20220415Brady Direct.pdf

BEFORE TflE IDAIIO PUBLIC UTILITIES COMMISSION
IN THE MATTER Otr" THE APPLICATION
OF IDAHO POWER COMPANY EOR
AUTHORITY TO IMPLEMENT POWER
COST AD.IUSTMENT (.PCA") RATES
FOR ELECTRIC SERVTCE FROM 'JUNEtt 2022, TIIROUGH MAY 31, 2423.
IDAHO POTIER COMPANY
DIRECT TESTIMONY
'JESSICA G. BRADY
cAsE NO. IP3-E-22-1,L
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O. PLease state your name, business address, and
present position with Idaho Power Company ("Idaho Power" or
ttCompany" ) .
A. My name is ,Jessica G. Brady. My business
address is L221 West Idaho Street, Boise, Idaho 83702. I
am employed by Idaho Power as a Regulatory Analyst in the
Regulatory Affairs Department.
A. Please describe your educational background.
A. In May of 2016, I received a Bachelor of
Science degree in Economj-cs and a Bachel-or of Arts degree
in Spanish from the University of Idaho. I have also
attended "Electric Utility Fundamentals & InsighLs," an
electric utility course offered through the Western Energy
Institute.
a. Please describe your work experience.
A. In September 202L, I was hired as a Regulatory
Analyst in Idaho Power's Regulatory Affairs Department. As
a Regulatory Analyst, I provide support for the Company's
regulatory activities, including compliance reporting,
financial analysis, and the development of revenue
forecasts for regulatory filings. I am also responsible for
the Company's power cost filings in both Idaho and Oregon.
Prior to Idaho Power, I worked for fj-ve years at
Clearwater Analytics, a provider of investment accounting
and reportlng software. I hel-d various roles at Clearwater
BRADY,
Idaho
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Analytics but was pri-marily focused on customer success and
relationship management. f gained a breadth of knowledge in
investments and the use of proprietary software to
streamline the operations of a company's finance and
accounti-ng teams. I spent my last year at Clearwater
developing a training program focused on providing new
hires with the technical skiIIs to be successful in an
operations role.
O. What is the Company requesting in this case?
A. The Company is requesting approval of its
2022-2023 Power Cost Adjustment (*PCA") rates to become
effective ,June t, 2022. If approved, the 2022-2023 PCA
will result in an increase in total billed revenue of
approximately $103.4 million, or 8.27 percent.
A. How is your testimony organized?
A. My testimony consists of four sections. In the
first section, I provide an overview of the PCA. In the
second section, I detail the 2022-2023 PCA amount in
comparison to last year's PCA amount, identify and discuss
the main factors contributing to this change, and present
the quantification of the 2022-2023 PCA rates to become
effective June t, 2022. fn the third section, I discuss
the additional PCA component related to revenue sharing. In
the final section, I detail the net customer impact of the
2022-2023 PCA rates if approved as fil-ed.
BRADY, DI 2
Idaho Power Company
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I. PCA O\TER\EEIT
O. What is the purpose of the PCA?
A. The PCA is a rate mechanism that quantifies
and tracks annual differences between actual Net Power
Supp1y Expenses (*NPSE") and the normalized or "base 1eve1"
of NPSE recovered in the Company's base rates, resulting in
a credit or surcharge that is updated annually on ,June 1.
The PCA mechanism uses a l-2-month test period of April
through March (*PCA Year") and includes a forecast
component and a Balancing Adjustment, formerly referred to
as the "true-up" and the "true-up of the true-up". The
forecast component represents the difference between the
Company's NPSE forecast from the March Operating Plan and
base level NPSE recovered in the Company's base rates. The
Balancing Adjustment includes a backward-looking tracking
of differences between the prior PCA Year's forecast and
actual NPSE incurred by the Company, and also tracks the
coll-ection of the prior year's Balancing Adjustment.
O. Is the Balancing Adjustment new to this PCA
BRADY,
Idaho
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20 fi1ing?
2L A.Yes. In Order No. 352901, the Idaho Public
22 Utilities Commission ("Commission") approved a modification
r In the l@tter of the AppTication of ldaho Power Company forIbdification of the Power Cost Adjustment l@chanism, Case No. IPC-E-2 1-
38, Order No. 35290 (January 1-0, 2022).
DI
Power
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Company
1 to the PCA filing to replace the "true-up" and "true-up of
2 luhe true-up" with a single Balancing Account. The two
3 "true-up" rates previously included in PCA filings are now
4 combined into one "Balancing Adjustment" rate. It should be
5 noted that this modification solely impacts the presentment
6 of the PCA but has no material impact on the rates charged
7 to customers.
I Q. How does the PCA mechanism function?
9 A. With the exception of Public Utility
l-0 Regulatory Policies Act of L978 (*PURPA") expenses and
l-1 demand response incentive payments, the PCA allows the
1"2 Company to pass through to customers 95 percent of the
13 annual differences in actual NPSE as compared with base
1,4 l-evel NPSE, whether positive or negative. With respect to
15 PURPA expenses and demand response incentive paymentsr ds
1,6 actual annual expenses deviate from base level NPSE, the
1,7 Company is allowed to pass 1-00 percent of the difference
18 for recovery or credit through the PCA. The PCA is also
19 the rate mechanism used by the Company to provide customer
20 benefits resulting from the revenue sharing mechanism
21, approved by the Commission in Order No. 340'7L.
22 O. Does the revenue collected from customers
23 through the annual PCA rate contribute toward the Company's
24 earnings?
BRADY, DI 4
Idaho Power Company
1 A. No. The PCA mechanism provides for the annual
2 coLlection or refund of net power supply cost differences
3 between actual costs incurred by the Company and the base
4 l-evel NPSE component of base rates. Aside from the 95
5 percent to 5 percent sharj-ng component I just described,
6 the PCA provides for a one-for-one collection or refund of
7 actual net power supply expenses incurredr or to be
8 incurred, to provide safe, reliable electri-c service to
9 customers.
10 A. What are the components of the PCA base leve1
11 NPSE?
12 A. The PCA base leve1 NPSE includes the following
13 Federal Energy Regulatory Commission ("FERC") accounts:
L4 Account 501, FueI (coaI); Account 535, Water for Power;
15 Account 547, FueI (gas); Account 555, Purchased Power;
1,6 Account 565, Transmission of Electricity by Others; and
I7 Account 447, Sales for Resale (typically referred to as
18 surplus sales).
19 The PCA base 1evel expense component for FERC
20 Account 555 includes costs of both PURPA and non-PURPA
2L (market) purchases.
adjusts FERC Account
Per Order No. 32426, the Company
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incentive payments
who participate in
programs.
that the Company provides to
any of its three demand response
555 to also include demand
BRADY,
Idaho
response
customers
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Power
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rr. 2022-2023 PCA
A. What is the total PCA col-lection that woul-d
resul-t under the 2022-2023 PCA rates proposed by the
Company in this case?
A. The 2022-2023 PCA rates would resul-t in total
PCA collection of $216.9 mil-l-ion. This represents an
increase in total billed revenue of $103.4 million for the
upcoming year, an increase of 8.27 percent.
