20171114White Direct.pdf

RECEIVED
?0l1HOY lh Plt h: 25
, r l,?i'li ttii'!l8t'o*
BEFORE THE ]DAHO PUBLIC UTILITIES COMM]SSION
IN THE MATTER OF IDAHO POWER
COMPANY' S APPLICATION TO
ESTABLISH A METHOD OF RECOVERY
FOR COSTS ASSOC]ATED W]TH
PARTICIPATION ]N THE WESTERN
ENERGY IMBALANCE MARKET.
IDAHO POWER COMPANY
DIRECT TESTIMONY
OF
TAM] WHITE
CASE NO. IPC-E-17_76
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0.Please state your name, busi-ness address, and
present position with Idaho Power Company ("Idaho Power" or
"Company").
A. My name is Tami White and my business address
is 1,221, West Idaho Street, Boise, Idaho 83702. f am
employed by Idaho Power as the Senior Manager of Revenue
Requirement in the Regulatory Affairs Department.
O. Please describe your educational background.
A. I earned a Bachelor of Business Administration
degree in Accounting from California State UnJ-versity,
Stanislaus. I have attended various el-ectric utility
courses, including "E1ectric Utility System Operationr " a
course offered through Professional- Training Systems, Irrc.,
and "Overview of System Operations" presented by the
Western Electricity Coordinating Council. In 201,4, I
attended the Utility Executive Course at the University of
Idaho.
O. Pl-ease describe your work experience with
Idaho Power.
A. I began my employment with Idaho Power in 7999
as a Financial Analyst in the Company's Delivery Finance
Support area where I provided accounting and financial
support services to the Delivery Business Unit.
In 2005, I was promoted to Finance Team Leader where
I was responsible for leading a group of Einancial-
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1 Analysts, Accountants, and Accountj-ng Specialists in
2 providing accounting and fj-nancial support services to the
3 Operations Business Unit. I was responsible for all
4 aspects of the monthly accounting closing process for the
5 Operations Business Unit and for the monthly billing and
6 settlements processes for transmission sal-es and purchases,
7 whol-esafe energy transactions, Public Utility Regulatory
B Policies Act of 7918 transactions, large special contracts,
9 and joint use transactions.
10 While working in Operations Finance Support, I was
11 involved in the development of the Company's Federal Energy
L2 Regulatory Commission (*FERC") Open Access Transmission
13 Tariff ("OATT") formula rate for transmission services.
14 In October 2070, after 11 years in finance, I
15 accepted a position as Manager of FERC and Regional Affairs
76 in the Regulatory Affairs Department. In this position, f
77 was responsible for managing regulatory activities, such as
18 the preparation and filing of Idaho Power's OATT rates for
L9 transmission service, supervising participation and
20 settlement negotiations of Bonneville Power Adminlstration
21, rate cases, and creating analyses that form the basis for
22 Idaho Power's FERC regulatory strategy.
23 In January 2072, I was promoted to Senior Manager of
24 Rate Design. As Senior Manager of Rate Design, I was
25 responsible for the Company's rate design activities, such
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1 as regulatory ratemaking and compliance filings, tariff
2 administration, and the development of varj-ous pricing
3 strategies and policies.
4 Tn March 2011, I accepted a 12-month cross-trainJ-ng
5 assignment as Senior Manager of Revenue Requirement. As
6 Senior Manager of Revenue Requirement, I oversee the
7 Company's regulatory activities related to revenue
8 requirement, such as power supply expense modeling,
9 )urisdictional- separation studies, and Idaho Power's OATT
10 rate.
11 O. What is the Company requesting in this case?
\2 A. Idaho Power expects to begin participating in
13 the western Energy Imbal-ance Market ("EIM") begj-nning in
1,4 April 2018, dt which time benefits from Idaho Power's
15 participation-in the form of reduced net power supply
1,6 expenses (*NPSE")-wiIl begin accruing on behalf of
71 customers. The Company is requesting that the Idaho Public
18 Utilities Commission ("Commission") authorize a proposed
19 interim method for recovering j-ncremental EIM-related costs
20 that are being incurred to achieve the EfM-related
27 benefits.
22 O. How is your testimony organized in this case?
23 A. My testimony in this case first reviews Idaho
24 Power's pJ-anned participation in the western EIM as
25 detailed in the Company's filing and addressed by the
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1 Commissi-on's Order No. 33706 in Case No. IPC-E-16-19.
Next, I wil-I provide updated estimated costs associated
with Idaho Power's participatlon in the western EIM.
FinalJ-y, I will describe Idaho Power's proposed interim
method for recovery of incremental- costs associated with
participation in the western EIM and describe the estimated
Idaho jurisdictional- revenue requirement impact.
I. BACKGROT'IID
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What is an EIM?
An EIM is a real--time market to dispatch
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11 economic blds vol-untarily offered by participating
72 resources to efficlently balance supply, transfers between
13 bal-ancing authority areas, and load. An EfM solves sub-
74 hourly imbalances through an automated five-minute energy
15 dispatch service across a broad footprint with more
L6 deployable resources available, providing a more
l7 economically efficient method for maintaining ba1ance.
