20140415Direct S. Wright.pdf

I
BEEORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OE IDAHO POWER COMPANY FOR
AUTHORITY TO IMPLEMENT POWER COST
ADJUSTMENT ('PCA") RATES EOR
ELECTRIC SERVICE FROM JUNE T,
2074, THROUGH MAY 31, 20L5, AND
TO UPDATE BASE RATES IN
COMPLIANCE WITH ORDER NO. 33OOO.
CASE NO. IPC-E-14-05
IDAHO POWER COMPANY
DIRECT TESTIMONY
OF
SCOTT WRIGHT
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O.
A.
O. Please state your name, business address, and
present positj-on with Idaho Power Company ("Idaho Power" or
"Company").
A.My name is Scott Wright. My business address
is 1,221 West Idaho Street, Boise, Idaho 83102. I am
employed by Idaho Power as a Regulatory Analyst II in the
Regulatory Affairs Department.
O. Please describe your educational background.
A. I received a Bachelor of Science degree in
Business Economics from Eastern Oregon University. I have
also attended the Center for Publ1c Utilities "Practical-
Skil-Is for a Changing Electric Industry" a course offered
through New Mexico State University in Albuquergue, New
Mexico, the Edison Electric Institute's "Electric Rate
Advanced Course" in Madj-son, Wisconsin, and the NERA
"Marginal Costing for El-ectric Utilities", j-n Los Angeles,
California.
Pl-ease describe your work experj-ence.
In May L998, I accepted a position as Research
Assistant with Idaho Power in the Regulatory Affairs
Department. In March 2007, I was promoted to a Regulatory
Analyst. In March 2070, I was promoted to a Regulatory
Anal-yst fI. As a Regulatory Analyst Il, I am responsible
for running the AURORA model- to calculate Net Power Supply
Expenses ("NPSE") for ratemaking purposes, preparing the
WRIGHT, DI 1
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Power Cost Adjustment ("PCA") filings 1n Idaho and Oreqon,
as well as the marginal cost of energy used in the
Company's marginal cost analysis. I also provide
analytical support for other regulatory actj-vities within
the Regulatory Affairs Department, as well as providing
testimony in other Company filings.
What is the purpose of your testimony?
The purpose of my testi-mony is to present the
quantification of the 201,4-2075 PCA rates and to quantify
the rate listed on Schedul-e 89, Unit Avolded Energy Cost
for Cogeneration and Small Power Production ("Schedule
89',).
O. Please provide a summary of the sections
presented in your testimony.
A.My testimony is divided into several- sections.
The first section of my testimony provides an overview of
the PCA components. The second section presents the
quantification of the PCA forecast rate using the PCA
components approved in Order No. 33000 in Case No. IPC-E-
1,3-20. The third section details the quantification of the
True-Up and the True-Up of the True-Up. The fourth section
addresses revenue sharing benefits and the proposal to
transfer surplus Idaho Energy Efficiency Rider ('DSM
Rj-der") funds, which are described in more detail in Mr.
Timothy E. Tatum's testimony. The final section of my
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testimony describes the update to the Company's Schedul-e
89.
O\IERVIEI'I OF PCA COMPOI{EI{TS
Please describe the components of the PCA
base.
A. The PCA base level expenses are reflective of
the following Federal- Energy Regulatory Commission (*FERC")
Accounts: FERC Account 501, fuel (coal); FERC Account 536,
water for power; FERC Account 541, fuel (gas); EERC Account
555, purchased power; EERC Account 555, transmission of
electricity by others,' and EERC Account 447 , sales f or
resale (typically referred to as surplus sales).
The PCA base expense component for FERC Account 555
includes both power purchases resulting from the Publ-1c
Utility Regulatory Policies Act of L918 (*PURPA") and non-
PURPA (market) purchases. As per Order No. 32426, the
Company adjusts FERC Account 555 to incl-ude demand response
incentive payments that the Company provi-des to customers
for participating in any of its three demand response
programs.