O. Have you prepared a tabl-e that detail-s the
$103.4 mil-Iion revenue impact by component?
A. Yes. Table 1 presents a separation of the
$103.4 million increase into each component included in the
Company's proposed rates.
o.Vilhat are the main factors driving the revenue
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change requested
A. The
in this case?
r_ncrease
to an increase 1n both the
Balancinq Adjustment. The
component is attributed to
in this year's PCA is attributed
forecast component and the
increase in this year's forecast
lower expected hydro generation,
BRADY, DI
Idaho Power
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Company
Table 1 Revenue lmpact by Component
Line No. Rate Component 2021-2022PCA 2022-2023PCI Difference
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PCA Forecast
PCA Balancinc Adiustment
s
s
131,825,063
(18.320.281)
5 L78,79s,L45
s 38.564.487
s
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46,970,081
56.984.758
PCA Total
Revenue Sharinc
s
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113,504,783
0
s 217,4s9,632
S (s58,771)
s
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103,954,849
(s68,77]-1
Total Revenue ImDact s 113.s04.783 s 216.890.861 s 103.386.078
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higher market energy prices, and higher natural gas prices,
which will be discussed in detail- l-ater in this testimony.
Thls year's PCA Balancinq Adjustment is
approximately $38.7 miIlion, which is $57.0 mil-l-ion higher
than last year's Bal-ancing Adjustment, which was a credit
of $18.3 milIion. This year's Balancing Adjustment
demonstrates that actual power supply costs for the 2021,-
2022 PCA Year were higher than the forecast power supply
costs included in last year's PCA forecast.
A. PCA Forecast.10
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A.
How is the PCA forecast amount determined?
As described previously, the PCA forecast
l_3 component
forecast
represents the difference between the
L4 of NPSE for the upcoming April - March
L5 and base Ievel NPSE recovered in the Company's base rates.
16 O. What is the Company's determination of the
l7 system-level difference between currently approved base
18 level NPSE2 and the forecast of NPSE for the 2022-2023 PCA
1,9 Year?
20 A. The system-Ievel forecast of NPSE for the
21 2022-2023 PCA Year is $498,834,556, which is $193,I49,687
22 higher than the currently approved base level NPSE of
23 $305,684,869. Tab1e 2 presents the system-Ievel
2 In the l@tter of the AppTication of ldaho Power Company forAuthority to EstabTlsh a New Base Level of Net Power SuppJy Expense,
Case No. IPC-E-13-20, Order No. 33000 (March 21, 201,41.
Company's
test year
BRADY, DI
Idaho Power
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Company
1 differences between currently approved base level- NPSE and
2 the forecast of NPSE for the 2022-2023 PCA Year by EERC
3 account.
Table 2 2022-202, PCA FORECAST (Total System)
Line No.FERC Account Base NPSE Forecast Difference
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95% Sharins Accounts
Account 501, Coal
Account 535, Water for Power
Account 547, Other Fuel
Account 555, Purchased Power Non-PURPA
Account 555, 3rd Party Transmission
Account 447, Surplus Sales
S
s
s
s
s
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108,503,180
2,380,s97
33,357,563
52,605,593
s,455,955
(51,735,1s3)
S 151,179,100
So
s 86,983,s66
S 99,906,480
s 5,149,239
s (6s,08s,848)
s
s
s
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s
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42,675,980
(2,380,s97)
53,616,003
37,299,881
(306,716)
(13,3s0,69s)
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s 160,578,735 s 278,132,598 s 117,553,853
100% Sharinq Accounts
Account 555, PURPA
Account 555, Demand Response lncentives
s
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133,853,869
lL,252,265
s 212,s86,0s8
S 8,11s,900
s
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78,732,189
(3,136,36s)
9 Total s 30s,584,869 s 498,834,ss5 s 193,149,687
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O. What is the basis for the forecast of NPSE for
the 2022-2023 PCA Year?
A. The forecast of NPSE for the 2022-2023 PCA
Year is based on the Company's March 31, 2022, Operating
P1an.
O. How is the NPSE forecast developed for the
Company's Operating Plan?
A. The Operating Pl-an is prepared monthly and
represents a forecast of the Company's monthl-y NPSE for the
following 1B-month period; however, for the PCA, the
Company includes only the 12 months that correspond to the
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Idaho Power
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L PCA Year. The Operating Plan is developed by simulating
2 the dispatch of the Company's generation resources for each
3 month, segmented by heavy load and light load hours. The
4 dispatch considers a current forecast of forward market
5 energy prices, available hydro generation, coal- and natural
6 gas prices, and any existing hedge transactions. The
7 system load forecast is then analyzed against the resulting
B monthly heavy load and light load dispatch to determine a
9 monthly load and resource balance. Any identified resource
10 deficiency is assumed to be filled with market energy
1l- purchases or natural gas to fuel the Langley Gulch power
t2 plant ("Langley Gulch"), based on economics and available
13 generati-ng capacity at Langley Gulch. Economically
L4 dispatched generation above the system load forecast
15 represents surplus energy sales. The forecast of monthly
1,5 NPSE and generation for the 2022-2023 PCA Year, as
17 determined in the Company's March 31, 2022, Operating PIan,
18 is provided in Exhibit No. 1.
L9 O. Please explain how the Company modeled Bridger
20 Units 1 and 2 Ln the March 3L, 2022 Operating Plan, in
2L 1ight of the ongoing Bridger Regional Haze compliance
22 discussions.
23 A. In light of ongoing discussions with the U.S.
24 Environmental Protection Agency regarding the Wyoming
25 Regional Haze State Implementation Plan (*SIP"), Idaho
BRADY, DI 9
Idaho Power Company
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Power adjusted the availability of Bridger Units 1 and 2
within the March Operating Plan. Specifically, the Company
modeled Bridger Unit 2 Lo be available for dispatch at a 25
percent level from June - October 2022 to reflect ongoing
uncertainty related to these discussions. For the remaining
months within the PCA year, Unit 2 is modeled at
availability levels that meet the overall plant emj.ssions
limits and annual emissions cap as required per the revised
SIP. Bridger Unit 1- operations were modeled as available
for dispatch at the revised approved SIP leve1s for the
entire 2022-2023 PCA year.
a. How does the Company's forecast of system-
1eve1 NPSE for the 2022-2023 PCA compare to the system-
1evel forecast included in last year's PCA?
A. Tabl-e 3 below compares this year's 2022-2023
PCA forecast of NPSE to last year's PCA forecast by FERC
account. As detailed in this tabIe, the PCA forecast on a
total system basis for the 2022-2023 PCA Year is
$498,834,556, which is $56,477,L49 higher than last year's
forecast amount of $442,357,407.
