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2mlJ HAY 28 PH 12: 01
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE )
APPLICATION OF ROCKY )
MOUNTAIN POWER FOR )
APPROVAL OF CHANGES TO ITS )
ELECTRIC SERVICE SCHEDULES )
AND A PRICE INCREASE OF $27.7 )
MILLION, OR APPROXIMATELY )
13.7 PERCENT )
CASE NO. PAC.E.10.07
Direct Testimony of C.. Craig Paice
ROCKY MOUNTAIN POWER
CASE NO. PAC.E.10.07
May 2010
1 Q.
2
3 A.
Please state your name, business address and present position with Rocky
Mountain Power ("Company").
My name is C. Craig Paice. My business addrss is 825 NE Multnoma, Suite
4 2000, Portland, Oregon 97232, and I am curently employed as a Regulatory
5 Consultant in the Regulation Deparment.
6 Qualifications
7 Q.
8 A.
9
10
11
12
13
14 Q.
15 A.
16
17
18 Q.
19 A.
20
Briefly describe your educational and professional background.
I received a Bachelor of Science Degree in Business Management from Brigham
Young University in 1976. I have also attended varous educational, professional
and electrc industr seminars durng my career with the Company. I have been
employed by PacifiCorp since the merger in 1989. Pror to that time, I was
employed by Utah Power & Light Company beginning in 1978 holding varous
positions in the accounting, customer service, and regulatory areas.
What are your responsibilties?
My primar responsibilities are to prepare, present, and explain the results of the
Company's cost of service studies to regulators and interested paries in
jurisdictions where PacifiCorp provides retail electrc service.
Have you appeared as a witness in previous regulatory proceedings?
Yes, I have previously filed testimony on behalf of the Company in the states of
Washington, California, Utah, Oregon, and Wyoming.
21 Purpose of Testimony
22 Q.
23 A.
What is the purpose of your testimony in this proceeding?
I wil present Rocky Mountan Power's embedded class cost of service study for
Paice,'Di - 1
Rocky Mountain Power
1 the state of Idaho based on the twelve month test period ending December 31,
2 2010.
3 Cost of Service
4 Q.
5 A.
Please identify and explain Exhibit No. 47.
Exhibit No. 47 provides a summar of the results from the embedded class cost of
6 service study for Idao. It is based on the Company's annual results of operations
7 for the state of Idaho, which are presented in the testimony of Company witness
8 Mr. Steven R. McDougaL. Page 1 presents the summar of the results at the
9 Company's rate of return assuming curent rate levels. Page 2 shows the results
10 using the taget rate of return based on the requested $27.7 milion revenue
11 increase.
12 Q.
13 A.
Please describe Exhibit No. 48.
Exhibit No. 48 is a summar of the cost of service results by rate schedule aIid by
14 function. Page one contains the total cost of service summar by rate schedule
15 and pages two though six contain a summar by rate schedule for each function.
16 Cost of Service Study Changes
17 Q.
18
19
20 A.
21
22
23
Are there any methodology differences between this cost study and the study
fied with the Idaho Commission in Case No. PAC.E.08.07 (the "2008
general rate case")?
No. On page 5 of Commssion Order No. 30783, the final order from the
Company's 2008 general rate case, the Commssion references the order issued in
Case No. PAC-E-07-05, which states the following regarding cost of service
methodology:
Paice, Di - 2
Rocky Mountain Power
1 "The cost of service methodology proposed by the Company in this
2 proceeing wil remain in effect as the accepted methodology though the
3 maximum duration of the rate plans for Agrum and Monsanto, which
4 expire December 31,2010."
5 For this reason, no methodology changes have been made to the cost of service
6 study presented in this case.
7 Irrigation Load Control Program
8 Q.
9
10
11
12 A.
13
14 Q.
15 A.
16
Mr. McDougal explains that the irrigation load control progrm curtlment
is reflected in the coincident peak loads used in the Jurisdictional Allocation
Model ("JAM"). Is the load control program also recognized in the customer
class loads employed in the Cost of Service ("COS") study?
Yes. Customer class loads employed in the COS study are calculated using Load
Research sample data and applied to the test period energy,
How are costs associated with the irrigation load control program allocated?
Load control payments are contained in Account 557 and are alocated to
customer classes using factor FI0. This is consistent with previous COS studies.
17 Description of Cost of Service Procedures
18 Q.
19 A.
20
21
22
23
Please explain how the cost of service study was developed.
The COS study utilizes annual results of operations for the state of Idaho
produced by Mr. McDougal. The study employs a thee-step process generally
referred to as functionalization, classification, and allocation. These thee steps
recognize the way a utilty provides electrcal service and assigns cost
responsibilty to the groups of customers for whom those costs were incurred.
Paice, Di - 3
Rocky Mountain Power
1 Q.
2
3 A.
4
5
6
7
8
9
10
11
12
13
14
15
16 Q.
17
18 A.
19
20
21
22
23
Please describe functionalization and how it is employed in the cost of service
study.
Functionalization is the process of separating expenses and rate base items
according to utilty function. The production function consists of the costs
associated with power generation, including coal mining and wholesale sales and
purchases. The transmission function includes the costs associated with the high
voltage system utilzed for the bulk transmission of power from the generation
source and interconnected utilties to the load centers. The distrbution function
includes the costs associated with all the facilities that are necessar to connect
individual customers to the transmission system. This includes distrbution
substations, poles and wires, line transformers, service drops, and meters. The
retail'service function includes the costs of meter reading, biling, collections, and
customer service. The miscellaneous function includes costs associated with
demand side management, franchise taxes, regulatory expenses, and other
miscellaneous expenses.
Describe clasifcation and explain how the Company uses it in the cost of
service study.
Classification identifies the component of utility service being provided. The
Company provides, and customers purchase, service that includes at least three
different components: demand-related, energy-related, and customer-related
components. Demand-related costs are incurred by the Company to meet the
maximum demand imposed on generating units, transmission lines, and
distribution facilities. Energy-related costs var with the output of a kiowatt-
Paice,Di - 4
Rocky Mountain Power
1
2
3 Q.
4
5 A.
6
7
8
9
10
11
12
13
14
15 Q.
16
17 A.
18
19
20
21
22
23
hour of electrcity. Customer-related costs are drven by the number of customers
served.
How does the Company determine cost responsibilty between customer
groups?
After the cQsts have been functionalized and classified, the next step is to allocate
them among the customer classes. This is achieved by the use of allocation
factors that specify each class' share of a paricular cost drver such as system
peak demand, energy consumed, or number of customers. The appropriate
allocation factor is then applied to the respective cost element to determne each
class' share of cost. A detailed description of the Company's functionalization,
classification and allocation procedures, and the supporting calculations for the
allocation factors are contained in my workpapers, which are attached hereto as
Exhibit No. 49. Also included in the workpapers are the functionalized results of
operations and class cost of service detaiL.
How are generation and transmission costs apportioned among customer .
classes?
Production and transmission plant and non-fuel related expenses are classified as
75 percent demand related and 25 percent energy related. For non-seasonal
resources, the demand-related porton is allocated using the class' 12 monthy
peaks coincident with the Company's system fir peak. Customer class peak
data is derived by extrapolating the load data for each month to the test period
class energy usage. The energy portion is allocated using class MWs adjusted
for losses to generation leveL. For seasonal resources the process is very simiar.
Paice, Di - 5
Rocky Mountain Power
1
2
3
4
5 Q.
6 A.
7
8
9
10
11
12
13
14
15
16 Q.
17
18 A.
19
20
21
The only difference is that prior to summg each class' twelve monthly
coincident peaks or monthly energy usage, the monthly values are weighted by
the monthly portion of the total annual energy generated or delivered to the
Company by the seasonal resource.
Are distribution costs determied using the same methodology?
No. Distribution costs are classified as either demand related or customer related.
In this study only meters and services are considered as customer related with all
other costs considered demand related. Distribution substations and prima lines
. are allocated using the weighted monthly coincident distrbution peaks.
Distrbution line transformers and secondary lines are allocated using the
weighted non-coincident peak method. Services costs are allocated to secondar
voltage delivery customers only. The allocation factor is developed using the
installed cost of new services for different types of customers. Meter costs are
allocated to all customers. The meter allocation factor is developed using the
installed costs of new meterig equipment for different types of customers.
Please explain how customer accounting and customer service expenses are
allocated.
Customer accounting expenses are allocated to classes using weighted customer
factors. The weightings reflect the resources required to perform such activities as
meter reading, biling, and collections for diferent types of customers. Customer
service expenses are allocated on the number of customers in each class.
Paice, Di - 6
Rocky Mountain Power
1 Q.
2
~A.
4
5
6
7
8 Q.
9
10 A.
11
12
13
14
15
How are administrative & general expens, general plant, and intangible
plant allocated by the Company?
Most general plant, intangible plant, and administrative and general expenses are
functionalized and allocated to classes based on generation, transmission, and
distribution plant. Costs that have been identified as supporting customer systems
are considered par of the retail services function and have been allocated using
customer factors. Coal mine plant is allocated on the energy factor.
How are costs and revenues assoiated with wholesale contracts and other
electric revenues treated in the cost of service study?
The revenues from wholesale transactions are treated as revenue credits and are
allocated to customer classes using the appropriate allocation factors. Other
electric revenues are also treated as revenue credits. Revenue credits reduce the
revenue requirement that is to be collected from retail customers. The cost of
purchase power contracts are allocated to customer classes using the appropriate
allocation factors increasing the Company's revenue requirement.
16 Work papers
17 Q.
18 A.
19
20
21
22
Have you included your workpapers?
Yes. My workpapers are included as Exhibit 49. Tab 1 of this exhibit is a
detailed nartive describing the Company's functionalization, classification and
allocation procedures. Tab 2 is the complete functionalized results of operations.
Tab 3 shows the functionalization factors used in this case. Tabs 4 though 5
show the class cost of service detaiL.
Paice, Di-7
Rocky Mountain Power
1 Q.
2 A.
Does this conclude your testimony?
Yes.
Paice, Di - 8
Rocky Mountain Power
Case No. PAC-E-I0-07
Exhibit No. 47
Witness: C. Craig Paice
BEFORE THE IDAHO PUBLIC UTLITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of C. Craig Paice
Cost of Service - Summar by Rate Schedule
May 2010
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Exhibit No. 48
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BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of C. Craig Paice
Cost of Service - Summar by Function
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Case No. PAC-E-I0-07
Exhibit No. 49
Witness: C. Craig Paice
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of C. Craig Paice
Cost of Service - Study
May 2010
Case No. PAC-E-IO-07
Exhbit No. 49
Witness: C. Craig Paice
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAI POWER
Exhbit Accompanying Direct Testimony of C. Craig Paice
Cost of Service - Study
May 2010
Rocky Mountain Power
Table of Contents
Tab 1 Cost of Service Procedures
Tab 2 Functionalized Results of Operations
Tab 3 Functionalization Factors
Tab 4 Class Cost of Service Detail
Tab 4.1
Tab 4.2
Tab 4.3
. Tab 4.4
Tab 4.5
Tab 4.6
All Functions (G+ T +D+R+M)
Generation
Transmission
Distribution
Retail Service
Miscellaneous
Tab 5 Cost of Service Allocation Factors
ROCKY MOUNTAIN POWER
COST OF SERVICE
FUNCTIONALIZATION, CLASSIFICATION & ALLOCATION PROCEDURES
INTRODUCTION
The Class Cost of Service Study is based on PacifiCorp's normalized results of operations.
It employs a three-step process referred to as functionalization, classification, and
allocation. These three steps recognize the way a utility provides electrical service and
assigns cost responsibility to the groups of customers for whom the costs are incurred.
Functionalization
Functionalization recognizes the different roles played by the various facilties in the
electric utility system. It is the process of separating expenses and rate base items to
determine a separate revenue requirement for each of five major electric utility functions;
Production (or Generation), Transmission, Distribution (Poles and Wires), Retail Services
and Miscellaneous Services. These functions are also referred to as P, T, 0 (or DPW), R,
and M.
The production function consists of the costs associated with power generation, including
coal mining and wholesale purchases.
The transmission function includes the costs associated with the high voltage system
utilized for the bulk transmission of power from the generation source and interconnected
utilties to the load centers.
The distribution function includes the radial distribution system that connects the customer
to the transmission system. This includes distribution substations, poles and wires, line
transformers, service drops and meters.
The Retail Service function includes the retail activities associated with customer service
including Meter Reading, Customer Accounting, Customer Service activities and Sales.
The Misc. Services function is a catchall for expenses that are associated with regulatory
activities. These activities include franchise requirements and regulatory commission
expenses.
Classification
Classification identifies the component of utility service being provided. The Company
provides and customers purchase service that includes at least three different
components: demand-related, energy-related, and customer-related.
Demand-related costs are incurred by the Company to meet the maximum demand
imposed on generating units, transmission lines, and distribution facilities. The maximum
Tab 1 Page 1 of 11
demand influences the size of these facilities, and correspondingly, the amount of
Company investment and related expenses.
Energy-related costs vary with the output of a kWh of electricity. Typical energy-related
costs include fuel, maintenance that occurs on the generating unit due to running of the
unit, purchased energy and other costs that are impacted by the decision to supply energy.
Customer-related costs are driven by the number of customers served. Once the
Company makes a commitment to serve a customer, these costs continue, even if the
customer uses little or no electricity. At a minimum, they consist of the costs associated
with meters, service drops, meter reading, biling, and customer service related expenses.
Allocation
After the costs have been functionalized and classified, the next step is to allocate them
among the customer classes. Some utility plant and expenses can be identified as serving
one or a small group of customers and can be directly assigned to those customers. In
most cases, however, utility plant and expenses are used to serve multiple classes of
customers. As such, those costs must be equitably shared among the customer classes.
This is achieved by the use of allocation factors, which specify each class' share of a
particular cost driver such as system peak demand, energy consumed, or number of
customers. The appropriate allocation factor is then applied to the respective cost element
to determine each class' share of cost. Factors with two digits (i.e. F30 - MWH) identify
allocation factors that are calculated using cost driver information that is external to the
cost study.
Many expense and rate base items track plant investment or some other value in the cost
of service study. The allocation factors for these items are internally generated within the
cost of service modeL. Internally identified factors are identified with three digits (i.e. F102
- Gross Plant). Many plant related allocation factors are identified by function and are so
identified (F102G - Generation Plant, F1 02T - Transmission Plant, F1 02D - Distribution
Plant and so on).
FUNCTIONALIZATION PROCEDURES
For regulatory reporting purposes costs are collected into the Business Warehouse (BW)
database. Each account balance in BW is assigned a functional identification or FUNC
F actor. Account balances captured in BW that are directly related to one Of the primary
business functions - P, T, D (or DPW), R, or M - are so designated. The functional
designation is generally driven by the location code associated with an asset or
transaction. In some cases, the customer service system for example, the business
purpose of the asset or transaction is used rather than the physical location. Assets and
expenses that support more than one of the five (for example, administrative and general
expenses and general office rate base) are apportioned between the functions. Those
items that are considered plant related are split between functions in the same proportion
Tab 1 Page 2 of 11
as generation, transmission, and distribution plant (PTD FUNC factor). Those items that
are considered directly related to employee compensation are splitin the same proportion
as company labor,(LABOR FUNC factor).
In the Results of Operations Model (Jurisdictional Allocation Model or JAM), account
balances from BW are aggregated by FERC account and by Revised Protocol
jurisdictional allocation factor and roll up to a single line item. Each of these line items is
also assigned or allocated to one or more ofthe functions using a series of
functionalization factors (FUNC factors). When all, or essentially all, of the account
balance associated with one FERC account and Revised Protocol factor have the sanie
functional designation, that FUNC factor is used. For example any item allocated to a
jurisdiction using the SE factor is generally fuel related and assigned to the generation
function using the "P" FUNC factor.
When the various account balances from BW that roll up to one line in the JAM and have
more than one functional designation, a new FUNC factor is developed. An example of
this is the SCHMAT-SO FUNC factor. Of the Schedule M Additions Temporary account
balances allocated on the SO Protocol factor, some are labor related, some are directly
associated with generation and some are overall plant related. Each of these account
balances is assigned or apportioned to the appropriate function. The SCHMAT-SO FUNC
factor is derived from the summation of the account balances by function. The Schedule
M Additions Temporary allocated to a state using the SO Protocol factor are then assigned
to functions using the SCHMAT-SO FUNC factor.
Some FUNC factors, such as the Production, Transmission and Distribution (PTD) factor
or the Cash Working Capital (CWC) factor are calculated from data inside the JAM modeL.
Operation Revenues:
General Business Revenue: Account 440-445. Residential Revenues, and Account 442,
Retail- Commercial and Industrial Revenues, are not functionalized. The dollar amounts
assigned to PTDRM for retail revenues have been derived to produce the jurisdictional
normalized ROE.
