20150415Wright Direct.pdf

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UTILITI
BEFORE THE IDAHO PUBLIC UTILTTIES COMMISSION
.ii,*' i- irtr ,1-.i tt,*U L"-jl:lti i-*,-: ,!r{
IN THE MATTER OF THE APPLICATION
OF ]DAHO POI/{ER COMPANY FOR
AUTHORTTY TO IMPLEMENT POI/{ER COST
ADJUSTMENT (*PCA") RATES FOR
ELECTRIC SERVICE FROM JUNE T,
2075, THROUGH MAY 31, 20L6.
CASE NO.rPc-E-15-14
IDAHO POWER COMPANY
DIRECT TESTIMONY
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SCOTT WRIGHT
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A.
O. Please state your name, business address, and
present position with Idaho Power Company ("Idaho Power" or
ttCompany" ) .
A.My name is Scott Wright. My business address
is 122! West Idaho Street, Boise, Idaho 83102. I am
employed by Idaho Power as a Regulatory Analyst II in the
Regulatory Affairs Department.
P1ease descrj-be your educatj-onal background.
I received a Bachelor of Science degree in
Busj-ness Economics from Eastern Oregon Uni-versity. I have
al-so attended the Center for Publ-ic Utilities "Practical
Skills for a Changing Electric Industry" a course offered
through New Mexico State University in Albuquereu€, New
Mexico, the Edj-son Electric fnstitute's "Electric Rate
Advanced Course" in Madison, Wisconsin, the NERA "Margina1
Costing for Electric Utilities", in Los Angeles,
Cal-ifornia, and the Financial Accounting Institute "Utility
Finance and Accounting Course" in Las Vegas, Nevada.
o.Pl-ease describe your work experience with
Idaho Power.
A. In May L998, I accepted a position as Research
Assistant with Idaho Power in the Regulatory Affairs
Department. fn March 2001, T was promoted to a Regulatory
Analyst. In March 2010, T was promoted to a Regulatory
Analyst II. As a Regulatory Analyst If, I am responsJ-b1e
WRIGHT, DI 1
Idaho Power Company
1 for running the AURORA model to calculate Net Power Supply
2 Expenses (*NPSE") for ratemakj-ng purposes, preparing the
3 Power Cost Adjustment filings in Idaho and Oregon, as well-
4 as the marginal- cost of energy used in the Company's
5 marginal cost analysis. I also provide analytical support
6 for other regulatory activitles within the Regulatory
7 Affairs Department, as wel-I as providing testimony in other
8 Company filings.
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11 quantification of the 2075-2076 PCA rates to become
12 effective June 1-, 2075. If approved, the 20L5-2016 PCA
13 w111 result in a revenue decrease of approximately $10.1
L4 million, or a 0. 91 percent.
O. What is the Company requesting in this case?
A. The Company is requesting approval of its
O. How is the Company's case organized?
A. The Company's case includes testimony and
L7 exhibits from two witnesses. My testimony provides an
18 overview of the PCA, describes the determination of the
1,9 201-5-2076 PCA amount, identifies and explaj-ns the main
20 factors contributing to this year's PCA amount, and
2L presents the quantification of the 20L5-2076 PCA rates.
22 Kelley K. Noe provides testimony that describes the
23 quantification of the revenue sharing amount to be included
24 in this year's PCA.
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V'IRIGHT, DI 2
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I. O\TERVIETf, OF PCA COMPONENTS
O. What is the purpose of the PCA and how does
the mechanism function?
A.The PCA is a rate mechanism that quanti-fies
and tracks annual- differences between actual NPSE and the
normalized or "base levef" of NPSE recovered in the
Company's base rates for recovery or credit through an
annual rate change on June 1. The PCA mechanj-sm utilj-zes a
12-month test period of April through March (*PCA Year")
and is comprised of a forecast component and a PCA True-Up
component. The PCA forecast component is based on the
Company's March Operating PIan and represents the
difference between the NPSE forecast from the March
Operating PIan and the base level NPSE recovered in the
Company's base rates. The PCA True-Up incl-udes a backward
looking tracking of differences between the prj-or year's
forecast and actual NPSE incurred by the Company during the
prior PCA year. The PCA True-Up contains a second
component that tracks the coll-ection of the prior year's
true-up amount, referred to as the "True-Up of the True-
Up."
