20210415Blackwell Direct.pdf

BETORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF TTIE APPLICATION
OT IDAI{O POIIER COMPANY FOR
AUTITORITY TO IMPLEMENT POWER
COST ADJUSTIIEN! ('.PCA") RATES
rOR ELECTRIC SERVICE TROM JUNEL, 202L, TIIROUGH MAY 31, 2022.
IDAHO POWER COMPANY
Df,RECT TESTIMONY
OF
NICOLE A. BLACIffiELL
CASE NO. rPC-E-21_-10
1 Q. Please state your name, business address, and
2 present position with Idaho Power Company ("Idaho Power" or
3 "Company").
4 A. My name is Nicole A. Blackwell. My business
5 address is 122L West Idaho Street, Boise, Idaho 83702. T
6 am employed by ldaho Power as a Regulatory Consultant in
7 the Regulatory Affai-rs Department.
8 Q. Please describe your educational background.
9 A. In May of 20L0, I received Bachelor of Science
10 degrees in Finance and Economics from the University of
11 ldaho. I have also attended "The Basics: Practical
!2 Regulatory Training for the Electric Industry, " an electric
13 utility ratemaking course offered through New Mexico State
1,4 University's Center for Public Util-ities, "E1ectric Utility
15 Fundamentals & Insightsr" an electric utility course
t6 offered through the Western Energy Institute, and Edison
L7 Electric Institute's "Electric Rates Advanced Course."
l-8 O. Please describe your work experience with
19 Idaho Power.
20 A. In January 20t6, I was hired as a Regulatory
2L Analyst in Idaho Power's Regulatory Affairs Department, and
22 in 2021- I was promoted to my current posj-tion of Regulatory
23 Consultant. As a Regulatory Consultant, I provide support
24 for the Company's regulatory activities, including
25 compliance reporting, financial analysis, and the
BLACKWELL, DI 1
Idaho Power Company
l- development of revenue forecasts for regulatory filings.
2 Q. Vihat is the Company requesting in this case?
3 A. The Company j-s requesting approval- of its
4 2021,-2022 Power Cost Adjustment ("PCA") rates to become
5 effective June I, 2021. If approved, the 2021,-2022 PCA
6 will result i-n an increase in total billed revenue of
7 approximately $39.1 milIion, or 3.36 percent.
8 Q. How is your testimony organized?
9 A. My testimony consists of four sections. In the
10 first section, I provide an overvj-ew of the PCA. In the
11 second section, I detail the 2021,-2022 PCA amount in
12 comparison to last year's PCA amount, identify and discuss
13 the main factors contrj-buting to this change, and present
1,4 the quantification of th,e 2021-2022 PCA rates to become
L5 effective June I, 2021. In the third section, I will
t6 discuss the additional PCA component related to revenue
sectJ-on, I detail the net customer1,7 sharJ-ng.
impact of
In the final
the 2021-2022 PCA rates if approved as filedr.8
19
20
21,
22
I.
O. What is the
the mechanism functi-on?
A. The PCA is a
PCA OVER\IIETT
purpose of the PCA and how does
rate mechanism that quantifies
23 and tracks annual differences between actual Net Power
24 Supply Expenses (*NPSE") and the normalized or "base 1eveI"
25 of NPSE recovered in the Company's base rates, resulting in
BLACKWELL, DI 2
Idaho Power Company
l- a credit or surcharge that is updated annually on ,June 1.
2 The PCA mechanism uses a 12-month test period of April
3 through March ("PCA Year") and includes a forecast
4 component and a True-up component ("True-up"). The
5 forecast component represents the difference between the
6 Company's NPSE forecast from the March Operating Plan and
7 base level NPSE recovered in the Company's base rates. The
I True-up component includes a backward-looking tracking of
9 differences between the prior PCA year's forecast and
10 actual NPSE incurred by the Company. The True-up contains
11 a second component that tracks the col-lection of the prior
12 year's True-up amount, referred to as the "True-up of the
13 True-up. "
14 With the exception of Public Utility Regulatory
15 Policies Act of L97B (*PURPA") expenses and demand response
16 incentive payments, the PCA allows the Company to pass
L7 through to customers 95 percent of the annual- differences
18 in actual NPSE as compared with base 1eve1 NPSE, whether
19 positive or negative. With respect to PURPA expenses and
20 demand response incentive payments, as actual annual
2l expenses deviate from base level NPSE, the Company is
22 allowed to pass 100 percent of the difference for recovery
23 or credit through the PCA. The PCA is also the rate
24 mechanism used by the Company to provide customer benefits
25 resulting from the revenue sharing mechanism approved by
BLACKWELL, DI 3
Idaho Power Company
2
3
4
5
6
7
8
9
1 the Idaho Public Utilities Commission ("Commission") in
11
Order No. 3407L.
O. Does the revenue collected from customers
through the annual PCA rate contribute toward the Company's
net .income?
A. No. The PCA mechanism provides for the annual
collection or refund of net power supply cost differences
between actual costs incurred by the Company and the base
level NPSE component of base rates. Aside from the 95
percent to 5 percent sharing component I just described,
the PCA provides for a one-for-one collection or refund of
1,2 actual net power supply expenses incurredr or to be
to provide safe, reliable electric service tol-3 incurred,
15
customers.
O. What are the components of the PCA base leve1
NPSE?
A. The PCA base level NPSE includes the following
FERC accounts: Account 501, Fuel (coal); Account 536,
Water for Power; Account 547, Euel (gas); Account 555,
Purchased Power; Account 565, Transmission of Electricity
by Others; and Account 447, Sales for Resale (t1pica11y
referred to as surplus sales).
The PCA base level- expense component for FERC
Account 555 includes costs of both PURPA and non-PURPA
(market) purchases. Per Order No. 32426, the Company
1,6
1,7
1B
19
20
2L
22
l_0
1,4
23
24
BLACKWELL, DI 4
Idaho Power Company
25
1
2
3
4
5
6
7
I
9
adjusts FERC Account 555 to also include demand
j-ncentive payments
who participate in
programs.
that the Company provides to
response
customers
10
any of its three demand response
:tI. 202L-2022 PC,A
O. What is the total PCA collection that would
result under the 2021,-2022 PCA rates proposed by the
Company in this case?
A. The 2021-2022 PCA rates would result in total
PCA coll-ection of $109.3 mil1ion. This represents an
increase in total bilIed revenue of $39.1 million for the
upcoming year, an increase of 3.36 percent.
