20040220Hessing Exhibits.pdf

~~
n
t
'
I
:
1
N'

P
'
;X
:
::
q

r
6

s
-
:
(1
)

0-
'
.j
:
o
.
.
~

Z
:
=
;
:
S'

~

Z
gq

~

~
en

n

...
.
.
.
.
..
.
.
.
.
.

I

...
.
.
.
.
P'

t
:
d

0
0
...
.
.
.
.
CO
M
P
A
R
I
S
O
N

O
F

J
U
R
I
S
D
I
C
T
I
O
N
A
L

Al
l
O
C
A
T
O
R
S
Ca
s
e

N
o
.

I
P
C
-
94
-
5
t
o

C
a
s
e

N
o
.

I
P
C
-
O3
-
Ca
s
e

N
o
.

I
P
C
-
O3
-
De
s
c
r
i
p
t
i
o
n
IP
C
-
94
-
IP
C
-
03
-
To
t
a
l
Id
a
h
o
All
o
c
a
t
o
r

To
t
a
l
Id
a
h
o
Al
l
o
c
a
t
o
r
Co
m
p
a
n
Co
m
p
a
n
Cu
s
t
o
m
e
r

A
l
l
o
c
a
t
i
o
n
s
Av
e
r
a
g
e

N
u
m
b
e
r

o
f

C
u
s
t
o
m
e
r
s

-

D
A
9
0
9
30
6
,
4
3
0
28
9
94
8
94
.
62
%
40
7
31
1
38
9
97
4
95
.
74
%
De
m
a
n
d

A
l
l
o
c
a
t
i
o
n
s
Tw
e
l
v
e

C
o
i
n
c
i
d
e
n
t

P
e
a
k

D
e
m
a
n
d

-

D
1
0
13
8
07
6
84
9
77
4
86
.
52
%
19
8
,
4
0
4
07
6
,
4
3
7
94
.
4
5
%
En
e
r
g
y

A
l
l
o
c
a
t
i
o
n
s
Ge
n
e
r
a
t
i
o
n

L
e
v
e
l

E
n
e
r
g
y

-

E
1

14
,
4
9
1
12
1
39
4
75
9
85
.
53
%
10
7
57
6
27
5
01
2
94
.
10
%
U:
\
k
h
e
s
s
i
n
\
I
P
C
E
0
3
1
3
\
S
t
a
f
f

C
a
s
e
\
C
o
m
p
a
r
i
s
o
n

o
f

J
S
S

A
l
l
o
c
a
t
o
r
s

2/
1
0
/
2
0
0
4
ID
A
H
O

C
O
M
M
I
S
S
I
O
N

S
T
A
F
F
JU
R
I
S
D
I
C
T
I
O
N
A
L

S
E
P
A
R
A
T
I
O
N

S
T
U
D
Y

-

R
E
V
E
N
U
E

R
E
Q
U
I
R
E
M
E
N
T
FO
R

TH
E

TW
E
L
V
E

M
O
N
T
H
S

E
N
D
I
N
G

D
E
C
E
M
B
E
R

3
1
20
0
3
WI
T
H

A
L
L

A
D
J
U
S
T
M
E
N
T
S
RE
T
A
I
L

J
U
R
I
S
D
I
C
T
I
O
N
S
SU
M
M
A
R
Y
AL
L
O
e
!
TO
T
A
L
ID
A
H
O
TO
T
A
L
TO
T
A
L
FI
R
M
3
D
E
S
C
R
I
P
T
I
O
N
SO
U
R
C
E
SY
S
T
E
M
IP
U
C
RE
T
A
I
L
RE
S
A
L
E
TR
A
N
S
F
E
R
SU
M
M
A
R
Y
O
F
R
E
S
U
L
T
S
'
"
6
R
A
T
E

