20220513Comments.pdf

CHRIS BURDIN
DEPUTY ATTORNEY GENERAL ,.
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE,IDAHO 83720-0074
[phone]
IDAHO BAR NO.98 10
Street Address for Express Mail:
11331 W CHINDEN BLVD,BLDG 8,SUITE 201-A
BOISE,ID 83714
Attorneyfor the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF ROCKY MOUNTAIN )POWER'S APPLICATION REQUESTING )CASE NO.PAC-E-22-05
APPROVAL OF $28.4 MILLION ECAM )DEFERRAL )
)COMMENTS OF THE
)COMMISSION STAFF
COMES NOW the Staff of the Idaho Public Utilities Commission ("Staff"),by and
throughits Attorneyof record,Chris Burdin,Deputy AttorneyGeneral,and submits the following
comments.
BACKGROUND
On March 30,2022,PacifiCorp dba Rocky Mountain Power ("Company")applied for
Commission authorization to adjust its rates under the Energy Cost Adjustment Mechanism
("ECAM")and requested approval of approximately $28.4 million in deferred costs from the
deferral period beginning January 1,2021,through December 31,2021.
The Commission approvedthe use ofthe ECAM in 2009.Order No.30904.Every month,
the Company tracks the difference between the actual net power costs ("NPC")it incurred to serve
customers,and the base NPC it collected from customers through previouslyestablished base rates.
Those costs vary by year with changes in the Company's fuel (gas and coal)costs,surplus power
sales,power purchases,and associated transmission.The Company defers the difference between
actual NPC and base NPC into a balancing account for later disposition at the end of the yearly
STAFF COMMENTS l MAY 13,2022
deferral period.The ECAM allows the Company to credit or collect the difference between actual
NPC and base NPC through a decrease or increase in customer rates.
In addition to the NPC difference,the ECAM includes:(1)the Load Change Adjustment
Revenues ("LCAR");(2)an adjustment for coal stripping costs under Emerging Issues Task Force
("EITF")04-06;(3)a true-up of 100%of the incremental Renewable Energy Credit ("REC")
revenues;(4)Production Tax Credits ("PTC");(5)the Lake Side 2 generation resource adder;(6)
a resource tracking mechanism ("RTM");and (6)the reasonable energy price ("REP"),as defined
in the 2020 Protocol,qualified facility ("QF")and energy imbalance market ("EIM")body of state
regulators ("BOSR")costs.The ECAM also includes a "90/10 sharing band"in which customers
pay/receive 90%of the increase/decrease in the difference between actual NPC and base NPC,
LCAR,and the EITF 04-06 coal stripping costs;and the Company incurs/retains the remaining
10%.The Company's Application included witness testimony explaining the calculation of each
of the above items.
The Company requested an order approving:(1)approximately $28.4 million in ECAM
deferral;and (2)a 4.5 percent increase to Electric Service Schedule No.94,Energy Cost
Adjustment.The Company estimated that a residential customer using 783 kilowatt-hours per
month would see an increase of approximately $2.97 a month on their electricity bill,and the
Company provided a summary of the estimated increased percentage impacts by customer class:
Residential Customers -(3.2%)
Residential Schedule 36 -(3.7%)
General Service Schedule 6 -(4.6%)
General Service Schedule 9 -(5.8%)
Irrigation Service Schedule 10 -(4.1%)
General Service Schedule 23 -(3.8%)
General Service Schedule 35 -(4.4%)
Public Street Lighting-(2.2%)
Tariff Contract 400 -(6.0%)
The Company requested that its proposed adjustment to the Electric Service Schedule No.
94 become effective on June 1,2022.
STAFF ANALYSIS
A.ECAM Calculation
Staff reviewed the Company's external audit reports,journal entries,invoices,contracts,
and bills to customers.Staff also reviewed the Company's adjustment to actual costs.Staff
reconciled the general ledger amounts to the NPC provided in Exhibit No.1 of Mr.Painter's
testimony.Staff reviewed the Company's hedge contracts and policies,and Staff believes they
STAFF COMMENTS 2 MAY 13,2022
reasonably safeguard price and fuel stability.Staff also reviewed the transactions and invoices for
the EIM revenues.Additionally,Staff verified the calculations of the RTM adjustment included
in the ECAM.The Company included three new items in this ECAM,the REP,BOSR and the
Western Resource Adequacy Program ("WRAP")funding.Because the BOSR and WRAP
fundingare not net power cost items,Staff opposes includingthem in the ECAM.Removal of the
BOSR and WRAP funding would reduce the ECAM deferral by $15,000.Staff believes this
change is very small,and will require a very minor change to the Schedule 94 rates.Staff
concludes that the ECAM deferral shown in Table No.1 is accurate and complies with ECAM
orders.
