20070927Smith direct.pdf

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BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY FOR
AUTHORITY TO INCREASE ITS RATES
AND CHARGES FOR ELECTRIC SERVICE
TO ELECTRIC CUSTOMERS IN THE STATEOF IDAHO.
CASE NO. IPC-O7-
IDAHO POWER COMPANY
DIRECT TESTIMONY
LORI SMITH
Would you please state your name, business
address, and present occupation?
My name is Lori Smith and my business address
is 1221 West Idaho Street , Boise, Idaho.I am employed by
Idaho Power Company as Vice President of Finance and Chief
Risk Officer.
What is your educational background?
I graduated in 1983 from Boise State
University, Boise, Idaho, receiving a Bachelor of Business
Administration degree in Information Sciences.In 1999, I
was awarded the designation of Chartered Financial Analyst.
I have also attended numerous seminars and conferences
related to utility accounting, corporate finance and risk
related topics.
Would you please outline your business
experience?
From 1983 to 1986, I was employed by Idaho
Power Company and assigned to the Materials Management
From 1986 to 1994, I served as a FinancialDepartment.
Accountant and later as a Budget Accountant.I was promoted
to Business Analyst in 1994.In 1996 , I was promoted to
Strategic Analysis Team Leader.In 2000, I was named
Director of Strategic Analysis.In 2003, I was named
Director of Strategic Analysis and Risk Management.
2004 , I was named to my current position as Vice President
SMITH , DI
I DAHO POWER COMPANY
of Finance and Chief Risk Officer.
What are your duties as vice President of
Finance and Chief Risk Officer?
I oversee and direct four distinct areas
wi thin Idaho Power Company.First, Strategic Analysis has
the responsibilities of regulatory accounting and support,
financial forecasting, valuation and analytical support.
Second , Financial Accounting and Reporting is responsible
for the general ledger , property records, assuring the
Company s compliance with Generally Accepted Accounting
Principles (GAAP) and external reporting (Securities
Exchange Commission and New York Stock Exchange) .Third,
Corporate Risk Management has the responsibility of
implementing risk management tools related to credit, market
and operational risk along with exploring and implementing
hedging strategies.Last is the Corporate Support Area that
is responsible for developing, monitoring and updating, as
appropriate, the annual budget for operating expenses and
construction expenditures.
What is the purpose of your testimony in this
proceeding?
The purpose of my testimony is to present the
actual and forecasted financial information for the twelve-
month periods ended December 31 , 2006, 2007 and 2008.
these three years, 2007 is the proposed test year.
SMITH, DI
IDAHO POWER COMPANY
addition, my testimony presents certain deductions to
operating expenses as well as adj ustments which have been
included to annualize certain 2007 operating expenses and
rate base items.The purpose of presenting 2008 forecasted
information along with the 2007 forecasted test year is to
demonstrate the continued significant financial burden the
Company is experiencing due to the growth within its service
terri tory.
will you be supporting any of the normalizing
adjustments to the 2007 forecasted test year?
Ms. Schwendiman will address theNo.
normalizing adjustments to sales and revenues and Mr. Said
will address the normalization of power supply costs.
How was the 2007 test year financial
information prepared?
For the 2007 test year , the system financial
information was prepared using an entire year of forecasted
information.The test year data reflects expected 2007
Operation and Maintenance (O&M) expense and 2007
Construction expenses and investment (Construction). Both
O&M and Construction data were derived from the standard
Company budget process.All items unrelated to O&M and
Construction and all other non-normalized components for the
test year 2007 were forecast using a variety of methods
specific to the item being forecasted.
SMITH, DI
IDAHO POWER COMPANY
The forecast process began with calendar year
2006 actual data as a basis to forecast all non-normalized
components for the test year 2007.In addition, we
forecasted specific items related to operating expenses and
rate base which include reductions to operating expenses,
annualizing adjustments to operating expenses and rate base
and specific other operating expense and rate base
adj ustments.
Was the forecast information for calendar
year 2008 prepared in a similar manner?
Yes.
What
financial test year information that you are sponsoring?
are the forecasted components to the
In describing the forecasted components, I
will use the account names from the Uniform System of
The forecasted components include the followingAccounts.
items:(2) other revenues and(1) other operating revenues,
(3) operation and maintenance expenses,(4 )expenses,
property insurance expenses,(6 )(5) regulatory expenses
depreciation and amortization expenses,(7) amortizations
adjustments, gains and losses,(8) regulatory debits and
credits (10) Idaho(9) taxes other than income taxes,
Energy Resources Company (IERCo) Statement of Income and
(11) electric plant in service andRate Base Components
related items (13) deferred(12) materials and supplies
SMITH , DI
I DAHO POWER COMPANY
conservation programs,(14) other deferred programs (15 )
deferred income taxes,(16) customer advances for
construction , and (17) certain deductions from operating and
maintenance expenses.
Please summarize the test year adjustments.
After the initial 2007 test year information
was compiled , the 2007 O&M expenses were reduced by making
certain deductions consistent with previous orders issued by
the Commission.After the O&M expense reductions,
annualizing adjustments and certain other adjustments were
made.The additional components included in this filing for
annualizing adjustments to operating expenses and rate base
are adjustments for payroll, employee incentives, a 2008
salary structure adj ustment, depreciation , depreciation
reserve , and annualized major plant additions and their
associated impacts.
How was the financial forecast developed?
O&M and Construction estimates were the
result of Idaho Power s annual budgeting process which was
prepared in the fall of 2006.The budgets were presented to
Idaho Power s Board of Directors on November 16, 2006 and
approved.The approved Construction budget was adjusted to
incorporate updated information known by January 2007.
Other items were forecasted using a variety of methods
specific to the item being forecast.
SMITH, DI
IDAHO POWER COMPANY
The financial forecast is an annual forecast.
Although Idaho Power s budgets are analyzed and developed on
a monthly basis, predicting the actual month in which
transactions will ultimately occur is inherently uncertain.
Some items such as amortization expense are fixed monthly
expenses while most other items are dependent on project
timing, external providers of goods and services and other
variables over which Idaho Power has no control.
Addi tionally, GAAP dictates when the transactions are
recorded for book purposes.For example, events that were
originally expected to occur in April may not actually occur
until June.These changes are commonly referred to as
timing differences and are expected to take place in the
near future.
In past rate cases, a 13 -month average was
used for determining Electric Plant in Service and most
other rate base items.However , because of the inherent
uncertainty in forecasting monthly amounts and the certainty
that timing differences will exist, a simple average
methodology has been used for determining the expected
amount of Electric Plant in Service and other rate ase
items.
Please describe the budgeting process for O&M
and Construction.
SMITH, DI
I DAHO POWER COMPANY
Idaho Power s 2007 and 2008 O&M expense and
construction expenditure budgets were prepared in late
summer and fall of 2006.The budget process began with
general guidance from executive management to Idaho Power
business units (Delivery, Power Supply and Corporate and
Administration) Each business unit identified proposed O&M
expenses and Construction expenditures based on knowledge of
their business unit's unique business activities and
requirements.Some of the factors taken into consideration
in developing the budget were individual cost center
requirements, the 2006 Integrated Resource Plan, customer
growth , infrastructure needs to maintain reliability, new
compliance acti vi ties and inflation.Business unit budgets
were prepared for each cost center by cost element (labor,
materials, purchases services and other) .Idaho Power does
not develop budgets by the Federal Energy Regulatory
Commission (FERC) account.The proposed cost center budgets
were then rolled up and summarized in a business unit view
and reviewed by the business units' senior management and
vice-presidents.
Once business unit reviews were completed,
the proposed budgets were reviewed and approved by executive
After executive management finalized the 2007managemen t .
budgets, they were presented to Idaho Power s Board of
Directors on November 16 , 2006 and approved.At this time
SMITH , DI
I DAHO POWER COMPANY
Idaho Power s Board of Directors reviewed the 2008
forecasted O&M expense and Construction expenditures but did
not formally approve them.
Please describe the method for allocating the
cost center O&M budgets to FERC account in more detail.
As I have stated, Idaho Power does not budget
O&M by FERC account.Business unit budgets are prepared for
each cost center by cost element (labor, materials
purchased services and other) To present an O&M budget by
FERC account as I have done in my exhibits, an allocation
methodology was developed and applied.
Budgeted O&M expense by cost center was
allocated to FERC account based on 2006 actual O&M charges
to those accounts.There were exceptions to the historical
allocation treatment including property insurance - Account
924, pension expense - Account 926.2, third party
transmission - Account 565, regulatory commission expense
Account 928, incentive expense and demand side management
(DSM) expenses.Budgeted amounts were known by FERC account
for property insurance, pension expense and third-party
transmission expense and did not require an allocation.
Estimates for amounts to be paid to third parties for
transmission were based on the September 28, 2006 operating
plan presented to Idaho Power s Risk Management Committee.
In 2006, regulatory commission expense included a $3.
SMITH, DI
IDAHO POWER COMPANY
million credit resulting from the settlement of a lawsuit
with FERC pertaining to FERC billings from 2003 through
2005.without adjustment , an allocation based on 2006
actuals would have distorted the results; therefore, the
FERC account balance was estimated for the account and was
not subj ect to allocation.Incenti ve and DSM expenses were
not part of the original business unit budgets and did not
require allocation.
Please describe the process for developing
forecasted electric plant and plant-related items in more
detail.
To forecast Electric plant in service
Account 101 , December 31 , 2006 account balances served as
the beginning balance and were adjusted for forecasted
Closed to Plant" driven by the Construction Budget and
expected retirements of plant items.I will describe
Closed to Plant" and "Retirements " in greater detail later
in my testimony.The budget process identified Construction
expenditures by project and business unit leaders estimated
Closed to Plant" amounts.Estimated closings to plant were
allocated based on an historical average.Retirements were
then estimated based on the historical percentage of
retirements to plant by FERC account.
What do you mean by the term "Closed to
Plant?"
SMITH, DI
IDAHO POWER COMPANY
Closed to Plant" are those dollar amounts
that are moved from Construction Work in Progress (CWIP) -
Account 107 to Electric plant in Service (EPIS) - Account
101 because a particular proj ect has been completed.
How is "Closed to Plant" handled in
developing the test year data?
Closed to Plant" amounts were estimated by
Project Type by the business units.As part of the
Construction budget process , proj ect leaders provided
estimated in-service dates for their projects.The expected
in-service dates were used to determine when those projects
would close to plant.Blanket-type work orders are used for
purchases that are made throughout the year and are defined
as budgeted non-specific location work orders that are less
than $25,000.The "Closed to Plant" estimates for this type
of work order were averaged throughout the year.
How are construction expenditures handled in
developing the 2007 test year?
Expected construction expenditures are
developed in the course of the budget process described
previously.Budgeted construction expenditures approved by
Idaho Power s Board of Directors on November 16 , 2006 were
reduced to recognize the planned delay of expenditures for
the upgrade to the Shoshone hydro plant and to remove the
majority of expenditures for the development of coal-fired
SMITH, DI
I DAHO POWER COMPANY
generating resources.Nei ther proj ect is expected to close
to plant in 2007 or 2008 and will thus remain in CWIP.
Although Idaho Power estimates that $20 million to $50
million could be spent from 2007 to 2009 for the development
of a coal resource, the proj ects require very long lead
times with significant expenditures spread over many years
making accurate estimates difficult.As such , spending
estimates in the development of coal-fired generating
resources were removed from the construction expenditures.
Estimates for the long lead time proj ects will be developed
and presented when appropriate.
What are "retirements " and how are they
addressed?
Retirements are specific plant items that
have been removed from service due to damage, replacement or
have reached the end of their estimated useful life (fully
depreciated or amortized) and thus are being removed from
Retirements were estimated based on aEPIS - Account 101.
five-year historical average percentage of monthly
retirements to monthly additions.The average monthly
percentages were applied to additions to plant to determine
the dollar value of the retirements.The retirements
reduced both EPIS and Accumulated Depreciation.
please explain how major plant additions are
included in the test year?
SMITH, DI
I DAHO POWER COMPANY
The business units were asked to identify
maj or plant additions by proj ect in excess of $2 million
that would close to EPIS - Account 101 , prior to year-end
2007.These estimates served as the basis for maj or plant
additions to be annualized for 2007 as shown on page 3 of
Exhibi t 18.
Earlier you mentioned a variety of methods
were used for forecasting items unrelated to O&M and
Construction and all other non-normalized components.What
are some of those other methods used?
Items unrelated to plant, O&M and non-
normalized components were forecasted using a variety of
methodologies.Since each item is unique , Company personnel
with the most knowledge of the item analyzed them separately
to determine the best forecasting method.Methods used
included trending based on historical averages,
identification and adjustment for known events, and if
appropriate, applying inflation.If a more appropriate
method did not exist, 2006 data was used.
Are you sponsoring exhibits in this
proceeding?
Yes, I am sponsoring Exhibits 16 through 19.
The work papers supporting my testimony and exhibits have
also been included with the Company s rate case filing.
Would you please describe Exhibit No. 16?