O
F

R
E
T
U
R
N

U
N
D
E
R

P
R
E
S
E
N
T

R
A
T
E
S
TO
T
A
L

C
O
M
B
I
N
E
D

R
A
T
E

B
A
S
E
60
0
61
9
12
6
48
1
82
4
49
2
1 ,
55
9
92
6
94
4
50
0
46
0
19
1
72
2
SA
L
E
S

R
E
V
E
N
U
E
S
57
6
03
9
17
8
54
3
33
2
60
5
57
1
66
8
73
1
37
0
44
7
OT
H
E
R

O
P
E
R
A
T
I
N
G

R
E
V
E
N
U
E
S
58
2
21
4
97
5
99
0
87
8
10
8
24
3
98
7
4,
4
6
0
11
8
TO
T
A
L

O
P
E
R
A
T
I
N
G

R
E
V
E
N
U
E
S
61
8
62
1
39
2
57
9
30
8
59
5
60
9
54
6
83
9
61
4
,
4
3
4
4,
4
6
0
11
8
OP
E
R
A
T
I
N
G

E
X
P
E
N
S
E
S
OP
E
R
A
T
I
O
N

&

M
A
I
N
T
E
N
A
N
C
E

E
X
P
E
N
S
E
S
37
0
56
3
22
0
34
6
81
9
65
6
36
4
;
6
9
2
81
6
3,
4
9
3
24
5
37
7
16
0
DE
P
R
E
C
I
A
T
I
O
N

E
X
P
E
N
S
E
99
5
21
7
03
6
65
3
81
3
23
7
60
2
,
4
4
5
57
9
53
4
AM
O
R
T
I
Z
A
T
I
O
N

O
F

L
I
M
I
T
E
D

T
E
R
M

P
L
A
N
T
81
8
33
8
08
9
40
3
57
9
08
7
45
2
17
3
,
7
9
9
TA
X
E
S

O
T
H
E
R

T
H
A
N

I
N
C
O
M
E
21
,
4
0
9
72
4
48
2
79
3
93
0
32
5
12
1
21
6
35
8
18
3
PR
O
V
I
S
I
O
N

F
O
R

D
E
F
E
R
R
E
D

I
N
C
O
M
E

T
A
X
E
S
10
9
04
3
03
0
14
9
15
9
88
1
36
1
)
(4
8
47
7
)
IN
V
E
S
T
M
E
N
T
T
A
X

C
R
E
D
I
T

A
D
J
U
S
T
M
E
N
T
(3
0
8
16
6
)
(3
0
0
34
6
)
(3
1
3
20
5
)
23
4
80
5
FE
D
E
R
A
L

I
N
C
O
M
E

T
A
X
E
S
36
8
28
9
77
1
18
6
75
3
05
3
(1
7
86
8
)
(3
6
6
89
6
)
ST
A
T
E

I
N
C
O
M
E

T
A
X
E
S
3,
4
7
5
57
4
38
3
52
1
53
4
89
2
75
5
)
(5
6
56
3
)
TO
T
A
L

O
P
E
R
A
T
I
N
G

E
X
P
E
N
S
E
S
51
7
,
4
3
1
23
9
48
3
31
3
01
5
50
9
15
0
08
6
25
9
60
8
02
1
54
5
OP
E
R
A
T
I
N
G

I
N
C
O
M
E
10
1
19
0
15
3
99
5
58
0
10
0
39
6
75
3
35
4
82
6
43
8
57
4
AD
D
:

I
E
R
C
O

O
P
E
R
A
T
I
N
G

I
N
C
O
M
E
57
8
25
4
13
1
,
02
0
50
5
25
9
99
5
CO
N
S
O
L
I
D
A
T
E
D

O
P
E
R
A
T
I
N
G

I
N
C
O
M
E
10
8
,
7
6
8
,
4
0
7
10
3
,
12
6
60
0
10
7
90
2
01
2
42
7
82
1
43
8
57
4
RA
T
E

O
F

R
E
T
U
R
N

U
N
D
E
R

P
R
E
S
E
N
T

R
A
T
E
S
79
5
%
95
9
%
91
7
%
07
4
%
1.
4
5
3
%
27

D
E
V
E
L
O
P
M
E
N
T

O
F

R
E
V
E
N
U
E

R
E
Q
U
I
R
E
M
E
N
T
S
RA
T
E

O
F

R
E
T
U
R
N

R
E
Q
U
I
R
E
D

~

1
0
.
0%

R
O
E
65
0
%
RE
T
U
R
N

A
T

C
L
A
I
M
E
D

R
A
T
E

O
F

R
E
T
U
R
N
11
3
35
9
57
4
EA
R
N
I
N
G
S

D
E
F
I
C
I
E
N
C
Y
23
2
97
3
NE
T
-
TO
-
GR
O
S
S

T
A
X

M
U
L
T
I
P
L
I
E
R
1.
4
4
6
RE
V
E
N
U
E

D
E
F
I
C
I
E
N
C
Y
79
6
88
0

I
FIR
M

J
U
R
I
S
D
I
C
T
I
O
N
A
L

R
E
V
E
N
U
E
S
48
3
96
1
,
36
9
PE
R
C
E
N
T

I
N
C
R
E
A
S
E

R
E
Q
U
I
R
E
D
06
%
SA
L
E
S

A
N
D

W
H
E
E
L
I
N
G

R
E
V
E
N
U
E
S

R
E
Q
U
I
R
E
D
49
8
75
8
24
9
t2

~

n

t'I
:
1
N'

P'

&
::
q

g
;

.,
.
.
.
--
-

(
1
)

0-
'
CJ
)

'
"
7

.
,
.
.
.
.j
:
o
.
.

C
J
)

~
.
.
.
.
.
.
.
S'

~

Z
gq

~

~
en

n

..
.
.
.
.
.
..
.
.
.
.
.

"
""
"
"
P'

t
:
d

...
.
.
.
.
U:l
k
h
e
s
s
i
n
I
I
P
C
E
0
3
1
3
1
S
(
a
f
f

C
a
s
e
l
A
c
o
u
n
U
n
9

J
S
S

R
e
s
u
l
t
s

2
-
17
-
04

2
1
1
9
/
2
0
0
4
t0
~
O
t
:
d
i0
'

P
'
;X
:
~:
:
q

g;

~
1
6
~
~

Z:
:
;
,
'
gJ
.
o
Z
~
~

~
en
O
-
,
..
.
.
.
.
.

