20170417Blackwell Direct.pdf

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BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLTCATION
OE IDAHO POII{IER COMPANY FOR
AUTHORITY TO IMPLEMENT POWER
COST ADJUSTMENT ("PCA") RATES
FOR ELECTRIC SERVICE FROM JUNE
L, 2017, THROUGH MAY 31, 2018.
IDAHO POWER COMPANY
DTRECT TESTTMONY
OF
NICOLE A. BLACKWELL
CASE NO. IPC-E-17-06
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o.P1ease state your name, business address, and
present position
"Company").
A- My
address is 7227
with Idaho Power Company ("Idaho Power" or
name is Nicol-e A. Blackwell. My business
West Idaho Street, Boise, Idaho 83702. I
am employed by Idaho Power as a Regulatory Analyst I in the
Regulatory Affairs Department.
0. Please describe your educational background.
A. In May of
in Fi-nance and
2070 | I received Bachelor of Sclence
10 degrees
Idaho.
Economics from the
I have also attended "The Basics:
University of
Practical11
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L4
L1
Regulatory Training
utility ratemaklng
University's Center
for the Electric Industryr " an electric
course offered through New Mexico State
for
15 Utility Fundamentals &
Public Utilities, and "Electric
Insightsr" an el-ectric utility
the Western Energy Institute.l-6 course offered through
1B
O. Please describe your work experience with
Idaho Power.
A. fn January 2076, T accepted my current
posj-tion at Idaho Power as a Regulatory Analyst in the
Regulatory AffaJ-rs Department. As a Regulatory Analyst, I
provj-de support for the Company's regulatory activities,
including compliance reporting, financial analysis, and the
development of revenue forecasts for regulatory fiJ-ings.
O. What is the Company requesting in this case?
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BLACKWELL, DI ]-
Idaho Power Company
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(*PCA") rates to become
approved, the 2077-2078
total bi11ed revenue of
0.93 percent.
o
fn the flrst
10 PCA. In the
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The Company is requesting approval of its
quantification of the 20L7-20L8 Power
effecti-ve June
Cost Adjustment
l, 2071. 7f
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PCA will result in an increase in
approximately $10. 6 mi-1Iion,or
How is your testimony organized?
My testimony is comprised of four sections.
section, I will provide an overview of the
second section, I will detail the 201,1-201,8
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PCA amount, identify
contributing to this
of the 20L7-20L9 PCA
and di-scuss the main factors
amount, and present the quantification
rates. In the third section, I will
discuss
sharing
final section of my
proposed to become
customer impact of
additional PCA components
and the Energy Efficiency
related to revenue
Rider ("Rider"). In the
testimony, I will summarize the rates
effective June L, 20L7, and the net
these rates if approved.
I. PCE O\TERVIEIY19
20 O. What is the purpose of the PCA and how does
2L the mechanism function?
22 A. The PCA is a rate mechanism that quantifies
23 and tracks annual differences between actual Net Power
24 Supply Expenses (*NPSE") and the normalized or "base level"
25 of NPSE recovered in the Company's base rates, resulting in
BLACKWELL, DI 2
fdaho Power Company
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a credit or surcharge that is updated annually on June 1.
The PCA mechanism utj-lizes a 12-month test peri-od of April
through March ('PCA Year") and is comprised of a forecast
component and a true-up component ("True-Up"). The
forecast component represents the difference between the
NPSE forecast from the March Operating Plan and base l-evel-
NPSE recovered in the Company's base rates. The True-Up
includes a backward looking tracking of differences between
the prior year's forecast and actual NPSE incurred by the
Company in that PCA Year. The True-Up contains a second
component that tracks the col-Iection of the prior year's
True-Up amount, referred to as the "True-Up of the True-
Up."
With the exception of Public Utility Regulatory
Policies Act of 7918 ('PURPA") expenses and demand response
incentive payments, the PCA allows the Company to pass
through to customers 95 percent of the annual differences
in actual- NPSE as compared to base level NPSE, whether
positive or negative. With respect to PURPA expenses and
demand response incentive payments, as actual- annual
expenses deviate from base level NPSE, the Company is
allowed to pass through 100 percent of the difference for
recovery or credit through the PCA. The PCA is al-so the
rate mechanism used by the Company to provide direct
benefits resulting from the revenue sharing mechanism
BLACKWELL, DI 3
Idaho Power Company
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1 approved by the Idaho Public Utilities Commission
2 ("Commission") in Order No. 33149.
3 O. What are the components of the PCA base l-evel-
4 NPSE?
5 A. The PCA base level NPSE incl-udes the following
6 Federal Energy Regulatory Commission ("FERC") accounts:
7 Account 501, FueI (coal-); Account 536, Water for Power;
8 Account 547, Fuel (gas); Account 555, Purchased Power,'
9 Account 565, Transmissi-on of Electricity by Others; and
10 Account 447, Sales for Resale (typically referred to as
11 surplus sales).
1,2 The PCA base level expense component for FERC
13 Account 555 includes costs resulting from both PURPA and
74 non-PURPA (market) purchases. Per Order No. 32426, the
15 Company adjusts FERC Account 555 to include demand response
76 incentive payments that the Company provides to customers
t7 for participating in any of j-ts three demand response
18 programs.
19 rr. 20L7-20L8 PCA
20 o ['Ihat is the tota] PCA col-lection that would
2L result under the 2071-2018 PCA rates proposed by the
22 Company in this case?
23 The total PCA collection that would result
24 under the 20L7-20I8 PCA rates proposed in thls case is
BLACKWELL, DI 4
Idaho Power Company
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$90.1 million.1 This represents an increase in total billed
revenue of $10.6 million for the upcoming year, do increase
of 0.93 percent.
A. PCA Forecast.
o What is the Company's determination of the
system-Ieve1 difference between currently approved base
level NPSE2 and the
Year?
forecast of NPSE for the 2071-2078 PCA
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A. The system-Ievel forecast of NPSE for the
2017-20L8 PCA Year is $377,451,633, which is $17,166,-164
higher than the currentl-y approved base level NPSE of
$305,684,869. Table 1 be1ow presents the system-Ievel-
13 differences between currently approved base
for the 20L1-2018 PCA
leve1 NPSE and
Year by FERC
15 account.