18 In an EIM, afl bal-ancing authority areas begin the
19 hour with matched generation and forecasted load. As
20 imbalances occur within the hour, resources within the EIM
2I can voluntarily provide bids to dispatch their facil-ities
22 to manage these imbal-ances. The market operator of the EIM
23 uses advanced market systems to look across the expanded
24 EIM region to determine the l-east-cost order of generation
25 dispatch and issues an operating target for each
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1 participating resource, resulting in the most economj-cal
2 bids avail-able to meet these imbal-ances. The real--time
3 optimization process determj-nes the least-cost mj-x of
4 resources and dispatches them to resol-ve these j-mbalances
5 while also respecting llmits on the transmission system to
6 alleviate overl-oads or congestion.
1 Q. What is the western EIM?
8 A. The western EIM is a vol-untary EIM service
9 that was implemented by the California Independent System
10 Operator (*CAlSO") and PacifiCorp on November l, 2014.
11 Since then, NV Energy, fnc.; Puget Sound Energy; Arj-zona
72 Public Service Company; and Port.land General- Efectric
13 Company have entered the market.
L4 O. How will participation in the western EIM
15 benefit Idaho Power's customers?
1,6 A. As reported by CAISO in its quarterly Western
77 EIM Benefits Reports, participation in the western EIM is
18 resulting in real,, sustainabl-e cost savings in the form of
19 reduced annual NPSE for participants. Moving from the
20 current hourly market structure to a sub-hourly, five-
2l minute imbalance market l-eads to increased surplus sales
22 opportunities as wel-l- as net cost savings from increased
23 access to others' lower-cost generation, translating into
24 reduced NPSE.
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1 Even without the requested ratemaking treatment in
2 this case, the benefits of reduced NPSE will- accrue
3 directly to Idaho Power customers through the true-up
4 component of the existing Power Cost Adjustment (*PCA")
5 mechanism, beginning in April 2078. Because the PCA tracks
6 differences in NPSE for recovery from or refund to
7 customers, the cost savings benefits of EIM participation
B w1l-l automatically be provided to customers through the
9 PCA.
10 O. Please summarize the Company's request in Case
11 No. IPC-E-I6-79.
12 A. In Case No. IPC-E-16-I9, the Company requested
13 the Commission (1) acknowledge the potential for long-term
14 benefits related to Idaho Power's participation in the
15 western EIM, (2) authorize the establ-ishment of a
76 regulatory deferral account to track incremental costs
tl associated with western EIM participation, and (3)
18 authorize the Company to recover, in a future rate
19 proceeding, the estimated incremental costs of joining the
20 western EIM.
2L At that time, the Company estimated that it woul-d
22 j-ncur $1.73 mil-lion of start-up costs, $9.36 million of
23 additional capital expenditures, and $4.68 mil-l-ion of
24 incremental- ongoing operations and maintenance ("O&M")
25 costs through 2020 to participate in the western EIM. The
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1 Company's 10-year net present val-ue revenue requirement
2 analysis filed in that case showed that partj-cipation in
3 the western EIM wiII reduce its net revenue requirement and
4 thus provide a net benefit to customers.
5 The Company al-so noted that under currently approved
6 regulatory practices, most of the benefits of reduced NPSE
7 (gS percent of the Idaho jurisdictional- share) will
8 automatically flow directly to customers through the PCA
9 mechanism, while the addi-tional start-up, capital, and
10 ongoing O&M costs, without additional ratemaking treatment,
11 would be borne by shareowners.
!2 O. Did the Company request recovery of any of the
13 additional- costs to participate in the western EIM as part
1,4 of Case No. IPC-E-16-79?
15 A. No. Idaho Power requested authority to defer
1,6 to a regulatory asset account the incrementaf costs
11 associated with participatj-on in the western EIM, and
18 requested assurance that Idaho Power's prudently incurred
19 expenses rel-ated to its participation in the western EIM
20 woul-d be recoverable in a future rate proceeding. The
21, Company did not request recovery of the incremental costs
22 of participation at that time, but indicated on pages L2-13
23 of Mr. Tatum's testimony in that case that it may be
24 necessary to implement an interim rate mechanism for cost
25 recovery to provide for proper matching of costs and
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Company
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1 benefi-ts in customer rates upon commencement of the
the western EIM.
outcome of Case No. IPC-E-L6-L9?
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Company's
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participation in
What was the
Commission Order No. 33706 issued 1n Case No
rPC-E-16-19:
o Determined that the Company's joining the
western EIM 1s reasonabl-e and in the public interest;
o Required Idaho Power to provide evi-dence of
any benefits it is receiving and how those benefits are
being passed on to customers once participation in the
western EIM begins;
o Determined that a deferra] account is the
13 appropriate mechanism to capture the
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initial- start-up costs
time as benefitsof joining the western EIM until
begin to flow to customers, and
reasonable to all-ow the Company
expenses associated with joining
def erral account,'
o Determined that
period for the deferred start-up
such
found it fair, just, and
to record the start-up O&M
the western EIM to a
a 10-year amortization
costs was reasonable;
o Eound it fair, just, and reasonabl-e to
al-low the Company to record expenses to the deferral-
account until the earl-ier of when the Company begins
recovery of western EIM costs and the deferral balance or
the end of 2078;
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o Declined to apply a carrying charge to
deferred amounts; and
o Declined to provide pre-approval for
recovery of Idaho Power's estimated incremental- costs of
joining the western EIM.
