20180412Blackwell Direct.pdf

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CASE NO. ]PC_E-18-06
u.i':q
BEEORE THE IDAHO PUBLIC UT]LIT]ES COMM]SS]ON
IN THE MATTER OE THE APPLICATION
OF IDAHO POWER COMPANY FOR
AUTHORITY TO ]MPLEMENT POWER
COST ADJUSTMENT (*PCA") RATES
FOR ELECTRIC SERVICE FROM JUNE
7, 2018, THROUGH MAY 31, 2019.
IDAHO POWER COMPANY
DIRECT TESTIMONY
OF
NICOLE A. BLACKWELL
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Y
O.PIease state your name, busi-ness address, and
present position
"Company").
A. My
address is 1227
am employed by Idaho Power
Regulatory Affairs Department.
O. Pl-ease describe
A. In May of
1n Flnance and
2070,
degrees
Idaho.
Economics
with Idaho Power Company ("Idaho Power" or
name is Nicol-e A. BIackweIl. My business
West Idaho Street, Boise, Idaho 83102. I
as a Regulatory Analyst in the
your educational background.
I received Bachelor of Science
10
I have also attended "The
from the University of
Basics: Practical11
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2L
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Regulatory Training
utility ratemaking
University's Center
Fundamentals & InsighLs," an
offered through the Western
Utility System Operatiofls, "
offered through Professlonal
O Please describe
for the Electric Industryr " an electric
course offered through New Mexico State
for Public Utilities, "Electric Utility
electrj-c utility course
Energy Institute, and "Electric
an efectric utility course
Training Systems, Inc.
your work experience with
Idaho Power.
A. In January 20L6, I accepted my current
position at Idaho Power as a Regulatory Analyst 1n the
Regulatory Affairs Department. As a Regulatory Analyst, I
provide support for the Company's regulatory activities,
BLACKWELL, DI 1
Idaho Power Company
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1 incfuding compliance reporting, financial analysis, and the
2 development of revenue forecasts for regulatory filings.
3 Q. What is the Company requesti-ng in this case?
4 A. The Company is requesting approval of its
5 quantiflcation of the 2078-2019 PCA rates to become
6 effective June L, 2078. If approved, the 20LB-2019 PCA
7 will resuft in a decrease in total billed revenue of
B approximately $22.6 million, or negative 1.90 percent.
9 Q. How is your testj-mony organized?
10 A. My testimony is comprised of four sections.
11 In the first section, I wiII provide an overview of the
72 PCA. In the second section, I wil-l detail the 2018-2019
13 PCA amount, identify and discuss the main factors
74 contributing to this amount, and present the quantification
15 of the 20L8-20L9 PCA rates to become effective June l,
76 201,8. In the third section, I will discuss additional PCA
11 components related to revenue
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sharing, and the Company's
Energy Imbalance Marketparticipation in
("EIM") . fn the
the Western
final section of my testimony, I will
of the 201,8-2019 PCA rates20 detail the net customer i-mpact
27 if approved.
22
Z3
24 the mechanism functlon?
a
I. PCA O\IERVIEI{
What is the purpose of the PCA and how does
BLACKWELL, DI 2
Idaho Power Company
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A. The PCA is a rate mechanism that quantifies
and tracks annual differences between actual Net Power
Supply Expenses ("NPSE") and the normalized or "base level-"
of NPSE recovered in the Company's base rates, resulting in
a credit or surcharge that is updated annually on June 1.
The PCA mechanism utilizes a 12-month test period 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 PIan and base level
NPSE recovered in the Company's base rates. The True-Up
compares actual- PCA account resul-ts to actual- power cost
col-l-ections for the prior PCA year. The True-Up contains a
second component that tracks the collection of the prior
year's True-Up amount, referred to as the "True-Up of the
True-Up. "
With the exception of
7918 (*PURPA")
PubIic Utility Regulatory
19 incentive payments, the PCA allows the
and demand response
Company to pass
annual differences20through to
in actual
customers 95 percent of the
27 NPSE as compared to base
or negative. With respect
level- NPSE, whether
22 positive
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18 Policies Act of expenses
to PURPA expenses and
actual annuaf
the Company is
the difference for
23 demand response incentive payments, ds
l-evel NPSE,devi-ate from base
to pass through 100 percent of
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expenses
allowed
BLACKWELL, DI 3
Idaho Power Company
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recovery or credit through
by the
from thebenefits resulting
approved by the Idaho Publ1c
rate mechanlsm used
("Commj-ssion" ) in
O. What
NPSE?
the PCA. The PCA is al-so the
Company to provide direct
revenue sharing mechanism
Utilities Commission
33149.
Account 555, Purchased Power,'
of Electrlcity
( typically
by Others; and
Order No
10
are the components of the PCA base level
A. The PCA base level NPSE incl-udes the following
Federal Energy Regulatory Commission ("EERC") accounts:
Account 501, Fuel (coal-); Account 536, Water for Power;
11 Account 547, Fuef (gas);
12 Account 565, Transmission
13 Account 44'l , SaIes for Resal-e referred to as
14 surplus sales).
15 The PCA base level- expense component for FERC
76 Account 555 includes costs resulting from both PURPA and
L7 non-PURPA (market) purchases. Per Order No. 32426, the
18 Company adjusts FERC Account 555 to incl-ude demand response
79 incentive payments that the Company provides to customers
20 for participating in any of its three demand response
2I programs.
22 rr. 20L8-20L9 PCA
23 What 1s the total PCA collection that would
24 result under the 2018-2019 PCA rates proposed by the
25 Company in this case?
BLACKWELL, DI 4
Idaho Power Company
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A The total PCA collecti-on that would result
under the 2078-2079 PCA rates proposed in this case is
$69.4 miIIion. This represents
revenue of $22.6 mlI]ion for the
of 1.90 percent.