Ir. QUAITTTFTCATION OF pCA FORECAST
O. Were there any changes to this year's PCA base
components compared to l-ast year's PCA base components?
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A. Yes. On March 21, 2014, Order No. 33000 in
Case No. IPC-E-13-20 approved the new base level components
used for quantifying this year's PCA rates.
0.Please quantify the PCA component amounts
described previously that are included in the PCA base from
which deviations are to be tracked based on customers
receiving a 95 percent share.
A. Order No. 33000 approved the Company's base
Ievel PCA component amounts from which deviations are to be
tracked at 95 percent for customer responsi-bility as
fo]1ows:
Account 501, coal
Account 536, water for power
Account 547, gas
Account 555, non-PURPA
Account 565, transmission
$108,503,180
$2,380,597
$ 33, 3 6't , 563
$62,606, 593
$5,455,955
Account 441, surplus sales ($51r 735,153)
Net of 95 percent accounts $160,578 ,735
O. Please quantJ-fy the PCA component amounts
included in the PCA base from which deviations are to be
tracked with a 100 percent customer responsibility.
A. Order No. 33000 approved the PCA base
component amounts from which deviations are to be tracked
with 100 percent customer responsJ-bility as fol-Iows:
Account 555, PURPA $133,853,869
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O. Pl-ease quantify the PCA component amounts
i-ncluded in the PCA base from which deviations are tracked
differently than described above.
A.The base l-evel recovery of demand response
j-ncentives in the amount of $71,,252,265 was approved per
Order No. 33000. The $7L,252,265 represents the Idaho
jurisdictional- share of the incentive costs. Because the
demand response incentive payments are jurisdictionalized
prior to j-ncl-usion in the PCA, this cost category is
calculated separately from the net 95 percent accounts.
Under this separate treatment, an Idaho jurisdictional
sales denominator i-s used rather than the normalized system
firm sales denominator used for 95 percent accounts in the
PCA rate development process.
o.Please detail the amounts included in the PCA
forecast for which deviati-ons from base are to be tracked
based upon a 95 percent customer sharing percentage.
A.Based upon the Company's March 27, 20L4,
Operatj-ng PIan ("Operating Plan"), the forecast of amounts
for which deviations from base are to be tracked at 95
percent for customer responsJ-bility is as follows:
Account 501, coal
Account 536, water for power
Account 54'7 , gas
Account 555, non-PURPA
$169,424,8'79
$1,7 51,000
$7 3 , 94L, 6'7 3
$6L,996,853
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Account 565, transmission $6, 645,77 5
Account 447, surpl-us sales ($126,166,913)
Net of 95 percent accounts $187,593,267
o.What is the difference between the net of the
95 percent accounts of the forecast amount of $187r593,261
and the $160,578,135 PCA base amount approved in Order No.
33000 ?
A. The PCA forecast amount of $187,593,267 is
higher than the base amount of $160,578,135, a dj-fference
of 527,014,532.
o.What is the Operating Pl-an quantification of
PURPA expenses anticipated from April 201,4 through March
2075?
A. The Operating PIan anticipates $134,L42,386 of
PURPA expenses during the April 2014 through March 20L5
time perlod.
O.How does this amount compare to the base level
of PURPA expenses approved in Order No. 33000?
A. The Operating Pl-an quantification of PURPA
expense is $288,5L'7 greater than the base level amount of
$133,853,869 approved in Order No. 33000.
O. What j-s the Operating PIan quantification of
the demand response incentive payments anticipated from
April 201,4 through March 201-5?
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A.The Operating Plan anticipates $8,290,603 of
Idaho jurisdictional demand response incentive payments
during the April 20!4 through March 2015 tj-me period.
O. How does this amount compare to the base 1evel
of Idaho jurisdictj-onal demand response incentive payments
quantified in Order No. 33000?