II. EIM COST UPDATES
the
that
O. Has the Company updated its quantlfication of
incremental start-up, capital, and ongoing O&M costs
wil-l- be incurred due to its participation in the
2016 2017 2018
10 western EIM?
11 A. Yes. In total, current cost estimates have
t2 decreased to $13.71 mi11ion, a reduction of $2.06 mil1ion
13 from the $15.77 mil-l-ion initiall-y estimated in Case No.
14 IPC-E-16-L9. The updated estimates are summarized in the
15 tabl-e bel-ow:
EIM Incremental Cost Estimates
in millions of dollars
As filed
in case
2019 2020 Total IPC-E-I6-19 $ Chanse
Capital
Software
Metering
Total Capital
Operation and Maintenance
Start-up costs
Ongoing O&M
Total O&M
$ 0.00
0.00
7.88 $
1.48
7.96 9.36 (1.40)
$ 0.21
0.04
$3.8 r
r.97
$ r.83
0.r0
$ 0.00 $
0.00
5.85 $
2.tl
(2.03)
0.63
0.25 5.78 r.93 0.00 0.00
0.34
0.00
0.86
0.00
0.87
0.79
0.00
1.42
0.00
1.47
2.07
3.68
1.73
4.68
0.34
( 1.00)
(0.66)0.34 0.86 1.66 1.42 1.47 s.7s 6.41
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Total projected costs $_qi59 $q,.10l $.].I9
The changes in estimated costs
j-ncreased capitalized meterlng
$ 1.42 $ r.47 $ 13.7r $ rs.77 $___p.00)
are due primarily to
costs, which were more than
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offset by reduced capitalized software costs and lower than
expected ongoing incremental O&M costs.
III. TNTERIM METTIOD FOR RECOVERY OF COSTS
O. Please describe the Company's proposal in this
case for interim recovery of incremental- costs associated
with participation in the western EIM.
A. The Company will- begin to participate in the
western EIM in April 2078, dt which time, under currently
established regulatory mechanisms, the benefits of
participation wil-l accrue to customers through l-ower actual-
NPSE included in the PCA. To most accurately match the
timing of benefits and costs of participation in the
western EIM, the Company proposes to adjust its PCA
forecast to reflect the anticipated reduction in NPSE
resulting from EIM participation and to inc1ude the revenue
requirement associated with the j-ncremental costs of EIM
participation as a temporary rate component in Schedul-e 55,
Power Cost Adjustment ("Schedule 55"), until- these costs
and benef its can be ref l-ected i-n base rates.
O. Please explain how the costs associated with
EIM participation would be coll-ected through Schedul-e 55.
A. Idaho Power proposes to incl-ude the annual
revenue requirement
recovery through a
55, similar to how
associated with EIM-refated costs for
component under Schedule
and Energy Efficlency
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revenue sharing
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1 Rider transfers have been incl-uded in Schedule 55 in recent
2 filings.
3 Q. Why does the Company believe it is appropriate
4 to util-ize Schedufe 55 for interim cost recovery of EIM-
5 related costs?
6 A. The benefits of EIM participation are in the
7 form of reduced NPSE, and in the interim these benefits
8 wiII be reflected in the forecast portion of the PCA rate,
9 which is col1ected through Schedul-e 55. The Company
l-0 believes it is appropriate to recover the EIM-rel-ated costs
1l- incurred to achj-eve those NPSE benefits through the same
12 rate schedul-e. Using Schedul-e 55 for interim cost recovery
13 of EIM-related costs wil-l- al-so provide administrative
74 efficiencies.
15 Has Idaho Power quantified the revenue
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requirement
proposing to
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associated with ElM-rel-ated costs it is
recover through Schedule 55?
Yes. Based on the current cost i-nformation
79 discussed earlier in my testimony, the estimated Idaho
20 j urisdictional- revenue
June 2078 through May
No. 1.
requirement is $3.57 million using a
shown in Exhibit201,9 test period, as
O. Under the Company's current PCA methodology,
only 95 percent of the benefits associated with EIM
participation will- flow to customers. Will the Company
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1 include 100 percent of the costs assocj-ated with EIM
2 participation in Schedule 55?
3 A. No. Idaho Power is proposing to include only
4 95 percent of the Idaho jurisdictional revenue requlrement
5 for recovery under Schedule 55. This results in $3.39
6 mill-ion ($3.57 million x 95 percent $3.39 mil-l-ion) to be
7 coll-ected f rom Idaho customers.
