HomeMy WebLinkAbout20110316Comments.pdfDONALD L. HOWELL, II
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
(208) 334-03 12
IDAHO BAR NO. 3366
,-""
3: :;0
Street Address for Express Mail:
472 W. WASHINGTON
BOISE, IDAHO 83702-5918
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF )
PACIFICORP DBA ROCKY MOUNTAIN )
POWER FOR AUTHORITY TO INCREASE )
RATES BY $11.0 MILLION TO RECOVER )
DEFERRD NET POWER COSTS THROUGH )
THE ENERGY COST ADJUSTMENT )MECHANISM (ECAM). )
)
CASE NO. PAC-E-11-07
COMMENTS OF THE
COMMISSION STAFF
The Staff of the Idaho Public Utilties Commission, by and through its Attorney of Record,
Donald L. Howell II, Deputy Attorney General, submits the following comments in the above
referenced case.
BACKGROUND
On February 1,2011, PacifiCorp dba Rocky Mountain Power fied an Application for
authority to recover its deferred net power costs pursuant to the Energy Cost Adjustment
Mechanism (ECAM) approved in Order No. 30904 (September 2009). The ECAM is designed to
anually adjust Rocky Mountain's rates upward or downward to reflect the difference between the
Company's actual power supply costs and those costs embedded in base rates. Rocky Mountain's
actual costs of providing electric service (its "power supply costs") vary from year to year
depending on the Company's fuel (natural gas and coal) costs, the surplus power sales, the power
STAFF COMMENTS 1 MARCH 16,2011
purchases, and the market price of power. In this Application, the Company is proposing to
recover an additional $ 1 1 millon in deferred net power costs starting April 1, 2011, and ending
March 31, 2012. The energy cost adjustment rates are contained in service Schedule No. 94.
Rocky Mountain requested that this Application be processed by Modified Procedure.
The ECAM
The ECAM is designed to recover all components of net power costs as traditionally
defined in the Company's general rate cases and modeled in its production dispatch model
"GRID". (Recovery is subject to adjustment for load growth and sharing.) The ECAM is
calculated to collect or credit the accumulated difference between total Company base net power
costs ("Base NPC") and the total Company actual net power costs ("Actual NPC") incurred to
serve customers in Idaho calculated on a cents-per-kilowatt-hour basis. In this case, the Company
requests authority to recover its net power costs for the deferred period December 1, 2009 to
November 30,2010. Application at 1. The annual ECAM rate surcharge or credit is combined
with the Company's base rates to produce a customer's overall energy rate. The ECAM rate
adjustment is applicable to all customer classes excluding tariff contract customers (Monsanto
Company and Agrium, Inc.). i
The ECAM rate component is in effect for one year, usually from April 1 through March
31 of the following calendar year. The primary components of the ECAM are base and actual
NPC booked to the following Federal Energy Regulatory Commission (FERC) accounts:
Account 447 - Sales for resale, excluding on-system wholesale sales and other
revenues that are not modeled in GRID.
Account 501 - Fuel, steam generation, excluding fuel handling, start-up
fuel/gas,2 diesel fuel, residual disposal and other costs that are not modeled in
GRID.
Account 503 - Steam from other sources.
Account 547 - Fuel, other generation.
i Tariff contract loads (Monsanto and Agrium) are not subject to any ECAM deferral period until January i, 20 i i.
Order No. 30482 (Case No. PAC-E-07-05).
2 Start-up fuel is accounted for separately from the primar fuel for steam-powered generation plants. Star-up costs
are not accounted for separately for natural gas plants, and therefore all fuel for natural gas plants is included in the
determination of both base NPC and actual NPC.
STAFF COMMENTS 2 MARCH 16,2011
Account 555 - Purchased power, excluding BPA residential exchange credit
pass-through, if applicable.
Account 565 - Transmission of electricity by others (wheeling).
In addition to the comparison of actual NPC to base NPC, the ECAM includes four
additional components: (l) the Load Growth Adjustment; (2) a credit for the sale of S02 emission
credits; (3) an adjustment for coal stripping costs (EITF 04-6 Adjustment); and (4) a Renewable
Resource Adder for renewable resources not in rate base.
