20160415Larkin Direct.pdf

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BEFORE THE IDAHO PUBLIC UTILITTES COMMTSSION
IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY EOR
AUTHORTTY TO IMPLEMENT POWER
COST ADJUSTMENT ('PCA") RATES )
FOR ELECTRIC SERVTCE FROM JUNE )7, 2076, THROUGH MAY 3L, 20L7. )
)
CASE NO. IPC_E-16-08
IDAHO POWER COMPANY
DIRECT TESTIMONY
OF
MATTHEW T. LARKIN
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0. Please state your name, business address, and
present position with Idaho Power Company ("Idaho Power" or
"Company" )
A.
address is
am employed
Manager in
o.
A.
My name is Matthew T. Larkin. My business
7227 West Idaho Street, Boise, Idaho 83702. I
by Idaho Power as the Revenue Requirement
the Regulatory Affairs Department.
Please describe your educational background.
I recei-ved a Bachelor of Business
Administration degree in Finance from the University of
Oregon in 2001. In 2008, I earned a Master of Business
Administration degree from the University of Oregon. I
have also attended electric utility ratemaking courses,
including the El-ectric Rates Advanced Course, offered by
the Edison El-ectric Institute, and Estjmation of
El-ectricity Marginal Costs and Application to Pricing,
presented by National Economic Research Associates, Inc.
0.Please describe your work experience with
Idaho Power.
A. I began my employment with fdaho Power as a
Regulatory Analyst I in January 2009. As a Regulatory
Analyst I, I provided support for the Company's reguJ-atory
activities, including compliance reporting, financial
analysis, and the development of revenue forecasts for
regulatory filings.
LARKIN, DI 1
Idaho Power Company
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fn January 2072, I was promoted to Regulatory
Analyst If, and, in January 2014, T was promoted to Senior
Regulatory Analyst. As a Senior Regulatory Analyst, my
responsibilities expanded to include the development of
complex cost-related studies and the analysis of strategic
regulatory issues.
fn March of 2076, I was promoted to my current
position of Revenue Requirement Manager. As Revenue
Requi-rement Managex, I oversee the Company's regulatory
activities rel-ated to revenue requirement, such as power
supply expense modeling, jurisdictional separation studies,
and Idaho Power's Open Access Transmission Tariff Eormula
Rate.
quantificatj-on of the 2076-20L1 Power Cost Adjustment
(*PCA") rates to become effective June 7, 2076. If
approved, the 20L6-20L7 PCA will result j-n a revenue
increase of approximately $17.3 mi1lion, or 1.57 percent.
O.
A.
o.
A.
What is the Company requesting in this case?
The Company is requesting approval of its
How is your testimony organized?
My testimony is comprised of four sections.
In the first section, I will provide an overview of the
PCA. In the second section, I wil-I detail the 20L6-20L7 PCA
amount, identify and discuss the main factors contributing
to this amount, and present the quantification of the 20L6-
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Idaho Power Company
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2011 PCA rates. In the third section, I will dlscuss
additional rate adjustments resulting from revenue sharing
and the Company's 2074 update to base net power supply
expenses (*NPSE"). In the final- section of my testimony, I
will summarj-ze the rates proposed to become effective June
L, 20t6, and the net customer impact of these rates if
approved.
I. PCe, O\IERVIEI'I
O. What is the purpose of the PCA and how does
the mechanism function?
A.The PCA is a rate mechanism that quantifies
and tracks annual differences between actual NPSE and the
normal-ized or "base l-evel" of NPSE recovered in the
Company's base rates, resulting in a credit or surcharge
that is updated annually on June 1. The PCA mechanism
utilizes a 12-month test period of April through March
(*PCA Year") and is comprised of a forecast component and a
true-up component ("True-Up"). The forecast component
represents the difference between the NPSE forecast from
the March Operating Pl-an and base l-evel NPSE recovered in
the Company's base rates. The True-Up includes a backward
looking tracking of differences between the prior year's
forecast and actual- NPSE incurred by the Company in that
PCA Year. The True-Up contains a second component that
LARKTN, Dr 3
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tracks the coll-ection of the prior year's True-Up amount,
referred to as the "True-Up of the True-Up."
Ir'Iith the exception of Public Utility Regulatory
Pol-icies Act of 7978 (*PURPA") expenses and demand response
incentive payments, the PCA allows the Company to pass
through to customers 95 percent of the annual differences
in actual NPSE as compared to base level NPSE, whether
positive or negative. V{ith respect to PURPA expenses and
demand response incentive payments, as actual annual
expenses deviate from base, the Company is allowed to pass
through 100 percent of the difference for recovery or
credit through the PCA. The PCA is also the rate mechanism
used by the Company to provide direct benefits resulting
from the revenue shari-ng mechanj-sm approved by the Idaho
Public Utilities Commission ("Commission") in Order No.
33749.
O. What are the components of the PCA base level
NPSE?
A.The PCA base leve1 NPSE incl-ude the following
Eederal Energy Regulatory Commi-ssj-on (*FERC") accounts:
FERC Account 501, fuel (coa1); EERC Account 536, water for
power; FERC Account 547, fuel (gas); EERC Account 555,
purchased power; FERC Account 565, transmission of
electrj-city by others; and FERC Account 44'7, sal-es for
resale (typically referred to as surplus sal-es).
LARKIN, DI 4
Idaho Power Company
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The PCA base leve1 expense component for FERC
Account 555 includes costs resultJ-ng from both PURPA and
non-PURPA (market) purchases. Per Order No. 32426, the
Company adjusts FERC Account 555 to lnclude demand response
incentlve palrments that the Company provides to customers
for participating in any of its three demand response
programs.
rr. 20L6-20L7 PCA,
o.
measured from
A.
What is the total 20L6-2011 PCA amount as
the currently approved base l-eveI NPSE?
The 20I6-20L7 total- PCA amount as measured
from the currently approved base level NPSE1 is $79.2
mill-ion.2 This represents an increase in total billed
revenue of $17.3 mill-ion for the upcoming yearr dD increase
of 1.57 percent.
PCA Forecast
a. What is the Company's determination of the
system-1evel difference between currently approved base
Ievel NPSE and the forecast of NPSE for the 201,6-20L7 PCA
Year?
