20140415Direct T. Tatum.pdf

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OE THE APPLICATION
OE IDAHO POWER COMPANY FOR
AUTHORITY TO IMPLEMENT POWER COST
ADJUSTMENT (*PCA") RATES EOR
ELECTRIC SERVICE EROM JUNE 7,
2074, THROUGH MAY 31, 20L5, AND
TO UPDATE BASE RATES IN
COMPLIANCE WITH ORDER NO. 33OOO.
CASE NO.rPC-E-14-05
IDAHO POWER COMPANY
DIRECT TESTIMONY
OE
TTMOTHY E. TATUM
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o.
A.
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A.
address is t22I West Idaho Street, Boise, Idaho 83102.
O. By whom are you employed and in what capacity?
A. I am employed by Idaho Power Company ("Idaho
Power" or "Company") as the Senior Manager of Cost of
Service in the Regulatory Affairs Department.
Pl-ease state your name and busj-ness address
My name is Timothy E. Tatum and my business
Please describe your educational background.
I have earned a Bachelor of Business
Administration degree in Economics and a Master of Busj-ness
Administration degree from Boise State University. I have
also attended electric utility ratemaking courses,
including "Practicaf Skills for The Changing Electrical
Industry, " a course offered through New Mexico State
University's Center for Public Utilities, "Introduction to
Rate Design and Cost of Service Concepts and Techniques"
presented by El-ectric Utilities Consultants, Inc., and
Edison Electric Institute's "E1ectric Rates Advanced
Course." In 20!2, I attended the Utility Executive Course
at the University of Idaho.
O. Pl-ease describe your work experience wj-th
Idaho Power.
A. I began my employment with Idaho Power in 7996
as a Customer Service Representative in the Company's
Customer Service Center where I handled customer phone
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call-s and other customer-rel-ated transacti-ons. In 7999,
began working in the Customer Account Management Center
where I was responsible for customer account maintenance
the areas of bil-Iing and metering.
In June of 2003, after seven years in customer
service, I began working as an Economic Analyst on the
Energy Efficiency Team. As an Economic Anal-yst, I was
responsible for ensuring that the demand-side management
("DSM") expenses were accounted for properly, preparing and
reporting DSM program costs and actj-vities to management
and varj-ous external stakeholders, conducting cost-benefit
analyses of DSM programs, and providing DSM anal-ysis
support for the Company's 2004 Integrated Resource Plan
(*rRP").
In August of 2004, T accepted a position as a
Regulatory Analyst in Regulatory Affairs. As a Regulatory
Analyst, f provided support for the Company's various
regulatory activities, including tariff administration,
regulatory ratemaking and compl-i-ance filings, and the
development of various pricing strategies and policies.
In August of 2006, T was promoted to Senior
Regulatory AnaJ-yst. As a Senior Regulatory Analyst, my
responsibil-ities expanded to include the development of
complex financial studies to determj-ne revenue recovery and
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1 pricing strategies, including the preparation of the
2 Company's cost-of-service studies.
3 In September of 2008, T was promoted to Manager of
4 Cost of Service and in April of 20L1, I was promoted to
5 Senior Manager of Cost of Service. As Senior Manager of
6 Cost of Service, I oversee the Company's cost-of-service
7 activities such as power supply modeling, jurisdictional
8 separation studies, class cost-of-service studies, and
9 marginal cost studies.
10 O. Pl-ease revj-ew the intent and design of the
11 Power Cost Adjustment ("PCA") mechanism?
72 A. The PCA is a rate mechanism that quantifies
13 and tracks annual differences between actual net power
74 supply expenses (*NPSE") and the normalized level of NPSE
15 recovered in the Company's base rates ("base level NPSE")
16 for recovery or credit through an annual- rate change each
77 June 1. The PCA mechanism utilizes a 12-month test period
18 of April through March (*PCA Year") and i-s composed of a
19 forecast component (*PCA Eorecast") and a true-up component
20 (*PCA True-Up"). The PCA Eorecast is based on the
2t Company's March Operating Plan and represents the
22 difference between the NPSE forecast from the March
23 Operating Plan and the base level NPSE recovered in the
24 Company's base rates. The PCA True-Up incl-udes a backward-
25 looking tracking of differences between the prior year's
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1 PCA Forecast and actual NPSE j-ncurred by the Company during
2 the prior PCA Year. The PCA True-Up contains a second
3 component that tracks the collection of the prior year's
4 true-up amount, referred to as the "True-Up of the True-
5 up."
6 With the exception of Public Utility Regulatory
7 Policies Act of L97B (*PURPA") expenses and demand response
8 incentive costs, the PCA allows the Company to pass through
9 to customers 95 percent of the annual dlfferences in actual-
10 NPSE as compared to the base l-evel NPSE, whether positive
11 or negatj-ve. The PCA is also the rate mechanism used by
72 the Company to provide any revenue sharing benefits
13 resulting from the revenue sharing mechanism approved by
L4 Order No. 32424.
15 O. What is the Company requesting in this case?
1,6 A. The Company is making three requests in this
L7 case. First, Idaho Power is requesting a determination by
18 the fdaho PubIic Utilities Commission ("Commission") that
19 the Company has correctly calculated new base rates in a
20 manner that complies with Commission Order No. 33000 1n
27 Case No. IPC-E-13-20.1 If the Company's calculation is
lOrder No. 33000 approved a new normalized or base l-evel- NPSE of
$305,684,869 to be utilized 1) to update base rates on June 1,201,4,
and 2) as the basis for quantifying the 2014-2015 PCA rates that wouldalso become effective June 1, 201,4. The order al-so directed the Companyto implement the change to base level NPSE in a manner that will haveno net impact to the overall revenue col-lected through customer rates
and is "revenue neutral" for all c.l-asses of ldaho customers.
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approved, the newly establ-ished base rates will provide for
collection of an additional $99.3 million in base level-
NPSE as dj-rected in Order No. 33000. Second, the Company
is requesting approval of the 201,4-20!5 PCA amount of $87.5
million, a decrease of approximately $72.L mil-Iion as
compared to 2013-2014 PCA collection. If approved, the net
effect of the change in base rates and the PCA would be an
increase in annual bi1led revenue of approximately $27.L
million to become effective on June L, 2074. Lastly, the
Company is requesting that the Commission approve a one-
time PCA mitigation measure intended to lessen the impact
of this year's PCA on customers by utiliz:-r,g $16 million of
surplus Idaho Energy Efficiency Rider (*DSM Rider") funds
as an offset to this year's PCA col-Iection resulting in an
adjusted net increase of approximately $11.1 miIlion.
O. Pl-ease provide an overview of the Company' s
CASC.
A.Mr. Scott Wright is the Company witness j-n
this case who will present the development of the 2074-2075
PCA rates. Mr. Wright will explain that the methodology
used to determine the 201,4-2075 PCA rates is consi-stent
with that approved by the Commission in prior PCA rate
proceedings. Mr. Wright will al-so descrj-be the changes to
the PCA rate inputs that have occurred since last year's
PCA. Einally, Mr. Wright wil-I present for the Commission's
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1 approval an update to the rate l-isted on Schedul-e 89, Unit
2 Avoided Energy Cost of Cogeneration and Small Power
3 Production. The update to the Schedule 89 rate ref1ects
4 the newly established base level NPSE as required by Order
5 No. 32758.
6 My testimony in this case wil-I present the
7 quantification of the base rate increase pursuant to Order
8 No. 33000 and describe the factors that have i-mpacted this
9 year's PCA quantification (including revenue sharing) .
10 Einal1y, my testimony wiII present the Company's rationale
11 for proposing a one-time PCA mitigation measure intended to
\2 lessen the impact of this year's PCA on customers.
