20050118Taylor Exhibits Part II.pdf

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Exhibit No. 24
CASE NO. PAC-O5-1
Witness David L. Taylor
PACIFICORP
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), Rand 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 purc~ase, 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
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Exhibit No. 24
CASE NO. PAC-O5-1
Witness David L. Taylor
imposed on generating units, transmission lines, and distribution facilities. The maximum
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, billing, 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. cust9mers. 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 cQst 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, F1 02T - Transmission Plant, F1 020 - Distribution
Plant and so on).
FUNCTIONALIZATION PROCEDURES
For regulatory reporting purposes costs are collected into the Jurisdictional Allocation
Reporting System (JARS). Each account balance in the JARS database is assigned a
functional identification or FUNC Factor. Account balances captured in the JARS
database 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
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Exhibit No. 14
CASE NO. PAC-O5-1
Witness David L. Taylor
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 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 JARS are aggregated by FERC account and by 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 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 lip" FUNC factor.
When the various account balances from JARS that roll up to one line in the JAM 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 SCHMA T -SO FUNC factor.
Some FUNC factors, s~ch as the Production, Transmission and Oistribution (PTD) factor
or the Cash Working Capital (CWC) factor are calculated from data inside the JAM
. model.
Operation Revenues:
General Business Revenue: Account 440-445. Residential Revenues, and Account 442
, .
Retail - Commercial and Industrial Revenues, are not functionalized. The dollar amounts
assigned to PTDRM for retail revenues have been derived to produce the jurisdictional
normalized ROE.
Interdepartmental: Account 448. Interdepartmental Sales, is allocated to Distribution
Poles & Conductor (DPW)
Special Sales: Account 447. Firm Wholesale Sales (sometime referred to as Sales for
Resale), are allocated on the Wholesale Sales Factor
, "
WSF". This factor is developed by
identifying the production transmission components of wholesale sales.
Other Operating Revenue: Accounts 450 to 456. Other Revenues , is functionalized on
the "OTHREV" factors. The vast majority of revenue in this line item are associated with
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Exhibit No. 24
CASE NO. PAC-O5-1
Witness David L. Taylor
account 456 and have been functionalized using the "OTHSE" factor. These factors are
developed by identifying each specific revenue item as PTDRM.
Operating Expenses:
Production: Accounts 500-557. Production expense includes all generation
maintenance expenses as well as fuel and purchased power expenses. All of these costs
are assigned to P.
Transmission: Accounts 560-573. Transmission costs, including wheeling expenses
are assigned to T.
Distribution: Accounts 580-598. Maintenance and operation expenses are assigned to
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 & O. 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 o~ 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 GUST. 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. Property 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. Generation Taxes and Idaho kWh tax are assigned to P. The Washington
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Exhibit No. 24
CASE NO. PAC-O5-1
Witness David L Taylor
Business Tax, Regulatory Commission fees for Wyoming and Idaho and other situs taxes
are assigned to R.
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
and Deductions are functionalized and netted against PTDRM operating revenues to
arrive at total taxable income before state income tax.
Schedule M items that can be specifically identified with P, T , D or R are so assigned.
Those items that are salary or benefit related are functionalized using the "LABOR" factor.
Items associated with bond refinancing are functionalized using the "PTD" factor. The
reversal of book deprecation is functionalized according to book depreciation.
Income Taxes - State: Account 409.11. The total income before state taxes is
calculated for PTDRM in the same manner as done for Federal income taxes. This
amount is multiplied by the composite state tax rate to arrive at functionalized state
income taxes for each function.
Income Taxes Deferred - Net: Accounts 410 & 411. The Tax Department determines
whether the plant deferred income taxes are production, transmission , distribution or
general plant related. These items are functionalized into PTDRM accordingly, 4sing the
DITEXP" factor. Deferred taxes associated with employee benefits are functionalized
using the IILABOR" factor. Items associated with property taxes are functionalized usi
the IIGP" 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 "PTO" factor.
Miscellaneous Revenue & Expense: Accounts 411.8, 421 & 431.1 The gains and losses
arising from the sale of utility property 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, are assigned
to P. Likewise, transmission plant accounts are assigned to T. Distribution plant accounts
are split between D and R based upon asset utilization.
General and Intangible Plant: General plant rate base accounts, except coal mine plant
which is assigned to P, are functionalized using functionalization factors. The General
Plant factors were developed using the functional identification in the Jurisdictional
Allocation Reporting System (JARS) reports of general plant. JARS identifies investments
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Exhibit No. 24
CASE NO. PAC-O5-
Witness David L. Taylor
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 property are assigned to that function. The
general office items within the JARS listing were functionalized on the "PTD" factor and
those items associated with the customer service system were functionalized to R.
separate General Plant functionalization factor was developed to correspond to each PITA
allocation factor.
Intangible plant was functionalized in the same manner.
Plant Held for Future Use: JARS tracks Account 105 transactions to production
transmi~sion, 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: The JARS system tracks and collects deferred debits that are related to
production. These costs are assigned to P directly. Situs and system overhead debits are
functionalized using the "DEFSG"
, "
DDSO2" and "DDSO6" functionalization factors.
These three factors were developed by generating a detailed listing of JARS debits to
situs and system overhead (see page 20).
Electric Plant Acquisition Adjustments: Account 114. All Electric Plant Acquisition
Adjustments are assigned to P.
Prepayments: Account 169. Situs prepayments for franchi~e taxes and regulatory
commission fees are assigned to R. Fuel related prepayments a~e assigned to P.
Property insurance was functionalized using "PTD". 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 , (ProductionlTotal, TransmissionlTotal, DistributionlTotal).
Tab 1 Page 6 of 11
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Exhibit No. 24
CASE NO. PAC-O5-1
Witness David L. Taylor
Weatherization: Accounts 124, 182, 186. Weatherization loans and other deferred debits
related to conservation and DSM programs are assigned to M.
Other Miscellaneous Rate Base: Accounts 182.22 & 141 Other misc. rate base includes
the deferred debits related to the Trojan Nuclear Plant which are assigned to P.
Accumulated Provision for Depreciation & Amortization: Accounts 108 & 111 The
functionalization of the accumulated depreciation matches the functionalization of rate
base. For example, accumulated depreciation for production plant is assigned to P, and
the accumulated depreciation for general plant is functionalized in the same manner as
described in line 37.
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, see
page 9. 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
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 is consistent with the MSP Protocol method filed with the Utah
Commission on June 28, 2004. The MSP Protocol identifies four categories of
Resources: Seasonal Resources, Regional Resources , State Resources , and System
Resources. Fuel costs are classified as 1000/0 energy related. Production and
transmission plant and non-fuel related expenses for all resources are classified ~s 75%
demand related and 250/0 energy related. The costs of Seasonal Resources are allocated
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Exhibit No. 24
CASE NO. PAC-O5-1
Witness David L. Taylor
using seasonal factors because they are designed to be used more intensively at certain
times of the year. All other resources are allocated using non-seasonal factors.
The non-seasonal energy related costs are allocated using each class' share of annual
MWH (F30).
Demand-related costs of non-seasonal resources are allocated using each class
contribution to the 12 monthly peaks coincident with the PacifiCorp system firm peak.
Non-seasonal demand costs are allocated in this manner because capacity is important to
the Company each month for meeting peak loads, load following, and accommodating
plant maintenance. For these reasons, the Company supports the use of all twelve
monthly peak loads in the non-seasonal capacity allocation factor (F12). The energy
portion is allocated using class MWH adjusted for losses to generation level (F30). The
fixed costs composite factor is (F10).
There are three types of Seasonal Resources, simple-cycle combustion turbines, seasonal
contracts and the Cholla Unit IV (adjusted for megawatt hours delivered to and received
from APS). The cost of each type of Seasonal Resource is allocated using a set of
seasonal allocation factors that reflect the monthly portion of the total annual energy
generated by the Seasonal Resource. Prior to summing each class' monthly energy
usage or contribution to the twelve monthly Coincident Peaks, each monthly energy or CP
measurement is weighted by the monthly portion of the total annual energy generated or
delivered to PayifiCorp by the ~easonal Resource. For example, if 30 percent of the
annual generation of a particular Seasonal Resource occurs in July, the monthly
Coincident Peak for July would be weighted by 30 percent in the calculation of the
allocation factor. This, in essence, allocates 30 percent of the de~and related cost for
that resource among classes based upon their contribution to the July Coincident Peak
and 30 percent of the energy related costs based on each class' July energy usage.
The demand costs associated with seasonal simple cycle combustion turbines, SCCT'
are allocated on factor (F13) and the energy portion is allocated on (F32). The fixed costs
composite factor for the SCCT's is (F14). The demand costs associated with Seasonal
Contracts are allocated on factor (F17) and the energy portion is allocated on (F37). The
fixed costs composite factor for the Seasonal Contracts is (F18). The demand costs
associated with Cholla IV are allocated on factor (F15) and the ener,gy portion are
allocated on (F35). The fixed costs composite factor for the Cholla IV is (F16).
The Embedded Cost Differentials are allocated using the generation fixed costs composite
factor (F1 0).
Transmission plant is classified and allocated using the same methods described for non-
seasonal generation resources.
Tab 1 Page 8 of 11
paCiflCorp
Exhibit No. 24
CASE NO. PAC-O5-1
Witness David L. Taylor
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, that 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
billing 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 amount of diversity in the load on each piece of
equipment also declines. While the transition between system costs and faC?ilitie~ costs
occurs gradually over the distribution system, it becomes necessary in a cost study to
draw a line between equipment which is judged to fit best into each of the categories.
Substations and Primary Lines
. Distribution substations and primary lines fall into the system costs category. Because
many customers use substations and primary lines, an allocation methodology that
recognizes the diversity of load among the customers is used. Distribution substations
and primary lines are allocated using the weighted monthly coincident distribution peaks
(F20). The coincident distribution peak is the simultaneous combined demand of all
distribution voltage customers at the hour of the distribution system peak. These monthly
values are weighted by the percent of substations that achieve their annual peak in each
month of the year.
Line Transformers
Distribution line transformers are used either by'only one or by a small number of
customers. As such , they are considered part of the facilities category. Since the cost
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
ofa lack of detailed property records. As a surrogate for installed capacity, we use the
maximum monthly class NCP estimates from load research data.
Tab 1 Page 9 of 11
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Exhibit No. 24
CASE NO. PAC-O5-1
Witness David L. Taylor
Only customers taking service at secondary voltage are allocated distribution line
transformer costs. The allocation factor (F21) is based on summing the individual
customer NCPs for all customers in the class each month and selecting the month with the
highest value. This may be a different month for each class. For classes of customers
where transformers are shared by more than one customer, the NCP is weighted by the
appropriate coincidence factor from the Company s Job Designer's Manual to recognize
the diversity of load at the transformer.
Secondary Lines
Distribution secondary lines operate as an extension of the line transformer. They are also
allocated using the weighted NCP method. Only customer classes where transformers
are shared by more than one customer are allocated the costs of distribution secondary
lines. (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, CustQmer 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,
billing, 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. Typical meter reading time is calculated from the elapsed time between
meter reads captured by the itron meter reading system. (F47)
The customer weighting for Customer Accounting and Records expenses , Account 903
are a composite of several factors such as number of customers receiving manual bills
number of billing adjustments, and average account balances 90 days delinquent. (F48)
Uncollectible Accounts expense is allocated based on class net write off history. (F80)
Customer service expenses are allocated on number of customers (F40).
General & Intangible Plant, Administrative & General Expenses
Most general plant, intangible plant, and administrative and general expenses are
functionalized and allocated to classes based on generation, transmission , and distribution
plant (F1 02). Employee Pensions and Benefits costs have been assigned to functions
Tab 1 Page 10 of 11
~ -_...~~. rExhibit No. 24
CASE NO. PAC-O5-
Witness David L. Taylor
and classes on the basis of labor (F138). Costs that have been identified as supporting
customer systems are considered part of the retail function and have been allocated using
customer factors (F42). Regulatory Commission Expense is allocated on Revenue
(F 141 ).
Taxes
State and Federal Income Taxes are allocated on Rate Base (F1 01). An embedded cost
of service study is designed to determine the revenues needed to provide an equal rate
return for all classes. At full cost of service, allocating income taxes on rate base
produces the same result as allocating on income. This simplifies and reduces the size of
the cost model by eliminating the need to allocate all of the taxable income adjustments.
Deferred Income Taxes are allocated primarily on Net Plant (F1 04). Most deferred taxes
are a result of plant investment. Deferred Income Taxes associated with bad debt are
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 (F1 01). The bulk of taxes other
than Income Taxes are property taxes. Property Taxes are assessed on plant investment.
Rate Base Additions and Deductions
Additions and deductions that relate to Generation and Transmission plant are allocated
accordingly (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 (F1 04). 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 or fixed priced
contracts approved under the IPUC Contract Standard. The revenue from these types of
sales are treated as a revenue credit and are allocated to customer groups using
appropriate allocation factors. Other electric revenues are also treated as revenue credits.
Revenue credits reduce the revenue requirement that is to be collected from firm retail
customers.
Sales for Resale revenues are classified between demand-related (F10) and energy-
related (F30) and allocated consistent with the treatment of purchased power. Other
Electric Operating Revenues are assigned as closely as possible to the specific customer
classes providing the revenue.
