20131101DIRECT T. Tatum.pdf

BEEORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION )oF rDAHO POWER COMPANY FOR )
AUTHORTTY TO ESTABLTSH A NEW BASE )
LEVEL OE NET POWER SUPPLY EXPENSE )
)
CASE NO.r PC-E-13-2 0
IDAHO POWER COMPANY
DIRECT TESTIMONY
OF
TIMOTHY E. TATUM
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O.Please state your name and business address.
A. My name is Timothy E. Tatum and my business
address is 7227 West Idaho Street, Boise, Idaho 83702.
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.
o.
A.
Please describe your educational background.
I have earned a Bachel-or of Business
Administration degree j-n Economics and a Master of Business
Administratj-on degree from Boise State University. I have
also attended electric utility ratemaking courses,
including "Practical- Skitts for The Changing Electrical
fndustryr " a course offered through New Mexj-co State
University's Center for Public Utilities, "Introduction to
Rate Design and Cost of Service Concepts and Techniques"
presented by Electric Utilities Consultants, Tnc., and
Edison Electric Institute's "Electric Rates Advanced
Course." Tn 20L2, I attended the "Utility Executive
Course" at the University of Idaho.
O. Please describe your work
Idaho Power.
A. I began my employment with
as a Customer Service Representative in
Customer Service Center where I handled
experience with
Idaho Power in 7996
the Company's
customer phone
TATUM, DI 1
Idaho Power Company
1 call-s and other customer-related transactions. In L999, T
2 began working in the Customer Account Management Center
3 where f was responsible for customer account maintenance in
4 the areas of bitling and metering.
In June of 2003, after seven years in customer
6 service, I began working as an Economic Analyst on the
7 Energy Efficiency Team. As an Economic Analyst, I was
8 responsible for ensuring that the demand-side management
9 ("DSM") expenses were accounted for properly, preparing and
10 reporting DSM program costs and activities to management
11 and various external stakeholders, conducting cost-benefit
72 analyses of DSM programs, and providing DSM ana1ysis
13 support for the Company's 2004 Integrated Resource Plan.
74 In August of 2004, T accepted a position as a
15 Regulatory Analyst in the Regulatory Affairs Department.
76 As a Regulatory Analyst, I provided support for the
71 Company's various regulatory acti-vities, including tariff
18 administration, regulatory ratemaking and compliance
!9 filings, and the development of various pricing strategies
20 and policies.
2t In August of 2006, I was promoted to Senior
22 Regulatory Analyst. As a Senior Regulatory Analyst, my
23 responsibilj-ties expanded to include the development of
24 complex financial studies to determine revenue recovery and
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TATUM, DI 2
Idaho Power Company
I pricing strategies, incl-uding the preparation of the
2 Company's cost-of-service studies.
3 In September of 2008, I was promoted to Manager of
4 Cost of Service and in April of 20Ll I was promoted to
5 Senior Manager of Cost of Service. As Senior Manager of
6 Cost of Servj-ce, I oversee the Company's cost-of-service
7 activj-ties such as power supply modeling, jurisdictional-
I separation studies, cJ-ass cost-of-service studies, and
9 marginal- cost studies.
10 O. What is the Company requesting in this
11 proceeding?
72 A. Idaho Power is requesting that the Idaho
13 Public Utilities Commission ("Commission") approve the
L4 Company's determination of new normalized or "base level"
15 net power supply expense (*NPSE") to be utilized 1) to
76 update base rates on June l, 20L4, and 2) as the basis for
77 quantifying the 2014/20L5 Power Cost Adjustment (*PCA")
18 rates that would also become effectj-ve June 1-, 20L4. If
L9 approved, the Company's proposed change in base level NPSE
20 woul-d have no net impact to the overal-I revenue collected
2L through customer rates and would al-so be "revenue neutral"
22 for aII cl-asses of Idaho customers.
23 O. If the overall revenue collected from each
24 customer class would not be affected by this application,
25 why is the Company makj-ng this filing?
TATUM, DI 3
Idaho Power Company
1 A. The Company's currently approved normalized
2 l-evel- NPSE included in base rates reflects a 2010
3 normalized condition. Most of the individual cost and
4 revenue components of NPSE have changed significantly and
5 permanently resulting in an overall increase in the
6 normalized l-evel of NPSE of approximately $100 million from
7 the 2070 normalized condition to the 20L3 normallzed
8 condition. Because these increased expenses are not
9 reflected in base rates, such ongoing and permanent costs
10 are instead currently being recovered through the PCA
l-l- annua11y. The Company bel-ieves that it is more appropriate
!2 for these ongoing and permanent power costs to be recovered
13 through base rates than through PCA rates. Therefore,
74 Idaho Power is proposing to remove the recovery of these
15 additional normalized NPSE from the PCA and instead collect
1,6 these ongoing NPSE through base rates.
:-.'l O. Has the Commission previously expressed
18 concern regarding the recovery of ongoing and permanent
L9 power costs in the PCA?
20 A. Yes. On page 1l- of Order No. 32821 regarding
27 the 2073/2074 PCA (Case No. IPC-E-13-10), the Commj-ssion
22 expressed concern about the level- of ongoing NPSE recovery
23 in the PCA:
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The danger of using the PCA as a costrecovery mechanism for more than the
current annual power cost fluctuatlon is
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plainly demonstrated here. The PCA wasnever intended for long term recovery of
costs that continue year to year. It wasimplemented to properly recover the
Company's annual fl-uctuation in power costs
and keep the customers from paying eithertoo little or too much of those costs.
Idaho Power believes its proposal in thls case is a
simple and effective way to address the Commission's
concerns regarding the PCA and would restore the PCA to its
intended purpose with no impact to customers' biIIs.
o.Please provide an overview of the Company's
case.
A.In this case, the Company wil-I provide current
computations of normalized NPSE utilizing methods
previously supported by the Commj-ssion that demonstrate
that the level of NPSE recovery in base rates is
significantly below the current normalized level of NPSE.
By utilizing an artlficially low normalized NPSEr drl
artificially high PCA rate must be approved year after
year. Periodic correction of the normalized NPSE in base
rates also corrects the PCA price signal-.
Mr. Scott Wright is the Company witness in this case
who presents the development of proposed base level- NPSE as
determined using the AURORAxmp model ("AURORA"). Mr.
Wright explains the methodology used to determine the
normalized NPSE and detail the changes to the modeling
inputs that have occurred since the last update.
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My testimony in this case wil-l- describe the
Company's request and the supporting rationale for that
request. I wiII also present the Company's proposed
implementation approach that wou1d result in no net change
to the annual revenue col-l-ected through customer rates.
Einally, my testimony will address what the Company
believes to be the appropriate regulatory treatment of
transmission wheeling revenue.
O. Please provide a summary of the sections
presented in your testj-mony.
A.My testimony contains five sections. The
first section provides the reguJ-atory background that l-ed
to the currentfy approved base level NPSE. In the second
section, I present the quantificatj-on of the Company's
updated base level NPSE based on a 20L3 calendar year
(*2013 Base Level NPSE") and describe the factors that
contrj-buted to changes from the currently approved base
level NPSE. The third section describes the Company's
proposed approach to implementation that would result in no
net change in annual revenue and would have no impact to
customer biIIs. The fourth section of my testimony
provi-des the Company' s rational-e f or making this request.
The final section of my testimony describes the Company's
view with regard to the appropriate regulatory treatment of
transmission wheeling revenue.
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O. Pl-ease provide an overview of the intent and
design of the PCA mechanism.
A.The PCA is a rate mechanism that quantifies
and tracks annual differences between actual NPSE and the
normal-ized or base level of NPSE recovered in the Company's
base rates for recovery or credit through an annual rate
change each June 1. The PCA mechanism utilizes a 12-month
test period of April through March and is composed of a
forecast component and a true-up component. The PCA
forecast is based on the Company's March Operating Pl-an and
represents the difference between the NPSE forecast from
the March Operating Pl-an and the base level- NPSE recovered
in the Company's base rates. The PCA true-up includes a
backward-looking tracking of differences between the prior
year's PCA forecast and actual NPSE incurred by the Company
during the prior PCA year. The PCA true-up contains a
second component that tracks the collection of the prior
year's true-up amount, referred to as the "true-up of the
true-up. "
I. BACKGROI'IID
O. Please provide an overview of the regulatory
background that led to the currently approved base level
NPSE.
A. In Case No. IPC-E-09-30, Order No. 30978, the
Commission approved a Settlement Stipulation that provided
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for an update of the Company's base level NPSE in 2010. In
compliance with Order No. 30978, the Company filed on
January L9, 2070, a request to update base leve1 NPSE using
a 2070 calendar-year test period (Case No. IPC-E-10-01).
On April 13, 2070, the Commission issued Order No. 37042
establishing the Company's base level NPSE at 5220,710,731
on a total system basis.
In Case No. IPC-E-11-08, Idaho Power's last general
rate case, the Commission issued Order No. 32426 on
December 30, 2077, approvj-ng a Settl-ement Stipulation
whereby the parties agreed to set base level NPSE at
$208,100,936 on a total system basis. This amount held all-
base level NPSE cost and revenue categories at the same
l-evels established in 2070 by Order No. 3L042, with the
addition of $23,921,466 in expected revenue from Hoku
Materials, Inc. ("Hoku") and $1,1,,252,265 rel-ated to demand
response program incentive payments. The net effect of
adding these two components was a reduction to base level
NPSE of $1,2, 669,20L.