SMITH, DI
IDAHO POWER COMPANY
Exhibit No. 16 is a compilation of the
Company I S supporting schedules of the test year financial
information for the twelve months ended December 31, 2007.
Page 1 of Exhibit No. 16 sets forth the development of the
Other Operating Revenues - Accounts 449,451, 454 and 456.
Have there been any changes in the way you
account for Other Operating Revenues?
Under the Company s FERC Open AccessYes.
Transmission Tariff (OATT) , parties using the Company
transmission system must reimburse the Company for
transmission line losses.In previous general rate cases
the Company had included revenues for the provision of
energy to serve third-party transmission line losses in
Other Electric Revenues - Account 456.However , at the end
of 2005 , it was determined since these revenues are energy-
related it would be more appropriate to record these
revenues to Sales for Resale - Account 447.The amount 0
revenues included in Account 447 , as an adder to the
normalized revenues in this account , for 2007 and 2008 is
$6.4 million and $7.2 million , respectively.Al though
Account 447 is a PCA account , these amounts are not subj ect
to PCA treatment.
How has Idaho Power determined the pricing
for these revenues?
SMITH, DI
IDAHO POWER COMPANY
The Company determined the Mwh' s scheduled
and applied the heavy load (HL) and light load (LL) hour
marginal costs provided to us by Mr. Said.
How does Idaho Power account for the
provision of energy for losses when the Company uses the
transmission systems of other companies to bring in energy
to serve customer loads?
At the same time the Company determined the
more appropriate recording of its provision of energy to
serve third-party transmission line losses in Account 447,
the Company also determined that its cost to reimburse to
other Companies for their transmission losses should be
recorded in Purchased Power - Account 555 rather than
Transmission of Electricity by Others - Account 565.These
payments to other companies are also not reflected in power
supply modeling supervised by Mr. Said.The amounts are
included in Account 555 as adders to normalized purchased
power expenses and were $1.3 million and $1.9 million for
2007 and 2008, respectively.Again, these amounts are not
subj ect to PCA treatment.
How has Idaho Power determined the pricing of
these expenses?
The Company determined , based on its
experience, that the rate for line losses should be 2
Multiplying this percentage by the MWh's scheduledpercent.
SMITH, DI
I DAHO POWER COMPANY
establishes the estimated losses in MWh' s.Finally, using
the heavy load and light load hour marginal cost estimate
provided by Mr. Said , the Company was able to estimate the
expense.
Would you please describe pages 2 through
of Exhibit No. 16?
Page 2 of Exhibit 16 reflects the Other
Revenues - Account 415 and other Expenses - Account 416.
The O&M expenses, by FERC account, appear on pages 3 through
6 of Exhibit No. 16.
Would you please describe pages 7 through
of Exhibit No. 16?
Page 7 reflects the detail of Property
Page 8 reflects theInsurance Expenses - Account 924.
detail for Regulatory Commission Expenses - Account 928.
Has anything occurred that has had a
significant effect on Regulatory Commission Expenses -
Account 928?
As I mentioned briefly above, IdahoYes.
Power Company and numerous other companies were involved in
a lawsuit with the FERC involving both FERC administration
fees and Other Federal Agency (OFA) charges.The subsequent
settlement resulted in the Company receiving a non-recurring
credit for $0.7 million in its 2006 billing.Addi tionally,
the Company had accrued FERC and OFA fees since 2003 , based
SMITH, DI
I DAHO POWER COMPANY
upon an estimate provided by the FERC.Upon settlement, the
Company was required to adjust its accrual for OFA fees and
administration fees in the amount of $2.4 million and $0.
million, respectively, in addition to the credit received
for 2006.This amounted to a total reduction of fees in the
amount of $3.3 million.
How has this settlement impacted your 2007
and forecast?
The 2007 expense is based upon the 2006
actual billing, excluding the non-recurring credit received.
Would you please describe pages 9 through 17
of Exhibit No. 16?
Pages 9 through 14 show total depreciation
and amortization expense by plant account.Page 15 shows
the prairie Power acquisition amortization adjustment and
gains on the sale of electric plant.Page 16 reflects the
regulatory debit for the amortization of Professional Fees
created by IPUC Order 29505.Page 17 shows the detail of
the Taxes Other Than Income Taxes.
Would you please describe page 18 of Exhibit
No. 16?
Page 18 of Exhibit No. 16 develops the net
earnings from IERCo that are added to the booked operating
income for ratemaking purposes.
How does the Company treat IERCo I s earnings
SMITH, DI
I DAHO POWER COMPANY
and investment for ratemaking purposes?
The primary purpose of IERCo is to mine coal
and providing fuel for the Jim Bridger thermal power plant
in Wyoming.Consistent with prior Commission orders, the
Company treats IERCo I s coal operations as part of its
utility operations and accordingly adds the current year
IERCo earnings to electric operating income and the
investment in IERCo to the net electric rate base.
Accordingly, the interest expense (line 13, page 18 of
Exhibit No. 16) resulting from the notes payable to Idaho
Power has been added back to IERCo ' s income.Additionally,
the notes payable (line 3, page 27 of Exhibit No. 16) to
Idaho Power was added back to IERCo in determining the
Company I S net investment in IERCo to include in rate base.
Why have you made these adjustments to
IERCo s earnings and rate base in this proceeding?
These adj ustments were made to increase
IERCo I S rate base for notes payable to Idaho Power in the
amount of $12,020,924 and the associated interest expense
adjustment of $479 696 to allow IERCo I s rate base and
earnings to reflect only the cash required to fund IERCo
operations for the year 2007.If IERCo were to use these
funds to make a distribution of earnings to the Company, or
if the Company were to actually fold IERCo into its own
operations, the result would be the same as presented
SMITH, DI
I DAHO POWER COMPANY
herein.
Please explain any significant events that
have impacted the net income of IERCO.
In 2006 IERCO , who has one-third ownership of
Bridger Coal Company (BCC) , had anticipated revenues from
BCC of approximately $7.1 million.BCC is a provider of
coal to the Jim Bridger electric generating plant.Black
Butte Coal , who is also a provider of coal to the Jim
Bridger electric generating plant , encountered production
problems that reduced the volume of coal they delivered to
the plant.BCC increased production to make up for the
reduced deliveries from Black Butte.This increased
production provided $2.2 million in additional revenues that
IERCO had not anticipated.
The Company s forecast for 2007 and 2008
reflects a return to a more normal level of production and
subsequent revenues for these years.
Are there any other maj or events that have
impacted IERCO's forecast?
IERCO's income taxes are calculatedYes.
using the federal tax rate of 35 percent.No accrual is
made for state income taxes since the state of Wyoming has
no state income tax.In the previous rate cases, BCC
utilized a fiscal year which ended March 31st.After the
buyout of PacifiCorp, BCC's fiscal year was converted to a
SMITH , DI
I DAHO POWER COMPANY
calendar year.Since BCC taxes are accrued and paid during
the calendar year, the conversion caused additional tax
adjustments to occur in 2006.One such adjustment,
depletion, is a permanent tax difference and thus impacts
income tax expense.Due to BCC's fiscal year conversion,
IERCO recorded an additional depletion tax benefit of $.
million in 2006.A $0.7 million tax benefit for depletion
is forecasted for 2007 and 2008.
Also in 2006, BCC settled IRS audits for tax
The settlement allowed IERCO to reverseyears 2001-2003.
$1.9 million of accrued income tax reserves, as the amounts
assessed were less than previously accrued.
By adjusting for these non-recurring events,
IERCO's 2006 effective tax rate is 22.2 percent which is
consistent with the 2007 forecasted rate of 25 percent.
Finally, IERCO's notes payable to Idaho Power
will continue to increase from approximately $9.2 million at
December 31, 2006 to $14.9 million for 2007 as a result of
reclamation costs and capital expenditures for the
construction of BCC's new underground mine.Starting in
2008 , reclamation costs will be paid out of the reclamation
trust fund and the new mine will be substantially complete,
resulting in a decline in notes payable to $4.4 million by
year-end 2008.
Would you please describe the data contained
SMITH, DI
IDAHO POWER COMPANY
on pages 19 through 27 of Exhibit No. 16?
Pages 19 through 27 of Exhibit No. 16 reflect
the development of all the components applicable to the
combined system rate base of the Company for the year 2007.
Page 19 reflects the balance at the beginning and end of
2007 and the average balance of Electric Plant in Service
Account 101.Page 20 reflects the balance at the beginning
and end of 2007 and the average balance of Accumulated
provision for Depreciation - Account 108.Page 21 reflects
the balance at the beginning and end of 2007 and the average
balance of Accumulated provision for Amortization - Account
Page 22 reflects the balance at the beginning and end111.
of 2007 and the average balance of Materials and Supplies
Accounts 154 and 163.Page 23 and Page 24 reflect the
balance of the Company I s Deferred Conservation and Other
Deferred Programs.For these programs the Company includes
the December 31 , 2007 ending balance in rate base consistent
with prior orders of this Commission.
Would you please describe in more detail
Other Deferred Programs on Page 24?
The previously approved programs areYes.
the American Falls Bond Refinancing costs that are a direct
reduction to O&M, the 2001 through 2003 Incremental Security
Costs incurred after September 11 , 2001, Professional Fees
which are being amortized over a five-year period and
SMITH, DI
IDAHO POWER COMPANY
Intervenor Funding costs resulting from the 2005 rate case
the load growth adjustment case and the fixed cost
adjustment case, all with an assumed amortization period of
one year and finally, Oregon and the FERC's jurisdictional
portion of the Grid West loans.
Would you please describe the remaining pages
in Exhibit 16?
Yes. Page 25 reflects the balance at the
beginning and end of 2007 and the average balance for
Accumulated Deferred Income Taxes - Accounts 190, 282, and
Page 26 reflects the balance at the beginning and end283.
of 2007 and the average balance of Customer Advances for
Construction - Account 252.Page 27 reflects the balance at
the beginning and end of 2007 and the average balance of the
rate base components for IERCo, consistent with prior orders
of the Commission.
Would you please describe Exhibit No.1 7?
Exhibit No. 17 reflects the detailed support
of deductions from the O&M expense of the Company for
certain general advertising expenses, memberships and
contributions and senior management expenses. These
adjustments have been made by the Company consistent with
prior orders of the Commission and are responsive to
concerns brought during the 2003 general rate case, Case No.
IPC-03-13.They are reflected on pages 1 through
SMITH , DI
I DAHO POWER COMPANY
In light of some of the concerns expressed in
the 2003 rate case, the Company has put processes in place
to review accounting for memberships and contributions in an
effort to properly identify, account for and share the costs
of each. All of the contributions and one-third of all
memberships have been removed, which is consistent with the
last general rate case.Addi tionally, senior management
expenses have been reviewed and adjusted by (1) removing 100
percent of charges for the Arid Club and Oregon direct
charge s ;(2) removing one- third of EEI travel expenses; and
(3) allocating the balance of charges between Idaho Power
and IDACORP on the basis of how their payroll is charged.
Four officers were excluded from the allocation as their
expenses are reviewed monthly, not requiring a further
allocation.These reductions are consistent with the
Commission s order in Case No. IPC-03-13.
Would you please describe Exhibit No. 18?
Exhibit No. 18 , consisting of four pages,
reflects the detailed support for annualizing adjustments to
the 2007 operating expenses and the rate base of the
These adjustments reflect changes to certainCompany.
operating expense and rate base items as if they had been in
existence for a full year , or to year-end 2007 levels,
whichever is applicable.Page 1, line 1 reflects an
adjustment to year-end levels resulting in an increase in
SMITH, DI
IDAHO POWER COMPANY
operating payroll of $4,500 064.Line 2, page 1 shows the
annualized employee incentive expense adjustment of
$229,859.This increase to expense is a result of using the
normalized incentive target rate for customer satisfaction,
operational excellence and network reliability of four
percent, which is more than the forecasted incentive expense
included in Administration and General Salaries - Account
Line 3 , page 1 shows the operating payroll adjustment920.
of $3,020 719 to estimate the Company I s salary structure
adjustment for 2008.
The computation and detail supporting the
amounts shown on page 1 of Exhibit No. 18 are shown on page
Page 3 shows the annualized impacts of maj or
plant additions for transmission , production and general
plant assets during 2007.Page 3 , column 4 , line 23
reflects the net annualizing adjustment to rate base of
$44 855,880.The related changes to Property Tax and
Insurance Expense are shown on page 3 , columns 6 and 8 , line
, respectively.Page 4 details, by plant account, the
related change to Depreciation Expense - Account 403 and
Depreciation Reserve - Account 108.
What was the purpose of including an
adjustment for the 2007 incentive?
In summary, the incentive plan program
SMITH , DI
I DAHO POWER COMPANY
includes three components:(1) customer satisfaction based
on the Consumer Relation Index (CRI) ,(2) budgetary
management goals based on operation and maintenance expenses
and (3) network reliability, all which provides benefits to
In addition, Idaho Power Company has aour customers.
profit sharing component as part of its incentive program.
However, this component is not included in the 2007 rate
case due to previous Commission concerns that its primary
benefit is to Idaho Power s shareholders.