Tab 1 Page 11 of 11
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Exhibit No. 24
CASE NO. P AC-O5-
Witness David L. Taylor
BEGINNING/ENDING
RESULTS OF OPERATIONS SUMMARY
IDAHO-UPL
Desc Uon of Account Summa ormalized Production Transmission tribution 8m!!Mise
~.)perating Revenues
163,367,214 114,121.969 11,162,047 31,427,402 789,983General Business Revenues 865,813
General Business Revenues
.;,
Interdepartmental
Special Sales 57,659,204 49,281,868 377,335
Other Operating Revenues 646 757 644,890 135,388 315,645 354,290 196,545
ToCal Operating Revenues 225,673,175 164.048,728 22,674,770 31,743.047 144,273 062,357
Operating Expenses:
Steam Production 48,110,159 48,110,159
Nuclear Production
Hydro Production 893,668 . 2,893,668
Other Power Supply 78,344,011 76.344,012 (0)
Transmission 764,690 764,690
Distribution 158,224 158,224
Customer Accounts 914,022 914,022
Customer Service 426,622 426,622
Sales 144 144
Administrative & General 14,238,229 325,407 092,675 423,039 104,476 292,632
Total 0 & M Expenses 162,849,771 133,673,246 857,365 13,581,263 445,265 292,632
Depreciation 21,086,177 10,890,882 700,846 450,689 43,760
Amortization Expense 635,450 910 547 591,498 747217 386,188
Taxes Other Than Income 637,786 043,959 937,616 614,854 41,357
Income Taxes. Federal 018,491 (26,271)338,045 408,174 32,083 266,460
Income Taxes - State 335,206 35,945 97,013 116,803 904 76,541
Income Taxes - Def Net 156 994 120,979 613,311 435,922 (13 217)
Investment Tax Credit Adj.(774,576)(371,206)(175,667)(227,703)
Mise Revenue & Expense (21,826)(41 700)(14,266)34,141
Total Operating ~es 200,923.474 152.236,380 16,945,761 25,161,360 944,340 635,632
iperating Revenue for Retum 24,749,701 11,812,347 729,009 581,687 199,933 426,725
Rate Base:
Electric Plant in Service 793,337,921 382,105,831 172,256,240 233,904,613 071,236
Plant Held for Future Use 86.684 66,460 20.224
Misc Deferred Debits 459,954 967,738 365,450 55,941 253,146 (182,320)
.40 Elec Plant Acq Adj 131,129 .131,129
Nuclear Fuel
Prepayments 918,334 505,252 134,954 205,073 162 89,894
Fuel Stock 088,440 088,440
Material & Supplies ~1,934 714 813 291,779 725,342
Wormg Capital 416,572 303,570 374,802 639,813 89,714 672
Weatherization Loans 135,137 135,137
Miscellaneous Rate Base 004,811 004,811
Total Electric Plant 828,310,916 405,888,044 174,443,449 235,530,782 417 258 031,383
Rate Base Deductions:
Accum Prov For Depr (324 793,998)(166,121,214)(61.180,596)(97.246.700)(243,487)
Accum Prev For Amort (16,335,064)(7,022,544)(3,019,033)(3,970,467)(2,323,020)
Accum Def Income Taxes (69,570,167)(31,389,172)(14,519,737)(24 104,512)443,254
Unamortized ITC (68,345)(32,754)(15,500)(20,091)
Customer Adv for Const (40,362)(40,760)398
Customer Service Deposits
Misc. Rate Base Deductions (9,688 792)683,936)(1,308 610)696,245)
Total Rate Base Deductions (420,496,727)(211,249 620)(80,043 476)(127 080,775)(2,122,855)
Total Rate Base 407,814 189 194,638,424 94,399.972 108,450,008 294,402 031.383
6r'etum on Rate Base 069%069%069%8.1)69%069%089%
Retum on Equity 762%762%762%762%782%782%
Tab 2 Page 1
MARCH 2004 REVISED PROTOCOL
BEGINNINGIENDING
FERC BUSINESS PITA
DESCRIPTION FUNCTION
Sales to Ultimate Customers
440 Residential Sales
442 Commercial & Industrial Sales
444 Public: Street & Highway Lighting
445 Other Sales to Public Authority
100
101 448 IntenIepartmenta
102 DPW
103
104
105
106 Total &1.. to Uhlmate Customer.
107
108
109
110 447 Sales for Resale
111 WSF
112 WSF
113 WSF
114 WSF
115
118
117 449 ProvIsIon for R8te Refund
. 1 WSF
WSF
120
121
122
123
124 Total Sale. from EI8c:trIdty
& .....au,-ua
Exhibit No. 24
CASE NO. PAC-O5-1
Witness David L. Taylor
IDAHO-UPL
ormalized Production ransmission tribution BmiI M!G
(0)(0)(0)(0)
43,769,079 114,121,969 11,182,047 31,427402 789,983 865,813
43,769,079 114,121,969 11,162,047 31,427,402 789 983 865,813
119.385,802
119,385,802
212,333
212,333
163 367 214 114,121 969 11,162,047 427402 789 983 865813
57,659,204 281,868 377,335
57,659,204 281,868 377 335
221 026 418 163,403,838 19,539 382 427402 789983 865 813
. .
Tab 2 Page 2
, ~
125 MARCH 2004 REVISED PROTOCOL
128 BEGINNINGIENDING
127 FERC BUSINESS PITA
128 ACCT DESCRIPTION FUNCTION FACTOR
129 450 forfeited Discounts & Interest
130 CUST
131 CUST
134 451 Misc Electric Revenue
135 CUST
138
137
138
139
140 453 Water Sales
141
142
143
144 454 Rent of Electric Property
145 DPW
148
147
148
149
150
151
152 456 Other Electric Revenue
153 DMSC
154 CUST
155 OTHSE
158 OTHSO
157 OTHSGR
158
159
160
161
162 Total Other Electric Revenues
163
164 Total Electric Operating Revenues
165
166 Summary of Revenues by Factor
167
168
169
1',
172 DGP
173
174 Total Electric Operating Revenues
raclII\..orp
Exhibit No. 24
CASE NO. PAC-O5-1
s David L. TaylorWitnes
IDAHO-UPL
nnallzed roduction ransmission Distribution B!!I!l MIs
248.579 248.579
248,579 248,579
105,633 105.833
105,633 105,633
237.308 237.308
318.126 318.128
656 789 759 030
564,088 789 319.886 240,336
198.517 198.517
191,274 202.637 988.609
213.894 93.835 44,750 75,309
126,773 344,629 782.143
728,457 641,101 815,503 75,309 198,545
646 757 644,890 135 388 315,645 354 290 196 545
225 673 175 164 048 728 674 770 31,743 047 144273 062,357
164 155,249 114 121,969 11.162.047 31.664 708 144.195 082.330
191,274 202.637 988.609
222,550 97;824 48.509 78.339
80.104 102 49.628.498 10.477 605
, -
225,673,175 164,048,728 22,674 770 743,047 144 273 082,357
Tab 2 Page 3
175 MARCH 2004 REVISED PROTOCOl
178 BEGINNINGIENDING
177 FERC BUSINESS PITA
178 DESCRIPTION FUNCTION
179 MIscellaneous Revenues
180 41180 GaIn on. Sale of Utility Plant- CR
181 DPW
184
185
188
187
188 41170 Loss on Sale of Utility Plant
189 DPW
190
191
192
193 4118 GaIn from Emission Allowances
194
195
198
197
198 41181 GaIn from DIIposI1Ion of NOX Credits
199
200
201
202 4194 Impact Hou8Ing Interest Income
203
204
205
208 421 (GaIn) Loss on 5ale of Utility Plant
207 DPW
208
209
210
211 PTD
212
213
214
215 Total Miscellaneous R....nues
216 Miscellaneous Expenses
217 4311 Interest on Customer Deposits
218 CU5T
219
.2'ot8I MI8c8I"~ Expen...
222 Net Mise Revenue and Expense
CII~III\"U"I'
Exhibit No. 24
NO. P AC-O5-1
s David L. Taylor
CASE
Witnes
IDAHO-UPL
Normaliz roduction Trans sion stribution Bm!!MIs
141.253)141.253)
141.253 141,253)
34,069 34,069
(14 321)(14,321)
242 116
(563)(563)
19,427 (4471 (14.266)34.141
121826\141,7001 114266)34,141
.. . .
'21 8261 '41,7001 '14 266)34,141
Tab 2 Page 4
, ~
223
224 MARCH 2004 REVISED PROTOCOL
225 BEGINNINGIENDING
228 FERC BUSINESS PITA
227 DESCRIPTION FUNCTION FACTOR
228 500 Operation Supervision & Engineering
229 DGU
2;,SSGCH
232
233
234 501 Fuel Related
235
238
237
238 DEU
239 SSECT
240 SSECH
241
242
243 502 Steam Expenses
244 DGU
245
246 SSGCH
247
246
249 503 Steam From Other Spurces
250
251
252
253 505 Electric Expenses
254
255 SSGCH
256
257
258 506 Misc. Steam Expense
259 DGU
260
261
262 SSGCH
263
264
265 507 Rents
266 DGU
267
SSGCH
21.
270
271 510 Maint Supervision & Engineering
272 DGU
273
274 SSGCH
275
276
277
278
279 511 Maintenance of Structures
280 DGU
281
282 SSGCH
283
284
285 512 Maintenance of Boiler Plant
286 DGU
287
288 SSGCH
289
290
291 513 Maintenance of Electric Plant
292 DGU
293
294 SSGCH
295
296
297 514 Maintenance of Misc. Steam Plant
298 DGU
299
300 SSGCH
301
302
303 Total Steam PoWer Generation
. ""IIl'-UII'
Exhibit No. 24
CASE NO. PAC-O5-
s David L TaylorWitnes
IDAHO-UPL
onnallzed Prod ctio ission Distri tion B!!!!!!MIs
111,473 111,473
78,680 78,680
190,153 190,153
28,336,174 28,336,174
2,553,833 553,833
30,890,007 30,890,007
973).79 973,279
123,215 123,215
096,493 096,493
267,924 267,924
267,924 267,924
143,507 143,507
082 60,082
203,590 203 590
681.492 681,492
54,772 54,772
736,264 736 264
293,609 293,609
578 578
295,187 295 187
347,058 347 058
125 157 125 157
472,215 472,215
091,683 091 683
862 862
115,545 115,545
983,974 983,974
259,296 259,296
5,243 270 243270
927,139 927 139
51,139 51,139
978 278 978,278
498,854 498,854
122,379 122.379
621,232 621,232
. ,
48,110159 48,110 159
Tab 2 Page 5
304 MARCH 2004 REVISED PROTOCOL
305 BEGINNINGIENDING
306 FERC BUSINESS PITA
307 DESCRIPTION FUNCTION FACTOR
308 517 Operation Super & Engineering
309
310
31'
Nucl88' Fuel Expense
31;:.
314
315
318
317 519 Coolants and Water
318
319
320
321 520 Steam Expenses
322
323
324
325
328
327 523 Electrtc Expenses
328
329
330
331 524 MIsc. NucJeao Expenses
332
333
334
335 528 Maintenance Super & Engineering
336
337
338
339 529 Maintenance of Structures
340
341
342
343 530 Maintenance of Reactor Plant
3404
345
346
347 531 Maintenance of Electric Plant
348
34'
31.
35~ ..J2 M81ntenance of Mise Nuclear
352
353
354
355 Total Nudur Power Generation
raclII~orp
Exhibit No. 24
NO. PAC-O5-1
David L. Taylor
CASE
Witness
IDAH~PL
ormaliz Production rans sion tri ution BU!!!M!s
Tab 2 Page 6 , r
356 MARCH 2004 REVISED PROTOCOl
357 BEGINNINGIENDING
358 FERC BUSINESS PITA
359 DESCRIPTION FUNCTION
360
361 535 Operation Super & Engineering
362 DGP
. 3l
365
366
367
366 536 Water For
369 DGP
370
371
372
373
374
375 537 H)'draulic Expenses
376 DGP
377
376
379
380
381
382 538 EIec:trk: Expenses
363 DGP
364
385
386
387
388
389 539 Misc. Hydro Expenses
390 DGP
391
392
393
394
395
396
397 540 Rents (H)'dro Generation)
398 DGP
399
400
403
404 541 Maint Supervision & Engineering
405 DGP
406
407
408
409
410
411 542 Maintenance of Structures
~12 DGP
413
414
415
416
417
418
419
420
421 543 Maintenance of Dams & Waterways
422 DGP
423
424
425
426
427
428 544 Maintenance of Electric Plant
429 DGP
430
431
432
433
434
435 545 Maintenance of Misc. H)'dro Plant
438 DGP
437
438
4:'
44-
441
442 Total Hydraulic Power Generation
CII~IU\..Ul"p
Exhibit No. 24
CASE NO. P AC-O5-
s David L. TaylorWitnes
IDAHQ.UPL
Nonnalized roduction ransm ion Distribution B!!!!!M!G
285.121 285.121
125.352 125.352
410,473 410473
473 473
473 473
237,005 237,005
11.019 11.019
248.024 248024
387 387
387 387
392,172 392,172
303794 303 794
695,966 695,966
3,258 3,258
973 973
4,231 4,231
74,205 205
6,279 6,279
80,484 80,484
60,159 60,159
72,729 72,729
132,888 132,888
82.726 82.726
35.332 35,332
118,057 118,057
150.383 150.383
46,304 46.304
196,686 196 686
893 668 893 668
Tab 2 Page 7
443 MARCH 2004 REVISED PROTOCOL
444 BEGINNINGIENDING
445 FERC BUSINESS PITA
448 DESCRIPTION FUNCTION
447
448 548 Operatkin Super & Engineering
449
452 547 Fuel
453
454 SSECT
455
458
457 548 Generation Expense
458
459 SSGCT
480
461
462 549 Miscellaneous Other
463
464
465
466
467
468
469 550 MaInt Supervision & Engineering
470
471 SSGCT
472
473
474 551 Main! Supervision & Engineering
475
476
477
478 552 Maintenance of Structures
479
480
481
482
483 553 Main! of Generation & Electric Plan!