On March 2, 20L2, Idaho Power f j-l-ed a request to
include the Langley Gulch Power Plant in rate base (Case
No. TPC-E-12-14). As part of its request, the Company
updated base l-eve1 NPSE pursuant to Order No. 29790 (Case
No. IPC-E-05-10) in which the Commission ordered that
future filings by the Company that result in the j-ncl-usion
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of plant j-nvestment in rate base reflect the associated
reduction J-n power supply costs in base rates. On June 29,
2072, the Commission issued Order No. 32585 establishing
the now current base level- NPSE of $199,993,178 on a total
system basis, a net reduction of $8r 107r 158 as compared to
the previously approved l-evel-. This newly established base
Ievel NPSE maintained the orj-ginaI 2070 l-oad and fuel cost
inputs in the AURORA modeling process with the exception of
the addition of Langley Gulch as a generation resource.
II. 2OL3 BASE I.E\IEL NPSE
O.lnlhat are the power cost and revenue
components that make up base l-evel- NPSE?
A.Base level NPSE is comprised of the following
Eederal Energy Regulatory Commission ("FERC") Accounts:
FERC Account 501, Fuel (coal); FERC Account 536, hlater for
Power; FERC Account 547, Euel- (gas); EERC Account 555,
Purchased Power,' FERC Account 565, Transmission of
Electricity by Others; FERC Account 442, Hoku Revenues
(first bl-ock energy only); and FERC Account 447, Sales for
Resale (typically referred to as surplus sales).
The NPSE component EERC Account 555 includes power
purchases under the Publ-ic Utility Regulatory Policies Act
of 1978 (*PURPA") and non-PURPA purchases. FERC Account
555 also inc1udes incentive payments the Company provides
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to customers for participating in any of its three demand
response programs.
O. What is the Company's determination of the
20L3 Base Level NPSE requested for approval in this
proceeding?
A. As quantified by Mr. Wright and presented in
his testimony, the 2013 Base Level- NPSE is $305.7 mil-lion
on a total system basis. This represents a change of
$105.7 mil-Iion as compared to the currently approved 2010
base level NPSE amount of $200.0 million.
O. Please summarize the main factors that
contributed to the increase in base level- NPSE since the
last update.
A.There are three
the increase in base level- NPSE
Iower market energy prices, 2)
anticipated Hoku revenues, and
purchases under PURPA.
main factors contrj-buting to
since the last update: 1)
the elimination of
3) increased energy
O. How do l-ower market prices impact the
current determination of base level NPSE?
A.Lower market prJ-ces impact the current
expectation of the normalized l-evel of surplus sal-es, which
serve to offset power supply expenses to the benefit of
customers. Lower market prices impact Idaho Power's
ability to economically dispatch its thermal generating
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units for surpJ-us sa1es. That is, when market energy
prices are near or below the dispatch price of the
Company's thermal- generators, it becomes uneconomical- to
operate the plants for surplus sales. During times when it
is economical to dispatch the thermal units for surplus
sal-es, lower market energy prices reduce the overall val-ue
of surplus sa1es.
O. What factors have contributed to lower
market energy prices since 20L0?
A. Lower natural- gas pri-ces and increased
level-s of surplus generation in the Pacific Northwest have
contrj-buted to Iower market energy prices in recent years.
o.What is the Company's expectation with
regard to revenue collection from Hoku?
A.Electric service to Hoku under its Special
Contract terminated on April 26, 2072. Neither Hoku nor
j-ts United States bankruptcy trustee has given the Company
any indication that it j-ntends to take service in the
foreseeable future; therefore, no Hoku first block revenue
and subsequently no Hoku load has been included in the
determination of the 2073 Base Level- NPSE.
O. What impact has increased energy purchases
under PURPA had on base level NPSE?
A. Growth in energy purchases under PURPA has
contributed significantly to the increase in NPSE in recent
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years. As described by Mr. Wright in his testimony, PURPA
generation has increased from 119 average megawatts ("aMW")
in 201,0 to an anticipated 245 aMW j-n 20L3r do increase of
726 aMW or more than double the generation in 2010. PURPA-
rel-ated energy purchases have increased by approximately
$71.0 mil-l-ion since 201.0. That represents a 113 percent
increase in the PURPA expense over the three-year period.
O.lnlere increased loads a factor that
contributed to the increase i-n base l-evel- NPSE?
A. No. As described by Mr. Wright in his
testimony, annual- normalj-zed l-oad for the 20L3 update to
base l-evel NPSE is projected to be 15.3 mil-l-lon megawatt-
hours ("MWh"), the same as the Ieve1 used in the
determination of the currently approved base level NPSE.
o.Have you prepared a detailed listing of the
differences that exist between the currently approved base
l-evel NPSE and the proposed 2073 Base Level NPSE?
A.Yes. The following Table 1 presents the
dj-fferences that exist on a total system basis between the
currently approved base l-evel NPSE and the proposed 2073
Base Level NPSE on a detalled component basis:
TATUM, Dr L2
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Tab1e 1. Systen-Level PCA Accounts:
FERC Account 20to Prooosed 2013 Difference
Account 501, Coal
Account 536, Water for Power
Account 547,Gas
Account 555, Non-PURPA
Account 565, Tra nsmission
Account 447, Surplus Sales
Account 442, Hoku Revenues
Base NPSE
5 L61,L92,744 S
L,g2g,640
5L,934,20t
45,510,093
g,262,OOO
1L24,9L6,L531
(23,92t,4661
Base NPSE
108,503,180 s
2,39O,597
33,367,563
62,606,593
5,455,955
(51,735,153)
(58,689,564)
55L,957
(18,566,638)
17,096,500
(2,906,0451
73,181,000
23,92L,466
Net 95% Accounts
Account 555, PURPA
125,890,059
62,85L,454
L6O,578,735
133,853,869
LL,252,265
34,6881676
7t,ooz,4t5
Account 555, DR lncentives L1,252,265
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Total
Table 1.
A.
5 L99,993,778 S 305,684,869 S 105,691,091
a. Pl-ease describe the information contained in
Table 1 presents a comparison of the
currently approved 2010 base l-evel NPSE and the proposed
20L3 Base Level NPSE by detailed FERC Account category on a
total- system basis. As can be seen on Tabl-e \, FERC
Account 501, Coal, representing the Company's normalized
coal fuel expense, is lower by approximately $58.7 mil-Iion.
FERC Account 536, Water for Power, representing the water
leases expense, has increased by $0.6 mil1ion. FERC
Account 547, Gas, representing natural gas fuel expense,
has decreased by approximately $18.6 mil-l-ion. EERC Account
555, Non-PURPA, representing market energy purchases and
power purchase agreements, increased by approxlmately $17.1
mil-l-ion. FERC Account 565, Transmission, representing
third-party transmissj-on expense, decreased by
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approximately $2. I mil-Iion.
Sa1es, representing revenue
FERC Account 447, Surplus
from the sal-e of surplus
energy, decreased by approximately $13.2 miIlion. EERC
Account 442, Hoku Revenues, representing anticipated first
block energy revenue from Hoku, decreased from $23.9
million to zero. EERC Account 555, PURPA, representing
energy purchases under PURPA, increased by $71.0 million.
EinalIy, FERC Account 555, Demand Response Incentives,
representing payments to customers participating in demand
response programs, remains unchanged.
O. In light of the recently filed settl-ement
agreement in Case No. IPC-E-13-14 ("Settlement Agreement")
that, Lf approved, will modify the leve1 of incentive
payments made to customers participating in the Company's
demand response programs, why is the Company not proposing
to update the base level amount of demand response
incentive payment recovery as part of this case?
A.The Company bel-ieves that the currently
approved base leve1 amount of demand response incentive
payment recovery of $11.3 mlI1ion wiII continue to be an
appropriate 1evel of recovery goj-ng forward, even in light
of the recently filed Settlement Agreement. Absent the
modj-fications to the incentive structure proposed in the
Settlement Agreement, the current level of demand response
recovery wou1d like1y have been below the anticipated l-evel-
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of related j-ncentive expense. However, under the
redesigned program incentive structure, the anticipated
Ievel of j-ncentive expense will more closely alj-gn with the
4 currently approved base level of recovery.
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III. IMPLEMEI{TI}IG A RE\TENT'E NEI'':[RAI RATE
o.If approved, how does the Company envision its
7 revenue neutral- update to base level- NPSE would occur?
A.To successfully implement the proposed revenue
9 neutral update to base 1evel NPSE, the Company i-s
10 requesting that the Commission issue an order by March 37,
11 201,4, approving Idaho Power's determination of the system-
t2 l-evel- 2013 Base Level- NPSE in the amount of $305,684,869.
13 Recej-ving an order by March 31, 20L4, will al1ow the
L4 Company time to compute the 2014/2075 PCA using the newly
15 established 2013 Base Level NPSE.