Under the ECAM, the Company and its ratepayers share the differences between the actual
NPC and base NPC, S02 sales, and the Load Growth Adjustment. The sharing percentage is 90%
for ratepayers and 10% for the Company. In good years, Rocky Mountain's Idaho customers are
credited with 90% of the below normal cost savings. In high cost years, Idaho customers pay 90%
of the Company's higher than normal power supply costs. In last year's ECAM case, the
Commission approved recovery of approximately $2.0 milion in deferred net power costs for the
Company's first ECAM deferral period from July 1, 2009 to November 30, 2009. Order No.
31033.
The Current Application
In the present Application, the Company seeks an increase of $ 11.0 milion over the
Schedule 94 ECAM rates currently in effect. Application at 2. This Application would recover
the deferred power supply costs for the 12-month period ending November 30,2010. ¡d. at ~ 12.
As shown below, the Company is requesting authority to recover a total of $ 1 2.8 milion (existing
$1.8 milion + $11 millon increase).
The ECAM includes a deferral for renewable resources that recognizes the Company's
investments in renewable generation projects that were not being recovered in Idaho rates" even
though these projects provided significant benefits to customers. Specifically, the adjustment
recognizes that actual NPC were reduced by power generated from these renewable generation
projects.3 Pursuant to Commission Order No. 30904, the Commission approved a renewable
resource adjustment of $55 per megawatt-hour (MWh) multiplied by the actual MWh output
generated by the renewable resources that were not included in rate base in Case No.
3 The renewable wind resources included in this Application are: Glenrock; Glenrock II; Seven Mile; Seven Mile II;
Rollng Hils; High Plains; McFadden Ridge; and Dunlap. Dir. Testimony at 8.
STAFF COMMENTS 3 MARCH 16,2011
PAC-E-08-07. ¡d. at ~ 20.
The components making up the deferred ECAM balance are reflected in the following
table:
Customer Responsibilty
Renewable Resource Adder
Unamortized Previous Balance
Interest
November 2010 Deferral Balance
Less ECAM Balance
Proposed ECAM Recovery
$ 6,073,522
5,286,046
(93,906)
008,588)
$11,157,074
90%
$ 1 0,04 1 ,366
2,696,763
760,036
61,885
$13,560,051
(760,036)
$12,800,015
NPC Differential for Deferral
Load Growth Adjustment
S02 Credit
EITF 04-6 Adjustment
Total
Source: Dir. Testimony at 10.
The Company calculates that the change in ECAM rates in Schedule 94, if approved, will
result in an overall increase of 7.4% or $11 milion for the ECAM recovery year (April 1,2011
through March 3 1, 2012). The proposed ECAM rates would increase the Company's rates as
follows:
Residential Customers (Schedule 1): 6.1% increase, i.e.,
approximately $5.00 per month for the average residential home using 839
kWh per month.
Residential Time-of-Day (Schedule 36):7.5%
Irrigation Customers (Schedule 10):7.9%
General Service
Schedule 23/23A:
Schedule 6/6A:
Time-of-Day (Schedule 35):
High Voltage (Schedule 9):
Commercial/Industrial (Schedule 19):
7.1%
8.6%
11.2%
10.9%
8.2%
Public Street Lighting (Schedules 7/7 A, 11, 12): 2.8%
STAFF COMMENTS 4 MARCH 16,2011
STAFF ANALYSIS
This is the Company's first full year ECAM filing after the Commission issued Order No.
30904 in September 2009. Last year's ECAM filing only covered a 5-month period ending
November 30,2009. Consequently, this filing includes adjustments for Net Power Cost
Differential, Load Growth Adjustment, S02 Sales, EITF 04-6 Adjustment, and a Renewable
Resource Adder for the 12-month period of December 1,2009 through November 30, 2010.
The Commission Staff has reviewed the Company's ECAM filing and audited the
Company's actual results as they pertin to the ECAM.
Net Power Cost Differential - The Net Power Cost differential is the primary reason for
the creation of a power cost adjustment mechanism for Rocky Mountain. Normally this
differential is by far the single largest cost component of the mechanism. In this case, however,
the Net Power Cost differential is just about half of the ECAM recovery amount requested by the
Company (the LGA (see below) is the other large balance).
The Staff reviewed the transactions in the FERC accounts used to record net power costs.
