20070608Tucker direct.pdf

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BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE
APPLICATION OF ROCKY
MOUNTAIN POWER FOR
APPROVAL OF CHANGES TO ITS
ELECTRIC SERVICE SCHEDULES
Direct Testimony of Mark E. Tucker
CASE NO. P AC-07-
ROCKY MOUNTAIN POWER
CASE NO. P AC-07-
June 2007
Please state your name, business address and position with the Company
(also referred to as Rocky Mountain Power).
My name is Mark E. Tucker. My business address is 825 NE Multnomah, Suite
2000, Portland, Oregon 97232, and I am currently employed as a Cost of Service
& Pricing Analyst in the Regulation Department.
Qualifications
Please briefly describe your education and business experience.
I graduated magna cum laude with a B.A. in English Education from Western
Oregon University in 1992, and I received an MBA from Washington State
University in 2007. In addition, I have attended various educational, professional
and electric industry seminars during my career at the Company. I joined the
Company in 2001 and have been working in Regulation since 2003.
Purpose of Testimony
What is the purpose of your testimony?
I will present the Company s functionalized Class Cost of Service Study based on
the twelve month test period ending December 31 , 2006. I will also describe the
differences between this cost study and the cost study filed with the Idaho
Commission in the Company s last general rate case (Case No. PAC-05-1).
Cost of Service
Please describe Exhibit No. 28.
Exhibit No. 28 is the summary table from the Company s twelve months ending
December 2006 class cost of service study for the state of Idaho. It is based on the
Company s annual results of operations for the state of Idaho presented in the
Tucker, Di - 1
Rocky Mountain Power
testimony of Company witness Steven R. McDougal. It summarizes, both by
customer group and by function, the results of the December 2006 cost study.
Page 1 presents results at the Company s December 2006 rate of return assuming
current rate levels. Page 2 shows the results using the return provided by the
$18.5 million requested price increase.
Please describe Exhibit No. 29.
Exhibit No. 29 shows the cost of service results in more detail by rate schedule
and by function. Page 1 contains the total cost of service summary by rate
schedule and pages 2 through 6 contain a summary by rate schedule for each
major function.
Description of Cost of Service Procedures
Please explain how the cost of service study was developed.
Using the twelve months ended December 2006 annual results of operations for
the state of Idaho, the study employs a three-step process generally 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 those costs were incurred.
Please describe functionalization and how it is employed in the cost of service
study.
Functionalization is the process of separating expenses and rate base items
according to utility function. 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
Tucker, Di - 2
Rocky Mountain Power
system utilized for the bulk transmission of power from the generation source and
interconnected utilities to the load centers. The distribution function includes the
costs associated with all the facilities that are necessary to connect individual
customers to the transmission system. This includes distribution substations
poles and wires, line transformers, service drops, and meters. The retail services
function includes the costs of meter reading, billing, collections, and customer
service. The miscellaneous function includes costs associated with demand side
management, franchise taxes, regulatory expenses, and other miscellaneous
expenses.
Describe classification and explain how the Company uses it in the cost of
service study.
Classification identifies the component of utility service being provided. The
Company provides, and customers purchase, service that includes at least three
different components, demand-related, energy-related, and customer-related
components. Demand-related costs are incurred by the Company to meet the
maximum demand imposed on generating units, transmission lines, and
distribution facilities. Energy-related costs vary with the output of a kWh of
electricity. Customer-related costs are driven by the number of customers served.
How does the Company determine cost responsibility between customer
groups?
After the costs have been functionalized and classified, the next step is to allocate
them among the customer classes. This is achieved by the use of allocation
factors that specify each class' share of a particular cost driver such as system
Tucker, Di - 3
Rocky Mountain Power
peak demand, energy consumed, or number of customers. The appropriate
allocation factor is then applied to the respective cost element to determine each
class' share of cost. A detailed description of the Company s functionalization
classification and allocation procedures and the supporting calculations for the
allocation factors are contained in my work papers, which are attached hereto as
Exhibit No. 30. Also included in the work papers is the complete functionalized
results of operations and class cost of service detail.
How are generation and transmission costs apportioned among customer
classes?
Production and transmission plant and non-fuel related expenses are classified as
75 percent demand related and 25 percent energy related. For non-seasonal
resources, the demand-related portion is allocated using the class 12 monthly
peaks coincident with the Company s system firm peak. The energy portion is
allocated using class megawatt-hours adjusted for losses to generation level. For
seasonal resources the process is very similar. The only difference is that prior to
summing each class' twelve monthly coincident peaks or monthly energy usage
the monthly values are weighted by the monthly portion of the total annual energy
generated or delivered to the Company by the seasonal resource.
Are distribution costs determined using the same methodology?
No. Distribution costs are classified as either demand related or customer related.
In this study only meters and services are considered as customer related with all
other costs considered demand related. Distribution substations and primary lines
are allocated using the weighted monthly coincident distribution peaks.
Tucker, Di - 4
Rocky Mountain Power
Distribution line transformers and secondary lines are allocated using the
weighted non-coincident peak method. Services costs are allocated to secondary
voltage delivery customers only. The allocation factor is developed using the
installed cost of new services for different types of customers. Meter costs are
allocated to all customers. The meter allocation factor is developed using the
installed costs of new metering equipment for different types of customers.
Please explain how customer accounting and customer service expenses are
allocated.
Customer accounting expenses are allocated to classes using weighted customer
factors. The weightings reflect the resources required to perform such activities as
meter reading, billing, and collections for different types of customers. Customer
service expenses are allocated on the number of customers in each class.
How are administrative & general expenses, general plant and intangible
plant allocated by the Company?
Most general plant, intangible plant, and administrative and general expenses are
functionalized and allocated to classes based on generation, transmission, and
distribution plant. Employee pensions and benefits have been assigned to
functions and classes on the basis of labor. Costs that have been identified as
supporting customer systems are considered part of the retail services function and
have been allocated using customer factors. Coal mine plant is allocated on the
energy factor.
Tucker, Di - 5
Rocky Mountain Power
Are costs and revenues associated with wholesale contracts and other electric
revenues included in the cost of service study?
No costs are assigned to wholesale contracts. The revenues from these
transactions are treated as revenue credits 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.
Changes in Cost of Service Study
Are there any differences between this cost study and the study filed
previously with the Idaho Commission in Case No. P AC-05-
Yes. This cost study includes the Schedule 400 customer as a single customer
class. In Case No. PAC-05-, this customer was excluded from the cost study
because its special contract rate was not eligible to be adjusted. As part of the
stipulated rate increase effective January 1 2007 (Case No. PAC-06-04)
Schedule 400 was moved from contract standard to tariff standard. The
Commission wrote in Order No. 30197
, "
The transition of Monsanto from
contract to tariff standard customer, we find, will facilitate future rate adjustments
and should serve to keep Monsanto s rates better aligned with its cost of
service. . .. Under the submitted Agreement Monsanto s future rates after January
2008 will be adjusted using the same process as all other customers." In
accordance with the tariff standard, Schedule 400 is included in the cost of service
study with results calculated using the same procedures as for all other rate
schedules.
Tucker, Di - 6
Rocky Mountain Power
What do the cost of service results show for Schedule 400?
The cost of service results show that based on the filed 8.07 percent target return
on rate base, an increase of $11.7 million, or 24.1 percent is indicated for
Schedule 400.
What are the reasons for the proposed price change for Schedule 400?
Prior to January 1 2007, Schedule 400 rates had not changed since January 1
2003. The $6.8 million increase the customer agreed to in Case No. PAC-06-
recovered less than half of the $14.3 million dollar shortfall the Company s cost
of service study showed at that time. The Company s cost of providing service
most notably net power costs, has increased since then, resulting m the need for an
additional increase to Schedule 400. Consistent with past procedure, the current
cost of service results are for firm service only and do not reflect an adjustment or
credit for interruptibility.
Does this conclude your testimony?
Yes.
Tucker, Di - 7
Rocky Mountain Power
Case No. PAC-07-
Exhibit No. 28
Witness: Mark E. Tucker
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Mark E. Tucker
Cost of Service Summary by Rate Schedule
Earned and Target Return on Rate Base
June 2007
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BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Mark E. Tucker
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i i Exhibit No. 30
1 I
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"" I :' r,~;i Witness: MarkE.Tucker~1 --I..1 ~-
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Mark E. Tucker
Cost of Service Work Papers
June 2007
Tab 1
Tab 2
Tab 3
Tab 4
Tab 4.1
Tab 4.
Tab 4.
Tab 4.4
Tab 4.
Tab 4.
TabS
PacifiCorp
Table of Contents
Cost of Service Procedures
Functionalized Results of Operations
Functionalization Factors
Class Cost of Service Detail
Functions (G+T+D+R+M)
Generation
Transmission
Distribution
Retail Service
Miscellaneous
Cost of Service Allocation Factors
PACIFICORP
COST OF SERVICE
FUNCTIONALIZA TION, 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), H,
and M.
The production function consists of the costs associated with power generation, including
coal mining and wholesale purchases.
The transmission function includes the costs associated with the high voltage system
utilized for the bulk traosmission of power from the generation source and interconnected
utilities to the load centers.
The distribution function includes the radial distribution system that connects the customer
to the transmission system. This includes distribution substations, poles and wires, line
transformers, service drops and meters.
The Retail Service function includes the retail activities associated with customer service
including Meter Reading, Customer Accounting, Customer Service activities and Sales.
The Misc. Services function is a catchall for expenses that are associated with regulatory
activities. These activities include franchise requirements and regulatory commission
expenses.
Classification
Classification identifies the component of utility service being provided. The Company
provides, and customers purchase, service that includes at least three different
components: demand-related, energy-related, and customer-related.
Demand-related costs are incurred by the Company to meet the maximum demand
Tab 1 Page 1 of 11
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-r€lated
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 customers. The appropriate allocation factor is then applied to the respective
cost element to determine each class' share of cost. Factors with two digits (Le. F30 -
MWH) identify allocation factors that are ~alculated using cost driver information that is
external to the cost study.
Many expense and rate base items track plant investment or some other value in the cost
of service study. The allocation factors for these items are internally generated within the
cost of service model. Internally identified factors are identified with three digits (Le. F102
- Gross Plant). Many plant related allocation factors are identified by function and are so
identified (F102G - Generation Plant, F102T - Transmission Plant,F102D - Distribution
Plant and so on).
FUNCTIONALIZA TION PROCEDURES
For regulatory reporting purposes costs are collected into the Business Warehouse (BW)