With the exceptj-on of PubIic Utility Regulatory
Policies Act of 1978 (*PURPA") expenses and demand response
incentive costs, the PCA allows the Company to pass through
to customers 95 percent of the annual dj-fferences in actual
WRIGHT, DI 3
Idaho Power Company
I NPSE as compared to the base l-evel NPSE, whether positive
2 or negative. The PCA is also the rate mechanism used by
3 the Company to provide direct revenue sharing benefits
4 resulting from the revenue sharing mechanism approved by
5 Order No . 32424.
O. What comprises the components of the PCA base
7 level NPSE?
I A. The PCA base leve1 NPSE include the following
9 Federal- Energy Regulatory Commission (*FERC") accounts:
10 FERC Account 501, fuel (coal-); FERC Account 536, water for
11 power; EERC Account 541, fuel- (gas); FERC Account 555,
72 purchased power FERC Account 565, transmissj-on of
13 electricity by others; and FERC Account 447, sales for
L4 resale (typically referred to as surplus sales).
15 The PCA base level expense component for FERC
16 Account 555 j-ncludes both power purchases resulting from
1-7 PURPA and non-PURPA (market) purchases. As per Order No.
18 32426, the Company adjusts FERC Account 555 to include
19 demand response i-ncentive payments that the Company
20 provides to customers for participating in any of its three
27 demand response programs.
22 rr. 20L5-20L6 PCA,
23 O. What is the total 2075-20L6 PCA amount as
24 measured from the currently approved base level NPSE?
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wRrGHT, Dr 4
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A.Approved on March, 21, 20L4, Order No. 33000
authorized Idaho Power's current base level- NPSE. The
2075-2016 total PCA amount (including revenue sharlng and a
$4.0 million DSM Rider adjustment) as measured from the
currently approved base 1evel NPSE is $63.1 mil-Iion. This
represents a decrease in total billed revenue of $10.1
million for the upcoming year, a reduction of 0.91 percent.
PCA Forecast
O. What is the Company's determination of the
system-Ieve1 dj-fference between the currently approved base
l-evel NPSE and the forecast of NPSE for the 20L5-2016 PCA
Year?
A.The system-Ievel- forecast of NPSE for the
2075-20L6 PCA Year 1s for $348,384,726, which is
$42,699,257 higher than the currently approved base level-
NPSE of $305,684,869. The foll-owing Table 1- presents the
system-Ievel differences between the currentl-y approved
base level- NPSE and the forecast of NPSE for the 201,5-20L6
PCA Year by each NPSE category.
WRIGHT, DI 5
Idaho Power Company
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Table 1:201$rc16 PCA FORECAST (Total System)
Line No.FERC Account Base NPSE Forecast Difference
1.
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95% Sharing AcFounts
Account 501, Coal
Account 536, Waterfor Power
Account 547, Other Fuel
Account 555, Purchased Power Non-PURPA
Account 565, 3rd Party Transmission
Account 2147, Surplus Sales
s
s
s
s
s
s
108,s03,180
2,380,597
33,367,563
62,606,593
5,455,955
(s1,73s,1s3)
t77,032,475
2,425,23O
57,t73,815
48,372,214
6,453,427
(39,c4,8,702],
s
s
s
s
s
s
s
S
s
s
s
s
8,529,295
M,633
23,806.,252
(L4,2U,3791
997,472
12,686,457
1097o Sharine Aqcgunts
7. Account 555, PURPA
8. Account 555, Demand Response lncentives
Ss
s
s
L60,578,735
133,8s3,869
tL,252,265
t92,48,4s9 5 3t,829,724
L48,0s,626 5 t4,2@,7s7
7,e2t,u\ $ 13,331,224"
S
s
9. Total s 30s,684,869 s 34a3%,t26 5 qZ,eW,ZSt
O. What is the basis for the forecast of NPSE for
the 2OL5-2076 PCA Year?
A. The forecast of NPSE for the 20L5-2016 PCA
Year is based upon the Company's March 26, 2075, Operating
Plan ("Operatj-ng P1an") .
a. How is the NPSE forecast developed for the
Company's Operating Plan?