What percentage for incentives have you
included in the rate case?
As stated earlier , the percentage used was
the normalized target rate of 4 percent as determined and
approved by the Board of Directors.
What is the purpose of including the 2008
Salary Structure Adj ustment?
The Salary Structure Adjustment (SSA) is a
process reviewed annually in the fall.The purpose is to
review key factors to keep the salary structure competi ti ve
wi th other companies.The SSA is not intended to be a cost-
of-living adjustment nor is it guaranteed that the Company
will adjust the structure every year.In the SSA review
process, Idaho Power gathers and analyzes data from the
following sources:(1) preliminary results of our annual
wage study - which is a comparison of our pay for certain
SMITH, 01
I DAHO POWER COMPANY
benchmark jobs to the market pay for the same jobs;(2) data
of other local companies on their plans for salary structure
adj ustments;(3) bargaining uni t and non-bargaining uni t
adjustments made by other northwest utilities; and (4) the
Consumer Price Index through September of each year.All of
the above information is considered as well as the impact of
an estimated increase in compensation costs on the Company.
Overall , the Company considers what is necessary to remain
competitive and avoid other costs such as those related to
A final recommendation is made to our Board oft urnove r .
Directors ' Compensation Committee.Salary structure
adjustments that are approved by the Compensation Committee
are effective in January of the ensuing year.Since rates
will be in effect around January 1st, and in discussions
with Mr. Gale, we have deemed it appropriate to be included
in the revenue requirement.
Would you please explain Exhibit No. 19?
Exhibit No. 19 , consisting of one page
reflects additional adjustments to rate base and operating
expenses resulting from charges to Electric Plant
Acquisition Adjustments - Account 114, Accumulated provision
for Amortization of Electric Plant Acquisition Adjustments
Account 115, Investment in Associated Companies - Account
123, Employee Pension and Benefits - Account 926, Idaho DSM
Rider Revenues and Customer Assistance Expenses - Accounts
SMITH , DI
I DAHO POWER COMPANY
456 and 908, Regulatory Commission Expense - Account 928 and
Miscellaneous Transmission Expenses - Account 566.
Would you please describe the adjustments to
rate base, operating revenues and operating expenses on
Exhibit No. 19?
Exhibit No. 19, lines 1 through 3 reflect the
unamortized portion of the Electric Plant Acquisition
Adjustment associated with the prairie Power Rural Electric
Cooperative purchase in July 1992.Line 4 reflects a
decrease to Investment in Associated Companies (IERCO) -
Account 123, for a portion of plant deemed not used and
useful at Bridger Coal.This adj ustment was as a result of
IPUC Order No. 29505.Lines 5 through 7 reflect FAS 87
Pension Expense removed from Employee Pension and Benefits
Account 926 which was also a result of IPUC Order No. 29505.
Lines 8 and 9 remove the income statement impact of the DSM
accounting resulting from IPUC Order No. 30189.Lines 10
through 12 record the amortization expense increasing
Regulatory Commission Expenses - Account 928, based on an
assumed one-year amortization period which resulted from
IPUC Order Nos. 30035, 30215 and 30267.Line 13 increases
Miscellaneous Transmission Expenses - Account 566 for one
year of the five-year amortization period for the Grid West
Loan ,as a result of IPUC Order No. 30157.
Please describe the adjustment to Exhibit No.
SMITH, DI
I DAHO POWER COMPANY
19 related to pension expense removal.
Exhibit No. 19 line 5 shows the $6,950 435
total FAS 87 Net periodic Pension Cost the Company estimates
it will report in the Company s financial statements.The
operating expense percentage of 66.29 percent is then
applied to the total FAS 87 cost to arrive at the operating
expense portion of $4,607 443.In accordance with GAAP , the
Company continues to capitalize the remaining period cost of
$2,342,992 related to pension.
Are all the data and their adjustments made
to your exhibits and supporting schedules calculated on a
total system basis?
Yes.
Does this conclude your direct testimony in
this case?
Yes, it does.
SMITH, 01
IDAHO POWER COMPANY
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LINE
FERC
ACCOUNT
NUMBER
IDAHO POWER COMPANY
OPERATION AND MAINTENANCE EXPENSES
For Twelve Months Ended December 31 , 2006 , 2007 and 2008
DESCRIPTION
Oper and supv engineering
Fuel
Steam expenses
Electric expenses
Misc steam power expenses
TotaJ. operation
Rents
Power production expenses,
Steam power generation -
Operation -
500
501
502
505
506
507
Maintenance -510 Main supv and engineering511 Main of structures512 Main of boiler plant513 Main of electric plant514 Main of misc steam pJ.ant
TotaJ. maintenance
Total steam power generation
Hydraulic power generation -
Operation -
535
536
537
538
539
540
Oper supv and engineering
Water for power
Hydraulic expenses
Electric expenses
Misc hydro pwr gen exp
Rents
Total operation
Maintenance -541 Main supv and engineering542 Main of structures543 Main of res,dams,waterwys544 Main of electric pJ.ant545 Main of misc hydro pJ.ant
Total maintenance
Total hydraulic power generation
Other power generation -
Operation -
546
547
548
549
550
Oper supv and engineering
Fuel
Generation expenses
Misc other pwr gen exp
Rents
Total operation
(1)
Actuals
Dec 2006
712,,506
107,143
444,277
112,999
248,621
18,655,519
2,,52~,469
408,848
';'/7,169
133,882
~;75 61?
321,285
45,976,831
522,31.2
93'/,659
258,502
38'/391
10'/, on
109,191
21,922,126
871,365
1.,193,32'/
916 682
138,'133
6"5
363,762
31,286,188
322 341
23,844
290,3':,
29'/218
933 755
(2)
Forecast
2007
821,361
'/,
558,882
536,07'/
660,
':,
'/9
261,12'/
19,841 326
685,992
131,83':,
16,354,882
715, '/0':-
866,448
29,057,862
48,899,188
810,216
01,516
784,461
-175,628
560,489
435,518
23,317,858
990,26'/
269,
006,868
2'/4,6'/9
418,1.24
959,063
33,276,921
3-13,
308,802
316,159
968,006
(3)
Forecast
2008
903 322
899,032
605,200
050,305
2'16,326
20,734,185
806 862
454,403
1'1 090 852
'J, 92'9,2
085 ,138
30,365,467
099,652
026,676
48'1 866
179,762
542,031
2 , 6 -, 5 , '711
455,116
24,367 162
19,829
326,236
1 ,05;~, l'!'
37'1 0'10
'3,571,940
10,407 222
34,774 384
358,',82
322,698
3'30,386
011,566
Exhibit No, 16
Case No, IPC-07-
L. Smith, IPC
Page 3 of 27
LINE
FERC
ACCOUNT
NUMBER
IDAHO POWER COMPANY
OPERATION AND MAINTENANCE EXPENSES
Fen Twelve, ~1')nt.hs Ended December 31 , 2006, 2007 and 2008
DESCRIPTION
Other power generation - (continued)
Maintenance -551 Main supv and engineering552 Main of structures553 Main of gen and elec pIt554 Main misc oth pwr gen pIt
Total maintenance
TotaJ. other power generation
Other power
555
556
557
suppJ.y expenses -
Purchased power
System cont and
Other expenses
load disp
Total other power supply expenses
Total power production expenses
(1)
Actuals
Dec 2006
173
176,972
12'1,319
392,516
693,980
627 735
76,1'10
221,692
297,832
81,188,589
(2)
Forecast
2007
184
188,220
132,220
117 465
738,089
706,095
80,979
362 928
443,907
86,326,111
(3)
Forecast
2008
192
196,690
138 170
B6,251
771,303
782,869
623
-169,260
553,883
90,210,788
Exhibit No. 16
Case No. IPC-07-
L. Smith, IPC
Page 4 of 27
LINE
IDAHO POWER COMPANY
OPERATION AND MAINTENANCE EXPENSES
For Twelve MontIlC' Ended December 31, 2006, 2007 and 2008
DESCRIPTION
Oper supv and engineering
Load dispatching
Station expenses
Overhead line expenses
Underground 1 ine expenses
Trans of elec by others
Misc trans expenses
Rents
Total operation
FERC
ACCOUNT
NUMBER
Transmission expenses:
Operation -
560
561
562
563
564
565
566
567
Maintenance -568 Main569 Main570 Main571 Main573 Main
supv and engineering
of structures
of station equip
of overhead lines
of misc trans pJ.ant
Total maintenance
TotaJ. transmission expenses
Distribution expenses:
Operation -
580
581
582
583
584
585
586
587
588
589
Oper supv and engineering
Load dispatching
Station expenses
Overhead line expenses
Underground 1 ine expenses
St light and sgnl sys exp
Meter expenses
CUstomer instaH expenses
Misc distribution exp
Rents
Maintenance -
Total operation
590
591
592
593
594
595
596
597
598
Main supv and engineering
Main of structures
Main of station equip
Main of overhead lines
Main of underground lines
Main of line transformers
Main of st 19ht-sgnl sys
Main of meters
Main of misc dist plant
Total maintenance
Total distribution expenses
(1 )
Actuals
Dec 2006
537 078
486,275
866,906
869,797
638,680
270 768
152,152
17,821,656
460,937
198,081
900 424
257,538
31,222
848 202
23,669,858
051,138
020,110
159,8133
856,696
042,167
154,596
288,265
148,759
589,808
149,968
24,461,390
22:' ,168
1326 0213
11,020 129
114,7136
583,246
711,171
895,593
1413,970
17,523,091
41,984,481
(2)
Forecast
2007
679,711
685,996
972,017
918,731
112,'0-10
286,037
216,8'0-1
16,871,776
186,860
209,216
063,715
385,091
33,042
6, 177, 924
23,049,700
223 185
18",903
225,357
073,573
156,989
163,286
529,437
213,167
912,806
159,530
25,847 533
235,714
985,16,
11,639,783
177,687
616,052
751,148
945,960
157,347
18,508,855
44,356,388
(3)
Forecast
2008
800,298
851,366
060,758
960,074
387 500
298,909
271,602
631,007
508,769
218,631
201 582
492,420
34,529
455,931
24,086,938
368,228
303,449
280,498
256,884
254 054
170,63'1
733,262
268,073
178,882
166,709
27,010,673
2'16,321
119,496
12,163,573
230,683
6'13,774
784,950
988,528
164 428
19,341 753
46,352,426
Exhibit No. 16
Case No. IPC-07-
L. Smith, IPC
Page 5 of 27
LINE
FERC
ACCOUNT
NUMBER
IDAHO POWER COMPANY
OPERATION AND MAINTENANCE EXPENSES
For Twelve etonths Ended December 31, 2006, 2007 and 2008
DESCRIPTION
Customer accounts expenses,
Operation -
901
902
903
904
905
Supervision
Meter reading expenses
Cust records - collect exp
Uncollectible accounts
Misc customer accts exp
TotaJ. customer accounts expenses
Customer service and informational
Operation -
907
908
909
910
912
Supervision
Customer assistance exp
Info and instruct adv exp
Misc cust svc and inf exp
Demo and selling exp
expenses,
Total customer service and
informational expenses
Administrative and generaJ. expenses:
Operation -
920
921
922
923
924
925
926
927
928
929
930,
930.
931
Admin and gen saJ.aries
Office supplies and exp
Admin exp transf - cr
Outside services employed
Property insurance
Injuries and damages
Emp pensions and benefits
Franchise requirements
Reg commission expenses
Duplicate charges - cr
General advertising exp
Misc general expenses
Rents
Total operation
Maintenance -935 Main of general plant
Total maintenance
Total administrative and
generaJ. expenses
Total electric operation
and maintenance expenses
(1)
Actuals
Dec 2006
537 023
254,777
10,146,625
848,490
372
18,787 287
288,822
047 316
200
847,736
10,184 074
48,935,653
665,998
(29,324,259)
149,646
945,897
152,000
29,2-11,893
2, 000
976,225
107 310
901,158
003
757 524
969,367
969,367
86,726,891
262,541,180
(2)
Forecast
2007
567 670
550,318
10,766,272
008,612
393
19,893,265
305,080
25,290,188
214
895,540
26,491,322
15,865,180
15,714,482
131,406,717)
73.025
1101,021
518,327
30,885,371
11,4
013,084
115,013
027,623
L 290
84,587 143
228,573
228,573
88,815,716
288,932,502
(3)
Forecast
2008
593,215
800,082
11,250,75'1
144,000
'111
20,788,462
318,809
28,808,848
224
935,339
30,063,720
'17 929,427
'121.,634
320,019)
127 056
254,152
766,652
275,213
240
'1,193,673
120,139
118,366
, '183
88,393,566
418 859
418,859
92,812 425
304 314,759
Exhibit No. 16
Case No. IPC-07-
L. Smith, IPC
Page 6 of 27
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Idaho Power Company
Intelliplant Depreciation System
Depreciation and Amortization Expense
Twelve Months Ending 12/31/00
FERC Account Jan-06 Feb-06 Mar-O6 Apr-May.Jun-O6
302 943,950,949.017.990.947,
303 669 527.669 527,669 527.669 527,669 527.669527.