8 Q. Please describe the EIM costs that are
9 included 1n the revenue requirement presented in Exhibit
10 No. 1.
ll A. The EIM-rel-ated costs inc]uded in the revenue
12 requj-rement computation consist of the return on net rate
13 base (at the Company's currently authorized rate of return)
74 from the capital investment required to participate in the
15 western EIM, depreciation and amortization expense, taxes,
16 ongoing incremental O&M expenses, and amortization of
L'l deferred start-up costs. In accordance with Order No.
18 33706, the revenue requirement computation includes a 10-
19 year amortization of deferred start-up costs beginning June
20 t, 201,8, allowing the continued deferral of expenses
21 associated with EIM participation until- cost recovery
22 begins.
23 O. Wil-l the revenue requirement associated with
24 EIM-related costs be updated annually?
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A Yes. Each year the Company will estimate the
annual revenue requirement
Idaho-allocated basis, to
associated with EIM costs, on an
be recovered through Schedule 55.
The Company proposes to update Schedule 55 rates annually
with rates going into effect on June 1.
O. How does Idaho Power propose to allocate the
revenue requirement associated with EIM participation to
each class of customers?
A. The Company is proposing to collect the
10 revenue requirement through a uniform cents-per-kilowatt-
11 hour ("kwh") rate, in the same manner that forecasted EIM
12 benefits will be applied to customer rates. For
13 il1ustrative purposes, the Company has provided an example
74 of Schedule 55 modified to include this rate component as
15 Exhibit No. 2. Based on 95 percent of the $3.57 mil-lion
!6 Idaho jurisdictional revenue requirement, or $3.39 milllon,
1,7 and the Company's normalized Idaho jurisdictional forecast
18 sal-es for the June 20LB through May 2019 test period of
79 74,295,406 megawatt-hours ("MWh"), the EIM cost recovery
20 rate included on Schedule 55 would be 0.0231 cents per kwh
27 ( ($3,393,272 / 74,295,406 MWh) $0.231A/MWb : 0.0237
22 cents/kwh). Please note that the sample Schedule 55
23 provided as Exhibit No. 2 ts for i1Iustrative purposes only
24 and is intended to demonstrate the Company's proposal to
25 collect ETM-related costs through Schedule 55. The Company
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is not proposing any rate changes to Schedule 55 at this
time.
O. Please explain how forecasted EIM benefits
will be included in customer rates.
A. The Company proposes to estimate EIM benefits
on an annual basls and incl-ude the benefits as an offset to
the PCA forecast of NPSE. The forecasted EIM benefits will
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be captured
is recovered
demonstrated
Schedule 55
O.
A.
in the forecast portion of the PCA rate, which
from customers on a cents-per-kWh basis, ds
in the Projected Power Cost section of
inc]uded as Exhibit No. 2.
How will EIM benefits be estimated?
For the first year of participation, the
assumed to equal the estimated
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estimated benefits
costs, resulting in a net zero impact to NPSE and customer
gai-ns experience in the EIM, lt
forecast of EIM benefits for
wiII be
determining
information
the forecast
rates. As the Company
intends to update this
inclusion in subsequent PCA filings.
EIM benefits
The method of
will incorporate
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from quarterly EIM benefits reports received
27 from CAISO as well as any other availab1e pertinent data.
22 O. Has the Company updated its analysj-s of the
23 benefits that may be derived from participation in the EIM?
24 A. No. The Energy and Environmental Economics,
25 Inc. ("E3") study used to estimate EIM benefits has not
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been updated from
TPC-E-1 6-79 -
O. What
A. E3'S
the original study used in Case No
estimate of EIM benefits?
scenario estimated savings of
annually on a system basis.
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was E3's
basel-ine
approximately $4. 5 mil-l-ion
Anderson DI, p. 71.
O. Why is the Company not proposing to use this
amount to estimate June 20tB through May 2019 EIM savings?
A. Due to the uncertainty surrounding the level
of benefits that wifl be achieved during the first year of
participation and the number of assumptj-ons inherent in
E3's study, the Company believes that it would be prudent
to take a conservative approach to estimating the benefits
until- it has actual experience participating in the EIM.
The Company also believes the proposal to set EIM benefits
equal to costs for the first year of participation is
reasonable as EIM benefits will- automatically be trued-up
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through
the form
accounts
of NPSE
the existing PCA mechanism. ActuaI benefits, in
of reduced NPSE, will accrue through the NPSE
of the PCA. Any variance between the PCA forecast
and actual NPSE, includj-ng the benefits assoclated
with EIM participation, will be captured in the true-up
bal-ance of the PCA.
0. Will the EIM-related annua] revenue
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A. Yes. The Company wil-l- recal-cufate the revenue
requirement annual1y, based on actual- costs, from the prior
calendar year for true-up in the subsequent year, j-ncluding
changes in rate base.
0. Please elaborate on how the true-up wou1d be
calcul-ated.
A. In February of each year, the Company wil-l-
recalculate the Idaho jurisdictional- revenue requirement
based on actual costs and compare it to the revenue
requirement included in customer rates. Any under- or
over-recovery woul-d be collected or refunded as part of the
Schedul-e 55 EIM Participation Cost rate component in the
following year, in conjunction with the fol-l-owing year's
updated Idaho jurisdictional- revenue requirement.
