20190415Annis Direct.pdf

BEFORE THE ]DAHO PUBL]C UTIL]T]ES COMM]SS]ON
i..i: il ; lV;.l
F{{ :'L ,'r. I rJ r ii 1. wl
CASE NO. IPC-E-I9_76
IN THE MATTER OF THE APPL]CATION
OE TDAHO POWER COMPANY FOR
AUTHORITY TO ]MPLEMENT POWER
COST ADJUSTMENT (*PCA") RATES
FOR ELECTR]C SERVICE FROM JUNE
l, 20L9, THROUGH MAY 31, 2020.
]DAHO POWER COMPANY
D]RECT TESTIMONY
OF
MARK A. ANNIS
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Pl-ease state your name, business address, and
present position
"Company").
with Idaho Power Company ("Idaho Power" or
A. My name is Mark A. Annis. My business address
is 7221 West Idaho Street, Boise, Idaho 83102. I am
employed by Idaho Power as a Senior Regulatory Analyst in
the Regulatory Affairs Department.
O. Please describe your educational- background.
A. I earned a Bache1or of Arts degree in Business
Administration (accounting emphasis) from the University of
South Dakota in May 1984. Al-so that year, I passed the
Uniform Certified Public Accounting (*CPA") exam and am
currently a l-icensed CPA in the state of Idaho. I have
al-so attended electric utilit.y ratemaking and finance
courses, including "Introduction to Rate Design and Cost of
Service" presented by Electric Utilities Consultants, Inc.
O. Please describe your work experJ-ence with
Idaho Power.
A. I began my employment with Idaho Power in 1991
in the Company's Finance Department as an Accountant If,
where I performed a variety of general and corporate
accounting duties, with a focus on external reportlng and
accounting research. Over the next 18 years, I hel-d
several- other positions within the Einance Department,
including Business Analyst II, Technical- Research
ANNIS, DI
Idaho Power
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Coordinator, External Reporting Team Leader, and Financial
Reporting and Accounting Research Manager. fn these
positions, I was responsible for researching accounting
policy issues and implementing new accounting standards,
including Federal- Energy Regulatory Commi-ssion (*FERC")
accounting and reporting issues, and the completion of the
Company's quarterly and annual reports f1led with the
Securitj-es and Exchange Commission and EERC.
10
In May 20L6, I accepted a position
Revenue Manager in the Finance Department.
position, I acted as a l-iaison between the
as the Budget and
In this
11 Regulatory
1,2 Affairs and Einance Departments, as well as overseeing
13 aspects of the Company's budgeting processes.
74 In March 20L7, I went on a temporary duty assignment
15 1n the Regulatory Affairs Department and, in March 20L8, I
16 transitioned full-time to the Regulatory Affaj-rs Department
11 as a Senior Regulatory Analyst. As a Regulatory Ana1yst, I
18 provide support for the Company's varj-ous regulatory
79 activities, including regulatory ratemaking and compl-iance
20 filings.
21, O. What is the Company requesting in this case?
22 A. The Company is requestj-ng approval of its
23 2019-2020 Power Cost Adjustment ("PCA") rates to become
24 effective June l, 2079. If approved, the 201,9-2020 PCA
25
ANNI S,
Idaho
DI
Power
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Company
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wil-l- resul-t in a decrease in total billed revenue of
approximately $50.1 mil1ion, ot negative 4.34 percent.
O. How is your testimony organized?
A. My testimony consists of four sections. fn the
first section, I will- provide an overview of the PCA. In
the second section, I will detail- the 2079-2020 PCA amount,
contributing to this
of the 2019-2020 PCA
identify and discuss the main factors
amount, and present the quantification
rates to become effective June t, 20L9.
10 sectj-on, I will discuss additional PCA components related
11 to revenue sharing and tax
section of my testimony, I
impact of the 2019-2020 PCA
In the third
reform benefits. fn the flnal
wiII detail the net customer
13 rates if approved as filed.
L4 I. PCA OVERVIEW
15 O What is the purpose of the PCA and how does
1,6 the mechanism function?
t1 The PCA is a rate mechanism that quantifies
18 and tracks annual- differences between actual Net Power
t9 Supply
of NPSE
Expenses (*NPSE") and the normal-ized or "base level"
20 recovered in the Company's base rates,resulting in
on June 1.2L a credit or surcharge
72
22 The PCA mechanism uses
that is updated
a 12-month test
annually
period of April
a forecast
A
23 through March (*PCA Year") and includes
24 and a true-up component ("True-Up"). The
difference between the
component
forecast
ANNIS, DI
Idaho Power
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Company
25 component represents the
1 Company's NPSE forecast from the March Operating Pl-an and
2 base l-evel NPSE recovered in the Company's base rates. The
3 True-Up j-ncludes a backward-looking tracking of differences
4 between the prior PCA year's forecast and actual NPSE
5 incurred by the Company. The True-Up contains a second
6 component that tracks the col-l-ection of the prior year's
7 True-Up amount, referred to as the "True-Up of the True-
B up."
9 With the exception of Public Utility Regulatory
10 Polj-cies Act of 1978 ('PURPA") expenses and demand response
11 j-ncentive payments, the PCA allows the Company to pass
12 through to customers 95 percent of the annual differences
13 in actual- NPSE as compared with base l-evel- NPSE, whether
14 positive or negative. With respect to PURPA expenses and
15 demand response incentive payments, as actual- annual
L6 expenses deviate from base l-evel- NPSE, the Company i-s
Ll allowed t.o pass through 100 percent of the dj-fference for
18 recovery or credit through the PCA. The PCA is also the
79 rate mechanism used by the Company to provide customer
20 benefits resulting from the revenue sharing mechanism
Utilities Commission2t approved by the Idaho Publ-ic
))("Commission") in Order No. 33149 and from tax reform
benefits approved in Order No. 34077.
O. What are the components of the PCA base l-evel
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24
ANNTS, DI
Idaho Power
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Company
25 NPSE?
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The PCA base l-evel- NPSE includes the following
536,
555,
EERC accounts: Account 501,
Water for Power; Account 541,
Purchased Power; Account 565,
FueI (coal-) ; Account
Fuel- (gas ) ;
Transmission
Account
of Electricity
by Others; and Account 44'l , Sal-es for Resale (typically
referred to as surplus sales).
The PCA base level-expense component for FERC
of both PURPA and non-PURPAAccount 555 incl-udes costs
(market) purchases. Per Order No. 32426,the Company
demand response10 adjusts FERC Account 555 to also include
11 incentive payments that
who participate in any
programs.
the Company provides to customers
L2 of its three demand response
13
74 rr. 20L9-2020 PCA
15 What is the total PCA collection that woul-d
76 result under the 2079-2020 PCA rates proposed by the
1,1 Company in this case?
1B A The total- PCA colfection that would resuft
19 under the 2019-2020 PCA rates proposed in this case is
20 $18.7 mill-ion. This represents
27 PCA revenue of $50.1 million for
a decrease in total billed
the upcoming year, a
22 decrease of 13 percent in the PCA
23 A. PCA Forecast.
24 O What is the Company's determlnation of the
25 system-1evel- difference between currently approved base
ANNIS,
Idaho
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Power
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l-evel- NPSE1 and the forecast of NPSE for the 201,9-2020 PCA
Year?