Specifically, base and actual NPC include amounts booked to the following FERC accounts:
Account 447 (sales for resale, excluding on-system wholesale sales and other revenues not
modeled in GRID); Account 501 (fuel, steam generation, excluding fuel handling, star up
fuel/gas, diesel fuel, residual disposal and other costs not modeled in GRID); Account 503 (steam
from other sources); Account 547 (fuel, other generation); Account 555 (purchased power,
excluding BP A residential exchange credit pass-through if applicable); and Account 565
(transmission of electricity by others). The Staff analysis did not find any transaction that was not
reasonable or significantly out-of-trend with previous activity.
Staff confirmed the Idaho share of net power costs increased by $6,073,522; the Idaho
customers' share of the increased cost is $5,466,170 after 90/10 sharing.
Load Growth Adjustment - The Load Growth Adjustment (LGA) is also a major
component of this year's ECAM deferraL. During the 12-month review period, actual Idaho loads
were down 302,438 MWh or 12.52% from the 2007 normalized 12-month period used to calculate
the Idaho base load. At an approved adjustment rate of $ 1 7.48/MWh, this results in a Load
Growth Adjustment of $5,286,046. The Idaho customer share is $4,757,441 after 90/10 sharing.
These are the same results obtained by the Company.
When loads are reduced from base conditions, the Load Growth Adjustment mechanism
imputes revenue to reimburse the Company for unecovered fixed costs approved for recovery by
STAFF COMMENTS 5 MARCH 16,2011
the Commission in previous general rate cases. Idaho Power and A vista PCA' s include similar
mechanisms. When loads are increasing, this adjustment removes fixed costs from the ECAM
because the approved level of fixed cost is recovered in the sale of additional MWh. The Load
Growth Adjustment is designed to be symmetrical. Therefore, because the Idaho Load Growth
was negative, the approved level of fixed cost is added to the ECAM adjustment. Staff notes that
this is a unique situation in which the Load Growth Adjustment comprises a major par of the
ECAM adjustment. In spite of an overall decrease in load, net power costs have risen during the
12-month period primarily due to a large increase in net power costs during all months except
June and July of201O.
Given this unique situation (loads decreasing, while power costs increasing), the Staff
proposes that the Load Growth Adjustment amount be amortized over two years for the following
reasons. First, less than three months ago, Rocky Mountain received a general rate increase that
averaged 6.78%. The Staff proposal reduces the average increase in this case from 7.4% to 5.8%.
Even with Staff s proposed adjustment, the combination of these two increases is significant.
Second, the Commission recently issued an order that changed the Company's Load Growth
Adjustment Rate (LGAR) mechanism. The effect of this change reduced the LGAR by about
three-quarers (Case No. GNR-E-I0-03, Order No. 32206). The reduced LGAR reduces the
amount of next year's Load Growth Adjustment even if the load decline is equivalent to this
year's decline. However, because the recent rate case reset the base load, Staff expects that the
201 1 actual load wil more closely match the reset base load. This would furher reduce the Load
Growth Adjustment for next year. Staff believes that this year's Load Growth Adjustment can be
spread over two years without causing an ECAM rate increase next year.
The Staff also proposes that the second year's amortization of the Load Growth
Adjustment amount be caried in the deferral balance with interest for future recovery. Because
the two tariff contract customers are not subject to ECAM rate adjustments that accumulated prior
to January 1, 201 1, the Staff believes that these customers should be assessed none of the
amortized portion of this Load Growth Adjustment in future filings.
S02 Credits - In Commission Order No. 30904 the Commission accepted a stipulated
settlement that required that the ECAM include and share revenues from the sale of S02 credits
between the Company and its customers (90% customers/1 0% company). This applied to all S02
sales beginning July 2009. For the 12-month ECAM deferral period ending November 30,2010,
Staff calculated the Idaho portion of the credit by multiplying total sales by the Idaho energy
STAFF COMMENTS 6 MARCH 16,2011
allocation factor of 6.5865%. The Idaho portion of the S02 credit was then further reduced to an
Idaho tariff customer portion by multiplying the percent of the Idaho tariff load to total Idaho load
in each month. The Staff calculated the Idaho tariff customer portion to be $93,906. The Idaho
customer share is $84,516 after 90/1 0 sharing. These are the same results obtained by the
Company.