A. The Company's Operating Plan is produced
monthly and forecasts 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 economic dispatch of the Company's generation resources
for each month, segmented by heavy load and light ]oad
hours. The dispatch considers a current forecast of
forward market energy prices, available hydro generation,
wRrGHT, Dr 6
Idaho Power Company
1 coal- and natural gas prices, and any existing hedge
2 transactions. The system l-oad forecast is then analyzed
3 against the resul-tj-ng monthly heavy load and light l-oad
4 dispatch to determine a monthly load and resource balance.
5 Any identified resource deficiency is assumed to be filled
6 with market energy purchases. Economically dispatched
7 generation above the system load forecast represents
8 surplus energy sales.
O. How does the Company's forecast of NPSE for
10 the 2075-2016 PCA compare to the forecast in last year's
11 PCA?
T2 A. As can be seen on Table 2, the PCA forecast on
13 a total forecast system basis for the 201,5-20L6 PCA is
L4 expected to be $348,384,126, which is $18,357,810 higher
15 than last year's forecast amount of $330,026,256.
Table 2:PCA Forecast Comoarison Exoenses (Tortal Svsteml
Line No.FERC Account
20t4-2015 20L5-20L6
Forecast Forecast Difference
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95 % Sharing Accounts
Account 501, Coa I
Account 536, Water for Power
Account 547, Other Fuel
Account 555, Purchased Power Non-PURPI
Account 565, 3rd Pa rty Tra ns mis si on
Account 447. Surolus Sa I es
S 169,424,879s 1,7s1,ooo
s 73,947,673
s 61,9s6,8s3
5 6,64s,77s
S (12G.1G6.s131
5 777,O32,47s
s 2,42s,23O
s s7,173,87s
5 48,372,21.4
5 6,4s3,427
S (39.048.7021
s $2,392,404)
S . 674,230
s (16,767,8s8)
s 173,624,63s1
s (1s2,348)
S a7.7ta.2tl
1OO% Sharing AccAUnts
7. Account 555, PURPA
8. Account 555, Demand Response
5 t87,s93,267
s L34,!42,386
lncentiv. S 8.290.603
5 792,4OA,4s9 5 4,8Ls,792
$ t48,Os4,626 5 t3,9t2,240
s 7.921.O4L s (369.s62)
9.Total PCA Forecast
s
s
742,432,9a9 s1ss,97s,667 $ L3,s42,678
330.026.256 s348.384.126 s 18.357.37076
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0. What concl-usions can be drawn from the
information contained in Table 2?
WRIGHT, DI 1
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A.Table 2 compares this year's 2075-2076 PCA
forecast to last year's PCA forecast for each NPSE
category. As can be seen on Tabl-e 2, the 95 percent
sharing accounts represent an increase of $4.8 million and
the 100 percent sharing accounts represent an increase of
$13.5 mill-ion over l-ast year's 2074-2075 PCA forecast.
o.What factors do you believe contributed to the
major differences presented on Table 2?
A.Lower market energy prices have driven down
the Company's expectation of surpJ-us sales revenue by 69
percent as compared to last year's forecast. The reductj-on
in surplus sales revenue is, however, largely offset by the
reductions in coal and gas production costs and lower Non-
PURPA market energy purchases. Increases in PURPA costs
account for approximately 76 percent or $13.9 million of
the year-over-year lncrease in this year's PCA forecast.
o.Is the increase in PURPA costs related to
increased generation output from PURPA projects?
A.No. The increase in PURPA expense j-s largely
the result of a higher per-unit cost, not vol-umes. As can
be seen on the following Table 3, PURPA generation output
is anticipated to increase by only 131 thousand megawatt-
hours ('MWh") , or 6 percent, as compared to last year's PCA
forecast. The majority of the 76 percent j-ncrease in
PURPA-rel-ated costs can be attributed to price escalation
v{RrGHT, Dr I
Idaho Power Company
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in PURPA contracts and updated production curves based on
newly available historical- operational data.
O.What else can be concluded from the
information in Table 3?
A.The first item of note in Table 3 is the
additlonal hydro generation of 1.2 million MWh over last
year's PCA forecast. The April-July Brownlee Reservoir
infl-ow forecast for this year's PCA forecast is 4.5 million
acre feet (*MAF"), as compared to last years forecast of
3.6 MAF for the same months. The 30-year average April-
July Brownlee Reservoir inflow is 5.5 MAF, 1.0 MAF above
this year's forecast. The additional forecasted
streamflows for this year's PCA forecast over last year's
PCA forecast is expected to increase hydro generation by 18
percent.