Interdepartmental: Account 448. Interdepartmental Sales, is allocated to Distribution
Poles & Conductor (DPW).
Special Sales: Account 447. Firm Wholesale Sales (sometime referred to as Sales for
Resale), are allocated on the Wholesale Sales Factor, "WSF". This factor is developed by
identifying the production/transmission components of wholesale sales.
Other Operating Revenue: Accounts 450 to 456. Other Revenues is functionalized on
the "OTHREV" factors. The vast majority of revenue in this line item is associated with
account 456 and has been functionalized using the "OTHSE" factor. These factors are
developed by identifying each specific revenue item as PTDRM.
Tab 1 Page 3 of 11
Operating Expenses:
Production: Accounts 500-557. Production expense includes all generation maintenance
expenses as well as fuel and purchased power expenses. All of these costs are assigned
to P.
Transmission: Accounts 560-573. Transmission costs, including wheeling expenses, are
assigned to T.
Distribution: Accounts 580-598. Maintenance and operation expenses are assigned to
D.
Customer Accounts & Sales: Accounts 901-916. Customer Accounts and Sales are
assigned to R.
Administrative & General: Accounts 920-935. Most A&G expenses are functionalized on
the "PTD" functionalization factor. The "PTD" factor used here is based on the ratio of total
company plant investment between P, T & D. Costs that have been identified as
supporting customer systems are considered part of the retail function. Account 926,
Pension Benefits and Account 929 Duplicate Charges are functionalized on the "LABOR"
functionalization factor. The "LABOR" factor is based on the FERC Form 1 breakdown of
labor expenses between P, T, 0 & R (As shown above, Customer Accounting, Service and
Sales are considered part of the R function). Account 927, Franchise Requirements, and
Account 928, Regulatory Commission Expense are assigned to M. Account 928, FERC
annual charge is functionalized on the "FERC" factor with the balance going to M. Account
935 is functionalized on the General Plant "Gil factor.
Depreciation: Account 403. The functionalization of depreciation matches the
functionalization of rate base. For example, the functionalization of General Plant
Depreciation expense matches the functionalization of General Plant rate base.
Amortization: Accounts 404-407. Account 404, Amortization of Limited Term Electric
Plant is functionalized based on analysis of the items being amortized to this account with
the vast majority of the money being functionalized by PTD or CUST. Account 405, Other
Electric Plant Amortization is allocated on the "GP" factor. Account 406, Plant Acquisition
Adjustment Amortization and Account 407, Amortization of un-recovered Plant are
assigned to P.
Taxes Other Than Income: Account 408. Propert tax, Excise and Super-fund taxes are
functionalized to P, T, 0, & R using the "GP" factor. The "GP" factor is different than the
"PTD" factor in that the "GP" includes General and Intangible plant balances in the
calculation.
Income Taxes. Federal: The federal income tax calculations for PTDRM are based on
the functionalized breakdown of revenues and expenses as described above. In addition
to the above expense deductions, Account 427, Interest Expense, is functionalized to
Tab 1 Page 4 of 11
PTDRM using the "GP" factor and deducted from PTDRM revenue. Schedule M Additions
and Deductions are functionalized and netted against PTDRM operating revenues to arrive
at total taxable income before state income tax.
Schedule M items that can be specifically identified with P, T, D or R are so assigned.
Those items that are salary or benefit related are functionalized using the "LABOR" factor.
Items associated with bond refinancing are functionalized using the "PTD" factor. The
reversal of book deprecation is functionalized according to book depreciation.
Income Taxes. State: Account 409.11. The total income before state taxes is calculated
for PTDRM in the same manner as done for Federal income taxes. This amount is
multiplied by the composite state tax rate to arrive at functionalized state income taxes for
each function.
Income Taxes Deferred - Net: Accounts 410 & 411. The Tax Department determines
whether the plant deferred income taxes are production, transmission, distribution or
general plant related. These items are functionalized into PTDRM accordingly, using the
"DITEXP" factor. Deferred taxes associated with employee benefits are functionalized
using the "LABOR" factor. Items associated with propert taxes are functionalized using
the "GP" factor. Items that can be directly associated with a function are directly
functionalized using "P" or "PT" factors.
Investment Tax Credit Adjustment: Accounts 411.40 & 411.41. The Federal deferred
investment tax credit was functionalized on the "PTD" factor.
Miscellaneous Revenue & Expense: Accounts 411.8, 421 & 431.1. The gains and losses
arising from the sale of utilty propert are identified and assigned to P, T, or D. Emission
allowances are assigned to P. The interest expense associated with customer deposits in
Account 431.1 is assigned to R.
Rate Base:
Electric Plant in Service: Production plant rate base, Accounts 310 - 346, is assigned to
P. Likewise, transmission plant accounts are assigned to 1. Distribution plant accounts
are split between D and R based upon asset utilization.
General and Intangible Plant: General plant rate base accounts, except coal mine plant,
which is assigned to P, are functionalized using functionalization factors. The General
Plant factors were developed using the functional identification in the Business Warehouse
reports of general plant. BW identifies investments by accounting location, as steam,
hydro, transmission, distribution, general office, or the customer service system. The
identified generation items are assigned to P and known transmission items are assigned
to T. General plant items that are assigned situs because they are associated with
distribution propert are assigned to that function. The general office items within the BW
listing were functionalized on the "PTD" factor and those items associated with the
Tab 1 Page 5 of 11
customer service system were functionalized to R. A separate General Plant
functionalization factor was developed to correspond to each PITA allocation factor.
Intangible plant was functionalized in the same manner.
Plant Held for Future Use: BW tracks Account 105 transactions to production,
transmission, general and mining totals. Production and mining are assigned to P, and
transmission to T. The general amount is functionalized using the "G" factor.
Deferred Debits: BW tracks and collects deferred debits that are related to production.
These costs are assigned to P directly. Situs and system overhead debits are
functionalized using the "DEFSG", "00S02" and "DOS06" functionalization factors. These
three factors were developed by generating a detailed listing of BW debits to situs and
system overhead.
Electric Plant Acquisition Adjustments: Account 114. All Electric Plant Acquisition
Adjustments are assigned to P.
Prepayments: Account 165. Situs prepayments for franchise taxes and regulatory
commission fees are assigned to R. Fuel related prepayments are assigned to P.
Propert insurance was functionalized using "PTO". Other prepayments are functionalized
using the "PT" functionalization factor.
Fuel Stock: Account 151 assigned to P.
Materials & Supplies: Accounts 154, 163 & 253.18. Materials and Supplies are
functionalized using the "MSS" factor. This functionalization factor was developed using
FERC form 1 data.
Working Capital: Accounts CWC, 131, 135, 143, 232 & 253. Cash Working Capital is
calculated by subtracting the expense lag days from the revenue lead days and multiplying
this difference times the daily cost of service. The daily cost of service is calculated within
the model by adding 12 months of O&M, Taxes Other than Income, and State and Federal
Income Taxes and dividing by 365. This amount is functionalized using the "cwc" factor.
The "cwc" factor is internally calculated by adding the O&M, Taxes Other than Income,
and State and Federal Income Taxes, for each of the three functions and dividing by the
functional total, (Productionffotal, Transmissionffotal, Oistributionffotal).
Weatherization: Accounts 124, 182, 186. Weatherization loans and other deferred debits
related to conservation and OSM programs are assigned to M.
Other Miscellaneous Rate Base: Accounts 182.22 & 141. Other miscellaneous rate
base includes the deferred debits related to the Trojan Nuclear Plant which are assigned to
P.
Tab i Page 6 of 11
Accumulated Provision for Depreciation & Amortization: Accounts 108 & 111. The
functionalization of the accumulated depreciation matches the functionalization of rate
base.
Accumulated Deferred Income Taxes: Accounts 190, 281-283. The largest component
of accumulated deferred income taxes is due to timing differences between book
depreciation and tax depreciation. This timing difference is functionalized on the
"ACCMDIT" factor. Detail to develop this factor is supplied by the Tax Department. The
percentage for P in the "ACCMDIT" factor, for example, is developed by taking the total of
production items as determined by the Tax Department and dividing it by the total of all
PTDRM items. This includes the accumulated deferred income taxes arising from general
plant which are functionalized using the "Gil factor for the purposes of developing the
"ACCMDIT" factor.
Unamortized Investment Tax Credits: Account 255. The accumulated investment tax
credits are functionalized using the "PTD" factor.
Customer Advances for Construction: Account 252. State situs customer advances for
construction are assigned to D. System allocated advances are assigned to T.
Customer Service Deposits: Account 253. Customer service deposits are assigned to R.
Other Miscellaneous Rate Base Deductions: Account 228. All items are functionalized
using the "PTD" factor.
CLASSIFICATION AND ALLOCATION PROCEDURES
Generation and Transmission Costs
The methodology used in this study for the classification and allocation of generation and
transmission costs are consistent with the MSP Revised Protocol method approved by the
Idaho Commission in Case No. PAC-E-02-3 on February 28, 2005. The MSP Revised
Protocol identifies four categories of Resources: Seasonal Resources, Regional
Resources, State Resources, and System Resources. Fuel costs are classified as 100%
energy related. Production and transmission plant and non-fuel related expenses for all
resources are classified as 75% demand-related and 25% energy-related. The costs of
Seasonal Resources are allocated using seasonal factors because they are designed to
be used more intensively at certain times of the year. All other resources are allocated
using non-seasonal factors.
The non-seasonal energy related costs are allocated using each class' share of annual
MWH (F30).
Demand-related costs of non-seasonal resources are allocated using each class'
contribution to the 12 monthly peaks coincident with the PacifiCorp system firm peak.
Tab 1 Page 7 of 11
Non.,seasonal demand costs are allocated in this manner because capacity is important to
the Company each month for meeting peak loads, load following, and accommodating
plant maintenance. For these reasons, the Company supports the use of all twelve
monthly peak loads in the non-seasonal capacity allocation factor (F12). The energy
portion is allocated using class MWH adjusted for losses to generation level (F30). The
fixed costs composite factor is (F10).
There are three types of Seasonal Resources, simple-cycle combustion turbines, seasonal
contracts and the Cholla Unit IV (adjusted for megawatt hours delivered to and received
from APS). The cost of each type of Seasonal Resource is allocated using a set of
seasonal allocation factors that reflect the monthly portion of the total annual energy
generated by the Seasonal Resource. Prior to summing each class' monthly energy
usage or contribution to the twelve monthly Coincident Peaks, each monthly energy or CP
measurement is weighted by the monthly portion of the total annual energy generated or
delivered to PacifiCorp by the Seasonal Resource. For example, if 30 percent of the
annual generation of a particular Seasonal Resource occurs in July, the monthly
Coincident Peak for July would be weighted by 30 percent in the calculation of the
allocation factor. This, in essence, allocates 30 percent of the demand related cost for that
resource among classes based upon their contribution to the July Coincident Peak and 30
percent of the energy related costs based on each class' July energy usage.
The demand costs associated with seasonal simple cycle combustion turbines, SCCT's,
are allocated on factor (F13) and the energy portion is allocated on (F32). The fixed costs
composite factor for the SCCT's is (F14). The demand costs associated with Seasonal
Contracts are allocated on factor (F17) and the energy portion is allocated on (F37). The
fixed costs composite factor for the Seasonal Contracts is (F18). The demand costs
associated with Cholla iV are allocated on factor (F 15) and the energy costs are allocated
on (F35). Thefixed costs composite factor for the Cholla iV is (F16).
The Embedded Cost Differentials are allocated using the generation fixed costs composite
factor (F1 0).
Transmission plant is classified and allocated using the same methods described for non-
seasonal generation resources.
Distribution Costs
All distribution costs are classified as either demand related or customer related. There
are no significant energy-related costs associated with the distribution system. In this
study only meters and services are considered customer related with all other costs
considered demand related.
To understand how demand-related costs are treated it is first necessary to understand the
concept of diversity. Diversity is the characteristic whereby individual customer peak
demands usually occur at different times. Because of this, a piece of equipment, such as
a power plant or a substation, which is used by many customers, does not need to be
Tab i Page 8 of i i
large enough to meet the sum of the individual customer peak demands (non-coincident or
billng demands). Rather it needs to be just large enough to meet the coincident peak
demand (demand that occurs at the same time) of those customers.
The demand-related costs fall into two subclassifications: those that vary with changes in
overall system load (system costs) and those that are established at the time customers
are connected to the distribution network and seldom vary after that time (facilities costs).
PacifiCorp's distribution system is primarily a set of radial lines extending from substations
connected to the transmission system. As you move through these radial branches, from
the substation to the meter, the number of customers using each piece of equipment
declines and, with that decline, the diversity in the load on each piece of equipment also
declines. While the transition between system costs and facilities costs occurs gradually
over the distribution system, it becomes necessary in a cost study to draw a line between
equipment which is judged to fit best into each of the categories.
Substations and Primary Lines
Distribution substations and primary lines fall into the system costs category. Because
many customers use substations and primary lines, an allocation methodology that
recognizes the diversity of load among the customers is used. Distribution substations and
primary lines are allocated using the weighted monthly coincident distribution peaks (F20).
The coincident distribution peak is the simultaneous combined demand of all distribution
voltage customers at the hour of the distribution system peak. These monthly values are
weighted by the percent of substations that achieve their annual peak in each month of the
year.
Line Transformers
Distribution line transformers are used either by only one or by a small number of
customers. As such, they are considered part of the facilities category. Since the cost
responsibilty for line transformers is incurred at the time a load is added to the system,
that cost responsibilty should be assigned on the basis of individual customer installed
capacity. Assignment of cost based on installed capacity cannot be done directly because
of a lack of detailed property records. As a surrogate for installed capacity, we use the
maximum monthly class NCP estimates from load research data.
Only customers taking service at secondary voltage are allocated distribution line
transformer costs. The allocation factor (F21) is based on the maximum monthly class
NCP. This may be a different month for each class. For classes of customers where
transformers are shared by more than one customer, the NCP is weighted by the
appropriate coincidence factor from the Company's Job Designer's Manual to recognize
the diversity of load at the transformer.
Secondary Lines
Distribution secondary lines operate as an extension of the line transformer. They are also
allocated using the weighted NCP method. Only customer classes where transformers are
shared by more than one customer are allocated the costs of distribution secondary lines.
Tab 1 Page 9 of 11
(F22)
Services and Meters
Services costs are allocated to secondary voltage delivery customers only. The allocation
factor is developed using the installed cost of newly installed services for different types of
customers. (F70)
Meter costs are allocated to all customers. The meter allocation factor is developed using
the installed costs of new metering equipment for diferent types of customers. (F60)
Customer Accounting, Customer Services & Sales
Customer accounting, customer &ervice, and sales expenses are considered customer-
related costs. They are allocated to customers using weighted customer factors. The
weightings reflect the resources required to perform such activities as meter reading,
billng, and collections for different types of customers.
The customer weightings for Meter Reading expenses, Account 902, are determined by
the typical time, including travel time between meters, to read meters for different classes
of customers. (F47)
The customer weighting for Customer Accounting and Records expenses, Account 903, is
a composite of the number of customers, customers receiving manual bills and the amount
of write-offs by customer class. (F48) .
Uncollectible Accounts expense is allocated based on class net write off history. (F80)
Customer service expenses are allocated on number of customers (F40).
General & Intangible Plant, Administrative & General Expenses
Most general plant, intangible plant, and administrative and general expenses are
functionalized and allocated to classes based on generation, transmission, and distribution
plant (F102). Costs that have been identified as supporting customer systems are
considered part of the retail function and are allocated using customer factor (F42).
Regulatory Commission Expense is allocated on Revenue (F141).
Taxes
State and Federal Income Taxes are allocated on Rate Base (F101). An embedded cost
of service study is designed to determine the revenues needed to provide an equal rate of
return for all classes. At full cost of service, allocating income taxes on rate base produces
the same result as allocating on income. This simplifies and reduces the size of the cost
model by eliminating the need to allocate all of the taxable income adjustments.
Deferred Income Taxes are allocated primarily on Net Plant (F1 04). Most deferred taxes
are a result of plant investment. Deferred Income Taxes associated with bad debt are
Tab 1 Page 10 of i i
allocated using customer factors (F42). Deferred Income Taxes associated with employee
benefits are allocated using labor (F138).
Taxes Other Than Income Taxes are allocated on Plant (F101). The bulk of taxes other
than Income Taxes are property taxes. Property Taxes are assessed on plant investment.
Rate Base Additions and Deductions
Additions and deductions that relate to Generation and Transmission plant are allocated
accordingly (F10). Items that are associated with Distribution plant are allocated in a
similar manner (F20). Items directly relating to fuel or coal mining are allocated on energy
(F30). Weatherization investments are allocated on (F40) consistent with customer
service expense. Accumulated Deferred Income Taxes are allocated consistent with
Deferred Income Tax Expense (F104). Customer advances for Construction are allocated
based on recent history for Contributions in Aid of Construction (F50). Where applicable,
Customer Deposits are allocated on recent deposit history (F51). All other additions and
deductions are allocated on Plant (F102).