A. PCA Forecast.
a decrease in total billed
upcoming year, a decrease
o What is the Company's determination of the
system-Ieve1 difference between currently approved base
Ievel- NPSE1 and the forecast of NPSE for the 2078-2079 PCA
10 Year?
11 A. The system-level forecast of NPSE for the
1,2 2018-20L9 PCA Year is $403,075,273, which is $97,390,404
13 higher than the currentl-y approved base level NPSE of
!4 $305,684,869. Table 1 be1ow presents the system-Ievel
15 differences between currently approved base l-evel- NPSE and
L6 the forecast of NPSE for the 201,8-20t9 PCA Year by EERC
l'l account.
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1 Approved on March 21, 2014, Order No. 33000
BLACKWELL, DI 5
Idaho Power Company
Table 1 201&2019 PCA FORECAST (Total System)
Line No.FERC Account Base NPSE Forecast Difference
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2
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4
5
6
95% Sharing Accounts
Account 501, Coal S
Account 536, Water for Power S
Account 547, Other Fuel S
Account 555, Purchased Power Non-PURPA S
Account 565, 3rd Party Transmission S
Account 2147, Surplus Sales S
108,s03,180 s
2,3ffi,s97 s
33,367,s63 s
62,@6,593 s
5,455,955 s
(51,735,153) s
t25,477,505 s0s
37,ffi9,237 s
67,654,802 s
5,435,4M s
(25,523,2961 s
16,974,325
{.2,3&,s97l,
4,24L,674
5,@8,2()!)
(20,ss1)
26,2tt,8s7
7
8
100% Sharing Accounts
Account 555, PURPA S
Account 555, Demand Response lncentives S
133,853,869 s
t1,252,255 s
s r0o,sze,zes 5 2t0,6s3,6s2 5 so,oru,gn
185,019,923 s
7,40t,698 s
51,166,0v
(3,8s0,s67)
9 Total s aos,6s4,e6g 5 nt,ots,ztE 5 gt,zgo,qu1
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v What is the basls for the forecast of NPSE for
the 2018-2079 PCA Year?
-H.The forecast of NPSE for the 20lB-20L9 PCA
Year is based on the Company's March 29, 20L8, Operating
Plan.
o How is the NPSE forecast developed for the
Company's Operating Plan?
A. The Operating PIan is prepared monthly and
represents a forecast of the Company's monthl-y NPSE for the
following 1B-month period; however, for the PCA, the
Company incl-udes only the 12 months that correspond to the
PCA Year. The Operating PIan 1s developed by simulating
the dispatch of the Company's generation resources for each
month, segmented by heavy Ioad and light l-oad hours. The
dispatch considers a current forecast of forward market
energy prices, available hydro generation, coal and natural
BLACKWELL, DI 6
Tdaho Power Company
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I gas prices, and any existing hedge transactions. The
2 system load forecast is then analyzed against the resulting
3 monthly heavy load and J-ight load dispatch to determine a
4 monthly load and resource bal-ance. Any identified resource
5 deficiency is assumed to be fifled with market energy
6 purchases. Economically dj-spatched generation above the
7 system load forecast represents surplus energy sales. The
8 forecast of monthly NPSE and generation for the 20LB-2019
9 PCA Year, as determined in the Company's March 29, 201,8,
10 Operating Plan, 1s provided in Exhibit No. 1.
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o.
the 2078-20L9
PCA?
A.
How does the Company's forecast of NPSE for
PCA compare to the forecast from last year's
Table 2 compares this year's 2078-2079 PCA
15 forecast to last year's
16 detai1ed in this table,
PCA forecast by EERC account. As
the PCA forecast on a total system
77 basis for the 2078-2079 PCA Year 1s $403,075 t273, which is
18 $25,623,641 higher than l-ast year's forecast amount of
19 $377 ,457,632.
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BLACKWELL, DI 1
Idaho Power Company
Table 2 PCA Forecast Comparison Expenses (Total System)
Line No.FERC Account
mL7-20L8
Forecast
201&2019
Forecast Difference
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6
95% Sharine Accounts
Account 501, Coal s rzo,zog,sos 5 72s,477,s0s s (1,291,998)
Account 536, Water for Power S
Account 547, Other Fuel S
Account 555, Purchased Power Non-PURPA S
Account 565, 3rd Party Transmission S
Account 2147, Surplus Sales S
37,305,583
s2,6Ls,287
6,OL7,O2s
(34,371,8s8)
s
s
s
s
s
37,609,237
67,654,802
5,435,M
(2s,s23,296)
s
S
s
s
s
303,6s4
15,039,515
(s81,621)
8,848,s63
7
8
s 188,33s,s40 s 210,6s3,6s2 5 22,3L8,rL2
100% Sharins Accounts
Account 555, PURPA S
Account 555, Demand Response lncentives S
787,7L4,395 s
7,qt,698 s
185,019,923 s
7,N7,698 s
3,305,529
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s
s
189,116,093 S
s
t92,42L,62t s
s
3,305,528
Total PCA Forecast 377,45L,632 4O3,075,273 25,623,il71
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a. What general conclusions can be drawn from the
information contained 1n Tabl-e 2?
A. When viewed by category, the 95 percent
sharing accounts represent an increase of approximately
$22.3 mill-ion from last year's forecast, while the 100
percent sharing accounts represent an increase of
approximately $3. 3 mil,l-ion over l-ast year' s forecast.
O. What factors are contributing to the major
differences presented in Tabl-e 2?
A. At a high level, because of a reduction in
forecast hydro generation, the Company's expectation of
surpl-us sal-es revenue decreased as compared to l-ast year' s
forecast. The decrease in forecast hydro generation is
being met primarily with market purchased power. Finally,
the Company's forecast of coal fuel expense is down
BLACKWELL, D] B
Idaho Power Company
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1 slightly from the prlor year, which is partially offset by
2 increased natural gas expense.
3 Q. Pl-ease elaborate on the changes in the 95
4 percent sharing accounts for this year's forecast as
5 compared to last year's forecast.