WRIGHT, DI 9
Idaho Power Company
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table 3:PCA Forecast Comparison Generation (Total Svstem-MWhl
Line No.FERC Account 201t1-2015 Forecast 201$2016 Forecast Differe nce
1.Hydro 6,912,870
6,529,271
2,t14,t21
1.345.589
8,L.32,99L
3,953,050
2,297,6@
858.438
t?2o,t?t
(1,576,272],
183,488
(487.151)
95% Sharine Accounts
2. Account 501, Coal
3. Account 547, Other Fuel
4. Account 555, Purchased Power Non-PURPA
5.
1007o Sharins Accounts
Account 555, PURPA
15,90L,852
2,067,959
1s,242,W8 (r,6s9,7s41
2.tgg.2t6 131.257
6.
10@o Accounts
Total Generation
2,067,959
18.969.811
2,t99,2t6 13r,257
L7.447.314 n.s28.497\
95% Sharine Acco.qnts
8. Account44T, Surplus Sales 3.397.32t L.65L.2il (L.746.0s7',1
9. Total Load L5.572,49) 15.790.050 2t7.560
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Surplus sales vofumes are expected to decrease by 51
percent or 1.7 million MV[h from last year, resulting from
the lower market prices that were mentioned earlier in my
testimony. The combinatj-on of additi-onal hydro generation
of 1.2 million MWh and reduced surplus sal-es volumes of 1.1
million MWh is expected to reduce coal generation by 39
percent or 2.6 million MWh from last year's PCA forecast,
which is very close to the combined increase in hydro
generation and the reduction in surplus sales.
o.How are the forecasted NPSE di-fferences
presented in Table 1 used to determine the 2015-2076 PCA
forecast component to be collected from Idaho customers?
A.The 2015-20L6 PCA forecast component is
represented by the fdaho jurisdictional share of the
forecasted NPSE differences presented in Table t, adjusted
for the PCA sharing provj-sions. The Idaho jurisdictional
share of the forecast NPSE differences 1s determined by
applying a ratio of forecast firm Idaho jurisdictional-
sal-es to forecast firm system-level- sales to the system-
l-evel NPSE differences, adjusted for sharlng.
O. What is the Company's forecast of system-level-
firm sales and Idaho jurisdictional firm sales for the
201,5-201,6 PCA Year?
A. For the 2075-20L6 PCA Year, fdaho Power has
forecast system-1evel- firm sales to be t4,545,294 MWh and
v[RrGHT, Dr 10
Idaho Power Company
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Idaho jurisdictional- firm sales to
95. 57 percent of the system-Ievel-.
O. What is the Company's
20L5-20L6 PCA forecast component to
customers ?
be 13,901,424 MWh or
determination of the
be col]ected from Idaho
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A. The 2015-2016 PCA forecast component that is
expected to be col-l-ected from Idaho customers is
$39,140,610. Tabl-e 4 presents the determinatj-on of the
20I5-20L6 PCA forecast component by individual PCA expense
and revenue category.
True-Up and True-up of the True-Up
o.What is this year's quantification of the
True-Up?
A. The True-Up portion of the PCA is detailed on
the deferral- expense report, attached as Exhibit No. 1.
Thls report compares actual PCA account resul-ts to l-ast
year's PCA account projections on a monthly basis, with the
WRIGHT, DI 11
Idaho Power Company
Iable 4:20192016 PCA FORECAST
Line No.FERC Account
Difference from Difference After
Base Sharing ldaho Allocation
95% Sharing"Accounts
1. Account 501, Coal
2. Account 536, Waterfor Power
3. Account 547, Other Fuel
4. Account 555, Purchased Power Non-PURPA
5. Account 565, 3rd Party Transmission
6. Account 2147, Surplus Sales
(Frofn,J?ble 1)s 8,s29,29s s
S 44,633 Ss 23,805,2s2 ss $4,2?4,3791 5
5 997,472 5s 12.686.4s1 s
8,102,830 s
42,N1 S
22,61s,940 s
(13,s22,660) s
947,598 s
12.0s2.728 s
7,74,746
N,524
2L,6L4,81O
(1?,924,Os8l,
905,651
71.5L8.622
100% Shgli ne Accog nls
7. Account 555 PURPA
8. Account 555, Demand Response lncentives
5 31,829,724
$ r4,2@,7s7
s 8.331.2241
30,238,238 s ZA,S99,6S0
14,2@,757 s 13,572,138
N/A s (3.331,2241
S
s
9. Total 5 42.699.2s7 S 44.438.99s S 39.140.610
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differences accumulated as the deferral balance. The
balance at the end of March 2075, with i-nterest applied,
was $34,515,981, as shown on row 90 of Exhibit No. 1. The
approximately $34.5 million represents a charge to
customers in this year's PCA.