database. Each account balance in BW is assigned a functional identification or FUNC
Factor. Account balances captured in BW that are directly related to one of the primary
business functions - P, T, D (or DPW), R, or M - are so designated. The functional
designation is generally driven by the location code associated with an asset or
transaction. In some cases, the customer service system for example, the business
purpose of the asset or transaction is used rather than the physical location. Assets and
expenses that support more than one of the five (for example, administrative and general
Tab 1 Page 2 of 11
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 BW are aggregated by FERC account and by Revised Protocol
jurisdictional allocation factor and roll up to a single line item. Each of these line items is
also assigned or allocated to one or more 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 Revised Protocol factor have the same
functional designation , that FUNC factor is used. For example any item allocated to a
jurisdiction using the SE factor is generally fuel related and assigned to the generation
function using the "P" FUNC factor.
When the various account balances from BW that roll up to one line in the JAM have more
than one functional designation, a new FUNC factor is developed. An example of this is
the SCHMAT-SO FUNC factor. Of the Schedule M Additions Temporary account
balances allocated on the SO Protocol factor, some are labor related, some are directly
associated with generation and some are overall plant related. Each of these account
balances is assigned or apportioned to the appropriate function. The SCHMAT-SO FUNC
factor is derived from the summation of the account balances by function. The Schedule
M Additions Temporary allocated to a state using the SO Protocol factor are then assigned
to functions using the SCHMAT-SO FUNC factor.
Some FUNC factors, such as the Production , Transmission and Distribution (PTD) factor
or the Cash Working Capital (CWC) factor are calculated from data inside the JAM
model.
Operation Revenues:
General Business Revenue: Account 440-445. Residential Revenues, and Account 442
Retail- Commercial and Industrial Revenues, are not functionalized. The dollar amounts
assigned to PTDRM for retail revenues have been derived to produce the jurisdictional
normalized ROE.
Interdepartmental: Account 448. Interdepartmental Sales, is allocated to Distribution
Poles & Conductor (DPW).
Special Sales: Account 447. Firm Wholesale Sales (sometime referred to as Sales for
Resale), are allocated on the Wholesale Sales Factor
, "
WSF". This factor is developed by
identifying the production transmission components of wholesale sales.
Other Operating Revenue: Accounts 450 to 456. Other Revenues, is functionalized on
the "OTHREV" factors. The vast majority of revenue in this line item is associated with
Tab 1 Page 3 of 11
account 456 and has 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 & D. Costs that have been identified as
supporting customer systems are considered part of the retail function. Account 926,
Pension Benefits and Account 929 Duplicate Charges are functionalized on the "LABOR"
functionalization factor. The "LABOR" factor is based on the FERC Form 1 breakdown of
labor expenses between P, T, D & R (As shown above, Customer Accounting, Service and
Sales are considered part of the R function). Account 927 Franchise Requirements, and
Account 928, Regulatory Commission Expense are assigned to M. Account 928, FERC
annual charge is functionalized on the "FERC" factor with the balance going to M.
Account 935 is functionalized on the General Plant "G" factor.
Depreciation: Account 403. The functionalization of depreciation matches the
functionalization of rate base. For example, the functionalization of General Plant
Depreciation expense matches the functionalization of General Plant rate base.
Amortization: Accounts 404-407. Account 404, Amortization of Limited Term Electric
Plant is functionalized based on analysis of the items being amortized to this account with
the vast majority of the money being functionalized by PTD or CUST. Account 405, Other
Electric Plant Amortization is allocated on the "GP" factor. Account 406, Plant Acquisition
Adjustment Amortization and Account 407, Amortization of un-recovered Plant are
assigned to P.
Taxes Other Than Income: Account 408. 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
Tab 1 Page 4 of 11
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, using the
DITEXP" factor. Deferred taxes associated with employee benefits are functionalized
using the "LABOR" factor. Items associated with property taxes are functionalized using
the "GP" factor. Items that can be directly associated with a function are directly
functionalized using "P" or "PT" factors.
Investment Tax Credit Adjustment: Accounts 411.40 & 411.41. The Federal deferred
investment tax credit was functionalized on the "PTD" factor.
Miscellaneous Revenue & Expense: Accounts 411.8, 421 & 431.1. The gains and
losses arising from the sale of utility 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, is 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 Business
Warehouse reports of general plant. BW identifies investments by accounting location , as
Tab 1 Page 5 of 11
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
BW listing were functionalized on the "PTO" factor and those items associated with the
customer service system were functionalized to R. A separate General Plant
functionalization factor was developed to correspond to each PITA allocation factor.
Intangible plant was functionalized in the same manner.
Plant Held for Future Use: BW tracks Account 105 transactions to production
transmission , general and mining totals. Production and mining are assigned to P, and
transmission to T. The general amount is functionalized using the "G" factor.
Deferred Debits: BW tracks and collects deferred debits that are related to production.
These costs are assigned to P directly. Situs and system overhead debits are
functionalized using the "OEFSG"
, "
00S02" and "00S06" functionalization factors.
These three factors were developed by generating a detailed listing of BW debits to situs
and system overhead.
Electric Plant Acquisition Adjustments: Account 114. All Electric Plant Acquisition
Adjustments are assigned to P.
Prepayments: Account 165. Situs prepayments for franchise taxes and regulatory
commission fees are assigned to R. Fuel related prepayments are assigned to P.
Property insurance was functionalized using "PTO". Other prepayments are functionalized
using the "PT" functionalizationfactor.
Fuel Stock: Account 151 assigned to
Materials & Supplies: Accounts 154 163 & 253.18. Materials and Supplies are
functionalized using the "MSS" factor. This functionalization factor was developed using
FERC form 1 data.
Working Capital: Accounts CWC, 131, 135, 143,232 & 253. Cash Working Capital is
calculated by subtracting the expense lag days from the revenue lead days and multiplying
this difference times the daily cost of service. The daily cost of service is calculated within
the model by adding 12 months of O&M, Taxes Other than Income, and State and Federal
Income Taxes and dividing by 365. This amount is functionalized using the "cwc" factor.
The "cwc" factor is internally calculated by adding the O&M, Taxes Other than Income,
and State and Federal Income Taxes, for each of the three functions and dividing by the
functional total, (Productionffotal, Transmissionffotal, Oistributionffotal).
Weatherization: Accounts 124, 182, 186. Weatherization loans and other deferred debits
related to conservation and OSM programs are assigned to M.
Tab 1 Page 6 of 11
Other Miscellaneous Rate Base: Accounts 182.22 & 141. Other miscellaneous rate
base includes the deferred debits related to the Trojan Nuclear Plant which are assigned
to P.
Accumulated Provision for Depreciation & Amortization: Accounts 108 & 111. The
functionalization of the accumulated depreciation matches the functionalization of rate
base.
Accumulated Deferred Income Taxes: Accounts 190 281-283. The largest component
of accumulated deferred income taxes is due to timing differences between book
depreciation and tax depreciation. This timing difference is functionalized on the
ACCMDIT" factor. Detail to develop this factor is supplied by the Tax Department. The
percentage for P in the "ACCMDIT" factor, for example, is developed by taking the total of
production items as determined by the Tax Department and dividing it by the total of all
PTDRM items. This includes the accumulated deferred income taxes arising from general
plant which are functionalized using the "G" factor for the purposes of developing the
ACCMDIT" factor.
Unamortized Investment Tax Credits: Account 255. The accumulated investment tax
credits are functionalized using the "PTD" factor.
Customer Advances for Construction: Account 252. State situs customer advances for
construction are assigned to D. System allocated advances are assigned to T.
Customer Service Deposits: Account 253. Customer service deposits are assigned to R.
Other Miscellaneous Rate Base Deductions: Account 228. All items are functionalized
using the "PTD" factor.
CLASSIFICATION AND ALLOCATION PROCEDURES
Generation and Transmission Costs
The methodology used in this study for the classification and allocation of generation and
transmission costs is consistent with the MSP Revised Protocol method approved by the
Idaho Commission in Case No. PAC-02-3 on February 28, 2005. The MSP Revised
Protocol identifies four categories of Resources: Seasonal Resources, Regional
Resources, State Resources, and System Resources. Fuel costs are classified as 100%
energy related. Production and transmission plant and non-fuel related expenses for all
resources are classified as 75% demand related and 25% energy related. The costs of
Seasonal Resources are allocated using seasonal factors because they are designed to
be used more intensively at certain times of the year. All other resources are allocated
using non-seasonal factors.
Tab 1 Page 7 of 11
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 PacifiCorp by the Seasonal Resource. For example, if 30 percent of the
annual generation of a particular Seasonal Resource occurs in July, the monthly
Coincident Peak for July would be weighted by 30 percent in the calculation of the
allocation factor. This, in essence, allocates 30 percent of the demand related cost for
that resource among classes based upon their contribution to the July Coincident Peak
and 30 percent of the energy related costs based on each class' July energy usage.
The demand costs associated with seasonal simple cycle combustion turbines, SCCT's,
are allocated on factor (F13) and the energy portion is allocated on (F32). The fixed costs
composite factor for the SCCT's is (F14). The demand costs associated with Seasonal
Contracts are allocated on factor (F17) and the energy portion is allocated on (F37). The
fixed costs composite factor for the Seasonal Contracts is (F18). The demand costs
associated with Cholla IV are allocated on factor (F15) and the energy costs 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.
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.
Tab 1 Page 8 of 11
To understand how demand-related costs are treated it is first necessary to understand
the concept of diversity. Diversity is the characteristic whereby individual customer peak
demands usually occur at different times. Because of this, a piece of equipment, such as
a power plant or a substation, which is used by many customers, does not need to be
large enough to meetthe 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 diversity in the load on each piece of equipment also
declines. While the transition between system costs and facilities costs occurs gradually
over the distribution system, it becomes necessary in a cost study to draw a line between
equipment which is judged to fit best into each of the categories.
Substations and Primary Lines
Distribution substations and primary lines fall into the system costs category. Because
many customers use substations and primary lines, an allocation methodology that
recognizes the diversity of load among the customers is used. Distribution substations
and primary lines are allocated using the weighted monthly coincident distribution peaks
(F20). The coincident distribution peak is the simultaneous combined demand of all
distribution voltage customers at the hour of the distribution system peak. These monthly
values are weighted by the percent of substations that achieve their annual peak in each
month of the year.
Line Transformers
Distribution line transformers are used either by only one or by a small number of
customers. As such, they are considered part of the facilities category. Since the cost
responsibility for line transformers is incurred at the time a load is added to the system
that cost responsibility should be assigned on the basis of individual customer installed
capacity. Assignment of cost based on installed capacity cannot be done directly because
of a lack of detailed property records. As a surrogate for installed capacity, we use the
maximum monthly class NCP estimates from load research data.
Only customers taking service at secondary voltage are allocated distribution line
transformer costs. The allocation factor (F21) is based on the maximum monthly class