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1 Includes the lmpact of the Rider refund detaifed in Section flf
2 Approved on March 27, 2014, Order No. 33000.
BLACKWELL, DI 5
Idaho Power Company
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14 the forecast of NPSE
Table 1 2OL7-m78 PCA FORECAST (Total Svsteml
Line No.Base NPSEFERC Account Forecast Difference
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95Yo Sharins Accounts
Account 5O1, Coal S
Account 536, Water for Power S
Account gZ Other Fuel S
Account555,PurchasedPowerNon-PURPA S
Account 565, 3rd Party Transmission S
Account447. SurolusSales S
108,503,180 s
2,*0,597 s
33,367,563 s6zffi,s93 S
5,455,95s s
(s1.73s.1s3) s
126,769,fi3
3230s,s83
52,615,287
6,Ot7,O25
(:t4.371.8s8)
t8.,2ffi,323
(2,3&,s971
3,938,O20
(9,991,306)
561,O70
77.363.295
s
s
s
S
S
s
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1OO7o Sharing Accounts
Account 555, PURPA S
Account555- Demand Resoonse lncentives S
s r@,s7a,73s s 188,33s,s4o 5 27,7s6,W
133,8s3,869 18L,7a439s 47,4@,526
t,..2s2.26,5 7-67.694 (3.a50.557)
s
s
s
s
9 Total s :tos-6M.a69 s ?77.451.633 3 7L.766.7&L7
befow.
1 Q. What is the basis for the forecast of NPSE for
2 the 20L7-20L8 PCA Year?
3 A. The forecast of NPSE for the 20L7-2018 PCA
4 Year is based on the Company's March 30, 2071, Operating
5 P1an.
6 Q. How is the NPSE forecast developed for the
7 Company's Operating Plan?
8 A. The Operating Pl-an is prepared monthly and
9 represents a forecast of the Company's monthly NPSE for the
10 following 18-month period; however, for the PCA, the
11 Company includes only the 12 months that correspond to the
t2 PCA Year. The Operating PIan is developed by simulating
1-3 the economic dispatch of the Company's generation resources
t4 for each month, segmented by heavy l-oad and light load
15 hours. The dispatch considers a current forecast of
!6 forward market energy prices, available hydro generation,
L7 coal and natural gas prices, and any exlsting hedge
18 transactlons. The system l-oad forecast is then analyzed
79 against the resulting monthly heavy load and light load
20 dispatch to determine a monthly load and resource balance.
2L Any identified resource deficiency is assumed to be filled
22 with market energy purchases. Economically dlspatched
23 generation above the system l-oad forecast represents
24 surplus energy sales. The forecast of monthly NPSE and
25 generation for the 20L7-20L8 PCA Yearr ds determined 1n the
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Idaho Power Company
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Company's March 30, 2077, Operating Plan, is provided in
Exhibit No. 1
O How does the Company's forecast of NPSE for
the 2077-20L8 PCA compare to the forecast from l-ast year's
PCA?
A Table 2 below compares this
PCA forecast
year's 2011-20L8
for each NPSE
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category. As detaifed in this tabl-e, the PCA forecast on a
total system basis for the 20L1-2078 PCA Year is
$377,451,633, which is $19,903,893 higher than l-ast year's
forecast amount of $357 ,54'7,740.
o.What general concl-usions can be drawn from the
L6 lnformation contained in Table 2?
17 A.When viewed by category, the 95 percent
1B
PCA forecast to last year's
sharing
mlllion
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13t4
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accounts represent a decrease of approximately $3.1
from last year's forecast, whil-e the 100 percent
BLACKWELL, DI 1
Idaho Power Company
Table 2 PCA Forecast Comparison Expenses (Total Svsteml
Line No.
20LG2(IL7
Forecast
mL7-2078
ForecastFERC Account Difference
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3
4
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95% Sharins Accounts
Account 5O1, Coal S
Account 53Q Water for Power S
Account 542 Other Fuel S
Account 555, Purchased Power Non-PURPA S
Account 565, 3rd Party Transmission S
Account447, Surplus Sales S
\L2,127,L6 L26,769,fi3 74,@2,397
39,202,422
il,988,467
5,9W,412
(20,930,1471
3230s,s83
52,615,287
6,077,O25
(34,371,858)
(L,897,239l.
(2,373,7ffi1
t7,6]-3
(73,441,77L1
s
s
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s
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100% Sharinq Accounts
Account 551 PURPA S
Account 555, Demand Response lncentives S
tsa,7sa382 s
7,nL,698 s
L8L,714,395 s
7,&1,698 s
22,956,073
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s 191,387,660 s rs8,SsS,s4O s (3,0s2,120)
9 Total PCA Forecast
166,160,080 s
357.il7,7$ s
189,116,093 s
377,45L,633 s
22,956,O13
19,903,893
s
S
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1 sharing accounts represent an increase of approximately $23
2 million over last year's forecast.
3 Q. What factors are drivlng the $3.1 mill-ion
4 decrease in the 95 percent sharing accounts?
5 A. At a high level, increased hydro generation is
6 reducing NPSE, in addition to slight decreases in gas
7 production costs and purchased power expenses, which is
8 offset by increased coal production costs, resulting in a
9 $3 million net decrease in the 95 percent sharing accounts
10 relative to last year's PCA forecast.
11 O. Please explai-n the increase in coal- fuel
72 expense for this year's PCA forecast as compared to last
13 year's forecast.
74 A. Coal fuel expense j-ncluded in this year's PCA
15 forecast is $126,769,503, which is $!4,642,391, ot 13
1,6 percent, higher than last year. The increase j-s mainly
77 attributed to the operations of the Company's Jim Bridger
18 ("Bridger") p1ant, where coal- mining costs at Bridger CoaI
19 Company (*BCC") are being spread over lower production
20 volumes, thereby increasing the per-unit cost of production
21 at the Bridger plant. The per-unit cost for Bridger
22 included in this year's PCA forecast is $31.64 per
23 megawatt-hour (*MWh"), compared to 527.59 per MWh for last
24 year's forecast, a 15 percent increase.
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BLACKWELL, DI 8
Idaho Power Company
1 Q. Pl-ease provide a brief overview of how Bridger
2 ts supplied with coal.
3 A. rdaho Power and PacifiCorp co-own the Bridger
4 plant and j-ts associated mininq operation, BCC. The
5 Bridger plant is operated primarily with coal- from BCC's
6 surface and underground mining operations. Supplemental
7 coal is purchased from the nearby Black Butte Mine.
8 Bridger was designed and constructed as a mine-mouth plant,
9 whlch means it is physically located next to the coal mine
10 that supplies the majority of its coal-. This arrangement
11 ensures that Bridger has access to a continuous and
72 reliable source of coal. Coal is delivered to Bridger from
13 the BCC mine by use of a large conveyor belt system that
74 transports and delivers coal directly from the mj-ning
l-5 operation to the plant.
L6 0. What factors are driving the increase in
L7 Brj-dger coaf costs?
