HomeMy WebLinkAbout20110527Paice Di.pdfRECEIVED
lO',HAY27 AHII: 10
UTfL
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 $32.7 )
MILLION, OR APPROXIMATELY )15~0 PERCENT )
CASE NO. PAC-E-l1-12
Direct Testimony of C. Craig Paice
ROCKY MOUNTAIN POWER
CASE NO. PAC-E-l1-12
May 2011
1 Q.
2
3 A.
Please state your name, business address and present position with Rocky
Mountain Power (the "Company"), a division of PacifiCorp.
My name is C. Craig Paice. My business address is 825 NE Multnomah, Suite
4 2000, Portland, Oregon 97232, and I am curently employed as a Regulatory
5 Consultant in the Regulation Departent.
6 Qualifications
7 Q.
8 A.
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10
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12
13
14 Q.
15 A.
16
17
18 Q.
19 A.
20
Please 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 various educational, professional
and electric industr seminars during my career with the Company. I have been
employed by PacifiCorp since the merger in 1989. Prior to that time, I was
employed by Utah Power & Light Company beginning in 1978 holding various
positions in the accounting, customer service, and regulatory areas.
What are your responsibilties?
My primary responsibilities are to prepare, present, and explain the results of the
Company's cost of service studies to regulators and interested parties in
jursdictions 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
Idaho, Utah, Wyoming, California, Oregon, and Washington.
21 Purpose of Testimony
22 Q.
23 A.
What is the purpose of your testimony in this proceeding?
I wil present Rocky Mountain Power's embedded class cost of service (COS)
Paice, Di - 1
Rocky Mountain Power
1 study for the state of Idaho based on the 12 month test period ending December
2 31,2010.
3 Cost of Service
4 Q.Please identify Exhibit No. 40, Cost of Servce - Summary by Rate Schedule,
5 and explain what it shows.
6 A.Exhibit No. 40, Cost of Service - Summary by Rate Schedule, shows the
7 summar of the results from the COS study for Idao. It is based on the
8 Company's actual December 2010 results of operations for the state of Idaho
9 presented in the testimony of Company witness Mr. Steven R. McDougaL. Page 1
10 presents a summary of the Company's actual eared rate of retu by rate
11 schedule based on curent rate levels. Page 2 shows the results using the taget
12 rate of retu based on the requested $32.7 milion revenue increase.
13 Q.Please describe Exhibit No. 41, Cost of Servce - Summary by Function.
14 A.Exhibit No. 41, Cost of Service - Summary by Function, shows the cost of
15 service results by rate schedule and by fuction. Page 1 contains the total cost of
16 service summary by rate schedule and pages 2 through 6 contain a summar by
17 rate schedule for each fuction.
18 Cost of Service Study Changes
19 Q.Are there any methodology differences between the COS study presented in
20 this proceeding and the cost study fied with the Idaho Commission in Case
21 No. PAC-E-I0-07, Order No. 32196 (the "2010 General Rate Case")?
22 A.Yes. In the 2010 General Rate Case, the COS study was prepared consistent with
23 Idaho results of operations which were developed using the Revised Protocol
Paice, Di - 2
Rocky Mountain Power
1 methodology. In the current proceeding, Idaho results of operations are based on
2 the 2010 Protocol described in the direct testimony of Mr. McDougaL. The
3 Company's standard practice is to allocate costs in the COS study to customer
4 classes consistent with the way that they are allocated to the jursdiction. As such,
5 the COS study fied in this proceeding employs the 2010 Protocol methodology.
6 Q.How are costs associated with the Irrigation Load Control Program being
7 treated in the COS study?
8 A.Pursuant to the Commission's Order in the 2010 General Rate Case, Order No.
9 32196, the delivery costs of the Irrgation Load Control Program were shifted
10 from the customer efficiency rider to base rates and allocated as a system expense.
11 Based on this decision, Idaho jursdictional loads include the full level of peak
12 demand excluding the impact of the irgation load control program. Class load
13 data used in the COS study does not reflect a similar adjustment. This assures that
14 Idaho's allocated share of the costs and benefits of the irgation load control
15 program are spread among all Idaho customer classes. This logic is consistent
16 with prior treatment where the benefits associated with the curailment program
17 were shared among all customer classes.
18 Description of Cost of Servce Procedures
19 Q.Please explain how the cost of service study was developed.
20 A.The cost of service study utilizes anual Idaho results of operations produced by
21 Mr. McDougaL. The study employs a three-step process generally referred to as
22 fuctionalization, classification, and allocation. These three steps recognize the
23 way a utility provides electrcal service and assigns cost responsibility to the
Paice, Di - 3
Rocky Mountain Power
1
2 Q.
3
4 A.
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6
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8
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10
11
12
13
14
15
16
17 Q.
18
19 A.
20
21
22
23
groups of customers for whom those costs were incured.
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 utility fuction. The production fuction consists of the costs
associated with power generation, including coal mining and wholesale sales and
purchases. The transmission fuction 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 fuction
includes the costs associated with all the facilties that are necessary to connect
individual customers to the transmission system. This includes distrbution
substations, poles and wires, line trnsformers, service drops, and meters. The
retail service fuction includes the costs of meter reading, biling, collections, and
customer service. The miscellaneous fuction includes costs associated with
demand side management, franchise taxes, regulatory expenses, and other
miscellaneous expenses.
Describe classifcation and explain how the Company uses it in the cost of
servce study.
Classification identifies the component of utilty service being provided. The
Company provides, and customers purchase, servce that includes at least three
different components, demand-related, energy-related, and customer-related
components. Demand-related costs are incured by the Company to meet the
maximum demand imposed on generating units, transmission lines, and
Paice, Di - 4
Rocky Mountain Power
1
2
3
4 Q.
5
6 A.
7
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16 Q.
17
18 A.
19
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22
distribution facilities. Energy-related costs var with the output of a kilowatt-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 costs have been fuctionalized 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 determine each class' share
of cost. A detailed description of the Company's fuctionalization, classification
and allocation procedures and the supporting calculations for the allocation
factors are contained in my workpapers, which are attached hereto as Exhibit No.
42, Cost of Service - Study. Also, included in the workpapers is the
fuctionalized 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. The demand-related
portion is allocated using the class' 12 monthly peaks coincident with the
Company's system firm peak. The energy portion is allocated using class
megawatt hours adjusted for losses to generation leveL.
Paice, Di - 5
Rocky Mountain Power
1 Q.
2 A.
3
4
5
6
7
8
9
10
11
12
13
14
15
16 Q.
17
18 A.
19
20
21
Please describe how distribution costs are determined?
Distrbution 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. Distrbution substations and primar lines
are allocated using the weighted monthly coincident distrbution peaks.
Distribution line transformers and secondary lines are allocated using the
weighted non-coincident peak method. Servces costs are allocated to secondary
voltage delivery customers only. The allocation factor is developed using the
installed cost of new services for different tyes 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 tyes of customers. Meter
costs were revised in the COS study to reflect that Schedule 36 customers require
time-of-use meters which are capable of measuring energy consumption durng on
and off peak hours. Previously, standard non-time-of-use watt-hour meter costs
were used for both Schedule 1 and Schedule 36.
Please explain how customer accounting and customer servce 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 different tyes of customers. Customer
service expenses are allocated on the number of customers in each class.
Paice, Di - 6
Rocky Mountain Power
1 Q.
2
3 A.
4
5
6
7
8 Q.
9
10 A.
11
12
13
14
15
How are administrative & general expenses, general plant and intangible
plant allocated by the Company?
Most general plant, intangible plant, and administrative and general expenses are
fuctiona1ized and allocated to classes based on generation, transmission, and
distrbution plant. Costs identified as supporting customer systems are considered
par of the retail services fuction and are allocated using customer factors. Coal
mine plant is allocated on the energy factor.
How are costs and revenues associated with wholesale contracts and other
electric revenues treated in the cost of servce study?
The revenues from wholesale transactions are treated as revenue credits and are
allocated to customer classes using appropriate allocation factors. Other electrc
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 Residential Schedules 1 and 36
17 Q.
18
19 A.
20
21
22
In the 2010 General Rate Case, what did the Commission find with respect to
COS results for Schedule 1 and Schedule 36?
On page 44, of its Order, the Commission found that, "( c )omments and testimony
of customers under the two residential rate schedules, we note, reflect that they do
not understand why the Company proposes separate treatment for Schedules 1
and 36."
Paice, Di-7
Rocky Mountain Power
1 Q.
2
3 A.
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
Why does the Company calculate results for both Schedule 1 and Schedule
36 in the COS study?
Separate results are developed for Schedule 1 and Schedule 36 because they have
different underlying cost characteristics including different meter costs, customers
per transformer, load factors, and energy usage per customer. Due to these
different cost characteristics, Exhibit No. 40, Cost of Service - Summary by Rate
Schedule, shows that Schedule 36 is significantly underperforming relative to
Schedule 1. The increase needed for Schedule 36 customers is approximately 2.3
times the increase required for Schedule 1 customers and is consistent with results
from recent cost studies fied in Idaho. The COS study results in case the 2010
General Rate Case showed Schedule 36 customers needing an increase of about
1.9 times the increase needed for Schedule 1 customers. In case PAC-E-07-05,
cost of service results showed that Schedule 36 customers needed an increase
slightly more than 1.8 times the increase required for Schedule 1 customers.
These comparisons demonstrate that the Company's cost of service methodology
produces a high level of consistency between cases and separate COS results for
Schedules 1 and 36 contiue to show significant cost differences between these
customer classes.
19 Work papers
20 Q.
21 A.
22
23
Have you included your workpapers?
Yes. My workpapers are included as Exhibit No. 42 Cost of Service - Study. Tab
1 of this exhibit is a detailed narrative describing the Company's
fuctionalization, classification and allocation procedures. Tab 2 is the complete
Paice, Di - 8
Rocky Mountain Power
1
2
3 Q.
4 A.
fuctionalized results of operations. Tab 3 shows the fuctionalization factors
used in this case. Tabs 4 through 5 show the class cost of service detaiL.
Does this conclude your direct testimony?
Yes.
Paice, Di - 9
Rocky Mountain Power
2011 MAY 27 AM 11= II Case No. PAC-E-11-12
Exhibit No. 40
Witness: C. Craig Paice
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNAIN POWER
Exhibit Accompanying Direct Testimony of C. Craig Paice
Cost of Service - Sumary by Rate Schedule
May 2011
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Case No. PAC-E-11-12
Exhibit No. 41
Witness: C. Craig Paice
BEFORE THE IDAHO PUBLIC UTILITffS COMMISSION
ROCKY MOUNTAI POWER
Exhibit Accompanying Direct Testimony ofC. CraigPaice
Cost of Service - Sumary by Function
May 2011
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,on MAY 21 AM II: II
Cas No. PAC-E-11-12
Exhbit No. 42
Witness: C. Craig Paice
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhbit Accompanying Direct Testiony of C. Craig Paice
Cost of Servce - Study
May 2011
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 facilities 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, D (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
utilities 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 10
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, billng, 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 (Le. 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 (Le. F102
- Gross Plant). Many plant related allocation factors are identified by function and are so
identified (F102G - Generation Plant, F102T - Transmission Plant, F102D - 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
Factor. 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 10
as generation, transmission, and distribution plant (PTD FUNC factor). Those items that
are considered directly related to employee compensation are split in 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 2010 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 of the functions using a series of functionalization factors
(FUNC factors). When all, or essentially all, of the account balance associated with one
FERC account and 2010 Protocol factor have the same 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 to Production "P".
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.
Operating Expenses:
Tab 1 Page 3 of 10
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, D & 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 "G" 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, D, & 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
PTDRM using the "GP" factor and deducted from PTDRM revenue. Schedule M Additions
Tab 1 Page 4 of 10
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, 0 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 utility 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 T. Distribution plant accounts
are split between 0 and R based upon asset utilzation.
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
customer service system were functionalized to R. A separate General Plant
functionalization factor was developed to correspond to each PITA allocation factor.
Tab 1 Page 5 of 10
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 "OEFSG", "00S02" and "00S06" 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.
Property 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, (Productionrr otal, Transmissionrr otal, Oistributionrr otal).
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 1 Page 6 of 10
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 "G" 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 2010 Protocol method currently under
consideration by the Idaho Commission in Case No. in Docket No. PAC-E-10-09. The
MSP 2010 Protocol identifies three categories of 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.
Energy related costs are allocated using each class' share of annual MWH (F30).
Demand-related costs are allocated using each class' contribution to the 12 monthly peaks
coincident with the PacifiCorp system firm peak. 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 capacity allocation
factor (F12). The energy portion is allocated using class MWH adjusted for losses to
Tab 1 Page 7 of 10
generation level (F30). The fixed costs composite factor is (F1 0).
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
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
large enough to meet the sum of the individual customer peak demands (non-coincident or
biling 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
Tab 1 Page 8 of 10
customers. As such, they are considered part of the facilities category. Since the cost
responsibility for line transformers is incurred at the time a load is added to the system,
that cost responsibility 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 propert 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 Distribution Construction Standard -
DA411 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.
(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 different types of customers. (F60)
Customer Accounting, Customer Services & Sales
Customer accounting, customer service, 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 bils 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).
Tab 1 Page 9 of 10
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 (F104). Most deferred taxes
are a result of plant investment. Deferred Income Taxes associated with bad debt are
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 propert taxes. Propert Taxes are assessed on plant investment.
Rate Base Additions and Deductions
Additions and deductions that relate to Generation and Transmission plant are allocated
accordingly (F1 0). 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 (F1 02).