Total Amortization
Expense 72'1470.727 4'17.62 12'1,476,727 544,62,727,517,'7274'14,
310 384.384,384.384,384,384,
311 280 940.280895.280 830.280,725,280723,280857,
312 170,865.171 341,167 559,166 866.173 041,180424,
314 354 825,354 933.48 358 726,357 784,357 798.357,927.
315 109 831.47 109 855.109 855.109 865,109 865,109 865.
316 711,818.818,778,789,092,
Total Steam
Production 951 558,'/4 952 226,952 1'75,46 950 405,956,602,964 552.
331 256,410.40 255 631.255 686.255 844,255,833,255 703.
332 387 898,388 006.388 037.388 050,388 059.388 062,
333 283 665.283 670,283 670,283670.283 670.283,610.
334 953.87,221.43 87,414,87,663.664,613.
335 848,22,984.032.055,23,090.167,
336 11,246.246.246.246.246.246.
Total Hydro
Production 049024,048,'160,049067 049 531 049 56548 049,404,
341 12,784.41 12,694.12,694.40 694,12,695.07 694,46
342 298,299,45 300.22 301,301,300.
343 488,70,489.77 70,490,70,490.70,491.70,490,
344 144 956,144,985.146 504.146 523,146 533.146,506.71
345 11,498.11,499.11,500,501,501,49 500.
346 220,314,360.363,363,363.
Total Other
Production 251 247 251 283,252 649:16 252 874,252 886,252 856,
Total Production 251 630,47 252 272.10 254 113,252,610,259,055,266.812,
352 217,252.500.172,212.393.
353 416 745,416,714,416467,417 729,417 747.420017.
Total Transmission
Stations 451 963,451 96'1.451 957.453 902,41 453960,457 411,
350 377.825,670,43 303.299.45 299.45
354 161 919.22 161 963,191,203.191 555.191 559.66 191,497,
355 225,893.20 225 810.185,439.185 557.185615,185,485.
356 187,428.187 337.190 766.191 014.191,061.191 077,
359 283.283.283.283.283.283.
Total Transmission
Lines 615 902.615,22079 606 364,606.715,606 820.606,644
Total Transmission 067 866,067 188,058,332,060.617,060 781,064 055.
361 979,999,34,139,160,205,216,
362 189 281,189 393.189 278,189,495,191 536.192,366.
Total Distribution
Stations 223,260,22339280 223.418.223,655,225,742,226 582.41
384 582.410,582 081.582,794,583,498,583,375.584,477.
385 260,646.23 260.400.260 513.260 610.260741.44 261,220.
366 70,737,70,739,025.71,432.71,471,441,
367 350,034,350846.45 351 514.352 697,354,236.354 997,
368 423,495,425,075.427 521,430,239.432,555.43 435 510.
369 149 321.149692.150 401.150 854.42 151,410.151 927.
370 170,465.171 238.169 009.168 621.42 172,785.41 173 228,
371 734,705,21,787,21,863,21,830,914,
373 171,149.207,207,244.262.
Total Distribution
Lines 048 018.050.929.78 053 776.059,022,067 65289 073.980,
Total Distribution 271 279,274.322,277 195.282 678,293,39521 300 563,
390 123 205.123,430.123 521.16 123,454.123 536.127,801,
391 442 818.446,046.41 455 336.431,432,474,328.477,090.45
392 150.150.150.150.150.150,
393 402.48 536.536.539,539.539.
394 143.29,214,234.379,563.565.
395 394,394,840.51,116,141.51,56BA1
396
397 212 091.213487.214 076,214 076.215,401,223 350.
398 18,577.34 856,20,470.784,784,784.
Total General 682 783.889 116,900 166.876 933.921,444,936 850,
Total Depreciation
Expense 7,473,760,7,482 899.489 807.473,040.534 676.568 281,
Depreciation on
Disallowed Costs :24,6l'16')(24 69' 61)124,691 0')(24.691,61;(24 591.511 (24.69'.61)
Total Account 403 7.449068.43 458 207 7,465,115,7.448,348,509,984.46 543,589,
Exhibit No. 16
Case No, IPC-07-
L. Smith, IPC
Page 9 of 27
Idaho Power Company
Intelliplant Depreciation System
Depreciation and Amortization Expense
Twelve Months Ending 12/31'\)6
FERC Account Jul.Aug-Se~6 Oct-Nov-Dec-12 Month Total
302 029.57,411,57,400.57,404,57,557.OB6.700,690.44
303 669 527,669 527,935 513,699 OBO.699,OBO.699OB1 ,388 970,
Total Amortization
Expense 727,556,726.938,992 913.756 4B4,756 637,764 168.21 089 661,
310 3B4.3B4,3B4,3B4.3B4.3B4,609.20
311 280 973.2BO,973,2BO,84B.2BOB70.2B1,464.40 281 217.21 371 320.
312 1B1 761.201,946.201,150,202 327,201,579,200 B97,14,219,762,
314 358,4BB,359 739.35B,193.35B,457,35B,433.354 205.289 513,
315 109 865.109 B65,110 129,110 129.110 136.110 130,319,397.41
316 015.047,047,047,070.43 070,419 307,
Total Steam
Production 966.4B9.9B7 956.985 752.987 216.987 06B.50 1 ,9B1 .905,623 910.45
331 255 5B6.255 570,255624,255 61B.46 255 6BO.262 671.075 B62.40
332 3BB070.3BB 105,3BB329.3BB331,3BB660,3B8 770.658 383,
333 283 701,283697.20 2B3 924,2B3 924,2B5 022,2B5,029.3,407,255,
334 614.B7,612.45 612.45 B7,612.45 653.46 77B,050,414,
335 276.29 23,563.44 593.674.6B6,715.279.68B,
336 246.1',246.1',246,246.246,246.134 961,
Total Hydro
Production 049.496,049.795.050 330,050 407.051 949,059.212,12,606 565,
341 694.694,12,694.12,695.46 695.46 695.46 152.427.
342 300,300.301.302.302.302.610,
343 490.4B 70,490.70,490.70,491.B63.B63.B4B.631.
344 146 512,146 3BB,146 399.147 91B.146,615.146 741.756585,
345 500.500,501,502,502.502,138,011,
346 363.363.370,370,325,327.109.45
Total Other
Production 252,B62.42 252,739.252 759.42 254 280,254.304,254,432,035 377.33
Total Production 26B,847,290,491.28B B43,291 904,293 323,295.549.77 265,B53.44
352 529,562,95B,3B,973.4B 977.006,446,75B,
353 425 742.431 929.46 430,626,431 306.434,11B.434 047.093 192.45
Total Transmission
Stations 463.271,469.491,469 585.470,279,473 095,473 053.539 950.
350 120,050,050.44 805.B06.BB9.473,499.
354 194 042.194 274.194,22B,199B9B.199 914.200 OB3.272 140.
355 1B6,11B.1 B6660,186,801.1B7382.187 24B.1B7 6B5,315,699,
356 192 696,192 993,193 O6B.49 1942B4,194 313.194,4B1.300 524,
359 2B3,283.2B3,2B3.2B3,2B3,3.407,
Total Transmission
Lines 609 262.613 262,613.433.623,654.623 567,624424.365 271,
Total Transmission 072 533.082 754,083 01B,1.093.934 096,662,097,478,905 222,
361 34.476,B34.960.971.45 517,613.410 075.
362 191.406.192,154.192 BB9.193 OB4,195 OBO.195 974.301.943.
Total Distribution
Stations 225 B83,225 989.226 850,227 055.229 59B,230 58B.2,712 01B,
364 5B6,831.5B7 160,5B9 101.5B9 463,592,BB2.49 593 B95.43 037 971.
365 262,6B5.262 765,262,941,263928,266 B26.266 9B6.4B 150.267,
366 707,810,72,34B.72,B07.73,129,292,861 943,
367 355 360,355 713.357 36B.49 359 195.363665.45 364,609.44 270.241.11
36B 43B 579,441 711,445 935.44B349,452 503.456 035,257 512,
369 152,B39.153 702,154,305.49 1549BO,156 1B5,156,466.832 OB9,
370 170,B92.172,011.171 904.173795,174 701,176557.065 211,
371 21,964.973.22,032,099.231,300.4B 263.43B,
373 2B9.273,334,354,431.4B 19.442.231 370.23
Total Distribution
Lines OBO149,0B6.122 095 272,103 974.21 121 55B,129,587,970 045,
Total Distribution 306 032.312 11107 322 123.331 030.351 156,360 175.6B2 064.
390 127 617.127.479.127 559,127 559.127 693,128 BB2,511 740.
391 492 493.493 922.495 B51.499 744.42 50B 312.511 50B,5,728 8B3,
392 150.150.150.9B.9B,9B,649.
393 511,511,511,511.511.525,177.39
394 701.839,932,932,9B2,035.40 355,523,
395 059,059,193.854,872.90B.626 404.46
396
397 232 222,232,B65,233 262,233726,235 657,237535,697 753.41
39B 739,739,20,B63.B79,B79.077.246.435,
Total General 962,495.27 964 567.967 32516 972 306,983 007,9B9 57U5 11.246 56B,
Total Depreciation
Expense 609909.649 924.46 661 309.6B9 175.724 150,742 775.91,099,709.
Depreciation on
Disallowed Costs (24,691.6"124,691.61)124391,31)(24 691 611 (24 691.6'"'24 69'61)(296 299.32)
Total Account 403 585 218,625 232,63661B02 664.4B4 699 458,71B 083,B03,410.29
Exhibit No. 16
Case No. IPC-07-
L. Smith , IPC
Page 10 of27
Idaho Power Company
Intelliplant Depreciation System
Estimated Depreciation and Amortization Expense
Twelve Months Ending 12131107
FERC Account Accrual Rate Accrual Rate Jan-O7 Feb-O7 Mar-O7 Apr-O7 May-O7 Jun-O7
302 088,088,088,088.65.088.85.088.
303 599.991.608 648,610.350,613.848.620.556.630.876.41
Total Amortization
Expensa (Account 404)885.080,673,738.675.439.41 678.93729 685645,895,967.
310 0227 00189 383,383.383,383.383,383.
311 0259 00218 281 959.282.149.282.340,282,602.47 282,889,283.081,
312 0289 00241 218.154.42 221.249.224.385,228.626,233 290,236.430.
314 0348 00290 355.499.356.193,358 892.357.848.358 895.359.600.
315 0216 00180 110.448,110.485,110,483.110.508.110.536.110.555.
316 0331 00276 36.118.36.044,35.969,35.867.755.35.679,
Total Steam Production 002.561 006,465,010436,015.837.49 021.75U4 025,732,
331 0237 00198 264.706,284.953,285.224.265.419,265,497.265.656,
332 0194 00162 398.286.396,439.398.681,396.800,396.866.396.978.
333 0183 00153 286 784,286 924,286 918,287.032,287.041.287.100,
334 0285 00238 87.597.177,126,88.802,88.632.873,
335 0184 00153 23,853.23.925,941.74 000,24.008,043,
336 0195 00163 329,11.329.11.342.49 342.11.345.42 11.348.
Total Hydro Production 070 557.071)50,0n.23514 0"13.198.073 391,074,001.
341 0284 00237 565,12.565,565.565.12.578.578.
342 0283 00236 308,308,308.308,326.326,
343 0288 00240 71.896,896,896,71.896,71.905.42 905,
344 0284 00237 146 194,146 194,146194.146 194,146.661.52 146 661.
345 0279 00233 908.10.906,10.909.908.10.921,921.
346 0288 00240 324,324,324.324.35226 352,
Total Other Production 253 198,253.198 253,198,253,198.253.745.253 745
Total Production 326 317,331,434,335 86927 342 233.348,88824 353,478,
352 0129 00108 725,39.812,832,361.40.472,636,
353 0212 00177 435 049.436,405,436 780,442 409,444.083,450 309,
Total Transmission
Stations 474,774,476,217.45 478 613,482.771,484 556,490 945,
350 0182 00152 39.964,39.973,39.975,719,43.720.270,
354 0245 00204 199 927,199 938,199.940,204 518.204 52023 205 195,
355 0294 00245 189.342,189.344,189340,202.674,202.641.204 491,
356 0196 00163 195 627.40 195 626,195623,205.576,205.548.206,920,
359 0107 00089 283,283,283,282,282.282.
Total TransmissIon
Lines 625,14460 625 16736 625,16228 656 771.49 656714,061 16072
Total Transmission 1.099.91926 101.384.1.101,775,139.542,U41 UO,1.152.100.
361 0205 00171 35.044.35.082,113,35.986.35.986.349.
362 0164 00137 195.852.196.144.196.392,203 217,203.219.206056,
Total Distribution
Stations 230 897 92 231.22709 231.506,239.203,206.242.40595
364 0367 00306 595.786.596.630.597 379.602.204.43 603 652.608 856,
365 0325 00271 268.070.268455,268 837,271.654,272.326.275 281.
366 0204 00170 175.256.74,419.74,486,647.671.
