20100528McDougal Direct.pdf

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iow HAY 28 AM fl: 55
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE
APPLICATION OF ROCKY
MOUNTAIN POWER FOR
APPROVAL OF CHANGES TO ITS
ELECTRIC SERVICE SCHEDULES
AND A PRICE INCREASE OF $27.7
MILLION, OR APPROXIMATELY
13.7 PERCENT
)
) CASE NO. PAC-E-10-07
)
) Direct Testimony of Steven R. McDougal
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ROCKY MOUNTAIN POWER
CASE NO. PAC-E-10-07
May 2010
1 Q.
2
3 A.
Please state your name, business address and present position with Rocky
Mountain Power ("Company"), a division of PacifiCorp.
My name is Steven R. McDougal, and my business address is 201 South Main,
4 Suite2300, Salt Lake City, Utah, 84111. I am currently employed as the diector
5 of revenue requirements for the Company.
6 Qualifications
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Briefly describe your educational and professional background.
I received a Master of Accountancy from Brigham Young University with an
emphasis in Management Advisory Services in 1983 and a Bachelor of Science
degree in Accounting from Brigham Young University in 1982. In addition to my
form education, I have also attended varous educational, professional, and
electrc industry-related seminars. I have been employed by Rocky Mountain
Power or its predecessor companies since 1983. My experience at Rocky
Mountain Power includes varous positions within regulation, finance, resource
planning, and internal audit.
What are your responsibilties as director of revenue requirements?
My primar responsibilities include overseeing the calculation and reportng of
the Company's regulated earnings or revenue requirement, assuring that the inter-
jursdictional cost allocation methodology is correctly applied, and explaining
those calculations to regulators in the jurisdictions in which the Company
operates.
Have you testified in previous regulatory proceedings?
Yes. I have provided testimony before the Utah Public Service Commssion, the
McDougal, Di - 1
Rocky Mountain Power
1 Washington Utilities and Transportation Commssion, the California Public
2 Utilities Commssion, the Idaho Public Utilities Commssion, the Wyoming
3 Public Service Commssion, and the Utah State Tax Commssion.
4 Purpose and Overview of Testimony
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What is the purpose of your tetimony in this proceeding?
My diect testimony addresses the calculation of the Company's Idaho-allocated
revenue requirement and the revenue increase requested in the Company's filng.
I describe the major assumptions used by the Company to compute revenue
requirement and present the calculation of the requested price increase.
Specifically, I provide testimony on the following:
. The $27.7 millon retail revenue increase requested in this case
representing the increase over curent rates required for the Company to
recover the costs incurred to serve Idao customers;
. A description of the test period proposed in this case, including the
treatment of rate base and jursdictional loads;
. Inter-jursdictional allocations, including treatment of irgation demand
side management ("DSM") costs and special contracts with ancilar
services;
. Treatment of revenue from the sale of renewable energy credits ("RECs");
. The detailed results of operation for the test period, demonstrating that
under current rates the Company wil ear an overall return on equity
("ROE") in Idaho of 5.7 percent, which is significantly below the retu
on equity requested in this case and the curent authorized retu; and
McDougal, Di - 2
Rocky Mountain Power
1 . Calculation of the Load Growth Adjustment Rate ("LGAR") based on
2 costs in this filing for use in the EnergyCost Adjustment Mechanism
3 ("ECAM").
4 Revenue Increase
5 Q.
6 A.
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What revenue increase is the Company seeking in this case?
The Company's application supports an overall revenue increase of $27.7 millon,
or 13.7 percent. Exhibit No.1 provides a summar of the Company's Idao-
allocated results of operations for the test period. At curent rate levels, Rocky
Mountain Power wil ear an overall ROE in Idaho of 5.7 percent during the test
period. This retu is significantly less than the most recently approved ROE of
10.25 percent included in the stipulation approved by the Commssion in Case
No. PAC-E-07-05 (the "2007 general rate case"), and is less than the 10.6 percent
return recommended by Company witness Dr. Samuel C. Hadaway in this
proceeding.
Is the Company requesting the full $27.7 millon as a change to customer
rates at this time?
Yes. . The Company's curent application requests that rates for all customers,
including the tarf contract customers whose rate plans expire December 31,
2010, be adjusted effective Januar 1, 2011, to reflect customers' tre cost of
service based on the test period data.
McDougal, Di - 3
Rocky Mountain Power
1 Test Period
2 Q.
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What test period did the Company use to determine revenue requirement in
this case?
Revenue requirement in the Company's application is based on the historical
twelve-month period ending December 31,2009, adjusted for known and
measurable changes through December 31,2010 (the "Test Period").
Is the Test Period in this case consistent with test period used by the
Company in previous Idaho general rate cases?
The Test Period is prepared in a manner consistent with the Company's general
rate cases filed previously in Idaho. Later in my testimony I provide additional
support for major decisions made in the Test Period preparation, including
treatment of rate base, normalization of jurisdictional loads, and treatment of
renewable energy credit sales. I also describe the process employed by the
Company to prepare revenue requirement, and provide brief descriptions of each
normlizing adjustment made to revenue, net power costs, depreciation, taxes,
rate base, and operations and maintenance r'O&M") expense.
What over-riding principle guided the Company's development of the Test
Period in this case?
The prima objective in determning a test period is to develop normlized
results of operations which best reflect the' operating conditions during the time
the new rates wil be in effect ("rate effective period"). Multiple factors must be
considered to determne which test period best reflects these conditions.
Ultimately this is best accomplished with a forecast test period that coincides with
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Rocky Mountain Power
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the rate effective period. However, since this method has not been previously
allowed by the Commssion, the Company has relied on historical data with
normlizing adjustments made though December 2010 to reflect as closely as
possible the rate effective period.
Why is it important that the Test Period and the rate effective period be
aligned as closely as possible?
In an environment of rapidly expanding rate base and increasing net power costs a
test period that is not aligned with the rate effective period cannot adequately
capture the conditions that the Company wil experience while rates are in effect.
When a utility is in a significant investment cycle and experiencing other cost
increases, a pure historical test period constrains the utilty to chronically under-
recover the tre cost of service. The Company wil continue to place needed
assets into service during the rate effective period. These assets wil immediately
provide benefits to the Company's customers in Idao, but the Company wil no
longer be able to defer the cost of financing such assets in the form of allowance
for funds used during constrction ("AFUDC") and wil begin to incur
depreciation expense as soon as the asset is in service. Due to the current
regulatory framework in Idaho, rates cannot be adjusted to adequately recover the
cost of these assets until a future rate case whose historical test period captures
these plant additions. The ECAM mitigates the under recovery on increased fuel
costs related to new assets, but it can also work against the Company by passing
though the benefits of zero-cost energy from new wind facilties while the fixed
costs of these same facilities go unrecovered until they can be incoiporated into a
McDougal, Di - 5
Rocky Mountain Power
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general rate case.
1
What has the Company done in this case to better align the Test Period with
the rate effective period?
A significant cost drver in this application is the capital investment the Company
has incurred to serve its retail customers. The Company has calculated rate base
on an end-of-period basis, including actual rate base at December 31,2009, plus
major capital additions that wil be in service by December 31,2010, reflected at
the additions' full cost. The Company also proposed this treatment for rate base
in PAC-E-08-07 (the "2008 general rate case"). This treatment better aligns the
case with the level of investment that wil be used and useful durng the rate
effective period, and sets the customer rates at a more appropriate leveL. All of
the capital additions in this case wil be in service prior to the anticipated date of
the price change. Expense and revenue items related.to new capital additions,
including net power cost impacts, are annualized so that a full year of the cost or
benefit is included in the Test Period. Absent this treatment, customers would
receive the full benefit of capital additions such as the Dunlap wind facility
though the ECAM without paying the full capital cost of the resource.
Has the Company treated any revenue requirement components in this case
different from its past cases in Idaho?
Yes. The historical 2009 load has been normalized to remove abnormal operating
conditions that occurred. Jurisdictional load directly impacts thee main
components of the Company's revenue requirement: retail revenue, system net
1 The curent ECAM includes an adjustment mechanism designed to counteract this effect for select wind
facilities, but this mechanism wil expire once rates from this case are effective.
McDougal, Di - 6
Rocky Mountain Power
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power costs, and inter-jurisdictional allocation factors.
Why is the use of the Company's normalized load necessary in this cas?
As the Company examned the historical 2009 load, it found anomalous results
that, if left unchanged, would materially distort the revenue requirement
calculation for the Test Period. Durng 2009, sales to irgation customers and
Monsanto were significantly below levels experienced over the previous five
years. The table below ilustrates the dramatic reduction in energy sales for these
customers in 2009.
Table 1: Tariff Contract and Irrigatioii Sales
Year MWh
2004 1,969,495
1,855,452
1,954,176
1,996,,641
1,952,,495
lODS
2I.~e-:6
2(~07
2008
Average 20ü4 - 2008 1,945,651
20C'S 1,526,õ83
Test?erlcd 1,.9D8~la9:!J
The Company typically adjusts residential and commercial historical loads in
general rate cases to normalize varation due to atypical temperatures. However,
the shai reduction seen in tariff contract load in 2009 was not weather drven and
would not be normlized with the Company's traditional adjustment. Amore
comprehensive adjustment to loads is needed to reflect energy usage for these
customers at a level expected during the Test Period, as well as load across the
Company's system. Company witness Dr. Peter C. Eelkema's testimony explains
McDougal, Di - 7
Rocky Mountain Power
1 how the Company's loads were developed and provides support for the projected
2 energy usage by customers in Idaho during 2010.
3 Q.What is the impact of the anomalous historical load on the inter-
4 jurisdictional allocation factors?
5 A.The reduced load in Idaho during 2009 causes a notable drop in Idaho's System
Generation ("SG,,)2 allocation factor, which allocates the majority of system-wide6
7 costs among the Company's six jurisdictions. The following table shows Idaho's
8 SG factor since fiscal year 2004 for previous years compared to the factor
9 computed using 2009 historical loads and the Company's 2010 forecasted loads.
Table i: SG AUt)c.atiol1 Fador
Year
¡: 20M
Idaho %
:6.~3~9;S
Pt'200.5 £.46%
629%FY';2006
C¥ 2C-D6 6,31%
CY2007$6.JJ:5%
C'~f::2QOg 5.~8.i ~Q
CY2uD9 .s.c.£%
CY201u 5~51%
of .ç~ase N:Q:. PAC-E-C~5;-C:7
Note: FY denotes a fiscal year ending on March 31, and CY denotes
a calendar year ending December 31 of the given years.
10 This significant drop in the SG factor from one year to the next is not typical, and
11 highlights not only that the load in Idaho declined, but that it was inconsistent
12 with changes in other states' load, causing a reduction in the ratio of Idaho load
13 compared to system load. The Company does not expect the drop in Idao load
2 The SO factor measures each state's contnbution to system demand and energy. Demand is weighted
75% and energy is weighted 25%.
McDougal, Di - 8
Rocky Mountain Power
1 during 2009 to continue into 201 0, and setting rates in this case based on the 2009
2 trough would not be appropriate. Using the 2010 normalized load in this case
3 results in an SG factor more in line with historical trend in Idaho and is supported
4 by the Company's forecasting process that accounts for known changes in
5 customer load as explained by Dr. Eelkema.
6 Inter-Jurisdictional Allocation
7 Q.
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You previously mentioned the Revised Protocol. Has the Company applied
that allocation method in this case?
Yes. As approved by the Commssion in Case No.PAC-E-02-03, the Idaho
jurisdictional revenue requirement in this case is computed using the Revised
Protocol allocation methodology.
Please briefly describe the history of inter-jurisdictional alocations and the
Revised Protocol.
The first effort to achieve a multi-state agreement followed the merger of Pacific
Power and Light Company and Uta Power and Light in 1989. The PacifiCorp
Inter-JurisdictionalTask Force on Allocations ("PITA") was formed which
included Company personnel, regulatory agency representatives from each state
jurisdiction in which PacifiCoip serves (including Idaho), and other interested
paries. Two main issues were at the forefront of the PITA process: PacifiCorp's
integrated system operations and the equitable sharng of operational costs and
benefits.
The first agreement reached in March 1990 was called the Consensus
Allocation Method. Further methods were developed and implemented over time
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Rocky Mountain Power
1 to addrss emerging issues, including the PIT A Accord in Januar 1993 and the
2 Modified Accord in June 1997. In April 1998, Utah chose not to follow the PITA
3 agreements, adopting another method of allocation, the Rolled In method. After
4 Utah's deparre from the PITA agreements, other states began to question the
5 sustainabilty of the PITA process, and the group held its last meeting in April
6 2000.
7 On December 1, 2000, due in par to the breakdown of the PITA process,
8 the Company filed an application seeking approval to restrcture into six separate
9 state electric companies, a generation company, and a service company. As a
10 result of strong opposition to the Company's proposal, interested pares began
11 discussions about the need for a common method of allocating costs, benefits and
12 risks. On March 7, 2002, the Company fied applications in five states requesting
13 the initiation of an investigation of inter-jursdictional issues. Monthly multi-day
14 meetings ensued for the next 18 months. In September 2003, the Company
15 initiated proceedings in Utah, Oregon, Wyomig, and Idaho seeking ratification
16 of an Inter-Jursdictional Cost Allocation Protocol ("Protocol")?
17 Subsequent to the filing of the Protocol, substantial discussions occured
18 among interested paries in the context of what has been referred to as the MSP.
19 As a result of discussions among the MSP paries, the Company developed the
20 Revised Protocol which was ultimately approved in Uta, Oregon, Wyoming, and
21 Idaho and has been used (although not officially approved) in California.
3 The Company's Protocol fiings were docketed as 02-035-04 in Utah, UM 1050 in Oregon, 20000-EI-02-
183 in Wyoming, and PAC-E-02-3 in Idaho.
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Is there ongoing discussion related to the Revised Protocol involving the
Company's other jurisdictions?
Yes. The Revised Protocol commts the Company to continue the process
through at least annual meetings of the MSP Stading Commttee to consider
changed circumstances and possible amendments, and to resolve new inter-
jurisdictional issues should they arse. The MSP enjoys much broader
paricipation than the previous PIT A process. Standing Commttee members are
provided by the commssion staffs of Utah, Oregon, Idaho, and Wyoming, and
customer and other interest groups from various states paricipate in periodic
work groups and technical meetings. Terr Carlock of the Idaho Commssion
staff held the position of chaiierson of the Standing Commttee until it was
transitioned to Darell Zlomke of the Wyomig Commssion staff in 2010. More
than 20 years after the merger of Utah Power and Pacific Power, the relevant
issues remain largely the same: PacifiCoip's integrated system operations and the
equitable sharing of operational costs and benefits.
Based on those discussions, should the Revised Protocol continue to be used
in this case?
Yes. The MSP Standing Commttee serves the purpose of exploring arsing
issues related to the Revised Protocol along with possible solutions that may be
recommended for Commssion approvaL. Ongoing discussions may result in
modifications to the curently approved method, but until such time as any
proposed deviations are brought before the Commssion and approved for use,
revenue requirement should continue to be computed using the current Revised
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Protocol.
Does the Revised Protocol prescribe the treatment of state-specific demand
side management progrms?
Yes. As described in Section iv, Subpar C of the Revised Protocol, demand-side
management programs are assigned to the State Resources category. According
to the Revised Protocol:
"Costs associated with Demand-Side Management Programs wil
be assigned on a situs basis to the State in which the investment is
made. Benefits from these programs, in the form of reduced
consumption, wil be reflected through time in the Load-Based
Dynamic Allocation Factors."
U sing this allocation, there is consistency between the cost and benefit associated
with demand-side management programs as described below.
Have you treated the Idaho Irrigation Load Control Program as a demand-
side management program as contained in the Revised Protocol?
Yes. As described by Dr. Eelkema, the Company's loads used to compute the
inter-jursdictional allocation factors have been adjusted to reflect peak
curtailment during 2010. Consequently, Idaho's contrbution to the system
coincident peak and the resulting rate for allocating system-wide costs are
reduced. The program costs recovered through base rates, namely the incentive
payments made to paricipating customers, are situs assigned to Idaho. This is
consistent with the Company's filngs in previous Idaho rate cases using Revised
Protocol, as well as cases in the Company's other states utilzing the Revised
Protocol.
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Do any other jurisdictions served by PacifiCorp have similar programs, and
are those programs treated in a similar manner in this case?
Yes. The Company operates progras to control irgation and central air
conditioning load in its Utah service terrtory. Both of these programs are treated
in a similar manner as the Idaho irgation program, i.e. the Utah load used to
compute inter-jursdictional allocation factors is reduced to reflect program
paricipation and the program costs are diect assigned to Utah.
Does the Revised Protocol prescribe the treatment of special contracts with
ancilary services?
Yes. Appendix D of the Revised Protocol describes the treatment of special
contracts, including those with and without ancilar service contrct attrbutes.
Specifically, the Revised Protocol states:
"For allocation puiposes Special Contracts with Ancilar Service
Contract attrbutes are viewed as two transactions. PacifiCoip sells
the customer electrcity at the retail service rate and then buys the
electrcity back during the interrption period at the Ancilar
Service Contract rate. Loads of Special Contract customers wil be
included in all Load-Based Dynamc Allocation Factors. When
interrptions of a Special Contract customer's service occur, the
host jursdiction's Load-Based Dynamic Allocation Factors and
the retail service revenue are calculated as though the interrption
did not occur. Revenues received from Special Contract customer,
before any discounts for Customer Ancilar Service attrbutes of
the Special Contract, wil be assigned to the State where the
Special Contract customer is located. Discounts from tarff prices
provided for in Special Contracts that recognize the Customer
Ancilar Service Contract attributes of the Contract, and payments
to retail customers for Customer Ancilar Services wil be
allocated among States on the same basis as System Resources."
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Rocky Mountain Power
1 Q.Have you treated the Company's agreement with Monsanto as a special
2 contract with ancilary service contract attributes, as described in Appendix
3 D of the Revised Protocol?
4 A.Yes. In the Company's calculation of Idaho revenue requirement, Monsanto's
5 load is included in the load-based dynamic allocation factors, and the retail
6 revenue is calculated as if there is no interrption and is direct assigned to Idaho.
7 In addition, the cost of the ancilar services is allocated among all states on the
8 same basis as other system resources. The net power cost study sponsored by
9 Company witness Dr. Hui Shu includes the payment to Monsanto based on the
10 terms of the special contract for 2010.
11 REC Sales Revenue
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Please explain how revenue from the sale of RECs has been treated in this
case?
Revenue from the sale of renewable energy credits is treated as a revenue offset in
the revenue requirement computation. This case includes a total of $91.8 millon
in revenue from the sale of RECs for the Test Period. Adjustment 3.6 of Exhibit
No.2 provides the detailed calculation of revenue in the Test Period as well as the
inter-jursdictional allocation of such revenue. Adjustment 3.6 is made up of two
main components: (1) adjusting the total Company revenue to the level expected
during the Test Period; and (2) reallocating revenue to avoid assignig a portion
to states for which the Company is currently not sellng RECs in order to comply
with curent or futue requirements related to renewable energy.
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Rocky Mountain Power
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Please explain the computation of total REC sales revenue for the Test
Period.
To compute the level of REC revenue expected in the Test Period, the Company
must calculate the volume of wind-related RECs expected to be available for sale.
This calculatiòn begins with the total wind generation from the net power cost
study for which the Company has the right to sell RECs. Then, in order to
comply with current and futue restrctions related to renewable energy in
California and Oregon, the Company assumes that those states' allocated share of
RECs are banked, or go unsold, durng the Test Period. Next, based on market
conditions and Company policy designed to mitigate the risks described by
Company witness Mr. Stefan Bird, the Company assumes it wil be able to sell 75
percent of un-banked RECs. Sale transactions known at the time the rate case
was prepared, for both wind and non-wind-related RECs, are included at their
contractual volume and price. Known wind transactions are then compared to the
available wind generation after the adjustments described above, and any Test
Period RECs remaining available are assumed to be sold.
Please explain the reallocation of revenue to avoid asigning revenue to states
for which the Company is currently not sellng RECs.
Revenue from REC sales is initially allocated system-wide in the Company's
results. However, because the Company currently banks the share of RECs
allocated to Oregon and California, those states should not receive an allocation
of the revenue generated from the sale of the remaining RECs. To appropriately
allocate the sales revenue to the remaining four states, an adjustment is made to
McDougal, Di - 15
Rocky Mountain Power
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reverse Oregon and California share of the initial system allocation, and this
amount is spread ratably to the remaining states. Detas are provided on pages
3.6.1 and 3.6.2 in Exhibit No.2.
Is the Company proposing specifc changes to the ratemaking treatment for
REC sales in this application?
Yes. In addition to including the expected revenue from REC sales as a credit to
customers in this case, the Company believes actual REC sales revenue should be
tracked similar to net power costs and included as a component of the ECAM
calculation. The Company proposes that the current rate case serve to set the base
level of REC sales to which actual sales would be compared. Varations from the
base REC sales revenue would be deferred and recovered or refunded on a dollar
for dollar basis by way of subsequent ECAM proceedings. Company witness Mr.
13 Bird provides testimony describing the volatile nature of these transactions
14 supporting inclusion in the ECAM.
15 Idaho Results of Operations
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Please explain how the Company developed the revenue requirement for the
Test Period.
Revenue requirement preparation began with historical accounting informtion; in
this case the Company used the 12 months ended December 31,2009. The
revenue requirement components in that historical period were analyzed to
determne if an adjustment was warnted to reflect normal operating conditions.
The historical information was adjusted to recognize known, measurable and
anticipated events and to include previous Commssion-ordered adjustments.
McDougal, Di - 16
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Historical rate base is calculated using end-of-period balances as of
December 31,2009. Major capital additions planned to go into service by
December 31, 2010, are added based on the full cost expected to be placed into
service. In order to synchronize other components of the revenue requirement,
costs and benefits related to these major plant additions are included in revenue
requirement on an annualized level regardless of the date the resource wil go into
service. For example, the Dunlap I wind plant wil be placed into service in
November 2010. The capital cost of the project is included in this case at the full
amount, an annual level of operation and maintenance expense is added, and the
net power cost study assumes generation from that project was available for a full
12 months.
Please describe Exhibit No.2.
Exhibit No.2 is Rocky Mountain Power's Idaho results of operations report (the
"Report"). The historical period for the Report is the 12 months ended December
31,2009, which has been adjusted for known and measurable changes though
December 31,2010. The Report provides totals for revenue, expenses, net power
costs, depreciation, taxes, rate base and loads in the Test Period. The Report
presents operating results for the period in terms of both retu on rate base and
ROE.
Please describe how Exhibit No.2 is organized.
The Report is organized into sections marked with tabs as follows:
. Tab 1 Summar contains a summar of normalized Idaho-allocated
results of operations.
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Rocky Mountain Power
1 . Tab 2 Results of Operations details the Company's overall revenue
2 requirement, showing unadjusted costs for the year ended December
3 2009 and fully normalized results of operations for the Test Period by
4 FERC account.
5 . Tabs 3 through 8 provide supporting documentation for the
6 normalizing adjustments required to reflect on-going costs of the
7 Company. Each of these sections begins with a numerical summar
8 that identifies each adjustment made to the 2009 actual results and the
9 adjustment's impact on the case. Each column has a numerical
10 reference to a corresponding page in Exhibit No.2, which contains a
11 lead sheet showing the adjustedFERC account(s), allocation factor,
12 dollar amount and a brief description of the adjustment. The specific
13 adjustments included in each .of these tab sections are described in
14 more detail below.
15 . Tab 9 is Tab 2 restated with the Idaho allocation based on the Rolled
16 In allocation method.
17 . Tab 10 contains the calculation of the Revised Protocol allocation
18 factors.
19 Tab 3 - Revenue Adjustments
20 Q.Please describe the adjustments made to revenue in Tab 3.
21 A.Temperature Normalization (page 3.1)., This adjustment recalculates Idao
22 revenue based on temperature normlized historical load assuming average
23 temperatue patterns.
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Rocky Mountain Power
1 Revenue Normalization (page 3.2) - This adjustment normalizes base year
2 revenue by removing items that should not be included to determne retail rates,
3 such as credits from the Bonnevile Power Admnistration ("BPA") for the
4 Residential Exchange Program. The expense side of the BP A credit is removed in
5 adjustment 5.2.
6 Effective Price Change (page 3.3) - This adjustment reflects the $4.38 millon
7 revenue increase which became effective on April 18, 2009, in the 2008 general
8 rate case. This adjustment also normalizes the pro forma effects for the special
9 contract price changes effective Januar 1,2010 as determned in the 2007
10 general rate case.
11 Forecat Price Change (page 3.4) - This adjustment reflects the revenue effects
12 of using the normalized Idaho loads supported by Dr. Eelkema for the Test Period
13 ending December 2010.
14 SOi Emission Allowances (page 3.5) - Consistent with Case No. PAC-E-06-04,
15 this adjustment removes the sulfur dioxide ("SOi") sales occurrng prior to June
16 30,2009, and amortizes those sales over a 15-year period. SOi sales occurng
17 after June 30, 2009, are captured as par of the ECAM.
18 Green Tag Revenue or RECs (page 3.6) - In order to help meet jursdiction
19 specific renewable portfolio standards, a market for green tags or RECs is
20 developing where the tag or green traits of qualifying power production facilties
21 can be detached and sold separately from the power itself. Generally, wind, solar,
22 geothermal and some other resources qualify as renewable resources, although
23 each state may have a slightly different definition. Currently, California and
McDougal, Di - 19
Rocky Mountain Power
1 Oregon have renewable portolio standards that limit the Company's ability to sell
2 green tags. As I described earlier in my testimony, this adjustment adds into
3 results an incremental amount of 2010 REC revenues over and above the 2009
4 level, and correctly allocates the REC revenue among states to account for
5 baning in California and Oregon. The Company also proposes that REC
6 revenues be dealt with as par of the Company's ECAM proceeding due to the
7 volatilty described in the testimony of Mr. Bird.
8 Wheeling Revenue (page 3.7) - During 2009 there were various transactions
9 resulting in wheeling revenue that the Company does not expect to occur in the
10 Test Period. These transactions relate to varous prior period adjustments and
11 contract termnations. This adjustment also includes pro forma wheeling revenue
12 for the Test Period.
13 Tab 4 - O&M Adjustments
14 Q.Has the Company made considerable effort to control its operating costs?
15 A.Yes. As par of the Mid American Energy Holdings Company ("MEHC") merger
16 commtments in Case No. PAC-E-05-08, commtment 131, the Company agreed
17 to reduce its admnistrative and general expense below $222.8 milion annually,
18 adjusted for inflation. As shown in Exhibit No.2, Page 2.2, the Company's actual
19 December 2009 A&G level is $162.6 millon, far below the merger commtment.
McDougal, Di - 20
Rocky Mountain Power
1 Normalizing Adjustments
2 Q.
3
4 A.
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
Please describe the adjustments made to O&M expense in Tab 4 of Exhibit
No.2.
Miscellaneous General Expense (page 4.1) - This adjustment removes certain
miscellaneous expenses that should have been charged below-the-line to non-
regulated expenses. This adjustment also corrects the allocation of Utah related
sales tax refunds.
Wage & Employee Benefit Adjustments (page 4.2 and 4.3) - This adjustment
is used to compute labor-related costs for the Test Period. Labor-related costs are
computed by adjusting salares, incentives, benefits and costs associated with FAS
87 (pension), F AS 106 (post retirement benefits) and F AS 112 (post employment
benefits) for changes expected beyond the actual costs experienced in 2009. Page
4.3.4 is a numerical summary staing with actual labor costs in 2009 and
summarzing the adjustments made to reflect the Test Period level of expense.
This summry is followed by the detailed worksheets used to adjust the labor
costs forward to the Test Period.
The first step to adjust labor is to annualize salar increases that occurred
durng 2009. This was done by identifying actual wages by labor group by month
along with the date each labor group received wage increases. The next step is to
apply the wage increases through the end of the Test Period to the annualized
2009 salares. The Company used union contract agreements to escalate union
labor group wages, while increases for non-union and exempt employees were
based on actual increases. This calculation is detailed on pages 4.3.5 through
McDougal, Di - 21
Rocky Mountain Power
1 4.3.6. Payroll taxes were updated to captue the impact of the changes to
2 employee salaries.
3 An adjustment is also made to incentive compensation, pension expenses,
4 and.other employee benefit costs expected to be incured in 2010. The Company
5 utilzes an incentive compensation program as par of its philosophy of deliverig
6 market competitive pay structured in a manner that benefits customers with safe,
7 adequate and reliable electric service at a reasonable cost.
8 MEHCTransition Savings (page 4.4) - The Company elimiated many
9 positions in our labor force as a result of the MEHC transaction. These savings
10 were made possible by the payment of change-in-control severance, which is
11 curently being amortized over a three year period as authorized inCase Nos.
12 PAC-E-06-11 and PAC-E-07-05. Since the amortization wil end December 31,
13 2010, this adjustment removes the amortization from results.
14 Irrigation Load Control Program (page 4.5) - Incentive payments made to
15 Idaho customers participating in the irgation load control program were system
16 allocated in unadjusted data. This adjustment corrects that allocation and assigns
17 these costs directly to Idaho consistent with other DSM programs. This
18 adjustment also recognizes a $261,233 increase in total incentive payments based
19 on program paricipation in the Test Period. An offsetting adjustment was made
20 to reduce the jurisdictional load used to develop allocation factors to reflectload
21 paricipating in the program during the Test Period irgation season. This load
22 adjustment reduces Idaho load used to compute inter-jurisdictional allocation
23 factors and consequently the level of system-wide costs allocated to Idaho.
McDougal, Di - 22
Rocky Mountain Power
1 Details supporting the incremental adjustment are provided on pages 4.5.2 and
2 10.13.
3 Incremental Generation O&M (page 4.6) - This adjustment adds incremental
4 O&M expense for the High Plains, McFadden Ridge I, and the Dunlap I wind
5 generating plants, as well as the Dave Johnston coal plant scrubber, all of which
6 were placed into service durig 2009 or wil be durng the Test Period.
7 Consistent with the end-of-period rate base treatment, this adjustment includes a
8 full year of O&M for the Dave Johnston scrubber and the Dunlap I wind plant,
9 even though they wil be placed into service part way though the year. The net
10 power cost study sponsored by Company witness Dr; Shu also includes the full
11 year impact (cost or benefit) from these resources.
12 Remove Non Recurring Entries (page 4.7) - Varous accounting entries were
13 made during 2009 that were non-recurrng in nature or relate to a prior period.
14 This adjustment removes these items reducing total Company operating expense
15 by $1.3 millon.
16 MEHC Affliate Management Fee (page 4.8) - This adjustment complies with
17 the MEHC acquisition commtment 128, which states:
18 "MEHC and PacifiCoip wil hold customers haress for increases in
19 costs retained by PacifiCorp that were previously assigned to affilates
20 relating to management fees. . .This commtment is off settble to the
21 extent PacifiCoip demonstrates to the Commssion's satisfaction, in the
22 context of a general rate case the following:
23 i) Corporate allocations from MEHC to PacifiCoip included in
24 PacifiCorp's rates are less than $7.3 millon..."
25 This adjustment limits the MEHC corporate charge to PacifiCoip to $7.3 millon.
26 Intervenor Funding (page 4.9) - This adjustment increases amortization expense
27 on previously deferred intervenor funding by the expected amortization amount
McDougal, Di - 23
Rocky Mountain Power
1 through the Test Period and rate base is adjusted to reflect all balances as of
2 December 2010.
3 Generation Overhaul Expense (page 4.10) - This adjustment normlizes
4 generation overhaul costs using a four year average methodology. Actual
5 overhaul expenses from 2006 - 2008 are escalated to 2009 dollars using escalation
6 indices and then those escalated expenses are averaged over four years. For the
7 Currant Creek, Lake Side and Chehalis generating units, the four year average is
8 comprised of the overhaul expense projected durng the first four full years these
9 plants are operationaL. The adjustment is calculated by. subtracting the actual
10 overhaul costs from the four year averages.
11 Memberships and Subscriptions (page 4.11) - This adjustment removes
12 expenses in excess of Commssion policy as stated in Order No. 29505. National
13 and regional trade organizations are recognized at 75 percent and dues for
14 membership in Western Electrc Coordinating Council ("WECC") and Nortern
15 Tier Transmission Group are included at 100 percent. All other membership dues
16 are removed.
17 Postretirement Measurement Date Change (page 4.12) - This adjustment
18 removes the Idaho situs assigned expense related to a change in the measurement
19 date for postretirement benefits.
20 Cash Basis Idaho Pension Expense (page 4.13) - This adjustment replaces the
21 actuarially determned pension expense for the Test Period with the actual amount
22 funded (cash basis). This adjustment is consistent with the Idaho Commssion's
23 orders number 29838 and 29871 referrg to a United Water case, and with the
McDougal, Di - 24
Rocky Mountain Power
1 Company's 2007 general rate case, Case No. PAC-E-07-05, and the Company's
2 2008 general rate case, Case No. PAC-E-08-07.
3 Insurance Expense (page 4.14) - This adjustment normalizes injury and damage
4 expenses to reflect a thee-year average of gross expense minus insurance
5 proceeds. This adjustment also examines the level of captive insurance expense
6 which continues to remain below $7.4 millon as agreed to by the Company as
7 par of the MEHC transaction in Case No. PAC-E-05-08, commitment 129.
8 DSM Removal (page 4.15) - Idaho allows for recovery of DSM expenses
9 through the customer effciency services rate adjustment (Schedule 191). This
10 adjustment removes Idaho DSM costs in order to prevent a double recovery
11 though base rates and Schedule 191.
12 Wyoming Advertising (page 4.16) - This adjustment removes from results
13 certain advertising costs that the Company was ordered to incur by the Wyoming
14 Public Service Commssion.. These costs wil be charged situs to Wyoming
15 customers.
16 Avian Settlement (page 4.17) - In 2009 the Company and the U.S. Attorney for
17 Wyoming reached an agreement associated with increasing protection for wildlife
18 habitat in and around the Company's transmission and distribution assets. Under
19 the terms of the agreement, the Cömpany is providing funds to varous wildlife
20 agencies in Wyoming as well as Idaho, Utah and Montana to support
21 improvements to design and the construction of avian-safe power lines. This
22 adjustment removes the April 2009 reversal of a December 2008 entry. Also, this
23 adjustment includes capital improvements of existing power lines that wil benefit
McDougal, Di - 25
Rocky Mountain Power
1 customers by protecting wildlife habitat and reducing avian related outages.
2 Tab 5 - Net Power Cost Adjustments
3 Q.
4 A.
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
Please describe the adjustments included in Tab 5.
Net Power Cost Study (page 5.1) - The net power cost study adjustment
presents normalized Test Period steam and hydro power generation, fuel,
purchased power, wheeling expense and sales for resale based on the Company's
GRID modeL. It also normalizes hydro, weather conditions and plant availabilty
as described in Dr. Shu's testimony.
BP A Residential Exchange (page 5.2) - The Company received a monthly
purchase power credit from BPA which is treated as a 100 percent pass-through
customers eligible to paricipate in the Residential Exchange Program in Oregon,
Washington, and Idaho. This adjustment reverses the BPA purchase power
expense credit recorded.
James River Royalty Offset and Little Mountain Steam Sales (page 5.3) - On
Januar 13, 1993, the Company executed a contract with James River Paper
Company with respect to the Camas mill, later acquired by Georgia Pacific.
Under the agreement, the Company built a steam turbine and is recovering the
capital investment over the twenty-year operational term of the agreement as an
offset to royalties paid to James River based on contract provisions. The contract
costs of energy for the Camas unit are included in the Company's net power costs
as purchased power expense, but GRID does not include an offsetting revenue
credit for the capital and maitenance cost recovery. This adjustment adds the
royalty offset to account 456, other electric revenue, for the Test Period.
McDougal, Di - 26
Rocky Mountain Power
1 This adjustment also normalizes the ongoing level of steam revenues
2 related to the Little Mountain plant. Contractually, the steam revenues from Little
3 Mountain are tied to natual gas prices. The Company's net power cost study
4 includes the cost of running the Little Mountain plant but does not include the
5 offsetting steam revenues. This adjustment aligns the steam revenues to the gas
6 prices modeled in GRID.
7 Electric Lake Settlement (page 5.4) - Canyon Fuel Company ("CFC") owns the
8 Skyline mine located near Electric Lake. Electrc Lake is a reservoir owned by
9 the Company that provides water storage for the Huntington generating plant.
10 The two companies have disputed a claim made by PacifiCoip that CFC's mining
11 operations caused the lake to leak water into the Skyline mine, thus makng it
12 unavailable for use by the Huntington generating plant. The Company has
13 incured capital costs and O&M costs to pump water from the breach back into
14 Electric Lake. The two companies negotiated a settlement of the claims made by
15 the Company. The settlement of costs includes reimbursement to the Company
16 for O&M and capital costs associated with the pumping. The value of the
17 settlement was amortized over three years. This adjustment includes the
18 appropriate Test Period amortization and rate base balances.
19 Tab 6 - Depreciation and Amortization Expense Adjustments
20 Q.Pleas describe the adjustments included in Tab 6.
21 A.Depreciation and Amortization Expense (page 6.1) - This adjustment enters
22 into the Test Period results depreciation and amortization expense for the major
23 plant added to rate base in adjustment 8.6.
McDougal, Di - 27
Rocky Mountain Power
1 Depreciation and Amortization Reserve (page 6.2) - This adjustment enters
2 into Test Period results depreciation and amortization reserve for the major plant
3 additions added to rate base in adjustment 8.6.
4 Hydro Decommissioning (page 6.3) - Based on the Company's latest
5 depreciation study approved in Case No. PAC-E-07-14, an annual accrual of
6 $19.4 millon is required for the decommssioning of varous hydro facilities.
7 This adjustment adjusts the decommssioning reserve balance to the end of the
8 Test Period leveL.
9 Tab 7 - Tax Adjustments
10 Q.
11 A.
12
13
14
15
16
17
18
19
20
21
22
23
Please describe the adjustments included in Tab 7.
Interest True Up (page 7.1) - This adjustment details the tre up to interest
expense required to synchronize the Test Period expense with rate base. This is
done by multiplying normlized net rate base by the Company's weighted cost of
debt in this case.
Property Tax Expense (page 7.2) - Property tax expense for the Test Period was
computed by adjusting calendar year 2009 property tax expense for known and
anticipated changes in assessment levels though the end of the Test Period.
Please refer to Confidential Exhibit No.3 for detals supporting the Test Period
expense.
Renewable Energy Tax Credit (page 7.3) - The Company is entitled to
recognize certain tax credits as a result of placing qualifying renewable generating
plants into service. The federal tax credit is based on the generation of the plants
and the credit can be taken for ten years on qualifying propert. Under the
McDougal, Di - 28
Rocky Mountain Power
1 calculation required by Internal Revenue Service Code Sec. 45(b )(2), the Test
2 Period renewable electricity production credit is 2.2 cents per kilowatt hour of the
3 electricity produced from wind energy. The Utah state tax credit is based on the
4 generation of the Blundell bottoming cycle, and the credt/can be taen for four
5 years. In addition to the Utah state tax credit, the Company is able to recognize
6 the Oregon Business Energy Tax Credit, which is based on investment in specific
7 assets and is taken over a five year period on qualifying propert.
8 Idaho State Investment Tax Credit (page 7.4) - The Idaho state investment tax
9 credit ("ITC") is based on the plant placed in servce, and the credit is usually
10 utilzed in a subsequent period depending on the availabilty of Idaho state taxable
11 income. Since PacifiCorp is a 46(f)(1) Company, this adjustment includes into
12 results the ITC unamortized balance as a rate base reduction.
13 AFUDC Equity (page 7.5) - This adjustment includes the appropriate level of
14 AFUDC - Equity into results for the purpose of aligning the tax Schedule M's
15 with regulatory income.
16 Adjust Accumulated Deferred Income Taxes to.Actual.(page 7.6) - This
17 adjustment aligns the Company's original jurisdictionally allocated accumulated
18 deferred income taes related to depreciable and amortizable assets with actual
19 deferred income tax expense from the Power Tax system.
20 Correct Allocation Factor (page 7.7) - This adjustment corrects an allocation
21 factor on an item related to accumulated deferred income taxes.
22 Income Tax Normalization (page 7.8) - As described in the testimony and
23 exhibits of Company witness Mr. Ryan R. Fuller, the income taxes in this case
McDougal, Di - 29
Rocky Mountain Power
1
2
3
4
5
6
7
8
9
10
11 Q.
12 A.
13
14
15
16
17
18
19
have been presented on a fully normlized basis, excluding AFUDC equity.
Accordingly, this adjustment removes the base period Idaho allocated income tax
flow-though.
Medicare Subsidy (page 7.9) - On March 23,2010, the Patient Protection and
Affordable Care Act was signed into law. The Act, including a subsequent
amendment to the Act (the amendment is known as the Health Care and
Education Reconciliation Act signed into law March 30, 2010), changes the
deductibilty of certain costs incured for post-retirement prescription drg
coverage. This change is described in the Company's accounting application in
Case No. PAC-E-I0-4 and in the testimony of Mr. Fuller.
How have current state and federal income tax expenses been calculated?
Current state and federal income tax expenses were calculated by applying the
applicab'ie tax rates to the taxable income calculated in the Report. State income
tax expense was calculated using the state statutory rates applied to the
jursdictional pre-tax income. The result of accumulating those state tax expense
calculations is then allocated among the jurisdictions using the Income Before
Tax ("IBT") factor. Federal income tax expense is calculated using the same
methodology that the Company uses in preparng its filed income tax retus. The
detail supporting this calculation is contained on pages 2.18 though 2.20.
20 Tab 8 - Rate Base Adjustments
21 Q.
22 A.
23
Please describe the adjustments included in Tab 8.
Update Cash Working Capital (page 8.1) - This adjustment supports the
calculation of cash working capital included in rate base based on the normlized
McDougal, Di - 30
Rocky Mountain Power
1 results of operations for the Test Period. Total cash workig capital is calculated
2 by multiplying jursdictional net lag days by the average daly cost of service.
3 Net lag days in this case are based on a lead lag study prepared by the Company
4 using calendar year 2007 information. .The Company's 2008 general rate case
5 relied on this same lead lag study, a copy of which was provided along with the
6 Company's filing in that case. Based on the results of the 2007 lead lag study, the
7 Company experiences 4.72 net lag days in Idao requirng a cash working capital
8 balance of $2.1 millon to be included in rate base.
9 Trapper Mine Rate Base (page 8.2) - The Company owns a 21.4 percent share
10 of the Trapper Mine, which provides coal to the Craig generating plant. This
11 investment is accounted for on the Company's books in FERC account 123.1,
12 investment in subsidiar company, which is not included as a regulatory rate base
13 account. The normalized coal cost from Trapper Mine in net power costs includes
14 operation and maintenance costs but does not include a return on investment.
15 This adjustment adds the Company's portion of the Trapper Mine net plant.
16 investment to rate base in order for the Company to earn a return on its
17 investment.
18 Jim Bridger Mine Rate Base (page 8.3) - The Company owns a two-thirds
19 interest in the Bridger Coal Company, which supplies coal to the Jim Bridger
20 generating plant. The Company's investment in Bridger Coal Company is
21 recorded on the books of Pacific Minerals, Inc. Because of this ownership
22 arangement, the coal mine investment is not included in electrc plant in service.
23 The normalized coal costs for Bridger Coal Company in net power costs include
McDougal, Di - 31
Rocky Mountain Power
1 the operation and maintenance costs of the mine but provide no retu on
2 investment. This adjustment is necessar to properly reflect the Bridger Coal
3 Company investment in rate base in order for the Company to earn a return on its
4 investment.
5 Environmental Settlement (PERCO) (page 8.4) - In 1996, the Company
6 received an insurance settlement of $33 millon for environmental clean-up
7 projects. These funds were transferred to a subsidiary called PacifiCoip
8 Environmental Remediation Company ("PERCO"). This fund balance is
9 amortized or reduced as PERCO expends dollars on clean-up costs. PERCO
10 received an additional $5 millon of insurance proceeds plus associated liabilties
11 from Rocky Mountan Power in 1998. This adjustment includes the unspent
12 insurance proceeds in results of operations as a reduction to rate base.
13 Customer Advances for Construction (page 8.5) - Refundable customer
14 advances for construction are recorded to FERC account 252. The December
15 2009 balances do not reflect the proper allocation because amounts were recorded
16 to a corporate cost center location rather than state-specific locations in the
17 Company's accounting system. This adjustment corrects the allocation of
18 customer advances.
19 Pro Forma Major Plant Additions (page 8.6) - To reasonably represent the cost
20 of system infrastructure required to serve our customers, the Company has
21 identified capital projects that wil be completed by the end of the Test Period.
22 Company business units identifed capital projects with expenditures over $5
23 milion that wil be used and useful by December 31,2010. Additions by
McDougal, Di ~ 32
Rocky Mountain Power
1 functional category are summarzed on separate sheets, indicating the in-sèrvice
2 date and amount by project. The associated depreciation expense and
3 accumulated reserve impacts are accounted for in adjustment 6.1 and 6.2.
4 Miscellaneous Rate Base (page 8.7) - In this adjustment fuel stock is increaseG
5 due to the cost of coal and the number of tons stored at each site. Also, prepaid
6 overhaul balances in FERC account 186 for the Lake Side, Chehalis, and Curent
7 Creek plants are adjusted forward to reflect future payments and transfers of
8 capital to electric plant in service expected durg the Test Period.
9 Powerdale Hydro Decommission (page 8.8) - Powerdale is a hydroelectrc
10 generating facility located on the Hood River in Oregon. This facility was
11 scheduled to be decommssioned in 2010; however, in 2006 a flash flood washed
12 out a major section of the flow line. The Company determed that the cost to
13 repai this facility was not economical and determned it was in the ratepayers'
14 best interest to cease operation of the facility.
15 This adjustment reflects the treatment approved by the Commssion in
16 Case No. PAC-E-07-04. Durng 2007, the net book value (includig an offset for
17 insurance proceeds) of the assets to be retired was transferred to the unrecovered
18 plant regulatory asset. In addition, future decommssioning costs are deferred as
19 they are spent and amortized over 10 years, beginning in the subsequent year.
20. Goose Creek Transmission (page 8.9) - On April 1, 2008, the Company sold its
21 undivided interest in 13.85 miles of transmission line, running from the
22 Company's Goose Creek switching station and extending north to the Decker 230
23 kV substation near Decker, Montana. The assets sold included structures,
McDougal, Di - 33
Rocky Mountain Power
1 miscellaneous support equipment, easements, and rights-of-way associated with
2 the transmission line. The sale of the transmission line resulted in the Goose
3 Creek switching station no longer being needed or useful to the Company. The
4 Company plans to remove the Goose Creek switching station including all above
5 ground facilities. Consistent with Commssion Order No. 30904, in September
6 2009 the Company wrote off the gain associated with the sale. This adjustment
7 removes the rate base and accumulated depreciation balances and depreciation
8 expense included in December 2009 unadjusted results.
9 FERC 105 (PHFU) (page 8.10) - This adjustment removes all plant held for
10 futue use ("PHFU") assets from FERC account 105. The Company's is makng
11 this adjustment in compliance with Title 16 of Public Utility Regulation, chapter
12 5, "Powers and Duties of Public Utilties Commssion" section 61-502A.
13 EITF 04-6 Coal Stripping (page 8.11) - In Docket No. PAC-E-09-08, The
14 Company filed for an Accounting Order authorizing the Company to record, as a
15 regulatory asset, the costs associated with the removal of overburden and waste
16 materials at its affiliate coal mines. In January 2010, the Commssion ordered the
17 Company in Order No. 30987 to record the removal costs within its fuel expense
18 account but withheld its review and judgment regarding the propriety of these
19 removal costs until such time as the Company fies an application with the
20 Commssion seeking a specific recovery of these costs though rates. This
21 adjustment aligns the costs of coal stripping and the benefits to customers by
22 adding the deferred strpping costs into rate base as a regulatory asset. The
McDougal, Di - 34
Rocky Mountain Power
1 related reduction to fuel expense is accounted for in the net power costs
2 adjustment 5.1.
3 Tab 9 - Rolled In
4 Q.Please describe the information contained behind Tab 9 Rolled In
5 A.Tab 9 isTab 2 restated with the Idao allocation based on the rolled in allocation
6 method. This information is being provided pursuant to the Commssion order on
7 inter-jurisdictional issues in Case No. PAC-E-02-03.
8 Tab 10 - Allocation Factors
9 Q.Please describe the information contained behind Tab 10 Allocation Factors
10 A.Tab 10 Allocation Factors summarzes the derivation of the jurisdictional
11 allocation factors using the Revised Protocol allocation methodology. Factors in
12 this case are based on the load forecast though December 2010 and pro forma
13 account balances.
14 Rate MitigationCap
15 Q.
16
17
18 A.
19
20
21
22
23
24
25
26
In the Company's previous rate case the price increase was reduced bya rate
mitigation cap. Is a rate mitigation cap applied to the revenue requirement
in this case?
No. The rate mitigation cap was approved by the Commssion in Case No. PAC-
E-02-03 and was applied to rate cases as described in the following exceipt from
the stipulation in that case:
"For all Idaho general rate proceedngs initiated after the effective
date of this Stipulation and Revised Protocol, and until March 31,
2009, the Company's Idaho revenue requirement to be used for
puiposes of setting rates for Idaho customers wil be the lesser of:
(i) the Company's Idaho revenue requirement calculated under the
Rolled-In Allocation Method multiplied by 101.67 percent, or (ii)
McDougal, Di - 35
Rocky Mountain Power
1 the Company's Idaho revenue requirement resulting from use of
2 the Revised Protocol."
3 The rate mitigation cap is no longer applicable in Idaho under the Revised
4 Protocol as approved by the Commssion. The revenue increase sought in this
5 case is supported by revenue requirement allocated to Idaho according to the
6 Revised Protocol.
7 Load Growth Adjustment Rate
8 Q.
9
10 A.
11
12
13
14
15
16
17
18
19
20
21 Q.
22 A.
Has the Company updated the calculation of the LGAR that is applied to the
calculation of net power costs to be recovered through the ECAM?
Yes. Exhibit No.4 provides the detailed calculation, using revenue requirement
numbers from Exhibit No.2. To calculate the LGAR I have incorporated the
applicable elements from this case, including production-related return on
investment and non-NPC expenses, into the template approved by the
Commssion in Case No. PAC-E-08-08. The LGARitself does not affect revenue
requirement in this case, but is applied to the calculation of net power costs to be
deferred and recovered through the ECAM, and is to be updated each time base
net power costs are updated in a general rate case. Using the revenue requirement
in the Company's filing results in an increase in the LGAR from $17.48 per MW
to $20.19 per MW. The Company wil also provide an updated calculation of
this rate based on the Commssion-approved outcome of this case.
Does this conclude your direct testimony?
Yes.
McDougal, Di - 36
Rocky Mountain Power
Case No. PAC-E-1O-07
Exhibit NO.1
Witness: Steven R. McDougal
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Steven R. McDougal
Revenue Requirement Summa
May 2010
Rocky Mountain Power
IDAHO
Result of Operations - REVISED PROTOCOL
12 Months Ended DECEMBER 209
(1)
Total
Resu~s
1 Operating Revenues:
2 General Business Revenues
3 Interdepartmental
4 Special Sales
5 Other Operating Revenues
6 Total Operating Revenues
7
8 Operating Expenses:
9 Steam Production
10 Nuclear Production
11 Hydro Production
12 Other Power Supply
13 Transmission
14 Distribution
15 Customer Accounting
16 Customer Serviæ & Info
17 Sales
18 Administrative & General
19
20 Total O&M Expenses
21
22 Depreciation
23 Amortization
24 Taxes Other Than Income
25 Income Taxes - Federal
26 Income Taxes - State
27 Income Taxes - Def Net
28 InvestmenHax Cred~ Adj.
29 Misc Revenue & Expense
30
31 Total Operating Expenses:
32
33 Operating Rev For Return:
34
35 Rate Base:
36 Elecric Plant In Service
37 Plant Held for Future Use
38 Misc Deferred Debits
39 Elec Plant Acq Adj
40 Nuclear Fuel
41 Prepayments
42 Fuel Stock
43 Material & Supplies
44 Working Cap~al
45 Weatherization Loans
46 Misc Rate Base
47
48 Total Elecric Plant:
49
50 Rate Base Deductions:
51 Accum Prov For Deprec
52 Accum Prov For Amort
53 Accum Def Income Tax
54 Unamortized ITC
55 Customer Ad\ For Const
56 Customer Serviæ Deposits
57 Misc Rate Base Deductions
58
59 Total Rate Bas Deductions
60
61 Total Rate Base:
62
63 Return on Rate Base
64
65 Return on Equity
66
67 TAX CALCULATION:
68 Operating Revenue
69 Other Deductions
70 Interest (AFUDC)
71 Interest
72 Schedule "M" Additions
73 Schedule "M" Deductions
74 Income Beore Tax
75
76 State Income Taxes
77 Taxble Income
78
79 Federal Income Taxes + Other
202,73,162
45,289,382
13,773,492
261,796,035
60,406,070
2,133,930
79,705,561
10,588,482
11,434,564
4,643,836
1,847,458
11,494,297
182,254,199
27,477,478
2,100,480
5,735,330
(17,477,596)
(1,952,739)
25,508,213
(201,494)
(279,445)
223,164,426
38631609
1 ,168,782,728
(0)
4,174,115
3,352,852
2,570,335
12,146,136
9,955,906
3,095,969
3,503,640
123,279
1,207,704,959
(371,681,993)
(21,605,949)
(140,588,834)
(228,311)
(947,697)
(5,192,760)
(540,245,544)
667459415
5.788%
5.669%
44,507,993
(3,235,657)
18,808,472
43,239,731
113,145,215
(40,970,306)
(1,952,739)(39017567)
(17 477 596)
(2)
Price Change
27,697,872
64,379
9,232,626
1,254,561
10,551,566
17146306
27,633,492
27,633,492
1,254,561
26378932
9232626
Rocky Mountain Power
Exh.ibit No. 1 Page 1 of 3
Case No. PAC-E-10-07
Witness: Steven R. McDougal
(3)Resultw~h
Price Change
230,431,033
4,708,215
5,735,330
(8,244,970)
(698,178)
233,715,992
55777 915
1,207,704,959
(540,245,544)
667459415
8.357%
10.600%
72,141,485
(3,235,657)
18,808,472
43,239,731
113,145,215
(13,336,814)
(698,178)
(12638636)
(8244970)
Rocky Mountain Power
Noimallzed Result 01 Opeations
Adjustmnt SUmmar
Twelve Months Endin Decmbe 31, 2009
Tab 2 Tab 2
Total Compay Idaho Allocated
Actal Resutts Acal Results
December 2009 Decmber 2009
1 Operating Reenues
2 Generl Busines Revues 3,484,413,565 186,759,389
31n1erdeparmental
4 Speaal Sales 64.32,157 34,98.299
5 Other Operating Reenues 226,031,656 14263,037
6 T oial Oping Revenues 4,353,766,380 23,00,725
7
8 Operating Expenses'
9 Stear Production 898,300,862 54,579,857
10 Nuclear Produc1icn
11 Hydro Production 37,92.259 2.089,057
12 Other PCN9l Supply 1,023.69.683 66.851,90
13 Transmission 172.874.522 9,532,492
14 Distrbution 215,468,741 11,148,340
15 Customer Accounting 93.785,007 4.505,501
16 Customer Serice & Inf 71,462,744 6,838.635
17 Sales
18 Administrative & General 162,619,511 9.473,261
19
20 Total O&M Expenses 2.676,130,329 165,016.333
21
22 Deprciation 464,027,603 24.372,146
23 Amorizaiion 43,698,570 2,251,446
24 Taxes O1erThan IncaTe 123,8n,487 5,321,337
25 Income Taxes. Fødera (169,083,383)(14,015,615)
26lncaTeTaxes- S1ale (22,655,140)(1,927,760)
27 IncaTe Taxes - Oaf Ne1 482,616,183 23,827,937
28 Investment Tax Credit Adj (1,874,204)(201,494)
29 Misc Reveue & Expense (5,975,707)(296,743)
30
31 T olel OperingExpenses 3,500,761,738 204,347,587
32
33 Opera1ing Re For Return 763,004,64 31,661,138
34
35 Raie Base
36 Electric Plant In Service 19,556,037,605 1 :054,50,200
37 Plant Held fo Futue Use 13,674,549 570,032
38 Mise Deferred Debits 140,117,584 3,620,813
39 Elec Plani Acq Adj 60,866,907 3,352,852
40 Nuclear Fuel
41 Prepayments 46,150,453 2,570,335
42 Fuel Stock 167,792,599 10,626,940
43 Material & Supplies 1n,874,022 9,95,90
44 Working Capital 55,802,250 2,912,834
45 Weaiherization Loans 37,358,188 3,503,64
46 Mise Rate Base 1,809,172 123,279
47
48 Total Beclc Plant.20,257,483,328 1,091,740,831
49
50 Rate Base Deductions
51 Accum Prov For Deprec (6,626,518.392)(369,078,016)
52 Aca.m Prov For Ama1 (427,140,689)(21,58,54)
53 Aca.m Def Income Tax (2,332,318,663)(140,546,898)
54 Unamortized ITC (7,294,222)(44,168)
55 Customr Adv For Canst (20,94,658)(686,658)
56 Custoer Service Deposits
57 Misc Rate Base Deductions (57,36,419)(2,686,58)
58
59 Total Rate BaSe Deductons (9,471,582,04)(534,622,870)
60
61 T olal Rate Base 10,785,901,285 557.117.960
62
63 Retu on Rate Base 7.074%5.683%
64
65 Return on Equity 8.138%5.468%
Exhib~ 2
Tab 3 Tab 4
Revenue Adjusten O&M Adjusten
15,973,773
4,302,563
20,276,335
(4,913)
(4,913)
6,992,701
950,192
(252,521)
17,298
7,702.757
12,573,578
(5,010,486)
(5,010,486)
469,585
44,873
7,320,567
59,134
28,225
138,335
(4,989,1n)
1,811,040
5,140,583
1,497
(3,231,060)
(439,047)
(182,892)
1,289,080
(6,299,566)
74,490
(17,580)
TabS
Net Power CostAdjustent
10,303,08
218,378
10,521,461
5,356,628
5,533,80
1,001,768
Rocky Mountain Power
Exhibit No. 1 Page 2 of 3
Case No. PAC-E-10-07
Witness: Steven R. McDougal
Tab 6
Depraton &
Amortzaon
Adjuslms
1,701,671
(2.402,284)
(700,613)
(700,613)
56,910
(1.497)
898,145
896,648
953,558
(108,911)
15,885
(2,615,963)
(25,402)
261,400
77389
93,274 (2,379,965)
(15,637)(2,379,96)
Rocky Mountain Power
Normalized Result 01 Opeations
Adjustmnt SUmmarTwlve Months Ending De 31,2008
1 Operating Revenues
2 Generl Business Revenues
3 Inlerepamen1al
4 Special Sales
5 Other Operating Reenues
6 Total Operaing Revenues
7
8 Operating Expenses
9 Sieam Prouction
10 Nuclear Producion
11 Hydro Produclion
12 Other PC7er Suppy
13 Transmission
14 Distribution
15 Customer Accounting
16 Cus10er Service & Info
17 Sales
18 Administrative & General,.
20 TotalO&MExpenses
21
22 Depreciation
23 ArOrizatioo
24 Taxes OlerThan InOO9
25 Income Taxes - Federa
26 Income Taxes - 81819
27 Income Taxes - Oaf Net
28 Investment Tax Credit Adj
29 Mise Revnue & Expense
30
31 To1al Op9ring Expeses
32
33 Operating Rev For Aaum
34
35 Ra1e Base
36 Electc Plant In Seice
37 Plant Held for Fu1ureUs9
38 Mise Deferd Debits
39 Elec PI.am Acq Adi
40 Nuclear Fuel
41 Prepayments
42 Fuel Stock
43 Materal & Supplies
44 Workng Capital
45 Weaheria1ioo Loans
46 Mise Rale Base
47
48 T oIa1 8eeinc Plant
4.
50 Rate Base Deduc1ons'
51 Accum Prev For Depree
52 Accum Prev For Amort
53 Accum Oaf Income Tax
54 Unamoized ITC
55 Customer Ad For Const
56 Customer Servce Deposits
57 Misc Rate Base Dedueiions
56
59 Total Rate Base Dedueiions
60
61 T oIa1 Rate Base
62
63 Return on Rate Base
64
65 Return on Equity
Tab 7
Exhibi 2
TabS
Rate Bae
Adjus1entsTax Adjus1ents
209,99
209,996
413,992
(4,118,090)
(114,133)
229,019
(1,810,240)
(24.98)
2,126,953
(3,379,215)
3,379,215
114,20,æ8
(570,032)
679.793
1,519,196
(8;8,818)
(184,142)
116,016,129
(2,02.219)
(1,082,960)113.$7,072
(1,082,960)(2,44,057)
(468)
(185,900)
(115,64)
115,64
183,135
13,482
(261,039)
(181,282)
Rocky Mountain Power
Exhibit No. 1 Page 3 of 3
Case No. PAC-E-10-07
WitnesS: Steven R. McDougal
Tab 2
Idaho Normized
Results
202,733,162
45,289,382
13,773,492
261,796,035
60,406.070
2,133,930
79,705,561
10,588,482
11,434,564
4,643,836
t,847,458
11,494,297
182,254,199
27,477,478
2,100,450
5,73,330
(17,477,596)
(1,952,739)
25,50,213
(201.494)
(279,445)
223,164,426
38,631,609
1,168,782728
4,174,115
3,352,852
2,570,335
12,146,136
9,955,906
3,09,96
3,50,540
123,279
t.07,704,959
(371 ,681,993)
(21,60,94)
(140,588,834)
(228,311)
(947,697)
(5,192,760)
(54,24,54)
667,459,415
5.788%
5.669%
Case No. PAC-E"'1O-07
Exhibit No.2
Witness: Steven R. McDougal
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Steven R. McDougal
Revenue Requirement
May 2010
Case No. PAC-E-I0-07
Exhbit NO.2
Witness: Steven R. McDougal
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNAI POWER
Exhbit Accompanying Direct Testimony of Steven R. McDougal
Revenue Requirement
May 2010
r-=..c::ii:-eN00
:i::..~..