A. The system-Ieve1 forecast of NPSE for the
20L9-2020 PCA Year is $394,288,921, which is $88,604,058
higher than the currently approved base l-evel- NPSE of
$305,684,869. TabIe 1 below presents the system-Ievel
differences between currently approved base l-evel- NPSE and
the forecast of NPSE for the 2019-2020 PCA Year by FERC
account.
O What is the basis for the forecast of NPSE for
the 2019-2020 PCA Year?
A The forecast of NPSE for the 20L9-2020 PCA
Year is based on the Company's March 28, 20L9, Operatj-ng
Plan.
t In the l"Iatter of the Application of ldaho Power Company for
Authority to EstabLish a New Base Levef of Net Power SuppTy Expense,
Case No. IPC-E-13-20, Order No. 33000 (March 21, 2074).
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ANN]S, DI
Idaho Power
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Company
Table 1 20t9-2020 PCA FORECAST
FERC Account Base NPSE DifferenceForecastLine No.
unt 501, Coal
unt 536, Water for Power
unt 547, Other Fuel
unt 555, Purchased Power Non-PURPA
100% Sharins Accounts
Account 555, PURPA
Account 555, Demand Response lncentives
Total
58,448,009
7 698
153
133,8s3,869
265
792,307,878
746,63t,692 s
0
44,723,759
62,039,274
5,319,681
38,128,s72
(2,380,s97)
11,356,196
(s67,319)
(136,2741
s 194,s8s,3s1 s 34,006,616
Account 565, 3rd Party Transmission
Account 2147, Surplus Sales
s 108,s03,180 s
2,380,s97
33,367,s63
62,606,s93
5,455,955
s 160,s78,73s
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O. How is the NPSE forecast developed for the
Company' s Operating Pl-an?
A. The Operating Plan is prepared monthly and
represents a forecast of the Company's monthly NPSE for the
following 18-month period; however, for the PCA, the
Company includes only the 12 months that correspond to the
PCA Year. The Operating Plan is developed by simulating
the dispatch of the Company's generation resources for each
month, segmented by heavy load and light load hours. The
dispatch considers a current forecast of forward market
energy prices, available hydro generatj-on, coal and natural
gas prices, and any exj-sting hedge transactions. The
system l-oad forecast is then analyzed agai-nst the resultlng
monthly heavy load and light load dispatch to determine a
monthly l-oad and resource bal-ance. Any identified resource
deficiency is assumed to be filIed with market energy
purchases or natural- gas to fuel Langley Gu1ch power plant
("Lang1ey Gu1ch"), based on economics and avail-abl-e
generating capacity at Langley Gul-ch. Economically
dispatched generation above the system l-oad forecast
represents surplus energy sales. The forecast of monthly
NPSE and generation for the 2019-2020 PCA Yearr dS
determined in the Company's March 28, 201,9, Operating P1an,
is provided in Exhibit No. 1.
ANNIS,
Idaho
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How does the Company's forecast of NPSE for
the 20L9-2020 PCA compare to the forecast from last year's
PCA?
Table 2 bel-ow compares
O
PCA forecast NPSE to last year's PCA
account. As detailed in
this year's 20L9-2020
forecast by FERC
the PCA forecast on a
PCA Year is
A
this tabIe,
the 2079-2020total system basis
$394 ,288,921, which
forecast amount of
for
is $8,786,346 lower than last year's
$403,075,213.
Table 2 PCA Forecast
Line No.
2018-2019
Forecast
20L9-2020
ForecastFERC Account Difference
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5 t2s,477,sos S 146,631,692 5 21,Ls4,L87
Total PCA Forecast
s
s s
7 7,1s 7 s7
unt 501, Coal
nt 555, Purchased Power Non-PURPA
60s,
100% Sharing Accounts
Account 555, PURPA
Account 555, Demand Response lncentives
0
37,609,237
67,654,802
5,435,404
0
44,723,759
62,039,274
5,319,681
185,0r.9,923 t92,301,,878 7,28L,955
0
Account 565, 3rd Party Transmission
Account 447, Surplus Sales
unt 536, Water for Power
unt547, Other Fuel
0
7,114,522
(s,61s,s28)
{.L75,724)
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O.What general concl-usions can be drawn from the
informati-on contained in Table 2?
A When viewed by category, the 95 percent
$16. 1 millionsharlng accounts have decreased approximately
from l-ast year's forecast, whil-e the 100 percent sharing
accounts have increased approximately $7.3 mil-lion over
last year's forecast.
ANNIS,
Idaho
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Power
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Company
1 Q. What factors are contributing to the major
2 differences presented in Table 2?
3 A. Due to the impact of higher electric market
4 prj-ces, the Company expects to j-ncrease coal--fired
5 generation, both to economj-ca1ly serve load as well- as to
6 make economic off-system sal-es. The Company expects that
7 market purchases of power wil-l decrease due to the higher
8 costs. Additionally, PURPA expense is expected to increase
9 as compared with l-ast year.
10 O. Pl-ease elaborate on the changes in the 95
11 percent sharing accounts for this year's forecast as
12 compared with l-ast year' s f orecast.
13 A. As mentioned prevj-ously, the lncrease in
L4 electric market prices is impacting the Company's forecast
15 of coal fuel expense, ds well as market purchased power
16 expense and surplus sales revenue.
L7 For the 2079-2020 PCA Year, the average forecast
18 market purchase price is $35.23 per megawatt-hour ("MWh"),
19 as compared with $21.82 tn last year's PCA forecast. Due
20 to rising market prices, the Company's use of coal--fired
2l generati-on is expected to j-ncrease, both to serve load and
22 to make economic surplus sal-es. Coal fuel expense is
23 expected to increase 1,1 percent as compared to last year's
24 forecast, from $125,4'l'7,505 to $146,63\,592.
25
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Idaho Power
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The increase in market prices is forecast to reduce
the Company's use of non-PURPA purchased power, resulting
in a $5r 615,528, or 8 percent, decrease as compared with
last year's forecast. Non-PURPA purchase power expense
includes power purchase agreements ("PPA") as well- as
market power purchases. Eor the 2079-2020 PCA Year, PPA
expense is expected to increase by $!,149,215.
At the same tj-me,surplus sales revenues are
percent as compared with lastexpected to
year, from
i-ncrease 151
10 $25,523,295 to $64,729,054. Eor the 2019-2020
11 PCA Year, the average forecast market sal-es price is $35.84
12 per MWh compared with $16.77 last year.
13 Fina1ly, mainly due to the increase in natural gas
14 prices, forecast fuel expense at the Company's natural gas
15 plants increased $7,\74,522, or about 19 percent, as
76 compared to l-ast year's forecast. The average per-unit
tl cost of natural- gas generation is $23.04 per MWh compared
18 with $19.79 per MWh last year, a 16 percent j-ncrease.
19 0. What is drlving the increase j-n natural- gas
20 prices and market prices?
27 On October B,
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Pipeline suffered a
pipeline in Brj-tish
natural gas supply
the first few days
2018, Enbridge's Westcoast
of its 36-inch diameterfailure
Col-umbia. This pipeline is a major
source for the Pacific Northwest. In
after this j-ncident, there were no
ANNIS, DT
Idaho Power
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1 natural gas imports from Canada at the Sumas, Washington,
2 hub. This situation caused utilities in the Pacific
3 Northwest to rely heavily on gas in storage to meet winter
4 demand. Although imports were restored after those first
5 few days, they were and continue to be limited. The
6 Enbridge Westcoast Pipeline is expected to have severa1
7 planned outages during 2079 in order to restore the
8 pipeline to 100 percent del-iverability; the pipel-ine is
9 expected to be fully restored and returned to 100 percent
10 deliverability by October 2019.
