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CASE NO. UWI-O4-
FIRST PRODUCTION REQUEST
OF UNITED WATER IDAIIO
TO COMMISSION STAFF
WORKP APERS TO
RESPONSE TO
REQUEST NO.
Preparer/Sponsoring Witness for Workpapers: Rick Sterling
Telephone Number: [phone]
Title: Staff Engineer
Line No.
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UNITED WATER IDAHO
Details of Adjustments to
Operations and Maintenance Expense
At Present Rates
Adjustment No.
Description
Adjustment of Purchased Power Expense
To adjust purchased power expense based on test year usage priced
at Idaho Power rates effective July 28 and December 1 , 2004; also
reflect for CWTP and RWPS
Details
Schedule 7 with and without franchise fee
Schedule 9 with and without franchise fee
Marden WTP repriced from 9P to 19
CWTP and RWPS projected consuptive power use
CWTP Redundant Power and Stand By Charge
Pro Forma Power Expense
10.Test Year Expense
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Exhibit No.
Healy
Schedule 1
Page 11 of 34
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C
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CA
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C
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C
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CA
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S
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6
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16
5
16
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6
6
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L
A
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S
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6
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10
3
10
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63
6
6
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L
A
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S
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16
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63
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6
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L
A
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R

S
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6
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4
15
6
0
15
6
0
,
69
,
16
2
63
6
6
6
0
6
4
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0

1
5
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0

L
A
T
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M
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R

S
T
/
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12
/
2
4
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0
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6
0
12
6
0
,
69
,
16
2
63
6
6
6
0
6
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15
0
0

LA
T
I
M
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R

S
T
/
B
O
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E
,
11
/
2
5
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2
0
0
3
66
0
66
0
,
66
,
16
2
63
6
6
6
0
6
4
0
0

1
5
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0

L
A
T
I
M
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R

S
T
/
B
O
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,
10
/
2
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2
0
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37
6
0
37
6
0
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10
5
10
5
,
16
2
63
6
6
6
0
6
4
0
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1
5
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0

L
A
T
I
M
E
R

S
T
/
B
O
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S
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,
9/
2
4
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2
0
0
3
97
2
0
19
4
4
,
77
7
6
,
16
1
36
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14
4
,
16
2
63
6
6
6
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6
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15
0
0

LA
T
I
M
E
R

S
T
/
B
O
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S
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61
2
5
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2
0
0
3
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6
0
66
6
0
,
16
2
16
2
.
16
2
63
6
6
6
0
6
4
0
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1
5
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0

L
A
T
I
M
E
R

S
T
/
B
O
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S
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,
7/
2
5
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2
0
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90
6
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6
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16
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16
0
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16
2
24
6
2
4
0
7
4
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5

1
5
7
6
1
/
2

N

G
A
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D
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N

S
T
/
B
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S
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,
26
6
9
26
6
9
,
33
,
24
6
2
4
0
7
4
0
5

1
5
7
6
1
/
2

N

G
A
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N

S
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/
B
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51
0
23
9
,
27
0
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16
.
4
16
,
24
6
2
4
0
7
4
0
5

1
5
7
6
1
/
2

N

G
A
R
D
E
N

S
T
/
B
O
I
S
E
,
5/1
4
/
2
0
0
4
24
1
9
24
1
9
,
31
,
24
6
2
4
0
7
4
0
5

1
5
7
6
1
/
2

N

G
A
R
D
E
N

S
T
/
B
O
I
S
E
,
I
D
4/1
5
/
2
0
0
4
66
0
66
0
,
32
,
24
6
2
4
0
7
4
0
5

15
7
6
1
/
2

N

G
A
R
D
E
N

S
T
/
B
O
I
S
E
,
3/1
6
(
,
W0
4
39
,
24
6
2
4
0
7
4
0
5

1
5
7
6
1
/
2

N

G
A
R
D
E
N

S
T
/
B
O
I
S
E
,
2/1
3
/
2
0
0
4
22
1
22
1
,
30
,
24
6
2
4
0
7
4
0
5

1
5
7
6

1
/
2

N

G
A
R
D
E
N

S
T
/
B
O
I
S
E
1/
1
4
/
2
0
0
4
25
,
24
6
2
4
0
7
4
0
5

1
5
7
6

1
/
2

N

G
A
R
D
E
N

S
T
/
B
O
I
S
E
12
/
1
5
/
2
0
0
3
69
,
30
,
24
6
2
4
0
7
4
0
5

1
5
7
6
1
/
2

N

G
A
R
D
E
N

S
T
I
B
O
I
S
E
,
I
D
11
/
1
4
/
2
0
0
3
69
9
69
9
,
35
,
24
6
2
4
0
7
4
0
5

1
5
7
6
1
/
2

N

G
A
R
D
E
N

S
T
/
B
O
I
S
E
,
10
/
1
5
/
2
0
0
3
36
6
9
36
6
9
,
31
,
24
6
2
4
0
7
4
0
5

1
5
7
6
1
/
2

N

G
A
R
D
E
N

S
T
/
B
O
I
S
E
,
9/
1
5
/
2
0
0
3
76
3
4
41
6
1
.
6
36
7
2
,
15
,
14
,
24
6
2
4
0
7
4
0
5

1
5
7
6
1
/
2

N

G
A
R
D
E
N

S
T
I
B
O
I
S
E
,
6/
1
4
/
2
0
0
3
72
3
3
72
3
3
.
37
,
67
0
5
7
3
2
6
6
15
7
6

N

G
A
R
D
E
N

S
T
/
B
O
I
S
E
,
52
4
4
0
52
4
4
0
,
64
,
67
0
5
7
3
2
6
6
15
7
6

N

G
A
R
D
E
N

S
T
/
B
O
I
S
E
,
19
0
4
0
69
2
5
,
10
1
1
5
.
44
,
49
,
67
0
5
7
3
2
6
6
15
7
6

N

G
A
R
D
E
N

S
T
/
B
O
I
S
E
,
5/
1
4
/
2
0
0
4
14
0
6
0
14
0
8
0
,
97
,
67
0
5
7
3
2
6
6
15
7
6

N

G
A
R
D
E
N

S
T
/
B
O
I
S
E
,
4/
1
5
/
2
0
0
4
60
,
67
0
5
7
3
2
6
6
15
7
6

N

G
A
R
D
E
N

S
T
/
B
O
I
S
E
,
3/
1
6
/
2
0
0
4
32
0
32
0
,
67
0
5
7
3
2
6
6
15
7
6

N

G
A
R
D
E
N

S
T
/
B
O
I
S
E
,
2/1
3
/
2
0
0
4
72
0
72
0
,
67
0
5
7
3
2
6
6
15
7
6

N

G
A
R
D
E
N

S
T
/
B
O
I
S
E
,
1/
1
4
/
2
0
0
4
52
0
52
0
.
67
0
5
7
3
2
6
6
15
7
6

N

G
A
R
D
E
N

S
T
i
B
O
I
S
E
12
/
1
5
/
2
0
0
3
24
0
24
0
,
2:0
67
0
5
7
3
2
6
6
15
7
6

N

G
A
R
D
E
N

S
T
/
B
O
I
S
E
11
/
1
4
/
2
0
0
3
12
0
12
0
,
67
0
5
7
3
2
6
6
15
7
6

N

G
A
R
D
E
N

S
T
/
B
O
I
S
E
,
10
/
1
5
/
2
0
0
3
40
,
67
0
5
7
3
2
6
6
15
7
6

N

G
A
R
D
E
N

S
T
/
B
O
I
S
E
,
9/1
5
/
2
0
0
3
47
2
0
0
25
0
7
5
,
22
1
2
5
,
44
,
39
,
67
0
5
7
3
2
6
6
15
7
6

N

G
A
R
D
E
N

S
T
/
B
O
I
S
E
,
61
1
4
/
2
0
0
3
51
4
6
0
51
4
6
0
.
67
,
96
6
2
6
0
6
4
0
0

1
6
4
9
E
B
E
R
G
E
S
O
N

S
T
/
B
O
I
S
E
,
56
6
4
0
47
3
6
6
,
94
7
3
,
70
,
14
,
96
6
2
6
0
6
4
0
0

1
6
4
9

E

B
E
R
G
E
S
O
N

S
T
/
B
O
t
S
E
5/
2
6
/
2
0
0
4
51
4
0
0
51
4
0
0
,
60
,
7/
2
.
1
96
8
2
6
0
6
4
0
0

1
6
4
9

E

B
E
R
f
'B
O
I
S
E
o
4/
2
7
/
2
0
0
4
48
0
8
0
48
0
8
0
,
96
8
2
6
0
6
4
0
0

1
6
4
9

E
B
E
R
l
BO
I
S
E
o
3/
2
9
/
2
0
0
4
56
9
2
0
56
9
2
0
,
96
8
2
6
0
6
4
0
0

1
6
4
9

E

B
E
r
flB
O
I
S
E
,
2/
2
6
1
2
0
0
4
46
9
6
0
46
9
6
0
,
96
8
2
6
0
6
4
0
0

1
6
4
9

E

B
f
ST
/
B
O
I
S
E
o
1/2
7
/
2
0
0
4
52
5
6
0
52
5
6
0
,
84
,
96
8
2
6
0
6
4
0
0

1
6
4
9

E

B
E
.
ST
/
B
O
I
S
E
,
12
/
2
6
1
2
0
0
3
49
2
4
0
49
2
4
0
,
(;
,
88
,
96
8
2
6
0
6
4
0
0

1
6
4
9

E

B
E
h
~
,
_.,
~ S
T
I
B
O
I
S
E
11
/
2
6
/
2
0
0
3
30
3
2
0
30
3
2
0
,
84
,
96
8
2
6
0
6
4
0
0

1
6
4
9

E

B
E
R
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E
S
O
N

S
T
/
B
O
I
S
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,
10
/
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7
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56
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7
6
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84
.
10
6
96
8
2
6
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4
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1
6
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9

E

B
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R
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S
O
N

S
T
/
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9/2
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4
6
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3
.
13
,
67
,
12
4
96
8
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6
0
6
4
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0

1
6
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9

E

B
E
R
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N

S
T
/
B
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8/2
6
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53
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5
2
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86
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6
96
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1
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9

E

B
E
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S
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7/2
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o
3
62
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90
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12
6
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7
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1
7
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8

R
I
V
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R
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5
.
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7
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8

R
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D
R
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68
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R
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T
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6
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T
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4

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A
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T

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T
A
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T

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9
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0
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19
8
19
8
.
19
9
24
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8
2
8
0
8
3
4

1
7
1
4

T
A
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G
A
R
T

S
T
f
B
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o
3/2
2
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2
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13
8
8
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13
8
8
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0
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19
5
19
5
,
19
9
24
2
8
2
8
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8
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4

1
7
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4

T
A
G
G
A
R
T

S
T
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2/2
0
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2
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8
8
0
13
3
8
8
0
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19
5
19
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24
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8
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1
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T
A
G
G
A
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T

S
T
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9
3
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3
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24
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8
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1
7
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T
A
G
G
A
R
T

S
T
I
B
O
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E
12
/
1
9
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2
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3
12
9
4
8
0
12
9
4
8
0
,
19
3
19
3
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19
9
24
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8
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8
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8
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4

1
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4

T
A
G
G
A
R
T

S
T
/
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O
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o
11
/
2
0
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2
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13
4
0
0
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13
4
0
0
0
,
19
5
19
5
,
19
9
24
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8
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8
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8
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4

1
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4

T
A
G
G
A
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T

S
T
/
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,
10
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.
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0
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19
8
19
8
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19
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24
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8
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8
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4

1
7
1
4

T
A
G
G
A
R
T

S
T
/
B
O
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E
9/
1
9
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13
4
4
8
0
49
3
0
9
,
85
1
7
0
.
19
7
.
7
2
,
12
4
,
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9
24
2
8
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8
0
8
3
4

1
7
1
4

T
A
G
G
A
R
T

S
T
/
B
O
I
S
E
,
8/
2
0
/
2
0
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3
13
1
3
6
0
13
1
3
6
0
.
19
8
19
8
,
19
9
67
3
3
9
4
3
5
5
17
7
0

N

F
I
S
K

S
T
/
B
O
I
S
E
61
9
2
0
61
9
2
0
.
96
,
67
3
3
9
4
3
5
5
17
7
0

N

F
I
S
K

S
T
I
B
O
I
S
E
,
33
6
8
0
14
7
3
5
,
18
9
4
5
,
41
,
53
,
67
3
3
9
4
3
5
5
17
7
0

N

F
I
S
K

S
T
/
B
O
I
S
E
,
5/
1
3
/
2
0
0
4
47
7
2
0
47
7
2
0
,
95
.
67
3
3
9
4
3
5
5
17
7
0

N

F
I
S
K

S
T
/
B
O
I
S
E
,
4/1
4
/
2
0
0
4
17
1
6
0
17
1
6
0
,
0
.
95
,
67
3
3
9
4
3
5
5
17
7
0

N

F
I
S
K

S
T
/
B
O
I
S
E
,
3/1
5
/
2
0
0
4
20
0
20
0
,
67
3
3
9
4
3
5
5
17
7
0

N

F
I
S
K

S
T
/
B
O
I
S
E
2/1
2
/
2
0
0
4
67
3
3
9
4
3
5
5
17
7
0

N

F
I
S
K

S
T
/
B
O
I
S
E
,
1/
1
3
/
2
0
0
4
32
0
32
0
.
67
3
3
9
4
3
5
5
17
7
0

N

F
I
S
K

S
T
/
B
O
I
S
E
,
12
/
1
2
/
2
0
0
3
80
.
90
,
67
3
3
9
4
3
5
5
17
7
0

N

F
I
S
K

S
T
/
B
O
I
S
E
11
/
1
3
/
2
0
0
3
16
5
2
0
16
5
2
0
,
93
,
67
3
3
9
4
3
5
5
17
7
0

N

F
I
S
K

S
T
/
B
O
I
S
E
,
10
/
1
4
/
2
0
0
3
53
8
0
0
53
8
0
0
,
94
,
67
3
3
9
4
3
5
5
17
7
0

N

F
I
S
K

S
T
/
B
O
I
S
E
,
9/1
2
/
2
0
0
3
54
1
2
0
32
4
7
2
.
21
6
4
8
,
56
,
37
,
67
3
3
9
4
3
5
5
17
7
0

N

F
I
S
K

S
T
f
B
O
I
S
E
8/1
3
/
2
0
0
3
59
6
8
0
59
6
8
0
.
94
,
97
6
2
5
0
8
0
0
2

2
0
1
0

E

P
A
R
K
C
E
N
T
E
R

B
L
V
D
/
B
O
I
S
E

o
lD

15
6
4
0
13
0
3
3
,
26
0
6
,
72
,
14
,
97
6
2
5
0
8
0
0
2

2
0
1
0

E

P
A
R
K
C
E
N
T
E
R

B
L
V
D
I
B
O
I
S
E
o
5/
2
6
/
2
0
0
4
17
5
6
0
17
5
6
0
,
86
,
97
6
2
5
0
8
0
0
2

2
0
1
0

E

P
A
R
K
C
E
N
T
E
R

B
L
V
D
/
B
O
I
S
E
,
4/
2
7
/
2
0
0
4
14
5
2
0
14
5
2
0
.
86
.
97
6
2
5
0
8
0
0
2

2
0
1
0

E

P
A
R
K
C
E
N
T
E
F
f

B
L
V
D
/
B
O
I
S
E
3/
2
9
/
2
0
0
4
20
0
20
0
.
97
6
2
5
0
8
0
0
2

2
0
1
0

E

P
A
R
K
C
E
N
T
E
R

B
L
V
D
/
B
O
I
S
E

o
lD

2/
2
6
/
2
0
0
4
17
6
0
17
6
0
,
97
6
2
5
0
8
0
0
2

2
0
1
0

E

P
A
R
K
C
E
N
T
E
R

B
L
V
D
/
B
O
I
S
E
1/
2
7
/
2
0
0
4
24
0
24
0
,
97
6
2
5
0
8
0
0
2

2
0
1
0

E

P
A
R
K
C
E
N
T
E
R

B
L
V
D
/
B
O
I
S
E
12
/
2
6
/
2
0
0
3
20
0
20
0
,
97
6
2
5
0
8
0
0
2

2
0
1
0

E

P
A
R
K
C
E
N
T
E
R

B
L
V
D
/
B
O
I
S
E
,
11
/
2
6
/
2
0
0
3
80
,
97
6
2
5
0
8
0
0
2

2
0
1
0

E

P
A
R
K
C
E
N
T
E
R

B
L
V
D
/
B
O
I
S
E

o
lD

10
/
2
7
/
2
0
0
3
15
8
8
0
15
8
8
0
,
88
,
97
6
2
5
0
8
0
0
2

2
0
1
0

E

P
A
R
K
C
E
N
T
E
R

B
L
V
D
/
B
O
I
S
E
9/2
5
/
2
0
0
3
23
2
8
0
38
8
0
,
19
4
0
0
,
11
,
59
,
97
6
2
5
0
8
0
0
2

2
0
1
0

E

P
A
R
K
C
E
N
T
E
R

B
L
V
D
/
B
O
I
S
E
,
8/2
6
/
2
0
0
3
19
8
8
0
19
8
8
0
,
75
,
97
6
2
5
0
8
0
0
2

2
0
1
0

E

P
A
R
K
C
E
N
T
E
R

B
L
V
D
/
B
O
I
S
E
,
7/2
8
/
2
0
0
3
21
8
8
0
21
8
8
0
.
79
,
28
9
0
0
2
2
8
4
8

2
0
1
1

M
A
N
I
T
O
U

A
V
E
/
B
O
I
S
E
,
88
4
0
67
7
7
,
20
6
2
,
21
,
28
9
0
0
2
2
8
4
8

2
0
1
1

M
A
N
I
T
O
U

A
V
E
/
B
O
I
S
E
,
51
2
4
/
2
0
0
4
13
9
2
0
13
9
2
0
,
29
,
28
9
0
0
2
2
8
4
8

2
0
1
1

M
A
N
I
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2
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2
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2
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8
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2
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4
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2
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A
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D
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6
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48
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5
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2
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3
1
3
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2
2
1
3