Table No.1.Deferred ECAM Balance
NPC Differential for Deferral $13,040,849
EITF 04-6 Adjustment (144,329)
LCAR (1,026,323)
Total Deferral Before Sharing 11,870,197
Sharing Band 90%
Customer Responsibility 10,683,178
Lake Side 2 Resource Adder 5,431,705
Production Tax Credits (6,086,042)
RTM Adjustment 17,733,989
REP QF 520,515
REC Deferral (101,687)
Interest on Deferral 225,928
Annual Deferral (Jan -Dec 2021)28,407,586
Unamortized Previous Balance 19,050,233
ECAM Rider Revenues (17,532,227)
Total Company Recovery $29,925,593
1.Net Power Cost Deferral
The NPC adjustment in the ECAM allows the Company to collect or credit the difference
between NPC incurred to serve customers in Idaho,and the NPC collected from Idaho customers
through base rates.In Order No.33668,the NPC embedded in rates were set at $26.90 per MWh.
The revenue collected through base rates is calculated by multiplying$26.90 by 3,513,348
MWh of actual Idaho sales,for a total of $94.5 million.The difference between base rate revenue
and Idaho's share of $108 million in actual NPC for 2021 is an under-collected balance of
STAFF COMMENTS 3 MAY 13,2022
approximately $13.5 million.The under collected balance is subject to a 90/10 customer sharing
band,with the Company paying 10%of the NPC differential.After removing the 10%Company
share,the amount to be collected through Schedule 94 rates is $10.68 million.
2.Emerging Issues Task Force 04-6 Adjustment
The EITF 04-6 adjustment is the difference between coal stripping costs the Company
incurred and recorded,as stated in the accounting pronouncementEITF 04-6,and the amortization
approved by Order No.30987.The Company uses this account to "undo"the effects of EITF 04-
6 that requires the Company to expense coal stripping costs as opposed to amortizing it over the
coal produced from the section of open mines.The adjustment decreases the deferral by $144,329.
Staff has reviewed the Company's calculation of the adjustment and believes it is accurate.
3.Load Change AdjustmentRevenues
Staff confirmed the Company's LCAR adjustment complied with Order No.33440.The
LCAR adjusts for the under or over recovery of fixed energy-classifiedproduction cost (excluding
NPC)because of the difference between Idaho sales used to determine base rates and the sales
from the deferral year.The LCAR of $5.54 per MWh was set in Order No.33668,and
subsequently adjusted due to changes in the corporate tax rate in Case No.GNR-U-18-01.
Multiplyingthe LCAR by the actual Idaho sales of 3,513,348 MWh shows that the Company
collected $19.46 million of energy-classified fixed production costs through base rates.The
$1.026 million difference between the actual energy-classified fixed production costs collected
and the $18.43 million embedded in base rates will be returned to customers by offsetting the
ECAM deferral.
4.Lake Side 2 Resource Adder
In Order No.32910,the Commission approveda stipulation wherein the parties to that case
agreed the Company could recover its investment in the Lake Side 2 generation facility through
the ECAM until its investment was included in base rates.The adder allows the Company to
recover $1.99 per MWh of generation at Lake Side 2,up to $5 million per year.In 2021,the
Company generated over 2.7 million MWh at Lake Side 2,allowing the Company to include the
maximum of $5.43 million in the deferral balance.
5.Production Tax Credits
In Order No.33668,the Commission approveda stipulation wherein the parties to that case
agreed to move the PTC true-up to the ECAM,with a $1.99 per MWh benefit to customers
included in base rates.In 2021,base rates included a $7.0 million benefit from PTCs.However,
STAFF COMMENTS 4 MAY 13,2022
the Company's actual PTCs in 2021 allocated $13.1 million to Idaho customers.The $6.1 million
difference between the PTCs in base rates and the actual PTCs is a benefit to customers.Compared
to last year's PTCs this is a significant increase to the number of PTCs the Company received.
This difference is explained by several new and repowered wind projects being online for the full
year of 2021.
6.RTM Adjustment
In Order No.33954,the Commission approveda stipulation wherein the parties to that case
agreed the Company would recover costs related to wind repowering projects through the ECAM.