L6 On April 15, 20L4, Idaho Power will fil-e its annuaf
77 request to adjust its PCA rates and wil-l- request to
18 simul-taneously adjust base rates effective June I, 2014.
t9 The Company's PCA request would include a PCA determination
20 based upon a measurement of the forecast April 20L4 through
2L March 20L5 NPSE to the newly established 2013 Base Level-
22 NPSE. Because the 2073 Base Level NPSE will- be higher than
23 the current base level NPSE, the resulting proposed PCA
24 coll-ection amount wiII be l-ower by the Idaho jurisdictional-
25 share of the incremental base l-evel NPSE requested in this
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1 case, adjusted for PCA sharing. The Company will- also
2 request an equal and offsetting increase to base rates to
3 become effective on June t, 2074. In other words, base
4 rates would be increased in a manner that will- generate the
5 same Ievel of revenue that would have otherwise been
6 allowed for recovery through the PCA.
1 Q. V[hat is the Idaho jurisdictional share of the
8 $105.7 million difference in system-Ievel base NPSE?
A. Based upon the current energy-based allocation
10 used for PCA computational purposes of 95.53 percent, the
11 Idaho jurisdictional share of the $105.7 million difference
L2 in system-level base NPSE would be approximately $101.0
1-3 miIlion.
L4 0. Does the $101.0 million represent the increase
15 to Idaho jurisdictional- base rates that the Company plans
16 to request as part of the 2074/20L5 PCA filing?
71 A. No. The Company's proposal in this case
18 envisions a rate adjustment that is intended to maintain
L9 the same overall leve1 of revenue recovery from base rates
20 and the PCA in aggregate. In other words, the Company's
27 proposal is intended to be "revenue neutral." To achieve
22 this goal it wil-I be necessary to adjust the $101.0 mill-ion
23 difference in Idaho jurisdictj-onal base level NPSE to
24 reflect the 95/5 customer to Company sharing provision that
25 exj-sts in the PCA. With the exception of PURPA expenses
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and demand response incentive costs, the PCA allows the
Company to pass through to customers 95 percent of the
annual differences in actual NPSE as compared to the base
l-evel NPSE, whether positive or negative.
As can be seen on Tabl-e L, the total- system-level
difference 1n NPSE within the FERC 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
jurisdictional share of the $34.7 million difference or
$31.5 million ($34.7 million x 95.53% x 95.00%: $31.5
mil-Iion) . When the $31.5 mil-Iion of allowed recovery is
combined with 100 percent of the difference in the fdaho
jurisdictional share of FERC Account 555, PURPA, of $67.8
million ($71.0 million x 95.53% $67.8 mil]ion) , the total-
al-Iowed recovery under the PCA would be $99.3 mill-ion.
Therefore, the Company's proposal would result in an
increase to base rates of approximately $99.3 million,
which includes a $1.7 million reduction to the total
difference in Idaho jurisdictional base 1evel NPSE of
$101.0 mil1ion. This $1.7 mj-Ilion "PCA shari-ng adjustment"
would continue to be reflected in base rates until the
Company files its next general- rate case or it is otherwise
adjusted by Commission Order.
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o.How does the Company propose to allocate the
$99.3 million base rate increase to each customer cl-ass?
A.The Company proposes to use the same energy
allocati-on basis that woul-d exist under the PCA to
apportion the approximately $99.3 million base rate
increase to each customer class; that is, in proportion to
each class's annual energy consumption. By using the same
energy all-ocation basis applied in next year's PCA filing,
each customer cl-ass will contribute exactly the same amount
of revenue to offset NPSE that would exist under the PCA
collectj-on. Exhibit No. 2 demonstrates that the Company's
proposal would result in no change to the total amount of
revenue by customer cl-ass from base rates and the PCA, j-n
aggregate. For il-lustrative purposes, Exhibit No. 2 has
been prepared utilizing the currentl-y approved revenue from
base rates and revenue from the 2073/20f4 PCA. As can be
seen on Exhibit No. 2, the Company's proposal would result
in an increase to base rate revenue of $99.3 mi-Ilion and an
equal and offsetting reduction j-n PCA revenue.
o.Are there other components of the PCA that
shoul-d be adjusted as part of this case?
A.Yes. The Load Change Adjustment Rate (*LCAR")
should be updated effective June L, 2074, to reflect the
incremental change in base level NPSE col-Iected through
base rates.
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o.Have you quantified an updated LCAR to become
effective June 7, 201-4?
A. Yes. By applying the methodology established
by Commission Order No. 32206 in Case No. GNR-E-10-03, the
LCAR should be increased from the current level of $1,1.64
per MWh to $24.34 per MWh.
o.Have you prepared an exhibit that details the
derivation of the updated LCAR?
A. Yes. Exhibit No. 3 details the derivati-on of
the updated LCAR amount of $24.34 per MWh. As can be seen
on Exhibit No. 3, the numerator of the LCAR has been
updated to reflect the new Ievel of NPSE to be coll-ected in
base rates.
IV. RATIONAI,E FOR UPDATING BASE LE\IEL NPSE
o.Why should the Commission approve the
Company's proposal to update base l-evel NPSE at this time?
A.As demonstrated by the Company's determination
of the 2013 Base Level NPSE, the PCA coll-ects approximately
$99.3 mil-Iion annually from ldaho customers for ongoing and
permanent NPSE. The Company believes that it is more
approprj-ate for these ongoing and permanent power costs to
be recovered through base rates than through PCA rates.
The collection of significant ongoing and permanent costs
through the PCA has compromised the intended symmetrical
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design of the PCA and has created counterintuitive
messaging on customers' bill-s.
O.How has the collection of significant ongoing
and permanent costs through the PCA compromised the
j-ntended symmetrical design of the PCA and created
counterintuitive messaging on customers' bills?
A.As mentioned earlier in my testimony, the PCA
j-s a rate mechanism that quantifies and tracks annual
differences between actual NPSE and the normalized level of
NPSE recovered in the Company's base rates. These
differences may exist as a resul-t of changes in hydro
condi-tions, fuel costs and/or market energy prices. Whil-e
fuel costs and market energy prices contribute to annual
fluctuations in NPSE, it is the availability of
hydroelectric generation that can have the most significant
impact on year-to-year dlfferences in NPSE. When the
Company's base level NPSE is reflective of current
normalized NPSE, one would expect that a better than
average water-year would result in a negative PCA or a
credit, and a worse than average water-year would result in
a positive PCA or a surcharge. Because the PCA is
col-lecting nearly $100 million in ongoing and permanent
NPSE, the annual PCA collection is likely to always be
positj-ve or a surcharge to customers, even in a good water-
year. This is not representative of the symmetrical
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mechanism the PCA was intended to be and has been a source
of confusi-on for customers.
O. Has the Commission ever approved an adjustment
to the level of normalized NPSE recovered in base rates
outside of a general rate case?
A.Yes. The currentl-y approved base level- NPSE
was originally established in 20L0 outside of a general
rate case j-n Case No. IPC-E-10-01. In that 20L0 case, the
Company fil-ed a request very similar to its request in this
case. The Commission ultimately issued Order No. 37042
establishing a new base l-evel of NPSE to be used in the
Company's 201,0/201,1 PCA filing. On April 15, 201,0, the
Company fil-ed Case No. IPC-E-10-12 requesting that the
Commission approve its 20L0/2011 PCA rate determination
based on the base leve1 NPSE approved by Order No. 31042 to
become effective June 1-, 20L0. In that same case, the
Company al-so requested an adjustment to base rates to
reflect the newly established base level NPSE, also to
become effective June L, 2010. The Company's request was
approved by Order No. 31093 on May 28, 201,0.
V. TRA}ISMISSION TNEEELING RE\TENT'E
O. Please provj-de an overvj-ew of issues related
to transmissj-on wheeling revenues that were raised in the
Company's 20L3/20L4 PCA, Case No. IPC-E-13-10.
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A.In the 2013/20t4 PCA filing, Case No. IPC-E-
13-10, the Commisslon invited the parties to comment on
whether the Company's PCA calcul-ation should only include
transmission expensesr ds has been the practice since 2009,
or should be expanded to include both transmission expenses
and revenues. Commission Staff and intervenors explained
that they believed there was a mismatch by only including
third-party transmission expense and not transmission
wheeling revenue. The Company subsequently filed reply
comments argui-ng to the contrary; however, the Commission
ultimately concluded that excl-udj-ng transmission wheeling
revenue differences from the PCA results in a regulatory
mismatch. In support of its conclusion, the Commissj-on
made the following findings:
We reject the Company's claim that a
mismatch will arise if the Company's PCA
includes transmission wheeling revenues
wi-thout their associ-ated costs. The
Company provided no detail about these
costs. We expect they are de minimis.
Order No. 3282L, page 13.
o.Vrlhat was the Commission's directive to the
revenue in OrderCompany regarding transmj-ssion wheelj-ng
No. 3282]-?
A. Order No. 32821 issued in the 20L3/2074 PCA
docket (Case No. IPC-E-13-10), directed the Company to
establ-ish a base level of transmission wheeling revenue in
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o.
A.
the next rate case so that deviations may be tracked
through the PCA. Order No. 3282L, page 13.
O. Does the Company believe that this case
provides the venue in which the Commission intended Idaho
Power to comply with its directlve regarding transmission
wheeling revenue?
A. No. Because the Company's proposal in this
case is intended to be revenue neutral, it would not be
appropri-ate to establj-sh a base l-evel amount for a new PCA
component as part of this case. The Company believes that
it was the Commission's intent that a new base level of
transmission wheeling revenue would be established as part
of a broader general rate case where the associated
transmission costs would al-so be addressed.