BRADY,
Idaho
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Power
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Table 3 PCA Forecast Comparison Expenses (Total Systeml
line No.FERC Account Difference
2021-2022
Forecast
2022-2023
Forecast
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95% Sharins Accounts
Account 501, Coal
Account 536, Water for Power
Account 547, Other Fuel
Account 555, Purchased Power Non-PURPA
Account 565, 3rd Party Transmission
Account 447, Surplus Sales
s
S
s
$
s
s
L18,562,796 s0s
57,235,044 s
74,800,530 s
4,853,909 s
125,842.2251 s
151,179,150 s0s
85,983,566 s
99,906,480 s
5,149,239 s
(6s.08s.848) s
32,615,355
0
29,748,522
25,105,950
295,331
{.39,243.6231
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100% Sharins Accounts
Account 555, PURPA
Account 555, Demand Response lncentives
s 229,510,0s4 s 278,L32,s98 5 48,522,s44
s
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s
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205,133,74L
7,673,5t2
s 212,s86,0s8
s 8,11s,900
7,452,3t7
s02,288
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s 212,747,353 s 220,70L,958 s 7,954,505
$ 442,3s7,407 s 498,834,ss6 s SS,qt,UgTotal PCA Forecast
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O.What general conclusions can be drawn from the
information contained 1n Table 3?
A. When vj-ewed by category, the 95 percent
sharing accounts have increased approximately $48.5 mill-ion
from l-ast year' s forecast, while the 100 percent sharing
accounts have increased approximately $8.0 mi1l1on over
last year's forecast.
O. What factors are contributing to the major
differences presented in Table 3?
A. Forecast expenses included in the 95 percent
sharing accounts are expected to increase by 21 percent as
compared to last year, from $229,610,054 to $278tL32r598.
BRADY, Dr 11
Idaho Power Company
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Due to a reduction in forecast hydro generation, higher
forecast market energy prices, and higher forecast naturaf
gas prices, the Company expects to rely more on coal
generation to serve load and is expected to increase off-
system surplus sales.
O. Please elaborate on the changes in the 95
sharing accounts for this year's forecast as
forecast.with last year's
A In addition to lower forecast hydro
1-0 generation, which will- be discussed in detail later in
testimony,
gas prices
Company's
higher forecast market energy prices and natural
are contributing to increased generation at the
coal plants, as well- as increased off-system
l4 surplus sales.
For the 2022-2023 PCA Year, the average forecast
market purchase price is $49.11 per megawatt-hour ('MWh"),
compared to $21.34 per MWh last year, an i-ncrease of B0
percent. In addition, the per-unit cost of natural gas for
the 2022-2023 PCA Year is $34.03 per MWh, an increase of 39
percent compared to last year. As a result of higher market
energy prices and natural gas prices, coal generation
becomes more economic. The average per-unit cost of coal-
fired generation is $29.7 4 per MWh, which is a 10 percent
decrease from last year. Accordingly, expenses from market
purchases are expected to increase 91 percent as compared
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BRADY, DI
Idaho Power
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l- to last year's forecast, natural gas expense is expected to
2 increase 52 percent, and coal fuel expense is expected to
3 increase 28 percent.
4 The increase in forecast market energy prices is
5 also resul-ting in hi-gher surplus sales revenue. Surplus
6 sales revenue is expected to increase 1-52 percent compared
7 to last year, from $25,842,225 Lo $65,085,848. For the
B 2022-2023 PCA Year, the average forecast market sales price
9 is $51.73 per MWh compared with $34.23 last year, a 51
10 percent increase.
11 O. What factors are contributing to the change in
1"2 the 100 percent sharing accounts?
13 A. Forecast expenses included in the 100 percent
L4 sharing accounts are expected to increase by 4 percent as
15 compared to last year, from $2L2,747,353 Lo $220,701,958.
1,6 Forecast PURPA costs increased by $7.45 million as compared
L7 to l-ast year's forecast and forecast demand response
18 incentive palrments increased by $0.5 mill-ion as compared to
19 last year.
20 O. Is the increase in forecast PURPA costs
21, related to increased generation output from PURPA projects?
22 A. fn part. Table 4 details changes between last
23 year's
respect
PCA forecast and this year's PCA forecast with
generation in MVCh. As shown in Tabl-e
anticipated to increase by 10r 708
BRADY, Dr 13
Idaho Power Company
24 to forecasted
25 4, PURPA generation is
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2
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4
Mwh, or less than
PURPA expense is
PURPA contracts,
MWh, compared to
1- percent.
largely the
The 4 percent increase in
result of price escalation j-n
for which the average cost is $69.96 per
$67 .75 l-ast year.
Table 4 PCA Forecast Comparlson Generation (Total System-Mwhl
line No.FERC ACCount 2O2L-2022 Forecast
2022-202?
Forecast Difference
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2
3
4
Hydro 6,690,890 5,972,743 17L8,L47l
95% Sharins Accounts
Account 501, Coal
Account 547, Other Fuel
Account 555, Purchased Power Non-PURPA
3,599,2L9
2,340,994
L,478,696
5,093,043
2,556,322
1,s80,326
L,483,825
2L5,328
101,630
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95% Sharing Accounts L4,109,799 L5,192,435 1,082,636
lfi)% Sharins Accounts
Account 555, PURPA 3,027s05 3,038,613 10,708
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1fi)% Accounts 3,027,905 3,039,513 10,708
Total Generation L7,137,7M 18,231,048 L,093,344
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95% Sharinr Accounts
Account 447, Surplus Sales 754,975 1.258.195 503.220
8 Total Load L6,382,729 L6,972,853 590,L24
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o.$Ihat other general conclusions can be drawn
from the information in Table 4?
A. Compared to last year' s forecast, hydro
generation is expected to decrease 718r 147 MWh, or 11
percent. The decrease in hydro generation, combined with an
increase in market energy prices and natural gas prices, is
driving an increase in coal-fired generation and surpl-us-
sales. Coal-fired generation is projected to increase
L,483r825 MWh compared to last year, or 41 percent and
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BRADY, DI
Idaho Power
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Company
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1 surplus-sales volumes are expected to increase 503r220 l,tfrilh,,
2 or 67 percent.
3 Q. What is causing the decrease in expected hydro
4 generatj-on of 7L8,147 MVlh?
5 A. The decrease in expected hydro generation is
5 mainly due to lower projected inflows into Brownlee
7 reservoir. The March Operating Plan used in this year's
8 PCA forecast projects April through ,July inflows into
9 Brownlee of 2.9 million acre-feet ("MAF") as compared to
10 4.2 I,IAE used to determine last year' s PCA forecast, a
tL decrease of 31 percent. Expected inflows into Brownlee
L2 were higher for last year's PCA forecast as a resuLt of
13 better snowpack conditions, which provide for sustained
L4 runoff and increased hydro generation during the spring and
15 summer months.
1,6 Additionally, this year's PCA forecast reflects
17 weaker reservoir storage condj-tions, as compared to last
18 year's forecast. The March Operating Plan used in this
19 year's PCA demonstrates that available storage in the 11
20 reservoirs above Brownlee is 76 percent of normal and at 51
2t percent of capacity, compared to last year's 2021 March
22 Operating PIan, in whj-ch storage was 113 percent of normal
23 and at 75 percent of capacity. Together weaker snowpack
24 conditions and carryover as compared to the prior year are
BRADY, DI 15
Idaho Power Company
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resulting in the 11- percent reduction in forecast hydro
generation for th.e 2022-2023 PCA Year.