6 A. As mentloned, the reduction in forecast hydro
7 generation is impacting the Company's forecast of surplus
8 sal-es revenue, which decreased 26 percent as compared to
9 last year, from $34,371,858 to $25,523,296.
10 The reduction in forecast hydro generation is also
11 increasing the rel-iance on market purchased power. As
12 shown on Table 2, non-PURPA purchased power expense
13 increased by $15,039,515, or 29 percent, as compared to
74 l-ast year. The increase in forecast non-PURPA purchased
15 power is primarily re1ated to market purchased power
76 expense, which increased $L2,974,340, from $70,285,528 to
11 $23,799,868. WhiIe additional market purchases are
1B expected to partially replace the reduction in forecast
19 hydro generation, for the 20LB-2079 PCA year the average
20 forecast market purchase price is $21.83 per megawatt-hour
2L ("MWh"), as compared to $25.52 for last year's PCA
22 forecast. The l-ower average market purchase price helps to
23 mitigate the increased re1iance on market purchased power
24 and the associated increase in forecast market purchased
25 power expense.
BLACKWELL, DI 9
Idaho Power Company
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decreased
last year.
offset by
$303 ,654,
accounts,
compared
increase,
O. What factors are contributing to the change 1n
the 100 percent sharing accounts?
A Wlth regard to the 100 percent sharing
$3.3 million as
Forecast fuel- expense at
about 1
the Company's coal plants
percent, ds compared to
fuel- expense is partially
expense, whi-ch is up
$7,29L,99B , or
The decrease in coal
increased natural gas
or about 1 percent.
forecast PURPA costs increased by
to l-ast year's
while forecast
10 forecast, reflecting a 2 percent
11 demand response incentive payments
72 did not change.
O. fs the increase in forecast PURPA costs
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related to increased generation output from PURPA projects?
A. No. Table 3 details changes between last
year's PCA forecast and this year's PCA forecast with
respect to forecasted generation in MWh. As shown in Tabfe
3, PURPA generation is antlcipated to remain relatively
flat with last year, decreasing by 9,428 MWh, or less than
1 percent. The increase in PURPA expense is largely the
result of price escalation in PURPA contracts.
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BLACKWELL, DI 1O
Idaho Power Company
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Table 3 PCA Forecast Comparison Generation (Total System-MWh)
Line No.FERC Account
20L7-20L8
Forecast
201&2019
Forecast Difference
1
2
3
4
Hydro 8,79s,879 7,902,57L (893,369)
95% Sharins Accounts
Account 501, Coal
Account 547, Other Fuel
Account 555, Purchased Power Non-PURPA
3,939,630
7,s39,407
899,3s9
3,473,907
1,900,54s
L,s84,227
(46s,7221
361,138
684,868
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95% Sharing Accounts ls,t74,27s 14861,190 (313,085)
100% Sharing Accounts
Account 555, PURPA 2,971,248 2,XJI.,820 19,4281
6
100% Accounts 2,971,248 2,901.,820 (9,428)
Total Generation 18,08s,s23 77,763,0t0 (322,513)
7
95% Sharing Accounts
Account 2147, Surplus Sales 2,165,061 7,522,W2 (642,978)
8 Total Load 7s,920,462 t6,240,928 320,4651
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6
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O. What other general conclusions can be drawn
from the i-nformation in Tabl-e 3?
A Hydro
or 10
generation is expected to decrease by
893,369
hydro qe
surplus
decrease
MWh,percent from last year.
the primary driver for
The decrease in
neration is the decrease in
sales volumes of 642,918 MWh, or 30 percent. The
being met
purchases, which
as compared to
in expected hydro generation is
10 primarlly wlth increased non-PURPA power
increased by 684,868 MWh, or 76 percent,11
72 last year' s forecast. Again, the j-ncrease in
power purchase volumes is prlmarily related to
non-PURPA
13 market power
MWh to74purchases, which increased
L,062,901 MWh.
659,854 MWh, from 403,041
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BLACKWELL, DI 11
Idaho Power Company
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Coal- generation is expected to decrease by 465,122
MWh, or 1,2 percent. Due to l-ow natural gas and market
prices, generation at the Company's coal plants is being
displaced and the ability to economically dispatch the
plants for surplus sal-es has decreased. Consequently,
forecast natural gas generation increased 361,138 MWh, or
23 percent, ds compared to last year.
O. What is causing the decrease in expected hydro
generation of 893,369 MWh?
A. The decrease in expected hydro generation is
primarily the result of lower projected inflows j-nto
Brownlee Reservoir ("Brownlee"). The March Operating Pl-an
13 used in this year's PCA forecast projects April through
1 mlflion acre-feet74 JuIy inflows into Brownlee of 5
10
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15 ("MAE"). This
lower than the76
L] forecast.
last year's
conditions,
2l
increased hydro
months.
22 o.
generation
inflows at
23
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is approximately 3.2 MAF, or 39
8.3 MAF used to determine last
Expected inflows into Brownlee were
PCA forecast as a result of better
which provide for sustained runoff
percent,
year's PCA
higher for
snowpack
and
generati-on durlng the spring and summer
Why is the decrease in forecast hydro
not proportional to the decrease in expected
Brownlee as compared to last year?
BLACKWELL, DI 12
Idaho Power Company
1 A. Although forecasted inflows into Brownlee are
2 39 percent lower for the months of April through July as
3 compared to last year, total forecast generation is only 10
4 percent lower than Last year. This is primarily due to
5 lower fl-ood risk management elevation targets for Brownlee
6 and strong carryover from last year.