N

8
T
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S
T
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4
8
0
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.
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13
7
12
4
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12
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57
4
2
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3
1
3
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2
2
1
3

N

8
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S
T
/
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51
2
8
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2
0
0
4
23
6
8
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N.A
.
23
6
8
0
,
13
9
13
9
,
15
8
57
4
2
9
3
1
3
4
0

2
2
1
3

N

8
T
H

S
T
I
B
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E
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4/2
9
/
2
0
0
4
14
1
6
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14
1
6
0
,
88
,
15
7
57
4
2
9
3
1
3
4
0

2
2
1
3

N

8
T
H

S
T
I
B
O
I
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E
,
31
3
1
/
2
0
0
4
65
6
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65
6
0
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.
15
7
57
4
2
9
3
1
3
4
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2
2
1
3

N

8
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S
T
/
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1
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2
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0
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54
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A
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54
4
0
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22
,
15
7
57
4
2
9
3
1
3
4
0

2
2
1
3

N

8
T
H

S
T
/
B
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,
11
2
9
/
2
0
0
4
54
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N.
A
.
54
4
0
,
22
.
15
7
57
4
2
9
3
1
3
4
0

2
2
1
3

N

8
T
H

S
T
/
B
O
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S
E
,
I
D
12
1
3
0
1
2
0
0
3
54
4
0
54
4
0
,
21
,
15
7
57
4
2
9
3
1
3
4
0

2
2
1
3

N

8
T
H

S
T
/
B
O
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S
E
,
11
/
2
9
1
2
0
0
3
56
0
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56
0
0
,
21
.
0
15
7
57
4
2
9
3
1
3
4
0

2
2
1
3

N

8
T
H

S
T
I
B
O
I
S
E
10
1
2
9
1
2
0
0
3
23
7
6
0
23
7
6
0
,
13
6
13
6
,
15
7
57
4
2
9
3
1
3
4
0

2
2
1
3

N

8
T
H

S
T
/
B
O
I
S
E
91
2
9
/
2
0
0
3
26
5
6
0
24
9
0
,
24
0
7
0
,
13
1
12
,
11
8
,
15
8
57
4
2
9
3
1
3
4
0

2
2
1
3

N

8
T
H

S
T
/
B
O
I
S
E
,
8/
2
8
1
2
0
0
3
37
9
2
0
37
9
2
0
,
13
4
13
4
,
15
8
57
4
2
9
3
1
3
4
0

2
2
1
3

N

8
T
H

S
T
/
B
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S
E
,
71
3
0
1
2
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0
3
40
0
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40
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.
17
7
17
7
.
15
8
14
7
2
2
3
9
1
9
8

2
4
2
5

W

B
O
I
S
E

A
V
E
/
B
O
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S
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39
1
2
1
29
9
9
2
,
N.A
.
91
2
8
,
62
,
18
,
14
7
2
2
3
9
1
9
8

2
4
2
5

W

B
O
I
S
E

A
V
E
/
B
O
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S
E
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51
2
4
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2
0
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36
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5
9
36
1
5
9
.
80
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14
7
2
2
3
9
1
9
8

2
4
2
5

W

B
O
I
S
E

A
V
E
/
B
O
I
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E
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2
3
1
2
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0
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31
5
9
3
31
5
9
3
,
80
.
14
7
2
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3
9
1
9
8

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4
2
5

W

B
O
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S
E

A
V
E
/
B
O
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S
E
31
2
5
/
2
0
0
4
25
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6
1
N.A
.
25
6
6
1
.
79
,
14
7
2
2
3
9
1
9
8

2
4
2
5

W

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O
I
S
E

A
V
E
/
B
O
I
S
E
,
21
2
4
/
2
0
0
4
14
7
0
6
14
7
0
6
,
80
,
14
7
2
2
3
9
1
9
8

2
4
2
5

W

B
O
I
S
E

A
V
E
/
B
O
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S
E
,
11
2
3
1
2
0
0
4
53
6
53
6
,
14
7
2
2
3
9
1
9
8

2
4
2
5

W

B
O
I
S
E

A
V
E
/
B
O
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S
E
,
12
1
2
3
1
2
0
0
3
25
9
25
9
,
73
0
14
7
2
2
3
9
1
9
8

2
4
2
5

W

B
O
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S
E

A
V
E
/
B
O
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S
E
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I
D
11
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2
4
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0
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4
14
5
2
4
,
73
,
14
7
2
2
3
9
1
9
8

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4
2
5

W

B
O
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S
E

A
V
E
/
B
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10
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3
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2
0
0
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41
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8
6
41
2
8
6
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73
0
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7
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3
9
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9
8

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4
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5

W

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V
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/
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3
1
2
0
0
3
47
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4
8
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7
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34
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7
5
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20
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52
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3
9
1
9
8

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4
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5

W

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O
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E

A
V
E
/
B
O
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E
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2
2
1
2
0
0
3
47
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4
47
3
2
4
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72
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7
2
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3
9
1
9
8

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4
2
5

W

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O
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S
E

A
V
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/
B
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S
E
,
71
2
4
1
2
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51
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7
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51
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7
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60
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4
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6

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T

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D
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31
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91
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27
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4
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31
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93
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27
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4
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D
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27
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10
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8
4
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18
2
18
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27
0
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9
4
7
5
4
8
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3

2
4
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6

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N
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T

P
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A
D
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9
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50
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47
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5
.
45
6
7
5
.
27
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25
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24
4
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27
0
60
9
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4
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0
3

2
4
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6

S
U
N
S
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T

P
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K

A
D
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6
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62
5
6
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N.A
.
27
0
27
0
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27
0
60
9
4
7
5
4
8
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3

2
4
8
6

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N
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T

P
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A
D
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2
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68
4
8
0
68
4
8
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27
0
27
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27
0
41
5
5
9
6
4
6
0
8

2
5
9
9

W

V
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C
T
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A
D
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43
4
0
0
29
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5
6
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42
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41
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5
9
6
4
6
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8

2
5
9
9

W

V
I
C
T
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A
D
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2
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.
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8
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0
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62
,
.
4
1
5
5
9
6
4
6
0
8

25
9
9

W

V
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T
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.
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.
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J

1-
.
.
,
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5
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6
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9

W

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31
2
3
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0
4
56
0
56
0
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41
5
5
9
6
4
6
0
8

2
5
9
9

W

V
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C

I
30
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S
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2/2
3
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2
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24
0
24
0
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41
5
5
9
6
4
6
0
8

2
5
9
9

W

vl
r
-
D/B
O
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1/
2
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0"
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41
5
5
9
6
4
6
0
8

2
5
9
9

W

V
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1/B
O
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12
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2
2
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1
2
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, 4
5
,
41
5
5
9
6
4
6
0
8

2
5
9
9

W

V
I
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O
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2
1
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2
0
0
3
31
8
4
0
31
8
4
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47
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41
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5
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6
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6
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8

2
5
9
9

W

V
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L
.
.D
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2
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6
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33
1
6
0
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50
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41
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5
9
6
4
6
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8

2
5
9
9

W

V
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C
l
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,
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Y

R
D
/
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36
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2
5
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1
3
5
,
15
.
35
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41
5
5
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6
4
6
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8

2
5
9
9

W

V
I
C
T
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R
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R
D
/
B
O
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S
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8/2
1
/
2
0
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34
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8
0
34
2
8
0
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52
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41
5
5
9
6
4
6
0
8

2
5
9
9

W

V
I
C
T
O
R
Y

R
D
/
B
O
I
S
E
7/2
3
1
2
0
0
3
36
6
8
0
36
6
8
0
,
54
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18
0
0
9
6
4
0
3
9

2
7
4
6

N

L
A
K
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H
A
R
B
O
R

L
N
/
B
O
I
S
E
,
40
0
40
0
,
11
2
18
0
0
9
6
4
0
3
9

2
7
4
6

N

L
A
K
E

H
A
R
B
O
R

L
N
/
B
O
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S
E
,
40
0
26
.
37
3
.
11
2
18
0
0
9
6
4
0
3
9

2
7
4
6

N

L
A
K
E
H
A
R
B
O
R

L
N
/
B
O
t
S
E
,
5/3
/
2
0
0
4
67
2
0
67
2
0
,
11
4
11
4
,
11
2
18
0
0
9
6
4
0
3
9

2
7
4
6

N

L
A
K
E
H
A
R
B
O
R

L
N
/
B
O
I
S
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,
4/2
/
2
0
0
4
16
0
0
16
0
0
.
44
,
10
1
18
0
0
9
6
4
0
3
9

2
7
4
6

N

L
A
K
E
H
A
R
B
O
R

L
N
/
B
O
I
S
E
,
3/
3
/
2
0
0
4
24
0
0
24
0
0
,
10
1
18
0
0
9
6
4
0
3
9

2
7
4
6

N

L
A
K
E
H
A
R
B
O
R

L
N
/
B
O
I
S
E
,
2/
2
/
2
0
0
4
18
4
0
18
4
0
,
10
1
18
0
0
9
6
4
0
3
9

2
7
4
6

N

L
A
K
E
H
A
R
B
O
R

L
N
I
B
O
I
S
E
,
1/2
/
2
0
0
4
32
0
0
32
0
0
,
' 1
0
1
18
0
0
9
6
4
0
3
9

2
7
4
6

N

L
A
K
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H
A
R
B
O
R

L
N
/
B
O
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S
E
,
12
/
2
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2
0
0
3
12
0
0
12
0
0
.
10
1
18
0
0
9
6
4
0
3
9

2
7
4
6

N

L
A
K
E
H
A
R
B
O
R

L
N
/
B
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S
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10
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3
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0
0
3
32
0
32
0
,
10
1
18
0
0
9
6
4
0
3
9

2
7
4
6

N

L
A
K
E

HA
R
B
O
R

L
N
/
B
O
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S
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,
10
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2
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2
0
0
3
32
0
32
0
,
14
0
18
0
0
9
6
4
0
3
9

2
7
4
6

N

L
A
K
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H
A
R
B
O
R

L
N
I
B
O
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D
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86
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,
86
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17
3
18
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2
7
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6

N

L
A
K
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H
A
R
B
O
R

L
N
I
B
O
I
S
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,
8/
1
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0
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3
65
8
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8
4
0
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11
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11
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17
3
84
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6
3
7
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7
3

2
7
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9

L
A
M
P
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O
R
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B
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,
11
7
1
6
0
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36
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2
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6
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11
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50
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16
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84
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9
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3
7
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7
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2
7
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9

L
A
M
P
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D
R
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B
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5/2
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2
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0
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.
16
4
16
4
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16
9
84
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6
3
7
1
7
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2
7
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L
A
M
P
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R
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D
R
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B
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4/2
2
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2
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81
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4
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81
4
4
0
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16
5
16
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16
9
84
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3
7
1
7
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2
7
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L
A
M
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O
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B
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3/2
4
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50
1
6
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,
80
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16
9
84
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9
6
3
7
1
7
3

2
7
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9

L
A
M
P
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R
T

D
R
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B
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80
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16
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84
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7
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7
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2
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L
A
M
P
E
R
T

D
R
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B
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,
1/2
2
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4
51
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51
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0
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,
78
,
16
9
84
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9
6
3
7
1
7
3

2
7
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L
A
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D
R
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12
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2
2
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0
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51
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6
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51
3
6
0
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78
,
16
9
84
0
9
6
3
7
1
7
3

2
7
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9

L
A
M
P
E
R
T

D
R
/
B
O
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11
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2
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2
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77
.
16
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6
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7
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,
26
,
-
3
0
47
6
5
5
0
2
8
5
2

5
1
9
1

W
I
L
L
O
W

L
N
/
B
O
I
S
E
,
8/5
/
2
0
0
3
17
7
6
0
17
7
6
0
.
30
,
86
4
1
5
5
1
4
9
7

5
1
9
1

W
I
L
L
O
W

L
N
/
B
O
I
S
E
,
18
8
3
5
18
8
3
5
,
45
,
86
4
1
5
5
1
4
9
7

5
1
9
1

W
I
L
L
O
W

L
N
/
B
O
I
S
E
,
29
3
4
39
1
,
25
4
2
,
36
.
86
4
1
5
5
1
4
9
7
5
1
9
1

W
I
L
L
O
W
L
N
/
B
O
I
S
E
,
5/5
/
2
0
0
4
87
6
67
6
,
44
,
86
4
1
5
5
1
4
9
7

5
1
9
1

W
I
L
L
O
W

L
N
I
B
O
I
S
E
4/6
/
2
0
0
4
20
6
20
6
,
86
4
1
5
5
1
4
9
7

5
1
9
1

W
I
L
L
O
W

L
N
/
B
O
I
S
E
,
3/5
/
2
0
0
4
47
0
47
0
,
86
4
1
5
5
1
4
9
7

5
1
9
1

W
I
L
L
O
W

L
N
/
B
O
I
S
E
,
2/
4
/
2
0
0
4
15
2
15
2
,
86
4
1
5
5
1
4
9
7

5
1
9
1

W
I
L
L
O
W

L
N
I
B
O
I
S
E
,
1/5
/
2
0
0
4
86
4
1
5
5
1
4
9
7

5
1
9
1

W
I
L
L
O
W

L
N
/
B
O
I
S
E
,
12
/
4
/
2
0
0
3
86
4
1
5
5
1
4
9
7

5
1
9
1

W
I
L
L
O
W

L
N
/
B
O
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S
E
11
/
4
/
2
0
0
3
11
2
1
11
2
1
.
24
,
86
4
1
5
5
1
4
9
7

5
1
9
1

W
I
L
L
O
W

L
N
I
B
O
I
S
E
,
10
/
6
1
2
0
0
3
63
7
1
63
7
1
.
0
24
,
86
4
1
5
5
1
4
9
7

5
1
9
1

W
I
L
L
O
W

L
N
/
B
O
I
S
E
,
9/
4
/
2
0
0
3
49
8
1
8
49
6
1
6
,
45
.
31
2
3
7
4
4
8
2
7

5
3
2
4

C
L
I
N
T
O
N

S
T
/
B
O
I
S
E
,
I
O
37
0
0
0
37
0
0
0
,
93
,
31
2
3
7
4
4
8
2
7

5
3
2
4

C
L
I
N
T
O
N

S
T
/
B
O
I
S
E
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14
8
0
69
3
,
78
6
.
42
,
48
,
31
2
3
7
4
4
8
2
7

5
3
2
4

C
L
I
N
T
O
N

S
T
I
B
O
I
S
E
,
I
D
5/1
4
/
2
0
0
4
12
4
0
0
12
4
0
0
.
91
,
31
2
3
7
4
4
6
2
7

5
3
2
4

C
L
I
N
T
O
N

S
T
/
B
O
I
S
E
,
4/1
5
/
2
0
0
4
80
,
31
2
3
7
4
4
6
2
7

5
3
2
4

C
L
I
N
T
O
N

S
T
I
B
O
I
S
E
,
3/1
6
/
2
0
0
4
24
0
24
0
,
31
2
3
7
4
4
8
2
7

5
3
2
4

C
L
I
N
T
O
N

S
T
I
B
O
I
S
E
2/
1
3
/
2
0
0
4
32
0
32
0
,
31
2
3
7
4
4
6
2
7

5
3
2
4

C
L
I
N
T
O
N

S
T
/
B
O
I
S
E
,
1/1
4
/
2
0
0
4
12
0
12
0
,
31
2
3
7
4
4
6
2
7

5
3
2
4

C
L
I
N
T
O
N

S
T
I
B
O
I
S
E
,
12
/
1
5
/
2
0
0
3
80
.
31
2
3
7
4
4
6
2
7

5
3
2
4

C
L
I
N
T
O
N

S
T
I
B
O
I
S
E
,
11
/
1
4
/
2
0
0
3
12
0
12
0
,
31
2
3
7
4
4
6
2
7

5
3
2
4

C
L
I
N
T
O
N

S
T
/
B
O
I
S
E
,
10
/
1
5
1
2
0
0
3
80
,
40
,
J~

/'
2
.