I

P'

t
:
d

0
...
.
.
.
.
Li
n
e
Ta
r
i
f
f

D
e
s
c
r
i
p
t
i
o
n
Un
i
f
o
r
m

T
a
r
i
f
f

R
a
t
e
s
:
Re
s
i
d
e
n
t
i
a
l

S
e
N
i
c
e
Sm
a
l
l

G
e
n
e
r
a
l

S
e
N
i
c
e
La
r
g
e

G
e
n
e
r
a
l

S
e
N
i
c
e
Du
s
k

t
o

D
a
w
n

L
i
g
h
t
i
n
g
La
r
g
e

P
o
w
e
r

S
e
N
i
c
e
Ag
r
i
c
u
l
t
u
r
a
l

I
r
r
i
g
a
t
i
o
n

S
e
N
i
c
e
Un
m
e
t
e
r
e
d

G
e
n
e
r
a
l

S
e
N
.
St
r
e
e
t

Li
g
h
t
i
n
g
10

Tr
a
f
f
i
c

C
o
n
t
r
o
l

L
i
g
h
t
i
n
g
11

To
t
a
l

U
n
i
f
o
r
m

T
a
r
i
f
f
s
Sp
e
c
i
a
l

C
o
n
t
r
a
c
t
s
:
12

Mi
c
r
o
n
13

J

R
S
i
m
p
l
o
t
14

D
O
E
15

To
t
a
l

Sp
e
c
i
a
l

C
o
n
t
r
a
c
t
s
To
t
a
l

I
d
a
h
o

Re
t
a
i
l

S
a
l
e
s
U:l
k
h
e
s
s
i
n
l
i
P
C
E
0
3
1
3
l
S
l
a
f
f

C
a
s
e
l
C
O
S

E
x
h
i
b
i
l
s

2
/
1
1
/
2
0
0
4
Id
a
h
o

C
o
m
m
i
s
s
i
o
n

S
t
a
f
f
Re
s
u
l
t
s

o
f

We
i
Q
h
t
e
d

1
2
C
P
Co
s
t

o
f

S
e
r
v
i
c
e

S
t
u
d
y
Fo
r

I
d
a
h
o

P
o
w
e
r

C
o
m
p
a
n
y
St
a
t
e

o
f

I
d
a
h
o
No
r
m
a
l
i
z
e
d

1
2
-
Mo
n
t
h
s

E
n
d
i
n
g

D
e
c
e
m
b
e
r

3
1
,
20
0
3
(1
)

(2
)
Ra
t
e

20
0
3

A
v
g
.
Sc
h
.

N
u
m
b
e
r

o
f
No
.

Cu
s
t
o
m
e
r
s
(4
)
Cu
r
r
e
n
t
Ba
s
e
Re
v
e
n
u
e
(5
)
(6
)
(7
)
Av
g
.
Ce
n
t
s
Pe
r

K
W
H
(8
)
(3
)
20
0
3

S
a
l
e
s
No
r
m
a
l
i
z
e
d
(k
W
h
)
W1
2
C
P
Re
v
e
n
u
e
Pe
r
c
e
n
t
Ch
a
n
G
e
Re
v
e
n
u
e
Ad
i
u
s
t
m
e
n
t
s
33
5
,
60
5
14
1
,
39
3
,
4
2
6
21
4
,
28
9
,
4
1
2
(2
,
32
4
,
00
9
)
21
1
,
96
5
,
4
0
3
(1
.
08
)
%
32
,
31
6
26
5
,
33
5
,
66
7
16
,
7
9
8
,
4
7
9
87
,
59
1
16
,
88
6
,
07
0
52
%
17
,
4
1
5
01
4
,
4
2
6
,
98
6
10
7
,
66
9
,
01
1
(3
,
78
6
,
25
7
)
10
3
,
88
2
,
75
4
3.
4
5
(3
.
52
)
%
87
2
,
58
6
1,
3
8
9
,
11
2
(1
,
5
1
9
,
20
7
)
(1
3
0
,
09
5
)
(2
.
22
)
(1
0
9
.
37
)
%
10
5
97
8
,
82
4
,
23
7
55
,
06
3
,
58
1
(2
,
4
6
5
,
4
0
3
)
52
,
59
8
,
17
8
(4
.
4
8
)
%
13
,
51
7
62
0
,
93
0
,
93
1
60
,
29
1
,
58
0
28
,
4
7
0
,
28
6
88
,
7