UI0'
Rocky Mountain Power Page 1.0
IDAHO
Results of Operations. REVISED PROTOCOL
12 Months Ended DECEMBER 2009
(1)(2)(3)
Total Resu~s wi
Result Price Change Price Change
1 Operating Revenues:
2 General Business Revenue 202,733,162 27,697,872 230,431,033
3 Interdepartmenal
4 Speial Sales 45,289.362
5 Other Operatng Revenues 13.n3,492
6 Total Operating Revenues 261,796,035
7
8 Operating Expenses:
9 Steam Prouction 60,406,070
10 Nuclear Prouction
11 Hydro Prouction 2,133,930
12 Other Pow Supply 79,705,561
13 Transmission 10,588,82
14 Distibuln 11,434,56
15 Customer Accounting 4,643,836 64,379 4,708,215
16 Customer Servic & Info 1,847,458
17 Sales
18 Administrtive & Generl 11,494,297
19
20 TotalO&M Expeses 182,254,199
21
22 Depreciation 27,477,47823 Amor 2,100,480
24 Taxes Other Than Income 5,735,330 5,735,330
25 Income Taxes. Federal (17,477,596)9,232,626 (8,244.970)
26 Income Taxes. State (1,952,739)1,254,561 (698,178)
27 Income Taxes. Def Net 25,508,213
28 Investment Tax Cred" Adj.(201,494)
29 Misc Revenue & Expense (279,45)
30
31 Total Operating Expenses:223,164,426 10,551,58 233,715,992
32
33 Operating Rev For Return:38631609 17146,306 557n915
34
35 Rate Base:
36 Elec Plant In Service 1,168,782,728
37 Plant Held for Future Use (0)
38 Misc DeferT Debits 4,174,115
39 Elec Plant Acq AdJ 3,352,852
40 NtJlear Fuel
41 Prepayments 2,570,335
42 Fuel Stock 12.146,136
43 Material & Supplies 9,955,90
44 Wonting Capital 3,095.969
45 Weatherization Loans 3,503,64
46 Misc Rae Base 123,279
47
48 Total Electric Plant:1,207,704,959 1,207,704,959
49
50 Rate Base Deductions:
51 Accum Prov For Depre (371,681,993)
52 Accum Pro For Amort (21,605,949)
53 Accum Deflncome Tax (140,58,834)
54 Unamortized irc (228,311)
55 Customer Adv For Const (947,697)
56 Customr Service Deposits
57 Misc Rate Base Deducton (5,192,760)
58
59 Total Rate Base Deductions (540,245,54)(540.245,544)
60
61 Total Rate Base:667459415 667459415
62
63 Retum on Rate Base 5.788%8.357%
64
65 Retum on Equit 5.669%10.60%
66
67 TAX CALCULATION:
68 Operating Revenue 44,507,993 27,833,492 72,141,485
69 Other Deductions
70 Interest (AFUDC)(3,235,657)(3,235,657)
71 Interest 18,80,472 18,808,472
72 Schedule "M" Addiüons 43,239,731 43.239,731
73 Schedule "M" Deductions 113.145,215 113,145,215
74 Income Before Tax (40.970,306)27,633,92 (13,336,814)
75
76 State Income Taxes (1.952,739)1.254,561 (698,178)
n Taxable Income 139017 567\26378932 112 638636\
78
79 Federal Income Taxes + Other (174n596\9232.626 18244970\
Ref. Page 2.2
Rocky Mountain Power
IDAHO
Results of Operations. REVISED PROTOCOL
12 Months Ended DECEMBER 2009
Pagé 1.1
Net Rate Base $667,459,415 Ref. Page 1.1
Return on Rate Base Requested 8.357%Ref. Page 2.1
Revenues Required to Earn Requested Return 55,777,915
Less Current Operating Revenues (38,631,609)
Increase to Currnt Revenues 17,146.306
Net to Gross Bump-up 161.54%
Price Change Required for Requested Return $27,697.872
Requested Pnce Change $27,697.872
Uncollectible Percent 0.232%Ref. Page 1.3
Increased Uncollectible Expense $64,379
RequestedPnce Change $27,697.872
Franchise Tax 0.000%Ref. Page 1.3
Revenue Tax 0.000%Ref. Page 1.3
Resource Supplier Tax 0.00%Ref. Page 1.3
Gross Receipts 0.000%Ref. Page 1.3
Increase Taxes Other Than Income $
Requested Price Change $27,697,872
Uncollectible Expense (64,379)
Taxes Other Than Income
Income Before Taxes $27,633,492
State Effctive Tax Rate 4.54%Ref. Page 2.1
State Income Taxes $1.254,561
Taxable Income $26,378,932
Federal Income Tax Rate 35.00%Ref. Page 2.1
Federal Income Taxes $9.232,626
Operating Income 100.000%
Net Operating Income 61.905%Ref. Page 1.3
Net to Gross Bump-Up 161.54%
Rocky Mountin Power
IDAHO
Results of Operations. REVISED PROTOCOL
12 Months Ended DECEMBER 2009
Page 1.2
Operating Revenue 100.000%
Operating Deductions
Uncollectible Accounts
Taxes Other - Franchise Tax
Taxes Other - Revenue Tax
Taxes Other - Resource Supplier
Taxes Other - Gross Receipts
0.232% See Note (1) below
0.000%
0.000%
0.000%
0.000%
Sub-Total 99.768%
State Income Tax (g 4.54%4.529%
Sub-Total 95.238%
Federal Income Tax (g 35.00%33.333%
Net Operating Income 61.905%
(1) Uncollectible Accounts =472,263
202,733,162
Pg 2.12, Sits frm Accunt 904
Pg 2.2, General Business Revenues
IDAHO SUMMARY OF ADJUSTMENTS TOTAL Page 1,4
Net Power Cost
Revenue Adjustments O&M Adjustments Adjustment Deptetion &Tax Adjustents Mise Rate Base
Tota Adjustments (Tab 3) (Tab 4) (Tab 5)Amortzati (Tab 6)(Tab 7)Adjustments (Tab 8)(Tab 9) (Tab 10)
1 Operetlng Revenues:
2 General Business Revenues 15,973,773 15,g13,773
3 Interdpartmental
4 Speciel Sales 10,303,083 10,303.08
5 Other Operating Revenues (488.545)4.302.563 (5.10,486)216,376
6 Total Operating Revenues 25,787,310 20.276.335 (5,010,48)10:521,461
7
B Operating Expnss'
9 Steam Prouction 5.826.213 469.85 5.56.28
10 Nucar Production
11 Hydro Production 44,673 44,873
12 Other Power Supply 12,854,371 7.320,561 5,533.04
13 Trensmì$skm 1.55.80 (4.913)59,134 1,001,168
, 4 Diribution 28.225 286,225
15 Custmer ACCunting 138,335 138,335
16 Customer Servce & info (4,008.177)(4.008,177)
17 Salea
18 Adminitrativ & Genaral 2.021,036 1,8",04 209.988
19 T ola! O&M Expenses 17.237,868 (4,913)5.140.583 11,892,200 209.988
20 Depreçltion 3,105,332 1,497 3,104,302 (488)
21 Amortization (150.98)34.942 (185.808)
22 Taxs Other Then Income 413,992 413,992
23 Incme Taiæs: Fedral (3,4tl,981)8,992,701 (3.231,060)(476,5881 (818.724)(4,118.08)(1.810,240)
24 St.(24,918)850,192 (438.047)(84.758)(111,251)(114.133)(245.982)
25 Deferrd Income Taxes 1,680.276 (252,521)(182,882)21.117 (261.400)229.19 2,126.853
26 .Investment Tax Credit Adj.
2? Mise Revenue & Expense 17,29B 17.29B
28 Total.Operetlng Expenses:1""6,838 7,702.757 1,289,080 11,311,991 1,947,870 (3.378.215)(115.44)
28
30 Operating Rev For Return:6,970,471 12,573,578 (6,29l,588)(860,530)(1,947,870)3,379,215 11!i,64
31
32 Rate Base:
33 Electri Plant In Servce 114,278,528 74,490 114,204,038
34 Plant Held for Future Use (570.32)(570,032)
35 MiscOeferr Debit 553,302 (17.580)(108.11)679,793
36 Elec Plant Acq Adj
37 Nuclear Fuel
38 Prpaymnts
39 Fuel Stoek 1,519,196 1,519,196
40 Materil & Supplies
41 Workin Capital 183,136 183,135
42 Weatherization Loans
43 Misc Rate Base
44 T oUtI Electc Plant:116,964,128 56,910 (106.11)116.016.129
45
4t Deductions:
47 Accum Prov For Depree (2.80.977)(1,487)(2,615,1l3)13,48
48 Accum Pl'V For Amort (25,402)(25.02)
49 Accm Oef Income Tax (41,836)1,701.e71 898,145 15,886 261,400 (898,818)(2.020,219)
60 Unamortzed ITC (184.142)(184,142)
51 Customer Adv For Canst (251.038)(261.039)
52 Customer Servce Deposit
53 Miscellaneous Deductions (2.506.176)(2.402,284)77.389 (181.282)
54
55 Total Deductons:(5,622.873)(100,613)81l,"8 93,274 (2.379.1l5)(1,082.1l0)(2,449,057)
58
57 Total Rate B8se:110.341.455 (700,613)853.558 ¡'5.631)(2,379,905)(1,082.960)113,567,072
58
58
60 Estimated ROE impact 0,201%4.351%-2,185%-0,293%-0,821%1.ia8%~1.814%0.000%0,000%
61
62
63
64 TAX CALCULATION:
85
ee Operating Revenu 5,163,787 20,283,950 (10,152,588)(1,310.139)(3.139,245)(623.88)18e.375
67 Other Deuctions
68 Interest (AFUDC)160,213 160,213
eo Interest 177.481 177,481
70 Schedul "M" Additions 2,318.239 (51l,061)(55.81)888.183 2.281.097
72 Seedulé "M" Deductions 6,142,263 (665,388)(1.077,878)81 1.885.569
73 Income Before Tax 1,002,068 2Q.29.338 (8.670,848)(1.28,381)(2,450,462)(881,683)(5.1B.1l)
74
76- State income Taxes (24,878)950.182 (439.047)(84.758)(111.251)(114,133)(245.982)
77 Taxble Income 1.027,048 19.79.14t (8,231.601)(1.361,623)(2,339.211)(847.551)(5.172.115)
78
79 Federal Income T aX8&(3,461,981)6,9Q2,701 (3.231,060)(476,568)(818,724)(4.118.090)(1,810,240)
Rocky Mountain Power
RESULTS OF OPERATIONS
Page 2.1
USER SPECIFIC INFORMATION
STATE:
PERIOD:
IDAHO
DECEMBER 2009
FILE:
PREPARED BY:
DATE:
TIME:
JAM Dec 2009 ID GRC
Revenue Requirement Department
5/20/2010
1:51:09 PM
TYPE OF RATE BASE:
ALLOCATION METHOD:
Year-End
REVISED PROTOCOL
FERC JURISDICTION:Separate Jurisdiction
80R 12 CP:12 Coincidental Peaks
DEMAND %
ENERGY %
75% Demand
25°/~ Energy
TAX INFORMATION
TAX RATE ASSUMPTIONS:
FEDERAL RATE
STATE EFFECTIVE RATE
TAX GROSS UP FACTOR
FEDERAUSTATE COMBINED RATE
TAX RATE
35.00%
4.54%
1.615
37.951%
CAPITAL STRUCTURE INFORMATION
CAPITAL
STRUCTURE
EMBEDDED
COST
WEIGHTED
COST
DEBT
PREFERRED
COMMON
47.60%
0.30%
52.10%
100.00%
5.92%
5.41%
10.60%
2.818%
0.016%
5.523%
8.357%
OTHER INFORMATION
The Company's current estimated cost of equity is 10.6%. The capital structure is calculated using the five quarter average from
12/31/2009 to 1213112010.
REVISED PROTOCOL Page 2.2
Year.End
RESULTS OF OPERATIONS SUMMARY
UNADJUSTED RESULTS IDAHO
Description of Account Summary:Ref TOTAL OTHER IDAHO ADJUSTMENTS ADJTOTAl
1 Operating Revenues
2 General Business Revenues 2.3 3,84,413,565 3,297,654,176 186,759,389 15,973,773 202,733,162
3 Interdepartmental 2.3 0 0 0 0 0
4 Special Sales 2.3 643,321,157 608,334,858 34,986,299 10,303,083 45,289,382
5 Other Operating Revenues 2.4 226,031,658 211,768,621 14,263,037 (489,545)13,773,92
6 Total Operating Revenues 2.4 4,353,766,380 4,117,757,655 236,008,725 25,787,310 261,796,035
7
8 Operating Expenses:
9 Steam Production 2.5 898,300,862 843,721,00 54,579,857 5,826,213 60,406,070
10 Nuclear Production 2.6 0 0 0 0 0
11 Hydro Production 2.7 37,924,259 35,835,202 2,089.057 44,873 2,133,930
12 Other Power Supply 2.9 1,023,694;683 956,843,493 66,851,190 12,854,371 79,705,561
13 Transmission 2.10 172,874,522 163,342,030 9,532,492 1,055.990 1Q.88,82
14 Distnbution 2.12 215.68.741 204,320,401 11,148,340 286,225 11.434,564
15 Customer Accunting 2.12 93,785,007 89,279,506 4,505,501 138,335 4,643,836
16 Customer Service & Infor 2.13 71,462.744 64,626,109 6.836,635 (4.989,177)1,847,458
17 Sales 2.13 0 0 0 0 0
18 Administrative & General 2.14 162,619,511 153,146.250 9,473,261 2.021,036 11,494,297
19
20 Total 0 & M Expenses 2.14 2.676,130,329 2.511,113,996 165,016,333 17,237,866 182,254,199
21
22 Depreciation 2.16 464,027,603 439,655,457 24,372,146 3,105,332 27,477,478
23 Amortization 2.17 43,698,570 41,447,124 2,251,446 (150,966)2.100,480
24 Taxes Other Than Income 2.17 123,877,487 118,556.149 5,321,337 413,992 5,735,330
25 Income Taxes. Federal 2.20 (169,083,383)(155.067,768)(14,015,615)(3,461.981 )(17,477,596)
26 Income Taxes. State 2.20 (22.655,140)(20.727,379)(1,927,760)(24,978)(1,952,739)
27 Income Taxes. Def Net 2.19 482,616.183 458,788,246 23,827,937 1,680,276 25,508.213
28 Investment Tax Credit Adj.2.17 (1,874.204)(1,672,710)(201,494)0 (201,494)
29 Misc Revenue & Expense 2.4 (5.975.707)(5.678,965)(296,743)17.298 (279,445)
30
31 Total Operating Expenses 2.20 3.590,761.738 3.386,414,150 204.347,587 18,816,839 223,164,426
32
33 Operating Revenue for Retum 763,004,643 731,343.505 31,661,138 6,970,471 38,631,609
34
35 Rate Base:
36 Electric Plant in Service 2.30 19.556,037,605 18,501,533,405 1,054,504,200 114,278,528 1,168.782.728
37 Plant Held for Future Use 2.31 13,674,549 13,104,516 570,032 (570,032)(0)
38 Misc Deferred Debis 2.33 140,117,584 136,496,771 3,620,813 553,302 4,174,115
39 Elec Plant Acq Ad)2.31 60.866,907 57.514,055 3,352,852 0 3,352,852
40 Nuclear Fuel 2.31 0 0 0 0 0
41 Prepayments 2.32 46,150,453 43,580,118 2.570,335 0 2,570,335
42 Fuel Stock 2.32 167,792,599 157,165.659 10.626,940 1,519,196 12,146,136
43 Material & Supplies 2.32 177,874,022 167,918.116 9,955,906 0 9,955,906
44 Working Capital 2.33 55,802,250 52,889,415 2,912,834 183.135 3,095,969
45 Weatherization Loans 2.31 37.358.188 33,854,547 3,503.640 0 3,503,640
46 Miscellaneous Rate Base 2.34 1.809,172 1,685.894 123,279 0 123,279
47
48 Total Electric Plant 20,257,483,328 19,165,742,497 1,091,740,831 115.964,128 1,207,704,959
49
50 Rate Base Deductions:
51 Accum Prov For Depr 2.38 (6,626.518,392)(6,257,440,375)(369,078,016)(2,603,977)(371,681,993)
52 Accum Prov For Amort 2.39 (427.140,689)(405,560,142)(21,580,546)(25,402)(21,605,949)
53 Accum Def Income Taxes 2.35 (2.332,318,663)(2,191,771,765)(140,546,898)(41,936)(140,588,834)
54 Unamortized ITC 2.35 (7.294,222)(7,250,054)(44,168)(184,142)(228,311)
55 Customer Adv for Const 2.34 (20,944,658)(20,258,001)(686,658)(261,039)(947.697)
56 Customer Service Deposits 2.34 0 0 0 0 0
57 Misc. Rate Base Deductions 2.34 (57,365,419)(54,678,835)(2,686,584)(2,506,176)(5,192,760)
58
59 Total Rate Base Deductions (9,471.582,043)(8,936,959,173)(534,622,870)(5,622.673)(540,245,544)
60
. 61 Total Rate Base 10,785,901,285 10,228,783.324 557,117,960 110,341,455 667,459,415
62
63 Return on Rate Base 7.074%5.683%5.788%
64
65 Return on Equity 8.138%5.468%5.669%
66 Net Power Costs 1,042,847,44 67,484,891 69,234,037
67 100 Basis Points in Equity
68 Revenue Requirement Impact 90.564.789 4,677,891 5.604,383
69 Rate Base Decrease (739,879,667)(46,785,528)(55.120,325)
REVISED PROTOCOL Page 2.3
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
70 Sales to Ultimate Customers
71 440 Residential Sales
72 0 S 1,346,519,773 1,287,272,744 59,247,029 386,357 59,633,386
73
74 B1 1,346,519,773 1,287.272,744 59,247,029 386,357 59,633,386
75
76 442 Commercial & Industrial Sales
77 °S 2,097,948.247 1,970,908,587 127,039,660 15.459,595 142.499,255
78 P SE
79 PT SG
80
81
82 B1 2,097,948,247 1.970,908,587 127,039,660 15.459,595 142,499.255
83
84 444 Public Street & Highway Lighting
85 °S 20,913,398 20,440,698 472,700 127,821 600,521
86 0 SO
87 B1 20,913,398 20,440,698 472,700 127,821 ~600,521
88
89 445 Other Sales to Public Authority
90 °S 19,032,148 19,032,148
91
92 81 19,032,148 19,032,148
93
94 448 Interdepartental
95 DPW S
96 GP SO
97 81
98
99 Total Sales to Ultimate Customers B1 3,48,413,565 3,297,654,176 186,759,389 15,973,773 202,733,162
100
101
102
103 447 Sales for Resale-Non NPC
104 WSF S 8,352,641 8,352,641
105 8,352,641 8,352,641
106
107 447NPC Sales for Resale-NPC
108 WSF SG 633,900,033 598,981,663 34,918,370 10.371,012 45,289,382
109 WSF SE 1,068,483 1,000,554 67.929 (67,929)
110 WSF SG
111 634,968,516 599,982,217 34,986,299 10,303,083 45,289,382
112
113 Total Sales for Resale 81 643.321,157 608,334,858 34,986,299 10,303,083 45,289,382
114
115 449 Provision for Rate Refund
116 WSF S
117 WSF SG
118
119
120 81
121
122 Total Sales from Electricity B1 4,127,734,722 3,905,989,034 221,745,688 26,276,855 248,022,543
123 450 Forfeited Discounts & Interest
124 CUST S 7,318,368 6,907,026 411,342 411.342
125 CUST SO
126 81 7.318,368 6,907,026 411,342 411,342
127
128 451 Misc Electric Revenue
129 CUST S 6,902,761 6,732,681 170,080 170,080
130 GP SG
131 GP SO 6.131 5,801 331 331
132 B1 6,908.893 6,738,82 170.411 170,411
133
134 453 Water Sales
135 P SG 12,155 11.485 670 670
136 B1 12,155 11.485 670 670
137
138 454 Rent of Electric Property
139 DPW S 10,421,181 10,119.677 301,504 301,504
140 T SG 5,304,571 5.012.368 292,202 292,202
141 T SG 4,886 4.617 269 269
142 GP SO 3,428,294 3,243,433 184.861 184.861
143 B1 19,158,931 18,380,095 778,836 778.836
144
145
REVISED PROTOCOL Page 2.4
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
146
147 456 Other Electric Revenue
148 DMSC S 50,609,068 45,598,459 5.010,609 (5,010,486)123
149 CUST CN
150 OTHSE SE 8.005,386 7,496,442 508,944 508.944
151 OTHSO SO 173,123 163,788 9.335 9.335
152 OTHSGR SG 133,845.735 126,472.845 7.372,890 4.520.941 11.893.830
153
154
155 B1 192.633,312 179.731,534 12.901,778 (489.545)12,412,233
156
157 Total Other Electric Revenues B1 226,031,658 211,768.621 14,263,037 (489,545)13,773,492
158
159 Total Electric Operating Revenues B1 4,353,766,380 4,117,757,655 236,008,725 25,787,310 261,796,035
160
161 Summary of Revenues by Factor
162 S 3,568,017.584 3,375,364,659 192,652,925 10.963,287 203,616,212
163 eN
164 SE 9.073,869 8,496,996 576,873 (67,929)508,944
165 SO 3,607,548 3,413,021 194,527 194,527
166 SG 773.067,379 730,482,978 42,584,400 14,891,952 57,476,353
167 DGP
168
169 Total Electric Operatin9 Revenues 4.353,766.380 4,117.757,655 236.008.725 25,787.310 261.796,035
170 Miscellaneous Revenues
171 41160 Gain on Sale of Utilty Plant - CR
172 DPW S
173 T SG
174 G SO
175 T SG
176 P SG
177 B1
178
179 41170 Loss on Sale of Utilty Plant
180 DPW S
181 T SG
182 B1
183
184 4118 Gain from Emission Allowances
185 P S
186 P SE (3,790,891)(3,549,884)(241.007)17.298 (223,709)
187 B1 (3,790.891 )(3,549.884)(241.007)17,298 (223.709)
188
189 41181 Gain from Disposition of NOX Credits
190 P SE
191 B1
192
193 4194 Impact Housln9 Interest Income
194 p SG
195 B1
196
197 421 (Gain) ! Loss on Sale of Utility Plant
198 DPW S (1,173,272)(1.173,272)
199 T SG (145.556)(137.538)(8.018)(8.018)
200 T SG (68,192)(64,436)(3,756)(3,756)
201 PTO CN
202 PTD SO 12,862 12.169 694 694
203 P SG (810,657)(766,002)(44.655)(44.655)
204 B1 (2.184,816)(2.129,080)(55.736)(55,736)
205
206 Total Miscellaneous Revenues (5,975,707)(5,678,965)(296,743)17,298 (279,445)
207 Miscellaneous Expenses
208 4311 Interest on Customer Deposits
209 CUST S
210 B1
211 Total Miscellaneous Expenses
212
213 Net Misc Revenue and Expense B1 (5,915,707)(5,678,965)(296,743)17,298 (279,445)
214
REVISED PROTOCOL Page 2,5
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DE SCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
215 500 Operation Supervision & Engineering
216 P SG 20,160,039 19,049,523 1,110,515 37,227 1,147,743
217 P SSGCH 1,216,352 1,150,075 66,277 66,277
218 82 21,376,391 20.199,598 1,176,792 37,227 1,214,019
219
220 501 Fuel Related-Non NPC
221 P SE 11,157,930 10,446,562 709.368 1,067 710,434
222 P SE
223 P SE
224 P SSECT
225 P SSECH 3,213,384 3,019,878 193,506 193,506
226 82 14,371.314 13,468,44 902,874 1,067 903,941
227
228 501NPC Fuel Related-NPC
229 P SE 552,903,370 517,752,418 35,150,952 5,304,933 40,55,884
230 P SE
231 P SE
232 P SSECT
233 P SSECH 52,991,371 49,800,292 3,191,079 65,913 3.256,992
234 82 605,894,741 567,552,710 38,342,031 5,370,846 43,712,877
235
236 Total Fuel Related 620,266,055 581,021,150 39,244,905 5,371,913 44,616,817
237
238 502 Steam Expenses
239 P SG 30.407,397 28,732,406 1,674,991 41,453 1,716,44
240 P SSGCH 5,101,692 4,823,710 277,982 277,982
241 82 35,509,090 33.556,116 1,952,973 41,453 1,994,426
242
243 503 Steam From Other Sources-Non-NPC
244 P SE 147 147
245 82 147 147
246
247 503NPC Steam From Other Sources-NPC
248 P SE 3,597,576 3,368,859 228,717 (14,218)214,498
249 62 3,597,576 3,368,859 228,717 (14,218)214,498
250
251 505 Electrc Expenses
252 P SG 2,754,507 2.602,775 151,732 3,675 155,407
253 P SSGCH 1,150,021 1,087,358 62,663 62,663
254 62 3.904,528 3,690,134 214,395 3,675 218,069
255
256 506 Misc. Steam Expense
257 P SG 42,056,734 39.740,040 2,316,694 91,465 2,408,180
258 P SE
259 P SSGCH 1,502,518 1,420,649 81,870 (1 81,869
260 62 43,559,253 41.160,689 2,398,564 91,485 2,490,049
261
262 507 Rents
263 P SG 44.653 423,939 24,714 24,714
264 P SSGCH 1,762 1,666 96 96
265 82 450,415 425,605 24,810 24,810
266
267 510 Maint Supervision & Engineering
268 P SG 4,057,736 3,834,216 223,520 106,827 330,348
269 P SSGCH 1,912,378 1,808,176 104,202 104,202
270 82 5,970,114 5,642,392 327,722 106,827 434,550
271
272
273
274 511 Maintenance of Structures
275 P SG 21,886,763 20,681,131 1,205.632 14,388 1,220,020
276 P SSGCH 938,302 887,176 51,126 (2)51,124
277 82 22,825,065 21,568,307 1,256,758 14,386 1,271,144
278
279 512 Maintenance of 60ller Plant
280 P SG 91,029,755 86,015,382 5,014,372 141,730 5,156,102
281 P SSGCH 3,403,827 3,218,358 185,469 (298)185,170
282 82 94,433,581 89,233,740 5,199,841 141,432 5,341,273
283
284 513 Maintenance of Électric Plant
285 P SG 33,316,896 31,481,635 1,835,260 25,634 1,860,894
286 P SSGCH 410,626 388,252 22,374 22,374
287 82 33,727,522 . 31,869,887 1,857,635 25,634 1,883,269
288
289 514 Maintenance of Misc. Steam Plant
290 P SG 9.660,457 9,128,311 532,146 6,265 538,411
291 P SSGCH 3,020,817 2,856,218 164,599 (11)164,588
292 82 12,681.274 11,984,529 696.745 6,254 702,999
293
294 Total Steam Power Generation B2 898,300,862 843,721,006 54,579,857 5,826,213 60,406,070
REVISED PROTOCOL Page 2.6
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
295 517 Operation Super & Engineering
296 P SG
297 82
298
299 518 Nuclear Fuel Expense
300 P SE
301
302 82
303
304 519 Coolants and Water
305 p SG
306 82
307
308 520 Steam Expenses
309 P SG
310 82
311
312
313
314 523 Electric Expenses
315 P SG
316 82
317
318 524 Misc. Nuclear Expenses
319 P SG
320 82
32.1.
322 528 Maintenance Super & Engineering
323 P SG
324 82
325
326 529 Maintenance of Structures
327 P SG
328 82
329
330 530 Maintenance of Reactor Plant
331 P SG
332 62
333
334 531 Maintenance of Electric Plant
335 P SG
336 62
337
338 532 Maintenance of Misc Nuclear
339 P SG
340 62
341
342 Total Nuclear Power Generation 82
343
344 535 Operation Super & Engineering
345 P DGP
34 P SG 8.95,683 7,649,732 445,951 9,813 455,763
347 P SG 1,289,537 1,218,502 71,034 10,929 81,963
348
349 82 9,385,219 8,868,235 516,985 20,742 537,726
350
351 536 Water For Power
352 P DGP
353 P SG 285,794 270,051 15,743 193 15,936
354 P SG 4,415 4,172 243 (5)238
355
356 82 290,209 274,223 15,986 188 16,174
357
REVISED PROTOCOL Page 2.7
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJ TOTAL
358 537 Hydraulic Expenses
359 P DGP
360 P SG 3,168,766 2,994,214 174,551 1,298 175,850
361 P SG 349,844 330,573 19,271 146 19,417
362
363 62 3,518,610 3,324,787 193,823 1,44 195,267
364
365 538 Electric Expenses
366 P DGP
367 P SG
368 P SG
369
370 62
371
372 539 Misc. Hydro Expenses
373 P DGP
374 P SG 11,894,606 11,239,392 655,214 10,025 665,239
375 P SG 5,705,129 5,390,862 314,267 7,665 321,932
376
377
378 62 17,599,735 16,630,254 969,481 17,690 987,17
379
380 540 Rents (Hydro Generation)
381 P DGP
382 P SG 180,404 170,466 9,938 (31)9,907
383 P SG 3,040 2,873 167 (3)165
384
385 B2 183,444 173,339 10,105 (33)10,072
386
387 541 Maint Supervision & Engineering
388 P DGP
389 P SG 84,358 79,711 4,647 2 4,649
390 P SG
391
392 62 84,358 79,711 4,647 2 4,649
393
394 542 Maintenance of Structures
395 P DGP
396 P SG 1,092,399 1,032,224 60,175 606 60,781
397 P SG 114,713 108,394 6,319 196 6.515
398
399 62 1,207,112 1,140,619 66,494 802 67.296
400
401
402
403
404 543 Maintenance of Dams & Waterways
405 P DGP
406 P SG 1,189,774 1,124.235 65,539 632 66,170
407 P SG 410,765 388,138 22,627 280 22.907
408
409 62 1,600,539 1,512,374 88,166 912 89,077
410
411 544 Maintenance of Eiectric Plant
412 P DGP
413 P SG 1,188,647 1,123,171 65,477 1,140 66,617
414 P SG 327,068 309,052 18,017 531 18,548
415
416 62 1,515,716 1,432,223 83,493 1,671 85,164
417
418 545 Maintenance of Misc. Hydro Plant
419 P DGP
420 P SG 1,925,303 1,819,248 106,055 1.076 107,132
421 P SG 614,013 580,190 33,823 379 34,202
422
423 62 2,539,316 2,399,438 139,878 1,455 141,333
424
425 Total Hydraulic Power Generation B2 37,924,259 35,835,202 2,089,057 44,873 2,133,930
REVISED PROTOCOL Page 2.8
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
426
427 546 Operation Super & Engineering
428 P SG 316.964 299,504 17,460 63 17,523
429 P SSGCT
430 82 316.964 299.504 17,460 63 17.523
431
432 547 Fuel-Non-NPC
433 P SE
434 P SSECT
435 82
436
437 547NPC Fuel-NPC
438 P SE 426,253;895 399,154,711 27,099,184 829.841 27.929,025
439 P SSECT 35,489,120 32.787,645 2.701,475 (1,719,670)981,806
440 82 461,743.015 431.942.356 29.800.659 (889,828)28,910.831
441
442 548 Generation Expense
443 P SG 14,113,019 13,335,604 777,415 10,615 788,03144PSSGCT1,626,465 1,538.170 88.296 1,873 90,169
445 82 15,739,485 14,873,774 865,711 12,488 878.199
446
447 549 Miscellaneous Other
448 P SG 18.635.853 17,609,298 1,026,556 330,179 1,356,734
449 P SSGCT
450 82 18.635,853 17,609,298 1,026,556 330,179 1.356,734
451
452
453
454
455 550 Rents
456 P SG 1.861.263 1.758,736 102.528 102,528
457 P SSGCT
458 82 1.861.263 1,758,736 102,528 102,528
459
460 551 Maint Supervision & Engineering
461 p SG
462 82
463
464 552 Maintenance of Structures
465 P SG 1,350.705 1.276,301 74,404 455 74,859
466 P SSGCT 193.326 182,831 10,495 155 10.651
467 82 1,544.031 1,459.133 84,899 611 85.509
468
469 553 Maint of Generation & Electric Plant
470 P SG 12,141,793 11,472,963 668,830 (210,322)458,508
471 P SSGCT 2,84,046 2,690,598 154,448 447 154,896
472 82 14.986,840 14,163,561 823,279 (209.875)613,404
473
474 554 Maintenance of Misc. Other
475 P SG 1.200,375 1,134,253 66,123 97 66,220
476 P SSGCT 121.530 114,933 6,597 183 6,780
477 82 1,321,906 1.249,186 72,720 280 73000
478
479 Total Other Power Generation B2 516.149.358 483.355.547 32,793,811 (756.083)32,037.728
460
481
482 555 Purchased Power.Non NPC
483 DMSC S (33,207,768)(33.362,478)154.710 (154,710)
484 (33,207.768)(33,362,478)154,710 (154,710)
485
486 555NPC Purchased Power-NPC
487 P SG 409,727.945 387,158,090 22.569,855 7,167,862 29.737,717
488 P SE 79,691,472 74,625,070 5,066,403 (584,201)4,482,201
489 Seasonal Co P SSGC
490 DGP
491 489,419,417 461,783,159 27,636,258 6.583,660 34,219.918
492
493 Total Purchased Power 82 456,211,649 428,420.681 27.790,968 6,428,950 34,219,918
494
495 556 System Control & Load Dispatch
496 P SG 1,514,461 1,431,037 83,424 1,524 84,948
497
498 82 1,514,461 1,431.037 83,424 1,524 84.948
499
500
REVISED PROTOCOL Page 2.9
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
501
502 557 Other Expenses
503 P S (183,792)(150,819)(32,973)7,585,721 7,552,748
504 P SG 48,880,583 46,187,997 2,692,586 (405,742)2,286,844
505 P SGCT 1,122,425 1,060,360 62,065 ,62,065
506 P SE
507 P SSGCT
508 P TROJP
509
510 82 49,819,215 47,097,537 2,721,678 7,179,979 9,901,657
511
512 Embedded Cost Differentials
513 Company Owned Hyd P DGP (66.96,986)(66,096,986)
514 Company Owned Hyd P SG 66,096,986 62,456,034 3,640,951 S,640,951
515 Mid-C Contrct P MC (40,183,729)(39,117,620)(1,066,109)(1,066,109)
516 Mid-C Contract P SG 40,183,729 37,970,209 2,213,520 2,213,520
517 Existing QF Contracts P S 42,736,158 41,709,090 1,027,068 1,027,068
518 Existing QF Contracts P SG (42,736,158)(40,382,0&3)(2,354,120)(2,354,120)
519
520 (3,461,309)3,461,309 3,61,309
521
522 Total Other Power Supply 82 507,545,325 473,487,946 34,057,379 13,610,454 47,667,833
523
524 Total Produc;ion Expense 82 1,959,919,804 1,836,399,700 123,520,104 18,725,457 142,245,561
525
526
527 Summary of Production Expense by Factor
528 S 9,344,598 8,195,793 1,148,805 7,431,011 8,579,816
529 SG 866,990,714 819,232,549 47,758,165 7,408,288 55,166,454
530 SE 1,073,604,242 1,005,349,620 68,254,622 5,537,568 73792,190
531 SNPPH
532 TROJP
533 SGCT 1,122,425 1,060,360 62,065 62,065
534 DGP (66,096,986)(66,096,986)
535 DEU
536 DEP
537 SNPPS
538 SNPPO
539 DGU
54 MC (40,183,729)(39,117,620)(1,066,109)(1,066,109)
541 SSGCT 4,786,369 4,526,532 259,836 2,659 262,495
542 SSECT 35,489,120 32,787,645 2,701,475 (1,719,670)981,806
543 SSGC54SSGCH 18,658,295 17,641,637 1,016,658 (312)1,016,346
545 SSECH 56,204,755 52,820,170 3,384,585 65,913 3,450,499
546 Total Production Expense by Factor 82 1,959,919,804 1,836,399,700 123,520,104 18,725,57 142,245,561
547 560 Operation Supervision & Engineenng
548 T SG 6,088,583 5,753,193 335,389 10,916 346,305
549
550 82 6,088,583 5,753,193 335,389 10,916 346,305
551
552 561 Load Dispatching
553 T SG 9,323,709 8,810,112 513,596 18,577 532,174
554
555 82 .9,323,709 8,810,112 513,596 18,577 532,174
556 562 Station Expense
557 T SG 1,506,478 1,423,494 82,984 2,259 85,243
558
559 82 1,506,78 1,423,494 82,984 2,259 85,243
560
561 563 Overhead Line Expense
562 T SG 245,152 231,648 13,504 206 13,710
563
564 82 245,152 231,648 13,504 206 13,710
565
566 564 Underground Line Expense
567 T SG
568
569 82
570
REVISED PROTOCOL Page 2.10
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
571 565 Transmission of Electricity by Others
572 T SG
573 T SE
574
575
576 565NPC Transmission of Electricity by Others-NPC
577 T SG 116,018,414 109,627,542 6,390,872 1,068,531 7,459,403
578 T SE 1,142,797 1,070,143 72,654 (66,763)5;891
579 117,161,210 110,697,685 6,463,525 1,001,768 7.465,294
580
581 Total Transmission of Electricity by Others 82 117,161,210 110,697,685 6,463.525 1,001,768 7.465,294
582
583 566 Misc. Transmission Expense
584 T SG 2,393,112 2,261,287 131,825 (4,285)127,540
585
586 82 2,393,112 2,261,287 131,825 (4,285)127,540
587
588 567 Rents - Transmission
589 T SG 1,656,975 1,565,700 91,274 509 91,784
590
591 82 1,656,975 1,565,700 91,274 509 91,784
592
593 568 Maint Supervision & Engineering
594 T SG 35,453 33,500 1,953 39 1,992
595
596 82 35,53 33,500 1,953 39 1,992
597
598 569 Maintenance of Structures
599 T SG 4,060,560 3,836,884 223,676 5,35 229.110
600
601 82 4.060,560 3,836,884 223,676 5,435 229,110
602
603 570 Maintenance of Station Equipment
604 T SG 10,549,624 9,968,498 581,126 16,773 597,899
605
606 82 10,549,624 9,968,498 581,126 16,773 597,899
607
608 571 Maintenance of Overhead Lines
609 T SG 19,620,066 18,539,295 1,080,771 3,679 1,084,449
610
611 82 19,620,066 18,539,295 1,080,771 3,679 J,84,449.
612
613 572 Maintenance of Underground Lines
614 T SG 51,599 48,757 2,842 84 2,926
615
616 82 51,599 48,757 2,842 84 2,926
617
618 573 Main! of Misc. Transmission Plant
619 T SG 182,001 171,976 10,026 30 10,056
620
621 82 182,001 171,976 10,026 30 10,056
622
623 Total Transmission Expense B2 172,874,522 163,342,030 9,532,492 1,055,990 10,588,482
624
625 Summary of Transmission Expense by Factor
626 SE 1,142,797 1,070,143 72,654 (66,763)5,891
627 SG 171,731,725 162,271,887 9,459,839 1,122,753 10,582,592
628 SNPT
629 Total Transmission Expense by Factor 172,874,522 163,342,030 9,532.492 1,055.990 10,588,482
630 580 Operation Supervision & Engineering
631 DPW S 1,012,443 930,166 82,277 82,277
632 DPW SNPD 18,641,946 17,781,836 860,111 34,479 894,590
633 82 19,654,389 18,712,001 942,388 34,479 976,867
634
635 581 Load Dispatching
636 DPW S
637 DPW SNPD 13,439,746 12,819,657 620,089 25,714 645,83
638 82 13,439,746 12,819,657 620,089 25,714 645,803
639
640 582 Station Expense
641 DPW S 3,849,839 3,641,292 208,547 4,008 212,555
642 DPW SNPD 29,848 28,71 1,377 46 1,423
643 82 3,879,687 3,669,763 209,924 4,053 213,977
644
REVISED PROTOCOL Page 2.11
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
645 583 Overhead Line Expenses
646 DPW S 5,777,056 5,475,120 301,936 11,118 313,054
647 DPW SNPD 17,767 16,98 820 29 849
648 82 5,794,824 5,492,068 302,756 11,147 313,903
649
650 584 Underground Line Expense
651 DPW S 305 305
652 DPW SNPD
653 82 305 305
654
655 585 Street Lighting & Signal Systems
656 DPW S
657 DPW SNPD 207,152 197,594 9,558 402 9,960
658 82 207,152 197,594 9,558 402 9,960
659
660 586 Meter Expenses
661 DPW S 5,630,733 5,374,972 255,761 9,193 264,954
662 DPW SNPD 1,082,827 1,032,867 49,960 1,765 51,725
663 82 6,713,560 6,407,839 305,721 10,958 316,679
664
665 587 Customer Installation Expenses
666 DPW S 12,458,762 12,009,846 44,917 16,305 465,222
667 DPW SNPD 496 473 23 1 24
668 82 12,459,259 12,010,319 448,940 16,306 465,248
669
670 588 Misc. Distribution Expenses
671 DPW S 1,903,892 1,827,783 76,109 (2,139)73,970
672 DPW SNPD 5,537,508 5,282,016 255,492 (46)255,44
673 82 7,441,400 7,109,799 331,601 (2,186)329,416
674
675 589 Rents
676 DPW S 3,082,013 3,056,279 25,733 33 25,767
677 DPW SNPD 114,242 108,971 5,271 0 5.271
678 82 3,196,255 3,165,250 31,004 33 31.038
679
680 590 Maint Supervision & Engineering
681 DPW S 1.168,290 1,079,917 88,373 3,126 91,498
682 DPW SNPD 6,367,680 6,073,885 293,795 10,425 304,219
683 82 7,535.970 7,153,802 382,168 13,550 395.718
684
685 591 Maintenance of Structures
686 DPW S 1,855,991 1,709,849 146,142 146,142
687 DPW SNPD 159,999 152,617 7,382 7,382
688 82 2,015,990 1,862,466 153,524 153,524
689
690 592 Maintenance of Station Equipment
691 DPW S 10.926,178 10,135,064 791,114 25,517 816,631
692 DPW SNPD 1,874,179 1,787,708 86,472 3,387 89.858
693 82 12,800,357 11,922,771 877,586 28,904 906;490
694 593 Maintenance of Overhead Lines
695 DPW S 82,112,317 77,011,054 5,101,264 100,942 5,202,206
696 DPW SNPD 1,224,337 1,167,848 56,489 951 57,440
697 82 83,336,655 78,178.902 5,157,753 101,893 5,259,646
698
699 594 Maintenance of Underground Lines
700 DPW S 22,479,205 21,746,414 732,791 18.984 751,774
701 DPW SNPD 7,391 7,050 341 11 352
702 82 22,486,595 21,753,464 733.132 18,995 752,126
703
704 595 Maintenance of Line Transformers
705 DPW S 24,717 24,717
706 DPW SNPD 1,081,164 1,031,280 49,883 1,698 51,581
707 82 1,105,880 1,055.997 49.883 1.698 51,581
708
709 596 Maint of Street Lighting & Signal Sys.
710 DPW S 4,217,687 4,084,975 132,712 4,670 137.382
711 DPW SNPD
712 82 4.217.687 4,084,975 132,712 4,670 137.382
713
REVISED PROTÖCOL Page 2.12
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAl
714 597 Maintenance of Meters
715 DPW S 4,536,131 4,239,464 296,667 10,873 307,541
716 DPW SNPD 1,100,892 1,050,098 50,793 1,662 52,455
717 B2 5,637,023 5,289,562 347,461 12.535 359,996
718
719 598 Maint of Misc. Distrbution Plant
720 DPW S 2,967,838 2,882,374 85,465 128 85,592
721 DPW SNPD 578,169 551,493 26,676 2.944 29,620
722 82 3,546,007 3,433,867 112,141 3,072 115,212
723
724 Total Distribution Expense B2 215,468,741 204,320,401 11,148,340 286,225 11,434,564
725
726
727 Summary of Distribution Expense by Factor
728 S 164,003,397 155,229,589 8,773,808 202,757 8,976.565
729 SNPD 51,465,34 49,090,812 2,374,532 83.467 2,457,999
730
731 Total Distribution Expense by Factor 215,468,741 204,320,401 11,146,340 286,225 11,434,564
732
733 901 Supervision
734 CUST S 102,805 87,017 15,788 56 15,844
735 CUST CN 2,451,290 2.356,068 95,222 4,004 99.226
736 82 2,554,096 2,443,085 111,010 4,060 115,070
737
738 902 Meter Reading Expense
739 CUST S 20,750,177 19,136,393 1,613,784 62.513 1.676,297
740 CUST CN 1.770,041 1,701,283 68,758 2,274 71,033
741 82 22,520,219 20.837,676 1,682,543 64,787 1.747,330
742
743 903 Customer Receipts & Coliections
744 CUST S 7,352,864 7,023,206 329,657 10,345 340,002
745 CUST CN 48,927,462 47,026,843 1,900,620 58,841 1,959,461
746 82 56,280,326 54,050,049 2,230,277 69,186 2,299,463
747
748 904 Uncollectible Accounts
749 CUST S 12,149,005 11,677,783 471.222 471,222
750 P SG
751 CUST CN 26,790 25,749 1,041 1,041
752 82 12,175,795 11,703,532 472,263 472,263
753
754 905 Misc. Customer Accounts Expense
755 CUST S 12,390 12,390
756 CUST CN 242,182 232,774 9,08 302 9,710
757 82 254,572 245.164 9,408 302 9,710
758
759 Total Customer Accounts Expense B2 93,785,007 89,279,506 4,505,501 138.335 4.643,836
760
761 Summary of Customer Accts Exp by Factor
762 S 40,367,241 37,936,789 2,430,452 72,914 2,503,366
763 CN 53,417,766 51,342,717 2,075,049 65,421 2,140,470
764 SG
765 Total Customer Accounts Expense by Factor 93.785,007 89,279,506 4,505,501 138,335 4,643,836
766
767 907 Supervision
768 CUST S
769 CUST CN 286,417 275,290 11,126 396 11.523
770 82 286,417 275.290 11.126 396 11,523
771
772 908 Customer Assistance
773 CUST S 63,240,907 56,710,070 6,530,837 (4,992,585)1,538,252
774 CUST CN 2,861,099 2,749,957 111,141 4,430 115,571
775
776
777 B2 66,102,006 59.480,027 6,641.979 (4,988.155)1.653,823
778
REVISED PROTOCOL Page 2.13
Year-End
FERC 8US UNADJUSTED RESULTS IDAHO
ACCT DE SCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
779 909 Informational & Instructional Adv
780 CUST S 349.724 349.724
781 CUST CN 4.574.542 4.396.841 177.701 (1,426)176,275
782 82 4.924.267 4.746.566 177.701 (1,426)176.275
783
784 910 Misc. Customer Service
785 CUST S
786 CUST CN 150.055 144.226 5.829 8 5.837
787
788 82 150.055 144.226 5.829 8 5.837
789
790 Total Customer Service Expense 82 71,46,744 64,626,109 6,836,635 (4,989,177)1,847,458
791
792
793 Summary of Customer Service Exp by Factor
794 S 63,590.631 57.059,794 6.530,837 (4,992.585)1.538.252
795 CN 7,872,112 7,566,315 305.797 3,408 309,206
796
797 Total Customer Service Expense by Factor 82 71.462,744 64.626,109 6,836,635 (4,989,17)1.47,458
798
799
800 911 Supervision
801 CUST S
802 CUST CN
803 82
804
805 912 Demonstration & Sellng Expense
806 CUST S
807 CUST CN
808 82
809
810 913 Advertising Expense
811 CUST S
812 CUST CN
813 82
814
815 916 Misc. Sales Expense
816 CUST S
817 CUST CN
818 82
819
820 Total Sales Expense 82
821
822
823 Total Sales Expense by Factor
824 S
825 CN
826 Total Sales Expense by Factor
827
828 Total Customer Service Exp Including Sales 82 71,462,744 64,626,109 6,836,635 (4,989,177)1,847,458
829 920 Administrative & General Salaries
830 PTD S (4,135,538)(5,140,020)1,004,482 (1.004,482)
831 CUST CN
832 PTO SO 77.010.359 72,857,792 4.152.566 180,813 4.333,380
833 62 72,874.820 67.717,772 5.157,048 (823,669)4.333,380
834
835 921 Offce Supplies & expenses
836 PTO S (568.262)(568,12)150 150
837 CUST CN
838 PTO SO 11.599.349 10,973.887 625,462 (31,318)594,144
839 82 11,031,087 10,405,475 625.612 (31,318)594,294
840
841 922 A& G Expenses Transferred
842 PTO S
843 CUST CN
844 PTO SO (25.866,776)(24,471,983)(1,394.793)69,014 (1.325,779)
845 62 (25,866.776)(24,471.983)(1,394,793)69,014 (1.325,779)
846
REVISED PROTOCOL Page 2.14
Year.End
FERC 8US UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
847 923 Outside Services
848 PTD S 630 630
849 CUST eN
850 PTD SO 11.038.720 10.443,88 595.232 (25,987)569.245
851 82 11.039,350 10,444.118 595,232 (25,987)569,245
852
853 924 Propert Insurance
854 PTD SO 23,970,318 22,677,786 1,292,532 1,292,532
855 B2 23.970,318 22,677786 1,292,532 1,292,532
856
857 925 Injuries & Damages
858 PTD SO 7,434,336 7,033,460 400,876 113,441 514,316
859 B2 7,434,336 7,033,60 400,876 113,441 514,316
860
861 926 Employe Pensions & 8enefis
862 LABOR S
863 eUST eN
864 LABOR SO
865 B2
866
867 927 Franchise Requirements
868 DMse S
869 DMse SO
870 82
871
872 928 Regulatory Commission Expense
873 DMSC S 11,943,931 11.526,839 417,092 4,691 421,783
874 eUST eN
875 DMSC SO 2,197,338 2,078,852 118,485 78 118,563
876 FERC SG 2,323,478 2,195,489 127,989 127.989
877 B2 16,464,747 15,801.180 663,566 4,769 668.335
878
879 929 Duplicate Charges
880 LABOR S
881 LABOR SO (3,420,843)(3,236.383)(184,459)(246)(184.706)
882 B2 (3,420.843)(3,236,383)(184,459)(246)(184,706)
883
884 930 Mise General Expenses
885 PTD S 5,290,870 5.282,370 8,500 201,496 209,996
886 CUST CN 4,500 4.325 175 (44)131
887 LABOR SO 14,400,017 13,623.536 776.480 2,503,642 3.280,122
888 82 19.695,387 18.910,232 785.155 2.705.094 3,490.249
889
890 931 Rents
891 PTD S 961,066 961,066
892 PTD SO 5,238,518 4.956.045 282,472 282,472
893 B2 6,199.584 5,917,112 282,472 282,472
894
895 935 Maintenance of General Plant
896 G S 15.577 15,577
897 eUST eN
898 G SO 23,181,924 21.931.904 1,250.020 9.939 1,259,958
899 82 23,197,501 21,947,481 1.250.020 9,939 1,259.958
900
901 Total Administrative & General Expense 82 162,619.511 153.146250 9.473,261 2,021,036 11.494,297
902
903 Summary of A&G Expense by Factor
904 S 13.508.275 12,078,050 1,430.224 (798,295)631,929
905 SO 146.783,259 138,868,386 7.914,873 2,819,375 10,734.248
906 SG 2.323,478 2.195,489 127,989 127,989
907 CN 4,500 4,325 175 (44)131
908 TotalA&G Expense by Factor 162,619,511 153.146,250 9,473,261 2.021,036 11.94,297
909
910 Total O&M Expense 82 2,676.130,29 2.511.113,996 165,016.333 17,237,866 182.254, 199
REVISED PROTOCOL Pag.e 2.15
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
911 403SP Steam Depreciation
912 P SG 23.110.000 21.836.987 1.273.014 1.273.014
913 P SG 25.963.107 24.532.930 1,430.177 1,430.177
914 P SG 52.664.788 49.763,750 2.901.039 837.592 3,738.631
915 P SSGCH 7.785.936 7.361.694 424.242 424.242
916 83 109.523.832 103,495.360 6.028,472 837.592 6.866,064
917
918 403NP Nuclear Depreciation
919 P SG
920 83
921
922 403HP Hydro Depreciation
923 P SG 3.645,29 3.44.621 200.808 200.808
924 P SG 1.016,91 960,98 55.993 55,993
925 P SG 7.347.198 6.942,478 404.720 24.509 429.229
926 P SG 3,441.241 3.251,681 189.561 189.561
927 83 15,450.360 14.599.277 851.083 24.509 875.592
928
929 4030P Other Production Depreciation
930 P SG 124.817 117,942 6.876 6.876
931 P SG 94.515.821 89.309,419 5.206.402 1.050,470 6,256,872
932 P SSGCT 2.544,778 2.406.630 138.148 138,148
933 P SSGCH
934 83 97.185,416 91.833.990 5.351,425 1.050,470 6,401.895
935
936 403TP Transmission Depreciation
937 T SG 11.260.768 10.640,469 620.299 620.299
938 T SG 12.574.497 11.881.831 692.666 692.666
939 T SG 39.057.941 36.906.435 2.151.506 1.180,474 3.331.980
940 83 62.893.206 59,428.735 3,464,471 1.180,474 4.644,945
941
942
943
944 403 Distribution Depreciation
945 360 Land & Land R;ghl. DPW S 292.392 274.904 17,488 17,488
946 361 Strctre DPW S 1.016.944 993.937 23.007 23.07
947 362 Stalion Equipmnt DPW S 17.275.368 16.659.953 615,415 615,415
948 363 Storage Battery Eqi DPW S 91.113 91.113
949 364 Poles & Towers DPW S 33.365.759 31.345.364 2.020.396 1.199 2.021.595
950 365 OH Conductrs DPW S 18.807.119 17.850.287 956.832 956.832
951 366 UGConduif DPW S 7.529.925 7.372.273 157.652 157,652
952 367 UG Conductr DPW S 17,412.373 16.938.733 473.640 473,640
953 368 Line Trans DPW S 26.759.726 25.342.167 1,417.559 1,417.559
954 369 Services DPW S 11.531.258 11.013.789 517.468 517,468
955 370 Meters DPW S 6.509.338 6.062.663 44.676 44.676
956 371 Ins Cust Prem DPW S 496.358 488.788 7.570 7.570
957 372 Leesed Propey DPW S
958 373 Street Lighting DPW S 2.255.605 2.226.651 28.954 28.954
959 83 143.343.279 136.660.621 6.682.658 1,199 6.683,857
960
961 403GP General Depreciation
962 G-SITUS S 12.310.835 11.555.600 755.235 (173)755.062
963 PT SG 502.163 474.501 27.662 27,662
964 PT SG 706.142 667.244 38.898 38,898
965 P SE 26.236 24,568 1.668 1.668
966 CUST CN 1.759.170 1.690.834 68.336 68.336
967 G-SG SG 5.229.908 4.941.819 288.089 2.848 290,938
968 PTD SO 14.946,453 14.140,508 805.945 8,412 814,358
969 G-SG SSGCT 6.010 5.684 326 326
970 G-SG SSGCH 144.595 136.716 7.879 7.879
971 83 35.631.512 33.637,474 1.994,038 11,087 2.005.125
972
973 403GVO General Vehicles
974 G-SG SG
975 83
976
977 403MP Mining Depreciation
978 P SE
979 83
980
REVISED PROTOCOL Page 2.16
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
981 403EP Experimental Plant Depreciation
982 P SG
983 P SG
984 B3
985 4031 ARO Depreciation
986 P S
987 B3
988
989
990 Total Depreciation Expense 83 464,027,603 439,655,457 24,372,146 3,105,332 27,477478
991
992 Summary S 155,654,113 148,216,221 7,437,892 1,026 7,438.918
993 DGP
994 DGU
995 SG 281,160,312 265,672,602 15,487,710 3,095,893 18.583,03
996 SO 14,946,453 14,140,508 805,945 8,412 814,358
997 CN 1,759,170 1,690,834 68,336 68,338
998 SE 26,236 24,568 1,668 1,668
999 SSGCH 7,930,531 7,498,410 432,121 432,121
1000 SSGCT 2,550,788 2,412,314 138,474 138,474
1001 Total Depreciation Expense 8y Factor 464,027,603 439,655,457 24,372,146 3,105,332 27,477,478
1002
1003 404GP Amort of L T Plant. Capital Lease Gen
1004 I.SITUS S 1,345,062 1,345,02
1005 I-8G SG
1006 PTD SO 929,374 879,260 50,114 50,114
1007 P SG
1008 CUST CN 249,571 239,876 9,695 9,695
1009 P SG
1010 B4 2,524:007 2,464,199 59,809 59,809
1011
1012 404SP Amort of L T Plant - Cap Lease Steam
1013 P SG
1014 P SG
1015 84
1016
1017 4041P Amort of L T Plant. Intangible Plant
1018 I-SITUS S 94,304 73,772 20,532 20,532
1019 P SE 14,498 13,577 922 922
1020 I-8G SG 8,952,161 8,459,032 493,130 25,402 518,532
1021 PTD SO 13,131,339 12,423,268 708,070 9,540 717,611
1022 CUST CN 5,000,879 4,806,617 194,262 194,262
1023 I.SG SG 2,615,13 2,471,343 144,070 5,786 149,856
1024 I-SG SG 310,432 293,332 17,100 17,100
1025 P SG
1026 I.SG SSGCT
1027 I.SG SSGCH 54,934 51,940 2,993 2,993
1028 P SG 16,758 15,835 923 923
1029 84 30,190,717 28,608,715 1,582,003 40,728 1.622,731
1030
1031 404MP Amort of L T Plant. Mining Plant
1032 P SE
1033 84
1034
1035 4040P Amort of L T Plant. Other Plant
1036 P SG
1037 84
1038
1039
1040 404HP Amortization of Other Electric Plant
1041.P SG 6,589 6,226 363 363
1042 P SG 40,392 38,167 2,225 2,225
1043 P SG
1044 84 46,981 44,393 2,588 2,588
1045
1046 Total AmortizatIon of Limited Term Plant 84 32,761,706 31,117,307 1,644,399 40,728 1,685,127
1047
1048
1049 405 Amortization of Other Electric Plant
1050 GP S
1051
1052 84
1053
REVISED PROTOCOL Page 2.17
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1054 406 Amortization of Plant Acquisition Adj
1055 P S
1056 P SG
1057 P SG
1058 P SG 5,479.353 5,177.523 301.830 301.830
1059 P SO
1060 B4 5,79.353 5,177.523 301,830 301.830
1061 407 Amort of Prop Losses. Unrec Plant, etc
1062 DPW S (36.176)(36,176)
1063 GP SO
1064 P SG-P 3,479.961 3.288,268 191,694 (191.694)0
1065 P SE
1066 P SG
1067 P TROJP 2.013,725 1.900.202 113.523 113.523
1068 64 5,57,511 5.152.294 305.217 (191.694)113.523
1069
1070 Total Amortization Expense 84 43,698,570 41,447,124 2,251,446 (150,966)2,100,480
1071
1072
1073
1074 Summary of Amortization Expense by Factor
1075 S 1,403.190 1.382,658 20.532 20,532
1076 SE 14,498 13,577 922 922
1077 TROJP 2,013.725 1,900,202 113.523 113,523
1078 DGP
1079 DGU
1080 SO 14;060,713 13.302.528 758.184 9,540 767.724
1081 SSGCT
1082 SSGCH 54,934 51,940 2,993 2,993
1083 SG-P 3,479,961 3,288,268 191,694 (191.694)0
1084 CN 5,250,450 5,046,493 203.957 203.957
1085 SG 17,421,098 16,461.458 959.641 31,188 990.829
1086 Total Amortization Expense by Factor 43,698.570 41,447,124 2.251,446 (150.966)2.100,480
1087 408 Taxes Other Than Income
1088 DMSC S 25,320,436 25.320,436
1089 GP GPS 87,317,409 82,609,064 4,708.345 413,992 5,122,338
1090 GP SO 10.522.150 9,954,773 567.377 567.377
1091 P SE 717,492 671.877 45.615 45.615
1092 P SG
1093 DMSC OPRV-ID
1094 GP EXCTAX
1095 GP SG
1096
1097
1098
1099 Total Taxes Other Than Income 85 123,877,487 11,556,149 5,321,337 413,992 5,735,330
1100
1101
1102 41140 Deferred Investment Tax Credit - Fed
1103 PTD DGU (1,874.204)(1,672.710)(201,494)(201,494)
1104
1105 67 (1,874.204)(1,672710)(201,494)(201,494)
1106
1107 41141 Deferred Investment Tax Credit - Idaho
1108 PTD DGU
1109
1110 67
1111
1112 Total Deferred ITC B7 (1,874,204)(1,672,710)(201,494)(201,494)
1113
REVISED PROTOCOL Page 2.18
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1114
1115 427 Interest on Long-Term Debt
1116 GP S 177,481 177.481
1117 GP SNP 369.236.117 349.630.585 19.605,532 19,605.532
1118 B6 369,236,117 349,630,585 19,605,532 177,481 19.783.014
1119
1120 428 Amortization of Debt Disc & Exp
1121 GP SNP 6.571.354 6,222,431 348,923 348,923
1122 B6 6,571.354 6,222,431 348.923 348,923
1123
1124 429 Amortization of Premium on Debt
1125 GP SNP (2.718)(2.574)(144)(144)
1126 B6 (2.718)(2,574)(144)(144)
1127
1128 431 Other Interest Expense
1129 NUTIL OTH
1130 GP SO
1131 GP SNP 10,264.106 9,719,107 544,999 544.999
1132 B6 10.264.106 9.719.107 544.999 544,999
1133
1134 432 AFUDC . Borrowed
1135 GP SNP (35.186.532)(33.318,213)(1.868.319)(1.868.319)
1136 (35,186.532)(33.318,213)(1,868.319)(1.868,319)
1137
1138 Total Elec. Interest Deductions for Tax B6 350.882.327 332,251.336 18.630.991 177,481 18.808,72
1139
1140 Non-Utilty Portion of Interest
1141 427 NUTIL NUTIL
1142 428 NUT1L NUTIL
1143 429 NUTIL NUTIL
1144 431 NUTIL NUTIL
1145
1146 Total Non-utilty Interest
1147
1148 Total Interest Deductions for Tax B6 350,882.327 332,251.336 18,630.991 177,481 18,808,72
1149
1150
1151 419 Interest & Dividends
1152 GP S
1153 GP SNP (63,955,322 (60.559.451 )(3.395.871 160.213 (3,235,657)
1154 Totai Operating Deductions for Tax B6 5, 2 . 51 3. 95. 71 6 , 13
1155
1156
1157 41010 Deferred Income Tax - Federal-DR
1158 GP S 26.529,700 26,102,344 427.356 (347,371)79.985
1159 P TROJD 735.881 694,228 41.653 41.653
1160 P SSGCH 26.126 24.702 1,424 1,424
1161 LABOR SO 37.814,180 35,775.157 2,039.023 (275,926)1,763.097
1162 GP SNP 35,849.593 33,946.068 1,903.525 1,903.525
1163 P SE 23,499.301 22,005,328 1,493,973 (75,548)1,418,425
1164 PT SG 51,291,699 48,466.297 2,825,402 2.926.043 5.751,445
1165 GP GPS 31,266,440 29.580,485 1,685.955 1,685,955
1166 TAXDEPR TAXDEPR 615.608,170 584,405,196 31,202.974 31,202.974
1167 CUST BADDEBT 443,332 426,136 17.196 17,196
1168 CUST CN 22,893 22.004 889 889
1169 P IBT 348,313 318.675 29,638 (29.638)
1170 DPW SNPD 67,978 64,842 3.136 3,136
1171 B7 823,503.606 781,831,462 41,672,144 2.197.560 43,869,704
1172
REVISED PROTOCOL Page 2.19
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1173
1174
1175 41110 Deferred Income Tax - Federal-CR
1176 GP S (26,854,405)(25,660,209)(1,194,196)322,685 (871,511)
1177 P SE (17,999,483)(16,855,162)(1,144,321 )228,207 (916,114)
1178 P SSGCH (538,368)(509,033)(29,335)(29,335)
1179 GP SNP (31,616,890)(29,938,111 )(1,678,779)(1,678,779)
1180 PT SG (7,932,473)(7,495,513)(436,960)(1,099,084)(1,536,044)
1181 DPW CIAC (20,332,444)(19,394,336)(938,108)(938,108)
1182 LABOR SO (28,202,710)(26,681,958)(1,520,752)(5,505)(1,526,257)
1183 PT SNPD (1,949,167)(1,859,235)(89,932)(89,932)
1184 CUST BADDEBT
1185 P SGCT (356,221)(336,523)(19,698) .(19,698)
1186 BOOKDEPR SCHMDEXP (203,344,850)(192,664,558)(10,680,292)(10,680,292)
1187 P TROJD (1,332,481 )(1,257,059)(75,422)(75,422)
1188 P IBT (427,931)(391,518)(36,413)36,413
1189
1190
1191 B7 (340,887,423)(323,043,216)(17,844,207)(517,284)(18,361,491)
1192
1193 Total Deferred Income Taxes B7 482,616,183 458,788,246 23,827,937 1,680,276 25,508,213
1194 SCHMAF Addiüons - Flow Through
1195 SCHMAF S
1196 SCHMAF SNP
1197 SCHMAF SO
1198 SCHMAF SE
1199 SCHMAF TROJP
1200 SCHMAF SG
1201 B6
1202
1203 SCHMAP Additions - Permanent
1204 P S 20,000 20,000
1205 P SE 90,872 85,095 5,777 5,777
1206 LABOR SNP
1207 SCHMAP-SO SO 12,568,198 11,890,94 677,705 677,705
1208 SCHMAP SG
1209 DPW BADDEST
1210 B6 12,679,071 11,995,589 683,482 683,482
1211
1212 SCHMAT Additions - Temporary
1213 SCHMAT-SITLS 57,590,033 56,886,057 703,976 (591,588)112,388
1214 P SSGCH
1215 DPW CIAC 53,575,515 51,103,623 2,471,892 2,471,892
1216 SCHMA T -SNP SNP 83,309,767 78,886,223 4,423,544 4,423,544
1217 P TROJD 1,572,028 1,483,047 88,981 88,981
1218 P SGCT 938,633 886,730 51,903 51,903
1219 SCHMAT-SE SE 27,051,042 25,331,266 1,719,776 (741)1,719,635
1220 P SG 20,901,884 19,750,504 1,151,380 2,896,061 4,047,441
1221 CUST CN
1222 SCHMA T -SO SO 23,130,941 21,883,670 1,247,271 14,506 1,261,777
1223 SCHMAT -5NP SNPD 5,136,011 4,899,043 236,968 236,968
1224 DPW BADDEBT
1225 P SSGCT
1226 BOOKDEPR SCHMDEXP 535,808,937 507,666,616 28,142,321 28,142,321
1227 B6 809,014,791 768,776,781 40,238,011 2,318,239 42,556,249
1228
1229 TOTAL SCHEDULE - M ADDITIONS B6 821,693,862 780,772,370 40,921,492 2,318,239 43,239,731
1230
REVISED PROTOCOL Page 2.20
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1231 SCHMDF Deductions - Flow Through
1232 SCHMDF S
1233 SCHMDF DGP
1234 SCHMDF DGU
1235 B6
1236 SCHMDP Deductions - Permanent
1237 SCHMDP S 904 904
1238 P SE 840,899 787,439 53,460 53,460
1239 PTD SNP 381,063 360,830 20,234 20,234
1240 SCHMDP IBT
1241 P SG
1242 SCHMDP-SO SO 26,365,079 24,943,416 1,421,663 1,421,663
1243 B6 27,587,945 26,092,589 1,495,356 1,495,356
1244
1245 SCHMDT Deductions - Temporary
1246 GP S 39,346,405 38,274,657 1,071.746 (915,314)156,434
1247 DPW BADDEBT 1,168,170 1,122.860 45.310 45.310
1248 SCHMDT-SNF SNP 94.462.842 89,447,097 5,015,745 5,015,745
1249 SCHMDT CN 60.323 57,980 2,343 2.343
1250 SCHMDT SSGCH 68,82 65,091 3,751 3,751
1251 CUST DGP
1252 P SE 41,542,935 38,901.834 2.641,101 401.512 3,042.613
1253 SCHMDT-SG SG 135.152,429 127,707.560 7.44.869 7,710.054 15,154,923
1254 SCHMDT-GP~ GPS 82.386,340 77943,889 4,442,451 4,442,451
1255 SCHMDT -SO SO 48,456.951 45,844,047 2,612.904 (1,053,989)1,558,915
1256 TAXDEPR TAXDEPR 1,622,113,173 1,539,894,065 82,219,108 82.219.108
1257 DPW SNPD 179,120 170.856 8.264 8,264
1258 B6 2.064.937.530 1,959,429,935 105,507.595 6.142,263 111.649,859
1259
1260 TOTAL SCHEDULE - M DEDUCTIONS B6 2,092,525,75 1,985,522,523 107,002,952 6,142,263 113.145.215
1261
1262 TOTAL SCHEDULE - M ADJUSTMENTS B6 (1,270,831,613)(1,204,750,154)(66,081,459)(3,824,025)(69,905,484)
1263
1264
1265
1266 40911 State Income Taxes
1267 IBT IBT (22,655,140)(20.727,379)(1.927,760)45,494 (1,882,266)
1268 IBT SE
1269 PTC P SG (70,472)(70,472)
1270 IBT IBT
1271 Total State Tax Expense (22,655,140)(20,727,379)(1,927,760)(24,978)(1,952,739)
1272
1273
1274 Calculation of Taxable Income:
1275 Operating Revenues 4.353.766,380 4,117,757.655 236.008.725 25.787.310 261.796.035
1276 Operating Deductions:
1277 o & M Expenses 2.676,130.329 2.511,113.996 165.016,333 17.237,866 .182.254,199
1278 Depreciation Expense 46,027,603 439,655,457 24.372.146 3.105.332 27,477,478
1279 Amortization Expense 43.698,570 41,447.124 2,251,446 (150.966)2,100,480
1280 Taxes Other Than Income 123,877,487 118.556.149 5.321,337 413,992 5,735,330
1281 Interest & Dividends (AFUDC-Eqult)(63.955,322)(60,559,451 )(3.395.871 )160.213 (3.235.657)
1282 Misc Revenue & Expense (5.975.707)(5.678.965)(296.743)17,298 (279,445)
1283 Total Operating Deductions 3.237.802,959 3.044.534.311 193,268,649 20,783,736 214,052,385
1284 Other Deductions:
1285 Interest Deductions 350,882,327 332,251,336 18,630,991 177,481 18,808.72
1286 Interest on PCRBS
1287 Schedule M Adjustments (1,270,831,613)(1,204,750,154)(66,081,459)(3,824,025)(69,905,484)
1288
1289 income Before State Taxes (505,750.519)(463,778,145)(41,972,374)1,002.068 (40,970,306)
1290
1291 State Income Taxes (22,655,140)(20,727,379)(1,927,760)(24,978)(1,952,739)
1292
1293 Total Taxable Income (483,095,380)(443,050,766)(40,044,614)1,027,046 (39,017,567)
1294
1295 Tax Rate 35.0%35.0%35.0%35.0%35.0%
1296
1297 Federal Income Tax - Calculated (169,083,383)(155.067,768)(14,015,615)359,466 (13,656.149)
1298
1299 Adjustments to Calculated Tax:
1300 40910 PMI P SE
1301 40910 REC P SG (3,821,447)(3,821,447)
1302 40910 P SO
1303 40910 IRS Sette LABOR S
1304 Federal Income Tax Expense (169,083,383)(155,067,768)(14,015,615)(3,461,981)(17,477,596)
1305
1306 Total Operating Expenses 3,590,761,738 3,386,414,150 204,347,587 18,816,839 223,164,426
REVISED PROTOCOL Page 2.21
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1307 310 Land and Land Rights
1308 P SG 2.329.517 2,201,196 128.321 128.321
1309 P SG 34.798.44 32.881.574 1,916,872 1,916.872
1310 P SG 56,303,435 53.201.961 3,101.474 3,101,474
1311 P S
1312 P SSGCH 2,448.255 2.314.854 133,401 133,401
1313 68 95,879.653 90,599.585 5,280.068 5,280.068
1314
1315 311 Structures and Improvements
1316 P SG 234.107,411 221.211.609 12,895.802 12.895.802
1317 P SG 325,036.982 307.132.327 17,904.655 17.904.655
1318 P SG 221,770.821 209.554.580 12.216,241 12,216.241
1319 P SSGCH 57.386.063 54.259.197 3.126,866 3,126.866
1320 68 838.301.276 792,157.712 46.143,564 46.143,564
1321
1322 312 60iler Plant Equipment
1323 P SG 698,182.038 659.722.695 38,459.343 38,459.343
1324 P SG 658.624,890 622,344.552 36.280.338 36.280,338
1325 P SG 1,442.122,538 1.362.683.24a 79.439.290 33,484.991 112.924,281
1326 P SSGCH 325,425.382 307.693.523 17.731,858 17,731.858
1327 68 3,124.354,84a 2,952,444,018 171.910,830 33.4a4.991 205.395,820
1328
1329 314 Turbogenerator Units
1330 P SG 139,149.055 131.4a4,032 7,665.023 7,665.023
1331 P SG 141,986,218 134.164.910 7.821.308 7.821,308
1332 P SG 4a7,922.642 4a1,045.433 26.877,209 26,877.209
1333 P SSGCH 63,734.933 60.262,128 3.472.805 3,472.805
1334 68 832.792,88 786.956.504 45.836.344 45.836,344
1335
1336 315 Accessory Electric Equipment
1337 P SG 87.739,621 82,906.4a6 4.833.135 4.833,135
1338 P SG 138,674.494 131.035.612 7.638.882 7.638,882
1339 P SG 74.099.755 70,017.971 4.081,783 4.081.183
1340 P SSGCH 66.352.508 62.737,076 3.615.432 3.615,32
1341 68 366.866.378 346.697.14a 20.169.232 20.169,232
1342
1343
1344
1345 316 Mlsc Power Plant Equipment
1346 P SG 4.786,848 4,523,164 263,683 263.683
1347 P SG 5.245,086 4,956.160 288.925 288.925
1348 P SG 15.109.785 14,277,463 832.322 832.322
1349 P SSGCH 4.037.788 3.817.776 220.012 220.012
1350 68 29.179.506 27.574.563 1.604.943 1.604.943
1351
1352 317 Steam Plant ARO
1353 P S
1354 68
1355
1356 SP Unclassified Steam Plant - Account 300
1357 P SG 787.304 743.936 43,369 43.369
1358 68 787.304 743.936 43.369 43.369
1359
1360
1361 Total Steam Production Plant B8 5,288,161,813 4,997,173,464 290,988,349 33,484,991 324,473.340
1362
1363
1364 Summary of Steam Production Plant by Factor
1365 S
1366 DGP
1367 DGU
1368 SG 4.768.776.885 4.506.088.910 262.687.975 33,4a4.991 296,172,966
1369 SSGCH 519.384.929 491.084,554 28,300.374 28.300.374
1370 Total Steam Production Plant by Factor 5.288,161.813 4.997.173,64 290.988.349 33,484.991 324,473.340
1371 320 Land and Land Rights
1372 P SG
1373 P SG
1374 68
1375
1376 321 Structures and Improvements
1377 P SG
1378 P SG 68
1379
REVISED PROTOCOL Page 2.22
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1380
1381 322 Reactor Plant Equipment
1382 P SG
1383 P SG
1384 B8
1385
1386 323 Turbogenerator Units
1387 P SG
1388 P SG
1389 B8
1390
1391 324 Land and Land Rights
1392 P SG
1393 P SG
1394 B8
1395
1396 325 Misc. Power Plant Equipment
1397 P SG
1398 P SG
1399 B8
1400
1401
1402 NP Unclassified Nuclear Plant - Acct 300
1403 P SG
1404 B8
1405
1406
1407 Total Nuclear Production Plant B8
1408
1409
1410
1411 Summary of Nuclear Production Plant by Factor
1412 DGP
1413 DGU
1414 SG
1415
1416 Total Nuclear Plant by Factor
1417
1418 330 Land and Land Rights
1419 P SG 10,621,118 10,036,054 585,064 585,064
1420 P SG 5,270,019 4,979,720 290,299 290,299
1421 P SG 3,645,604 3,44,786 200,818 200,818
1422 P SG 672,873 635,808 37,065 37,065
1423 B8 20,209,614 19,096,368 1,113,246 1,113,246
1424
1425 331 Structures and Improvements
1426 P SG 21,272,790 20,100,979 1,171,811 1,171,811
1427 P SG 5,299,236 5,007,327 291.908 291,908
1428 P SG 69,738,251 65,896,721 3,841,530 3,841,530
1429 P SG 7,984,198 7,544,388 439,809 439,809
1430 B8 104,294,475 98,549,416 5,745,059 5,745,059
1431
1432 332 Reservoirs, Dams & Waterways
1433 p SG 151,296,614 142,962,443 8,334,171 8,334,171
1434 P SG 20,156,916 19,046,572 1,110,343 1,110,343
1435 P SG 106,245,543 100,393,009 5,852.534 324,857 6.177,391
1436 P SG 37,108,148 35,064,047 2,044,102 2,044,102
1437 B8 314,807,221 297,466,072 17,341,149 324,857 17,666,007
1438
1439 333 Water Wheel, Turbines, & Generators
1440 P SG 31,913,924 30,155,946 1,757,978 1,757,978
1441 P SG 8,828,844 8,342,508 486,337 486,337
1442 P SG 43,462,254 41,068,137 2,394,117 2,394,117
144 P SG 27,234,682 25,734,460 1,500.222 1.500.222
1444 B8 111,439,704 105,301,050 6,138,654 6,138.654
1445
1446 334 Accessory Electric Equipment
1447 P SG 4,430,934 4,186,857 244,078 244,078
1448 P SG .3.69,976 3,467,816 202,161 202,161
1449 P SG 43,817,031 41,403,370 2,413,660 2,413,660
1450 P SG 7,133,812 6,740,846 392.966 392,966
1451 B8 59,051,753 55,798,888 3,252,865 3,252,865
1452
REVISED PROTOCOL Page 2.23
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1453
1454
1455 335 Misc. Power Plant Equipment
1456 P SG 1,197,194 1,131,247 65,947 65,947
1457 P SG 186,194 175,938 10,257 10,257
1458 P SG 996,385 941,499 54,886 54,886
1459 P SG 11,353 10,728 625 625
1460 B8 2,391,127 2,259,411 131,715 131,715
1461
1462 336 Roads. Railroads & Bridges
1463 P SG 4,620,060 4.365,564 254,496 254,496
1464 P SG 828.931 783,269 45,662 45,662
1465 P SG 9,817,317 9,276,530 540,787 540,787
1466 P SG 682,347 644,760 37,587 37,587
1467 B8 15,948,654 15,070,123 878,531 878,531
1468
1469 337 Hydro Plant ARO
1470 P S
1471 B8
1472
1473 HP Unclassified Hydro .Plant - Acct 300
1474 P S
1475 P SG
1476 P SG
1477 P SG
1478 B8
1479
1480 Total Hydraulic Production Plant B8 628,142,54 593,541,329 34,601,219 324,857 34,926,077
1481
1482 Summary of Hydraulic Plant by Factor
1483 S
1484 SG 628,142,548 593,541,329 34,601,219 324,857 34,926,077
1485 DGP
1486 DGU
1487 Total Hydraulic Plant by Factor 628,142,58 593,541,329 34,601,219 324,857 34,926,077
1488
1489 340 Land and Land Rights
1490 P SG 23,516,708 22,221,290 1,295,417 1,295,417
1491 P SG
1492 P SSGCT
1493 B8 23,516,708 22,221,290 1,295,417 1,295,417
1494
1495 341 Structures and Improvements
1496 P SG 151,043,941 142,723,688 8,320,252 8,320,252
1497 P SG 163,512 154,505 9,007 9,007
1498 P SSGCT 4,241,952 4,011,670 230,282 230,282
1499 B8 155,449,405 146,889,863 8,559,541 8,559,541
1500
1501 342 Fuel Holders, Producers & Accessories
1502 P SG 8,406,209 7,943,153 463,056 463,056
1503 P SG 121,339 114,655 6,684 6,684
1504 P SSGCT 2,284,126 2,160,128 123,998 123,998
1505 B8 10,811,674 10,217,936 593,738 593,738
1506
1507 343 Prime Movers
1508 P S
1509 P SG 754,466 712,906 41,560 41,560
1510 P SG 2,223,358,082 2,100,884,449 122,473,634 14,387,299 136,860,932
1511 P SSGCT 51,744,608 48,935,561 2,809,048 2.809,048
1512 B8 2,275,857,156 2,150.532,915 125,324,241 14,387,299 139,711.540
1513
1514 344 Generators
1515 P S
1516 P SG
1517 P SG 331,535,449 313,272,825 18,262,623 18,262,623
1518 P SSGCT 15,873,643 15,011,915 861,729 861.729
1519 B8 347,409,092 328,284,740 19,124,352 19,124,352
REVISED PROTOCOL.Page 2.24
Year-End
FERC 8US UNADJUSTED RESUL. TS IDAHO
ACCT OESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT AOJTOTAL.
