2005Annual report.pdf

THIS FILING IS
Item 1: 00 An Initial (Original)
Submission
OR Resubmission No.
FERC FINANCIAL REPORT
FERC FORM No.1: Annual Report of
Major Electric Utilities, Licensees
and Others and Supplemental
Form 3-Q: Quarterly Financial Report
These reports are mandatory under the Federal Power Act, Sections 3, 4(a), 304 and 309, and
18 CFR 141.1 and 141.400. Failure to report may result in criminal fines, civil penalties and
other sanctions as provided by law. The Federal Energy Regulatory Commission does not
consider these reports to be of confidential nature
Form 1 Approved
OMB No. 1902-0021
(Expires 7/31/2008)
Form 1-F Approved
OMB No. 1902-0029
(Expires 6/30/2007)
Form 3-0 Approved
OMB No. 1902-0205
(Expires 6/30/2007)
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Exact Legal Name of Respondent (Company)
Idaho Power Company End of
Year/Period of Report
2005/04
FERC FORM No.1/3-(REV. 02-04)
Deloitte.Deloitte & Touche LLP
Suite 1700
101 South Capitol Boulevard
Boise, ID 83702-7717
USA
Tel: + 1 2083429361
www.deloitte.com0 0
, :!.\: :.:" ; -
INDEPENDENT AUDITORS' REPORT
Idaho Power Company
Boise, Idaho
We have audited the balance sheet-regulatory basis of Idaho Power Company (the "Company ) as of
December 31 , 2005, and the related statements of income-regulatory basis; retained earnings-
regulatory basis; cash flows-regulatory basis; and accumulated comprehensive income, comprehensive
income, and hedging activities-regulatory basis for the year ended December 31 , 2005, included on
pages 110 through 123 of the accompanying Federal Energy Regulatory Commission Form 1. These
financial statements are the responsibility of the Company s management. Our responsibility is to express
an opinion on these financial statements based on our audit.
We conducted our audit in accordance with auditing standards generally accepted in the United States of
America. Those standards require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit includes consideration of
internal control over financial reporting as a basis for designing audit procedures that are appropriate in
the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company
internal control over fmancial reporting. Accordingly, we express no such opinion. An audit also includes
examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements
assessing the accounting principles used and significant estimates made by management, as well as
evaluating the overall fmancial statement presentation. We believe that our audit provides a reasonable
basis for our opinion.
As discussed in Note 1, these financial statements were prepared in accordance with the accounting
requirements ofthe Federal Energy Regulatory Commission as set forth in its applicable Uniform System
of Accounts and published accounting releases, which is a comprehensive basis of accounting other than
accounting principles generally accepted in the United States of America.
In our opinion, such regulatory-basis financial statements present fairly, in all material respects, the
assets, liabilities, and proprietary capital of Idaho Power Company as of December 31 , 2005, and the
results of its operations and its cash flows for the year ended December 31, 2005, in accordance with the
accounting requirements of the Federal Energy Regulatory Commission as set forth in its applicable
Uniform System of Accounts and published accounting releases.
This report is intended solely for the information and use of the Board of Directors and management of
Idaho Power Company and for filing with the Federal Energy Regulatory Commission and is not intended
to be and should not be used by anyone other than these specified parties.
DELOITTE & TOUCHE LLP
March 6, 2006
Boise, Idaho
Member of
Deloitte Touche Tohmatsu
INSTRUCTIONS FOR FILING FERC FORMS 1, 1-F and 3-
GENERAL INFORMATION
Purpose
Form 1 is an annual regulatory support requirement under 18 CFR 141.1 for Major public utilities, licensees and others. Form 1-F is an annual regulatory
support requirement under 18 CFR 141.2 for Nonmajor public utilities, licensees and others. Form 3-0 is a quarterly regulatory support requirement which
supplements Forms 1 and 1-F under 18 CFR 141.400. The reports are designed to collect financial and operational information from major and nonmajor
electric utilities, licensees and others subject to the jurisdiction of the Federal Energy Regulatory Commission. These reports are also considered to be a
non-confidential public use forms.
II. Who Must Submit
Each Major electric utility, licensee, or other, as classified in the Commission s Uniform System of Accounts Prescribed for Public Utilities and Licensees
Subject To the Provisions ofThe Federal Power Act(18 CFR 101), must submit Form 1 as prescribed in 18 CFR Part 141.1. Each Nonmajorelectric utility,
licensee or other must submit Form 1-F as prescribed in 18 CFR Part 141.2. Each Major and Nonmajor electric utility licensee or other, must submit Form
0 as prescribed in 18 CFR Part 141.400.
Note: Major means having, in each of the three previous calendar years, sales or transmission service that exceeds one of the following:
(1) one million megawatt hours oftotal annual sales,
(2) 100 megawatt hours of annual sales for resale,
(3) 500 megawatt hours of annual power exchanges delivered, or
(4) 500 megawatt hours of annual wheeling for others (deliveries plus Losses).
Nonmajor means having in each of the three 'previous calendar years, total annual sales of 10,000 megawatt hours or more
III. What and Where to Submit
(a) Submit Forms 1 , 1-F and 3-0 electronically through the Form 1/3-0 Submission Software. Retain one copy of each report for your files.
(b) Respondents may submit the Corporate Officer Certification electronically, or file/mail an original signed Corporate Officer Certification to:
Chief Accountant
Federal Energy Regulatory Commission
888 First Street, NE
Washington, DC 20426
(c) Submit, immediately upon publication, four (4) copies of the latest annual report to stockholders and any annual financial or statistical report regularly
prepared and distributed to bondholders, security analysts, or industry associations. (Do not include monthly and quarterly reports. Indicate by checking the
appropriate box on Form 1 , Page 4, List of Schedules, if the reports to stockholders will be submitted or if no annual report to stockholders is prepared.) Mail
these reports to the address in III(c) above.
(d) For the Annual CPA certification, submit with the original submission, or within 30 days after the filing date for Form 1 , a letter or report (not
applicable to respondents classified as Class C or Class D prior to January 1 , 1984):
(i) Attesting to the conformity, in all material aspects, of the below listed (schedules and) pages with the Commission s applicable Uniform Systems of
Accounts (including applicable notes relating thereto and the Chief Accountant's published accounting releases), and
(ii) be signed by independent certified public accountants or an independent licensed public accountant certified or licensed by a regulatory authority
of a State or other political subdivision of the U. S. (See 18 CFR 158.10-158.12 for specific qualifications.Reference Reference
Schedules Pages
Comparative Balance Sheet 110-113Statement of Income 114-117
Statement of Retained Earnings 118-119
Statement of Cash Flows 120-121
Notes to Financial Statements 122-123
Insert the letter or report immediately following the cover sheet. When submitting after the filing date for this form , send the letter or report to the address
indicated at III (b). Use the following form for the letter or report unless unusual circumstances or conditions, explained in the Letter or report, demand that it
be varied. insert parenthetical phrases only when exceptions are reported.
FERC FORM NO.1 (REV. 12-99)Page i
GENERAL INFORMATION (continued)
In connection with our regular examination of the financial statements of for the year ended on which we have reported separately under date of
We have also reviewed schedules of FERC Form No.1 for the year filed with the Federal Energy Regulatory Commission, for conformity in all material
respects with the requirements of the Federal Energy Regulatory Commission as set forth in its applicable Uniform System of Accounts and published
accounting releases. Our review for this purpose included such tests of the accounting records and such other auditing procedures as we considered
necessary in the circumstances.
Based on our review, in our opinion the accompanying schedules identified in the preceding paragraph (except as noted below) conform in all
material respects with the accounting requirements of the Federal Energy Regulatory Commission as set forth in its applicable Uniform System of Accounts
and published accounting releases.
State in the letter or report, which, if any, of the pages above do not conform to the Commission s requirements. Describe the discrepancies that exist
(d) Federal, State and Local Governments and other authorized users may obtain additional blank copies to meet their requirements free of charge from:
Public Reference and Files Maintenance Branch Federal Energy Regulatory Commission 888 First Street, NE. Room 2A ED-12.2 Washington, DC 20426
(202).502-8371
IV. When to Submit:
Submit Form 1 according to the filing dates contained in section 18 CFR 141.1 of the Commission s regulations. Submit Form 1-F according to the filing
dates contained in section 18 CFR 141.2 of the Commission s regulations. Submit Form 3-0 according to the filing dates contained in section 18 CFR
141.400 of the Commission s regulations.
V- Where to Send Comments on Public Reporting Burden.
The public reporting burden for the Form 1 collection of information is estimated to average 1,144 hours per response, including the time for reviewing
instructions, searching existing data sources, gathering and maintaining the data-needed, and completing and reviewing the collection of information.public
reporting burden for the Form 1-F collection of information is estimated to average 112 hours per response. The public reporting burden for the Form 3-
collection of information is estimated to average 150 hours per response. Send comments regarding these burden estimates or any aspect of these
collecti.ons of information, including suggestions for reducing burden, to the Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC
20426 (Attention: Mr. Michael Miller, ED-30); and to the Office of Information and Regulatory Affairs, Office of Management and Budget, Washington, DC
20503 (Attention: Desk Officer for the Federal Energy Regulatory Commission). No person shall be subject to any penalty if any collection of information
does not display a valid control number (44 U.C. 3512 (a)).
FERC FORM NO.1 (REV. 12-99)Page ii
GENERAL INSTRUCTIONS
I. Prepare this report in conformity with the Uniform System of Accounts (18 CFR 101) (U.S. of A.). Interpret all accounting words and phrases in
accordance with the U. S. of A.
II. Enter in whole numbers (dollars or MWH) only, except where otherwise noted. (Enter cents for averages and figures per unit where cents are important.
The truncating of cents is allowed except on the four basic financial statements where rounding is required.) The amounts shown on all supporting pages
must agree with the amounts entered on the statements that they support. When applying thresholds to. determine significance for reporting purposes, use for
balance sheet accounts the balances at the end of the current reporting period, and use for statement of income accounts the current year s year to date
amounts.
III Complete each question fully and accurately, even if it has been answered in a previous report. Enter the word "None" where it truly and completely
states the fact.
IV. For any page(s) that is not applicable to the respondent, omit the page(s) and enter "
" "
NONE " or "Not Applicable" in column (d) on the List of
Schedules, pages 2 and 3.
V. Enter the month, day, and year for all dates. Use customary abbreviations. The "Date of Report" included in the header of each page is to be completed
only for resubmissions (see VII. below).
VI. Generally, except for certain schedules, all numbers, whether they are expected to be debits or credits, must be reported as positive. Numbers having a
sign that is different from the expected sign must be reported by enclosing the numbers in parentheses.
VII For any resubmissions, submit the electronic filing using the Form 1/3-Q software and send a letter identifying which pages in the form have been
revised. Send the letter to the Office of the Secretary.
VIII.Do not make references to reports of previous periods/years or to other reports in lieu of required entries, except as specifically authorized.
IX. Wherever (schedule) pages refer to figures from a previous period/year, the figures reported must be based upon those shown by the report of the
previous period/year, or an appropriate explanation given as to why the different figures were used.
Definitions for statistical classifications used for completing schedules for transmission system reporting are as follows:
FNS - Firm Network Transmission Service for Self. "Firm" means service that can not be interrupted for economic reasons and is intended to remain reliable
even under adverse conditions. "Network Service" is Network Transmission Service as described in Order No. 888 and the Open Access Transmission Tariff.
Self' means the respondent.
FNO - Firm Network Service for Others. "Firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under
adverse conditions. "Network Service" is Network Transmission Service as described in Order No. 888 and the Open Access Transmission Tariff.
lFP - for long-Term Firm Point-to-Point Transmission Reservations. "long-Term" means one year or longer and "firm" means that service cannot be
interrupted for economic reasons and is intended to remain reliable even under adverse conditions. "Point-to-Point Transmission Reservations" are described
in Order No. 888 and the Open Access Transmission Tariff. For all transactions identified as lFP , provide in a footnote the termination date of the contract
defined as the earliest date either buyer or seller can unilaterally cancel the contract.
OlF - Other long-Term Firm Transmission Service. Report service provided under contracts which do not conform to the terms of the Open Access
Transmission Tariff. "long-Term" means one year or longer and "firm" means that service cannot be interrupted for economic reasons and is intended to
remain reliable even under adverse conditions. For all transactions identified as OlF, provide in a footnote the termination date of the contract defined as the
earliest date either buyer or seller can unilaterally get out of the contract.
SFP - Short-Term Firm Point-to-Point Transmission Reservations. Use this classification for all firm point-to-point transmission reservations, where the
duration of each period of reservation is less than one-year.
NF - Non-Firm Transmission Service, where firm means that service cannot be interrupted for economic reasons and is intended to remain reliable even
under adverse conditions.
OS - Other Transmission Service. Use this classification only for those services which can not be placed in the above-mentioned classifications, such as all
other service regardless of the length of the contract and service form. Describe the type of service in a footnote for each entry.
AD - Out-of-Period Adjustments. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an
explanation in a footnote for each adjustment.
DEFINITIONS
I. Commision Authorization (Comm. Auth.) - The authorization of the Federal Energy Regulatory Commission, or any other Commission. Name the
commission whose authorization was obtained and give date of the authorization
II. Respondent -- The person, corporation, licensee, agency, authority, or other legal entity or instrumentality in whose behalf the report is made.
FERC FORM NO.1 (REV. 12-99)Page iii
EXCERPTS FROM THE LAW
Federal Power Act, 16 U.C. 791a-825r
Sec. 3. The words defined in this section shall have the following meanings for purposes of this Act, to wit: .., (3) . corporation' means any corporation,
joint-stock company, partnership, association, business trust, organized group of persons, whether incorporated or not, or a receiver or receivers, trustee or
trustees of any of the foregoing. It shalt not include 'municipalities, as hereinafter defined;
(4) 'Person' means an individual or a corporation;
(5) 'Licensee, means any person, State, or municipality Licensed under the provisions of section 4 of this Act, and any assignee or successor in interest
thereof;
(7) 'municipality means a city, county, irrigation district, drainage district, or other political subdivision or agency of a State competent under the Laws
thereof to carry an the business of developing, transmitting, unitizing, or distributing power; ......
(11) "project' means. a complete unit of improvement or development, consisting of a power house, all water conduits, all dams and appurtenant works
and structures (including navigation structures) which are a part of said unit, and all storage, diverting, or forebay reservoirs directly connected therewith, the
primary line or Lines transmitting power therefrom to the point of junction with the distribution system or with the interconnected primary transmission system,
all miscellaneous structures used and useful in connection with said unit or any part thereof, and all water rights, rights-of-way, ditches, dams, reservoirs,
Lands, or interest in Lands the use and occupancy of which are necessary or appropriate in the maintenance and operation of such unit;
Sec. 4. The Commission is hereby authorized and empowered
(a) To make investigations and to collect and record data concerning ;he utilization of the water 'resources of any region to be developed, the
water-power industry and its relation to other industries and to interstate or foreign commerce, and concerning the location, capacity, development -costs, and
relation to markets of power sites; ... to the extent the Commission may deem necessary or useful for the purposes of this Act."
Sec. 304. (a) Every Licensee and every public utility shall file with the Commission such annual and other periodic or special' reports as the Commission
may be rules and regulations or other prescribe as necessary or appropriate to assist the Commission in the -proper administration of this Act. The
Commission my prescribe the manner and form in which such reports shalt be made, and require from such persons specific answers to all questions upon
which the Commission may need information. The Commission may require that such reports shall include, among other things, full information as to assets
and Liabilities, capitalization, net investment, and reduction thereof, gross receipts, interest due and paid, depreciation, and other reserves, cost of project
and other facilities, cost of maintenance and operation of the project and other facilities, cost of renewals and replacement of the project works and other
facilities, depreciation, generation, transmission, distribution, delivery, use, and sale of electric energy. The Commission may require any such person to
make adequate provision for currently determining such costs and other facts. Such reports shall be made under oath unless the Commission otherwise
specifies
Sec. 309. The Commission shall have power to perform any and all acts, and to prescribe, issue, make, and rescind such orders, rules and regulations as it
may find necessary or appropriate to carry out the provisions of this Act. Among other things, such rules and regulations may define accounting, technical,
and trade terms used in this Act; and may prescribe the 'form or forms of all statements, declarations, applications, and reports to be filed with the
Commission, the information which they shall contain, and the time within which they shall be field...
GENERAL PENALTIES
Sec. 315. (a) Any licensee or public utility which willfully fails, within the time prescribed by the Commission, to comply with any order of the Commission, to
file any report required under this Act or any rule or regulation of the Commission thereunder, to submit any information of document required by the
Commission in the course of an investigation conducted under this Act .... shall forfeit to the United States an amount not exceeding $1 000 to be fixed by the
Commission after notice and opportunity for hearing .... "
FERC FORM NO.1 (ED. 12-91)Page iv
IDENTIFICATION
01 Exact Legal Name of Respondent 02 Year/Period of Report
Idaho Power Company End of 2005/04
03 Previous Name and Date of Change (if name changed during year)
Idaho Power Company
/ /
04 Address of Principal Office at End of Period (Street, City, State, Zip Code)
1221 W Idaho Street, P.O. Box 70 Boise, ID 83707-0070
05 Name of Contact Person 06 Title of Contact Person
Darrel Anderson Senior VP of Admin Ser & CFO
07 Address of Contact Person (Street, City, State, Zip Code)
1221 W Idaho Street, P.O. Box 70 Boise, ID 83707-0070
08 Telephone of Contact Person,lnc/uding 09 This Report Is 10 Date of Report
Area Code (1) !XI An Original (2) 0 A Resubmission (Mo , Yr)
[phone] 04/18/2006
ANNUAL CORPORATE OFFICER CERTIFICATION
The undersigned officer certifies that:
I have examined this report and to the best of my knowledge, information, and belief all statements of fact contained in this report are correct statements
of the business affairs of the respondent and the financial statements, and other financial information contained in this report, conform in all material
respects to the Uniform System of Accounts.
01 Name 03 Signature 04 Date Signed
Darrel Anderson (Mo , Yr)
02 Title
Senior VP of Admin Ser & CFO Darrel Anderson
/ /
Title 18, U.C. 1001 makes it a crime for any person to knowingly and willingly to make to any Agency or Department of the United States any
false, fictitious or fraudulent statements as to any matter within its jurisdiction.
FERC FORM NO. 1/3-
REPORT OF MAJOR ELECTRIC UTILITIES LICENSEES AND OTHER
FERC FORM No.1/3-Q (REV. 02-04)Page 1
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2005/04
(2)0 A Resubmission 04/18/2006
LIST OF SCHEDULES (Electric Utility)
Enter in column (c) the terms "none," "not applicable " or "" as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none
" "
not applicable," or "NA"
Line Title of Schedule Reference Remarks
No.Page No.
(a)(b)(c)
Generallnformation 101
Control Over Respondent 102
Corporations Controlled by Respondent 103
Officers 104
Directors 105
Important Changes During the Year 108-109
Comparative Balance Sheet 110-113
Statement of Income for the Year 114-117
Statement of Retained Eamings for the Year 118-119
Statement of Cash Flows 120-121
Notes to Financial Statements 122-123
Statement of Accum Comp Income, Comp Income, and Hedging Activities 122(a)(b)
Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep 200-201
Nuclear Fuel Materials 202-203 None
Electric Plant in Service 204-207
Electric Plant Leased to Others 213 None
Electric Plant Held for Future Use 214
Construction Work in Progress-Electric 216
Accumulated Provision for Depreciation of Electric Utility Plant 219
Investment of Subsidiary Companies 224-225
Materials and Supplies 227
Allowances 228-229 None
Extraordinary Property Losses 230
Unrecovered Plant and Regulatory Study Costs 230
Other Regulatory Assets 232
Miscellaneous Deferred Debits 233
Accumulated Deferred Income Taxes 234
Capital Stock 250-251
Other Paid-in Capital 253
Capital Stock Expense 254
Long-Term Debit 256-257
Reconciliation of Reported Net Income with Taxable Inc for Fed Inc Tax 261
Taxes Accrued, Prepaid and Charged During the Year 262-263
Accumulated Deferred Investment Tax Credits 266-267
Other Deferred Credits 269
Accumulated Deferred Income Taxes-Accelerated Amortization Property 272-273
FERC FORM NO.1 (ED. 12-96)Page 2
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2005/04
(2)0 A Resubmission 04/18/2006
LIST OF SCHEDULES (Electric Utility) (continued)
Enter in column (c) the terms "none,
" "
not applicable," or "" as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none,
" "
not applicable " or "NA"
Line Title of Schedule Reference Remarks
No,Page No.
(a)(b)(c)
Accumulated Deferred Income Taxes-Other Property 274-275
Accumulated Deferred Income Taxes-Other 276-277
Other Regulatory Liabilities 278
Electric Operating Revenues 300-301
Sales of Electricity by Rate Schedules 304
Sales for Resale 310-311
Electric Operation and Maintenance Expenses 320-323
Purchased Power 326-327
Transmission of Electricity for Others 328-330
Transmission of Electricity by Others 332
Miscellaneous General Expenses-Electric 335
Depreciation and Amortization of Electric Plant 336-337
Regulatory Commission Expenses 350-351
Research, Development and Demonstration Activities 352-353
Distribution of Salaries and Wages 354-355
Common Utility Plant and Expenses 356 None
Purchase and Sale of Ancillary Services 398 None
Monthly Transmission System Peak Load 400
Electric Energy Account 401
Monthly Peaks and Output 401
Steam Electric Generating Plant Statistics 402-403
Hydroelectric Generating Plant Statistics 406-407
Pumped Storage Generating Plant Statistics 408-409 None
Generating Plant Statistics Pages 410-411
Transmission Line Statistics Pages 422-423
Transmission Lines Added During the Year 424-425
. Substations 426-427
Footnote Data 450
Stockholders' Reports Check appropriate box:
Four copies will be submitted
No annual report to stockholders is prepared
FERC FORM NO.1 (ED. 12-96)Page 3
Name of Respondent
Idaho Power Company
This Report Is:
(1) 00 An Original(2) 0 A Resubmission
Date of Report
(Mo, Da, Yr)
04/18/2006
Year/Period of Report
End of 2005/04
GENERAL INFORMATION
1. Provide name and title of officer having custody of the general corporate books of account and address of
office where the general corporate books are kept, and address of office where any other corporate books of account
are kept, if different from that where the general corporate books are kept.
Darrel Anderson Senior Vice President of Administration and CFO, Idaho Power Company
1221 W. Idaho Street, P.O. Box 70, Boise, Idaho 83707-0070
2. Provide the name of the State under the laws of which respondent is incorporated, and date of incorporation.
If incorporated under a special law, give reference to such law. If not incorporated, state that fact and give the type
of organization and the date organized.
Idaho , June 30, 1989
3. If at any time during the year the property of respondent was held by a receiver or trustee, give (a) name of
receiver or trustee, (b) date such receiver or trustee took possession, (c) the authority by which the receivership or
trusteeship was created, and (d) date when possession by receiver or trustee ceased.
Not Applicable
4. State the classes or utility and other services furnished by respondent during the year in each State in which
the respondent operated.
state
Idaho
Oregon
Class of utility Service
Electric
5. Have you engaged as the principal accountant to audit your financial statements an accountant who is not
the principal accountant for your previous year s certified financial statements?
(1) 0 Yes...Enter the date when such independent accountant was initially engaged:
(2) IXI No
FERC FORM No.1 (ED. 12-87)PAGE 101
Name of Respondent
Idaho Power Company
This Report Is:
(1) 00 An Original(2) 0 A Resubmission
Date of Report
(Mo , Yr)
04/18/2006
Year/Period of Report
End of 2005/04
CONTROL OVER RESPONDENT
1. If any corporation, business trust, or similar organization or a combination of such organizations jointly held
control over the repondent at the end of the year, state name of controlling corporation or organization, manner in
which control was held, and extent of control. If control was in a holding company organization, show the chain
of ownership or control to the main parent company or organization. If control was held by a trustee(s), state
name of trustee(s), name of beneficiary or beneficiearies for whom trust was maintained , and purpose of the trust.
Idaho Power Company is a subsidiary of IDACORP, INC
IDACORP owns 100% of Idaho Power Company s Common Stock.
IDACORP is a public utility Holding Company incorporated effective 10-1998
FERC FORM NO.1 (ED. 12-96)Page 102
This Page Intentionally Left Blank
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2005/Q4
(2)0 A Resubmission 04/18/2006
CORPORATIONS CONTROLLED BY RESPONDENT
1. Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent
at any time during the year. If control ceased prior to end of year, give particulars (details) in a footnote.
2. If control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, naming
any intermediaries involved.
3. If control was held jointly with one or more other interests, state the fact in a footnote and name the other interests.
Definitions
1. See the Uniform System of Accounts for a definition of control.
2. Direct control is that which is exercised without interposition of an intermediary.
3. Indirect control is that which is exercised by the interposition of an intermediary which exercises direct control.
4. Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where the
voting control is equally divided between two holders, or each party holds a veto power over the other. Joint control may exist by
mutual agreement or understanding between two or more parties who together have control within the meaning of the definition of
control in the Uniform System of Accounts, regardless of the relative voting rights of each party.
Line Name of Company Controlled Kind of Business Percent Voting Footnote
No.Stock Owned Ref.
(a)(b)(c)(d)
Direct Control
Idaho Energy Resources Company Coal mining and mineral 100%
development
FERC FORM NO.1 (ED. 12-96)Page 103
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2005/04
(2)0 A Resubmission 04/18/2006
OFFICERS
Report below the name, title and salary for each executive officer whose salary is $50,000 or more.An "executive officer" of a
respondent includes its president, secretary, treasurer, and vice president in charge of a principal business unit, division or function
(such as sales, administration or finance), and any other person who performs similar policy making functions.
If a change was made during the year in the incumbent of any position, show name and total remuneration of the previous
incumbent, and the date the change in incumbency was made.
Line Title Name of Officer Salary
No.for Year
(a)(b)(c)
Jan B. Packwood 630,000
4 1I,'e
;;",~~:~',:'"' ~"
, 7 '~"n
::;
_~f~~f.~11!'i~~~j,\1;!'.":4 J. LaMont Keen 400,000
Sr Vice President,Power Supply James C. Miller 270,000
Sr Vice President, General Counsel and Secretary Thomas Saldin 250,000
Sr Vice President, Administrative Services & CFO Darrel T Anderson 240,000
Vice President and Chief Information Officer A. Bryan Kearny 193,000
Sr Vice President, Delivery Dan Minor 205,000
Vice President, Human Resources Luci McDonald 160,000
Vice President, Regulatory Affairs Ric Gale 175,000
Vice President, Public Affairs Greg Panter 160,000
Vice President and Treasurer Dennis Gribble 155,000
Vice President, Finance and Chief Risk Officer Lori Smith 155,000
Lisa Grow 135,000f---
~~J'lifij!_~~Jl!aj~~'j$J.'lj~?~~j~\~ffi~ii'8~~Bf&~1:11 Warren Kline 140,000
FERC FORM NO.1 (ED. 12-96)Page 104
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company I (2) A Resubmission 04/18/2006 2005/04
FOOTNOTE DATA
ISchedu/e Page: 104 Line No.Column:
Retired as Chief Executive Officer November 17 , 2005
'Schedule Page: 104 Line No.Column:
Appointed Chief Executive Officer November 17 , 2005.