9
31
2
3
7
4
4
8
2
7

5
3
2
4

C
U
N
T
O
~
'
9/1
5
1
2
0
0
3
30
0
4
0
15
9
5
8
,
14
0
8
1
,
51
,
31
2
3
7
4
4
8
2
7

5
3
2
4

C
U
N
T
O
I
\
8/1
4
/
2
0
0
3
59
6
8
0
59
6
8
0
,
94
.
48
7
2
1
0
1
8
~

5
6
0
0

N

FA
R
'
-
JI
S
E
,
96
6
8
0
96
6
8
0
,
13
8
13
8
,
14
6
48
7
2
1
0
1
8
~

5
6
0
0

N

FA
R
OI
S
E
,
83
8
8
0
30
7
5
6
,
53
1
2
4
,
13
8
50
.
1'.
4
14
6
48
7
2
1
0
1
8
~

5
6
0
0

N

FA
R
K:
H
S
E
51
1
2
/
2
0
0
4
81
5
6
0
N.
A
.
81
5
6
0
,
13
8
'
:
:
1
8
,
14
6
48
7
2
1
0
1
8
5
4

5
6
0
0

N

F
A
R
R
L
i
.
.

"
i
I
B
O
I
S
E
,
4/1
3
/
2
0
0
4
45
9
6
0
45
9
6
0
,
13
8
13
8
.
14
6
48
7
2
1
0
1
8
~

5
6
0
0

N

FA
R
R
O
W

S
T
/
B
O
I
S
E
.
l
D
3/1
2
1
2
0
0
4
92
4
0
I\
j
,
92
4
0
,
14
2
14
2
,
14
6
48
7
2
1
0
1
8
~

5
6
0
0

N
F
A
R
R
O
W

S
T
/
B
O
I
S
E
,
2/
1
1
/
2
0
0
4
~8
0
0
54
8
0
0
,
14
6
14
6
.
14
6
48
7
2
1
0
1
8
~

5
6
0
0

N F
A
R
R
O
W

S
T
/
B
O
I
S
E
,
1/1
2
1
2
0
0
4
49
7
2
0
49
7
2
0
,
14
5
14
5
,
14
6
48
7
2
1
0
1
8
~

5
6
0
0

N

FA
R
R
O
W

S
T
/
B
O
I
S
E
,
12
/
1
1
/
2
0
0
3
36
5
2
0
36
5
2
0
,
14
5
14
5
,
14
6
48
7
2
1
0
1
8
~

5
6
0
0

N

FA
R
R
O
W

S
T
/
B
O
I
S
E
11
/
1
2
/
2
0
0
3
51
5
2
0
51
5
2
0
.
14
5
14
5
,
14
6
48
7
2
1
0
1
8
~

5
6
0
0

N

FA
R
R
O
W

S
T
/
B
O
I
S
E
,
10
/
1
3
/
2
0
0
3
10
4
0
4
0
10
4
0
4
0
,
14
4
14
4
,
14
6
48
7
2
1
0
1
8
~

5
6
0
0

N F
A
R
R
O
W

S
T
/
B
O
I
S
E
,
9/
1
1
/
2
0
0
3
94
3
6
0
59
7
6
1
,
N.A
.
34
5
9
8
.
14
2
89
,
52
,
14
6
48
7
2
1
0
1
8
5
4

5
6
0
0

N

F
A
R
R
O
W

S
T
/
B
O
I
S
E
8/
1
2
1
2
0
0
3
86
7
2
0
86
7
2
0
,
14
3
14
3
,
14
6
72
1
4
3
8
8
5
1
8

6
0
2
8

K
I
R
K
W
O
O
D

C
I
R
I
B
O
I
S
E
,
13
7
4
6
13
7
4
6
,
22
,
72
1
4
3
8
8
5
1
8

6
0
2
8

K
I
R
K
W
O
O
D

C
I
R
/
B
O
I
S
E
,
14
1
3
5
75
3
8
,
65
9
6
,
11
,
10
,
72
1
4
3
8
8
5
1
8

6
0
2
8

K
I
R
K
W
O
O
D

C
I
R
I
B
O
I
S
E
,
5/
1
7
/
2
0
0
4
14
4
8
7
N.A
.
14
4
8
7
,
22
,
72
1
4
3
8
8
5
1
8

6
0
2
8

K
I
R
K
W
O
O
D

C
I
R
/
B
O
I
S
E
,
4/
1
6
/
2
0
0
4
37
1
9
37
1
9
,
23
,
72
1
4
3
8
8
5
1
8

6
0
2
8

K
I
R
K
W
O
O
D

C
I
A
/
B
O
I
S
E
,
3/1
7
/
2
0
0
4
61
7
61
7
,
72
1
4
3
8
8
5
1
8

6
0
2
8

K
I
R
K
W
O
O
D

C
I
R
/
B
O
I
S
E
,
2/1
7
/
2
0
0
4
99
8
99
8
,
72
1
4
3
8
8
5
1
8

6
0
2
8

K
I
R
K
W
O
O
D

C
I
R
/
B
O
I
S
E
,
1/
1
5
/
2
0
0
4
77
9
77
9
,
72
1
4
3
8
8
5
1
8

6
0
2
8

K
I
R
K
W
O
O
D

C
I
R
I
B
O
I
S
E
,
12
/
1
6
/
2
0
0
3
43
2
N.
A
.
43
2
.
72
1
4
3
8
8
5
1
8

6
0
2
8

K
I
R
K
W
O
O
D

C
I
R
/
B
O
I
S
E
,
11
/
1
7
/
2
0
0
3
30
8
30
8
,
72
1
4
3
8
8
5
1
8

6
0
2
8

K
I
R
K
W
O
O
D

C
I
R
/
B
O
I
S
E
,
10
/
1
6
/
2
0
0
3
13
7
7
3
13
7
7
3
,
22
,
72
1
4
3
8
8
5
1
8

6
0
2
8

K
I
R
K
W
O
O
D

C
I
R
/
B
O
I
S
E
;
I
D
9/1
6
/
2
0
0
3
1~
4
6
77
2
3
,
N.
A
.
77
2
3
,
11
,
11
.
0
72
1
4
3
8
8
5
1
8

6
0
2
8

K
I
R
K
W
O
O
D

C
I
A
/
B
O
I
S
E
.
l
D
8/1
5
1
2
0
0
3
11
0
4
5
11
0
4
5
,
23
,
71
8
2
9
2
1
1
3
3

6
2
2
5

F
E
D
E
R
A
L

W
A
Y
/
B
O
I
S
E
,
11
/
2
4
/
2
0
0
3
13
9
13
9
,
71
8
2
9
2
1
1
3
3

6
2
2
5

F
E
D
E
R
A
L

W
A
Y
/
B
O
I
S
E
,
10
/
2
3
/
2
0
0
3
14
0
14
0
,
71
8
2
9
2
1
1
3
3

6
2
2
5

F
E
D
E
R
A
L

W
A
Y
/
B
O
I
S
E
9/2
3
/
2
0
0
3
14
9
41
.
10
7
,
71
8
2
9
2
1
1
3
3

6
2
2
5

F
E
D
E
R
A
L

W
A
Y
/
B
O
I
S
E
,
8/2
2
/
2
0
0
3
22
0
22
0
,
71
8
2
9
2
1
1
3
3

6
2
2
5

F
E
D
E
R
A
L

W
A
Y
/
B
O
I
S
E
,
7/2
3
/
2
0
0
3
32
4
32
4
,
46
,
91
2
9
0
5
6
1
4
2

6
8
7
3

O
V
E
R
L
A
N
D

R
D
/
B
O
I
S
E
,
~6
7
9
~6
7
9
,
80
,
91
2
9
0
5
6
1
4
2

6
8
7
3

O
V
E
R
L
A
N
D

R
D
/
B
O
I
S
E
,
40
8
2
2
21
7
7
1
,
19
0
5
0
.
43
,
37
,
91
2
9
0
5
6
1
4
2

6
8
7
3

O
V
ER
L
A
N
D

R
D
/
B
O
I
S
E
,
5/1
7
/
2
0
0
4
45
9
5
9
45
9
5
9
,
81
,
91
2
9
0
5
6
1
4
2

6
8
7
3

O
V
E
R
L
A
N
D

R
D
/
B
O
I
S
E
,
4/1
6
/
2
0
0
4
11
7
3
2
11
7
3
2
,
80
,
91
2
9
0
5
6
1
4
2

6
8
7
3

O
V
E
R
L
A
N
D

R
D
/
B
O
I
S
E
,
3/1
7
/
2
0
0
4
93
1
93
1
,
80
,
91
2
9
0
5
6
1
4
2

6
8
7
3

O
V
E
R
L
A
N
D

R
D
/
B
O
I
S
E
,
2/1
7
/
2
0
0
4
79
6
79
6
,
91
2
9
0
5
6
1
4
2

6
8
7
3

O
V
E
R
L
A
N
D

R
D
/
B
O
I
S
E
,
1/1
5
1
2
0
0
4
54
4
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IDAHO POWER COMP ANY NINTH REVISED SHEET NO. 7-
CANCELS
EIGHTH REVISED SHEET NO. 7-
IDAHO PUBLIC UTILITIES COMMISSIONAPPROVED EFFECTIVEC. NO. 26, TARIFF NO, 101
MAY 11 'MAY 16
SCHEDULE 7
SMALL GENERAL SERVICE ~/?a.. J2. SECRETARY
AVAILABILITY
Service under this schedule is available at points on the Company s interconnected system within
the State of Idaho where existing facilities of adequate capacity and desired phase and voltage are
adjacent to the Premises to be served,
APPLICABILITY
Service under this schedule is applicable to Electric Service supplied to a Customer at one Point
of Delivery and measured through one meter. This schedule is applicable to Customers with energy
loads that are 3,000 kWh, or less, per month for ten or more months during the Annual Review Period.
This schedule is also applicable to non-profit or tax supported ball fields, fairgrounds or rodeo grounds
with high demands and intermittent use exceeding 3,000 kWh per month, This schedule is not
applicable to standby service, service for resale, or shared service, or to individual or multiple family
dwellings first served through one meter after February 9, 1982.
TYPE OF SERVICE
The type of service provided under this schedule is single and/or three-phase, at approximately
60 cycles and at the standard service voltage available at the Premises to be served.
ANNIVERSARY DATE
The Anniversary Date is the date on which service is initially taken under this schedule.
ANNUAL REVIEW PERIOD
The Annual Review Period is the 12-month period ending with the Billing Period in which the
Customer s Anniversary Date falls. Each yeaL at the end of the Annual Review Period, each Customer
account will be reviewed for continued service eligibility under this schedule. Customers who qualify for
service under a different schedul~ will be transferred to the appropriate schedule effective with the
next Billing Period. The accounts of new Customers or Customers whose load characteristics are
experiencing fundamental changes may be reviewed more frequently,
MONTHLY CHARGE
The Monthly Charge is the sum of the Customer and the Energy Charges at the following rate~:
'-'::"~
;~:ji;ii~.
~~\O
~:/
;:;:(;er month \~ ~\ t\~\
, ~~: r
" ;
; i
f. ~'
.; ~t~
Base Rate
9649~
Power Cost
Adiustment*
1371~
Revenue Sharing
Adiustmen
~O,0371 ).~
Effective
Rate
0649~ per kWh for a k"fh .' &C
j. '" \:. ',,'
Wi. f~\'c J '
,," r \) n'EnerQY _qLQe
IDAHO
Issued - May 10, 2000
Effective - May 16, 2000
Issued by IDAHO POWER COMPANY
James C, Miller, Senior Vice President, Delivery
1221 West Idaho Street Boise, Idaho
IDAHO POWER COMPANY TENTH REVISED SHEET NO. 7-
CANCELS
NINTH REVISED SHEET NO. 7-
:~~6~~~ C UTI UTI ES ~9~M ISSrONl..trt-tCTIVE
I.P.C. NO. 26, TARIFF NO. 101
APR .3 0 ' 0 1 MAY 1
SCHEDULE 7
SMALL GENERAL SERVICE ~~tO.~J.,f SECRETARY
AVAILABILITY
Service under this schedule is available at points on the Company s.intercE)nnected system within
the State of Idaho where existing facilities of adequate capacity and desired phase and voltage are
adjacent to the Premises to be served.
APPLICABILITY
Service under this schedule is applicable to Electric Service supplied to a Customer at one Point
of Delivery and measured through one meter. This schedule is applicable to Customers with energy
loads that are 3,000 kWh, or less, per month for ten or more months during the Annual Review Period.
This schedule is also applicable to non-profit or tax supported ball fields, fairgrounds or rodeo grounds
with high demands and intermittent use exceeding 3,000 kWh per month. This schedule is not
applicable to standby service, service for resale, or shared service, or to individual or multiple family
dwellings first served through one meter after February 9, 1982.
TYPE OF SERVICE
The type of service provided under this schedule is single and/or three-phase, at approximately
60 cycles and at the standard service voltage available at the Premises to be served.
ANNIVERSARY DATE
The Anniversary Date is the date on which service is initially taken under this schedule.
ANNUAL REVIEW PERIOD
The Annual Review Period is the 12-month period ending with the Billing Pefiod in which the
Customer s Anniversary Date falls. Each year, at the end of the Annual Review Period, each Customer
account will be reviewed for continued service eligibility under this schedule, Customers who qualify for
service under a different schedule will be transferred to the appropriate schedule effective with the
next Billing Period, The accounts of new Customers or Customers whose load characteristics are
experiencing fundamental changes may be reviewed more frequently.
MONTHLY CHARGE
The Monthly Charge is the sum of the Customer and the Energy Charges at the following rates:
Energy Charge
. .
%. r-: hf\;~ ~i~l ttl
~~:, ~!~~:, '
~r1\n ~ q.t;,jI ;,~ ~". Wi c;" :,:",,
, ~," -
tz 1\ 1~, \:;1 '~:": ~L t, V:"
Customer Charge
$2.51 per meter per month
Base Rate
96491t
Power Cost
Adiustment*
1.34 1 51t
Effective
Rate
30641t per kWh for all kWh
'1 n 1"1 "
""'
;oA LljtJ j
.....\,~, ,
i'\
). ~.
II. - . '~ i
\ '" j
\.1
IDAHO
Issued Per IPUC Order No. 28722
Effective - May 1,2001
Issued by IDAHO POWER COMPANY
John R. Gale, Vice President, Regulatory Affairs
1221 West Idaho Street Boise, Idaho
IDAHO POWER COMPANY ELEVENTH REVISED SHEET NO. 7-
CANCELS IDAHO PUBLIC UTIUTIES COMMISSION
TENTH REVISED SHEET NO. 7-1' APPROVED EFFECTIVEI.P.C. NO. 26, TARIFF NO.1 01
SEP27 OCT 1 - ' 0 1
SCHEDULE 7
SMALL GENERAL SERVICE ~JfJ.~ SECRETARY
AVAILABILIN
Service under this schedule is available at points on the Company s interconnected system within
the State of Idaho where existing facilities of adequate capacity and desired phase and voltage are
adjacent to the Premises to be served.
APPLICABILIN
Service under this schedule is applicable to Electric Service supplied to a Customer at one Point
of Delivery and measured through one meter. This schedule is applicable to Customers with energy
loads that are 3,000 kWh, or less, per month for ten or more months during the Annual Review Period.
This schedule is also applicable to non-profit or tax supported ball fields, fairgrounds or rodeo grounds
with high demands and intermittent use exceeding 3,000 kWh per month. This schedule is not
applicable to standby service, service for resale, or shared service, or to individual or multiple family
dwellings first served through one meter after February 9, 1982,
NPE OF SERVICE
The type of service provided under this schedule is single and/or three-phase, at approximately
60 cycles and at the standard service voltage available at the Premises to be served.
ANNIVERSARY DATE
The Anniversary Date is the date on which service is initially taken under this schedule.
ANNUAL REVIEW PERIOD
The Annual Review Period is the 12-month period ending with the Billing Period in which the
Customer s Anniversary Date falls. Each year, at the end of the Annual Review Period, each Customer's
account will be reviewed for continued service eligibility under this schedule. Customers who qualify for
service under a different schedule will be transferred to the appropriate schedule effective with the
next Billing Period. The accounts of new Customers or Customers whose load characteristics are
experiencing fundamental changes may be reviewed more frequently.
MONTHLY CHARGE
The Monthly Charge is the sum of the Customer and the Energy Charges at the following rates:
\iltUl I
i; i. ,:jIj
" ,
It, ~J "
~\ ~
' (ill.; ~~ "~~' l t;f
" \~'~\:"
\!i:"
~' ":"'
;bo'
~ ~j1 (~lJ ~t:~ i'Iii ,~
"~~
Customer Charge
$2.51 per meter per month
Energy Charge
~ '
t~; 'i).1, '\fit,
Base Rate
9649C::
Power Cost
Adiustment*
1 ,7241 c::
Effective
Rate *
6890C:: per kWh for all kWh
Mf\'( 1 6 2.002
~.~.
IDAHO
Issued Per IPUC Order No. 28852
Effective - October 1, 2001
Issued by IDAHO POWER COMPANY
John R. Gale, Vice President, Regulatory Affairs
1221 West Idaho Street, Boise, Idaho
IDAHO POWER COMPANY THIRTEENTH REVISED SHEET NO. 7-IDAHO PUBLIC UTILITIES COMMISSION
CANCELS Approved Effective
TWELFTH REVISED SHEET NO. 7-May 16, 2003 May 16 , 2003
Per O.N. 29243
Jean D. Jewell Secretary
SCHEDULE 7
SMALL GENERAL SERVICE
LP .C. NO. 26, TARIFF NO.1 01
AVAILABILITY
Service under this schedule is available at points on the Company s interconnected system withinthe State of Idaho where existing facilities of adequate capacity and desired phase and voltage are
adjacent to the Premises to be served,
APPLICABILITY
Service under this schedule is applicable to Electric Service supplied to a Customer at one Point
of Delivery and measured through one meter. This schedule is applicable to Customers with energy
loads that are 3,000 kWh, or less, per month for ten or more months during the Annual Review Period.
This schedule is also applicable to non-profit or tax supported ball fields, fairgrounds or rodeo grounds
with high demands and intermittent use exceeding 3,000 kWh per month. This schedule is not
applicable to standby service, service for resale, or shared service, or to individual or multiple family
dwellings first served through one meter after February 9, 1982.
TYPE OF SERVICE
The type of service provided under this schedule is single and/or three-phase, at approximately
60 cycles and at the standard service voltage available at the Premises to be served.
ANNIVERSARY DATE
The Anniversary Date is the date on which service is initially taken under this schedule.
ANNUAL REVIEW PERIOD
The Annual Review Period is the 12-month period ending with the Billing Period in which the
Customer s Anniversary Date falls. Each year, at the end of the Annual Review Period, each Customer
account will be reviewed for continued service eligibility under this schedule. Customers who qualify for
service under a different schedule will be transferred to the appropriate schedule effective with the
next Billing Period, The accounts of new Customers or Customers whose load characteristics are
experiencing fundamental changes may be reviewed more frequently,
MONTHLY CHARGE
The Monthly Charge is the sum of the Customer and the Energy Charges at the following rates:
Customer CharGe
$2.51 per meter per month
'" ':;!
t;~,i!~ r~ ""~~t\J
~ ~' '
'. ~iJa ;iS
\~ '
1;:1
Lrk~
Enerqy CharGe
Base Rate
9649~
Power Cost
Adiustment*
8477~
Effective
Rate
8126~ per kWh for all kWh
n ! t. J 1
- '
)(1 ;j U j \.l.
...
IDAHO
Issued Per IPUC Order No. 29243
Effective - May 16, 2003
~ l' It n\ ff!-
(1' ~ '
Issued by IDAHO POWER COMPANY
John R. Gale, Vice President, Regulatory Affairs
1221 West Idaho Street, Boise, Idaho
IDAHO POWER COMPANY TENTH REVISED SHEET NO, 7-IDAHO PUBLIC UTILITIES COMMISSION
CANCELS Approved Effective
NINTH REVISED SHEET NO. 7-2 'May 16, 2003 May 16, 2003
Per C.N. 29243
Jean D. Jewell Secretary
I.P,C. NO. 26, TARIFF NO.1 01
SCHEDULE 7
SMALL GENERAL SERVICE
(Continued)
MONTHLY CHARGE (Continued)
Minimum CharGe