O. Have you prepared a table that details the
$39.1- million revenue impact by component?
A. Yes. Table 1- presents a separation of the
BLACKWELL, DI 5
Idaho Power Company
11
T2
13
1,4
15
1,6 $39.1- million j-ncrease into each component included in the
L7 Company's proposed rates.
1B
1
2
3
4
5
5
7
I
9
Table I Revenue lmpact by Component
Line No. Rate Component 202G2021PCAI 2021-2022PCA2 Difference
1
2
3
PCA Forecast
PCA True-up
s 113,084,63s
5(42,892,181)
s L26,944,108
s (17,641,9s4)
S 13,8s9,473
5 2s,2s0,227
PCATotal g 70,192,45s S 1o9,3oa$4 $ 39,1@,700
0. What are the maln factors driving the revenue
change requested in this case?
A. The increase in this year' s PCA is primarily
attributed to a smaller credit to customers through the
true-up component. This year's PCA true-up reflects a
credit to customers of approximately $17.6 milIion, which
is $25.3 mi-Ilion, or 59 percent, less than Last year's PCA
true-up credit of $42.9 million. This year's lower true-up
credit balance demonstrates that actual- power supply costs
for the 2020-2021, PCA Year were more in line with forecast
power supply costs included in last year's PCA forecast
than the forecast-to-actuals variance from the 20L9-2020
PCA Year. As a result, the true-up credit is smaller than
last year and is drj-ving an increase in the PCA.
1 Because Table 1 contains the expected b1IIed revenue impact to
customers, the *2020-2021 PCA" column reflects approved 2020-2021 PCArates applied to the June 2021 through May 2022 sales forecast, and
will not tie to the specific dol-l-ar amounts approved in the 2020 PCA
filing.
2 The *2Q27-2022 PCA" column reflects the Company's proposed rates
applied to the June 202L through Vlay 2022 forecast, and may not tj-e
exactly to the figures listed in the Company's testimony due to the
rounding of rates to six digits.
BLACKWELL, DI 6
Idaho Power Company
10
11
1-2
13
14
15
L6
1 The increase in this year's PCA forecast component
2 is attributed to lower expected hydro qeneration and higher
3 market energy prices, which are resulting in increased
4 reliance on thermal generation and decreased market power
5 purchases. Additionally, this year's PCA forecast reflects
6 higher PURPA expense. These drivers will be discussed in
7 detail later in testimony.
I A. PCA Forecast.
0 How is the PCA forecast amount determined?9
10
11
t2
13
1-4
15
16
L7
18
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20
2t
22
A. As described previously, the PCA forecast
component represents the difference between the Company's
forecast of NPSE for the upcoming April - March test year
and base 1evel NPSE recovered in the Company's base rates.
O. What is the Company's determination of the
system-1evel difference between currently approved base
leve1 NPSE3 and the forecast of NPSE for the 202L-2022 PCA
Year?
A. The system-leve1 forecast of NPSE for the
202L-2022 PCA Year is $442t357,407, which is $136,672,538
higher than the currently approved base level NPSE of
$305,684,859. Table 2 presents the system-Ieve1
differences between currently approved base level NPSE and
the forecast of NPSE for the 202L-2022 PCA Year by FERC
s fn the Matter of the Application of Idaho Power Company forAuthority to Establish a New Base Level- of Net Power Supply Expense,
Case No. IPC-E-13-20, Order No. 33000 (March 21, 2074) .
BLACKWELL, DI 7
Idaho Power Company
23
1 account.
a What is the basis for the forecast of NPSE for
the 202L-2022 PCA Year?
A The forecast of NPSE for the 2027-2022 PCA
Year is based on the Company's March 25, 2021, Operating
Plan.
a. 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 monthly NPSE for the
following 18-month period; however, for the PCA, the
Company includes only the 12 months that correspond to the
PCA Year. The Operating PIan is developed by simulating
the dispatch of the Company's generation resources for each
month, segmented by heavy Ioad and Iight load hours. The
dispatch considers a current forecast of forward market
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3
4
5
6
7
B
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10
11
L2
l_3
L4
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L6
BLACKWELL, DI 8
Idaho Power Company
Table 2 2021-2022 PCA FORECAST (Tota! System)
Line No.Base NPSE Forecast DifferenceFERC Account
1
2
3
4
5
5
95% Sharine 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 t147, Surplus Sales
S 108,503,180
S 2,380,597
S 33,3G7,5G3
S 62,606,593
S 5,455,955
S (s1,73s,1s3)
s 118,562,796 ss os
S 57,235,044 SS 748oo,s3o Ss 4853,909 s
S Qs,842,22s1 S
10,059,616
(2,380,597)
23,857,48t
L2,t93,937
(502,046)
25,892,928
7
8
100% Sharing Accounts
Account 555, PURPA S
Account 555, Demand Resoonse lncentives S
133,853,869
7L.2s2.26s
S 205,133,741 SS 7.613.612 S
71,279,872
(3.638.5s3)
5 L60,s78/3s S 229,610,0s4 S Sg,O3r,arg
9 Total s 30s.684.859 s 442.3s7.407 s 136.672.s38
L7
1 energy prices, available hydro generation, coal and natural
2 gas prices, and any existing hedge transactions. The
3 system load forecast is then analyzed against the resulting
4 monthly heavy load and light load dispatch to determine a
5 monthly load and resource balance. Any identified resource
6 deficiency is assumed to be filled with market energy
7 purchases or natural gas to fuel the Langley Gulch power
8 plant ("Lang1ey Gulch"), based on economics and availabl-e
9 generating capacity at Langley Gulch. Economically
10 dispatched generation above the system load forecast
11 represents surplus energy sa1es. The forecast of monthly
L2 NPSE and generation for the 202t-2022 PCA Year, as
13 determined in the Company's March 25, 2021,, Operating P1an,
1,4 is provided in Exhibit No. 1 .
15 O. How does the Company's forecast of system-
t6 level NPSE for the 2021,-2022 PCA compare to the system-
L7 leve1 forecast included in last year's PCA?
18 A. Table 3 compares this year's 2021,-2022 PCA
1,9 forecast of NPSE to last year's PCA forecast by FERC
20 account. As detailed in this table, the PCA forecast on a
L}:e 202L-2022 PCA Year is2tfor
22
total system basis
$442,357,407 , which
forecast amount of
is $1-5,452 ,686 higher than last year's
$426, 904 ,7 2L .