1520
1521 345 Accessory Electric Plant
1522 P SG 226,854,809 214,358,517 12,496,292 12,496.292
1523 P SG 156,586 147,961 8,626 8,626
1524 P SSGCT 2.919,649 2,761,151 158,498 158,498
1525 88 229,931,044 217,267,628 12.663,416 12,663,416
1526
1527
1528
1529 346 Misc. Power Plant Equipment
1530 P SG 12,167,872 11,497,605 670,267 670,267
1531 P SG 11,813 11,162 651 651
1532 B8 12,179,685 11,508,767 670,918 670,918
1533
1534 347 Other Production ARO
1535 P S
1536 B8
1537
1538 OP Unclassified Other Prod Plant-Acct 300
1539 P S
1540 P SG
1541
1542
1543 Total Other Production Plant 88 3,055,154,764 2,886,923,140 168,231,623 14,387,299 182,618,922
1544
1545 Summary of Other Production Plant by Factor
1546 S
1547 DGU
1548 SG 2,978,090,785 2,814,042,716 164,048,069 14,387,299 178,435,367
1549 SSGCT 77,063,979 72.880,424 4,183.554 4.183.554
1550 Total of Other Production Plant by Factor 3,055,154,764 2,886,923,140 168,231623 14,387,299 182,618,922
1551
1552 Experimental Plant
1553 103 Experimental Plant
1554 P SG
1555 Total Experimental Production Plant 88
1556
1557 Total Producton Plant 88 8,971,459,125 8,477,637,933 493,821,192 48,197,147 542,018,338
1556 350 Land and Land Rights
1559 T SG 21.145,733 19.980,920 1,164,812 1,164,812
1560 T SG 48,501,155 45,829,470 2,671.685 2,671,685
1561 T SG 31,414,150 29.683,702 1,730,448 (23,847)1,706,601
1562 88 101.061,037 95,94.092 5,566,945 (23,847)5,543,098
1563
1564 352 Structures and Improvements
1565 T S
1566 T SG 7,741,609 7,315.163 426,44 426,446
1567 T SG 18,157,495 17,157,289 1,000,205 1,000,205
1568 T SG 59,577,575 56,295,746 3,281,829 3,281,829
1569 88 85,476,679 80,768,198 4,708,481 4.708,461
1570
1571 353 Station Equipment
1572 T SG 129,985,618 122,825,363 . 7,160,255 7,160,255
1573 T SG 188,825,398 178,423,955 10,401,443 10,401,443
1574 T SG 988,384,505 933.939,365 54,44,140 54,445,140
1575 B8 1,307,195,521 1,235,188,683 72,006,838 72,006,838
1576
1577 354 Towers and Fixtures
1578 T SG 156,322,773 147,711,736 8,611,037 8,611,037
1579 T SG 127,544,198 120,518,428 7,025,769 7,025,769
1580 T SG 165,062,634 155,970,163 9,092,472 9,092,472
1581 88 448,929,605 424,200,327 24.729,278 24,729,278
1582
1583 355 Poles and Fixtures
1584 T SG 66.244,763 62,595,672 3,649,091 3,649,091
1585 T SG 117,745,408 111,259,405 6,486,003 6,486,003
1586 T SG 375,300,433 354,627,017 20,673,417 51,961.670 72,635,086
1587 B8 559,290,604 528,482,093 30,808,511 51,961,670 82,770,181
1588
REVISED PROTOCOL Page 2.25
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1589 356 Clearing and Grading
1590 T SG 197.260.339 186,394,257 10.866.082 10.866.082
1591 T SG 156.882,468 148.240.600 8.641,867 8.641,867
1592 T SG 380.070.379 359.134.210 20.936.169 20.936,169
1593 68 734,213.185 693.769.067 40.444.118 40,444.118
1594
1595 357 Underground Conduit
1596 T SG 6.371 6.020 351 351
1597 T SG 91,651 86.602 5.049 5,049
1598 T SG 3.113,807 2.942.283 171.524 171,524
1599 68 3.211.828 3.034,905 176.923 176.923
1600
1601 358 Underground Conductors
1602 T SG
1603 T SG 1,087,552 1,027.644 59,908 59,908
1604 T 5G 6,442,172 6,087,305 354,867 354.867
1605 68 7.529,724 7.114.949 414,775 414,775
1606
1607 359 Roads and Trails
1608 T SG 1,863,032 1.760,406 102.625 102.625
1609 T SG 440.513 416,248 24,266 24,266
1610 T SG 9,151.569 8,647,455 504.114 504,114
1611 B8 11,455,113.10,824,109 631,005 631.005
1612
1613 TP Unclassified Trans Plant. Ace 300
1614 T SG 84.550,623 79,893.154 4,657,469 4,657.469
1615 68 84.550,623 79,893.154 4.657.469 4.657.469
1616
1617 T50 Unclassifed Trans 5ub Plant. Acct 300
1618 T SG
1619 68
1620
1621 Total Transmission Plant B8 3,342,913,921 3,158,769,577 184,144,34 51,937,823 236,082,166
1622 Summary of Transmission Plant by Factor
1623 DGP
1624 DGU
1625 SG 3.342,913.921 3,158,769.577 184,144.344 51.937.823 236,082.166
1626 Total Transmission Plant by Factor 3.342,913,921 3,158.769,577 184.144.344 51.937.823 236.082.166
1627 360 land and land Rights
1628 DPW 5 51.856.326 50,519.585 1,336,741 1,336.741
1629 68 51.856.326 50.519,585 1.336,741 1.336.741
1630
1631 361 Structures and Improvements
1632 DPW 5 66,95,517 65.002.256 1,493.261 1,493.261
1633 68 66,495.517 65.002.256 1,493,261 1,493.261
1634
1635 362 Station Equipment
1636 DPW 5 787.676.940 761,044,499 26,632,441 26.632.441
1637 68 787,676,940 761.044,499 26,632.441 26.632,441
1638
1639 363 Storage Battery Equipment
1640 DPW 5 1,457,805 1.457,805
1641 68 1,457,805 1.457,805
1642
1643 364 Poles. Towers & Fixtures
1644 DPW 5 903,958.177 842;950.744 61,007.433 61.007,433
1645 68 903.958.177 842,950.744 61,007.433 61,007,433
1646
1647 365 Overhead Conductors
1648 DPW 5 631,378,730 597,455,532 33.923.198 33.923,198
1649 68 631,378,730 597,455.532 33,923.198 33,923,198
1650
REVISED PROTOCOL Page 2.26
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1651 366 Underground Conduit
1652 DPW S 290.621.174 283.247.994 7.373.179 7,373,179
1653 68 290,621.174 283.247.994 7.373,179 7,373,179
1654
1655
1656
1657
1658 367 Underground Conductors
1659 DPW S 697,799,779 674.120,851 23.678,928 23.678,928
1660 68 697.799.779 674,120,851 23.678,928 23.678.928
1661
1662 368 line Transformers
1663 DPW S 1,056.509.849 990.583,151 65,926.697 65,926,697
1664 68 1,056,509,849 990.583.151 65,926.697 65,926.697
1665
1666 369 Services
1667 DPW S 559.763,102 531,874,191 27.888,911 27,888,911
1668 B8 559,763.102 531,874.191 27,888,911 27.888,911
1669
1670 370 Meters
1671 DPW S 187,209,616 173.388,196 13,821,420 13.821,420
1672 B8 187.209,616 173,388.196 13,821,420 13.821,420
1673
1674 371 Installations on Customers' Premises
1675 DPW S 8,809.120 8,644,004 165,115 165,115
1676 68 8,809,120 8,644,004 165,115 165,115
1677
1678 372 Leased Propert
1679 DPW S
1680 B8
1681
1682 373 Street Lights
1683 DPW S 62.885.04 62.283,269 602.135 602.135
1684 68 62.885.04 62,283.269 602,135 602.135
1685
1686 DP Unclassified Dist Plant. Acct 300
1687 DPW S 20.216,252 19.291,256 924,997 924.997
1688 B8 20,216,252 19,291.256 924,997 924,997
1689
1690 DSO Unclassified Dist Sub Plant - Acct 300
1691 DPW S
1692 B8
1693
1694
1695 Total Distnbutlon Plant B8 5,326,637,791 5,061,863,333 264,774,458 264,774,458
1696
1697 Summary of Distribution Plant by Factor
1698 S 5,326,637,791 5,061,863.333 264.774,458 264,774,458
1699
1700 Total Distribution Plant by Factor 5,326,637. 791 5,061.863.333 264, 774,458 264,774,458
REVISED PROTOCOL Page 2.27
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1701 389 Land and Land Rights
1702 G.SITUS S 9,472,275 9,274,636 197,639 197,639
1703 CUST CN 1.128,506 1,084,668 43,838 43.838
1704 PT SG 332 314 18 18
1705 G.SG SG 1,228 1,160 68 68
1706 PTO SO 5,598,055 5.296.196 301.859 301,859
1707 B8 16.200.395 15,656,974 543,422 543,422
1708
1709 390 Structures and 1m provements
1710 G.SITUS S 111.200,704 101,422,380 9,778,324 9,778,324
1711 PT SG 358.127 338,400 19,727 19,727
1712 PT SG 1,653.732 1,562,636 91,096 91,096
1713 CUST CN 12,319.587 11,841,025 478,563 478,563
1714 G.SG SG 3,675,782 3,473,302 202,480 202,480
1715 PTD SO 102.313,681 96,796,704 5.516,977 5,516,977
1716 B8 231.521,614 215,434,446 16,087,167 16,087,167
1717
1718 391 Offce Furniture & Equipment
1719 G.SITUS S 13,065,614 12,137.233 928,381 928,381
1720 PT SG 1.046 988 58 58
1721 PT SG 5,295 5,003 292 292
1722 CUST CN 8,685,337 8,347,949 337,388 337,388
1723 G.SG SG 4,784,588 4,521,029 263,559 263,59
1724 P SE 97,829 91,609 6,219 6,219
1725 PTO SO 54,551,124 51,609,608 2,941,516 2,941,516
1726 G-SG SSGCH 74,351 70,300 4,051 4.051
1727 G-SG SSGCT
1728 B8 81,265,184 76.783,720 4,481,463 4,481,463
1729
1730 392 Transportation Equipment
1731 G.SITUS S 73.113.164 68,190,669 4,922,495 4,922,495
1732 PTO SO 7,996,779 7,565,575 431,204 431.204
1733 G-SG SG 17,254,817 16,304,336 950,461 950,481
1734 CUST CN
1735 PT SG 838,181 792,010 46,171 46.171
1736 P SE 404,148 378,54 25,694 25,694
1737 PT SG 120,286 113,660 6,626 6,626
1738 G.SG SSGCH 374,178 353,790 20,388 20.388
1739 PT SSGCT 44,655 42,231 2,424 2,424
1740 B8 100,146,208 93,740,725 6,405,483 6,405,483
1741
1742 393 Stores Equipment
1743 G.SITUS S 8,861,339 8,312,757 548,582 548,582
1744 PT SG 108,31 102,458 5,973 5,973
1745 PT SG 360,063 340,229 19.834 19.834
1746 PTD SO 445.293 421,282 24,011 24,011
1747 G.SG SG 4,062,155 3,838,392 223,764 223,764
1748 PT SSGCT 53.971 51.041 2,930 2,930
1749 B8 13,891.252 13,066,158 825,094 825,094
REVISED PROTOCOL Page 2.28
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1750
1751 394 Tools, Shop & Garage Equipment
1752 G-SITUS S 32,024,394 30,281,765 1,742,629 1,742,629
1753 PT SG 2,120,983 2,004,148 116,834 116,834
1754 G-SG SG 20,499,259 19,370,058 1,129,201 -1,129,201
1755 PTO SO 3,986,801 3,771,824 214,977 214,977
1756 P SE 7,106 6,655 452 452
1757 PT SG 2,176,302 2,056.20 119,882 119,882
1758 G-SG SSGCH 1,716,105 1,622,597 93,508 93,508
1759 G-SG SSGCT 89,913 85,032 4,881 4,881
1760 68 62,620,863 59,198,500 3,22,364 3,422,364
1761
1762 395 Laboratory Equipment
1763 G-SITUS S 25,228,787 23,956.55 1,272,132 1,272,132
1764 PT SG 20,622 19,486 1,136 1,136
1765 PT SG 13,281 12,550 732 732
1766 PTO SO 5,197,970 4,917,684 280,286 280,286
1767 P SE 7,593 7,111 483 483
1768 G-SG SG 6,353,527 6,003,543 349,984 349,984
1769 G-SG SSGCH 253,001 239,215 13,786 13,786
1770 G-SG SSGCT 14,022 13,260 761 761
1771 68 37,088,802 35,169,504 1,919,299 1,919,299
1772
1773 396 Power Operated Equipment
1774 G-SITUS S 94,279,509 87.117,887 7,161,622 7,161,622
1775 PT SG 845,108 798,555 46,553 46,553
1776 G-SG SG 31.633,038 29.890.533 1,742.505 1,742.505
1777 PTD SO 1,410,640 1.334,576 76.065 76,065
1778 PT SG 1,664,492 1,572,804 91,689 91,689
1779 P SE 73,823 69,130 4,693 4.693
1780 P SSGCT
1781 G-SG SSGCH 968,906 916.112 52.794 52,794
1782 68 130,875,517 121,699,596 9,175,921 9,175,921
1783 397 Communication Equipment
1784 COM_EO S 101,721,635 96,539,236 5,182,399 5.182,399
1785 COM_EO 5G 4,816,644 4,551,319 265,325 265,325
1786 COM_EO SG 9,615,788 9,086,102 529,685 529,685
1787 COM_EO SO 48,166,017 45,568,801 2.597,217 2,597,217
1788 COM_EO CN 2,641,488 2,538,878 102,610 102.610
1789 COM_EO SG 74,202,015 70,114.598 4,087,416 4,087,416
1790 COM_EO SE 114.538 107,256 7,282 7,282
1791 COM_EO SSGCH 1,055,756 998,229 57,526 57,526
1792 COM_EO SSGCT 1,590 1,504 86 86
1793 68 242,335,71 229,505,923 12,829,547 12,829,547
1794
1795 398 Misc. Equipment
1796 G-SITUS S 1,354,746 1,290.393 64,352 64.352
1797 PT SG
1798 PT SG 1,997 1,887 110 110
1799 CUST CN 199,765 192,005 7,760 7,760
1800 PTO SO 3,376,792 3,194,708 182.084 182,084
1801 P SE 1,668 1,562 106 106
1802 G-SG SG 1,865,540 1,762,777 102,763 102,763
1803 G-SG SSGCT
1804 68 6,800,507 6,443,332 357,176 357,176
1805
1806 399 Coal Mine
1807 P SE 278,021,722 260,348 ,431 17,675,291 13.511,711 31.187,003
1808 MP P SE
1809 68 278,021,722 260,346,431 17,675,291 13,511,711 31,187,003
1810
1811 399L WIOCO Capital Lease
1812 p 5E B8
1813
1814
1815 Remove Capital Leases
1816 68
1817
REVISED PROTOCOL Page 2.29
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1818 1011390 General Capital Leases
1819 G-SITUS S 18,984,156 18,984,156
1820 P SG 16,951,793 16,018,004 933,789 933,789
1821 PTD SO 12,664,054 11,981,180 682,873 682,873
1822 B9 48,600,002 46,983,340 1,616,663 1,616,663
1823
1824 Remove Capital Leases (48,600,002)(48,983,340)(1,616,663)(1,616,663)
1825
1826
1827 1011346 General Gas Line Capital Leases
1828 P SG
1829 B9
1830
1831 Remove Capital Leases
1832
1833
1834 GP Unclassified Gen Plant - Acct 300
1835 G-SITUS S
1836 PTD SO 4,694,044 4,440,931 253,113 253,113
1837 CUST CN
1838 G-SG SG
1839 PT SG
1840 PT SG
1841 B8 4,694,044 4,440,931 253,113 253,113
1842
1843 399G Unclassified Gen Plant - Acct 300
1844 G-SITUS S
1845 PTD SO
1846 G-SG SG
1847 PT SG
1848 PT SG
1849 88
1850
1851 Total General Plant B8 1,205,461,579 1,131,486,239 73,975,340 13,511,711 87,487,051
1852
1853 Summary of General Plant by Factor
1854 S 489,306,322 457,507,766 31,798,556 31,798,556
1855 DGP
1856 DGU
1857 SG 206,004,452 194,656,701 11,347,751 11,347,751
1858 SO 250,401,250 236,899,068 13,502,182 13,502,182
1859 SE 278,728,27 261,008,207 17,720,220 13,511,711 31,231,932
1860 CN 24,974,683 24,004,525 970,158 970,158
1861 DEU
1862 SSGCT 204,151 193,068 11,083 11,083
1863 SSGCH 4,442,297 4,200,244 242,053 242,053
1864 Less Capital Leases (48,600,002)(46,983,340)(1,616,663)~1,616.663)
1865 Total General Plant by Factor 1,205,461,579 1,131,486,239 73,975,340 13,511,711 7,487,051
1866 301 Organization
1867 I-SITUS S
1868 PTD SO
1869 I-SG SG
1870 B8
1871 302 Franchise & Consent
1872 I-SITUS S 1,000,000 1,000,000 1,000,000
1873 I-SG SG 9,402,471 8,884,536 517.935 517,935
1874 I-SG SG 99,510,474 94,028,942 5,481,532 5,81,532
1875 I-SG SG 9,240,742 8,731,716 509,026 509,026
1876 P SG
1877 P SG 600,993 567,887 33,106 33,106
1878 B8 119.754,679 112.213,080 7,541.599 7,541,599
1879
REVISED PROTOCOL Page 2.30
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1880 303 Miscellaneous Intangible Plant
1881 I-SITUS S 6,042,837 5,626,978 415,859 415.859
1882 I-SG SG 95.041.256 89.805.910 5.235.346 631,847 5,867.193
1883 PTO SO 366.513,585 346.750,373 19,763,212 19.763,212
1884 P SE 3,453,872 3,234,291 219,581 219,581
1885 CUST CN 118,758,961 114,145,691 4,613,271 4.613.271
1886 P SG
1887 P SSGCT
1888 88 589,810,510 559,563.242 30.247.268 631,847 30,879,115
1889 303 Less Non-Utilty Plant
1890 1-SITUS S
1891 589,810,510 559,563,242 30.247.268 631,847 30.879,115
1892 IP Unclassified Intangible Plant - Acct 300
1893 I-SITUS S
1894 I-SG SG
1895 P SG
1896 PTD SO
1897
1898
1899 Total Intangible Plant B8 709,565,190 671,776,323 37,788,867 631,847 38,420,714
1900
1901 Summary of Intan9ible Plant by Factor
1902 S 7,042,837 5,626,978 1,415.859 1.15.859
1903 OGP
1904 OGU
1905 SG 213.795,935 202,018.990 11,776.945 631,847 12,408.792
1906 SO 366,513.585 346,750,373 19.763,212 19.763.212
1907 eN 118.758,961 114,145,691 4.613.271 4.613,271
1908 SSGCT
1909 SSGCH
1910 SE 3,453.872 3,234,291 219,581 219,581
1911 Total Intangible Plant by Factor 709,565.190 671,77.323 37,88,867 631,847 38.20,714
1912 Summary of Unclassified Plant (Account 106)
1913 OP 20,216.252 19,291.256 924,997 924.997
1914 OSO
1915 GP 4,694,044 4,440,931 253,113 253,113
1916 HP
1917 NP
1918 OP
1919 TP 84,550,623 79,893,154 4.657,469 4,657,469
1920 TSO
1921 IP
1922 MP
1923 SP 787.304 743,936 43.369 43,369
1924 Total Unclassified Plant by Factor 110,248,224 104,369,276 5.878.948 5,878.948
1925
1926 Total Electric Plant In Service B8 19,556,037,605 18,501,533,405 1,054,504,200 114,278,528 1,168,782,728
REVISED PROTOCOL Page 2.31
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT OESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1927 Summary of Electric Plant by Factor
1926 S 5,822,986,950 5,524,998,077 297,988,873 297,988,673
1929 SE 282,182,299 264,242,496 17,939,801 13,511,711 31,451,512
1930 DGU
1931 DGP
1932 SG 12,137,724,526 11,469,118,223 668,606,302 100,766,817 769,373,119
1933 SO 616,914;834 583,649,441 33,265,393 33,265,393
1934 CN 143,733,644 138,150,216 5,583,29 5,583,429
1935 DEU
1936 SSGCH 523,827,225 495,284,798 28,542,427 28,542,427
1937 SSGCT 77,268,130 73,073,492 4,194,637 4,194,637
1938 Less Capital Leases (48,600,002)(46,983,340)(1,616,663)(1,616,663)
1939 19,556,037,605 18,501,533.05 1,054,504.200 114,78,528 1,168,782.728
1940 105 Plant Held For Future Use
1941 DPW S 3,473,204 3,473,204
1942 P SG
1943 T SG 325,029 307,125 17,904 (509,444)(491,540)
1944 P SG 8,923,302 8,431,762 491.540 491.540
1945 P SE 953,014 892,426 60,588 (60,588)
1946 G SG
1947
1948
1949 Total Plant Held For Future Use 810 13,674,549 13,104,516 570,032 (570M2)(0)
1950
1951 114 Electric Plant Acquisition Adjustments
1952 P S
1953 P SG 142,633,069 134,776,129 7,856,940 7,856,940
1954 P SG 14,560,711 13,758,634 802,076 802,076
1955 Total Electric Plant Acquisition Adjustment 815 157,193,780 148,534,764 8,659,016 8,659,016
1956
1957 115 Accum Provision for Asset Acquisition Adjustments
1958 p S
1959 P SG (84,100,707)(4,632,666)
1960 P SG (12,226,166)(673,478)
1961 615
1962
1963 120 Nuclear Fuel
1964 P SE
1965 Total Nuclear Fuel 815
1966
1967 124 Weatheriation
1968 DMSC S 2,633,178 2,599,959 33,220 33,220
1969 DMSC SO
t,454)(4,214)(240)(240)
1970 616 2,68,725 2,595,745 32,90 32,980
1971
1972 182W Weatherization
1973 DMSC S 34,729,463 31,258,802 3,470,661 3,470,661
1974 DMSC SG
1975 DMSC SGCT
1976 DMSC SO
1977 616 34,729,463 31,258,802 3,470,661 3,470,661
1978
1979 186W Weatherization
1980 DMSC S
1981 DMSC CN
1982 DMSC CNP
1983 DMSC SG
1984 DMSC SO
1985 616
1986
1987 Total Weatherization 816 37,358,188 33,854,547 3,503,640 3,503,640
REVISED PROTOCOL Page 2.32
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DE SCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1988
1989 151 Fuel Stock
1990 P DEU
1991 P SE 158,860,196 148,760,625 10,099,571 1,839,370 11.938,941
1992 P SSECT
1993 P SSECH 12.069,947 11,343.108 726.838 (258,194)468,644
1994 Total Fuel Stock B13 170,930,143 160,103,733 10,826,410 1,581,176 12,407,586
1995
1996 152 Fuel Stock - Undistributed
1997 P SE
1998
1999
2QOO 25316 DG& T Working Capital Deposit
2001 P SE (1,379,000)(1.291,330)(87,670)(56,073)(143,744)
2002 813 (1,379,000)(1,291,330)(87,670)(56,073)(143,744)
2003
2004 25317 DG& T Working Capital Deposit
2005 P SE (1,758,544)(1,646,744)(111,800)(5,907)(117,706)
2006 813 (1,758,544)(1,648,744)(111,800)(5,907)(117,706)
2007
2008 25319 Provo Working Capital Deposit
2009 P SE
2010
2011
2012 Total Fuel Stock 813 167,792,599 157,165,659 10,626,940 1,519,196 12,146,136
2013 154 Materials and Supplies
2014 MSS S 86,919,683 82,030,372 4,889,311 4,889,311
2015 MSS SG 3,082..186 2,912,404 169,782 169,782
2016 MSS SE 4,170,119 3,905,003 265,116 265,116
2017 MSS SO 253,641 239,964 13,677 13,677
2018 MSS SNPPS 81,516,215 77,032,136 4,484,080 4,484,080
2019 MSS SNPPH (1,860)(1,757)(102)(102)
2020 MSS SNPD (3,081,941)(2,939,745)(142,196)(142,196)
2021 MSS SNPT
2022 MSS SG
2023 MSS SG
2024 MSS SSGCT
2025 MSS SNPPO 5,288,978 4,997,723 291,256 29-1,256
2026 MSS SSGCH
2027 Total Materials and Supplies B13 178,147,022 168,176,099 9,970,923 9,970,923
2028
2029 163 Stores Expense Undistributed
2030 MSS SO
2031
2032 813
2033
2034 25318 Provo Working Capital Deposit
2035 MSS SNPPS (273,000)(257,983)(15,017)(15,017)
2036
2037 813 (273,000)(257,983)(15,017)(15,017)
2038
2039 Total Materials & Supplies 613 177,874,022 167.918.116 9,955,906 9.955,906
2040
2041 165 Prepayments
2042 DMSC S 2,934,455 2,770.438 164,017 164,017
2043 GP GPS 9,858,973 9,327,356 531,617 531,617
2044 PT SG 6,415,547 6,062,148 353,400 353,400
2045 P SE 7,102,118 6,650.600 451.519 451,519
2046 PTD SO 19,839,360 18,769,578 1,069,782 1,069,782
2047 Total Prepayments B15 46,150,453 43,580,118 2,570,335 2,570,335
2048
REVISED PROTOCOL Page 2.33
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
2049 182M Mise Regulatory Assets
2050 DDS2 S 56,142.627 56,331.298 (188,671)(17,580)(206.251)
2051 DEFSG SG 2,654.642 2,508,411 146.231 146.231
2052 P SGCT 8,511,723 8,041.060 470.663 470.663
2053 DEFSG SG.p 74,434 74,434
2054 P SE 74.327 74.327
2055 P SSGCT
2056 DOS02 SO 7,516.382 7,111.083 405.300 405.300
2057 B11 74,825,374 73991.851 833.523 131.181 964,704
2058
2059 186M Mise Deferred Debits
2060 LABOR S 16,240,410 16,240,410
2061 P SG
2062 P SG
2063 DEFSG SG 38.988,960 36,841.254 2,147,706 531.032 2.678,738
2064 LABOR SO 16,926 16.014 913 913
2065 P SE 10,045,914 9,407,242 638,671 (108.911 )529,760
2066 P SNPPS
2067 GP EXCTAX
2068 Total Misc. Deferred Debits 811 650292,210 62,50,920 2,787,290 422,121 3,209,11
2069
2070 Working Capitai
2071 CWC Cash Working Capital
2072 CWC S 36,076.546 34,125.171 1,951,376 183,135 2,134.510
2073 CWC SO
2074 CWC SE
2075 B14 36.076.546 34.125,171 1,951.376 183,135 2,134,510
2076
2077 OWC OIer Work. Cap.
2078 131 Cash GP SNP
2079 135 WClrkng Fund GP SG 1,920 1.814 106 106
2080 141 Noles Receivabli GP SO 540,572 511,423 29,149 29.149
2081 143 Other AI GP SO 33,985,372 32,152,807 1,832,565 1,832.565
2082 232 Al PTO S
2083 232 Al PTD 50 (4,215,163)(3.987,872)(227,291)(227,291)
2084 232 NP P 5E (1,408,97)(1,318,951)(89,545)(89,545)
2085 232 NP T SG
2086 2533 Othe Ms. Of Crd. P S
2087 2533 OtheMsc. Of. Cr-d. P SE (6,046,034)(5.661,656)(384,378)(384,378)
2088 230 Ast Ret. Oblig.P SE (2,415,872)(2,262.283)(153.590)(153,590)
2089 230 Ast Retr. Oblig. P 5
2090 254105 ARO Reg Liability P 5
2091 254105 ARO Reg liabiity P 5E (716,594)(671,036)(45.558)(45,558)
2092 2533 Cholle ReclamaUon P 5SECH
2093 B14 19,725.703 18.764.245 961,459 961,459
2094
2095 Total Working Capital 814 . 55.802,250 52,889,415 2,912,834 183.135 3.095,969
2096 Miscellaneous Rate Base
2097 18221 Unree Plant & Reg Study Costs
2098 P 5
2099
2100 B15
2101
2102 18222 Nuclear Plant - Trojan
2103 P 5 (372363)(372,363)
2104 P TROJP 885,265 835,358 49,907 49,907
2105 P TROJO 1,296,271 1,222,899 73,372 73.372
2106 B15 1.809,172 1,685,894 . 123,279 123,279
2107
2108
REVISED PROTOCOL Page 2.34
Year-End
FËRC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSrMENT ADJ TOTAL
2109
2110 1869 Mise Deferred Debits-Trojan
2111 P S
2112 P SNPPN
2113 B15
2114
2115 Total Miscellaneous Rate Base B15 1,809,172 1,685,894 123,279 123,279
2116
2117 Total Rate Base Additions B15 701,445,723 664,209,092 37,236,631 1,685,600 38,922,231
2118 235 Customer Service Deposits
2119 CUST S
2120 CUST CN
2121 Total Customer Service Deposit B15
2122
2123 2281 Prop Ins PTD SO
2124 2282 Inj & Dam PTD SO (7,487,871 )(7,084,109)(403,762)(403,762)
2125 2283 Pen & Ben PTD SO (22,725,860)(21,500,432)(1,225,428)(1,225,428)
2126 254 Reg Uab PTD SG
2127 254 Reg Uab PTD SE 77,389
2128 254 Ins Prov PTD SO (5,908
2129 B15 773 1,5,
2130
2131 22841 Accum Mise Oper Provisions - Other
2132 P S
2133 P SG (82,627)(82,627
2134 B15 , 27 ,6
2135
2136 22842 Prv-Trojan P TROJD
2137 230 ARO P TROJP (1,711,281)(1,614,808)(96,473)(96,73)
2138 254105 ARO P TROJP (3,608,947)(3,405,494)(203,453)(203,453)
2139 254 P S
f6,009,324)16,009,324)2140 815 (1,329,552)(1,029,626)(299,926)(299,926)
2141
2142 252 Customer Advances for Constrction
2143 DPW S (13,473,111)(13,198,024)(275,088)6,822 (268,266)
2144 DPW SE
2145 T SG (7,471,547)(7,059,977)(411,570)(267,861)(679,431)
2146 DPW SO
2147 CUST CN
2148 Total Customer Advances for Construction B19 (20,94.658)(20,258,001)(686,658)(261,039)(947,697)
2149
2150 25398 502 Emissions
2151 P 5E (2,402,284)¡2.402,284l
2152 B19 (2,402.284)2,402,284
2153
2154 25399 Other Deferred Credits
2155 P S . (3,803,740)(3,728,560)(75,180)(75,180)
2156 LABOR SO (181,282)(181,282)
2157 P SG (7,567,103)(441,134)
2158 P SE 1,108,081)(75,229
2159 B19 1 ,,7 3 1,2 7
REVISED PROTOCOL Page 2.35
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
2160
2161 190 Accumulated Deferred Income Taxes
2162 P S 10,695,484 10,695,486 (2)(2)
2163 CUST CN 65,488 62,944 2,544 2,544
2164 P IBT
2165 LABOR SO 36,490,690 34,523,032 1.967,658 (49,961)1,917,697
2166 P DGP
2167 CUST BADDEBT 3,345,135 3,215,387 129,748 129,748
2168 P TROJD 1,332,481 1,257,059 75,422 75,422
2169 P SG 39,391,566 37,221,682 2,169,884 (2,002.880)167,004
2170 P SE 3,097,022 2,900,128 196,894 (347,312)(150,418)
2171 PTD SNP
2172 DPW SNPD 703,93 671,035 32,458 32,458
2173 P SSGCT
2174 Total Accum Deferred Income Taxes B19 95,121,359 90,546,754 4,574,605 (2,400,152)2,174,453
2175
2176 281 Accumulated Deferred Income Taxes
2177 P S
2178 PT DGP
2179 T SNPT
2180 B19
2181
2182 282 Accumulated Deferrd Income Taxes
2183 GP S (138,317,516)(138,317,516)
2184 ACCMDIT DITBAL (2,336,392,077)(2,195,736,556)(140,655,521 )140,655,521 0
2185 P SSGCH
2186 LABOR SO (6,909;549)(6,536,971 )(372,578)6,813 (365,765)
2187 CUST CN
2188 P SE (5,607,614)(5,251,109)(356,505)(61,607)(418,113)
2189 P SG (5,705,530)(5,391,241 )(314,289)(1,664,205)(1,978,494)
2190 B19 (2,354,614,770)(2,212,915,877)(141,698,893)619,006 \141,079,887)
2191
2192 283 Accumulated Deferred Income Taxes
2193 GP S (30,884,504)(29,777,409)(1,107,095)1,028,227 (78,868)
2194 P SG (6,716,785)(6,346,791)(369,994)(41,055)(411,08)
2195 P SE (4,844,933)(4,536,915)(308,018)41,333 (266,685)
2196 LABOR SO (16,761,723)(15,857,894)(903,829)710,704 (193,125)
2197 GP GPS (5,687,055)(5,380,397)(306,658)(306,658)
2198 PTD SNP (5,228,914)(4,951,271)(277,643)(277,63)
2199 P TROJD
2200 P SSGCT
2201 P SGCT (2,701,338)(2,551,965)(149,373)(149,373)
2202 P SSGCH
2203 B19 (72,825,252)(69,402,643)(3,422,609)1,739,209 (1,683,400)
2204
2205 Total Accum Deferred Income Tax B19 (2,332,318,663)(2,191,771,765)(140,546,898)(41,936)(140,588,834)
2206 255 Accumulated Investment Tax Credit
2207 PTD S
2208 PTD ITC84 (1,745,297)(1,745,297)
2209 PTD ¡TC85 (3,044,242)(3,044,242)
2210 PTD ITC86 (1,479,759)(1,479,759)
2211 PTD ITC88 (222,246)(222,246)
2212 PTD ITC89 (486,772)(486,772)
2213 PTD ITC90 (315,906)(271.738)(44,168)(44,168)
2214 PTD IBT (184,142l (184,142)
2215 Total Accumlated ITC B19 (7,294,222)(7,250,054)(44,168)(184,142 (228,311)
2216
2217 Total Rate Base Deductions (2,417,922,963)(2,273,958,655)(143,964,308)(2,993,294)(146,957,602)
2218
REVISED PROTOCOL Page 2.36
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJ TOTAL
2219
2220
2221 108SP Steam Prod Plant Accumulated Depr
2222 P S
2223 P SG (828,531.5a9)(782,891.896)(45.639.643)(45,639,643)
2224 P SG (936.120.976)(884,554.772)(51.566.204)(51,566,204)
2225 P SG (552,789,110)(522.338.733)(30,450,377)(792,318)(31.242,695)
2226 P SSGCH (158,685.661 )(150.039,158)(8,646,503)(8.646,503)
2227 817 (2,476,127,286)(2,339,824.559)(136,302,727)(792,318)(137,095,045)
2228
2229 108NP Nuclear Prod Plant Accumulated Depr
2230 P SG
2231 P SG
2232 P SG
2233 817
2234
2235
2236 108HP Hydraulic Prod Plant Accum Depr
2237 P S
2238 P SG (150,429,735)(142,143,316)(8.286,419)(8,286,419)
2239 P SG (28,604,226)(27,028,563)(1,575,663)(1,575,663)
2240 P SG (59,853,861)(56,556,813)(3,297,049)(70,598)(3,367,647)
2241 P SG (12,861,842)(12,153,348)(708,494)(72,398)(780,893)
2242 B17 (251,749,664)(237,882,039)(13,867,625)(142,997)(14,010,622)
2243
2244 1080P Other Production Plant - Accum Depr
2245 p S
2246 P SG (1,347,482)(1,273,256)(74,226)(74,226)
2247 P SG
2248 p SG (263,762,956)(249.233,579)(14,529,377 (583,034)(15.12,411)
2249 P SSGCT (19,564,578)(18,502,480)(1,062,098)(1,062,098)
2250 B17 (284,675,015)(269,009,315)(15,665,701)(583,034)(16,248,735)
2251
2252 108EP Experimental Plant - Accum Depr
2253 p SG
2254 P SG
2255
2256
2257 Total Production Plant Accum Depreciation 817 (3,012,551,966)(2,846,715,913)(165,836,053)(1,518,349)(167,354,402)
2258
2259 Summary of Prod Plant Depreciation by Factor
2260 S
2261 DGP
2262 DGU
2263 .SG (2,678,174,275)(1,518,349)(157,645,801)
2264 SSGCH (150,039,158)(8,646,503)
2265 SSGCT (18,502,480)(1,062,098
2266 Total of Prod Plant Depreciation by Factor , 4 ,71 , 1 4,4
2267
2268
2269 108TP Transmission Plant Accumulated Depr
2270 T SG (366,532,026)(21,367,434)(21,367,434)
2271 T SG (366,312,895)(21,354,659)(21,354,659)
2272 T SG (347,041,141 )(20,231,189)1,030,788)(21,261,976)
2273 Total Trans Plant Accum Depreciation 817 ,079,886,62,953,2 1,030,788 6 ,984,069
REVISED PROTOCOL Page 2.37
Year-End
FERC 6US UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
2274 108360 Land and Land Rights
2275 DPW S (5,731,126)(5,71,879)(259,247)(259,247)
2276 817 (5,731,126). (5,71 ,879)(259,247)(259,247)
2277
2278 108361 Structures and Improvements
2279 DPW S (13,581,278)(13,138,403)(442,875)(442,875)
2280 817 (13,581,278)(13,138,03)(442,875)(442,875)
2281
2282 108362 Station Equipment
2283 DPW S (207.834,133)(198.557,095)(9.277,038)(9,277038)
2284 817 (207,834,133)(198,57.095)(9,277,038)(9,277,038)
2285
2286 108363 Storage 8attery Equipment
2287 DPW S (775,263)(775.263)
2288 817 (775.263)(775.263)
2289
2290 108364 Poles, Towers & Fixtures
2291 DPW S (472,497,456)(438,618.489)(33,878.967). (33.878.967)
2292 817 (472,497,456)(438.618,489)(33,878,967)(33,878,967)
2293
2294 108365 Overhead Conductors
2295 DPW S (257,576,586)(247.145.604)(10,430.983)(10,430,983)
2296 617 (257,576.586)(247,145,604)(10,430,983)(10.430.983)
2297
2298 108366 Underground Conduit
2299 DPW S (121.003.027)(117,701.126)(3,301,901 )(3,301.901)
2300 817 (121.003,027)(117,701.126)(3,301,901 )(3.301,901 )
2301
2302 108367 Underground Conductors
2303 DPW S (279,736.871 )(268,973.545)(10.763.326)(10,763,326)
2304 817 (279.736,871)(268.973.545)(10.763,326)(10,763,326)
2305
2306 108368 Line Transformers
2307 DPW S (361,323,647)(337,660,494)(23,663,153)(23.663,153)
2308 817 (361,323,67)(337,660,494)(23,663,153)(23.663,153)
2309
2310 108369 Services
2311 DPW S (163.299,910)(152,868,799)(10,431,110)(10.431,110)
2312 617 (163.299,910)(152,868.799)(10,431,110)(10,431,110)
2313
2314 108370 Meters
2315 DPW S (84,175,634)(75,808,861 )(8,366,773)(8,366,77)
2316 817 (84,175.634)(75,808,861 )(8,366,773)(8,366.773)
2317
2318
2319
2320 108371 Installations on Customers' Premises
2321 DPW S (7,846,403)(7,709,414) ,(136,989)(136,989)
2322 817 (7,846,403)(7,709,414)(136.989)(136,989)
2323
2324 108372 Leased Property
2325 DPW S
2326 817
2327
2328 108373 Street Lights
2329 DPW S (28,660.733)(28.170,544)(490,188)(490,188)
2330 817 (28,660,733)(28,170,544)(490,188)(490.188)
2331
2332 108DOO Unclassified Dist Plant - Acct 300
2333 DPW . S
2334 817
2335
2336 108DS Unclassified Dist Sub Plant. Acet 300
2337 DPW S
2338 817
2339
2340 108DP Unciassified Dist Sub Plant. Acct 300
2341 DPW S 730.582 729.334 1,248 1.248
2342 617 730.582 729,334 1.248 1.248
2343
2344
2345 Total Distribution Plant Accum Depreciation 817 (2,003,311.485)(1,891.870,183)(111.441,302)(111,441,302)
2346
2347 Summary of Distribution Plant Depr by Factor
2348 S (2.003,311,485)(1,891.870,183)(111,441,302)(111.441,302)
2349
2350 Total Distribution Depreciation by Factor 817 (2,003,311,485)(1,891.870,183)(111,441.302)(111,441,302)
REVISED PROTOCOL Page 2.38
Year-End
FERC BUS UNADJUSTEDRESUL TS IDAHO
ACeT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT AÐJTOTAL
2351 108GP General Plant Accumulated Depr
2352 G-SITUS S (151,989,352)(141,794,438)(10,194,914)(10,194,914)
2353 PT SG (6,272,465)(5,926,947)(345,519)(345,519)
2354 PT SG (11,172,030)(10,556,619)(615,411)(615,411)
2355 G-SG SG (46,253,779)(43,705,891)(2,547,888)(2,547,888)
2356 CUST CN (6,625,150)(6,367,792)(257,358)(257,358)
2357 PTD SO (72,527,529)(68,616,686)(3,910,843)(3,910,843)
2358 P SE (339,900)(318,291)(21,609)(21,609)
2359 G-SG SSGCT (33,094)(31,297)(1,797)(1,797)
2360 G-SG SSGCH (2,331,547)(2,204,505)(127,Q2)(127,042)
2361 617 (297,544,846)(279,522,466)(18,022,380)(18,022,380)
2362
2363
2364 108MP Mining Plant Accumulated Depr.
2365 P S
2366 P SE (170,270,750)(159,44,750)(10,825,000)(54,840)(10,879,840)
2367 617 (170,270,750)(159,445,750)(10,825,000)(54,840)(10,879,84)
2368 108MP Less Centrali¡¡ Situs Depreciation
2369 P S
2370 617 (170,270,750)(159,445,750)(10,825,000)(54.840)(10,879,840)
2371
2372 1081390 Accum Depr - Capital Lease
2373 PTD SO 617
2374
2375
2376 Remove Capitl Leases
2377 617
2378
2379 1081399 Accum Depr - Capital Lease
2380 P S
2381 P SE 617
2382
2383
2384 Remove Capital Leases
2385 617
2386
2387
2388 Total Genenil Plant Accum Depreciation B17 (467,815,596)(438,968,216)(28,847,380)(54,840)(28,902,221)
2389
2390
2391
2392 Summary of General Depreciation by Factor
2393 S (151,989,352)(141,794,438)(10,194,914)(10,194,914)
2394 DGP
2395 DGU
2396 SE (170,610,651)(159,764,042)(10,846,609)(54,840)(10,901,50)
2397 SO (72,527,529)(68,616,686)(3,910,843)(3,910,843)
2398 CN (6,625,150)(6,367,792)(257,358)(257,358)
2399 SG (63,698,274)(60,189,456)(3,508,818)(3,508,818)
2400 DEU
2401 SSGCT (33,094)(31,297)(1,797)(1,797)
2402 SSGCH (2,331,547)(2,204,505)(127,Q2)(127,042)
2403 Remove Capital Leases -
2404 Total General Depreciation by Factor (467,815,596)(438,968,216)(28,847,380)(54,80)(28,902,221)
2405
2406
2407 Total Accum Depreciation - Plant In Service B17 (6,626,518,392)(6,251,44,375)(369,078,016)(2,603,977)(371,681,993)
2408 111SP Ac.cum Prov for Amort-Steam
2409 P SG
2410 P SS.GCT
2411 618
2412
2413
2414 111GP Accum Prov for Amort-General
2415 G-SITUS S (15,417,186)(15,417,186)
2416 CUST CN (2,453,306)(2,358,005)(95,300)(95,300)
2417 I-SG SG
2418 PTD SO (9,907,217)(9,372,998)(534,219)(534,219)
2419 P SE
2420 618 (27,77,708)(27,148,189)(629,519)(629,519)
2421
REVISED PROTOCOL Page 2.39
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
2422
2423 111HP Accum Prov for Amort-Hydro
2424 P SG
2425 P SG
2426 P SG (13.027)(12.310)(718)(718)
2427 P SG (390.637)(369.119)(21.518)(21.518)
2428 818 (403.664)(381,429)(22.236)(22.236)
2429
2430
2431 1111P Accum Prev for Amort-Intangible Plant
2432 I-SITUS S (866.992)(130.826)(736.166)(736.166)
2433 P SG
2434 P SG (332.638)(314.315)(18.323)(18.323)
2435 P SE (1.011.087)(946.807)(64.280)(64.280)
2436 I-5G SG (42,153.361)(39.831.344)(2.322.017)(25,402)(2.347,419)
2437 I-SG SG (11.454.352)(10.823,389)(630.963)(630.963)
2438 I-SG SG (3.111.807)(2,940.393)(171,414)(171,414)
2439 CUST CN (89.511.348)(86.034.220)(3,77,128)(3,477.128)
2440 P SSGCT
2441 P SSGCH (67.877)(64.179)(3.699)(3.699)
2442 PTD SO (250,449,855)(236.945.052)(13.504.802)(13.504,802)
2443 818 (398.959.316)(378.030.525)(20.928,792)(25.402)(20.954.194)
244 1111P Less Non-Utilty Plant
2445 NUTIL OTH .
2448 (398.959.316)(378,030,525)(20,928.792)(25.402)(20,954,194)
2447
2448 111390 Accum Amtr - Capital Lease
2449 G-SITUS S (5,302,423)(5,302,423)
2450 P SG (1,390,857)(1,314.242)(76,615)(76,615)
2451 PTD SO 1.860.994 1,760.645 100.349 100,349
2452 (4,832.287)(4.856,020)23.733 23,733
2453
2454 Remove Capita Leae Amtr 4.832,287 4.856,020 (23.733)(23.733)
2455
2456 Total Accum Provision for Amortization 818 (427,140,689)(405,560,142)(21,5ŠÖ.54)(25,402)(21,605,949)
2457
2458
2459
2460
2461 Summary of Amortization by Factor
2462 S (21.586,600)(20,850,434)(736.166)(736.166)
2463 DGP
2464 DGU
2465 SE (1.011,087)(946.807)(64,280)(64.280)
2466 SO (258,496.078)(244.557,406)(13,938.672)(13.93a.72)
2467 CN (91.964.653)(88.392.225)(3,572.428)(3,?2,428)
2468 SSGCT
2469 SSGCH (67.877)(64,179)(3.699)(3.699)
2470 SG (58.846.679)(55,605.111 )(3.241.568)(25,402)(3,266.970)
2471 Less Capital Lease 4.832.287 4.856.020 (23,733)(23.733)
2472 Total Provision For Amortization by Factor (427.140.689)(405.560.142)(21.580.546)(25.402)(21,605.949)
IDAHO REVISED PROTOCOL Page 3.0.1 Total
Revenue Adjustments (Tab 3)
TOTAL
3.7 0 0 0 0 0 0
Wheeling Revenue 0 0 0 0 0 0
1 Operating Revenues:
2 General Business Revenues
3 Interdepartental
4 Speciai Sales
5 Other Operating Revenues
6 Total Opeting Revenues
7
8 Operating EXenses:
g Steam Production
10 Nuclear Production
11 Hydro Production
12 Other Power Supply
13 Transmission
14 Distrbution
15 Customer Accounting
16 Customer Service & Info
17 Sales
18 Administrtive & General
19 Total O&M Expenses
20 Depreciation
21 Amortization
22 Taxes Other Than Income
23 Income Taxes: Federal24 State
25 Deterred Income Taxes
26 Investment Tax Credit Adj.
27 Misc Revenue & Exense
28 Total Operatig Expenses:
29
30 Operating Rev For Retum:
31
32 Rate Base:
33 Electric Plant In Servce
34 Plant Held for Future Use
35 Misc Deferrd De
36 Elec Plant Acq Adj
37 Nuciear Fuel
38 Prepayments
39 Fuel Siock
40 Malerial & Supplies
41 Working Capital
42 Weatherition Loans
43 Misc Rate Base
44 Total Electri Plant:
45
46 Deductions:
47 Accum Prov For Deprec
48 Accum Prov For Amort
49 Accum Def InCom Tax
50 Unamortized ITC
51 Customer Adv For Const
52 Customer Servce Deposns
53 Miscellaneous Deductions
54
55 T otel Deductions:
56
57 Total Rate Base:
58
59
60 Estimated ROE impact
61
62
63
64 TAX CALCULATION:
65
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67 Other Deductions
66 Interest (AFUDC)
69 tnierest
70 Schedule "M" Additions
71 Schedule"M" Deuctions
72 Income Before Tax
73
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75
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77
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69,370
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24,819
Rocky Mountain Power
Idaho General Rate Case. December 2009
Temperature Normalization
PAGE 3.1
TOTAL IDAHO
ACCOUNT ~COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Revenue:
Residential 440 1 (898,935)10 Situs (898,935)
Commercial 442 1 (157,884)10 Situs (157,884)
Total (1,056,819) .(1,056,819)3.1.1
Description of Adjustment:
This adjustment normalizes revenues in the test period by comparing actual sales to temperature normalized sales.