The monthly Minimum Charge shall be the sum of the Customer Charge and the Energy Charge,
This Power Cost Adjustment (Schedule 55), and Effective Rate expire May 15, 2004.
PAYMENT
The monthly bill rendered for service supplied hereunder is payable upon receipt, and becomespast due 15 days from the date on which rendered.
" ,~~ =- "\;
1Ft, i:l "-I
~-""'"'
'C. I'~h'
~;'' "~ ~"!;';: ...;." ~'" ,'-" ~~ . ,
;e, "~,i'~
.. ;,'" ,,",
mi I~ i~,";" f~ ~~~!~ ~~
~:~~ ~~
;0
?1~it~ iJ m ~j ~~~~ ktll 1~ 1~ ;f.
n "
it
, ,
fi
:/
l '
, ,
i.
.... - ...'"~ -
A).
g .
IDAHO
Issued Per Order No. 29243
Effective - May 16, 2003
Issued by IDAHO POWER COMPANY
John R. Gale, Vice President, Regulatory Affairs
1221 West Idaho Street, Boise~ Idaho
Idaho Power Company IDAHO PUBLIC UTILITIES COMMISSIONApproved Effective
Ori inal Sheet No. 7-June 1 ) 2004 June 1 2004
Jean D. Jewell Secretary
LP.C. No. 27 . Tariff No. 101
SCHEDULE 7
SMALL GENERAL SERVICE
AVAILABILITY
Service under this schedule is available at points on the Company s interconnected systemwithin the State of Idaho where existing facilities of adequate capacity and desi'red phase and voltageare adjacent to the Premises to be served , and additional investment by the Company for transmission
substation , or terminal facilities is not necessary to supply the desired service.
APPLICABI LlTY
Service under this schedule is applicable to Electric Service supplied to a Customer at one Pointof Delivery and measured through one meter. This schedule is applicable to Customers whosemetered energy usage is 3 000 kWh , or less , per Billing Period for ten or more Billing Periods during
the most recent 12 consecutive Billing Periods. When the Customer s Billing Period is less than 27
days or greater than 33 days, the energy usage will be prorated to 30 days for purposes of determining
eligibility under this schedule. Customers whose metered energy usage exceeds 3 000 kWh per Billing
Period on an actual or prorated basis three times during the most recent 12 consecutive Billing Periodsare not eligible for service under this schedule and will be automatically transferred to the applicable
schedule effective with the next Billing Period. New customers may initially be placed on this schedulebased on estimated usage.
This schedule is also applicable to non-profit or tax supported ball fields, fairgrounds or rodeo
grounds with high demands and intermittent use exceeding 3 000 kWh per month. This schedule is notapplicable to standby service, service for resale , or shared service, or to individual or multiple family
dwellings first served through one meter after February 9 , 1982 , or to agricultural irrigation service after
October 31 , 2004.
TYPE OF SERVICE
The type of service provided under this schedule is single and/or three-phase, at approximately
60 cycles and at the standard service voltage available at the Premises to be served.
SUMMER AND NON-SUMMER SEASONS
The summer sE?ason begins on June 1 of each year and ends on August 31 of each year. The
non-summer season begins on September 1 of each year and ends on May 31 of each year.
IDAHO
Issued Per IPUC Order Nos. 29505 and 29506
Effective - June 1 , 2004
Issued by IDAHO POWER COMPANY
John R. Gale , Vice President, Regulatory Affairs
1221 West Idaho Street, Boise , Idaho
Idaho Power Company First Revised Sheet No.7 -2 IDAHO PUBLIC UTILITIES COMMISSION
Cancels Approved Effective
Ori inal Sheet No.7 -July 27, 2004 July 28, 2004
Per O.N. 29547
Jean D. Jewell Secretary
I.P.C. No. 27, Tariff No, 101
SCHEDULE 7
SMALL GENERAL SERVICE
(Continued)
MONTHLY CHARGE
The Monthly Charge is the sum of the Service Charge the Energy Charge, and the Power Cost
Adjustment at the following rates:
Summer Non-summer
Service Charge, per month $3.$3.
Energy Charge , per kWh
300 kWh
Over 300 kWh
6, 11 77
8915i
5761
1177i
6, 11 77
5761 Power Cost Adjustment*, per kWh
This Power Cost Adjustment is computed as provided in Schedule 55.
Minimum Charge
The monthly Minimum Charge shall be the sum of the Service Charge, the Energy Charge, and
the Power Cost Adjustment.
PAYMENT
The monthly bill rendered for service supplied hereunder: is payable upon receipt, and becomes
past due 15 days from the date on which r:-endered.
IDAHO
Issued Per IPUC Order No. 29547
Effective ~ July 28 , 2004
Issued by IDAHO POWER COMPANY
John R, Gale, Vice President, Regulatory Affairs
1221 West Idaho Street, Boise , Idaho
IDAHO ~UBlIC UTILITIES COMMISSION
APPR"
-,,
VED EFFECTIVE
MAY 11 '00 MAY 16 '
~-=
J2 SECRETARY
IDAHO POWER COMP ANY ELEVENTH REVISED SHEET NO, 9-
CANCELS
TENTH REVISED SHEET NO. 9-I.P.C. NO. 26, TARIFF NO. 101
SCHEDULE 9
LARGE GENERAL SERVICE
(Continued)
FACILITIES BEYOND THE POINT OF DELIVERY
At the option of the Company, transformers and other facilities installed beyond the Point of
Delivery to provide Primary or Transmission Service may be owned, operated, and maintained by the
Company in consideration of the Customer paying a Facilities Charge to the Company,
Company-owned Facilities Beyond the Point of Delivery will be set forth in Distribution Facilities
Investment Report provid~d to the Customer. As the Company s investment in Facilities Beyond the
Point of Delivery changes in order to provide the Customer s service requirements, the Company shall
notify the Customer of the additions and/or deletions of facilities by forwarding to the Customer a
revised Distribution Facilities Investment Report.
In the event the Customer requests the Company to remove or reinstall or change Company-
owned Facilities Beyond the Point of Delivery, the Customer shall pay to the Company the "non-
salvable cost" of such removal, reinstallation or change. Non-salvable cost as used herein is comprised
of the total original costs of materials, labor and overheads of the facilities, less the difference between
the salvable cost of material removed and removal labor cost including appropriate overhead costs.
POWER FACTOR
Where the Customer s Power Factor is less than 85 percent, as determined by measurement
under actual load conditions, the Company may adjust the kW measured to determine the Billing
Demand by multiplying the measured kW by 85 percent and dividing by the actual Power Factor.
MONTHLY CHARGE
The Monthly Charge is the sum of the Customer, the Basic, the Demand, the Energy, and the
Facilities Charges at the following rates,
SECONDARY SERVICE
""~ \1',;:'.::.?;~
1!:~ ~1t",
,"
\~i~?
.~ ~ ~\ ~, ~:, ,\, \\~,
J~'
~~)
.r.;.W'~ IC\,.r~'c':? ;
" ','--
. '-0
\J ~\
\%i \;)
",.-, C"
: ~ ~\,-
-1 .... CUD,'Ii.'" ~- -\1 \\\; I,A ~
~;'. .
Customer Charge
$5,54 per meter per month
Basic Charge
$0.36 per kW of Basic Load Capacity
f\
~-
Demand Charqe
$2.73 per kW for all kW of Demand
Enerqy Charqe
Base Rate
6 150~
Power Cost
Adiustment*
O. 1371 ~
Revenue Sharing
Adiustment*
.:::0.0663;:.~
Effective
Rate
6858~ per kWh for all kWh
IDAHO
Issued - May 10, 2000
Effective - May 16, 2000
Issued by IDAHO POWER COMPANY
James C. Miller, Senior Vice President, Delivery
1221 West Idaho street, Boise, Idaho
- - -
IDAHO POWER COMP ANY TWELTH REVISED SHEET NO. 9-
CANCELS
ELEVENTH REVISED SHEET NO. 9-
IDAHO PUBLIC UTILITIES COMMISSIONAPPROVED EFFECTIVEI.P.C. NO. 26, TARIFF NO. 101
APR 3 0 '0 1 MAY 1 - 10 1
SCHEDULE 9
LARGE GENERAL SERVICE
Continued)
lt1. SECRETARY
FACILITIES BEYOND THE POINT OF DELIVERY
A t the option of the Company, transformers and other facilities installed beyond the Point of
Delivery to provide Primary or Transmission Service may be owned, operated, and maintained by the
Company in consideration of the Customer paying a Facilities Charge to the Company.
Company-owned Facilities Beyond the Point of Delivery will be set forth in a Distribution Facilities
Investment Report provided to the Customer, As the Company s inv~stment in Facilities Beyond the
Point of Delivery changes in order to provide the Customer s service requirements, the Company shall
notify the Customer of the additions and/or deletions of facilities by forwarding to the Customer a
revised Distribution Facilities Investment Report.
In the event the Customer requests the Company to remove or reinstall or change Company-
owned Facilities Beyond the Point of Delivery, the Customer shall pay to the Company the "non-
salvable cost" of such removal, reinstallation or change, Non-salvable cost as used herein is comprised
of the total original costs of materials, labor and overheads of the facilities, less the difference between
the salvable cost of material remQved and removal labor cost including appropriate overhead costs.
POWER FACTOR
Where the Customer s Power Factor is less than 85 percent, as determined by measurement
under actual load conditions, the Company may adjust the kW measured to determine the Billing
Demand by multiplying the measured kW by 85 percent and dividing by the actual Power Factor.
MONTHLY CHARGE
The Monthly Charge is the sum of the Customer, the Basic, the Demand, the Energy, and the
Facilities Charges at the following rates.
Customer Charge
$5,54 per meter per month
""'
;\/iI\
;~?~~,.~ "'
""- "t,,;;:;1
~ ")j\
V:'\ \t~ ~~,\i
;l!l/t m.?" t '"' t"\\ :;;a
~ '
t '
~ !' '
~'I\ \"~\"O' 'i;~
, ~
10'" '-1.1 ~' t"1 '
~ "
I ".,
" \ ~ ~\~
~jij~
~\,
:':l \:' ,::~i :!id/'
" ".,, '
;f5:;'io-
. '.,....
SECONDARY SERVICE
Basic Charge
$0,36 per kW of Basic Load Capacity
'j
(Wf\(lC1 '- u
I\~~' t (\ R
t,
Demand Charge
$2.73 per kW for all kW of Demand
Energy Charge
Base Rate
6 1501t
Power Cost
Adiustment*
1.34 151t
Effective
Rate
95651t per kWh for all kWh
IDAHO
Issued Per IPUC Order No. 28722
Effective - May 1, 2001
Issued by IDAHO POWER COMPANY
John R. Gale, Vice President, Regulatory Affairs
1221 West Idaho Street, Boise, Idaho
IDAHO POWER COMPANY THIRTEENTH REVISED SHEET NO. 9-2 IDAHO PUBLIC UTILITIES COMMISSION
TWELFTH REVISED SHEE
~~~~~~;
APPROVED EFFECTIVEC. NO. 26, TARIFF NO. 101
SEP 2 7 'OCT 1 - '
SCHEDULE 9
LARGE GENERAL SERVICE
(Continued)t-- to. SECRETARY
FACILITIES BEYOND THE POINT OF DELIVERY
At the option of the Company, transformers and other facilities installed beyond the Point of
Delivery to provide Primary or Transmission Service may be owned, operated, and maintained by the
Company in consideration of the Customer paying a Facilities Charge to the Company.
Company-owned Facilities Beyond the Point of Delivery will be set forth in a Distribution Facilities
Investment Report provided to the Customer. As the Company s investment in Facilities Beyond the
Point of Delivery changes in order to provide the Customer's service requirements, the Company shall
notify the Customer of the additions and/or deletions of facilities by forwarding to the Customer arevised Distribution Facilities Investment Report.
In the event the Customer requests the Company to remove or reinstall or change Company-
owned Facilities Beyond the Point of Delivery; the Customer shall pay to the Company the \\non-
salvable cost" of such removal, reinstallation or change. Non-salvable cost as used herein is comprised
of the total original costs of materials, labor and overheads of the facilities, less the difference between
the salvable cost of material removed and removal labor cost including appropriate overhead costs.
POWER FACTOR
Where the Customer s Power Factor is less than 85 percent, as determined by measurement
under actual load conditions, the Company may adjust the kW measured to determine the Billing
Demand by multiplying the measured kW by 85 percent and dividing by the actual Power Factor.
MONTHLY CHARGE
The Monthly Charge is the sum of the Customer, the Basic, the Demand, the Energy, and the
Facilities Charges at the following rates,
SECONDARY SERVICE
Customer Charge
$5.54 per meter per month
~! ~
r,; i~lll t' ~;)II
, .
,"I' .\I 111 ok, ~""
'\ "".
t'- w.."" ~17~'
c;JJ1
~~ ='""
Basic Charge
$0.36 per kW of Basic Load Capacity MI\Y 1 6 2002
Demand Charge
$2,73 per kW for all kW of Demand
~.~.
Enerav Charge
Base Rate
6150c
Power Cost
Adjustment*
1 .7241 c
Effective
Rate *
3391 c per kWh for all kWh
IDAHO
Issued Per IPUC Order No. 28852
Effective - October 1, 2001
Issued by IDAHO POWER COMPANY
John R. Gale, Vice President, Regulatory Affairs
1221 West Idaho Street Boise, Idaho
IDAHO POWER COMPANY FOURTEENTH REVISED SHEET NO. 9-IDAHO PUBLIC UTILITIES COMMISSION
CANCELS Approved Effective
THIRTEENTH REVISED SHEET NO. 9-May 15) 2002 May 16, 2002
Per O.N. 29026
Jean D. Jewell Secretary
I.P .C. NO. 26, TARIFF NO.1 01
SCHEDULE 9
LARGE GENERAL SERVICE
(Continued)
FACILITIES BEYOND THE POINT OF DELIVERY
At the option of the Company, transformers and other facilities installed beyond the Point of
Delivery to provide Primary or Transmission Service may be owned, operated, and maintained by the
Company in consideration of the Customer paying Q Facilities Charge to the Company.
Company-owned Facilities Beyond the Point of Delivery will be set forth in a Distribution Facilities
Investment Report provided to the Customer. As the Company s investment in Facilities Beyond the
Point of Delivery changes in order to provide the Customer s service requirements, the Company shall
notify the Customer of the additions and/or deletions of facilities by forwarding to the Customer a
revised Distribution Facilities Investment Report.
In the event the Customer requests the Company to remove or reinstall or change Company-
owned Facilities Beyond the Point of Delivery, the Customer shall pay to the Company the "non-
salvable cost" of such removal, reinstallation or change. Non-salvable cost as used herein is comprised
of the total original costs of materials, labor and overheads of the facilities, less the difference between
the salvable cost of material removed and removal labor cost including appropriate overhead costs.
POWER FACTOR
Where the Customer s Power Factor is less than 85 percent, as determined by measurement
under actual load conditions, the Company may adjust the kW measured to determine the Billing
Demand by multiplying the measured kW by 85 percent and dividing by the actual Power Factor.
MONTHLY CHARGE
The Monthly Charge is the sum of the Customer, the Basic, the Demand, the Energy, and the
Facilities Charges at the following rates.
Customer Charqe
$5.54 per meter per month
- ~.../ .
fJt
'" ', ,
fa 1fj ~,
\iJ rh-,,
!!$. ?
,",j~ 't.~
SECONDARY SERVICE
Basic Charqe
$0.36 per kW of Basic Load Capacity
M~'( 1 0
2.Q03
Demand Charqe
$2.73 per kW for all kW of Demand
~.
Energy Charqe
Base Rate
6 150~
Power Cost
Adiustment*
9370~
Effective
Rate
5520~ per kWh for all kWh
IDAHO
Issued per IPUC Order No. 29026
Effective - May 16,2002
Issued by IDAHO POWER COMPANY
John R. Gale, Vice President, Regulatory Affairs
1221 West Idaho Street, Boise, Idaho
IDAHO POWER COMPANY FOURTEENTH REVISED SHEET NO. 9-IDAHO PUBLIC UTILITIES COMMISSION
CANCELS Approved Effective
THIRTEENTH REVISED SHEET NO. 9-May 15 2002 May 16, 2002
Per O.N. 29026
LP .C, NO. 26, TARIFF NO.1 01
SCHEDULE 9