11 The combination of reduced imports from Canada, Iow
L2 storage inventory levels, and l-ate winter col-d temperatures
13 have pushed prices and vol-atility of naturaf gas delivered
14 west of the Columbia River Gorge along the Washington-
1-5 Oregon border to high levels. This vol-atility also impacts
76 regional electric market prices.
O. What factors are contributing
the 100 percent sharing accounts?
A. Forecast PURPA costs increase
71 to the change in
1B
79 by $1,281,955 as
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compared with
while forecast
change.
O
24 expense?
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last year's forecast, a 4 percent increase,
payments did notdemand response incentive
What is driving the increase in forecast PURPA
ANNTS, Df
Idaho Power
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A. The increase in forecast PURPA expense is
related to j-ncreased generatlon, as well as price
escalation in PURPA contracts. Table 3 below details
changes between last year's PCA forecast and this year's
PCA forecast with respect to forecasted generation in MWh.
As shown in Tab1e 3, PURPA generation is anticipated to
increase by 60,908 MWh, or 2 percent, as compared with l-ast
year's PCA forecast.
O. What other general conclusions can be drawn
from the information in Tabl-e 3?
A. Hydro generation is expected to decrease by
360,158 MWh, or 5 percent, from last year's forecast. The
decrease in expected hydro generation i-s being met
primarily with increased coal-fired generation, which 1s
also displacing non-PURPA (market) power purchases. As
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ANNTS,
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PCA Forecart
line No.
2018-2019
Forecast
20192020
ForecastFERC Account Difference
7
8
1
5
6
2
3
4
7,902.511 7,542,353
Total Ceneration 17,763,010 17,897,990
Hydro
134,S0
257
728
728
14,851,190 14,935,262 74,07295% Sharing Accounts
nt 555, Purchased Power Non-PURPA
100% Accounts
nt 555, PURPA
Total load
unt &7,Surplus Sales
3,473,907
1,900,545
4,477,L77
t,947,257
t,0o3,270
40,712
Account 501, Coal
Account 547, Other Fuel
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compared with l-ast year's
increases 1, 003,210 MWh,
power purchases decreases
forecast, coal-fired generation
non-PURPAor 29 percent,
609,152 MWh,
while
or approximately 38
percent.
The increase in market prices is also contributing
to the increase in coal generation to take advantage of
opportunities to economically dispatch the Company's coal
plants for surplus sales. Consequently, surplus sales
volumes i-ncrease 18 percent, from L,522,082 MWh to
10 1,7 89 ,39'l
O.
generation
A.
MWh, compared with last
What is causing the
of 360,158 MWh?
The
year's forecast.
decrease in expected hydro11
L2
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15
14 primarily due to
L6
conditions for this year's
last year's forecast. The
23
decrease i-n expected hyd
l-ess favorable reservoir
PCA forecast as
ro generation is
storage
i compared with
Pl-an used in thisMarch Operatlng
L1 year's PCA demonstrates that available storage in the 11
18 reservoirs above Brownlee Reservoir ("Brownlee") is 110
79 percent of normal- and at 14 percent of
Operating
normal- and
capacity, compared
20 with last year's 2078 March Plan, in which
27 storage was 725 percent of
capacity.
Additionally, this
at 84 percent of
22
year's PCA forecast reflects
24 lower projected inflows
Pl-an used in this year's
into Brownlee. The March Operating
PCA forecast projects April
ANNIS, DI
Idaho Power
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through
( "MAE" )
year's
inflows
July inflows into Brownlee of 5.0 million acre-feet
as compared with 5. 1 MAF used to determine l-ast
percent. Expected
last year's PCA
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PCA forecast, a decrease of 2
into Brownfee were higher for
forecast because of the stronger
Brownlee,
releases
reservoir storage
condj-tions upstream of which resulted in a
forecast for increased from upstream reservoj-r
projects that would flow into Brownl-ee. Snowpack
conditions in the Upper Snake River Basin, which directly
impact stream flows at Mil-ner Dam and, subsequently,
through the maSority of Idaho Power's hydroelectric plants,
were stronger for l-ast year's PCA forecast as compared with
this year. The combination of reservoir storage and Upper
Snake River snowpack led t.o a larger Brownl-ee inflow
forecast and overall hydrogeneration forecast in last
year's PCA forecast as compared with this year.
O. How are the forecasted NPSE differences
presented in Table 1 used to determine the 2019-2020 PCA
forecast component to be collected from Idaho customers?
A. The 2019-2020 PCA forecast component refl-ects
the Idaho jurisdictional 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
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ANNTS, DI
Idaho Power
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1 firm system-Ievel sales to the system-1evel NPSE
2 differences.
3 Q. What is the Company's forecast of system-Ievel
4 firm sales and Idaho jurisdictional- firm sales for the
5 20t9-2020 PCA Year?
6 A. The system-level- firm sal-es forecast is
7 L4,859,780 MWh, with Idaho jurisdlctional firm sales of
8 1 4 ,1,'72,516 MWh, or 95. 38 percent of the system level-.
9 Q. What is the Company's determination of the
10 20L9-2020 PCA forecast component to be collected from Idaho
11 customers?
12 A. The 20L9-2020 PCA forecast component to be
13 col1ected from Idaho customers is $82,'106,1L5. Table 4
74 below presents the determinatj-on of the 2019-2020 PCA
15 forecast component by individual PCA expense and revenue
L6 category.
L1
ANNIS, DI
Idaho Power
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Company
Table 4 2079-2020 PCA FORECAST
Line No.
Difference from
BaseFERC Account ldaho Allocation
Difference After
Sha
7
2
3
4
5
6
7
8
9
100% Sharins Accounts
Account 555, PURPA
Account 555, Demand Response lncentives
Total 775s
34,006,615 32,305,296 30,812,252
58,448,009 58,448,009 55,745,030
Account 447, Surplus Sales
unt 565, 3rd Party Transmission
Sh
nt 555, Purchased Power Non-PURPA
(From Table 1)
S 38,128,512 S
(2,380,597)
11,356,196
(567,319)
(735,274l|
36,222,086 s
(2,267,5671
10,788,386
(538,953)
{.129,4671
34,545,964
(2,156,9791
70,289,467
(514,028)
(123,474l'
unt 501, Coal
unt 535, Water for Power
unt 547, Other Fuel
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2
3
4
5
6
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B. True-Up and True-Up of the True-Up.
o
True-Up?
A
What is this year's quantification of the
The True-Up portion of the PCA is
the deferral expense report, attached hereto as
2. This report compares actual NPSE amounts to
cost col-l-ections monthly, with the differences
as a deferral balance. The balance at the end
detai-l-ed 1n
Exhibit No.
actual- power
accumulated
of March
10
2078, with j-nterest
shown on row 104 of
negative $53, 933,956, ds
2. The approximate
a refund due to customers
applied, was
Exhibit No.
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negative
in this
$54 million represents
year's PCA True-Up.
O. To
accumufation of
what factors do you attribute the
the approximate negative $54 million
deferral balance?
A. The approxi-mate negative $54 million deferral-
bal-ance was primarily driven by higher than forecast
surplus sales and natural gas hedging activities.