Notwj-thstanding this view, the Company believes that
it is appropriate as part of this case to provide the
Commission with additional detailed information that
demonstrates the significant regulatory mismatch that would
occur as a result of incl-udingr transmission wheelj-ng
revenues as an offset to third-party transmisslon expense
in the PCA.
What is transmission wheeling?
Transmissj-on wheeling refers to the transfer
of electric power by use of the transmission network of one
utility for the benefit of a transmission customer, such as
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o.
A.
another utility or an independent power generator.
Transmj-ssion wheeling is commonly referred to as
transmission service and is provided under a FERC-approved
Open Access Transmission Tariff (*OATT"). The OATT sets
out the terms and conditions of service and rates to
customers for transmissi-on services.
Idaho Power purchases transmission service from other
transmission owners 1) to move purchased power over their
system(s) into Idaho Power's system for service to
customers or 2) to move surplus sal-es off of the Idaho
Power system on to the transmission system(s) of other
transmissj-on owners. These expenses result from PCA-
related transacti-ons and are booked to EERC Account 565.
Such expenses have been included in the PCA since 2009
(Case No. IPC-E-09-11) .
What are third-party transmission expenses?
Third-party transmission expenses result when
What are transmissj-on wheeling revenues?
Transmissj-on wheeling revenues result when
O.
A.
third-partj-es buy capacity on Idaho Power's transmission
system to facil-ltate the movement of their power. These
third-party transmission customers are charged the OATT
rate and the revenues Idaho Power receives are booked to
FERC Account 456 and serve to offset the Company's
transmission-rel-ated costs or revenue requirement.
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O. What costs are being recovered through Idaho
Power's OATT formula rate?
A.The transmission formul-a rate outlined in
Attachment H of the OATT is designed to recover the cost of
owning, operating, and maintaining Idaho Power's
transmission facilities. The rate specifically excludes
expense accounts or plant items the FERC has deemed to be
generation related and not appropriately recovered in the
transmissj-on formula rate, even though those items are
properly recorded in the transmission function EERC
accounts.
O. Have you prepared any exhibits that detail the
FERC Accounts used in Idaho Power's transmission formula
rate?
A. Yes. Exhibit No. 4 is Attachment H "Total
Transmission Revenue Requirement" from Idaho Power's FERC-
approved OATT and Exhibit No. 5 details the current rate
calculati-on which sets forth the method used to calculate
the total amount of transmission costs to be recovered.
O. Please summarize the major cost components of
the transmission formula rate as presented in Exhibit No.
4.
A. The major cost components of the transmission
formula rate, dS described fully in Exhibit No. 4 section
3. 0 are as follows:
TATUM, Dr 25
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1) Transmission Rate Base (Transmission
Plant recorded in EERC Accounts 350 to 359) plus
transmission-related general and intangible plant,
transmission related working capital, less the
associated accumulated depreciation,
2) Return and associated income taxes on
rate base,
3) Direct transmissj-on expenses including
depreciation, operations and maintenance (FERC
Accounts 560 to 573 excl-uding EERC Accounts 561 and
555) and an allocated portion of qeneral and
administrative and general expenses, and
4) Prior year short-term and non-firm
transmission revenue credits.
O. Are third-party transmission expenses incurred
16 by the Company included in the cost components of the
11 transmi-ssion formula rate?
1B A. No. As depicted in Exhibit No. 4, the OATT
19 rate specifically excludes third-party transmission
20 expenses because they are not expenses related to Idaho
2L Power's transmission system.
22 O. What is the magnitude of the transmission-
23 rel-ated costs currently authorized for recovery through the
24 transmj-ssion rate in the Company's OATT?
25
TATUM, Dr 26
Idaho Power Company
1 A. As can be seen on l-ine 45 of Exhibit No. 5,
2 the transmission-related costs currently authorized for
3 recovery through the transmission formula rate in the
4 Company's OATT are approximately $118.2 million.
5 Q. Is any portion of the transmission-rel-ated
5 costs that transmission wheeling revenues are intended to
7 offset tracked through the PCA?
8 A. No. There is no portion of Company-owned
9 transmission-related costs of whj-ch transmissj-on wheeling
10 revenues are intended to recover that are tracked through
11 the PCA.
12 O. To what extent do transmissj-on wheeling
13 revenues from third-parties offset the Company's
74 transmission-related costs?
15 A. Tn 20L2, the Company received approximately
16 $21.1 mil-Iion in transmission wheeJ-J-ng revenues from third-
17 parties. Revenue from the Company's base rates is intended
18 to offset the remaining transmission-related costs.
79 O. Does the Company view its current level of
20 transmission-rel-ated costs offset by transmissi-on wheeling
2t revenue from thlrd-parties to be de minimis?
22 A. No. Transmission wheeling revenue from third-
23 parties offsets approximately $2L.I million of the
24 Company's total transmission-related costs of $118.2
25 milIion, or nearly 18 percent.
TATUM, Dr 27
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O. How are transmission wheeling revenues treated
in Idaho Power's base rates?
A.Retail customers receive the benefit of
transmission wheeling revenues as a revenue credit in base
rates. The test-year level of transmission wheeling
revenues is set at the time of a general rate case to
offset the test-year amount of transmission j-nvestment and
expenses in the Company's revenue requirement
determination. The test year leve1 of transmission
wheeli-ng revenues in base rates is reflective of the
transmission plant and expense information current at the
time of the test year.
o.Does the Company believe that a general rate
case is the appropriate proceeding to set the leve1 of
transmission wheeling revenues reflected in customer rates?
A.Yes. Base level transmiss j-on wheeling
revenues and base level transmission expenses shoul-d be
based on the same test period. Introducing transmission
wheeling revenues as an offset to base transmission
expenses outsj-de a general rate case creates an improper
matchj-ng of transmission wheeling revenues and transmission
expenses.
O. What is the Company's reconrmendatj-on with
regard to the future regulatory treatment of transmission
wheeling revenues?
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o.
A.
A. The Company believes it has provided evidence
to show that transmission wheeling revenues do not offset
third-party transmission expenses and should not be tracked
through the PCA. However, if the Commission is not swayed
by this evidence, then the Company recommends that
transmission wheeling revenues remain out of the PCA until
the Company files 1ts next general rate case, a time when
the Commission can approve an appropriate regulatory
treatment.
VI. CONCLUSION
o.
proceeding
Please summarize the Company's request in this
A.Idaho Power requests that the Commission
approve the Company's determination of new normalized or
base l-evel NPSE to be utilized l-) to update base rates on
June L, 2074 and 2) as the basis for quantifying the
2014/2015 PCA rates that would also become effective June
7, 20L4. If approved, the Company's proposed change in
base level NPSE woul-d have no net impact to the overal-l-
revenue collected through customer rates and would al-so be
"revenue neutral" for all classes of Idaho customers.
Does this conclude your testimony?
Yes, it does.
TATUM, Dr 29
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ATTESTATION OF TESTIIIONY
STATE OF IDAHO )
) ss.
County of Ada )
Tt Timothy E Tatum, having
testify truthfully, and based upon
state the following:
been duly sworn to
my personal knowledge,
I am employed by ldaho Power Company as a Senior
Manager in the Regulatory Affairs Department and am
competent to be a wi-tness 1n this proceeding.
f declare under penalty of perjury of the laws of
the state of Idaho that the foregoing pre-fiIed testimony
and exhibits are true and correct to the best of my
information and bel-ief .
DATED this 1st day of November, 2013.
imoth
SUBSCRIBED AND
November, 20L3.
SWORN to
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tt vJ
TATUM, Dr 30
Idaho Power Company
,€,2. Tatum
before me this 1st day of
1()T.{p,
r-a-t
&g3s1C
Notary PNotary Pufl)c for Idaho
Residinq "t- S+At, fuahaMy commission expiiEi: ,J-Jo€art'
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BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
cAsE NO. !PC-E-13-20
IDAHO POWER COMPANY
TATUM, DI
TESTIMONY
EXHIBIT NO.2
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Case No. IPC-E-1$20
T. Tatum, IPC
Page 1 of 1
FNoseoN6oP:SP :99=PP R9orizl
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
cAsE NO. IPG-E-13-20
IDAHO POWER COMPANY
TATUM, DI
TESTIMONY
EXHIBIT NO.3
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Page 1 of 1
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GASE NO. IPC-E-13-20
IDAHO POWER COMPANY
TATUM, DI
TESTIMONY
EXHIBIT NO.4
Idaho Power Company
FERC Electric Tariff
Open Access Transmission Tariff
ATTACIIMENT H
Total Transmission Revenue Requirement
Exhibit No.4
Case No. IPC-E-1&20
T. Tatum, IPC
Page 1 of18
3.8
Page I ofl
Version 0.0.0
Effective: August 5, 2010
Filed on : August 5, 2010
FERC Docket No. ERl0-2126-000
Idaho Power Company
FERC Electric Tariff
Open Access Transmission Tariff
Exhibit No.4
Case No. IPC-E-13-20
T. Tatum, IPC
Page 2 of 18
3.8.1
Page I of4
Version 0.0.0
Effective: August 5, 2010
Filed on : August 5, 2010
l.0Methodology
This formula sets forth the method that the Transmission Provider will use to determine its
annual Total Transmission Revenue Requirement. The Total Transmission Revenue
Requirement reflects the Transmission Provider's total cost to own, operate and maintain
the transmission facilities used for providing Open Access Transmission Service to
transmission customers under this Tariff.