O. How are the forecasted NPSE differences
presented in Table 2 used to determine the 2022-2023 PCA
forecast component to be collected from Idaho customers?
A. T}:e 2022-2023 PCA forecast component reflects
the Idaho jurisdictional share of the forecasted NPSE
differences presented in Table 2, adjusted for the PCA
sharing provisions. The Idaho jurisdictional share of the
forecast NPSE differences is determined by applying a ratio
of forecast firm Idaho jurisdictional sales to forecast
firm system-Ieve1 sales to the system-1evel NPSE
differences.
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1-1
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1-3
L4 A. What is the Company's forecast of system-1eveI
15 firm sales and Idaho jurisdictional firm sales for the
16 2022-2023 PCA Year?
1.7 A. Eor the 2022-2023 PCA Year, Idaho Power has
18 forecast system-Ievel firm sales to be 15r 690,546 MlVh and
19 ldaho jurisdictional firm sales to be 14,992,046 MWh, or
20 95.55 percent of the system Ievel.
2L O. What is the Company's determination of the
22 2022-2023 PCA forecast component to be collected from fdaho
23 customers?
24 A. 'II:,e 2022-2023 PCA forecast component to be
25 coll-ected from Idaho customers j-s $178,795t544. Table 5
BRADY,
Idaho
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Power
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Company
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presents the determination of the 2022-2023 PCA forecast
component by individual- PCA expense and revenue category.
B. Bal.ancing Adjustneat.
a. What is this year's quantification of the
Bal-ancing Adjustment?
A. The Bal-anclng Adjustment is detailed in the
PCA deferraf report, attached hereto as Exhibit No. 2. This
report compares actual NPSE amounts to actual power cost
collections monthly, with the differences accumulated as a
deferral balance. The balance at the end of March 2022,
with interest applied, was $38,669t525 as shown on row 100
of Exhibit No. 2. The approximate $38.7 mil-Iion represents
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BRADY, DI
Idaho Power
l7
Company
Table 5 2022-2023 PCA FORECAST
Line No.FERC Account Difference from Base
Difference After
Sharinc ldaho Allocation
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2
3
4
5
6
95% Sharins Accounts
Account 501, Coal
Account 536, Water for Power
Account 547, Other Fuel
Account 555, Purchased Power Non-PURPA
Account 555, 3rd Party Transmission
Account 447, Surplus Sales
(From Table 1)
s 42,67s,980
s (2,380,s97)
S s3,616,003
5 37,299,887
s (305,716)
S (13,3s0,59s)
s
s
s
s
s
s
40,542,18L
(2,26L,s67l.
50,93s,202
3s,434893
(291,380)
(12,583,150)
s
s
S
s
s
s
38,737,356
(2,150,888)
48,567,709
33,857,430
.278,4081
(t2,1L8,5471
7
s 117,ss3,863 $ 771,676,770 s 106,704,6s8
100% Sharinq Accounts
Account 555, PURPA
Account 555. Demand Resoonse lncentives
s
s
78,732,189
(3.136.3651
s
s
78,732,L89
(3.135.355)
s
s
75,227,25L
(3.136.36s)
9 Total s 193.149.587 s 787.27L,994 s t78.79s,s44
1,4
1
2
3
4
5
6
7
8
9
an increase to customer rates in this year's PCA Balancing
Adjustment.
O. To what factors do you attribute the
accumulation of the approximate $38.7 million deferral-
balance?
A. The approximate $38.7 million deferral balance
was primarily driven by a decrease in actual hydro
generation from expected as well as higher than forecast
market purchases, offset by higher surplus sales.
ActuaL hydro generation for the 202L-2022 PCA year
totaled 5,268,002 MWh, d 21 percent decrease from last
year's forecast of 6,6901890 M[rIh. Actual purchased power
totaled 4,079r834 MWh, a 176 percent increase from last
year's forecast. Actual surplus sales volumes totaled
L,373r 630 MWhr Errr increase of 82 percent from 754,975 MWh.
Actual natural gas prices were also higher than
forecast, driving a 55 percent increase in natural gas fuel
expense. Although natural gas prices were higher than
forecast, the Company's reliance on natural gas generation
did not decrease as it was needed to serve Load due to
Iower than expected hydro generation
expected temperatures during l'h,e 202L
0. Please elaborate on the
and higher than
summer season.
changes in actual
versus forecast generation and
PCA Year.
expense for the 2021-2022
10
11
1,2
13
L4
15
16
t7
18
l-9
20
2t
22
23
24
BRADY,
Idaho
DI
Power
18
Company
25
1 A. Last year's PCA forecast included an average
2 market sal-es price of $34.23 per MWh. The actual average
3 market sal-es price for the 2021-2022 PCA year was $57.70
4 per MVflh, a 69 percent increase. As a result of the
5 difference in forecast and actual market sales prices, as
6 wel-l- as economic opportunity during the spring and winter
7 months of Lhe 202L-2022 PCA year, actual surplus sales
B volumes were 82 percent higher than forecast. Surplus sales
9 revenue total-ed $79,257,653, which was 201 percent higher
10 than forecast revenues of $25r842,225.
11 Coal--fired generation totaled 3,241,970 MWh, which
L2 was 10 percent lower than forecast, and actual coal fuel
13 expense was $104.5 mi11ion, 12 percent .l-ower than forecast.
1,4 Coal-fired generation was lower than forecast due to the
15 increase in market energy purchases and increase j-n natural-
16 gas generation.
L7 Natural gas generatJ-on totaled 2,719,869 MWh for the
18 2021-2022 PCA Year, which was 378,875 MWh, or L6 percent,
1,9 higher than forecast. Due to natural gas prices being
20 higher than expected, actual natural qas expense totaled
2l $88,941,596, which was 55 percent higher than forecast.
22 While natural gas prices were higher than forecast, the
23 Company's reliance on natural gas generation increased 16
24 percent as it was needed to meet 1oad, as wel-I as make off-
25 system sales when it was economic, as noted prevj-ously.
BRADY, Dr t9
Idaho Power Company
1 While both purchased power and surplus sales
2 increased, surplus sale volumes were highest in off-peak
3 spring and winter months, and purchased power was highest
4 in summer months, where hot temperatures caused
5 continuously higher than forecast peak loads.
6 Q. Were there any items included in this year's
7 Balancing Adjustment in addition to actual NPSE incurred
8 durj-ng the April 202L through March 2022 period?
9 A. Yes. Per Commission Order No. 34100, Idaho
10 Power included its actual costs of Western Energy Imbalance
11 Market (*EIM") participation for ApriL 2021 through March
L2 2022 j-n the Balancing Adjustment. Benefits associated with
13 EIM participation are embedded j-n actual NPSE experienced
L4 over that same period.
l-5 A. Please summarize the conditions of Order No.
16 34100 as they pertain to EIM cost recovery through the 202I
1,7 PCA.
18 A. Per the terms of the settlement stipulation
1,9 (*EIM Stipulation") approved by Order No. 34100, Idaho
20 Power agreed to include an EIM-related monthly revenue
21- requlrement in its monthly PCA deferral calculation based
22 on actual EIM participation costs commencing April L, 201-8.