In 2021,all of these projects were online and generating electricity.The RTM adjustment properly
reflects costs that offset the repowering projects'benefits to customers that are reflected as PTC
and NPC benefits in the ECAM.Based on the terms of the stipulation,the Company included
$17.7 million in the deferral.
7.Reasonable Energy Price QF Adjustment
The 2020 Protocol that was approvedby Order No.34640,included a provision that all QF
contracts approved in 2020 and beyond would be subject to a reasonable price adjustment.The
amount that the Company paid for that power from the QF contract that is over a reasonable energy
price would be SITUS allocated to the state that approved the QF contract.
In this case,there are 11 contracts that qualify for the reasonable energy price QF
adjustment,of which four incurred a SITUS allocation to Idaho.Staff reviewed the process for
creating the reasonable energy price and the energy price for those contracts and Staff believes it
complies with the 2020 Protocol.The reasonable energy price QF adjustment results in a $520,515
increase to the deferral that the Company proposed.
8.Renewable Energy Credit
In Order No.33668,the Commission approved $0.09 per MWh in REC revenues to be
included in base rates.The difference between the embedded amount and actual REC revenue is
trued-up in the ECAM.In 2021,base rates included $315,296 in benefits from REC revenues.
Idaho's share of the Company's actual REC revenues was $416,983.The difference of $101,687
offsets the deferral balance.
9.Body of State Regulators
The primary function of the BOSR is to provide an educational forum for participating
state regulators to learn about the EIM.The BOSR is comprised of at least one member from each
state commission.In its Application,the Company included $7,500 of fees allocated to Idaho as
STAFF COMMENTS 5 MAY 13,2022
part of its membership in BOSR.Staff believes the BOSR fees are administrative costs for the
EIM and are not NPC.Recovery of these fees has not been approved by the Commission.Staff
opposes including these administrative fees in the ECAM deferral balance as they are not NPC.
Combined with the adjustment below,Staff believes this will have a very minor impact on the rate
for the ECAM.See Attachment A.
10.Western Resource Adequacy Program
The WRAP is responsible for ensuring there is sufficient generation capacity to meet
forecasted peak energy demand in the West.In this year's ECAM,the Company included $7,092
in WRAP membership fees.While WRAP may have an impact in future NPC,its primary focus
is for future resource adequacy,not current NPC.In addition,the Commission has not approved
recovery of these administrative costs in the ECAM.Staff opposes including these non-NPC in
the ECAM.Combinedwith the adjustment above,Staff believes this will have a very minor impact
on the rate for the ECAM.See Attachment A.
11.Energy Imbalance Market
The EIM is a platformthat allows participating utilities to combine their stack of resources
to lower the costs of energy.This is a real-time market that balances every 15 minutes and issues
dispatch orders every five minutes.The California Independent System Operator ("CAISO")is
responsible for issuing dispatch orders.
All participant utilities can benefit from the EIM.If the EIM marginal price is lower than
the Company's marginal unit cost,then the Company benefits by buying power cheaper than if
they generated it themselves.If the EIM marginal price is higher than the Company's marginal
unit cost,the Company benefits by selling power at the EIM marginal price.
Idaho customers receive a benefit from the Company's participation in the EIM through
reduced overall NPC,which flow through the ECAM.The Company's participation in the EIM
also provides more transparency in the dispatch of the Company's resources.Staff is able to
compare the bid price in the EIM to fuel costs in the ECAM,which allows for prudencyverification
of the dispatch of the Company's resources.The ECAM only captures the benefits and not the
operation and participation costs which are included in base rates.
12.Analysis of Actual NPC
Staff believes the Company prudently dispatched its generation resources,purchased
power from the wholesale market,and sold excess generation into the market resulting in
reasonable NPC during the 2021 deferral year.Staff's analysis of Actual 2021 NPC is based on:
STAFF COMMENTS 6 MAY 13,2022
1)a review of the Company's Application,exhibits,and testimony to understand the factors
contributingto higher NPC;2)a comparison of actual-to-base NPC to confirm the amounts
attributed to the ECAM deferral;and 3)a comparison of actual NPC to the 5-year historical
average to identify any trends affecting NPC.
First,Staff reviewed the Application,exhibits,and testimony to identify and understand
the contributors to higher levels of NPC than amounts recovered in base rates over the 2021
deferral period.The Company requested an increase in the ECAM of $28.42 million,of which
$11.74 million was attributed to an under collection of NPC through base rates.Without the
ECAM 90/10 customer sharing band,the NPC differential would be $13.04 million,or $1.30
million higher.The Company noted higher costs for fuel and wholesale electricityin 2021 because
of higher energy market prices,which makes purchased power to serve its customers more
expensive.The Company also noted a reduction in wholesale sales likelydue to lower availability
of Company generation at or below market prices.The Company saw a $151 million increase in
purchased power expense,a $67 million increase in natural gas expense,and a $15 million increase
in wheeling and other expenses.These costs were partially offset by a $148 million reduction in
coal fuel expense.