Revenue Credits
In the class COS study, no costs are assigned to wholesale transactions. The revenue
from these sales is treated as a revenue credit and is allocated to customer groups using
appropriate allocation factors. Other electric revenue is also treated as a revenue credit.
Revenue credits reduce the revenue requirement that is to be collected from firm retail
customers.
Sales for Resale revenue is classified between demand-related (F10) and energy-related
(F30). Other Electric Operating Revenue is assigned as closely as possible to the specific
customer classes providing the revenue.
Tab I Page 11 of 11
REVISED PROTOCOL
Year-End
RESULTS OF OPERATIONS SUMMARY
IDAHO
Decription of Account Summary:~Production Transmission Distribution Distrbuion Retil M!
1 General Business Revenues 202.733.162 146.514.515 15.475,383 40.743,264 33.335.083 6.877,701 530,480
2 Geneia( Business Revenues
3 Interdepartmentai
4 Special Sales 45,289.382 35.157.340 10.132.041
5 Oter Operating Revenues 13.773,492 5.030,209 7,793.040 950,243 358.118 582.852 9,272
6 Total Operating Revenues 261.796.035 186.702.064 33,400.465 41.693.507 33,693.201 7,460,553 539.752
7
8 Operating Expenses:
9 Steam Production 60.406,070 80.406.070
10 Nuclear Production
11 Hyro Prouction 2,133.930 2.133.930
12 Oter Powor SUppl 79.705.661 79.705,661
13 Transmissio 10.588,482 10,588.482
14 Distribution 11,434.564 11,434,564 11.434.564
15 Customer Accounts 4,643.936 4,643.836 4.643,836
16 Customer Seivice 1.847,458 1.647.458 1.647,458
17 Sales
18 Administraive. & General 11.494.297 5.148.744 1.854.049 4,491,505 3,459.072 492.086 540,36
19
20 Total 0 & M Expenses 182,254.199 147.394.305 12,442.531 22,417.363 14.893,636 6.983.380 540.346
21
22 Depreciation 27,477478 14,774.260 5,129.393 7.573,825 7.505,89 68.336
23 Amortizaion Expense 2.100.480 1,452.090 216,525 431.85 227.908 203.957
24 Taxes Other Than Iooome 5.735,330 2,905,243 1,048.546 1,781.541 1.737.634 43,907
25 Income Taxes. Federal (17.477596)(17,706,581)1,361.182 (1.132.197)(824,277)(107.863)(200.057)
26 Income Taxes ~ 8tme (1.952,739)(1.984,243)187.277 (155.773)(113,08)(14.840)(27.525)
27 Incoe Taxes ... Dof Net 25.508.213 19.035.653 3.778,430 2,694,131 2,476,393 217,737
28 Inveslment Tax Credtt Adj.(201.494)(105.54)(39.358)(66.591)(66.591)
29 Mise Revenue & Expense (279,445)(288.001)(11.639)195 195
30
31 Total Operating Expenses 223.164.426 165,497.180 24.112,867 33,554.359 25.846,980 7.394.615 312,765
32
33 Operating Revenue for Return 38.631,609 21.20.884 9,287,578 8.139.148 7.846.221 65.939 226.988
34
35 Rate Base:
36 Elocnc Plant In Service 1.168,782.728 605,807.354 257.120.569 305.854.805 300.196,541 5.658,264
37 Plant Held lor Future Use (0)491.540 (491.540)
38 Mise Deferred Debits 4.174.115 2,66.708 1,246,603 282,804 43.862 (31,228)250,171
39 Eiec Plant Acq Adj 3.352.652 3.352,852
40 Nuclear Fuel
41 Prepayments 2,570.335 1.536,487 402.918 830.930 462.810 4,102 164.017
42 Fuei Siock 12.146,136 12,146.136
43 Material & SuppUes 9.955.906 8.013.002 55.984 1.886.920 1,886,920
44 Working Capttal 3.095.969 1.797.546 489.164 809.257 703,94 101,802 3.961
45 Weatherization loans 3,503.640 3.503.640 3.503.64
46 Miscellaneous Rate Base 123,279 123.279
47
48 Total Eloc~c Plant 1.207,704.959 635,932,906 258.623,698 312.948.355 303.293.627 5.732.940 3.921.788
49
50 Rate Base.Deductions:
51 Accum Proii For Depr (371.661.993)(182,382,22)(68,97.133)(120,802,641)(120.545.282)(257.358)
52 Accum Prov For Amort (21,605.949)(10.370.588)(3.279,395)(7.955,966)(4.383.538)(3,572,428)
53 Accurn Def Income Taxes (140,588,834)(72.377768)(25,525.148)(42.885.918)(41.948,840)(737,079)
54 Unamortized ITC (226,311)(119.593)(44.596)(64,122)(64.122)
55 Customer Adv for Const (97.697)(679,431)(268.26)(266,266)
66 Customer Service Deposits
57 Mise. Rate Base Deductions (5.192.760)(4.314.380)(331,441)(546.939)(520.125)(26.814)
58
59 Total Rate Base Deductions (540.245.54)(269,664,548)(98,357,143)(172.323.853)(167.730.173)(4,593.679)
60
61 Total Rate Base 667,459,415 36.368.358 160,466.555 140.624,503 135,663,454 1.139.261 3,921,788
62
63 Return on Rate Base 5,768%5,788%5,788%5,788%5.786%5.788%5.788%
64
65 Return on Equity 5.669%5.669%5.669%5,669%5,869%5,669%5,669%
66
67 100 Basis Polnls in Equity:3,477._1.908,779 836.031 732.654 706,286 5.936 20.43
68 Revenue Requirement Impact 5.604.383 3,076.245 1,347.372 1.180.766 1.138.271 9.56 32.930
69 Rate Base Decrease (55.120,325 (30,255,537)(13.251.695)(11.613.093)(11.195.140)(94,083)(323.870)
TAB 2 1 of 29
Descripton of Account Summary:
REVISED PROTOCOL
Year~End
FERC BUSINESS PITA
ACCT DESCRIPTION FUNCTION fA
70 Sales to Ultmate Customers
71 440 Residential sales
72 S
73
74
75
76 442 Commercial & Industnal Sales
77 S
78 P SE
79 PT SG
80
81
82
83
84 444 Publc Slreel & Highway Lighling
85 S
86 SO
87
88
89 445 other Saies to Public Authori
90 S
91
92
93
94 448 Inlerdepartmental
95 DPW S
98 GP SO
97
98
99 Total Sales to Ulmate Custmers
100
101
102
103 447 Sales for Resale~Non NPC
104 WSF S
105
108
107 447NPC Sales for ResaleNPC
108 WSF SG
109 WSF SE
110 WSF SG
ILL
112
113 Total Sales for Resale
114
115 449 Provision for Rate Refund
116 WSF S
117 WSF SG
118
119
120
121
122 Tolol S_leslrom Eleetcl1
123 450 Foreited Discounts & Interest
124 CUST S
125 CUST SO
128
127
128 451 Mise Electric Revenue
129 CUST S
130 GP SG
131 GP SO
132
133
134 453 WaterSaies
135 P SG
136
137
138 454 Rent of Electric Propert
139 DPW S
140 T SG
141 T SG
142 GP SO
143
144
145
146
IDAHO
Normalized B!MiseProuctionTransmissionDistributionDistrbution
IDAHO
Noo_lized Proucljon Trasmission DIstrbution Dlslriution Reiail MJ
0 0 0 0 0 0
59.633,386 146.514.515 15.475.383 40.743.264 33.335.083 6,877701 530.480
59.633.386 148,514.515 15,475.383 40.743.264 33.335.083 6,877701 530,480
142,499.255
142.499.255
600.521
600,521
202,733,182 146,514,516 15,475,383 40,743,26 33,335,083 8,877,701 630,480
45.289,382 35.157.340 10.132.041
45,289,382 35.157.340 10,132.041
45.289.382 35.157.340 10,132.041
248,022,643 181,871,866 26,607,424 40,743,264 33,335,083 8,877,701 630,48
411.342 411.342 411,342
411.342 411.342 411.342
170.080 170.08 170.080
331 186 61 104 101 3
170.411 166 61 170.184 101 170,083
670 670
670 670
301.504 301.504 301.504
292.202 292.202
269 269
184.861 92.910 34.068 57.883 56,456 1,427
778.836 92.910 328.539 359.387 357,960 1.427
TAB 2 2 of 29
Descripton of Account Summary:
147 456 Other Elecc Revenue:
148 OMSC 5
149 CUST CN
150 OTHSE SE
151 OTHSO SO
152 OTHSGR SG
153
154
155
156
157 Total Other Electric Revenues
158
159 Total Electric Operating Revenues
160
161 Summary of Revenues by Factor
162 5
163 CN
164 SE
165 SO
166 SG
167 OGP
168 0
169 Total Electric Operating Revenues
170 Miscellaneous Revenues
171 41160 Gain on sala of Utilty Plant. CR
172 OPW 5
173 T SG
174 G SO
175 T SG
176 P SG
177
178
179 41170 Loss on Sale of UtUIt Plant
180 OPW 5
181 T sa
182
183
184 4118 Gain from EmissÎon Allowances
185 P 5
186 P SE
187
188
189 41181 Gain from OisposUlon of NOX Credits
190 P SE
191
192
193 4194 Impact Housing Interest Income
194 P sa
195
196
197 421 (Gain) I Loss on Sale of Utilit Plant
198 OPW 5
199 T SG
200 T SG
201 PTO CN
202 PTO SO
203 P sa
204
205
206 Totl Miseellaneous Revenues
207 Miscellaneous Expees
208 4311 Interest on Customer Deposits
209 CUST 5
210
211 Total Miscellaneous Expenses
212
213 Net Mise Revenue and Expense
214
215 500 Operaion Supision & Engineering
216 P SG
217 P SSGCH
218
219
220 501 Fuel Related.Non NPC
221 P SE
22 P SE
223 P SE
224 P SSECT
225 P SSECH
226
227
IDAHO
Normalized Distribution Retail MiseProductionTransmissionDistrbution----
123 123 123
.
508.944 508.944
9.335 94 35 9,206 57 9,149
11,893.830 4.936,368 6.957.462
12,412,233 4.936.463 7,466,40 9.330 57 9,272
13,773,492 5,030,209 7,793,040 950,243 358,118 582,852 9,272
261,796,035 186,702,064 33,400,485 41.693,507 33,693,201 7,460,553 539,752
203.616.212 146.514.515 15,475.383 41.626.314 33,636,587 7,459;124 530,603
508.944 50._
194,527 93,171 34,163 67.193 56.614 1,429 9.149
57,476.353 40.094.378 17.381.974
261,796.035 186.702.064 33,400,465 41.693.507 33.693.201 7,480.553 539,752
(223.709)(223,709)
(223.709 223.7091
(8.018)(8.018)
(3.756)(3.756)
894 363 135 195 195
(44.655 (44,655)
(55.736)144.292)(11.639)195 195
f279.44)1268,001\111,639\195 195
.
1279,44 1268,001)111,839\195 195
1,147.743 1.147,743
66.277 66.277
1.214.019 1.214.019
710.434 710,434
193.506 193.50
903,941 903.941
TAB 2 30f29
Description of Account Summary:
228 501NPC Fuel Relaed.NPC
229 p SE
230 P SE
231 P SE
232 p SSECT
233 P SSECH
234
235
236 Totel Fuel Related
237
238 502 Steam Expenses
239 p SG
240 p SSGCH
241
242
243 503 Steam From Other Sources-Non-NPC
244 P SE
245
246
247 503NPC Stea From Other Sources-NPC
248 p SE
249
250
251 505 Electric Expenses
252 P SG
253 p SSGCH
254
255
256 506 Misc. Steam Exense
257 p SG
258 P SE
259 p SSGCH
260
261
262 507 Rents
263 p SG
254 P SSGCH
265
266
267 510 Malnt Supervlslon & Engineenng
268 P SG
269 P SSGCH
270
271
272
273
274 511 Maintenance of StNCures
275 P SG
276 P SSGCH
277
278
279 512 Maintenance of Boiler Plant
280 P SG
281 p SSGCH
282
283
284 513 Maintenance of Electric Plant
285 p SG
266 P SSGCH
287
288
289 514 Maintenance of Mise; Steam Plant
290 P SG
291 P SSGCH
292
293
29 Totl Steam Power Generation
295 517 Operation Super & Engineering
296 p SG
297
298
299 518 Nuclear Fuel Expense
300 P SE
301
302
303
304 519 Coolants and Water
305 p SG
306
307
308 520 Steam Expenses
309 p SG
310
311
312
313
314 523 Electnc Expenses
315 p SG
316
IDAHO
Normlized Retail MiseProductinTransmissionDistributionDistribution-----
40,455._40,455._
.
3.256.992 3,256,992
43,712.877 43,712,877 .
44.616.817 44,616.817
1.716.444 1.716,444
277,962 277982
1.994.426 1.994.426
147 147
147 147
214,498 214,498 ,
214,498 214,498
155.407 155,407
62.663 62,663
218,069 218.069
2.408,180 2,408.180
81.869 81.869
2,490.049 2.490.049
24.714 24.714
96 96
24.810 24.810
330.348 330.348
104.202 104.202
434.550 434.550
1,220.020 1,20,020
51.124 51.124
1.271.144 1.271.144
5.156.102 5.156.102
185,170 185.170
5.341.273 5.341,273
1.860,894 1.860,894
22.374 22,374
1.883;269 1.883.269
538,411 538,11
164.588 164,588
702.999 702,999
60.406.070 60.40.070
-
TAB 2 40129
Description of Account Summary:
317
318 524 Misc. Nuclear Expenses
319 P 5G
320
321
322 528 Maintenance Super & Engineering
323 P 5G
324
325
326 529 Maintenance of Structures
327 p 5G
328
329
330 530 Maintenance of Reactor Plant
331 P 5G
332
333
334 531 Maintenance of Electric Plant
335 P 5G
336
337
338 532 Maintenance of Misc Nucear
339 P sa
340
341
342 Totl Nuclear Power Generation
343
34 535 Operation Super & Engineenng
345 P DGP
346 P 5G
347 P 5G
348
349
350
351 536 Watr For Powr
352 P DGP
353 P 5G
354 P 5G
355
356
357
358 537 Hydraulic Expenses
359 P DGP
360 P 5G
361 P 5G
362
363
364
365 538 Electric Expenses
366 P DGP
367 P SG
368 P 5G
369
370
371
372 539 Misc. Hydro Expenses
373 p DGP
374 P 5G
375 P 5G
376
377
378
379
380 540 Rents (Hyro Generation)
381 P DGP
382 P 5G
383 P SG
384
385
386
387 541 Mamt Supervlsiòn & Engineering
388 P DGP
389 P 5G
390 P 5G
391
392
393
394 542 Maintenance of Structures
395 P DGP
396 P 5G
397 P 5G
398
399
400
401
402
403
404 543 Maintenance of Dams & Waterways
405 P DGP
IDAHO
Normalized B!MiseTransmissionDistrbutnDistributionProduction-,
-
455,763 455,763
81,963 81.963
537.726 537.726 ,
15.936 15.936 -
238 238
16,174 16.174
175.850 175,850
19.417 19.417
195.267 196.287
665,239 665.239
321.932 321,932
987,171 987.171
9.907 9.907
165 185
10.072 10.072 .
4.649 4,649
4.649 4.649
80.781 80.781
6,515 6.515
67.29 67.296
TAB 2 50129
Desçription of Account Summary:
406 P SG
407 P SG
408
409
410
411 544 Maintenance of Electric Plant
412 P CGP
413 P SG
414 P SG
415
416
417
418 545 Maintenance of Misc. Hydro Plant
419 P CGP
420 P SG
421 P SG
422
423
424
425 Total Hydraulic Power Generation
426
427 54 Operation Super & E"9lneering
428 P SG
429 P SSGCT
43
431
432 547 Fue~Non.NPC
433 P SE
434 P SSECT
435
436
437 547NPC Fuel.NPC
438 P SE
439 P SSECT
440
441
442 548 Generation Exnse
443 P SG
44 P SSGCT
445
446
447 549 Miscellaneous other
448 P SG
449 P SSGCT
450
451
452
453
454
455 550 Maint Supervsion & Engineering
456 P SG
457 P SSGCT
458
459
460 551 Maint Supervision & Engineering
461 P SG
462
463
464 552 Maintenance of Struures
465 P se
466 P SSGCT
467
468
469 553 Maint of Generation & Electric Plant
470 P SG
471 P SSGCT
472
473
474 554 Mainenance of Misc. other
475 P SG
476 P SSGCT
477
478
479 Total Other Power Generation
480
481
482 555 Purchased Power~Non NPC
483 CMSC S
464
485
486 555NPC Purchased Power~NPC
487 P SG
488 P SE
489 P SSGC
490 P CGP
491
492
493 Total Purchased Power
494
IDAHO
Normalized DiS1ribullon ß!MiscTransmissionDistrbutionProduction---
66,170 66.170
22,907 22,907
,
89,077 89.077
66.617 66.617
18,548 18.548
85,164 85.164
107,132 107,132
34,202 34.202
141.333 141.333
2,133,930 2,133,930
17.523 17.523
17.523 17.523
"
27,929.025 27,929.025 .