Weather normalization reflects weather or temperature patterns which can be measurably different than normal, defined as
the average weather over a 20-year rollng time period (currently 1990 - 2009). Only residential and commercial sales are
considered weather sensitive. Industrial sales are more sensitive to specific economic factors. This revenue adjustment
corresponds with temperature adjustments made to load and net power costs.
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Description of Adjustment:
Included in actual revenue are a number of items that should not be included in regulatory results. These items include the
SPA credit, the SMUD regulatory liabilty amortization, the acquisition commitment amortization & write-off, and special
contract pass-through revenue. This adjustment normalizes revenues by removing the effect of these items.
Rocky Mountain Power PAGE 3.3
Idaho General Rate Case. December 2009
Effective Price Change
TOTAL IDAHO
ACCOUNT ~COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Revenue:
Residential 440 2 896,631 ID Situs 896,631
Commercial 442 2 227,249 ID Situs 227,249
Industrial 442 2 178,556 ID Situs 178,556
Irrigation 442 2 1,153 ID Situs 1,153
Special Contract 2 442 2 ID Situs
Special Contract 1-Firm 442 2 ID Situs
Special Contract 1-Non Firm 442 2 ID Situs
Special Contract 1 - Curtailed 442 2 ID Situs
Public Street & Highway 444 2 138,610 ID Situs 138,610
Other Sales to Public Authorities 445 2 ID Situs
Total Type 2 1,442,197 1,442,197 3.1.1
Residential 440 3 ID Situs
Commercial 442 3 ID Situs
Industrial 442 3 ID Situs.
Irrigation 442 3 ID Situs
Special Contract 2 442 3 264,117 ID Situs 264,117
Special Contract 1~Firm 442 3 152,597 ID Situs 152,597
Special Contract 1-Non Firm 442 3 2,008,706 ID Situs 2,008,706
Special Contract 1 - Curtailed 442 3 54,183 ID Situs 54,183
Public Street & Highway 444 3 ID Situs
Other Sales to Public Authorities 445 3 ID Situs
Total Type 3 2,479,602 2,479,602 3.1.1
Description of Adjustment:
This adjustment annualizes the price change (Type 2) occurring during the 12 months ended December 2009 from the Idaho
general rate case, Case No. PAC-E-08-07($4.38 milion), which was effective April 18, 2009. This adjustment also
normalizes the proforma effects (Type 3) for special contract price changes effective January 1, 2010 as established in Idaho
general rate case, Case No. PAC-E-07-05.
Rocky Mountain Power PAGE 3.4
Idaho General Rate Case - December 2009
Forecast Price Change
TOTAL IDAHO
ACCOUNT ~COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Revenue:
Residential 440 3 777,380 ID Situs 777,380
Commercial 442 3 (1,578,424 )ID Situs (1,578,424)
Industrial 442 3 (750,475)ID Situs (750,475)
Irrigation 442 3 3,059,398 ID Situs 3,059,398
Special Contract 2 442 3 435,541 ID Situs 435,541
Special Contract 1.Firm 442 3 (0)ID Situs (0)
Special Contract 1-Non Firm 442 3 12,726,685 ID Situs 12,726,685
Special Contract 1 . Curtailed 442 3 50,916 ID Situs 50,916
Public Street & Highway 444 3 (6,674)ID Situs (6,674)
Other Sales to Public Authorities 445 3 ID Situs
Total Type 3 14,714,345 14,714,345 3.1.1
~
Description of Adjustment:
This adjustment reflects the incremental retail reveneue resulting from the Company's load forecast for 2010 compared to
the normalized historical revenue.
Rocky Mountain Power PAGE 3.5
Idaho General Rate Case. December 2009
502 Emission Allowances
TOTAL IDAHO
ACCOUNT ~COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Revenue:
Remove CY 2009 Allowance Sales 4118 3,790,891 SE 6.358%241,007 3.5.1
Add CY 2010 Amortization 4118 (3,518,808)SE 6.358%(223,709)3.5.1
272,083 17,298
Adjustment to Rate Base:
Regulatory Deferred Sales 25398 1 (37,786,481 )SE 6.358%(2,402,284) 3.5.1
Adjustment to Tax:
Accumulated Deferred Income Taxes 190 1 14,340,347 SE 6.358%911,691 3.5.1
Schedule M Deduction SCHMDT 1 3,518,808 SE 6.358%223,709 3.5.1
DIT Expense 41010 1 1,335,423 SE 6.358%84,900 3.5.1
Description of Adjustment:
Over the years, the Company's annual revenue from the sale of sulfur dioxide ("502") emission allowances has been
uneven. This adjustment removes the sales occurring in the six months ended June 2009 and includes amortization of
sales over a 15 year period. This treatment was included in the Company's stipulated general rate case in Case No. PAC-
E-06-4. After June 30,2009, all S02 sales will be captured in the Energy Cost Adjustment Mechanism (ECAM), and the
sales made prior to such date wil continue to be amortized. Consequently, this adjustment reflects the continued
amortization through CY 2010 of all sales made through June 2009.
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Rocky Mountain Power PAGE 3.6
Idaho General Rate Case. December 2009
Green Tag Revenue
TOTAL IDAHO
ACCOUNT Type COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Revenue:
Re-allocation for Non-RPS States 456 19,847,414.SG 5.508%1,093,294 3.6.1
Adjustment for CA RPS Banking 456 (1,210,981)CA Situs 3.6.1
Adjustment for OR RPS Banking 456 (18,636,433)OR Situs 3.6.1
1,093,294
Incremental CY 2010 REC Revenues 456 3 40,985,931 SG 5.508%2,257,709 3.6.2
Re-allocation for Non-RPS States 456 3 16,015,051 SG 5.508%882,189 3.6.2
Adjustment for CA RPS Banking 456 3 (977,151 )CA Situs 3.6.2
Adjustment for OR RPS Banking 456 3 (15,037,900 )OR Situs 3.6.2
882,189
Description of Adjustment:
A market for green tags or renewable energy credits ("RECs") exists where the tag or "green" traits of qualifying power
production facilties can be detached and sold separately from the power itself. These RECs may be applied to meet
renewable portolio standards in various states. Currently, California and Oregon have renewable portolio standards. As
such, the Company does not sell California or Oregon eligible RECs. Instead, the Company uses the renewable output to
comply with current year or future year renewable portolio requirements. This adjustment adds into results an
incremental amount of calendar year 2010 REC revenues over and above the 2009 leveL. This adjustment also
reallocates Oregon and California's SG factor amounts to the Company's other jurisdictions, consistent with the
agreement with the Multi-State Process (MSP) standing committee.
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Page 3.6.3
Rocky Mountain Power
Idaho General Rate Case - December 2009
Green Tag Revenues
Total Revenue Calculation
Total Wind Generation from GRID - MWH 4,339,922
Renewable Energy Credits Allocation
IDIWAIUTIWY/FERC - SG Factor Allocated Portion
Wind MWH Available for Sale
71.90%
3,120,573
Percent Sold in Test Period
MWH Sold in Test Period
75.00%
2,340,430
Known Contract Sales - MWh
Available Wind Credits Remaining for Sale
1,782,626
557,803
2,340,430
Known Contract Sales for 2010 - Wind
Remaining Available Sold ~ $5.00 per MWH
$69,165,212 A
$2,789,017 B
Total 2010 Vintage REC Sales
Wind
Non-Wind
Total 2010 Revenue for CY 2010 Vintage
$71,954,230 (A+B)
$18,010,672
$89,964,902
Total 2010 Revenue for CY2009 Vintage $1,814,795
$91,779,696 Ref 3.6.2Grand Total Revenue for Test Period
Adjustment Detail:
Actual Wheeling Revenues 12 ME Dec 2009
Total Adjustments
Normalized Wheeling Revenues
63,697,983
1,259,331
64,957,314
81
3.7.2
3.7.2
Description of Adjustment:
This adjustment reflects the level of wheeling revenues the Company expects in the12 months ending December 31,2010
by adjusting the actual revenues for the 12 months ended December 31 , 2009 for normalizing, annualizing and pro forma
changes. Imbalance penalty revenue and expense is removed to avoid any impact on regulated results.
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l
11
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.
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7
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.
28
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3
60
8
5
5
11
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IDAHO REVISED PROTOCOL Page 4.0.1 Total
O&M Adjustments (Tab 4)
TOTAl
4.3.2 4.4 4.5 4.6 4.7 4.8 4.9
4.3.2. Wage and Affliate
Employe Benef. Traition Savings Irrigation Load Incrememal Remove Non-Managment Fee
Pro Forma (MEHC)Control Program Generation O&M Recurrng Entries (MEHC)Intervenor Funding
1 Operatlng Revenues:
2 General Business Revenues
3 Interdepartental
4 Special Sales
5' Other Operating Revenues
6 Total Operatlng Revenues
7
8 Operatlng Expenses:
9 Steam Production 80,118 (24)
10 Nuclear Production
11 Hydro Producton
12 Other Power Supply 7.182,252 323,842 (72,216)
13 Transmission
14 Distrbutn 21,542 (43)
15 Customer Accounting 135,538
16 Customer Service & Info 23,034
17 Sales
18 Adminlstratlve & General 229,285 (610.194)(56.782)4,395
19 Total O&M Expenses 409.398 (610,194)7,182,252 403,960 (72,283)(56,782)4,395
20 Depreciation
21 Amorlon
22 Taxes Other Than Income
23 Income Taxes: Federal (136.784)15.132 (2,399,662)(134,967)24.151 18,971 13.165
24 Slate (18.587)2,056 (326,074)(18.340)3,282 2.578 1,789
25 Deferred Income Taxes 214,387 -(16,621)
26 investment Tax Credit Adj.
27 Misc Revenue & Expense
28 Total Operatlng Expenses:254.027 (378.619)4,456,515 250.653 (44,851)(35.232)2.27
29
30 Operating Rev For Return:(254.027)378.19 (4,456.515)(250,653)44.851 35,232 (2.727)
31
32 Rate Base:
33 Electric Plant In Service
34 Plant Held for F ulure Use
35 Misc Deferred Debits (17.580)
36 Elec Plant Acq Adj
37 Nuclear Fuel
38 Prepayments
39 Fuel Stock
4Q Material & Supplies
41 Working Capital
42 Weatherization Loans
43 Mlsc Rate Base
44 Total Electric Plant:(17,580)
45
46 Deductions:
47 Accum Prov For Depree
48 Accum Prov For Amort
49 Accum De Income Tax 232,104 6.672
50 Unamortize iTC
51 Customer Adv For Canst
52 Customer Service Deosits
53 Miscellaneous Deductons
54
55 Total DeducOris:232,104 6,672
58
57 Total Rate Base:232,104 (10.908)
58
59
60 Estimated ROE impact -0.086%0.126%-1.535%-0.086%0,015%0.012%-0.001%
61
62
63
64 TAX CALCULATION:
65
66 Operating Revenue (408.398)610,194 (7,182.252)(403,980)72,283 56,782 (4,395)
67 Other Deductions
68 Interest (AFUDC)
69 Interest
70 Schedule "M" Additions (610.194)17.580
71 Schedule "M" Deductions (45,280)(28,217)
72 Income Before Tax (409,398)45,290 (7,182,252)(403,960)72.283 58,782 39,4Q2
73
74 State Income Taxes (18,587)2.056 (326,074)(18,340)3,282 2.578 1,789
75
76 Taxable Income (390.811)43.234 (6.85.178)(385,620)69,002 54,204 37.613
77
78 Federal Income Taxes (136,784)15,132 (2,399.862)(134,967)24.151 18.971 13,185
IDAHO REVISED PROTOCOL
O&M Adjustments (Tab 4)
TOTAL
1 Operating Revenues:
2 General Business. Revenue
3 Interdepartental
4 Special Sales
5 Other Operating Revenues
6 Total Operating Revenues
7
8 Operating Expenses:
g Steam Production
10 Nuclear Productin
11 Hydro Proucton
12 Other Power Supply
13 Transmission
14 Distibution
15 Customer Accounting
16 CuslOmer Servce & Info
17 Sales
18 AdministraUve& General
19 Total O&M Expenses
20 DepreciaUon
21 Amortzation
22 Taxes Other Than Income
23 Income TaxeS' Federal24 State
25 Deferred Income Taxes
26 Investment Tax Credk Adj.
27 Misc Revenue & Expense
28 T ota Operating ExpenseS;
29
30 Operating Rev For Return:
31
32 Rate Base:
33 Electric Plant In Service
34 Plant Held for Future Use
35 Misc Deerrd Debits
36 Elec Plant Acq Adj
37 Nui;lear Fuel
38 Prepayments
39 Fuel Stock
40 Material & Supplies
41 Working Capitl
42 Weatherization Loans
43 Misc Rate Base
44 Total Electc Plant:
45
46 DeducUons:
47 Accum Prov For Deprec
48 Accu Prov For Amrt
49 Accum Def Income Tax
50 Unamortzed ITC
51 Customer Adv For Const
52 Customer Service Deposit
53 Miscellaneous Deducons
54
55 Total Deductons:
56
57 Total Rate Base:
56
59
60 Estimated ROE impact
61
62
63
64 TAX CALCULATION:
85
66 Operating Revenue
67 Other Deductions
88 Interest (AFUDC)
69 Interest
70 Schedule "M" Additions
71 Schedule "M" Deductons
72 Income Before Tax
73
74 Stale Income Taxes
75
76 Taxable Income
77
78 Federal Income Taxes
Page 4.0.3 Total
4.17 o o o o
Avian Setten o ooo
26,961
26,961
1,497
(10,252)
(1,393)
845
17,658
(17,658)
74,490
74,490
(1,497)
(645)
(2,342)
72,148
-0.007%0.00%0.00%0,00%0.00%
(28,458)
2,227
(30,666)
(1,393)
(29,292)
(10,252)
Rocky Mountain Power PAGE 4.1
Idaho General Rate Case. December 2009
Miscellaneous General Expense
TOTAL IDAHO
ACCOUNT ~COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Expense:
Company Plane 557 1 (4,810)SG 5.508%(265)
Company Plane 921 1 (1,637)SO 5.392%(88)
Advertising Expense 909 1 (8,535)CN 3.885%(332)
Office Supplies & Expense 921 1 (581,208)SO 5.392%(31,340)
Office Supplies & Expense 921 1 569,225 UT Situs
Miscellaneous General Expense 930 1 (8,500)10 Situs (8,500)
Miscellaneous General Expense 930 1 (129,400)OR Situs
Miscellaneous General Expense 930 1 (157,822)UT Situs
Miscellaneous General Expense 930 1 (1,250)SO 5.392%(67)
Total (323,938)(40,592)4.1.1
Description of Adjustment:
This adjustment removes from results of operations certain miscellaneous expenses that should have been charged
to non-regulated accounts and corrects the allocation of a sales tax refund.
Rocky Mountain Power Page 4.1.1
Idaho General Rate Case - December 2009
Miscellaneous General Expense
Description FERC Factor Amt to Exclude
Company Plane
Other Power Supply 557 SG 4,810
Office Supplies and Expenses 921 SO 1,637
6,447
FERC 909 - Informational & Instructional Advertising
Festivals 909 CN 6,613
Miscellaneous 909 CN 971
Donations 909 CN 672
Public Relations 909 CN 279
8,535
FERC 921 . Ofce Supplies & Expenses
Charitable Donations and Sponsorships 921 SO 2,278
Employee Expenses 921 SO 2,341
Legislative & Lobbyist 921 SO 2,914
Misc Expense 921 SO 4,450
Reclassify Utah sales tax credits 921 UT (569,225)
Reclassif Utah sales tax credits 921 SO 569,225
11,984
FERC 930 - Miscellaneous General Expense
Challenge Grant - Idaho 930 ID 8,500
Challenge Grant - Oregon 930 OR 129,400
EDCU Rent Contribution 930 UT 100,000
Utah Sports Authority Rent Contribution 930 UT 57,072
EDCU Other Contribution 930 SO 1,250
EDCU Other Contribution 930 UT 750
296,972
TOTAL MISCELLANEOUS GENERAL EXPENSE REMOVED 323,938
Ref4.1
Rocky Mountain Power PAGE 4.2
Idaho General Rate Case - December 2009
4.2 . Wage and Employee Benefit . Annualization
TOTAL IDAHO
ACCOUNT ~COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Expense:
Steam Operations 500 2 13,665 SG 5.508%753
Fuel Related Non-NPC 501 2 339 SE 6.358%22
Steam Operations 502 2 15,216 SG 5.508%838
Steam Operations 503 2 47 SE 6.358%3
Steam Operations 505 2 1,349 SG 5.508%74
Steam Operations 506 2 33,591 SG 5.508%1,850
Steam Operations 506 2 (0)SSGCH 5.449%(0)
Steam Maintenance 510 2 2,167 SG 5.508%119
Steam Maintenance 511 2 5,282 SG 5.508%291
Steam Maintenance 511 2 (1 )SSGCH 5.449%(0)
Steam Maintenance 512 2 22,616 SG 5.508%1,246
Steam Maintenance 512 2 (111 )SSGCH 5.449%(6)
Steam Maintenance 513 2 9,410 SG 5.508%518
Steam Maintenance 514 2 2,300 SG 5.508%127
Steam Maintenance 514 2 (4)SSGCH 5.449%(0)
Hydro Operations 535 2 3,602 SG-P 5.508%198
Hydro Operations 535 2 4,012 SG-U 5.508%221
Hydro Operations 536 2 71 SG-P 5.508%4
Hydro Operations 536 2 (2)SG-U 5.508%(0)
Hydro Operations 537 2 477 SG-P 5.508%26
Hydro Operations 537 2 54 SG-U 5.508%3
Hydro Operations 539 2 3,680 SG-P 5.508%203
Hydro Operations 539 2 2,814 SG-U 5.508%155
Hydro Operations 540 2 (11 )SG-P 5.508%(1 )
Hydro Operations 540 2 (1 )SG-U 5.508%(0)
Hydro Maintenance 541 2 1 SG-P 5.508%0
Hydro Maintenance 542 2 223 SG-P 5.508%12
Hydro Maintenance 542 2 72 SG-U 5.508%4
Hydro Maintenance 543 2 232 SG-P 5.508%13
Hydro Maintenance 543 2 103 SG-U 5.508%6
Hydro Maintenance 544 2 418 SG-P 5.508%23
Hydro Maintenance 544 2 195 SG-U 5.508%11
Hydro Maintenance 545 2 395 SG-P 5.508%22
Hydro Maintenance 545 2 139 SG-U 5.508%8
Other Operations 546 2 23 SG 5.508%1
Other Operations 548 2 3,897 SG 5.508%215
Other Operations 548 2 698 SSGCT 5.429%38
Other Operations 549 2 2,326 SG 5.508%128
Other Maintenance 552 2 167 SG 5.508%9
552 2 58 SSGCT 5.429%3
129,506 7,137 4.2.2
Description of Adjustment:
The Company has several labor groups, each with different effective contract renewal dates. This adjustment
annualizes the wage increases that occurred during the year for labor charged to operations and maintenance
accounts. See page 4.3.3 for more information on how this adjustment was calculated.
Rocky Mountain Power PAGE 4.2.1
Idaho General Rate Case - December 2009
4.2.1 - Wage and Employee Benefit - Annualization
TOTAL IDAHO
ACCOUNT ~COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Expense:
Other Maintenance 553 2 1,756 SG 5.508%97
Other Maintenance 553 2 167 SSGCT 5.429%9
Other Maintenance 554 2 36 SG 5.508%2
Other Maintenance 554 2 68 SSGCT 5.429%4
Other Operations 556 2 559 SG 5.508%31
Other Expenses 557 2 27,724 SG 5.508%1,527
Transmission Operations 560 2 4,007 SG 5.508%221
Transmission Operations 561 2 6,819 SG 5.508%376
Transmission Operations 562 2 829 SG 5.508%46
Transmission Operations 563 2 76 SG 5.508%4
Transmission Operations 566 2 231 SG 5.508%13
Transmission Operations 567 2 187 SG 5.508%10
Transmission Maintenance 568 2 14 SG 5.508%1
Transmission Maintenance 569 2 1,995 SG 5.508%110
Transmission Maintenance 570 2 6,157 SG 5.508%339
Transmission Maintenance 571 2 1,350 SG 5.508%74
Transmission Maintenance 572 2 31 SG 5.508%2
Transmission Maintenance 573 2 11 SG 5.508%1
Distribution Operations 580 2 15,130 SNPD 4.614%698
Distribution Operations 581 2 11,269 SNPD 4.614%520
Distribution Operations 582 2 1,719 10 Situs 81
Distribution Operations 582 2 20 SNPD 4.614%1
Distribution Operations 583 2 4,171 10 Situs 225
Distribution Operations 583 2 13 SNPD 4.614%1
Distribution Operations 585 2 176 SNPD 4.614%8
Distribution Operations 586 2 4,061 10 Situs 186
Distribution Operations 586 2 774 SNPD 4.614%36
Distribution Operations 587 2 9,060 10 Situs 330
Distribution Operations 587 2 0 SNPD 4.614%0
Distribution Operations 588 2 (555)10 Situs (43)
Distribution Operations 588 2 (20)SNPD 4.614%(1 )
Distribution Operations 589 2 (335)10 Situs 1
Distribution Operations 589 2 0 SNPD 4.614%0
Distribution Maintenance 590 2 580 10 Situs 63
Distribution Maintenance 590 2 4,569 SNPD 4.614%211
Distribution Maintenance 592 2 6,220 10 Situs 516
Distribution Maintenance 592 2 1,484 SNPD 4.614%68
Distribution Maintenance 593 2 19,488 10 Situs 2,041
Distribution Maintenance 593 2 417 SNPD 4.614%19
Distribution Maintenance 594 2 11,437 10 Situs 384
141,693 8,209 4.2.2
Description of Adjustment:
The Company has several labor groups, each with different effective contract renewal dates. This adjustment
annualizes the wage increases that occurred during the year for labor charged to operations and maintenance
accounts. See page 4.3.3 for more information on how this adjustment was calculated.
Description of Adjustment:
The Company has several labor groups, each with different effective contract renewal dates. This adjustment
annualizes thewage increases that occurred during the year for labor charged to operations and maintenance
accounts. See page 4.3.3 for more information on how this adjustment was calculated.
Rocky Mountain Power PAGE 4.3
Idaho General Rate Case - December 2009
4.3 - Wage and Employee Benefit - Pro Forma
TOTAL IDAHO
ACCOUNT ~COMPANY FACTOR FACTOR % ALLOCATED REF#
Adjustment to Expense:
Steam Operations 500 3 662,150 SG 5.508%36,475
Fuel Related Non-NPC 501 3 16,436 SE 6.358%1,045
Steam Operations 502 3 737,306 SG 5.508%40,615
Steam Operations 503 3 2,260 SE 6.358%144
Steam Operations 505 3 65,362 SG 5.508%3,600
Steam Operations 506 3 1,627,642 SG 5.508%89,659
Steam Operations 506 3 (10)SSGCH 5.449%(1 )
Steam Maintenance 510 3 105,023 SG 5.508%5,785
Steam Maintenance 511 3 255,919 SG 5.508%14,097
Steam Maintenance 511 3 (41 )SSGCH 5.449%(2)
Steam Maintenance 512 3 1,095,870 SG 5.508%60,366
Steam Maintenance 512 3 (5,360)SSGCH 5.449%(292)
Steam Maintenance 513 3 455,944 SG 5.508%25,116
Steam Maintenance 514 3 111,431 SG 5.508%6,138
Steam Maintenance 514 3 (203)SSGCH 5.449%(11)
Hydro Operations 535 3 174,539 SG-P 5.508%9,614
Hydro Operations 535 3 194,385 SG-U 5.508%10,708
Hydro Operations 536 3 3,437 SG-P 5.508%189
Hydro Operations 536 3 (92)SG-U 5.508%(5)
Hydro Operations 537 3 23,093 SG-P 5.508%1,272
Hydro Operations 537 3 2,598 SG-U 5.508%143
Hydro Operations 539 3 178,315 SG-P 5.508%9,822
Hydro Operations 539 3 136,331 SG-U 5.508%7,510
Hydro Operations 540 3 (543)SG-P 5.508%(30)
Hydro Operations 540 3 (46)SG-U 5.508%(3)
Hydro Maintenance 541 3 42 SG-P 5.508%2
Hydro Maintenance 542 3 10,781 SG-P 5.508%594
Hydro Maintenance 542 3 3,491 SG-U 5.508%192
Hydro Maintenance 543 3 11,235 SG-P 5.508%619
Hydro Maintenance 543 3 4,978 SG-U 5.508%274
Hydro Maintenance 544 3 20,276 SG-P 5.508%1,117
Hydro Maintenance 544 3 9,449 SG-U 5.508%520
Hydro Maintenance 545 3 19,144 SG-P 5.508%1,055
Hydro Maintenance 545 3 6,736 SG-U 5.508%371
Other Operations 546 3 1,117 SG 5.508%62
Other Operations 548 3 188,808 SG 5.508%10,401
Other Operations 548 3 33,810 SSGCT 5.429%1,835
Other Operations 549 3 112,717 SG 5.508%6,209
Other Maintenance 552 3 8,094 SG 5.508%446
Other Maintenance 552 3 2,806 SSGCT 5.429%152
6,275,230 345,804 4.3.2
Description of Adjustment:
The Company has several labor groups, each with different effective contract renewal dates. This adjustment
recognizes increases that have occurred, or are projected to occur for labor charged to operation and maintenance
accounts through December 2010. See page 4.3.3 for more information on how this adjustment was calculated.
Rocky Mountain Power PAGE 4.3.1
Idaho General Rate Case - December 2009
4.3.1 . Wage and Employee Benefit - Pro Forma
TOTAL IDAHO
ACCOUNT ~COMPANY FACTOR FACTOR % ALLOCATED REF#
Adjustment to Expense:
Other Maintenance 553 3 85,103 SG 5.508%4,688
Other Maintenance 553 3 8,074 SSGCT 5.429%438
Other Maintenance 554 3 1,730 SG 5.508%95
Other Maintenance 554 3 3,297 SSGCT 5.429%179
Other Operations 556 3 27,105 SG 5.508%1,493
Other Expenses 557 3 1,343,383 SG 5.508%74,000
Transmission Operations 560 3 194,151 SG 5.508%10,695
Transmission Operations 561 3 330,431 SG 5.508%18,202
Transmission Operations 562 3 40,176 SG 5.508%2,213
Transmission Operations 563 3 3,661 SG 5.508%202
Transmission Operations 566 3 11,170 SG 5.508%615
Transmission Operations 567 3 9,060 SG 5.508%499
Transmission Maintenance 568 3 692 SG 5.508%38
Transmission Maintenance 569 3 96,663 SG 5.508%5,325
Transmission Maintenance 570 3 298,344 SG 5.508%16,434
Transmission Maintenance 571 3 65,429 SG 5.508%3,604
Transmission Maintenance 572 3 1,490 SG 5.508%82
Transmission Maintenance 573 3 539 SG 5.508%30
Distribution Operations 580 3 733,101 SNPD 4.614%33,824
Distribution Operations 581 3 546,043 SNPD 4.614%25,194
Distribution Operations 582 3 83,298 ID Situs 3,927
Distribution Operations 582 3 967 SNPD 4.614%45
Distribution Operations 583 3 202ì086 ID Situs 10,893
Distribution Operations 583 3 626 SNPD 4.614%29
Distribution Operations 585 3 8,545 SNPD 4.614%394
Distribution Operations 586 3 196,772 ID Situs 9,007
Distribution Operations .586 3 37,490 SNPD 4.614%1,730
Distribution Operations 587 3 438,979 ID Situs 15,975
Distribution Operations 587 3 18 SNPD 4.614%1
Distribution Operations 588 3 (26,917)ID Situs (2,096)
Distribution Operations 588 3 (984)SNPD 4.614%(45)
Distribution Operations 589 3 (16,239)ID Situs 33
Distribution Operations 589 3 4 SNPD 4.614%0
Distribution Maintenance 590 3 28,119 ID Situs 3,062
Distribution Maintenance 590 3 221,371 SNPD 4.614%10,214
Distribution Maintenance 592 3 301,370 ID Situs 25,001
Distribution Maintenance 592 3 71,918 SNPD 4.614%3,318
Distribution Maintenance 593 3 944,314 ID Situs 98,901
Distribution Maintenance 593 3 20,194 SNPD 4.614%932
Distribution Maintenance 594 3 554,178 ID Situs 18,600
6,865,748 397,770 4.3.2
Description of Adjustment:
The Company has several labor groups, each with different effective contract renewal dates. This adjustment
recognizes increases that have occurred, or are projected to occur for labor charged to operation and maintenance
accounts through December 2010. See page 4.3.3 for more information on how this adjustment was calculated.
Rocky Mountain Power PAGE 4.3.2
Idaho General Rate Case - December 2009
4.3.2 . Wage and Employee Benefit - Pro Forma
TOTAL IDAHO
ACCOUNT ~COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Expense:
Distribution Maintenance 594 3 236 SNPD 4.614%11
Distribution Maintenance 595 3 572 ID Situs
Distribution Maintenance 595 3 36,060 SNPD 4.614%1,664
Distribution Maintenance 596 3 74,600 ID Situs 4,576
Distribution Maintenance 597 3 164,337 ID Situs 10,654
Distribution Maintenance 597 3 35,286 SNPD 4.614%1,628
Distribution Maintenance 598 3 5,915 ID Situs 125
Distribution Maintenance 598 3 62,524 SNPD 4.614%2,885
Customer Accounts 901 3 100,979 CN 3.885%3,923
Customer Accounts 901 3 842 ID Situs 55
Customer Accounts 902 3 57,365 CN 3.885%2,228
Customer Accounts 902 3 812,330 ID Situs 61,249
Customer Accounts 903 3 1,484,105 CN 3.885%57,651
Customer Accounts 903 3 218,929 ID Situs 10,136
Customer Accounts 905 3 7,624 CN 3.885%296
Customer Service 907 3 10,000 CN 3.885%388
Customer Service 908 3 111,728 CN 3.885%4,340
Customer Service 908 3 1,202 OTHER 0.000%
Customer Service 908 3 182,036 ID Situs 17,539
Customer Service 909 3 19,539 CN 3.885%759
Customer Service 910 3 193 CN 3.885%7
Administrative & General 920 3 3,285,419 SO 5.392%177,157
Administrative & General 921 3 2,005 SO 5.392%108
Administrative & General 922 3 1,253,997 SO 5.392%67,6Hl
Administrative & General 923 3 (472,184)SO 5.392%(25,461 )
Administrative & General 928 3 47,213 ID Situs 290
Administrative & General 928 3 1,415 SO 5.392%76
Administrative & General 929 3 (4,475)SO 5.392%(241 )
Administrative & General 935 3 559 ID Situs
Administrative & General 935 3 180,585 SO 5.392%9,738
7,680,936 409,398 Below
6,275,230 345,804 4.3
6,865,748 397,770 4.3.1
7,680,936 409,398 Above
Total WEBA Pro forma Adjustment 20,821,914 1,152,972 4.3.4
Description of Adjustment:
.
The Company has several labor groups, each with different effective contract renewal dates. This adjustment
recognizes increases that have occurred, or are projected to occur for labor charged to operation and maintenance
accounts through December 2010. See page 4.3.3 for more information on how this adjustment was calculated.
Rocky Mountain Power
Idaho General Rate Case. December 2009
Wage and Employee Benefit Adjustment
The unadjusted, annualized (12 months ended December 2009), and pro forma period (12 months ending
December 2010) labor expenses are summarized on page 4.3.4. The following is an explanation
of the procedures used to develop the proforma labor expenses.
1. Actual December 2009 total labor related expenses are identified on page 4.3.4, including bare
labor, incentive, other labor, pensions, benefits, and payroll taxes.
2. Actual December 2009 expenses for regular time, overtime, and premium pay were identified by
labor group and annualized to reflect wage increases during the base period. These annualizations
can be found on page 4.3.5.
3. The annualized December 2009 regular time, overtime, and premium pay expenses were then
escalated prospectively by labor group to December 2010 (see page 4.3.6). Union costs
were escalated using the contractual rates found on page 4.3.7. Non-union costs were escalated
using actual increases.
4. Miscellaneous non-union incentive payments were escalated at the non-union rate. The Annual
Incentive Plan costs are included at the 2010 budgeted leveL. Union employees do not participate
in the Company's annual incentive program; instead, they receive annual increases to their
wages that are reflected in the escalation described above.
5. Pro forma December 2010 pension and employee benefit expenses are based on either December
2010 actuarial projections or are calculated by using actual data and then escalated to December 2010.
These expenses can be found on page 4.3.9.
6. Payroll tax calculations can be found on page 4.3.10.
Page 4.3.3
Page 4.3.4
Rocky Mountain Power
Idaho General Rate Case. December 2009
Wage and Employee Benefit Adjustment Annualiz
5OO1XX Regular Ordinary lime 418,399,378 418,893,878 494,500 425,287,985 6,394,107 4.3.5
5OO2XX Ovme 51,932,555 51,993,934 61,378 52,787,583 793,649 4.3.5
5003XX Preium Pay 5,481,914 5488393 6479 5572 169 83776 4.3.5
Subtotal for Escala 475,813,847 476376204 56 357 483647737 7271533 4.3.5 & 4.3.6
500110 Sear Labo Adjustmet 1,457,921 1,459,64 1,723 1,481,924 22,280 4.3.8
500Sl Unuse Leave Accral (503,856)(504,452)(595)(512,152)(7,700)4.3.8
500600 Temporary/Contrct Labor 22 22 22
500700 SeeranceReundancy (1)317,884 317,884 317,884
500850 oter Salary/Labo Co 7,077,706 7,077,706 7,077,706
50109X JO Cutback (1,371,822)1373444 1621 1394408 20965 4.3.8
Subtol Bare Labor 4112,791,702 483353565 561863 490618713 72651411
50000 Bous 899,939 899,939 907,859 7,919 4..8
50010 Annual Incentie 29,876,294 29876294 32196 000 2319706 4.3.8
Total Incetive 30,776,233 30776233 33103859 327626
500250 Overtime Meals 912,893 912,893 912,893
501325 Physica Exam 1,627 1,627 1,627
502300 EducatiOl Asistnce 307,290 307,290 307,290
580899 Mining SalaryBenefi Creit (179,429)179429 179429
Total Ot Labor 1,042,380 1042380 104 380
Subtotal Labor and Incntwe 514,610,314 51517 178 5611163 524764952 9592774
50110X Pensi (2)29,902,759 29,902,759 38,965,062 9,062,304 4.3.9
501115 5ERP Plan 3,537,000 3,537,000 2,60,00 (937,000)4.3.9
50115X Post Retirent Benefits. FAS 106 (2)16,342,489 16,342,489 21,164,750 4,822,261 4.3.9
501160 Pos Employment Benefits - FAS 112 5,261,415 5 261 415 5347889 86474 4.3.9
Total Pensions 55,043,663 55043 663 68077 701 13034039 4.3.9
501102 PensiOn Administtin 546,200 546,200 559,653 13,453 4.3.9
50112X Medical 55,801,071 55,801,071 57,914,222 2,113,151 4.3.9
501175 Dental 1,838,403 1,838,403 2,282,474 444,071 4..9
501200 Vision 252,236 252,236 257,393 5,156 4.3.9
50122X Ufe 1,050,608 1,050,608 1,068,186 17,578 4.3.9
501250 401(k)21,903,761 21,903,761 15,994,864 (5,908,897)4.3.9
501251 401(k) AdminlstratiOl (245,579)(245,579)171,847 417,426 4.3.9
501252 401(k) Fixed 8,684,576 8,684,576 16,858,963 8,174,386 4.3.9
501275 Acdental Death & Disbilty 51,788 51,788 52,233 445 4.3.9
501300 LOIg' Ter Disabilit 2,677,087 2,677,087 3,386,732 709,645 4.3.9
5016XX Worers Compesati 1,573,683 1,57,683 1,599,616 25,933 4.3.9
50290 Other saiary Overea 1,765,640 1765640 1794 599 28958 4.3.9
Total BeneFit 95,899,475 95899475 101940 781 6041 6 4.3.9
5ubtotal Pensions and Benefits 150,943,138 150943138 170018483 19075345 4.3.9
580500 Payrol Tax Expese 35,045,109 35,085,658 40,550 35,607,418 521,759 4.3.10
580700 Payrll Tax ExpeseUnempiyment 3,352,222 3352222 3352222
Total Payroll Taxes 38,397,330 38 37880 40550 38959639 521759
Total Labor 703,950,783 704 553196 60 413 733743074 29189878 4.3.14
NOI.utlity and capitlized Labor 201,804,020 201,976,715 172,696 210,344,679 8,367,964 4.3.14
Total Utility Labor 502,146,763 50 5 ,480 4 ,717 523,8,394 0,82,914 4.3.14
Page 4.2.2 Pag 4.3.2
Notes:
(1) MEHCTransitin severeæ amortizatiOl accl effec are not induded.
(2) PensiOl Curtilment Gain and PensiOl and Post Retireent Measuremet Date Change effec are not inlcuded.
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Page 4.3.9
Rocky Mountain Power
Idaho General Rate Case - December 2009
Wage and Employee Benefi Adjustment
D E E - A
50110X Pensions - FAS 87 29,902,759 31,080,708 40,50,000 38,965,062 9,062,304 4.3.4
501115 SERP Plan 3,537,000 3,537,000 2,600,000 2,600,000 (937,000)4.3.4
50115X Post Retireent Benefits - FAS 106 16,342,489 16,833,001 21,800,000 21,164,750 4,822,261 4.3.4
501160 Post Employment Benef - FAS 112 5,261,415 5,418,937 5,508,000 5,347,889 86,474 4.3.4
Subtotal 55,043,663 56,869,646 70,408,000 68,077,701 13,034,039 4.3.4
501102 Pension Administration 546,200 559,226 573,000 559,653 13,453 4.3.4
50112X Medical 55,801,071 57,646,947 59,830,000 57,914,222 2,113,151 4.3.4
501175 Detal 1,838,403 1,912,122 2,374,000 2,282,474 44,071 4.3.4
501200 Vision 252,236 262,631 268,000 257,393 5,156 4.3.4
50122X Life 1,050,608 1,081,899 1,100,000 1,068,186 17,578 4.3.4
501250 401(k)21,903,761 22,521,557 16,446,000 15,994,864 (5,908,897)4.3.4
501251 401(k) Administration (245,579)(252,94)177,000 171,847 417,426 4.3.4
501252 401(k) Enhanced Fixed 8,684,576 8,740,745 16,968,000 16,858,963 8,174,386 4.3.4
501275 Acddental Death & Disabilit 51,788 52,548 53,000 52,233 445 4.3.4
501300 Long-Term Disabilit 2,677,087 2,779,268 3,516,000 3,386,732 709,645 4.3.4
5016XX Worker's Compensation 1,573,683 1,616,364 1,643,000 1,599,616 25,933 4.3.4
502900 Other Salary Overhead 1,765,640 1,767,019 1,796,000 1,794,599 28,958 4.3.4
Subtotal 95,899,475 98,687,383 104,744,000 101,940,781 6,041,306 4.3.4
Grand Total 150,943,138 155,557,029 17S,152,000 170,018,483 19,075,345 4.3.4
Ref 4.3.4 Ref 4.3.4
7,265,148 4.3.4
1.45%
105,345
6.20%
450,439
92.45%
416,415
521,759 4.3.4
Rocky Mountain Power
Idaho General Rate Case - December 2009
Wage and Employee Benefit Adjustment
Payroll Tax Adjustment Calculation
FICA Calculated on December 2009 Annualized Labor
Annualized Wages Adjustment
Medicare Rate (no cap)
561,863
1.45%
8,147
Social Security Rate 6.20%
34,836
93.02%
32,403
Percentage of Social Security Eligible Wages
Total FICA Tax 40,550
FICA Calculated on December 2010 Pro Forma Labor
Pro Forma Wages Adjustment
Medicare Rate (no cap)
Social Security Rate
Percentage of Social Security Eligible Wages
Total FICA Tax
Page 4.3.10
Reference
4.3.4
4.3.4
Page 4.3.11
Rocky Mountain Power
Idaho General Rate Case. December 2009
Wage and Employee Benefit Adjustment
Adjustment by FERC Account and Revised Protocol Factor
Actuals Annualized Proforma
12 Months Ended Annualization 12 Months Ended Proforma 12 Months Ending
Indicator December 2009 % Of Total Adjustment December 2009 Adjustment December 2010
5005G 15,968,586 2.27%13,665 15,982,251 662,150 16,644,401
5015E 396,382 0.06%339 396,722 16,436 413,158
5025G 17,781,076 2.53%15,216 17,796,293 737,306 18,533,599
5035E 54,509 0.01%47 54,556 2,260 56,816
5055G 1,576,294 0.22%1,349 1,577,643 65,362 1,643,005
5065G 39,252,649 5,58%33,591 39,286,240 1,627,642 40,913,882
50655GCH (240)0.00%(0)(240)(10)(250)
5105G 2,532.755 0.36%2,167 2,534,922 105,023 2,639,945
5115G 6,171,798 0.88%5,282 6,177,080 255,919 6,432,998
51155GCH (992)0.00%(1)(992)(41)(1,034)
5125G 26,428,298 3.75%22,616 26,50,915 1,095,870 27,546,785
51255GCH (129,273)-002%(111)(129,383)(5,360)(134,744)
5135G 10,995,656 1.56%9,410 11,005,066 455,944 11,461,009
5145G 2,687,309 0.38%2,300 2,689,609 111,431 2,801,040
514S5GCH (4,893)0.00%(4)(4,897)(203)(5,100)
5355G.P 4,209,224 0.60%3,602 4,212,826 174,539 4,387,365
535SG.U 4,687,830 0.67%4,012 4,691,841 194,385 4,886,226
536SG.P 82,878 0.01%71 82,949 3,437 ii,385
536SG.U (2,224)0.00%(2)(2,226)(92)(2,318)
5375G-P 556,911 0.08%477 557,388 23,093 580,480
537SG-U 62,658 0.01%54 62,712 2,598 65,310
539SG-P 4,300,287 0.61%3,680 4,303,967 178,315 4,482,282
539SG.U 3,287,792 0.47%2,814 3,290,606 136,331 3,426,937
54SG.P (13,096)0.00%(11)(13,107)(543)(13,650)
54OSG.U (1,112)0.00%(1)(1,113)(46)(1,159)
541SG-P 1,016 0.00%1 1,017 42 1,059
5425G.P 260,007 0.04%223 260,229 10,781 271,010
5425G-U 84,192 0.01%72 84,264 3,491 87,756
5435G.P 270,939 0.04%232 271,170 11,235 282,405
5435G"U 120,062 0.02%103 120,165 4,978 125,144
54G.P 488,979 0.07%418 489,398 20,276 509,673
544SG.U 227,872 0.03%195 228,067 9,449 237,516
5455G.P 461,693 0.07%395 462,088 19,144 481,232
545SG-U 162,453 0.02%139 162,592 6,736 169,328
5465G 26,934 0.00%23 26,957 1,117 28,074
5485G 4,553,353 0.65%3,897 4,557,250 188,808 4,746,058
5485SGCT 815,372 0.12%698 816,070 33,810 849,880
549SG 2,718,308 0.39%2,326 2,720,635 112,717 2,833,351
552SG 195,192 0.03%167 195,359 8,094 203,453
5525SGCT 67,670 0.01%58 67,728 2,806 70,534
553SG 2,052,377 0.29%1,756 2,054,133 85,103 2,139,237
553SSGCT 194,718 0,03%167 194,885 8,074 202,959
554SG 41,711 0.01%36 41,747 1.730 43,476
554SSGCT 79,507 0.01%68 79,575 3,297 82,872
556SG 653,662 0.09%559 654,222 27,105 681.326
5575G 32,397,375 4.60%27,724 32,425.099 1,343,383 33,768,482
560SG 4,682,195 0.67%4.007 4,686,202 194,151 4,880,352
561SG 7,968,759 1.13%6,819 7,975,579 330,431 8,306.010
562SG 968,896 0.14%829 969,725 40,176 1,009,901
563SG 88,287 0.01%76 88,362 3.661 92.023
566SG 269,368 0.04%231 269,598 11,170 280,768
567SG 218,504 0.03%187 218,691 9,060 227,752
568SG 16,696 0.00%14 16,710 692 17,402
5695G 2,331,151 0.33%1,995 2,333,146 96.63 2,429,809
5705G 7,194,936 1.02%6,157 7,201,093 298,344 7,499,437
5715G 1,577,907 0.22%1,350 1,579,257 65,429 1,644,686
572SG 35,944 0.01%31 35,975 1,490 37,466
5735G 12,991 0.00%11 13,002 539 13,541
580SNPD 17,679,655 2.51%15,130 17,694,784 733,101 18,427,885
5815NPD 13,168,515 1.87%11,269 13,179,784 546,043 13,725,827
582CA 71,088 0.01%61 71,149 2,948 74,096
582IDU 94,696 0.01%81 94,777 3,927 98,704
5820R 599,400 0.09%513 599,913 24,855 624,767
5825NPD 23,317 0.00%20 23,337 967 24,304
582UT 761,001 0.11%651 761,652 31,555 793,207
582WA 233.657 0.03%200 233,857 9,689 243,546
582WYP 248,991 0.04%213 249,204 10,325 259,528
583CA 386,838 0.05%331 387,169 16,041 403,209
583IDU 262,693 0.04%225 262,918 10,893 273,810
Page 4.3.12
Rocky Mountain Power
Idaho General Rate Case. December 2009
Wage and Employee Benefit Adjustment
Adjustment by FERC Account and Revised Protocol Factor
Actuals Annualized Proforma
12 Months Ended Annualization 12 Months Ended ProfOrma 12 Months Ending
indicator December 2009 % Of Total Adjustment December 2009 Adjustment December 2010
5830R 2,454.845 0.35%2,101 2,456,946 101,792 2,558,738
583SNPD 15,103 0.00%13 15,116 626 15,743
583UT 1,090,346 0.15%933 1,091,280 45,212 1,136,92
583WA 373,714 0.05%320 374,034 15,496 389,530
583WYP 214,570 0.03%184 214,753 8,897 223,651
583WYU 90,554 0.01%77 90,632 3,755 94,387
585SNPD 206,076 0.03%176 206,252 8,545 214,797
586CA 191,847 0.03%164 192,011 7,955 199,966
586IDU 217,214 0.03%186 217,400 9,007 226,407
5860R 2,164,854 0.31%1,853 2,166,706 89,767 2,256,474
586SNPD 904,111 0.13%774 904,885 37,490 942,374
586UT 1,235.141 0.18%1,057 1,236,198 51,216 1,287,414
586WA 401,146 0.06%343 401,489 16,634 418,123
586WYP 486,098 0.07%416 486,514 20,156 506,670
586WYU 49,097 0.01%42 49,139 2.036 51.174
587CA 516,23 0.07%442 516,865 21,414 538,279
5871DU 385,265 0.05%330 385,595 15,975 401,570
5870R 3,850,961 0.55%3,295 3,854,257 159,683 4,013,940
587SNPD 430 0.00%0 430 18 448
587UT 4,255,700 0.60%3,642 4,259,342 176,66 4,435,808
587WA 773,010 0..11%662 773,672 32,03 805,725
587WYP 722,740 0.10%618 723,359 29,969 753,328
587WYU 82,423 0.01%71 82,493 3,418 85,911
588CA (23,250)0.00%(20)(23,269)(96)(24,233)
5881DU (5o.49)...01%(43)(50,593)(2,096)(52,689)
5880R (108,371)...02%(93)(108,463)(4,494)(112,957)
588SNPD (23,735)0.00%(20)(23,756)(984)(24,740)
588UT (261,048)...04%(223)(261,272)(10,825)(272,096)
588WA (67,259)-0.01%(58)(67,317)(2,789)(70,106)
588WYP (93,282)-0.01%(80)(93,362)(3,868)(97,230)
588WYU (45,371)-0.01%(39)(45,410)(1,881)(47,291)
589CA (8,582)0.00%(7)(8,90)(356)(8,946)
5891DU 786 0.00%1 787 33 820
5890R (302,471)-0.04%(259)(302,729)(12,542)(315,272)
589SNPD 97 0.00%0 97 4 101
589UT 14,753 0.00%13 14,766 612 15,377
589WA (17,810)0.00%(15)(17,825)(739)(18,564)
589WYP (81,491)-0.01%(70)(81,561)(3,379)(84,940)
589WYU 3,184 0.00%3 3,187 132 3,319
590CA 24,492 0.00%21 24,513 1,016 25.529
590lDU 73,856 0.01%63 73,919 3,062 76,982
5900R 224,747 0.03%192 224,939 9,319 234,258
590SNPD 5,338,642 0.76%4,569 5,343,210 221,371 5,564,581
590UT 275,933 0.04%236 276,169 11,442 287,611
590WA 10,389 0.00%9 10,398 431 10,828
590WYP 68,699 0.01%59 68,758 2,849 71,607
592CA 277.646 0.04%238 277,88 11,513 289,396
592lDU 602,938 0.09%516 603,454 25,001 628,455
5920R 2,384,168 0.34%2,040 2,386,208 98,861 2,485,070
592SNPD 1,734,388 0.25%1,484 1,735,872 71,918 1,807,790
592UT 2,590,063 0.37%2,216 2,592,279 107,399 2,699,678
592WA 547,441 0.08%468 547,909 22.700 570,609
592WYP 865,657 0.12%741 866,397 35,895 902,293
592WYU 0.00%
593CA 2.011,749 0.29%1,722 2,013,471 83,419 2,096,890
5931DU 2,385.129 0.34%2,041 2,387,170 98.901 2,486.071
5930R 9,371,319 1.33%8,020 9,379,339 388,589 9.767,928
593SNPD 487,004 0.07%417 487,421 20,194 507,615
593UT 5,486,330 0.78%4,695 5,491,025 227,495 5,718,520
593WA 1,770,421 0.25%1,515 1,771,936 73,412 1,845,347
593WYP 1,188.113 0.17%1,017 1,189,129 49,266 1,238,395
593WYU 560,255 0.08%479 560,735 23,231 583,966
594CA 433,003 0.06%371 433,374 17,955 451,329
5941DU 448,562 0.06%384 44,946 18,600 467,546
5940R 3.705,836 0.53%3,171 3,709,007 153,665 3,862,673
594SNPD 5,684 0.00%5 5,689 236 5,925
594UT 7,026,298 1.00%6,013 7,0~2,310 291,351 7,323,661
594WA 922,388 0.13%789 923,177 38,248 961,424
594WYP 694,704 0.10%594 695,299 28,806 724,105
Page 4.3.13
Rocky Mountain Power
Idaho General Rate Case - December 2009
Wage and Employee Benefit Adjustment
Adjustment by FERC Account and Revised Protocol Factor
Actuals Annualized Proforma
12 Months Ended Annualization 12 Months Ended Proforma 12 Months Ending
Indicator December 2009 % Of Total Adjustmnt December 2009 Adjustment December 2010
594WYU 133,917 0.02%115 134,031 5,553 139.584
5955NPD 869,632 0.12%744 870,376 36,060 906,436
595WYP 13.792 0.00%12 13,804 572 14,376
596CA 112,197 0.02%96 112,293 4,652 116,946
596IDU 110,346 0.02%94 110,440 4,576 115,015
5960R 801,488 0.11%686 802,174 33.234 835,408
596UT 314,016 0.04%269 314,285 13,021 327,306
596WA 155,173 0.02%133 155,306 6.34 161,740
596WYP 265,148 0.04%227 265,375 10,995 276,369
596WYU 40,715 0.01%35 40,750 1,688 42,438
597CA 52,569 0.01%45 52,614 2,180 54,794
5971DU 256,924 0.04%220 257,144 10,654 267,797
5970R 980,103 0.14%839 980,942 40,641 1,021,583
5975NPD 850,961 0.12%728 851,689 35,286 886,975
597UT 1,786,904 0.25%1,529 1,788,33 74,095 1,862,529
597WA 285,123 0.04%244 285,367 11,823 297,190
597WYP 534,666 . 0.08%458 535,124 22,170 557,294
597WYU 66,905 0.01%57 66,962 2,774 69,737
598CA 17,850 0.00%15 17,865 740 18,605
5981DU 3,017 0.00%3 3,019 125 3,144
5980R 79.825 0.01%68 79,894 3,310 83.204
5985NPD 1,507,846 0.21%1,290 1,509,136 62,524 1,571,660
598UT 6,111 0.00%5 6,116 253 6,369
598WA 34,125 0.00%29 34,155 1,415 35,570
598WVP 1,521 0.00%1 1,522 63 1,585
598WYU 210 0.00%0 210 9 218
901CA 150 0.00%0 150 6 157
901CN 2,435,229 0.35%2,084 2,437,313 100,979 2,538,292
9011DU 1,323 0.00%1 1,324 55 1,379
9010R 10,268 0.00%9 10,277 426 10,702
901UT 270 0.00%0 271 11 282
901WA 4,005 0.00%3 4,009 166 4,175
901WYP 4,287 0.00%4 4,291 178 4,469
902CA 702,48 0.10%601 703,049 29.128 732,177
902CN 1,383,425 0.20%1,184 1,38,609 57,365 1,441,973
9021DU 1,477095 0.21%1,264 1,478,359 '61,249 1,539,607
9020R 8.283,123 1.18%7.088 8,290,211 343,466 8,633,678
902UT 5,014,924 0.71%4,292 5,019,215 207,948 5,227,163
902WA 2,014,347 0.29%1,724 2,016,070 83,526 2,099,597
902WYP 1.892,394 0.27%1,619 1,894,013 78,470 1,972,483
902WYU 206.043 0.03%176 206,219 8,544 214,763
903CA 168,646 0.02%144 168,790 6,993 175,783
903CN 35,791,059 5.08%30,629 35,821,688 1,484,105 37,305,793
9031DU 244,433 0.03%209 244,642 10,136 254,777
9030R 1,463,619 0.21%1,253 1,464,871 60,690 1,525,561
903UT 2,639,929 0.38%2,259 2,642,188 109,467 2,751,655
903WA 373,298 0.05%319 373,618 15,79 389,097
903WYP 315,071 0.04%270 315,340 13,065 328,405
903WY 74,745 0.01%64 74,809 3,099 77,908
905CN 183,865 0.03%157 184,023 7,624 191,647
907CN 241.174 0.03%206 241,381 10,000 251,381
908CA 2,581 0.00%2 2,584 107 2,691
908CN 2,694,462 0.38%2,306 2,696,768 111,728 2,808,496
9081DU 422,972 0.06%362 423,334 17,539 440,873
9080R 1,159,520 0,16%992 1,160,513 48,080 1,208,593
9080THER 28,976 0.00%25 29,001 1,202 30,202
908UT 1,958.624 0.28%1,676 1,960,300 81,216 2,041,516
908WA 0.00%
908WYP 846,330 0.12%724 847,054 35,094 882,148
909CN 471,209 0.07%403 471,612 19,539 491,151
910CN 4,646 0.00%4 4,650 193 4,843
92050 79,232,022 11.26%67,804 79,299,826 3,285,419 82,585,245
92150 48,363 0.01%41 48,404 2,005 50,409
92250 30,241,721 4.30%25,880 30.267,601 1,253,997 31,521,598
92350 (11,387,305)-1.62%(9,745)(11,397,049)(472,184)(11,869,233)
928CA 159,423 0.02%136 159,560 6,611 166,171
9281DU 6,994 0.00%6 7,000 290 7,290
9280R 228,915 0.03%196 229,111 9,492 238,603
92850 34,115 0.00%29 34,145 1,415 35.559
Page 4.3.14
Rocky Mountain Power
Idaho General Rate Case. December 2009
Wage and Employee Benefit Adjustment
Adjustment by FERC Account and Revised Protocol Factor
Actuals Annualized Profonna
12 Months Ended Annualization 12 Months Ended Proforma 12 Months Ending
Indicator December 2009 %OfTotal Adjustment December 2009 Adjustment December 2010
928UT 471,051 0.07%403 471,454 19,533 490,987
928WA 52.998 0.01%45 53,Q3 2,198 55,241
928WY?219.229 0.03%188 219,417 9.091 228,507
92950 (107.927)-0.02%(92)(108.020)(4,475)(112,495)
9350R 11,992 0.00%10 12.002 497 12,499
93550 4,355,038 0.62%3,727 4,358,765 180.585 4.539,350
935WA 1,497 0.00%1 1,498 62 1,561
Utilit Labor 502,146,763 71.33%429,717 502,576,480 20,821,914 523,398,394 Ref. Page 4.3.4
Capitl/Non Utility 201,804,020 28.67%172,696 201,976,715 8,367.964 210,344,679 Ref. Page 4.3.4
Total Labor 703,950,782 100.00%602,413 704,553,195 29,189,878 733,743,073 Ref. Page 4,3.4
Rocky Mountain Power PAGE 4.4
Idaho General Rate Case. December 2009
Transition Savings (MEHC)
TOTAL IDAHO
ACCOUNT Type COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Expense:
Amortization of Deferred
Change-in-Control Severance 920 1 (610,194)10 Situs (610,194)
Adjustment to Tax:
10 MEHC 2006 Transition Cost SCHMAT 1 (610,194)10 Situs (610,194)
Deferred Tax Expense 41110 1 231,575 10 Situs 231,575
Accumulated Deferred Tax 283 1 231,575 10 Situs 231,575
Accrued CIC Severance SCHMDT 1 (839,908)SO 5.392%(45,290)
Deferred Tax Expense 41010 1 (318,753)SO 5.392%(17,188)
Deferred Tax Balance 190 1 9,805 SO 5.392%529
Description of Adjustment:
The Company eliminated many positions as a result of the MEHC transaction. These savings were made possible by
the payment of Change-In-Control Severance, which is being amortized into expense over a three-year period on the
books of the Company as authorized by the Commission in Case No. PAC-E-07-05. Since the amortization will end
December 31, 2010, it is being removed from unadjusted results.
Rocky Mountain Power
Idaho General Rate Case. December 2009
Irrigation Load Control Program
PAGE 4.5
TOTAL IDAHO
ACCOUNT ~COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Expense:
Other Purchased Power 557 (7,324,489)SG 5.508%(403,469)4.5.1
Other Purchased Power 557 7,324,489 ID Situs 7,324,489 4.5.1
6.921,019
Incremental Adjustment to Expense:
Other Purchased Power 557 3 261,233 JD Situs 261,233 4.5.2
Description of Adjustment:
Payments made to Idaho irrigators as part of the Idaho Irrigation Load Control Program are system allocated in the
unadjusted data. This adjustment situs assigns the payments to Idaho. The reallocation is required as DSM costs are
situs assigned to the states in which the costs are incurred to match the benefi of reduced load reflected in allocation
factors.
The incremental portion of the adjustment reflects CY 2010 expected payments.
Rocky Mountain Power
Idaho General Rate Case. December 2009
Irrgation Load Control
Idaho Irrgation load Contrl Payments. 12 Months Ended December 2009 7.324.489
Ref. 4.5
Page 4.5.1
Rocky Mountain Power
Idaho General Rate Case - December 2009
Irrigation Load Control
Page 4.5.2
CY 2010 Participation (KW)
CY 2010 Participation - $
Attrition %
Attrition
273,406
$ 8,113,071
6.5%
527,350
CY 2010 Participation (net of attrition) - $.7,585,721
CY 2009 Payments 7,324,489 4.5.1
Incremental Adjustment $ 261,233
Ref. 4.5
Rocky Mountain Power PAGE 4.6
Idaho General Rate Case - December 2009
Incremental Generation O&M
TOTAL IDAHO
ACCOUNT~COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Expense:
High Plains 549 3 2,621,060 SG 5.508%144,381
McFadden Ridge I 549 3 648,655 SG 5.508%35,731
Dunlap i 549 3 2,435,111 SG 5.508%134,138
DJ Scrubber 512 3 1,454,447 SG 5.508%80,118
Administration 549 3 174,119 SG 5.508%9,591
7,333,392 403,960 4.6.1
Description of Adjustment:
This adjustment increases Generation O&M expense to an annual level for plants with in-service dates during
2009 and 2010, including the High Plains, Mc Fadden Ridge i, and Dunlap i wind plants, and also the Dave
Johnston coal plant scrubber. The adjustment also adds incremental expenses for administration of the wind
plants.
Rocky Mountain Power
Idaho General Rate Case. December 2009
Incremental Generation O&M
In Service Date 2009 Actuals 2010 Pro Forma Adjustment
High Plains Sept. 2009 401,303 3,022.363 2.621,060
McFadden Ridge i Sept. 2009 203.806 852,461 648.655
Dunlap i Nov. 2010 2,435.111 2,435,111
DJ Scrubber May 2010 1,454,447 1,454,447
Administration various 1,662,029 1,836,148 174.119
Total 2.267,138 9,600,530 7,333,392 Ref 4.6
"
Page 4.6.1
Description of Adjustment:
A variety of accounting entries were made to expense accounts during the twelve months ended December 2009 that
are non-recurring in nature or relate to a prior period. These transactions are removed from results of operations to
normalize the test period results. A description of each item is provided on pages 4.7.1.
Page 4.7.1
Rocky Mountain Power
Idaho General Rate Case - December 2009
Remove Non-Recurring Entries
INO. IPostg Date I Text FERC Acctl Amount as Booked I Reference I
Oracle 111 eBusiness Suite Write-Off: In June 2007, the
Company decided to implement Oracle 11 i eBusiness Suite at
Interwest Mining. In June, 2009 the Company decided to
1 6/30/2009 abandon the implementation of the project due to reassessment 5570000 311,000 Ref 4.7
of the remaining reserve base at the Deer Creek mine. This entry
includes a total write-off of $311,000 including application
licenses, maintenance fees, and specific configuration
development costs tht cannot be redeployed to other areas.. .
Settlement Fees: A variety of accounting entres were made to
expense accounts during the twelve months ended December
2 Various 2009 for settlement fees involving possible compliance violations.Various 1,001,423 Ref 4.7
These transactions are removed frm results of opertions to
normalize the test period results.
Total 1,312,423 Ref 4.7
Rocky Mountain Power
Idaho General Rate Case - December 2009
Affilate Management Fee (MEHC)
PAGE 4.8
Adjustment to Expense:
Operation & Maintenance expense
TOTAL
ACCOUNT:l COMPANY
IDAHO
FACTOR FACTOR % ALLOCATED REF#
930 (1,053,029) SO 5.392%(56,782)
Adjustment Detail
MEHC Management Fee Limit
per Commitment 28
MEHC Management Fee booked
Above the Line - 12 Mos Ended Dec 2009
Adjustment Required
7,300,000
(8,353,029)
(1,053,029)
Description of Adjustment:
In merger Commitment #28, the Company committed to hold customers harmless for costs that were previously
assigned to affiliates relating to management fees and set the total company amount at $1,500,000. This
commitment is off settable to the extent PacifiCorp demonstrates to the Commission's satisfaction that corporate
allocations from MEHC to PacifiCorp included in PacifiCorp's rates are less than $7.3 milion. This adjustment limits
Corporate allocations from MEHC included in rates to the $7.3 millon limit.
