$8,$6,$4.$8.$15.Customer $/Custlmo $15,$13.$18,$32.$206,$745.$21.42 $622,
Cost Classifications at Uniform Current Return
Energy 73,706,844 23,530.128 364,330 16,018,432 068,823 20.251,373 164,674 309.063Demand132.346 21,521 065 258,895 12,749,629 4,494,400 699,202 864,101 545,054
10 Customer 20,406.610 15,400.146 231 699 620,776 35,604 917 251,365 860,062
Total Unfform Current Cost 146 246,000 60,451,341 13,855,124 386,637 596,827 26,959,492 260,161 714.219
Expressed as Unh Cost
12 Energy $IkWh $0,02360 $0.02381 $0.02361 $0.02376 $0.02326 $0.02326 $0.02361 $0.02361
13 Demand $IkW/mo $7,$6,$7.$7,$7,$4.$7,$13.
14 Customer $/Custlmo $15,$14.$16,$28,$211,$743,$20,$577,
15 Revenue to Cost Ratio at Current Rates 1.00 1.17 1.16 1.03 1.12 1.09
Cost Classifications at Proposed Return by Schedule
16 Energy 926,193 25,413,276 104 693 150,079 871,849 524 661 1,466,727 376,685
17 Demand 027,560 24,916,976 695,063 160,436 436,049 625,161 354,429 839,463
18 Customer 22,514 227 16,254 744 972 244 786,464 102 157 304 844 147,652
Total Proposed Rate Revenue 161,470,000 66,565,000 19,772 000 43,099,000 13,345,000 33,159,000 146,000 364,000
Expressed as Unh Cost
20 Energy $IkWh $0,02615 $0.02571 $0.03153 $0,03137 $0.02592 $0.02619 $0,03039 $0.02903
21 Demand $IkW/mo $9,$9.$12,$11.75 $9.$5,$11.41 $21.39
22 Customer $/Custlmo $17,$15.46 $20,$36,$220,$763,$24,$770,
Cost Classifications at Uniform Requested Return
23 Energy 67,475,366 926,035 366,952 011 994 366,137 24,031,056 362,356 366 653
24 Demand 70,761 720 29,451,462 238 510 656 193 041,423 6,402,699 195,532 795,900
25 Customer 212,692 17,396,065 656,404 716 606 36,065 130 267,519 105 101
Total Unfform Cost 161,470,000 74,775,562 263,666 366,796 14,467,626 442 667 665,409 267.654
Expressed as Unh Cost
27 Energy $IkWh $0.02600 $0.02626 $0,02626 $0.02620 $0.02762 $0,02762 $0,02826 $0.02826
26 Demand $IkW/mo $9.$11.19 $10.$9,$10.$5,$10.07 $20,
29 Customer $/Custlmo $16,$16,$16.$33.46 $226.$760.$22,$742,
30 Revenue to Cost Ratio at Proposed Rates 1.00 1.15 1.15 1.02 1.04
Exhibh No, 16, Schedule 3
T. Knox
Avista Corporation
Page 4 of4
DAVID J. MEYER
SENIOR VICE PRESIDENT AND GENERAL COUNSEL
A VISTA CORPORATION
O, BOX 3727
1411 EAST MISSION AVENUE
SPOKANE, WASHINGTON 99220-3727
TELEPHONE: [phone]
FACSIMILE: [phone]
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF A VISTA CORPORATION FOR THE
AUTHORITY TO INCREASE ITS RATES
AND CHARGES FOR ELECTRIC AND
NATURAL GAS SERVICE TO ELECTRIC AND
NATURAL GAS CUSTOMERS IN THE STATE~ IDAHO
CASE NO. A VU-04-
EXHIBIT NO. 17
TARA L. KNOX
FOR A VISTA CORPORATION
(NATURAL GAS)
SCHEDULE NO
SCHEDULE 4
SCHEDULE 5
PART
PART 2
PART 3
CASE NO. A VU-G-O4-
EXHIBIT 17
TABLE OF CONTENTS
DESCRIPTION PAGE
COST OF SERVICE PROCESS DESCRIPTION
Description
Methodology Matrix 7 -
NATURAL GAS BASE CASE COST OF SERVICE STUDY
SUMMARIES
General Summary
Summary by Function
Summary by Classification
CALCULATION MODEL
Calculation Model
Allocation Factors
Classification Tables
Labor Study
PRO FORMA RESULTS SEGREGATION
Operating Expenses
Rate Base
28 - 30
31 - 32
33 - 44
45 - 52
53 - 58
NATURAL GAS COST OF SERVICE STUDY
A cost of service study is an engineering-economic study, which apportions the revenue
expenses, and rate base associated with providing natural gas service to designated groups of
customers. It indicates whether the revenue provided by the customers recovers the cost to serve
those customers. The study results are used as a guide in determining the appropriate rate spread
among the groups of customers.