LARGE GENERAL SERVICE
(Continued)
J n re ell ~ieta
ry
~,,
\~ r.-j
,..~
rf. rl~".",i ,
;":':;"'" .,
I~ .)iO"";;1 ~.11 t:
~. ,,: ;;'
.1 ~a~
...
.;1 ~f,i1'~
~ ";
, ii:iI
~~~ ~:
c"'
".,
,t.,
'. ,. '
\~f~ i!I f,~l t'J
!~ ~ ,
fo ~iW; "~1\.Y ~13 ,iQw t~~
q -
SECONDARY SERVICE (Continued)MAY 1 6 2003
Facilities Charqe
None
, I
IJ.
Minimum Charqe
The monthly Minimum Charge shall be the sum of the Customer Charge, the Basic Charge, theDemand Charge, and the Energy Charge,
,;;.;.":'
This Power Cost Adjustment (Schedule 55), and Effective Rate expire May 15, 2003.
PRIMARY SERVICE
Customer Charqe
$85.58 per meter per month
Basic Charqe
$0.77 per kW of Basic Load Capacity
Demand Charqe
$2.65 per kW for all kW of Demand
Enemy Charqe
Base Rate
1308(t
Power Cost
Adiustment*
9370(t
Effective
Rate
0678(t per kWh for all kWh
Facilities Charge
The Company s investment in Company-owned Facilities Beyond the Point of Delivery times 1.7percent.
Minimum Charqe
The monthly Minimum Charge shall be the sum of the Customer Charge, the Basic Charge, theDemand Charge, the Energy Charge, and the Facilities Charge.
This Power Cost Adjustment (Schedule 55), and Effective Rate expire May 15,2003.
IDAHO
Issued per IPUC Order No. 29026
Effective - May 16,2002
Issued by IDAHO POWER COMPANY
John R. Gale, Vice President, Regulatory Affairs
1221 West Idaho Street, Boise, Idaho
IDAHO POWER COMPANY FIFTEENTH REVISED SHEET NO. 9-IDAHO PUBLIC UTILITIES COMMISSION
CANCELS Approved Effective
FOURTEENTH REVISED SHEET NO. 9-May 16, 2003 May 16, 2003
Per O.N. 29243
Jean D. Jewell Secretary
SCHEDULE 9
LARGE GENERAL SERVICE
(Continued)
I.P .C. NO, 26, TARIFF NO.1 01
FACILITIES BEYOND THE POINT OF DELIVERY
At the option of the Company, transformers and other facilities installed beyond the Point of
Delivery to provide Primary or Transmission Service may be owned, operated, and maintained by the
Company in consideration of the Customer paying a Facilities Charge to the Company.
Company-owned Facilities Beyond the Point of Delivery will be set forth in a Distribution Facilities
Investment Report provided to the Customer, As the Company s investment in Facilities Beyond the
Point of Delivery changes in order to provide the Customer s service requirements, the Company shall
notify the Customer of the additions and/or deletions of facilities by forwarding to the Customer a
revised Distribution Facilities Investment Report.
In the event the Customer requests the Company to remove or reinstall or change Company-
owned Facilities Beyond the Point of Delivery, the Customer shall pay to the Company the "non-
salvable cost" of such removal, reinstallation or change. Non-salvable cost as used herein is comprised
of the total original costs of materials, labor and overheads of the facilities, less the difference between
the salvable cost of material removed and removal labor cost including appropriate overhead costs.
POWER FACTOR
Where the Customer s Power Factor is less than 85 percent, as determined by measurement
under actual load conditions, the Company may adjust the kW measured to determine the Billing
Demand by multiplying the measured kW by 85 percent and dividing by the actual Power Factor.
MONTHLY CHARGE
The Monthly Charge is the sum of the Customer, the Basic, the Demand, the Energy, and the
'Facilities Charges at the following rates.
SECONDARY SERVICE
Customer Charqe
$5.54 per meter per month
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Basic Charge
$0.36 per kW of Basic Load Capacity JUN 1 - 2004
Demand Charqe
$2.73 per kW for all kW of Demand
Enerqy Charge
,.. r,ft \ f.'L
l'~"
Base Rate
6150!t
Power Cost
Adiustment*
6039!t
Effective
Rate
2189!t per kWh for all kWh
IDAHO
Issued Per IPUC Order No. 29243
Effective - May 16, 2003
Issued by IDAHO POWER COMPANY
John R. Gale, Vice President, Regulatory Affairs
1221 West Idaho Street, Boise, Idaho
I.P .C. NO. 26, TARIFF NO.1 01
FIFTEENTH REVISED SHEET NO, 9-IDAHO PUBLIC UTILITIES COMMISSION
CANCELS Approved Effective
FOURTEENTH REVISED SHEET NO. 9-May 16 2003 May 16, 2003
Per O.N. 29243
Jean D. Jewell Secretary
IDAHO POWER COMPANY
SCHEDULE 9
LARGE GENERAL SERVICE
(Continued)
SECONDARY SERVICE (Continued)
Facilities Charqe
None
Minimum Charge
The monthly Minimum Charge shall be the sum of the Customer Charge, the Basic Charge, the
Demand Charge, and the Energy Charge.
This Power Cost Adjustment (Schedule 55), and Effective Rate expire May 15, 2004.
PRIMARY SERVICE
Customer Charqe
$85,58 per meter per month
Basic Charge
$0.77 per kW of Basic Load Capacity
Demand Charqe
$2.65 per kW for all kW of Demand
Energy Charqe
Base Rate
2. 1 308~
Power Cost
Adiustment*
6039~
Effective
Rate
2.7347 ~ per kWh for all kWh
Facilities Charqe
The Company s investment in Company-owned Facilities Beyond the Point of Delivery times 1.
percent.
Minimum Charge
The monthly Minimum Charge shall be the sum of the Customer Charge, the Basic Charge, the
Demand Charge, the Energy Charge, and the Facilities Charge.
This Power Cost Adjustment (Schedule 55), and Effective Rate expire May 15, 2004.
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IDAHO
Issued Per IPUC Order No. 29243
Effective - May 16,2003
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Issued by IDAHO POWER COMPANY
John R, Gale, Vice President, Regulatory Affairs
1221 West Idaho Street, Boise, Idaho
IDAHO POWER COMPANY FIFTEENTH REVISED SHEET NO. 9-IDAHO PUBLIC UTILITIES COMMISSION
CANCELS Approved Effective
FOURTEENTH REVISED SHEET NO. 9-May 16, 2003 May 16, 2003
Per O.N. 29243
Jean D. JewelI Secretary
I.P .C. NO. 26, TARIFF NO.1 01
SCHEDULE 9
LARGE GENERAL SERVICE
(Continued)
TRANSMISSION SERVICE
Customer Charqe
$85,58 per meter per month
Basic Charqe
$0.39 per kW of Basic Load Capacity
Demand Charge
$2.57 per kW for all kW of Demand
Enerqy Charge
Base Rate
0833!t
Power Cost
Adiustment*
6039!t
Effective
Rate
6872!t per kWh for all kWh
Facilities Charqe
. The Company s investment in Company-owned Facilities Beyond the Point of Delivery times 1.7
percent.
Minimum Charqe
The monthly Minimum Charge shall be the sum of the Customer Charge, the Basic Charge, the
Demand Charge, the Energy Charge, and the Facilities Charge.
This Power Cost Adjustment (Schedule 55), and Effective Rate expire May 15, 2004.
PAYMENT
The monthly bill rendered for service supplied hereunder is payable upon receipt, and becomes
past due 15 days from the date on which rendered.
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MAY 1 6 2004
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IDAHO
Issued Per IPUC Order No. 29243
Effective - May 16,2003
Issued by IDAHO POWER COMPANY
John R. Gale, Vice President, Regulatory Affairs
1221 West Idaho Street, Boise, Idaho
IDAHO POWER COMPANY SIXTEENTH REVISED SHEET NO. 9-
CANCELS
FIFTEENTH REVISED SHEET NO, 9-
IDAHO PUBLIC UTILITIES COMMISSIONApproved EffectiveApril 22, 2004 May 16) 2004
. Per D.N. 29478
Jean D, Jewell Secretary
LP.C. NO. 26, TARIFF NO. 101
SCHEDULE 9
LARGE GENERAL SERVICE
(Continued)
SECONDARY SERVICE (Continued)
Facilities Charge
None
Minimum Charge
The monthly Minimum Charge shall be the sum of the Customer Charge, the Basic Charge, the
Demand Charge, and the Energy Charge.
This Power Cost Adjustment is computed as provided in Schedule 55.
PRIMARY SERVICE
Customer Charqe
$85.58 per meter per month
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Basic Charqe
$0.77 per kW of Basic Load Capacity JUN 1 - 2004
Demand Charqe
$2.65 per kW for all kW of Demand
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Enerqy Charqe
Base Rate
1308~
Power Cost
Adiustment*
6039~
Effective
Rate
2.7347~ per kWh for all kWh
Facilities Charqe
The Company s investment in Company-owned Facilities Beyond the Point of Delivery times 1,
percent.
Minimum Charqe
The monthly Minimum Charge shall be the sum of the Customer Charge, the Basic Charge, the
Demand Charge, the Energy Charge, and the Facilities Charge.
This Power Cost Adjustment is computed as provided in Schedule 55.
IDAHO
Issued - April 15, 2004
Effective - May 16, 2004
Issued by IDAHO POWER COMPANY
John R. Gale, Vice President, Regulatory Affairs
1221 West Idaho Street, Boise, Idaho
IDAHO POWER COMPANY SIXTEENTH REVISED SHEET NO. 9-
CANCELS
FIFTEENTH REVISED SHEET NO. 9-
IDAHO PUBLIC UTILITIES COMMISSIONApproved Effective
April 22, 2004 May 16, 2004
Per O.N, 29478
Jean D. Jewell Secretary
I.P .C. NO. 26, TARIFF NO.1 01
SCHEDULE 9
LARGE GENERAL SERVICE
(Continued)
TRANSMISSION SERVICE
Customer CharGe
$85.58 per meter per month
Basic CharGe
$0.39 per kW of Basic Load Capacity
Demand Charge
$2.57 per kW for all kW of Demand
Energy CharGe
Base Rate
0833~
Power Cost
Adiustment*
6039~
Effective
Rate
6872~ per kWh for all kWh
Facilities CharGe
The Company s investment in Company-owned Facilities Beyond the Point of Delivery times 1.
percent.
Minimum Charge
The monthly Minimum Charge shall be the sum of the Customer Charge, the Basic Charge, the
Demand Charge, the Energy Charge, and the Facilities Charge.
This Power Cost Adjustment is computed as provided in Schedule 55.
PA YMENT
The monthly bill rendered for service supplied hereunder is payable upon receipt, and becomes
past due 15 days from the date on which rendered.
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JUN 1 - 2004
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IDAHO
Issued - April 15, 2004
Effective - May 16,2004
Issued by IDAHO POWER COMPANY
John R. Gale, Vice President, Regulatory Affairs
1221 West Idaho Street, Boise, Idaho
daho Power Company
C. No. 27 , Tariff No. 101
IDAHO PUBLIC UTILITIES COMMISSIONApproved Effective
Ori inal Sheet No. 9-June 1 , 2004 June 1 2004
Jean D. Jewell Secretary
SCHEDULE
lARGE GENERAL SERVICE
AVAilABILITY
Service under this schedule is available at points on the Company s interconnected system
within the State of Idaho where existing facilities of adequate capacity and desired phase and voltage
are adjacent to the Premises to be served and additional investment by the Company for new
transmission, substation , or terminal facilities is not necessary to supply the desired service.
APPLICABILITY
Service under this schedule is applicable to firm Electric Service supplied to a Customer at one
Point of Delivery and measured through one meter. This service is applicable to Customers whose
metered energy usage e~ceeds 3 000 kWh per Billing Period for a minimum of three Billing Periods
during the most recent 12 consecutive Billing Periods and whose metered Demand per Billing Period
has not equaled or exceeded 1 000 kW more than twice during the most recent 12 consecutive Billing
Periods. Where the Customer s Billing period is less than 27 days or greater than 33 days , the metered
energy usage will be prorated to 30 days for purposes of determining eligibility under this schedule.
Customers whose metered energy usage does not exceed 3 000 kWh per Billing Period on an actual or
prorated basis three or more times during the most recent 12 consecutive Billing Periods or whose
metered demand equals or exceeds 1 000 kW per Billing Period three times or more during the most
recent 12 consecutive Billing Periods are not eligible for service under this schedule and will
automatically transferred to the applicable schedule effective with the next Billing Period. New
customers may initially be placed on this schedule based on estimated usage.
This schedule is not applicable to standby service, service for resale, or shared service , or to
individual or multiple family dwellings first served through one meter after February 9 , 1982 , or to
agricultural irrigation service after October 31 , 2004.
TYPE OF SERVICE
The type of service provided under this schedule is single and/or three-phase, at approximately
60 cycles and at the standard service voltage available at the Premises to be served.
BASIC lOAD CAPACITY
The Basic load Capacity is the average of the two greatest non-zero monthly Billing Demands
established during the 12-month period which includes and ends with the current Billing Period.
BilLING DEMAND
The Billing Demand is the average kW supplied during the 15-consecutive-minute period of
maximum use during the Billing Period , adjusted for Power Factor.
IDAHO
Issued Per IPUCOrder Nos. 29505 and 29506
Effective - June 1 , 2004
Issued by IDAHO POWER COMPANY
John R. Gale , Vice President, Regulatory Affairs
, 1221 West Idaho Street, Boise, Idaho
Idaho Power Company IDAHO PUBLIC UTILITIES COMMISSIONApproved Effective
Ori inal Sheet No. 9-June 1 , 2004 June 1 , 2004
Jean D. Jewell Secretary
I.P.C. No. 27, Tariff No. 101
SCHEDULE 9
LARGE GENERAL SERVICE
(Continued)
FACILITIES BEYOND THE POINT OF DELIVERY
At the option of the Company, transformers and other facilities installed beyond the Point of
Delivery to provide Primary or Transmission Service may be owned , operated , and maintained by the
Company in consideration of the Customer paying a Facilities Charge to the Company.
Company-owned Facilities Beyond the Point of Delivery will be set forth in a Distribution
Facilities Investment Report provided to ,the Customer. As the Company s investment in Facilities
Beyond the Point of Delivery changes in order to provide the Customer s service requirements , the
Company shall notify the Customer of the additions and/or deletions of facilities by forwarding to the
Customer a revised Distribution Facilities Investment Report.
In the event the Customer requests the Company to remove or reinstall or change Company-
owned Facilities Beyond the Point of Delivery, the Customer shall pay to the Company the "non-
salvable cost" of such removal , reinstallation or change. Non-salvable cost as used herein is
comprised of the total original costs of materials, labor and overheads of the facilities, less the
difference between the salvable cost of material removed and removal labor cost including appropriate
overhead costs.
POWER FACTOR
Where the Customer s Power Factor is less than 85 percent, as determined by measurement
under actual load conditions, the Company may adjust the kW measured to determine the Billing
Demand by multiplying the measured kW by 85 percent and dividing by the actual Power Factor.
Effective November 1 , 2004 where the Customer s Power Factor is less than 90 percent, as
determined by measurement under actual load conditions, the Company may adjust the kW measured
to determine the Billing Demand by multiplying the measured kW by 90 percent and dividing by the
actual Power Factor.
SUMMER AND NON-SUMMER SEASONS
The summer season beings on June 1 of each year and ends on August 31 of each year. The
non-summer season begins on September 1 of each year and ends on May 31 of each year.
MONTHLY CHARGE
The Monthly Charge is the sum of the Service , the Basic, the Demand, the Energy, the Power
Cost Adjustment , and the Facilities Charges at the following rates.
IDAHO