Second,Staff compared 2021 actual NPC by FERC account/resource type to NPC included
in base rates (as shown in Table No.1 infra)and concludes that the circumstances in the
Company's system and the wholesale market explain how the Company dispatched their system.
To meet higher system load in 2021,the Company relied on increased amounts of purchased
power,natural gas generation,and renewables due to the implementation ofthe Company's Energy
Vision 2020 ("EV2020")project that came online at the beginning of 2021.Purchased power and
the cost of natural gas generation was 24.9%and 23.5%higher,respectively,than amounts
included in base NPC.The cost of renewables was also approximately 10%higher due to an
increase in wind capacity on the Company's system.However,coal generationwas approximately
19%lower and hydro generationwas approximately 27%lower than amounts reflected in the base.
The lower cost of coal generationwas due to the retirement of coal units.The lower amount of
hydro generation was due to water availability being lower than normal during the 2021 deferral
year.However,a large percentage of the increase in this year's ECAM can be attributed to the
reduction in the amount of generationthe Company sold into the market with a reduction of almost
46%as compared to base amounts.The combination of increased loads,and reduced amounts of
generation available from coal and hydro were likely contributors to the reduction in outside sales.
STAFF COMMENTS 7 MAY 13,2022
Table No.2 Comparison of AdjusterActual NPC to Base NPC
Adjusted Base-to-Actual PercentageSourceBaseNPCActualDifferenceDifference
Wholesale Sales (revenue)($181,516,972)($334,520,634)$153,003,6621 -45.7%
Purchased Power /Net
Interchange(cost)$755,610,634 $604,970,831 $150,639,803 24.9%
Coal (cost)$632,877,543 $780,404,471 ($147,526,928)-18.9%
Gas (cost)$351,392,214 $284,628,008 $66,764,206 23.5%
Other -Primarily Wind $164,685,177 $149,965,098 $14,720,079 9.8%(cost)
Total System $1,723,048,596 $1,485,447,775 $237,600,821 16.0%
Finally,Staff compared the monthly2021 ECAM actual NPC components to historical 5-
year average amounts to identify any trends or anomalies that either support or are inconsistent
with the increased 2021 actual NPC amounts.During 2021,the average net system yearly load
increased by 2.94%over a historical 5-year average.Figure No.I below compares the net system
load by month for 2021 relative to the 5-year average net system load.The month of June shows
the greatest difference at 113.2%above the 5-year average load amount,while December shows
the largest decrease at 96.6%of the 5-year average.Overall in 2021,the chart reflects higher
monthly loads during the period from March through July.This is likely due to increased
temperatures during June and July,which is consistent with the higher monthly net system loads
shown during those two months.
I The positive amount forthe wholesale sales base-to-actual difference represents a reduction in revenue from the total
actual amount of sales relative to the base amounts;whereas positive amounts for base-to-actual cost components
represent increases in actual cost as compared to base amounts.
STAFF COMMENTS 8 MAY 13,2022
Figure No.1 Comparison of Net System Load
NET SYSTEM LOAD -MONTHLY (MWH)
6,500,000
6,000,000
5,500,000 /
5,000,000 \,4
4,500,000 x '
4,000,000
JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC
----2021 ---5 YEAR AVG
To show how the percentage of generation of the different resource types has changed,
Staff compared the 2021 actual amounts of generation for each resource type (outer ring)to the
average amounts over the past five years (inner ring)as shown in the Figure No.2 below.
Figure No.2 Comparison of Resource Types
GENERATION RESOURCE TYPE IN YEAR 2021
VERSUS 5-YEAR AVERAGE
2021,OTHER 2021,PURCHASEDGENERATION,10.45%POWER AND NET
INTERCHANGE,2021,HYDRO 17.31%GENERATION,4.22%
5.74%
2021,GAS
GENERATION,20.16%5.21%
19.76%
16.61%
52.69%
2021,COAL
GENERATION,47.85%
STAFF COMMENTS 9 MAY 13,2022
Coal generation,the largest resource type,declined by 4.84%from 52.69%to 47.85%.