18 A. The increase in Bridger coal- costs is the
19 result of decreased coal production volumes at the BCC
20 mj-ne. Due to 1ow market prices, low-cost natura1 9ds, and
2L increased must-take PURPA generation on Idaho Power's
22 system, generation at the Bridger plant has experienced a
23 downward trend over the last three years. Based on lower
24 generation at Bridger, the BCC mine plan was adjusted in
25 20L6 to reflect reduced coal volumes. Lower production at
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Idaho Power Company
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the mine results in fixed costs being recovered over fewer
tons, causi-ng the cost per ton of coal to increase. The
reductj-on in volumes is causing an increase in the coal
price and is ultimately contributing to the 13 percent
i-ncrease in coal fuel- expense between last year's PCA
forecast and this year's forecast.
o.
95 percent
l-ast year?
A.
What else is contributing to the change in the
sharing accounts for this year as compared to
Surplus sales revenue
is 534,371,858, which
included in this year's
is $13,44:-.,777, or 64
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percent, higher than last year's forecast. Forecast
surplus sales volumes are up approxlmately 91 percent from
the prj-or year, from 1,135,459 MWh to 2,!65,06L MWh. The
increase 1n surplus sales revenue is related to lncreased
hydro generation, which will be discussed in more detail-
l-ater in my testimony.
Although surplus sales have increased, the va1ue, on
a per MWh basis, has decreased as compared to last year.
Due to improved hydrologic conditions throughout the regTion
and 1ow projected natural gas prices, expected market
prices have declined. The average market sales price for
thls year's PCA forecast is $15.88 per MWh, compared to
$18.43 per MWh in last year's PCA forecast.
BLACKWELL, DI 10
Idaho Power Company
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O. What factors are contributing to the change in
the 100 percent sharing accounts?
A. With regard to the 100 percent sharing
accounts, PURPA costs increased by $23 million as compared
to last year's forecast, reflecting a 74 percent J-ncrease,
while demand response j-ncentive payments did not change.
PURPA is a must-take resource regardless of cost, which in
this case has an average cost of $62.42 per MWh. By
comparison, the average market purchase price for this
year's PCA forecast is $23.46 per MWh.
0. Is the increase in PURPA costs rel-ated to
increased generation output from PURPA projects?
A. Yes. Table 3 below details changes between
l-ast year's PCA forecast and this year's PCA forecast with
respect to forecasted generation in MWh. As shown j-n Table
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3, PURPA generation is
MWh, or 18 percent, ds
forecast. The increase
anticipated to increase
compared to last
in generation is
year's
by 454,Ll5
PCA
largely due to the18
!9 addition of 289.5 megawatts ("MW") of
20 and 50 MW of PURPA wind projects that
2t the last year.
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23 year's PCA forecast?
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PURPA solar
came on-line
proj ects
within
0 Were these PURPA projects included in last
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Idaho Power Company
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A. Yes, the projects were included in last year's
PCA forecast.3 However, the majority of this additional-
capacity,
2016 and
20L6-20L1 PCA Year.
approximately four months of the
In this year's PCA forecast, these
250 MW, was forecast to come on-l-ine in December
generate for
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proj ects
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are generating for the entire PCA Year, resulting
percent increase in PURPA generati-on.
O. What other general concl-uslons can be drawn
from the information in Table 3?
A. The combj-natlon of increased PURPA generation
of 454,L'7 5 MWh and hydro generation of 7,L62,626 MW!;r j-s
offset by a reduction in expected natural gas generation of
l7 percentr or 308,329 MWh, and purchased power volumes of
3 The 2076-201"1 PCA forecast i-ncl-uded 320 MW of additional- PURPA
so.l-ar capacity and 50 MW of PURPA wind capaci-ty. of whj-ch 339.5 MW have
actually come on-fine.
BLACKWELL, DI 1.2
Idaho Power Company
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Table 3 PCA Forecast Comparison Generation (Total System-Mwh)
Line No.FERC Account
zoLG20L7
Forecast
2oL7-2oL8,
Forecast Difference
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Hydro 7,633,253 8,795,879 r,162,626
95% Sharine Accounts
Account 501, Coal
Account 542 Other Fuel
Account 555, Purchased Power Non-PURPA
3,895,O94
t,u7,736
r,787,511
3,939,630
7,539,N7
899,3s9
44,536
(308,32e)
(288,1s2)
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95% Sharing Accounts L4,553,59/+t5,t74,275 610,681
10O% Sharine Accounts
Account 555, PURPA 2.457.O73 2.97t.24 4*,175
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10O7o Accounts
Total Generation
2,457,O73
L7.020.667
2,9L,.,28
18.O85.523
4v,175
1.O54.856
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95% Sharing Accounts
Account 447. Surplus Sales 1.135.459 2.L65.6L L.O29.@2
8 Total Load 15.845.208 15.920,62 35.2v
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24 percent, or 288,152 MWh, from last
As mentioned previously, the increase
generati-on is also driving an increase
sales volumes of L,029,602 MWh, or 9L
year's PCA forecast.
year's PCA forecast.
in expected hydro
in expected surplus
percent, from l-ast
o Is the increase i-n expected hydro generation
result of higher projected j-nflowsof !,762,626 MWh the
into Brownl-ee Reservoir ("Brownl ee" ) ?
A Yes. The March Operating Plan used in this
10 year's PCA forecast projects April through July infl-ows
11 into Brownl-ee of 8.3 millj-on acre-feet (*MAF") . This is
72 approximately 3.8 MAF, or 84 percent, higher than the 4.5
13 MAF used to determine l-ast year's PCA forecast.
L4 0. How does the increase in expected j-nflows
15 impact this year's hydro generation forecast compared to
76 last year's forecast?
L1 A. The hydro generation forecast for this year's
18 PCA is 8,795,819 MWh compared to 7,633,253 MWh in last
19 year's PCA forecast, a 15 percent increase.
20 O. Please explain why the higher inflows at
2l Brownlee do not translate into a proportional increase in
22 hydro generation compared to last year.
23 A. Although forecasted infl-ows into Brownlee are
24 84 percent higher for the months of April through Ju1y,
25 Brownlee headwater elevation targets for the months of
BLACKWELL, Dr l-3
Idaho Power Company
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February, March, and April are lower than normal- due to
fl-ood control operations. The U.S. Army Corp of Engineers
manages a region-wide flood control plan for the entire
Columbla River Basj-n, and it sets water surface el-evation
targets
as this
for Brownlee. In above average water years, such
year, lower headwater elevation targets are set for
Brownlee in the spring, as the Company must make room to
capture anticipated runoff to prevent downstream flooding.
Eor April 30, 2077, the forecasted elevation target for
Brownlee is 2,0L7 feet, a decrease of 25 feet from last
year's April 30, 2076, forecasted elevation target of 2,042
feet.