Issued Per PUG Order Nos. 29505 and 29506
Effective - June 1 , 2004
Issued by IDAHO POWER COMPANY
John R. Gale , Vice President, Regulatory Affairs
1221 West Idaho Street, Boise, Idaho
Idaho Power Company First Revised Sheet No, 9-3 IDAHO PUBLIC UTILITIES COMMISSION
Cancels Approved Effective
Ori inal Sheet No. 9-July 27 ) 2004 July 28 2004
Per O.N. 29547
Jean D. Jewell Secretary
I.P.C. No. 27. Tariff No.1 01
SCHEDULE 9
LARGE GENERAL SERVICE
(Continued)
SECONDARY SERVICE Summer Non-summer
Service Charge, per month $5,$5,
Basic Charge , per kW of
Basic Load Capacity $0,$0.
Demand Charge, per kW of
Billing Demand
Energy Charge , per kWh
$3.
9062i
$2,
Power Cost Adjustment*, per kWh 6039i
This Power Cost Adjustment is computed as provided in Schedule 55.
5926i
6039i
J9(PS'
Facilities Charqe
None,
Minimum Charqe
The monthly Minimum Charge shall be the sum of the Service Charge, the Basic Charge, the
Demand Charge, the Energy Charge , and the Power Cost Adjustment.
PRIMARY SERVICE Summer Non-summer
Service Charge, per month $125.$125.
Basic Charge, per kW of
Basic Load Capacity $0,$0.
Demand Charge , per kW of
Billing Demand
Energy Charge , per kWh 5464i
6039i
$2.
2825i
$3.
Power Cost Adjustment*, per kWh 6039i
This Power Cost Adjustment is computed as provided in Schedule 55,
Facilities Charqe.The Company s investment in Company-owned Facilities Beyond the Point of
Delivery times 1.7 percent.
IDAHO
Issued Per IPUC Order No. 29547
Effective - July 28 , 2004
Issued by IDAHO POWER COMPANY
John R, Gale, Vice President, Regulatory Affairs
1221 West Idaho Street, Boise , Idaho
Idaho Power Company First Revised Sheet No. 9-4 IDAHO PUBLIC UTILITIES COMMISSION
Cancels Approved Effective
Ori inal Sheet No. 9-July 27, 2004 July 28, 2004
Per O,N, 29547
Jean D. Jewell Secretary
I.P.C. No. 27 , Tariff No. 101
SCHEDULE 9
LARGE GENERAL SERVICE
(Continued)
Minimum Charqe. The monthly Minimum Charge shall be the sum of the Service Charge, the
Basic Charge, the Demand Charge, the Energy Charge , the Power Cost Adjustment, and the
Facilities Charge.
TRANSMISSION SERVICE Summer Non-summer
Service Charge , per month $125.$125.
Basic Charge, per kW of
Basic Load Capacity $0.43 $0.43
Demand Charge, per kW of
Billing Demand $3,$2,
Energy Charge, per kWh 2.4897 if,
6039if,
2414if,
6039if,Power Cost Adjustment*
This Power Cost Adjustment is computed as provided in Schedule 55.
Facilities Charqe
The Company s investment in Company-owned Facilities Beyond the Point of Delivery times 1,
percent.
Minimum Charqe
The monthly Minimum Charge shall be the sum of the Service Charge, the Basic Charge, the
Demand Charge , the Energy Charge, the Power Cost Adjustment, and the Facilities Charge.
PAYMENT
The monthly bill rendered for service supplied hereunder is payable upon receipt, and becomes
past due 15 days from the date on which rendered.
IDAHO
Issued Per IPUC Order No. 29547
Effective - July 28 , 2004
Issued by IDAHO POWER COMPANY
John R, Gale, Vice President, Regulatory Affairs
1221 West Idaho Street, Boise, Idaho
Idaho Power Company First Revised Sheet No. 19-
Cancels
Oriqinal Sheet No. 19-I.P.C, No. 27 Tariff No. 101
SCHEDULE 19
LARGE POWER SERVICE
AVAILABILITY
Service under this schedule is available at points on the ComP9r1~t~ '~~y,onnected system
within the State of Idaho where existing facilities of adequate capacitYt9n~;;~~9Ir~~Il?IDase and voltage
are available. If additional distribution facilities are required to suppl:y:tn~;~g.e~iFe(h service , those
facilities provided for under Rule H will be provided under the terms an~\ 29n~itl~h~I'pf that rule, To the
extent that additional facilities not provided for under Rule H , inq~~ding tr~wsAJI~~ioh and/or substation
facilities, are required to provide the requested service sped~ arrang eAts will be made in a
separate agreement between the Customer and the Company,
Effective June 1 , 2004 , all Uniform Large Po~.
~,..
C Sg~i~;~ Agreert)ents currently in effect will
automatically be cancelled, Customers with loads equ~~;td!ct9rrru excess of 1 000 kW Demand at a
single Point of Delivery will be required to enter int9,i :5f~\
~~\
rvice Agreement as provided under
Rule C.
APPLICABILITY
Service under this schedule "A\aRP"to and mandatory for Customers who register a
metered Demand of 1 ,000 kW or moreIRe:~~il iJlgPeriod for three or more Billing Periods during the
most recent 12 consecutiv~ Billip~Ii!l~err~g~h ';)eustomers whose initial usage, based on information
provided by the Customec iis ~i~~~~~d to'pe 1 000 kW or more per Billing Period for three or more
Billing Periods during 12 co.ig:g~Iv~~illing Periods may, at the Customer s request, take service
under this schedule priqffi, "~~irig;;ithe metered demand criterion, This schedule will remain
applicable until th~:~u~t~tm~r to~:tegister a metered demand of 1 000 kW or more per Billing Period
for three or m~rel3i
' ,"""..''.' ," '
IJring the most recent 12 consecutive Billing Periods.
Deliverie rnG?r ban one Point of Delivery or more than one voltage will be separately
metered and biIT .,tfi~ aggregate power requirement of a Customer who receives service at one or
more Points of rD~J!;~ry on the same Premises exceeds 25,000 kW, the Customer is ineligible for
service under thiss~nedule and is required to make special contract arrangements with the Company.
This schedule is not applicable to service for resale , to shared or irrigation service , to standby or
supplemental service , unless the Customer has entered into a Uniform Standby Service Agreement or
other standby agreement with the Company, or to multi-family dwellings.
Contract Option. Customers for which this schedule is applicable may optionally take service
under a mutually agreed upon individual special contract between the Customer and the Company
provided the Customer contracts for firm electric demand of 10 000 kW to 25 000 kW and the special
contract terms, conditions, and rates are approved by the Idaho Public Utilities Commission without
change or condition.
TYPE OF SERVICE
The Type of Service provided under this schedule is three-phase at approximately 60 cycles
and at the standard service voltage available at the Premises to be served.
IDAHO
Issued Per IPUG Order No. 29505
Effective - December 1 , 2004
Issued by Idaho Power Company
John R, Gale ) Vice President, Regulatory Affairs
1221 West Idaho Street, Boise, Idaho
Idaho Power Company First Revised Sheet No. 19-
Cancels
Oriqinal Sheet No. 19-I.P.C. No. 27 Tariff No.1 01
SCHEDULE 19
LARGE POWER SERVICE
(Continued)
BASIC LOAD CAPACITY
The Basic Load Capacity is the average of the two gre9t~
, ,. '
rS3illing Demands
established during the 12-month period which includes and ends with t1~?"urr~ntBj,ITihg Period, but not
less than 1 ,000 kW,
BILLING DEMAND
The Billing Demand is the average kW supplied dYtr~'~ the
.,,
~onsecutive-minute period of
maximum use during the Billing Period, adjusted for Po' ~r Ea'cfoL butnbtl~ss than 1 000 kW.
The On-Peak Billing Demand is the ?v~r
maximum use during the Billing Period for the
(,+, ." ~ ,
during the 15-minute period of
ON-PEAK BilLING DEMAND
TIME PERIODS
All times are stated in Mountain Time.
~ii ,0 9:00 p.m. Monday through Friday, except holidays
:m, to 1 :00 p.m. and 9:00 p,m. to 11 :00 p.m, Monday through
I.. 'I, except holidays , and 7:00 a,m. to 11 :00 p,m. Saturday, Sunday,
/TId holidays
11 :00 p.m, to 7:00 a,m. all days
Non-summeh ,.ason
Mid1.;eak: 7:00 a.m. to 11 :00 p.m, Monday through Saturday, except holidays
Off-Peak: 11 :00 p.m. to 7:00 a,m. Monday through Saturday and all hours
Sunday and holidays
The holidays observed by the Company are New Year s Day, Memorial Day, Independence
Day, labor Day, Thanksgiving Day, and Christmas Day. When New Year s Day, Independence Day, or
Christmas Day falls on a Sunday, the Monday immediately following that Sunday will be considered a
holiday.
SUMMER AND NON-SUMMER SEASONS
The summer season begins on June 1 of each year and ends on August 31 of each year, The
non-summer season begins on September 1 of each year and ends on May 31 of each year.
IDAHO
Issued Per IPUC Order No. 29505
Effective - December 1 , 2004
Issued by Idaho Power Company
John R. Gale, Vice President, Regulatory Affairs
1221 West Idaho Street, Boise, Idaho
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Idaho Power Company First Revised Sheet No. 19-
Cancels
Oriqinal Sheet No. 19-I.P,C. No. 27 Tariff No. 101
SCHEDULE 19
LARGE POWER SERVICE
(Continued)
FACILITIES BEYOND THE POINT OF DELIVERY
,""i",
..," "
At the option of the Company, transformers and other facilities Qpt~ll~p!i6~yond the Point ofDelivery to provide Primary or Transmission Service may be owned , 9~en~tt?q!a0 ", aintained by the
Company in consideration of the Customer paying a Facilities Charge t~:i:~ "orm any.
Company-owned Facilities Beyond the Point of Delive~ will b
) "
orth in a Distribution
Facilities Investment Report provided to the Customer, As th~iJ~!~ompa~~r..Hlvestment in Facilities
Beyond the Point of Delivery changes in order to provide thE?, C tls~em~r service requirements, the
Company shall notify the Customer of the additions and/ord$l~tions;Qf~~pcilities by forwarding to the
Customer a revised Distribution Facilities Investment Re 0
'\(+ "
In the event the Customer requests the Co~g.~H)';!ii;
;;
d e or reinstall or change Company-
owned Facilities Beyond the Point of DeliverY"
~~~,
!q~~~r shall pay to the Company the "non-
salvable cost" of such removal , reinstallatio~ "
" \!~~g,
~;il;:i' Non-salvable cost as used herein is
comprised of the total original costs of ma~~Eial i(Japor and overheads of the facilities , less the
difference between the salvable cost ,maf" reftJ,~e'(j and removal labor cost including appropriate
overhead costs.
.;i
POWER FACTOR ADJUSTMENT
~!;"
Q~ctor is less than 85 percent, as determined by measurement
Orrtpany may adjust the kW measured to determine the Billing
i.,~~~fed kW by 85 percent and dividing by the actual Power Factor,
\I!nere the Customer s Power Factor is less than 90 percent , as
der actual load conditions , the Company may adjust the kW measured
~and by multiplying the measured kW by 90 percent and dividing by the
TEMPORARY SUSItJENSION
When a Customer has properly invoked Rule G Temporary Suspension of Demand , the Basic
Load Capacity, the Billing Demand , and the On-Peak Billing Demand shall be prorated based on the
period of such suspension in accordance with Rule G, In the event the Customer s metered demand is
less than 1 000 kW during the period of such suspension , the Basic Load Capacity and Billing Demand
will be set equal to 1 )000 kW for purposes of determining the Customer s monthly Minimum Charge.
MONTHLY CHARGE
The Monthly Charge is the sum of the Service, the Basic, the Demand , the Energy, the Power
Cost Adjustment, and the Facilities Charges at the following rates:
IDAHO
Issued Per IPUC Order No. 29505
Effective - December 1 , 2004
Issued by Idaho Power Company
John R. Gale, Vice President) Regulatory Affairs
1221 West Idaho Street , Boise , Idaho
Idaho Power Company First Revised Sheet No. 19-
Cancels
Oriqinal Sheet No. 19-I.P,C. No. 27 Tariff No. 101
SCHEDULE 19
LARGE POWER SERVICE
(Continued)
Basic Charge , per kW of
Basic Load Capacity
Summer
MONTHLY CHARGE (Continued)
SECONDARY SERVICE
Service Charge , per month
$0,
On-Peak Demand Charge , per kW of
On-Peak Billing Demand n/a
Demand Charge , per kW of
Billing Demand $2.
Energy Charge, per kWh
On-Peak
Mid-Peak
Off-Peak
Power Cost Adjustm
0169i
8664i
6716i
5731
n/a
5790i
2.4626i
5731
f1f\is computed as provided in Schedule 55.
Minimum .. ar
The month inimum Charge shall be the sum of the Service Charge, the Basic Charge) the
Demand Charge , the On-Peak Demand Charge, the Energy Charge and the Power Cost
Adjustment.
IDAHO
Issued Per IPUC Order No. 29505
Effective - December 1 , 2004
Issued by Idaho Power Company
John R, Gale) Vice President , Regulatory Affairs
1221 West Idaho Street, Boise , Idaho
Idaho Power Company First Revised Sheet No. 19-
Cancels
Oriqinal Sheet No. 19-I.P,C. No. 27 Tariff No.1 01
SCHEDULE 19
LARGE POWER SERVICE
(Continued)
MONTHLY CHARGE (Continued)
Energy Charge, per kWh
On-Peak
Mid-Peak
Off-Peak
SummerPRIMARY SERVICE
Service Charge , per month $125.
Basic Charge, per kW of
Basic Load Capacity
Demand Charge, per kW of
Billing Demand
$2.
On-Peak Demand Charge, per kW of
On-Peak Billing Demand n/a
Power Cost Adjust
5719~
3214~
1636~
, 0.5731 ~
n/a
1001~
0037~
5731 ~
This Power Cost computed as provided in Schedule 55.
ent in Company-owned Facilities Beyond the Point of Delivery times 1.
MinimumCDb .
The monthl~:NI1inimum Charge shall be the sum of the Service Charge, the Basic Charge) the
Demand Charge , the On-Peak Deman~ Charge the Energy Charge, the Power Cost
Adjustment, and the Facilities Charge.
IDAHO
Issued Per IPUC Order No. 29505
Effective - December 1 , 2004
Issued by Idaho Power Company
John R. Gale , Vice President, Regulatory Affairs
1221 West Idaho Street , Boise , Idaho
Idaho Power Company First Revised Sheet No. 19-
Cancels
Oriqinal Sheet No. 19-LP.C. No. 27 Tariff No, 101
SCHEDULE 19
LARGE POWER SERVICE
(Continued)
MONTHLY CHARGE (Continued)
TRANSMISSION SERVICE Summer
Service Charge , per month
Basic Charge, per kW of
Basic Load Capacity $0.40
Demand Charge, per kW of
Billing Demand $2.51 .
On-Peak Demand Charge , per kW of
On-Peak Billing Demand n/a
Energy Charge, per kWh
On-Peak
Mid-Peak
Off-Peak
Power Cost AdjustrT1'
2. 5364~
2. 2893~
2, 1338~
5731~
n/a
0668~
9719~
5731 ~
m~Q;is computed as provided in Schedule 55.
. ,
r~,~tment in Company-owned Facilities Beyond the Point of Delivery times 1,
Minimum C, r
The monthly Minimum Charge shall be the sum of the Service Charge , the Basic Charge, the
Demand Charge, the On-Peak Demand Charge, the Energy Charge, the Power Cost
Adjustment, and the Facilities Charge.
PAYMENT
The monthly bill for service supplied hereunder is payable upon receipt, and becomes past due
15 days from the date on which rendered,
IDAHO
Issued Per IPUC Order No. 29505
Effective - December 1 2004
Issued by Idaho Power Company
John R. Gale , Vice President , Regulatory Affairs
1221 West Idaho Street, Boise, Idaho
IDAHO POWER COMPANY
I.P.C. NO. 26, TARIFF NO. 101
APPLICABILITY
FIRST REVISED SHEET NO, 91-IDAHO PUBLIC UTILITIES COMMISSION
CANCELS Approved Effective
ORIGINAL SHEET NO. 91-May 20,2002 May 16, 2002
Per D.N. 29026 Errata
Jean D. Jewell Secretary
SCHEDULE 91
ENERGY EFFICIENCY RIDER
This schedule is applicable to all retail Customers served under the Company s schedules and
special contracts. This energy Efficiency Rider is designed to fund the Company s expenditures for the
analysis and implementation of energy conservation programs,
MONTHLY CHARGE
The Monthly Charge is a flat per month charge for Customers taking service under Schedule
and is a cent per kWh charge equal to the Energy Efficiency Rider amount times the monthly billed