This is likely due to the closure of the Cholla coal fired power plant.Some of this reduction in
generation was displaced by the Company's natural gas generating resources which are also
dispatchable and provide increased operational flexibility.Gas generation in 2021 increased by
3.55%to 20.16%of system generation which is up from the 5-year average of 16.61%.This
increase is likely due to the higher temperatures seen in the spring and summer and the Company's
need to meet system load through dispatchable capacity.Although recent years have seen
relativelylow natural gas prices,2021 saw trending higher natural gas prices contributing to higher
NPC in 2021.
Hydro generation comprised just4.22%of the generationresource types compared to a 5-
year average of 5.21%.Specifically,generation from the Company's hydro resources in 2021 was
just 81.7%of the normal amount seen in the 5-year average.The lower amount of hydro
generationdirectly leads to higher NPC because it is a zero-fuel cost resource.
Other generation,which is comprised primarily of the Company's wind resources,has
expanded to 10.45%of the resource mix in 2021 compared to 5.74%in the 5-year average.This
is likely due to the completion of EV2020 just prior to 2021.NPC benefited from these wind
resources in that they are a zero-cost fuel resource.
During the deferral period,the total natural gas fuel expense increased $67 million over the
NPC cost in base rates.The increased expense in natural gas fuel expense is primarily due to
increases in natural gas fueled generation and commodity costs.Use of natural gas generation
resources increased by 963 GWh,or 8%.The Company stated that overall gas prices at the Opal
natural gas trading hub were 137%higher in 2021 compared to 2020.Painter Direct at 17.Staff
examined a sample of the Company's natural gas invoices,reviewed supporting workpapers,and
considered industry trends in commodity prices for the deferral period.Staff believes that the
increased natural gas costs in the Company's filing are correct and reasonable.
B.Proposed Rates
Staff verified that the rates in the Company's proposed Schedule 94,Energy Cost
Adjustment,were calculated using the methodology approvedin Order No.33440.However,with
the changes in the deferral balances proposed by Staff,the rates would be lower than what the
Company proposed.The Company's proposed rates in Schedule 94 are voltage-level specific:
0.733 cents per kWh for secondary service;0.720 cents per kWh for primary service;and 0.696
cents per kWh for transmission service.Staff s proposed rates are 0.733 cents per kWh for
STAFF COMMENTS 10 MAY 13,2022
secondary service,0.719 cents per kWh for primary service,and 0.695 cents per kWh for
transmission service.See Attachment A.
Both the Company's and Staff's proposed revision to Schedule 94 increases Company
revenue by approximately 3.9%.However,revenue increases to specific classes will vary because
of differences in rate design among the classes.The overall revenue increase for residential
Schedule 1 customers is 3.3%.A typical residential customer using an average of 783 kWh per
month would still pay $2.97 more per month under Staff's proposed rates.
C.Customer Notice and Press Release
The Company's press release and customer notice were included with its Application.
Staff reviewed the documents and determined that both met the requirements of Rule 125 of the
Commission's Rules of Procedure.The notice was included with bills mailed to customers
beginning April 4,and ending May 2,2022,providing customers with a reasonable opportunity to
file timely comments with the Commission by the May 13,2022,deadline.As of May 12,2022,
the Commission has received no comments from customers.
STAFF RECOMMENDATION
Staff recommends the Commission:
Approve the ECAM deferral balance without the BOSR and WRAP expenses.
Approve the rates as provided in Staff Attachment A.
Order the Company to provide revised tariffs for the proposed rates.
Respectfullysubmitted this j)(day of May 2022.
Chris Burdin
Deputy Attorney General
Technical Staff:Joe Terry
Ty Johnson
Rick Keller
Kevin Keyt
Curtis Thaden
i:umisc/comments/pace22.3cbjttjkskrketcomments
STAFF COMMENTS 11 MAY 13,2022
AT
T
A
C
H
M
E
N
T
A
RO
C
K
Y
MO
U
N
T
A
I
N
PO
W
E
R
ES
T
I
M
A
T
E
D
IM
P
A
C
T
OF
PR
O
P
O
S
E
D
EC
A
M
AD
J
U
S
T
M
E
N
T
FR
O
M
EL
E
C
T
R
I
C
SA
L
E
S
TO
UL
T
I
M
A
T
E
CO
N
S
U
M
E
R
S
DI
S
T
R
I
B
U
T
E
D
BY
RA
T
E
SC
H
E
D
U
L
E
S
IN
ID
A
H
O
AD
J
U
S
T
E
D
HI
S
T
O
R
I
C
A
L
12
MO
N
T
H
S
EN
D
E
D
DE
C
E
M
B
E
R
20
2
0
Pr
e
s
e
n
t
At
Me
t
e
r
At
EC
A
M
Pr
o
p
o
s
a
l
Pr
e
s
e
n
t
Li
n
e
Av
e
r
a
g
e
Ba
s
e
MW
h
by
Vo
l
t
a
g
e
Ge
n
e
r
a
t
i
o
n
Re
v
Ra
t
e
¢/k
W
h
EC
A
M
Re
v
Ne
t
Ch
a
n
g
e
De
s
c
r
i
p
t
i
o
n
Sc
h
.