For example, in Eebruary 2019, Idaho Power proposes
to submit a compliance filing in this docket to provide an
updated revenue requirement computation that incl-udes seven
months of actual EIM-related costs (June-December 2018) and
five months of forecasted costs (January-May 201,9). Idaho
Power wj-1l compare this updated revenue requirement amount
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would be22 collected in customer rates. Any variance
23 j-ncl-uded for coll-ection or refund beginning June t, 20L9.
24 In addition to cal-culating the revenue requirement true-up
25 in February 20L9, the Company wj-l-l- al-so prepare a revenue
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requirement estimate for the June 20L9 through May 2020
test period. Together, the net of these two components
will- be included for recovery through Schedul-e 55,
beginnj-ng June 7, 2079.
fn February 2020, Idaho Power w111 submit a
compliance filing t.o
computation for the
that wil-f include 12
provide the final- revenue
June 2078 through May 2019
months of actual costs.
requirement
test period
Idaho Power
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will compare this final updated revenue requirement
computation to the June 20LB through May 2079 revenue
requirement collected through customer rates. Any variance
would be included for collection or refund through this
mechanism, beginning June 7, 2020.
O. Has the Company prepared an exhibit to
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15 demonstrate how the annual- true-up will work?
16 A. Yes. Pl-ease see Exhibit No. 3, which provides
l1 a numerical example as well as a timel-ine that summarizes
18 the annual- true-up process described above.
19 O. Why is the Company proposing to provide this
20 compliance filing each year in February?
21 A. fdaho Power is proposing to provide Commission
22 Staff ("Staff") and intervening parties this information by
23 the end of February each year to al-l-ow adequate time for
24 review of the prudence of the incurred costs and accuracy
25 of the true-up calculation, as well as the following year's
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forecasted revenue requi-rement computation. The Company
wil-l- then seek approval of the revenue requj-rement true-up
amount and the fol-lowing year's revenue requirement
computation as part of the annual- PCA filing.
O. What happens in subsequent years?
A. Estimated benefits will continue to be
included in the PCA forecast as an offset to NPSE, and the
revenue requirement associated with EIM-rel-ated costs wil-l
be recovered through Schedule 55, updated and trued up
annua1ly.
Until the EIM benefits and costs are incorporated
into base rates through a future rate proceedj-ng, the cost
recovery methodology would not change.
O. Why not wait for a general rate case to
15 incl-ude the incremental EIM costs in rates at that ti-me?
term, the Company envisions that
associated with its
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L1 both the benefits and costs
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participation
rates through
the timing of
woul-d adj ust
mechanism for recovery
costs and
in the western EIM would be refl-ected in base
a future rate proceeding. However, because
the Company's next regulatory proceeding that
base rates is not known, dD interim rate
cost is necessary to provide for
Z3 proper matching
The cost/benefit24
benefits 1n customer rates.
matching proposed by the Company in this
that the customers who receive the
of
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1 benefits of Idaho Power's participation in the EIM also pay
2 for the costs to participate.
IV. CONCLUSION
O. Please summarize the Company's request.
A. Idaho Power is requesting authority to
establish an interim recovery mechanism for costs
associated with participation in the western EIM beginning
June 1-, 20L8, through a rate component of Schedule 55. The
Company bel-ieves the ratemaking treatment proposed in this
case 1s appropriate for several reasons.
The proposal closely matches the tlming of the EIM-
rel-ated benefits, whi-ch will begin accruing to customers
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13 through reduced NPSE in April 2018, with the recovery of
L4 the costs. A1so, with the proposed true-up mechanism for
15 estimated costs, Idaho Power wil-I coll-ect actual- EIM-
76 rel-ated costs and all costs will be subject to
71 review by Staff and approval by the Commission.
1B absent the ability to recover j-ncremental- costs
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thorough
Fina11y,
associ-ated
with EIM participation, Idaho Power woul-d suffer negative
financial impacts. The costs and benefits of EIM
participation should continue to be refl-ected in Schedule
55, until- they can be incorporated into base rates j-n a
future proceeding.
wHrTE, Dr 79
Idaho Power Company
1 Q. Is there a specific date the Company requests
2 the Commission to consider as it contemplates the schedule
3 for the processing of this case?
4 A. Yes. In order to inc1ude any impacts of this
5 filing in the next PCA filing, the Company respectfully
6 requests the Commission consider a case schedule that would
7 all-ow for an order to be issued by March 31, 201,8.
I Q. Do you believe that approval of the Company's
9 request in this case wil-l- serve the public interest and
10 provide Idaho Power a reasonabl-e opportunity to recover its
11 prudently j-ncurred costs rel-ated to its participation in
72 the western EIM?
13
74
15
76
L1
1B
79
20
27
22
A
O
A
Yes, I do.
Does this complete your testj-mony?
Yes, it does.
23
24
wHrTE, Dr 20
fdaho Power Company
25
1
2
3
4
trJ
6
1
9
ATTESTATION OF TESTIMONY
STATE OF IDAHO
SS.