Rocky Mountain Power
Idaho General Rate Case - December 2009
Intervenor Funding
PAGE 4.9
Adjustment to Expense:
Misc. General Expense
TOTAL
ACCOUNT Type COMPANY
IDAHO
FACTOR FACTOR % ALLOCATED REF#
928 3 4,395 ID Situs 4,395 Below
Adjustment to Rate Base:
Deferred Regulatory Expense 182M 3 (17,580)ID Situs (17,580) Below
Adjustment to Tax:
Schedule M - Proforma Adjustment SCHMAT 3 17,580 ID Situs 17,580
Deferred Tax Expense 41110 3 (6,672)ID Situs (6,672)
Accum. Def. Tax Balance 283 3 6,672 ID Situs 6,672
Schedule M - Def Regulatory Expense SCHMDT 3 (26,217)ID Situs (26,217)
Deferred Tax Expense 41010 3 (9,950)ID Situs (9,950)
Adjustment Detail:
Amortization Expense - 2009 13,185 4.9.1
Amortization Expense - 2010 17,580 4.9.1
Incremental adjustment to expense 4,395 Above
December 2009 Balance
December 2010 Balance
Incremental adjustment to rate base
61,378
43,798
(17,580)
4.9.1
4.9.1
Above
Description of Adjustment:
This adjustment amortizes intervenor funding awarded to the Community Action Partnership of Idaho (CAPAI) and the
Idaho Irrigation Pumpers Association (IIPA), as ordered in Case Nos. PAC-E-07-05, PAC-E-08-07, and PAC-E-08-08.
Amortization expense is increased by the expected amortization amount through the year ending December 2010 and rate
base is adjusted to reflect a December 2010 balance.
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Rocky Mountain Power
Idaho General Rate Case - December 2009
Generation Overhaul Expense
PAGE 4.10
TOTAL IDAHO
ACCOUNT Type COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Expense:
Generation Overhaul Expense - Steam 510 1 1,832,129 SG 5.508%100,923 4.10.1
Generation Overnaul Expense - Other 553 (3,905,002)SG 5.508%(215,107) 4.10.1
(2,072,873)(114,184)
Description of Adjustment:
This adjustment normalizes generation overhaul expenses in the year ended December 2009 using a four year
average methodology. In this adjustment overhaul expenses from December 2006 to December 2008 are escalated
to a December 2009 level using escalation indices and then those escalated expenses are used in computing a four
year average. For new generating units, which include Currant Creek, Lake Side and Chehalis, the four year average
is comprised of the overhaul expense planned for the first four full years these plants are operationaL. The actual
overhaul costs for the year ended December 2009 are subtracted from the four year average which results in this
adjustment.
Rocky Mountain Power
Idaho General Rate Case. December 2009
Generation Overhaul Expense
FUNCTION: OTHER
Period
Year Ending December 2006
Year Ending December 2007
Year Ending December 2008
Year Ending December 2009
4 Year Average
New Plant Overhaul Expense
Lake Side Plant - 4 Year Average
Currant Creek Plant - 4 Year Average
Chehalis Plant - 4 Year Average
Total New Plant Overhaul Expense
Total 4 Year Average - Other
Overhaul Expense
2,940,000
2,860,000
1,725,000
2,552,000
2,519,250
Year Ending December 2009 Overhaul Expense - Other
Total 4 Year Average - Other
Adjustment
"Escalation Rates: Ref 4.10.3
FUNCTION: STEAM
Period
Year Ending December 2006
Year Ending December 2007
Year Ending December 2008
Year Ending December 2009
4 Year Average
Overhàul Expense
29,613,264
28,560,541
20,030,017
25,392,474
25,899,074
Year Ending Dec 2009 Overhaul Expense - Steam
Total 4 Year Average - Steam
Adjustment
"Escalation Rates: Re,f 4.10.3
Page 4.10.1
Escalation Rates
to Dec 2009 " Escalated Expense10.43% 3,246,6126.64% 3,049,9861.22% 1,725,000
2,552,000
2,643,400
1,031,367
2,051,886
753,346
3,836,599 Ref 4.10.2
6,479,998
10,385,000 Ref4.10.2
6,479,998
(3,905,002) Ref 4.10
Escalation Rates
to Dec 2009 " Escalated Expense11.04% 32,882,9337.29% 30,643,282-0.25% 19,979,722
25,392,474
27,224.603
25,392,474 Ref4.10.2
27.224,603
1,832,129 Ref4.10
Rocky Mountin Power
Idaho General Rale Case. December 2009
Genertion Overhaul Expense
Existing UnIts
Blundell
Carbon
DaveJohnslon
Gadsby
Hunler
Hunlingløn
Naughton
Wyodak
Cholla
Colstrp
Craig
Hayden
JimBridger
Plants . Steam
Planls . Olher
Hermiston
LltteMt
Camas
WVaney
Tolal . Includes Sleam and Other
By FunctIon
Sleam
Other
Total
New Generating Unit'
Curranl Creek
Lake Side
Chehalis
Restatement Percenlage
Restatement in December 2009 Dollars
Curranl Creek
Lake Side
Chehalis
Calendar Calendar Calendar Calandar
Yr 2006 Yr2007 Yr 2008 Yr 2009
73,934 2,677,913 83.913 418,189
723,024 24,146 1,730.915 1,676,722
30,900 3,279,981 5,24,658 6.78.000
2,290.000
3.910,432 8,171,859 (950,900)
7,575,000 (39,000)769,000
3,648;974 4,864,643 1,341,431 6,895,563
5,629,000
6,460,000
925;000 1,300,000 1,156,000
44,000 1,376.000 743,000
745,000 90,000 370,000 495,000
5.904,000 6,815.000 4,427,000 5,214,000
2,383,000 2,860.000 1,725,000 2,023,000
139,000 529,000
418.000
32.553.264 31,420,541 21.55,017 27.944,474
29,613,264 28,560,541 20,030,017 25,392,474 R.f.4.10.1
2,940.000 2,860,000 1,725,000 2.552.000
$32,55,264 $31,420,541 $21,755,017 $27.94,474
Page 4.10.2
Actual Budoet 2010 Dollars I
i
Calendar
i
Calenda
i
Calandar Calendar
I
Calendar I Calendar I 4 Year
Yr2007 Yr2008 Yr 2009 Yr 2010 Yr2011 Yr2012 Averaoe
1,523,000 1.216,000 5,121,000 232,000 .2,023,000
-54,000 1,001,000 2,579,000 593,000 1,031,000
-.1,711,000 1,305.000 754,000
3.808.000
106.64%101.22%99.80%99.80%99.80%
I
Calendar
I
Calendar I Calendar Calendar
I
Calendar i Calendar I 4 Year Averaged
Yr 2007 Yr 2008 Yr 2009 Yr 2010 Yr 2011 Yr2012 Averaoe Years
1,624,171 1.230,839 5,121,000 231,535 -2,051.886 2007-20'0
550,639 1,001,000 2,573,828 591.811 1,031.367 2008~2011
1.711.000 1,302,383 753,34 2009.2012
1.624,171 1,781,478 7,833,00 231.535 2,573,828 1,894.194 3,836,599
'Currant Creek, Lake Side, & Chehalis are all tunction - Other
Below
December 2009 Overhaul Expense. Other
Pre-2007 Planl:
2009 Currant Creek, Lae Side. and Chehalis:
2.552,000
7,833,000 Abo""
10,385,000 Ref. 4.10.1
Ref. 4.10.1
Rocky Mountain Power
Idaho General Rate Case - December 2009
Generation Overhaul Expense
Escalation Rates: OTHER
Escalation Rate to December 2009
Deflation Rate from December 2010 to Dec 2009
Escalation Rates: STEAM
Escalation Rate to December 2009
CY06
10.43%
CY06
11.04%
CY07
6.64%
CY07
7.29%
CY08 CY09
1.22%
CY08 CY09
-0.25%
£X
99.80%
Page 4.10.3
Rocky Mountain Power
Idaho General Rate Case - December 2009
Memberships & Subscriptions
PAGE 4.11
Adjustment to Expense:
TOTAL IDAHO
ACCOUNT Type COMPANY FACTOR FACTOR % ALLOCATED REF#
Remove Total Memberships and Subscriptions in Account 930.2
930 1 (5,887,528)SO 5.392%(317,468)
930 1 (4,500)CN 3.885%(175)
930 1 (2,045)OR Situs
930 1 (250)WY-AII Situs
Total (5,894,323)(317,643) 4.11.1
Add Back 75 % of National & Regional Membership:
930 1 1,384,958 SO 5.392%74,680 4.11.1
930 1 3,375 CN 3.885%131 4.11.1
Total 1,388,333 74,811
Add Back Memberships at 100% :
WECC 930 1 3,910,285 SO 5.392%210,851
NTTG 930 1 353,726 SO 5.392%19,074
Total 4,264,011 229,925 4.11.1
304,736Total Memberships and Subscriptions Allowed 5,652,344 4.11.
Description of Adjustment:
This adjustment removes expenses in excess of Commission policy allowances as stated in Idaho Power's Order No.
29505. National and regional trade organizations are recognized at 75%. whereas fees for Western Electricity
Coordinating Council and Northern Tier Transmission Group are included at 100%..
Rocky Mountain Power
Idaho General Rate Case - December 2009
Postretirement Measurement Date Change
PAGE 4.12
TOTAL IDAHO
ACCOUNT IY COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Expense:
Remove postretirement measurement
date change from unadjusted results 920 (394,287)ID Situs (394,287) .4.12.1
Adjustment to Tax:
Schedule M Adjustment SCHMAT 1 (63,920)SO 5.392%(3,447)
Deferred Tax Expense 41110 1 24,258 SO 5.392%1,308
Accumulated Deferred Tax 190 1 (936,336)SO 5.392%(50,489)
Description of Adjustment:
An entry made to recognize the actuarial effecls on postretirement benefits due to a change in measurement date
needs to be removed from unadjusted results.
Page 4.12.1
Rocky Mountain Power
Idaho General Rate Case - December 2009
Postretirement Measurement Date Change
Postretirement Measurement Date Change Amortization -
12 Months Ended December 2009 included in Unadjusted Results
Postretirement Date Change
FERC Acct Location Factor
920 103 CA
920 106 10
920 108 OR
920 109 UT
920 114 WYP
502 385 SG
Amount
17,235
394,2871
199,297
332,959
278,231
(0)
1,222,008
Total base period amort to remove
) I 394,287 I
Ref 4.12
Rocky Mountain Power
Idaho General Rate Case. December 2009
Cash Basis Pension Expense
PAGE 4.13
TOTAL
ACCOUNT ~ COMPANY
IDAHO
FACTOR FACTOR % ALLOCATED REF#
Adjustment to Expense:
Pension expense 930 47,723,488 SO 5.392%2,573,355 4.13.1
Description of Adjustment:
This adjustment replaces the actuarially determined pension expense for the 12 months ended December 2010
with the amount to be funded during the 12 months ended December 2010.
Rocky Mountain Power
Idaho General Rate Case - December 2009
Convert Actuarial Pension Expense to Cash Basis
Cash Basis Pension Expense
Pension Funding 12 Mas Ended December 2010
Portion to exclude Mines
Portion to exclude Joint Ventures
Pension Funding to Electric Expense
Accrual Basis Pension Expense
Total Pension Expense
Less: Local 57 Pension Expense*
Actuarial Pension Expense in Results 12 Mas Ended December 2010
Electric Portion
Electric Expense in Results
Total Difference
O&M portion
Adjustment to O&M
*Not actuarially determined, the amount funded is the amount expensed
104,800,000
96.71%
101,350,829
96.21%
40,500,000
8,700,000
31,800,000
96.21%
Page 4.13.1
97,509,663
30,594,790
66,914,874
71.32%
47,723,488 Ref 4.13
Rocky Mountain Power
Idaho.General Rate Case - December 2009
Insurance Expense
PAGE 4.14
Adjustment to Expense:
Injuries and Damages
TOTAL
ACCOUNT Type COMPANY
IDAHO
FACTOR FACTOR % ALLOCATED RÉF#
925 3 1,603,785 SO 5.392%86,480 4.14.1
..
Description of Adjustment:
This adjustment normalizes injury and damages expense to reflect a three year average of gross expense minus
insurance receivables. This adjustment also examines the level of captive insurance expenses which remain
below $7.4 milion as agreed to by the Company as part of the MEHC transaction as approved in Case No. PAC-
E-05-0S, commitment 129.
Page 4.14.1
Rocky Mountain Power
Idahö General Rate Case. December 2009
Insurance Expense
Jan - Dec 2007 Jan. Dec 2008 Jan. Dec 2009 Totals
Accrual Accrual Accrual Accrual
8,99,118 8,157,958 3,961,337 21,109,414
1,084,570 292,375 406,645 1,783,589
50,000 50,000 125,000 225,000
10,124,688 8,500,333 4,492,982 23,118,003
(4,717,560)(5,340,408)(2,615,133)(12,673,101)
5,407,128 3,159,925 1,877,849 10,444,902
3,481,634
Cost Center 13272
Excluding Auto (280311)
Auto (280312)
Construction (280313)
* Receivable
Net - Accrual Minus Receivable
3 Year Average
* A receivable is established at the time the reserve analysis (accrual) for a given incident goes above the
insurance deductible. These monies are not received until after the incident is settled, paid. At that time a claim
is submitted to insurance company
Adjustment Detail:
Base Year Expense
Minus Insurance Receivable
NetBase Year Expense - Cost Center 13272
Regulatory Adjustment
$4,492,982
(2,615,133) Above
$1,877,849
$3,481.634 Above
$1,603.785 Ref 4.14
3 Year Average. Accrual Basis
Rocky Mountain Power
Idaho General Rate Case. December 2009
Insurance Expense
Adjustment Detail:
Base Year Expense
Captive
Liabilty
Insurance
Premium
Expense
548523/925
1,588,680
Limit per Commitment 129 1,600,000
Captive
Property
Insurance
Premium
Expense
548522/924
5,572,797
5,800,000
Page 4.14.2
Total
7,161,477
7,400,000
Description of Adjustment:
This adjustment removes DSM.- related revenues and expenses from regulated results. DSM revenues
removed in this adjustment for Washington and California represerit only the over/under collection of DSM
spending. Actual DSM revenues for both states flow through retail revenues.
Page 4.15.1
Rocky Mountain Power
Idaho General Rate Case - December 2009
DSM Removal
Remove DSM Revenue:i'&llmi:eBll~~el!1ltim~il~ll!ï_~r~__i'\III!IDïlll
4562200 DSM Revenue - GA SSG GA 1,097,786
4562200 DSM Rev - ID SSG ID (5,010,486)
4562200 DSM Revenue - OR EGG OR (8,579,678)
4562200 DSM Rev - UT SSG UT (36,046,587)
4562200 DSM Rev-WY SSG Gat 1 WY (682,530)
4562200 DSM Rev-WY SSG Gat 2 WY (356,387)
4562200 DSM Rev-WY SSG Gat 3 WY (364,175)
(1,403,092)
Total FERC Account 4562200 (49,942,057) Ref 4.15
Remove DSM Amortization Expense:\8t1Øij\l¡~l¡li"_~~f,!~;';;1S:,,\\~'.; ;i/";"'"
9085100 DSM AMORT-SSG/EGG
9085100 DSM AMORT-SSG/EGG
9085100 DSM AMORT-SSG/EGG
9085100 DSM AMORT-SSG/EGG
9085100 DSM AMORT-SSG/EGè
9085100 DSM AMORT-SSG/EGG
Total FERC Account 9085100
.~--GA (816,551)ID (5,010,486)OR (8,579,678)UT (36,046,587)WA (4,858,459)WY (1,403,092)
(56,714,853) Ref 4.15
Rocky Mountain Power
Idaho General Rate Case - December 2009
Wyoming Advertising
PAGE 4.16
TOTAL IDAHO
ACCOUNT ~COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Expense:
Inverted Rates Advertising 909 1 (48,109)CN 3.885%(1,869)
909 1 (4,463)WY-AII Situs
(52,572)(1,869) 4.16.1
Adjustment to Rate Base:
Advertising Deferral 182M 1 52,572 OTHER 0.000%
Description of Adjustment:
This adjustment removes advertsing costs that were ordered by the Wyoming P.S.C. and wil be recovered from
Wyoming customers.
Rocky Mountain Power
Idaho General Rate Case. December 2009
Wyoming Advertising
Page 4.16.1
7/24/2009 2009 7 9090000 1 112618 CN 340
7/24/2009 2009 7 530022 9090000 1 112618 CN 1,576
7/24/2009 2009 7 530022 9090000 1 112618 CN 411
7/27/2009 2009 7 530022 9090000 1 112618 CN 15,932
8/6/2009 2009 8 530022 9090000 1 112618 CN 2,415
8/6/2009 2009 8 530022 9090000 1 112618 CN 1,332
8/6/2009 2009 8 530022 9090000 1 112618 eN 8,738
816/2009 2009 8 530022 9090000 1 112618 CN 1,130
8/6/2009 2009 8 530022 9090000 1 112618 CN 2,883
8/6/2009 2009 8 530022 9090000 1 112618 CN 3,293
8/6/2009 2009 8 530022 9090000 1 112618 CN 1,266
9/1/2009 2009 9 530019 9090000 1 112618 CN 1,336
9/1/2009 2009 9 530019 9090000 1 112618 CN 3,293
9/1/2009 2009 9 530019 9090000 1 112618 CN 2,793
9/1/2009 2009 9 530019 9090000 563000 112618 WY 4,463
9/24/2009 2009 9 530022 9090000 1 112618 CN 1,373
Total Inverted Rates Adustment 52,572 Ref 4.16
Description of Adjustment:
In 2009 the Company and the U.S. Attorrney General reached an agreement associated with increasing protection for
wildlife habitat in and around the Company's transmission and distribution assets. This adjustment removes the April
2009 reversal of a December 2008 entry. In the terms of the agreement, the Company is providing funds to vanous
wildlife agencies specifically in Wyoming as well as Idaho, Utah and Montana for the purpose of supporting
improvements to design and construction of avian-safe power lines. Also, the Company is providing capital
improvements of existing power lines in the state of Wyoming that wil benefit customers by protecting wildlife habitat
and reducing avian-related outages.
Rocky Mountain Power
Idaho General Rate Case. December 2009
Avian Settlement
O&M
Postg Date RefDoc.No.Account FERCAcct Locatn Allocation Amount Text
Actual CY 2008:
12131/2008 116692372 545501 9250000 114 SO 500,000 Restitution
500,000
Actual CY 2009:
4/30/2009'117273123 545501 9250000 114 SO (500,000) Reverse Dec entry - Restitution
(500,000)
Page 4.17.1
Ref
'Need to reverse this entry as it reverses an entry made in December 2008
4.17
Rocky Mountain Power
Idaho General Rate Case. December 2009
Avian Settlement
Settlement Capital Additions
I Depreciation Rate (Distribution WY)2.825%1
Distribution Capital Addition CY 2010
Depreciation Expense
Depreciation Reserve
2,147,717
60,672
(60,672)
¡Depreciation Rate (Transmission SG)2.010%1
Transmission Capital Addition CY 2010
Depreciation Expense
Depreciation Reserve
1,352,283
27,177
(27,177)
Page 4.17.2
Ref 4.17
Ref 4.17
Ref 4.17
Ref 4.17
Ref 4.17
Ref 4.17
IDAHO REVISED PROTOCOL Page 5.0 Total
Net Power Cost Adjustments (Tab 5)
TOTAL
5.1 5.2 5.3 5.4 0 0
James River
BPA Residentil Royalty Ofet!Electric Lake
T olal Normalized Net Power Cost Exchange Litte Mountain Settlement 0 0
1 Operating Revenues:
2 General Business Revenues
3 Interdepartmental
4 Special Sales 10,303,083 10,303,083
5 Other Operatig Revenues 218,378 218,378
6 Total Operating Revenues 10,521,461 10.303,083 218,378
7
8 Operating Expenses:
9 Steam Productn 5,356.28 5,356,628
10 Nuclear Prduction
11 Hyro ProduCl.on
12 Other Power Supply 5.533.04 5,693,832 (154,710)(5,319)
13 Transmission 1.001,768 1,001,768
14 Distribution
15 Customer Accounting
16 Customer Service & Info
17 Sales
18 Administrative & General
19 Total O&M Expenses 11.892.200 12.052,228 (154.710)(5,319)
20 Depreciation
21 Amorizatin
22 Taxes Other Than Income
23 Income Taxes: Federal (476,568)(584,407)51,690 72,962 (16.813)
24 State (64,758)(79,411)7,024 9,914 (2,285)
25 Deferred Income Taxes 21,117 21,117
26 Investment Tax Credit Adj.
27 Misc Revenue & Expense
28 Total Operatig Exenses:11,371,991 11.388,410 (95,996)82,877 (3,300)
29
30 Operating Rev For Return:(850,530)(1,085,327)95,996 135.01 3,300
31
32 Rate Base:
33 Electric Plant In Service
34 Plant Held for Future. Use
35 Mi Deferred Debit (108,911)(108,911)
36 Elec Plant Acq Adj
37 Nuclear Fuel
38 Prepayments
39 Fuel Stock
40 Material & Supplies
41 Working Capital
42 Weatheriation Loans
43 Mise Rate Base
44 Total Electric Plant (108,911)(108,911)
45
46 Deductions:
47 Accum Prov For Depree
48 Accum Prov For Amort
49 Accum Def Income Tax 15.85 15,885
50 Unamorted ITC
51 Customer Adv For Const
52 Customer Service Deposits
53 Miscellaneous Deductions 77,389 77,389
54
55 Total Deductions:93,274 93,274
56
57 Total Rate Base:(15,637)(15.37)
58
59
60 Estimated ROE impact -0.293%-0.374%0.033%0.047%0.001%0.000%0.000%
61
62
63
64 TAX CALCULATION:
65
66 Operating Revenue (1,370,739)(1,749,146)154,710 218.378 5.319
67 Oter Deductons
68 Interest (AFUDC)
69 Interest
70 Schedule"M" Additons (55.581)(55.81)
71 Schedule "M" Deductions 61 61
72 Income Before Tax (1,426,381)(1,749.146)154,710 218.378 (50,323)
73
74 State Income Taxes (64,758)(79,411)7.024 9.914 (2,285)
75
76 Taxable Income (1.361.623)(1.669,735)147,686 208,64 (48,039)
77
78 Federal Income Taxes (476,568)(584,407)51.690 72,962 (16,813)
Rocky Mountain Power PAGE 5.1
Idaho General Rate. Case. December 2009
Net Power Cost
TOTAL IDAHO
ACCOUNT ~COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Revenue:
Sales for Resale (Account 447)
Existing Firm PPL 447NPC 3 2,811,079 SG 5.508%154,848 5.1.1
Existing Firm UPL 447NPC 3 2,349,900 SG 5.508%129,444 5.1.1
Post-Merger Firm 447NPC 3 183,111,971 SG 5.508%10,086,719 5.1.1
Non-Firm 447NPC 3 (1,068,483)SE 6.358%(67,929)5.1.1
Total Sales for Resale 187,204,468 10,303,083
Adjustment to Expense:
Purchased Power (Account 555)
Existing Firm Demand PPL 555NPC 3 26,852,544 SG 5.508%1,479,172 5.1.1
Existing Firm Demand UPL 555NPC 3 41,455,319 SG 5.508%2,283,565 5.1.1
Existing Firm Energy 555NPC 3 (28,211,629)SE 6.358%(1,793,560)5.1.1
Post-merger Firm 555NPC 3 48,109,163 SG 5.508%2,650,092 5.1.1
Secondary Purchases 555NPC 3 19,022,490 SE 6.358%1,209,359 5.1.1
Seasonal Contracts 555NPC 3 SSGC 0.000%-5.1.1
Wind Integration Charge 555NPC 3 34,187,931 SG 5.508%1,883,241 5.1.1
Total Purchased Power Adjustments:141,415,818 7,711,869
Wheeling Expense (Account 565)
Existing Firm PPL 565NPC 3 (2,960,982)SG 5.508%(163,106)5.1.1
Existing Firm UPL 565NPC 3 (820,285)SG 5.508%(45,185)5.1.1
Post-merger Firm 565NPC 3 23,179,140 SG 5.508%1,276,822 5.1.1
Non-Firm 565NPC 3 (1,050,141)SE 6.358%(66,763)5.1.1
Total Wheeling Expense Adjustments:18,347,732 1,001,768
Fuel Expense (Accounts 501, 503, 547)
Fuel Consumed - Coal 501NPC 3 113,299,594 SE 6.358%7,203,046 5.1.1
Fuel Consumed - Gas 501NPC 3 (29,856,185)SE 6.358%(1,898,113)5.1.1
Steam from Other Sources 503NPC 3 (2.23,647)SE 6.358%(14,218)5.1.1
Natural Gas Consumed 547NPC 3 13,052,907 SE 6.358%829,841 5.1.1
Simple Cycle Combustion Turbines 547NPC 3 (22,591,198)SSECT 7.612%(1,719,670)5.1.1
Cholla I APS Exchange 501NPC 3 1,094,564 SSECH 6.022%65,913 5.1.1
Total Fuel Expense Adjustments:74,776,036 4,466,800
47,335,117 2,877,355Total Power Cost Adjustment
Remove Power Cost Deferrals 555NPC 1 (20,481,246)SG 5.508%(1,128,209)5.1.1
Description of Adjustment:
The net power cost adjustment normalizes power costs by adjusting sales for resale, purchased power, wheeling and
fuel in a manner consistent with the contractual terms of sales and purchase agreements, and normal hydrò and
weather conditions for the twelve-month period ending December 2010.
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Rocky Mountain Pows,
Idaho General Rate Case - December 2009
Period Ending
December-fO
SPECIAL SALES FOR RESALE
Pacific Pre Merger
Post Merger
Utah Pre Merger
Non Firm Sub Total
TOTAl SPECIAL SALES
PURCHASED POWER & NET INTERCHANGE
BPA Peak Purchase
Pacific Capacity
Mid Columbia
Mise/Pacific
Q.F. ContractslPPl
Pacific Sub Total
Gemstate
GSLM
QF ContractslUPl
IPP Layoff
UP&l toPP&l
Utah Sub Total
APS Supplemental p27875
Blanding Purchase p379174
BPA Reserve Purchase
Chehalis Station Service
Combine Hills Wind p160595
Constellation p257677
Constellation p257678
Constellation p268849
Deseret Purchase p194277
Georgia-Pacific Camas
Hermiston Purchase p99563
Hurricane Purchase p393045
Kennecott Generation Incentive
LADWP p491303-4
MagCorp p229846
MagCorp Reserves p510378
Morgan Stanley p189046
Morgan Stanley p272153-6-8
Morgan Stanley p272154-7
Nucor p346856
P4 Production p137215/p145258
Rock River Wind p100371
Roseburg Forest Products p312292
Three Buttes Wind p457
Top òf the World Wind p575862
Tri-State Purchase p27057
Wolverine Creek Wind p244520
BPA So. Idaho p64885/p83975/p64705
PSCo Exchange p340325
TransAIt p37134s37134
Seasonal Purchased Power
Morgan Stanley p244840
Morgan Stanley p244841
UBS p268848
UBS p268850
Study Results
MERGED PEAK/ENERGY SPLIT
($)
Merged
0110-12/10
25,036,260
771,646,134
25,490,589
822,172,983
57,615,000
1,470,755
29,774,072
6,326,113
67,443,841
162,629,782
2,716,400
107,365,737
25,490,589
135,572,726
2,923,149
28,864
239,962
138,194
3,911,516
31,867,569
6,434,764
97,020,236
145,210
10,824,184
774,380
4,370,90
10,683,600
1,485,00
1,572,000
4,885,800
16,193,520
5,041,688
8,767,111
20,598,497
9,793,609
11,359,280
9,748,726
(56,234)
3,600,000
(1,64,004)
Pre-MergerIÆ
25,036,260
25,90,589
50,526,850
57,615,000
600,00
8,932,222
1,311,801
6,571,976
75,030,998
21,091,915
25,490,589
Pre-Merger~
870,755
20,841,851
5,014,313
32,019,623
58,746,542
2,716,400
9,039,392
t:
Page 5.1.2
post-Me!1eC
771,646,134
771,646,134
28,852,243
28,852,243
77,234,430
46,582,504
--..-----_........----_. .._---_....--------_. -....-----_....-........-.. ---_..----_..__........
11,755,792 77,234,430
2,923,149
28,864
239,962
138,194
3,911,516
31,867,569
6,434,764
97,020,236
145,210
10,824,184
774,380
4,370,900
10,683,600
1,485,000
1,572,000
4,885,800
16,193,520
5,041,688
8,767,111
20,598,497
9,793,609
11,359,280
9,748,726
(56,234)3,600,00
(1,644,004)
Rocky Mountain Power
Idaho General Rate Case. December 2009
Period Ending
December-10
Short Term Firm Purchases
New Firm Sub Total
Wind Integration Charge
Non Firm Sub Total
TOTAL PURCHASED PW & NET INT.
WHEELING & U. OF F. EXPENSE
Pacific Firm Wheeling and Use of Facilties
Utah Firm Wheeling and Use of Facilties
Post Merger
Nonfirm Wheeling
TOTAL WHEELING & U. OF F. EXPENSE
THERMAL FUEL BURN EXPENSE
Carbon
Cholla
Colstrip
Craig
Chehalis
Currant Creek
Dave Johnston
Gadsby
GadsbyCT
Hayden
Hermiston
Hunter
Huntington
Jim Bridger
Lake Side
Little Mountain
Naughton
Wyodak
TOTAL FUEL BURN EXPENSE
OTHER GENERATION EXPENSE
Blunçlell
TOTAL OTHER GEN. EXPENSE
NET POWER COST
Study Results
MERGED PEAK/ENERGY SPLIT
($)
Merged
01/10=12/10
17,256,031
277,963,549
34,187,931
610.353,988
26,972,928
3,373,929
3,373,929
Pre-MergerJÆ Pre-MergerfD
121,613,502 70,502,334
26,972,928
tl
3,373,929
3,373,929
Page 5.1.3
Post-Merger
17,256,031
277,963,549
34,187,931
418,238,153
============ ============ =========== ============= ============
1,069,701,315 98,059,581 70,502,334 1,146,104,023 (244,964,622)
Ref 5.1.1
============= =--=========== =========== ============ ============
Rocky Mountain Power
Idaho General Rate Case - December 2009
SPA Residential Exchange
PAGE 5.2
TOTAL IDAHO
ACCOUNT ~COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Expense:
Purchased Power Expense 555 1 25,337,357 OR Situs
Purchased Power Expense 555 1 8,025,121 WA Situs
Purchased Power Expense 555 1 (154,710)ID Situs (154,710)
33,207,768 (154,710)
Description of Adjustment:
The Company receives a monthly purchase power credit from Bonneville Power Administration (BPA). This credit is
treated as a 100% pass-through to eligible customers. Both a revenue credit and a purchase power expense credit is
posted to unadjusted results which need to be removed for normalized results. This adjustment reverses the BPA
purchase power expense credit recorded. The Revenue Normalizing Adjustment No. 3.2 removes the revenue credit
passed onto customers.
Rocky Mountain Power
Idaho General Rate Case. December 2009
James River Royalty Offset! Little Mountain
TOTAL
ACCOUNT ~ COMPANY
Adjustment to Expense:
Other Electric Revenue
Other Electric Revenue
456
456
3
3
5,804,843
(1,840,457)
3,964,386
Adjustment Detail:
James River Offset
Capital Recovery
Major Maintenance Allowance
Total Offset
12 Months Ended
12/31/2010
5,285,341
519,502
5,804,843
Little Mountain Revenue
Pro Forma Steam Sales - 12 Mo. Ended Dec. 2010
Less: Steam Sales in Unadjusted Results
3,017,258
4,857,715
(1,840,457)
PAGE 5.3
IDAHO
FACTOR FACTOR % ALLOCATED REF#
SG
SG
5.508%
5.508%
319,760 Below
(101,382) Below
218,378
Above
5.3.1
Above
Description of Adjustment:
This adjustment credits Other Electric Revenues for the James River Royalty Offset as agreed in the January 13,
1993 agreement. Since the cost of James River power is included in the net power cost adjustment, it is necessary to
show a credit for capital cost and maintenance cost recovery.
This adjustment also accounts for an increase in the Little Mountain Steam sales which is attributable to matching
revenue with the assumptions used in the net power cost study.
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Rocky Mountain Power PAGE 5.4
Idaho General Rate Case. December 2009
Electric Lake Settlement
TOTAL IDAHO
ACCOUNT ~COMPANY FACTOR FACTOR %ALLOCATED REF#
Settlement of Costs:
Amortization O&M Portion 557 3 (96,552)SG 5.508%(5,319)5.4.1
Regulatory Asset 186M 3 (1,713,105)SE 6.358%(108,911 )5.4.1
Regulatory Liability 254 3 1,217,286 SE 6.358%77,389 5.4.1
Adjustment to Tax:
Fuel Amortization
Sch M SCHMAT 3 (2,587,363)SE 6.358%(164,492)
DIT Exp.41010 3 (2,096,804)SE 6.358%(133,305)
DIT Exp.41110 3 3,078,734 SE 6.358%195,731
DITBal.283 3 650,140 SE 6.358%41,333
Sch M SCHMAT 3 1,713,105 SE 6.358%108,911
DIT Exp.41110 3 (650,141)SE 6.358%(41,333)
Coal Supply Adjustment
Sch M SCHMDT 3 (1,836,574)SE 6.358%(116,761 )
DtT Exp.41010 3 (2,185,328)SE 6.358%(138,933)
DIT Exp.41110 3 1,488,330 SE 6.358%94,621
DITBal.190 3 (461,972)SG 5.508%(25,448)
SchM SCHMDT 3 1,217,286 SE 6.358%77,389
DIT Exp.41010 3 461,972 SE 6.358%29,370
Settlement Costs
Sch M SCHMDT 3 715,840 SG 5.508%39,432
DtT Exp.41010 3 271,668 SG 5.508%14,965
Description of Adjustment:
Canyon Fuel Company ("CFC") owns the Skyline mine located near Electric Lake, Utah. Electric Lake is owned by the
Company and provides water for the Huntington power plant. CFC disputed the claim made by the Company that CFC's
mining operations punctured the lake and caused water to flow into the Skyline mine. The two companies negotiated a
settlement and release agreement for the claims made by the Company. This adjustment includes one year of
amortization and adjusts the rate base balances to the December 2010 leveL.
Rocky Mountain Power
Idaho General Rate Case - December 2009
Electric Lake Settlement
Settlement of Costs
Value of Settlement
Offet O&M
Reduction of O&M
Amortization Account 25399 over 3 years
Amortization Account 254
Reduction to Account 557
Account 557 Reduction in actual results
Adjustment needed to reflect reducton amount
Reduction to Account 557
Regulatory Liabilit Account 25399
Offet O&M Account 557
Amortization of Offet
Remaining Liabilty Balance
Regulatory Asset 186.5
Set-Up Deferred Asset
Amortization
Ending Balance
Account 186.5 ending balance in actual results
Adjustment needed to reflect account balance
Dec 10 Ending
Regulatory Liabilty Account 254
Set-Up Deferred Asset
Amortization
Ending Balance
Account 254 ending balance in actual results
Adjustment needed to reflect accont balance
Dec 10 Ending
Page 5.4.1
10,087,658
71%
7,162,237
(715,840)
(1,217,286)
(1,933,126)
(1,836,574)
(96,552)Ref 5.4
(1,933,126)
Dec-Q8 Dec-09 Dec-10
2,147,520 1,431,680 715,840
(71!¡,840)(715,840)(715,840)
1,431,680 715,840 0
Dec-08 Dec-09 Dec-10
7,062,982 4,300,468 1,713,105
(2,762,514)(2,587,363)(1,713,105)
4,300,468 1,713,105
1,713,105
(1,71:l,105)Ref 5.4
Dec-08 Dec-09 Dec-10
(5,014,717)(3,053,860)(1,217,286)
1,960,857 1,836,574 1,217,286
(3,053,860)(1,217,286)
(1,217,286)
1,217,286 Ref 5.4
IDAHO REVISED PROTOCOL Page 6.0 Total
Depection & Amortation (Tab 6)
TOTAL
6.1 6.1.1 6.2 6.3 0 0
Contd
Depreciation &Depreciation &Dereciation &
Amoriztion Amortzation Amortion Hydro
Total Normalized Expense Expense Reserve Decommissioning 0 0
1 Operating Revenues:
2 General Business Revenues
3 Interdepartental
4 Special Sales
5 Other Operating Revenues
6 Total Operating Revenues
7
8 Operating Expenses:
9 Steam Production
10 Nuclear Prodvcton
11 Hydro Production
12 Other Power Supply
13 Transmission
14 Distribution
15 Customer Accounting
16 Custor Servlèe & Info
17 Sales
18 Administratie & General
19 Total O&M Exnses
20 Depreciation 3.104.302 3,104,302
21 Amortzation 34,942 34,942
22 Taxes Other Than Income
23 Income Taxes: Federal (818,724)(1,048,853)230,129
24 State (111,251)(142,522)31,271
25 Deferred Income Taxes (261,400)(261,400)
26 Investment Tax Cred~ Adj.
27 Mise Revenue & Expense
28 Total Operating Expenses:1,947,870 1,947,870 0
29
30 Operating Rev For Return:(1,947,870)(1.947,870)(0)
31
32 Rate Base:
33 Electc Plant In Servce
34 Plant Held for Future Use
35 Misc Defered Debl
36 Elec Plant Acq Adj
37 Nucr Fuel
38 Prepayments
39 Fuel Stock
40 Material & Supplies
41 Working Capital
42 Weatherization Loans
43 Misc Rate Base
44 Total Elecc Plant:
45
46 Deductions:
47 Accum Prov For Deprec (2.615,963)(2,479,900)(136,063)
46 Accum Prov For Amort (25,402)(25,402)
49 Accum Def Incme Tax 261,400 261,400
50 Unamortized ITC
51 Customer Adv For Const
52 Customer Service Deposits
53 Miscellaneus Deductions
54
55 Total Deductons:(2,379,965)261,40 (2,505,302)(136,05)
56
57 Total Rate Base:(2,379,965)261,400 (2,505,302)(136,063)
58
59
60 Estimated ROE impact -0.627%-0.671%-0.00%0.049%0.003%0.000%0.000%
61
62
63
64 TAX CALCULATION:
65
66 Operating Revenue (3.139.245)(3.139,245)
67 Other Deductions
68 Interest (AFUDC)
69 interest
70 Schedule "M" Additions 686,783 688,783
71 Scheduie "M" Deductions
72 Income Before Tax (2,450,462)(3,139,245)688,783
73
74 State Income Taxes (111,251)(142,522)31,271
75
76 Taxable Income (2,339,211)(2,996,723)657,512
77
78 Federal Income Taxes (818,724)(1,046,853)230.129
Rocky Mountain Power PAGE 6.1
Idaho General Rate Case - December 2009
Depreciation & Amortization Expense
TOTAL IDAHO
ACCOUNT Type COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Expense:
Steam Production 403SP 2 821,891 SG 5.508%45,274
Hydro Production 403HP 2 319,051 SG-P 5.508%17,575
Other Production 4030P 2 8,485,714 SG 5.508%467,435
Transmission 403TP 2 2,481,114 SG 5.508%136,672
Distribution - California 403364 2 499 CA Situs
Distribution - Oregon 403364 2 121,280 OR Situs
Distribution - Washington 403364 2 2,998 WA Situs
Distribution - Utah 403364 2 408,693 UT Situs
Distribution - Idaho 403364 2 1,199 ID Situs 1,199
General Plant - Oregon 403GP 2 14 OR Situs
General Plant - Washington 403GP 2 0 WA Situs
General Plant - Utah 403GP 2 (57)UT Situs
General Plant - Idaho 403GP 2 (173)ID Situs (173)
General Plant - Wyoming 403GP 2 8,371 WY-AII Situs
General Plant 403GP 2 156,011 SO 5.392%8,412
General Plant 403GP 2 51,705 SG 5.508%2,848
Intangible Plant 4041P 2 176,923 SO 5.392%9,540
13,035,232 688,783 6.1.2
Steam Production 403SP 3 14,383,564 SG 5.508%792,318
Hydro Production 403HP 3 125,881 SG-P 5.508%6,934
Other Production 4030P 3 10,584,269 SG 5.508%583,034
Transmission 403TP 3 18,930,257 SG .5.508%1,042,773
Intangible Plant 4041P 3 461,144 SG 5.508%25,402
44,485,115 2,450,462 6.1.3
Description of Adjustment:
This adjustment enters into the test period results depreciation and amortization expense for the major plant additions
added to rate base in adjustment 8.6.
Rocky Mountain Power PAGE 6.1.1
Idaho General Rate Case - December 2009
Contd Depreciation & Amortization Expense
TOTAL IDAHO
ACCOUNT ~COMPANY FACTOR FACTOR % ALLOCATED REF#
Adjustment to Tax:
Schedule M Additions SCHMAT 2 11,840,424 SG 5.508%652,230
SCHMAT 2 319,051 SG 5.508%17,575
SCHMAT 2 499 CA Situs
SCHMAT 2 121,294 OR Situs
SCHMAT 2 2,998 WA Situs
SCHMAT 2 408,635 UT Situs
SCHMAT 2 1,026 10 Situs 1,026
SCHMAT 2 8,371 WY-AII Situs
SCHMAT 2 332,934 SO 5.392%17,953
13,035,232 688,783
Deferred Income Tax Expense 41110 2 (4,493,559)SG 5.508%(247,528)
41110 2 (121,083)SG 5.508%(6,670)
41110 2 (189)CA Situs
41110 2 (46,032)OR Situs
41110 2 (1,138)WA Situs
41110 2 (155,081)UT Situs
41110 2 (389)10 Situs (389)
41110 2 (3,177)WY-AII Situs
41110 2 (126,352)SO 5,392%!6,813)
!4,947,000). !261,400)
Accum Def Income Tax Balance 282 2 4,493,559 SG 5.508%247,528
282 2 121,083 SG 5.508%6,670
282 2 189 CA Situs
282 2 46,032 OR Situs
282 2 1,138 WA Situs
282 2 155,081 UT Situs
282 2 389 10 Situs 389
282 2 3,177 WY-AII Situs
282 2 126,352 SO 5.392%6,813
4,947,000 261,400
Description of Adjustment:
This adjustment enters into the test period results depreciation and amortization expense for the major plant additions
added to rate base in adjustment 8.6.
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Page 6.1.3
Rocky Mountain Power
Idaho General Rate Case - December 2009
Major Plant Addition Detell- Jan2010 to Dec2010
Account Depreciation Jan10 to 0 c10 Plant Incremental Expense on
Proiect DescrtDtlon Plant Facr In-Servce Date Account Deoreclation Rate Addltins Plant Adds
Steam Production
Dave Johnston: U3 502 & PM Emission Cntrl Upgrades 312 SG May-l0 403SP 2.366%2 9,768.628 7,093.093
Huntington U 1 Clean Air - PM 312 SG Nov-10 403SP 2.366%8,104,324 2.084,715
Hunter. 301 Turine Upgrae HP/IPILP 312 SG Apr-10 403SP 2.366%1,714,226 750,419
Huntington: U1 Turbine Upgrae HP/iPILP 312 SG Nov-10 403SP 2.366%1.260.581 739,685
U1 Huntington Clean Air - 502 312 SG Nov-I 0 403SP 2.366%4.325,082 575,577
Jim Bridger: UL S02 & PM Em Cntrl Upgrades 312 SG Jun-10 403SP 2.36%7,148.123 405.757
Dave Johnston: U3 Low Nox Burners 312 SG Aug-l0 403SP 2.366%5,080.879 35,842
Hunter: 301 Main Controls Replacement 312 SG Apr-10 403SP 2.366%0.959,812 259,33
Dave Johnston: U3 . Replace BollerlTurbirle Controls 312 SG May-l0 403P 2.366%0,767,578 254,781
Jim Bridger: U1 Turbne Upgrade HP/iP 312 SG Jun-10 403SP 2.366%9,471.009 224,102
Huntington: U 1 Clean Air . NOx 312 SG Nov-10 403SP 2.366%9,34,367 221,108
Jim Brldger: U1 Reheater Replacement 10 312 SG Jun-10 403SP 2.366%8.67,849 190.901
Huntington: U1 Economizr Repiacement 312 SG Nov-I 0 403SP 2.366%8,011,393 189,565
Huntingto Water Effcienc Mg Project 312 SG Jun-10 403SP 2.366%7,614,560 180,175
Jim Bridger: UL Clean Air. NOx 312 SG Jun-10 403SP 2.366%7.086.74 167.679
Hunter: 301 Economizer Replacement 312 SG Apr.l0 403SP 2.36%6,301,709 149,110
Huntington: UL Boiler Finish SH Pendants Replacement 312 SG Nov-l0 403SP 2.366%8.147,658 145,465
Jim Bridger: UL Generator Rewind 312 SG Jun-l0 403SP 2.366%6,145.656 145,418
Hunter: 301 Low Temp. SH Replacement 312 SG Apr-l0 403SP 2.366%5,70,087 129,432
Dave Johnston: U3 - Horizontal SH Replace 312 SG May-I 0 403SP 2.366%5,068,802 120,411
Steam Production Total 6 7,878,794 14,383,564
Hydro Production
INU 11,5 Lemolo 1 Forebay Expansion & We 332 SG-P Aug-l0 403HP 2.135%5.897.387 125.881
Hydro Production Total 5,897,387 125,881
Other Production
Dunlap i Wind Proect 343 SG Nov-I 0 4030P 4.052%2 1.83,699 10,584,269
Other Production Total 2 1,183,699 10,584,269
Transmission
Populus to Terinal (Populus to Ben Lomond)355 SG Nov.l0 403TP 2.010%4~:23O,246 8,143.883
Populus to Terminal (Populus to Ben Lomond)35 SG Oct-l0 403TP 2.010%1 ,568,559 2,905,384
Populus to Terminal (Ben Lomond to Terminal)355 SG Mar.10 403TP 2.010%190,877,118 3.836,043
Populus to Terminal (Ben Lomond to Terminal)355 SG Apr.10 403TP 2.010%7,340.277 147.517
Three Peaks Sub: Install 345 kV Substation. Phase II 355 SG Jun-l0 403TP 2.010%1,134,84 1.027.53
Camp Williams. 90th Sout Double Circuit 345 kV line 355 SG Dec-l 0 403TP 2.010%5,600.000 916.20
Red Butte -St George 138 kv dbl ckt, (345 kv Const)355 SG May-I 0 403TP 2.010%1,038,986 422,819
Pinto 345 kV Serles Capacitor 355 SG Nov.l0 403TP.2.010%9,50,483 391,899
Dunlap Ranch Wind F arm Phase 1 Intercoection 355 SG Aug-l0 403TP 2.010%11,130,000 223,679
Upper Green River Basin Superior Project - Transmission Part 355 SG Del0 40TP 2.010%10,025.204 201.476
Oquirrh - New 345-136 kV Sub & 138 kV Switchyard 355 SG Jun-l0 403TP 2.010%6,16,078 169.137
Parrsh Gap Canst Nw 23D-69kV Sub 355 SG Jun.l0 403TP 2.010%8,340,559 167,620
Lie 37 Conv to 115kV 81d Nicel Mt Sub' Trans 355 SG Mar-l0 403TP 2.010%7,982.605 160,024
Chappel Creek 230 kV Cimarex Energy 20 t# Phase II 355 SG DecI 0 403TP 2.010%5,496.321 110,459
Communi Parn Convert to 115-12.5 kV - Transmission Part 355 SG Oct10 403TP 2.010%5,286.21 100,245
Transmission Total 941,947,879 18,930,257
Intangible
TriP II Energy Trading Systems Capitl 303 SG Dec-l0 401P 4.020%11,470,40 461.144
intangible T otai 11,470,08 481,144
MinIng
Deer Creek-Reconstruct Longwall System 399 SE Dec-l 0 403MP 3.608%23.905,000 862.608
Minln9 Total 23,905,000 862,608
1,852,283,166 45.347,723
Ref# 8.6.1
Total not Including Mining 44,485,115
Ref 6.1
Description of Adjustment:
This adjustment enters into the test period results depreciation and amortization reserve for the major plant additions
added to rate base in adjustment 8.6.
Page 6.2.1
Rocky Mountain Power
Idaho General Rate Case. December 2009
Major Plant Addition Detail - Jan2010 to Dec2010
Account Depreciation Janl0 to DeclO Plant Incremental Reserve on
Project Description Plant Facor In.Servce Date Aècount Depreciation Rate Additons Plant Adds
Steem Production
Dave Johnston: U3 S02 & PM Emission Cntr Upgrades 312 SG May-l 0 108SP 2.366%299,768,628 (7.093.093)
Huntington UL Clean Air - PM 312 SG Nov-l0 108SP 2.366%88,104,324 (2,08,715)
Hunter: 301 Turbine Upgrade HP/IP/LP 312 SG Apr-l0 108SP 2,366%31,714.226 (750.419)
Huntington: VL Turbine Upgrde HP/IPILP 312 SG Nov-l0 108SP 2.366%31,260,581 (739,685)
UL Huntington Clean Air - S02 312 SG Nov-I 0 108SP 2,366%24.325,082 (575.577
Jim Bridger: U i S02 & PM Em Cntr Upgrades 312 SG Jun-l0 108SP 2.366%17.148,123 (405.757)
Dave Johnston: U3 Low Nox Burners 312 SG Aug-10 108SP 2.366%15.080,879 (356.842)
Hunter: 301 Maln Controls Repiacement 312 SG Apr.l0 108SP 2.366%10.959,812 (259.330)
Dave Johnston: U3 - Replace BoilerfTurbine Controls 312 SG May-l0 I08P 2.366%10.767.578 (254,781)
Jim Briger: VI Turne Upgrade HPnp 312 SG Jun-10 108SP 2.36%9.471,009 (224.102)
Huntington: UL Clean Air. NOx 312 SG Nov-10 108SP 2.36%9.34,367 (221,106)
Jim Bndger: UL Reheater Replacement 10 312 SG Jun-10 108SP 2.366%8,067,849 (190.901)
Huntington: U 1 Economizer Replacement 312 SG Nov-I 0 108SP 2.366%8,011.393 (189.565)
Huntington Water Effciency Mgt Project 312 SG Jun.l0 108SP 2.366%7.614,56 (180,175)
Jim Bndger: UL Clean Air - NOx 312 SG Jun-l0 108SP 2.366%7.086.474 (187.679)
Hunler. 301 Economizer Replacement 312 SG Apr-l0 108SP 2.366%6,301,709 (149,110)
Huntington: UL Bollr FiniSh SH Pendant Repiacement 312 SG Nov-l0 I08SP 2.366%6.147.658 (145,465)
Jim Bndger: UL Generator Rewind 312 SG Jun-l0 108SP 2.366%6,145.656 (145,18)
Hunter: 301 Low Temp. SH Replacement 312 SG Apr-I 0 108SP 2.36%5.470.067 (129.32)
Dave Johnston: U3 - Horizontal SH Replace 312 SG May-I 0 108SP 2.366%5.088.802 (120.411)
Steam Production Total 607,878,794 (14,363,564)
Hydro Production
INV 11.5 Lemol 1 Forebay Expansion & We 332 SG.p Aug-10 I08HP 2.135%5.897.367 (125,881)
Hydro Production Total 5,897,367 (125,881)
Other Production
Dunlap i Wind Project 343 SG Nov-l0 1080P 4.052%261.183,699 (10,58,269)
Other Production Total 261,183,699 (10,584,269)
Transmission
Populus to Terminal (Populus to Ben Lomond)365 SG Nov-I 0 108TP 2,010%405,230,248 (8.143.863)
Populus to Terminal (Populus to Ben Lomond)355 SG Oct-I 0 108TP 2.010%144,568,559 (2.905,384)
PopuluS tc Terminal (Ben Lomond to Terminal)355 SG Mar.IO 108TP 2.010%190.877.118 (3.836,43)
Populus to Termnal (Ben Lomond to Termnal)355 SG Apr-IO 108TP 2.010%7.340,277 (147.517)
Three Peaks Sub: Install 345 kV Substation - Phase II 355 SG Jun-l0 I08TP 2.010%51,134,840 (1,027.653)
Camp Wiliams - 90th South Double Circut 345 kV line 355 SG Dec-l0 108TP 2.010%45.600,000 (916.20)
Red Butt -St George 138 kv dbl ckt, (345 kv Const)355 SG May-l 0 108TP 2.010%21,038.986 (422.819)
Pinto 345 kV Senes Capacitor 365 SG Nov-I 0 108TP 2.010%19,500.463 (391.899)
Dunlap Rach Wind Farm Phase 1 Interconnection 365 SG AugI 0 108TP 2.010%11,130,000 (223.679)
Uppr Green River Basin SuperiOr Project - Transmission Part 355 SG Decl0 108TP 2.010%10.025,204 (201.476)
Oquirr - New 345-138 kV Sub & 138 kV Switchyard 355 SG Jun-l0 108TP 2.010%8.416,078 (169.137)
Parrish Gap Canst Nw 23069kV Sub 355 SG Jun-l0 I08TP 2.010%8.34.559 (167.620)
Line 37 Conv to 115kV Bid Nickel Ml Sub - Trans 355 SG Mar-I 0 108TP 2.010%7.962,605 (160,024)
Chappel Creek 230 kV Cimerex Energy 20 MW Phase II 355 SG Dec-I 0 108TP 2.010%5,496,321 (110,459)
Communit Park Convert to 115-12.5 kV - Transmission Part 355 SG OctI 0 108TP 2.010%5,286.621 (106.245)
Transmission Total 941,947,879 (18,930,257)
Intangible
TriP 11 Energy Trading Systems Capital 303 SG Dec-I 0 1111P 4.020%11.470.408 (461.144)
Intangible T otai 11,470,408 (461,144)
Mining
Deer Creek-Reconstruct Longwall System 399 SE Dec-l0 108MP 3.608%23,905.000 (862,608)
Mining Total 23,905,000 (862,608)
1,852,283,166 (45,347,723)
Reff8.6.1 Rel# 6.2
Rocky Mountain Power PAGE 6.3
Idaho General Rate Case. December 2009
Hydro Decommissioning
TOTAL IDAHO
ACCOUNT ~COMPANY FACTOR FACTOR %ALLOCATED REF#
Allocation Correction to Booked Reserve
Depreciation Reserve 108HP 1 (36,245)SG-P 5.508%(1,997)6.3.2
Depreciation Reserve 108HP 1 36,245 SG-U 5.508%1,997 6.3.2
Adjustment to Reserve
Depreciation Reserve 108HP 3 (1,119,499)SG-P 5.508%(61,668)
Depreciation Reserve 108HP 3 (1,350,550)SG-U 5.508%(74,395)
(2,470,049)(136,063)Below
Adjustment to Reserve for Forecast Spend I Accrual Detail:
Dec 2009 Year End Reserve Balance (12,813,989)
Dec 2010 Year End Reserve Balance (15,284,037)Adjustment to Reserve (2,470,049)
6.3.1
6.3.1
6.3.1
Description of Adjustment:
In the current depreciation study effective Jan. 1, 2008, the Company proposed to establish a decommissioning fund in
order to build up a reserve for possible decommissioning of some of the remaining smaller hydro plants. The $19.4
milion estimate included the recovery of $6.5 milion for Cove and American Fork, as well as the accrual of an estimated
decommissioning fund for Condit and other small hydro facilities that have a probability of being decommissioned during .
the next ten years. The decommissioning reserve balance is adjusted to a December 2010 year end balance through this
adjustment.
Rocky Mountain Power
Idaho General Rate Case. December 2009
Hydro Decommissioning
Spending, Accruals, and Balances - Total Resources (East and West Sides)
Total Resources
December-08 79,976 (297,898)(10,234,242)
January-09 125,572 (297,898)(10,406,568)
February-09 (37,556)(297,898)(10,742,022)
March-09 189,347 (297,898)(10,850,573)
April-09 53,930 (297,898)(11,094,542)
May-09 59,853 (297,898)(11,332,587)
June-09 100,860 (297,898)(11,529,625)
July-09 45,031 (297,898)(11,782,492)
August-09 142,008 (297,898)(11,938,382)
Septem ber-09 136,997 (297,898)(12,099,284)
October-09 105,517 (297,898)(12,291,665)
November-09 34,374 (297,898)(12,555,189)
December-09 39,099 (297,898)(12,813,989)Ret 6.3
Total Resources
January-10 26,880 (297,898)( 13,085,007)
February-10 51,350 (297,898)(13,331,555)
March-10 156,250 (297,898)(13,473,203)
April-10 156,250 (297,898)( 13,614,852)
May-10 156,250 (297,898)(13,756,500)
June-10 128,750 (297,898)(13,925,648)
July-10 77,500 (297,898)(14,146,046)
August-10 66,500 (297,898)(14,377,444)
September-10 63,750 (297,898)(14,611,593)
October-10 73,750 (297,898)(14,835,741)
November-10 73,750 (297,898)(15,059,889)
December-10 73,750 (297,898)(15,284,037)Ret 6.3
Total Resources
12 ME Dec 2010
Spending Accruals
1,104,730 (3,574,779)
Adjustment to Reserve
Dec-2010 Year
End Balance
(15,284,037) Ref 6.3
(2,470,049) Ref 6.3
Page 6.3.1
Rocky Mountain Power
Idaho General Rate Case - December 2009
Hydro Decommissioning
Corrections to booked data
12 Months ended December 2009
Page 6.3.2
Dec 2009 Dec 2009 Adjustment to
Balance Balance Dec 2009
Accumulated Depreciation Booked Page Ref. Actuals Balance
108 I SG-P (15,880,185)B17 pçi 14 (15,916,430\(36,245)
108 I SG-U 3,066,196 B17 pg 14 3,102,442 36,245
To 6.3
To 6.3
During 2008 several entries were made to FERC locations that incorrectly assigned the balance on an
Eastlest basis. This adjustment is necessary to correctly assign accumulated depreciation related to Hydro
Decommissioning.
IDAHO REVISED PROTOCOL Page 7.0 Totl
Tax Adjustments (Tab 7)
TOTAL
7.1 7.2 7.3 7.4 7.5 7.6
Adjusl
Idaho Slate Accumulaled
Proper Tax Renewable Enery Investment Tax Deferred Incóme
Total Normalizd Interesl True Up Expense Tax Credit Credit AFUDC Equit Taxes 10 Actual
1 Operabng Revues:
2 General BUSIness . Revnues
3 Interdepartental
4 Speal Sales
5 Other Operbng Revenues
6 Total Operbng Revenues
7
8 Operabng Expenses:
9 Steam Proucbon
10 Nucler Proucbon
11 Hydro Produeon
12 Oth power Supply
13 Transmission
14 Distribubon
15 Custom Acounbng
16 Customer Service & Info
17 Sales
18 Adminislrative & Generl 209.996
19 Total O&M Expenes 209.996
20 Deprelabon
21 Amortion
22 Taxes Other Than Incoe 413,992 413.992
23 Incoma Taxes: Federal (4.118,90)(59.298)(138.319)(3,796.782)(53.29)
24 State (114.133)(8.58)(18,795)(70.472)(7,274)
25 Deferred Income Taxes 229.019 6,775
26 Investmnt Tax Credit Adj.
27 Mise Revenue & Expense
28 Totl Operating Expenses:(3,379.215)(67.356)256,878 (3.860.479)(60.803)
29
30 Operating Rev For Retum:3,379.215 67.356 (256,878)3,860.479 60.803
31
32 Rate Base:
33 Elecc Plat In Servic
34 Plant Held lo Future Us
35 MI~cDeferd Debits
36 Elee Plant Ac Adj
37 Nuclear Fuel
36 Preayments
39 Fuel Stoc
40 Maleral & Supplies
41 Wor1lng Capital
42 Weatheritio,n loans
43 Mise Rate Base
44 Total Electric Plant:
45
46 Deducbons:
47 Accum Prov For Depre
48 Accum Prov For Amort
49 Atcum Def Income Tax (898.818)458,355
50 Unamorzed irc (184.142)(184.142)
51 Customer Adv For Const
52 Customer Servce Deposit
53 Miscellaneo Deductios
54
55 Total DeduCbons:(1.082.96)(184.142)458.355
56
57 Totl Rate Base:(1.082.960)(184,142)458,355
56
59
60 Estimated ROElmpacl 1.188"1 0.023"1 .0.088"1 1.330"1 0.004%0.021%-0.009"1
61
62
63
84 TAX CALCULATION:
65
66 Operating Revenue (623.988)(413.992)
67 Other Deducbons
68 Interest (AFUDC)160.213 160.213
691nlerest 177.481 177.481
70 Schedule "M" Addlbons
71 Schedule "M" Deductions
72 Income Before Tax (961.683)(177.481)(413.992)(160.213)
73
74 State Income Taxes (114,133)(8.05)(18.795)(70,472)(7,274)
75
76 Taxable Income (847.551)(169,424)(395.197)70,472 (152,940)
77
78 Federal Income Tax - Calculated (296.643)(59,298)(138.319)24.665 (53.529)
79 Adjustents to Calculaed Tax:
80 Renewable Energy Tax Credijs (3.821,447)(3.821.447)
81 Federal Income Taxes (4.118.090)(59.298)(138,319)(3.796.782)(53.529)
1 Operating Revenues:
2 General Business Revenues
3 Interdepartental
4 Specal Sales
5 Other Operating Revenues
6 Total Operating Revenue
7
8 Operating Expenses:
9 Steam Producton
10 Nucr Production
11 Hydro Producon
12 Other Power Supply
13 Transmission
14 OistMbutlon
15 Customer Accounting
16 Customer Serviee & Info17 Sal
18 Administrative & General
19 Total O&M Exenses
20 Depreciation
21 Amorzation
22 Taxes Other Than Ineoe
23 inc:me Taxes: Fèder24 State
25 Defer Inco Taxes
26 Investment Tax Credit Adj.
27 Mise Revenue & Exense
28 T olal Operating Exenses:
29
30 Opeating Rev For Retm:
31
32 Rate eas.:
33 Eleete Plant In Serlee
34 Plant Held for Future Use
35 Mise Deferred Debits
35 Else Plant Aeq Adj
37 Nuelar Fuel
38 Prepayments
39 Fuel Stok
40 Materal & Supplies
41 Woring Capijal
42 Weatherition Loans
43 Mise Rate Base
44 Totl Elec Plant:
45
46 Dedctons:
47 Aeum Pro For Oepre
48 Accum Prov For Amort
49 Aceum Deflneome Tax
50 Unamortize ITC
51 Customer Adv For Canst
52 Custom"r Servee Deposits
53 Miscellaneos Deuctns
54
55 Total Dedons:
56
57 Total Rate Base:
58
59
60 Estimated ROE impact
61
62
63
64 TAX CALCULATION:
65
66 Operating Revenue
67 Other Deductons
68 Interet (AFUDC)
69 Interest
70 Schedule "M" Additions
71 Schedule .M" Deductions
72 Income Before Tax
73
74 State Income Taxes
75
76 Taxable Income
77
78 Federal Income Tax - Caleulated
79 Adjustment to Calculated Tax:
80 Renewabl Energy Tax Credit
81 Federllncme Taxes
98.171
209.996
209.996
(70.162)
(9.534)
124.073
98.171 254.374
(98.171)(254.374)
(1.259.002)(98.17)
(1.259.002)(96.17)
(1.259.02)(98.17)
0.025%-0.032%-0.088%0.00%0.0010 0.0010 0.000%
(209.996)
(209.996)
(9.534)
(200,462)
(70.162)
(70.162)
Rocky Mountain Power
Idaho General Rate Case . December 2009
Interest True Up
Adjustment to Expense:
Other Interest Expense - Type 1
Other Interest Expense - Type 2
Other Interest Expense - Type 3
Adjustment Detail:
Type 1
Jurisdiction Specific Adjusted Rate Base
Weighted Cost of Debt:
Trued-up Interest Expense
Actual Interest Expense
Total Interest True-up Adjustment
Type 2
Jurisdiction Specific Adjusted Rate Base
Weighted Cost of Debt:
Trued-up Interest Expense
Type 1 Interest Expense
Total Interest True-up Adjustment
Type 3
Jurisdiction Specific Adjusted Rate Base
Weighted Cost of Debt:
Trued-up Interest Expense
Type 2 Interest Expense
Total Interest True-upAdjustment
Description of Adjustment:
TOTAL
ACCOUNl Type COMPANY
427
427
427
1
2
3
(2,680,286)
7,223
2,850,544
177,481
PAGE 7.1
IDAHO
FACTOR FACTOR % ALLOCATED REF#
ID
ID
ID
Situs
Situs
Situs
(2,680,286) Below
7.223 Below
2,850,54 Below
177,481 2.18
566.045,341 1.3
.2.818% 2.1
15,950,705 1.0
18,630,991 2.18
(2.Mo,286) 1.3
566,301,670 1.3
2.818%2.1
15,957,928 1.3
15,950,705 1.3
7,223 1.3
667,459,415 2.2
2.818%2.1
18,808,472 2.18
15,957,928 1.3
2,850,544 1.3
This adjustment synchronizes interest expense with the jurisdictional allocated rate base by multiplying the rate base by
the Company's weighted cost of debt.