367 0273 00228 370 155.41 370.765,371 494,374.411.86 375.08323 375 144.
368 0173 00144 459 017.46023728 462 036.465,405.467.883.471.299.
389 0369 00308 157 919.158 142,158 553.158.982.159.486,159.849.
370 0406 00338 177,862,179.314,180.185,181 041,181 826,182.056,
371 1185 00988 22.474,22.595,22.741,22.804.61 907,23.008.
373 0575 00479 19,481,19.530,19.562,19.571,712.42 678.
Total Distribution Lines 144 943,149 928,155 209,170 562,1n525.38 189.847.49
Total Distribution 375,841 11 381 15514 386.715,2.409 766AO 416 732,2.432,253 44
390 0239 00199 128 138,128 145,127 992.127.970,127.847,127.602,
391 1662 01385 517,299,524,209,528.923,533 251,537.397,539.854.
392 0407 00339 173 062,173.443.77 174 483.174 718.176 266,179 226.
393 0789 00658 463,6,463,463,6,463,6,463.463,
394 0831 00693 260,29,342.29.573,30,484.241,31.324,
395 0653 00544 100.53.858.134.55.166.621,725.77
396 0699 00583 42.599.42.578.43.581.43.571,499.75 363,
397 1079 00899 253,489.48 256,476.48 257 315.259.359.260666.262,464,
396 0950 00708 565,034,774,795,789,794.
Total Genaral 223,979,238,552,250 242,260 771 83 269.014.275.820.
Depreciation Expense on
Electric Plant in Service 026 05703 052.528,07480329 152.314,175 905,8213658,
Depreciation Expense on
Disallowed Costs ,24,("" "",-/4 "'" ,)O!(24.&81 ,(JO)::'4 W" ,r!D),::'0'" D'h ;;4,0", ,,:))
Total Dapreciation
Expense 8001388,027,835,049,91229 127 62355 151,214,186 967.
Account 312.300 ~""o "
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Account 392 I"e,Go; ",)
",;
U 220 ")
Account 386 ('0","1 (4",11 ,:,1)'o~"3.59'
Account 387,300 GO,'::2.000,)0,(22,":!000'inyu mooo GO)
Tot81403 Expense 754 65'7.52 760 766.55 800 800,878 287,000.401.26 935,33L29
Exhibit No. 16
Case No. IPC-07-
L. Smith , IPC
Page 11 of 27
Idaho Powar Company
Inteniplant Depreciation System
Estimated Depreciation and Amortization Expense
Twalve Months Ending 12/31/07
FERC Account Jul-O7 -O7 -O7 Oct-O7 Nov-O7 Dec-O7 12 Month Total
302 65,066.066,066.066,066,65,066.761 063.44
303 660,075,669 266.672,292,676632,663,610,669356.20 7.735 53'
Total Amortization
Expense (Account 404)725,164,734,376,737,361.'13 741 720.746,696.754.446,516,594,
310 363.70 363,383,363,363.363.70 604.40
311 284 270.29 264464,264 721,265 426,265 624.265 622,3.405,353,
312 255,776,256 945,263,132,274 607.277,622,261,053.41 973 457.46
314 363 941.54 364 652.25 365 591,366 166,366,667,369,612.345 763,
315 110,670.110,669.110714.110 762,110,602,110,621,327,47796
316 35,215.139.036,763.665,606,424 665.
Total Steam Production 050,260,054 275,059,562,074 130,076 206.062,302.24.46'1.562.43
331 266 175,266,296,266 377.85 267 569,275,600.42 276,164.02 20966U2
332 397,393.397 476.397 525,396,541.B0 405 767,406 225,762,963.
333 267,194.267 246,267 294.267 373.267 102,267,225,3.445.239.41
334 69,227.69.441.640,666.663,66,361,064 430.46
335 24,115.144.169,262.727,24,616,290,029,
336 364,366,366.11.414,604,11,621.43 137 174,
Total Hydro Production 75,470,1.075,970,076.373.31 079 047,092 666,094,635,12,929,516.
341 12,576.12,576.12,576.12,560.12,560,12,560,150,692:72
342 326,326,326.329,329,329,653,
343 71,905.42 71,905.42 71,905.42 71,906,906.906.862,834.
344 146,661,146,661,146,661.146 733,146 733,146,733,756 26'
345 10,921,10,921.10,921.32 10,923.923,10,923,131.009,
346 352,352,352.26 356,356.356,129,
Total Other Production 253,745:14 253,745,253,745.253 629,253 629,253,629.043 007,
Total Production 379.4'76,363,991,369.701,3.407 00191 3.424 922.76 3.430:16'7.32 40.454,066.40
352 40,742,40,765,40,765.40 40,691,41,096,376.466.461,
353 452.466,452,650.452 976,455,056,455 933,459,167,373 490,
Tota' Transmission
Stations 493 210,493615.493,742.23 495 946,497 031,500 545,659 972.76
350 609,44,637,636.639.662.443,531.274,
354 205 609,205,643,205,645.205,647.211,611.49 213 964,462,361,
355 205 662.41 205 754,205 756.205 712.223,625.230 062,2.454,626.
356 207 792.207,660.207,661,207 625,221 357,226,027.2,46364606
359 262.77 262,262,262,262,262.394,
Total Transmission
Lines 663.956,664,178.664 164.664 107,706.95946 721 799,935 306.
Total Transmission 1.157 167,157.794,15'926,1.160 055,203,991,222344,6'7 795 219.
361 36,796.927,36,965,36,965,36,966,37,003.20 435.250,
362 209 564,210 575,211 030,211,033,211,035,211,166.40 2.465 29129
Total Distribution
Stations 246,36220 247 502.47 248,016,248 019,248.022,248.171.60 900 541.98
364 610 114.611 608,613 710,614,961,616221,619,903,293 028,
365 275 960.276,726,277,772,276 363,260201.44 261,030.294 700,
366 74,970.167,75,336,75,646.75,604,75,670,699 254.
367 376,303,377,344,376,197,379 240,379468,360,540.4.508 15005
366 474.469.477.165,480,064,463 937,465,369.466,667,675 611.67
369 160596.161 141,161 663,162 560,162,602,163,362.24 924 903,
370 162,996,163 656,164,511,185 253,165,676,166 616.191 399.
371 091.06 23,196,23,307.23.433.42 23,561.726.46 276,850,
373 701.19,671,19,733.46 19,656.19,646.667,235.616.46
Total Distribution Lines 196,247,205 661.'16 2214 336.223,077.01 230 553,239,606.26.299.717.
Total Distribution 2.444.60906 2.453,364,462 352,471 096.20 476,575.42 2.487,777,29,200 259.
390 127 557,126090.126 605.126930.44 129,326,129 265,539693,
391 544,473,572,101,562,467.40 593,716.595,926,609 641,679 264
392 161 536,161 602,161 644,162,196.162,204.163 446,144,03220
393 6.463,6,463,463.6,463,463,6,463,567,
394 366,506,559,671.32,076.26 163,371 592,
395 351,57,100.215.46 57,266.57,354.57,442,670,35746
396 244,191.43,113.43,063,46 43,046.42,962.517 637.
397 264 320,266,954.266,469,269,090,272,764.275,536.45 167 166.45
396 29,601,29,606,610,615,29,620,627,340 625,
Total General 265 137.77 316,616,32~,770,342 256,349,004,366 770,15,506 13915
Depreciation Expense on
Electric Plant in Service 266,391.20 311.96~,339751.29 360 416.51 6.456.493,507,65~,98,957,767.
Depreciation Expense on
Disallowed Costs ;2U01 e(;)(:14,
;;"'\,
0(';,::, w; 1 0:): ,2461)1 ()i)J (2-\0\11 U(;)(:'4;;"1,::'D6 ",r:,OOI
Total Depreciation
Expense 24'1.700.20 267 296.D7 315 06029 355725,6,431 602.39 6,462 966.661,475,
Account 312,300 (9,0'0 io)040 'lo!0'6.151 (9040 i5)(9.040"'.5)(103,561.00)
Account 392 (131,00'),91,)Y" 1 ".. 1 (1B2,1% 3n (13'-20':,~1i ,,50.440,09)(2,1"'GO2,20)
Account 396 (40 2',"8)(42191,
"',,".
OSHel (4)0'099)(4V6202)(51U21.'13)
Account 397.300 C:,O000iJ).,;'2 :)G'iOO,,22 :;GO 122,GGO GO)(2'.000,00),22,"')0,001 ,264 0(jG 00)
Total 403 Expense
'/,
965 612,031,45"059,055,099 396.175,504.225 513.95.627 044,
Exhibit No. 16
Case No, IPC-O7-
L. Smith, IPC
Page 12 of27
Idaho Power Company
Intelliplant Depreciation System
Depreciation and Amortization Expense
1'w.iv. Month, Ending 12131;02
FERC Account Accrual Rate Accrual Rate Jan.Feb-Mar.Apr-May-Jun-
302 65,088,088,068.65,066.086.068,
303 427,227.435,884.437 567.441 064.447,792.456 114,
Total Amortization Expense
(Account 404)492 316,500 972.96 502 675,506 173.52 512 881.24 523 203,
310 0227 00189 363.383.363,383,363.363,
311 0259 00216 286022,266,167,266 353,266 516.266679.266 840.
312 ) 0"""00241 284 300,286,991.40 269 695,292,372.295,002.297 615,
314 0348 00290 370 341,370945,371 551.372,152,372 742,373 329.
315 0216 00160 110,640.110 656,110 672.69 110 868,110 904.110 920,
316 (' 'J?,"00276 530.465,34,400,336.45 273,210.
Total Steam Production 086,416.49 089 830,093 257,096 652,099 986.41 103 298,
331 0237 00196 280,407.280,425,260 505.280 616.280,632,280649.
332
,, """
00162 409 678.41 409 891,409,942.410 034,410 046.410058,
333 0183 00153 287 399.41 287,404,287 446.267,460,267,465.41 287,470,
334 0265 00238 88,689.709,883.934,953,972.
335 0184 00153 175.44 178.200.213,216,25,219.93
336 0195 00163 001.002.002.006,006,007,
Total Hydro Production 103 552,103 611,103961.43 104 266,104 322,104 378.15
341 0284 00237 12,620,620,620,847,990,005.
342 0263 00236 382.382,382.723,916,12,936.
343 0288 00240 71,932.71,932,932,025.118.126,
344 0284 00237 148,147,148 147,148 147.262 603.267 665.266,224.
345 0279 00233 10,962,962.962,150.44 292,306.
346 0288 00240 3,440,3,440,3,440,10,222.523.555.
Total Other Production 255.48550 255.485,255,485.369 572,395 527,396 157.
Total Production 3.445,456.3.448,921,3.452 724.590.491,599635,603 834,
352 0129 00108 743,41,787,41,831,41,875,893,42 564,
353 0212 00177 463,922.464646.465 274,465 901,464 801.473,531,
Total Transmission Stations 505 666,506.434.507 106,507 777.50 506 695,516 09670
350 0182 00152 349,52,439.52,559,679,122.704,
354 0245 00204 215 074.215 184.215 331,215.478,219 686,221 621,
355 0294 00245 233 236.49 233 543.233 960,234 378,246 782,252 272.43
356 0196 00163 228 375,228,603.44 228 914,229 224.238.495.242 562,
359 0107 00089 282,282.281.281.28U1 281.48
Total Transmission Lines 729 318,730,052..731 047,732,042,761 367,774,462.
Total Transmission 234 964.46 1.236,48,'238,153,239 820.0"1 1.266 063.1.290 559,
361 0205 00171 177.23 165.192,37,200.275.766.
362 0164 00137 212 529.49 212 590.212,652,212 713,213 298.217 291.
Total Distribution Stations 249 "106,249,775,249 645,249 914,250 5"14.255 07785
364 0367 00306 624 631.626231.41 627 660,629 022.630,559.632,748.
365 0325 00271 283 824.40 284546.23 285 302.286 017.286 802.287,976.
356 0204 00170 133,305.76,481.648.48 600.014,
367 0273 00228 381 500,362.4D9.383 370.364 323.385 186,366 226,
366 0173 00144 494 031,496308.496 575.27 500 708.502 951.41 506 061.45
369 0369 00308 164 241,164701.165 156.165 581,166 009,166 611.
370 0406 00338 166 956,188,313,169 091.47 190,581,191 290.191 895.
371 1165 00988 876,23,978.092.194.296.47 24.413,
373 0575 00479 669,691.712.723.40 746,76U6
Total Distribution Lines 255 067,262.487.269 444.276,801,283,844,292,711,
Total Distribution 504.773,512 263,519 289.526.715,534 219.23 547 78956
390
-,",,
00199 129 029.130 523.48 131,719.132 915.134 111.95 135 308.40
391 01385 512 638.515 620,524 057,531 967,539 878,548 357.
392 00339 184 946.184 773,184753,184 733,184 712.184692.
393 0789 00658 853.853,853,853.853,853,
394 0831 00693 31,561.699,31,823,947,071.96 209,
395 0653 00544 855.086,517,947,378,608,
396 0699 00583 42.406.279.42,171.063,955,847.