There are three basic steps involved in a cost of servIce study: functionalization
classification, and allocation. See flow chart.
First, the expenses and rate base associated with the natural gas system under study are
assigned to functional categories. The uniform system of accounts provides the basic segregation
into production, underground storage, and distribution.Traditionally customer accounting,
customer information, and sales expenses are included in the distribution function and
administrative and general expenses and general plant rate base are allocated to all functions. In
this study I have created a separate functional category for common costs. Administrative and
general costs that cannot be directly assigned to the other functions have been placed in this
category.
Second, the expenses and rate base items are classified into three primary cost components:
Demand, commodity or customer related. Demand (capacity) related costs are allocated to rate
schedules on the basis of each schedule s contribution to system peak demand. Commodity
(energy) related costs are allocated based on each rate schedule share of commodity
consumption. Customer related items are allocated to rate schedules based on the number of
customers within each schedule, The number of customers may be weighted by appropriate factors
such as relative cost of metering equipment. In addition to these three cost components, any
revenue related expense is allocated based on the proportion of revenues by rate schedule.
Exhibit No, 17, Schedule 4
T. Knox
Avista Corporation
Page 1 of 9
NATURAL GAS COST OF SERVICE STUDY FLOWCHART
Production
Purchased Gas
Cost
Underground
Storage
Distribution and
Customer Relations Common
Energy
Commodity
Related
Demand
Capacity Related
Customer Related
Residential Small General Interruptible
Pro Forma Results of Operations by Customer Group
Exhibit No. 17, Schedule 4
T. Knox
A vista Corporation
Page 2 of9
The final step is allocation of the costs to the various rate schedules utilizing the allocation
factors selected for each specific cost item. These factors are derived from usage and customer
information associated with the test period results of operations.
BASE CASE COST OF SERVICE STUDY
Production - Purchased Gas Costs
The Company has no natural gas production facilities serving the Idaho jurisdiction. The
natural gas costs included in the production function include the cost of gas purchased to serve
sales customers, pipeline transportation to get it to our system, and expenses of the gas supply
department. The demand and commodity components of account 804 have been determined
directly from the weighted average cost of gas (W ACOG) approved in the most recent purchased
gas adjustment (PGA) filing effective October 3 , 2003. The allocation of these costs agrees with
the gas costs computation used to determine pro forma results of operations. The expenses of the
gas supply department recorded in accounts 807 and 813 are classified as commodity related costs.
The gas scheduling process includes transportation customers, so estimated scheduling labor
expenses are allocated by throughput.The remaining gas supply department expenses are
allocated by sales volumes.
Underground Storage
Underground storage rate base, operating and maintenance expenses and offsetting gas
operating revenue from a long term capacity release to BC Gas are all classified as commodity
related and allocated to customer groups by annual throughput. The Company was specifically
instructed to utilize total annual throughput for underground storage costs in Order No. 22749
resolving Case No. WWP-88-
Exhibit No. 17, Schedule 4
T. Knox
Avista Corporation
Page 3 of9
Distribution Facilities Classification (Peak and Average)
Distribution mains and regulator station equipment (both general use and city gate stations)
are classified Demand and Commodity using the peak and average ratio for the distribution system.
Peak demand is defined as the average of the five-day sustained peaks from the most recent three
years. Average daily load is calculated by dividing annual throughput by 365 (days in the year).
The average daily load is divided by peak load to arrive at the system load factor of 48%. This
proportion is classified as commodity related. The remaining 52% is classified as demand related.
Meters, services and industrial measuring & regulating equipment are classified as customer
related distribution plant. Distribution operating and maintenance expenses are classified (and
allocated) in relation to the plant accounts they are associated with.
Customer Relations Distribution Cost Classification
Customer service, customer information and sales expenses are the core of the customer
relations functional unit which is included with the distribution cost category. For the most part
these costs are classified as customer related. Exceptions include uncollectible accounts expense
which is considered separately as a revenue conversion item, and Demand Side Management
amortization expense recorded in Account 908, The demand side management investment costs
and amortization expense are included with the distribution function and classified to demand and
commodity by the peak and average ratio.