A. The system-Ievel forecast of NPSE for the
2076-2077 PCA Year j-s $357,54'l ,740, which is $51,862,877
1 Approved
2 Includes
Side Management
below.
on March 21,
the impact
Rider (*DSM
2074, Order No. 33000.
of revenue sharing and the ongoing Demand-Rider") transfer detaifed in Section III
LARKTN, Dr 5
Idaho Power Company
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higher than
$305,684,869
differences
the forecast
account.
the currently approved base .l-evel- NPSE of
. Table 1 below presents the system-level-
between currently approved base level NPSE and
of NPSE for the 2076-20L7 PCA Year by FERC
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O. What is the basis for the forecast of NPSE for
the 2016-20L'1 PCA Year?
A. The forecast of NPSE for the 2016-20L7 PCA
Year is based on the Company's March 31, 2076, Operating
PIan.
O. How is the NPSE forecast developed for the
Company's Operating PIan?
LARKIN, DI 6
Idaho Power Company
Tab]-e 1 2OL6-20L7 PCA FORECAST (Total Systen)
Line No.EERC Aacount Base NPSE Forecaat Difference
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958 Sharing Accounts
Account 501, Coal- $ 108,503,180 $ 71-2,Lz'l ,L06 $ 3,623,926
Account 536, Water for
Power I 2,380,597 $ - $ (2,380,597)
Account 547, Other Fuel $ 33,367,563 $ 39,202,822 $ 5,835,259
Account 555, Purchased
Power Non-PURPA $ 62,606,593 $ 54 ,988,467 $ (7,6L8,726)
Account 565, 3rd Party
Transmissj-on $ 5,455,955 $ 5, 999,4L2 $ 543,457
Account 447, Surplus
Sales $ (51,735,153) I (20,930,147) $ 30,805,006
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$ 160,578, 735 $ 191, 381 ,660 $ 30,808, 925
1008 Sharing Accounts
Account 555, PURPA $ 133,853,869 S 158,758,382 I 24,904,513
Account 555, Demand
Response Incentives $ 11,252,265 $ 7,401,698 $ (3,850,567)
9 Total s 305, 684,869 $ 357,541,140 $ 51,862,81L
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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 t.he
PCA Year. The Operating PIan is developed by simulating
the economic di-spatch 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, avallabl-e hydro generation,
coal and natural gas prices, and any exlsting hedge
transactions. The system load forecast is then analyzed
against the resulting monthly heavy Ioad and light l-oad
dispatch to determine a monthly load and resource bal-ance.
Any identified resource deficiency is assumed to be fill-ed
with market energy purchases. Economically dispatched
generation above the system load forecast represents
surplus energy sales.
a. How does the Company's forecast of NPSE for
the 2076-2077 PCA compare to the forecast from last year's
PCA?
A. Table 2 compares this year's 2076-20L7 PCA
forecast to last year's PCA forecast for each NPSE
category. As detail-ed in this tabl-e, the PCA forecast on a
total- system basis for the 2076-20L7 PCA is expected to be
LARKIN, DI 1
Idaho Power Company
1 $357,547,740, which i-s $9,163,674 higher than last year's
2 forecast amount of $348,384,L26.
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rab].e 2 PCA Forecast Coulrarison - Er1€naes (Total- Syaten)
Line No.
20L5-20L6 20L6-20L7
EERC Account Forecast Forecaat Difference
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958 Sharing Accounts
Account 501, Coal $ 117 ,032,475 I 1]-2,721 ,1-06 $ (4,905,369)
Account 536, Water for
Power $ 2,425,230 $ - S (2,425,230)
Account 547, Other Fuel $ 57,173,815 $ 39,202,822 $ (17,970,993)
Account 555, Purchased
Power Non-PURPA $ 48,372,214 S 54,988,467 $ 6,676,253
Account 565, 3rd Party
Transmission $ 6,453,427 $ 5,999,472 $ (454,015)
Account 447, Surplus
Sal-es $ (39,048,1A2) $(20,930,147) $ 18,11-8,555
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$ 792,408,459 $ 191,387,660 I (1,020,'t99)
l-008 Sharing Accounts
Account 555, PURPA $ 148,054,626 $ 158,158,382 $ 10,103,756
Account 555, Demand
Response Incentives $ 7,921,041- $ '1,407,698 $ (519,343)
9 Total- PCA Eorecast
755, 9'l 5, 667
348 ,384, L25
166,160,080
351,541,740
10,184,413
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O. What general- conclusions can be drawn from the
information contained in Tabl-e 2?
A. When viewed by category, the 95 percent
sharing accounts represent a decrease of $1 million from
last year' s forecast, while the 100 percent sharing
accounts represent an j-ncrease of $L0.2 m11Iion over last
year' s forecast.
O. Why is the Company forecasting $0 for
inclusion j-n FERC Account 536, Water for Power, when last
year's forecast was $2.4 million?
LARKTN, Dr I
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A. Account 536 was reduced to $0 i-n the current
forecast from the previous forecast amount of $2.4 million
due to the expiration of the Company's water l-ease with the
Shoshone-Bannock Tribal Water Supply Bank. In the past,
the Company leased 45,7L6 acre-feet of American Fal-ls
storage water. Under the terms of this agreement, the
Company could schedule the release of the water to maximize
the val-ue of generatj-on from the entire system of mainstem
Snake River hydroelectric projects. The Company typically
scheduled delivery of the water between July and October
each year to offset the effect of drought and changing
water-use patterns in southern Idaho, and to provide
additi-onal generation in summer months when customer demand
is high. However, the five-year contract term expired in
201-5, and the Company made an economic decision not to
renew as the potential contract pricing was not competitive
with current market energy prices.
o.What other factors do you belleve contributed
to the notab1e differences presented in Tab1e 2?
A. Expected market prices have decl-ined due to
Iow projected gas prices and improved hydrologic conditions
in the region. When market prices are depressed, it is
economic for the Company to serve load through increased
market purchases and system generation, while the ability
to selI surplus is reduced. Consequently, the Company's
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expectation of surplus sales revenue has declined by 46
percent compared to Iast year's forecast, while expected
non-PURPA market purchases have increased by 14 percent.
The reduction in surplus sales revenue and increase in non-
PURPA market purchases are offset by reductions in expected
coal and gas production costs, resultj-ng in the $1 million
net decrease in the 95 percent sharing accounts rel-ative to
last year's forecast.