484
485 SSGCT
488
487
Maintenance of MIse. Other
490 SSGCT
481
492
493 Total Other Power Gener8t1on
PacitiCorp
Exhibit No. 24
CASE NO. PAC-O5-
David L. TaylorWitness
IDAHO-UPL
onnallzed rod cti ransmission Disbibution BI!i!!I
629 20,629
20,629 20,629
189,736 189,736
801,509 801,509
991 245 991 245
36,277 36,277
819,035 819,035
855,312 855,312
86,383 86,383
86,383 86,383
21,159 21,159
145,648 145,648
166,807 166 807
756 756
756 756
202 16,202
641 641
17,643 17,843
648 648
705 705
152.679 152 679
Tab 2 Page 8
, ~
494
495
496 MARCH 2004 REVISED PROTOCOL
497 BEGINNINGIENDING
498 FERC BUSINESS PITA
499 DESCRIPTION FUNCTION FACTOR
50(\'is Purchased Power
DMSC
50'..
503
504 SSGC
505 DGP
506
507
508
509 556 System Control & Load Dispatch
510
511
512
513
514
515
516 557 Other Expenses
517
518
519 SGCT
520
521 TROJP
522
523
524
525 Embedded Cost Differentials
526 Company Owned Hydrc P DGP
527 Company Owned Hydrt P
528 Mid-C Contract
529 Mid-C Contract
530 Existing OF Contracts
531 Existing OF Contracts
532
533
534
535 T~I o.her Power Supp~
536
537 TOTAL PRODUCTION EXPENSE
53'
5411 -eRC
541 ACCT DESCRIPTION FACTOR
542.Summary of Production Expense by Factor
543
544
545
546 SNPPH
547 TROJP
548 SGCT
549 DGP
550 DEU
551 DEP
552 SNPPS
553 SNPPO
554 DGU
555
556 SSGCT
557 SSECT
558 SSGC
559 . SSGCH
560 SSECH
561 Tota/Production Expense by Factor
562 MARCH 2004 REVISED PROTOCOL
563 BEGINNING/ENDING
564 FERC BUSINESS PITA
565 ACCT DESCRIPTION FUNCTION FACTOR
566 560 Operation Supervision & Engineering
567
568
569
570
571 561 Load Dispatching
572
573
574
raCI1ILOrp
Exhibit No. 24
CASE NO. PAC-O5-1
David L. TaylorWitness
IDAHQ.UPL
Nonnaliz roduction Trans sion tribution BmI!I M!G
(0)(0)
54,152,586 54,152,586 .
399,152 399,152
3.294,321 3.294,321
62,846 059 62,846,059 (0)
176,588 176,588
176,588 176,588
289,019 289,019
525,342 525,342
814,361 814,361
532,128 532,128
(878 228)(878,228)
012,880 012,880
113 268 113,268
(3,425,724)(3,425,724)
354,324 354,324
191,332 191,332 10)
127347,838 127,347,838 (01
IDAHQ.UPL
nnalized rod tion Tran mis ion tribution M!G
402,287 402.287
, -
(0)
114 589 114589
37,192,987 37,192,987
(878,228)(878,228)
966,381 966 381
801,509 801,509
900,160 900,160
553.833 553,833
124053 517 124 053,517 10)
IDAHO-UPL
Nonnalized Production nsmi ion tribution B!!Ii!M!K
. 491,629 491 629
491 629 491.629
271,678 271,678
271,678 271,678
Tab 2 Page 9
575 MARCH 2004 REVISED PROTOCOL
576 BEGINNINGIENDING
577 FERC BUSINESS PITA
578 DESCRIPTION FUNCTION FACTOR
579 562 SI8llon Expense
580
581
51"
584 563 Ov8lhe8d Line Expense
585
586
587
586
589 584 Underground Une Expense
590
591
592
593
594 565 Transmission of Elec:trtclty by OthI!lS
595
598
597
598
599
600
601.566 MIse. TnnmIssIon Expense
602
603
604
605
606 567 Rents. Transmission
607
608
609
610
611 568 Maint Supervision & Engineering
612
613
614
615
616 569 Mainten8lC8 of Structures
617
818
819
s-.
M81nt8n81c:e of Station Equipment
822
823
624
625
828 571 Mainlen8nc8 of Overtlead Lines
827
628
829
630
631 572 Melnlen8nc8 of Underground Lines
632
633
634
635
636 573 Malnt of Misc. Transmission Plant
637
638
639
640
641 TOTAL TRANSMISSION EXPENSE
642
643 SummlWY of Transmission Expense by Factor
644
645
846 SNPT
647 Total Transmission Expense by Factor
ca~llI\..urp
Exhibit No. 24
CASE NO. PAC-O5-
s David L. TaylorWitnes
IDAHO-UPL
rmaliz Prod ctio Transmission tribution Retail M!&
80.604 80,604
80.804 80,804
189.102 169.102
169.102 169 102
552.325 552,325
149.645 149,845
702,170 702,170
11,429 11,429
11.429 11,429
37,597 37,597
597 597
276 276
276 276
513.800 513800
513.800 513800
477,206 477,206
477,206 477,206
819 819
819 819
175 175
175 175
764690 764 690
149,845 149845
614845 614845
764,690 764690
Tab 2 Page 10 , r
648 MARCH 2004 REVISED PROTOCOL
649 BEGINNINGIENDING
650 FERC BUSINESS PITA
651 DESCRIPTION FUNCTION FACTOR
652 580 Operation Supervision & Engineering
653 DPW
654 DPW SNPD
65r
65;Load Dispatching
658 DPW
659 DPW SNPD
660
661
662 582 Station Expense
663 DPW
664 DPW SNPD
665
668
667 583 Ov8ltlead LIne Expenses
668 DPW
669 DPW SNPD
870
671
872 584 Underground LIne Expense
873 DPW
674 DPW SNPD
675
676
677 585 Street Lighting & Signal Systems
678 DPW
679 DPW SNPD
680
681
682 586 Meter Expenses
683 DPW
684 DPW SNPD
685
686
687 587 Customer Installation Expenses
688 DPW
689 DPW SNPD
690
691
692 588 Misc. Distribution Expenses
69"DPW
DPW SNPD
69b
696
697 589 Rents
698 DPW
699 DPW SNPD
700
701
702 590 Malnt SupelVision & Engineering
703 DPW
704 DPW SNPD
705
706
707 591 Maintenance of Structures
708 DPW
709 DPW SNPD
710
711
712 592 Maintenance of Station Equipment
113 DPW
114 DPW SNPD
115
.. A"au,",u, l'
Exhibit No. 24
NO. PAC-O5-1
David L. Taylor
CASE
Witness
IDAHO-UP!..
Normaliz roduction rans ion Distribution BI!!!!!M!I5i
468.454 468.454
468.414 468,474
354.533 354.533
354.533 354,533
177.667 177.667
19.559 19.559
197.425 191425
668.985 866,985
266.532 266.532
133 516 133,516
568 568
568 568
689 689
689 689
316,875 318.875
59.451 59,451
318,325 318,325
13.558 13.558
13.558 558
,473.243 413.243
213.016 213,076
746.319 146.319
30.896 30,896
984 36.964
67.680 880
27.674 27.674
674 21,614
85.972 85.972
15,500 15,500
101,472 101 472
354.370 354.37d
101.853 101,853
456,223 456,223
Tab 2 Page 11
718 MARCH 2004 REVISED PROTOCOL
717 BEGINNINGIENDING
718 FERC BUSINESS PITA
719 DESCRIPTION FUNCTION FACTOR
720 593 Maintenance of Ovelhead LInes
721 DPW
722 DPW SNPD
72~ :i94 Maintenance of Underground Lines
728 DPW
727 DPW SNPD
728
729
730 595 Maintenance of LIne Transfonners
731 DPW
732 DPW SNPD
733
734
73S 596 MaInt of Street Lighting & Signal Sys.
738 DPW
737 DPW SNPD
738
739
740 597 MaInt8nance of Meters
741 DPW
742 DPW SNPD
743
744
745 599.MaInt of MIse:. Dlsb1but1on Plent
748 DPW
747 DPW SNPD
748
749
750 TOT At DISTRIBUTION EXPENSE
751
752
753 Summary 01 Distribution Expense by Factor
754
755 SNPD
756
757 Total Distribution Expense by Factor
758
759 MARCH 2004 REVISED PROTOCOL
780 ~EGINNINGIENDING
BUSINESS PITA
DESCRIPTION FUNCTION fACIQB
783 901 Supervision
784 CUST
765 CUST
766
787
788 902 'Meter Re8Ilng Expense
769 CUST
770 CUST
771
773 903 Customer Receipts & CoIIec:Iions
774 CUST
775 CUST
778
777
778 904 Uncollectible Accounts
779 CUST
780
781 CUST
782
783
784 905 Mise, Customer ACCXlUflts Expense
785 CUST
786 CUST
787
788
789 TOTAL CUSTOMER ACCOUNTS EXPENSE
790
791 Summary of ~lOmer Accts Exp by Factor
792
793
714
795 TotII Customer Accountl ExpelWe by Factor
. ""'II'-'U' P
Exhibit No. 24
CASE NO. PAC-O5-
David L. TaylorWitness
IDAHO-IJPl
Normaliz roduction rans sion tributi BmIi!M!!!;
491,896 491,896
12,665 498)12,665498)
826,198 826 198
822,783 822,783
22,740 22,740
845,523 845,523
118593 118,593
535 11,535
128,129 128 129
160,062 160,062
160,062 160,062
283,297 283.297
65,794 65,794
349,091 349,091
083,535 083,535
(186,972)(186,972)
896,563 896,563
158 224 158 224
9,267,761 267,761
(109 538)(109,538)
158,224 158224
IDAHO-IJPL
Normaliz Production rans sion tribution Bm!!!!
52,820 52,820
294,876 294,876
. -
347,697 347,697
317,558 317,558
(4,089)(4,089)
313,468 313 468
347 107 347,107
741,746 741,746
088,853 088,853
113,230 113,230
917 917
119,147 119,147
44,858 858
44,858 858
914 022 914 022
830 714 830,714
083 308 083,308
914 022 914 022
Tab 2 Page 12
, ~
796
797 MARCH 2004 REVISED PROTOCOl
798 BEGINNINGJENDING
799 FERC BUSINESS PITA
800 DESCRIPTION FUNCTION FACTOR
801 907 Supervision
802 CUST
80'CUST
eo...
808 908 Customer Assistance
807 CUST
808 CUST
809
810
811
812
813 909 Infonnatlonal & Instructional Adv
814 CUST
815 CUST
816
817
818 910 MIsc. Customer Service
819 CUST
820 CUST
821
822
823
824 TOTAL CUSTOMER SERVICE EXPENSE
825
826
827 Summary of Customer Service Exp by Factor
828
829
830
831 Total Customer Service Expense by Factor
832
833 MARCH 2004 REVISED PROTOCOL
834 BEGINNING/ENDING
835 FERC BUSINESS PITA
836 ACCT DESCRIPTION FUNCTION FACTOR
837
838 911 Supervision
839 CUST
840 CUST
843 ::112 Demonstration & SellIng Expense
844 CUST
845 CUST
846
847
848 913 Advertising Expense
849 CUST
850 CUST
851
852
853 916 Misc. Sales Expense
854 CUST
855 CUST
856
857
858 TOTAL SALES EXPENSE
859
860
861 Total Sales Expense by Factor
862
863
884 Total Sales Expense by Factor
865
866 Total Customer Service Exp Including Sales
Jr ""III"-UII'
Exhibit No. 24
NO. PAC-O5-
s David L. Taylor
CASE
Witnes
IDAHO-UPL
Nonnalized roductio Transmission tri ution Bm!l MIs
247,619 247,619
247,619 247,619
091,986 091,986
45,718 45,718
137,703 137 703
12,433 12,433
12,433 12,433
20,131 20,131
738 738
28,867 867
426,622 426,622
112,117 112,117
314,506 314 506
426,622 426,622
IDAHO-UPL
Nonnalized Production Transmission Distribution Retail
144 144
144 144
144 144
144 144
144 144
426 767 426 787
Tab 2 Page 13
887 MARCH 2004 REVISED PROTOCOl
888 BEGINNINGIENDING
889 FERC BUSINESS PITA
870 DESCRIPTION FUNCTION FACTOR
871 920 Administrative & General Salaries
872 PTD
873 CUST
PTD
87,
876
877 921 OfIIce Supplies & expenses
878 PTD
879 CUST
880 PTD
881
882
883 922 0ftIce Supplies & expenses
884 PTD
885 CUST
886 PTD
887
888
889 923 Outside Sell/Ices
890 PTD
891 CUST
892 PTD
893
894
895 924 PIoperty Insurance
896 PTD
897
898
899 925 Injuries & Damages
900 PTD
901
902
903 926 Employee Pensions & Benefits
904 LABOR
905 CUST
906 LABOR
907
908
909 927 Franchise Requirements
810 DMSC
811 DMSC
11~
81~
814 928 Regulatory Commission Expense
815 DMSC
916 CUST
917 DMSC
818 FERC
819
920
921 929 Duplicate ChaIges
922 LABOR
923 LABOR
924
925
928 930 Mise General Expenses
927 PTD
928 CUST
929 LABOR
930
931
932 931 Rents
933 PTD
934 PTD
935
936
937 935 Maintenance 01 Gener81 Plant
938
939 CUST
940
941
942
943 TOTAL ADMINISTRATIVE & GEN EXPENSE
944
845 Summery of A&G Expense by F8C1Dr
Its
Its
N'"
aI A&G Expense by F8C1Dr
851
852 TOTAL aiM EXPENSE
CII\:III\...orp
Exhibit No. 24
CASE NO. PAC-O5-1
David L. TaylorWitness
IDAHO-UPL
Normalized roduction ransmission tribution Retail MIs
18.372 805 167 401
128 128
781 517 249,960 537,988 993,568
800.017 258,765 542,155 998,969 128
955 955
021.311 489 451 231,624 300,236
022,266 489.451 231,624 300,236 955
12,234,405)11,070812)1506.743)1656,850)
12,234.405\11,070812)1506,743)(656.850)
046 046
314913 109,394 525.002 680,517
317,959 109.394 525,002 680.517 046
512,735 724,960 343,075 444,700
512,735 724,960 343.075 444,700
098,352 526 372 249096 322,883
098.352 526 372 249,096 322,883
265;137 265.137
27.495 27.495
75,068 52,864 22,204
367.700 52.864 22,204 292,632
1814036)1416,509)142.386)(208,948)(146.192)
18140361 1416,509)142,386)(208 948)(146,192)
130408 541,734 256.366 332.307
141283 583,948 59.425 292.947 204,963
271 694 125 683 315,792 625 254 204,966
260.914 125 040 59,173 701
260.914 125.040 59,173 76.701
173,076 42,284 369 88,707 716
059)(3.059)
465.018 357,917 316.314 750,871 39,917
635,035 400,201 353,683 839 578 41.573
238 229 325407 092 675 423 039 104 476 292 632
588.993 592.823 297.902 426,415 716 265.137
12,575.095 679.721 568 996,624 98,687 27,495
75,068 52.864 22,204
074 074
14.238229 325 407 092,675 423 039 104.476 292.632
182.849771 133 673 246 857 365 .581 263 445265 292.632
Tab 2 Page 14
, ~
953 MARCH 2004 REVISED PROTOCOL
954 BEGINNINGIENDING
955 FERC BUSINESS PITA
956 DESCRIPTION FUNCTION FACTOR
957 4O3SP Steam Depreciation
958
95P
96.DGU
962 SSGCH
963
984
965 4O3NP Nuclear Depreciation
968
967
968
969 403HP Hydro Depreciation
970 Pre-Merger Pacific
971 Pre-Merger Utah
972 Post-Merger Pacific
973 Post-Merger Utah
974
975
976 4030P Other Production Depreciation
977
978
979 SSGCT
980 SSGCH
981
982
983 4O3TP Transmission Depreciation
984
985
986
987
988
969
990
991 403 Distribution Depreciation
992 360 land & land Rights DPW
993 361 Structures DPW
994 362 Station Equipment DPW
995 364 Poles & Towers DPW
996 365 OH Conductors DPW
997 ;366 UG Conduit DPW
367 UG Conductor DPW
99..368 line Trans DPW
1000 369 Services DPW
1001 370 Meters DPW
1002 371 Inst Cust Prem DPW
1003 372 leased Property DPW
1004 373 Street lighting DPW
1005
1006
1007 4O3GP General Depreciation
1006 G-SITUS
1009 G-DGP
1010 G-DGU
1011
1012 CUST
1013 G-SG
1014 PTD
1015 DGU
1016 G-SG SSGCT
1017 G-SG SSGCH
1018
1019
1020 403GVO General Vehicles
1021 G-SG
1022
1023
1024 403MP Mining Depreciation
1025
1026
1O2!