Relinquished Chief Operating Officer November 17, 2005.
ISchedule Page: 104 Line No.26 Column:
Appointed to newly created position July 2005.
ISchedule Page: 104 Line No.28 Column:
Appointed to newly created position July 2005.
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report Is:Date of Report Year/Period of Report
Idaho Power Company (1) 0An Original (Mo, Da, Yr)End of 2005/04
(2)0 A Resubmission 04/18/2006
DIRECTORS
Report below the information called for concerning each director of the respondent who held office at any time during the year.Include in column (a), abbreviated
titles of the directors who are officers of the respondent.
Designate members of the Executive Committee by a triple asterisk and the Chairman of the Executive Committee by a double asterisk,
qne Name (and Title) of Director Principal Business AddressNo.(a)(b)
Rotchford L. Barker O. Box 2080, Cody Wyoming 82414
Jack K. Lemley Lemley & Associates, Inc.
1508 N.13th, Boise, Idaho 83702
Gary Michael ***O. Box 1718 Boise Idaho 83701
Jon H. Miller ***O. Box 1557, Boise, Idaho 83701
Peter S. O'Neill ***Neill Enterprises, Inc.
871 E. Parkcenter Blvd., Boise, Idaho 83706
~~"~f.~1,
~ -' ~;:'~ ~ ~,
Jt\t~~l'.-M!~!fJ,X~i/~~i)jf!f~ ~W~?~Jr. ~~~~~\'5l~~iJ~$Idaho Power Company,1221 W. Idaho Street,
O. Box 70, Boise, Idaho 83707-0070
ITitj~~ ~!i,-'~J.~!
~~~~~
1.tfEJ~~'!~~~1~ix1;~~ ~1J~;~ii#2 Idaho power Company,1221 W. Idaho Street,
O. Box 70, Boise, Idaho 83707-0070
Robert A. Tinstman ***4433 W. Ouail Point Court, Boise, Idaho, 83703
Richard G. Reiten NW Natural 220 NW 2nd Ave - 13th floor Portland, Oregon 97209
Thomas Wilford Alscott Inc, 501 Baybrook Court Boise, Idaho 83706
Joan Smith 2309 S.w. Avenue,No.1141 Portland,OR 97201
FERC FORM NO.1 (ED. 12-95)Page 105
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2006 2005/04
FOOTNOTE DATA
\Schedule Page: 105 Line No.13 Column:
Relinquished position as Chief Executive Officer November 17 , 2005
IScheduie Page: 105 Line No.16 Column:
Appointed Chief Executive Officer November 17 , 2005.
Relinquished Chief Operating Officer November 17 , 2005.
IFERC FORM NO.(ED. 12-87)Page 450.
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2005/Q4
This Report Is: Date of Report(1) ~ An Original(2) 0 A Resubmission 04/18/2006
IMPORTANT CHANGES DURING THE QUARTERNEAR
Give particulars (details) concerning the matters indicated below. Make the statements explicit and precise, and number them in
accordance with the inquiries. Each inquiry should be answered. Enter "none,
" "
not applicable " or "NA" where applicable. If
information which answers an inquiry is given elsewhere in the report, make a reference to the schedule in which it appears.
1. Changes in and important additions to franchise rights: Describe the actual consideration given therefore and state from whom the
franchise rights were acquired. If acquired without the payment of consideration , state that fact.
2. Acquisition of ownership in other companies by reorganization, merger, or consolidation with other companies: Give names of
companies involved, particulars concerning the transactions, name of the Commission authorizing the transaction, and reference to
Commission authorization.
3. Purchase or sale of an operating unit or system: Give a brief description of the property, and of the transactions relating thereto
and reference to Commission authorization, if any was required. Give date journal entries called for by the Uniform System of Accounts
were submitted to the Commission.
4. Important leaseholds (other than leaseholds for natural gas lands) that have been acquired or given, assigned or surrendered: Give
effective dates, lengths of terms, names of parties, rents, and other condition. State name of Commission authorizing lease and give
reference to such authorization.
5. Important extension or reduction of transmission or distribution system: State territory added or relinquished and date operations
began or ceased and give reference to Commission authorization, if any was required. State also the approximate number of
customers added or lost and approximate annual revenues of each class of service. Each natural gas company must also state major
new continuing sources of gas made available to it from purchases, development, purchase contract or otherwise, giving location and
approximate total gas volumes available, period of contracts, and other parties to any such arrangements, etc.
6. Obligations incurred as a result of issuance of securities or assumption of liabilities or guarantees including issuance of short-term
debt and commercial paper having a maturity of one year or less. Give reference to FERC or State Commission authorization, as
appropriate, and the amount of obligation or guarantee.
7. Changes in articles of incorporation or amendments to charter: Explain the nature and purpose of such changes or amendments.
8. State the estimated annual effect and nature of any important wage scale changes during the year.
9. State briefly the status of any materially important legal proceedings pending at the end of the year, and the results of any such
proceedings culminated during the year.
10. Describe briefly any materially important transactions of the respondent not disclosed elsewhere in this report in which an officer,
director, security holder reported on Page 106, voting trustee, associated company or known associate of any of these persons was a
party or in which any such person had a material interest.
11. (Reserved.
12. If the important changes during the year relating to the respondent company appearing in the annual report to stockholders are
applicable in every respect and furnish the data required by Instructions 1 to 11 above, such notes may be included on this page.
13. Describe fully any changes in officers, directors, major security holders and voting powers of the respondent that may have
occurred during the reporting period.
14. In the event that the respondent participates in a cash management program(s) and its proprietary capital ratio is less than 30
percent please describe the significant events or transactions causing the proprietary capital ratio to be less than 30 percent, and the
extent to which the respondent has amounts loaned or money advanced to its parent, subsidiary, or affiliated companies through a
cash management program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio.
PAGE 108 INTENTIONALLY LEFT BLANK
SEE PAGE 109 FOR REQUIRED INFORMATION.
FERC FORM NO.1 (ED. 12-96)Page 108
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2006 2005/04
IMPORTANT CHANGES DURING THE OUARTERNEAR (Continued)
1. Re1icensing costs closed to account 302 - $3,254,971 for Mid-Snake Power Plant-Idaho.
2. None
3. None
4. None
5. New Transmission Lines:
Eagle - Star 138 Kv line #464 6.35 miles
Eckert - 138 Kv tap line #412
Bennett Mtn Power Plant to rattlesnake sub #716 4.48 miles
1 Transmission3 Distribution
Ten Mile
Lake ForkRattlesnake
station - Horse Flat transmission stationstations:
6. Issued $60 million of 5.30% First Mortgage Bonds maturing 8/26/35. Commission
authorization for IPUC IPC-E-04-22 OPUC UF-4211, and WPSC 2005-ES-04-27.
7. None
8. On December 29, 2005 a general wage increase of 3.0%.
9. See pages 123.9 to 123.
10. None
11. None
12. None
13. Refer to pages 104 & 105 for changes in officers and directors. There were a number of
changes in Major Security Holders in 2005. Top ten institutional shareholders list saw the
addition of Lord, Abbett & Company, Prenza Investment Management, NWQ Investment
Management and ICM Asset Management. Leaving the top ten list of institutional
shareholders was Martingale Asset Management, TIAA-CREF Investestment, Smith Barney Asset
Management and Bear Stearns & Company.
14. None
I FERC FORM NO.1 (ED. 12-Page 109.
Name of Respondent This Report Is:Date of Report Year/Period of Report
Idaho Power Company (1)An Original (Mo, Da, Yr)
(2)A Resubmission 04/18/2006 End of 2005/04
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line Current Year Prior Year
No.Ref.End of OuarterlYear End Balance
Title of Account Page No.Balance 12/31
(a)(b)(c)(d)
UTILITY PLANT
Utility Plant (101-106, 114)200-201 3,479,972,995 327,451,494
Construction Work in Progress (107)200-201 149,814 313 151 651 719
TOTAL Utility Plant (Enter Total of lines 2 and 3)629,787 308 3,479 103,213
(Less) Accum. Provo for Depr. Amort. Depl. (108, 110, 111, 115)200-201 364 640,116 316 124,554
Net Utility Plant (Enter Total of line 4 less 5)265,147,192 162,978,659
Nuclear Fuel in Process of Ref., Conv.,Enrich., and Fab. (120.202-203
Nuclear Fuel Materials and Assemblies-Stock Account (120.
Nuclear Fuel Assemblies in Reactor (120.
Spent Nuclear Fuel (120.
Nuclear Fuel Under Capital Leases (120.
(Less) Accum. Provo for Amort. of Nucl. Fuel Assemblies (120.202-203
Net Nuclear Fuel (Enter Total of lines 7-11 less 12)
Net Utility Plant (Enter Total of lines 6 and 13)265 147 192 162,978,659
Utility Plant Adjustments (116)122
Gas Stored Underground - Noncurrent (117)
OTHER PROPERTY AND INVESTMENTS
Nonutility Property (121)922 349 828,002
(Less) Accum. Provo for Depr. and Amort. (122)
Investments in Associated Companies (123)
Investment in Subsidiary Companies (123.224-225 43,512,409 36,544,480
(For Cost of Account 123., See Footnote Page 224, line 42)
Noncurrent Portion of Allowances 228-229
Other Investments (124)025,159 32,458 340
Sinking Funds (125)
Depreciation Fund (126)
Amortization Fund - Federal (127)
Other Special Funds (128)337 666 507,094
Special Funds (Non Major Only) (129)
Long-Term Portion of Derivative Assets (175)
Long-Term Portion of Derivative Assets - Hedges (176)
TOTAL Other Property and Investments (Lines 18-21 and 23-31)72,797,583 97,337,916
CURRENT AND ACCRUED ASSETS
Cash and Working Funds (Non-major Only) (130)
Cash (131)583,874 359,186
Special Deposits (132-134)510,000
Working Fund (135)750 57,457
Temporary Cash Investments (136)48,687 442 236,000
Notes Receivable (141)10,522,187 863,100
Customer Accounts Receivable (142)49,830,007 45,440,589
Other Accounts Receivable (143)860,636 201,303
(Less) Accum. Provo for Uncollectible Acct.-Credit (144)833,238 363,426
Notes Receivable from Associated Companies (145)
Accounts Receivable from Assoc. Companies (146)637,084 297 952
Fuel Stock (151)227 11,494,190 6,450,733
Fuel Stock Expenses Undistributed (152)227
Residuals (Elec) and Extracted Products (153)227
Plant Materials and Operating Supplies (154)227 28,705,792 25,378,777
Merchandise (155)227
Other Materials and Supplies (156)227
Nuclear Materials Held for Sale (157)202-203/227
Allowances (158.1 and 158.228-229
FERC FORM NO.1 (REV. 12-03) Page 110
Name of Respondent This Report Is:Date of Report Year/Period of Report
Idaho Power Company (1)An Original (Mo , Yr)
(2)A Resubmission 04/18/2006 End of 2005/04
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)Continued)
Line Current Year Prior Year
No.Ref.End of OuarterlYear End Balance
Title of Account Page No.Balance 12/31
(a)(b)(c)(d)
(Less) Noncurrent Portion of Allowances
Stores Expense Undistributed (163)227 745,428 685,830
Gas Stored Underground - Current (164.
Liquefied Natural Gas Stored and Held for Processing (164.164.
Prepayments (165)17,532,437 28,448,966
Advances for Gas (166-167)
Interest and Dividends Receivable (171)28,192 52,040
Rents Receivable (172)
Accrued Utility Revenues (173)38,905,298 33,832,290
Miscellaneous Current and Accrued Assets (174)
Derivative Instrument Assets (175)244,432 87,506
(Less) Long-Term Portion of Derivative Instrument Assets (175)
Derivative Instrument Assets - Hedges (176)
(Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176
Total Current and Accrued Assets (Lines 34 through 66)215,496,511 175,028,303
DEFERRED DEBITS
Unamortized Debt Expenses (181)128,248 741 547
Extraordinary Property Losses (182.230
Unrecovered Plant and Regulatory Study Costs (182.230
Other Regulatory Assets (182.232 418,241 190 438,780,828
Prelim. Survey and Investigation Charges (Electric) (183)187,483 953
Preliminary Natural Gas Survey and Investigation Charges 183.
Other Preliminary Survey and Investigation Charges (183.
Clearing Accounts (184)300.821 12,057
Temporary Facilities (185)
Miscellaneous Deferred Debits (186)233 82,087,452 272,850
Def. Losses from Disposition of Utility PIt. (187)
Research, Devel. and Demonstration Expend. (188)352-353
Unamortized Loss on Reaquired Debt (189)032 339 15,193,036
Accumulated Deferred Income Taxes (190)234 103,660,136 72,712 115
Unrecovered Purchased Gas Costs (191)
Total Deferred Debits (lines 69 through 83)629,637,669 617 804 386
TOTAL ASSETS (lines 14-16, 32, 67, and 84)183.078,955 053,149,264
FERC FORM NO.1 (REV. 12-03)Page 111
Name of Respondent This Report is:Date of Report Year/Period of Report
Idaho Power Company (1)An Original (mo, , yr)
(2)A Rresubmission 04/18/2006 end of 2005104
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
Line
Current Year Prior Year
No.
Ref.End of OuarterlYear End Balance
Title of Account Page No.Balance 12/31
(a)(b)(c)(d)
PROPRIETARY CAPITAL
Common Stock Issued (201)250-251 877,030 97,877,030
Preferred Stock Issued (204)250-251
Capital Stock Subscribed (202, 205)252
Stock Liability for Conversion (203, 206)252
Premium on Capital Stock (207)252 483 707,552 483,707,552
Other Paid-In Capital (208-211)253
Installments Received on Capital Stock (212)252
(Less) Discount on Capital Stock (213)254
(Less) Capital Stock Expense (214)254 096,925 096,925
Retained Earnings (215, 215.1, 216)118-119 321,453,283 309,178,039
Unappropriated Undistributed Subsidiary Earnings (216.118-119 39,802,850 30,928 808
(Less) Reaquired Capital Stock (217)250-251
Noncorporate Proprietorship (Non-major only) (218)
Accumulated Other Comprehensive Income (219)122(a)(b)3,425,32~887 774
Total Proprietary Capital (lines 2 through 15)937 318,466 918,706,730
LONG-TERM DEBT
Bonds (221)256-257 955,460,000 955,460,000
(Less) Reaquired Bonds (222)256-257
Advances from Associated Companies (223)256-257
Other Long-Term Debt (224)256-257 585,000 31,585,000
Unamortized Premium on Long-Term Debt (225)
(Less) Unamortized Discount on Long-Term Debt-Debit (226)325,109 135,446
Total Long-Term Debt (lines 18 through 23)983 719,891 983,909,554
OTHER NONCURRENT LIABILITIES
Obligations Under Capital Leases - Noncurrent (227)
Accumulated Provision for Property Insurance (228.
Accumulated Provision for Injuries and Damages (228.191,411 797,494
Accumulated Provision for Pensions and Benefits (228.361 444 10,592,032
Accumulated Miscellaneous Operating Provisions (228.4)
Accumulated Provision for Rate Refunds (229)400,102
Long-Term Portion of Derivative Instrument Liabilities
Long-Term Portion of Derivative Instrument Liabilities - Hedges
Asset Retirement Obligations (230)10,079,335 287,789
Total Other Noncurrent Liabilities (lines 26 through 34)24,632,190 077,417
CURRENT AND ACCRUED LIABILITIES
Notes Payable (231)
Accounts Payable (232)77,435,649 72,530,597
Notes Payable to Associated Companies (233)101,115 20,469 707
Accounts Payable to Associated Companies (234)152,888 278,488
Customer Deposits (235)103 299 000,352
Taxes Accrued (236)262-263 72,183,706 280,158
Interest Accrued (237)104,406 13,742 553
Dividends Declared (238)
Matured Long-Term Debt (239)
FERC FORM NO.1 (rev. 12-03)Page 112
Name of Respondent This Report is:Date of Report Year/Period of Report
Idaho Power Company (1)(XI An Original (mo , yr)
(2)A Rresubmission 04/18/2006 end of 2005/04
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDIT~ntinued)
Line Current Year Prior Year
No,Ref.End of Ouarter/Year End Balance
Title of Account Page No,Balance 12/31
(a)(b)(c)(d)
Matured Interest (240)
Tax Collections Payable (241)997,689 111 305
Miscellaneous Current and Accrued Liabilities (242)834,534 17,015,196
Obligations Under Capital Leases-Current (243)
Derivative Instrument Liabilities (244)445
(Less) Long-Term Portion of Derivative Instrument Liabilities
Derivative Instrument Liabilities - Hedges (245)
(Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges
Total Current and Accrued Liabilities (lines 37 through 53)194 913 286 167,428,801
DEFERRED CREDITS
Customer Advances for Construction (252)19,427 988 15,073,749
Accumulated Deferred Investment Tax Credits (255)266-267 68,786,273 66,836,157
Deferred Gains from Disposition of Utility Plant (256)
Other Deferred Credits (253)269 672,479 257 710
Other Regulatory Liabilities (254)278 276 567 305 209 105,349
Unamortized Gain on Reaquired Debt (257)
Accum. Deferred Income Taxes-Accel. Amort.(281)272-277
Accum. Deferred Income Taxes-Other Property (282)586,260,338 585 543 346
Accum. Deferred Income Taxes-Other (283)23,780,739 210,451
Total Deferred Credits (lines 56 through 64)042,495,122 961,026 762
TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65)183,078,955 053 149 264
FERC FORM NO.1 (rev. 12-03)Page 113
Name of Respondent This Report Is:Date of Report Year/Period of Report
Idaho Power Company (1) ~An Original (Mo, Da, Yr)End of 2005/Q4
(2)D A Resubmission 04/18/2006
STATEMENT OF INCOME
Quarterly
1. Enter in column (d) the balance for the reporting quarter and in column (e) the balance for the same three month period for the prior year.
2. Report in column (f) the quarter to date amounts for electric utility function; in column (h) the quarter to date amounts for gas utility, and in G) the
quarter to date amounts for other utility function for the current year quarter.
3. Report in column (g) the quarter to date amounts for electric utility function; in column (i) the quarter to date amounts for gas utility, and in (k) the
quarter to date amounts for other utility function for the prior year quarter.
4. If additional columns are needed place them in a footnote.
Annual or Quarterly if applicable
5. Do not report fourth quarter data in columns (e) and (f)
6. Report amounts for accounts 412 and 413, Revenues and Expenses from Utility Plant Leased to Others, in another utility columnin a similar manner to
a utility department. Spread the amount(s) over lines 2 thru 26 as appropriate. Include these amounts in columns (c) and (d) totals.
7. Report amounts in account 414, Other Utility Operating Income, in the same manner as accounts 412 and 413 above.
8. Report data for lines 8, 10 and 11 for Natural Gas companies using accounts 404., 404., 404., 407.1 and 407.
Line Total Total Current 3 Months Prior 3 Months
No.Current Year to Prior Year to Ended Ended
(Ref.)Date Balance for Date Balance for Quarterly Only Quarterly Only
Title of Account Page No.Quarter/Year Quarter/Year No 4th Quarter No 4th Quarter
(a)(b)(c)(d)(e)
1 UTILITY OPERATING INCOME
2 Operating Revenues (400)300-301 849,075,951 800,822,106
3 Operating Expenses
4 Operation Expenses (401)320-323 505,272,123 523,328,322
5 Maintenance Expenses (402)320-323 59,538,848 58,404,718
Depreciation Expense (403)336-337 933 330 90,986,890
Depreciation Expense for Asset Retirement Costs (403,336-337
8 Amort. & Depl. of Utility Plant (404-405)336-337 574 137 10,050,731
9 Amort, of Utility Plant Acq, Adj. (406)336-337 723 22,723
Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407)
Amort. of Conversion Expenses (407)
Regulatory Debits (407.3)16,191,442 19,944
(Less) Regulatory Credits (407.4)820,743 18,949,682
Taxes Other Than Income Taxes (408.262-263 20,856,185 19,090,214
Income Taxes - Federal (409,262-263 64,853,588 16,305,814
Other(409.262-263 931,316 273,792
Provision for Deferred Income Taxes (410.234, 272-277 279 913 28,170,120
(Less) Provision for Deferred Income Taxes-Cr. (411,234, 272-277 58,648,054 45,142,816
Investment Tax Credit Adj, - Net (411,266 950,116 952,821
(Less) Gains from Disp. of Utility Plant (411,
Losses from Disp, of Utility Plant (411.7)591 071
(Less) Gains from Disposition of Allowances (411.173,359 158,330
Losses from Disposition of Allowances (411.
Accretion Expense (411,10)
TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24)738,716,710 688,402 102
Net Uti! Oper Inc (Enter Totline 2 less 25) Carry to Pg117,line 27 110,359 241 112,420,004
FERC FORM NO. 1/3.Q (REV. 02-04)Page 114
Name of Respondent This Report Is:Date of Report Year/Period of Report
Idaho Power Company (1) ~An Original (Mo, Da, Yr)End of 2005/04
(2)D A Resubmission 04/18/2006
STATEMENT OF INCOME FOR THE YEAR (Continued)
9. Use page 122 for important notes regarding the statement of income for any account thereof.
10. Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a material amount may need to be
made to the utility's customers or which may result in material refund to the utility with respect to power or gas purchases. State for each year effected
the gross revenues or costs to which the contingency relates and the tax effects together with an explanation of the major factors which affect the rights
of the utility to retain such revenues or recover amounts paid with respect to power or gas purchases.
11 Give concise explanations concerning significant amounts of any refunds made or received during the year resulting from settlement of any rate
proceeding affecting revenues received or costs incurred for power or gas purches, and a summary of the adjustments made to balance sheet, income,
and expense accounts.
12. If any notes appearing in the report to stokholders are applicable to the Statement of Income, such notes may be included at page 122.
13. Enter on page 122 a concise explanation of only those changes in accounting methods made during the year which had an effect on net income,
including the basis of allocations and apportionments from those used in the preceding year. Also, give the appropriate dollar effect of such changes.
14. Explain in a footnote if the previous years/quarter s figures are different from that reported in prior reports.
15. If the columns are insufficient for reporting additional utility departments, supply the appropriate account titles report the information in a footnote to
this schedule.
ELECTRIC UTILITY GAS UTILITY OTHER UTILITY
Current Year to Date Previous Year to Date Current Year to Date Previous Year to Date Current Year to Date Previous Year to Date Line
(in dollars)(in dollars)(in dollars)(in dollars)(in dollars)(in dollars)No.
(g)
(h) (i) 0) (k) (I)
505,272,123 523 328 322
538 848 58,404,718
933 330 90,986,890
574 137 050 731
22,723 22,723
191,442 19,944
820,743 18,949,682
856,185 090,214
853 588 16,305,814
931 316 273,792
24,279,913 28,170,120
58,648,054 45,142 816
950,116 952,821
591 071
173,359 158,330
738 716 710 688,402 102
110 359,241 112,420,004
FERC FORM NO.1 (ED. 12-96)Page 115
This Page Intentionally Left Blank
Name of Respondent
Idaho Power Company
This Report Is: Date of Report
(1) 0 An Original (Mo, Da, Yr)
(2) D A Resubmission 04/18/2006
STATEMENT OF INCOME FOR THE YEAR (continued)
TOTALLine
No,
Title of Account
(a)
(Ref,
Page No,
(b)
Current Year
(c)
Previous Year
(d)
Year/Period of Report
End of 2005/Q4
Current 3 Months
Ended
Quarterly Only
No 4th Quarter
(e)
Prior 3 Months
Ended
Quarterly Only
No 4th Quarter
(I)
27 Net Utility Operating Income (Carried folWard from page 114)
28 Other Income and Deductions
29 Other Income
30 Nonutilty Operating Income
31 Revenues From Merchandising, Jobbing and Contract Work (415)
32 (Less) Costs and Exp, of Merchandising, Job. & Contract Work (416)
33 Revenues From Nonutility Operations (417)
34 (Less) Expenses of Nonutility Operations (417,
35 Nonoperating Rental Income (418)
36 Equity in Earnings of Subsidiary Companies (418,
37 Interest and Dividend Income (419)
38 Allowance for Other Funds Used During Construction (419,
39 Miscellaneous Nonoperating Income (421)
40 Gain on Disposition of Property (421.
41 TOTAL Other Income (Enter Total of lines 31 thru 40)
42 Other Income Deductions
43 Loss on Disposition of Property (421.
44 Miscellaneous Amortization (425)
45 Donations (426.
46 Lffe Insurance (426,
47 Penalties (426,
48 Exp, for Certain Civic, Political & Related Activities (426,
49 Other Deductions (426,
50 TOTAL Other Income Deductions (Total of lines 43 thru 49)
51 Taxes Applic, to Other Income and Deductions
52 Taxes Other Than Income Taxes (408.
53 Income Taxes-Federal (409.
54 Income Taxes-Other (409.
55 Provision for Deferred Inc. Taxes (410,
56 (Less) Provision for Deferred Income Taxes-Cr. (411.2)
57 Invesb11ent Tax Credit Adj,Net (411,
58 (Less) Invesb11ent Tax Credits (420)
59 TOTAL Taxes on Other Income and Deductions (Total oflines 52-58)
60 Net Other Income and Deductions (Total of lines 41, 50, 59)
61 Interest Charges
62 Interest on Long-Term Debt (427)
63 Amort. of Debt Disc, and Expense (428)
64 Amortization of Loss on Reaquired Debt (428,
65 (Less) Amort, of Premium on Debt-Credit (429)
66 (Less) Amortization of Gain on Reaquired Debt-Credit (429,1)
67 Interest on Debt to Assoc, Companies (430)
68 Other Interest Expense (431)
69 (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432)
70 Net Interest Charges (Total of lines 62 thru 69)
71 Income Before Extraordinary Items (Total of lines 27, 60 and 70)
72 Extraordinary Items
73 Extraordinary Income (434)
74 (Less) Extraordinary Deductions (435)
75 Net Extraordinary Items (Total of line 73 less line 74)
76 Income Taxes-Federal and Other (409,
77 Extraordinary Items After Taxes (line 75 less line 76)
78 Net Income (Total of line 71 and 77)
110,359,241 112,420,004
---
119
986 557
553 933
125 826
285 293
036
874 042
192 922
950,151
069,732
521
22,386,489
3.427,754
388 329
110 035
279 748
136
190,247
412 553
904,027
624756
469,258
20,468,417
~---
106,328 207
340
340 533,964 538,360
508 671 031
351 382 550,041
637,585 923 708
724 767 348 285
262-263
262-263
262-263
234 272-277
234, 272-277
262-263
~---
228
042 859
244 977
213 137
817 329
720 872
940,850
38,712
144 957
43,666
586,407
5,482,592
668 850
788 982
~---
339 531
262 733
160 697
340
340
386,020
103 151
790,871
54,461 261
838,830
50,317 585
188 137
192 994
256,468
598,490
952,809
600,865
70,608,121
70,608,121
~---
Page 117
838 830
FERC FORM NO. 1I3-Q (REV. 02-04)
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2005/Q4
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) 0 A Resubmission 04/18/2006
STATEMENT OF RETAINED EARNINGS
1. Do not report Lines 49-53 on the quarterly version.
2. Report all changes in appropriated retained eamings, unappropriated retained eamings, year to date, and unappropriated
undistributed subsidiary earnings for the year.
3. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436
- 439 inclusive). Show the contra primary account affected in column (b)
4. State the purpose and amount of each reservation or appropriation of retained earnings.
5. List first account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow
by credit, then debit items in that order.
6. Show dividends for each class and series of capital stock.
7. Show separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Earnings.
8. Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be
recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated.
9. If any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.
Line
No.
Item
(a)
UNAPPROPRIATED RETAINED EARNINGS (Account 216)
1 Balance-Beginning of Period
2 Changes
3 Adjustments to Retained Earnings (Account 439)
9 TOTAL Credits to Retained Earnings (Acct. 439)
15 TOTAL Debits to Retained Earnings (Acct. 439)
16 Balance Transferred from Income (Account 433 less Account 418.
17 Appropriations of Retained Earnings (Acct. 436)
22 TOTAL Appropriations of Retained Earnings (Acct. 436)
23 Dividends Declared-Preferred Stock (Account 437)
29 TOTAL Dividends Declared-Preferred Stock (Acct. 437)
30 Dividends Declared-Common Stock (Account 438)
31 $2.50 Par Value
36 TOTAL Dividends Declared-Common Stock (Acct. 438)
37 Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings
38 Balance - End of Period (Total 1,15,16,22,36,37)
Current Previous
QuarterlY ear QuarterlY ear
Contra Primary Year to Date Year to Date
Account Affected Balance Balance
(b)(c)(d)
62,964 788 62.417 874
934 959)
934,959)
50,689,544 46.413.448)
50,689,544 46.413.448)
319,909,317 309,522,362
FERC FORM NO. 1/3-Q (REV. 02-04)Page 118
Name of Respondent
Idaho Power Company
YearlPeriod of Report
End of 20051Q4
This Report Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) DA Resubmission 0411812006
STATEMENT OF RETAINED EARNINGS
1. Do not report Lines 49-53 on the quarterly version.
2. Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriated
undistributed subsidiary earnings for the year.
3. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436
- 439 inclusive). Show the contra primary account affected in column (b)
4. State the purpose and amount of each reservation or appropriation of retained earnings.
5. List first account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow
by credit, then debit items in that order.
6. Show dividends for each class and series of capital stock.
7. Show separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Earnings.
8. Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be
recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated.
9. If any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.
Line
No.
Item
(a)
APPROPRIATED RETAINED EARNINGS (Account 215)
45 TOTAL Appropriated Retained Earnings (Account 215)
APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.
46 TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 215.
47 TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46)
48 TOTAL Retained Earnings (Acct. 215, 215.1, 216) (Total 38, 47) (216.
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account
Report only on an Annual Basis, no Quarterly
49 Balance-Beginning of Year (Debit or Credit)
50 Equity in Earnings for Year (Credit) (Account 418.
51 (Less) Dividends Received (Debit)
53 Balance-End of Year (Total lines 49 thru 52)
Current Previous
QuarterN ear QuarterNear
Contra Primary Year to Date Year to Date
Account Affected Balance Balance
(b)(c)(d)r---~
543,966
543,966
321,453,283
543,966
543,966
311 066,328r---~r---
30,928,808
874 042
738,561
190,247
39,802 850 30,928,808
FERC FORM NO. 1/3-Q (REV. 02-04)Page 119
Name of Respondent
Idaho Power Company
This ~ort Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)(2) DA Resubmission 04/18/2006
STATEMENT OF CASH FLOWS
Year/Period of Report
End of 2005/Q4
(1) Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items as
investments, fixed assets, intangibles, etc.
(2) Information about noncash investing and financing activities must be provided in the Notes to the Financial statements, Also provide a reconciliation between "Cash and Cash
Equivalents at End of Period" with related amounts on the Balance Sheet.
(3) Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing activities should be reported
in those activities, Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid,
(4) Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies, Provide a reconciliation of assets acquired with liabilities assumed in the Notes to
the Financial Statements, Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconciliation of the
dollar amount of leases capitalized with the plant cost.
Line
No.
Description (See Instruction No.1 for Explanation of Codes)Current Year to Date
QuarterlY ear
(b)
Previous Year to Date
QuarterlY ear
(c)(a)
1 Net Cash Flow from Operating Activities:
2 Net Income (Line 78(c) on page 117)
3 Noncash Charges (Credits) to Income:
4 Depreciation and Depletion
5 Amortization of (see note)
8 Deferred Income Taxes (Net)
9 Investment Tax Credit Adjustment (Net)
10 Net (Increase) Decrease in Receivables
11 Net (Increase) Decrease in Inventory
12 Net (Increase) Decrease in Allowances Inventory
13 Net Increase (Decrease) in Payables and Accrued Expenses
14 Net (Increase) Decrease in Other Regulatory Assets
15 Net Increase (Decrease) in Other Regulatory Liabilities
16 (Less) Allowance for Other Funds Used During Construction
17 (Less) Undistributed Earnings from Subsidiary Companies
18 Other (provide details in footnote):
22 Net Cash Provided by (Used in) Operating Activities (Total 2 thru 21)
24 Cash Flows from Investment Activities:
25 Construction and Acquisition of Plant (including land):
26 Gross Additions to Utility Plant (less nuclear fuel)
27 Gross Additions to Nuclear Fuel
28 Gross Additions to Common Utility Plant
29 Gross Additions to Nonutility Plant
30 (Less) Allowance for Other Funds Used During Construction
31 Other: Sale of Emission Allowance
~\'S'iijf,$hli~~'ii t~t~_l~1i
972 335
950,117
885,165
9,430,070
373,450
952,821
049,547
587 583
355,903
112 357
837 689
950,151
874 042
699,394
122,666
334 354
904 027
127 301
15,690,324~~~~~4t~i,1~;~f;'~?tf-l h~-i:1f~J.~~t;
176,665 211 186 342,542
183,073,929 187 333,369
200,675
790,871
70,757,625
952,809
34 Cash Outflows for Plant (Total of lines 26 thru 33)
36 Acquisition of Other Noncurrent Assets (d)
37 Proceeds from Disposal of Noncurrent Assets (d)
39 Investments in and Advances to Assoc. and Subsidiary Companies
40 Contributions and Advances from Assoc. and Subsidiary Companies
41 Disposition of Investments in (and Advances to)
42 Associated and Subsidiary Companies
115,307 850 190,286,178
~- ------~- -
-- r
--'----
831
r'-
44 Purchase of Investment Securities (a)
45 Proceeds from Sales of Investment Securities (a)
333,932
120,025 599
295,355,514
266,331 185
FERC FORM NO.1 (ED. 12-96)Page 120
Name of Respondent
Idaho Power Company
This Report Is: Date of Report(1) 0 An Original (Mo, Da, Yr)
(2) DA Resubmission 04/18/2006
STATEMENT OF CASH FLOWS
Year/Period of Report
End of 2005/Q4
(1) Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items as
investments, fixed assets, intangibles, etc,
(2) Information about noncash investing and financing activities must be provided in the Notes to the Financial statements, Also provide a reconciliation between "Cash and Cash
Equivalents at End of Period" with related amounts on the Balance Sheet.
(3) Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing activities should be reported
in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid,
(4) Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes to
the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconciliation of the
dollar amount of leases capitalized with the plant cost.
(a)
Current Year to Date
QuarterlY ear
(b)
Previous Year to Date
QuarterlY ear
(c)
Line
No.
Description (See Instruction No.1 for Explanation of Codes)
56 Net Cash Provided by (Used in) Investing Activities
57 Total of lines 34 thru 55)
59 Cash Flows from Financing Activities:
60 Proceeds from Issuance of:
61 Long-Term Debt (b)
62 Preferred Stock
63 Common Stock
64 Other (provide details in footnote):
70 Cash Provided by Outside Sources (Total 61 thru 69)
72 Payments for Retirement of:
73 Long-term Debt (b)
74 Preferred Stock
75 Common Stock
76 Other (provide details in footnote): Other long-term assets
78 Net Decrease in Short-Term Debt (c)
80 Dividends on Preferred Stock
81 Dividends on Common Stock
82 Net Cash Provided by (Used in) Financing Activities
83 (Total of lines 70 thru 81)
85 Net Increase (Decrease) in Cash and Cash Equivalents
86 (Total of lines 22,57 and 83)
Loans Made or Purchased
Collections on Loans
Net (Increase) Decrease in Receivables
Net (Increase) Decrease in Inventory
Net (Increase) Decrease in Allowances Held for Speculation
Net Increase (Decrease) in Payables and Accrued Expenses
Other (provide details in footnote):
116,424 39,409
60,000,000 105,000,000
Net Increase in Short-Term Debt (c)
Other (provide details in footnote):
11,448,683
85,920,000
60,000,000 202 368,683
r p
- -
60,000,000 50,000 000
350,828
4,445,891 119,881
10,368,593
50,689,545
823,248
46,413,448
88 Cash and Cash Equivalents at Beginning of Period
90 Cash and Cash Equivalents at End of period
FERC FORM NO.1 (ED. 12-96)Page 121
This Page Intentionally Left Blank
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2006 2005/04
FOOTNOTE DATA
ISchedu/e Page: 120
Amortization
Line No.Column: b
12 Months Ended
12/31/2005
Plant
Regulatory Assets
Unamortized Debt Expense
Unamortized Discount
Other
551,414
314 589
309 764
(189 663)
986 104
ISchedule Page: 120 Line No.18 Column: b
Cash Flow from Operating Activites 12 Months Ended(Other) 12/31/2005
Unbilled Revenues
Other Current Liabilities
Other long-term Assets
Other long-term Liabilities
Gain on Sale of Assets
Loss on sale of non-utility assets
073 008)
269,138
(697 657)
841 225
(778 334 )
106 328
667 692
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent
Idaho Power Company
Date of Report
04/18/2006
YearlPeriod of Report
End of 2005/Q4
This Report Is:(1) ~ An Original(2) 0 A Resubmission
NOTES TO FINANCIAL STATEMENTS
1. Use the space below for important notes regarding the Balance Sheet, Statement of Income for the year, Statement of Retained
Earnings for the year, and Statement of Cash Flows, or any account thereof. Classify the notes according to each basic statement,
providing a subheading for each statement except where a note is applicable to more than one statement.
2. Furnish particulars (details) as to any significant contingent assets or liabilities existing at end of year, including a brief explanation of
any action initiated by the Internal Revenue Service involving possible assessment of additional income taxes of material amount, or of
a claim for refund of income taxes of a material amount initiated by the utility. Give also a brief explanation of any dividends in arrears
on cumulative preferred stock.
3. For Account 116, Utility Plant Adjustments, explain the origin of such amount, debits and credits during the year, and plan of
disposition contemplated, giving references to Cormmission orders or other authorizations respecting classification of amounts as plant
adjustments and requirements as to disposition thereof.
4. Where Accounts 189, Unamortized Loss on Reacquired Debt, and 257, Unamortized Gain on Reacquired Debt, are not used, give
an explanation , providing the rate treatment given these items. See General Instruction 17 of the Uniform System of Accounts.
5. Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such
restrictions.
6. If the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders are
applicable and furnish the data required by instructions above and on pages 114-121 , such notes may be included herein.
7. For the 3Q disclosures, respondent must provide in the notes sufficient disclosures so as to make the interim information not
misleading. Disclosures which would substantially duplicate the disclosures contained in the most recent FERC Annual Report may be
omitted.
8. For the 3Q disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurred
which have a material effect on the respondent. Respondent must include in the notes significant changes since the most recently
completed year in such items as: accounting principles and practices; estimates inherent in the preparation of the financial statements;
status of long-term contracts; capitalization including significant new borrowings or modifications of existing financing agreements; and
changes resulting from business combinations or dispositions. However were material contingencies exist, the disclosure of such
matters shall be provided even though a significant change since year end may not have occurred.
9. Finally, if the notes to the financial statements relating to the respondent appearing in the annual report to the stockholders are
applicable and furnish the data required by the above instructions, such notes may be included herein.
PAGE 122,1NTENTIONALL Y LEFT BLANK
SEE PAGE 123 FOR REQUIRED INFORMATION.
FERC FORM NO.1 (ED. 12-96)Page 122
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2006 2005/04
NOTES TO FINANCIAL STATEMENTS (Continued)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Nature of Business
Idaho Power Company (IPC) a wholly-owned subsidiary of IDACORP, is an electric utility with a service territory covering approximately
000 square miles in southern Idaho and eastern Oregon. IPC is regulated by the Federal Energy Regulatory Commission (FERC) and
the State regulatory commissions ofIdaho and Oregon. IPC is the parent ofIdaho Energy Resources Co. (IERCO), a joint venturer in
Bridger Coal Company, which supplies coal to the Jim Bridger generating plant owned in part by IPc. IERCO is not consolidated for
FERC Form-1 reporting purposes. IDACOl\:D\f a wholly-owned subsidiary of IDACORP is a provider of telecommunications services and
commercial Internet services.
Basis of Presentation
These financial statements were prepared in accordance with the accounting requirements of FERC as set forth in its applicable Uniform
System of Accounts and published accounting releases, which is a comprehensive basis of accounting other than generally accepted
accounting principles.
Management Estimates
Management makes estimates and assumptions when preparing financial statements in conformity with accounting principles generally
accepted in the United States of America. These estimates and assumptions affect the reported amounts of assets and liabilities and the
disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses
during the reporting period. These estimates involve judgments with respect to, among other things, future economic factors that are
difficult to predict and are beyond management s control. As a result, actual results could differ from those estimates.
System of Accounts
The accounting records of IPC conform to the Uniform System of Accounts prescribed by the FERC and adopted by the public utility
commissions of Idaho, Oregon and Wyoming.
Property, Plant and Equipment and Depreciation
The cost of utility plant in service represents the original cost of contracted services, direct labor and material, Allowance for Funds Used
During Construction (i\FDC) and indirect charges for engineering, supervision and similar overhead items. Maintenance and repairs of
property and replacements and renewals of items determined to be less than units of property are expensed to operations. Repair and
maintenance costs associated with planned major maintenance are recorded as these costs are incurred. For utility property replaced or
renewed, the original cost plus removal cost less salvage is charged to accumulated provision for depreciation, while the cost of related
replacements and renewals is added to property, plant and equipment.
All utility plant in service is depreciated using the straight-line method at rates approved by regulatory authorities. Annual depreciation
provisions as a percent of average depreciable utility plant in service approximated 2.91 percent in 2005 and 2.96 percent in 2004.
Long-lived assets are periodically reviewed for impairment when events or changes in circumstances indicate that the carrying amount of an
asset may not be recoverable as prescribed under Statement of Financial .-\ccounting Standards (SFAS) 144
, "
Accounting for the
Impairment or Disposal of Long-Lived Assets." SFAS 144 requires that if the sum of the undiscounted expected future cash flows from an
asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements.
Allowance for Funds Used During Construction
-\FDC represents the cost of financing construction projects with borrowed funds and equity funds, While cash is not realized currently
from such allowance, it is realized under the rate-making process over the service life of the related property through increased revenues
resulting from a higher rate base and higher depreciation expense. The component of AFDC attributable to borrowed funds is included as
a reduction to interest expense, while the equity component is included in other income. IPe's weighted, average montWy AFDC rates for
2005 and 2004 were 7.4 percent and 6.9 percent. IPe's reductions to interest expense for AFDC were $3 million annually for 2005 and
2004. Other income included $5 million and $4 million for 2005 and 2004, respectively.
Revenues
IFERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2) A Resubmission 04/18/2006 2005/04
NOTES TO FINANCIAL STATEMENTS (Continued)
IPC accrues unbilled revenues for electric services delivered to customers but not yet billed at month-end. IPC collects franchise fees and
similar taxes related to energy consumption. These amounts are recorded as liabilities until paid to the taxing authority. None of these
collections are reported on the income statement as revenue or expense.
Regulation of U tiIity Operations
IPC follows SFAS 71
, "
Accounting for the Effects of Certain Types of Regulation " and its financial statements reflect the effects of the
different rate-making principles followed by the jurisdictions regulating IPc. The application of SFAS 71 by IPC can result in IPC
recording expenses in a period different than the period the expense would be recorded by an unregulated enterprise. When this occurs
costs are deferred as regulatory assets on the balance sheet and recorded as expenses in the periods when those same amounts are reflected
in rates. Additionally, regulators can impose regulatory liabilities upon a regulated company for amounts previously collected from
customers and for amounts that are expected to be refunded to customers.
Power Cost Adjustment
IPC has a Power Cost Adjustment (PC\) mechanism that provides for annual adjustments to the rates charged to its Idaho retail
customers. These adjustments are based on forecasts of net power supply costs, which are fuel and purchased power less off-system sales
and the true-up of the prior year s forecast. During the year, 90 percent of the difference between the actual and forecasted costs is
deferred with interest. The ending balance of this deferral, called the true,up for the current year s portion and the true-up of the true-up
for the prior years' unrecovered or over-recovered portion, is then included in the calculation of the next year s PCA.
Income Taxes
The liability method of computing deferred taxes is used on all temporary differences between the book and tax basis of assets and
liabilities and deferred tax assets and liabilities are adjusted for enacted changes in tax laws or rates. Consistent with orders and directives
of the Idaho Public Utilities Commission (IPUC), the regulatory authority having principal jurisdiction, IPe's deferred income taxes
(commonly referred to as normalized accounting) are provided for the difference between income tax depreciation and straight-line
depreciation computed using book lives on coal-fired generation facilities and properties acquired after 1980. On other facilities, deferred
income taxes are provided for the difference between accelerated income tax depreciation and straight-line depreciation using tax guideline
lives on assets acquired prior to 1981. Deferred income taxes are not provided for those income tax timing differences where the
prescribed regulatory accounting methods do not provide for current recovery in rates. Regulated enterprises are required to recognize
such adjustments as regulatory assets or liabilities if it is probable that such amounts will be recovered from or returned to customers in
future rates. See Note 2 for more information.
The State of Idaho allows a three-percent investment tax credit on qualifying plant additions. Investment tax credits earned on regulated
assets are deferred and amortized to income over the estimated service lives of the related properties. Credits earned on non,regulated
assets or investments are recognized in the year earned.
Stock-Based Compensation
Stock,based employee compensation is accounted for under the recognition and measurement principles of I\ccounting Principles Board
(APB) Opinion 25
, "
-\ccounting for Stock Issued to Employees " and related interpretations. Grants of performance shares are reflected in
net income based on the market value at the award date, or the period-end price for shares not yet vested. Grants of restricted stock are
reflected in net income based on the market value on the grant date. No stock-based employee compensation cost is reflected in net
income for stock options, as all options granted had an exercise price equal to the market value of the underlying common stock on the
date of grant. IPC has adopted the disclosure only provision of SFAS 123
, "
Accounting for Stock-Based Compensation.
The following table illustrates the effect on net income and EPS if the fair value recognition provisions of SFAS 123 had been applied to
stock-based employee compensation:2005 2004
(thousands of dollars except
for per share amounts)
Net income, as reported
-\dd: Stock-based employee compensation expense included in
reported net income, net of related tax effects
Deduct: Stock-based employee compensation expense
determined under fair value based method for all awards, net
839 608
108 276
IFERC FORM NO.(ED. 12-88) Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2006 2005/04
NOTES TO FINANCIAL STATEMENTS (Continued)
of related tax effects
Pro forma net income
568
379
977
907
For purposes of these pro forma calculations, the estimated fair value of the options, restricted stock and performance shares is amortized
to expense over the vesting period. The fair value of the restricted stock and performance shares is the market price of the stock on the
date of grant. The fair value of an option award is estimated at the date of grant using a binomial option-pricing model. Expense related to
forfeited options is reversed in the period in which the forfeit occurs. For more information see Note 9.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand and higWy liquid temporary investments with maturity dates at date of acquisition of three
months or less.
Derivative Financial Instruments
Financial instruments such as commodity futures, forwards, options and swaps are used to manage exposure to commodity price risk in the
electricity market. The objective of the risk management program is to mitigate the risk associated with the purchase and sale of electricity
and natural gas. The accounting for derivative financial instruments that are used to manage risk is in accordance with the concepts
established by SE\S 133
, "
Accounting for Derivative Instruments and Hedging ,Activities " as amended.
Comprehensive Income
Comprehensive income includes net income, unrealized holding gains and losses on marketable securities, IPe's proportionate share of
unrealized holding gains and losses on marketable securities held by an equity investee and the changes in additional minimum liability
under a deferred compensation plan for certain senior management employees and directors. The following table presents IPe's
accumulated other comprehensive loss balance at December 31:
Unrealized holding gains on securities
I\finimum ension liabili ustment
Total
2005 2004
(thousands of dollars)725 $ 4 538150) (5 426)425) (888)
New Accounting Pronouncements
SFAS 123(R): In December 2004, the FASB issued SFAS 123 (revised 2004), "Share-Based Payment " which revises SFAS 123 and
supersedes APB 25 and its related interpretive guidance. SFAS 123(R) establishes standards for the accounting for transactions in which an
entity exchanges its equity instruments for goods or services. It also addresses transactions in which an entity incurs liabilities in exchange
for goods or services that are based on the fair value of the entity s equity instruments or that may be settled by the issuance of those equity
instruments. SFAS 123(R) focuses primarily on accounting for transactions in which an entity obtains employee services in share-based
payment transactions,
Under the provisions of SPAS 123(R), the fair value of all stock options must be reported as an expense on the financial statements. IPC
currently applies the measurement provisions of APB 25 and the disclosure-only provisions of SPAS 123. SPAS 123(R) also changes other
measurement, timing and disclosure rules relating to share-based payments.
In March 2005, the staff of the Securities and Exchange Commission issued Staff .\ccounting Bulletin (SAB) 107 to provide additional
guidance regarding the application of SPAS 123(R). SAB 107 permits registrants to choose an appropriate valuation technique or model to
estimate the fair value of share options, assuming consistent application, and provides guidance for the development of assumptions used
in the valuation process. Additionally, SAB 107 discusses disclosures to be made under "Management s Discussion and Analysis of
Financial Condition and Results of Operations" in the registrants' periodic reports.
Based upon Securities and Exchange Commission rules issued in April 2005, SPAS 123(R) is effective for fiscal years that begin after June
2005 and will be adopted by IPC in the first quarter of 2006. Adoption is not expected to have a material effect on IPe's fl11ancial
statements.
SFAS 153: In December 2004, the FASB issued SPAS 153
, "
Exchanges of Nonmonetary Assets " which amends existing guidance on
IFERC FORM NO.1 (ED. 12-88) Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2006 2005/04
NOTES TO FINANCIAL STATEMENTS (Continued)
accounting for nonmonetary transactions. SFAS 153 is effective for exchanges occurring in fiscal periods beginning after June 15, 2005
and is not expected to have a material effect on IPe's f111ancial statements.
SFAS 154: In May 2005 the FASB issued SFAS 154
, "
Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20
and FASB Statement No." SFAS 154 changes the requirements for the accounting for and reporting of a change in accounting principle.
It applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement that does not include
specific transition provisions. When a pronouncement includes specific transition provisions, those provisions should be followed. SFAS
154 requires retrospective application to prior periods' financial statements of changes in accounting principle , unless it is impracticable to
determine either the period-specific effects or the cumulative effect of the change. When it is impracticable to determine the
period-specific effects of an accounting change on one or more individual prior periods presented, SFAS 154 requires that the new
accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective
application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings for that period rather
than being reported in an income statement. When it is impracticable to determine the cumulative effect of applying a change in
accounting principle to all prior periods, SFAS 154 requires that the new accounting principle be applied as if it were adopted prospectively
from the earliest date practicable. SFAS 154 is effective for accounting changes and corrections of errors made in fiscal years beginning
after December 15, 2005.
Other Accounting Policies
Debt discount, expense and premium are being amortized over the terms of the respective debt issues.
Reclassifications
Certain items previously reported for years prior to 2005 have been reclassified to conform to the current year s presentation. Net income
and shareholder s equity were not affected by these reclassifications.
2. INCOME TAXES:
i\ reconciliation between the statutory federal income tax rate and the effective tax rate is as follows:
2005 2004
(thousands of dollars)
Federal income tax expense bases on federal 861 394
statutory rate
Change in taxes resulting from:
Equity in earnings of subsidiary companIes 106)867)
AFDC 709)400)
Investment tax credits 295)295)
Repair allowance 750)450)
Removal costs 490)244)
Pension accrual 276 237
Capitalized overhead costs 658)
Regulatory tax liability (16 457)
Settlement of prior years tax returns (2)460)
State income taxes, net of federal benefit 847 100
Deprecla tion 603 350
Other, net 816 697
Total income tax expense (benefit)051 947
Effective tax rate 36.
The items comprising income tax expense are as follows:
2005 2004
(thousands of dollars)
Income taxes currently payable:
IFERC FORM NO.1 (ED. 12-88)Page 123.4
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2S An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2006 2005/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Federal 896 451
State 177 318
Total 073 769
Income taxes deferred:
Federal (29 891)(17 318)
State 081 551
Total 972 869
Investment tax credits:
Deferred 374 700
Restored 424)653)
Total 950 953
Total income tax expense 051 947
(benefit)
The components of the net deferred tax liability are as follows:
2005 2004
(thousands of dollars)
Deferred tax assets:
Regulatory liabilities
Advances for construction
Deferred compensation
Emission allowances
Other
Total
Deferred tax liabilities:
Property, plant and equipment
Regulatory assets
Conservation programs
PC\
Other
Total
Net deferred tax liabilities
627
881
276
380
496
103 660
447
357
324
584
712
240 144
346 116
705
410
666
610 041
506 381
241 324
344 220
972
516
722
613 754
541 042
Amounts accrued by IPC for income taxes are payable to IDACORP, as IPC joins in the filing of IDA CORP's federal and state
consolidated income tax returns.