BLACKWELL, DI 9
Idaho Power Company
23
Tabh 3 PCA Forecast Comparison Expenses (Total Systeml
Line No.
2020-202t
Forecast
202,'-2022
ForecastFERC Account Difference
1
2
3
4
5
6
95% Sharine Accounts
Account 501, Coal
Account 535, Water for Power S
Account547, Other Fuel S
Account 555, Purchased Power Non-PURPA S
Account 565, 3rd Party Transmission S
Account 447, Surplus Sales S
s 102,s34012 s t78,s62,796 5 L6,028,783
1,500,000 s
42,599,258 s
99,849,920 s
5,058,450 s
(16,076,860) s
0s
57,235,044 s
74800,530 s
4853,909 s
Qs,842,2251 s
(1,500,000)
L4,535,776
(15,049,389)
(2O4,54tl.
(9,75s,36s)
7
8
100% Sharine Accounts
Account 555, PURPA
Account 555, Demand Response lncentives
s 225,464,790 s 229,510,054 5 4,145,264
s 193,826,319 5 205,L33,74L 5 77,307,422
s 7.513,612 s 7,6L3,5L2 s
9 Total PCA Forecast
s 201,439,93L s 2L2,747,353 s t7,3O7,422
5 426,9o4,72L S M2,357,4o7 S rs,+sz,sgsl_
2
3
4
5
6
7
8
9
a. What general conclusions can be drawn from the
information contained in Table 3?
A. When viewed by category, the 95 percent
sharing accounts have increased approximately $4.1 mil-lion
from last year's forecast, while the 100 percent sharing
accounts have increased approximately $11-.3 million over
last year's forecast.
O. What factors are contributing to the major
differences presented in Tab1e 3?
A. Forecast expenses included in the 95 percent
sharing accounts are expected to increase by 2 percent as
compared to last year, from $225,464t'790 to $229,610,054.
Due to a reduction in forecast hydro generation and higher
forecast market energy prices, the Company expects to rely
BLACKWELL, DI 10
Idaho Power Company
10
11
L2
13
1,4
15
1 more on thermal- generation to serve load and is expected to
2 decrease market power purchases.
3 Q. Please elaborate on the changes in the 95
4 percent sharing accounts for this year's forecast as
5 compared with last year's forecast.
6 A. In addition to lower forecast hydro
7 generati-on, which will be discussed in detail later, higher
8 forecast market energy prices are contributing to increased
9 generation at the Company's thermal plants. For Lhe 2021-
10 2022 PCA Year, forward market prices range from a 1ow of
11 10.35 per MWh to a high of $78.80 per MV0h compared to a Iow
12 of $4.85 per MWh and a high of $45.85 per MWh for last
13 year's PCA. As a result of higher market energy pri-ces,
t4 thermal- generation becomes more economic, wherein the
15 average per-uni-t costs of natural gas and coal-fired
15 generation are $24.45 per MWh and $32.94 per MIatrh,
t7 respectively. Accordingly, natural gas expense is expected
18 to increase 34 percent as compared to last year's forecast,
1,9 from $42,599,268 to $57,235,044, and coal fuel expense is
20 expected to increase 16 percent, from $102,534,012 to
2t $118,562,796.
22 The increase in forecast market energy prices is
23 also causing a $15r049,389 decrease in non-PURPA purchased
24 power, a 17 percent decrease from last year's forecast.
includes market power
BLACKWELL, DI 11
Idaho Power Company
25 Non-PURPA purchased power expense
L purchases, as well as power purchase agreements ("PPAs").
2 The decrease in forecast non-PURPA purchased power is
3 primarily related to market power purchases, whj-ch are
4 expected to decrease from $41,404,265 in last year's PCA
5 forecast to $24,654,472 in this year's PCA forecast, a 40
6 percent decrease.
7 The reduction in forecast hydro generation is also
I resulting in lower surplus sales volumes. However, as a
9 result of higher market energy prices, surplus sales
l-0 revenue is expected to increase 61 percent compared to last
11 year, from $L6,076,860 to 525,842,225. Eor the 2021,-2022
12 PCA Year, the average forecast market sales price is $34.25
13 per MWh compared with $15.14 last year, a 126 percent
L4 i-ncrease.
15 Finally, this year's PCA forecast does not include
L6 water lease expense whereas last year's PCA forecast
1,7 included $1.S mil-l-ion in water lease expense. The Company
18 does not anticipate procuring a water lease for this PCA
L9 Year due to weaker snowpack conditions in the Upper Snake
20 basin and the decreased availability of water.
2l O. What factors are contributing to the change in
22 the 100 percent sharing accounts?
23 A. Forecast expenses included in the 100 percent
24 sharing accounts are expected to increase by 6 percent as
25 compared to last year, from $201,439,931 to $21,2,747,353.
BLACKWELL, DI T2
Idaho Power Company
1 With regard to the 100 percent sharing accounts, forecast
2 PURPA costs increased by $11.3 million as compared to Iast
3 year's forecast, while forecast demand response incentive
4 payments did not change.
5 Q. Is the increase in forecast PURPA costs
6 related to increased generation output from PURPA projects?
7 A. In part. Table 4 details changes between last
8 year's PCA forecast and this year's PCA forecast with
9 respect to forecasted generation in MWh. As shown in Table
10 4, PURPA generation is anticipated to increase by 51r350
11 MWh, or less than 2 percent. The 6 percent increase in
12 PURPA expense is largely the result of price escalation in
13 PURPA contracts, whereby the average cost is $67.75 per
L4 MWh.
Table 4 PCA Forecast Comparison Generation ffotal System-Mwh)
Line No.FERC Account
202G202t
Forecast
202,-2022
Forecast Dlfference
1
2
3
4
Hydro 7,34L,7L7 6,590,890 (650,827)
95% Sharing Accounts
Account 501, Coal
Account 547, Other Fuel
Account 555, Purchased Power Non-PURPA
2,972,154
1,973,546
2.@5,454
3,s99,2L9
2,34O,994
L.478.696
627,064
367,448
(616.758)
5
95% Sharing Accounts 74,382,811. 1.4,L09,799 (273,072l.
1fi)% Sharing Accounts
Account 555, PURPA 2,976,554 3,027,905 51,3s0
6
1fi)% Accounts 2,976,554 3,027,905 51,350
(221.,72t!,Total Generation L7,359,425 L7,L37,704
7
95% Sharine Accounts
Account 447, Surplus Sales L,O62,077 754,975 (307,102)
8 Total Load L6.297.348 L6.382.729 85,381
BLACKWELL, DI 13
Idaho Power Company
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1 Q. What other general conclusions can be drawn
2 from the information in Tab1e 4?