23 The Company also agreed to apply a soft cap to EIM-related
24 revenue requirement incl-uded in the PCA deferral equal to
25 annual EIM benefits as reported by the California
BRADY,
Idaho
DT
Power
20
Company
1 Independent System Operator (*CAISO") for the corresponding
2 period.
3 Q. Is the ElM-related revenue requirement
4 included in the April 2021 through March 2022 PCA deferral
5 under the soft cap of annual CAlSO-reported benefits for
6 that same period?
7 A. Yes. Eor the April 2021 through March 2022
8 period, the EIM-related revenue requirement totaled $2.9
9 miI1ion, while CAISO reported EIM benefits for ldaho Power
10 of approximately $40 million from April through December
1l- (CAISO' s first quarter 2022 report has not yet been
1,2 published) . Therefore, the Company's ElM-related revenue
13 requirement is less than the soft cap agreed to in the EIM
L4 Stipulation.
15 O. Does Idaho Power believe the EIM has provided
L6 net benefits to customers since joining in April 20lB?
I7 A. Yes. While Idaho Power believes the CAISO
18 benefit calculation overstates esti-mated benefits to Idaho
t9 Power's system, the Company believes customers have
20 realj-zed significant net benefits since the Company's entry
2L into the EIM in April 20L8. As discussed in the Company's
22 May 24, 20L9, Report of EIM Benefits and Costs of
23 Participation, filed in Case No. IPC-E-16-L9, Idaho Power
24 has developed a more precise methodology for determining
25 EIM benefits that uses inputs specific to the Company.
BRADY, D] 2T
Idaho Power Company
l_
2
3
4
5
6
7
B
9
Based on this methodology, the Company believes benefits
achieved between April 2021, and December 202L are
approximately $16 million (benefits for the first quarter
of 2022 are not yet available). This level of EIM benefits
compared to the ldaho-jurisdictional EIM costs of $2.9
milIion, demonstrates a net benefit to the Company and,
ultimately, its customers.
C. PCA Rate tion.
O. How i-s the rate for the forecast portion of
the PCA for April 2022 through March 2023 determined?
A. The rate for the forecast portion of the PCA
is equal to the sum of (1) 95 percent of the difference
between the non-PURPA expenses quantified in the Operating
Plan and those quantified in the Company's last approved
update of NPSE, divided by the Company's forecast of system
firm sales for ,June 1,, 2022, through May 31, 2023 ("System-
1evel Sales Eorecast") i and (2) 100 percent of the
difference between PURPA-related expenses quantified in the
Operating Plan and those quantified in the Company's last
approved update of NPSE, divided by the Company's System-
l-eveI Sa1es Forecast; and (3) 1-00 percent of the difference
between the Idaho jurisdictional demand response incentive
payments quantified in the Operating Plan and those
quantified in the Company's last approved update of NPSE,
10
11
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13
1,4
15
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17
18
1,9
20
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23
BRADY, DI
Idaho Power
22
Company
24
1- divided by the forecast of Idaho jurisdictional- firm sales
2 for ,June L, 2022, through May 3L, 2023.
3 Q. What is the rate for the forecast portion of
4 the PCA for April 2022 through March 2023?
5 A. The rate for non-PURPA expenses is 0.7L17
6 cents per kilowatt-hour (*kwh"), which is calculated by
7 multiplying $1-17,553,863 from Table 2 by 95 percent and
B then dividing it by the System-leve1 Sales Forecast of
9 15,690,546 MV0h (($117,553,863 * 0.95) / 15,690,546) =
10 $7 .I1.7 /MWh = 0.7L1,7 cents/kWh) . The rate for PURPA
11 expenses is 0.5018 cents per kWh, which is calculated by
1,2 dividing $78,732,189 from Table 2 by the 15,690,546 MWh
l-3 ($78,732,189 / 15,690,546 MVilh : $5.018/MWh : 0.5018
L4 cents/kWh). The rate for demand response incentive
15 payments is a negative 0.0209 cents per kwh, which is
t6 calculated by dividing the negative $3,136,365 from Table 2
17 by the forecast of Idaho jurisdictional firm sales of
18 t4,992,046 MWh (-$3,136,365 / 1-4,992,046 MI/{h = -$0 .209/tmh
19 : -0,0209 cents/kWh) . The forecast portion of the PCA rate
20 is L.L926 cents per kwh, which is calculated by adding the
2t non-PURPA expense of 0.711,7 cents per kWh to the PURPA
22 expense of 0.5018 cents per kWh to the demand response
23 incentive payment of negative 0.0209 cents per kWh (0. 7L1,7
24 + 0.5018 + -0.0209 = 1.1926 cents/kwh).
BRADY,
Idaho
DI
Power
23
Company
1
2
3
4
5
6
7
8
9
0. How did you compute this year's Balancing
Account rate?
A. As shown in Exhibit No. 2, this year's
Balancing Adjustment of the PCA is approximately $38.7
miIlion, whi-ch, when divided by the Company's forecast of
Idaho jurisdictional sales of 14,992,046 MWh, results in a
rate of 0 .2579 cents per kWh ($38, 669,526 / 14,992,046 :
$2.57 9/MWh : A.2579 cenrs/kWn) .
O. What is the resulting PCA rate when you
comblne all the PCA components described previously?
A. The unlform PCA rate comprises (1) the 1,.1,926
cents per kWh for the 2022-2023 projected power cost of
serving firm loads under the current PCA methodology and 95
percent sharing, and (2) the 0.257 9 cents per kWh for the
202L-2022 Balancing Adjustment of the PCA. The sum of these
two components is a 1.4505 cents per kWh charge for all
rate classes.
III. ADDITIONAI, PCA REITE ADiN'STMEIITS
19 A. Revenue Shanr-D.ct
20 O. When was the
originally established?
A. The revenue
revenue sharing mechanism
sharing mechanism was originally
10
11
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13
1,4
15
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1B
21,
22
23 established in Case No. IPC-E-09-30 and approved in Order
24 No. 30978, effective for the years
25 the revenue sharing mechanlsm has
2009-201,1,. S j-nce then,
been modified and
BRADY, DI
Idaho Power
24
Company
l- extended three times.3 Most recently, the revenue sharing
2 mechanism was extended indefinitely, with modifications, in
No. GNR-U-18-01.
a. What are
sharing mechanism?
A. In Case
the provisions of the current revenue
No. GNR-U-18-01, the Company filed a
3
4
5
6
7
B
9
Order No. 34071 in Case
10
motion to approve a settlement stipulation (*2018
Stipulation") extending the sharing mechanism indefinitely,
with modifications. The Commission approved the 20L8
Stipulation in Order No. 3407L.
Per the terms of the 201,8 Stipulation, if the
Company's actual year-end Return on Equity (*ROE") for the
Idaho jurisdiction exceeds 10 percent, all amounts up to
and including a l-0.5 percent ROE will be shared between
customers and the Company on an 80 percent and 20 percent
basis, respectively, to be provided as a rate reduction to
become effective at the time of the subsequent year's PCA.