A.The Operating Plan quantification of demand
response j-ncentive payments is $2,967,662 less than the
$lL,252,265 quantified in the Company's update of power
supply expenses approved per Order No. 33000. The lower
incentive payments reflect the newly establ-ished demand
response incentj-ve structure as agreed to by the settlement
stipulation approved by the Idaho Public Utilities
Commission ("Commission") in Order No. 32923.
O.What is the rate for the projection portion of
t.he PCA for April 201,4 through March 20L5?
A.The rate for the projection portion of the PCA
is equal to the sum of (1) 95 percent of the difference
between the non-PURPA expenses quantj-fied in the Operating
Pl-an and those quantlfied in the Company's last approved
update of power supply expenses, divided by the Company's
normallzed system firm sales, and (2) 100 percent of the
difference between PURPA-rel-ated expenses quantified in the
Operating Plan and those quantifled in the Company's l-ast
approved update of power supply expenses, divided by the
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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
PIan and those quantified in the Company's last approved
update of power supply expenses, divided by the Idaho
jurisdictional sales.
The rate for non-PURPA expenses is 0.1807 cents per
kilowatt-hour (*kv0h"), which is ca1culated by multiplying
$21,074,532 by 95 percent and then dividing it by the
normal-ized system firm sales of 74,200r871- megawatt-hours
(*MWh-) (($27,0:14,532 * O.95) / 74,200,871) $1.8l/MWh :
0.1807 cents/kwh). The rate for PURPA expenses is 0.0020
cents per kwh, which is calculated by dividing $288,577 by
the 74,200,871 MWh ($288,5L7 / U,200,871 MWh : $0.o2lMwh :
0.0020 cents/kwh) . The rate for the demand response
incentive payment is a negative 0.021-8 cents per kwh, which
is calcul-ated by dividing a negative $2,961,662 by the
Idaho jurisdictional firm sales of 13,558,865 MWh
(-52,96L,662 / t2,558,865 MWh : -$0.22lMWh : -0.0218
cents/kwh). The projection portion of the PCA rate is
0.1609 cents per kwh, which is calculated by adding the
non-PURPA expense of 0.1807 cents per kWh to the PURPA
expense of 0.0020 cents per kWh to the demand response
incentive payment of negative 0.0218 cents per kwh (0.1807
+ 0.0020 + -0.0218 : 0.1609 cents/kwh) .
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0. What j-s the recoverable deviation of forecast
power supply expenses from base level- power supply expenses
for the 201,4-2075 PCA forecast?
A. The recoverable portion of power supply
expenses is $22,990 , 660 million ( ($Zl ,0L4,532 x 0 . 95 ) +
$288,517 + -$2,967,662 $22,990,660) .
rrr. QUAIITIFICATTON OF TEE TRI,E-UP
ATID TRT'E-UP OF THE TRT'E-UP
O. Please describe the True-Up portion of the PCA
rate.
A.The True-Up portion of the PCA rate starts
with the deferral expense report, attached as Exhibit No.
5. This report compares actual PCA account results to l-ast
year's PCA account projections on a monthly basis, with the
differences accumulated as the deferral balance. The
ba1ance at the end of March 20L4, with interest applied,
was $58,088,816, as shown on row 90 of Exhibit No. 5. The
$58.1 mill-ion represents a charge to customers largely
resulting from actual power supply expenses being greater
than what had been forecast fast year.
O. Please describe the computation of this year's
True-Up rate.
A. This year's True-Up component of the PCA is
$58,088,8'76, divided by the Company's projected fdaho
jurisdictiona1 sales of 13,558,865 MWh which resul-ts in a
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rate of 0.4284 cents per kwh ($58,088,876 / 73,558,865 =
$4.28lrqWh : 0.4284 cents/kwh) .
O. What is this year's True-Up of the True-Up
rate?