7 In 20L1, high j-nf l-ows into Brownlee occurred during
B the spring months. Concurrent with hiqh inflows, Brownlee
9 was required to meet fl-ood risk management el-evation
10 targets in ApriJ-, then undergo refill coordinated with the
11 U.S. Army Corp of Engineers. For April 30, 2011, the
72 forecasted elevatlon target for Brownlee was 2,01-7 feet,
13 which is 10 feet lower than this year's April 30, 2018,
L4 forecasted elevation target of 2,027 feet. The resuft of
15 higher infl-ows concurrent with l-ower elevation targets for
L6 last year was that flows in excess of power plant capacity
71 were spilled through the Hells Canyon Complex. Therefore,
18 a portion of the higher inffows l-ast year were unavailable
79 for hydro generati-on. This year, inflows and fl-ood control
20 targets are forecast to keep fl-ows generally withln power
2t plant capacit.y through the spring, Iimiting the reduction
22 in forecast ge.nerati-on compared to Iast year to 10 percent.
23 Additionally, this year's PCA forecast refl-ects
24 improved reservoir storage conditions, as compared to last
25 year's forecast. The March Operating Pl-an used in this
BLACKWELL, DI 13
Idaho Power Company
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year' s PCA
reservoirs
84 percent
Operating
and at 68
o.
presented
forecast
A
demonstrates that available storage in the 11
above Brownlee is L25 percent of normal and at
of capacity, compared to last
Plan, in which storage was 101
percent of capacity.
How are the forecasted NPSE
year's
percent
20L1 March
of normal
di fferences
in Table 1 used to determine the 20LB-20]9 PCA
component
. The,
to be collected from Idaho customers?
2018-2019 PCA forecast component reflects
10 the Idaho jurisdlctional- share of the forecasted NPSE
differences presented in Table L, adjusted for the PCA
sharing provisions. The Idaho jurisdictional share of the
forecast NPSE differences is determined by applying a ratio
of forecast firm Idaho jurisdictional sales to forecast
firm system-Ievel sal-es to the system-Ievel- NPSE
differences, adjusted for sharing.
O. What is the Company's forecast of system-level
firm sales and Idaho jurisdictional- firm sales for the
2018-2079 PCA Year?
A. For the 20L8-2079 PCA Year, Idaho Power has
forecast system-Ievel firm sal-es to be 74,996,599 MWh and
Idaho jurisdictional firm sal-es to be 14,300,'159 MWh, or
95.36 percent of the system level.
BLACKWELL, DI 14
Idaho Power Company
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a1LL
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n What is the Company's determination of the
20tB-2079 PCA forecast component to be collected from Idaho
customers ?
A. The 2078-20L9 PCA forecast component to be
collected from Idaho customers is $90,305,261. Tabl-e 4
presents the determination of the 2078-2079 PCA forecast
component by individual PCA expense and revenue category.
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11 B. True-Up and True-Up of the True-Up.
L2 O.
True-Up?
A.
What is this year's quantification of the
13
74 The True-Up portion of the PCA is detailed in
15 the deferral expense report,
actual
attached as Exhibit No. 2
t6 This report
power cost
differences
bal-ance at
compares PCA account results to actual
l1 collections on a monthly basis, with the
the def erral- bal-ance. The1Baccumulated as
the end of March 2078, with interest appJ-ied,
BLACKWELL, DI 15
Idaho Power Company
Table 4 201&2019 PCA FORECAST
Line No.FERC Account
Difference from
Base
Difference After
Sharing ldaho Allocation
7
2
3
4
5
6
95% Sharing 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 2147, Surplus Sales
(From Table 1)
5 16,974,32s
s (2,380,se7)
$ q,zqt,aru
S s,oas,zogs (20,ss1)s 26,2rr,8s7
S ro,rzs,oos S
5 12,267,s671 5
s 4,029,s90 s
5 4,79s,799 5s (1e,s23) s5 24,$L,26s S
L5,377,383
(2,1s6,631)
3,842,6L8
4,573,274
( 18,617)
23,145,850
7
8
100% Sharinq Accounts
Account 555, PURPA S
Account 555, Demand Response lncentives S
51,166,054 s
(3,8s0,s67) s
51,166,0s4 s
(3,8s0,s67) s
48,791,9s7
(3,8s0,s67)
5 so,oA,gtt 5 47,57t,172 5 4s,363,877
9 Total 5 gt,tgo,qu S g4sa0,0sg S go,sos,zez
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was negative $19,993,280, as shown on row 91 of Exhibit No.
2. The approximate negative $20 million represents a
refund to customers in thls year's PCA.
O. To what factors do you attribute the
accumufation of the approximate negative $20 million
deferral- balance?
A. The approxlmate negative $20 million deferral
balance was Iargely driven by higher than forecast hydro
generation, which resulted in higher than forecast surplus
sales. The increase in hydro generation, as well as an
increase in market purchased power, displaced generatlon at
the Company's coal and natural- gas plants.
Actua1 hydro generation for the 2011-2018 PCA Year
was 9,262,607 MWh, which was 466,122 MWh more than the
forecast of 8,195,819 MWh, reflecting a 5 percent increase
between forecast generation and actual generation. As a
result of improved hydroelectric conditions, surplus sales
volumes totaled 2,466,289 MWh, which was t4 percent higher
than expected. The val-ue of surplus sales was also higher
than expected wj-th an average actual market sales price of
$16.48 per MWh compared to the forecast market sal-es price
of $15.88. This resulted in actual surplus sales revenue
of $40,633,4L5, ds shown on row 25 of Exhibit No 2, which
was approximately 18 percent higher than expected.
BLACKWELL, DI T6
Idaho Power Company
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1 Actual- coal generation and natural gas generation
2 were fower than forecast as a result of increased hydro
3 generation, as wel-l- as increased market power purchases.
4 Actual coal- generation total-ed 3,054,216 MWh, which was 22
5 percent less than forecast. Actual- coal fuel expense was
6 $103,318,634, which was approximately L9 percent lower than
7 forecast. Actual natural gas generation was 71 percent
B l-ess than f orecast, totaling 7,27 5, B 95 MWh, and actua1
9 natural- gas expense was $33,654,439, which was 10 percent
10 lower than forecast.