13 O. How is your testimony organi-zed?
14 A. My testimony is organized into seven secti.ons.
15 The first section presents the quantification of the base
16 rate update pursuant to Order No. 33000 and details the
l7 implementation plan which will- result in no net impact to
18 the overal1 revenue col-l-ected through customer rates and
19 wil-I al-so be "revenue neutral" for al-I classes of Idaho
20 customers. The second section provides a high-Ieve1
27 discussion of the 20L4-2075 PCA amount and the year-over-
22 year differences that contribute to this year's PCA rate
23 change. Beginning with the third section of my testimony,
24 I wil-l- focus on individual components of the PCA. The
25 third section provides a review of the factors that
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contributed to this year's true-up amount. The fourth
section presents the determination of this year's revenue
sharing amount. The fifth section describes the PCA
forecast amount and the mai-n drivers of that amount. In
the sixth section of my testimony, I present a one-time PCA
rate impact mitigation alternative for the Commission's
consideration. The final- section of my testimony
summarizes the Company's request.
I. RE\IENT'E NEUTRAI BASE RATE UPDATE
O. Please provide a brief summary of the
Commission's Order No. 33000 in Case No. IPC-E-13-20.
A. On March 27, 2074, the Commission issued
Order No. 33000 approving the Company's request to
establish a new normallzed or base level NPSE of
$305,684,869 to be utilized l-) to update base rates on June
L, 2014, and 2) as the basis for quantifying the 2074-20L5
PCA rates that would al-so become effective June 7, 2074.
The order also directed the Company to implement the change
to base level- NPSE in a manner that will- have no net impact
to the overall revenue col-lected through customer rates and
is "revenue neutral" f or al-l- classes of Idaho customers.
(Order No. 33000, p. 9.)
O. How does the Company propose to implement the
newly establ-ished base level NPSE of $305,684,869 to
achj-eve a revenue neutral base rate adjustment?
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A.The Company's request in this case incl-udes a
PCA determination based upon a measurement of the forecast
April 2074 through March 2015 NPSE compared to the newly
established 2013 base l-evel- NPSE of approximately $305.7
million. Because the new base leve1 NPSE is greater than
the previous base level NPSE, the resulting j-ncremental PCA
col-lection amount will be lower. Pursuant to Order No.
33000, the Company has quantified the base rate increase
required to offset the reduction in incremental- PCA
collection on June L, 2074. In other words, base rates are
to be increased in a manner that will generate the same
l-evel of revenue that would have otherwise been allowed for
recovery through the PCA.
O. What is the difference between the previous
base level NPSE and the newly established 2013 base l-evel-
NPSE that will become effective on June 7, 20L4, per Order
No. 33000?
A.The difference between the previous base
l-eve1 NPSE and the newly established 2013 base level- NPSE
per Order No. 33000 that wil-l become effectlve on June 7,
20L4, is $105,69L,09L on a total- system-level. The
fol-Iowing Table 1 presents on a detailed component basis
the differences that exist on a total- system-basis between
the current base l-evel NPSE and the 20L3 base l-evel- NPSE
that will become effective on June 7, 201,4:
TATUM, D] B
Idaho Power Company
Tab].e 1. System-Level PCjA Accounts:
FERC Account Cunent Effective 611114 Difference
Account 501, Coal
Account 536, Water for Power
Account 547, Other Fuel
Account 555, Purchased Power Non-PURPA
Account 565, 3rd Party Transmission
Account 447, Surplus Sales
Account 4y'.2,Hoku 1st Block
Base NPSE
5 L67,tgz,7q
7,929,6N
5L,934,20L
45,510,093
8,262,W
(124915,153)
.23,92L,4661
Base NPSE
S 108,503,180 S
2,380,597
33,367,563
62,606,593
5,455,955
(51,735,153)
(5&689,564)
551,957
(18,555,538)
17,096 500
(2,806,045)
73,181,m0
23,921,466
Net 95% Accounts
Account 555, PURPA
Account 555, Demand Response lncentives
S 125,890,059
5 62,8sr,454
1L,252,265
160,578,735 s
133,853,859 s
L1,252,265
u,688,676
77,m,2,475
s
s
Total s 199,993,778 5 305,684,869 s 105,591,091
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3 Q. What is the Idaho jurisdictional share of the
4 $105.7 million difference in system-Ievel base NPSE?
5 A. Based upon the current energy-based al-focatlon
6 used for PCA computational purposes of 95.48 percent, the
7 Idaho jurisdictional share of the $105.7 million difference
8 in system-level- base NPSE would be approximately $100.9
9 million.
10 O. Does the $100.9 mil-Iion represent the increase
11 to Idaho jurlsdictional base rates that the Company is
72 proposing as part of this filing?
13 A. No. To maintain the same overall- level of
!4 revenue recovery from base rates and the PCA in aggregate,
15 it is necessary to adjust the $100.9 million difference in
76 Idaho jurisdictional base level- NPSE to reflect the 95/5
11 customer to Company sharing provision that exists in the
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PCA. With the exception of PURPA expenses and demand
response incentive costs, the PCA all-ows the Company to
pass through to customers 95 percent of the annual
differences in actual NPSE as compared to the base leve1
NPSE, whether positive or negative.
As can be seen on Table 7, the total- system-1evel
difference in NPSE within the Eederal Energy Regulatory
Commission ("EERC") accounts that are subject to 95 percent
recovery (or credit) under the PCA is approximately $34.7
million. Under the PCA mechanism, the Company would
recover 95 percent of the Idaho jurlsdictional share of the
$34.7 million difference or $31.5 million ($34.7 mil-l-ion x
95.48% x 95.00? $31.5 mill-ion) . When the $31.5 mi]Iion
of all-owed recovery j-s combined with 100 percent of the
difference in the Idaho jurisdictional- share of FERC
Account 555, PURPA, of $67.8 mil-Iion ($2f .0 million x
95.48% : $67.8 million) , the total- al-l-owed recovery under
the PCA would be $99.3 million. Therefore, the Company's
implementation of Order No. 33000 will result in an
increase to base rates of approximately $99.3 milli-on,
which includes a $1.6 million "PCA sharing" reduction to
the total difference in Idaho jurisdictional base level
NPSE of $100.9 million. This $1.6 mi1lion "PCA sharing
adjustment" will- continue to be reflected in base rates
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i-n
of
until the Company fil-es its next general rate case or it is
otherwise adjusted by Commission order.
o.Has the Company determined the new base rates
a manner that will be "revenue neutral" for all classes
customers as directed by Order No. 33000?
A Yes. The Company has determined new base
rates by apportloning the approxi-mately 999.3 million base
rate increase to each customer cl-ass using the same energy
allocation basj-s that would exist under the PCA; that is,
in proportj-on to each class's annual energy consumption.
By using the same energy all-ocatj-on basis applied in this
year's PCA filing, each customer class will contribute
exactly the same amount of revenue to offset NPSE that
would exist under the PCA col-lection. Attached as Exhibit
No. 1 to my testimony is a schedul-e which demonstrates that
the Company's proposal would result in no change to the
total amount of revenue by customer class from base rates
and the PCA, in aggregate. As can be seen on Exhibit No.
l, a comparison of cofumns (D) and (H) demonstrates a
revenue neutral shift of $99.3 million from the PCA into
base rates.
O. Are there any other steps that must be taken
to ensure that the requested base rate increase is "revenue
neutral" for all classes of Idaho customers?