The Total Transmission Revenue Requirement will be an annual formula rate calculation,
and will be based on the previous calendar year's FERC Form I data and the Transmission
Provider's books and records where greater detail is required. The Total Transmission
Revenue Requirement shall be effective for an initial term commencing June l, 2006 and
ending on September 30, 2007. Thereafter, the Total Transmission Revenue Requirement
shall be effective October 1, of each year, and ending September 30 of the following year.
1.1 Annual Informational Filing
1.1 .l On or before June I of each year or as soon as practical thereafterr, the
Transmission Provider shall post a draft Informational Filing on the
publicly accessible portion of its OASIS (the "Posting Date"). The posting
will notiff Transmission Customers of the date of the meeting to be held
pursuant to Section 1.1.3. If the posting is made prior to June, the
Transmission Provider shall provide notice via e-mail to the parties in
Docket No. ER06-787.
1.1.2 The draft Informational Filing shall include the following information:
(a) The rates and revenue requirements for transmission service under
Schedules 7 ,8 and 9 of this Tariff;
(b) The formularate calculation and all inputs thereto, in Microsoft Excel
spreadsheet format (inclusive of all formulas, references and linkages), in a
form similar to that which the Transmission Provider provided to
Transmission Customers and posted on its OASIS on May 22,2006;
(c)Allocation demand and capability data, in a form similar to that included
in the Statement BB workpapers filed on March 24,2006 in Docket No.
ER06-787-000, and a reconciliation of such data with the FERC Form 1
load data;
' Th"r" procedures shall become effective August l, 2OO7 ,and all other dates set out in Section I . I shall be
adjusted accordingly for 2007 only.
FERC Docket No. ERl0-2126-000
Idaho Power Company
FERC Electric Tariff
Open Access Transmission Tariff
Exhibit No.4
Case No. IPC-E-13-20
T. Tatum, IPC
Page 3 of 18
3.8.1
Page 2 of4
Version 0.0.0
Effective: August 5, 2010
Filed on : August 5, 2010
(d) The generator step-up substation (including jointly-owned generator step-
up substations) plant investment, depreciation reserve, depreciation
expense, and operation and maintenance expense;
(e) The property taxes directly assigned to fransmission and general plant, as
reflected in Section 3.7;
(0 Workpapers showing Account 454 revenues, which shall identify the types
of revenue sources and the amount of each source, describe the nafure of
each such source, and indicate the allocation ffeatment;
(g) Workpapers showing the Account 456 revenue included as revenue
credits, which shall contain annual data by customer, and which shall
identify the transmission-related revenues reported in Account 456 that are
included as revenue credits and those for which the transactions are
included in the rate divisor;
(h) Workpapers showing the calculation of the Long-Term Debt Component
included in Section 3.1.2.1;
(i) Workpapers showing the calculation of the Equity AFUDC component of
Transmission Depreciation and Amortization Expense included in Section
3.1.2.2;
0) Workpapers showing the calculation of the State Income Tax Rate used in
Section 3.1.2.2(b);
(k) The plant investment, depreciation reserve, depreciation expense and
operation and maintenance expense associated with the Transmission
Provider directly-assigned Interconnection Facilities excluded from
transmission rate base pursuant to Section 2.2.10 of the formula rate;
(l) The data used in the formula rate for Network Upgrade Prepayments and
Reimbursable Interest;
(m) A list of substantive changes to the Transmission Provider's accounting
policies, practices and procedures from those in effect for the calendar year
upon which the immediately preceding Informational Filing was based that
could affect the charges under the formula rate;
(n) A description of each item of new transmission plant installed during the
calendar year upon which the Informational Filing is based with a cost in
excess of $250,000; and
(o) For costs based on 2005 and 2006 data only, workpapers showing the
calculation of the revenue credit for Non-Firm Point-to-Point
Transmission Service and Short-Term Firm Point-to-Point Transmission
Service under the Tariff.
FERC Docket No. ERl0-2126-000
Idaho Power Company
FERC Electric Tariff
Open Access Transmission Tariff
3.8.1
Page 3 of4
Version 0.0.0
The above list does not preclude the Transmission Provider from including
in the draft Informational Filing additional information to that set forth
above.
1 . I .3 The Transmission Provider will hold an open meeting within 14 to 2l days
from the Posting Date to explain and clarify the draft Informational Filing.
A Transmission Customer and any parties in Docket No. ER06-787 may
make reasonable requests to the Transmission Provider for additional
information relating to the formula rate inputs from the Posting Date until
60 days thereafter. Such information requests will be limited to what is
necessary to determine if the Transmission Provider has properly applied
the formularate, and will not be directed to determining whether the
formula rate is just and reasonable. The Transmission Provider will
respond to such requests in a reasonable time frame, typically l0 to 15
business days, unless the Transmission Provider disagrees as to the
reasonableness of such requests, in which case the matter will be subject to
the Dispute Resolution Procedures set forth in Section 12 of the Tariff
(except that the requirements of Section 12.2 regarding senior
representative review will be eliminated and all time periods in Section
12.3 and 12.4 will be shortened by half). The Transmission Provider will
not be required to respond to any such contested request pending the
outcome of such procedures. The Transmission Customer and any parties
in Docket No. ER06-787 will submit any comments on the draft
Informational Filing to the Transmission Provider no later than 75 days
following the Posting Date.
1.1.4 Within 90 days following the Posting Date, the Transmission Provider shall
post the Informational Filing on the publicly accessible portion of its
OASIS and submit such filing to FERC. The Informational Filing will
include the information described in Section 1.1.2 and any modifications
thereto that the Transmission Provider made. The Transmission Provider
will advise the parties that submitted comments on the draft Informational
Filing of the comments that the Transmission Provider agrees with and
provide a reference to applicable resulting change(s). The Transmission
Provider will not propose any modifications to the formula rate or the
Tariff in the Informational Filing. The Informational Filing does not re-
open the formula rate for review or challenge, and shall not constifute arate
change filing under Section 205 of the Federal Power Act. If there are any
corrections to the Informational Filing after it is submitted to FERC, the
Transmission Provider shall post such corrections on the publicly
accessible portion of its OASIS and file the corrections with FERC.
Exhibit No.4
Case No. IPC-E-13-20
T. Tatum, IPC
Page 4 of 18
Effective : August 5, 2010
Filed on : August 5, 2010
FERC Docket No. ERl0-2126-000
Idaho Power Company
FERC Electric Tariff
Open Access Transmission Tariff
1.1.5 A Transmission Customer and any parties in Docket No. ER06-787 may
challenge the Informational Filing by filing a protest at FERC.
1.1.6 If the Transmission Provider files a revision to its FERC Form I that affects
the formula rate calculations, the Transmission Provider will post such
revisions on the publicly accessible portion of its OASIS. In addition, if the
Transmission Provider files revisions to its FERC Form I after it posts its
draft Informational Filing on the OASIS, the Transmission Provider will
post on the publicly accessible portion of its OASIS a list of such revisions
and the associated changes the revision has on the Informational Filing.
Exhibit No.4
Case No. IPC-E-13-20
T. Tatum, IPC
Page 5 of 18
3.8.1
Page 4 of4
Version 0.0.0
Effective: August 5, 2010
Filed on : August 5, 2010
FERC Docket No. ERl0-2126-000
Idaho Power Company
FERC Electric Tariff
Open Access Transmission Tariff
Exhibit No.4
Case No. IPC-E-13-20
T. Tatum, IPC
Page 6 of 18
3.8.2
Page I of4
Version 0.0.0
Effective: August 5, 2010
Filed on : August 5, 2010
2.0Definitions
Capitalized terms not otherwise defined in Section I of this Tariff have the following
definitions:
Allocation Factors
2.1.1 Transmission Wases and Salaries Allocation Factor shall equal the ratio of
the Transmission Provider's Transmission-related Direct Wages and
Salaries to the Transmission Provider's total direct wages and salaries
excluding administrative and general wages and salaries.
2.1.2 Plant Allocation Factor shall equal the ratio of the sum of total investment
in Transmission Plant, Transmission Related General Plant and
Transmission Related Intangible Plant to Total Plant in Service.
Terms
2.2.1 Adminisffative and General Expense shall equal the Transmission
Provider's expenses as recorded in FERC Account Nos. 920-935, excluding
FERC Account Nos. 924, 928 and 930.1, and EPRI dues recorded in
Account No. 930.2; provided, that for rates in effect after September 30,
2007, the Transmission Provider will make a Section 205 filing to
implement any increase in the expense for post-retirement benefits other
than pensions that results in an increase in the rate for Firm Point-to-Point
Transmission Service of more than $.05&W-month, as compared to the rate
for Firm Point-to-Point Transmission Service in effect for the immediately
preceding Service Year.
2.2.2 Amortization of Intangible Plant Expense shall equal the Transmission
Provider's balance in Account 404 - Amortization of Limited Term
Electric Plant.
2.2.3 Amortization of Investment Tax Credits shall equal the Transmission
Provider's credits as recorded in FERC Account No. 4l1.4.
2.2.4 Amortization of Other Utility Plant shall equal the Transmission Provider's
Amortization of Other Utility Plant balance in Account 1l l.