1026 403EP Experimental Plant Depreciation
1029
1030
1031
raCIIILorp
Exhibit No. 24
CASE NO. PAC-O5-
David L. TaylorWitness
IDAH~PL
llz roduction ransmission Distribution MIs
524,919 524,919
774,449 774,449
618,165 818,165
523,355 523355
440666 440,666
335,038 335,038
81.299 81.299
287.225 287.225
83,966 83,966
787,529 787,529
934 934
410,938 410,938
518,505 516,505
930,377 930,377
606,672 806,672
670,866 670,666
533 392 533 392
210,930 210,930
469 17,469
14,359 359
343,320 343320
761 465 761,465
823,913 823,913
133,007 133,007
403,739
. .
403,739
195,819 195,819
383,584 383,584
454,324 45i\,324
116 116
127 127
012 29,012
567,256 567 256
716,661 144,295 572,344
33,955 330 14,625
58.272 33,447 22 , 902 923
041 041
43,760 43,760
246,203 170 629 69,605 970
029,953 493 593 233,584 302,776
339 12,017 902 420
149,197 732,066 469,916 663.433 760
Tab 2 Page 15
1032 MARCH 2004 REVISED PROTOCOL
1033 BEGINNINGIENDING
1034 FERC BUSINESS PITA
1035 DESCRIPTION FUNCTION FACTOR
1036
1037
1036
10:r
1041 \JTAL DEPRECIATION EXPENSE
1042 Summary of Amortization Expense by Factor
1043
1044 DGP
1045 DGU
1048
1047
1048
1049
1050 SSGCH
1051 SSGCT
1052 Total DePreciation Expense By Factor
1053
1054 MARCH 2004 REVISED PROTOCOL
1055 BEGINNINGIENDING
1056 FERC BUSINESS PITA
1057 DESCRIPTION FUNCTION FACTOR
1058.4O4GP Amort of L T Plant . CapItal Lease Gen
1059 !-SITUS
1080 !-SG
1061 PTD
1062 I.oGU
1063 CUST
1064 I-DGP
1065
1066
1067 4O4SP Amort of L T Plant - Cap Lease Steam
1068
1069
1070
1071
1072 4O4IP Amort 01 L T Plant - Intangible Plant
1073 !-SITUS
1074
1075 !-SG
1078 PTD
tOT CUST
10;!-SG
1079 I-SG
1080 I-DGP
1081 I-DGU DGU
1082 I-DGU
1083
1084
1085 4O4MP Amort of L T Plant . Mining Plant
1088
1067
1088
1089 4O4HP Amortization 01 Other Electric Plant
1090 Pr8-Mlllger PacifIC DGP
1091 Pre-Merger Utah DGU
1092 Post-MlIIget Plant
1093
1094
1095 Twl Amortization of Umlted Term P~nt
1096
1097
1098 405 Amortization of Other EIec:tIic Plant
1099
1100
1101
1102
1103 406 Amortization of Plant Acquisition AlIi
1104
1105
1108
1107
1108
1109
raCtliLOrp
Exhibit No. 24
NO. PAC-O5-
s David L. Taylor
CASE
Witnes
IDAHQ..UPL
Nonnallzed Production Transmission Distribution B!!i!il M!I!&
21,086177 10,890 882 700 846 450 689 43,760
6.283,918 144.295 139,599
12,868.295 342.341 318,062 893
029.953 493,593 233,584 302,776
43,760 43,760
041 041
540,694 535,372 902 420
516,517 516,513
086,177 10.890 882 700 846 450,689 43,760
IDAHQ..UPL
onnallz Production rans tri tion B!!!!!!
38,108 18.263 643 11.203
545 545
654 18,263 643 11,203 545
123,628 102 896 48,629
612 612
119670 105.223 12,452 996
323,556 113,536 526962 683,058
378,643 378,643
328 336 335 656
40,461 35,576 4.210 675
043 043
733 733
110,675 413,163 582,856 736,014 378643
839 839
839 839
158,168 1.433 265 591 498 747 217 386,188
- .
353 208 353208
353,208 353.208
Tab 2 Page 16
, ~
1110
1111
1112
1113
1114
1115
1118
1119
1120
1121
1122
1123
1124
1125
1126
1127
1128
1129
1130
1131
1132
1133
1134
1135
1136
1137
1138
1139
1140
1141
1142
1143
1144
1145
1146
1147
1148
1149
1150
1151
1152
1153
, 11~'
MARCH 2004 REVISED PROTOCOL
BEGINNINGIENOING
FERC
407
BUSINESSDESCRIPTION FUNCTION
Amort of Prop Losses, Unrec Plant, etc
DPW
TOTAL AMORTIZATION EXPENSE
Summary of Amortization Expense by Factor
TROJP
DGP
DGU
SNPPO
Total Amortization Expense bY Fac1or
MARCH 2004 REVISED PROTOCOL
BEGINNINGIENOING
FERC
ACCT
408
DESCRIPTION
Taxes Other Than Income
BUSINESS
FUNCTION
DMSC
DMSC
TROJP
GPS
OPRV-
EXCTAX
J'acitit:orp
Exhibit No. 24
CASE NO. PAC-O5-1
s David L. Taylor
PITA
FACTOR
Witnes
IDAHQ.UPL
liz Prod ctio ransmission tri tion B!!!!!MIs
157 157
116,917 116,917
124,074 124 074
3,635,450 910547 591,498 747,217 386,188
123,628 102 28,896 48,629
612 612
116,917 116,917
361,665 131,799 535,605 694,261
386,188 386.188
644,440 613,116 26,997 327
635,450 910 547 591 498 747,217 386,188
IDAHQ.UPL
Nonnalized Production Transmission tribution Retail Misc
185,506 832,112 850,704 465,167 37,524
427,608 187.176 86,911 149.687 834
24,671 24,671
637,786 043.959 937.616 614 854 41.357
PITA
FACTOR
Tab 2 Page 17
1156
1157 MARCH 2004 REVISED PROTOCOL
1158 BEGINNINGIENDING
1159 FERC
1160 DESCRIPTION FACTOR
1161 41140 Deferred Investment Tax Credit - Fed
1162 PTD DGU
11F-
11&
1168 41141 Deferred Investment Tax Credit -Idaho
1167 PTD DGU
1168
1169
1170
1171 TOTAL DEFERRED ITC
1172
1173
1174 FERC BUSINESS PITA
1175 DESCRIPTION FUNCTION FACTOR
1178 427 Interest on Long- Tenn Debt
1177
1178 SNP
1179
1180
1181 428 AmortIzatIon of Debt Disc & Exp
1182 SNP
1163
1184
1185 429 AmoItIzaIIon of Premium on Debt
1188 SNP
1187
1188
1189 431 Other Interest Expense
1190 NUTIL OTH
1191
1192 SNP
1193
1194
1195 432 AFUDC - Bo~
1196 SNP
1197
1198
1199 Total EIec1ric: Interest Deductions for Tax
1200
12'Non-UtIHty PortIon of InIienIsI
121.427 NUTIL NUTIL
1203 428 NUTIL NUTIL
1204 429 NUTIL NUTIL
1205 431 NUTIL NUTIL
1206
1207 Total Non-utillty Intef8st
1208
1209 Total Interest Deductionl for Tax
1210
1211
1212 419 Interest & Dividendi
1213 SNP
1214 Total Operating Deductions for Tax
PacifiCorp
Exhibit No. 24
NO. P AC-O5-
s David L. Taylor
CASE
Witnes
IDAHQ.UPL
Nonnaliz Productio ransmission tri tio Retail MIs
(774,576)(371,206)(175,667)(227,703)
(774576\(371,206)(175,667)(227,703)
m4,576 1371,2061 (175,6671 (227,7031
IDAHQ.UPl
rmalized roducti Transmis ion Distri ution BJmiI MIs
(897952)(393,058)(182,509)(314,335)(8,050)
12,849,331 624507 611,627 498,001 115,196
11,951,379 5,231,449 429,118 183,666 107,145
644,615 282 166 131,018 225,652 779
644,615 282,166 131,018 225,652 779
(5,163)(2,260)(1,049)(1,807)(46)
(5,163)(2,260)(1,049)(1,807)(46)
043,040 456 567 211 998 365.124 351
043 040 456,567 211,998 365.124 351
(441,366)(193 198)(89,708)(154,504)(3,957)
(441.366)(193,1981 (89708)(154,504)(3,957)
13,192,504 774 723 661.377 618 131 118.272
13,192.504 774.723 681,377 618.131 118.272
Tab 2 Page 18
, ~
1215 MARCH 2004 REVISED PROTOCOL
1216 BEGINNINGIENDING
1217 FERC BUSINESS PITA
1218 DESCRIPTION FUNCTION FACTOR
1219 41010 Deferred Income Tax . Federal-OR
1220
1221 TROJD
12.'DGP
12.LABOR
1224 SNP
1225
1226
1227 GPS
1228 DITEXP DITEXP
1229 CUST SADDEBT
1230 CUST
1231 SGCT
1232 DPW SNPD
1233
1234
1235 41011 Deferred Income Tax . State-DR
1236 CUST
1237 DGP
1238 LABOR
1239
1240
1241 GPS
1242 TROJP
1243 SNP
1244 CUST SADDEBT
1245 DITEXP DITEXP
1246 SGCT
1247 DPW SNPD
1248
1249
1250
1251
1252
1253 41110 Deferred Income Tax - Federal-CR
1254
1255
1256 DGP
1257 SNP
1258
1259 GPS
12'LABOR
12.SNPD
1262 CUST SADDEBT
1263 DITEXP DITEXP
1264 TROJD
1265 SGCT
1266
1267
1268
1269
1270 41111 Deferred Income Tax - State-CR
1271
1272 SNP
1273 DITEXP DITEXP
1274 SNPD
1275 SGCT
1276
1277 CUST BADDEST
1278 GPS
1279 LABOR
1280
1281 TROJP
1282
1283
1284
1285
1286
1287
1288 TOTAL DEFERRED INCOME TAXES
nu:lU\..urp
Exhibit No. 24
NO. P AC-O5-
David L. Taylor
CASE
Witness
IDAHO-UPL
onnalized Production Transmission istribution 8m!MIs
470,331 470,331
86,268 66,268
337,011 195,754 121,685 599,869 419.703
223,217 97.708 45,369 78,139 001
025,456 025.456
387,110 282.762 124,348
45,359 19.855 9,219 15,878 407
15,092,744 552,242 086,544 435,145 18,814
76,121 76.121
189.502 189.502
22,913.118 11.766,497 387,164 316,532 440925
(816,857)(357561)(166.026)(285,947)(7,323)
(2,334544)(2,334 544)
(112,650)(49,310)(22,896)(39,434)(1,010)
(645,823)(438,371)(207.452)
(39034)(17.086)(7.934)(13,664)(350)
I (20.134,485)(1.092,130)(111,140)(547,884)(383,331)
(18775)(12 744)(6,031)
(51.758)(51.758)
(8,318,648)(3,060,222)(2,252,375)(2,99~,682)(10 370)
(144 759)(144,759)
(138,791)(138,791)
(14 756.124)(7,645,519)(2,773,853)882 610)(454 142)
156,994 120 979 613 311 435,922 (13 217)