Distribution Cost Allocation
Demand related distribution costs are allocated to customer groups (rate schedules) by each
groups' contribution to the three year average five-day sustained peak.Commodity related
distribution costs are allocated to customer groups by annual throughput. Distribution main
investment has been segregated into large and small mains. Small mains are defined as less than
four inches, with large mains being four inches or greater. The small main costs use the same
Exhibit No. 17, Schedule 4
T. Knox
Avista Corporation
Page 4 of 9
demand and commodity data, but large usage customers (Schedules 121 , 131 , and 146) have been
excluded from the allocations.
Most customer related costs are allocated by the annualized number of customers billed
during the test period. Meter investment costs are allocated using the number of customers
weighted by the relative current cost of meters in service at December 31 , 2002.Services
investment costs are allocated using the number of customers weighted by the relative current cost
of typical service installations. Industrial measuring and regulating equipment investment costs are
allocated by number of customers excluding the small usage customer groups (Schedules101 and
111 ).
Administrative and General Costs
General and intangible rate base items are allocated by the sum of Underground Storage
and Distribution plant. Administrative and general expenses are segregated into plant related
labor related, revenue related and other. The plant related items are allocated based on total plant
In servIce.Labor related items are allocated by operating and maintenance labor expense.
Revenue related items are allocated by pro forma revenue. Other administrative and general
expenses are allocated 50% by annual throughput (classified commodity related) and 50% by the
sum of operating and maintenance expenses not including purchased gas cost or administrative &
general expenses.Whenever costs are allocated by sums of other items within the study,
classifications are imputed from the relationship embedded in the summed items.
Special Contract Customer Revenue
Three special contract customers receive transportation service from the Company. Rates
for these customers were individually negotiated to cover any incremental costs and retain some
contribution to margin. The rates for these customers are not being adjusted in this case. The
revenue from these special contract customers has been segregated from general rate revenue and
Exhibit No, 17, Schedule 4
T. Knox
Avista Corporation
Page 5 of9
allocated back to all the other rate classes by relative rate base. In treating these revenues like
other operating revenues their system contribution reduces costs for all rate schedules.
Revenue Conversion Items
In this study uncollectible accounts and commission fees have been classified as revenue
related and are allocated by pro forma revenue. These items vary with revenue and are included in
the calculation of the revenue conversion factor. Income tax expense items are allocated to
schedules by net income before income tax less interest expense.
The following matrix outlines the methodology applied in the Company Base Case natural
gas cost of service study.
Exhibit No. 17, Schedule 4
T. Knox
A vista Corporation
Page 6 of9
IP
U
C

C
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Sum cost AVISTA UTILITIES Natural Gas UtilityCompany Base Case Cost of Service General Summary idaho Jurisdiction 19-
W A Accepted Methodology For The Twelve Months Ended December 31 2002 10:06 AM
(b)(c) (d) (e)(f)
(g)
(h)(i)(k)
Residential Small Firm Large Firm Interrupt Transport
System Service Service Service Service ServiceDescriptionTotalSch 101 Sch 111 Sch 121 Sch 131 Sch 146Plant In Service
