20110527McDougal Di.pdf

RECEIVED
2UII NAY 27 AM 10: 43
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE
APPLICATION OF ROCKY
MOUNTAIN POWER FOR
APPROVAL OF CHAGES TO ITS
ELECTRIC SERVICE SCHEDULES
AND A PRICE INCREASE OF $32.7
MILLION, OR APPROXIMTELY
15.0 PERCENT
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) CASE NO. PAC-E-l1-12
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) Direct Testimony of Steven R. McDougal
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ROCKY MOUNTAIN POWER
CASE NO. PAC-E-l1-12
May 2011
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3 A.
Please state your name, business address and present position with Rocky
Mountain Power (the "Company"), a division of PacifCorp.
My name is Steven R. McDougal, and my business address is 201 South Main,
4 Suite 2300, Salt Lake City, Utah, 84111. I am curently employed as the Director
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 Accountig from Brigham Young University in 1982. In addition to my
formal education, I have also attended various educational, professional, and
electrc industr-related seminars. I have been employed by Rocky Mountain
Power or its predecessor companies since 1983. My experience at Rocky
Mountain Power includes various positions within regulation, fiance, resource
planning, and internal audit.
What are your responsibilties as director of revenue requirements?
My primary responsibilties include overseeing the calculation and reporting of
the Company's regulated earnings or revenue requirement, assurg that the inter-
jurisdictional cost allocation methodology is correctly applied, and explaining
those calculations to regulators in the jursdictions in which the Company
operates.
Have you testified in previous regulatory proceedings?
Yes. I have provided testimony before the Idaho Public Utilities Commission, the
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1 Utah Public Service Commission, the Washington Utilities and Transporttion
2 Commission, the California Public Utilities Commission, the Oregon Public
3 Utilities Commission, the Wyoming Public Service Commission, and the Utah
4 State Tax Commission.
5 Purpose and Overview of Testimony
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What is the purpose of your testimony in this proceeding?
My direct testimony describes the calculation of the Company's Idaho revenue
requirement and the rate relief requested, based upon the Company's cost of
service fiing. Specifically, I provide testimony on the following:
. Calculation of the $32.7 milion retail revenue increase requested in this
case, representing the increase over curent rates required for the
Company to recover the costs incured to serve Idaho customers;
. Inter-jursdictional allocations, including utilization of 2010 Protocol and
treatment of Idaho's Irrgation Load Control Program costs and other
Class 1 demand side management ("DSM") costs;
· A description of the Test Period proposed in this case, including the
treatment of rate base and jursdictional loads;
. The results of operation for the Test Period, demonstrating that under
curent rates the Company wil ear an overall retu on equity ("ROE")
in Idaho of 5.3 percent, which is significantly below the retu on equity
requested in this case and the curent authorized retu; and
. Calculation of the Load Change Adjustment Rate ("LCAR") based on
costs in this fiing for use in the Energy Cost Adjustment Mechanism
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1 ("ECAM").
2 In addition to supporting the Company's revenue requirement, I discuss a number
3 of items that were addressed by the Commission in Case No. PAC-E-1O-07 (the
4 "2010 General Rate Case") and explain their treatment in this case. I also describe
5 two accounting changes included in the Company's fiing: (1) elimination of
6 captive insurance coverage, replaced with self-insurance accruals on a state
7 specific basis; and (2) accelerated depreciation of certain hydro generation
8 facilities on the Klamath river. My testimony is accompanied by various
9 supporting exhibits including the results of operations for the Company's
10 proposed 2011 test period based on calendar year 2010 data, adjusted for known
11 and measurable changes through December 31, 2011.
12 Revenue Increase
13 Q.What is the revenue increase necessary to achieve the requested return on
14 equity ("ROE") in this case?
15 A.Utilizing Dr. Samuel C. Hadaway's recommended ROE of 10.5 percent produces
16 an overall Idaho revenue requirement of $250.9 milion. When compared to retail
17 revenue at present rates an overall revenue increase of $32.7 milion is needed for
18 the Company to achieve its recommended retu. Exhibit NO.2 also shows that
19 without a rate increase Rocky Mountain Power wil earn an ROE of 5.3 percent in
20 Idaho durng the Test Period. This retu is far less than the 9.9 percent authorized
21 by the Commission in the 2010 General Rate Case and the 10.5 percent ROE
22 requested in this case.
23 Idaho's jurisdictional revenue requirement is determined based on the
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2010 Protocol allocation methodology, which is curently being considered by the
Commission. Exhibit No. 1 provides a summary of Idaho-allocated results of
operations for the Test Period, and details supporting the revenue requirement by
FERC account are provided in Exhibit No.2.
Please explain the main drivers causing the need for a rate increase.
Two main drvers are causing the need for a revenue increase in this case: net
power costs and capital investment. As a regulated utility the Company must
serve existing, and reasonably anticipated customer loads. It must also comply
with environmental and other regulatory and statutory requirements regarding
production and transmission facilities. The actions that are taken by the Company,
in this regard, are guided by the standard of "risk-adjusted least-cost," over the
term of the action or investment. This means that the Company wil weigh all
legally mandated requirements against its obligation to provide service to the
greatest extent possible at the least cost.
Company witness Mr. Gregory N. Duvall describes the increases in
system-wide net power costs. The Company's application seeks to increase net
power costs from $1.025 bilion to $1.312 bilion, which wil also become the
base net power costs tracked in the Company's ECAM in the futue. Company
witness Mr. Darrell T. Gerrard testifies regardig the transmission investments
that have been made to serve customers. Company witnesses Ms. Cathy S.
Woollums and Mr. Chad A. Teply testify regarding significant generation
resource investments that have been required to satisfy environmental
requirements as well as investments that have been made to improve the
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I effciency of some units. My testimony addresses the revenue requirement impact
2 of these major projects and that of other investments across the Company.
3 Inter-jurisdictional Allocations
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What methodology did the Company use to calculate the Idaho-allocated
revenue requirement in this case?
The Company's requested price increase is calculated using the 2010 Protocol
inter-jurisdictional allocation that is curently before this Commission for
approval in Case No. PAC-E-10-09 (the "2010 Protocol Case"). The 2010
Protocol contains proposed amendments to the Revised Protocol resulting from
collaboration with multiple stakeholders through the Multi-State Process ("MSP")
Standing Committee, the group tasked with evaluating the continued use of the
Revised Protocol for setting rates.
What is the status of the Company's application for approval of the 2010
Protocol?
The Company fied its application on September 15, 2010, and the Case remains
open for Commission consideration. On March 30, 2011, Commission Staff fied
comments supporting approval of the 2010 Protocol, with the condition that the
Idaho Irrgation Load Control Program be treated consistent with the
Commission's order in the Company's 2010 General Rate Case.!
The Company fied reply comments on April 15, 2011, agreeing to the
Staff position, and the Company's fiing in this general rate case is made
consistent with Staffs comments. However, because the Commission has not yet
¡Monsanto also fied comments on March 30,2011.
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approved the 2010 Protocol, the Company's fiing in this case may need to be
updated to reflect the final outcome of the 2010 Protocol Case.
What are the direct impacts on this case related to the 2010 Protocol?
There are three main impacts in this case. First, the scope of the Embedded Cost
Differential ("ECD") is reduced and is now a fixed amount rather than changing
with each set of results. Second, seasonal allocation of certin resources is
eliminated. Third, state income taxes are calculated for each jurisdiction using the
weighted statutory state tax rate rather than allocated using the Income Before
Tax ("IBT") allocation factor. As agreed to in the Company's reply comments in
the 2010 Protocol Case, Tabs 11 and 12 of Exhibit No.2 provide the test period
results using the Revised Protocol and Rolled-In allocation methodology for
comparison puroses.
Please describe the treatment of Class 1 DSM programs in this rate case.
In this case, the Company is treating all Class 1 DSM programs consistent with
Order No. 32196 from the 2010 General Rate Case, wherein the Commission
ruled that the costs associated with the Idaho Irgation Load Control Program be
system allocated. The Company curently rus three programs that are classified
as Class 1 DSM programs: the Idaho Irrgation Load Control Program, the Utah
Irrgation Load Control Program, and the Utah Cool Keeper program. In previous
Idaho filings, the Company treated these programs as situs resources to their
respective state.
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Please describe the treatment of the Company's Class 1 DSM programs
proposed as part of the 2010 Protocol methodology.
As part of the Company's 2010 Protocol filing, and consistent with the filings in
Utah, Oregon and Wyoming, the Company proposed treating all Class 1 DSM
programs as situs, identical to their treatment under the previously approved
Revised Protocol. However, Staffs comments in that Case state that "to be
consistent with Order No. 32196 in Case No. PAC-E-1O-07, Staff recommends a
deviation be included in the Idaho Order for the system allocation of these costs."
Thus, the Company is treating all Class 1 DSM programs, including the Idaho
Irgation Load Control Program, as system resources in this filing.
Have other states agreed to treat Class 1 DSM programs as system
resources?
No. Commission Staff has raised this issue to the MSP Standing Committee, and
the issue is being discussed between the states. Company filings in other states
continue to treat Class 1 DSM programs as situs DSM programs pending a
resolution of the issue. However, as par of the 2010 Protocol settlements in
Oregon and Wyoming, language was included referrg to the ongoing MSP
discussions on the topic. The Wyoming 2010 Protocol stipulation states:
The Paries agree that the emerging issues related to the allocation
of Class 1 DSM programs are not yet ripe for Commssion action.
The Paries agree that additional analysis and discussion of these
issues should be underten in the MSP Standing Committee
workgroup, and the Parties wil endeavor to paricipate in the
workgroup efforts to the extent possible, subject to the availability
of resources. The Paries shall encourage the workgroup to develop
a proposed resolution on these issues by the next MSP
Commissioners' Forum. The Paries understand that the Company
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may make a subsequent fiing with the Commission to address this
discrete issue.2
Where is the system treatment of Class 1 DSM programs reflected in the
Company's revenue requirement calculation?
There are two components of the Class 1 DSM programs that are reflected in the
Company's revenue requirement, the costs and the benefits of the programs. The
costs of the Class 1 DSM programs consist of the administrative costs of ruing
the program and the credits paid to the paricipants of the program. On page 4.4 of
Exhibit No.2 these costs are shown to be included in the results of operations on
a system ("SG") factor. On an actual basis, the benefits of the Class 1 DSM
programs occur in the load reductions by state as a result of program operation.
The 2010 coincident peaks in the filing were adjusted to reflect system treatment
of the load curilments from the Class 1 DSM programs, i.e. jursdictional load
does not include reductions in load caused by operating the programs in 2010.
Reductions in peak loads due to the programs operating at time of system
coincident peak were added back to the relevant jursdictions so that the
jursdictions do not receive the full benefits of the program while other states pay
for the costs. The calculation of the coincident peaks can be viewed in Exhibit No.
2 on page 10.13. Furher discussion regarding the loads used in this fiing is
provided later in my testimony.
2Wyoming Public Service Commission Docket No. 20000-381-EA-1O, Record No. 12624, Stipulation and
Agreement paragraph 21, March 25, 2011
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1 Test Period
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What test period did the Company use to determine revenue requirement in
this case?
The Company used the historical results of operations for the 12-month period
ended December 31, 2010, adjusted for known and measurable changes through
December 31, 2011 (the "Test Period"). As I wil discuss later in my testimony,
rate base is included using the end of year balances.
Is the Test Period in this case consistent with test periods used by the
Company in previous Idaho general rate cases?
Yes. The Test Period is prepared in a manner that is consistent with past
Commission practice and the Company's general rate cases filed previously,
includig the Company's last two general rate cases, Case Nos. PAC-E-08-07 and
PAC-E-I0-07. The Company uses historical data and adjusts it for known events
and costs or normalizes the data to reflect a test period that is as reflective as
possible of the rate effective period given Idaho test period treatment.
What overriding principle guided the Company's development of the Test
Period in this case?
The primary objective in determining a test period is to develop normalized
results of operations which best reflect the operating conditions during the time
that new rates wil be in effect (the "rate effective period"). Because Idaho has
predominantly relied on historical test periods for setting rates, the Company used
historical data with normalizing adjustments through December 2011 to reflect as .
closely as possible the rate effective period. Aligning the Test Period and rate
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effective period is crucial in an environment of rapidly expanding rate base and
increasing net power costs in order to adequately capture the conditions that the
Company wil experience in providing safe and reliable electrcal service durg
the time that service wil actually be provided. To better align the Test Period
with the rate effective period, and consistent with past cases and Commission
treatment, the Company has calculated rate base on an end-of-period basis,
including actual rate base at December 31,2010, plus major capital additions that
wil be in service by December 31, 2011, reflected at the additions' full cost.
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.
Does the method the Company used to calculate loads difer from the
treatment used in the 2010 General Rate Case?
Yes. In its 2010 General Rate Case, the Company found that the metered loads
reflected abnormal operating conditions that occured in the 2009 calendar year.
Specifically, a sharp reduction in irrgation and tariff contract load that was not
weather related was distorting the loads. Due to this abnormality, loads were
calculated using a forecasted level to better reflect the ongoing load the Company
expected to serve durg the rate effective period.
Is this abnormality an issue in the metered loads used in this case?
No. The unadjusted loads in this case do not reflect such abnormal operating
conditions as described above. For this reason, the Company used actul metered
loads, adjusted for special contract curailments, Class 1 DSM programs and
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1 weather in its request.
2 2010 General Rate Case, Order No. 32196
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Please describe how the Company reflected the Commission's ruling in
Order No. 32196 from the 2010 General Rate Case in this filing.
Most directives from the Commission's Order are reflected thoughout the
Company's request. The treatment ofa few of those items is highlighted below:
Irrigation Load Control Program Allocation - As described earlier, the Idaho
Irrgation Load Control Program is treated as a system resource.
Uncollectible Revenues - Consistent with the Commission's Order, the
Company adjusted its actul 2010 uncollectible expense to reflect a three-year
historical average. The details of the adjustment are shown in Exhibit No. 2 on
page 4.17.
Outside Services Expense -The Company adjusted the 2010 outside services
expense to a three-year historical average consistent with the Commission's
Order. The calculation can be found in Exhibit No.2 on page 4.18.
Pension Expense - As directed by the Commission, the Company used a three-
year average of cash contributions to the pension plan. The details of the
calculation are shown on page 4.16 of Exhibit No.2.
Supplemental Executive Retirement Plan ("SERP") Costs - In accordance
with the Commission's Order, the Company's request does not contain any costs
related to SERP. The removal of these costs can be viewed in Exhibit No.2 in the
Company's Wage and Employee Benefits Adjustment on page 4.3.4 and the
MEHC Management Fee Adjustment on page 4.10.
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Is this a complete list of the items from the Commission's Order that were
implemented in this Application?
No. Several other adjustments ordered by the Commission are included and noted
throughout Exhibit No.2.
Were there any items addressed by the Commission in its Order in the 2010
General Rate Case that the Company did not reflect in this Application?
Yes. A few of the items that were addressed by the Commission in the 2010
General Rate Case are not implemented in the Company's Application. For these
specific items, the Company respectfully requests the Commission reexamine
these particular issues within the context of this general rate case and additional
evidence being offered by the company. The impact that each item would have on
the Company's request is provided in Tab 9 of Exhibit NO.2. Each of these items
is listed below with a brief discussion or reference to the appropriate Company
witness.
Idaho Disconnect Policy - The Company's Idaho disconnect policy is addressed
in the direct testimony of Company witness Ms. Barbara A. Coughlin.
Wage Increases - The Company's costs associated with wage increases are
discussed in the direct testimony of Company witness Mr. Erich D. Wilson.
Populus to Terminal - The Populus to Terminal transmission project is
discussed in the direct testimony of Company witness Mr. Gerrard.
Coal Pile Inventory - This topic is discussed in detail in the direct testimony of
Company witness Ms. Cindy A. Crane.
MEHC Management Fees - In 2010, the Company booked approximately $7.5
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1 millon to regulated accounts for the MEHC management fee. This amount
2 includes approximately $200k for SERP costs and $1.9 milion related to the
3 Anual Incentive Plan ("AlP") costs paid to employees of PacifiCorp affliates
4 and biled to PacifiCorp through the MEHC management fee. In the Company's
5 2010 General Rate Case, the Commission approved Staffs adjustment to remove
6 costs associated with both SERP and AlP from the MEHC management fee. In
7 this fiing, the Company removed the SERP from the MEHC management fee as
8 shown in Exhibit NO.2 on page 4.10, but the Company included the AlP in the
9 MEHC management fee for the Test Period. Company witness Mr. Wilson
10 provides fuher support for including these costs in results. The impact of the AlP
11 as included in the MEHC management fee is shown in Exhibit No 2. on page 9.0.
12 Accounting Changes
13 Q.Please explain the Company's proposed treatment of property and liabilty
14 insurance.
15 A.Obtaining insurance though a captive insurance policy at curent rates is no
16 longer an option. The transaction commitment to . maintain captive insurance
17 expired at the end of 2010 and the curent policy expires on March 21,2011. The
18 captive coverage wil be replaced with self-insurce coverage for third-part
19 liabilty, transmission and distrbution ("T&D") propert, and non-T&D propert.
20 This eliminates the expense for captive insurance premiums and instead provides
21 an accrual to state specific self-insurance reserves. These self insurance reserves
22 wil cover certain Idaho allocated O&M related damages. Capital related damages
23 wil be recovered as projects are added to rate base, consistent with other capital
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investments.
What level of coverage was provided by the captive insurance?
The coverage under the captive varied by category:
. Excess liability insurance provided indemnity for amounts the Company is
legally obligated to pay for damages due to bodily injur, personal injur
or propert damage. The captive covered $750,000 per occurrence, in
excess of a $250,000 deductible. Commercial insurance covered $175.0
millon per occurence after a deductible of$l milion.
. T &D propert damage insurance covered propert damage to overhead
transmission and distrbution lines related to both O&M and capital
events. The first $25,000 damages per event were defined as a deductible
and were allocated to O&M and capitaL. The captive then covered $10.0
milion anually in excess of an annual $5.0 milion aggregate deductible
(over and above the $25,000 per-event deductible). There was no
incremental commercial insurance for T &D propert damage.
. Non- T &D propert damage covered all risks of direct physical loss or
damage including boiler explosion, machinery and electrcal breakdown,
flood and eartquake. The captive covered $6.0 milion per occurence, in
excess of a $1.5 milion deductible. Commercial insurance covered $400
milion per occurence after a deductible of$7.5 millon.
When did the change from captive insurance coverage to self insurance take
22 effect?
23 A.The Company's captive insurance coverage expired March 21, 2011. Coverage
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curently provided by commercial camers wil continue, and the related
premiums are included in this case at actul levels. The Test Period in this case
includes captive insurance coverage until March, 21, 2011, and self insurance
accruals thereafter.
What wil be the new level of coverage for storm or casualty events?
The initial deductible for each storm or casualty O&M event damaging
distrbution propert wil be raised from the curent level of $25,000 to $250,000.
The deductible for O&M transmission and non-T&D propert damages will be $1
milion per event. O&M related damages for all costs up to these deductible limits
wil be charged to the proper fuctional O&M FERC account. Amounts
exceeding these deductible limits wil be charged to the accumulated insurance
reserve. There wil be no reserve amounts related to capital projects.
Please describe the Test Period treatment of third-party liabilty insurance.
As shown on page 4.11.2 of Exhibit No.2, captive insurance premiums and
coverage are assumed only through March 21, 2011. For the Test Period self-
insurance accruals replace the captive premiums after March 21. The level of the
self-insurance accrual is set based on the annual average ofliabilty claims related
to O&M payments by MEHC captive insurance from January 2008 through
December 2010. Idaho's allocated portion of the Test Period amount is based on
the System Overhead ("SO") factor. The injuries and damages expense the
Company incurs in addition to the amount previously covered by the captive. are
included based on a three-year average of the net expense accrued, consistent with
the Company's 2010 General Rate Case.
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1 Q.Please describe the treatment of propert insurance in the Test Period.
2 A.As shown on page 4.11.3 of Exhibit No. 2, captive insurance premiums and
3 coverage for T &D and non- T &D propert are assumed to be in place only
4 through March 21, 2011. For the Test Period, self insurance accruals after March
5 21 are set based on the annual average of actual damages from April 2007 through
6 December 2010. Damages are included in the average calculation only to the
7 extent they exceed the revised deductibles by category. The allocation of accruals
8 and actual storm or casualty costs wil be consistent with the allocation of similar
9 tyes of electrc plant in service (i.e. distrbution is situs assigned and
10 transmission and non-T&D are allocated on the SG factor) in place at the time.
11 Due to the increase in deductible limits, expenses for propert damages
12 that are curently classified as insurance expense are effectively being transferred
13 to O&M. Page 4.11.4 of Exhibit NO.2 shows that the increase in deductible limits
14 reduces the amount of storm or casualty events that would be covered by the
15 insurance reserve. Costs not covered by the insurance reserve would need to be
16 covered by the Company's ongoing O&M. The Company has included the effect
17 of this transfer as an O&M expense of $562,000 in the Test Period in order to set
18 rates at a level that wil adequately cover expected storm and casualty damage
19 below the new deductible threshold.
20 Q.Please describe the accounting entries that wil be booked once self insurance
21 coverage begins.
22 A.Each month, debits wil be made to FERC account 924 - Propert Insurance, with
23 the corresponding credits booked to insurance reserves in FERC account 254 on a
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state-specific basis. Separate internal accounting orders wil be used for the
reserve balances to track the state-specific amounts associated with the liability
and propert balances. When the Company experiences an insurance event, the
reserve balance wil be debited to pay for the damages incured allocated to Idaho
using then-curent allocation factors. If the Company experiences events in excess
of the accumulated reserve balance, or anticipated reserve balance though the
remaining portion of each calenda year, the Company wil accumulate these
amounts as a regulatory asset until such time as the allowed annual accrual
amount covers such losses or specific recovery for an event is requested and
approved.
What is the impact of the Company's proposal on Idaho customers in this
case?
Overall, the Company's proposal results in a slight decrease in costs allocated to
Idaho compared to the actual costs in the year ended December 2010. Page 4.1 1
of Exhibit No. 2 shows the Idaho-allocated impact of the adjustments for both
liability and propert insurance. The net Idaho-allocated expense decreases
approximately $15,000.
Please describe the Company's requested change to the depreciation
associated with the Klamath facilties.
Consistent with the Klamath Hydroelectric Settlement Agreement ("KHSA"),
depreciation of all Klamath Project facilties (existing assets, relicensing and
settlement process costs, and futue capital additions) is set at a level that wil
fully depreciate the assets by December 31, 2019. Depreciation associated with
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the existing Klamath Project facilities is accelerated from curent rates effective
January 1,2011. The Company wil monitor the depreciation expense booked in
the futue to ensure assets reach a zero net book value by December 31, 2019. The
impact of the change in depreciation rates is shown on page 8.12 of Exhibit 2; on
an Idaho-allocated basis, depreciation expense in this case is increased by
$262,161.
Please describe how the Company proposes to monitor the depreciation rates
to ensure that the Klamath assets reach a net book value of zero by
December 31, 2019.
The Company proposes to provide the Commission an annual report regarding the
composite depreciation rates related to the Klamath facilities for the previous
calendar year and the rates curently in effect at year-end. This report could be
provided as part of the Company's anual results of operations or as a separate
filing. In this case, the Company is requesting the Commission approve the
terminal date for depreciation of the assets, which wil result in rates varing
slightly over the remaining life as a result of potential retirements and additions
required to keep the facilty operational. Once approved, additional action by the
Commission would not be required. The Commission can continue to monitor the
rates and related depreciation expense through the Company's annual reports. If
the terminal date changes in the futue, the Company would include the impact in
a general rate case in a similar maner as presented in the curent case and seek
Commission approval of that change.
McDougal, Di - 18
Rocky Mountain Power
1 Idaho Results of Operations
2 Q.
3
4 A.
5
6
7
8
9
10
11
12
13
14
15
16
17 Q.
18 A.
19
20
21
22 Q.
23 A.
Please explain how the Company developed the revenue requirement for the
Test Period.
Revenue requirement preparation began with historical accounting information; in
this case the Company used the 12-months ended December 31, 2010. The
revenue requirement components in that historical period were analyzed to
determine if an adjustment was warranted to reflect normal operating conditions.
The historical information was also adjusted to recognize known and measurable
events, and to include previous Commission-ordered adjustments.
As stated earlier, historical rate base is calculated using end-of-period
balances as of December 31, 2010. Major capital additions planned to go into
service by December 31, 2011, 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.
Please describe Exhibit No.2.
Exhibit NO.2 is Rocky Mountain Power's Idaho results of operations report (the
"Report"). 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:
McDougal, Di - 19
Rocky Mountain Power
1 . Tab 1 Summary contains a sumary of normalized Idaho-allocated
2 results of operations.
3 . Tab 2 Results of Operations details the Company's overall revenue
4 requirement, showing unadjusted costs for the year ended December
5 2010 and fully normalized results of operations for the Test Period by
6 FERC account.
7 . Tabs 3 though 8 provide supporting documentation for the
8 normalizing adjustments required to reflect on-going costs of the
9 Company. Each of these sections begins with a numerical summary
10 that identifies each adjustment made to the 2010 actual results and the
11 adjustment's impact on the case. Each colum has a numerical
12 reference to a corresponding page in Exhibit No.2, which contains a
13 lead sheet showing the adjusted FERC account(s), allocation factor,
14 dollar amount and a brief description of the adjustment. The specific
15 adjustments included in each of these tab sections are described in
16 more detail below.
17 . Tab 9 shows the impacts of several items addressed by the
18 Commission in the 2010 General Rate Case that are not implemented
19 in the Company's request. More discussion on Tab 9 was provided
20 earlier in my testimony.
21 . Tab 10 contains the calculation of the 2010 Protocol allocation factors.
22 . Tab 11 is Tab 2 restated based on the Revised Protocol allocation
23 method.
McDougal, Di - 20
Rocky Mountain Power
1 . Tab 12 is Tab 2 restated based on the Rolled-In allocation method.
2 . Tabs B 1 through B20 provide backup for the actual results included in3 tab 2.
4 . Tab C1 provides the Company's 2007 lead lag Study.
5 Tab 3 - Revenue Adjustments
6 Q.Please describe the adjustments made to revenue in Tab 3.
7 A.Temperature Normalization (page 3.1) - This adjustment recalculates Idaho
8 revenue based on temperatue normalized historical load assuming average
9 temperature patterns.
10 Revenue Normalization (page 3.2) - This adjustment normalizes base year
11 revenue by removing items that should not be included to determine retail rates,
12 such as credits from the Bonnevile Power Administration ("BPA") for the
13 Residential Exchange Program, amortization of the Sacramento Municipal Utility
14 District ("SMUD") liability and collections related to the ECAM. The expense
15 side ofthe BPA credit is removed in adjustment 5.2.
16 Effective Price Change (page 3.3) - This adjustment reflects the $8.1 millon
17 revenue increase which became effective on December 28,2010, as a result of the
18 2010 General Rate Case. This adjustment also normalizes the pro forma effects
19 for the $6.46 millon special contract price change effective January 1,2011, also
20 determined in the 2010 General Rate Case.
21 S02 Emission Allowances (page 3.4) - This adjustment removes revenue from
22 the sale of sulfu dioxide ("S02") emission allowances occurng durng the base
23 period and replaces it with the corresponding grandfathered amortzation through
McDougal, Di - 21
Rocky Mountain Power
1 the Test Period. Prior to the 2010 General Rate Case, these sales were amortized
2 over a 15 year period, but in the 2010 General Rate Case the Company agreed to
3 shorten the amortization of the remaining balances to five years. Thus,
4 unamortized balances of sales prior to June 30, 2009, are amortzed over five
5 years to reflect this new methodology. Revenue from the sale of S02 emission
6 allowances after June 30, 2009, is retued to customers through the ECAM per
7 Case No. PAC-E-08-08.
8 Renewable Energy Credit ("REC") Revenue (page 3.5) - Curently,
9 California, Washington and Oregon have implemented renewable portfolio
10 standards. Consequently, the Company does not sell these states' share of eligible
11 RECs. Instead, the Company uses the renewable output to comply with curent
12 year or futue year renewable portfolio requirements. This adjustment reflects the
13 amount of REC revenues the Company expects during the Test Period and
14 allocates the REC revenue among states to account for compliance in California,
15 Washington and Oregon. Any differences between the projected REC revenues in
16 this adjustment and actual REC revenues wil be accounted for in the Company's
17 ECAM filings as ordered by the Idaho Commission in Order No. 32196.
18 Wheeling Revenue (page 3.6) - Durng 2010 there were various transactions
19 involving wheeling revenue that the Company does not expect to occur in the Test
20 Period. These transactions relate to various prior period adjustments and contract
21 terminations. This adjustment also includes pro forma wheeling revenue for the
22 Test Period.
McDougal, Di - 22
Rocky Mountain Power
1 Tab 4 - O&M Adjustments
2 Q.Please describe the adjustments made to O&M expense in Tab 4.
3 A.Miscellaneous General Expense (page 4.1) - This adjustment removes certin
4 miscellaneous expenses that should have been charged to non-regulated accounts.
5 Wage and Employee Benefits (pages 4.2 and 4.3) - This adjustment is used to
6 compute labor-related costs for the Test Period. Labor-related costs are calculated
7 by adjusting salaries, incentives, benefits, and costs associated with F AS 87
8 (pension), FAS 106 (post retirement benefits) and FAS 112 (post employment
9 benefits) for changes expected beyond the actual costs experienced in the year
10 ended December 2010. Page 4.3.4 provides a numerical summary starting with
11 actual labor costs in. 2010 and sumarizing the adjustments made to reflect the
12 Test Period level of expense.
13 The first step to adjust labor is to anualize salar increases that occured
14 during 2010. This was done by identifying actual wages by labor group by month
15 along with the date each labor group received wage increases. The next step is to
16 apply pro forma wage increases through the end of the Test Period to the
17 annualized 2010 salaries. Union contract agreements are used to escalate union
18 wages, while increases for non-union and exempt employees are based on actual
19 increases. In other words, wages in the Test Period are actual costs adjusted only
20 for contractul changes or known increases that have already occured. The only
21 exception to this is Locals IBEW 125 and IBEW 659 where 2011 planning targets
22 were used as union negotiations are curently ongoing.
23 Incentive compensation, used by the Company to deliver market
McDougal, Di - 23
Rocky Mountain Power
1 competitive pay, is included based on 2011 pro forma wages multiplied by a three
2 year average of the actual payment rate. Payroll taxes were updated to captue any
3 associated impacts of the changes to labor costs. Other employee benefit costs
4 were itemized starting with amounts booked durg the year ended December
5 2010 and adjusted to the planned expense for the Test Period. This adjustment is
6 fuher supported by the testimony of Company witness Mr. Wilson.
7 Class 1 DSM Program Costs (page 4.4) - In accordance with Order No. 32196
8 in the 2010 General Rate Case, costs of the Idaho Irigation Load Control
9 Program are allocated system-wide, including both customer incentives and
10 program administration costs. In addition, this adjustment allocates the costs of
11 Class 1 DSM programs in other states to all jursdictions. The Idaho Irrigation
12 Load Control Program incentive payments are already allocated as a system cost
13 in the Company's unadjusted results, but the other costs referenced are added to
14 results in this adjustment. The jursdictional loads used for allocation factors
15 reflect system treatment for these programs, consistent with the Commission
16 Order and this adjustment. In other words, no reductions in load resulting from
17 program operations in 2010 are reflected for puroses of inter-jursdictional
18 allocations.
19 Remove Non-Recurring Entries (page 4.5) - This adjustment removes various
20 accounting entres made durng 2010 that were non-recurg in natue or relate to
21 a prior period.
22 Pension Curtailment (page 4.6) - During the base period the Company made an
23 entr to reflect the actuaral effects of the UMA 127 pension curilment. Since
McDougal, Di - 24
Rocky Mountain Power
1 Idaho uses a cash basis for pension expense, this adjustment removes this entr.
2 DSM Revenue and Expense Removal (page 4.7) - This adjustment removes
3 Idaho DSM revenue and expenses which are accounted for though the customer
4 effciency services rate adjustment (Schedule 191).
5 Wyoming Inverted Rates Advertising (page 4.8) - This adjustment removes the
6 credit booked to set up a regulatory asset to defer advertising costs that were
7 ordered by the Wyoming Public Service Commission and are being recovered
8 from Wyoming customers.
9 MEHC Transition Cost Amortization (page 4.9) - The Company eliminated
10 many positions in its labor force as a result of the MEHC transaction. These
11 savings were made possible by the payment of change-in-control severance,
12 which is curently being amortized over a three year period as authorized in Case
13 Nos. PAC-E-06-11 and PAC-E-07-05. Because the amortization ended December
14 31, 2010, it is being removed from unadjusted results. This adjustment also
15 removes from unadjusted results the credit booked when the Oregon and
16 California transition plan regulatory assets were established.
17 MEHC Cross Charge (page 4.10) - The Company has included the actual
18 MEHC cross charge expense from 2010. This adjustment removes SERP expense
19 from the cross charge consistent with Order No. 32196 in the 2010 General Rate
20 Case.
21 Insurance Expense (page 4.11) - This adjustment reflects changes to the
22 Company's insurce expense as described above in my testimony under the
23 Accounting Changes section.
McDougal, Di - 25
Rocky Mountain Power
1 Generation Overhaul Expense (page 4.12) - This adjustment normalizes
2 generation overhaul costs by averaging actual overhaul expenses over four years.
3 For new generating units, which include Lake Side and Chehalis, the four-year
4 average is comprised of the actual overhaul expense to the extent it is available
5 and projected expense to complete the first four full years these plants are
6 operationaL. The adjustment is calculated by subtracting the actual overhaul costs
7 from the four year historical average.
8 Incremental O&M (page 4.13) - This adjustment anualizes incremental O&M
9 related to new generation plant in service, improvements to plants, or
10 transmission projects that were placed into service durng the 12-months ended
11 December 2010, and includes projected O&M expense for projects placed into
12 service during the 12-months ending December 2011. The adjustment also
13 addresses two known changes in O&M at existing facilities. First, on December
14 29, 2010, the Company sold to Black Hils, Co. an undivided joint ownership
15 interest in certain transmission facilities, causing a reduction in ongoing O&M
16 expense. Second, as of December 2010, with the depletion of the McKinley Mine,
17 the Cholla 4 plant wil be using coal from a different source which requires
18 additional scrubbing and therefore requires higher volumes of scrubbing agents.
19 Memberships and Subscriptions (page 4.14) - This adjustment removes
20 expense in excess of Commission policy as stated in Order No. 29505. National
21 and regional trade organizations are recognized at 75 percent of above the line
22 costs and dues for membership in Western Electrc Coordinating Council
23 ("WECC") and Northern Tier Transmission Group are included at 100 percent.
McDougal, Di - 26
Rocky Mountain Power
1 Other membership dues are removed.
2 Intervenor Funding (page 4.15) - This adjustment accounts for intervenor
3 fuding awarded to the Community Action Partership of Idaho ("CAP AI"), the
4 Idaho Irgation Pupers Association ("LIP A") and the Idaho Conservation
5 League ("ICL"), as ordered in Case No's. PAC-E-07-05, PAC-E-08-07, PAC-E-
6 10-07 and PAC-E-08-08. Amortization expense is adjusted to reflect the expected
7 amount through the year ending December 2011, and rate base is adjusted to
8 reflect the December 2011 remaining balance.
9 Idaho Pension Expense - Cash Basis (page 4.16) - This adjustment replaces the
10 actuarally determed pension expense for the Test Period with the three-year
11 average of cash contrbutions, consistent with the Commission's Order No.
12 32196.
13 Uncollectible Expense (page 4.17) - As discussed earlier in my testimony,
14 uncollectible expense is adjusted to a three-year historical average (2008-2010)
15 per Commission Order No. 32196.
16 Outside Servces (page 4.18) - As discussed above, outside services expense is
17 adjusted to a three-year historical average (2008-2010) per Commission Order
18 No. 32196.
19 Tab 5 - Net Power Cost Adjustments
20 Q.Please describe the adjustments included in Tab 5.
21 A.Net Power Cost Study (page 5.1) - The net power cost adjustment presents
22 normalized Test Period generation, fuel, purchased power, wheeling expense and
23 sales for resale based on the Company's GRID modeL. It also normalizes hydro,
McDougal, Di - 27
Rocky Mountain Power
1 weather conditions and plant availabilty as described in Mr. Duvall's testimony.
2 James River Royalty Offset and Little Mountain Steam Sales (page 5.2) - On
3 January 13, 1993, the Company executed a contract with James River Paper
4 Company with respect to the Camas mil, later acquired by Georgia Pacific.
5 Under the agreement, the Company built a steam tubine and is recoverig the
6 capital investment over the twenty-year operational term of the agreement as an
7 offset to royalties paid to James River based on contract provisions. The contract
8 costs of energy for the Camas unit are included in the Company's net power costs
9 as purchased power expense, but GRID does not include an offsetting revenue
10 credit for the capital and maintenance cost recovery. This adjustment adds the
11 royalty offset to account 456, other electrc revenue, for the Test Period.
12 This adjustment also normalizes the ongoing level of steam revenues
13 related to the Little Mountain plant. Contractully, the steam revenues from Little
14 Mountain are tied to natual gas prices. The Company's net power cost study
15 includes the cost of ruing the Little Mountain plant but does not include the
16 offsetting steam revenues. This adjustment aligns the steam revenues to the gas
17 prices modeled in GRID.
18 Electric Lake Settlement (page 5.3) - Canyon Fuel Company ("CFC") owns the
19 Skyline mine located near Electrc Lake. Electric Lake is a reservoir owned by the
20 Company that provides water storage for the Huntington generating plant. The
21 two companies disputed a claim made by PacifiCorp that CFC's mining
22 operations caused the lake to leak water into the Skyline mine, making it
23 unavailable for use by the Huntington generating plant. The Company has
McDougal, Di - 28
Rocky Mountain Power
1 incurred capital costs and O&M costs to pump water from the breach back into
2 Electrc Lake. The two companies negotiated a settlement of the claims made by
3 the Company. The settlement includes reimbursement to the Company for O&M
4 and capital associated with the pumping. The value of the settlement was
5 amortized over thee years, which was completed Januar 2011. This adjustment
6 removes the Test Period amortization and rate base balances from results.
7 BP A Residential Exchange (page 5.4) - The Company receives a monthly
8 purchase power credit from Bonnevile Power Administration ("BP A"). This
9 credit is treated as a 100% pass-through to eligible customers. As a result of the
10 Ninth Circuit Cour of Appeals decision, BP A offsets this credit against a look
11 back payment to the public utilities. To date this look back has been larger than
12 the BPA credit in Idaho. This adjustment reverses the related entres to purchase
13 power expense. The revenue normalizing adjustment on page 3.2 removes the
14 offsetting entries to retail revenue.
15 Tab 6 - Depreciation and Amortization Expense Adjustments
16 Q.Please describe the adjustments included in Tab 6.
17 A.Depreciation and Amortation Expense (page 6.1) - This adjustment
18 normalizes the Test Period results for depreciation and amortation expense
19 associated with the major plant additions to rate base in adjustment 8.6.
20 Depreciation and Amortization Reserve (page 6.2) - This adjusts the
21 depreciation and amortization reserve to include the depreciation and amortization
22 expense from adjustment 6.1 associated with the major plant additions in
23 adjustment 8.6.
McDougal, Di - 29
Rocky Mountain Power
1 Hydro Decommissioning (page 6.3) - Based on the Company's latest
2 depreciation study approved in Case No. PAC-E-07-14, an annual accrual of
3 $19.4 milion is required for the decommissioning of various hydro facilities. This
4 adjusts the decommissioning reserve balance to the end of the Test Period leveL.
5 Tab 7 - Tax Adjustments
6 Q.
7 A.
8
9
10
11
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 normalized net rate base by the Company's weighted cost of
debt in this case.
Property Tax Expense (page 7.2) - This adjustment normalizes propert tax
expense to include the taxes associated with capital additions. Please refer to
Confidential Exhibit NO.3 for details supporting the Test Period expense.
Renewable Energy Tax Credit (page 7.3) - The Company is entitled to
recognize certain production tax credits as a result of generation from qualifying
renewable generating facilities. The federal tax credit is based on the generation
of the plants and the credit can be taken for 10 years on qualifying propert.
Under the calculation required by Internal Revenue Service Code Sec. 45(b )(2),
the Test Period renewable electrcity production credit is 2.2 cents per kilowatt
hour of electrcity produced from wind facilities. The Utah state tax credit is
based on the generation of the Blundell bottoming cycle; the credit can be taken
for four years. In addition to the Utah state tax credit, the Company is able to
recognize the Oregon Business Energy Tax Credit, which is based on investment
McDougal, Di - 30
Rocky Mountain Power
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18 Q.
19 A.
20
21
22
23
in specific assets and is taken over a five year period.
Idaho State Investment Tax Credit (page 7.4) - The Idaho state investment tax
credit ("ITC") is based on plant placed in service, and the credit is usually utilized
in a subsequent period depending on the availabilty of Idaho state taxable
income. Since PacifiCorp is a 46(f)(1) Company, this adjusts results to reflect the
ITC unamortized balance as a rate base reduction.
AFUDCEquity (page 7.5) - This adjustment aligns the AFUDC - Equity in
results with the tax Schedule M's associated with regulatory income.
Post Retirement Benefits Tax Deferral (page 7.6) - As approved in the 2010
General Rate Case, this adjustment recognizes the amortization of the post
retirement benefits tax deferral regulatory asset for the 12-months ending
December 2011.
Accumulated Deferred Income Tax Balance Adjustment (page 7.7) - This pro
forma adjustment reflects the known and measurable change to the accumulated
deferred income tax balances for guidance received from the Internal Revenue
Service (Rev. Proc. 2011-26) on March 29, 2011, which affected the Company's
estimate of bonus depreciation for assets placed in service durg 2010.
How have current state and federal income tax expenses been calculated?
Curent state and federal income tax expenses were calculated by applying the
applicable tax rates to the taxable income calculated in the Report. State income
tax expense was calculated using the blended state statutory rate applied to the
jursdictional pre-tax income. The treatment of state taxes is also discussed under
the Inter-Jurisdictional Allocation section of my testimony. Federal income tax
McDougal, Di - 31
Rocky Mountain Power
1 expense is calculated using the same methodology that the Company uses in
2 preparing its fied income tax retus. The detail supporting this calculation is
3 contained on pages 2.18 through 2.20 of Exhibit NO.2.
4 Tab 8 - Rate Base Adjustments
5 Q.
6 A.
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
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 for the Test Period. Total
cash working capital is calculated by multiplying the jursdictional net lag days by
the average daily cost of service. Net lag days in this case are based on a lead lag
study prepared by the Company using calendar year 2007 information. Based on
the results of the 2007 lead lag study, included in Tab C1 of Exhibit No.2, the
Company experiences 4.72 net lag days in Idaho requiring a cash working capital
balance of$1.8 millon to be included in rate base.
The cash working capital calculation is consistent with the treatment
included in the last two general rate cases. In the 2010 General Rate Case, the
Commission accepted the Company's 2007 lead lag study with the directive that
in the next rate case the Company demonstrate that a lead lag study appropriately
considers the source of the fuds. The Company believes the lead lag study
methodology to be the best measurement of the Company's required working
capital fuds and appropriately considers the source of the fuds. There are thee
viable sources to provide a utilty's working capital fuds: debt, equity and
payment terms (or the difference between when the Company receives payment
from a customer and pays for the cost of providing service). The first two sources
McDougal, Di - 32
Rocky Mountain Power
1 of these fuds are supplied by investors. The third source may be provided by
2 investors or customers, and a lead lag study is the best method of determining
3 which group is responsible. The Company's 2007 lead lag study shows a net lag,
4 meaning that investors must infuse cash into the business for day-to-day
5 operations. Based on the Company's latest FERC Form 1 filing, the Company's
6 curent assets exceed the curent liabilities, suggesting that the Company requires
7 more working capital than is supplied by customers. This supports the findings of
8 the lead lag study and demonstrates that the lead lag study offers reasonable
9 analysis on the source of fuds. The Company believes that actul working.capital
10 requirements of a utilty are best measured by examining the dynamic cash flows
11 as done in a lead lag study instead of a looking at a snapshot of account balances.
12 Therefore, the Company continues to advocate for the use of its 2007 lead lag
13 study as the most accurate tool for determining the level of working capital
14 required for ongoing operations to serve customers.
15 Trapper Mine Rate Base (page 8.2) - The Company owns a 21.4 percent share
16 of the Trapper Mine, which provides coal to the Craig generating plant. This
17 investment is accounted for on the Company's books in FERC account 123.1,
18 investment in subsidiar company, which is not included as a regulatory rate base
19 account. The normalized coal cost from Trapper Mine in net power costs includes
20 operation and maintenance costs but does not include a return on investment. This
21 adjustment adds the Company's portion of the Trapper Mine net plant investment
22 to rate base in order for the Company to earn a return on its investment. This
23 adjustment also walks forward the reclamation liability through December 2011.
McDougal, Di - 33
Rocky Mountain Power
1 Jim Bridger Mine Rate Base (page 8.3) - The Company owns a two-thirds
2 interest in the Bridger Coal Company, which supplies coal to the Jim Bridger
3 generating plant. The Company's investment in Bridger Coal Company is
4 recorded on the books of Pacific Minerals, Inc. Because of this ownership
5 arangement, the coal mine investment is not included in electrc plant in service.
6 The normalized coal costs for Bridger Coal Company in net power costs include
7 the operation and maintenance costs of the mine but provide no retu on
8 investment. This adjustment is necessary to properly reflect the Bridger Coal
9 Company investment in rate base in order for the Company to ear a retu on its
10 investment.
11 Environmental Settlement (PERCO) (page 8.4) - In 1996, the Company
12 received an insurance settlement of $33 milion for environmental clean-up
13 projects. These fuds were transferred to a subsidiary called PacifiCorp
14 Environmental Remediation Company ("PERCO"). This fud balance is
15 amortzed or reduced as PERCO expends dollars on clean-up costs. PERCO
16 received an additional $5 milion of insurance proceeds plus associated liabilties
17 from Rocky Mountain Power in 1998. This adjustment reduces rate base for the
18 unspent insurance proceeds through the end of the Test Period. The Company
19 expects the fuds to be exhausted durg 2011.
20 Customer Advances for Construction (page 8.5) - Refudable customer
21 advances for constrction are recorded to FERC account 252. The December
22 2010 balances do not reflect the proper allocation because amounts were recorded
23 to a corporate cost center location rather than state-specific locations in the
McDougal, Di - 34
Rocky Mountain Power
1 Company's accounting system. This adjustment corrects the allocation of
2 customer advances.
3 Pro Forma Major Plant Additions (page 8.6) - To reasonably represent the cost
4 of system infrastrctue required to serve our customers, the Company has
5 identified capital projects that wil be completed by the end of the Test Period.
6 Company business units identified capital projects with expenditues over $5
7 milion that wil be used and useful by December 31, 2011. These additions are
8 sumarzed by fuctional category, indicating the in-service date and amount by
9 project. The associated depreciation expense and accumulated reserve impacts are
10 accounted for in adjustment 6.1 and 6.2. The associated tax impacts are included
11 on page 8.6.1.
12 Miscellaneous Rate Base (page 8.7) - In this adjustment fuel stock is increased
13 due to the cost of coal and the number of tons stored at each site. Also, prepaid
14 overhaul balances in FERC account 186 for the Lake Side, Chehalis, and Curant
15 Creek plants are adjusted forward to reflect futue payments and transfers of
16 capital to electrc plant in service expected durng the Test Period.
17 Powerdale Hydro Decommission (page 8.8) - Powerdale is a hydroelectrc
18 generating facility located on the Hood River in Oregon. This facilty was
19 scheduled to be decommissioned in 2010; however, in 2006 a flash flood washed
20 out a major section of the flow line. The Company determined that the cost to
21 repair this facility was not economical and decided it was in the ratepayers' best
22 interest to cease operation of the facilty.
23 This adjustment reflects the ratemaking treatment approved by the
McDougal, Di - 35
Rocky Mountain Power
1 Commission in Case No. PAC-E-07-04. Durg 2007, the net book value
2 (including an offset for insurance proceeds) of the assets to be retired was
3 transferred to the unecovered plant regulatory asset, which was fully amortized
4 on December 31, 2010. In addition, decommissioning costs are deferred as they
5 are spent and amortized over 10 years, beginning in the subsequent year. The
6 decommissioning project was substatially completed durng 2010.
7 Goose Creek Transmission (page 8.9) - On April 1, 2008, the Company sold its
8 undivided interest in 13.85 miles of transmission line, ruing from the
9 Company's Goose Creek switching station and extending nort to the Decker 230
10 kV substation near Decker, Montana. The assets sold included strctues,
11 miscellaneous support equipment, easements, and rights-of-way associated with
12 the transmission line. The sale of the transmission line resulted in the Goose
13 Creek switching station no longer being needed or useful to the Company, and the
14 Company plans to remove all above ground facilities at the switching station.
15 Consistent with Commission Order No. 30904, in September 2009 the Company
16 wrote off the gain associated with the sale. This adjustment removes the rate base
17 and depreciation expense included in December 2010 unadjusted results.
18 FERC 105 (pHFU) (page 8.10) - This adjustment removes all plant held for
19 futue use ("PHFU") assets from FERC account 105. The Company is making
20 this adjustment in compliance with Title 16 of Public Utilty Regulation, chapter
21 5, "Powers and Duties of Public Utilties Commission" section 61-502A.
22 Trojan Unrecovered Plant (page 8.11) - The regulatory assets associated with
23 Trojan unecovered plant and decommissioning wil be fully amortized as of
McDougal, Di - 36
Rocky Mountain Power
1 Januar 2011. This adjustment removes the amortization expense and rate base
2 balances from the Test Period.
3 Klamath Hydroelectric Settlement Agreement ("KHSA") (page 8.12) - This
4 adjustment accounts for the impact of the KHSA including: amortization of the
5 Klamath relicensing and settlement process costs, accelerated depreciation
6 associated with the existing Klamath facilties (startg in Januar 1, 2011, and
7 finishing by December 31, 2019) and incurred operation and maintenance
8 expenses. Under the 2010 Protocol, a surcharge to cover the cost of facilties
9 removal is initially allocated to Idaho, but is re-assigned to Oregon and California
10 though the 2010 Protocol Klamath surcharge adjustment. The accelerated
11 depreciation associated with the existing Klamath facilities was discussed in detail
12 above.
13 Tab 9 - PAC-E-I0-07Items
14 Q.Please describe the information contained behind Tab 9.
15 A.As described earlier in my testimony, Tab 9 contains the impacts of several items
16 addressed in Commission Order No. 32196 in the 2010 General Rate Case.
17 Tab 10 - Allocation Factors
18 Q.Please describe the information contained behind Tab 10 Allocation Factors.
19 A.Tab 10 Allocation Factors summarizes the derivation of the jursdictional
20 allocation factors using the 2010 Protocol allocation methodology. Factors in this
21 case are based on the actual loads through December 2010 and unadjusted
22 account balances.
McDougal, Di - 37
Rocky Mountain Power
1 Tab 11 - Revised Protocol
2 Q.Please describe the information contained behind Tab 11 Revised Protocol.
3 A.Tab 11 is Tab 2 restated with the Idaho allocation based on the Revised Protocol
4 allocation method. The Company agreed to provide this information in its reply
5 comments in the pending 2010 Protocol Case.
6 Tab 12 - Rolled-In
7 Q.Please describe the information contained behind Tab 12 Rolled In.
8 A.Tab 12 is Tab 2 restated with the Idaho allocation based on the Rolled-In
9 allocation method. The Company agreed to provide this information in its reply
10 comments in the pendig 2010 Protocol Case.
11 Tab CL - 2007 Lead Lag Study
12 Q.Please describe the information contained behind Tab CL 2007 Lead Lag
13 Study.
14 A.Tab C1 contains the Company's 2007 lead lag study as discussed earlier in my
15 testimony under the Tab 8 - Rate Base section.
16 Load Change Adjustment Rate
17 Q.Has the Company updated the calculation of theLCAR that is applied to the
18 calculation of net power costs to be recovered through the ECAM?
19 A.Yes. Exhibit No. 4 provides the detailed calculation based on the revenue
20 requirement numbers from Exhibit NO.2. Using the revenue requirement in the
21 Company's fiing results in an increase in the LCAR from $5.47 per MW to
22 $6.17 per MW. To calculate the LCAR I have incorporated the applicable
23 elements from this case, including production-related return on investment and
McDougal, Di - 38
Rocky Mountain Power
1 non-NPC expenses. My calculation does not include demand related charges as
2 approved by the Commission in Case No. GNR-E-1O-03 Order No. 32206. The
3 LCAR itself does not affect revenue requirement in this case, but is applied to the
4 calculation of net power costs to be deferred and recovered though the ECAM
5 and is to be updated each time base net power costs are updated in a general rate
6 case. The Company wil also provide an updated calculation of this rate. based on
7 the Commission-approved outcome of this case.
8 Conclusion
9 Q.Do you believe the proposed revenue increase supported by your calculation
10 of revenue requirement is in the public interest?
11 A.Yes. The Company's proposed revenue increase is in the public interest because it
12 balances the needs of customers and the Company by setting rates at a level
13 commensurate with the reasonable and prudent cost of providing safe and reliable
14 service when those rates wil be in effect.
15 Q.Does this conclude your direct testimony?
16 A.Yes.
McDougal, Di - 39
Rocky Mountain Power
RECE\VEO
iß\\1V,~ 21 ~l' \. :Case No. PAC-E-ll-12
Exhibit NO.1
Witness: Steven R. McDougal
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAI POWER
Exhibit Accompanying Direct Testimony of Steven R. McDougal
Revenue Requirement Sumary
May 2011
Rocky Mountain Power
IDAHO
Results of Operations - 2010 PROTOCOL
12 Months Ended DECEMBER 2010
(1)
Total
Results
1 Operating Revenues:
2 General Business Revenues
3 Interdepartental
4 Special Sales
5 Other Operating Revenues
6 Tota Operatng Revenues
7
8 Operating Expenses:
9 Steam Prouction
10 Nuclear Production
11 Hydro Production
12 Other Power Supply
13 Transmission
14 Distrbution
15 Customer Accunting
16 Customer Service & 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 Investment Tax Credit Adj.
29 Misc Revenue & Expense
30
31 Total Operating Expenses:
32
33 Operating Rev For Return:
34
35 Rate Base:
36 Electric Plant In Service
37 Plant Held for Future Use
38 Mlsc Deferred Debits
39 Elec Plant Acq Adj
40 Nuclear Fuel
41 Prepayments
42 Fuel Stock
43 Material & Supplies
44 Working Capital
45 Weatheriation Loans
46 Misc Rate Base
47
48 Total Electric 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 Adv For Const
56 Customer Service Deposits
57 Misc Rate Base Deductions
58
59 Total Rate Base 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" Deductons
74 Income Before Tax
75
76 State Income Taxes
77 Taxable Income
78
79 Federallncorne Taxes + Oter
218,197,789
30,864,481
13,831,492
262,893,763
64,517,140
2,676,169
68,710,805
12,145,689
11,017,503
4,663,581
1,208,172
11,262,040
176,201,098
30,729,804
2,767,529
7,183,133
(36,068,197)
(4,379,078)
46,037,202
(221,638)
(633,171)
221,616,681
41277 081
1,310,429,312
5,68,268
3,469,909
2,693,181
14,046,799
11,026,835
3,631,222
3,181,004
o
(2)
Price Change
32,670,159
75,472
10,890,211
1,479,799
12,445,482
20224678
Rocky Mountain Power
Exhibit No. 1 Page 1 of 3
Case No. PAC-E-11-12
Witness: Steven R. McDougal
(3)
Results with
Price Change
250,867,949
4,739,053
7,183,133
(25,177,986)
(2,899,279)
234,062,163
61501759
1,353,946,529 1,353,946,529
(407,334,769)
(24,983,348)
(170,126,518)
(158,324)
(1,166,620)
(4,476,016)
(608,245,595)
745700934
(608,245,595)
745700934
5.535%8.248%
5.314%
46,645,370
(4,348,752)
20,430,118
47,219,093
173,182,978
(95,399,881 )
(4,379,078)
(91020803)
(36068191)
32,594,688
32,594,688
1,479,799
31114 889
10890211
10.500%
79,240,058
(4,348,752)
20,430,118
47,219,093
173,182,978
(62,805,194)
(2,899,279)(59905914)
(25177986)
Rocky Mountain Power
Normalizd Results of Operaons
Adjustment Summary
Twelve Months Ending Decmber 31, 2010
Tab2 Tab2
Total Company Idaho Allocated
Actual Results Actual Result
Decmber 2010 Decmber 2010
1 Operating Renues:
2 Genral Business Reues 3,574,58,105 20,560,116
3lnlerdepmen
4 Special Sale 501,56,210 29,812,4905 Otr Opra Renues 326,069,070 19,09,327
6 T ala Oping Reveues 4,402,215,385 255,46,93
7
6 0"."9 .,,
9 Stem Pructon 957,497,818 59,637,970
10 Nucler Proucon
11 Hyro Prouctn 40,481,667 2,45,150
12 other Por Supply 922,755,111 59,618,70313 Trasmss 195,628,269 11,85,335
14 Distruti 208,550,302 10,426,83215 Custr Acnting 92,750,645 4,772,0016 Custr 8e & Inf 128,94,905 7,131,894
17 saes
18 Administtie & Gen 146,016,485 9,46,079
19
20 Total Q&M Ex 2,692,685,201 165,360,970
2122 Deprti 491,64,870 27,991,77823 Amizti 44,975,94 2,494,630
24 Taxs 0I Th Income 136,512,728 6,417,97125 Inc Taxes. Federa (482,761,917)(24,66,111)26 Incoe Taxes- Slae (58,348,068)(2,912,537)27lncoeTaxes.DefNe 761,44,172 36,724,89
28 Invent Tax Creit Adj. (1,874,204)(221,638)29 Mise Revenu & Exns (5,388,60)(287,997)3.
31 Total Openg Exnses:3,578,889,124 210,903,95
32
33 Opting Rev For Ret:823,326,261 44,56,977
34
35 Rate Base:
36 Eleric Plant In Serv 21,68,524,069 1,256,337,918
37 Plant He fo Futu Use 17,678,149 64,154
38 Mise Derr Debits 198,021,223 5,321,674
39 Elee Plat Acq AdJ 57,33,243 3,469,90
40 NuclrFue1
41 Prepaymnts 45,378,667 2,693,181
42 Fuel St 184,380,973 11,691,641
43 Mate & Suppies 186,133,158 11,026,835
44 WorngCapi 64,526,097 3,662,00045 Wearion Los 8,619,651 3,181,00
46 Mis Ra Base 135,56 10,019
47
48 Totl Elec Plant 22,44,727,798 1,298,038,335
49
50 Ra Bas Deducts:
51 Acm Pro For Deree (6,842,986,868)(40,547,397)
52 Acm Pro For Amor (456,063,105)(24,449,758)53 Acm De Ince Tax (2,999,20,147)(165,740,459)
54 UnamortzelTC (5,66,770)(40,145)55 Custer Mv For Co (18,494,962)(832,083)56 CUstr Sece Depots
57 Mise Rate Ba Deductons (136,93,409)(2,907,316)..
59 Totl Ra Base Deducton (10,459,399,26)(600,517,158)60
61 Total Rate Bae:11,985,328,537 697,521,177
62
63 Rern on Ra Base 6.869%6.38%
64
65 Reurn on Equit 7.865%6.94%
Exhibk2
Tab 3 Tab 4
Revenue Adjustment O&M Adjustments
11,637,673
521,143
12,158,816
(5,939,833)
(5,939,833)
Tab 5
Net Power Cost
Adjustments
1,051,991
157,85
1,209,846
Rocky Mountain Power
Exhibit NO.1 Page 2 of 3
Case No. PAC-E-11-12
Witness: Steven R. McDougal
Tab 6
Depreciation &
Amorttion
Adjustments
(48,437)
1,005
27,913
857,607
71,772
590,671
(108,425)
(5,923,722)
1,591,96
4,878,165
7,25,533
264,019
(48,437)
4,018,872
54,098
198,801
(345,174)
(2,891,217)
(1,625,412)
(220,867)
861,571
4,370,161
7,788,655
(3,875,925)
(2,063,908)
(4.59)
1,615,479
(1,571,507)
43,972
43,972
(4,596)
(122,194)
(122,194)
(126,790)
(3,997)
50
(448,442)
(32,631)
(272,164)
2,807
3,307 (753,436)
(690)(753,43)
Rocky Mountain Power
Noralizd Result of Operations
Adjustment Summary
Twelve Months Ending December 31,2010
Exhibit 2
Tab 7 Tab 8 Tab 2
Rate Ba..ldaho Normalized
Tax Adjustments Adjustments Results
1 Opera Renu:
2 Genral Business Reveues 218,197,7893 Interepame
4 Spel Sale 30,86,481
5 Other Oprang Revenes 13,831,492
6 Tot Opating Reues 262,89,763
7
8 Opting Ex:
9 Stem Prouct 64,517,140
10 Nuclr Pructon
11 Hydro Prouctio 198,106 2,676,169
12 Othr Powr Supply 975,961 68,710,80513 Trasmisn 12,145,689
14 DistrbUon 11,017,50315 Custr Accnting 4,66,581
16 Custme Sece & Inf 1,208,172
17 Sale
18 Admlnlsttl & Geer 204,998 11,262,04,.
20 Total O&M Ex 20.99 1,174,067 176,201,098
21
22 Deretin 261,649 30,72,8023Amon22,715 2,767,52924 Tax Otr Thn Incoe 765,162 7,183,13325 Inc Tax - Feder (1,588,174)(7,377,86)(36,068,197)
26 Ince Taxes . State (132,722)(1,00,529)(4,379,078)27 Inc Taxes - Def Net 218,810 7,749,48 46,037,20228 Invent Tax Crit Adj.(221,63)29 Mise Reenu & Exnse (633,171)
30
31 Tota Opng Exns:(531,925)1,031,52 221,616,681
32
33 Operag Re For Return:531",925 (1,031,522)41,2n,081
34
35 Rate Bas:
36 I:lee Plan In Servce 54,091,394 1,310,429,312
31 Pla Held for Future Use (64,154)38 Mise De Deits 155,186 5,46,268
39 EI Plant Acq Adj 3,46,909
40 Nucr Fuel
41 Preymnts 2,693,181
42 Fuel Sto 2,355,158 14,04,799
43 Marial & SUpplie 11,026,835
44 Worin Capta (30,778)3,631,222
45 Weaheiiion Lons 3,181,00
46 Mise Rate Base (10,019)0
47
48 Totl Elec Plant: 55,916,788 1,353,946,5294.
50 Rate Bas Deucns:
51 Acm Prv For De (338,930)(407,33,769)52 Accm Pr For Am (50,760)(24,983,348)53 Accm 0t Inc Tax 2,245,557 (7,853,238)(170,126,518)54 Unamo ITC (118,179)(158,324)55 Custr Mv For Cot (334,536)(1,166,620)56 Custmer Sece Dets
57 Mise Ra Bae Deducton (4,476,016)
58
59 Tota Ra Base Deducons 2,127,378 (9,027,46)(608,245,59)
60
61 Total Rate Bas:2,127,378 46,889,32 745,700,e3
62
63 Return on Rat Ba 5.535%
64
65 Retrn on Equìt 5.314%
Rocky Mountain Power
Exhibit No. 1 Page 3 of 3
Case No. PAC-E-11-12
Witness: Steven R. McDougal
R J
ion MAY 21 AM 10: 44
Case No. PAC-E-11-12
Exhbit NO.2
Witness: Steven R. McDougal
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAI POWER
Exhbit Accompanying Direct Testimony of Steven R. McDougal
Revenue Requirement
May 2011
Rocky Mountain Power Page 1.0
IDAHO
Results of Operations. 2010 PROTOCOL
12 Months Ended DECEMBER 2010
(1)(2)(3)
Total Results with
Results Price Change Price Change
1 Operating Revenues:
2 General Business Revenues 218,191,189 32,810,159 250,861,949
3 Interdepartental
4 Special Sales 30,86,481
5 Other Operatin9 Revenues 13,831,492
6 Total Operatlng Revenues 262,893,163
1
8 Operating Expenses:
9 Steam Production 64,511,140
10 Nuclear Production
11 Hydro Production 2,616,169
12 Other Power Supply 68,110,805
13 Transmission 12,145,68
14 Distribution 11,011,503
15 Customer Accounting 4,663.581 15,72 4,139,053
16 Customer Service & Info 1,208,172
11 Sales
18 Administrative & General 11,262,040
19
20 Total O&M Expenses 116,201,098
21
22 Depreciation 30,129,804
23 Amorization 2,161,529
24 Taxes Other Than Income 1,183,133 1,183,13325 Income Taxes - Federal (38,08,191)10,890,211 (25,177986)26 Income Taxes.. State (4,319,018)1,419,199 (2,899,219)
21 Income Taxes, Def Net 46,031,202
28 Investment Tax Credit Adj.(221,638)29 Misc Revenue & Expense (633,111)30
31 Total Operating Expenses:221,616,681 12,445,82 234,062,163
32
33 Operatin Rev For Return:41,211,081 20224618 61501159
34
35 Rate Base:
36 Electric Plant In Serice 1,310,429,312
31 Planl Held for Future Use
38 Misc Deferred Debits 5,68,26839 Elec Plant Acq Adj 3,69,909
40 Nuclear Fuel
41 Prepayments 2,693,181
42 Fuel Stock 14,046,199
43 Material & Supplies 11,026,835
44 Working Capital 3,631,222
45 Weathrization Loans 3,181,004
46 Misc Rate Base 0
41
48 Tolal Electric Plant:1,353,946,529 1,353,946,529
49
50 Rate Base Deductions:
51 Accum Prav For Deprec (401,334,169)52 Accum Prov For Amort (24,983,348)53 Accum Def Income Tax (170,126,518)
54 Unamortized ITC (158,324)
55 Customer Adv For Canst (1,166,620)58 Customer Service Deposit
51 Misc Rate Base Deductions (4,416.016)
58
59 Total Rale Base Deductons (608.245,595)(608,245,595)60
61 Total Rate Base:145100934 145100 934
62
63 Return on Rate Base 5.535%8.248%
64
65 Return on Equity 5.314%10.500%
68
61 TAX CALCULATION:
68 Operating Revenue 46,645,310 32,594,68 19,240,058
69 Other Deductlons
70 Interest (AFUDC)(4,348,152)(4,348.152)11 Interst 20,430,118 20,430,118
72 Schedule "M" Additions 41,219,093 41,219,09313 Schedule "M" Deductons 173,182,918 113,182,91874 Income Before Tax (95.399.881 )32,594,688 (62.805,194)15
16 State Income Taxes (4,319,078)1,479,199 (2,899,219)17 Taxable Income 191020803\31114889 159905914\18
79 Federal Income Taxes + Other 13608191\10890 211 12517 986\
Ref. Page 2.2
Rocky Mountain Power
IDAHO
Results of Operations - 2010 PROTOCOL
12 Months Ended DECEMBER 2010
Page 1.1
Net Rate Base $745,700.934 Ref. Page 1.0
Retum on Rate Base Requested 8.248%Ref. Page 2.1
Revenues Required to Eam Requested Retum 61,501.759
Less Current Operating Revenues (41.277.081)
Increase to Current Revenues 20.224.678
Net to Gross Bump-up 161.54%
Price Change Required for Requested Retum $32.670,159
Requested Price Change $32.670,159
Uncollectible Percent 0.231%Ref. Page 1.2
Increased Uncollectible Expense $75,472
Requested Price Change $32.670.159
Franchise Tax 0.000%
Revenue Tax 0.000%
Resource Supplier Tax 0.000%
Gross Receipts 0.000%
Increase Taxes Other Than Income $
Requested Price Change $32.670.159
Uncollectible Expense (75,72)
Taxes Other Than Income
Income Before Taxes $32,594.688
State Effective Tax Rate 4.S4%Ref. Page 2.1
State Income Taxes $1,479.799
Taxable Income $31.114.889
Federallncóme Tax Rate 35.00%Ref. Page 2.1
Federal Income Taxes $10.890.211
Operating Income 100.000%
Net Operating Income 61.906%Ref. Page 1.2
Net to Gross Bump-Up 161.54%
Operating Revenue
Operating Deductions
Uncollectible Accounts
Taxes Other - Franchise Tax
Taxes Other - Revenue Tax
Taxes Other - Resource Supplier
Taxes Other - Gross Receipts
Sub-Total
State Income Tax ~ 4.54%
Sub-Total
Federal Income Tax ~ 35.00%
Net Operating Income
(1) Uncollectible Accounts =
Rocky Mountain Power
IDAHO
Results of Operations - 2010 PROTOCOL
12 Months Ended DECEMBER 2010
Page 1.2
100.000%
0.231% See Note (1) below
0.000%
0.000%
0.000%
0.000%
99.769%
4.530%
95.239%
33.334%
61.906%
504,061 Pg 2.12, Situs from Accunt 904
218,197,789 Pg 2.2, General Business Revenues
IDAHO SUMMARY OF ADJUSTMENTS TOTAL Page 1.4
Net Power Cost
Revenue Adjustments O&M Adjustments Adjustments Depreation &Tax Adjustments Mise Rate Base
Total Adjustments (Tab 3) (Tab 4) (Tab 5)Amortzaton (Tab 6)(Tab 7)Adjustments (Tab 8)
1 Operating Revenues:
2 Genera! Business Revenues 11,637,673 11.637,673
3 Interdepartmental
4 Speoial Sales 1,051,991 1,051,991
5 Other Operating Revenues (5,260.634)521,143 (5,939,633)157,656
6 T olal Operating Revenues 7,428,829 12,158,816 (5,939,633)1,209,846
7
6 Operating Expnses
9 Steam Production 4,879,169 1,005 4,676,165
10 Nuclear Production
11 Hydro Production 226,019 27,913 ige,10f
12 Other Power Supply 9.092,101 857,607 7,258,533 975.961
13 Transmission 287,354 (48,437)71,772 264.019
.14 Distribution 590,671 590,671
15 Customer Accounting (108,25)(108,425)
16 Customer Servce & Info (5,923,722)(5,923,722)
17 Sales
18 Administrative & General 1,796,960 1,691,962 204,998
19 Total O&M Expenses 10,840,128 (48,37)(2,891,217)12,400.716 204,998 1.174.067
20 Depreciation 2,738,026 2,476,377 261,649
21 Amortization 272,898 46,183 226,715
22 Taxes Other Than Income 765,162 765,162
23 Income Taxes: Federal (11.404,086)4,018.872 (1,625,12)(3,749,089)(1,082.418)(1,588,174)(7,377866)
24 State (1,466,541)546,098 (220,867)(509,439)(147,083)(132,722)(1,002,529)
25 Deferrd Income Taxes 9,312,312 198,801 861,571 11,480 272,164 218,810 7,749,486
26 Investment Tax Credit Adj.
27 Misc Revenue & Expense (345,174)(345,174)
26 Total Operating Expenses 10,712,725 4,370,161 (3,875.925)8,153,869 1,665,223 (531,925)1,031,622
29
30 Operating Rev For Return'(3,283,896)7,788,656 (2,063,908)(6,943,823)(1,565,223)531,925 (1,031,622)
31
32 Rate 8ase'
33 Electric Plent In Servce 54,091.394 54.091,394
34 Plant Held for Future Use (644,154)(644.154)
35 Misc Deferrd Debit 146,593 (4.596)(3,997)155.186
36 Elec Plant Acq Adj
37 Nuclear Fuel
38 Prepaymnts
39 Fuel Stock 2,355,158 2,355,158
40 Material & Supplies
41 Working Capitl (30,778)(30,778)
42 Weatherization Loans
43 Misc Rate Base (10.019)(10,019)
44 Total Electric Plant:55,908,195 (4,596)(3,997)55,916,788
45
46 Deductions
47 Accum Prov For Deprec (787,372)(448,42)(338,930)
48 Accum Prov For Amort (533.90)(32.831)(500,760)