NCP. This may be a different month for each class. For classes of customers where
transformers are shared by more than one customer, the NCP is weighted by the
appropriate coincidence factor from the Company s Job Designer s Manual to recognize
the diversity of load at the transformer.
Tab 1 Page 9 of 11
Secondary Lines
Distribution secondary lines operate as an extension of the line transformer. They are also
allocated using the weighted NCP method. Only customer classes where transformers
are shared by more than one customer are allocated the costs of distribution secondary
lines. (F22)
Services and Meters
Services costs are allocated to secondary voltage delivery customers only. The allocation
factor is developed using the installed cost of newly installed services for different types of
customers. (F70)
Meter costs are allocated to all customers. The meter allocation factor is developed using
the installed costs of new metering equipment for different types of customers. (F60)
Customer Accounting, Customer Services & Sales
Customer accounting, customer service, and sales expenses are considered customer-
related costs. They are allocated to customers using weighted customer factors. The
weightings reflect the resources required to perform such activities as meter reading,
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. (F47)
The customer weighting for Customer Accounting and Records expenses, Account 903, is
a composite of the number of customers, customers receiving manual bills and the
amount of write-offs by customer class. (F48)
Uncollectible Accounts expense is allocated based on class net write off history. (F80)
Customer service expenses are allocated on number of customers (F40).
General & Intangible Plant, Administrative & General Expenses
Most general plant, intangible plant, and administrative and general expenses are
functionalized and allocated to classes based on generation, transmission, and distribution
plant (F1 02). Employee Pensions and Benefits costs have been assigned to functions
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
(F141).
Taxes
State and Federal Income Taxes are allocated on Rate Base (F101). An embedded cost
of service study is designed to determine the revenues needed to provide an equal rate of
return for all classes. At full cost of service, allocating income taxes on rate base
Tab 1 Page 10 of 11
produces the same result as allocating on income. This simplifies and reduces the size of
the cost model by eliminating the need to allocate all of the taxable income adjustments.
Deferred Income Taxes are allocated primarily on Net Plant (F104). Most deferred taxes
are a result of plant investment. Deferred Income Taxes associated with bad debt are
allocated using customer factors (F42). Deferred Income Taxes associated with employee
benefits are allocated using labor (F138).
Taxes Other Than Income Taxes are allocated on Plant (F101). The bulk of taxes other
than Income Taxes are property taxes. Property Taxes are assessed on plant investment.
Rate Base Additions and Deductions
Additions and deductions that relate to Generation and Transmission plant are allocated
accordingly (F10). Items that are associated with Distribution plant are allocated in a
similar manner (F20). Items directly relating to fuel or coal mining are allocated on energy
(F30). Weatherization investments are allocated on (F40) consistent with customer
service expense. Accumulated Deferred Income Taxes are allocated consistent with
Deferred Income Tax Expense (F104). Customer advances for Construction are allocated
based on recent history for Contributions in Aid of Construction (F50). Where applicable
Customer Deposits are allocated on recent deposit history (F51). All other additions and
deductions are allocated on Plant (F1 02).
Revenue Credits
In the class cas study, no costs are assigned to wholesale transactions. The revenue
from these sales is treated as a revenue credit and is allocated to customer groups using
appropriate allocation factors. Other electric revenue is also treated as a revenue credit.
Revenue credits reduce the revenue requirement that is to be collected from firm retail
customers.
Sales for Resale revenue is classified between demand related (F10) and energy related
(F30). Other Electric Operating Revenue is assigned as closely as possible to the specific
customer classes providing the revenue.
Tab 1 Page 11 of 11
REVISED PROTOCOL
Beginning/Ending
RESULTS OF OPERATIONS SUMMARY
IDAHO
DeeeriDdDn of Account SuIlllll8rv:tSm!!IDJI Tren.ml.eIDn R!I!II
Genenol Bu.ine.. Revenue.178 992,943 133,117,998 755,100 119 745 32,070,145 196,398 853 202
Generel Busine.s Revenues
Int_por1mentel
Specill Solas 122,881,936 109835,118 248,818
Other Operating Revenue.331,774 283,833 335,557 712,5&4 359772 352,588 224
Totel Opereting Revenues 308,206 552 244,036,749 23,337,474 832,329 32,429,917 54&,986 853426
OpeI8ting e.pen...:
Sleam Production 51,804283 804,283
Nucleiit' Production
Hydro Production 324,572 324,572
Other Power Supply 152,299,347 152,299,347
Tre..nia.lDn 009,675 009,875
Distribution 136,621 10.138,821 136,621
Cuatomar AccDunta 588,151 588,151 588,151
Customer 861,078 861,078 881 078
Sale.
AdmIniatretive & General 578 462 058475 185,029 352,958 693,462 344,802 314,695
Totel 0 & M Expon..s 243 398,189 211,488,858 174,704 20,738,809 830,083 592,030 314 695
Deprecietion 24,581;802 13,111,771 171,260 298,770 243,278 55,493
Amortizetion Expo..e 344,839 027,815 514,833 802,190 609,776 192,414
Texe. OthorThln Income 930,519 280937 977804 891 978'691 931
Income Taxes - Federal 800890 (12,983)384.854 229,199 806,758 251,744 170697
Income Taxe. - State 282,838 91,702 556 145,578 547 29,815 20.216
Income Taxe. - Del Net 508,352 212,152 597 281 603 019 647 261 956
Investment Tax Credn Adj,(757,790)(364,897)(186,800)(228,094)(228,094)
Mise Re.enue & Exponse (168461)(175448)980 988 986
TD18' OpeI8ting Expen..s 279.721 136 229,837,726 17,119369 32,964,020 25,074912 383,500 505608
Operating Rlvenue for Retum 28,485417 399,022 218,085 888,309 355,005 165 488 347 818
Rete Be.e:
Electric Plent in ServIce 928,123 257 456,196,483 195,488 973 272,439,820 287,246267 191 554
Ptent Held lor Future U..
Mise Defend Debits 916,010 357,855 622,788 (94,433)(5,523)(105 358)446
Elec Plent Acq Adj 047,975 047975
Nuclear Fuel
Prepayments 774,200 893,938 315,878 564,384 407,077 157,302
Fuel SIDck 740,834 740,834
Metorial & Supplie.488,667 8,266,887 412,070 807,730 807,730
_ngCIlJiteI 188,378 970,782 425,181 772 415 669,496 888 051
Weatherizetion lDlns 828,433 828433 828.433
Miscelleneou. Rite Be.e 587735 587,735
TDteI Electric Plenl 960,873 488 482,062,250 198,262890 280 348,348 269,127,046 182,070 039,232
Rite Be.. Deductions:
Acalm Pro. For Del"(358,234,391)(180,599244)(87,944,513)(107,890834)(107465,306)(225,328)
Accum Prov FDr Amort (20,727,275)102,454)(3,740,404)(7,884,418)(4,883967)000,451)
Acalm Del Income Taxe.(18015,264)(35,358,678)(16 753,382)(25,903,204)(26,820,287)917,083
Unamortized ITC (2,125 317)(1,023,398)(487,811)(634,108)(634,108)
Customer A4v for Conll (259,285)(258,980)(305)(305)
Customer Service Deposita
Mi.e, Rile Bese DeductIons 714,054)(5,965,414)131,964)~1,616 677)616,666)(11)
TDtel Rite Be.. DeductiDns (488,075,587)(232,049,188)(90,297 053)(143,729348)(141 420,640)308 706)
TDtel Rate Be.e 494,597902 250,013,062 107,985,837 136,819,002 127 706,407 873,384 039,232
Retum on Rite Be.e 759%759%759%759%759%759%759%
Return on Equity 275%5.275%275%275%275%275%275%
100 BesiI Points in Equity:492,773 1,280,068 544,148 888560 843,840 14,482 436
Revenue Requiremenllmped 017,362 030,727 878,951 109885 037,293 23,339 054
Rite Be.. Decree"(39,799,830)(20,118,218)887,886)(10,99354&)(10 278,363)(231 216)(485,989)
Tab 2 Page 1
DeocriDIIDn Df AccDunt Summary:
REVISED PROTOCOL
Seainnina/Ending
FERC BUSINESS PITA
DESCRIPTION
Solei 10 Ultimate Cuotome..
440 Rolidentill Salol
442 CDmmerci81 & Indultri81 So101
444 Public StrHt & HighWoy Ughting
445 Other Solei tD Public AuIhDrity
448 Intenlep.or1menlal
DPW
100
101
102
103 TDtal Sola to Ultimata Cultomero
104
105
106
107 447 SoI.11Dr Reule
108 WSF
109 WSF
110 WSF
111 WSF
112
113
114 449 Prevision IDr Rite Refund
115 WSF
118 WSF
117
118
119
120
121 Total Sala from ElectrfcIty
122 450 Ferfeited DIlCDUnta & Int""'lt
123 CUST
124 CUST
125
126
127 451 Milc Electric Reven",
128 CUST
129
130
131
IDAHO
Tranlmlaalon B!/!!I MiK
IDAHO
!r!nImi!Ii2I!Bt.IIiI
(0)(0)
51,050,462 133,117,998 755,100 40,119,745 070 145 196,39B 853 202
050462 133,117998 755100 40,119,745 32070,145 196,398 B53 202
127,891,069
127 891069
251 3f2
251312
178992843 133117998 5755100 40 119745 32070,145 7186 398 853202
122,881,938 109,835,118 13,246 818
122 B81,938 109635118 13246818
301 874779 2012753118 19001 918 40 119 745 32070145 7186 398 853202
238,900 238,900 238,900
238 900 238.900 238,900
115 688 115,688 1156B8
1470 670 293 507 507
117158 870 293 116,195 507 115688
Tab 2 Page 2
Deacriotion of Account SummaIV:
132
133 453 Wiler Sales
134
135
136
137 454 Rent 01 ElectriC property
13S DPW
139
140
141
142
143
144
145 456 Other Eleclric Revenue
146 DM5C
147 CU5T
148 OTH5E
149 OTHSO
150 OTHSGR
151
152
153
154
155 Total Other Electric Revenue.
156
157 Total EJectrtc Operating Revenuea
158
159 Summary 01 Revenues by FldDr
160
161
162
163
164
165 DGP
166
167 Total EIecIric Operating Revenues
168 Miscellaneous Revenues
169 41160 Gain on Sale 01 Utility Plonl- CR
170 DPW
171
172
173
174
175
176
171 41170 Lou on SIIe 01 Utility Plant
178 DPW
179
160
181
182 4116 Gain 110m Enis8iDn Allowances
183
184
185
166
187 41181 Gain 110m Disposition 01 NOX Cre0t8
166
189
190
191 4194 Impact Housing Interest Income
192
193
194
195 421 (Gain) Lou on Sale of Utility Plant
196 DPW
197
198
199 PTD
200 PTD
201
202
203
204 Total Mlacellaneous Ravenuea
205 Miscellaneous Expenses
206 4311 Inlerest on Customer Deposits
207 CU5T
208
209,Total MlscaUaneoua ExpeIlHl
210
211 Net Mlac Revenue and Expenaa
IDAHO
H!!!m!.I!U!I Transmluion B!!IlI
960 960
960 960
354,846 354 846 354,846
309,428 309,428
12794 830 2550 414 414
677 069 830 311,979 359 260 359,260
224 224 224
788,623 111,226 675,395
512 826 184,939 347,887
5299,687 1 276 173 4 023,285 229 224
6331774 283 833 4335 557 112,584 359772 352588 224
308206"2 244 038749 23 337414 40,832 329 32429917 548,988 853428
179,700,501 133,111,998 755 100 827,403 32,424991 548,966 853426
788,823 111,228 675,395
14,278 506 846 928 926
127,705,150 110,601,017 904,133
308 206 552 244 036 749 23337474 40 832,329 32429917 7548966 853426
1172 883 1172,8831
1172683 (172883\
(32)(32)(32)
727 313 600 814 814
741 172 3&1 205 205
/9,050 /9,050\
4401 125651 2980 3986 966
/188481 /175448\2980 3988 3986
1188 481 /175448\2880 3988 888
Tab 2 Page 3
DeeenDtiDn Df Account SummarY:
212
213 500 Operation Supervision & Enginaenng
214
215 SSGCH
216
217
216 501 Fuel Releted
219
220
221
222 SSECT
223 SSECH
224
225
226 502 Steam Expens..
227
228 SSGCH
229
230
231 503 Sleom From Other Source.
232
233
234
235 505 Eledrie Expon...
236
237 SSGCH
238
239
240 506 Mise, Steom Expon..
241
242
243 SSGCH
244
245
248 507 Ron..
247
248 SSGCH
249
250
251 510 Meint SupeNi.iDn & Enginaering
252
253 SSGCH
254
255
256
257
258 511 Meinlena'" Df SInICtu....
259
260 SSGCH
281
262
263 512 Mainl...... Df Boiler Plent
264
265 SSGCH
266
267
288 513 Maintenance of Electric Plant
269
270 SSGCH
271
272
273 514 Meint.ne... of Mi.e, Stum Planl
274
275 SSGCH
276
277
278 Tol8lSleIm PDWIt' Generation
IDAHO
ti9!mIIiU!!fm!I!!s!i2D Tranomioolon BI1I!!
591,847 591 847
88 926 926
1680 774 1680 774
32,188 466 32,188466
084662 084 662
35,273128 273,128
881,317 881,317
145 181 145 181
026,498 026,498
282,164 282,184
262 164 262 164
180,494 180,484
947 947
259,442 259442
823014 823014
104 042 104 042
1 927058 927,058
66,255 66,255
169 169
73423 73423
326,135 326 135
141,923 141923
488 058 488 058
185,654 185,654
39394 39,394
1225,047 225047
500,063 500,063
176 961 176 961
677,023 5677 023
009,231 009,231
37728 37,728
046 959 046 959
738 752 736,752
145,938 145938
884691 884,691
51804 283 51804 283
Tab 2 Paga 4
ee.criDtion of Account Summorv:
279 517 Operation Super & Engineering
280
281
282
283 518 NucIe.r Fuel Expen..
284
285
286
287
286 519 CooI.nllanll Wlt.r
289
290
291
292 520 Steam expen...
293
294
295
298
297
298 523 Electric expen...
299
300
3Ot
302 524 Mise, Nuclear Expen.a.
303
304
305
306 528 Maintenance Super & Enginaerin9
307
308
309
310 529 Malnt.nance of Structure.
311
312
313
314 530 Maintenance of R..clDr Plant
315
316
317
318 531 Maintenance of Electric Plant
319
320
321
322 532 Maintena.... of Mise Nuclear
323
324
325
326 Tol8l Nuc"', PoWlr Ge.....tIon
327
IDAHO
f!2!I!!s!i9D T....mlulon DI!!DI!!I!i2D BI!IlI
Tab 2 Page 5
DescriDIIDn of AccDunt Summary:
328 535 Operation Super & Engineering
329 DGP
330
331
332
333
334
335 536 Water Far Power
336 DGP
337
336
339
340
341
342 537 Hydraulic Expanses
343 DGP
344
345
346
347
348
349 538 EIactric Expanses
350 DGP
351
352
353
354
355
356 539 Misc. Hydro ExpanHl
357 DGP
358
359
360
361
362
363
364 S4O Rants (Hydro GonaratiDn)
365 DGP
366
367
368
369
370
371 541 Mainl SUparvisiDn & Engineering
372 DGP
373
374
375
378
377
378 542 Maintenenea Df Structures
379 DGP
360
381
362
383
3&4
385
386
387
368 543 Maintononea Df Dama & Waterways
369 DGP
390
391
392
393
394
395 544 Maintononce Df Electric Plant
398 DGP
397
398
399
.coo
401
402 545 Maintenance of Mise. Hydro Plant
403 DGP
.co4
405
.we
407
.coa
409 TDtal Hydraulic PDwer GenarallDn
IDAHO
TransmiselDn !!!.!Ill .M!!s
327,259 327,259
183 615 183,615
510875 510,875
937 937
298 298
15233 15,233