Rocky Mountain Power
Idaho General Rate Case. December 2009
Propert Tax Expense
PAGE 7.2
Adjustment to Tax:
Taxes OtherThan Income
TOTAL
ACCOUN1 ~ COMPANY
IDAHO
FACTOR FACTOR % ALLOCATED REF#
408 3 7,677,591 GPS 5.3922%413,992 7.2.1
Description of Adjustment:
This adjustment normalizes the difference between actual accrued property tax expense and proforma property tax
expense resultng from capital additions through 2010.
Rocky Mountain Power
Idaho General Rate Case. December 2009
Property Tax Adjustment Summary
Page 7.2.1
FERC Account GIL Account Co. Code Factor408.15 579000 1000 GPS
Total Accrued Propert Tax .12 Months End. December 2009
Total
87,317,409
87,317,409
Ref
Propert Tax Exp. for the Twelve Months Ending Dec 2010 94,995,000 See Confidential Exhibit
Less Accrued Property Tax - 12 Months Ended December 31, 2009 (87,317,409)
7,677,591 Ref 7.2Incremental Adjustment to Propert Taxes
Rocky Mountain Power PAGE 7.3
Idaho General Rate Case - December 2009
Renewable Energy Tax Credit
TOTAL IDAHO
ACCOUNT~COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Tax:
FED Renewable Energy Tax Credit 40910 1 (43,720,761)S8 5.5085%(2,408,357)
FED Renewable Energy Tax Credit 40910 2 (17,873,583)S8 5.5085%(984,566)
FED Renewable Energy Tax Credit 40910 3 (7,779,326)S8 5.5085%(428,524)
(69,373,671 )(3,821,447) 7.3.1
UT Renewable Energy Systems Tax Credit 40911 1 (307,545)S8 5.5085%(16,941) 7.3.1
OR Business Energy Tax Credit 40911 1 (545,197)S8 5.5085%(30,032)
OR Business Energy Tax Credit 40911 2 (34,996)S8 5.5085%(1,928)
OR Business Energy Tax Credit 40911 3 (391,600)S8 5.5085%(21,571)
(971,793)(53,531) 7.3.1
Deferred Tax Expense - OR BETC 41010 1 (119,974)OTHER 0.0000%
Deferred Tax Expense - OR BETC 41010 1 (348,313)IBT 8.5092%(29,638)
Deferred Tax Expense - OR BETC 41110 1 164,200 OTHER 0.0000%
Deferred Tax Expense - OR BETC 41110 1 427,931 IBT 8.5092%36,413
123,844 6,775
Description of Adjustment:
This adjustment normalizes federal and state renewable energy production tax credits and other state tax credits the
Company is entitled to take asa result of placing qualified generating plants into service. The federal PTe is based on the
generation of the plant, and the credit can be taken for ten years on qualifying property. The Utah state PTe is based on
the generation of the plant, and the credit can be taken for four years on qualifying property. The Oregon BETe is based
on investment, and the credit is taken over a 5 year period on qualifying property.
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Rocky Mountain Power
Idaho General Rate Case - December 2009
Idaho State Investment Tax Credit
PAGE 7.4
TOTAL
ACCOUNl ~ COMPANY
IDAHO
FACTOR FACTOR % ALLOCATED REF#
Adjustment to Tax:
Idaho -ITC 255 (2,164,049)1ST 8.5092%(184,142) 7.4.1
Description of Adjustment:
This adjustment normalizes Idaho state investment tax credit the Company has taken as a result of placing propert into
service. The tax credit is based on the plant placed in service, and the credit is usually utilized in a subsequent period
depending on the availability of Idaho state taxable income. Since PacifiCorp is a 46(f)(1) Company, the ITC unamortized
balance is what is reflected in results of operations as a rate base reduction.
Rocky Mountain Power Page 7.4.1
Idaho General Rate Case - December 2009
IdahQ - Investment Tax Credit (ITC) Amortization Adjustment. Summary
(E-G)
A B C 0 E F G H
Generated To Utlized to Amortized to Unamortized
Generated Date Unutilzed Utlized Date Amortized Date But Utilzed Yr-Yr Avg Ref
1992 $586,035 $586,035 $447,026 $ 139,009 $139,009 $4,634 $4,634 $134,375
1993 $160,034 $746,069 $66,476 $ 540,58 $679,593 $23,167 $27,801 $651,792 $393,084
1994 $95,054 $841,123 $1,848 $ 159,682 $839,275 $28,566 $56,367 $782,908 $717,350
1995 $526,562 $1,367,685 $33,408 $ 495,002 $1,334,277 $45,068 $101,435 $ 1,232.842 $1,007,875
1996 $391,295 $1,758,980 $1,848 $ 422,855 $1,757,132 $59,202 $160,637 $ 1.596,95 $1,414,669
1997 $222,807 $1,981,787 $2,287 $ 222,368 $1,979,500 $66,616 $227,253 $ 1,752,247 $1,674,371
1998 $332,201 $2,313,988 $189,115 $ 145,373 $2,124,873 $71,465 $298,718 $ 1,826,155 $1,789,201
1999 $177,341 $2,491,329 $233,862 $ 132,594 $2,257,467 $76,037 $374,754 $ 1,882,713 $1,854,434
2000 $148,753 $2,640,082 $267,001 $ 115,614 $2,373,081 $80,093 $454,847 $ 1,918,234 $1,900,473
2001 $174,914 $2,814,996 $441,865 $50 $2,373,131 $80,095 $534,942 $ 1,838,189 $1,878,211
2002 $159,742 $2,974,738 $601,557 $50 $2,373,181 $80,097 $615,039 $ 1,758,142 $1,798,165
2003 $525,855 $3,500,593 $ 1,127,362 $50 $2,373,231 $80,099 $695,138 $ 1,678,093 $1,718,118
2004 $593,452 $4,094,045 $ 1,425,989 $ 294,825 $2,668,056 $91,58 $786,718 $ 1,881,338 $1,779.716
2005 $578,273 $4,672,318 $ 1,640,194 $ 364,068 $3,032,124 $105,197 $891,915 $ 2,140,209 $2.010,774
2006 $593,136 $5,265,454 $ 2,015,439 $ 217,891 $3,250,015 $113,267 $1,005,182 $ 2,244,833 $2,192,521
2006.1 $494,926 $5,760,380 $ 2,510,365 $3,250,015 $.$1,005,182 $ 2,244,833 $2,244,833
2007 $737,121 $6,497,501 $ 2,954,885 $292,601 $3~542,616 $124,461 $1,129,644 $ 2,412,972 $2,328,902
2008 $1,549,142 $8,046,643 $ 4,504;027 $.$3,542,616 $124,461 $1,254,105 $ 2,288,511 $2,350,741
2009 $506,257 $8,552,900 $ 5,010,284 $$3,542,616 $124,461 $1,378,567 1$ 2,164,0491 $2,226,280 Ref 7.4
2010 $8,552,900 $ 5,010,284 $3,542,616 $124,461 $1,503,028 $ 2.039,88 $2,101,819
2011 $8,552,900 $ 5,010,284 $3,542,616 $124,461 $1,627,489 $ 1,915,127 $1,977,357
2012 $8,552,900 $ 5,010,284 $3,542,616 $124,461 $1,751,951 $ 1,790,665 $1,852.896
2013 $8,552,900 $ 5,010,284 $3,542,616 $124,461 $1,876,412 $ 1,666,204 $1,728,434
2014 $8,552,900 $ 5,010,284 $3,542,616 $124,461 $2,000,874 $ 1,541.742 $1,603,973
2015 $8,552,900 $ 5,010,284 $3,542,616 $124,461 $2,125,335 $ 1,417,281 $1,479,512
2016 $8,552,900 $ 5,010,284 $3,542,616 $124,461 $2,249,796 $ 1,292,820 $1,355,050
2017 $8,552,900 $ 5,010,284 $3,542,616 $124,461 $2,374,258 $ 1,168,358 $1,230,589
2018 $8,552,900 $ 5,010,284 $3,542,616 $124,461 $2,498,719 $ 1,043,897 $1,106,127
2019 $8,552,900 $ 5,010,284 $3,542,616 $124,461 $2,623,181 $919,435 $981,666
2020 $8,552,900 $ 5,010,284 $3,542,616 $124,461 $2,747,642 $794,974 $857,205
2021 $8.552,900 $ 5,010,284 $3,542,616 $124,461 $2,872,104 $670,512 $732,743
2022 $8,552,900 $ 5,010,284 $3,542,616 $104,413 $2,976,517 $566,099 $618,306
2023 $8,552,900 $ 5,010,284 $3,542,616 $99,002 $3,075.519 $467.097 $516,598
2024 $8,552.900 $ 5,010.284 $3,542.616 $95,832 $3.171,350 $371,266 $419.181
2025 $8,552,900 $ 5.010,284 $3,542,616 $78,241 $3,249,592 $293,024 $332,145
2026 $8.552,900 $ 5.010,284 $3,542,616 $65,196 $3,314,787 $227,829 $260,426
2027 $8,552,900 $ 5,010,284 $3,542,616 $57,766 $3,372,554 $.170,062 $198,945
2028 $8,552.900 $ 5,010,284 $3,542,616 $46,406 $3,418,960 $123,656 $146.859
2029 $8.552,900 $ 5,010,284 $3,542.616 $39,639 $3,458,599 $84,017 $103,837
2030 $8,552.900 $ 5,010,284 $3.542,616 $33,918 $3,492,516 $50,100 $67,059
2031 $8,552,900 $ 5,010,284 $3,542,616 $27,230 $3,519,746 $22,870 $36,485
2032 $8,552.900 $ 5,010,284 $3,542.616 $21,314 $3.541.060 $1,556 $12,213
2033 $8,552,900 $ 5,010,284 $3.542,616 $1,556 $3,542,616 $-$778
2034 $8,552,900 $ 5,010,284 $3,542,616 $.$3,542.616 $$
2035 $8,552.900 $ 5,010,284 $3.542,616 $.$3,542.616 $$
2036 $8,552,900 $ 5,010,284 $3,542.616 $.$3.542,616 $-$
2037 $8.552,900 $ 5.010,284 $3,542,616 $$3,542,616 $-$
2038 $8,552,900 $ 5,010,284 $3,542,616 $$3,542.616 $$
2039 $8,552,900 $ 5,010,284 $3,542,616 $.$3,542,616 $$
2040 $8,552,900 $ 5,010.284 $3,542,616 $$3,542.616 $-$
Rocky Mountain Power
Idaho General Rate Case. December2009
AFUDC Equity
TOTAL
ACCOUNT ~ COMPANY
Adjustment to Tax:
AFUDC - Equity 419 3,017,342
Description. of Adjustment: .
PAGE 7.5
IDAHO
FACTOR FACTOR % ALLOCATED REF#
SNP 5.3098%160,213
This adjustment brings in the appropriate level of AFUDC - Equity into results to align the tax Schedule M with
regulatory income.
Rocky Mountain Power PAGE 7.6
Idaho General Rate Case. December 2009
Adjust Accumulated Deferred Income Taxes to Actual
TOTAL IDAHO
ACCOUNT.~COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Rate Base:
Remove Base Period Amounts 190 1 (35,897,842)SG 5.5085%(1,977,432)
190 1 (4,380,987)NUTIL 0.0000%
282 1 2,336,392,080 DITBAL 6.0202%140,655,521
2,296,113,251 138,678,089 7.6.1
Replace Base Period Amounts 282 1 (56,470,338)CA Situs
282 1 (1,032,376)FERC Situs )
282 1 (138,219,734)ID Situs (138,219,734)
282 1 (648,426,881)OR Situs
282 1 (5,433,808)OTHER 0:0000%
282 1 (986,586,568)UT Situs
282 1 (159,148,238)WA Situs
282 1 (245,809,941 )WY-AII Situs
282 1 (54,985,367)WY-AII Situs
(2,296,113,251 )(138,219,734) 7.6.1
Description of Adjustment:
This adjustment aligns the Company's original jurisdictionally allocated accumulated deferred income taxes related to
depreciable and amortizable assets with actual deferred income tax expense from the Power Tax system.
Rocky Mountain .Power
Idaho General Rate Case -December 2009
Adjust Accumulated Deferred income Taxes to Actual
PAGE H.1
Accoont Book Tax DiferenceSAP FERC Descl'Dtion # Factor 1213112009
.. ~m~ i~g19!i()n~~I:.~.ri:lix_lnt,:IIi~R~!!!L...._.,....~_....._... ............. ......_...... _. ...~iHH..-... .-.. .ï;¡~¥iC-..... ......l~SßI!T,84?1.... ..... ...foaHnSHLJTax.lni.:Ta~RElnt+.e()()ki:pl. ... . . . ...... ........ .(4,380,987)... ..28Ie!J§. __..?a?j..... ~Q~~ÇllPJtllli!E(jI.llb.l)!çl)s!Sf()r.fO~rtll~il1put......_____..._ja$:i~a~..Qi:rI3~t;: ...... (e,.9.ee,t~'!)
....8!,e.9~.. ...._?8.?:.:.__B.~!2 Adj: De..!El£Ít~E~.:~r()~'\!!~~..._._...._..____.___. ...._.: 05:.:.2§"_. _..~A~_._ _!9?&§!,§2!.
... 287~OS. .... 282..1.... B.ei()k()ElprEl£i~i()n.........__..._......._..............1Q.S:1?..L..........gi:El..L,.....J2,,1.~&3SÆ6,)
.. 287605 282.1 Tax Depreciation ...106,.125.__ .... DITB...~ .... 3,047,028,895
.. .287695.. ?a?.: .9IA(;....... ....... ....................... ...1Q.6,.230 ....P.ITB...L.Oe9.,ee9.,772)
-1~ý~&~... .....~~H-... :~rifi~#t~¡~ii~~:llllcn..._.__.__.... .-------=:.. ......... ......_....:::=J~tl~~=.:.. :::=-:~tf~L':::: "--"''''-:d~:~~H~'¥j287605 282.1 AFUDC 105.141 DITBAL 133,222,5322a7eQ~.. .... . 28?1,;voigeg(;osts............. ..... ........ .J(j5:i4? ...... .... ........j:irfBAL. ...... ....... ...... .( 11S,9s2,739)
..?E6,Q.~... ...?6,?,L. §.r:.l)~).£n Pro'p,Qi.s.e!,.si~eii:......._._................~._.._ .._....2.Q.S,!g...._ _.l)..!!l~L._. _.... 6S.,SaZ~?6,!J
287605 .28?,1.. 9eia.!~JI1~Elv.ElIl)!?riEl.nL............ ....... ....196,,26,6,...._ .........Q!.!eAL. ...... 4.487,495287605 282.1 Coal Mine Extension 105.170 DITBAL 3.337,81928760S 282.1 RemovaïCõSïï iÓS:175ÓïTBAC107:êó5,63
"3~ffE =.=ilR-: ~:~~~~~if~~:~~:"~~.==:::~=~.~=~:~-..===~====~ :=::::.~~t~I=:~.= .:==~~L=':. .:.~~:::~~=~:::::IHI~l~l
2876Q5 . 28.?.1 .. R~E::S.El~.1Z.'!.I?El(ju.çtiQl...._. .... .............. .....3?Q,?1a...P.ITBAL ........ 10,404.917.
?~7~OS.. ......?8.?,t... .R~P!lIrê.I?(j~£li211_._..._.--_._.......__.._._..___ ...__._.... .__.!Qe,2..?~........_ ...._QIT_B"'... . ..........9.3,2.1:3,3Z3_.?1l76q~.. _._..?8.?:.._ Sec. 481a Adjustment.. Repair Deduction...____.__. _._':.Q5.123 __ ...~~__ ~_.___..lq¿~.2..ZP.?
...i~~~~~. .... ......~l1+.. fÕ~i!~~~Ro~f.T~~I~~!ll't_sales...-.-.-_........ ..._-..-............~f.~;--._--.~~~~E-_..-........_..(l.~~H~§)Remove Base Period Amounts 2.296,113,251 Ref 7.6
... -.:.:.... ...._,?6,?..:._ ~EcumiJl!~.QE1erred 1'!.~2~axes :.!!!!'!.1f.L.____ .--:::::____ _.-.A-___.. __--~1Z.Q.~.:,a......... - - - ..... 282.1._A.C£u.Il.u.!lite.a.l?ef~!C.Ln~El.lii~~~fr21?.!xJE.eR_ÇL.....__.__.____ ...__._._........_....___I!õB£._. _.....____..!,Q:g:3?.61282.1 AccullulatEldQeferredlnceilTeT!lxEls::~p.ert(Il)L. -::.::...._.... .._......I.I?...... .... ...J1aa,?192:34J
- - - - ... 282,2.... Aç~~niulatedl?e.fElrredll1~eill~!axEls_:f'eip~rtJ9R)..........._......_. .._.......::.::.:............... .____913.. ....... ....J~~il:?e,!8.1J
...:.:: -.:....... .....?8..:L. ..£~~ri~JElE..I?El!El'!ea_i.'!E..l)ni":rllX!.s_::.!'r£e..'.LQl'eBL._.._.___.__...._.:_:.:_:.__ OTHER ",........ ___~_..__l§..~3.8Q§2
282.1 Ac.niul"tElE i:eferre(jlncÇlrne "l"!'El.s::f'reipertyJU.TL ...._... .., _.... - - .::...._._ .__lJT_.. .. _ .__. . ...I986t5.le,56,8)- - - 282.1 Accumulated DeferrEllncome Taxes:: Prope'!(VYA). - - .:.............. .... .. VYf.. ...... ........ (159,148.238)
..:.. .. ....... i~H ~~~~i~l:âg:t:~:â:~¿~~H~~=~i~lë~~¡~~~~. ............. --: -: _ ..... ~.~...... J~~t~~~:~:?ReDlace Base P",riod Amounts 2.296,113,251 Ref 7.6Net Adiustment . 0
Rocky Mountain Power
Idaho General Rate Case. December 2009
Correct Allocation Factor
PAGE 7.7
Description of Adjustment:
This adjustment corrects an allocation factor on an item of accumulated deferred income taxes, related to the Bridger
Coal Company reclamation trust. Reclamation trust earnings are not included in results of operations and this related
deferred tax asset is being removed accordingly.
Rocky Mountain Power
Idaho General Rate Case- December 2009
Income Tax Normalization
Adjustment to Expense:
Deferred 1 ncome Tax Expense
TOTAL
ACCOUNl ~ COMPANY
41110 1 98,171
Adjustment to Rate Base:
Accum Def Income Tax Balance 1 (98,171 )282
Description of Adjustment:
PAGE 7.8
IDAHO
FACTOR FACTOR % ALLOCATED REF#
ID Situs 98,171 7.8.1
ID Situs (98,171)
As described in the testimony and exhibits of Company witness Ryan Fuller, the income taxes in this case have been
presented on a fully normalized basis. Accordingly, this adjustment removes the base period Idaho allocated income
tax flow-through.
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Rocky Mountain Power
Idaho General Rate Case. December 2009
Medicare Subisdy
PAGE 7.9
TOTAL IDAHO
ACCOUNT~COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Expense:
Deferred Income Tax Expense 41010 2,300,969 SO 5.3922%124,073 7.9.1
Regulatory Asset Amortization 930 209,996 ID Situs 209,996
Description of Adjustment:
The Company fied an application with the Commission to defer and amortize the initial write off related to the change
in law. This adjustment includes one year of amortization.
Rocky Mountain Power
Idaho General Rate Case -December 2009
Medicare Subisdy
Basé Period Medicare Subsidy Receivable
Federäi&.State' àlended-Statuto -fax Rate
Non-Deductible Post-Retirement Benefits
PAGE 7.9.1
......_......._------(~.Q~~-,gQQ)37.951%
2,300,969 Ref 7.9
IDAHO REVISED PROTOCOL Page 8.0 Total
Mise Rate Base Adjustments (Tab 8)
TOTAL
8.1 8.2 8.3 8.4 8.5 8.6
Environmental Custoer
Update Cash Trapper Mine Rate Jim Bndger Mine Settement Advances for Pro Forma Major
Total Normalized Working Capital Base Rate Base (PERCO)Constrction Plant Additons
1 Operating Revenues:
2 General Business Revenues
3 Inteepartmental
4 Speial Sales
5 Other Operating Revenues
6 Total Operating Revenues
7
8 Operatin9 Expenses:
9 Steam Production
10 Nuclear Production
11 Hydro Production
12 Other Power Supply
13 Transmission
14 Distrbution
15 Customer Accountin9
16 Custmer Service & Info
17 Sales
18 Administrative.& General
19 Total O&M Expenses
20 Depreciation (468)
21 Amortiztion (185,908)
22 Taxes Other Than Income
23 Income Taxes: Federal (1.810.240)(1.742.401)
24 State (245,982)(236.763)
25 Deferred Income Taxes 2,126,953 (950.787)
26 Investment Tax Credit Adj.
27 Mise Revenue & Expense
28 Total Operatin9 Expenses:(115,644)(2,929,952)
29
30 Operatin9 Rev For Return:115,644 2,929,952
31
32 Rate Base:
33 Electric Plnt In Service 114,204,038 751,615 11,240,331 102,235.939
34 Plant Held for Future Use (570,032)
35 Mise Deferred Debit 679,793
36 Elec Plant Acq Adj
37 Nuclear Fuel
38 Prepayments
39 Fuel Stock 1,519,196
40 Material & Supplies
41 WorkingCapttal 183.135 183,135
42. Weatheriation Loans
43 Misc Rate Base
44 Total Electric Plant:116.16,129 183,135 751,615 11,240,331 102.235,939
45
46 Deductions:
47 Accum Prov For Depree 13.482
48 Accm Prov For Amort
49 Accum Oaf Income Tax (2,020,219)950.787
50 Unamortized ITC
51 Customer Adv For Const (261,039)(261,039)
52 Customer Service Deposits
53 Miscellaneous Deductons (181,282)(181,282)
54
55 Total Deductions:(2,449,057)(181,282)(261,039)950,787
56
57 Total Rate Base:113.567,072 183,135 751,615 11,240,331 (181,282)(261,039)103.186,726
58
59
60 Estimated ROE impact .1.814%-0.004%-0.015%-0.216%0.004%0.005%-0.853%
61
62
63
64 TAX CALCULATION:
65
66 Operating Revenue 186,375
67 Other Deductions
68 Interest (AFUOC)
69 Interest
70 Schedule"M" Addttions 2,281.097 2,505,302
71 Schedule"M" Deductons 7,885.569 7.720,354
72 Income Before Tax (5,418,096)(5,215,052)
73
74 State Income Taxes (245,982)(236,763)
75
76 Taxable Income (5,172,115)(4.978,288)
77
78 Federal Income Taxes (1,810,240)(1,742.401)
Rocky Mountain Power PAGE 8.1
Idaho General Rate Case. December 2009
Update Cash Working Capital
CWC
CWC
CWC
1
2
3
(29,056)
(5,070)
217,261
183,135
IDAHO
FACTOR FACTOR % ALLOCATED REF#
ID Situs (29,056)
ID Situs (5,070)
ID Situs 217,261
183,135
Adjustment to Rate Base:
Cash Working Capital
Cash Working Capital
Cash Working Capital
TOTAL
ACCOUNT ~ COMPANY
Adjustment Detail:
Typé1 Type 2 Type 3
O&M Expense 167,146,247 167,170,041 182,254,199 1.3
Taxes Other Than Income Tax 5,321,337 5,321,337 5,735,330 1.3
Federal Income Tax (18,114,086)(18,596,263)(17,477,596)1.3
State Income Tax (2,206,626)(2,140,379)(1,952,739)1.3
Less: Embedded Cost Differential (3,461,309)(3,461,309)(3,461,309)2.9
Total 148,685,562 148,293,427 165,097,885
Divided by Days in Year 365 365 365
Average Daily Cost of Service 407,358 406,283 452,323
Net Lag Days 4.72 4.72 4.72
Cash Working Capital 1,922,319 1,917,249 2,134,510
Unadjusted Cash Working Capital 1,951,376 1,922,319 1,917,249
Cash Working Capital Adjustment (29,056)(5,070)217,261
Description of Adjustment:
This adjustment is necessary to compute the cash working capital for the normalized results made in this fiing. Cash
working capital is calculated by taking total operation and maintenance expense allocated to the jurisdiction (excluding
depreciation and amortization) and adding its share of allocated taxes, including state and federal income taxes and taxes
other than income. This total is divided by the number of days in the year to determine the Company's average daily cost of
service. The daily cost of service is multiplied by net lag days to produce the adjusted cash working capital balance. Net lag
days are calculated using the Company's December 2007 lead lag study.
Rocky Mountain Power PAGE 8.2
Idaho General Rate Case - December 2009
Trapper Mine Rate Base
399
399
1
3
11,210,192
612,257
11,822,449
IDAHO
FACTOR FACTOR %ALLOCATED REF#
SE 6.358%712,690 Below
SE 6.358%38,924 Below
751,615 Below
Adjustment to Expense:
Other Tangible Propert
Other Tangible Property.
TOTAL
ACCOUNT ~ COMPANY
Adjustment Detail
Dec 2009 Year End Balance
Dec 2010 Year End Balance
Adjustment to Dec 2010 YE Balance
11,210,192
11,822,449
612,257
8.2.1
8.2.1
Above
Description of Adjustment:
The Company owns a 21.40% interest in the Trapper Mine, which provides coal to the Craig generating plant. The
normalized coal cost of Trapper includes all operating and maintenance costs but does not include a return on investment.
This adjustment adds the Company's portion of the Trapper Mine plant investment to rate base. This adjustment reflects net
plant to recognize the depreciation of the investment over time.
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Rocky Mountain Power
Idaho General Rate Case. December 2009
Jim Bridger Mine Rate Base
Adjustment to Expense:
Other Tangible Propert
. Other Tangible Propert
TOTAL
ACCOUNT ~ ,COMPANY
399
399
1
3
163,626,605
13,177,056
176,803,661
Adjustment Detail
Dec 2009 Balance
Dec 2010 Balance
Adjustment to Dec 2010 Balance
163,626,605
176,803,661
13,177,056
PAGE 8.3
IDAHO
FACTOR FACTOR %ALLOCATED REF#
SE 6.358%10,402,597 Below
SE 6.358%837,734 Below
11,240,331
8.3.1
8.3.1
Above
Description of Adjustment:
PacifiCorp owns a two-thirds interest in the Bridger Coal Company (BCC), which supplies coal to the Jim Bridger generating
plant. The Company's investment in BCC is recorded on the books of Pacific Minerals, INC (PMI), a wholly-owned
subsidiary. Because of this ownership arrangement, the coal mine investment is not included in Account 101 -Electric Plant
in Service. The normalized costs for BCC provide no return on investment. The return on investment for BeC is removed in
the fuels credit which the Company has included as an offset to fuel prices leaving no return in results. This adjustment is
necessary to properly reflect the BCC plant investment in the 12-month period.
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Rocky Mountain Power
Idaho General Rate Case. December 2009
Environmental Settlement (PERCO)
PAGE 8.4
Adjustment to Rate Base:
Unspent Proceeds Dec 2009 25399
Proceeds Spent Through Dec 2010 25399
Unspent Environmental Proceeds Dec 2010
TOTAL
ACCOUNT ~ COMPANY FACTOR
IDAHO
FACTOR % ALLOCATED REF#
1
3
(7,903,238)
4,541,327
(3,361,911)
SO
SO
5.392%
5.392%
(426,160) 8.4.2
244,878 8.42
(181,282) 8.4.2
Description of Adjustment:
The Company received an insurance settlement of $38 milion for environmental clean-up projects. These funds were
transferred to a subsidiary called PacifiCorp Environmental Remediation Company (PERCO). This adjustment reduces rate
base by the amount of unspent cash proceeds on regulated projects from the insurance settlement.
Page 8.4.1
Page 8.4.2
Rocky MoutlO Power
Idaho General Rat Case. December 2009
Paclfcor Environmental Remediation Cll.
Spending by Environmntal Project
Cash Cumulative Remaining Actual Actual Pro Fonna Remaining
Received Actual Spending Cash at Spending Spendin Spending Cash at
Sije WBS 1996 & after thru De 31. 2008 Dec 31. 2008 Jan-Jun 09 Jul.De 09 2010 Dec 31. 2010
Portable Equipment GW PERC/1997/ElOS9 (259.086)
Idaho Falls Pole Yard PERC/19971E090 3,156.207 776.243
Idaho Falls Pole Yard PERC/1997/El091 180,489 270,645
Astoria Steam Plant PERC11997/El092 529,908
Bear River Erosion Control PERC/1997/EI93 3,394
Beaver Bay Drinfield Cleanup PERC/1998/ElO94 20,264
Bridger Bon Contaminated Soil Rem PERC/1998/El095 2.34
Bridger Coal Warehouse Spil PERC/19981E097 2,278
Bndger Oil Spill (New Releeses)PERC/1998/El098 591,830 75,476 103.613 112.785
Cedar Steam Plant PERCI19981E099 3.533
Centralia Mine Pond Reclamation PERC/19981E100 503.287
Cougar Shore Line Repair PERC/19981E101 29,921
Mining Central Warehouse Cleanup PERC/19981E102 82,628 3,828 46,266 19.226
Deer Creek Terrce Stablization PERC/1998/El103 12,778
Domestic Water System Testing and Review PERC/19981104 64,768
Hale Plant Cleanup PERC/1998/El105 300,828
Huntington Ash Stonn Runoff Pond PERC/1998/El106 33,55
Huntington Lead Paint Removal PERC/1998/El107 143,979
Lead Paint Removal (1998 Funds)PERC/1998/El108 9,591
Lewis / Swif Reservoir Cleanup PERC/1998/El109 290,538
Lifton Pumping Station Cleanup PERC/19981E110 401
Merw Oil House Removal PERC/1998/El111 20,022
Naughton South Ash Pond Reclam PERC/1998/El112 239,493
Ogden Pole Treating Remediation PERC/1998/E113
Speelyai Weli PERC/199/El114 176
Bi9 Fork PCB Soil Cleanup PERC/2003/El123 103,407 52,247
Pw Delivery UST Compliance Audij PERC/2003lEl124 12.123
Brdger FGD Pond 1 Closure PERC/20071E126 177507 34,276-73,635 430,026
Huntingon Plant Fuel and Lube Oil Tank Fann PERC/2007/El127 113,931 62,205
Olympia. WA PERC/2007/El128 7,151 111 18 24,880
Powerdale Cleanup PERC/2007/El129 13,94
Lincoln Steam Plant PERC/20081E130 56.207
Portland Harbor Source Control PERCI008/El131 3,463 135,96 185,775 646.69
Grace Hydro Plant PERC/2009/El132 7,527 31,789
Astoria Young's Bay 401980 2,313,081
Silver Bell / Telluride (Ms cost center)401981 525,275
Attorney contingency ree received
REGULATED TOTAL 38,624,130 28,823,333 9,800,797 879.692 1,017.867 4,541,327 3,361,911
Pag.8.4 Page 8.4
12131/2009
Balance
7,903,238
Page 8.4
Rocky Mountain Power
Idaho General Rate Case - December 2009
Customer Advances for Construction
Adjustment to Rate Base:
Customer Advances
Customer Advances
Customer Advances
Customer Advances
Customer Advances
Customer Advances
Customer Advances
Customer Advances
TOTAL
ACCOUNT ~ COMPANY
252
252
252
252
252
252
252
252
1
1
1
1
1
1
1
1
15,092
6,822
(135,799)
734,632
(187,907)
2,990,242
1,439,607
(4,862,689)
Description of Adjustment:
FACTOR
CA
ID
OR
UT
WA
WY-AII
WY-AII
SG
PAGE 8.5
IDAHO
FACTOR % ALLOCATED REF#
Situs
Situs
Situs
Situs
Situs
Situs
Situs
5.508%
6,822
(267,861l
(261,039l 8.5.1
Customer advances for construction are booked into FERC Account 252. When they are booked, the entries do not reflect the
proper jurisdictional allocation. This adjustment corrects the allocation of customer advances for construction.
Rocky Mountain Power
Idaho General Rate Case - December 2009
Customer Advances for Construction
Page 8.5.1
YEAR I END BASIS:
Account
252CA
2521DU
2520R
252UT
252WA
252WYP
252WYU
252SG
Total
Booked Allocation
(21,136)
(275,088)
(1,433,537)
(3,338,475)
(72,130)
(6,893,138)
(1,439,607)
(7,471,547)
(20,944,658)
Correct Allocation
(6,044)
(268,266)
(1,569,336)
(2,603,843)
(260,037)
(3,902,896)
( 12,334,236)
(20,944,658)
Adjustment Ref
15,092
6,822
(135,799)
134,632
(187,907)
2,990,242
1,439,607
(4,862,689)
Ref 8.5
Rocky Mountain Power PAGE 8.6
Idaho General Rate Case. December 2009
Pro Forma Major Plant Additions
TOTAL IDAHO
ACCOUNT :I COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Rate Base:
Steam Production 312 3 607,878,794 SG 5.508%33,484,991
Hydro Production 332 3 5,897,387 SG-P 5.508%324,857
Other Production 343 3 261,183,699 SG 5.508%14,387,299
Transmission 355 3 941,947,879 SG 5.508%51,887,179
Mining Plant 399 3 23,905,000 SE 6.358%1,519,766
Intangible Plant 303 3 11,470,408 SG 5.508%631,847
Total 1 ,852,283,166 102,235,939 8.6.2
Adjustment to Tax:
Schedule M Additions
Mining SCHMAT 3 862,608 SE 6.358%54,840
Steam Production SCHMAT 3 14,383,563 SG 5.508%792,318
Other Production SCHMAT 3 10,584,269 SG 5.508%583,034
Transmission SCHMAT 3 18,930,257 SG 5.508%1,042,773
Intangible Plant SCHMAT 3 461,144 SG 5.508%25,402
Hydro Production SCHMAT 3 125,881 SG 5.508%6,934
Total 45,347,723 2,505,302
Deferred Tax Expense
Mining 41110 3 (327,368)SE 6.358%(20,813)
Steam Production 41110 3 (5,458,706)SG 5.508%(300,693)
Other Production 41110 3 (4,016,836)SG 5.508%(221,267)
Transmission 41110 3 (7,184,222)SG 5.508%(395,743)
Intangible Plant 41110 3 (175,009)SG 5.508%(9,640)
Hydro Production 41110 3 (47,773)SG 5.508%(2,632)
Total (17,209,914)(950,787)
Accum Def Income Tax Balance
Mining 282 3 327,368 SE 6.358%20,813
Steam Production 282 3 5,458,706 SG 5.508%300,693
Othér Production 282 3 4,016,836 SG 5.508%221,267
Transmission 282 3 7,184,222 SG 5.508%395,743
Intangible Plant 282 3 175,009 SG 5.508%9,640
Hydro Production 282 3 47,773 SG 5.508%2,632
Total 17,209,914 950,787
Schedule M Deductions
Mining SCHMDT 3 3,416,025 SE 6.358%217,174
Steam Production SCHMDT 3 36,337,080 SG 5.508%2,001,627
Other Production SCHMDT 3 52,236,740 SG 5.508%2,877,460
Transmission SCHMDT 3 47097393.95 SG 5.508%2,594,359
Intangible Plant SCHMDT 3 318,622 SG 5.508%17,551
Hydro Production SCHMDT 3 221,152 SG 5.508%12,182
Total 139,627,012 7,720,354
Description of Adjustment:
This adjustment places into rate base the major plant additions for calendar year 2010. Major plant additions include
individual projects valued at $5 million or more.
The associated depreciation expense and accumulated reserve impacts are accounted for in adjustment 6.1 and 6.2
Rocky Mountain Power PAGE 8.6.1
Idaho General Rate Case. December 2009
Contd Pro Forma Major Plant Additions
TOTAL IDAHO
ACCOUNT~COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment To Tax (Contd):
Deferred Tax Expense
Mining 41010 3 1.296.415 SE 6.358%82,420
Steam Production 41010 3 13.790.285 SG 5.508%759.638
Other Production 41010 3 19.824.365 SG 5.508%1.092.025
Transmission 41010 3 17.873.932 SG 5.508%984.585
Intangible Plant 41010 3 120.920 SG 5.508%6.661
Hydro Production 41010 3 83.929 SG 5.508%4.623
Total 52.989.847 2.929.952
Accum Def Income Tax Balance
Mining 282 3 ( 1.296,415)SE 6.358%(82,420)
Steam Production 282 3 (13.790.285)SG 5.508%(759.638)
Other Production 282 3 (19.824,365)SG 5.508%( 1.092.025)
Transmission 282 3 (17.873,932)SG 5.508%(984.585)
Intangible Plant 282 3 (120.920)SG 5.508%(6.661 )
Hydro Production 282 3 (83.929)SG 5.508%(4.623)
(52.989.847)(2.929,952)
Description of Adjustment:
This adjustment places into rate base the major plant additions for calendar year 2010. Major plant additions include
individual projects valued at $5 million or more.
The associated depreciation expense and accumulated reserve impacts are accounted for in adjustment 6.1 and 6.2
Page 8.6.2
Rocky Mountain Power
Idaho General Rate Case - December 2009
Major Plant Addition Detail - Jan2010 to Dec2010
Jan10 to Dec10 Plant
Project Description Account Factor In-Service Date Additions
Steam Production
Dave Johnston: U3 S02 & PM Emission Cnti1 Upgrades 312 SG May-10 299,768,628
Huntington U1 Clean Air - PM 312 SG Nov-10 88,104,324
Hunter: 301 Turbine Upgrade HPIIP/LP 312 SG Apr-10 31,714,226
Huntington: U1 Turbine Upgrade HPIIP/LP 312 SG Nov-10 31,260,581
U1 Huntington Clean Air - S02 312 SG Nov-10 24,325,082
Jim Bridger: U1 S02 & PM Em Cnti1 Upgrades 312 SG Jun-10 17,148,123
Dave Johnston: U3 Low Nox Burners 312 SG Aug-10 15,080,879
Hunter: 301 Main Controls Replacement 312 SG Apr-10 10.959.812
Dave Johnston: U3 - Replace BoilerlTurbine Controls 312 SG May-10 10,767,578
Jim Bridger: U1 Turbine Upgrade HP/IP 312 SG Jun-10 9,471,009
Huntington: U1 Clean Air - NOx 312 SG Nov-10 9,344,387
Jim Bridger: U1 Reheater Replacement 10 312 SG Jun-10 8,067.849
Huntington: U1 Economizer Replacement 312 SG Nov-10 8,011.393
Huntington Water Effciency Mgt Project 312 SG Jun-10 7,614.560
Jim Bridger. U1 Clean Air - NOx 312 SG Jun-10 7,086,474
Hunter: 301 Economizer Replacement 312 SG Apr-10 6,301.709
Huntington: U1 Boiler Finish SH Pendants Replacement 312 SG Nov-10 6.147,658
Jim Bridger: U1 Generator Rewind 312 SG Jun-10 6.145.656
Hunter: 301 Low Temp. SH Replacement 312 SG Apr-10 5,47.,067
Dave Johnston: U3 - Horizontal SH Replace 312 SG May-10 5,088,802
Steam Producton Total 607,878,794
Hydro Production
INU 11.5 Lemolo 1 Forebay Expansion & We 332 SG-P Aug-10 5,897,387
Hydro Production Total 5,897,387
Other Production
Dunlap i Wind Project 343 SG Nov-10 261,183,699
Other Production Total 261,183,699
Transmission
Populus to Terminal (Populus to Ben Lomond)355 SG Nov-10 405,230,248
Populus to Terminal (Populus to Ben Lomond)355 SG Oct-10 144,5g8,559
Populus to Terminal (Ben Lomond to Terminal)355 SG Mar-10 190,877,118
Populus to Terminal (Ben Lomond to Terminal)355 SG Apr-10 7,340,277
Three Peaks Sub: Install 345 kV Substation - Phase II 355 SG Jun-10 51,134,840
Camp Willams - 90th South Double Circuit 345 kV line 355 SG Dec-10 45,600,000
Red Butte -St George 138 kv dbl ckt, (345 kv Const)355 SG May-10 21,038,986
Pinto 345 kV Series Capacitor 355 SG Nov-10 19,500,463
Dunlap Ranch Wind Farm Phase 1 Interconnection 355 SG Aug-10 11,130,000
Upper Green River Basin Superior Project - Transmission Part 355 SG Dec-10 10,025.204
Oquirr - New 345-138 kV Sub & 138 kV Switchyard 355 SG Jun-10 8,416,078
Parrish Gap Const Nw 230-69kV Sub 355 SG Jun-10 8,340,559
Line 37 Cony to 115kV Bid Nickel MlSub. Trans 355 SG Mar-10 7,962,605
Chappel Creek 230 kV Cimarex Energy 20 MI Phase II 355 SG Dec-10 5,496,321
Community Park Convert to 115-12.5 kV - Transmission Part 355 SG Oct-10 5,286.621
Transmission Total 941,947,879
Intangible
TriP II Energy Trading Systems Capital 303 SG Dec-10 11,470,408
Intangible Total 11,470,408
Mining
Deer Creek-Reconstruct Longwall System 399 SE Dec-10 23.905,000
Mining Total 23,905,000
1,852,283,166
Ref#8.6
Rocky Mountain Power PAGE 8.7
Idaho General Rate Case. December 2009
Miscellaneous Rate Base
TOTAL IDAHO
ACCOUNT~COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment Rate Base:
1 - Fuel Stock - Pro Forma 151 3 28,932,183 SE 6.358%1,839,370
1 - Fuel Stock - Pro Forma 151 3 (4,287,592)SSECH 6.022%(258,194)
24,644,591 1,581,176 8.7.1
1 - Fuel Stock - Working Cap. Depo!25316 3 (882,000)SE 6.358%(56,073) 8.7.1
1 - Fuel Stock - Working Cap. Depo:25317 3 (92,906)SE 6.358%(5,907) 8.7.1
(974,906)(61,980)
2 - Prepaid Overhauls 186M 3 9,640,233 SG 5.508%531,032 8.7.1
Description of Adjustment:
1 - The cost of the Company's coal plant fuel stock is increasing due to increases in the cost of coal and the number of
tons stored at each site. This adjustment reflects the increase in the fuel stock balance into results. This adjustment
also reflects the working capital deposits which are an offset to fuel stock costs.
2 - Balances for prepaid overhauls at the Lake Side, Chehalis and Currant Creek gas plants are walked forward to reflect
payments through the test period and transfers of capital to electric plant in service during the 12 months ending
December 2010.
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Rocky Mountain Power
Idaho General Rate Case - December 2009
Powerdale Hydro Decommission
, PAGE 8.8
Adjustment to Expense:
Remove Booked Amortization 407
TOTAL
ACCOUNT ~ COMPANY FACTOR
IDAHO
FACTOR % ALLOCATED REF#
3 (3,479,961 )SG-P 5.508%(191,694) 8.8.1
Adjustment to Unrecovered Plant:
Powerdale Unrecvd. Plant Reg. Ass 182M 3 (2,654,642)SG-P 5.508%(146,231) 8.8.2
Adjustment to Decommissioning Regulatory Asset:
Decommissioning Amortization 4041P 3
Decommissioning Reg Asset 182M 3
105,034
4,005,902
SG-P
SG-P
5.508%
5.508%
5,786 8.8.3
220,665 8.8.3
Adjustment to Tax:
Schedule M Deduction SCHMDT 3 2,999,281 SG 5.508%165,215
Deferred Income Tax Expense 41010 3 1,138,257 SG 5.508%62,701
Deferred Income Tax Balance 283 3 (1,520,280)SG 5.508%(83,745)
Schedule M Addition SCHMAT 3 (4,070,159)SG 5.508%(224,205)
Deferred Income Tax Expense 41110 3 1,544,666 SG 5.508%85,088
Deferred Income Tax Balance 283 3 774,986 SG 5.508%42,690
Description of Adjustment:
This adjustment reflects the treatment approved by the Commission in Case No. PAC-E-07-04 to account for the
decommissioning of the Powerdale hydroelectric plant due to damage caused by a flood in November 2006. During
2007, the net book value (including an offset for insurance proceeds) of the assets to be retired was transferred to the
unrecovered plant regulatory asset. In addition, future decommissioning costs are deferred as they are spent and
amortized over ten years, beginning in the subsequent year after they are spent.
Page 8.8.1Rocky Mountain Power
Idaho General Rate Case. December 2009
Powerdale Hydro Decommission
Powerdale Amortization
Date
Jan 2009
Feb 2009
Mar 2009
Apr 2009
May 2009
June 2009
July 2009
Aug 2009
Sept 2009
Oct 2009
Nov 2009
Dec 2009
Total
Amortization
289,997
289,997
289,997
289,997
289,997
289,997
289.997
289,997
289,997
289,997
289,997
289,997
3,479,961
RefS.S
Gil Account Balance Display
289,996.77
\\i;¡'~ea¡a~~~~\:
289,996.76 2,31
"Edl1:tØ9;~$6i7G. ¿ 'jiEl&
289,996.76 ~-:2,899,967.61
289,996,76 '.3,189;$64.31'
289,996.77 3,479,961.14
3;479,961.14
Rocky Mountain Power
Idaho General Rate Case - December 2009
Powerdale Hydro Decommission
Page 8.8.2
Unrecovered Plant Adjustment:
Dec 2009 Balance
Dec 2010 Balance
Adj to Dec 2010 Balance
2,654,642 Below
(0) Below
(2,654,642) Ref 8.8
Unrecovered Plant Amortization Schedule:
Beg Balance
Amort May 07 - Dec 07
Balance Remaining to Amortze
Monthly Amort Exp
,,,
Dec-09 221,220 2,654,642
Jan-10 221,220 2,433,422
Feb-10 221,220 2,212,201
Mar-10 221,220 1,990,981
Apr-10 221,220 1,769,761
May-10 221,220 1,548,541
Jun-10 221,220 1,327,321
Jul-10 221,220 1,106,101
Aug-10 221,220 884,881
Sep-10 221,220 663,660
Oct-10 221,220 442,440
Nov-10 221,220 221,220
Dec-10 221,220 (0)
May-07
Jun-07
Jul-07
Aug-07
Sep~07
Oct-07
Nov-07
Dec-07
Jan-08
Feb-08
Mar-08
Apr-08
May-08
Jun-08
Jul-OB
Aug-OB
Sep-OB
Oct-08
Nov-OB
Dec-08
Jan-09
Feb-09
Mar-09
Apr-09
May-09
Jun-09
Jul-09
Aug-09
Sep-09
Oct-09
Nov-09
8,796,061
(832,136)
7,963,925
221,220
Amort
104,017
104,017
104,017
104,017
104,017
104,017
104,017
104,017
221,220
221,220
221,220
221,220
221,220
221,220
221,220
221,220
221,220
221,220
221,220
221,220
221,220
221,220
221,220
221,220
221,220
221,220
221,220
221,220
221,220
221,220
221220
Balance
8,692,044
8,588,027
8,84,010
8,379,993
8,275,976
8,171,959
8,067,942
7,963,925
7,742,705
7,521,485
7,300,265
7,079,044
6,857,824
6,636,604
6,415,384
6,194,164
5,972,944
5,751,724
5,530,503
5,309,283
5,088,063
4,866,843
4,645,623
4,424,403
4,203,183
3,981,963
3,760,742
3,539,522
3,318,302
3,097,082
2875862
8,796,061
Rocky Mountain Power
idaho General Rate Case. December 2009
Powerdale Hydro Decommission
Regulatory Treatment of Decommissioning Costs
Amorize actual cash spent over 10 years beginning in the year subsequent to the cash being spent.
Case No. PAC-E-07-04
Monthly Amortization Through Dec 2010
Dec 2007 June 2008
Date Spend Spend
Oec.Q7
Jan-08
Feb-08
Mar-08
Apr-08
May-08
Jun-08
Jul-08
Aug.Q8
Sep-08
Oct-08
Nov-08
Dec-08
Jan-09
Feb-09
Mar-09
Apr-09
May-09
Jun-09
Jul-09
Aug-09
Sep.Q9
Oct-09
Nov-09
De-09
Jan-10
Feb-10
Mar-10
Apr-10
Mày-10
Jun-10
Jul-10
Aug-10
Sep-10
Oct-10
Nov-10
Oec-10
Cash Spend
TOTAL
4,423,006
Actual
Dec 2007
38,236
Actual
June 2008
34,523
Actual
Dec 2008
326,331
Actual
June 2009
41Q,104
Actuat
Dec 2009
241,160
Dec 2008
Spend
June 2009
Spend
Dec 2009
Spend
319
319
319
319
319
319
319
319
319
319
319
319
319 288 2,719
319 288 2,719
319 288 2,719
319 288 2,719
319 288 2,719
319 288 2,719
319 288 2,719
319 288 2,719
319 288 2,719
319 288 2,719
319 288 2,719
319 288 2,719
319 288 2,719 3,418 2,010
319 288 2,719 3,418 2,010
319 288 2,719 3,418 2,010
319 288 2,719 3,418 2,010
319 288 2,719 3,418 2,010
319 288 2,719 3,418 2,010
319 288 2,719 3,418 2,010
319 288 2,719 3,418 2,010
319 288 2,719 3,418 2,010
319 288 2,719 3,418 2,010
319 288 2,719 3,418 2,010
319 288 2,719 3,418 2,010
Estimate
June 2010
1,552,158
June 2010
Spend
Estimate
Dec 2010
1,552,158
Dec 2010
Spend
Page 8.8.3
Estimate
Dec 2011
43,555
Estimate
Dec 2012
204,382
Estimate
Dec 2013
20,399
Amor Regulatory
Total Asset Balance
38,236
Reference
319
319
319
319
319
319 70,847
319
319
319
319
319
319 395,266
3,326
3.326
3,326
3,326
3,326
3,326 785,416
3,326
3,326
3,326
3,326
3,326
3326 1 006 621
8,753
8,753
8,753
8,753
8,753 12 ME Dec 2010
8,753 ):Amortzation
8,753 $105,035
8,753 Ref 8.8
8,753
8,753
8,753 -/
8,753 4,005,902 Ref 8.8 I
Rocky Mountain Power
Idaho General Rate Case - December 2009
Goose Creek Transmission
PAGE 8.9
TOTAL IDAHO
ACCOUNT IY COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Rate Base:
Remove Future Retirement:
Transmission Plant In Service 350 1 (432,913)SG 5.508%(23,847) 8.9.1
Accum. Provo for Depreciation 108TP 1 244,755 SG 5.508%13,482 8.9.1
Adjustment to Depreciation Expense:
Depreciation Expense 403TP 1 (8,488)SG 5.508%(468) 8.9.1
Description of Adjustment:
On April 1, 2008, the Company sold 13.85 miles of transmission line, running from the Company's Goose Creek switching
station and extending north to the Decker 230 kV substation near Decker, Montana. The assets sold included structures,
miscellaneous support equipment, easements and rights-ot-way associated with the transmission line. The sale ot the
transmission line resulted in the Goose Creek switching station no longer being useful to the Company. The Company
plans to remove the Goose Creek switching station including all above ground facilities. ECAM Order No. 30904 stated that
the Company could write off the gain associated with the Goose Creek sale. The gain was written-off in September 2009.
Rocky Mountain Power
.Idaho General Rate Case - December 2009
Goose Creek Transmission Sale
Rate Base (Assets Retired)
Switching Station
Switching Station Accum Depr
Switching Station Book Value
Depreciation Expense
FERC Acct
350
108TP
FERC Acct
403TP
Factor
SG
SG
Balance
Dec 2009
432,913
(244,755)
188,158
Page 8.9.1
Reference
Page 8.9
Page 8.9
12 Months Ended
Factor Dec 2009 ReferenceSG 8,488 Page 8.9
Rocky Mountain Power
Idaho General Rate Case - December 2009
FERC 105 (PHFU)
PAGE 8.10
Adjustment to Rate Base:
Remove PHFU
Remove PHFU
Remove PHFU
Remove PHFU
TOTAL
ACCOUNT ~ COMPANY FACTOR
IDAHO
FACTOR % ALLOCATED REF#
105
105
105
105
1
1
1
1
(9,248,330)
(953,014)
(2,726,936)
(746,268)
(13,674,549)
SG
SE
UT
OR
5.508%
6.358%
Situs
Situs
(509,444)
(60,588)
(570,032) 8.10.1
Description of Adjustment:
This adjustment removes all Plant Held for Future Use (PHFU) assets from FERC account 105. The company is making this
adjustment in compliance with Title 16 of Public Utilty Regulation, chapter 5 "Powers and Duties of Public Utilties
Commission" section 61-502A.
Page 8.10.1
Rocky Mountain Power
Idaho General Rate Case - December 2009
FERC 105 (PHFlI)
Primary Account Secondary Account A1loc Total
1050000 LAND AND LAND RIGHTS 3400000 LAND AND LAND RIGHTS 5G $8,923
1050000 LAND AND LAND RIGHTS 3500000 LAND AND LAND RIGHTS SG $156
1050000 LAND OWNED IN FEE 3501000 LAND OWNED IN FEE SG $169
1050000 LAND OWNED IN FEE 3601000 LAND OWNED IN FEE OR $746
1050000 LAND OWNED IN FEE 3601000 LAND OWNED IN FEE UT $2,727
1050000 LAND RIGHTS 3992200 LAND RIGHTS SE $953
Overall Result $13,675
SG
SE
UT
OR
Total:
9,248,330
953,014
2,726,936
746,268
13,674,549 Ref. 8.10
Rocky Mountain Power
Idaho General Rate Case - December 2009
EITF 04-6 Coal Stripping
PAGE 8.11
Adjustment to Rate Base:
Misc. Regulatory Assets
TOTAL
ACCOUNT ~ COMPANY FACTOR
IDAHO
FACTOR % ALLOCATED REF#
182M 3 1,169,114 SE 6.358%74,327 8.11.1
Description of Adjustment:
This adjustment aligns the costs of coal stripping and the benefis to customers of coal-fired generation. In this case,
stripping costs are expensed based on the "extracted" coal delivered. Consistent with the Company's application in Case
No. PAC-E-09-08, deferred stripping costs are included as a regulatory asset, serving much like a fuel inventory account
and wil be expensed as the coal is extracted from the mine and delivered to the Company for use at its plants. This
adjustment incorporates the regulatory asset into results. The related reduction to fuel expense is accounted for in the net
power costs.
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Rocky Mountain Power
RESULTS OF OPERATIONS
Page 9.1
USER SPECIFIC INFORMATION
STATE:
PERIOD:
IDAHO
DECEMBER 2009
FILE:
PREPARED BY:
DATE:
TIME:
JAM Dec 2009 ID GRC
Revenue Requirement Department
5/20/2010
2:03:48 PM
TYPE OF RATE BASE:
ALLOCATION METHOD:
Year-End
ROLLED.IN
FERC JURISDICTION:Separate Jurisdiction
80R 12 CP:12 Coincidental Peaks
DEMAND %
ENERGY %
75% Demand
25% Energy
TAX INFORMATION
TAX RATE ASSUMPTIONS:
FEDERAL RATE
STATE EFFECTIVE RATE
TAX GROSS UP FACTOR
FEDERAUSTATE COMBINED RATE
TAX RATE
35.00%
4.54%
1.615
37.951%
CAPITAL STRUCTURE INFORMATION
CAPITAL
STRUCTURE
EMBEDDED
COST
WEIGHTED
COST
DEBT
PREFERRED
COMMON
47.60%
0.30%
52.10%
100.00%
5.92%
5.41%
10.60%
2.818%
0.016%
5.523%
8.357%
OTHER INFORMATION
The Company's currènt estimated cost of equity is 10.6%. The capital structure is calculated using the five quarter average from
12131/2009 to 12/31/2010.
ROLLED.IN Page 9.2
Year-End
RESULTS OF OPERATIONS SUMMARY
UNADJUSTED RESULTS IDAHO
Description of Account Summary:Ref TOTAL OTHER IDAHO ADJUSTMENTS ADJTOTAL
1 Operating Revenues
2 General Business Revenues 9.3 3,484,413,565 3,297,654,176 186,759,389 15,973,773 202,733.162
3 Interdepartmental 9.3 0 0 0 0 0
4 Special Sales 9.3 643,321,157 608,334,858 34,986,299 10,303,083 45,289.382
5 Other Operating Revenues 9.4 226,031,658 211,768,550 14,263,108 (489,545)13,773,563
6 Total Operating Revenues 9.4 4,353,766,380 4,117,757,584 236,008,796 25,787,310 261,796,106
7
8 Operating Expenses:
9 Steam Prouction 9.5 898,300,862 843,521,228 54,779,635 5,829,883 60,609,518
10 Nuclear Production 9.6 0 0 0 0 0
11 Hydro Production 9.7 37,924,259 35,835,202 2,089,057 44,873 2,133,930
12 Other Power Supply 9.9 1,023,694,683 960,746,228 62,948,455 13,137,839 76,086,294
13 Transmission 9.10 172,874,522 163,342,030 9,532,492 1,055,990 10,588,482
14 Distribution 9.12 215,468,741 204,320,401 11,148,340 286,225 11,434,564
15 Customer Accounting 9.12 93,785,007 89,279,506 4,505,501 138,335 4,643,836
16 Customer Service & Infor 9.13 71,462,744 64,626,109 6,836,635 (4,989,177)1,847,458
17 Sales 9.13 0 0 0 0 0
18 Administrative & General 9.14.162,619,511 153,143,351 9,476,160 2,022,069 11,498,229
19
20 Total 0 & M Expenses 9.14 2,676,130,329 2,514,814,055 161,316,274 17,526,037 178.842.311
21
22 Depreciation 9.16 464,027,603 439,648,393 24.379.210 3,105.335 27,464,545
23 Amortization 9.17 43,698,570 41,446,814 2,251,756 (150,962)2,100,794
24 Taxes Other Than Income 9.17 123,877,487 118,554.217 5,323,269 414,144 5,737,413
25 Income Taxes. Federal 9.20 (169.394.084)(156.582.335)(12.811,749)(3,558,448)(16,370,196)
26 Income Taxes - State 9.20 (21,767,423)(20,090.190)(1,677,233)(38,087)(1,715,320)
27 Income Taxes. Def Net 9.19 482.616,183 458,790.109 23,826,074 1.679.532 25,505.607
28 Investment Tax Credit Adj.9.17 (1,874.204)(1.672,710)(201,494)0 (201,494)
29 Misc Revenue & Expense 9.4 (5.975,707)(5,678,965)(296,742)17,298 (279,445)
30
31 Total Operating Expenses 9.20 3,591,338.753 3,389,229,388 202,109.365 18,994,850 221,104,215
32
33 Operating Revenue for Return 762,427.627 728,528,196 33,899,431 6,792,460 40,691,891
34
35 Rate Base:
36 Electrc Plant in Service 9.30 19,556,037,605 18.501.147,212 1,054,890,394 114,278,528 1.169,168,922
37 Plant Held for Future Use 9.31 13.674,549 13,104,516 570,032 (570,032)0
38 Misc Deferred Debits 9.33 140,117,584 136.496.623 3.620,962 553,302 4,174,263
39 Elec Plant Acq AdJ 9.31 60,866,907 57,514,055 3,352,852 0 3.352.852
40 Nuclear Fuel 9.31 0 0 0 0 0
41 Prepayments 9.32 46,150,453 43,579,532 2,570,921 0 2,570,921
42 Fuel Stock 9.32 167,792,599 157,125,148 10,667,451 1,504,805 12,172,256
43 Matenal & Supplies 9.32 177,874.022 167,911,805 9,962.217 0 9,962,217
44 Working Capital 9.33 55,832,695 52,903,521 2,929,174 140,695 3.069,870
45 Weatherization Loans 9.31 37,358,188 33,854,548 3,503,640 0 3.503.640
46 Miscellaneous Rate Base 9.34 1,809,172 1,685,894 123,279 0 123.279
47
48 Total Electric Plant 20,257,513,773 19,165,322,851 1.092,190.922 115,907,298 1,208,098,220
49
50 Rate Base Deductions:
51 Accum Prov For Depr 9.38 (6,626,518,392)(6,257,327,216)(369,191,176)(2.603,977)(371,795,153)
52 Accum Prov For Amort 9.39 (427,140,689)(405,554,960)(21,585,729)(25,402)(21,611,131)
53 Accum Def Income Taxes 9.35 (2,332,318,663)(2,191,772,364)(140,546.299)(41,692)(140,587,991)
54 Unamortized ITC 9.35 (7,294,222)(7,250,054)(44.168)(166,745)(210.914)
55 Customer Adv for Const 9.34 (20,944,658)(20.258,001)(686.658)(261,039)(947,697)
56 Customer Service Deposits 9.34 0 0 0 0 0
57 Misc. Rate Base Deductions 9.34 (57,365,419)(54,678,237)(2,687,183)(2.506,243)(5,193,25)
58
59 Total Rate Base Deductions (9,471.582.043)(8,936,840,831 )(534,741,212)(5.605,098)(540.348,310)
60
61 Total Rate Base 10,785,931,730 10,228,482,020 557,449,710 110,302,200 667.751.910
62
63 Return on Rate Base 7.069%6.081%6.094%
64
65 Return on Equity 8.128%6.232%6.257%
66 Net Power Costs 1,042,847.44 67,217,503 69,253,752
67 100 Basis Points in Equity
68 Revenue Requirement Impact 90,565,044 4,680.677 5,606,839
69 Rate Base Decrease (740,405,216)(43,990,319)(52,593,487)
ROLLED.IN Page 9.3
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
AceT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
70 Sales to Ultimate Customers
71 44 Residential Sales
72 0 S 1,346,519,773 1,287,272,744 59,247,029 386,357 59,633,386
73
74 B1 1,346,519,773 1.287,272,744 59.247.029 386,357 59.633,386
75
76 442 Commercial & Industrial Sales
77 0 S 2.097,948.247 1,970,908,587 127,039,660 15,459,595 142,499,255
78 P SE
79 PT SG
80
81
82 B1 2.097,948,247 1,970,908.587 127,039,660 15,459,595 142.499.255
83
84 444 Public Street & Highway Lighting
85 0 S 20,913,398 20,440,698 472,700 127,821 600,521
86 0 SO
87 B1 20,913,398 20,440,698 472,700 127,821 600,521
88
89 445 Other Sales to Public Authority
90 0 S 19,032,148 19.032,148
91
92 B1 19.032,148 19.032,148
93
94 448 Interdepartmental
95 DPW S
96 GP SO
97 B1
98
99 Total Sales to Ultimate Customers B1 3,48,413,565 3,297,654,176 186,759,389 15,973,773 202,733,162
100
101
102
103 447 Sales for Resale-Non NPC
104 WSF S 8,352,641 8,352.641
105 8,352,641 8.352,641
106
107 447NPC Sales for Resale.NPC
108 WSF SG 633.900.033 598,981,663 34.918.370 10,371,012 45,289,382
109 WSF SE 1.068,83 1,000,554 67.929 (67.929)
110 WSF SG
111 634.968,516 599,982,217 34,986,299 10.303,083 45.289.382
112
113 Total Sales for Resale B1 643,321,157 608,334.858 34,986.299 10.303,083 45.289,382
114
115 449 Provision for Rate Refund
116 WSF S
117 WSF SG
118
119
120 B1
121
122 Total Sales from Electricity B1 4,127,734,722 3,905,989,034 221,745,688 26,276,855 248,022,543
123 450 Forfeited Discounts & Interest
124 CUST S 7,318,368 6,907,026 411.342 411,342
125 CUST SO
126 B1 7,318.368 6.907,026 411,342 411,342
127
128 451 Mise Electric Revenue
129 CUST S 6,902,761 6.732,681 170.080 170,00
130 GP SG
131 GP SO 6,131 5.801 331 331
132 B1 6,908,893 6.738,482 170,411 170,411
133
134 453 Water Sales
135 P SG 12,155 11,485 670 670
136 B1 12,155 11,485 670 670
137
138 454 Rent of Electric Propert
139 DPW S 10,421,181 10,119,677 301.504 301.504
140 T SG 5.304.571 5,012.368 292,202 292,202
141 T SG 4.886 4,617 269 269
142 GP SO 3,428,294 3.243.365 184.929 184,929
143 B1 19.158.931 18.380,027 778,904 778.904
144
145
ROL.L.ED-IN Page 9.4
Year-End
FERC BUS UNADJUSTED RESUL. TS IDAHO
ACCT DE SCRIP FUNC FACTOR Ref TOTAL.OTHER IDAHO ADJUSTMENT ADJ TOTAL.