energy consumption for all other Customers. The Monthly Charge will be separately stated on the
Customer s regular billing.
Schedule
Schedule
Schedule 7
Schedule 9
Schedule 15
Schedule 19
Schedule 24
Schedule 25
Schedule 32
Schedule 40
Schedule
Schedule 42
Schedule 26
Schedule 28
Schedule 29
Schedule 30
Energy Efficiency Rider
$0.30 per meter per month
$0.000315 per kWh
$0.000178 per kWh
$0.001176 per kWh
$0.000139 per kWh
$0.000301 per kWh, but not to exceed $15.00 per meter per month
$0.000301 per kWh, but not to exceed $15,00 per meter per month
$0.000565 per kWh
$0.000235 per kWh
$0.000565 per kWh
$0.000155 per kWh
$0.000122 per kWh
$0.000110 per kWh
$0.000123 per kWh
$0.000112 per kWh
\ \w\.
;...
~J' Q\
. If
~ ~ \ \\ '
1\ "
\ \\. \"..)
IDAHO
Issued per IPUC Order No. 29026
Effective - May 16, 2002
Issued by IDAHO POWER COMPANY
John R. Gale, Vice President, Regulatory Affairs
1221 West Idaho Street, Boise, Idaho
Idaho Power Company
C. No.. 27. Tariff No.1 01
IDAHO PUBLIC UTILITIES COMMISSIONApproved Effective
Ori inal Sheet No. 91-June 1 , 2004 June 1 , 2004
Jean D. Jewell Secretary
APPLICABILITY
SCHEDULE
ENERGY EFFICIENCY RIDER
This schedule is applicable to all retail Customers served under the Company s schedules and
special contracts. This energy Efficiency Rider is designed to fund the Company s expenditures for the
ana lysis and implementation of energy conservation programs.
MONTHLY CHARGE
The Monthly Charge is a flat per month charge for Customers taking service under Schedule 1 .
and is a cents per kWh charge equal to the Energy Efficiency Rider amount times the monthly billed
energy consumption for all other Customers. The Monthly Charge will be separately stated on the
Customer s regular billing.
Schedule
Schedule
Schedule 7
Schedule 9
Schedule 15
Schedule 19
Schedule 24
Schedule 25
Schedule 32
Schedule 40
Schedule 41
Schedule 42
Schedule 26
Schedule 28
Schedule 29
Schedule 30
Enerqy Efficiency Rider
$0.30 per meter per month
$0.000315 per kWh
$0.000178 per kWh
$0.001176 per kWh
$0.000139 per kWh
$0.000301 per kWh , but not to exceed $15.00 per meter per month
$0.000301 per kWh, but not to exceed $15.00 per meter per month
$0.000565 per kWh
$0.000235 per kWh
$0.000565 per kWh
$0.000155 per kWh
$0.000122 per kWh
$0.000110 per kWh
$0.000123 per kWh
$0.000112 per kWh
IDAHO
Issued Per IPUCOrder Nos. 29505 and 29506
Effective - June 1 , 2004
Issued by IDAHO POWER COMPANY
John R. Gale, Vice President, Regulatory Affairs
1221 West Idaho Street, Boise, Idaho
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CWTP and RWPS Projected Consumptive Power Use Adjustment
Usage (kWh/mo)
RWPS
WTP
Total
2 MGD 3 MGD 4 MGD 6 MGD
159,444 224 000 281 899 405 437
125,000 150 000 175 000 230,000
284,444 374 000 456 899 635,437
Decrease usage to match estimate in Response to Staff Request No. 94RWPS 158,423 222 565 280 093 402 840WTP 125,000 150 000 175 000 230,000Total 283,423 372 565 455 093 632 840
9936
Power Cost Avg. Rate/kWh
RWPS 830 190 10,307 825 0368
WTP 600 520 6,440 464
Total 10,430 710 16,747 289
Months indicated
capacity
Total 52,150 710 33,495 154 192,509
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UNITED W TE R IDAHO IN~ .'\PR 29 PH ~: 23
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CASE NO. UWI-O4-
FIRST PRODUCTION REQUEST
OF UNITED WATER IDAHO
TO COMMISSION STAFF
WORKPAPERS TO
RESPONSE TO
REQUEST NO.
Preparer/Sponsoring Witness: Kathy Stockton
Telephone Number: [phone]
Title: Senior Auditor
FERC: Accounting Releases http://www.ferc.gov/legal/ferc-regs/acct-matts/docs/AI93 - 5-000. asp
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Accounting for Income Taxes
FEDERAL ENERGY REGULATORY COMMISSION
WASHINGTON. D C 20426
In Reply Refer To:
AI935000
April 23r 1993
TO ALL JURISDICTIONAL PUBLIC UTILITIES
LICENCES
AND NATURAL GAS COMPANIES
SUBJECT: ACCOUNTING FOR INCOME TAXES
Ea rly Adoption
Method of Adoption
FERC Approval to Adjust the Deferred Tax
Accounts
Reportinq Any Net Income Effect
Discontinuance of Net-of- Tax Accountinq
Equity AFUDC
Adjustinq Netoftax Components of Utility Plant
Chanqes in Tax Lase or Rates
Flowthrouqh Items
NOL and Tax Credit Carryforwards
Alternative Minimum Tax Credit Carryforward
Requlatory Assets and Liabilities
Costofservice Tariffs
Investment Tax Cred its
Financial Statement Disclosure
Classification of Current Portion of Deferred
Income Taxes
Consolidated Income Taxes
INTRODUCTION
In February 1992, the Financial Accounting
Standards Board (FASB) issued Statement of
Financial Accounting Standards No. 109,
Accounting for Income Taxes (SF AS 109). This
Statement was the culmination of a process
which the FASB began in 1982 to reexamine the
accounting standards for income taxes. SFAS
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109 superseded Accounting Principles Board
Opinion No. 11 , Accounting for Income Taxes
(APB 11).
Under SFAS 109, a current or deferred tax
liability or asset is recognized for the current or
deferred tax consequences of all events that
have been recognized in the financial statements
or tax returns, measured on the basis of enacted
tax law. Under APB 11 , deferred tax
consequences were recognized based on the
differences between the periods in which
transactions affect taxable income and the
periods in which they enter into the
determination of pretax accounting income. The
change affects significantly the measurement
and recognition of current and deferred income
taxes reported in general purpose financial
statements.
' :-
Public utilities, licensees, and natural gas
companies are required to implement the
provisions of SFAS 109 in general purpose
financial statements issued to the public no later
than the first quarter of 1993. The Statement
however encouraged earlier application.
The FERC's Uniform Systems of Accounts
generally provide that an entity follow
comprehensive interperiod income tax allocation
except that an entity is not required to adopt
comprehensive interperiod income tax allocation
until the deferred income taxes are included as
an expense in its rate levels by regulatory
authorities.
Since the issuance of Order No. 144 in 1981 , the
FERC's regulations have required companies to
determine the income tax allowance included in
jurisdictional rate levels on a fully normalized
basis. Also, Order No. 144 requires an entity to
compute the income tax component in its cost of
service by making provision for any excess or
deficiency in deferred taxes under the following
circumstances: (1) if the entity has not provided
deferred taxes in the same amount that would
have accrued had tax normalization been applied
for tax effects of timing difference transactions
originating at any time prior to the test period;
or (2) if, as a result of changes in tax rates, the
accumulated provision for deferred taxes
becomes deficient in or in excess of amounts
necessary to meet future tax liabilities as
determined by application of the current tax rate
to all timing difference transactions originating
in the test period and prior to the test period.
Therefore, the FERC's accounting and rate
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regulations, when read together, already require
use of a liability method somewhat similar to
SFAS 109 for the jurisdictional portion of an
entity s business.
;"',.., "
" I
The primary conceptual difference between SFAS
109 and the FERC's method relates to how
regulatory assets and liabilities are recognized.
Under the FERC approach, regulatory assets and
liabilities are effectively netted against the
deferred tax asset and liability accounts or, in
some cases, not reported until related revenues
are recognized. Under SFAS 109 all tax related
regulatory assets and liabilities are shown broad.
Certain other differences between the FERC'
Uniform Systems of Accounts and SFAS 109 are
discussed in the guidance that follows.
\/j
It is axiomatic that accounting statements issued
by the FASB for use in general purpose financial
statements of business entities should not,
itself, have an economic rate effect on a
regulated entity or its customers. SFAS 109, in
the main, requires costbased regulated entities
to account for and report deferred tax assets and
liabilities separately from related regulatory
assets and liabilities. In general, such increases
in the level of detail for an entity s assets and
liabilities enhance disclosure, making financial
information more usefu I to its users. The
enhanced disclosure required by SFAS 109 may
also prove useful for regulatory purposes.
Moreover, adoption of SFAS 109 for FERC
accounting and reporting purposes would result
in financial information reported to the FERC and
the public using the same accounting standard
an objective having considerable merit in its own
right.
Therefore, public utilities, licensees, and natural
gas companies shall adopt SFAS 109 for financial
accounting and reporting to FERC. In order
insure that the FERC continues to have the
financial information it needs for regulatory
purposes however, entities shall conform their
accounting and reporting to the guidance
provided in this letter. Neither SFAS 109 nor the
guidance contained in this letter for
implementing the standard for FERC financial
accounting and reporting purposes relieves
entities from the requirements of Section
154.63a, Tax normalization for interstate
pipelines, or Section 35., Tax normalization
for public utilities, of the Commission
regulations.
The Commission delegated authority to the Chief
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Accountant under 18 C.R. 375.303 to issue
interpretations of the Uniform System of
Accounts for public utilities, licensees and
natural gas companies and sign correspondence
on behalf of the Commission relating to Annual
Report Nos. 1 , IF, 2, and 2F. The guidance
provided herein constitutes final agency action
pursuant to this authority. Within 30 days of the
date of this letter, interested parties may file a
request for rehearing by the Commission under
18 C.R. 9 385.713.
! .-, ".
1. EARLY ADOPTION
Question: SFAS 109 is effective for fiscal years
beginning
after December 15, 1992, but the FASB
encourages
earlier application. Mayan entity implement
SFAS
109 for FERC accounting and reporting
requirements
prior to January 1 , 1993?
;:', " ;
Response: An entity implementing SFAS 109 in
its general purpose financial statements prior to
the Statement's required effective date, may
also adopt the Statement for FERC accounting
and reporting purposes. An entity however shall
not implement SFAS 109 for FERC accounting
and reporting purposes before it implements the
Statement in its general purpose financial
statements. Entities shall implement SFAS 109
for FERC accounting and reporting purposes no
later than fiscal years beginning after December
15, 1992.
2. METHOD OF ADOPTION
Question: In the first year applied, SFAS 109
permits an entity to either (1) include the
cumulative effect of the accounting change
the determination of current year net income, as
provided for in APB Opinion No. 20, Accounting
Changes; or (2) restate financial statements for
prior periods to conform to the provisions of the
Statement. Are both of these procedures
acceptable to the FERC?
Response: No. In reporting to the FERC, the
effect of initially applying this statement shall be
reported as the cumulative effect of a change in
accounting principle in accordance with the
provisions of APB 20. An entity wi II not be
permitted to restate prior years financial
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statements.
3. FERC APPROVAL TO ADJUST THE
DEFERRED TAX ACCOUNTS
Question: The instructions to the Uniform
Systems of Accounts presently restrict the use of
the deferred tax balance sheet accounts to the
purposes set forth in the text of the accounts
unless prior Commission approval is obtained.
Do the adjustments to the deferred tax accounts
for the implementation of SFAS 109 fall within
this restriction?
Response: Yes. This letter however, will
constitute the requisite authority for making
adjustments to the deferred tax accounts when
the application of SFAS 109 does not affect net
income (i.e. the deferred tax adjustments are
accompanied by the recordation of equal
regulatory assets or liabilities). Entities shall
request and obtain specific FERC approval for all
other adjustments to the deferred tax accounts,
including those related to nonjurisdictional
activity. The filing shall include a complete
explanation of and justification for an entity
proposed accounting.
4. REPORTING ANY NET INCOME EFFECT
Question: If the initial implementation of SFAS
109 affects net income and an entity obtains
FERC approval to adjust its deferred tax
accounts, where should the income effect be
reported in FERC financial reports (i.e. FERC
Form Nos. 1 , l-, 2 and 2-A etc.
Response: The FERC report forms do not
currently have a line for reporting the
cumulative effect of a change in accounting
principle. Therefore, the effect on net income
shall be reported on the income statement on
the lines designated for extraordinary income or
deductions, as appropriate , in FERC financial
reports. To identify that the effects on net
income resulting from the initial adoption of
SFAS 109 are not an "extraordinary item " as
that term is defined in the Uniform Systems of
Accounts, entities shall also disclose in a
footnote to the financial statements the full
particulars of any amounts reports as the
cumulative effect of a change in accountingprinciple.
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5. DISCONTINUANCE Of NET-Of-TAX
ACCOU NTING
Question: SF AS 109 prohibits net-of-tax
accounting and reporting in general purpose
financial statements. May entities continue to
account and report to FERC on a net-of-tax
basis?
Response: No. The present instructions to the
Uniform Systems of Accounts require entities to
record and report the deferred tax consequences
of transactions, events, and circumstances in the
appropriate deferred tax accounts. While the
FERC has always preferred gross-of-tax financial
accounting and reporting, it permitted an
exception to this general requirement where a
net-of-tax allowance for funds used during
construction (AFUDC) rate was prescribed by a
regulatory body in setting an entity s rate levels.
The FERC granted this exception to avoid the
burden of maintaining duplicate records for
utility plant on a net-of-tax basis for one
jurisdiction and a gross-of-tax basis for another.
Because SFAS 109 prohibits netoftax accounting
and reporting in general purpose financial
statements, the reasons for permitting the
exception to the general requirement are no
longer relevant. Therefore, entities shall
discontinue the use of netoftax AFUDC rates.
, ;)
6. EQUITY AfU DC
Question: SFAS 109 considers the equity