County of Ada
I, Tami White, having been duly sworn to testify
truthfully, and based upon my personal knowledge, state the
following:
I am employed by Idaho Power Company as the Senior
Manager of Revenue Requirement and am competent to be a
witness in this proceeding.
f declare under penalty of perjury of the .l-aws of
the state of fdaho that the foregoing pre-filed testimony
and exhibits are true and correct to the best of my
information and belief.
DATED this 14tt day of November 20L7.
Tami V[hlte
SUBSCRIBED AND SWORN to before me thls 14th day of
November 20L7.
;3.S3
t
Notary for
Residing at:Boise Idaho
My commission expires: 02/04/2027
wHrTE, Dr 2L
Idaho Power Company
10
11
72
13
t4
15
76
L1
1B
79
20
2L
22
23
24
25
26
27
2B
6otA4,
lulr,lc
rDa-t
I lg DT 10
.4r^LD/H.
;q
BEFORE THE
!DAHO PUBLIG UTILITIES GOMMISSION
cAsE NO. IPC-E-17-16
IDAHO POWER COMPANY
WHITE, DI
TESTIMONY
EXHIBIT NO. 1
ldaho Power Company
Western EIM Participation Costs
ldaho Jurisdictional Revenue Requirement
RATE BASE 612Ot8-Slz0te
1 Electric Plant in Service
2 lntangible Plant
3 Production Plant
4 Total Electric Plant in Service
5 Less: Accumulated Depreciation
5 Less: Amortization of Other Plant
7 Net Electric Plant in Service
8 Less: Accumulated Deferred lncome Taxes
9 Add: Other Deferred Amounts
10 TOTAL COMBINED RATE BASE
NET INCOME
S 5,598,587
2,077,407
7,6L5,994
28,922
54L,799
7,O45,2-13
814,303
t,965,442S a,ogs,+rz
s
t,3L7,926
57,844
t,279,357
37,689
1,3L3,409
(2,205,959)
(255,368)
1,538,898
(1,538,898)
(1,538,898)
1.86%
2,L75,276
7.642
s 3,571,902
9s%
s 3,393,212
Exhibit No. 1
Case No. IPC-E-17-'16
T. White, IPC
Page 1 of 1
11 Operating Revenues
72 Sales Revenues
13 Operating Expenses
t4 Operation and Maintenance Expenses
15 Depreciation Expenses
16 Amortization of Limited Term Plant
t7 Taxes Other Than lncome
18 Provision for Deferred lncome Taxes
19 Federal lncome Taxes
20 State lncome Taxes
2t Total Operating Expenses
22 Operating lncome
23 Consolidated Operating lncome
25 Authorized Rate of Return
26 Earnings lmpact
27 Net-to-Gross Tax Multiplier
28 Revenue Requirement
ldaho sharing percentage
IDAHO EIM COST RECOVERY AMOUNT
BEFORE THE
IDAHO PUBLIC UTILITIES GOMMISSION
GASE NO. IPC-E-17-16
IDAHO POWER COMPANY
WHITE, DI
TESTIMONY
EXHIBIT NO.2
ldaho Power Company enventnfwe[h Revised Sheet No. 55-1
Cancels
l.P.U.C. No. 29, Tariff No, lOlTenthEleventh Revised Sheet No. 55-1
SCHEDULE 55
POWER COST ADJUSTMENT
APPLICABILITY
This schedule is applicable to the electric energy delivered to all ldaho retail Customers served
under the Company's schedules and Special Contracts. These loads are referred to as "firm" load for
purposes of this schedule.
BASE POWER COST
The Base Power Cost of the Company's rates is computed by dividing the sum of the Company's
power cost components by firm kWh sales. The power cost components are segmented into three
categories: Category 1, Category 2 and Category 3. Category 1 power costs include the sum of fuel
expense and purchased power expense (excluding purchases from cogeneration and small power
producers), less the sum of off-system surplus sales revenue and revenue from market-based special
contract pricing. Category 2 power costs include purchased power expense from cogeneration and small
power producers. Category 3 power costs include demand response incentive payments. The Base
Power Cost is 2.0838 cents per kWh, which is comprised of Category 1 power costs of 1.0927 cents per
kWh, Category 2 power costs of 0.9108 cents per kWh and Category 3 power costs of 0.0803 cents per
kwh.
The Projected Power Cost is the Company estimate, expressed in cents per kWh, of the Category
1, Category 2 and Category 3 power cost components for the forecasted time period beginning April 1
each year and ending the following March 31. The Projected Power Cost is 2.5708 cents per kWh, which
is comprised of Category 1 power costs of 1.2815 cents per kWh, Category 2 power costs of 1.2365
cents per kWh and Category 3 power costs of 0.0528 cents per kWh. The forecasted customer benefits
associated with ldaho Power's participation in the western Enerqv lmbalance Market are reflected in the
Cateqory 1 power cost component of the Proiected Power Cost.
TRUE.UP AND P o FTH E TRUE-UP
The True-up is based upon the difference between the previous Projected Power Cost and the
power costs actually incurred. The True-up of the True-up is the difference between the previous year's
approved True-Up revenues and actual revenues collected. The total True-up is 0.2585 cents per kWh.