Production Plant
Underground Storage Plant 041,000 611 517 915,988 167 002 48,956 297 537Distribution Plant 598 000 75,115,371 10,131,341 937 240 199.847 214 201Intangible Plant 766,000 651 012 91,325 123 055 12,485General Plant 943,000 050,507 708 711 70,840 15,961 96,981Total Plant in Service 99,348,000 84,428,406 11,847 365 184,205 266,819 621,204
Accum Depreciation
Production Plant
Underground Storage Plant (2.294 000)(1,643,487)(416,837)(75,998)(22,278)(135,400)Distribution Plant (26,397 000)(22 793,740)(2,880.654)(299,560)(63,624)(359,421)10 Intangible Plant (626,000)(531.990)(74 651)(7,462)(1,681)(10,215)
:J 1 General Plant (2,076.000)764,236)(247 566)(24 746)(5,576)(33,877)Total Accumulated Depreciation (31,393,000)(26,733 453)(3,619,709)(407,765)(93,160)(538,913)
13 Net Plant 955,000 694,953 227,656 776,440 173,660 082,29114 Accumlulated Deferred FIT (7,192 000)(6,111,941)(857,654)(85,727)(19,316)(117,362)15 Miscellaneous Rate Base 315,000 642,548 423,653 588 066 142,145Total Rate Base 63,078,000 53,225,560 793,655 775,301 176,410 107 074
17 Revenue From Retail Rates 51,396,000 114,000 931 000 522 000 385,000 444 00018 Other Operating Revenues 156,000 894,341 179,430 27,581 682 46,965Total Revenues 52,552 000 41,008,341 110,430 549,581 392 682 490,965
Operating Expenses
20 Purchased Gas Costs 35,803,000 27,300.352 924 182 262,412 312,556 3,497Underground Storage Expenses 134,000 96,001 24,349 4,439 301 90922 Distribution Expenses 207,000 895,249 222,617 40,382 744 40,00823 Customer Accounting Expenses 068,000 012,214 533 269 316 669
24 Customer Information Expenses 261,000 223,492 24,073 949 040 7,44625 Sales Expenses 234 000 231 645 279
26 Admin & General Expenses 812,000 128,853 462 574 710 753 119,110Total O&M Expenses 519,000 887,807 707 606 397,200 346,719 179,667
28 Taxes Other Than Income Taxes 876,000 744 738 104,327 10,395 337 14.20229 Depreciation Expense
30 Underground Storage Plant Depr 111 000 79,524 20,170 677 078 552Distribution Plant Depreciation 125.000 841,640 226,067 23,626 013 28,65332 General Plant Depreciation 358,000 304,237 42,692 267 961 84233 Amortization of Intangible Plant 260,000 220,954 005 099 698 243Total Depr & Amort Expense 854,000 2,446,355 319,934 670 751 45,29035 Income Tax 148 000 393,907 508,040 58,708 22,745 164,598Total Operating Expenses 49,397,000 38,472,807 639,908 500,974 379,553 403,757
37 Net Income 155,000 535,534 470,523 48,607 13,129 207
38 Rate of Retum 00%76%04%27%7.44%88%39 Retum Ratio
40 Interest Expense 902,000 448,723 358,559 35,669 116 50,933
Exhibit No, 17, Schedule 5 Page 1 of 58
T, Knox
Avista Corporation
Sumcost AVISTA UTILITIES Natural Gas Utility 1-04Company Base Case Summary by Function with Margin Analysis Idaho Jurisdiction 10:06 AMWA Accepted Methodology For The Twelve Months Ended December 31 . 2002
(b)(c) (d) (e)(f)
(g)
(h)(i)(k)
Residential Small Firm Large Firm Interrupt Transport
System Service Service Service Service ServiceDescriptionTotalSch 101 Sch 111 Sch 121 Sch 131 Sch 146
Functional Cost Components at Current Rates
1 Production 015 325 27,462.253 965 245 269 899 314.410 5182 Underground Storage (63,568)(123.032)764 298 061 3413 Distribution 059 198 206 192 383.578 157 963 42,224 269.2414 Common 385 045 568,587 562.413 88.841 24.304 140 901Total Current Rate Revenue 51,396,000 40,114,000 931 000 522,000 365.000 444.000
6 Exclude Cost of Gas w Revenue Exp,35,849 346 27.338 561 933.873 264,179 312,733Total Margin Revenue at Current Rates 15,546,654 12,775 439 997,127 257,821 72,267 444,000
Margin per Therm at Current Rates