Idaho EITF 04-6 Deferral - The EITF -04-6 Deferral reflects the Idaho-allocated
differences between excluding the Company's coal stripping costs recorded on the Company's
books (pursuant to the guidance of the accounting pronouncement EITF 04-6), and the
amortization of the coal stripping costs when the coal was excavated and consumed as directed in
Commission Order No. 30987. Idaho's allocated share is further prorated to exclude the two taiff
contract customers' load. The total EITF 04-6 coal stripping deferral adjustment was calculated
by the Company to be a $ 1 08,588 reduction to the NPC deferral balance; the Idaho customer share
of the credit is $97,729 after 90/10 sharing. Staff agrees with the Company's calculation.
Renewable Resource Adder - The Renewable Resource Adder is a relatively short term
adjustment included in the ECAM. This adjustment allows the ECAM to include the costs for
renewable resources that have come on-line since base power costs were set in Case No.
PAC-E-08-07. The costs are included at 55 $/MWh. The costs of the Renewable Resource Adder
were not included in base rates during the original case but generation from these resources
reduces actual Net Power Costs. Because the costs and benefits of these resources were included
in base rates in the recent general rate case (Case No. PAC-E-1O-07), this special adjustment wil
not be included in ECAM deferrals after December 31, 2010. Staff calculated the Idaho customer
share of this cost to be $2,696,763. These are the same results obtained by the Company.
Interest - As required by Commission Order No. 30904 the Company included interest on
monthly deferral balances at the Commission approved customer deposit interest rate of 1 % for
2010. The Staff calculated the interest amount to be $61,885. These are the same results obtained
by the Company.
STAFF COMMENTS 7 MARCH 16,2011
The Staff calculates the ECAM components proposed for recovery in this filing to be:
NPC Differential for Deferral $ 6,073,522
Load Growth Adjustment 2,643,023S02 Credit (93,906)EITF 04-6 Adjustment (108,588)Total $8,514,051
90%
$7,662,646
2,696,763
760,036
61,885
$11,181,330
(760,036)
$ 1 0,42 1 ,294
Customer Responsibility
Renewable Resource Adder
Unamortized Previous Balance
Interest
November 2010 Deferral Balance
Less ECAM Balance
Proposed ECAM Recovery
The Staff proposed amortization of the Load Growth Adjustment discussed above reduces the
ECAM recovery in this case from the Company calculation of$12,800,015 to $10,421,294, a
reduction of$2,390,723 or 18.58%. Attachment A shows Staffs calculations in more detaiL.
ECAMRates
The methodology for calculating ECAM rates is generally defined in the Settlement
Stipulation accepted by the Commission in Order No. 30904. The details of the rate design were
accepted by paricipating parties in discussions after Order No. 30904 was issued and applied in
last year's ECAM case. The rates were to be energy rates (~/kWh) and they were to be loss
differentiated. In Company Exhibit No.3, the Company proposes three different energy rates that
vary by delivery voltage. In general, the lower the delivery voltage, the higher the losses
associated with serving the load. Higher losses translate into higher ECAM rates and lower losses,
due to higher delivery voltages, translate into lower ECAM rates.
Attachment B to these comments shows the Staff calculations of the three loss
differentiated rates on line 30. The Staff calculates the ECAM rates for customers taking service
at the secondary distribution voltage level to be 0.569 ~/kWh. The ECAM rate for those taking
service at the Primary Distribution voltage level is 0.550 ~/kWh. Finally, customers taking service
at the Transmission voltage level would pay an ECAM rate of 0.535 ~/kWh. These rates applied
to the Company's customer Classes are expected to produce $10,421,000 in ECAM revenue over
the course of the year which is approximately a 5.8% average increase in curent revenue. As
STAFF COMMENTS 8 MARCH 16,2011
shown in the extreme right column of Attachment B, the actual percentage increases vary by
customer class.
CUSTOMER RELATIONS
Customer Notice and Press Release
The Customer Notice and Press Release were included in Rocky Mountain Power's
. Application. Staff identified a few items in the Customer Notice and Press Release that needed to
be changed to be in compliance with Procedural Rule 125, IDAPA 31.01.01.125. The corrections
were made by RMP.
The Customer Notice was mailed to Rocky Mountain's customers with cyclical bilings
beginning February 7, 2011 and ending March 4,2011.
Customer Comments
Customers were given until March 23,2011 to fie comments. As of March 15,2011,
sixteen customers had sent comments. None supported the Company's proposed rate increase.
Most customers complained that the utilty just received a general rate increase. About five
customers objected to the proposed increase because they are on fixed or low incomes.