Tab 2 Page 19
1289 MARCH 2004 REVISED PROTocOL
1290 BEGINNING/ENDING
1291 FERC BUSINESS PITA
1292 DESCRIPTION FUNCTION FACTOR
1293 SCHMAF Additions - Flow Through
1294 SCHMAF
1295 SCHMAF SNP
12r .SCHMAF
129.SCHMAF
1298 SCHMAF TROJP
1299 SCHMAF DGP
1300
1301
1302 SCHMAP Additions - Permanent
1303
1304 LABOR SNP
1305 SCHMAP-SO
1308
1307
1308
1309 SCHMAT Additions - Temporary
1310 SCHMA T -SITUS
1311 SGCT
1312 DPW CIAC
1313 SCHMAT-SNP SNP
1314 TROJD
1315 DGP
1318 SCHMAT.
1317
1318 SCHMAT-GPS GPS
1319 SCHMAT-SO
1320 SCHMAT-SNP SNPD
1321 DPW SADDEST
1322 SOOKDEPR SCHMDEXP
1323
1324
1325 TOTAL SCHEDULE - M ADDITIONS
1326
1327 SCHMDF Deductions - Flow Through
1328 SCHMDF
1329 SCHMDF DGP
1330 SCHMDF
1331
1332
133.~
13:
133...:HMDP Deductlonl - Permanent
1338 SCHMDP
1337
1338 PTD SNP
1339 SCHMDP 1ST
1340 SCHMDP-
1341
1342
1343 SCHMDT Deductions. Temporaty
1344
1345 DPW SADDEST
1348 SCHMDT-SNP SNP
1347 CUST DGP
1348
1349 SCHMDT-
1350 SCHMDT -GPS GPS
1351 SCHMDT-
1352 BOOKDEPR TAXDEPR
1353 DPW SNPD
1354
1355
1358 TOTAL SCHEDULE - M DEDUCTIONS
1357
1358 TOTAL SCHEDULE. M ADJUSTMENTS
1359
1380 NOTE:
1381
.. ."un..uII'
Exhibit No. 24
CASE NO. PAC-O5-
s David L. TaylorWitnes
IDAHO-UPL
nnallz roduction ransmission stribution B!!!!i!M!!!&
105,954 105,954
200,889 102,787 10,460 51,565 36,078
(268,034)(137,142)(13,956)(88 800)(48,136)
38,808 71,598 13,496)117 235)(12,059)
996,212 908,285 132,970 426,155 359,489 171,313
231,160 231,160
641,448 841,448
002,382 439,734 209,711 352,917
206,823 206,823
882,114 887,058 (1,843)(3,101)
338,329 338,329
(2,629.806)(1,153,691)(550,199)(925,916)
(178,799)(21,870)(37,092)(22,953)300 (103,185)
821 859 360548 171 947 289,364
22,249,993 491,986 905,108 806,724 175
28,559 694 684,362 830,602 10,564 638 411,965 68,128
598 503 13,755,960 827 105 10,547,403 399906 128
360,270 360,270
921 10,506 972 444
060781 518,478 107,531 304 033 130,739
442,972 889,253 112503 310,477 130,739
8,298,306 756,943 1,280 131 204,767 56,465
(136,381)(136,381)
323,282 580,239 275,114 465,317 612
603 463 603,463
(229,918)(30,393)(101 019)(98,507)
668 7,296 388 835 149
510 088 285,142 (24 218)858 149 306
34,981 283 18,067,620 139,584 701,483 72,596
412,718 412,718
43,779,510 22,270,310 572,980 13,655,093 281,128 - I
222,482 23,159 563 685.482 965 570 411 867
116,623 979\19,403,603\858 377)418 1671 111,961\68,128
Positive Schedule M amounts increase taxable Income and therefore reduce tax expense.
Negative Schedule M amounts decrease taxable income and therefore increase tax expense.
Tab 2 Page 20
, ~
1362 MARCH 2004 REVISED PROTOCOL
1363 BEGINNINGIENDING
1364 FERC BUSINESS PITA
1365 DESCRIPTION FUNCTION FACTOR
1368 40911 Slate Income Taxes
1367 IBT IBT
1368 IBT IBT
13F IBT IBT
IBT IBT
137.OTAL STATE TAXES
1372
1373
1374 FERC
1375 DESCRIPTION FACTOR
1376 Calculation orTaxable Income:
1377 Operating Revenues
1378 Operating Deductions:
1379 0 & M Expenses
1380 Depreciation Expense
1361 Amortization Expense
1382 Taxes Other Than Income
1383 Interest & Dividends (AFUDC-Equity)
1384 Mise Revenue & Expense
1385 Total Operating Deductions
1386 Other Deductions:
1367 Interest Deductions
1386 Interest on PCRBS
1389 Schedule M Adjustments
1390
1391 Income Before State Taxes
1392
1393 State Income Taxes
1394
1395 Total Taxable Income
1396
1397 Tax Rate
1398
1399 Federal Income Tax - Calculated
1400
1401 Adjustments to Calculated Tax:
1402 40910 PM!
1403 FITGCC Glenrock Coal
1404 FITOTH FIT True-up NUTIL OTH
1405 FIT LABOR
1406 Federal Income Tax Per Books
14,JTAL OPERATING EXPENSES
& M~".~V. l'
Exhibit No. 24
NO. PAC-O5-
s David L. Taylor
CASE
Witnes
IDAHQ..UPL
Normalized Productio rans sion Distributi B.t!i!!I MIs
335.206 35,945 013 118,803 904 78,541
335.206 945 013 116 803 904 541
IDAHQ..UPL
nnallzed Producti ransmissio Distribution Retail MIs
225,673,175 164,048,728 22.874.770 31,743 047 144,273 062,357
162,849,771 133,873.246 857,365 13,581,263 445.265 292.832
21,086,177 10,890,882 700,846 450,689 43,760
835,450 910,547 591,498 747.217 386,188
637,786 043,959 937.816 1.814,854 41,357
/21,826\(41,7001 114,266)34,141
192,187358 148,476,934 15,073.059 22.428,163 916,570 292,832
13,192,504 774,723 681,377 818,131 118,272
(18,623,979)(9,403,603)(3,856,377)(3,418.167)(11,961)88,128
669,334 393,467 061,958 1.278.586 97,470 837.854
335,206 35,945 013 118803 904 78,541
334,128 357.523 964,944 161 782 88,565 761,313
35.00%35.00%35.00%35.00%35.00%35.00%
166.945 125,133 337,730 406,624 30,998 266,460
(154495)(154,495)
041 091 315 551 085
018,491 126,27ru 336.045 I 408,174 I 32,083 I 266.460 I
200,923,474 152,236,380 16,945761 38,742,623 11,389 605 928264
Tab 2 Page 21
1409 MARCH 2004 REVISED PROTOCOL
1410 BEGINNINGIENDING
1411 FERC BUSINESS PITA
1412 . DESCRIPTION FUNCTION FACTOR
1413 310 Land and Land Rights
1414
1415
14.
1411.SSGCH
1419 DGU
1420
1421
1422 311 StlUctures and Improvements
1423
1424
1425
1428 SSGCH
1427 DGU
1428
1429
1430 312 Boller Plant Equipment
1431
1432
1433
1434 SSGCH
1435 DGU
1438
1437
1438 314 urbogeneratorUnits
1439
1440
1441
1442 SSGCH
1443 DGU
1444
1445
1446 315 Accessory Electric Equipment
1447
1448
1449
1450 SSGCH
1451 DGU
1452
1453
j4'
1450 ~18 Mise Power Plant Equtpment
1457
1458
1459
1460 SSGCH
14e1 COO
1482
1483
1464
1465 UncllISsifted Steam Plant. Account 300
1468
1487
1468
1489
1470 Total Steam Production Plant
1471
1472
1473 Summary of Steam Production Plant by Factor
1474
1475 DGP
1478 DGU
1477
1478 SSGCH
1479 Total Steam Production Plant by FBCIOr
.. """""u' I'
Exhibit No. 24
O. PAC-O5-1
David L Taylor
CASE N
Witness
IDAHo-UPl
Nonnaliz rod cti ransmissio istribution Bmil M!!Si
233.402 233.402
223504 2,223.504
665.417 665.417
74.221 74.221
196544 196.544
15.428.577 15.428.577
21.390.830 21.390.830
180.194 180.194
135.859 735.859
48.733.460 48.733 460
49.447.073 49.447073
48.910.238 48.910,236
48.803818 46.803.816
13.005.181 13.005.181
158.166.306 158.166 306
10.436.853 10.438.653
10.575.728 575 728
18.211.830 18,211.830
047.420 047 420
42,271.631 42,271 631
748 065 748.085
152.954 152.954
039,187 039,187
764.398 764.398
20.704,624 17 .940,226
383.338 383.338
736.258 736.258
606 775 606 775
181.539 181.539
907,911 907.911
274 980 476 274,980 476
253.171.658 253.171.658
21,808,618 21.808 618
274 980 476 274980,476
Tab 2 Page 22
, ~
1480 MARCH 2004 REVISED PROTOCOL
1481 BEGINNINGIENDING
1482 FERC BUSINESS PITA
1483 ACCT DESCRIPTION FUNCTION
1484 320 L8Id and Land Rights
1485
1486
14'
. 14.
1489 321 Structures and Improvements
1490
1491
1492
1493
1494 322 Reactor Plant Equipment
1495
1496
1497
1498
1499 323 Turbogenerator Units
1500
1501
1502
1503
1504 324 Land and Land Rights
1505
1506
1507
1508
1509 325 Mise. Power Plant Equipment
1510
1511
1512
1513
1514
1515 Unclassified Nuclear Plant - Acct 300
1516
1517
1518
1519
1520 Total Nuclear Production Plant
1521
1522
1523
152'~umm~ of Nuclear Production Plant by Factor
DGP
15..DGU
1527
1528
1529 Total Nuclear Plant by Factor
PacifiCorp
Exhibit No. 24
C S NO. PAC-O5-1
s David L. TaylorWitnes
IDAHO-UPL
lized Productio ransmiss Distribution BBi!MIs
Tab 2 Page 23
1530 MARCH 2004 REVISED PROTOCOL
1531 BEGINNINGIENDING
1532 FERC
1533 DESCRIPTION
1534
1535 330 Land Land Rights
153ft Pre-Merger Pacific
153 PrMtetger Utah
1538 Post-Merger Pacific
1539 Post-Merger Utah
1540
1541
1542 331 Structures and Improvements
1543 Pre-Merger Pacific
1544 Pre-Merger Utah
1545 Post-Merger Pacific
1548 Post-Merger Utah
1547
1548
1549 332 . ResIIVOIlS, Dams & WateIways
1550 PrMtelg8l' Pdc
1551 Pre-MeIger Utah
1552 Post-Merger Pacific
1553 Post-Merger Utah
1554
1555
1558 333 WaterWheel, TUlbines, & Generators
1557 Pacific
1558 Pr8-Merger Utah
1559 Post-Merger Pacific
1580 Post-Merger Utah
1561
1562
1563 334 Accessory Electric Equipment
1564 Pre-Melger Pacific
1565 Pre-Merger Utah
1566 Post-Merger Pacific
1567 Post-Merger Utah
1568
1569
1570
1571
1572 335 Misc. ~ Plant. Equipment
1573 Pacific
'~7/Pr8-Merger Utah
15;Post-Merger Pacific
157b PosI-Merger Utah
1577
1578
1579 338 Roads, Railroads & Bridges
1580 Pre-Merger PacifIC
1581 PIK4erger Utah
1582 . Post-Melger Pacific
1583 Post-Merger Utah
1584
1585
1586
1587 Unclassified Hydro Plant - Acct 300
1588 Pre-Merger PacifIC
1589 Pre-Merger Utah
1590 Post-Merger Pacific
1591
1592
1593
1594
1595
1596
1597
1598
1599
1800
1801 Total Hydraulic pqnt
1602
1803 SummlWY of HydrauHc PI...t by Factor
1604
1605
1606 DGP
1807 DGU
1808 Tot8I Hydraulic Plant by Factor
raclU\..orp
Exhibit No. 24
CASE NO. PAC-O5-1
ess David L. TaylorWitn
IDAHO-lIPL
Normalized Productio ransmission Distributio .BI!i!!!MIs
737,010 737,010
341,774 341,774
148.241 148.241
937 40,937
1.267 962 1.267 962
485,137 485,137
417.246 417.246
631,423 631,423
312,042 312,042
845.848 845 848
10,657,107 10,657,107
445,077 445,077
639,546 639546
189397 189,397
16,931,127 16,931 127
106,422 106,422
652,772 652,772
1,673,096 673 098
372,143 372,143
804,434 804,434
403 077 403 077
286,094 286.094
211 299 211,299
193,297 193.297
093767 093767
111.231 111,231
15,140 15,140
68,028 68,026
069 069
201 469 201.469
314 924 314,924
54,931 931
362,393 362.393
19,946 19,946
752,194 752,194
30,B9BBOO 30,B9BBOO
696,800 896,800
30,896 800 30,896 800
Tab 2 Page 24
, ~
1609 MARCH 2004 REVISED PROTOCOL
1610 BEGINNINGIENDING
1811 FERC BUSINESS PITA
1812 DESCRIPTION FUNCTION
1813
1614 340 Land and Land Rights
1811'
16.
1818
1819 341 StnJctures and Improvements
1620
1621
1622 SSGCT
1623
1624
1625 342 Fuel Holders. Producers & Accessories
1628
1627
1828 SSGCT
1829
1830
1831 343 Prime Movers
1632
1833
1834
1835 SSGCT
1638
1837
1638 344 Generators
1839
1640
1641
1642 SSGCT
1643
1644
1645 345 Accessory Electric PIant
1646
1647
1648 SSGCT
1649
1650
1651
1652
. 165."'\46 Misc. Power Plant Equipment
1&.