11 The decrease in fossil- fuel generation was partially
12 met with i-ncreased market purchases, which were 584,083
13 MWh, or 145 percent, higher than forecast. Actual market
14 purchase expense was $25,691,933, or 150 percent, higher
15 than forecast.
L6 O. Did the Company calculate the Sa1es Based
Ll Adjustment ("SBA") per the terms of the settl-ement
18 stipulation approved in Order No. 33307 in Case No.
19 rPC-E-15-15?
20 A. Yes. The Company's deferral report provided
27 as Exhibit No. 2 reflects the SBA per the methodology
22 approved in Case No. IPC-E-15-15. Beginning on line 10 of
23 Exhibit No. 2, the Company calculates the SBA using actual
24 Idaho jurisdictional billing month sales.
25 O. What is this year's True-Up of the True-Up?
BLACKWELL, DI L7
Idaho Power Company
1
2
3
q
5
6
1
B
9
A. This year's True-Up of the True-Up bal-ance is
a credit to customers of $898,592, ds shown on row 771 of
Exhibit No. 2.
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 negative $20 mil-lion associated
with the True-Up and the negative $898,592 associated with
the True-Up of the True-Up represents an approximate $20.9
million credit to customers.
O. How does this year's combined True-Up and the
11 True-Up of the True-Up compare to
10
72
13
74
15
16
71
1B
19
20
27
The combined True-Up
last year's amount?
and the True-Up of the
$36,210, 580, as compared
$20,89t.,8'12, a decrease
Year wasTrue-Up for the last PCA
to this year's amount of
of $57,102,552.
O. Were there
negative
any items included in this year's
True-Up in
the April
A.
approximately
501, Coal FueI
addition to actual fuel-
2011 through March 20tB
Yes. In March 20lB
costs i-ncurred during
time .perj-od?
Idaho Power charged
$1 million ln deferred fuel costs to Account
Expense. The expenses are assoclated with a
22 test burn of Powder River Basin ("PRB") coal at the Jim
23 Bridger plant ("Bridger") .
24 When did the test burn of PRB coal occur?
BLACKWELL, D] 1B
Idaho Power Company
O
l- A. The test burn of PRB coaf occurred in March
2 2075.
3 Q. Why did Idaho Power conduct a t.est burn of PRB
4 coal- ?
5 A. To support continued evaluation of a least-
6 cost, Ieast-risk long-term fueling strategy for Bridger,
7 Idaho Power and 1ts ownership partner, PacifiCorp,
B commissioned a study to investigate the operational and
9 financial feasibil-ity of fueling Bridger with various
10 level-s of PRB coal-. The test burn provided baseline
11 performance data that helped identify potential impacts to
72 current systems at the plant, and what capital improvements
13 would be necessary at the plant to safely and rel-iab1y burn
L4 various levels of this fuel source.
15 O. Why were the costs associated with the test
L6 burn deferred?
11 A. It was antlclpated that the util-ization of
18 certain levels of PRB coal would require the Company and
19 PacifiCorp to invest in additional capital infrastructure
20 at Bridger including modifications to coal handling
27 facllities, conveyor systems, and pulverJ-zer steam inerting
22 units, ds wel-l as power island modifications and potential
23 modifications to the existing rail and load out
24 infrastructure. One of the key deliverables of the fueling
25 evaluation was to determine the cost and scope of
BLACKWELL, DI L9
Idaho Power Company
1 incremental capital investments required to burn higher
2 levels of PRB coal at Bridger to determine if such
3 investments could be a viable option. Therefore, these
4 costs were deferred for potential incl-usion in the total
5 capital costs required to enable Bridger to burn
6 significant quantities of PRB coal.
1 These costs were included in a deferred debit
I account due to the potential that they could be capitalized
9 to Electric Plant in the future if the investments were
10 made. No Allowance for Funds Used During Construction
11 (AFUDC) or general overheads were al-located to these costs.
L2 {l Why is the
expense now?
Through the
Company charging these costs to
13 coal fuel
74 ongoing evaluationA
15
76
t1
1B
22
fueling strategies for
recently concluded that
Bridger, Idaho Power
fueling mix options
such significant plant investments
represent the least-cost, l-east-rlsk
of long-term
and PacifiCorp
that wou]d
to burn PRB coal-
fueling option
the likel-ihood
the best
Power has
to defer these
BLACKWELL, DI 20
Idaho Power Company
require
do not
19 for the remaining life of Bridger. Because
20 of investing in these facil-ities is not in
interest of customers at this time, Idaho
concl-uded that it is no longer appropriate
costs.
27
23
24 O. Why is it appropriate to record the costs to
25 Account 501?
1 A. The cost of $984,969 is appropriateJ-y
2 recorded to Account 501 as 1t refl-ects the net fuel- costs
3 of providing electric generation to customers, whil-e also
4 serving to evaluate a long-term, least-cost, l-east-risk
5 fueling source. Idaho Power pursued the evaluation of PRB
6 coal as a fuel- source for Bridger with the intent of
7 identlfying potential long-term savings for customers, and
B the net fuel costs should be recovered through the PCA as a
9 component of this year's true-up balance.
10 C. PCA Rate Determination.
11 O How is the rate for the forecast portion of
20L9 determined?72 the PCA for April 2018 through March
13 A.
is equal to
between the
The rate for the forecast
the sum of: (1) 95 percent
portion of the PCA
of the difference74
71
15 non-PURPA expenses quantified in the Operating
approved76 Pfan and those quantified in the Company's last
1B
update of NPSE, divided by the Company's forecast of system
firm sales for June l, 2078, through May 31, 2019 ("System-
level Sales Forecast"); and (2) 100 percent of the
difference between PURPA-rel-ated expenses quantified in the
Operating Pl-an and those quantified in the Company's last
approved update of NPSE, dlvided by the Company's System-
fevef Sales Eorecast,' and (3) 100 percent of the difference
between the Idaho jurisdictional demand response incentive
payments quantified in the Operating Pl-an and those
19
20
27
22
.A
25
BLACKWELL, DI 21
Idaho Power Company
1
2
3
4
q
6
1
x
Y
quantified
divided by
for June 1
multiplying
dividing it
14,996,596
$3.112/Mwh
in the Company's last
the forecast of Idaho
, 20L8,
approved update
j urisdictional
2019.