981.806 981.806
28,910,831 28,910.831
788,031 788.031
90,169 90.169
878.199 878.199
1.356.734 1,356,734
1,356.734 1.356,73
102,528 102.528
102.528 102.528
.
74.859 74.859
10.651 10.651
85,509 85.50
458.508 458,508
154.896 154.896
613,404 613,404
66,220 66.220
6.780 6.780
73.000 73.00
32,037,728 32,037,728
29.737.717 29.737,717
4.482.201 4,482,201
34.219.918 34.219.918
34.219,918 34.219.918
TAB 2 60129
Description of Account Summary:
495 556 System Control & loa Dispatch
496 P SG
497
498
499
500
501
502 557 Other Expenses
503 P S
504 P SG
505 P SGCT
506 P SE
507 P SSGCT
508 P TROJP
509
510
511
512 Embedde Cost Düerentials
513 Company Owed Hyd. P DGP
514 Company Owed Hyd. P SG
515 Mid.. Contract P MC
516 MId-CContract P SG
517 Exlstlng OF Contracts P S
518 ExistingQF Contracts. P SG
519
520
521
522 Total Oter Power Supply
523
524 TOTAL PRODVCTION EXPENSE
525
526
527 Summary of Production Expense by Factor
528 S
529 SG
530 SE
531 SNPPH
532 TROJP
533 SGCT
534 DGP
535 DEU
536 DEP
537 SNPPS
538 SNPPO
539 DOU
540 MC
541 SSGCT
542 SSECT
543 SSGC
544 SSGCH
545 SSECH
54 Total Production Expense by Factor
547 560 Operaion Supeivision & Engineering
548 T SG
549
550
551
552 561 Load DIspatching
553 T SG
554
555
55 562 Station Expense
557 T SG
558
559
560
561 563 Overhead line Expense
562 T SG
563
56
565
55 564 Underground Line Expense
567 T SG
568
569
570
571 565 Transmls$ion of Electricity by Others-Non NPC
572 T so
573 T SE
574
575
576 565NPC Transmission of Electricity by Others-NPC
577 T SG
578 T SE
579
580
581 Total Transmission Of Electricity by Others
582
583 566 Misc. Transmission Expese
IDAHO
Normlized Retail MiTransmissionDistributionDistributionProduction----
84.948 84.948
84.948 84,948
7.552,748 7,552.748
2.286.84 2.286.84
62,065 62,065 -
9.901,657 9.901.657
3.840.951 3.640.951
(1.06.109)(1.06.109)
2,213.520 2.213.520
1,027.068 1,027.068
(2.354,120)(2,354.120)
3,461.309 3,461,309
47,667,833 47,667,833
142,24,561 142,24,561
8.579.816 8.579.818
55.186,454 55.186,454
73.792,190 73.792.190
62.065 62.065
(1.06.109)(1.06.109)
262.495 282.495
981.806 981,806
1.018,34 1.016.346
3.450.499 3,450,499
142,245.561 142,245.581
346.305 34.305
346.305 346.305
532.174 532.174
532,174 532.174
86.243 85.243
85.243 85.243
13.710 13.710
13.710 13.710
7.459.403 7,459,403
5.891 5.891
7,465.29 7.465.294
7.465,294 7.465.294
TAB 2 7 of 29
Descripton of Account Summary:
584 T SG
585
586
587
588 567 Rents. Transmission
589 T SG
590
591
592
593 566 MaintSupervision & Engineering
584 T SG
595
596
597
598 569 Maintenance of Stnures
599 T SG
600
601
602
603 570 Maintenane of Station Equipment
60 T SG
605
606
607
608 571 Maintenance of Overh LInes
609 T SG
610
611
612
613 572 Maintennce of Underground lines
614 T SG
615
616
617
618 573 Maint of Misc. Transmission Plant
619 T SG
620
621
622
623 TOTAL TRANSMISSION EXPENSE
624
625 Summary of Transmission Expense by Factor
626 SE
627 SG
628 SNPT
, 629 Total Transmission Expense by Factor
630 580 Operation Supervision & Engineering
631 OPW S
632 OPW SNPO
633
634
IDAHO
Normalized Di,'rlbuton Retail MiseProductionTransmissionDistribution---127.840 127,540
127.840 127.540
91,784 91.784 -
91.784 91.784
1,992 1.992
1,992 1.992
229.110 229.110
229.110 229,110
597,899 597.899
597.899 597,899
1,084.449 1.084.49
1.084.449 1,084,449
2,926 2.926
2.926 2.926
10.056 10.056
10.05 10.05
10,588,482 10,588,482
5.891 5.891
10.582.592 10.582.592
-
10.588.482 10.588,482
82.277 82.277 82.277
894.590 894.590 894.590
976,867 976.867 976.867
TAB 2 60f29
Description of Account Summary:
635 581 Load Dispatching
636 DPW S
637 DPW SNPD
638
639
640 582 Station Exense
841 DPW S
642 DPW SNPD
643
844
645 583 Overhead Line Expenses
646 DPW S
847 DPW SNPD
648
849
850 584 Underground Une Expense
851 DPW S
652 DPW SNPD
653
654
655 585 Stret Lighting & Signal Systems
656 DPW S
657 DPW SNPD
658
659
66 586 Meter Expenses
661 DPW S
862 DPW SNPD
863
66
665 587 Customer Installaton Expeses
666 DPW S
667 DPW SNPD
868
869
670 588 Misc. Distribution Expenses
671 DPW S
672 DPW SNPD
673
674
675 589 Rents
878 DPW S
677 DPW SNPD
678
679
680 590 Maint Supeivision & Engineering
681 DPW S
682 DPW SNPD
683
684
685 591 Maintenance of Strctures
686 DPW S
687 DPW SNPD
688
689
690 592 Maintenance of station Equipment
691 DPW S
692 DPW SNPD
693
694 593 Maintenance of Overhead Lines
695 DPW S
698 DPW SNPD
697
698
699 594 Maintenance of Underground Lines
700 DPW S
701 DPW SNPD
702
703
704 598 Maintenance of Line Transformers
705 DPW S
706 DPW SNPD
707
708
709 598 Maint of stre Lighting &.8i9nal Sys.
710 DPW S
711 DPW SNPD
712
713
IDAHO
Normlized Retail MiseProducllonTransmissionDistributionDistrbution-----
645.803 645.803 645.803
845,803 645.803 645.803
212.555 212.555 212,555
1,423 1,423 1,423
213,977 213.977 213.977
313.054 313.054 313.05
849 849 849
313.903 313.903 313,903
9.980 9.980 9.96
9.860 9.960 9.96
26.954 284.954 264.954
51.725 51.725 51,725
316,679 316.679 316.679
465.222 465.222 465.22
24 24 24
465,246 465.246 465.246
73.970 73.970 73970
255,446 255._255._' .
329,418 329,416 329.416
25.767 25.767 25,767
5,271 5.271 5.271
31.038 31.038 31.038 -
91,498 /91,498 91,498
304,219 304,219 304.219
395.718 395,718 395.718 -
146,142 146.142 146,142
7.382 ,7,382 7,382
153,524 153.524 153,524
818.831 816.631 816.631
89.858 89.858 89,858
906,490 908,490 906,490
5.202,206 5,202.208 5.202,206
57,440 57.440 57,40
5.259.848 5.259.64 5.259.646 ,
751,774 751.774 751.774
352 352 352
752,126 752.126 752,126
51.581 51.581 51.581
51.581 51.581 51.581
137.382 137,382 137.382
137.382 137.382 137.382
TAB 2 90f29
Description of Account Summary:
714 597 Maintenance of Meters
715 DPW S
716 DPW SNPD
717
718
719 599 Maint of Misc. Distrbuton Plant
720 DPW S
721 DPW SNPD
722
723
724 TOTAL DISTRIBUTION EXPENSE
725
726
727 Summary of DIstrbution Expense by Factor
728 S
729 SNPD
730 0
731 Total Distribution Expense by Facor
732
733 901 Supervision
734 CUST S
735 CUST CN
736
737
738 902 Meter Reading Expense
739 CUST S
740 CUST CN
741
742
743 903 Customer Receipts & Collecions
744 CUST S
745 CUST CN
746
747
746 904 Uncollectible Accounts
749 CUST S
750 P SG
751 CUST CN
752
753
754 905 Misc. Customer Accoun'ts Expense
755 CUST S
756 CUST CN
757
756
759 TOTAL. CUSTOMER ACCOUNTS EXPENSE
760
761 Summary of Customer Accts Exp by Factor
762 S
763 CN
764 SG
765 Total Customer Accounts Expense by Factor
766
767 907 Supervision
768 CUST S
769 CUST CN
770
771
772 908 Customer Assistance
773 CUST S
774 CUST CN
775
776
777
778
779 909 Informational & Instructional Adv
780 CUST S
781 CUST CN
782
783
784 910 Misc. Customer Service
785 CUST S
786 CUST CN
787
788
789
790 TOTAL CUSTOMER SERVICE EXPENSE
791
792
IDAHO
Nonnallzd &!Distribution MiseTransmissionDistributionProducton-----
307.541 307.541 307.541
52,455 52,455 52.455
359.996 359.996 359.996
85.592 85,592 85.592
29,620 29,620 29.620
115,212 115.212 115.212
11,43,56 11,4,564 11,_,564
8,976.565 8.976,565 8.976,565
2,457.999 2,457,999 2,457,999
11.43,564 11,434.564 11,434.564
15.844 15.84 15.84
99.226 99.22 99.226
115.070 115.070 115,070
1.676.297 1,676.297 1,676.297
71.033 71.033 71.033
1.747,330 1,747.330 1,747.330
340.00 340,002 340.002
1.959,461 1.959.461 1.959.461
2,299.463 2.299.463 2,299.46
471.222 471,22 471.222
1.041 1,041 1.041
472,263 472,26 472.263
9.710 9.710 9.710
9,710 9.710 9.710
4,64,836 4,643,836 4,64,836
2.503,366 2,503.36 2.503.366
2,140,470 2.140,470 2,140,470
4,53.836 4.643,836 4.643.836
11.523 11,523 11.523
11,523 11.523 11.523
1.535.252 1.538.252 1.538.252
115,571 115.571 115,571
1.653,823 1.653.823 1.653.823
176.275 176,275 176.275
176.275 176,275 176.275
5.837 5.837 5.837
5.837 5,837 5.837
1,847,468 1,847,458 1,847,468 .
TAB 2 10 of 29
Description of Account Summary:
793 Summary of Customer Service Ex by Factor
794 S
795 CN
796 0
797 Total Customer Service Expense by Factor
798
799
800 911 Supervision
801 CUST S
802 CUST CN
803
804
805 912 Demonstration & Selling Expense
808 CUST S
807 CUST CN
808
809
810 913 Advertising Expense
811 CUST S
812 CUST CN
813
814
815 916 Misc. Sales Expense
816 CUST S
817 CUST CN
818
819
820 TOTAL SALS EXPENSE
821
822
823 Total Sales Expense by Factor
824 S
825 CN
826 Total Sales Expense by Factor
827
828 Totl Customer 5erviçe Exp Including Sales
829 920 Administrive & General Salanes
830 PTO S
831 CUST CN
832 PTO SO
833
834
835 921 Offce Supplies & expenses
838 PTO S
837 CUST CN
838 PTe SO
839
840
841 922 Offce Supplies & expenses
842 PTe S
843 CUST CN
84 PTO SO
845
846
847 923 Outside Services
848 PTO S
849 CUST CN
850 PTO SO
851
852
853 924 Propert Insurance
854 PTO SO
855
856
857 925 Injuries & Damages
858 PTO SO
859
860
861 926 Employee Pensions & Benefis
862 LAOR S
86 CUST CN
86 LAOR SO
865
886
867 927 Franchise Requiements
868 OMSC S
869 OMSC SO
870
871
872 928 Regulatory Commission Expense
873 OMSC S
874 CUST CN
875 OMSC SO
876 FERC SG
877
878
IOAHO
Normanzed Production Transmission Distribution Distribution Retail Mise-----
1.538.252 1.538,252 1.538,252
309.208 309,208 30,208
1.847,458 1.847,458 1.847,458
,
..
.
1,847,458 ..1,847,458 1,847,458
4,333.380 2.269.888 846.434 1.217.057 1;217.087
4,333.380 2.269.888 846,434 1.217.057 1.217.057
150 79 29 42 42
594,144 311.22 116.054 186.869 186,869
594.294 311.300 116.083 166,911 166.911
(1.325.779 (694.46)(258.963)1372.353\(372.353)
(1,325.779 (694.463)(258.963)1372.353 372.353\
589.245 298.179 111.190 159.876 159.876
589,245 298,179 111.190 159.876 159.876
1.292.532 677.047 252,469 .383.016 383.016
1,292,532 677.047 252,469 383.016 383.016
514.316 269,407 100.461 144.449 144.449
514.318 269.407 100,461 144,49 144.449
.