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 1 Page 10 of 10
2010 PROTOCOL
Year-End
RESULTS OF OPERATIONS SUMMARY
IDAHO
Decripton of Acunt Summary.~f!TramissIon ~~B!Ii
1 General Busines Revenues 216,197,769 142,017,362 35.346,390 40,632,037 32,62,666 6,164,651 2,024,500
2 General Busines Revenues
3 Interdepartmental
4 Special Sales 30,66,461 30,66,461
5 Other Operating Revenues 13,631,492 6,=,132 4,606,731 602,630 265,777 50,325 27,527
6 Total Operating Revenues 262,693,763 161,103,975 40,155,121 41,634,667 32,666,63 6,69,177 2,052,027
7
6 Operating Expenses:
9 Steam Production 64,517,140 64,517,140
10 Nuclear Production
11 Hyro Pructon 2,676,169 2,676,169
12 other Power Suppy 68,710,605 68,710,605
13 Transmission 12,145,669 12,145,669
14 Distbution 11,017,503 11.017.503 11,017,503
15 Cusomer Acunts 4,663,561 4,663,561 4,66,561
16 Cusomer Service 1.06,1n 1,206,172 1,20,172
17 Sales
16 Administraive & General 11,262,040 4,603,634 2,015,953 4.642,453 2,916,624 396,310 1,327,519
19
20 Total 0 & M Expenses 176,201,096 140,507.47 14,161,642 21,531.09 13.934,127 6,270,06 1,327,519
21
22 Depreciation 30,729,604 17.183.09 5,614,703 7.32,09 7.66,147 65,94
23 Amortiztion Expense 2,767,529 1,993,466 322.36 451,675 22,953 224,722
24 Taxes Other Than Income 7,163,133 3,601,292 1,553,202 2,026,639 1,960,369 46,270
25 Income Taxes - Federal (36,066,197)(26,193,416)(6,920,632)(95,147)(1,305,662)(105,370)456,906
26 Income Taxes - Stte (4,379,076)(3,037,259)(1,212,166)(129,653)(177,421)(14,316)62,066
27 Income Taxes - Def Net 46,037,202 24,374,653 16,555,443 3,107,106 2,991,573 115,533
26 Invesment Tax Credit Adj,(221,636)(116,520)(51,379)(53,740)(53,740)
29 Mise Revenue & Expnse (633,171)(556,712)(74,466)29 29
30
31 Total Operating Exns 221,616,661 157,754,260 30,146,691 33,713,710 25,262,354 6,604,646 1,646,510
32
33 Oprating Revenue for Return 41,277.081 23,349,69 10,00,431 7,92,95 7,626,109 69,331 205,517
34
35 Rate Base:
36 Electic Plant in Service 1,310,429,312 69,666,121 296,423,961 314,337,210 306,705,321 5,631,669
37 Plant Held for Future Use 540,062 (540,062)
36 Mise Deferred Debit 5.466,26 3,n6,036 1,402,454 337,777 46,639 (26,606)317,944
39 Elee Plant Aoq Adj 3,469.909 3,469,909
40 Nuclear Fuel
41 Prepayments 2,693,161 1,514.173 513.64 665,324 471,051 4,310 169,963
42 Fuel stock 14.046,799 14,046,799
43 Material & Supplies 11,02,635 9,296,675 71,502 1,656,657 1,656,657
44 Workng Capital 3,631,222 1,975,470 62,120 1,029,632 90,471 99,264 23,897
45 Weatherization Loans 3.161,00 3,161,004 3,181,004
46 Miscellaneous Rate Base 0
47
46 Total Electc Plant 1,35.94,529 734,239,265 296,497,66 321,209,605 311,790,139 5,706,656 3,712,606
49
50 Rate Bas Deductions:
51 Accum Prbv For Depr (407,334,769)(205,316,166)(76,470,150)(125,546,453)(125,263,657)(264,796)
52 Accum Prov For Amort (24,983,346)(12,602,202)(4,365,226)(7,995,919)(4,215,762)(3,760,157)
53 Accum Def Income Taxes (170,126,516)(90,649,045)(35,571,350)(43,706,123)(43,678,243)(27,660)
54 Unamortized ITC (156,324)(63,234)(36,702)(36,366)(38,366)
55 Cusomer Ad for Const (1,166,620)(612,539)(354,081)(354,061)
56 Cusomer Seivice Depoits
57 Mis. Rate Base Deductons (4,476,016)(3,559,160)(446,133)(466,722)(468,n2)
56
59 Total Rate Base Deductons (606.245,59)(312,409,607)(117,n4,102)(176,111,666)(174,016,653)(4,092,633)
60
61 Total Rate Bas 745,700,934 421,629,457 160,773,556 143,097,919 137,771,266 1,613,625 3,712,606
62
63 Return on Rate Bas 5.535%5.635%5535%5.535%5.535%5.535%5.535%
64
65 Return on Equit 5.314%5.314%5314%5.314%5.314%5.314%5.314%
66
67 100 Basis Points in Equit:3,900,016 2,20,166 945,446 746,402 720,544 6,440 19,416
68 Revenue Requirement Impact 6,265,361 3,555,526 1,523,706 1,20,147 1,161,250 13,603 31,295
69 Rate Base Decrease (64,374,333)(36,415,369)(15,605,669)(12,353,254)(11,693,20)(139,317)(320,517)
JAM Dec 2010 IDGRe Tab 2 - Page 1 of28
Description of Acunt Summary'
2010 PROTOCOL~
FERC BUSINESS PITA~DESCRIPTION fI Ee
70 Sales to Ultimate Cusomers
71 440 Residential Sales
72 S
73
74
75
76 442 Commercial & Indusrial Sales
77 S
78 P SE
79 PT SG
80
81
82
83
84 444 Public Street & Highwy Lighting
65 S
86 SO
87
88
89 445 Other Sales to Public Authorit
90 S
91
92
93
94 448 Interdepartmental
95 DPW S
96 GP SO
97
98
99 Total Sate to Ultima Customer.
100
101
102
103 447 Sales for Resle-on NPC
104 P S
105
106
107 447NPC Sales for Resale-NPC
108 P SG
109 P SE
110 P SG
111
112
113 Total Sales for Resale
114
115 449 Provision for Rate Refund
118 P S
117 P SG
118
119
120
121
122 Total Sales from Elecicity
123 450 Forfeited Discounts & Interes
124 CUST S
125 CUST SO
126
127
128 451 Misc Electic Revenue
129 CUST S
130 GP SG
131 GP SO
132
133
134 453 Water Sales
135 P SG
136
137
138 454 Rent of Electric Property
139 DPW S
140 T SG
141 T SG
142 GP SO
143
144
145
146
JAM Oec2010 IOGRe
IDAHO~fi Iw ll ll Bm Ii
IDAHO~~Trasmision plsrlbuion Distribution Bm Mi
(0)(0)0 0 (0)(0)
64.015.913 142.017.36 35.348.390 40.832.037 32.622.686 8.184.851 2.024.500
64.015.913 142.017.362 35.348.390 40.832.037 32.622.686 6.184.851 2.024.50
153.583.988
153.583.988
597.888
597.888
218.197.789 142.017.382 35.34.390 40.832.037 32.622.68 6.184.851 2.024.50
30.864.481 30.864.481
30.86.481 30.86,481
30.864,481 30.864,481
249.062.270 172,881.843 35.34.390 40,832.037 32,62U86 6.184.851 2,024.50
406,930 406,930 406,930
406.930 406.930 406.930
101.005 101.005 101.005
3.337 1._727 950 927 23
104.342 1.660 727 101,954 927 101.027
158 158
158 158
208.736 208.736 208.736
327,879 327.879
201,957 100,464 44,011 57,482 56.114 1.36
738,571 100,46 371,889 26,218 26.850 1.368
Tab 2 - Page 2 0128
Decription of Acnt Summary:
147 456 Other Electric Revenue
148 DMSC S
149 CUST CN
150 OTHSE SE
151 OTHSO SO
152 OTHSGR SG
153
154
155
156
157 Totl Otr Electic Revenun
158
159 Total Elecic Operatng Reve:nun
160
161 Summary of Revenues by Factor
162 S
163 CN
164 SE
165 SO
166 SG
167 DGP
168 0
169 Towl Electc Operating Revenues
170 Miscellaneous Revenues
171 41160 Gain on Sale of Utilit Plant - CR
172 DPW S
173 T SG
174 G SO
175 T SG
176 P SG
177
178
179 41170 Loss on Sale of Utilit Plaii
180 DPW S
181 T SG
182
183
184 4118 Gain from Emission Allownces
185 P S
188 P SE
187
188
189 41181 Gain from Dispoition of NOX Credits
190 P SE
191
192
193 4194 Impact Housing Interes Income
194 P SG
195
196
197 421 (Gain) I Loss on Sate of utilit Plant
198 DPW S
199 T SG
200 T SG
201 PTD CN
202 PTD SO
203 P SG
204
205
206 Total MiscellanUi Reven..
207 Mlsllaneous Exnses
208 4311 Interes on Cusomer Depoit
209 CUST S
210
211 Total MlscelaneUi Expena
212
213 Ne Mlsc Revenue and Expenle
214
215 500 Operation Supervision & Engineering
216 P SG
217 P SG
218
219
220 501 Fuel Related-Non NPC
221 P SE
222 P SE
223 P SE
224 P SE
225 P SE
226
227
JAM Dec 2010 ID GRC
IDAHONi Producon Transmission ll ll B!li
39 39 39
650,127 650,127
27,487 27,487 27,487
11,903,837 8,119,850 3,783,987
12,581,491 8,119,85 4,434,115 27,527 27,527
13,831,492 8,22,132 4,80,731 802,630 265,m 50,325 27,52
262,693,763 181,103,975 40,156,121 41834,667 32,88 463 8,694,177 2,052,27
218,914,500 142,017,36 35,348,390 41,548,747 32,831,422 6,692,786 2,024,539
65,127 650,127
232,781 102,124 44,738 85,919 57,042 1,390 27,487
43,09,355 38,984,489 4,111,86
262,893,763 181,103,975 40,155,121 41,634,667 32,88,463 8,694,177 2,052,027
/523,836 /523,836\
523,836 523,83
(46,119)(46,119)
(28,397)(28.397)
5 2 1 1 1
113 59 26 27 27
134,938 134,938\
1109,336 134,876 74,488 29 29
1633,171 55,712 174,488\29 29
1633,171 155,712\174,48)29 29
1,127,881 1,127,881
109,293 109,293
1,237,174 1,237174
951,786 951,786
214,21&214,215
1,166,00 1,166,00
Tab 2. Page 3 of 28
DecrjPton of Accoynt Summary:
228 501NPC Fuel RelatedNPC
229 P S
230 P SE
231 P SE
232 P SE
233 P SE
234
235
236 Total Fuel Related
237
238 502 Steam Exnses
239 SG
240 SG
241
242
243 503 Steam From Oter Sources-Non-NPC
244 P SE
245
246
247 503NPC Steam From Other Sources-NPC
248 P SE
249
250
251 505 Electric Expnses
252 P SG
253 P SG
254
255
256 50 Misc. Steam Expense
257 P SG
258 P SE
259 P SG
260
251
252 507 Rents
263 P SG
264 P SG
25526
267 510 Maint Supervision & Engineering
268 P SG
269 P SG
270
271
272
273
274 511 Maintenance of Structures
275 P SG
275 P SG
277
278
279 512 Maintenance of Boiler Plant
280 P SG
281 P SG
282
283
284 513 Maintenance of Electric Plant
285 P SG
288 P SG
287
288
289 514 Maintenance of Mis. Steam Plant
290 P SG
291 P SG
292
293
294 Total Stem Power Generation
295 517 Operation Super & Engineering
298 P SG
297
298
299 518 Nuclear Fuel Expense
300 P SE
301
302
303
304 519 Coolant and Water
305 P SG
308
307
308 520 Steam Expenses
309 P SG
310
JAM Dec 2010 ID GRC
IDAHO
Normalized fi Transmission Distributon ll !l MI
41,500,579 41,500.579
3,050,574 3,050,574
44 551,253 44,551.253
45,717,254 45,717,254
1.927,722 1,927,722
423.353 423,353
2,351,075 2,351,075
108 108
108 108
210,87 210,587
210,587 210,587
189,097 189,097
72,829 72,529
251,725 251725
2,856,755 2,856.755
117,033 117,033
2,973,798 2,973,798
20,472 20,472
27 27
20,499 20,499
(111,536)(111,536)
113,902 113,902
2,367 2,367
1,526,293 1,525,293
24,908 24,90
1,551.99 1,551,199
5,550,847 5,550,847
435,867 435,867
7.088,714 7,088,714
2,323,501 2,323,501
47,427 47,427
2,370,927 2,370,927
56,555 563,555
170,159 170,159
733,713 733,713
64,517,140 Cl,517,14O
Tab 2 - Page 4 0128
pecrlDton of Accoynt Summary.