Additionally, although the forecasted April through
JuIy j-nflows into Brownlee are higher than last year, flow
through the generators is l-imited by the capacity of each
unit. The Brownlee hydro facility can run approximately
35,000 cubic feet per second ("cfs") . Any flows in excess
of this capacity are spilled past the dam and cannot be
used for generation. For the month of April 207-1, inflows
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20 at Brownlee are forecast at 52,375 cfs, which is
27 approximately 163 percent higher than forecasted inflows
22 for April 20L6. However, because the infl-ows are in excess
23 of Brownlee's capacity, the excess water has to be spilled
24 rather than used for generation.
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Idaho Power Company
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While the forecast hydro generation for the months
of April through July has increased from l-ast year by 4L
percent, for the remaining months of the PCA Year, the
forecast hydro generation is simil-ar to l-ast year,
decreasing by less than 1 percent.
O. How are the forecasted NPSE differences
presented
forecast
in Table 1 used to determine the 2077-20L9 PCA
component to be collected from Idaho customers?
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A. The 20L7-20L8 PCA forecast component reflects
the Idaho jurisdictlonal- share of the forecasted NPSE
differences presented in Tabl-e L, adjusted for the PCA
sharlng provisions. The Idaho jurisdictlonal share of the
forecast NPSE differences is determined by applying a ratio
of forecast firm Idaho jurisdictional sales to forecast
firm system-level sales to the system-level- NPSE
differences, adjusted for sharing.
O. What is the Company's forecast of system-Ievef
firm sales and Idaho jurisdictional firm sal-es for the
2071-2078 PCA Year?
A. For the 20L7-20L8 PCA Year, Idaho Power has
2l forecast system-Ievel firm sales
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to be L4,696,223 MWh and
to be 14,0L0,286 MWh, orIdaho jurisdictional
95.33 percent of the
firm sa-Ies
BLACKWELL, Dr 15
Idaho Power Company
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system level-
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O. What 1s the Company's determination of the
20L7-20L8 PCA forecast component to be collected from Idaho
customers?
A. The 2071-20L8 PCA forecast component to be
col-Iected from ldaho customers is $66,914,308. Table 4
presents the determj-nation of the 2017-2018 PCA forecast
component by individual- PCA expense and revenue category.
B. True-and True-of the True-
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t2 o
True-Up?
A
What is this year's quantificatj-on of the
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t4 The True-Up portion of the PCA is detailed in
15 the deferral expense report, attached as Exhibit No. 2.
This report compares actual- PCA account results to last
year's PCA account projections on a monthly basj-s, with the
dif f erences accumul-ated as the def erral bal-ance. The
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L9 balance at the end of March 20L1, with interest appJ-ied,
BLACKWELL, DI 76
Idaho Power Company
Table 4 2017-2018 PCA FORECAST
line No.
Difference from
Base
Difference After
Sharing ldaho AllocationFERC Account
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2
3
4
5
6
95% Sharing Accounts
Account 501, Coal
Account 53O Water for Power
Account 542 Other Fuel
Account 555, Purchased Power Non-PURPA
Account 565, 3rd Party Transmission
Account M7, Surpl us Sal es
(From Table 1)
s 1&255,323 s5 (2,380,597) S
S 3,938,020 Ss (s,se1,306) sS ssr,ozo S5 v,za3,zgs S
L7,353,@7 s
(2,26t,5671 5
3,741,LL9 5
(9,497,74L1 5
533,016 s
16,495,130 s
76,543,W
(2,156,010)
3,566,505
(9,W,72O)
508,138
L5,725,2n
7
8
10(Yo Sharing Accounts
Account555, PURPA S
Account 555, Demand Response lncentives S
5 z7,7s6,gos 5 za,$a,su 5 zs,]3,e,za
47,8@,526 s
(3.850.s67)
47,ffiOF26 sN/A S
45,626,656
(3.8s0.s67)
9 Total 5 ntaaJs S 74,229,4e0 S oe,gr4aos
1 was $33,953,029, ds shown on row 97 of Exhibit No.2. The
2 approximate $34 million represents a charge to customers j-n
3 this year's PCA.
4 Q. To what factors do you attribute the
5 accumulation of the approximate $34 mj-I1ion deferral
6 balance?
'1 A. The $34 million deferral bafance was largely
8 driven by lower than forecast hydro generation, which was
9 met with higher than forecast market energy purchases and
1-0 coal generation. Actual hydro generation for the 2016-201"7
11 PCA Year was 6,923,714 MWh, whj-ch was 709,539 MWh less than
1,2 the forecast of 7,633,253 MWh, refl-ecting a 9 percent
13 reductj-on between forecast generation and actual
L4 generation.
The shortfal-l-15 in hydro generatj-on was met with
1,6 increased market purchases, which were L32 percent, or
l7 906,477 MWh, higher than forecast. Actual market purchase
18 expenses were $25,257,952, ot l-68 percent, higher than
t9 forecast. The shortfal-I in hydro generation was also met
20 with increased coal generati-on at Bridger, where fuel costs
2L were higher than expected due to higher mining costs at
22 BCC. The higher mining costs were due mostly to issues
23 with underground mining equipment and associated safety
24 measures. Coal- generation was 5 percent, or 21-Lr346 MWh,
25 higher than forecast.
BLACKWELL, DI L]
Idaho Power Company
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0. Did the Company calcul-ate the Sales Based
Adjustment (*SBA") per the terms of the settl-ement
stipulation approved in Order No. 33307 in Case No.
r PC-E-1 5-1 5 ?
A. Yes. The Company's deferral report provided
as Exhibit No. 2 reflects the SBA per the methodology
approved in Case No. IPC-E-15-15. Beginning on line 10 of
Exhibit No. 2, the Company calculates the SBA using actual
Idaho jurisdictional billing month sales.
O. What is this year's True-Up of the True-Up?
A. This year's True-Up of the True-Up balance is
a charge to customers of $2,257,651-, as shown on row 1,1,7 of
the deferral expense report.
O. 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 $33,953,029 associ-ated with the
True-Up and the $2,257,651 associated with the True-Up of
the True-Up represents $36,210,680 of required coll-ection
from customers. This additional cost in large part
reflects that actual NPSE for the 20L6-2017 PCA Year was
greater than the forecast.
a. How does this year's combj-ned 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 $38,588,056, as compared
BLACKWELL, DI 18
Idaho Power Company
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to this year's amount of $36,210,680, a decrease of
$2,311,316.
C. PCA, Rate Determination.
O. How
the PCA for April
A. The
is the rate for the forecast portion of
20tB determined?2071 through
rate for the
March
10
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, di-vided by the Company's normalized system
firm sales; and (2) 100 percent of the difference between
PURPA-related expenses quantified in the Operating Pl-an and
those quantified in the Company's last approved update of
NPSE, divided by the Company's normalj-zed system firm
sal-es; and (3) 100 percent of the difference between the
Idaho jurisdictj-onal- demand response j-ncentive payments
quantified in the Operating PIan and those quantified in
the Company's last approved update of NPSE, divided by
Idaho jurlsdictional- firm sales.