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79 Actual surplus sales
20 totaled 2,l82,B2B MWh,year
than2I l-ast year's forecast of
24
vol-umes for the 20].8-20L9 PCA
whlch was 7,260 ,'l 46 MWh more
L,522,082 MWh, reflecting an
forecast and actual-. The value22 83 percent increase between
23 of surplus sales was also higher than expected, with an
$36.50 per MWhaverage actual market sales price
compared with the forecast market
of
sal-es price of $16.77 per
ANNIS, D]
Idaho Power
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MWh. This resulted in actual surplus
$101,5'16,987, ds shown on line 25 of
was 298 percent higher than expected.
The increase in surplus sales
primarily through increased economj-c
13 increase over forecast. The i-ncrease in
L4 was due in part to a water fease that the
15 into in 2018.
76
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generatj-on, as wel-I as higher than forecast hydro
generation. Actual coal generation totaled 3,798,4'77 MWh,
which was 9 percent higher than forecast, and actual- coal-
fuel expense was $130,865,930, which was approximately 4
percent higher than forecast. Actual hydro generation for,
the 2018-201,9 PCA Year was 8,057,097 MWh, which was 154,586
72 MWh more than the forecast of 1,902,511 MWh, a 2 percent
sal-es revenue of
Exhlbit No. 2, which
vo]umes was achieved
dispatch of coal-fired
hydro generation
Company entered
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O.
entered into
A.
agreements to
supplemental-
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19
20
2l acre-feet and were
22 cost of $2, 450, 000,
Z5
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Please explain the water lease the Company
in 2078.
In 20L8, Idaho Power entered into two
purchase water from the Water District 1
rental poo1. The agreements total-ed
priced at
as shown
$3s
on
per acre foot for
line 26 of Exhibit
70,000
a total
No. 2.
The water flowed through Idaho
M1J-ner Dam from JuIy 31, 20L8,
Power's system beginning at
through August L1 , 2078.
ANNIS, DI L]
Idaho Power Company
25
1
2
3
4
5
6
7
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O.
generation?
A.
How did the water l-ease impact hydro
Company estimated that
the actual daily water f1ow, the
hydro generation from the water
lease total-ed 58,320 MWh, resulting in a price of
approximately $42.00 per MWh.
O. Did the water lease expense and associated
increase in hydro generation benefit customers?
A. Yes. During the period of f1ow, daily market
prices ranged from $35.49 per MWh during light l-oad hours
to $307.52 per MWh during heavy l-oad hours. Idaho Power
was able to minimize market purchases during this tlme by
using the leased water and running additional- water through
the Hel-l-s Canyon Complex. The purchase of leased water at
$42.00 per MWh compared favorably with the average price
paid for market purchases during the month, which was
approximateJ-y $74. BB per MWh.
This additj-onal hydro generation al-so contributed to
Based on
10
11
72
13
74
15
t6
L1
1B
27
24
19 Idaho Power's ability to sell- into high-priced hours to the
20 of customers. The average
this tj-me was $90.63 per MWh
price for market sales
, compared to the cost
22 leased water at $42.00 per MWh, resulting in net
23 from surplus
O. How did the Company benefit from natural gas
25 hedging activitj-es during the 2078-2079 PCA Year?
benefit
during
of the
revenue sal-es.
ANNIS, DI
Idaho Power
1B
Company
1 A. As mentioned previously, the Enbridge
2 Westcoast Pipeline explosion that occurred in October 20LB
3 pushed prices and vol-atil-ity of natural- gas in the Pacific
4 Northwest to extremely high levels. Because Idaho Power
5 hedges most of its winter natura1 gas supply in advance
6 with derivative products tied to the Sumas hub, savings
7 were realized by procuring physical supply from the A1berta
8 and Rocky Mountain regions. Col-d snaps during the winter
9 of 2018-2079 caused signifi-cant price differential-s across
l-0 the region. These spreads resul-ted in Idaho Power
11 collecting high Sumas prices from its hedges whil-e
12 purchasing physical supplies at much lower prices, which
13 resulted in savings of more than $25 million this winter
14 for Idaho Power customers.
15 u Were there any items included
76 to actual NPSE i-ncurred
in this year's
during theTrue-Up in addition
April 201,8 through
A. Yes.
t7 March 2079 period?
1B Per Commission Order No. 34100, Idaho
79 Power incl-uded its actual- costs of Western Energy fmbalance
20 Market ("EfM") participation for April 2018 through March
27 2019 in the True-Up. Benefits associated with EIM
22 participation are embedded in actual NPSE experienced over
23 that same period.
24
25
ANN]S, DI
Idaho Power
t9
Company
1
2
3
4
5
6
1
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9
O. Please summarize the conditions of Order No.
34100 as they pertain to EIM cost recovery through the 2079
PCA.
A. Per the terms of the settlement stipulation
(*EIM Stipulation") approved by Order No. 34100, Idaho
Power agreed to lncl-ude an EIM-related monthly revenue
requirement in its monthly PCA deferral calculation based
on actual- EIM particj-pation costs commencj-ng April 7, 20tB .
Company afso agreed to
10 to ElM-related revenue requirement
11 PCA deferral equal to annual EfM benefits
72 as reported by the California Independent System Operator
13 ('CAISO") for the corresponding period.
74 O. fs the EIM-related revenue requirement
15 incl-uded in the April 20tB through March 2019 PCA deferral-
L6 under the soft cap of annual- CAISO-reported benefits for
11 that same period?
18 A. Yes. For the April 2018 through March 2019
L9 period, EIM-rel-ated revenue requirement totaled $3 million,
20 whil-e CAfSO reported EIM benefits specific to fdaho Power
2l of $27 mil-l-ion from April through December (CAfSO's first
22 quarter 2019 report has not yet been published). Therefore,
23 the Company's EIM-related revenue requirement is l-ess than
24 the soft cap agreed to in the EIM Stipulation.
25
Through
apply a
incl-uded
t.he EIM Stipulation, the
soft cap
in the
ANNIS, DI
Idaho Power
20
Company
1
2
3
4
5
6
1
9
O. Does Idaho Power belj-eve the EIM has provided
net benefits to customers since joining in April 20tB?
A. Yes. Whil-e Idaho Power believes the CAISO
benefit cal-cul-ati-on overstates estimated benefi-ts to Idaho
Power's system, the Company believes customers have
real-ized signif icant net benef its s j-nce the Company's entry
into the EIM in April 2018. Idaho Power has been analyzing
its EIM benefits. In its analysis, the Company has noted
several- modifications and adjustments to CAISO's published
EIM benefits reports that would be necessary to accurately
measure such benefits. Based on preliminary analysis, the
10
11
t2
13
t4
Company believes
March 2079 ranged
be noted that in
benefits achieved between April
between $10 and $15 mil-l-ion.
2078 and
It should
15 Power wil-l- be preparing a report describing the costs and
76 benefits of EIM participation based on experience gained in
l1 its first full
compliance with Order No. 33106, Idaho
of participation, which the Companyyear
in18 expects to file Case No. IPC-E-76-79 on or before May
t9 24, 20L9.
20 O. Did the Company calculate the Sales Based
2t Adjustment ("SBA") per the terms of the settl-ement
22 stipulation approved in Order No. 33307 in Case No.
23 rPC-E-15-15?
24 A. Yes. The Company's deferral- report provided
25 as Exhibit No. 2 refl-ects the SBA per the methodology
ANNTS, Dr 2L
Idaho Power Company
1
2
3
4
5
6
't
a
9
approved in Case No. IPC-E-15-15. Beginning on line 10 of
Exhibit No. 2, the Company cal-culates the SBA using actual
Idaho jurisdictional billing month sal-es.