146
147 456 Other Electric Revenue
148 DMSC S 50,609,068 45,598,459 5,010,609 (5,010,486)123
149 CUST CN
150 OTHSE SE 8,005,386 7,496,442 508,944 508.944
151 OTHSO SO 173,123 163,784 9.339 9.339
152 OTHSGR SG 133,845,735 126,72,845 7,372,890 4,520,941 11,893.830
153
154
155 B1 192,633,312 179,731,530 12,901,781 (489,545)12,412,236
156
157 Total Other Electric Revenues B1 226,031,658 211,768,550 14,263,108 (489,545)13,773,563
158
159 Total Electric Operaing Revenues B1 4,353,766,380 4,117,757,584 236,008,796 25,787,310 261,796,106
160
161 Summary of Revenues by Factor
162 S 3,568,017,584 3,375,364,659 192,652.925 10,963.287 203,616.212
163 CN
164 SE 9,073.869 8,96,996 576,873 (67,929)508.944
165 SO 3,607,548 3,12,950 194,598 194,598
166 SG 773,067.379 730,482,978 42,584,400 14,891,952 57,476,353
167 DGP
168
169 Total Electric Operating Revenues 4,353,766,380 4,117,757,584 236.08,796 25,787,310 261,796,106
170 Miscellaneous Revenues
171 41160 Gain on Sale of Utilty Plant . C~
172 DPW S
173 T SG
174 G SO
175 T SG
176 P SG
177 61
178
179 41170 Loss on Sale of Utilty Plant
180 DPW S
181 T SG
182 61
183
184 4118 Gain from Emission Allowances
185 P S
186 P SE (3,790,891)(3,549,884)(241.07)17,298 (223,709)
187 61 (3,790,891)(3,549,884)(241,007)17,298 (223,709)
188
189 41181 Gain frm Disposition of NOX Credits
190 P SE
191 61
192
193 4194 Impact Housing Interest Income
194 P SG
195 61
196
197 421 (Gain) I Loss on Sale of Utilty Plant
198 DPW S (1,173,272)(1,173,272)
199 T SG (145,556)(137,538)(8,018)(8,018)
200 T SG (68,192)(64,436)(3,756)(3,756)
201 PTD CN
202 PTO SO 12,862 12,168 694 694
203 P SG (810,657)(766,002)(44,655)(44.655)
204 61 (2.184,816)(2,129,080)(55,736)(55.736)
205
206 Total Miscellaneous Revenues (5,975,707)(5,678,965)(296,742)17,298 (279.445)
207 Miscellaneous Expenses
208 4311 Interest on Customer Deposits
209 CUST S
210 61
211 Total Miscellaneous Expenses
212
213 Net Mise Revenue and Expense B1 (5,975,707)(5,678,965)(296,742)17,298 (279,445)
214
ROLLED.IN Page 9.5
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DE SCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
215 500 Operation Supervision & Engineering
216 P SNPPS 20,160,039 19,049,523 1,110,515 37,227 1,147,743
217 P SNPPS 1,216,352 1,149.349 67,003 67,003
218 82 21.376,391 20,198.873 1.177,518 37.227 1.214,745
219
220 501 Fuel Related-Non NPC
221 P SE 11,157,930 10,448,562 709,368 1.067 710,434
222 P SE
223 P SE
224 P SE
225 P SE 3.213,384 3.009.093 204,292 204.292
226 82 14.371,314 13.457,654 913,659 1.067 914.726
227
228 501NPC Fuel Related-NPC
229 P SE 552,903.370 517,752,418 35,150,952 5,374,520 40,525,472
230 P SE
231 P SE
232 P SE
233 P SE 52.991,371 49.622.433 3,368.938 3,368,938
234 82 605.894.741 567,374.851 38,519,889 5,374,520 43.894,409
235
236 Total Fuel Related 620,266,055 580.832,506 39,433,549 5,375,586 44.809,135
237
238 502 Steam Expenses
239 P SNPPS 30,407,397 28.732,406 1.674,991 41,453 1.716.444
240 P SNPPS 5,101.692 4,820.666 281,027 281.027
241 82 35,509,090 33,553,072 1.956,017 41,453 1,997,470
242
243 503 Steam From Other Sources-Non-NPC
244 P SE 147 147
245 82 147 147
246
247 503NPC Steam From Other Sources-NPC
246 P SE 3,597,576 3.368,859 228,717 (14.218)214,498
249 82 3.597,576 3.368.859 228.717 (14.218)214,498
250
251 505 Electric Expenses
252 P SNPPS 2,754.507 2,602,775 151,732 3,675 155,407
253 P SNPPS 1,150,021 1,086,672 63,349 63,349
254 82 3,904,528 3,689,447 215,081 3.675 218.756
255
256 506 Misc. Steam Expense
257 P SNPPS 42,056,734 39,740,040 2,316,694 91,485 2,408,179
258 P SE
259 P SNPPS 1,502,518 1,419,752 82,766 82,766
260 82 43,559,253 41,159,792 2,399,461 91,485 2,490,945
261
262 507 Rents
263 P SNPPS 448,653 423,939 24,714 24,714
264 P SNPPS 1,762 1,665 97 97
265 82 450,415 425.604 24,811 24.811
266
267 510 Maint Supervision & Engineering
268 P SNPPS 4.057,736 3.834,216 223,520 106,827 330.348
269 P SNPPS 1.912,378 1,807,035 105,343 105,343
270 82 5,970,114 5,641,250 328,864 106,827 435,691
271
272
273
274 511 Maintenance of Structures
275 P SNPPS 21,886,763 20.681,131 1,205,632 14,386 1,220,018
276 P SNPPS 938,302 886,616 51,686 51,686
277 82 22.825.065 21.567.747 1.257,318 14,386 1,271,704
278
279 512 Maintenance of 80iler Plant
280 P SNPPS 91,029,755 86,015,382 5,014,372 141,429 5,155,801
281 P SNPPS 3,403,827 3,216.327 187.500 187.500
282 82 94,433.581 89,231,709 5,201,872 141,429 5.343,300
283
284 513 Maintenance of Electric Plant
285 P SNPPS 33,316,896 31,481,635 1,835,260 25,634 1,860,894
286 P SNPPS 410,626 388,007 22.619 22,619
287 82 33,727.522 31.869,642 1,857.880 25.634 1,883.514
288
289 514 Maintenance of Misc. Steam Plant
290 P SNPPS 9.660,457 9,128,311 532,146 6,253 538,400
291 P SNPPS 3.020,817 2.854,415 166,402 166,402
292 82 12,681,274 11,982.726 698.548 6,253 704.801
293
294 Total Steam Power Generation 82 898,300,862 843,521,228 54,779,635 5,829,883 60,609,518
ROLLED-IN Page 9.6
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
295 517 Operation Super & Engineering
296 P SNPPN
297 82
298
299 518 Nuclear Fuel Expense
300 P SE
301
302 82
303
304 519 Coolants and Water
305 P SNPPN
306 B2
307
308 520 Steam Expenses
309 P SNPPN
310 82
311
312
313
314 523 Electrip Expenses
315 P SNPPN
316 62
317
318 524 Misc. Nuclear Expenses
319 P SNPPN
320 62
321
322 528 Maintenance Super & Engineering
323 P SNPPN
324 62
325
326 529 Maintenance of Structures
327 P SNPPN
328 82
329
330 530 Maintenance of Reactor Plant
331 P SNPPN
332 62
333
334 531 Maintenance of Electric Plant
335 P SNPPN
336 62
337
338 532 Maintenance of Mise Nuclear
339 P SNPPN
340 62
341
342 Total Nuclear Power Generation 82
343
344 535 Operation Super & Engineering
345 p DGP
346 P SNPPH 8,095,683 7,649,732 445.951 20,742 466,692
347 P SNPPH 1,289.537 1.218,502 71.034 71,034
348
349 62 9.385,219 8,868.235 516.985 20.742 537,726
350
351 536 Water For Power
352 P DGP
353 P SNPPH 285.794 270.051 15.743 188 15,931
354 P SNPPH 4,415 4.172 243 243
355
356 82 290,209 274,223 15,986 188 16,174
357
ROLLED-IN Page 9.7
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR -Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
358 537 Hydraulic Expenses
359 P DGP
360 P SNPPH 3.168,766 2,994,214 174,551 1,444 175,996
361 P SNPPH 349,844 330,573 19,271 19.271
362
363 62 3,518,610 3,324,787 193,823 1,444 195,267
364
365 538 Electric Expenses
366 P DGP
367 P SNPPH
368 P SNPPH
369
370 62
371
372 539 Misc. Hydro Expenses
373 P DGP
374 P SNPPH 11,894,606 11,239,392 655,214 17,690 672,904
375 P SNPPH 5,705,129 5,390,862 314,267 314,267
376
377
378 62 17,599,735 16,630,254 969,481 17,690 987,171
379
380 540 Rents (Hydro Generation)
381 P DGP
382 P SNPPH 180,404 170,466 9,938 (33)9,904
383 P SNPPH 3,040 2,873 167 167
384
385 62 183,444 173,339 10,105 (33)10,072
386
387 541 Maint Supervision & Engineering
388 P DGP
389 P SNPPH 84,358 79,711 4,647 2 4,649
390 P SNPPH
391
392 62 84,358 79,711 4,647 2 4,649
393
394 542 Maintenance of Structures
395 P DGP
396 P SNPPH 1,092,399 1,032,224 60,175 802 60,977
397 P SNPPH 114,713 108,394 6,319 6,319
398
399 62 1,207,112 1,140,619 66,494 802 67,296
400
401
402
403
404 543 Maintenance of Dams & Waterways
405 P DGP
406 P SNPPH 1,189,774 1,124,235 65,539 912 66,50
407 P SNPPH 410,765 388,138 22,627 22,627
408
409 62 1,600,539 1,512,374 88,166 912 89,077
410
411 544 Maintenance of Electric Plant
412 P DGP
413 P SNPPH 1,188,647 1,123,171 65,477 1,671 67,148
414 P SNPPH 327,068 309,052 18,017 18,017
415
416 62 1,515,716 1,432,223 83,93 1,671 85,164
417
418 545 Maintenance of Misc. Hydro Plant
419 P DGP
420 P SNPPH 1,925,303 1,819,248 106,055 1,455 107,510
421 P SNPPH 614,013 580,190 33,823 33,823
422
423 62 2,539,316 2,399,438 139,878 1,455 141,333
424
425 Total Hydraulic Power Generation B2 37,924,259 35,835,202 2,089,057 44,873 2,133,930
ROLLED-IN Page 9.8
Year-End
FERC 6US UNADJUSTED RESULTS IDAHO
ACCT OESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT AOJTOTAL
426
427 546 Operation Super & Engineering
428 P SNPPO 316.964 299.504 17,460 63 17.523
429 P SNPPO
430 82 316.964 299.504 17.460 63 17.523
431
432 547 Fuel-Non-NPC
433 P SE
434 P SE
435 82
436
437 547NPC Fuel-NPC
438 P SE 426.253.895 399.154.711 27.099.184 (606.399)26.492.785
439 P SË 35.489.120 33,232.892 2,256.229 2.256,229
440 82 461,743.015 432.387.603 29,355.412 (606,399)28,749,013
441
442 548 Generation Expense
443 P SNPPO 14,113,019 13.335,604 777,415 12.516 789.931
444 P SNPPO 1.626,465 1.536,872 89.594 89.594
445 62 15.739,485 14.872,475 867.009 12.516 879.525
446
447 549 Miscellaneous Other
448 P SNPPO 18.635.853 17,609.298 1.026.556 330.179 1.356,734
449 P SNPPO
450 82 18.635,853 17,609.298 1.026.556 330.179 1.356,734
451
452
453
454
455 550 Rents
456 P SNPPO 1.861,263 1.758.736 102,528 102.528
457 P SNPPO
458 62 1.861.263 1,758.736 102,528 102,528
459
460 551 Maint Supervision & Engineering
461 P SNPPO
462 82
463
464 552 Maintenance of Structures
465 P SNPPO 1,350.705 1.276.301 74,404 613 75.016
466 P SNPPO 193.326 182.677 10.649 10,649
467 82 1.544.031 1,458,978 85,053 613 85,666
.468
469 553 Maint of Generation & Electric Plant
470 P SNPPO 12.141.793 11,472.963 668.830 (209,868)458,962
471 P SNPPO 2,845.046 2.688.327 156.719 156,719
472 82 14.986.840 14.161.290 825,550 (209,868)615.681
473
474 554 Maintenance of Misc. Other
475 P SNPPO 1,200,375 1.134.253 66,123 283 66.405
476 P SNPPO 121.530 114,836 6.694 6,694
477 82 1.321.906 1.249,089 72.817 283 73,100
478
479 Total Other Power Generation 62 516,149,358 483,796,973 32,352,385 (472.614)31,879,770
480
481
482 555 Purchased Power-Non NPC
483 DMSC S (33.207,768)(33.362,478)154.710 (154,710)
484 (33.207,768)(33.362,478)154,710 (154,710)
485
486 555NPC Purchased Power-NPC
487 P SG 409.727.945 387.158.090 22,569.855 7,167.862 29.737.717
488 P SE 79.691,472 74.625.070 5.066,403 (584.201)4.482.201
489 Seasonal Co P SG
490 DGP
491 489,419,417 461.783,159 27.636.258 6,583.660 34,219,918
492
493 Total Purchased Power 82 456.211.649 428.420.681 27.790.968 6,428,950 34.219,918
494
495 556 System Control & Load Dispatch
496 P SG 1.514,461 1,431.037 83,424 1,524 84.948
497
498 82 1.514,461 1,431,037 83,424 1,524 84.948
499
500
ROLLED-IN Page 9.9
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
501
502 557 Other Expenses
503 P S (183,792)(150,819)(32,973)7,585,721 7,552,748
504 P SG 48,880,583 46,187,997 2,692,586 (405,742)2,286,844
505 P SGCT 1,122,425 1,060,360 62,065 62,065
506 P SE
507 P SG
508 P TROJP
509
510 62 49,819,215 47,097,537 2,721,678 7,179,979 9,901,657
511
512 Embedded Cost Differentials
513 Company Owned Hyd P DGP
514 Company Owned Hyd P SG
515 Mid-C Contract P MC
516 Mid-C Coritraèt P SG
517 Existing QF Contracts P S
518 Existing QF Contracts P SG
519
520
521
522 Total Other Power Supply B2 507,545,325 476,949,255 30,596,070 13,610,454 44,206,524
523
524 Total Production Expense B2 1,959,919,804 1,840,102,658 119,817,146 19,012,596 138,829,742
525
526
527 Summary of Production Expense by Factor
528 S (33,391,560)(33,513,297)121,737 7,431,011 7,552,748
529 SG 460,122,988 434,777,123 25,345,865 6,763,644 32,109,509
530 SE 1,165,298,118 1,091,214,038 74,084,080 4,170,914 78,254,995
531 SNPPH 37,924,259 35,835,202 2,089,057 44,873 2,133,930
532 TROJP
533 SGCT 1,122,425 1,060,360 62.065 62.065
534 DGP
535 DEU
536 DEP
537 SNPPS 274,437,232 259,319.863 15,117,369 468.369 15.85,738
538 SNPPO 54,406,342 51,409,370 2,996,972 133,785 3,130,757
539 DGU
540 MC
541 SSGCT
542 SSECT
543 SSGC
544 SSGCH
545 SSECH
546 Total Production Expense by Factor 62 1,959,919,804 1,840,102;658 119,81,146 19,012,596 138,829,742
547 560 Operation Supervision & Engineering
548 T SNPT 6,088,583 5,753,193 335.389 10,916 346,305
549
550 62 6,088,583 5,753,193 335,389 10,916 346,305
551
552 561 Load Dispatching
553 T SNPT 9,323,709 8,810,112 513,596 18,577 532,174
554
555 62 9,323,709 8,810,112 513.596 18,577 532,174
556 562 Station Expense
557 T SNPT 1,506,78 1,423,494 82.984 2,259 85,243
558
559 62 1,506,478 1,423,494 82,984 2.259 85,243
560
561 563 Overhead Une Expense
562 T SNPT 245,152 231,648 13,504 206 13.710
563
564 62 245,152 231,648 13,504 206 13,710
565
566 564 Underground Une Expense
567 T SNPT
568
569 62
570
ROLLED-IN Page 9.10
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
571 565 Transmission of Electricity by Others
572 T SG
573 T SE
574
575
576 565NPC Transmission of Electricity by Others-NPC
577 T SG 116,018,414 109,627,542 6,390,872 1,068,531 7,459,403
578 T SE 1,142,797 1,070,143 72,654 (66,763)5,891
579 117,161,210 110,697,685 6,463,525 1,001,768 7,465,294
580
581 Total Transmission of Electricity by Other!62 117,161,210 110,697,685 6,463,525 1,001,768 7,465,294
582
583 566 Misc. Transmission Expense
584 T SNPT 2,393,112 2,261,287 131,825 (4,285)127,540
585
586 82 2,393,112 2,261,287 131,825 (4,285)127,540
587
588 567 Rents - Transmission
589 T SNPT 1,656,975 1,565,700 91,274 509 91,784
590
591 62 1,656,975 1,565,700 91,274 509 91,784
592
593 568 Maint Supervision & Engineering
594 T SNPT 35,53 33,500 1,953 39 1,992
595
596 62 35,453 33,500 1,953 39 1,992
597
598 569 Maintenance of Structures
599 T SNPT 4,060,560 3,836,884 223,676 5,435 229,110
600
601 62 4,060,560 3,836,884 223,676 5,435 229,110
602
603 570 Maintenance of Station Equipment
604 T SNPT 10,549,624 9,968,498 581,126 16,773 597,899
605
606 62 10,549,624 9,968,498 581,126 16,773 597,899
607
608 571 Maintenance of Overhead Lines
609 T SNPT 19,620,066 18,539,295 1,080,771 3,679 1,084,449
610
611 82 19,620,066 18,539,295 1,080;771 3,679 1,084,449
612
613 572 Maintenance of Underground Lines
614 T SNPT 51.599 48,757 2,842 84 2,926
615
616 82 51,599 48,757 2,82 84 2.926
617
618 573 Maint of Misc. Transmission Plant
619 T SNPT 182,001 171,976 10,026 30 10.056
620
621 82 182,001 171,976 10,026 30 10,056
622
623 Total Transmission Expense B2 172,874,522 163,342,030 9.532,492 1.055.99 10,588,482
624
625 Summary of Transmission Expense by Factor
626 SE 1.142,797 1,070,143 72,654 (66,763)5,891
627 SG 116,018,414 109,627,542 6,390.872 1,068.531 7,459,403
628 SNPT 55,713,312 52,644.345 3,068,967 54.222 3,123,188
629 Total Transmission Expense by Factor 172,874,522 163.342,030 9,532,492 1,055.990 10,588,4S2
630 580 Operation Supervision & Engineering
631 DPW S 1,012,443 930,166 82,277 82,277
632 DPW SNPD 18.641,946 17,781,836 860,111 34,479 894,590
633 82 19,654,389 18,712,001 942,388 34,479 976.867
634
635 581 Load Dispatching
636 DPW S
637 DPW SNPD 13,439.746 12.819,657 620,089 25.714 645.803
638 82 13,439,746 12,819,657 620.089 25,714 645.803
639
640 582 Station Expense
641 DPW S 3,849.839 3,641.292 208,547 4,008 212,555
642 DPW SNPD 29,848 28,471 1,377 46 1,423
643 82 3.879,.687 3.669,763 209,924 4,053 213,977
644
ROLLED.IN Page 9.11
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
645 583 Overhead Line Expenses
646 DPW S 5,777.056 5,75.120 301.936 11.118 313,054
647 DPW SNPD 17.767 16.94 820 29 849
648 62 5.794,824 5,92.068 302.756 11,147 313,903
649
650 584 Underground Line Expense
651 DPW S 305 305
652 DPW SNPD
653 62 305 305
654
655 585 Street Lighting & Signal Systems
656 DPW S
657 DPW SNPD 207,152 197,594 9.558 402 9,960
658 62 207,152 197,594 9.558 402 9,960
659
660 586 Meter Expenses
661 DPW S 5,630,733 5.374.972 255.761 9,193 264.954
662 DPW SNPD 1.082,827 1.032.867 49.960 1,765 51,725
663 62 6.713.560 6.407,839 305.721 10.958 316,679
664
665 587 Customer Installation Expenses
666 DPW S 12,458,762 12,009,846 44.917 16,305 465,222
667 DPW SNPD 496 473 23 1 24
668 62 12,459.259 12,010.319 44.940 16.306 465,246
669
670 588 Misc. Distributin Expenses
671 DPW S 1,903,892 1.827.783 76,109 (2.139)73970
672 DPW SNPD 5.537.508 5.282.016 255,492 (46)255.44
673 62 7.441,400 7.109,799 331.601 (2,186)329,416
674
675 589 Rents
676 DPW S 3,082,013 3,056.279 25.733 33 25.767
677 DPW SNPD 114.242 108,971 5.271 0 5,271
678 62 3.196,255 3.165,250 31,004 33 31,038
679
680 590 Maint Supervision & Engineering
681 DPW S 1.168,290 1.079.917 88,373 3,126 91,498
682 DPW SNPD 6,367.680 6.073,885 293,795 10,425 304,219
683 82 7.535.970 7,153,802 382,168 13.550 395,718
684
685 591 Maintenance of Structures
686 DPW S 1,855,991 1,709.849 146.142 146.142
687 DPW SNPD 159,999 152,617 7.382 7.382
688 62 2.015.990 1,862,466 153,524 153,524
689
690 592 Maintenaiie of Station Equipment
691 DPW S 10,926.178 10.135.064 791,114 25.517 816,631
692 DPW SNPD 1,874.179 1.787,708 86,72 3,387 89,858
693 82 12,800,357 11.922,771 877,586 28,904 906,490
694 593 Maintenance of Overhead Lines
695 DPW S 82.112.317 77.011.054 5,101.264 100,942 5.202.206
696 DPW SNPD 1,224.337 1.167,848 56.489 951 57,44
697 82 83.336,655 78,178,902 5,157.753 101.893 5,259,646
698
699 594 Maintenance of Underground Lines
700 DPW S 22,479.205 21.746,414 732,791 18.984 751.774
701 DPW SNPD 7.391 7,050 341 11 352
702 62 22,486,595 21,753.464 733,132 18.995 752,126
703
704 595 Maintenance of Line Transformers
705 DPW S 24.717 24,717
706 DPW SNPD 1,081,164 1,031,280 49,883 1,698 51,581
707 82 1,105,880 1,055.997 49.883 1,698 51,581
708
709 596 Maint of Street Lighting & Signal Sys.
710 DPW S 4.217,687 4,084,975 132,712 4,670 137.382
711 DPW SNPD
712 82 4.217.687 4.084,975 132,712 4.670 137,382
713
ROLLED.IN Page 9.12
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DE SCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
714 597 Maintenance of Meters
716 DPW S 4.536,131 4.239,464 296.667 10,873 307,541
716 DPW SNPD 1.100.892 1.050,098 50.793 1,662 52,455
717 82 5,637,023 5,289,562 347,461 12,535 359,996
718
719 598 Maint of Misc. Distribution Plant
720 DPW S 2,967.838 2,882,374 85,465 128 85,592
721 DPW SNPD 578,169 551,493 26,676 2,944 29.620
722 82 3,546.007 3,433,867 112.141 3,072 115.212
723
724 Total Distnbution Expense B2 215,468,741 204.320,401 11,148,340 286,225 11.434,564
725
726
727 Summary of Distribution Expense by Factor
728 S 164,003.397 155,229.589 8.773,808 202,757 8,976,565
729 SNPD 51,465.34 49.090,812 2.374.532 83,467 2,457.999
730
731 Total Distribution Expense by Factor 215,468,741 204.320,401 11,146.340 286,225 11,434,564
732
733 901 Supervision
734 CUST S 102.805 87,017 16.788 56 15.844
735 CUST CN 2.451,290 2.356.068 95.222 4,004 99.226
736 82 2.554,096 2.443,085 111.010 4.060 115,070
737
738 902 Meter Reading Expense
739 CUST S 20.750.177 19.136.393 1.613.784 62,513 1.676.297
740 CUST CN 1.770,041 1.701,283 68.758 2,274 71,033
741 82 22.520.219 20.837.676 1.682.543 64,787 1.747,330
742
743 903 Customer Receipts & Collections
744 CUST S 7.352.864 7,023,206 329.657 10.345 340.02
745 CUST CN 48,927.462 47.026.843 1.900.620 58,841 1,959,461
746 82 56,280.326 54,050,049 2,230.277 69.186 2,299,463
747
748 904 Uncollectible Accounts
749 CUST S 12.149,005 11.677,783 471,222 471.222
750 P SG
751 CUST CN 26.790 25,749 1,041 1,041
752 82 12.175,795 11,703,532 472.263 472.263
753
754 905 Misc. Customer Accounts Expense
755 CUST S 12.390 12,390
756 CUST CN 242,182 232,774 9.408 302 9,710
757 82 254.572 245,164 9.408 302 9,710
758
759 Total Customer Accounts Expense B2 93,785,007 89.279.506 4.505,501 138,335 4.643,836
760
761 Summary of Customer Accts Exp by Factor
762 S 40.367.241 37.936,789 2.430.452 72,914 2,503.366
763 CN 53,417.766 51.342.717 2.075.049 65.421 2,140,470
764 SG
765 Total Customer Accounts Expense by Factor 93.785.007 89,279,506 4.505.501 138.335 4.643.836
766
767 907 Supervision
768 CUST S
769 CUST CN 286,417 275,290 11.126 396 11,523
770 82 286,417 275.290 11.126 396 11,523
771
772 908 Customer Assistance
773 CUST S 63,240.907 56.710.070 6,530,837 (4,992,585)1,536.252
774 CUST CN 2.861.099 2,749.957 111.141 4,430 115,571
775
776
777 82 66.102,006 59,460.027 6.641,979 (4.988.155)1.653,823
778
ROLLED.IN Page 9,13
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DE SCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
779 909 Informational & Instructional Adv
780 CUST S 349,724 349,724
781 CUST CN 4,574,542 4,396,841 177,701 (1,426)176,275
782 62 4,924,267 4,746,566 177,701 (1,426)176,275
783
784 910 Misc. Customer Service
785 CUST S
786 CUST CN 150,055 144,226 5,829 8 5,837
787
788 62 150,055 144,226 5.829 8 5,837
789
790 Total Customer Service Expense 62 71,462,744 64,626,109 6,836,635 (4,989,177)1,847,458
791
792
793 Summary of Customer Service Exp by Factor
794 S 63,590.631 57.059,794 6,530,837 (4,992,585)1,538,252
795 CN 7,872,112 7,566,315 305,797 3,408 309,206
796
797 Total Customer Service Expense by Factor 62 71,462,744 64,626.109 6.836.635 (4,989,177 1.47,458
798
799
800 911 Supervision
801 eUST S
802 CUST CN
803 62
804
805 912 Demonstration & Sellng Expense
806 CUST S
807 eUST eN
808 62
809
810 913 Advertising Expense
811 CUST S
812 CUST CN
813 62
814
815 916 . Misc. Sales Expense
816 CUST S
817 CUST CN
818 62
819
820 Total Sales Expense 62
821
822
823 Total Sales Expense by Factor
824 S
825 CN
626 Total Sales Expense by Factor
827
828 Total Customer Service Exp Including Sales B2 71,462,744 64,626,109 6,836,635 (4,989,177)1,847,458
829 920 Administrative & General Salaries
830 PTO S (4,135,538)(5,140,020)1,004,462 (1,004,482)
831 CUST CN
832 PTD SO 77,010,359 72,856,271 4,154,087 180,879 4,334,967
833 B2 72.874,820 67,716,251 5,158,569 (823.603)4.334,967
834
835 921 Office Supplies & expenses
836 PTD S (568,262)(568,12)150 150
837 CUST CN
838 PTO SO 11,599,349 10,973,658 625,691 (31,329)594,362
839 62 11,031,087 10.405,246 625,841 (31,329)594,512
840
841 922 A&G Expenses Transferred
842 prD S
843 CUST eN
84 PTO SO (25,866,776)(24,471,472)(1,395,304)69,039 (1 ,326,265)
845 62 (25,866.776)(24,471,472)(1,395,304)69,039 (1,326,265)
846
ROLLED-IN Page 9.14
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
847 923 Outside Services
848 prD S 630 630
649 CUST CN
850 PTD SO 11.038.720 10.443.270 595,450 (25.996)569.454
851 B2 11.039.350 10,443.900 595,50 (25.996)569,454
852
853 924 Property Insurance
854 PTD SO 23.970.318 22.677.312 1.293.005 1.293.005
855 B2 23.970,318 22.677,312 1.293.005 1,293,005
856
857 925 Injuries & Damages
858 PTD SO 7,43,336 7.033.313 401,022 113,482 514.505
859 B2 7,434.336 7;033.313 401,022 113.482 514.505
860
861 926 Employee Pensions & Benefits
862 LABOR S
863 CUST CN
864 LABOR SO
865 B2
866
867 927 Franchise Requirements
868 DMSC S
869 DMSC SO
870 B2
871
872 928 Regulatory Commission Expense
873 DMSC S 11.943.931 11.526,639 417.092 4.691 421.783
874 CUST eN
875 DMse SO 2,197.338 2.078,809 118,529 78 118,607
876 FERC SG 2,323.478 2.195,89 127.989 127.989
877 82 16.464,747 15.801.137 663.610 4.769 668.379
878
879 929 Duplicate Charges
880 LABOR 5
881 LABOR SO (3,420.843)(3.236,316)(184.527)(246)(184,77)
882 82 (3,420.843)(3.236,316)(184,527)(246)(184.773)
883
884 930 Mise General Expenses
885 PTD 5 5.290.870 5.282.370 8,00 201.496 209.996
886 eUST CN 4.500 4.325 175 (44)131
887 LA80R SO 14,400.017 13,623.252 776.765 2.504.559 3,281.323
888 82 19.695.387 18,909.947 785.439 2.706.011 3,491;451
889
890 931 Rents
891 PTD S 961.066 961,066
892 PTD SO 5.238,518 4.955,942 282.576 282,576
893 82 6,199.584 5.917,009 282.576 282.576
894
895 '935 Maintenance of General Plant
896 G 5 15.577 15.577
897 eUST CN
898 G SO 23.181.924 21,931,44 1.250,478 9,942 1.260,420
899 B2 23.197.501 21.947,023 1,250,478 9.92 1.260,420
900
901 Totl Administrative & General Expense B2 162,619,511 153,143,351 9,476,160 2,022,069 11,98,229
902
903 Summary of A&G Expense by Factor
904 S 13,508.275 12.078.050 1,430.224 (798.295)631.929
905 SO 146,783.259 138,865,487 7.917,772 2.820.407 10.738.180
906 SG 2.323.478 2,195,489 127,989 127,989
907 CN 4,500 4,325 175 (44)131
908 Total A&G Expense by Factor 162,619,511 153,143.351 9.476.160 2.022.069 11,498.229
909 2,514,ih4,055910Total O&M Expense B2 2,676,130,329 161,316.274 17,526,037 178,842,31
ROLLED-IN Page 9.15
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
911 403SP Steam Depreciation
912 P SG 23,110,000 21,836,987 1,273,014 1,273,014
913 P SG 25,963,107 24,532,930 1,430,177 1,430,177
914 P SG 52,664,788 49,763,750 2,901,039 837,592 3,738,631
915 P SG 7,785,936 7,357,048 428,888 428,888
916 B3 109,523,832 103,490,714 6,033,118 837,592 6,870,710
917
918 403NP Nuclear Depreciation
919 P SG
920 63
921
922 403HP Hydro Depreciation
923 P SG 3,645,429 3,444,621 200,808 200,808
924 P SG 1,016,491 960,498 55,993 5.5,993
925 P SG 7,347,198 6,942,478 404,720 24,509 429,229
926 P SG 3.441,241 3,251,681 189,561 189,561
927 63 15,50,360 14,599,277 851,083 24,509 875.592
928
929 4030P Other Production Depreciation
930 P SG 124,817 117,942 6.876 6,876
931 P SG 94,515,821 89,309,419 5,206,402 1,050,470 6,256,872
932 P SG 2,544,778 2,404,599 140,179 140,179
933 P SG
934 63 97,185,16 91,831,959 5,353,457 1,050,470 6,03,926
935
936 403TP Transmission Depreciation
937 T SG 11,260.768 10,640,469 620.299 620,299
938 T SG 12,574,497 11,881,831 692,666 692.666
939 T SG 39,057,941 36,906,35 2,151,506 1,180,474 3,331,980
940 63 62,893,206 59,428,735 3,464,471 1,180,474 4,644,945
941
942
943
944 403 Distribution Depreciation
945 360 Lane & La.ne Righ" DP\i S 292,392 274,904 17,468 17,488
946 361 strct DPW S 1.016,944 993,937 23,007 23,007
947 362 station Equipmnt DPW S 17,275,368 16,659,953 615,415 615,415
948 363 Slorage 6eile Eq. DPW S 91,113 91,113
949 364 Poles & Towers DPW S 33,365.759 31,345,364 2,020,396 1,199 2,021,595
950 365 OH Condrs DPW S 18,807.119 17,850,287 956.832 956,832
951 366 UGConduit DPW S 7,529,925 7,372.273 157,652 157.652
952 367 UG Conductr DPW S 17,412,373 16,938.733 473,640 473,640
953 368 Una Trans DPW S 26.759,726 25,342,167 1,417,559 1,417,559
954 369 Servce DPW S 11,531.258 11.013,789 517,468 517,468
955 370 Melers DPW S 6,509.338 6,062,663 446.676 44,676
956 371 InslCustPrem DPW S 496,358 488,788 7,570 7,570
957 372 Lease Property DPW S
958 373 Street Lighting DPW S 2.255,605 2,226,651 28,954 28,954
959 63 143,343,279 136,660,621 6,682,658 1,199 6,683,857
960
961 403GP General Depreciation
962 G-SITUS S 12,310,835 11,555,600 755,235 (173)755,062
963 PT SG 502,163 474.501 27.662 27,662
96 PT SG 706.142 667,244 38,898 38,898
965 P SE 26,236 24,568 1.668 1,668
966 eUST eN 1,759,170 1,690,834 68,336 68,336
967 G-SG SG 5.229,908 4,941,819 288,089 2,848 290,938
968 PTD SO 14.946,453 14,140,213 806,241 8,416 814.656
969 G-SG SG 6,010 5,679 331 331
970 G-SG SG 144,595 136,630 7,965 7,965
971 63 35,631,512 33,637,088 1.994,424 11,090 2,005,515
972
973 403GVO General Vehicles
974 G-SG SG
975 63
976
977 403MP Mining Depreciation
978 P SE
979 63
980
ROLLED-lN Page 9.16
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
981 403EP Experimental Plant Depreciation
982 P SG
983 P SG
984 63
985 4031 ARO Depreciation
986 P S
987 63
988
989
990 Total Depreciation Expense B3 464,027,603 439,648,393 24,379,210 3,105,335 27,484,545
991
992 Summary S 155,654,113 148,216,221 7,437,892 1,026 7,438,918
993 DGP
994 DGU
995 SG 291,641,631 275,576.558 16,065,073 3.095.893 19,160.967
996 SO 14,946,453 14,140,213 806.241 8,416 814,656
997 CN 1,759,170 1,690.834 68,336 68,336
998 SE 26.236 24,568 1,668 1,668
999 SSGCH
1000 SSGCT
1001 Total Depreciation Expense 6y Factor 464,027,603 439,64,393 24,379,210 3,105,335 27,464,545
1002
1003 404GP Amort of L T Plant. Capital Lease Gen
1004 I.SITUS S 1,345,062 1,345,062
1005 I-SG SG
1006 PTD SO 929,374 879,242 50,132 50.132
1007 P SG
1008 CUST CN 249.571 239,876 9,695 9,695
1009 P SG
1010 64 2,524,007 2,464.180 59,827 59,827
1011
1012 404SP Amort of L T Plant. Cap Lease Steam
1013 P SG
1014 P SG
1015 64
1016
1017 4041P Amort of L T Plant. Intangible Plant
1018 I.SITUS S 94,304 73,772 20,532 20.532
1019 P SE 14,498 13,577 922 922
1020 I-SG 5G 8,952,161 8,459,032 493,130 31,188 524,318
1021 PTD 50 13.131,339 12,423,009 708,330 9,544 717,873
1022 CUST CN 5,000,879 4,806,617 194,262 194,262
1023 1-5G SG 2,615,413 2,471,343 144,070 144,070
1024 1-5G SG 310,432 293,332 17,100 17.100
1025 P SG
1026 1-5G SG
1027 1-5G SG 54,934 51,908 3.026 3,026
1028 P SG 16,758 15,835 923 923
1029 64 30,190,717 28,608,423 1,582.295 40,732 1,623.026
1030
1031 404MP Amort of L T Plant. Mining Plant
1032 P 5E
1033 64
1034
1035 4040P Amort of L T Plant. Other Plant
1036 P 5G
1037 64
1038
1039
1040 404HP Amortzation of Other Electnc Plant
1041 P SG 6,589 6,226 363 363
1042 P SG 40,392 38,167 2,225 2,225
1043 P SG
1044 B4 4ß,981 44,393 2.588 2,588
1045
104ß Total Amortization of Limited Term Plant 84 32,761,706 31,116,997 1,64,710 40,732 1,685,441
1047
1048
1049 405 Amortzation of Other Electnc Plant
1050 GP S
1051
1052 64
1053
ROLLED.IN Page 9.17
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1054 406 Amortization of Plant Acquisition Adj
1055 P S
1056 P SG
1057 P SG
1058 P SG 5,479,353 5,177,523 301.830 301,830
1059 P SO
1060 B4 5,79.353 5,177523 301.830 301,830
1061 407 Amort of Prop Losses. Unrec Plant. etc
1062 DPW S (36,176)(36,176)
1063 GP SO
1064 P SG 3,479,961 3.288,268 191.694 191,694
1065 P SE
1066 P SG (191.694)(191.694)
1067 P TROJP 2.013.725 1.900,202 113.523 113,523
1068 B4 5,457.511 5,152,294 305.217 (191.694)113.523
1069
1070 Total Amortization Expense B4 43,698,570 41,446.814 2,251,756 (150,962)2.100,794
1071
1072
1073
1074 Summary of Amortization Expense by Factor
1075 S 1,403.190 1,382,68 20,532 20.532
1076 SE 14,498 13,577 922 922
1077 TROJP 2.013.725 1.900.202 113.523 113.523
1078 DGP
1079 DGU
1080 SO 14.060.713 13.302.251 758,462 9,544 768.006
1081 SSGCT
1082 SSGCH
1083 SG.p
1084 CN 5.250,450 5,046,493 203.957 203.957
1085 SG 20.955,993 19.801.633 1.154.360 (160.506)993.855
1086 Total Amortization Expense by Factor 43.698.570 41,446.814 2,251.756 (150.92)2.100.794
1087 408 Taxes Other Than Income
1088 DMSC S 25.320,436 25,320,36
1089 GP GPS 87.317,409 82.607.339 4.710.069 414.144 5,124,214
1090 GP SO 10.522.150 9.954.565 567.585 567,585
1091 P SE 717,492 671.877 45.615 45.615
1092 P SG
1093 DMSC OPRV-ID
1094 GP EXCTAX
1095 GP SG
1096
1097
1098
1099 Total Taxes Other Than Income 85 123,871,487 118,554,217 5,323,269 414,144 5,737,413
1100
1101
1102 41140 Deferred Investment Tax Credit - Fed
1103 PTD DGU (1,874.204)(1,672,710)(201,494)(201.494)
. 1104
1105 B7 (1.874.204)(1.672.710)(201,494)(201,94)
1106
1107 41141 Deferrd Investment Tax Credit -Idaho
1108 PTD DGU
1109
1110 67
1111
1112 Total Deferred ITC 87 (1,874,204)(1,672,710)(201,494)(201,494)
1113
ROLLED-IN Page 9.18
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1114
1115 427 Interest on Long- Term Debt
1116 GP S 178,206 178,206
1117 GP SNP 369,236,117 349,622,675 19,613,44 19,613,443
1118 B6 369,236,117 349,622,675 19,613,43 178,206 19,791,649
1119
1120 428 Amortzation of Debt Disc & Exp
1121 GP SNP 6,571,354 6,222,290 349,064 349,064
1122 B6 6,571,354 6,222,290 349,064 349,064
1123
1124 429 Amortization of Premium on Debt
1125 GP SNP (2,718)(2,574)(144)(144)
1126 B6 (2,718)(2,574)(144)(144)
1127
1128 431 Other Interest Expense
1129 NUTIL OTH
1130 GP SO
1131 GP SNP 10,264,106 9,718,887 545,219 545,219
1132 B6 10.264,106 9,718,887 545,219 545,219
1133
1134 432 AFUDC - Borrowed
1135 GP SNP (35,186,532)(33,317,459)(1,869,072)(1,869,072)
1136 (35,186,532)(33.317,459)(1,869,072)(1.869,072)
1137
1138 Total Elec. Interest Deductions for Tax B6 350,882,327 332,243,819 18,638,508 178,206 18,816,715
1139
1140 Non-Utility Portion of Interest
1141 427 NUTIL NUTIL
1142 428 NUTIL NUTIL
1143 429 NUTIL NUTIL
1144 431 NUTIL NUTIL
1145
1146 Total Non-utility Interest
1147
1148 Total Interest Deductions for Tax B6 350,882,327 332,243,819 18,638.508 178,206 18,816,715
1149
1150
1151 419 Interest & Dividends
1152 GP S
1153 GP SNP (63,955,322 60,558,081 )(3,397,241
1154 Total Operating Deductions for Tax B6 0.55 ,,3 ,4
1155
1156
1157 41010 Deferred income Tax - Federal-DR
1158 GP S 26,529,700 26,102,344 427,356 (347,371)79,985
1159 P TROJD 735,881 694,228 41,653 41,653
1160 P SG 26,126 24,687 1,439 1,439
1161 LABOR SO 37,814,180 35,774,410 2,039,770 (276,027)1.763,743
1162 GP SNP 35,849,593 33,945,299 1,904,294 1,904,294
1163 P SE 23,499,301 22,005,328 1,493,973 (75,58)1,418,425
1164 PT SG 51,291,699 48,466,297 2,825,402 2,926,043 5,751,445
1165 GP GPS 31,266,44 29,579,868 1,686,572 1,686,572
1166 TAXDEPR TAXEPR 615,608,170 584,405,196 31,202,974 31,202,974
1167 CUST BADDEBT 443,332 426,136 17,196 17,196
1168 CUST CN 22,893 22,004 889 889
1169 P IBT 348,313 321,475 26,838 (26,838)(0)
1170 DPW SNPD 67,978 64,842 3.136 3,136
1171 B7 823,503,606 781,832.114 41,671,492 2,200,259 43,871,751
1172
ROLLED-IN Page 9.19
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1173
1174
1175 41110 Deferred Income Tax - Federal-CR
1176 GP 5 (26.854.405)(25.660.209)(1.194,196)322,685 (871.511)
1177 P 5E (17.999.483)(16,855,162)(1,144.321)228,207 (916,114)
1178 P SG (538,368)(508,712)(29.656)(29,656)
1179 GP SNP (31.616,890)(29.937,433)(1,679.457)(1.679,457)
1180 PT 5G (7,932,473)(7,495.513)(436.960)(1,099.084)(1.536,044)
1181 DPW CIAC (20.332,44)(19,394,336)(938.108)(938.108)
1182 LASOR SO (28,202,710)(26.681.401 )(1,521.309)(5.507)(1.526.816)
1183 PT SNPD (1.949.167)(1.859.235)(89.932)(89.932)
1184 CUST BADDEST
1185 P SGCT (356.221)(336.523)(19.698)(19.698)
1186 BOOKDEPR SCHMDEXP (203.344.850)(192.661,462)(10.683.388)(10.683.388)
1187 P TROJD (1.332.481)(1.257.059)(75,422)(75,422)
1188 P 16T (427.931)(394.958)(32.973)32.973 0
1189
1190
1191 67 (340.887,23)(323.042.005)(17,845,418)(520.726)(18.366.144)
1192
1193 Total Deferred Income Taxes B7 482,616,183 458,790,109 23,826,074 1.,679,532 25,505,607
1194 SCHMAF Add"ions - Flow Through
1195 SCHMAF S
1196 SCHMAF SNP
1197 SCHMAF SO
1198 SCHMAF SE
1199 SCHMAF TROJP
1200 SCHMAF SG
1201 B6
1202
1203 SCHMAP Additions - Permanent
1204 P S 20,000 20.000
1205 P SE 90.872 85,095 5.777 5.777
1206 LA60R SNP
1207 SCHMAP-SO SO 12.568.198 11,890.245 677.953 677953
1208 SCHMAP SG
1209 DPW BADDEST
1210 66 12,679,071 11.995.341 683.730 683,730
1211
1212 SCHMAT Additions - Temporary
1213 SCHMAT-SITLS 57.590.033 56.886.057 703,976 (591,588)112,388
1214 P SG
1215 DPW CIAC 53.575.515 51.103,623 2,471,892 2.471.892
1216 SCHMA T -SNP SNP 83.309,767 78,884,438 4,425,329 4,425,329
1217 P TROJD 1.572.028 1,483,047 88.981 88.981
1218 P SGCT 938.633 886.730 51,903 51,903
1219 SCHMAT-SE SE 27.051,042 25.331.266 1.719,776 (741)1.719.035
1220 P SG 20.901.884 19,750,504 1.151,380 2.896.061 4.047.441
1221 CUST CN
1222 SCHMAT-SO SO 23.130.941 21.883,214 1.247.728 14.511 1.262.239
1223 SCHMA T -SNP SNPD 5.136,011 4.899.043 236.968 236.968
1224 DPW BADDE6T
1225 P SG
1226 600KDEPR SCHMDEXP 535.808,937 507.658.460 28,150,477 28,150.477
1227 B6 809.014.791 768.766.383 40.248.409 2.318.244 42.566,652
. 1228
1229 TOTAL SCHEDULE - M ADDITIONS B6 821.693.862 780.761.724 40.932,139 2.318.244 43.250,383
1230
ROLLED.IN Page 9.20
Year.End
FERC BUS UNADJUSTED RESUlTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1231 SCHMDF Deductions - Flow Through
1232 SCHMDF S
1233 SCHMDF DGP
1234 SCHMDF DGU
1235 B6
1236 SCHMDP Deductions. Permanent
1237 SCHMDP S 904 904
1238 P SE 840,899 787,439 53,460 53,460
1239 PTD SNP 381,063 360,822 20,242 20.242
1240 SCHMDP IBT
1241 P SG
1242 SCHMDP-SO SO 26,365,079 24,942.895 1,422,183 1,422,183
1243 B6 27,587,945 26,092,060 1,495,885 1,495,885
1244
1245 SCHMDT Deductions - Temporary
1246 GP S 39,346,405 38,274,657 1,071,748 (915,314)156,434
1247 DPW BADDEBT 1,168,170 1,122,860 45,310 45,310
1248 SCHMDT -SNF SNP 94,462,842 89,445,073 5,017,769 5,017,769
1249 SCHMDT CN 60,323 57,980 2,343 2,343
1250 SCHMDT SG 68,842 65,050 3,792 3,792
1251 CUST DGP
1252 P SE 41,542,935 38,901,834 2,641,101 401,512 3,042,613
1253 SCHMDT -SG SG 135,152,429 127,707,560 7,44,869 7,710,054 15,154,923
1254 SCHMDT -GPi; GPS 82,386,340 77,942,262 4,44,078 4,44,078
1255 SCHMDT-SO SO 48,456,951 45,843,090 2,613,861 (1,054,375)1,559,486
1256 TAXDEPR TAXDEPR 1,622,113,173 1,539,894,065 82,219,108 82,219,108
1257 DPW SNPD 179,120 170,856 8,264 8,264
1258 B6 2,064,937,530 1,959,425,286 105,512,244 6,141,877 111,654,121
1259
1260 TOTAL SCHEDULE - M DEDUCTIONS B6 2,092,525,475 1,985,517 ,346 107,008,129 6,141,877 113,150,007
1261
1262 TOTAL SCHEDULE -M ADJUSTMENTS B6 (1,270,831,613)(1,204,755,622)(66,075.991)(3,823,633)(69.899,624)
1263
1264
1265
1266 40911 State Income Taxes
1267 IBT IBT (21,767,423)(20,090,190)(1,677,233)32,386 (1,64,847)
1268 IBT SE
1269 PTC P SG (70,472)(70,472)
1270 IBT IBT
1271 Total State Tax Expense (21,767.423)(20,090.190)(1.67.233)(38,087)(1.715,320)
1272
1273
1274 Calculation of Taxable Income:
1275 Operating Revenues 4,353,766,380 4,117,757,584 236,008,796 25,787,310 261,796,106
1276 Operating Deductions:
1277 o & M Expenses 2,676,130,329 2,514,814,055 161,316,274 17,526,037 178,842,311
1278 Depreciation Expense 464,027,603 439,648,393 24,379,210 3,105,335 27,484,545
1279 Ámortization Expense 43.698,570 41,446,814 2,251,756 (150,962)2,100,794
1280 Taxes Other Than Income 123,877,487 118,554,217 5,323,269 414,144 5,737,413
1281 Interest & Dividends (AFUDC-Equity)(63,955,322)(60,558,081 )(3,397,241 )160,278 (3,236,963)
1282 Misc Revenue & Expense (5,975,707)(5,678,965)(296,742)17,298 (279,445)
1283 Total Operating Deductions 3,237,802,959 3,048,226,433 189,576,526 21,072,130 210,648,656
1284 Other Deductions:
1285 Interest Deductions 350,882,327 332,243,819 18,638,508 178,206 18,816,715
1286 Interest on PCRBS
1287 Schedule M Adjustments (1,270,831,613)(1,204,755,622)(66,075,991 )(3,823,633)(69,899,624)
1288
1289 Income Before State Taxes (505,750,519)(467,468,290)(38,282,229)713,340 (37,568,889)
1290
1291 State Income Taxes (21,767,423)(20,090,190)(1,677,233)(38,087)(1,715,320)
1292
1293 Total Taxable Income (483,983,096)(447,378,100)(36,604,996)751,427 (35,853,569)
1294
1295 Tax Rate 35.0%35.0%35.0%35.0%35.0%
1296
1297 Federal Income Tax - Calculated (169,394,084)(156,582,335)(12,811,749)262,999 (12,548,749)
1298
1299 Adjustments to Calculated Tax:
1300 40910 PMI P SE
1301 40910 REC P SG (3,821,447)(3,821,447)
1302 40910 P SO
1303 40910 IR$$ee LABOR S
1304 Federal Income Tax Expense (169.394,084)(156,582.335)(12,811,749)(3.558.44)(16,370,196)
1305
1306 Total Operating Expenses 3.591,338,753 3,389,229,388 202.109.365 18.994,850 221,104,215
ROLLED.IN Page 9.21
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1307 310 Land and Land Rights
1308 P SG 2,329,517 2,201,196 128,321 128,321
1309 P SG 34,798,446 32,881,574 1,916,872 1,916,872
1310 P SG 56,303,435 53,201,961 3,101,474 3,101,474
1311 P S
1312 P SG 2,44,255 2,313,393 134,862 134,862
1313 B8 95,879,653 90,598,124 5,281,529 5,281,529
1314
1315 311 Structures and Improvements
1316 P SG 234,107,411 221,211,609 12,895,802 12,895,802
1317 P SG 325,036,982 307,132,327 17,904,655 17,904,655
1318 P SG 221,770,821 209,554,580 12,216,241 12,216,241
1319 P SG 57,386,063 54,224.953 3.161,110 3,161,110
1320 B8 838,301,276 792,123,468 46,177.808 46,177,808
1321
1322 312 Boiler Plant Equipment
1323 P SG 698,182,038 659,722,695 38,459,343 38,459,343
1324 P SG 658,624,890 622,344,552 36,280,338 36,280,338
1325 P SG 1,442,122,538 1,362,683,248 79,439,290 33,484,991 112,924,281
1326 P SG 325,425,382 307,499,331 17,926,050 17,926.050
1327 B8 3,124,354,848 2,952,249,826 172.105,022 33,484.991 205,590,012
1328
1329 314 Turbogenerator Units
1330 P SG 139,149,055 131,484,032 7,665,023 7,665,023
1331 P SG 141,986,218 134,164,910 7,821,308 7.821,308
1332 P SG 487,922,642 461,045,433 26,877,209 26,877,209
1333 P SG 63,734;933 60,224,096 3,510,837 3,510,837
1334 B8 832,792,848 786,918,71 45,874,377 45,874,377
1335
1336 315 Accessory Electric Equipment
1337 P SG 87,739,621 82,906,486 4,833,135 4,833,135
1338 P SG 138,674,494 131,035,612 7,638,882 7,638,882
1339 P SG 74,099,755 70,017,971 4,081,783 4,081,783
1340 P SG 66,352,508 62,697,482 3,655,027 3,655,027
1341 B8 366,866,378 346,657,551 20,208,827 20.208.827
1342
1343
1344
1345 316 Mise Power Plant Equipment
1346 P SG 4,786,848 4,523,164 263,683 263,683
1347 P SG 5,245,086 4,956,160 288,925 288,925
1348 P SG 15,109,785 14,277,463 832,322 832,322
1349 P SG 4,037,788 3,815,366 222,421 .222,421
1350 B8 29,179,506 27,572,154 1,607,352 1,607,352
1351
1352 317 Steam Plant ARO
1353 P S
1354 B8
1355
1356 SP Unclassified Steam Plant - Account 300
1357 P SG 787,304 743,936 43,369 43,369
1358 B8 787,304 743,936 43,369 43,369
1359
1360
1361 Total Steam Production Plant B8 5,288,161,813 4,996,863,530 291,298,283 33,484,991 324,783,274
1362
1363
1364 Summary of Steam Production Plant by Factor
1365 S
1366 DGP
1367 DGU
1368 SG 5,288,161,813 4,996,863,530 291,298,283 33,484,991 324,783,274
1369 SSGCH
1370 Total Steam Production Plant by Factor 5,288,161,813 4,996,863,530 291,298,283 33,484,991 324,783,274
1371 320 Land and Land Rights
1372 P SG
1373 P SG
1374 B8
1375
1376 321 Structures and Improvements
1377 P SG
1378 P SG B8
1379
ROLLED-IN Page 9.22
Year-End
FERC 8US UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAl
1380
1381 322 Reacor Plant Equipment
1382 P SG
1383 P SG
1384 B8
1385
1386 323 Turbogenerator Units
1387 P SG
1388 P SG
1389 B8
1390
1391 324 Land and Land Rights
1392 P SG
1393 P SG
1394 B8
1395
1396 325 Misc. Power Plant Equipment
1397 P SG
1398 P SG
1399 88
1400
1401
1402 NP Unclassified Nuclear Plant - Acct 300
1403 P SG
1404 88
1405
1406
1407 Total Nuclear Production Plant 88
1408
1409
1410
1411 Summary of Nuclear Production Plant by Factor
1412 DGP
1413 DGU
1414 SG
1415
1416 Total Nuclear Plant by Factor
1417
1418 330 Land and Land Rights
1419 P SG 10,621.118 10.036.054 585.064 585.064
1420 P SG 5.270,019 4,979,720 290.299 290,299
1421 P SG 3.645,604 3.44,786 200.818 200.818
1422 P SG 672.873 635,808 37.065 37,065
1423 B8 20,209.614 19,096,368 1,113.246 1.113.246
1424
1425 331 Structures and Improvements
1426 P SG 21.272.790 20.100.979 1.171,811 1.171.811
1427 P SG 5.299.236 5,007.327 291.908 291,908
1428 P SG 69.738,251 65,896,721 3.841,530 3.841.530
1429 P SG 7.984,198 7.544.388 439.809 439.809
1430 B8 104.294,475 98,549,416 5,745.059 5.745.059
1431
1432 332 Reservoirs. Dams & Waterways
1433 P SG 151.296.614 '142.962.443 8.334.171 8.334,171
1434 P SG 20.156.916 19.046.572 1,110,343 1.110.343
1435 P SG 106.245.543 100.393.009 5.852.534 324,857 6,177.391
1436 P SG 37.108,148 35.064,047 2.044.102 2.044.102
1437 B8 314,807.221 297,466,072 17.341.149 324.857 17,666.007
1438
1439 333 Water Wheel. Turbines, & Generators
1440 P SG 31,913,924 30.155.946 1.757.978 1,757.978
1441 P SG 8.828,844 8.342.508 486.337 486.337
1442 P SG 43,462.254 41.068.137 2.394,117 2.394,117
1443 P SG 27,234.682 25.734,460 1,500.222 1.500,222
144 88 111,439.704 105.301,050 6.138,654 6,138.654
1445
1446 334 Accessory Electric Equipment
1447 P SG 4,430.934 4.186.857 244.078 244,078
1448 P SG 3,669.976 3.467.816 202.161 202.161
1449 P SG 43.817.031 41.403.370 2,413,660 2,413.660
1450 P SG 7,133.812 6.740.846 392,966 392,966
1451 B8 59,051.753 55.798.888 3.252,865 3,252.865
1452
ROLLED-IN Page 9.23
Year-End
FERC BUS.UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO AÒJUSTMENT AOJTOTAL
1453
1454
1455 335 Misc. Power Plant Equipment
1456 P 5G 1.197.194 1.131.247 65.947 65.947
1457 P 5G 186.194 175.938 10,257 10.257
1458 P 5G 996,385 941,499 54.886 54.886
1459 P 5G 11,353 10.728 625 625
1460 B8 2,391,127 2.259,411 131,715 131.715
1461
1462 336 Roads, Railroads & Bridges
1463 P 5G 4,620.060 4.365,564 254,496 254,496
1464 P 5G 828.931 783.269 45,662 45.662
1465 P 5G 9,817.317 9,276,530 540,787 540.787
1466 P 5G 682,347 644.760 37.587 37.587
1467 B8 15,946,654 15.070.123 878.531 878.531
1468
1469 337 Hydro Plant ARO
1470 P 5
1471 B8
1472
1473 HP Unclassified Hydro Plant - Acct 300
1474 P 5
1475 P 5G
1476 P 5G
1477 P 5G
1478 B8
1479
1480 Total Hydraulic Production Plant B8 628,142,54 593,541,329 34,601,219 324,857 34,926,017
1481
1482 Summary of Hydraulic Plant by Factor
1483 S
1484 SG 628,142,548 593,541,329 34.601,219 324.857 34,926.077
1485 DGP
1486 DGU
1487 Total Hydraulic Plant by Factor 628,142,548 593,541,329 34.601.219 324,857 34,926,077
1488
1489 340 Land and Land Rights
1490 P SG 23.516.708 22.221.290 1.295,417 1.295,417
1491 P SG
1492 P SG
1493 B8 23,516.708 22,221,290 1.295,417 1.295,417
1494
1495 341 Structures and Improvements
1496 P SG 151,043,941 142,723.688 8,320,252 8,320,252
1497 P SG 163.512 154,505 9,007 9,007
1498 P 5G 4.241.952 4,008.284 233.668 233.668
1499 B8 155.449,405 146.886,77 8.562,927 8.562.927
1500
1501 342 Fuel Holders. Producers & Accessories
1502 P SG 8,406.209 7,943.153 463,056 463.056
1503 P SG 121.339 114.655 6.684 6,684
1504 P SG 2.284.126 2,158,305 125.821 125,821
1505 B8 10,811,674 10.216,113 595.561 595.561
1506
1507 343 Prime Movers
1508 P S
1509 P SG 754,466 712,906 41,560 41,560
1510 P 5G 2.223,358.082 2,100.884,449 122,473,634 14,387.299 136.860,932
1511 P SG 51,744,608 48,894.258 2.850.351 2,850.351
1512 B8 2,275,857.156 2.150,491.612 125.365.544 14,387.299 139,752.843
1513
1514 344 Generators
1515 P S
1516 P SG
1517 P SG 331,535,449 313.272,825 18.262.623 18.262.623
1518 P 5G 15.873,643 14.999,244 874.399 874.399
1519 B8 347,409.092 328.272,070 19.137.023 19.137.023
ROLLED-IN Page 9.24
Year-End
FERC 8US UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1520
1521 345 Accessory Electrc Plant
1522 P SG 226,854,809 214,358,517 12,496,292 12,496,292
1523 P . SG 156,586 147,961 8,626 8,626
1524 P SG 2,919,649 2,758.820 160,829 160,829
1525 88 229,931.044 217.265,297 12,665,747 12.665,747
1526
1527
1528
1529 346 Misc. Power Plant Equipment
1530 P SG 12,167.872 11,497.605 670,267 670.267
1531 P SG 11,813 11.162 651 651
1532 88 12,179,685 11.508,767 670.918 670.918
1533
1534 347 Other Production ARO
1535 P S
1536 88
1537
1538 OP Unclassified Oter Prod Plant-Acct 300
1539 P S
1540 P SG
1541
1542
1543 Total Other Production Plant B8 3,055,154,764 2,886,861,627 168,293,136 14,387,299 182,680,435
1544
1545 Summary of Other Production Plant by Factor
1546 S
1547 DGU
1546 SG 3,055,154,764 2.886.861.627 168,293.136 14.387,299 182,680,435
1549 SSGCT
1550'Total of Other Production Plant by Factor 3,055.154,764 2,886,861.627 168,293.136 14.387.299 182.680.435
1551
1552 Experimental Plant
1553 103 Experimental Plant
1554 P SG
1555 Total Experimental Production Plant 88
1556
1557 Total Production Plant 88 8,971,459,125 8,477,266,486 494,192,639 48,197,147 542,389,786
1558 350 Land and Land Rights
1559 T SG 21,145,733 19,980,920 1,164.812 1,164.812
1560 T SG 48.501,155 45,829,470 2.671.685 2.671.685
1561 T SG 31,414,150 29,683,702 1.730,44 (23.847)1.706.601
1562 88 101.061,037 95,494.092 5.566,945 (23.847)5.543.098
1563
1564 352 Structures and Improvements
1565 T S
1566 T SG 7.741,609 7.315.163 426,446 426,44
1S67 T SG 18,157,495 17,157,289 1.000.205 1.000,205
1568 T SG 59.577,575 56,295,746 3.281,829 3.281.829
1569 88 85,476,679 80,768,198 4,708,481 4,708,81
1570
1571 353 Station Equipment
1572 T SG 129,985,618 122,825,363 7,160,255 7.160.255
1573 T SG 188,825,398 178,423,955 10,401.443 10,401.443