o.To what factors do you attrj-bute the
accumul-atlon of the approxlmately $34 .5 million deferral-
balance?
A.The $34.5 mil-l-ion deferral bal-ance was largely
driven by lower than forecast market energy prices
resulting in lower surplus sales volumes. Actual surplus
sales volumes were approximately 43 percent lower than
forecasted in last year's PCA. As a result, the Company
experienced lower than expected surpJ-us sales revenue,
which serves to offset power supply expense.
Actual hydro generation was approximately 7 percent
l-ower than forecast. The April-July Brownlee Reservoir
infl-ows fox 20L4 were 3.4 MAF, 0.2 MAF below last year's
forecast. Lower than forecasted hydro generation also
contributed to this year's True-Up.
O. What is this year's True-Up of the True-Up?
A. The Company under collected last year's PCA
True-Up Balance by $1,4841515 as shown on row 110 of the
deferral expense report.
WRIGHT, DI 12
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O. What is the combined effect of the True-Up and
the True-Up of the True-Up in this year's PCA?
A. The sum of the $34,515,981 assocj-ated with the
True-Up and the $1,484,515 associated with the True-Up of
the True-Up represents $36,000,496 of additional coll-ection
from customers. This additional cost in large part
refl-ects that actual net power supply expenses for the
2074-2075 PCA year were greater than the forecast.
o.How does this year's combined True-Up and the
True-Up of the True-Up compare to last year's amount?
A.The combined True-Up and the True-Up of the
True-Up for the last PCA Year was $77,229,193 as compared
to the this year's amount of $36,000,496, a decrease of
$4L,229,297.
O. Why is the total combined True-Up a decrease
of approximately $41.2 mil-Iion over last year's combined
PCA True-Up?
A. Even though the 20L4-20L5 comblned PCA True-Up
was a positive vafue, it is still a decrease of
approximately $41.2 mill-ion over the 201,3-2074 combj-ned PCA
True-Up balance because the forecast for the 2074-201-5 PCA
was more accurate than the previous year's forecast for the
20L3-2074 PCA.
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Other PCA Adjustnents
a.What is the revenue sharing amount for this
2015-2076 PCA Year?
A. Based on the quantification described by Ms.
Noe in her testimony, the revenue sharing benefit to be
credited to customers in this year's PCA is $7,999,745.
O. Are there any other reconrmended adjustments to
this year's PCA?
A.Yes. The Company proposes the continued
application of a PCA credit related to the Demand-Side
Management ("DSM") Rider in the amount of $3,970,036.
o.Why is this credit necessary?
A. This credi-t is necessary to malntaj-n the
revenue neutrality associated with the 2014 update to the
normalized level of NPSE included in base rates approved by
Order No. 33000. Idaho Power's current leve1 of DSM Rider
coll-ection is four percent of base rate revenues. The
approval to increase the Company's l-evel- of base rate
revenues by $99.3 million effective June L, 2014, resulted
in approximately $4.0 million per year of additional DSM
Rider funds. To ensure the base rate increase associated
with the new base level of NPSE approved in Case No. IPC-E-
L3-20 is revenue neutral- for all- classes of customers, it
j-s appropriate to offset the increase in DSM Rider revenue
by moving $4.0 milllon out of the DSM Rider balancing
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account and providing that amount as a credit to customers
in the 2015-2016 PCA. This adjustment shoul-d contj-nue to
be included in PCA rate determinations until the leve1 of
NPSE recovery in base rates is re-established as part of a
general rate case or otherwise adjusted by Commlssion
order.