Cu
s
t
o
m
e
r
s
MW
H
($
0
0
0
)
S
P
T
MW
h
($
0
0
0
)
S
P
T
($
0
0
0
)
($
0
0
0
)
¾
(1
)
(2
)
(3
)
(4
)
(5
)
(6
)
(7
)
(8
)
(9
)
(1
0
)
(l
l)
(1
2
)
(1
3
)
(1
4
)
(1
5
)
(1
6
)
Re
s
i
d
e
n
t
i
a
l
l
Re
s
i
d
e
n
t
i
a
l
Se
r
v
i
c
e
1
55
,
6
5
9
52
3
,
1
0
7
$6
0
,
1
4
7
52
3
,
1
0
7
57
0
,
5
0
5
$3
,
8
3
3
0.7
3
3
0.
7
1
9
0.
6
9
5
$1
,
8
5
2
$1
,
9
8
1
3.2
%
2
Re
s
i
d
e
n
t
i
a
1
O
p
t
i
o
n
a
l
T
O
D
36
11
,
7
1
1
19
6
,
3
3
7
$1
9
,
4
4
8
19
6
,
3
3
7
21
4
,
1
2
8
$1
,
4
3
9
0.7
3
3
0.
7
1
9
0.
6
9
5
$6
9
5
$7
4
4
3.7
%
3
AG
A
Re
v
e
n
u
e
$4
4
To
t
a
l
Re
s
i
d
e
n
t
i
a
l
67
,
3
7
0
71
9
,
4
4
4
$7
9
,
5
9
9
71
9
,
4
4
4
0
0
78
4
,
6
3
3
$5
,
2
7
2
$2
,
5
4
7
$2
,
7
2
5
3.3
%
5
Co
m
m
e
r
c
i
a
l
&
In
d
u
s
t
r
i
a
l
6
Ge
n
e
r
a
l
Se
r
v
i
c
e
-
La
r
g
e
Po
w
e
r
6
1,
1
5
8
34
5
,
8
5
4
$2
7
,
0
8
7
30
3
.
0
0
7
42
.
8
4
7
37
6
,
3
4
4
$2
,
5
2
9
0.7
3
3
0.
7
1
9
0.
6
9
5
$1
,
2
1
9
$1
,
3
0
9
4.
6
%
7
Ge
n
e
r
a
l
Sv
c
.
-
Lg
.
Po
w
e
r
(R
&
F
)
6A
20
7
26
,
8
0
5
$2
,
3
2
6
26
,
6
5
6
14
9
29
,
2
3
1
$1
9
6
0.7
3
3
0.
7
1
9
0.
6
9
5
$9
5
$1
0
2
4.
2
%
8
Su
b
t
o
t
a
l
-
S
c
l
i
e
d
u
l
e
d
1,3
6
5
37
2
,
6
5
9
$2
9
,
4
/
3
32
9
,
6
6
3
42
,
9
9
6
0
40
5
,
5
7
5
$2
,
7
2
5
$/
,
3
/
4
$/
,
4
/
/
4.
6
%
9
Ge
n
e
r
a
l
Se
r
v
i
c
e
-
Hi
g
h
Vo
l
t
a
g
e
9
17
22
2
,
6
9
9
$1
3
,
2
2
5
0
0
22
2
,
6
9
9
23
0
,
5
0
0
$1
,
5
4
9
0.7
3
3
0.
7
1
9
0.6
9
5
$7
4
2
$8
0
7
5.8
%
10
Ir
r
i
g
a
t
i
o
n
10
5,9
7
1
61
5
,
8
8
6
$5
5
,
3
6
3
61
5
,
8
8
6
67
1
,
6
9
1
$4
,
5
1
3
0.7
3
3
0.
7
1
9
0.6
9
5
$2
,
1
8
0
$2
,
3
3
3
4.