PURPA
year's
Viith regard to the 100 percent sharing accounts,
costs increased by $10.7 million as compared to last
forecast, reflecting a 7 percent increase, while
demand response incentive payments declined by $519,343,
reflectj-ng a 7 percent decrease. The net j-mpact to the 100
percent sharing accounts is an increase of $10.2 million
over l-ast year' s forecast.
o.Is the increase in PURPA costs related to
increased generation output from PURPA projects?
A. Yes. Table 3 below details changes between
last year's PCA forecast and this year's PCA forecast with
respect to forecasted generation in megawatt-hours (*MWh").
As shown in Table 3, PURPA generation is anticlpated to
increase by 2571857 MWh, or 12 percentr dS compared to l-ast
year's PCA forecast. This increase is largely due to the
addition of 320 megawatts ("MW") of PURPA solar projects
LARKIN, DI 10
Idaho Power Company
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and 50 MW of PURPA wind
on-line in the 20L6-20L1
projects that are expected to come
PCA year.
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O.Did the expiration of the Shoshone-Bannock
Tribal Water Supply Bank l-ease impact modeled hydro
generation in the 2076-2017 PCA forecast?
A. Yes. The expiration of the Shoshone-Bannock
Tribal Water Supp1y Bank lease l-ed to a reduction in
modeled hydro generati-on of approximately 53,000 MWh.
O. Is the remainder of the 499,738 MWh reduction
in expected hydro generation the result of lower projected
inflows into Brownfee?
LARKIN, DI 11
Idaho Power Company
Tab1e 3 PCA Forecast Coulrarison - Generation (Eotal Systen-Mlfh)
Line No.FERC Account
2015-2016 20L6-20L7Foracaat Forecaat Difference
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Hydro 8,732,991 7,633,253 (499,738)
95t Sharlng Accounts
Account 501, Coal 3,953,060 3,895,094 (51,966)
Account 547, Other Euel 2,29"1,609 \,841,736 (449,873)
Account 555, Purchased Power
Non-PURPA 858,438 1,187,511 329,013
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958 Sharing Accounts
100t Sharing Accounts
Account 555, PURPA
L5,242,098 L4,563,594 (678,504)
2, L99 ,216 2, 457 ,07 3 25"1 ,857
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1008 Accounts
Total Generati-on
2 , L99 ,216 2 , 45'l ,07 3 25'l ,857
L'7 , 441,,31,4 77 ,020 , 667 (420 , 647 )
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95* Sharlngr Accounts
Account 447, Surplus Sal-es L,65L,264 L,L35,459 (515,805)
B Total- Load 15,790,050 15,885,208 95,158
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A.No. The March
year's PCA forecast projects
into Brownlee of 4.5 million
approximately equi-valent to
Iast year's PCA forecast.
Operati-ng Plan used in this
April through July inflows
acre-feet ("MAF"). This is
the 4.5 MAE used to determine
o.Why is projected hydro generation less than
l-ast year's forecast if expected inflows into Brownlee have
not declined?
A.Whil-e this year's forecast of April through
July lnflows into Brownlee is comparable to last year's,
projected hydro generation is lower due to decreased flows
from the Upper Snake Basin. The reservoir leve1s in this
region are l-ower than initially forecast in 2015, which has
resulted in no projected flood control from the Upper Snake
Basin. Consequently, whil-e projected j-nflows into Brownl-ee
and through the Company's Hel1s Canyon Complex are
comparable to last year, the l-ack.of flood control in the
Upper Snake Basin results in less water projected to flow
through all upstream generation facilities from American
Ealls to Swan Eal-ls.
o.What else can be concluded from the
information in Table 3?
A. Another item of note in Table 3 is the
additional- non-PURPA market purchases of 329,073 MWh over
l-ast year's PCA forecast. The average market purchase
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price for this year's PCA forecast is $46.31 per MWh,
compared to l-ast year's forecast of $56.35 per MWh. As
dj-scussed above, these lower prices are driving an increase
j-n non-PURPA market purchases for this year's PCA forecast
as compared to last year's PCA forecast.
Alternatively, lower market prices also result in an
expected reduction j-n surplus sales volumes of 31 percent,
or 515,805 MWh, as compared to last year's forecast. The
average market energy sale price for this year's PCA
forecast is $18.43 per MWh, compared to last year's
forecast of $23.65 per MWh.
The combination of additional- non-PURPA market
purchases of 329,073 MWh and reduced surplus sales volumes
of 515,805 MWh is offset by the reduction in hydro
generation of 6 percent, or 499,738 MWh, as well as a
reduction in coal- generation of 1.5 percent, or 571966 MWh,
and natural gas generation of 20 percentr or 449,873 MWh,
from l-ast year' s PCA f orecast.
0.How are the forecasted NPSE differences
presented in Table 1 used to determine the 2076-2017 PCA
forecast component to be collected from Idaho customers?
A.The 20L6-2071 PCA forecast component reflects
the Idaho jurisdictional share of the forecasted NPSE
differences presented in Table 7, adjusted for the PCA
sharing provj-sions. The Idaho jurisdictional share of the
LARKIN, DI 13
Idaho Power Company
1 forecast NPSE differences is determined by applying a ratio
2 of forecast firm Idaho jurisdictional sales to forecast
3 firm system-leve1 sal-es to the system-1eve.l- NPSE
4 differences, adjusted for sharing.
O. What is the Company's forecast of system-level
6 firm sales and Idaho jurisdictional firm sales for the
1 20L6-20L7 PCA Year?
A. For the 2076-20L1 PCA Year, Idaho Power has
9 forecast system-Ievel firm sales to be 74,641,388 Mt{h and
10 Idaho jurisdictional firm sal-es to be 13,955,821- MWh, or
11 95.28 percent of the system leveI.
72 O. What is the Company's determination of the
13 2016-20L1 PCA forecast component to be collected from Idaho
74 customers?
15 A. The 2076-20L1 PCA forecast component that j-s
L6 expected to be col-lected from Idaho customers is
L7 $41 ,764,680. Table 4 presents the determi-nati-on of the
18 20L6-2077 PCA forecast component by individual- PCA expense
1,9 and revenue category.