EARNINGS SHARING
Order Nos. 30978, 32424, and 33149 directed the Company to share a portion of its earnings
above a certain threshold with customers through the annual Power Cost Adjustment. The Company's
2016 earnings were below the prescribed threshold resulting in a credit of 0.0000.
Schedule
I
3
5
7
9S
9P
d per kWh
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
Description
Residential Service
Master Metered Mobile Home Park
Residential - Time-of-Day Pilot Plan
Small General Service
Large General Service - Secondary
Large General Service - Primary Exhibit No. 2
Case No. IPC-E-17-16
T. White, IPC
Page 1 of3
IDAHO
lssued per Order No. 33775
Effective - Jun€-+2O+7
lssued by IDAHO POWER COMPANY
Timothy E. Tatum, Vice President, Regulatory Affairs
1221 West ldaho Street, Boise, ldaho
ldaho Power Company Sixth Revised Sheet No. 55-2
Cancels
|.P.U.C. No. 29. Tariff No. 101 Fifth Revised Sheet No. 55-2
SCHEDULE 55
POWER COST ADJUSTMENT
(Continued)
EARNINGS SHARING (Continued)
9T
15
195
19P
197
24
40
41
42
Large General Service - Transmission
Dusk to Dawn Lighting
Large Power Service - Secondary
Large Power Service - Primary
Large Power Service - Transmission
Agricultural I rrigation Service
Unmetered General Service
Street Lighting
Traffic Control Lighting
Monthlv Credit
Micron
Simplot
DOE
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
$0.00
$0.00
$0.00
(0.057e)
(0.0543)
(0.056s)
d per kWh
(0.1 148)
(0.1097)
(0.1 107)
(0.1463)
(0.0864)
(0.o7so)
(0.0846)
(0.2486)
(0.0746)
(0.0661)
(0.062s)
(0.0e3e)
(0.1032)
(0.1633)
(0.0730)
26
29
30
REFUND OF ENERGY EFFICIENCY ("EE') RIDER FUNDS
The following rate schedules will receive a rate credit associated with the refund of EE Rider funds
in the form of a cents per kWh rate.
Schedule Description
Residential Service
Master Metered Mobile Home Park
Residential - Time-of-Day Pilot Plan
Small GeneralService
Large General Service - Secondary
Large General Service - Primary
Large General Service - Transmission
Dusk to Dawn Lighting
Large Power Service - Secondary
Large Power Service - Primary
Large Power Service - Transmission
Agricultural lrrigation Service
Unmetered General Service
Street Lighting
Traffic Control Lighti ng
Micron
Simplot
DOE
1
3
5
7
9S
9P
9T
15
195
19P
197
24
40
41
42
26
29
30
Exhibit No. 2
Case No. IPC-E-17-16
T. White, IPC
Page 2 of 3
IDAHO
lssued per Order No. 33775
Effective - June 1, 2017
lssued by IDAHO POWER COMPANY
Timothy E. Tatum, Vice President, Regulatory Affairs
1221 West ldaho Street, Boise, ldaho
ldaho Power Company Fifrh$jlh Revised Sheet No. 55-3
Cancels
LP.U.C. No. 29. Tariff No. 101 Eeu#hFifth Revised Sheet No. 55-3
SCHEDULE 55
POWER COST ADJUSTMENT
(Continued)
ENERGY IMBALANCE MARKET PARTICIPATION COSTS
Order No.orovides for cost recovery of the incremental costs associated with ldaho
Power's participation in the western Enerqv lmbalance fvlarket. The Enerqv lmbalance Market
Participation Cost is 0.0237 cents per kWh based upon the ldaho iurisdictional revenue requirement
associated with western Enerqv lmbalance Market participation costs.
POWER COST ADJUSTMENT
The Power Cost Adjustment is the sum of: 1) 95 percent of the difference between the Projected
Power Costs in Category 1 and the Base Power Costs in Category 1;2) 100 percent of the difference
between the Projected Power Costs in Category 2 and the Base Power Costs in Category 2; 3) 100
percent of the difference between the Projected Power Costs in Category 3 and the Base Power Costs
in Category 3; 4) the True-ups; 5) Earnings Sharing; and 6) the refund of EE Rider funds.
The monthly Power Cost Adjustment rates applied to the Energy rate of all metered schedules
and Special Contracts are shown below. The monthly Power Cost Adjustment applied to the per unit
charges of the nonmetered schedules is the monthly estimated usage times the cents per kWh rates
shown below.
Schedule Description
Residential Service
Mastered Metered Mobile Home Park
Residential - Time-of-Day Pilot Plan
Small GeneralService
Large General Service - Secondary
Large General Service - Primary
Large General Service - Transmission
Dusk to Dawn Lighting
Large Power Service - Secondary
Large Power Service - Primary
Large Power Service - Transmission
Agricultural lrrigation Service
Unmetered General Service
Street Lighting
Traffic Control Lighting
Micron
Simplot
DOE
d per kWh
0.6213
0.6264
0.6254
0.5898
0.6497
0.6611
0.6515
0.4875
0.661s
0.6700
0.6736
0.6422
0.6329
0.5728
0.6631
1
3
5
7
9S
9P
9T
15
195
19P
197
24
40
41
42
26
29
30
EXPIRATION
0.6782
0.6818
0.6796
The Power Cost Adjustment included on this schedule will expire May 31,2018.