of NPSE,
firm sales
O. What
the PCA for April
A. The
cents per kilowatt-hour
the forecast portion of
20lB through March 2019?
rate for non-PURPA expenses is 0.3712
37,
for
(*kwh"), whlch is calculated by
from Table 1 by 95 percent and then
through May
is the rate
10
$50,014,91'7
by the System-Ievel- SaIes Forecast of
MWh (($50,0't4,971 * 0.95) / L4,996,596)
0.3712 cents/kwh) . The rate for PURPA11
!2
13
74
15
76
t1
1B
79
20
2t
22
23
24
25
expenses is 0.34L2 cents per kwh, which is cal-culated by
dividing $51,166,054 from Table 1 by the 14,996,596 MWh
($51,166,054 / tq,996,596 MWh : $3.4L2/vwh : 0.3472
cents/kVrlh). The rate for demand response incentive
payments is a negative 0.0269 cents per kwh, which is
cal-cul-ated by dividing the negative Sg,450,567 from Table 1
by the forecast of Idaho jurisdictional fj-rm sal-es of
L4,300,759 MWh (-$3,,850,561 / 14,300,159 MWh: -$0.269lMWh
: -0.0269 cents/kwfr1 . The forecast portion of the PCA rate
is 0. 6315 cents per kwh, which is cal-cul-ated by adding the
non-PURPA expense of 0.3112 cents per kWh to the PURPA
expense of 0.34L2 cents per kWh to the demand response
incentj-ve payment of negative 0.0269 cents per kwh (0.3L12
+ 0.34L2 + -0.0269 0.6315 cents/kWtr) .
BLACKWELL, DI 22
Idaho Power Company
1 Q. How did you compute this year's True-Up rate?
2 A. As shown in Exhibit No. 2, this year's True-Up
3 component of the PCA is approximately negative $20 mi1I1on,
4 which, when divided by the Company's forecast of Idaho
5 jurisdictional sales of 14,300,759 MWh, results in a rate
6 of negati-ve 0. 1398 cents per kwh (-$19 ,993,280 / 1,4, 300 ,'159
1 - -$1.389/MWh: -0.1398 cents/kwirl .
B The True-Up of the True-Up rate is calculated by
9 dividing negative $898,592 (also from Exhibit No. 2) by the
10 forecast of Idaho ;urlsdictional sales of L4,300,759 MWh,
11 which resul-ts in a rate of negative 0.0063 cents per kwh
cents/kwh) .L2
13
74
15
76
l1
1B
t9
20
27
))
23
24
(-$898,592 / 74,300,'159 -$0.063/Mwh : -0.0063
O. Does the quantified True-Up rate
sal-es of Renewabl-e Energy Certificates ("REC")
Dioxide ("SOz") proceeds?
inc]ude the
and Sulfur
A. Yes. The RECs and SOz proceeds are included
in the Company's deferral expense report, provided as
Exhibit No. 2, in l-ines 41 and 48. Order No. 32002 issued
on June 17, 2010, 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 issued on January 12, 2012, directed the Company to
pass SOz proceeds through the PCA to help offset the
Company's PCA deferral balance.
BLACKWELL, DI 23
ldaho Power Company
25
1 Q. What is the resulting PCA rate when you
2 combine al-l of the PCA components described previously?
3 A. The uniform PCA rate is comprised of (1) the
4 0.6315 cents per kV'ih adjustment for the 20L8-20L9 projected
5 power cost of serving firm l-oads under the current PCA
6 methodology and 95 percent sharing, (2) the -0.1398 cents
7 per kwh for the 2071-20L8 True-Up portion of the PCA, and
B (3) the -0.0063 cents per kwh for the True-Up of the True-
9 Up. The sum of these three components results in a 0.4854
10 cents per kwh charge for all rate cl-asses.
11 III. ADDITIONAI RATE ADiIIISTI4ENTS
72 A. Revenue Shar].NCT
13 o.
originally
A.
established
When was the revenue sharing mechanism
74 established?
15 The revenue sharing mechanism was originally
t6 in Case No. IPC-E-09-30
71
1B
79
20
27
No. 30918, effective
sharing mechanism was
2012-2014 in Order No
for the years
modified and
32424 in Case
and approved in Order
2009-201L. The revenue
extended for the years
and extended for
No. IPC-E-ll-22, and
the years 201,5-2019 inwas again modified
Order No. 33149 in
0. What
sharing mechanism?
Case No. IPC-E-14-14.
22 are the provisions of the current revenue
Z3
24 A. In Case No. IPC-E-74-L4, the Company fil-ed a
25 motion to approve a settlement stipulation (*2014
BLACKWELL, DI 24
Idaho Power Company
1 Stipulation") extending the sharing mechanism, with
2 modifications, through the end of the 2019 fiscal year.
3 The Commission approved the 2074 Stipulation in Order No.
4 33149.
5 Per the terms of the 2074 Stipulatlon, if t.he
6 Company's actual, year-end Return on Equity ("ROE") for the
7 Idaho jurlsdiction exceeds 10 percent, aII amounts up to
B and including a 10.5 percent ROE wil-I be shared between
9 customers and the Company on a 15 percent and 25 percent
10 basis, respectively, to be provided as a rate reduction to
11 become effective at the time of the subsequent year's PCA.