397 00899 255 171.256 798,258 258,259 718.48 261 178.262,637.
398 0850 00708 824,942,060.178.46 296.43.414.22
Total General 261 086,267 578.21 279 215.290,326,301.437,313,130.27
Depreciation Expense on
Electric Plant in Service 8.446,303.55 6.465 256,8.489 384,647 353,703 55508 755 313,
Depreciation Expense on
Disallowed Costs (2'
(;:,) '
Do.)(2' :;::
:,/,)
(2'(;": ,:Xi)'24 (;(,,;,:Xi) (2,
(;;:
:Xi'(2o (;(r:,:xi'
Total Depreciation Expense 421 612,8.440 56512 8.464 693,622 662,676 664,730 622,
Account 312.300 :8,4f)i;O,04f).1'":9,('46 c",""6 ;ob,,9.D4f) '6,('46 i;O:
Account 392 \10",:;,6,1:'):(H",?/:,,;1S:',Yr,7:;:,S;)
"",,'!:::j,"";
',Yr.1E;Y)) nYr ,(;(,;;, oD)
Account 396 (4240552)(42,27964)(42 ;' 60)
\",
063 i'O)(41SGr;68),4' e47 68)
Account 397,300
:;,
()OO OOj
(;,
();n OOj (:2 ()O() OOj
;(.
()GO GOj :;.'.2,OPO(1(1,:;-'2 ()OO ()OJ
Total 403 Expense 163 212,162,465.206 721.384 619,421 148.6,473 035.25
Exhibit No, 16
Case No. IPC-07-
L. Smith IPC
Page 13 of 27
Idaho Power Company
Intelliplant Depreciation System
Depreciation and Amortization Expense
Twelve Months Ending 12/31/08
FERC Account Jul-Aug-Sep-Oct-o8 Nov-Dec-12 Month Total
302 352 853,354 297.44 355 160.356 139.41 356,740,357 573.523,29'1,
303 487 312.496 524.499 528,503 868.44 510,846,516 594.43 662,366,
Total Amortization Expense
(Account 404)840 165,850 822,854,689,860,00'/.86'1 586,6'/8'14,168.09 185663.48
310 383.383.383,383,383.383,604.40
311 288 376,288 537.288 698.289 206.289 367,289,530.3.452,316.
312 322 624,325 243.45 327 866.336 135.338 769,341,410.15,738,026.
314 378,940.379 528.41 380 116.381 972.44 382 563,383 156.517 340.
315 111 069.11 111 084.111 100,111 149,111,165.111,181,332,034,
316 609.547.33,484,285,222.26 158,406 524,
Total Steam Production 135 003,'/8 138,324.48 141 649.29 152,133.155,472.44 158 820.25,450 847,
331 280,'/65.281 346.281,410,284 085,284 212.284241.379.298,
332 410 153.49 410510.410565.412 256.47 412 368,412,392.928 099,
333 287,487,287823,28'/826.24 289,270.289 271.289,275,3,455600.
334 034,90,433,440.437.28 96,426,96,442.092 357,
335 234,406,412.44 26,165.174,177.86 305 776.
336 011.011,014.28 023.029.030,144 148.41
Total Hydro Production 104,685.10'/533,10'1668J3 120 239.45 120,481.120 559.305 281.39
341 035.050,065.065.065.18,065,182 052,
342 978.996.016,016,016.016.141 765.
343 147,156.166,74,166,166,166.883 040,
344 269 265.269 802.270 339.270 339.270339.270 339.863 362.27
345 14,336,350,365.365.365.365,161J88,
346 617.849.681.21 681.681.681.105 615,
Total Other Production 397 37'7.93 398 007,398 636.398 636,398636,398636,33'1 643.
Total Production 637 06759 643 865,647 954,671 00861 674 590.46 6'78 015,43,093.772,
352 607,654.43 697,304.24 347.42 374,509 683.43
353 474,813.475,438.476027.484,461.485 082,484 859,676,562,
Total Transmission Stations 517.421.518.093.24 518,724.527,'186,528.429.528 033.188.245,
350 824,57,944,58,121.58,239.358.60,480.674,824.
354 221,768,221 915.222 132.222 279,222,425.225 018,63'1,91'1,
355 252 676,253,093.43 253,'119.253 951.254 367.262 005,963,987.24
356 242 881.243,192.42 243,658.243.818.244 127.249835,863,'109,
359 281.46 281.44 281.42 281,281,28U4 379,
Total Transmission Lines 775 43257 776 42699 777 91395 778.57005 779,56147 797621 00 14381766
Total Transmission 292,854,294 520,296 638,306 33619 307 99102 325554,332,063.43
361 828.37,836.23 37,854.996.38,517.624,452,575,
362 217 621,217683.217 828.218 938,223 790.223,851,600 790,
Total Distribution Stations 255.450.26 255.519,255682.256 934 262.407.262.476,053,365,
384 534,465.636 836.638,472.46 640,030,841,687,843 689.606 235.
365 288 881,290,174.291 007,291 799,292 661.47 293 704,3.462 702,
386 77,273.443.694.23 77,947.060,253.926056,
367 387,481.388,389,389 607.390 710.40 391 544,392 556.643306,
368 509 224,512 030.515,168,518 355.520241.523 127,096784,
369 167 279,167 779.15 168,443,169 132.24 169,447.170000.004383.42
370 192 770.193,490,194 183.194 786.195,673.196295.305,330,
371 538,640.747,24,877.84 007.145.293 811.
373 779,792,811.19,830.852,19,869.43 237,240,
Total Distribution Lines 301 69252 310 57771 319 13609 327 469,334 174,342 642,575 851.
Total Distribution 557 14278 586 09753 574 81880 584,404.49 596 582,605 119.46 629 216,
390 136,297,137,263.43 138456.139,647.140 838.142 027.628 138,
391 556,273,584,184.572,621.580,531.588 442,596 893.631 467,
392 186,935.186014,185 995.185,977.185,960.47 185 943,225.439.21
393 853.853.853.853.853,853,240.56
394 32,333.32,457,582.706.830.32,954,367 179.49
395 239.42 869.60,100,531.60,961.392.708,289,
396 637.46 417.309.48 201,094,986,500 371,
397 284,097.265 557.48 267 017.23 268,476.269936.271 396.49 160.246.
398 532,649,767.885.003.44,121.51 521 6Ti,
Total General 326 200,336,06751 347 70386 358,812.46 369920,381 569.833 051
Depreciation Expense on
Electric Plant in Service 813265.46 840,550.867 115.920 561,949 084.25 990,359,104,886 103,
Depreciation Expense on
Disallowed Costs
,:,
:4(;\)1'1(::\" OC)(!4 fo\" GC)(14(;:" (X')(:4-';:" ex')UH;\"()O)(:i\'(;2\J2,G;';;
Total Depreciation Expense 788,574.46 815 859.842,424.895,870.924,393.965 668,104 591,811,
Account 312.300 ,004(;"
',:
l004(;,
'-,;)
04(;
;')
(9,04(;,04(;'1,;)(0,04G'1c,),:'0B 5(:, CD)
Account 392 W:')"59'::W:!)',;O";:W;';95 "I; ('W',')1'(O;C:W;9';:" 4;'; i:W;
')":::(:,
25,'""\1.21\
Account 396 :-"Fr;4';:"";2'0:"iDO84B',J'2G1!8i
'"'
0941';;,40,98';;;9,1 ,,;OG 3';1."3)
Account 397.300 :2;'.UOG,(;O):2i,(;UJ.(X))'L,(;OD.OC'
'?;',
()(X).lrG):2Z,(X;(),OG)qz,C()(),
()())
(254J)Q,()Q)
Total 403 Expense 528 954,557 381,584 072,637644.666,291.707 691.101,493,439,
Exhibit No, 16
Case No. IPC-07-
L. Smith, IPC
Page 14 of27
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IDAHO POWER COMPANY
TAXES OTHER THAN INCOME TAXES
FOR THE YEARS ENDED DECEMBER 31,2006, 2007 AND 2008
Line 2006 2007 2008
DESCRIPTION Actual Estimate Estimate
Federal taxes:
Unemployment 117 590.
Social Security 898 116.
TOTAL FEDERAL TAXES 10,015,707.
State, county and local taxes:
Real and personal property:
Idaho 270 559.41 200,000.200 000,
Oregon 988,382.100,000.200 000.
Montana 362.110 000.120 000.
Wyoming 028 149.100 000,200 000,
Nevada 857 397.870 000.900 000.
Shoshone-Bannock 300.908.500.
TOTAL REAL AND PERSONAL PROPERTY 308,152.15,445,908.16,687,500.
Kilowatt-hour tax - Idaho (normalized 07)058,404.053,719.053,719.
Licenses:
Wyoming 144.3,400.700.
Nevada 100.100.100.
Shoshone-Bannock 150.150,150.
TOTAL LICENSES 394.650.950.
Regulatory commission:
Idaho 682 341.700 000.1,720 000.
Oregon 102 377.11 104 811.106 300.
TOTAL REGULATORY COMMISSION 784,718.804,811.826,300.
Franchise:
Oregon 503,988.520,000.536,000.
Unemployment - total state 280,978.280,978.280,978.
TOTAL STATE, COUNTY AND LOCAL TAXES 18,939,636.20,109,066.21,388,447.
Total other taxes 28,955,344.20,109,066.21,388,447.
Less: State & Fed P/R Loading Reversal (10,293,931.79)
NET OTHER TAXES 18,661 412.20,109,066.21,388,447.
Exhibit No. 16
Case No. IPC-07-
L. Smith, IPC
Page 17 of 27
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IDAHO POWER COMPANY
2007 RATE CASE ESTIMATE
DEFERRED INCOME TAX BALANCES
BEGINNING CHANGE IN ENDING ADJUSTED
BALANCE BALANCE BALANCE AVERAGE
BALANCE
ACCOUNT 190 - ACCUM DEF INC TAXES
004003-CONSTRUCTION ADV-252 211519 537,155 848 674 530,097
004018-LlNDEN FEEDER DEPOSITS-ACCT 253 164403 164,403 164,403
004022-CITY OF EAGLE-ACCT 253 20,891 011 902 897
005010-SFAS 112-POST-EMPL Y BEN 182/253 306,630 306 630 306 630
005033-NONVEBA PEN&BEN-Acct 228 853 341 (39 095)814 246 833 794
005044-RESTRICTED STOCK PLAN-CaMP 160 625 (255,865)(95,240)693
005047 -OTHER EMPLOYEE'S L T DEFERRED COMP-228 538 014 538,014 538,013
005053-FAS 123R-STOCK BASED COMPENSATION 585 567 684 0'76 269 643 927 605
005531-RATE CASE DISALLOWANCES-REVERSE AMORT 228546 (115,835)112 711 170 629
005532-DELIVERY ACCRUALS-ACCT 253 692 692)846
007009-PROVISION FOR RATE REFUNDS-ACCT 229 479,888 888 069 367 957 923,923
008001-VEBA-POST RET BNFTS-TRUST-ACCT 228 367 220 682 208 049,428 708 324
TOTAL 190 922 336 537 032 26,459 368 190,854
ACCOUNT 282 - ACCUM DEF INC TAXES - OTHER PROPERTY
LIBERALIZED DEPR - ELEC PLANT (219.454 280)528,629 (214 925 651)(217 189 966)
BRIDGER PRTNRSHP CPTLZD ITMS - DEF ONLY (222457)102,400 (120,057)(171 257)
FERC JURISDICTION - S, GEORGIA & 144A 818,502)818 502)818 502)
N VALMY PRTNRSHP CPTLZD ITMS - DEF ONLY (l33,?66)500 (657 266)(695 516)
TOTAL 282 (228 229 005)707 529 (223,521 476)(225 875,241)
ACCOUNT 283 - ACCUM DEF INC TAXES - OTHER
004501-ROYALTY INCOME (287571)39,095 (248,476)(268 024)
005008-GAIN/LOSS ON REACQUIRED DEBT-DEFERRED (197052)197 052 (98,526)
005051-PUC ORDER 29505 PROFESSIONAL FEES (8306)306 153)
005054-IPUC GRID WEST LOANS-ACCT 182 (364.435)887 (291 548)(327 992)
005055-0PUC GRID WEST LOANS-ACCT 182 (21 896)(1,/20)(23 616)(22 756)
005056-FERC GRID WEST EXP-ACCT 182 (118 13)(118 113)(118 113)
005057-INTERVENOR FUNDING ORDERS-ACCT 182 19,801 801 901
008020-CONSERV A TION PROGRAMS (4.436 949)267,696 169 253)803 101)
008074-INCREMENTAL SECURITY COSTS DEDUCTED (130./39)103,844 (26 895)(78 817)
FERC JURIS,144A-ACCT 283-DEF ONLY 163 100 (163,100)550
TOTAL 283 (5,401 961)543,861 (3,858,100)630,031)
TOTAL DEFERRED TAX BALANCES (211 708 630)788 422 (200 920,208)(206,314 418)
Exhibit No. 16
Case No. IPC-07-
L. Smith, IPC
Page 25 of 27
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IDAHO POWER COMPANY
DEDUCTIONS FROM OPERATION AND MAINTENANCE EXPENSES
MEMBERSHIPS AND CONTRIBUTIONSFor Twelv" ,Ianthe EndErd D"cErmber 31 2006,2007 and 200B
(1)(2)(3)(4)(5)(6)
Line Acct Y-T-D Actual-December 2006ContrbtnsMemberships Forecast ForecastOr\janization 100%33.33%(1)100%Total 2007 200B
535 The Ecological Sodety,..,...114 114 120 125
537 Brett Dumas...
,...",,..........