RECOMMENDATIONS
The Staff recommends that the Commission accept an Idaho ECAM deferral balance of
$12,800,015 for the December 1,2009 through November 30,2010 deferral period as proposed by
the Company and verified by the Staff. The Staff further proposes that $10,421,294 be set for
recovery in this ECAM case. The reduced amount reflects the 2-year amortization of the Load
Growth Adjustment as previously discussed in these comments. Staff further recommends that the
amortized portion of the Load Growth Adjustment be specifically excluded from any ECAM
application to special contract customers (Monsanto Company and Agrium, Inc.) in future fiings.
The Staff also recommends that the Commission approve the following loss differentiated
energy rates to be included in Schedule 94 (See Attachment B, line 30):
STAFF COMMENTS 9 MARCH 16,2011
Secondary Distribution Rate
Primary Distribution Rate
Transmission Rate
0.569 ~/kWh
0.550 ~/kWh
0.535 ~/kWh
The Staff recommends that these rates become effective April 1, 201 1 as requested by the
Company.
Respectfully submitted this I ~l'day of March 201 1.
Donald L. H II, II
Deputy Attorney General
Technical Staff: Keith Hessing
Cecily Vaughn
Marilyn Parker
i:umisc/commentspace i i .7dhkhcvmp comments
STAFF COMMENTS 10 MARCH 16,2011
Id
a
h
o
E
C
A
M
D
e
f
e
r
r
a
l
(
P
A
C
-
E
-
1
1
-
7
)
De
c
e
m
b
e
r
1
,
2
0
0
9
t
h
r
o
u
g
h
N
o
v
e
m
b
e
r
3
0
,
2
0
1
0
%
Di
f
f
e
r
e
n
c
e
As
P
r
o
p
o
s
e
d
b
y
fr
o
m
R
M
P
As
F
i
l
e
d
b
y
R
M
P
St
a
f
f
Di
f
f
e
r
e
n
c
e
Fi
l
i
n
g
NP
C
D
i
f
f
e
r
e
n
t
i
a
l
f
o
r
D
e
f
e
r
r
6,
0
7
3
,
5
2
2
6,
0
7
3
,
5
2
2
LG
A
R
5,
2
8
6
,
0
4
6
2,
6
4
3
,
0
2
3
(2
,
6
4
3
,
0
2
3
)
S0
2
C
r
e
d
i
t
(9
3
,
9
0
6
)
(9
3
,
9
0
6
)
EI
T
F
0
4
-
6
A
d
j
u
s
t
m
e
n
t
(1
0
8
,
5
8
8
)
(1
0
8
,
5
8
8
)
To
t
a
l
11
,
1
5
7
,
0
7
4
8,
5
1
4
,
0
5
1
(2
,
6
4
3
,
0
2
3
)
1
1
Cu
s
t
o
m
e
r
R
e
s
p
o
n
s
i
b
i
l
i
t
y
10
,
0
4
1
,
3
6
7
7,
6
6
2
,
6
4
6
(2
,
3
7
8
,
7
2
1
)
Re
n
e
w
a
b
l
e
R
e
s
o
u
r
c
e
A
d
d
e
r
2,
6
9
6
,
7
6
3
2,
6
9
6
,
7
6
3
Un
a
m
o
r
t
i
z
e
d
P
r
e
v
i
o
u
s
B
a
l
a
n
c
e
76
0
,
0
3
6
76
0
,
0
3
6
In
t
e
r
e
s
t
61
,
8
8
5
61
,
8
8
5
No
v
e
m
b
e
r
2
0
1
0
D
e
f
e
r
r
a
l
B
a
l
a
n
c
e
13
,
5
6
0
,
0
5
1
11
,
1
8
1
,
3
3
0
(2
,
3
7
8
,
7
2
1
)
Le
s
s
E
C
A
M
B
a
l
a
n
c
e
(7
6
0
,
0
3
6
)
(7
6
0
,
0
3
6
)
Pr
o
p
o
s
e
d
E
C
A
M
R
e
c
o
v
e
r
y
12
,
8
0
0
,
0
1
5
10
,
4
2
1
,
2
9
4
(2
,
3
7
8
,
7
2
1
)
-1
8
.
5
8
%
o
V
J
(
'
~
i
~
S
'
~
:
:
1
..
:
:
(
1
~
!
~
(
'
Z
2
"
.
.
1
..