3 A. Compared to last year's forecast, hydro
4 generation is expected to decrease 5501 827 MWh, or 9
5 percent. The decrease in hydro generation j-s driving a
5 decrease in surplus sales volumes of 30711-02 MWh, or 29
7 percent. As discussed previously, the decrease in forecast
B hydro generation is also resulting in an increase in
9 thermal generation. Coal-fired generation is project.ed to
l-0 increase 621,054 MWh compared to last year, or 21 percent,
11 while natural gas generation is expected to increase
L2 3671448 MWh, or l-9 percent, compared to l-ast year.
l-3 Additionally, non-PURPA purchased power is expected to
L4 decrease by 6161758 MWh, or 29 percent. As discussed
1-5 earlier, higher forward market prices are contributing to
L6 increased economic dispatch of the Company's thermal plants
L7 for load service and reducing market power purchases.
18 a. What is causj-ng the decrease in expected hydro
19 generation of 650,827 MWh?
20 A. The decrease in expected hydro generation is
2! mainly due to lower projected inflows into Brownlee
22 reservoir. The March Operating Plan used in this year's
23 PCA forecast projects April through July inflows into
24 Brownlee of 4.2 million acre-feet ("MAE") as compared to
25 4.6 MAF used to determine last year's PCA forecast, a
BLACKWELL, DI 1,4
Idaho Power Company
1 decrease of 9 percent. Expected lnflows into Brownlee were
2 higher for last year's PCA forecast as a result of better
3 snowpack conditions, which provide for sustained runoff and
4 increased hydro generation durj-ng the spring and summer
5 months.
5 Additionally, this year's PCA forecast reflects
7 weaker reservoir storage conditions, as compared to last
B year's forecast. The March Operating Plan used in this
9 year's PCA demonstrates that available storage in the 11
10 reservoirs above Brownl-ee is 1-13 percent of normal and at
11 75 percent of capacity, compared to last year's 2020 March
12 Operating P1an, in which storage was 125 percent of normal
13 and at 82 percent of capacity. Together weaker snowpack
t4 conditions and carryover as compared to the prior year are
15 resulting in the 9 percent reduction in forecast hydro
16 generation for the 2027-2022 PCA Year.
1,7 O. How are the forecasted NPSE differences
18 presented in Table 2 used to determine the 2021-2022 PCA
1,9 forecast component to be collected from Idaho customers?
20 A. The 202L-2022 PCA forecast component reflects
27 the Idaho jurisdictional share of the forecasted NPSE
22 differences presented in Table 2, adjusted for the PCA
23 sharing provisions. The Idaho jurisdictional share of the
24 forecast NPSE differences is determined by applying a ratio
25 of forecast firm Idaho jurlsdictional sales to forecast
BLACKWELL, DI 15
Idaho Power Company
t-
2
3
4
5
6
't
I
9
fj-rm system-Ievel sales to the system-Ieve1 NPSE
differences.
l-0
O. $Ihat is
firm sales and Idaho
2O2L-2022 PCA Year?
A. For the
forecast system-leve1
Idaho jurisdictional
95.41 percent of the
A. What is
the Company's forecast of system-level
jurisdictional firm sales for the
2021-2022 PCA Year, Idaho Power has
firm sales to be 15,131,418 Mlllh and
firm sales to be 1,4,436,951 MWh, or
system leveI.
the Company's determination of the
11 202L-2022 PCA forecast component to be coll-ected from ldaho
L2 customers?
13 A. Th,e 2021-2022 PCA forecast component to be
L4 collected from Idaho customers is $126,939,705. Table 5
15 presents the determination of the 202L-2022 PCA forecast
1,6 component by individual PCA expense and revenue category.
BLACKWELL, DI 76
Idaho Power Company
1
Table 5 2021-2022 PCA FORECAST
Line No.FERC Account
Difference from Difference After
Base Sharing ldaho Allocation
1
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 1147, Surplus Sales
(From Table 1)
S 10,059,G1G S
s (2,380,597) s
S 23,867,481 S
S 12,193,937 Ss (602,046) ss 2s,892,928 s
9,555,635
12,26t,5671
22,674,L07
LL,584,240
157L,944!,
24,598,282
9,7L8,026
(2,L57,7711
27,633,463
Ll,052,574
(545,594)
23,469,327
s
s
s
s
s
s
7
8
100% Sharine Accounts
Account 555, PURPA S
Account 555, Demand Response lncentives S
s 69,031,319 s 65,579,753 5 62,569,925
68,008,433
(3,638,6s3)
71,279,872 s
(3,538,5s3) s
7!,279,872 5
(3,638,5s3) s
9 Total s 136.672.s38 s L33,220.972 s 126.939.7052
3
4
5
6
1
B
9
B. |rrue-up and Erue-up of the trrue-up.
a. What is this year's quantification of the
True-up?
A. The True-up portion of the PCA is detailed in
the deferral expense report, attached hereto as Exhibit No.
2. This report compares actual NPSE amounts to actual
power cost col-lections monthly, with the differences
accumulated as a deferral balance. The balance at the end
11 of March 202L, with interest
10
as shown on row
applied, was negati-ve
104 of Exhibit No. 2. The12
13
L4
15
$22,t56,186,
approximate
to customers
O.
accumulation
negative $22.7 million represents a refund due
in this year's PCA True-up.
To what factors do you attribute the
of the approximate negative $22.1, million16
BLACKV,IELL, DI L1
Idaho Power Company
11 deferral balance?
1 A. The approximate negative $22.1 million
2 deferral balance was largely driven by unpredictable
3 changes in market energy prices and the resulting variation
4 between forecast prices and actual prices. Because actual
5 market energy prices were higher than expected, it resulted
6 in higher than forecast surplus sales revenue and coal fuel
7 expense. The increase in market energy prices also
8 resulted in higher than forecast market power purchase
9 expense. Actual natural gas prices were also higher than
10 forecast driving an increase in natural gas fuel expense.
l-1 Although actual market energy prices and natural gas prices
L2 were higher than forecast, the Company's reliance on market
13 power purchases and natural gas generation did not decrease
1,4 as they were needed to serve load due to lower than
15 expected hydro generation.
L6 0. P1ease eLaborate on the changes in actual
l7 versus forecast generation and expense for the 2020-2021,
l-8 PCA Year.