O. What is the rate for the forecast portion of
the PCA for April 20L1 through March 2078?
A. The rate for non-PURPA expenses is 0.L794
cents per kilowatt-hour (*kwh"), whlch is cal-cul-ated by
multiplying $21 ,7 56,805 from Table I by 95 percent and then
dividlng it by the normalized system firm sales of
BLACKWELL, Dr 1,9
Idaho Power Company
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1 14,696,223 MWh (($27,156,805 * 0.95) / L4,696,223) :
2 $1.794/Mwh : 0.1194 cents/kwh). The rate for PURPA
3 expenses is 0.3257 cents per kwh, which is calcul-ated by
4 dividing $47,860,526 from Table 1 by the L4,696,223 MWh
5 ( $4'7 ,860 ,526 / L4,696,223 MWh : $3 .251lMWh : 0 .3257
6 cents/kwh). The rate for demand response incentive
7 payments is a negative 0.0215 cents per kwh, which is
I calculated by dividing the negative $3,850,567 from Tabl-e 1
9 by the Idaho jurisdictional firm sales of 14,010,286 MWh
10 (-$3,850,567 / 74,010,286 MWh: -$0.275lMWh: -0.0275
l-1 cents/k['Ih) . The forecast portion of the PCA rate is 0.4166
12 cents per kwh, which is calculated by adding the non-PURPA
13 expense of 0.7794 cents per kWh to the PURPA expense of
74 0.3251 cents per kWh to the demand response incentive
15 payment of negative 0.0275 cents per kwh (0.1194 + 0.3257 +
16 -0 .021 5 : 0 .477 6 cents/kwh) .
L7 0. How did you compute this year's True-Up rate?
18 A. As shown in Exhibit No. 2, this year's True-Up
l-9 component of the PCA is $34 mi1Iion, which, when divided by
20 the Company's forecast of Idaho jurisdictional- sal-es of
2l L4,010,286 MWh, results in a rate of 0.2423 cents per kwh
22 ($33,953,029 / 1,4,01-0,286 : $2.423/MWh : 0.2423 cents/kwh) .
23 The True-Up of the True-Up rate is calculated by
24 dividing $2,257,651, million (aIso from Exhibit No. 2) by
25 the forecast of Idaho jurisdictlonal sales of 74,01-0,286
BLACKWELL, DI 20
Idaho Power Company
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MWh, which results j-n a rate of 0.0161 cents per kwh
($2,257 ,651 / 74, 010 ,286 : $0. 1611/MWh : 0.0161 cents/fwfr) .
O. Does the quantified True-Up rate include the
sales of Renewable Energy Certiflcates (*REC" or "RECs")
and Sulfur Dioxj-de ("SOz") proceeds?
A. Yes. The RECs and SO2 proceeds are included
in the Company's deferral- expense report, provided as
Exhibit No. 2, in lines 47 and 48. Order No. 32002 issued
on June 1\, 2070, accepted for filing the Company's REC
Management Plan, which passes the customers' share of REC
benefits back to customers through the PCA. Order No.
32434 j-ssued on Janoary 72, 20L2, directed the Company to
pass SO2 proceeds through the PCA to help offset the
Company' s PCA deferral bal-ance.
O. What is the resuJ-ting PCA rate when you
combine all of the PCA components described previousJ-y?
A. The Company's PCA rate for the 2011-20L8 PCA
Year is detailed in Exhibit No. 3, column C. The unj-form
PCA rate is comprised of (1) the 0.4776 cents per kwh
adjustment for the 20L1-2018 projected power cost of
serving firm loads under the current PCA methodoJ-ogy and 95
percent sharing, (2) the 0.2423 cents per kwh for the 2016-
20L7 True-Up portion of the PCA, and (3) the 0.0161 cents
per kV'Ih for the True-Up of the True-Up. The sum of these
BLACKWELL, Dr 27
Idaho Power Company
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three components resul-ts in a 0.736L4 cents per kwh charge
for all rate cl-asses.
ITI. ADDITIONAT RATE ADiruSI!{ENTS
A. Revenue Sharing
0. When was the revenue sharing mechanism
originally established?
A. The revenue sharing mechanj-sm was originally
established in Case No. IPC-E-O9-30 and approved in Order
No. 30978, effective for the years 2009-2077. The revenue
sharing mechanism was modified and extended for the years
2012-2074 in Order No. 32424 in Case No. IPC-E-1L-22, and
was again modified and extended for the years 2075-20L9 in
Order No. 33149 in Case No. IPC-E-14-14.
O. What are the provisions of the current revenue
sharing mechanism?
A. In Case No. IPC-E-14-14, the Company filed a
motion to approve a settlement stipulation (*2014
Stipulation") extendlng the sharing mechanism, with
modifications, through the end of the 2019 fiscal- year.
The Commission approved the 20L4 Stipulatlon 1n Order No.
33L49.
Per the terms of the 2074 Stipulation, if the
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23 Company's actual-, year-end Return on Equity ("ROE") for the
' The sum of the three components will not tie out in testimony as
the rates are fisted to the fourth diqit. However, this rate wil-l- tie
to Exhibit No. 2, in which rates are rounded to six digits.
BLACKWELL, Dr 22
Idaho Power Company
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Idaho jurisdiction exceeds 10 percent, all amounts up to
and including a 10.5 percent ROE will be shared between
customers and the Company on a 75 percent and 25 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 10.5
percent, all amounts in excess of 10.5 percent will be
shared 50 percent with Idaho customers as a rate reduction
to become effective with the subsequent year's PCA, 25
fdaho customers in the form of
Company's pension balancing
be apportioned to the Company.
10 percent will be shared with
11
t2 25 percent will-
13 regard to the amortization of Accumulated
BLACKWELL, DI 23
Idaho Power Company
an offset to
account, and
wirh
amounts in the
74 Deferred Investment Tax Credits (*ADITC"), the 2014
15 Stipulation allows the Company to accelerate the
16 amortization of ADITC to achieve a maximum 9.5 percent
L7 fdaho jurisdictional ROE if the Company's year-end actual
18 resufts faII below that amount in any si-ng1e year between
79 201,5 and 2019. The extensi-on l-imits total cumulative
20 accel-erated amortization of ADITC to $45 million over the
21 2015-20L9 time period, wj-th no more than $25 millj-on to be
22 accelerated in a single year.
23 O. Have you provided an exhibit that summarizes
24 the terms of the current sharing mechanism?
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Y
A.
depiction of
various ROE
o.