2.2.5 Depreciation Expense for Transmission Plant shall equal the Transmission
Provider's transmission expense as recorded in FERC Account No. 403
(excluding the portion of such depreciation expense associated with the
Transmission Provider's (l) solely- and jointly-owned generator step-up
facilities and (2) IPC Order 2003 Interconnection Facilities); provided, that
2.1
2.2
FERC Docket No. ERl0-2126-000
Idaho Power Company
FERC Electric Tariff
Open Access Transmission Tariff
3.8.2
Page2 of4
Version 0.0.0
if the depreciation rates used to calculate transmission expense as recorded
in FERC Account No. 403 differ from those set forth in Section 4.1, then,
solely for purposes of calculating Depreciation Expense for Transmission
Plant for use in this formula rate, the calculation of transmission expense as
recorded in FERC Account No. 403 shall be modified as necessary to
reflect the depreciation rates set forth in Section 4.1.
2.2.6 General Plant shall equal the Transmission Provider's gross plant balance
as recorded in FERC Account Nos. 389-399.
2.2.7 General Plant Depreciation Expense shall equal the Transmission
Provider's general plant depreciation expenses as recorded in FERC
Account No. 403; provided, that if the depreciation rates used to calculate
general plant expense as recorded in FERC Account No. 403 differ from
those set forth in Section 4.1, then, solely for purposes of calculating
Depreciation Expense for General Plant for use in this formula rate, the
calculation of general plant expense as recorded in FERC Account No. 403
shall be modified as necessary to reflect the depreciation rates set forth in
Section 4.1.
2.2.8 General Plant Depreciation Reserve shall equal the Transmission
Provider's general plant reserve balance as recorded in FERC Account No.
108 (excluding the portion of such reserve balance associated with the
Transmission Provider's asset retirement costs for general plant), except as
provided in Section 4.2.
2.2.9 Idaho Power Order 2003 Interconnection Facilities shall mean the
Transmission Provider's Interconnection Facilities, as that term is defined
in Attachment M of the Tariff, that were constructed on or after March 15,
2000, and that are associated with the Transmission Provider's generating
units, provided that such facilities do not comprise part of the Transmission
Provider's Transmission System, as that term is defined in Attachment M
of the Tariff.
2.2.l0Intangible Plant shall equal the Transmission Provider's plant balance as
recorded in FERC Account Nos. 301-303
2.2.11Network Upgrade Prepayments and Reimbursable Interest shall equal the
reimbursable prepayments made by an Interconnection Customer for a
Network Upgrade constructed under aLarge Generator Interconnection
Agreement and associated reimbursable interest earned by the
Interconnection Customer during construction of the Network Upgrade,
recorded in Account 252.
Exhibit No.4
Case No. IPC-E-13-20
T. Tatum, IPC
Page 7 of 18
Effective: August 5, 2010
Filed on : August 5, 2010
FERC Docket No. ERl0-2126-000
Idaho Power Company
FERC Electric Tariff
Open Access Transmission Tariff
3.8.2
Page 3 of4
Version 0.0.0
2.2.12 Other Fees and Charees shall equal the Transmission Provider's balance in
FERC Account Nos. 408.1 and 409.1 excluding Payroll Taxes, Property
Taxes the license tax on the production of electricity through the use of
water power assessed under Idaho Code $ 63-2701, franchise fees assessed
by municipalities in Oregon, fees assessed by the Idaho Public Utilities
Commission under Idaho Code $$ 6l-1001 through 6l-1008 for the costs
of such Commission, and fees assessed by the Public Utility Commission
of Oregon under Oregon Revised Statute $ 756.310 for the costs of such
Commission.
2.2.13 Other Rezulatory Assets/Liabilities - FAS 106 shall equal the net of the
Transmission Provider's FAS 106 balance as recorded in FERC Account
No. 182.3 and the FAS 106 balance as recorded in the Transmission
Provider's FERC Account No. 254.
2.2.14 Other Reeulatory Assetslliabilities - FAS 109 shall equal the net of the
Transmission Provider's FAS 109 balance in FERC Account No. 182.3 and
the FAS 109 balance as recorded in the Transmission Provider's FERC
Account No. 254 as adjusted for offsetting amounts related to FAS 109 in
accounts identified as accumulated deferred income taxes.
2.2.15 Payroll Taxes shall equal those payroll expenses as recorded in the
Transmission Provider's FERC Account Nos. 408.1 and 409.1, less the
payroll loading reversal.
2.2.16 Plant Held for Future Use shall equal the Transmission Provider's balance
in FERC Account No. 105.
2.2.17 Prepayments shall equal the Transmission Provider's prepayment balance
as recorded in FERC Account No. 165, excluding prepaid pension expense.
2.2.18 Property Insurance shall equal the Transmission Provider's expenses as
recorded in FERC Account No. 924.
2.2.19 Property Taxes shall equal the Transmission Provider's property tax
balance in FERC Accounts 408.1 and 409.1.
2.2.20 Total Accumulated Deferred Income Taxes shall equal the net of the
Transmission Provider's deferred tax balance as recorded in FERC Account
Nos. 281-283 and the Transmission Provider's deferred tax balance as
recorded in FERC Account No. 190, as adjusted for offsetting amounts
related to FAS 109 in accounts identified as regulatory assets or liabilities.
Exhibit No.4
Case No. IPC-E-13-20
T. Tatum, IPC
Page 8 of 18
Effective: August 5, 2010
Filed on : August 5, 2010
FERC Docket No. ERl0-2126-000
Idaho Power Company
FERC Electric Tariff
Open Access Transmission Tariff
Exhibit No.4
Case No. IPC-E-13-20
T. Tatum, IPC
Page 9 of 18
3.8.2
Page 4 of4
Version 0.0.0
Effective: August 5, 2010
Filed on : August 5,2010
2.2.21Total Materials and Suoplies shall equal the Transmission Provider's
balance in FERC Account Nos. 154 and 163.
2.2.22 Total Plant In Service shall equal the Transmission Provider's total gross
plant balance as recorded in FERC Account Nos. 301-399, excluding asset
retirement costs recorded in FERC Account Nos. 3 17 , 326, 337 ,347 ,359.1
and374.
2.2.23 Total Transmission Depreciation Reserve shall equal the Transmission
Provider's Transmission reserve balance as recorded in FERC Account No.
108, excluding the portion of such reserve balance associated with the
Transmission Provider's (1) solely- and jointly-owned generator step-up
facilities (2) IPC Order 2003 Interconnection Facilities and (3) asset
retirement costs for ffansmission plant, except as provided in Section 4.2.
2.2.24 Transmission Operation and Maintenance Expense shall equal:
o the Transmission Provider's expenses as recorded in FERC Account Nos.
560,562-564 and 566-573,less RTO development costs amortized to
these accounts, less
o the portion of such expense associated with the Transmission Provider's
solely- and jointly-owned generator step-up facilities (for which the
Transmission Provider shall have a separate work order or its functional
equivalent), less
o the product of (l) the Transmission Provider's expenses as recorded in
FERC Account Nos. 560, 562-564 and 566-573 artd (2) the ratio of (a) IPC
Order 2003 Interconnection Facilities and (b) Transmission Plant plus (i)
the portion of the Transmission Provider's gross plant balance associated
with the Transmission Provider's solely- and jointly-owned generator step-
up facilities and (ii) IPC Order 2003 Interconnection Facilities..
2.2.25 Transmission Plant shall equal the Transmission Provider's gross plant
balance as recorded in FERC Account Nos. 350-359, excluding the portion
of such gross plant balance associated with the Transmission Provider's (l)
solely- and jointly-owned generator step-up facilities and (2) IPC Order
2003 Interconnection Facilities.
2.2.26 Transmission-related Direct Wages and Salaries shall equal Transmission-
related direct wages and salaries multiplied by the ratio of (a) Transmission
Plant to (b) the sum of Transmission Plant and the gross plant balance
associated with the Transmission Provider's (l) solely- and jointly-owned
generator step-up facilities and (2) IPC Order 2003 Interconnection
Facilities.
FERC Docket No. ERl0-2126-000
Idaho Power Company
FERC Electric Tariff
Open Access Transmission Tariff
O
o
o
o
a
3.0 Total Transmission Revenue Requirement Calculation
The Total Transmission Revenue Requirement shall equal the sum of the Transmission
Provider's:
Refurn and Associated Income Taxes,
Transmission Depreciation Expense,
Transmission Related Amortization of Investment Tax Credits,
Transmission Operation and Maintenance Expense,
Reimbursable interest earned by an Interconnection Customer following
the Commercial Operation Date of the Interconnection Customer's
Generating Facility that the Transmission Provider reimburses to the
Interconnection Customer,
Transmission Related Administrative and General Expense,
Transmission Related Taxes Other than Income Taxes, and
Amortization of RTO Development Costs.
3.1 Return and Associated Income Taxes shall equal the product of the Transmission
Investment Base and the Cost of Capital Rate.