6
1
,
8
6
6
5.
4
8
47
.
22
%
22
4
16
,
05
4
,
94
2
90
7
,
69
1
(3
1
3
,
56
2
)
59
4
,
12
9
3.
7
0
(3
4
.
55
)
%
1,
4
3
2
17
,
91
2
,
03
9
1
,
80
9
,
26
5
(4
9
1
,
8
0
9
)
31
7
,
4
5
6
(2
7
.
18
)
%
38
4
21
8
28
4
14
7
36
5
27
2
78
2
(4
.
00
)
%
40
1
,
6
7
2
11
,
07
0
,
13
5
,
03
2
45
8
,
50
2
,
27
8
17
,
64
6
,
26
5
47
6
,
14
8
,
54
3
85
%
63
6
,
96
7
,
67
0
16
,
20
4
,
10
7
(1
,
66
6
,
38
3
)
14
,
53
7
,
72
4
(1
0
.
28
)
%
18
6
,
68
4
,
66
5
63
2
,
57
1
(6
6
4
,
12
3
)
96
8
,
4
4
8
(1
4
.
34
)
%
20
3
,
08
4
,
14
6
62
2
,
4
1
3
(1
1
5
,
22
4
)
50
7
,
18
9
(2
.
4
9
)
%
02
6
,
73
6
,
4
8
1
25
,
4
5
9
,
09
1
(2
,
4
4
5
,
7
3
0
)
23
,
01
3
,
36
1
(9
.
61
)
%
40
1
,
67
5
12
,
09
6
,
87
1
,
5
1
3
48
3
,
96
1
,
36
9
15
,
20
0
,
53
5
49
9
,
16
1
,
90
4
14
%
Li
n
e
T
o
r
i
f
f

De
s
c
r
i
p
t
i
o
n
Un
i
f
o
r
m

T
o
r
i
f
f

R
a
t
e
s
:
Re
s
i
d
e
n
t
i
a
l

S
e
r
v
i
c
e
Sm
a
l
l

G
e
n
e
r
a
l

S
e
r
v
i
c
e
Lo
r
g
e

G
e
n
e
r
a
l

S
e
r
v
i
c
e
Du
s
k

t
o

D
a
w
n

L
i
g
h
t
i
n
g
Lo
r
g
e

P
o
w
e
r

S
e
r
v
i
c
e
Ag
r
i
c
u
l
t
u
r
a
l

I
r
r
i
g
a
t
i
o
n

S
e
r
v
i
c
e
Un
m
e
t
e
r
e
d

G
e
n
e
r
a
l

Se
r
v
o
St
r
e
e
t

L
i
g
h
t
i
n
g
10

Tr
a
f
f
i
c

C
o
n
t
r
o
l

L
i
g
h
t
i
n
g
11

To
t
a
l

U
n
i
f
o
r
m

T
a
r
i
f
f
s
Sp
e
c
i
a
l

C
o
n
t
r
a
c
t
s
:
12

Mi
c
r
o
n
13

J

R
S
i
m
p
l
o
t
14

D
O
E
15

To
t
a
l

S
p
e
c
i
a
l

C
o
n
t
r
a
c
t
s
t2
~
O
t
:
d
N'

P
'
;X
:
::
q

r
6

S
"
'
.
1
6
(I
)

'
"
7

0
-
'
.j
:
o
.
.

~

~:
:
;
.
.
_.

0

'"
7
.
~
gq

~

~
en
O
-
..
.
.
.
.
.

'
P'

t'I
:
1
.
.
.
.
.
.
.
...
.
.
.
.
To
t
a
l

I
d
a
h
o

Re
t
a
i
l

S
a
l
e
s
U:l
k
h
e
s
s
i
n
\
I
P
C
E
0
3
1
3
\
S
l
a
f
f

C
a
s
e
l
C
e
S

E
x
h
i
b
i
t
s

2
/
1
7
/
2
0
0
4
Id
a
h
o

C
o
m
m
i
s
s
i
o
n

S
t
a
f
f
Re
s
u
l
t
s

o
f

4
M
o
n
t
h

W
e
i
Q
h
t
e
d

1
2
C
P
Co
s
t

o
f

S
e
r
v
i
c
e

S
t
u
d
y
Fo
r

I
d
a
h
o

P
o
w
e
r

C
o
m
p
a
n
y
St
a
t
e

o
f

I
d
a
h
o
No
r
m
a
l
i
z
e
d

1
2
-
Mo
n
t
h
s

E
n
d
i
n
g

D
e
c
e
m
b
e
r

3
1
,
20
0
3
(1
)

(2
)
Ra
t
e

20
0
3

A

v
g
.
Sc
h
.

N
u
m
b
e
r

o
f
No
.

Cu
s
t
o
m
e
r
s
(3
)
20
0
3

S
a
l
e
s
No
r
m
a
l
i
z
e
d
(k
W
h
)
(4
)
Cu
r
r
e
n
t
Ba
s
e
Re
v
e
n
u
e
(5
)
(6
)
(7
)
Av
g
.
Ce
n
t
s
Pe
r

K
W
H
(8
)
Re
v
e
n
u
e
Ad
j
u
s
t
m
e
n
t
s
4W

1
2
C
P
Re
v
e
n
u
e
Pe
r
c
e
n
t
Ch
a
n
g
e
33
5
,
60
5
14
1
,
39
3
,
4
2
6
21
4
,
28
9
,
4
1
2
(1
,
16
1
,
3
9
2
)
21
3
,
12
8
,
02
0
(0
.
54
)
%
32
,
31
6
26
5
,
33
5
,
66
7
16
,
79
8
,
4
7
9
39
,
14
8
16
,
83
7
,
62
7
23
%
17
,
4
1
5
01
4
,
4
2
6
,
98
6
10
7
,
66
9
,
01
1
(3
,
64
0
,
93
0
)
10
4
,
02
8
,
08
1
3.
4
5
(3
.
38
)
%
87
2
,
58
6
1,
3
8
9
,
11
2
(1
,
5
1
9
,
20
7
)
(1
3
0
,
09
5
)
(2
.
22
)
(1
0
9
.
37
)
%
10
5
97
8
,
82
4
,
23
7
55
,
06
3
,
58
1
(2
,
21
1
,
08
0
)
52
,
85
2
,
50
1
(4
.
02
)
%
13
,
51
7
62
0
,
93
0
,
93
1
60
,
29
1
,
58
0
26
,
7
9
9
,
02
3
87
,
09
0
,
60
3
44
.
4
5
%
22
4
16
,
05
4
,
94
2
90
7
,
69
1
(3
0
1
,
4
5
1