0
0
S
!3
'
(
1
,
!3
~
g
g
(
'
~
..
I
VJ
t
I
i....Io-.
MA
R
C
H
1
6
,
2
0
1
1
CO
M
M
I
S
S
I
O
N
S
T
A
F
F
-
A
T
T
A
C
H
M
E
N
T
B
ES
T
I
M
A
T
E
D
I
M
P
A
C
T
O
F
P
R
O
P
O
S
E
D
E
C
A
M
A
D
J
U
S
T
M
E
N
T
FR
O
M
E
L
E
C
T
R
I
C
S
A
L
E
S
T
O
U
L
T
I
M
A
T
E
C
O
N
S
U
M
E
R
S
DI
S
T
R
I
B
U
T
E
D
B
Y
R
A
T
E
S
C
H
E
D
U
L
E
S
I
N
I
D
A
H
O
12
M
O
N
T
H
S
E
N
D
I
N
G
D
E
C
E
M
B
E
R
2
0
1
0
Pr
e
s
e
n
t
At
M
e
t
e
r
At
EC
A
M
P
r
o
p
o
s
a
l
Pr
e
s
e
n
t
Li
n
e
Av
e
r
a
g
e
Re
v
MW
h
b
y
V
o
l
t
a
g
e
Ge
n
e
r
a
t
i
o
n
Re
v
Ra
t
e
t
/
k
W
h
2
EC
A
M
R
e
v
Ne
t
Ch
a
n
g
e
No
.
De
s
c
r
i
p
t
i
o
n
Sc
h
.
Cu
s
t
MW
H
($
0
0
0
)
S
P
T
MW
h
!
($
0
0
0
)
S
P
T
($
0
0
0
)
3
($
0
0
0
)
%
--
-
(I
)
(2
)
(3
)
(4
)
(5
)
(6
)
(7
)
(8
)
(9
)
(1
0
)
(1
1
)
(1
2
)
(1
3
)
(1
4
)
(1
5
)
(1
6
)
Re
s
i
d
e
n
t
i
a
l
S
a
l
e
s
1
Re
s
i
d
e
n
t
i
a
l
S
e
r
v
i
c
e
i
42
,
5
0
6
42
7
,
9
0
7
$4
1
,
6
5
8
42
7
,
9
0
7
47
1
,
3
3
1
$2
,
4
3
5
0.
5
6
9
0.
5
5
0
0.
5
3
5
$4
2
8
$2
,
0
0
7
4.
8
%
2
Re
s
i
d
e
n
t
i
a
l
O
p
t
i
o
n
a
l
T
O
D
36
15
,
0
5
0
28
0
,
4
0
7
$2
2
,
0
2
7
28
0
,
4
0
7
30
8
,
8
6
2
$1
,
5
9
6
0.
5
6
9
0.
5
5
0
0.
5
3
5
$2
8
0
$1
,
3
1
5
5.
9
%
3
AG
A
R
e
v
e
n
u
e
--
--
0
$4
4
To
t
a
l
R
e
s
i
d
e
n
t
i
a
l
57
,
5
5
6
70
8
,
3
1
4
63
,
6
8
9
70
8
,
3
1
4
0
0
78
0
,
1
9
3
4,
0
3
0
70
8
--
3
2
2
5.
2
%
--
-
5
Co
m
m
e
r
c
i
a
l
&
I
n
d
u
s
t
r
i
a
l
6
Ge
n
e
r
a
l
S
e
r
v
i
c
e
-
L
a
r
g
e
P
o
w
e
r
6
1,
0
5
9
28
0
,
4
9
7
$1
8
,
9
6
2
23
9
,
0
2
6
41
,
4
7
0
30
7
,
4
3
8
$1
,
5
8
8
0.
5
6
9
0.
5
5
0
0.
5
3
5
$2
7
8
$1
,
3
1
1
6.
8
%
7
Ge
n
e
r
a
l
S
v
c
.
-
L
g
.
P
o
w
e
r
(
R
&
F
)
6A
24
3
33
,
0
0
1
$2
,
4
9
6
33
,
0
0
1
36
,
3
5
0
$1
8
8
0.
5
6
9
0.
5
5
0
0.
5
3
5
$3
3
$1
5
5
6.
1
%
8
Su
b
t
o
t
a
l
-
S
c
h
e
d
u
l
e
6
1,
3
0
2
31
3
,
4
9
8
21
,
4
5
8
27
2
,
0
2
8
41
,
4
7
0
0
34
3
,
7
8
8
1,
7
7
6
31
1
1,
4
6
5
6.