A.The Company under collected last year's PCA
True-Up Balance by $L9,L40,9I7 as shown on row 109 of the
deferral expense report. The True-Up of the True-Up rate
is calculated by dividing $19,140,917 by the projected
Idaho jurisdictional- sales of 13,558,865 MWh, which results
in a rate of 0.7472 cents per kV[h ($19,740,977 / 73,558,865
: $1.41lMV{h : 0.\472 cents/kwh) .
o.Please explain 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 $58.1 million associated wi-th
the True-Up and the $19.1 million associated with the True-
Up of the True-Up represents $17.2 million of additional
collection from customers. This additional cost in large
part reflects that actual- net power supply expenses for the
2074-2075 PCA year were greater than the forecast.
o.Does the quantified True-Up rate include the
sales of Renewable Energy Certificates ("RECs") and Sulfur
Dioxj-de ("SOz") proceeds?
A.Yes. The RECs and SO2 proceeds are included
in the Company's deferral expense report, provided as
Exhibit No. 5 on l-ines 37 and 38. Order No. 32002 issued
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on June 11, 2070, 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, 2012, directed the Company to pass
SO2 proceeds through the PCA to help offset the Company's
PCA deferral bal-ance.
IV. RE\IENT'E SIIARING A}ID DSM RIDER ADdIuSTMENT
O. Please give a brief overview of the revenue
sharing and DSM Rider adjustment proposal described in Mr
Tatum's testimony.
A. The revenue sharing and DSM Rider adjustment
proposal includes a revenue sharing benefit of $'7,602,043
as well as a transfer of DSM Rider funds of $20 miltion.
O. How has the Company incorporated this refund
into the PCA rate?
A. As detailed in Mr. Tatum's testimony, the
Company plans to apportion the revenue sharj-ng benefits and
the transfer of $16 million in DSM Rider funds based on
each class's proportlon of base revenues. The transfer of
$a million in DSM Rider funds that is necessary to ensure a
revenue neutral J-mplementation of the 2073 base leve1 NPSE
will be provided as a uniform rate credit. This approach
will allow each customer class to receive the credlt in the
same proportj-on as their respective increase in base rates.
AlI classes of customers will receive revenue sharing
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benefits in the form of a volumetri-c rate with the
exception of the Special Contract customers who will
receive this benefit in the form of 72 equal monthly bill
credits. The transfer of DSM Rider funds wil-l- be provided
in the form of a volumetric rate for all classes of
customers. Exhibit No. 6, page 7, columns A, B, and C show
the annual revenue sharing benefits and the transfer of DSM
Rider funds for all classes of customers. Columns D, E,
and E show the cents per kwh rate for the classes that will
receive revenue sharing benefits and the transfer of DSM
Rider funds in the form of a volumetric rate.
o.What is the resulting PCA rate when you
combine aII of the PCA components described previously?
A.The Company's PCA rate for the 2074-20L5 PCA
year is detailed in Exhibit No. 6, page l, col-umn H. The
uniform PCA rate 1s comprised of (1) the 0.1609 cents per
kwh adjustment for the 20L4-2075 projected power cost of
serving firm loads, under the current PCA methodology and
95 percent sharing, (2) the 0.4284 cents per kwh for the
2013-20L4 True-Up portion of the PCA, and (3) the 0.7412
cents per kV[h for the True-Up of the True-Up. The sum of
these three components results in a 0.7305 cents per kwh
charge f or all rate cl-asses.
In addition to the uniform PCA rate, each rate class
is assigned a portion of the $7.6 million of revenue
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sharing and a portion of the $20 million related to the
transfer of DSM Rider funds. When these amounts are
combined with the uniform PCA rate, each class will- receive
a different PCA rate. The final- PCA rates, including
revenue sharing and the transfer of DSM Rider funds are
l-isted by rate schedule in Exhibit No. 6, page 7, col-umn I.
O. Have you cal-cul-ated the expected PCA revenue
using the PCA rates described above?
A. Yes. The Company would expect to collect
$99.0 mil-Iion through the uniform PCA rate using the
approved base power supply expenses approved in Order No.