If the Company's Idaho jurisdictional ROE exceeds 1-0.5
percent, all amounts in excess of 10.5 percent will be
shared 55 percent with Idaho customers as a rate reduction
2L to become effective with the subsequent year's PCA, 25
fdaho customers in the form of22 percent will be shared with
23 an offset to amounts in the Company's pension balancing
20 percent will be apportioned to the Company.24 account, and
11
L2
13
14
15
t6
L7
l-8
1,9
20
BRADY, DI
Idaho Power
25
Company
3 Order Nos. 32424, 33149 and 34071.
1
2
3
4
5
6
7
8
9
With regard
Deferred Investment
to the amortization of Accumulated
Tax
Stipulation
amortization of ADITC,
achieve a maximum 9.4 percent Idaho jurisdictional ROE if
the Company's year-end actual results fa11 below that
amount for any year beginning January 1, 2020. Idaho Power
may use up to $25 million of additional amortization of
ADITC per year, provided the total, cumulative amount of
ADITC does not exceed $45 miIIion. Per the 2018
Sti-pulation, once the Company has fully amortlzed the $45
million of ADITC, revenue sharing will cease; however,
Idaho Power may at any time request to replenish the total
amount of ADfTC it is permitted to amortize, and if
approved by the Commission, revenue sharing would continue.
O. Did the revenue sharing mechanj-sm result in
any action following the 2009-2020 fiscal years?
A. Yes. The Company's earnings in each year from
20Lt through 20L5, as well as 2018, resulted in revenue
sharing with customers totaling $126.2 million, either as a
direct rate offset in the PCA or as an offset to amounts
that would have otherwi-se been collected in rates. The
Company's earnings in 20L6, 20L7, 20L9, and 2020 were below
the revenue sharing threshold. These amounts are detailed
in Table 6 below.
BRADY, DI 26
Idaho Power Company
all-ows the
Credits (*ADITC"), the 2018
Company to accelerate the
in an amount up to $45 mi11ion, to
10
11
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13
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15
t6
1,7
18
19
20
2L
22
23
24
25
Table 6 2W9-2O2O Revenue Sharing
Line No.Revenue Sharing Component 2m9-2011 20L2-20,4 2015-2020
1
2
3
4
5
5
7
Available ADITC For Use
ROE Threshold
5G50 Sharing Threshold
75-25 Sharing Threshold
Customer Benefits (S Millions):
Reduction to Rates
Offset to Pension Balancing Account
S45 Million
9.SVo
los%
N/A
S45 Million
9.SYo
10.0%
to.5%
S45 Million
70.0%
N/A
to.o%
527.L
s20.3
522.8
s47.8
Ss.z
s0.0
8 Total 547.4 s70.5 s8.2 iL26.2
1
2
3
4
5
6
7
I
9
O. Did the Company's year-end 202L financial
resul-ts warrant any actj-on rel-ated to the existing sharing
agreement per the terms of the 2018 Stipulation?
A. Yes. The Company's year-end 202L financial-
results ylelded an actual- Idaho jurisdictj-onal ROE of 10.02
percent, above the 10 percent ROE threshold for revenue
sharing, and thus resulting in a revenue amount to be
shared with customers after tax gross-up of $568,77L.
O. Did the Company use the same methodol-ogy to
determj-ne the Idaho jurlsdictional 2021 year-end ROE that
was used in prlor PCA filings?
A. Yes. The methodology used to determj-ne the
Company's fdaho jurisdictional 2021 year-end ROE is
consistent with the methodology used for the year-end ROE
determinations since the inception of the mechanism.
O. Do you have an exhiblt demonstrating the
application of this methodology?
BRADY, DI 21
Idaho Power Company
10
11
72
13
L4
15
t6
t7
1B
1 A. Yes. Exhibit No. 3 provides a step-by-step
2 calculation of the Idaho jurisdictional ROE based on year-
3 end 2021, financial results utilizing the Commission-
4 approved methodology from previous PCA filings.
5 Q. What is the revenue sharing amount to be
6 included in Lhe 2022-2023 PCA?
7 A. As detailed in Exhibit No. 3, the 2021 Idaho
8 jurisdictional ROE was L0.02 percent. As quantified on line
9 53 of Exhibit No. 3, in 202L, the Company's earnings
10 exceeded an Idaho jurisdictional ROE of 10 percent by
11 $527,962. Per the terms of the 20LA Stipulation, 80 percent
L2 of the $527,962 should be shared with customers as a direct
13 reduction to PCA rates effective June 1, 2022. Applying the
L4 B0 percent sharing provision to the $527,962 yields a
15 customer-allocated sharing amount of $422,369. After tax
t6 gross-up, the revenue sharing amount to be applied to
1-7 customer bilIs is $568,771,.
18 O. How does the Company propose to al-locate the
L9 $568r771 revenue sharing to customer classes?
20 A. The Company proposes to allocate the revenue
21, sharing benefit to customer classes utilizing the same
22 methodology as in past cases, i.e., based on each class's
23 proportional share of forecasted base rate revenues for the
24 upcoming PCA rate effective year, whj-ch in this case is
25 ,June L, 2022, through May 3L, 2023.
BRADY, DI
Idaho Power
28
Company
1
2
3
4
5
6
7
8
9
O. Have you provided an exhibit detailing the
class allocation utilizing this methodology?
A. Yes. Exhibit No. 4 details the class
allocation of the $568,771 revenue sharing benefit. As
j-n column G of Exhibit No. 4, each customer classdisplayed
receives a decrease of approximately 0.05 percent relative
to current base revenues.
O. How does the Company propose to include the
class-all-ocated revenue sharing benefits in rates?
A. Except for the special contracts for Micron
Technology, Inc., the U.S. Department of Energy, and the
,J.R. Simplot Company - Pocatello, Idaho Power proposes to
include the class-a1located revenue sharing benefits on a
cents-per-kWh basis applied to the 2022 PCA rates effective
,June L, 2022, through May 31, 2023. Column F of Exhibit No.
4 contains the rates proposed for inclusion in each class's
PCA rate.
O. What is the Company's proposal for providing
revenue sharing benefits to its special contract customers?
A. Consistent with the methodology used to share
2011-2015 and 20IB revenues, the Company proposes to
provide the special contract customers a flat dolIar-per-
month credit in 1"2 equal portions to serve as a reduction
to monthly invoices billed from June 2022 through NIay 2023.
The total revenue sharing benefit allocated to the special
10
11
1,2
13
1,4
15
16
1-7
18
t9
20
21,
22
23
24
BRADY, DI
Idaho Power
29
Company
25
1
2
3
4
5
6
7
I
9
10
11
L2
13
L4
15
L6
L7
18
19
20
2L
22
23
24
25
contract customers is displayed in column E of Exhibit No.
4.
O. Is the Company's rate design proposal for the
2022 revenue sharing benefits consistent with past-approved
proposals?
A. Yes.
rV. ITET CUSTOMER IMPACE
O. What is the revenue impact of the requested
PCA rate when compared with PCA rates currently in effect?
A. Attachmeat 2 to the Application filed
contemporaneously with my testimony provides a detailed
description of the overall revenue impact of this filing on
each customer c1ass. As shown in Attachment 2, applying
the requested PCA rates to expected customer sales for the
June 2022 through May 2023 test year results in a PCA
i-ncrease of $103.4 mi1lion.