Yes. Exhibit No. 4 contains a graphical
the current sharing mechanism, detailj-ng the
thresholds and sharing provisions
Did the revenue sharing mechanism resul-t in
any action following the 2009-20L5 fiscal years?
A. Yes. The Company's earnings in each year from
2071 through 20L5 resulted in revenue sharing with
customers totaling $121.2 mi11ion, either as a direct rate
offset in the PCA or as an offset to amounts that would
10 have otherwise been col-Iected in rates. These amounts are
11 detail-ed i-n Table 5 below
L2
13
74 0. Did the Company's year-end 201,6 financial
results warrant any action related to the existing sharing
agreement per the terms of the 2014 Stipulation?
A. No. The Company's year-end 20L6 financial
results yielded an actual fdaho jurisdictional- ROE of 9.53
percent, falling below the 10 percent ROE threshold for
revenue sharing, and thus resulting j-n no revenue sharing
wlth customers.
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BLACKWELL, DI 24
fdaho Power Company
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Table 5 ZX)!['2015 Revenue
Line No.Revenue zxJpmtt mx2-?0.4 n15
Total
zD$201s
S45 MiIion
9.5/o
L0.5%
N/A
545 Million
L0.Wo
N/A
l0.Vo
Sa.zSzz.a
Account .8
Szt.t
Sharing5G50Threshold
lable ADITC For Use
ROE Threshold
Offset to Pension
7!25 Sharing Ihreshold
Customer Benefits ($ Millions)
Reduction to Rates
8 *t.tTotal s70.5 $s.z $nt2
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O. Did the Company utj-lize the same methodology
to determine the Idaho jurisdictional- 20L6 year-end ROE
that was used in prior PCA filings?
A. Yes. The methodology used to determj-ne the
Company's Idaho jurisdictional 2076 year-end ROE is
consistent with the methodology used for the year-end ROE
determinations since the inception of the mechanj-sm.
O. Do you have an exhibit demonstrating the
application of this methodol-oqy?
A. Yes. Exhibit No. 5 provides a step-by-step
cal-cul-ation of the Idaho jurisdictional ROE based on year-
end 201-6 financial results util-izing the Commission-
approved methodology from previous PCA filings.
B. Energy Efficiency Rider Transfer.
O. fs the Company proposing the continuation of
the approxi-mate $4 million Rider transfer adjustment that
was incfuded in the 2014, 207,5, and 2016 PCA filinqs?
A. No. The Company excluded the annual $+
million Rider transfer through the PCA, in compliance with
Commisslon Order No. 33736 in Case No. IPC-E-16-33. In
Case No. IPC-E-16-33, the Company proposed a decrease to
the coll-ection percentage of the Rider from 4 percent to
3.75 percent of base rate revenues, the el-imination of the
annual $4 million Rlder transfer through the PCA, and a $13
BLACKWELL, DI 25
Idaho Power Company
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1 million refund of previously collected Rider funds to be
2 included in the 20!1-20\8 PCA.
3 O. Please explain why the $4 million annual Rider
4 transfer is being e1j-minated.
5 A. The $a mil-lion annual Rider transfer was
6 origlnally established in Case No. IPC-E-13-20 and approved
7 1n Order No. 33000. The Rider transfer was implemented to
8 offset the increase in Rider revenue associated with an
9 increase in the Company's base 1eve1 NPSE of $99.3 million.
10 At that time, Idaho Power's Rj-der collection was 4 percent
11 of base rate revenues. Therefore, the approval to increase
1,2 the Company's base rate revenues by $99.3 mil-l-ion resul-ted
13 in the Company col-lecting approximately $4 million per year
14 of additional Rider funds. To ensure the base rate
15 increase associated wlth the new base Ievel of NPSE
16 remaj.ned revenue neutral- for all- cl-asses of customers, it
L7 was appropriate to offset the increase j-n Rider revenue by
18 moving $4 million out of the Rider balancing account and.
19 providing that amount as a credit to customers through the
20 PCA.
27 Because the Rider collection percentage has been
22 adjusted from 4 percent to 3.75 percent, the goal of
23 revenue neutrality included in Order No. 33000 j-s no longer
24 applicable. As such, Idaho Power wil-I eliminate the $a
25 million annual- Rider transfer through the PCA mechanism
BLACKWELL, DI 26
Idaho Power Company
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effective June L, 2077, consj,stent with Commj-ssj-on Order
No. 33736.
O. What is the reason for the $13 million refund
of Rider funds?
A. At the end of 20L6, the Rider balancing
account had a collected bal-ance of approximately $10.7
mi11ion. In Case No. IPC-E-16-33, Idaho Power proposed a
$1-3 million refund to help mitigate further accumulation of
surplus Rider balances while stil-l providing adequate
funding for the recovery of all prudently incurred costs
related to the pursuit of cost-effective energy efficiency
for the 2071-2020 time periods. The partles concluded that
$13 million was an appropriate estimation of the amount
that should be refunded, and that the Company's requested
June L, 201,7, refund date is suitable.s The Commission
approved the $13 million refund of previously coll-ected
Rider funds through the PCA in Order No. 33136.
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prevj-ously
A.
How wifl the
collected Rider
Company refund the $13 million in
funds?
The refund will be a]located to individual
27 customer classes based on each cl-ass's proportional share
22 of forecasted base revenues for the June L, 201,1, through
23 May 37, 2078, PCA col-l-ection period. This allocation
s In the Matter of the AppTication of ldaho Power Company for
Authority to Revise Tariff ScheduLe 97 - The Energy Efficiency Rider,
Case No. IPC-E-16-33, Order No. 33736 at 3 (March 28, 20L7) .
BLACKWELL, DI 27
Idaho Power Company
1 method ensures that each customer class receives the Rider
2 rate credit in a similar proportion to the initial Rider
3 collection.
4 Q. Have you prepared an exhibit detailing the
5 class al-location utll-izing this methodology?
6 A. Yes. Exhibit No. 6 details the class
7 all-ocation of the $13 million Rider refund. As displayed
8 in column G of Exhibit No. 6, each customer class receives
9 a decrease of approximately 1,.27 percent relative to
10 current base revenues.
11 IV. RATE SI'M!{ARY E}ID ![ET CUSTOMER IMPACT
L2 O. Has the Company provided an exhibit detailing
13 the final rates requested to become effective June 7, 20L1,
14 incl-uding the PCA components and Rider refund?
15 A. Yes. Col-umn D of Exhibit No. 3 contains the
16 final rates for each customer class proposed to become
L7 effective June L, 2077, through May 31, 2018. These rates
18 include the standard PCA rate of 0.7361 cents per kwh, and
t9 each class's al-l-ocation of the Rider refund component.
the requestedof20 O. What is the revenue impact
2L PCA rate combi-ned with the Rider refund
22 PCA rates currently in effect?
23
24
when compared to
A. Attachment 2 Lo the Applj-catj-on fil-ed
contemporaneously herewith provj-des a detailed description
of the overall revenue impact of this filing on each
BLACKV{ELL, Dr 28
Idaho Power Company
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o.Have you prepared a table that details the
$10.6 million revenue impact by component?