TATUM, Dr 11
Idaho Power Company
I A. Yes. Idaho Power's current level of DSM Rider
2 collection is four percent of base rate revenues. The
3 approval to increase the Company's l-evel- of base rate
4 revenues by $99.3 million effective June l, 2014, will
5 result in approximately $A millj-on per year of additional
6 DSM Rider funds. To ensure the base rate increase
7 associated with the new base level of NPSE approved in Case
B No. IPC-E-L3-20 is revenue neutra] for aII classes of
9 customers, it is appropriate to offset the increase in DSM
10 Rider revenue by moving $4 million out of the DSM Rider
11 balancing account and providing that amount as a credit to
L2 customers in the 2074-2015 PCA. This adjustment should
13 continue to be included in future PCA rate determinations
1,4 until the level- of NPSE recovery in base rates is re-
15 established as part of a general rate case or otherwise
76 adjusted by Commission order.
11 rr. 2014-2015 PCA OVERVTET{
18 O. What is the total 2014-2015 PCA amount as
19 measured from the newl-y established 2013 base level NPSE
20 for the 20L4-2015 PCA Year?
2L A. The 2074-2015 total PCA amount (including
22 revenue sharing and a $q million DSM Rider adjustment) as
23 measured from the newly established 2013 base level- NPSE is
24 $87.5 mil-Iion. This represents a year-over-year reduction
25 in PCA collection of $72.L million when measured from the
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7 20L3-2074 PCA amount of $159.6 mil-l-ion. However, when
2 comblned with the base rate j-ncrease of $99.3, the total
3 change in annual billed revenue would be an increase of
4 approximately ;27.7 mil-Iion. The following Table 2
5 presents the year-over-year difference in biIled revenue
5 that would become effective June 7, 2074, segmented into
7 the fj-ve components: 1) the PCA Eorecast, 2) the PCA True-
B Up, 3) Revenue Sharing, 4) DSM Rider Transfer, and 5) Base
9 Rate Adjustment.
10 Tab1e 2. BilJ.ed Revenu@_
Table 2: Billed Revenue Comparison (ldaho Jurisdictional Amounts)
2013-2014 PCA* 2014-2015 PCA Difference
PCA Forecast
PCA True-Up
Revenue Sharing
DSM Rider Transfer
5LL!,969,Lo7
54,885,285
(7,276,2031
0
527,8L6,2r4
77,231,295
(7,602,0431
(3,97O,276l,
(s90,152,893)
22,345,OO9
(325,840)
8.970.2751
PCA Total $159,579,189 587,475,L9O ($72,103,999)
Base NPSE Update 0 99,250,892 99,2sO,892
Total S159,579,189 s185,726,081 $27,146,892* For comparison purposes, 20L3-2014 PCA component amounts
represent the Commission-approved 2013-2014 PCA rate applied to the
June 2014 through May 2015 sales forecast
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O. Please describe the information contained in
Table 2.
A.Table 2 demonstrates the extent to which each
PCA and base rate component contributes to the year-over-
year change in required revenue. As can be seen on Table
2, this year's PCA Forecast component is $2L,8L6,21,4 which
is $90,1,52,893 l-ess than l-ast year's PCA Eorecast of
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$111,969,707. This year's PCA True-Up component j-s
$71,23L,295. The difference between this year's PCA True-
Up component and last year's PCA True-Up component is an
increase of $22,345r009. This year's revenue sharing
component is a credit of $7,602,043, which is $325,840
greater than l-ast year's revenue sharing amount of
$7,276,203. The *DSM Rider Transfer" that is necessary to
ensure a revenue neutral implementation of the newly
establ- j-shed base Ievel NPSE is $3 , 97 0 ,27 6 . Fina11y, when
the base rate increase of $99,250,892 mill-ion is included,
the net increase in total annual billed revenue is
$21,746,892 milllon.
III. PCA TRT'E-UP
o.What is the most significant factor
contributing to this year's PCA True-Up amount of
approximately $77 .2 million?
A.The most significant factor contributing to
this year's PCA True-Up amount was lower actual hydro
generation during the PCA Year as compared to the 2073-2074
forecasted amount. The lower actual hydro generation
contributed to lower surplus energy sales revenue ("surplus
saIes"), which serves to offset power suppJ-y expenses
recovered from customers.
In the 2073-20!4 PCA Year, surplus sales were
forecasted to be approximately $98.5 million. Actual
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surplus sales in the 2073-2074 PCA Year were approximately
$66.8 million, or approximately 68 percent of the
forecasted amount. Attached as Exhibit No. 2 to my
testj-mony is a memo prepared at my direction that provides
additional detail regarding the factors contributing to
reduced surplus sales during the 201,3-201,4 PCA Year.
O. How did actual hydro generation compare to the
forecasted amount of hydro generation j-n the 2073-20!4 PCA
Year?
A.As can be seen on page 1 of Exhibit No. 2,
hydro generation for the 20L3-2074 PCA Year was forecast to
be 6.8 mill-ion megawatt-hours (*MWh"). Actual hydro
generation for the 20\3-2014 PCA Year was 5.7 million MWhs,
1.1 million MWhsr or 16 percent, less than had been
forecasted. The forecast of Brownl-ee Reservoir inflows for
the 20L3-20L4 PCA Year included in last year's March
Operating Plan was 9.42 mil-l-ion acre feet ("MAF") . Actual
inflows for the PCA Year were 1.91 MAE, 16 percent lower
than the forecasted amount. Detall- regarding the Company's
hydro generation for the 201,3-2014 PCA Year is presented on
page 2 of Exhibit No. 2.
O. Were there any other factors that contributed
to higher than projected NPSE during the 2073-201-4 PCA
Year?
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A. Yes. Customer loads during the 20!3-2074 PCA
Year were higher than forecasted in the March 20L3
Operating Plan by approximately one percent. Higher
customer loads contributed to higher than forecasted power
costs and lower surplus sales.
O. To what extent did the True-Up of the True-Up
contribute to this year's overal-1 true-up bal-ance?
A. Of the $77.2 million overall true-up balance,
approximately $19.1 million is associated with the True-Up
of the True-Up.
o.What led to a True-Up of the True-Up balance
of approximately $19.1 million?
A.As mentioned earlier i-n my testimony, the
True-Up of the True-Up is the part of the PCA mechanism
that tracks the collection of the prior year's true-up
amount. Because col-lection of the PCA does not begin until
June of each year, there is a two month lag between when
the PCA rates are calculated based on March 31 balances and
when collection/crediting actually begins in June.
Therefore, when the PCA True-Up of the True-Up component of
the PCA is developed, the bal-ance only reflects
approximately l-0 months of col-Iection. The impact of the
Iag in col-Iection of the True-Up of the True-Up balance was
compounded in this case because the 20L2-201,3 PCA True-Up
component was a credit rate. As a result, revenue
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crediting rather than col-l-ection of the true-up bal-ance was
occurring during the billing months of April and May of
2073 also contributing to the True-Up of the True-Up
balance.
In summary, this year's True-Up of the True-Up
ba]ance reflects the standard ten months of annual
col-l-ection plus the impact of the revenue crediting that
existed during the billing months of April and May of 20!3
under the prior year's PCA rate.
a. On ApriJ- 2, 2073, the Commission lssued Order
No. 32776 (Case No. IPC-E-L2-29) temporarily suspending two
of three Idaho Power demand response programs for 2073.
Did the suspension of the two demand response resources
result in net benefits to customers?
A. Yes.
O. Have you quantified the savings associated
with the reduction in the incentive payments to the program
participants?
A. Yes. Idaho Power estimates that the two
temporarily suspended programs reduced program incentive
expenses by more than $10.0 million. The reduced demand
response program incentj-ve costs were reflected in the
2013/2074 PCA Forecast.
TATUM, Dr L]
Idaho Power Company
O. Did the Company incur additional power supply
2 expenses in order to obtain the $10.0 million in incentive
3 payment reductions?
A. Yes, but only to a very limited extent. Idaho
5 Power estimates that 1t incurred additional power supply
6 expenses of less than $10,000 associated with the
7 suspension of the two programs. Therefore, the suspensi-on
8 of the two demand response programs in 2073 resul-ted in a
9 net benefit to customers of nearly $10.0 million doll-ars.