,
421.783 421,783 421.783
118.563 118,583 118.583
127.989 69.080 58.908
668.335 69.080 58.908 540.346 540.34
TAB 2 11 of 29
Decription of Account Summary:
879 929 Duplicale Charges
880 LABOR S
881 lAOR SO
882
883
884 930 Misc General Expenses
885 PTD S
886 CUST CN
887 lAOR SO
888
889
890 931 Rents
891 PTD S
892 PTD SO
893
894
895 935 Maintenance of General Plant
895 a S
897 CUST CN
898 G SO
899
900
901 TOTAL ADMINISTRATIVE & GEN EXPENSE
902
903 Summar; of A&G Expense by Factor
904 S
905 SO
906 SG
907 CN
906 Tolal A&G Expense by Facor
909
910 TOTAl O&M EXPENSE
911 403SP Steam Depreciation
912 P SG
913 P SG
914 P SG
915 P SSGCH
916
917
918 403NP Nuclear Depreciation
919 P SG
920
921
922 403HP Hydro Depreciation
923 PreMerger Pacifc P SG
924 Pre. Merger utah P SG
925 Post-Merger Pacific P SG
926 Post-Mergr utah P SG
927
928
929 40,30P Other Production Depreciation
930 P SG
931 P SG
932 P SSGCT
933 P SSGCH
934
935
936 403TP Transmission Deprciation
937 T sa
938 T SG
939 T SG
940
941
942
943
94 403 Distribution Depreciation
945 360 Lend & Land Rights DPW S
946 361 Structures DPW S
947 362 51alion Equipment DPW S
948 363 510rage BaUer; Equipm DPW S
949 364 Poles & Towers DPW S
950 365 OH Conductors DPW S
951 366 UG ConduK DPW S
952 367 UG Conductor DPW S
953 368 Line Trans DPW S
954 369 Services DPW S
955 370 Meters DPW S
956 371 Inst Cust Prem DPW S
957 372 Leased Property DPW S
958 373 Street Lighting DPW S
959
950
951 403GP Generai Depreciation
952 G.SITUS S
953 PT SG
96 PT SG
965 P SE
966 CUST CN
967 G-SG SG
958 PTD SO
959 G.SG SSGCT
970 G-SG SSGCH
971
972
973 403GVO Genral Vehicles
IDAHO
Normalized Retail MiseTransmiS$ion Distrbution DIstnbU1lonProuction----
(184,706)(83.051)(12,287)(89.368\(62,08)(27.320)
184,706)(83.051 (12.287)89.368)62,048 (27.320)
209.995 109,999 41,018 58.979 58,979
131 131 131
3,280.122 1,474.867 218.196 1,587.059 ,1.101.885 485.174
3,490,249 1,584,866 259.214 1,648,169 1.160.863 485.305
282,472 147.963 55.175 79,334 79.334
282,472 147.96 55.175 79.334 79.334
1.259,958 298.526 325._636.068 801,967 34.102
1.259,58 298,526 325,_636,068 601,967 34.102
11,494,297 5,148,744 1,854,049 4,491,505 3,459.072 492,086 54,348
631.929 110,08 41.048 480.804 59.021 421.783
10.734.248 4.969.586 1.754.093 4.010,570 3,00.051 491.955 118.563
127.989 69.080 58.90
131 131 131
11.494.297 5.148,744 1.854.049 4,491.505 3,459.072 492.086 54,34
182,254,199 147,394,305 12,442,531 22,417,363 14,893,636 6,983,380 54,346
1.273,014 1.273.014
1,430.177 1.430.177
3,738.631 3,738.631
424.242 424,242
6.866.06 6,866,064
-
200.808 200.808
55.993 55,993
429.229 429,229
189.561 189.561
875.592 875.592
6.876 6.876
6.256.872 6.256.872
138.148 138.148
6,401.895 6,401,895 ,
620,299 620.299
692.68 692.68
3.331.980 3.331.980
4,644.945 4.64.945
17.488 17.488 17.488
23.007 23.007 23.007
615.415 615,15 615.415
2.021.595 2.021,595 2.021,595
956,832 956.832 956,832
157,652 157.652 157.652
473.640 473,640 473.640
1,417.559 1,417.559 1,417.559
517,488 517.488 517,468
446,676 446.676 446,676
7,570 7,570 7.570
-
28.954 28.964 28.954
6.683.857 6.683.857 6,683,857
755,082 182,147 592.915 592.915
27,662 20.148 7.513
38.898 28.333 10,565
1,668 1,668
68.336 68.336 68.336
290.938 149.764 141.173
814.358 426,573 159.068 228.718 228.718
326 168 158
7.879 4.056 3.823
2.005.125 630.709 484.447 889,959 821,633 68.336
TAB 2 12 of 29
Description of Account Summarj:
974 G-SG SG
975
976
977 403MP Mining Depreciation
976 P SE
979
980
981 403EP Experimental Plant Depreciation
982 P SG
983 P SG
984
985 4031 ARO Depreciation
986 P S
987
988
989
990 TOTAL DEPRECIATION EXPENSE
991 Summaiy of Amorization Expense by Factor
992 S
993 DGP
994 OGU
995 SG
996 SO
997 CN
998 SE
999 SSGCH
1000 SSGCT
1001 Total Depreciation Expense By Factoi
1002
1003 404GP Amort of L T Plant ~ Capital Lease Geo
1004 I-SITUS S
1005 I-SG SG
1006 PTO SO
1007 P SG
1006 CUST CN
1009 P SG
1010
1011
1012 404SP Amort of L TPlant . Cap Lease Steam
1013 P SG
1014 P SG
1015
1016
1017 4041P Amort of L T Plant - Intangible Plant
1018 I-SITUS 5
1019 P SE
1020 I-SG SG
1021 PTD SO
1022 CUST CN
1023 I-SG SG
1024 ~SG SG
1025 P SG
102 I-SG SSGCT
1027 I-SG SSGCH
1028 P SG
1029
1030
1031 404MP Amort of L T Plant - Mining Plant
1032 P SE
1033
1034
1035 4040P Amort of L T Plant. Other Plant
1036 P SG
1037
1038
1039
1040 404HP Amortization of other Electrtc Plant
1041 PreMerger Pacific P SG
1042 PreMerger Utah P SG
1043 Post-Merger Plant P SG
1044
1045
1046 Total Amrtization of Limited Term Plant
1047
1048
1049 405 Amortization of Other Electric Plant
1050 GP 5
1051
1052
1053
IDAHO
Normalized Distribution B!M!Production Transmission Distrbution---
-
27,477,478 14,774,280 5,129,393 7,573,825 7,505,489 88,338
7,438.918 162,147 7.276.772 7.276,772
18,583.603 13.779._4,804,197 -
814,358 426,573 159.068 226.718 228,718
68,336 68,336 68.336
1.668 1.688
432.121 428,298 3.823
138,474 138.316 158
27,477,478 14,774.260 5,129.393 7,573.825 7.505,89 68,336
50.114 26,250 9,789 14.075 14.075
9.895 9,695 9,696
59,809 26,250 9,789 23,770 14.075 9,695
20,532 807 7.437 12,288 12.288
922 922
518.532 473.999 44,533
717.611 375.895 140.170 201,55 201,945
194,262 194.262 194,282
149.856 136.986 12.870
17.100 15,632 1.469
2,993 2,736 257
923 923
1.622.731 1.007,899 206.736 406.096 213.834 194,262
363 363
2.225 2.225
2.588 2.588
1,685,127 1.036.737 216.525 431.866 227.908 203,957
TAB 2 13 of 29
Description of Account Summary:
1054 406 Amortizion of Plant Acquisition Adj
1055 P 5
1056 P SG
1057 P SG
1058 P SG
1059 P SO
1060
1061 407 Amort of Prop Losses, Unr:c Plant, etc
1062 DPW S
1063 GP SO
1064 P SG-P
1065 P SE
106 P SG
1067 P TROJP
1068
1069
1070 TOTAL AMORTIZTION EXPENSE
1071
1072
1073
1074 Summary of Amortization Expense by Factor
1075 S
1076 SE
1077 TROJP
1078 DGP
1079 DGU
1080 SO
1081 SSGCT
1082 SSGCH
1083 SG.p
1064 CN
1085 SG
1086 Total Amortization Expense by Factor
1087 408 Taxes other Than Income
1088 DMSC 5
1089 GP GPS
1090 GP SO
1091 P SE
1092 P SG
1093 DMSC OPRV-ID
1094 GP EXCTAX
1095 GP SG
1096
1097
1098
1099
1100
1101
1102 41140 Deferrd Investment Tax Credit. Fed
1103 PTD DGU
1104
1105
1106
1107 41141 Deferrd Investment Tax Cred" - Idaho
1108 PTD DGU
1109
1110
1111
1112 TOTAL DEFERRED ITC
1113
1114
1115 427 Interest on Long-Term Debt
1116 GP 5
1117 GP SNP
1118
1119
1120 428 Amortization of Debt Disc & Exp
1121 GP SNP
1122
1123
1124 429 Amortization of Premium on Debt
1125 GP SNP
1126
1127
1128 431 Other 'nteret Exense
1129 NUTIL OTH
1130 GP SO
1131 GP SNP
1132
1133
1134 432 AFUDC ~ Borrowed
1135 GP SNP
1136
1137
1138 Totl Electric Interest Deductions for Tax
1139
IDAHO
Normalized Retail MiseProductionTransmissionDistributionDistrbytlon---
301.830 301.830
301.830 301,830
0 0
113,523 113.523
113,523 113.523
2,100,480 1,452,090 216,525 431,866 227,908 203,9S7
20.532 807 7.437 12.288 12,288
922 922
113.523 113.523
767,724 402.145 149.959 215.620 215.620
2.993 2.736 257
0 0
203.957 203.957 203,957
990.829 931,957 58.872
2.100,480 1,452.090 216.525 431,866 227.908 203.957
5.122.338 2.574.467 943,985 1,603,886 1,564.357 39,529
567.377 285.162 104.561 177,655 173277 4,378
45.615 45.615
-
5.735.330 2,905.243 1,048,546 1.781,541 1.737.634 43.907
(201,494)(105.546)(39,358)(56,591)(56,591)
(201.494)(105.54 (39.358 (1;6.591\(56.5911
(201,494)1105.54)13.358)/56.591)156.591\
177,481 89.201 32,708 55,572 54.203 1.370
19.605,532 9,853.563 3,613.064 6,138.805 5,987,512 151,294
19.783.014 9.942.86 3.645.772 6,194.378 6,041.714 152.663
348,923 175.367 64.302 109.253 106,561 2.693
348.923 175.367 64.302 109.253 106,561 2.693
(144)(73)(27\(45\144\(1)
(144)(73)27)(45 (44\1)
544.999 273,914 100,437 170,648 156,42 4.206
54.999 273914 100.437 170.648 156,42 4,206
/1,868.319 /939.009)/344.309\(585.000\(570.563)(14,418).
0.868.319 939009)134,309 1585.000)(570.583)14,418\
18.808,472 9,453.06 3.46.176 5.889.233 5.744,090 145.143
TAB 2 14 of 29
1140
1141
1142
1143
1144
1145
1146
1147
1148
1149
1150
1151
1152
1153
1154
1155
1156
1157
1158
1159
1160
1161
1162
1163
1164
1165
1166
1167
1168
1189
1170
1171
1172
1173
1174
1175
1176
1177
1178
1179
1180
1181
1182
1183
1164
1185
1186
1187
1188
1189
1190
1191
1192
1193
1194
1195
1196
1197
1198
1199
1200
1201
1202
1203
1204
1205
1206
1207
1208
1209
1210
1211
1212
1213
1214
1215
1216
1217
1218
1219
1220
1221
1222
1223
1224
1225
122
1227
1228
1229
Description of Account Summary:
Non-utility Ponion of Interest
427 NUTIL
428 NUTIL
429 NUTIL
431 NUTIL
Totl Non.utlilly Interest
Total Interest Deducts lor Tax
419 Interest & Dividends
GP
GP
Total Operating ~Oedu¡ons for Tax
41010 Deferrd Income Tax - Federal-DR
GP
P
P
LAOR
GP
P
PT
GP
TAXDEPR
CUST
CUST
P
DPW
41110 Delerrd Income Tax - Fecieral-CR
GP
P
P
GP
PT
DPW
LABOR
PT
CUST
P
BOOKDEPR
P
P
TOTAL DEFERRED INCOME TAXES
SCHMAF Addllion. - Flow Through
SCHMA
SCHM
SCHMA
SCHMAF
SCHMA
SCHMAF
SCHMAddiiions . Permanent
P
P
LAOR
SCHMA-SO
SCHMAP
DPW
SCHMAT Addllions - Temporary
SCHMT-SITUS
P
DPW
SCHMAT.SNP
P
P
SCHMAT.SE
P
CUST
SCHMAT.SO
SCHMAT-SNP
DPW
P
BOOKDEPR
TOTAL SCHEDULE. M ADDITIONS
NUTIL
NUTIL
NUTIL
NUTL
S
SNP
S
TROJD
SSGCH
SO
SNP
SE
SG
GPS
TAXDEPR
BAODEBT
eN
IBT
SNPD
S
SE
SSGCH
SNP
SG
CIAC
SO
SNPD
CN
SGCT
SCHMDEXP
TROJD
IBT
S
SNP
SO
SE
TROJP
SG
S
SE
SNP
SO
SG
BADEBT
S
SSGCH
CIAC
SNP
TROJD
SGCT
SE
sa
CN
SO
SNPD
BAODEBT
SSGCT
SCHMDEXP
IDAHO
Nonnalized Production Transmission Distribution Distributon Retail Mise------
18.808,472 9,453.06 3.466,176 5,889.233 5.744,090 145,143
(3.235.657)(1.626.229)(596.293)(1.013.136)(968.187)(24,969)
(3,25,657)(1.626.229)1596.293)11.013.136\(988.167)(24.969)
79,985 40.200 14,740 25.045 24,427 617
41.853 41.653
1,424 1,424
1,763.097 792,755 117.282 853,059 592.273 260.786
1,903.525 956.704 350,797 596,024 581.335 14.689
1,418.425 1.418.425
5,751,445 4.189,277 1.562,168
1,685.955 847.35 310,701 527,899 514,889 13.010
31,202.974 20,454.706 4.011.266 6.737.00 6.538,815 198.187
17.196 17.196 17.196
889 889 889
3.136 3,136 3.136
43.869.704 28.742,499 6.36.955 8,760.251 8,254.876 505.375
(871.511)(438.018)(160,609)(272,884)(266.159)(6,725)
(916,114)(916,114)
(29.335)(29.335)
(1.678.779)(843,748)(309,379)(525.653)(512,698)(12.955)
(1.536.044)(1.118.835)(417.210)
(938.106)(938.106)(938,108)
(1.526.257 (686,263)(101.528)(738,66)(512,712)(225.754)
(89.932)(65,505)(24.427)
(19,698)(19,698)
(10,680,292)(5.513.910)(1.575,373)(3,591.010)(3,548.806)(42,203)
(75,422)(75.422)
(18.361,491 9,706,846 2.588.525 16.068,120\(5.778.482 (287.637)
25.506.213 19.035.653 3,778,430 2.694.131 2.476,393 217.737
5,777 5.777
677,705 308.143 52.163 317.398 225.940 91.458
683.482 313.921 52.163 317.398 225.940 91,458
112.388 91.931 1.820 18.637 12.654 2,671 3,312
2,471.892 2,471.892 2,471.892
4,423,544 2.243.188 821,586 1.358,771 1.357,630 1.141
88,981 88.981
51,903 51.903
1.719,035 1,719.035
4.047.441 4,047.441
1.261.777 567.343 83.934 610,500 423.86 186.634
236,968 120.167 44.012 72.789 72.728 61
28,142,321 14.529.023 4.151,071 9.462.227 9.351,022 111.204
42.556.249 23,459.011 5.102.424 13.994.815 13,689.791 301.712 3,312
43,239.731 23.772.931 5.154.587 14,312.213 13.915.731 393.170 3.312
TAB 2 15 of 29
1230
1231
1232
1233
123
1235
1236
1237
1238
1239
1240
1241
1242
1243
1244
1245
1246
1247
1248
1249
1250
1251
1252
1253
1254
1255
1256
1257
1258
1259
1260
1261
1262
1263
1284
1265
1286
1267
1268
1269
1270
1271
1272
1273
1274
1275
1276
1277
1278
1279
1280
1281
1282
1283
1284
1285
1286
1287
1288
1289
1290
1291
1292
1293
1294
1295
1296
1297
1298
1299
1300
1301
1302
1303
1304
1305
1306
1307
1308
1309
1310
1311
1312
1313
1314
1315
1316
1317
1318
1319
1320
Description of Account Summary:
5CHMDF Deuctions. Flow Through5CHMDF 5
5CHMDF DGP
5CHMDF DGU
SCHMDP Deductions ~ Permanent 5CHMDP 5P 5EPTD 5NP
5CHMDP IBTP 5G
5CHMDP-SO 50
SCHMDT Deductions. Temporary
GP
DPW
5CHMDT-5NP
5CHMDT
P
CU5T
P
SCHMDT.5G
5CHMDT-GP5
SCHMDT-50
TAXPR
DPW
TOTAL SCHEDULE. M DEDUCTIONS
TOTAL SCHEDULE - M ADJUSTMENTS
5
SADEBT
5NP
CN
55GCH
DGP
SE
SG
GP5
50
TAXOEPR
5NPD
IDAHO
Normalized Retail MiseProductonTransmissionDistñbutionDlstnbution-----
-
53,460 53,60
20.234 10.599 3,952 5.683 5.683
1.421.863 839.233 94.570 687,859 ~ 477.576 210,283
1,495.356 703.292 98.522 693,52 483,259 210.283
156.43 78.623 28,829 48.982 47.775 1.207
45.310 45.310 45,310
5.015.745 2.544,275 931.826 1.539.64 1.539,644
2,343 1,564 283 496 460 15 22
3,751 3,751
3.042,613 3,042.613
15.154.923 14,953.56 201.357
4.442,451 2.252,291 824.942 1.365.218 1.363.20 1.948
1,558.915 56,665 128.094 862.156 239.026 21.318 601,812
82,219,108 53.897.674 10.569.592 17.751.943 17,229.624 522.218
8.264 8.264 8,26
111.649.859 77343.024 12.694.922 21.621.913 20,473.374 546.706 601,833
113.145,215 78.04.316 12.783,44 22.315,455 20,956.633 758,969 601.833
(69.905.484)(54,273.385)(7.628.857)(8.003,242\17.040.901)(33.819)(598.522\
NOTE: Posiive Schedule M amount incrase taxable income and therefore redu~ tax expense.
Negative SChele M amounts decrease taxable Income and therefore increase tax expense
40911 51ate Income Taxes
IBT
IBT
Renewble Energy Credits P
IBT
TOTAL STATE TAXES
Calculaion' of Taxable Income:
Oprating Revenues
Operaing Deductions:
o & M Expense$
Depreciation Expense
Amortization Expense
Taxes other Than Income
Interest & Diidends (AFUDC.Equijy)
Mise Revenue & Exense
Total Operaing Deductions
Other Deductions:
Interest Deductions
Interest on PCRBS
Schedule M Adjustments
Income Befor Staté Taxes
State Income Taxes
Totl Taxable Income
Tax Rete
Federal Income Tax - Calculated
Adjustments to Calculated Tax:40910 PMI P SE
40910 Reneble Energy Credits P SG40910 P 504010 LABOR 5
Federal Income Tax
TOTAL OPERATING EXPENSES
310 Lend and Lend Rights
P
P
P
P
P
311 Structures and Improvements
P
P
P
P
IBT
SE
SG
18T
5G
SG
5G
S
S5GCH
(1.882.266)(1.913.771)187.277 (155,773)(113,08)(14.840)(27.525)
(70.472)(70.472)
(1.952.739)11,984,243)187,277 155.773'(113,08)(14.840)(27.525
261.796,035 186.702.06 33,400.465 41,693.507 33.693,201 7,460,553 539.752
182,254.199 147.394,305 12.442.531 22.417.363 14.893.636 6.983.380 540.346
27,477.478 14,774,260 5.129.393 7.573.825 7.505.489 88.336
2.100,480 1,452,090 216.525 431.86 227.908 203,957
5.735.330 2,905,243 1.048.54 1,781,541 1,737.634 43,907
(3.235.657)(1,626.229)(596.293)(1.013,136)(988.167)(24,969)
(279.445)(268.001\(11.6391 195 195 .