A. Yes. Tab1e 6 below separates the $10.6
mil-l-ion increase into each component included in the
Company's proposed rates.
customer cl-ass. As shown on Attachment
requested PCA rates to expected customer
2071 through May 2018 test year results
of $10.6 mill-ion.
2, applying the
sales for the June
in a PCA increase
revised Schedule 55 that
to the Application is a
10
11
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13 incl-udes the
L4 A
Have you prepared a
proposed PCA rates?
Yes. Attachment 1
15 revised Schedule 55 and includes the proposed PCA rates in
t6 clean and legisl-ative formats.
6 Because Tabfe 6 contains the expected bill-ed revenue impact to
customers, the *20L6-2071 PCA" column refl-ects approved 2076-2011 PCArates appJ-ied to the June 201-7 through May 2018 sal-es forecast, and
wil-l- not tie to the specific dol-lar amounts approved in the 2016 PCA
filing.
7 The *201-1 -201-8 PCA- cofumn refl-ects the Company's proposed rates
applied to the June 2017 through May 2018 forecast, and may not tieexactly to the figures l-isted in the above testimony due to the
rounding of rates to sj-x digits.
BLACKWELL, Dr 29
Idaho Power Company
Eable 6 R€venue Iupact by Conponent
Lin€ No. Rate CoEponent 2016-2012 peA6 zofi-zota pd Difference
L
2
3
4
5
PCA Eorecast
PCA True-Up
Revenue Sharing
EE Rider Annual Transfer
EE Rider Refund
$ 4'7 , 943 ,199
$ 38,738,44L
$ (3,155,010)
$ (3,985,530)
s0
$ 66,9L3,726
$ 36,2L6,590
$0
$0
$ (13,000,000)
$ 18,969,927
s Q,52L,85L)
$ 3,155,010
$ 3,985,530
s (13,000,000)
6 PCA Total $ 79,5{1,100 $ 90,L29,7L6 $ 10,588,615
1
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0
computation of the
A. Yes.
Should the Commission approve the Company's
PCA rates?
The Commission shoul-d approve the
of the PCA rates. The cal-culation of
10
Company's computation
the PCA rates fol-lows the methodology that was approved in
Order Nos. 30715, 33L49, and 33307.
O. Does thls conclude your testimony?
A. Yes, it does.
BLACKWELL, Dr 30
Idaho Power Company
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AETESTATTON OF TESTIMONY
STATE OF IDAHO
SS.
County of Ada
Tt Nicol-e A. Blackwell, having been duly sworn to
testify truthfully, and based upon my personal knowledge,
state the following:
I am employed by Idaho Power Company as a Regulatory
Analyst I in the Regulatory Affairs Department and am
competent to be a witness in this proceeding.
I declare under penalty of perjury of the l-aws of
the state of Idaho that the foregoing pre-filed testimony
and exhibits are true and correct to the best of my
information and belief.
DATED this 14th day of April 20L7.
d
Nic o e A. Bla
SUBSCRIBED AND SWORN to before me this 14th day of
24 April 2071.
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S tNotary Pub l_c for Idaho
Residing at:Boise Idaho
My commissj-on expi-res z 02/04/2
BLACKVIELL, DI 31
Idaho Power Company
)l
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
GASE NO. IPC-E-17-06
IDAHO POWER COMPANY
BLACKWELL, DI
TESTIMONY
EXHIBIT NO. 1
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Exhibit No. 1
Case No. IPC-E-17-06
N. Blackwell, IPC
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BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
GASE NO. IPC-E-17-06
IDAHO POWER COMPANY
BLACKWELL, DI
TESTIMONY
EXHIBIT NO.2
Exhibit No. 2
Case No. IPC-E-17-06
N. Blackwell, IPC
Page 1 of2
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Exhibit No. 2
Case No. IPC-E-17-06
N. Blackwell, IPC
Page 2 of 2
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
GASE NO. IPC-E-17-06
IDAHO POWER GOMPANY
BLACKWELL, DI
TESTIMONY
EXHIBIT NO.3
ldaho Power Company
Total PCA Rate Calculation
Class Allocated EE Rider Refund
State of ldaho
Sales Based Adjustment Rate Methodology
(A)(B)(c)(D)
PCA per kwh EE Rider Refund +
Rate PCA Rate
Rate
Sch.
No.
Allocated EE Rider
Refund
EE Rider Refund
Dollars per kWh
RateLine
No Tariff Description
Uniform Tariff Rates:
1 Residential Service
2 Master Metered Mobile Home Park
3 Residential Service Energy Watch
4 Residential Service Time-of-Day
5 Small General Service
5 Large General Service - Secondary
7 Large General Service - Primary
8 Large General Service - Transmission
9 Dusk to Dawn Lighting
10 Large Power Service - Secondary
7L Large Power Service - Primary
t2 Large Power Service - Transmission
13 Agricultural lrrigationService
74 Unmetered General Service
15 Street Lighting
16 Traffic Control Lighting
L7 Total Uniform Tariffs
18 Soecial Contracts
19 Micron
20 J R Simplot
27 DOE
23 Total Special Contracts
1
3
4
5
7
9S
9P
9T
15
19S
19P
197
24
40
4t
42
26
29
30
(Ss,7s8,844)
(S4,s64)
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$1s4,762]'
(52,837,2371
(S3se,186)
(Sz,sos;
(s1s,s32)
$4,74s]|
(s1,433,307)
(S20,443)
$7,7s4,0741
(Slr,oss1
($+:,aoo1
(S1,ee7)
(0.001148)
(0.001097)
0.000000
(0.001107)
(0.001453)
(0.000864)