Capitalized Overhead Costs: On .-\ugust 2, 2005, the IRS and Treasury Department issued guidance interpreting the meaning of
routine and repetitive" for purposes of the simplified service cost and simplified production methods of the Internal Revenue Code
section 263A uniform capitalization rules. The guidance was issued in the form of a revenue ruling (Rev. Rul. 2005-53) and proposed and
temporary regulations. The regulations are effective for tax years ending on or after 1-\Ugust 2, 2005, and the revenue ruling applies for all
prior open years. Both pieces of guidance take a more restrictive view of the defInition of self-constructed assets produced by a taxpayer
on a "routine and repetitive" basis than do the current treasury regulations.
Generally, section 263A requires the capitalization of all direct costs and those indirect costs, known as "mixed service costs , which
direcdy benefit or are incurred by reason of the production of property by a taxpayer. The treasury regulations for section 263A provide
IFERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2006 2005/04
NOTES TO FINANCIAL STATEMENTS (Continued)
several "safe-harbor" methods taxpayers may adopt in order to comply with the statute. The simplified service cost method is one of the
methods available for the calculation of indirect overhead ("mixed service costs ) cost capitalization. IPC changed to the simplified service
cost method for both the self-construction of utility plant and production of electricity beginning with its 2001 federal income tax return.
For IPC, the simplified service cost method produces a current tax deduction for costs capitalized to electricity production that are
capitalized into fixed assets for financial accounting purposes. Deferred income tax expense has not been provided for this deduction
because the prescribed regulatory tax accounting treatment does not allow for inclusion of such deferred tax expense in current rates. Rate
regulated enterprises are required to recognize such adjustments as regulatory assets if it is probable that such amounts will be recovered
from customers in future rates.
For fiscal years 2002 through 2004, the simplified service cost method decreased IPe's income tax expense by $60 million and resulted in
cash refunds from federal and state tax authorities of $75 million. For years 2004 and prior open tax years, if IPC cannot satisfy the new
guidance as currently drafted, IPC would be required to use another method of uniform capitalization, which could be more or less
favorable to IPC than the simplified service cost method. A less favorable method could result in a one time charge to earnings and
reduced cash flow that could be partially offset by carryover tax credits, accelerated tax depreciation, changes in tax regulations and state
regulatory recovery.
The temporary regulations are effective for IPe's 2005 tax year and, as drafted, preclude IPC from using this method for self-constructed
assets for 2005 and thereafter. Accordingly, in the third quarter of 2005, IPC reversed its previously accrued 2005 tax deduction for
capitalized overhead costs for both financial reporting and estimated tax payment purposes. IPC is evaluating alternatives for a new
uniform capitalization method.
IPC is actively involved in pursuing resolution of this matter and is working diligently with the IRS in the examination process. 1\t this
time, IPC cannot predict the earnings or cash flow impacts that the revenue ruling, temporary regulations, or additional action by the IRS in
this matter may have on 2005 or prior tax years.
Regulatory Settlement
In 2004, IPC and the IPUC finalized an income tax issue from IPe's 2003 Idaho general rate case. The issue concerned the regulatory
accounting treatment for the capitalized overhead tax method IPC adopted in the 2001 IDACORP federal income tax return. As a result
of the settlement, a $16 million regulatory tax liability was reversed, creating benefit in 2004.
3. COMMON STOCK:
In December 2004, IDACORP contributed $86 million of additional equity to IPc. No additional shares of IPC common stock were
issued in this transaction.
Dividend Restrictions
IPe's articles of incorporation contain restrictions on the payment of dividends on its common stock if preferred stock dividends are in
arrears. On September 20, 2004, IPC redeemed all of its outstanding preferred stock. Also, certain provisions of credit facilities contain
restrictions on the ratio of debt to total capitalization.
IPC must obtain the approval of the Oregon Public Utility Commission (OPUC) before it could directly or indirectly loan funds or issue
notes or give credit on its books to IDACORP.
4. PREFERRED STOCK OF IDAHO POWER COMPANY:
On September 20, 2004, IPC redeemed all of its outstanding preferred stock for $54 million using proceeds from the issuance of first
mortgage bonds. This amount includes $2 million of premium that was recorded as preferred dividends on the Consolidated Statements of
Income. The redemption price was $104 per share for the 122 989 shares of 4% preferred stock, $102.97 per share for the 150 000 shares
of 7.68% preferred stock and $103.18 per share for the 250 000 shares of 7.07% preferred stock, plus accumulated and unpaid dividends.
5. LONG-TERM DEB
The following table summarizes long-term debt at December 31:
IFERC FORM NO.(ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2006 2005/04
NOTES TO FINANCIAL STATEMENTS (Continued)2005 2004
(thousands of dollars)
First mortgage bonds:83 % Series due 200538 % Series due 200720 % Series due 200960 % Series due 201175 % Series due 20124.25 % Series due 2013
Series due 20325.50 % Series due 20335.50 % Series due 2034875 % Series due 203430 % Series due 2035
Total first mortgage bonds
Pollution control revenue bonds:
Variable Auction Rate Series 2003 due 2024 (a) 49 800 49 80005 % Series 1996A due 2026 68 100 68 100Variable Rate Series 1996B due 2026 24 200 24 200Variable Rate Series 1996C due 2026 24 000 24 000Variable Rate Series 2000 due 2027 4 360 4 360Total pollution control revenue bonds 170 460 170 460-\merican Falls bond guarantee 19 885 19 885Milner Dam note guarantee 11 700 11 700
Unamortized premium/discount, net (3 325) (3 135)Total 983 720 983 910
Current maturities oflong-term debt (60 000)
Total long-term debt $ 983 720 $ 923 910
(a) Humboldt County Pollution Control Re\-enue bonds are secured by first mortgage bonds, bringing the total of first mortgage
bonds outstanding at December 31 2005 to $834,8 million,
000
000
000
120 000
100 000
000
100 000
000
000
000
000
000
120 000
100 000
000
100 000
000
000
000
000
785 000 785 000
At December 31 , 2005, the maturities for the aggregate amount oflong-term debt outstanding were (in thousands of dollars):
2006 2007 2008 2009 2010 Thereafter
IPC 064 064 064 $ 1 064 $ 822 789
On October 22, 2003, Humboldt County, Nevada issued, for the benefit ofIPC, $49.8 million Pollution Control Revenue Refunding
Bonds (Idaho Power Company Project) Series 2003 due December 1, 2024. IPC borrowed the proceeds from the issuance pursuant to a
Loan Agreement with Humboldt County and is responsible for payment of principal, premium, if any, and interest on the bonds. The
bonds are secured, as to principal and interest, by IPC first mortgage bonds and as to principal and interest when due, by an insurance
policy issued by Ambac Assurance Corporation. The bonds were issued in an auction rate mode under which the interest rate is reset every
35 days. The initial auction rate was set at 0.95 percent. At December 31, 2005, the auction rate was 3.15 percent. Proceeds from this
issuance together with other funds provided by IPC were used to redeem the outstanding $49.8 million Pollution Control Revenue Bonds
(Idaho Power Company Project) 8.3% Series 1984 due 2014, on December 1, 2003, at 103 percent.
On March 14 2003, IPC filed a $300 million shelf registration statement that could be used for first mortgage bonds (including
medium-term notes), unsecured debt and preferred stock. On May 8 2003, IPC issued $140 million of secured medium-term notes in two
series: $70 million First Mortgage Bonds 4.25% Series due 2013 and $70 million First Mortgage Bonds 5.50% Series due 2033. Proceeds
were used to pay down IPC short-term borrowings incurred from the payment at maturity of $80 million First Mortgage Bonds 6.40%
IFERC FORM NO.(ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2S. An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2006 2005/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Series due 2003 and the early redemption of$80 million First Mortgage Bonds 7.50% Series due 2023, on May 1, 2003. On March 26
2004, IPC issued $50 million First Mortgage Bonds 5.50% Series due 2034. Proceeds were used to reduce short-term borrowings and
replace short-term investments, which were used on March 15, 2004 to pay at maturity the $50 million First Mortgage Bonds 8% Series due
2004. On August 16, 2004, IPC issued $55 million First Mortgage Bonds 5.875% Series due 2034. On September 20, 2004, the proceeds
of this issuance were used to redeem all ofIPC's outstanding preferred stock.
On January 19 2005, IPC filed a $245 million shelf registration statement that could be used for first mortgage bonds (including
medium-term notes) and debt securities, and when combined with the $55 million remaining from the March 14 2003 shelf registration
provided for $300 million available in shelf registration form. On August 26, 2005 IPC issued $60 million First Mortgage Bonds 5.30%
Series due 2035. Proceeds were invested in short-term investments, which were used on September 9, 2005 to pay at maturity the $60
million First Mortgage Bonds 5.83% Series due 2005. At December 31 , 2005, $240 million remained available to be issued on this shelf
registration statement.
On August 17, 2004, IPC redeemed all $1 million of its Rural Electrification Administration notes.
On August 30, 2005, IPC settled a forward,starting interest rate swap agreement by making a payment of $2.7 million to the counterparty
of the agreement. In accordance with regulatory accounting practices under SFAS 71 , IPC is amortizing this amount over the life of its
30% First Mortgage Bonds due 2035.
At December 31, 2005 and 2004, the overall effective cost ofIPC's outstanding debt was 5.84 percent and 5.69 percent, respectively.
The amount of first mortgage bonds issuable by IPC is limited to a maximum of $1.1 billion and by property, earnings and other provisions
of the mortgage and supplemental indentures thereto. IPC may amend the indenture and increase this amount without consent of the
holders of the first mortgage bonds. Substantially all of the electric utility plant is subject to the lien of the mortgage. As of December 31
2005, IPC could issue under the mortgage approximately $560 million of additional first mortgage bonds based on unfunded property
additions and $452 million of additional first mortgage bonds based on retired first mortgage bonds. At December 31, 2005, unfunded
property additions, which consist of electric property, were approximately $933 million.
6. FAIR VALUE OF FINANCIAL INSTRUMENTS:
The estimated fair value ofIPC's financial instruments has been determined using available market information and appropriate valuation
methodologies. The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair
value amounts.
Cash and cash equivalents, customer and other receivables, notes payable, accounts payable, interest accrued and taxes accrued are reported
at their carrying value as these are a reasonable estimate of their fair value. The estimated fair values for notes receivable, long-term debt
and investments are based upon quoted market prices of the same or similar issues or discounted cash flow analyses as appropriate.
December 31, 2005 December 31, 2004Carrying Estimated Carrying EstimatedAmount Fair Value Amount Fair Value
(thousands of dollars)
Assets:
Notes receivable 047 876 946 877
Investments 137 137 155 155
Liabilities:
Long-term debt 987 045 003 651 987 045 008 369
7. NOTES PAYABLE:
At December 31 , 2005, IPC had regulatory authority to incur up to $250 million of short-term indebtedness. IPC has a $200 million credit
facility that expires on March 31, 2010. Under this facility IPC pays a facility fee on the commitment, quarterly in arrears, based on its
IFERC FORM NO.1 (ED. 12-88) Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2006 2005/04
NOTES TO FINANCIAL STATEMENTS (Continued)
rating for senior unsecured long-term debt securities without thiId-party credit enhancement as provided by Moody s and S&P. IPe's
commercial paper may be issued up to the amounts supported by the bank credit facilities. There was no commercial paper outstanding at
December 31 , 2005 or 2004.
8. COMMITMENTS AND CONTINGENCIES:
\s of December 31, 2005, IPC had agreements to purchase energy from 87 cogeneration and small power production (CSPP) facilities with
contracts ranging from one to 30 years. Under these contracts IPC is required to purchase all of the output from the facilities inside the
IPC service territory. For projects outside the IPC service territory, IPC is required to purchase the output that it has the ability to receive
at the facility s requested point of delivery on the IPC system. IPC purchased 715 209 megawatt-hours (MWh) at a cost of$43 million in
2005 677 868 I\IWh at a cost of$40 million in 2004 and 654 131l\IWh at a cost of$38 million in 2003.
At December 31 2005, IPC had the following long-term commitments relating to purchases of energy, capacity, transmission rights and
fuel:
thouands of dollars 2006 2007 2008 2009 2010 Thereafter
Cogeneration and small
power prod $59 719 $70 283 $70 283 $73 753 $73 753 039 377
Power and transmission
rights 148 818 362 762 193 714 001
Fuel 370 496 997 013 010 118
IPC has agreed to guarantee the performance of reclamation activities at Bridger Coal Company of which Idaho Energy Resources Co., a
subsidiary of IPC, owns a one-third interest. This guarantee, which is renewed each December, was $60 million at December 31 , 2005.
Bridger Coal Company has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs. Bridger Coal
Company and IPC expect that the fund will be sufficient to cover all such costs. Because of the existence of the fund, the estimated fair
value of this guarantee is minimal.
From time to time IPC is a party to legal claims, actions and complaints in addition to those discussed below. IPC believes that it has
meritorious defenses to all lawsuits and legal proceedings. Although they will vigorously defend against them, they are unable to predict
with certainty whether or not they will ultimately be successful. However, based on IPe's evaluation, they believe that the resolution of
these matters, taking into account existing reserves, will not have a material adverse effect on IPe's ftnancial position, results of operations
or cash flows.
Legal Proceedings
Public Utility District No.1 of Grays Harbor County, Washington: On October 15, 2002, Public Utility District No.1 of Grays
Harbor County, Washington (Grays Harbor) flied a lawsuit in the Superior Court of the State of Washington, for the County of Grays
Harbor, against IDACORP, IPC and IE. On March 9, 2001, Grays Harbor entered into a 20-megawatt (l\IW) purchase transaction with
IPC for the purchase of electric power from October 1 , 2001 through March 31 , 2002, at a rate of $249 per l\IWh. In June 2001, with the
consent of Grays Harbor, IPC assigned all of its rights and obligations under the contract to IE. In its lawsuit, Grays Harbor alleged that
the assignment was void and unenforceable, and sought restitution from IE and IDACORP, or in the alternative, Grays Harbor alleged that
the contract should be rescinded or reformed. Grays Harbor sought as damages an amount equal to the difference between $249 per MWh
and the "fair value" of electric power delivered by IE during the period October 1, 2001 through March 31 2002.
IDACORP, IPC and IE removed this action from the state court to the U.S. District Court for the Western District of\Vashington at
Tacoma. On November 12, 2002, the companies filed a motion to dismiss Grays Harbor s complaint, asserting that the U.S. District Court
lacked jurisdiction because the FERC has exclusive jurisdiction over wholesale power transactions and thus the matter is preempted under
the Federal Power Act and barred by the filed-rate doctrine. The court ruled in favor of the companies' motion to dismiss and dismissed
the case with prejudice on January 28, 2003. On February 25, 2003, Grays Harbor filed a Notice of Appeal, appealing the ftnal judgment of
dismissal to the u.S. Court of Appeals for the Ninth Circuit. On August 10, 2004, the Ninth Circuit aff1Imed the dismissal of Grays
Harbor s complaint, finding that Grays Harbor s claims were preempted by federal law and were barred by the filed-rate doctrine. The
court also remanded the case to allow Grays Harbor leave to amend its complaint to seek declaratory relief only as to contract formation
and held that Grays Harbor could seek monetary relief, if at all, only from the FERC, and not from the courts. ID"\CORP, IPC and IE
IFERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2006 2005/04
NOTES TO FINANCIAL STATEMENTS (Continued)
sought rehearing from the Ninth Circuit arguing that the court erred in granting leave to amend the complaint as such a declaratory relief
claim would be preempted and would be barred by the filed-rate doctrine. The Ninth Circuit denied the rehearing request on October 25
2004, and the decision became final on November 12 2004.
On that same date, the companies took steps to have the case transferred and consolidated with other similar cases arising out of the
California energy crisis currently pemling before the Honorable Robert H. Whaley, sitting by designation in the Southern District
California and presiding over Multidistrict Litigation Docket No. 1405, regarding California Wholesale Electricity Antitrust Litigation.
November 18, 2004, Grays Harbor filed an amended complaint alleging that the contract was formed under circumstances of "mistake" as
to an "artificial. . . power shortage." Grays Harbor asked that the contract therefore be declared "unenforceable" and found
unconscionable." On December 23 2004, the Judicial Panel on Multidistrict Litigation conditionally transferred the case to Judge Whaley.
Grays Harbor sought to vacate the transfer; however, on April 18, 2005, the Judicial Panel on Multidistrict Litigation ordered the case
transferred. On May 18 2005, ID"-\CORP, IPC and IE filed a motion to dismiss the amended complaint. The motion was heard on
September 29, 2005.
On December 16, 2005, Judge Whaley issued an Order Setting Status Conference wherein, rather than expressly ruling on the companies
motion to dismiss Grays Harbor s amended complaint, he ruled that either Grays Harbor or the companies may, within 45 days of the date
of the order, petition the FERC to weigh in on this case in light of "the extensive hearings. . . already undertaken by FERC in the
Northwest refund proceeding" which may be relevant to this case. On January 27, 2006 Grays Harbor and the companies jointly filed a
stipulation requesting that the court stay the action and extend the time in which the parties may petition the FERC by sixty days to March
2006 stating that the parties felt the case was appropriate for mediation prior to further proceedings. On January 31, 2006 the court
approved the stipulation staying the case untill\Iarch 31 2006 and setting a status conference for April 14, 2006. The companies intend to
vigorously defend their position in this proceeding and believe this matter will not have a material adverse effect on their consolidated
financial positions, results of operations or cash flows.
Port of Seattle: On May 21, 2003, the Port of Seattle, a Washington municipal corporation, filed a lawsuit against 20 energy frnns
including IPC and IDA CORP, in the U.S. District Court for the Western District of Washington at Seattle. The Port of Seattle s complaint
alleges fraud and violations of state and federal antitrust laws and the Racketeer Influenced and Corrupt Organizations Act. On December
2003, the Judicial Panel on Multidistrict Litigation transferred the case to the Southern District of California for inclusion with several
similar multidistrict actions currently pending before the Honorable Robert H. Whaley.
All defendants, including IPC and IDACORP, moved to dismiss the complaint in lieu of answering it. The motions were based on the
ground that the complaint seeks to set alternative electrical rates, which are exclusively within the jurisdiction of the FERC and are barred
by the filed-rate doctrine. A hearing on the motion to dismiss was heard on March 26, 2004. On May 28, 2004, the court granted IPe's
and ID.-\CORP's motion to dismiss. In June 2004, the Port of Seattle appealed the court s decision to the u.S. Court of Appeals for the
Ninth Circuit. On July 19, 2005 the companies flied a motion for summary affirmance of the district court's order dismissing the Port of
Seattle s complaint. The Ninth Circuit issued an order denying this motion on October 17, 2005. The appeal has been fully briefed; and
oral argument has been scheduled for March 7, 2006. The companies intend to vigorously defend their position in this proceeding and
believe this matter will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.
Wah Chang: On May 5, 2004, Wah Chang, a division of TDY Industries, Inc., flied two lawsuits in the U.S. District Court for the District
of Oregon against numerous defendants. IDACORP, IE and IPC are named as defendants in one of the lawsuits. The complaints allege
violations of federal antitrust laws, violations of the Racketeer Influenced and Corrupt Organizations Act, violations of Oregon antitrust
laws and wrongful interference with contracts. \Vah Chang s complaint is based on allegations relating to the western energy situation.
These allegations include bid rigging, falsely creating congestion and misrepresenting the source and destination of energy. The plaintiff
seeks compensatory damages of $30 million and treble damages.
On September 8, 2004, this case was transferred and consolidated with other similar cases currently pending before the Honorable Robert
H. Whaley. The companies' motion to dismiss the complaint was granted on February 11 2005. Wah Chang appealed to the Ninth Circuit
on J\Iarch 10 2005. The Ninth Circuit set a briefing schedule on the appeal, requiring Wah Chang s opening brief to be flied by July 6
2005. On May 18, 2005, Wah Chang filed a motion to stay the appeal or in the alternative to voluntarily dismiss the appeal without
prejudice to reinstatement. The companies opposed the motion and filed a cross-motion asking the Court to summarily affirm the district
court s order of dismissal. On July 8, 2005, the Ninth Circuit denied Wah Chang s motion and also denied the companies' motion for
summary affirmance without prejudice to renewal following the filing ofWah Chang s opening brief. Wah Chang s opening brief was filed
on September 21 , 2005. On October 11 , 2005 the companies, along with the other defendants, filed a motion to consolidate this appeal
with Wah Chang v. Duke Energy Trading and Marketing currently pending before the Ninth Circuit. On October 18, 2005 the Ninth
IFERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo. Da, Yr)
Idaho Power Company (2) A Resubmission 04/18/2006 2005/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Circuit granted the motion to consolidate and established a revised briefmg schedule. The companies filed an answering brief on
November 30, 2005. Wah Chang s reply brief was filed on January 6, 2006. The appeal has been fully briefed; however, no date has yet
been set for oral argument. The companies intend to vigorously defend their position in this proceeding and believe this matter will not
have a material adverse effect on their consolidated fmancial positions, results of operations or cash flows.
City of Tacoma: On June 7 , 2004, the City of Tacoma, Washington filed a lawsuit in the U.S. District Court for the Western District of
Washington at Tacoma against numerous defendants including IDA CORP, IE and IPC The City of Tacoma s complaint alleges violations
of the Sherman Antitrust Act. The claimed antitrust violations are based on allegations of energy market manipulation, false load
scheduling and bid rigging and misrepresentation or withholding of energy supply. The plaintiff seeks compensatory damages of not less
than $175 million.
On September 8, 2004, this case was transferred and consolidated with other similar cases currently pending before the Honorable Robert
H. Whaley. The companies' motion to dismiss the complaint was granted on February 11 2005. The City of Tacoma appealed to the
Ninth Circuit on March 10 2005.
On August 9, 2005, the companies moved for summary affirmance of the district court s order dismissing the City of Tacoma s complaint.
The City of Tacoma filed a response to the companies' motion for summary affirmance on "-\ugust 24, 2005. The Ninth Circuit denied the
companies' motion for summary affmnance on November 3 , 2005. The appeal has been fully briefed; however, no date has yet been set
for oral argument. The companies intend to vigorously defend their position in this proceeding and believe this matter will not have a
material adverse effect on their consolidated financial positions, results of operations or cash flows.
Wholesale Electricity Antitrust Cases I & II: These cross-actions against IE and IPC emerged from multiple California state court
proceedings first initiated in late 2000 against various power generators/ marketers by various California municipalities and citizens. Suit
was filed against entities including Reliant Energy Services, Inc., Reliant Ormond Beach, L.L.C, Reliant Energy Etiwanda, L.L.C, Reliant
Energy Ellwood, LL.C, Reliant Energy 1Iandalay, L.LC and Reliant Energy Coolwater, L.L.C (collectively, Reliant); and Duke Energy
Trading and Marketing, L.L.C, Duke Energy Morro Bay, L.L.C, Duke Energy Moss Landing, L.L.C, Duke Energy South Bay, L.L.C and
Duke Energy Oakland, L.L.C (collectively, Duke). While varying in some particulars, these cases made a common claim that Reliant, Duke
and certain others (not including IE or IPC) colluded to influence the price of electricity in the California wholesale electricity market. The
plaintiffs asserted various claims that the defendants violated the California "-\ntitrust Law (the Cartwright Act), Business and Professions
Code Section 16720 and California s Unfair Competition Law, Business and Professions Code Section 17200. Among the acts complained
of are bid rigging, information exchanges, withholding of power and other wrongful acts. These actions were subsequently consolidated
resulting in the filing of Plaintiffs' Master Complaint in San Diego Superior Court on March 8, 2002.
On April 22, 2002, more than a year after the initial complaints were filed, two of the original defendants, Duke and Reliant, filed separate
cross-complaints against IPC and IE, and approximately 30 other cross-defendants. Duke and Reliant s cross-complaints sought indemnity
from IPC, IE and the other cross-defendants for an unspecified share of any amounts they must pay in the underlying suits because, they
allege, other market participants like IPC and IE engaged in the same conduct at issue in the Plaintiffs' Master Complaint. Duke and
Reliant also sought declaratory relief as to the respective liability and conduct of each of the cross-defendants in the actions alleged in the
Plaintiffs' Master Complaint. Reliant also asserted a claim against IPC for alleged violations of the California Unfair Competition Law
Business and Professions Code Section 17200. As a buyer of electricity in California, Reliant requested the same relief from the
cross-defendants, including IPC, as that sought by plaintiffs in the Plaintiffs' Master Complaint as to any power Reliant purchased through
the California markets.
Some of the newly added defendants (foreign citizens and federal agencies) removed that litigation to federal court. IPC and IE, together
with numerous other defendants added by the cross-complaints, moved to dismiss these claims, and those motions were heard in
September 2002, together with motions to remand the case back to state court filed by the original plaintiffs. On December 13, 2002, the
u.S. District Court granted Plaintiffs' Motion to Remand to state court , but did not issue a ruling on IPC and IE's motion to dismiss. The
S. Court of .-\ppeals for the Ninth Circuit granted certain Defendants and Cross-Defendants' Motions to Stay the Remand Order while
they appeal the order. The briefing on the appeal was completed in December 2003. On December 8, 2004, the Ninth Circuit issued its
opinion in People of California v. NRG Energy, Inc., et aI., which affirmed the district court s remand of these cases to state court and
dismissed certain federal government defendants due to their sovereign immunity from suit.
On June 3, 2005, the cross-defendants, including IPC and IE, filed a demurrer in state court seeking to dismiss the cross-complaints filed
by Duke and Reliant. On August 8, 2005, before that demurrer was to be heard, the Clerk of the Court entered Duke s voluntary dismissal
with prejudice, of the cross-complaint against IE and IPC Further briefing and hearing on IE and IPe's demurrer to the Reliant
IFERC FORM NO.ED. 12-Page 123.
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(1) ~ An Original (Mo, Da , Yr)
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NOTES TO FINANCIAL STATEMENTS (Continued)
cross-complaint was stayed pending the outcome of the demurrer flied by Reliant on the Master Complaint. On September 22, 2005, the
Court took Reliant s demurrer off calendar pending approval of a proposed settlement as to the plaintiffs Master Complaint. On October
2005 the court sustained the defendants' (other than Reliant s) joint demurrer to the Master Complaint and scheduled a status conference
to discuss the status of the cross-complaints. On October 13, 2005 the court set IE and IPe's demurrer on the cross-complaint for hearing
on December 23, 2005.
However, on November 14, 2005, Judge Joan M. Lewis approved a stipulation between the cross-defendants, including IE and IPC, and
Reliant. This stipulation provided for dismissal of IE and IPC by Reliant with prejudice subject to reinstatement in the event that approval
and finalization of a settlement agreement between Reliant and the underlying plaintiffs in these cases does not occur. The December 23
2005 hearing on IE and IPe's demurrer to the cross-complaint was taken off the calendar. A hearing regarding approval of the Reliant
settlement was held on Friday January 6, 2006 before Judge Lewis.
Reliant has filed a request for dismissal of IE and IPC with prejudice, which was entered by the clerk of the court on December 19, 2005.