311
312
313
314 523 Electric Expenses
315 P SG
316
317
318 524 Misc. Nuclear Expenss
319 SG
320
321
322 528 Maintenance Super & Engineering
323 P SG
324
325
326 529 Maintenance of structures
327 SG
328
329
330 530 Maintenance of Reactor Plant
331 P SG
332
333
334 531 Maintenance of Electric Plant
335 P SG
336
337
338 532 Maintenance of Misc Nuclear
339 P SG
340
341
342 Total Nuclear Powr Generation
343
344 535 Operaion Super & Engineering
345 P DGP
346 P SG
347 P SG
348
349
350
351 536 Water For Power
352 P DGP
353 P SG
354 P SG
355
356
357
358 537 Hydraulic Exnse
359 P DGP
360 P SG
361 P SG
362
363
364
365 538 Electric Expenses36 P DGP
367 P SG
368 P SG
369
370
371
372 539 Misc. Hydro Expenses
373 P DGP
374 P SG
375 P SG
376
377
378
379
380 540 Rents (Hydro Generaion)
381 P DGP
382 P SG
383 P SG
384
385
386
387 541 Malnt Supetvsion & Engineering
388 P DGP
389 P SG
390 P SG
391
392
393
JAM Dec 2010 ID GRC
IDAHO~~!r Distribution ~B!MI
284,721 284,721
(44.098)(44,098)
240.623 240,623
12,961 12,961
12,961 12961
398,483 398,483
12,365 12,365
410,848 410,848
1,085,843 1,085.843
450,292 450.292
1,536,135 1,536,135
6,857 6,857
47 47
6,90 6,90
29 29
29 29
Tab 2. Page 5 of 28
Decripton of Account Summary:
394 542 Maintenance of Structures
395 DGP
396 SG
397 SG
398
399
400
401
402
403
404 543 Maintenance of Dams & Waterwys
405 P DGP
400 P SG
407 P SG
408
409
410
411 54 Maintenance of Electic Plant
412 P DGP
413 P SG
414 P SG
415
416
417
418 545 Maintenance of Misc. Hyro Plant
419 P DGP
420 P SG
421 P SG
422
423
424
425 Total Hydraulic Power Geeratn
426
427 54 Operation Super & Engineering
428 P SG
429 P SG
430
431
432 547 Fuel-Non-NPC
433 P SE
434 P SE
435
436
437 547NPC Fuel.NPC
438 P SE
439 P SE
440
441
442 548 Generation Expense
443 SG
444 SG
445
446
447 549 Miscellaneous Other
448 P SG
449 P SG
450
451
452
453
454
455 550 Maint Supervion & Engineering
456 P SG
457 P SG
458
459
460 551 Maint Supervision & Engineering
461 P SG
46
463
464 552 Maintenance of Structures
465 P SG
46 P SG
467
468
469 553 Maint of Generaion & Electric Plant
470 P SG
471 P SG
472 P SG
473
474
JAM Dec 2010 IOGRe
IDAHOtl eæ I1 Il Il ll Ml
80,254 80,254
6,938 6,938
87,191 87,191
80,986 80,986
38,840 38,840
119,62 119,62
76,586 78,586
23,692 23,692
100.278 100,278
111,988 111,988
49,569 49,589
161,575 161,575
2.876,189 2676.169
21,708 21,708
21,708 21,708
21.08 21,708
23,931.98 23,931,198
1.353,494 1,353,494
25,284,692 25284,692
813,417 813,417
79,578 79.578
892,995 892.995
211,641 211,641
1,037,408 1,037,408
211,841 211.641
1,820 1.820
213,568 213,568
215,389 215,389
84,146 84,146
11,165 11,165 .
75,311 75,311
587,284 587,284
127,200 127,200
148,679 148,679
863,184 863,164
Tab 2 - Page 6 of 28
DecriDton of Account SummarY"
475 554 Maintenance of Mis. other
476 P SG
477 P SG
478 P SG
479
480
481 Total Othr Power Generation
482
483
484 555 Purchase PowerMNon NPC
485 DMSC S
486
487
488 555NPC Purchased PowerMNPC
489 P SG
490 P SE
491 P SG
492 P DGP
493
494
495 Total Purchased Power
496
497 556 Sysem Control & Load Dispatch
498 P SG
499
500
501
502
503
504 557 Other Expnses
505 P S
506 P SG
507 P SGCT
50s P SE
509 P SG
510 P TRDJP
511
512
513
514 Emb Cos Difla
515 Comy OW Hyd P DGP
516 Comny Ow Hydn: P SG
517 MKf Cora P MC
518 M~Conra P SG
519 ExQFCora P S
520 ExiQFCora P SG
521
522
523
524 Hydro Endowment Fixed Dollar Proposal
525 Klamath Surcharge Sit P S
526 ECDHyro P S
527
528
529 Total Other Powr Supply
530
531 TOTAL PRODUCTION EXPENSE
532
533
534 Summary of Production Expense by Factor
535 S
536 SG
537 SE
538 SNPPH
539 TROJP
540 SGCT
541 DGP
542 DEU
543 DEP
544 SNPPS
545 SNPPO
546 DGU
547 MC
548 SSGCT
549 SSECT
550 SSGC
551 SSGCH
552 SSECH
553 Total Production Exns by Factor
JAM Dec 2010 ID GRC
IDAHO~~Transmission I2 ll I!!i
44,252 44,252
80,586 80.586
8,251 8,251
133,089 133,OS9
28,735,39 28,735,39e
31,340,729 31,340,729
3,680,061 3,680,061
35,020,790 35,020.790
35,020,790 35,020,790
53.68 53.648
53,648 53,648
942,988 942,988
4.030,206 4,03,206
68,196 68,196
5,041,390 5,041,390
(975,961)(975,961)
835,542 835,542
1140,419 140,419
39,97540 39,975,40
135,90113 135,90,113
802,569 802,569
60,140,645 60,140,645
74,89,703 74,892,703
68,196 68,196
135,904,113 135,90,113
Tab 2 - Page 7 0128
Decripton of Acunt Summary:
554 560 Operation Supeivision & Engineering
555 T SG
556
557
558
559 561 Load Dispaching
560 T SG
561
562
563 562 Staon Expnse
564 SG
565
56
567
568 563 Ovrhead Line Exnse
569 SG
570
571
572
573 564 Underground Une Expnse
574 T SG
575
576
577
578 565 Transmision of Electricit by otherson NPC
579 T SG
580 T SE
581
582
583 565NPC Transmission of Electici by othersNPC
584 T SG
585 T SE
586
587
588 Total Transmission Of Electricit by others
589
590 566 Mlsc, Transmission Exns
591 T SG
592
593
594
595 567 Rents - Transission
596 SG
597
598
599
600 568 Maint Supervion & Engineering
601 T SG
602
603
604
605 569 Maintenance of Structures
606 T SG
607
608
609
610 570 Maintenance of Station Equipment
611 T SG
612
613
614
615 571 Maintenance of Overhead Lines
616 SG
617
618
619
620 572 Maintenance of Underground Lines
621 T SG
622
623
624
625 573 Maint of Misc. Transmission Plant
626 T SG
627
628
629
630 TOTAL TRANSMISSION EXPENSE
631
632 Summary of Transmission Exnse by Factor
633 SE
634 SG
635 SNPT
636 Total Transmission Exns by Factor
JAM Dec 2010 ID GRC
IDAHOtl ~Transmission !l Distributon Il MJ
310,186 310,lB6
310,186 310,186
636,971 636,971
636,971 636,971
130,06 130,06
130,062 130,062
7,367 7.367
7,367 7,367
B,225,69 B,225,690
339,395 339,395
B,565,OB5 B.565,OB5
8,565,085 8,565,085
209,688 209.688
209,688 209.688
79,639 79,639
79,639 79,639
82,109 82,109
82,109 82,109
285,959 285,959
285,959 285,959
618,973 618,973
618,973 618,973
1,200,839 1,200.839
1.200.839 1,200,839
2.251 2,251
2.251 2,251
16,560 16,560
16,560 16,560
12.145689 12.145,689
339.395 339.395
11,806,294 11,806,294
12,145,689 12.145,689
Tab 2 - Page 8 0128
Decripton of Account Summary:
637 580 Operaton Supervsion & Engineering
638 DPW S
639 DPW SNPD
640
641
642 581 Load Dispatching
643 DPW S64DPWSNPD
645
64
647 582 Station Expense
648 DPW S
649 DPW SNPD65
651
652 583 Overhead Line Exnss
653 DPW S
654 DPW SNPD
655
858
657 584 Underground Line Expense
658 DPW S
659 DPW SNPD
660
661
662 585 Street lighting & Signal Sysems
663 DPW S66DPWSNPD
665
66
667 586 Meter Expenses
668 DP S
669 DP SNPD
670
671
672 587 Cusomer Insllation Exnses
673 DPW S
674 DPW SNPD
675
676
677 588 Mis. Disribuion Expenses,
678 DPW S
679 DPW SNPD
680
681
682 589 Rents
683 DPW S
684 DPW SNPD
685
686
687 590 Maint Supervsion & Engineering
688 DPW S
689 DPW SNPD
690
691
692 591 Maintenance of Structures
693 DPW S
694 DPW SNPD
695
696
697 592 Maintenance of Station Equipment
698 DPW S
699 DPW SNPD
700
701 593 Maintenance of Overhead Lines
702 DPW S
703 DPW SNPD
704
705
706 594 Maintenance of Underground Lines
707 DPW S
708 DPW SNPD
709
710
711 595 Maintenance of Line Transformers
712 DPW S
713 DPW SNPD
714
715
716 596 Maint of Steet Lighting & Signal Sys.
717 DPW S
718 DPW SNPD
719
720
JAM Dec 2010 ID GRC
IDAHON2 ~Iw ll Il B!!i
(35,716)(35,718)(35,716)
737,084 737,084 737,084
701,368 701,368 701,368
650,047 650 047 650,047
650,047 650,047 650,047
242,261 242,261 242,261
1,127 1,127 1,127
243,389 243,389 243,389
196,818 196,818 196,818
1,705 1,705 1,705
198,522 198,522 198,522
23 23 23
23 23 23
9,911 9,911 9,911
9,911 9,911 9.911
280,532 280.532 280,532
55,953 55.953 55,953
336,485 336.85 336,485
40,58 406.585 406.585
40,585 40,585 406.585
1,164 1,164 1,164
212,373 212.373 212,373
213,537 213537 213,537
12,66 12,866 12,866
3,051 3,051 3,051
15,917 15.917 15,917
53,991 53,991 53.991
221,382 221382 221.382
275,373 275,373 275,373
154,460 154,460 154.460
3,691 3.691 3,691
158,151 158,151 158,151
745,001 745,001 745,001
69,844 69,844 69,64
814,844 814,844 814,84
5,611,197 5,611,197 5,611,197
48.428 48,28 48,28
5,659,624 5,659,624 5,659,624
695,823 695,823 695,823
695,823 695,823 695.23
41,670 41,670 41,670
41,670 41,670 41,670
159.489 159,489 159,489
159,489 159.489 159,489
Tab 2. Page 9 0128
Decription of Açcount Summary'
721 597 Maintenance of Meters
722 DPW S
723 DPW SNPD
724
725
726 599 Maint of Mis. Disribuion Plant
727 DP S
728 DPW SNPD
729
730
731 TOTAl DISTRIBUTION EXPENSE
732
733
734 Summary of Distribution Exnse by Factor
735 S
736 SNPD
737 0
738 Total Distributon Expense by Factor
739
740 901 Supeivision
741 CUST S
742 CUST CN
743
744
745 902 Meter Reading Exnse
746 CUST S
747 CUST CN
746
749
750 903 Customer Receipt & Collections
751 CUST S
752 CUST CN
753
754
755 90 Uncollectible Accounts
756 CUST S
757 P SG
758 CUST CN
759
760
761 90 Mis. Customer Accounts Exns
762 CUST S
763 CUST CN
764
765
766 TOTAL CUSTOMER ACCOUNTS EXPENSE
767
768 Summary of Customer Acct Ex by Factor
769 S
770 CN
771 SG
772 Total Customer Accounts Expense by Factr
773
774 907 Supeivision
775 CUST S
776 CUST CN
777
778
779 908 Customer Asistnce
780 CUST S
781 CUST CN
782
783
784
785
786 909 Informational & Instructional Ad
787 CUST S
788 CUST CN
789
790
791 910 Misc. Cusomer Seivice
792 CUST S
793 CUST CN
794
795
796
797 TOTAL CUSTOMER SERVICE EXPENSE
798
799
800 Summary of Customer Servce Ex by Factor
801 S
802 CN
803 0
804 Total Customer Service Expnse by Factor
JAM Dec 2010 ID GRC
IDAHO~eæ Iw I2 B!I2 !i
307,749 307,749 307,749
51,189 51,189 51,189
358,938 358,938 368,938
44,807 44,807 44,807
33,018 33018 33,018
77,826 77,826 77,826
11017,503 11,17,503 11,017,503
8,877,030 8,877,03 8,877,030
2,140.473 2.140,473 2,140.473
11,017,503 11,017,503 11.017.503
98,179 98,179 98,179
98,179 98,179 98,179
1,714,275 1,714,275 1,714,275
75,516 75,518 75,516
1,789,791 1,789,791 1,789,791
397,577 397,577 397,577
1,663,799 1.663,799 1,663,799
2,261376 2,261,376 2,261,376
504,061 504,061 50.061
3,701 3,701 3,701
507,761 507,761 507,761
6,74 6,74 6,74
6,74 6,74 6,74
4,803,581 4,663,581 4,66,581
2,615,913 2,615,913 2,615,913
2,047,668 2,047,668 2,047.668
4,663,581 4,663,581 466,581
10,413 10.413 10,413
10.413 10.413 10.413
872,856 872,856 872,856
110,230 110,230 110,230
983,066 983,086 983,086
63,693 63,693 63,693
147.490 147.490 147.490
211,183 211,183 211,183
3,90 3,90 3.490
3.490 3,90 3,490
1,208,172 1,20,172 1.08,172
936,550 936,550 936,550
271,623 271,623 271,623
1,208,172 1,208,172 1.08,172
Tab 2. Page 10 of 28
Decripton of Account Summary'
605
606
607 911 Supeivsion
606 CU5T 5
609 CU5T CN
610
611
612 912 Demonstration & Sellng Expense
613 CU5T 5
614 CU5T CN
615
616
617 913 Advertising Exns
616 CU5T 5
619 CU5T CN
620
621
622 916 Misc. Sales Exns
623 CU5T 5
624 CU5T CN
625
626
627 TOTAL SALE5 EXPEN5E
626
629
630 Totl Sales Exns by Factor
631 5
632 CN