214.052.385 184,631,669 18,229.083 ,31,191.653 23,376.696 7.274.611 540.346
18',808.472 9.463.06 3.496,176 5,889,233 5,744,090 145.143
(69.905,484)(54,273.385)(7,628.857)(8.003.242)(7,040.901)(363,819)(598.522)
(40.970,306)(41,656.054)4.076.369 (3,390.621)(2.458.486)(323,020)(599,116)
(1.952.739 11,984,243\187,277 1155.773\'113,408'(14,840\(27.525\
(39.017.567)139,671,810)3.889.092 (3.234.849\(2,355.078)(308.179)(571.591\
36.00%35.00%35.00 35.00%35.00%35.00%35.00%
(13.656.149)(13.885.134)1,361,182 (1.132.197)(824.277)(107.863)(200.057)
(3.821.447)(3.821.447)
(17.477596)(17,706.581)1.361.182 (1,132.191)~(824,277)1 (107,863)1 200.057l1
223,164,426 165,497,180 24,112,887 33,554,359 40,740,616 14,377995 853,111
128.321 128,321
1.916.872 1.916,872
3.101,474 3.101,474
133,401 133.401
5.280.068 5.280.068
12,895.802 12,895.802
17.904.655 17.904.855
12.216.241 12.216,241
3.126,866 3.126.86
46.143.564 46.143.56
5G
5G
SG
SSGCH
TAB 2 16 of 29
Description of Account.Summary
1321
1322 312 Boller Plant Equipment
1323 P SG
1324 P SG
1325 P SO
132 P SSGCH
1327
1328
1329 314 Turbogenerator Units
1330 P SG
1331 P SG
1332 P SG
1333 P SSGCH
1334
1335
1336 315 Aceessoiy Elete Equipment
1337 P SG
1338 P SO
1339 P SG
1340 P SSGCH
1341
1342
1343
1344
1345 316 Mise Power Plant Equipment
1346 P SG
1347 P SG
1348 P SG
1349 P SSGCH
1350
1351
1352 317 Steam Plant ARO
1353 P S
1354
1355
1356 SP Unclassifed Steem Plant. Accunt 300
1357 P SG
1358
1359
1360
1361 Total Stem Producton Plant
1362
1363
1364 Summaiy of Steam Prductin Plant by Factor.
1365 S
136 DGP
1367 DGU
1368 SG
1369 SSGCH
1370 Total Steam Production Plant by Factor
1371 320 Lend and Land Rights
1372 P SG
1373 P SG
1374
1375
1376 321 Structures and tmproiiements
1377 P SG
1378 P SO
1379
1380
1381 322 Reactor Plant Equipment
1382 P SG
1383 P SG
1384
1385
138 323 Turbogenerator Units
1387 P SG
1388 P SG
1389
1390
1391 324 Lend end Land Rights
1392 P SG
1393 P SG
1394
1395
1396 325 Misc. Power Plant Equipment
1397 P SG
1398 P SG
1399
1400
1401
1402 NP Unclasslfted Nuclear Plant. Acct 300
1403 P SG
1404
1405
1406
1407 Total Nuclear Production Plant
1408
1409
1410
IDAHO
Normlized Retail MiseTransmissionDlslnbuiionDistributionProducton----
38,459,343 38.459.343
36,280.338 36.280.338
112.924.281 112.924.281
17.731.858 17.731.858
205.395.820 205,395.820
7,665.023 7,585,023
7,821.308 7.821.308
26.877,209 26,877,209
3.472.805 3.472.805 .
45,836,344 45.836.34
4.833.135 4.833.135
7.638.882 7.638.882
4,081.783 4.081.783
3.615.432 3.615.432 .
20,169.232 20.169.232 ~ .'~
263.683 263,683
288.925 268,925
832,322 832.322
22,012 220.012
1,604,943 1.604.943
, -
43.369 43.369
43,369 43.369
324,473,340 324,473,340 ,
296.172._296.172._
28.300.374 28.300.374
324,473.340 324,473.340
"
TAB 2 17 of 29
Description of Account Summary:
1411 Summary of Nuclear Production Plant by Factor
1412 DGP
1413 DGU
1414 SG
1415
1416 Total Nuclear Plant by Factr
1417
1418 330 Land and Land RighI.
1419 Pre. Merger Pacific P SG
1420 PreMerger Uth P SG
1421 Post.Merger Pacific P SG
1422 PosL-Merger Utah P SG
1423
1424
1425 331 Strctures and Improvements
1426 PreMerer Pacific P SG
1427 Pre-Merger Utah P SG
1428 Post-Merger Pacifc P SG
1429 Post-Merger UIah P SG
1430
1431
1432 332 Reservoirs. Dams & Waterws
1433 PreMerger Pacifi P SG
1434 PreMergr Utah P SG
1435 Post-Merger Pacifc P SG
1436 PosL-Mergr Utah P SG
1437
1438
1439 333 Water Wheel. Turbines, & Generators
1440 Pre-Merger Pacific P SG
1441 Pre~Merger utah P SG
1442 Post~Merger Pacific P SG
1443 Post-Merger Utah P SG
1444
1445
1448 334 Accessor Elecric Equipment
1447 Pre-Merer Pacific P SG
1448 PreMerger UIah P SG
1449 Post-Merger Pacific P SG
1450 Post.Merger Utah P SG
1451
1452
1453
1454
1455 335 Misc. Powr Plant Equipmnt
1456 Preerg Pacific P SG
1457 Pre-Merger Utah P SG
1458 Post.Merger Pacific P SG
1459 PosL.Merger Utah P SG
1480
1481
1462 336 Roads. Railroads & Bridges
1463 PreMerger Pacific P SG
1464 Pre.Merger Utah P SG
1465 Post. Merger Pacific P SG
146 PosL-Mergr Utah P SG
1467
1466
1469 337 Hydro PlanL ARO
1470 P S
1471
1472
1473 HP Unclsifed Hydro Plant. Acct 300
1474 PreMerger Pacifc P S
1475 Pre-Merger Utah P SG
1476 Post.Merger Pacific P SG
1477 P SG
1476
1479
1460 Total Hydraulic Plant
1461
1482 Summary of Hydraulic Piant by Factor
1483 S
1484 SG
1485 DGP
1486 DGU
1487 ToLal Hyraulic Plant by Factor
1466
1489 340 Land and Land Rights
1490 P SG
1491 P SG
1492 P SSGCT
1493
1494
1495 341 Stctures and Improvements
1496 P SG
1497 P SG
1498 P SSGCT
1499
150
IDAHO
Nonnllzed Dlsttlbut°n Retail MJProductionTransmissionDistrbution--
585,06 565,064
290.299 290.299
200.618 200,618
37.065 37.06
1.113,246 1.113,246 .
1,171,611 1.171.811 "
291,908 291.908
3.84t.630 3,841.530
439,809 439.60
5.745,059 5.745.059
8.334.17 8,334,171
1.110.343 1.110,343
6,177,391 6.177.391
2,04.102 2,044,102
17,68.007 17.666,007
1.757.978 1.757.978
486.337 486.337
2.394,117 2,394.117
1.500,22 1.500.22
6.138.684 6.138.654
244.078 244.078
202.181 202,161
2,413.860 2,413,860
392.98 392,98
3.252.865 3.252,865
65,947 65,947
10.257 10.257
54.886 54.686
625 625 ..
131.715 131.715
254,496 254.496
45,662 45.662
540.787 540.787
37.587 37.567 ,
878,531 878.531
34,926.077 34,926.077
34.926.077 34.926.077
34,926.077 34.926.077 .
1,295,417 1,295,417
.
1.295.417 1.295,417
8.320,252 8.32.252
9,007 9.007
230.282 230.262
8.559,541 8,559.541
TAB 2 180129
Description of Account Summary:
1501 342 Fuel Holders, Producers & Accessories
1502 P SG
1503 P SG
150 P SSGCT
1505
1506
1507 343 Prime Movers
1508 P S
1509 P SG
1510 P SG
1511 P SSGCT
1512
1513
1514 344 Generaors
1515 P S
1516 P SG
1517 P SG
1518 P SSGCT
1519
1520
1521 345 Acessory Electric Plant
1522 P SG
1523 P SG
1524 P SSGCT
1525
1526
1527
1528
1529 346 Misc. Powr Plant Equipment
1530 P SG
1531 P SG
1532
1533
1534 347 other ProduciQn ARO
1'35 P S
1536
1537
1538 OP Unclassifed Other Prod Plant-Açct 300
1539 P S
1540 P SG
1541
1542
1543 Total Olher Production Plant
1544
1545 Summary of Other ProducUon Plant by Factor
1546 S
1547 DGU
1548 SG
1549 SSGCT
1550 TQ\1 Qf other PrductiQn Plant by FactQr
1551
1552 Experimental Plant
1553 103 Experimental Plant
1554 P SG
1555 TQtal Experimentl Plant
1556
1557 TOTAL PRODUCTION PLANT
1558 350 Land and Land Rights
1559 T SG
1560 T SG
1561 T SG
1562
1563
156 352 Structures and Improvements
1565 T S
1566 T SG
1567 T SG
1568 T SG
1569
1570
1571 353 Station Equipment
1572 T SG
1573 T SG
1574 T SG
1575
1576
1577 354 Towers and Fixtures
1576 T SG
1579 T SG
1560 T SG
1581
1582
1563 355 Poles and Fixtures
1564 T SG
1565 T SG
1566 T SG
1567
1568
1569 356 Clearing and Grading
1590 T SG
1591 T SG
1592 T SG
1593
IDAHO
NQrrallzd Pnlduction Transmission Oistrbutlon Distrbution Retil M!----463,056 463,06
6,664 6,664
123,996 123,996
593.736 593.736
41.560 41,560
136.860,932 136,660,932
2,809.048 2,809.048 ,
139.711,540 139,711,540
18.262.623 16,262.623 .
861.729 661.729
19,124.352 19.124.352
12,496,292 12,496.292
6.626 6.626
158.496 156.496
12.663,416 12,663,416
670.267 670,267
651 651
670.918 670.916 .
182,618,922 ,182,618,922 .
176.435,367 176,435,367
4.183.554 4,183.554
182.618.922 182.618.922
542,018,338 542,018,338 .
1.164.812 1.164,812
2,671.685 2,671,665
1,706,601 1,706.601
5.543.096 5.543,096
426.44 426,446
1.00.205 1.000.205
3,281.829 3;281.829
4.708,481 4.708,461
7.160.255 7.160,255
10.401.443 10.401,443
54.445.140 54.445.140
72.006.838 72.006,838
8.611.037 8.611.037
7.026.769 7.025.769
9,092,472 9.092,472
24,729.278 24,729.278 .
3.649.091 3.649,091
6,466,003 6,466.003
72.635.066 72.635.066
82,770.181 62.770,161
10,66.062 10.666.082
6,641.667 6.641.667
20.936.169 20.936.169
40,44.116 40,444.116
TAB 2 19 of 29
Description of Account Summary
1594
1595 357 Underground Conduit
1596 T SG
1597 T SG
1598 T SG
1599
1600
1601 358 Underground Conductors
1602 T SG
1603 T SG
1604 T SG
1605
1606
1607 359 Roads and Traits
1608 T SG
1609 T SG
1610 T SG
1611
16,12
1613 TP Unclassiled Trans Plat. Acet 300
1614 T SG
1615
1616
1617 TSO Unclassifed Trans Sub Plant. Acct300
1618 T SG
1619
1620
1621 TOTAL TRASMISSION PLAT
1622 Summaiy of Transmission Plant by Factor
1623 DGP
1624 DGU
1625 SG
1626 Total Transmission Plant by Factor
1627 360 Land and Land Rights
1628 DPW S
1629
1630
1631 361 Structures and Imprvements
1632 OPW S
1633
1634
1636 362 Sttion Equipment
1636 DPW 5
1637
1638
1639 363 Storage Batery Equipment
1640 OPW S
1641
1642
1643 36 Poles, T ewers & Fixures
1644 DPW S
1645
1646
1647 365 Overhead Conductors
1648 OPW 5
1649
1650
1651 36 Underground Conduit
1652 DPW 5
1653
1654
1655
1656
1657
1658 367 Underground Conductors
1659 DPW S
1660
1661
1662 368 Line Transformers
1663 DPW 5
166
1665
166 369 services
1667 DPW S
1668
1669
1670 370 Meters
1671 DPW 5
1672
1673
1674 371 Installations on Customers' Premises
1675 DPW S
1676
1677
1678 372 Leased Property
1679 DPW S
1680
1681
1682 373 Street Lls
1683 DPW S
1684
1685
IDAHO
Normalized Retail MiseTransmissionDistrbutonDistributionProduction------
351 351
5.049 5.049
171.524 171,524~176.923 176.923
59.90 59,908
354.867 354.867
414,775 414.775
102.625 102.625
24,266 24.266
504,114 504.114
631,00 631.005
4.657.469 4.657.469
4.657,469 4.657.469
236,082,166 . '236,082,168
236.082.166 236.082.t66
236,082,166 236.082,166
1.336.741 1.336,741 1,336.741
1.336.741 1,336.741 1.336.741
1,493,261 1,493,261 1.493.261
1.493.261 1,493.261 1,493.261
26,632.41 26.632.441 26.632.441
26.632.41 26.632.441 26.632,441
61.007.433 61,007,433 61,007.433
61.007,433 61.007.433 61.007.433
33,923.198 33.923.198 33,923.198
33.923,198 33,923.198 33.923.198
7.373,179 7.373.179 7.373.179
7,373.179 7.373,179 7,373.179
23.678.928 23.678.928 23,678.928
23,678,928 23.678.928 23.678.928
65.926.697 65.926.697 65.926.697
65.926.697 65.926.697 65.926.697
27.888.911 27.888,911 27,888,911
27,668.911 27.668.911 27.888.911
13.821.420 13.821,420 13.821.420
13.821,420 13.821.420 13.821,420
165.115 165.115 165,115
165,115 165.115 165,115
602.135 602.135 602,135
602.135 602.135 602.135
TAB 2 20 of 29
Description of Account Summary:
1686 DP Unclassified Dist Plant - Acc 300
1687 DPW S
1688
1689
1690 DSC Uncassifid Dist Sub Plant - Acct 300
1691 DPW S
1692
1693
1694
1695 TOTAL DISTRBUTION PLANT
1696
1697 Summary of Distribution Plant by Factor
1698 S
1699 0
1700 Toial Distribution Plant by Factor
1701 389 land and Land Righls
1702 G-SITUS S
1703 CUST CN
1704 PT SG
1705 G-SG SG
1706 PTD SO
1707
1708
1709 390 Structures and Imprvements
1710 G.SITUS S
1711 PT SG
1712 PT SG
1713 CUST CN
1714 G-SG SG
1715 PTD SO
1716
1717
1718 391 Offce Furniture & Equipment
1719 G-SITUS S
1720 PT SG
1721 PT SG
1722 CUST CN
1723 G-SG SG
1724 P SE
1725 PTD SO
1726 G-8G SSGCH
1727 G-SG SSGCT
1728
1729
1730 392 Transportation Equipment
1731 G-SITUS S
1732 PTD SO
1733 G-SG SG
1734 CUST CN
1735 PT SG
1736 P SE
1737 PT SG
1738 G-SG SSGCH
1739 PT SSGCT
1740
1741
1742 393 Stores Equipment
1743 G-SITUS S
1744 PT SG
1745 PT SG
1746 PTD SO
1747 G-SG 50
1748 PT SSGCT
1749
1750
1751 394 Tools, Shop & Garage Equipment
1752 G-SITUS S
1753 PT SG
1754 G-SG SG
1755 PTD SO
1756 P SE
1757 PT SG
1758 G-SG SSGCH
1759 G-SG SSGCT
1760
1761
1762 395 laboraory Equipment
1763 G-SITS S
1764 PT SG
1765 PT SG
1766 PTD SO
1767 P SE
1768 G-SG SG
1789 G-SG SSGCH
1770 G-SG SSGCT
1771
1772
1773 396 Power Operated Equipment
1774'G-SITUS S
1775 PT SG
1776 G-SG SG
1777 PTD SO
1778 PT SG
1779 P SE
1780 P SSGCT
IDAHO
Nonnallzed RelilOlslribulion MiseProductonTransmissionDistribution------
924,997 924,997 924.997
924,997 924,997 924.997 -
264774,45 .264,774,458 264.774,458
264.774,458 264,774,458 264,774,458
264.774,458 264,774,458 264,774,458
197.639 42.42 155,197 155,197
43,838 43,838 43,838
18 13 5
68 35 33
301.859 158,118 58.962 84,779 64.779
543,422 158,167 101,442 283.813 239,976 43,838
9.778,324 2,099.857 7,678.467 7.678,467
19,727 14,369 5,356
91,096 66,353 24,743
478,563 478.563 478.583
202,480 104,230 98,251
5,516.977 2,889,874 1,077,625 1,549,478 1.549,478
16,087,167 3,074.826 3,305,834 9,706.507 9,227.945 478,563
928,381 199.366 729,015 729.015
58 42 16
292 212 79 .