100 100 105 110
537 Donation for Ems......,..
...............
400 400 420 439
537 Edison Electric Institute...................
.....
799 799 889 974
537 Oregon Departmant of Agriculture..173 173 182 190
537 Society for Amarican Archeology..,
537 The Ecological Sodety...233 233 245 256
539 Oregon State Sherriff,..
.....
100 100 105 110
580 Association."",.,..",.,.,.,.,.,..,.
.........
580 Association of Idaho Cities..
.........,
580 Edison Electric Institute...
............
247 247 259 271
586 Rotary Cub..........,.........
............
119 119 125 131
586 Rotary Cub of Boise..............
.......
588 College of Southern Idaho..
..... ..............
500 500 525 549
588 Rotary Cub of Twin Falls.. .....
.....
593 Arbor Day GranL......",
.....
000 000 350 681
902 Edison Electric Institute...185 165 173 181
907 Rotary Cub,................
..........
907 Rotary Cub of Boise........
.....
908 Lions Club of Twin Falls.........,
.....
908 Rotary Cub of Boise SlI1rise..
.....
102 106
908 Rotary Cub of Caldwell....,
.....
908 Rotary Cub of Twin Falls"
908 Toastmasters..
.....
400 400 420 439
910 Ag SummiL....
........,.............."....................
500 500 525 549
921 Arizona State Board of Accountancy..
.....
240 240 252 263
921 Barbara Jensen...
.........................
921 Edison Electric Institute.
...........,...........,........
2,416 2,416 537 651
921 Montana Tax Foundation..............,........
.....
827 827 868 907
921 National Assodation of Prop Tax Rep..
.....
921 Toastmasters..............,.. ".........
...............
208 208 218 228
921 United Way of Treasure Valley..
...............'
250 250 263 274
921 Wo~d at Work.....
..,..................
220 220 231 241
930 Balletofldaho...........,.......... ..... ..............
..............
298 298 313 327
930 Air Force Appredatlon Day............
................,........,..
100 100 105 110
930 American Faits Chamber of Comnerce..
930 Annual Golf Fund Raser..,100 100 105 110
930 Associated Oregon.................,..
..........
625 625 656 686
930 Associated Taxpayer of Idaho...
..........
252 252 315 319
930 Association of Idaho Cities..,000 000 050 097
930 Association of Idaho Cities...
930 Baker City Unlimited............,....
......
485 485 509 532
930 Bingham Economic De.....lopmant,500 500 625 743
930 Blackfoot Chanber of Comnerce..,
.....
170 170 179 187
930 Blue Lakes Rotary........132 132 139 145
930 Boise Metro Charmer-...........,
.....
344 344 611 864
930 Buhl Charmer of Commerce..334 334 351 366
930 Buhl Rotary Club..........
..........
140 140 147 154
930 Business Pluslnc....................000 000 300 584
930 Cambridge Comnercial Club........
,....
930 Cascade Chamber of Comnerce...
.....
930 Charmer of Commerce..........
......
1,472 472 546 615
930 CharTtJer of Corrmerce CaldwelL..,
....
328 328 344 360
930 CharTtJer ofCorrmerce for New G..........................
930 CharTtJer of Commerce State of the City Address..,
930 CharTtJer of Commerce Sustaining..
,....
333 333 350 365
930 Contribl.tion for Economic...........
...
800 800 840 878
930 Donation CharTtJerofCommerce...
....
100 100 105 110
930 Donation Corrmunity Celebration........
....
250 250 263 274
930 Donation for Econorric Deveiopman\..075 075 429 763
930 Econorric Developmant Cont..,
......
750 750 788 823
930 Edison Electric Institute...
.....
110,554 110 554 116 082 121,305
930 Fossil Days......
................., ........,.......
150 150 158 165
930 Fruitland CharTtJer of Commerce.........
,......
930 Gem County CharTtJer of Canmerce..
..........
317 317 333 348
930 Glens Ferry Chamber of Comnerce..
.......
930 Gold Fundraser......,................",....
.........,.."
150 150 158 165
930 Hailey CharTtJer of Conrnerce..
..... .....'....
119 119 125 131
930 Hailey Rotary ClUJ....................
..........."
378 378 397 415
930 Idaho Association of Couriies..........
930 Idaho City CharTtJer of Comnerce....
930 idaho Falls CharTtJer of Commerce..
.....
930 Idaho Mining Assedatlon............,
....
025 025 126 222
930 Jerome CharTtJer of Corrmerce..206 206 216 226
Exhibit No. 17
Case No. IPC-07-
L. Smith IPC
Page 2 of 6
IDAHO POWER COMPANY
DEDUCTIONS FROM OPERATION AND MAINTENANCE EXPENSES
MEMBERSHIPS AND CONTRIBUTIONS
For 1"'1"1",, ;lonthG Ended D"ce"be~31,2006,2,)0'1 and 2008
(1)(2)(3)(4)(5)16)
Line Acct 1'-D Actual,December 2006ContrbtnsMemberships Forecast Forecast
Organization 100%33.33%(1)100%Total 2007 2008
930 Jet Boat Races",."500 500 525 549
930 Joe Marrmas Car Show",750 750 788 823
930 Kiwanis Clubof Eagle""".
930 Kiwanis Club of Les Bois",211 211 222 232
930 Kiwanis Club of Meridian""
"".",
120 120 126 132
930 Mark Moorman Regatta Scramble"100 100 105 110
930 McCall Charmer of Col1Tl1erce" " " 167 167 175 183
930 Meridian Charmer of Corrmerce."" "
930 Mini Cassa Charmer of Commerce"196 196 206 215
930 Mini Cassa DevCommission"""000 000 050 097
930 Nampa Chamber of Col1Tl1erce"475 475 499 521
930 Nampa Lions Club."""""",."""
930 Ontario ChaniJerof Corrmerce",283 283 297 311
930 Oregon Rural Bectnc",750 750 788 823
930 Oregonians for Food"".
."""",
320 320 386 448
930 Payette Chamber of Corrmerce"".167 167 175 183
930 Pocateno Cha-nber of Corrmerce"138 138 195 249
930 Rotary Cub of Boise"".""."""174 174 183 191
930 Rotary Cub of Boise SlIlrise"".""189 189 198 207
930 Rotary Cub of Eagle-Garden City"199 199 209 218
930 Rotary Cub of Na-npa""",
930 Rotary Cub ofTwin Falls""""""""."".
930 Salmon River Charmer of Corrmerce"
930 Scareaow Festival"""",
"",.
500 500 525 549
930 Snake River Building Fundraiser".100 100 105 110
100 930 South Dakota Electric Institute",357 357 375 392
101 930 Southem Idaho Economic."000 000 150 292
102 930 Summer Fund Raiser""175 175 184 192
103 930 The Conference Beard".625 625 756 880
104 930 Thunder Mollltain Da;s"800 800 840 878
105 930 Trout Days"""""""
""",.""", """"""""
140 140 147 154
106 930 Twin Fail Area Cha-nber of Corrmerce".560 560 588 614
107 930 Twin Fail Area Cha-nber of Corrmerce"100 100 105 110
108 930 Twin Fails Lions Club."".
""""""""
109 930 Wyoming Tax Payers Asoociation"783 783 922 054
110 Total..775 129,713 38,425 199 913 209 911 219 359
Exhibit No. 17
Case No. IPC-07-
L. Smith, IPC
Page 3 of 6
IDAHO POWER COMPANY
DEDUCTIONS FROM OPERATION AND MAINTENANCE EXPENSES
ADJUSTMENT TO MANAGEMENT EXPENSES
Fc',' T'.ol'", Monthe Endod Doco"",'" Jl, 2006 200"1 and OG08
Ma.Iila
Darrel AndersonTotal Expenees.
" " , ' ." , , , " " "
IDACORP Exclueions Requiring Special Treatment ILieted Below) ,
Arid Club,EEL,
. ' ,
IDACOMM & IDATECH"",
Oregon Direct Charges.TotaL"..",.., '
" ..
Payroll Percentage Allocated to IDACORP"
, , , , , , , , ' , , , ,
Net IDACORP Exclusions"Other Exclusions,
Arid Club (1oot Per IPUC Order 29505),..
Oregon - Direct Allocation 1100%1""",lDACOMM&IDATECH,..,.."", .
EEl (1/3 Per lPUC Order 29505)
, ,
Total Exclusions,
."""""""",
Dennis GribbleTotal Expenses"""",
'" ,.,."".",.
IDACORP Exclusions Requiring Special Treatment IListed Belowl,
Arid Club,EEL, , , , , . ,
, , , , , ' , , " ' , , ' " ' , , , , , , , , . ,
Oregon Direct Charges"""""",.
Total, , , , , ,
, , , , , , . ' , ,
Payroll Percentage Allocated to IDACORP,
Net IDACORP Exclusions",."",." """"'"
""""""
Other Exclusions,
Arid Club 1100% Per lPUC Order 29505)",
Oregon - Direct Allocation (100%)"""
EEl 11/3 Per lPUC Order 29505)"".
Total Exclusions,
""""""
Brian Kearnsy
Total Expenses", ".. .,.
IDACORP Exclusions Requiring special Treatment IListed Below) Arid Club.""
EEL, , , ,
'" " ",.
Oregon Direct Charges,TotaL" ,...
,.... ...
Payroll Percentage Allocated to IDACORP.
Net IDACORP Exclusions"Other Exclusions,
Arid club 1100t Per lPUC Order 29505).Oregon, Direct Allocation 1100%).
EEl 11/3 Per lPUC Order 29505),
Total Exclusions, ,
."""",."
Steve KeenTotal Expenses""
, ." . , .
IDACORP Exclusions Requiring Special Treatment IListed Below) Arid Club".
IDACOMM, .EEL., ,
, . " , ' , .
Oregon Direct Charges",
"",'..""., .""",.",
TotaL.,..., ,.
"""
Payroll Percentage Allocated to IDACORP"",.,
Net IDACORP Exclusions,Other Exclusions,
Arid Club (100% Per lPUC Order 29505)
IDACOMM 1100%1,... ...
Oregon - Direct Allocation 1100%)""",
EEl 11/3 Per HUC Order 29505)
Total Exclusions,.
LaMont Keen
Total Expenses"
", '" ",.,
IDACORP Exclusions Requiring Special Treatment
Arid Club"EEL...
IDACOMM",.
Oregon Direct Charges",Total."", .
, """,."
payroll Percentage Allocated to IDACORP,Net IDACORP Exclusions,
, , , , , , , , , , .
Other Exclusions,
Arid Club 1100% Per lPUC Order 295051""",Oregon, Direct Allocation 1100%),.
IDACOMM"".."",.. .".,.
EEl 11/3 Per lPUC Order 29505)",.""Total Exclusions.
' , , . . , , , , , ,
IListed Below) ,
" , " " " "
(1)
Y-T-D
Actuals
Dee 2006
$13,927,
695,70)
143 ,'9)
185,00)
10,103,
0, DOt
85,
43 ,
231. 78
$ 1,360,
$10,115,
(1,096,71)
019,10,70t
965,
365,
$ 1,330,
483.
483,20t29,
29,
$ 2 933,
11,183,021
750,
46.60%
815,
394,
$ 1 210,
$11,689,
158,39)
1136,30)
394.
16,40%
04B.
136.
719,
$ 2,904,
(2)(31
Forecast Forecast
2007 2008
$",
623,$15 281.86
(3,880.'9)14,055,11)
189,25)193,27)
10,654,133,
0, oot 0, oot
89,93,
293,351.57382.444,
$10 621.75 $11,099,
151.55)203,37)
470,896,
1. 00%1. 00%
94,9B.
383,401. 08
478,500,
0, oot 00%
OBO,3, 21B, B5
11,242,17)(1,298,07)
838,920,
16.00%16,00%
294,307,
41.. 02 432,
708.739.
$12,274,$12 826.
15,416,31)15,660,04)
(143 ,12)1"9,56)71'.016,
31.00%31.00%
081,175,
"3."9,
805,886,029,211,
Exhibit No. 17
Case No. IPC-07-
L. Smith, IPC
Page 4 of 6
IDAHO POWER COMPANY
DEDUCTIONS PROM OPERATION AND MAINTENANCE EXPENSES
ADJUSTMENT TO MANAGEMENT EXPENSESF01. T..elve Mm"hs E!'.dod Doco""'o, Jl, 2006, 2007 .~d 2008
lliJ tia.mo
Thomaa Saldin
Total Exponses.....,......