Pursuant to IE and IPe's stipulation with Reliant, the dismissal will become final once any judgment and order from the Court approving
the Reliant settlement with the plaintiffs becomes final (i., once the time for any appeal on the order approving the settlements runs or, if
review is sought, the trial court s approval order is affirmed after resolution of all appeals). The time for an appeal from an order approving
the settlements would range from 30 to 90 days after entry of the Court s judgments and orders.
If the Court does not grant final approval for the Reliant settlement, Reliant may elect to reactivate its cross-complaint. Similarly, should
the Court for any reason fail to approve the Reliant settlement by May 31, 2006, IE and IPC may withdraw from the stipulation agreement
by giving ten days' advance written notice. The companies intend to vigorously defend their position in this proceeding and believe this
matter will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.
Western Energy Proceedings at the FERC:
California' Power Exchange Chargeback:
As a component of IPe's non-utility energy trading in the State of California , IPC, in January 1999, entered into a participation agreement
with the California Power Exchange (CaIPX), a California non-profit public benefit corporation. The CaIPX, at that time, operated a
wholesale electricity market in California by acting as a clearinghouse through which electricity was bought and sold. Pursuant to the
participation agreement, IPC could sell power to the CalPX under the terms and conditions of the CalPX Tariff. Under the participation
agreement, if a participant in the CalPX defaulted on a payment, the other participants were required to pay their allocated share of the
default amount to the CaIPx. The allocated shares were based upon the level of trading activity, which included both power sales and
purchases, of each participant during the preceding three-month period.
On January 18, 2001, the CalPX sent IPC an invoice for $2 million - a "default share invoice" - as a result of an alleged Southern California
Edison payment default of $215 million for power purchases. IPC made this payment. On January 24, 2001, IPC terminated its
participation agreement with the CaIPx. On February 8, 2001 , the CalPX sent a further invoice for $5 million, due on February 20, 2001
as a result of alleged payment defaults by Southern California Edison, Pacific Gas and Electric Company and others. However, because the
CalPX owed IPC $11 million for power sold to the CalPX in November and December 2000, IPC did not pay the February 8 invoice. The
CalPX later reversed IPe's payment of the January 18 2001 invoice, but on June 20, 2001 invoiced IPC for an additional $2 million which
the CalPX has not reversed. The CalPX owes IPC $14 million for power sold in November and December including $2 million associated
with the default share invoice dated June 20 2001. IPC essentially discontinued energy trading with the CalPX and the California
Independent System Operator (Cal ISO) in December 2000.
IPC believes that the default invoices were not proper and that IPC owes no further amounts to the CaIPX. IPC has pursued all available
remedies in its efforts to collect amounts owed to it by the CaIPx. On February 20, 2001 , IPC filed a petition with the FERC to intervene
in a proceeding that requested the FERC to suspend the use of the CalPX chargeback methodology and provide for further oversight in
the CaIPX's implementation of its default mitigation procedures.
i\ preliminary injunction was granted by a federal judge in the U.S. District Court for the Central District of California enjoining the CalPX
from declaring any CalPX participant in default under the terms of the CalPX Tariff. On March 9, 2001 , the CalPX filed for Chapter 11
protection with the U ,S. Bankruptcy Court, Central District of California.
In .\pril2001 , Pacific Gas and Electric Company flied for bankruptcy. The CalPX and the Cal ISO were among the creditors of Pacific
Gas and Electric Company. To the extent that Pacific Gas and Electric Company s bankruptcy filing affects the collectibility of the
receivables from the CalPX and the Cal ISO, the receivables from these entities are at greater risk.
IFERC FORM NO.1 (ED. 12-88)Page 123.
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(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2006 2005/04
NOTES TO FINANCIAL STATEMENTS (Continued)
The FERC issued an order on April 6, 2001 requiring the CalPX to rescind all chargeback actions related to Pacific Gas and Electric
Company s and Southern California Edison s liabilities. Shortly after the issuance of that order, the CalPX segregated the CalPX
chargeback amounts it had collected in a separate account. The CalPX claimed it was awaiting further orders from the FERC and the
bankruptcy court before distributing the funds that it collected under its chargeback tariff mechanism. On October 7, 2004, the FERC
issued an order determining that it would not require the disbursement of chargeback funds until the completion of the California refund
proceedings. On November 8, 2004, IE, along with a nwnber of other parties, sought rehearing of that order. On March 15 2005, the
FERC issued an order on rehearing confirming that the CalPX is to continue to hold the chargeback funds, but solely to offset
seller-specific shortfalls in the seller s CalPX account at the conclusion of the California refund proceeding. Balances are to be returned to
the respective sellers at the conclusion of a seller s participation in the refund proceeding. Powerex Corp. filed a petition for review of the
Commission s order on March 24, 2005 in the D.e. Circuit. Neither a briefmg schedule nor a date for oral argument has been set.
Based upon the settlement agreement filed with the FERC on February 17, 2006 between the California Parties and IE and IPC discussed
below in "California Refund," the California Parties have agreed to support a request that the FERC authorize the CalPX to release $2.
mil1ion related to the chargeback proceeding to IE and IPe.
California Refund:
In April 2001 , the FERC issued an order stating that it was establishing price mitigation for sales in the California wholesale electricity
market. Subsequently, in a June 19, 2001 order, the FERC expanded that price mitigation plan to the entire western United States
electrically interconnected system. That plan included the potential for orders directing electricity sellers into California since October 2
2000 to refund portions of their spot market sales prices if the FERC determined that those prices were not just and reasonable, and
therefore not in compliance with the Federal Power Act. The June 19 order also required all buyers and sellers in the Cal ISO market
during the subject time frame to participate in settlement discussions to explore the potential for resolution of these issues without further
FERC action. The settlement discussions failed to bring resolution of the refund issue and as a result, the FERC's Chief Administrative
Law Judge submitted a Report and Recommendation to the FERC recommending that the FERC adopt the methodology set forth in the
report and set for evidentiary hearing an analysis of the Cal ISO's and the CaIPX's spot markets to determine what refunds may be due
upon application of that methodology.
On July 25, 2001, the FERC issued an order establishing evidentiary hearing procedures related to the scope and methodology for
calculating refunds related to transactions in the spot markets operated by the Cal ISO and the CalPX during the period October 2, 2000
through June 20 2001 (Refund Period).
The i\dministrative Law Judge issued a Certification of Proposed Findings on California Refund Liability on December 12 2002.
The FERC issued its Order on Proposed Findings on Refund Liability on March 26, 2003. In large part, the FERC affinned the
recommendations of its Administrative Law Judge. However, the FERC changed a component of the formula the Administrative Law
Judge was to apply when it adopted findings of its staff that published California spot market prices for gas did not reliably reflect the
prices a gas market, that had not been manipulated, would have produced, despite the fact that many gas buyers paid those amounts. The
fmdings of the Administrative Law Judge, as adjusted by the FERC's March 26 , 2003 order, are expected to increase the offsets to amounts
still owed by the Cal ISO and the CalPX to the companies. Calculations remain uncertain because (1) the FERC has required the Cal ISO
to correct a number of defects in its calculations, (2) it is unclear what, if any, effect the ruling of the Ninth Circuit in Bonneville Power
Administration v. FERC, described below, might have on the ISO's calculations, and (3) the FERC has stated that if refunds will prevent a
seller from recovering its California portfolio costs during the Refund Period, it will provide an opportunity for a cost showing by such a
respondent. On August 8, 2005, the FERC issued an Order establishing the framework for filings by sellers who elected to make such a
cost showing. On September 14, 2005 IE and IPC made a joint cost filing, as did approximately thirty other sellers. On October 11, 2005
the California entities flied comments on the companies' cost filing and those made by other parties. IPC and IE submitted reply
comments on October 19, 2005. The California entities filed supplemental comments on October 24, 2005 and IPC and IE filed
supplemental reply comments on October 27, 2005. IPC and IE are unsure of the impact the FERC's rulings will have on the refunds due
from California. However, as to potential refunds, if any, IPC and IE believe their exposure is likely to be offset by amounts due from
California entities.
In December of 2005, IE and IPC reached a tentative agreement with the California Parties settling matters encompassed by the California
Refund proceeding including IE and IPC's cost filing and refund obligation. On January 20, 2006, the Parties flied a request with the
FERC asking that the FERC defer ruling on IE and IPC's cost filing for thirty days so the parties could complete and file the settlement
agreement with the FERe. On January 26, 2006, the FERC granted the requested deferral and required that the settlement be filed by
IFERC FORM NO.ED. 12-Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2006 2005/04
NOTES TO FINANCIAL STATEMENTS (Continued)
February 17, 2006. On February 17, 2006, IE and IPC jointly flied with the California Parties (pacific Gas & Electric Company, San Diego
Gas & Electric Company, Southem California Edison, the California Public Utilities Commission, the California Electricity Oversight
Board, the California Department of Water Resources and the California Attorney General) an Offer of Settlement at the FERc. Final
comments on the settlement are due to be filed by March 20, 2006, after which the FERC will determine whether to approve the
settlement. If the settlement is approved by the FERC, IE and IPC will assign $24.25 million of the rights to accounts receivable from the
Cal ISO and CalPX to the California Parties to pay into an escrow account for refunds to settling parties. Amounts from that escrow not
used for settling parties and $1.5 million of the remaining IE and IPC receivables which are to be retained by the CalPX are available to
fund, at least partially, payment of the claims of any non-settling parties if they prevail in the remaining litigation of this matter.
Approximately $10.25 million of the remaining IE and IPC receivables are to be released to IE and IPc. In the fourth quarter of 2005 IE
reduced by $9.5 million to $32 million its reserve against these receivables.
, along with a number of other parties, filed an application with the FERC on .-\pril 25, 2003 seeking rehearing of the March 26, 2003
order. On October 16 2003, the FERC issued two orders denying rehearing of most contentions that had been advanced and directing the
Cal ISO to prepare its compliance filing calculating revised :Mitigated Market Clearing Prices and refund amounts within five months. The
Cal ISO has since, on a number of occasions, requested additional time to complete its compliance filings. This Cal ISO compliance filing
has been delayed until at least March 2006. The Cal ISO is required to update the FERC on its progress monthly.
On December 2, 2003, IE petitioned the U.S. Court of Appeals for the Ninth Circuit for review of the FERC's orders , and since that time
dozens of other petitions for review have been filed. The Ninth Circuit consolidated IE's and the other parties' petitions with the petitions
for review arising from earlier FERC orders in this proceeding, bringing the total number of consolidated petitions to more than 100. The
Ninth Circuit held the appeals in abeyance pending the disposition of the market manipulation claims discussed below and the
development of a comprehensive plan to brief this complicated case. Certain parties also sought further rehearing and clarification before
the FERc. On September 21, 2004, the Ninth Circuit convened case management proceedings, a procedure reserved to help organize
complex cases. On October 22, 2004, the Ninth Circuit severed a subset of the stayed appeals in order that briefing could commence
regarding cases related to: (1) which parties are subject to the FERC's refund jurisdiction under section 201(f) of the Federal Power Act; (2)
the temporal scope of refunds under section 206 of the Federal Power Act; and (3) which categories of transactions are subject to refunds.
Oral argument was held on April 12-, 2005. On September 6, 2005 the Ninth Circuit issued its decision in one of the severed cases
Bonneville Power Administration v. FERc. In that decision, the Ninth Circuit concluded that the FERC lacked refund authority over
wholesale electric energy sales made by governmental entities and non-public utilities. The time for requests for rehearing was to expire on
October 21 , 2005, but has been extended until 45 days after the Ninth Circuit issues its decision in the other severed cases. The companies
cannot predict whether rehearing will be sought and, if sought, whether it will be granted or what action the FERC might take if the matter
is remanded.
On May 12, 2004, the FERC issued an order clarifying portions of its earlier refund orders and, among other things, denying a proposal
made by Duke Energy North America and Duke Energy Trading and Marketing (and supported by IE) to lodge as evidence a contested
settlement in a separate complaint proceeding, California Public Utilities Commission (CPUC) v. EI Paso, et aL The CPUC's complaint
alleged that the EI Paso companies manipulated California energy markets by withholding pipeline transportation capacity into California in
order to drive up natural gas prices immediately before and during the California energy crisis in 2000-2001. The settlement will result in
the payment by El Paso of approximately $1.69 billion. Duke claimed that the relief afforded by the settlement was duplicative of the
remedies imposed by the FERC in its l\Iarch 26, 2003 order changing the gas cost component of its refund calculation methodology. IE
along with other parties, has sought rehearing of the May 12 2004 order. On November 23, 2004, the FERC denied rehearing and within
the statutory time allowed for petitions, a number of parties, including IE, filed petitions for review of the FERC's order with the Ninth
Circuit. These petitions have since been consolidated with the larger number of review petitions in connection with the California refund
proceeding.
In June 2001 , IPC transferred its non-utility wholesale electricity marketing operations to IE. Effective with this transfer, the outstanding
receivables and payables with the CalPX and the Cal ISO were assigned from IPC to IE. At December 31, 2005, with respect to the CalPX
chargeback and the California refund proceedings discussed above, the CalPX and the Cal ISO owed $14 million and $30 million
respectively, for energy sales made to them by IPC in November and December 2000. IE has accrued a reserve of $32 million against
these receivables. This reserve was calculated taking into account the uncertainty of collection given the California energy situation. Based
on the reserve recorded as of December 31 , 2005, IDACORP believes that the future collectibility of these receivables or any potential
refunds ordered by the FERC would not have a material adverse effect on its consolidated fUlancial position, results of operations or cash
flows.
On March 20, 2002, the California Attorney General filed a complaint with the FERC against various sellers in the wholesale power market
IFERC FORM NO.1 (ED. 12-88)Page 123.
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(1) ~ An Original (Mo, Da, Yr)
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NOTES TO FINANCIAL STATEMENTS (Continued)
including IE and IPC, alleging that the FERC's market-based rate requirements violate the Federal Power .\ct, and, even if the
market-based rate requirements are valid, that the quarterly transaction reports filed by sellers do not contain the transaction,specific
information mandated by the Federal Power Act and the FERc. The complaint stated that refunds for amounts charged between
market-based rates and cost-based rates should be ordered. The FERC denied the challenge to market-based rates and refused to order
refunds, but did require sellers, including IE and IPC, to refile their quarterly reports to include transaction-specific data. The Attorney
General appealed the FERC's decision to the U.S. Court of .\ppeals for the Ninth Circuit. The Attorney General contends that the failure
of all market-based rate authority sellers of power to have rates on file with the FERC in advance of sales is impermissible. The Ninth
Circuit issued its decision on September 9 2004, concluding that market-based tariffs are permissible under the Federal Power Act, but
remanded the matter to the FERC to consider whether the FERC should exercise remedial power (including some form of refunds) when
a market participant failed to submit reports that the FERC relies on to confirm the justness and reasonableness of rates charged. Certain
parties to the litigation have sought rehearing. The companies cannot predict whether rehearing will be granted or what action the FERC
might take if the matter is remanded.
On May 26, 2005 the California Parties flied a motion to lodge additional evidence, primarily audiotapes produced by Enron employees, in
the California Refund Proceedings in Docket No. ELOO-95. A number of parties, including IDACORP, answered in opposition to that
motion.
Market Manipulation:
In a November 20, 2002 order, the 'FERC permitted discovery and the submission of evidence respecting market manipulation by various
sellers during the western power crises of 2000 and 2001.
On March 3, 2003, the California Parties (certain investor owned utilities, the California Attorney General, the California Electricity
Oversight Board and the CPUC) filed voluminous documentation asserting that a number of wholesale power suppliers, including IE and
IPC, had engaged in a variety of forms of conduct that the California Parties contended were impermissible. Although the contentions of
the California Parties were contained in more than 11 compact discs of data and testimony, approximately 12 000 pages, IE and IPC were
mentioned only in limited contexts with the overwhelming majority of the claims of the California Parties relating to the conduct of other
parties.
The California Parties urged the FERC to apply the precepts of its earlier decision, to replace actual prices charged in every hour starting
May 1, 2000 through the beginning of the existing Refund Period with a l\fitigated Market Clearing Price, seeking approximately $8 billion
in refunds to the Cal ISO and the CalPX On March 20, 2003, numerous parties, including IE and IPC, submitted briefs and responsive
testimony.
In its March 26, 2003 order, discussed above in "California Refund " the FERC declined to generically apply its refund determinations to
sales by all market participants, although it stated that it reserved the right to provide remedies for the market against parties shown to have
engaged in proscribed conduct.
On June 25, 2003, the FERC ordered over 50 entities that participated in the western wholesale power markets between January 1 2000
and June 20, 2001 , including IPC, to show cause why certain trading practices did not constitute gaming or anomalous market behavior in
violation of the Cal ISO and the CalPX Tariffs. The Cal ISO was ordered to provide data on each entity s trading practices within 21 days
of the order, and each entity was to respond explaining their trading practices within 45 days of receipt of the Cal ISO data. IPC submitted
its responses to the show cause orders on September 2 and 4, 2003. On October 16, 2003, IPC reached agreement with the FERC Staff on
the two orders commonly referred to as the "gaming" and "partnership" show cause orders. Regarding the gaming order, the FERC Staff
determined it had no basis to proceed with allegations of false imports and paper trading and IPC agreed to pay $83 373 to setde allegations
of circular scheduling. IPC believed that it had defenses to the circular scheduling allegation but determined that the cost of setdement was
less than the cost of litigation. In the settlement, IPC did not admit any wrongdoing or violation of any law. With respect to the
partnership" order, the FERC Staff submitted a motion to the FERC to dismiss the proceeding because materials submitted by IPC
demonstrated that IPC did not use its "parking" and "lending" arrangement with Public Service Company of New Mexico to engage in
gaming" or anomalous market behavior ("partnership ). The "gaming" setdement was approved by the FERC on March 3, 2004. Eight
parties have requested rehearing of the FERC's March 3 , 2004 order, but the FERC has not yet acted on those requests. The motion to
dismiss the "partnership" proceeding was approved by the FERC in an order issued on January 23, 2004 and rehearing of that order was
not sought within the time allowed by statute. Some of the California Parties and other parties have petitioned the u.s. Court of Appeals
for the Ninth Circuit and the District of Columbia Circuit for review of the FERC's orders initiating the show cause proceedings. Some
the parties contend that the scope of the proceedings initiated by the FERC was too narrow. Other parties contend that the orders
initiating the show cause proceedings were impermissible. Under the rules for multidistrict litigation, a lottery was held and although these
IFERC FORM NO.1 (ED. 12-Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2006 2005/04
NOTES TO FINANCIAL STATEMENTS (Continued)
cases were to be considered in the District of Columbia Circuit by order of February 10, 2005, the District of Columbia Circuit transferred
the proceedings to the Ninth Circuit. The FERC had moved the District of Columbia Circuit to dismiss these petitions on the grounds of
prematurity and lack of ripeness and finality. The transfer order was issued before a ruling from the District of Columbia Circuit and the
motions, if renewed, will be considered by the Ninth Circuit. IPC is not able to predict the outcome of the judicial determination of these
1ssues.
On June 25, 2003, the FERC also issued an order instituting an investigation of anomalous bidding behavior and practices in the western
wholesale power markets. In this investigation, the FERC was to review evidence of alleged economic withholding of generation. The
FERC determined that all bids into the CalPX and the Cal ISO markets for more than $250 per i\.I\Vh for the time period May 1 , 2000
through October 1 , 2000 would be considered prima facie evidence of economic withholding. The FERC Staff issued data requests in this
investigation to over 60 market participants including IPc. IPC responded to the FERC's data requests. In a letter dated May 12, 2004, the
FERC's Office of Market Oversight and Investigations advised that it was terminating the investigation as to IPc. In March 2005, the
California Attorney General, the CPUC, the California Electricity Oversight Board and Pacific Gas and Electric Company sought judicial
review in the Ninth Circuit of the FERC's termination of this investigation as to IPC and approximately 30 other market participants. IPC
has moved to intervene in these proceedings. On April 25, 2005, Pacific Gas and Electric Company sought review in the Ninth Circuit of
another FERC order in the same docketed proceeding confirming the agency s earlier decision not to allow the participation of the
California Parties in what the FERC characterized as its non-public investigative proceeding.
The February 17, 2006 Offer of Settlement, if approved by the FERC, would terminate the investigations the FERC initiated without
finding of wrongdoing by IE or IPC, and would provide for the disposition of the " gaming" settlement.
Pacific Northwest Refund:
On July 25, 2001 , the FERC issued an order establishing another proceeding to explore whether there may have been unjust and
unreasonable charges for spot market sales in the Pacific Northwest during the period December 25, 2000 through June 20, 2001. The
FERC Administrative Law Judge submitted recommendations and findings to the FERC on September 24, 2001. The Administrative Law
Judge found that prices should be governed by the Mobile-Sierra standard of the public interest rather than the just and reasonable
standard, that the Pacific Northwest spot markets were competitive and that no refunds should be allowed. Procedurally, the
Administrative Law Judge s decision is a recommendation to the commissioners of the FERc. Multiple parties submitted comments to the
FERC with respect to the AdmIDistrative Law Judge s recommendations. The Administrative Law Judge s recommended fmdings had been
pending before the FERC, when at the request of the City of Tacoma and the Port of Seattle on December 19, 2002, the FERC reopened
the proceedings to allow the submission of additional evidence related to alleged manipulation of the power market by Enron and others.
As was the case in the California refund proceeding, at the conclusion of the discovery period, parties alleging market manipulation were to
submit their claims to the FERC and responses were due on March 20, 2003. Grays Harbor, whose civil litigation claims were dismissed, as
noted above, intervened in this FERC proceeding, asserting on March 3, 2003 that its six-month forward contract, for which performance
had been completed, should be treated as a spot market contract for purposes of the FERC's consideration of refunds and is requesting
refunds from IPC of $5 million. Grays Harbor did not suggest that there was any misconduct by IPC or IE. The companies submitted
responsive testimony defending vigorously against Grays Harbor s refund claims.
In addition, the Port of Seattle, the City of Tacoma and the City of Seattle made filings with the FERC on March 3, 2003 claiming that
because some market participants drove prices up throughout the west through acts of manipulation, prices for contracts throughout the
Pacific Northwest market should be re-set starting in May 2000 using the same factors the FERC would use for California markets.
Although the majority of these claims are generic, they named a number of power market suppliers, including IPC and IE, as having used
parking services provided by other parties under FERC-approved tariffs and thus as being candidates for claims of improperly having
received congestion revenues from the Cal ISO. On June 25, 2003, after having considered oral argument held earlier in the month, the
FERC issued its Order Granting Rehearing, Denying Request to Withdraw Complaint and Terminating Proceeding, in which it terminated
the proceeding and denied claims that refunds should be paid. The FERC denied rehearing on November 10, 2003, triggering the right to
file for review. The Port of Seattle, the City of Tacoma, the City of Seattle, the California Attorney General, the CPUC and Puget Sound
Energy, Inc. filed petitions for review in the Ninth Circuit. These petitions have been consolidated. Grays Harbor did not file a petition
for review, although it has sought to intervene in the proceedings initiated by the petitions of others. On July 21 , 2004, the City of Seattle
submitted to the Ninth Circuit in the Pacific Northwest refund petition for review a motion requesting leave to offer additional evidence
before the FERC in order to try to secure another opportunity for reconsideration by the FERC of its earlier rulings. The evidence that the
City of Seattle seeks to introduce before the FERC consisted of audio tapes of what purports to be Enron trader conversations containing
inflammatory language that have been the subject of coverage in the press. Under Section 313(b) of the Federal Power .-\ct, a court is
empowered to direct the introduction of additional evidence if it is material and could not have been introduced during the underlying
proceeding. On September 29, 2004, the Ninth Circuit denied the City of Seattle s motion for leave to adduce evidence, without prejudice
I FERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2006 2005/04
NOTES TO FINANCIAL STATEMENTS (Continued)
to renewing the request for remand in the briefIng in the Pacific Northwest refund case. Briefing was completed on May 25, 2005;
however, no date has been set for oral argument.
The companies are unable to predict the outcome of these matters.
9. STOCK-BASED COMPENSATION:
IDACORP has two employee stock-based compensation plans, the 2000 Long-Term Incentive and Compensation Plan (LTICP) and the
1994 Restricted Stock Plan (RSP). These plans are intended to align employee and shareholder objectives related to its long-term growth.
IDACORP also has one non-employee stock-based compensation plan, the Director Stock Plan (DSP). The purpose of the DSP is to
increase directors' stock ownership through stock-based director compensation.
The LTICP for officers, key employees and directors, permits the grant of nonqualified stock options, incentive stock options, stock
appreciation rights, restricted stock, restricted stock units, performance units, performance shares and other awards. The RSP permits only
the grant of restricted stock or performance-based restricted stock. At December 31 , 2005, the maximum number of shares available under
the LTICP and RSP were 1 552 802 and 74 839, respectively.
All options granted have an exercise price equal to the market price of IDACORP's stock on the date of grant. In accordance with APB
, no compensation costs have been recognized for the option awards.
IDACORP stock option transactions for shares granted to IPC employees are summarized as follows:
Outstanding, beginning of year
Granted
Exercised
Forfeited
Outstanding, end of year
Exercisable
2005
Weighted average
exercise price
32.
29.
Number
of shares
952 600 $
157 837
300
094 137 $
30.
32.
Number
of shares
886 800$
110 500
200)
(40 500
952 600$
2004
Weighted average
exercise price
32.
31.21
22.
32.
32.
559 140 $34.41 373 600$35.42
The following table summarizes information about stock options outstanding at December 31 , 2005:
Outstanding
Exercise Price Ranges
$22.92 - $31.21
$35.81 - $40.
IPC Employees
$22.92 - $31.21
$35.81 - $40.
Number
of shares
746 514
675 400
Weighted average
exercise rice
$ 26.
38.41
Weighted average
remaining
contractual life
93 years
37 years
87 years
28 years
The fair value of each option granted was estimated at the date of grant using a binomial option-pricing model with the following
assumptions:
Dividend yield
Expected stock price volatility
Risk-free interest rate
575 537
518 600
26.
38.43
2004
87%
29%
96%
IFERC FORM NO.1 (ED. 12-
2005
07%
23%
22%
Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo , Da, Yr)
Idaho Power Company I (2) A Resubmission 04/18/2006 2005/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Expected option lives
Weighted average fair value of options granted
7 years
$5.
7 years
$7.
Restricted stock grants have vesting periods up to four years. Performance share grants have a three-year vesting period with the final
award amount dependent on the attainment of cumulative EPS performance goals.
Restricted stock and performance share awards are compensatory awards and IPC accrues compensation expense, which is charged to
operations, based upon the market value of the granted shares. For 2005 and 2004 total compensation accrued under the plans was less
than $1 million annually.
IDACORP restricted stock and performance shares granted to IPC employees are summarized as follows: (These amounts are included in
the table above.