L9 A. Last year's PCA forecast included an average
20 market sales price of $15.14 per MWh. The actual average
2L market sales price was $34.45 per MWh, a 128 percent
22 increase. As a result of the difference in forecast and
23 actual market sales prices, actual surplus sales volumes
24 were 77 percent higher than forecast and surplus sales
BLACKWELL, DI ].8
Idaho Power Company
l- revenue totaled $641583,553, which was 302 percent higher
2 than forecast surplus sales revenue of $L6,0761860.
3 Coal-fired generation totaled 3,794,008 MWh, which
4 was 28 percent higher than forecast, and actual coal fuel
5 expense uras $18.3 mi11ion, or 18 percent, higher than
6 forecast. Coal-fired generation was higher than forecast
7 due to the increase i-n market energy prices, making it more
8 economic for l-oad service and surplus sa1es.
9 The increase in market energy prices contributed to
10 higher than forecast purchased power expense. The actual
11 average market purchase price for the 2020-202t PCA year
72 was $30.45 per M[rIh, a 12 percent increase from the average
13 forecast price of $27.14 per MWh. Market power purchases
t4 totaled 11 583,605 MWh, which was 4 percent higher than
15 forecast. As a result, market purchased power expense was
16 $48,225,1"68 compared to $41",404,266 included in the
17 forecast, reflecting a 16 percent increase.
18 Natural gas generation totaled 2,1,12,933 MWh for the
L9 2020-2021 PCA Year, which was 139,387 MWh, or 7 percent,
20 higher than forecast. Due to natural gas prices being
21, higher than expected, actual natural gas expense totaled
22 $54,873,821, which was 29 percent higher than forecast.
23 Although actual market energy prj-ces and natural gas
24 prices were higher than forecast, the Company's reliance on
25 these resources increased, 4 percent and 7 percent,
BLACKWELL, Dr 19
Idaho Power Company
1 respectively, as they were needed to meet l-oad due to the
2 reduction in hydro generation. Actual hydro generation for
3 the 2020-2021 PCA year was 6,786,206 MWh, which was 555,511
4 MWh, or 8 percent, less than forecast.
5 Fina11y, actual water for power expense was $480,000
6 compared to forecast expense of $1.5 mi11ion. Due to
7 weaker-than-expected hydrologic conditions in the Upper
8 Snake Basin last year and the resulting decrease in water
9 availability, the Company was not able to procure as much
10 leased water as expected.
11 O. P1ease explain the water lease the Company
12 entered into in 2020.
13 A. In 2020, Idaho Power entered into an agreement
t4 to purchase
rental poo1.
price of $24
water from the Water District 1 supplemental
15
t6
1,7 shown on line
18
The agreement totaled 20r 000 acre-feet at a
per acre foot for a total cost of $480,000r ds
26 of Exhibit No. 2. The water was delivered
19
20
21.
22
23
above American Fa1Is and flowed through Idaho Power's
system, passing Milner Dam between September 15, 2020, and
September 25, 2024,
a. How did the water lease impact hydro
generation?
A. Based on the actual daily water flow, the
Company estimated that hydro generation from the water
BLACKWELL, DI 20
Idaho Power Company
24
1
2
3
4
5
6
7
B
9
lease totaled 20,756 MWh, resulting in a price of
approximately $23.13 per MWh.
Did the water l-ease expense and associateda
increase in hydro generation benefit customers?
A. Yes. Idaho Power was able to reduce market
purchases during this time by using the leased water and
running additional water through the Hells Canyon Complex.
The purchase of leased water at $23.13 per MWh compared
favorably with the average price paid for market purchases
during the month, which was approximately $61.55 per MVilh.
This additional hydro generation also contributed to
Idaho Power's ability to sel1 into high-priced hours to the
benefit of customers. The average price for market sales
during the month was $55.98 per MWh, compared to the cost
of the leased water at $23.13 per MWh, resulting in net
revenue from surplus sa1es.
A. Were there any items included in this year's
True-up in addition to actual NPSE incurred during the
April 2020 through March 202L period?
A. Yes. Per Commission Order No. 34100, Idaho
Power included its actual- costs of Western Energy Imbalance
Market ("EfM") participation for April- 2020 through March
202L in the True-up. Benefits associated with EIM
participation are embedded in actual NPSE experienced over
that same period.
BLACKWELL, DI 21.
Idaho Power Company
t-0
11
1,2
13
14
15
16
l7
r-8
1-9
20
21
22
23
24
25
1 Q. Please summarize the conditions of Order No.
2 341,00 as they pertain to EIM cost recovery through the 202t
3 PCA.
4 A. Per the terms of the settlement stipulation
5 ("EIM Stipulation") approved by Order No. 34100, Idaho
6 Power agreed to include an ElM-related monthly revenue
7 requirement in its monthly PCA deferral calculation based
8 on actual EIM participation costs commencing April L, 201"8.
9 The Company also agreed to apply a soft cap to ElM-related
10 revenue requirement included in the PCA deferral equal to
11 annual EIM benefits as reported by the California
L2 Independent System Operator ("CAISO") for the corresponding
13 period.
L4 O. Is the ElM-related revenue requirement
15 included in the April 2020 through March 2021, PCA deferral
16 under the soft cap of annual CAISO-reported benefits for
L7 that same period?
18 A. Yes. Eor the April 2020 through March 2021
19 period, the EIM-rel-ated revenue requJ-rement totaled $3.2
20 mj-llion, while CAISO reported EIM benefits for Idaho Power
2L of approximately $21- million from April through December
22 (CAISO's first quarter 202L report has not yet been
23 published) . Therefore, the Company's EIM-related revenue
24 requirement is less than the soft cap agreed to in the EIM
25 Stipulation.
BLACKWELL, DI 22
Idaho Power Company
1
2
3
4
5
6
7
I
9
a. Does Idaho Power believe the EIM has provided
net benefits to customers since joining in April 20L8?
A. Yes. While Idaho Power believes the CAISO
benefit calculation overstates estimated benefits to Idaho
Power's system, the Company believes customers have
realized significant net benefits since the Company's entry
into the EIM in April 20L8. As discussed in the Company's
M,ay 24, 2OL9, Report of EIM Benefits and Costs of
Participation, filed in Case No. IPC-E-16-1"9, Idaho Power
has developed a more precise methodology for determining
EIM benefits that uses inputs specific to the Company.