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LARKTN, DI L4
Idaho Power Company
Table ll 2OL6-2OL7 PCA FORECAST
Line No.FERC Account
Difference
From Bage
Difference Idaho
After Sharing A.Llocation
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95? Sharing Accounts (From Table 1)
Account 501, Coal $ 3, 623,926 $ 3, 442,730 I 3,280,183
Account 536, Water for
Power $ (2,380,597) $ (2t261 ,56'l) I (2,154,789\
Account 547, Other Euel I 5,835,259 $ 5,543,496 I 5,287,763
Account 555, Purchased
Power Non-PURPA $ ('7,6]-8,726) $ (7,237,220) I (6,895,519)
Account 565, 3rd PartyTransmission $ 543,457 I 5L6,284 $ 491,908
Account 447, SurplusSales $ 30,805,006 $ 29,264,756 $ 27,883,039
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$ 30,808,925 s 29,268,479 I 27,886,585
1008 Sharing Accounts
Account 555, PURPA $ 24,904,513 $ 24,904,513 $ 23,728,662
Account 555, Demand
Response lncentives $ (3,850.567) $ (3,850,567) $ (3,850,567)
9 Total $ 51, 862 ,8't t I 50, 322 , 425 S 47 ,'7 64 , 680
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o.
True-Up?
True-Up and True-Up of the True-Up
What is this year' s quantification of the
A.The True-Up portion of the PCA is detailed on
the deferral expense report, attached as Exhibit No. 1.
This report compares actual- PCA account results to last
year's PCA account projections on a monthly basis, with the
di-f ferences accumulated as the deferral bal-ance. The
balance at the end of March 20L6, wj-th interest applj-ed,
was $43,667,L93, ds shown on row 91 of Exhibit No. 1. The
approximate $43.7 mill-i-on represents a charge to customers
in this year' s PCA.
LARKIN, DI 15
Idaho Power Company
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o.
accumulation
balance?
To what factors do you attribute the
of the approximate $43.7 million deferral
A.The $43.7 mil-Iion deferral bal-ance was largely
driven by lower than forecast hydro generation coupled with
l-ower than f orecast market energy pri-ces. Actual hydro
generatj-on for the 2075-2016 PCA year was 5,938,469 MWh,
which was 2,794,522 MWh- less than the forecast of 8,732,99L
MV[h, reflecting a 21 percent reduction between forecast
generatlon and actual generation.
In addition to l-ower than forecast hydro qeneration,
l-ower market energy prices led to a decrease in surplus
sales and an increase in market purchases. Actual surplus
sales volumes were approximately 26 percent Iower than
forecasted in l-ast year's PCA, while actual non-PURPA
purchase volumes were approximately 92 percent higher than
forecasted in last year's PCA.
O. Did the Company calculate the Sal-es Based
Adjustment ("SBA") per the terms of the settlement
stipulation approved in Order No. 33307 in Case No. IPC-E-
15- 15 ?
A. Yes. The Company's deferral report provided
as Exhibit No. 1 contains a modified structure from
previous years' PCA deferral reports to refl-ect the
methodology approved in Case No. IPC-E-15-15. Beginning on
LARKIN, DI 76
Idaho Power Company
1 line 10 of Exhibit No. 1, the Company calculates the SBA
2 using actual- Idaho jurisdictional billing month sales
3 rather than system generatJ-on-l-eve1 1oads, ds was the case
4 under the prior Load Change Adjustment ("LCA") method.
5 Q. Did the Company quantify the impact of the
6 methodology change on the 2015-20L6 PCA deferra1 balance?
7 A. Yes. Had the Company continued to calculate
8 the deferral balance util-izing the LCA method, the 2075-
9 2016 True-Up balance as of March 31, 2016, would have been
10 $4'7,198,396, or $4,137,203 greater than the deferral
11 balance calculated under the new SBA method.
72 O. What is this year's True-Up of the True-Up?
13 A. This year's True-Up of the True-Up balance j-s
t4 a benefit to customers of $51073,737r ds shown on row 119
15 of the deferral expense report.
L6 O. What is the combined effect of the True-Up and
Ll the True-Up of the True-Up in this year's PCA?
18 A. The sum of the $43,661,193 associated with the
1,9 True-Up and the negative $5,073,731 associated with the
20 True-Up of the True-Up represents $38,588,056 of required
2L col-lection f rom customers. Thj-s additional cost in large
22 part refl-ects that actual NPSE for the 201,5-2076 PCA year
23 were greater than the forecast.
24 0. How does this year's combined True-Up and the
25 True-Up of the True-Up compare to last year's amount?
LARKIN, DI L7
Idaho Power Company
1 A. The combined True-Up and the True-Up of the
2 True-Up for the last PCA Year was $34,529,699,3 as compared
3 to this year's amount of $38,588,056, an j-ncrease of
4 $4,058 ,357 .
PCA Rate Determination
O. How j-s the rate for the forecast portion of
7 the PCA for April 2076 through March 201-7 determined?
A. The rate for the forecast portion of the PCA
9 is equal to the sum of (1) 95 percent of the difference
10 between the non-PURPA expenses quantified in the Operating
11 PIan and those quantified in the Company's last approved
L2 update of NPSE, divided by the Company's normalized system
13 firm sales, and (2) 100 percent of the difference between
14 PURPA-related expenses quantified in the Operating Plan and
15 those quantified in the Company's l-ast approved update of
L6 NPSE, divided by the Company's normalized system firm
L] sales, and (3) 100 percent of the difference between the
l-8 Idaho jurisdictional demand response incentive payments
79 quantified in the Operating PIan and those quantified in
20 the Company's last approved update of NPSE, divlded by
2L Idaho jurisdictional firm sales.
22
3 This amount reflects the leve1 of recovery currently embedded in
rates, which incl-udes the $36,000,496 deferral approved in the 2015 PCA
case (Case No. lPC-E-15-14, Order No. 33306) , as weIJ- as the $1 ,41 0,'797
deferral- balance reduction due to the transition to the SBA approved by
Order No. 33307 in Case No. 1PC-E-15-15.
LARKIN, DI 18
Idaho Power Company
1 Q. What is the rate for the forecast portion of
2 the PCA for Aprj-I 2016 through March 2077?