249,927 249.927
059 059
290 986 290 986
200 200
239 239
786,218 788,218
339,081 339,081
127299 127299
007 007
936 938
5945 5945
55,793 793
11,780 11,780
67573 87,573
517 87,517
20,242 20,242
87759 87,759
25,325 25,325
939 33,939
59,265 59285
123 365 123,365
36,033 033
159398 159398
2324 572 2324 572
Tab 2 Page 6
eoocriDtiDn 01 AccDunt SUmmllY:
410
411 546 Operotion SUper & €ngineorin9
412
413 SSGCT
414
415
416 547 FuoI
417
416 SSECT
419
420
421 548 GenerotiDn Expense
422
423 SSGCT
424
425
426 549 MiIcoIloneouo Other
427
428 SSGCT
429
430
431
432
433
434 550 Moinl SUporviaiDn & Engineering
435
436 SSGCT
437
438
439 551 Moint SuperYiIion & Enginoering
440
441
442
443 552 Mlln_nco of Structurol
444
445 SSGCT
446
447
446 553 Molnl of Geno- & Electric Plont
449
450 SSGCT
451
452
453 554 Moln_nco of MioC, 011181'
454
455 SSGCT
456
457
458 TDtol 0th8r powsr _lion
IDAHO
ronomulDn W!!!:iI!Y!I2I!Dlotribution B!!!!!MI&
73,036 73,036
73,036 73036
572,478 14,572,478
3862,791 3862,791
455269 18455269
530,787 530,787
306,837 306 837
837624 837624
874,744 674,744
674744 674 744
35,711 711
917 673 917,673
953364 953364
328 328
10,650 10650
16978 16,978
103,425 103425
70,827 827
174251 174251
283 16,283
13680 680
943 29943
21215229 21 215229
Tab 2 Page 7
eeocnotion of Account Summorv:
459
460
461 555 Purchooed Powor
462 DMSC
463
464
465 SSGC
4e6 DGP
467
4e6
469
470 556 SYltem ConIrDI & Load Dilpotch
471
472
473
474
475
476
477 557 Other Expensel
478
479
480 SGCT
461
482 SSGCT
463 TROJP
484
485
486
467 Embeddod Colt Diller."'"
486 Compony Owned Hy"" P DGP
469 Compony Owned Hydn P
490 MIcI-C CanDid
491 MIcI-C Comacl
492 ExIsting QF Controd.
493 ~QF~
494
495
496
497 Total Other POW8t' Supply
498
499 TOTAL PRODUCTION EXPENSE
500
501
502 Summory of Production e.pense by Foetor
503
504
505
506 SNPPH
507 TROJP
508 SGCT
509 DGP
510 DEU
511 DEP
512 SNPPS
513 SNPPO
514 DGU
515
516 SSGCT
517 SSECT
518 SSGC
519 SSGCH
520 SSECH
521 Toto! Production e.penle by Factor
IDAHO
Tronlml..lon ID!1!I!!!!!I2I!BtJII!
114,385,440 114 385,440
477,300 477,300
3,250,835 250835
121113,575 121 113,575
158,993 158,993
158993 158 993
963 397 963,397
237,568 237,568
259 259
4201224 201,224
56&614 56&,614
(884,030)(884 030)
070 074 070,074
604,429 604,429
(2,746762)12,746,762)
610,325 610325
131084118 131084118
206,428 182 208 428182
567 826 567,826
142 739,574 142,739 574
500409 50,500,409
(884,030)(884,030)
319,905 319905
882,791 882,791
250,835 250,835
986,210 986,210
084 882 084 882
208428,182 208 428 182
Tab 2 Page 8
eescriollon Df Account Summorv:
522 560 Operation Supe".;sion & Engineering
523
524
525
526
527 561 Lo8d Dispatching
526
529
530
531 562 SIIIIion Expense
532
533
534
535
536 563 Overt1ead Uno Expense
537
538
539
540
541 564 Underground Une Expense
542
543
544
545
546 565 T...smillion Df Electricity by Others
547
548
549
550
551
552
553 566 Mile. Transmillion Expense
554
555
556
557
558 567 Renll - Transmillion
559
560
581
562
563 568 Malnt Supervision & Engineering
564
565
566
567
568 569 Meinten..... 01 Structures
569
570
571
572
573 570 Mointenonee 01 StIllion Equipment
574
575
576
577
578 571 Mainten..... 01 OvetIIaad Unes
579
580
581
582
583 572 Maintenance 01 Underground Unes
564
585
566
587
588 573 Maint Df Misc. Transmission Plont
589
590
591
592
593 TOTAL TRANSMISSION EXPENSE
594
595 Surnrn8IY 01 Transmission Expense by Factor
596
597
598 SNPT
599 Tolll Transmillion Expense by Factor
IDAHO
Tranamillion J2I!!I:iI!J!!I2 BI!!iI M!&
505,987 505,987
505,987 505987
413 845 413,845
413845 413845
182 20,182
20182 182
148315 146,315
146315 146,315
388,708 388,708
611 611
396 319 396 319
59,209 59,209
209 59,209
52,878 52,878
52678 52878
1,247 247
1247 1247
117,207 117,207
117 207 117 207
634 569 634,569
634,569 634 569
616 294 616,294
616 294 616 294
624 45,624
45624 45624
9009,675 9009875
611 611
000,084 000,084
009 675 9009675
Tab 2 Page 9
D..crtotion of Account Summary:
600 580 Operation Supervision & Engineering
601 DPW
602 DPW SNPD
603
604
605 581 Load Dilpl1ching
608 DPW
607 DPW SNPD
608
609
810 582 Station e.pen..
611 DPW
812 DPW SNPD
613
814
615 583 Ovorh..d Un. e.pen...
816 DPW
817 DPW SNPD
618
619
620 584 Underground Un. Expons.
621 DPW
822 DPW SNPD
623
624
625 585 Stroot Ughting & Sign.1 Sy.tema
626 DPW
827 DPW SNPD
628
629
630 586 M.t.r EJcpen...
631 DPW
832 DPW SNPD
633
634
835 587 Cu.tomer Inslallotion expen.e.
638 DPW
837 DPW SNPD
638
639
840 588 Mise, Dia1ribulion e.pen...
841 DPW
842 DPW SNPD
643
844
645 589 R.nts
646 DPW
847 DPW SNPD
646
849
650 590 Maint Supervision & Engineerin9
851 DPW
652 DPW SNPD
653
654
855 591 Maintenance 01 Struchn'8.
856 DPW
657 DPW SNPD
658
859
680 592 Meint.n...... 01 SIaIiDn Equipment
861 DPW
862 DPW SNPD
863
864 593 Mainton.nce 01 Overh.ad Un..
865 DPW
868 DPW SNPD
867
868
869 594 Maint.nance of Underground Un..
670 DPW
871 DPW SNPD
672
673
874 595 Maintonance of Un. Transformers
675 DPW
678 DPW SNPD
677
878
879 596 Maint of Stroot Ughting & Signal Sy.,
680 DPW
681 DPW SNPD
662
663
IDAHO
Tran.mla.lon Q!!!DI!sdi2I:I B!!!II M!!i
(14069)(14,069)(14,069)
902870 902,870 902,870
888,801 888801 888 801
573,292 573,292 573292
573292 573,292 573292
299,754 299754 299,754
819 619 7819
307373 307,373 307,373
958,203 958,203 958 203
42788 42,788 42,788
1 000 991 1000,991 000 991
15,717 717 15,717
15,717 717 15717
175 175 7175
175'7175 175
189,442 189,442 189,442
945 66.945 86 945
256 388 256 388 256 388
349,106 349,106 349,106
532,033 532,033 532033
881139 881139 881139
32,198 32,198 32,198
31,281 261 281
459 459 83459
106 329 106 329 106,329
106,329 106,329 106,329
106,800 106,800 106,800
15,320 15,320 15,320
122120 122120 122,120
845,335 645,335 845335
107864 107864 107864
752,999 752999 752,999
784,972 784 972 784,972
178928 178,928 178,928
963 899 3963 899 963,899
658,468 858468 858,468
434 8434 434
864 902 864 902 864,902
18,922 922 922
395 2395 2395
19317 317 19,317
185654 165 854 165,654
223 223 223
185877 185,877 185,877
Tab 2 Page 10
De8CriDtion of Account SUrntlUlrv:
6&1 597 Meinletiance 01 Meters
685 DPW
eee DPW SNPD
887
eee
889 599 Mein!DI Mile. DisltibutiOn Plen!
690 DPW
691 DPW SNPD
692
693
694 TOTAL DISTRIBUTION EXPENSE
695
696
697 Sunvnary 01 DistributiDn ~se by Foetor
69S
699 SNPD
700
701 Total Distribution Expen.. by Foetor
702
703 901 SupeNision
704 CUlT
705 CUlT
706
707
706 902 Meter Reading Expense
709 CUlT
710 CUlT
711
712
713 903 Customer Receipts & Collections
714 CUlT
715 CUlT
716
717
716 904 Uncollectible Accounts
719 CUlT
720
721 CUlT
722
723
724 905 Mise, customer AI:counll Expense
725 CUlT
726 CUlT
727
728
729 TOTAL CUSTOMER ACCOUNTS EXPENSE
730
731 Sunwnory 01 Cuotorner AcctI Exp by F
732
733
734
735 Totsl CUI\DmIIr Accounts Expon.. by Fedor
736
737 907 supervision
738 CUlT
739 CUlT
740
741
742 908 CUslomer Assistance
743 CUlT
744 CUlT
745
746
747
748
749 909 Inlormlltionsl & Instructional A4v
750 CUlT
751 CUlT
752
753
754 910 Mise, CUSlomer Servic8
755 CUlT
756 CUlT
757
758
759
760 TOTAL CUSTOMER SERVICE EXPENSE
761
762
763 summery 01 Customer Service Exp by Fodor
764
765
766
767 Totsl Cullomer SeNice Exponse by Foetor
IDAHO
I'J2!:mIlID!!Transmlaslon I2I!.!!:I!!!!!i .B!!II!MiK
248605 248,605 248,605
89053 053 053
337,658 337,658 337658
728 728 728
4456 456 456
164 164 164
10138621 10,136821 10138621
461,836 461 636 481 836
674,785 874 765 674,785
10 136 621 10136,621 10136621
385,6&1 365,664 365864
246 645 246,645 246,645
632,509 632509 632,509
317,828 317,626 317,828
182 272 (82,272\/82 272\
235555 1 235,555 235555
251 197 251 197 251 197
1 942,695 942,895 942,895
194 092 194092 194,092
263,180 263,180 263 180
210,454 210,454 210 454
473,634 473634 473634
359 359 359
50,359 50,359 359
4586151 586,151 4588151
217,889 217,889 217,669
368.282 368,282 368 282
4566 151 4566 151 588 151
53,226 53,226 53,226
53226 53,226 53.226
373 836 373,836 373,838
110,327 110,327 110,327
1484,165 464 165 464,165
46,181 46,181 46,181
66 643 66,643 66,643
112824 112824 112824
10,463 10,463 463
400 400 400
883 10663 10,863
1881078 1 681 078 1861078
430,482 430,482 430482
230,596 230,596 230,596
1661 078 1661,078 1 661 078
Tab 2 Page 11
DelCriDUDn of AeeDunt SumlMrv:
768
789
770 911 Supervilion
771 CUST
772 CUST
773
774
775 912 Demonl1ration & Selling ExpenI8
778 CUST
CUST
778
779
780 913 A-rtiling Expense
781 CUST
782 CUST
783
784
785 918 Mile, 51188 Expenle
786 CUST
787 CU5T
788
789
790 TOTAL SALES EXPENSE
791
792
793 Total S8I88 exponle by FlCIor
784
795
796 Total Salel Exponle by Factor
797
788 ToI8l Cultomor Service Exp Including SlIII
799 920 Adminillnltive & General SIIIIrieI
800 PTD
801 CU5T
802 PTD
803
804
805 921 0IIice 5upp1iel & exponlel
806 PTD
807 CU5T
808 PTD
809
810
811 922 0IIice 5uppliel & expon181
812 PTD
813 CUST
814 PTD
815
816
817 923 OUIIide Services
818 PTD
819 CU5T
820 PTD
821
822
823 924 Property Inaurance
824 PTD
825
826
827 925 Injuriel & Dlmagel
828 PTD
829
830
831 926 Employee Penlions & Benefita
832 LABOR
833 CU5T
834 LABOR
835
836
837 927 Frlnchll8 Requirementa
836 DMSC
839 DMSC
840
841
842 928 Regulltory COImilllon Exponle
843 DM5C
844 CU5T
845 DM5C
846 FERC
847
846
849 929 Duplicate Chlrgel
850 LABOR
851 LABOR
852
853
854 930 Mile Gentlt'll Expen..s
855 PTD
856 CU5T
857 LABOR
858
859
860 931 Rents
IDAHO
f!!!!!!!!!!iD!!Trlmml..ion QIJ.IdI!!!II2tI B!!!II MI1e
861078 1861,078 1861078
251 185 528 590 155.858 566,740 566,740
5251,185 528 590 155 856 566 740 566,740
629 303 139 186 188
560 854 270,066 123451 167,336 167 336
581,525 270370 123590 167,566 167,524
' -
373682 /661 486\1302,366\/409 851\/409851\
1373682 /661 486\302366 409,851\409 851
971,118 467620 213 758 289742 289.742
971 129 467625 213,759 289745 289745
373,951 661 595 302425 409,931 409 931
373.951 661 595 302425 409 931 409 931
590 464 284325 129 969 176 170 176 170
590 464 284 325 129 969 176 170 176 170
314,805 314 605 314605
75,605 970 9,835
390,300 65970 635 314695 314 695
/545,219 1244,515\/29 658\(271 0471 /181 328\/89719\
545 219 /244 515\/29 658 /271 0471 181 3281'/89719
103,190 689 22,713 30,788 788
045 045 045
372,673 064 078 129 057 179538 789.101 390437
2478,908 1113 766 151770 213,372 819,889 393,483
Tab 2 Page 12
Descriotion of Account Summary:
PTO
PTO
881
882
883
864
885
B66
887
888
889
870
871
872
873
874
875
876
877
878
879
860
935 Mlinlanonce of Gona..1 Plonl
CUST
TOTAL ADMINISTRATIVE & GEN EXPENSE
SUI'IVTIIIY of A&G ExponD by Fletor
Tol8l A&G ExponD by Fodor
TOTALO&M EXPENSE
IDAHO ..nomlulon BIll!!
402,690 193906 637 120,146 120,146
402690 193906 637 120,146 120,146
45,391 11,882 908 822 22,641 180
703 703 703
1,427 116 368 647 311,503 748966 711 854 112
475,210 378 308 321410 775,491 734 495 40,996
11 876462 8088,478 2168029 352 888 3 693,462 344802 314695
463,827 61,659 32,782 369406 53,620 180 314605
11,031,236 930,845 122,632 977,762 639,642 337,830
805 85,970 635
791 791 5791
11 576462 5058475 2 165029 352959 3 693,462 340\ 602 314695
243 398169 211486688 11 174704 20736809 13830 083 6592030 314695
Tab 2 Page 13
Descnotion of Account 5ummary:
881 4O3SP Steam Depreciation
882
883
884
885 SSGCH
886
887
888 4O3NP Nucleer Depreciation
889
890
891
892 4O3HP Hydro Depreciation
893 P..,.Merger Pacific
894 P..,.Merger Ulah
895 Poll-Merger Pacific
896 Post-Merger Utah
897
898
899 4030P Other Production Dopr8dation
900
901
902 SSGCT
903 SSGCH
904
905
906 4O3TP Transmission Depreciation
907
908
909
910
911
912
913
914 403 Distribution Dopracialion
915 360 Land & Land Rights DPW
916 361 Structuras DPW
917 362 elation Equipment DPW
918 383 Stora9a Battery Equip",. DPW
919 364 Poles & Towers DPW
920 365 OH COnductors DPW
921 386 UG COnduK DPW
922 367 UG COndUClOr DPW
923 368 Una Trans DPW
924 369 DPW
925 370 Metors DPW
926 371 Inlleust Prom DPW
927 372 Leased Property DPW
928 373 S-t Ughtin9 DPW
929
930
931 4O3GP Genaral Depreciation
932 G-SITUS
933
934
935
936 CUST
937 G-SG
938 PTD
939 G-5G SSGCT
940 G-SG SSGCH
941
942
943 4O3GVO General Vahlcles
944 G-SG
945
946
947 4O3MP Minin9 Dopraciation
948
949
950
951 4O3EP Exporimonlal Ptant Depreciation
952
953
954
955 4031 ARO Depreciation
956
957
958
959
960 TOTAL OEPRECIATION EXPENSE
961 Summary 01 Amortization Exponse by Factor
962
983 DGP
964 DGU
965
968
967
968
969 SSGCH
970 SSGCT
971 Tola! Daprociation Exponse By Factor
IDAHO
tW!!!!IIW!f!2!!Yd2D Tranarnlaalon DI!!d!!!IIi2L'Bt1IlI !!in
400,720 400,720
592,107 592,107
596,038 596,038
523 694 523694
9112,559 112559
326 075 326,075
77,426 77,426
315,828 315,828
85,176 85178
804,305 804 305
861 861
121 220 121 220
242,753 242,753
368,634 366,634
778 113 778,113
845,371 845 371
005,195 2005 195
628,879 3628679
17,469 17,469 17,469
14,408 408 408
368,463 366,463 386,463
093,257 093,257 093,257
882,702 862,702 862,702
147246 147,246 147 246
439,627 439,627 439,827
312,101 312,101 312,101
484,699 484,899 484699
458,883 458,883 458,883
237 237 237
127 127 127
31,496 496 496
235716 6.235,718 235716
884,385 824 180,951 680,810 680 810
30,443 20,893 550
55,149 37,848 17,301
108 108
55,493 55,493 55,493
300,183 208,832 91,364 987 987
088,902 524,338 239,682 324 884 324,884
023 705 311
11241 746 3421
408 927 803.291 542 581 083 055 1 007562 55493
982 982
982 24,982
24581,802 13111771 4171 280 7298770 7 243,278 5,.93
100,101 824 180,951 918 326 918,326
15,531,505 782,624 746,895 987 987
088,902 524,336 239 682 324 884 324 884
493 55,493 55,493
27,090 27,090
534,935 531 440 421
243,776 243.458 311
24581.802 13111771 171260 7298770 7243278 55493
Tab 2 Page 14
c.scriDlion 01 Account summarY:
972
973 4O4GP Amort of L T PIant- Capital Lease Gen
974 I-SITUS
975 I-SG
976 PTO
977
976 CUST
979
960
961
962 4O4SP Amort ofLT Piant- Cap Lease Stoom