1
%
ll
Ge
n
e
r
a
l
Se
r
v
i
c
e
23
7,
7
3
4
18
3
,
0
1
6
$1
7
,
3
7
5
18
2
,
6
6
2
35
3
0
19
9
,
5
9
2
51
,
3
4
1
0.7
3
3
0.
7
1
9
0.6
9
5
$6
4
8
$6
9
3
3.
8
%
12
Ge
n
e
r
a
l
Se
r
v
i
c
e
(R
&
F
)
23
A
2,
5
7
6
39
,
7
1
0
$3
,
9
2
2
38
,
6
2
6
1,0
8
4
43
,
2
8
7
$2
9
1
0.7
3
3
0.
7
1
9
0.6
9
5
$1
4
0
$1
5
0
3.
7
%
/3
Su
b
t
o
t
a
l
-
S
c
l
i
e
d
u
l
e
23
10
,
3
1
0
22
2
,
7
2
6
21
,
2
9
8
22
1
,
2
8
9
/,4
3
7
0
24
2
,
8
7
9
1,6
3
2
78
8
84
4
3.
8
%
14
Ge
n
e
r
a
l
Se
r
v
i
c
e
Op
t
i
o
n
a
l
TO
D
35
2
27
8
$2
3
27
8
30
3
$2
0.7
3
3
0.
7
1
9
0.6
9
5
$1
$1
4.
4
%
15
Ge
n
e
r
a
l
Se
r
v
i
c
e
Op
t
i
o
n
a
l
TO
D
(R
&
F
)
35
A
0
0
$0
0
0
$0
0.7
3
3
0.
7
1
9
0.6
9
5
$0
$0
I6
Su
b
t
o
t
a
l
-
S
c
h
e
d
u
l
e
35
2
27
8
23
27
8
0
0
30
3
2
0.7
3
3
0.
7
/
9
0.
6
9
5
/
I
4.
4
%
17
Sp
e
c
i
a
l
Co
n
t
r
a
c
t
40
0
1
1,
3
6
9
,
7
1
6
$7
9
,
4
6
5
1,
3
6
9
,
7
1
6
1,4
1
7
,
6
9
7
$9
,
5
8
7
0.7
0
0
54
,
5
6
1
$5
,
0
2
6
6.0
%
18
AG
A
Re
v
e
n
u
e
$6
0
2
19
To
t
a
l
Co
m
m
e
r
c
i
a
l
&
In
d
u
s
t
r
i
a
l
17
,
6
6
6
2,
8
0
3
,
9
6
4
$1
9
9
,
3
8
9
1,
1
6
7
,
1
1
6
44
,
4
3
3
1,
5
9
2
,
4
1
5
2,
9
6
8
,
6
4
6
$2
0
,
0
0
8
$9
,
5
8
6
$1
0
,
4
2
2
5.0
%
20
Pu
b
l
i
c
Str
e
e
t
Li
g
h
t
i
n
g
21
Se
c
u
r
i
t
y
Ar
e
a
Lig
h
t
i
n
g
7
18
8
27
4
$5
0
27
4
29
8
$2
0.7
3
3
0.
7
1
9
0.6
9
5
$1
$1
2.
1
%
22
Se
c
u
r
i
t
y
Ar
e
a
Lig
h
t
i
n
g
(R
&
F
)
7A
13
2
10
6
$2
4
10
6
11
5
$1
0.7
3
3
0.
7
1
9
0.6
9
5
$0
$0
1.
6
%
23
St
r
e
e
t
Lig
h
t
i
n
g
-
Co
m
p
a
n
y
11
57
15
4
$6
1
15
4
16
8
$1
0.7
3
3
0.
7
1
9
0.6
9
5
$1
$1
0.
9
%
24
St
r
e
e
t
Lig
h
t
i
n
g
-
Cu
s
t
o
m
e
r
19
95
6
2,
4
1
7
$3
6
8
2,
4
1
7
2,
6
3
6
$1
8
0.7
3
3
0.
7
1
9
0.6
9
5
$9
$9
2.
4
%
25
AG
A
Re
v
e
n
u
e
$0
26
To
t
a
l
Pu
b
l
i
c
St
r
e
e
t
Li
g
h
t
i
n
g
63
3
2,
9
5
0
$5
0
3
2,
9
5
0
0
0
3,2
1
8
$2
2
$1
0
$1
1
2.
2
%
27
To
t
a
l
Sa
l
e
s
to
Ult
i
m
a
t
e
Cu
s
t
o
m
e
r
s
85
,
6
6
9
3,
5
2
6
,
3
5
9
$2
7
9
,
4
9
1
1,
8
8
9
,
5
1
I
44
,
4
3
3
1,
5
9
2
,
4
1
5
3,
7
5
6
.