O. What is this year's True-Up
A. This year's True-Up of the
a credit to customers of $10,09'7,724, as
of Exhi-bit No. 2.
of the True-Up?
True-Up balance is
shown on row 124
What is the combined effect of the True-Up and
the True-Up of the True-Up in this year's PCA?
True-Up for the last PCA
compared with this year's
change of $43,139,208.
Year was negative $20,89L,812, as
amount of negative $54,031,080, a
O
10 A. The sum of the negative $54 mill-ion associated
11 with the True-Up and the negative $10 mil-lion associated
72 with the True-Up of the True-Up represents an approxi-mate
13 $64 mil-lion credit to customers.
14 O. How does this year's combined True-Up and the
15 True-Up of the True-Up compare to last year's amount?
16 A. The combined True-Up and the True-Up of the
71
1B
79
20 C. PCA Rate Determination.
2! O. How j-s the rate for the forecast portion of
22 the PCA for April 201,9 through March 2020 determined?
23 A. The rate for the forecast portion of the PCA
24 is equal to
between the
the sum of (1) 95 percent of the dj-fference
non-PURPA expenses quantified in the Operating
ANNTS, Dr
Idaho Power
22
Company
25
1
2
3
4
trJ
6
1
q
9
Pl-an and those quantif ied in the Company's l-ast approved
update of NPSE,
firm sales for
divlded by the Company's forecast of system
June L, 20L9, through May 37, 2020 ("System-
level Sales Forecast"); and (2) 100 percent of the
difference between PURPA-related expenses quantified in the
Operating Plan and those quantified in the Company's last
approved update of NPSE, divided by the Company's System-
level Sal-es Forecast; and (3) 100 percent of the difference
between the Idaho jurisdictional- demand response j-ncentive
payments quantified in the Operating Plan and those
quantified in the Company's l-ast approved update of NPSE,
divided by the forecast of Idaho jurisdictional firm sales
for June 7, 2079, through May 31, 2020.
O. What is the rate for the forecast portion of
the PCA for April 201-9 through March 2020?
A. The rate for non-PURPA expenses is 0.2714
cents per kilowatt-hour ("kwh"), which is calculated by
multiplying $34,006,6L6 from Table 1 by 95 percent and then
dividing it by the System-level Sal-es Forecast of
74,859,7 80 MWh ( ($34,006 ,676 * 0.95) / 74,859,780) :
$2.L1A/Mwh : 0.2714 cents/kwn) . The rate for PURPA
expenses is 0.393 cents per kwh, which is calculated by
dividing $58,448,009 from Table 1 by the L4,859,780 MWh
($S8,448,009 / U,859,180 MWh: $3.934lMWh: 0.3934
cents/kV{h). The rate for demand response incentive
10
11
72
13
74
15
t6
71
18
t9
20
27
22
23
24
ANNTS, DI
fdaho Power
23
Company
25
1 payments is a negative 0.02'12 cents per kwh, which is
2 calcul-ated by dividing the negative $3,850,557 from Tabl-e 1
3 by the forecast of Idaho jurisdictional firm sal-es of
4 74,7'72,516 MWh (-$3,850,567 / 74,172,516 MWh: -$0.212/MWh
5 : -0.0212 cents/kwh). The forecast portion of the PCA rate
6 is 0.5836 cents per kwh, which is cal-cul-ated by adding the
7 non-PURPA expense of 0.271 4 cents' per kWh to the PURPA
B expense of 0.3934 cents per kWh to the demand response
9 incentive payment of negative 0.0272 cents per kwh (0.2174
10 + 0.3934 + -0.0212 0.5836 cents/kwh) .
11 O. How did you compute this year's True-Up rate?
L2 A. As shown in Exhibit No. 2, this year's True-Up
13 component of the PCA is approximately negative $54 million,
74 which, when divided by the Company's forecast of Idaho
15 jurisdictional- sal-es of L4,772,516 MWh, results in a rate
1,6 of negative 0.3806 cents per kwh (-$53,933,956 / 74,712,5'16
l7 -$3.806/MWh : -0.3806 cents/kwh) .
18 The True-Up of the True-Up rate is calculated by
19 dividing negative $10,097 ,724 (also from Exhibit No. 2) by
20 the forecast of fdaho jurisdictional safes of L4,1l2,576
21, MWh, which results in a rate of negative 0.0172 cents per
22 kwh (-$10,091 ,124 / L4,772,576 : -$0.71-2/Mwh : -0.0112
23 cents/kwh).
24
25
ANNIS, DI
Idaho Power
24
Company
1
2
3
4
5
6
1
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9
O. Does the quantified True-Up rate incl-ude the
sales of Renewable Energy Certificates ("REC" or "RECs")
and SuIfur Dioxide ("SOz") proceeds?
A. Yes. The RECs and SOz proceeds are included
in the Company's deferral- expense report, provj-ded as
Exhibit No. 2, in lines 41 and 48 . Order No. 32002 issued
on June IL, 2070, accepted for filing the Company's REC
Management Plan, which passes the customers' share of REC
beneflts back to customers through the PCA. Order No.
32434 issued on January L2, 2012, directed the Company to
pass SOz proceeds through the PCA to help offset the
Company's PCA deferral balance.
O. What 1s the resulting PCA rate when you
combine al-l- the PCA components described previously?
A. The uniform PCA rate comprises (1) 0.5836
cents per kwh for the 20L9-2020 projected power cost of
servj-ng firm loads under the current PCA methodology and 95
percent sharing, (2) the negative 0.3806 cents per kV{h for
the 2078-20!9 True-Up portion of the PCA, and (3) the
negative 0.0172 cents per kwh for the True-Up of the True-
Up. The sum of these three components is a 0.1318 cents
per kwh charge for all rate cl-asses.
10
11
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16
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27
22
23
24
ANNIS, DI
Idaho Power
25
Company
25
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3
4
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't
9
III. ADDITIONAI. RATE ADJUS${ENTS
A. Revenue Shar
O. When was the revenue sharing mechanism
originally established?
A. The revenue sharing mechanism was originally
established in Case No. IPC-E-O9-30 and approved in Order
No. 30978, effective for the years 2009-2071. The
sharing mechanism was modified and extended for the
revenue
10
2012-2014 in Order No. 32424 in Case No. IPC-E-17-22
years
and
was again modified and extended for the years 2015-2019 in
Order No. 33149 in Case No. IPC-E-L4-L4.
O. What are
sharing mechanism?