1656
1657
1658 Unclassified Other Prod Plant-Acct 300
1659
1660
1661
1662
1663 Total Other Production Plant
1664
1665 Summary of Other Production Plant by Factor
1666
1667 DGU
1668
1669 SSGCT
1670 Total of Other Production Plant by Factor
1671
1672 Experimental Plant
1673 103 Experimental Plant
1674
1675 Total Experimental Plant
1676
1677 TOTAL PRODUCTION PlANT
CiI\:lII\...urp
Exhibit No. 24
CASE NO. PAC-O5-1
s David L. TaylorWitnes
IDAHQ.UPL
nnallz roductio ransmission isbibution 8I!i!i!MIs
54.292 54.292
54.333 54.333
806.075 806.075
11.212 11.212
122.146 122.146
939.434 939.434
199.105 199.105
622 822
038.477 036.477
9.243.404 9.243404
52.758 52,758
088.970 088.970
120.068 120.068
12.281.794 12.261.794
662 662
876.393 876.393
534,555 534.555
416,609 416.609
729,878 729.878
10.322 322
147,314 147,314
887,514 887 514
32.060 32.060
413 413
34.473 34.473
837 560 26.837.560
12.877.001 12,877001
13.960,559 13,960,559
26,837 560 26,837560
332 714 838 332,714,836
Tab 2 Page 25
1878 MARCH 2004 REVISED PROTOCOL
1879 BEGINNINGIENDING
1880 FERC BUSINESS PITA
1681 DESCRIPTION FUNCTION
1682 350 Land and Land Rights
1683
1684
18f
1687
1688 352 Structures and Improvements
1689
1690
1891
1892
1893
1894
1895 353 Station Equipment
1698
1897
1898
1899
1700
1701 354 Towers and F"odures
1702
1703
1704
1705
1706
1707 355 Poles and FIxtures
1708
1709
1710
1711
1712
1713 356 Clearing and Grading
1714
1715
1716
1717
1718
1719 357 Underground Conduit
1720
1721
1722
'7:'
17.
1725 358 Underground Conductors
1726
1727
1728
17211
1730
1731 359 RoIKIs and Traits
1732
1733
1734
1735
1736
1737 Undassiroed Trans Plant - Acct 300
1738
1739
1740
1741 TSO Unclassified Trans Sub Plant. Acct 300
1742
1743
1744
1745 TOTAL TRANSMISSION PLANT
1748 Summary of Transmission PIn by Factor
1747 DGP
1748 DGU
1749
17SO Total Transmission Plant by Factor
ra\:lu\.-urp
Exhibit No. 24
CASE NO. PAC-O5-1
s David L. TaylorWitnes
IDAHQ-UPL
ormalized Production ransmission istributi BI!!!!M!G
378,485 376,485
183.625 183,625
111,463 111,463
671,574 671,574
558.590 558,590
181.879 181,879
345.464 345.464
065,934 065,934
125,560 125,560
13,186,361 13.188.361
30,786689 30,786 669
53,096,610 53,096,610
10,062.727 10,062,727
8.205,674 8,205.674
747,039 747,039
23,035,440 23,035,440
577,721 577.721
668 624 668,624
17,011,627 17,011,627
257,971 29,257,971
462,728 462,726
224 527 224,527
680,756 14,660,756
36,366 011 36,366,011
411 411
10,491 10.491
141,503 141,503
152,404 152,404
85,665 65,665
187,551 187,551
253,216 253,216
125.213 125.213
308 32,308
569,512 569512
727 034 727 034
- I
153,630 194 153 630 194
153,630,194 153 630,194
153630 194 153,630 194
Tab 2 Page 26
, ~
1751 MARCH 2004 REVISED PROTOCOL
1752 BEGINNINGIENDING
1753
1754 FERC BUSINESS PITA
1755 DESCRIPTION FUNCTION FACTOR
1758 360 Land and Land Rights
1757 DPW
17f
17!.
1760 361 StnJctures and Improvements
1761 DPW
1762
1763
1764 362 Station Equipment
1765 DPW
1766
1767
1768 364 Poles, Towers & Axtures
1769 DPW
1770
1771
1772 365 Overhead Conductors
1773 DPW
1774
1775
1778 368 Und8lground Conduit
1777 DPW
1778
1779
1780
1781
1782
1783 367 Underground Conductors
1784 DPW
1785
1786
1787 368 Line Transfonners
1788 DPW
1789
1790
1791 369 Services
1792 DPW
1793
1794
1795 '\70 Meters
17f DPW
171
1798
1799 371 Installations on Customers' Premises
1800 DPW
1801
1802
1803 372 Leased Property
1804 DPW
1805
1806
1807 373 Street Lights
1808 DPW
1809
1810
1811 Unclassified Dist Plant - Acct 300
1812 DPW
1813
1814
1815 DSO Undassified Dist Sub Plant - Acct 300
1816 DPW
1817
1818
1819
1820 TOTAL DISTRIBUTION PLANT
1821
1822 Summary of Distribution Plant by Factor
1623
1824
1825 Total Distribution Plant by Factor
1826 MARCH 2004 REVISED PROTOCOL
.. "","'vu,t'
Exhibit No. 24
CASE NO. PAC-O5-1
s David L. TaylorWitnes
IDAHO-UPL
nnalized Productio ransmission Distributio Bmi!M!G
149,294 149.294
149,294 149,294
767,250 767,250
767,250 767.250
18,314.387 18.314.387
18,314.387 18,314.387
44.774,740 44.774,740
44,774740 44,774 740
29.269.821 29,269.821
29,269 821 29.269 821
439 583 439.583
439,583 439.583
18,349 268 18.349,268
349.268 18,349,268
832,664 50.832,664
50.832,664 832.664
16.183.278 16.183.278
16.183278 16.183,278
'~,
4O8.537
. .
13,408,537
13,408.537 13.408.537
155,210 155,210
155,210 155,210
873 873
873 873
492.909 492,909
492.909 492.909
199 141 815 199 141 815
199.141,815 199.141.815
199,141 815 199 141 815
Tab 2 Page 27
1827 BEGlNNINGIENDING
1828 FERC BUSINESS PITA
1829 DESCRIPTION FUNCTION FACTOR
1830 389 Land end Land Rights
1831 G-SITUS
1832 CUST
1833 G-DGU
18:'G-SG
PTD
1836
1837
1838 390 SJruclures and Improvements
1839 G-SITUS
1840 G-DGP
1841 G-DGU
1842 CUST
1843 G-SG
1844 PTD
1845 G-DGU DGU
1848
1847
1848 391 0If1c:e Fum1Iure & Equipment
1849 G-SITUS
1850 G-DGP
1851 G-DGU
1852 CUST
1853 G-SG
1854
1855 PTD
1856 G-SG SSGCH
1857 G-SG SSGCT
1858 G-DGU DGU
1859
1860
1861 392 Transportation Equipment
1862 G-SITUS
1863 PTD
1864 G-SG
1865 CUST
1866 G-DGU
1867
1868 G-DGP
1869 G-SG SSGCH
1870 G-DGU SSGCT
1871
187
18'Stores Equipment
1874 G-SITUS
1875 G-DGP
1878 G-DGU
1877 PTD
1878 G-SG
1879 G-DGU SSGCT
1880
1881
1882 394 Tools. Shop & Garage Equipment
1883 G-SITUS
1884 G-OGP
1885 G-SG
1886 PTD
1887
1888 G-OGU
1889 G-SG SSGCH
1890 G-DGU DGU
1891
1892
1893 395 Labora1Dry Equipment
1894 G-SITUS
1895 G-OGP
1898 G-OGU
1897 PTD
1898
1899 G-SG
1900 G-SG SSGCH
1901 G-DGU DGU
1902
1903
1904 398 PoMr Operated Equipment
1105 G-SITUS
11108 G-OGP
1107 G-SG
11108 PTD
1lIOII G-OGU
11'
11\G-SG SSGCH
1112 G-OGU DGU
1113
nl~ln\.-Ul"p
Exhibit No. 24
CASE NO. PAC-O5-1
s David L. TaylorIDAHO-UPL Witnes
nnalized Producti Tran mission Disbib tion Retail MIs
291.364 58,664 232.690
43.404 43,404
325 186 128
333,689 159,917 75,678 98,095
668,860 160 167 134,492 330.798 43,404
9,213.135 288 855.001 357.847
861 14,153 10,708
110,245 83,279 43.328 838
440,001 440.001
191.045 132,402 54.832
774,139 787,187 309,524 697,429
15,753,427 977,308 3,272.571 063.546 440 001
795,495 160.167 635.303
29.483 16.784 12.698
41,434 23.782 18,284 367
241,456 241,458
439.670 304,708 124.300 10,881
17.194 17.194
979,053 386,151 129,205 463.698
38,587 26.729 10,903 935
582,351 775,373 453,559 111,963 241 456
662,512 114 737 421 924 976
378 331 181 311 85,802 111,218
534.365 370336 151 072 12.957
628 628
67.358 663 473 223
43.696 696
161 631 530
21,928 15,197 199 532
853 490 335
724,832 658,437 013 833 051,934 628
475.272 693 379,565
21.384 12,174 210
63,979 36,723 25,145 111
869 107 042 720
75,696 52,460 21.400 835
256 721 494
677.456 121.200 160,984 395,273
951,175 191 513 759 633
224,910 128,040 96.870
601,279 555317 226.532 429
230 706 110563 52,322 67,821
928 928
327,038 187714 128532 10,792
118.803 82,335 33,587 881
659,838 069 927 729,355 860556
870.073 175,183 694,863
10,606 038 568
806 42,937 29.400 468
318,558 151 706 71.792 059
139 139
217,491 150.730 61,488 5,274
884 692 098
495.557 356,270 343,530 795.758
923886 185 192.733 730,968
112,498 84,045 48,454
007,797 698.442 284.917 24,437
269,844 129,319 81,198 79.326
74,311 42,653 29,205 452
8,254 8,254
58~85 40,380 16,472 413
454.854 983 279 632,980 838 596
Tab 2 Page 28
, ~
1914 MARCH 2004 REVISED PROTOCOl
1915 BEGINNINGIENDING
1916 FERC BUSINESS PITA
1917 DESCRIPTION FUNCTION FACTOR
1918 397 Communication Equipment
1919 COM
1920 COM
19'.COM
19..COM
1923 COM
1924 COM
1925 COM
1926 COM SSGCH
1927 COM DEU
1928 COM DGU
1929
1930
1931 398 Misc. Equipment
1932 G-SITUS
1933 G-OGP
1934 G-DGU
1935 CUST
1936 PTD
1937
1938 G-SG
1939 G-OGU DGU
1940
1941
1942 399 Coal Mine
1943
1944 DEU
1945 Urickassified Mine Plant
1946
1947
1948 399L WIDCO Capital Lease
1949
1950
1951
1952 Remove Capital Leases
1953
1954
1955 1011390 General Capital Leases
1956 G-5ITUS
1957 PTD
. 1958
19'
19l Remove Capital Leases
1961
1962
1963 1011392 General Vehides Capital Leases
1964 LABOR
1965
1966
1967 Remove Capital Leases
1968
1969
1970 Unclassified Gen Plant - Acct 300
1971 G-SITUS
1972 PTD
1973 CUST
1974 G-SG
1975 G-DGP
1976 G-DGU
1977
1978
1979 399G Unclassified Gen Plant - Acct 300
1980 G-5ITUS
1981 PTD
1982 G-SG
1983 G-DGP
1984 G-DGU
1985
1986
1987 TOTAL GENERAL PLANT
1988
1989 Summary 0' General Plant by Factor
1990
1991 DGP
1992 DGU
1993
1994
1995
199f'
19'.DEU
1!19..SSGCT
1999 SSGCH
2000 Less Capital Leases
2001 Total General Plant by Factor
raCItlLOrp
Exhibit No. 24
CASE NO. PAC-O5-
s David L. TaylorWitnes
IDAHO-UPL
Nonnalized Producti Transmission Distribution B!!!!!MIs
755,035 973,637 766,191 752,587 262,620
415,576 70,307 127,538 198,767 18,964
668,919 113,168 205,288 319,939 30,525
3,204,973 542,217 983,590 532,913 146,253
211.817 35,835 65,006 101,310 666
614,670 442,350 802,429 1,250,576 119,315
438 134 210
52.347 856 16,065 25,037 389
12,923774 186,444 966,242 181,338 589,751
55.797 11,234 44,561
599 049 550
33,371 19.154 13,115 101
8,218 6,218
176.008 84.350 39,917 51,741
297 297
50,721 35,152 14,339 1,230
326,011 141,003 156 633 6,2.
21.335,986 21,335,986
21,335 986 21,335 986
053,289 504,776 238,877 309,636
053,289 504,776 238 877 309,636
'1,053,289)'504,776\(238 877)(309,636)
- .