49 Accum Def Income Tex (4,386,060)1,615,479 (122.194)500 (272,164)2,245,557 (7.853,238)
50 Unamortized ITC (116.179)(118,179)
51 Customer Adv For Canst (334,536)(334,536)
52 Customer Service Deposits
53 Miscellaneous Deductions (1.568,700)(1,571,507)2,807
54
55 Total Deductions'(7,728,37)43.972 (122,194)3,307 (753,36)2,127,378 (9,027.464)
56
57 Total Rate Base:48,179,758 43.972 (126,790)(690)(753,436)2,127,378 46,889.323
58
59
60 Estimated ROE impact ~1.6310/2.134%-0.564%~1.9030/.(,416%0.108%~1.034%0.000%0.000%
61
62
63
64 TAX CALCULATION-
65
66 Operating Revenue (6.42,211)12,552,426 (3.48,616)(11.90,870)(2,522,560)(970,160)(1,662,431)
67 Other Deductions
68 Interest (AFUDCI 201,475 201,475
69 Interest 1,092,182 1,092,182
70 Schedule -M" Additions 428,502 (2,581.684)(104.632)3.114,818
72 Schedule "M" Deductions 23.935,734 523,836 (765.399)(74.381)717.145 23,534,533
73 Income Before Tax (31.643.100)12,028.591 (4,864,902)(11,221.20)(3,239,706)(2,263.817)(22.082,146)
74
76 State Income Taxes (1,466,541)546,098 (220,867)(509.439)(147.083)(132,722)(1.002,529)
77 Taxable Income (30,176,559)11.482.493 (4.644,035)(10,711.681)(3.92.623)(2,131,095)(21.079.616)
78
79 Federal Income Taxes (11.404,086)4,018,872 (1,625,412)(3,749,089)(1.082.418)(1,588,174)(7,377.866)
Rocky Mountain Power
RESULTS OF OPERATIONS
Page 2.1
USER SPECIFIC INFORMATION
STATE:
PERIOD:
IDAHO
DECEMBER 2010
FILE:
PREPARED BY:
DATE:
TIME:
JAM Dec 2010 ID GRC
Revenue Requirement Department
5/18/2011
9:34:21 AM
TYPE OF RATE BASE:
ALLOCATION METHOD:
Year-End
2010 PROTOCOL
FERC JURISDICTION:Separate Jurisdiction
8 OR 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
FEDERAL/STATE COMBINED RATE
TAX RATE
35.00%
4.54%
1.615
37.951%
CAPITAL STRUCTURE INFORMATION
CAPITAL
STRUCTURE
EMBEDDED
COST
WEIGHTED
COST
DEBT
PREFERRED
COMMON
47.40%
0.30%
52.30%
100.00%
5.78%
5.43%
10.50%
2.740%
0.016%
5.492%
8.248%
OTHER INFORMATION
For information and support regarding capital structure and cost of debt, see the testimony of Mr. Bruce Willams.
For information and support regarding return on common equity, see the testimony of Dr. Sam Hadaway.
2010 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 3,574,583,105 3,368,022,988 206,560,116 11,637,673 218,197,789
3 Interdepartmental 2.3 0 0 0 0 0
4 Special Sales 2.3 501,563,210 471,750,719 29,812,490 1,051,991 30,864,481
5 Other Operating Revenues 2.4 326,069,070 306,976,744 19,092,327 (5.260,834)13,831,492
6 Total Operating Revenues 2.4 4,402,215,385 4,146,750,451 255,464,934 7,428,829 262,893,763
7
8 Operating Expenses:
9 Steam Production 2.5 957,497,818 897,859,848 59,637.970 4,879,169 64,517,140
10 Nuclear Production 2.6 0 0 0 0 0
11 Hydro Production 2.7 40,481,667 38,031,517 2,450,150 226,019 2,676,169
12 Other Power Supply 2.9 922,755,111 863,136,407 59,618,703 9,092,101 68,710,805
13 Transmission 2.10 195,628.269 183,769,934 11,858,335 287,354 12,145,689
14 Distribution 2.12 208,550.302 198,123,470 10,426,832 590,671 11,017,503
15 Customer Accounting 2.12 92,750,645 87,978,639 4,772,006 (108.25)4,663,581
16 Customer Service & Infor 2.13 128,944,905 121,813,010 7,131,894 (5,923,722)1,208,172
17 Sales 2.13 0 0 0 0 0
18 Administrative & General 2.14 146,076,485 136,611,406 9,465,079 1.796,96Q 11,262,040
19
20 Total 0 & M Expenses 2.14 2,692.685,201 2,527,324,231 165,360,970 10.840.128 176.201,098
21
22 Depreciation 2.16 491,643,870 463,652,092 27,991,778 2,738,026 30,729,804
23 Amortization 2.17 44,975,946 42,481,316 2,494,630 272,898 2,767,529
24 Taxes Other Than Income 2.17 136,512,728 130,094,757 6,417,971 765,162 7,183,133
25 Income Taxes - Federal 2.20 (482,761,917)(458,097,806)(24.664,111 )(11,404.086)(36,068,197)
26 Income Taxes - State 2.20 (58,348,068)(55,435,531 )(2.912.537)(1,466,541 )(4,379,078)
27 income Taxes - Def Net 2.19 761,444,172 724,719,282 36,724,890 9,312,312 46,037,202
28 Investment Tax Credit Adj.2.17 (1,874,204)(1,652,566)(221,638)0 (221,638)
29 Misc Revenue & Expense 2.4 (5,388,606)(5,100,609)(287,997)(345,174)(633.171)
30
31 Total Operating Expenses 2.20 3,578,889,124 3,367,985,168 210,903.956 10,712,725 221,616,681
32
33 Operating Revenue for Return 823,326,261 778,765,283 44,560.977 (3,283,896)41,277,081
34
35 Rate Base:
36 Electric Plant in Service 2.30 21,682,524,069 20,426,186,152 1,256,337,918 54,091,394 1.310,429,312
37 Plant Held for Future Use 2.31 17,678,149 17,033,995 644,154 (644,154)0
38 Misc Deferred Debits 2.33 198,021,223 192,699,549 5,321,674 146,593 5,468,268
39 Elec Plant Acq Adj 2.31 57,330,243 53,860,334 3,469,909 0 3,469,909
40 Nuclear Fuel 2.31 0 0 0 0 0
41 Prepayments 2.32 45,378,667 42,685,86 2,693,181 0 2,693,181
42 Fuel Stock 2.32 184,380,973 172,689,333 11.691,641 2.355,158 14,046,799
43 Material & Supplies 2.32 186.133,158 175,106,323 11,026,835 0 11,026,835
44 Working Capital 2.33 64,526,097 60.864,098 3,662,000 (30,778)3,631,222
45 Weatherization Loans 2.31 8,619,651 5,438,646 3,181,004 0 3,181,004
46 Miscellaneous Rate Base 2.34 135,566 125,548 10,019 (10,019)0
47
48 Total Electric Plant 22,444,727,798 21,146,689,463 1,298,038.335 55,908,195 1,353,946,529
49
50 Rate Base Deductions:
51 Accum Prov For Depr 2.38 (6,842,986,868)(6,436,439,471 )(406,547.397)(787,372)(407,334,769)
52 Accum Prov For Amort 2.39 (456,063,105)(431,613,347)(24,449,758)(533,590)(24.983,348)
53 Accum Def Income Taxes 2.35 (2,999,250,147)(2,833,509,688)(165,740,459)(4,386,060)(170,126,518)
54 Unamortized ITC 2.35 (5,669,770)(5,629,625)(40,145)(118,179)(158,324)
55 Customer Adv for Const 2.34 (18,494,962)(17,662,878)(832,083)(334,536)(1,166,620)
56 Customer Service Deposits 2.34 0 0 0 0 0
57 Misc. Rate Base Deductions 2.34 (136,934,409)(134,027,093)(2,907.316)(1,568,700)(4,476,016)
58
59 Total Rate Base Deductions (10,459,399,260)(9,858,882,103)(600,517.158)(7,728,437)(608,245.595)
60
61 Total Rate Base 11,985,328.537 11,287,807,361 697,521,177 48,179.758 745,700,934
62
63 Return on Rate Base 6.869%6.388%5.535%
64
65 Return on Equity 7.865%6.945%5.314%
66 Net Power Costs 1,125,770,120 70,880,883 82,767,927
67 100 Basis Points in Equity:
68 Revenue Requirement Impact 101,022,205 5,879,282 6,285,381
69 Rate Base Decrease (847,936,212)(52,782,292)(64,374,333)
2010 PROTOCOL Page 2.3Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
70 Sales to Ultimate Customers
71 44 Residential Sales
72 0 S 1,357,826,906 1,296,315,399 61,511,506 2,504,407 64,015,913
73
74 81 1,357,826,906 1,296,315,399 61,511,506 2,504,407 64,015,913
75
76 442 Commercial & Industrial Sales
77 0 S 2,176,375,421 2,031,797,692 144,577,729 9,006,259 153,583,988
78 P SE
79 PT SG
80
81
82 81 2,176,375,421 2,031,797,692 144,577,729 9,006,259 153,583,988
83
84 444 Public Street & Highway Lighting
85 0 S 20,610,361 20,139,481 470,881 127,007 597,888
86 0 SO
87 81 20,610,361 20,139,481 470,881 127,007 597,888
88
89 445 Other Sales to Public Authority
90 0 S 19,770,416 19,770,416
91
92 81 19,770,416 19,770,416
93
94 448 Interdepartmental
95 DPW S
96 GP SO
97 81
98
99 Total Sales to Ultimate Customers 81 3,574,583,105 3,368,022,988 206,560,116 11,637,673 218,197,789
100
101
102
103 447 Sales for Resale-Non NPC
104 P S 9,040,737 9,040,737
105 9,040,737 9,040,737
106
107 447NPC Sales for Resale-NPC
108 p SG 491.619,370 461,864,146 29,755,225 1,109,256 30,864,481
109 P SE 903,103 845,837 57,266 (57,266)
110 P SG
111 492,522,473 462.709,983 29,812,490 1,051,991 30,864,481
112
113 Total Sales for Resale 81 501,563,210 471,750,719 29.812,490 1.051,991 30,864,481
114
115 449 Provision for Rate Refund
116 p S
117 P SG
118
119
120 81
121
122 Total Sales from Electricit B1 4,076,146,315 3,839,773,708 236,372,607 12,689,663 249,062,270
123 450 Forfeited Discounts & Interest
124 CUST S 7,411,88 7,004,958 406,930 406,930
125 CUST SO
126 81 7,411,888 7,004,958 406,930 406,930
127
128 451 Misc Electric Revenue
129 CUST S 5,861,680 5,760,675 101,005 101,005
130 GP SG
131 GP SO 57,591 54,254 3,337 3,337
132 81 5,919,272 5,814,930 104,342 104,342
133
134 453 Water Sales
135 P SG 2,609 2,451 158 158
136 81 2,609 2,451 158 158
137
138 454 Rent of Electric Propert
139 DPW S 10,656,375 10,447,639 208,736 208,736
140 T SG 5,417,250 5,089,371 327,879 327,879
141 T SG
142 GP SO 3,485,471 3,283,514 201,957 201,957
143 81 19,559,096 18,820,525 738,571 738,571
144
145
2010 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 96,891,344 90,951,471 5,939,873 (5,939,833)39
149 CUST CN
150 OTHSE SE 8,162,720 7,645,120 517,600 132.527 650,127
151 OTHSO SO 474,389 44,902 27,487 27,487
152 OTHSGR SG 187,647,753 176,290,387 11,357,366 546,471 11,903,837
153
154
155 B1 293,176,206 215,333,880 17,842,326 (5,260,834)12,581,491
156
157 Total Other ElectriC Revenues B1 326,069,070 306,976,744 19,092,327 (5,260,834)13,831,492
158
159 Totl Electric Operating Revenues B1 4,402,215,385 4,146,750,451 255,464,934 7,428,829 262,893,763
160
161 Summary of Revenues by Factor
162 S 3,704,44,128 3,491,228,468 213,216,660 5,697,840 218,914,500
163 CN
164 SE 9,065,823 8,90,957 574,866 75,261 650,127
165 SO 4,017,451 3,784,670 232,781 232,781
166 SG 684,686,982 643,246,355 41,440,627 1,655,728 43,096,355
167 DGP
168
169 Total Electric Operating Revenues 4,402,215,385 4,146,750,451 255,464,934 7,428,29 262,893,763
170 Miscellaneous Revenues
171 41160 Gain on Sale of Utility Plant - CR
172 DPW S
173 T SG
174 G SO
175 T SG
176 P SG
177 81
178
179 41170 Loss on Sale of Utiity Plant
180 DPW S
181 T SG
182 81
183
184 4118 Gain from Emission Allowances
185 P S
186 P SE (2,817,551)(2,638,890)(178,662)(345,174)(523,836)
187 81 (2,817,551)(2,638,890)(178,662)(345,174)(523,836)
188
189 41181 Gain from Disposition of NOX Credits
190 P SE
191 81
192
193 4194 Impact Housing Interest Income
194 P SG
195 81
196
197 421 (Gain) I Loss on Sale of Utilty Plant
198 DPW S (764,726)(764,726)
199 T SG (761,976)(715,858)(46,119)(46,119)
200 T SG (469,173)(440.776)(28,397)(28,397)
201 PTD CN 121 116 5 5
202 PTD SO 1,951 1,838 113 113
203 P SG (577,251)(542,313)(34,938)(34,938)
204 81 (2,571,055)(2,461,719)(109,336)(109,336)
205
206 Total Miscellaneous Revenues (5,388,606)(5,100,609)(287,997)(345,174)(633,171)
207 Miscellaneous Expenses
208 4311 Interest on Customer Deposits
209 CUST S
210 81
211 Total Miscellaneous Expenses
212
213 Net Mise Revenue and Expense B1 (5,388,606)(5,100,609)(287,997)(345,174)(633,17)
214
2010 PROTOCOL Page 2.5
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAl
215 500 Operation Supervision & Engineering
216 P SG 18.301,279 17.193.595 1.107.684 20.198 1.127.881
217 P SG 1.805.751 1.696.458 109,293 109.293
218 B2 20.107.030 18.890.054 1.216.976 20.198 1.237.174
219
220 501 Fuel Related-Non NPC
221 P SE 15.015.379 14.063.250 952.129 (343)951.786
222 P SE
223 P SE
224 P SE
225 P SE 3.378.234 3.164.020 214.215 214.215
226 B2 18.393.613 17.227.269 1.166.343 (343)1.166.000
227
228 501NPC Fuel Related-NPC
229 P S (914.987)(665.891)(249.096)249,096
230 P SE 581.140.995 544.290.708 36.850.287 4,650.292 41.500.579
231 P SE
232 P SE
233 P SE 48.110.124 45.059,450 3.050.674 3.050.674
234 B2 628.336.133 588.684.267 39.651.865 4.899.388 44.551.253
235
236 Total Fuel Related 646.729,745 605.911,537 40.818.209 4.899.045 45.717.254
237
238 502 Steam Expenses
239 P SG 31,477.336 29.572.173 1.905.163 22.559 1.927,722
240 P SG 6.994.684 6.571.332 423.353 423.353
241 B2 38.472.021 36.143.505 2.328.516 22.559 2.351.075
242
243 503 Steam From Other Sources-Non-NPC
244 P SE 108 108
245 B2 108 108
246
247 503NPC Steam From Other Sources-NPC
248 P SE 3,655.727 3,423.917 231.811 (21.223)210.587
249 B2 3.655.727 3,423.917 231.811 (21.223)210.587
250
251 505 Electric Expenses
252 P SG 3.085.158 2.898,429 186.729 2.368 189.097
253 P SG 1.199.979 1.127.351 72.629 72.629
254 B2 4.285.137 4.025.779 259.358 2.368 261.725
255
256 506 Misc. Steam Expense
257 P SG 46.109.239 43.318.481 2,790.758 66.006 2.856.765
258 P SE
259 P SG 1.933.634 1.816.601 117.033 117.033
260 B2 48.042.874 45.135.082 2,907.791 66.006 2.973.798
261
262 507 Rents
263 P SG 338.245 317,773 20,472 20,472
264 P SG 44 413 27 27
265 B2 338.685 318,186 20,499 20,499
266
267 510 Maint Supervision & Engineering
268 P SG 4.580.349 4.303,123 277.225 (388.761)(111.536)
269 P SG 1.881.910 1.768,007 113.902 113.902
270 B2 6,462.259 6.071.131 391.128 (388.761)2.367
271
272
273
274 511 Maintenance of Structures
275 P SG 25.069,456 23.552.129 1.517.327 8.966 1,526.293
276 P SG 411,499 386.593 24.906 24.906
277 B2 25,80.955 23.938.722 1,542.233 8.966 1.551.199
278
279 512 Maintenance of Boiler Plant
280 P SG 105.721,429 99.322,648 6.398,781 252.065 6.650.847
281 P SG 7.201.452 6.765.584 435,867 435.867
282 B2 112.922.881 106.088,232 6.834,649 252.065 7.086.714
283
284 513 Maintenance of Electric Plant
285 P SG 38.150.749 35.841.678 2.309.071 14,430 2.323.501
286 P SG 783.588 736.162 47,427 47,427
287 B2 38.934.338 36.577.840 2.356,498 14,430 2.370.927
288
289 514 Maintenance of Misc. Steam Plant
290 P SG 9.254.784 8.694.639 560,145 3,410 563.555
291 P SG 2.811.384 2.641,225 170.159 170.159
292 B2 12.066.167 11.335.863 730.304 3,410 733.713
293
294 Total Steam Power Generation B2 957,497,818 897,859,848 59,637,970 4,879,169 64,517,140
2010 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
321
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 82
333
334 531 Maintenance of Electric Plant
335 P SG
336 82
337
338 532 Maintenance of Misc Nuclear
339 P SG
340 82
341
342 Total Nuclear Power Generation B2
343
344 535 Operation Super & Engineering
345 P DGP
346 P SG 4,590,184 4,312,364 -271,821 6,900 284,721
347 P SG (764,519)(718,246)(46,272)2,174 (44,098)
348
349 82 3,825,666 3,594,117 231,548 9,07Ji 240,623
350
351 536 Water For Power
352 P DGP
353 P SG 212,409 199,553 12,856 105 12,961
354 P SG
355
356 82 212,409 199,553 12,856 105 12.961
357
2010 PROTOCOL Page 2.7
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 SG 3,246,477 3,049,985 196,493 201,990 398,83
361 P SG 203,031 190,743 12,288 76 12,365
362
363 62 3,449,509 3,240,727 208,781 202,066 410,846
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 17,855,44 16,774,745 1,080,699 5,143 1,085,843
375 P SG 7,340,718 6,896,422 444,296 5,996 450,292
376
377
378 62 25.196.163 23,671.167 1,524,996 11,139 1,536,135
379
380 540 Rents (Hydro Generation)
381 P . DGP
382 P SG 116.623 109.564 7,059 (201)6.857
383 P SG 775 728 47 47
384
385 62 117,398 110,292 7,105 (201)6.904
386
387 541 Maint Supervision & Engineering
388 P DGP
389 P SG 469 441 28 0 29
390 P SG
391
392 62 469 441 28 0 29
393
394 542 MaintenanCe of Structures
395 P DGP
396 P SG 1.317,460 1,237,721 79,739 514 80,254
397 P SG 112.932 106.097 6,835 102 6,938
398
399 62 1,430,392 1,343,818 86,574 617 87,191
400
401
402
403
404 543 Maintenance of Dams & Waterways
405 P DGP
406 P SG 1,331.256 1,250,682 80.574 412 80.986
407 P SG 628,444 590,407 38.037 603 38.640
408
409 62 1,959,700 1.841,089 118,611 1.016 119.626
410
411 544 Maintenance of Electric Plant
412 P DGP
413 P SG 1.249.523 1,173.895 75,627 958 76.586
414 P SG 385,648 362.307 23.341 351 23.692
415
416 62 1.635,171 1,536.202 98,969 1,309 100.278
417
418 545 Maintenance of Misc. Hydro Plant
419 P DGP
420 P SG 1,841.743 1,730,271 111,471 514 111.986
421 P SG 813,048 763,838 49,210 379 49.589
422
423 62 2,654,790 2,494,109 160.681 894 161,575
424
425 Total Hydraulic Power Generation B2 40,481,667 38,031,517 2,450,150 226,019 2,676,169
2010 PROTOCOL Page 2.8
Year-End
FERC 6US UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
426
427 546 Operation Super & Engineering
428 P SG 358,628 336,922 21,706 2 21,708
429 P SG
430 82 358,628 336,922 21,706 2 21,708
431
432 547 Fuel-Non-NPC
433 P SE
434 P SE
435 82
436
437 547NPC Fuel-NPC
438 P SE 411,275,695 385,196,607 26,079,089 (2,147,890)23,931,198
439 P SE 21,345,038 19,991,544 1,353,494 1,353,94
440 82 432,620,733 405,188,151 27,432,583 (2,147,890)25,284,692
441
442 548 Generation Expense
443 p SG 13,323,739 12,517,320 806,418 6,999 813,417
444 P SG 1,314,796 1,235,218 79,578 79,578
445 82 14,638,534 13,752,538 885,996 6,999 892,995
446
447 549 Miscellaneous Other
448 P SG 3,440,696 3,232,448 208,248 3,393 211,641
449 P SG 15,260,859 14,337,197 923,662 113,745 1,037,408
450 82 18,701,556 17,569,646 1,131,910 117,138 1,249,048
451
452
- 453
454
455 550 Rents
456 P SG 30,076 28,256 1,820 1,820
457 P SG 3,528,603 3,315,034 213,568 213,568
458 82 3,558,679 3,343,290 215,389 215,389
459
460 551 Maint Supervision & En9ineering
461 P SG
462 62
463
464 552 Maintenance of Structures
465 P SG 1,056,123 992,201 63.922 224 64,146
466 P SG 184,471 173,306 11,165 11,165
467 82 1,240,594 1,165,507 75,087 224 75,311
468
469 553 Maint of Generation & Electric Plant
470 P SG 4,438,293 4,169,666 268,627 318,657 587,284
471 P SG 2,101,615 1,974,415 127,200 127,200
472 P SG 2,456,496 2,307,817 148,679 148,679
473 82 8,996,404 8,451,897 544,507 318,657 863,164
474
475 554 Maintenance of Misc. Other
476 P SG 728,404 684,318 44,087 166 44,252
477 P SG 1,331,445 1,250,859 80,586 80,586
478 P SG 136,317 128,066 8,251 8,251
479 82 2,196,166 2,063,243 132.923 166 133,089
480
481 Total Other Power Generation 62 482,311,295 451,871,195 30,44,100 (1.704,704)28,735,396
482
483
484 555 Purchased Power-Non NPC
485 DMSC S (36,817,673)(37,424,309)606,635 (606,635)
486 (36,817,673)(37,424.309)606,635 (606,635)
487
488 555NPC Purchased Power-NPC
489 P SG 469,600,699 441,178,153 28,422,546 2,918,183 31.340,729
490 P SE (52,775,347)(49,2128,850)(3,346,497)7,026,558 3.680,061
491 Seasonal Co P SG
492 DGP
493 416,825,351 391,749,303 25,076,049 9,944,741 35,020,790
494
495 Total Purchased Power 82 380,007,678 354,324,994 25,682.684 9,338,106 35,020.790
496
497 556 System Control & Load Dispatch
498 P SG 877,454 824,346 53.108 540 53,68
499
500 82 877,454 824,346 53,108 540 53,648
501
502
2010 PROTOCOL Page2.9
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
503
504 557 Other Expenses
505 P S (183,792)(150,819)(32,973)975,961 942,988
506 P SG 58,620,601 55,072,594 3,548,007 482,199 4,030,206
507 P SGCT 1,122,425 1,054,229 68.196 68.196
508 P SE
509 P SG
510 P TROJP
511
512 82 59,559,234 55,976.003 3,583,231 1,458,160 5.041,390
513
514 Embedded Cost Differentials
515 Company Owned Hyd P DGP
516 Company Owned Hyd P SG
517 Mid-C Contract P MC
518 Mid-C Contract P SG
519 Existing OF Contracts P S
520 Existing OF Contracts P SG
521
522
523
524 Hydro Endowment Fixed Dollar Proposal
525 Klamath Surcharge Sit P S (550)975,411 (975,961)(975,961)
526 ECD Hydro P S (0)(835.542)835,542 835,542
527 (550)139.869 (140,419)(140,419)
528
529 Total Other Power Supply B2 44,443,816 411,265,212 29,178,604 10,796,805 39,975,409
530
531 Total Production Expense B2 1,920,734,596 1,799,027,772 121,706,823 14,197,290 135,904,113
532
533
534 Summary of Production Expense by Factor
535 S (37,917,003)(38,101,150)184,147 618,22 802.569
536 SG 926,383,328 870,314,048 56,069,280 4,071,366 60,140,645
537 SE 1.031,145,846 965,760,645 65,385,201 9,507,502 74,892,703
538 SNPPH
539 TROJP
540 SGCT 1,122,425 1,054,229 68,196 68,196
541 DGP
542 DEU
543 DEP
544 SNPPS
545 SNPPO
546 DGU
547 MC
548 SSGCT
549 SSECT
550 SSGC
551 SSGCH
552 SSECH
553 Total Production Expense by Factor 82 1,920,734,596 1,799,027,772 121,706,823 14.197,290 135.904.113
554 560 Operation Supervision & Engineering
555 T SG 5,041,115 4.736,002 305.113 5.073 310,186
556
557 82 5,041,115 4,736,002 305,113 5.073 310.186
558
559 561 Load Dispatching
560 T SG 10.336,896 9,711,256 625,640 11.331 636,971
561
562 82 10,336,896 9.711,256 625,640 11,331 636.971
563 562 Station Expense
564 T SG 2.124,825 1,996,220 128,605 1.457 130,062
565
566 82 2.124.825 1,996,220 128,605 1,457 130,062
567
568 563 Overhead Line Expense
569 T SG 120,209 112,934 7,276 92 7,367
570
571 82 120,209 112,934 7,276 92 7,367
572
573 564 Underground Line Expense
574 T SG
575
576 82
577
2010 PROTOCOL Page 2.10
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
578 565 Transmission of Electricity by Others
579 T SG
580 T SE
581
582
583 565NPC Transmission of Electricity by Others-NPC
584 T SG 130,633,756 122,727,158 7,906,598 319,092 8,225,690
585 T SE 6,220,893 5,826,425 394,468 (55,073)339,395
586 136,854,649 128,553,583 8,301,066 264,019 8,565,085
587
588 Total Transmission of Electricity by Others 62 136,854,649 128,553,583 8,301,066 264,019 8,565.o5
589
590 566 Misc. Transmission Expense
591 T SG 4,257,862 4,000,155 257,707 (48,019)209,688
592
593 62 4,257,862 4,000,155 257,707 (48,019)209,688
594
595 567 Rents - Transmission
596 T SG 1,312,382 1,232,950 79,432 207 79,639
597
598 62 1,312,382 1,232,950 79,432 207 79,639
599
600 568 Maint Supervision & Engineering
601 T SG 1,334,303 1,253,545 80,759 1,350 82,109
602
603 62 1,334,303 1,253,545 80,759 1,350 82,109
604
605 569 Maintenance of Structures
606 T SG 4,669,784 4,387,146 282,638 3,321 285,959
607
608 62 4,669,784 4,387,146 282,638 3,321 285,959
609
610 570 Maintenance of Station Equipment
611 T SG 10,092,385 9,481,544 610,841 8,132 618,973
612
613 62 10,092.385 9,481,544 610,841 8,132 618,973
614
615 571 Maintenance of Overhead Lines
616 T SG 19,173.510 18,013,035 1,160,475 40,363 1,200,839
617
618 62 19,173,510 18,013,035 1,160,475 40,363 1,200,839
619
620 572 Maintenance of Underground Lines
621 T SG 36.881 34,649 2,232 18 2,251
622
623 62 36,881 34,649 2,232 18 2,251
624
625 573 Maint of Misc. Transmission Plant
626 T SG 273,467 256,915 16,552 9 16,560
627
628 62 273,467 256,915 16,552 9 16,560
629
630 Total Transmission Expense B2 195,628,269 183,769,934 11,858,335 287,354 12,145,689
631
632 Summary of Transmission Expense by Factor
633 SE 6,220.893 5,826,425 394,468 (55,073)339,395
634 SG 189,407,376 177,943,509 11,463,867 342,427 11,806,294
635 SNPT
636 Total Transmission Expense by Factor 195,628.269 183,769,934 11.858,335 287,354 12.145,689
637 580 Operation Supervision & Engineering
638 DPW S 53,020 88,736 (35,716)(35,716)
639 DPW SNPD 15.572,431 14,850,466 721,945 15,139 737,084
640 62 15,625,451 14,939,222 686,229 15,139 701,368
641
642 581 Load Dispatching
643 DPW S
644 DPW SNPD 13,735,481 13,098,698 636,783 13,264 650,047
645 62 13,735,481 13,098,698 636,783 13,264 650,047
646
647 582 Station Expense
648 DPW S 3,788,937 3,549,316 239,621 2,641 242,261
649 DPW SNPD 23,895 22,787 1,108 19 1,127
650 62 3,812,831 3,572,103 240,728 2,660 243,389
651
2010 PROTOCOL Page 2.11
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
652 583 Overhead Line Expenses
653 DPW S 5.725.809 5,532.611 193;198 3.620 196,818
654 DPW SNPD 36.344 34.659 1,685 20 1,705
655 62 5.762.152 5,567.270 194,882 3.640 198.522
656
657 584 Underground Line Expense
658 DPW S 287 264 23 23
659 DPW SNPD
660 62 287 264 23 23
661
662 585 Street Lighting & Signal Systems
663 DPW S
664 DPW SNPD 209.265 199.563 9.702 209 9.911
665 62 209.265 199.563 9.702 209 9,911
666
667 586 Meter Expenses
668 DPW S 5,377.919 5.102,422 275,498 5.034 280.532
669 DPW SNPD 1,186,441 1.131,437 55.004 949 55.953
670 62 6,564.361 6.233.859 330.502 5.983 336,85
671
672 587 Customer Installation Expenses
673 DPW S 12.634.849 12.235.508 399,341 7.224 406.565
674 DPW SNPD
675 62 12.634.849 12.235,508 399.341 7,224 406.565
676
677 588 Misc. Distribution Expenses
678 DPW S 1.310.808 1.308,497 2.311 (1,147)1,164
679 DPW SNPD 4.576,455 4.364.288 212.167 206 212.373
680 62 5.887.263 5.672.785 214,478 (941)213.537
681
682 589 Rents
683 DPW S 3.187.858 3.175.008 12.850 16 12.866
684 DPW SNPD 65,814 62.763 3.051 3.051
685 62 3,253.672 3.237.771 15.901 16 15.917
686
687 590 Maint Supervision & Engineering
688 DPW S 816.745 763.677 53,068 923 53.991
689 DPW SNPD 4.676,84 4,459.680 216.804 4.579 221,382
690 62 5,493.229 5.223.,358 269,871 5.502 275.373
691
692 591 Maintenance of Structures
693 DPW S 1.749.265 1,594.805 154.460 154,460
694 DPW SNPD 79.605 75.914 3.691 3.691
695 62 1.828.870 1,670.719 158.151 158.151
696
697 592 Maintenance of Station Equipment
698 DPW S 11.145.163 10,410.931 734.232 10.769 745.001
699 DPW SNPD 1,476.908 1.408,438 68,70 1.374 69,844
700 62 12.622.071 11.819.369 802.702 12.143 814,844
701 593 Maintenance of Overhead Lines
702 DPW S 83.673.582 78.569,424 5.104.158 507.039 5.611.197
703 DPW SNPD 1.056.813 1.007.819 48.994 (567)46.428
704 62 84.730.396 79.577.243 5.153.152 506,472 5,659.624
705
706 594 Maintenance of Underground Lines
707 DPW S 22.786,414 22.099.175 687.240 8.584 695,823
708 DPW SNPD
709 62 22.786,414 22.099.175 687.240 8.584 695.823
710
711 595 Maintenance of Line Transformers
712 DPW S
713 DPW SNPD 883,285 842,335 40,949 720 41,670
714 62 883.285 842.335 40.949 720 41,670
715
716 596 Maint of Street Lighting & Signal Sys.
717 DPW S 4,084.559 3.927.770 156.790 2.700 159,489
718 DPW SNPD
719 62 4.084.559 3.927,770 156,790 2.700 159,489
720
2010 PROTOCOL Page 2.12Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
721 597 Maintenance of Meters
722 DPW S 4.802.396 4.500.189 302.207 5.541 307.749
723 DPW SNPD 1.088.248 1.037.796 50,452 738 51.189
724 62 5.890.644 5.537,985 352.659 6.279 358.938
725
726 598 Maint of Misc. Distribution Plant
727 DPW S 2.056.220 2.011,413 44.807 44.807
728 DPW SNPD 689.001 657.058 31.942 1.076 33.018
729 62 2.745,221 2.668,472 76.749 1.076 77.826
730
731 Total Distribution Expense B2 208.550.302 198,123,470 10,426,832 590,671 11,017,503
732
733
734 Summary of Distribution Expense by Factor
735 S 163.193.833 154,869.747 8.324.086 552.944 8.877.030
736 SNPD 45.356,469 43.253.723 2.102.746 37.726 2.140,473
737
738 Total Distribution Expense by Factor 208.550,302 198.123.470 10,426.832 590.671 11,017.503
739
740 901 Supervision
741 CUST S 1.704 1.704
742 CUST CN 2,495.978 2.399,412 96.567 1.613 98.179
743 62 2,497.682 2,401,115 96.567 1.613 98.179744
745 902 Meter Reading Expense
746 CUST S 20.633.641 18.949.062 1,684.580 29,696 1.714,275
747 CUST CN 1.919.847 1.845.571 74.277 1.239 75.516
748 62 22.553.488 20.794.632 1.758.856 30.935 1.789.791
749
750 903 Customer Receipts & Collections
751 CUST S 7,456.791 7.065,77 391.315 6.262 397.577
752 CUST CN 47,482.101 45.645.070 1.837.031 26.768 1,863.799
753 62 54.938.892 52.710.547 2.228.346 33.030 2.261.376
754
755 904 Uncollectible Accounts
756 CUST S 12,495.007 11.816,850 678.156 (174.096)504.061
757 P SG
758 CUST CN 95,649 91.948 3.701 3.7017596212.590.656 11.908.799 681.857 (174.096)507.761
760
761 905 Misc. Customer Accounts Expense
762 CUST S 5.016 5.016
763 CUST CN 164.911 158,531 6.380 93 6,474
764 62 169.927 163.546 6.380 93 6,74765
766 Total Customer Accounts Expense B2 92,750,645 87,978,639 4,772,006 (108,425)4,663.581
767
768 Summary of Customer Accts Exp by Factor
769 S 40.592.159 37.838.108 2.754,051 (138.138)2.615.913
770 CN 52.158,486 50.140.531 2.017,955 29.713 2.047.668
771 SG
772 Total Customer Accounts Expense by Factor 92.750.645 87.978.639 4.772.006 (108,425)4.663.581
773
774 907 Supervision
775 CUST S
776 CUST CN 263.903 253,693 10.210 203 10,41377762263.903 253.693 10.210 203 10,413
778
779 908 Customer Assistance
780 CUST S 121.361.303 114,557.969 6,803,334 (5.930,478)872.856
781 CUST CN 2.794,497 2.686.381 108.116 2.114 110.230
782
783
784 62 124.155.800 117.244,350 6.911.450 (5.928.364)983,086
785
2010 PROTOCOL Page 2.13
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
786 909 Informational & Instructional Adv
787 CUST S 645,251 585,129 60,122 3,571 63,693
788 CUST CN 3,789,781 3,63,159 146,623 867 147,490
789 82 4,435,032 4,228,287 206,745 4,438 211,183
790
791 910 Misc. Customer Service
792 CUST S
793 CUST CN 90,169 86,680 3,489 3,490
794
795 82 90,169 86,680 3,489 3,90
796
797 Total Customer Service Expense B2 128,94,905 121,813,010 7,131,894 (5,923,722)1,208,172
798
799
800 Summary of Customer Service Exp by Factor
801 S 122,006,554 115,143,098 6,863,457 (5,926,907)936,550
802 CN 6,938,350 6,669,913 268,437 3,186 271,623
803
804 Total Customer Service Expense by Factor 82 128,944,905 121,813,010 7,131,894 (5,923,722)1,208,172
805
806
807 911 Supervision
808 CUST S
809 CUST CN
810 82
811
812 912 Demonstration & Selln9 Expense
813 CUST S
814 CUST CN
815 82
816
817 913 Advertisin9 Expense
818 CUST S
819 CUST CN
820 82
821
822 916 Misc. Sales Expense
823 CUST S
824 CUST CN
825 82
826
827 Total Sales Expense 82
828
829
830 Total Sales Expense by Factor
831 S
832 CN
833 Total Sales Expense by Factor
834
835 Total Customer Service Exp Including Sales B2 128,94,905 121,813,010 7,131,894 (5,923,722)1,208,172
836 920 Administrative & General Salaries
837 PTD S (5,230,152)(5,723,882)493,730 (493,730)(0)
838 CUST CN
839 PTD SO 71,688,978 67,535,145 4,153,833 380,524 4,534,357
840 82 66,458,826 61,811,263 4,647,563 (113,206)4,534,357
841
842 921 Offce Supplies & expenses
843 PTD S 736,310 687,081 49,229 49,229
844 CUST CN
845 PTD SO 9,237,574 8,702,326 535,247 (2,787)532,461
846 82 9,973,883 9,389,407 584,476 (2,787)581,689
847
848 922 A&G Expenses Transferred
849 PTD S
850 CUST CN
851 PTD SO (28,375,128)(26,731,004)(1,644,124)35,815 (1,608,309)
852 82 (28,375,128)(26,731,004)(1,644,124)35,815 (1,608,309)
853
2010 PROTOCOL Page 2.14
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
854 923 Outside Services
855 PTD S 8,195 8,195
856 CUST CN
857 PTD SO 9,396,107 8,851,674 544,433 141,157 685,590
858 B2 9,404,302 8,859,869 544,433 141,157 685,590
859
860 924 Property Insurance
861 PT S
862 PT SG 88,661 88,661
863 PTD SO 23,341,430 21,988,971 1,352,459 (571,407)781,052
864 B2 23,341,430 21,988,971 1,352,459 (482,745)869,714
865
866 925 Injuries & Damages
867 PTD SO 8,492,514 8,000,438 492,077 (22,932)469,144
868 B2 8,492,514 8,000,438 492,077 (22,932)469,144
869
870 926 Employee Pensions & Benefits
8I"LABOR S
872 CUST CN
873 LABOR SO
874 B2
875
876 927 Franchise Requirements
877 DMSC S
878 DMSC SO
879 B2
880
881 928 Regulatory Commission Expense
882 DMSC S 13,874,697 12,675,629 1,199,068 39,083 1,238,151
883 CUST CN
884 DMSC SO 1,538,229 1,449,101 89,129 239 89,367
885 FERC SG 2,513,914 2,361,760 152,154 152,154
886 B2 17,926,840 16,486,489 1,44,351 39,322 1,479,673
887
888 929 Duplicate Charges
889 LABOR S
890 LABOR SO (6,130,868)(5,775,630)(355,237)(1,172)(356,409)
891 B2 (6,130,868)(5,775,630)(355,237)(1,172)(356,409)
892
893 930 Misc General Expenses
894 PTD S 2,718,026 2,705,076 12.950 192.048 204,998
895 CUST CN 1,601 1,539 62 (7)55
896 P SG
897 LABOR SO 13,592,405 12.804,828 787,577 2,008,412 2,795,989
898 B2 16,312,031 15,511,443 800.589 2,200,453 3,001,042
899
900 931 Rents
901 PTD S 993,159 993,159
902 PTD SO 5,344,545 5,034,869 309.676 (34)309,62
903 B2 6,337,703 6.028,028 309,676 (34)309,642
904
905 935 Maintenance of General Plant
906 G S 22,861 22,861
907 CUST CN
908 G SO 22,312,089 21.019,273 1,292,816 3,089 1,295.906
909 82 22,334,950 21,042,134 1,292,816 3,089 1,295.906
910
911 Total Administrative & General Expense B2 146,076,485 136,611,406 9,465,079 1,796,960 11,262,040
912
913 Summary of A&G Expense by Factor
914 S 13,123,095 11,368,118 1.754,977 (262.599)1,492,378
915 SO 130,437,875 122,879,988 7,557,886 1.970,905 9,528,791
916 SG 2,513,914 2,361,760 152,154 88.661 240.816
917 CN 1.601 1,539 62 (7)55
918 Total A&G Expense by Factor 146,076.485 136,611,406 9,465,079 1.796,960 11,262,040
919
920 Total O&M Expense B2 2,692,685,201 2,527,324,231 165,360,970 10,840,128 176,201,098
2010 PROTOCOL Page 2.15
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
921 403SP Steam Depreciation
922 P SG 22,205.504 20,861,518 1,343,986 1,343,986
923 P SG 25,715,098 24,158,693 1,556,404 1,556,404
924 P SG 63,751,644 59,893,081 3,858,563 1,051,088 4,909,651
925 P SG 7,844,012 7,369,254 474.758 474,758
926 63 119,516,259 112,282,546 7,233,712 1,051,088 8,284,800
927
928 403NP Nuclear Depreciation
929 P SG
930 63
931
932 403HP Hydro Depreciation
933 P SG 3,407,623 3,201,377 206,246 206,246
934 P SG 1,007,037 946,086 60,951 60,951
935 P SG 7,864,486 7,388,489 475,997 291,813 767,811
936 P SG 3,557,399 3,342,088 215.311 13,270 228,581
937 63 15.836,545 14,878,040 958,506 305,083 1.263.589
938
939 4030P Other Production Depreciation
940 P SG 123,595 116,114 7,481 7,481
941 P SG 31,868.578 29.939,735 1,928,843 1,928,843
942 P SG 2,601,101 2,443,669 157,431 157,431
943 P SG 73,261,078 68.826,957 4,434,121 480,531 4,894,652
944 63 107.854,351 101.326,475 6,527,876 480,531 6,988,407
945
946 403TP Transmission Depreciation
947 T SG 11,210,232 10,531,734 678,98 678,498
948 T SG 12,494,962 11.738,705 756,257 756,257
949 T SG 47.973,502 45,069,909 2,903,592 895,587 3,799,180
950 63 71.678.696 67,340,348 4,338.348 895,587 5.233,935
951
952
953
954 403 Distribution Depreciation
955 360 Land & Land Right' DPW S 307,179 289,385 17,794 17,794
956 361 Strctres DPW S 1,149.215 1,126,198 23,017 23,017
957 362 Station Equipment DPW S 12.399.378 11,765.381 633,997 633,997
958 363 Storage Battery Eqt DPW S 29.272 29,272
959 364 Poles & Towers DPW S 34.584.953 32,455,413 2,129,540 471 2,130,011
960 365 OH Conducrs DPW S 19,225.134 18,255,947 969,187 969.187
961 366 UG Conduit DPW S 7.784,052 7,621,932 162,121 162.121
962 367 UG Conductr DPW S 17,901.089 17,418.940 482,149 482.149
963 368 Line Trans DPW S 27,722,730 26,257.642 1,465.088 1,465,088
964 369 Seivice DPW S 12.019,012 11,478.139 540,873 540,873
965 370 Meter DPW S 6,471.787 6,025.308 44,479 446,479
966 371 Inst Cust Pram DPW S 495,548 487.909 7,637 7,637
967 372 leased Property DPW S
968 373 Street Lighting DPW S 2,211,652 2,182.252 29,400 29,400
969 63 142,300,998 135,393.717 6,907.280 471 6.907.752
970
971 403GP General Depreciation
972 G-SITUS S 12.056,052 11,313,018 743.034 13,380 756,414
973 PT SG 328,358 308,484 19,874 19,874
974 PT SG 574,222 539,487 34,755 34.755
975 P SE 22.664 21,227 1,437 1,437
976 CUST CN 1,704,508 1,638,562 65,948 65,948
977 G-SG SG 5,817,168 5,465.084 352.084 12,903 364,986
978 PTD SO 13,800,885 13,001.229 799,657 (1.017)798,640
979 G-SG SG 6.010 5,646 364 364
980 G-SG SG 147,156 138,249 8,907 8.907
981 B3 34,457.022 32,430,967 2.026.056 25,266 2.051,322
982
983 403GVO General Vehicles
984 G-SG SG
985 63
986
987 403MP Mining Depreciation
988 P SE
989 63
990
2010 PROTOCOL Page 2.16
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
991 403EP Experimental Plant Depreciation
992 P SG
993 P SG
994 B3
995 4031 ARO Depreciation
996 P S
997 B3
998
999
1000 Total Depreciation Expense B3 491,643,870 463,652,092 27,991,778 2,738,026 30,729,804
1001
1002 Summary S 154,357,049 146,706,735 7,650,314 13.852 7,664,166
1003 DGP
1004 DGU
1005 SG 321,758,764 302,284,340 19,474,424 2.725.192 22.199,616
1006 SO 13,800,885 13,001,229 799,657 (1.017)798,640
1007 CN 1,704,508 1,638,562 65,946 65,946
1008 SE 22,664 21,221 1,437 1,437
1009 SSGCH
1010 SSGCT
1011 Total Depreciation Expense By Factor 491,643,80 463,652,092 27,991,778 2,738.026 30.729.804
1012
1013 404GP Amort of L T Plant - Capital Lease Gen
1014 I-SITUS S 1,478,533 1,478,533
1015 I-SG SG
1016 PTD SO 1,166,807 1.099,199 67,608 67,608
1017 P SG
1018 CUST CN 275,829 265,157 10,672 10.672
1019 P SG
1020 B4 2.921,169 2.842,890 78,279 78,279
1021
1022 404SP Amort of L T Plant - Cap Lease Steam
1023 P SG
1024 P SG
1025 64
1026
1027 4041P Amort of L T Plant - Intangible Plant
1028 I-SITUS S 184,245 163,713 20,532 20.532
1029 P SE 12,068 11,322 767 767
1030 I-SG SG 9.041.830 6,494.574 547,256 46,183 593,439
1031 PTD SO 14,250,413 13,424.710 825,703 825.703
1032 CUST CN 5.532,601 5,318,551 214,050 214,050
1033 I-SG SG 2,615,539 2,457,233 158,305 522,199 680,505
1034 I-SG SG 309,262 290.563 18,719 18,719
1035 P SG
1036 I-SG SG
1037 I-SG SG 54.154 50.676 3,278 3,278
1038 P SG (197.996)(186,013)(11,984)(11,984)
1039 B4 31,802,156 30,025,529 1,776,627 568,382 2,345,009
1040
1041 404MP Amort of L T Plant - Mining Plant
1042 P SE
1043 64
1044
1045 4040P Amort of L T Plant - Other Plant
1046 P SG
1047 B4
1048
1049
1050 404HP Amortization of Other Electric Plant
1051 P SG 122,773 115,342 7,431 7,431
1052 P SG 46,413 43,604 2,809 2,809
1053 P SG
1054 B4 169,186 158,946 10,240 10,240
1055
1056 Total Amortization of Limited Term Piant B4 34,892,511 33,027,365 1,865,146 568,382 2,433,528
1057
1058
1059 405 Amortization of Other Electric Plant
1060 GP S
1061
1062 64
1063
2010 PROTOCOL Page 2.17
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1064 406 Amortization of Plant Acquisition Adj
1065 P S
1066 P SG
1067 P SG
1068 P SG 5,518.393 5.184.392 334.000 334.000
1069 P SO
1070 B4 5.518.393 5.184,392 334.000 334.000
1071 407 Amort of Prop Losses. Unrec Plant. etc
1072 DPW S (302,455)(302,455)1073 GP SO
1074 P SG.p 2.860.972 2.687.811 173.160 (173,160)(0)
1075 P SE
1076 P SG
1077 P TROJP 2,006.526 1.884.202 122.324 (122.324)1078 84 4,565.043 4.269.559 295.484 (295,484)(0)1079
1080 Total Amortization Expense 84 44,975,946 42,481,316 2,494,630 272,898 2,767,529
1081
1082
1083
1084 Summary öf Amortization Expense by Factor
1085 S 1.360.324 1.339.792 20,532 20,532
1086 SE 12.088 11.322 767 767
1087 TROJP 2.006,526 1,884.202 122.324 (122.324)
1088 DGP
1089 DGU
1090 SO 15,17.220 14.523,909 893.311 893.311
1091 SSGCT
1092 SSGCH
1093 SG-P 2,860.972 2.687.811 173.160 (173.160)(0)
1094 CN 5.808,430 5.583.708 224.722 224.722
1095 SG 17,510.387 16,450,572 1.059.815 568.382 1.628.197
1096 Total Amortization Expense by Factor 44.975.946 42.481.316 2,494.630 272.898 2.767.529
1097 408 Taxes Other Than Income
1098 DMSC S 25.831.078 25.831,078
1099 GP GPS 100.361,440 94.548,256 5,815,185 765.162 6.580.347
1100 GP SO 9.44.796 8.893.773 547.023 547,023
1101 P SE 879,415 823.651 55.764 55,764
1102 P SG
1103 DMSC OPRV-ID
1104 GP EXCTAX
1105 GP SG
1106
1107
1108
1109 Total Taxes Other Than Income B5 136,512,728 130,094,757 6,417,971 765,162 7,183,133
1110
1111
1112 41140 Deferred Investment Tax Credit - Fed
1113 PTD DGU (1.874.204)(1.652,566)(221.638)(221,638)
1114
1115 87 (1.874.204)(1.652.566)(221,638)(221.638)1116
1117 41141 Deferred Investment Tax Credit - Idaho
1118 PTD DGU
1119
1120 87
1121
1122 Total Deferred ITC B7 (1,874,204)(1,652,566)(221,638)(221,638)
1123
2010 PROTOCOL Page 2.18
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1124
1125 427 Interest on Long-Term Debt
1126 GP S 1.092.182 1,092,182
1127 GP SNP 363,203,396 342.362.355 20.841.041 20.841.041
1128 B6 363,203,396 342.362,355 20,841.041 1,092,1ß2 21.933.223
1129
1130 428 Amortization of Debt Disc & Exp
1131 GP SNP 6.058.937 5,711.268 347.669 347,669
1132 B6 6,058.937 5,711.268 347,669 347.669
1133
1134 429 Amortization of Premium on Debt
1135 GP SNP (2.718)(2.562)(156)(156)1136 B6 (2.718)(2.562)(156)(156)
1137
1138 431 Other Interest Expense
1139 NUTIL OTH
1140 GP SO
1141 GP SNP 12.367,152 11.657.510 709.642 709,642
1142 B6 12,367.152 11.657,510 709.642 709,642
1143
1144 432 AFUDC - Borrowed
1145 GP SNP (44,618,458)(42,058,198)(2,560.260)(2,560.260)
1146 (44,618,58)(42,058,198)(2.560,260)(2,560.260)1147
1148 Total Elec. Interest Deductions for Tax B6 337.008.309 317,670,373 19.337,936 1.092.182 20,430.118
1149
1150 Non-Utiity Portion of Interest
1151 427 NUTIL NUTIL
1152 428 NUTIL NUTIL
1153 429 NUTIL NUTIL
1154 431 NUTIL NUTIL
1155
1156 Total Non-utilty Interest
1157
1158 Total Interest Deductions for Tax B6 337.008,309 317.670,373 19,337.936 1,092.182 20,430,118
1159
1160
1161 419 Interest & Dividends
1162 GP S
1163 GP SNP (79,298.238)(74,748.011)(4.550.227)201,475 (4.348.752)1164 Total Operating Deductions for Tax B6 (79.298,238)(74.748.011 )(4.550,227)201,475 (4,348.752)
1165
1166
1167 41010 Deferred Income Tax - Federal-DR
1168 GP S 27.885.806 27.747.783 138,023 (110,006)28.017
1169 P TROJD
1170 PT SG 31.324 29,428 1,896 1.896
1171 LABOR SO 8.859,456 8.346.117 513,338 (5,052)508.286
1172 GP SNP 44.945.274 42.366.261 2.579.013 2.579.013
1173 P SE 18.245,954 17.088.974 1.156.980 548.997 1.705.978
1174 PT SG 42.534,872 39.960,452 2,574.420 8.940,991 11.515,11
1175 P SGCT
1176 GP GPS 24.704,090 23.272,675 1,431,415 1.431,415
1177 TAXDEPR TAXDEPR 934.697,178 887.014.033 47.683.145 47.683,145
1178 CUST SADDEBT
1179 CUST CN 18,276 17,569 707 707
1180 P IBT
1181 DPW SNPD
1182 B7 1,101,922.230 1.045,843.293 56,078,937 9.374,930 65,453.868
1183
2010 PROTOCOL Page 2.19
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1184
1185
1186 41110 Deferred Income Tax - Federal-CR
1187 GP S (34,496,605)(32,484,238)(2,012,367)338,916 (1,673,451 )1188 P SE (12,433,468)(11,645,059)(788,409)25,713 (762,696)
1189 P SG (538,368)(505,783)(32,585)(32,585)
1190 GP SNP (28,801,933)(27,149,244)(1,652,689)(1,652,689)
1191 PT SG (8,590,259)(8,070,334)(519,925)(1,094,411 )(1,614,336)1192 DPW CIAC (17,775,107)(16.951,045)(824,02)(844.062)
1193 LABOR SO (17,583.311)(16,564,491 )(1.018,820)623,107 (395,713)1194 PT SNPD (3,638,499)(3,469.817)(168.682)(168,682)1195 CUST TAXDEPR
1196 P SGCT (425,972)(400.091)(25.881)(25,881)
1197 BOOKDEPR SCHMDEXP (214.973,755)(202.734.209)(12,239.546)(12.239.54)
1198 P TROJD (721,757)(677.700)(44.057)44.057
1199 CUST BADDEBT (499,023)(471,998)(27.025)(27.025)
1200 GP GPS
1201
1202 B7 (340.478,057)(321,124,010)(19,354.047)(62,619)(19,416.666)
1203
1204 Total Deferred Income Taxes B7 761,44,172 724,719,282 36,724,890 9,312,312 46,037,202
1205 SCHMAF Additions - Flow Through
1206 SCHMAF S
1207 SCHMAF SNP
1208 SCHMAF SO
1209 SCHMAF SE
1210 SCHMAF TROJP
1211 SCHMAF SG
1212 B6
1213
1214 SCHMAP Additions - Permanent
1215 P S 29,612 29.612
1216 P SE 98,463 92,219 6,244 6.244
1217 LABOR SNP
1218 SCHMAP-SO SO 14,344.602 13.513,441 831.161 (313,06)518,105
1219 SCHMAP SG
1220 BOOKDEPR SCHMDEXP (234,743)(221,378)(13.365)(13.365)
1221 B6 14,237,933 13,413,894 824.039 (313,056)510,984
1222
1223 SCHMAT Additions - Temporary
1224 SCHMA T -SITUS S 52.139,597 51,484,661 654.936 (613.922)41.014
1225 P SG
1226 DPW CIAC 46,836,990 44,665,606 2,171.384 2.171.384
1227 SCHMAT-SNP SNP 75.892,423 71,537,626 4.354.797 4,354.797
1228 P TROJD 1.901,813 1,785.725 116,Q8 (116,Q8)
1229 P SGCT 1,122,425 1,054,229 68,196 68,196
1230 SCHMAT-SE SE 32,761.900 30,684,460 2,077,440 (67.754)2.009,685
1231 P SG 17,720.677 16,648,135 1,072,543 3,181,194 4.253,736
1232 CUST CN
1233 SCHMAT-SO SO 46,331.612 43.647.046 2,684,566 (1,641.872)1.042.694
1234 SCHMAT-SNP SNPD 9,587,358 9,142,884 444,474 444,474
1235 DPW SADDEBT 1,314.913 1,243.703 71,210 71.210
1236 P SG
1237 BOOKDEPR SCHMDEXP 566,450.834 534.199,916 32,250,918 32.250,918
1238 B6 852,060,543 806,093,991 45,966,551 741.558 46,708,109
1239
1240 TOTAL SCHEDULE - M ADDITIONS B6 866,298,476 819.507.885 46,790,591 428.502 47.219,093
1241
2010 PROTOCOL Page 2.20
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1242 SCHMDF Deductions. Flow Through
1243 SCHMDF S
1244 SCHMDF DGP
1245 SCHMDF DGU
1246 B6
1247 SCHMDP Deductions - Permanent
1248 SCHMDP S
1249 P SE 676,074 633,204 42,870 42,870
1250 PTD SNP 381,03 359,198 21,866 21,866
1251 SCHMDP IBT
1252 P SG
1253 SCHMDP-SO SO 24,434,943 23,019,124 1,415,820 (766,990)648,830
1254 B6 25,492.081 24,011,526 1,480,556 (766,990)713,565
1255
1256 SCHMDT Deductions - Temporary
1257 GP S 73,478,450 73,114,765 363,685 (289,862)73,823
1258 DPW BADDEBT
1259 SCHMDT-5NP SNP 118,429,747 111,634,108 6,795,639 6,795,639
1260 SCHMDT CN 48,156 46,293 1,863 1,863
1261 SCHMDT SG 82,539 77,543 4,996 4,996
1262 CUST DGP
1263 P SE 48,077,661 45,029,045 3,048,616 1,446,595 4,495,211
1264 SCHMDT-SG SG 112,078,393 105,294,857 6,783,536 23,559,303 30,342,839
1265 SCHMDT-GPS GPS 65,094,701 61,322,957 3,771,745 3,771,745
1266 SCHMDT-SO SO 23,344,458 21,991,824 1,352,634 (13,312)1,339,322
1267 TAXDEPR TAXDEPR 2,462,905,267 2,337,261,292 125,643,975 125,643,975
1268 DPW SNPD
1269 B6 2,903,539,372 2,755,772,684 147,766,689 24,702,724 172,469,413
1270
1271 TOTAL SCHEDULE - M DEDUCTIONS B6 2,929,031,454 2,779,784,209 149,247,244 23,935,734 173,182,978
1272
1273 TOTAL SCHEDULE - M ADJUSTMENTS B6 (2,062,732,978)(1,960,276,324)(102,456,653)(23,507,232)(125,963,885)
1274
1275
1276
1277 40911 State Income Taxes
1278 IBT S (58,051,019)(55,156,461)(2,894,558)(1,436,597)(4,331,155)1279 IBT SE
1280 PTC P SG (297,049)(279,070)(17,979)(29,945)(47,923)
1281 IBT IBT
1282 Total State Tax Expense (58,348,068)(55,435,531)(2,912,537)(1,466.541 )(4,379,078)
1283
1284
1285 Calculation of Taxable Income:
1286 Operating Revenues 4,402,215,385 4,146,750,451 255,464,934 7,428,829 262,893,763
1287 Operating Deductions:
1288 o & M Expenses 2,692,685,201 2,527,324,231 165,360,970 10,840,128 176,201,098
1289 Depreciation Expense 491,643,870 463,652,092 27,991,778 2,738,026 30,729,804
1290 Amortization Expense 44,975,946 42,481,316 2,494,630 272,898 2,767,529
1291 Taxes Other Than Income 136,512,728 130,094,757 6,417,971 765,162 7,183,133
1292 Interest & Dividends (AFUDC-Equity)(79,298,238)(74,748,011)(4,550,227)201,475 (4,348,752)
1293 Misc Revenue & Expense (5,388,606)(5,100,609)(287,997)(345,174)(633,17)1294 Total Operating Deductions 3.281,130,902 3,Oa3. 703, 776 197,427,126 14,472,515 211,899,641
1295 Other Deductions:
1296 Interest Deductions 337,008,309 317,670,373 19,337,936 1,092,182 20,430,118
1297 Interest on PCRBS
1298 Schedule M Adjustments (2,062,732,978)(1,960,276,324)(102,456,653)(23,507,232)(125,963,885)
1299
1300 Income Before State Taxes (1,278,656,804)(1,214,900,023)(63,756,781)(31,643,100)(95,399,881)
1301
1302 State Income Taxes (58,348,068)(55,435,531 )(2,912,537)(1,466,541)(4,379,078)1303
1304 Total Taxable Income (1,220,308,736)(1,159,464,491 )(60,844,244)(30,176,559)(91,020,803)
1305
1306 Tax Rate 35.0%35.0%35.0%35.0%35.0%
1307
1308 Federal Income Tax - Calculated (427,108,058)(405,812,572)(21,295,486)(10,561,796)(31,857,281)1309
1310 Adjustments to Calculated Tax:
1311 40910 PMI P SE (88,878)(83,242)(5,636)(5,636)1312 40910 PTe P SG (55,535,369)(52,174,095)(3,361,274)(842,290)(4,203,564)1313 40910 P SO (29,612)(27,896)(1,716)(1,716)1314 40910 IRS seWe LABOR S
1315 Federal Income Tax Expense (482.761,917)(458,097,806)(24,664,111 )(11,404,086)(36,068,197)1316
1317 Total Operating Expenses 3,578,889,124 3,367,985,168 210,903,956 10,712,725 221,616,681
2010 PROTOCOL Page 2.21
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1318 310 Land and Land Rights
1319 P SG 2.328,228 2.187.312 140.916 140.916
1320 P SG 34.798.44 32.692.272 2,106,173 2,106,173
1321 P SG 56.303.435 52,895,674 3,407,761 3,407,761
1322 P S
1323 P SG 2,468.743 2,319,323 149,420 149,420
1324 B8 95.898.852 90,094,581 5,804,271 5,804,271
1325
1326 311 Structures and Improvements
1327 P SG 233,697,069 219,552.572 14,144.497 14.144,497
1328 P SG 325,016,640 305,345.033 19.671,607 19.671,607
1329 P SG 304.038,753 285,636.831 18,01.922 18.401,922
1330 P SG 58,700,214 55,147.388 3.552.826 3.552.826
1331 B8 921,452.677 865.681.824 55,770,852 55.770,852
1332
1333 312 Boiler Plant Equipment
1334 P SG 665.806.134 625.508,269 40,297,865 40,297.865
1335 P SG 642,590.325 603.697,595 38,892.730 38.892.730
1336 P SG 1.885,355.962 1,771,244,938 114,111,024 28.935,270 143.046.294
1337 P SG 324,773,916 305,116,999 19,656.916 19.656,916
1338 B8 3,518,526,337 3,305,567.802 212.958.535 28.935.270 241,893.805
1339
1340 314 Turbogenerator Units
1341 P SG 133,730,947 125.636,892 8,094,055 8.094.055
1342 P SG 144,430.870 135.689.203 8,741,667 8.741.667
1343 P SG 554,615.741 521.047,666 33.568,075 33.568,075
1344 P SG 63.736,56 59.878,812 3,857,644 3,857,644
1345 B8 896,514.013 842,252,572 54.261,442 54.261,442
1346
1347 315 Accessory Electric Equipment
1348 P SG 87.016,417 81,749,755 5.266,662 5,266.662
1349 P SG 138.274,538 129,905,483 8.369,056 8,369.056
1350 P SG 124,032,336 116,525,289 7.507,048 7,507.048
1351 P SG 66,644,224 62.610,587 4,033,637 4.033,637
1352 B8 415,967,515 390,791.113 25,176,402 25.176,02
1353
1354
1355
1356 316 Misc Power Plant Equipment
1357 P SG 4.715.664 4,430,249 285,15 285,415
1358 P SG 5.085.197 4,777,416 307,781 307,781
1359 P SG 19,393,369 18,219.587 1.173.782 1,173.782
1360 P SG 4,039,790 3,795,282 244.508 244.508
1361 B8 33,234,020 31,222,534 2,011,487 2,011.487
1362
1363 317 Steam Plant ARO
1364 P S
1365 B8
1366
1367 SP Unclassified Steam Plant - Account 300
1368 P SG 3.351,463 3.148,616 202,87 202,847
1369 B8 3.351,463 3.148,616 202,87 202,87
1370
1371
1372 Total Steam Production Plant B8 5,884,94,878 5,528.759,042 356,185,835 28,935,270 385,121,105
1373
1374
1375 Summary of Steam Production Plant by Factor
1376 S
1377 DGP
1378 DGU
1379 SG 5,884,944,878 5,528,759,02 356,185,835 28,935.270 385.121,105
1380 SSGCH
1381 Total Steam Production Plant by Factor 5,884,944,878 5.528.759.042 356,185,835 28,935.270 385.121,105
1382 320 Land and Land Rights
1383 P SG
1384 P SG
1385 B8
1386
1387 321 Structures and Improvements
1388 P SG
1389 P SG B8
1390
2010 PROTOCOL Page 2.22Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1391
1392 322 Reactor Plant Equipment
1393 P SG
1394 P SG
1395 B8
1396
1397 323 Turbogenerator Units
1398 P SG
1399 P SG
1400 B8
1401
1402 324 Land and Land Rights
1403 p SG
1404 P SG
1405 B8
1406
1407 325 Misc. Power Plant Equipment
1408 p SG
1409 P SG
1410 B8
1411
1412
1413 NP Unclassified Nuclear Plant - Acct 300
1414 P SG
1415 B8
1416
1417
1418 Total Nuclear Production Plant B8
1419
1420
1421
1422 Summary of Nuclear Production Plant by Factor
1423 DGP
1424 DGU
1425 SG
1426
1427 Total Nuclear Plant by Factor
1428
1429 330 Land and Land Rights
1430 P SG 10,621,118 9,978,276 642,82 642,842
1431 P SG 5,269,427 4,950,496 318,932 318,932
1432 P SG 9,560,168 8,981,540 578,628 578,628
1433 P SG 672,873 632,148 40,726 40,726
1434 B8 26,123,587 24,542,459 1,581,128 1.581,128
1435
1436 331 Structures and Improvements
1437 P SG 20,915,379 19.649,478 1,265,902 1,265,902
1438 P SG 5,280,294 4,960,705 319,589 319,589
1439 P SG 78,435,286 73,687,997 4,747,290 4,747,290
1440 P SG 8,183,946 7,688,613 495,333 495,333
1441 B8 112,814,905 105,986,792 6,828,113 6,828,113
1442
1443 332 Reservoirs, Dams & Waterways
1444 P SG 150,943,088 141,807,270 9,135,819 9,135,819
1445 P SG 20,006,881 18,795,966 1,210,915 1,210,915
1446 P SG 114,583,184 107,648,045 6,935,138 1,260,021 8,195,159
1447 P SG 40,934,944 38,457,359 2,477,584 486,52 2,964,127
1448 B8 326,468.097 306,708,641 19,759,456 1,746,563 21,506,020
1449
1450 333 Water Wheel, Turbines, & Generators
1451 P SG 31,307,452 29,412,571 1,894,881 1,894,881
1452 P SG 8,771,526 8,240,630 530,896 530,896
1453 P SG 45,115,448 42,384,839 2,730,609 2,730,609
1454 P SG 27,236,711 25,588,211 1,648,500 1,648,500
1455 B8 112,431,137 105,626,251 6,804,886 6,804,886
1456
1457 334 Accessory Electric Equipment
1458 P SG 4,363,326 4,099,236 264,090 264,090
1459 P SG 3,646,790 3,426,068 220,722 220,722
1460 P SG 44,929,172 42,209,837 2,719,335 2,719,335
1461 P SG 7,177,004 6,742,617 434,388 434,388
1462 B8 60,116,292 56,477,758 3,638,534 3,638,534
1463
2010 PROTOCOL Page 2.23Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL1464
1465
1466 335 Misc. Power Plant Equipment
1467 P SG 1,195,178 1,122.840 72,338 72,338
1468 P SG 161,986 152,181 9,804 9,804
1469 P SG 992,216 932,162 60,054 60,054
1470 P SG 11,353 10,666 687 687
1471 B8 2,360,733 2,217,850 142,883 142,883
1472
1473 336 Roads, Railroads & Bridges
1474 P SG 4,648,527 4,367.176 281.352 281,352
1475 P SG 822,839 773.037 49.802 49.802
1476 P SG 10,183,215 9,566.876 616,338 616.338
1477 P SG 668.735 628,259 40,475 40,475
1478 B8 16,323,315 15.335,348 987,967 987.967
1479
1480 337 Hydro Plant ARO
1481 P S
1482 B8
1483
1484 HP Unclassified Hydro Plant - Acct 300
1485 P S
1486 P SG
1487 P SG
1488 P SG
1489 B8
1490
1491 Total Hydraulic Production Plant B8 656,638,066 616,895,098 39,742,968 1,746,563 41,489,532
1492
1493 Summary of Hydraulic Plant by Factor
1494 S
1495 SG 656.638.066 616,895,098 39,742,968 1,746,563 41,489,532
1496 DGP
1497 DGU
1498 Total Hydraulic Plant by Factor 656,638,066 616,895,098 39,742,968 1,746,563 41.489,532
1499
1500 340 Land and Land Rights
1501 P SG 23,516.708 22,093,361 1,423,347 1,423,347
1502 P SG 5,394,604 5,068,096 326,508 326.508
1503 P SG
1504 B8 28,911,312 27,161,457 1,749,855 1,749,855
1505
1506 341 Structures and Improvements
1507 P SG 107,792,505 101.268,372 6,524,133 6,524,133
1508 P SG 163.512 153,615 9,897 9,897
1509 P SG 43.775.824 41,126.296 2,649.528 2,649.528
1510 P SG 4,241.952 3.985.208 256,744 256,744
1511 B8 155,973,793 146,533,491 9.44,302 9.44,302
1512
1513 342 Fuel Holders, Producers & Accessories
1514 P SG 8,406,209 7.897,424 508,785 508,785
1515 P SG 121,339 113.995 7.344 7.344
1516 P SG 2.284.126 2,145.879 138.247 138.247
1517 B8 10,811.674 10,157.298 654,376 654.376
1518
1519 343 Prime Movers
1520 P S
1521 P SG 754,440 708,777 45.662 45,662
1522 P SG 1,801,277,182 1.692.255,019 109.022,163 109.022,163
1523 P SG 658,057,132 618.228,275 39.828,857 39.828,857
1524 P SG 53,648,952 50,401,854 3.247.099 3.247,099
1525 B8 2.513.737.706 2.361.593.925 152,143.781 152.143,7811526
1527 344 Generators
1528 P S
1529 P SG 47,700,523 44,813.452 2,887.070 2,887,070
1530 P SG 283,380,358 266.228,783 17.151,574 17,151.574
1531 P SG 15.873,643 14.912,892 960,751 960.751
1532 B8 346.954,524 325.955,128 20.999,396 20,999.396
2010 PROTOCOL Page 2.24
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1533
1534 345 Accessory Electric Plant
1535 P SG 134.281.439 126.154.066 8.127.374 8.127.374
1536 P SG 97.391.746 91,497.118 5.894,628 5,894,628
1537 P SG 156.586 147,109 9,477 9,477
1538 P SG 2.919.649 2,742,937 176,712 176,712
1539 S8 234,749,420 220,541,229 14,208.191 14.208,191
1540
1541
1542
1543 346 Misc. Power Plant Equipment
1544 P SG 9.819.979 9.225,625 594.353 594,353
1545 P SG 2,349.890 2.207,664 142,227 142.227
1546 P SG 11.813 11.098 715 715
1547 S8 12.181.682 11,444.387 737.295 737,295
1548
1549 347 Other Production ARO
1550 P S
1551 S8
1552
1553 OP Unclassified Other Prod Plant-Acctl02
1554 P S
1555 P SG (4.484.801 )(4,213.359)(271,442)(271.442)
1556 (4,484.801 )(4,213,359)(271,442)(271,442)
1557
1558 Total Other Production Plant B8 3,298,835,309 3,099,173,557 199,661,753 199,661,153
1559
1560 Summary of Other Production Plant by Factor
1561 S
1562 DGU
1563 SG 3.298.835,309 3,099,173,557 199.661.753 199,661,753
1564 SSGCT
1565 Total of Other Production Plant by Factor 3.298.835.309 3,099,17.557 199,661,753 199,661,753
1566
1567 Experimental Plant
1568 103 Experimental Plant
1569 P SG
1570 Total Experimental Production Plant B8
1571
1572 Total Production Plant B8 9,840,418,253 9,244,827,697 595,590,556 30,681,833 626,272,390
1573 350 Land and Land Rights
1574 T SG 21,114,634 19,836.673 1,277.962 1.277.962
1575 T SG 48,91,936 45,556,965 2,934,971 2.934,971
1576 T SG 111.910,895 105.137,497 6,773.398 (25.595)6,747.804
1577 S8 181,517,465 170,531,135 10,986.331 (25.595)10.960.736
1578
1579 352 Structures and Improvements
1580 T S
1581 T SG 7,550,730 7,093,722 457.007 457,007
1582 T SG 18,144.311 17,046,128 1,098.183 1.098.183
1583 T SG 97,158,664 91,278,143 5.880.521 5.880.521
1584 S8 122,853,704 115,417,993 7,435.711 7,435.711
1585
1586 353 Station Equipment
1587 T SG 127.623.942 119,899,513 7,724,429 7.724,429
1588 T SG 186,316.529 175,039,735 11,276.794 11.276.794
1589 T SG 1,224,680,278 1.150.556,598 74,123.679 74.123,679
1590 S8 1,538,620,749 1,445.495,846 93,124.902 93,124,902
1591
1592 354 Towers and Fixtures
1593 T SG 161.082,488 151.332.983 9.749.505 9.749.505
1594 T SG 128.007.635 120.259,983 7.747,652 7.747.652
1595 T SG 336.682.164 316.304,502 20.377,662 20.377,662
1596 B8 625.772.287 587.897,468 37.874,819 37,874,819
1597
1598 355 Poles and Fixtures
1599 T SG 66.617.046 62.585.054 4.031,992 4,031.992
1600 T SG 117 .303.325 110.203.550 7.099,775 7,099,775
1601 T SG 415.637.115 390,480.711 25.156,404 9,151,416 34,307.820
1602 S8 599.557,486 563,269.315 36.288,171 9,151,416 45,439.587
1603
2010 PROTOCOL Page 2.25
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1604 356 Clearing and Grading
1605 T SG 194.103.526 182.355.425 11.748.101 11.748.101
1606 T SG 151.170.861 142.021.256 9.149,605 9.149.605
1607 T SG 433.610.805 407.366.545 26.244.261 26.244.261
1608 S8 778.885.193 731.743.226 47.141,966 47.141.966
1609
1610 357 Underground Conduit
1611 T SG 6.371 5.985 386 386
1612 T SG 91.651 86.103 5.547 5.547
1613 T SG 3.161,431 2.970.085 191.345 191,345
1614 S8 3.259,452 3.062.174 197.278 197,278
1615
1616 358 Underground Conductors
1617 T SG
1618 T SG 1.087.552 1,021.728 65.824 65.824
1619 T SG 6.387.543 6,000.937 386.606 386.606
1620 S8 7,475.095 7.022.665 452,430 452,430
1621
1622 359 Roads and Trails
1623 T SG 1.863.032 1.750.272 112.760 112.760
1624 T SG 44.513 413.851 26,62 26.662
1625 T SG 9.295.159 8,732.570 562.589 562.589
1626 S8 11.598,703 10,896.693 702.011 702,011
1627
1628 TP Unclassified Trans Plant - Acct 300
1629 T SG 469.574,099 441.153.163 28,20.936 28,20.936
1630 S8 469.574,099 441.153,163 28,420.936 28,420.936
1631
1632 TSO Unclassified Trans Sub Plant - Acct 300
1633 T SG
1634 S8
1635
1636 Total Transmission Plant 88 4,339,114,233 4,076,489,678 262,624,554 9,125,821 271,750,376
1637 Summary of Transmission Plant by Factor
1638 DGP
1639 DGU
1640 SG 4.339.114.233 4.076,89.678 262.624.554 9.125.821 271.750.376
1641 Total Transmission Plant by Factor 4.339.114.233 4.076.489.678 262.624.554 9,125.821 271.750.376
1642 360 Land and Land Rights
1643 DPW S 52.837,393 51,476,125 1,361.267 1.361,267
1644 S8 52.837.393 51,476.125 1,361.267 1.361.267
1645
1646 361 Structures and Improvements
1647 DPW S 74.675.983 73.174,078 1.501.905 1.501,905
1648 S8 74.675.983 73.174,078 1.501,905 1.501.905
1649
1650 362 Station Equipment
1651 DPW S 822.438.749 794.121,744 28.317.005 28.317,005
1652 S8 822,438.749 794.121,744 28.317.005 28,317.005
1653
1654 363 Storage Sattery Equipment
1655 DPW S
1656 S8
1657
1658 364 Poles, Towers & Fixtures
1659 DPW S 936.606.530 872,248.984 64.357.546 64.357.546
1660 S8 936.606.530 872,248.984 64.357.546 64.357.546
1661
1662 365 Overhead Conductors
1663 DPW S 646,426.178 612.036.781 34.389.397 34.389.397
1664 S8 646,426.178 612,036.781 34.389.397 34.389.397
1665
2010 PROTOCOL Pcige 2.26
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1666 366 Underground Conduit
1667 DPW S 300,853,912 293,226,761 7,627,151 7,627,151
1668 B8 300,853,912 293,226,761 7,627,151 7,627,151
1669
1670
. 1671
1672
1673 367 Underground Conductors
1674 DPW S 716,202,893 692,155,372 24,047,521 24,047,521
1675 B8 716,202,893 692,155,372 24,047,521 24,047,521
1676
1677 368 Line Transformers
1678 DPW S 1,092.258,181 1,024,496,725 67,761,455 67,761,455
1679 B8 1,092,258,181 1,024,496,725 67,761,455 67,761,455
1680
1681 369 Services
1682 DPW S 581,777,749 552,728,553 29,049,197 29,049,197
1683 B8 581,ïi1,ï49 552,728,553 29,049,197 29,049,197
1684
1685 370 Meters
1686 DPW S 179,597,171 165,632,928 13,964.243 13,964,243
1687 B8 179,597,171 165,632,928 13,964,243 13,964,243
1688
1689 371 Installations on Customers' Premises
1690 DPW S 8,801,076 8,631,743 169,333 169,333
1691 B8 8,801,076 8,631,743 169,333 169,333
1692
1693 372 Leased Propert
1694 DPW S
1695 B8
1696
1697 373 Street Lights
1698 DPW S 60,795,839 60,180,066 615,773 615,773
1699 B8 60,795,839 60,180,066 615,773 615,773
1700
1701 DP Unclassified Dist Plant - Acct 300
1702 DPW S 12,090,316 10,561,483 1,528,833 1,528,833
1703 B8 12,090,316 10,561,483 1,528,833 1,528,833
1704
1705 DSO Unclassified Dist Sub Plant - Acct 300
1706 DPW S
1707 B8
1708
1709
1710 Total Distribution Plant B8 5,485,361,969 5,210,671,34 274,690,625 274,690,625
1711
1712 Summary of Distribution Plant by Factor
1713 S 5,485,361,969 5,210,671,344 274,690,625 274,690,625
1714
1715 Total Distribution Plant by Factor 5,485,361,969 5,210,671,344 274,690,625 274,690,625
2010 PROTOCOL Page 2.27
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1716 389 Land and Land Rights
1717 G-SITUS S 9,472,275 9,274,636 197,639 197,639
1718 GUST GN 1,128,506 1,084,845 43,661 43,661
1719 PT SG 332 312 20 20
1720 G-SG SG 1.228 1,153 74 74
1721 PTD SO 5,598.055 5.273,690 324.365 324,365
1722 68 16,200.395 15.634,636 565,759 565,759
1723
1724 390 Structures and Improvements
1725 G-SITUS S 113,258,556 103,350,062 9,908,495 9.908,95
1726 PT SG 356,327 334,760 21,567 21,567
1727 PT SG 1,638.404 1,539.240 99,164 99,164
1728 GUST GN 12,312,990 11,836,614 476,376 476,376
1729 G-SG SG 4,107,582 3,858.971 248.611 248.611
1730 PTD SO 103,816.679 97.801.289 6.015.390 6,015,390
1731 68 235,90,538 218.720,936 16.769.603 16,769,603
1732
ii33 391 Offce Furniture & Equipment
1734 G-SITUS S 10.714,257 9,922,539 791,718 791,718
1735 PT SG 1,046 982 63 63
1736 PT SG 5,295 4.975 320 3201737GUSTGN8.507,385 8,178.243 329,141 329,141
1738 G-SG SG 4,793,839 4,503.692 290.147 290,147
1739 P SE 80,160 75,077 5,083 5,083
1740 PTD SO 53,024,085 49.951,741 3,072,344 3,072,344
1741 G-SG SG 74,351 69,851 4,500 4,500
1742 G-SG SG
1743 68 77,200,417 72,707,100 4,493,317 4,493,317
1744
1745 392 Transportation Equipment
1746 G-SITUS S 72.695,382 67,622,274 5,073.108 5,073.108
1747 PTD SO 7,496,170 7,061,824 434,346 434,346
1748 G-SG SG 16.861,910 15,841,344 1,020.566 1,020.566
1749 GUST GN
1750 PT SG 788,230 740.522 47.708 47.708
1751 P SE 404,148 378,521 25,627 25,27
1752 PT SG 120,286 113,006 7,280 7,280
1753 G-SG SG 343,984 323,164 20,820 20,8201754PTSG44,655 41,952 2,703 2,703
1755 68 98.754.764 92,122,607 6,632,157 6.632.157
1756
1757 393 Stores Equipment
1758 G-SITUS S 8.748,806 8,259,899 488.907 488,907
1759 PT SG 108,431 101.868 6.563 6.563
1760 PT SG 360,063 338.270 21.793 21.793
1761 PTD SO 366.257 345,035 21,222 21.222
1762 G-SG SG 4,117,724 3,868,499 249,225 249.225
1763 PT SG 53.971 50.704 3,267 3.267
1764 68 13,755,252 12.964,276 790,976 790,976
2010 PROTOCOL Page 2.28
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1765
1766 394 Tools, Shop & Garage Equipment
1767 G-SITUS S 31,993,392 30,190,583 1.802.808 1.802.808
1768 PT SG 1,547.621 1,453,951 93,670 93.670
1769 G-SG SG 20,748.569 19,492.763 1.255.806 1,255.806
1770 PTD SO 3,941.347 3.712.976 228.371 228,371
1771 P SE 7.106 6,656 451 451
1772 PT SG 1.779.683 1.671.968 107.715 107,715
1773 G-SG SG 1,702.983 1.599.910 103.073 103.073
1774 G-SG SG 89.913 84,471 5.442 5.442
1775 B8 61,810.613 58.213.278 3.597.335 3.597,335
1776
1777 395 Laboratory Equipment
1778 G-SITUS S 24,898.296 23,620.023 1.278.273 1,278,273
1779 PT SG 1,518 1.426 92 92
1780 PT SG 5,371 5,06 325 325
1781 PTD SO 5,041,840 4.749.704 292.136 292.136
1782 p SE 7.593 7,112 4ôî 481
1783 G-SG SG 6,252,885 5,874.430 378.455 378,55
1784 G-SG SG 253.001 237.688 15.313 15.313
1785 G-SG SG 14,022 13,173 849 849
1786 B8 36,474,525 34.508,601 1.965.924 1.965.924
1787
1788 396 Power Operated Equipment
1789 G-SITUS S 96,176,244 89.210,759 6.965.485 6,965,85
1790 PT SG 845,108 793,958 51,150 51.150
1791 G-SG SG 31.225,794 29,335,855 1,889,939 1,889,939
1792 PTD SO 1.137,422 1,071,517 65.905 65.905
1793 PT SG 1.664,492 1.563,749 100.743 100,743
1794 P SE 73,823 69,142 4,681 4,681
1795 P SG
1796 G-SG SG 999,837 939,322 60.515 6Ó,515
1797 B8 132.122,721 122.984,302 9,138,419 9,138,419
1798 397 Communication Equipment
1799 G-SITUS S 108,711,341 102,010,465 6,700.875 6.700,875
1800 PT SG 2,017,325 1,895,226 122.098 122,098
1801 PT SG 2,735,730 2,570,150 165,580 165.580
1802 PTD SO 49.790,369 46,905,394 2,884,974 2.884.974
1803 CUST CN 2,849,382 2,739,142 110.239 110.239
1804 G-SG SG 92,965,111 87,338,05 5.626,706 5,626.706
1805 P SE 126,846 118,802 8,03 8,043
1806 G-SG SG 606,135 569,448 36.686 36.686
1807 G-SG SG 1,590 1,494 96 96
1808 B8 259,803,827 244,148,528 15,655,299 15.655.299
1809
1810 398 Misc. Equipment
1811 G-SITUS S 1,462,713 1,398,361 64,352 64.352
1812 PT SG
1813 PT SG
1814 CUST CN 211,499 203,316 8.183 8.183
1815 PTD SO 3,306,006 3,114,448 191,558 191.558
1816 P SE 1,668 1,562 106 106
1817 G-SG SG 1,918,568 1,802,447 116,121 116.121
1818 G-SG SG
1819 B8 6.900,453 6,520.133 380,320 380.320
1820
1821 399 Coal Mine
1822 P SE 274.151.311 256,767.312 17.383.999 13.434.281 30,818.280
1823 MP P SE
1824 B8 274,151.311 256,767,312 17.383.999 13,434,281 30.818,280
1825
1826 399L WIDCO Capital Lease
1827 P SE B8
1828
1829
1830 Remove Capital Leases
1831 B8
1832
2010 PROTOCOL Page 2.29
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1833 1011390 General Capital Leases
1834 G-SITUS S 18,984,156 18,984,156
1835 P SG 16,951,793 15,925,787 1,026,006 1,026,006
1836 PTD SO 12,664,054 11,930,268 733,786 733,786
1837 B9 48,600,002 46.840,210 1,759,792 1,759,792
1838
1839 Remove Capital Leases (48,600,002)(46,840,210)(1,759,792)(1,759,792)
1840
1841
1842 1011346 General Gas Line Capital Leases
1843 P SG
1844 B9
1845
1846 Remove Capital Leases
1847
1848
1849 GP Unclassified Gen Plant - Acct 300
1850 G-SITUS S
1851 PTD SO 672,542 633,573 38,969 38,969
1852 CUST CN
1853 G-SG SG
1854 PT SG
1855 PT SG
1856 B8 672,542 633,573 38,969 38,969
1857
1858 399G Unclassified Gen Plant - Acct 300
1859 G-SITUS S
1860 PTD SO
1861 G-SG SG
1862 PT SG
1863 PT SG
1864 B8
1865
1866 Total General Plant B8 1,213,337,359 1,135,925,283 77,412,077 13,434,281 90,846,357
1867
1868 Summary of General Plant by Factor
1869 S 497,115,417 463,843,757 33,271,660 33,271,660
1870 OGP
1871 OGU
1872 SG 218,104,703 204,903,933 13,200,770 13,200,770
1873 SO 246,854,826 232,551,460 14,303,366 14,303,366
1874 SE 274,852,655 257,424,183 17.428,472 13,434,281 30,862,752
1875 CN 25,009,761 24,042,161 967,601 967,601
1876 OEU
1877 SSGCT
1878 SSGCH
1879 Less Capital Leases ~48,600,002)(46,840,210)11,59,792)
£,759,792)
1880 Total General Plant by Factor 1, 13,337,359 1,135,925,283 7,412,077 13,34,281 ,846,357
1881 301 Organization
1882 I-SITUS S
1883 PTO SO
1884 I-SG SG
1885 B8
1886 302 Franchise & Consent
1887 I-SITUS S 1,000,000 1,000,000 1,000,000
1888 I-SG SG 11,966,103 11,241,856 724,247 724,247
1889 I-SG SG 173,628,256 163,119,419 10,508,837 10,508,837
1890 I-SG SG 9,240,742 8,681,446 559,295 559,295
1891 P SG
1892 P SG 600,993 564,618 36,375 36,375
1893 B8 196,436,094 183,607,340 12,828,755 12,828,755
1894
2010 PROTOCOL Page 2.30Year.End
FERC 8US UNADJUSTED RESULTS IDAHOACCTDESCRIPFUNCFACTORRefTOTALOTHERIDAHOADJUSTMENT ADJTOTAL
1895 303 Miscellaneous Intangible Plant
1896 I-SITUS S 7.517.189 7.089.597 427.593 427.5931897I-SG SG 108.821.038 102,234,653 6.586.385 849,459 7.435.8441898PTDSO367.518,11 346.223.504 21.294.906 21.294.9061899PSE3,440.744 3.222.565 218.178 218.178
1900 CUST CN 120.558.779 115.894,491 4,664.288 4.664.2881901PSG
1902 P SG
1903 88 607,856,161 574.664,811 33.191.351 849,459 34.040.8101904303Less Non-Utility Plant
1905 I-SITUS S
1906 607.856.161 574,664.811 33,191.351 849,459 34.040.810
1907 IP Unclassified Intangible Plant - Acct 300
1908 I-SITUS S
1909 I-SG SG
1910 P SG
1911 PTD SO
1912
1913
1914 Tolallntangible Ptant 88 804,292,255 758,272,150 46,020,105 849,459 46,869,564
1915
1916 Summary of Intangible Plant by Factor
1917 S 8,517,189 7.089,597 1,427.593 1,427.593
1918 DGP
1919 DGU
1920 SG 304,257.133 285,841.993 18.415,140 849,459 19,264,599
1921 SO 367.518,411 346.223.504 21,294,906 21,294.9061922CN120.558.779 115.894,491 4,664.288 4.664,288
1923 SSGCT
1924 SSGCH
1925 SE .3.440,744 3.222.565 218.178 218.1781926Total Intangible Plant by Factor 804.292.255 758,272,150 46.020,105 849.59 46,869.564
1927 Summary of Unclassified Plant (Account 106 & 102)
1928 DP 12.090.316 10.561.483 1,528.833 1.528.833
1929 DSO
1930 GP 672.542 633.573 38.969 38.969
1931 HP
1932 NP
1933 OP (4,484.801 )(4.213.359)(271.442)(271.442)1934 TP 469.574.099 441.153.163 28,420,936 28,20.936
1935 TSO
1936 IP
1937 MP
1938 SP 3,351,463 3,148,616 202,847 202.8471939Total Unclassified Plant by Factor 481.203,619 451.283,477 29.920.142 29.920.142
1940
1941 Total Electric Plant In Service 88 21,682,524,069 20,426,186,152 1,256,337,918 54,091,394 1,310,429,312
2010 PROTOCOL Page 2.31
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1942 Summary of Electric Plant by Factor
1943 S 5.990.994.575 5.681.604.697 309.389.878 309,389.878
1944 SE 278.293.398 260.646.748 17.646.650 13,434,281 31.080.931
1945 DGU
1946 DGP
1947 SG 14,701,894.321 13.812.063.301 889,831.021 40.657.114 930.488.134
1948 SO 614.373.236 578.774.964 35.598.272 35.598.272
1949 CN 145.568.541 139.936.652 5,631.889 5.631.889
1950 DEU
1951 SSGCH
1952 SSGCT
1953 Less Capital Leases (48.600.002)(46.840.210)(1.759.792)(1.759.792)
1954 21.682,524.069 20,426.186.152 1,256,337.918 54.091.394 1.310,29.312
1955 105 Plant Held For Future Use
1956 DPW S 7,080,785 7.080.785
1957 P SG
1958 T SG 721,Q8 677.407 43.641 (583,724)(540.082)
1959 P SG 8,923.302 8.383.219 540.082 540.082
1960 P SE 953,014 892.583 60.431 (60.431)
1961 G SG
1962
1963
1964 Total Plant Held For Future Use B10 17,678,149 17,033,995 644,154 (64,154)
1965
1966 114 Electric Plant Acquisition Adjustments
1967 P S
1968 P SG 144.614.797 135.861,998 8.752,799 8.752.799
1969 P SG 14.560.711 13.679,425 881.286 881.286
1970 Total Electric Plant Acquisition Adjustment 815 159,175,508 149,541,423 9,634,085 9,634,085
1971
1972 115 Accum Provision for Asset Acquisition Adjustments
1973 P S
1974 P SG (88.957.249)(83.573,118)(5.384.131)(5.384.131 )
1975 P SG (12.888.017l (12.107,97Ol (780,046l (780.046l1976815(101,845.265 (95.681,089 (6.164,17 (6.164.17
1977
1978 120 Nuclear Fuel
1979 P SE
1980 Total Nuclear Fuel 815
1981
1982 124 Weatherization
1983 DMSC S 2.213.350 2,194,663 18.688 18,88
1984 . DMSC SO ~4,454)(4,196)(258)(258)1985 B16 2.2 8.897 2,190.467 18,30 18,430
1986
1987 182W Weathenzation
1988 DMSC S 6,410.754 3.248.179 3,162.575 3.162.575
1989 DMSC SG
1990 DMSC SGCT
1991 DMSC SO
1992 B16 6,10.754 3.248.179 3,162.575 3.162.575
1993
1994 186W Weathenzation
1995 DMSC S
1996 DMSC CN
1997 DMSC CNP
1998 DMSC SG
1999 DMSC SO
2000 B16
2001
2002 Total Weatherization B16 8,619,651 5,438,64 3,181,004 3,181,004
2010 PROTOCOL Page 2.32
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
2003
2004 151 Fuel Stock
2005 P DEU
2006 P SE 178,314,939 167,007,947 11,306,992 2,398,786 13,705,778
2007 P SE
2008 P SE 10,178,149 9,532,750 645,399 645,399
2009 Total Fuel Stock B13 188,493,087 176,540,696 11,952,391 2,398,786 14,351,177
2010
2011 152 Fuel Stock - Undistributed
2012 P SE
2013
2014
2015 25316 DG&T Working Capital Deposit
2016 P SE (2,263,000)(2,119,503)(143,497)(32,593)(176,090)
2017 813 (2,263,000)(2,119,503)(143,497)(32,593)(176,090)2018
2019 25317 DG& T Working Capital Deposit
2020 p SE (1,849,114)(1,731,8ô1ì (117,253)(11,035)íî2ô,288)2021 813 (1,849,114)(1,731,861 )(117,253)(11,035)(128,288)
2022
2023 25319 Provo Working Capital Deposit
2024 P SE
2025
2026
2027 Total Fuel Stock 813 184,380,973 172,689,333 11,691,641 2,355,158 14,046,799
2028 154 Materials and Supplies
2029 MSS S 87.724,078 82,701,505 5,022,573 5,022,573
2030 MSS SG 4,657,098 4,375,227 281,870 281,870
2031 MSS SE 4,477,840 4,193,899 283,941 283.941
2032 MSS SO 220,250 207,488 12.762 12,762
2033 MSS SG 84,929,002 79,788,681 5.140.321 5.140,321
2034 MSS SG (1,860)(1.747)(113)(113)
2035 MSS SNPD (2,521,016)(2,404.141 )(116.875)(116,875)2036 MSS SG
2037 MSS SG
2038 MSS SG
2039 MSS SG
2040 MSS SG 6,920,767 6.501.888 418,879 418.879
2041 MSS SG
2042 Total Materials and Supplies B13 186.406,158 175,362,800 11,043,359 11,043,359
2043
2044 163 Stores Expense Undistributed
2045 MSS SO
2046
2047 813
2048
2049 25318 Provo Working Capital Deposit
2050 MSS SG (273,000)(256,477)(16,523)(16,523)
2051
2052 813 (273,000)(256,77)(16,523)(16.523)
2053
2054 Total Materials & Supplies 813 186.133,158 175.106,323 11,026.835 11,026,835
2055
2056 165 Prepayments
2057 DMSC S 2,918.959 2.728,996 189,963 189.963
2058 GP GPS 10.983,376 10.346.973 636,03 636.403
2059 PT SG 5,058,945 4,752,753 306,192 306.192
2060 P SE 5,474,749 5.127,594 347,155 347.155
2061 PTD SO 20.942.638 19,729,171 1,213,467 1,213,467
2062 Total Prepayments B15 45,378,667 42,685,486 2,693,181 2,693,181
2063
2010 PROTOCOL Page 2.33
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
2064 182M Mise Regulatory Assets
2065 DDS2 S 97,616,141 97,484,653 131,488 (309,362)(177,874)
2066 DEFSG SG
2067 P SGCT 7,389,298 6,940,338 448,960 448,960
2068 DEFSG SG-P 186,749 186.749
2069 P SE
2070 P SG
2071 DDS02 SO 8,296.641 7,815,914 480,727 480,727
2072 B11 113,302.081 112.240,905 1,061,175 (122.613)938,53
2073
2074 186M Mise Deferred Debits
2075 LABOR S 15.110.335 15,110,335
2076 P SG
2077 P SG
2078 DEFSG SG 53.166.550 49,948,649 3,217,901 273,203 3,491,104
2079 LABOR SO 1,784 1,681 103 103
2080 P SE 16,440,473 15,397.979 1,042,494 (3,997)1,038,498
2081 P SG
2082 GP EXCTAX
2083 Total Misc. Deferred Debits B11 84,719,143 80,45,64 4,260,499 269,206 4,529,705
2084
2085 Working Capital
2086 CWC Cash Working Capital
2087 CWC S 32,376.753 30,512,397 1,864,356 (14,544)1.849,812
2088 CWC SO
2089 CWC SE
2090 B14 32,376,753 30.512.397 1,864,356 (14,544)1,849,812
2091
2092 OWC Other Work. Cap.
2093 131 Cash GP SNP
2094 135 Working Funds GP SG
2095 141 Notes Receivabh GP SO
2096 143 Other AIR GP SO 48,531,707 45,719,663 2,812,045 2,812,045
2097 232 Al PTD S
2098 232 AlP PTD SO (4,386,790)(4,132.609)(254.181)(254,181)
2099 232 AlP P SE (2,202,647)(2.062.977)(139,670)(139,670)
2100 232 AlP T SG (146,335)(137,478)(8,857)(8,857)
2101 2533 Other Msc, Df.Crd. P S
2102 2533 Othe Msc. Of Crd. P SE (6.240,898)(5,845,162)(395,737)(16.234)(411,971)
2103 230 Asel Retir, Oblig.P SE (2.528,519)(2,368,185)(160,334)(160,334)
2104 230 Assel Retir. Oblig. P S
2105 254105 ARO Reg Liability P S
2106 254105 ARO Reg Liability P SE (877,173)(821.552)(55,622)(55,622)
2107 2533 Cholla Reclamation P SE
2108 B14 32,149,344 30,351,701 1,797.643 (16.234)1.781,409
2109
2110 Total Working Capital B14 64,526,097 60,864,098 3,662,000 (30,778)3,631,222
2111 Miscellaneous Rate Base
2112 18221 Unree Plant & Reg Study Costs
2113 P S
2114
2115 B15
2116
2117 18222 Nuclear Plant - Trojan
2118 P S (28,645)(28.645)
2119 P TROJP 64,498 60.566 3,932 (3.932)0
2120 P TROJD 99,713 93.627 6,087 (6,087)0
2121 615 135.566 125,548 10,019 (10,019)0
2122
2123
2010 PROTOCOL Page 2.34
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
2124
2125 1869 Misc Deferred Debits-Trojan
2126 P S
2127 P SG
2128 B15
2129
2130 Total Miscellaneous Rate Base B15 135,566 125,548 10,019 (10,019)0
2131
2132 Total Rate Base Additions B15 762,203,728 720,503,311 41,700,417 1,816,800 43,517,217
2133 235 Customer Service Deposits
2134 CUST S
2135 CUST CN
2136 Total Customer Service Deposits B15
2137
2138 2281 Prop Ins PTD SO
2139 2282 Inj & Dam PTD SO (8,499.000)(8.006.547)(492,453)(492.453)
2140 2283 Pen & Ben PTD SO (24.864.308)(23,423.610)(1,440.698)(1.440.698)
2141 2283 Pen & Ben PTD S (71.232.015)(71.232.015)
2142 254 Reg Liab PTD SE (44.269)(41,462)(2.807)2.807
2143 254 Ins Prov PTD SO
2144 B15 (104.639.593)(102,703.635)(1.935.958)2,807 (1.933.151)
2145
2146 22841 Accum Misc Oper Provisions - Other
2147 P S
2148 P SG
11.500.0001
(1,409.213)(90.787)(90.787)
2149 615 1.500,000 (1,409.213)(90,787)(90.787)
2150
2151 22842 Prv-Trojan P TROJD
2152 230 ARO P TROJP (1,691,988)(1,588.839)(103,149)(103,149)
2153 254105 ARO P TROJP (3,512,728)(3,298,581 )(214,147)(214,147)
2154 254 P S (13,908,965)(13,908,9651
2155 B15 (19,11,682)(18.796,385 (317,296)(317,296)
2156
2157 252 Customer Advances for Construction
2158 DPW S (10,535,734)(10,185,382)(350,352)(3.729)(354,081)
2159 DPW SE
2160 T SG (7,959,228)(7,477,496)(481.732)(330,807)(812.539)
2161 DPW SO
2162 CUST CN
2163 Total Customer Advances for Construction B19 (18.4Ø4,962)(17,662,878)(832.083)(334,536)(1,166,620)
2164
2165 25398 S02 Emissions
2166 P SE (1,571.5071
11,571,507)2167 B19 (1,571,507 1,571,507)
2168
2169 25399 Other Deferred Credits
2170 P S (3,632,420)(3,557,473)(74,947)(74,947)
2171 LABOR SO
2172 P SG (7,639,843)(7,177,442)(462,401)(462,401)
2173 P SE (408,8711 (382,944)(25,927)(25,927)
2174 B19 (11,681,135 (11,11,860)(563,274)(563,274)
2010 PROTOCOL Page 2.35
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
2175
2176 190 Accumulated Deferred Income Taxes
2177 P S 15,585,863 15,585,864 (1)(1)2178 CUST CN 47,212 45,385 1,827 1,827
2179 P 1ST
2180 LASOR SO 75,156.683 70.801.923 4.354,760 (257.507)4.097,253
2181 P DGP
2182 CUST SADDEST 3.844,158 3.635,975 208.183 208.183
2183 P TROJD 1,912.923 1,796,157 116.766 (116.766)
2184 P SG 39.603.966 37.206,939 2,397.027 (2,232.800)164.227
2185 P SE (19.942,198)(18.677,658)(1.264.539)596,403 (668,137)
2186 PTD SNP
2187 DPW SNPD 1.793,564 1,710,414 83.150 83,150
2188 P SG
2189 Total Accum Deferred Income Taxes B19 118,002,171 112,104,998 5,897,173 (2,010,671)3,886,502
2190
2191 281 Accumulated Deferred Income Taxes
2192 P S
2193 PT SG (11,642,708)(10,938,034)(704,674)704,674
2194 T SNPT
2195 B19 (11,642,708)(10,938,034)(704,674)704,674
2196
2197 282 Accumulated Deferred Income Taxes
2198 GP S (164.376,500)(164,376,500)
2199 ACCMDIT DITBAL ('3,06,185.039)(2,877,281,043)(168,903.996)168,903,996
2200 P SG
2201 P SG
2202 IBT IBT
2203 LABOR SO 32,477.154 30,595,349 1,881,805 (386)1,881.419
2204 CUST CN
2205 P SE (5,543,047)(5.191,561 )(351.486)(364,430)(715,916)
2206 P SG (5,198.486)(4.883,848)(314,638)(8,487,956)(8,802,594)2207 B19 (3,024,449,418)(2,856.761,103)(167,688.315)(4,325.275)(172,013,591)
2208
2209 283 Accumulated Deferred Income Taxes
2210 GP S (46,066,263)(44,925,191)(1,141,072)1.129,081 (11,991)
2211 P SG (9,100,662)(8.549,845)(550,817)(26,356)(577,172)
2212 P SE (7.531,923)(7,054.322)(477,601)1,517 (476.084)
2213 LABOR SO (3,864,666)(3,640.738)(223,928)140,971 (82,957)
2214 GP GPS (7,448,211 )(7,016,644)(431,567)(431,567)
2215 PTD SNP (4,344,154)(4,094.881 )(249,273)(249,273)
2216 P TROJD
2217 P SG
2218 P SGCT (2.804.313)(2,633,928)(170.385)(170,385)
2219 P SG
2220 B19 (81,160,192)(77.915.549)(3,244.643)1,245.213 (1,999,430)
2221
2222 Total Accum Deferred Income Tax B19 (2,999,250,147)(2,833,509,688)(165,740,459)(4,386,060)(170,126,518)
2223 255 Accumulated Investment Tax Credit
2224 PTD S
2225 PTD ITC84 (1,163,513)(1,163,513)2226 PTD ITC85 (2,365.510)(2.365,510)
2227 PTD ITC86 (1,233,135)(1,233.135)
2228 PTD ITC88 (192,618)(192,618)2229 PTD ITC89 (427,864)(427,864)
2230 PTD ITC90 (287,130)(246.985)(40,145)(40.145)
2231 PTD SO (118,1791 (118,179)
2232 Total Accumlated ITC S19 (5,669,770)(5.629,625)(40,145)(11,179 (158,324)