IPC
Shares outstanding - beginning of year
Shares granted
Shares forfeited
Shares issued
Shares outstanding - end of year
Weighted average fair value of current year stock grants on grant date
2005 2004
121 420 454
620 056
(25 220)(24 014)
(251)076)
183 569 121 420
29.31.15
10. BENEFIT PLANS:
Pension Plans
IPC has a noncontributory defined benefit pension plan covering most employees. The benefits under the plan are based on years of
service and the employee s final average earnings. IPC's policy is to fund , with an independent corporate trustee, at least the minimum
required under the Employee Retirement Income Security Act of 1974 (ERISA) but not more than the maximwn amount deductible for
income tax purposes. IPC was not required to contribute to the plan in 2005 and 2004 and does not expect to make a contribution in 2006.
The market,related value of assets for the plan is equal to market value.
In addition, IPC has a nonqualified, deferred compensation plan for certain senior management employees and directors. This plan was
financed by purchasing life insurance policies and investments in marketable securities, all of which are held by a trustee. The cash value of
the policies and investments exceed the projected benefit obligation of the plan but do not qualify as plan assets in the actuarial
computation of the funded status.
IPC uses a December 31 measurement date for its plans.
The following table summarizes the changes in benefit obligations and plan assets of these plans:
Pension Plan Deferred Com ensation Plan2005 2004 2005 2004
(thousands of dollars)
Change in benefit obligation:
Benefit obligation at January 1
Service cost
Interest cost
Actuarial loss (gain)
Benefits paid
Plan amendments
Benefit obli ation at December 31
Change in plan assets:
Fair value at January 1
IFERC FORM NO.1 (ED. 12-
374 333 339 121 645 870
129 809 170 358
126 437 151 312
399 626 799 225)
(13 938)(13 660)312)670)
270
406 049 374 333 723 645
356 217 335 229
Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2) A Resubmission 04/18/2006 2005/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Actual return on plan assets 774 648
Employer contributions
Benefit payments (13 938)(13 660)
Fair value at December 31 368 053 356 217
Funded status (37 996)(18 116)(42 723)(38 645)
Unrecognized actuarial loss 806 491 553 443
Unrecognized prior service cost 118 889 414 372
Unrecognized net transition liability (126)310
Net amount recognized 928 138 (27 756)(25 520)
Amounts recognized in the statement of
financial position consist of:
Prepaid (accrued) pension cost 928 138 (39 268)(36 110)
Intangible asset 414 682
\ccumulated other comprehensive income 098 908
Net amount recognized 928 138 (27 756)(25 520)
Accumulated benefit obligation 340 007 316 498 268 110
The following table shows the components of net periodic benefit cost for these plans:
Pension Plan Deferred Com ensation Plan
2005 2004 2005 2004
(thousands of dollars)
Service cost 129 809 170 358
Interest cost 126 437 151 312
Expected return on assets (29 690)(27 935)
Recognized net actuarial loss 689 878
Amortization of prior service cost 771 770 228 (361)
Amortization of transition asset (126)(263)310 613
Net periodic pension cost 210 818 548 800
Changes in the Deferred Compensation Plan minimum liability decreased other comprehensive income by $1 million in 2005, increased
other comprehensive income by $1 million in 2004.
The following table summarizes the expected future benefit payments of these plans:
Pension Plan
Deferred Compensation Plan
2006
277
165
2007
885
233
2008
988
629
2009
233
911
2010
701
092
2011-2015
120 589
653
Plan Asset Allocations: IPe's pension plan and postretirement benefit plan weighted average asset allocations at December 31 , 2005 and
2004, by asset category are as follows:
Pension Postretirement
Plan Benefits
2005 2004 2005 2004
66%69%
100
100%100%100%100%
Page 123.
Asset Category
Equity securities
Debt securities
Real estate
Other (a)
Total
IFERC FORM NO.1 (ED. 12-88)
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo , Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2006 2005/04
NOTES TO FINANCIAL STATEMENTS (Continued)
(a) The postretirement benefit plan assets are primarily life insurance contracts,
Pension Asset Allocation Policy: The target allocations for the portfolio by asset class are as follows:
Large-Cap Growth Stocks
Large-Cap Core Stocks
Large-Cap Value Stocks
Small-Cap Growth Stocks
Small-Cap Value Stocks
Cash and Cash Equivalents
12%
12%
12%
International Growth Stocks
International Value Stocks
Intermedia te- T erm Bonds
Short-Term Bonds
Core Real Estate
Venture Capital
13%
10%
Assets are rebalanced as necessary to keep the portfolio close to target allocations.
The plan s principal investment objective is to maximize total retum (defmed as the sum of realized interest and dividend income and
realized and unrealized gain or loss in market price) consistent with prudent parameters of risk and the liability profile of the portfolio.
Emphasis is placed on preservation and growth of capital along with adequacy of cash flow sufficient to fund current and future payments
to pensioners.
There are three major goals in IPe's asset allocation process:
Determine if the investments have the potential to earn the rate of return assumed in the actuarial liability calculations.
Match the cash flow needs of the plan. IPC sets cash allocations sufficient to cover the current year benefit payments and bond
allocations sufficient to cover at least five years of benefit payments. IPC then utilizes growth instruments (equities, real estate
venture capital) to fund the longer-term liabilities of the plan.
Maintain a prudent risk profile consistent with ERISA fiduciary standards.
Allowable plan investments include stocks and stock funds, investment'grade bonds and bond funds, core real estate funds, private equity
funds, and cash and cash equivalents. With the exception of real estate holdings and private equity, investments must be readily marketable
so that an entire holding can be disposed of quickly with only a minor effect upon market price. Uncovered options, short sales, margin
purchases, letter stock and commodities are prohibited.
Rate-of-return projections for plan assets are based on historical risk! return relationships among asset classes. The primary measure is the
historical risk premium each asset class has delivered versus the return on 10-year US Treasury Notes. This historical risk premium is then
added to the current yield on 10-year US Treasury Notes, and the result provides a reasonable prediction of future investment
performance. Additional analysis is performed to measure the expected range of returns, as well as worst-case and best-case scenarios.
Based on the current low interest rate environment, current rate-of-return expectations are lower than the nominal returns generated over
the past 20 years when interest rates were generally much higher.
IPe's asset modeling process also utilizes historical market returns to measure the portfolio s exposure to a "worst-case" market scenario, to
determine how much performance could vary from the expected "average" performance over various time periods. This "worst-case
modeling, in addition to cash flow matching and diversification by asset class and investment style, provides the basis for managing the risk
associated with investing portfolio assets.
Postretirement Benefits
IPC maintains a defined benefit postretirement plan (consisting of health care and death benefits) that covers all employees who were
enrolled in the active group plan at the time of retirement as well as their spouses and qualifying dependents. Effective January 1 2003
IPC amended its postretirement benefit plan. The amendment affects all employees who retire after December 31, 2002, limiting their
postretirement benefit to a fixed amount. This amendment will limit the growth of IPe's future obligations under this plan.
The net periodic postretirement benefit cost was as follows (in thousands of dollars):
Service cost
Interest cost
Expected return on plan assets
2005
392
381
486)
2004
400
974
294)
IFERC FORM NO.(ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1).2S. An Original (Mo, Da , Yr)
Idaho Power Company (2)A Resubmission 04/18/2006 2005/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Amortization of unrecognized transition obligation
Amortization of prior service cost
Recognized actuarial loss
Net periodic postretirement benefit cost
040
(535)
754
546
040
(523)
489
086
The following table summarizes the changes in benefit obligation and plan assets (in thousands of dollars):
2005 2004
Change in accumulated benefit obligation:
Benefit obligation atJanuary 1 105 090
Service cost 392 400
Interest cost 381 974
Actuarial (gain) loss 186)201
Benefits paid 934)997)
Plan Amendments 125 437
Benefit obli ation at December 31 633 105
Change in plan assets:
Fair value of plan assets at January 1 723 603
Actual return on plan assets 127 301
Employer contributions 800 577
Benefits paid 757)758)
Fair value of lan assets at December 31 893 723
Funded status (33 740)(41 382)
Unrecognized prior service cost 677)087)
Unrecognized actuarial loss 978 559
Unrecognized transition obligation 280 320
Accrued benefit obli ations included with other deferred credits 159 590
Medicare Act: The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Act) was signed into law in
December 2003 and established a prescription drug benefit, as well as a federal subsidy to sponsors of retiree health care benefit plans that
provide a prescription drug benefit that is at least actuarially equivalent to Medicare s prescription drug coverage.
The measures of accumulated postretirement benefit obligation at December 31 , 2004 and net periodic benefit cost for the years ended
December 31 , 2004 and 2003, do not reflect any amount associated with the subsidy, because IDACORP and IPC initially determined that
the effect of the Medicare Act would not be material. Regulations published on January 28, 2005 provided more flexibility in determining
actuarial equivalence to Medicare of the benefits provided by the plan than was initially estimated by IDACORP's and IPe's actuaries.
Based on these new regulations, the effect of the Medicare Act is a reduction for ID.-\CORP and IPC of $6 million to the accumulated
postretirement benefit obligation at December 31 , 2005 and $1 million to the 2005 periodic postretirement benefit cost.
The following table summarizes the expected future benefit payments of the postretirement benefit plan and expected Medicare Part D
subsidy receipts (in thousand of dollars):
2006 2007 2008 2009 2010 2001-2015
Expected benefit payments'000 200 300 400 600 100
Expected Medicare Part D
subsidy receipts 480 488 503 518 530 936
'Expected benefit payments are net of expected t\ledicare Part D subsidy receipts,
The assumed health care cost trend rate used to measure the expected cost of benefits covered by the plan was 6.75 percent in 2005 and
IFERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2006 2005/04
NOTES TO FINANCIAL STATEMENTS (Continued)
2004. A one-percentage point change in the assumed health care cost trend rate would have the following effect (in thousands of dollars):
Percentage-Pointincrease decrease
Effect on total of cost components
Effect on accumulated postretirement benefit obligation
242
397
(184)
900)
The following table sets forth the weighted, average assumptions used at the end of each year to determine benefit obligations for all
IPC-sponsored pension and postretirement benefits plans:
Discount rate
Expected long-term rate of return on assets
Rate of compensation increase
Medical trend rate
Expected working lifetime (years)
2005
8.5%
Pension
Benefits
2004
75%
8.5%
4.5%
Postretirement
Benefits2005 20046% 5.75%5% 8.5%
75%75%
The following table sets forth the weighted-average assumptions used for the end of each year to determine net periodic benefit cost for all
IPC,sponsored pension and postretirement benefit plans:
Discount rate
Expected long-term rate of return on assets
Rate of compensation increase
Medical trend rate
Expected working lifetime (years)
2005
75%
Pension
Benefits
2004
15%
8.5%
Postretirement
Benefits2005 200475% 6.15%5% 8.
75%75%
Employee Savings Plan
IPC has an Employee Savings Plan that complies with Section 401 (k) of the Internal Revenue Code and covers substantially all employees.
IPC matches specified percentages of employee contributions to the plan. Matching contributions amounted to $4 million in 2005 and
million in 2004.
Postemployment Benefits
IPC provides certain benefits to former or inactive employees, their beneficiaries and covered dependents after employment but before
retirement. These benefits include salary continuation, health care and life insurance for those employees found to be disabled under IPC's
disability plans and health care for surviving spouses and dependents. IPC accrues a liability for such benefits. In accordance with an
IPU C order, the portion of the liability attributable to regulated activities in Idaho as of December 31 , 1993, was deferred as a regulatory
asset, and amortized over a ten-year period, which ended in January 2005.
The following table summarizes postemployment benefit amounts included in IPC's consolidated balance sheets at December 31 (in
thousands of dollars):
2005
Included with regulatory assets
Included with other deferred credits 845
2004
$ 3 924
11. PROPERTY PLANT AND EQUIPMENT AND JOINTLY-OWNED PROJECTS:
The following table presents the major classifications of IPC's utility plant in service, annual depreciation provisions as a percent of average
depreciable balance and accumulated provision for depreciation for the years 2005 and 2004 (in thousands of dollars):
IFERC FORM NO.(ED. 12-88) Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da , Yr)
Idaho Power Company (2)A Resubmission 04/18/2006 2005/04
NOTES TO FINANCIAL STATEMENTS (Continued)
2005 2004
Balance Avf!. Rate Balance Avf!. Rate
Production 563 008 2.54%1,482 517 51%
Transmission 580 382 560 303
Distribution 046 880 992 248 2.59
General and Other 286 797 289 748 10.
Total in service 477 067 91%324 816 96%
Accumulated provision for depreciation 364 640)316 125)
In service - net 112 427 008 691
IPC has interests in three joindy-owned generating facilities. Under the joint operating agreements, each participating utility is responsible
for financing its share of construction, operating and leasing costs. IPC's proportionate share of direct operation and maintenance
expenses applicable to the projects is included in the Consolidated Statements of Income. These facilities, and the extent of IPC's
participation, were as follows at December 31, 2005 (in thousands of dollars):
Utility Construction Accumulated
Plant In Work in Provision for
Name of Plant Location Service Progress Depreciation
Jim Bridger Units 1-Rock Springs, WY 462 240 148 265 641 707
Boardman Boardman, OR 385 454 160
Valmy Units 1 and 2 \1VU1fiemucca ~\T 311 993 042 193 920 261
IPC's wholly-owned subsidiary, Idaho Energy Resources Co., is a joint venturer in Bridger Coal Company, which operates the mine
supplying coal to the Jim Bridger generating plant. Coal purchased by IPC from the joint venture amounted to $43 million and $47 million
in 2005 and 2004, respectively.
IPC has contracts to purchase the energy from four PURPA Qualified Facilities that are 50 percent owned by Ida-\1Vest. Power purchased
from these facilities amounted to $7 million annually in 2005 and 2004.
12. REGULATORY MATTERS:
Idaho General Rate Case
IPC filed a general rate case in October 2005, requesting the IPUC to approve an annual increase to its Idaho retail base rates of $44
million or 7.8 percent. Base rates primarily reflect IPC's cost of providing electrical service to its customers , including equipment, vehicles
and infrastructure,
On February 27 2006, IPC, the IPUC staff and representatives of customer groups flied a proposed stipulation with the IPUC that, if
approved, would settle this case. The stipulation calls for an $18.1 million increase, or 3.2 percent in IPC's annual electric rates.
approved by the IPUC, the changes in rates are expected to become effective on June 1 2006.
The rate case filing was made with six months of actual operating expenses and six months of projected expenses. The agreed to increase
in rates was lower than the requested amount primarily due to three factors: (1) 2005 actual numbers were significandy less than those
forecasted; (2) the overall rate of return agreed to was 8.1 percent compared to the 8.42 percent IPC requested (no specific return on
equity was determined); and (3) net power supply costs were kept at levels currendy existing in rates. As a result of the setdement, IPC's
overall rate of return will increase from the 7.85 percent currently authorized.
Oregon Rate Case
On September 21 , 2004, IPC filed an application with the Oregon Public Utility Commission (OPUC) to increase general rates an average
of 17.5 percent or approximately $4.4 million annually,
The OPUC issued its order on July 29, 2005 authorizing an increase of $0.6 million in annual revenues, an average of 2.37 percent. The
significant decrease from IPC's requested amount was primarily related to differences in net power supply costs , which reduced IPC's initial
rate request of $4.4 million by $2.4 million.
IFERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2006 2005/04
NOTES TO FINANCIAL STATEMENTS (Continued)
On September 26, 2005, IPC filed a complaint with the Circuit Court of Marion County, Oregon asking the court to reverse the portion of
the OPUe's general rate case order related to the determination of net power supply costs.
Deferred Power Supply Costs
IPe's deferred net power supply costs consisted of the following at December 31 (in thousands of dollars):
2005 2004
Idaho PC\ current year:
Deferral for the 2005-2006 rate year 778
Deferral for the 2006-2007 rate year 684
Irrigation Lost Revenues 290
Idaho PC\ true-up awaiting recovery:
Authorized May 2004 415
Authorized May 2005*567
Oregon deferral:
2001 costs 411 047
2005 costs 880
Total deferral 542 530
*$28 million will be recovered with interest during the 2006-2007 PC\ rate year.
Idaho: IPC has a PCA mechanism that provides for annual adjustments to the rates charged to its Idaho retail customers. These
adjustments are based on forecasts of net power supply costs, which are fuel and purchased power less off-system sales, and the true-up of
the prior year s forecast. During the year, 90 percent of the difference between the actual and forecasted costs is deferred with interest.
The ending balance of this deferral, called the true-up for the current year s portion and the true-up of the true-up for the prior years
unrecovered portions, is then included in the calculation of the next year s PC\.
On April 15, 2005, IPC filed the 2005-2006 PC\ with the IPUC with a proposed effective date of June 1 2005. The application proposed
to hold the PC\ component of customers' rates at the existing level, which is currently recovering $71 million above base rates. By IPUC
order, the 2005 - 2006 PC-\. includes $12 million in lost revenues and $2 million in related interest resulting from IPe's Irrigation Load
Reduction Program that was in place in 2001. IPC proposed to defer recovery of approximately $28 million of power supply costs, or 4.
percent, for one year to help mitigate the impacts of the increases for the Bennett Mountain Power Plant and the rate case tax settlement
adjustments, since all three were proposed to be effective June 1, 2005, The $28 million will be recovered during the 2006-2007 PC\ rate
year, and IPC will earn a two percent carrying charge on this balance. The IPUC accepted the company s PC-\. proposal.
On April 15, 2004, IPC filed its 2004-2005 PC-\. with the IPUC requesting recovery of$71 million above base rates and a proposed
effective date of June 1 , 2004. On May 25, 2004, the IPUC issued Order No. 29506 approving IPe's filing.
On May 15 2003, the IPUC issued Order No. 29243 approving IPe's 2003-2004 PC-\. filing, with a small adjustment to the original filing.
As approved, IPe's rates were adjusted to collect $81 million above 1993 base rates.
On April 15, 2002, the IPUC issued Order No. 28992 disallowing recovery of$12 million oflost revenues resulting from the Irrigation
Load Reduction Program that was in place in 2001. IPC believed that this IPUC order was inconsistent with Order No. 28699, dated May
2001 , that allowed recovery of such costs, and IPC filed a Petition for Reconsideration on May 2, 2002. On August 29, 2002, the IPUC
issued Order No. 29103 denying the Petition for Reconsideration. As a result of this order, approximately $12 million was expensed in
September 2002, IPC believed it was entitled to recover this amount and argued its position before the Idaho Supreme Court on
December 5, 2003. On March 30, 2004, the Idaho Supreme Court set aside the IPU C denial of the recovery of lost revenues and
remanded the matter to the IPUC to determine the amount oflost revenues to be recovered. On December 29, 2004, the IPUC issued
Order No. 29669 allowing IPC to recover $12 million in lost revenues and $2 million in interest. The recovery was included as part of
IPe's annual PC-\. beginning June 1 2005.
Oregon: On March 2, 2005 IPC filed for an accounting order to defer net power supply costs for the period of March 1 2005 through
February 28, 2006 in anticipation of continued low water conditions. The forecasted net system power supply costs included in this filing
was $169 million, of which $3 million related to the Oregon jurisdiction, IPC is proposing to use the same methodology for this deferral
IFERC FORM NO.(ED. 12-88) Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2006 2005/04
NOTES TO FINANCIAL STATEMENTS (Continued)
filing that was accepted in 2002 for Oregon s share ofIPe's 2001 net power supply expenses. On July 1, 2005, IPC, the OPUC staff and
the Citizen s Utility Board entered into a stipulation requesting that the OPUC accept IPe's proposed methodology. Under this
methodology, IPC will earn its Oregon authorized rate of return on the deferred balance and will recover the amount through rates in
future years, as approved by the OPUe.
IPC is also recovering calendar year 2001 excess power supply costs applicable to the Oregon jurisdiction. In two separate 2001 orders, the
OPUC approved rate increases totaling six percent, which was the maximum annual rate of recovery allowed under Oregon state law at
that time. These increases were recovering approximately $2 million annually. During the 2003 Oregon legislative session, the maximum
annual rate of recovery was raised to ten percent under certain circumstances. IPC requested and received authority to increase the
surcharge to ten percent. As a result of the increased recovery rate, which became effective on April 9, 2004, IPC is recovering
approximately $3 million annually.
Fixed-Cost Adjustment Mechanism:
On January 27, 2006, IPC filed with the IPUC for authority to implement a rate adjustment mechanism which would adjust IPe's rates
upward or downward to recover IPe's fIXed costs independent from the volume of IPe's energy sales. The filing is a continuation of an
Idaho case opened in 2004 to investigate the financial disincentives to investment in energy efficiency by IPe. The true-up mechanism
entitled "fixed-cost adjustment" (FCA) would be applicable only to residential service and small general service customers.
The fixed-cost recovery portion of IPe's revenue requirement allowed for recovery in rates would be established for these two customer
classes at the time of a general rate case. Thereafter, the FCA would provide a mechanism to true,up the collection of fixed costs to
recover the difference between the fIXed costs actually recovered through rates and the fixed costs that were allowed to be recovered.
Accounting for the FC,.\, would be effective as of January 1 , 2006, and the first FC-\ rate change would occur on June 1 2007.
The FCA is proposed to change rates coincidentally with IPe's Power Cost Adjustment (PC\) and IPe's seasonal rates. Although the FC-\
would be timed to adjust on the same schedule as the PCA, the accounting for the FCA would be separate from the PC-\. Additionally,
IPC proposes to include a three percent cap on any FC-\ filing, to be applied at the discretion of the IPUe.
Regulatory Assets and Liabilities
The following is a breakdown of IPe's regulatory assets and liabilities (in thousands of dollars):
As of December 31, 2005
As of
Remaining Not Pending December
Amortization Earning Earning Regulator 2005 , 2004
DescrI tion Period a Return a Return Treatment Total Total
Regulatory
Assets:
Income Taxes 346 117 346 344 220
Conservation 2010 592 592 836
PC-\ Deferral 2007 251 251 193
Oregon Deferral(l)291 291 047
Asset Retirement
Obligations 363 363 372
Tax Settlement
Order 2006 994 994 119
Irrigation Lost
Revenues (2)2007 290
Incremental
Security Costs 2008 575 575 813
Other Various
thru 2007 891
Total 744 354,497 418 241 438 781
IFERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2006 2005/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Regulatory Liabilities:
Income Taxes 627 627 447
Conserva tion 2007 535 535 205
-\sset Retirement
Obligations 152 683 152 683 147 700
Deferred ITC 786 786 836
IPUC Settlement
Order 2006 021 021 671
BPA Settlement 2006 393 393 833
OPUC Settlement 100
Emission
Allowance 034 034
Other Various
thru 2007
Total 979 263 096 034 345 109 275 854
(1) Capped at 10 percent increase per year.
(2) Included in PC\ amortization balance,
For further information on the asset retirement obligations amounts, see Note 14.
In the event that recovery of costs through rates becomes unlikely or uncertain, SF"\S 71 would no longer apply. HIPC were to
discontinue application of SFAS 71 for some or all of its operations, then these items may represent stranded investments. If IPC is not
allowed recovery of these investments, it would be required to write off the applicable portion of regulatory assets and the fmancial effects
could be significant.
13. INVESTMENTS:
The following table summarizes IPe's investments as of December 31 (in thousands of dollars):
IPC Investments:
Auction rate securities (available-for-sale)
Equity method investment
Available-for-sale equity securities
Executive deferred compensation
Other investments
Total IPC investments
2005 2004
650
764 028
137 505
201 002
025 808
127 993
Equity Method Investments
IPC, through its subsidiary Idaho Energy Resources Co- (IERCO), is a 33 percent owner of Bridger Coal Company, which supplies coal to
the Jim Bridger generating plant owned in part by IPC
The following table presents IPe's earnings of unconsolidated equity-method investments (in thousands of dollars):
IERCO
2005
874
2004
190
Investments in Debt and Equity Securities
Investments in debt and equity securities are accounted for in accordance with SFAS 115
, "
Accounting for Certain Investments in Debt
and Equity Securities." Those investments classified as available-for,sale securities are reported at fair value, using either specific
identification or average cost to determine the cost for computing gains or losses. Any unrealized gains or losses on available-for-sale
IFERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da , Yr)
Idaho Power Company (2)A Resubmission 04/18/2006 2005/04
NOTES TO FINANCIAL STATEMENTS (Continued)
securities are included in other comprehensive income.
IPC held $32 million of auction rate securities at December 31 2004. Auction rate securities are long-term instruments whose interest rates
or dividends are reset at specific frequencies. The typical reset periods are either 28 or 35 days. The rates or dividends are reset via a
Dutch auction. The original maturities of these securities at the time of issuance ranged from 2007 to 2042. IPC did not hold any auction
rate securities at December 31 2005.
The following table summarizes investments in debt and equity securities (in thousands of dollars):
2005 2004
Gross Gross Gross Gross
Unrealized Unrealized Fair Unrealized Unrealized Fair
Gain Loss Value Gain Loss Value
Available-for,sale
securities 925 497 137 530 256 155
The following table summarizes sales of available-for-sale securities (in thousands of dollars):
2005 2004
Proceeds from sales 120 026 266 331
Gross realized gains from sales 850 044
Gross realized losses from sales 643 634
Additionally, these investments are evaluated to determine whether they have experienced a decline in market value that is considered
other-than-temporary, IPC analyzes securities in loss positions as of the end of each reporting period. Any security with an unrealized loss
of more than 20 percent is evaluated for other-than-temporary impairment. "\ security will generally be written down to market value if it
has an unrealized loss of 20 percent or more for more than nine months. If additional information is available that indicates a security is
other-than-temporarily impaired, it will be written down prior to the nine-month time period. In the alternative, if a security has been
impaired for more than nine months but available information indicates that the impairment is temporary, the security will not be written
down. This decline is included in other income in the Consolidated Statements ofIncome. In 2005 and 2004, there were no
other-than-temporary declines in market value recorded.
The following table summarizes information regarding securities that were in an unrealized loss position at the end of each year, but for
which no other-than-temporary impairment was recognized (in thousands of dollars).
Aggregate Aggregate Aggregate Aggregate
Unrealized Related Fair Unrealized Related Fair
Loss Value Loss Value
Less than 12 months 12 months or Ion er
215 731 282 423
181 934 362
2005:
Available for sale equity securities
2004:
Available for sale equity securities
The available-for-sale equity securities in unrealized loss positions are diversified investments in common stock of various companies used
to fund IPe's Senior Management Security Plan, At December 31 , 2005, nine available-for-sale securities were in an unrealized loss
position. At December 31 , 2004, ten available-for-sale securities were in an unrealized loss position. At December 31, 2005 two
available-for-sale securities had unrealized loss positions of greater than 20 percent. Both securities exceeded 20 percent for fewer than
nine months. IPC does not consider these investments to be other-than-temporarily impaired at December 31 , 2005 or 2004.