74,602,948 32,765,395 12,787 701 27,728 394 321 458
27,993,744 974,331 243,801 512 993 262,620
8,252.674 632,433 575,535 875,902 188,804
16,756,458 038,604 056,947 516,655 148,253
21,413,933 21.413,569 134 210
943,525 35,835 85,006 101.310 741,373
110 1,211 829
293,794 176,188 84,325 30,892 389
(1,053,289) (504,776)(238,877)(309,636)
74,602.948 32,765,395 12,787 701 27,728394 321,458
Tab 2 Page 29
2002 MARCH 2004 REVISED PROTOCOL
2003 BEGINNINGIENDING
2004 FERC BUSINESS PITA
2005 DESCRIPTION FUNCTION FACTOR
2006 301 OIganization
2007 !-SITUS
2001'PTD
!-SG
2011 302 Franchise & Consent
2012 !-SITUS
2013 !-SG
2014 !-SG
2015 !-SG
2018
2017 I-DGU
2018
2019
2020 303 MIscellaneous Intangible Plant
2021 !-SITUS
2022 !-SG
2023 PTD
2024
2025 CUST
2028 DGU
2027 DEU
2028 I-DGP
2029
2030 303 Less Non-UtIIity Pl8I1t
2031 !-SITUS
2032
2033 Unclassified Intangible Plant. Acct 300
2034 SITUS
2035
2036 DGU
2037 PTD
2038
2039
2040 TOTAl INTANGIBLE PlANT
2041
2042 Summary of Intangible Plant by FaclOr
2043
2044 DGP
2045 DGU
2CW'
'2(
zo.-
2049 DEU
2050
2051 TotBIlntanglbie Plant by Factor
2052 SunwnBIY of Unclassified Plant (Account 106)
2053
20501 DSO
2055
2058
2057
2058
2059
2060 TSO
2061
2062
2063
2064 Total Unclassified Plant by Fac1Dr
2065
2066 TOTAl ELECTRIC PlANT IN SERVICE
2067 Summary of Electric Plant by Factor
2066
2069
2070 DGU
2071 DGP
2072
2073
2074
2075 DEU
2076 SSGCH
2017 SSGCT
2078 Less Capillllleases
2079
ra~lII\.-urp
Exhibit No. 24
CASE NO. PAC-O5-1
David L. TaylorWitness
IDAHQ.UPL
onnallzed roduction ransmission Disbibulio Bi!I!!M!K
600,526 598,855 374.103 629,568
600,526 596,855 374 103 629,568
008.444 376.061 235,711 396.612
80,046 70,382 329 335
156,411 175;346 328,429 52,637
168.113 027.090 121,544 19.480
184,499 164,499
61,474 61,474
658,988 494,851 694 013 470 123
102,802 848.936 218.600 35,067
20.068,811 617,737 551,429 899,646
67,222 87.222
749,178 749,778
25.988 613 11,533,894 770,229 934 712 749,778
988613 11,533,894 170 229 934,712 749 778
248 127 625600 838,344 034 404 749 778
608 970 972,915 609,814 026,241
753,346 967,727 677.101 108,518
20,068,811 617,737 551 429 699,646
749 778 749.778
67,222 222
33.248,127 16.625.600 838 344 034 404 749.778
793,337921 382,105 831 172,256240 233 904 613 071.236
229 744529 947.246 853,615 220.681,048 262,620
21,481 154 21,480 790 134 210
465,581 873 306545.819 156,882.831 984.419 168 804
36,625269 16,654,341 608.376 416,300 146,253
693,303 35,835 65,006 101 310 491 152
22,102 412 21,964,606 64,325 30,892 389
13.962,669 13,961,170 829
053,289)(504.776)(238 877)(309636)
793 337 921 382,105 831 172.256 240 233.904,613 071 236
Tab 2 Page 30
, ~
2080 MARCH 2004 REVISED PROTOCOL
2081 BEGINNINGIENDING
2082 FERC BUSINESS PITA
2083 DESCRIPTION FUNCTION FACTOR
2084 105 Plant Held For Future Use
2085 DPW
2086
20e-
20l
20811
2090
2091
2092
2093
2094
2095 114 Electric Plant Acquisition Adjustments
2096
2097
2098
2099
2100
2101 115 Accum Provision for Asset Acquisition Adjustments
2102
2103
2104
2105
2106
2107 120 Nuclear Fuel
2108
2109
2110
2111 124 Weatherization
2112 DMSC
2113 DMSC
2114
2115
2116 182W Weatherization
2117 DMSC
2118 DMSC
2119 DMSC SGCT
2120 DMSC
2121
2122
2123 186W Weatherization
, 212'DMSC
21:DMSC
212~DMSC CNP
2127 DMSC
2128.DMSC
2129
2130
2131 Total Weatherization
2132
2133 151 Fuel Stock
2134 DEU
2135
2136 DEU
2137 SSECH
2138
2139
2140 152 Fuel Stock - Undistributed
2141
2142
2143
2144 25316 DG&T Wor\(ing Capital Deposit
2145
2146
2147
2148 25317 DG&T Wor\(ing Capital Deposit
2149
2150
2151
2152 25319 Provo Wor\(ing Capital Deposit
2153
2154
2155
2156 Total Fuel Stock
. raCIIll.-orp
Exhibit No. 24
NO. PAC-O5-1
s David L. Taylor
CASE
Witnes
IDAHD-UPL
nnallzed Productio ransmission istribution BBi!.MIs
20,224 20,224
68,460 460
86,684 86,460 224
194,359 194,359
938,607 938,607
132,966 10,132,966
(3,480 368)(3,480,368)
1521469)1521.469)
14,001,837 001 837)
267207 267,207
307,096 307096
574303 574 303
560834 560,834
560,834 560,834
135.137 135.137
944.310 944 310
365541 365,541
309.851 309,851
181.337)(81,337)
181.337 (81,3371
(140074)(140,074)
(140,074 (140.074)
088,440 088,440
Tab 2 Page 31
2157 MARCH 2004 REVISED PROTOCOL
2158 BEGINNINGIENDING
2159 FERC BUSINESS PITA
2160 DESCRIPTION FUNCTION
2181 154 Materials and Supplies
2162 MSS
2163 MSS
21'MSS
MSS
216&MSS SNPPS
2187 MSS SNPPH
2188 MSS SNPO
2189 MSS SNPT
2170 MSS
2171 MSS
2172 MSS SNPP
2173 MSS SSGCH
2174 MSS DEU
2175
2178
2177 183 Stores Expense Undistributed
2178 MSS
2179
2160
2181
2182 25318 Provo Working Capital Deposit
2183 MSS SNPPS
2184
2185
2188
2187 Total M8I8rtels & Supplies
2188
2189 165 Prepayments
2190 DMSC
2191 GPS
2192
2193
2194 PTD
2195
2196
2197 182M Mise Regulatory Assets
2198 DD52
2199 DEFSG
2200 SSGCH
2201
DDS02
221.
2204
2205 188M Mise Defllmld Debits
2208 LABOR
2207
2208
2209 DEFSG
2210 LABOR
2211
2212 SNPPS
2213 EXCTAX
2214 DEU
2215
2218
2217 Worldng Capital
2218 CWC Cash Worlting Capital
2219 CWC
2220 CWC
2221 CWC
2222
2223
2224 OWC Other WorItlng Capital
2225 131 Cash SNP
2228 135 WorItlng Funds
2227 143 Other Accounts Receivablo GP
2228 232 Accounts Payable PTD
2229 232 Accounts Payable
2230 253 Deferred Hedge
2231 2533 Other Defllmld Credits - M P
2232 230 A,sset Retirement ObIigatic P
2233 254105 ARO Regula1ory Liability
2234 2533 Deer Creek DEU
2235 2533 ChoIIa Reclamation SSECH
2238
2237
2238 Tot8I WorItlng Capital
nll.:ll1\-Ul"p
Exhibit No. 24
CASE NO. PAC-OS-
David L TaylorWitness
IDAHD-UPL
nnalized Productio nsmi Distribution B!!I!l
158.355 773.713 109,787 272.874
155.923 128.255 937 19,731
(380.387)(312.888)(19,363)(48.136)
057,610 515.042 155,645 388,922
132 109
614 7.250 449 115
797,848 856.271 40,614 100,963
(48.651)(38,537)(2.385)(5,929)
749 444 729,216 292,670 727,558
(17.510)(14.403)(691)(2.218)
1175101 114.4031 1891)12,2161
731 934 714813 291,779 725,342
894 69,894
352652 154 366 71,677 123 449 162
952 646 306
217 173 217 173
277662 133,066 62,971 81,625
918334 505,252 134,954 205,073 162 894
270520 429 077 222,297 374,097 245049
935.790 935,790
532.602 532,602
(781,304)1211,637)(57,618)(329729)(182,320)
957 608 685,833 164,679 368 245,049 1182,3201
500 279 130 642 449
110 423 911 999 198.424
42,585 21,789 2.217 10.931 648
346 838 346838
502,346 281 905 200,772 11,573 097
303,642 651,835 153 221 214 496 75,418 672
303,642 651 835 153,221 214 496 75,418 672
768,167 336,248 156,130 288,902 887
(9,365)(4,099)(1,903)278)(84)
835,877 365,886 169,892 292,605 494
(452,124)(218,875)(102,538)(132,911)
(6,836)(6,836)
(329 918)(329,918)
(685,868)(685 868)
003)(7,003)
112,929 (548 2651 221,581 425,317 14,296
416 572 303,570 374,802 714639,813 672
Tab 2 Page 32
, ;
2239
2240
2241
2242
2243
2244
2245
224
224
2248
2249
2250
2251
2252
2253
2254
2255
2256
2257
2258
2259
2260
2281
2282
2283
2284
2285
2266
2287
2266
BEGINNINGIENDING
FERC
DESCRIPTION
MIscellaneous Rate Base18221 Unrec Plant & Reg Study Costs
BUSINESS
FUNCTION
18222 Nuclear Plant - Trojan
1869 Mise Deferred Debits-Trojan
141 Impact Housing - Notes Receivable
TOTAL MISCELLANEOUS RATE BASE
TOTAL RATE BASE ADDITIONS
TROJP
TROJO
PITA
FACTOR
PacifiCorp
Exhibit No. 24
CASE NO. PAC-O5-
ess David L. Taylor
SNPPN
IOAHO-UPL Witn
Nonnalized rod cti ransmission DIstribution BI!IJ!MIs
394.127 394.127
575.128 575.126
969,253 969.253
35.558 35,558
35.558 35.558
004.811 1.004.811
34,972,995 23.782 212 187.209 826169 348,022 031,383
Tab 2 Page 33
2289 MARCH 2004 REVISED PROTOCOL
2270 BEGINNINGIENDING
2271 FERC BUSINESS PITA
2272 DESCRIPTION FUNCTION FACTOR
2273 235 Customer Service Deposits
2274 CUST
2275
22;
227.il1 PlOY for Property Insurant PTD
2278 2282 PlOY for Injuries & Damagt PTD
2279 2283 PlOY for Pensions and Ber PTD
2280 254 Reg Liabilities. Insurance PTD
2281
2282
2283 22844 PruvI8ion lor Hydro ~icenslng
2284
2285
2288
2287
2288 22842 Accum Mise Oper Proy.Tn P TROJD
2289 230 Asset Retirement Obllgallc P TROJD
2290 254105 ARO RegulalDry Uabillty TROJD
2291 254
2292
2293
2294 252 CusIDmer Advences for ConslNction
229S DPW
2298 DPW . SE
2297
2298 DPW
2299 CUST
2300
2301
2302 25399 Other Delerred Credits
2303
2304 GPS
2305
2306
2307
2308
2309 190 Accumulated Delerred Income Taxes
2310
2311 DGU
2312 LABOR
23'DGP
23;CUST BADDEBT
2315 TROJP
2318
2317
2318 PTD SNP
2319 DPW SNPD
2320
2321
2322
2323 281 Accumulated Deferred Income Taxes
2324
2325 DGP
2328 SNPT
2327
2328
2329 282 Accumulated Delerredlncome Taxes
2330
2331 ACCMDIT DITBAL
2332 DGP
2333 LABOR
2334 CUST
2335
2338
2337
2338
2339 283 Accumulated Deferred Income Taxes
2340
2341
2342
2343 LABOR
2344 GPS
2345 PTD SNP
2348 TROJP
2347 PTD SNPD
2348 SGCT
2348
2350,
23f
TAL ACCUMULATED DEF INCOME TAX
raCIULorp
Exhibit No. 24
CASE NO. PAC-O5-
s David L. TaylorWitnes
IDAHO-UPL
nnalized Production Transmission tributi Bs!!iIil MIls;
. -
(58,540)(28,055)(13,276)(17,209)
(705,842)(338,266)(160,079)(207,497)
(4,696 638)(2,250,807)(1,065,156)(1.380,675)
1309,092)1148,129)170,099)(90,864)
15,770,112\(2,765,257)(1,308,610)(1,696,245)
(785,056)(785,056)
1782,900)(782,900)
(1,567,956)/1,567956)
(353,572)(353,572)
(103,228)(103,228)
(24,827)(24827)
(481 627 (481,627)
(40,760)(40,760)
398 398
/40,362\/40,760)398
(9,614)(9,614)
(1,109,209)(1,109,209)
(750,273)(750,273)
869 096)869096)
850,101 850,101
166,790 85,340 685 42,812 29,954
447237 447,237
(155,999)(155,999)
943,738 943,738
992,788 992,788
135,977 65,166 30,838 39,973
380,633 781,134 523 82,785 477,191
(74352,224)(35,740,577)(14,382,420)(24,075,114)(154,112)
(181,DO9)(92,615)(9,425)(46,462)(32,507)- I
(549922)(549922)
/949,186)(949,186)
176,032,342)(37332,301)114,391 845)124,121 576)1186,620)
50,528 22,118 10,270 17,688 453
133,988 133,988
41,255 41,255
856 359 438,165 44,590 219,812 153,793
(174 416)(76,347)(35,450)(61,056)(1,564)
(833,159)(399,281)(188,953)(244,924)
(2,400)(2,400)
388 499 129 760
81,542 161 9951 (167,415)1 (65 721)1 152,683 I
(69,570 167\/31,389 172)(14,519,737)(24,104,512)443,254
Tab 2 Page 34
, ~
2353 MARCH 2004 REVISED PROTOCOL
2354 BEGINNINGIENDING
2355 FERC BUSINESS PITA
2356 DESCRIPTION FUNCTION FACTOR
2357 255 Accumulated Investment Tax Credit
2358 PTI.
2359 PTD ITeM
231 PTD 1TC85
236 PTD 1TC86
2362 PTD 1TC88
2363 PTD 1TC89
2364 PTD ITC90
2365 PTD DGU
2366
2367
2366 TOTAL RATE BASE DEDUCTIONS
2369
2370
2371
2372 FERC
2373 DESCRIPTION fAgQB
2374 108SP Steam Prod Plant Accumulated Depr
2375
2376
2377
2378 DGU
2379 SSGCH
2380
2381
2382 108NP Nuclear Prod Plant Accumulated Depr
2383
2384
2385
2386
2387
2388
2389 108HP Hydraulic Prod Plant Accum Depr
2390 Pre-Merger Pacific
2391 Pre-Merger Utah
2392 Post-Merger Pacific
2393 Post-Merger Utah
2394
2395
2396 1060P Other Production Plant. Accum Depr
, 239-
23&.