633 Total Sales Exnse by Factor
634
635 Total Customer 8ervçe Exp Including Sales
636 920 AdministratiVe & General Salaries
637 PTD 5
636 CU5T CN
639 PTD 50
640
641
642 921 Office Supplies & expnses
643 PTD 5
644 CU5T CN
645 PTD 50
646
647
646 922 Offce Suppies & expenses
649 PTD 5
650 CU5T CN
651 PTD 50
652
653
654 923 Oute Seivices
655 PTD 5
656 CU5T CN
657 PTD 50
656
659
660 924 Propert Insurance
661 PTD 5
862 PTD 5G
663 PTD 50
664
665
666 925 Injuries & Damages
667 PTD 50
866
869
670 926 Employee Pensions & Benefits
671 LABOR 5
672 CU5T CN
673 LAOR 50
674
675
676 927 Franchise Requirements
677 DM5C 5
676 DM5C 50
679
660
661 926 Regulatory Commission Expense
662 DM5C 5
663 CU5T CN
664 DM5C 50
665 FERC 5G
666
667
666 929 Duplicate Charges
669 LAOR 569LAOR50
691
692
JAM Dec 2010 IDGRe
IDAHO~Producton Transmision Distributon Distribution BI MI
1,2.172 .1.208.172 1.20172
(0)(0)(0)(0)(0)
4,534,357 2,363,600 1.051,132 1,099,426 1,09,426
4,534,357 2,363,600 1,051,132 1,099,425 1,099,425
49,229 25,660 11,412 11,936 11,936
532,461 279,925 123.32 129,103 129,103
561,669 305,605 134,644 141,040 141,040
(1,608,30 /645,519\(372,630\/369,959\(389,959\
1.606,309 645,519 372,630 /369,959 369,959\
665,590 360,426 156,930 166,232 166,232
665,590 360,426 156,930 166,232 166,232
66,661 46,611 20.553 21,497 21,497
761,052 410,614 161,060 169,376 169,376
869,714 457,225 201,613 210676 210,676
469,144 246,636 108,755 113,751 113.51
469,144 246,636 106,755 113,751 113751
1.236,151 1.36,151 1,236,151
69,367 69,367 69,367
152,154 61,751 70,404
1,479,673 61,751 70,404 1,327,519 1,327,519
1356,409 152,233 (24,432 179,744\(126,646\53.099\
/356,409 152,233 (24,432 179744 (126,646\53,099\
Tab 2 - Page 11 0128
DecriDtlon of Acunt Summary'
893 930 Mis General Exenses
894 PTD 6
895 CU6T CN
896 P 6G
897 LABOR 60
898
899
90 931 Rents
901 PTD 6
902 PTD 60
903
904
905 935 Maintenance of General Plant
906 G 6
907 CU6T CN
908 G 60
909
910
911 TOTAL ADMINISTRATIVE & GEN EXPENSE
912
913 Summary of A&G Expense by Factor
914 6
915 60
916 6G
917 CN
918 Total A&G Exnse by Factor
919
920 TOTAL O&M EXPEN6E
921 403SP Steam Depreciation
92 P SG
923 P 6G
924 P 6G
925 P 6G
926
927
928 403NP Nuclear Depreciation
929 P 6G
930
931
932 403HP Hydro Depreciation
933 Pre-Merger Pacific P 6G
934 Pre-Merger Utah P 6G
935 Post-Merger Pacific P 6G
936 Post-Merger Utah P 6G
937
938
939 4030P other Producton Depreciation
940 P 6G
941 P 6G
942 P 6G
943 P 6G94
945
946 403TP Transmission Depreciation
947 T 6G
948 T 6G
949 T 6G
950
951
952
953
954 403 Distribution Depreciation
955 360 Land & Land Rights DPW 6
956 361 Structures DPW 6
957 362 Station Equipment DPW 6
958 363 Storage Battery Equipm DPW 6
959 364 Poles & Towrs DPW 6
960 365 OH Conductors DPW 6
961 366 UG Conduit DPW 6
96 367 UGConduetor DPW 6
963 368 Une Trans DPW 696369ServicesDPW6
965 370 Meters DPW 696371ins Cust Prem DPW 6
967 372 Leased Property DPW 6
968 373 Street Lighting DPW 6
969
970
971 403GP General Depreciation
972 G-61TU6 6
973 PT 6G
974 PT 6G
975 P 6E
976 CU6T CN
977 G-SG 6G
978 PTD 60
979 G-6G 6G
980 G-6G 6G
981
982
983 403GVO General Vehicles
984 G-6G 6G
985
986
987 403MP Mining Depreciation
988 6E
989
990
991 403EP Experimental Plant Depreciation
992 P 6G
993 P 6G
994
995 4031 ARO Depreciation
996 P 6
997
JAM Dec 2010 ID GRC
IDAHON!~rransmllllon Il l2 B!li
204.998 107.771 47.522 49.705 49.705
55 55 55
2,795.989 1,194.248 191.867 1,410.074 993.522 416.552
3.001.042 1.302.020 239.188 1,459.834 1.043.227 416807
309,642 162,785 71.780 75,078 75.078
309,642 162.785 71,780 75,078 75,078
1.295.906 30.933 376.569 618,03 583.601 34.802
1,295906 300.933 376.56 618,03 583.01 34,802
11,262,04 4,603,834 2,015,953 4,642,453 2,916,624 396,310 1,327.519
1.492,378 133,652 58.934 1.299.793 61.641 1.238.151
9.528.791 4.341.620 1,866,063 3.321,109 2.833,486 398.256 89.367
240.816 128.36 90.957 21,497 21,497
55 55 55
11,26.040 4,603.634 2.015.953 4.642,453 2.916.624 398.310 1327,519
176,201,09 140,50 747 14,161,642 21,531,709 13,934,127 6,70,06 1,327,519
1.343.986 1.343,98
1.556,404 1.556,404
4.909.651 4,909.651
474.758 474,758
8,284.800 8,284.800
206.246 206.246
60,951 60,951
767,811 767,811
228.581 228,581
1.263.589 1263.589
7,481 7,481
1.28.843 1.928.843
157,431 157,431
4.894.652 4.894.652
6.988,07 6.988.407
678,98 678,498
756.257 756.257
3,799.180 3,799.180
5,233.935 5.233.935
17.794 17.794 17.794
23,017 23,017 23017
633.997 633.997 633.997
2.130,011 2,130,011 2,130.011
969,187 969.187 969,187
162,121 162,121 162.121
482,149 482,149 482.149
1.465,088 1,465,088 1.465,088
540,873 540,873 540.873
446.479 446,79 446.479
7.837 7.637 7,637
29,00 29,400 29.40
6.907.752 6.907,752 6.907.752
756,414 191,66 564,753 56.753
19,874 13.792 6.082
34,755 24,119 10,635
1,437 1,437
65,94 65.94 65.94
364,986 182.371 182.615
798.640 419,860 185,137 193,643 193,643
364 182 182
8.907 4,450 4,456
2.051.322 646.213 580.769 824.341 758,395 65.946
Tab 2 . Page 12 of 28
Decription of Account Summary'
998
999
1000 TOTAL DEPRECIATION EXPENSE
1001 Summary of Amorttion Exense by Factor
1002 S
1003 DGP
1004 DGU
1005 SG
1006 SO
1007 CN
1006 SE
100 SSGeH
1010 SSGeT
1011 Total Depreciation Exnse By Facto
1012
1013 404GP Amort of LT Plant - Capital Lease Gen
1014 I-SITUS S
1015 I-SG SG
1016 PTD SO
1017 P SG
1016 CUST CN
1019 P SG
1020
1021
1022 404SP Amort of L T Plant - Cap Lease Steam
1023 P SG
1024 P SG
1025
102
1027 4041P Amort of LT Plant - Intangible Plant
1026 I-SITUS S
1029 P SE
1030 I-SG SG
1031 PTD SO
1032 CUST CN
1033 I-SG SG
1034 I-SG SG
1035 P SG
1036 I-SG SG
1037 I-SG SG
1036 P SG
1039
1040
1041 404MP Amort of LT Plant - Mining Plant
1042 P SE
1043
1044
1045 40P Am of LT Pla - Ot Plan
1046 P SG
1047
1046
1049
1050 404HP Amortization of other Electric Plant
1051 Pre-Merger Pacific P SG
1052 Pre-Merger Utah P SG
1053 Pos-Merger Plant P SG
1054
1055
1056 Total Amortizaion of Limit Term Plant
1057
1056
1059 405 Amortization of other Electric Plant
1060 GP S
1061
106
1063
106 406 Amortization of Plant Acquisiton Adj
1065 P S
106 P SG
1067 P SG
1066 P SG
1069 P SO
1070
JAM Oec2010 10 GRC
IDAHO~l2ProuctonIil2 !l ~
30.729,60 17.183,00 5,14.703 7.732.092 7.868,147 8S,He
7,684.166 191,662 7,472,504 7,472504
22,199,616 16,761,711 5,37,905
796,640 419,660 165,137 193,643 193,643
65,946 65,946 85,94
1,437 1,437
30,729,604 17.163,009 5,614,703 7,732,092 7,66,147 65,94
67.606 35,543 15.72 16,393 16,393
10,672 10,672 10,672
76,279 35.543 15,672 27,06 16,393 10,672
20,532 564 9,593 10,356 10,356
767 767
593,439 545,041 46,396
625,703 434,066 191,410 200,205 200,205
214,050 214,050 214,050
680,505 625,006 55,499
16,719 17.193 1,527
3.276 3,010 267
(11,984 (11,98)
2,345,00 1,613,705 306,693 424,611 210,560 214050
7,431 7,431
2,809 2.809
10,240 10,240
2,433,528 1,659,466 322,36 451,675 22,953 224,722
334,000 334.00
334,00 334,000
Tab 2 - Page 13 of 28
Description of Accun Summary:
1071 407 Amort of Prop Loses, Unrec Plant. etc
1072 DPW S
1073 OP SO
1074 P SG-P
1075 P SE
1076 P SO
1077 P TROJP
1078
1079
1080 TOTAL AMORTIZTION EXPENSE
1091
1082
1083
1084 Summary of AmortiZation Expense by Factor
1085 5
1086 SE
1087 TROJP
1088 DOP
1089 DGU
1090 SO
1091 SSOCT
1092 SSOCH
1093 SG-
1094 CN
1095 SO
1096 Total Amortization Exnse by Factor
1097 408 Taxes other Than Income
1098 DMSC 5
1099 OP OPS
1100 OP SO
1101 P SE
1102 P SO
1103 DMSC OPRV-ID
1104 OP EXCTAX
1105 OP SO
1106
1107
1108
1109
1110
1111
1112 41140 Deferred Investment Tax Credit - Fed
1113 PTD DOU
1114
1115
1116
1117 41141 Deferred Investent Tax Credit ~ Idaho
1118 PTD DOU
1119
1120
1121
1122 TOTAL DEFERRED ITC
1123
1124
1125 427 Interest on Long-Term Debt
1126 OP S
1127 OP SNP
1126
1129
1130 428 Amortization of Debt Di & Exp
1131 OP SNP
1132
1133
1134 429 Amortization of Premium on Debt
1135 OP SNP
1136
1137
1138 431 Other Interest Exnse
1139 NUTIL OTH
1140 OP SO
1141 OP SNP
1142
1143
1144 432 AFUDC - Borrowed
1145 OP SNP
1146
1147
1148 Total Elecric Interest Deductions for Tax
1149
1150 Non-utilit Portion of Interest
1151 427 NUTIL NUTIL
1152 428 NUTIL NUTIL
1153 429 NUTIL NUTIL
1154 431 NUTIL NUTIL
1155
1156 Total Non-utility Interes
1157
1158 Total Interest Deductions for Tax
1159
1160
1161 419 Interest & Dividends
1162 OP S
JAM Dec 2010 ID GRC
IDAHOl:fæ Transmission ~~l!Ii
(0)(0)
10 0\
2,767,529 1,993,48 322,366 451675 226,953 224,722
20,532 584 9.593 10,356 10,356
767 767
893,311 469,631 207,083 216,597 216,597
(0)(0)
224,722 224,722 224,722
1,628,197 1,522,507 105.90
2,767,529 1,993,488 322,366 451,675 226,953 224,722
6,580,347 3,273,411 1,433,99 1,872,942 1,828,376 44,565
547,023 272,118 119,208 155,697 151,992 3,705
55,764 55,764
7,183,133 3,601,292 1,553,202 2,028,639 1,980,369 46,270
(221,638)(116,520)(51,379)(53,740)(53,740)
221,638 116,520 51,379\53,740 153,740
1221,638 1116,520\151.379\153,740\(53,740\
1,092.182 543,309 238,009 310,B6 303,467 7,397
20,841,041 10,367430 4,541,696 5,931,914 5,790,768 141,146
21,933,223 10,910,739 4,779,706 6,242,776 6,094,235 148,543
347,669 172,949 75,764 98,956 96,601 2,355
347,669 172,949 75,764 98,956 96,801 2,355
(156 (78)(34)(44)(43)11\
156 78 34 (44)(43 1
709,642 353,013 154,64 201,963 197,177 4,808
709,642 353,013 154,64 201,983 197,177 4,806
12,560260 11.273,608\(557,9341 1728,718\1711,379\17,339'
2,560260 1,273,608 557,934 178,718\711.379 17,339
20,430,118 10,163,015 4,452,148 5,814,956 5,676,592 138,363
20,430,118 10,163,015 4,452,148 5,814,955 5,676,592 138,363
Tab 2 - Page 14 of 28
SCHMAT-5ITUS SP SGDPW CIAC
SCHMAT-5NP SNPP TRDJDP SGCT
SCHMAT-5E SEP SGCUST CN
SCHMAT-SO SO
SCHMAT-SNP SNPDDPW BADDEBTP SG
BOOKDEPR SCHMDEXP
1163
1164
1165
1166
1167
1168
1169
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
1226
1227
1228
1229
1230
1231
1232
1233
1234
1235
1236
1237
1238
1239
1240
1241
1242
1243
1244
1245
1246
1247
1248
1249
1250
1251
1252
1253
1254
Decripton of Account Symmary:GP SNP
Total Operating Deductions for Tax
41010 Deferred Income Tax - Federal.DR
GP
P
PT
LABOR
GP
P
PT
P
GP
TAXDEPR
CUST
CUST
P
DPW
41110 Deferred Income Tax - Federal-CR
GP
P
P
GP
PT
DPW
LABOR
PT
CUST
P
BOOKDEPR
P
CUST
GP
TOTAL DEFERRED INCOME TAXES
SCHMAF Additions - Flow ThroughSCHMAF SSCHMAF SNPSCHMAF SO
SCHMAF SE
SCHMAF TROJPSCHMAF SG
SCHMAP Aditions - Permanent
P
P
LABOR
SCHMAP-SO
SCHMAP
BOQKDEPR
SCHMATAddltions - Temporary
TOTAL SCHEDULE - M ADDITONS
SCHMDF Deductions. Flow Through
SCHMDF S
SCHMDF DGP
SCHMDF DGU
SCHMDP Deductions - Permanent
SCHMDP SP SEPTD SNPSCHMDP IBTP SG
SCHMDP-50 SO
JAM DBC 2010 ID GRC
S
TROJD
SG
SO
SNP
SE
SG
SGCT
GPS
TAXEPR
BADDEBT
CN
IBT
SNPD
S
SE
SG
SNP
SG
CIAC
SO
SNPD
CN
SGeT
SCHMDEXP
TROJD
BADDEBT
GPS
S
SE
SNP
SO
SG
SCHMDEX
IDAHO~fæ Transmission Q!Il B!!!