component of AFUDC a temporary difference for
which deferred income taxes must be provided.
How should an entity record the deferred tax
liability for the equity component of AFUDC and
the related regulatory asset in its accounts?
Response: An entity shall record the deferred
tax liability for the equity component of AFUDC
in Account 282, Accumulated Deferred Income
Taxes Other Property, and any corresponding
regulatory asset in Account 182., Other
Regulatory Assets. The regulatory asset is itself
a temporary difference for which deferred
incomes taxes shall be recognized and recorded
in Account 283, Accumulated Deferred Income
Taxes Other. This accounting shall be followed
for the adjustments required upon initial
application of the statement and for all amounts
of equity AFUDC capitalized in subsequent
periods.
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7. ADJUSTING NETOFTAX COMPONENTS OF
UTILITY PLANT
,.\.;
Question: Upon initial application of SF AS 109,
an entity must adjust any netoftax components
of construction workinprogress and plant in
service. How should an entity account for these
adjustments?
Response: Entities that previously accounted
for certain components of plant cost on a
netoftax basis, primarily the borrowed funds
component of AFUDC, have effectively recorded
the deferred income tax effects of those
components directly in the plant accounts. The
deferred income taxes were computed using the
income tax rates in effect when the items were
capitalized.
5:\"
For constructionworkinprogress, an entity shall
transfer the deferred income taxes actually
included therein to Account 282, Accumulated
Deferred Income Taxes Other Property. If the
amount transferred to Account 282 is greater or
less than the amount needed to meet the future
tax liability related to those items based on
current tax rates, additional adjustments to the
deferred tax liability shall be made consistent
with SFAS 109. If as a result of action by a
regulator it is probable that such excess or
deficiency will be returned to or recovered from
customers in rates, an asset or liability shall be
recognized for that probable future revenue or
reduction in future revenue in Accounts 182.
Other Regulatory Assets, or 254, Other
Regulatory Liabilities, respectively. That asset or
liability is also a temporary difference for which
a deferred tax asset or liability shall be
recognized in Account 190, Accumulated
Deferred Income Taxes, or Account 283,
Accumulated Deferred Income Taxes Other, as
appropriate.
:' i)
Similar accounting is to be followed for
plantin-service items when the required
information is available. However, in order to
properly adjust the plantinservice account an
entity will need to determine the specific
amounts of borrowed funds and equity AFUDC
capitalized in prior periods, the extent to which
those amounts and other netoftax components
have been depreciated , the specific property
units to which the amounts have been assigned
and the extent to which property retirements
affect the accounts in which the income tax
effects now reside. In virtually all instances that
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information will simply not be available or will be
too costly to develop. In that situation, an entity
shall not adjust the plantinservice accounts
based on estimates or presumed relationships.
Instead , an alternate method shall be used to
determine the necessary adjustments.
Under the alternate method, any difference
between the reported amount and the tax basis
of plant is a temporary difference for which a
deferred tax liability shall be recorded in Account
282. If as a result of action by a regulator, it is
probable that amounts required for settlement of
that deferred tax liability will be recovered from
customers through future rates, a regulatory
asset equal to that probable future revenue
should be recorded in Account 182.3. That asset
is also a temporary difference for which a
deferred tax liability shall be recognized in
Account 283, Accumulated Deferred Income
Taxes Other.
8. CHANGES IN TAX LAW OR RATES
Question: How should an entity record the
effect of a change in tax law or rates that occurs
after the year of initial implementation of SFAS
109?
Response: The entity shall adjust its deferred
tax liabilities and assets for the effect of the
change in tax law or rates in the period that the
change is enacted. The adjustment shall be
recorded in the proper deferred tax balance
sheet accounts (Accounts 190 , 281 , 282 and
283) based on the nature of the temporary
difference and the related classification
requirements of the accounts. If as a result of
action by a regulator, it is probable that the
future increase or decrease in taxes payable due
to the change in tax law or rates will
recovered from or returned to customers through
future rates, an asset or liability shall
recognized in Account 182.3, Other Regulatory
Assets, or Account 254, Other Regulatory
Liabilities, as appropriate, for that probable
future revenue or reduction in future revenue.
That asset or liability is also a temporary
difference for which a deferred tax asset or
liability shall be recognized in Account 190
Accumulated Deferred Income Taxes or Account
283, Accumulated Deferred Income Taxes Other
as appropriate.
9. FLOWTHROUGH ITEMS
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Question: An entity adopting SFAS 109
previously flowed through the tax benefits of
certain temporary differences in rates when the
differences originated. How should the Company
recognize the deferred income taxes attributable
to these temporary differences in its accounts?
Response: Deferred income taxes on all
temporary differences, including differences
where the related income tax effects have been
or are presently flowed through in rates, should
be recorded in Accounts 190, 281, 282 and 283
based on the nature of the temporary difference
and the classification requirements of those
accounts. If as a result of action by a regulator
it is probable that the future increase or
decrease in taxes payable due to flow through
ratemaking practices will be recovered from or
returned to customers through future rates, an
asset or liability shall be recognized in Account
182., Other Regulatory Assets, or Account 254
Other Regulatory Liabilities, as appropriate, for
that probable future revenue or reduction in
future revenue. That asset or liability is also a
temporary difference for which a deferred tax
asset or liability shall be recognized in Account
190, Accumulated Deferred Income Taxes or
Account 283, Accumulated Deferred Income
Taxes Other, as appropriate.
. ,/;
oJ.
10.NOL AND TAX CREDIT CARRYFORWARDS
Question: How should an entity account for the
income tax effect of a net operating loss (NOl)
carryforward or a tax credit carryforward?
, '
Response: An entity shall record the income tax
effects of a NOl carryforward and a tax credit
carryforward in a separate subaccount of
Account 190, Accumulated Deferred Income
Taxes Debit. In the event that it is more likely
than not (a likelihood of more than 50 percent)
that some portion of its deferred tax assets wi
not be realized , an entity hall record a valuation
allowance in a separate subaccount of Account
190. The entity shall disclose full particulars as
to the nature and amount of each type of
operating loss and tax credit carryforward in the
notes to the financial statements.
11. ALTERNATIVE MINIMUM TAX CREDIT
CARRYFO RW ARD
Question: How should an entity record an
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alternative minimum tax credit carryforward?
Response: SFAS 109 requires a deferred tax
liability or asset to be recognized for the
estimated future tax effects attributable to
temporary differences and carryforwards. Under
SF AS 109, the AMT is viewed as a tax credit
carryforward. Therefore, an entity shall record
an alternative minimum tax credit carryforward
in a separate subaccount of Account 190,
Accumulated Deferred Income Taxes.
12. REGULATORY ASSETS AND LIABILITIES
Question: Where an entity recognizes
regulatory assets or liabilities in connection with
a change in its deferred tax assets and liabilities
should an entity record the change in the
required deferred income tax balances in the
appropriate income tax expense accounts and
separately recognize the creation of regulatory
assets and liabilities in a different income
statement account? If so, which income
statement account should be used to record the
creation of regulatory assets and liabilities?
Response: The FERC recently considered the
proper accounting for regulatory assets and
liabilities in a rulemaking proceeding, Docket No.
RM921000. Under the final rule issued in that
proceeding (Commission Order No. 552 issued
March 31 1993), an entity is not required to use
income statement accounts to recognize
regulatory assets and liabilities related to
changes in deferred tax assets or liabilities when
an equal and corresponding deferred tax asset or
liability is recorded.
13. COSTOFSERVICE TARIFFS
Question: An entity has a costofservice tariff
under which monthly billings are based
recorded amounts under FERC's Uniform
Systems of Accounts. Under the tariff, only the
amounts recorded in certain specified accounts
affect the monthly billings. For example, the
tariff may specify that Account 282 must be
included in the determination of rate base but is
silent with respect to Account 254. If
implementing sFAs 109 for FERC accounting and
reporting results in a reduction in the balance in
Account 282 but a corresponding and equal
increase in Account 254 (to recognize a
regulatory liability) may an entity adjust its
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monthly billings to give proper effect to the
revised accounting for income taxes?
" \'
Response: Adoption of SFAS 109 for FERC
accounting and reporting purposes should not
affect the measurement of cost included in an
entity s billing determinations. If an entity
billing determinations would be affected
adoption of SFAS 109, because of the provisions
of its tariffs, the entity shall make a filing with
the proper rate regulatory authorities prior to
implementing the change for tariff billing
purposes.
14. INVESTMENT TAX CREDITS
Question: Some entities accounted for
investment tax credits using the deferral
method. SFAS 109 views deferred investment
tax credits as a temporary difference (i.e. as a
reduction in the book basis of the property) for
which deferred income taxes are required. How
should the deferred income taxes be recorded?
\,\
Response: The deferred income taxes
attributable to deferred investment tax credits
shall be recorded in a separate subaccount of
Account 190, Accumulated Deferred Income
Taxes. If as a result of action by a regulator it is
probable that the reduction in future taxes
payable due to the tax deductibility of the higher
tax basis of the property will be returned to
customers in rates, a regulatory liability shall
recorded for the amount by which future rates
will be reduced. The regulatory liability shall be
recorded in Account 254, Other Regulatory
Liabilities. The regulatory liability is itself a
temporary difference for which deferred incomes
taxes shall be recognized. Those deferred
income taxes shall also be recorded in Account
190.
15. FINANCIAL STATEMENT DISCLOSURE
Question: SFAS 109 requires certain financial
statement disclosures concerning income taxes.
Should entities disclose the same information in
financial statements filed with FERC?
Response: Yes. In addition to the disclosure
requirements specified elsewhere in this letter
entities shall follow the disclosure requirements
of SFAS 109 in any financial statements filed
with the FERC. The required information shall be
shown in the Notes To Financial Statements.
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,- ...; .
16. CLASSIFICATION OF CURRENT
PORTION OF DEFERRED INCOME TAXES
Question: SFAS 109 requires entities that
prepare classified statements of financial
position to separate deferred tax liabilities and
assets into current and noncurrent amounts.
Should entities reclassify the current portion
deferred tax liabilities or assets to current
accounts, such as Account 174, Miscellaneous
Current and Accrued Assets, or Account 242
Miscellaneous Current and Accrued Liabilities, for
FERC accounting and financial reporting
pu rposes?
Response: No. All deferred tax liabilities and
assets shallbe recorded in Accounts 190, 281,
282, or 283 , asappropriate, and the current
portion of thoseamounts shall not be reclassified
to otheraccounts for FERC reporting purposes.
17. CONSOLIDATED INCOME TAXES
Question: Prior to SFAS 96, the FASB (or its
predecessor) had not issued any specific
pronouncements related to how an entity that
joins in the filing of a consolidated income tax
return should determine income tax expense in
its separately reported financial statements.
Footnote 12 of SFAS 96 provided that the
consolidated amount is the amount of current
and deferred taxes reported in the consolidated
financial statements for the group, or the
amount that would be reported if such financial
statements were prepared. Under SFAS 96, the
sum of the amounts allocated to members of the
group (net of consolidation eliminations) would
equal the consolidated amount.
. :;
SFAS 109 modified the requirements set forth in
SFAS 96. SFAS 109 does not require one
particular method to allocate the consolidated
income tax liability between members of a
group. Instead, SFAS 109 permits a number of
methods, including methods in which the sum of
the amounts allocated to individual members of
the group may not equal the consolidated
amount. SFAS 109 specifically states that a
method that allocates current and deferred taxes
to members of the group as if each member
were a separate taxpayer (separate return
method) is consistent with the statement'
criteria.
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Will the FERC permit an entity to use a separate
return method for FERC financial accounting and
reporting?
Response: No. The FERC has issued several
decisions rejecting the use of the separate return
method for determining income tax expense
when an entity files as part of a consolidated
group. Instead , the FERC relies on the
standalone method of allocating income taxes
between members of a consolidated group.
Under the standalone method the consolidated
tax expense is allocated to individual members
through recognition of the benefits/burdens
contributed by each member of the consolidated
group to the consolidated return. Under the
standalone method, the sum of amounts
allocated to individual members equal the
consolidated amount.
Russell E. Faudree Jr.
Chief Accountant
Updated: October 2003
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