8 Production $0,002333 $0,002426 $0,002426 $0,002426 $0,002426 $0,0008389 Underground Storage ($0.000893)($0.002413)$0.001529 $0,002247 $0.005877 $0,00722410 Distribution $0,155423 $0,180592 $0,107009 $0,067010 $0,061104 $0,06410711 Common $0,061626 $0.070003 $0,043498 $0.037687 $0,035171 $0,033549Total Current Margin Melded Rate per Therm $0.218488 $0.250607 $0.154463 $0,109371 $0.104578 $0.105718
Functional Cost Components at Uniform Current Return
13 Production 36.015,325 27.462.253 965 245 269.899 314.410 51814 Underground Storage (119 311)(85,478)(21 680)(3,953)(1.159)(7,Q42)15 Distribution 11,113,060 836,866 998 295 115,257 675 137.96816 Common 386,926 605.972 539,587 86,Q47 23.093 132,227Total Uniform Current Cost 51,396.000 40,819,613 481 447 467.250 361,019 266,67018 Exclude Cost of Gas w Revenue Exp,849.346 338,561 933.873 264.179 312,733Total Uniform Current Margin 15,546 654 13.481,052 547,575 203,071 285 266.670
Margin per Therm at Uniform Current Return
20 Production $0,002333 $0,002426 $0,002426 $0,002426 $0,002426 $0,00083821 Underground Storage ($0,001677)($0,001677)($0,001677)($0,001677)($0,001677)($0,001677)22 Distribution $0,156180 $0,192963 $0,077210 $0,048894 $0,035707 $0,03285123 Common $0,061653 $0,070736 $0,041733 $0,036502 $0,033418 $0,031484Total Current Uniform Margin Melded Rate per Therm $0.218488 $0,264449 $0.119693 $0.086146 $0.069874 $0.063495
25 Margin to Cost Ratio at Current Rates 1.66
Functional Cost Components at Proposed Rates
26 Production 014.861 27.461.865 965.178 269.892 314.408 51827 Underground Storage 234 101 529 163 15.099 892 41828 Distribution 265.920 12.792.476 889 291 203 210 51.739 329,20429 Common 635.119 781 130 592.369 799 961 144 860Total Proposed Rate Revenue 56,150,000 126,000 521 000 580.000 398 000 525,00031 Exclude Cost of Gas w Revenue Exp,35.848.885 27,338.175 933 806 264.172 312.732Total Margin Revenue at Proposed Rates 301,115 16,787 825 587,194 315,828 85,288 525,000
Margin per Therm at Proposed Rates
33 Production $0,002333 $0,002426 $0,002426 $0,002426 $0,002426 $0,00083834 Underground Storage $0,003290 $0,001776 $0,005736 $0,006405 $0.009973 $0,01129035 Distribution $0,214543 $0,250941 $0,146122 $0,086204 $0,074872 $0,07838536 Common $0,065141 $0,074172 $0,045815 $0,038943 $0,036121 $0,034492Total Proposed Margin Melded Rate per Therm $0,285306 $0.329315 $0.200100 $0.133979 $0.123393 $0.125004
Functional Cost Components at Uniform Proposed Return
38 Production 014.662 27.461 748 965,117 269.875 314.404 51839 Underground Storage 178 757 128,067 32,482 922 736 55140 Distribution 15.319.594 13.422.815 501.787 160.842 34,406 199,74441 Common 636.987 818.482 569,407 027 23.764 136.306Total Uniform Proposed Cost 56,150,000 831,111 068,793 525,667 374 310 350 11943 Exclude Cost of Gas w Revenue Exp.35.848.687 27,338 058 933 745 264.156 312.728Total Uniform Proposed Margin 20,301,313 17,493,053 135,047 261,511 61,583 350,119
Margin per Therm at Uniform Proposed Retum
45 Production $0.002333 $0,002426 $0,002426 $0,002426 $0,002426 $0,00083846 Underground Storage $0,002512 $0.002512 $0,002512 $0.002512 $0.002512 $0,00251247 Distribution $0,215297 $0,263306 $0,116152 $0,068231 $0,049789 $0,04756048 Common $0,065167 $0,074905 $0,044039 $0,037767 $0.034389 $0,032455Total Proposed Uniform Margin Melded Rate per Therm $0.285309 $0.343149 $0.165130 $0.110937 $0,089117 $0,083365
50 Margin to Cost Ratio at Proposed Rates
Exhibit No, 17. Schedule 5 Page 2 of 58
T, Knox
Avista Corporation
Sumcost AVISTA UTILITIES Natural Gas Utility
Company Base Case Summary by Classification with Unit Cost Analysis Idaho Jurisdiction 19-04
WA Accepted Methodology For The Twelve Months Ended December 31 , 2002 10:06 AM
(b)(c) (d) (e)(f)
(g)
(h)(i)(k)
Residential Small Firm Large Firm Interrupt Transport
System Service Service Service Service Service
Description Total Sch 101 Sch 111 Sch 121 Sch 131 Sch 146
Cost by Classification at Current Return by Schedule