(4.348,752)(2,163,298)(947,683)(1,237,770)(1,208,318)(29,452)
(4,348,752 12,163,298)1947,68). 11.37,770)(1,208,318)129,452;
28,017 13,937 6,105 7,974 7,785 190
1,896 1,316 580
508,286 217,104 34,843 256,339 180,614 75,726
2,579,013 1,282,937 562,021 734,056 716,589 17,466
1,705,978 1,705,978
11.515,411 7,991,551 3,523,860
1,431,415 712,061 311,935 407,419 397,724 9,694
47,683,145 22,809,310 17,348,129 7,525,706 7,361,322 164,384
707 707 707
65,453,868 34,734,193 21,787,473 8,932,201 8,66,034 268,167
(1,673,51)(832,463)(36,680)(476,309)(46,975)(11.333)
(762,69)(762,69)
(32,585)(32,585)
(1,652,689)(82,134)(360.155)(470,399)(459,206)(11,193)
(1,614,336)(1,120,329)(494,007)
(824,06)(824,06)(824,062)
(395.713)(169,020)(27,126)(199,56)(140,612)(58,954)
(168,682)(117,06)(51.619)
(25,881)(25.881)
(12,239,54)(6,477,368)(1 ,934.43)(3,827,734)(3,783,606)(44,129)
(27,025)(27,025)(27,025)
19,416,66 (10,359,540 3,232,031 (5,825,095)5,672,461 (152,634
46,037,202 24,374,653 18.555,43 3,107.106 2,991.573 115,533
6,244 6,244
518,105 224,078 41,288 252,740 181,204 71.536
113,365 17.073)12.112)14.180)14,132);48'
510,984 223,249 39.175 248,560 177,072 71,488
41,014 23.023 1.58 16,133 8,952 1,472 5,710
2,171,364 2,171.64 2,171,384
4,354,797 2,178,769 960.533 1.215,96 1.214,590 906
68,196 68,196
2,00,685 2,00,071 74 541 381 160
4,253,736 4,253,736
1,042,694 174,958 31.543 836,193 142,162 56,718 637,313
444,474 222,377 98,037 124,060 123,968 82
71,210 71,210 71,210
32,250,918 17,067,714 5,097,213 10,085,99 9,969,712 116,278
46,708,109 25,997,645 6,189,257 14,521,007 13,702,359 175,625 64,023
47.219,093 26,221,094 6,228432 14,769,567 13,879,431 247,113 643,023
42,870 42.870
21._11,495 5,069 5,302 5,302
648.830 277,134 44,478 327,218 230,554 96,66
713,565 331,499 49,54 332,520 235,856 96,66
Tab 2 - Paga 15 of 28
1255
1256
1257
1258
1259
1260
1261
1262
1263
1264
126
126
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
1321
1322
1323
1324
1325
1326
1327
1328
1329
1330
1331
1332
1333
1334
1335
1336
1337
1338
Decription of Accnt Summary:
SCHMDT Deductions - Temporary
GP
DPW
SCHMDT-5NP
SCHMDT
P
CUST
P
SCHMDT-5G
SCHMDT-GPS
SCHMDT-SO
TAXDEPR
DPW
TOTAL SCHEDULE - M DEDUCTIONS
TOTAL SCHEDULE - M ADJUSTMENTS
IDAHO
Normalized ~Tratmllslon ll ll !l li
S
BADOEBT
SNP
CN
SG
OGP
SE
SG
GPS
SO
TAXDEPR
SNPD
73,823 36,723 16,087 21,012 20,512 500
6,795,639 3,40,574 1,499,477 1,895.588 1,895,586
1,863 965 611 287 281 6 0
4,99 4,99
4,495,211 4,495,211
30,342,839 30,342,639
3,771,745 3,138,044 278,735 354,_353,040 1,926
1,339,322 590,08 244,980 504,259 497,750 6,09
125,643,975 60,101,999 45,711,915 19,830,061 19,396,912 433,148
172,469,413 102,111,435 47,751,805 22,606,173 22,164,083 442,089 0
173,162,978 102,442,934 47,801,351 22,938,693 22,399,939 538,753 0
(125,963,885 (76,221.641)(41.572,919)(8,169,126)(6,520,508)(291,640)643,02
NOTE: Pose Schedule M amounts increase taxble Income and therefore reduc tax expense.
Negative Schedule M amounts decreas taxable income and therefore increas ta expns
40911 State Income Taxes
PTe
IBT
IBT
P
IBT
TOTAL STATE TAXES
Calculation of Taxble Income:
Operatng Revenues
Operating Deductions:
o & M Exnss
Depreciation Expense
Amortization Expense
Taxes other Than Income
Interes & Dividends (AFUOC-Equity)
Mise Revenue & Expnse
Total Operating Deductions
oter Deductions:
Interest Deductions
Interest on peRBS
Schedule M Adjustments
Income Before State Taxes
state Income Taxes
Total Taxble Income
Tax Rate
Federal Income Tax. Calculated
Adjustment to Calculated Tax:
40910 PMI
40910 PTe
40910
40910
Federal Income Tax
P
P
P
LABOR
TOTAL OPERATING EXPENSES
310 Land and Land Rights
P
P
P
P
P
311 Structures and Improvements
P
P
P
P
312 Boiler Plant Equipment
P
P
P
P
JAM Dec 2010 10 GRC
S
SE
SG
IBT
(4,331,155)(2,989.336)(1,212,166)(129.653)(177.421)(14,318)62,086
(47,923)(47,923)
4,379,076 3,037259 1,212,166 (129,6531 177,4211 14,3161 62,086
262,893763 161,103,975 40,155,121 41,634667 32,888,6.6,69,177 2,052,027
176,201,098 140,507,747 14,161,642 21,531,709 13,934,127 6,270,06 1,327,519
30,729,804 17,183.009 5,814,703 7,732,092 7,66,147 65,946
2,767,529 1,993.88 322,36 451,675 226,953 224,722
7.183,133 3,601,292 1,553,202 2,028,639 1,980,369 48,270
(4.348,752)(2,163,298)(947,683)(1,237,770)(1,206.318)(29,452)
1633171 1558,7121 174,4661 29 29
211.99,641 160,563,526 20.829,742 30,506,373 22,599,305 6,579,549 1,327,519
20.430,118 10,163,015 4.462.148 5,814.955 5,676,592 136,363
(125,963,885)(76.221.641)(41,572,919)(8,169,126)(8,520,506)(291.640)643.22
(95,399,881)(65,844.407)(26.699,687)(2,855.787)(3.907,941)(315,376)1.367.530
14.379.078 13,037.2591 11.212,166)1129,653)1177,421)(14,3181 62.086
91,020,803 62 607,148 125,67,5211 12,726.1341 13,730,521 )13010581 1,305,445
35.00%35.00%35.00%35.00%35.00%35.00%35.00
(31.857,261 )(21,982,502)(8,92,632)(954,147)(1.305,682)(105,370)456,90
(5,636)(5.636)
(4,203,56)(4,203.56)
(1,716)(1,716)
36,068197 26,193,41811 8,920,63211 954,14711 11,305,66211 105,37011 456,906
221,616.661 157,754.280 30,146,691 33,713,710 39.196,461 12,874,910 3,174.029
140,916 140,916
2,106,173 2.106,173
3,407.761 3.407,761
149,420 149,420
5,80,271 5,804,271
14,144,497 14,144,497
19,671,607 19,671,607
18,01,922 18,01,92
3,552,826 3552,826
55,770,852 55,770,852
40,297,865 40,297,865
38,892,730 38,892,730
143,046,294 143,046,294
19,656,916 19,656,916
241,893,805 241,893,805
SE
SG
SO
S
SG
SG
SG
S
SG
SG
SG
SG
SG
SG
SG
SG
SG
Tab 2 - Page 16 of 28
Decription of Accunt Summary'
1339
1340 314 Turboenerator Unit
1341 SG
1342 SG
1343 SG
1344 SG
1345
134
1347 315 Acceory Electric Equipment
1348 P SG
1349 P SG
1350 P SG
1351 P SG
1352
1353
1354
1355
1356 316 Misc Power Plant Equipment
1357 P SG
1358 P SG
1359 P SG
1360 P SG
1361
1362
1363 317 Steam Plant ARO
1364 S
1365
136
1367 SP Unclassified Steam Plant - Acunt 30
1368 P SG
1369
1370
1371
1372 Total Stem Production Plant
1373
1374
1375 Summary of steam Production Plant by Factor
1376 S
1377 DGP
1378 DGU
1379 SG
1380 SSGCH
1381 Total Steam Prouction Plant by Factor
1382 320 Land and Land Right
1383 P SG
1384 P SG
1385
1386
1387 321 Structures and Improvements
1388 P SG
1389 P SG
1390
1391
1392 322 Reactor Plant Equipment
1393 P SG
1394 P SG
1395
1396
1397 323 Turbogenerator Unit
1398 P SG
1399 P SG
1400
1401
1402 324 Land and Land Rights
1403 P SG
1404 P SG
1405
1406
1407 325 Misc. Power Plant Equipment
1408 P SG
1409 P SG
1410
1411
1412
1413 NP Unclassified Nuclear Plant - Ac 300
1414 P SG
1415
1416
1417
1418 Total Nuclea Production Plant
1419
1420
1421
1422 Summary of Nuclear Prouction Plant by Factor
1423 DGP
1424 DGU
1425 SG
1426
1427 Total Nuclear Plant by Factor
1428
JAM Dec 2010 ID GRC
IDAHO
Normalized Transmission Ilfil2 !l MI
8.094.055 8.09.055
8.741.667 8.741.667
33.568.075 33.568.075
3.857644 3.857.644
54.261.442 54.261.442
5.26.66 5.26.662
8.369.05 8.369.056
7.507.048 7.507.048
4033.637 4.033.637
25.176.402 25.176.02
285.415 285,415
307.781 307.781
1.173.782 1.173,782
244.50 244.508
2.011,487 2.011,487
20.847 202.847
202.847 202.847
385.121.105 385.121.105
385.121.105 385.121.05
385.121.105 385.121.105
Tab 2. Page 17 0128
Decripton of Açcount SummarY:
1429 330 Land and Land Rights
1430 Pre-Merger Pacific P SG
1431 Pre-Merger utah P SG
1432 Post-Merger Pacific P SG
1433 Post-Merger Utah P SG
1434
1435
1436 331 Structure and Improvement
1437 Pre~Merger Pacific P SG
1436 Pre-Merger Uth P SG
1439 Pos.Merger Pacific P SG
1440 Post-Merger utah P SG
1441
1442
1443 332 Reseivolrs, Dams & Waterwys
1444 PreMerger Pacifc P SG
1445 Pre-Merger Uth P SG
144 Pos-Merger Pacifc P SG
1447 Pos-Merger utah P SG
1446
1449
1450 333 Water Wheel, Turbines, & Generators
1451 Pre.Merger Pacific P SG
1452 Pre-Merger utah P SG
1453 Post-Merger Pacific P SG
1454 Pos-Merger utah P SG
1455
1456
1457 334 Accssory Electric Equipment
1456 Pre-Merger Pacific P SG
1459 Pre-Merger utah P SG
1460 Pos-Mergr Pacifc P SG
1461 Post-Merger Uth P SG
1462
1463
1464
1465
146 335 Misc. Powr Plant Equipment
1467 Pre. Merger Pacific P SG
1466 Pre.Merger Uth P SG
1469 Post-Merger Pacific P SG
1470 Post-Merger Uth P SG
1471
1472
1473 336 Roads, Railroads & Bridges
1474 Pre-Merger Pacifc P SG
1475 Pre-Merger utah P SG
1476 Pos-Merger Pacific P SG
1477 Pos-Merger utah P SG
1476
1479
1460 337 Hydro Plant ARO
1461 P S
1462
1463
1464 HP Unclassified Hydro Plant - Acct 300
1465 Pre~Merger Pacific P S
1466 Pre-Merger utah P SG
1467 Post-Merger Pacific P SG
1466 P SG
1469
1490
1491 Total Hydraulic Plant
1492
1493 Summary of Hyraulic Plant by Factor
1494 S
1495 SG
1496 DGP
1497 DGU
1496 Total Hydraulic Plant by Factor
1499
1500 340 Land and Land Rights
1501 P SG
1502 P SG
1503 P SG
1504
1505
1506 341 Structures and Improvements
1507 P SG
1506 P SG
1509 P SG
1510 P SG
1511
1512
1513 342 Fuel Holders, Producers & Accesories
1514 P SG
1515 P SG
1516 P SG
1517
1516
JAM Dec 2010 10 GRC
IDAHOI'~Ii ll J1 !!li
642.642 642,642
316,932 316.932
576,626 576,626
40,726 40,726
1561,126 1,561.126
1,265,90 1,265,902
319,589 319,569
4,747,29 4,747,29
495.333 495,333
6,626,113 6,626,113
9,135,619 9,135,619
1,210,915 1,210,915
6,195,159 6,195,159
2,96127 2,96,127
21,506,020 21,506,02
1.694.661 1.694.661
530,696 530,696
2,730,609 2,730,609
1,646,500 1,646,500
6,604,666 6,604,666
26,09 26,090
220,722 22,722