7
%
9
Ge
n
e
r
a
l
S
e
r
v
i
c
e
-
H
i
g
h
V
o
l
t
a
g
e
9
12
10
6
,
4
8
6
$5
,
4
3
2
10
6
,
4
8
6
11
0
,
3
2
5
$5
7
0
0.
5
6
9
0.
5
5
0
0.
5
3
5
$9
7
$4
7
3
8.
6
%
10
Ir
r
g
a
t
i
o
n
10
4,
8
1
0
54
5
,
2
9
0
$4
1
,
0
0
7
54
5
,
2
9
0
60
0
,
6
2
6
$3
,
1
0
3
0.
5
6
9
0.
5
5
0
0.
5
3
5
$5
4
5
$2
,
5
5
7
6.
2
%
11
Co
m
m
.
&
I
n
d
.
S
p
a
c
e
H
e
a
t
i
n
g
19
13
5
7,
7
6
9
$5
6
3
7,
7
6
9
8,
5
5
7
$4
4
0.
5
6
9
0.
5
5
0
0.
5
3
5
$8
$3
6
6.
4
%
12
Ge
n
e
r
a
l
S
e
r
v
i
c
e
23
6,
6
9
2
13
4
,
2
9
4
$1
1
,
2
1
6
13
3
,
5
6
3
73
1
14
7
,
8
9
5
$7
6
4
0.
5
6
9
0.
5
5
0
0.
5
3
5
$1
3
4
$6
3
0
5.
5
%
13
Ge
n
e
r
a
l
S
e
r
v
i
c
e
(
R
&
F
)
23
A
1,
4
9
4
18
,
9
0
7
$1
,
6
4
8
18
,
9
0
7
20
,
8
2
6
$1
0
8
0.
5
6
9
0.
5
5
0
0.
5
3
5
$1
9
$8
9
5.
3
%
14
Su
b
t
o
t
a
l
-
S
c
h
e
d
u
l
e
2
3
8,
1
8
6
15
3
,
2
0
1
12
,
8
6
4
15
2
,
4
7
0
73
1
0
16
8
,
7
2
1
87
2
15
3
71
8
5.
5
%
15
Ge
n
e
r
a
l
S
e
r
v
i
c
e
O
p
t
i
o
n
a
l
T
O
D
35
3
1,8
8
3
$9
9
1,
8
8
3
2,
0
7
4
$1
1
0.
5
6
9
0.
5
5
0
0.
5
3
5
$2
$9
8.
7
%
16
Sp
e
c
i
a
l
C
o
n
t
r
a
c
t
1
1
1,
3
8
5
,
1
7
3
$6
5
,
2
4
9
1,
3
8
5
,
1
7
3
1,
4
3
5
,
1
0
9
17
Sp
e
c
i
a
l
C
o
n
t
r
c
t
2
1
10
1
,
4
5
0
$4
,
8
8
4
10
1
,
4
5
0
10
5
,
1
0
7
18
AG
A
R
e
v
e
n
u
e
--
--
0
$6
8
1
19
To
t
a
l
C
o
m
m
e
r
c
i
a
l
&
I
n
d
u
s
t
r
a
l
14
,
4
5
1
2,
6
1
4
,
7
5
0
15
2
,
2
3
7
97
9
,
4
3
9
42
,
2
0
2
1,
5
9
3
,
1
0
9
2,
7
7
4
,
3
0
8
6,
3
7
5
1,
1
1
6
5,
2
5
9
3.
4
%
--
-
20
Pu
b
l
i
c
S
t
r
e
e
t
L
i
g
h
t
i
n
g
21
Se
c
u
r
i
t
y
A
r
e
a
L
i
g
h
t
i
n
g
7
20
4
26
4
$9
7
26
4
29
1
$2
0.
5
6
9
0.
5
5
0
0.
5
3
5
$0
$1
1.
%
22
Se
c
u
r
i
t
y
A
r
e
a
L
i
g
h
t
i
n
g
(
R
&
F
)
7A
15
3
13
1
$5
2
13
1
14
4
$1
0.
5
6
9
0.
5
5
0
0.
5
3
5
$0
$1
1.