IFERC FORM NO.1 (ED. 12-88) Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2006 2005/04
NOTES TO FINANCIAL STATEMENTS (Continued)
14. ASSET RETIREMENT OBLIGATIONS:
OnJanuary 1 2003, IPC adopted SFAS 143
, "
Accounting for Asset Retirement Obligations." This statement addresses financial
accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement
costs. An obligation may result from the acquisition, construction, development or the normal operation of a long-lived asset. SFAS 143
requires an entity to record the fair value of a liability for an asset retirement obligation (ARO) in the period in which it is incurred. When
the liability is initially recorded, the entity increases the carrying amount of the related long-lived asset to reflect the future retirement cost.
Over time, the liability is accreted to its present value and paid, and the capitalized cost is depreciated over the useful life of the related
asset. If, at the end of the asset's life, the recorded liability differs from the actual obligations paid, a gain or loss would be recognized at
that time. As a rate-regulated entity, IPC records regulatory assets and liabilities instead of accretion, depreciation and gains or losses. This
treatment was approved by Order No. 29414 from the IPUc. The regulatory assets recorded under this order do not earn a return on
mvestment.
In 2005, IPC adopted FIN 47. This Interpretation clarifies that the term "conditional asset retirement obligation," as used in FASB
Statement No. 143, refers to a legal obligation to perform an asset retirement activity in which the timing and/ or method of settlement are
conditional on a future event that mayor may not be within the control of the entity. The obligation to perform the asset retirement
activity is unconditional even though uncertainty exists about the timing and/ or method of settlement. Thus, the timing and/ or method of
settlement may be conditional on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional
ARO if the fair value of the liability can be reasonably estimated. The fair value of a liability for the conditional ARO should be recognized
when incurred-generally upon acquisition, construction, or development and/ or through the normal operation of the asset. Uncertainty
about the timing and/ or method of settlement of a conditional ARO should be factored into the measurement of the liability when
sufficient information exists. FAS 143 acknowledges that, in some cases, sufficient information may not be available to reasonably estimate
the fair value of an .\RO. The Interpretation also clarifies when an entity would have sufficient information to reasonably estimate the fair
value of an ARO.
FIN 47 became effective December 31 2005. After reviewing the provisions of FIN 47, no significant additional AROs were identified at
IPc.
The regulated operations of IPC also collect removal costs in rates for certain assets that do not have associated AROs. The adoption of
SFAS 143 required IPC to redesignate these removal costs as regulatory liabilities. As of December 31 2005, IPC had $153 million of such
costs recorded as regulatory liabilities on its Balance Sheet.
The following table presents the changes in the aggregate carrying amount of .-\ROs (in thousands of dollars):
2005 2004
Balance at beginning of year 288 140
Amount recorded on adoption
Accretion expense 531 421
Revisions in estimated cash flows 260 727
Balance at end of year 079 288
15. RELATED PARTY TRANSACTIONS:
IDACORP
IPC performs corporate functions such as fmancial, legal and management services for IDACORP and its subsidiaries. IPC charges
ID.-\CORP for the costs of these services based on service agreements and other specifically identified costs. IPC billed IDACORP $4
million in each 2005 and 2004 for these services.
IDACOMM
IPC provides project management and engineering services to IDACOJ\.ll\f. IDACOJ\.ll\I also pays joint use fees to IPc. Total fees
charged to IDACOMM were $0.3 million per year in 2005 and 2004.
IFERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2006 2005/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Ida-West
IPC purchases all of the power generated by four of Ida-West s hydroelectric projects, IPC paid $7 million per year in 2005 and 2004,
I FERC FORM NO.1 (ED. 12-Page 123.
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2005/Q4
(2)0 A Resubmission 04/18/2006
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME. AND HEDGING ACTIVITIES
1. Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate.
2. Report in columns (f) and (g) the amounts of other categories of other cash flow hedges.
3. For each category of hedges that have been accounted for as "fair value hedges , report the accounts affected and the related amounts in a footnote.
Line Item Unrealized Gains and Minimum Pension Foreign Currency Other
No.Losses on Available-Liability adjustment Hedges Adjustments
for-Sale Securities (net amount)
(a)(b)(c)(d)(e)
1 Balance of Account 219 at Beginning of
Preceding Year 676,536)305,701
2 Preceding QtrlYr to Date Reclassifications
from Acct 219 to Net Income 195,783
3 Preceding QuarterlYear to Date Changes in
Fair Value 057,039)880,135)
4 Total (lines 2 and 3)861,256)880 135)
5 Balance of Account 219 at End of
Preceding QuarterlYear 537 792)5,425,566
6 Balance of Account 219 at Beginning of
Current Year 887,773
7 Current QtrlYr to Date Reclassifications
from Acct 219 to Net Income 355,332
8 Current QuarterlYear to Date Changes in
Fair Value 182,219
9 Total (lines 7 and 8)537,551
Balance of Account 219 at End of Current
QuarterlY ear 887,773 537 551
FERC FORM NO.(NEW 06-02)Page 122a
Name of Respondent This ~ort Is: Date of Report YearlPeriod of Report
(1) ~ An Original (Mo, Da, Yr) End 2005/04Idaho Power Company (2) 0 A Resubmission 04/18/2006
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME , COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
Line
No.
Other Cash Flow
Hedges
Interest Rate Swaps
Totals for each
category of items
recorded in
Account 219
(h)
629,165
195,783
937 174)
741 391)
887 774
887 773
355,332
182,219
537 551
3,425,324
Other Cash Flow
Hedges
(Specify)
(f)
(g)
FERC FORM NO.1 (NEW 06-02)Page 122b
Net Income (Carried
Forward from
Page 117, Line 78)
Total
Comprehensive
Income
(i)
IS epo s: a e 0 epo(1) Q9AnOriginal (Mo,Da,Yr)
(2) 0 A Resubmission 04/18/2006
SUMMA Y OF UTILITY PLANT AND ACCUMULATED PROVISIONS
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Report in Column (c) the amount for electric function, in column (d) the amount for gas function, in column (e), (f), and (g) report other (specify) and in
column (f) common function.
End of
(a)
Total Company for the
Current Year/Quarter Ended
(b)
Electric
(c)
Line
No.
Classification
1 Utility Plant
2 In Service
3 Plant in Service (Classified)
4 Property Under Capital Leases
5 Plant Purchased or Sold
6 Completed Construction not Classified
7 Experimental Plant Unclassified
8 Total (3 thru 7)
9 Leased to Others
3,477 521,238 3,477 521 238
3,477,521,238 3,477 521,238
10 Held for Future Use
11 Construction Work in Progress
12 Acquisition Adjustments
13 Total Utility Plant (8 thru 12)
14 Accum Prov for Depr, Amort, & Depl
15 Net Utility Plant (13 less 14)
16 Detail of Accum Prov for Depr, Amort & Depl
17 In Service:
18 Depreciation
19 Amort & Depl of Producing Nat Gas Land/Land Right
20 Amort of Underground Storage Land/Land Rights
21 Amort of Other Utility Plant
22 Total In Service (18 thru 21)
23 Leased to Others
906,206
149,814,313
454,449
629,787,308
364 640,116
265,147,192
906 206
149,814 313
454,449
629 787,308
364 640 116
265,147 192
,---------
24 Depreciation
25 Amortization and Depletion
26 Total Leased to Others (24 & 25)
27 Held for Future Use
28 Depreciation
29 Amortization
30 Total Held for Future Use (28 & 29)
31 Abandonment of Leases (Natural Gas)
32 Amort of Plant Acquisition Adj
33 Total Accum Prov (equals 14) (22 30,32)
304 858
364,640,116
304 858
364 640 116
FERC FORM NO.1 (ED. 12-89)Page 200
Name of Respondent
Idaho Power Company
Gas
This Report Is: Date of Report
(1) I!JAn Original (Mo, Da, Yr)
(2) D A Resubmission 04/18/2006
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Other (Specify) Other (Specify) Other (Specify)
Year/Period of Report
End of 2005/04
Common
----~
(d)(e)(f)
(g)
(h)
Line
No.
-~ ----------~
FERC FORM NO.1 (ED. 12-89)Page 201
Name of Respondent This Report Is:Date of Report Year/Period of Report
Idaho Power Company (1) (!IAn Original (Mo, Da, Yr)End of 2005/04
(2)0 A Resubmission 04/18/2006
ELECTRIC PLANT IN SERVICE (Account 101,102,103 and 106)
1. Report below the original cost of electric plant in service according to the prescribed accounts.
2. In addition to Account 101, Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant Purchased or Sold;
Account 103, Experimental Electric Plant Unclassified; and Account 106, Completed Construction Not Classified-Electric.
3. Include in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year.
4. For revisions to the amount of initial asset retirement costs capitalized, included by primary plant account, increases in column (c) additions and
reductions in column (e) adjustments.
5. Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such accounts.
6. Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in column (c). Also to be included
in column (c) are entries for reversals of tentative distributions of prior year reported in column (b). Likewise, if the respondent has a significant amount
of plant retirements which have not been classified to primary accounts at the end of the year, include in column (d) a tentative distribution of such
retirements, on an estimated basis, with appropriate contra entry to the account for accumulated depreciation provision. Include also in column (d)
Line Account
No.Beginning of Year
(a)(b) (c)
1. INTANGIBLE PLANT
(301) Organization 703 62,527
(302) Franchises and Consents 10,169,022 848,216
(303) Miscellaneous Intangible Plant 66,579,839 038,091
TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)76,754,564 13,948,834
2. PRODUCTION PLANT
A. Steam Production Plant
(310) Land and Land Rights 282,073 88,246
(311) Structures and Improvements 130,003,136 430,783
(312) Boiler Plant Equipment 476,487,554 18,603,255
(313) Engines and Engine-Driven Generators
(314) Turbogenerator Units 116,615,282 001,952
(315) Accessory Electric Equipment 61,106,974 69,847
(316) Misc. Power Plant Equipment 12,692,624 629,769
(317) Asset Retirement Costs for Steam Production 775,120 858,214
TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)800,962 763 26,682,066
B. Nuclear Production Plant
(320) Land and Land Rights
(321) Structures and Improvements
(322) Reactor Plant Equipment
(323) Turbogenerator Units
(324) Accessory Electric Equipment
(325) Misc. Power Plant Equipment
(326) Asset Retirement Costs for Nuclear Production
TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24)
C. Hydraulic Production Plant
(330) Land and Land Rights 935 723 256
(331) Structures and Improvements 129 090 704 003 010
(332) Reservoirs, Dams, and Waterways 243,405,546 592,572
(333) Water Wheels, Turbines, and Generators 185,352,429 335,134
(334) Accessory Electric Equipment 36,199,922 291 218
(335) Misc. Power PLant Equipment 14,166,220 678,800
(336) Roads, Railroads, and Bridges 950,430
(337) Asset Retirement Costs for Hydraulic Production
TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34)629,100,974 902,990
D. Other Production Plant
(340) Land and Land Rights 219,037 183,708
(341) Structures and Improvements 207,423 131 377
(342) Fuel Holders, Products, and Accessories 676,666 842 209
(343) Prime Movers 765,800 28,604 602
(344) Generators 43,894 011 17,046,301
(345) Accessory Electric Equipment 177 547 502 829
(346) Misc. Power Plant Equipment 512,876
FERC FORM NO.1 (REV. 12-03)Page 204
Name of Respondent
Idaho Power Company
YearlPeriod of Report
End of 2005/04
This Report Is: Date of Report(1) ~AnOriginal (Mo, Da, Yr)
(2) DA Resubmission 04/18/2006
ELECTRIC PLANT IN SERVICE (Account 101,102 103 and 106) (Continued)
distributions of these tentative classifications in columns (c) and (d), including the reversals of the prior years tentative account distributions of these
amounts. Careful observance of the above instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount of
respondent's plant actually in service at end of year.
7. Show in column (f) reclassifications or transfers within utility plant accounts. Include also in column (f) the additions or reductions of primary account
classifications arising from distribution of amounts initially recorded in Account 102, include in column (e) the amounts with respect to accumulated
provision for depreciation, acquisition adjustments, etc., and show in column (f) only the offset to the debits or credits distributed in column (f) to primary
account classifications.
8. For Account 399, state the nature and use of plant included in this account and if substantial in amount submit a supplementary statement showing
subaccount classification of such plant conforming to the requirement of these pages.
9. For each amount comprising the reported balance and changes in Account 102, state the property purchased or sold, name of vendor or purchase,
and date of transaction. If proposed journal entries have been filed with the Commission as required by the Uniform System of Accounts, give also dateRetirements Adjustments Transfers Balance at Line
End ?J)Year No.
620,693
20,339,949
20,960,642
68,230
19,396,545
50,277 981
69,742,756
40,709
535,903
370,319
130,393,210
493,554 906
112,068
352
379,322
122 505,166
129,469
943,071
633 334
825 529,475115,354
507
28,652
924,472
130 044 154
243 998 118
185 687 563
36,464 633
816,368
950,430
13,507
49,560
118,226 631,885 738
171,473
402,745
338,800
518 875
29,370,402
60,940,312
680 376
341,403
FERC FORM NO.1 (REV. 12-03)Page 205
Name of Respondent This Report Is:Date of Report Year/Period of Report
Idaho Power Company (1) Q9An Original (Mo, Da, Yr)End of 2005/04
(2)0 A Resubmission 04/18/2006
ELECTRIC PLANT IN SERVICE (Account 101 102 103 and 106) (Continued)
Line Account Balance Additions
No.Beginning of Year
(a)(b)(c)
(347) Asset Retirement Costs for Other Production
TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44)52,453,360 311,026
TOTAL Prod. Plant (Enter Total of lines 16,25, 35, and 45)1,482,517,097 83,896,082
3. TRANSMISSION PLANT
(350) Land and Land Rights 22,409,168 2,462,366
(352) Structures and Improvements 307 239 839,179
(353) Station Equipment 228,308,784 12,798,478
(354) Towers and Fixtures 76,573,247 788,332
(355) Poles and Fixtures 89,925,076 844 357
(356) Overhead Conductors and Devices 111,461,261 4,495,795
(357) Underground Conduit
(358) Underground Conductors and Devices
(359) Roads and Trails 318,351
(359.1) Asset Retirement Costs for Transmission Plant
TOTAL Transmission Plant (Enter Total of lines 48 thru 57)560,303,126 27,228.507
4. DISTRIBUTION PLANT
(360) Land and Land Rights 3,444,009 704,212
(361) Structures and Improvements 722,119 178,329
(362) Station Equipment 129,850,071 530,868
(363) Storage Battery Equipment
(364) Poles, Towers, and Fixtures 185,762,953 005,448
(365) Overhead Conductors and Devices 94,136,122 858,254
(366) Underground Conduit 39,213,897 535,196
(367) Underground Conductors and Devices 147,815,584 688,731
(368) Line Transformers 272,981 978 25,057 535
(369) Services 46,412 203 506,649
(370) Meters 47,456,634 4,465,727
(371) Installations on Customer Premises 2,483,682 123 267
(372) Leased Property on Customer Premises
(373) Street Lighting and Signal Systems 968 946 101 932
(374) Asset Retirement Costs for Distribution Plant
TOTAL Distribution Plant (Enter Total of lines 60 thru 74)992,248,198 756 148
5. GENERAL PLANT
(389) Land and Land Rights 562,258 571
(390) Structures and Improvements 60,206,722 399,785
(391) Office Furniture and Equipment 007,353 192 812
(392) Transportation Equipment 43,831,169 823,363
(393) Stores Equipment 006,913 23,859
(394) Tools, Shop and Garage Equipment 832,595 427 676
(395) Laboratory Equipment 230 030 307,002
(396) Power Operated Equipment 324 623 080,983
(397) Communication Equipment 100,726 805 565
(398) Miscellaneous Equipment 344,859 328,900
SUBTOTAL (Enter Total of lines 77 thru 86)213,447,248 13,431 516
(399) Other Tangible Property
(399.1) Asset Retirement Costs for General Plant
TOTAL General Plant (Enter Total oflines 87, 88 and 89)213 447,248 13,431 516
TOTAL (Accounts 101 and 106)325,270,233 203,261 087
(102) Electric Plant Purchased (See Instr. 8)
(Less) (102) Electric Plant Sold (See Instr. 8)
(103) Experimental Plant Unclassified
TOTAL Electric Plant in Service (Enter Total of lines 91 thru 94)325,270,233 203,261 087
FERC FORM NO.1 (REV. 12-03)Page 206
Name of Respondent
Idaho Power Company
Retirements
(d)
Year/Period of Report
End of 2005/Q4
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) 0 A Resubmission 04/18/2006
ELECTRIC PLANT IN SERVICE (Account 101 102,103 and 106) (Continued)Adjustments Transfers Balance at
End 9f Year00
171,473
3,405,053
63,565
11,613
258,014
152
568,129
181,484
149,957
389
915,843
313,589
743,922
138,568
642,799
353,657
358,959
533,378
46,653
098
10,123,855
231 812
576,917
123,846
57,011
94,926
276,735
142,602
815,773
50,953
370,575
370,575
010,082
51,010,082
105 592,913
563,008,126
807 969
33,134 805
235,849,248
79,294,427
201 304
114,775,572
318,351
580,381,676
148,221
19,894 059
138,465,096
190,454,812
96,250,454
41,610,525
153,861 516
293,685,856
48,559,893
50,388,983
560 296
000,780
046,880,491
603,829
374 695
49,623,248
530,686
973,761
165,345
260,297
263,004
090 518
622 806
217,508,189
217 508 189
3,477 521,238
3,477,521,238
Line
No.
FERC FORM NO.1 (REV. 12-03)Page 207
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2005/04
This Report Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) 0 A Resubmission 04/18/2006
ELECTRIC PLANT HELD FOR FUTURE USE (Account 105)
1. Report separately each property held for future use at end of the year having an original cost of $250,000 or more. Group other items of property held
for future use.
2. For property having an original cost of $250,000 or more previously used in utility operations, now held for future use, give in column (a), in addition to
other required information, the date that utility use of such property was discontinued, and the date the original cost was transferred to Account 105,Line DescriJJtion and Location Date Originally Included Date Expected to be used Balance atNo Of Property in This Account in UtilitY Service End of Year(b) (c) (d)
1 Land and Rights:
2 Boise Operations Center
3 Production
4 Transmission Stations
5 Transmission Lines
6 Distribution Stations
12/31/82 768,377
224,961
360,819
73,987
099,877
10 Boise Operations Center
11 Boise Mechanical and Electrical Shop
12 Transmission Stations
13 Distribution Stations
12/31/82
12/31/01
12/31/81
72,785
47,000
178,094
306
19 Column B if no date listed it is various
21 Other Property:
47 Total 906,206
FERC FORM NO.1 (ED. 12-96)Page 214
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2005/Q4
(2)D A Resubmission 04/18/2006
CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
1. Report below descriptions and balances at end of year of projects in process of construction (107)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $100,000, whichever is less) may be grouped.
Line Description of Project Construction work in progress -
No.Electric (Account 107)
(a)(b)
ROLLUP RELIC COST BROWNLEE 824 175
ROLLUP RELIC COST HELLS CANYON 19,159,112
ROLLUP RELIC COST OXBOW 680,393
DALY CREEK PROPERTY ACQUISITIO 728,032
HELLS CANYON RELICENSING OUTSI 018,846
KINPORT CONDENSER REPAIR 3,455,692
LINE 470 HRFT-STKY 138 KV 795,293
NAMPA - ADD 230KV TRANSFORMER 749,836
BRIDGER UNDISTRIBUTED WORK ORD 675,648
CIAC LIABILITY RECLASS 569,896
WOOD RIVER VALLEY OPERATIONS C 2,441,599
LINE #470, 2ND 138KV LINE TO M 379,559
VALMY UNDISTRIBUTED WORK ORDER 276,735
STKY 138KV SWITCHING STATION 910,705
EKRT - BUILD NEW 138-34.5 KV E 708,083
EMS/ADVANCED APPLICATION PROJE 607,994
AP ACCRUAL ESTIMATE 565,176
TERR HELLS CANYON RELICENSING-280,278
PAHSIMEROI HATCHERY EXPANSION 278,468
COTTONWOOD PROPERTY ACQUISITIO 167,240
ADEL UPGRADE AFTS LINE TERMINA 163,230
HCC ENGINEERING RELICESNING ST 154,093
HCC RELICENSING FISH2004 FEASI 143,982
HTSU ADD BORA & MPSN 230KV LlN 138,174
SNMW0401 EQUIP OLD QWEST SITE 121,467
VALMY 32247 COAL CAR THAW STAT 108,169
NAMPA TAP ROW ACQUISITION 086,814
WQ ONGOING HELLS CANYON RELICE 073,692
342 COST CENTER DELIVERY CAPIT 978,822
BORAH - NEW 345KV, 150 MVAR CA 942,878
CUMW EQUIP OLD QWEST SITE 905,823
BRIDGER 2006CO02 REWIND U1 MAl 899,144
MIDPOINT - NEW 345KV, 175 MVAR 893,973
REL-HELLS CANYON COMPLEX FY200 855,238
BOARDMAN UNDISTRIBUTED WORK OR 751 638
HAPPY VALLEY SUBSTATION 724 182
RELICENSING: HCC SEDIMENT & GE 707 009
MEGG-SQCK REBUILD TO 4/0 AC 697 780
HCC SUPPORT 696,287
CAPITALIZED SPARE PARTS 2004 D 620,872
LINE 722, CONSTRUCT NEW BORAH-583,305
VALMY 31818 U1 DCS UPGRADE PRO 565,387
TOTAL 149,814 313
FERC FORM NO.1 (ED. 12-S7)Page 216
Name of Respondent This (!Jort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2005/04
(2)0 A Resubmission 04/18/2006
CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
1. Report below descriptions and balances at end of year of projects in process of construction (107)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3. Minor projects (5% of the Balance End ofthe Year for Account 107 or $100,000, whichever is less) may be grouped.
Line Description of Project Construction work in progress -
No.Electric (Account 107)
(a)(b)
418-CC DELIVERY CAPITAL OVERHE 551 124
WM-HELLS CANYON CONTINUED STUD 549,373
Line 722, ROW/Easements 537,602
IPCO- 2005 BOISE DOWNTOWN CAPT 495,841
IPCO-KARCHER RD EXIT RELOCATIO 492,447
REL-HCC SEDIMENTATION STUDIES 487,106
COST CENTER 316 DELIVERY CAP IT 459,709
FSH-DEV. WHITE STURGEON CONSER 457,439
HCC RELICENSING, FISH2004 REDB 444 903
HELLS CANYON COMPLEX 432,876
HCC RESERVOIR/DISCHARGE WO 424 350
390 COST CENTER DELIVERY CAPIT 424 232
HELLS CANYON RELICENSING 418,514
RIGHT OF WAY, LINE 470, HORSE 416,925
336-COST CENTER DELIVERY CAPIT 412,839
HCC RELICENSING, FISH2004 ANAD 401 609
LINE #438 CDAL-LCST IMPROVE RO 393,385
FISH-HCC-REDBAND TROUT/BULL TR 390,502
CONSTRUCTION ACCOUNTING CAPITA 386,353
360 COST CENTER DELIVERY CAP IT 364 137
FISH-HELLS CANYON INSTREAM FLO 361,010
BRIDGER 2006CO05 REFURBISH U2 340,221
WM STREAMFLOW FORECAST MODEL P 334,318
343 COST CENTER DELIVERY CAPIT 330,974
410-CC DELIVERY CAPITAL OVERHE 330,892
HAILEY TEAM CAP OH WORK ORDER 317 292
415-CC DELIVERY CAPITAL OVERHE 315,513
VALMY 31647 NUCLEAR COAL ANAL Y 306,143
IPCO-CSCD-013 REBUILD FROM CAS 306 125
LINE 441 MODIFICATION FOR LlNE4 298,314
IPCO-CSCD-011 REBUILD SOUTH AR 297,482
BSU SECOND FEEDER-INSTALL SECO 296,414
REL-HCC OREGON REAUTHORIZATION 296,119
SERVER CONSOLIDATION 295,064
BRIDGER 2005C013 REVERSE OSMOS 293,422
CALL CENTER LABOR HOURS FOR LI 293,386
324-COST CENTER DELIVERY CAPIT 289,597
REL - SWAN FALLS FY2004 CAPITA 285,136
HTSU0101 REPLACE C131 CAP BANK 283,000
INTRUSION DETECTION SYSTEM UPD 281 542
UNIT 6711-6X6 57-72' MAT HANDL 281,304
MPSN REPLACE RELAYING ON MPSN-276,841
TOTAL 149,814,313
FERC FORM NO.1 (ED. 12-87)Page 216.
Name of Respondent This
wort
Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2005/04
(2)0 A Resubmission 04/18/2006
CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
1. Report below descriptions and balances at end of year of projects in process of construction (107)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $100,000, whichever is less) may be grouped.
Line Description of Project Construction work in progress -
No.Electric (Account 107)
(a)(b)
BRIDGER 2006C010 U1 SUBMERGED 276,685
PAYROLL & IBNR ACCRUAL 276,639
STORAGE GROWTH 276 203
BARBER FLATS LAND SWAP-OXBOW 275 852
BRIDGER 2004C027 UPGRADE GREEN 275,815
LEGAL DEPT LABOR: HELLS CANYON 273,154
HCC RELICENSING, FISH2004 INST 272 897
Delivery Overheads 269 832
578 COST CENTER DELIVERY CAPIT 269 053
OXMW04011NSTALL RADIO & TOWER 268 104
RELICENSING: SWAN FALLS 266,487
ST AL'S - INSTALL DUCT VAULT S 262 276
WO-HCC TMDU401-2003-CAPIT AL 258,575
REL HCC BAKER COUNTY SETTLEMEN 258 505
TAMARACK RESORT -WHITEWA TER SUB 251,878
CAPITAL OVERHEADS FOR CADD & A 249 923
IPCO/HAL 015/F-18 TO IC-12 -240,371
FISH-HCC-ANADROMOUS FISH BELOW 236,453
HCPR0501 UWAVE RADIO & ANT 234 068
392 COST CENTER DELIVERY CAPIT 233,596
SWAN FALLS RELICENSING 232,490
404 COST CENTER DELIVERY CAPIT 232 001
DEVCON CONST -SERVICE FOR NEW B 231 246
FIR GROVE ESTATES-121 LOT SUBD 230 711
COST CENTER 317 DELIVERY CAPIT 230,548
COST CENTER 310 DELIVERY CAPIT 230,266
577 COST CENTER DELIVERY CAPIT 227,446
NEW UNIT 6707-LlNEBED COC 224,583
100-COST CENTER DELIVERY CAPIT 221,959
REC-HCC RELICENSING PROCESS 214,597
LN 426, EMERGENCY REPAIRS CAUS 212 827
370 -COST CENTER DELIVERY CAPI 210 053
GOODING TEAM CAP OH WORK ORDER 209 661
575 COST CENTER DELIVERY CAPIT 209,367
METER MTF WO FOR NEW INSTALLAT 203,466
ADAMSFAM TEAM CAP OH WORK ORDE 201,428
POPULATION VIABILITY MODEL - 0 199,810
BOISE BENCH - KING 138 KV LINE 198,349
420-CC DELIVERY CAPITAL OVERHE 198 002
TWINWEST TEAM CAP OH WORK ORDE 196,058
335-COST CENTER DELIVERY CAPIT 195 903
334-COST CENTER DELIVERY CAPIT 194 956
TOTAL 149,814 313
FERC FORM NO.1 (ED. 12-87)Page 216.