2233
2234 Total Rate Base Deductions (3,160,349,288)(2,990,829,285)(169,520,003)(6,407,474)(175,927,478)
2235
2010 PROTOCOL Page 2.36
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
2236
2237
2238 108SP Steam Prod Plant Accumulated Depr
2239 P S
2240 P SG (804,085.770)(755,18,540)(48,667,229)(48,667,229)
2241 P SG (931,773,797)(875,378,260)(56,395,537)(56,395,537)2242 P SG (599,387,572)(563,109,685)(36,277,887)(699,345)(36,977,231)2243 P SG
2244 P SG (164,881,495)(154,902,055)(9,979,440)(9,979,44)2245 617 (2,500,128,634)(2,348,808,541 )(151,320,093)(699,345)(152,019,438)
2246
2247 108NP Nuclear Prod Plant Accumulated Depr
2248 P SG
2249 P SG
2250 P SG
2251 B17
2252
2253
2254 108HP Hydraulic Prod Plant Accum Depr
2255 P S
2256 P SG (153,199,830)(143,927,422)(9,272,408)(9,272,408)2257 P SG (29,592.043)(27,800,987)(1,791,056)(1,791,056)2258 P SG (64,346,115)(60,451,572)(3,894,544)203,627 (3,690,917)2259 P SG (15,581,955)(14,638,858)(943,097)(92,818)(1,035,914)2260 617 (262,719,943)(246,818,839)(15,901,104)110,809 (15,790,295)2261
2262 1080P Other Production Plant - Accum Depr
2263 P S
2264 P SG (1,499,697)(1,408,928)(90,769)(90,769)2265 P SG (187,115,295)(175,790,156)(11,325,139)(11,325,139)2266 P SG (179,211,214)(168,364,469)(10,846,745)(10,846,745)2267 P SG (20,480,021 )(19,240,469)(1,239,552)(1,239,552)2268 617 (388,306,227)(364,804,022)(23,502,204)(23,502,204)2269
2270 108EP Expenmental Plant - Accum Depr
2271 P SG
2272 P SG
2273
2274
2275 Total Production Plant Accum Depreciation 617 (3,151,154,804)(2,960,431,403)(190,723,402)(588,535)(191,311,937)2276
2277 Summary of Prod Plant Depreciation by Factor
2278 S
2279 DGP
2280 DGU
2281 SG (3,151,154,804)(2,960,431,403)(190,723,402)(588,535)(191,311,937)2282 SSGCH
2283 SSGCT
2284 Total of Prod Plant Depreciation by Factor (3,151,154,84)(2,960,431,403)(190,723,402)(588,535)(191,311937)2285
2286
2287 108TP Transmission Plant Accumulated Depr
2288 T SG (381,012,603)(357,951,845)(23,060,758)2289 T SG (398,290,095)(374,183,618)(24,106,477)2290 T SG 393,511,965)(369,694,683)23,817,281 )(161,960)2291 Total Trans Plant Accum Depreciation B17 , 7 ,814,663 7 , 84,5 7 1, 6
2010 PROTOCOL Page 2.37
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
2292 108360 Land and Land Rights
2293 DPW S (7.520.631 )(7.069.954)(450.676)(450.676)
2294 617 (7.520.631)(7.069.954)(450.676)(450.676)
2295
2296 108361 Structures and Improvements
2297 DPW S (14,400,815)(13.938.693)(462.122)(462.122)
2298 617 (14,400.815)(13.938.693)(462.122)(462.122)
2299
2300 108362 Station Equipment
2301 DPW S . (215.414.073)(205.959.864)(9,454.209)(9,454.209)
2302 617 (215,14.073)(205.959.864)(9,454.209)(9,454.209)
2303
2304 108363 Storage Battery Equipment
2305 DPW S
2306 617
2307
2308 108364 Poles. Towers & Fixtures
2309 DPW S (499.610.379)(463.144.133)(36,66.247)(36,66.247)
2310 617 (499.610.379)(463.144.133). (36.466.247)(36.466.247)
2311
2312 108365 Overhead Conductors
2313 DPW S (271.507.003)(260.179.548)(11.327,454)(11.327,454)
2314 617 (271.507.003)(260.179.548)(11.327.454)(11.327,454)
2315
2316 108366 Underground Conduit
2317 DPW S (125.057.953)(121.694.746)(3.363.206)(3.363.206)
2318 617 (125.057.953)(121.694.746)(3.363.206)(3.363.206)
2319
2320 108367 Underground Conductors
2321 DPW S (289.382.714)(278.272.333)(11.110.381)(11.110.381)
2322 B17 (289.382.714)(278.272.333 )(11.110.381)(11.110.381)
2323
2324 108368 Line Transformers
2325 DPW S (374.776.489)(350.828,934)(23.947.556)(23.947.556)
2326 617 (374.776.489)(350.828.934)(23.947.556)(23.947.556)
2327
2328 108369 Services
2329 DPW S (173.063.574)(162.208.058)(10.855.515)(10.855.515)
2330 617 (173.063.574)(162.208.058)(10.855.515)(10.855.515)
2331
2332 108370 Meters
2333 DPW S (73,459.993)(65.057.658)(8,402.334)(8,402.334)
2334 617 (73,459.993)(65.057.658)(8,02.334 )(8,402.334)
2335
2336
2337
2338 108371 Installations on Customers' Premises
2339 DPW S (7.902.179)(7.765.116)(137.063)(137.063)
2340 617 (7.902.179)(7.765.116)(137,03)(137.063)
2341
2342 108372 Leased Properl
2343 DPW S
2344 617
2345
2346 108373 Street Lights
2347 DPW S (27,437.568)(26.951.399)(486.169)(486.169)
2348 617 (27.437.568)(26.951.399)(486.169)(486.169)
2349
2350 108DOO Unclassified Dist Plant - Acct 300
2351 DPW S
2352 617
2353
2354 108DS Unclassified Dist Sub Plant - Acct 300
2355 DPW S
2356 617
2357
2358 108DP Unclassified Dist Sub Plant - Acct 300
2359 DPW S 7.323.293 7.315.721 7.572 7.572
2360 617 7.323.293 7.315.721 7.572 7.572
2361
2362
2363 Total Distribution Plant Accum Depreciation B17 (2,072,210,076)(1.955,754,716)(116,455,361)(116,455,361)
2364
2365 Summary of Distribution Plant Depr by Factor
2366 S (2.072.210.076)(1.955.754.716)(116,455.361 )(116,455.361)
2367
2368 Total Distribution Depreciation by Factor 617 (2.072.210.076)(1.955.754.716)(116,455.361)(116.455.361 )
2010 PROTOCOL Page 2.38
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
2369 108GP General Plant Accumulated Depr
2370 G-SITUS S (152,075,528)(141,631,971)(10,443,557)(10,443,557)
2371 PT SG (3,260,839)(3,063,477)(197,362)(197,362)
2372 PT SG (5,665,017)(5,322,143)(342,875)(342,875)
2373 G-SG SG (49,106,625)(46,134,451)(2,972,175)(2,972,175)
2374 CUST CN (7,361,183)(7,076,386)(284,796)(284,796)
2375 PTD SO (71,958,569)(67,789,115)(4,169,454)(4,169,454)
2376 P SE (334,770)(313,542)(21,228)(21,228)
2377 G-5G SG (40,513)(38,061)(2,452)(2,452)2378 G-SG SG (1,892,045)(1,777,529)(114,516)(114.516)
2379 B17 (291,695,088)(273,146,674)(18,548,414)(18,548,14)
2380
2381
2382 108MP Mining Plant Accumulated Depr.
2383 P S
2384 P SE (155,112,236)(145,276,532)(9,835,703)(36,877)(9,872,581)
2385 B17 (155,112,236)(145,276,532)(9,835,703)(36,877)(9,872,581 )
2386 108MP Less Centralia Situs Depreciation
2387 P S
2388 617 (155,112,236)(145,276,532)(9,835,703)(36,877 (9,872,581)
2389
2390 1081390 Accum Depr - Capital Lease
2391 PTD SO B17
2392
2393
2394 Remove Capital Leases
2395 617
2396
2397 1081399 Accum Depr - Capital Lease
2398 P S
2399 P SE 617
2400
2401
2402 Remove Capital Leases
2403 617
2404
2405
2406 Total General Plant Accum Depreciation B17 (446,807,324)(418,423,207)(28,384,117)(36,877)(28,420,995)
2407
2408
2409
2410 Summary of General Depreciation by Factor
2411 S (152,075,528)(141,631,971)(10,443,557)(10,43,557)
2412 DGP
2413 DGU
2414 SE (155,447,006)(145,590,074)(9,856,931 )(36,877)(9,893.808)
2415 SO (71,958,569)(67,789,115)(4,169,454)(4,169,454)
2416 CN (7,361,183)(7,076,386)(284,796)(284,796)
2417 SG (59,965,039)(56,335,660)(3,629,379)(3,629,379)
2418 DEU
2419 SSGCT
2420 SSGCH
2421 Remove Capital Leases
2422 Total General Depreciation by Factor (446,807,324)(418,423,207)(28,384,117)(36,877)(28,20,995)
2423
2424
2425 Total Accum Depreciation. Plant In Service B17 (6,842,986,868)(6,436,439,471 )(406,547,397)(787,372)(407,334,769)
2426 111SP Accum Prov for Amort-Steam
2427 P SG
2428 P SG
2429 618
2430
2431
2432 lllGP Accum Prov for Amort-General
2433 G-SITUS S (16,724,813)(16,724,813)2434 CUST CN (2,724,543)(2,619,133)(105,410)(105,410)
2435 I-SG SG
2436 PTD SO (10,775,043)(10,150.710)(624,332)(624,332)
2437 P SE
2438 618 (30,224,398)(29,494,656)(729,742)(729,742)
2439
2010 PROTOCOL Page 2.39
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
2440
2441 111HP Accum Prov for Amort-Hydro
2442 P SG
2443 P SG
2444 P SG (135.728)(127,513)(8.215)(8.215)
2445 P SG (437.050)(410.598)(26,452)(26,52)
2446 618 (572.778)(538,111)(34.667)(34.667)
2447
2448
2449 1111P Accum Prov for Amort-Intangible Plant
2450 I-SITUS S (1.045.867)(289.169)(756.698)(756,698)
2451 P SG
2452 P SG (349.396)(328.249)(21.147)(21.147)
2453 P SE (1.299.989)(1.217.557)(82,433)(82,433)
2454 I-SG SG (47.842.258)(44,946.609)(2.895.649)(32.831)(2.928,480)
2455 I-SG SG (14.069,890)(13.218.311)(851.579)(500.760)(1.352.339)
2456 1-5G SG (3,21.089)(3.214.027)(207.061)(207.061)
2457 CUST CN (94.981.920)(91.307,173)(3.674.748)(3.674.748)
2458 P SG
2459 P SG (122.031)(114.645)(7.386)(7.386)
2460 PTD SO (262.133,488)(246.944.839)(15.188.649)(15.188.649)
2461 618 (425.265.929)(401.580.580)(23.685.349)(533.590)(24.218.939)
2462 1111P Less Non-Utilty Plant
2463 NUTIL OTH
2464 (425.265.929)(401.580.580)(23.685.349)(533.590)(24.218.939)
2465
2466 111390 Accum Amtr - Capital Lease
2467 G-SITUS S (5.580.322)(5.580.322)
2468 P SG (1.701.025)(1,598.070)(102.954)(102.954)
2469 PTD SO 1.340.129 1.262,479 77650 77650
2470 (5.941.217)(5.915.913)(25.304)(25.304)
2471
2472 Remove Capital lease Amtr 5.941.217 5.915.913 25.304 25.304
2473
2474 Total Accum Provision for Amortization B18 (456,03,105)(431 ,613,347)(24,44,758)(533,590)(24,983,348)
2475
2476
2477
2478
2479 Summary of Amortization by Factor
2480 S (23.351,001 )(22.594.303)(756,698)(756,698)
2481 DGP
2482 DGU
2483 SE (1,299.989)(1.217.557)(82,433)(82,433)
2484 SO (271.568,401 )(255.833.071 )(15.735.330)(15.735.330)
2485 CN (97.706,463)(93.926.306)(3.780.157)(3.780,157)
2486 SSGCT
2487 SSGCH
2488 SG (68.07'8,468)(63,958.024)(4.120.44)(533.590)(4,654.034)
2489 Less Capital Lease 5.941.217 5.915.913 25.304 25.304
2490 Total Provision For Amortization by Factor (456.063.105)(431.613.347)(24.449.758)(533.590)(24.983,348)
IDAHO 2010 PROTOCOL Page 3.0 Total
Revenue Adjustments (Tab 3)
TOTAL
3.1 3.2 3.3 3.3.5 3.6
Temperature Revenue Effective Pnce S02 Emission
Total Normalized Normalization Normalization Change Allowances REC Revenues Wheeling Revenue
1 Operating Revenues:
2 General Business Revenues 11,637,673 54,163 (3,469,568)14,561,078
3 Interdepartmental
4 Special Sales
5 Other Operating Revenues 521,143 405,372 115,771
6 Total Operating Revenues 12,158,816 54,163 (3,69,568)14,561,078 405,372 115,771
7
8 Operating Expenses:
9 Steam Production
10 Nuclear Production
11 Hydro Prouction
12 Other Power Supply
13 Transmission (48,37)(48.37)
14 Distnbution
15 Customer Accounting
16 Customer Seivice & Info
17 Sales
18 Administrative & General
19 Total O&M Expenses (48.37)(48.37)
20 Depreciation
21 Amortization
22 Taxes Other Than Income
23 Income Taxes: Federal 4,018,872 182,478 (1,159,217)4,865,002 (59,693)135,439 54,863
24 State 54,098 24,796 (157,518)661,073 (8,111)18,404 7,455
25 Deferred Income Taxes 198,801 196,801
26 Investment Tax Credit Adj.
27 Misc Revenue & Expense (345,174)(345,174)
28 Total Operating Expenses:4,370,161 207,274 (1,316,736)5,526,075 (214,177)153,843 13,882
29
30 Operating Rev For Retum:7,788,655 338,889 (2,152,832)9,035,003 214,177 251.530 101,889
31
32 Rate Base:
33 Electnc Plant In Servce
34 Plant Held for Future Use
35 Misc Deferred Debits
36 Elec Plant Acq Adj
37 Nuclear Fuel
38 Prepayments
39 Fuel Stock
40 Matenal & Supplies
41 Working Capital
42 Weathenzation Loans
43 Misc Rate Base
44 Total Electnc Plant:
45
46 Deductions:
47 Accum Prev For Deprec
48 Accum Prov For Amort
49 Accum Def Income Tax 1,615,479 1,019,076 596,403
50 Unamortized ITC
51 Customer Adv For Const
52 Customer Seivice Deposits
53 Miscellaneous Deductions (1,571,507)(1,571,507)
54
55 Total Deductions:43,972 1,019,076 (975,104)
56
57 Total Rate Base:43,972 1,019,076 (975.104)
58
59
60 Estimated ROE impact 2.134%0.093%-0.607%2,477%0.076%0.069%0.028%
61
62
63
64 TAX CALCULATION:
65
66 Operating Revenue 12,552,426 54,163 (3,69,568)14,561,078 345,174 405,372 164,207
67 Other Deductions
68 Interest (AFUOC)
69 Interest
70 Schedule "M" Additions
71 Schedule "M" Deductions 523,836 523,836
72 Income Before Tax 12,028,591 546,163 (3,469,568)14,581,078 (178.662)405,372 164,207
73
74 State Income Taxes 546,098 24,796 (157,518)661,073 (8,111)18,404 7,455
75
76 Taxable Income 11,482,493 521,367 (3,312.050)13,900,005 (170,550)386,968 156,752
77
78 Federal Income Taxes 4,018,872 182,478 (1,159,217)4,865,002 (59,693)135,439 54,863
Rocky Mountain Power
Idaho General Rate Case - December 2010
Temperature Normalization
PAGE 3.1
TOTAL IDAHO
ACCOUNT ~COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Revenue:
Residential 440 1 450,023 ID Situs 450,023
Commercial 442 1 96,140 ID Situs 96,140
Total 546,163 546,163 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 rolling 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 system peak, energy loads and net power costs.
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Rocky Mountain Power
Idaho General Rate Case. December 2010
Table 1 . Usage Adjustments
State of Idaho
MWh's. Historic 12 Months Ended December 2010
Page 3.1.2
A B c
Normalization Total
Booked Adjustments 1 Normalized
Residential 705,128 4,541 709,669
Commercial 394,132 1,728 395,860
Industrial 181,298 (18)181,280
Irriaation 557,228 (1,924)555,304
Public St & Hwl ..2,583 250 2,833
Special Contract 2 104,026 386 104,412
Special Contract 1 Firm 78,840 0 78,840
Special Contract 1 Non Firm 1,303,060 (48,029)1,255,031
Special Contract 1 - Curtailed3 0 44,828 44,828
Total Idaho 3,326,294 1,762 3,328,057
Source I Formula 305 Table 2 A+B
1. Includes out of period adjustment, temperature adjustmènt and normalization of special contracts (buy-through out, curtailment in); Moving
Schedules 7 and 7A from Residential. Commercial and Industrial to Public Street Lighting; Moving Schedule 23 from Public Street Lighting to IndustriaL.
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Rocky Mountain Power PAGE 3.2
Idaho General Rate Case - December 2010
Revenue Normalization
TOTAL IDAHO
ACCOUNT ~COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Revenue:
Residential 440 1 (2,177,867)ID Situs (2,177,867)
Commercial 442 1 (415,733)ID Situs (415,733)Industrial 442 1 (234,320)10 Situs (234,320)
Irrigation 442 1 432,014 10 Situs 432,014
Public Street & Highway 444 1 1,458 10 Situs 1,458
Special Contract 2 442 1 37,751 10 Situs 37,751
Special Contract 1 - Firm 442 1 6,464 10 Situs 6,464
Special Contract 1- Interruptible 442 (2,186,693)10 Situs (2,186,693)
Special Contract 1 - Curtailed 442 1,067,357 10 Situs 1,067,357
Total (3,469,568)(3,469,568)3.1.1
Adjustment to Tax:
Schedule M - NW Power Act SCHMDT (603,662)OTHER 0.000%
Deferred Income Tax Expense 41010 (229,096)OTHER 0.000%
Accumulated Oef. Income Tax Balance 283 1,019,076 ID Situs 1,019,076
Schedule M - Oef Excess NPC - ID 09 SCHMDT 1 (10,341,116)OTHER 0.000%
Deferred Income Tax Expense 41010 1 (3,924,557)OTHER 0.000%
Accumulated Oef. Income Tax Balance 283 1 4,917,284 OTHER 0.000%
Description of Adjustment:
Included in actual revenue are a number of items that should not be included in regulatory results. These items include
the BPA credit, the SMUO and ECAM amortization, out of penod revenues, load curtailment and buy-throughs. This
adjustment normalizes revenues by removing the effect of these items.
Rocky Mountain Power PAGE 3.3
Idaho General Rate Case. December 2010
Effective Price Change
TOTAL IDAHO
ACCOUNT ~COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Revenue:
Residential 440 2 4,232,250 10 Situs 4,232,250
Commercial 442 2 1,778,781 10 Situs 1,778,781
Industrial 442 2 745,879 10 Situs 745,879
Irrigation 442 2 1,216,145 10 Situs 1,216,145
Public Street & Highway 444 2 125,550 10 Situs 125,550
8,098,605 8,098,605 3.1.1
Special Contract 2 442 3 434,526 10 Situs 434,526
Special Contract 1-Firm 442 3 326,942 10 Situs 326,942
Special Contract 1-lnterruptible 442 3 5,594,762 10 Situs 5,594,762
Special Contract 1 - Curtailed 442 3 106,243 10 Situs 106,243
6,462,473 6,462,473 3.1.1
Description of Adjustment:
This adjustment normalizes retail revenues for known and measurable changes through December 2011, including the price
change effective December 28, 2010 and January 1, 2011 as ordered in Case No. PAC-E-10-07.
Rocky Mountain Power
Idaho General Rate Case - December 2010
502 Emission Allowances
PAGE 3.4
TOTAL IDAHO
ACCOUNT ~COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Revenue:
Remove 12 ME Dec 2010 Allowance Sales 4118 1 2,817,551 SE 6.341%178,662 3.4.1
Add 12 ME Dec 2011 Amortization 4118 3 (8,261,058)SE 6.341%(523,836) 3.4.2
Total (5,443,506)(345,174)
Adjustment to Rate Base:
Regulatory Deferred Sales 25398 3 (24,783,174)SE 6.341%(1,571,507)3.4.2
Adjustment to Tax:
Schedule M Deduction
DIT Expense
Accumulated Deferred Income Taxes
SCHMDT 3
41010 3190 3
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3,135,154
9,405,462
SE
SE
SE
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6.341%
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523,836 3.4.2
198,801 3.4.2
596,403 3.4.2
Description of Adjustment:
Over the years, the Company's annual revenue from the sale of sulfur dioxide ("S02") emission allowances has been
uneven. This adjustment amortizes sales prior to June 30, 2009, includes a reduction to rate base for the unamortized
balance and the associated tax impacts. In Case No. PAC-E-07-05 revenue from S02 sales was amortized over 15 years.
However, in Case No. PAC-E-10-07 the Company agreed to shorten the amortization of the remaining balances to five
years. Thus, this adjustment reflects the new five year amortization methodology. Revenue from the sales of S02
emission allowances after June 30, 2009 are captured in the power cost recovery mechanism per Case No. PAC-E-08-08.
Rocky Mountain Power Page 3.4.1
Idaho General Rate Case. December 2010
S02 Emission Allowance Sales
SAP Account 301947
Year Month Amount Balance
2010 1
2010 2 (402,500)(402,500)
2010 3 (1,647,551 )(2,050,051 )
2010 4 (372,500)(2,422,551 )
2010 5 (2,422,551 )
2010 6 (0)(2,422,551 )
2010 7 (2,422,551 )
2010 8 (395,000)(2,817,551 )
2010 9 (2,817,551)
2010 10 (2,817,551 )
2010 11 (2,817,551 )
2010 12 (2,817,551)
(2,817,551 )Pg.3.4.1
Sales after June 2009 are passed back to customers via the
Company's Energy Cost Adjustment Mechanism (ECAM).
Refer to Order No. 30904 of Case No. PAC-E-08-08, Item 14.
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Rocky Mountain Power PAGE 3.5
Idaho General Rate Case. December 2010
REC Revenues
TOTAL IDAHOACCOUNT ~COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Revenue:
Remove 2010 Booked Revenues 456 3 (101,136,015)SG 6.052%(6,121,249)Add 2011 Forecast Revenues 456 3 78,842,787 SG 6.052%4,771,954
ORlCAf A RPS Eligible:
Reallocation of CY 2011 Revenue
for Non-RPS States 456 3 10,693,506 SG 6.052%647,224 3.5.1
Adjustment for CA RPS Banking 456 3 . (503,456)CA Situs 3.5.1
Adjustment for OR RPS Banking 456 3 (7,802,147)OR Situs 3.5.1
Adjustment for WA RPS Banking 456 3 (2,387,903)WA Situs
647,224
ORICA RPS Eligible
Reallocation of CY 2011 Revenue
for Non-RPS States 456 3 18,085,116 SG 6.052%1,094,600 3.5.1
Adjustment for OR RPS Banking 456 3 (1,096,255)CA Situs 3.5.1
Adjustment for CA RPS Banking 456 3 (16,988.860)OR Situs 3.5.1
1,094,600
CA RPS Eligible
Reallocation of CY 2011 Revenue
for Non-RPS States 456 3 212,217 SG 6.052%12,844 3.5.1
Adjustment for CA RPS Banking 456 3 (212,217)CA Situs 3.5.1
Adjustment for OR RPS - Ineligible Wind 456 3 (1.821,378)OR Situs 3.5.1
Adjustment for OR RPS - Ineligible Wind 456 3 1,821,378 OTHER 0.000%3.5.1
12,844
Description of Adjustment:
A market for green tags or renewable energy credits ("RECs") has developed where the tag or "green" traits of qualifying
power production facilities 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, Oregon, and Washington have renewable
portolio standards. As such, the Company does not sell California, Oregon, or Washington eligible RECs. Instead, the
Company uses the renewable output to comply with current year or future year renewable portolio requirements. This
adjustment reallocates Oregon, California, and Washington's SG factor amounts of 2011 estimated revenues to the
Company's other jurisdictions, consistent with the agreement with the Multi-State Process (MSP) standing committee.
Actual REC revenues wil be accounted for in the Company's ECAM fiings as ordered by the Idaho Commission in Order
No. 32196, Docket No. PAC-E-10-07.
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Page 3.5.2
Rocky Mountain Power
Idaho General Rate Case. December 2010
REC Revenues
2011 Estimated Renewable Energy Credits From Wind Generation
1 - Renewable Energy Credits from Wind (Eligible for ORlCNWA RPS) - MWH 1,152,722
3.356.680
292,594
1,152,722 Above
64.31%
741,317
75.00%
555,987
404.449 $18,208,000
151,538 $1,060,769
$19.268,769
$19,268,769
Ref 3.5.1
3,356,680 Above
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75.00%
1,819,651
1,219.348 $38,888,820
600.303 $4,202,122
$43,090,942
109,646 $3,786.592
49,000 $279.000
$47,156,534
Ref 3.5.1
292,594 Above
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287,677
75.00%
215,758
119.830 $6,205.540
95,928 $671,496
215,758 $6,877,036
156,345 $5.540.448
$12,417,484
Ref 3.5.1
2 ~ Renewable Energy Credits from Wind (Eligible for CAlOR RPS) - MWH
3 - Renewable Energy Credits from Wind (Eligible for CA RPS only) - MWH
1 . Renewable Energy Credits Eligible for OR/CAIA RPS
Wind Generation - MWH
SG Factor Allocated Portion
Wind MWH Available for Sale
Percent Sold
MWH Sold in Test Period
Known Wind Sales
Available Wind Credits Remainino for Sale (e $7
Total 2011 Estimated REC Revenues Eliaible for OR/CAIA RPS
2 - Renewable Energy Credits Eligible for CAlOR RPS
Wind Generation - MWH
SG Factor Allocated Portion
Wind MWH Available for Sale
Percent Sold
MWH Sold in Test Period
Known Wind Sales - MWh
Available Wind Credits Remaining for Sale ~ $7
Known Non-Wind Sales
Known Vintage Sales
Total 2011 Estimated REC Revenues Eli ible for CAlOR RPS
3 - Renewable Energy Credits Eligible for CA RPS
Wind Generation - MWH
SG Factor Allocated Portion
Wind MWH Available for Sale
Percent Sold
MWH Sold in Test Period
Known Wind Sales
Available Wind Credits Remainino for Sale (â $7
Known Non-Wind Sales
Total 2011 Estimated REC Revenues Eliiiible for CA RPS
Rocky Mountain Power
Idaho General Rate Case. December 2010
Wheeling Revenue
PAGE 3.6
Wheeling Imbalance Expense 566 3 (800,275) SG 6.052%(48,437)
Adjustment Detail:
Actual Wheeling Revenues 12 ME Dec 2010
Total Adjustments
Normalized Wheeling Revenues
67,812,115
1,813,143
69,625,258
B1
3.6.3
3.6.2
Description of Adjustment:
This adjustment reflects the level of wheeling revenues the Company expects in the12 months ending December 31,
2011 by adjusting the actual revenues for the 12 months ended December 31,2010 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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IDAHO 2010 PROTOCOL Page 4.0 Total
O&M Adjustments (Tab 4)
TOTAL
4.1 4.2 4.2.1 4.2.2 4.3 4.3.1
4.2 - Wage and 4.2.1 - Wage and 4.2.2 - Wage and 4.3 - Wage and 4.3.1 - Wage and
Miscellaneous Employee Beneft.Employee Benefit -Employee Beneft -Employee Benefi - Employee Benefrt -
Total Normalized General Expense Annuallzation Annualízation Annualization Pro Forma Pro Forma
1 Operating Revenues:
2 General Business Revenues
3 Interdepartmental
4 Special Sales
5 Other Operating Revenues (5.939.833)
6 Total Operating Revenues (5.939.833)
7
8 Operating Expenses:
9 Steam Production 1.005 11.792 150.620
10 Nuclear Production
11 Hydro Production 27.913 1.723 22.006
12 Other Power Supply 657.607 968 3.124 12.382 39.906
13 Transmission 71.772 (11)2,054 26,230
14 Distribution 590.671 (34)9,034 534 115.384
15 Customer Accounting (108,425)(551)4,808
16 Customer Service & Info (5,923,722)2,031 876
17 Sales
18 Administrative & General 1,591,962 (15,470)10,821
19 Total O&M Expenses (2,891.217)(14,035)14,483 14,211 17,038 184,988 181,520
20 Depreciation
21 Amortization
22 Taxes Other Than Income
23 Income Taxes: Federal (1,625,412)4,689 (4,839)(4,748)(5,693)(61,806)(60,648)
24 State (220,867)637 (658)(645)(774)(8,398)(8,241)
25 Deferred Income Taxes 861,571
26 Investment Tax Credit Adj.
27 Misc Revenue & Expense
28 Total Operating Expenses:(3,875,925)(8,708)8,986 8,818 10,572 114,783 112,631
29
30 Operating Rev For Return:(2,063,908)8,708 (8,986)(8,818)(10,572)(114,783)(112,631)
31
32 Rate Base:
33 Electric Plant In Service
34 Plant Held for Future Use
35 Misc Deferred Debits (4,596)
36 Elec Plant Acq Adj
37 Nuclear Fuel
38 Prepayments
39 Fuel Stock
40 Material & Supplies
41 Working Capital
42 Weatherization Loans
43 Misc Rate Base
44 Total Electrc Plant:(4,596)
45
46 Deductions:
47 Accum Prov For Deprec
48 Accum Prov For Amort
49 Accum Def Income Tax (122,194)
50 Unamortized ITC
51 Customer Adv For Canst
52 Customer Service Deposits
53 Miscellaneous Deductions
54
55 Total Deductions:(122,194)
56
57 Total Rate Base:(126,790)
56
59
60 Estimated ROE impact -0.56%0.002%-0.002%-0.002%-0.003%-0.031%-0.031%
61
62
63
64 TAX CALCULATION:
65
66 Operating Revenue (3,046,616)14,035 (14.463)(14.211)(17,038)(184,988)(181,520)
67 Other Deductons
68 Interest (AFUDC)
69 Interest
70 Schedule "M" Additions (2,581,684)
71 Schedule "M" Deductons (765.399)
72 Income Before Tax (4,884.902)14,035 (14,483)(14,211)(17,038)(184,988)(181,520)
73
74 State Income Taxes (220,867)637 (658)(645)(774)(8,398)(8,241)
75
76 Taxable Income (4,64,035)13,397 (13,825)(13,566)(16,265)(176,590)(173,279)
77
78 Federal Income Taxes (1,625,412)4,689 (4,839)(4.748)(5,693)(61,806)(60,848)
IDAHO 2010 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
Employee Benefit.Class 1 DSM Remove Non~Pension DSM Revenue and Wyoming Inverted MEHC Transition
Pro Forma Program Costs Recurring Entries Curtilment Expense Removal Rates Advertsing Cost Amortzation
1 Operating Revenues:
2 General Business Revenues
3 Interdepartental
4 Special Sales
5 Other Operating Revenues (5,939,833)
6 Total Operating Revenues (5,939,833)
7
8 Operating Expenses:
9 Steam Producton 12,999
10 Nuclear Production
11 Hydro Production 4,184
12 Other Power Supply 555,129 (183,572)
13 Transmission (36)
14 Distribution 6,821 (88)
15 Customer Accounting 61,414
16 Customer Service & Info 11.185 (5,939;833)2,019
17 Sales
18 Administrative & General 138,210 135,060 116,84 (330,460)19 Total O&M Expenses 217,629 555,129 (31.453)116.464 (5,939,833)2,019 (33,460)
20 Depreciation
21 Amortization
22 Taxes Other Than Income
23 Income Taxes: Federal (7,712)(185.474)10,509 (38.912)(548,226)(675)(93,462)
24 State (9.880)(25,203)1,428 (5,287)(74,495)(92)(12,700)25 Deferred Income Taxes 622,721 231,575
26 InvestmentT ax Cred~ Adj.
27 Misc Revenue & Expense
28 Total Operating Expenses:135,37 34,452 (19.516)72,265 (5,939,833)1,253 (205.047)
29
30 Operating Rev For Return:(135,037)(34.452)19.516 (72.265)(1.253)205,047
31
32 Rate Base:
33 Electric Plant In Service
34 Plant Held for Future Use
35 Misc Deferred Debits
36 Elec Plant Acq Adj
37 Nuclear Fuel
38 Prepayments
39 Fuel Stock
40 Material & Supplies
41 Working Capital
42 Weatherization Loans
43 Misc Rate Base
44 Total Electric Plant:
45
46 Deductons:
47 Accum Prov For Deprec
48 Accum Prov For Amort
49 Accum Def Income'Tax (206.465)140.971 568
50 Unamortzed ITC
51 Customer Adv For Const
52 Customer Service Deposits
53 Miscellaneous Deductions
54
55 Total Deductions:(206,465)140.971 568
56
57 Total Rate Base:(206,465)140,971 568
58
59
60 Estimated ROE impact -0.037%-0.094%0.009%-0.020%-0.002%0.000%0.056%
61
62
63
64 TAX CALCULATION:
65
66 Operating Revenue (217,629)(555.129)31,453 (116,64)(2,019)330,460
67 Other Deductions
68 Interest (AFUDC)
69 Interest
70 Schedule "M" Additions (1,640,855)(610.194)71 Schedule "M' Deductions
72 Income Before Tax (217,629)(55,129)31,453 (116,64)(1,640,855)(2.019)(279,734)
73
74 State Income Taxes (9.880)(25.203)1,428 (5,287)(74.495)(92)(12,700)
75
76 Taxable Income (207,749)(529.926)30,025 (111.177)(1,566.360)(1,928)(267,034)
77
78 Federal Income Taxes (72,712)(185,474)10,509 (38.912)(548.226)(675)(93,462)
IDAHO 2010 PROTOCOL Page 4.0.2 Total
O&M Adjustments (Tab 4)
TOTAL
4.10 4.11 4.12 4.13 4.14 4.15 4.16
10 Pension
MEHC Cross Generation Memberships &Expense - Cash
Charge Insurance Expense Overhaul Expense Incremental O&M Subscriptions Intervenor Funding Basis
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 (392.533)218,126
10 Nuclear Production
11 Hydro Production
12 Other Power Supply 64.738 251,208 113.745
13 Transmission 38.300 5.236
14 Distrbution 459.020
15 Customer Accounting
16 Customer Service & Info
17 Sales
18 Administrative & General (11.592)(576.947)(34,452)26,016 2,054,449
19 Total O&M Expenses (11.592)(14,889)(141.325)337.107 (34,452)26,016 2.054,449
20 Depreciation
21 Amortization
22 Taxes Other Than Income
23 Income Taxes: Federal 3,873 158.760 47,218 (112.631)11.511 (19.545)(684.085)24 State 526 21.573 6,416 (15.305)1.56 (2.656)(92.956)25 Deferred Income Taxes (2,409)12.328 (2.643)26 Investment Tax Credit Adj.
27 Misc Revenue & Expense
28 Total Operating Expenses:(7.193)163.34 (87.691)209.172 (21.377)16.143 1.274,765
29
30 Operating Rev For Return:7.193 (163.034)87,691 (209.172)21.377 (16,143)(1.274,765)
31
32 Rate Base:
33 Electric Plant In Service
34 Plant Held for Future Use
35 Mlsc Deferred Debits (4,596)36 Elec Plant Acq Ad)
37 Nuclear Fuel
38 Prepayments
39 Fuel Stock
40 Material & Supplies
41 Workin9 Capital
42 Weatherization Loans
43 Misc Rate Base
44 Total Electric Plant:(4.596)
45
46 Deductions:
47 Accum Prov For Deprec
48 Accum Prov For Amort
49 Accum Def Income Tax (5,657)(51,611)50 Unamortized ITC
51 Customer Adv For Const
52 Customer Servi.ce Deposit
53 Miscellaneous Deductions
54
55 Total Deductions:(5.657)(51.611)
56
57 Total Rate Base:(10.253)(51,611)
58
59
60 Estimated ROE Impact 0.002%-0.045%0.024%-0.057%0.006%-0.004%-0.349%
61
62
63
64 TAX CALCULATION:
65
66 Operating Revenue 11.592 14,889 141.325 (337.107)34,452 (26.016)(2.054.449)
67 Other Deductons
68 Interest (AFUDC)
69 Interest
70 Schedule "M" Additions (313.056)(17.560)71 Schedule "M' Deductions (773.339)14,904 (6.964)72 Income Before Tax 11.592 475.172 141,325 (337.107)34,452 (58,500)(2,047,486)
73
74 State Income Taxes 526 21,573 6,16 (15.305)1.564 (2.656)(92.956)
75
76 Taxable Income 11.066 453,599 134,909 (321,803)32.888 (55.844)(1.954.530)
77
78 Federal Income Taxes 3.873 156.760 47.218 (112,631)11.511 (19.545)(684.085)
IDAHO 2010 PROTOCOL
O&M Adjustments (Tab 4)
TOTAL
1 Operating Revenues:
2 General Business Revenues
3 Interdepartmental
4 Special Sales
5 Other Operaüng Revenues
6 Total Operating Revenues
7
8 Operating Expenses:
9 Sleam Production
10 Nuclear Producton
11 Hydro Production
12 Other Power Supply
13 Transmission
14 Distribution
15 Customer Accountin9
16 Customer Service & Info
17 Sales
18 Administrative & General
19 Total O&M Expenses
20 Depreciation
21 Amortzaüon
22 Taxes Other Than Income
23 Income Taxes: Federal24 State
25 Deferred Income Taxes
26 Investment Tax Credit Adj.
27 Misc Revenue & Expense
28 Total Operatin9 Expenses:
29
30 Operaüng Rev For Return:
31
32 Rate Base:
33 Electric Plant In Service
34 Plant Held for Future Use
35 Misc Deferred Debits
36 Elec Plant Acq Adj
37 Nuclear Fuel
38 Prepayments
39 Fuel Stock
40 Material & Supplies
41 Workin9 Capital
42 Weatherizaüon Loans
43 Misc Rate Base
44 Total Electric Plant:
45
46 Deductons:
47 Accum Prov For Deprec
48 Accum Prov For Amort
49 Accum Def Income Tax
50 Unamortized ITC
51 Customer Adv For Canst
52 Customer Service Deposits
53 Miscelianeous Deductions
54
55 Total Deductions:
56
57 Total Rate Base:
58
59
60 Estimated ROE impact
61
62
63
64 TAX CALCULATION:
65
66 Operatln9 Revenue
67 Other Deductions
68 Interest (AFUDC)
69 Interest
70 Schedule 'M" Additions
71 Schedule "M" Deductons
72 Income Before Tax
73
74 State Income Taxes
75
76 Taxable Income
77
78 F ederallncome Taxes
Page 4.0.3 Total
4.17 4.18 o o o
Uncoliectble
Expense Outside Services o o
(174,096)
79,863
(174,096)79,863
58,167 (26,683)
7,904 (3,626)
(108,025)49,554
108,025 (49,554)
0.030%-0.014%0.000%0.00%0.000%
174,096 (79,863)
174,096 (79,863)
7.904 (3,626)
166.192 (76,237)
58,167 (26,683)
Description of Adjustment:
This adjustment removes from results of operations certain miscellaneous expenses that should have been charged to non-
regulated accounts.
Rocky Mountain Power Page 4.1.1
Idaho General Rate Case - December 2010
Miscellaneous General Expense
Description FERC Factor Amt to Exclude
Non-utility Flights
Office Supplies and Expenses 921 SO 3,260
Customer Accounts 901 CN 991 .
Transmission 560 SG 185
Distribution 580 SNPD 726
5,162
FERC 903 - Customer Accounts
Miscellaneous 903 CN 13,262
FERC 909 - Informational & Instructional Advertising
Miscellaneous 909 CN 22,455
Miscellaneous 909 ID (3,571)Donations 909 CN 2,975
Blue Sky 909 CN 1,207
23,066
FERC 921 - Office Supplies & Expenses
Charitable Donations and Sponsorships 921 SO 19,781
Employee Expenses 921 SO 32
Legislative & Lobbyist 921 SO 4,450
DSM Costs 921 SO 2,578
26,841
FERC 923 - Outside Services
Blue Sky 923 SO 1,360
1,360
FERC 930 - Misc General Expense
Challenge Grant - Idaho 930 IDU 12,950
Challenge Grant - Oregon 930 OR 38,850
EDCU Rent Contribution 930 UT 84,981
Utah Sports Authority Rent Contribution 930 UT 57,072
EDCU Other Contribution 930 UT 6,500
200,353
Centennial Celebration Expenses
Advertising 909 CN 13,157
Offce Supplies and Expenses 921 SO 11,443
Miscellaneous 931 SO 583
25,183
TOTAL MISC GENERAL EXPENSE REMOVED 295,227
Ref 4.1
Rocky Mountain Power PAGE 4.2
Idaho General Rate Case. December 2010
4.2 . Wage and Employee Benefit. Annualization
TOTAL IDAHO
ACCOUNT~COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Expense:
Steam Operations 500 2 24,229 SG 6.052%1,466
Fuel Related - Non NPC 501 2 (393)SE 6.341%(25)
Steam Operations 502 2 27,062 SG 6.052%1,638
Fuel Related - Non NPC 503 2 124 SE 6.341%8
Steam Operations 505 2 2,840 SG 6.052%172
Steam Operations 506 2 63,593 SG 6.052%3,849
Steam Operations 506 2 (5)SG 6.052%(0)
Steam Maintenance 510 2 4,525 SG 6.052%274
Steam Maintenance 511 2 10,757 SG 6.052%651
Steam Maintenance 511 2 (1 )SG 6.052%(0)
Steam Maintenance 512 2 40,829 SG 6.052%2,471
Steam Maintenance 512 2 (115)SG 6.052%(7)
Steam Maintenance 513 2 17,310 SG 6.052%1,048
Steam Maintenance 514 2 4,098 SG 6.052%248
Steam Maintenance 514 2 (8)SG 6.052%(0)
Hydro Operations 535 2 3,722 SG-P 6.052%225
Hydro Operations 535 2 2,608 SG-U 6.052%158
Hydro Operations 536 2 126 SG-P 6.052%8
Hydro Operations 537 2 587 SG-P 6.052%36
Hydro Operations 537 2 92 SG-U 6.052%6
Hydro Operations 539 2 9,218 SG-P 6.052%558
Hydro Operations 539 2 7,193 SG-U 6.052%435
Hydro Operations 540 2 (242)SG-P 6.052%(15)
Hydro Maintenance 542 2 667 SG-P 6.052%40
Hydro Maintenance 542 2 123 SG-U 6.052%7
Hydro Maintenance 543 2 513 SG-P 6.052%31
Hydro Maintenance 543 2 724 SG-U 6.052%44
Hydro Maintenance 544 2 1,150 SG-P 6.052%70
Hydro Maintenance 544 2 421 SG-U 6.052%25
Hydro Maintenance 545 2 1,110 SG-P 6.052%67
Hydro Maintenance 545 2 455 SG-U 6.052%28
Other Operations 546 2 3 SG 6.052%0
Other Operations 548 2 7,450 SG 6.052%451
Other Operations 548 2 946 SG 6.052%57
Other Operations 549 2 4,070 SG 6.052%246
Other Maintenance 552 2 194 SG 6.052%12
Other Maintenance 552 2 75 SG 6.052%5
Other Maintenance 553 2 3,027 SG 6.052%183
Other Maintenance 553 2 226 SG 6.052%14
239,301 14,483 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 dunng the year ended December 31, 2010 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 2010
4.2.1 - Wage and Employee Benefit - Annualization
TOTAL IDAHO
ACCOUNT~COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Expense:
Other Maintenance 554 2 65 SG 6..052%4
Other Maintenance 554 2 134 SG 6.052%8
Other Operations 556 2 648 SG 6.052%39
Other Operations 557 2 50,773 SG 6.052%3,073
Transmission Operations 560 2 6,143 SG 6.052%372
Transmission Operations 561 2 13,592 SG 6.052%823
Transmission Operations 562 2 1,748 SG 6.052%106
Transmission Operations 563 2 110 SG 6.052%7
Transmission Operations 566 2 501 S8 6.052%30
Transmission Operations 567 2 249 SG 6.052%15
Transmission Maintenance 568 2 1,620 SG 6.052%98
Transmission Maintenance 569 2 3,984 SG 6.052%241
Transmission Maintenance 570 2 9,755 SG 6.052%590
Transmission Maintenance 571 2 (3,806)SG 6.052%(230)Transmission Maintenance 572 2 22 SG 6.052%1
Transmission Maintenance 573 2 10 SG 6.052%1
Distribution Operations 580 2 23,900 SNPD 4.636%1,108
Distribution Operations 581 2 20,773 SNPD 4.636%963
Distribution Operations 582 2 2,998 ID Situs 192
Distribution Operations 582 2 31 SNPD 4.636%1
Distribution Operations 583 2 7,526 ID Situs 263
Distribution Operations 583 2 31 SNPD 4.636%1
Distribution Operations 585 2 328 SNPD 4.636%15
Distribution Operations 586 2 7,090 ID Situs 366
Distribution Operations 586 2 1,486 SNPD 4.636%69
Distribution Operations 587 2 16,588 ID Situs 525
Distribution Operations 588 2 (1,125)ID Situs (83)
Distribution Operations 588 2 323 SNPD 4.636%15
Distribution Operations 589 2 199 ID Situs 1
Distribution Maintenance 590 2 1,046 ID Situs 67
Distribution Maintenance 590 2 7,171 SNPD 4.636%332
Distribution Maintenance 592 2 10,984 ID Situs 782
Distribution Maintenance 592 2 2,151 SNPD 4.636%100
Distribution Maintenance 593 2 36,105 ID Situs 3,486
Distribution Maintenance 593 2 (888)SNPD 4.636%(41)
Distribution Maintenance 594 2 21,152 ID Situs 623
Distribution Maintenance 595 2 1,128 SNPD 4.636%52
Distribution Maintenance 596 2 2,931 ID Situs 196
247,478 14,211 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 ended December 31 , 2010 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 4.2.2
Idaho General Rate Case. December 2010
4.2.2 . Wage and Employee Benefit. Annualization
TOTAL IDAHOACCOUNT~COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Expense:
Distribution Maintenance 597 2 6,121 10 Situs 402
Distribution Maintenance 597 2 1,155 SNPD 4.636%54
Distribution Maintenance 598 2 183 10 Situs
Distribution Maintenance 598 2 1,685 SNPD 4.636%78
Customer Accounts 901 2 2 ID Situs
Customer Accounts 901 2 3,098 CN 3.869%120
Customer Accounts 902 2 27,406 ID Situs 2,156
Customer Accounts 902 2 2,325 CN 3.869%90
Customer Accounts 903 2 8,303 ID Situs 455
Customer Accounts 903 2 51,198 CN 3.869%1,981
Customer Accounts 905 2 175 CN 3.869%7
Customer Services 907 2 381 CN 3.869%15
Customer Services 908 2 7,201 ID Situs 679
Customer Services 908 2 3,968 CN 3.869%154
Customer Services 908 2 59 OTHER 0.000%
Customer Services 909 2 727 CN 3.869%28
Customer SerVices 910 2 2 CN 3.869%0
Administrative & General 920 2 123,187 SO 5.794%7,138
Administrative & General 921 2 (395)SO 5.794%(23)
Administrative & General 922 2 44,879 SO 5.794%2,600
Administrative & General 928 2 4,463 ID Situs 949
Administrative & General 928 2 299 SO 5.794%17
Administrative & General 929 2 (1,469)SO 5.794%(85)
Administrative & General 935 2 31 ID Situs
Administrative & General 935 2 3,871 SO 5.794%224
288,857 17,038 Below
Total Annualization Adjustment
239,301
247,478
288,857
775,636
14,483
14,211
17,038
45,733
4.2
4.2.1
Above
4.3.4
The Company has several labor groups, each with different effective contract renewal dates. This adjustment annualizes
the wage increases that occurred during the year ended December 31, 2010 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 2010
4.3 . Wage and Employee Benefit. Pro Forma
TOTAL IDAHOACCOUNT~COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Expense:
Steam Operations 500 3 309,477 SG 6.052%18,731
Fuel Related - NON NPC 501 3 (5,017)SE 6.341%(318)Steam Operations 502 3 345,653 SG 6.052%20,921
Fuel Related - NON NPC 503 3 1,585 SE 6.341%101
Steam Operations 505 3 36,279 SG 6.052%2,196
Steam Operations 506 3 812,267 SG 6.052%49,162
Steam Operations 506 3 (68)SG 6.052%(4)Steam Maintenance 510 3 57,794 SG 6.052%3,498
Steam Maintenance 511 3 137,396 SG 6.052%8,316
Steam Maintenance 511 3 (18)SG 6.052%(1 )Steam Maintenance 512 3 521,509 SG 6.052%31,564
Steam Maintenance 512 3 (1,469)SG 6.052%(89)Steam Maintenance 513 3 221,098 SG 6.052%13,382
Steam Maintenance 514 3 52,346 SG 6.052%3,168
Steam Maintenance 514 3 (103)SG 6.052%(6)
Hydro Operations 535 3 47,545 SG-P 6.052%2,878
Hydro Operations 535 3 33,313 SG-U 6.052%2,016
Hydro Operations 536 3 1,605 SG-P 6.052%97
Hydro Operations 537 3 7,493 SG-P 6.052%454
Hydro Operations 537 3 1,169 SG-U 6.052%71
Hydro Operations 539 3 117,742 SG-P 6.052%7,126
Hydro Operations 539 3 91,874 SG-U 6.052%5,561
Hydro Operations 540 3 (3,087)SG-P 6.052%(187)Hydro Maintenance 541 3 5 SG-P 6.052%0
Hydro Maintenance 542 3 8,520 SG-P 6.052%516
Hydro Maintenance 542 3 1,569 SG-U 6.052%95
Hydro Maintenance 543 3 6,548 SG-P 6.052%396
Hydro Maintenance 543 3 9,245 SG-U 6.052%560
Hydro Maintenance 544 3 14,683 SG-P 6.052%889
Hydro Maintenance 544 3 5,376 SG-U 6.052%325
Hydro Maintenance 545 3 14,180 SG-P 6.052%858
Hydro Maintenance 545 3 5,808 SG-U 6.052%352
Other Operations 546 3 34 SG 6.052%2
Other Operations 548 3 95,161 SG 6.052%5,760
Other Operations 548 3 12,080 SG 6.052%731
Other Operations 549 3 51,986 SG 6.052%3,146
Other Maintenance 552 3 2,480 SG 6.052%150
Other Maintenance 552 3 960 SG 6.052%58
Other Maintenance 553 3 38,660 SG 6.052%2,340
Other Maintenance 553 3 2,882 SG 6.052%174
3,056,560 184,988 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 2011. 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 2010
4.3.1 - Wage and Employee Benefit. Pro Forma
TOTAL IDAHO
ACCOUNT~COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Expense:
Other Maintenance 554 3 825 SG 6.052%50
Other Maintenance 554 3 1,714 SG 6.052%104
Other Operations 556 3 8,271 SG 6.052%501
Other Operations 557 3 648,522 SG 6.052%39,252
Transmission Operations 560 3 78,462 SG 6.052%4,749
Transmission Operations 561 3 173,614 SG 6.052%10,508
Transmission Operations 562 3 22,322 SG 6.052%1,351
Transmission Operations 563 3 1,406 SG 6:052%85
Transmission Operations 566 3 6,402 SG 6.052%387
Transmission Operations 567 3 3,179 SG 6.052%192
Transmission Maintenance 568 3 20,693 SG 6.052%1,252
Transmission Maintenance 569 3 50,889 SG 6.052%3,080
Transmission Maintenance 570 3 124,605 SG 6.052%7,542
Transmission Maintenance 571 3 (48,611 )SG 6.052%(2,942)
Transmission Maintenance 572 3 280 SG 6.052%17
Transmission Maintenance 573 3 132 SG 6.052%8
Distribution Operations 580 3 305,275 SNPD 4.636%14,153
Distribution Operations 581 3 265,337 SNPD 4.636%12,301
Distribution Operations 582 3 38,291 10 Situs 2,449
Distribution Operations 582 3 390 SNPD 4.636%18
Distribution Operations 583 3 96,128 10 Situs 3,357
Distribution Operations 583 3 393 SNPD 4.636%18
Distribution Operations 585 3 4,188 SNPD 4.636%194
Distribution Operations 586 3 90,561 10 Situs 4,669
Distribution Operations 586 3 18,987 SNPD 4.636%880
Distribution Operations 587 3 211,881 10 Situs 6,700
Distribution Operations 588 3 (14,364)10 Situs (1,064)Distribution Operations 588 3 4,123 SNPD 4.636%191
Distribution Operations 589 3 2,537 10 Situs 15
Distribution Maintenance 590 3 13,366 10 Situs 856
Distribution Maintenance 590 3 91,590 SNPD 4.636%4,246
Distribution Maintenance 592 3 140,295 10 . Situs 9,987
Distribution Maintenance 592 3 27,477 SNPD 4.636%1,274
Distribution Maintenance 593 3 461,158 10 Situs 44,532
Distribution Maintenance 593 3 (11,337)SNPD 4.636%(526)
Distribution Maintenance 594 3 270,176 10 Situs 7,960
Distribution Maintenance 595 3 14,409 SNPD 4.636%668
Distribution Maintenance 596 3 37,440 10 Situs 2,504
3,161,007 181,520 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 2011. 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 recognizes increases that have occurred, or are projected to occur for labor charged to
operation and maintenance accounts through December 2011. See page 4.3.3 for more information on
how this adjustment was calculated.
Rocky Mountain Power
Idaho General Rate Case. December 2010
Wage and Employee Benefit Adjustment
Page 4.3.3
The unadjusted, annualized (12 months ended December 2010), and pro forma period (12 months ending
December 2011) labor expenses are summarized on page 4.3.4. The following is an explanation
of the procedures used to develop the pro forma labor expenses.
1. Actual December 2010 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 2010 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 2010 regular time, overtime, and premium pay expenses were then
escalated prospectively by labor group to December 2011 (see page 4.3.6). Union costs
were escalated using the contractual and planned rates found on page 4.3.7. Non-union costs
were escalated using the actual rates for 2011.
4. Annual Incentive Plan (AlP) compensation is included using a three year average
of the actual payment rate from 2008 through 2010, multiplied by pro forma wages.
AlP is the second step of a two-stage compensation philosophy that provides employees
with market average compensation with a portion at risk and based on achieving annual
goals. Union employees do not participate in the Company's Annual Incentive Plan;
instead, they receive annual increases to their wages that are reflected in the escalation
described above.
5. Pro forma December 2011 pension and employee benefit expenses are based on either December
2011 actuarial projections or are calculated by using actual data escalated to December 2011.
These expenses can be found on page 4.3.9.
6. Payroll tax calculations can be found on page 4.3.10.
Wage and Employee Beneft Adjustment Annualized Pro Fonna
Account Desription 12 Months Ended 12 Months Ended Adjustment 12 Months Ending Adjustment Ref.December 2010 December 2010 Decmber 2011
5001XX Re9ular Ordinary Time 414,975,436 415,875.743 900.308 422,488,925 6,613,182 4.3.5
5002XX Overtime 55,849,018 55.970,185 121.167 56,860.213 890.028 4.3.5
5003XX Premium Pay 6,931,756 6,946.795 15,039 7,057.261 110,467 4.3.5
Subtotal for Escalation 477,756,209 478.792,723 1,036,513 486,406 399 7,613,677 4.3.5&6
5005XX Unused Leave Accrual 2.660.645 2,666,417 5.772 2,708.818 42,401 4.3.8
500600 Temporary/Contract Labor --
500700 Severance/Redundancy (1)235,337 235,337 235.337
500850 Other Salary/Labor Costs 5,196.782 5,196.782 -5.196,782
50109X JO Cutbacks (1.288,739)(1,291.535 (2796)(1,312.073 (20,538)4.3.8
Subtotal Bare Labor 484,560,233 485.599,723 1,039,490 493235263 7,635540
500410 Annual Incentive Plan 26,606,117 26.606,117 29.962.000 3.355,883 4.3.8
Total Incentive 26.606,117 26606117 2996,000 3,355,883
500250 Overtime Meals 1.008,475 1.008,475 1.008,475
500400 Bonus and Awards 738.091 738,091 738.091
501325 Physical Exam 831 831 831
502300 Education Assistance 291.907 291.907 291.907
580899 Mining SalaryBenefit Credit (222.514)r222,514 1222.514
Total Other Labor 1,816,789 1,816,789 1,816789
Subtotal Labor and Incentive 512,983,139 514,022,629 1,039,490 525,014051 10,991,422
50110X Pensions (2)29,858,38 29.858,438 29.858,438 (0)4.3.9
501115 SERP Plan 3.528,224 3,528.224 (3.528,224)4.3.9
50115X Post Retirement Benefis - FAS 106 (2)15,236.246 15,236.246 15.713,233 476.987 4.3.9
501160 Post Employment Benefis - F AS 112 6.65,155 6,065,155 6,175.314 110159 4.3.9
Total Pensions 54,688,063 54,688063 51,746,985 2,941,078\4.3.9
501102 Pension Administration 188.389 188.389 -188.389 4.3.9
50112X Medical 55.743.330 55,743.330 58.978.141 3.234.811 4.3.9
501175 Dental 1.875.056 1.875,056 2.260.682 385,626 4.3.9
501200 Vision 250.755 250.755 -251.829 1.074 4.3.9
50122X Life 835,Q2 835,Q2 849,805 14,764 4.3.9
501250 401(k)19.44.818 19,46.818 19.905.510 458,692 4.3.9
501251 401(k) Administration 405.897 405.897 405.897 0 4.3.9
501252 401 (k) Fixed 16.397,234 16,397.234 -17,605.624 1,208,389 4.3.9
501275 Accidental Death & Disability 49.500 49.500 50,607 1.107 4.3.9
501300 Lon9-Term Disability 3.150.832 3.150,832 3.208,006 57,174 4.3.9
5016XX Worker's Compensation 1,789,597 1.789,597 -1.822.307 32,710 4.3.9
502900 Other Salary Overhead 2,165.973 2.165.973 2.165.973 -4.3.9
Total Benefts 102,298,424 102298424 107,692,770 5,394,34 4.3.9
Subtotal Pensions and Benefts 156,986,486 156,986,486 159439755 2,453,268 4.3.9
580500 Payroll Tax Expense 35.894,843 35.969,420 74.578 36.754.558 785.137 4.3.10
580700 Payroll Tax Expense-Unemployment 3,865.704 3.865.704 3.865.704 -
Total Payroll Taxes 39,760,547 39,835,124 74578 40,620,262 785,137
Total Labor 709,730,172 710,84,240 1,114067 725,074,068 14229,28 4.3.14
Non-Utility and Capitalized Labor 215,601.678 215.940,109 338,431 220.262.843 4.322.734 4.3.14
Total Utilit Labor 494,128,494 494,904,130 775,636 504,811,224 9,907,094 4.3.14
Rocky Mountain Power
Idaho General Rate Case. December 2010
Page 4.2.2
Notes:
(1) MEHC Transition severance amortization accrual effects are not included. Please refer to adjustment 4.9.
(2) Pension Curtailment Gain and Pension and Post Retirement Measurement Date Change efects are not included. Please also refer to pension related adjustments 4.6 and 4.16.
Page 4.3.4
Page 4.3.2
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Actual
December Actal December December 2011 Pro FonnaAccountDescription2010December 2010 2011 Projected Projected NET Adjustent
Net of Joint GROSS GROSS of Joint Venture
V..ntiir..
Rocky Mountain Power
Idaho General Rate Case - December 2010
Wage and Employee Benefit Adjustment
A CB D
50110X Pensions - FAS 87*29,858,438 30,723,502 30,723,502 29,858,438
501115 SERP Plan 3,528,224 3,528,224
50115X Post Retirement Benefits - FAS 106 15,236,246 15,715,024 16,207,000 15,713,233
501160 Post Employment Benefi - FAS 112 6,065,155 6,248,511 6,362,000 6,175,314
Subtotal 54,688,063 56,215,261 53,292,502 51,746,985
501102 Pension Administration 188,389 189,449 189,449 188,389
50112X Medical 55,743,330 57,443,526 60,777,000 58,978,141
501175 Dental 1,875,056 1,948,309 2,349,000 2,260,682
501200 Vision 250,755 260,883 262,000 251,829
50I22X Life 835,042 859,799 875,000 849,805
501250 401(k)19,446,818 20,073,526 20,547,000 19,905,510
501251 401(k) Administration 405,897 417,071 417,071 405,897
501252 40I(k) Fixed 16,397,234 17,041,157 18,297,000 17,605,624
501275 Accidental Death & Disability 49,500 49,884 51,000 50,607
501300 Long-Term Disabilty 3,150,832 3,246,098 3,305,000 3,208,006
5016XX Worker's Compensation 1,789,597 1,841,345 1,875,000 1,822,307
502900 Other Salary Overhead 2,165,973 2,167,367 2,167,367 2,165,973
Subtotal 102,298,424 105,538,412 111,111,887 107,692,770
Grand Total 156,986,486 161,753,673 164,404,389 159,439,755
Ref 4.3.4
'Adjusted to cash basis in Adjustment 4.16
D -A
4.3.4
(3,528,224) 4.3.4476,987 4.3.4
110,159 4.3.4
(2,941,078) 4.3.4
4.3.4
3,234,811 4.3.4
385,626 4.3.4
1,074 4.3.4
14,764 4.3.4
458,692 4.3.4
4.3.4
1,208,389 4.3.41,107 4.3.4
57,174 4.3.432,710 4.3.4
4.3.4
5,394,346 4.3.4
2,453,268 4.3.4
Ref 4.3.4
Page 4.3.9
B
Reference
1,039,490 4.3.4
4.3.4
1,039,490
1.45%
15,073
6.20%
64,448
92.33%
59,505
74,578 4.3.4
Rocky Mountain Power
Idaho General Rate Case. December 2010
Wage and Employee Benefit Adjustment
Payroll Tax Adjustment Calculation
FICA Calculated on December 2010 Annualized Labor
Annualized Wages Adjustment
Annualized Incentive Adjustment
Medicare Rate (no cap)
Social Security Rate
Percentage of Social Security Eligible Wages
Total FICA Tax
FICA Calculated on December 2011 Pro Forma Labor
Pro Forma Wages Adjustment
Pro Forma Incentive Adjustment
7,635,540
3,355,883
10,991,422
Medicare Rate (no cap)1.45%
159,376
Social Security Rate 6.20%
681,468
91.83%
625,762
Percentage of Social Security Eligible Wages
Total FICA Tax 785,137
Page 4.3.10
4.3.4
4.3.4
4.3.4
Page 4.3.11
Rocky Mountain Power
Idaho General Rate Case. December 2010
Wage and Employee Benefit Adjustment
Adjustment by FERC Account Revised Protocol & 2010 Protocol Factor
Actual Annualized Pro Fonna
Indicator Indicator 12 Months Ended Annualization 12 Months Ended Pro Fonna 12 Months Ending
2010 RP RP December 2010 % OfTotal Adjustment December 2010 Adjustment December 2011
500SG 500SG 15,35,524 2.17%24,229 15,459,754 309,477 15,769,230
501SE 501SE (250,205)-0.04%(393)(250,598)(5,017)(255,614)502SG 502SG 17,239,877 2.43%27,062 17,266,939 345,653 17,612,592
503SE 503SE 79,073 0.01%124 79,197 1,585 80,783
505SG 505SG 1,809,446 0.25%2,840 1,812,287 36,279 1,848,565
506SG 506SG 40,512,791 5.71%63,593 40,576,384 812,267 41,388,651
506SG 506SSGCH (3,378)0.00%(5)(3,383)(68)(3,451 )510SG 510SG 2,882,561 0.41%4,525 2,887,086 57,794 2,944,880
511SG 511SG 6,852,782 0.97%10,757 6,863,538 137,396 7,000,934
511SG 511SSGCH (915)0.00%(1)(916)(18)(934)512SG 512SG 26,010,898 3.66%40,829 26,051,728 521,509 26,573,237
512SG 512SSGCH (73,265)-0.01%(115)(73,380)(1,469)(74,849)513SG 513SG 11,027,523 1.55%17,310 11,044,833 221,098 11,265,931
514SG 514SG 2,610,826 0.37%4,098 2,614,925 52,346 2,667,271
514SG 514SSGCH (5,115)0.00%(8)(5,123)(103)(5,226)535SG-P 535SG-P 2,371,355 0.33%3,722 2,375,077 47,545 2,422,622
535SG-U 535SG-U 1,661,539 0.23%2,608 1,664,147 33,313 1,697,461
536SG-P 536SG-P 80,063 0.01%126 80,189 1,605 81,794
537SG-P 537SG-P 373,739 0.05%587 374,326 7,493 381,819
537SG-U 537SG-U 58,328 0.01%92 58,419 1,169 59,589
539SG-P 539SG-P 5,872,547 0.83%9,218 5,881,765 117,742 5,999,508
539SG-U 539SG-U 4,582,329 0.65%7,193 4,589,522 91,874 4,681,396
540SG-P 540SG-P (153,968)-0.02%(242)(154,209)(3,087)(157,296)540SG-U 540SG-U 8 0.00%0 8 0 8
541SG-P 541SG-P 241 0.00%0 241 5 246
542SG-P 542SG-P 424,955 0.06%667 425,622 8,520 434,142
542SG-U 542SG-U 78,243 0.01%123 78,366 1,569 79,935
543SG-P 543SG-P 326,593 0.05%513 327,106 6,548 333,654
543SG-U 543SG-U 461,125 0.06%724 461,849 9,245 471,094
544SG-P 544SG-P 732,316 0.10%1,150 733,465 14,683 748,148
544SG-U 544SG-U 268,113 0.04%421 268,534 5,376 273,910
545SG-P 545SG-P 707,237 0.10%1,110 708,347 14,180 722,527
545SG-U 545SG-U 289,682 0.04%455 290,137 5,08 295,945
546SG 546SG 1,713 0.00%3 1,716 34 1,750
548SG 548SG 4,74!ì,249 0.67%7,450 4,753,700 95,161 4,848,860
548SG 548SSGCT 602,492 0.08%946 603,438 12,080 615,518
549SG 549SG 2,592,869 0.37%4,070 2,596,939 51,986 2,648,925
552SG 552SG 123,671 0.02%194 123,865 2,480 126,344
552SG 552SSGCT 47,862 0.01%75 47,937 960 48,897
553SG 553SG 1,928,227 0.27%3,027 1,931,254 38,660 1,969,914
553SG 553SSGCT 143,736 0.02%226 143,961 2,882 146,843
554SG 554SG 41,167 0.01%65 41,231 825 42,057
554SG 554SSGCT 85,491 0.01%134 85,625 1,714 87,339
556SG 556SG 412,506 0.06%648 413,153 8,271 421,424
557SG 557SG 32,345,818 4.56%50,773 32,396,592 648,522 33,045,113
560SG 560SG 3,913,406 0.55%6,143 3,919,549 78,462 3,998,011
561SG 561SG 8,659,236 1.22%13,592 8,672,829 173,614 8,846,443
562SG 562SG 1,113,332 0.16%1,748 1,115,079 22,322 1,137,401
563SG 563SG 70,117 0.01%110 70,227 1,406 71,633
566SG 566SG 319,322 0.04%501 319,824 6,402 326,226
567SG 567SG 158,567 0.02%249 158,816 3,179 161,996
568SG 568SG 1,032,071 0.15%1,620 1,033,691 20,693 1,054,383
569SG 569SG 2.538,134 0.36%3,984 2,542,118 50,889 2,593,006
570SG 570SG 6,214,824 0.88%9,755 6,224,579 124,605 6,349,184
571SG 571SG (2,424,522)-0.34%(3,806)(2,428,328)(48,611 )(2,476,939)572SG 572SG 13,984 0.00%22 14,006 280 14,286
573SG 573SG 6,591 0.00%10 6,601 132 6,733
580SNPD 580SNPD 15,225,990 2.15%23,900 15,249,890 305,275 15,555,166
581SNPD 581SNPD 13,234,012 1.86%20,773 13,254,785 265,337 13,520,122
582CA 582CA 75,780 0.01%119 75,899 1,519 77,418
5821DU 5821DU 122,148 0.02%192 122,340 2,449 124,789
5820R 5820R 482,635 0.07%758 483,393 9,677 493,070
582SNPD 582SNPD 19,452 0.00%31 19,482 390 19,872
Page 4.3.12
Rocky Mountain Power
Idaho General Rate Case - December 2010
Wage and Employee Benefit Adjustment
Adjustment by FERC Account Revised Protocol & 2010 Protocol Factor
Actual Annualized Pro Forma
Indicator Indicator 12 Months Ended Annuallzation 12 Months Ended ProForma 12 Months Ending
2010 RP RP December 2010 % Of Total Adjustment December 2010 Adjustment December 2011
582UT 582UT 769,234 0.11%1.207 770,441 15,23 785,864
582WA 582WA 144,038 0.02%226 144,265 2,88 147,152
582WYP 582WYP 315,987 0.04%496 316,483 6,335 322,818
583CA 583CA 303,211 0.04%476 303,687 6,079 309,766
5831DU 5831DU 167,453 0.02%263 167,716 3,357 171,073
5830R 5830R 2,450,270 0.35%3,846 2,454.117 49,127 2.503.244
583SNPD 583SNPD 19,599 0.00%31 19,630 393 20,023
583UT 583UT 1,267,749 0.18%1,990 1,269,739 25,418 1,295,157
583WA 583WA 284.771 0.04%447 285,218 5.710 290,927
583WYP 583WYP 246,466 0.03%387 246,852 4.942 251.794
583WYU 583WYU 74,574 0.01%117 74,691 1,495 76,186
585SNPD 585SNPD 208,882 0.03%328 209,210 4,188 213.398
586CA 586CA 178.756 0.03%281 179,037 3,584 182,621
5861DU 5861DU 232.855 0.03%366 233,220 4,669 237,889
5860R 5860R 2,133,419 0.30%3,349 2,136.768 42.774 2.179,543
586SNPD 586SNPD 946.990 0.13%1,486 948,77 18,987 967,464
586UT 586UT 1,168,255 0.16%1,834 1,170,089 23,423 1,193.512
586WA 586WA 290,871 0.04%457 291.328 5,832 297.160
586WYP 586WYP 459,960 0.06%722 460,682 9,222 469.904
586WYU 586WYU 52,733 0.01%83 52,816 1.057 53.873
587CA 587CA 515,995 0.07%810 516,805 10.346 527.150
5871DU 5871DU 334,150 0.05%525 334,674 6,700 341.374
5870R 5870R 3.788,904 0.53%5,947 3,794,852 75.966 3,870,818
587UT 587UT 4.268,914 0.60%6.701 4,275.614 85,590 4,361,205
587WA 587WA 816.519 0.12%1,282 817,801 16,371 834,172
587WYP 587WYP 790,773 0.11%1.241 792,014 15,855 807,869
587WYU 587WYU 52.555 0.01%82 52,638 1,054 53,691
588CA 588CA (41,459)-0.01%(65)(41.525)(831)(42,356)
5881DU 5881DU (53.059)-0.01%(83)(53.143)(1,064)(54,206)5880R 5880R (459,157)-0.06%(721)(459,88)(9,206)(469.084)588SNPD 588SNPD 205,631 0.03%323 205,954 4,123 210.077
588UT 588UT 10,494 0.00%16 10,510 210 10,721
588WA 588WA (51,309)-0.01%(81)(51,389)(1,029)(52,418)
588WYP 588WYP (81,311)-0.01%(128)(81,438)(1,630)(83,069)588WYU 588WYU (40,631 )-0.01%(64)(40,695)(815)(41.510)589CA 589CA 10.587 0.00%17 10.603 212 10,815
5891DU 5891DU 747 0.00%1 749 15 764
5890R 5890R 82.574 0.01%130 82,704 1.656 84,359
589UT 589UT 14,725 0.00%23 14.748 295 15,03
589WA 589WA 9,111 0.00%14 9,125 183 9.308
589WYP 589WYP 8.923 0.00%14 8,937 179 9,116
589WYU 589WYU (129)0.00%(0)(129)(3)(132)590CA 590CA 15.519 0.00%24 15.544 311 15.855
5901DU 590lDU 42.707 0.01%67 42,774 856 43,630
5900R 5900R 231,701 0.03%364 232,064 4,646 236.710
590SNPD 590SNPD 4,568,144 0.64%7,171 4.575,314 91,590 4,666,904
590UT 590UT 287,801 0.04%452 288,253 5,770 294,023
590WA 590WA 9,867 0.00%15 9,883 198 10,081
590WYP 590WYP 79,070 0.01%124 79,194 1,585 80,780
592CA 592CA 410,155 0.06%644 410,799 8,223 419,022
5921DU 5921DU 498,117 0.07%782 498,899 9,987 508,886
5920R 5920R 2,310,317 0.33%3,627 2.313,944 46,321 2,360,265
592SNPD 592SNPD 1,370,439 0.19%2,151 1,372,590 27,477 1,400,067
592UT 592UT 2.619,811 0.37%4,112 2.623,924 52.526 2,676,50
592WA 592WA 458.313 0.06%719 459,032 9,189 468.221
592WYP 592WYP 700,122 0.10%1,099 701,221 14,037 715,258
592WYU 592WYU 532 0.00%1 533 11 543
593CA 593CA 3,479,385 0.49%5,462 3,484.847 69,760 3,554,607
5931DU 5931DU 2,221,096 0.31%3,486 2,224,582 44,532 2,269,114
5930R 5930R 7,309,925 1.03%11,474 7,321,399 146,561 7,467,960
593SNPD 593SNPD (565,452)-0.08%(888)(566,340)(11,337)(577;677)5.93UT 593UT 7,790,611 1.10%12.229 7,802.840 156.199 7,959,039
593WA 593WA 426,491 0.06%669 427,161 8,551 435,712
Page 4.3.13
Rocky Mountain Power
Idaho General Rate Case. December 2010
Wage and Employee Benefit Adjustment
Adjustment by FERC Account Revised Protocol & 2010 Protocol Factor
Actual Annualized Pro Fonna
Indicator Indicator 12 Months Ended Annuallztion 12 Months Ended Pro Fonna 12 Months Ending
2010 RP RP December 2010 % Of Total Adjustment December 2010 Adjustment December 2011
593WYP 593WYP 1,363,427 0.19%2,140 1,365,567 27,336 1,392,903
593WYU 593WYU 409,907 0.06%643 410,551 8,218 418,769
594CA 594CA 358,863 0.05%563 359,427 7,195 366,622
5941DU 5941DU 397,039 0.06%623 397,662 7,960 405,623
5940R 5940R 3,718,513 0.52%5,837 3,724,350 74,555 3,798,905
594UT 594UT 7,258,787 1.02%11,394 7,270,181 145,536 7,415,717
594WA 594WA 728,084 0.10%1,143 729,226 14,598 743,824
594WYP 594WYP 900,346 0.13%1,413 901,759 18,052 919,811
594WYU 594WYU 113,751 0.02%179 113,929 2,281 116,210
5955NPD 5955NPD 718,683 0.10%1,128 719,811 14,409 734,221
596CA 596CA 108,144 0.02%170 108,314 2,168 110,482
5961DU 5961DU 124,883 0.02%196 125,079 2,504 127,583
5960R 5960R 836,381 0.12%1,313 837,694 16.769 854,463
596UT 596UT 337,882 0.05%530 338,12 6.774 345,186
596WA 596WA 135,063 0.02%212 135,275 2.708 137.983
596WYP 596WYP 287,075 0.04%451 287,525 5,756 293.281
596WYU 596WYU 37.949 0.01%60 38,008 761 38.769
597CA 597CA 49.796 0.01%78 49,874 998 50,872
5971DU 597JDU 256.319 0.04%402 256,722 5,139 261.861
5970R 5970R 888.167 0.13%1.394 889,561 17,807 907,368
5975NPD 5975NPD 735.993 0.10%1,155 737,149 14,756 751,905
597UT 597UT 1,782,924 0.25%2,799 1.785.723 35,747 1.821,470
597WA 597WA 371.784 0.05%584 372.367 7,454 379.821
597WYP 597WYP 468,262 0.07%735 468,997 9.388 478.385
597WYU 597WYU 82,138 0.01%129 82,267 1,647 83.913
598CA 598CA 14,940 0.00%23 14.964 300 15.263
5980R 5980R 65.306 0.01%103 6M08 1,309 66,717
5985NPD 5985NPD 1,073.610 0.15%1,685 1,075,296 21,525 1.096,821
598UT 598UT 6.172 0;00%10 6,182 124 6.305
598WA 598WA 30.041 O.Oook 47 30,088 602 30.691
598WYU 598WYU 167 0.00%0 168 3 171
901CN 901CN 1,973.931 0.28%3,098 1.977030 39,577 2.016,606
9010R 9010R 1,164 0.00%2 1.166 23 1,189
901WYP 901WYP 70 0.00%0 70 1 71
902CA 902CA 743,717 0.10%1.167 744.885 14,911 759,796
902CN 902CN 1,481,155 0.21%2.325 1,483,480 29.697 1,513.176
9021DU 9021DU 1.373,570 0.19%2.156 1,375,726 27.540 1,403.266
9020R 9020R 8.002.932 1.13%12.562 8.015,494 160,56 8,175.950
902UT 902UT 3,831.813 0.54%6,015 3,837,828 76.826 3,914.654
902WA 902WA 1,937.914 0.27%3.042 1,940,956 38.854 1,979,810
902WYP 902WYP 1,346,458 0.19%2.114 1,348,572 26,996 1,375,568
902WYU 902WYU 223,212 0.03%350 223,562 4,475 228,37
903CA 903CA 164.263 0.02%258 164.521 3,293 167,815
903CN 903CN 32,616.032 4.60%51,198 32,667.230 653,939 33.321.169
9031DU 903JDU 289,643 0.04%455 290.098 5,807 295.905
9030R 9030R 1,481,811 0.21%2,326 1,484.137 29,710 1,513.847
903UT .903UT 2,575,463 0.36%4.043 2.579.506 51.637 2,631.143
903WA 903WA 450,392 0.06%707 451,099 9,030 460,129
903WYP 903WYP 256,617 0.04%403 257,020 5.145 262,165
903WYU 903WYU 71,281 0.01%112 71,393 1,429 72,822
905CN 905CN 111,700 0.02%175 111,875 2,240 114,115
907CN 907CN 242,742 0.03%381 243,123 4,867 247,990
908CA 908CA 1.180 0.00%2 1,182 24 1,205
908CN 908CN 2,527.617 0.36%3,968 2,531,584 50,678 2,582,262
9081DU 9081DU 432.706 0.06%679 433,385 8,676 442.061
9080R 9080R 1,200.240 0.17%1,884 1,202.124 24,064 1,226,189
9080THER 9080THER 37.716 0.01%59 37.775 756 38,531
908UT 908UT 2,107.082 0.30%3,307 2,110.389 42.246 2.152,636
908WYP 908WYP 846,466 0.12%1,329 847.794 16.971 864,766
909CA 909CA 87 0.00%0 87 2 89
909CN 909CN 463,253 0.07%727 463,980 9.288 473,268
910CN 910CN 1,350 0.00%2 1.352 27 1,379
92050 92050 78,477,845 11.06%123,187 78.601,032 1,573,452 80.174,4849215092150(251,351)-0.04%(395)(251,746)(5.040)(256,785)
921WA 921WA 22 0.00%0 22 0 23922509225028,590.607 4.03%44.879 28.635,486 573.231 29,208.717
Page 4.3.14
Rocky Mountain Power
Idaho General Rate Case. December 2010
Wage and Employee Benefit Adjustment
Adjustment by FERC Account Revised Protocol & 2010 Protocol Factor
Actual Annualized Pro Fonna
Indicator Indicator 12 Months Ended Annualizatlon 12 Months Ended Pro Forma 12 Months Ending
2010 RP RP December 2010 % Of Total Adjustment December 2010 Adjustment December 2011
928CA 928CA 204.104 0.03%320 204,424 4,092 208,516
9281DU 9281DU 604,415 0.09%949 605,364 12,118 617,482
9280R 9280R 440,935 0.06%692 441,627 8,841 450,467
92850 92850 190,393 0.03%299 190,692 3,817 194,509
928UT 928UT 666,682 0.09%1,046 667,728 13,367 681.095
928WA 928WA 416,207 0.06%653 416.860 8,345 425.205
928WYP 928WYP 510.623 0.07%802 511,424 10,238 521.662
92950 92950 (935.554)-0.13%(1,469)(937.022)(18.758)(955,780)9350R 9350R 17.309 0.00%27 17,336 347 17,683
93550 93550 2,466,115 0.35%3.871 2,469,986 49,445 2,519,431
935WA 935WA 2,130 0.00%3 2,133 43 2.176
Utilty Labor 494.128.494 69.62%775,636 494,904,130 9,907,094 504,811 ,224 Ref. Page 4.3.4
CapitaVNon Utilty 215,601,678 30.38%338,431 215,940,109 4.322,734 220,262,843 Ref. Page 4.3.4
Total Labor 709,730,172 100.00%1,114,067 710,844,240 14,229,828 725,074,068 Ref. Page 4.3.4
Rocky Mountain Power
Idaho General Rate Case. December 2010
Class 1 DSM Program Costs
PAGE 4.4
TOTAL IDAHO
ACCOUNT~COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Expense:
Other Purchased Power 557 1 11,632,374 SG 6.052%704,049 4.4.1
Other Purchased Power 557 3 (2,460,474)SG 6.052%(148,920) 4.4.1
9,171,900 555,129
Description of Adjustment:
In Case No. PAC-E-10-07, Order No. 32196, the Idaho Commission found that the costs of the Irrigation Load Control
Program should be treated as a system cost and no longer flowed through the Company's tariff rider. The incentive
payment is allocated as a system cost in the Company's unadjusted results. This adjustment allocates the administrative
costs of the Idaho program system-wide and brings into results the costs of Class 1 DSM programs in other states. The
jurisdictional loads used for allocation factors do not reflect peak reductions from these programs, consistent with this
adjustment.
Rocky Mountain Power
Idaho General Rate Case. December 2010
Class 105M Program Costs
Page 4.4.1
(A)(B)(B). (A) = C (D)(B)*(D)
Total
Idaho
Actual Costs Expeted Costs Type 3 Allocation Allocation Allocated
Class 1 DSM Program 12 ME Dec 2010 12 ME Dec 2011*Adjustment Factor %Costs
Idaho Irrigation Load Control
Incentive Payment 8,100,681 6,623,600 (1,477,081 )SG 6.0525%400,893
Other Prooram Costs 4,283,393 3,300,000 (983,393)SG 6.0525%199,732
Total Program Costs $12,384,074 $9,923,600 $(2,460,474)$600,625
Utah Irrigation Load Control
Incentive Payment 1,338,679 1,338,679 -SG 6.0525%81,023
Other Prooram Costs 1,174,032 1,174,032 -SG 6.0525%71,058
Total Program Costs $2,512,712 $2,512,712 $-$152,082
Utah Cool Keeper Program
Incentive Payment 1,939,385 1,939,385 -SG 6.0525%117,381
Other Prooram Costs 2,896,884 2,896,884 -SG 6.0525%175,334
Total Program Costs $4,836,269 $4,836,269 $-$292,715
Total Class 1 DSM Program Costs $19,733,055 $17,272,581 $1,045,22
Adjustment Calculation:
Amount Factor Reference
'Total Class 1 DSM Costs - 12 ME Dec 2010 $19,733,055 SG
Costs Included in Unadjusted Results of Operations 8,100,681 SG
Type 1 Adjustment $11,632,374 SG To Page 4.4
Total Class 1 DSM Costs - 12 ME Dec 2010 19,733,055 SG
Total Class 1 DSM Costs - 12 ME Dec 2011 17,272,581 SG
Type 3 Adjustment $(2,460,474)SG To Page 4.4
'The calendar year 2011 program costs reflect the reduction in the Idaho Irrigation Load Control Program costs as stipulated
in Case No. PAC-E-11-06.
Rocky Mountain Power PAGE 4.5
Idaho General Rate Case - December 2010
Remove Non-Recurring Entries
TOTAL IDAHOACCOUNT~COMPANY FACTOR FACTOR %ALLOCATED REF#Adjustment to Expense:
1) TransAlta Sale Liability 923 1 1,281,524 SO 5.794%74,255 4.5.1
2) Settlement Fees
506 1 214,779 SG 6.052%12,999 4.5.1
535 1 69,125 SG-P 6.052%4,184 4.5.1
560 1 (600)SG 6.052%(36)4.5.1
580 1 (1,900)SNPD 4.636%(88)4.5.1
Total Settlement Fees 281,404 17,059
3) Set up California Regulatory Asset 924 1,230,000 SO 5.794%71,269 4.5.1
4) Record Local 127 Pension Curtailment 920 1 42,847 SO 5.794%2,483 4.5.1
5) Jim Bridger Turbine Upgrade 557 1 (3,033,000)SG 6.052%(183,572)4.5.1
6) Legal Fees 921 (1,116)SO 5.794%(65)4.5.1
923 (222,313)SO 5.794%(12,881)4.5.1
Total Legal Fees (223,429)(12,946)
Total Non-Recurring Entries (420,654)(31,453)
Adjustment to Tax:
1) Year End AD IT Balance 190 (3,563,273)SO 5.794%(206,465)
3) Sch M - CA January 2010 Storm Costs SCHMDT 1 (1,230,000)OTHER 0.000%
DITE - CA January 2010 Storm Costs 41010 1 (466,797)OTHER 0.000%
Year End ADIT Balance 283 1 466,797 OTHER 0.000%
Description of Adjustment:
A variety of accounting entries were made to expense accounts during the twelve months ended December 2010 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 page 4.5.1.
Page 4.5.1
Rocky Mountain Power
Idaho General Rate Case - December 2010
Remove Non-Recurring Entries
INo. IPostg Date I Text FERC Acctl Amount as Booked I Reference I
TransAlta Sale Liabilty: Per the Centralia Mine sale
agreement with TransAlta in May 2000, ten years from the date
1 6/30/2010 of the sale, PacifiCorp can release the liabilty it had set aside 923000 (1,281,524)Ref 4.5for future potential environmental remediation. In June 2010 an
entry was made to reduce the regulatory liabilty with an offsettng
credit to FERC Account 923.
Settlement Fees: A variety of accounting entries were made to
expense accounts during the twelve months ended December
2 Various 2010 for settlement fees involving possible compliance Various (281,404)Ref 4.5
violations. These transactions are removed from results of
operations to normalize the test period results.
California CEMA Regulatory Asset Set-Up: This entry credited
3 10/31/2010 expense to set up a regulatory asset in California. It needs to be 9240000 (1,230,000)Ref 4.5
removedJrom results.
Pension Curtilment In FERC and OTHER Jurisdiction: In
January, 2010 entries were made to record the pension
4 1/31/2010 curtailment of Local 127 in all jurisdictions.The FERC and 920000 (42,847)Ref 4.5
OTHER jurisdiction portion was recorded on an SO factor and
needs to be removed from results.
Jim Bridger Unit 2, 3 and 4 turbine upgrades:The contract
with the vendor is being renegotiated due to certain portions of
the Jim Bridger turbine upgrade projects being delayed, deferred
5 10/26/2010 andlor potentially cancelled due to project reconfiguration, scope 5570000 3,033,000 Ref 4.5
and timing changes in the projects which result from transmission
constraints and other issues. This should not impact results of
operations.
Legal Fees: This adjustment removes legal fees for Willkie Farr
6 Various and Gallagher LLP as well as Herbert Smith LLP for legal matters 921,923 223,429 Ref 4.5
that are non-recurring in nature.
Total 420,654 Ref 4.5
Settlement Fee Summary by Account/Factor:
Account
506
535
560
580
Factor
SG
SG-P
SG
SNPD
Amount
(214,779)
(69,125)
600
1,900
(281,404)
Rocky Mountain Power
Idaho General Rate Case. December 2010
Pension Curtailment
PAGE 4.6
TOTAL IDAHO
ACCOUNT Iï COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Expense:
Remove pension curtailment entry
from unadjusted results 920 1 116,464 ID Situs 116,464 4.6.1
Description of Adjustment:
Idaho is on a cash basis for pension expense. The entry to recognize the actuarial effects of the UMWA 127 pension
curtailment included in unadjusted results needs to be removed.
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Rocky Mountain Power PAGE 4.7
Idaho General Rate Case. December 2010
DSM Revenue and Expense Removal
TOTAL IDAHO
ACCOUNT~COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Revenue:
Remove DSMRevenue 456 1 (865,247)CA Situs
456 1 (5,939,833)ID Situs (5,939,833)
456 1 (18,762,568)OR Situs
456 1 (62,981,154)UT Situs
456 1 (8,855,002)WA Situs
456 1 (2,691,337)WY Situs
(100,095,141 )(5,939,833)4.7.1
Adjustment to Expense:
Remove DSM Amortization Expense 908 1 (865,247)CA Situs
908 1 (5,939,833)ID Situs (5,939,833)
908 1 (18,762,568)OR Situs
908 1 (73,831,154 )UT Situs
908 1 (8,855,002)WA Situs
908 1 (2,691,337)WY Situs
(110,945,141)(5,939,833)4.7.1
Adjustment to Tax:
Schedule M Adjustment SCHMAT (28,318,709)SO 5.794%(1,640,855)Schedule M Adjustment SCHMAT (1,516,395)OR Situs
Deferred Tax Expense 41110 1 10,747,233 SO 5.794%622,721
Deferred Tax Expense 41110 1 575,487 OR Situs
Year End ADIT Balance 283 1 2,432,945 SO 5.794%140,971
Year End ADIT Balance 190 1 (887,670)OR Situs
Description of Adjustment:
This adjustment removes DSM-related revenues and expenses from regulated results.
Rocky Mountain Power
Idaho General Rate Case. December 2010
DSM Revenue & Expense Removal
SAP Unadjusted January 2010 - December 2010
Page 4.7.1
4562200 DSM Revenue - CA SSC
DSM Rev - ID SSC
DSM Revenue - OR ECC
DSM Rev - UT SSC
DSM Revenue - WA SSC
DSM Rev-WY
CA
IDU
OR
UT
WA
WY
865,247
5,939,833
18,762,568
62,981,154
8,855,002
2,691,337
100,095,141 Ref 4.7
Remove DSM Amortization Expense:
,FERC .AuCQUntDe$çrlptioi .: ,;' ê ''.;.. , ..t;;' Af~ç~ltjQffi'~;;)¡,;; .';. ;.;'tJrieäjüstèd Actuafs ..
9085100 DSM CA Amortization
DSMID Amortization
DSM Oregon Amort Exp
DSM UT Amortization
DSM WA Amortization
DSMWYAmort
CA
IDU
OR
UT
WA
WY
865,247
5,939,833
18,762,568
73,831,154
8,855,002
2,691,337
110,945,141 Ref 4.7
Rocky Mountain Power
Idaho General Rate Case. December 2010
Wyoming Inverted Rates Advertising
PAGE 4.8
TOTAL IDAHOACCOUNT~COMPANY FACTOR FACTOR %ALLOCATED REF#Adjustment to Expense:
Remove inverted rates reg asset set up
from base period 909 1 52,198 CN 3.869%2,019 4.8.1
Description of Adjustment:
This adjustment removes the credit booked to set up a regulatory asset to defer advertising costs that were ordered by the
Wyoming P.S.C. and are being recovered from Wyoming customers.
Rocky Mountain Power
Idaho General Rate Case. December 2010
Wyoming Inverted Rates Advertising
Description
Inverted rates advertising in actual data
Postg Date FERC Acct
30-Jun-10 9090000
Locatn
1
Factor
CN
Total Reference
(52,198) Ref4.8
Page 4.8.1
Rocky Mountain Power
Idaho General Rate Case. December 2010
MEHC Transition Cost Amortization
PAGE 4.9
TOTAL IDAHO
ACCOUNT~COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to E:ipense:
Remove amortization expense
from base period 920 3 (610,194)ID Situs (610,194)4.9.1
Remove expense credited when
Oregon reg asset was set up 920 1 4,605,029 SO 5.794%266,827 4.9.2
Remove expense credited when
California reg asset was set up 920 222,772 SO 5.794%12,908 4.9.2
Adjustment to Tax:
Deferred Tax Balance
Sch M Adjustment
Deferred Tax Expense
190
SCHMAT 1
41110 1
9,805
(610,194)
231,575
SO 5.794%568
ID
ID
Situs
Situs
(610,194)
231,575
Description of Adjustment:
The Company eliminated many positions as a result of the MEHC transaction. The resulting savings were made possible by
the payment of change-in-control severance. . Severance costs were amortized to 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 ended December
31,2010 it is being removed from unadjusted results. This adjustment also removes from unadjusted results the expense
credited when the Oregon and California transition plan regulatory assets were set up .
Rocky Mountain Power
Idaho General Rate Case. December 2010
MEHC Transition Amortization Schedule
Account 187212
Pro Forma Amount
Base Period Amount (below)
Adjustment
2008 January
February
March
April
May
June
July
August
September
October
November
December
2009 January
February
March
April
May
June
July
August
September
October
November
December
2010 January
February
March
April
May
June
July
August
September
October
November
December
Beginning Balance
1.830,583
1,779,734
1,728,884
1,678,035
1,627,185
1,576,336
1,525,486
1,474,637
1,423,787
1,372,938
1,322,088
1,271.238
1,220,389
1,169,539
1.118,690
1,067,840
1,016,991
966;141
915,292
864,442
813,593
762,743
711,894
661,044
610,194
559,345
508,495
457,646
406,796
355,947
305,097
254,248
203,398
152,549
101,699
50,850
Total Amortization CY 2010 =
Page 4.9.1
Amortization
610,194
(610,194)
Ref 4.9
Amortization
(50,850)
(50,850)
(50,850)
(50,850)
(50,850)
(50,850)
(50,850)
(50.850)
(50,850)
(50,850)
(50,850)
(50,850)
(50,850)
(50,850)
(50,850)
(50,850)
(50,850)
(50,850)
(50.850)
(50,850)
. (50,850)
(50,850)
(50,850)
(50,850)
(50,850)
(50,850)
(50,850)
(50,850)
(50,850)
(50,850)
(50,850)
(50,850)
(50,850)
(50,850)
(50,850)
(50,850)
(610,194)
Ending Balance
1,779,734
1,728,884
1,678,035
1,627,185
1,576,336
1,525,486
1,474,637
1,423,787
1,372,938
1,322,088
1,271,238
1,220,389
1,169,539
1,118,690
1,067,840
1,016,991
966,141
915,292
864,442
813,593
762,743
711,894
661,044
610,194
559,345
508,495
457,646
406,796
355,947
305,097
254,248
203,398
152,549
101,699
50,850
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Rocky Mountain Power
Idaho General Rate Case. December 2010
MEHC Cross Charge
PAGE 4.10
Adjustment to Expense:
Remove SERP portion of MEHC
cross charge booked above the line
TOTAL
ACCOUNT ~ COMPANY
IDAHO
FACTOR FACTOR % ALLOCATED REF#
930 1 (200,062) SO 5.794%(11,592)
Adjustment Detail
MEHC Cross Charge booked
Above the Line -12 ME December 2010
Remove SERP charges included above
Adjusted MEHC Cross Charge
7,473,148
(200,062)
7,273,086 4.10.1
Description of Adjustment:
In merger Commitment 128, the Company committed to hold customers harmless for costs that were previously assigned to
affliates relating to management fees and set the total company amount at $1,500,000. This commitment was offsettable to
the extent the Company demonstrated to the Commission's satisfaction that corporate allocations from MEHC included in
rates was less than $7.3 million. This commitment expired on December 31,2010. This adjustment removes SERP from the
cross charge consistent with the Commission's order in Case No. PAC-E-10-07.
Page 4.10.1
Rocky Mountain Power
Idaho General Rate Case. December 2010
MEHC Cross Charge
12 Months Ended December 31,2010
Department
CEO
Communication
Environmental
Finance & Accounting
General Services
Human Resources
Information Technology
Legal
Purchasing
Regulation
Tax
Transmission
Amount
1,564,703
277,174
324,141
1,675,658
877,458
623,645
939,114
290,275
269,430
46,117
384,723
648
7,273,086
Ref 4.10
Rocky Mountain Power PAGE 4.11Idaho General Rate Case -December 2010
Insurance Expense
TOTAL IDAHO
ACCOUNT~COMPANY FACTOR FACTOR %ALLOCATED REF#Adjustment to Expense:
Remove Liabilty Insurance Expense from Base Period:
Inj. & Damg. Expense (Net of Receivable)925 3 (2,769,258)SO 5.794%(160,458) 4.11.1Captive Insurance Premiums 925 3 (1,584,944)SO 5.794%(91,836) 4.11.2
(4,354,202)(252,293)Include Liabilty Insurance Expense in Pro Forma Period:
Injuries and Damages Expense
3 Year Average (Net of Receivable)925 3 2,602,344 SO 5.794%150,786 4.11.1
January 2011 to March 21, 2011
Captive Liabilty Insurance Premiums 925 3 347,385 SO 5.794%20,128 4.11.2
March 22, 2011 to December 2011
Self-insured Liability Expense 925 3 1,008,694 SO 5.794%58,446 4.11.2
Total Liability Insurance Expense 3,958,423 229,361
Remove Property Insurance Expense from Base Period:
Captive Insurance Premiums 924 3 (5,560,493)SO 5.794%4.11.3
Self-Insured Property Damage Expense 924 3 (8,644,574)SO 5.794%(500,888) 4.11.3Total Propert Insurance Expense (14,205,067)(500,888)
Include Propert Insurance Expense in Pro Forma Period:
January 2011 to March 21, 2011