2400
2401.SSGCT
2402
2403
2404 106EP Experimental Plant - Accum Depr
2405
2406
2407
2408
2409
2410
2411
2412
2413
2414
2415 TOTAL PRODUCTION PLANT DEPRECIATION
2416
2417 FERC BUSINESS PITA
2418 . DESCRIPTION FUNCTION FACTOR
2419 Summary of Prod Plant Depreciation by Factor
2420
2421 DGP
2422 DGU
2423
2424 SSGCH
2425 SSGCT
2428 Total of Prod Plant Depreciation by Factor
2427
2428
2429 FERC
2430 DESCRIPTION FACTOR
2431 106TP Transmission Plant Accumulated Depr
2432
2433
2434
24'")TAL TRANS PLANT ACCUM DEPR
.. ""IIl'--UqJ
Exhibit No. 24
CASE NO. PAC-O5-
s David L. TaylorWitnes
IDAHO-UPl
nnalized rod cti rans ion tribution B!!I!I M!G
(68.345)(32.754)(15,500)(20.091)
166345 132,754)'15,500)(20,091\
- .
/19 367 665)(38,105,862)115,843,847)(25.861,608\443.652
IDAHO-UPl
nnall Production Transmiss Distributi BI!i!!!MIs
(48.168.649)(48,168,649)
(54.445,382)(54.445.382)
(19.565.082)(19.565,062)
/11.609.010)111,609,010)
1133.786323\1133.786,323)
(9,468,642)(9,468,642)
(1,795,209)(1,795,209)
(1,502,001)502.001)
1598,838)(598,838)
113,364,690)113,364,690\
(155.544)(155,544)
(2.374 107)(2.374.107)
1376,549)1376,549)
12,906,199 '2,906,199)
- .
1150 057 212\1150 057 212\
IDAHO-UPl
nnalized rod cti nsmission tri ution BmI!i!
(138.071 654)(138,071,654)
(11.609.010)(11.609,010)
(376549)1376,549)
(150,057212 '150,057 212\
IDAHO-UPl
Nonnallzed Production Transmission Distribution BH!MI&
(21.968,267)(21.988,267)
(21,278 187)(21,278.187)
113,456,319)/13,456 319)
156 722 774 156 722,774)
Tab 2 Page 35
2438 MARCH 2004 REVISED PROTOCOl.
2437 BEGINNINGIENDING
2438 FERC BUSINESS PITA
2439 DESCRIPTION FUNCTION
2440 108360 Land and Land Rights
2441 DPW
2442
241
2440..381 Structures and Improvements
2445 Df'W
2446
2447
2448 108362 Station Equipment
2449 DPW
2450
2451
2452 108364 Poles, Towers & FIxtures
2453 DPW
2454
2455
2456 108365 Overhead Conduc:tDIs
2457 DPW
2458
2459
2480 108386 Underground Conduit
2481 DPW
2462
2483
2464 108367 Underground Conduc:tDIs
2465 DPW
2488
2467
2468 108368 Line Transformers
2469 DPW
2470
2471
2472 108369 Services
2473 DPW
2474
2475
2476 108370 Meters
2477 DPW
2478
2479
2480
241
246.J371 InaI8IIaIIonI on Cus~. Premises
2483 DPW
2484
2485
2488 108372 Leased Proper1y
2487 DPW
2488
2489
2490 108373 Street Lights
2491 DPW
2492
2493
2494 108000 Unclassified DiSI Plant - Acct 300
2495 DPW
2496
2497
2498 108DS Unclassified Oisl Sub Planl . Acct 300
2499 DPW
2500
2501
2502 1080P Unclassified Disl Sub Plant. Acct 300
2503 DPW
2504
2505
2506
2507 TOTAL DISTRIBUTION PlANT DEPR
2508
2509
2510
2511 Summary of qistribution Plant Oepr by Factor
2512
2513
2514 ToI8I Dlitribution Depr8Ci8IIon by Factor
.. ""1 II ""U 1 l'
Exhibit No. 24
CASE NO. PAC-O5-
s David L. TaylorWitnes
IDAHO-UPL
Nonnaliz Production ransmission tributi Bmi!MIG
/152,272)/152,272)
/152,272 (152,272)
(417 129)(417,129)
(417 129)(417,129)
/6,647 817)647 817)
647 817)(6,6478171
/18,757,525)(18 757,525)
(18,757,525 118,757 525)
(8,889,344)889,344)
/8,889,344)(8,889,344)
(3,152,340)(3,152340)
/3,152,340)(3,152,340)
(9,323,762)(9,323 762)
(9,323,762)323,762)
(24,582,898)(24 582 898)
(24,582,898)(24 582,898)
19,354.174)354,174)
(9,354,174)(9,354,174)
(5,655,557)(5,655.557)
(5,655,557)(5.655 557)
(153,276)(153,276)
(153,276)(153,276)
/4,864)(4,864)
(4,864)864)
(338.546)(338 546)
(338,546)(338,546)
/87429 502'/87 429,5021
(87 429 502)(87,429,502)
(87,429 502 (87429,5021
Tab 2 Page 36
, ~
2515
2516
2517
2518
2519
2520
2521
252".
252'.
2524
2525
2526
2527
2528
2529
. 2530
2531
2532
2533
2534
2535
2536
2537
2538
2539
2540
2541
2542
2543
2544
2545
2546
2547
2548
2549
2550
2551
2552
2553
2554
2555
2556
2557
2558
2559
256
256.
2562
2563
2564
2565
2566
2567
2568
2569
2570
2571
2572
2573
2574
2575
2576
2577
2578
MARCH 2004 REVISED PROTOCOL
BEGINNINGIENDING
FERC
108GP
BUSINESS
DESCRIPTION FUNCTION
General Plant Accumulated Depr
G-SITUS
G-DGP
G-DGU
G-SG
CUST
PTD
G-DGU
G-SG
G-SG
108MP Mining Plant Accumulated Depr.
108MP Less Centralia Situs Depredation
1081390 Accum Depr. Capital Lease
PTD
Remove Capital Leases
1081399 Accum Depr - Capital Lease
Remove Capital Leases
TOTAL GENERAL PlANT ACCUM DEPR
Summary 01 General Depreciation by Factor
DGP
DGU
DEU
SSGCT
SSGCH
Remove Capital Leases
Total General Depreciation by Factor
TOTAL ACCUM DEPR. PLANT IN SERVICE
DGU
DEU
SSGCT
SSGCH
DEU
ca~lII\..urp
Exhibit No. 24
CASE NO. PAC-O5-
s David L Taylor
PITA
fAgQB
Witnes
IDAHQ.UPL
onnalized Production nsmi sion tri utio Bt!IJ!MIs
(10.225.137)(319)(2.058.760)(8,166,058)
(517 786)(294.773)(223.013)
001 482)(574.835)(393.600)(33.047)
(1.866,546)(1,293.589)(527.697)(45,260)
(243.487)(243.467)
(5.344.671)(2.561.370)(1,212.124)(1.571.178)
(45,705)(45.705)
(139)(96)(39)(3)
(150,642)/104,401)/42,588)/3,653)
/19.395 597)/4,875,0891 /4,457 823)/9,819,198)(243,487)
(11.188,914)111.188,914)
/11.188,914)111,188,914\
/11,188,914 /11.188,9141
130.584,5101 116.064 0021 457,823)(9,819198)1243,487\
(10,225,137)(319)(2,058,760)(8,166.058)
(11,234,619)(11,234,619)
(5,344671)(2,561 370)(1,212.124)571 178)
(243.487)(243,487)
(3,385815)(2,163.197)(1.144,310)(78,307)
(139)(96)(39)(3)
(150,642)(104,401)(42,588)(3,653)
/30,584,510 /16064,0021 /4,457,6231 819,1961 /243,4871
/324 793 998 /166 121 2141 /61 180 5961 /91 248 7001 (243 4811
Tab 2 Page 37
2579 MARCH 2004 REVISED PROTOCOL
2580 BEGINNINGIENDING
2581
2582 FERC BUSINESS PITA
2583 DESCRIPTION FUNCTION FACTOR
2584 111SP Accum PlOY for Amort-Sleam
2585
2sr
258&
2589
2590 111GP Accum PloY for Amort.General
2591 G-SITUS
2592 CUST
2593 !-SG
2594 PTD
2595
2596
2597
2598
2599 111HP Accum Prov for A~IO
2800 Pre-Merger PICiflc DGP
2801 Pre-Merger UIIIh DGU
2602 Post-Metg- Pacific
2803 PoIt-MeIger UtIIh SG-U
2804
28OS
2808
2807 1111P Accum Prov for Amoft./ntanglble Plant
2808 !-SITUS
2809 I-DGP
2610 I-DGU
2611
2612
2613
2614 I-SG
2615 CUST
2616 DGU DGU
2617 DEU
2618 PTO
2619
2620 1111P Less Non-Utility Plant
2821 NUTIL OTH
2822
282~
1399 Accum Prov for Amort-Mlnlng
26..
2828
2827
2828 TOTAL ACCUM PRaY FOR AMORTIZATION
& M~."~V' l'
Exhibit No. 24
CASE NO. PAC-O5-1
s David L. TaylorWitnes
IDAHQ.UPL
Nonnalized roductio ransmissi Distribution BmIil M!&
(59,357)(59.357)
(373,052)(178,781)(84,605)(109,666)
/432,409 /178,781)(84,605\/109 666\/59,357\
(10,020)(10,020)
/10,020 /10,020\
(1,980,362)(738500)(482,885)(778,977)
(137,860)(137,860)
(19 782)(19,782)
(35,226)(35,226)
(715,602)(629,209)(74 459)(11 933)
(229,451)(201 750)(23,875)(3,826)
(85,732)(75,382)(8,921)(1,430)
(2,263,663)(2,263663)
(10 424,957)/4,996,035)364288)064 634)
(15,892,635)833,744)(2,934,428)(3,860800)(2,263,663)
/15892,635 (6,833,744)(2,934,428\. 13,8608001 263,663\
(16,335 064 (7,022,544)0190331 9704671 323 0201
Tab 2 Page 38
, ~
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N ~0'"
'"!1
(;1
I , ~
;;-.;:
i~")
~:'
"It
0 N
o..XXO::
o::c(oo090::....c(O
O:IEC(. 0 ~zoo..c(wz.... 0:: ::)enc(
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
000000000000000000000000.00000000 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
. a a a a ci ci ci 0 0 0 0 d 000 0 ci ci 0 0 0 ci 0 0 ci 0 0 d000000000000000000000000000000
~ - - - - ~ ~ ~ ~ ~ ~ ~ ~ - - ~ - ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~ ~~ ~~~~~~~~ ~~~ ~ ~~ ~ ~ ~ ~ ~ ~~ ~ ~ ~ ~
0 0 0 0 ~ 0 0 MOO 0 0 0 0 0 N 0 0 0 0 0 0 0 m 0 00 0 0
u g g g g ~ g ~ ~ g g g g g g g ~ g g g g g g g ~ g g g g g g0000 M 0 N MOO 0 0 0 0 0 - 0 0 0 0000 ro 0 00000
. ~
ci ci ci ci ci ci M ci ci ci 0 0 0 ci ci ci 00 0 ci ci ci 0 0N~
~ ~ ~ ~ ~ ~ ~ ~~ ~ ~ ~~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
M ~ Mom ~ 000 0 0000 0 ~ 0 0 ~ 0 0 ~ MOO 0 000
~ ~~~ g ~~gg gg~gg ggg gg~ g
g m ~ggggmg
~ N N ~ 0 N ~ 0 0 0 0 - 0 0 00- ~ 0 0 ro 0 0
~ ~
0000 m
~ ci ci ci M ci ci ci ci 0 0 ci M N ci ci ci ci ~ N ci ci ci ci ~
....~ ~~ ~ ~ ~ ~ ~ ~~~~ ~~~ ~~ ~ ~ ~ ~ ~ ~ ~ ~~~~~
~ 0 NON M ~ ~ 0 0 ~ 0 0 0 0 ~ M 0 ro ~ ro ~ ~ N 0 0 ~ ~ N ~
m N m 0 ~ ~ 0 NO 0 - 000 0 ~ Mom ~ ~ N 0 ~ 0 0 ~ ~ ro ~
~ ~ m NO - ~ MOO 0 ~ 0 00 0 ~ ~ 0 m 0 N ~ ~ ~ 0 0 ~ M ~ ~~ M ~ ro 0 M ~ - N 0 0 000000 NON 0 v ro ~ ro 0 0 ~ M ~ ~
N a ~ m ~ ~ N 0 0 0 0 ci ci ~ M ~ N m M ~ ci ~ m ~ NMM~ ~M~ M o~
~~
M ~NM MN~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
8 ~ ~ ~ 0 N ~ N ~ 0 0 N 0 0 0 ~ ro ~ ~ ro 0 M M V vO 0 - ro m v- ~~~g~~~~g~~ggg~~~R~~~~~;gg~~8g
= M ~ ~ 0 ~ ~ ro~ 0 ~ 0 00 0 ~ ~ ~ 0 M M N ~ ~ moo v M~ 0
E m ~ ci ~ m
~ ~
0 0 ci m M ~ M m ci ~ ci
~ ~
ci ci M ~ ~--M ~N -NMNvMNNN~N
~ ~~ ~ ~~ ~ ~ ~ ~ ~ ~~ ~ ~~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~ ~
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