2.19,335 2,719.335
434,366 434,366
3,636,534 3636,534
72,336 72,336
9,60 9,604
60.05 60,05
667 667
142,663 142,663
261.352 261,352
49,602 49.602
616,336 616,336
40,475 40,475
967,967 967,967
41,489,532 41,4,532
41,469.532 41,469,532
41,469,532 41,469,532
1,423,347 1,423,347
326,506 326,506
1.49.655 1,749655
6.24.133 6,524.133
9,697 9,697
2,649,526 2,649,526
256,744 256,744
9,440,302 9,440,302
506,765 50,765
7.344 7.344
136,247 136,247
654,376 65,376
Tab 2. Page 18 0128
OecrlDtpn of Account Summary-
1519 343 Prime Movers
1520 P S
1521 P SG
1522 P SG
1523 P SG
1524 P sa
1525
1526
1527 344 Generators
1528 P S
1529 P SG
1530 P SG
1531 P SG
1532
1533
1534 345 Accssry Electric Plant
1535 SG
1536 SG
1537 SG
1538 SG
1539
1540
1541
1542
1543 346 Mis. Power Plant Equipment
1544 P SG
1545 P SG
1546 P SG
1547
1548
1549 347 Other Production ARO
1550 P S
1551
1552
1553 OP Unclasified other Prod Plant~Acct 300
1554 P S
1555 P sa
1556
1557
1558 Total other Producton Plant
1559
1560 Summary of Other Production Plant by Factor
1561 S
1562 COO
1563 sa
1564 SSGCT
1565 Total of oter Prouction Plant by Factor
156
1567 Exrimental Plant
1568 103 Experimental Plant
1569 SG
1570 Totl Experimental Plant
1571
1572 TOTAL PRODUCTION PLANT
1573 350 Land and Land Right
1574 T SG
1575 T SG
1576 T SG
1577
1578
1579 352 Structures and Improvement
1580 T S
1581 T SG
1582 T SG
1583 T SG
1584
1585
1586 353 Station Equipment
1587 T SG
1588 T SG
1589 T SG
1590
1591
1592 354 Towel' and Fixtures
1593 T SG
1594 T SG
1595 T SG
1596
1597
1598 355 Poles and Fixures
1599 SG
1600 SG
1601 SG
1602
1603
1604 356 Clearing and Grading
1605 T SG
1606 T SG
1607 T SG
1608
1609
JAM Dec 2010 ID GRC
IDAHO!l Transmission~Distrlbuton ~!l Mi
45.66 45,662
109,02,163 109,022,163
39,828.57 39,828,857
3,247.099 3,247099
152,143,781 152,143,781
2,887,070 2,887,070
17,151,574 17,151,574
96,751 96,751
20,999,396 20,999,396
8.127.374 8,127,374
5.894,628 5,894,628
9,477 9,477
176,712 176,712
14,208,191 14,208,191
594,353 594,35
142,227 142,227
715 715
737,295 737,295
1271,442 1271,442\
271,42 1271,442\
199.661,753 199.681,753
199,661,753 199,661,753
199,661,753 199,661,753
626,272.390 626272.39
1,277.962 1,277.962
2.934,971 2,934,971
6,747.804 6,747,804
10,960,736 10,96.736
457.007 457.007
1.098.183 1,098.183
5,880.521 5,880,521
7,435.711 7.435.711
7,724,429 7,724,429
11.276,794 11,276,794
74,123679 74,123,679
93,124,90 93,124,902
9,749.50 9,749,50
7,747,652 7,747,652
20377,662 20,377,662
37,874,819 37,874,819
4,031,992 4.031,992
7.099,775 7,099,775
34,307,820 34,307,820
45,39,587 45,439,587
11.48.101 11,748,101
9.149,605 9,149,605
26.244,261 26,244.261
47,141,96 47.141.966
Tab 2. Pege 19 of 28
Decription of Account Summary:
1610 357 Underground Conduit
1611 T SG
1612 T SG
1613 T SG
1614
1615
1616 358 Underground Conductors
1617 T SG
1618 T SG
1619 T SG
1620
1621
1622 359 Roads and Trails
1623 SG
1624 SG
1625 SG
1626
1627
1628 TP UnclaSsified Trans Plant - Acct 300
1629 T SG
1630
1631
1632 TSO Unclasified Trans Sub Plant - Acct 300
1633 T SG
1634
1635
1636 TOTAL TRANSMISION PLANT
1637 Summary of Transmission Plant by Factor
1638 OGP
1639 DGU
1640 SG
1641 Total Transmision Plant by Factor
1642 360 Land and Land Rights
1643 DPW S
1644
1645
1646 361 Structures and Improvements
1647 OPW
1648
1649
1650 362 Station Equipment
1651 DPW S
1652
1653
1654 363 Storae Battery Equipment
1655 DPW
1656
1657
1658 364 Poles, Towers & Fixures
1659 DPW S
1660
1661
1662 365 OVerhead Conductors
1663 DPW S
1664
1665
1666 366 Underground Conduit
1667 DPW
1668
166
1670
1671
1672
1673 367 Underground Conductors
1674 DPW S
1675
1676
1677 368 Line Transformers
1678 DPW S
1679
1680
1681 369 Servces
1682 DPW S
1683
1684
1665 370 Meters
1686 DPW
1687
1688
1689 371 Installations on Customers' Premis
1690 DPW S
1691
1692
1693 372 Leased Propert
169 DPW S
1695
1696
1697 373 street Lights
1698 DPW S
1699
1700
JAM Dec 2010 10 GRC
IDAHO
Normalized Production Transmission Distribution Il Retil M!-
386 386
5,547 5,547
191,345 191,345
197,278 197,278
65,824 65,824
386,606 386,606
452,430 452,430
112,760 112,760
26,662 26,662
562.589 562,589
702.011 702,011
28,420,936 28,420,936
28,420,936 28,420,936
271,750,376 271,750,376
271,750,376 271,750,376
271,750,376 271,750.376
1,361,267 1,361,267 1,361,267
1,361,267 1,361,267 1,361,267
1,501,905 1.501,90 1,501,905
1,501.905 1,501,905 1,501,905
28,317,005 28,317,005 28,317,005
28,317,005 28,317,005 28,317,005
64,357,54 64.357,54 64,357,546
64,357,546 64 357,546 64,357,546
34,389,397 34,389,397 34,389,397
34,389,397 34,389,397 34,389,397
7,627,151 7,627,151 7,627,151
7,627,151 7,627,151 7,627,151
24,047,021 24,047,521 24,047.521
24,047.521 24,047,521 24,047,521
67,761,455 67,761,455 67,761,455
67.61,455 67,761,455 67,761,455
29,049,197 29,049,197 29,049,197
29,049,197 29,049,197 29,049,197
13,964,243 13,964,243 13,96,243
13,96,243 13,964,243 13,96,243
169.333 169,333 169,333
169 333 169,333 169.333
615,773 615.773 615,773
615,773 615,773 615,773
Tab 2 - Page 20 of 28
Perlptlon of Acunt Summary:
1701 OP Unclassified Dist Plant. Acc 300
1702 OPW S
1703
1704
1705 OSO Unclassifed Dist Sub Plant - Acc 300
1706 OPW S
1707
1708
1709
1710 TOTAL DISTRIBUTION PLANT
1711
1712 Summary of Distribution Plant by Factor
1713 S
1714 0
1715 Total Distribution Plant by Factor
1716 389 Land and Land RIghts
1717 G-ITUS S
1718 CUST CN
1719 PT SG
1720 G-G SG
1721 PTO SO
1722
1723
1724 390 structures and Improvements
1725 G-SITUS S
1726 PT SG
1727 PT SG
1728 CUST CN
1729 G-G SG
1730 PTO SO
1731
1732
1733 391 OffIce Furniture & Equipment
1734 G-SITUS S
1735 PT SG
1736 PT SG
1737 CUST CN
1738 G-SG SG
1739 P SE
1740 PTO SO
1741 G-G SG
1742 G-G SG
1743
1744
1745 392 Transportation Equipment
1746 G-SITUS S
1747 PTO SO
1748 G-G SG
1749 CUST CN
1750 PT SG
1751 P SE
1752 PT SG
1753 G-SG SG
1754 PT SG
1755
1756
1757 393 stores Equipment
1758 G-ITUS S
1759 PT SG
1760 PT SG
1761 PT SO
1762 G-SG SG
1763 PT SG
1764
1765
1766 394 Tools, Shop & Garae Equipment
1767 G-ITUS S
1768 PT SG
1769 G-G SG
1770 PTO SO
1771 P SE
1772 PT SG
1773 G-SG SG
1774 G-G SG
1775
1776
1777 395 Laboratory Equipment
1778 G-ITUS S
1779 PT SG
1780 PT SG
1781 PTO SO
1782 P SE
1783 G-G SG
1784 G-G SG
1785 G-G SG
1786
1787
1788 396 Power Operated Equipment
1789 G-SITUS S
1790 PT SG
1791 G-SG SG
1792 PTO SO
1793 PT SG
1794 P SE
1795 P SG
1796 G-SG SG
1797
JAM Dec 2010 10 GRC
IDAHO~~Transmission l!l!BI MI
1.528.833 1.528.833 1.528833
1.528.833 1.528.833 1.528.833
274,690,626 274,690,626 274,890,626
274.690,626 274,690.625 274,690,626
274,690,626 274,690,626 274,690,625
197,639 50,078 147,561 147,561
43,661 43,661 43,661
20 14 6
74 37 37
324,366 170.626 76.193 78,647 78,647
565,759 170,576 125,314 269,86 22,208 43,661
9,908,95 2.510.635 7,397,860 7,397,860
21,567 14,967 6.00
99,164 68,819 30,346
476.376 476,378 476,376
248.611 124.223 124,388
6,015,39 3,162,407 1,394,458 1,458,525 1.458,525
16,769,603 3370,416 4,06,426 9,332,761 8,856,385 476,376
791.18 200,607 591,111 591.111
63 44 19
320 222 98
329,141 329,141 329,141
290,147 144,977 145,170
5,083 5,083
3,072.344 1,615,191 712.215 744,938 744,938
4.500 2.249 2.252
4493,317 1,767,765 1,060,362 1665,190 1.336,048 329,141
5,073,108 1.285,34 3,787,673 3,787,673
434,346 228,34 100,688 105,314 105.314
1,020,56 509,942 510,623
47,708 33,108 14,599
25,627 25,27
7,280 5,52 2,228
20,820 10,403 10,417
2,703 1,876 827
6.632,157 814353 1,924,817 3.892,987 3,892,987
488,907 123,880 365,027 365.027
6,563 4,554 2,008
21.793 15,124 6,669
21,222 11,157 4,920 5,146 5,146
249.225 124,529 124,696
3,267 2,267 1,00
790,976 157,631 263,172 370172 370,172
1,802.808 456,799 1,34,009 1,346,009
93,670 65,00 28.664
1,255,806 627,484 628.322
228.371 120,059 52,940 55.372 55,372
451 451
107,715 74,753 32,96
103,073 51.502 51.571
5442 2719 2,723
3,597,335 941.973 1,253.981 1,401,381 1,401,381
1,278.273 323,891 954,381 954,381
92 64 28
325 226 99
292,136 153.56 67,722 70,833 70,833
481 481
378,55 189.101 189,354
15.313 7.651 7,662
849 424 425
1,965,924 351,529 589,181 1,025.214 1,025,214
6,965,485 1,764,929 5,200.556 5.200,556
51,150 35,98 15,653
1,889,939 944,339 945,600
65,905 34,648 15,278 15,980 15,980
100,743 89,915 30.829
4,681 4,681
60,515 30.237 30,278
9,138,19 1,119,317 2,802,56 5,216,536 5,216.536
Tab 2 - Page 21 of 28
Decription ofAecount Summary:
1798 397 Communication Equipment
1799 G-SITUS S
1800 PT SG
1801 PT SG
1802 PTD SO
1803 CUST CN
1804 G-SG SG
1805 P SE
1806 G-G SG
1807 G-G SG
1808
1809
1810 398 Misc. Equipment
1811 G-SITUS S
1812 PT SG
1813 PT SG
1814 CUST CN
1815 PTD SO
1816 P SE
1817 G-SG SG
1816 G-SG SG
1819
1820
1821 399 Coal Mine
1822 SE
1823 MP Unckassifed Mine Plant SE
1824
1825
1826 399L WIDCO Capital Lease
1827 P SE
1828
1829
1830 Remove Capital Leass
1831
1832
1833 1011390 General Capitl Leases
1834 G-ITU5 5
1835 P 5G
1836 PTD 50
1837
1838
1839 Remove Capial Leass
1840
1841
1842 1011346 General Gas Line Capital Leases
1843 P 5G
1844
1845
1846 Remove Capital Leases
1847
1848
1849 GP Unclassifed Gen Plant - Ac 300
1850 G-51TU5 5
1851 PTD SO
1852 CU5T CN
1853 G-G SG
1854 PT SG
1855 PT 5G
1856
1857
1858 399G Unclasified Gen Plant - Acc 300
1859 G-SITU5 5
1860 PTD 50
1861 G-5G 5G
1862 PT 5G
1863 PT 5G
1864
1865
1866 TOTAL GENERA PLA
1867