963
964
965
966
967 4O41P Amort of LT Plant -In\8ngibla Plant
986 I-SITUS
969
960 I-SG
991 PTO
992 CUST
993
994
995
996 I-SG SSGCT
997 SSGCH
998
999
1000
1001 4O4MP Amort or L T Plont- Mining Plont
t002
1003
1004
1005 4O4OP _GILT Plant-OIlIer Plant
1006 SSGCT
1007
1008
1009
1010 4O4HP AmortizotiDn or Other EIocIriC Plant
1011 Pre-Merger PacifiC
1012 Pre-Merger Utoh
1013 Post-Merger Plant
1014
1015
1018 Tol8l Arnor1lzotion 01 Limited Torm Plont
1017
1018
1019 405 AmortizotiDn of Other EJedric Plant
1020
1021
1022
1023
1024 406 AmortizItion or Plant Acquisition Adj
1025
1026
1027
1028
1029
1030
1031 407 Amort or Prop Losses, Unrec PlonL ete
1032 DPW
1033
1034
1035
1036
1037 TROJP
1038
1039
1040 TOTAL AMORTIZA noN EXPENSE
1041
1042
1043
1044 SUmmary of AmortizItion Expense by Fodor
1045
1046
1047 TROJP
1046 DGP
1049 DGU
1050
1051 SSGCT
1052 SOOCH
1053
1054
1055 Totol Amortization Expense by Foetor
IDAHO
ronsml..lon I2!!!f:I!!J!!!9 BtJ!!I
114 015 54,901 25,096 34,017 017
836 636 836
122851 54901 096 654 34 017 636
47,571 17,421 30,150 150
185 185
401 954 359,159 42,511 283 283
827 129 879 813 402,175 545 141 545 141
183,778 183778 183 778
235824 210,718 24,941 166 166
25,078 22,406 652
326 328
337 301
159 159
2728339 1479,066 489737 759536 575759 183 778
445 18,445
18445 18,445
158 158
360 380
2519 2519
871 954 554 931 514,833 802190 609778 192 414
345,553 345 553
345553 345.553
21,007 007
106,325 106,325
127,332 127 332
3344 839 2027815 514833 802.190 609778 192414
47,571 17,421 150 150
185 185
106,325 106,325
941,144 934 714 427,272 579,158 579,158
18,445 18,445
337 301
192,414 192,414 192.414
038417 967945 70,105 467 467
3344 839 027815 514833 802190 609,778 192414
Tab 2 Page 15
DelcriDtion of Account Summlrv:
1056 408 TlXes Other ThIn Income
1057 DMSC
1058 GPS
1059
1060
1061
1062 DMSC OPRV-
1063 EXCTAX
1064
1065
1066
1067
1068
1069
1070
1071 41140 DeflfTld Inveltmont T IX Credit - Fill
1072 PTD DGU
1073
1074
1075
1076 41141 Delemld Invellm8nt TIX Credit -Idaho
1077 PTD DGU
1076
1079
1080
1061 TOTAL DEFERRED ITC
1082
1083
1084 427 Inl8r8llon Long-Tenn Debt
1085
1086 SNP
1087
1086
1089 428 AmortizItion Df Debt Di.. & Exp
1090 SNP
1091
1092
1093 429 AmortizIlion 01 Premium on Debt
1094 SNP
1095
1096
1097 431 Other In18l881 ExpenSI
1098 NUTIL OTH
1099
1100 SNP
1101
1102
1103 432 AFUDC - Bonow8d
1104 SNP
1105
1106
1107 Total Eleclric Inl8r8st Deductions for TIX
1108
1109 Non-Utility Portion of Interssl
1110 427 NUTIL NUTIL
1111 428 NUTIL NUTIL
1112 429 NUTIL NUTIL
1113 431 NUTIL NUTIL
1114
1115 Total Non-utillty Interell
1116
1117 Tollllnl8l8s1 Deductions for TIX
1118
1119
1120 419 Interest & Dividlnds
1121
1122 SNP
1123 TolIl Operatin9 Deductions for TIX
1124
1125
1126 41010 Delerrad Income TIX - Federa~DR
1127
1126 TROJD
1129 DGP
1130 lABOR
1131 SNP
1132
1133
1134 GPS
1135 DITEXP DITEXP
1136 CUST SADDEBT
1137 CUST
1136 SGCT
1139 DPW SNPD
1140
1141
1142
1143
1144 41110 Delerrad Income TIX - Federal-CR
1145
1146
1147 DGP
1146 SNP
IDAHO
fr.Ws!I2D Tranlmlulon Ql!Ui!!IdI2n 8!!Ill
415,218 011 656 680 113 523 247 523 204
469078 222,855 97,491 168 732 168,727
26,225 26,225
4930,519 260937 977604 691 978 1691931
(757,790)(364,897)(166 800)(228,094)(226,094)
(757790 /364 8971 /166 800 228094\226094
(757790 (364 897\(166 800\'226 094\1226094\
858511 845,845 370070 640,495 640,477
14,014698 6 365,997 793639 835062 834,925 137
871 209 231 942 163,709 5475 557 5475 402 155
492 864 224,581 86 246 170 038 170033
492 864 224581 96,246 170038 170033
14968 12264\(990\11714\714\/0\
/4,968 264 990\714 /1714\
487 868 677,968 296 586 513314 513299
487868 677968 296 586 513314 513299
'1295,722 1590,414\1258 2841 1447 023)1447011\/13\
11.295,722 (590414\(258 284 4470231 /447011
16551 251 7541 813 3299 267 710171 5710010 162
16551 251 541 813 299 267 710171 5710010 162
(1,348,993)(814,688)(268903)(465,402)(465389)(13)
348993 ;614688\(288 9O3i ;465402);465389\/13i
333924 075 792 657,936 600,195 600,065 130
622 622
660,048 089902 253,474 316 672 549,834 786 838
213 484 641 109 109
223 000 223,000
174,234 119,575 659
603 010 274770 120,202 208036 208,032
950,906 801,496 94,760 254,650 253887 763
345 038 345,036 345.038
801 801 801
459 459 14,459
23,310255 12,387.621 181 672 740,963 6627367 113 576
(11,188,269)(5,098,094)(2,230,229)859946)859,837)(109)
(2,293011)(2,293,011)
(198,203)(90,314)(39,509)(68,380)(68,378)(2)
Tab 2 Page 16
IDAHO
eoacriDtion of Account SummarY:Tranaml..lon Q!I.!!i!!!!!I!W BIIIll MIK
1149 844,204)265,655)(576,549)
1150 GPS (91,349)(41825)(16209)(31 515)(31 515)(I)
1151 LABOR 955245)222,269)(289,530)(2,483,425)(1,648,011)(815415)
1152 SNPD (96,987)(87,920)(31 047)
1153 CUST (144)(144)(144)
1154 CUST SADDEST (35,949)(35 949)(35,949)
1155 DITEXP DITEXP
1156 TROJD (60 198)(60 198)
1157 SSGCH (38,365)(38,365)
1158
1159
1180 (20 601 903 /11 115 489\187074 16459 360\/5,607740 851 620
1181
1182 TOTAl DEFERRED INCOME TAXES 2508352 212,152 14597 281803 1 019647 261 956
Tab 2 Page 17
1163
1164
1165
1166
1167
1168
1189
1170
1171
1172
1173
1174
1175
1178
1177
1178
1179
1180
1181
1182
1183
1184
1185
1166
1187
1166
1189
1190
1191
1192
1193
1184
1195
1196
1197
1198
1199
1200
1201
1202
1203
1204
1205
1206
1207
1208
1209
1210
1211
1212
1213
1214
1215
1216
1217
1218
1219
1220
1221
1222
1223
1224
1225
1226
1227
1228
1229
1230
1231
1232
1233
1234
1235
1236
1237
1236
1239
1240
1241
1242
1243
1244
1245
1246
1247
1246
1249
1250
1251
1252
1253
1254
1255
Descriatian of Accaunt Summary:
SCHMAF AdditiDna . Flaw Through
SCHMAF
SCHMAF
SCHMAF
SCHMAF
SCHMAF
SCHMAF
SCHMAP A_na . P.rman.nt
lABOR
SCHMAP-SO
DPW
SCHMAT AddiliDna. Tomparary
SNP
TROJP
SNP
BADDEBT
IDAHO
T",namlulan ID!\!iI!!di2D R!.I!!i!!YII2D B!H!J
35,222 222
208,691 93,592 351 103747 69,408 34,341
421,614 189 082 22,933 209,599 140,220 379
139089 139089 139089
804,616 317 896 34284 452435 348,715 103.720
041 092 450,879 489 508,724 393 849 114 876
821 95,821
852,716 852,718 652,716
465450 108,789 504 153 872,509 872,507
182,870 182,870
935,566 935566
887,235 887,235
(927,398)(412,842)(188402)(326 055)(326,055)
(166 759)(81,246)(19885)(85,628)(46467)332)(30809)
953,841 425 564 193,499 334,878 3304,877
168 168 168
25 825,044 12,312,938 151,444 9360,661 236849 124012
35,845 746 905474 722.299 14317 973 118056 230726 130 8091
36 750,362 17223371 756 583 14770 408 466,771 334 447 30,809'
785,899 785899
498 796 392 309 309
463,615 463815
333 384 597985 72,540 662,859 443457 219,402
2607,396 859.295 77 932 670 168 450766 219402
101 380 195 20,209 34,976 34,975
814455 814 455 814 455
128 923 944,809 433,716 750 598 750,801 (3)
993 866 993,866
403174 263,348 962 85,866 85,884
802,391 708 327 766,867 327,197 327,183
736,887 781 442 424 815 530,630 614,180 (83,531)
32,971 429 720 212 300,245 11,950972 11,792,643 158,329
1796 1796 1796
43954 302 21,457,997 999 814 15,496491 15,421 678 74,813
46,561 698 23,317,293 077746 16,166659 15,872.444 284 215
19811336 (6 093 922\'2,321.163)/1 396 2511 4056731 231 (30 8091
SCHMAT-SITUS S
SSGCHDPW CIAC
SCHMAT-SNP SNP
TROJD
SCHMAT-SE SE
SCHMAT-GPS GPS
SCHMAT-SO SO
SCHMAT-SNP SNPDCUST DPW BADDEBT
BOOKDEPR SCHMDEXP
TOTAL SCHEDULE - M ADDITIONS
SCHMDF Deduction. - FIDwThraugh
SCHMDF
SCHMDF DGP
SCHMDF DGU
SCHMDP Deductions . penn.n.nt
SCHMDP
PTD SNP
SCHMDP IBT
SCHMDP-SO
SCHMDT Deductian. - TompDIIIry
DPW
SCHMDT-SNP
CUST
SCHMDT-
SCHMDT-GPS
SCHMDT-SO
TAXDEPR
DPW
TOTAL SCHEDULE - M DEDUCTIONS
TOTAL SCHEDULE - M ADJUSTMENTS
BADDEBT
SNP
DGP
GPS
TAXDEPR
SNPD
NOTE:PDSitive SChedule M amounls InCAlaa. taxabl. income and th.raIDra roduce tax _n..,
Negative Schedula M amounts _a.. taxabla Incams and 1II000fa'" inCAla.. tax .xpon..,
Slat. Incamo Tax..40911
IBT
IBT
IBT
IBT
TOTAL STATE TAXES
Calculation at Taxable Income:
Operating R.venusa
Operating Deductian.:
0 & M Exponas.
Deprsciation Expan..
Amortization Expan..
Tax.. Oth.r Than Incams
Intera.' & Dividonda (AFUDC-Equily)
Mise R.ven.. & Expon..
Talsl Operating Deduction.
Other Deductions: '
Inte",.t Deductian.
IntOte.' on PCRBS
Schedul. M Adjuatmonls
Incams BolD'" Sisto Tax..
IBT
IBT
IBT
IBT
282,836 91702,22878 45,556 145,578 547 29,815 216
282836 91702 45556 145578 95547 29815 20216
308,206552 244 036 749 23337474 40,832 329 32,429917 7 548,986 853426
243,398,169 211,486,656 174,704 20,736,809 13,830,083 592,030 314695
24,581,802 13,111,771 171,280 298 770 7,243,278 55,493
344,839 027,815 514 833 802,190 609,776 192,414
930 519 280,937 977,604 891,978 691,931
(1,348,993)(614888)(288,903)(465,402)(465,389)(13)
1168 481 1175,448\980 986 986
274,737 854 228097044 572,479 30,068,332 22,913665 839,972 314 695
551,251 541 813 299267 710,171 710010 162
811,336)(8,093 922)321 163)396,251)405,673)40,231 (30,809)
106 111 303 969 144,566 657 576 400.569 749,084 507,922
Tab 2 Page 18
eelcriotlon 01 Account Summorv:
1256
1257
1258
1259
1260
1261
1262
1263
1264
1265
1268
1267
1268
1269
1270
1271
1272
S18I. Income To.1
TO181 To.bIe Income
ToRI'.
Fodorollncome To. Cllculltod
Adj.I_1s to Cllculltod To:
40910 PMI
40910
FITOTH
40910
Fodorollncome To
FIT Truo-up
TOTAL OPERATING EXPENSES
NUTI~
lABOR
IDAHO
Tronlmlllion B!JII!
OTH
282,836 91,702 45556 145578 547 815 216
823275 212267 1099010 3511997 2305022 719 269 487706
35,00%35,00%35,00%35,00%35,00%35,00%35,00%
368 146 774 294 364,654 229,199 806,758 251,144 170,697
(787,256)(787,256)
1800 890 11296311 384 654 I 229199 806 758 I 251 744 I 170697
279721,136 229637,726 17119,389 32984020 36,904,995 13975 530 820303
Tab 2 Page 19
o.aeriDtlDn 01 AeeDunt Summarv:
1273 310 Land Ind Land Righto
1274
1275
1276
1277
1278 SSGCH
1279
1280
1281 311 Structural and l"'I""vemants
1282
1283
1284
1285 SSGCH
1286
1287
1288 312 BDiIer Plant Equipment
1289
1290
1291
1292 SSGCH
1293
1294
1295 314 TurbogenelBtDrUnlto
1296
1297
1298
1299 SSGCH
1300
1301
1302 315 AcceSIDry Eloctrie Equipment
1303
1304
1305
1306 SSGCH
1307
1308
1309
1310
1311 318 Mile Power Plant Equipment
1312
1313
1314
1315 SSGCH
1316
1317
1318 317 Steam Plant ARO
1319
1320
1321
1322 Uncillsi1iod Steam Pllnt- AccDunt300
1323
1324
1325
1326
1327 TDtal Steam PrDduetlDft Pllnt
1328
1329
1330 Summery DI Stelm PtDdudIon Plent by FocIDr
1331
1332 DGP
1333 DGU
1334
1335 SSGCH
1336 TDIaI Steem Pmduction Pllnt by FocIDr
1337 320 !JInd Ind Land Righto
1338
1339
1340
1341
1342 321 Structural end l"'I""vemanto
1343
1344
1345
1346
1347 322 ReeolDr Plant Equipment
1348
1349
1350
1351
1352 323 TurbogenerlltDr Unlto
1353
1354
1355
1356
1357 324 !JInd end !JInd Rights
1358
1359
1380
1361
1362 325 Mlae, PDWllr Pllnt Equipment
1363
1384
1365
IDAHO
lBnamiaalDn !li!!IiI!!!!I2I Bt!I!!MIn
146910 146,910
187,107 187,107
815,373 815,373
72275 72,275
5221 864 221,864
928788 928786
20,724,210 20,724,210
10,273,376 273,376
2706 559 706 559
48,632931 632,931
47,025,377 47,025,377
44,206,516 206,516
62,422,661 422,661
13,096,544 13,096 544
166 751 098 166 751 ,098
603,157 803,157
740,939 740,939
30,835,884 30,835,884
050,860 050,860
53230 840 53 230840
583 424 583,424
818,748 818.748
520 307 520 307
728,446 2728 446
20,650925 922 479
343,731 343731
453,462 453 462
675,683 675,683
183126 183 126
656002 656,002
222,647 222 647
222,647 222 647
296 388107 296 366 107
274,528,297 274 528,297
21,837810 837810
296 366 107 296 366 107
Tab 2 Page 20
Deacrtotio" of Account SummarY:
1366
1367
1366
1369
1370
1371
1372
1373
1374
1375
1376
1371
1378
1379
1360
1361
1362
Unclassified Nudea' Plant - AccI3OO
Tol8l Nuclea, produc1lon Planl
SUmmary 01 Nudaa, Production Plant by Facto,
DGP
DGU
Tol8l Nudea' Plant by Factor
IDAHO
t!em!!IIw!Tronami..lon QI!!!i!!!!!!2I!.!1i!!tIII.Y!!2 BtaII Mise
Tab 2 Page 21
eeoeriotion of Account Su.......rv:
1383
1384 330 Land and Land Rights
1385 Pre-Merger Pacific
1386 pre-Merger Utah
1387 Post-Merger Pacific
1388 Post-Merger Utah
1389
1390
1391 331 SlnIcturas and Improvements
1392 Pre-Merger Pacific
1393 pre-Merger Utah
1394 Post-Merger Pacific
1395 Post-Merger Utah
1396
1397
1398 332 Resarvoira, Dams & Wal8fW8YI
1399 Pre-Merger Pacific
1400 Pre-Merger Utah
1401 Poll-Merger Pacific
1402 Polt-Marger Utah
1403
1404
1405 333 Water _I, Turbinal, & General...
1406 Pre-Merger Pacific
1407 Pre-Merger Utah
1408 Post-Merger PacifiC
1409 Post-Merger Utah
1410,
1411
1412 334 AccellDlY Eledric Equipment
1413 Pre-Merger Pacific
1414 Pre-Merger Utah
1415 Post-Merger Pacific
1416 Post-Merger Utah
1417
1418
1419
1420
1421 335 Misc. power Plent Equipment
1422 Pro-Merger Pacific
1423 Pre-Merger Utah
1424 Post-Merger Pacific
1425 Polt.Merger Utah
1426
1427
1428 336 Roads, Railroads & Bridgel
1429 Pro-Merger PacifiC
1430 Pro-Merger Utah
1431 Post.Merger Pecific
1432 Post-Merger Utah
1433
1434
1435 337 Hydro Plant ARO
1438
1437
1438
1439 Unclaui1ied Hydro Plant- At:d 300
1440 Pro-Merger Pacific
1441 Pro-Merger Utah
1442 Post-Merger Pacific
1443
1444
1445
1446 Total Hydraulic Plant
1447
1448 Summary of HydrauHc ptant by Faclor
1449
1450
1451 DGP
1452 DGU
1453 Total Hydrautic Plant by Factor
IDAHO
b!2m!!!!D!I f!2!!!!s!!2J!Tranlml..lon Q!!!d!!!!!W B!JIII MIE
689,125 669 125
334,957 334,957
194,340 194,340
40 090 090
238511 238511
376 220 376 220
407 589 407,589
955 179 955 179
353675 353,675
092,843 5092,643
979,283 979,263
379 852 379 852
538 095 538,095
931,340 931,340
17,828550 828550
993,914 993,914
631 081 831 081
245,278 245,278
577916 577 916
5448 170 448,170
373,383 373,383
274,155 274,155
894 757 694,757
230,898 230,898
573193 2573193
97,664 97.664
13,791 791
891 691
4003 003
181149 181 149
288,704 288,704
53,197 197
469,899 469,698
34,703 34,703
846 302 846 302
33208519 33208519
33,208,519 208,519
208519 33208519
Tab 2 Page 22
Deleriotlon 01 Aecount Summsrv:
1454