A. Given the magnitude of the increase for the
2022-2023 PCA, did the Company consider proposing any rate
mitigation options?
A. Yes. Gi-ven the magnitude of the 2022-2023 PCA
increase, I consulted with management to determj-ne what
mitigation, if any, the Company should include in this
year's PCA filing.
O. Eollowing these discussions, is the Company
proposing to include any rate mitigation in this filing?
BRADY, DI 30
Idaho Power Company
1 A. No. After careful- consideration, I was advised
2 by management to not propose any rate mitigation measures
3 in this case. However, the Company is open to rate
4 mitigation measures if the Commission deems them
5 appropriate.
6 Q. Why is the Company not proposing any rate
7 mitigation in this case?
I A. Eirst, the Company believes that customer
9 interests are generally best served by matching cost
10 recovery as closely as possible with the period in which
11 power supply costs are incurred. Additionally, mitigating
t2 rate impacts by spreading recovery over multiple years
13 creates the possibility that the deferred collection will
L4 result in "rate pancaki-ng" with potential future rate
15 increases, essentially deferring an increase in the current
16 year to create an even larger increase in the future. The
1,7 Company also considered prior Commission orders with regard
18 to rate mitigation measures in the PCA. In orders from the
l-9 2008, 2009, 20L3, and 2020 PCA casesa in which rate
20 mitigation was discussed, the Commission declined to adopt
2L any rate mitigation measures, primarily for the same
22 concerns surrounding rate pancaking, appropriate matching
23 of costs and recovery, and the overall intent of the PCA
24 mechani-sm.
BRADY,
Idaho
DI
Power
31
Company
a Order Nos. 30563, 30828, 32821-, and 34682
1
2
3
4
5
6
7
I
9
O. Would Idaho Power be amenable to j-mplementing
rate mitigation measures for the 2022-2023 PCA if the
Commission determines such measures are appropriate?
A. Yes. While both Idaho Power and the Commission
have expressed concerns with rate mitigation measures in
the past, the Company would be amenable to discussing such
measures in the current filing. A two-year recovery period,
for example, would reduce the rate impact from the proposed
$103.4 miIlion, or 8.27 percent increase, to an approximate
$50 mi11ion, or slightly more than 4 percent, annual
increase in collection spread over two years.
L0
11
L2
l-3 includes
L4
l_5
l_6
L7
18
19
20
21,
22
23
24
a . Have you prepared a
the proposed PCA rates?
. Yes. Attachment 1
revised Schedule 55 that
to the Application is a
revised Schedule 55 and includes the proposed PCA rates in
clean and legislative formats.
0. Shou1d the Commission approve the Company's
computation of the PCA rates?
A. Yes. The Commission should approve the
Company's computation of the PCA rates. The calculation of
the PCA rates follows the methodology that was approved in
Order Nos. 30715, 33307, and 34071. If approved, luh,e 2022-
2023 PCA will result i-n an increase in total billed revenue
of approximately $103.4 mi11ion, or 8.27 percent.
\\
A
BRADY,
Idaho
DI
Power
32
Company
25
1
2
3
4
5
6
7
8
9
o.
A.
Does this conclude your testimony?
Yes, it does.
10
11
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22
23
24
BRADY, DI 33
Idaho Power Company
25
]- DECI.ERAITION OF {'ESSICA C. BRADT
2 I, .fessica G. Brady, declare under penalty of
3 perjury under the laws of the state of Idaho:
4 L. My name is Jessica G. Brady. I am employed
5 by Idaho Power Company as a Regulatory Analyst in the
6 Regulatory Affairs Department.
7 2. On behalf of Idaho Power, I present this
8 pre-fi1ed direct testimony and Exhibit Nos. 1-4 in this
9 matter.
10 3. To the best of my knowledge, my pre-fiIed
1-1 direct testimony and exhibits are true and accurate.
L2 I hereby declare that the above statement is true to
l-3 the best of my knowledge and belief, and that I understand
L4 it is made for use as evidence before the Idaho Public
15 Utilities Commission and j-s subject to penalty for perjury.
L6 SIGNED this 15th day of April 2022, dt Boise, Idaho.
L7 w^r
18 Signed:
BRADY, DI 34
Idaho Power Company
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Calo No. IPC€-22-11
J. Brady, IPC
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C@ No. IPC€-22-1t
J. BEdy, IPCP.!E 1 ol2
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J. &!dy, lrc
P.g,B2d2
IDAHO POWERCO,IIPANY
ADDITIONAL INVESTIIENT TAX CREDIT ANALYSIS
Fortt6 Twolyo tonths Endod lrscombp,t?1,20.21
Adrd$tubt rr{Mrllt.,ibtl h2l
EAU9.:b
TOTAL
SYSTEM IDAHO
3,552,703,864
IDAHO *
96.076%
TOTAL
sYsTEM tDAlg
S.ptembrr All6tlon6rRati6ro@
ti12ry
" OPEilTING RMNUES
t. RETALruS RffiNUES (ld *.1 R.v)
15 OTHEROPEMNNOREWNUES
I' TOTA OPEilTING RffiNUES
17
I' OPERANre WENSES
19 OPEilNON E MNreWCE UPENSES
D EPRECATION ffENSE
2! MRTBTION S LIMIED ERf Plff
2 TUESOTHERTNINCOME
A REGUUTORY DBtrSREDITS
2' PROUSION FOR DEFERREO Iil@ME IreS
6 IMSTUEM Tff CREOIT BUSilEI
A FEOEM INCflE TreS
27 STATE INCOME TffiS
6 TOTATOPEUNtrGEPENSES
a
$ OPEilNre INCilE
!1 &0: IERCO OPEMTING INGOME
i