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IV. REVENT'E SEARTNG
O. What impact does revenue sharing have on thls
TATUM, Dr 18
Idaho Power Company
t2 year's PCA?
13 A. The Company's 20L3 Idaho jurisdictional
L4 earnings were at a level that provides for approximately
15 $7.6 mill-ion in direct benefits to customers as part of
76 this year's PCA. This represents an j-ncrease in the level-
71 of sharing of approximately $326 thousand as compared to
18 l-ast year's sharing amount.
19 O. What j-s the total benefit customers will
20 receive as a result of revenue sharing based on the
27 Company's actual year-end 2013 financial results?
22 A. After tax gross-up, the combination of a
23 $1,602,043 reduction to PCA rates and a $16,5L2,853
24 reduction to the pensj-on balancing account results in an
25 overall- customer benefit of $24,L74,895.
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0.Have you prepared an exhibit that details the
Company's quantl-fication of the ldaho jurisdictional 20L3
Return on Equity ("ROE") and year-end earnings j-n excess of
10 percent?
A.Yes. Exhibit No. 3 details the Company's
quantification of the fdaho jurisdictional 201-3 ROE and
year-end earnings in excess of 10 percent. As can be seen
on l-ine 46 of Exhiblt No. 3, the 20L3 Idaho jurisdictional
ROE was 1,1.22 percent. As quantified on l-ine 73 of Exhibit
No. 3, rn 2013, the Company's earnings exceeded an Idaho
jurisdictional year-end ROE of 10 percent by $22,668,223.
O. How did the Company determj-ne the portion of
the $22,668,223 that is to be shared with customers?
A.fn accordance with the terms of the settlement
stj-pulation approved in Order No. 32424, revenue sharing
based on year-end 2013 financial results is to be provided
to customers in two tiers. The first tier refl-ects
customers' 50 percent share of the 20L3 Idaho
jurisdictional year-end earnings in excess of 10 percent
ROE up to and including 10.5 percent. The first tier,
calculated at 50 percent of $9,259,492, results in a
customer benefit prior to tax gross-up of $4,629,146.
After tax gross-up, customers recej-ve a total rate
reductj-on of $7,602,043. These amounts are displayed in
Exhibit No. 3 on l-ine 69.
TATUM, Dr 19
Idaho Power Company
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The second tier reflects customers' 75 percent share
of the 20!3 ldaho jurisdictional- year-end earnings in
excess of 10.5 percent ROE. The second tier, calculated at
75 percent of $13r408r731, results in a customer benefit
prj-or to tax gross-up of $10,056,549. After tax gross-up,
customers receive a total- benefit of $1-6,572,853 in the
form of an offset to the Company's pension balancing
account. These amounts are displayed in Exhibit No. 3 on
Iine 17. An accounting entry was made to reduce the
pension deferral balancing account by $16,5L2,853 with an
effective date of December 31, 2073, to ref]ect this
benefit.
o.How does the Company propose to a.l-Iocate the
$1,602,043 revenue sharing to customer classes?
A.The Company proposes to al-l-ocate the
$7,602,043 revenue sharing as a rate reduction to customer
classes based on each class's proportional share of the
forecasted base revenues for the June t, 201,4, through May
31, 2015, shari-ng period. This is the same methodology
used to allocate the revenue sharing in 2011, and 20L2.
o.What is the impact of al1ocating the proposed
rate reduction to customer classes proportionally to base
revenues ?
TATUM, Dr 20
Idaho Power Company
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A.As displayed in column G of Exhj-bit No. 4,
each customer class receives a decrease of approximately
0 .7 6 percent rel-ative to current base revenues.
o.How does the Company propose to j-nclude the
class-allocated revenue sharing benefits in rates?
A.With the exception of the Special Contracts
for Micron, the U.S. Department of Energy, and J.R.
Simplot, Inc. ("Special Contracts"), the Company proposes
to include the class-allocated revenue sharing benefits as
an offset to the 2074 PCA rates effective June 7, 2014,
through May 31, 20L5r ds detailed in this case by Mr. Scott
Wright. Column E of Exhibit No. 4 details the proposed
class-specific revenue sharing rates I have provided to Mr.
Wright to be included as an offset in the 2014 PCA rates.
o.What is the Company's proposal for providing
revenue sharing benefits to its Specj-a1 Contracts?
A.Consistent with the methodology used to share
2017 and 20L2 revenues, the Company proposes to provide the
Special Contracts a flat dollar-per-month credit in twelve
equal portions to serve as an offset to monthly invoj-ces
bil-Ied for June 2074 through May 2015.
V. PCA FORECAST
O. How does the Company's forecast of NPSE for
the 2074-201-5 PCA compare to the forecast in last year's
PCA?
TATUM, Dr 27
Idaho Power Company
1 A. The PCA Forecast on a total- system
2 the 20L4-20L5 PCA Year is $330,026,256, which is
3 $70,52L,190 higher than last year's PCA Forecast
4 $319,505,066. Table 3 presents a comparison of
5 PCA Forecast to last year's PCA Forecast by PCA
6 on a total- system basis.
7 Table 3. PCA Forecast Conparison:
basis for
of
this year'
component
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a. What are the mai-n factors contributing to the
increase in the PCA Forecast this year?
A. As can be seen in Table 3, Coal and Gas
production costs are expected to increase from l-ast year's
forecast by a combj-ned $10.9 mil-l-ion. That increase is
expected to be offset by decreases in Water for Power
expense and Third Party Transmission expense as wel-l- as an
TATUM, Dr 22
Idaho Power Company
Table 3: PCA Forecast Comparison (TotalSvstem-Levell
20L3-20,4
Forecast
20t4-20t5
Forecast Difference
Coal
Water for Power
Gas
Non-PURPA
3rd Party Transmission
Hoku First Block
Surplus Sales
L69,424,879
1,751,000
73,941,673
61,996,853
6,645,775
(126,166,913)
3,473,487
(603,374t.
7,405,609
2L,9L6,319
(46,610)
(27,656,7441
165,951,392
2,354,374
56,536,064
40,080,534
6,692,395
(98,510,159)
Net 95% accounts s 183,104,580 5 t87,593,267 5 4,488,687
PURPA
Demand Response lncentive
sSs134,L42,386
8,290,603
2,41O,860
3,62t,643
L3L,73t,526
4,669,950
100% accounts s 135,400,486 5 t42,432,999 s 6,032,503
Total PCA Forecast s 3t9,505,066 5 330,026,256 s 10,521,190
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increase in net Surplus Sales. The combined increase j-n
the expense categories under which Idaho Power is all-owed
95 percent recovery of deviations from base level NPSE is
approximateJ-y $4. 5 mj-ll-ion.
PURPA and Demand Response Incentive expenses are
expense categories under which Idaho Power is allowed 100
percent recovery of deviations from base l-eveI NPSE. These
two expense categories combined account for almost 60
percent of the increase over last year's forecast or
approximately $6. 0 million.
o.What is driving the increase in Demand
Response Incentive expenses?
A.The increase is due to'increased incentive
payments assocj-ated with the A/C Cool Credit and Irrigation
Peak Rewards programs that wil-I be operational again in
201,4 as a result of the settlement agreement approved by
Order No. 32923. Based on enrollment as of April J, 20L4,
fdaho Power expects 392 megawatts of demand response load
reduction at the generation level- for the 2014 season.
O. Recent reports suggest near normal snow pack
for the basins above the Brownlee Reservoir. Based on the
status of this year's snow pack conditions, is Idaho Power
expecting near normal hydro production?