3 A. The rate for non-PURPA expenses is 0.1998
4 cents per kilowatt-hour (*kwh"), whlch is calculated by
5 multiplying $30,808,925 from Table 1 by 95 percent and then
6 dividing it by the normalized system firm sales of
7 14,647,388 MWh (($30,808,925 * 0.95) / 1,4,647,388) :
8 $1.998/MWh : 0.1998 cents/kwh). The rate for PURPA
9 expenses is 0.1700 cents per kwh, which is calculated by
10 dividing $24,904,573 from Tabl-e 1 by the 14,647,388 MWh
11 ($24,904,513 / tq,641,388 MWh: $1.7OlMWh:0.1700
L2 cents/kwh). The rate for demand response incentive
13 payments is a negative 0.0216 cents per kwh, which is
L4 calculated by dividing the negative $3,850,567 from Tabl-e 1
15 by the Idaho jurisdictional firm sales of 13,955,821 MWh
16 (-$3,850,567 / t2,955 ,827 MWh : -$0.27 6/tqwh : -0.0276
L7 cents/kwh) . The forecast portion of the PCA rate is 0.3422
18 cents per kwh, which is calculated by adding the non-PURPA
19 expense of 0.1998 cents per kWh to the PURPA expense of
20 0.1700 cents per kWh to the demand response j-ncentive
2l payment of negative 0.0216 cents per kwh (0.1998 + 0.1700 +
22 -0.0276 : 0.3422 cents/kwh).
23 a. How dj-d you compute this year's True-Up rate?
24 A. As shown in Exhibit No. L, this year's True-Up
25 component of the PCA is $43.7 mi-1lion, which when divided
LARKIN, DI L9
Idaho Power Company
1 by the Company's forecast of Idaho jurisdictional sal-es of
2 13,955,821 MWh results in a rate of 0.3729 cents per kwh
3 ($43,661,793 / 73,955,821: $3.13/uwrr: 0.3129 cents/kwrr).
4 The True-Up of the True-Up rate is calculated by
5 dividing a negative $5.1 million (a1so from Exhibit No. l-)
6 by the forecast of Idaho jurisdictional sal-es of 13,955,827
7 MI/,Ih, which results in a rate of negative 0.0364 cents per
8 kvih (-$5,073,L31 / 13,955,82l.: -$0.36lMWh : -0.0364
9 cents/kwfr) .
10 O. Does the quantified True-Up rate incl-ude the
11 sal-es of Renewable Energy Certificates ("REC" or "RECs")
12 and Sulfur Dioxide ("SOz") proceeds?
13 A. Yes. The RECs and SOz proceeds are included
14 in the Company's deferral- expense report, provided as
15 Exhibit No. 7, on lines 47 and 48. Order No. 32002 issued
L6 on June 7L, 2010, accepted for filing the Company's REC
Ll Management PIan, which passes the customers' share of REC
18 benefits back to customers through the PCA. Order No.
1,9 32434 approved on January 12, 20L2, directed the Company to
20 pass SO2 proceeds through the PCA to heJ-p offset the
27 Company's PCA deferral balance.
22 O. What is the resulting PCA rate when you
23 combine al-1 of the PCA components described previously?
24 A. The Company's PCA rate for the 2016-20L7 PCA
25 year is detailed in Exhibit No. 2, column E. The uniform
LARKIN, DI 20
Idaho Power Company
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4
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PCA rate is comprised of (1) the 0.3422 cents per kwh
adjustment for the 20L6-2071 projected power cost of
serving firm loads under the current PCA methodology and 95
percent sharing, (2) the 0.3L29 cents per kVllh for the 2075-
2076 True-Up portion of the PCA, and (3) the negative
0.0364 cents per kwh for the True-Up of the True-Up. The
sum of these three components results in a 0.6187 cents per
kwh charge for all rate classes.
III. ADDIEIONAL RATE ADJUSIA@NTS
Revenue Sharinq
O. lllhen was the revenue sharing mechanism
originally establ-ished?
A. The revenue sharing mechanism was origi-na1ly
established in Case No. IPC-E-09-30 and approved in Order
No. 30978, effective for the years 2009-20LL, then modified
and extended for the years 20L2-2014 in Order No. 32424 in
Case No. IPC-E-1L-22.
o.Did the revenue sharing mechanism resul-t in
any action following the 2009-2074 fiscal years?
A.Yes. The Company's earnings in each year from
2071 through 20L4 resu1ted in revenue sharing with
customers totaling $118 millj-on, ej-ther as a direct rate
offset in the PCA or as an offset to amounts that would
have otherwise been collected in rates. These amounts are
detailed in Table 5 bel-ow.
LARKIN, DT 2I
Idaho Power Company
Table 5 2OO9-2OL4 R€venu€ Sharins
Line No. Revenue Sharinq Conponent 2OO9-2OLL 2OL2-2OL4
1
2
3
4
q
6
7
Available ADITC For Use
ROE Threshold
50-50 Sharing Threshold
'15-25 Sharing Threshold
Customer Benefits ($ Millions)
Reduction to Rates
Offset to Pension Balancinq Account
$4s
Mil-lion
9.58
10.58
N/A
927 .7
$20.3
$4s
Mill-ion
9.5t
10.0t
10.58
922.8
s47.8
IotaI
2009-20L4
I Total $41.4 $70. 6 9118.0
2
3
4
5
6
7
I
9
10
11
t2
13
L4
15
76
1-1
18
19
o.Has the revenue sharing mechanlsm been
extended beyond the 2072-2014 time frame?
A. Yes. In Case No. IPC-E-I4-14, the Company
filed a motion to approve a settlement stipulation (*2014
Stipulation") extending the sharing mechanism, with
modj-fications, through the end of the 20L9 fiscal year.
The Commission approved the 20L4 Stipulation in Order No.
3314 9.
o.What are the provisions of the current revenue
sharing mechanism as approved in the 2014 Stipulation?
A. Per the terms of the 2074 Stipulation, if the
Company's actual-, year-end Return on Equity (*ROE") for the
Idaho jurisdiction exceeds 10 percent, all amounts up to
and including a 10.5 percent ROE will be shared between
customers and the Company on a 75 percent and 25 percent
basis, respectively, to be provided as a rate reduction to
become effective at the time of the subsequent year's PCA.