1455 340 l.8nd Ind l.IInd Righl8
1456
1457
1458 SSGCT
1459
1460
1461 341 SlnJclurel Ind I""",,_nll
\462
1463
1464 SSGCT
1465
1466
1467 342 Fuel HoIdorI, ProdUClfl & Accelsories
1468
\489
1470 SSGCT
1471
1472
1473 343 Prime Movora
1474
1475
1476
1477 SSGCT
\478
1479
\480 344 Generators
\481
1482
1483
1484 SSGCT
1465
1486
1487 345 Acceuory Electric Pllnt
1468
1489
1490 SSGCT
1491
1492
1493
1494
1495 346 Misc. Power Pllnt Equipment
\496
1497
\498
1499
1500 347 Other Production ARO
1501
1502
\503
1504 UncllUIfled Other Prod Pllnt-AccI300
1505
1506
1507
1508
\509 TolIl 0th8r Production Pllnt
1510
1511 Summlry olO1ller Production PIIIIII by Fletor
1512
1513 DGU
15\4
1515 SSGCT
1516 TolIl 01 Other Production Plllllt by FlICIor
\517
1516 Experimenl8l Pllnt
1519 103 Experimentsl Pllnt
1520
152\TOIII ExpIrimenlll Pllnt
1522
1523 TOTAL PRODUCTION PlANT
IDAHO
Tronsmlllion B!!!iI Mise
357,262 357,282
357,282 357,282
693,886 693,868
10,874 10,874
325065 325065
3 029 806 029 806
957 468 957468
652 652
17433\174 331
\139450 139450
49,647 49,647
226 \58 22,226,\58
924 057 924057
26,200 063 200,063
538 538
35,607 146 35,607 146
1,216954 1216 954
36 627 638 627636
624 347 624,347
909 909
364,343 384 343
2,218600 22\8600
231,383 23\,383
745 745
232 128 232128
71 004 868 71 004 866
978,216 978,216
6,026 750 026,750
71004 966 71004 966
400 579 592 400,579 592
Tab 2 paga 23
Descriotion of Account SummalV:
1524 350 Land and Land Ri9hla
1525
1526
1527
1528
1529
1530 352 Structures and Improvemenla
1531
1532
1533
1534
1535
1536
1537 353 Station Equipment
1538
1539
1540
1541
1542
1543 354 Towers and Fixtures
1544
1545
1546
1547
1548
1549 355 Poles and Fixtures
1550
1551
1552
1553
1554
1555 356 Cleering and Grading
1556
1557
1558
1559
1560
1561 357 Underground Conduit
1562
1563
1564
1565
1566
1567 358 Underground Conductors
1568
1569
1570
1571
1572
1573 359 Roads end Tre~s
1574
1575
1576
1571
1578
1579 Unclassified Trans Plant - Acct 300
1580
1581
1582
1583 TSO Unclassified Trans Sub Plant - Acct 300
1584
1585
1586
1587 TOTAL TRANSMISSION PLANT
1588 Summary 01 Transmias;on Plant by Factor
1589 DGP
1590 DGU
1591
1592 TOIII Transmission Plent by Factor
IDAHO
Production Transml..lon ID!!II!!Idi2D B!I!II 14!!s
443,864 443 864
087 448 087,448
171,100 1171 100
702212 702,212
484,495 484,495
152,118 152,118
1722,104 722 104
358 716 3358718
547 852 547,852
12,539,909 12,539909
613471 37,813,477
701 037 701,037
883 893 883,893
010,551 010,551
820,441 820,441
894,684 694 684
371,516 371 518
528,185 528,185
27431120 27,431120
330 821 330 821
13,119,086 13,119088
014 787 014,787
17,853,870 17,853870
987723 987723
402 402
284 10,264
167,387 167387
178053 178,053
64,241 64,241
289 516 289 516
353758 353758
120,170 120,170
31,808 31,608
569 402 569,402
721180 721180
310 171 310 171
310177 310171
173338361 173338381
173336 361 173338,381
173338361 173,338381
Tab 2 Page 24
DescriDtion of Account Summorv:
1593 360 L.nd and L.nd Rights
1594 DPW
1595
1596
1597 361 Structu... and Il11j)IDvoments
1598 DPW
1599
1600
1601 362 Sl8tion Equipment
1602 DPW
1603
1604
1605 363 Storsgo B8t18ry Equipment
1606 DPW
1607
1808
1809 364 Pol.., Towers &
1810 DPW
1811
1812
1813 365 0v8th88d CondudDr8
1814 DPW
1815
1818
1817 368 Underground Conduit
1818 DPW
1619
1620
1821
1622
1823
1824 367 Undotground Conductors
1625 DPW
1828
1627
1628 388 Un. T18n.Io.......
1829 DPW
1630
1631
1632 389
1633 DPW
1634
1635
1836 370 M.t...
1837 DPW
1638
1639
1640 371 In.l8IIstions on CuotDm...' Premis.s
1641 DPW
1642
1643
1644 372 L8..8d Propo!1y
1645 DPW
1646
1647
1648 373 StrHt Ugh"
1649 DPW
1850
1651
1852 Uncl8uifi8d Dlot Plllnt. Acd. 300
1653 DPW
1654
1655
165&DSO Unclsuifi8d Dial Sub PI.nt. Acd. 300
1857 DPW
185&
1859
1660
1661 TOTAL DISTRIBUTION PLANT
1662
1663 Sul1Vl18ry of DIstribution Plant by FlICtDr
1664
1665
1866 Toilli Distribution Plsnl by F8ClDr
IDAHO
fm!!I!S!!!!D Trsnsmiulon 1!1!!!1!!!!!1!!B!!!II .MI!s
1,206,383 206,363 206,363
1,206,383 206383 206 383
774 559 774 559 774559
774 559 774559 774,559
19444,141 19,444 141 19444 141
444,141 19444,141 444,141
55,840 965 840,965 840,965
55840965 55,840965 55840 965
687,460 887460 687,460
31,687460 31 687 460 31,687460
189786 6189 786 189,786
189786 189786 189786
20,443 407 20,443407 20,443407
20,443 407 20443407 20443407
928482 928,482 928482
5& 928482 5& 928 482 56 928 482
21,681 798 681,798 681,798
681798 681798 21,681 798
781,667 781 667 13,781 667
13,781 667 13781,667 13,781667
158955 158,955 158,955
158,955 158 955 158 955
873 873 873
4873 4873 4873
552 554 552 554 552,554
552,554 552,554 552 554
781,969 781 969 781 969
781 989 781 969 781 989
229476 980 229,476 980 229476980
229478980 229 478,980 229,476 980
229476980 229476980 229 476980
Tab 2 Page 25
o.scriotion 01 Account Summary:
1667 389 land and land Rights
1668 SITUS
1669 CUST
1670
1671 G-SG
1672 PTD
1673
1674
1675 390 Structures and ImprovemantJ
1676 G-SITUS
1677
1676
1679 CUST
1680 G-SG
1681 PTD
1682
1683
1684 391 0IIic8 Furniture & Eqlipment
1685 G-SITUS
1686
1687
1686 CUST
1689 G-SG
1890
1691 PTD
1892 G-SG 5SGCH
1893 G-SG SSGCT
16114
1895
1698 392 Trsnaporl8tion Equipmenl
1697 G-SITUS
1898 PTD
1699
1700 CUST
1701
1702
1703
17004 G-SG SSGCH
1705 SSGCT
1706
1707
1708 393 Siores Equipment
1709 G-SITUS
1710
1711
1712 PTD
1713 G-SG
1714 SSGCT
1715
1718
1717 394 Tools, Shop & Garege Equipment
1718 G-SITUS
1719
1720 G-SG
1721 PTD
1722
1723
1724 G-SG SSGCH
1725 G-SG SSGCT
1726
1727
1728 395 LobonItory Equipment
1729 G-SITUS
1730
1731
1732 PTD
1733
1734 G-SG
1735 G-SG SSGCH
1738 G-SG SSGCT
1737
1738
1739 396 Power Operated Equipment
1740 G-SITUS
1741
1742 G-SG
1743 PTD
1744
1745
1746 SSGCT
1747 G-SG SSGCH
1748
IDAHO
Production Transml.slon QI!!dI!!!I!2D B!II1I !!II!;
197839 646 374 155,619 155 619
45,142 142 45,142
328,801 158,327 374 101 98101
571 681 159040 113778 298.863 253 721 45.142
491,114 31,007 986878 473 231 473,231
23,404 16,082 342
99,617 68,368 251
477 558 477,558 477,558
231,286 159,381 395 531 531
075 412 925,477 337279 812856 812,856
398392 200 273 3433143 9764,976 287417 477559
033,510 376 218,356 813,778 813 778
319 17,376 943
28,130 19,305 825
225,322 225,322 225,322
387,920 267285 118 068 567 567
817 817
806 983 314,694 058,081 434,208 434208
18,292 12,804 567 121 121
508 350 155
6535,801 644,807 1414994 476000 2250 678 225322
734533 15,467 991,130 727,935 727 935
592,908 285501 130 507 178,900 178,900
883,835 608981 269,005 849 849
770 770 770
813 52,030 23,783
49,558 49,558
12,423 526 897
20,712 271 304 137 137
567 134 433
375120 037468 426,060 911591 910,821 770
815,502 011 128,850 4114,841 4114,841
21,0049 448 603
527 421 17,106
37,848 18.224 330 11,292 292
150,922 103 988 935 999 999
218 639 2577
888062 181729 209 401 496 932 496 932
489,711 867 311,857 172,987 172,987
208,201 141 513 64,688
084,904 747,521 330,203 180 180
260,015 125,2004 233 578 77,578
102 102
296,498 203 483 015
127,101 575 685 841 841
431 053 1349
470963 315318 897029 I 258616 258,615
121 920 865 234,863 883 391 883,391
824 232 392
052 37,095 18,957
343 988 165,830 712 102,828 102 826
793 793
324,982 223,920 98,912 151 151
10,547 287 210
8289 711 523
1874,176 451 314 434 569 988,293 988293
144089 20,072 288,208 837,809 837 808
94,793 056 738
582,863 090487 481 702 474 10,474
126,702 010 889 803 803
167,825 115,176 52,649
859 859
42 384 2004 12900 281 281
163315 385,864 891,085 886368 888,368
Tab 2 Page 26
DucriDtion of Account Summary:
1749 397 Communication Equipment
1750 COM
1751 COM
1752 COM
1753 COM
1754 COM
1755 COM
1756 COM
1757 COM SSGCH
1756 COM SSGCT
1759
1760
1761 398 Mise, Equipment
1762 G-SITUS
1763
1764
1765 CUST
1766 PTO
1767
1768 G-SG
1769 G-SG SSGCT
1770
1771
1772 399 Coal Mina
1773
1774 Unck...ifiad Mina Plant
1775
1776
1777 399L WlDCO Capilli LaaH
1778
1779
1780
1781 Remova Capital L"HS
1782
1763
1764 1011390 Goneral Capilli L..a..
1765 G-SITUS
1786
1787 PTO
1768
1789
1790 Ramova Captal L.....
1791
1792
1793 1011346 G_ral Gas line Capnalleasas
1794
1795
1796
1797 Remova Capital LeaHS
1798
1799
1800 UnciSSlifiad Gen Plant- Acct 300
1601 G-SITUS
1802 PTO
1603 CUST
1804 G-SG
1805
1806
1807
1808
1809 399G Unclassifiad Gen Plant- ACCl3OO
1810 G-SITUS
1611 PTO
1812 G-SG
1613
1614
1815
1616
1817 TOTAL GENERAL PLANT
1816
1619 Summary 01 Genaral Plant by F8cIor
1620
1821 DGP
1822 DGU
1823
1824
1625
1826
1627 OEU
1826 SSGCT
1829 SSGCH
1830 La.. Capilli LeaHI
1631 Total General Plent by Factor
IDAHO
Tranlmllalon Jll!!IiI!Y!I2tI B!!!D Mi&
307,456 986,808 451 126 669,520 782,268 87,232
397,039 117 154,293 180 629 175,138 491
730,234 114,246 283 775 332,213 322,114 10,099
886,586 420 319 044,029 222,238 165,063 37,155
199,278 31,177 77,441 90,660 87,904 756
549,956 555394 379 541 615,021 565,925 096
019 785 1.950 283 2,214
121 998 19,866 257 22,550 707
145 179 445 521 505
927835 2 179 024 412466 336 343 143721 192622
607 182 683 43,942 942
630 805 825
913 10,235 678
078 076 078
179,786 86,562 39,569 53,635 635
255 255
62,471 43,044 19,014 413 413
203 140
323 124 142,223 831 105070 992 078
931,330 931,330
931,330 24931 330
782,740 782,740
677,711 422,642 193 196 261,873 261 873
1 660,451 1 205,362 193196 261,673 261,873
11 660,451 '1 205,382\1193,196\1261 873\1261,673\
11,218 402 469 347 347
11,216 402 469 347 347
83471017 37 833793 15310828 30528,396 29577 903 948 493
191,262 068,102 660,324 22,4&2,855 22,375 622 233
11,353,873 572,279 622565 159,029 094,343 886
16,327,918 988,993 046,667 292,256 255 100 155
25,005,732 25,001 498 950 283 214
955,147 177 77,441 846,529 904 758,626
27,380 18,207 543 610 594
270,158 158,919 86,533 707 000 707
660,451 205,362\1193196\1261 673\1261,873\
83471017 633,793 15310828 30526396 577 903 948 493
Tab 2 Page 27
Deacrio~on of Account Sum_IV:
1832 301 OrganizaliDn
1833 SITUS
1834 PTO
1835
1836
1837 302 Franchis. & Consent
1838 SITUS
1839
1840
1841
1842
1843
1844
1845
1846 303 Miscellaneous Inlangible Pt.nt
1847 SITUS
1846 I-SG
1849 PTO
1850
1851 CUST
1852 SSGCH
1853 SSGCT
1854
1855 303 Less Non-Utility Pt.nt
1856 SITUS
1857
1858 Unclassified Inlangibla Ptant - 300
1859 SITUS
1860 I-SG
1881
1882 PTD
1883
1864
1885 TOTAL INTANGIBLE PLANT
1886
1887 Summary of Inlanglbl. Ptant by Foetor
1886
1889 DGP
1870 DGU
1871
1872
1873
1874 SSGCT
1875 SSGCH
1876
1877 Tolallnlangibl. Plant by Foetor
1878 Sunvnary of Unclassified Plant (Account 106)
1879
1880 DSO
1881
1882
1883
1884
1885
1888 TSO
1887
1888
1889
1890 Tolal Unclassified Plant by Faclor
1891
1892 TOTAL ELECTRIC PLANT IN SERVICE
1893 SUnvnary 01 Elactric Plant by F.-
1894
1895
1896 DGU
1897 DGP
1898
1899
1900
1901 DEU
1902 SSGCH
1903 SSGCT
1904 L.ss Capilal L..s.s
1905
1906 105 Plant H.ld For Future Us.
1907 DPW
1908
1909
1910
1911
1912
1913
1914
1915
1918
1917 114 Elactric Plant Acquisition Adjustments
1918
1919
1920
1921
IDAHO
Production franamlnion Diatribution B!1!II
800,263 293,068 507,194 507 194
800 263 293,068 507,194 507 194
000,000 368215 633 785 633,785
185 741 185,966 644 131 131
126,258 580 480 542,184 614 614
811 924 546,774 84,718 431 431
179,411 179 411
42,858 42,858
7146191 515 488 992,742 637,961 637 961
391,378 143329 248,049 248,049
723,262 328,857 393780 625 825
22,783,111 10,970692 014,868 797,553 797,553
170,041 170,041
4,243061 243,061 243,061
31310853 467590 551 974 11,291 289 048 228 243,061
31310 853 14,487,590 551,974 291 289 7 048,228 4243061
39,257307 19 983,079 6837784 12436"
,,"
8193383 4243 061
191,841 802,612 389,029 389 029
869454 842,346 020 306 802 802
22,783,111 10,970 892 014 868 797,553 797,553
4,243,061 243061 243061
170,041 170,041
39257 307 19983079 6837784 12436 "'"193383 4243061
781,969 781,969 781 969
218 402 469 347 347
310,177 310,177
222,847 222847
326011 228,049 312,846 785316 785316
926123 257 488196 483 195,488973 272439820 287248 287 5191,
262,859902 068,102 462,937 253 328,884 253,241 631 233
175,772 25,171,539 1.950 283 214
567,276,719 387,129657 177,981,232 185830 101,144 686
39,111,027 959,886 061 533 12,089,809 12,052,653 155
198 209 177 77,441 089591 87,904 001,687
22,107,968 21,996 728 86,533 707 000 707
6,054,110 044,957 543 610 594
11680451 11,205 382\1193 196\1261 873\1261,873\
928123257 458 196 463 195 486 973 272439820 267248 267 5 191 554
995,082 995 082
918,284 918,284
913,346 913346
Tab 2 Page 28
eelcnotlon of Account Summarv:
1922
1923 115 Accum Provision for 0411.\ Acquisition AdjuI-
1924
1925
1926
1921
1926
1929 120 Nud..r Fuel
1930
1931
1932
1933 124 Weltherization
1934 DMSC
1935 DMSC
1936
1937
1936 182W Weltherization
1939 DMSC
1940 DMSC
1941 DMSC SGCT
1942 DMSC
1943
1944
1945 188W Welthorizltion
1946 DMSC
1941 DMSC
1946 DMSC CNP
1949 DMSC
1950 DMSC
1951
1952
1953 Totol Welthorizltion
1954
1955 151 Fuel Stock
1956 DEU
1957
1958 SSECT
1959 SSECH
1960
1961
1962 152 Fuel Stock. Undiotribulod
1963
1964
1965
1966 25316 00& T Wortdng Copltol Depos~
1967
1968
1969
1910 25317 oo&T WoriIIn9 Copltol Deposit
1911
1912
1913
1914 25319 Provo Wor1Un9 Copltol Dopos~
1915
1916
1917
1918 TolIl Fuel Stock
1919 154 Mlterills and SUpplies
1980 MSS
1981 MSS
1982 MSS
1983 MSS
1984 MSS SNPPS
1985 MSS SNPPH
1988 MSS SNPD
1987 MSS SNPT
1988 MSS
1989 MSS
1990 MSS SSGCT
1991 MSS SNPP
1992 MSS SSGCH
1993
1984
1995 183 SIo..s Expon.. Undisttibutod
1996 MSS
1997
1998
1999
2000 25318 Provo WoriIIng CapItol Dopos~
2001 MSS SNPPS
2002
2003
2004
2005 TolIl Mlterills & Supplies
2006
2007 165 P..poymonls
2008 OMSC
2009 GPS
2010
2011
2012 PrO
2013
IDAHO
f.!2!!!!WD T..nsmlllion B!!!II .t4i!s
240,422)(4,240,422)
/624 950 1624950;
(4,865 371 4865371
44,196 44,196 196
44212 44212 44,212
721,987 721 987 721,987
62,233 62,233 62,233
5784 221 784 221 5184 221
5828,433 5828433 5828433
476,993 478,993