III. PCA RATE DETERMINATION
o.How is the rate for the forecast portion of
the PCA for April 20L5 through March 2076 determined?
A.The rate for the forecast portion of the PCA
is equal to the sum of (1) 95 percent of the difference
between the non-PURPA expenses quantified in the Operating
Pl-an and those quantified in the Company's last approved
update of power supply expenses, divided by the Company's
normalized system firm sales, and (2) 100 percent of the
difference between PURPA-related expenses quantified in the
Operating PIan and those quantified in the Company's last
approved update of power supply expenses, divided by the
Company's normalized system firm sal-es, and (3) 100 percent
of the difference between the Idaho jurisdictional demand
response incentive payments quantified in the Operating
Plan and those quantified in the Company's last approved
update of power supply expenses, divided by the Idaho
jurisdictional sales.
WRIGHT, DI 15
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O.What is the rate for the forecast portion of
the PCA for April 201,5 through March 20L6?
The rate for non-PURPA expenses is 0.207 9 cents per
kilowatt-hour ("kwh"), which is calcul-ated by multiplying
$31,829,724 from Tabl-e 1by 95 percent and then dividing it
by the normalj-zed system firm sales of 1,4,545,294 MWh
(($31,829,724 * 0.95) / 74,545,294) : $2.08/MWh: 0.2019
cents/kwh). The rate for PURPA expenses is 0.0976 cents
per kwh, which is calculated by dividing $74,200,15'7 from
Table 1 by the 14,545,294 MWh ($1a,200,751 / 14,545,294 MWh
: $0.98/MWh : 0.0976 cents/kwh). The rate for the demand
response j-ncentive payment 1s a negative 0.0240 cents per
kwh, whj-ch is calculated by dlviding a negative $3,33L,224
from Table 1 by the Idaho jurisdictional firm sales of
73,901,424 MWh (-$3,331,224 / 13,907,424 MWh: -$0.24/MWh:
-0.0240 cents/fwfr) . The forecast portion of the PCA rate
is 0.2815 cents per kwh, which is cal-cul-ated by adding the
non-PURPA expense of 0.207 9 cents per kWh to the PURPA
expense of 0.0976 cents per kWh to the demand response
incentive payment of negative 0.0240 cents per kwh (0.2079
+ 0.0976 + -0.0240 : 0.2815 cents/kwh).
o.
A.
How dld you compute this year's True-Up rate?
As shown in Exhibit. No. 1, this year's True-Up
component of the PCA is $34.5 miJ-J-ion, which when divided
by the Company's forecast of Idaho jurisdictional sal-es of
wRrGHT, Dr L6
Idaho Power Company
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13,901,424 MWh results in a
($34.5 million / !3,901 ,424
cents/kwh) .
rate of 0.2483 cents per klnlh
: $2 . 48 /l,tWh : 0 .2483
The True-Up of the True-Up rate is calculated by
dividing $1.5 mill-1on (a1so from Exhibit No. 1) by the
forecast of Idaho jurisdictional- sales of 13,901,,424 MWh,
which results in a rate of 0.0107 cents per kwh ($1.S
mil]ion / L3,901 ,424 : $0.11lMWh : 0.0107 cents/kwh) .
o.Does the quantified True-Up rate include the
sales of Renewable Energy Certificates ("RECs") and Sulfur
Dioxide ("SOz") proceeds?
A.Yes. The RECs and SO2 proceeds are included
in the Company's deferral expense report, provided as
Exhibit No. 1 on lines 37 and 38, Order No. 32002 issued
on June LL, 2010, approved the Company's REC Management
P1an, which passes the customers' share of REC benefits
back to the customer through the PCA. Order No. 32434
approved on January 12, 201,2, directed the Company to pass
SO2 proceeds through the PCA to help offset the Company's
PCA deferral balance.
O. How has the Company determined the PCA rate
credits assocj-ated with revenue sharing and the DSM Rider
transfer?
A. A1l- classes of customers wiLl receive revenue
sharing benefits in the form of a volumetric rate with the
WRIGHT, DI L7
Idaho Power Company
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exceptlon of the special contract customers who will
receive this benefit in the form of !2 equal monthly bill
credits. The adjustment rel-ated to the DSM Rider wil-I be
provided as a uniform rate credit. This approach will
allow each customer cl-ass to receive the credit in the same
proportion as their respective increase in base rates. The
adjustment related to the DSM Rider will be provided in the
form of a volumetric rate for all classes of customers.