3.1.1 Transmission Investment Base will be the end of year balances of:
o Transmission Plant, less
o The unreimbursed portion of Network Upgrade Prepayments
and Reimbursable Interest, net of the accumulated depreciation
reserve associated with the Network Upgrades to which the Network
Upgrade Prepayments and Reimbursable Interest relate, plus
o Transmission Related General Plant, plus
o Transmission Related Intangible Plant, plus
o Transmission Related Plant Held for Future Use, less
o Transmission Related Depreciation and Amortization Reserve,
less
o Transmission Related Accumulated Deferred Taxes, plus
. Other Regulatory Assets/Liabilities, plus
o Transmission Prepayments, plus
o Transmission Related Materials and Supplies, plus
Exhibit No.4
Case No. IPC-E-13-20
T. Tatum, IPC
Page 10 of 18
3.8.3
Page I of6
Version 0.0.0
Effective: August 5, 2010
Filed on : August 5, 2010
a
a
O
FERC Docket No. ERl0-2126-000
Idaho Power Company
FERC Electric Tariff
Open Access Transmission Tariff
o Transmission Related Cash Working Capital, plus
o Unamortized RTO Development Costs.
3.l.l.l Transmission Plant will equal the balance of the Transmission
Provider's investment in Transmission Plant, as defined in Section
2.2.25.
3.1.1.2 Transmission Related General Plant shall equal the Transmission
Provider's balance of investment in General Plant multiplied by the
Transmission Wages and Salaries Allocation Factor.
3.1.1.3 Transmission Related Intangible Plant shall equal the Transmission
Provider's balance of investment in Intangible Plant multiplied by
the Transmission Wages and Salaries Allocation Factor.
3.1.1.4 Transmission Related Plant Held for Future Use shall equal the
Transmission Provider's balance of Transmission Plant Held for
Future Use, plus general Plant Held for Future Use multiplied by the
Transmission Wages and Salaries Allocation Factor.
3.1 . I .5 Transmission Related Depreciation and Amortization Reserve shall
equal the balance of the Transmission Provider's:
o Total Transmission Depreciation Reserve, plus
o Transmission Related General Plant Depreciation Reserve and the
Transmission Related Amortization of Other Utility Plant
(i) Transmission Related General Plant Depreciation Reserve
shall equal the product of General Plant Depreciation Reserve
and the Transmission Wages and Salaries Allocation Factor.
(ii) Transmission Related Amortization of Other Utility Plant shall
equal the product of Amortization of Other Utility Plant and
the Transmission Wages and Salaries Allocation Factor.
3.1.1.6 Transmission Related Accumulated Deferred Taxes shall equal the
Transmission Provider's electric balance of Total Accumulated
Deferred Income Taxes multiplied by the Plant Allocation Factor.
3.1.1.7 Transmission Related Other Regulatory Assets/Liabilities shall equal
the Transmission Provider's Other Regulatory Assets/Liabilities-
FAS 106 multiplied by the Transmission Wages and Salaries
Allocation Factor, plus the Transmission Provider's Other
Exhibit No.4
Case No. IPC-E-13-20
T. Tatum, IPC
Page11of18
3.8.3
Page 2 of6
Version 0.0.0
Effective: August 5, 2010
Filed on : August 5, 2010
FERC Docket No. ERl0-2126-000
Idaho Power Company
FERC Electric Tariff
Open Access Transmission Tariff
3.8.3
Page 3 of6
Version 0.0.0
Regulatory Assets/Liabilities-FAS 109 multiplied by the Plant
Allocation Factor.
3.1.1 .8 Transmission Prepayments shall equal Prepayments multiplied by
the Transmission Wages and Salaries Allocation Factor.
3.1.1.9 Transmission Related Materials and Supplies shall equal the
Transmission Provider's balance assigned to transmission as
recorded in FERC Account 154; plus the Transmission Related
portion of Account 154 assigned to General Plant, determined as the
product of the balance assigned to General Plant and the
Transmission Wages and Salaries Allocation Factor; plus the
Transmission Related portion of Account 163, determined as the
balance in Account 163 multiplied by the Plant Allocation Factor.
3.1.1.10 Transmission Related Cash Workine Capital shall be a 12.5o/o
allowance (45 daysl360 days) of the Transmission Provider's
Transmission Operation and Maintenance Expense and
Transmission Related Administrative and General Expense.
3.1.1.11 Unamortized RTO Development Costs shall be:
(a) $4.229.802 for the period May l. 2008 - September 30. 2008
(b) $3.306.936 for the period October l. 2008 - September 30. 2009
(c) $2.384.070 for the period October 1. 2009 - September 30. 2010
(d) $1.461.204 for the period October l. 2010 - September 30. 2011
(e) $538.338 for the period October l. 201I - September 30. 2012
(0 Commencing October 1.2012. Unamortized RTO Development
Costs shall be $0.
3.1.2 Cost of Capital Rate will equal the Transmission Provider's:
o Weighted Cost of Capital, plus
o Federal lncome Tax, plus
o State Income Tax.
3.1.2.1 Weighted Cost of Capital will be calculated based upon the capital
structure at the end of each year and will equal the sum of the Long-
term Debt Component, The Preferred Stock Component, and the
Return on Equity Component.
Exhibit No.4
Case No. IPC-E-13-20
T. Tatum, IPC
Page 12 of 18
Effective: August 5, 2010
Filed on : August 5,2010
FERC Docket No. ERl0-2126-000
Idaho Power Company
FERC Electric Tariff
Open Access Transmission Tariff
(i) The Lone-term Debt Component shall equal the product of the
actual weighted average embedded cost to maturity of the
Transmission Provider's long-term debt then outstanding and the
ratio that long-term debt is to the Transmission Provider's total
capital.
(ii) The Preferred Stock Component shall equal the product of the
actual weighted average embedded cost to maturity of the
Transmission Provider's preferred stock then outstanding and the
ratio that preferred stock is to the Transmission Provider's total
capital.
(iii) The Return on Equity Component shall equal the product of the
Transmission Provider's Return on Equity ("ROE") of 10.7o/o and
the ratio that common equity is to the Transmission Provider's total
capital. This ROE will remain effective until new ROE provisions
are made effective for the Transmission Provider.
3.1.2.2 Federal Income Tax shall equal
[(A + [(C+B) / D]) x (Fr)l divided by (1-Fr)
where;
FT is the Federal Income Tax Rate
is the sum of the preferred stock component and the return on
equity component, as determined in Sections 3.1.2.1(iD and (iii)
above.
is the Transmission Related Amortization of Investment Tax
Credits, as determined in Section 3.4 below.
is the Equity AFUDC component of Transmission Depreciation and
Amortization Expense, as defined in Section 3.2 and
is the Transmission Investment Base, as determined in Section
3.1.1, above.
3.1.2.3 State Income Tax shall equal
(A + [(C+B) / D] + Federal Income Tax) x (ST) divided by (1-ST)
where;
ST is the State Income Tax Rate,
A is the sum of the preferred stock component and return on equity
component determined in Sections 3.1.2.1 (ii) and (iii) above,
C
Exhibit No.4
Case No. IPC-E-13-20
T. Tatum, IPC
Page 13 of 18
3.8.3
Page 4 of6
Version 0.0.0
Effective: August 5, 2010
Filed on : August 5, 2010
FERC Docket No. ERl0-2126-000
Idaho Power Company
FERC Electric Tariff
Open Access Transmission Tariff
Exhibit No.4
Case No. IPC-E-13-20
T. Tatum, IPC
Page 14 of 18
3.8.3
Page 5 of6
Version 0.0.0
Effective: August 5, 201 0
Filed on : August 5, 2010
B is the Amortization of Investment Tax Credits as determined in
Section 3.4 below,
C is the equity AFUDC component of Transmission Depreciation and
Amortization Expense, as defined in Section 3.2,
D is the Transmission Investment Base, as determined in Section 3.1.1
above, and
Federal Income Tax is the rate determined in Sectiot3.l.2.2 above.
3.2 Transmission Depreciation and Amortization Expense shall equal the sum of the
Transmission Provider' s :
. Depreciation Expense for Transmission Plant, plus
. An allocation of General Plant Depreciation Expense calculated by
multiplying General Plant Depreciation expense by the Transmission
Wages and Salaries Allocation Factor, plus
. An allocation of Amortizationof Intangible Plant Expense calculated by
multiplying Amortization of Intangible Plant Expense by the Transmission
Wages and Salaries Allocation Factor.
Transmission Related Amortization of Investment Tax Credits shall equal the
Transmission Provider's electric Amortization of Investment Tax Credits
multiplied by the Plant Allocation Factor.
Transmission Operation and Maintenance Expense shall equal be as determined in
accordance with Section 2.2.24.
Transmission Related Administrative and General Expenses shall equal the sum of
the Transmission Provider's :
o Administrative and General Expenses multiplied by the Transmission
Wages and Salaries Allocation Factor,
. Property Insurance multiplied by the Plant Allocation Factor, and
. Expenses included in Account 928 related to FERC Assessments
multiplied by the Plant Allocation Factor, plus any other Federal and State
transmission related expenses or assessments in Account 928 plus specific
transmission related expenses included in Account 930.1
3.6 Transmission Related Taxes Other Than Income Taxes shall equal the sum of the
Transmission Provider' s :
Balance of Property Taxes direct assigned to transmission, multiplied by
the ratio of (a) Transmission Plant to (b) the sum of Transmission Plant
3.3
3.4
3.5
FERC Docket No. ER10-2126-000
Idaho Power Company
FERC Electric Tariff
Open Access Transmission Tariff
Exhibit No.4
Case No. IPC-E-13-20
T. Tatum, IPC
Page 15 of 18
3.8.3
Page 6 of6
Version 0.0.0
Effective: August 5, 2010
Filed on: August 5, 2010
and the gross balances associated with IPC Order 2003 Interconnection
Facilities and the Transmission Provider's solely- and jointly-owned
generator step-up facilities,
o An allocated amount of Property Taxes direct assigned to general plant
calculated by multiplying Property Taxes direct assigned to general plant
by the Transmission Wages and Salaries Allocation Factor,
o An allocated amount of Payroll Taxes calculated by multiplying Payroll
Taxes by the Transmission Wages and Salaries Allocation factor, and
. An allocated amount of Other Fees and Charges calculated by multiplying
Other Fees and Charges by the Plant Allocation Factor.