$ OPEMNNGINCOME BEFMEOTHERINCOMEANODEOUCTIONI
a
^DD:trUOC
EOulry
s rcD:OfrER lrc4E&D mDUCTIoNS
974.391.28:'
143,588.027
1,1 17,979,310
51a7@,74 Dire.i Asbn
136,940,469 95.4%
1.(r9,650.202
1,198,904,622 Dkod A$ien
'189,896,371 95.4%
1 .388.630,903
't,252,*3,142
199,1 14.549
1,452,017,631
3.697,810.735
217,377,59 240,197,319
6E3,260,685
123,5n.643
6.256,m0
26,188.106
1,087,3S t
(14,885,903)
't'1.?64,544
29, I 56,558
11,4't 1,459
877,316,39r
649,645,4S
118,717,524
6,013.901
24,462,6U
878,35
(14.382,662)
10,a24,447
24,544,231
11.163.398
835.867,704
95.1%
96 1%
96.1%
93.4%
80.8%
96.696
96. t96
97.9%
97.8%
95.5%
917,571.975
165,4{6.697
8,,195,466
30,947,260
1,197,775
(21,55S,910)
11,83eE97
35,047,688
13,298,956
1,162,578,m3
672,4X,@O
1 58.9/m.333
8.166,702
28.908,278
1.209,905
(20,83O,S19)
1 1,370,59ti
34,3't 1,639
13.009,865
1,107,515,477
95.'r %
96. t%
93.4%
80.E*
96.6%
96. t%
97.9%
97.8%
INCilE BEFORE IMEREST CffiGES
LESS: INTERESTcffiOES
240,662,916
6,715,053
233,79l1*
6,414,821
289,438.88a
8,991,347
281,315,516
8,589,341 95.5%
96.1% (L 10)
237,275,6*
96.1% (LlO)
'to.c8r
Exhibit No. 3
Case No. IPC-E-22-11
J. Brady, IPC
Page 1 of 1
298,430,236
31,537,344
343.755
289,904,857
30.299.778
333.934
97.1%
96.1% (L 10)
97.1% (L 33)
430,31 1,334
86,853,666
3m,538,570
43,x2,472
$
!7
$
T
a1
a
6
6
s
tt
s
$
g
$
t
a7
I
T
o
at
@
6
g
6
i
a
6
o
rc
71
n
D
NET INCOME 243,647,668
9.89%
ACru[ Yffi{ND RESULTS . BEFORE TC DUSilEM
*NINGON COMMON ST&X
COMTd EOUIWAT ff ENO
2,r3,647,668
2,M,724.26
237,275,698
2.368.m5.322
REruRil ON ff+ilO CilMON EOUIry
234.1{8,807
246,472,4n
258.7$.050
U.W.,fi (Lr{z{'9.4%)
ztc,to,sl2 (Lr[4 ' 10%)
2i|.,OO.5$ (1,{,{ ' 10.5%)
ACTW ff{NO RESULTS - mR rC 0USTmmi
IMSTUENT TA CREDIT UUSruENT
msTEo ffiNtxGoN @mm slex
DUSTED COUMON EOUIW ATff{NO
ADJUSED RETURN OT ff{NO COUMON EOUIil
(16,206,620) (14&143) / (1-9.4%)
221,069,078
2.35 t ,798.702
rF IDAHO RETURN ON COMMOII EOUIrY (Un. {6) <e.a9a
ILg bUfr, hOi ilFtu.htrlbrdLgdl6,m,m 0
lF IOAHO RElURll Ol{ COilMOt{ EOulrY (un.46l >loL
IDffiOWNINOSGRATERflN 1095 NOEBW LESSTMN lOS 527,96A (143149y(1-10%)
lF IDAHO RETURN Oil COlrtilON EqUITY (Un. /lc) >lo.Sa
INCREMENTIIDSO ffiNING GRAER ]il IO,SROE 0 (14+L50y(1-10.596)
Pd Ofl,.r t34o7l :
ROE tu 1610.5I4USTilER SffiE-& Ed6nb nh)
ROE tu t&to.s{oMPNY SffiE-ffi
RoEgmrhnlo.*(Iffi)-CUSTOMERSffiE-S*(Rffinbra!)
ROE gdrss 10.6$(llmmdl)-CUSTOMER SURE -5% (ffib P.lffi bhno)
ROE Fdrhn 10.5* (llffi){wPAW sffi E - ffi
12.,@
105,59a
0
0
0
527,52
Tu G@ Up
56E,z,l
ffixtNG oN coMMoN s@K o e{ RoE
ffiNrNS ON COMMON STmKO t0 ROE
PEparod by: K6lley N@
ReviMd by:
ldaho Power Company
C.lqrhtbn of Revenue lmpact
Class Allocated Revenue Sharlng 2022-2023
State of ldaho
Filed Aprll lt 2022
(A)(B)(c)(D)(E)
Percentageof Allocated
ldaho Base Revenue Sharing
Revenues Benefit
(F)(c)
Line
No
Rate
Sch.
No,
Average
Number of
Customers
Normalized Energy
(kwh)
Current Base
Revenue
Dollars per
kwh Rate
Percent
Revenue
changeTariff Descriotion
Uniform Tariff Rates:
I Residential Service
2 Master Metered Mobile Home Park
3 Residential Service Energy Watch
4 ResidentialServiceTime-of-Day
5 Residential Service On-Site Generation5 Small GeneralService7 Small General Service On-Site Generation8 Large General Service - Secondary9 Large General Service - Primary10 Large General Service - Transmission
11 Duskto Dawn LiShting
12 Lar8e Power Service - Secondary
13 Large Power Service - Primary
14 Large Power Service - Transmission
15 Agricultural lrrigation Service
15 Unmetered General Service17 Street Lighting
18 Traffic Control tighting
19 Total Uniform Tariffs
1
3
4
5
6
7
8
9S
9P
9T
15
195
19P
197
24
40
4r
42
490,293
21
0
988
72,024
30,3t18
80
37,535
280
4
0
0
Lr4
2
19,120
1,563
2,980
766
5,458,972,074
4,52t,955
0
L7,662,33I
55,895,664
L37,395,7t5
190,425
33M,L76,U0
592,994,508
3,557,L43
5,267,423
0
2,358,498,546
32,893,530
L,897,5L7,Lt9
13,925,301
2?,760,0t4
2,U7,96r
494,239,s46
38&104
0
1,530,838
6,387,494
r5,753,365
24,755
225,029,0U
35,347,188
240,2N
L,234,927
0
!2L,99L,234
1,601,499
140,388,800
L,t24,204
3,409,701
L6Z,7U
45.079(,
0.04%
0.00%
o.t4%
0.s8%
t.44%
0.0096
2o.52%
3.22%
0.02%
o.7L%
0.0096
tL.7Z%
0.15%
L2.n%
0.10%
0.31%
0.01%
(Szg+)
(S3,os7)
(58,171)
(Srr1
(Su5,704)
(518,332)
(Srzs1
(9543)
(563,257)
(s831)
(S72,8081
(Ssea1
(s1,768)
($al1
(0.00004s)
(0.000047)
(0.(xrc0s9)
(0.0000s9)
(0.00003s)
(0.000031)
(0.00003s)
(0.m0u2)
(0.000035)
(0.000027)
(0.00002s)
(0.0000381
(0.(xxm42l
(0.000074)
(0.000030)
(0.0s)%
(0.0s)%
0.00%
(0.0s)%
(0.0s)%
(0.0s)%
(0.0s)%
(0.0s)%
(0.05)%
(0.0s1%
(0.0s)%
0.0096
(0.0s)%
(0.0s)%
(0.0s)%
(0.0s)%
(0.0s)%
(0.0s)%
(s2s5,s3s) (0.000047)
(s2ou (o.oooo4s)
20 Total Special Contracts
21 Total ldaho Retail Sales
Note:
(1) June 01, 2OZZ - May 3L,7023 Forecasted Test Year (Spring 2022 Forecast)
(2) 19S rate in column (F) set to match 95 rate due to sinSle customer movement between classes,
s95,318
3
596,32r
13,920,071,569
7,O7L,974,663
L4,992,0r',6,332
S1,048,8s1,023
S47,8s0,839
s1,095,701,852
95.64%
4.36%
100.00%
(ss43,9ss)
(S24,815)
(Ss58,77U
(0.0s)%
(0.0s)%
(0,0s)%
Exhibit No.4
Cass No. IPC-E-22-1 I
Paqs 1 of 1