Exhibit No. 2, columns A and B show the annuaf revenue
sharing benefits and the adjustment rel-ated to the DSM
Rider for al-1 classes of customers. Columns C and D show
the cents per kwh rate for the classes that wil-I receive
revenue sharing benefits and the adjustment rel-ated to the
DSM Rider in the f orm of a volumetri-c rate.
o.What is the resulting PCA rate when you
combine all of the PCA components described previously?
A.The Company's PCA rate for the 20L5-201-6 PCA
year is detail-ed in Exhibi-t No. 2, column E. The uniform
PCA rate is comprised of (1) the 0.2815 cents per kV[h
adjustment for the 20L5-2016 projected power cost of
serving fi-rm 1oads, under the current PCA methodology and
95 percent sharing, (2) the 0.2483 cents per kwh for the
2014-201,5 True-Up portion of the PCA, and (3) the 0.0107
cents per kwh for the True-Up of the True-Up. The sum of
WRIGHT, DI 18
Idaho Power Company
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these three components results in a 0.5405 cents per kwh
charge for all rate classes.
In addition to the unj-form PCA rate, each rate class
is assigned a portion of the $8.0 million of revenue
sharing and a portion of the $4.0 million for the
adjustment related to the DSM Rider. V{hen these amounts
are combined with the uniform PCA rate, each class will
recej-ve a different PCA rate. The final PCA rates,
including revenue sharing and the adjustment related to the
DSM Rider are listed by rate schedule in Exhibit No. 2,
column E.
a. What is the revenue impact of the requested
PCA rate combined with the revenue sharing rates and the
adjustment rel-ated to the DSM Rider when compared to the
PCA rate currently in effect?
A. Attachment 2 to the Application provides a
detailed description of the overall revenue impact of this
filing on each customer class. As shown on Attachment 2,
applying the requested PCA rates to expected customer l-oads
for the June 2015 through May 2016 test year results in a
PCA decrease of $10.1 mil-lion.
O.Have you prepared a revised Schedule 55 that
WRIGHT, DI 19
Idaho Power Company
includes the proposed PCA rates?
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o.
A.
A.Yes, Attachment 1 to the AppJ-ication includes
a revised Schedule 55 that includes the proposed PCA rates
in legislative and final formats.
O.Should the Commission approve the Company's
computation of the PCA rates?
A.Yes. The Commission should approve the
Company's computation of the PCA rates. The calculation of
the PCA rates follows the methodology that was approved in
Order Nos. 30715 , 30978, 32424, 325'18, and 33000.
Does this concl-ude your testimony?
Yes, it does.
WRIGHT, DI 20
Idaho Power Company
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2B
STATE OF IDAHO
County of Ada
ATTESTATION OF TESTIMOIW
SS.
I, Scott Wright, having been duly sworn to testify
based upon my personal knowledge, state thetruthfully, and
following:
I am employed by Idaho Power Company as a Regulatory
Analyst II in the Regulatory Affairs Department and am
competent to be a wj-tness in this proceeding.
1 declare under penalty of perjury of the l-aws of
the state of Idaho that the foregoing pre-fiIed testimony
and exhibits are true and correct to the best of my
information and bel-ief .
DATED this 15th day of April , 2075.
SUBSCRIBED
Apri1, 2015.
AND SWORN to before me this 15th day of
My commissj-on .*pir"= z l*-J7n-JDeo
WRIGHT, DI 27
Idaho Power Company
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-15-14
IDAHO POWER COMPANY
WRIGHT, DI
TESTIMONY
EXHIBIT NO. 1
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Case No. IPC-E-15-14
S. Wright, IPC
Page 1 of 2
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Exhibit No. 1
Case No. IPC-E-15-14
S. Wright, IPC
Page 2 of 2
BEFORE THE
IDAHO PUBLIG UTILITIES COMMISSION
GASE NO. IPC-E-15-14
IDAHO POWER COMPANY
WRIGHT, DI
TESTIMONY
EXHIBIT NO.2
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Case No. IPC-E-15-14
S. Wright, IPC
Page 1 of 1