A. In Case
the provisions of the current revenue
No. IPC-E-74-74, the Company filed a
15 motion to approve a settlement stipulation (*2014
76 Stipulation") extending
71 modifications, through
18 The Commission approved
1,9 331,49.
the sharing mechanism, with
the end of the 201,9 fiscal year
the 2074 Stipulation in Order No
/t)Per the terms of the 2074 Stipulation, if the
on Equity (*ROE") for the
11
t2
13
74
2L
22
Company's actual- year-end
Idaho jurisdiction exceeds percent, all amounts up to
ROE wiII be shared between
Return
10
23 and including a 10.5 percent
24 customers and the Company on a 75 percent and
25 basis, respectively, to be provided as a rate
25 percent
reduction to
ANNI S,
Idaho
D]
Power
26
Company
1
2
3
4
5
6
1
9
become effective at the
If the Company's Idaho
time of the subsequent year's PCA.
jurisdictj-onal- ROE exceeds 10.5
excess of 10.5 percent wil-l- bepercent,
shared 50
to become
al-l- amounts in
percent with Idaho customers as a rate reduction
effective with the
percent will
an offset to
account, and
with
the terms of
A.
depictlon of
various ROE
be shared with
amounts in the
25 percent will-
subsequent year's PCA, 25
Idaho customers in the form of
Company's pension balancing
be apportioned to the Company
10
regard to the amortization of Accumulated
Deferred Investment Tax Credits ("ADITC"), the 2014
Stipulation allows the Company to accelerate the
amortization of ADITC to achieve a maximum 9.5 percent
Idaho jurisdictional- ROE if the Company's year-end actual
resul-ts fal-l below that amount in any single year between
20L5 and 2019. The extension limits total cumulative
accel-erated amortization of ADITC to $45 mill-ion over the
2015-2079 period, with no more than $25 million to be
acceferated in a single year.
O. Have you provided an exhibit that summarizes
11
t2
13
74
15
I6
71
1B
79
20
27
22
23
the current sharlng mechanism?
Yes. Exhibit No. 3 contains a graphical
the current sharing mechanism, detail-ing the
thresholds and sharing provi-si-ons.
24 O. Did the revenue sharing mechanism resul-t in
25 any acti-on foll-owing the 2009-2071 fiscal- years?
ANNTS, DI
Idaho Power
21
Company
1
2
3
4
5
6
1
A Yes. The Company's earnings in each year from
20LL through 2075 resul-ted 1n revenue sharing wlth
customers totaling
offset in the PCA
$127.2 miIlion, either as a direct rate
or as an offset to amounts that would
have otherwise been col-lected in rates. The Company's
earnings in 2076 and 20L1 were below the revenue sh4rj-ng
threshold. These amounts are detailed in Table 5 below.
Table 5 2009-2017 Revenue Sharing
line No.Revenue Sharing Component 2009-2011 20t2-20t4 20L5-20t7
L
2
3
4
5
6
7
Available ADITC For Use
R0E Threshold
50-50 Sharing Th reshold
75-25 Sharing Th reshold
Customer Benefits ($ Millions):
Reduction to Rates
Offset to Pension Balancing Account
Total Customer Eenefits
S45 Million
9.5Yo
t0.5Yo
N/A
S45 Million
9.SYo
10.0%
105%
S45 Million
95%
N/A
t0.0%
5 27.1 5
20.3
22.8 s
4t.8
3.2
0.0
S 47.4 5 70.6 s 3.2
Did the Company's year-end 2018 financial
10 results warrant any action related to the existing sharlng
11 per the terms of the 2074 Stipulation?
8
9 o
agreement
A.Yes.72
13
t4
15
results yj-eIded an
percent, resultlng
customers after tax
The Company's year-end 2018 financial
actual Idaho jurisdictional ROE of 1,0.27
in a revenue amount to be shared with
gross-up of $5,024,562.
16 O. Did the Company use the same methodol-ogy to
l7 determine the Idaho jurisdictj-onal- 2078 year-end ROE that
18 was used in prior PCA filings?
79 A. Yes. The methodology used to determine the
20 Company's Idaho jurisdlctional- 201,8 year-end ROE is
ANNTS, DI
Idaho Power
2B
Company
1
2
3
4
5
6
1
B
9
O.
appl j-cation
A.
calculation
consistent with the methodol-ogy used for the year-end ROE
the inception of the mechanism.
have an exhi-bit demonstrating the
determinations since
Do you
of this methodology?
Exhibit No. 4 provi-des a
of the Idaho jurisdictional ROE
end 20tB financial- resul-ts util-izing the Commission-
approved methodology from previous PCA fil-ings.
O. What is the revenue sharing amount to be
included in the 20L9-2020 PCA?
A. As detailed in Exhibit No. 4, the 2018 Idaho
jurisdictional ROE was 10.21 percent. As quantified on
l-ine 63 of Exhibit No. 4, in 2078, the Company's earnings
exceeded an Idaho jurisdictional ROE of 10 percent by
$4,974,98'l . Per the terms of the 2074 Stipulation, 15
percent of the $4,914,987 should be shared with customers
as a direct reduction to PCA rates effective June l, 2079.
Yes.
10
step-by-step
based on year-
to the $4,914,98'l
of $3,731,,240.
to be
11
72
13
74
15
76
l1
18
t9
20
Applying
yields a
After tax
the 15 percent sharing provi-sion
customer-all-ocated sharing amount
gross-up, the revenue sharing amount
2I applied to customer bills is $5,024,562.
22 How does the Company propose to allocate the
23 $5,024,562 revenue sharing to customer cl-asses?
24 A The Company proposes to allocate the revenue
25 sharing benefit to customer classes utilizing the same
O
ANNIS,
Idaho
DI
Power
29
Company
1
2
3
4
5
6
1
U
9
methodology as in past cases; i.e., based on each cfass's
proportional share of forecasted base rate revenues for the
upcoming PCA rate effective year, which in this case is
June L, 2079, through May 31, 2020.
O. Have you provided an exhj-bit detailing the
cl-ass allocation utilizinq this methodology?
A. Yes. Exhibit No. 5 detail-s the cl-ass
allocation
displayed
receives a
11 to current
of the $5,024,562 revenue
in column G of Exhibit No.
decrease of approximately
base revenues.
sharing benefit. As
5, each customer cl-ass
0.48 percent rel-ative10
72 I How does the Company propose to incl-ude the
13 cl-ass-allocated revenue sharing benefits in rates?
74 A Except for the special contracts for Micron
15
L6
71
Technology, Inc., the U.S.
Simplot Company-Pocatello,
the cl-ass-allocated revenue
Department of Energy, and J.R.
Idaho Power proposes to include
sharing benefi-ts on a cents-
2019 PCA rates effective June18 per-kWh basis applied to the
t9 7, 2019, through May 3L, 2020. Col-umn F of Exhibit No. 5
contains the rates proposed for incl-usion in each cl-ass's
PCA rate.
O. What is the Company's proposal for providing
revenue sharing benefits to its special contract customers?
A. Consistent with the methodology used to share
2011,, 2072, 2073, 20L4, and 2015 revenues, the Company
20
27
))
)?
24
25
ANNIS,
Idaho
DI
Power
30
Company
1
2
3
4
5
6
1
I
9
proposes to provide the special contract customers a flat
dolIar-per-month credit in 72 equal portions to serve as a
reduction to monthly invoices billed from June 2079 through
tlay 2020. The total revenue sharing benefit allocated to
each special contract customer is displayed in column E of
Exhibit No. 5.
O. Is the Company's rate design proposal for the
20LB revenue sharing benefits consistent with past-approved
proposals ?
A. Yes.
11 B. Tax Refor:m Benefits.
72 O. Are customers currently receiving tax reform
13 benefits through the PCA?
74 A. Yes. Pursuant to the settl-ement stipulation
15 approved by Order No. 34071 in Case No. GNR-U-18-01 ("Tax
76 Stipulation"), Idaho Power incl-uded $7,8L8,624 in tax
71 savings associated with the federal Tax Cuts and Jobs Act
18 of 2017 ("TCJA") as a credj-t to customers through the
79 Earnings Sharing component of the PCA for June l, 2078,
20 through May 31, 2079.