365,549 365549
5842,542 5842,542
/22,312 122,312'
(22,312 22312
179396 396\
179396 396'
5140,834 5740 834
604,498 011,219 198,393 388886 388,886
131 322 114 949 558 816 816
239345 200,349 13,114 823 823
478 748 248 483 483
705,058 101 394 203928 399,735 399,735
(1,329)113)(73)(143)(143)
(248,942)(208,382)(13,702)(28 858)(26858)
63359 53,036 487 6836 6836
503789 6281 200 413 012 809,517 809 517
(11,122)(14,333)(942)(1,847)(1,847)
11122 114333 9421 /1,8411 847
486 861 6266 867 412010 807730 807730
157,302 157 302 157 302
472,170 215,151 94,121 162,898 162,894
132,&48 033 613
193,863 193,863
818 419 394 091 180145 244 183 244 183
1 774 200 893938 315,878 564 384 407017 151302
Tab 2 Page 29
Dolenollon of Account Summorv:
2014
2015 182M Mise Regulatory AssaIl
2016 DDS2
2017 DEF5G
2018 SSGCH
2019 DEFSG
2020 DEF5G
2021
2022 DDS02
2023
2024
2025 186M Mile Defarrad Debita
2028 lABOR
2027
2028
2029 DEFSG
2030 LABOR
2031
2032 SNPPS
2033 EXCTAX
2034
2035
2036 Worldng Capital
2037 cwe Cash Wor1Iing Capital
2038 cwe
2039 cwe
2040 cwe
2041
2042
2043 owe Othar _ing Capital
2044 131 Calh 5NP
2045 135 Wor1Ung Fundi
2046 141 Notel Racaivabla
2047 143 Other Accountl Racalvabl, GP
2048 232 Accounll Payable PTD
2049 232 Accounts Payable PTD
2050 232 Accounll Payable
2051 253 Deferred Hedge
2052 2533 Other Deferred Credill - M P
2053 2533 Other Defened Credttl - M P
2054 230 Aslet Retirement Obligalic P
2055 230 Aslet Retirement Obligatlc P
2056 2S4105 ARO Regulatory Ulbility
2057 2S41OS ARO Regulatory Uabl1i1y
2058 2533 Chona Reclamation 55ECH
2059
2080
2061 Total Wortdng Capital
2062 Miscellaneous Rate Ban
2063 18221 Unroc Plant & Rag Study CoslI
2064
2065
2068
2067
2068 18222 Nuclear Plant - Trojan
2069
2070 TROJP
2071 TROJD
2072
2073
2074
2075
2076 1869 Mise Deferred Debita-Trojan
2077
2078 5NPPN
2079
2080
2081 TOTAL MISCELLANEOUS RATE BASE
2082
2083 TOTAL RATE BASE ADDITIONS
IDAHO
Transmila;on Ql!!!iI!I!!i2D t!imII!!!!I2L'B!JIll .MI&
(36M55)(129,190)(46925)(189,340)(81 210)(108,130)
604 276 204 310 399,986
725698 725,698
230,358 230,358
303 236 162477 234 116 526 080 46,446
1498115 193653 377,276 172 814\11129 108130 46 446
880 357 835,762 244,595
858 580 917 361 807 774
520,680 520 880
2417 895 164,002 1 245512 8381 5607 774
489 264 981,852 1754&8 331 946 229040 95,8S4 051
489264 981,852 175,4&8 331 946 229,040 854 051
(0)(0)(0)(0)(0)(0)
12,483 679 484 300 300
58,585 26,695 11,678 20,212 20,211
1.292 328 588,888 257808 445,852 445,840
(100,198)(48,248)(22,055)(29,895)(29,895)
(78,906)(78,906)
(355,963)(355963)
(122,452)(122,452)
(28,744)(26 744)
679,114 111070 249716 440469 440,456
4168378 2970782 425181 772,415 869496 95 B68 7051
239,177 239 177
348 557 348557
587735 587735
587735 587.735
34 550 231 23885786 2775917 7908528 1878780 19,484\039232
Tab 2 Page 30
DeecriDIIDR of Account Summarv:
2084 235 Customer Service Dopolits
2085 OUST
2086 OUST 'ON
2087
2086
2089 22BI Prav for Property Inlurane PTD
2090 22B2 prov for Injuriol & Dame9' PTD
2091 2283 prov for Penllons and Ber PTD
2092 22B3 Prav for PensiOns end Bor PTD
2093 254 R09 UabU1tio1 - Inlurance PTD
2084
2095
2096 22844 Accum Hydro Ro1icenslng Obligation
2097
2098
2099
2100
2101 22842 Accum MilO Oper Prav-Tn P TROJD
2102 230 AllOt Rot/rOmont ObU90tl, P TROJP
2103 254105 ARO Regulatory Uebiity TROJP
2104 254
2105
2106
2107 252 Cultomer Advencel for Conltruction
2108 DPW
2109 DPW
2110
2111 DPW
2112 OUST
2113
2114
2115 25398 S02 Emiuionl
2116
2117
211B
2119 25399 Other DefofTOd Credits
2120
2121
2122
2123
2124
2125
2126 190 Accumulated Deferred Income Tool
2127
212B
2129 LABOR
2130 DGP
2131 OUST BADDEBT
2132 TROJD
2133
2134
2135 PTD SNP
2136 DPW SNPD
2137
2136
2139
2140 281 Accumuleted DefofTOd Income Tool
2141
2142 DGP
2143 SNPT
2144
2145
2148 2B2 Accumulatod DefofTOd Income Tool
2147
2148 ACCMDIT DITBAL
2149 DGP
2150 lABOR
2151 PTD SNP
2152
2153
2154
2155
2156 2B3 Accumutated DefofTOd Income Tool
2157
2158
2159
2160 lABOR
2161 GPS
2162 PTD SNP
2163 TROJD
2164 PTD SNPD
2165 SGCT
2166 SSGCH
2167
2166
2169 TOTAl ACCUMULATED DEF INCOME TAX
IDAHO
Trln.mlnion Ri!!IiI!!!.!!2D 8U!!I MiE
(58,994)(2B 4O7)(12,985)(17 601)(17,601)
(190 776)(91,864)(41,992)(58,920)(58,920)
726,343)(1,794,336)(820,218)(1,111,789)(1,111 789)
/169683 /81,B03\(37,393\/50,686\/50,688\
145 995 1 996 410 (912 589 236 996 236 996
(170 131)(170,131)
(149,025)(149 025)
(58,534)(56,534)
375 690 /375690\
(305)(305)(305)
(258,980)(258,980)
259 285 258 980\/305)305\
(2,350891 /2,350,8911
350891 350 B91
(78 984)(78,994)
100,526)(501,470)(219,375)(379 661)(379 670)(11)
(549 151)(549,151)
/112 817 n12,B1n
641 478 1242422\(219,375 379681 379670
121 251 121,251
816 616
705,586 55B 767 310 342 836 436 897 552 938,884
326,974 326,974 326,974
747 747
245,822 245,822
395,837 395B37
824 360 B22 843 843
527881 527881 527,661
333 299 4330421 310964 164,253 426 055 1265 859
(82 347,002)(37,233,731)(16,630,754)(28,482 517)(28 305,688)(176,B29)
96,129 111 229 789 31,971 819
(26564)(12,791)(5,947)(7,926)(7,926)
(327,514)(327514)
970,391 970,391
81,634 559 /36,560 534)/16631 373 128442653)/28281,6431 161 010
(131 798)(60,058)(26,272)(45,470)(45489)(1)
(593,604)(593,604)
(670,585)(B7o,585)
140,981)(511,698)(62,061)(567,221)(379486)(IB7755)
(970,B22)(442,369)(193,520)(334933)(334 924)(9)
(688556)(330,596)(151,120)(204,840)(204 940)
(96 111)(96 111)
1223,348 /223 348\
714004 /3128,565 (432974\/1,152,485)964 699\(167 766\
/78015264 /35 358 676\/16753382\/25,903204)/26 B2o 267\917 083
Tab 2 Page 31
DeacriDIIDn of AccDunt SUmm81Y".
2170 255 Accumulated Investment Tax Credit
2171 PTD
2172 PTD ITC84
2173 PTD ITC85
2174 PTD ITC86
2175 PTD ITCBB
2176 PTD tTC89
2177 PTD ITC9O
2178 PTD DGU
2179
2180
2181 TOTAL RATE BASE DEDUCTIONS
2182
2183
2184
2185 10BSP Steam Prod Plant Accumulated Depr
2186
2187
2188
2189
2190 SSGCH
2191
2192
2193 I08NP Nudear Prod Plant Accumulated Depr
2194
2195
2198
2197
2198
2199
2200 I08HP Hydraulic Prod Plant Accum Depr
2201
2202 Pra-Merger Pacific
2203 Pra-Merger Utah
2204 PDst.Merger Pacific
2205 Post-Merger Utah
2208
2207
2208 1080P Other Production Plant. Accum Depr
2209
2210
2211
2212
2213 SSGCT
2214
2215
2216 108EP Experimental Plant. Accum Depr
2217
2218
2219
2220
2221 TOTAL PRODUCTION PLANT DEPRECIATION
2222
2223 SuI1VTl8fY of Prod Plant Depreciation by FactDr
2224
2225 DGP
2226 DGU
2227
2228 SSGCH
2229 SSGCT
2230 Total Df Prod PI.nt Depreciation by Factor
2231
2232
2233 I08TP Transmission Plant Accumulated Depr
2234
2235
2236
2237 TOTAL TRANS PLANT ACCUM DEPR
IDAHO
Tran.mi..ion !1!!!!iI!I!!!2D BI!!IJ
(2,067,067)(995,349)(454,989)(616,729)(618,729)
(58250)(28,049)(12,822)(17,379)(17,379)
2125317 023398 467,811\16M 108)634 108
/89 113,920 /423474901 /18,6121361 /28,154,294\/28 071 3881 917072
(51,353 916)(51,353,918)
(57,320 395)(57,320,395)
(25 169,941)(25 169,941)
112 156,344 112,156,344)
146 000,495 146000 495
(9,552,912)(9,552,912)
(1,785,399)785,399)
(2,446738)(2,446 738)
/578,441 1578,4411
/14 363490 114363.490
(131,171)(131,171)
070,248)070,248)
, 1902,833 1902 833\
/5,104,252 104 252
/165468 237 /165,4882371
(152 409,061)(152.409061)
(12,158,344)(12 156,344)
1902 833 1902,8331
1165,468237 1654682371
(22,498.332)(22,498,332)
(22,543,571)(22,543,571)
116.007 383 iI8.oo7383\
63049,286 163049286
Tab 2 Page 32
D..criDtlDn of ACCDunl Summarv:
2238 108360 L.nd .nd Lond Rights
2239 DPW
2240
2241
2242 108361 Structures and ImprDV8ments
2243 DPW
2244
2245
2246 108362 Station Equipment
2247 DPW
2246
2249
2250 108363 Storage Battery Equifmonl
2251 DPW
2252
2253
2254 108364 Poles, TDWlIS & Fixtures
2255 DPW
2256
2257
2258 108365 Overl1..d CDnductora
2259 DPW
2280
2261
2262 108388 Underground ConduIt
2263 DPW
2264
2265
2286 108367 Underground CondudDra
2267 DPW
2288
2269
2270 108388 Uno Transfonnera
2271 DPW
2272
2273
2274 108389 Servicls
2275 DPW
2276
2277
2278 108370 Motors
2279 DPW
2280
2281
2282
2283
2284 108371 InstaJlatiDns on CuatDmera' Premis.s
2285 DI'W
2286
2287
2288 108372 lIaaed Property
2288 DPW
2290
2291
2292 108373 Streel Ughts
2293 DPW
2294
2295
2298 108000 Unclassified Disl Plant- Accl3OO
2297 DPW
2298
2288
2300 I08DS Unclassified Disl Sub Planl - Acct 300
2301 DPW
2302
2303
2304 108DP Unclaaaified Dial SUb Plant - Accl3OO
2305 DPW
2306
2307
2308
2308 TOTAL DISTRIBUTION PLANT DEPR
IDAHO
Transmi..iDn Qimi!!Y!I2LI B!!!I!M!!S
(200,311 1200311\12003111
200 311 200 3111 200311
1520818 (520916\1520,818\
(520,916 520,816 1520 9181
(7,324712 324712\3247121
(7,324712 324 712 (73247121
'22,281,022 122 281 022\122,281 0221
122.281,022 122,281 022 122,281 0221
(11 048,182 111048,182\111,048,182\
111048182 (11048,182 048,182\
13,101 328 (3,101 329\101,328\
13101 329 101329\101,3291
'10 168 174 110,168,174\110 189,1741
110169174 169174 110,168 174
(26232,665 126,232 665\126 232,665\
126 232665 (26 232.665 (28,232,665\
(10 072,291 110072,2811 110072,2811
(10072,291 1100722911 0722811
489,605 489605\489605\
15,489605 (5,4896051 5 488.6051
11358271 /1358271 1135 927\
1359271 135927 /135,9271
(4794 14794\147941
(4,794 14794\794\
(258,765 (258 765\(258,765\
(258 765 /258765\258 7651
(96839693 f96839,693\f96,U9,6UI
Tab 2 Page 33
Deacrt.tion of Accounl Summary:
2310
2311 Summary 01 Dialribution Plant Dol'" by Flctor
2312
2313
2314 Toll' DIstribution Depreciation by Factor
2315 10BGP Gan"",! Pllnt Accumullted Depr
2316 G-SITU5
2317
2318
2319 G-SG
2320 CU5T
2321 PTD
2322
2323 G-SG 5SGCT
2324 G-SG 55GCH
2325
2326
2327
2328 I08MP Mining Pllnt Accumullted Depr,
2329
2330
2331
2332 I08MP Lasa Cantralla Situ. Depreciltion
2333
2334
2335
2336 1081390 Accum Del'" - Capilli Lal..
2337 PTD
2336
2339
2340 Ramove Clpilll Leue.
2341
2342
2343 1081399 Accum Depr - Clpilal Lal..
2344
2345
2346
2347
2346 RemoveClpital Lelae.
2349
2350
2351
2352 TOTAL GENERAL PLANT ACCUM DEPR
2353
2354
2355
2356 5ul1V1Ulry 01 Genenli Depreciltion by Foetor
2357
2356 DGP
2359 DGU
2360
2361
2362
2363
2364 DEU
2365 SSGCT
2366 SSGCH
2367 Remove ClpiIIl Laua.
2366 TolIl Genenli Dopreciltion by Foetor
2369
2370
2371 TOTAL ACCUM DEPR - PLANT IN 5ERVICE
IDAHO
Transmission Qi!!d!!!II!2!!R!BII M!!S
(96,839 693)(96839693)(96839,693)
96,839 693 196 839693 96 639 69:1\
(11 395,274)(37 228)(2,385 494)(6,972,552)(8,972,552)(0)
(551 342)(376 379)(172,963)
066,040)(745 336)(340,704)
(2,421 485)668 453)(737,007)(16026)(16,026)
(225 327)(225 327)(225 327)
482,992)(2,640,211)(1,206,679)(1,635,902)(1,635,902)
(34 074)(34,074)
(3,337)(2,299)(1,016)(22)(22)
1168 104 1115827\151,1641 11,1131 1131
121367,975 621 807\4 895227 110,850941 110,625614 1225 328
19,509200 /9 509 200\
19;509200 509,200
509 200 19,509 200
130817176 /15 131 0071 148952271 /10650,9411 110,625,8141 1225,328\
(11 395274)(37228)(2,385,494)972,552)(8,972,552)(0)
(9,543,275)543,275)
482,992)(2,640,211)(1,206,879)(1,635,902)(1,635902)
(225,327)(225,327)(225 327)
(4,058 667)(2,792 168)250,674)(18,026)(16,026)
337)(2,299)(1,016)(22)(22)
(166 104)(115 827)(51 164)(1,113)(1,113)
30677176 '1513100 695 227 10650 941)110625614 225328\
/356234,391 /180599,2441 1679445131 /107690 6341 /107465,3061 /225,3281
Tab 2 Page 34
Deacrtotion of Account SUmlllllrY:
2372 111SP Accum Proy for Amort-Staam
2373 SSGCH
2374 SSGCT
2375
2376
2377
2376 l11GP Accum Proy for Amort-Genaral
2379 G-SITUS
2380 CUST
2381
2362 PTD
2363
2364
2385
2386
2387 l11HP Accum Proy for Amort-Hydro
2388 Pre-Merger Pacific
2389 Pre-Merger Utah
2390 POII-M8fg8r Pecific
2391 Post-Marger Utah
2392
2393
2394
2395 l11IP Accum Proy for Amort-Intangible Ptant
2396 !-SITUS
2397
2398
2399
2400 I-SG
2401 I-SG
2402
2403 CUST
2404 SSGCT
2405 SSGCH
2406 PTD
2407
2406 l111P Less Non-Utility Plant
2409 NUTIL OTH
2410
2411
2412 111390 Ac:cum Amlr .. Capital Leasa
2413 G-SITUS
2414
2415 PTD
2416
2417
2418 R.move c.pIIaI Lo... Amtr
2419
2420 TOTAL ACCUM PROVFOR AMORTIZATION
2421 BaginninglEnding
2422
2423
2424
2425 Sul'M18IY of Amortization by Fador
2426
2427 DGP
2428 DGU
2429
2430
2431
2432 SSGCT
2433 SSGCH
2434
2435 Less Capilli Lea..
2438 Total Provision For AmortiZation by Factor
end and and end
IDAHO
Transmission Distribution Distribution B!!!!!
116,101 116,10,1
16101 16101\
(70,640) (70 640)(70 640)
(18 204)(16,288)(1,925)(13)(13)
(344,238)(165,759)(75,771)(102,706)(102706)
433260 182,025 177 696 /173558 1102719 no 6401
(21,710)(21,710)
(59)(59)
116,126 116,126)
137696 37,696'
484,690)(536,465)(926,425)(926,425)
(176 748)(176748)
(19,672)(19872)
(44 414)(44,414)
896,040)(1,695,961)(200,741)336)338)
(644,741)(578,098)(88 169)(455)(455)
(154,230)(137 809)(16,312)(109)(109)
(2,929,811)(2,929,61 I)(2,929 611)
(880)(880)
641 001\13,650921\112 906 993 215,071\13,850 921\
(20 239,999)(6,688,432)882,707)(7,710 859)781,246)(2,929611)
20239 999 18 688 4321 8827071 7710859 4 781 248\2929611\
120727275 9 102 4541 3740404 /7 884,4181 14 883,9671 13,000 451
484,890)(538,465)(928,425)(928,425)
(44,414)(44,414)
(13,251,230)380,830)(2,916,772)(3,953,628)(3,953628)
000,451)000,451) (3,000,451)
(16 101)(16,101)
(880)(880)
(2,949,530)(2,880,449)(287 167)914)(1,914)
/20727 275 102454'740404 i7 864,4181 48839671 13,000,451
end end end and end end
Tab 2 Page 35
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t
r
i
b
u
t
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o
n
Re
t
a
i
l
Mi
s
c
In
c
r
e
a
s
e
Pe
r
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e
n
t
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g
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Li
n
e
Sc
h
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d
u
l
e
De
s
c
r
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p
t
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o
n
An
n
u
a
l
Ra
t
e
Re
t
u
r
n
Co
s
t