""",..""",.
IDACORP Exclusions Requiring Spedal Treatment (Listed Below) r
Arid Club................
EEl........,..... .
Oregon Direct Charges..TotaL,.........,.., .
Payroll Percentage Allocated to IDACORP,.
Net IDACORP Exclusions".Other Exclusions,
Arid Club (1000 Per IPUC Order 29505),..oregon, Direct Allocation (1000),
EEl 11/3 Per IPUC Order 29505).Total Exclusions.....
.".....",....,................,,...,..,...,.,....,.....,
100
101
102
Naomi Crafton-ShankalTotalExpenses,.."""
...,...,.".. ".
IDACORP Exclusions Requi ring Special Treat",ent
Arid Club.........,EEl",.....
...
Oregon Direct Charges.Total. , , ,
" , "'" ..,. , . . . . . .
Payroll Percentage Allocated to IDACORP....,
Net IDACORP Exclusions,Other Exclusions,
Arid club 11000 Per IPUC Order 29505),.,
Oregon - Direct Allocation (l000).
EEl (1/3 Per IPUC Order 29505),.
Total Exclusions...
,....,.....,
(Listed Below),
,................".....,
103
104
105
106
107
108
109
110III
112
113
114
115
116
117
118
Lori Smith
Total Expenses,..,
IDACORP Exclusions Requiring Spedal Treatment (Listed Below) ,
Arid Club.EEl.
",..,.
IDACOMM & IDATECH.....
Oregon Direct Charges....,.
Total....., ,... "
Payroll Percentage Allocated to IDACORP.,.
Net IDACORP Exclusions..Other Exclusions,
Arid Club (1000 Per IPUC Order 29505),oregon, Direct Allocation 11000).IDACOMM&IDATECH.,.,. .
EEl (1/3 Per IPUC Order 29505)
. . .
Total Exclusions.., , '
..........,
119
120
121
122
123
124
125
126
127
128
129
130
131
132
Luci McDonaldTotal Expenses,."". "
.., .' ,..""."".",
IDACORP Exclusions Requiring Spedal Treatment IListed Below) ,
Arid Club...,......EEl".., ....
Oregon Direct Charges.......Total. , .
. , , . .
Payroll Percentage Allocated to IDACORP.
Net IDACORP Exclusions,Other Exclusions,
Arid Club 11000 Per IPUC Order 29505),
Oregon - Direct Allocation 1100%).
EEl 11/3 Per IPUC Order 29505).
Total Exclusions,
,.,...,.....,.....
133
134
135
136
137
138
139
140
141
142
143
144
145
146
Jon PackwoodTotal Expenses...,.
IDACORP Exclusions Requiring Spedal Treatment IListed Below) ,
Arid Club.
EEl" ..,..
,. . . .. .
Oregon Direcc Charges,TotaL....,...""
"", ".",.."
Payroll Percentage Allocated to IDACORP..,
Net IDACORP Exclusions,
Ocher Exclusions,
Arid Club 11000 Per IPUC Order 29505).
Oregon' Direct Allocation 11000)""
EEl 11/3 Per IPUC Order 29505).
Total Exclusions,
,.,.....,....,
(1)
Actuals
Dee 2006
$ 4,073.
1170.59)
902.
000
170,
170.
$ 2,266,
266,
14,800335.
335.
$18,819,
(3,600.75)
$15 218.
000
200.
$ 1 200.
$ 5 420.
(316.93)
103.
100260.
105,
365,
69.
69.
98.700
68.
68.
(2)(3)
Forecast Porecast
2007 2008
277.469.
(179,12)(187.181
098,282.
00%000245.256,
179.187.
425,444.
379.486.
379,486,
10.000 10.000
237.248.
237.248,
$19,760.$20,649,
(3,780.79)(3,950.92)
$15 979.$16,698.
000 000
260.$ 1,260.
316.
$ 1 316.
$ 5 69L84 $ 5 947.
1332,78)1347.75)
359.
000214.
600.
000
224.
110,
325,
115.
339,
Exhibit No. 17
Case No. IPC-07-
L Smith IPC
Page 5 of 6
IDAHO POWER COMPANY
DEDUCTIONS FROM OPERATION AND MAINTENANCE EXPENSES
ADJUSTMENT TO MANAGEMENT EXPENSESFo" Twolve Momhs ""dod O'oce""'o~ n , 20G6, 200" ."d 2008
Name.
147
148
149
150
151
152
153
154
155
156
157
158
159
160
Greg PenterTotal Expenses.""
"""",.""
IDACORP Exclusions Requiring Special Treatment ILieted Belowl 'AridChlb",.".
""""""".",
EEl, , "
"'" " "". . , ' " , ' , , '.. , " ,
Oregon Direct Chargee,
, . , , , , , , , , , , ,
TotaL, , , , , ,
, , , , , , , , , , , , , , . , , . " , , , , , , , , " , . , " , , . , .
Payroll Percentage Allocated to IDACORP",
Net IDACORP Exclusions""",
Other Exclueions,
Arid Club 1100% Per IPUC Order 295051
' , , , , , ,
Oregon - Direct Allocation 1100%1
EEl 11/3 Per IPUC Order 295051"
Total Exclusions,
""""""
161
162
163
164
165
166
167
168
169
170
171
172
173
17'
John GaleTotal Expenses"",
.""""""
IDACORP Exclusions Requiring Special Treatment IListed Belowl,Arid Club,
"""""""
EEL, , , " ' , , , , ,
, , , , , , , , , , , , , .
Oregon oirect Charges.
Total, .. ..
" " '"
Payroll Percentage Allocated to IDACORP,.
Net IDAcaRP Exclusions.,.".Other Exclusions,
Arid Club 1100% Per IPUC Order 295051.
Oregon - Oirect Allocation 1100%1,
EEl 11/3 Per IPUC Order 295051,
Total Exclusione,
175 Total Reduction to Officer s Expenses.
III
Actuals
Dec 2006
$ 6,340,
145L701
1216,081672,100,00%
672.
216.150.
$ 6.038.
$ 3,150,
11,761.8'1
388.
00%
587,587,
$15 601.94
(2)
Forecast
2007
00%
$ 3 307.
849.931
457.
00%
616,616.
$ 9,464.
131
Forecast
2008
00%
$ 3,456.
933.17)
523,
0, 00%
644.
644,
$ 9,890,
Exhibit No. 17
Case No. IPC-O7-
L. Smith , IPC
Page 6 of 6
Line
No.
Idaho Power Company
Summary of Adjustments to 2007
Operating Expenses
Operating Payroll
Incentive
2008 Salary Structure Adjustment
Total Adjustments
(1 )
Amount
$ 4 500 064
229 859
020 719
750 642
Exhibit No. 18
Case No. IPC-07-
L. Smith, IPC
Page 1 of 4
Line
No.
Idaho Power Company
Detail of Adjustments to 2007
Operating Expenses
1) Operating Payroll (Various accts)
ST Payroll 2007 December
Annualized (Divided by 2 pay periods, times 26)
Less 2007 Total
Gross adjustment
Add payroll tax
Total adjustment including payroll tax
Operating percent
Adjustment to Operating Expense
00%
2) Incentive Expense (Various accts)
2007 Straight-time Payroll
Plus 2007 Overtime Budget
Less: 2007 Officer Payroll
Total Payroll Excl Officers
Normalized Incentive Rate
Normalized Incentive
Payroll Tax on Normalized Incentive
Normalized Incentive Including Payroll Tax
Less 2007 Est Incentive Incl PR Tax Excl Officers
Gross Adjustment
Times incentive operating percent
Adjustment to Operating
Expense for Incentive
3) 2008 Operating Payroll SSA (Various accts)
2007 Annualized Gross Payroll
Estimated 2008 SSA
Increase
Plus Payroll Tax
Annualized Increase Including Payroll Tax
Operating percent
Adjustment to Operating Expense
00%
00%
(1 )
Amount
$ 10,818 671
140,642 723
134 357 120
285 603
502 848
788,451
66.29%
500 064
$ 140 642 723
549 699
320 001
143 872,421
00%
754 897
460 392
215 289
978,345
236 944
97.01%
229 859
$ 140 642 723
00%
219 282
337 543
556 825
66.29%
020 719
Exhibit No. 18
Case No. IPC-07-
L. Smith, IPC
Page 2 of 4
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Account Account Desaiption301 Organization302 Franchises and Consents303 Miscellaneous Intangible Plant
TOTAL INTANGIBLE PLANT
310 Land and Land Rights311 Structures and Improvements312 Boiler Plant Equipment314 Turbogenerator Units315 Accessory electric Equipment316 Mise Power Plant Equipment
TOTAL STEAM PRODUCTION PLANT
330 Land and Land Rights331 Structures and Improvements332 Reservoirs, Dams, Waterways
333 Waterwheel, Turbines, Generato334 Accessory Electric Equipment335 Mise Power Plant Equipment
336 Roads, Railroads and Bridges
TOTAL HYDRO PROI1JCTION PLANT340 LAND AND LAND RIGHTS341 Structures and Improvements342 Fuel Holders, Producers, Acces343 Prime Movers344 Generators345 Accessory Electric Equipment346 Mise Power Plant Equipment
TOTAL OTHER ffiODUCTION PLANT
350 Land and Lend Rights352 Structures and Improvements353 Station Equipment354 Towers and Fixtures355 Poles and Fixtures356 Overhead Conductors, Devices359 Roads and Trails
TOTAL lRANSMISSION PLANT360 Land and Land Rights361 Structures and improvements362 Station Equipment
TOTAL SUBSTATION EQUIPMENT
364 Poles, Towers and Fixtures365 Overhead Conductors, Devices366 Underground Conduit367 Underground Conductors, Device368 Line Transformers369 Services370 Meters371 Installations, Cust Premises373 Street Lighting, Signal System
TOTAL DISTRIBUTION LINES
389 Land and Land Rights390 Structures and Improvements391 Office Fumiture, Equipment392 Transportation Equipment393 Stores Equipment
394 Tools, Shop, Garage Equipment395 Laboratory Equipment396 Power Operated Equipment397 Communication Equipment398 Miscellaneous Equipment
TOTAL GENERAL EQUIPMENT PLANT
TOTAL ELB:TRIC PLANT IN SERVICE
Amortization of Disallowed Costs
TOTAL DEPRECIATION & AMORTIZATION
Idaho Power ColT4'any
2007 Annualized Expense end Reserve Adjustment
2007 Annualized 2007 Estimated
Depreciation Depreciation 2007 Annualizing
Expense Expense Adjustment
781 063.781 063.44
745 351.40 735 531.820.
526.414,516 594,820,
608.45 604.40
429 618,3,405,353.264.
15,400 944.973.457.48 427.486,
444 096.345 783,313,
330 088,327 477,610.
414 113,424 885.(10 772.05)
023.469.34 24.481 562.43 541 906.
356 395,209 661.146 733.
908 420.46 782 983,125.436.49
3,437 522,3,445 239.4 1 717,06)
062 042,064,430.48 387,64)
302 763.43 290 029,734.43
143 578.137 174,404.
210 722,929 518.281.204,
151 228.150 892,336.
100 521.853.667,
863 190,862 834.356,
775 264.758 287,977.70
131 269.131 009,260,
283.48 129.154.20
062.759,043,007,752.
626 821,531 274.547.
498 606,486 481.79 124.
556 584.373 490,183 093,
583 001.2,462 361,120639.43
798 837.454 628.344209.
746 109,2,483 648,262.461.
390,394.(3,57)
813 351,795 279,018 072,
445 691.435 250,441,
544 148,465 291.857.
989.84058 900,541,298.60
7,493 889.293 028.200 860,
403 798,294 700.109 097.49
913 597.899 254,343,
567 970.508 150,820.
935 235.675 811,259.423.
967 698,924 903,795,
245 718,191 399,318,
286 377.276850,526,
236 112.235618.46 494,
050 398,299 717,750 680,
549648.539 693.955.
151 664.48 679 264.(527 599,66)
220,445.144 032,413,
187.77.567,379.98)
378,469.371 592.876,
680 079.670 357.46 722,
508 443,517 837,394.67)
062 630.167 168.45 (104 538.16)
514 139,340 625.173 513,
135 708,508 139,(372 430,99)
109 812 665.107,474 361,338 303.45
(286,29;',00)(296 292,00)
109 516 373.107 178 069,338 303.45
2007 Annualizing
Reserve
Adjustment
910.
910.
132,
213 743,
156.
305.45
386,02)
270 953.47
366.
718.
858,53)
193.82)
367.22
202,
140 602,
168.
333,
178.
8,488.
130,
577.10
876.
773.
062.49
546,
319.
172 104.
131 230.
(1.78)
509 036.
220.
428,
649,
100,430.44
548.
171,
910,
129 711.
397,
159,
763.45
247.
375 340,
977.67
(263 799.83)
206.
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3,438.
861.
697,33)
(52 269,08)
756.
(186 215.48)
169 151.
169 151.82
ExhibitNo,
Case No. IPC-07-
L. Smith, IPC
Page 4 of 4
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