1868 Summary of General Plant by Factor
1869 5
1870 DGP
1871 DGU
1872 SG
1873 50
1874 SE
1875 CN
1876 DEU
1877 55GCT
1878 SSGCH
1879 Les Capital Leases
1880 Total General Plant by Factor
1881 301 Organiztion
1882 I-SITUS 5
1883 PTD SO
1884 1-5G 5G
1885
1886 302 Franchis & Consent
1887 1-SITU5 5
1888 1-5G 5G
1889 1-5G SG
1890 1-5G SG
1891 P SG
1892 P SG
1893
1894
JAM Dec 2010 ID GRC
IDAHOt:I2~Transmission Il Il Ii
6,700,875 1,697,881 5,002,994 5,002,994
122,098 84.735 37,364
165,580 114,910 50,670
2,884,974 1,516,887 668,760 699,507 699,507
110,239 110,239 110,239
5,62,706 2,811,476 2,815,231
8,043 8,043
36,66 18,331 18,355
96 48 48
15,655,299 4,554,230 5,288.329 5,812,740 5,702,501 110,239
64,352 16,306 48,047 48,047
8,183 8,183 8,183
191,558 100,706 44.406 46.446 46,446
106 106
116,121 58,02 58,099
360,320 158 833 118,811 102,676 94,493 8,183
30,818,280 30,818,280
30,818,280 30,818,280
1,02.00 1,02,00
733,786 385,766 170,103 177,918 177,916
1,759,792 1,411.771 170,103 177,918 177,918
11,759,792 11.411,771)(170103)177,918 177918
38,969 20.487 9.034 9,449 9,449
38,969 20,487 9,034 9.449 9,449
90,846,351 44,245,391 17 501,992 29,09,975 28,131,374 967,501
33.271,660 8,430,442 24,841.219 24,841,219
13,200,770 7,274,852 5,925,918
14.303,366 7,519,557 3,315,735 3,468,074 3,468,074
30.86,752 30.86,752
967,601 967,601 967.601
11,759,792 11,411,771)1170,103)1177,918)1177,918)
90,846,357 44,245,391 17,501,992 29.098,975 28,131,374 967,601
1,00,00 28,22 467,205 504.374 504,374
724,247 665,182 59,06
10,508,837 9,651,789 857,048
559,295 513,682 45,613
36,375 36,375
12,828,755 10,895,449 1,428,932 504,374 50,374
Tab 2. Page 22 of 28
Decription of Acunt Summary:
1895 303 Miscellaneous Intangible Plant
1896 I-SITUS 5
1897 I-SG SG
1898 PTD SO
1899 P SE
1900 CUST CN
1901 P SG
1902 P SG
1903
190 303 Less Non-utlity Plant
1905 I-SITUS 5
190
1907 IP Unclassified Intangible Plant. Ac 300
1908 I.SITUS 5
1909 I-SG SG
1910 P SG
1911 PTD SO
1912
1913
1914 TOTAL INTANGIBLE PLANT
1915
1916 Summary of Intangible Plant by Factor
1917 5
1918 DOP
1919 DOU
1920 SG
1921 SO
1922 CN
1923 SSGCT
1924 SSGCH
1925 SE
1926 Total Intangible Plant by Factor
1927 Summary of Unclasified Plant (Account 106)
1928 DP
1929 050
1930 GP
1931 HP
1932 NP
1933 OP
1934 TP
1935 TSO
1936 IP
1937 MP
1938 SP
1939 Total Unclasified Plant by Factor
1940
1941 TOTAL ELECTRIC PLANT IN SERVICE
1942 Summary of ElectrIc Plant by Factor
1943 5
194 SE
1945 DGU
1946 DGP
1947 SG
1948 SO
1949 CN
1950 DEU
1951 SSGCH
1952 SSGCT
1953 Less Capital Leases
1954
1955 105 Plant Held For Future Use
1956 DPW S
1957 P SG
1958 T SG
1959 P SG
1960 P SE
1961 G SG
1962
1963
196
196
196 114 Electc Plant Acquisition Adjustment
1967 P 5
1968 P SG
196 P SG
1970
1971
1972 115 Accum Provision for Ast Acquisition Adjustents
1973 P S
1974 P SG
1975 P SG
1976
1977
1978 120 Nuclear Fuel
1979 p SE
1980
1981
1982 124 WeatherIzaion
1983 DMSC 5
1984 DMSC SO
1985
1966
1987 182W Weatherizaion
1988 DMSC 5
1969 DMSC SG
1990 DMSC SoeT
1991 DMSC SO
1992
1993
1994 186W Weatherization
1995 DMSC 5
1996 DMSC CN
1997 DMSC CNP
1998 DMSC SG
1999 DMSC SO
JAM Dec 2010 ID GRC
IDAHOlW ~I!Q!Plstrlbulon ß!Ml
427,593 12,153 199,773 215,667 215,667
7,435,844 6,829,414 606,430
21,294,906 11,195,146 4,936,479 5,163,281 5,163,281
218,178 218.178
4,66.288 4,66,288 4,66,288
34,040,810 18,254,891 5,742,682 10043,236 5,378,948 4,66,288
34,040,810 18,254,891 5,742,682 10,043,236 5,378,948 4664,288
46.889,56 29.150,i.7.171,614 10.547,610 5.883.322 4,66.288
1,427,593 40.575 66,978 720,040 720,040
19,26,599 17,696,442 1,568,157
21,294,90 11,195,146 4,936,479 5,163,281 5,163,281
4,664,288 4,66,288 4,66,288
218,178 218,178
46,869,56 29,150.340 7,171,614 10,547,610 5,883,322 4,66,288
1,528,833 1,528,833 1,528,833
38,969 20,487 9,034 9,449 9,449
(271,442)(271,442)
28,420,936 28,420,936
202,847 202,847
29.920,142 48,1091 28.429,970 1,538,281 1,538.281
1.310.429 312 699.66.121 296,423.981 314.337,210 306.705,321 5,631.869
309,389,876 40,575 9,097,419 300,251,884 300,251,884
31.080,931 31,080,931
930,488,134 651,243,684 279,244,450
35,596,272 18,714,703 8,252,214 8.31.55 8,631,355
5.631,889 5,631,889 5,631,889
11,759,792 11,411,7711 1170,1031 1177,9181 1177,918)
1.10,429,312 699,66,121 296,423,981 314,337,210 308,705,321 5,631,889
(540,082)(540,082)
540,082 540,082
540,082 1540,082
8,752,799 8,752,799
881,286 881,286
9.634,085 9,634.085
(5,384,131)(5,384,131)
1780,046 1780,04)
6,164,177 6,164,177
18,688 18,688 18,688
1258 (258)1258118.30 18,430 18,430
3,162,575 3,162,575 3,162,575
3,162,575 3,162,575 3,162,575
Tab 2 - Page 23 of 28
Decription of Account SummarY:
2000
2001
2002 Total Weatherization
2003
200 151 Fuel stock
2005 P DEU
2006 P SE
2007 P SE
2008 P SE
2009
2010
2011 152 Fuel stock - Undistributed
2012 P SE
2013
2014
2015 25316 DG&T Working Capital Depoit
2016 P SE
2017
2018
2019 25317 DG& T Working Capital Deposit
2020 P SE
2021
2022
2023 25319 Provo Working Capital Depoit
2024 P SE
2025
2026
2027 Total Fuel Stock
2028 154 Materials and Supplies
2029 MSS S
2030 MSS SG
2031 MSS SE
2032 MSS SO
2033 MSS SG
2034 MSS SG
2035 MSS SNPD
2036 MSS SG
2037 MSS SG
2038 MSS SG
2039 MSS SG
2040 MSS SG
2041 MSS SG
2042
2043
2044 163 Stores Exnse Undistributed
2045 MSS SO
2046
2047
2048
2049 25318 Provo Working Capital Depoit
2050 MSS SG
2051
2052
2053
2054 Total Materials & Suppies
2055
2056 165 Prepayments
2057 DMSC S
2058 GP GPS
2059 PT SG
2060 P SE
2061 PTD SO
2062
2063
2064 182M Misc Regulatory Asets
2065 DDS2 S
2066 DEFSG SG
2067 P SGCT
2068 DEFSG SG-
2069 P SE
2070 P SG
2071 DDS02 SO
2072
2073
2074 186M Mis Deferre Debit
2075 LAOR S
2076 P SG
2077 P SG
2078 DEFSG SG
2079 LAOR SO
2080 P SE
2081 P SG
2082 GP EXCTAX
2083
2084
2085 Workng Capital
2086 CWC Cash Working Capital
2087 CWC S
2088 CWC SO
2089 CWC SE
2090
JAM Oec2010 IOGRe
IDAHO
Normalize Producon Transmission Dlalrlbuton D1trlbuton Ralll Mlae
3.181.04 3,181,004 3,181,004
13,705,778 13,705,778
64,399 645,399
14,351,177 14,351,177
1176,090 1176,090\
176,090 1176,090\
128,288 '128,288\
128,288 '128,288\
14,04,799 14,04,799
5,02,573 4,234,509 32,56 755,496 755,496
281,870 237,644 1,828 42,399 42,399
283,941 239,389 1,841 42.10 42,710
12,762 10,759 83 1,920 1.920
5,140.321 4.333,782 33.332 773,208 773,208
(113)(95)(1)(17)(17)
(116,875)(98,37)(758)(17.580)(17.580)
418,879 353,155 2,716 63,008 63,008
11,043,359 9,310,606 71,610 1,661,143 1,661,143
(16,523)(13,931)(107)(2,485)(2,485)
116,523 13,931 1107 2,485)2,485
11.02,835 9,296,675 71,502 1,658,657 1,658,657
189,963 189,963 189,963
636,403 316,581 138,686 181,137 176,27 4,310
306,192 212,494 93,699
347,155 347,155
1,213,467 637,943 281300 294,224 294,224
2,693,181 1,514.173 513,684 665,324 471,051 4,310 189,963
(177,874)(159,032)584 (19,426)4,487 (28,821)4,90
448,960 448,960
186,749 115,941 70,809
480,727 116,224 7,353 357,151 44,115 313,036
938,563 522,093 78,745 337,725 48.602 28,821\317,944
3,491,104 2,167,402 1,323,702
103 44 7 52 37 15
1,038,498 1.038,498
4,529,705 3,205,94 1,323709 52 37 15
1,849,812 1,486,693 72,240 290,879 186,763 80,220 23,897
1,849,812 1,486,693 72,240 290.879 186,763 80,220 23,897
Tab 2. Page 24 of 28
Decripton 01 Account Summary'
2091
2092 OWC Other Working Capltal
2093 131 Cash GP SNP
2094 135 Working Funds GP SG
2095 141 Notes Receivable GP SO
2096 143 other Accounts Receivabl GP SO
2097 232 Accounts Payabl PTD S
2098 232 Accounts Payable PTD SO
2099 232 Acunt Payable P SE
2100 232 Accunt Payable P SG
2101 2533 other Deferred Creit ~ ~ P S
2102 2533 other Deferred Credits ~ F\ P SE
2103 230 Aset Retirement Obligatii P SE
2104 230 Aset Retirement Obligati. P S
2105 254105 ARO Regulatory liabilit P S
2106 254105 ARC Regulatory liabilit P SE
2107 2533 Cholla Reclamation P SE
2108
2109
2110 Total Working Capital
2111 Miscellaneous Rate Bas
2112 18221 Unrec Plant & Reg Study Cos
2113 P S
2114
2115
2116
2117 1822 Nuclear Plant - Trojan
2118 P S
2119 P TROJP
2120 P TROJD
2121
2122
2123
2124
2125 1869 Mis Deferred DebitTrojan
2126 P S
2127 P SG
2128
2129
2130 TOTAl MISCELLAEOUS RATE BASE
2131
2132 TOTAL RATE BASE ADDITONS
2133 235 Customer Servce Deposit
2134 CUST S
2135 CUST CN
2136
2137
2138 2281 Prov for Propert Insuranc PTD SO
2139 2282 Proii for Injuries & Damag PTD SO
2140 2283 Proii for Pensions and Bei PTO SO
2141 2283 Proii for Pensons and Bei PTO S
2142 254 Reg Liabilities PTD SE
2143 254 Reg Liabilities - Insurance PTO SO
2144
2145
2146 22841 Accum Mis Oper Proviions ~ other
2147 P S
2148 P SG
2149
2150
2151 22842 Accum Misc Oper Proii~ Tr P TROJD
2152 230 Ast RetlrementObllgali, P TROJP
2153 254105 ARC Regulatory Liabilit P TROJP
2154 254 P S
2155
2156
2157 252 Customer Adnces for Consruction
2158 DPW S
2159 DPW SE
2160 T SG
2161 DPW SO
2162 CUST CN
2163
2164
2165 25398 502 Emissions
2166 SE
2167
2168
2169 25399 Other Deferred Credit
2170 P S
2171 LABOR SO
2172 P SG
2173 P SE
2174
2175
2176 190 Accumulated Deferred Income Taxes
2177 P S
2178 CUST CN
2179 P IBT
2180 LABOR SO
2181 P DGP
2182 CUST BADDEBT
2183 P TROJD
2184 P SG
2185 P SE
2186 PTD SNP
2187 DPW SNPD
2188 P SG
2189
JAM Dec 2010 10 GRC
IDAHOJl !!QI ll Bt~Ml
2,812.045 1,39,859 612,803 800,383 781,338 19,045
(254,181)(133,628)(58,923)(61,630)(61,630)
(139,670)(139,670)
(8,857)(8,857)
(411,971)(411,971)
(160,334)(160,334)- .