LARKIN, DI 22
Idaho Power Company
1- If the Company's Idaho jurisdictional- ROE exceeds 10.5
2 percent, all amounts in excess of 10.5 percent wil-l- be
3 shared 50 percent with Idaho customers as a rate reduction
4 to become effective with the subsequent year's PCA, 25
5 percent w111 be shared with Idaho customers in the form of
6 an offset to amounts in the Company's pension balanclng
7 account and 25 percent will- be apportioned to the Company.
8 With regard to the amortization of Accumulated
9 Deferred Investment Tax Credits ("ADITC"), the 2014
10 Stipulation allows the Company to acceferate the
11 amortizati-on of ADfTC to achieve a maximum 9.5 percent
12 Idaho jurisdictional ROE if the Company's year-end actual-
13 results fall below that amount in any single year between
L4 2015 and 2019. The extension limits total- cumul-ati-ve
15 accelerated amortization of ADITC to $45 million over the
1,6 20L5-2079 time perj-od, with no more than $25 miltion to be
l'7 accelerated in a single year.
18 O. Have you provided an exhibit that summarizes
L9 the terms of the current shari-ng mechanj-sm?
20 A. Yes. Exhibit No. 3 contains a graphical
2L depiction of the current sharing mechanism, detailing the
22 various ROE thresholds and sharing provisions.
23 O. Did the Company's year-end 2015 fj-nancial
24 results warrant any action related to the existing sharing
25 agreement per the terms of the 2074 Stipulatj-on?
LARKIN, DI 23
Idaho Power Company
I A. Yes. The Company's year-end 2015 financj-al
2 results yielded an actual Idaho jurlsdictional ROE of 10.13
3 percent, resulting in a revenue amount to be shared with
4 customers after tax gross-up of $3,159,418.
5 O. Did the Company uti-lize the same methodology
6 to determine the Idaho jurisdictional 2075 year-end ROE
7 that was used J-n prior PCA filings?
I A. Yes. The methodology used to determine the
9 Company's Idaho jurisdictional 2075 year-end ROE j-s
10 consistent with the methodology used for the year-end ROE
l-1 determinatj-ons since the inception of the mechanism.
1,2 O. Do you have an exhibit demonstrating the
13 application of this methodology?
74 A. Yes. Exhibit No. 4 provides a step-by-step
15 calcul-atj-on of the Idaho jurisdictional ROE and subsequent
L6 revenue sharing benefits based on year-end 2015 financial
71 results utilizing the Commissj-on-approved methodology from
18 previous PCA filings.
L9 O. What is the revenue sharing amount to be
20 incl-uded in the 201,6-2017 PCA?
2L A. As detail-ed in Exhibit No. 4, the 2075 Idaho
22 jurisdictional- ROE was 10.13 percent. As quantified on
23 line 63 of Exhibit No. 4, in 2015, the Company's earnings
24 exceeded an Idaho jurisdictional- ROE of 10 percent by
25 $2,565,553. Per the terms of the 20L4 Stipulation, 75
LARKIN, DI 24
Idaho Power Company
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percent of the $2,565,553 should be shared with customers
as a direct reduction to PCA rates effective June l, 2016.
Applying the 75 percent sharing provision to the $2,565,553
yields a customer-allocated sharing amount of $L,924,L65.
After tax gross-up, the revenue sharing amount to be
applied to customer bills is $3,159,478.
o.How does the Company propose to al-l-ocate the
$3r159,47 8 revenue sharing to customer classes?
A.The Company proposes to allocate the revenue
sharing benefit to customer classes util-izing the same
methodology as in past cases; i.e., based on each class's
proportional share of forecasted base rate revenues for the
upcoming PCA rate effective year, which in this case is
June l, 20L6, through May 31, 201,7 .
o.Have you provided an exhibi-t detail-ing the
class all-ocation utiliz:-ng this methodology?
A.Yes. Exhibit No. 5 details the class
allocation of the $3,159,41 8 revenue sharing benefit. As
displayed in cofumn G of Exhibit No. 5, each customer class
receives a decrease of approximately 0.31- percent relative
to current base revenues.
o.How does the Company propose to j-nclude the
cl-ass-allocated revenue sharing benefits in rates?
A.With the exceptlon of the special contracts
for Micron Technology, Inc., the U.S. Department of Energy,
LARKIN, DI 25
Idaho Power Company
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and the J. R. Simplot Company - Pocatello, Idaho Power
proposes to j-nclude the cl-ass-allocated revenue sharing
benefits on a cents-per-kWh basis applied to the 20L6 PCA
rates effective June L, 20L6, through May 31, 2077. Column
F of Exhibit No. 5 contains the rates proposed for
inclusion in each class's PCA rate.
a.What is the Company's proposal for providing
revenue sharing benefits to its special contract customers?
A.Consistent with the methodology used to share
20t7, 2012, 201,3, and 20L4 revenues, the Company proposes
to provide the special contract customers a flat do11ar-
per-month credit in L2 equal portions to serve as a
reduction to monthly invoices bil-Ied from June 2016 through
Nlay 2017. The total revenue sharing benefit al-located to
each special contract customer is displayed in column E of
Exhibit No. 5.
O. Is the Company's rate design proposal for the
2015 revenue sharing benefits consistent with past-approved
proposals ?
A. Yes.
DSM Rider Transfer
O. Is the Company proposing the continuation of
the approximate $4.0 million DSM Rider transfer adjustment
that was incl-uded in the 2015 PCA filing?
LARKIN, DI 26
Idaho Power Company
1 A. Yes. The Company is proposing the
2 continuation of a PCA credit re]ated to the DSM Rider in
3 the amount of $3,970,036.
4 Q. Why is this credit necessary?
5 A. This credit is necessary to malntain the
6 revenue neutrality associated with the 201,4 update to the
7 normalized level of NPSE included in base rates approved by
8 Order No. 33000.
9 Q. Pl-ease explain.
10 A. Idaho Power's current l-evel of DSM Rider
11 collection is 4 percent of base rate revenues. The
72 approval to increase the Company's l-evel of base rate
13 revenues by $99.3 million effective June L, 20L4, results
L4 in the Company collecting approxi-mately $4.0 million per
15 year of additional- DSM Rider funds. To ensure the base
16 rate increase associated with the new base l-evel of NPSE
77 approved in Case No. IPC-E-L3-20 remains revenue neutral
18 for all classes of customers, it is appropriate to offset
19 the increase in DSM Rider revenue by moving $4.0 mill-ion
20 out of the DSM Rider balancing account and providing that
2! amount as a credit to customers in the 20L6-2071 PCA. This
22 adjustment should contj-nue to be j-ncl-uded in PCA rate
23 determinations until the level of NPSE recovery in base
24 rates is re-established as part of a general rate case or
25 otherwise adjusted by Commisslon order.