Based on this methodology, the Company believes benefits
achieved between April 2020 and December 2020 are
approximately $14 million (benefits for the first quarter
of 2021, are not yet available). This leve1 of EIM benefits
compared to the ldaho-jurisdictional EIM costs of $3.2
milIion, demonstrates a net benefit to the Company and,
ultimately, its customers.
O. What is this year's True-up of the True-up?
A. This year's True-up of the True-up balance i-s
$4,5L9,61-4, as shown on row 124 of Exhibit No. 2.
0. What is the combined effect of the True-up and
the True-up of the True-up in this year's PCA?
A. The sum of the negatj-ve $22.1 million
associated with the True-up and the $4.5 million associated
BLACKWELL, DI 23
Idaho Power Company
10
11
t2
13
L4
15
1,6
L7
l_8
L9
20
2t
22
23
24
25
1
2
3
4
5
6
7
I
9
with the True-up of the True-up represents an approximate
$17.6 mil-Iion credit to customers.
0. How does this year's combined True-up and the
True-up of the True-up compare to last year's amount?
A. The combined True-up and the True-up of the
True-up for the last PCA Year was negative 542,648,447, ds
compared with this year's amount of negative $17,637,772.
While this year's true-up reflects a credit to customers,
it is approximately 59 percent less than the credit
customers are currently receiving through last year's true-
up, and ultimately refl-ects an increase in billed revenue
of $25 ,01.L,27 5 .
C. PCA Rate Detenmination.
O. How is the rate for the forecast portion of
the PCA for April 2021 through March 2022 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 L, 2021,, throuqh May 31, 2022 ("System-
leve1 SaIes Eorecast") i and (2) 100 percent of the
difference between PURPA-related expenses quantified in the
Operating PIan and those quantified in the Company's last
approved update of NPSE, divided by the Company's System-
BLACKWELL, D] 24
Idaho Power Company
10
11
L2
13
t4
15
t6
t7
18
1-9
20
2L
22
23
24
25
1 level Sa.l-es Eorecast; and (3) 100 percent of the difference
2 between the Idaho jurisdictional demand response incentive
3 payments quantified in the Operating PIan and those
4 quantified in the Company's last approved update of NPSE,
5 divided by the forecast of Idaho jurisdictional firm sales
6 for June L, 2021, through May 31, 2022.
7 Q. What is the rate for the forecast portion of
8 the PCA for April 202t through March 2022?
9 A. The rate for non-PURPA expenses is 0.4334
10 cents per kilowatt-hour ('kwh"), which is calculated by
11 multiplying 969,031,319 from Table 2 by 95 percent and then
L2 dividing it by the System-Ieve1 Sales Eorecast of
13 l-5,131,418 MVih ( ($59,031,319 * 0.95) / 15,131 ,41,8) :
L4 $4.334/lqwfr : 0.4334 cents/kWh) . The rate for PURPA
15 expenses is 0.47LL cents per kwh, which is calculated by
1.6 dividing $71.,279,8'72 from Table 2 by the 15,131,418 MVlIh
t7 ($2t,279,872 / 15,131,418 MWh: $4.711lMWh :0.471,1
18 cents/klrilh) . The rate for demand response incentive
1,9 payments is a negative 0.0252 cents per k$ih, which is
20 calculated by dividing the negative $3,638,653 from Table 2
2t by the forecast of Idaho jurisdictional firm sales of
22 L4,436,951 MWh (-$3,638,653 / 14,436,951 MWh : -$0.252lUWrr
23 - -0.0252 cents/kwh) . The forecast portion of the PCA rate
24 is 0.8793 cents per klrlh, which is calculated by adding the
25 non-PURPA expense of 0.4334 cents per kV[h to the PURPA
BLACKWELL, DI 25
Idaho Power Company
1 expense of 0.4711, cents per kWh to the demand response
2 incentive payment of negative 0.0252 cents per kwh (0.4334
3 + 0.4711 + -0.0252: 0.8793 cents/kwh).
4 Q. How did you compute this year's True-up rate?
5 A. As shown in Exhibit No. 2, this year's True-up
6 component of the PCA is approximately negative $22.1,
7 million, which, when divided by the Company's forecast of
8 Idaho jurisdictional sales of 14,436,951 Mt^trh, results in a
9 rate of negative 0.1535 cents per kWh (-$22,1,56,786 /
10 L4,435,951 : -$1.535/Mv[h = -0.1535 cents/kwh) .
11 The True-up of the True-up rate is calculated by
1,2 dividing $4,519,614 (also from Exhibit No. 2) by the
13 forecast of Idaho jurisdictional sales of 1,4,436,951 MWh,
14 which results j-n a rate of 0.0313 cents per kwh ($4,519,61,4
l-5 / tq,436,951 = $0.313/MWh : 0.0313 cents/kwh) .
16 O. What i-s the resulting PCA rate when you
L7 combine all the PCA components described previously?
18 A. The uniform PCA rate comprises (1) the 0.8793
L9 cents per kWh for the 202L-2022 prolected power cost of
20 serving firm loads under the current PCA methodology and 95
2L percent sharing, (2\ the negative 0.1535 cents per kWh for
22 the 2020-2021 True-up portion of the PCA, and (3) the
23 0.0313 cents per kWh for the True-up of the True-up. The
24 sum of these three components is a 0.7511" cents per kwh
25 charge for all rate classes.
BLACKWELL, DI 26
Idaho Power Company
1,
2
3
4
5
6
7
B
9
III. ADDIEIONAIJ PCA RATE ADJuSIIIIENES
A. Revenue Sharinqt
A. Ialhen was the
originally established?
A. The revenue
revenue sharing mechanj-sm
sharing mechanism was originally
established in Case No. IPC-E-09-30 and approved in Order
No. 30978, effective for the years 2009-201L. Since then,
the revenue sharing mechanj-sm has been modified and
extended three times.4 Most recently, the revenue sharing
mechanism was extended indefinitely, with modifications, in
Order No. 34071 in Case No. GNR-U-18-01.
O. What are the provisions of the current revenue
sharing mechanism?
A. In Case No. GNR-U-18-01, the Company filed a
motion to approve a settl-ement stipulation (*2018
Stipulation") extending the sharing mechanism indefinitely,
with modifications. The Commission approved the 20LB
Stipulation in Order No. 340'7L.
Per the terms of the 2018 Stipulation, if the
Company's actual year-end Return on Equity ("ROE") for the
Idaho jurisdiction exceeds 10 percent, all amounts up to
and incl-uding a 10.5 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
BLACKVIELL, Dr 27
Idaho Power Company
10
11
L2
13
t4
15
16
17
18
19
20
21,
22
23
24
a Order Nos. 32424, 33749 and 34071.