L2 If the Company's Idaho jurisdictional- ROE exceeds 10.5
13 percent,
shared 50
to become
al-l- amounts in excess of 10.5 percent will be
t4 percent with Idaho customers as a rate reduction
15 effective with the
L6 percent will
L] an offset to
1B account, and
19 wirh regard to the amortj-zation of Accumulated
20 Deferred Investment Tax Credits (*ADITC"), the 20L4
2l Stipulation allows the Company to accel-erate the
22 amortlzation of ADITC to achieve a maximum 9.5 percent
23 Idaho jurisdictional ROE if the Company's year-end actual
24 results fal-l- below that amount in any single year between
25 2075 and 2019. The extension limits total cumulat.ive
be shared wlth
amounts in the
25 percent will
subsequent year's PCA, 25
Idaho customers in the form of
Company's pens j-on balancing
be apportioned to the Company
BLACKWELL, Dr 25
Idaho Power Company
)
3
4
5
6
1
a
9
1 accelerated amortization of ADITC to $45 million over the
2015-20L9 time period, with no more than $25 mlllion to be
accelerated in a single year.
O.Have you provided an exhibit that summarizes
the terms of the current sharing mechanism?
A. Yes. Exhibit No. 3 contains a graphical
depiction of the current sharing mechanism, detailing the
various ROE threshol-ds and sharing provJ-sions.
O. Did the revenue sharing mechanism result in
10 any action following the 2009-20L6 fiscal- years?
11 A. Yes. The Company's earnings in each year from
L2 20L1 through 2015 resu1ted i-n revenue sharing with
13 customers totaling $727.2 milIion, either as a direct rate
L4 offset in the PCA or as an offset to amounts that would
15 have otherwise been collected in rates. These amounts are
L6 detai-l-ed in Table 5 below.
2fi)9,20165
Line No.Revenue 2m92011 20L2-20L4 20LU20L6
1;0.Wo
N/A
LO,VO
5:.2527.L
Account .8
s45 Million 95 Million s4s villion
522.8
Threshold
e ADITC For Use
r Benefits (S Millions)
9.5%
10.5%
N/A
Reduction to Rates
Offset to Pension Balanci
9.s%
10.0/o
LO.S%
Sharing Threshold
Sharing Threshold
Total
2(x)s2016
3
4
5
6
7
1
2
Total 2871
1B
79
20
2t
\l Did the Company's year-end 20L1 financial
results warrant any action rel-ated to the existing sharing
agreement per the terms of the 2074 Stipulation?
BLACKWELL, DI 26
Idaho Power Company
1
2
3
4
5
6
1
B
9
A. No. The Company's year-end 207'l financial-
result.s yielded an actual Idaho jurisdictional ROE of 9.94
percent, fal-ling below the 10 percent ROE threshold for
revenue sharj-ng, and thus resulting in no revenue sharing
with customers.
O. Did the Company util-ize the same methodology
to determine the Idaho jurisdictional 20L1 year-end ROE
that was used i-n prior PCA filings?
A. Yes. The methodology used to determine the
Company's Idaho jurisdictional 20L7 year-end ROE is
consj-stent with the methodology used for the year-end ROE
determinatj-ons since the inception of the mechanism.
10
11
72
13
74
15
L6
71
1B
19
O.
application
A.
calculation
Yes.
of the
Do you have an exhibit demonstrating the
of this methodology?
Exhibit No. 4 provides a step-by-step
Idaho jurisdictional- ROE based on year-
end 20L1 financial results utilizing the Commission-
approved methodoJ-ogy from previous PCA f111ngs.
B. Enerqy Imbalance Market.
20 0. When did Idaho Power begin participating in
2L the Western EIM?
22 A. Idaho Power's participation in the Western EfM
23 began on April 4, 2018. Participation in the Vfestern EIM is
24 expected to result in real, sustainabl-e cost savings that
25 will benefit customers over the lonq term.
BLACKWELL, DI 21
Idaho Power Company
1
2
3
4
5
6
1
9
PIease describe an EIM.
An EIM is a real-time market to dispatch
economic bids voluntarily offered by participating
resources to efficiently balance supply, transfers between
balancing authority areas, and l-oad. An EIM solves sub-
hourly imbal-ance through an automated five-minute energy
dispatch service across a broader footprint with more
o
A
10
deployable resources avail-able,
method f or maintaining bal-ance.
In an EIM, al-I balancing
hour with matched generation and
providing a more efficient
authority areas
forecasted load
begin the
.As11
24
72 j-mbal-ances occur within the hour, resources within the EIM
13 can voluntarily provide bids to dispatch their facilities
74 to manage these imbal-ances. The market operator of the EIM
15 will automatically l-ook across the expanded EIM region to
16 determine the least-cost dispatch order and issue an
71 operating target for each participating resource, resulting
18 in the most economical- bids avail-able to meet these
19 imbalances. The real--time optimization process determines
20 the least-cost mix of resources and dispatches them to
2L resolve these imbalances while also respecting l-imits on
22 the transmission system to al-l-eviate overloads or
23 congestion.
The Western EIM is a voluntary EIM service that
25 was implemented by the California Independent System
BLACKWELL, Dr 28
Idaho Power Company
1
2
3
4
5
6
1
B
9
Operator and PacifiCorp on November I, 2074. Since then,
NV Energy, Puget Sound Energy, Arizona Public Service
Company, Portland General E1ectric Company, and Powerex
have entered the market.
0. How does participatj-on in the Western EIM
benefit Idaho Power's customers?
A. Participation in t.he Western EIM real-time
market is expected to result in efflciencies that translate
into NPSE savj-ngs for the Company's
the previous hourly market structure
customers. Moving from
to a sub-hourIy, five-
11 minute imbalance market is expected to lead to increased
72 surplus sales opportunities, ds wel-l- as net cost savings
13 from increased access to others' lower-cost generation,
L4 translating into reduced NPSE.
15 As of April 4, 2018, EIM benefits that are achieved
1,6 wil-l accrue directly to Idaho Power customers and will be
L1 tracked through the PCA deferral report.
1B o.
particlpate
A.
79
20 to participate in the Western
on behalf of customers, Idaho
continue to incur, incremental
27 EIM and achieve NPSE
22 Power has incurred,
23 costs to prepare for
24
25
and participate i-n the Western EIM.