o
f
Co
s
t

0
1

Co
s
t

o
f
Co
s
t

o
f
Co
s
t

o
f
Co
s
t

o
f
(D
e
c
r
e
a
s
e
)
Ch
a
n
g
e

f
r
o
m
No
.
No
,
Re
v
e
n
u
e
Ba
s
e
In
d
e
x
Se
r
v
i
c
e
Se
r
v
i
c
e
Se
r
v
i
c
e
Se
r
v
i
c
e
Se
r
v
i
c
e
Se
r
v
i
c
e
to

=

R
O
R
Cu
r
r
e
n
t

R
e
v
e
n
u
e
s
Re
s
i
d
e
n
t
i
a
l
65
3
36
9
70
%
26
,
86
6
89
8
51
8
,
36
3
71
6
,
16
5
27
5
,
87
3
01
3
,
29
7
34
3
,
20
0
78
6
,
47
1
65
%
Re
s
i
d
e
n
t
i
a
l

-

T
O
O
21
,
36
2
23
5
18
%
20
,
52
3

6
7
8
12
,
66
6
,
19
1
54
8
,
10
1
32
7
24
9
81
8
,
27
0
16
3
,
86
8
83
8
,
55
7
93
%
Ge
n
e
r
a
l

S
e
r
v
i
c
e

-

L
a
r
Q
e
18
,
60
9
42
5
10
.
70
%
16
,
28
7
,
01
2
12
,
68
2
,
26
9
55
8
,
17
8
83
9
,
09
8
16
3
10
8
44
,
35
9
32
2
41
3
12
.
4
8
%
Ge
n
e
r
a
l

S
e
r
v
i
c
e

-

M
e
d
i
u
m

V
o
R
a
a
e
13
0
25
5
10
,
24
%
11
5
,
55
4
57
2
16
0
27
9
28
6
25
7
(1
4
,
70
1
11
.
29
%
Ge
n
e
r
a
l

S
e
r
v
i
c
e

-

H
l
a
h

V
a
R
a
a
e
06
1
14
3
13
.
32
%
24
7
,
57
1
04
7
,
45
9
16
5
,
99
9
70
5
99
2
41
7
81
3
,
57
2
16
,
07
%
Im
Q
a
t
i
a
n
39
,
4
0
4
67
9
03
%
39
,
09
9
,
29
5
25
,
40
2
,
68
1
98
1
,
15
6
12
,
17
6
,
60
3
42
9
,
47
0
10
9
,
38
5
30
5
,
38
4
77
%
St
r
e
e
t

&

A
r
e
a

L
i
a
h
t
i
n
a
32
6
,
29
8
17
,
96
%
/3
,
55
7
88
7
76
,
17
9
16
7
41
1
50
2
61
,
52
0
51
9
23
1
,
58
9
70
.
97
%
Tr
a
f
f
i
c

S
k
m
a
l
s
15
,
52
6
14
.
57
%
12
,
56
3
25
1
29
6
90
3
90
2
21
1
96
3
19
.
08
%
Sp
a
c
e

H
e
a
t
i
n
a
63
5
62
0
12
,
33
%
53
2
,
15
1
39
6
,
84
8
95
8
10
1
83
6
13
,
21
5
29
3
11
0
3
46
9
16
,
28
%
Ge
n
e
r
a
l

S
e
r
v
i
c
e

-

S
m
a
l
l
71
1
25
2
11
.
91
%
04
4
,
68
8
64
5
,
46
3
25
5
5
4
2
37
6
99
0
69
1
,
24
6
75
,
44
7
11
,
66
6
,
56
4
15
.
56
%
Sp
C
Co
n
t
r
a
c
t

1
99
8

8
5
2
99
%
18
5
,
33
6
39
3
4
,
27
4
18
5
,
42
3
58
0
1
3
19
9
74
2
7
18
6
4
8
4
66
%
SP
C
Co
n
t
r
a
c
t

2
48
,
66
8
,
72
7
23
%
55
,
10
4
,
74
7
52
,
64
9
,
44
9
31
9
9
5
7
48
,
63
2
14
,
10
8
90
,
81
8
43
6
0
2
0
13
,
22
%
To
t
a
l
St
a
t
e

o
f

I
d
a
h
o

-
17
8
57
7
38
1
76
%
17
8
,
57
7
,
38
1
13
3
,
11
7
,
99
8
75
5
,
10
0
31
,
65
4
68
3
19
6
,
39
8
85
3
,
20
2
(0
)
00
%
Fo
o
t
n
a
t
e
s

:
Co
l
u
m
n

C
:

A
n
n
u
a
l

r
e
v
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n
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s

b
a
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o
n

1
2
-
20
0
6
,
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l
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n

0
:

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a
l
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t
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d

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t
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p
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r

1
2
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0
6

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m
b
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b
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s
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1
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6

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p
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1
2
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20
0
6

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m
b
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d

ca
s

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n

H
:

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r
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1
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of

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:

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d

t
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M
o
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Fr
o
m

A
n
n
u
a
l

R
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t
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F
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t
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4

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a
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e

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ca
s

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0

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1
2
-
06
F
i
n
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l
.
x
l
s
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c
l
f
l
C
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p
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O
f

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y

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c
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f

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d
a
h
o
12

M
o
n
t
h
s

E
n
d
i
n
g

D
e
c
e
m
b
e
r

2
0
0
6
MS
P

P
r
o
t
o
c
o
l
07
%

=

T
a
r
g
e
t

R
e
t
u
r
n

o
n

R
a
t
e

B
a
s
e
Re
t
u
m

o
n
Ra
t
e

o
f

To
t
a
l
Ge
n
e
r
a
t
i
o
n
Tr
a
n
s
m
i
s
s
i
o
n
Di
s
t
r
i
b
u
t
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o
n
Re
t
a
i
l
Mi
s
e
In
c
r
e
a
s
e
Pe
r
c
e
n
t
a
g
e
Lin
e
Sc
h
e
d
u
l
e
De
s
c
r
i
p
t
i
o
n
An
n
u
a
l
Ra
t
e
Re
t
u
m
Co
s
t

o
f
Co
s
t

o
f
Co
s
t

o
f
Co
s
t

o
f

Co
s
t

o
f
Co
s
t

o
f

(D
e
c
r
e
a
s
e
)
Ch
a
n
g
e

f
r
o
m
No
,
No
.
Re
v
e
n
u
e
Ba
s
e
In
d
e
x
Se
r
v
i
c
e
Se
r
v
i
c
e
Se
r
v
i
c
e
Se
r
v
i
c
e
Se
r
v
i
c
e
Se
r
v
i
c
e
to

=

R
O
R
Cu
r
r
e
n
t

R
e
v
e
n
u
e
s
Re
s
i
d
e
n
t
i
a
l
29
,
65
3
36
9
70
%
31
,
97
6
01
4
16
.
67
7
00
0
21
7
21
1
54
4
,
4
0
0
07
2
,
36
9
46
5
,
03
4
32
2
,
64
5
83
%
Re
s
i
d
e
n
t
i
a
l

-

T
O
D
36
2
,
23
5
18
%
22
,
72
1
,
03
3
13
5
7
2
,
20
6
93
7
47
1
15
0
35
8
84
4
25
5
21
6
74
3
35
8
,
79
8
36
%
Ge
n
e
r
a
l

S
e
r
v
i
c
e

-

L
a
r
a
e
60
9
42
5
10
,
70
%
04
1
97
1
60
0
88
7
95
3
06
4
27
3
,
47
7
16
5
39
7
49
,
14
6
/5
6
7
45
4
05
%
Ge
n
e
r
a
l

S
e
r
v
i
c
e

-

M
e
d
i
u
m

V
o
l
t
a
a
e
13
0
,
25
5
10
,
24
%
1.7
8
12
7
81
3
98
,
32
2
08
4
84
8
29
1
26
9
/2
,
44
2
87
%
Ge
n
e
r
a
l

S
e
r
v
i
c
e

-

H
i
a
h

V
o
l
t
a
o
e
06
1
14
3
13
,
32
%
64
9
,
4
2
1
32
6
,
06
6
28
4
98
9
69
1
04
9
62
6
/4
1
1
,
72
2
13
%
Ir
r
i
G
a
t
i
o
n
39
,
40
4
67
9
03
%
1.
0
5
43
,
28
1
,
52
4
27
,
05
8
,
33
3
68
1
91
3
13
,
97
7
,
05
9
43
8
,
15
9
12
6
,
06
0
87
6
,
84
5
84
%
07
,
Str
e
e
t

&

A
r
e
a

L
i
l
l
h
t
i
n
a
32
6
29
8
17
.
96
%
/3
.
59
4
,
34
0
80
,
32
6
86
5
43
8
,
50
9
62
,
63
2
00
8
26
8
,
04
2
62
.
15
%
Tr
a
f
f
i
c

S
i
l
l
n
a
l
s
52
6
14
.
57
%
81
8
74
6
50
8
33
9
93
6
28
9
(1
,
70
8
11
.
00
%
Sa
a
c
e

H
e
a
t
i
n
a
63
5
,
62
0
12
,
33
%
59
0
,
94
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10
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4
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d
86
5
35
3
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76
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t
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9
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m

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1
4
10
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5
39
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3
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7
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