2
%
23
St
r
e
e
t
L
i
g
h
t
i
n
g
-
C
o
m
p
a
n
y
11
30
10
1
$4
4
10
1
11
1
$1
0.
5
6
9
0.
5
5
0
0.
5
3
5
$0
$0
1.
%
24
St
r
e
e
t
L
i
g
h
t
i
n
g
-
C
u
s
t
o
m
e
r
12
32
3
2,
3
1
3
$4
0
7
2,
3
1
3
2,
5
4
8
$1
3
0.
5
6
9
0.
5
5
0
0.
5
3
5
$2
$1
1
2.
6
%
25
AG
A
R
e
v
e
n
u
e
--
--
0
$0
26
To
t
a
l
P
u
b
l
i
c
S
t
r
e
e
t
L
i
g
h
t
i
n
g
71
0
2,
8
0
9
60
1
2,
8
0
9
0
0
3,
0
9
4
16
3
13
2.
2
%
--
-
27
To
t
a
l
S
a
l
e
s
t
o
U
l
t
i
m
a
t
e
C
u
s
t
o
m
e
r
s
72
,
7
1
7
3,
3
2
5
,
8
7
3
21
6
,
5
2
7
1,
6
9
0
,
5
6
2
42
,
2
0
2
1,
5
9
3
,
1
0
9
3,
5
5
7
,
5
9
6
10
,
4
2
1
1,
8
2
7
8,
5
9
5
3.
9
%
==
=
28
To
t
a
l
S
a
l
e
s
t
o
U
l
t
i
m
a
t
e
C
u
s
t
o
m
e
r
s
72
,
7
1
5
1,
8
3
9
,
2
5
0
14
6
,
3
9
4
1,
6
9
0
,
5
6
2
42
,
2
0
2
10
6
,
4
8
6
2,
0
1
7
,
3
8
0
10
,
4
2
1
1,
8
2
7
8,
5
9
5
5.
8
%
==
=
(e
x
c
l
u
d
i
n
g
C
o
n
t
r
c
t
s
1
&
2
)
29
i E
q
u
a
l
t
o
M
W
h
s
a
l
e
s
b
y
v
o
l
t
a
g
e
t
i
m
e
s
t
h
e
c
o
r
r
e
s
p
o
n
d
i
n
g
l
o
s
s
f
a
c
t
o
r
s
i
n
t
h
i
s
l
i
n
e
:
1.
0
1
4
8
1.
0
6
4
7
5
1.
0
3
6
0
5
30
2
T
o
t
a
l
P
r
o
p
o
s
e
d
E
C
A
M
R
e
v
e
n
u
e
(
$
0
0
0
)
a
n
d
R
a
t
e
b
y
V
o
l
t
a
g
e
(
c
e
n
t
s
W
h
)
:
0.
5
6
9
0.
5
5
0
0.
5
3
5
0.
5
1
7
$1
0
,
4
2
1
31
3
E
q
u
a
l
t
o
M
W
s
a
l
e
s
b
y
v
o
l
t
a
g
e
t
i
m
e
s
t
h
e
c
o
r
r
e
s
p
o
n
d
i
n
g
p
r
e
s
e
n
t
r
a
t
e
i
n
t
h
i
s
l
i
n
e
:
0.
1
0
0
0.
0
9
3
0.
0
9
1
At
t
a
c
h
m
e
n
t
B
.C
a
s
e
N
o
.
P
A
C
-
E
-
i
i
-
o
i
St
a
f
f
C
o
m
m
e
n
t
s
:0
3
/
1
6
/
1
I
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 16TH DAY OF MARCH 2011,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. PAC-E-11-07, BY MAILING A COpy THEREOF, POSTAGE PREPAID,
TO THE FOLLOWING:
TED WESTON
ID REG AFFAIRS MGR
ROCKY MOUNTAIN POWER
201 S MAIN ST STE 2300
SALT LAKE CITY UT 841 1 1
E-MAIL: ted.weston(fpacificorp.com
YVONNE R HOGLE
SENIOR COUNSEL
ROCKY MOUNTAIN POWER
201 S MAIN ST STE 2300
SALT LAKE CITY UT 841 1 1
E-MAIL: yvonne.hogle(fpacificorp.com
DATA REQUEST RESPONSE CENTER
E-MAIL ONLY:
datareguest(fpacificorp.com
.~~ -=
SECRETAR
CERTIFICATE OF SERVICE