)
60
6
,
24
0
3.
7
8
(3
3
.
21
)
%
1,
4
3
2
17
,
91
2
,
03
9
1,
8
0
9
,
26
5
(4
9
1
,
8
0
9
)
31
7
,
4
5
6
(2
7
.
18
)
%
38
4
21
8
28
4
14
7
36
5
27
2
(4
.
00
)
%
40
1
,
67
2
11
,
07
0
,
13
5
,
03
2
45
8
,
50
2
,
27
8
17
,
50
0
,
93
7
47
6
,
00
3
,
21
5
82
%
63
6
,
96
7
,
67
0
16
,
20
4
,
10
7
(1
,
60
5
,
83
0
)
14
,
59
8
,
27
7
(9
.
91
)
%
18
6
,
68
4
,
66
5
63
2
,
57
1
(5
9
1
,
4
6
0
)
04
1
,
11
1
(1
2
.
7
7
)
%
20
3
,
08
4
,
14
6
62
2
,
4
1
3
(1
0
3
,
11
3
)
51
9
,
30
0
(2
.
23
)
%
02
6
,
7
3
6
,
4
8
1
25
,
4
5
9
,
09
1
(2
,
30
0
,
4
0
3
)
23
,
15
8
,
68
8
(9
.
04
)
%
40
1
67
5
12
,
09
6
,
87
1
,
5
1
3
48
3
,
96
1
,
36
9
15
,
20
0
,
53
4
49
9
,
16
1
,
9
0
3
14
%
Li
n
e
Ta
r
i
f
f

D
e
s
c
r
i
p
t
i
o
n
Un
i
f
o
r
m

T
a
r
i
f
f

R
a
t
e
s
:
Re
s
i
d
e
n
t
i
a
l

S
e
r
v
i
c
e
Sm
a
l
l

G
e
n
e
r
a
l

S
e
r
v
i
c
e
La
r
g
e

G
e
n
e
r
a
l

S
e
r
v
i
c
e
Du
s
k

t
o

D
a
w
n

L
i
g
h
t
i
n
g
La
r
g
e

P
o
w
e
r

S
e
r
v
i
c
e
Ag
r
i
c
u
l
t
u
r
a
l

I
r
r
i
g
a
t
i
o
n

S
e
r
v
i
c
e
Un
m
e
t
e
r
e
d

G
e
n
e
r
a
l

Se
r
v
o
St
r
e
e
t

L
i
g
h
t
i
n
g
10

Tr
a
f
f
i
c

C
o
n
t
r
o
l

L
i
g
h
t
i
n
g
11

To
t
a
l

U
n
i
f
o
r
m

T
a
r
i
f
f
s
Sp
e
c
i
a
l

C
o
n
t
r
a
c
t
s
:
12

Mi
c
r
o
n
13

J

R
S
i
m
p
l
o
t
14

D
O
E
15

To
t
a
l

S
p
e
c
i
a
l

C
o
n
t
r
a
c
t
s
t2
~
O
t
:
d
W'

P'

~
~
~

g;

~

1
6
ss
:
~

Z
~
:
.,
.
.
.
0
Z
fJ

~

~
en
O
-
rl
-

I

N
po

t
:
d

N
To
t
a
l

I
d
a
h
o

Re
t
a
i
l

S
a
l
e
s
U:
\
k
h
e
s
s
i
n
I
I
P
C
E
0
3
1
3
I
S
l
a
f
f

C
a
s
e
l
C
O
S

E
x
h
l
b
i
l
s

2
/
1
1
/
2
0
0
4
Id
a
h
o

C
o
m
m
i
s
s
i
o
n

S
t
a
f
f
Re
s
u
l
t
s

o
f

12
C
P
Co
s
t

o
f

S
e
r
v
i
c
e

S
t
u
d
y
Fo
r

I
d
a
h
o

P
o
w
e
r

C
o
m
p
a
n
y
St
a
t
e

o
f

I
d
a
h
o
No
r
m
a
l
i
z
e
d

1
2
-
Mo
n
t
h
s

E
n
d
i
n
g

D
e
c
e
m
b
e
r

3
1
,
2
0
0
3
(1
)

(2
)
Ra
t
e

20
0
3

A
v
g
.
Sc
h
.

N
u
m
b
e
r

No
.