BLACKWELL, DI 29
Idaho Power Company
10
Did Idaho Power incur incremental costs to
in the Western EIM?
Yes. In order
savings
and will
1
2
3
4
q,
6
1
B
9
O. Is Idaho Power proposing to inc1ude the costs
associated with EIM participation as a rate adjustment to
the 20L8 PCA?
A. No. The costs associated with EIM
particlpation w111 not be reflected in the 20LB PCA. Idaho
Power requested approval for a method of recovery for costs
associated with participation in the Western EIM in Case
No. IPC-E-71-16. The procedural schedul-e in this case was
suspended on February 20, 2078, ds a result of parties
reaching settl-ement in principle.2 The Company and Staff are
currently working to final-ize and execute a settl-ement
stipulation regarding EIM cost recovery.
IV. NET CUSTOMER IMPACT
10
72
11
13
14 0. What is the
15 PCA rate when compared to
16 A. Attachment 2
20
2L
))
revenue impact of the requested
PCA rates currently in effect?
to the Application filed
\1 contemporaneousl-y herewith provides a detailed description
each18 of the overall revenue impact of this filing on
19 customer class. As shown on Attachment 2 , applying the
sal-es for the Junerequested PCA rates to
20LB t.hrough May 2019
of $22.6 million.
expected customer
test year results in a PCA decrease
2 ldaho Power and Commission Staff are the only parties appearingin this case.
BLACKWELL, DI 3O
Idaho Power Company
23
1
Z
3
4
q
o.Have you prepared a table that details the
$22.6 million revenue impact by component?
A Yes. Table 6 below separates the $22.6
m1l-lion decrease into each component included in the
Company's proposed rates.
Table 5 Revenue Impact by Component
Line No. Rate Component 2017-2018 PcA3 2018-2019 PcA4 Difference
1
2
3
4
PCA Forecast
PCA True-Up
Revenue Sharlng
Energy Effj-cj-ency
Rider Refund
$ 68, 300, 424
$ 36, 961 ,467
$0
$(13,263,438)
$ 90,309,292
$ (20,893,409)
$0
$ 22,008, B6B
$ (57,860,870)
$0
$0 $73,263,438
5 PCA Total $ 92,004,447 $ 69,415,883 ($22,588,564)
O. Please explain the revenue impact associated
wlth the Energy Efficiency Rider ("Rider") refund.
A. The "2071-2078 PCA" col-umn refl-ects a one-time
$13 million refund of previously collected Rider funds.s In
Case No. IPC-E-16-33, Idaho Power proposed a $13 million
refund to help mitigate accumulation of surplus Rider
3 Because Table 6 contains the expected billed revenue impact to
customers, the *2011-2018 PCA" col-umn reflects approved 2011-201,8 PCArates applied to the June 2018 through May 2019 sales forecast, andwill not tie to the speci-fic dol-l-ar amounts approved in the 2011 PCAfiling.
4 The '2018-2019 PCA" col-umn reffects the Company's proposed ratesapplied to the June 2018 through May 2079 forecast, and may not tieexactly to the flgures fisted in the above testimony due to the
rounding of rates to six digits.
5 Because Tabfe 6 contaj-ns the expected billed revenue impact to
customers, the "20L1-2078 PCA" column refl-ects the approved 2017-2018Rider refund rates applied to the June 2018 through May 2019 salesforecast, and wilf not tie to the specific dollar amount approved in
the 2017 PCA filing.
BLACKWELL, DI 31
Idaho Power Company
6
7
8
9
10
11
1
2
3
4
5
6
1
B
Y
bal-ances wh1le still providing adequate funding for
recovery of al-l- prudently incurred costs related to
pursuit of cost-effective energy efficiency. The
the
the
Commission approved
20L1 PCAthe
the one-time refund of the Rider funds
in Order No. 33736. The refund is nothrough
longer
PCA.
appllcable and therefore is not included in the 2078
revised Schedule 55 that
10
O. Have you prepared a
incl-udes the proposed PCA rates?
A. Yes. At.tachment 1 to the Application is a
11 revised Schedule 55 and includes the proposed PCA rates in
12 clean and Iegislative formats.
13 0.Shoul-d the Commission approve the Company's
!4 computation of the PCA rates?
15 Yes. The Commission shoul-d
76
t1
1B
t9
20
2L
22
A
Company's computation
the PCA rates follows the methodology
Order Nos. 30715, 33749, and 33307.
20\9 PCA wiII result in a decrease in
approve the
The calculation of
that was approved in
If approved, the 20\8-
total billed revenue
BLACKWELL, DI 32
Idaho Power Company
of the PCA rates.
of approximately $22.6 millionr ot negative l-.90 percent.
0. Does this conclude your testimony?
A. Yes, it does.
23
24
25
1
2
3
4
5
6
7
I
9
ATTESTATION OF TESTIMONY
STATE OF IDAHO
EQ
County of Ada
T, Nicole A. B1ackwe11, having been duly sworn to
testify truthfully, and based upon my personal knowledge,
state the following:
f am employed by Idaho Power Company as a Regulatory
11 Analyst in the Regulatory Affairs Department and am
12 competent to be a witness in thj-s proceeding.
13 I declare under penalty of perjury of the laws of
14 the state of Idaho that the foregoing pre-fl1ed testimony
15 and exhibits are true and correct to the best of my
informati-on and bel-ief .
DATED this 12th day of April 2078.
76
18
10
71
19
20
2t
22
23
24 April 2018.
25
26
21
28
29
30
N
Nicol-e A.ell-
SUBSCRIBED AND SWORN to before me this 12th day of
No ary P for Idaho
Residing at: Boise, Idaho
My commission expires:t2/20/2020
BLACKWELL, DI 33
Idaho Power Company
trOTrfril
aueurc
(Da.a
OF ID
ar,
Yr.
".$A[(,,x
J-*8
ri -1 6r!'\
l Y.,
?
.1
{t qo
ea