A. Unfortunately, no. The Company's expectation
for hydro production included in the March 2073 Operating
TATUM, Dr 23
Idaho Power Company
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PIan is not materially different from last year's hydro
production forecast. The Company is forecasting 6.9
mill-ion MWhs of hydro generation for the 2014-20!5 PCA
Year, nearly the same as last year's forecast of 6.8
million MWhs. The 3O-year average annuaf hydro generation
for f daho Power's system j-s approximately 8.0 mil-Iion MWhs
placing the 20L4-201-5 PCA forecast of hydro generation at
about 86 percent of the normal expectation. The 2074-2075
PCA hydro generation forecast is based on projected
Brownlee j-nflow volumes of 3.6 MAF for April through July
and 8.8 MAE for the PCA Year of April 20\4 through March
2015. The historical 3O-year averages for the same peri-ods
are 5.5 MAE and 13.1 MAF, respectively. The l-ower
anticipated hydro generation will contribute to increased
coal- and gas production costs and lower surplus sal-es
revenue as compared to normal- levels.
O. ff snowpack level-s in the basins above the
Brownlee Reservoj-r are at or near normal- level-s, then why
is the Company expecting lower than normal hydro
generation?
A. The hydro generation forecast for the 2014-
201,5 PCA Year is impacted primarily by the persistent dry
weather conditions that occurred during 201,3 and through
January 20L4. The impacts of these dry conditj-ons to the
TATUM, Dr 24
Idaho Power Company
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hydro generation forecast incl-ude significantly low
upstream reservoir levels, considerabl-e reductions in
irrigation returns impacting reach gains, and continued dry
soil conditions in parts of the Snake River Basin.
Boise
flows
this
Federal reservoj-rs in the Upper Snake, Payette, and
basins greatly impact the magnitude and timing of
to Idaho Power's hydro system. At the beginning of
water year, October L, 20t3, the major federal-
treservoirs above Brownlee were 38 percent of normal
storage. This carryover storage level- would rank as the
fifth lowest when compared to the \98\-2010 period. In
order to refill from the low carryover storage level, the
reservoirs would require significantly above normal
snowpack, measured in terms of snow water equivalent
('SWE"). When the upstream reservoirs fail- to refill,
Idaho Power, along with al-1 other downstream water users,
are likeIy to experlence bel-ow normal reservoir releases.
The l-ate season precipitation over the recent months has
greatly improved the forecast for projected releases from
upstream reservoir systems, but the inflow forecast remains
below normal. Detail regardlng these events and their
impact on the Company's forecast hydro generation is
presented on pages 2-4 of Exhibit No. 2.
TATUM, Dr 25
fdaho Power Company
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VI. IDAIIO POITER' S PCA MITIGATION ATTERNATI\IE
o.Did the Company eval-uate potential options to
mitigate the impact of this year's PCA on customer rates?
A.Yes. The Company be1ieves it woul-d be
appropriate for the Commission to consider allowing a one-
time transfer of an additional $16 million from the DSM
Rider balancinq account to offset this year's PCA. This
action woul-d result in a total- transfer of $20 million of
DSM Rider funds into this year's PCA.
o.
proposal?
What is the Company's rational-e for this
A.Idaho Power's current level- of DSM Rider
collection is four percent of base rate revenues or
approxl-mately $36 million annually. The June L, 2074, DSM
Rider balance is expected to be a surplus of about $12.2
million. DSM Rider-funded expenses are forecasted to be
approximately $20 million per year on average over the next
two years. Without the proposed one-time transfer, the DSM
Rider balance is forecasted to be a surplus of $26 mill-ion
by May 31, 2015, and Idaho Power expects to continue to
accumul-ate a surplus of energy efficiency funding in the
near-term. In order to mitj-gate the customer impact of the
requested PCA increase, Idaho Power is proposing a one-time
transfer of $16 million of surplus DSM Rider funds back to
customers through the PCA.
TATUM, DI 26
Idaho Power Company
O. How does the Company propose to allocate the
2 $16 million DSM Rider transfer to individual- customer
3 classes?
A. The Company proposes to all-ocate the $16
5 million DSM Rider transfer to individual customer classes
6 as a rate reduction based on each class's proportional
7 share of the forecasted base revenues for the June 7, 20L4,
8 through May 31, 2015, PCA collection period. This
9 allocation method will- ensure that each customer class
10 receives the PCA rate credit j-n a similar proportion to the
11 initial- DSM Rider collection.
72 O. What are the benefits assoclated with Idaho
13 Power's proposal for a transfer of surplus DSM Rider funds
L4 to offset this year's PCA?
15 A. In addition to providing immediate rate
16 reJ-ief, the Company believes that a one-time transfer of
l7 DSM Rider funds will help to manage the DSM Rider balance
18 in the near-term without impacting the longer-term l-eve1 of
19 funding provided by the DSM Rider.
20 O. What would be the impact to the DSM Rider
27 bal-ance if the Commission were to approve the Company's PCA
22 mitigation proposal?
23 A. A transfer of $20 mil-Iion in DSM Rider funds
24 to offset the PCA would bring the DSM Rider bal-ance to an
25 estimated surplus of $9.8 million at May 31, 2075. The
TATUM, Dr 21
Idaho Power Company
1 Company believes that customers woul-d prefer a rate credit
2 tn this year's PCA rather than Idaho Power holding on to
3 funds that are not expected to be used in the next few
4 years.
5 Q. You stated that the transfer of $20 million in
6 DSM Rider funds includes the $a million of DSM Rider funds
7 associated with the increase in base rate revenues
B effective June L, 20L4. Does the Company believe that the
9 $4 mil-lion transfer shou]d conti-nue in future PCAs?
10 A. Yes. fn order to maintain a "revenue neutral"
11 rate adjustment, the Company believes that it would be
72 appropriate to transfer $4 mil-l-j-on each year from the DSM
13 Rider balance to serve as an offset to the PCA until- the
L4 next general rate case.
15 O. How will the additional one-time transfer of
L6 $16 mil-Iion from DSM Rider funds to the PCA impact the
77 Company's energy efficiency activities?
18 A. A total- transfer of $20 million in surplus DSM
19 Rider funds wil-l- have no impact on existing or new energy
20 efficiency activities. Idaho Power will continue to offer
27 a ful-I portfolio of energy efficiency programs for al-l-
22 customer sectors. Regardl-ess of the DSM Rider's balance,
23 the Company is committed to energy efficiency j-nitiatives
24 and pursing al-l- cost-effective energy efficlency.
25
TATUM, DI 28
Idaho Power Company
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a. What impact will the total $20 mil-l-ion
transfer of DSM Rider funds have on the DSM Rider balancing
account in the near-term?
A.As I mentioned earlier, the DSM Rider balance
is expected to be approximately $72.2 million on June 7,
201,4. Even with the transfer of $20 million and forecasted
energy efficiency expenses, Idaho Power estimates the DSM
Rider balancing account wil-l- be in a collected status again
by September 2074. By managing the DSM Rider ba1ance
today, no changes to the level of DSM Rider fund col-l-ection
are being reconrmended at this time.
O. You indicated the DSM Rider balance will be a
deficit for three months, in June, July, and August 20L4.
Will customers pay an additional interest charge on the
deficit balance for those months?
A.No, not on a net basis. The current deposit
rate used to cal-culate the annual carrying charge on
deferred balances, which incl-udes both the DSM Rider
balancing account and the PCA, is one percent. Although
customers will pay interest on the DSM Rider deficit
bal-ance for three months, the DSM Rider funds transferred
to the PCA will reduce the amount of interest that would
accrue on the PCA balance by the same amount, resulting in
a net change of zero in the amount of interest customers
would pay.
TATUM, Dr 29
Idaho Power Company
1 Q. Has the Company shared its planned proposal to
2 Lransfer funds from the DSM Rider to offset this year's PCA
3 balance with external- stakehol-ders?