(0.0007s0)
(0.000846)
(0.002486)
(0.000746)
(0.000661)
(0.00062s)
(0.000939)
(0.001032)
(0.001633)
(0.000730)
So.oo7351
So.oo7351
So.oo7361
s0.007361
s0.007361
s0.007361
So.oo7351
So.oo7361
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s0.007361
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s0.00s898
So.oo6497
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s0.006700
So.006736
s0.006422
s0.006329
s0.00s728
s0.005531
(S12,4s8,400)
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(s118,s93)
(0.000s79)
(0.000s43)
(0.000s6s)
s0.007361
s0.007361
s0.007361
s0.006782
s0.006818
So.006796
(Ss41,5oo)
(s13,000,000)24 Total ldaho Retail Sales
Note:
June 1, 2017 - May 3L,20LB Forecasted Test Year
Exhibit No. 3
Case No. IPC-E-17-06
N. Blackwell, IPC
Page 1 of 1
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
GASE NO. IPC-E-17-06
IDAHO POWER COMPANY
BLACKWELL, DI
TESTIMONY
EXHIBIT NO.4
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Exhibit No. 4
Case No. IPC-E-17-06
N. Blackwell, IPC
Page 1 of 1
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BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
GASE NO. IPC-E-I7-06
IDAHO POWER COMPANY
BLACKWELL, DI
TESTIMONY
EXHIBIT NO.5
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IDAHO POWER COMPANY
ADDITIONAL INVESTMENT TAX CREDIT ANALYSIS
For tho Twolve Month3 Ended Decembor 31, 2016
Adul D*mhr fi- ml3
IYIIEI
TOTAL
SIro rsHe tslol
D€VELOPTENT OF NET INCOME
TOTAL COMBINED UTE USE 3,1 79,,13.4,05.t
203,521,737 136,110,762
tlaHo
3,0.r5,,461,191
ISrO-t
95.E%
95.0%
95.E%
95.9%
93.1%
66.6%
95.896
95.8%
,00.0%
97.7%
OEMTING REENUES
RETAIL$LES REWNUES (ld 4S 1 Rd)
OTHER OPEMTING REWtrUES
fOTAL OPEMTING ffiWNUES
88!t,484,371
2,905,320
963,391,091
Eis,lE4,2oil Dircd A$iOn
73,623.62 9/t.s96
91E,E07,266
1,145,993,1 72
109,305,628
1,255,298,799
1,092,721,318 OiEdAssion
103.2€7,371 9,a.5%
1,19€.018,692
OPERATING ilPENSES
OPEMTION & MAINTEMNCE SPENSES
DEPRECIATION ilPENSE
AMORTIANON OF LIMITEDfERM PBNT
TSES OIHER TUN INCOME
REGUUTOtr DEBITSCREDITS
PROUSION FOR EFERRED INCOME TAES
INWSTM&T TA CREDIT OUSTIENT
FEDEW INCOYE filES
STATE IrcOME IAES
TOTAL OPEMTNG EXPENSES
603,422,334
10'1,14,t,655
5,021,210
25,227,v1
931,E16
,|6,1,r0,687
(359,920)
1 1,953,592
,l,35o,ogo
70E,132,007
573,011,a62
97,1$,437
4,613,r6E
23,175,125
a)6,S15
15,/ta9,31!7
(3,1,4.671 )
11,953,502
1,250,18
730.561.,413
761,32S,530
130,016,5E7
6,326,753
30,5it3,649
1,075,35i1
30,5E2,,40E
252,16
($,137)
3,575,193
963,645,5S2
801,734,623
135,76E,850
6,800,189
32,E23,311
1,242,422
31,909,741
304,915
(9€,137)
3,659,280
1,013,947,400
95.0%
95.6%
95.9%
93.1%
E6.6%
95.6%
95.E%
't(x).0%
97 7*
! OreilTING INCOME
.1 ADD: IERGOOPEMTITINCOME
I 95,259,0Eu1
E,262,053
1E6,225,653
7,68ii,930 S5.,0%
241,351,399
7,993,520
232,373,100
7,62E,650
NET INCOME
OPEMTING INCOME BEFORE OTHER INCOME AND DEDUCTIONS
AoO: AFUm EQUIW
ADOI OTHER INCOME ANO DEOrcIIONS
INCOME BEFORE INTEREST CURGES
LESS: INTEREST cfficES
249,314,925
22,030,422
(294,063)
240,001.759
21,102,311
(2E3.0E,1t
90.3%
95.E% (L t0)
s0.3% (L 33)
271,081,181
81,839.502
260,E21.04
78,391,0€2
95.,0%
95.E% (L 10)
142,129,51
s5.6% (110)
s.53%
(612,220) (L4eL4) / (J-9.s%)
1A1,A17,711
1,913,870.989
1E9,211,922
9.17%
ACTUAL YAR.ENO RESULTS. AEFORE ITC ANUSfTENT
ARNIreS ON COMMON STOCK
COMMON EAUIfl AT YAR ENO
1E5,211.922
't ,9s6 ,703 ,227
182,125,!&1
1,91,1,a83,209
RETURN ON YAR.END COMMON EOUITY
ilRNrreS ON COMMON ST@K@ 9.50 ROE
aRNtres oN coMMoN sTocK@ r0 RoE
aRNrres oN coMMoN sTocKe r0 50 RoE
ACTUAL YAR-ENO RESULTS. AffER ITC AOJUSTMENT
INESTMENT TA CREDIf ADJUSTMENT
ADJUSIED ARNINGS ON COMMON STO*
ADJUSTED COMMON EQUIryAT YAR.END
ADJUSTED RETURN ON YAR-END COMMON EOUIW
189,870,807
199,E70,323
20s,663,839
16r,175,9rr5 (144.9.5%)
l9l,{4t,321 (L,a,r' l0%)
2o1,o2o,737 (L,aia' 10.5%)
lF IDAHO RETURN ol{ COMMON EOt ITY (LiD la) <9594
ADOITIOML ITC ADJUSTMENT (Annuelizd) ll L g is n{dvq S.n 0i il pdtv., h6 6mdlr d 154 d t25,m,@0
lF IDAHO RETURN ON COMMON ECUTTY (LimiL) >lr
IDAHO ffiNINGS GRATER Tffi 10* ROE BUT LE$ THAN 10.5%
0
0 (14!L4S)41-10%)
lF IDAHO RETURN OI{ COMMOI{ EOrrrY (um 46) >10.5!a
INCREMENTAL IDAHO URNINGS GRilTER TUN 10.58 ROE o (143-150y(1-10.5%)
PGr OnLr #33149:
RoE btus 10*t0 5% -cusToMER SHARE - 75% (Rdudonto rat6)
ROE btuM 10%-10.5% -COMPANY SHARE - 25%
RoE Edssan 10.5% (lncrumffiD - CUSToMER SHARE - 50% (R€dudon to rd6)
ROE gd6 h$ 10.5% (lnq.mabD - CUSTOMER MRE - 25% (OMb Pdon b.lsc!)
RoE sd6hil 10.5% {ln6.mnbD -COMPAW SHARE - 25%
A[er Td
0
0
0
0
Exhibit No. 5
Case No. IPC-E-17-06
N. Blackwell, IPC
Page'l of 1
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
GASE NO. IPC-E-17-06
IDAHO POWER COMPANY
BLACKWELL, DI
TESTIMONY
EXHIBIT NO.6
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Exhibit No. 6
Case No. IPC-E-17-06
N. Blackwell, IPC
Page 1 of 1
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