Cu
s
t
o
m
e
r
s
(3
)
20
0
3

S
a
l
e
s
No
r
m
a
l
i
z
e
d
(k
W
h
)
(4
)
Cu
r
r
e
n
t
Ba
s
e
Re
v
e
n
u
e
(5
)
(6
)
(7
)
Av
g
.
Ce
n
t
s
Pe
r

K
W
H
(8
)
Pe
r
c
e
n
t
Ch
a
n
c
e
Re
v
e
n
u
e
Ad
j
u
s
t
m
e
n
t
s
12
C
P
Re
v
e
n
u
e
33
5
,
60
5
14
1
,
39
3
,
4
2
6
21
4
,
28
9
,
4
1
2
66
0
,
59
5
21
7
,
95
0
,
00
7
1.
7
1
%
32
,
31
6
26
5
,
33
5
,
66
7
16
,
7
9
8
,
4
7
9
22
6
,
90
2
17
,
02
5
,
38
1
6.
4
2
35
%
17
,
4
1
5
01
4
,
4
2
6
,
98
6
10
7
,
66
9
,
01
1
(1
,
9
5
7
,
56
0
)
10
5
,
7
1
1
,
4
5
1
(1
.
8
2
)
%
87
2
,
58
6
1,
3
8
9
,
11
2
(1
,
4
9
3
,
28
2
)
(1
0
4
,
17
0
)
(1
.
7
7
)
(1
0
7
.
50
)
%
10
5
97
8
,
82
4
,
23
7
55
,
06
3
,
58
1
(7
9
9
,
52
7
)
54
,
26
4
,
05
4
2.
7
4
(1
.
4
5
)
%
13
,
51
7
62
0
,
93
0
,
93
1
60
,
29
1
,
58
0
17
,
7
1
2
,
20
5
78
,
00
3
,
7
8
5
29
.
38
%
22
4
16
,
05
4
,
94
2
90
7
,
69
1
(3
2
0
,
64
9
)
58
7
,
04
2
(3
5
.
33
)
%
1,
4
3
2
17
,
91
2
,
03
9
80
9
,
26
5
(4
9
1
,
8
0
9
)
31
7
,
4
5
6
(2
7
.
18
)
%
38
4
21
8
28
4
14
7
(4
,
63
8
)
27
9
50
9
(1
.
6
3
)
%
40
1
,
67
2
11
,
07
0
,
13
5
,
03
2
45
8
,
50
2
,
27
8
16
,
53
2
,
23
7
47
5
,
03
4
,
51
5
61
%
63
6
,
96
7
,
67
0
16
,
20
4
,
10
7
(1
,
22
3
,
24
9
)
14
,
98
0
,
85
8
(7
.
55
)
%
18
6
,
68
4
,
66
5
63
2
,
57
1
(4
2
6
,
23
0
)
20
6
,
34
1
(9
.
20
)
%
20
3
,
08
4
,
14
6
62
2
.
4
1
3
31
7
77
5
94
0
,
18
8
2.
4
3
87
%
02
6
,
7
3
6
,
4
8
1
25
,
4
5
9
,
09
1
(1
,
3
3
1
,
70
4
)
24
,
12
7
,
38
7
(5
.
23
)
%
40
1
,
6
7
5
12
,
09
6
,
87
1
51
3
48
3
,
96
1
,
36
9
15
,
20
0
,
53
3
49
9
,
16
1
,
9
0
2
14
%
IDAHO POWER COMPANY
CASE NO. IPC-03-
SECOND PRODUCTION REQUEST
IDAHO IRRIGATION PUMPERS ASSN.
TT A CHMENT TO
RESPONSE TO
REQUEST NO. 30
Exhibit No. 123
Case No. IPC-03-
K. Hessing, Staff
2/20/04 Page 1 of 5
IDAHO
POWER
IDAHO POWER COMPANY
O. BOX 70
BOISE, IDAHO 83707
An IDACORP Company
Pete Pengilly
Senior Analyst
Pricing Regulatory Services
Chq-
rr 2281
Date: August 19, 2003
Re:Marginal Cost Analysis 2003
To:Maggie Brilz
Attached are the results of the 2003 Marginal Cost Analysis. This is an update of the 1993
Marginal Cost Study completed by Patty Nichols. The 1993 study followed the model used for
previous years studies. The concept and design of these studies is from the National Economic
Research Associates Inc. (NERA) marginal cost model. The NERA model is constantly being
refined but the basic concepts and methods have remained the same since Idaho Power began
using this method. In this analysis, only the Generation Capacity, Transmission Capacity, and
the Generation Energy marginal costs have been updated for use in the Company s class cost
of service model. A five-year historic period and a five year forecast period were selected for
this update. The historic data used for this analysis is from the years 1998 to 2002. The
projected data used is from 2003 to 2007.
Attachments Worksheets:
Marginal Cost of Energy
Annual Generation Capacity Marginal Costs
Seasonalization of Generation Capacity Marginal Costs
Annual Transmission Marginal Costs
Seasonalization of Transmission Marginal Costs
MRrginal Cost of Energy
The marginal cost of energy was derived from output of the Company s power supply model
AURORA. The model was run under median water conditions. The inputs were consistent with
the inputs used for the normalized net power supply cost runs used for the 2003 rate case.
However, since the marginal cost runs were done for a five year projected period, rather than a
single test year, the existing power supply contracts were left in place for 2003 and then allowed
Exhibit No. 123
Case No. IPC-03-
K. Hessing, Staff
2/20/04 Page 2 of 5
to expire as contracted, the PPL and Tiber (CSPP) contracts were allowed to begin as contracted
coal prices reflected the contracts in place, average gas prices were used, and additional
resources were added as specified in the Company s 2002 Integrated Resource Plan (IRP). The
model was first run for the five projected load years beginning with 2003. The model was then run
a second time with the same inputs except the loads were increased by ten average megawatts
shaped across all hours. The difference in power supply costs and the difference in megawatt
hours were then used to calculate an average monthly marginal cost per megawatt hour. Added