4 A. Yes. On Monday, March 71, 2014, fdaho Power
5 held a conference caII with its Energy Efficiency Advisory
6 Group (*EEAG") to inform EEAG members that the Company was
7 considering using DSM Rider funds to achieve a revenue
8 neutral implementation of the new base level NPSE and to
9 possibly mitigate the impact on customers of a PCA
10 increase. The Company also solicited feedback from the
11 EEAG members regarding the proposal as part of the call.
72 In this call-, the Company informed the EEAG that, if
13 the Commission approved Idaho Power's request to set a new
L4 level of net power supply expense, base rate revenue would
15 increase by approximately $100 mi11i-on, resulting in an
L6 additional $4 million (approximate) per year in DSM Rider
71 revenue (4 percent x $100 mil-Iion : $a million). In this
18 event, the Company planned to request authority to transfer
79 $+ mill-ion out of the DSM Rider balancing account and
20 provide that amount as a uniform rate credit in the 2074-
2L 2015 PCA, thus keeping the net power supply expense filing
22 revenue neutral- for customers.
23 The Company al-so shared with the EEAG that, if the
24 PCA was an j-ncrease, the Company was considering a one-time
25
TATUM, Dr 30
Idaho Power Company
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transfer of additional DSM Rider funds to the PCA, which
woul-d reduce the impact of the PCA on customers.
O. What was the overall- sentiment from the EEAG
members regardj-ng the transfer of funds from the DSM Rider
to mitigate the PCA balance?
A.Of the participating members who attended the
telephonic meeting, there were several clarifying questions
asked, some concerns expressed, as well as comments of
support. EEAG members also expressed gratitude for the
company bringing this concept to their attention and the
opportunity to discuss the issue.
O.What is the adjusted billed revenue impact
that would result from applying the Company's PCA
mitigation alternative?
A.Should the Commission wish to apply the
mitigation adjustment presented by the Company, this year's
net increase in billed revenue would be reduced from $27.L
mil-Iion to $11.1 million, as presented in Table 4 below.
The $11-.1 mi]lion represents an overal-l- increase of
approxJ-mately 1.0 percent over current billed revenue.
TATUM, Dr 31
Idaho Power Company
1
2
Table 4. Updated Bil1ed Revenue Comparison:
*For comparison purposes,20t3-20L4 PCA component amounts represent the Commission-
approved 2Ot3-20L4 PCA rate applied to the June 2014 through May 2015 sales forecast
O.Why should the Commisslon consider approving
the Company's mitigation alternative in this case?
ft is my bel-ief that when the Commission has
considered PCA mitigation in the past it has tried to
bal-ance the impact that any mitigation may have on the
financial heal-th of Idaho Power with a desire to maintain
falr rates and rate stabillty. The Company believes that
its mitigation proposal wou1d have no financial impact on
the Company and would al-so satisfy the Commission's desire
to maintain fair rates and rate stability. The Company's
proposed PCA mitigation al-ternative wou1d simply util-ize
surplus customer funds from the DSM Rider balancing account
to offset excess power costs in this year's PCA. Unlike
other PCA mitigation options consj-dered by the Commission
in the past, this approach would not defer any PCA
coll-ection to a subsequent period, but rather would use
TATUM, DI 32
Idaho Power Company
3
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Y
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20
A.
Table 4: Billed Revenue Comparison (!daho Jurisdictional Amounts)
2013-2014 PCA* 2014-2015 PCA Difference
PCA Forecast
PCA True-Up
Revenue Sharing
DSM Rider Transfer (Ongoing)
DSM Rider Transfer (One-time)
s111,959,107
54,886,285
17,276,203],
0
0
5zL,gL6,zL4
77,237,295
(7,602,043l,
(3,97O,276l'
(t6,o29,724!'
(s90,152,893)
22,345,009
(325,840)
(3,970,276l,
{.L6,O29,724],
PCA Total S159,579,189 s71,445,466 (s88,133,7241
Base NPSE Update 0 99,250,892 99,250,892
Total s159,579,189 Suo,6g6,357 Su,u7,168
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funds already col-lected from customers to offset currently
known costs.
VII. CONCLUSION
O. Please summarize the Company's request in this
case?
A. Idaho Power is requesting that the Commission
issue an Order that 1) approves the Company's cal-culation
of new base rates resultj-ng in approximately $99.3 million
of additional base rate recovery of net power supply
expense annually in compliance with Order No. 33000, 2)
approves the 2014-2075 PCA recovery amount of approximately
$87.5 million, as the measured deviation from newly
established base rates, resulting in a net j-ncrease j-n
annual billed revenue of approximately $27.1 mi-11ion, and
3) approves a one-tj-me PCA mitigation measure intended to
Iessen the impact of this year's PCA on customers by
utilizing an additional $16 mil-lion of surplus DSM Rider
funds to offset this year's PCA collection resulting j-n an
adjusted net increase of approximately $11.1 mill-ion to
become effective June L, 2014.
o.Has the Company prepared revised tariff
schedul-es that present the updated base rates and PCA rates
that would result from applying the Company's mitigation
alternative?
TATUM, Dr 33
Idaho Power Company
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A.Yes. Attachment 1 to the Application is
revised tariff schedules, in both clean and legislative
formats, specifying the proposed base rate and PCA rate
changes for providing el-ectric service to customers in the
state of Idaho with a net change of $11.1 mill-ion in total
bill-ed revenue to be collected during the 20!4-2075 PCA
Year.
O. Does this conclude your testimony?
A. Yes, it does.
TATUM, Dr 34
Idaho Power Company
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2B
STATE OF IDAHO
County of Ada
ATTESTATION OF TESTIMOIIY
aq
T, Timothy E. Tatum, having been duly sworn to
testify truthfully, and based upon my personal knowledge,
state the following:
f am employed by Idaho Power Company as a Senior
Manager in the Regulatory Affairs Department and am
competent to be a witness in this proceedi-ng.
I declare under penalty of perjury of the laws of
the state of Idaho that the foregoing pre-fil-ed testimony
and exhibits are true and correct to the best of my
information and belief.
DATED this 15th day of April, 20L4
SUBSCRIBED AND
April , 2074.
SWORN to before me this 15th day of
c for Idaho
Residing at:
My commissio
Timoth E. Tatum
S-1"^,Ad/*n expires: IJ-Jo -J-4
TATUM, DI 35
Idaho Power Company
4$ts'l tir
ea'
)13 6114
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
GASE NO. IPC.E.I4.O5
IDAHO POWER COMPANY
TATUM, DI
TESTIMONY
EXHIBIT NO, 1
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Exhibit No. 1
Case No. IPC-E-14-05
T. Tatum, IPC
Page 1 of 1
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BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
GASE NO. IPC-E-14-05
IDAHO POWER COMPANY
TATUM, DI
TESTIMONY
EXHIBIT NO.2
Date: April 11,2014
To: Tim Tatum, Cost of Service Manager
From: Philip DeVol, Resource Planning Leader
Subject: 2013-2014 Surplus Sales Forecast Compared to Actual
2014-2015 Surplus Sales Forecast
This memo is intended to address the variances between the 2013-2014 PCA forecast and the
actual amounts for both the hydro generation and surplus sales components of the PCA, and to
provide an explanation for the 2014-2015 PCA forecast.
2013-2014 Surplus Sales Forecast Gompared to Actual
The differences between forecasted and actualamounts are shown below.
Forecast Actual Variance
Hydro Generation (000s MWh)6,826 5,702 1,124
Surplus Sales (000s MWh)3,115 1,998 1,117
Surplus Sales (000s of dollars)98,510 66,785 31,725
Surplus Sales
Surplus sales were impacted primarily by lower hydro generation. Surplus sales were also
impacted by lower production at Langley Gulch power plant, particularly during October 2013
and March 2014. However, these sales were mostly offset by decreased Langley Gulch fuel
costs, resulting in a minimal overall impact to the PCA. The dollar variance (in thousands of
dollars) is shown by month in the table below. The graph below the table further demonstrates
the variance of forecasted MWh sales volume as compared to actual MWh sales volume by
month.