(55,622)(55.22)
1,781,409 488,777 553,880 738.752 719,708 19,045
3,631,22 1,975,470 626,120 1,029,632 906,471 99,264 23,897
-
0 0
0 0
0 0
0 0
43,517,217 34571,144 2,073,879 8,872,395 3,084,818 74,789 3,712,B0
(492,453)(258,892)(114,158)(119,403)(119,403)
(1,440,698)(757,403)(333,975)(349,320)(349,320)
11,933,151 1,016,295 448,133 468,722 468,722
90,787 90,787
90,787 190,787
(103,149)(103,149)
(214,147)(214,147)
317296 317,296
(354,081)(354,081)(354,081)
(812,539)(812,539)
1,166,820 812,539 354,081 1354,081
11.71,507 11,571,507)
1.571,507 1,571507
(74,947)(74,947)
(462,401)(462,401)
125,927 125,927)
563,274 56,274)
(1)(1)
1.827 1,827 1,827
4,097,253 1.50,056 280,869 2,06,328 1,455,911 610,417
208,183 208,183 208,183
164,227 164,227
(668,137)(668,137)
83,150 83,150 83,150
3.86,502 1,246,145 280,869 2,359,488 1,539,061 820,428
Tab 2 . Page 25 of 28
Decripton of Accunt Symmary'
2190
2191 281 Accumulated Deferred Income Taxes
2192 P S
2193 PT SG
2194 T SNPT
2195
2196
2197 282 Accumulated Deferred Income Taxes
2198 GP S
2199 ACCMOIT OITBAL
2200 P SG
221 P SG
2202 IBT IBT
2203 LAR SO
2204 CUST CN
2205 P SE
2206 P SG
2207
2208
2209 283 Accumulated Deferred Income Taxes
2210 GP S
2211 P SG
2212 P SE
2213 LAOR SO
2214 GP GPS
2215 PTO SNP
2218 P TROJO
2217 P SG
2218 P SGCT
2219 P 5G
2220
2221
2222 TOTAL ACCUMULATEO OEF INCOME TAX
223 255 Acumulated Investment Tax Credit
224 PTD 5
225 PTO ITC8422PTOITC85
2227 PTO ITC86
2228 PTO ITC88
2229 PTD ITC89
2230 PTD ITC90
2231 PTD 50
2232
2233
2234 TOTAL RATE BASE DEDUCTIONS
2235
2236
2237
2238 1085P Steam Prod Plant Accmulated Depr
2239 P 5
2240 P SG
2241 P SG
2242 P SG
2243 P SG
2244 P SG
2245
2246
2247 108NP Nuclear Prod Plant Accumulated Depr
2248 P SG
2249 P SG
2250 P SG
2251
222
2253
2254 108HP Hyraulic Prod PlantAcem Depr
2255 P S
2258 Pre~Merger Pacific P 5G
2257 Pre-Merger Uth P 5G
2258 Post-Merger Pacific P SG
2259 Post~Merger Uth P 5G
2260
2261
2262 1080P Other Production Plant - Accum Depr
2263 P S
2264 P SG
2265 P SG
2266 P SG
2267 P SG
2268
2269
2270 108EP Exerimental Plant - Accum Depr
2271 P SG
2272 P SG
2273
2274
2275 TOTAL PRODUCTION PLANT DEPRECIATION
2276
2277 Summary of Prod Plant Depreciation by Factor
2278 5
2279 OGP
2280 OGU
2281 5G
2282 SSGCH
2283 SSGCT
2284 Total of Prod Plant Depreciation by Factor
2285
2286
2287 106TP Transission Plant Acumulated Depr
2288 T SG
2289 T SG
2290 T SG
2291 TOTAL TRANS PLA ACCUM DEPR
JAM Dec 2010 ID GRC
IDAHO~~Transmission Distributon Distributon Il li
(164.376,500)(81,769,517)(35,821,059)(46,785,923)(45,672,682)(1,113,242)
1,881.419 803,609 128,972 948,838 668,540 280,298
(715.916)(715,916)
18,802,594 18,802,594)
1172,013,591 90,484,418 135,692,067 45,837,086)45,004,142 832,944
(11,991)(5,965)(2,613)(3,413)(3,332)(81)
(577,172)(577,172)
(476,064)(476,064)
(82,957)(35,434)(5,687)(41,837)129,478)(12,359)
(431,567)(214,684)(94.048)(122,836)(119,913)(2,923)
(249,273)(131,047)(57.785)(60,440)(60.440)
(170,385)(170,385)
1,999,430 1,610,772 160,133 (226.26)213,162 15,363'
1170,126,516 190,849,045 /35571.50 43,706.123)43,678,243 27,880'
(40,145)(21,105)(9,306)(9,734)(9,734)
1118,179 /62,129 127396 28,654)128,654)
/158,324 /83,234 36,702 38,388 38.388)
/175,927.478 194.491.43)136.866.724)144.567.314)144.539,434)127 880)
(48,667,229)(48,667,229)
(56,395,537)(56,395,537)
(36,977,231)(36,977,231)
(9,979.440 9,979,440
152,019,438 /152,019,438
(9,272.408)(9,272,408)
(1,791.056)(1,791,056)
(3,590,917)(3,690,917)
11,035,914 /1,035,914)
15,790,295 15,790295
(90,769)(90,769)
(11,325.139)(11.325,139)
(10.846,745)(10,846.745)/1,239,552 /1,239,552)
23,502204 23,502,204
1191.311,937)/191.311,9371
(191,311,937)(191,311,937)
191,311,937 1191,311.937
(23,060,758)(23,060,758)
(24,106,477)(24,106,477
123,979,241 /23,979.241'
1.148.477 1.148,477
Tab 2 . Page 26 of 28
Decripton of Account Summar:
2292 108360 Land and Land Rights
2293 DPW 5
2294
2295
2296 108361 Structures and Improvements
2297 DPW 5
2298
2299
2300 108362 Sttion Equipment
2301 DPW 5
2302
2303
2304 108363 Storage Batery Equipment
2305 DPW 5
2306
2307
2308 10836 Poles, Towl' & Fixure
2309 DPW
2310
2311
2312 108365 Overhead Conductors
2313 DPW 5
2314
2315
2316 108366 Underground Conduit
2317 DPW 5
2318
2319
2320 108367 Underground Conductors
2321 DPW 5
2322
2323
2324 108368 Line Transformers
2325 DPW 5
2326
2327
2328 108369 Seivices
2329 DPW
2330
2331
2332 108370 Meters
2333 DPW 5
2334
2335
2336
2337
2338 108371 Instllations on Cusomers' Premises
2339 DPW 5
2340
2341
2342 108372 Leased Propert
2343 DP 523
2345
2346 108373 Street Lights
2347 DPW 5
2348
2349
2350 108DOO Unclasified Dis Plant. Acct 300
2351 DPW
2352
2353
2354 108D5 Unclasified Om Sub Plant. Acct 300
2355 DPW
2356
2357
2358 108DP Unclasified Dis Sub Plant - Acct 300
2359 DPW 5
2360
2361
2362
2363 TOTAL DISTRIBUTION PLAT DEPR
236
2365 Summary of Distibution Plant Depr by Factr
236 5
2367 0
2368 Totell Disribuion Depreciaton by Factor
2369 108GP General Plant Accumulated Depr
2370 G-51TU5 5
2371 PT 5G
2372 PT 5G
2373 G-G 5G
2374 CU5T CN
2375 PTD 50
2376 P 5E
2377 G-G 5G
2378 G-G 5G
2379
2380
2381
2382 108MP Mining Plant Acumulated Depr.
2383 P 5
2384 P 5E
2385
2386 108MP Less Centralia Sit Depreciation
2387 P
2388
2389
2390 1081390 Accum Oepr - Capil Lease
2391 PTD 50
2392
2393
2394 Remove Capital Leases
2395
JAM Dec 2010 ID GRC
IDAHO~fi Ii !2!2 I!ti
1450,676 1450,676\1450,676\
450,676 450,6761 450,676
1462,122 1462,122 462,122
462,122 462,1221 462,122
9,454 209 19,454,2091 9,454,209
9,454,209 9,454,209 9,454,209
136,466,247 136,466,247\136,466,2471
36,46,247 36,466,247)36,466 247
111,327,454 111,327,454)111,327,454)
11327,454 11,327,454)11,327,454
13,363,20 13,363,20\13,363,20)
3,363,206 13,363,206\3,363,206
111,110,381 111,110,381)111,110.381)
11.10,381 11,110,3811 11,110,381
23,947,556 123.947,556\123947,556\
23,947,556 23,947.55 23,947,556\
10,855,515 110,855,515\110,855,515\
10,855,515 10,855.515 10,855,515\
/8,402,334 /8,402,334)18,402,334\
/8,402,334 /8,402,334 8,402,334\
1137,063 137,063\1137,0631
1137,06 137,06 1137,0631
1486,169 1486,169 1486,169\
1486,169 486,169 1486,169\
7,572 7,572 7,572
7,572 7,572 7,572
(116,455,361 1116,455,361 116,455,361\
(116,55,361)(116,55,361 )(116,455,361)
116,55,361 116,455,361 116,455,361
(10,443,557)(2,64,210)(7,797,347)(7,797,347)
(197,362)(136,967)(60.395)
(342,875)(237,951)(104.924)
(2,972,175)(1,485,09)(1,487,079)
(284,796)(284,796)(284,796)
(4,169,454)(2,191,963)(96,542)11,010,949)(1,010,949)
(21,228)(21,228)
(2,452)(1,225)(1,227)
114,516 57,220\157,296
18,548,414 4,131,649\5,323.673 9.093,092 18,808,296 264796
9,872,581 19,872,581\
9,872,581 9,872,581\
9,872,581 19,872,581\
Tab 2 - Page 27 of 28
Decription of Account Summary:
2396
2397 1081399 Accum Depr - Capitl Leas
2398 P S
2399 P SE
2400
2401
2402 Remove Capital Leases
2403
2404
2405
2406 TOTAL GENERAL PLANT ACCUM DEPR
2407
2408
2409
2410 Summary of General Depreciation by Factor
2411 S
2412 DOP
2413 DGU
2414 SE
2415 SO
2416 CN
2417 SO
2418 DEU
2419 SSOCT
2420 SSOCH
2421 Remove Capital Leass
2422 Total General Depreciation by Factor
2423
2424
2425 TOTAL ACCUM DEPR - PLANT IN SERVICE
2426 111SP Accum Prov for Amort-Steam
2427 P SO
2428 P SO
2429
2430
2431
2432 1110P Accm Prov for Amort-General
2433 G-SITUS S
2434 CUST CN
2435 I-SO SO
2436 PTD SO
2437 P SE
2438
2439
2440
2441 111HP Accum Prov for Amort-Hydro
2442 Pre-Merger Pacific P SO
2443 Pre-Merger Utah P SO
2444 Pos-Merger Pacifc P SO
2445 Pos-Merger Utah P SO
2446
2447
2448
2449 L111P Accum Prov for Amort-Intangible Plant
2450 I-SITUS S
2451 P SO
2452 P SO
2453 P SE
2454 I-SO SO
2455 I-SO SO
2456 I-SO SO
2457 CUST CN
2458 P SO
2459 P SO
2460 PTD SO
2461
2462 L111P Les Non-Utilty Plant
2463 NUTIL OTH
2464
2465
2466 111390 Accum Amtr - Capital Lease
2467 G-ITUS S
2468 P SO
2469 PTD SO
2470
2471
2472 Rem capit Le Amr
2473
2474 TOTAL ACCUM PROV FOR AMORTIZTION
2475 Year-End
2476
2477
2478
2479 Summary of Amortization by Factor
2480 S
2481 DOP
2482 DOU
2483 SE
2484 SO
2485 CN
2488 SSOCT
2487 SSOCH
2488 SO
2489 Less Capital Leas
2490 Total Provision For Amortization by Factor
JAM Dec 2010 ID GRC
IDAHO~Producton Transmission Distribuon ~B!MJ
128.42.995 114.00.221 15.323.873)~9,93.92)18.80.29)1284798\
110.443.557)(2.64.210)(7,797.347)(7,797.347)
19.893.808)19,893.808)
14.169.454)(2,191.96)(96.542)11.010.949)(1.010.949)
(284.796)(284.796)(284.96)
(3.629.379)(1.918,58)(1.10.921)
28,20,995 14.004.229 5.323.673 9.093.092 8,808.296 284.796\
1407.334.769 1205 316.1661 176.470.150)1125.48,4531 (125,23,857)1284.798\
1105.410)1105.410)(105,10)
(624.332)(328.223)(144,730)(151.379)(151,379)
1729.742 328.223 144.730 256.789 (151.79)(105.410\
(8.215)(8.215)
(26.452 (26.452)
34,667 (34.667
(756,698)(21.507)1353.533)(381.658)(381.658)
(21,147)(21.147)
(82,433)(82.433)
(2.928,48)(2.689.648)(238.832)
(1.352.339)(1.242.04)1110.29)
(207,061)(190.174)116.887)
(3.674,748)(3.674.748)(3.674.748)
(7.386)(7.386)
115.188.649 7.984.968\3.520.957)13,682.724)(3.682.724\
(24.218,939)(12.239.311)(4.240.498)17.739.130)(4.06.383)(3.674,748)
24.218,939 12.239.311 4.240.498 (7,739.130 (4.06 383)(3.674,748\
(102.95)-10294.3895
77.650 40822 18.001 18.828 18.828
25.304 162.132 18.001 18,28 18,28
25.304 62.132 118.001 18,28 18.828\
24,98.348 112,802.202 4.385.228 17,995.9191 (4.215.7621 13,780,1571
(756,696)(21.507)(353.533)(381.658)(381,658)
182,433)(82.433)
(15.735,330)(8.272.369)(3.647.686)(3.815.276)(3.815,276)
(3.780.157)(3,780.157)(3.780.157)
(4.654,034)(4.288.02)(366,009)
25,304 62.132 118,001 18,828\18,828\
24.983,348 112.802.202 4.385,228 17.995,919 4.215.762\13,780.157\
Tab 2 - Page 28 of 28
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