337,388 337,388 337,388
263,559 135,671 127,888
6.219 6.219
2.941,516 1,540,809 574,563 826,143 826,143
4,051 2,085 1,966
4,481,463 1,885.039 903,878 1,892,54 1.555.158 337,388
4,922,495 1,057,087 3,865,408 3,865,408
431.204 225.871 84,227 121,106 121.106
950,481 489,273 461,208
46,171 33,630 12,541
25,694 25,694
6,626 4,826 1,800
20,388 10.495 9,893
2,424 1.786 658
8,05,483 791,556 1,627,413 3,986,514 3.986,514
548,582 117.806 430,776 430,778
5,973 4,351 1,622
19,834 14.447 5,387
24,011 12.577 4,690 6,744 6,744
223.764 115,185 108,578
2,930 2,134 796
825.094 148,694 238,880 437,520 437,520
1.742.629 374,223 1.368,406 1.368,406
116,834 85,101 31,734
1,129,201 581,272 547,929
214,977 112,608 41,991 60,378 80,378
452 452
119.882 87,320 32,581
93.508 48,134 45,373
4.881 2,513 2.368
3,422,_917,400 1,076.180 1,428,784 1.428,784
1,272.132 273,185 998.947 998,947
1,136 827 309
732 533 199
280,286 146,818 54,748 78,720 78,720
483 483
349,984 180,159 169,825
13,786 7,096 6,689
761 392 369
1.919.299 336,308 505,324 1,077.667 1,077.667
7,161,622 1,537.931 5,623,692 5.623,692
45,553 33,908 12,64
1.742,505 896.979 845.526
76,065 39.844 14,858 21.363 21.363
91,689 66,785 24,904
4.693 4,693
TAB 2 21 of 29
Description of Account Summary:
17Bl G-sa SSGCH
17B2
17B3 397 Comnicion Equipment
17B4 COM_EO S
17B5 COM_EO sa
17B6 COM_EO sa
17B7 COM_EO SO
17BB COM_EO CN
17B9 COM_EO sa
1790 COM_EO SE
1791 COM_EO ssaCH
1792 COM_EO ssaCT
1793
1794
1795 39B Misc. Equipment
1796 a-SITUS S
1797 PT sa
1798 PT sa
1799 CUST CN
1 BOO PTO SO
lBOl P SE
lB02 a-sa sa
lB03 a-sa ssaCT
1804
lB05
1 BOO 399 Coal Mine
lB07 P SE
lBOB MP Unckassifed Mine Plant P SE
1809
lBl0
lBl1 399L WIOCO Capnal Lease
lB12 P SE
lB13
lB14
lB15 Remove Capital Leases
1816
lB17
181B 1011390 General Capital Leases
1819 a-SITUS S
182 P sa
1821 PTO SO
1822
1823
1824 Remove Capltal Leases
1825
1826
1827 1011346 General Gas Line Capital Leases
182B P sa
1829
1830
lB31 Remove Cap"al Leases
lB32
1833
1834 GP Unclassified Gen Plant - Acet 300
lB35 a-SiTUS S
1836 PTO SO
1837 CUST CN
1838 a-sa sa
lB39 PT sa
1840 PT sa
1841
1842
1843 399a UnClssified aen Plant - Acet 300
1844 a-SiTUS S
1845 PTO SO
1846 G-sa sa
1847 PT SG
1848 PT SG
1849
lB50
1851 TOTAL GENERAL PLANT
1852
1853 Summary of General Plam by Facor
1854 S
1855 OOP
lB56 DaU
1857 sa
1858 SO
1859 SE
1860 CN
1861 DEU
1862 SSGCT
1863 SSaCH
1864 Less Capitl Leases
1865 Total aeneral Plant by Facor
1886 301 Organization
1867 I.SITUS S
186B PTO SO
1869 i-sa SG
1870
tDAHO
Nonnalized Production Transmission Distribution Distributon Retil Mise-----52,794 27.176 25,618
9,175,921 1,069,386 2,461.4BO 5,645.055 5,845,055
5,lB2,399 B75,017 2,113,916 2,193,46 2,121,7BB 71,67B
256,325 44,798 10B,227 112,299 10B,630 3,670
52,6B5 B9,434 216,060 224,191 216,B65 7,326
2,597,217 43B,524 1,059,412 1,099,2BO l,063,35B 35.922
102,610 17,325 41,B55 43,430 42,011 1,419
4,OB7,416 690,136 1,667,269 1,730,011 l,673,47B 56,533
7,2B2 1,229 2,970 3,OB2 2,981 101
57,526 9,713 23,465 24,34B 23,553 798
86 15 35 37 35 1
12.82.547 2,166,192 5,233,211 5,430,144 5,252,699 177445
64,352 13,B19 50,533 50,533
110 BO 30
7,780 7,760 7,780
lB2.08 95,37B 35,56 51.139 51,139
106 106
102.763 52,B99 49,B64
357,176 14B,463 99,2BO 109,432 101,672 7,760
31,187.003 31,lB7,003
31 ,1 B7,003 31,lB7,003
933,7B9 933,7B9
682,B73 357,699 133,385 191.7B9 191,7B9
1,616,663 1,291,488 133.385 191,7B9 191,7B9
(1,616,663 (l,291,45BI (133,385)1191,789)(191.789)
-
.
253,113 132,584 49,440 71,OBB 71,OBB
253.113 132,584 49,440 71,OBB 71OB8
B7,487,051 41,815,618 15,602,362 30,069.072 29,024,078 1,044,993
31.79B,556 B75,017 7,B29,832 23.093.907 23,022,229 71.678
11,347.751 4,726,659 4,554,591 2,066;502 l,99B,973 67,529
13,50,lB2 6,150,707 3,lB9,467 4,162,OO 4,126,OB6 35,922
31,231,932 31,225,B79 2,970 3,062 2,9Bl 101
970,15B 17,325 41,B55 910,97B 42,011 66,957
11,OB3 6,819 4,227 37 35 1
242,053 104,701 113,004 24,34B 23.553 795
(1,616,863 (1,291,4B8)(133.385'(191,7B9\(191,B91
87.487.051 41,B15,61B 15,602,362 30,069,072 29,024,07B 1,04,99
TAB 2 22 of 29
Description of Account Summary:
1871 302 Franchise & Consent
1872 I.SITUS S
1873 I.SG SG
1874 I.SG SG
1875 I.SG SG
1876 P SG
1877 P SG
1878
1879
1880 303 Miscellaneos Intangible Plant
1881 I.SITUS S
1882 I.SG SG
1883 PTO SO
1864 P SE
1885 CUST CN
1888 P SG
1887 P SSCT
1888
1889 303 le.s Non-utility Plant
1890 I.SITUS S
1891
1892 IP Unclassifed Intangible Plant ~ Acct 300
1893 I.SITUS S
1894 I.SG SG
1695 P SG
1896 PTO SO
1897
1898
1899 TOTAL INTANGIBLE PLANT
1900
1901 Summary of Intaible Plant by FaClor
1902 S
1903 DGP
1904 OGU
1905 SG
1906 SO
1907 CN
1908 SSGCT
1909 SSGCH
1910 SE
1911 Total Intangible Plant by Factor
1912 Summary of Unclassifid Plant (Account 106)
1913 DP
1914 OSO
1915 GP
1916 HP
1917 NP
1918 OP
1919 TP
1920 TSO
1921 IP
1922 MP
1923 SP
1924 Total Unciassified Plant by Factor
1925
1926 TOTAL ELECTRIC PLANT IN SERVICE
1927 Summary of Elec1ri Plant by Factor
1928 S
1929 SE
1930 DGU
1931 DGP
1932 SG
1933 SO
1934 CN
1935 OEU
193 SSGCH
1937 SSGCT
1938 Less Capital Leases
1939
1940 105 Piant Held For Futre Use
1941 OPW S
1942 P SG
1943 T SG
1944 P SG
1945 P SE
1946 G SG
1947
1948
1949
1950
1951 114 Electc Plant Acquisition Adjustments
1952 P S
1953 P SG
1954 P SG
1955
1956
1957 115 Accurn Provision for Asset Acquisition Adjustments
1958 P S
1959 P SG
1960 P SG
1961
1962
IDAHO
Nonnllzed Retail MiseDistributionDistrbutionProductionTransmission------
1,000,000 39,285 362,221 598,494 598,494
517,935 473,453,44,482
5,481,532 5,010,762 470,770
509,026 465,309 43,717
33,106 33,106
7,541.599 6,021,916 921,190 598,94 598,494
415.859 16,37 150,633 246,889 248,889
5,887,193 5,363,301 503,892
19,763,212 10,352,26 3,860,326 5.550,622 5.550,622
219,581 219,581
4,613,271 4.613,271 4,613,271
30,879,115 15,951,482 4,514,851 10,412,782 5,799,512 4,613,271
,
30,879,115 15,951,482 4,514,851 10,412.782 5,799,512 4,613,271
38,420,714 21,973,398 5,436,040 11,011,276 6,398,Ol 4,613,271 .
1,415,859 55,622 512,854 647,383 647,383
12,408,792 11,345,931 1.062,860
19,763,212 10,352,26 3,860,326 5,550,622 5,550,622
4,613,271 4,613,271 4,613,271
219,581 219,581
38,420,714 21,973,398 5,438.040 11.011,278 6,398,005 4,613,271
924,997 924,997 924,997
253,113 132,584 49,40 71,088 71.08
4,657,469 4,657,469
43.389 43.369
5,878,948 175,953 4,706,910 996,085 99,085
1,168,782,718 605,807,354 257,120,569 305,85,805 300,196,541 5,658,264
297,988,873 930,639 8,342,486 288,715,747 288,64,070 71,678
31,451,512 31,445,45 2,970 3,082 2,981 101
769,373,119 525,607,000 241,699,617 2,06,502 1,998,973 67,529
33,265,393 16,502,970 7,049,793 9,712,630 9,676,708 35,922
5,583,429 17,325 41,855 5,524,249 42,011 5,482,238
28,542,427 28,405,075 113,004 24,348 23,553 796
4,194,637 4,190,373 4,227 37 35 1
(1,616,663)11,291,488)(133,385)(191,7891 (191,789)
1,168,782,728 605,807,35 257,120,569 305,854,805 300,196,541 5,658,264
(491,540)(491,540)
491,540 491,540
(0 491,540 491,540)
.
7,856,940 7,856,940 .
802,076 802,076
8,659,016 8,659,016
(4,832,886)(4,632,666)
(673,478 (673,478)
(5,306,164)5,306,164)
TA82 23 ()I 29
Descnption of Account Summary:
1963 120 Nuclear Fuel
196 P SE
1965
196
1967 124 Weatherization
1968 OMSC S
1969 OMSC SO
1970
1971
1972 182W Weatherization
1973 OMSC S
1974 OMSC SG
1975 OMSC SGCT
1976 OMSC SO
1977
1978
1979 186W Weatherization
1980 OMSC S
1961 OMSC CN
1982 OMSC CNP
1983 OMSC SG
1984 OMSC SO
1985
1986
1987 Total Weatherization
1988
1989 151 Fuel Stock
1990 P OEU
1991 P SE
1992 P SSECT
1993 P SSECH
1994
1995
1996 152 Fuel Stock. UndlslMbuled
1997 P SE
1998
1999
2000 25316 OG& T WorKing Capital Oeposn
2001 P SE
2002
2003
2004 25317 OG& T Workng CapUal OeposU
2005 P SE
200
2007
2008 25319 Provo WorKing Capital OeposU
2009 P SE
2010
2011
2012 Totl Fuel Stock
2013 154 Materials and Supplies
2014 MSS S
2015 MSS SG
2016 MSS SE
2017 MSS SO
2018 MSS SNPPS
2019 MSS SNPPH
2020 MSS SNPO
2021 MSS SNPT
2022 MSS SG
2023 MSS SG
2024 MSS SSGCT
2025 MSS SNPPO
2026 MSS SSGCH
2027
2028
2029 163 Stores Expense Undistributed
203 MSS SO
2031
2032
2033
2034 25318 Provo WorKing CapUal OeposU
2035 MSS SNPPS
2036
2037
2038
2039 Total Materials & Supplies
2040
2041 165 Prapayenls
2042 OMSC S
2043 GP GPS
204 PT SG
2045 P SE
2046 PTO SO
2047
2048
2049 182M Mise Regulatoiy Assets
2050 00S2 S
2051 OEFSG SG
2052 P SGCT
2053 OEFSG SG.p
2054 P SE
2055 P SSGCT
2056 DDS02 SO
2057
IDAHO
Normalized Production Transmission Distribution Qislrlbullon Retil Mise-----
33,20 33,220 33,220
(240 (240\(240)
32,980 32,980 32,980
3,470,661 3,470,661 3.70,661.
3,470.661 3,470,661 3.70,661
.
3,503,640 3,503,640 3,503,640
,
11,938,941 11,938,941
468,64 468,64
12,407,58 12,407,566
(143,744 (143,744\
(143,744 (143.744\
(117,7061 (117,706\
1117,706 1117,706\
.
12,146,136 12,146,136
4,889,311 3,935,158 27,494 926,660 926.660
169,782 136,649 955 32,178 32,178
265,116 213,379 1,491 50,247 50,247
13,677 11,008 77 2,592 2,592
4,464,050 3,609,007 25,215 649,857 849,857
(102)(82)(1)(19)(19)
(142,196)(114,446)(800)(26,950)(26,950)
291,256 234,417 1,638 55,201 55,201
9,970,923 8,025,089 56,069 1,889,766 1,889,766
(15,017)(12.087)(84)(2,846)(2,646)
15,017 12,087\(84\(2,846\(2,84
9,955,90 8,013.002 55,984 1,866,920 1,886,920 .
164,017 164.017 164,017
531,617 267,189 97,971 166,458 162,355 4,102
353,400 257,412 95,988
451,519 451,519
1,069,782 560,367 208,959 300,455 300,455
2,570,33 1,536,487 402,918 630,930 462,810 4,102 164,017
(206,251)(176,66)(3,300)(26,285)(398)(31,363)5.77
146,231 83,565 62,666
470,663 470,663
74,434 42,536 31,898
74,327 74,327
405,300 109,328 7.325 288,647 43,953 244,694
96,704 603,752 98,590 262,362 43,555 131,363)250,171
TAB 2 240129
Description of Account Summary:
2058
2059 186M Mise Deferrd Debits
206 LAOR S
201 P SO
2062 P sa
2063 DEFSO SO
206 LABOR SO
2065 P SE
206 P SNPPS
2067 OP EXCTAX
2068
2069
2070 Working Cap~al
2071 CWC Cash Workin Capitl
2072 CWC S
2073 CWC SO
2074 CWC SE
;175
2076
2077 owe other Working Capial
2078 131 Cam OP SNP
2079 135 Working Funds OP SO
2080 141 Notes Receivable OP SO
2081 143 other Accounts Receivabl GP SO
2082 232 Acounts Payabl PTD S
2083 232 Accounts Payble PTD SO
2084 232 Accnts Payable P SE
2085 232 Accounts Payable T SO
2086 2533 other Deferrd Cred~s . II P S
2087 2533 other Deferred Credns . II P SE
2088 23 Asset Retirement Obligatii P SE
2089 230 Aset Retirement Otlligatii P S
209 254105 ARO Reguletoiy liability P S
2091 254105 ARO Regulatoiy Liabilit P SE
2092 2533 Cholla Reclamation P SSECH
2093
2094
2095 Total Working Capital
2096 Miscellaneous Rate Base
2097 18221 Unrec Plant & Reg Study Costs
2098 P S
209
2100
2101
2102 18222 Nuclear Plant. Trojan
2103 P S
2104 P TROJP
2105 P TROJD
2106
2107
2108
2109
2110 1869 Misc.Deferred Debits-Trojan
2111 P S
2112 P SNPPN
2113
2114
2115 TOTAL MISCELLANEOUS RATE BASE
2116
2117 TOTAL RATE BASE ADDlTIONS
2118 235 Customer Service Deposits
2119 CUST S
2120 CUST CN
2121
2122
2123 2281 Prov for Propert Insuranc PTO SO
2124 2282 Prov for Injuries & Damag PTO SO
2125 2283 Prov for Pensions and Bei PTO SO
2126 254 Reg L1abil~ies PTD SO
2127 254 Reg liabi~ities PTD SE
2128 254 Reg Liabilities - Insurance PTD SO
2129
2130
2131 22841 AccumMisc Oper Provisions ¥ Other
2132 P S
2133 P SO
2134
2135
2136 22842 Accum Mise OperProv- Tr P TROJD
2137 230 Asset Retiremen ObUgatil P TROJP
2138 254105 ARO Reglatoiy liabilit P TROJP
2139 254 P S
2140
2141
2142 252 Customer Advances for Constrction
2143 DPW S
2144 DPW SE
2145 T SG
2146 DPW SO
2147 CUST CN
2148
IDAHO
Normalized Retail MiProduCllonTransmis$ion Distrbution Distributon----
2,678,738 1,530,785 1,147,953
913 410 61 442 307 135
529,760 529,760 .