LARKIN, DI 27
fdaho Power Company
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o.How j-s the Company proposing to apply the DSM
Rider transfer to customer rates?
A.The Company is proposing to apply the
previously approved method of a cents-per-kWh credit to
each class's PCA rate effective June t, 2016, through May
31, 201,1. This approach al-l-ows each customer class to
receive the credj-t in the same proportion as its respecti-ve
increase in base rates.
IV. RATE ST'U}IARY A}ID NET CUSTOMER IMPACT
o.Has the Company provided an exhibit detailing
the final rates requested to become effecti-ve June L, 20L6,
including the PCA components, revenue sharing, and DSM
Rider transfer?
A. Yes. Column E of Exhibit No. 2 contains the
final rates for each customer cl-ass proposed to become
effective June 7, 2076, through May 31, 20L7. These rates
include the standard PCA rate of 0.6187 cents per kI/'Ih, the
-0.0284 cents per kWh associated with the DSM Rider
transfer, and each class's allocation of the revenue
sharing component.
O. What is the revenue lmpact of the requested
PCA rate combined with revenue sharing and the adjustment
related to the DSM Rider when compared to PCA rates
currently in effect?
LARKIN, DI 28
Idaho Power Company
1
2
3
4
5
6
7
8
9
10
11
72
A. Attachment 2 to the Application provides a
detailed description of the overa1l revenue impact of this
filing on each customer class. As shown on Attachment 2,
applying the requested PCA rates to expected customer sales
for the June 2076 through May 2017 test year results in a
PCA increase of $17.3 mlllion.
O.Have you prepared a tabl-e that detaj-ls the
$17.3 million revenue impact by component?
A.Yes. Tab1e 6 below separates the $17.3
million increase into each component included in the
Company's proposed rates.
O. Have you prepared a revised Schedule 55 that
includes the proposed PCA rates?
n Because Tabl-e 6 contains the expected billed revenue impact to
customers, the "20L5-20L6 PCA" cofumn refl-ects approved 2075-2016 PCA
rates applied to the June 201,6 through May 201,1 sal-es forecast, andwill- not tie to the specific dol-l-ar amounts approved in the 2015 PCAfiling.
5 The -20L6-20L7 PCA' column reffects the Company's proposed ratesapplied to the June 2016 through May 201-1 forecast, and may not tie
exactly to the figures l-isted in the above testimony due to the
rounding of rates to six digits.
LARKIN, DI 29
Idaho Power Company
13
L4
15
Tab].e 6 Rovenue I[Dact bv Comoonent
tine No. Rate Conponent 2015-2015 PCA{ 2015-ZO1Z pCes Difference
1
2
3
4
PCA Forecast
PCA True-Up
Revenue Sharing
DSM Rider Onqoinq Transfer
$ 39, 299,591-
$ 34,652,303
$ (8,048,717 )
s (3,991,36s)
$ 41 ,110,11 4
$ 38,587,844
$ (3,159,478)
s (3,970,036)
s 8,471,183
$ 3,935,541
$ 4,889,239
s 27,329
q PCA Tota]-9 61 ,911,812 $ 79,229,LOA $ L7,3L7,292
1 A. Yes. Attachment 1 to the Application is a
2 revrsed Schedul-e 55 and includes the proposed PCA rates in
3 clean and legislative formats.
4 Q. Should the Commj-ssion approve the Company's
5 computatj-on of the PCA rates?
6 A. Yes. The Commission shoul-d approve the
7 Company's computation of the PCA rates. The calculation of
8 the PCA rates follows the methodology that was approved 1n
9 Order Nos. 30715, 30978, 32424, 32518, and 33000.
10 0. Does this conclude your testimony?
11 A. Yes, it does.
1,2
13
74
15
76
77
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L9
20
27
22
23
24
25
LARKIN, DI 30
fdaho Power Company
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3
4
5
6
7
8
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31
STATE OE TDAHO
County of Ada
ATTESTATIOT{ OE'TESTIMOIIY
SS.
)
)
)
l, Matthew T. Larkin, 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 Revenue
Requirement Manager in the Regulatory Affairs Department
and am competent to be a witness in this proceeding.
I declare under penalty of perjury of the laws 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 15th day of April 2076.
':/-- .=-2--
Matthew T. Larkin
SUBSCRfBED AND SWORN to before me this 15th day of
April 20L6.
LARKIN, DI 31
Idaho Power Company
Notaiy Public or Idaho
Residing at:
expr-res:My commission
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
GASE NO. IPC-E-16-09
IDAHO POWER COMPANY
LARKIN, DI
TESTIMONY
EXHIBIT NO. 1
Exhibit No. 1
Case No. IPC-E-16-08
M. Larkin, IPC
Page 1 of 2
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Exhibit No. 1
Case No. IPC-E-16-08
M. Larkin, IPC
Page2 of 2
BEFORE THE
IDAHO PUBLIG UTILITIES GOMMISSION
GASE NO. IPC-E-16-08
IDAHO POWER COMPANY
LARKIN, DI
TESTIMONY
EXHIBIT NO.2
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Case No. IPC-E-16-08
M. Larkin, IPC
Page 1 of 1
dNmst!ntoF6(h3*SP=H
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
GASE NO. IPG-E-16-09
IDAHO POWER COMPANY
LARKIN, D!