2L O. Will customers continue to receive a tax
22 reform benefit through this year's PCA?
23 A. Yes. Per the Tax Stipulation, Idaho Power
24 will- inc]ude $2,680,957 in tax savings as a credit to
25 customers through the Earnings Sharing component of the PCA
10
ANN] S,
Idaho
DI
Power
31
Company
1
2
3
4
5
6
1
9
for June I, 2079, through May 31,
tax reform benefit being reduced
2020.2 As a result of the
from $7,818,624 to
billed revenue is an
to two components.
in rates included
associated with the
$2,680,951 ,
increase of
o.
$7,878,624
A.
this year's
First, the
a one-time
the impact to
$5,131 ,661 .
Why did the
to $2,680,951
current
TCJA savings reduce from
for this year's PCA?
The reduction in TCJA benefits incl-uded i-n
10
PCA is the result of changes
$7, 878,624 currently embedded
rate reduction of $4,244,075
11 deferral of estimated tax savings incurred between January
72 and May 2078. Because the rate change resulting from the
13 Tax Stipulation did not occur until June l, 2078, parties
74 to the Tax Stipulation agreed that Idaho Power woufd credit
15 customers for the January through May 2018 estimated tax
76 savings as a one-time reduction to the PCA.
l7 Second, per the terms of the Tax Stipulation,
18 parties agreed that customers woul-d receive a short-term
19 rate reduction associated with the regulatory Iag embedded
20 in the Company's Open Access Transmission Tariff ("OATT")
21, f ormula rate. Because the OATT 1s cal-cul-ated on an
22 historical basis, it wil-l- take approximately two years for
23 tax savings resulting from the TCJA to be fully reflected
2 In the Matter of the Investigation into the Impact of FederaL
Tax Code Rerzjsions on Utifity Costs and Ratemaking, Case No. GNR-U-18-
01, Order No. 3401L, page 3 (May 31, 2018).
ANNTS, Dr 32
Idaho Power Company
1 in OATT rates. Parties agreed in the Tax Stipulation that
2 Lax benefits that would eventually be passed through to
3 OATT customers woul-d be applied to retaj-l- rates in the
4 interim. Therefore, rates approved in the 20LB PCA
5 included an OATT-related benefit of $3,574,609, while the
6 2079 PCA incl-udes a partial-Iy phased down amount of
7 $2r680,951, resulting in a year-over-year rate increase of
8 $893,652.
9 In sum, removal of the one-ti-me January through May
10 20LB deferred benefit of $4,244,0L5 and the OATT benefit
11 phaseout of $893,652 from the $7,878,624 credit currently
12 included in rates yields the $2,680,957 tax-related
13 customer benefit incfuded in the 20L9 PCA Year.
1,4 O. How does the Company propose to al-l-ocate the
15 $2,680,957 in tax reform benefits to customer cl-asses?
16 A. Idaho Power will allocate the tax reform
L7 benefits in the same manner as revenue sharing; i.e., based
18 on each cl-ass's proportional share of forecasted base rate
L9 revenues for the upcoming PCA rate effective year, which j-s
20 June 7, 20L9, through May 31, 2020. The Company wil-l afso
2! inc]ude the cl-ass-a1l-ocated tax reform benefits 1n rates in
22 the same manner as revenue sharing, as described in the
23 previous section.
24
25
ANN]S, DI
Idaho Power
33
Company
1
2
3
4
5
6
1
B
9
O. Has Idaho Power prepared an exhj-bit to
demonstrate the revenue impact associated with tax reform
benefits ?
A. Yes. Exhibit No. 5 details the cl-ass
all-ocation of the $2,680,951 revenue sharing benefit as
weII as the rates proposed for i-ncl-usion in each class's
PCA rate.3
IV. NET CUSTOMER TMPACT
O. What is the revenue impact of the requested
PCA rate when compared with PCA rates currently in effect?
A. Attachment 2 to the Application filed
contemporaneously with my testimony provides a detailed
description of the overal-I revenue impact of this flling on
each customer class. As shown in Attachment 2, applying
the requested PCA rates to expected customer sales for the
June 20L9 through NIay 2020 test year results in a PCA
decrease of $50 . 1 mif l-ion.
O. Have you prepared a table that detail-s the
$50.1 mill-ion revenue impact by component?
A. Yes. Tabl-e 6 below separates the $50. 1
2l million decrease into each component included in the
22 Company's proposed rates.
23
3 Special contract customers wiff receive a flat dolfar-per-monthcredit associated with tax reform beneflts in 12 equal portions to
serve as a reduction to monthly invoices billed from June 2019 through
May 2020.
10
11
t2
13
74
15
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79
ZU
ANNIS,
Idaho
DI
Power
34
Company
1
Because Table 5 contains the expected billed revenue impact to customers, the '2078-2079 PCA" column reflects approved 2018-
201.9 PCA rates applied to the June 2019 through May 2020 sales forecast, and will not tie to the specific dollar amounts approved in
the 201,8 PCA a nd Tax Settlement filings.
' th" "ZO[}-ZOZ0 PCA" column reflects the Company's proposed rates applied to the June 2019 through May 2020 forecast, and may
not tie exactly to the figures listed in the above testimony due to the rounding of rates to six digits.
O. Have you prepared a
includes the proposed PCA rates?
A. Yes. Attachment 1
revised Schedule 55 and includes
cl-ean and legislative formats.
revised Schedul-e 55 that
approve the
The cal-culation of
o.
computation
A.
Company's computation of
the PCA rates follows the
Order Nos. 30715, 33749,
2020 PCA wil-l- result in a
to the Application is a
the proposed PCA rates in
Shoufd the Commission approve the Company's
of the PCA rates?
Yes. The Commission should10
11
72
13
\4
71
the PCA rates.
methodology
and 33307.
decrease in
that was approved ln
If approved,
total- bl]led
the 2019-
revenue
15 of approximately $50.1
76 0 Does this
million, or negative 4.34 percent
conclude your testimony?
ANN]S,
Idaho
D]
Power
35
Company
Table 5 Revenue lmpact by Component
line No. Rate Component 2018-2019 PCA1 2019-2020 PCA2 Difference
1.
2
3
4
5
5
PCA Forecast
PCA True-up
PCA Total
Revenue Sharing
Tax reform
S 89,499,819 S
(.20,706,1341
82,771,!55 s
(54,031,699)
(6,788,664)
(43,325,566)
68,793,68s t8,679,455
(5,024,5621
(2,580,9s7)
(50,114,230)
(5,024,5521
5,072,447(7,7s3,398)
Total Revenue lmpact I 61.,W,287 S 10,973,936 S (50,055,351)
1B
A Yes, it does.
2
3
4
5
6
1
B
9
1
2
3
4
5
6
1
x
9
ATTESTATION OF TESTIMONY
STATE OF IDAHO
ee
County of Ada
I, Mark A. Annis, havi-ng been duly sworn to testify
truthfully, and based upon my personal knowledge, state the
following:
f am employed by Idaho Power Company as a Senior
Regulatory Analyst 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 15th day of April 2079.
10
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74
15
76
77
18
19
20
2t
22
23
24 April 2019.
25
26
2't
28
29
30
o-
Mark Annis
SUBSCRIBED AND SWORN to before me this 15th day of
s.