4rbt3 slm' 6t't Tl,,ra o-rt"''irll1"t*to1#"* rr-, Dtan tr,ot4 2r,,t4 rrmt4 rotarFoBei 6,054 6,64i1 39,f 911 1,040 9,935 12,21e 12,11A 6,361 10,24 11,171 15,420 98,510
&l8l 1.21 _!ll0 2.3ss 6.1b _5,21 9.126 7.1s2 9.811 10.814 JEJ!5vn{Ie (4611) (s,420) r,67 1,87 992 (3,s0s) (s,e88) (2,ee2l (910) (1,852) (4363) (1506) l31,12,5l
PrGCnt 3c -1ffi -ADi 268iA 153% 9596 -3596 49,1 -25fi -11X -L8,6 -37* -3& -32*
SurplusSales (MWh)
600,000
50o,000
400,000
300,000
200,000
100,000
s/2071 612073 7120L3 8/2013 9/2073 1O/2O13 1t/2O13 t2l20L3
-ActualSurplus
Sales - - Forecastsurplus Sales
Exhibit No. 2
Case No. IPC-E-14-05
T. Tatum, IPC
Page 1 of4
Two months requiring special explanation are October 2013 and March 2014. For both months,
the 2013-2014 PCA forecast included the full dispatch of Langley Gulch in support of surplus
sales. However, the plant ultimately was not dispatched in October 2013 due to required
maintenance and was not dispatched in March 2014 due to lower market prices. While surplus
sales for the two months were impacted by the lower than forecast production from Langley
Gulch, the impact on the overall PCA was minimal because of a corresponding decrease in
Langley Gulch fuel expense.
With the exception of October 20'13 and March 2014, the lower than forecast surplus sales are
primarily explained by a decline in hydro generation.
Hydro Generation
Actual hydro generation was lower than anticipated in almost every month and for the PCA year
was nearly 1.1 million MWh, or 16 percent, lower than forecast. Hydro generation is directly
related to Brownlee Reservoir inflow, which was also lower than forecast in nearly every month
and for the PCA year was 1.5 million acre-feet (MAF), or 16 percent, lower than forecast. The
following tables show hydro generation and Brownlee inflow by month.
,m' st2o13 ,tzots ,,*u"!iffll"';r:.?"'[%lll"lll#, *ro* Ltzou ztn, ilma rotar
Forecast 558 78L 686 5E 514 491 43L 4LZ 497 587 551 793 6,826
Actuar '-M. '-E@ 'J3 '-s '-w.'-jf.4 '-453 '-s '&'-3,5.'-3!f.' E9s s,loz
vailance ' Loz' 22L' 203' 19 ' 94' 6!' (zzl' ro' 55 t 162' rl-s' 98 L,rz4
Percentage -L8fA -28P6 -WA -4oA -ttri6 -f2P/o 5% -4oA -LL% -28,6 -21% -LTA -t6%
arn, st2n13 612013 rmB ,rrl'*i'ff,It.r:r$f' qx^, r2r2o.s ttzou ztzou yxn4 rotar
Forecat O.92 1.15 1.00 0.56 0.57 0.57 0.58 0.73 O.7L 0.68 O.74 1.09 9.42
Actual 0.66 0.86 0.63 0.45 0.48 0.60 0.68 0.54 0.53 0.62 0.77 O.gt 7.9L
variance (0.26) (0.2s) (0.37) (0.11) (0.0e) o.o2 (0.00) (0.08) (0.08) (0.07) (0.03) (0.1s) (1.s1)
Percentage -28A -E% -17/. -2CPA -16% 4% tr/o -Lt% -71% -lCA -4% -L4o/o -16%
201 4-201 5 Hydro Generation Forecast
The hydro generation forecast for the 2014-2015 PCA year is 6.9 million MWh. The hydro
generation forecast for the 2014-2015 PCA year is impacted primarily by the persistent dry
weather conditions that occurred during 2013 and through January 2014. The impacts of these
dry conditions to the hydro generation forecast include significantly low upstream reservoir
levels, considerable reductions in irrigation returns impacting reach gains, and continued dry soil
conditions in parts of the Snake River Basin. A discussion of these impacts follows.
Reservoir Levels
Federal reservoirs in the Upper Snake, Payette, and Boise basins greatly impact the magnitude
and timing of flows to ldaho Powe/s hydro system. ln a normal year, the company's hydro
system generates with flow releases from these reservoir systems associated with the
company's primary storage right in American Falls Reservoir, federal flow augmentation to aid
downstream salmon outmigration, and flood control. ln addition, ldaho Power currently has a
contract agreement in place to release water leased from the Shoshone-Bannock Tribal Water
Supply Bank. The volume of these releases is directly related to the amount of reservoir
storage.
Exhibit No. 2
Case No. IPC-E-14-05
T. Tatum, IPC
Page2 of 4
At the beginning of this water year, October 1, 2013, the major federal reservoirs above
Brownlee were at 38 percent of normal storage. This carryover storage levelwould rank as the
fifth lowest when compared to the 1981-2010 period. ln order to refill from the low carryover
storage level, the reservoirs would require significantly above normal snowpack, measured in
terms of snow water equivalent (SWE). When the upstream reservoirs fail to refill, ldaho Power,
along with all other downstream water users, risk below normal reservoir releases.
Precipitation during the snow accumulation months of November through January ranked the
15th lowest of the 119 years of record for the state of ldaho. The estimated weighted SWE
above Brownlee Reservoir on January 31,2014, was at 9.7 inches, or 72 percent of normal, and
major federal reservoirs above Brownlee were at 65 percent of normal storage. February and
March precipitation was normal or above normal for much of the region, improving the Brownlee
SWE to 22.2 inches, or 109 percent of normal, and major federal reservoir levels rose to 80
percent of normal storage. The table below shows the combined reservoir storage for the major
federal reservoirs above Brownlee and the estimated weighted SWE above Brownlee Reservoir
at three critical dates: the beginning of the water year, January 31,2014, and March 31,2014.
Reservoir Storage at Major
Reservoirc Above Brownlee SWE at Brownlee
Actual Norma! Percent of
(MAFI (MAF) Norma!
October L,2OL3 1.05 2.74 38%
January 3t,20t4 LM 3.73 65%
March 3t,20t4 3.45 4.30 Wo
Actual Normal Percent of
(inches) (inches) Normal
9.7 13.5 72%
22.2 20.3 LWo
This late season precipitation greatly improved the forecast for projected releases from
upstream reservoir systems, but the inflow forecast remains below normal. The PCA forecast
was prepared near the end of March and incorporated the latest information from ldaho Power's
own models, including the most current snowpack and soil conditions, projected upstream
reservoir releases, and forecasted irrigation demand. The March flow forecast included
upstream reservoir releases for all of the company's primary storage right at American Falls
Reservoir, 93 percent of federal flow augmentation for salmon outmigration, and 75 percent of
the full Shoshone-Bannock water lease. The March forecast also assumes no flood control
releases from the Upper Snake River basin past Milner Dam, since any additional water will be
captured by American Falls and Palisades Reservoirs. However, the forecast does include
some flood control releases from the Boise and Payette basins. The table below shows the
progression of the forecast assumptions over the course of the water year as compared to
normal water year assumptions.