Captive Propert Insurance Premiums 924 3 1,218,738 SO 5.794%70,617 4.11.3
Self-insured Propert Damage Expense 924 3 1,894,701 SO 5.794%109,784 4.11.3
March 22, 2011 to December 2011
Propert Insurance - Transmission 924 3 76,330 SG 6.052%4,620 4.11.3
Property Insurance - Idaho Distribution 924 3 ID Situs 4.11.3
Propert Insurance - Non- T&D 924 3 1,388,542 SG 6.052%84,041 4.11.3
Total Propert Insurance Expense 4,578,311 269,061
Transfer to System Transmission Maintenance 571 3 632,794 SG 6.052%38,300 4.11.4
Transfer to Idaho Distribution Maintenance 593 3 459,020 ID Situs 459,020 4.11.4
Transfer to System Non- T&D Maintenance 553 3 1,069,608 SG 6.052%64,738 4.11.4
2,161,422 562,058
Adjustment to Tax:
Schedule M Adjustment SCHMAP 3 (5,402,878)SO 5.794%(313,056)Schedule M Adjustment SCHMDP 3 (13,237,110)SO 5.794%(766,990)
Schedule M Adjustment SCHMDT 3 (109,564)SO 5.794%(6,348)Deferred Tax Expense 41010 3 (41,581)SO 5.794%(2,409)
This adjustment normalizes injury and damages expense to reflect a three year average of gross expense net of insurance
receivables. This adjustment also reflects the end of coverage by the captive insurance company on March 21 ,2011. Prior to
that date, the level of captive insurance expense allowed is limited to $7.4 millon as agreed to by the Company as part of the
MEHC transaction in commitment 129. Thereafter, the Company wil replace the captive insurance with self-insurance
accruals for liability and propert insurance. Per event deductibles for propert damage wil be raised from $25,000 to
$250,000 for distribution property and to $1,000,000 for system transmission and non- T&D property. Due to the change in per-
event deductibles, costs previously covered by insurance wil be covered by additional O&M.
Page 4.11.1
Rocky Mountain Power
Idaho General Rate Case - December 2010
Insurance Expense
Adjust Liabilty Reserve Accrual to Three Year Average
Construction (280313)
CY 2008 CY2009 CY 2010 Totals
Accrual Accrual Accrual Accrual
8,157,958 3,961,337 4,803,416 16,922,711
292,375 406,645 25,944 724,963
50,000 125,000 0 175,000
8,500,333 4,492,982 4,829,359 17,822,674
(5,340,408)(2,615,133)(2,060,101)(10,015,642)
3,159,925 1,877,849 2,769,258 7,807,032
Ref4.11
2,602,344
Ref4.11
Excluding Auto (280311)
Auto (280312)
* 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.
Rocky Mountain Power
Idaho General Rate Case. December 2010
Insurance Expense
Liabilty Insurance Expense
Third Party Liabilty Insurance Expense. Captive portion
A portion of third part liabilty will be covered by captive insurance through March 21, 2011,
replaced by self-insurance thereafter.
1. Captive Liability Insurance
Actual captive liability premium CY 2010
Portion CY 2011 covered by captive insurance
Captive liabilty insurance expense CY 2011
2. Self Insured Liability Insurance. Based on a 36 Month Average
Year
2008
2009
2010
3 year total
Annual average claim accruals
Portion of year self-insured
Self Insured expense in CY 2011
Total CY 2011
Total
1,584,944 Ref4.11
21.92%
Amount
815,407
2,050,000
1,010,101
3,875,509
1,291,836
78.08%
Page 4.11.2
347,385 Ref 4.11
1,008,694 Ref 4.11
1,356,079
Page 4.11.3
Rocky Mountain Power
Idaho General Rate Case. December 2010
Insurance Expense
Propert Damage Not Covered by Commercial Insurance
Commercial insurance covers a portion of non- T&D property damage above a deductible. Up through March 21, 2011, captive insurance
covered a portion and the rest is self-insured. After March 21, 2011, all propert damage not covered by commercial insurance will be
self-insured.
Actual captive property insurance premium CY 2010
Actual self-insured property provision CY 2010
Total Company
Total
5,560,493
8,64,574
14,205,067
Ref 4.11
Ref 4.11
Through March 21, 2011 (21.92%)
Captive premium
Self-insurance expense
1,218,738
1,894,701
3,113,439
Ref 4.11
Ref 4.11
Following the termination of the captive insurance coverage on March 21, 2011, the insurance accrual wil be based on the average of damages
occurring in the last 3.75 years, after applying a deductible.
Deductible
Actual Losses (after deductible)
System Transmission Idaho Distribution System Non-T&D
Losses Losses Losses
$1,000,000 $250,000 $1,000,000
255,868
110,715 5,410,474
847,444
410,738
366,583 6,668,656
$97,755 $0 $1,778,308
76,330 1,388,542
Ref 4.11 Ref 4.11 Ref 4.11
Apr 2007 - Mar 2008
Apr 2008 - Mar 2009
Apr 2009 - Mar 2010
Apr 2010 - Dec 2010
Total
Annual Average
Following March 21, 2011 (78.08%)
Page 4.11.4
Rocky Mountain Power
Idaho General Rate Case - December 2010
Insurance Expense
Transfer to O&M
Annual Losses Above Deductible
System
Transmission Idaho Distribution System Non- T &D
Losses Losses Losses
Previous Plan Structure:
Apr 2007 - Mar 2008 1,453,809 439,825 1,038,168
Apr 2008 - Mar 2009 450,957 356,675 6,784,172
Apr 2009 - Mar 2010 1,105,725 568,022 2,535,080
Apr 2010 - Dec 2010 395,171 839,981 1,448,168
Total 3,405,662 2,204,504 11,805,588
Annual Average $908,176 $587,868 $3,148,157
Per Event Deductible $25,000 $25,000 $25,000
System
Transmission Idaho Distribution System Non-T&D
Losses Losses Losses
New Plan Structure:
Apr 2007 - Mar 2008 255,868
Apr 2008 - Mar 2009 110,715 5,410,474
Apr 2009 - Mar 2010 847,444
Apr 2010 - Dec 2010 410,738
Total 366,583 6,668,656
Annual Average $97,755 $$1,778,308
Difference $810,421 $587,868 $1,369,848
Following March 21, 2011 $632,794 $459,020 $1,069,608
Ref 4.11 Ref 4.11 Ref 4.11
Per Event Deductible (Covered by O&M)$1,000,000 $250,000 $1,000,000
..
Rocky Mountain Power
Idaho General Rate Case. December 2010
Generation Overhaul Expense
PAGE 4.12
TOTAL IDAHO
ACCOUNT~COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Expense:
Generation Overhaul Expense - Steam 510 (6,485,476)SG 6.052%(392,533) 4.12.1
Generation Overhaul Expense - Other 553 4,150,487 SG 6.052%251,208 4.12.1
(2,334,990)(141,325)
Description of Adjustment:
This adjustment normalizes generation overhaul expenses in calendar year 2010 using a four-year average methodology.
For new generating units, which include Lake Side and Chehalis, the four-year average is comprised of the overhaul
expense for the first four full years these plants are operationaL. The actual overhaul costs for calendar year 2010 are
subtracted from the four-year average which results in this adjustment.
Page 4.12.1
Rocky Mountain Power
Idaho General Rate Case. December 2010
Generation Overhaul Expense
FUNCTION: OTHER
Period
CY 2007
CY 2008
CY 2009
CY 2010
4 Year Average
Overhaul Expense
4,383,000
2,941,000
7,672,775
2,303,074
4,324,962
New Plant Overhaul Expense
Lake Side Plant - 4 Year Average
Chehalis Plant - 4 Year Average
Total New Plant Overhaul Expense
1,753,435
726,012
2,479,446 Ref 4.12.2
Total 4 Year Average - Other 6,804,408
CY 2010 Overhaul Expense - Other
Total 4 Year Average - Other
Adjustment
2,653,922 Ref 4.12.2
6,804,408
4;150,487 Ref 4.12
FUNCTION: STEAM
Period
CY 2007
CY 2008
CY 2009
CY 2010
4 Year Average
Overhaul Expense
28,560,541
20,030,017
25,392,474
33,308,312
26,822,836
Total 4 Year Average - Steam 26,822,836
CY 2010 Overhaul Expense - Steam
Total 4 Year Average - Steam
Adjustment
33,308,312 Ref 4.12.2
26,822,836
(6,485,476) Ref 4.12
Page 4.12.2
Rocky Mountain Power
Idaho General Rate Case. December 2010
Generation Overhaul Expense
Existing Units
Yr. Ending Yr. Ending Yr. Ending Yr. Ending
Dec 2007 Dec 2008 Dec 2009 Dec 2010
Steam
Blundell 1.337.219 83,913 418,189 208,000
BlundellGC 1.340,694
Carbon 24.146 1.730.915 1.676,722 702,361
DaveJohnston 3,279,981 5,824,658 6,78,000 8,540,000
Gadsby 2.290,000 2,076,000
Hunter 8,171.859 (950,900)8,696,951
Huntington (39.000)769,000 7,244,000
JimBridger 6,815.000 4,427,000 5.214,000 4,291,000
Naughton 4,864,643 1,341,431 6,895,563
Wyodak 60,000
Cholla 6,460.000 542.000
Colstrip 1.300,000 1.156.000
Craig 1.376.000 743,000 948,000
Hayden 90.000 370,000 495,000
Total - Steam 28,560.541 20.030.017 25.392,474 33,308,312 Ref 4.12.1
Other
Hermiston 2,860,000 1,725,000 2,023.000 1,374.000
LittleMt 529,000 13,000
Camas 506.000
Currant Creek 1.523,000 1,216.000 5,120.775 410.074
Total - Other 4.383,000 2.941.000 7,672.775 2,303,074 Below
Grand Total 32.943.541 22.971.017 33,065,249 35,611,386
New Generating Units 1
Actual
Yr. Ending
Dec 2009
999,471
1,711,217
2,710.688
Yr. Ending
Dec 2010
349,018
1,830
350,848
Below
Budget I
Yr. Ending Yr. Ending
Dec 2011 Dec 2012
5,119,000 N/A
87,000 1,104,000
5,206,000 1,104.000
Lake Side
Ch.ehalis
Yr. Ending
Dec 2008
546,249
N/A
546,249
1Lake Side & Chehalis are Function. Other
Calendar Year 2010 Overhaul Expense. Other
2010 Existing Plant:
2010 New Generating Units:
2.303,074 Above
350,848 Above
2,653,922 Ref 4.12.1
4 Year
Avera e
1.753,435
726,012
2,479,446 Ref 4.12.1
Rocky Mountain Power PAGE 4.13
Idaho General Rate Case. December 2010
Incremental O&M
TOTAL IDAHOACCOUN1~COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Expense:
Dunlap I 549 2 1,879,314 SG-W 6.052%113,745
OJ Scrubber - Unit 3 512 2 1,347,558 SG 6.052%81,561
Wyodak Unit 1 - Emissions Controls 512 3 571,550 SG 6.052%34,593
Naughton U2 Scrubber 512 3 481,384 SG 6.052%29,136
. Dunlap Interconnection 571 2 30,000 SG 6.052%1,816
Ben Lomond to Terminal 571 2 16,500 SG 6.052%999
Populus to Ben Lomond 571 2 140,000 SG 6.052%8,473
Black Hils - Transmission Sale 571 2 (99,989)SG 6.052%(6,052)
Cholla 4 Scrubber 512 3 1,203,409 SG 6.052%72,836
5,569,726 337,107 4.13.1
Description of Adjustment:
This adjustment annualizes incremental O&M from plant in service, improvements to plants, or transmission projects
that were placed into service during the twelve months ended December 2010, and includes projected O&M expense
for projects placed into service during the twelve months ending December 2011.
Also, on December 29,2010 the Company sold Black Hils, Co, an undivided joint ownership interest in certain
transmission facilities. This adjustment reflects the expected reduction to O&M related to these facilities.
As of December 2010, with the depletion of the McKinley Mine the Cholla 4 scrubber will be using coal from a different
source which requires additional scrubbing
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This adjustment removes expenses in excess of Commission policy allowances as stated in the Commission order 29505.
National and regional trade organizations are recognized at 75%. Western Electricity Coordinating Council and Northern
Tier Transmission Group dues are included at 100% .
Page 4.14.1Rocky Mountain Power
Idaho General Rate Case - December 2010
Memberships and Subscriptions Adjustment Detail
Account Factor Description Amount
Remove Total Memberships and Subscriptions in Account 930.2
930.2 SO SAP Extract from Accounting (6,091,256)930.2 CN SAP Exract from Accounting (185)930.2 OR SAP Exract from Accounting (460)
(6,091,901 )Ref 4.14
Allowed National and Regional Trade Memberships at 75%
930.2 SO AFCOM 510
930.2 SO Americas' SAP User Group 5,000
930.2 SO Associated Oregon Industries 28,000
930.2 CN Association of Energy Engineers 185
930.2 SO Associated Taxpayers of Idaho Inc 850
930.2 SO Association of Idaho Cities 550
930.2 SO Association of Washington Business 4.000
930.2 SO Association of Washington Cities 1,000
930.2 SO Columbia Corridor Assn 3,00930.2 SO Consortium for Energy Effciency 16,190
930.2 SO Edison Electric Institute 726,784
930.2 SO Electric Power Research Institute 547,651
930.2 SO EUCG Inc 3,000
930.2 SO Idaho Association of Counties 450
930.2 SO IESNA 500
930.2 SO Intermountain Electrical Assoc 9,000
930.2 SO Lane Utilities Coordinating Council 200
930.2 SO League of Oregon Cities 500
930.2 SO Lloyd District Community Association 300
930.2 SO Metropolitan Utility Coordinating 125
930.2 SO Montana Tax Foundation Inc 1,050
930.2 SO National Automated Clearing House 4,500
930.2 SO National Coal Transporttion Assoc 1,250
930.2 SO National Electric Energy Testing Research and Application Center 23,750
930.2 SO National Joint Utilties 9,000
930.2 SO Northwest Public Power Association 620
930.2 SO Oregon Business Association 11,000
930.2 SO Oregon Business Council 33,228
930.2 SO Oregon Rural Electric Cooperative 750
930.2 SO Oregon Solar Energy Indstrs Assoc 5,000
930.2 SO Oregon Sports Authority Foundation 5,000
930.2 SO Pacific NW Utilities Conference 69,069
930.2 SO Portland Business Allance 39,400
930.2 SO PORTLAND SIM 450
930.2 SO Project Management Instiute 432
930.2 SO Rocky Mountain Electrical League 18,000
930.2 SO Society for Human Resource Management 160
930.2 SO Society for Information Management 225
930.2 SO Solar Electric Power Association 7,000
930.2 SO The Climate Registry 10,000
930.2 SO The Eastern Idaho Water Rights 250
930.2 SO Utah Foundation 20,000
930.2 SO Utah Manufacturers Association 6,00930.2 SO Utah Taxpayers Association 20,000
930.2 SO Walla Walla Area Utilities Coord 100
930.2 SO Washington Pulp & Paper Foundation 1,800
930.2 SO Washington State Water Resource Association 300
930.2 SO West Associates 28,511
930.2 SO Westem Energy Institute 42.004
930.2 SO Western Lampac 2,000
930.2 SO Wyoming Assoc of Municipaliies 325
930.2 SO Wyoming Business Allance 5,000
930.2 SO Wyoming Taxpayers Association 9,523
Total of Memberships Above 1,723.492
75% of Memberships Above 1,292,619 Ref 4.14
Membership Fees at 100%
930.2 SO Westem Electricity Coordinating Council 3,786,077
930.2 SO Northern Tier Transmission Group 418,088
4,204,165 Ref 4.14
Total Memberships and Subscriptions Allowed 5,496,785
Rocky Mountain Power PAGE 4.15
Idaho General Rate Case.December 2010
Intervenor Funding
TOTAL IDAHO
ACCOUNT~COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Expense:
Misc. General Expense 928 3 26,016 ID Situs 26,016 Below
Adjustment to Rate Base:
Deferred Regulatory Expense 182M 3 (4,596)ID Situs (4,596)Below
Adjustment to Tax:
Schedule M SCHMDT 3 14,904 ID Situs 14,904
Deferred Tax Expense 41010 3 5,656 ID Situs 5,656
Accum. Def. Tax Balance 283 3 (22,279)ID Situs (22,279)
Schedule M SCHMAT 1 (17,580)ID Situs (17,580)
Deferred Tax Expense 41110 1 6,672 ID Situs 6,672
Accum. Def. Tax Balance 283 1 16,622 ID Situs 16,622
Adjustment Detail:
Amortization Expense - 2010 17,580 4.15.1
Amortization Expense - 2011 43,596 4.15.1
Incremental adjustment to expense 26,016 Above
December 2010 Balance 43,798 4.15.1
December 2011 Balance 39,201 4.15.1
Incremental adjustment to rate base (4,596)Above
Description of Adjustment:
This adjustment accounts for intervenor funding awarded to the Community Action Partnership of Idaho (CAPAI) , the Idaho
Irngation Pumpers Association (IIPA) and the Idaho Conservation League (ICL), as ordered in Case No's. PAC-E-07-05, PAC-E-
08-07, PAC-E-10-07 and ECAM Case No. PAC-E-08-08. Amortization expense is increased by the expected amortization
amount through the year ending December 2011 and rate base is adjusted to reflect the December 2011 balance.
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Description of Adjustment:
Per IPUC Order No. 32196, this adjustment replaces the accrual pension expense for the 12 months ended December
2010 with the average actual amount funded during the 36 months ended December 2011.
Rocky Mountain Power
Idaho General Rate Case - December 2010
Convert Accrual Pension Expense to a Three-Year Cash Basis Average
Cash Basis Pension Expense
Pension Funding CY 2009
Pension Funding CY 2010
Pension Funding CY 2011
Pension Funding Three-Year Average Ending December 2010
Exclude Mines
Exclude Joint Ventures
Pension Funding to Electric Expense
Accrual Basis Pension Expense
Total Pension Expense
Less: Local 57 Pension Expense
Accrual Basis Pension Expense in Results 12 Mos Ended December 2010
Electric Expense in Results
Total Difference
O&M portion
Adjustment to O&M
49.564,280
112.800,000
66,482,100
76,282,127
96.35%
73,494,927
97.18%
29,858,438
(9,360.346)
20,498.092
71,425,572
20,498,092
Page 4.16.1
Ref 4.3.4
50,927,480
69.6% Ref 4.3.14
35,456,741 Ref 4.16
Rocky Mountain Power
Idaho General Rate Case. December 2010
Uncollectible Expense
PAGE 4.17
Adjustment to Expense:
UncQllectible Expense
TOTAL
ACCOUNT ~ COMPANY
IDAHO
FACTOR FACTOR % ALLOCATED REF#
904 1 (174,096)ID Situs (174,096) 4.17.1
Description of Adjustment:
Uncollectible expense is adjusted to a 3 year average (2008-2010) as ordered by the Commission in Case No. PAC-E-10-
07.
Rocky Mountain Power
Idaho General Rate Case. December 2010
Uncollectible Expense
CY 904 Expense
2008 303,406
2009 471,222
2010 678,156
GRID West
Amortization
27,162
27,162
27,162
General
Adjusted 904 Business
Expense Revenue
276,244 197,742,910
444,060 186,759,389
650,994 206,560,116
3 Year Average
CY 2010 Idaho General Business Revenue
Uncollectible Expense Calculated Using Average Rate
CY 2010 Idaho Uncollectible Expense
Adjustment to Reflect 3 Yr Average
Page 4.17.1
Uncollectible
Rate Reference
0.140%
0.238%
0.315%
0.231% A
206,560,116 B
476,899 =A*B
650,994
(174,096) Ref 4.17
Rocky Mountain Power
Idaho General Rate Case. December 2010
Outside Services
PAGE 4.18
TOTAL IDAHO
ACCOUNT Type COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Expense:
Outside Services Expense 923 1,378,313 SO 5.794%79,863 4.18.1
Outside Services Expense 923 1,024 UT Situs 4.18.1
Outside Services Expense 923 (5,464)OR Situs 4.18.1
1,373,874 79,863
Description of Adjustment:
Per Order No. 32196 in Case No. PAC-E-10-07, this adjustment averages outside services expense for 2008,2009
and 2010.
Rocky Mountain Power
Idaho General Rate Case. December 2010
Outside Services Expense
Summary of Outside Services Expense by Year
Year Factor ... .. Labor Non-Labor ... Total2008 SO (61,758) 11,950,192 11,888,4342008 UT 0 2,442 2,442
(61,758) 11,952,634 11,890,876
2009 SO (11,387,305)22,426,025 11,038,720
2009 UT 0 630 630
(11,387,305)22,426,655 11,039,350
2010 SO 0 9,396,107 9,396,107
2010 OR 0 8,195 8,195
0 9,404,302 9,404,302
Three-Year Averaae
.. Factor.';..
SO
UT
OR
Adjustment from 2010 ActualsFactor . .
SO
UT
OR
.
Tóúll
10,774,420
1,024
2,732
Total
1,378,313
1,024
(5,464)
Page 4.18.1
Ref 4.18
Ref 4.18
Ref 4.18
IDAHO 2010 PROTOCOL Page 5.0 Total
Net Power Cost Adjustments (Tab 5)
TOTAL
5.1 5.2 5.3 5.4 0 0
James River
Royalt OfeV Electic Lake BPA Residential
Totai Normalized Net Power Cost Lite Mountain Settement Exchange 0 0
1 Operating Revenues:
2 General Business Revenues
3 Interdepartental
4 Special Sales 1.051,991 1,051,991
5 Other Operating Revenues 157,856 157,856
6 Total Operating Revenues 1,209,846 1,051,991 157.856
7
8 Operating Expenses:
9 Steam Producton 4.878,165 4,878,165
10 Nuclear Production
11 Hydro Production
12 Other Power Supply 7,258,533 7,796,851 68,317 (606,635)
13 Transmission 264,019 264,019
14 Distribution
15 Customer Accountin9
16 Customer Service & Info
17 Sales
18 Administrative & General
19 Total O&M Expenses 12,400,716 12,939,034 68.317 (606.35)
20 Depreciation
21 Amortzation
22 Taxes Other Than Income
23 Income Taxes: Federal (3,749.089)(3.971.580)52,741 (32.932)202.683
24 State (509,439)(539,62)7,167 (4.475)27.541
25 Deferred Income Taxes 11,480 11,480
26 Investment Tax Credit Adj.
27 Misc Revenue & Exense
28 Total Operating Expenses:8,153,669 8,27,782 59,908 42,390 (376,11)
29
30 Operating Rev For Return:(6,943,823)(7.375.792)97,948 (42.390)376,11
31
32 Rate Base:
33 Eiectric Plant In Service
34 Plant Held for Future Use
35 Misc Deferred Debits (3,997)(3,997)
36 Elec Plant Acq Adj
37 Nuclear Fuel
38 Prepayments
39 Fuel Stock
40 Material & Supplies
41 Working Capital
42 Weatherization Loans
43 Mlsc Rate Base
44 Total Electric Plant:(3,997)(3,997)
45
46 Deductions:
47 Acum Prov For Deprec
48 Accum Prov For Amort
49 Accum Def Income Tax 500 500
50 Unamortized ITC
51 Customer Adv For Canst
52 Customer Service Deposits
53 Miscellaneous Deductions 2.807 2,807
54
55 Total Deductons:3.307 3.307
56
57 Total Rate Base:(690)(690)
58
59
60 Estimated ROE impact -1.903%-2.022%0.027%-0.012%0.103%0.000%0.000%
61
62
63
64 TAX CALCULATION:
65
66 Operatin9 Revenue (11,190,870)(11.887,044)157,856 (68,317)606.635
67 Other Deductions
68 Interest (AFUDC)
69 Interest
70 Schedule "M" Additions (104,632)(104.632)
71 Schedule 'M" Deuctions (74,381)(74,381)
72 Income Before Tax (11,221.120)(11.887,044)157,856 (98.568)606.635
73
74 State Income Taxes (509,439)(539,672)7,167 (4,475)27.541
75
76 Taxable Income (10.711,681)(11.347.372)150,689 (94,093)579.094
77
78 Federal Income Taxes (3,749,089)(3,971,580)52.741 (32,932)202.683
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Rocky Mountain Power
Idaho General Rate Case. December 2010
Period Ending Dec.11
SPECIAL SALES FOR RESALE
Pacifc Pre Merger
Post Merger
Utah Pre Merger
NonFirm Sub Total
TOTAL SPECIAL SALES
Page 5.1.2
Study Results
MERGED PEAKINERGY SPLIT
(S)
Merged Pre-Merger Pre-Merger
01/11-12/11 Demand ~.t Post-Merger
25,994,866 25,994,866
455,386,402 455,386,02
28,565,371 28,565,371
509,946,638 54.560,237 - 455,386,402
PURCHASED POWER & NET INTERCHANGEBPA Peak Purchase 38,410,000
Pacifc Capacity 1,914,028Mid Columbia 11,656.355MisclPaciflc 6,482,026
OF Contracls/PPL 66,399,857Small Purchases west 18,822
Pacifc Sub Total
Gemstate
GSLM
OF Contracls/UPL
IPP Layoff
Small Purchases east
UP&L to PP&L
Utah Sub Total
APS Supplemental p27875
Avoided Cost Resource
Blanding Purchase p379174
BPA Reserve Purchase
Chehalis Station Service
Combine Hills Wind p 160595
Constellation p257677
Constellation p257678
Constellation p268849
Deseret Purchase p194277
Georgia-Pacifc Camas
Hermiston Purchase p99563
Hurricane Purchase p393045
Idaho Power p278538
Kennecott Generation Incentive
LADWP p491303-4
MagCorp p229846
MagCorp Reserves p51 03 78
Morgan Stanley p189046
Morgan Stanley p272153-6-8
Morgan Stanley p272154-7
Nebo Heat Rate Option p360539
Nucor p346856
P4 Production p137215/p145258
Rock River Wind p100371
Roseburg Forest Product p31229
Three Buttes Wind p460457
Top of the World Wind p522807
Tri-State Purchase p27057
Weyerhaeuser Reserve p356685
Wolverine Creek Wind p244520
BPA So. Idaho p64885/p83975/p6-
DSM (Irrigation)
PSCo Exchange p340325
TransAita p371343/s371344
Seasonal Purchased Power
Morgan Stanley p244840
124,883,088
38,10,000
600,000 1.314,028
3,497,507 8,160,849
1,344,131 5,137,895
6,337,752 30,878,50 29,183,655
18.622-------------
50,189,389 45,510,044 29,183,655
2,840,300
20,958,683 8,982,293 80,778,346
28.565,371
703,122
2,840,300
110,719,323
28,565,371
703,122
142,828,116 49.524,054 12,525,715 80,778,346
1,164.603 1.164,603
29.631
249,081
32,222
4,524.776
29.631
249,081
32,222
4,524.776
30,731,420 30,731,420
7,408.226 7,408,226
79,750.744 79.750,744
146,459 146,459
3,809,448 3,809,448
774,380 774,380
4.908.240 4,908,240
1,530,000 1,530,000
1,620,000 1.620.000
4.998,000 4,998.000
17.086,750 17.086,750
5,041,688 5,041.688
5,091,045 5.091,045
20.598,497 20,598,97
40,244.928 40,244,928
9,515,758 9,515,758
9,844,245 9.844,245
(9,884)(9,884)
4,500,000 4.500,000
Rocky Mountain Power
Idaho General Rate Case. December 2010
Period Ending Dec.11
Morgan Stanley p244841
UBS p268848
UBS p268850
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
Pacife Firm Wheeling and Use of Fae
Utah Firm Wheeling and Use of Facill
Post Merger
Nonfirm Wheeling
TOTAL WHEELING & U. OF F EXPENS
THERMAL FUEL BURN EXPENSE
Carbon
Cholla
Colstrip
Craig
Chehalis
Currant Creek
Dave Johnston
Gadsby
GadsbyCT
Hayden
Hermiston
Hunter
Huntington
Jim Bridger
Lake Side
Litte Mountain
Naughton
Wyodak
TOTAL FUEL BURN EXPENSE
OTHER GENERATION EXPENSE
Blundell
TOTAL OTHER GEN. EXPENSE
NET POWER COST
Merged
01/11-12/11
50,491,241
304,081,497
4,058,320
575,851,022
27,756,081
108,149,743
5,352,375
141,258,199
15,795,521
51,032,865
14,897,448
21,073,014
67,381,818
149,720,779
53,001,260
4,994,157
38,998,743
10,481,204
62,189,230
124,798,54
99,701,103
184,070,050
70,406,316
10,050,921
102,395,723
20,346,930
1,101,335,536
3,321,028
3,321,028
1,311,819,146
Ref 5.1
Study Results
MERGED PEAK/ENERGY SPLIT
($)
Pre.Merger
Demand
Pre.Merger
Energy
99,713,444 58,035,759
27,756,081
27,756,081
Non.Firm
5,352,375
Page 5.1,3
Post-Merger
50,491,241
304,081,497
4,058,320
. 418,101,818
108,149,743
5,352,375 108,149,743
15,795,521
51,032,865
14,897,448
21,073,014
67,381,818
149,720,779
53,001,260
4,994,157
38,998,743
10,481,204
62,189,~30
124,798,54
99,701,103
184,070,050
70,406,316
10,050,921
102,395,723
20,346,930
1,101,335,536
3,321,028
3,321,028
72,909,288 58,035,759 1,110,008,939 70,865,159
Rocky Mountain Power
Idaho General Rate Case. December 2010
James River Royalty Offset! Little Mountain
PAGE 5.2
Adjustment Detail:
Calendar Year
2011
James River Offset
Capital Recovery
Major Maintenance Allowance
Total Offset
4,890,370
540,282
5,430,652 Above
Little Mountain Revenue
Pro forma steam sales - CY2011
Less: Steam sales in unadjusted results
2,897,430
5,719,969
(2,822,539)
5.2.1
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 aligns the Litte Mountain steam sales with the assumptions used in the net power cost study.
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Rocky Mountain Power PAGE 5.3
Idaho General Rate Case - December 2010
Electric Lake Settlement
TOTAL IDAHO
ACCOUNT IY COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Expense:
Amortization O&M Portion 557 3 1,128,747 SG 6.052%68,317 5.3.1
Regulatory Asset 186M 3 (63,030)SE 6.341%(3.997)5.3.1
Regulatory Liabilty 254 3 44,269 SE 6.341%2,807 5.3.1
Adjustment to Tax:
Fuel Amortization
Schedule M SCHMAT (1,650,075)SE 6.341%(104,632)
Deferred Tax Expense 41110 626,220 SE 6.341%39,709
Accum Def Income Tax Balance 283 23,920 SE 6.341%1,517
Coal Supply Adjustment
Schedule M SCHMDT 1 (1,173,017)SE 6.341%(74,381)
Deferred Tax Expense 41010 1 (445,172)SE 6.341%(28,228)
Accumulated Deferred Income Taxes 190 1 (16,800)SG 6.052%(1,017)
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. The two companies 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. The amortization for this settlement
ended January 2011. This adjustment removes the amortization and rate base from actual results.
Rocky Mountain Power
Idaho General Rate Case - December 2010
Electric Lake Settlement
Year End
Settlement of Costs
Value of Settlement
Offset 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 reduction amount
Reduction to Accunt 557
Regulatory Liabilty Account 25399
Offset O&M Account 557
Amortization of Offset
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 11 Ending Balance
Regulatory Liabilty Account 254
Set-Up Deferred Asset
Amortization
Ending Balance
Account 254 ending balance in actual results
Adjustment needed to reflect account balance
Dec 11 Ending Balance
Page 5.3.1
10,087,658
71%
7,162,237
(44,269)
(44,269)
(1,173,017)
1,128,747 Ref 5.3
(44,269)
Dec-09 Dec-10 Dec-11
1,431,680 715,840 0
(715,840)(715,840)
715,840 0
Dec-09 Dec-10 Dec-11
4,300,468 1,713,105 63,030
(2,587,363)(1,650,075)(63,030)
1,713,105 63,030
63,030
(63,030)Ref 5.3
Dec-09 Dec-10 Dec-11
(3,053,860)(1,217,286)(44,269)
1,836,574 1,173,017 44,269
(1 ,217,286)(44,269)
(44,269)
44,269 Ref 5.3
Rocky Mountain Power PAGE 5.4
Idaho General Rate Case. December 2010
BPA Residential Exchange
TOTAL IDAHO
ACCOUNT Type COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Expense:
Purchased Power Expense 555 (606,635)ID Situs (606,635)5.4.1
Description of Adjustment:
The Company receives a monthly purchase power credit from Bonnevile 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 are posted to
unadjusted results and 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 2010
BPA Residential Exchange
Account 505204
Idaho
12 months Ended December 31,2010 expense 606,635
Ref 5.4
Page 5.4.1
810,697.00
806,785.00
4:68,4:22.00
459,672.00
337,113.1JO
183,799.00
69,956.59
624,156.00
668,502.07
164,378.32
305i71l.1ô
604,198.34
357,289.00
453,408.00
232,020.0u ."
236,402.00
223,270.00
113,843.00
694,112.01
1,292,657.42
828,272.63
159,770.05
4,608.20
301,102.97
453,408.00
353,377.00
223,270.00
113;843.(10
69,956.00
624,155.42-
668,501.42-
159,77056-
4,608.27
3l:t,102.96...
303,095.37
453,408
80ô,785.00
1,043,187.00
1,266,457.00
1,380,300.00
1,450,256.00
826,100.58
157,599.16
2,171.40-
2,436.87
303,539.83
60ô,ô35.20
ÔOÔ,635.20
ÔOÔ,Ô35.20
606,635.20
IDAHO 2010 PROTOCOL Page 6.0 Total
Depreciation & Amortization (Tab 6)
TOTAL
6.1 6.2 6.3 0 0 0
Depreciation &Depreciation &
Amortization Amortzation Hydro
Total Normalized Expense Reserve Decommissioning 0 0 0
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 Distrbution
15 Customer Accounting
16 Customer Service & Info
17 Sales
18 Administrative & General
19 Total O&M Expenses
20 Depreciation 2,476.377 2.476,377
21 Amortization 46,183 46,183
22 Taxes Other Than Income
23 Income Taxes: Federal (1,082.418)(842,813)(239,605)
24 State (147,083)(114,524)(32,558)
25 Deferred Income Taxes 272,164 272,164
26 InvestmentT ax Credit Adj.
27 Misc Revenue & Expense
28 Total Operating Expenses:1,565,223 1,565,223 0
29
30 Operating Rev For Return:(1,565,223)(1,565,223)(0)
31
32 Rate Base:
33 Electric Plant In Service
34 Plant Held for Future Use
35 Misc Deferred Debits
36 Elec Plant Acq Adj
37 Nuclear Fuel
38 Prepayments
39 Fuel Stock
40 Material & Supplies
41 Working Capital
42 Weatherization Loans
43 Misc Rate Base
44 Total Electc Plant:
45
46 Deductons:
47 Accum Prov For Deprec (448,42)(949,224)500,782
48 Accum Prov For Amort (32,831)(32,831)
49 Accum Oef Income Tax (272,164)(272,164)
50 Unamortized ITC
51 Customer Adv For Const
52 Customer Service Deposits
53 Miscellaneous Deductions
54
55 Total Deductions:(753.436)(982,055)228,618
56
57 Total Rate Base:(753,36)(982,055)228,618
58
59
60 Estimated ROE impact -0.416%-0.429%0.017%-0.004%0.000%0.000%0.000%
61
62
63
64 TAX CALCUlATION:
65
66 Operating Revenue (2,522,560)(2,522,560)
67 Oter Deductions
68 Interest (AFUDC)
69 Interest
70 Schedule 'M" Additions
71 Schedule "M" Deductions 717,145 717,145
72 Income Before Tax (3,239,706)(2,522.560 )(717,145)
73
74 Slate Income Taxes (147,083)(114,524)(32,558)
75
76 Taxable Income (3,092,623)(2.408,036)(684,587)
77
78 Federal Income Taxes (1,082.418)(842,813)(239,605)
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. Depreciation expense related to major plant additions placed into service during 2010 is also
annualized.
Page 6.1.2
Rocky Mountain Power
idaho General Rate Case. December 2010
Major Plant Addition Detil. January 2011 . December 2011
Depreciation Depreciation Jan11 to Dec11 Plant Incremental Expense on
Project Description Account Factor In-Service Date Account Rate Additions Plant Adds Steam Production
Naughton U2 Flue Gas Desulfrization Sys 312 SG Nov.11 403SP 2.417%151,812,653 3,669,203
Wyodak U1 S02 and PM Emiss Control Upgrade 312 SG Apr-11 403SP 2.417%103,798,008 2,508,723
Hunter 302 Clean Air - PM 312 SG May-11 403SP 2.417%53,436,997 1,291,534
Huntington U 1 S02 & PM Em Cntr Upgrades 312 SG Mar11 403SP 2.417%28,770,137 695,354302 . Hunter U2 S02 Project 312 SG Jul.11 403SP 2.417%22,521,188 54,321Wyodak U1 . Air Cooled Condenser Replacement 312 SG May-11 403SP 2.417%21,480,503 519,168
Hunter 302 Turbine Upgrae HPIIPILP 312 SG Apr-11 403SP 2.417%20,728,107 500,983
Jim Bridger U3 S02 & PM Em Cntn Upgrades 312 SG May-11 403SP 2.417%17,151,525 414,540
Hayden UO Coal Unloading Facilty 312 SG Oct-11 403SP 2.417%12,329,739 298,001
Wyodak U1 OH Clean Air. NOX 312 SG May-11 403SP 2.417%11,858,187 286,604Naughton U2 NOx LNB . Clean 312 SG Nov-11 403SP 2.417%9,200,272 222,36Hunter 302 Main Contrls Replacement 312 SG Apr-11 403SP 2.417%7,303,465 176,519
Hunter U2 NOx LNB . Ciean Air 312 SG May-11 403SP 2.417%6,246,843 150,982
Huntington U2 Boiler Finishing SH Pendants Replacem 312 SG Nov-11 403SP 2.417%5,920,859 143,103
Wyodak U1 - Replacement of Secondary Superheat 312 SG Apr.11 403SP 2.417%5,513,500 133,257
Steam Production Total 478,071,983 11,554,656
Hydro Producton
INU 6.1 Lemolo 2 Reroute to Toketee 332 SG-P Dec.11 403HP 2.114%8,979,199 189,862
INU 4.1.1 (1)16.9 Slide Tailrace Barrer 332 SG-P Dec.11 403HP 2.114%8,603,272 181,913
Ashton Dam Seepage Contrl. Tunnel 332 SG-U Mar.11 403HP 2.727%8,038,710 219,243
Hydro Producton Totl 25,621,180 591,018
Transmission
Red Butte Staic Var Compensator and 345 kV Shunt Capacitor 355 SG May-11 403TP 1.937%46,434,990 899,283
Malin 500 kV series cap replacement 355 SG Feb.11 403TP 1.937%18,700,000 362,154
Hany Allen Sub Install Transformer 355 SG Jun-11 403TP 1.937%15,100,000 292,434Populus.Terminal: Obi Cir 345 kV TransLn. Transmission 355 SG Nov-10 403TP 1.937%13,409,213 259,689
Populus - Terminal 345 kV line - Borah Reconductor 355 SG Feb-11 403TP 1.937%13,400,000 259,511Mona. Limber. Oquirr 500135 kV line Phases I and ii 355 SG Apr.111May11 403TP 1.937%8,362,700 161,966
Oquirr New 345.138kV Substation 355 SG Jan.11 403TP 1.937%6,804,918 131,787Idaho Clearance Issue Corrctons 355 SG Jun-11 403TP 1.937%6,616,683 128,142
Dave Johnston - Casper 230 kV Rebuild - #1 Line 355 SG Jan-11 403TP 1.937%6,127,474 118,668
Califomia-Qregon Intertie Upgrade 4800MW Rating 355 SG Jul-11 403TP 1.937%6,157,000 119,240
Skypark: Build New 138-12.5 kV Substtion 355 SG Oct-11 403TP 1.937%5,070,679 98,201
Wyoming Clearance Issue Corrctons 355 SG Dec-11 403TP 1.937%5,017,130 97,164
Transmission Total 151,.200,786 2,928,230
Intangible
TnP ii Energy Trading Systems Capital 303 SG Jan11/Aug11 4041P 3.865%14,034,863 542,430
Intangible Total 14,034,863 542,430
Mining
Deer Creek-Reconstrct Longwall System 399 SE Apr11/Nov11 403MP 3.497%16,630,298 581,567Mining Total 16,630,298 581,567
685,559,110 16,197,901
Ref# 8.6.2
Totl not Including Mining 15,616,334
Ref6.1
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.
Rocky Mountain Power PAGE 6.3
Idaho General Rate Case. December 2010
Hydro Decommissioning
TOTAL IDAHO
ACCOUNT Type COMPANY FACTOR FACTOR %ALLOCATED REF#
Allocation Correction to Booked Reserve
Depreciation Reserve 108HP (36,247)SG-P 6.0525%(2,194)6.3.2
Depreciation Reserve 108HP 36,247 SG-U 6.0525%2,194 6.3.2
Adjustment to Reserve
Depreciation Reserve 108HP 3 9,624,534 SG-P 6.0525%582,524 6.3.1
Depreciation Reserve 108HP 3 (1,350,550)SG-U 6.0525%(81,742)6.3.1
8,273,984 500,782 6.3.1
Adjustment to Tax
Schedule M Deduction SCHMDT 3 11,848,763 SG 6.0525%717,145 6.3.1
Deferred Income Tax Expense 41010 3 4,496,724 SG 6.0525%272,164 6.3.1
ADIT YIE Balance 282 3 (4,496,724)SG 6.0525%(272,164)6.3.1
Adjustment to Reserve for Projected Spend I Accrual Detail:
December 2010 Year End Reserve Balance (15,540,703)
December 2011 Year End Reserve Balance (7,266,719)Total Adjustment to Reserve 8,273,984
6.3.1
6.3.1
6.3.1
Description of Adjustment:
In the current depreciation study, in which depreciation rates were approved by the Commission in February 2008 under
Idaho Case No. PAC-E-07-14, Order 30499, 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 millon estimate
included the recovery of $6.5 million 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.
This adjustment walks the depreciation reserve balance to the December 2011 year-end projected leveL.
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Rocky Mountain Power
Idaho General Rate Case. December 2010
Hydro Decommissioning
Corrections to Booked Data
12 Months Ended December 2010
Page 6.3.2
Accumulated Depreciation108 SG-P108 SG-U
IDAHO 2010 PROTOCOL Page 7.0 Total
Tax Adjustments (Tab 7)
TOTAL
7.1 7.2 7.3 7.4 7.5 7.6
Idaho State Post Retirement
Properl Tax Renewable Energy Investment Tax Benefits Tax
Total Normalized Interest True Up Expense Tax Credit Credit AFUDC Equity Deferral
1 Operating Revenues:
2 General Business Revenues
3 Interdepartmental
4 Speclai 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 Distributon
15 Customer Accounting
16 Customer Service & info
17 Sales
18 Administrative & General 204,998 204,998
19 Total O&M Expenses 204,998 204,998
20 Depreciation
21 Amortization
22 Taxes Other Than Income 765,162 765,162
23 Income Taxes: Federal (1,588,174)(364,909)(255,648)(831,810)(67,315)(68,92)
24 State (132,722)(49,585)(34,738)(29,945)(9,147)(9,307)
25 Deferred Income Taxes 218,810 112,884
26 Investment Tax Credit Adj.
27 Misc Revenue & Expense
28 Total Operating Expenses:(531,925)(414.494)474,775 (748,870)(76,462)127,199
29
30 Operating Rev For Return:531,925 414,494 (474,775)748,870 76,62 (127,199)
31
32 Rate Base:
33 Electric Plant In Service
34 Plant Held for Future Use
35 Misc Deferred Debit
36 Elec Plant Acq Adj
37 Nuclear Fuel
38 Prepayments
39 Fùel Stock
40 Material & Supplies
41 Working Capitl
42 Weatherization Loans
43 Misc Rate Base
44 Total Electrc Plant:
45
46 Deductions:
47 Accum Prov For Deprec
48 Accum Prov For Amort
49 Accum Def Income Tax 2,245,557
50 Unamortzed ITC (118,179)(118,179)
51 Customer Adv For Const
52 Customer Service Deposits
53 Miscellaneous Deductions
54
55 Total Deductons:2,127,378 (118,179)
56
57 Total Rate Base:2,127,378 (118,179)
58
59
60 Estimated ROE impact 0.108%0.114%-0.130%0.205%0.002%0.021%-0.035%
61
62
63
64 TAX CALCULATION:
65
66 Operating Revenue (970,160)(765,162)(204,998)
67 Other Deductions
68 Interest (AFUDC)201,475 201,475
69 Interest 1,092,182 1,092,182
70 Schedule "M" Additions
71 Schedule "M" Deductions
72 Income Before Tax (2,263,817)(1,092,182)(765,162)(201,475)(204,998)
73
74 State Income Taxes (132,722)(49,585)(34,738)(29,945)(9,147)(9,307)
75
76 Taxable Income (2,131.095)(1,042,597)(730,424)29,945 (192,328)(195,691)
77
78 Federal Income Tax - Calculated (745,883)(36,909)(255,68)10,481 (67,315)(68,492)
79 Adjustments to Calculated Tax:
80 Renewable Energy Tax Credits (842,290)(842,290)
81 Federal Income Taxes (1,568,174)(364,909)(255,648)(831,810)(67,315)(68,492)
IDAHO 2010 PROTOCOL Page 7.0.1 Total
Tax Adjustments (Tab 7)
TOTAL
7.7 0 0 0 0 0 0
ADIT Balance
Adjustment 0 0 0 0 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:
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 Administrative & General
19 Total O&M Expenses
20 Depreciation
21 Amortization
22 Taxes Other Than Income
23 Income Taxes: Federal24 State
25 Deferred Income Taxes
26 Investmen1 Tax Credit Adj.
27 Misc Revenue & Expense
28 Total Operating Expenses:
29
30 Operating Rev For Return:
31
32 Rate Base:
33 Electrc Plant In Service
34 Plant Held for Future Use
35 Misc Deferred Debits
36 Elec Plant Acq Adj
37 Nuclear Fuel
38 Prepayments
39 Fuel Stock
40 Material & Supplies
41 Working Capitl
42 Weatherization Loans
43 Misc Rate Base
44 Total Electric Plant
45
46 Deductions:
47 Accum Prov For Deprec
48 Accum Prov For Amort
49 Accum Def Income Tax
50 Unamortzed ITC
51 Customer Adv For Const
52 Customer Service Deposits
53 Miscellaneous. Deductions
54
55 Total Deductions:
56
57 Total Rate Base:
58
59
60 Estimated ROE impact
61
62
63
64 TAX CALCULATION:
65
66 Operating Revenue
67 Other Deductions
68 Interest (AFUDC)
69 Interest
70 Schedule "M" Addttions
71 Schedule "M" Deductions
72 Income Before Tax
73
74 State Income Taxes
75
76 Taxable Income
77
78 Federal Income Tax. Calculated
79 Adjustments to Calculated Tax:
80 Renewable Energy Tax Credits
81 Federal Income Taxes
105.926
105.926
(105;926)
2.245,557
2.245,557
2.245,587
-0.068%0.00%0.000%0.000%0.000%0.000%0.000%
Rocky Mountain Power
Idaho General Rate Case. December 2010
Interest True Up
Adjustment to Expense:
Other Interest Expense - Type 1
Other Interest Expense - Type 2
Other Interest Expense - Type 3
Total
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-up Adjustment
PAGE 7.1
TOTAL IDAHO
ACCOUNT Type COMPANY FACTOR FACTOR %ALLOCATED REF#
427 1 85,791 ID Situs 85,791 Below
427 2 939 ID Situs 939 Below
427 3 1,005,452 ID Situs 1,005,452 Below
1,092,182 1,092,182 2.18
708,967,587 1.3
2.740%2.1
19,423,727 1.3
19,337,936 2.18
85,791 1.3
709,001,865 1.3
2.740%2.1
19,424,666 1.3
19,423,727 1.3
939 1.3
745,700,934 2.2
2.740%2.1
20,430,118 2.18
19,424,666 1.3
1,005,452 1.3
Description of Adjustment:
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 PAGE 7.2
Idaho General Rate Case.December 2010
Property Tax Expense
TOTAL IDAHOACCOUNT ~COMPANY FACTOR FACTOR % ALLOCATED REF#
Adjustment to Expense:
Taxes Other Than Income 408 3 13,205,560 GPS 5.794%765,162 7.2.1
Description of Adjustment:
This adjustment normalizes the difference between actual accrued propert tax expense and pro forma property tax
expense resulting from estimated capital additions.
Rocky Mountain Power
Results of Operations. December 2010
Propert Tax Adjustment Summary
Page 7.2.1
FERC Account GIL Account Co. Code408.15 579000 1000
Total Accrued Propert Tax. 12 Months End. December 2010
Projected Propert Tax Exp. for the Twelve Months Ending Dec 2011
Less Accrued Propert Tax - 12 Months Ended December 31,2010
Incremental Adjustment to Propert Taxes
Factor
GPS
Total
100,361,440
100,361,440
Ref
113,567,000 Confidential Exhibit NO.3
(100,361,440)
13,205,560 Ref7.2
Description of Adjustment:
This adjustment normalizes federal! state renewable energy income tax credits and state tax credits the Company is entitled
to take as a result of placing qualified generating plants into service. The federal production tax credit (PTC) for renewable
energy is based on the generation of the plant, and the credit can be taken for ten years on qualifying propert. The Utah state
PTC is based on the generation of the plant, and the credit can be taken for four years on qualifying propert. The Oregon
Business Energy Tax Credit is based on investment of plant, and the credit is taken over a 5 year period on qualifying propert.
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Rocky Mountain Power
Idaho General Rate Case. December 2010
Idaho State Investment Tax Credit
PAGE 7.4
Adjustment to Expense:
TOTAL IDAHO
ACCOUNT ~ COMPANY FACTOR FACTOR % ALLOCATED REF#
Idaho - Investment Tax Credit 255 1 (2,039.588) SO 5.794%(118,179) 7.4.1
Description of Adjustment:
This adjustment normalizes the Idaho state investment tax credit (ITC) 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 utilzed in a
subsequent period depending on the availability of Idaho state taxable income. Since the Company is classified
46(f)(1), the ITC unamortized balance is reflected in results of operations as a rate base reduction.
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.
1
Rocky Mountain Power
Idaho General Rate Case - December 2010
AFUDC Equity
PAGE 7.5
Adjustment to Expense:
AFUDC - Equity
TOTAL IDAHO
ACCOUNT ~ COMPANY FACTOR FACTOR % ALLOCATED REF#
419 1 3,511,169 SNP 5.738%201,475
Dèscription of Adjustment:
This adjustment brings in the appropriate level of AFUDC - Equity into results to align the tax schedule M with regulatory
income.
Rocky Mountain Power
Idaho General Rate Case. December 2010
Post Retirement Benefits Tax Deferral
PAGE 7.6
Adjustment to Expense:
TOTAL IDAHO
ACCOUNT ~ COMPANY FACTOR FACTOR % ALLOCATED REF#
Post Retirement Benefits Deferral Amortization 930 3 204,998 ID Situs 204,998 7.6.1
Description of Adjustment:
As approved in Case No. PAC-E-10-07, this adjustment recognizes the amortization of the Post Retirement Benefits tax
deferral regulatory asset for the twelve-months ending December 2011.
Rocky Mountain Power
Idaho General Rate Case. December 2010
Post Retirement Benefits Tax Deferral
Page 7.6.1
Summary of Regulatory assets for Non-Deductible Post Retirement Benefits
DescriDtion Idaho
Net Tax Benefits of Non-Deductible Post-Retirement Benefits A 9,435.766
Gross~ÜpFaCior.for Income Taxes ::( 1/( 1 ~:37951))B 1.6116
ll?teLÇ2rnpanYBe9ulatoryAssetf2r.Non-()ed lJci.ble Post~Retire.rnent. Benefits C 15,206,959
Revised Protocol Allocation Factor:SO D 5:3922%'
Jurisdictionally Allocated Regulatory Asset for Non-Deductible Post-Retirement
Benefits E 819,990
I Net Income Impact - A * D 508.7951
Period
Three Months Ended December 31,2010
caleridarvearErided December31, 2011
caleridar'YearErided. December31, .2012
caìeridarVearEndedDecember3T:2O1.3..
caleridar Year' Ended. December àf;'2O14
c~ife'nd'ã'rO~y'éar"E'I,aea"--t5èc£imb'er":3'1-",""2"0'1"5' '~
Calendar'YearErided Decemberá1 ,2O 16
Total Amortization Reaulatory Assets
Idaho
o
204.998.
2Ò4.998
...... ......264.998
.. . .~=._..:.: . 294 ;998 :.
o
o
819,992
I.Page 7.6
Rocky Mountain Power PAGE 7.7
Idaho General Rate Case - December 2010
ADIT Balance Adjustment
TOTAL IDAHO
ACCOUNT ~COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Expense:
ADIT Balance 282 3 3,046,185,039 DITBAL 5.545%168,903,996
Cholla SHL 190 3 (36,873,792)SG 6.052%(2,231,783)
Accel Amort of Pollution Cntrl Facilities 281 3 11,642,708 SG 6.052%704,674
California 282 3 (66,909,433)CA Situs
Idaho 282 3 (164,381,757)ID Situs (164,381,757)
FERC 282 3 (6,322,829)FERC Situs
Other 282 3 (33,019,766)OTHER 0.000%
Oregon 282 3 (800,140,907)OR Situs
Utah 282 3 (1,242,145,828)UT Situs
Washington 282 3 (181,903,370)WA Situs
Wyoming 282 3 (394,332,207)WY Situs
131,797,858 2,995,130
Repair Deduction Year End Balance 282 3 (12,384,526)SG 6.052%(749,572)
Depreciation Flow-Through - CA 41110 3 156,731 CA Situs
Depreciation Flow-Through - ID 41110 3 105,926 ID Situs 105,926
Depreciation Flow-Through - FERC 41110 3 9,837 FERC Situs
Depreciation Flow-Through - OTHER 41110 3 24,189 OTHER 0.000%
Depreciation Flow-Through - OR 41110 3 (95,704)OR Situs
Depreciation Flow-Through - UT 41110 3 1,171,363 UT Situs
Depreciation Flow-Through - WA 41110 3 20,913 WA Situs
Depreciation Flow-Through - WY 41110 3 (79,076)WY Situs
1,314,179 105.926
Description of Adjustment:
This pro forma adjustment reflects the known and measurable change to the accumulated deferred income tax.balances for
guidance received from the Internal Revenue Service (Rev. Proc. 2011-26) on March 29, 2011, which affected the
Company's estimate of bonus depreciation for assets placed in service during 2010.
IDAHO 2010 PROTOCOL Page 8.0.1 Total
Misc Rate Base Adjustments (Tab 8)
TOTAL
8.6.1 8.7 8.8 8.9 8.10 8.11 8.12
Klamath
Tax Impacts of Hydroelectrc
Major Plant Miscellaneous Powerdale Hydro Goose Creek Trojan Settement
Additions Rate Base Removal Transmission FERC 105 (PHFU)Unrecovered Plant Agreement
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 Production
11 Hydro Production (4,048)202,154
12 Other Power Supply 975,961
13 Transmission
14 Distribution
15 Customer Accounting
16 Customer Service & Info
17 Sales
18 Administrative & General
19 Total O&M Expenses (4,048)1,178,115
20 Depreciation (512)262,161
21 Amortization (151,720)(122,324)500,760
22 Taxes Other Than Income
23 Income Taxes: Federal (7,109,814)157,995 171 2,084 (428,302)
24 State (966,106)21,469 23 283 (58,199)
25 Deferred Income Taxes 8,05,920 (120,349)44,057 (250,142)
26 Investment Tax Credtt Adj.
27 Mlsc Revenue & Expense
28 Total Operating Expenses:0 (96,653)(318)(75,901)1,204,393
29
30 Operating Rev For Return:(0)96,653 318 75,901 (1,204,393)
31
32 Rate Base:
33 Electric Plant In Service (25,595)195,83
.34 Plant Held for Future Use (64,154)
35 Misc Deferred Debits 273,203 (118,016)
36 Elec Plant Acq Adj
37 Nuclear Fuel
38 Prepayments
39 Fuel Stock 2,355.158
40 Material & Supplies
41 Working Capitl
42 Weatherization Loans
43 Mlsc Rate Base (10,019)
44 Total Electrc Plant:2,628,361 (118,016)(25,595)(644,154)(10,019)195,83
45
46 Deductions:
47 Accum Prov For Depree 15,271 (354.202)
48 Accum Prov For Amort (50,760)49 Accum Def Income Tax (8,075.920)89.306 (116,766)250,142
50 Unamortized ITC
51 Customer Adv For Cons!
52 Customer Service Deposits
53 Miscellaneous Deductions
54
55 Total Deductions:(8,075,920)89,306 15,271 (116.766)(604,820)
56
57 Total Rate Base:(8,075,920)2,628,361 (28,710)(10,324)(64,154)(126,785)(408,976)
58
59
60 Estimated ROE impact 0.143%-0.046%0.027%0.00%0.011%0.023%-0.323%
61
62
63
64 TAX CALCULATION:
65
66 Operating Revenue 155,768 512 122,324 (1,941,036)
67 Other Deductions
68 Interest (AFUDC)
69 Interest
70 Schedule 'M' Additions 2,559,438 12,350 (116,088)659,118
71 Schedule "M' Deductions 23,839,299 (30,766)
72 Income Before Tax (21,279,861 )472,884 512 6,236 (1,281.918)
73
74 State Income Taxes (966,106)21,469 23 283 (58,199)
75
76 Taxable Income (20,313,755)451,415 489 5,953 (1,223,719)
77
78 Federal Income Taxes (7,109,814)157,995 171 2,084 (428,302)
Rocky Mountain Power
Idaho General Rate Case - December 2010
Update Cash Working Capital
PAGE 8.1
TOTAL IDAHO
ACCOUNT IY COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Rate Base:
Cash Working Capital CWC 1 (77,256)ID Situs (77,256)
Cash Working Capital CWC 2 34,278 ID Situs 34,278
Cash Working Capital CWC 3 28,435 ID Situs 28,435
Total (14,544)(14,544)
Adjustment Detail:
Type1 Type 2 Type 3
O&M Expense 162,642,956 162,889,231 176,201,098 1.3
Taxes Other Than Income Tax 6,417,971 6,417,971 7,183,133 1.3
Federal Income Tax (27,655,564 )(25,538,278)(36,068,197)1.3
State Income Tax (3,319,026)(3,031,322)(4,379,078)1.3
Less: Embedded Cost Differential 140,419 140,419 140,419
Total 138,226,756 140,878,021 143,077,375
Divided by Days in Year 365 365 365
Average Daily Cost of Service 378,703 385,967 391,993
Net Lag Days 4.72 4.72 4.72
Cash Working Capital 1,787,100 1,821,377 1,849,812
Unadjusted Cash Working Capital 1,864,356 1,787,100 1,821,377
Cash Working Capital Adjustment (77,256)34,278 28,435
Description of Adjustment:
This adjustment is necessary to compute the cash working capital for the normalized results made in this filing. Cash working
capital is calculated by taking total operation and maintenance expense allocated to the jurisdiction 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 2010
Trapper Mine Rate Base
TOTAL IDAHO
ACCOUNT Type COMPANY FACTOR FACTOR % ALLOCATED REF#
Adjustment to Expense:
Other Tangible Property 399 1 11,675,959 SE 6.341%740,375 Below
Other Tangible Property 399 3 (1,136,102)SE 6.341%(72,041)Below
Total 10,539,857 668,335 Below
Final Reclamation Liabilty 2533 3 (256,021)SE 6.341%(16,234)8.2.2
Adjustment Detail
Deè 2010 Year End Balance
Dec 2011 Year End Balance
Adjustment to Dec 2011 YE Balance
11,675,959
10,539,857
(1,136,102)
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 the rate base. This adjustment reflects net plant to recognize
the depreciation of the investment over time. This adjustment also walks forward the Reclamation liabilty through December
2011. This adjustment was included in Case No. PAC-E-10-07.
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Rocky Mountain Power
Idaho General Rate Case. December 2010
Jim Bridger Mine Rate Base
PAGE 8.3
Adjustment Detail
Dec 2010 Balance
Dec 2011 Balance
Adjustment to Dec 2011 Balance
176,566,399
184,692,815
8,126,416
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 BCC 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. This adjustment was included in Case No. PAC-E-10-07.
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Rocky Mountain Power
Idaho General Rate Case - December 2010
Environmental Settlement (PERCO)
PAGE 8.4
Adjustment to Rate Base:
Unspent Environmental Proceeds
at December 2010
TOTAL
ACCOUNT Type COMPANY FACTOR
IDAHO
FACTOR % ALLOCATED REF#
25399 (3,888,236)SO 5.794%(225,294) 8.4.2
225,294 8.4.2
8.4.2
Adjust to Dec 2011 Unspent Proceeds 25399
Unspent Environmental Proceeds December 2011
3 3,888,236 SO 5.794%
Description of Adjustment:
The Company received an insurance settlement of $38 millon 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. The Company expects these proceeds to
be exhausted during 2011.
Rocky Mountain Power
Idaho General Rate Case - December 2010
PacifiCorp Environmental Remediation Co.
Spending by Environmental Project
Site WBS
American Barrel PERC/1997/E/001
Astoria I Unocal PERC/1997/E1002
Eugene - PacifiCorp PERC11997/E1003
Everett - PacifiCorp PERC/1997/E1004Jordan I Barber Tar PERC/1997/E1005Ogden PERC/1997/E/006Tacoma A Street PERC/1997/E/007
Tacoma River Street PERC/1997/E1008
Bridger GW Sampling PERC/1997/E/009Bridger Landfill Repermitting PERC/1997/E/010
Bridger Oil Spil PERC11997/E1011
Carbon Fuel Oil PERCI1997/E/012Carbon Landfill Permit PERC/1997/E1013
Carbon Emerg. Gen. Remediation PERC/1997/E/014
Centralia Heavy Equipment Shop PERC/1997/E/013Dave Johnston GW Sampling PERC/1997/E/016
Dave Johnston Landfill Repermit PERC/1997/E/017
Dave Johnston Diesel Release PERC/1997/E1018
Dave Johnston Landfill Closure PERC/1997/E1019
Dave Johnston Landfill Reclamation PERC/1997/E1020
Farm GW Monitoring - Hunter PERC/1997/E1021
Farm GW Monitoring - Huntington PERC/1997/E/022Hunter Fuel Oil PERC/1997/E/023Hunter Injection Wells PERC/1997/E/024
Hunter Landfill Permit PERC/1997/E1025 .
Huntington Injection Wells PERC/1997/E1026Huntington Landfill Closure PERC/1997/E1027Huntington Landfill Permit PERC/1997/E1028
Huntington Lead Paint Removal PERC/1997/E1029
Huntington Wellhead Protection PERC/1997/E1030Buried Pitch PERC/1997/E1031Tank Farm PERC/1997/E/032
Naughton FGD Pond Closure PERC/1997/E/033
Naughton GW Monitoring PERC/1997/E/034Naughton Landfill Repermit PERCl1997/E1035
Naughton Landfill Closure PERC11997/E1036
Wyodak Pond Study PERC/1997/E1037Wyodak Fuel Oil PERC/1997/E/038
Bank Stabilzation & Restoration PERC/1997/E1039
Restore River Embankments PERC/1997/E/040Cutler PERC/1997/E/041
Bank Stabilzation & Restoration PERC/1997/E/042
Merwin Hatchery Fix Erosion Problems PERC/1997/E/044
Speelyai Hatchery Stabilze River Bank PERC/1997/E1045
No. Umpqua Erosion Repairs PERC/1997/E1046
Klamath River Domestic Water Studies PERC/1997/E1048
Big Fork Flowline Repairs PERC/1997/E1050
No. Umq Remove Contaminated Soils PERC/1997/E1052
Rogue River Domestic Water Studies PERC/1997/E/053UST Removal PERC/1997/E/054
Lead Paint Removal PERC/1997/E/055Annex i PERC/1997/E/056Cedar Diesel PERC/1997/E1057
Holiday Gun Club PERC/1997/E1058
Jordan Substation PERC11997/E1059
Montague Ranch PERC/1997/E/060
Ross Island Tower Clean-up PERC/1997/E/061
Spill Prevention, Containment and Countermeas PERC/1997/E/062
Ashton Substation PERC/1997/E/070
Rock Springs Plant Substation PERC/1997/E/071
Sinclair Substation PERC/1997/E1072
Cash RemainingReceived Cash at
1996 & after Dec 31,2010
ProForma
Spending
CY 2011
151,916
664,285
344,354
.393,285
170,956
193,092
19,538
34,191
19,538
38,099
249,107
14,653
170,956
Remaining
Cash at
Dec31,2011
Page 8.4.1
Rocky Mountain Power PAGE 8.5
Idaho General Rate Case. December 2010
Customer Advances for Construction
TOTAL IDAHO
ACCOUNT Iï COMPANY FACTOR.FACTOR %ALLOCATED REF#
Adjustment to Rate Base:
Customer Advances 252 (13,365)CA Situs 8.5.1
Customer Advances 252 (3,729)ID Situs (3,729)8.5.1
Customer Advances 252 (399,519)OR Situs 8.5.1
Customer Advances 252 725,969 UT Situs 8.5.1
Customer Advances 252 (376,301)WA Situs 8.5.1
Customer Advances 252 (12,721 )WY Situs 8.5.1
Customer Advances 252 5,545,304 WY Situs 8.5.1
Customer Advances 252 (5,465,639)SG 6.052%(330,807)8.5.1
(334,536)
Description of Adjustment:
Customer advances for construction are booked intoFERC Account 252. When they are booked, the entries do not reflect the
proper allocation. This adjustment corrects the allocation.
Rocky Mountain Power
Idaho General Rate Case - December 2010
Customer Advances for Construction
YEAR I END BASIS:
Account
252CA
2521DU
2520R
252UT
252WA
252WYP
252WYU
252NUTIL
252SG
Total
Booked Allocation
(6,353)
(350,352)
(119,646)
(3,540,158)
(4,381 )
(969,541)
(5,545,304)
2,664
(7,959,228)
(18,492,298)
Page 8.5.1
Correct Allocation
(19,718)
(354,081)
(519,164)
(2,814,189)
(380,682)
(982,261)
Adjustment Ref.
(13,365) Page 8.5
(3,729) Page 8.5
(399,519) Page 8.5
725,969 Page 8.5
(376,301) Page 8.5
(12,721) Page 8.5
5,545,304 Page 8.5
(0) Page 8.5
(5,465,639) Page 8.5
2,664
(13,424,867)
(18,492,298)
Rocky Mountain Power PAGE 8.6
Idaho General Rate Case.December 2010
Major Plant Additions
TOTAL IDAHO
ACCOUNT ~COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Rate Base:
Steam Production 312 3 478,071,983 SG 6.052%28,935,270
Hydro Production 332 3 17,582,471 SG-P 6.052%1,064,178
Hydro Production 332 3 8,038,710 SG-U 6.052%486,542
Transmission 355 3 151,200,786 SG 6.052%9,151,416
Mining Plant 399 3 16,630,298 SE 6.341%1,054,531
Intangible Plant 303 3 14,034,863 SG 6.052%849,459
Total 685,559,110 41,541,396 8.6.2
Description of Adjustment:
This adjustment places into rate base the major plant additions for calendar year 2011. Major plant additions include individual
projects valued at $5 millon 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 2010
Tax Impacts of Major Plant Additions
TOTAL IDAHO
ACCOUNT ~COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment To Tax:
Schedule M Additions SCHMAT 3 581,567 SE 6.341%36,877
Schedule M Additions SCHMAT 3 41,465,985 SG 6.052%2,509,726
Schedule M Additions SCHMAT 3 (17,553)SO 5.794%(1,017)
Schedule M Additions SCHMAT 3 124,938 OR Situs
Schedule M Additions SCHMAT 3 110,047 UT Situs
Schedule M Additions SCHMAT 3 13,852 ID Situs 13,852
Schedule M Additions SCHMAT 3 183,433 WY Situs
Schedule M Deductions SCHMDT 3 15,725,233 SE 6.341%997,141
Schedule M Deductions SCHMDT 3 377 ,400,859 SG 6.052%22,842,158
Deferred Tax Expense 41110 3 (220,710)SE 6.341%(13,995)DeferredTax Expense 41110 3 (15,736,756)SG 6.052%(952,466)Deferred Tax Expense 41110 3 6,662 SO 5.794%386
Deferred Tax Expense 41110 3 (47,415)OR Situs
Deferred Tax Expense 41110 3 (41,764)UT Situs
Deferred. Tax Expense 41110 3 (5,257)ID Situs (5,257)Deferred Tax Expense 41110 3 (69,615)WY Situs
Deferred Tax Expense 41010 3 5,967,883 SE 6.341%378,425
Deferred Tax Expense 41010 3 143,227,400 SG 6.052%8,668,827
Accum Def Income Tax Balance 282 3 (5,747,173)SE 6.341%(364,430)Accum Def Income Tax Balance 282 3 (127,490,644)SG 6.052%(7,716,361)Accum Def Income Tax Balance 282 3 (6,662)SO 5.794%(386)Accum Def Income Tax Balance 282 3 47,415 OR Situs
Accum Def Income Tax Balance 282 3 41,764 UT Situs
Accum Def Income Tax Balance 282 3 5,257 ID Situs 5,257
Accum Def Income Tax Balance 282 3 69,615 WY Situs
Description of Adjustment:
This adjustment includes the tax impacts of Pro Forma Major Plant Additions Adjustment No. 8.6.
Page 8.6.2
Rocky Mountain Power
Idaho General Rate Case. December 2010
Major Plant Addition Detail. January to December 2011
Jan11 to Dec11 Plant
Project Description Account Factor In-Service Date Additions
Steam Production
Naughton U2 Flue Gas Desulfurization Sys 312 SG Nov-11 151,812,653
Wyodak U1 S02 and PM Emiss Control Upgrade 312 SG Apr-11 103,798,008
Hunter 302 Clean Air - PM 312 SG May-11 53,436,997
Huntington U1 S02 & PM Em Cntrl Upgrades 312 SG Mar11 28,770,137
302 - Hunter U2 S02 Project 312 SG Jul-11 22,521,188
Wyodak U1 - Air Cooled Condenser Replacement 312 SG May-11 21,480,53
Hunter 302 Turbine Upgrade HPIIP/LP 312 SG Apr-11 20,728,107
Jim Bridger U3 S02 & PM Em Cntrl Upgrades 312 SG May-11 17,151,525
Hayden UO Coal Unloading Facilty 312 SG Oct-11 12,329,739
Wyodak U1 OH Clean Air - NOX 312 SG May-11 11,858,187
Naughton U2 NOx LNB - Clean 312 SG Nov-11 9,200,272
Hunter 302 Main Controls Replacement 312 SG Apr-11 7,303,465
Hunter U2 NOx LNB - Clean Air 312 SG May-11 6,246,843
Huntington U2 Boiler Finishing SH Pendants Replacem 312 SG Nov-11 5,920,859
Wyodak U1 -Replacement of Secondary Superheat 312 SG Apr-11 5,513,500
Steam Production Total 478,071,983
Hydro Production
INU 6.1 Lemolo 2 Reroute to Toketee 332 SG-P Dec-11 8,979,199
INU4.1.1 (f)/6.9 Slide Tailrace Barrier 332 SG-P Dec-11 8,603,272
Ashton Dam Seepage Control - Tunnel 332 SG-U Mar-11 8,038,710
Hydro Production Total 25,621,180
Transmission
Red Butte Static Var Compensator and 345 kV Shunt Capacitor 355 SG May-11 46,434,990
Malin 500 kV series cap replacement 355 SG Feb-11 18,700,000
Harry Allen Sub Install Transformer 355 SG Jun-11 15,100,000
Populus-Terminal: Obi Ckt 345 kV TransLn - Transmission 355 SG Nov-10 13,409,213
Populus - Terminal 345 kV line - Borah Reconductor 355 SG Feb-11 13,400,000
Mona - Limber - Oquirrh 500/345 kV line Phases I and II 355 SG Apr.11/May11 8,362,700
Oquirrh New 345-138kV Substation 355 SG Jan-11 6,804,918
Idaho Clearance Issue Corrections 355 SG Jun-11 6,616,683
Dave Johnston - Casper 230 kV Rebuild - #1 Line 355 SG Jan-11 6,127,474
Califomia-Oregon Intertie Upgrade 4800MW Rating 355 SG Jul-11 6,157,000
Skypark: Build New 138-12.5 kV Substation 355 SG Oct-11 5,070,679
Wyoming Clearance Issue Corrections 355 SG Dec-11 5,017,130
Transmission Total 151,200,786
Intangible
TriP II Energy Trading Systems Capital 303 SG Jan11/Aug11 14,034,863
Intangible Total 14,034,863
Mining
Deer Creek-Reconstruct Longwall System 399 SE Apr11/Nov11 16,630,298
Mining Total 16,630,298
685,559,110
Ref# 8.6
2 - Prepaid Overhauls 186M 3 4,513,887 SG 6.052%273,203 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 and transfers of capital to electric plant in service during calendar year 2011 on a year-end basis.
Rocky Mountain Power
Idaho General Rate Case - December 2010
Miscellaneous Rate Base
Year-End Balances - Summary
Page 8.7.1
Dec-2010 Dec-2011 Adjustment
1 - Coal Fuel Stock Balances by Plant Account Factor Balance Balance Per Dec-2011 Bal
Bridger 151 SE 25,002,697 26,759,915 1,757,218
Carbon 151 SE 1,795,661 1,814,196 18,535
Cholla 151 SE 10,178,149 8,Q1,067 (2,167,082)
Colstrip 151 SE 617,748 680,648 62,900
Craig 151 SE 4,432,729 5,198,673 765,944
Hayden 151 SE 1,386,622 1,489,101 102,479
Hunter 151 SE 55,060,900 71,376,781 16,315,880
Huntington 151 SE 24,950,568 28,267,756 3,317,189
Johnston 151 SE 8,131,782 6,097,853 (2,033,928)
Naughton 151 SE 11,705,193 13,504,697 1,799,504
Deer Creek 151 SE 121,017 568,214 447,197
Prep Plant 151 SE 16,841,844 32,836,497 15,994,652
Rock Garden 151 SE 20,951,955 22,401,094 1,449,140
Total 181,176,864 219,006,493 37,829,629
Actuals Pro Forma
To 8.7
Dec-2010 Dec-2011
T Adjustment1 . Workina Caoital Deoosits Balance Balance
I~AMPS Working Capital Deposit
25316 SE (2,263,000)(2,777,000)(514,000)
DPEC Working Capital Deposit 25317 SE (1,849,114'12.023,136\(174,022'
Actuals Pro Forma
To 8.7
To 8.7
Dec-2010 Dec-2011
~r Adjustment2 - Overhaul Preoavments bv Plant Account Balance Balance
irke Side
186M SG 14,720,749 11,266,265 (3,454,484)
Chehalis 186M SG 5,777,606 9,345,399 3,567,793
Currant Creek 186M SG 5,465,610 9,866,187 4,400,578
Total 25,963,965 30,477 ,851 I 4,513,887
Actuals Pro Forma
To 8.7
Rocky Mountain Power PAGE 8.8
Idaho General Rate Case. December 2010
Powerdale Hydro Removal
TOTAL IDAHO
ACCOUNT ~COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Rate Base:
Remove O&M Expense 535 3 (6,385)SG-P 6.052%(386)
537 3 (10,783)SG-P 6.052%(653)
539 3 (41,983)SG-P 6.052%(2,541)
542 3 (688)SG-P 6.052%(42)
543 3 (249)SG-P 6.052%(15)
545 3 (6,790)SG-P 6.052%(411 )
(66,877)(4,048)8.8.1
Remove Booked Amortization 407 3 (2,860,972)SG-P 6.052%(173,160)8.8.1
Decommissioning Reg Asset:
Decommissioning Amortization 4041P 3 354,229 SG-P 6.052%21,440 8.8.3
Decommissioning Reg Asset 182M 3 3,085,497 SG-P 6.052%186,749 8.8.3
Remove Booked Decom Reg Asset 182M 3 (304,766)ID Situs (304,766)B.16
Schedule M - Decommissioning SCHMAT 3 308,029 SG 6.052%18,643
Deferred Income Tax Expense 41110 3 (116,900)SG 6.052%(7,075)
Year End AD IT Balance 283 3 (1,170,977)SG 6.052%(70,873)
Schedule M - Decommissioning SCHMAT 3 (103,976)SG 6.052%(6,293)
Deferred Income Tax Expense 41110 3 39,460 SG 6.052%2,388
Year End ADIT Balance 283 3 735,526 SG 6.052%44,518
Schedule M - Decommissioning SCHMDT 3 (304,766)ID Situs (304,766)
Deferred Income Tax Expense 41010 3 (115,662)ID Situs (115,662)
Year End ADIT Balance 283 3 115,662 ID Situs 115,662
Descriptionot 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, decommissioning costs are deferred as they are spent and amortized over ten years, beginning
in the subsequent year after they are spent. The decommissioning of the plant was substantially complete by the end of 2010.
Rocky Mountain Power
Idaho General Rate Case - December 2010
Powerdale Removal
Powerdale Amortization
Operation & Maintenance Expense
Description
Operation & Maintenance Expense
Hydraulic Expense
Misc. Hydro Expense
Maintenance of Structures
Maintenance. of Dams and Waterways
Maintenance of Misc. Hydro Plant
Unrecovered Plant Amortization Expense
Date
Jan 2010
Feb 2010
Mar 2010
Apr 2010
May 2010
June 2010
July 2010
Aug 2010
Sept 2010
Oct 2010
Nov 2010
Dec 2010
Total
Account
535
537
539
542
543
545
Amortization
289,997
289,997
289,997
221,220
221,220
221,220
221,220
221,220
221,220
221,220
221,220
221,220
2,860,972
Ref 8.8
Factor
SG-P
SG-P
SG-P
SG-P
SG-P
SG-P
12 Months Ended
Dec 2010 Expense
6,385
10,783
41,983
688
249
6,790
66,877
Ref 8.8
Page 8.8.1
Rocky Mountain Power
Idaho General Rate Case - December 2010
Powerdale Removal
Year-End
Unrecovered Plant Amortization Schedule:
Beg Balance
Amort May 07 - Dec 07
Balance Remaining to Amortze
Monthly Amort Exp
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-08
Aug-08
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-09
Oct-09
Nov-09
Dec-09
Jan-10
Feb-10
Mar-10
Apr-10
May-10
Jun-10
Jul-10
Aug-10
Sep-10
Oct-10
Nov-10
Dec-10
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
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
Page 8.8.2
8,796,061
(832,136)
7,963,925
221,220
Balance
8,692,044
8,588,027
8,484,010
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
2,875,862
2,654,642
2,433,422
2,212,201
1,990,981
1,769,761
1,548,541
1,327,321
1,106,101
884,881
663,660
442,440
221,220
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Rocky Mountain Power
Idaho General Rate Case. December 2010
Goose Creek Transmission
PAGE 8.9
Adjustment to Rate Base:
Remove Future Retirement:
Transmission Plant In Service 350 (422,880)SG 6.052%(25,595)8.9.1
Accum. Provo for Depr 108TP 252,314 SG 6.052%15,271 8.9.1
Adjustment to Depreciation Expense:
Depreciation Expense 403TP (8,465)SG 6.052%(512)8.9.1
TOTAL
ACCOUNT ~ COMPANY FACTOR
IDAHO
FACTOR % ALLOCATED REF#
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-of-way associated with the transmission line. The sale of the
transmission line resulted in the Goose Creek switching station no longer being useful to the Company. Per the ECAM Order
No. 30904, the Company wrote off the gain associated with the Goose Creek sale in September 2009.
Rocky Mountain Power
Idaho General Rate Case - December 2010
Goose Creek Transmission Sale
Rate Base (Assets Retired)
Switching Station
Switching Station Accum Depr
Switching Station Book Value
Depreciation Expense
FERC Acct
350
108TP
Factor
SG
SG
Page
Balance
Dec 2010
422,880
(252,314)
170,566
8.9.1
Reference
Page 8.9
Page 8.9
12 Months Ended
FERC Acct Factor Dec 2010403TP SG 8,465 Page 8.9
Rocky Mountain Power
Idaho General Rate Case. December 2010
FERC 105 (PHFU)
PAGE 8.10
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 Utilities Commission"
section 61-502A.
Page 8,10,1
Rocky Mountain Power
Idaho General Rate Case - December 2010
FERC 105 (PHFU)
From BW Report (SAP)
Primary Account .Secondary Account Alloc Total
1050000 EL PL T HLD FTR USE 3400000 LAND AND LAND RIGHTS SG $8,923
1050000 EL PL T HLD FTR USE 3500000 LAND AND LAND RIGHTS SG $156
1050000 EL PL T HLD FTRUSE 3501000 LAND OWNED IN FEE SG $169
1050000 EL PL T HLD FTR USE 3501000 LAND OWNED IN FEE UT $0
1050000 EL PL T HLD FTR USE 3601000 LAND OWNED IN FEE OR $4,254
1050000 EL PL T HLD FTR USE 3601000 LAND OWNED IN FEE UT $2,827
1050000 EL PL T HLD FTR USE 3601000 LAND OWNED IN FEE SG $396
1050000 EL PL T HLD FTR USE 3992200 LAND RIGHTS SE $953
Overall Result (000'5)$17,678
SG
SE
UT
OR
Total:
9,644,350
953,014
2,826,679
4,254,106
17,678,149 Ref. 8.10
Rocky Mountain Power PAGE 8.11
Idaho General Rate Case -December 2010
Trojan Unrecovered Plant
TOTAL IDAHO
ACCOUNT Type COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Expense - Trojan Unrecovered Plant:
Remove amortization expense
from base period 407 3 (809,968)TROJP 6.096%(49,378) 8.11.1
Adjustment to Rate Base. Trojan Unrecovered Plant:
Remove accumulated amortization
from base period 18222 3 15,147,037 TROJP 6.096%923,412 8.11.1
Remove unrecovered plant
from base period 18222 3 (15,211,535)TROJP 6.096%(927,344) 8.11.1
Adjustment to Expense - Trojan Decommissioning:
Remove amortization expense
from base period 407 3 (1,196,558)TROJP 6.096%(72,946) 8.11.2
Adjustment to Rate Base - Trojan Decommissioning:
Remove accumulated amortization
from base period 18222 3 17,880,828 TROJD 6.104%1,091,457 8.11.2
Remove unrecovered plant
from base period 18222 3 (17,980,541)TROJD 6.104%(1,097,544) 8.11.2
Adjustment to Tax:
Schedule M Adjustment SCHMAT 3 (1,901,813)TROJD 6.104%(116,088)
Deferred Income Tax Expense 41110 3 721,757 TROJD 6.104%44,057
ADIT Balance 190 3 (1,912,923)TROJD 6.104%(116,766)
Description of Adjustment:
Amortization of Trojan Regulatory assets wil expire during the pro forma period. This adjustment removes the rate base and
amortization from unadjusted results.
Rocky Mountain Power
Idaho General Rate Case. December 2010
Trojan Amortization. Idaho
Unrecovered Plant
Account 185802
Beg Balance Adjustment
2010 January (14,326,270)February (14,394,368)March (14,462,465)
April (14,530,562)May (14,598,660)June (14,666.757)
July (14.734,854)August (14,802,951)
September (14,871,049)
October (14,939,146) (10.799) (1)November (15,018,042)
December (15,082,540)
Base Period Amortization Expense =
2011 January
February
March
April
May
June
July
August
September
October
November
December
(15.147,037)
(1) Trojan Water Rights sale
185801 Balance =-
Amortization
(68,097)
(68.097)
(68.097)
(68.097)
(68.097)
(68,097)
(68,097)
(68,097)
(68,097)
(68,097)
(64,498)
(64,498)
809,968
Ref 8.11
(64,498)
15,211,535 Ref 8.11
End Balance
( 14,394.368)
(14,462.465)
(14,530.562)
(14,598,660)
(14.666,757)
(14,734,854)
(14,802,951 )
(14,871,049)
(14,939,146)
( 15.018.042)
(15,082.540)
(15,147,037) Ref8.11
(15.211,535)
(15,211,535)
(15,211,535)
(15.211,535)
(15.211,535)
(15.211,535)
(15.211,535)
(15,211.535)
(15,211,535)
(15,211,535)
(15,211,535)
(15,211.535)
Page 8.11.1
Rocky Mountain Power
Idaho General Rate Case. December 2010
Trojan Amortization. Idaho
Decommissioning
Account 185804
185803 Balance =
Beg Balance Amortization2010 January (16,684,270
February (16,783,983March (16,883,696April (16,983,409May (17,083,123June (17,182,836July (17,282,549August (17,382,262September (17,481,975
October (17,581,688November (17,681,401December (17,781,115
Base Period Amortization Expense = 1,196,558
Ref 8.11
)(99,713)
)(99,713)
)(99,713)
)(99,713)
)(99,713)
)(99,713)
)(99,713)
)(99,713)
)(99,713)
)(99,713)
)(99,713)
)(99,713)
2011 January
February
March
April
May
June
July
August
September
October
November
December
(17,880,828)(99,713)
Page 8.11.2
17,980,541 Ref 8.11
End Balance
(16,783,983)
(16,883,696)
(16,983,409)
(17,083,123)
(17,182,836)
(17,282,549)
(17,382,262)
(17,481,975)
(17,581,688)
(17,681,401)
(17,781,115)
(17,880,828) Ref8.11
(17,980,541)
(17,980,541)
(17,980,541)
(17,980,541)
(17,980,541)
(17,980,541)
(17,980,541)
(17,980,541)
(17,980,541)
(17,980,541)
(17,980,541)
(17,980,541)
Rocky Mountain Power PAGE 8.12
Idaho General Rate Case - December 2010
Klamath Hydroelectric Settlement Agreement
TOTAL IDAHO
ACCOUNT IY COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Expense:
Operation & Maintenance 537 3 3,340,008 SG-P 6.052%202,154 8.12.1
Facilties Removal Costs 557 3 17,200,000 10 Situs 975,961
Adjustment to Revenue:
Oregon Customer Surcharge 440 3 15,824,000 OR Situs
California Customer Surcharge 440 3 1,376,000 CA Situs
Adjustment to Rate Base:
Existing Klamath 332 3 3,235,749 SG-P 6.052%195,843 8.12.2
Adjustment to Depreciation Expense:
Existing Klamath 403HP 3 4,331,461 SG-P 6.052%262,161 8.12.2
Klamath Relicensing &
Settlement Process Costs 4041P 3 8,273,613 SG-P 6.052%500,760 8.12.2
Adjustment to Depreciation Reserve:
Existing Klamath 108HP 3 (5,852,160)SG-P 6.052%(354,202) 8.12.2
Klamath Relicensing &
Settlement Process Costs 1111P 3 (8,273,613)SG-P 6.052%(500,760) 8.12.2
Adjustment to Tax:
Schedule M Addition SCHMAT 3 10,890,024 SG 6.052%659,118
Deferred Tax Expense 41110 3 ( 4,132,873)SG 6.052%(250,142)
Accum Def Inc Tax Balance 282 3 4,132,873 SG 6.052%250,142
Description of Adjustment:
This adjustment adds into rate base the Klamath relicensing and settlement procss costs. This adjustment also accelerates the
depreciation associated with the existing Klamath facilities starting in January 1,2011 and finishing by December 31,2019
consistent with the KHSA. The operation and maintenance expense associated with the Klamath project is adjusted to the
December 2011 leveL.
Rocky Mountain Power
Idaho General Rate Case - December 2010
Klamath Hydroelectric Settlement Agreement Adjustment
O&M
12 ME Dec 10 Actuals
IKL IM.12 JCB Bypass Reach/Spencer Creek
IKL IM.5 Iron Gate Flow Variabilty
IKL IM.3 Iron Gate Turbine Venting
IKL IM.15 Water Quality Monitoring
IKL IM.11 Interim Water Quality Improvement
IKL IM.1 0 Water Quality Conference
IKL IM.4 Hatchery and Genetics Mgmt
IKL IM.18 Hatchery Funding2
IKL IM.19a Iron Gate Hatchery Study
IKL IM.21.A BLM Road Maintenance
IKL IM.21.B BLM Weed Management
IKL IM.21.C BLM Cultural Resource Mgmt
IKL.M.21.D BLM Road Management Plan
IKL Ad Hoc Water Qualiy Support
IKL Administration Support
IKL IM.2 Coho Enhancement Fund
IKL IM.7 JC Boyle Gravel/Habitat Enhancement
Klamath Implementation Total
500,155
106,182
100,000
69,108
851,182
15,000
10,000
10,000
110,135
170,889
1,942,652
12 ME Dec 11 Projected
15,000
15,000
1,000
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500,290
555,567
1,279,000
500,000
15,000
10,000
10,000
12,000
4,857
1,182,183
510,020
172,662
5,282,660
Page 8.12.1
Adjustment
15,000
15,000
1,000
(74)
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486,459
427,818
500,000
12,000
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1,011,294
510,020
172,662
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Rocky Mountain Power
Idaho General Rate Case. December 2010
Commission Order in Case No. PAC.E.10.07
(In OOO's)
Approximate
Revenue
Requirement
Impact1
1) Idaho Disconnect Policy
2) Pro Forma Wage Increases
3) Populus to Terminal Transmission Line
4) Fuel Stock
5) MEHC Cross Charge - AlP
(90)
(949)
(1,482)
(249)
(112)
1 Revenue requirement impacts include effects of tax
Page 9.0
The Company has identified various issues addressed by the Idaho Public Utilties Commission in
Case No. PAC-E-lO-07 Order 32196 that are not accounted for in the price change requested in this
case. Page 9.1 provides the details of the items listed above.
Rocky Mountain Power
Idaho General Rate Case - December 2010
Commission Order in Case No. PAC.E.10-Q7
1. Idaho Disconnect Poliey -Include revenue for disconnections with usage exceeding 1,000 kWh. See Order No. 32196
Revenues
Total Company
Adjustment
90,000
2010 ProtocolFactr
10
Idaho's
Percent
100%
2. Pro Fonna Wage Increases - Remove annualized 2009 and 2010 wage Increases per Reconsideration Order No. 32224
Disallowed Wage Increases 2009.2010
Wage Increase Annualization Correction
Total Company
Adjustment
(14,375,075)
(1,660,215)
(16,035,290)
Idaho's Labor
Allocation
5.896%
5.896%
Idaho
Allocaion
(847,576)
(97,889)
(945,465)
Idaho
Allocation
90,000
Populus to Terinal Amount Placed Into Servce Throu9h December 2010:
3. Populus to Tennlnal Transmission Line - Remove 27% of Populus to Terminal capital investment See Order No's. 32196 & 32224
General Plant
Intangible
Transmission
Amount Placed
Into Serice
through
December 2010
13,924,735
4,035,602
777937,466
795,897,804
Populus to Terminal Forecast to be Placed Into Service Through December 2011:
Transmission
Amount Foreast
through
December 2011
13,409,213
Remove 27% of Capital Investment
2010 Transmission Plant Reduction
2011 Transmission Plant Reduction
2010 Protocol Factor
Idaho's Percent
Idaho Allocation
Reduction to
Plant Placed Into
Service
(214,892,407)
(3,620,488)
SG
6.052%
(13,225,476)
Depreciation
Expense CY 2010
236,087
17,545
14,859,552
15,113,184
Depreciation Reserve Dec
2010
(266,375)
(17,545)
(5,44,897)
(5,724,817)
Depreciation
Expense CY 2011
259,689
Depreiation Reserve Dec
2011
(259,689)
Reduction to
Depreiation
Expense
(4,080,560)
(70,116)
SG
6.052%
(251,219)
Reduction to Depreciation
Reserve
1,545,701
70,116
SG
6.052%
97,797
4. Fuel Stock - Transition stock pile increases over a 3 year period. See Order No. 32196
Tax Impact:
ScheduleM
108,034,818
1,830,640
SG
6.052%
6,649,598
Tax Impact:
Defer Income
Tax Exp
(41,000,294)
(694,746)
SG
6.052%
(2,523,589)
Dec-2010 Dec-2011 Order 32196 Balance Adjustment as Adjustent Per
Coal Fuel Stock Balances by Plant Balance Balance Year 2 of Transition Flied Order
Bridger 25,002,697 26,759,915 21,781,78 1,757,218 (3,221,220)Carton 1,795,661 1,814,196 1,977,713 18,535 182,Q2
Cholla 10,178,149 8,011,067 7,782,355 (2,167,082)(2,395,79)
Colstrip 617,748 680,648 640,850 62,900 23,102
Craig 4,432,729 5,198,673 3,148,236 765,94 (1,284,493 )
Hayden 1,386,622 1,489,101 1,847,775 102,479 461,153
Hunter 55,060,900 71,376,781 57,029,612 16,315,880 1,968,712
Huntington 24,950,568 28,267,756 26,806,196 3,317,189 1,855,628
Johnston 8,131,782 6,097,853 5,751,225 (2,033,928)(2,380,557)
Naughton 11,705,193 13,504,697 9,159,486 1,799,504 (2,545,707)Deer Creek 121,017 568,214 894,169 447,197 773,152
Prep Plant 16,841,844 32,836,497 25,850,396 15,994,652 9,008,562
Rock Garden 20,951,955 22,401,094 22,542,451 1,449,140 1,590,496
Total 181,176,864 219,006,493 185,211,942 37,829,629 4,035,078
2010 Protocol Factor SE SE
Idaho's Percent 6.341%6.341%
Idaho Allocation 2,398,786 255,865
5. MEHC Cross Charge. Remove AlP from Cross Charge
Remove AlP from Cross Charge
Total Company
Adjustent
(1,934,864)
2010 Protool
Factr
SO
Idaho's
Percent
5.794%
Idaho
Allocation
(112,111)
Page 9.1
Tax Impact:
Defed Income
TaxBaI
41,000,294
694,746
SG
6.052%
2,523,589
Idaho General Rate Case
December 2010
Year End Factors
Page 10.1
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10
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10
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Use
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Use
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Use
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c
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10
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1