1 Commodity 34,845 222 26,133,043 909,747 187 555 354.815 260.062
2 Demand 8.416,682 272.818 746,152 264 515 12,684 120 5133 Customer 134.096 708,139 275.102 929 17.501 63.425
Total Current Rate Revenue 51.396.000 40,114.000 931 000 522.000 385 000 444.000
Revenue per Therm at Current Rates
5 Commodity $0,489704 $0,512634 $0,534416 $0,503777 $0,513458 $0,061922
6 Demand $0,118285 $0.123050 $0,135052 $0,112211 $0,018356 $0,0286957 Customer $0,114314 $0,151205 $0,021277 $0,029665 $0.025326 $0,015102Total Revenue per Therm at Current Rates $0,722304 $0,786889 $0,690745 $0,645653 $0,557139 $0,105718
Cost per Unit at Current Rates
9 Commodity Cost per Therm $0,489704 $0,512634 $0,534416 $0,503777 $0,513458 $0,061922
10 Demand Cost per Peak Day Therms $20,$20,$26,$15,$5,$5,
11 Customer Cost per Customer per Month $11,$11,$40,$582,$729,$755,
Cost by Classification at Uniform Current Return
12 Commodity 685.437 340 553 680,749 162 884 340,892 160 35913 Demand 339.563 461 649 565 353 244.449 955 15614 Customer 371,000 018.129 234 888 59.862 13.147 975
Total Uniform Current Cost 51.396,000 40,820,331 8.480,990 467.195 360.994 266.490
Cost per Therm at Current Return
16 Commodity $0.487459 $0,516705 $0,516705 $0,493311 $0,493311 $0,03818217 Demand $0,117202 $0,126754 $0,121068 $0,103699 $0,010065 $0,01456118 Customer $0,117643 $0,157286 $0,018167 $0,025394 $0,019025 $0,010709
Total Cost per Therm at Current Return $0,722304 $0,800745 $0,655940 $0,622404 $0,522400 $0,063452
Cost per Unit at Uniform Current Return
20 Commodity Cost per Therm $0,487459 $0,516705 $0.516705 $0,493311 $0,493311 $0,03818221 Demand Cost per Peak Day Therms $20,$21.47 $23,$14,$2,$2,
22 Customer Cost per Customer per Month $11,$11.49 $34,$498,$547.$535,
23 Revenue to Cost Ratio at Current Rates
Cost by Classification at Proposed Return by Schedule
24 Commodity 401,540 27.310.182 209.810 213.643 362 349 305.55525 Demand 778 350 345 866 983,327 285.763 15,790 147 60326 Customer 970.110 9.469.952 327.862 593 19.861 71.841Total Proposed Rate Revenue 56.150 000 126 000 521 000 580,000 398,000 525,000
Revenue per Therm at Proposed Rates
28 Commodity $0,511576 $0,535725 $0,557624 $0,514844 $0.524361 $0.07275429 Demand $0,137422 $0,144099 $0,153395 $0,121225 $0,022850 $0,03514530 Customer $0,140117 $0,185766 $0,025358 $0,034189 $0.028741 $0,017106Total Revenue per Therm at Proposed Rates $0,789115 $0,865590 $0,736377 $0,670257 $0,575952 $0,125004
Cost per Unit at Proposed Rates
32 Commodity Cost per Therm $0,511576 $0,535725 $0,557624 $0,514844 $0.524361 $0,07275433 Demand Cost per Peak Day Therms $23,$24,$29,$17.$6,$6,34 Customer Cost per Customer per Month $14,$13,$47,$671,$827,$855,
Cost by Classification at Uniform Proposed Return
35 Commodity 241.863 27,517 639 979.292 189,096 348 576 207 25936 Demand 701 114 534 613 801 447 265.842 10.131 89.081
37 Customer 10.207 023 779.797 287.412 70.602 15.560 53,652Total Uniform Proposed Cost 56,150,000 44,832.049 068 152 525.539 374,267 349.993
Cost per Therm at Proposed Retum
39 Commodity $0,509332 $0,539795 $0,539795 $0.504431 $0,504430 $0,04934940 Demand $0,136337 $0,147801 $0,139328 $0,112774 $0,014661 $0,021211
41 Customer $0,143446 $0,191844 $0.022229 $0,029950 $0,022517 $0,012775Total Cost per Therm at Proposed Return $0,789115 $0,879440 $0,701352 $0.647155 $0.541608 $0,083335
Cost per Unit at Uniform Proposed Retum
43 Commodity Cost per Therm $0,509332 $0,539795 $0,539795 $0,504431 $0,504430 $0,04934944 Demand Cost per Peak Day Therms $23.$25,$27,$16,$4,$4,45 Customer Cost per Customer per Month $14,$14.$41.$588,$648,$638,
46 Revenue to Cost Ratio at Proposed Rates 1.08
Exhibit No, 17. Schedule 5 Page 3 of 58
1. Knox
Avista Corporation
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