1574 T SG 988,384.505 933,939,365 54,445,140 54.445.140
1575 88 1,307,195,521 1.235,188,683 72,006.838 72.006.838
1576
1577 354 Towers and Fixtures
1578 T SG 156.322,773 147.711.736 8.611.037 8.611.031
1579 T SG 127.544,198 120.518,428 7.025,769 7.025.769
1580 T SG 165.062,634 155,970.163 9,092,472 9,092,472
1581 88 44.929.605 424.200.327 24.729.278 24,729,278
1582
1583 355 Poles and Fixtures
1584 T SG 66,244.763 62.595.672 3,649.091 3,649.091
1585 T SG 117.745,408 111.259.405 6,486,003 6.86,003
1586 T SG 375.300,433 354.627.017 20.673.417 51.961.670 72.635,086
1587 88 559.290.604 528,482.093 30,808.511 51.961.670 82.770.181
1588
ROLLED-IN Page 9.25
Year-End
FERC BUS UNADJUSTED RESUL T8 IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1589 356 Clearing and Grading
1590 T SG 197,260,339 186,394,257 10,866,082 10,866,082
1591 T SG 156,882,468 148,240,600 8,641,867 8,641,867
1592 T SG 380,070,379 359,134,210 20,936,169 20,936,169
1593 B8 734,213,185 693,769,067 40,44,118 40,444,118
1594
1595 357 Underground Conduit
1596 T SG 6,371 6,020 351 351
1597 T SG 91,651 86,602 5,049 5,049
1598 T SG 3,113,807 2,942,283 171,524 171,524
1599 B8 3,211,828 3,034,905 176,923 176,923
1600
1601 358 Underground Conductors
1602 T SG
1603 T SG 1,087,552 1,027,64 59,908 59,908
1604 T SG 6,442,172 6,087,305 354,867 354,867
1605 68 7,529,724 7,114,949 414,775 414,775
1606
1607 359 Roads and Trails
1608 T SG 1,863,032 1,760,406 102,625 102,625
1609 T SG 440,513 416,248 24,266 24,266
1610 T SG 9,151,569 8,647,455 504,114 504,114
1611 68 11,455,113 10,824,109 631,005 631,005
1612
1613 TP Unclassified Trans Plant. Acct 300
1614 T SG 84,550,623 79,893,154 4,657,469 4,657,469
1615 68 84,550,623 79,893,154 4,657,469 4.657,469
1616
1617 TSO Unclassified Trans Sub Plant. Acct 300
1618 T SG
1619 68
1620
1621 Total Transmission Plant 68 3,342,913,921 3,158,769,577 184,144,344 51,937,823 236,082,166
1622 Summary of Transmission Plant by Factor
1623 DGP
1624 DGU
1625 SG 3,342,913,921 3,158,769,577 184,144,344 51,937,823 236,082,166
1626 Total Transmission Plant by Factor 3,342,913.921 3,158,769,577 184,144,344 51,937,823 236.082,166
1627 360 Land and Land Rights
1628 DPW S 51,856,326 50,519,585 1,336,741 1,336,741
1629 68 51,856,326 50,519,585 1,336,741 1,336,741
1630
1631 361 Structures and Improvements
1632 DPW S 66,495,517 65,002,256 1,493,261 1,493,261
1633 68 66,495.517 65,002,256 1,493,261 1,493,261
1634
1635 362 Station Equipment
1636 DPW S 787,676,940 761,044,499 26,632,441 26,632,441
1637 68 787,676.940 761,044,499 26,632,441 26,632,441
1638
1639 363 Storage Battery Equipment
1640 DPW S 1,457,805 1,457,805
1641 B8 1,457.805 1,457,805
1642
1643 364 Poles, Towers & Fixtures
1644 DPW S 903,958,177 842,950,744 61,007,433 61.007,433
1645 68 903,958,177 842,950,744 61,007,433 61,007,433
1646
1647 365 Overhead Conductors
1648 DPW S 631,378,730 597,455,532 33,923,198 33,923,198
1649 68 631,378,730 597,455,532 33.923,198 33,923,198
1650
ROLLED-IN Page 9.26
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1651 366 Underground Conduit
1652 DPW S 290.621.174 283,247,994 7.373,179 7.373.179
1653 B8 290.621.174 283,247,994 7.373.179 7.373.179
'1654
1655
1656
1657
1658 367 Underground Conductors
1659 DPW S 697.799.779 674.120,851 23.678.928 23.678.928
1660 B8 697,799.779 674.120,851 23,678.928 23.678.928
1661
1662 368 Line Transformers
1663 DPW S 1,056,509.849 990,583.151 65,926.697 65,926.697
1664 B8 1,056,509,849 990,583,151 65,926,697 65.926.97
1665
1666 369 Services
1667 DPW S 559.763.102 531,874,191 27,888,911 27,888,911
1668 B8 559.763.102 531,874.191 27.888,911 27,888,911
1669
1670 370 Meters
1671 DPW S 187,209.616 173,388,196 13,821,420 13.821,420
1672 B8 187,209,616 173,388.196 13,821,420 13.821,420
1673
1674 371 Installations on Customers' Premises
1675 DPW S 8,809.120 8,644.004 165,115 165,115
1676 B8 8,809,120 8.644,004 165,115 165.115
1677
. 1678 372 . Leased Propert
1679 DPW S
1680 B8
1681
1682 373 Street Lights
1683 DPW S 62.885,404 62.283.269 602.135 602,135
1684 B8 62,885.404 62,283.269 602.135 602.135
1685
1686 DP Unclassified Dist Plant - ACet 300
1687 DPW S 20,216,252 19.291,256 924.997 924,997
1688 B8 20,216,252 19.291.256 924,997 924,997
1689
1690 DSO Unclassified Dist Sub Plant - Acct 300
1691 DPW S
1692 B8
1693
1694
1695 Total Distribution Plant B8 5,326,637,791 5,061,863,333 264,774,458 264,774,458
1696
1697 Summary of Distnbution Plant by Factor
1698 S 5.326.637,791 5,061.663,333 264.774,458 264,774,458
1699
1700 Total Distnbution Plant by Factor 5,326,637.791 5,061,863,333 264,774,458 264.774,458
ROLLED-IN Page 9.27
Year-End
FËRC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1701 389 Land and Land Rights
1702 G-SITUS 5 9,472.275 9.274.636 197.639 197.639
1703 CUST CN 1,128.506 1,084,668 43.838 43,838
1704 PT SG 332 314 18 18
1705 G-SG SG 1,228 1,160 68 68
1706 PTD SO 5,598,055 5.296,085 301,970 301,970
1707 B8 16,200.395 15,656.863 543.532 543,532
1708
1709 390 Structures and Improvements
1710 G-SITUS 5 111,200.704 101,422.380 9.778,324 9,778,324
1711 PT SG 358.127 338.400 19.727 19.727
1712 PT SG 1,653.732 1.562,636 91,096 91,096
1713 CUST CN 12,319.587 11,841.025 478.563 478,563
1714 G-SG SG 3,675.782 3,73.302 202,480 202,480
1715 PTO SO 102.313,681 96,794,683 5,518.997 5.518.997
1716 B8 231.521,614 215,432.426 16.089.188 16.089.188
1717
1718 391 Ofice Furniture & Equipment
1719 G.SITUS 5 13.065,614 12,137,233 928,381 928.381
1720 PT SG 1,046 988 58 58
1721 PT SG 5,295 5,003 292 292
1722 CUST CN 8,85.337 8,347.949 337.388 337,388
1723 G-SG SG 4.784,588 4.521,029 263.559 263,559
1724 P SE 97,829 91.609 6,219 6,219
1725 PTO SO 54,551,124 51,608.531 2.942,593 2.942.593
1726 G.SG SG 74.351 70,256 4,096 4,096
1727 G-SG SG
1728 B8 81,265.184 76,782,599 4,482,585 4,482,585
1729
1730 392 Transportation Equipment
1731 G.SITUS 5 73.113.164 68.190,669 4,922,495 4,922,495
1732 PTD SO 7.996.779 7,565.417 431,362 431,362
1733 G-SG SG 17,254,817 16,304,336 950,481 950,481
1734 CUST CN
1735 PT SG 838,181 792.010 46,171 46,171
1736 P SE 404,148 378,454 25.694 25.694
1737 PT SG 120.286 113.660 6.626 6.626
1738 G-SG SG 374.178 353.567 20.612 20,612
1739 PT SG 44,655 42,195 2.480 2,460
1740 B8 100,146.208 93.740,308 6.405,900 6,405,900
1741
1742 393 Stores Equipment
1743 G-SITUS 5 8.861.339 8.312.757 548.582 548.582
1744 PT SG 108,431 102,458 5.973 5,973
1745 PT SG 360.063 340,229 19.834 19.834
1746 PTD SO 445.293 421,273 24.020 24.020
1747 G-SG SG 4.062,155 3.838.392 223.764 223,764
1748 PT SG 53,971 50,998 2.973 2.973
1749 B8 13.891,252 13,066.106 825.146 825.146
ROLLED-IN Page 9.28
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Rèf TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1750
1751 394 Tools, Shop & Garage Equipment
1752 G-SITUS S 32,024,394 30.281,765 1,742.629 1,742,629
1753 PT SG 2.120.983 2.004,148 116.834 116,834
1754 G-SG SG 20,499,259 19.370,058 1,129,201 1,129,201
1755 PTO SO 3,986.801 3,771,746 215,56 215,056
1756 P SE 7.106 6,655 452 452
1757 PT SG 2.176.302 2,056,420 119,882 119,882
1758 G-SG SG 1,716,105 1.621,573 94,532 94,532
1759 G-SG SG 89,913 84,961 4,953 4,953
1760 B8 62,620,863 59,197,325 3,423,538 3,423,538
1761
1762 395 Laboratory Equipment
1763 G-SITUS S 25,228.787 23,956,655 1,272,132 1,272,132
1764 PT SG 20,622 19,486 1,136 1.136
1765 PT SG 13,281 12,550 732 732
1766 PTD SO 5,197,970 4,917,581 280,389 280.389
1767 P SE 7,593 7,111 483 483
1768 G-SG SG 6,353,527 6,003,543 349,984 349,984
1769 G-SG SG 253.001 239,064 13,937 13,937
1770 G-SG SG 14,022 13,249 772 772
1771 B8 37,088,802 35,169,239 1,919,564 1,919,564
1772
1773 396 Power Operated Equipment
1774 G-SITUS S 94,279,509 87,117,887 7,161,622 7,161,622
1775 PT SG 845.108 798,555 46,553 46,553
1776 G-SG SG 31,633,038 29,890,533 1,742,505 1,742.505
1777 PTD SO 1,410,640 1,334,548 76,093 76,o3
1778 PT SG 1,664,492 1,572,804 91,689 91.689
1779 P SE 73,823 69,130 4.693 4,693
1780 P SG
1781 G-SG SG 968.906 915,534 53,372 53,372
1782 B8 130,875.517 121,698,990 9.176,527 9,176,527
1783 397 Communication Equipment
1784 COM_EO S 101,721,635 96,539,236 5,182,399 5,182,399
1785 COM_EO SG 4,816,644 4,551,319 265,325 265,325
1786 COM_EO SG 9,615,788 9.086,102 529,685 529,685
1787 COM_EO SO 48.166.017 45,567.850 2,598.168 2,598,168
1788 COM_EO CN 2,641,488 2,538,878 102,610 102,610
1789 COM_EO SG 74,202,015 70.114,598 4,087,416 4.087,416
1790 COM_EO SE 114,538 107,256 7,282 7.282
1791 COM_EO SG 1,055,756 997,599 58,156 58,156
1792 COM_EO SG 1,590 1,503 88 88
1793 B8 242.335,471 229,504,341 12,831,130 12,831,130
1794
1795 398 Misc. Equipment
1796 G-SITUS S 1.354,746 1.290,393 64,352 64,352
1797 PT SG
1798 PT .SG 1.997 1,887 110 110
1799 CUST CN 199,765 192.005 7,760 7.760
1800 PTO SO 3,376,792 3,194.641 182,151 182,151
1801 P SE 1,668 1.562 106 106
1802 G-SG SG 1,865,540 1.762,777 102,763 102,763
1803 G-SG SG
1804 B8 6,800,507 6,443,265 357.242 357,242
1805
1806 399 Coal Mine
1807 P SE 278.021.722 260.346,31 17,675.291 13,511,711 31,187.003
1808 MP P SE
1809 B8 278,021,722 260,346,431 17.675,291 13,511.711 31,187,003
1810
1811 399L WIOCO Capital Lease
1812 P SE B8
1813
1814
.1815 Remove Capital Leases
1816 B8
1817
ROLLED-IN Page 9.29
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1818 1011390 General Capital Leases
1819 G-SITUS S 18,984,156 18,984,156
.1820 P SG 16,951,793 16,018,004 933,789 933,789
1821 PTD SO 12,664,054 11,980,930 683,123 683,123
1822 69 48,600,02 46,983,090 1,616,913 1,616,913
1823
1824 Remove Capital Leases (48,600,002)(46,983,090)(1,616,913)(1,616,913)
1825
1826
1827 1011346 General Gas Line Capital Leases
1828 P SG
1829 89
1830
1831 Remove Capital Leases
1832
1833
1834 GP Unclassified Gen Plant - Acct 300
1835 G-SITUS S
1836 PTD SO 4,694,044 4,440,838 253,206 253,206
1837 CUST CN
1838 G-SG SG
1839 PT SG
1840 PT SG
1841 88 4.694,044 4,440,838 253.206 253,206
1842
1843 399G Unclassified Gen Plant - Acct 300
1844 G-SITUS S
1845 PTD SO
1846 G-SG SG
1847 PT SG
1848 PT SG
1849 88
1850
1851 Total General Plant 88 1,205,461,579 1,131,478,731 13,982,849 13,511,711 87,494,560
1852
1853 Summary of General Plant by Factor
1854 S 489.306,322 457,507,766 31,798,556 31.798,556
1855 DGP
1856 DGU
1857 SG 210,650,900 199,047,199 11,603,700 11,603.700
1858 SO 250,401,250 236.894,123 13,507,126 13,507,126
1859 SE 278,728,427 261,008,207 17,720.220 13,511,711 31.231,932
1860 CN 24.974,683 24,004,525 970.158 970.158
1861 DEU
1862 SSGCT
1863 SSGCH
1864 Less Capital Leases ~48.600.002)(48,983,090)(1,616,913)(1,616,913)
1865 Total General Plant by Factor 1, 05.461579 1,131,478,731 73,982,849 13,511,711 87.494,560
1866 301 Organization
1867 I-SITUS S
1868 PTD SO
1669 I-SG SG
1870 88
1871 302 Franchise & Consent
1872 I-SITUS S 1,000,000 1,000,000 1.000.000
1873 I-SG SG 9,402,471 8,884,536 517,935 517.935
1874 I-SG SG 99,510,474 94,028,942 5,481,532 5.481,532
1875 I-SG SG 9,240,742 8,731,716 509,026 509,026
1876 P SG
1877 P SG 600.993 567,867 33,106 33,106
1878 68 119,754.679 112.213.060 7.541.599 7.541.599
1879
ROLLED.IN Page 9.30
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1880 303 Miscellaneous Intangible Plant
1881 I-SITUS S 6.042,837 5,626.978 415,859 415.859
1882 I-SG SG 95,041,256 89,805,910 5,235,346 631,847 5.867,193
1883 PTO SO 366,513,585 346,743,135 19,770,450 19,770,450
1884 I"SE 3,453,872 3,234,291 219,581 219,581
1885 CUST CN 118,758,961 114,145,691 4,613,271 4,613,271
1886 I"SG
1887 I"SG
1888 B8 589.810,510 559,556.004 30,254.506 631.847 30.886.353
1889 303 Less Non-Utilty Plant
1890 I-SITUS S
1891 589,810,510 559,556,004 30.254,506 631,847 30.886.353
1892 iF'Unclassified Intangibie Plant - Acet 300
1893 I-SITUS S
1894 I-SG SG
1895 I"SG
1896 PTO SO
1897
1898
1899 Total Intangible Plant B8 709,565,190 671,769,085 37,796,105 631,847 38,427,952
1900
1901 Summary of Intangible Plant by Factor
1902 S 7.042.837 5,626,978 1,415,859 1,415.859
1903 OGF'
1904 OGU
1905 SG 213,795.935 202,018,990 11.776.945 631,847 12,408.792
1906 SO 366,513.585 346,743,135 19,770,450 19,770,450
1907 CN 118,758.961 114,145,691 4,613,271 4,613.271
1908 SSGCT
1909 SSGCH
1910 SE 3.453,872 3,234,291 219,581 219.581
1911 Total Intangible Plant by Factor 709.565,190 671,769,085 37.796,105 631,847 38.27.952
1912 Summary of Unclassified Plant (Account 106)
1913 01"20,216,252 19,291,256 924,997 924,997
1914 OSO
1915 GP 4,694,044 4,44,838 253,206 253.206
1916 HI"
1917 NP
1918 01"
1919 TP 84,550,623 79,893.154 4,657.469 4,657,469
1920 TSO
1921 II"
1922 MP
1923 SP 787,304 743,936 43.369 43.369
1924 Total Unclassified Plant by Factor 110,246,224 104.369.183 5.879,040 5.879.040
1925
1926 Totl Electric Plant In Service B8 19,556,037,605 18,501,147,212 1,054,890,394 114,278,528 1,169,168,92
ROLLED-IN Page 9.31
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT AOJTOTAL
1927 Summary of Electric Plant by Factor
1928 S 5,822,986,950 5,524,998,077 297,988,873 297,988,873
1929 SE 282,182,299 264,242,498 17,939,801 13,511,711 31,451,512
1930 DGU
1931 DGP
1932 SG 12,738,819,880 12,037,102,253 701,717,627 100,766,817 802,484,444
1933 SO 616,914,834 583,637,258 33,277,576 33,277,576
1934 CN 143,733,644 138,150,216 5,583,429 5,583,429
1935 DEU
1936 SSGCH
1937 SSGCT
1938 Less Capital Leases (48,600,002)~48,983,090)(1,616,913)(1,616,913)
1939 19,556,037,605 18, 01,147,212 1,054,890,394 114,78,528 1,169,168,922
1940 105 Plant Held For Future Use
1941 DPW S 3,473,204 3,473,204
1942 P SNPP$
1943 T SNPT 325,029 307,125 17,904 (509.44)(491,540)
1944 P SNPP 8,923,302 8,431,762 491,540 491,540
1945 P SE 953,014 892,426 60,588 (60,588)
1946 G SNPG
1947
1948
1949 Total Plant Held For Future Use B10 13,674,54 13,104,516 570,032 (570,032)0
1950
1951 114 Electric Plant Acquisition Adjustments
1952 P S
1953 P SG 142,633,069 134,776,129 7,856,940 7,856,940
1954 P SG 14,560,711 13,758,634 802,076 802.076
1955 Total Electric Plant Acquisition Adjustment B15 157,193,780 148,534,764 8,659,016 8,659,016
1956
1957 115 Accum Provision for Asset Acquisltlon Adjustments
1958 P S
1959 P SG (84,100,707)(79,468,021 )(4,632,686)(4,632,686)
1960 P SG (12,226,166)(11,552,688)(673,478 673,478)
1961 815 6,, 09 5,4 ,0 , 6
1962
1963 120 Nuclear Fuel
1964 P SE
1965 Total Nuclear Fuel B15
1966
1967 124 Weatherization
1968 DMSC S 2,633,178 2,599,959 33,220 33,220
1969 DMSC SO ~4,454)(4,213)(240)(240)
1970 816 2,6 8,725 2,595,745 3i979 32,979
1971
1972 182W Weatherization
1973 DMSC S 34,729,463 31,258,802 3;470,661 3,470,661
1974 DMSC SG
1975 DMSC SG
1976 DMSC SO
1977 816 34,729,463 31,258.82 3,470,661 3,470,661
1978
1979 186W Weatherization
1980 DMSC S
1981 DMSC CN
1982 DMSC CNP
1983 DMSC SG
1984 DMSC SO
1985 816
1986
1987 Total Weatherization 816 37,358,188 33,854,54 3,503,64 3,503,640
ROLLED-IN Page 9.32
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1988
1989 151 Fuel Stock
1990 P DEU
1991 P SE 158,860,196 148,760,625 10,099,571 1,566,785 11,666,357
1992 P SE
1993 P SE 12,069,947 11,302,597 767,349 767,349
1994 Totl Fuel Stock B13 170,930,143 160,063,22 10,866,921 1,566,785 12,433,706
1995
1996 152 Fuel Stock - Undistributed
1997 P SE
1998
1999
2000 25316 DG& T Working Capital Deposit
2001 P SE (1,379,000)(1,291,330)(87,670)(56,073)(143,744)
2002 613 (1,379,000)(1,291.330)(87.670)(56,073)(143.744)
2003
2004 25317 DG& T Working Capital Deposit
2005 P SE (1.758,544)(1,646,744)(111,800)(5,907)(117.706)
2006 613 (1,758,544)(1,646,744)(111,800)(5,907)(117,706)
2007
2008 25319 Provo Working Capital Deposit
2009 P SE
2010
2011
2012 Total Fuel Stock 613 167.792,599 157,125,148 10,667,451 1,504,805 12,172,256
2013 154 Materials and Supplies
2014 MSS S 86,919,683 82,030,372 4,889,311 4,889,311
2015 MSS SG 3,082,186 2,912,404 169,782 169,782
2016 MSS SE 4,170,119 3,905,003 265,116 265,116
2017 MSS SO 253,641 239,959 13,682 13,682
2018 MSS SNPPS 81,516,215 77,025,896 4,490,319 4,490,319
2019 MSS SNPPH (1,860)(1,757)(102)(102)
2020 MSS SNPD (3,081,941)(2,939,745)(142,196)(142,196)
2021 MSS SNPT
2022 MSS SG
2023 MSS SG
2024 MSS SNPPS
2025 MSS SNPPO 5,288,978 4,997,635 291,343 291,343
2026 MSS SNPPS
2027 Total Materials and Supplies B13 178,147,022 168,169,767 9,977,255 9,977,255
2028
2029 163 Stores Expense Undistributed
2030 MSS SO
2031
2032 613
2033
2034 25318 Provo Working Capital Deposit
2035 MSS SNPPS (273,000)(257,962)(15,038)(15,038)
2036
2037 613 (273,000)(257,962)(15,038)(15,038)
2038
2039 Total Materials & Supplies 613 177 ,87 4,022 167,911,805 9,962,217 9,962,217
2040
2041 165 Prepayments
2042 DMSC S 2,934,455 2,770,438 164,017 164,017
2043 GP GPS 9,858,973 9,327,161 531,812 531,812
2044 PT SG 6,15,547 6,062,146 353,400 353,400
2045 P SE 7,102,118 6,650,600 451,519 451.519
2046 PTD SO 19,839,360 18,769,187 1,070,173 1,070,173
2047 Total Prepayments 615 46,150,453 43,579,532 2,570,921 2,570,921
2048
ROLLED.IN Page 9.33
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DE SCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
2049 182M Mise Regulatory Assets
2050 DDS2 S 56,142,627 56,331,298 (188,671)(17,580)(206.251)
2051 DEFSG SG 2,654.642 2,508,411 146.231 74,434 220,665
2052 P SGeT 8,511.723 8.041,060 470.663 470,663
2053 DEFSG SG
2054 P SE 74,327 74.327
2055 P SG
2056 . DDS02 SO 7,516.382 7.110,934 405,448 405,48
2057 B11 74,825.374 73.991,703 833.671 131.181 964,82
2058
2059 186M Mise Deferred Debits
2060 LABOR S 16,240,410 16.240,410
2061 P SG
2062 P SG
2063 DEFSG SG 38,988.960 36.841,254 2,147.706 531.032 2,678.738
2064 LABOR SO 16.926 16,013 913 913
2065 P SE 10,045,914 9,407,242 638,671 (108.911 )529.760
2066 P SNPPS
2067 GP EXeTAX
2068 Total Misc. Deferred Debits 811 65,292,210 62,504,920 2,787,290 422,121 3,209,411
2069
2070 Working Capital
2071 ewe Cash Working Capital
2072 ewe S 36.106,992 34,139.875 1.967,117 140,695 2,107.812
2073 ewc SO
2074 ewe SE
2075 B14 36.106,992 34,139.875 1.967,117 140.695 2,107.812
2076
2077 OWC Other Work. Cap.
2078 131 Cash GP SNP
2079 135 Workin Funs GP SG 1.920 1.814 106 106
2080 141 Notes Recevabli GP SO 540.572 511,412 29,159 29,159
2081 143 Othe, AIR GP SO 33,985.372 32.152,136 1.833.237 1,833.237
2082 232 AlP PTD S
2083 232 Al PTD SO (4.215.163)(3.987.789)(227.374)(227,374)
2084 232 Al P SE (1,408.497)(1,318.951)(89.545)(89,545)
2085 232 Al T SG
2086 2533 Othe Msc_ Ot.Cfd. P S
2087 2533 Otti Msc_ Of. Crd_ P SE (6.046,034)(5.661.656)(384.378)(384.378)
2088 230 Ast Retir. Oblig P SE (2,415,872)(2,262,283)(153.590)(H¡3,590)
2089 230 Asset Retir. Obllg. P S
2090 254105 ARO Re Lllbüity P S
2091 254105 ARO Reg Liability P SE (716.594)(671,036)(45.558)(45.558)
2092 2533 ChOla Recamation P SE
2093 814 19.725.703 18.763.64 962.057 962.057
2094
2095 Total Working Capital 814 55,832,695 52,903,521 2,929,174 140,695 3,069,870
2096 Miscellaneous Rate Base
2097 18221 Unrec Plant & Reg Study Costs
2098 P S
2099
2100 615
2101
2102 18222 Nuclear Plant. Trojan
2103 P S (372,363)(372,363)
2104 P TROJP 885.265 835,358 49,907 49.907
2105 P TROJD 1.296.271 1,222,899 73.372 73.372
2106 615 1,809.172 1.685.894 123.279 123,279
21Ú7
2108
ROLLED-IN Page 9.34
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR , Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
2109
2110 1869 Misc Deferred Debits-Trojan
2111 P 5
2112 P SNPPN
2113 B15
2114
2115 Total Miscellaneous Rate Base B15 1,809,172 1,685,894 123,279 123,279
2116
2117 Total Rate Base Additions B15 701,476,168 664,175,640 37,300,528 1,628,770 38,929,299
2118 235 Customer 5ervlce Deposits
2119 CU5T 5
2120 CU5T CN
2121 Total Customer Service Deposits B15
2122
2123 2281 Prop Ins pro 50
2124 2282 Inj& Dam PTO 50 (7,487,871 )(7,083,961)(403,910)(403,910)
2125 2283 Pen & Ben PTO SO (22,725,860)(21,499,983)(1,225,877)(1,225,877)
2126 254 Reg Uab PTO 5G
2127 254 Reg Uab PTO 5E (1,217,286)77,389
2128 254 Ins Prov PTO 50 109.564)
2129 B15 , 4 ,5 1
2130
2131 22841 Accum Mlsc Oper Provisions. Other
2132 P 5
2133 P 5G (1,500,000 82,627)(82.627
2134 B15 .5 ,0 8 ,6
2135
2136 22842 Prv.Trojan P TROJO
2137 230 ARO P TROJP (1,711.281)(1,614,808)(96,473)(96,73)
2138 254105 ARO P TROJP (3,608,947)(3.405,494)(203,453)(203,453)
2139 254 P 5 (6,009.324l (6,009,324l
2140 B15 (11,329.552 (11.029,626 (299,926)(299,926)
2141
2142 252 Customer Advances for Construction
2143 DPW 5 (13,473,111)(13,198.024)(275,088)6.822 (268.266)
2144 OPW 5E
2145 r 5G (7,471.547)(7.059,977)(411,570)(267,861)(679,31)
2148 DPW 50
2147 CU5T CN
2148 Total Customer Advances for Construction B19 (20,94,658)(20,258,001)(686.658)(261,039)(947,697)
2149
2150 25398 502 Emissions
2151 P 5E (2,402,284)(2,402;284l
2152 B19 (2.402,284)(2.402,284
2153
2154 25399 Other Deferred Credits
2155 P 5 (3,803,740)(3,728,560)(75.180)(75.180)
2156 LABOR 50 (181,348)(181.348)
2157 P 5G (441,134)
2158 P 5E (75.229)
2159 B19 181,1
ROLLED.IN Page 9.35
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
2160
2161 190 Accumulated Deferred Income Taxes
2162 P S 10,695,84 10,695,486 (2)(2)
2163 CUST CN 65.488 62.944 2.544 2,544
2164 P IBT
2165 LABOR SO 36,490,690 34.522.312 1.968,378 (49,979)1.918.399
2166 P OGP
2167 CUST BAOOEBT 3,345.135 3.215.387 129.748 129,748
2168 P TROJO 1,332,481 1.257.059 75.422 75,422
2169 P SG 39,391.566 37,221,682 2,169.884 (2,002,880)167,004
2170 P SE 3.097.022 2,900,128 196.894 (347,312)(150,418)
2171 PTO SNP
2172 OPW SNPO 703,493 671,035 32,458 32,458
2173 P SSGCT
2174 Total Accum Deferred Income Taxes 819 95,121,359 90,546,034 4,575,325 (2,400,170)2,175,155
2175
2176 281 Accumulated Deferrd Income Taxes
2177 P S
2178 PT DGP
2179 T SNPT
2180 819
2181
2182 282 Accumulated Deferrd Income Taxes
2183 GP S (138.317.516)(138,317.516)
2184 ACCMOIT OITBAL (2.336,392,077)(2.195,736,556)(140,655,521 )140.655,521 0
2185 P SG
2186 LABOR SO (6,909,549)(6,536,835)(372,714)6,816 (365.899)
2187 CUST CN
2188 P SE (5,607,614)(5.251,109)(356.505)(61,607)(418,113)
2189 P SG (5,705.530)(5.391,241 )(314.289)(1,664,205)(1.978,94)
2190 B19 (2,354.614,770)(2,212.915,740)(141,699.030)619,009 (141,080.021 )
2191
2192 283 Accumulated Deferred Income Taxes
2193 GP S (30,884.504)(29,777,409)(1.107,095)1,028,227 (78.868)
2194 P SG (6,716,785)(6,346,791 )(369,994)(41.055)(411,048)
2195 P SE (4,844.933)(4,536,915)(308,018)41,333 (266,685)
2196 LABOR SO (16,761.723)(15,857,563)(904,160)710,964 (193,195)
2197 GP GPS (5,687,055)(5,380.284) .(306.771)(306,771)
2198 PTD SNP (5,228,914)(4,951.159)(277.755)(277.755)
2199 P TROJO
2200 P SG
2201 P SG (2,701.338)(2,552,535)(148,803)(148,803)
2202 P SG
2203 619 (72.825,252)(69,402,657)(3,422,595)1.739,470 (1.683.125)
2204
2205 Total Accum Deferred Income Tax B19 (2,332,31ll63)(2,191,772,364)(140,54,299)(41,692)(140,587,991)
2206 255 Accumulated Investment Tax Credit
2207 PTD S
2208 PTD ITC84 (1,745.297)(1.745,297)
2209 PTO ITC85 (3.044.242)(3.044,242)
2210 PTO ITC86 (1,479.759)(1,479.759)
2211 PTD ITC88 (222,248)(222.246)
2212 PTD ITC89 (486,772)(486,772)
2213 PTO ITC90 (315.906)(271.738)(44,168)(44,168)
2214 PTO 1ST (166,745)(166,745)
2215 Total Accumlated ITC 619 (7.294,222)(7,250,054)(44,168)(166,745)(210,14)
2216
2217 Total Rate Base Deductions (2.417,922,96)(2,273,958,655)(143,964,308)(2,975,719)(148,940,027)
2218
ROLLED-IN Page 9.36
Year-End
FERC 6US UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
2219
2220
2221 108SP Steam Pro Plant Accumulated Depr
2222 P S
2223 P SG (828.531.539)(782.891.896)(45.639,643)(45.639,643)
2224 P SG (936.120,976)(884,554,772)(51,566.204)(51,566.204)
2225 P SG (552,789,110)(522,338.733)(30.450,377)(792.318)(31,242.695)
2226 P SG (158,685.661)(149,944,465)(8.741.196)(8.741.96)
2227 617 (2,476.127.286)(2.339.729.866)(136.397,420)(792.318)(137.189,738)
2228
2229 108NP Nuclear Prod Plant Accumulated Depr
2230 P SG
2231 P SG
2232 .P SG
2233 617
2234
2235
2236 108HP Hydraulic Prod Plant Accum Depr
2237 P S
2238 P SG (150,429.735)(142.143.316)(8.286,19)(8.286,419)
2239 P SG (28,604.226)(27.028.563)(1.575.663)(1.575.663)
2240 P SG (59,853.861)(56.556,813)(3,297.049)(142,997)(3,40,045)
2241 P SG (12.661,842)(12.153,348)(708,494)(708,494)
2242 B17 (251.749,664)(237,882,039)(13,867.625)(142.997)(14.010.622)
2243
2244 1080P Other Production Plant. Accum Depr
2245 P S
2246 P SG (1.347.482)(1.273,256)(74,226)(74.226)
2247 P SG
2248 P SG (263.762.956)(249.233.579)(14,529.377)(583.034)(15,112.411)
2249 P SG (19.564.578)(18,486,863)(1.077.714)(1,077,714)
2250 B17 (284.675,015)(268.993,698)(15.681,317)(583,034)(16.264,352)
2251
2252 108EP Experimental Plant - Accum Depr
2253 P SG
2254 P SG
2255
2256
2257 Total Production Plant Accurn Depreciation 817 (3,012,551.966)(2.846,605.604)(165.94.362)(1.518,349)(167,46.711)
2258
2259 Summary of Prod Plant Depreciation by Factor
2260 S
2261 DGP
2262 DGU
2263 SG (3.012.551,966)(2.848,605,604)(165,946.362)(1,518.349)(167.464.711)
2264 SSGCH
2265 SSGCT -
2266 Total of Prod Plant Depreciation by Factor (3,012.551.966)(2.846,605,64)(165.946,362)(1.518.349)(1é.464.71)
2267
2268
2269 108TP Transmission Plant Accumulated Depr
2270 T SG (21.367,434)(21,367,434)
2271 T SG (21.354.659)(21.354.659)
2272 T SG 20,231.189)1,030,788)(21.261,976
2273 Total Trans Plant Atcurn DeprecIation 817 , 5 .2 1 .03 ,788 63.9 .0 9
ROLLED.IN Page 9.37
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
2274 108360 Land and Land Rights
2275 DPW S (5.731.128)(5,471.879)(259.247)(259,247)
2276 617 (5.731.126)(5,471,879)(259.247)(259,247)
2277
2278 108361 Structures and Improvements
2279 DPW 8 (13,581,278)(13,138.403)(442,875)(442,875)
2280 617 (13,581.278)(13,138,403)(442,875)(442,875)
2281
2282 108362 Station Equipment
2283 DPW S (207,834,133)(198.557.095)(9,277.038)(9,277,038)
2284 617 (207,834,133)(198,557,095)(9,277.038)(9,277.038)
2285
2286 108363 Storage 6attery Equipment
2287 DPW 8 (775.263)(775,263)
2288 617 (75,263)(775,263)
2289
2290 108364 Poles. Towers & Fixtures
2291 DPW 8 (472,497,456)(438,618.489)(33.878.967)(33.878.967)
2292 617 (472,497,456)(438,618.89)(33,878,967)(33.878,967)
2293
2294 108365 Overhead Conductors
2295 DPW 8 (257.576,586)(247.145,604)(10,430,983)(10,30,983)
2296 617 (257.576,586)(247.145,604)(10,30,983 )(10,430.983)
2297
2298 108366 Underground Conduit
2299 DPW S (121.003,027)(117.701.126)(3.301,901 )(3,301.901)
2300 617 (121,003.027)(117.701.126)(3.301.901 )(3,301,901 )
2301
2302 108367 Underground Conductors
2303 DPW S (279,736,871)(268,973,545)(10,763.326)(10.763.326)
2304 617 (279,736,871)(268,973.545)(10,763,326)(10,763,326)
2305
2306 108368 Line Transformers
2307 DPW S (361,323,647)(337,660,94)(23,663,153)(23,663,153)
2308 617 (361,323,647)(337,660,94)(23,663,153)(23.663,153)
2309
2310 108369 Services
2311 DPW 8 (163,299,910)(152.868,799)(10,431,110)(10,431,110)
2312 617 (163,299,910)(152,868.799)(10,431.110)(10,431,110)
2313
2314 108370 Metérs
2315 DPW 8 (84,175,634)(75,808,861 )(8.366,773)(8.366,773)
2316 617 (84.175,634)(75,808,861 )(8,366,773)(8,366,773)
2317
2318
2319
2320 108371 Installations on Customers' Premises
2321 DPW 8 (7.846,403)(7,709,414)(136.989)(136,989)
2322 617 (7,846,403)(7.709.414)(136,989)(136.989)
2323
2324 108372 Leased Propert
2325 DPW 8
2326 617
2327
2328 108373 Street Lights
2329 DPW 8 (28,660,733)(28,170,544)(490.188)(490,188)
2330 617 (28,660,733)(28,170,544)(490,188)(490,188)
2331
2332 108000 Unclassified Dist Plant. Acc! 300
2333 DPW 8
2334 617
2335
2336 10808 Unclassified Dist Sub Plant. Acct 300
2337 DPW 8
2338 617
2339
2340 108DP Unclassified Dist 8ub Plant. Acct 300
2341 DPW 8 730,582 729.334 1,248 1,246
2342 617 730.582 729,334 1,248 1,248
2343
2344
2345 Total Distribution Plant Accum Depreciation B17 (2,003,311,485)(1,891,870,183)(111,441,302)(111,441,302)
2346
2347 Summary of Distribution Plant Depr by Factor )
2348 8 (2,003,311.485)(1,891,870.183)(111,441.302)(111,441.302)
2349
2350 Total Distribution Depreciation by Factor B17 (2.003.311,485)(1.891.870,183)(111.441.302)(111 ,441302)
ROLLED-IN Page 9.38
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT OESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT AOJTOTAL
2351 108GP General Plant Accumulated Depr
2352 G-SITUS S (151,989,352)(141,794,438)(10,194,914)(10.194,914)
2353 PT SG (6,272,465)(5,926,947)(345,519)(345,519)
2354 PT SG (11,172,030)(10.556,619)(615,11 )(615,11)
2355 G-SG SG (46,253,779)(43,705,891 )(2,547,888)(2,547,888)
2356 CUST CN (6,625,150)(6,367.792)(257,358)(257,358)
2357 PTD SO (72,527,529)(68,615.254)(3.912,275)(3,912.275)
2358 P SE (339,900)(318,291)(21,609)(21,609)
2359 G-SG SG (33.094)(31,271)(1,823)(1.823)
2360 G-SG SG (2,331,547)(2,203,113)(128,433)(128,331
2361 B17 (297,544,846)(279,519,616)(18.025,230)(18,025,2301
2362
2363
2364 108MP Mining Plant Accumulated Depr.
2365 P S
2366 P SE (170,270,7501 (159,445,750)(10,825,000)(54,840)(10,879.840)
2367 B17 (170,270,750)(159..445,750)(10,825,000)(54,840)(10,879,840)
2368 108MP Less Centralia Situs Depreciation
2369 P S
2370 B17 (170.270,7501 (159,445,750)(10,825,000)(54,8401 (10,879,8401
2371
2372 1081390 Accum Depr - Capital Lease
2373 PTD SO B17
2374
2375
2376 Remove Capital Leases
2377 B17
2378
2379 1081399 Accum Depr - Capital Lease
2380 P S
2381 P SE B17
2382
2383
2384 Remove Capital Leases
2385 817
2386
2387
2388 Total General Plant Accum Depreciation B17 (467,815,596)(438,965,366)(28,850,230)(54,840)(28,905,071)
2389
2390
2391
2392 Summary of General Depreciation by Factor
2393 S (151,989,352)(141,794,438)(10,194,914)(10,194,914)
2394 DGP
2395 DGU
2396 SE (170.610,651 )(159,764,042)(10,846,609)(54,840)(10,901,450)
2397 SO (72,527,529)(68.615,254)(3,912,275)(3,912,275)
2398 CN (6,625,150)(6.367,792)(257,358)(257,358)
2399 SG (66,062,915)(62,423,841 )(3,639,074)(3,639,074)
2400 DEU
2401 SSGCT
2402 SSGCH
2403 Remove Capital Leases -
2404 Total General Depreciation by Factor (467,815,596)(438.965,366)(28,850,230)(54,840)(28.905.071 )
2405
2406
2407 Total Accum Depreciation - Plant In Service B17 (6,626,518,392)(6,257,327,216)(369,191,176)(2,603,977)(371,795,153)
2408 111SP Accum Prov for Amort-Steam
2409 P SG
2410 P SG
2411 818
2412
2413
2414 111GP Accum Prov for Amort-General
2415 G-5ITUS S (15,417,186)(15,417,186)
2416 CUST CN (2,453,306)(2,358,005)(95,300)(95,300)
2417 I-SG SG
2418 PTD SO (9,907,217)(9,372,803)(534,414)(534,414)
2419 P SE -
2420 B18 (27,777 ,708)(27,147,994)(629,715)(629,11)
2421
ROLLED-IN Page 9.39
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
2422
2423 111HP Accum Prov for Amort-Hydro
2424 P SG
2425 P SG
2426 P SG (13,027)(12,310)(718)(718)
2427 P SG (390,637)(369,119)(21.518)(21,518)
2428 618 (403,664)(381,429)(22,236)(22,236)
2429
2430
2431 1111P Accum Prov for Amort-Intangible Plant
2432 I-SITUS S (866,992)(130,826)(736,166)(736,166)
2433 P SG
2434 P SG (332,638)(314,315)(18,323)(18,323)
2435 P SE (1,011,087)(946,807)(64,280)(64,280)
2436 l-SG SG (42,153,361)(39,831,344)(2,322,017)(25,402)(2,347,419)
2437 l-SG SG (11,454,352)(10,823,389)(630,963)(630,963)
2438 I-SG SG (3,111,807)(2,940,393)(171,414)(171,414)
2439 CUST CN (89,511,348)(86,034,220)(3,77,128)(3,477128)
2440 P SG
2441 P SG (67,877)(64,138)(3,739)(3,739)
2442 PTO SO (250,449,855)(236,940,106)(13,509,748)(13,509,748)
2443 618 (398,959,316)(378,025,538)(20,933,778)(25,402)(20,959,180)
2444 111LP Less Non-Utilty Plant
2445 NUTIL OTH .
2446 (398,959,316)(378.025,538)(20,933,778)(25,402)(20,959,160)
2447
2448 111390 Accum Amtr - Capital Lease
2449 G-SITUS S (5,302,423)(5,302,423)
2450 P SG (1,390,857)(1,314,242)(76,615)(76,615)
2451 PTO SO 1,860,994 1,760,608 100,386 100,386
2452 (4,832,287)(4,856,057)23,770 23,770
2453
2454 Remove Capital Leae Amtr 4,832,287 4,856,057 (23,770)(23,770)
2455
2456 Total Accum Provision for Amortization B18 (427,140,689)(405,554,960)(21,585,729)(25,402)(21.11,131)
2457
2458
2459
2460
2461 Summary of Amortization by Factor
2462 S (21,586,600)(20,850,434)(736,166)(736,166)
2463 OGP
2464 OGU
2465 SE (1,011,087)(946,807)(64,280)(64,280)
2466 SO (258,496,078)(244,552,301 )(13,943,777)(13,943,777)
2467 CN (91,964,63)(88,392,225)(3,572,428)(3,572,428)
2468 SSGCT
2469 SSGCH
2470 SG (58,914,556)(55,669,249)(25,402)
2471 Less Capitl Lease 4,832,287 4,856,057
2472 Total Provision For Amortization by Factor 4 0,5,554,
Idaho General Rate Case
Factors December, 2010
Year End Factors
Page 10.1
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DECEMBER 2010 FACTORS
Idaho General Rate Case. December 2009
COINCIDENTAL PEAKS
F.
Month Day lime
Jan-10 25 19
Feb.10 4 8
Mar-10 30 8
Apr-10 1 8
May-10 18 15
Jun-10 24 15
Jul-10 19 16
Aug.10 26 15
Sep-10 9 15
Oct-10 4 19
Nov-10 24 18
Dec-10 15 18
MOnth
Jan-10
Feb-10
Mar-10
Apr-10
May-10
Jun-10
Jul-10
AU9-10
Sep-10
Oct-10
Nov-10
Dec-10
Month
Jen-10
Feb-10
Mar-10
Apr.10
May-10
Jun-10
Jul-10
Aug-10
Sep.l0
Oct-10
Nov-10
Dec.10
Month
Jan-10
Feb-10
Mar.l0
Apr-10
May.10
Jun-10
Jul-10
Aug-10
Sep-10
Oct-10
Nov-10
Dec-10
Month
Jan-10
Feb.l0
Mar-l0
Apr-10
May-10
Jun-10
Jul.10
Aug-10
Sep-10
Oct-10
Nov.10
Dec-10
Day
25
4
30
1
18
24
19
26
9
4
.24
15
Day
25
4
30
1
18
24
19
26
9
4
24
15
Day
25
4
30
1
18
24
19
26
9
4
24
15
Day
25
4
30
1
18
24
19
26
9
4
24
15
lime
19
8
8
8
15
15
16
15
15
19
18
18
,.,C";:,. .. '"METERED.t.QAQS (CP ............c:.'i
,u,.',,, ..r"J!Øi'FERC i." '.".. .. ... .....,.. :U f,ERC
CA OR WA E.WY Total UT 10 W.W'UT Total
158 2,867 722 975 3,437 406 237 28 8.02
153 2.528 751 1.018 3,144 416 211 27 8,221
145 2,315 669 983 2,914 399 237 16 7.661
131 2,132 585 966 2,819 415 210 30 7,257
142 1,816 636 934 3,590 503 228 24 7,848
148 1,964 678 1,003 4,197 613 218 43 8,821
153 2,257 750 1,019 4,525 664 228 39 9.595
150 2.301 727 1.008 4.45 538 226 44 9,395
134 2,068 652 946 4.084 447 223 34 8,553
121 1,964 610 949 3.048 406 238 23 7,336
139 2,231 696 1,031 3,515 443 266 29 8,322
157 2,408 736 1,067 3.709 467 252 35 8,796
1,729 26,650 8.212 11.899 43,26 5.718 2,774 372 100,407
(less)
Adlustments for Curtilments, Buv.Throuahs and Load No Longer Sered (Reductions to Load)
'~l¿K¡;;;tì1èi¡¡::ti!r~:t\i;~~~~!ß\a~!M¡'A¡;~o:n,,':Cf;f,),~~Wf,0k1tf~g¡~,,-fnå!tli:(Si&~¿r~tt:~_,-;':~?L;,F~3gf¡i~~im~:d,::CA OR WA E. WY UT 10 W. W' UT Total(88) (88)
(231)
(228)
(237)
(197)
(415)
(417)
(420)
(197)
(184)
(189)
(182)
(74)
1,055
(74)
1.616\
=555
equals
Time
19
8
8
8
15
15
16
i5
15
19
18
18
L,,::.,,".j..(;QtNCII:ENTALlE~I($eRVEDf\RQNt CONiPA'NY .RESQl;RCE$.'\(i,U
i''',' ';~~~:::'r'd~H:Y:"/':,-,,::;;,::,;:\\,:i:.'",:,:;,'1';'::;;~t':'i:~~:1'i',-NÖílifRC':;':i:;;;:),::1t.:~;i \d'ER :...-1
CA OR WA E.WY UT 10 W.W UT Total
158 2,667 722 975 3,349 406 237 28 8,514
153 2.528 751 1,018 3,144 416 211 27 8,221
145 2,315 669 983 2,914 399 237 16 7,661
131 2.132 585 966 2,819 415 210 30 7,257
142 1,816 636 934 3,590 503 228 24 7,88
148 1,964 678 1.003 3,966 429 218 43 8,407
153 2,257 750 1,019 4.297 475 228 39 9,178
150 2,301 727 1,006 4,208 356 226 44 8,975
134 2,068 652 946 3,886 447 223 34 8,366
121 1,964 610 949 3,048 406 238 23 7,336
139 2,231 696 1,031 3,515 443 266 29 8,322
157 2,408 736 1,067 3.635 467 252 35 8,722
1.29 26.650 8.212 11,899 42.370 5.163 2.774 372 98,797
+ plus
Adjustments for Ancllary Service Contrcts Including Reserves (Addltlns to Load) and nonallton of Irrigaton and Mon
T'~/f/ -'--,'Hól:rERtl:"~;~:_~.f!',~.:~,:;\\i\Ù;~v \-/~\F'i:t~~~~h' ~:j-~FER(h~~:.' ¡::~--(~-~-.-:. "..:..lime CA OR WA E. WY UT 10 W. W U Total
19
8
8
8
15
15
16
15
15
19
18
18
--equals
lime
19
8
8
8
15
15
16
15
15
19
18
18
I
......... ...l.'QAi)$fORJURISDICTI()ti¡&L' ALI,()CArION(GP) .... ........'I
I ..Nori-FERC -;e'c-:';.:.,,:.FERC .I
CA OR WA E.WY UT 10 W.W~U1 Total
158 2,667 722 975 3,349 406 237 28 8,514
153 2,528 751 1,018 3,144 416 211 27 8,221
145 2.315 669 983 2,914 399 237 16 7,661
131 2,132 585 966 2.819 415 210 30 7,257
142 1,816 636 934 3,590 503 228 24 7,84
148 1,964 678 1,003 3,966 429 218 43 8,407
153 2,257 750 1,019 4,297 475 228 39 9,178
150 2,301 727 1,008 4.208 356 226 44 8,975
134 2.068 652 946 3,886 447 223 34 8,356
121 1,964 610 949 3,048 406 238 23 7.336
139 2,231 696 1,031 3,515 443 266 29 8,322
157 2,408 . 736 1,067 3,635 467 252 35 8,722
1.29 26.50 8,212 11,899 42.370 5,163 2,774 372 98,797
Page 10.13
ALLOCATIONS USING
PROFORMA LOADS
DECEMBER 2010 FACTORS
Idaho General Rate Case - December 2809
ENERGY
Year Month E.10 W.WY
2010 Jan 83,40 1,317.180 417.820 685.090 2.091,644 293.020 168.00 20.034
2010 Feb 70.500 1.176.930 359.160 630.56 1.852,104 245.80 137,35 16,674
2010 Mar 73.320 1.224.96 362,450 678.80 1.887.261 268.860 172.790 17.901
2010 Apr 71.50 1.103.860 331.570 627,440 1.88.547 262.230 145,690 17.807
2010 May 77,430 1.105.20 337.770 670.110 1,932.851 314.580 170.770 17,151
2010 Jun 80,930 1.076.30 333,250 622,640 2.036.210 359.680 154.080 19,90
2010 Jul 87.820 1.205.90 38.810 669,960 2.397.00 414.870 164.660 23.94
2010 Aug 83,470 1.91.060 367.570 671.940 2.344.784 371.140 164,410 23,86
2010 Sep 72.540 1.078.670 352.770 637,150 2.00,524 291.080 158.38 18.364
2010 Oct 68.70 1.109.380 367.210 678.10 1.891.210 267.470 172,480 17,490
2010 Nov 71.390 1.187.280 378,410 687,510 2.049.882 261.240 179.260 '16.242
2010 Dec 82,270 1.357.680 427.930 708,350 2.20,465 277880 173.120 18.775
923,430 14.134.240 4,440.720 7.967.560 24.395.787 3.628.130 1.961,490 .147
(less)
Adjustments for Curtilments. BUY. Throughs and Load No Lonoer servd (Reducfons 10 Loadlr. , :,'.NoIlFERO.....c -.
Year Mon CA OR WA E,WY UT 10 W-:Y lJ
2010 Jan (6.124)
2010 Feb
2010 Mar
2010 Apr
2010 May
2010 Jun (4.281)
2010 Jul (5.815)
2010 Aug (5.736)2010 Sep (3.640)2010 Oct
2010 Nov
2010 Dec (4,792)
30,387
Vear Month2010 Jan2010 Feb2010 Mar2010 Apr2010 May2010 Jun2010 Jul2010 Aug2010 Sep
2010 Oct2010 Nov
2010 Dec
Year Month2010 Jan2010 Feb
2010 Mar2010 Apr
2010 May
2010 Jun2010 Jul
2010 AU92010 Sep
2010 Oct2010 Nov2010 Dec
L~J, '~:. ~':'.': ::,": .(l." ;.:- .\",.
ala
5.056.694
4,472,484
4,667.641
4.331.087
4.608.531
4.663,420
5.324.714
5.214.374
4,594,414
4.555.130
4.814.972
5.147.895
57,451,357
i
Totai
(6.124)
(4,281)
(5.815)
(5.736)
(3.640)
(4.792)
30.387
equals
1.:..'..'::.\.:.....;-:.:):..:. . l(¡ADS Si:RVi:DFRQMÇOMl'.ANYRESOVRCES1~C
i...,'...:'.-"",,"...,. FfERl,:. .:. ,.' ,..,:
CA OR WA E.WY UT ID W.WY 'VT Tolal
83.440 1.317.180 417.820 685,090 2.085.521 293.020 168.500 20.034 5.050.571
70.50 1.176.930 359.160 630.560 1.852.104 245.880 137.350 16.74 4,472,484
73.320 1,224.960 362,450 678.000 1.887.281 268,860 172.790 17,901 4,667.641
71.750 1.103.860 331.570 627,440 1.788.547 262,230 145.690 17.807 4.331.087
77.430 1.105.020 337.770 670.110 1.932.851 314.580 170.770 17.151 4.608.531
80.930 1.076.430 333.250 622.640 2.031,929 359.880 154.080 19.900 4.659.139
87.820 1.205.590 38.810 669,960 2.391.190 414.870 164.680 23.944 5.318.900
83,470 1.191.080 387.570 871.940 2.339.049 371.140 164,410 23.864 5.208.639
72.540 1.078.670 352.770 637.180 2.000.185 291.080 158,380 18.364 4.590.775
68.570 1.109.380 367.210 678.810 1.891.210 267,470 172,480 17,490 4.555,130
71.390 1.187.280 378,410 687.510 2,049.882 261.240 179.260 16.242 4.814.972
82,270 1.357.880 427.930 708.350 2,115.672 277.89 173.120 18.775 5.143.102
923.30 14.134.240 4.440.720 7.967.560 4.365.399 3.828.130 1.961,490 -2?I\.f4;57,4 0.969
ID
646
515
29538
389
1.567
5,484
5.519
1,507
1,685
3,482
2.782
24,255
W.WY UT Total
1,1681.00
677
756
783
2.067
5.837
5.954
1.777
2,051
3.699
3.086
28.858
equals
L.::~\'\" :;:;:::;:ii';~ ';:':'~;::;"iJ,jfi/\"". ".q:i:O:.Ai)S F(i:JtlRISPICTIONAI . ,AWlOCA'IN\lMWJ'I ...:.":.3: ...::.....""":"'. 1
n¡FERC:"". ..: C,',¡;'::"/:".':"',.,:;,.,
i.A OR WA E.WY UT 10 W.W~U-alai
83,440 1.317.180 417.820 685;090 2.086.043 293.666 168.50 20.034 5.51.39
70.50 1.176.930 359.160 630,560 1.852.590 246.395 137.350 16.674 4,473,486
73.320 1.224.960 362.450 678.000 1.887.643 269.155 172.790 17.901 4.668.318
71.50 1.103.860 331.570 627,440 1.788.919 262.615 145.690 17.807 4.331,844
77,430 1.05.020 337,770 -670.110 1.933,245 314.969 170.770 17.151 4.609,314
80.930 1.076,430 333.250 622.640 2.032,429 361,447 154.080 19,900 4.661.206
87.820 1.205.590 38.810 669.960 2.391.543 420.354 164.660 23,94 5.324.737
83,470 1.91.060 387.570 671.940 2.339,484 376.659 164,410 23.864 5.214.593
72.540 1.078.670 352.770 637.150 2.00,455 292.587 158.380 18.38 4.592.552
68.570 1.109.380 367.210 678.810 1.891.576 269.155 172,480 17.490 4.557,181
71.390 1,187.280 378,410 687.510 2.050.099 264.722 179.260 16.242 4.818.872
82.270 1,357.880 427.930 708.350 2.115.976 280.662 173.120 18.775 5.146.168
923,430 14.134.240 4,440.720 .967.560 24,370.002 3.652.385 1.961,490 22,147 57,449.828
Page 10.14
ALLOCATIONS USING
PROFORMA LOADS
DE
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DECEMBER 2010 FACTORS
IDAHO
ANNUAL EMBEDDED COSTS
Period Ending Deceber 2009
YEAR END BALNCE
Company Owned Hydro. West
Account . Descnptlon Amount Mwh $/Mwh Difrential Reference
535.545 Hydro Operation & Maintenance EXpense 29.555,140 Page 2.7, West only
403HP Hydro Dereciation Exense 11.437,559 Page 2.15, West only
4041P Hydro Relicenslng Amortzation 2,720,447 Page 2.16, West only
T olal West Hydro Operating Expense 43,713,146
330- 336 Hyd Elecric Piant In Service 508.972.406 Pag 2.23. West oniY
302 & 182M Hydro ReHcensing 100.861.734 Page 2.29, West only
108HP Hydro Accumulated Depreiation Reerv (211.565.221)Page 2.36. West only
1111P Hydro Relicensing Accumulated Reserv (11.454.352)Page 2.39. West only
154 Matelials and Supplies (1.860)Page 2.32. Wes only
West Hydr Net Rate Bas..386,812,708
Pre-tax Retum 11.74%
Rate Base Reveue Requirement 45,429,071
Annual Embeddd Cost
W..st Hydro-Electc Resource 89,142,217 3.777.632 23.60 (66.096,986) MWh from GRID
Mid C Contrct
Account Description Amount Mwh $/Mwh Difrential Refrence
555 Annual Mid.C Contracts Costs 23.424.094 1.170,156 20,02 (24.660.114) GRID
Grant Reasonable Port (15,523.615)(15.523.615) GRID
7,900,479 (40,183.729)
Qualifid Facilti
Account Descrlptlon Amount Mwh $/Mh Difrential Refence
555 Utah Annual Oualifed Facilties Costs 25.157.082 388.084 64.82 9.209.886
555 Oreon Annual Oualifed Facilti Cos 39.578,386 275.120 143.86 28.273.117
555 idaho Annual QualiflO Facilities Costs 4.135.847 75,649 54.67 1.027.06
555 WYU Annual Ouallfed Facilities Cots
555 WYP Annual Qualifed FacHities Costs 723.797 11.373 63.84 286.457
555 C8lfora Annual Oualifiad Facilites Costs 3.958.769 33.443 118.37 2.584,525
555 Washingto Annual Quallfed Facilties Costs 1.920.742 13.035 147.35 1.385.106
Total Qualffled Facilties Costs 75.474,423 796,704 94.73 42,736,158 GRID
All Oter Generaton Resources
(Excl. West Hyro. Mid C, and OF)
Account Descnplion Amount Mwh $/Mwh Refrence
500.514 Stem Opetion & Maintenance EXpense 991,136.928 Page 2.5
535.545 East Hydro Operation & Mainteance Expense 9,183,739 Page 2.7. East only
546- 554 Other Generation Operation & Maintenance Expese 515.121.883 Page 2.8
555 Other Purchad Power Contract 492,791.55 GRID less QF and Mid.C
40910 Renewable Energ Producton Tax Credit (113,344,72)Page 2.20
4116 502 Emission Alance (3.518,808)Page 2.4
458 James River / Litle Mountain Ofet (8.822,101)James Rier Ad) (Tab 5)
456 Green Tag Revenues (91.779,696)Green Tag (Tab 3)
403SP Steam Depreiation Exense 124,729.286 Page 2.15
403HP East Hydro Depreation Expese 4.457.733 Page 2.15. East only
4030P Other Genertion Depreiation Expense 116.255.399 Page 2.15
403MP Mining Depreciation Expense 0 Page 2.15
4041P East Hydro Relicnsing Amorti 327,190 Pag 2.16. East only
406 Amorzation of Piant Acquisition Costs 5.79.353 Page 2.17
Totl All Other Operating Expenses 2,042,017,589
310- 316 Steam Elec Piant In Serce 5,896.040.607 Page 2.21
330- 336 East Hydro Elec Plant in Serce 125.067.529 Page 2.23. East only
302 & 186M East Hydro Reicslng 9,841,735 Page 2.29, East only
340- 346 Other Elecc Plant in Serce 3.316.336,463 Page 2.24
399 Mining 490.55.633 Page 2.28
106SP Steam Accumulated Depreciation Resere (2,490,510.850)Page 2.36
1080P Other Generation Accumulated Depreciation Reserv (295,259.285)Page 2.36
108MP Other Acculated D.~clation Resere (17.133.356)Page 2.38, East only
106HP East Hy Accumulated Depreiation Reserve (42,780,373)Page 2.36. East only
1111P East Hyro Relicenslng Accumulated Reserv (3,444,445)Page 2.39, East only
114 Elecric Plant Acqulslton Adjustment 157.193.780 Page 2.31
115 Acculated Proision Acquisition Adjustment (96.326.873)Page 2.31
151 Fuel Stock 195.574.734 Page 2.32
253.16-253.19 Joint Owner we Deposit (4,385.50)Page 2.32
253.98 S02 Emission Allowancs (37,786,481)Page 2.34
154 Materials & Supplies 81,516.215 Page 2.32
154 East Hyd Materals & Supplie
T olal Net Rat Base 7,130.498,781
Pre-tax Return 11.74%
Rate Base Reveue Requirement 837,438,714
Annual Embedded Cost
All Oter Generaüon Resources 2.879,456,303 70,073.166 41.09 MWh from GRID
T olal Annual Embedded Costs 3,051,973,42 75.817,858 40.25
Page 10.19
ALLOCATIONS USING
PROFORMA LOADS
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CONFIDENTIAL
Case No. PAC-E-I0-07
Exhibit No.3
Witness: Steven R. McDougal
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
CONFIDENTIAL
Exhibit Accompanying Direct Testimony of Steven R. McDougal
Propert Tax Calculation
May 2010
THIS EXHIBIT IS CONFIDENTIAL
AND IS PROVIDED UNDER
SEPARATE COVER
Case No. PAC-E-I0-07
Exhibit No.4
Witness: Steven R. McDougal
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Steven R. McDougal
LGAR Calculation
May 2010
Rocky Mountain Power
Exhibit No.4 Page 1 of 1
Case No. PAC-E-10-07
Witness: Steven R. McDougal
Unbun~led Production Revenue Requirement (Excluding NPC)
PAC-E-10-07
Unbundled Production Revenue Requirement
DescriDtion Amount Source
1 Production - Return On Investment 882,867,786 JAM Tab ECO
2 Production - Exoense 2,169,105,637 JAM Tab ECO
3 Production - Revenues (822,172,983)RAM Tab 5, Adj No 1
Production Revenue Requirement 2,229,800,439 (Line 1 + Line 2 - Line 3)
System Load 57,460,901 RAM Tab 5, Adj No 1
Production $ per MWH $38.81
PAC-E-10-07
Unbundled Production Revenue requirement (Excluding Net Power Costs)Descri tion Amount Source
1 Production - Return On Investment 882,867,786 JAM Tab ECO
2 Production - Ex ense 2,169,105,637 JAM Tab ECO
3 Production - NPC Expenses (1,891,874,298) RAM Tab 5, Adj No 1
Production Revenue Requirement
Excludin NPC
S stem Load
-Production $ per MWH
PAC-E-08-07
Unbundled Production Revenue Requirement (Per IPUC Order No.30715)
DescriDtion Amount Source
1 Production.- Return On Investment 615,420,689 JAM Tab ECO
2 Production - Exoense 3,624,067;686 JAMTabECO
3 Production - Revenues (2,242,830,255)RAM Tab 5, Adj No 1
Production Revenue Requirement 1,996,658,120 (Line 1 + Line 2 - Line 3)
System Load 58,052,638 RAM Tab 5, Adj No 1
Production $ per MWH $34.39
PAC-E-08-07
Unbundled Production Revenue Requirement (Excluding Net Power Costs)Descri tion Amount Source
1 Production - Return On Investment 615,420,689 JAM Tab ECO
2 Production - Ex ense 3,624,067,686 JAM Tab ECO
3 Production - NPC Expenses (3,224,837,687) RAM Tab 5, Adj No 1
Production Revenue Requirement
(Excluding NPC)
S stem Load
Production $ per MWH