In
t
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Use
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d

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b
t

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Us
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Fix
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9
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Fix
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Fix
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d
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Fix
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1
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12
AL
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S
DECEMBER 2010 FACTORS
Idaho General Rate Case - December 2010
COINCIDENTAL PEAKS
Month
Jan-10
Feb-10
Mar-10
Apr-10
May-10
Jun-10
Jul-10
Aug-10
Sep-10
Oct-10
Nov-10
Dec-10
Month
Jan-10
Feb-10
Mar-10
Apr-10
May-10
Jun-10
Jul-10
Aug-10
Sep-10
Oct-10
Nov-10
Dec-10
Month
Jan-10
Feb-10
Mar-10
Apr.10
May-10
Jun-10
Jul-10
Aug-10
Sep-10
Oct-10
Nov-10
Dec-10
Day Time7 1822 89 191 8
17 15
28 17
16 1717 163 171 16
23 1820 18
Day Time7 1822 89 191 8
17 15
28 17
16 1717 163 171 1623 1820 18
Day Time7 1822 89 191 817 15
28 17
16 1717 163 171 1623 1820 18
I METERED.LOAOS(CPI
I ..,.....'.Non"fERC '..PERC ,..iJ
CA OR WA EWY TotalUT 10 W.WY UT NETUT Total
123 2.129 735 1,092 3,359 470 244 28 3,330 8,152
151 2,359 689 1,072 3,049 442 240 25 3,024 8,002
141 2,171 592 983 3,036 428 223 25 3,011 7,574
144 2,231 621 980 2,717 331 225 27 2,690 7,248
113 1,688 520 930 3,005 452 214 29 2,976 6,922
135 1,986 660 1,022 4,135 660 226 42 4,093 8,824
165 2,200 697 1,057 4,241 628 206 43 4,198 9,194
140 2,345 766 1,035 4,362 520 212 44 4,319 9,382
131 2,144 614 1,009 3,609 469 191 35 3,574 8,168
107 1,689 589 965 3,465 384 227 31 3,434 7,426
157 2,513 809 1,068 3,354 448 243 28 3,326 8,592
144 2,267 702 1,092 3,498 432 241 29 3,469 ,8,377
1,652 25,724 7,994 12,307 41,830 5,663 2,692 387 41,443 97,861
(less)
Adjustments for Curtilments Buy Throughs and Load No Longer Served (Reductions to Load).-
I Non"fERC PERC I
CA OR WA EWY UT 10 W.WY UT NETUT Total
(53)-(53)(53)
----
----
----
----
(101 )-(101)(101)----
(95)-(95)(95)----
----
----
(49)-(49)(49)----(297)---(297)(297)
equals
I ..COINClÐENTALPEAKSER\1ED FRONICONIPANY RESOURCES
i Non-PERC FERC I
CA OR WA EWY UT 10 W.WY UT NETUT Total
123 2,129 735 1,092 3,306 470 244 28 3,278 8,099
151 2,359 689 1,072 3,049 442 240 25 3,024 8,002
141 2,171 592 983 3,036 428 223 25 3,011 7,574
144 2,231 621 980 2,717 331 225 27 2,690 7,248
113 1,688 520 930 3,005 452 214 29 2,976 6,922
135 1,986 660 1,022 4,034 660 226 42 3,992 8,724
165 2,200 697 1,057 4,241 628 206 43 4.198 9,194
140 2,345 766 1,035 4,268 520 212 44 4.224 9,287
131 2,144 614 1,009 3,609 469 191 35 3,574 8,168
107 1,689 589 965 3,465 384 227 31 3,434 7,426
157 2,513 809 1,068 3,354 44 243 28 3,326 8,592
144 2,267 702 1,092 3,449 432 241 29 3,420 8,328
1,652 25,724 7,994 12,307 41,533 5,663 2,692 387 41,146 97,564
+ plus
Adjustments for Ancilary Services Contracts including Reserves and Class 1 DSM Programs Treated As System Resources (Additions to Load)I. Non-PERC PERC IMonth Day Time CA OR WA E. WY UT 10 W, WY UT NET UT Total
Jan-10 7 18
Feb-10 22 8Mar-10 9 19Apr-10 1 8
May-10 17 15
Jun-10 28 17Jul-10 16 17 164 144 164 308Aug-10 17 16 105 105 105
Sep-10 3 17
Oct-10 1 16
Nov-10 23 18
Dec-10 20 18
269 144 269 413
Page 10.13
ALLOCATIONS USING
HISTORICAL LOADS
DECEMBER 2010 FACTORS
Idaho General Rate Case - December 2010
COINCIDENTAL PEAKS
Month
Jan-10
Feb-10
Mar-10
Apr-10
May-10
Jun-10
Jul-10
Aug-10
Serr10
Oct-10
Nov-10
Dec-10
Month
Jan-10
Feb-10
Mar-10
Apr-10
May-10
Jun-10
Jul-10
Aug-10
Sep-10
Oct-10
Nov-10
Dec-10
Month
Jan-10
Feb-10
Mar-10
Apr-10
May-10
Jun-10
Jul-10
Aug-10
Serr10
Oct-10
Nov-10
Dec-10
Day Time7 1822 89 191 8
17 15
28 17
16 17
17 163 171 16
23 18
20 18
Day Time7 1822 89 191 8
17 1528 1716 17
17 163 171 1623 1820 18
Day Time7 1822 89 191 8
17 1528 17
16 17
17 163 171 1623 18
20 18
--equals
I LOAtS FOR JUftlSDICTIONAL ALLOGATION(CP) .PtiQrtö Temperaure MJUstrl't I
i .Non-FERC FERC I
CA OR WA E. WY UT 10 W.WY UT NETUT Total
123 2.129 735 1.092 3.306 470 244 28 3.278 8,099
151 2.359 689 1.072 3.049 442 240 25 3.024 8.002
141 2.171 592 983 3,036 428 223 25 3.011 7.574
144 2.231 621 980 2,717 331 225 27 2.690 7.248
113 1.688 520 930 3,005 452 214 29 2.976 6.922
135 1,986 660 1.022 4.034 660 226 42 3.992 8.724
165 2.200 697 1.057 4,404 772 206 43 4.362 9.502
140 2,345 766 1.035 4.373 520 212 44 4.329 9.392
131 2.144 614 1.009 3.609 469 191 35 3.574 8.168
107 1,689 589 965 3.465 384 227 31 3,434 7.426
157 2.513 809 1.068 3.354 44 243 28 3.326 8.592
144 2.267 702 1.092 3.449 432 241 29 3,420 8.328
1.652 25.724 7,994 12.307 41.802 5.807 2.692 387 41,415 97,977
- less
dA justment or Coincidental System Peaks Temperature Adjustment
I NQn;.FERC FeRC I
CA OR WA E. WY UT 10 W.WY UT NETUT Total
1 (76)(10)-2 0 (3)2 (86)
3 (13)-1 27 2 1 27 22
(0)(2)2 (8)(36)(0)1 (36)(42)
(1)-3 (1 )(60)-(0)(60)(59)
11 207 (15)201 (6)56 (0)(6)455
0 (57)(23)23 108 1 1 108 52
(0)(9)(17)(12)5 5 0 5 (27)
1 1 (8)2 (47)5 1 (47)(44)
(4)--3 85 (9)1 85 76
4 135 (23)6 (102)(8)1 (102)12
3 56 30 (2)55 4 (2)55 144
(3)(16)(5)4 (20)1 1 (20)(36)
15 226 (65)219 12 57 2 -12 467--equals
I NORMALizEDLO~$ FOR JURISDltTDNALAlLOGATION:(I?Et) ...
I NQn-FERC .FERC ..I
CA OR WA E. WY UT 10 W.WY UT NETUT Total
124 2.054 725 1.092 3.308 470 241 28 3.279 8.013
154 2.346 689 1.074 3.076 444 240 25 3.051 8,023
141 2.169 594 975 3.000 428 224 25 2.975 7.532
143 2.231 624 979 2.656 331 225 27 2.629 7.189
124 1.895 505 1.131 2.999 508 214 29 2,970 7.377
135 1,929 637 1.045 4.142 661 227 42 4.100 8.775
165 2,192 680 1.045 4.410 777 207 43 4.367 9,474
142 2,346 758 1.038 4.326 525 213 44 4,282 9,348
128 2,144 614 1.012 3.694 460 191 35 3.659 8,244
111 1.824 565 971 3.364 375 228 31 3,333 7,438
160 2,568 840 1.066 3,410 451 241 28 3,382 8,737
141 2.252 698 1.097 3.429 433 242 29 3.400 8.291
1,667.4 25,950.0 7.929.1 12.525.5 41.813.8 5.863.6 2.694.0 387.3 41,426.5 98.443.4
The December 2010 Results of Operations report were calculated using monthly actual (metered) energy, adjusted to reflect normal temperatures
and class 1 DSM programs.
Page 10.14
ALLOCATIONS USING
HISTORICAL LOADS
DECEMBER 2010 FACTORS
Idaho General Rate Case - December 2010
ENERGY
Year Month
Jan 2010
Feb 2010
Mar 2010
Apr 2010
May 2010
Jun 2010
Jul 2010
Aug 2010
Sep 2010
Oct 2010
Nov 2010
Dec 2010
Year Month
Jan 2010
Feb 2010
Mar 2010
Apr 2010
May 2010
Jun 2010
Jul 2010
Aug 2010
Sep 2010
Oct 2010
Nov 2010
Dec 2010
Year Month
Jan 2010
Feb 2010
Mar 2010
Apr 2010
May 2010
Jun 2010
Jul 2010
Aug 2010
Sep 2010
Oct 2010
Nov 2010
Dec 2010
Year Month
Jan 2010
Feb 2010
Mar 2010
Apr 2010
May 2010
Jun 2010
Jul 2010
Aug 2010
Sep 2010
Oct 2010
Nov 2010
Dec 2010
I METEREPLOADS (MW)..
i .Non-FERC FERC I
CA OR WA E.WY Total UT 10 W.WY UT NetUT Total
80,851 1,305,544 422,795 732,263 2,095,12 295.955 171.058 17.052 2.078.360 5.103,878
71,589 1,156,228 345.538 661,560 1,869,991 263.287 149,608 14.649 1,855.342 4.517.802
76,428 1.234,791 354,934 700,441 1.870,967 272.177 160.493 16.261 1,854.707 4.670.231
74,482 1.149,866 329.525 655,182 1,763,537 259.025 150,196 15.761 1.747.776 4.381,813
75.909 1.106,767 325.368 661,838 1,789,517 297.306 158,055 15.587 1,773.930 4,414,761
79.250 1.061.006 310,849 650,320 2.004,349 332,472 158,565 17,698 1.986,651 4,596.811
89,602 1.246,481 394.267 709,183 2,401,054 501,026 159,457 21,595 2.379,459 5.501,070
85,603 1.226.650 384,810 719,078 2,310,919 362,204 153,502 21,225 2.289.693 5.242.765
70,467 1.088.771 341.096 675,913 1,972,427 281,539 147,499 17,422 1.955.005 4.577712
68,238 1,135,089 358,467 694,977 1,873,734 246,550 170,489 15.602 1,858.132 4,547,544
79,115 1,268.375 402.477 711,023 1,984,787 253,603 167,627 15.854 1,968.933 4,867,007
89,228 1,399.049 445,341 759,014 2,139,002 280,752 167.350 17,550 2,121,452 5,279.736
940,763 14.378,617 4,415,467 8.330.792 24,075,697 3,645,897 1,913.898 206.256 23,869,441 57,701,130
(less)
Adjustments for Curtilments Buy-Throughs and Load No Longer Served (Reductions to Load),
I Non.FERC FERC I
CA OR WA E. WY UT 10 W,WY UT NETUT Total
(5,612).(5,612)(5,612)
---.
---.
----
----
(2.357)-(2.357)(2.357)
(5.777)-(5,777)(5.777)
(3.495)-(3,495)(3,495)
(4.113)-(4.113)(4,113)-.-
----
(7,103)-(7.103)(7.103).-.-(28,456).--(28.456)(28,456)
equals
I LOAQS SERVED FRCJllÇONllANYRESOURCES.(NPÇ)
i Non-FERC FERC I
CA OR WA E. WY UT ID W.WY UT NetUT Total
80.851 1,305.544 422,795 732.263 2.089,801 295,955 171.058 17,052 2,072,749 5.098,266
71.589 1.156.228 345,538 661.560 1,869.991 263,287 149,608 14,649 1,855.342 4.517,802
76,28 1,234,791 354,934 700.441 1.870.967 272.177 160,493 16,261 1,854.707 4.670.231
74,482 1,149,866 329,525 655.182 1.763,537 259,025 150,196 15,761 1,747.776 4.381.813
75,909 1,106,767 325,368 661.838 1,789,517 297,306 158.055 15,587 1,773.930 4,414.761
79.250 1,061,006 310,849 650.320 2.001,992 332,472 158,565 17,698 1,984.294 4.594,454
89,602 1,246,481 394,267 709.183 2.395,277 501,026 159,457 21,595 2,373,682 5.495,293
85.603 1,226.50 384,810 719.078 2.307,424 362,204 153,502 21,225 2,286.198 5,239.270
70,467 1,088,771 341,096 675,913 1.968,314 281.539 147,499 17,422 1,950,892 4.573.600
68,238 1,135,089 358,67 694,977 1.873.734 246.550 170,489 15,602 1,858.132 4,547.544
79,115 1,268,375 402,477 711.023 1.984.787 253.603 167,627 15.854 1.968,933 4.867.007
89,228 1,399.049 445.341 759.014 2.131.899 280.752 167,350 17,550 2.114.349 5,272.633
940.763 14,378,617 4,415,67 8,330,792 24.047.241 3.645.897 1.913,898 206,256 23,840.985 57,672,674
+ plus
Adjustments for Ancilary Services Contracts Including Reserves (Additions to Load)
I Non-FERC FERC I
CA OR WA E.WY UT ID W,WY UT NetUT Total
109 197 109 305
125 -125 125
193 496 193 689
28 122 28 150
552 348 552 900
185 108 185 293
799 2,434 799 3.233
424 2.018 424 2.44
104 204 104 308
245 40 245 284
842 554 842 1.396
89 3 89 92
--.-3.694 6.523 -.3,694 10.217
i-ageiu,'io
ALLOCATIONS USING
HISTORICAL LOADS
DECEMBER 2010 FACTORS
Idaho General Rate Case - December 2010
ENERGY
Year Month
Jan 2010
Feb 2010
Mar 2010
Apr 2010May 2010
Jun 2010
Jul 2010
Aug 2010
Sep 2010
Oct 2010
Nov 2010
Dec 2010
Year Month
Jan 2010
Feb 2010
Mar 2010
Apr 2010May 2010
Jun 2010
Jul 2010
Aug 2010
Sep 2010
Oct 2010
Nov 2010
Dec 2010
Year Month
Jan 2010
Feb 2010
Mar 2010
Apr 2010
May 2010
Jun 2010
Jul 2010
Aug 2010
Sep 2010
Oct 2010
Nov 2010
Dec 2010
--equals
I NCJRMALIZi:P ..LQADS.&eRv.EPI5RQMGQMPAN¥Ri:SQQRGi:S...(NPG)~PÎ"i~Î"t().'Tltr~ra1lJl1..Acljuštrilnt .....1ii.........tlQn+FERC .c/./c.FERC i./i..c ...C.cC. J
CA OR WA E. WY UT ID W.WY UT UT Total
80,851 1,305,544 422,795 732,263 2,089,909 296,152 171,058 17,052 2,072,857 5,098,572
71,589 1,156,228 345,538 661,560 1,870,116 263,287 149,608 14,649 1,855,467 4,517,926
76,428 1,234,791 354,934 700,441 1,871,160 272,673 160,493 16,261 1,854,899 4,670,920
74,482 1,149,866 329,525 655,182 1,763,566 259,147 150,196 15,761 1,747,804 4,381,963
75,909 1,106,767 325,368 661,838 1,790,070 297,655 158,055 15,587 1,774,482 4,415,661
79,250 1,061,006 310,849 650,320 2,002,177 332,580 158,565 17,698 1,984,479 4,594,746
89,602 1,246,81 394,267 709,183 2,396,076 503,460 159,457 21,595 2,374,481 5,498,526
85,603 1,226,650 384,810 719,078 2,307,848 364,222 153,502 21,225 2,286,623 5.241,713
70,467 1,088,771 341,096 675,913 1,968,418 281,743 147,499 17,422 1,950,996 4,573,908
68,238 1,135,089 358,67 694,977 1,873,979 246,590 170,489 15,602 1,858,377 4,547,828
79,115 1,268,375 402,477 711,023 1,985,629 254,156 167,627 15,854 1,969,775 4,868,403
89,228 1,399,049 445,341 759,014 2,131,988 280,755 167,350 17,550 2,114,438 5,272,725
940,763 14,378,617 4,415,467 8,330,792 24,050,935 3,652,420 1,913,898 206,256 23,844,679 57,682,891
- less
Temperat re Adustment for EnerguJY
I Nón-ERC FERC I
CA OR WA E.WY UT ID W.WY UT UT Total
6,765 88,506 26,133 1,540 (13,029)2,258 287 (13,029)112,461
2,438 44,876 21,888 (3,703)11,546 (1,732)(689)11,546 74,623
(103)3,742 8,35 2,786 (2,812)(649)532 (2,812)11,931
(1,547)(21,071)2,161 (1,629)(7,553)(1,122)(253)(7,553)(31,013)
(204)(5,442)2,866 (3,650)81,200 20,222 (668)81,200 94,323
687 23,554 7,048 2,959 38,258 6,284 187 38,258 78,976
(409)(1,523)(7,029)1,815 (15,116)4,482 109 (15,116)(17,671)
151 12,497 (1,435)(2,270)23,964 4,598 (131)23,964 37.374
387 17,875 5,092 4,415 (10,395)(1,091)485 (10,395)16,767
1,005 15,792 5,960 6,535 5,306 (2,545)1,177 5,306 33,230
(945)(24,681)(12,364)(3,422)(18,088)(2,350)(668)(18,088)(62,519)
4,148 43,448 10,210 2,606 25,215 4,771 491 25,215 90,889
12,373 197,571 68,964 7,982 118,497 33,126 858 -118,497 439,372--equals
I NORMALIZED LOAD& FOR JURISDICTIONAL ALLOCATlCJ"'.~N1V')
I Non-FERC FERC J
CA OR WA E. WY UT ID W.WY UT UT Total
87,616 1,394,049 448,928 733,803 2,076,881 298,410 171,345 17,052 2,059,829 5,211,033
74,027 1,201,104 367,426 657,857 1,881,662 261,555 148,919 14,649 1,867,013 4,592,549
76,324 1,238,532 363,369 703,228 1,868,348 272,025 161,025 16,261 1,852,087 4,682,851
72,935 1,128,795 331,686 653,553 1,756,013 258,025 149,943 15,761 1,740,252 4,350,951
75,706 1,101,325 328,233 658,188 1,871,270 317,876 157,387 15,587 1,855,683 4,509,984
79,937 1,084,560 317,897 653,279 2,040,434 338,863 158,752 17,698 2,022,737 4,673,722
89,194 1,244,957 387,239 710,998 2,380,960 507,942 159,565 21,595 2,359,365 5,480,855
85,754 1,239,147 383,375 716,808 2,331,812 368,820 153,372 21,225 2,310,586 5,279,087
70,854 1,106,646 346,188 680,329 1,958,023 280,652 147,984 17,422 1,940.602 4,590,674
69,243 1,150,881 364,427 701,512 1,879,285 244,045 171,666 15.602 1,863,683 4,581,059
78,170 1,243,694 390,113 707,600 1,967,541 251,806 166,959 15,854 1,951,687 4,805,884
93,376 1,442,496 455,551 761,620 2,157,202 285,27 167,841 17.550 2,139,652 5,363,614
953,136 14,576,188 4,484,430 8,338,774 24,169,431 3,685,546 1,914,757 206,256 23,963,176 58,122,263
Page 10.16
ALLOCATIONS USING
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Page 10.19
IDAHO
ANNUAL EMBEDDED COSTS
Oecember-10
YEAR END BALCE
Company Owed Hydro. Weal
Account Description Amount Mw $IMw Differential Reference
_ 535 - 545 Hydro Operation & Maintenanc Expense 35,335,931 Page 2.7, Wea only
403HP Hyro Depreciation Expens 16,093,461 Page 2.15, Wea only
4041P Hydro Relicensing Amortization 11,243,361 Page 2.16, Wea only
Total West Hydro Operating Expense 62.672.793
330 - 336 Hydro Electric Plant in Service 546,610,977 Page 2.23, West only
302 & 162M Hydro Relicensing 176,713,753 Page 2.29, Wea only106HPHydro Accmulated Depreciation Resrve (214,181.594)Page 2.36, West only
1111P Hydro Relicensing Accumulated Reserve (22,343,503)Page 2.39, We.t only
154 Materials and Supplies (1,86)Page 2.32, Wea only
Weat Hydro Net Rate Ba..48.797.773
Pre-tax Return 11.62%
Rate Ba.. Revenue Requirement 56.779,907
Annual Embedded Coat
W.atHydro-Electric Resource.119.452,700 3,657.380 32,66 (38,406,980) MWh from GRID
Mid C Contract
Account Description Amount Mw $IMw Dlfrential Reference
555 Annual Mid.C Contracts Costs 18,68,110 98,667 19.37 (22,981,525) GRIDGrant Reasonable Portion (8.442,417)(8.442,417) GRID10,242,693 (31,403,942)
Qualified F aeilitie.
Account DeSCription Amount Mw $IMw Differential Reference
555 utah Annual Qualified Facllities Costs 25,980,876 404,403 84.25 8,525,956
555 Oregon Annual Qualified Facilities Costs 38,424,90 214,130 170.11 27,182,587
555 Idaho Annual Qualified FacUlties Costs 4,197,547 75,820 55.36 924,99
555 WYU Annual Qualified Facilities Costs
555 WYP Annual Qualified Facilties Cos 751,874 11,378 86.08 280,775
555 California Annual Qualified Facilties Costs 4,077,96 33,552 121.54 2,629,787
555 Washingon Annual Qualified Facilities Coss 1,98,329 13,070 151.62 1,420,199
Total Qualified Facilties Coss 73,417,500 752,353 --40,94,293 GRID
All other Generation Re80urcs
(Excl. Wea Hydro, Mid C, .nd OF)
Account Description Amount Mw $IMw Reference
500 - 514 Steam Operaion & Maintenance Expense 1,030,765,602 Pago 2.5535.545 Eas Hydr Operaion & Maintenance Expens 8.880,047 Page 2.7, Eea only
546 - 554 Other Generaion Operation & Maintenance Expe 45,816,805 Page 2.8555Other Purcas Power Contracts 488,132,509 GRID les OF .nd Mid-e
40910 Renewble Energy Production Tax Credit (112,981,523)Pago 2.20
4118 802 Emision Allowances (8,261,058)Page 2.4
456 James River I Litle Mountain Offse (8,328,081)J.mes River Adj (Teb 5)456 Green Tag Reven (78,842,87)Gre Tag (Tab 3)403SP Steam Depreation Expens 138,882,45 Page 2.15
403HP Eas Hydro Deprecation Expens 4,783,679 Page 2.15, Eas only
4030P Other Generation Deprecation Expens 115,463,298 Page 2.15
403MP Mining Depreciation Expense 0 Pago 2.16
4041P East Hydro RelicensingAmortization 111.266 Page 2.16, Eas only
406 Amortization of Plant Acquisition Costs 5,518,393 Page 2.17
Total All Other Operating Expenses 2,037,940.627
310- 316 Steam Electric Plant in SelviC8 6.363,016,861 Page 2.21
330 - 336 Eas Hydro Electric Plant in Service 138,884,018 Page 2.23, Eea only
302 & 186M Eas Hydro Relicensing 9,841,735 Page 2.29, Eas only340- 346 Other Electric Plant in Service 3,298,635,309 Pag.2.24
399 Mining 486,014,280 Pag.2.28
106SP Steam AccmuJated Depriation Reserve (2,511,683,290)Pago 2.36
1080P Oter Generation Accumulated Deprecation Resrve (366,306,227)Page 2.36
108MP Other Accumulated Depreciation Reserve (155,693,803)Page 2.38, Eas only
10BHP East Hydro Accmulated Deprecation Resrve (46,707,54)Page 2.36, East only
1111P Eas Hydro Relicensing Accmulated Resrve (3,770,485)Page 2.39. E.st only
114 Electric P.lant Acquisition Adjustment 159.175,508 Page 2.31
115 Accmulated Provision Acquisition Adjustmen (101,84,265)Page 2.31
151 Fuel Stock 226.322,717 Page 2.32
253.16-253.19 Joint Ower WC Depsi (5.073,136)Page 2.32
253.98 502 Emission Allowances (24,783,174)Page 2.34
154 Materials & Supplies 84,929,002 Page 2.32
154 East Hydro Materials & Supplies
Total Net Rate Siae 7,527,156.506
Pre-tax Return 11.2%Rate Base Revenue Requirement 874,372,335
Annual Embedded Coat
All Other Generation Resourços 2,912,312.962 67,473,698 43.16 MWh from GRID
Total Annual Embedded Costs 3,115.425.855 72.84.297 42.71
Rocky Mountain Power
RESULTS OF OPERATIONS
Page 11.1
USER SPECIFIC INFORMATION
STATE:
PERIOD:
IDAHO
DECEMBER 2010
FILE:
PREPARED BY:
DATE:
TIME:
JAM Dec 2010 10 GRC
Revenue Requirement Department
5/18/2011
10:29:43 AM
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
47.40%
0.30%
52.30%
100.00%
5.78%
5.43%
10.50%
2.740%
0.016%
5.492%
8.248%
OTHER INFORMATION
For information and support regarding capital structure and cost of debt, see the testimony of Mr. Bruce Wiliams.
For information and support regarding return on common equity, see the testimony of Dr. Sam Hadaway.
REVISED PROTOCOL Page 11.2Year.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 11.3 3,574,583,105 3,368,022,988 206,560,116 11,637,673 218,197,789
3 Interdepartmental 11.3 0 0 0 0 0
4 Special Sales 11.3 501,563,210 471,750,719 29,812,490 1,051,991 30,864,481
5 Other Operating Revenues 11.4 326,069,070 306,977,163 19,091.907 (5.260.834)13,831.073
6 Total Operating Revenues 11.4 4.402.215,385 4.146,750.871 255,464,514 7,428.829 262,893,343
7
8 Operating Expenses:
9 Steam Production 11.5 957,497,818 898,228.521 59,269,297 4,859,163 64,128,460
10 Nuclear Production 11.6 0 0 0 0 0
11 Hydro Production 11.7 40,481,667 38.031,517 2,450,150 226,019 2.676,169
12 Other Power Supply 11.9 922,755,661 861,341.168 61,414,493 8,117.716 69,532,209
13 Transmission 11.10 195,628,269 183,769,934 11,858.335 287,354 12,145,689
14 Distribution 11.12 208.550,302 198.123,70 10,426.832 590.671 11,017,503
15 Customer Accounting 11.12 92.750,645 87.978,639 4.772.006 (108,425)4,663,581
16 Customer Service & Infor 11.13 128,944,905 121.813.010 7.131,894 (5,923.722)1.208,172
17 Sales 11.13 0 0 0 0 0
18 Administrative & General 11.14 146,076,485 136,625,029 9,451.456 1,793,407 11,244,864
19
20 Total 0 & M Expenses 11.14 2,692,685,751 2,525,911,288 166,774,463 9,842,183 176,616.646
21
22 Depreciation 11.16 491,643,870 463.686,990 27,956,881 2,738,028 30.694.909
23 Amortization 11.17 44.975.946 42,483,154 2,492,792 272,898 2.765.690
24 Taxes Other Than Income 11.17 136,512.728 130,106,225 6,406,503 763,783 7,170.286
25 Income Taxes - Federal 11.20 (482,762,100)(457,640,872)(25,121,229)(11,066,315)(36,187.544)
26 Im,ome Taxes - State 11.20 (58,348,093)(55,373.441 )(2,974,652)(1,420,644)(4,395,296)
27 Income Taxes - Def Net 11.19 761.44,172 724,705.272 36.738,900 9,311.198 46,050,098
28 Investment Tax Credit Adj.11.17 (1,874.204)(1,652,566)(221,638)0 (221,638)
29 Misc Revenue & Expense 11.4 (5,388,606)(5,100,609)(287,997)(345.174)(633,17)
30
31 Total Operating Expenses 11.20 3,578,889,466 3.367.125,43 211,764,023 10,095.958 221,859,980
32
33 Operating Revenue for Return 823,325.919 779.625,428 43.700,491 (2.667,128)41,033,363
34
35 Rate Base:
36 Electric Plant in Service 11.30 21,682,524,069 20.428,450,755 1,254.073.315 54.091,394 1,308,164,709
37 Plant Held for Future Use 11.31 17,678.149 17,033,995 644,154 (644,154)0
38 Misc Deferred Debits 11.33 198,021,223 192,700,416 5.320,808 146,593 5,67,401
39 Elec Plant Acq Adj 11.31 57,330,243 53.860,334 3,69.909 0 3,469.909
40 Nuclear Fuel 11.31 0 0 0 0 0
41 Prepayments 11.32 45.378,667 42.688.821 2.689.846 0 2.689.846
42 Fuel Stock 11.32 184.380.973 172.741.386 11.639,587 2.366,241 14.005,828
43 Material & Supplies 11.32 186,133,158 175,143,765 10.989,394 0 10.989.394
44 Working Capital 11.33 64,503,333 60,855,904 3,647,429 (40,553)3.606.876
45 Weatherization Loans 11.31 8.619,651 5,438.646 3.181.005 0 3.181.005
46 Miscellaneous Rate Base 11.34 135.566 125.548 10,019 (10.019)0
47
48 Total Electric Plant 22,444.705,034 21,149,039.569 1.295,665,465 55.909.503 1,351,574.967
49
50 Rate Base Deductions:
51 Accum Prov For Depr 11.38 (6,842,986,868)(6,437.147.613)(405.839,255)(787.372)(406,626,627)52 Accum Prov For Amort 11.39 (456.063.105)(431,642,365)(24,420,740)(533,590)(24,954.331 )
53 Accum Def Income Taxes 11.35 (2,999.250.147)(2,833,500,090)(165.750.057)(4,385,849)(170,135,906)
54 Unamortized ITC 11.35 (5.669.770)(5,629,625)(40.145)(117,966)(158,111)55 Customer Adv for Const 11.34 (18.494.962)(17.662,878)(832,083)(334,536)(1, 166,20)
56 Customer Service Deposits 11.34 0 0 0 0 0
57 Misc. Rate Base Deductions 11.34 (136.934.409)(134,030,578)(2,903.832)(1,568,700)(4,472.531 )
58
59 Total Rate Base Deductions (10,459,399,260)(9,859.613,148)(599.786.113)(7,728.013)(607.514,126)
60
61 Total Rate Base 11,985,305.773 11,289,426,421 695.879.352 48,181,489 744.060.841
62
63 Return on Rate Base 6.869%6.280%5.515%
64
65 Return on Equity 7.865%6.738%5.275%
66 Net Power Costs 1.125,770.120 70,636.738 82,510,409
67 100 Basis Points in Equity:
68 Revenue Requirement Impact 101,022,014 5.865,43 6.271.557
69 Rate Base Decrease (847,933,32)(53,498,534)(64,451.410)
REVISED PROTOCOL Page 11.3
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 1,357.826.906 1.296.315.399 61.511,506 2.504,407 64.015.913
73
74 81 1.357.826.906 1,296,315.399 61.511,506 2.504,407 64.015.913
75
76 442 Commercial & Industrial Sales
77 0 S 2.176.375,21 2.031.797.692 144.577.729 9.006.259 153.583.988
78 P SE
79 PT SG
80
81
82 81 2.176.375,421 2.031.797,692 144.577.729 9.006.259 153.583.988
83
84 444 Public Street & Highway Lighting
85 0 S 20.610,361 20.139,481 470.881 127.007 597.888
86 0 SO
87 81 20.610.361 20.139,481 470.881 127.007 597.888
88
89 445 Other Sales to Public Authority
90 0 S 19.770,416 19.770,416
91
92 81 19.770,416 19.770,416.
93
94 448 Interdepartmental
95 DPW S
96 GP SO
97 81
98
99 Total Sales to Ultimate Customers B1 3,574,583,105 3,368,022,988 206,560,116 11,637,673 218,197,789
100
101
102
103 447 Sales for Resale-Non NPC
104 P S 9.040.737 9.040.737
105 9.040.737 9.040.737
106
107 447NPC Sales for Resale-NPC
108 P SG 491.619.370 461.864.146 29.755,225 1,109.256 30.864,481
109 P SE 903.103 845.837 57.266 (57.266)
110 P SG
111 492.522,473 462.709.983 29.812,490 1.051.991 30.864.481
112
113 Total Sales for Resale 81 501.563.210 471.750,719 29.812,490 1,051,991 30.864,481
114
115 449 Provision for Rate Refund
116 P S
117 P SG
118
119
120 81
121
122 Total Sales from Electricit B1 4,076,146,315 3,839,773,708 236,372,607 12,689,663 249,062,270
123 450 Forfeited Discounts & Interest
124 CUST S 7,411.888 7.004.958 406.930 406.930
125 CUST SO
126 81 7,411.888 7.004.958 406.930 406.930
127
128 451 Mise Electric Revenue
129 CUST S 5.861.680 5.760.675 101.005 101.005
130 GP SG
131 GP SO 57,591 54.260 3,331 3.331
132 81 5.919.272 5.814.936 104,336 104.336
133
134 453 Water Sales
135 P SG 2.609 2.451 158 158
136 81 2,609 2,451 158 158
137
138 454 Rent of Electric Propert
139 DPW S 10.656.375 10,447.639 208.736 208.736
140 T SG 5,417.250 5.089.371 327.879 327.879
141 T SG
142 GP SO 3,485,471 3.283.878 201.593 201,593
143 81 19.559,096 18.820.889 738.207 738.207
144
145
REVISED PROTOCOL Page 11.4Year.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 96,891,344 90,951,471 5,939,873 (5,939,833)39
149 CUST CN
150 OTHSE SE 8,162,720 7,645,120 517,600 132,527 650,127
151 OTHSO SO 474,389 446,951 27,438 27,438
152 OTHSGR SG 187,647,753 176,290,387 11,357,366 546,471 11,903,37
153
154
155 81 293,176,206 275,333,930 17,842,276 (5.260,834)12,581,442
156
157 Total Other Electric Revenues B1 326,069,070 306,977,163 19,091,907 (5,260,834)13,831,073
158
159 Total Electric Operating Revenues 81 4,402,215,385 4,146,750,871 255,46,514 7,428,829 262,893,343
160
161 Summary of Revenues by Factor
162 S 3,704,445,128 3,491,228,468 213,216,660 5,697.840 218,914,500
163 CN
164 SE 9,065,823 8,490,957 574,866 75,261 650,127
165 SO 4,017,451 3,785,090 232,361 232,361
166 SG 684,686,982 643,246,355 41,440,627 1,655,728 43,096,355
167 DGP
168
169 Total Electric Operating Revenues 4,402,215,385 4,146,750,871 255,464,514 7,428,829 262,893,343
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 81
178
179 41170 Loss on Sale of Utilty Plant
180 DPW S
181 T SG
182 81
183
184 4118 Gain from Emission Allowances
185 P S
186 P SE (2,817,551)(2,638,890)(178,662)(345,174)(523,836)187 81 (2,817 ,551)(2,638,890)(178,662)(345,174)(523,836)188
189 41181 Gain from Disposition of NOX Credits
190 P SE
191 81
192
193 4194 Impact Housing Interest Income
194 P SG
195 81
196
197 421 (Gain) / Loss on Sale of Utilty Plant
198 DPW S (764,726)(764,726)
199 T SG (761,976)(715,858)(46,119)(46,119)200 T SG (469,173)(44,776)(28,397)(28.397)201 PTD CN 121 116 5 5
202 PTD SO 1,951 1,838 113 113
203 P SG (577,251)(542,313)(34,938)(34,938)204 81 (2,571,055)(2,461,719)(109,336)(109,336)205
206 Total Miscellaneous Revenues (5,388,606)(5,100,609)(287,997)(345,174)(633,171)
207 Miscellaneous Expenses
208 4311 Interest on Customer Deposits
209 CUST S
210 81
211 Total Miscellaneous Expenses
212
213 Net Misc Revenue and Expense B1 (5,388,606)(5,100,609)(287,997)(345,174)(633,17)
214
REVISED PROTOCOL Page 11.5Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
215 500 Operation Supervision & Engineering
216 P SG 18,301,279 17,193,595 1,107,684 20,198 1,127,881
217 P SSGCH 1,805,751 1,704,060 101,691 101,691
218 82 20,107,030 18,897,656 1,209,375 20,198 1,229,572
219
220 501 Fuel Related-Non NPC
221 P SE 15,015,379 14,063,250 952,129 (343)951,786
222 P SE
223 P SE
224 P SSECT
225 P SSECH 3,378,234 3,181,297 196,937 196,937
226 82 18,393,613 17,244,547 1,149,066 (343)1,148,723
227
228 501NPC Fuel Related-NPC
229 P S (914,987)(665,891)(249,096)249,096
230 P SE 581,140,995 544,290,708 36,850.287 4,464,960 41,315,247
231 P SE
232 P SSECT
233 P SSECH 48,110,124 45,305,498 2,804,626 170,384 2,975,010
234 82 628,336,133 588,930,315 39,405,817 4,884,440 44,290,258
235
236 Total Fuel Related 646,729,745 606,174,862 40,554,883 4,884,097 45,38,981
237
238 502 Steam Expenses
239 P SG 31,477,336 29,572,173 1,905,163 22,559 1,927,722
240 P SSGCH 6,994,684 6,600,778 393,906 393,906
241 82 38,72,021 36,172.951 2.299,070 22,559 2.321,628
242
243 503 Steam From Other Sources-Non-NPC
244 P SE 108 108
245 82 108 108
246
247 503NPC Steam From Other Sources-NPC
248 P SE 3.655,727 3,423.917 231,811 (21.223)210.587
249 82 3,655,727 3,423.917 231,811 (21,223)210.587
250
251 505 Electric Expenses
252 P SG 3,085,158 2.898,429 186.729 2,368 189.097
253 P SSGCH 1,199.979 1,132,402 67.577 67,577
254 82 4.285.137 4,030,831 254.306 2,368 256,674
255
256 506 Misc. Steam Expense
257 P SG 46.109.239 43.318.481 2.790.758 66.011 2.856,769
258 P SE
259 P SSGCH 1.933.634 1,824,742 108,893 (4)108,889
260 82 48,042.874 45,143,223 2,899,651 66,007 2,965.658
261
262 507 Rents
263 P SG 338.245 317,773 20,472 20,472
264 P SSGCH 440 415 25 25
265 82 338,685 318,188 20,497 20,497
266
267 510 Maint Supervision & Engineering
268 P SG 4.580,349 4,303.123 277.225 (388.761)(111.536)
269 P SSGCH 1.881,910 1,775,930 105.980 105.980
270 82 6,462.259 6,079.053 383,205 (388,761)(5.556)271
272
273
274 511 Maintenance of Structures
275 P SG 25.069,456 23,552,129 1.517.327 8,967 1,526,294
276 P SSGCH 411,499 388,325 23,174 (1)23,172
277 B2 25,480,955 23,940,454 1.540,500 8,966 1,549,466
278
279 512 Maintenance of Boiler Plant
280 P SG 105.721,429 99,322,648 6.398,781 179,325 6,578,106
281 P SSGCH 7,201,452 6,795.901 405.550 67.681 473,231
282 B2 112.922,881 106.118.549 6,804.332 247,006 7.051,338
283
284 513 Maintenance of Electric Plant
285 P SG 38.150.749 35.841.678 2,309,071 14,430 2.323,501
286 P SSGCH 783,588 739.460 44.128 44,128
287 B2 38.934,338 36,581.139 2.353.199 14,430 2.367.629
288
289 514 Maintenance of Misc. Steam Plant
290 P SG 9.254.784 8,694.639 560.145 3,416 563,561
291 P SSGCH 2,811,384 2,653,060 158.323 (6)158,317292B212,066,167 11,347,699 718.468 3,410 721,878
293
294 Total Steam Power Generation B2 957,497,818 898,228,521 59,269,297 4,859,163 64,128,460
REVISED PROTOCOL Page 11.6
Year-End
FERC 6US UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
295 517 Operation Super & Engineering
296 P SG
297 62
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 62
321
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 82
333
334 531 Maintenance of Electric Plant
335 P SG
336 82
337
338 532 Maintenance of Misc Nuclear
339 P SG
340 82
341
342 Total Nuclear Power Generation 62
343
344 535 Operation Super & Engineering
345 P DGP
346 P SG 4,590,184 4,312,364 277,821 6,900 284,721
347 P SG (764,519)(718,246)(46,272)2,174 (44,098)
348
349 82 3,825,666 3,594,117 231,548 9,074 240,623
350
351 536 Water.For Power
352 P DGP
353 P SG 212,409 199,553 12,856 105 12,961
354 P SG
355
356 82 212,409 199,553 12,856 105 12,961
357
REVISED PROTOCOL Page 11.7
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 SG 3,246,477 3,049,985 196,493 201,990 398,483
361 P SG 203,031 190,743 12,288 76 12,365
362
363 82 3,449,509 3,240,727 208,781 202.066 410,848
364
365 538 Electric Expenses
366 P DGP
367 P SG
368 P SG
369
370 82
371
372 539 Misc. Hydro Expenses
373 P DGP
374 P SG 17,855,445 16,774,745 1,080,699 5,143 1,085,843
375 P SG 7,340,718 6,896,422 444,296 5,996 450,292
376
377
378 82 25,196,163 23,671,167 1,524,996 11,139 1,536,135
379
380 540 Rents (Hydro Generation)
381 P DGP
382 P SG 116,623 109,564 7,059 (201)6,857
383 P SG 775 728 47 47
384
385 82 117,398 110,292 7,105 (201)6.904
386
387 541 Maint Supervision & Engineering
388 P DGP
389 P SG 469 441 28 0 29
390 P SG
391
392 82 469 441 28 0 29
393
394 542 Maintenance of Structures
395 P DGP
396 P SG 1,317,460 1,237,V:21 79,739 514 80,254
397 P SG 112,932 106,097 6,835 102 6,938
398
399 82 1,430,392 1,343,818 86,574 617 87,191
400
401
402
403
404 543 Maintenance of Dams & Waterways
405 P DGP
406 P SG 1,331,256 1,250,682 80,574 412 80,986
407 P SG 628,444 590,407 38,037 603 38,640
408
409 82 1,959,700 1,841,089 118,611 1,016 119,626
410
411 544 Maintenance of Electric Plant
412 P DGP
413 P SG 1,249,523 1,173,895 75,627 958 76,586
414 P SG 385,68 362,307 23,341 351 23,692
415
416 82 1,635,171 1,536,202 98,969 1,309 100,278
417
418 545 Maintenance of Misc. Hydro Plant
419 P DGP
420 P SG 1,841,743 1,730,271 111,471 514 111,986
421 P SG 813,048 763,838 49,210 379 49,589
422
423 82 2,654,790 2,494,109 160,681 894 161,575
424
425 Total Hydraulic Power Generation B2 40,481,667 38,031,517 2,450,150 226,019 2,676,169
REVISED PROTOCOL Page 11.8
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 358,628 336,922 21,706 2 21,708
429 P SSGCT
430 62 358,628 336,922 21,706 2 21,708
431
432 547 Fuel-Non-NPC
433 P SE
434 P SSECT
435 62
436
437 547NPC Fuel-NPC
438 P SE 411,275,695 385,196,607 26,079,089 (3,267,316)22,811,773
439 P SSECT 21,345,038 19,989,641 1,355,397 1,121.000 2,476,397
440 62 432,620,733 405,186,247 27,434,486 (2,146,316)25.288,170
441
442 548 Generation Expense
443 P SG 13,323,739 12,517,320 806,418 6,211 812,629
444 P SSGCT 1,314,796 1,235,124 79,671 789 80,461
445 62 14,638,534 13,752,445 886,090 7,000 893,090
446
447 549 Miscellaneous Other
448 P SG 3,440,696 3,232,44 208,248 3,393 211,641
449 P SG 15,260,859 14,337,197 923,662 113,745 1,037,408
450 62 18,701,556 17,569,646 1,131,910 117,138 1,249,048
451
452
453
454
455 550 Rents
456 P SG 30,076 28,256 1,820 1,820
457 P SG 3,528,603 3,315,034 213,568 213,568
458 62 3,558,679 3,343,290 215,389 215,389
459
460 551 Maint Supervision & Engineering
461 P SG
462 62
463
464 552 Maintenance of Structures
465 P SG 1,056,123 992,201 63,922 162 64,084
466 P SSGCT 184,471 173,293 11,178 63 11,241
467 B2 1,240,594 1,165,494 .75,100 225 75,325
468
469 553 Maint of Generation & Electric Plant
470 P SG 4,438,293 4,169,666 268,627 318,469 587,096
471 P SG 2,101,615 1,974,415 127,200 127,200
472 P SSGCT 2,456,496 2,307,642 148,854 188 149,042
473 62 8,996,04 8,451,723 544,681 318,657 863,339
474
475 554 Maintenance of Misc. Other
476 P SG 728,404 684,318 44,087 54 44,140
477 P SG 1,331,445 1,250,859 80,586 80,586
478 P SSGCT 136,317 128,057 8,260 112 8,372
479 62 2,196,166 2,063,234 132,932 166 133,098
480
481 Total Other Power Generation B2 482,311,295 451,869,000 30,442,295 (1,703,128)28,739,166
482
483
484 555 Purchased Power-Non NPC
485 DMSC S (36,817,673)(37,424,309)606,635 (606,635)
486 (36,817,673)(37,424,309)606,635 (606,635)
487
488 555NPC Purchased Power-NPC
489 P SG 469,600,699 441,178,153 28,422,546 2,918,183 31,340,729
490 P SE (52,775,347)(49,428,850)(3,346,497)7,026,558 3,680,061
491 Seasonal Co P SSGC
492 DGP
493 416,825,351 391,749,303 25,076,049 9,944,741 35,020,790
494
495 Total Purchased Power 62 380,007,678 354,324,994 25,682,684 9,338,106 35,020,790
496
497 556 System Control & Load Dispatch
498 P SG 877,454 824,346 53,108 540 53,648
499
500 62 877,454 824,346 53,108 540 53,648
501
502
REVISED PROTOCOL Page 11.9
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
503
504 557 Other Expenses
505 P S (183,792)(150,819)(32,973)(32,973)
506 P SG 58,620,601 55,072,594 3,548,007 482,199 4,030,206
507 P SGCi 1,122,425 1,054,229 68,196 68,196
508 P SE
509 P SSGCT
510 P TROJP
511
512 82 59,559,234 55,976,003 3,583,231 482,199 4,065,429
513
514 Embedded Cost Differentials
515 Company Owned Hyd P DGP (38,406,980)(38,406,980)
516 Company Owned Hyd P SG 38,406,980 36,082,401 2,324,580 2,324,580
517 Mid-C Contract P MC (31,403,942)(30,384,977)(1,018,964)(1,018,964)
518 Mid-C Contract P SG 31,403,942 29,503,220 1,900,721 1,900,721
519 Existing QF Contracts P S 40,944,293 40,019,304 924,990 924,990
520 Existing QF Contracts P SG (40,944,293)(38,466,143)(2,478,150)(2,478,150)
521
522 (1,653,176)1,653,176 1,653,176
523
524 Hydro Endowment Fixed Dollar Proposal
525 Klamath Surcharge Sit P S
526 ECD Hydro P S
527
528
529 Total Other Power Supply B2 44,44,366 409,472,168 30,972,198 9,820,84 40,793,043
530
531 Total Production Expense B2 1,920,735,146 1,797,601,206 123,133,940 13,202,898 136,336,838
532
533
534 Summary of Production Expense by Factor
535 S 3,027,840 1,778,285 1,249,555 (357,539)892,016
536 SG 926,133,555 870,079,393 56,054,162 3,997,487 60,051,649
537 SE 958,312,449 897,545,631 60,766.818 8,202,745 68.969,563
538 SNPPH
539 TROJP
540 SGCT 1,122,425 1,054,229 68,196 68.196
541 DGP (38,406,980)(38,406,980)
542 DEU
543 DEP
544 SNPPS
545 SNPPO
546 DGU
547 MC (31,403,942)(30,384,977)(1,018,964)(1.018,964)
548 SSGCT 4,092,079 3,844.115 247.964 1,152 249,116
549 SSECT 21.345,038 19,989,641 1,355,397 1,121,000 2,476,397
550 SSGC
551 SSGCH 25,024,322 23,615,075 1,409,247 67,669 1,476,917
552 SSECH 51,488,359 48,486,795 3,001,564 170,384 3,171.948
553 Total Production Expense by Factor 82 1.920,735,146 1,797,601,206 123,133.940 13,202,898 136,336,838
554 560 Operation Supervision & Engineering
555 T SG 5,041,115 4,736,002 305,113 5,073 310,186
556
557 82 5,041,115 4,736,002 305,113 5,073 310,186
558
559 561 Load Dispatching
560 T SG 10,336,896 9,711,256 625,640 11,331 636,971
561
562 82 10.336,896 9,711.256 625,640 11,331 636,971
563 562 Station Expense
564 T SG 2,124.825 1,996,220 128.605 1,457 130.062
565
566 82 2,124,825 1,996,220 128,605 1,457 130,062
567
568 563 Overhead Line Expense
569 T SG 120,209 112,934 7,276 92 7.367
570
571 82 120,209 112,934 7,276 92 7,367
572
573 564 Underground Line Expense
574 T SG
575
576 82
577
REVISED PROTOCOL Page 11.10
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
578 565 Transmission of Electricity by Others
579 T SG
580 T SE
581
582
583 565NPC Transmission of Electricity by Others-NPC
584 T SG 130,633,756 122,727,158 7,906,598 319,092 8,225,690
585 T SE 6,220,893 5,826,25 394,468 (55,073)339,395
586 136,854,649 128,553,583 8-,301,066 264,019 8,565,085
587
588 Total Transmission of Electricity by Others B2 136,854,649 128,553,583 8,301,066 264,019 8,565,085
589
590 566 Misc. Transmission Expense
591 T SG 4,257,862 4,000,155 257,707 (48,019)209,688
592
593 62 4,257.862 4.000,155 257,707 (48,019)209,688
594
595 567 Rents - Transmission
596 T SG 1,312.382 1,232,950 79,432 207 79,639
597
598 62 1,312,382 1,232,950 79,432 207 79,639
599
600 568 Maint Supervision & Engineering
601 T SG 1,334,303 1,253,545 80,759 1,350 82,109
602
603 B2 1,334.303 1,253,545 80,759 1,350 82,109
604
605 569 Maintenance of Structures
606 T SG 4,669,784 4,387,146 282,638 3,321 285,959
607
608 62 4,669,784 4,387,146 282,638 3.321 285,959
609
610 570 Maintenance of Station Equipment
611 T SG 10,092,385 9,481,544 610.841 8.132 618,973
612
613 B2 10,092,385 9,481,544 610,841 8,132 618,973
614
615 571 Maintenance of Overhead Lines
616 T SG 19,173,510 18,013,035 1,160,475 40,363 1,200,839
617
618 62 19,173,510 18,013,035 1,160,475 40,363 1,200,839
619
620 572 rvaintenance of Underground Lines
621 T SG 36,881 34,649 2,232 18 2,251
622
623 62 36,881 34,649 2,232 18 2.251
624
625 573 Maint of Misc. Transmission Plant
626 T SG 273,461 256,915 16,552 9 16,560
627
628 62 273,467 256,915 16,552 9 16,560
629
630 Total Transmission Expense B2 195,628,269 183,769,934 11,858,335 287,354 12,145,689
631
632 Summary of Transmission Expense by Factor
633 SE 6,220,893 5,826,425 394,468 (55,073)339,395
634 SG 189,407,376 177,943,509 11,463,867 342,427 11,806,294
635 SNPT
636 Total Transmission Expense by Factor 195,628,269 183,769,934 11,858,335 287,354 12,145,689
637 580 Operation Supervision & Engineering
638 DPW S 53,020 88,736 (35,716)(35,716)639 DPW SNPD 15,572,431 14,850,486 721,945 15,139 737,084
640 62 15,625,451 14,939,222 686,229 15,139 701,368
641
642 581 Load Dispatching
643 DPW S
644 DPW SNPD 13,735,481 13,098,698 636,783 13,264 650,047
645 62 13,735,481 13,098,698 636,783 13,264 650,047
646
647 582 Station Expense
648 DPW S 3,788,937 3,549,316 239,621 2,641 242,261
649 DPW SNPD 23,895 22,787 1,108 19 1,127
650 62 3,812,831 3,572,103 240,728 2,660 243,389
651
REVISED PROTOCOL Page 11.11
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
652 583 Overhead Line Expenses
653 DPW S 5,725,809 5,532,611 193,198 3,620 196,818
654 DPW SNPD 36,344 34,659 1,685 20 1,705
655 82 5,762,152 5,567,270 194,882 3,640 198,522
656
657 584 Underground Line Expense
658 DPW S 287 264 23 23
659 DPW SNPD
660 82 287 264 23 23
661
662 585 Street Lighting & Signal Systems
663 DPW S
664 DPW SNPD 209,265 199,563 9,702 209 9,911
665 82 209,265 199,563 9,702 209 9,911
666
667 586 Meter Expenses
668 DPW S 5,377,919 5,102,422 275,498 5.034 280.532
669 DPW SNPD 1,186,441 1,131,437 55,004 949 55,953
670 82 6,564,361 6,233,859 330,502 5,983 336,85
671
672 587 Customer Installation Expenses
673 DPW S 12,634,849 12,235,508 399,341 7,224 406.565
674 DPW SNPD
675 82 12,634,849 12,235,508 399,341 7.224 406,565
676
677 588 Misc. Distribution Expenses
678 DPW S 1,310,808 1,308,97 2,311 (1,147)1,164
679 DPW SNPD 4,576,455 4,364.288 212,167 206 212,373
680 82 5.887.263 5,672.785 214,478 (941)213,537
681
682 589 Rents
683 DPW S 3.187,858 3,175,008 12,850 16 12,866
684 DPW SNPD 65.814 62,763 3,051 3,051
685 82 3.253,672 3,237,771 15,901 16 15.917
686
687 590 Maint Supervision & Engineering
688 DPW S 816.745 763,677 53,068 923 53.991
689 DPW SNPD 4,676.484 4,459,680 216,804 4,579 221,382
690 82 5,493.229 5.223,358 269,871 5,502 275.373
691
692 591 Maintenance of Structures
693 DPW S 1.749.265 1.594,805 154,460 154.460
694 DPW SNPD 79,605 75,914 3,691 3,691
695 82 1.828.870 1.670,719 158,151 158,151
696
697 592 Maintenance of Station Equipment
698 DPW S 11.145,163 10,410,931 734.232 10,769 745.001
699 DPW SNPD 1,476.908 1.408,38 68,70 1,374 69.844
700 82 12,622.071 11.819,369 802,702 12,143 814,844
701 593 Maintenance of Overhead Lines
702 DPW S 83,673,582 78,569,424 5,104,158 507,039 5,611,197
703 DPW SNPD 1,056,813 1,007.819 48.994 (567)48,428
704 82 84,730.396 79,577.243 5,153,152 506,472 5,659,624
705
706 594 Maintenance of Underground Lines
707 DPW S 22.786,414 22,099.175 687,240 8,584 695.823
708 DPW SNPD
709 82 22,786,414 22,099,175 687,240 8,584 695,823
710
711 595 Maintenance of Line Transformers
712 DPW S
713 DPW SNPD.883,285 842,335 40,949 720 41,670
714 82 883,285 842,335 40.949 720 41,670
715
716 596 Maint of Street Lighting & Signal Sys.
717 DPW S 4,084,559 3,927,770 156.790 2,700 159,489
718 DPW SNPD
719 82 4.084,559 3.927,770 156.790 2,700 159.489
720
REVISED PROTOCOL Page 11.12
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
721 597 Maintenance of Meters
722 DPW S 4,802,396 4,500,189 302,207 5,541 307,749
723 DPW SNPD 1,088,248 1,037,796 50,452 738 51,189
724 62 5,890,644 5,537,985 352,659 6,279 358.938
725
726 598 Maint of Misc. Distribution Plant
727 DPW S 2,056,220 2,011,413 44,807 44,807
728 DPW SNPD 689,001 657,08 31,942 1,076 33,018
729 62 2,745,221 2,668,472 76,749 1,076 77,826
730
731 Total DistrlbutionExpense B2 208,550,302 198,123,470 10,426,832 590,671 11,017,503
732
733
734 Summary of Distribution Expense by Factor
735 S 163,193,833 154,869,747 8,324,086 552,944 8,877,030
736 SNPD 45,356,69 43,253,723 2,102,746 37;726 2,140,473
737
738 Total Distribution Expense by Factor 208,550,302 198,123,470 10,426,832 590,671 11,017,503
739
740 901 Supervision
741 CUST S 1,704 1,704
742 CUST CN 2,495,978 2,399,412 96,567 1,613 98,179
743 62 2,497,682 2,401,115 96,567 1,613 98,179
744
745 902 Meter Reading Expense
746 CUST S 20,633,641 18,949,062 1,684,580 29,696 1,714,275
747 CUST CN 1,919,847 1,845,571 74,277 1,239 75,516
748 62 22,553,488 20,794,632 1,758,856 30,935 1,769,791
749
750 903 Customer Receipts & Collections
751 CUST S 7,456,791 7,065,477 391,315 6,262 397,577
752 CUST CN 47,482,101 45,645,070 1,837,031 26,768 1,863,799
753 62 54,938,892 52,710,547 2,228,346 33,030 2,261,376
754
755 904 Uncollectible Accounts
756 CUST S 12,495,007 11,816,850 678,156 (174,096)504,061
757 P SG
758 CUST CN 95,649 91,948 3,701 3,701
759 62 12,590,656 11,908,799 681,857 (174,096)507,761
760
761 905 Misc. Customer Accounts Expense
762 CUST S 5,016 5,016
763 CUST CN 164,911 158,531 6,380 93 6,474
764 62 169,927 163,546 6,380 93 6,474
765
766 Total Customer Accounts Expense 62 92,750,645 87,978,639 4,772,006 (108,425)4,663,581
767
768 Summary of Customer Accts Exp by Factor
769 S 40,592,159 37,838,108 2,754,051 (138,138)2,615,913
770 CN 52,158,486 50,140,531 2,017,955 29,713 2,047,668
771 SG
772 Total Customer Accounts Expense by Factor 92,750,645 87,978,639 4,772,006 (108,25)4,663,581
773
774 907 Supervision
775 CUST S
776 CUST CN 263,903 253,693 10,210 203 10,413
777 62 263,903 253,693 10,210 203 10,413
778
779 908 Customer Assistance
780 CUST S 121,361,303 114,557,969 6,803,334 (5,930,478)872,856
781 CUST CN 2,794,497 2,686,381 108,116 2,114 110,230
782
783
784 62 124,155,800 117 ,244,350 6,911,450 (5,928.364)983,086
785
REVISED PROTOCOL Page 11.13Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
786 909 Informational & Instructional Adv
787 CUST S 645.251 585.129 60.122 3.571 63.693
788 CUST CN 3.789,781 3.643,159 146.623 867 147,490
789 62 4,435,032 4.228.287 206.745 4,438 211.183
790
791 910 Misc. Customer Service
792 CUST S
793 CUST CN 90.169 86,680 3,89 3,90
794
795 62 90.169 86.680 3,89 3,490
796
797 Total Customer Service Expense B2 128,94,905 121,813,010 7,131,894 (5,923,722)1,208,172
798
799
800 Summary of Customer Service Exp by Factor
801 S 122.006.554 115.143.098 6.863,57 (5.926.907)936.550
802 CN 6.938.350 6.669.913 268,37 3.186 271.623
803
804 Total Customer Service Expense by Factor 62 128.944,95 121.813.010 7.131,894 (5.923,722)1,208.172
805
806
807 911 Supervision
808 CUST S
809 CUST CN
810 62
811
812 912 Demonstration & Selling Expense
813 CUST S
814 CUST CN
815 62
816
817 913 Advertising Expense
818 CUST S
819 CUST CN
820 62
821
822 916 Misc. Sales Expense
823 CUST S
824 CUST CN
825 62
826
827 Total Sales Expense 62
828
829
830 Total Sales Expense by Factor
831 S
832 CN
833 Total Sales Expense by Factor
834
835 Total Customer Service Exp Including Sales B2 128,94.905 121,813,010 7,131,894 (5,923,722).1,208,172
836 920 Administrative & General Salaries
837 PTD S (5.230.152)(5.723.882)493.730 (493,730)(0)
838 CUST CN
839 PTD SO 71.688.978 67.542.632 4,146.345 379.839 4.526.184
840 82 66,458.826 61.818.750 4,640.076 (113.892)4,526.184
841
842 921 Offce Supplies & expenses
843 PTD S 736.310 687.081 49.229 49.229
844 CUST CN
845 PTD SO 9,237,574 8.703.291 534.283 (2.782)531.501
846 82 9,973,883 9,390,372 583.511 (2,782)580.729
847
848 922 A&G Expenses Transferred
849 PTD S
850 CUST CN
851 PTD SO (28.375.128)(26.733.968)(1.641.160)35.750 (1.605,10)
852 82 (28.375.128)(26.733.968)(1.641.160)35.750 (1.605,410)853
REVISED PROTOCOL Page 11.14
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
854 923 Outside Services
855 PTD S 8,195 8.195
856 CU5T CN
857 PTD SO 9,396,107 8,852,655 543,452 140.903 684.355
858 B2 9,404,302 8.860.850 543,452 140.903 684,355
859
860 924 Propert Insurance
861 PT 5
862 PT 5G 88,661 88.661863PTDSO23.341.430 21.991.409 1.350.021 (570,377)779.644
864 B2 23.341,430 21,991.409 1.350.021 (481.715)868.306
865
866 925 Injuries & Damages
867 PTD 50 8,492,514 8,001,325 491,190 (22.891)468,299
868 B2 8,492,514 8.001.325 491.190 (22.891)468,299
869
870 926 Employee Pensions & Benefits
871 LABOR S
872 CUST CN
873 LABOR 50
874 B2
875
876 927 Franchise Requirements
877 DMSC S
878 DMSC SO
879 B2
880
881 928 Regulatory Commission Expense
882 DM5C 5 13.874.697 12.675.629 1.199,068 39.083 1,238.151
883 CUST CN
884 DMSC SO 1.538.229 1.449.261 88.968 238 89.206
885 FERC 5G 2.513.914 2.361.760 152,154 152.154
886 B2 17.926.840 16,486.650 1.44.190 39.321 1,479.512
887
888 929 Duplicate Charges
889 LABOR 5
890 LABOR SO (6.130.868)(5.776.271 )(354.597)(1,170)(355.767)891 B2 (6.130.868)(5.776.271 )(354.597)(1.170)(355,767)892
893 930 Mise General Expenses
894 PTD 5 2.718.026 2,705,076 12,950 192,08 204.998
895 CUST CN 1,601 1,539 62 (7)55
896 P 5G
897 LABOR SO 13,592,405 12,806.247 786.157 2,004,792 2.790,949
898 B2 16,312.031 15.512,862 799.169 2.196,833 2.996.002
899
900 931 Rents
901 PTD S 993.159 993.159
902 PTD 50 5.344.545 5.035,427 309,118 (34)309.084
903 B2 6,337.703 6.028.586 309.118 (34)309.084
904
905 935 Maintenance of General Plant
906 G S 22.861 22.861
907 CUST CN
908 G SO 22.312.089 21.021,603 1.290,486 3.084 1.293,570
909 B2 22.334.950 21.044,464 1.290.486 3.084 1.293,570
910
911 Total Administrative & General Expense B2 146,076,485 136,625,029 9,451,456 1,793,407 11,244,864
912
913 5ummary of A&G Expense by Factor
914 5 13.123,095 11.368.118 1.754.977 (262.599)1.492.378
915 50 130,437,875 122.893.612 7,544.263 1.967.352 9.511,615
916 SG 2,513.914 2.361.760 152.154 88.661 240,816
917 CN 1.601 1.539 62 (7)55918Total A&G Expense by Factor 146,076.485 136.625.029 9.451.456 1.793,407 11.244.864
919
920 Total O&M Expense B2 2,692,685,751 2,525,911,288 166,774,463 9,842,183 176,616,646
REVISED PROTOCOL Page 11.15
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
921 403SP Steam Depreciation
922 P SG 22,205.504 20.861,518 1,343,986 1,343,986
923 P SG 25.715.098 24.158,693 1,556,404 1,556,404
924 P SG 63.751.644 59,893.081 3,858.563 1,051,088 4,909,651
925 P SSGCH 7.844,012 7,402,276 441.736 441,736
926 B3 119.516,259 112,315,568 7,200.690 1,051,088 8,251,778
927
928 403NP Nuclear Depreciation
929 P SG
930 83
931
932 403HP Hydro Depreciation
933 P SG 3,407,623 3,201.377 206,246 206,246
934 P SG 1,007,037 946,086 60,951 60,951
935 P SG 7.864,486 7,388.489 475,997 291.813 767,811
936 P SG 3,557,399 3.342.088 215,311 13,270 228,581
937 83 15,836.545 14,878.040 958.506 305.083 1,263,589
938
939 4030P Other Production Depreciation
940 P SG 123,595 116,114 7,481 7,481
941 P SG 31.868,578 29,939,735 1,928,843 1.928,843
942 P SSGCT 2.601.101 2,443,484 157.617 157,617
943 P SG 73.261,078 68.826,957 4,434,121 460.531 4.894,652
944 83 107.854.351 101.326,290 6.528.061 460,531 6,988,92
945
946 403TP Transmission Depreciation
947 T SG 11,210,232 10,531,734 678,498 678,98
948 T SG 12,494,962 11.738.705 756,257 756,257
949 T SG 47.973.502 45,069.909 2.903.592 895.587 3,799.180
950 83 71.678.696 67,340,348 4.338,348 895,587 5.233,935
951
952
953
954 403 Distribution Depreciation
955 360 Lend & Lend RighI' DPW S 307,179 289.385 17,794 17,794
956 361 Strctures DPW S 1,149,215 1,126,198 23,017 23,017
957 362 Station Equipment DPW S 12,399,378 11,765,381 633,997 633,997
958 363 Storage Battery Eqi DPW S 29.272 29.272
959 364 Poles & Towers DPW S 34;584,953 32,455,413 2,129,540 471 2,130,011
960 365 OH Conductrs DPW S 19,225,134 18,255.947 969.187 969,187
961 366 UG Conduit DPW S 7,784,052 7.621.932 162,121 162,121
962 367 UG Conducr DPW S 17,901,089 17,418,940 482.149 482,149
963 368 Line Trans DPW S 27,722,730 26.257.642 1,465.088 1,465,088
964 369 Service DPW S 12,019,012 11,478,139 540,873 540,873
965 370 Meters DPW S 6,71,787 6.025,308 446,79 446,479
966 371 lnsl Cust Prem DPW S 495,546 487,909 7,637 7,637
967 372 leased Propety DPW S
968 373 Street Lighting DPW S 2,211,652 2.182,252 29.400 29,400
969 83 142,300.998 135.393,717 6.907.280 471 6,907,752
970
971 403GP General Depreciation
972 G-SITUS S 12.056.052 11,313,018 743.034 13,380 756,414
973 PT SG 328,358 308,484 19.874 19.874
974 PT SG 574.222 539,467 34.755 34.755
975 P SE 22,664 21,227 1.437 1,437
976 CUST CN 1.704,508 1.638,562 65.946 65.946
977 G-SG SG 5.817,168 5,465,084 352.084 12,903 364,986
978 PTD SO 13,800.885 13,002.670 798,215 (1,015)797,200
979 G-SG SSGCT 6.010 5,646 364 364
980 G-SG SSGCH 147,156 138.869 8,287 8,287
981 83 34,457.022 32,433,027 2.023,995 25,268 2,049,263
982
983 403GVO General Vehicles
984 G-SG SG
985 83
986
987 403MP Mining Depreciation
988 P SE
989 83
990
REVISED PROTOCOL Page 11.16
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DE SCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
991 403EP Experimental Plant Depreciation
992 P SG
993 P SG
994 83
995 4031 ARO Depreciation
996 P S
997 83
998
999
1000 Total Depreciation Expense B3 491,64,870 463,686,990 27,956,881 2,738,028 30,694,909
1001
1002 Summary S 154,357,049 146,706,735 7,650,314 13,852 7,664,166
1003 DGP
1004 DGU
1005 SG 311,160,486 292,327,521 18,832,964 2,725,192 21,558,156
1006 SO 13,800,885 13,002,670 798,215 (1,015)797,200
1007 CN 1.704,508 1,638,562 65.946 65.948
1008 SE 22,664 21.227 1,437 1.437
1009 SSGCH 7,991,168 7.541,145 450,023 450,023
1010 SSGCT 2.607,110 2.449,130 157,981 157.981
1011 Total Depreciation Expense 8y Factor 491.643,670 463.686,990 27.956.681 2,738.028 30.694,909
1012
1013 404GP Amort of L T Plant - Capital Lease Gen
1014 I-SITUS S 1,478,533 1,478,533
1015 I-SG SG
1016 PTD SO 1.166,807 1.099,321 67,486 67,486
1017 P SG
1018 CUST eN 275,829 265,157 10.672 10.672
1019 P SG
1020 84 2,921,169 2.843,012 78,157 78,157
1021
1022 404SP Amort of L T Plant - Cap Lease Steam
1023 P SG
1024 P SG
1025 84
1026
1027 4041P Amort of L T Plant - Intangible Plant
1028 I-SITUS S 184.245 163.713 20,532 20.532
1029 P SE 12.088 11.322 767 767
1030 I-SG SG 9,041.830 8,494.574 547,256 48.183 593,439
1031 PTD SO 14,250,413 13,426,198 824,215 824.215
1032 CUST CN 5,532.601 5,318.551 214,050 214,050
1033 I-SG SG 2,615.539 2,457.233 158,305 522,199 680,505
1034 I-SG SG 309.282 290.563 18,719 18,719
1035 P SG
1036 I-SG SSGCT
1037 I-SG SSGCH 54,154 51,104 3.050 3,050
1038 P SG (197,996)(186,03)(11.984)(11.984)
1039 84 31.802,156 30,027,248 1,774.910 568.382 2,343,293
1040
1041 404MP Amort of L T Plant - Mining Plant
1042 P SE
1043 84
1044
1045 4040P Amort of L T Plant - Other Plant
1046 P SG
1047 84
1048
1049
1050 404HP Amortization of Other Electric Plant
1051 P SG 122,773 115,342 7,431 7,431
1052 P SG 46,413 43,604 2.809 .2.809
1053 P SG
1054 84 169,186 158,948 10.240 10.240
1055
1056 Total Amortization of Limited Term Plant B4 34,892,511 33,029,203 1,863,308 568,382 2,431,690
1057
1058
1059 405 Amortization of Other Electric Plant
1060 GP S
1061
1062 B4
1063
REVISED PROTOCOL Page 11.17
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1064 406 Amortization of Plant Acquisition Adj
1065 P S
1066 P SG
1067 P SG
1068 P SG 5,518,393 5,184,392 334,000 334,000
1069 P SO
1070 84 5,518,393 5,184,392 334,000 334,000
1071 407 Amort of Prop Losses, Unrec Plant, etc
1072 DPW S (302,455)(302,455)
1073 GP SO
1074 P SG-P 2,860,972 2,687,811 173,160 (173,160)(0)
1075 P SE
1076 P SG
1077 P TROJP .2,006,526 1,884,202 122,324 (122,324)
1078 84 4,565,043 4,269,559 295,484 (295,84)(0)
1079
1080 Total Amortization Expense B4 44,975,946 42,483,154 2,492,792 272,898 2,765,690
1081
1082
1083
1084 Summary of Amortization Expense by Factor
1085 S 1,360,324 1,339,792 20,532 20,532
1086 SE 12,088 11,322 767 767
1087 TROJP 2,006,526 1,884,202 122,324 (122,324)
1088 DGP
1089 DGU
1090 SO 15,417,220 14,525,520 891,701 891,701
1091 SSGCT
1092 SSGCH 54,154 51,104 3,050 3,050
1093 SG.p 2,860,972 2,687,811 173,160 (173,160)(0)
1094 CN 5,808,430 5,583,708 224,722 224,722
1095 SG 17,456,233 16,399,696 1,056,537 568,382 1,624,920
1096 Total Amortization Expense by Factor 44,975,946 42,483,154 2,492,792 272,88 2,765,690
10!l7 408 Taxes Other Than Income
1098 DMSC S 25,831,078 25,831,078
1099 GP GPS 100,361,44 94,556,738 5,804,703 763,783 6,568,85
1100 GP SO 9,440,796 8,894,759 546,037 546,37
1101 P SE 879,415 823,651 55,764 55,764
1102 P SG
1103 DMSC OPRV.ID
1104 GP EXCTAX
1105 GP SG
1106
1107
1108
1109 Total Taxes Other Than income B5 136,512,728 130,106,225 6,4õ6,503 763,783 7,170,286
1110
1111
1112 41140 Deferred Investment Tax Credit - Fed
1113 PTD DGU (1,874,204)(1,652,566)(221,638)(221,638)
1114
1115 67 (1,874,204)(1,652,566)(221,638)(221,638)
1116
1117 41141 Deferred Investment Tax Credit. Idaho
1118 PTD DGU
1119
1120 67.
1121
1122 Total Deferred ITC B7 (1,874,204)(1,652,566)(221,638)(221,638)
1123
REVISED PROTOCOL Page 11.18
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADjTOTAL
1124
1125 427 Interest on Long-Term Debt
1126 GP S 1,083,037 1,083,037
1127 GP SNP 363,203,396 342,400,925 20,802,470 20,802,470
1128 B6 363,203,396 342,400,925 20,802,470 1,083,037 21,885.507
1129
1130 428 Amortization of Debt Disc & Exp
1131 GP SNP 6,058,937 5,711,911 347.026 347,026
1132 B6 6,058,937 5,711.911 347,026 347,026
1133
1134 429 Amortization of Premium on Debt
1135 GP SNP (2,718)(2,562)(156)(156)1136 B6 (2,718)(2,562)(156)(156)1137
1138 431 Other Interest Expense
1139 NUTIL OTH
1140 GP SO
1141 GP SNP 12,367,152 11.658,824 708.329 708,329
1142 B6 12,367,152 11,658,824 708,329 708.329
1143
1144 432 AFUDC - Borrowed
1145 GP SNP (44,618,458)(42,062,936)(2,555,522)(2.555.522)1146 (44,618,58)(42,062,936)(2,555,522)(2,555.522)
1147
1148 Total Elec. Interest Deductions for Tax B6 337.008,309 317,706.162 19,302,147 1.083,037 20,385,184
1149
1150 Non-Utilty Portion of Interest
1151 427 NUTIL NUTIL
1152 428 NUTIL NUTIL
1153 429 NUTIL NUTIL
1154 431 NUTIL NUTIL
1155
1156 Total Non-utiity Interest
1157
1158 Total Interest Deductions for Tax B6 337,008.309 317,706.162 19,302,147 1.083,037 20,385,184
1159
1160
1161 419 Interest & Dividends
1162 GP S
1163 GP SNP (74.756,432)(4,541,806)201,102
1164 Total Operating Deductions for Tax B6 7 .6,2 4. 41.8 20 .
1165
1166
1167 41010 Deferred Income Tax - Federal-DR
1168 GP S 27,885,806 27,747,783 138,023 (110,006)28.017
1169 P TROJD
1170 PT SSGCH 31,324 29,560 1,764 1,764
1171 LABOR SO 8,859,456 8,347,043 512,413 (5,Q3)507,370
1172 GP SNP 44,945.274 42,371,034 2.574,240 2.574.240
1173 P SE 18,245,954 17,088,974 1,156,980 548,997 1,705.978
1174 PT SG 42,534,872 39,960,452 2.574,420 8.940,991 11.515,11
1175 P SGCT
1176 GP GPS 24,704,090 23,275.255 1,428,835 1,428.835
1177 TAXDEPR TAXDEPR 934.697,178 887,014.033 47,683,145 47,683,145
1178 CUST BADDEBT
1179 CUST CN 18.276 17.569 707 707
1180 P IBT
1181 DPW SNPD
1182 B7 1,101,922.230 1.045.851,703 56.070.527 9.374,940 65.445,466
1183
REVISED PROTOCOL Page 11.20
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1242 SCHMDF Deductions - Flow Through
1243 SCHMDF S
1244 SCHMDF DGP
1245 SCHMDF DGU
1246 B6
1247 SCHMDP Deductions - Permanent
1248 SCHMDP S
1249 P SE 676,074 633,204 42,870 42,870
1250 PTD SNP 381,063 359,238 21,825 21,825
1251 SCHMDP IBT
1252 P SG
1253 SCHMDP-SO SO 24,434,943 23,021,676 1,413,268 (765,608)647,660
1254 B6 25,492,081 24,014,118 1,477,963 (765,608)712,355
1255
1256 SCHMDT Deductions - Temporary
1257 GP S 73,478,450 73,114,765 363,685 (289,862)73,823
1258 DPW BADDEBT
1259 SCHMDT-SNP SNP 118,429,747 111,646,684 6,783,062 6,783,062
1260 SCHMDT CN 48,156 46,293 1,863 1,863
1261 SCHMDT SSGCH 82,539 77,891 4,648 4,648
1262 CUST DGP
1263 P SE 48,077,661 45,029,045 3,048,616 1,446,595 4,495,211
1264 SCHMDT-5G SG 112,078,393 105,294,857 6,783,536 23,559,303 30,342,839
1265 SCHMDT-GPS GPS 65,094,701 61,329,756 3,764,946 3,764,946
1266 SCHMDT-SO SO 23,344,458 21,994,262 1,350,196 (13,288)1,336,908
1267 TAXDEPR TAXDEPR 2,462,905,267 2,337,261,292 125,643,975 125,643,975
1268 DPW SNPD
1269 B6 2,903,539,372 2,755,794,845 147,744,528 24,702,748 172,447,276
1270
1271 TOTAL SCHEDULE - M DEDUCTIONS B6 2,929,031,454 2,779,808,963 149,222,491..23,937,140 173,159,631
1272
1273 TOTAL SCHEDULE - M ADJUSTMENTS B6 (2,062,732,978)(1,960,246,491 )(102,486,487)(23,505,114)(125,991,601)
1274
1275
1276
1277 40911 State Income Taxes
1278 IBT S (58,051,044)(55,094.371 )(2,956,673)(1,390,699)(4,347,372)1279 IBT SE
1280 PTC P SG (297,049)(279.070)(17,979)(29.945)(47,923)
1281 IBT IBT
1282 Total State Tax Expense (M,348,093)(55,373,441)(2,974,652)(1,420,644)(4,395,296)
1283
1284
1285 Calculation of Taxable Income:
1286 Operating Revenues 4,402.215,385 4,146,750,871 255.464,514 7,428,829 262.893,343
1287 Operating Deductions:
1288 o & M Expenses 2,692,685,751 2.525,911,288 166,774,463 9,842,183 176,616,646
1289 Depreciation Expense 491,643,870 463,686,990 27,956,881 2,738,028 30.694,909
1290 Amortization Expense 44,975,946 42,483,154 2,492,792 272,898 2,765,690
1291 Taxes Other Than Income 136,512,728 130,106,225 6,406,503 763,783 7,170,286
1292 Interest & Dividends (AFUDC-Equity)(79,298,238)(74,756,32)(4,541,806)201,102 (4,340,704)
1293 Misc Revenue & Expense (5,388,606)(5,100,609)(287,997)(345,174)(633,17)
1294 Total Operating Deductions 3,281,131,452 3,082,330,617 198,800,836 13,472,821 212,273,656
1295 Other Deductions:
1296 Interest Deductions 337,008,309 317,706,162 19,302,147 1,083,037 20,385,184
1297 Interest on PCRBS
1298 Schedule M Adjustments (2,062,732,978)(1,960.246,91 )(102,486.487)(23,505.114)(125,991,601)
1299
1300 Income Before State Taxes (1,278,657,354)(1,213,532,398)(65,124,956)(30,632,142)(95,757,098)
1301
1302 State Income Taxes (58,348,093)(55,373,441 )(2,974,652)(1,420,644)(4.395,296)
1303
1304 Total Taxable Income (1,220,309,261 )(1,158,158,957)(62,150,304)(29,211,499)(91,361,803)
1305
1306 Tax Rate 35.0%35.0%35.0%35.0%35.0%
1307
1308 Federal Income Tax - Calculated (427,108,241)(405,355,635)(21,752,606)(10,224.025)(31,976,631)
1309
1310 Adjustments to Calculated Tax:
1311 40910 PMI P SE (88.878)(83.242)(5,636)(5,636)
1312 40910 PTe P SG (55,535,369)(52,174.095)(3,361,274)(842.290)(4,203.564)1313 40910 P SO (29,612)(27.899)(1.713)(1.713)
1314 40910 IRS Sette LABOR S
1315 Federal Income Tax Expense (482,762,100)(457,640,872)(25,121,229)(11,066,315)(36,187,54)
1316
1317 Total Operating Expenses 3,578,889,46 3,367,125,44 211,764,023 10,095,958 221,859,980
REVISED PROTOCOL Page 11.21
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUST-MENT ADJTOTAL
1318 310 Land and Land Rights
1319 P SG 2,328,228 2,187,312 140,916 140,916
1320 P SG 34,798,446 32,692,272 2,106,173 2,106,173
1321 P SG 56,303,435 52,895,674 3,407,761 3,407,761
1322 P S
1323 P SSGCH 2,468,743 2,329,716 139,028 139,028
1324 B8 95,898,852 90,104,974 5,793,878 5,793,878
1325
1326 311 Structures and Improvements
1327 P SG 233,697,069 219,552,572 14,144,497 14,144,497
1328 P SG 325,016,640 305,345,033 19,671,607 19,671,607
1329 P SG 304,038,753 285,636,831 18,401,922 18,401,922
1330 p SSGCH 58,700,214 55,394,506 3,305,709 3,305,709
1331 B8 921,452,677 865,928,942 55,523,735 55,523,735
1332
1333 312 Boiler Plant Equipment
1334 P SG 665,806,134 625,508.269 40,297,865 40,297,865
1335 P SG 642,590,325 603,697,595 38,892,730 38,892,730
1336 P SG 1,885.355,962 1,771,244,938 114,111,024 28,935,270 143,046,294
1337 P SSGCH 324,773,916 306,464,239 18,289,676 18,289,676
1338 B8 3,518,526.337 3,306,935,041 211,591,295 28,935.270 240,526,565
1339
1340 314 Turbogenerator Units
1341 P SG 133,730,947 125,636,892 8,094,055 8,094,055
1342 P SG 144,430,870 135,689,203 8,741,667 8,741,667
1343 P SG 554,615,741 521,047,666 33,568,075 33,568,075
1344 P SSGCH 63,736,456 60,147,131 3,589,325 3,589,325
1345 B8 896,514,013 842,520,891 53,993,123 53,993,123
1346
1347 315 Accessory Electric Equipment
1348 P SG 87,016,417 81,749,755 5,266,662 5,266,662
1349 P SG 138,274,538 129.905,483 8,369.056 8,369,056
1350 p SG 124.032,336 116,525,289 7,507,048 7,507,048
1351 P SSGCH 66.644,224 62,891,147 3,753,076 3,753,076
1352 B8 415.967,515 391,071,674 24,895,842 24,895.842
1353
1354
1355
1356 316 Misc Power Plant Equipment