33000. This is $67.9 mil-Iion less than the $165.9 million
associated with the current PCA rate. When the uniform PCA
rate is combined wj-th the additional $7.6 million in
revenue sharing and $20 mil-Ij-on for the transfer of DSM
Rider funds, the Company would expect to col-Iect $71.4
mj-1lion through the final combined PCA rates.
O. What is the revenue impact of the requested
PCA rate combined with the revenue sharing rates and the
transfer of DSM Rider funds when compared to the PCA rate
currentl-y in effect?
A. Attachment 2 to the Application provides a
detailed description of the overall revenue impact of this
filing on each customer cl-ass. As shown on Attachment 2,
applying the requested PCA rates to expected customer loads
WRIGHT, DI 13
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1 for the June 201-4 through May 2015 test year results in a
2 PCA increase of $11.1 million.
V. SCBEDT'LE 89 UPDATE
O. Please provide a brief overview of Schedule
s 89.
6 A. In 1980, Schedule 89 was created pursuant to
7 Order Nos. 1,5746 and 16025 to provide PURPA contracts with
I an updated avoided energy cost rate any time the Company
9 updated its variable power supply expenses.
10 O. Why 1s the Company updating Schedul-e 89 in
11 this proceeding?
72 A. The Company is updating Schedul-e 89 pursuant
13 to Order No. 32758 issued in Case No. IPC-E-12-28. Order
74 No. 32758 directs the Company to update Schedule 89
15 whenever NPSE amounts are updated, whereas typically this
76 update only occurred after a general rate case has been
71 approved. On l(arch, 2L, 2074, Order No. 33000 approved
18 updated NPSE amounts for the Company.
19 O. How is Schedule 89 calculated?
20 A. Schedule 89 is calcul-ated by combining Valmy's
27 variable power supply expense approved per Order No. 33000
22 and the variabl-e operations and maintenance expenses
23 assocj-ated with the p1ant.
24 O. Has the Company provided the proposed Schedule
25 89 tariff for approval?
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A.Yes. The Company has included an updated
Schedule 89 in Attachment 1 to the application.
O. Shoul-d the Commission approve the Company's
computation of the PCA rates using the PCA mitigation
calculatj-ons and the update to Schedule 89?
A. Yes. The Commission should approve the
Company's computation of the PCA rates using the PCA
mitigation calculations as wel-I as the update to Schedul-e
89. The calcul-ation of the PCA rates and the update to
Schedule 89 follows the methodology that was approved in
Order Nos. 30715, 30978, 32424, 32518, and 33000.
O. Does this concl-ude your testimony?
A. Yes.
WRIGHT, DI 15
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STATE OE IDAHO )
)
County of Ada )
lt Scott
truthfully, and
following:
ATTESTAIION OF TESTIIONT
SS.
Wright, having been duly sworn to testify
based upon my personal knowledge, state the
I am employed by Idaho Power Company as a Regulatory
Analyst II in the Regulatory Affairs Department and am
competent to be a witness in this proceeding.
f declare under penalty of perjury of the laws of
the state of ldaho that the foregoJ-ng pre-filed testimony
and exhibits are true and correct to the best of my
information and belief.
DATED this 15th day of April , 2074.
Scot
SUBSCRIBED AND
April, 201-4.
SWORN to before me this 15th day of
wRrGHT, Dr L6
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BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
GASE NO. IPC-E-14-05
IDAHO POWER COMPANY
WRIGHT, DI
TESTIMONY
EXHIBIT NO.5
Exhibit No. 5
Case No. IPC-E-14-05
S. Wright, IPC
Page 1 of2
Exhibit No. 5
Case No. IPC-E-14-05
S. Wright, IPC
Page 2 of 2
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
cAsE NO. IPC-E-14-05
IDAHO POWER COMPANY
WRIGHT, DI
TESTIMONY
EXHIBIT NO.6
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Exhibit No. 6
Case No. IPC-E-'14-05
S. Wright, IPC
Page 1 of 1
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