1 become effective at the time of the subsequent year's PCA.
2 Tf the Company's Idaho jurisdictional ROE exceeds 10.5
3 percent, al1 amounts in excess of 10.5 percent will be
4 shared 55 percent with Idaho customers as a rate reduction
5 to become effective with the subsequent year's PCA, 25
6 percent will be shared with Idaho customers in the form of
7 an offset to amounts in the Company's pension balancing
8 account, and 20 percent will be apportioned to the Company.
9 With regard to the amortization of Accumulated
10 Deferred fnvestment Tax Credits ("AD]TC"), the 20LB
11 Stipulation allows the Company to accelerate the
L2 amortization of ADITC, in an amount up to $45 miIlion, to
13 achieve a maximum 9.4 percent Idaho jurisdictional ROE if
14 the Company's year-end actual results fall below that
15 amount for any year beginning ,January 1, 2020. Idaho Power
1,6 may use up to $25 million of additional amortization of
t7 ADITC per year, provided the total, cumulative amount of
18 ADITC does not exceed 945 miIlion. Per the 20Lg
t9 Stipulation, once the Company has fu11y amortized the $45
20 million of ADITC, revenue sharing will ceasel however,
2L Idaho Power may at any time request to replenish the total
22 amount of ADITC it is permitted to amortize, and if
23 approved by the Commission, revenue sharing would continue.
24 O. Did the revenue sharing mechanism result in
25 any action following the 2009-2019 fiscal years?
BLACKWELL, DI 28
Idaho Power Company
1
2
3
4
5
6
7
8
A. Yes. The Company's earnings in each year from
20Lt through 20L5, as well as 2018, resulted in revenue
sharing with customers totaling $L26.2 m11l-ion, either as a
direct rate offset in the PCA or as an offset to amounts
that would have otherwise been collected in rates. The
Company's earnings Ln 2016, 20L7 and 2019 were below the
revenue sharing threshold. These amounts are detailed in
Table 6.
9
Table 6 2009-2018 Revenue Sharlnr
Line No.Revenue Sharins Comoonent 2d)9.2011 2012-20,.4 201s-2019
1
2
3
4
5
6
7
Available ADITC For Use
ROE Threshold
5G50 Sharing Threshold
75-25 Sharing Threshold
Customer Benefits (S Millions):
Reduction to Rates
Offset to Pension Balancins Account
S45 Million
9.5%
10.5%
N/A
S45 Million
9.5%
10.0%
10.5%
S45 Million
10.0%
N/A
L0.o%
izt.t
S20.3
S22.8
s47.8
s8.2
s0.0
8 Total Sqt.t s70.6 S8.2 Sr2G.2
10 O. Did the Company's year-end 2020 financial
11 results warrant any action rel-ated to the existing sharing
72 agreement per the terms of the 201,8 Stipulation?
13 A. No. The Company's year-end 2020 financial
14 results yielded an actual- Idaho jurisdictional ROE of 9.98
15 percent, falling below the 10 percent ROE threshold for
L6 revenue sharing, and thus resulting in no revenue sharing
L'7 with customers.
18 O. Did the Company use the same methodology to
L9 determine the ldaho jurisdictional 2020 year-end ROE that
20 was used in prior PCA filings?
BLACKWELL, DI 29
Idaho Power Company
1 A. Yes. The methodology used to determine the
2 Company's Idaho jurisdictional 2020 year-end ROE is
3 consistent with the methodology used for the year-end ROE
4 determinations since the inception of the mechanism.
5 Q. Do you have an exhibit demonstrating the
5 application of this methodology?
7 A. Yes. Exhibit No. 3 provides a step-by-step
8 calculation of the Idaho jurisdictional ROE based on year-
9 end 2020 financial results utilizing the Commission-
10 approved methodology from previous PCA filings.
11 TV. ![ET CUSTOMER IMPACT
1,2 O. What is the revenue impact of the requested
PCA rate when compared with PCA rates currently in effect?
A. Attachment 2 Lo the Application filed
contemporaneousl-y with my testimony provides a detailed
description of the overall revenue impact of this filing on
each customer cfass. As shown in Attachment 2, applying
the requested PCA rates to expected customer sales for the
.Tune 2021, through May 2022 test year results in a PCA
increase of $39.1 million.
13
1,4
15
L7
18
16
19
20
21,0
A
22 includes
23
. Have you prepared a
the proposed PCA rates?
. Yes. Attachment 1
revised Schedule 55 that
to the Application is a
the proposed PCA rates in24 revised Schedule 55 and includes
BLACKWELL, DI 30
Idaho Power Company
25 clean and legislative formats.
1 Q. Should the Commission approve the Company's
2 computation of the PCA rates?
3 A. Yes. The Commission should approve the
4 Company's computation of the PCA rates. The calculation of
5 the PCA rates follows the methodoloEy that was approved in
6 Order Nos. 30715, 33307, and 3407L. If approvedr the ZAZL-
7 2022 PCA will result ln an i-ncrease in total bilIed revenue
I of approximately $39.1 mi11ion, or 3.36 percent.
9 O. Does this conclude your testlmony?
10 A. Yes, it does.
BLACKWELL, DI 31
Idaho Power eompanli'
l- DECLARAUON OF NICOLE A. BI.ACKrTELL
2 l, Nicole A. B1ackwe11, declare under penalty of
3 perjury under the laws of the state of ldaho:
4 1,. My name is Nicole A. Blackwell. I am
5 employed by Idaho Power Company as a Regulatory Consultant
6 in the Regulatory Affairs Department.
7 2. On behalf of Idaho Power, I present this
8 pre-filed direct testimony and Exhibit Nos. 1-3 in this
9 matter.
L0 3. To the best of my knowledge, my pre-filed
11 direct testimony and exhibits are true and accurate.
1,2 I hereby declare that the above statement is true to
13 the best of my knowledge and belief, and that I understand
L4 it is made for use as evidence before the Idaho Pub1ic
15 Utilities Commission and is subject to penalty for perjury.
LG SIGNED this 15th day of April 202L, at Boise, Idaho.