3.7 Amortization of RTO Development Costs shall equal$922,866 each year for the
five-year period May l, 2008 through April 30,2013. Commencing May 1,2013,
Amortization of RTO Development Costs shall be $0.
FERC Docket No. ERl0-2126-000
Idaho Power Company
FERC Electric Tariff
Open Access Transmission Tariff
4.0Depreciation Rates For Use In Formula Rate
4.1
3.8.4
Page I of2
Version 0. 1.0
Account Number Column A
Depreciation Rates
for determining
depreciation expense
throush Mav 3l-2012
Column B
Depreciation Rates for
determining depreciation
expense beginning June 1,
2012
3s0.20 t.st%1.39%
350.21 1.50%
352.00 1.68%1.84%
3s3.00 2.06 1.90%
3s4.00 1.96%r.70%
3ss.00 2.81%2.77%
356.00 1.92o/o 2.25
359.00 0.98%0.79%
390.1l 2.38%2.58%
390.12 2.24%t90%
390.20 258%2.15o/o
391.10 4.97%2.88%
39r.20 24.37o/o ll.l2o/o
391.201
391.2r t3.96%ll.22o/o
39t.2tt
392.10 6.23o/o 750%
392.30 8.62%r.73%
392.40 3.58%7.36%
392.50 1.49%3.s3%
392.60 3.69%4.14%
392.70 2.39%3.21%
392.90 t.99%2.10%
393.00 s.40%3.30%
394.00 434%4.13%
395.00 s39%4.29%
396.00 6.95%1.66%
397.10 6.160/o 4.25%
397.20 6.99%5.38%
397.30 8.36%5.31%
397.40 8.20%7.90%
398.00 9.57%5.20%
FERC Docket No. ERl0-2126-000 Exhibit No. 4 Effective: June l, 2012
Case No. tpC-E-13_20 Filed on : July 16,2o12
T. Tatum, IPC
Page 16 of 18
Idaho Power Company
FERC Electric Tariff
Open Access Transmission Tariff
Exhibit No.4
Case No. IPC-E-13-20
T. Tatum, IPC
Page 17 of 18
3.8.4
Page 2 of2
Version 0.1.0
Effective: Jvne l,2ol2
Filed on : July 16,2012
4.1.1 For service provided during the period October 1,2012 through September
30,2013 (for which the ffansmission revenue requirement is based on 201I
costs) the depreciation rates in column A will be used to determine
depreciation expense. For service provided during the period October l,
2013 through September 30, 2014 (for which the transmission revenue
requirement is based on20l2 costs), the depreciation rates in column A
will be used to determine depreciation expense for January 1,2012 through
May 31,2012, and the depreciation rates in column B will be used to
determine depreciation expense for June 1,2012 through December 31,
2012. For service provided during the period October 1,2014 through
September 30,2015 (for which the transmission revenue requirement is
based on20l3 costs), the depreciation rates in column B will be used to
determine depreciation expense.
4.2 In the event that the Idaho Public Utilities Commission (IPUC) issues a final order
approving changes to the depreciation rates set forth in Section 4.1, Idaho Power will file
such changed rates with the FERC pursuant to Section 205 of the Federal Power Act within
45 days of the issuance of such final order, to be made effective on the same date as such
rates are made effective by the IPUC. If as a result of FERC's review or for any other
reason, the depreciation rates approved by FERC for ratemaking purposes differ from those
approved by the IPUC, the inputs to the formula rate will be calculated using the FERC-
approved depreciation rates.
FERC Docket No. ERl0-2126-000
Idaho Power Company
FERC Electic Tariff
Open Access Transmission Tariff
5.0Network Upgrade Prepayments and Reimbursable Interest
Exhibit No.4
Case No. IPC-E-13-20
T. Tatum, IPC
Page 18 of 18
Idaho Power shall record Network Upgrade Prepayments and Reimbursable Interest in
Account 252. Such amounts shall be subtracted from Accornt252 as reimbursed.
Reimbursable interest earned by an Interconnection Customer (as defined in Attachment M
of the Tarif| during the construction of a Network Upgrade (as defined in Aftachment M
of the Tarif! under aLarge Generator Interconnection Agreement pursuant to Attachment
M of the Tariff shall be capitalized in Account 107 as AFUDC.
3.14.17.20
Page I ofl
Version 0.0.0
Effective: August 5, 2010
Filed on : August 5, 2010
FERC Docket No. ERl0-2126-000
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
cAsE NO. IPC-E-13-20
IDAHO POWER GOMPANY
TATUM, DI
TESTIMONY
EXHIBIT NO.5
IDAHO POWER COilIPANY
Transmbsion Gost of Servlce Rate Development
12 Months Ended 1213112012
IDAHO POWER COMPANY
RATE CALCULATION
TRANSMISSION RATE BASE1 Transmission Plant (excluding Asset Retirement Costs)
2
3
4
5
6
7
8I
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
Generator Step Up Facilities
LGI's
Account 252-Transmission (Net)
General Plant (excluding Asset Retirement Costs)
lntangible Plant
Transmission Plant Held For Future Use
General Plant Held For Future Use
Transmission Depreciation Reserve (Acct 108) (excluding Asset Retirement Costs)
Transmission Depreciation Reserve Generator Step-Ups
Transmission Depreciation Reserve LGI's
General Plant Depreciation Reserve (excluding Asset Retirement Costs)
Amortization of Utility Plant
ADIT Allocated to Trans
ADIT Allocated to Gen & lntang
Transmission Related PrepaymenG
Transmission Materials & Supplies
Transmission Cash Working Capital
Unamortized RTO Development Costs
Transmission Rate Base
RETURN AND ASSOCIATED INCOME TA(ES
Overall Retum
Composite lncome Tax (Federal and State)
Return and lncome Taxes
EXPENSES
Deprec Expense: Transmission
Deprec Expense: General Plant
Amortization Expense: lntangible Plant
Amort of ITC (Acct 411.4)
O&M Expense: Transmission
Less Account 561 (Load Dispatching)
Less: Account 565 (Transmission of Electricity By Others)
O&M Expense: A&G
Taxes Other than lncome:
Amortization of RTO Development Costs
lnterest Expense ( Network Upgrade Prepayments)
Transmission Expense
Gross Transmission Revenue Requirement
Transmission Revenue Credits
Net PTP Tranamisaion Revenue Requiremsnt
System Peak Demand - MW
Annual Rate $/kW per year
Monthly Rate $/kW per month
Weekly Rate $/kW per week
Daily Rate $/kW per day (Mon-Sat)
Daily Rate $/kW per day (Sunday)
Hourly Rate $/MW per hour (Peak)
Hourly Rate $/MW per hour (Off-Peak)
Source
FF1 p207 58(g) less 57(g)
Schedule 7
Schedule I
Schedule 9
Schedule 1
Schedule'l
FF1 p214 4d + 5d + 10d + 23d
Schedule 1
FFI p 219 25(b) less 108.'100 = 0
Schedule 7
Schedule 8
Schedule 1
Schedule 1
Schedule 1
Schedule 1
Schedule 1
Schedule 1
Schedule 1
OATT Attach H, 3.1.1.1 I (f)
Sum (1 ) Thru (1 9)
Schedule 6
Schedule 6
(2o)'((23)+(24))
Schedule 2
Schedule 2
Schedule 2
Schedule 2
Schedule 2
FF1 p321 84bto 92b
FFI p 321 96b
Schedule 2
Schedule 2
OATT Attach H, 3.7
Schedule 9
Sum (29) Thru (39)
(2s) + (40))
Schedule 4
Schedule 5
(45y((47r1000)
(4s) t 12
(4e) t 52
(51) / 6
(51) t 7
(4911000 / 4896
(4911000 / 8760
Anrount
930,229,983
(22,535,890)
(1,O41,',t47)
(1,332,405)
38,319,569
7,815,583
1,132,474
436,134
(285,425,52O)
10,617,990
161,813
(14,284,412)
(2,979,941)
(63,360,246)
(3,224,093)
1,647,569
13,712,116
4,970,O27
614,859,604
0.081 13
0.03496
71,379,051
17,663,01 1
1 ,349,157
971,740
(63/.,572)
28,521,5N
(2,743,844)
(6,294,410)
20,276,930
5,560,569
82.O23
64,r5r,*3
'136,131 ,195
(17,890,979)
$ 118,240,216
5,'186
22.80
1.9000
0.4385
0.0731
0.0626
4.66
2.60
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Exhibit No.5
Case No. IPC-E-13-20
T. Tatum, IPC
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