1357 P SG 4,715,664 4,430,249 285,415 285,415
1358 P SG 5,085,197 4,777,416 307,781 307,781
1359 P SG 19,393,369 18,219,587 1,173,782 1,173,782
1360 P SSGCH 4,039,790 3,812,289 227.501 227,501
1361 B8 33,234,020 31,239.540 1.994.480 1,994,480
1362
1363 317 Steam Plant ARO
1364 P S
1365 B8
1366
1367 SP Unclassified Steam Plant - Account 300
1368 P SG 3,351,463 3,148,616 202,847 202,847
1369 B8 3,351,463 3,148,616 202,847 202,847
1370
1371
1372 Total Steam Production Plant B8 5.884.944,878 5,530,949,679 353,995.199 28,935,270 382,930,469
1373
1374
1375 Summary of Steam Production Plant by Factor
1376 S
1377 DGP
1378 DGU
1379 SG 5,364,581.535 5,039,890.651 324,690,884 28.935,270 353,626,154
1380 SSGCH 520,363,342 491,059,027 29,304,315 29,304,315
1381 Total Steam Production Plant by Factor 5,884,944,878 5,530,949,679 353,995,199 28,935,270 382,930,469
1382 320 Land and Land Rights
1383 P SG
1384 P SG
1385 B8
1386
1387 321 Structures and Improvements
1388 P SG
1389 P SG B8
1390
REVISED PROTOCOL Page 11.22Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1391
1392 322 Reactor Plant Equipment
1393 P SG
1394 P SG
1395 B8
1396
1397 323 Turbogenerator Units
1398 P SG
1399 P SG
1400 B8
1401
1402 324 Land and Land Rights
1403 P SG
1404 P SG
1405 B8
1406
1407 325 Misc. Power Plant Equipment
1408 P SG
1409 P SG
1410 B8
1411
1412
1413 NP Unclassified Nuclear Plant - Acct 300
1414 P SG
1415 B8
1416
1417
1418 Total Nuclear Production Plant B8
1419
1420
1421
1422 Summary of Nuclear Production Plant by Factor
1423 DGP
1424 DGU
1425 SG
1426
1427 Total Nuclear Plant by Factor
1428
1429 330 Land and Land Rights
1430 P SG 10.621.118 9.978.276 642,82 642.842
1431 P SG 5.269,427 4,950,496 318.932 318.932
1432 P SG 9.560.168 8.981,540 578,628 578.628
1433 P SG 672.873 632.148 40.726 40.726
1434 B8 26.123.587 24.542,459 1,581,128 1.581.128
1435
1436 331 Structures and Improvements
1437 P SG 20.915.379 19.649,478 1.265.902 1.265.902
1438 P SG 5.280.294 4.960.705 319.589 319.589
1439 P SG 78.435.286 73.687.997 4.747.290 4.747,290
1440 P SG 8.183.946 7.688.613 495.333 495,333
1441 B8 112.814,905 105.986.792 6.828.113 6.828,113
1442
1443 332 Reservoirs. Dams & Waterways
1444 P SG 150.943.088 141.807.270 9.135.819 9.135.819
1445 P SG 20.006.881 18.795.966 1.210.915 1,210.915
1446 P SG 114.583,184 107.648.045 6.935.138 1.260.021 8.195.159
1447 P SG 40.934.944 38,457.359 2,477.584 486.542 2.964.127
1448 B8 326.468,097 306.708.641 19.759,456 1.746.563 21,506.020
1449
1450 333 Water Wheel. Turbines. & Generators
1451 P SG 31.307.452 29,412.571 1.894.881 1,894.881
1452 P SG 8,771.526 8.240.630 530.896 530.896
1453 P SG 45.115,448 42.384.839 2.730.609 2,730.609
1454 P SG 27.236.711 25,588.211 1.648.500 1.648.500
1455 B8 112,431.137 105.626,251 6.804.886 6,804.886
1456
1457 334 Accessory Electric Equipment
1458 P SG 4.363.326 4.099,236 264,090 264.090
1459 P SG 3,646.790 3,426.068 220.722 220.722
1460 P SG 44.929.172 42.209,837 2,719.335 2.719.335
1461 P SG 7.177.004 6,742.617 434.388 434.388
1462 B8 60.116.292 56,77.758 3.638,534 3.638.534
1463
REVISED PROTOCOL Page 11.23
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1464
1465
1466 335 Misc. Power Plant Equipment
1467 P SG 1,195,178 1,122,840 72,338 72,338
1468 P SG 161,986 152,181 9,804 9,804
1469 P SG 992,216 932,162 60,054 60,054
1470 P SG 11,353 10,666 687 687
1471 68 2,360,733 2,217,850 142,883 142,883
1472
1473 336 Roads, Railroads & 6ridges
1474 P SG 4,648,527 4,367,176 281,352 281,352
1475 P SG 822,839 773,037 49,802 49,802
1476 P SG 10,183,215 9,566,876 616,338 616,338
1477 P SG 668,735 628,259 40,475 40,475
1478 68 16,323,315 15,335,348 987,967 987,967
1479
1480 337 Hydro Plant ARO
1481 P S
1482 B8
1483
1484 HP Unclassified Hydro Plant - Acct 300
1485 P S
1486 P SG
1487 P SG
1488 P SG
1489 B8
1490
1491 Total Hydraulic Production Plant B8 656,638,066 616,895,098 39,742,968 1,746,563 41,489,532
1492
1493 Summary of Hydraulic Plant by Factor
1494 S
1495 SG 656,638,066 616,895,098 39,742,968 1,746,563 41,489.532
1496 DGP
1497 DGU
1498 Total Hydraulic Plant by Factor 656,638,066 616,895,098 39,742,968 1,746,563 41,489,532
1499
1500 340 Land and Land Rights
1501 P SG 23,516,708 22,093,361 1,423,347 1,423,347
1502 P SG 5,394,604 5,068,096 326,508 326,508
1503 P SSGCT
1504 68 28,911,312 27,161,457 1,749,855 1,749,855
1505
1506 341 Structures and Improvements
1507 P SG 107,792,505 101,268,372 6.524,133 6,524,133
1508 P SG 163,512 153,615 9,897 9,897
1509 P SG 43,775,824 41,126,296 2,649,528 2,649,528
1510 P SSGCT 4,241,952 3,984,906 257,046 257,046
1511 68 155,973,793 146,533,189 9,44,604 9,440,604
1512
1513 342 Fuel Holders, Producers & Accessories
1514 P SG 8,06,209 7,897,424 508,785 508,785
1515 P SG 121,339 113,995 7,344 7,344
1516 P SSGCT 2,284,126 2,145,717 138,409 138,09
1517 B8 10,811,674 10,157,136 654,538 654,538
1518
1519 343 Prime Movers
1520 P S
1521 P SG 754,440 708,777 45,662 45,662
1522 P SG 1,801,277,182 1,692,255,019 109,022,163 109,022,163
1523 P SG 658,057,132 618,228,275 39,828,857 39,828,857
1524 P SSGCT 53,648,952 50,398,036 3,250,917 3,250,917
1525 B8 2,513,737,706 2,361,590,107 152,147,599 152,147,599
1526
1527 344 Generators
1528 P S
1529 P SG 47,700,523 44,813,452 2,887,070 2,887,070
1530 P SG 283,380,358 266,228,783 17,151,574 17,151,574
1531 P SSGCT 15,873,643 14,911,763 961,881 961,881
1532 68 346,954,524 325,953,998 21,000,525 21,000,525
REVISED PROTOCOL Page 11.24
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1533
1534 345 Accessory Electric Plant
1535 P SG 134.281,439 126,154.066 8.127,374 8,127,374
1536 P SG 97,391,746 91,497,118 5,894,628 5,894,628
1537 P SG 156,586 147,109 9,477 9,477
1538 P SSGCT 2,919,649 2,742,730 176,919 176,919
1539 B8 234,749,420 220,541,022 14,208,398 14,208,398
1540
1541
1542
1543 346 Misc. Power Plant Equipment
1544 P SG 9,819,979 9,225.625 594.353 594.353
1545 P SG 2.349,890 2.207.664 142,227 142,227
1546 P SG 11,813 11,098 715 715
1547 B8 12,181,682 11,444.387 737.295 737.295
1548
1549 347 Other Production ARO
1550 P S
1551 B8
1552
1553 OP Unclassified Other Prod Plant-Acct 102
1554 P S
1555 P SG (4,484.801 )(4.213,359)(271,442)(271.442)
1556 (4.484.801)(4,213.359)(271,42)(271.442)
1557
1558 Total Other Production Plant B8 3,298,835,309 3,099,167,937 199,667,373 199,667,373
1559
1560 Summary of Other Production Plant by Factor
1561 S
1562 DGU
1563 SG 3.219,866,987 3,024,984,786 194.882,201 194.882.201
1564 SSGCT 78.968,322 74,183,151 4.785.171 4,785,171
1565 Total of Other Production Plant by Factor 3.298.835,309 3,099,167,937 199.667.373 199.667,373
1566
1567 Experimental Plant
1568 103 Experimental Plant
1569 P SG
1570 Total Experimental Production Plant 88
1571
1572 Total Production Plant B8 9,840,418,253 9,247,012,713 593,405,540 30,681,833 624.087,373
1573 350 Land and Land Rights
1574 T SG 21,114.634 19,836,673 1,277,962 1,277.962
1575 T SG 48,491.936 45,556.965 2,934,971 2,934,971
1576 T SG 111.910.895 105,137,497 6,773,398 (25,595)6,747.804
1577 B8 181,517,465 170,531.135 10.986,331 (25,595)10,960.736
1578
1579 352 Structures and Improvements
1580 T S
1581 T SG 7.550,730 7,093.722 457,007 457,007
1582 T SG 18.144,311 17,046.128 1.098.183 1,098.183
1583 T SG 97.158.664 91,278.143 5,880,521 5,880.521
1584 B8 122.853,704 115,417.993 7,435.711 7,435.711
1585
1586 353 Station Equipment
1587 T SG 127.623,942 119,899,513 7.724,429 7.724,429
1588 T SG 186,316,529 175,039.735 11.276,794 11.276.794
1589 T SG 1,224,680,278 1.150.556,598 74.123.679 74.123,679
1590 B8 1,538,620,749 1,445,495,846 93.124,902 93.124,902
1591
1592 354 Towers and Fixtures
1593 T SG 161,082.488 151 ;332,983 9,749,505 9,749,505
1594 T SG 128,007.635 120.259,983 7,747.652 7,747,652
1595 T SG 336,682,164 316.304,502 20,377.662 20,377,662
1596 B8 625,772,287 587.897,468 37,874,819 37,874,819
1597
1598 355 Poles and Fixtures
1599 T SG 66,617.046 62,585,054 4,031,992 4,031,992
1600 T SG 117.303.325 110.203,550 7,099,775 7,099,775
1601 T SG 415.637.115 390,480,711 25,156,404 9,151,416 34,307,820
1602 B8 599.557.486 563,269.315 36,288.171 9,151,416 45,439.587
1603
REVISED PROTOCOL Page 11.25
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1604 356 Clearing and Grading
1605 T SG 194,103,526 182,355,425 11,748,101 11,748,101
1606 T SG 151,170,861 142,021,256 9,149,605 9,149,605
1607 T SG 433,610,805 407,366,45 26,244,261 26,244,261
1608 88 778,885,193 731,743,226 47,141,966 47,141,966
1609
1610 357 Underground Conduit
1611 T SG 6,371 5,985 386 386
1612 T SG 91,651 86,103 5,547 5,547
1613 T SG 3,161,431 2,970,085 191,345 191,345
1614 88 3,259,452 3,062,174 197,278 197,278
1615
1616 358 Underground Conductors
1617 T SG
1618 T SG 1,087,552 1,021,728 65,824 65,824
1619 T SG 6,387,543 6,000,937 386,606 386,606
1620 88 7,475,095 7,022,665 452,430 .452,430
1621
1622 359 Roads and Trails
1623 T SG 1,863,032 1,750,272 112,760 112,760
1624 T SG 440,513 413,851 26,662 26,662
1625 T SG 9,295,159 8,732,570 562,589 562,589
1626 88 11,598,703 10,896,693 702,011 702,011
1627
1628 TP Unclassified Trans Plant - Acct 300
1629 T SG 469,574,099 441,153,163 28,420,936 28,20,936
1630 88 469,574,099 441,153,163 28,420,936 28,420,936
1631
1632 TSO Unclassified Trans Sub Plant - Acct 300
1633 T SG
1634 88
1635
1636 Total Transmission Plant 88 4,339,114,233 4,076,489,678 262,624,554 9,125,821 271,750,376
1637 Summary of Transmission Plant by Factor
1638 DGP
1639 DGU
1640 SG 4,339,114,233 4,076,489,678 262,624,554 9,125,821 271,750,376
1641 Total Transmission Plant by Factor 4,339,114,233 4,076,489,678 262,624,554 9,125,821 271,750,376
1642 360 Land and Land Rights
1643 DPW S 52,837,393 51,476,125 1,361,267 1,361,267
1644 88 52,837,393 51,476,125 1,361,267 1,361,267
1645
1646 361 Structures and Improvements
1647 DPW S 74,675,983 73,174,078 1,501,905 1,501,905
1648 88 74,675,983 73,174,078 1,501,905 1,501,905
1649
1650 362 Station Equipment
1651 DPW S 822,438,749 794,121,744 28,317,005 28,317,005
1652 88 822,438,749 794,121,744 28,317,005 28,317,005
1653
1654 363 Storage 8attery Equipment
1655 DPW S
1656 88
1657
1658 364 Poles, Towers & Fixtures
1659 DPW S 936.606,530 872,248,984 64,357,546 64,357,546
1660 88 936,606,530 872,248,984 64,357,546 64,357,546
1661
1662 365 Overhead Conductors
1663 DPW S 646,426,178 612,036,781 34,389,397 34,389,397
1664 88 646,426,178 612,036,781 34,389,397 34,389,397
1665
REVISED PROTOCOL Page 11.26
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1666 366 Underground Conduit
1667 DPW S 300.853.912 293.226.761 7.627.151 7.627.151
1668 68 300.853.912 293.226.761 7.627,151 7.627.151
1669
1670
1671
1672
1673 367 Underground Conductors
1674 DPW S 716.202.893 692.155.372 24.047.521 24.047,521
1675 68 716.202.893 692.155.372 24.047,521 24.047.521
1676
1677 368 Line Transformers
1678 DPW S 1.092.258.181 1.024,496.725 67.761,455 67.761.455
1679 68 1.092.258.181 1.024,496,725 67.761,455 67.761,455
1680
1681 369 Services
1682 DPW S 581.777749 552.728.553 29.049.197 29.049.197
1683 68 581.777749 552.728.553 29.049.197 29,049,197
1684
1685 370 Meters
1686 DPW S 179.597.171 165.632.928 13,964.243 13.964.243
1687 68 179.597.171 165.632.928 13.964,243 13.964.243
1688
1689 371 Installations on Customers' Premises
1690 DPW S 8.801.076 8.631.743 169.333 169.333
1691 68 8.801.076 8.631.743 169.333 169.333
1692
1693 372 Leased Propert
1694 DPW S
1695 68
1696
1697 373 Street Lights
1698 DPW S 60.795.839 60.180.066 615.773 615.773
1699 B8 60,795,839 60.180.066 615.773 615.773
1700
1701 DP Unclassified Dist Piant - Acct 300
1702 DPW S 12,090.316 10,561,483 1.528.833 1.528.833
1703 68 12,090,316 10.561,483 1.528.833 1.528.833
1704
1705 DSO Unclassified Dist Sub Plant - Acct 300
1706 DPW S
1707 68
1708
1709
1710 Total Distribution Plant B8 5.485.361,969 5,210,671,344 274,690,625 274,690,625
1711
1712 Summary of Distribution Plant by Factor
1713 S 5,85.361.969 5.210.671.344 274,690.625 274,690.625
1714
1715 Total Distribution Plant by Factor 5.4ã5.361.969 5.210,671.344 274.690.625 274.690.625
REVISED PROTOCOL Page 11.27
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1716 389 Land and Land Rights
1717 G-SITUS S 9,472.275 9,274,636 197.639 197.639
1718 CUST CN 1.128.506 1,084,845 43.661 43.661
1719 PT SG 332 312 20 20
1720 G-SG SG 1.228 1.153 74 74
1721 PTD SO 5.598.055 5.274.275 323,780 323.780
1722 68 16,200,395 15.635.221 565,174 565,174
1723
1724 390 Structures and Improvements
1725 G-SITUS S 113,258.556 103.350.062 9.908,495 9,908.95
1726 PT SG 356,327 334,760 21.567 21,567
1727 PT SG 1.638.404 1,539,240 99,164 99,164
1728 CUST CN 12,312,990 11.836.614 476,376 476,376
1729 G-SG SG 4,107.582 3,858,971 248,611 248,611
1730 PTD SO 103.816,679 97.812,132 6.004,547 6,04,547
1731 68 235,490,538 218.731,779 16.758,760 16,758.760
1732
1733 391 Offce Furniture & Equipment
1734 G-SITUS S 10,714.257 9,922,539 791.718 791,718
1735 PT SG 1,D6 982 63 63
1736 PT SG 5.295 4,975 320 320
1737 CUST CN 8,507.385 8,178,243 329.141 329.141
1738 G-SG SG 4.793.839 4.503.692 290.147 29,147
1739 P SE 80.160 75,077 5.083 5.083
1740 PTD SO 53,024.085 49,957,279 3,066.806 3,066.806
1741 G-SG SSGCH 74.351 70,164 4.187 4.187
1742 G-SG SSGCT
1743 68 77,200,417 72,712.952 4,487.466 4,487.466
1744
1745 392 Transportation Equipment
1746 G-SITUS S 72.695.382 67.622.274 5,073,108 5.073,108
1747 PTD SO 7,496.170 7.062.607 433.563 433.563
1748 G-SG SG 16.861.910 15.841.344 1,020,566 1.020,566
1749 CUST CN
1750 PT SG 788.230 740.522 47,708 47.708
1751 P SE 404.148 378.521 25,627 25.627
1752 PT SG 120.286 113.006 7,280 7.280
1753 G-SG SSGCH 343.984 324.613 19,371 19,371
1754 PT SSGCT 44,655 41,949 2,706 2.706
1755 68 98,754,764 92,124,835 6.629,929 6,629.929
1756
1757 393 Stores Equipment
1758 G-SITUS S 8,748.806 8,259,899 488,907 488.907
1759 PT SG 108,431 101,868 6,563 6,563
1760 PT SG 360.063 338,270 21,793 21.793
1761 PTD SO 366.257 345,074 21.184 21.184
1762 G-SG SG 4,117,724 3,868.99 249,225 249.225
1763 PT SSGCT 53,971 50,700 3,270 3.270
1764 68 13,755,252 12,964,310 790.942 790.942
REVISED PROTOCOL Page 11.28
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1765
1766 394 Tools. Shop & Garage Equipment
1767 G-SITUS S 31,993,392 30,190,583 1,802,808 1,802,808
1768 PT SG 1,547,621 1,453,951 93,670 93,670
1769 G-SG SG 20,748,569 19,492,763.1,255,806 1,255,806
1770 PTD SO 3,941,347 3,713,388 227,960 227,960
1771 P SE 7,106 6,656 451 451
1772 PT SG 1,779,683 1,671,968 107,715 107,715
1773 G-SG SSGCH 1,702,983 1,607,079 95,904 95,904
1774 G-SG SSGCT 89,913 84,465 5,448 5,44
1775 B8 61,810,613 58,220,853 3,589,761 3,589,761
1776
1777 395 Laboratory Equipment
1778 G-SITUS S 24,898,296 23,620,023 1,278,273 1,278.273
1779 PT SG 1,518 1,426 92 92
1780 PT SG 5,371 5,046 325 325
1781 PTD SO 5,041,840 4,750,230 291,610 291,610
1782 P SE 7,593 7,112 481 481
1783 G-SG SG 6,252,885 5,874,430 378,455 378,455
1784 G-SG SSGCH 253,001 238,753 14,248 14,248
1785 G-SG SSGCT 14,022 13,172 850 850
1786 B8 36,474,525 34,510,191 1,964,334 1,964,334
1787
1788 396 Power Operated Equipment
1789 G-SITUS S 96,176,244 89,210,759 6,965,485 6,965,485
1790 PT SG 845,108 793,958 51,150 51,150
1791 G-SG SG 31,225,794 29,335,855 1,889,939 1,889,939
1792 PTD SO 1,137,422 1,071,636 65,786 65,786
1793 PT SG 1,664,492 1,563,749 100,743 100,743
1794 P SE 73,823 69,142 4,681 4,681
1795 P SSGCT
1796 G-SG SSGCH 999,837 943,531 56,306 56,306
1797 B8 132,122,721 122,988,630 9,134,091 9,134,091
1798 397 Communication Equipment
1799 G-SITUS S 108,711,341 102,010,465 6,700,875 6,700,875
1800 PT SG 2,017,325 1,895,226 122,098 122,098
1801 PT SG 2,735,730 2,570,150 165,580 165,580
1802 PTD SO 49,790,369 46,910,595 2,879,774 2,879,774
1803 CUST .CN 2,849,382 2,739,142 110,239 110,239
1804 G-SG SG 92,965,111 87,338,405 5,626,706 5,626,706
1805 P SE 126,846 118,802 8,043 8,03
1806 G-SG SSGCH 606,135 572,000 34,135 34,135
1807 G-SG SSGCT 1,590 1,494 96 96
1808 B8 259,803,827 244,156,280 15,647,547 15,647,547
1809
1810 398 Misc. Equipment
1811 G-SITUS S 1,462,713 1,398,361 64,352 64,352
1812 PT SG
1813 PT SG
1814 CUST CN 211,499 203,316 8,183 8,183
1815 PTD SO 3,306,006 3,114,793 191,213 191,213
1816 P SE 1,668 1,562 106 106
1817 G-SG SG 1,918.568 1,802,447 116,121 116,121
1818 G-SG SSGCT
1819 B8 6,900,453 6,520,479 379,975 379,975
1820
1821 399 Coal Mine
1822 P SE 274,151,311 256,767,312 17,383,999 13,434,281 30,818,280
1823 MP P SE
1824 B8 274,151,311 256,767,312 17,383,999 13,434,281 30,818,280
1825
1826 399L WIDCO Capital Lease
1827 P SE B8
1828
1829
1830 Remove Capital Leases
1831 B8
1832
REVISED PROTOCOL Page 11.29
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1833 1011390 General Capital Leases
1834 G-SITUS S 18.984,156 18,984,156
1835 P SG 16,951,793 15,925,787 1,026,006 1,026,006
1836 PTD SO 12,664,054 11,931,590 732,463 732,463
1837 69 48,600,002 46,841,533 1,758,469 1,758,469
1838
1839 Remove Capital Leases (48,600,002)(46,841,533)(1,758,69)(1,758,69)
1840
1841
1842 1011346 General Gas Line Capital Leases
1843 P SG
1844 69
1845
1846 Remove Capital Leases
1847
1848
1849 GP Unclassified Gen Plant - Acct 300
1850 G-SITUS S
1851 PTD SO 672,542 633.644 38,898 38,898
1852 CUST CN
1853 G-SG SG
1854 PT SG
1855 PT SG
1856 68 672,542 633,644 38,898 38,898
1857
1858 399G Unclassified Gen Plant - Acct 300
1859 G-SITUS S
1860 PTD SO
1861 G-SG SG
1862 PT SG
1863 PT SG
1864 68
1865
1866 Total General Plant B8 1,213,337,359 1,135,966,484 77,370,875 13,434,281 90,805,156
1867
1868 Summary of General Plant by Factor
1869 S 497,115,417 463,843,757 33,271,660 33,271,660
1870 DGP
1871 DGU
1872 SG 213,920,262 200,972,754 12,947,507 12,947,507
1873 SO 246,854,826 232,577,242 14,277,584 14,277,584
1874 SE 274,852,655 257,424,183 17,428,472 13,434,281 30,862,752
1875 CN 25,009,761 24,042,161 967,601 967.601
1876 DEU
1877 SSGCT 204,151 191,780 12,371 12,371
1878 SSGCH 3,980,291 3,756,140 224,150 224,150
1879 Less Capital Leases (48,600,002)~46,841.533)(1,758,469)(1,758,469)
1880 Total General Plant by Factor 1,213,337,359 1,35,966,484 77,370,875 13,34,281 90,805,156
1881 301 Organization
1882 I-SITUS S
1883 PTD SO
1884 I-SG SG
1885 B8
1886 302 Franchise & Consent
1887 I-SITUS S 1,000,000 1,000,000 1,000,000
1888 I-SG SG 11,966,103 11,241,856 724,247 724,247
1889 I-SG SG 173,628,256 163,119,419 10,508,837 10,508,837
1890 I-SG SG 9,240,742 8,681,446 559,295 559,295
1891 P SG
1892 P SG 600,993 564,618 36,375 36,375
1893 B8 196,436,094 183,607,340 12,828,755 12,828,755
1894
REVISED PROTOCOL Page 11.30Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1895 303 Miscellaneous Intangible Plant
1896 I-SITUS S 7,517,189 7,089,597 427,593 427,593
1897 I-SG SG 108,21,038 102,234,653 6,586,385 849,459 7,435,844
1898 PTO SO 367,518,411 346,261,889 21,256,521 21,256,521
1899 P SE 3,44,744 3,222,565 218,178 218,178
1900 CUST CN 120,558,779 115,894,491 4,664,288 4,664,288
1901 P SG
1902 P SSGCT
1903 B8 607,856,161 574,703,196 33,152,966 849,459 34,002,425
1904 303 Less Non-Utility Plant
1905 I-SITUS S
1906 607,856,161 574,703,196 33,152,966 849,459 34,002,425
1907 IP Unclassified Intangible Plant - Acct 300
1908 I-SITUS S
1909 I-SG SG
1910 P SG
1911 pro SO
1912
1913
1914 Totallntangible.Plant B8 804,292,255 758,310,535 45,981,720 849,459 46,831,179
1915
1916 Summary of Intangible Plant by Factor
1917 S 8,517,189 7,089,597 1,427,593 1,427,593
1918 OGP
1919 OGU
1920 SG 304,257,133 285,841,993 18,415,140 849,459 19.264,599
1921 SO 367,518,411 346,261,889 21.256,521 21,256,521
1922 CN 120,558,779 115,894,491 4,664,288 4,664,2881923SSGCT
1924 SSGCH
1925 SE 3,440,744 3,222,565 218,178 218,178
1926 Total Intangible Plant by Factor 804,292,255 758,310,535 45,981,720 849.459 46,831,179
1927 Summary of Unclassified Plant (Account 106 & 102)
1928 OP 12,090,316 10,561,483 1,528,833 1,528,833
1929 OSO
1930 GP 672,542 633,644 38,898 38,898
1931'HP
1932 NP
J933 OP (4,484,801 )(4,213,359)(271,42)(271,442)1934 TP 469,574,099 441,153,163 28,20,936 28,20,936
1935 TSO
1936 IP
1937 MP
1938 SP 3,351,463 3,148,616 202,847 202,8471939Total Unclassified Plant by Factor 481,203,619 451,283,547 29,920,072 29,920,072
1940
1941 Total Electric Plant In Service B8 21,682,524,069 20,428,450,755 1,254,073,315 54,091,394 1,308,164,709
REVISED PROTOCOL Page 11.31Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1942 Summary of Electric Plant by Factor
1943 S 5,990,994,575 5,681,604,697 309,389,878 309,389,878
1944 SE 278,293,398 260,646,748 17,646,650 13,434,281 31,080,931
1945 DGU
1946 DGP
1947 SG 14,098,378,215 13,245,074,960 853,303,255 40,657,114 893,960,368
1948 SO 614,373,236 578,839,132 35,534,105 35,534,105
1949 CN 145,568,541 139,936,652 5,631,889 5.631,889
1950 DEU
1951 SSGCH 524.343,633 494.815.168 29,528,65 29,528,65
1952 SSGCT 79.172,473 74,374.931 4,797.542 4.797.542
1953 Less Capital Leases (48,600,002)(46,841,533)(1,758.469)(1.758.469)1954 21.682,524.069 20,428,50,755 1.254,073,315 54,091.394 1,308,164,709
1955 105 Plant Held For Future Use
1956 DPW S 7,080.785 7.080.785
1957 P SG
1958 T SG 721.046 677,407 43.641 (583,724)(540.082)1959 P SG 8.923.302 8,383.219 540.082 540.082
1960 P SE 953,014 892.583 60,431 (60,431)
1961 G SG
1962
1963
1964 Total Plant Held For Future Use B10 17.678,149 17,033,995 644,154 (64,154)
1965
1966 114 Electric Plant Acquisition Adjustments
1967 P S
1968 P SG 144.614.797 135.861,998 8.752,799 8.752,799
1969 P SG 14.560,711 13.679,425 881.286 881,286
1970 Total Electric Plant Acquisition Adjustment B15 159.175,508 149,541 ,423 9,634,085 9,634,085
1971
1912 115 Accum Provision for Asset Acquisition Adjustments
1973 P S
1974 P SG
1975 P SG
1976 815
1977
1978 120 Nuclear Fuel
1979 P SE
1980 Total Nuclear Fuel B.15
1981
1982 124 Weatherization
1983 DMSC S 2,213,350 2,194,663 18,688 18.688
1984 DMSC SO
J4,454)(4,196)(258)(258)1985 816 2.2 8.897 2.190,467 18,30 1lf3ö
1986
1987 182W Weatherization
1988 DMSC S 6,410.754 3,248.179 3.162.575 3,162.575
1989 DMSC SG
1990 DMSC SGCT
1991 DMSC SO
1992 816 6,410.754 3,246.179 3,162,575 3.162.575
1993
1994 186W Weatherization
1995 DMSC S
1996 DMSC CN
1997 DMSC CNP
1998 DMSC SG
1999 DMSC SO
2000 816
2001
2002 Total Weatherization B16 8,619,651 5,438.646 3,181,005 3,181.005
REVISED PROTOCOL Page 11.32Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL2003
2004 151 Fuel Stock
2005 P DEU
2006 P SE 178,314,939 167,007,947 11,306,992 2,536,201 13,843,1932007PSSECT
2008 P SSECH 10,178,149 9,584,804 593,345 (126,332)467,013
2009 Total Fuel Stock B13 188,493,087 176,592,750 11,900,337 2,409,869 14,310,2062010
2011 152 Fuel Stock - Undistributed
2012 P SE
2013
2014
2015 25316 DG& T Working Capital Deposit
2016 P SE (2,263,000)(2,119,503)(143,497)(32,593)(176,090)2017 613 (2,263,000)(2,119,503)(143,497)(32,593)(176,090)2018
2019 25317 DG&T Working Capital Deposit
~020 P SE (1,849,114)(1,731,861)(117,253)(11,035)(128,288)2021 613 (1,849,114)(1,731,861)(117,253)(11,035)(128,288)2022
2023 25319 Provo Working Capital Deposit
2024 P SE
2025
2026
2027 Total"Fuel Stock 613 184,380,973 172,741,386 11,639,587 2,366,241 14,005,828
2028 154 Materials and Supplies
2029 MSS S 87,724,078 82,701,505 5,022,573 5,022,573
2030 MSS SG 4,657,098 4,375,227 281,870 281,870
2031 MSS SE 4,477,840 4,193,899 283,941 283,9412032MSSSO220,250 207,511 12,739 12,739
2033 MSS SNPPS 84,929,002 79,826,230 5,102,772 5,102,7722034MSSSNPPH(1,860)(1,747)(113). (113)2035 MSS SNPD (2,521,016)(2,404,141 )(116,875)(116,875)2036 MSS SNPT
2037 MSS SG
2038 MSS SG
2039 MSS SSGCT
2040 MSS SNPPO 6,920,767 6,501,878 418,889 418,889
2041 MSS SSGCH
2042 Total Materials and Supplies B13 186,406,158 175,400,362 11,005,796 11,005,7962043
2044 163 Stores Expense Undistributed
2045 MSS SO
2046
2047 613
2048
2049 25318 Provo Working Capital Deposit
2050 MSS SNPPS (273,000)(256,597)(16,403)(16,403)2051
2052 613 (273,000)(256,597)(16,403)(16,403)2053
2054 Total Materials & Supplies 613 186,133,158 175,143,765 10,989,394 10,989,394
2055
2056 165 Prepayments
2057 DMSC S 2,918,959 2,728,996 189,963 189,963
2058 GP GPS 10,983,376 10,348,120 635,256 635,256
2059 PT SG 5,058,945 4,752,753 306,192 306,192
2060 P SE 5,474,749 5,127,594 347,155 347,155
2061 PTD SO 20,942,638 19,731,358 1,211,280 1,211,2802062Total Prepayments B15 45,378,667 42,688,821 2,689,846 2,689,846
2063
REVISED PROTOCOL Page 11.33
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
2064 182M Mise Regulatory Assets
2065 DDS2 S 97,616,141 97,484,653 131.488 (309,362)(177,874)
2066 DEFSG SG
2067 P SGCT 7,389.298 6,940,338 448.960 44,960
2068 DEF5G 5G-P 186,749 186,749
2069 P 5E
2070 P 5SGCT
2071 DDS02 50 8.296.641 7,816,780 479,861 479,861
2072 B11 113.302,081 112,241.772 1,060,309 (122.613)937,696
2073
2074 186M Mise Deferred Debits
2075 LABOR S 15,110.335 15,110.335
2076 P SG
2077 P SG
2078 DEF5G SG 53.166,550 49.948,649 3,217,901 273,203 3,491,104
2079 LABOR SO 1.784 1.681 103 103
2080 P SE 16,440,73 15.397.979 1,042,494 (3,997)1.038,498
2081 P SNPPS
2082 GP EXCTAX
2083 Total Misc. Deferred Debit 811 84,719,143 80,458,64 4,260,499 269,206 4,529,705
2084
2085 Working Capital
2086 CWC Cash Working Capital
2087 CWC 5 32,353,989 30,499,593 1,854,396 (24.319)1.830,077
2088 CWC SO
2089 CWC SE
2090 B14 32,353,989 30,499,593 1,854.396 . (24,319)1,830.077
2091
2092 OWC Othr Work. Cap.
2093 131 Cash GP SNP
2094 135 Working Funds GP 5G
2095 141 Notes Receivable GP 50
2096 143 OtlerAlR GP 50 48,53.1,707 45,724,732 2.806,976 2,806,976
2097 232 AlP PTD S
2098 232 AlP PTD 50 (4.386.790)(4,133,067)(253.723)(253,723)
2099 232 AlP P 5E (2,202.647)(2,062.977)(139.670)(139,670)
2100 232 AlP T 5G (146,335)(137,478)(8.857)(8,857)
2101 2533 Other Msc, Of. Crd. P S
2102 2533 Othe Ms Of. Crd P 5E (6,240.898)(5,845,162)(395,737)(16,234)(411,971)
2103 230 Ast Retir. Oblig P 5E (2,528.519)(2,368.185)(160.334)(160.334)
2104 230 Aset Ret;r. Oblig. P 5
2105 254105 ARO Reg liabiliy P 5
2106 254105 ARC Reg liability P SE (877,173)(821.552)(55.622)(55,622)
2107 2533 Cholla Reclamation P 5SECH
2108 B14 32,149,344 30,356.312 1,793,033 (16,234)1,776,798
2109
2110 Total Working Capital 814 64,503,333 60,855,904 3,647,429 (40,553)3,606,876
2111 Miscellaneous Rate Base
2112 18221 Unrec Plant & Reg Study Costs
2113 P S
2114
2115 B15
2116
2117 18222 Nuclear Plant - Trojan
2118 P S (28,645)(28.645)
2119 P TROJP 64,498 60.566 3,932 (3,932)0
2120 P TROJD 99,713 93.627 6,087 (6,087)0
2121 B15 135,566 125.548 10,019 (10,019)0
2122
2123
REVISED PROTOCOL Page 11.34
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
2124
2125 1869 Misc Deferred Debits-Trojan
2126 P 5
2127 P SNPPN
2128 B15
2129
2130 Total Miscellaneous Rate Base B15 135,566 125,548 10,019 (10,019)0
2131
2132 Total Rate Base Additions B15 762,180,964 720,588,814 41,592,150 1,818,108 43,410,258
2133 235 Customer Service Deposits
2134 CUST 5
2135 CUST CN
2136 Total Customer Service Deposits B15
2137
2138 2281 Prop Ins PTD SO
2139 2282 Inj & Dam PTD SO (8,99.000)(8.007,435)(491.565)(491,565)
2140 2283 Pen & Ben PTD SO (24,864.308)(23,426,207)(1,438,101)(1,438,101)
2141 2283 Pen & Ben PTD 5 (71.232,015)(71.232,015)2142 254 Reg Liab PTD SE (44,269)(41,462)(2.807)2,807
2143 254 Ins Prov PTD SO
2144 B15 (104,639,593)(102,707,119)(1,932,473)2,807 (1.929,666)
2145
2146 22841 Accum Misc Oper Provisions - Other
2147 P 5
2148 P SG (1.500,000)(1,409.213)90,787)90.787)
2149 B15 .5 1,,1 ,7 7 .7
2150
2151 22842 Prv-Trojan P TROJD
2152 230 ARO P TROJP (1.691,988)(1,588.839)(103,149)(103.149)2153 254105 ARO P TROJP (3,512,728)(3,298.581 )(214,147)(214.147)2154 254 P 5 ¡13,908,965)(13,908,965)2155 B15 19.113.682)(18,796,385)(317,296)(317.296)
2156
2157 252 Customer Advances for Construction
2158 DPW 5 (10.535.734)(10.185.382)(350,352)(3.729)(354,081)2159 DPW 5E
2160 T 5G (7,959.228)(7,477,496)(481.732)(330,807)(812,539)
2161 DPW 50
2162 CUST CN
2163 Total Customer Advances for Construction B19 118,494,962)(17,662,878)(832,083)(334,536)(1,166,62)
2164
2165 25398 502 Emissions
2166 P 5E
f,571,507l
(1,571507l2167B191,571.507 (1,571,507
2168
2169 25399 Other Deferred Credits
2170 P 5 (3,632,420)(3,557,473)(74,947)(74,947)
2171 LABOR SO
2172 P SG (7,639,83)(7,177 ,442)(462,401)(462,401)
2173 P SE (408,871)(382.944)~25.927l (25,927l2174B19(11,61.135)(11,11,860)( 63,274 (563,274
REVISED PROTOCOL Page 11.35
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
2175
2176 190 Accumulated Deferred Income Taxes
2177 P S 15,585,863 15,585,864 (1)(1)
2178 CUST CN 47,212 45,385 1,827 1,827
2179 P IBT
2180 LABOR SO 75,156,683 70,809,773 4,346,910 (257,Q3)4,089,867
2181 P DGP
2182 CUST BADDEBT 3,844,158 3,635,975 208,183 208,183
2183 P TROJD 1,912,923 1,796,157 116,766 (116,766)
2184 P SG 39,603,966 37,206,939 2,397,027 (2,232,800)164,227
2185 P SE (19,942,198)(18,677,658)( 1,264,539)596,403 (668,137)2186 PTD SNP
2187 DPW SNPD 1,793,564 1,710,414 83,150 83,150
2188 P SSGCT
2189 Total Accum Deferred Income Taxes B19 118,002,171 112,112,848 5,889,323 (2,010,207)3,879,111
2190
2191 281 Accumulated Deferred Income Taxes
2192 P S
2193 PT SG (11,642,708)(10,938,034)(704,674)704,674
2194 T SNPT
2195 B19 (11,642,708)(10,938,034)(704,674)704,674
2196
2197 282 Accumulated Deferred Income Taxes
2198 GP S (164,376,500)(164,376,500)2199 ACCMDIT DITBAL (3,046,185,039)(2,877,281,043)(168,903,996)168,903,996
2200 P SSGCH
2201 P SSGCT
2202 IBT IBT
2203 LABOR SO 32,477,154 30,598,741 1,878,13 (385)1,878,028
2204 CUST CN
2205 P SE (5.543,047)(5,191,561)(351,486)(364,430)(715,916)
2206 P SG (5,198,86)(4,883,848)(314,638)(8,487,956)(8,802,594)
2207 B19 (3,024,449,418)(2,856,757,711)(167,691,707)(4,325,275)(172,016,982)
2208
2209 283 Accumulated Deferred Income Taxes
2210 GP S (46,066,263)(44,925,191)(1,141,072) .1,129,081 (11,991)
2211 P SG (9,100,662)(8,549,845)(550,817)(26,356)(577,172)
2212 P SE (7,531,923)(7,054,322)(477,601)1,517 (476,084)2213 LABOR SO (3,864,666)(3,641,142)(223,524)140,717 (82,808)
2214 GP GPS (7,448,211 )(7,017,422)(430,789)(430,789)
2215 PTD SNP (4,344,154)(4,095,343)(246,811)(248,811)2216 P TROJD
2217 P SSGCT
2218 P SGCT (2,804,313)(2,633,928)(170,385)(170,385)
2219 P SSGCH
2220 B19 (81,160,192)(77,917,192)(3,243,000)1,244,959 (1,998,041)
2221
2222 Total Accum Deferred Income Tax B19 (2,999,250,147)(2,833,500,090)(165,750,057)(4,385,849)(170,135,906)
2223 255 Accumulated Investment Tax Credit
2224 PTD S
2225 PTD ITC84 (1,163,513)(1,163,513)
2226 PTD ITC85 (2,365,510)(2,365,510)
2227 PTD ITC86 (1,233,135)(1,233,135)
2228 PTD ITC88 (192,618)(192,618)2229 PTD ITC89 (427,864)(427,864)
2230 PTD ITC90 (287,130)(246,985)(40,145)(40,145)
2231 PTD SO (117,966)(117,966l
2232 Total Accumlated ITC B19 (5,669,710)(5,629,625)(40,145)(117,966)(158,111
2233
2234 Total Rate Base Deductions (3,160,349,288)(2,990,823,170)(169,526,118)(6,407,051)(175,933,168)
2235
REVISED PROTOCOL Page 11.36Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
2236
2237
2238 108SP Steam Prod Plant Accumulated Depr
2239 P S
2240 P SG (804.085.770)(755,418.540)(48.667.229)(48.667.229)2241 P SG (931.773,797)(875,378.260)(56.395.537)(56.395.537)2242 P SG (599.387,572)(563,109.685)(36.277.887)(699.345)(36.977.231)2243 P SG
2244 P SSGCH (164.881,495)(155.596.177)(9.285,318)(9.285.318)2245 B17 (2,500,128,634 )(2.349.502,663)(150,625,971 )(699,345)(151.325,316)2246
2247 108NP Nuclear Prod Plant Accumulated Depr
2248 P SG
2249 P SG
2250 P SG
2251 B17
2252
2253
2254 108HP Hydraulic Prod Plant Accum Depr
2255 P S
2256 P SG (153,199,830)(143,927,422)(9,272,408)(9,272.408)2257 P SG (29,592.043)(27,800,987)(1,791.056)(1.791,056)2258 P SG (64,346.115)(60,451,572)(3,894,544)203,27 (3.690.917)2259 P SG (15.581.955)(14,638.858)(943,097)(92,818)(1.035,914)2260 B17 (262.719.943)(246,818.839)(15,901.104)110.809 (15,790.295)2261
2262 1080P Other Production Plant - Accum Depr
2263 P S
2264 P SG (1.499,697)(1.408.928)(90.769)(90.769)2265 P SG (187,115,295)(175.790.156)(11.325.139)(11.325.139)2266 P SG (179,211,214)(168.364.469)(10.846.745)(10.846.745)2267 P SSGCT (20,480.021 )(19,239.011 )(1,241,009)(1.241,009)2268 B17 (388,306.227)(364,802,565)(23,503,662)(23.503.662)2269
2270 108EP Experimental Plant. Accum Depr
2271 P SG
2272 P SG
2273
2274
2275 Total Production Plant Accum Depreciation B17 (3.151.154.804)(2,961,124,067)(190,030,738)(588,535)(190,619,273)
2276
2277 Summary of Prod Plant Depreciation by Factor
2278 S
2279 DGP
2280 DGU
2281 SG (2,965.793.289)(2.786,288.879)(179.504,410)(588.535)(180,092,946)2282 SSGCH (164.881,495)(155,596.177)(9,285.318)(9,285.318)2283 SSGCT (20.480,021 19.239.011)(1.241.009 (1,241,0092284Total of Prod Plant Depreciation by Factor , 5 . 5 ,4 ,1 4.7 1 .7 5 8.5 5 , 7
2285
2286
2287 108TP Transmission Plant Accumulated Depr
2288 T SG
2289 T SG
2290 T SG
2291 Total Trans Plant Accum Depreciation B17
REVISED PROTOCOL Page 11.37Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
2292 108360 Land and Land Rights
2293 DPW S (7,520,631)(7,069,954)(450,676)(450,676)2294 B17 (7,520,631)(7,069,954)(450,676)(450.676)2295
2296 108361 Structures and Improvements
2297 DPW S (14,400,815)(13,938,693)(462,122)(462,122)2298 B17 (14,400,815)(13,938,693)(462,122)(462,122)2299
2300 108362 Station Equipment
2301 DPW S (215,414,073)(205,959,864)(9,454,209)(9,454,209)2302 B17 (215,414,073)(205,959,864)(9,454,209)(9,454,209)2303
2304 108363 Storage Battery Equipment
2305 DPW S
2306 B17
2307
2308 108364 Poles, Towers & Fixtures
2309 DPW S (499,610,379)(463,144,133)(36,66,247)(36,66,247)2310 B17 (499,610,379)(463,144,133)(36,466,247)(36,66,247)2311
2312 108365 Overhead Conductors
2313 DPW S (271,507,003)(260,179,548)(11,327,454)(11,327,454)2314 B17 (271,507,003)(260,179,548)(11,327,454)(11,327,454)
2315
2316 108366 Underground Conduit
2317 DPW S (125,057,953)(121,694,746)(3,363,206)(3,363,206)
2318 B17 (125,057,953)(121,694,746)(3,363,206)(3,363,206)2319
2320 108367 Underground Conductors
2321 DPW S (289,382,714)(278,272,333)(11,110,381)(11,110,381)2322 B17 (289,382,714)(278,272,333)(11,110,381)(11,110,381)2323
2324 108368 Line Transformers
2325 DPW S (374,776,489)(350,828,934)(23,947,556)(23.947,556)2326 B17 (374,776,489)(350,828,934)(23,947,556)(23.947,556)2327
2328 108369 Services
2329 DPW S (173,063,574)(162,208,058)(10,855,515)(10,855,515)
2330 B17 (173,063,574)(162,208,058)(10,855,515)(10,855,515)2331
2332 108370 Meters
2333 DPW S (73,459,993)(65,057,658)(8,402,334)(8,402,334)2334 B17 (73,459,993)(65,057,658)(8,02,334)(8.402,334)2335
2336
2337
2338 108371 Installations on Customers' Premises
2339 DPW S (7,902,179)(7,765,116)(137,063)(137,063)2340 B17 (7,902,179)(7,765,116)(137,063)(137,063)2341
2342 108372 Leased Propert
2343 DPW S
2344 817
2345
2346 108373 Street Lights
2347 DPW S (27,437,568)(26,951,399)(486,169)(486,169)
2348 B17 (27,437,568)(26,951,399)(486,169)(486,169)2349
2350 108DOO Unclassified Dist Plant - Acct 300
2351 DPW S
2352 B17
2353
.2354 108DS Unclassified Dist Sub Plant - Acct 300
2355 DPW S
2356 B17
2357
2358 108DP Unclassified Dist Sub Plant - Acct 300
2359 DPW S 7,323,293 7,315,721 7,572 7,572
2360 B17 7,323,293 7,315,721 7,572 7,572
2361
2362
2363 Total Distribution Plant Accum Depreciation B17 (2,072,210,076)(1,955,754,716)(116,455,361)(116,455,361)
2364
2365 Summary of Distribution Plant Depr by Factor
2366 S (2,072,210,076)(1,955,754,716)(116,455,361)(116,455,361)2367
2368 Total Distribution Depreciation by Factor B17 (2,072,210,076)(1,955,754,716)(116,55,361)(116,55,361)
REVISED PROTOCOL Page 11.38
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
2369 108GP General Plant Accumulated Depr
2370 G-SITUS S (152,075,528)(141,631,971)(10,443,557)(10,44,557)2371 PT SG (3,260,839)(3,063,477)(197,362)(197,362)
2372 PT SG (5,665,017)(5,322,143)(342,875)(342,875)2373 G-SG SG (49,106,625)(46,134,451)(2,972,175)(2,972,175)2374 CUST CN (7,361,183)(7,076,386)(284,796)(284,796)2375 PTD SO (71,958,569)(67,796,631 )(4,161,938)(4,161,938)2376 P SE (334,770)(313,542)(21,228)(21,228)2377 G-SG SSGCT (40,513)(38,058)(2,455)(2,455)2378 G-SG SSGCH (1,892,045)(1,785,494)(106,551)(106,551)2379 B17 (291,695,08)(273,162,152)(18,532,936)(18,532,936)2380
2381
2382 108MP Mining Plant Accumulated Depr.
2383 P S
2384 P SE (155,112,236)(145,276,532)(9,835,703)(36,877)(9,872,581 )2385 817 (155,112,236)(145,276,532)(9,835,703)(36,877)(9,872,581 )
2386 108MP Less Centralia Situs Depreciation
2387 P S
2388 817 (155,112,236)( 145,276,532)(9,835,703)(36,877)(9,872,581 )2389
2390 1081390 Accum Depr - Capital Lease
2391 PTD SO 817
2392
2393
2394 Remove Capital Leases
2395 817
2396
2397 1081399 Accum Depr - Capital Lease
2398 P S
2399 P SE 817
2400
2401
2402 Remove Capital Leases
2403 817
2404
2405
2406 Total General Plant Accum Depreciation B17 (44,807,324)(418,438,685)(28,368,639)(36,877)(28,405,517)2407
2408
2409
2410 Summary of General Depreciation by Factor
2411 S (152,075,528)(141,631,971)(10,443,557)(10,443,557)2412 DGP
2413 DGU
2414 SE (155,447,006)(145,590,074)(9,856,931)(36,877)(9,893,808)2415 SO (71,958,569)(67,796,631 )(4,161,938)(4,161,938)2416 CN (7,361,183)(7,076,386)(284,796)(284,796)2417 SG (58,032,481 )(54,520,070)(3,512,411)(3,512,411)2418 DEU
2419 SSGCT (40,513)(38,058)(2,455)(2,455)
2420 SSGCH (1,892,045)(1,785,494)(106,551)(106,551)2421 Remove Capital Leases
2422 Total General Depreciation by Factor (44,807,324)(418,38,685)(28.368,639)(36,877 (28,405,517)
2423
2424
2425 Total Accum Depreciation. Plant In Service B17 (6,842,986,868)(6,437,147,613)(405,839,255)(787,372)(406,626,627)
2426 111SP Accum Prov for Amort-Steam
2427 P SG
2428 P SSGCT
2429 818
2430
2431
2432 111GP Accum Prov for Amort-General
2433 G-SITUS S (16,724,813)(16,724,813)2434 CUST CN (2,724,543)(2,619,133)(105,10)(105,10)2435 I-SG SG
2436 PTD SO (10,775,043)(10,151,836)(623,207)(623,207)2437 P SE
2438 818 (30,224,398)(29,495,782)(728,616)(728,616)
2439
REVISED PROTOCOL Page 11.39
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
2440
2441 111HP Accum Prov for Amort-Hydro
2442 P SG
2443 P SG
2444 P SG (135,728)(127,513)(8,215)(8,215)
2445 P SG (437,050)(410,598)(26,452)(26,452)
2446 818 (572,778)(538,111)(34,667)(34,667)
2447
2448
2449 1111P Accum Prav for Amort-Intangible Plant
2450 I-SITUS S (1,045,867)(289,169)(756,698)(756,698)
2451 P SG
2452 P SG (349,396)(328,249)(21,147)(21,147)
2453 P SE (1,299,989)(1,217,557)(82,433)(82,433)
2454 I-SG SG (47,842,258)(44,946,609)(2,895,649)(32,831)(2,928,480)
2455 I-SG SG (14,069,890)(13,218,311 )(851,579)(500,760)(1,352,339)
2456 I-SG SG (3,421,089)(3,214,027)(207,061)(207,061)
2457 CUST CN (94,981,920)(91,307,173)(3,674,748)(3,674,748)
2458 P SSGCT
2459 P SSGCH (122,031)(115,159)(6,872)(6,872)
2460 PTD SO (262,133,488)(246,972,218)(15,161,270)(15,161,270)
2461 818 (425,265,929)(401,608,472)(23,657,457)(533,590)(24,191,047)
2462 1111P Less Non-Utility Plant
2463 NUTIL OTH
2464 (425,265.929)(401,608,472)(23,657,457)(533,590)(24,191,047)
2465
2466 111390 Accum Amtr - Capital Lease
2467 G-SITUS S (5,580,322)(5,580,322)
2468 P SG (1,701,025)(1,598,070)(102,954)(102,954)
2469 PTD SO 1,340,129 1,262,619 77,510 77,510
2470 (5,941,217)(5,915,773)(25,44)(25,44)
2471
2472 Remove Capital Leae Amtr 5,941,217 5,915,773 25,444 25,444
2473
2474 Total Accum Provision for Amortization 818 (456,ö3.105)(431.642,365)(24,420.740)(533.590)(24.954.331)
2475
2476
2477
2478
2479 Summary of Amortization by Factor
2480 S (23,351,001 )(22,594,303)(756,698)(756,698)
2481 DGP
2482 DGU
2483 SE (1,299,989)(1,217,557)(82,433)(82,433)
2484 SO (271,568,401 )(255,861,434)(15,706,967)(15,706,967)
2485 CN (97,706,463)(93,926,306)(3,780,157)(3,780,157)
2486 SSGCT
2487 SSGCH (122,031)(115,159)(6,872)(6,872)
2488 SG (67,956,437)(63,843,379)(4,113,058)(533,590)(4,646,648)
2489 Less Capital Lease 5,941,217 5,915,773 25,444 25,444
2490 Total Provision For Amortization by Factor (456,063,105)(431,642,365)(24,420,740)(533,590)(24,954,331 )
Rocky Mountain Power
RESULTS OF OPERATIONS
Page 12.1
USER SPECIFIC INFORMATION
STATE:
PERIOD:
IDAHO
DECEMBER 2010
FILE:
PREPARED BY:
DATE:
TIME:
JAM Dec 2010 10 GRC
Revenue Requirement Department
5/18/2011
10:37:27 AM
TYPE OF RATE BASE:
ALLOCATION METHOD:
Year-End
ROLLED-IN
FERC JURISDICTION:Separate Junsdiction
8 OR 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
47.40%
0.30%
52.30%
100.00%
5.78%
5.43%
10.50%
2.740%
0.016%
5.492%
8.248%
OTHER INFORMATION
For information and support regarding capital structure and cost of debt, see the testimony of Mr. BruceWiliams.
For information and support regarding return on common equity, see the testimony of Dr. Sam Hadaway.
ROLLED.IN Page 12.2Year-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 12.3 3,574,583,105 3,368,022,988 206,560,116 11,637,673 218,197,789
3 Interdepartmental 12.3 0 0 0 0 0
4 Special Sales 12.3 501,563,210 471,750,719 29,812,490 1,051,991 30,864,481
5 Other Operating Revenues 12.4 326,069,070 306,976,744 19,092,327 (5,260,834)13,831,492
6 Total Operating Revenues 12.4 4,402,215,385 4,146,750,451 255,464,934 7,428,829 262,893,763
7
8 Operating Expenses:
9 Steam Production 12.5 957,497,818 897,859,848 59,637,970 4,879,169 64,517,140
10 Nuclear Production 12.6 0 0 0 0 0
11 Hydro Production 12.7 40,481,667 38,031,517 2,450,150 226,019 2,676,169
12 Other Power Supply 12.9 922,755,661 862,996,539 59,759,122 9,092,101 68,851,224
13 Transmission 12.10 195,628,269 183,769,934 11,858,335 287,354 12,145,689
14 Distribution 12.12 208,550,302 198,123,470 10,426,832 590,671 11,017,503
15 Customer Accounting 12.12 92,750,645 87,978,639 4,772,006 (108,25)4,663,581
16 Customer Service & Infor 12.13 128,944,905 121,813,010 7,131,894 (5,923,722)1,208,172
17 Sales 12.13 0 0 0 0 0
18 Administrative & General 12.14 146,076,485 136,611,406 9,465,079 1,796,960 11,262,040
19
20 Total 0 & M Expenses 12.14 2,692.685,751 2,527,184,362 165,501,389 10,840,128 176,341,517
21
22 Depreciation 12.16 491,643,870 483,652,092 27,991,778 2,738,026 30,729,804
23 Amortization 12.17 44,975,946 42,481,316 2,494,630 272.898 2,767,529
24 Taxes Other Than Income 12.17 136,512,728 130,094,757 6,417,971 765,162 7,183,133
25 Income Taxes - Federal 12.20 (482,762,100)(458,051,074)(24,711,026)(11,404,080)(36,115,106)
26 Income Taxes - State 12.20 (58,348,093)(55,429,181 )(2,918,912)(1,466,540)(4,385,452)27 Income Taxes - Def Net 12.19 761,444,172 724,719,282 36,724,890 9,312,312 46,037,202
28 Investment Tax Credit Adj.12.17 (1,874,204)(1,652,566)(221,638)0 (221,638)
29 Misc Revenue & Expense 12.4 (5,388,606)(5,100,609)(287,997)(345,174)(633,171)
30
31 Total Operating Expenses 12.20 3,578,889,486 3,367,898,381 210,991,085 10,712,732 221,703,817
32
33 Operating Revenue for Return 823,325,919 778,852,071 44,473,849 (3,283,903)41,189,946
34
35 Rate Base:
36 Electric Plant in Service 12.30 21,682,524,069 20,426,186,152 1,256,337,918 54,091,394 1,310,429,312
37 Plant Held for Future Use 12.31 17,678,149 17,033,995 644,154 (644,154)0
38 Misc Deferred Debits 12.33 198,021,223 192,699,549 5,321,674 146,593 5,468,268
39 Elec Plant Acq Adj 12.31 57,330,243 53,860,334 3,469,909 0 3,469,909
40 Nuclear Fuel 12.31 0 0 0 0 0
41 Prepayments 12.32 45,378,667 42,685,486 2,693,181 0 2,693,181
42 Fuel Stock 12.32 184,380,973 172,689,333 11,691,641 2,355,158 14,046,799
43 Material & Supplies 12.32 186,133,158 175.106,323 11,026,835 0 11,026,835
44 Working Capital 12.33 64.521,474 60,858,348 3,663,126 (32,593)3,630,533
45 Weatherization Loans 12.31 8,619,651 5,438,648 3,181.004 0 3,181,004
46 Miscellaneous Rate Base 12.34 135,566 125,548 10,019 (10,019)0
47
48 Total Electric Plant 22,444,723,175 21,146,683,714 1,298,039,461 55,906,379 1,353.945,840
49
50 Rate Base Deductions:
51 Accum Prov For Depr 12.38 (6,842,986,868)(6,436,39,471 )(406,547,397)(787,372)(407,334,769)
52 Accum Prov For Amort 12.39 (456.063,105)(431,613.347)(24,449,758)(533,590)(24,983,348)
53 Accum Def Income Taxes 12.35 (2,999,250,147)(2,833,509,688)(165,740,459)(4,386,060)(170,126;18)
54 Unamortized ITC 12.35 (5,669,770)(5,629,625)(40,145)(118.179)(158,324)
55 Customer Adv for Const 12.34 (18,494,962)(17,662,878)(832,083)(334,536)(1,166,620)
56 Customer Service Deposits 12.34 0 0 0 0 0
57 Misc. Rate Base Deductions 12.34 (136,934,409)(134,027,093)(2,907,316)(1,568,700)(4,476,016)
58
59 Total Rate Base Deductions (10,459,399,260)(9,858,882.103)(600,517,158)(7,728,437)(608,245.595)
60
61 Total Rate Base 11,985,323,914 11,287,801,611 697,522,303 48,177,942 745,700,245
62
63 Return on Rate Base 6.869%6.376%5.524%
64
65 Return on Equity 7.865%6.922%5.292%
66 Net Power Costs 1,125,770,120 70,880,883 82,767,927
67 100 Basis Points in Equity:
68 Revenue Requirement Impact 101,022,166 5,879,292 6,285,375
69 Rate Base Decrease (847,935,908)(52,878,023)(64;498,621 )
ROLLED.IN Page 12.3Year.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 1,357,826,906 1,296,315,399 61,511,506 2,504,407 64,015,913
73
74 61 1,357,826,906 1.296,315.399 61,511,506 2,504,407 64.015.913
75
76 442 Commercial & Industrial Sales
77 0 S 2.176,375,421 2.031.797.692 144,577,729 9.006,259 153,583,988
78 P SE
79 PT SG
80
81
82 61 2,176,375.421 2,031,797,692 144,577,729 9,006,259 153.583.988
83
84 444 Public Street & Hi9hway Lighting
85 0 S 20,610,361 20,139,481 470.881 127.07 597,888
86 0 SO
87 61 20.610,361 20.139.481 470.881 127.07 597.888
88
89 445 Other Sales to Public Authority
90 0 S 19,770,416 19.770,416
91
92 61 19,770,416 19.770,416
93
94 448 Interdepartmental
95 DPW S
96 GP SO
97 61
98
99 Total Sales to Ultimate Customers B1 3,574,583,105 3,368,022,988 206,560,116 11,637,673 218,197,789
100
101
102
103 447 Sales for Resale-Non NPC
104 P S 9.040.737 9.040,737
105 9,040,737 9,040,737
106
107 447NPC Sales for Resale-NPC
108 P SG 491,619,370 461,864.146 29,755.225 1.109.256 30,864.481
109 P SE 903,103 845,37 57,266 (57,266)110 P SG
111 492,522,473 462.709.983 29,812,490 1.051.991 30,864,481
112
113 Total Sales for Resale 61 501.563,210 471.750.719 29,812.490 1.051,991 30.864,481
114
115 449 Provision for Rate Refund
116 P S
117 P SG
118
119
120 61
121
122 Total Sales from Electricity B1 4,076,146,315 3,839,773,708 236,372,607 12,689,663 249,062,270
123 450 Forfeited Discounts & Interest
124 CUST S 7,411,888 7,004.958 406,930 406,930
125 CUST SO
126 61 7,411,888 7.004.958 406.930 406,930
127
128 451 Mise Electric Revenue
129 CUST S 5,861,680 5.760,675 101.005 101,005
130 GP SG
131 GP SO 57,591 54,254 3.337 3,337
132 61 5.919.272 5,814,930 104.342 104,342
133
134 453 Water Sales
135 P SG 2.609 2,451 158 158
136 61 2.609 2,451 158 158
137
138 454 Rent of Electric Properl
139 DPW S 10,656,375 10.447.639 208,736 208.736
140 T SG 5,417,250 5.089.371 327.879 327.879
141 T SG
142 GP SO 3.485,471 3.283.514 201.957 201.957
143 61 19.559,096 18.820,525 738.571 738.571144
145
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Year-End
FERC 8US UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
146
147 456 Other Electric Revenue
148 DMSC S 96,891,344 90,951,471 5,939,873 (5,939,833)39
149 CUST CN
150 OTHSE SE 8,162,720 7,645,120 517,600 132,527 650,127
151 OTHSO SO 474,389 44,902 27,487 27,487
152 OTHSGR SG 187,647,753 176,290,387 11,357,366 546,471 11,903.37
153
154
155 81 293,176,206 275,333,880 17,842,326 (5,260,834)12,581,491
156
157 Total Other Electric Revenues 81 326,069,070 306,976,744 19,092,327 (5,260,834)13,831,492
158
159 Total Electric Operating Revenues 81 4,402,215,385 4,146,750,451 255,464,934 7,428,829 262,893,763
160
161 Summary of Revenues by Factor
162 S 3,704,445,128 3,491,228,468 213,216,660 5,697,840 218,914,500
163 CN
164 SE 9,065,823 8,90,957 574,866 75,261 650,127
165 SO 4,017,451 3,784,670 232,781 232,781
166 SG 684,686,982 643.246,355 41,440,627 1,655,728 43,096,355
167 DGP
168
169 Total Electric Operating Revenues 4,402,215.385 4,146.750,451 255,64,934 7,428,829 262,893,763
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 81
178
179 41170 Loss on Sale of Utility Plant
180 DPW S
181 T SG
182 81
183
184 4118 Gain from Emission Allowances
185 P S
186 P SE (2,817,551)(2,638,890)(178,662)(345,174)(523,836)
187 81 (2,817,551)(2,638,890)(178,662)(345,174)(523,836)
188
189 41181 Gain from Disposition of NOX Credits
190 P SE
191 81
192
193 4194 Impact Housing Interest Income
194 P SG
195 81
196
197 421 (Gain) I Loss on Sale of Utilty Plant
198 DPW S (764,726)(764,726)
199 T SG (761,976)(715,858)(46,119)(46,119)
200 T SG (469,173)(440,776)(28,397)(28,397)
201 PTD CN 121 116 5 5
202 PTD SO 1,951 1,838 113 113
203 P SG (577,251)(542,313)(34,938)(34,938)
204 81 (2,571,055)(2,461,719)(109,336)(109,336)
205
206 Total Miscellaneous Revenues (5,388,606)(5,100,609)(287,997)(345,174)(633,171)
207 Miscellaneous Expenses
208 4311 Interest on Customer Deposits
209 CUST S
210 81
211 Total Miscellaneous Expenses
212
213 Net Misc Revenue and Expense 81 (5,388,606)(5,100,609)(287,997)(345,174)(633,171)
214
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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 18.301.279 17.193.595 1.107.684 20.198 1.127.881
217 P SG 1.805.751 1.696.458 109.293 109.293
218 62 20.107.030 18.890.054 1.216.976 20.198 1.237.174
219
220 501 Fuel Related-Non NPC
221 P SE 15.015.379 14.063.250 952.129 (343)951.786
222 P SE
223 P SE
224 P SE
225 P SE 3.378.234 3.164.020 214.215 214.215
226 62 18.393.613 17.227.269 1.166.343 (343)1.166,000
227
228 501NPC Fuel Related-NPC
229 P S (914.987)(665.891)(249,096)249,096
230 P SE 581.140.995 544,290.708 36.850,287 4.650.292 41.500,579
231 P SE
232 P SE
233 P SE 48.110,124 45.059,450 3.050.674 3,050,674
234 62 628.336.133 588,684.267 39.651.865 4,899,388 44,551,253
235
236 Total Fuel Related 646,729.745 605.911 .537 40.818.209 4,899.045 45.717,254
237
238 502 Steam Expenses
239 P SG 31,477,336 29.572.173 1.905.163 22.559 1,927.722
240 P SG 6,994,684 6.571.332 423.353 423.353
241 62 38,472,021 36.143.505 2.328.516 22,559 2.351,075
242
243 503 Steam From Other Sources-Non-NPC
244 P SE 108 108
245 62 108 108
246
247 503NPC Steam From Other Sources-NPC
248 P SE 3.655.727 3,423,917 231.811 (21.223)210.587
249 62 3.655.727 3,423,917 231,811 (21.223)210.587
250
251 505 Electric Expenses
252 P SG 3.085.158 2.898,29 186.729 2.368 189,097
253 P SG 1,199.979 1.127.351 72.629 72,629
254 62 4.285.137 4.025.779 259,358 2.368 261.725
255
256 506 Misc. Steam Expense
257 P SG 46,109,239 43.318,81 2.790.758 66.006 2.856,765
258 P SE
259 P SG 1.933.634 1.816.601 117.033 117,033
260 62 48.042.874 45,135.082 2,907,791 66,006 2.973798
261
262 507 Rents
263 P SG 338,245 317.773 20,472 20,472
264 P SG 440 413 27 27
265 62 338.685 318.186 20,499 20,499
266
267 510 Maint Supervision & Engineering
268 P SG 4.580,349 4.303.123 277.225 (388.761)(111,536)
269 P SG 1.881.910 1,768,007 113.902 113,902
270 62 6,462.259 6.071.131 391.128 (388.761)2,367
271
272
273
274 511 Maintenance of Structures
275 P SG 25,069,456 23.552.129 1.517.327 8,966 1.526.293
276 P SG 411,499 386,593 24.906 24.906
277 62 25,480.955 23.938.722 1.542.233 8.966 1.551.199
278
279 512 Maintenance of 60iler Plant
280 P SG 105.721,429 99,322.648 6.398,781 252.065 6.650.847
281 P SG 7.201,452 6.765.584 435,867 435,867
282 62 112.922,881 106.088.232 6,834,649 252.065 7.086,714
283
284 513 Maintenance of Electric Plant
285 P SG 38,150,749 35,841.678 2,309.071 14,430 2,323,501
286 P SG 783,588 736.162 47,427 47,427
287 62 38.934.338 36,577.840 2,356,98 14.430 2,370,927
288
289 514 Maintenance of Misc. Steam Plant
290 P SG 9.254.784 8,694,639 560,145 3,410 563,555
291 P SG 2,811.384 2.641,225 170.159 170,159
292 62 12.066.167 11.335,863 730.304 3,410 733,713
293
294 Total Steam Power Generation B2 957,497,818 897,859,848 59,637,970 4,879,169 64,517,140
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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 62
298
299 518 Nuclear Fuel Expense
300 P SE
301
302 62
303
304 519 Coolants and Water
305 P SG
306 62
307
308 520 Steam Expenses
309 P SG
310 62
311
312
313
314 523 Electric Expenses
315 P SG
316 62
317
318 524 Misc. Nuclear Expenses
319 P SG
320 62
321
322 528 Maintenance Super & Engineering
323 P SG
324 62
325
326 529 Maintenance of Structures
327 P SG
328 B2
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 B2
343
344 535 Operation Super & Engineering
345 P DGP
346 P SG 4,590,184 4,312,364 277,821 9,074 286,895
347 P SG (764,519)(718,246)(46,272)(46,212)348
349 62 3,825,666 3,594,117 231,548 9,074 240,623
350
351 536 Water For Power
352 P DGP
353 P SG 212,409 199,553 12.856 105 12,961
354 P SG
355
356 62 212,409 199,553 12,856 105 12,961
357
ROLLED-IN Page 12.7
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 SG 3.246.477 3.049.985 196,93 202.066 398.559
361 P SG 203,031 190.743 12.288 12.288
362
363 62 3,449.509 3.240.727 208.781 202.066 410.848
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 17.855.445 16.774.745 1.080.699 11,139 1.091.839
375 P SG 7.340.718 6.896,422 44,296 444.296
376
377
378 62 25.196,163 23.671.167 1,524,996 11.139 1.536.135
379
380 540 Rents (Hydro Generation)
381 P DGP
382 P SG 116.623 109.564 7.059 (201)6.857
383 P SG 775 728 47 47
384
385 62 117.398 110.292 7.105 (201)6.904 -
386
387 541 Maint Supervision & Engineering
388 P DGP
389 P SG 469 441 28 0 29
390 P SG
391
392 62 469 441 28 0 29
393
394 542 Maintenance of Structures
395 P DGP
396 P SG 1.317,460 1.237,721 79.739 617 80.356
397 P SG 112.932 106.097 6.835 6.835
398
399 B2 1,430.392 1.343.818 86.574 617 87.191
400
401
402
403
404 543 Maintenance of Dams & Waterways
405 P DGP
406 P SG 1.331.256 1.250,682 80.574 1.016 81.590
407 P SG 628,44 590,407 38,037 38.037
408
409 62 1.959,700 1.841.089 118.611 1,016 119.626
410
411 544 Maintenance of Electric Plant
412 P DGP
413 P SG 1.249.523 1.173.895 75.627 1,309 76.936
414 P SG 385,648 362,307 23.341 23.341
415
416 62 1,635,171 1.536.202 98.969 1.309 100,278
417
418 545 Maintenance of Misc. Hydro Plant
419 P DGP
420 P SG 1.841.743 1.730.271 111,471 894 112,365
421 P SG 813,048 763.838 49,210 49.210
422
423 62 2.654.790 2,494.109 160.681 894 161,575
424
425 Total Hydraulic Power Generation B2 40,481,667 38,031,517 2,450,150 226,019 2,676.169
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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 358,628 336,922 21,706 2 21,708
429 P SG
430 62 358,628 336,922 21,706 2 21,708
431
432 547 Fuel-Non-NPC
433 P SE
434 P SE
435 62
436
437 547NPC Fuel-NPC
438 P SE 411,275,695 385,196,607 26,079,089 (2,147,890)23,931,198
439 P SE 21,345,038 19,991,544 1,353,494 1,353,94
440 62 432,620,733 405,188,151 27,432,583 (2,147,890)25,284,692
441
442 548 Generation Expense
443 P SG 13,323.739 12,517,320 806,418 6,999 813,17
444 P SG 1,314,796 1,235,218 79,578 79,578
445 62 14,638,534 13,752,538 885,996 6,999 892,995
446
447 549 Miscellaneous Other
448 P SG 3,440,696 3,232,448 208,248 3,393 211,641
449 P SG 15,260,859 14,337,197 923,662 113,745 1,037,408
450 62 18,701,556 17,569,646 1,131,910 117,138 1,249,048
451
452
453
454
455 550 Rents
456 P SG 30,Q6 28,256 1,820 1,820
457 P SG 3,528,603 3,315,034 213,568 213,568
458 62 3,558,679 3,343,290 215,389 215,389
459
460 551 Maint Supervision & Engineering
461 P SG
462 62
463
464 552 Maintenance of Structures
465 P SG 1,056,123 992,201 63,922 224 64,146
466 P SG 184,471 173,306 11,165 11,165
467 62 1,240,594 1,165,507 75,087 224 75,311
468
469 553 Maint of Generation & Electric Plant
470 P SG 4,438,293 4,169,666 268,627 318,657 587,284
471 P SG 2,101,615 1,974,415 127,200 127,200
472 P SG 2,456,496 2,307,817 148,679 148,679
473 62 8,996,404 8,51,897 544,507 318,657 863,164
474
475 554 Maintenance of Misc. Other
476 p SG 728,404 684,318 44,087 166 44,252
477 P SG 1,331,445 1,250,859 80,586 80,586
478 P SG 136,317 128,066 8,251 8,251
479 62 2,196,166 2,063,243 132,923 166 133,089
480
481 Total Other Power Generation B2 482,311,295 451,871,195 30,440,100 (1,704,704)28,735,396
482
483
484 555 Purchased Power-Non NPC
485 DMSC S (36,817,673)(37,424,309)606,635 (606,635)
486 (36,817,673)(37,424,309)606,635 (606,635)
487
488 555NPC Purchased Power-NPC
489 P SG 469,600,699 441,178,153 28,422,546 2,918,183 31,340,729
490 P SE (52,775,347)(49,428.850)(3,346,497)7,026,558 3,680,061
491 Seasonal Co P SG
492 DGP
493 416,825,351 391,749,303 25,076,049 9,944,741 35,020,790
494
495 Total Purchased Power 62 380,007,678 354,324,994 25,682,684 9,338,106 35,020,790
496
497 556 System Control & Load Dispatch
498 p SG 877,454 824,346 53,108 540 53,648
499
500 62 877,454 824,346 53,108 540 53,648
501
502
ROLLED-IN Page 12.9
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
503
504 557 Other Expenses
505 P S (183.792)(150.819)(32.973)975.961 942.988
506 P SG 58.620.601 55.072.594 3.548.007 482.199 4.030.206
507 P SGCT 1.122,425 1.054.229 68.196 68.196
508 P SE
509 P SG
510 P TROJP
511
512 62 59.559.234 55.976.003 3.583.231 1,458.160 5.041.390
513
514 Embedded Cost Differentials
515 Company Owned Hyd P DGP
516 Company Owned Hyd P SG
517 Mid-C Contract P MC
518 Mid-C Contract P SG
519 Existing OF Contracts P S
520 Existing OF Contracts P SG
521
522
523
524 Hydro Endowment Fixed Dollar Proposal
525 Klamath Surcharge Sit P S
526 ECD Hydro P S
527
528
529 Total Other Power Supply B2 44,44,366 411,125,34 29,319,023 10,796,805 40,115,828
530
531 Total Production Expense B2 1,920,735,146 1,798,887,904 121,847,242 14,197,290 136,044,532
532
533
534 Summary of Production Expense by Factor
535 S (37.916.453)(38.241.019)324.566 618,422 942.988
536 SG 926.383.328 870.314.048 56.069.280 4.071.366 60.140.645
537 SE 1.031.145.846 965.760.645 65.385.201 9.507.502 74.892.703
538 SNPPH
539 TROJP
540 SGCT 1.122,425 1,054.229 68,196 68.196
541 DGP
542 DEU
543 DEP
544 SNPPS
545 SNPPO
546 DGU
547 MC
548 SSGCT
549 SSECT
550 SSGC
551 SSGCH
552 SSECH
553 Total Production Expense by Factor 62 1.920.735.146 1,798.887.904 121.847,242 14,197,290 136.044.532
554 560 Operation Supervision & Engineering
555 T SG 5.041.115 4.736.002 305,113 5.073 310.186
556
557 62 5.041,115 4.736.002 305,113 5,073 310.186
558
559 561 Load Dispatching
560 T SG 10,336,896 9.711.256 625.640 11.331 636.971
561
562 62 10.336.896 9.711.256 625,640 11,331 636.971
563 562 Station Expense
564 T SG 2.124.825 1.996.220 128.605 1.457 130.062
565
566 62 2.124.825 1.996.220 128.605 1,457 130.062
567
568 563 Overhead Line Expense
569 T SG 120.209 112.934 7,276 92 7.367
570
571 62 120.209 112.934 7,276 92 7.367
572
573 564 Underground Line Expense
574 T SG
575
576 62
577
ROLLED-IN Page 12.10
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
578 565 Transmissior of Electricity by Others
579 T SG
580 T SE
581
582
583 565NPC Transmission of Electricity by Others-NPC
584 T SG 130,633,756 122,727,158 7,906,598 319,092 8,225,690
585 T SE 6,220,893 5,826,425 394,468 (55,073)339,395
586 136,854,649 128,553,583 8,301,066 264,019 8,565,085
587
588 Total Transmission of Electricity by Others 82 136,854,649 128,553.583 8,301,066 264,019 8,565,085
589
590 566 Misc. Transmission Expense
591 T SG 4,257,862 4,000.155 257,707 (48,019)209.688
592
593 82 4.257,862 4,000.155 257.707 (48,019)209.688
594
595 567 Rents - Transmission
596 T SG 1.312,382 1,232,950 79,432 207 79.639
597
598 82 1.312,382 1.232,950 79,432 207 79.639
599
600 568 Maint Supervision & Engineering
601 T SG 1,334,303 1,253,545 80,759 1,350 82.109
602
603 82 1,334,303 1.253,545 80,759 1,350 82.109
604
605 569 Maintenance of Structures
606 T SG 4,669,784 4,387,146 282,638 3,321 285,959
607
608 82 4,669.784 4,387,146 282,638 3,321 285,959
609
610 570 Maintenance of Station Equipment
611 T SG 10,092,385 9,481.544 610,841 8,132 618,973
612
613 82 10,092,385 9,481.544 610.841 8.132 618,973
614
615 571 Maintenance of Overhead Lines
616 T SG 19.1i3,510 18,013,035 1,160,475 40.363 1.200,839
617
618 82 19,173,510 18,013,035 1,160.475 40.363 1,200,839
619
620 572 Maintenance of Underground Lines
621 T SG 36,881 34,649 2,232 18 2,251
622
623 82 36,881 34,649 2,232 18 2.251
624
625 573 Maint of Misc. Transmission Plant
626 T SG 273,467 256,915 16,552 9 16.560
627
628 82 273,467 256,915 16,552 9 16,560
629
630 Total Transmission Expense B2 195,628,269 183,769,934 11,858,335 287,354 12,145,689
631
632 Summary of Transmission Expense by Factor
633 SE 6,220.893 5,826,425 394,468 (55,073)339,395
634 SG 189,407,376 177 .943,509 11,463,867 342,427 11,806,294
635 SNPT
636 Total Transmission Expense by Factor 195,628.269 183.769,934 11,858,335 287.354 12,145,689
637 580 Operation Supervision & Engineering
638 DPW S 53.020 88,736 (35,716)(35,716)
639 DPW SNPD 15.572,431 14,850,486 721,945 15,139 737,084
640 82 15,625,451 14,939,222 686,229 15.139 701,368
641
642 581 Load Dispatching
643 DPW S
644 DPW SNPD 13.735,481 13,098.698 636,783 13,264 650.047
645 82 13.735,481 13,098,698 636,783 13,264 650,047
646
647 582 Station Expense
648 DPW S 3,788,937 3,549,316 239,621 2,641 242.261
649 DPW SNPD 23.895 22.787 1,108 19 1,127
650 82 3,812.831 3,572,103 240,728 2.660 243.389
651
ROLLED.IN Page 12.11
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
652 583 Overhead Line Expenses
653 DPW S 5.725.809 5,532.611 193.198 3.620 196.818
654 DPW SNPD 36.344 34,659 1.685 20 1.705
655 62 5.762.152 5.567.270 194.882 3.640 198.522
656
657 584 Underground Line Expense
658 DPW S 287 264 23 23
659 DPW SNPD
660 62 287 264 23 23
661
662 585 Street Lighting & Signal Systems
663 DPW S
664 DPW SNPD 209,265 199.563 9.702 209 9.911
665 62 209.265 199,563 9.702 209 9.911
666
667 586 Meter Expenses
668 DPW S 5.377.919 5.102,422 275.498 5.034 280.532
669 DPW SNPD 1.186,441 1,131,437 55.004 949 55,953
670 62 6.564,361 6.233.859 330.502 5.983 336,85
671
672 587 Customer Installation Expenses
673 DPW S 12.634,849 12.235.508 399.341 7,224 406,565
674 DPW SNPD
675 62 12.634.849 12.235.508 399.341 7.224 406.565
676
677 588 Misc. Distribution Expenses
678 DPW S 1.310,808 1.308,97 2.311 (1.147)1.164
679 DPW SNPD 4.576.455 4.364,288 212.167 206 212.373
680 62 5.887,263 5.672.785 214,478 (941)213,37
681
682 589 Rents
683 DPW S 3.187.858 3.175.008 12.850 16 12,866
684 DPW SNPD 65.814 62.763 3.051 3,051
685 82 3.253.672 3.237.771 15,901 16 15,917
686
687 590 Maint Supervision & Engineering
688 DPW S 816,745 763.677 53.068 923 53.991
689 DPW SNPD 4.676,484 4,459.680 216,804 4.579 221.382
690 62 5,93,229 5.223.358 269.871 5.502 275.373
691
692 591 Maintenance of Structures
693 DPW S 1.749,265 1.594.805 154,460 154,460
694 DPW SNPD 79.605 75.914 3,691 3.691
695 62 1.828.870 1.670.719 158.151 158.151
696
697 592 Maintenance of Station Equipment
698 DPW S 11.145.163 10,410.931 734.232 10.769 745.001
699 DPW SNPD 1,476,908 1,408,438 68.470 1.374 69.844
700 82 12.622.071 11.819.369 802.702 12.143 814.844
701 593 Maintenance of Overhead Lines
702 DPW S 83.673.582 78.569,424 5.104.158 507.039 5.611.197
703 DPW SNPD 1.056.813 1,007.819 48.994 (567)48,428
704 62 84.730.396 79,577.243 5.153.152 506,472 5.659.624
705
706 594 Maintenance of Underground Lines
707 DPW S 22.786.414 22,099.175 687.240 8,584 695.823
708 DPW SNPD
709 82 22.786,414 22,099.175 687.240 8,584 695.823