3,209,411 2,060,956 1.148,013 442 307 135
2,134,510 1,653,933 190,450 290,127 198,732 87,435 3,961
2,134,510 1.653,933 190,450 290,127 198,732 87,435 3,961
106 53 19 33 32 1
29,149 14,65 5,372 9.127 9,902 225
1,832,565 921,040 337,720 573,805 559.66 14,142
(27,291)(119,058)(44,396)(63,836)(63,836)
(89,545)(89,545)
(384,378)(384,378)
(153,590)(153,590)
(45,558)(45,558)
961,459 143,614 298.715 519,130 504,762 14,367
3,095,969 1,797,548 489,164 809,257 703,494 101,802 3,961
49,907 49,907
73372 73,372
123,279 123,279
123,279 123,279
38,922,231 30,125,551 1,703,130 7,093,560 3,097,085 74,676 3,921,700
.
(403,752)(211,497)(78,866)(113,399)(113,399)
(1,225.28)(641,897)(239,361)(34,169)(344,169)
(5,908 (3,095)(1,154)(1,659)(1,659\
(1,635,098)856,489\319,382)(459.228)(459,228)
(82,627\(82,627)
82,627)(82,627
(96,473)(96,473)
(203,453)(203,453)
299,926 (299,926)
(268.266)(268,266)(268,266)
(679,431)(679,431).
947,697 (679,431)(268,256)(268,26)
TAB 2 25 Of 29
Description of Account Summary:
2149
2150 25398 802 Emissions
2151 P SE
2152
2153
2154 25399 Oter Deferred Credtts
2155 P S
2156 LABOR SO
2157 P SG
2158 P SE
2159
2160
2161 190 Accumulated Deferrd Income Taxes
2162 P S
2163 CUST CN
2164 P IBT
2165 LABOR SO
2186 P DGP
2167 CUST BADDEBT
2168 P TROJD
2169 P SG
2170 P SE
2171 PTD SNP
2172 DPW SNPO
2173 P SSGCT
2174
2175
2176 281 Accumulated Deferrd Income Taxes
2177 P S
2178 PT DGP
2179 T SNPT
2180
2181
2182 282 Accumulated Deferred Income Taxes
2183 GP 5
2184 ACCMOIT DITBAL
2185 P SSGCH
2186 LABOR SO
2187 CUST CN
2188 P SE
2189 P SG
2190
2191
2192 283 Accumulated Deferrd income Taxes
2193 GP 5
2194 P SG
2195 P SE
2196 LABOR SO
2197 GP GPS
2198 PTD SNP
2199 P TROJD
2200 P SSGCT
2201 P SGCT
2202 P SSGCH
2203
220422 TOTAL ACCUMULATED DEF INCOME TAX
2208 255 Accumulatedlnvestment Tax Credit
2207 PTD 5
2208 PTD ITC84
2209 PTO ITC85
2210 PTO ITC86
2211 PTO ITC88
2212 PTO ITC89
2213 PTD ITC90
2214 PTO IBT
2215
2216
2217 TOTAL RATE BASE DEDUCTIONS
2218
221922
2221 108SP Steam Prod Plant Accumulated Oepr
2222 P S
2223 P SG
2224 P SG
225 P SG
2226 P SSGCH
227
228
229 108NP Nuclear Prod Plant Accumulated Depr
2230 P SG
2231 P SG
2232 P SG
2233
2234
223522 10BHP Hyraulic Prod ?tant Accurn Oepr
2237 P 5
2238 Pre~Merger Pacifc P SG
2239 Pfe.Merger Utah P SG
2240 Post~Merg Pacific P SG
2241 post~Merger Utah P SG
2242
IDAHO
Normalized Production Transmission Distribution Distributon Retail Mise------
(2,402,284)12,402,284)
(2,402,284)(2,402,284
(75,180)(75,180)
(181,282)(81,511)(12,059)(87,712)(60,898)(26,814)
(441,134)(441,134)
/75,29 (75,229)
(772,824 (673,054 (12,059 (87,712)/60,898'(26,814)
(2)(2)
2,544 2,544 2,54
1,917,697 862,29 127,567 927,861 64,208 283,653
129,748 129,748 129,748
75,422 75,422
167,004 167,004
(150,418)(150,418)
32,458 32,458 32,458
2,174,453 95,275 127,567 1.092,611 676,666 415.945
-
(138,317,516)(69,517,835)(25,490,257)(43,309,424)(42,242,042)(1,087,381)
°°°°0 °
(365,765)(164,462)(24,331)(176.972)(122,871)(54,102)
(418,113)(418,113)
11,978,494 (1,978,494),
(141,079,88 /72,078,9031 25,514,588)43,486,396\(42,36.913)1,121,483
(78,868)(39,639)(14,534)(24.695)(24.086)(609)
(411,048)(411,048)
(286,685)(286,685)
(193,125)(86,836)(12,847)(93,42)(64,876)(28,566)
(36.658)(154,125)(56,513)(96,020)(93,653)(2,366)
(277,643)(145,433)(54,232)(77,978)(77,978)
(149,373)(149,373).' .
11,683,400)(1,253,140 (138,126 1292,134)(260,593)31,51)
(140,588,834)172,377,768)(25,525,148)(42,685,918)141,948,840\(737,079)
(44.168)(23,136)(8,827)(12,405)(12,405)
(184.142)196,456)(35,96)(51,718)(51,718)
(228.311)(119,593)(44,596 64.122 64,122)
(146,957,602)(76,811,7401 (28,580,815)/43,585,246\/42,801,353)(783,893)
(45,639,643)(45,639,643)
(51,586,204)(51,566,204)
(31,242,695)(31,242.695)
(8,646,503 (8,64,503\
(137,095,045 (137,095,045)
(8,286,419)(8,286,419)
(1,575,663)(1,575.863)
(3,367,647)(3,367,647)
(780,893)(780,893\
(14,010,622 (14,010,622)
TAB 2 26 of 29
Desciiaüon of Account Summary;
2243
2244 1080P Other Production Pla - Accum Oepr
2245 P S
2246 P SG
2247 P SG
2248 P SG
2249 P SSGCT
2260
2251
2252 l08EP Experimental Plant. AeculJ Depr
2253 P SG
2254 P SG
2255
2256
2257 TOTAl PRODUCTION PLANT DEPRECIATION
2258
2259 Summary of Prod Plant Depreciation by Factor
2260 S
2261 DGP
2262 DGU
2263 SG
2264 SSGCH
2265 SSGCT
2266 Totalof Prod Plant Depreciation by Factor
2267
228
229 108TP Transmission Plant Accumulated Depr
2270 T SG
2271 T SG
2272 T SG
2273 TOTAL TRANS PLANT ACCUM DEPR
2274 108360 Land and Land Rights
2275 DPW S
2276
2277
2278 108361 Stnctures and Improvements
2279 DPW S
2280
2281
2282 108362 Station Equipment
2283 DPW S
2284
2285
2286 108363 Storage Ballery Equipmant
2287 DPW S
2288
2289
2290 108384 Poles. Towèrs & Fixtures
2291 DPW S
2292
2293
2294 108365 Overhead Conductor
2295 DPW S
2296
2297
2298 108366 Underground Conduit
229 DPW S
230
2301
2302 108367 Underground Conductors
2303 DPW S
2304
2305
230 108368 Une Transfomiers
2307 DPW S
2308
2309
2310 108369 Seilces
2311 DPW S
2312
2313
2314 108370 Meters
2315 DPW S
2316
2317
2318
2319
2320 108371 Installations on Customers' Premises
2321 DPW S
2322
2323
2324 108372 Leased Property
2325 DPW S
2326
2327
2328 108373 Street Lights
2329 DPW S
2330
2331
2332 108DOO Unclassified Dlst Plant 4 Acc1 300
2333 DPW S
2334
2335
IDAHO
Normalized Production Transmission Distnbuton Dislnbutlon Retail Mise-----
(74,22)(74,226)
(15,112,411)(15,112,411)
/1,062,098 11,062,09\
116,248,735 16,248,735)
(167,354,402 (167,354,402)
(157,845,801)(157,645,801)
(8,64,503)(8,646,503)
11,062,098 ii,OO:1,09)
(167,354,40:1)167,354,402)
(21,367,434)(21,367,434)
(21,354,659)(21,354,659)
(21,261.976 (21,261,976\
(63,984,069 63,984,069 .
1259,247)(259,247)1259,247)
(259,247)(259,247'' 1259,247
1442,875)(442,875\/442,875)
(442,875 (442,875), 1442,875\
(9,277038)(9,:177.038)(9,27,038'
9,277038 (9,277038'" 19,277,038
· 133,878,967 (33,878,967)133,878,967)
/33,878,967 (33,878.967)33,878,967)
(10,430,983 (10,430,983\(10,430,983'
(10,430,983)(10,430,983 10,430,983'
(3,301,901 (3,301,901'13,301,901\
(3,301,901 (3,301,901 (3,301,901\
/10,763,326)/10,763,326)(10,763,326\
10,763,326 (10,783,326)(10,763,326\
(23,663,153 (23,663,153\(23,663,153'
, 123,663,153 123,663.153\(23,663,153)
(10,431,110)(10,431,110)(10,431,110'.
110,431,110 10,431.10)(10,431,110)
(8,366,773 (8,366,773)(8,366,773)
8,36,773 (8,366,773)(8,366,773)
(136,989 (136,989\1136,989)
(136.989)(136,989 ~ii36,989
1490,188\1490,188)1490,188)
(490,188)490.188)(490,188\
TAB 2 270129
Description of Account Summary:
2336 108DS Unclassifed Dist Sub Plant - Acet 300
2337 DPW S
2338
2339
230 108DP Unclassified Dist Sub. Plant . Acct 300
2341 DPW S
2342
2343
2344
2345 TOTAL DISTRIBUTION PLANT DEPR
2346
2347 Summary of Distribution Plant Depr by Facor
234 S
2349 0
2350 Total Distribution Depralio by Facor
2351 106GP General Plant Accumulated Depr
2352 G-SITUS S
2353 PT SG
2354 PT SG
2355 G-SG SG
2356 CUST CN
2357 PTD SO
2358 P SE
2359 G-SG SSGCT
236 G-SG SSGCH
2361
2362
2363
236 108MP Mining Plant Accmulated Depr,
2365 P S
2366 P BE
2367
2368 108MP Less Centralia Situs Depreciation
2369 P S
2370
2371
2372 1081390 Accum Depr . Capital Lease
2373 PTD SO
2374
2375
2376 Remove Capital L.eas.es
2377
2378
2379 1081399 Accum Depr - Capital Lease
2380 P S
2381 P SE
2382
2383
2384 Remove Capital Leases
2385
2386
2387
2366 TOTAL GENER PLANT ACCUM DEPR
2389
2390
2391
2392 SUmmary af General Deprecatin by Factor
2393 S
2394 DGP
2395 DGU
2396 SE
2397 SO
2398 CN
2399 SG
240 DEU
2401 SSGCT
2402 SSGCH
2403 Remove Capital Leases
2404 Total General Depreciation by Factor
2405
2406
2407 TOTAL ACCUM DEPR . PLANT IN SERVICE
2408 L11SP Accum Prav for Amort.Steam
2409 P SG
2410 P SSGCT
24tl
2412
2413
2414 l11GP Accum Prav for Amort.General
2415 G-SITUS S
2416 CUST CN
2417 I-SG SG
2418 PTD SO
2419 P SE
2420
2421
2422
2423 l11HP Accum Pray for Amon-Hydro
2424 PreMerger Pacific P SG
2425 PreMerger utah P SG
2426 Post-Merger Pacific P SG
2427 Post..Merger utah P SG
2428
2429
2430
IDAHO
Normalized ~DistbutIon MiseProductionTransmIssionDistribution-----
1,248 1,248 1,248
1,248 1,248 1,248
(111,441,302 .1111,441,302)(111,441,302\
(111,441,302)(111,441,302)(111,441.02)
(111,441,302 (111,441,302 111,441,302)
(10,194,914)(2,189,316)(8,005,596 (8,005.96)
(345,519)(251,671)(93,847)
(615,11)(448,257)(167,154)-
(2,547,666)(1,311,561)(1,236,327)
(257,35)(257,358)(257,358)
(3,910,843)(2,048,557)(763,900)(1,098,385)(1,098,365)
(21,609)(21,609).
(1,797)(925)(872)
(127,042)(65,397)(61,645\
18,022,380)4,147,976 14,513,064 19,361,339'(9,103,980)(257,358)
(10,679,840)(10,879,840\
(10,879,840)10,879,840
(10,879,840)(10,879,840
128,902,221 116,027,818\14,613,06\19,361,339'(9,103,9801 1251,358)
(10,194,914)(2,189,318)(8,005,596)(8,005,596)
(10,901,450)(10,901,450)
(3,910,843)(2,048,557)(763,90)(1,098,385)(1,098,385)
(257,358)(257,358)(257,358)
(3,508,818)(2,011.490)(1,497,329)
(1,797)(925)(872)
(127,042)(85,397)(61,845)
(28,902,221)(15,027,818 (4,513,064)(9,381,339 19,103,980 257,358
(371,681,993 1182,382,220)168,497,1331 1120,802,6411 1120,645,2821 1257,358)
(95,300)(95,300)(95,300)
(534,219)(279,832)(104,348)(150,039)(150,039)
(629,519 (279,832)1104,348)(245,339)150,039)(95,300)
(718)(718)
(21,518 (21,518\
(22,236)22,23)
TAB 2 28 of 29
Description of Account Summary:
2431 111P Accum Prov for Amort-Intangible Plant
2432 I.SITUS S
2433 P SG
2434 P SG
2435 P SE
2436 !-SG SG
2437 I.SG SG
2438 I.SG SG
2439 CUST CN
2440 P SSGCT
2441 P SSGCH
2442 PTO SO
2443
2444 1111P Less Non-Utilit Plant
2445 NUTIL OTH
2446
2447
2448 111390 Accum Amtr - Capitl Lease
2449 G.SITUS S
2450 P SG
2451 pm SO
2452
2463
2454 Remove Capitl Lease AmtT
2455
2456 TOTAL ACCUM PROV FOR AMORTl nON
2457 Year~End
2458
2459
2460
2461 Summas of Amortization by Factor
2462 S
2463 DGP
2464 DGU
2465 SE
2486 SO
2467 CN
2468 ¡¡SGCT
2469 SSGCH
2470 SG
2471 Less Capital Lease
2472 Total Provision For Amortization by Factor
IDAHO
Normalized Distribution Retail MiseProductionTransmissionDistribution-----
(736,186)(28,920)(266,655)(440,591)(440.591)
(18,323)(16,323)
(64,260)(64,260)
(2,347,419)(2,145,816)(201,803)
(630,963)(576,774)(54,189)
(171,414)(156,692)(14,722)
(3,77,128)(3,477,128)(3,477 126)
(3,699)(3,699)
(2,637,878\13,782,909)13,792,909\/13,50,8021 (7,074,016\
(20,964,194)(10,068,520)(3,175,04)(7,710,527)(4,233,499)(3,477,128)
(20,954,194)(10,068,520 13,175,046)17,710,627)(4,233,499)/3,477,128
(76,615).78615.3371
100,349 52,56 19,601 28,194 28,184
23,733 24,051 19,601 28,194 28,184
(23.733)24,051 19,601\28,184)(28,184)
(21,60,949 (10,370,588 (3,279,395\17,955,9661 4,383,538 (3,572,428
(736,186)(28,920)(266,865)(440,591)(440,591)-
(84,280)(64,280)
(13,938,672)(7,301,283)(2,722,625)(3,914,764)(3,914,764)
(3,572.428)(3,572.428)(3,572.428)-
(3,699)(3,699)
(3,28,970)(2,996,456)(270,514)
128.184\(23,733 24,051 119,801\/28.184)
(21,605,949 (10,370,588\(3,279,395 (7,955,96 (4,383,538\(3.572,426\
TAB 2 29 of 29
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