Notary
Residi
ic for Idaho
ANNTS, Dr 36
Idaho Power Company
ng at:Merldian Idaho
My commission expires:02/04/2027
of
3
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
GASE NO. IPC-E-I9-16
IDAHO POWER COMPANY
ANNIS, DI
TESTIMONY
EXHIBIT NO. 1
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Case No. IPC-E-19-16
M. Annis, IPC
Page 1 of 1
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IDAHO POWER COMPANY
ANNIS, DI
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EXHIBIT NO.2
GASE NO. IPC-E-I9-1 6
Exhibit No. 2
Case No. IPC-E-1916
M. Annis, IPC
Page 1 of 2
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Case No. IPC-E-19-16
M. Annis, IPC
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GASE NO. IPC-E-I9-16
IDAHO POWER COMPANY
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TESTIMONY
EXHIBIT NO.3
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Case No. IPC-E-19-16
M. Annis, IPC
Page 1 of 1
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BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
GASE NO. IPC-E-I9-16
IDAHO POWER COMPANY
ANNIS, DI
TESTIMONY
EXHIBIT NO.4
IDAHO POWER COMPANY
ADDITIONAL INVESTMENT TAX CREDIT ANALYSIS
For the Twelve Months Ended Oecember 31, 20lE
Actual September 30, 2018 Actual December 31, 2018. " SUI'MARY OF RESULIS "'
TOTAL COMBINEO RATE BASE
DEVELOPMENT OF NET INCOME
OPERATING REVENUES
RETAIL SALES REVENUES (lnd 449.1 Rev)
OTHER OPERATING REVENUES
TOTAL OPERATING REVENUES
OPERATING EXPENSES
OPERATION & MAINTENANCE EXPENSES
DEPRECIATION EXPENSE
AMORTIZATION OF LIMITED TERM PLANT
TPfiES OTHER THAN INCOME
REGULATORY DEBITS/CREDITS
PROVISION FOR OEFERRED INCOME TAXES
INVESTMENT TAX CREOIT ADJUSTMENT
FEDERAL INCOME TP(ES
STATE INCOME Tru(ES
TOTAL OPERATING EXPENSES
OPERATING INCOME
ADD: IERCO OPERATING INCOME
OPERATING INCOME BEFORE OTHER INCOME AND
DEDUCTIONS
ADD: AFUDC EOUIry
ADD: OTHER INCOME AND DEDUCTIONS
INCOME BEFORE INTEREST CHARGES
LESS: INTEREST CHARGES
NET INCOME
TOTAL
SYSTEM IOAHO IDAHO%
$ 3,390,376,900 $ 3,243,796,756 95.7016
TOTAL
SYSTEM IDAHO IDAHO%
September Allocations / Ratios
S 1,180,176,477 $ 1,'125,016,052 DirectAssign
187,48,457 178,529,046 95.204
1,367,634,934 1,303,545,098
$ 922,638,2'11 $
131,500,704
879,559,334 Direct Assign
1252*,789 95.20k't,054,'t38,915 1,004,796,123
652,360,340
1 16,939,698
5,036,292
27,305,882
4,963,989
(6,836,469)
4,993,670
12,610,514
4,636,603
622,27't.673
't '11 ,888,570
4,820,663
25,416,198
4,799,572
(6,561,502)
4,778,778
1 1,972,806
4,397,2fi
869,398,321
1 56,899,252
6,841,156
34,792,143
5,287,633
(6,081,605)
5,405,098
20,o35,445
(2,242,797\
829,2W,261
I 50,1 22,099
6,548,251
32,384,378
5,1',t2,496
(5,836,999)
5,172,502
't9,o22,262
(2,127,O21\
95.40h
95.7o/o
95.70h
93.1 %
96.70h
96.00/6
95.70k
94.9%
94.8%
95.4%
95.70k
95.70k
93.1016
96.7%
96.0%
95.7o/o
94.9%
94.8%
822,O10,5',t9 783,7%p',14 1,090,334,646',t,039,697.228
277,300,288 263,847,870
95.40h 8,813,793 8,404,672 95.40k
232,',t28.396
8,452,636
221,012,109
8,060,280
$ 240,581,032 $ 229,0723A9 286,'t 14,081
24,352,523
't,769,'129
272,252,543
23,299,62
1,683,419
95.20h
95.7%
95.2%
312,235,733
86,1 70,203
297,235,623
82,444,705
(L 10)
(L 33)
$ 226,065,530 $ 2r4,790,91E
ACTUAL YEAR.END RESULTS - BEFORE ITC AD.'USTMENT
EARNINGS ON COMMON STOCK
COMMON EQUITY AT YEAR END
RETURN ON YEAR-END COMMON EQUITY
EARNTNGS ON COMMON STOCK @ 9.50 ROE
EARNINGS ON COMMON STOCK @ 1O ROE
EARNTNGS ON COMMON STOCK @ 10.50 ROE
$ 226,065,530 $ 214,790,918
$ 2,198,170,379 $ 2,103,134,299
10.2gok 1O.21o/o
95.7o/o (110)
D
s
i
208,826,186 I
219,817,038 $
230.807.890 3
199,797,75E
210,313,430
220,E?9,101
(L44'9.'okl
(L44'10okl
(L44' 10.5016)
ACTUAL YEAR-END RESULTS . AFTER ITC ADJUSTMENT:
IN/ESTMENT TAX CREDIT ADJUSTMENT
ADJUSTED EARNINGS ON COMMON STOCK
ADJUSTED COMMON EQUITY AT YEAR-ENO
ADJUSTED RETURN ON YEAR.END COMMON EQUITY
$ (16,567,027) (Lrl8-143) / (1-9.5%)
$ 198,223,891
$ 2,@6567,272
9.5006
Exhibit No. 4
Case No. IPC-E-19-16
M. Annis, IPC
Page 1 of 1
lF IDAHO RETURN ON COMMON EQUITY (Line 46) <9.5%
ADDITIONAL ITC ADJUSTMENT (Annualized) lf L 54 is negative, then 0: if positive, then smaller o, 154 or S25,000,000 $
lF IDAHO RETURN ON COMMON EQUITY (Line /t6) >10%
IDAHO EARNINGS GREATER THAN 10% ROE BUT LESS THAN 10.506 s 4,974,987 (14+149y(1-10%)
lF IDAHO RETURN ON COMMON EQUITY (Line 46) >10.5%
INCREMENTAL IDAHO EARNINGS GREATER THAN 10.500/6 ROE $(143-150y(1 -10.5%)
Per Order #33149:
ROE between '10%-10.5% --CUSTOMER SHARE - 75016 (Reduction lo rates)
ROE belween '10%-10.506 --COMPANY SHARE - 25%
ROE grealer than 10.5% (lnsemental) -- CUSTOMER SHARE - 50% (Reducrion to rates)
ROE greater than 10.5% (lnsemental) -- CUSTOMER SHARE - 25% (Ofiset to Pension balane)
ROE greaterthan 10.5% (tnmmental) -- COMPANY SHARE - 25%
$3,731,240
1,243,747
0
0
0$ 4,974,987
$ s,024,s62
1
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BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPG.E.I9.1 6
IDAHO POWER COMPANY
ANNIS, DI
TESTIMONY
EXHIBIT NO.5
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Exhibit No. 5
Case No. IPC-E-19-16
M. Annis, IPC
Page 1 of 1
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
GASE NO. IPC-E-I9-16
IDAHO POWER COMPANY
ANNIS, DI
TESTIMONY
EXHIBIT NO.6
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Case No. IPC-E-19-16
M. Annis, IPC
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