710
711 595 Maintenance of Line Transformers
712 DPW S
713 DPW SNPD 883,285 842.335 40.949 720 41.670
714 82 883.285 842,335 40.949 720 41.670
715
716 596 Maint of Street Lighting & Signal Sys.
717 DPW S 4.084.559 3.927.770 156,790 2.700 159,489
718 DPW SNPD
719 82 4.084.559 3.927,770 156.790 2.700 159,489
720
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Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
721 597 Maintenance of Meters
722 DPW S 4,802.396 4.500,189 302,207 5,541 307,749
723 DPW SNPD 1,088,248 1,037,796 50,452 738 51,189
724 62 5,890,644 5,537,985 352,659 6,279 358,938
725
726 598 Maint of Misc. Distribution Plant
727 DPW S 2,056,220 2,011,413 44,807 44,807
728 DPW SNPD 689,001 657,058 31,942 1,076 33,018
729 62 2,745,221 2,668,72 76,749 1,076 77,826
730
731 Total Distribution Expense B2 208,550,302 198,123,470 10,426,832 590,671 11,017,503
732
733
734 Summary of Distribution Expense by Factor
735 S 163,193,833 154.869,747 8,324,086 552,944 8,877,030
736 SNPD 45,356,469 43,253,723 2,102,746 37,726 2.140,473
737
738 Total Distribution Expense by Factor 208.550.302 198,123,470 10.426.832 590,671 11,017,503
739
740 901 Supervision
741 CUST S 1,704 1,704
742 CUST CN 2,495,978 2.399,412 96,567 1.613 98.179
743 62 2,497,682 2,401,115 96,567 1.613 98,179
744
745 902 Meter Reading Expense
746 CUST S 20,633,641 18,949,062 1,684,580 29,696 1,714,275
747 CUST CN 1,919,847 1,845,571 74,277 1,239 75,516
748 62 22,553,488 20,794,632 1,758,856 30,935 1,789,791
749
750 903 Customer Receipts & Collections
751 CUST S 7.456,791 7,065,477 391,315 6,262 397,577
752 CUST CN 47,482,101 45,645,070 1.837,031 26,768 1,863,799
753 62 54,938,892 52,710,547 2,228,346 33,030 2,261,376
754
755 904 Uncollectible Accounts
756 CUST S 12,495,007 11,816,850 678,156 (174,096)504.061
757 P SG
758 CUST CN 95.649 91,946 3,701 3,701
759 62 12,590,656 11,908,799 681,857 (174,096)507,761
760
761 905 Misc. Customer Accounts Expense
762 CUST S 5,016 5,016
763 CUST CN 164,911 158,531 6,380 93 6,474
764 62 169,927 163,546 6,380 93 6,474
765
766 Total Customer Accounts Expense B2 92,750,645 87,978,639 4,772,006 (108,425)4,663,581
767
768 Summary of Customer Accts Exp by Factor
769 S 40,592.159 37,838.108 2,754,051 (138,138)2,615,913
770 CN 52,158,486 50,140,531 2,017,955 29,713 2,047,668
771 SG
772 Total Customer Accounts Expense by Factor 92,750,645 87,978,639 4,772.06 (108.25)4,663,581
773
774 907 Supervision
775 CUST S
776 CUST CN 263,903 253,693 10,210 203 10,413
777 62 263,903 253,693 10,210 203 10,413
778
779 908 Customer Assistance
780 CUST S 121,361,303 114.557,969 6,803,334 (5,930,478)872,856
781 CUST CN 2,794,497 2,686,381 108,116 2,114 110,230
782
783
784 62 124,155,800 117,244,350 6,911,450 (5.928,364)983.086
785
ROLLED.IN Page 12.13Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
786 909 Informational & Instructional Adv
787 CUST S 645,251 585,129 60.122 3,571 63,693
788 CUST CN 3,789,781 3,643,159 146,623 867 147,490
789 82 4,435,032 4,228,287 206,745 4,438 211,183
790
791 910 Misc. Customer Service
792 CUST S
793 CUST CN 90,169 86,680 3,489 3,490
794
795 82 90,169 86,680 3,489 3,490
796
797 Total Customer Service Expense B2 128,94,905 121,813,010 7,131,894 (5,923,722)1,208,172
798
799
800 Summary of Customer Service Exp by Factor
801 S 122,006,554 115,143,098 6,863,457 (5,926,907)936,550
802 CN 6,938,350 6,669,913 268,437 3,186 271,623803
804 Total Customer Service Expense by Factor 82 128,944,905 121,813,010 7,131,894 (5,923,722)1,208,17
805
806
807 911 Supervision
808 CUST S
809 CUST CN
810 82
811
812 912 Demonstration & Selling Expense
813 CUST S
814 CUST CN
815 82
816
817 913 Advertising Expense
818 CUST S
819 CUST CN
820 82
821
822 916 Misc. Sales Expense
823 CUST S
824 CUST CN
825 82
826
827 Total Sales Expense 82
828
829
830 Total Sales Expense by Factor
831 S
832 CN
833 Total Sales Expense by Factor
834
835 Total Customer Service Exp Including Sales B2 128,944,905 121,813,010 7,131,894 (5,923,722)1,208,172
836 920 Administrative & General Salaries
837 PTD S (5,230,152)(5,723,882)493,730 (493,730)(0)838 CUST CN
839 PTD SO 71,688,978 67,535,145 4,153,833 380,524 4,534,357
840 82 66,458,826 61,811,263 4,647,563 (113,206)4,534,357
841
842 921 Offce Supplies & expenses
843 PTD S 736,310 687,081 49,229 49,229844CUSTCN
845 PTD SO 9,237,574 8,702,326 535,247 (2,787)532,461
846 82 9,973,883 9,389,407 584,476 (2,787)581,689847
848 922 A&G Expenses Transferred
849 PTD S
850 CUST CN
851 PTD SO (28,375,128)(26,731,004)(1,644,124)35,815 (1,608,309)852 82 (28,375,128)(26,731,004)(1,644,124)35,815 (1,608,309)853
ROLLED-IN Page 12.14
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
854 923 Outside Services
855 PTD S 8,195 8,195
856 CUST CN
857 PTD SO 9,396,107 8,851,674 544,433 141,157 685,590
858 B2 9,404,302 8,859,869 544,433 141,157 685,590
859
860 924 Properly Insurance
861 PT S
862 PT SG 88,661 88,661
863 PTD SO 23,341,430 21,988,971 1,352,459 (571,407)781,052
864 B2 23,341,430 21,988,971 1,352,459 (482,745)869,714
865
866 925 Injuries & Damages
867 PTD SO 8,492,514 8,000,438 492,077 (22,932)469,144
868 B2 8,492,514 8,000,438 492,077 (22,932)469.144
869
870 926 Employee Pensions & Benefits
871 LABOR S
872 CUST CN
873 LABOR SO
874 B2
875
876 927 Franchise Requirements
877 DMSC S
878 DMSC SO
879 B2
880
881 928 Regulatory Commission Expense
882 DMSC S 13.874.697 12,675.629 1.199,068 39,083 1,238,151
883 CUST CN
884 DMSC SO 1.538,229 1.449.101 89.129 239 89,367
885 FERC SG 2.513,914 2.361.760 152.154 152,154
886 B2 17.926,840 16.486,489 1.440,351 39,322 1,479,673
887
888 929 Duplicate Charges
889 LABOR S
890 LABOR SO (6,130,868)(5.775,630)(355.237)(1,172)(356,409)
891 B2 (6,130,868)(5.775,630)(355.237)(1,172)(356,409)
892
893 930 Misc General Expenses
894 PTD S 2,718,026 2,705,076 12,950 192.048 204,998
895 CUST CN 1.601 1.539 62 (7)55
896 P SG
897 LABOR SO 13.592,405 12,804.828 787,577 2,008,412 2.795,989
898 B2 16.312.031 15,511.443 800.589 2,200,453 3.001.042
899
900 931 Rents
901 PTD S 993,159 993.159
902 PTD SO 5.344,545 5.034.869 309,676 (34)309,62
903 B2 6.337.703 6.028.028 309.676 (34)309.642
904
905 935 Maintenance of General Plant
906 G S 22.861 22,861
907 CUST CN
908 G SO 22,312,089 21.019.273 1,292.816 3.089 1.295,906
909 B2 22,334,950 21.042,134 1,292.816 3.089 1.295.906
910
911 Total Administrative & General Expense B2 146,076.485 136,611,406 9,465,079 1,796,960 11,262,040
912
913 Summary of A&G Expense by Factor
914 S 13,123,095 11,368.118 1.754,977 (262,599)1,492,378
915 SO 130,437,875 122,879,988 7.557,886 1,970.905 9,528,791
916 SG 2,513.914 2,361,760 152,154 88.661 240,816
917 CN 1.601 1,539 62 ~7)55
918 Total A&G Expense by Factor 146,076.485 136,611.406 9.465.079 1.796,9 0 11,262,040
919
920 Total O&M Expense B2 2,692,685,751 2,527,184,362 165,501,389 10,840,128 176,341,517
ROLLED-IN Page 12.15
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
921 403SP Steam Depreciation
922 P SG 22.205.504 20.861.518 1.343.986 1.343.986
923 P SG 25.715.098 24,158.693 1.556,404 1.556.404
924 P SG 63.751.644 59.893.081 3.858.563 1.051.088 4.909.651
925 P SG 7,844.012 7.369.254 474.758 474.758
926 B3 119.516.259 112.282.546 7.233.712 1.051.088 8.284.800
927
928 403NP Nuclear Depreciation
929 P SG
930 B3
931
932 403HP Hydro Depreciation
933 P SG 3.407.623 3.201.377 206.246 206.246
934 P SG 1.007.037 946.086 60.951 60.951
935 P SG 7.864,486 7,388,89 475.997 305.083 781.080
936 P SG 3.557.399 3.342.088 215.311 215.311
937 B3 15.836.545 14.878.040 958.506 305.083 1.263.589
938
939 4030P Other Production Depreciation
940 P SG 123.595 116.114 7,481 7.481
941 P SG 31.868.578 29.939.735 1.928.843 460,531 2.389.374
942 P SG 2.601.101 2.443.669 157,431 157,431
943 P SG 73.261.078 68.826.957 4,434.121 4.434.121
944 B3 107.854.351 101.326,75 6.527.876 460.531 6.988,407
945
946 403TP Transmission Depreciation
947 T SG 11.210.232 10,531.734 678,98 678,498
948 T SG 12,494.962 11.738.705 756.257 756.257
949 T SG 47.973,502 45.069.909 2.903.592 895.587 3.799,180
950 B3 71.678,696 67.340.348 4,338.348 895.587 5.233.935
951
952
953
954 403 Distnbution Depreciation
955 360 Lond & Lond Right. DPW S 307.179 289.385 17.794 17.794
956 361 strctre DPW S 1,149.215 1.126.198 23,017 23.017
957 362 Station Equipment DPW S 12.399.378 11.765.381 633.997 633.997
958 363 Storage Battery Eqi DPW S 29.272 29.272
959 364 Poles & Towers DPW S 34.584.953 32,455,413 2.129.540 471 2.130.011
960 365 OH Conducrs DPW S 19.225.134 18.255.947 969.187 969.187
961 366 UG Conduit DPW S 7.784.052 7.621.932 162.121 162.121
962 367 UG Conducr DPW S 17.901.089 17,418.940 482.149 482.149
963 368 Line Tran DPW S 27.722.730 26.257.642 1,465.088 1,465.088
964 369 Service DPW S 12.019.012 11.478,139 540.873 540.873
965 370 Meters DPW S 6,471.787 6,025.308 446,479 446,79
966 371 Insl Cust Prem DPW S 495.546 487.909 7.637 7.637
967 372 leased Propey DPW S
968 373 Street lighting DPW S 2.211.652 2.182.252 29.400 29,400
969 B3 142.300.998 135,393.717 6.907.280 471 6.907.752
970
971 403GP General Depreciation
972 G-SITUS S 12,056.052 11.313.018 743,034 13.380 756,414
973 PT SG 328.358 308,484 19.874 19.874
974 PT SG 574.222 539,467 34,755 34.755
975 P SE 22.664 21,227 1,437 1,437
976 CUST CN 1.704.508 1.638.562 65.946 65.946
977 G-SG SG 5.817.168 5.465,084 352.084 12.903 364.986
978 PTD SO 13.800.885 13.001.229 799.657 (1.017)798.640
979 G-SG SG 6.010 5.646 364 364
980 G-SG SG 147,156 138.249 8.907 8,907
981 B3 34.457.022 32,430.967 2.026.056 25.266 2.051.322
982
983 403GVO General Vehicles
984 G-SG SG
985 B3
986
987 403MP Mining Depreciation
988 P SE
989 B3
990
ROLLED-IN Page 12.16
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAl
991 403EP Experimental Plant Depreciation
992 P SG
993 P SG
994 B3
995 4031 ARO Depreciation
996 P S
997 83
998
999
1000 Total Depreciation Expense B3 491,64,870 463,652,092 27,991,778 2,738,026 30,729,8(14
1001
1002 Summary S 154,357,049 146,706,735 7,650,314 13,852 7,664,166
1003 DGP
1004 DGU
1005 SG 321,758,764 302,284,340 19,474,424 2,725,192 22,199,616
1006 SO 13,800,885 13,001,229 799,657 (1,017)798,640
1007 CN 1,704,508 1,638,562 65,946 65,946
1008 SE 22,664 21,227 1,437 1,437
1009 SSGCH
1010 SSGCT
1011 Total Depreciation Expense By Factor 491,643,80 463,652,092 27,991,778 2,738,026 30,729,804
1012
1013 404GP Amort of L T Plant - Capital Lease Gen
1014 I-SITUS S 1,478,533 1,478,533
1015 I-SG SG
1016 PTD SO 1,166,807 1,099,199 67,608 67,608
1017 P SG
1018 CUST CN 275,829 265,157 10,672 10,672
1019 P SG
1020 84 2,921,169 2,842,890 78,279 78,279
1021
1022 404SP Amort of L T Plant - Cap Lease Steam
1023 P SG
1024 P SG
1025 B4
1026
1027 4041P Amort of L T Plant -Intangible Plant
1028 I-SITUS S 184,245 163,713 20,532 20,532
1029 P 5E 12,088 11,322 767 767
1030 I-SG 5G 9,041,830 8,494,574 547,256 568,382 1,115,639
1031 PTD SO 14,250,413 13,424,710 825,703 825,703
1032 CU5T CN 5,532,601 5,318,551 214,050 214,050
1033 1-5G SG 2,615,539 2,457,233 158,305 158,305
1034 I-SG 5G 309,282 290,563 18,719 18,719
1035 P 5G
1036 I-SG SG
1037 1-5G SG 54,154 50,876 3,278 3,278
1038 P SG (197,996)(186,013)(11,984)(11,984)1039 84 31,802,156 30,025,529 1,776,627 568,382 2,345,009
1040
1041 404MP Amort of L T Plant - Mining Plant
1042 P 5E
1043 B4
1044
1045 4040P Amort of L T Plant - Other Plant
1046 P 5G
1047 B4
1048
1049
1050 404HP Amortization of Other Electric Plant
1051 P 5G 122,773 115,342 7,431 7,431
1052 P SG 46,413 43,604 2,809 2,809
1053 P SG
1054 B4 169,186 158,946 10,240 10,240
1055
1056 Total Amortization of Limited Term Plant B4 34,892,511 33,027,365 1,865,146 568,382 2,433,528
1057
1058
1059 405 Amortization of Other Electric Plant
1060 GP 5
1061
1062 84
1063
ROLLED-IN Page 12.17
Year.End
FERC 6US UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1064 406 Amortization of Plant Acquisition Adj
1065 P S
1066 P SG
1067 P SG
1068 P SG 5.518.393 5.184,392 334.000 334.000
1069 P SO
1070 64 5.518,393 5.184,392 334.000 334.000
1071 407 Amort of Prop Losses, Unrec Plant. etc
1072 DPW S (302,455)(302.455)
1073 GP SO
1074 P SG-P 2,860.972 2.687.811 173.160 173.160
1075 P SE
1076 P SG (173.160)(173.160)
1077 P TROJP 2.006.526 1,884.202 122.324 (122.324)
1078 64 4.565,043 4,269.559 295,84 (295,84)(0)
1079
1080 Total Amortization Expense 64 44,975,946 42,481,316 2,494,630 272,898 2,767,529
1081
1082
1083
1084 Summary of Amortization Expense by Factor
1085 S 1.360.324 1.339.792 20.532 20.532
1086 SE 12.088 11.322 767 767
1087 TROJP 2.006.526 1.884,202 122.324 (122,324)
1088 DGP
1089 DGU
1090 SO 15.417.220 14.523.909 893.311 893.311
1091 SSGCT
1092 SSGCH
1093 SG-P 2.860.972 2.687.811 173.160 173.160
1094 CN 5.808.430 5.583.708 224.722 224.722
1095 SG 17.510.387 16,450.572 1,059.815 395.222 1,455.037
1096 Total Amortization Expense by Faclor 44.975.946 42,481,316 2.494.630 272,88 2.767.529
1097 408 Taxes Other Than Income
1098 DMSC S 25.831.078 25.831.078
1099 GP GPS 100.361.44 94,546.256 5.815.185 765.162 6,580,347
1100 GP SO 9,440.796 8.893.773 547.023 547.023
1101 P SE 879,415 823.651 55.764 55.764
1102 P SG
1103 DMSC OPRV-ID
1104 GP EXCTAX
1105 GP SG
1106
1107
1108
1109 Total Taxes Other Than Income 65 136,512.728 130,094,757 6,417,971 765,162 7,183,133
1110
1111
1112 41140 Deferred Investment Tax Credit - Fed
1113 PTD DGU (1.874.204)(1.652.566)(221,638)(221.638)
1114
1115 67 (1.874.204)(1.652.566)(221.638)(221.638)
1116
1117 41141 Deferred Investment Tax Credit - Idaho
1118 PTD DGU
1119
1120 67
1121
1122 Total Deferred ITC 67 (1,874,204)(1,652,566)(221,638)(221,638)
1123
ROLLED-IN Page 12.18
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1124
1125 427 Interest on Long-Term Debt
1126 GP S 1,092,163 1,092,163
1127 GP SNP 363.203,396 342,362,355 20,841,041 20,841,041
1128 B6 363,203,396 342,362,355 20,841,041 1,092,163 21,933,204
1129
1130 428 Amortization of Debt Disc & Exp
1131 GP SNP 6,058,937 5,711,268 347,669 347,669
1132 B6 6,058,937 5,711.268 347,669 347,669
1133
1134 429 Amortization of Premium on Debt
1135 GP SNP (2,718)(2.562)(156)(156)1136 B6 (2,718)(2,562)(156)(156)
1137
1138 431 Other Interest Expense
1139 NUTIL OTH
1140 GP SO
1141 GP SNP 12,367,152 11,657,510 709,642 709,642
1142 B6 12,367.152 11,657,510 709,62 709,642
1143
1144 432 AFUDC - Borrowed
1145 GP SNP (44,618,458)(42.058,198)(2,560,260)(2,560,260)
1146 (44,618,458)(42,058,198)(2,560,260)(2,560,260)
1147
1148 Total Elec. Interest Deductions for Tax B6 337,008.309 317,670.373 19,337,936 1,092,163 20,430,099
1149
1150 Non-Utility Portion of Interest
1151 427 NUTIL NUTIL
1152 428 NUTIL NUTIL
1153 429 NUTIL NUTIL
1154 431 NUTIL NUTIL
1155
1156 Total Non-utilty Interest
1157
1158 Total Interest Deductions for Tax B6 337,008,309 317,670,373 19.337,936 1,092,163 20,430.099
1159
1160
1161 419 Interest & Dividends
1162 GP S
1163 GP SNP 79,298,238)4,550,227)201,475 4,348,752)
1164 Total Operating Deductions for Tax B6 7 ,5 ,75
1165
1166
1167 41010 Deferred Income Tax - Federal-DR
1168 GP S 27.885.806 27,747,783 138,023 (110.06)28.017
1169 P TROJD
1170 PT SG 31.324 29,428 1,896 1,896
1171 LABOR SO 8.859.456 8,346.117 513,338 (5,052)508,286
1172 GP SNP 44,945,274 42,366,261 2.579.013 2,579,013
1173 P SE 18,245,954 17,088.974 1.156,980 548,997 1,705,978
1174 PT SG 42,534,872 39,960,452 2,574,420 8.940,991 11,515,411
1175 P SGCT
1176 GP GPS 24,704,090 23,272,675 1,431,415 1,431,415
1177 TAXDEPR TAXDEPR 934,697,178 887,014,033 47,683,145 47,683,145
1178 CUST BADDEBT
1179 CUST CN 18,276 17.569 707 707
1180 P IBT
1181 DPW SNPD
1182 B7 1,101,922,230 1,045,843,293 56,078,937 9,374,930 65,453,868
1183
ROLLED-IN Page 12.19
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1184
1185
1186 41110 Deferred Income Tax - Federal-CR
1187 GP S (34,496,605)(32,484,238)(2,012,367)338,916 (1,673,451 )1188 P SE (12,433,468)(11,645,059)(788,409)25,713 (762,696)
1189 P SG (538,368)(505,783)(32,585)(32,585)1190 GP SNP (28,801,933)(27,149,244)(1,652,689)(1,652,689)1191 PT SG (8,590,259)(8,070,334)(519,925)(1,094,411 )(1,614,336)1192 DPW CIAC (17,775,107)(16,951,045)(824,062)(824,062)
1193 LABOR SO (17,583,311)(16,564,491 )(1,018.820)623,107 (395,713)1194 PT SNPD (3,638,99)(3,469,817)(168,682)(168,682)1195 CUST TAXDEPR
1196 P SGCT (425,972)(400,091)(25,881)(25,881)1197 BOOKDEPR SCHMDEXP (214,973,755)(202,734,209)(12,23ll,546)(12,239,546)
1198 P TROJD (721,757)(677,700)(44,057)44,057
1199 CUST BADDEBT (499,023)(471,998)(27,025)(27,025)1200 GP GPS
1201
1202 B7 (340,478,057)(321,124,010)(19.354,047)(62,619)(19,416,666)1203
1204 Total Defarred Income Taxes B7 761,44,172 724,719.282 36,724,890 9.312,312 46,037,202
1205 SCHMAF Additions - Flow Through
1206 SCHMAF S
1207 SCHMAF SNP
1208 SCHMAF SO
1209 SCHMAF SE
1210 SCHMAF TROJP
1211 SCHMAF SG
1212 B6
1213
1214 SCHMAP Additions - Permanent
1215 P S 29,612 29,612
1216 P SE 98,463 92,219 6,244 6,244
1217 LABOR SNP
1218 SCHMAP-SO SO 14,344.602 13,513,441 831,161 (313.056)518,105
1219 SCHMAP SG
1220 BOOKDEPR SCHMDEXP (234,743)(221,378)(13,365)(13,365)1221 B6 14,237,933 13.413,894 824,039 (313,056)510,984
1222
1223 SCHMAT Additions - Temporary
1224 SCHMAT.SITUS S 52,139,597 51,484,661 654,936 (613,922)41,014
1225 P SG
1226 DPW CIAC 46,836,990 44,665,606 2,171,384 2,171,384
1227 SCHMAT-SNP SNP 75,892,423 71,537,626 4,354,797 4,354,797
1228 P TROJD 1,901,813 1,785,725 116,088 (116,088)1229 P SGCT 1,122,425 1,054,229 68,196 68,196
1230 SCHMAT-SE SE 32,761,900 30,684,460 2,077,440 (67,754)2,009,685
1231 P SG 17,720,677 16,648,135 1,072,543 3,181,194 4,253,736
1232 CUST CN
1233 SCHMAT-SO SO 46,331,612 43,647,046 2,684,566 (1,641,872)1.042,694
1234 SCHMAT-SNP SNPD 9,587,358 9,142,884 444,474 444,474
1235 DPW BADDEBT 1,314,913 1,243,703 71,210 71,210
1236 P SG
1237 BOOKDEPR SCHMDEXP 566,450,834 534,199,916 32.250,918 32,250,918
1238 B6 852,060,543 806,093,991 45,966,551 741,558 46,708,109
1239
1240 TOTAL SCHEDULE - M ADDITIONS B6 866.298,476 819,507,885 46.790,591 428,502 47,219,093
1241
ROLLED.IN Page 12.20
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1242 SCHMDF Deductions. Flow Through
1243 SCHMDF S
1244 SCHMDF DGP
1245 SCHMDF DGU
1246 B6
1247 SCHMDP Deductions. Permanent
1248 SCHMDP S
1249 P SE 676.074 633,204 42,870 42,870
1250 PTD SNP 381,03 359,198 21,866 21,866
1251 SCHMDP IBT
1252 P SG
1253 SCHMDP-SO SO 24,434,943 23,019,124 1,415,820 (766,990)648,830
1254 B6 25,492,081 24,011,526 1,480,556 (766,990)713,565
1255
1256 SCHMDT Deductions - Temporary
1257 GP S 73,478,450 73,114,765 363,685 (289,862)73,823
1258 DPW BADDEBT
1259 SCHMDT-SNP SNP 118,429,747 111,634,108 6,795,639 6,795,639
1260 SCHMDT CN 48,156 46,293 1,863 1,863
1261 SCHMDT SG 82,539 77,543 4,996 4,996
1262 CUST DGP
1263 P SE 48,077,661 45,029,045 3,048,616 1,446,595 4,495,211
1264 SCHMDT-SG SG 112,078,393 105,294,857 6,783.536 23,559,303 30,342,839
1265 SCHMDT-GPS GPS 65,094,701 61,322,957 3,771,745 3,771,745
1266 SCHMDT-SO SO 23,344,458 21,991,824 1,352,634 (13,312)1,339,322
1267 TAXDEPR TAXDEPR 2,462,905,267 2,337,261,292 125,643,975 125,643,975
1268 DPW SNPD
1269 B6 2,903,539,372 2,755,772,684 147,766,689 24,702,724 172,469,413
1270
1271 TOTAL SCHEDULE - M DEDUCTIONS B6 2,929,031,454 2,779,784,209 149,247,244 23,935,734 173,182,978
1272
1273 TOTAL SCHEDULE. M ADJUSTMENTS B6 (2,062,732,978)(1,960,276,324)(102,456,653)(23,507,232)(125,963,885)
1274
1275
1276
1277 40911 State Income Taxes
1278 IBT S (58,051,044)(55,150,111)(2,900,933)(1,436,596)(4,337,529)
1279 IBT SE
1280 PTC P SG (297,049)(279,070)(17,979)(29,945)(47,923)
1281 IBT IBT
1282 Total State Tax Expense (58,348,093)(55,429,181)(2,918.912)(1,466.540)(4,385,52)
1283
1284
1285 Calculation of Taxable Income:
1286 Operating Revenues 4,402,215,385 4,146,750,451 255,464,934 7,428,829 262,893,763
1287 Operating Deductions:
1288 o & M Expenses 2,692,685,751 2,527,184,362 165,501,389 10,840,128 176,341,517
1289 Depreciation Expense 491,643,870 483,652,092 27,991,778 2,738,026 30,729,804
1290 Amortization Expense 44,975,946 42,481,316 2,494,630 272,898 2,767,529
1291 Taxes Other Than Income 136,512,728 130,094,757 6,417,971 765,162 7,183,133
1292 Interest & Dividends (AFUDC-Equity)(79,298,238)(74,748,011)(4,550,227)201,475 (4,348,752)
1293 Misc Revenue & Expense (5,388,606)(5,100,609)(287,997)(345,174)(633,171)
1294 Total Operating Deductions 3,281,131,452 3,083,563,908 197,567.545 14,472,515 212,040.060
1295 Other Deductions:
1296 Interest Deductions 337,008,309 317,670,373 19,337,936 1,092,163 20,430,099
1297 Interest on PCRBS
1298 Schedule M Adjustments (2,062.732,978)(1,960,276,324)(102,456.653)(23,507,232)(125,963,885)
1299
1300 Income Before State Taxes (1,278,657,354)(1,214.760,154)(63.897,200)(31,643,081 )(95,540,281)
1301
1302 State Income Taxes (58,348.093)(55,29.181)(2.918.912)(1,466.540)(4,385,452)
1303
1304 Total Taxable Income (1 ,220.309.261 )(1.159,330.973)(60,978,288)(30,176,541 )(91,154,829)
1305
1306 Tax Rate 35.0%35.0%35.0%35.0%35.0%
1307
1308 Federal Income Tax - Calculated (427,108,241)(405,765,840)(21,342,401 )(10.561.789)(31.904,190)
1309
1310 Adjustments to Calculated Tax:
1311 40910 PMI P SE (88,878)(83,242)(5,636)(5.636)
1312 40910 PTe P SG (55.535,369)(52,174,095)(3,361,274)(842,290)(4,203,564)
1313 40910 P SO (29,612)(27,896)(1,716)(1,716)
1314 40910 IRSSelte LABOR S
1315 Federal Income Tax Expense (482.762.100)(458,051,074)(24,711,026)(11,404,080)(36,115.106)
1316
1317 Total Operating Expenses 3,578.889,466 3.367,898,381 210,991,085 10,712,732 221,703.817
ROLLED-IN Page 12.21Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1318 310 Land and Land Rights
1319 P SG 2.328.228 2.187.312 140.916 140.916
1320 P SG 34,798,44 32.692.272 2.106.173 2,106.173
1321 P SG 56.303,435 52.895.674 3.407.761 3,407.761
1322 P S
1323 P SG 2.468.743 2.319.323 149,420 149,420
1324 B8 95.898.852 90.094,581 5.804.271 5.804.271
1325
1326 311 Structures and Improvements
1327 P SG 233.697.069 219.552.572 14.144,497 14.144.497
1328 P SG 325.016.640 305.345.033 19,671.607 19.671.607
1329 P SG 304.038.753 285.636.831 18,401.922 18.401.922
1330 P SG 58.700.214 55.147.388 3.552.826 3.552.826
1331 B8 921,452.677 865.681.824 55,770.852 55.770.852
1332
1333 312 80iler Plant Equipment
1334 P SG 665,806.134 625,508.269 40.297.865 40.297.865
1335 P SG 642.590.325 603.697.595 38.892.730 38.892.730
1336 P SG 1.885.355.962 1.771.244.938 114.111,024 28.935.270 143.046.294
1337 P SG 324.773.916 305.116.999 19.656.916 19,656.916
1338 88 3.518.526.337 3.305.567.802 212,958,535 28.935.270 241.893.805
1339
1340 314 Turbogenerator Units
1341 P SG 133.730.947 125.636.892 8,094.055 8,094,055
1342 P SG 144,430.870 135.689.203 8,741.667 8.741.667
1343 P SG 554.615.741 521.047.666 33.568.075 33.568.075
1344 P SG 63.736,456 59.878.812 3.857.644 3.857.644
1345 88 896.514.013 842.252.572 54.261.442 54.261.442
1346
1347 315 Accessory Electric Equipment
1348 P SG 87.016.417 81.749.755 5.266.662 5.266.662
1349 P SG 138.274.538 129.905.463 8.369.056 8,369,056
1350 P SG 124.032.336 116.525.289 7,507,048 7.507.048
1351 P SG 66.644.224 62.610,587 4,033.637 4.033.637
1352 88 415.967.515 390.791.113 25,176.402 25.176,402
1353
1354
1355
1356 316 Misc Power Plant Equipment
1357 P SG 4.715.664 4,430.249 285,415 285,415
1358 P SG 5.085.197 4.777,416 307.781 307.781
1359 P SG 19.393.369 18.219,587 1,173.782 1.173.782
1360 P SG 4.039.790 3.795.282 244.508 244.508
1361 B8 33.234.020 31.222,534 2.011,487 2.011.487
1362
1363 317 Steam Plant ARO
1364 P S
1365 88
1366
1367 SP Unclassified Steam Plant - Account 300
1368 P SG 3,351.463 3.148.616 202.847 202.847
1369 88 3,351,463 3,148.616 202.847 202,847
1370
1371
1372 Total Steam Production Plant B8 5,884,94,878 5,528,759,042 356,185,835 28,935,270 385,121,105
1373
1374
1375 Summary of Steam Production Plant by Factor
1376 S
1377 DGP
1378 DGU
1379 SG 5.884.944.878 5.528.759.042 356.185.835 28.935.270 385.121.105
1380 SSGCH
1381 Total Steam Production Plant by Factor 5,884,944.878 5.528,759.042 356.185.835 28.935.270 385.121.105
1382 320 Land and Land Rights
1383 P SG
1384 P SG
1385 B8
1386
1387 321 Structures and Improvements
1388 P SG
1389 P SG 88
1390
ROLLED-IN Page 12.22
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1391
1392 322 Reactor Plant Equipment
1393 P SG
1394 P SG
1395 B8
1396
1397 323 Turbogenerator Units
1398 P SG
1399 P SG
1400 B8
1401
1402 324 Land and Land Rights
1403 P SG
1404 P SG
1405 B8
1406
1407 325 Misc. Power Plant Equipment
1408 P SG
1409 P SG
1410 B8
1411
1412
1413 NP Unclassified Nuclear Plant - Acct 300
1414 P SG
1415 B8
1416
1417
1418 Total Nuclear Production Plant B8
1419
1420
1421
1422 Summary of Nuclear Production Plant by Factor
1423 DGP
1424 DGU
1425 SG
1426
1427 Total Nuclear Plant by Factor
1428
1429 330 Land and Land Rights
1430 P SG 10.621.118 9.978.276 642.842 642.842
1431 P SG 5.269,427 4.950.496 318.932 318.932
1432 P SG 9.560.168 8.981.540 578.628 578.628
1433 P SG 672.873 632.148 40.726 40.726
1434 B8 26.123.587 24.542.459 1.581.128 1.581.128
1435
1436 331 Structures and Improvements
1437 P SG 20.915.379 19.649.478 1.265.902 1.265.902
1438 P SG 5.280.294 4.960.705 319.589 319.589
1439 P SG 78.435.286 73.687.997 4.747.290 4.747.290
1440 P SG 8.183.946 7.688.613 495.333 495.333
1441 B8 112.814.905 105.986.792 6.828.113 6.828.113
1442
1443 332 Reservoirs. Dams & Waterways
1444 P SG 150.943.088 141.807.270 9.135.819 9.135.819
1445 P SG 20.006.881 18.795.966 1.210.915 1.210.915
1446 P SG 114.583.184 107.648.045 6.935.138 1.746.563 8.681.702
1447 P SG 40.934.944 38,457.359 2,477.584 2,477.584
1448 B8 326,68.097 306.708.641 19.759,456 1.746.563 21.506.020
1449
1450 333 Water Wheel. Turbines. & Generators
1451 P SG 31.307,452 29,412.571 1.894.881 1.894.881
1452 P SG 8.771.526 8.240.630 530.896 530.896
1453 P SG 45.115,448 42.384.839 2.730.609 2.730.609
1454 P SG 27.236.711 25.588.211 1.648.500 1.648.500
1455 B8 112,431.137 105.626.251 6.804.886 6.804.886
1456
1457 334 Accessory Electric Equipment
1458 P SG 4.363.326 4.099.236 264.090 264.090
1459 P SG 3.648.790 3,426.068 220.722 220.722
1460 P SG 44.929.172 42.209.837 2.719.335 2.719.335
1461 P SG 7.177.004 6.742.617 434.388 434.388
1462 B8 60.116.292 56,477.758 3.638.534 3.638.534
1463
ROLLED-IN Page 12.23
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1464
1465
1466 335 Misc. Power Plant Equipment
1467 P SG 1,195,178 1,122,840 72,338 72,338
1468 P SG 161,986 152,181 9,804 9,804
1469 P SG 992,216 932,162 60,054 60,054
1470 P SG 11,353 10,666 687 687
1471 B8 2,360,733 2,217,850 142,883 142,883
1472
1473 336 Roads, Railroads & Bridges
1474 P SG 4,648,527 4,367,176 281,352 281,352
1475 P SG 822,839 773,037 49,802 49,802
1476 P SG 10,183,215 9,566,876 616,338 616,338
1477 P SG 668,735 628,259 40,475 40,475
1478 B8 16,323,315 15,335,348 987,967 987,967
1479
1480 337 Hydro Plant ARO
1481 P S
1482 B8
1483
1484 HP Unclassified Hydro Plant - Acct 300
1485 P S
1486 P SG
1487 P SG
1488 P SG
1489 B8
1490
1491 Total Hydraulic Production Plant B8 656,638,066 616,895,098 39,742,968 1,746,563 41,489,532
1492
1493 Summary of Hydraulic Plant by Factor
1494 S
1495 SG 656,638,066 616,895,098 39,742,968 1,746,563 41,489,532
1496 DGP
1497 DGU
1498 Total Hydraulic Plant by Factor 656,638,066 616,895,098 39,742,968 1,746,563 41.489,532
1499
1500 340 Land and Land Ri9hts
1501 P SG 23,516,708 22,093,361 1,423,347 1,423,347
1502 P SG 5,394,604 5,068,096 326,508 326,508
1503 P SG
1504 B8 28,911,312 27,161,457 1,749,855 1,749,855
1505
1506 341 Structures and Improvements
1507 P SG 107,792,505 101,268,372 6,524,133 6,524,133
1508 P SG 163.512 153,615 9,897 9.897
1509 P SG 43,775,824 41.126,296 2,649,528 2.649.528
1510 P SG 4,241,952 3.985,208 256,744 256.744
1511 B8 155,973,793 146.533,491 9,440.302 9,440,302
1512
1513 342 Fuel Holders, Producers & Accessories
1514 P SG 8,406,209 7,897,424 508,785 508.785
1515 P SG 121,339 113,995 7,344 7.344
1516 P SG 2.284,126 2,145,879 138.247 138.247
1517 B8 10,811,674 10,157,298 654,376 654.376
1518
1519 343 Prime Movers
1520 P S
1521 P SG 754,44 708,777 45.662 45,662
1522 P SG 1,801,277,182 1,692,255.019 109.022,163 109.022,163
1523 P SG 658,057,132 618,228.275 39.828.857 39.828,857
1524 P SG 53.648,952 50,401.854 3.247.099 3.247,099
1525 B8 2,513,737,706 2,361,593.925 152.143.781 152.143,781
1526
1527 344 Generators
1528 P S
1529 P SG 47.700,523 44,813,452 2,887.070 2,887.070
1530 P SG 283,380.358 266,228.783 17,151.574 17,151,574
1531 P SG 15,873,643 14,912,892 960.751 960,751
1532 B8 346.954.524 325,955,128 20,999,396 20,999,396
ROLLED-IN Page 12.24
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1533
1534 345 Accessory Electric Plant
1535 P SG 134,281,439 126.154,066 8.127,374 " 8.127.374
1536 P SG 97,391,746 91,497,118 5.894,628 5.894,628
1537 P SG 156,586 147,109 9,477 9,477
1538 P SG 2,919,649 2.742,937 176.712 176.712
1539 B8 234.749,420 220,541,229 14.208.191 14.208,191
1540
1541
1542
1543 346 Misc. Power Plant Equipment
1544 P SG 9.819.979 9,225,625 594,353 594.353
1545 P SG 2.349.890 2,207.664 142,227 142,227
1546 P SG 11.813 11.098 715 715
1547 B8 12,181,682 11,444.387 737,295 737.295
1548
1549 347 Other Production ARO
1550 P S
1551 B8
1552
1553 OP Unclassified Other Prod Plant-Acct 102
1554 P S
1555 P SG (4,484.801)(4.213.359)(271,442)(271.442)1556 (4,484,801)(4,213.359)(271,442)(271,442)1557
1558 Total Other Production Plant B8 3,298,835,309 3,099,173,557 199,661,753 199,661,753
1559
1560 Summary of Other Production Plant by Factor
1561 S
1562 DGU
1563 SG 3,298,835,309 3,099.173,557 199.661.753 199.661.753
1564 SSGCT
1565 Total of Other Production Plant by Factor 3,298.835.309 3,099.17,557 199.661.753 199.661,753
1566
1567 Experimental Plant
1568 103 Experimental Plant
1569 P SG
1570 Total Experimental Production Plant B8
1571
1572 Total Production Plant B8 9,840,418,253 9,244,827,697 595,590.556 30,681,833 626,272,390
1573 350 Land and Land Rights
1574 T SG 21,114,634 19,836,673 1.277962 1,277,962
1575 T SG 48,91,936 45,556,965 2.934,971 2.934.971
1576 T SG 111,910,895 105.137.497 6.773.398 (25,595)6.747,804
1577 B8 181,517,465 170,531,135 10.986,331 (25.595)10,960.736
1578
1579 352 Structures and Improvements
1580 T S
1581 T SG 7.550.730 7,093.722 457,007 457.007
1582 T SG 18.144.311 17,046.128 1,098,183 1.098,183
1583 T SG 97.158,664 91,278,143 5.880,521 5.880,521
1584 B8 122,853,704 115,417.993 7.435,711 7.435,711
1585
1586 353 Station Equipment
1587 T SG 127,623,942 119.899,513 7.724.429 7,724.429
1588 T SG 186,316.529 175.039,735 11.276.794 11,276.794
1589 T SG 1,224,680.278 1.150.556,598 74.123.679 74,123.679
1590 B8 1,538,620.749 1,445,495,846 93.124.902 93,124.902
1591
1592 354 Towers and Fixtures
1593 T SG 161.082,488 151,332,983 9,749,505 9,749,505
1594 T SG 128.007.635 120,259,983 7,747,652 7.747,652
1595 T SG 336.682.164 316,304.502 20,377,662 20.377,662
1596 B8 625,772.287 587,897,468 37.874.819 37.874.819
1597
1598 355 Poles and Fixtures
1599 T SG 66,617,046 62.585,054 4,031,992 4,031.992
1600 T SG 117 .303,325 110,203,550 7.099.775 7,099.775
1601 T SG 415,637,115 390.480,711 25,156,404 9.151,416 34,307.820
1602 B8 599.557,486 563.269,315 36.288.171 9.151,416 45,439.587
1603
ROLLED.IN Page 12.25
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1604 356 Clearing and Grading
1605 T SG 194,103,526 182,355,425 11,748,101 11,748,101
1606 T SG 151,170,861 142,021,256 9,149,605 9,149,605
1607 T SG 433,610,805 407,366,545 26,244,261 26,244,261
1608 B8 778,885,193 731,743,226 47,141,966 47,141,966
1609
1610 357 Underground Conduit
1611 T SG 6,371 5,985 386 386
1612 T SG 91,651 86,103 5,547 5,547
1613 T SG 3,161,431 2,970,085 191,345 191,345
1614 B8 3,259,452 3,062,174 197,278 197,278
1615
1616 358 Underground Conductors
1617 T SG
1618 T SG 1,087,552 1,021,728 65,824 65,824
1619 T SG 6,387,543 6,000,937 386,606 386,606
1620 B8 7,475,095 7,022,665 452,430 452,430
1621
1622 359 Roads and Trails
1623 T SG 1,863,032 1,750,272 112,760 112,760
1624 T SG 440,513 413,851 26,662 26,662
1625 T SG 9,295,159 8,732,570 562,589 562,589
1626 B8 11,598,703 10,896,693 702,011 702,011
1627
1628 TP Unclassified Trans Plant - Acct 300
1629 T SG 469,574,099 441,153,163 28,420,936 28,20,936
1630 B8 469,574,099 441,153,163 28,20,936 28,20,936
1631
1632 TSO Unclassified Trans Sub Plant - Acct 300
1633 T SG
1634 B8
1635
1636 Total Transmission Plant B8 4,339.114.233 4,076.489.678 262,624,554 9,125,821 271.750,376
1637 Summary of Transmission Plant by Factor
1638 DGP
1639 DGU
1640 SG 4,339,114,233 4,076,489,678 262,624,554 9,125,821 271,750,376
1641 Total Transmission Plant by Factor 4,339,114,233 4,076,489,678 262,624,554 9,125,821 271,750,376
1642 360 Land and Land Rights
1643 DPW S 52,837.393 51,476,125 1,361,267 1,361,267
1644 B8 52,837,393 51,476,125 1,361,267 1,361,267
1645
1646 361 Structures and Improvements
1647 DPW S 74,675.983 73,174,078 1,501,905 1,501,905
1648 B8 74,675,983 73,174,078 1,501,905 1,501,905
1649
1650 362 Station Equipment
1651 DPW S 822,438,749 794,121,744 28.317,005 28,317,005
.1652 B8 822,438,749 794,121,744 28,317,005 28,317,005
1653
1654 363 Storage Battery Equipment
1655 DPW S
1656 B8
1657
1658 364 Poles, Towers & Fixtures
1659 DPW S 936,606,530 872,248,984 64,357,546 64,357,546
1660 B8 936,606,530 872,248,984 64,357,546 64,357,546
1661
1662 365 Overhead Conductors
1663 DPW S 646,426,178 612,036,781 34,389,397 34,389,397
1664 B8 646,426,178 612,036,781 34,389,397 34,389,397
1665
ROLLED.IN Page 12.26
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1666 366 Underground Conduit
1667 DPW S 300,853,912 293,226,761 7,627,151 7,627,151
1668 B8 300,853,912 293,226,761 7,627,151 7,627,151
1669
1670
1671
1672
1673 367 Underground Conductors
1674 DPW S 716,202,893 692,155,372 24,047,521 24,047,521
1675 B8 716,202,893 692,155,372 24,047,521 24,047,521
1676
1677 368 Line Transformers
1678 DPW S 1,092,258,181 1,024,496,725 67,761,455 67,761,455
1679 B8 1,092,258,181 1 ,024,496,725 67,761,455 67,761,455
1680
1681 369 Services
1682 DPW S 581,777,749 552,728,553 29,049,197 29.049,197
1683 B8 581,777,749 552,728,553 29,049,197 29,049,197
1684
1685 370 Meters
1686 DPW S 179,597,171 165,632,928 13,964.243 13,964,243
1687 B8 179,597,171 165,632,928 13,964.243 13,964,243
1688
1689 371 Installations on Customers' Premises
1690 DPW S 8,801,076 8,631,743 169,333 169,333
1691 B8 8,801,076 8,631,743 169,333 169,333
1692
1693 372 Leased Propert
1694 DPW S
1695 B8
1696
1697 373 Street Lights
1698 DPW S 60,795,839 60,180,066 615,773 615,773
1699 B8 60,795,839 60,180,066 615,773 615,773
1700
1701 DP Unclassifed Dist Plant. Acct 300
1702 DPW S 12,090,316 10,561,483 1,528,833 1,528,833
1703 B8 12,090,316 10,561,483 1,528,833 1.528.833
1704
1705 DSO Unclassified Dist Sub Plant. Acct 300
1706 DPW S
1707 B8
1708
1709
1710 Total Distribution Plant B8 5.485,361,969 5,210,671,344 274,690,625 274.690,625
1711
1712 Summary of Distribution Plant by Factor
1713 S 5.485,361.969 5,210,671,344 274,690,625 274,690,625
1714
1715 Total Distribution Plant by Factor 5,485,361,969 5,210,671,344 274,690,625 274,690.625
ROLLED-IN Page 12.27
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1716 389 Land and Land Rights
1717 G.SITUS S 9,472,275 9,274,636 197,639 197,639
1718 CUST GN 1,128,506 1,084,845 43,661 43,661
1719 PT SG 332 312 20 20
1720 G-SG SG 1,228 1,153 74 74
1721 PTD SO 5,598,055 5,273,690 324,365 324,365
1722 88 16,200,395 15,634,636 565,759 565,759
1723
1724 390 Structures and Improvements
1725 G.SITUS S 113,258,556 103,350,062 9,908,495 9,908,95
1726 PT SG 356,327 334,760 21,567 21,567
1727 PT SG 1,638,404 1,539,240 99,164 99,164
1728 CUST CN 12,312,990 11,836,614 476,376 476,376
1729 G.SG SG 4,107,582 3,858,971 248,611 248,611
1730 PTD SO 103,816,679 97,801,289 6,015,390 6,015,390
1731 B8 235,490,538 218,720,936 16,769,603 16,769,603
1732
1733 391 Offce Furniture & Equipment
1734 G-SITUS S 10,714,257 9,922,539 791,718 791,718
1735 PT SG 1,046 982 63 63
1736 PT SG 5,295 4,975 320 320
1737 GUST CN 8,507,385 8,178,243 329,141 329,141
1738 G-SG SG 4,793,839 4,503,692 290,147 290,147
1739 P SE 80,160 75,077 5,083 5,083
1740 PTD SO 53,024,085 49,951.741 3,072,344 3,072,344
1741 G-SG SG 74.351 69,851 4,500 4.500
1742 G-SG SG
1743 88 77,200,417 72,707,100 4,493,317 4,493,317
1744
1745 392 Transporttion Equipment
1746 G-SITUS S 72,695,382 67,622,274 5,073,108 5,073,108
1747 PTD SO 7,496,170 7,061,824 434,346 434,346
1748 G-SG SG 16,861,910 15,841,344 1,020,566 1,020,566
1749 GUST CN
1750 PT SG 788,230 740,522 47,708 47.708
1751 P SE 404,148 378,521 25,627 25,627
1752 PT SG 120,286 113,006 7,280 7.280
1753 G.SG SG 343,984 323,164 20,820 20,820
1754 PT SG 44,655 41,952 2,703 2.703
1755 88 98,754,764 92,122,607 6,632,157 6,632,157
1756
1757 393 Stores Equipment
1758 G-SITUS S 8,748.806 8.259,899 488,907 488,907
1759 PT SG 108,431 101,868 6,563 6,563
1760 PT SG 360,063 338,270 21,793 21,793
1761 PTD SO 366.257 345,035 21,222 21.222
1762 G-SG SG 4.117,724 3,868,499 249,225 249,225
1763 PT SG 53,971 50,704 3,267 3.267
1764 88 13.755,252 12,964,276 790,976 790.976
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Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAl
1765
1766 394 Tools, Shop & Garage Equipment
1767 G-SITUS S 31,993.392 30.190,583 1,802,808 1.802,808
1768 PT SG 1,547,621 1,453,951 93,670 93.67.(
1769 G-SG SG 20,748,569 19,492,763 1,255,806 1.255,806
1770 PTD SO 3,941.347 3,712,976 228,371 228,371
1771 P SE 7,106 6,656 451 451
1772 PT SG 1,779,683 1,671,968 107,715 107,715
1773 G-SG SG 1,702,983 1,599,910 103,073 103,073
1774 G-SG SG 89,913 84,471 5,442 5,4217756861,810,613 58,213,278 3,597,335 3,597,335
1776
1777 395 Laboratory Equipment
1778 G-SITUS S 24,898,296 23,620,023 1,278,273 1,278.273
1779 PT SG 1,518 1,426 92 92
1780 PT SG 5,371 5,046 325 325
1781 PTD SO 5,041,840 4,749,704 292,136 292,136
1782 P SE 7,593 7,112 481 481
1783 G-SG SG 6,252.885 5.874,430 378,55 378,455
1784 G-SG SG 253,001 237,688 15,313 15,313
1785 G-SG SG 14.022 13,173 849 849
1786 68 36,474,525 34,508,601 1,965,924 1,965,924
1787
1788 396 Power Operated Equipment
1789 G-SITUS S 96,176,244 89,210,759 6,965,485 6,965,485
1790 PT SG 845,108 793,958 51,150 51,150
1791 G-SG SG 31,225,794 29,335,855 1,889,939 1,889,939
1792 PTD SO 1,137,422 1,071,517 65,905 65,905
1793 PT SG 1,664,492 1,563,749 100,743 100,743
1794 P SE 73,823 69,142 4,681 4,681
1795 P SG
1796 G-SG SG 999,837 939,322 60,515 60,515
1797 68 132,122,721 122,984,302 9,138,419 9,138,419
1798 397 Communication Equipment
1799 G-SITUS S 108,711,341 102,010,465 6,700,875 6,700.875
1800 PT SG 2,017,325 1,895.226 122,098 122,098
1801 PT SG 2,735,730 2,570,150 165,580 165,580
1802 PTD SO 49,790,369 46,905,394 2,884,974 2.884,974
1803 CUST . CN 2,849,382 2,739,142 110,239 110,239
1804 G-SG SG 92,965,111 87,338,05 5,626,706 5.626,706
1805 P SE 126,846 118,802 8,03 8.043
1806 G-SG SG 606,135 569,448 36,686 36.686
1807 G-SG SG 1.590 1,494 96 96
1808 B8 259,803,827 244,148,528 15,655,299 15,655,299
1809
1810 398 Misc. Equipment
1811 G-SITUS S 1,462,713 1,398,361 64,352 64,352
1812 PT SG
1813 PT SG
1814 CUST CN 211,499 203,316 8,183 8,183
1815 PTD SO 3,306,006 3,114,448 191,558 191,558
1816 P SE 1,668 1,562 106 106
1817 G-SG SG 1,918,568 1,802,447 116,121 116,121
1818 G-SG SG
1819 68 6,900,453 6,520,133 380,320 380,320
1820
1821 399 Coal Mine
1822 P SE 274,151,311 256,767,312 17,383,999 13,434,281 30,818.280
1823 MP P SE
1824 68 274,151,311 256,767,312 17,383,999 13,434,281 30,818.280
1825
1826 399L WIDCO Capital Lease
1827 P SE 68
1828
1829
1830 Remove Capital Leases
1831 68
1832
ROLLED.IN Page 12.29
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1833 1011390 General Capital Leases
1834 G-5ITUS 5 18,984,156 18,984,156
1835 P SG 16,951,793 15,925,787 1,026,006 1,026,006
1836 PTD SO 12,664,054 11,930,268 733,786 733,786
1837 89 48,600.02 46,840,210 1,759,792 1,759,792
1838
1839 Remove Capital Leases (48,600,002)(46,840,210)(1,759,792)(1,759,792)
1840
1841
1842 1011346 General Gas Line Capital Leases
1843 P SG
1844 B9
1845
1846 Remove Capital Leases
1847
1848
1849 GP Unclassified Gen Plant - Acct 300
1850 G-5ITU5 S
1851 PTD 50 672,542 633,573 38,969 38,969
1852 CUST CN
1853 G-5G 5G
1854 PT 5G
1855 PT SG
1856 B8 672,542 633,573 38,969 38,969
1857
1858 399G Unclassified Gen Plant - Acct 300
1859 G-5ITUS S
1860 PTD SO
1861 G-5G SG
1862 PT SG
1863 PT SG
1864 B8
1865
1866 Total General Plant B8 1,213,337,359 1,135,925,283 77,412,077 13,434,281 90,846,357
1867
1868 Summary of General Plant by Factor
1869 S 497,115,417 463,843,757 33,271,660 33,271,660
1870 DGP
1871 DGU
1872 SG 218,104,703 204,903,933 13,200,770 13,200,770
1873 50 246,854,826 232,551,460 14,303,366 14,303,366
1874 SE 274,852,655 257,424,183 17,428,472 13,434,281 30,862,752
1875 CN 25,009,761 24,042,161 967,601 967,601
1876 DEU
1877 55GCT
1878 55GCH
1879 Less Capital Leases (48,600,002)(46,840,210)11,759,792)(1,759,792)1880 Total General Plant by Factor 1,213,337,359 1,135,925,283 7,412,077 13,434,281 90,846.357
1881 301 Organization
1882 I-SITU5 S
1883 PTD 50
1884 I-SG 5G
1885 B8
1886 302 Franchise & Consent
1887 I-SITUS 5 1,000,000 1,000,000 1,000,000
1888 1-5G SG 11,966,103 11,241,856 724,247 724,247
1889 1-5G SG 173,628,256 163,119,419 10,508,837 10,508,837
1890 I-SG SG 9,240,742 8,681,446 559,295 559.295
1891 P SG
1892 P 5G 600,993 564,618 36,375 36,375
1893 B8 196,436,094 183,607,340 12,828,755 12,828,755
1894
ROLLED-IN Page 12.30
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1895 303 Miscellaneous Intangible Plant
1896 I-SITUS S 7,517,189 7,089,597 427,593 427,593
1897 I-SG SG 108,821,038 102,234,653 6,586,385 849,459 7,435,844
1898 PTO SO 367,518,411 346.223.504 21,294,906 21,294.906
1899 P SE 3,440,744 3.222.565 218,178 218,178
1900 CUST CN 120,558,779 115,894,491 4,664,288 4,664,288
1901 P SG
1902 P SG
1903 B8 607,856,161 574.664,811 33,191,351 849,459 34.040.810
1904 303 Less Non-Utility Plant
1905 I-SITUS S
1906 607,856,161 574,664,811 33,191,351 849,459 34,040,810
1907 IP Unclassified Intangible Plant - Acct 300
1908 I-SITUS S
1909 I-SG SG
1910 P SG
1911 PTD SO
1912
1913
1914 Total Intangible Plant B8 804.292,255 758,272,150 46,020,105 849,459 46,869,56
1915
1916 Summary of Intangible Plant by Factor
1917 S 8,517,189 7,089,597 1,427,593 1,427,593
1918 OGP
1919 OGU
1920 SG 304,257,133 285.841,993 18,15.140 849,459 19.264,599
1921 SO 367,518,411 346.223,504 21.294,906 21.294,906
1922 CN 120,558,779 115.894,491 4,664,288 4,664,288
1923 SSGCT
1924 SSGCH
1925 SE 3,44,744 3.222,565 218,178 218,178
1926 Total Intangible Plant by Factor 804,292,255 758.272,150 46,020.105 849,459 46,869.564
1927 Summary of Unclassified Plant (Account 106 & 102)
1928 OP 12,090,316 10.561,483 1,528,833 1.528.833
1929 DSO
1930 GP 672,542 633,573 38.969 38.969
1931 HP
1932 NP
1933 OP (4,484,801)(4,213,359)(271.442)(271,442)
1934 TP 469,574,099 441.153,163 28,420,936 28,420,936
1935 TSO
1936 IP
1937 MP
1938 SP 3.351,463 3.148,616 202.847 202.847
1939 Total Unclassified Plant by Factor 481,203,619 451.283,477 29,920,142 29.920,142
1940
1941 Total Electric Plant In Service B8 21,682,524.069 20,426,186,152 1,256,337,918 54,091,394 1,310,429,312
ROLLED-IN Page 12.31
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1942 Summary of Electric Plant by Factor
1943 S 5,990.994,575 5,681,604,697 309,389.878 309,389,878
1944 SE 278.293,398 260,646,748 17,646.650 13,434,281 31,080,931
1945 DGU
1946 DGP
1947 SG 14,701,894,321 13,812,063,301 889,831,021 40,657,114 930,488,134
1948 SO 614,373,236 578,774,964 35,598,272 35.598,272
1949 CN 145,568,541 139,936,652 5,631,889 5,631,889
1950 DEU
1951 SSGCH
1952 SSGCT
1953 Less Capital Leases ~46,600,002)(46.840,210)(1,759,792)(1.759,792)1954 21. 82,524,069 20,426,186,152 1,256,337,918 54,091.394 1,310,29,312
1955 105 Plant Held For Future Use
1956 DPW S 7,080,785 7,080,785
1957 P SG
1958 T SG 721,048 677,407 43,641 (583,724)(540,082)1959 P SG 8,923.302 8,383,219 540,082 540,082
1960 P SE 953,014 892.583 60,431 (60,431)1961 G SG
1962
1963
1964 Total Plant Held For Future Use B10 17,678,149 17,033,995 64,154 (64,154)
1965
1966 114 Electric Plant Acquisition Adjustments
1967 P S
1968 P SG 144.614.797 135,861,998 8,752,799 8,752,799
1969 P SG 14,560.711 13,679,425 881,286 881.2861970Total Electric Plant Acquisition Adjustment B15 159,175,508 149,541,423 9,634,085 9,634,085
1971
1972 115 Accum Provision for Asset Acquisition Adjustments
1973 P S
1974 P SG (83.573,118)(5.384,131)(5,384,131)1975 P SG (12,107,970 (780,046 780,046)
1976 815 5,7 7
1977
1978 120 Nuclear Fuel
1979 P SE
1980 Total Nuclear Fuel B15
1981
1982 124 Weatherization
1983 DMSC S 2,213,350 2,194,663 18,688 18,688
1984 DMSC SO (4,454)t,196)(258)(258)1985 816 2,208,897 2.10,467 18,36 18,30
1986
1987 182W Weatherization
1988 DMSC S 6,410.754 3,248,179 3,162.575 3,162,575
1989 DMSC SG
1990 DMSC SGCT
1991 DMSC SO
1992 816 6,410,754 3,248.179 3.162,575 3,162,57
1993
1994 186W Weatherization
1995 DMSC S
1996 DMSC CN
1997 DMSC CNP
1998 DMSC SG
1999 DMSC SO
2000 816
2001
2002 Total Weatherization B16 8,619,651 5,438,646 3,181,004 3,181,004
ROLLED-IN Page 12.32
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
2003
2004 151 Fuel Stock
2005 P DEU
2006 P SE 178,314,939 167.007,947 11,306,992 2,398,786 13,705,778
2007 P SE
2008 P SE 10,178,149 9,532,750 645,399 645,399
2009 Total Fuel Stock B13 188,493,087 176,540,696 11,952,391 2,398,786 14,351,177
2010
2011 152 Fuel Stock - Undistributed
2012 P SE
2013
2014
2015 25316 DG& T Working Capital Deposit
2016 P SE (2,263,000)(2,119,503)(143,497)(32,593)(176.090)
2017 B13 (2,263,000)(2.119,503)(143,497)(32,593)(176.090)
2018
2019 25317 DG& T Working Capital Deposit
2020 P SE (1,849,114)(1.731.861 )(117.253)(11,035)(128.288)
2021 613 (1.849.114)(1.731.861)(117.253)(11,035)(128.288)
2022
2023 25319 Provo Working Capital Deposit
2024 P SE
2025
2026
2027 Total Fuel Stock 613 184,380,973 172.689.333 11.691.641 2.355.158 14,046.799
2028 154 Materials and Supplies
2029 MSS S 87,724,078 82.701,505 5.022.573 5,022,573
2030 MSS SG 4,657,098 4.375,227 281.870 281.870
2031 MSS SE 4,477,840 4.193,899 283.941 283,941
2032 MSS SO 220,250 207,488 12.762 12.762
2033 MSS SG 84.929.002 79.788,681 5.140.321 5.140,321
2034 MSS SG (1,860)(1,747)(113)(113)
2035 MSS SNPD (2,521,016)(2.404.141 )(116.875)(116,875)
2036 MSS SG
2037 MSS SG
2038 MSS SG
2039 MSS SG
2040 MSS SG 6,920,767 6.501,888 418.879 418.879
2041 MSS SG
2042 Total Materials and Supplies 613 186,406,158 175,362,800 11,043,359 11,043.359
2043
2044 163 Stores Expense Undistributed
2045 MSS SO
2046
2047 613
2048
2049 25318 Provo Working Capital Deposit
2050 MSS SG (273.000)(256,77)(16,523)(16.523)
2051
2052 613 (273,000)(256,477)(16.523)(16.523)
2053
2054 Total Materials & Supplies 613 186,133,158 175.106,323 11.026,835 11.026.835
2055
2056 165 Prepayments
2057 DMSC S 2.918.959 2,728,996 189.963 189,963
2058 GP GPS 10.983.376 10,346.973 636,403 636,403
2059 PT SG 5.058.945 4,752,753 306.192 306,192
2060 P SE 5,474.749 5,127,594 347,155 347.155
2061 PTD SO 20.942.638 19,729,171 1.213,467 1.213.467
2062 Total Prepayments B15 45,378,667 42,685,486 2,693,181 2,693,181
2063
ROLLED-IN Page 12.33
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
2064 182M Misc Regulatory Assets
2065 DDS2 S 97,616,141 97,484,653 131,488 (309,362)(177,874)2066 DEFSG SG 186,749 186,749
2067 P SGCT 7,389,298 6,940,338 448,960 448,960
2068 DEFSG SG-P
2069 P SE
2070 P SG
2071 DDS02 SO 8,296,641 7,815,914 480,727 480,727
2072 B11 11,302,081 112,240,905 1,061,175 (122,613)938.63
2073
2074 186M Misc Deferred Debits
2075 LABOR S 15,110,335 15,110,335
2076 P SG
2077 P SG
2078 DEFSG SG 53,166,550 49,948,649 3,217,901 273,203 3,491,104
2079 LABOR SO 1,784 1,681 103 103
2080 P SE 16,40,473 15,397,979 1,042,494 (3,997)1,038,498
2081 P SG
2082 GP EXCTAX
2083 Total Misc. Deferred Debits B11 84,719,143 80,458,64 4,260,499 269,206 .4,529,705
2084
2085 Working Capital
2086 CWC Cash Working Capital
2087 CWC S 32,372,130 30,506,647 1,865,483 (16,359)1,849,124
2088 CWC SO
2089 CWC SE
2090 B14 32,372,130 30,506,647 1,865,483 (16,359)1,849,124
2091
2092 OWC Oter Work. Cap.
2093 131 Cash GP SNP
2094 135 Working Funds GP SG
2095 141 Noies Recivabli GP SO
2096 143 Other AI GP SO 48,531,707 45,719,663 2,812,045 2,812.045
2097 232 Al PTD S
2098 232 NP PTD SO (4,386,790)(4,132,609)(254,181). (254,181)2099 232 NP P SE (2,202,647)(2,062,977)(139,670)(139,670)2100 232 Al T SG (146,335)(137,478)(8,857)(8,857)
2101 2533 Othe Ms Of Crd P S
2102 2533 Other Msc. Of. Crd. P SE (6,240,898)(5,845,162)(395,737)(16,234)(411.,971)
2103 230 Asset Retir, Oblig P SE (2,528,519)(2,368,185)(160,334)(160,334)
2104 230 Asel Retír. Oblig, P S
2105 254105 ARO Reg Liability P S
2106 254105 ARO Reg Liability P SE (877,173)(821,552)(55,622)(55,622)
2107 2533 Cholla Reclamation P SE
2108 B14 32,149,344 30,351,701 1,797,643 (16,234)1,781,409
2109
2110 Total Working Capitl B14 64,521,474 60,858,348 3,663,126 (32,593)3,630,533
2111 Miscellaneous Rate Base
2112 18221 Unrec Plant & Reg Study Costs
2113 P S
2114
2115 B15
2116
2117 18222 Nuclear Plant - Trojan
2118 P S (28,645)(28,645)
2119 P TROJP 64,498 60,566 3,932 (3,932)0
2120 P TROJD 99,713 93,27 6,087 (6,087)0
2121 B15 135,566 125,548 10,019 (10,019)0
2122
2123
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Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
2124
2125 1869 Misc Deferred Debits-Trojan
2126 P S
2127 P SG
2128 B15
2129
2130 Total Miscellaneous Rate Base B15 135,566 125,54 10,019 (10,019)0
2131
2132 Total Rate Base Additions B15 762,199,105 720,497,562 41,701,54 1,814,985 43,516,529
2133 235 Customer Service Deposits
2134 CUST S
2135 CUST CN
2136 Total Customer Service Deposits B15
2137
2138 2281 Prop Ins PTD SO
2139 2282 Inj & Dam PTD SO (8,99,000)(8,006,547)(492,453)(492,453)
2140 2283 Pen & Ben PTD SO (24,864,308)(23,23.610)(1,44,698)(1,44,698)
2141 2283 Pen & Ben PTû S (71,232,015)(71,232,015)
2142 254 Reg Liab PTD SE (44,269)(41,462)(2,807)2,807
2143 254 Ins Prov PTD SO
2144 B15 (104,639,593)(102,703,635)(1,935,958)2,807 (1,933,151)
2145
2146 22841 Accum Misc Oper Provisions - Other
2147 P S
2148 P SG (1,500,000i (1,409,213l (90,787l (90,787)
2149 B15 (1,5OO,OÖÖ (1,409,213 (90,787 (90,787)
2150
2151 22842 Prv-Trojan P TROJD
2152 230 ARO P TROJP (1,691,988)(1,588,839)(103,149)(103,149)
2153 254105 ARO P TROJP (3,512,728)(3,298,581 )(214,147)(214,147)
2154 254 P S (13,908,965)
!13,908,965)2155 B15 (19,113,682)18,796,385)(317,296)(317,296)
2156
2157 252 Customer Advances for Construction
2158 DPW S (10,535,734)(10,185,382)(350,352)(3,729)(354,081)
2159 DPW SE
2160 T SG (7,959,228)(7,477 ,496)(481,732)(330,807)(812,539)
2161 DPW SO
2162 CUST CN
2163 Total Customer Advances for Construction B19 (18,494,962)(17,662,878)(832,083)(334,536)(1,166,620)
2164
2165 25398 S02 Emissions
2166 P SE (1,571,507)(1,571,507)
2167 B19 (1,571,507)(1,571,507)
2168
2169 25399 Other Deferred Credits
2170 P S (3,632,420)(3,557,473)(74,947)(74,947)
2171 LABOR SO
2172 P SG (7,639,843)(7,177,442)(462,401)(462,401)
2173 P SE (408,871)(382,944)~25,927)(25,927l
2174 B19 (11,681,135)(11,11,860)( 63,274)(563,274
ROLLED-IN Page 12.35
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
2175
2176 190 Accumulated Deferred Income Taxes
2177 P S 15,585,863 15,585.864 (1)(1)
2178 CUST CN 47,212 45.385 1,827 1,827
2179 P IBT
2180 LABOR SO 75,156,683 70,801,923 4.354,760 (257,507)4,097,253
2181 P DGP
2182 CUST BADDEBT 3.844.158 3,635,975 208,183 208.183
2183 P TROJD 1.912,923 1,796,157 116,766 (116,766)
2184 P SG 39.603,966 37,206.939 2.397,027 (2,232,800)164,227
2185 P SE (19.942,198)(18,677.658)(1,264,539)596,403 (668,137)
2186 PTD SNP
2187 DPW SNPD 1.793,564 1,710,414 83,150 83.150
2188 P SG
2189 Total Accum Deferred Income Taxes B19 118,002,171 112,104,998 5,897,173 (2,010,671)3,886,502
2190
2191 281 Accumulated Deferred Income Taxes
2192 P S
2193 PT SG (11,642,708)(10,938.034)(704.674)704,674
2194 T SNPT
2195 B19 (11,642,708)(10,938.034)(704,674)704,674
2196
2197 282 Accumulated Deferred Income Taxes
2198 GP S (164,376,500)(164,376,500)
2199 ACCMDIT DITBAL (3.046.185,039)(2,877,261,043)(168,903,996)168.903,996
2200 P SG
2201 P SG
2202 IBT IBT
2203 LABOR SO 32,477,154 30,595,349 1,861.605 (386)1,881,419
2204 CUST CN
2205 P SE (5,543.047)(5,191,561 )(351,486)(364,430)(715,916)
2206 P SG (5,198.466)(4,663,848)(314,638)(8,487,956)(8,802.594)
2207 B19 (3,024,449.418)(2,856,761,103)(167,688,315)(4,325,275)(172,013,591)
2206
2209 263 Accumulated Deferred Income Taxes
2210 GP S (46,066,263)(44,925,191)(1,141,072)1,129.081 (11,991)
2211 P SG (9,100,662)(8.549,845)(550,617)(26,356)(577.172)
2212 P SE (7,531,923)(7,054,322)(477,601)1.517 (476,084)
2213 LABOR SO (3,864,666)(3,640,738)(223,928)140.971 (82,957)
2214 GP GPS (7,446,211 )(7.016,644)(431.567)(431,567)
2215 PTD SNP (4,344,154)(4,094,881 )(249.273)(249,273)
2216 P TROJD
2217 P SG
2218 P SGCT (2,804,313)(2.633,928)(170,385)(170,385)
2219 P SG
2220 B19 (81,160,192)(77.915,549)(3,244.643)1,245.213 (1,999,430)
2221
2222 Total Accum Deferred Income Tax B19 (2,999,250,147)(2,833,509,688)(165,740,459)(4,386,060)(170,126,518)
2223 255 Accumulated Investment Tax Credit
2224 PTD S
2225 PTD ITC84 (1,163,513)(1,163,513)
2226 PTD ITC85 (2,365,510)(2,365,510)
2227 PTD ITC86 (1,233,135)(1,233,135)
2228 PTD ITC86 (192,618)(192,618)
2229 PTD ITC89 (427,664)(427,664)
2230 PTD ITC90 (267,130)(246,965)(40,145)(40,145)
2231 PTD SO (118,179l (118,179)
2232 Total Accumlated ITC B19 (5,669,170)(5.629,625)(40,145)(11.179 (158,324)
2233
2234 Total Rate Base Deductions (3,160,349,288)(2,990,829,285)(169,520,003)(6,407,474)(175,927,478)
2235
ROLLED-IN Page 12.36
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO.
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
2236
2237
2238 108SP Steam Prod Plant Accumulated Depr
2239 P S
2240 P SG (804,085,770)(755,18,540)(48,667,229)(48,667,229)
2241 P SG (931,773,797)(875,378,260)(56,395,537)(56,395,537)
2242 P SG (599,387,572)(563,109,685)(36,277,887)(699,345)(36,977,231)
2243 P SG
2244 P SG (164,881,495)(154,902,055)(9,979,440)(9,979,440)
2245 617 (2,500,128,634)(2,348,808,541 )(151,320,093)(699,345)(152,019,438)
2246
2247 108NP Nuclear Prod Plant Accumulated Depr
2248 P SG
2249 P SG
2250 P SG
2251 617
2252
2253
2254 108HP Hydraulic Prod Plant Accum Depr
2255 P S
2256 P SG (153,199,830)(143,927,422)(9,272,408)(9,272,408)
2257 P SG (29,592,043)(27,800,987)(1,791,056)(1,791,056)
2258 P SG (64,346,115)(60,451,572)(3,894,544)110,809 (3,783,734)
2259 P SG (15,581,955)(14,638,858)(943,097)(943,097)
2260 617 (262,719,943)(248,818,839)(15,901,104)110.809 (15,790,295)
2261
2262 1080P Other Production Plant - Accum Depr
2263 P S
2264 P SG (1,499,697)(1,408,928)(90,769)(90,769)
2265 P SG (187,115.295)(175,790,156)(11,325,139)(11,325.139)
2266 P SG (179,211,214)(168,364,469)(10,846,745)(10,846,745)
2267 P SG (20,480,021 )(19,240,469)(1,239,552)(1,239,552)2268 617 (388,306,227)(364,804,022)(23,502,204)(23,502,204)
2269
2270 108EP Experimental Plant - Accum Depr
2271 P SG
2272 P SG
2273
2274
2275 Total Production Plant Accum Depreciation B17 (3,151,154,804)(2,960,431,403)(190,723,402)(588,535)(191,311,937)
2276
2277 Summary of Prod Plant Depreciation by Factor
2278 S
2279 DGP
2280 DGU
2281 SG (3,151,154,804)(2,960,431,403)(190,723,402)(588,535)(191,311,937)
2282 SSGCH
2283 SSGCT
2284 Total of Prod Plant Depreciation by Factor (3,151,154,804)(2,960,431,403)(190,723,02)(588,535)(191,311,937)
2285
2286
2287 108TP Transmission Plant Accumulated Depr
2288 T SG (23,060,758)
2289 T SG (24,106,477)
2290 T SG (161,960)(23,979,241)
2291 Total Trans Plant Accum Depreciation B17 6 , 60 1,
ROLLED-IN Page 12.37Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
2292 108360 Land and Land Rights
2293 DPW S (7.520.631)(7.069.954)(450,676)(450.676)2294 B17 (7.520.631 )(7,069.954)(450,676)(450.676)
2295
2296 108361 Structures and Improvements
2297 DPW S (14,400,815)(13,938.693)(462.122)(462.122)2298 B17 (14.400.815)(13,938.693)(462,122)(462.122)
2299
2300 108362 Station Equipment
2301 DPW S (215.414.073)(205.959.864)(9,454,209)(9,454.209)
2302 B17 (215,414.073)(205.959.864)(9,454.209)(9,454.209)2303
2304 108363 Storage Battery Equipment
2305 DPW S
2306 B17
2307
2308 108364 Poles. Towers & Fixtures
2309 DPW S í499.610.379)í463.144.133)í36,466.247)(36.466.247)2310 B17 (499.610.379)í463.144.133)(36,466.247)(36.466.247)
2311
2312 108365 Overhead Conductors
2313 DPW S (271.507,003)(260.179.548)(11.327,454)(11.327,454)
2314 B17 (271.507.003)(260.179.548)(11.327,454)(11.327,454)
2315
2316 108366 Underground Conduit
2317 DPW S (125.057.953)(121.694.746)(3.363.206)(3.363.206)
2318 B17 (125.057.953)(121.694.746)(3.363.206)(3.363.206)2319
2320 108367 Underground Conductors
2321 DPW S (289.382.714)(278.272.333)(11.110.381)(11.110.381)
2322 B17 (289.382.714)(278.272.333)(11.110.381)(11.110.381)
2323
2324 108368 Line Transformers
2325 DPW S (374,776.489)(350.828.934)(23.947.556)(23,947.556)
2326 B17 (374.776,89)(350.828.934)(23.947.556)(23.947.556)
2327
2328 108369 Services
2329 DPW S (173.063.574)(162.208.058)(10.855.515)(10.855.515)2330 B17 (173.063.574)(162.208.058)(10.855.515)(10.855.515)
2331
2332 108370 Meters
2333 DPW S (73,459.993)(65.057.658)(8,02.334)(8,02.334)
2334 B17 (73,459.993)(65.057.658)(8,402.334)(8,02.334)
2335
2336
2337
2338 108371 Installations on Customers' Premises
2339 DPW S (7.902.179)(7.765.116)(137,063)(137,03)
2340 B17 (7.902.179)(7.765.116)(137.063)(137.063)
2341
2342 108372 Leased Properly
2343 DPW S
2344 B17
2345
2346 108373 Street Lights
2347 DPW S (27,437.568)(26.951,399)(486.169)(486.169)
2348 B17 (27,437.568)(26.951,399)(486.169)(486,169)2349
2350 108DOO Unclassified Dist Plant - Acct 300
2351 DPW S
2352 B17
2353
2354 108DS Unclassified Dist Sub Plant - Acct 300
2355 DPW S
2356 B17
2357
2358 108DP Unclassified Dist Sub Plant - Acct 300
2359 DPW S 7.323.293 7.315.721 7.572 7,572
2360 B17 7.323.293 7.315.721 7.572 7,572
2361
2362
2363 Total Distribution Plant Accum Depreciation B17 (2,072,210,076)(1,955.754,716)(116,455,361)(116,455,361 )
2364
2365 Summary of Distribution Plant Depr by Factor
2366 S (2.072.210.076)(1.955.754.716)(116,55.361 )(116,455,361 )
2367
2368 Total Distribution Depreciation by Factor B17 (2.072.210m6)(1.955.754.716)(116.55.361)(116,455.361)
ROLLED-IN Page 12.38
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
2369 108GP General Plant Accumulated Depr
2370 G-SITUS S (152.075,528)(141,631,971)(10,443,557)(10,44,557)
2371 PT SG (3,260,839)(3,063,477)(197,362)(197.362)
2372 PT SG (5,665.017)(5,322,143)(342,875)(342,875)
2373 G-SG SG (49,106,625)(46,134,451)(2,972,175)(2,972,175)
2374 CUST CN (7,361,183)(7,076.386)(284,796)(284,796)
2375 PTD SO (71,958,569)(67,789,115)(4,169,454)(4,169,454)
2376 P SE (334,770)(313,542)(21,228)(21,228)
2377 G-SG SG (40,513)(38,061)(2,452)(2,452)
2378 G-SG SG (1,892,045)(1,777,529)(114,516)(114,516)
2379 817 (291,695,088)(273,146,674)(18,548,414)(18,548,414)
2380
2381
2382 108MP Mining Plant Accumulated Depr.
2383 P S
2384 P SE (155,112,236)(145,276,532)(9,835,703)(36,877)(9,872,581 )
2385 817 (155,112,236)(145,276,532)(9,835,703)(36,877)(9,872,581 )
2386 108MP Less Centralia Situs Depreciation
2387 P S
2388 817 (155,112,236)(145,276,532)(9,835,703)(36,877)(9,872,581 )
2389
2390 1081390 Accum Depr - Capital Lease
2391 PTD SO 817
2392
2393
2394 Remove Capital Leases
2395 817
2396
2397 1081399 Accum Depr - Capital Lease
2398 P S
2399 P SE 817
2400
2401
2402 Remove Capital Leases
2403 817
2404
2405
2406 Total General Plant Accum Depreciation B17 (446,807,324)(418,423,207)(28,384,117)(36,877 (28,420,995)
2407
2408
2409
2410 Summary of General Depreciation by Factor
2411 S (152,075.528)(141,631,971)(10,443,557)(10,443,557)
2412 DGP
2413 DGU
2414 SE (155,447,006)(145,590,074)(9,856,931 )(36.877)(9,893,808)
2415 SO (71,958,569)(67.789,115)(4,169,454)(4,169,454)
2416 CN (7,361,183)(7,076,386)(284,796)(284,796)
2417 SG (59,965,039)(56,335,660)(3,629,379)(3,629,379)
2418 DEU
2419 SSGCT
2420 SSGCH
2421 Remove Capital Leases
2422 Total General Depreciation by Factor (446,807,324)(418,423,207)(28,384,117)(36,877)(28.20,995)
2423
2424
2425 Total Accum Depreciation. Plant in Service B17 (6,842,986,868)(6,436,439,471)(406,547,397)(787,372)(407,334,769)
2426 111SP Accum Prov for Amort-Steam
2427 P SG
2428 P SG
2429 818
2430
2431
2432 l11GP Accum Prov for Amort-General
2433 G-SITUS S (16,724,813)(16,724.813)
2434 CUST CN (2,724,543)(2,619,133)(105,10)(105,10)
2435 I-SG SG
2436 PTD SO (10,775,043)(10,150,710)(624,332)(624,332)
2437 P SE
2438 818 (30,224,398)(29,494,656)(729,742)(729,742)
2439
ROLLED.IN Page 12.39
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
2440
2441 111HP Accum Prov for Amort-Hydro
2442 P SG
2443 P SG
2444 P SG (135.728)(127.513)(8.215)(8,215)
2445 P SG (437.050)(410,598)(26,452)(26,52)
2446 618 (572,778)(538,111)(34.667)(34.667)
2447
244
2449 1111P Accum Prov for Amort-lntan9ible Plant
2450 I-SITUS S (1,045.867)(289,169)(756.698)(756,698)
2451 P SG
2452 P SG (349.396)(328,249)(21.147)(21,147)
2453 P SE (1,299,989)(1.217,557)(82,433)(82.433)
2454 I-SG SG (47.842.258)(44,946,609)(2,895.649)(533,590)(3,429,239)
2455 I-SG SG (14,069.890)(13,218,311 )(851.579)(851,579)
2456 I-SG SG (3,421.089)(3.214.027)(207.061).(207,061)
2457 CUST CN (94,981.920)(91.307,173)(3.674.748)(3,674,748)
2458 P SG
2459 P SG (122.031)(114,645)(7.386)(7,386)
2460 PTD SO (262.133.488)(246,944,839)(15,188.649)(15,188,649)2461 618 (425.265.929)(401,580,580)(23,685.349)(533,590)(24,218,939)
2462 1111P Less Non-Utility Plant
2463 NUTIL OTH
2464 (425,265,929)(401,580,580)(23,685,349)(533,590)(24,218,939)
2465
2466 111390 Accum Amtr - Capital Lease
2467 G-SITUS S (5,580.322)(5,580,322)
2468 P SG (1,701.025)(1,598.070)(102.954)(102,954)
2469 PTD SO 1,340,129 1.262,479 77,650 77.650
2470 (5,941.217)(5,915,913)(25.304)(25.304)
2471
2472 Remove Capital Lease Amtr 5,941.217 5,915,913 25,304 25.304
2473
2474 Total Accum Provision for Amortization B18 (456,063,105)(431,613,347)(24,449,758)(533,590)(24,983,348)
2475
2476
2477
2478
2479 Summary of Amortization by Factor
2480.S (23,351,001 )(22,594,303)(756,698)(756.698)
2481 DGP
2482 DGU
2483 SE (1,299.989)(1,217.557)(82,433)(82,433)
2484 SO (271,568,401 )(255,833.071 )(15,735,330)(15.735,330)
2485 CN (97.706,63)(93,926,306)(3,780.157)(3,780,157)
2486 SSGCT
2487 SSGCH
2488 SG (68.078,468)(63,958,024)(4,120,44)(533,590)(4.654.034)
2489 Less Capital Lease 5.941.217 5,915,913 25,304 25.304
2490 Total Provision For Amortization by Factor (456,03.105)(431.613.347)(24,449.758)(533,590)(24.983.348)
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a
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R
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H
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R
$7
5
6
$
$
$
$
$
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5
6
$
SC
H
M
A
T
41
5
7
0
2
Re
o