4
9
6
$2
5
,
3
0
2
$1
2
,
1
4
4
$1
3
,
1
5
8
4.
5
%
28
To
t
a
l
Ex
c
l
u
d
i
n
g
Sp
e
c
i
a
l
Co
n
t
r
a
c
t
40
0
85
,
6
6
8
2,
1
5
6
,
6
4
3
$2
0
0
,
0
2
6
1,
8
8
9
,
5
1
1
44
,
4
3
3
22
2
,
6
9
9
2,3
3
8
,
7
9
9
$1
5
,
7
1
5
$7
,
5
8
2
$8
,
1
3
2
3.
9
%
Re
v
.
Rq
m
t
Un
a
l
l
o
c
a
t
e
d
All
o
c
a
t
e
d
Pr
o
p
o
s
e
d
Ra
t
e
s
Cu
r
r
e
n
t
Ra
t
e
s
29
Vo
l
t
a
g
e
Lin
e
Lo
s
s
Fa
c
t
o
r
s
ap
p
l
i
e
d
to
ra
t
e
s
(2
0
1
8
St
u
d
y
)
:
1.
0
9
0
6
1
1.
0
7
0
8
2
1.
0
3
5
0
3
S
P
T
S
P
T
30
Ta
r
i
f
f
Cu
s
t
o
m
e
r
EC
A
M
de
f
e
r
r
a
l
an
d
Ra
t
e
(c
e
n
t
s
/
k
W
h
)
:
$1
5
,
7
1
5
0.
6
7
2
0.
7
3
3
0.
7
1
9
0.
6
9
5
Ta
r
i
f
f
Cu
s
t
o
m
e
r
Ra
t
e
0.7
3
3
0.
7
1
9
0.
6
9
5
0.3
5
4
0.
3
4
2
0.3
3
3
31
O
C/]
RE
C
Ad
j
u
s
t
m
e
n
t
an
d
Ra
t
e
(c
e
n
t
s
/
k
W
h
)
:
($
1
0
2
)
-0
.
0
0
3
-0
.
0
0
3
-0
.
0
0
3
-0
.
0
0
3
Sc
h
e
d
u
l
e
40
0
Ra
t
e
0.
7
0
0
0.
3
3
3
32
To
t
a
l
Id
a
h
o
EC
A
M
Ra
t
e
(c
e
n
t
s
/
k
W
h
)
:
25
,
3
0
2
0.
6
7
4
0.
7
3
5
0.
7
2
1
0.
6
9
7
RE
C
Ad
j
-$
3
8
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 13TH DAY OF MAY 2022,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF,IN
CASE NO.PAC-E-22-05,BY E-MAILING A COPY THEREOF,TO THE
FOLLOWING:
TED WESTON EMILY WEGENER
ROCKY MOUNTAIN POWER ROCKY MOUNTAIN POWER
1407 WEST NORTH TEMPLE STE 330 1407 WN TEMPLE STE 320
SALT LAKE CITY UT 84116 SALT LAKE CITY UT 84116
E-MAIL:[e-mail] E-MAIL:[e-mail]
DATA REQUEST RESPONSE CENTER
E-MAIL ONLY:
[e-mail]
THOMAS J BUDGE BRUBAKER &ASSOCIATES
RACINE OLSON PLLP BRIAN C COLLINS
201 E CENTER STREET GREG MEYER
PO BOX 1391 16690 SWINGLINY RIDGE RD,#140
POCATELLO ID 83204-1391 CHESTERFIELD MO 63017
E-MAIL:[e-mail] E-MAIL:[e-mail]
emever consultbai.com
RONALD LWILLIAMS Electronic Service Only:
HAWLEY TROXELL ET AL JONATHAN WHEATLEY
877 W MAIN ST HAWLEY TROXELL ET AL
BOISE ID 83701 E-MAIL:[e-mail]
E-MAIL:rwilliams hawlevtroxell.com
Electronic Service Only:Electronic Service Only:
BRADLEY MULLINS KYLE WILLIAMS
MW ANALYTICS BYU Idaho
ENERGY &UTILITIES E-MAIL:[e-mail]
E-MAIL:brmullins mwanalvtics.com
Electronic Service Only:
VAL STEINER
ITAFOS CONDA LLC
E-MAIL:Val.steiner itafos.com
SECRETARY
CERTIFICATE OF SERVICE