to this cost were the marginal fuel inventory, grossed up for cost of capital and taxes, and the
marginal variable operation and maintenance costs. This loaded energy cost was then increased
for losses at the transmission and distribution levels of service.
Gp.neration C8p8city M8rginal Costs
The annual generation capacity marginal costs were derived from data contained in Idaho
Power s 2002 IRP. Because of transmission constraints to the west of the Treasure Valley which
limits market imports, a simple cycle combustion turbine located east of Brownlee, is the most
likely marginal peaking resource needed on the system. A 61.2 MW simple cycle combustion
turbine was chosen as the next marginal peaking resource in the 2002 IRP. The investment in
dollars per kw, the fixed operating and maintenance costs, weighted cost of capital, composite tax
rate, escalation rate, and the after tax discount rate used in this analysis were all obtained from
the 2002 IRP Technical Appendix. The life of the resource (35 years) used in calculating the
carrying charge was obtained from Idaho Power s 2003 depreciation study. The materials and
supplies costs loading factors are derived from an average of five historic years data, from the
years 1998 through 2002. The revenue requirement, taxes, and the reserve margin calculations
are based on year-end 2002 information.
Sp.8son8li78tion of Gp.np.r8tion C8f18city M8rginal Costs
The seasonalization of the generation capacity marginal costs is based on information from the
2002 IRP and five-year historic coincidence peak (CP) data from the FERC Form 1. Using the
th percentile water and the 70th percentile load forecast information for the years 2003 to 2007
the 2002 IRP identifies June, July, August, November, and December as the months with
generation deficiencies. The monthly CP information was used to identify what portion of the
annual generation capacity marginal costs should be assigned to these months. For each month
the percentage of that monthly CP to the annual CP was calculated. These percentages were
averaged for each month for 1998 to 2002. These numbers were summed for the relevant
months and the percent for each month of the total was calculated. This method assigned a
portion of the annual generation capacity marginal costs to the months of June, July, August
November, and December. Exhibit No. 123
Case No. IPC-03-
K. Hessing, Staff
2/20/04 Page 3 of 5
TrAnsmission Marginal Costs
The method of calculating the transmission marginal cost is similar to the method for calculating
the generation capacity marginal cost. The cost of integrating a new network resource to meet
native load service requirements was used. This is the cost of integrating a new gas fired
generator located within 30 miles of Boise. This cost would be approximately $92 per kw for a
230 kv line and a small amount of 138 kv line to connect to distribution voltage. These costs were
obtained from the Company s Grid Operations and Planning Department. This cost was then
treated similarly to the generation capacity marginal costs. The cost was loaded with General
Plant loadings. The economic carrying charge rate was calculated using the same inputs as the
generation capacity costs except a different asset life (50 years) was used~ The asset life was
obtained from Idaho Power s 2003 depreciation study. Operation & Maintenance and
Administrative & General loadings were added to this cost. Materials & Supplies loadings that
were derived from historic five-year averages and grossed up for revenue requirement and taxes
were then added to complete the transmission marginal cost.
Sp.Asom'!1i7Ation of TrAm;mission Marginal Costs
The 2002 lAP identifies June, July, and August as the months that transmission constraints can
be expected in future years. Since the lAP identifies these months as the ones with transmission
constraints, the marginal cost of transmission capacity was allocated to these months based on
average monthly CP as compared to the annual CP for the years 1998 to 2002 using the same
method as was used for the generation capacity marginal costs.
Exhibit No. 123
Case No. IPC-03-
K. Hessing, Staff
2/20/04 Page 4 of 5
(1
)
(2
)
(3
)
(4
)
(5
)
(6
)
(7
)
(8
)
(9
)
(1
0
)
(1
1
)
(1
2
)
(1
3
)
(1
4
)
t2
~
O
t
:
d
N'