A
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t

-

L
a
k
e

S
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L
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.
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$2
8
$
$
$
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8
$
$
$
$
$
SC
H
M
A
T
41
5
7
0
3
Go
o
d
n
o
e

H
i
l
s

L
i
n
u
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d
a
t
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D
a
m
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-

W
Y
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P
$2
1
$
$
$
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1
$
$
$
$
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SC
H
M
A
T
41
5
7
0
4
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o

L
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$4
9
$
$
$
$
$4
9
$
$
$
$
SC
H
M
A
T
41
5
8
0
3
WA

R
T
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G
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W
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s
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N
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w
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WA
$4
7
$
$
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7
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$
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$
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SC
H
M
A
T
41
5
8
0
4
RT
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G
r
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d

W
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N
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l
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c
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$2
9
6
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$
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SC
H
M
A
T
41
5
8
0
5
RT
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G
r
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d

W
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s
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N
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t
e
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R
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-
W
Y
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P
$9
2
$
$
$
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2
$
$
$
$
$
SC
H
M
A
T
41
5
8
0
6
ID

R
T
O

G
r
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d

W
e
s
t

/
I
R
ID
U
$2
7
$
$
$
$
$
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7
$
$
$
SC
H
M
A
T
41
5
8
2
2
RA
n

A
s
s
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t

P
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s
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M
M
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-
U
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UT
$2
8
3
$
$
$
$
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8
3
$
$
$
$
SC
H
M
A
T
41
5
8
2
8
RA
O
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l
a
t
a
r
v

A
s
s
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-

P
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M
M
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-
W
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P
$3
0
9
$
$
$
$3
0
9
$
$
$
$
$
SC
H
M
A
T
41
5
8
2
9
Re
a

A
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t

-

P
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t

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M
M
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$2
7
9
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$
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$
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SC
H
M
A
T
41
5
8
4
0
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a

A
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3
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SC
H
M
A
T
41
5
8
5
0
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SC
H
M
A
T
41
5
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2
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SC
H
M
A
T
41
5
8
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3
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SC
H
M
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T
41
5
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M
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41
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SC
H
M
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T
41
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SC
H
M
A
T
41
5
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H
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T
41
5
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41
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SC
H
M
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T
42
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SC
H
M
A
T
42
5
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2
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$
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SC
H
M
A
T
42
5
2
1
5
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SC
H
M
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T
42
5
2
5
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SC
H
M
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T
42
5
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8
0
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SC
H
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T
42
5
3
6
0
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n

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$1
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2
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$
$
SC
H
M
A
T
43
0
1
0
0
Cu
s
t
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S
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0
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SC
H
M
A
T
43
0
1
1
1
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A
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$
SC
H
M
A
T
43
0
1
1
2
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A
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-

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$3
9
$
$
$
$
$
$
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9
$
SC
H
M
A
T
43
0
1
1
3
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A
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$2
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$
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,
6
0
4
$
SC
H
M
A
T
50
5
5
1
0
PM
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t
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d
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$1
7
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SC
H
M
A
T
50
5
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k

L
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$
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SC
H
M
A
T
60
5
1
0
0
Tr
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n

D
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c
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m
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1
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$
$
SC
H
M
A
T
60
5
7
1
0
Re
v
e
r
s
e

A
c
c
r
e
d

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l

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e
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l
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m
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t
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n
SE
$2
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4
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7
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8
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4
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$
$
SC
H
M
A
T
61
0
1
1
1
PM
I
B
C
C

G
a
i
n
/
L
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n

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d
SE
$1
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$3
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2
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3
$2
9
$6
9
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1
$1
$
$
SC
H
M
A
T
61
0
1
1
4
PM
I

E
I
T
F

P
r
e
-
t
r
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p
p
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g

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t
s
SE
$9
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$1
5
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2
7
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0
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6
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7
4
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$
$
SC
H
M
A
T
61
0
1
4
3
Re
g

L
i
a
b
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l
t
y

-

W
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L
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w

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n
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v

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r
a
m
WA
$2
4
1
$
$
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4
1
$
$
$
$
$
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SC
H
M
A
T
61
0
1
4
5
Re
g

L
i
a
b
-
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a
l
a
n
c
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C
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n
s
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OR
$2
,
6
2
6
$
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,
6
2
6
$
$
$
$
$
$
$
SC
H
M
A
T
61
0
1
4
6
OR

R
e
g

A
s
s
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t
l
a
b
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l
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C
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n
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t
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n
OR
$6
1
$
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1
$
$
$
$
$
$
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SC
H
M
A
T
70
5
2
4
0
CA

A
1
t
e
m
a
l
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v
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R
a
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f
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a
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m

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CA
$1
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1
4
3
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1
4
3
$
$
$
$
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$
$
SC
H
M
A
T
70
5
2
6
0
Ma
r
c
h

2
0
0
6

T
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n
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c
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s
-
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WA
$3
1
9
$
$
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9
$
$
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SC
H
M
A
T
70
5
2
6
1
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g

L
i
a
b
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l
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t
y

-

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$3
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9
2
2
$
$
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$
$
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9
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$
SC
H
M
A
T
70
5
2
6
5
Re
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L
i
a
b

-

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n
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C
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n
s
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v
a
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n

C
h
a
r
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e
OR
$1
5
1
6
$
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5
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6
$
$
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$
$
$
$
SC
H
M
A
T
70
5
3
3
7
Re
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l
a
t
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r
y

L
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a
b
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y

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w
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H
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R
$3
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5
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4
$
$
$
$
$
$
$
$3
5
9
4
$
SC
H
M
A
T
71
5
1
0
5
MC
I

F
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W
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r
e

L
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a
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e
SG
$1
$
$
$
$
$
$
$
$
$
SC
H
M
A
T
71
5
7
2
0
NW

P
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w
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A
c
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W
A
OT
H
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R
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2007 Lead/Lag Study Rocky Mountain Power
Table of Contents
1.0 Exhibit -Total Cash Working Capital
1.1 Introduction
2.0 Summary of Current Study
2.1 Exhibit - Cash Working Capital Summary
3.0 Revenue Lag
3.1 Exhibit - Revenue Lag Summary
3.2 Exhibit - Billing Lead/Lag Summary
3.3 Exhibit - Revenue Collection Lag
3.3.1 Exhibit - Daily Accounts Receivable Balances
3.3.2 Exhibit - Month-End Accounts Receivable Balances by State
3.3.3 Exhibit - Sum of Daily Customer Accounts Receivable Balances by Month
3.3.5 Exhibit - Sum of Daily Customer Accounts Receivable Balances by State
3.3.6 Exhibit - Revenues Included in Customer Accounts Receivable Balances
3.3.7 Exhibit - Other Taxes and Sales Taxes
3.3.8 Exhibit - Unbiled Revenues
3.4 Exhibit - Wholesale Power Receivables
4.0 Expense Lag
4.1 Exhibit - Expense Lag Summary
4.2 Exhibit - Coal Expense Lag Summary
4.2.1 Exhibit - Coal Expense and Steam Purchases
4.2.4 Exhibit - Energy West Mining Payables Lag
4.2.5 Exhibit-Jim Bridger Mine Accounts Payable Data
4.2.6 Exhibit - Hunter Joint Owner Bilings
4.2.7 Exhibit - Energy West Management Payroll
4.2.8 Exhibit - Energy West Workforce Payroll
4.2.9 Exhibit - Jim Bridger Payroll
4.3 Exhibit - Natural Gas Payables
4.4 Exhibit - Purchased Power Expense
4.5 Exhibit - Labor and Incentive Lag Calculation
4.5.1 Exhibit - Actual Labor, Overheads and Incentive Expenses
4.6 Exhibit - Other O&M Expenses Lag Calculation
4.6.1 Exhibit - Other O&M: Accounts Payable Analysis - January 2007
4.7 Exhibit - Cash Payments for Taxes Other
4.8 Exhibit - Other Taxes
4.8.1 Exhibit - Cash Payments for Franchise/Use Taxes and Regulatory Fees
4.9 Exhibit - Income Tax Lag
5.0 Exhibit - December 2007 Results of Operations Summary
5.1 Exhibit - Revenue Summary by Account, Factor, and Lead/Lag Category
5.2 Exhibit - O&M Summary by Account, Factor, and Lead/Lag Category
5.14 Exhibit - Taxes Other Than Income Summary by Account, Factor, and Lead/Lag Category
5.15 Exhibit - December 2007 Net Power Cost Summary
Enclosed is a CD containing an electrnic copy of the documents and exhibits in the file formats in which they wer creted.
ROCKY MOUNTAINPOWER
Page 1.0
A DIVISION OF PACIFICORP
Lead/Lag Study
December 2007
Idaho Jurisdiction
CASH WORKING CAPITAL
Revenue Lag Days
Amount Reference
39.58 Page 2.1
34.86 Page 2.1
4.72 Page 2.1
508,047 Page 2.1
2,397,469 Page 2.1
Expense Lag Days
Net Revenue Lag Days
Daily Cost of Service (Total Expense Lag /365)
Total Cash Working Capital
Introduction.
2007 Lead/Lag Study
Page 1.1
Rocky Mountain Power
INTRODUCTION
Lead/Lag Approach to Calculating Cash Working Capital
Working capital may be defined as the average amount of capital provided by investors in
the Company, over and above the investment in plant and other specifically identified rate base
items, to bridge the gap between the time expenditures are required to provide service and the
time collections are received for that service. While individual regulatory commissions may differ
as to the specific components of working capital, there is general agreement among working
capital theorists that the following elements are included: (1) fuel inventory; (2) materials and
supplies inventories; (3) prepayments; and (4) cash working capitaL. Of these elements, cash
working capital has traditionally been the most controversial due to differences in definition and
method of calculation.
Rocky Mountain Power has adopted the definition of cash working capital proposed by
FERC in its Notice of Proposed Rulemaking (NOPR) on "Calculation of Cash Working Capital
Allowance for Electric Utilties", Docket No. RM84-9-000, issued AprilS, 1984. In this NOPR,
FERC indicates that cash working capital is the amount of cash needed on-hand by a public utility
to pay its day-to-day operating expenses, for the time period during which the utility has provided
electric service to its customers and has not yet been fully paid for the service. If, on average, the
time difference between providing the service and collecting the associated revenue exceeds the
time difference between providing the service and paying the associated expenses, the utilty is
experiencing a "net revenue receipt lag". This necessitates maintaining a working cash balance
that must be funded. On the other hand, if the lag in payment of expenses is longer than the lag
in collecting revenues; there is a "net expense payment lag", meaning that the collection of
revenues occurs in advance of paying expenses. A utility experiencing a "net revenue receipt
lag" requires working cash in its revenue requirement.
The term describing the permissible net addition to rate base to reflect borrowed or
investor-supplied working cash is the cash working capital allowance. With respect to the method
of calculation of cash working capital, the FERC NOPR states that "a fully-developed and reliable
lead/lag study is the most accurate method of determining the working cash needs of a particular
utility". While the FERC NOPR was never fully adopted, it offered guidelines and is also
consistent with Robert Hahne's text "Accounting for Public Utilities."
This report presents the results of the Company's recently completed lead/lag study
based on 12-months ending December 2007 revenues and expenses. The revenues and
expenses used in the study are consistent with the Company's December 2007 unadjusted
results as published in the Results of Operations Report filed with the Commission. This report
summarizes the amount of the cash working capital requirement and describes the method of its
calculation. The elements, which the Company has included in its lead/lag study, are consistent
Introduction
2007 Lead/Lag Study
Page 1.2
Rocky Mountain Power
with those proposed in the FERC NOPR; namely, revenues, fuel costs, purchased power costs,
labor, operation and maintenance expenses, income taxes, and property and other taxes.
Separate lags were calculated for each major element in the study, based on information
developed from the Company's accounting and customer information systems. The report
describes the calculation of each element and provides source documents. It is the Company's
intention to clearly explain the assumptions and calculations included in this study. However, due
to the voluminous nature of many of the revenue and expense transactions, it is not feasible to
detail every invoice and payment in this report. Full supporting detail is available for inspection on
the Company's premises; additionally, the Company has provided a CD of the data files which
are too lengthy to provide in print.
Summary
2007 Lead/Lag Study
Page 2.0.1
Rocky Mountain Power
LEAD/LAG STUDY: SUMMARY
The lead/lag study described in this report incorporates data obtained directly from
various business units throughout the Company. Results of the study are summarized for the
total company and the Idaho jurisdiction on page 2.1. This summary sheet uses lag days
calculated from the data received from the business units along with actual results from the
December 2007 Results of Operations Report (Section 5.) The net revenue lag minus the net
expense lag equals the net revenue lag days. This represents the time from when goods and
services are provided by the Company to the time when payment for the goods and services are
received. By combining the net revenue lag days with the daily cost of service, the cash working
capital balance required by the Company is determined.
Revenue and Expense Detail
The materials in Sections 3 and 4 of this report describe the calculation of the revenue
and expense lag days used to determine the cash working capital requirement. Examples of
calculation worksheets are provided, starting with summary level documents and tracing the
calculations backward through successive levels of detail, to identify the source materials. The
Company anticipates that this approach wil be informative and wil prove to be a useful method of
identifying and explaining the vast scope of the source documents necessary to support the
study.
Accounts Payable Summary
As documented in the expense lag section (Section 4). expense lag calculations are
performed for each of the operational groups. The lag for each state is then calculated using the
jurisdictional operating expenses associated with each of these groups.
December 2007 Actual Results
The backup pages provided under Section 5 reflect the unadjusted results as reported in
the Company's December 2007 Results of Operations Report and are the basis for the
calculations in this study.
Other Working Capital
This lead/lag study does not include other working capitaL. Other working capital is
included in the miscellaneous rate base section of the Results of Operations Report. It is
separate from cash working capital, and since the related balances change on a continual basis,
other working capital was excluded from the lead/lag study. The omission of the other working
capital does not have an impact on the outcome of the leadllag study related to cash working
capitaL.
Summary
2007 Lead/Lag Study
Page 2.0.2
Rocky Mountain Power
Dollar Days
In this study dollar days are used as a method of computing lag days for each lag section
of the report. By using this approach each of the lead/lag categories are appropriately weighted
in developing the total lag days. This method is consistent with the Company's previous leadllag
filings.
ROCKY MOUNTAINPOWER Page 2.1
A DIVISION OF PACIFICORP
Lead/Lag Study
December 2007
Idaho Jurisdiction
2007 Unadjusted Results (1)
Line Description FERC Account(s)Total Company Idaho Allocated Lag Days Dollar Days Lag Days Ref.
1 REVENUE LAG:
2 General Business Revenues 440 -448 3,228,941,107 184,199,833 40.98 7,548,915,573 Page 3.1
3 Other CSS Revenues 450-454 60,312,704 1,231,736 22.40 27,595,546 Page 3.1
4 Sales for Resale 447NPC 849,248,543 54,281,130 35.65 1,935,020,227 Page 3.4
5 Wheeling and Other Misc. Revenues 456/447 103,779,006 6,083,694 35.65 216,872,262 Page 3.4
6 TOTAL REVENUE LAG 4,242,281,360 245,796,394 39.58 9,728,403,609
7
8
9 EXPENSE LAG:
10 Operation & Maintenance:
11 Coal 501NPC 54,349,711 35,578,791 25.57 909,800,971 Page 4.2
12 Natural Gas 501 NPC / 547NPC 352,928,291 23,990,279 42.03 1,008,421,726 Page 4.3
13 Purchased Power 555NPC 786,238,469 50,571,509 39.25 1,984,691,429 Page 4.4
14 Wheeling Expense 565NPC 106,592,110 6,819,746 39.25 267,642,626 Page 4.4
15 Labor and Benefits 500-935 483,419,789 28,287,960 13.81 390,727,451 Page 4.5
16 Incntive 500-935 21,485,711 1,257,265 167.50 210,591,952 Page 4.5
17 Other Operations & Maintenance EXI 500-935 514,525,795 29,576,849 31.25 924,422,173 Page 4.6
18 Operation & Maintenance Expense Lag 2,809,539,876 176,082,399 32.35 5,696,298,328
19
20 Embedded Cost Differential (2)ECD 5,493,615
21 BPA Credit (3)555 (22,499,508)(5,368,023)
22
23 O&M Expense From Results of Operations 2,787,040,368 176,207,991
24
25 Taxes Other Than Income:
26 Propert Taxes 408 69,102,426 4,113,723 136.81 562,809,454 Page 4.7
27 Other Taxes 408 32,370,321 543,342 41.20 22,387,221 Page 4.8
28 Total Taxes Other Than Income Lag 101,472,747 4,657,065 125.66 585,196,676
29
30 Incme Taxes:
31 Federal Income Taxes 148,774,136 4,093,241 37.87 155,031,484 Page 4.9
32 State Income Taxes 23,057,920 604,267 46.05 27,828,388 Page 4.9
33 Total Income Tax Lag 171,832,056 4,697,508 38.93 182,859,872
34
35 TOTAL EXPENSE LAG 3,082,844,679 185,436,973 34.86 6,46,354,875
36
37 NET REVENUE LAG DAYS 4.72
38
39 Daily Cost of Service (Total Expense Lag Amount /365)508,047
40
41 Cash Working Capital Balance (Net Revenue Lag Days x Daily Cost of Servce)2,397,469
Notes:
(1) The Amount column refects aclual results from the December 2007 Results of Operaion Report.
(2) The Embedded Cost Diferential is a non-cash expnse item. As a resutt, it has been excluded from the leadnag calculation.
(3) The BPAcredit was discontinued in March 2007.
Revenue Lag
2007 Lead/Lag Study
Page 3.0.1
Rocky Mountain Power
REVENUE LAG
This section of the report explains how the revenue lag was computed for the 2007
lead/lag study. Lags were computed for general business revenues, other customer service
system (CSS) revenues, sales for resale, and wheeling and other miscellaneous revenues. The
following is an explanation of how each of the separate components of the revenue lag was
developed.
The basic sources for detailed data used to calculate the revenue lag are CSS, and the
SAP accounting system. Revenue classes reported from these systems, which are detailed in
this study, correspond to FERC operating revenue accounts. Page 3.1 shows the revenue lag
associated with each of the sections mentioned above. These lag days are also shown on page
2.1.
General Business Revenue Lag
The general business revenue lag was computed by subdividing the lag into three
components: service lag, billng lag and collection lag (see Page 3.1). General business revenue
customers include the revenue categories of residential sales, commercial sales, industrial sales,
public street and highway lighting, and other sales to public authorities. Collectively, these
categories are referred to as sales to ultimate customers. Special contract revenues were
considered separately in the 2003 Rocky Mountain Power study. These contracts have now
been incorporated into the general business revenue lag calculation since these contracts are
now captured in CSS, whereas previously they were not.
Service Lag
The service lag is the time period beginning when the customer begins receiving service
for a billng cycle and ends when the customer's meter is read. The service lag equals the total
number of days in the year (365), divided by the number of biling periods per year (12), divided
by two, to arrive at the midpoint for each service period. This calculation would not change if the
meter reading date fluctuated from month-to-month, since any shortage of days from one month
would be reflected as an increase in days for the following month. Using this calculation, the
average service lag is 15.2 days for general business customers. This is the amount shown in
the "Service Lag" column of page 3.1.
Biling Lag
The billng lag is the period beginning when the meter is read and ending when the
invoice is processed in CSS. This lag was calculated using extracts obtained from CSS. Page
3.2 shows the calculation of the billng lag days.
Revenue Lag
2007 Lead/Lag Study
Page 3.0.2
Rocky Mountain Power
Collection Lag
The collection lag is the time interval from the invoice date until the customer pays for the
service. There is no automated reporting process within CSS to track payments against specific
bils. The payment patterns of some customers when paying only partial bils, multiple bils or
combining payments for multiple agreements renders a logical programming approach to tracking
the collection lag on specific agreements extremely difficult, if not impossible.
Due to these complexities, the Company has developed another process for determining
the collection lag. Using this process, the collection lag is calculated by summing the daily
accounts receivable balances for the year and dividing by the total revenues for the same period.
This yields an average age of the revenues in customer accounts receivable, or in other words
the collection lag. This is the same methodology used by the Company in the 2003 study.
The collection lag for general business revenues is shown on page 3.3, with pages 3.3.1
through 3.3.8 as backup. The general business revenue collection lag calculation also includes
the revenue categories of forfeited discounts and interest, miscellaneous service revenues, and
rent from electric property. These revenues are referred to as other CSS revenues in this study
since they are captured in CSS along with the general business revenues.
Daily Accounts Receivable
Development of the collection lag begins with identifying the daily customer accounts
receivable (AIR) balances for 2007 shown on page 3.3.1. Total company daily AIR balances are
obtained by extracting the daily activity for each AIR general ledger account from SAP, the
Company's accounting system. Each day's activity is added to the previous day's balance to
come up with a daily balance. Zero activity is input for those days with no activity due to holidays
and weekends and the previous day's balance is carried forward to the next day with activity.
The actual total company daily AIR balances from the SAP system were allocated to the
various states. This allocation was developed using the actual beginning and ending monthly AIR
balances which are available by state from a monthly AIR aging report generated from CSS
included as page 3.3.2. The state to total company ratios of the beginning/ending average
balances from page 3.3.2 are applied to the daily AIR balances from SAP. This procedure is
shown on pages 3.3.3 and 3.3.4.
By following this process each month, page 3.3.5 was developed. This page shows the
jurisdictional allocation of the sum of the daily customer AIR balances. The total company
amount shown on this page ties to the total company amount shown on page 3.3.1.
Revenues
Next, the total electric revenues applicable to the customer AIR must be determined.
Total electric revenues by state are obtained from SAP. The revenues used in the calculation of
Revenue Lag
2007 Lead/Lag Study
Page 3.0.3
Rocky Mountain Power
the general business collection lag are shown on page 3.3.6. These amounts tie to the totals
included in the December 2007 Results of Operations Report (Section 5.)
Sales and Other Taxes
Page 3.3.7 shows the amount of sales taxes and other taxes for the states in which the
Company bils these taxes directly on the customer bil each month. These amounts must be
considered in the collection lag calculation because the daily AIR balances include amounts owed
for these items. As a result, these taxes are added to revenues as shown on page 3.3. to ensure
that both the numerator (sum of daily AIR balances) and the denominator (total revenues) in the
collection lag calculation are consistent.
Unbiled Revenues
The final adjustment needed for the general revenue collection lag calculation is the
exclusion of the unbiled revenues. These amounts are included in electric revenues, but are not
included in the CSS AIR balances. The 2007 amount of unbiled revenue by state is shown on
page 3.3.8 and is also carried forward to page 3.3.
Sales for Resale, Wheeling, and Other Revenues
Sales for resale represent system revenues, so the lag days are identified at the total
company leveL. The commercial and trading department calculated the lag days for these
revenue categories. This calculation incorporates all energy transactions for 12-months ending
December 2007. Each payment received was analyzed through an automated process that
tracks the average lag in payment received from the mid-poin;t of the service period until payment
is received. The individual lags are then weighted to develop a weighted average revenue lag for
these accounts as shown on page 3.4. This page reflects only a small subset of the transactions
for the year. See the provided CD for a complete record of the transactions analyzed in this
study. The weighted average shown on the bottom of page 3.4 is carried forward to page 3.1.
Other CSS Revenues
The collection lag for these accounts is included in the calculation of the collection lag for
the general business revenue customers so the lag would be the same lag as that calculated for
those customers. Typical charges in these accounts would include late payment fees,
miscellaneous connection fees, temporary service loop rental, etc. Given the nature of these
accounts, there is no service lag or billng lag associated with them, because they do not reflect
metered usage. Therefore, there is no service period information in CSS to use in calculating
either of these lags. What service lag or billng lag there might be on some items in these
accounts would be immaterial to the overall revenue lag calculation.
ROCKY MOUNTAINPOWER
A DIVISION OF PACIFICORP
December 2007 Lead/Lag Study
Revenue Lag Summary
Reference
General Business Revenues
Other CSS Revenues
Sales for Resale
Wheeling and Other Misc. Revenues
Page 3.1
Note 1 Below
Service Lag
15.2
Idaho Jurisdiction
Page 3.2 Pages 3.3 & 3.4
Billng Lag Collection Lag
3.37 22.40
22.40
35.65
35.65
Notes:
(1) Service lag is calculated by taking 365 days per year, divided by 12 biling periods, divided by 2 to get the average service lag.
(2) Service lag and billng lag is included in the collection lag column for the cateegories of other CSS revenues, sales for resale, wheeling
revenues, and other misc. revenues.
Pa e2.1
Total
40.98
22.40
35.65
35.65
ROCKY MOUNTAINPOWER
Page 3.2
A DIVISION OF PACIFICORP
December 2007 Lead/Lag Study
Biling Lag Summary
YR MO total count Average
davs davs
2007 01 299,468 67,960 4.41
2007 02 279,555 68,285 4.09
2007 03 271,549 68,608 3.96
2007 04 277,289 68,831 4.03
2007 05 275,584 68,883 4.00
2007 06 250,474 68,714 3.65
2007 07 269,800 69,207 3.90
2007 08 229,314 69,593 3.30
2007 09 172,862 69,978 2.47
2007 10 162,926 69,867 2.33
2007 11 159,967 70,098 2.28
2007 12 149,940 70,438 2.13
Total Year 2,798,728 830,42 3.37
IDAHO JURISDICTION
Reference Page 3.1
Note: These days represent the amount of time from the biling cycle to when a bil is prepared.
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ROCKY MOUNTAIN Page 3.3.7
POWERA OIVISION OF PAIFICQRP
December 2007 Lead/Lag Study
Other Taxes and Sales Taxes
Sales Tax
Total Company California Idaho Oregon Utah Washington Wyoming
January 4,621,591 3,646,407 216 974,969
February 4,159,202 3,249,509 216 909,478
March 3,856,267 3,058,987 216 797,064
April 3,756,773 2,923,345 216 833,212
May 3,956,830 3,232,733 216 723,881
June 4,640,397 3,988,685 216 651,497
July 5,834,779 5,097,976 216 736,587
August 6,264,391 5,444,890 216 819,285
September 5,623,537 4,846,610 235 776,692
October 4,143,693 3,444,149 205 699,338
November 3,999,526 3,234,215 205 765,105
December 4,615,045 3,694,349 205 920,492
55,472,030 45,861,855 2,575 9,607,599
Other Taxes
Total Company California Idaho Oregon Utah Washington Wyoming
January 6,299,744 18,991 78,019 907,011 4,262,783 755,080 277,861
February 5,875,191 16,771 74,426 806,208 3,992,383 728,581 256,822
March 5,484,377 14,528 71,519 784,558 3,785,492 583,184 245,096
April 5,143,962 13,321 62,391 707,983 3,628,861 507,244 224,162
May 5,570,716 16,014 62,877 770,362 3,996,876 504,464 220,123
June 6,577,950 15,872 74,908 773,793 4,939,885 605,189 168,302
July 7,924,100 18,963 82,159 814,157 6,145,046 624,205 239,569
August 8,539,832 18,495 89,019 878,408 6,601,571 694,324 258,016
September 7,721,298 15,910 82,868 809,642 5,971,556 597,608 243,714
October 6,048,409 14,172 78,557 814,343 4,385,250 528,582 227,505
November 5,907,938 13,462 84,388 879,178 4,037,862 665,593 227,455
December 6,760,752 16,101 87,083 1,039,370 4,485,298 850,746 282,155
77,854,268 192,600 928,213 9,985,012 56,232,864 7,64,800 2,870,780
Total 133,326,298 192,600 928,213 9,985,012 102,094,719 7,647,375 12,478,380 Ref. 3.3
ROCKY MOUNTAINPOWERA DIVISION OF PACIFICORP
December 2007 Lead/Lag Study
Unbiled Revenues
Page 3.3.8
CY2007 14,676,000
Total Company California
797,000 1,505,000
Idaho Oregon
5,872,000
Utah
5,725,000 16,000
Washington Wyoming
761,000 Ref. 3.3
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Expense Lag
2007 Lead/Lag Study
Page 4.0.1
Rocky Mountain Power
EXPENSE LAG
This section of the report documents how the expense lag was developed. The lead/lag
analysis identifies the expense lag as the elapsed time from the receipt of goods and services to
the time the utility pays for the goods and services. In most cases, this study uses the invoice
date to represent the date goods and services were received and the check date to represent the
date payment occurred. The expense lag is comprised of the following elements: coal expense,
natural gas purchases, purchased power, wheeling, labor and benefits, incentive, other operation
and maintenance expenses, property taxes, other taxes, federal income taxes, and state income
taxes. The calculation conforms to the method sponsored by the FERC in Docket No. RM84-9-
000.
The following narrative explains the method and assumptions underlying the expense lag
analysis. The explanation begins with the summarized expense lag and ilustrates how the lag
days were calculated. It then gives key assumptions and components specific to each element
(or group) within expense (Le. coal expense, natural gas purchases, etc.)
By accessing information from the accounts payable office, commercial and trading back
office, fuels group, payroll department, tax department, and others, reports were used to calculate
the elapsed time from the invoice date to the check date (payment lag) for transactions processed
during the twelve-months ending December 2007. A description of each section is provided
below, and any assumptions made are explained. The expense lag summary can be found on
page 4.1.
Coal Lag
The coal expense lag is calculated from multiple sources. Page 4.2 is the coal expense
lag summary which consists of expenses for coal and transportation of coal (detailed in 4.2.1 -
4.2.3,) steam purchases (also included in 4.2.1 - 4.2.3), Energy West payables (4.2.4), Bridger
payables (4.2.5), adjustment for joint owner billings (4.2.6), Energy West management payroll
(4.2.7), Energy West workforce payroll (4.2.8) and Bridger payroll (4.2.9). The total weighted lag
days as calculated on page 4.2 are multiplied by the actual coal expense for the 12-months
period ending December 2007 (5.15) and summarized on page 2.1.
The coal and transportation lag analysis on page 4.2 includes the following groups of fuel
expenses: coal purchases, captive coal operations, steam purchases for the Blundell plant and
coal transportation.
This analysis is based on a number of assumptions, which include the following: First,
the lag for coal expense can be approximated by the lag for delivered coaL. Second, purchased
coal lag should be divided into coal contracts and transportation contracts since the lags may be
different depending on contract terms. Third, any non-cash costs that can be identified in the fuel
Expense Lag
2007 Lead/Lag Study
Page 4.0.2
Rocky Mountain Power
should be excluded since there is no lag related to non-cash costs. Fourth, where possible,
delivered dollars should be adjusted to exclude any period-end estimates that are included in
delivered fuel costs. Finally, for purchased coal, it is assumed that the product is received evenly
over the invoice period.
Coal Lag: Energy West and Bridger Lag
In addition to the amounts in the coal and transportation summary worksheet, the coal
expense lag incorporates accounts payable data from Energy West and Jim Bridger Mines.
Because Rocky Mountain Power funds the daily operations of the captive mines, an analysis of
the various cash expenditures of the mines is necessary. This analysis incorporates the accounts
payable lag and the payroll lag for each of the mines. It should be noted that only 66.67% of
amounts relating to the Bridger mine are used as this is the portion Rocky Mountain Power owns.
Coal Lag: Payroll Lag Days - Coal
The calculation of the payroll lag for each mining operation is shown on pages 4.2.7
through 4.2.9, and is carried forward to page 4.2. For Bridger, both union and management are
on the same payroll schedule, while at Energy West, these two categories are split into separate
schedules.
Coal Lag: Joint Owner Billngs Lag
The Company bils the Hunter plant joint owners monthly based on budgeted amounts.
Page 4.2.6 reflects the true-up entries each month calculated based on the difference between
the amounts billed and actual expenses incurred. The results of this calculation are carried
forward to the coal expense lag summary on page 4.2.
Natural Gas Purchases Lag
The natural gas purchases lag is displayed on page 4.3. This page shows a summary of
the data prepared by the commercial and trading back office based on data from vendor invoices.
It shows the total amount of purchases and the lag days associated with each transaction.
Natural gas receivables have been included with the purchases as negative amounts. The total
weighted lag days as calculated on page 4.3 are multiplied by the actual natural gas expense for
12-months ending December 2007 (5.15) and summarized on page 2.1.
Purchased Power Lag
Page 4.4 shows the calculation of the purchased power lag. This page provides the
information on the net payment by Rocky Mountain Power to counter parties for purchased power
for 12-months ending December 2007.
Expense Lag
2007 Lead/Lag Study
Page 4.0.3
Rocky Mountain Power
Wholesale power transactions are typically delivered throughout the month and invoiced
after month end. The lag was calculated as the difference between the payment date and the
end of service date, effectively combining the billng lag and payment lag into one amount. An
additional 15.2 day product lag is added to the lag calculated above, to account for the receipt of
energy that was assumed to occur evenly throughout the invoice month. The total weighted lag
days as calculated on page 4.4 are multiplied by the actual purchased power expense for 12-
months ending December 2007 (5.15) and summarized on page 2.1.
Wheeling Expense Lag
The wheeling expense lag used in this study is the same as the purchased power lag
described above. When the Company enters into a contract to purchase power, the associated
wheeling expense is included in the contract.
Labor and Benefits Lag
The labor and benefit lag is calculated on page 4.5, which shows the lag between the
midpoint of each pay period and the pay date. On page 2.1 these lag days are multiplied by the
actual labor and overhead expenses for 12-months ending December 2007 (4.5.1 - 4.5.2.)
Incentive Lag
The incentive lag is also calculated on page 4.5. This lag was developed by determining
the days between the midpoint of the year and the incentive pay date, December 17, 2007. On
page 2.1, these lag days are multiplied by the actual incentive expense incurred for the 12 month
period ending December 2007 (4.5.1 - 4.5.2.)
Other Operation and Maintenance (O&M) Expense Lag
The other O&M expense lag is used for expenses not included in other sections of the
study. Page 4.6 shows the calculated lag which was developed using monthly reports from the
central accounts payable office. The invoices from each month of payables were pulled into
reports which excluded all documents pertaining to the other expense lag categories accounted
for separately in this study. See page 4.6.1 for a data sample of invoices for January 2007.
Invoices with payment terms of RECUR and R999 were also removed from the data.
RECUR are associated with recurring payments that have the potential of being set up in SAP as
a parked document since 1999 and would skew the study. The payment terms of R999 are the
retention holdouts on invoice payments that are typically not due and payable until the end of a
project. These types of payments are generally associated with capital projects. The Company
could hold these invoices for up to 3 years or longer, depending on the project.
The database is only for company code 1000, which includes only the regulated electric
Expense Lag
2007 Lead/Lag Study
Page 4.0.4
Rocky Mountain Power
operations portion of the business. And like the other expense sections, the invoice date,
payment date and amount of each invoice were used to calculate the lag days, effectively
weighted by invoice amount. These lag days are multiplied by the remaining O&M expenses not
accounted for elsewhere in the study as shown on page 2.1.
Property Taxes Lag
The property tax lag relates specifically to each individual state's property taxes.
Because every state has different schedules for paying property taxes, the lags vary significantly
by state. The total company property tax lag is the weighted average of the state lags and is
shown on page 4.7.
Other Taxes Lag
The other taxes lag is the composite lag of various taxes included in FERC account 408
excluding property taxes. The lag days for this category vary by jurisdiction, caused by state
specific fees and taxes. These lags were calculated from the midpoint of the tax period to the
payment date from schedules obtained from the tax department for taxes paid for 12-months
ending December 2007 and are summarized on pages 4.8 and 4.8.2.
Income Tax Lag
Federal and state Income tax lags were developed based on data provided by the tax
department and shown on page 4.9. Federal income tax lag days were calculated as the number
of days between the midpoint of each quarter and the quarterly tax payment date. The lags
associated with each quarter were then weighted to arrive at a total federal tax lag. These lag
days were multiplied by the total federal taxes as reported in the Results of Operations Report,
shown on page 2.1.
State income tax lags follow the same procedure as federal taxes described above, with
the exception of Utah, which includes an additional tax payment in April 2008 related to the 2007
tax year. The average state income tax lag is multiplied by the total state income taxes as
reported in the Results of Operations Report, shown on page 2.1.
ROCKY MOUNTAIN Page 4.1
POWER
A DIVISION OF PACIFICORP
December 2007 Lead/Lag Study
Expense Lag Summary
Expense Lag Component Idaho Reference
Coal 25.57 Page 4.2
Natural Gas 42.03 Page 4.3
Purchased Power 39.25 Page 4.4
Wheeling Expenses 39.25 Page 4.4
Labor and Benefits 13.81 Page 4.5
Incentive 167.50 Page 4.5
Other Operations and Maintenance 31.25 Page 4.6
Propert Taxes 136.81 Page 4.7
Other Taxes 41.20 Page 4.8
Federal Income Taxes 37.87 Page 4.9
State Income Taxes 46.05 Page 4.9
ROCKY MOUNTAINPOER Page 4.2
A OIVISION OF PAIFICORP
December 2007 Lead/Lag Study
Coal Expense Lag Summary
Description Amount Lag Days Dollar Days Reference
552,458,000 26.13 14,437,878,280 4.2.1 - 4.2.3
43,106,458 20.56 886,286,621 4.2.4
69,923,640 29.51 2,063,590,947 4.2.5
(867,732)62.00 (53,798,277)4.2.6
664,620,366 26.08 17,333,957,571
6,861,200 16.06 110,188,215 4.2.7
15,083,523 20.00 301,670,453 4.2.8
21,994,140 16.96 373,064,753 4.2.9
43,938,862 17.86 784,923,421
$708,559,228 25.57 $18,118,880,992
Ref. Page 4.1
Expense
Coal & Transportation
Energy West Payables
Bridger Payables
Adjustment for Joint Owner Bilings
Total Fuel Expense
Coal Payroll
Energy West Management
Energy West Union
Bridger Payroll
Total Fuel Payroll
TOTAL COAL LAG
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ROCKY MOUNTAIN
POWER
Page 4.2.4
A DIVISION OF PAIFICORP
December 2007 Lead/Lag Study
Energy West Mining (Accounts Payable)
Invoice date Check date LAG Inv Amount Check number DOLLAR DAYS
4/10/2007 7/3/2007 84 2,291.70 193211 192,503
6/4/2007 8/28/2007 85 116.88 194041 9,935
8/6/2007 10/30/2007 85 250.00 195236 21,250
4/23/2007 7/17/2007 85 798.23 193431 67,850
8/25/2007 11/20/2007 87 202.31 195701 17,601
8/24/2007 11/20/2007 88 105.76 195648 9,307
12/22/2006 3/20/2007 88 142.99 191246 12,583
11/24/2006 2/20/2007 88 550.59 190632 48,452
3/9/2007 6/6/2007 89 195.00 192619 17,355
4/
4/
2/
3/
1 This data has been redacted due to its voluminous
3/nature.Please see cd provided for full record of3/
3/invoices.4/
5/
4/,,
4/30/2007 7/31/2007 92 15,298.04 193649 1,407,420
11/27/2006 2/27/2007 92 49,350.87 190735 4,540,280
5/11/2007 8/14/2007 95 119.00 193869 11,305
2/9/2007 5/15/2007 95 301.50 192230 28,643
12/15/2006 3/20/2007 95 588.43 191227 55,901
8/30/2007 12/4/2007 96 (446.79)195923 (42,892)5/3/2007 8/7/2007 96 61.48 193712 5,902
12114/2006 3/20/2007 96 230.43 191263 22,121
1/17/2007 4/24/2007 97 2,104.82 191908 204,168
7/31/2007 11/6/2007 98 15.00 195447 1,470
3/6/2007 6/12/2007 98 16.38 192784 1,605
5/22/2007 8/28/2007 98 20.17 194041 1,977
5/22/2007 8/28/2007 98 267.10 194148 26,176
5/22/2007 8/28/2007 98 517.17 194041 50,683
5/21/2007 8/28/2007 99 110.49 194041 10,939
5/21/2007 8/28/2007 99 577.00 194085 57,123
2/12/2007 5/22/2007 99 1,437.66 192439 142,328
11/6/2006 2/13/2007 99 1,562.67 190539 154,704
Total 20.56 43,106,458 886,286,621
Ref Page 4.2
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ROCKY MOUNTAIN Page 4.2.6
POWERA DIVISION OF PACIFICQRP
December 2007 Lead/Lag Study
Hunter Joint Owner O&M (no capital)
PERIOD Date Days
Jan-07 ($33,879.17)($33.879.17)3/20/2007 62.5 (2.117 ,48.13)15.50
Feb-07 ($7,267.01 )($7,267.01)4/18/2007 62.0 (450,554.62)14.00
Mar-07 ($184,865.47)($184,865.47)5/18/2007 62.5 (11.554,091.88)15.50
Apr-07 ($135.894.74)($135,894.74)6/20/2007 65.0 (8.833,158.12)15.00
May-07 ($176.362.92)($176,362.92)7/18/2007 62.5 (11.022,682.50)15.50
Jun-07 ($130,87716)($130,877.16)81172007 62.0 (8,114,383.92)15.00
Jui-07 ($92.202.02)($92,202.02)9/19/2007 64.5 (5,947,030.29)15.50
Aug-07 $40.972.25 $40,972.25 10/18/2007 62.5 2,560,765.63 15.50
Sep-07 ($12,009.28)($12,009.28)11/17/2007 62.0 (744,575.36)15.00
Oct-07 ($439.70)($439.70)12/18/2007 62.5 (27,481.25)15.50
Nov-07 ($13,478.50)($13,478.50)1/18/2008 63.0 (849,145.36)15.00
Dec-07 $122,031.12 $122.031.12 2120/2008 65.5 7,993.038.36 15.50
TOTAL (624,272.60)(624,272.60)62.6 (39,106,747.44)
Date Da s
Jan-07 ($41.718.35)($41,718.35)3/15/2007 57.5 (2,398,805.13)15.50
Feb-07 ($2.069.44)($2,069.44)4/16/2007 60.0 (124,166.40)14.00
Mar-07 ($77,805.50)($77,805.50)5/15/2007 59.5 (4,629,427.25)15.50
Apr-07 ($90.920.53)($90,920.53)6/15/2007 60.0 (5,455,231.80)15.00
May-07 ($113,605.76)($113,605.76)7/17/2007 61.5 (6,986,754.24)15.50
Jun-07 ($83,230.88)($83,230.88)8/15/2007 60.0 (4,993.852.80)15.00
Jui-07 ($57,785.06)($57.785.06)9/17/2007 62.5 (3,611.566.25)15.50
Aug-07 $22,109.08 $22.109.08 10/15/2007 59.5 1.315,490.26 15.50
Sep-07 ($15,505.27)($15.505.27)11/15/2007 60.0 (930.316.20)15.00
Oct-07 $5,564.71 $5.564.71 12/172007 61.5 342.229.66 15.50
Nov-07 ($6,085.21)($6.085.21 )1/15/2008 60.0 (365,112.60)15.00
Dec-07 $197,238.83 $197,238.83 2/15/2008 60.5 11,932,949.22 15.50
TOTAL (263,813.38)(263,813.38)60.3 (15,904,563.53)
Payment Payment
Date
Jan-07 ($11.744.58)($11,744.58)3/15/2007 57.5 (675.313.35)15.50
Feb-07 $27,289.62 $27.289.62 4/16/2007 60.0 1,637,37720 14.00
Mar-07 ($25,473.96)($25,473.96)5/15/2007 59.5 (1,515.700.62)15.50
Apr-07 ($23,012.33)($23.012.33)6/15/2007 60.0 (1.380,739.80)15.00
May-07 ($50,997.05)($50.997.05)7/16/2007 60.5 (3.085,321.53)15.50
Jun-07 ($30,938.25)($30.938.25)8/15/2007 60.0 (1,856,295.00)15.00
Jui-07 $24,068.93 $24.068.93 9/14/2007 59.5 1,432,101.34 15.50
Aug-07 $24,288.81 $24,288.81 10/15/2007 59.5 1,445,184.20 15.50
Sep-07 $4,593.78 $4,593.78 11/15/2007 60.0 275,626.80 15.00
Oct-07 $12,151.31 $12,151.31 12/14/2007 58.5 710,851.64 15.50
Nov-07 $34,900.58 $34,900.58 1/15/2008 60.0 2.094,034.80 15.00
Dec-07 $35,226.91 $35,226.91 2/15/2008 60.5 2.131,228.06 15.50
TOTAL 20,353.77 20,353.77 59.6 1,213,033.73
ITOTAL (867,732.21 )(867,732.21)62.00 (53,798,277.24)
Sensitivity to payment 62.00
Ref Page 4.2
* Note - Negative true-up amounts represent a LEAD.
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.ROCKY MOUNTAINPOWER
Page 4.5
A DIVISION OF PACIFlCORP
December 2007 Lead/Lag Study
Labor and Overhead Lag Calculation
Ending
Beginning Date Date Pay Period Check Total
Pay Period Pay Period Days Pay date Lag Lag
12/26/2006 1/10/2007 15.00 01/17/07 7 14.50
1/11/2007 1/25/2007 14.00 02/02/07 8 15.00
1/26/2007 2/10/2007 15.00 02/16/07 6 13.50
2/11/2007 2/25/2007 14.00 03/02/07 5 12.00
2/26/2007 3/10/2007 12.00 03/16/07 6 12.00
3/11/2007 3/25/2007 14.00 04/02/07 8 15.00
3/26/2007 4/10/2007 15.00 04/1707 7 14.50
4/11/2007 4/25/2007 14.00 05/02/07 7 14.00
4/26/2007 5/10/2007 14.00 05/17/07 7 14.00
5/11/2007 5/25/2007 14.00 06/01/07 7 14.00
5/26/2007 6/10/2007 15.00 06/15/07 5 12.50
6/11/2007 6/25/2007 14.00 07/02/07 7 14.00
6/26/2007 7/10/2007 14.00 07/17/07 7 14.00
7/11/2007 7/25/2007 14.00 08/02/07 8 15.00
7/26/2007 8/10/2007 15.00 08/17/07 7 14.50
8/11/2007 8/25/2007 14.00 08/31/07 6 13.00
8/26/2007 9/10/2007 15.00 09/17/07 7 14.50
9/11/2007 9/25/2007 14.00 10/02/07 7 14.00
9/26/2007 10/10/2007 14.00 10/17/07 7 14.00
10/11/2007 10/25/2007 14.00 11/02/07 8 15.00
10/26/2007 11/10/2007 15.00 11/16/07 6 13.50
11/11/2007 11/25/2007 14.00 11/30/07 5 12.00
11/26/2007 12/10/2007 14.00 12/17/07 7 14.00
12/11/2007 12/25/2007 14.00 12/31/07 6 13.00
AVERAGE 13.81 Ref. 4.1
Incentive Lag Calculation
Begininning of Year
End of Year
2007 Midpoint
Incentive Payment Date
Incentive Lag
January 1, 2007
December 31, 2007
July 2,2007
December 17, 2007
167.50 Ref. 4.1
~ROCKY MOUNTAINPORA DlIStOf'PI Page 4.5.1
December 2007 Leadla9 Study
Actual Labor, Overead and Incentive Expenses
500 SG 117,837,823 5,237,331 123,075,154
500 SSGCH 277,679 12,341 290,020
501 SE 700,146 31,118 731264
535 SG.p 9,404,505 417,986 9,822,490
535 SG.U 7,780,040 345786 8,125,82654SG4,285,916 190,489 4,476,405
548 SSGCT 2,580,974 114,712 2,695,686
557 SG 35,188,447 1,563,959 36,752,406
557 SSGCT 67,439 2,997 70,436
560 SG 19,560,341 869,364 20,429705
580 ID 848 38 885
580 SNPD 19,626,340 872,298 20,498,638
580 WYP 4,987 222 5,208
581 SNPD 11,652,093 517,880 12169,973 537,267 23,879 561,146
582 CA 46,326 2,059 48,385
582 ID 95,707 4,254 99,961 95,707 4,254 99,961
582 OR 640,273 28,457 668,731
582 SNPD 12,212 543 12,755 563 25 588
582 UT 606,897 26,974 633,871
582 WA 117,038 5,202 122,240
582 WYP 211612 9,405 221018
583 CA 298,996 13,289 312,285
583 ID 136,062 6,047 142,110 136,062 6,047 142,110
583 OR 1,966,029 87,381 2,053,410
583 SNPD 422,571 18,781 441,352 19,484 866 20,350
583 UT 2,389,747 106,213 2,495,959
583 WA 303,290 13,480 316,770
583 WYP 537,309 23,881 561,190
584 CA 0 0 0
584 OR 0 0 0
584 UT
584 WA 1,348 60 1,408
584 WYP 0 0 0
585 SNPD 323,041 14,358 337398 14,895 662 15,557
586 CA 153,760 6,834 160,594
586 ID 212,564 9,447 222,011 212,564 9,447 222,011
586 OR 1,469,655 65,319 1,534,974
586 SNPD 891,331 39,615 930,946 41,098 1,827 42,925
586 UT 1,018,611 45,272 1,063,883
586 WA 488,001 21,689 509,690
586 WYP 346,101 15383 361,483
587 CA 473,331 21,037 494,368
587 ID 517,984 23,022 541,006 517,98 23,022 541,006
587 OR 2,937,350 130,551 3,067,901
587 UT 2,398,120 106,585 2,504,705
587 WA 626,864 27,861 654,726
587 WYP 519323 23,081 542405
588 CA 32,421 1,441 33,862
588 ID 99,486 4,422 103,908 99,486 4,422 103,908
588 OR 763,709 33,943 797,653
588 SNPD 13,810,748 613,822 14,424,570 636,800 28,303 665,103
588 UT 976,975 43,422 1,020,397
588 WA 111,404 4,951 116,355
588 WYP 160,838 7,148 167,987
589 CA 4,831 215 5,046
589 ID 2,894 129 3,022 2,894 129 3,022
589 OR 40,912 1,818 42,731
589 UT 20,669 919 21,588
589 WA 2,711 120 2,831
589 WYP 32,311 1,436 33,747
590 CA 23,963 1,065 25,029
590 ID 18,154 807 18,961 18,154 807 18,961
590 OR 158,615 7,050 165,664
590 SNPD 7,114,923 316,225 7,431,147 328,062 14,581 342,643
590 UT 114,340 5,082 119,421
590 WA 9,064 403 9,466
590 WYP 64,593 2,871 67,463
592 CA 281,654 12,518 294,173
592 ID 240,317 10,681 250,998 240,317 10,681 250,998
592 OR 2,139,167 95,076 2,234,243
592 SNPD 2,411,637 107,186 2,518,823 111,198 4,942 116,140
592 UT 1,946,750 86,524 2,033,274
592 WA 389,307 17,303 406,610
592 WYP 754,918 33,553 788,471
593 CA 1,860,669 82,698 1,943,367
593 ID 1,846,601 82,073 1,928,674 1,846,601 82,073 1,928,674
593 OR 8,570,440 380,915 8,951,356
593 SNPD 1,808,313 80,371 1,888,684 83,380 3,706 87,085
593 UT 3,948,281 175,482 4,123,764
593 WA 1,155,778 51,369 1,207,147
593 WYP 1,535,149 68,230 1,603,379
594 CA 656,106 29,161 685,267
594 ID 436,949 19,420 456,370 436,949 19,420 456,370
594 OR 3,509,307 155,972 3,665,279
594 SNPD 19,133 850 19,983 882 39 921
594 UT 6,903,005 306,806 7,209,811
~.ROCKY MOUNTAINPOERA C!\SlN Of. l'flp Page 4.5.2
Oecember 2007 Lead/Lag Study
Actual Labor, Overhead and Incentive Expenses
594 WA 639,981 28,444 668,425
594 WYP 937,326 41,660 978,985
595 OR 37,816 1,681 39,497
595 SNPO 422,104 18,761 440,865 19,463 865 20,328
595 UT 5,293 235 5,528
595 WYP
596 CA 81,106 3,605 94,711
596 10 125,74 5,577 131,050 125,474 5,577 131,050
596 OR 686,995 30,534 717,529
596 UT 400,064 17,781 417,845
596 WA 162,750 7,233 169,983
596 WYP 257,035 11,424 268459
597 CA 41,812 1,858 43,671
597 10 231,844 10,304 242,149 231,844 10,304 242,149
597 OR 875,017 38,890 913,908
597 SNPO 1,151,465 51,177 1,202,842 53,093 2,360 55,453
597 UT 1,275,170 56,675 1,331,846
597 WA 301,301 13,391 314,692
597 WYP 476,486 21,178 497684
598 CA 17,429 775 18,204
598 10 10,289 457 10,746 10,289 457 10,746
598 OR 86,114 3,827 89,942
598 SNPO 1,186,190 52,720 1,238,910 54,694 2,431 57,125
598 UT 371,400 16,507 387,907
598 WA 42,039 1,868 43,907
598 WYP 12,844 571 13415
901 CA 2,512 112 2,624
901 CN 1,637,521 72,780 1,710,301 66,545 2,958 69,502
901 10 8,713 387 9,100 8,713 387 9,100
901 OR 65,610 2,916 68,526
901 UT 51,460 2,287 53,747
901 WA 49,966 2,221 52,187
901 WYP 21,018 934 21,953
902 CA 690,478 30,688 721,166
902 CN 519,69 23,ü6 542,745 21,117 939 22,056
902 10 1,208,639 53,718 1,262,357 1,208,639 53,718 1,262,357
902 OR 7,127,795 316,797 7,444,592
902 UT 8,905,222 395,795 9,301,017
902 WA 1,623,644 72,163 1,695,807
902 WYP 1,972,977 87,689 2,060667
903 CA 187,625 8,339 195,964
903 CN 31,606,880 1,404,776 33,011,656 1,284,427 57,087 1,341,513
903 10 181,076 8,048 189,124 181,076 8,048 189,124
903 OR 1,594,438 70,865 1,665,303
903 UT 1,941,160 86,275 2,027,436
903 WA 359,292 15,969 375,260
903 WYP 246,617 10,961 257,578
905 CN 163,418 7,263 170,681 6841 295 6,936
907 CN 300194 13,342 313,537 12,199 542 12,741
908 CA 4,177 186 4,363
908 CN 2,781,690 123,633 2,905,322 113,041 5,024 118,065
908 10 354,220 15,743 369,963 354,220 15,743 369,963
908 OR 1,052,380 46,773 1,099,153
908 UT 909,853 40,439 950,292
908 WA 0 0 0
908 WYP 632,284 28,102 660386
909 CN 407,879 18,128 426,007 16,575 737 17,312
920 SO 92,058,407 4,091,559 96,149,96 5,480,311 243,574 5,723,885
920 WA 343,185 15,253 358,438
920 WYP 6,361 283 6,843
922 SO 1,325,678 58,920 1384,598 8,919 3,508 82,426
929 SO 638,039 28,358 666,397 37,983 1,688 39,671
935 OR 34,355 1,527 35,882
935 SO 3,959,467 175,980 4,135,447 235710 10476 246,186
Utili Labor 483,419,789 21,485,711 504,905,501 28,287,960 1,257,265 29,545,226
Lag Days 13.81 167.50 Ref. Page 4.5
Dollar Days 390,727,451 210,591,952 Ref. Page 4.1
~~g~~ßo~OUNTAIN
December 2007 Lead/Lag Study
Other O&M Lag Calculation
Month Amount Lag Days Dollardays
January-07 81,348,760 30.48 2,479,123,296
February-07 51,359,850 33.19 1,704,697,344
March-07 84,570,951 29.75 2,515,751,768
April-07 101,746,125 27.78 2,826,197,420
May-07 125,682,310 33.95 4,266,551,109
June-07 86,978,954 28.24 2,456,485,277
July-07 82,586,965 31.64 2,612,698,240
August-07 81,210,035 31.73 2,576,960,583
September-07 85,041,421 30.60 2,602,011,901
October-07 85,775,425 34.13 2,927,392,771
November-07 90,132,423 33.00 2,974,541,637
December-07 96,089,511 30.74 2,954,106,631
TOTAL $1,052,522,730 31.25 $32,896,517,977
Ref. 4.1
Payables for fuel/gas, propert taxes/other taxes, power purchases,
wholesale trading positions and payroll are excluded.
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Page 4.8.1
ROCKY MOUNTAINPOWERA DIVlSION OF PACFlRP
December 2007 LeadlLag Study
Cash Payments for Other Taxes
Payment 2007 Payment Midpoint of
Category Period Payment Amt.date Tax Period Lag Days Dollardays Ref.
Oregon Franchise Tax Jan-07 2,005,041 02/20/07 01/16/07 35 70,176,435
Feb-07 1,800,298 03/20/07 02114107 34 61,210,132
Mar-07 1,728,166 04/20/07 03/16/07 35 60,485,810
Apr-07 1,880,101 05/20/07 04/15/07 35 65,803,535
May-07 1,161,250 06/20/07 05/16/07 35 40,643,750
Jun-07 1,194,310 07/20/07 06/15/07 35 41,800,850
Jul-07 2,253,618 08/20/07 07/16/07 35 78,876,630
Aug-07 1,343,820 09/20/07 08/16/07 35 47,033,700
Sep-07 1,253,469 10/20/07 09/15/07 35 43,871,415
Oct-07 2,291,931 11/20/07 10/16/07 35 80,217,585
Nov-07 1,343,167 12/20/07 11/15/07 35 47,010,845
Dec-07 1,643,009 01/20/08 12/16/07 35 57,505,315
19,898,180 35 694,636,002 4.8
Oregon Office of Energy Assessment 7/1/07 to 6/30/08 571,438 9/15/2007 12/31/07 (107)(61,143,866)4.8
Washington Business & Occupation Tax Jan-07 590 2125/2007 01116/07 40 23,616
Feb-07 1,336 3/25/2007 02114/07 39 52,104
Mar-07 1,762 4/25/2007 03/16/07 40 70,480
Apr-07 765 5/2512007 04/15/07 40 30,600
May-07 3,131 6/25/2007 05/16/07 40 125,240
Jun-07 2,470 7/25/2007 06/15/07 40 98,800
Jut-07 2,411 8/25/2007 07/16/07 40 96,440
Aug-07 1,229 9/2512007 08/16/07 40 49,160
Sep-07 1,108 10/25/2007 09/15/07 40 44,320
Oct-07 2,003 11/25/2007 10/16/07 40 80,120
Nov-07 1,805 12125/2007 11/15/07 40 72,200
Dec-07 1,208 1/25/2008 12/16/07 40 48,320
19,818 40 791,400 4.8
Washington Public Utility Tax Jan-07 785,410 2125/2007 01116/07 40 31,416,414
Feb-07 650,758 3/25/2007 02/14/07 39 25,379,562
Mar-07 528,318 4/25/2007 03/16/07 40 21,132,720
Apr-07 569,785 5/25/2007 04/15/07 40 22,791,400
May-07 725,521 6/25/2007 05116/07 40 29,020,840
Jun-07 807,294 7/25/2007 06/15/07 40 32,291,760
Jul-07 538,330 8/25/2007 07/16/07 40 21,533,200
Aug-07 830,068 9/25/2007 08/16/07 40 33,202,720
Sep-07 663,483 10/25/2007 09/15/07 40 26,539,320
Oct-07 713,620 11/25/2007 10/16/07 40 28,544,800
Nov-07 873,424 12125/2007 11/15/07 40 34,936,960
Dec-07 908,743 1/25/2008 12116/07 40 36,349,720
8,594,754 343,139,416 4.8
Idaho Kilowatt Hour Tax Jan-07 911 2125/2007 01116/07 40 36,40
Feb-07 1,132 3/2512007 02114/07 39 44,148
Mar-07 4,002 4/25/2007 03/16/07 40 160,080
Apr-07 1,929 5/25/2007 04/15/07 40 77,160
May-07 1,939 6/25/2007 05/16/07 40 77,560
Jun-07 4,086 7/2512007 06/15/07 40 163,440
Jul-07 3,449 8/25/2007 07/16/07 40 137,960
Aug-07 1,711 9/25/2007 08/16/07 40 68,440
Sep-07 353 10/25/2007 09/15/07 40 14,120
Oct-07 154 11/25/2007 10/16/07 40 6,160
Nov-07 189 1212512007 11/15/07 40 7,560
Dec-07 239 1/2512008 12116/07 40 9,560
20,094 40 802,628 4.8
California Franchise Tax 2007 906,262 3/15/2007 06/30/06 258 233,815,596 4.8
Paid annually in March
Page 4.8.2
ROCKY MOUNTAINPOERA DIVISION OF PACIRCORP
December 2007 Lead/Lag Study
Cash Payments for Other Taxes
Payment 2007 Payment Midpoint of
Category Period Payment Amt.date Tax Period Lag Days Dollardays Ref.
for prior calendar year
Wyoming Franchise Tax Jan-07 102,569 02120/07 01/16/07 35 3,589,915
Feb-07 95,984 03/20/07 02114/07 34 3,263,456
Mar-07 163,088 04/20/07 03/16/07 35 5,708,080
Apr-07 83,351 OS/20/07 04/15/07 35 2,917,285
May-07 80,385 06/20/07 05/16/07 35 2,813,475
Jun-07 142,251 07/20/07 06/15/07 35 4,978,785
Jul-07 87,926 08/20/07 07/16/07 35 3,077,410
Aug-07 93,985 09/20/07 08/16/07 35 3,289,475
Sep-07 154,760 10/20/07 09115/07 35 5,416,600
Oct-07 82,712 11/20/07 10/16/07 35 2,894,920
Nov-07 83,399 12120/07 11/15/07 35 2,918,965
Dec-07 169,861 01/20/08 12116/07 35 5,945,135
1,340,271 35 46,813,501 4.8
Montana Wholesale Energy Transaction Tax Jan 1 to Mar 31 42,684 4/23/2007 02/14/07 68 2,902,512
Apr 1 to Jun 30 31,742 7/24/2007 05/16/07 69 2,190,198
Jul 1 to Sep 30 44,658 10/17/2007 08/16/07 62 2,768,796
Oct 1 to Dec 31 44,183 1/18/2008 11/15/07 64 2,827,712
163,267 65 10,689,218 4.8
Montana Energy License Tax Jan 1 to Mar 31 59,906 4/23/2007 02114/07 68 4,073,608
Apr 1 to Jun 30 44,549 7/24/2007 05/16/07 69 3,073,881
Jul 1 to Sep 30 62,676 10/17/2007 08/16/07 62 3,885,912
Oct 1 to Dec 31 62,010 1/25/2008 11/15/07 71 4,402,710
229,141 67 15,436,111 4.8
TOTAL 31,743,226 40.48 1,284,980,006 4.8
ROCKY MOUNTAINPOWER
Page 4.9
December 2007 LeadlLag Study
Income Tax Lag
Q1 Q2 Q3 Q4
Federal Income Taxes
Start of Quarter 1/1/2007 4/1/2007 7/1/2007 1011/2007
End of Quarter 3131/2007 6/30/2007 9/3012007 12131/2007
Days in Quarter 90.00 91.00 92.00 92.00
Midpoint of Quarter 2115/2007 5/16/2007 8/16/2007 11/16/2007
Quarterly Payment Date 411512007 6/1512007 9/1512007 12115/2007
Lag 60 30 31 30
Weight 25%25%25%25%
Weighted Total 15.00 7.62 7.75 7.50 Total Federal Tax Lag Days 37.87
Ref. Page 4.1
State Income Taxes
California Start of Quarter 1/1/2007 4/1/2007 7/1/2007 1011/2007
End of Quarter 313112007 6/30/2007 9/3012007 12131/2007
Days in Quarter 90.00 91.00 92.00 92.00
Midpoint of Quarter 2115/2007 5/16/2007 8/16/2007 11/1612007
Quarterly Payment Date 411512007 6/15/2007 9/15/2007 1/15/2008
Lag 60 30 31 61
Weight 25%25%25%25%
Weighted Total 15.00 7.62 7.75 15.25 45.62
Idaho Start of Quarter 1/1/2007 4/1/2007 7/1/2007 1011/2007
End of Quarter 3131/2007 6/30/2007 9/3012007 1213112007
Days in Quarter 90.00 91.00 92.00 92.00
Midpoint of Quarter 2115/2007 5/16/2007 8/16/2007 11/16/2007
Quarterly Payment Date 411512007 6/15/2007 9/15/2007 1211512007
Lag 60 30 31 30
Weight 25%25%25%25%
Weighted Total 15.00 7.62 7.75 7.50 37.87
Oregon Start of Quarter 1/1/2007 4/112007 7/1/2007 1011/2007
End of Quarter 3131/2007 6/30/2007 9/30/2007 12131/2007
Days in Quarter 90.00 91.00 92.00 92.00
Midpoint of Quarter 2115/2007 5/16/2007 8/16/2007 11/1612007
Quarterly Payment Date 411512007 6/15/2007 9/15/2007 12115/2007
Lag 60 30 31 30
Weight 25%25%25%25%
Weighted Total 15.00 7.62 7.75 7.50 37.87
Utah Start of Quarter 1/1/2007 41112007 711/2007 1011/2007 1111207
End of Quarter 3/31/2007 6/30/2007 9/30/2007 12131/2007 12131/2007
Days in Quarter 90.00 91.00 92.00 92.00 365.00
Midpont of Quarter 2115/2007 5/16/2007 8/16/2007 11/16/2007 7121007
Quarterly Payment Date 4/1512007 6/15/2007 9/15/2007 12115/2007 4/1512008
Lag 60 30 31 30 287.5
Weight 22.5%22.5%22.5%22.5%10.0%
Weighted Total 13.50 6.86 6.97 6.75 28.75 62.84
Average Total State Tax Lag Days 46.05
Ref. Page 4.1
ROCKY MOUNTAIN Page 5.0
POWERA OIVlSIO OF PAC1~CORl
REVISED PROTOCOL
Beginning/Ending
Ref.
December 2007 RESULTS OF OPERATIONS SUMMARY
UNADJUSTED RESULTS
Description of Account Summary:TOTAL OTHER IDAHO
1 Operating Revenues
2 General Busines Revenues 3.228,941,107 3,04,741,273 184,199.833
3 Interdepartental 0 0 0
4 Special Sales 856,88,831 802,583,701 54,281.130
5 Other Operatig Revenues 156,475,422 149,159,992 7,315,430
6 Totl Operting Revenues 4,242,281,360 3,996,484,966 245,796,394 2.1
7
8 Operating Exenses:
9 Steam Pructin 85,983,104 799,561,899 55,421,205
10 Nuclear Productin 0 0 0
11 Hydro Pructio 34,359,368 32,162,175 2,197,193
12 Other Power Supply 1,199,378,442 1,119,244,504 80,133,939
13 TransmiSion 154,194,872 144,331,053 9,863,819
14 Disbutlo 221,340,872 210,736,037 10,604,835
15 Custer Acunting 95,457,786 91,184,36 4,273,420
16 Custer Serve & Infor 46,969,452 43,100,792 3,868,660 2.1
17 sales 0 0 0
18 Administi & General 180,356,471 170,511,550 9,84,921
19
20 Total 0 & M Exenses 2,787,04,368 2,610,832,377 176,207,991 2.1
21
22 Depreciatin 417,781,814 393,039,933 24,741,881
23 Amortin 84,157,451 60,972,032 3,185,419
24 Taxs Other Than Ince 101,472,747 96,815,662 4,657,065
25 Ince Taxs - Federal 148,774,136 144,68,895 4,093,241 2.1
26 Incoe Taxs - State 23,057,920 22,453,653 604,267 2.1
27 Ince Taxs - Oef Net 79,827,843 76,910,663 2,917,180
28 Investment Tax Credit Adj.(5,854,860)(5,109,951)(744,909)29 Mise Revenue & Exense (11,343,723)(10,616,925)(726,798)
30
31 Totl Operating Exnses 3,604,913,696 3,389,978,358 214,935,337
32
33 Operating Revenue for Return 637,367,684 606,50,608 30,861,056
34
35 Rate Base;
36 Electic Plant in Serve 15,787,758,656 14,847,900,714 939,857,942
37 Plnt Held for Future Use 8,529,582 8,071,181 458,401
38 Mis Deferred Debit 120,693,483 116,888,233 3,805,249
39 ElèC Plant Acq Adj 74,565,289 69,797,032 4,768,257
40 Nuclear Fuel 0 0 0
41 Prepayments 37,262,181 35,014,677 2,247,505
42 Fuel Stok 88,85,802 82,682,617 5,803,185
43 Material & Supplie 139,617,94 130,950,068 8,667,876
44 Woring Capitl 82,743,141 78,485,539 4,257,602
45 WeaUieriZti Loans 11,821,982 5,890,076 6,131,90646Misllaneous Rate Base 5,994,104 5,529,710 46,394
47
48 Total Electr Plant 16,357,472,163 15,381,009,847 976,462,31749
50 Rate Base Deductis:
51 Acum Pray For Depr (6,053,908,945)(5,679,545,496)(374,36,449)52 Accum Proy For Amor (391,421,787)(369,745,202)(21,676,585)53 Acum Def Income Taxs (1,274,447,96)(1,191,981,116)(82,46,850)
54 Unaored rrc (11,355,352)(11,301,125)(54,227)55 Custer Ady for Cost (13,914,775)(13,768,896)(145,880)56 Custer Serv Depoit 0 0 0
57 Mis. Rate Base Deductins (76,494,100)(72,052,183)(4,441,918)58
59 Total Rate Base Deductios (7,821,542,925)(7,338,394,017Y (483,148,908)60
61 Total Rate Base 8,535,929,238 8,042,615,830 493,313,409
62
63 Return on Rate Base 7.467%6.256%
84
65 Return on Equit 8.730%6.27900
66 Net Poer Cost 940,860,037 62,679,194
67 100 Basis Points In Equit
68 Revenue Requirement Impact 67,958,372 3,927,490
69 Rate Base Decease (529,683,729)(36,103,917)
511 Embedded Cost Diferentils
512 Company Owned. P DGP (92,090,202)(92,090,202)513 Company Owned. P SG 92,090,202 86,201,272 5,888,930
514 MId-G Contrct P MC (38,943,305)(38,135,147)(808,158)515 MId-CContrct P SG 38,943,305 36,452,981 2,490,324
516 Eisling OF Contr P S 44,27,180 43,485,808 751,372
517 Exing OF Contr P SG (44,237,180)(41,408,327)(2,828,853)
518
519 (5,493,615)5,493,615 2.1
520
521 Totl Oter Power Supply 826,816,684 772.106,036 54,710,629
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. ROCKY MOUNTAINPOWER
December 2007 Lead/Lag Study
Results of Operations for Taxes Other Than Income
Total Company Idaho
Taxes Other Than Taxes Other Than
Account RP Factor Amount Propert Taxes Income Propert Taxes Income
408 CA 978,962 978,962
408 GPS 69,102,426 69,102,426 4,113,723
408 OR 20,915,928 20,915,928
408 SE 545,664 545.664 35,940
408 SO 8,523,359 8,523,359 507,402
408 UT 18,389 18,389
408 WA 9,329 9,329
408 WYP 1,378,689 1,378,689
101,472,747 69,102,426 32,370,321 4,113,723 54,342 Ref. 2.1
Page 5.14
~ROCKY MOUNTAINPOWERo,VI\'lKlCFPACfICP
December 2007 Lead/La9 Study
Net Power Costs
Unadjusted
Description Account NPC Costs Factor Lead/Lag Section Idaho Ref.
Sales for Resale (Accunt 447)
Exislin9 Firm Sales PPL 447.12 23,609,027 SG Sales for Resale 1,509,736
Existing Firm Sales UPL 447.122 25,912,141 SG Sales for Resale 1,657,014
Post-merger Firm Sales 447.13,447.14,447.2,447.61,447.62 813,349,062 SG Sales for Resale 52,011,567
Non-firm Sales 447.5 (13,621,686)SE Sales for Resale (897,187)
Total Revenue Adjustments 849,248,543 54,281,130
Purchased Power (Account 555)
Existing Firm Demand PPL 555.66 126,380,515 SG Purchased Power 8,081,707
Exisling Firm Demand UPL 555.68 9,780,055 SG Purchased Power 625,409
Existing Firm Energy 555.65, 555.69 107,043,520 SE Purchased Power 7,050,382
Post-merger Firm 555, 555.55,555.61,555.2, 555.67 496,943,120 SG Purchased Power 31,778,226
Secondary Purchases 555.7,555.25 46,091,258 SE Purchased Power 3,035,784T olal Purchased Power Adjustment 786,238,469 50,571,509
Wheelin9 (Account 565)
Existing Firm PPL 565.26 36,800,093 SG Wheeling Expense 2,353,271
Existing Firm UPL 565.27 161,299 SG Wheeling Expense 10,315
Post-merger Firm 565.0, 565.46, 565.1 67,827,919 SG Wheeling Expense 4,337,420
Non-firm 565.25 1,802,80 SE Wheeling Expense 118,741
Total Wheeling Expense Adj 106,592,111 6,819,746
Fuel Expense (Accounts 501, 503 and 547)
Fuel Consumed - Coal 501.,501.11 469,100,755 SE Coal 32,214,442
Fuel Consumed - Gas 501.35 27,090,781 SE Natural Gas 1,784,324
Steam From Other Sources 503 4,845,079 SE Coal 319,119
Natural Gas Consumed 547 261,141,972 SE Natural Gas 17,200,020
Simple Cycle Combustion Turbines 547 64,695,537 SSECT Natural Gas 5,005,934
ChollaiAPS Exchange 501,501.1,501.2,501.45 50,403,877 SSECH Coal 3,045,229
Total Fuel Expense 897,278,001 59,569,070
Net Power Cost 940,860,037 62,679,194 5.0
Page 5.15
i8n r-1AY 27 AM 10: 52 CONFIDENTIA
Case No. PAC-E-11-12
Exhibit NO.3
Witness: Steven R. McDougal
BEFORE THE IDAHO PUBLIC UTILITIES COMMSSION
ROCKY MOUNTAIN POWER
CONFIDENTIAL
Exhibit Accompanying Direct Testimony of Steven R. McDougal
Propert Tax Calculation
May 2011
THIS EXHIBIT IS CONFIDENTIAL
AND IS PROVIDED UNDER
SEPARATE COVER
~.
,\_"",J .
Lot, HAY 21 AM 10: 52
Case No. PAC-E-11-12
Exhibit NO.4
Witness:. Steven R. McDougal
BEFORE THE IDAHO PUBLIC UTILITIES COMMSSION
ROCKY MOUNTAI POWER
Exhibit Accompanying Direct Testimony of Steven R. McDougal
LCAR Calculation
May 2011
Rocky Mountain Power
Exhibit NO.4 Page 1 of 1
Case No. PAC-E-11-12
Witness: Steven R. McDougal
Unbundled Production Revenue Requirement (Excluding NPC)
PAC.E.11.12
Unbundled Production Revenue requirement (Excluding Net Power Costs)
Description Amount Source
1 Production - Return On Investment 931 ,152,243 JAM Tab ECO
2 Production - Expense 2,184,273,612 JAM Tab ECO
3 Production - NPC Expenses (1,680,507,586\NPC Gold Study
Production Revenue Requirement
4 ¡(Excluding NPC)1,434,918,269 Line 1 + Line 2 + Line 3
5 Svstem Load 58,179,087 NPC Gold Study
6 Production $ per MWH 24.66 Line 4 I Line 5
7 %25%Energy Component*
8 LCAR Adjustment ..$6.1'7 Line 6 x Line 7
PAC.E.10.07
Unbundled Production Revenue requirement (Excluding Net Power Costs)
Description Amount Source
1 Production - Return On Investment 833,083,414 JAM Tab ECO
2 Production - Expense 2,173,162,370 JAM Tab ECO
3 Production - NPC Expenses (1,748,001,871 Commission Ordered NPC
Production Revenue Requirement
4 (Excluding NPC)1,258,243,913 (Line 1 + Line 2 + Line 3)
5 System Load 57,460,901 Commission Ordered NPC
6 Production $ per MWH 21.90 Line 4 I Line 5
7 %25%Energy Component*
8 LCAR Adjustment $5.47 Line 6 x Line 7
*LCAR does not include demand per Commission Order 32206