Exhibit No. 2
Case No. IPC-E-17-16
T. White, IPC
Page 3 of 3
IDAHO
lssued per Order lrle. 33775
Effective - June-4#e#
lssued by IDAHO POWER COMPANY
Timothy E. Tatum, Vice President, Regulatory Affairs
1221 West ldaho Street, Boise, ldaho
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-17-16
IDAHO POWER COMPANY
WHITE, DI
TESTIMONY
EXHIBIT NO.3
Energy lmbalance Market Cost Recovery
Revenue Requirement True-up Process
Note the omounts presented in this exhibit ore for illustrotive purposes only.
June 2018-May 2019 ldaho Jurisdictional Revenue Requirement
lnitial revenuerequirementestimate(95%) S 3,393,212 A lncludedinSchedule55ratesJunel,20ls
Updated revenue requirement estimate (95%)
filed February 2019
(7 months actuals; 5 months estimates) S 3,000,000
True-up S (393,212) B lncluded in Schedule 55 rates June 1, 2019
Final actual revenue requirement (95%)
filed February 2020
(12 month actuals) S 2,900,000 cFinalTrue-up $ (100,000)D lncludedinScheduleSsratesJunel,2O2O
June 2019-May 2020 ldaho Jurisdictional Revenue Requirement
lnitial revenue requirement estimate
filed February 2019 (95%l
Updated revenue requirement estimate (95%)
filed February 2020
(7 months actuals; 5 months estimates)
S 3,000,000 E lncluded in Schedule 55 rates June 1, 2019
S 2,9oo,ooo
True-up $ (100,000) F lncluded in Schedule 55 rates June 1, 2020
Final actual revenue requirement (95%)
filed February 2021
(12 month actuals)s 2,8s0,000
Final True-up s lncluded in Schedule 55 rates June 1, 2021(s0,000)
G
H
+These amounts would also include the initial revenue requirement estimates for June 2O2O-May 2O2L and June 2021-May
2022, respectively, but for purposes of limiting this exhibit to a two-year review of the revenue requirement true-up
process, these amounts have been excluded.
Exhibit No. 3
Case No. IPC-E-17-16
T. White, IPC
Page 1 of 2
Amounts lncluded in Schedule 55 Rates
June 2018-May 2019 Schedule 55 Rates
June 2019-May 2020 Schedule 55 Rates
June 2020.May 2021 Schedule 55 Rates
June 2021-May 2022 Schedule 55 Rates
Total collected through Schedule 55 Rates
Revenue Requirement
June 2018-
May 2019
June 2019-
May 2020
Total Requested Recovery
throu8h Schedule 55 Rates
S 3,393,2L2 A
(393,212) B
(100,000) D
NA
N/A
S 3,ooo,ooo E
F
H
(100,000)
(s0,000)
$3,393,212
2,606,788
(200,000) *
(5o,ooo) +
s 5,750,000S 2,9oo,ooo c s 2,8s0,000 G
Date Documentation Provided lntent
April2018 2018 PCA filing, which will include a
discussion of the EIM costs being included
for recovery through Schedule 55
Seek approval ofthe estimated revenue
requirement computation as filed in this case, as
well as the resulting EIM cost recovery rate to be
included in Schedule 55, beginning June 1, 2018
February 2019 Updated revenue requirement computation
for June 2018 - May 2019; includes 7
months actual costs and 5 months
estimated costs
lnitial estimated revenue requirement
comoutation for June 2019 - Mav 2020
Review of the incurred costs and review of the
revenue requirement true-up calculation
Review of the new estimated revenue
reouirement computation
April2019 2019 PCA filing, which will include a
discussion of the EIM costs being included
for recovery through Schedule 55
Seek approval of the revenue requirement true-
up amount and the updated revenue
requirement computation as provided in
February 2019, as well as the resulting EIM cost
recovery rate to be included in Schedule 55,
hesinnino lrrne 1 2O1 I
February 2020 Final actual revenue requirement
computation for June 2018 - May 2019;
includes 12 months actual costs
Updated revenue requirement computation
for June 2019 - May 2020; includes 7
months actual costs and 5 months
estimated costs
Estimated revenue requirement
computation for June 2O2O - Mav 2O2L
Review of the incurred costs and review of the
revenue requirement true-up calculation for both
test years
Review of the new estimated revenue
requirement computation
April2020 2020 PCA filing, which will include a
discussion of the EIM costs being included
for recovery through Schedule 55
Seek approval of the revenue requirement true-
up amount and the updated revenue
requirement computation as provided in
February 2020, as well as the resulting EIM cost
recovery rate to be included in Schedule 55,
haoinnino lrrne 1 7O7O
Energy lmbalance Market Cost Recovery
Revenue Requirement True-up Process
Exhibit No. 3
Case No. IPC-E-17-16
T. White, IPC
Page 2 of 2