P
'
ri
.
::
q

g
;

s
-
:
0(1
)

o-
'
.j
:
o
.
.

~

::
;
.
.
S'

~

Z
~g
q

~

~
(f
Q

e
n

..
.
.
.
.
.
(1
)

.
.
.
.
.
.
.

I

t:
d
W
HJ

W
VI

~
Id
a
h
o

P
o
w
e
r

C
o
m
p
a
n
y
Ma
r
g
i
n
a
l

C
o
s
t

A
n
a
l
y
s
i
s

2
0
0
3
Ma
r
g
i
n
a
l

C
o
s
t

o
f

E
n
e
r
g
y

-

D
o
l
i
a
r
s
/
M
w
h
An
n
u
a
l
Av
g
.
Ja
n
Fe
b
Ap
r
Ma
y
Ju
n
Ju
l
Se
p
Oc
t
Na
v
De
e
Au
g
Ma
r
-
-
~ ~
-
~
~ .
--
-
- -
~
--
-
_n

Ma
r
g
i
n
a
l

G
e
n
e
r
a
t
i
o
n

C
o
s
t

a
t

G
e
n
e
r
a
t
i
o
n
$2
6
.
$2
2
,
$2
3
.
$2
0
.
$2
3
.
$2
6
.
4
4
$3
3
.
2
7
$3
3
.
$2
7
.
$2
4
,
$2
6
.
$2
8
.
$2
7
.
Ma
r
g
i
n
a
l

F
u
e
l

I
n
v
e
n
t
o
r
y

$1
3
.
$1
3
.
$1
3
.
$1
3
.
$1
3
.
$1
3
.
$1
3
.
$1
3
.
$1
3
.
$1
3
.
$1
3
.
$1
3
.
Co
s
t

o
f

C
a
p
i
t
a
l

f
o
r

F
u
e
l

I
n
v
e
n
t
o
r
y

(2
)

x

8
.
58
9
%
(
8
)
$1
.
1
9
$1
.
1
9
$1
.
$1
.
$1
.
1
9
$1
.
1
9
$1
.
1
9
$1
.
1
9
$1
.
1
9
$1
.
1
9
$1
.
$1
.
1
9
Co
s
t

o
f

C
a
p
i
t
a
l

G
r
o
s
s
e
d

f
o
r

T
a
x
e
s
(3
)

x

1
.
64
s
1
Q
$1
.
9
6
$1
.
$1
.
9
6
$1
.
9
6
$1
.
9
6
$1
.
$1
.
9
6
$1
.
9
6
$1
.
9
6
$1
.
9
6
$1
.
$1
.
9
6
Ma
r
g
i
n
a
l

V
a
r
i
a
b
l
e

0

&

Me
n
)
$3
.
$3
.
$3
.
$3
.
$3
.
$3
.
$3
.
$3
.
$3
.
$3
.
$3
.
$3
.
Ma
r
g
i
n
a
l

e
n
e
r
g
y

c
o
s
t

a
t

G
e
n
e
r
a
t
i
o
n
$3
3
.
$2
9
.
$3
0
.
$2
7
.
$3
0
.
$3
3
.
$4
0
.
$4
0
.
$3
4
.
$3
1
.
$3
3
.
$3
5
.
$3
3
.
Av
e
r
a
g
e

S
y
s
t
e
m

l
o
s
s

f
a
c
t
o
r

C
o
e
f
f
i
d
e
n
t
s
(
E
)

a
t
:
Tr
a
n
s
m
i
s
s
i
o
n
1.0
5
5
05
5
05
5
05
5
05
5
05
5
05
5
05
5
05
5
1.0
5
5
1.0
5
5
05
5
Di
s
t
r
i
b
u
t
i
o
n
Ma
r
g
i
n
a
l

e
n
e
r
g
y

c
o
s
t

a
t

S
e
r
v
i
c
e

L
e
v
e
l
Po
w
e
r

S
u
p
p
l
y

(
6
)
$3
3
,
$2
9
.
$3
0
.
$2
7
.
$3
0
.
$3
3
.
$4
0
.
$4
0
.
$3
4
.
$3
1
.
$3
3
.
$3
5
.
$3
3
.
Tr
a
n
s
m
l
s
s
t
o
n

(
8
)

x

(
6
)
$3
5
.
$3
1
.
$3
2
.
$2
9
,
$3
1
.
9
3
$3
5
.
$4
2
.
$4
3
.
$3
6
.
$3
3
.
$3
5
.
$3
7
.
$3
5
.
Di
s
t
r
i
b
u
~
o
n

(
9
)

x

(
6
)
$3
7
.
$3
3
.
$3
4
.
$3
1
.
$3
4
.
$3
7
.
$4
5
,
$4
6
.
$3
9
.
4
0
$3
5
,
$3
7
.
$3
9
.
$3
7
.
"-
-
u_
u
-
.
.-
-
-
r_
-
-
.
..
-
-
--
-
Ja
n
Fe
b
Ap
r
Ma
y
Ju
n
Ju
l
Se
p
Oc
t
No
v
De
e
Av
g
.
Au
g
Ma
r
,.,

A
u
r
o
r
a

P
o
w
e
r

S
U
p
p
l
y

M
o
d
e
l

2
0
0
3

t
o

2
0
0
7
~,
D
e
c
e
m
b
e
r

3
1
,
2
0
0
2
,O
t

D
e
t
e
m
b
e
r

3
1
,
20
0
2
(I
I
)

I
P
C
n

2
0
0
2

I
R
P

T
e
c
I
1
n
l
C
i
l
I

A
p
p
e
l
'
"
l
I
.
'"

I
P
C
n

2
0
0
3

l
o
s
s

t
e
e
t
e
r

SI
1
J
d
y