Forecast Assumptions
(Percent of Normal)
Primary Flow Leased
Storage Augmentation Water
October t,20t3
January 31,20L4
March 31.,2OL4
L$U/o
LWo
two
3
650/0
47o/o
93%
2s%
25o/o
75o/o
Exhibit No. 2
Case No. IPC-E-14-05
T. Tatum, IPC
Page 3 of 4
Continued Dry Soil Gonditions and Decreased lrrigation Returns
Although the amount of precipitation that fell throughout the basin during February and March
2014 was significantly above average, the amount of precipitation from the beginning of the
water year in October remains below normal. This is most apparent in the southern tributaries
as well as the lower elevations throughout the basin. The impact of low overall precipitation is
that soil conditions throughout the Snake Basin remain low, affecting the forecasted amount of
subsurface flow and snowpack runoff entering the river system.
Due to the significantly dry conditions throughout the basin during the 2013 irrigation season,
irrigators more efficiently managed their water supplies to utilize less water. Growing seasons
were shortened, modifications to sprinkler heads were made to make systems more efficient,
and monitoring equipment was installed in some areas of the basin. The result to the hydro
generations forecast is that irrigation return flows back to the river during subsequent months
has been and is projected to continue to be greatly reduced. This reduction in irrigation return
flows is currently reflected in the 2014-2015 hydro generation forecast.
Exhibit No. 2
Case No. IPC-E-14-05
T. Tatum, IPC
Page 4 of 4
BEFORE THE
IDAHO PUBLIG UTILITIES COMMISSION
GASE NO. IPC-E-14-05
IDAHO POWER COMPANY
TATUM, DI
TESTIMONY
EXHIBIT NO.3
IDAHO POWER COTPANY
ADDITIO},IAL Ii'IVESTTiIEI{T TAX GREDIT ANALYSIS
For th. TFlv. toith. Endod D.comb.r 31, 20l3
r.. suffitARyoFREsuLrs...
RETURN ON YEAR.ENO COMMON EQUITY
EARNTNGS ON COMMON STOCK @ 9.50 ROE
EARNTNGS ON COMMON STOCK @ 10 ROE
EARNTNGS ON COMMON STOCK @ 'r0.50 ROE
ACTUAL YEAR.ENO RESULTS. AFTER ITC ADJUSTMENT:
INVESTMENT TAX CREDIT ADJUSTMENT
AOJUSTED EARNINGS ON COMMON STOCK
ADJUSTED COMMON EOUITY AT YEAR-END
ADJUSTED RETURN ON YEAR-ENO COMMON EQUITY
SYIIIjT IDAES
2,001.810,,428 2,781,135,627
SYSYEI IDAHO
September Allo€tions/Ratios
@
1,109,330 208
140 422 703
1,210,752,e11
762,4ri9,304
122,073,203
7,57'r,050
30,500,E23
56,176
65,218.600
(775,313)
9,91E,700
5.409.764
t.002.592.306
!q!g-r
95 0%
roaHo %
10
11
12 DEVELOPMENTOF NET INCOME
13
11
15
16
17
18
19
20
21
22
23
21
25
26
27
2A
29
30
3l
32
33
34
35
36
37
38
3S
40
41
42 ACTUAL YEAR-END RESULTS - EEFORE ITC ADJUSTMENT
13 EARNINGSON COMMON STOCK11 COMMON EOUITYAT YEAR ENO
RETAIL SALES REVENUES (lnci {49.1 Rev)
OTHER OPERATING REVENUES
TOTAL OPERATING REVENUES
OPERATING EXPENSES
OPERATION & MAINTENANCE EXPENSES
DEPRECIATION EXPENSE
AMORTIZATION OF LIMITEO TERM PLANT
TAXES OTHER THAN INCOME
REGULATORY OEBITS/CREOITS
PROVISION FOR OEFERREO INCOME TAXES
INVESTMENT TAX CREDIT ADJUSTMENT
FEDEML INCOME TAXES
STATE INCOME TAXES
TOTAL OPERATING EXPENSES
OPERATING INCOME
ADD: IERCOOPERATING INCOME
OPERATING INCOME BEFORE OTHER INCOME & OEDUCTIONS
AOO: AFUDC EQUITY
ADO: OTHER INCoME AND DEDUCTIoNS
INCOME BEFORE INTEREST CHARGES
LESS: INTEREST CHARGES
NET INCOME
852,279.026 812,821.840 DiectAssEn100,732.831 96 800,192 96.1%
953,0'11,E57 000.622,032
1,057,998,566 DirectAsson134.9,t0,560 96.1%
1,192,939,1 26
563,941,726 534,440,756
91 1 38,716 87,333,709
5.467.478 5 244.936
23242,609 21 610,259
42.132 046,297.181 44,562,002(524,128) (s02,605)
20,853,067 20 749,033
4.445,665 4,367,369
75.1.S04,,i49 717.E05.45E
'198,10r,/t08 191,E'16,57,t1,A21,703 4,616 496
202,935.111 196,433.070
9,{.8%
s5.E%
95.9%
93.0%
0.0%
96.3%
95.9%
99.5%
98.2%
722,582,911
1 16,976,6S3
7,262,886
24,111,508
0
62,771,262
o43,476)
I,E{19,210
5,102,902
952.530.032
2,t0,3s9.1S4
6.111,022
246,8't0,2't 6
11,212,250
3,266,289
264,31E,755
77,313,549
187,005,206
187,(x)5,208
t,666,708,489
11.22Yo
91.8%
95.6%
95.0%
93.0%
0.0%
96.3%
95.S%
99.5%
9E2%
95.6%
97.2%
ss.s% (L'r0)
07.2% (L 33)
s5.9% (L 10)
95.9% (L10)
2,t7,160,605
ss 6% _______lI-93,!39_
253,&r,a,e3,l
14,857,580
3,359,652
272,0E2.105
80,653,8,{5
't91,428,320
101.428,320
1 ,738,71 7.851
.t 1.01%
185.178.1S6
t73,E7't,785
tE2.505,374
45
46
17
4E
49
50
5l
52
53
54
55
56
57
56
59
60
6t
62
63
6,4
65
67
B8
69
70
71
72
737t
t54,337,308 (L44' 9.5%)
t66,670,Le (144 . 10%)
175,00,t,391 (14,(' 10.5%)
(31,877 ,237' (L4E-143) / 0-9.5%)
155,327.969
r,635,031,252
9.50%
PBpa.ed by: Kelley N@ on l-'14-'t,a
Revi*ed by: _
ADDITIONAL tTC ADJUSTMENT (Anoualized) lf L 54 is negatiw, then 0; if positive, then smaller of L5,{ or t25,000,000
IOAHO RETURil Oil COIlrOil EAUIY (Lln.,aB) >109t
IDAHO EARNINGS GREATER THAN IO% ROE BUT LESS THAN 10,5%
IDAHO RETURN Ot{ COIilOI EQUITY (Lin.48) >10.5%
INCREMENTAL IDAHO EARNINGS GREATER THAN 10,50% ROE
*321211
0
9,259,4S2 (Ls0-149y0-10%)
13,408,731 (143-150)41-10.5%)
ROE betwen'10%-10.5% -CUSTOMER SHARE - 50% (Reduc{ion to ratos)
ROE between 10%-10.5% -COMPANY SHARE - 50%
RoE greaterthan 10.5% (nqomental) - cusToMER SHARE - 75% (offset lo Pension balance)
ROE grcaterthan 10.5% (n@ment.l) -coMPANY SHARE - 25%3,352,163
22.68.223
Exhibit No. 3
Case No. IPC-E-14-05
T. Tatum, IPC
Page 1 of 1
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
GASE NO. !PC-E-14-05
IDAHO POWER COMPANY
TATUM, DI
TESTIMONY
EXHIBIT NO.4
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Exhibit No. 4
Case No. IPC-E-14-05
T. Tatum, IPC
Page 1 of 't
4:l - c\l (') \f lf, (o r- @ (,, P = S P = I P