TESTIMONY
EXHIBIT NO.3
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Exhibit No. 3
Case No. IPC-E-16-08
M. Larkin, IPC
Page 1 of 1
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
GASE NO. IPC-E-I6-08
IDAHO POWER COMPANY
LARKIN, DI
TESTIMONY
EXHIBIT NO.4
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IDAHO FOYI'ER COMPAI{Y
ADDITIONAL INVESTMENT TAX CREDIT ANALYSIS
For the Tmlve ilontb End,sd Do@mbar 31, 2015
ffi
!II!E E'E !M
3,084.399,544 2,962,272,U9 95 7%
A97.%276 a57.%2%O DidAssEn
u,o77,T1 40,032.272 95 2%
982.020.087 937.975.212
IOTAL
SYSTEM rc m*
September AllMonJFlatG
ffiOEVELOPMENT OF NET INCOME
OPEMNNG REWNUES
RETAII $tES REVENUES (d4I RE)
OTHER OPEMING REVENUES
TOTAL OPERATING REWNUES
OPEMNNG EXPENSES
OPERATION & MAINTENANCE EXPENSES
DEPREC[NON EXFENSE
AMORTUNON OF LIMITED TERM PUNT
TUES OTHER TUN INCOME
REGUUTORY OEBITSCREOITS
PROVISION FOR DEFERFEO INCOME TdES
INVESilENT TU CREOIT AOJUSruEN]
FEOERAL INCOME TUES
STATE INCOME TUES
TOTAT OPERAIING UPENSES
OPEMTING INCOME
AOO: IERCO @EMnNG INCWE
1.1U 191 532 1 1A1 A62025 DtrectA6iln
115.163 392 109.622.745 9s290
1,269,3@,925 1,211,4U,a10
611,253,343 5A2,013,724
97,613,ffi 93,396,616
5,231,314 5,008,289
24,999,080 23.2A4,959
61,959 0
12,048,295) (1,928345)
1444,742) 1425,774)
41,031,302 39,848 590
4.309,721 4.205,337
74206747 7454028S
800 756 552
130,931 146
6,998,504
32,808.301
42.611
29 419 016
492 099
12,593,365
5.986.1 10
1,020,067,703
249,293,z21
6,659 942
255,953,r63
21,7A5 246
(3 105,928)
271,632,481
a1 724 714
752 451,295
125,275,504
6,700 139
30,558,723
0
28,251,@1
471,112
12.230,6
5,441.123
971,779,Ul
239,705,{69
6,34n,437
246.069,906
20,852,OX
(2,985,997)
T3,935,935
78,n3,86
145,712,O79
105,712,O79
1,83,030,811
10 13%
952%
95 7%
95.7%
93.1%
0.0%
94.1%
95 7%
971
97.6%
95 6%
952%
95.7%
95.7%
93 1%
0.0%
96 0%
95 7%
97 1%
97 6%
OPEUNNG IrcOME BEFORE OTHER INCOME ANO OEDUCNONS 204,707,093
ADO AFUDC EAUIry
AOO, OTHER INC*E ANO DEOUCNONS
INCOME BEFORE INEREST CHARGES
TESS INERESICHARGES
NEI INCOM€
ACruAT YAR-ENO RESULTS. SEFORE ITCAOJUSWEXT
AFNINGSON COUMON STOCK
COMMON EOUIryATYAR ENO
RETURN ON YEAR.ENO CilMON EOUIry
aRNTNGS ON COMMON SIOCKO 9S ROE
ilFNTNGS ON COMMON STOCK O 10 ROE
ilRNINGS ON COMMON STOCK O 10 $ ROE
ACTUAI YEAR.ENO RESULTS.AFTER ITC AOJUSruENT:
INVESruENT IU CREDIT AOJUSilENI
AOJUSTED ARNINGS ON COWON STOCK
AOJUSTEO CWMON EQUIry ATYEAF-ENO
AOJUSTEO REruRN ON YilR.ENO CtrMON EOUIry
200,013,v0
4 693 753
192,572,316
4,485,48S)
197.057.805
95 6%
96 1%
95 7% (L 10)
96 1% (L 33)
95 7% (L 10)
192,9,)7,762
192,907,762
1 916.111.771
10.07%
182,030,618
191,611,177
201,191,75
9s 7% (L10)
171232,927 (L4'9.5%)
l83,r.(}3,Otl (L44'10%)
102.573,235 (144. 10.5%)
(12,684,145) (L48-143) / (1-9 s%)
173,027.933
1,821,m,666
I 50%
Notes: (11 The lina item "Provasion tor Oefsred Ta" refleds the sum of two defered tax categorios that are all@t6d to the ldaho jurisdiclion under dfierent alloGtion
bases. For the month€nding September 30,2015 the detailed tax €tegories included both posilive and n€gative values resulting in a skryed all@tion ratio. To remove
th€ skqfling €ff6ct ths September 30, 2015 dstailad ta devialions were @nverted to absolute values which r6sult6d in a more reasonable allffition ratio of 96.0 perunt.
Exhibit No. 4
Case No. IPC-E-16-08
M. Larkin, IPC
Page 1 of 1
IOAHO RETURN ON COMMON EQUITY llino{6} <0.5et
AoDITIoNAI ITC AUUSilENT (AnturH) lr Lsi..qe.lb 0:irF{k.lh mdEof gdS,m,m
lDffiO RETURN ON COT4MON EOUtrY (Llm,|al >10't
IMAO ARNNGS GRAIEF THAN IB ROE BUT LESSNAN 105%
pffiO RETURN oN COMiTON EOun (Lin./t8) >10.516
INCREMENTA! IDAHO ARNNGS GRAER BAN IOS ROE
Ordc, l(Xllrl0:
RoE tfu 1610.5*-CUSTWER SHARE - 6$ (Rd6bEb)
ROE blw6 IBIO5% -CqPAW SHARE,5*
ROE g*r h i0 5$ (rMffir) - cusTouER SMRE - S (RdEb b da)
ROE gdrtb l0 5I (lffi!!ld) - CUSTOMER SMRE ' 2st (ffi to tutu bbe)
RoE grdr tu 10.51(lEmd) -cqPANY SHARE ' 6%
0
2,565,513 (L41L49y(1-1ffi)
0 (L43L5O){1-r0596)
1,94.165
641,388
0
0
0
2,565,553
BEFORE THE
IDAHO PUBLIG UTILITIES COMMISSION
GASE No. iPc-E-l6-0g
IDAHO POWER COMPANY
LARKIN, DI
TEST!MONY
EXHIBIT NO.5
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Exhibit No. 5
Case No. IPC-E-16-08
M. Larkin, IPC
Page 1 of 1
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