77
18 Signed:
BLACKWELL, Dr 32
Idaho Power Company
e
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPG-E-21-10
IDAHO POWER COMPANY
BLACKWELL, DI
TESTIMONY
EXHIBIT NO. 1
(EXCEL SPREA DSH EEr ALS O ATTACH ED
TO EMATL)
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BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-21-10
IDAHO POWER COMPANY
BLACKWELL, DI
TEST!MONY
EXHIBIT NO.2
(EXCEL SPREA DS H EEr ArS O ATTACH ED
TO EMATL)
-+--
rc
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BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
cAsE NO. IPC-E-21-10
IDAHO POWER COMPANY
BLACKWELL, DI
TESTIMONY
EXHIBIT NO.3
(EXCEL SPREA DSH EEr AtS O ATTACH ED
TO EMATL)
IDAHO FOWERCOUPANY
ADDMONAL INVESTTENT TAX CREDIT ANALYSIS
For tho Twelvo lrlonths Ended December 31, 2020
.r.suffitrEsufrcr..
TOTAL COMINED ilTE BASE
Td&
lEIq
3,530,6i!8,329
D6!O
3,3U2,211,25A
D&p,
s5.8%
p.llo-r
96.1%
05.896
96.094
03.3%
83.1%
98.s%
95.896
98.7*
08.7*
Exhibit No.3
Case No. IPC-E-21-'10
N. Blackwell, IPC
Page 1 of 1
lddbhbr!l {{
TOTAL
AYSTEI
S€ptmbd Allo€toBrRrtiog
1,116,558,S67 Olr6d Aslgn
't07,€0,555 05.6*
1 ,2U,O15 ,522
Dallo
780,058,586
155,52,{,06}
7,400,073
30,818.,t36
1,,l07,,155
$,137,7271
2,70l,,@8
25.476.127
0,2u,171
1.013,101.S€6
OPEMTING RffiNUES
RfrAIL SES RMNUES (hlff.l R.v)
OTHER OPERATING REVENUES
TOTI OPEMTING REVENUES
800,037,053
132,A73,81
1.028.010.9r7
857,137,508 Di@tA$lgn
'127,@0,415 95.696
w,137,923
1.1@.068.(x3
1 75,2d),99a
'l,3il4,t@,041
OPEUTING INCOME
ADD: ERCO OPEilTING INCOME
227,451,415
6,24i,0e4
2.1,142,58
5,e62,E92
OPEilTING*ENSES
EERATON A MNTEMNCE *ENSES
DEPRECIATION EXPENSE
ArcRTZATION OF LIMTED TERM PUNT
TilESOTHER THAN INCOffi
reGULATORY OEBfiSrcREOITS
PROVISION FOR DEFERRED INCOre TreS
INVESTMENT TU CREDIT ANUSTMEM
FEOEru INCOME TilES
STATE INCOME TreS
TOTAL OPEilTING UPENSES
@0,E54,801
121,712,62.1
5,775,5,10
25,044,411
970,127
5,327,100
1,702,32
'15.717,(E6
3,369,422
801,259,502
589,990,584
'r6,640I@
5,535,0@
24.106.170
E06,515
5,2,15,587
1,680,(x6
15.520,,170
3,315,556
702,955,355
05.'t*
05.8!a
06.016
93.3%
8i).'l*
08.5t6
05.8*
08.7!6
98.7*
9,ltrz.,ln
192.,314,7&
7,727,5't3
33,047,@3
1,332,529
(o,233,',t271
2,820.Eeg
24,2U,174
0,280258
1,064.r07.455
DSELOPMENT S NET INCOME
RETURN ON ER{ND COMMN EOUfr
OPEilTING INCilE BEFORE OTHER INCOME AND DEDUCTIONS
ADO: AFUOC EOUITY
ADD: OTHER INCOMEAND DEDUCTDNS
INCOME SEFORE INTEREST CffiRGES
LESS: INTEREST CURGS
233,89?,,r09 227,145,1@ 288,373,8@
29,550,610
2,698,E67
274,874,9O7
28,320,008
2,@S,007
so.7*
95.8r,6 (L t0)
e0.7% (L 33)
320,@32n
a7,w,lg
300.80,r,9,(2
8i,,740,700
279,571,58
8,142,211
270,853,526
8,02't,381
224,50r'273
236,38ilrit6
218.202.O1A
95.5%
95.8* (L r0)
05.896 (11 0)
212,947,803 (144.9.4%)
228,5a0,q8 (La4.t09S)
2$,t67,0r8 (1,9. 10.5*)
(14,467,s87) (Lii&113), (1-e.4%)
211,5A7,U9
2,250,*t2,110
0.,10*
95.5*
NET NCOME 233,231,513 224,65237
e.e7%9.08J6
233,231,513
2,303,83/r,455
226,06,5237
2.26.1@.O27
ACTUI ER€ND RESULTS.SEFORE trC ADJUSTMENT
ARNNGS ON COMMONST@K
MMIDN EQUTTY AT ER END
EARNINGS ONCOMMONSTOCK O O,E ROE
aRNN6 ON COMrcN SIOC( @ i0 ROE
aRNNGS ONCOMrcN STOCK Q to.S RG
ACTUI BR€ND RESULTS.AFTER trC AUUSTMENT:
IWESTMENT TAX CREOtr AUUSTMENT
AA'USTEO EARNINGS ON COMM STOCK
A().'USTED COMN EOW AT YEAR€NO
ANUSTED RETURN ON ER{ND COIi'ON EOW
F lDAllO RETURN Ot{ COllIoil EQUEY(Llm it6) <9.4%
ADDTPML trC ADJUSTMENT (AnnusH) tr L g b n.g.h, hs 0; tr pdE, h.n mrhr ot Lg or t25.m,m 0
F [r^tlo RETURN Ot{ COIIox EQUITY (Um /la) >lor
IDArc ARNN6 GREATER TUN TffiROEBW LESTMN 10.5%o (143-r-4ey(r-r0*)
F IOAHO RETURT{ Ol{ COllIO]{ EQUrY(Lln. ia6) t10.5%
INCREMENTAL IDAHO EARNINGS GRATERTHAN 1O.S% ROE 0 (14$r50y(1r0.5%)
,.. Ord.r ,3aorl :
ROE M 10!b10.5% {USTilER SHARE. &9a (Rdffi b nE)
ROE M 10!b10.5% 4ilPAW SURE. A%
ROE g@Btun 10.5% (lnffidd)- CUSTOi/€:R SURE. S% (Rducbn b rc)
ROE guufr.n 10.5% (lnffiobD - CUSTOER SURE - 25% (ffi b Pa$n b.bn€)
ROE smgtun 10.5% (lffid) {OMPANY SURE. A%
Afrs Td
0