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Idaho Power Company
(1) An Original (Mo, Da, Yr)End of 2005/Q4
(2)0 A Resubmission 04/18/2006
CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
1. Report below descriptions and balances at end of year of projects in process of construction (107)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research. Development, and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $100 000, whichever is less) may be grouped.
Line Description of Project Construction work in progress -
No.Electric (Account 107)
(a)(b)
FISH HELLS CANYON RELICENSING 194 687
COST CENTER 320 DELIVERY CAPIT 194,439
IPCO/STAR-013/UNDERBUILD EAGL-191,453
LINE 438, RIGHT OF WAY, VICTOR 189 236
TOOL EXP TRANS TO CONST 188,428
RELOCATE ON POLELINE RD IN TWI 186,721
HCC RELICENSING FISH2004 RESID 186,515
326-COST CENTER DELIVERY CAPIT 185,880
NEW UNIT 6706-55' BUCKET - COC 183 708
WILS SUBSTATION CONSTRUCTION 182,677
EDEN - REPLACE 101Z & 102Z 181 092
ENVIRONMENTAL DATABASE - 2005 180,213
COST CENTER 318 DELIVERY CAPIT 179,512
NEW UNIT 6719 (CC 345) ADDL CR 178,660
PQ AG DSR LAB EQUIPMENT-ION 176,203
KING - REPLACE PCB SHUNT CAPAC 173,613
327-COST CENTER DELIVERY CAPIT 172 690
HULN UPGRADE FEEDER RELAYING &172,359
COST CENTER 321 DELIVERY CAPIT 171,430
WESR0402 011&012 GETAWAYS 170,247
OLYMPIC TERRACE- 631 N WASHING 169,252
328-COST CENTER DELIVERY CAPIT 169,046
SNBK RADIO & ANT 167 948
ACHD/IPCO FRANKLIN ROAD REBUI 166,390
OREGON REAUTHORIZATION - HELLS 164,543
BRIDGER 2006CO01 U1 CONTROLS R 164 220
OMS UPGRADE OPSCENTRICITY 1.164 102
PEAKING RESOURCE RFP - 2007 CT 163,260
EXPANSION OF EXISTING TWIN FAL 162,409
SWAN FALLS RELICENSING FISH200 157 204
REL-HCC OREGON HART 2004 CAPIT 155,453
COM - REC BAKER CO SETTLEMENT 155,352
375 COST CENTER DELIVERY CAPIT 153,225
DELIVERY CAPITAL OVERHEADS FOR 152,587
WQ SWAN FALLS RELICENSING-CAPI 151,447
REC-BLISS AREA LAND OPTION & P 150,168
WQ-HCC MITIGATION-RESERVOIR AE 149,817
337-COST CENTER DELIVERY CAPIT 149,368
REL - REC SWAN FALLS RELICENSI 148,194
PHEASANT MEADOWS SUBD #1-123 L 147,697
CHQ 9 EXECUTIVE AREA REMODEL 145,345
MIDPOINT 500 KV LINE RELAY REP 144,031
TOTAL 149,814,313
FERC FORM NO.1 (ED. 12-87)Page 216.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2005/04
(2)0 A Resubmission 04/18/2006
CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
1. Report below descriptions and balances at end of year of projects in process of construction (107)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $100 000, whichever is less) may be grouped.
Line Description of Project Construction work in progress -
No.Electric (Account 107)
(a)(b)
#3 TURBINE RUNNER PURCHASE (IN 142 107
TERR HELLS CANYON COMPLEX TRAN 141,462
HCC WILDLIFE AND BOTANICAL 141,008
210-COST CENTER DELIVERY CAPIT 140 549
MISCELLANEOUS DELIVERY HARDWAR 140,307
SWAN FALLS RELICENSING INITIAL 136,910
OPERATIONAL DATA STORE 135,985
PURCHASE BUCKET TRUCK 6713 -135,091
NEW BUCKET TRUCK 6714 - FARW 135,091
NEW BUCKET TRUCK 6715 - NORT 135,091
NEW BUCKET TRUCK 6716 - SOUTH 135 091
NEW BUCKET TRUCK 6717 - OREGO 134,969
NEW BUCKET TRUCK 6718 - CENT 134 967
WHISPERING PINES SUBDV. - POWE 132 920
377 -COST CENTER DELIVERY CAPI 130,242
IPCO CABLE REPLACEMENT BOBN-129,812
FISH-HCC-RESIDENT FISH-2003-128,074
WO-HCC MITIGATION-TURBINE VENT 127 726
TFEAST TEAM CAP OH WORK ORDER 127 219
153 COST CENTER DELIVERY CAPIT 126,939
INSTANT MESSAGING GATEWAY 126,786
REC-SWAN FALLS RELICENSING PRO 126,138
MINI CASSIA TEAM CAP OH WORK 0 126,006
CDWL-WILLIS 138 KV LINE CONSTR 124 232
REL - GEOMORPHOLOGY 124 208
BRIDGER 2006C022 PURCH SPARE U 120,486
CDWL-WILS TRANSMISSION & ROW 120 396
VINEYARD POINTE SUBDIVISION #2 120 068
IDAHO NATIONAL GUARD- STAGE ST 119,434
CDAL018 - ADD NEW FEEDER 117 141
REL - REC HCC RELICENSING PROC 116,712
BUILD 138-KV LlNE-CHUT TO HPVY 116,678
OXBOW FISH HATCHERY EXPANSION 113,612
378 -COST CENTER DELIVERY CAPI 112,091
FIREWALL CLUSTER IMPROVEMENTS 111 700
381 -COST CENTER DELIVERY CAPI 111,499
HR COMPETENCY MANAGEMENT SYSTE 109,322
FISH-HCC-FEASIBILITY OF REINTR 108,641
BOMT-REPLACE T131 107,338
376 -COST CENTER DELIVERY CAPI 106,482
BKAT-MRDN CONVERT T202 TO 138K 105,473
LINE #602, BLACKFOOT-GOSHEN 16 103,580
TOTAL 149,814 313
FERC FORM NO.1 (ED. 12-87)Page 216.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Me, Da, Yr)End of 2005/04
(2)0 A Resubmission 04/18/2006
CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
1. Report below descriptions and balances at end of year of projects in process of construction (107)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $100,000, whichever is less) may be grouped.
Line Description of Project Construction work in progress -
No.Electric (Account 107)
(a)(b)
50CFS SPILLWAY MIN FLOW MODS (103,564
BRIDGER 2006C042 U2 ADV SOOTBL 103,227
BRIDGER 2006C027 U2 BCP REBUIL 102 711
IPCO-NEW 35KV RISER FOR EKRT 0 100,348
IPCO- 2005 DOWNTOWN CAPTIAL 100,271
Other Minor Work Orders 973,977
Construction WIP CIAC Contra 279,578
TOTAL 149,814,313
FERC FORM NO.1 (ED. 12-S7)Page 216.
This Page Intentionally Left Blank
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2005/04
This Report Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) DA Resubmission 04/18/2006
ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108)
1. Explain in a footnote any important adjustments during year.
2. Explain in a footnote any difference between the amount for book cost of plant retired, Line 11 , column (c), and that reported for
electric plant in service, pages 204-207, column 9d), excluding retirements of non-depreciable property.
3. The provisions of Account 108 in the Uniform System of accounts require that retirements of depreciable plant be recorded when
such plant is removed from service. If the respondent has a significant amount of plant retired at year end which has not been recorded
and/or classified to the various reserve functional classifications, make preliminary closing entries to tentatively functionalize the book
cost of the plant retired. In addition, include all costs included in retirement work in progress at year end in the appropriate functional
classifications.
4. Show separately interest credits under a sinking fund or similar method of depreciation accounting.
No.(a)
1 Balance Beginning of Year
2 Depreciation Provisions for Year, Charged to
3 (403) Depreciation Expense
4 (403.1) Depreciation Expense for Asset
Retirement Costs
5 (413) Exp. of Elec. PIt. Leas. to Others
6 Transportation Expenses-Clearing
7 Other Clearing Accounts
8 Other Accounts (Specify, details in footnote):
Fuel Stock
10 TOTAL Deprec. Prov for Year (Enter Total of
lines 3 thru 9)
108.409
95,898,133
108.409
898,133
11 Net Charges for Plant Retired:
12 Book Cost of Plant Retired
r---r----~
13 Cost of Removal
14 Salvage (Credit)
15 TOTAL Net Chrgs. for Plant Ret. (Enter Total
of lines 12 thru 14)
28,813,920
084 965
28,813,920
084 965
161,520 f1~~~~~~~J~1I1IU~1
29,737 365 29,737,365
16 Other Debit or Cr. Items (Describe, details in
footnote):
18 Book Cost or Asset Retirement Costs Retired
19 Balance End of Year (Enter Totals of lines 1
16, and 18)
333,025,502 333,025,502
Section B. Balances at End of Year According to Functional Classification
27 General
28 TOTAL (Enter Total of lines 20 thru 27)
404,798,819 404 798,819
228,958 005 228,958 005
282,764 282,764
200,078,275 200,078,275
400,254 012 400,254 012
90,653,627 653 627
333,025,502 333,025,502
20 Steam Production
21 Nuclear Production
22 Hydraulic Production-Conventional
23 Hydraulic Production-Pumped Storage
24 Other Production
25 Transmission
26 Distribution
FERC FORM NO.1 (REV. 12-03)Page 219
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2) A Resubmission 04/18/2006 2005/04
FOOTNOTE DATA
'Schedule Page: 219 Line No.14 Column:
Relocation reimbursements, Up and down costs and damage and insurance claims $ 463,286.
ISchedule Page: 219 Line No.16 Column:
Accumulated Provision for Depreciation on Asset Retirement Obligation
Embedded removal in Accumulated provision for Depreciation
Disallowed capital cost from the 2003 Idaho rate case
$ (56,808)
983,275
296,299
----------
$5,222,766
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This
wort
Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2005/04(2)0 A Resubmission 04/18/2006
INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.
1. Report below investments in Accounts 123., investments in Subsidiary Companies.
2. Provide a subheading for each company and List there under the information called for below. Sub - TOTAL by company and give a TOTAL in
columns (e),(f),(g) and (h)
(a) Investment in Securities - List and describe each security owned. For bonds give also principal amount, date of issue, maturity and interest rate.
(b) Investment Advances - Report separately the amounts of loans or investment advances which are subject to repayment, but which are not subject to
current settlement. With respect to each advance show whether the advance is a note or open account. List each note giving date of issuance, maturity
date, and specifying whether note is a renewal.
3. Report separately the equity in undistributed subsidiary earnings since acquisition. The TOTAL in column (e) should equal the amount entered for
Account 418.
Line Description of Investment Date Acquired Date Of Amount ot Investment at
No.(a)(b)Mat
Wity
Beginning of Year(d)
1 Idaho Energy Resources Company
Common Stock 02/01/74 500
3 Capital contributions 2,462 594
Equity in earnings 081 386
Subtotal Idaho Energy Resources 36,544,480
Total Cost of Account 123.1 $2,463,0931 TOTAL 36,544,480
FERC FORM NO.1 (ED. 12-89)Page 224
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)
End of 2005/04(2)D A Resubmission 04/18/2006
INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1) (Continued)
4. For any securities, notes, or accounts that were pledged designate such securities, notes, or accounts in a footnote, and state the name of pledgee
and purpose of the pledge.
5. If Commission approval was required for any advance made or security acquired, designate such fact in a footnote and give name of Commission,
date of authorization, and case or docket number.
6. Report column (f) interest and dividend revenues form investments, including such revenues form securities disposed of during the year.
7. In column (h) report for each investment disposed of during the year, the gain or loss represented by the difference between cost of the investment (or
the other amount at which carried in the books of account if difference from cost) and the selling price thereof, not including interest adjustment includible
in column (t).
8. Report on Line 42 , column (a) the TOTAL cost of Account 123.
Equity in Subsidiary Revenues for Year Amount of Investment at Gain or Loss from Investment LineEarninqs of Year End fJ)year DiSP~~fd of No.(f)
500
2,462 594
967,929 049,315
967 929 43,512,409
967 929 43,512,409
FERC FORM NO.1 (ED. 12-89)Page 225
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)2005/04(2)D A Resubmission 04/18/2006 End of
MATERIALS AND SUPPLIES
1. For Account 154, report the amount of plant materials and operating supplies under the primary functional classifications as indicated in column (a);
estimates of amounts by function are acceptable. In column (d), designate the department or departments which use the class of material.
2. Give an explanation of important inventory adjustments during the year (in a footnote) showing general classes of material and supplies and the
various accounts (operating expenses, clearing accounts, plant, etc.) affected debited or credited. Show separately debit or credits to stores expense
clearing, if applicable.
Line Account Balance Balance Department or
No,Beginning of Year End of Year Departments which
Use Material
(a)(b)(c)(d)
Fuel Stock (Account 151)6,450 733 11,494 190 Electric
2 Fuel Stock Expenses Undistributed (Account 152)
3 Residuals and Extracted Products (Account 153)
Plant Materials and Operating Supplies (Account 154)
5 Assigned to - Construction (Estimated)
6 Assigned to - Operations and Maintenance
Production Plant (Estimated)10,372 441 11,238,406
Transmission Plant (Estimated)805,201 4,465,632
Distribution Plant (Estimated)10,171 811 235,598
Assigned to - Other (provide details in footnote)29,324 766,156
TOTAL Account 154 (Enter Total of lines 5 thru 10)25,378,777 705,792 Electric
Merchandise (Account 155)
Other Materials and Supplies (Account 156)
Nuclear Materials Held for Sale (Account 157) (Not
applic to Gas Uti!)
Stores Expense Undistributed (Account 163)685 830 745,428 Electric
TOTAL Materials and Supplies (Per Balance Sheet)515,340 945,410
FERC FORM NO.1 (ED. 12-96)Page 227
This Page Intentionally Left Blank
Name of Respondent This Report Is:Date of Report Year/Period of Report
Idaho Power Company (1) ~An Original (Mo, Da, Yr)End of 2005/04
(2)D A Resubmission 04/18/2006
EXTRAORDINARY PROPERTY LOSSES (Account 182.
Line DescriRtion of Extraordinary Loss Total Losses WRITTEN OFF DURING YEAR Balance atNo.(Include in the description the date of Amount RecognisedCommis~ Authorization to use Acc 182.of Loss During Year Account Amount End of Yearand perio 0 amortization (mo, yr to mo, yr).Charged
(a)(b)(c)(d)(e)(f)
1 None
TOTAL
FERC FORM NO.1 (ED. 12-88)Page 230a
Name of Respondent This Report Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) ~An Original (Mo, Da, Yr)End of 2005/04
(2)0 A Resubmission 04/18/2006
UNRECOVERED PLANT AND REGULATORY STUDY COSTS (182.
Line Description of Unrecovered Plant Total Costs WRITTEN OFF DURING YEAR Balance atNo.and Regulatory Study Costs (Include Amount Recognisedin the description of costs, the date of of Charges During Year Account Amount End of YearCommission Authorization to use Acc 182.Charged
and period of amortization (mo, yr to mo, yr)J
(f)(a)(b)(c)(d)(e)
None
TOTAL
FERC FORM NO.1 (ED. 12-88)Page 230b
Name of Respondent This Report Is:Date of Report Year/Period of Report
Idaho Power Company (1) I!J An Original (Mo, Da. Yr)End of 2005/04
(2)0 A Resubmission 04/18/2006
OTHER REGULATORY ASSETS (Account 182.
1. Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable.
2. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $50 000 which ever is less), may be grouped
by classes.
3. For Regulatory Assets being amortized, show period of amortization.
Line Description and Purpose of Balance at Debits CREDITS Balance at end of
No.Other Regulatory Assets Beginning of en 0" Uunng en 0" Uunng Current QuarterlYear
Current the QuarterlYear the Period
QuarterlYear Account Charged Amount
(a)(b)(c)(d)(e)(f)
Asset Retirment Obligations - IPUC 372.493 559.457 Footnote 363,188
Order #29414 - OPUC Order #04-585
Postretirment Benefits - IPUC order #25550 45.400 401 45.400
(amort period 2/95 thru 01/05)
Reorganization Costs -IPUC order 26216 754,055 401 754 055
OPUC order #95-1262 (amort 01/96 thru 12/05)
Regulatory Unfunded Accumulated Deferred Income Tax 344,219,574 10,686,489 282 789.430 346,116,633
Power Cost Adjustment -IPUG order 34,009,371 89,661,801 Footnote ThZ~~~i~;~~~J,~i2 33,561 270
-..-.
#27660 (amort period 6/05 thru 5/07)
Idaho - Demand Side Management -IPUC order 17,834,351 401 242 604 591,747
#27660 (amort period 7/98 thru 6/10)
Excess Power Amortization - Oregon 12,047.497 845,447 Footnote ~~Hdii;~\~~~j\\K~~1!8,411 119
-...
(Capped at 10% per year until full amort)
Security Costs 2001-2002 (Amort period 1/03 -12/07 553,393 401 178,284 375,109
Security Costs 2003 - IPUC Order #28975 259,783 648 401 64,591 199 840
Professional Fees - IPUC order #29505 60,166 038 4073 19,944 41,260
(Amort period 1/03 thru 12/07)
Tax Settlement -IPUC Order 29601 118,562 577 501 4073 702,106 993,957
(Amort period 6/05 thru 5/06)
Cloud Seeding - IPUC Order 29670 182 954 671,106 1823 854,060
(Included in PCA Amortization)
Irrigation Lost Revenue -IPUC Order 29669 13,289,763 193,120 1823 13,482,883
(Included in PCA Amortization)
PCA Unbilled Amortization Reserve 4073 309,994 309,994
(Reversed June 2006)
Excess Power Deferred - Oregon (see lines 18-19)958,704 401 79,258 879,446
Minor items (5)33.466 49,521 Various 65,372 615
TOTAL 438 780,828 110,208,832 130,748,470 418,241,190
FERC FORM NO. 1/3.Q (REV. 02-04)Page 232
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2006 2005/04
FOOTNOTE DATA
ISchedu/e Page: 232 Line No.107 557,501
108 261
568,762
ISchedule Page: 232 Line No.
1823 35,495 679253 166,667254 7,495,327401 38,764 8144073 8,159 3984210 16 292
431 11,725
90,109,902
Column:
Column:
'Schedule Page: 232 Line No.254 100,000401 4 371 602
4210 10,223
4,481 825
Column:
IFERC FORM NO.1 (ED. 12-Page 450.
YearlPeriod of Report
End of 2005/Q4
This Report Is: Date of Report(1) I!J An Original (Mo, Da, Yr)
(2) 0 A Resubmission 04/18/2006
MISCELLANEOUS DEFFERED DEBITS (Account 186)
1. Report below the particulars (details) called for concerning miscellaneous deferred debits.
2. For any deferred debit being amortized, show period of amortization in column (a)
3. Minor item (1 % of the Balance at End of Year for Account 186 or amounts less than $50 000 whichever is less) may be grouped by
classes.
Name of Respondent
Idaho Power Company
Line
No.
Description of Miscellaneous
Deferred Debits
DebitsBalance at
Beginning of Year ~~countCharged
(d)
956,225 ~\~m8~:,t~~\'
CREDITS
Amount
(e)(a)
1 Regional Transmsn Org - (RTO)
3 Advance prepaid coal royalties
Benefits plan - intangible asst
Security plan
9 American Falls bond refinance
11 Prepaid Credit Facility
13 Company owned Life Insurance
15 American Falls water rights
17 Milner bond guarantee
19 Southwest intertie project -
20 right of way costs
22 CSPP receivable
24 American Falls - bond refinance
25 (35 year amortization)
27 Transmission Deposit-PacifiCorp
29 Shelf Registration
31 Customer Svcs Finance Program
33 Minor Items & Job Orders (7)
(b)
251 115
(c)
176,829 131
681,824 219
28,175,826 938,529 4262
293,470 401
037 592 165
589,538 894,978 ~i~~ji\\dw'iV:3;
19,885,000
700,000
286 106 54,956 232
389,261 143
967 982 401
151,875 143,500
583,377 13,049 ~~~Qt~ti
;:;'
140 130 309,406 ;i'l~J,~IQot~;,:
!:~;
517 188,208 Various
47 Misc. Work in Progress
48 Deferred Regulatory Comm.
Expenses (See pages 350 - 351)
49 TOTAL 83,272,850
FERC FORM NO.1 (ED. 12-94)Page 233
956,225
200,776
268 571
528,870
552
413,870
669 180
671
372,414
999
596,426
405 265
240 022
Balance at
End of Year
(f)
251 115
976,053
1,413,253
28,585,485
278,918
623,722
815,336
19,885,000
700,000
333,391
016,847
919,983
295,375
44,271
51,297
82,087,452
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) 2S; An Original (Mo, Da, Yr)
Idaho Power Company (2) A Resubmission 04/18/2006 2005/04
FOOTNOTE DATA
Schedule Pa e: 233 Line No.Column: d
186 295,030
232 821
401 654 374
956 225
Schedule Page: 233 Line No.Column: d
131 773 387
4262 895,793
669,180
Schedule Page: 233 Line No.Column: d
131
181 585 758
186 10,446
401 154
596,426
Schedule Pa e: 233 Line No.Column: d
131 153 744
141 243,905
142 616
405,265
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2005/04
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) 0 A Resubmission 04/18/2006
ACCUMULATED DEFERRED INCOME TAXES (Account 190)
1. Report the information called for below concerning the respondent's accounting for deferred income taxes.
2. At Other (Specify), include deferrals relating to other income and deductions.
(a)
Balance 0 Beginingof Year
(b)
Balance at Endof Year
(c)
Line
No.
Description and Location
Electric
2 FASB 109 Accounting
3 Emission Allowances
4 Advances for Construction
40,447 292
357,401
627,445
27,379,836
881,386
Other
TOTAL Electric (Enter Total of lines 2 thru 7)
Gas
45,804,693 75,888,667
18 TOTAL (Acct 190) (Total of lines 8, 16 and 17)
Other
TOTAL Gas (Enter Total of lines 10 thru 15
907,422
72,712,115
27,771,469
103,660 136
Notes
FERC FORM NO.1 (ED. 12-88)Page 234
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2006 2005/04
FOOTNOTE DATA
!Schedule Page: 234 Line No.17 Column:
Other:
Senior Management Security Plan
Minimum Pension Liability
Rate Case Disallowance
Micron - CIAC
Other Employee s Long Term Deferred Compensation
Post Retiree Benefits - VEBA
SFAS112 - Post Retirement Benefits
Non - VEBA Pension and Benefits
Meridian Gold Contributions
Restricted Stock Plan
Linden Feeder Deposits
Dark Fiber Contracts
Other Regulatory Liabilities
Start-up and Organization Costs
Seattle City Light - CIAC
Loss on Pioneer Land Write - down
FERC Settlement Reserve
SHOBAN Transmission Right of Way Expense
SMSP - Market Change of Rabbi Investments
innin Balance
977 023
3,482 678
3,432 123
717 223
346,500
867 675
157 160
926 069
241 ,128
275 929
101 285
000
75,447
030
351
781 900
339,874
027
907,422
Endin Balance
10,851 325
947 905
316 285
2,477,838
2,424 225
893 065
037 355
905 653
219,017
215 673
128 814
101 285
990
75,447
241
351
771 469
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This
wort
Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2005/04
(2)D A Resubmission 04/18/2006
CAPITAL STOCKS (Account 201 and 204)
1. Report below the particulars (details) called for concerning common and preferred stock at end of year, distinguishing separate
series of any general class. Show separate totals for common and preferred stock. If information to meet the stock exchange reporting
requirement outlined in column (a) is available from the SEC 10-K Report Form filing, a specific reference to report form (Le., year and
company title) may be reported in column (a) provided the fiscal years for both the 10-K report and this report are compatible.
2. Entries in column (b) should represent the number of shares authorized by the articles of incorporation as amended to end of year.
Line Class and Series of Stock and Number of shares Par or Stated Call Price at
No.Name of Stock Series Authorized by Charter Value per share End of Year
(a)(b)(c)(d)
1 Account 201
Common Stock registered on New York 000,000
and Pacific Stock Exchange
4 Total Common Stock 50,000,000
FERC FORM NO.1 (ED. 12-91)Page 250
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2005/Q4
(2)D A Resubmission 04/18/2006
CAPITAL STOCKS (Account 201 and 204) (Continued)
3. Give particulars (details) concerning shares of any class and series of stock authorized to be issued by a regulatory commission
which have not yet been issued.
4. The identification of each class of preferred stock should show the dividend rate and whether the dividends are cumulative or
non-cumulative.
5. State in a footnote if any capital stock which has been nominally issued is nominally outstanding at end of year.
Give particulars (details) in column (a) of any nominally issued capital stock, reacquired stock, or stock in sinking and other funds which
is pledged, stating name of pledgee and purposes of pledge.
OUTSTANDING PER BALANCE SHEET HELD BY RESPONDENT Line(Total amount outstanding without reduction AS REACQUIRED STOCK (Account 217)IN SINKING AND OTHER FUNDS No.for amounts held by respondent)
Shares Amount Shares G9st Shares Amount(e)(f)
(g)
(h)(i)
150,812 877,030
150,812 877 030
FERC FORM NO.1 (ED. 12-88)Page 251
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2005/04
(2)D A Resubmlssion 04/18/2006
OTHER PAID-IN CAPITAL (Accounts 208-211 , inc.
Report below the balance at the end of the year and the information specified below for the respective other paid-in capital accounts. Provide a
subheading for each account and show a total for the account, as well as total of all accounts for reconciliation with balance sheet, Page 112. Add more
columns for any account if deemed necessary. Explain changes made in any account during the year and give the accounting entries effecting such
change.
(a) Donations Received from Stockholders (Account 208)-State amount and give brief explanation of the origin and purpose of each donation.
(b) Reduction in Par or Stated value of Capital Stock (Account 209): State amount and give brief explanation of the capital change which gave rise to
amounts reported under this caption including identification with the class and series of stock to which related.
(c) Gain on Resale or Cancellation of Reacquired Capital Stock (Account 210): Report balance at beginning of year, credits, debits, and balance at end
of year with a designation of the nature of each credit and debit identified by the class and series of stock to which related.
(d) Miscellaneous Paid-in Capital (Account 211)-Classify amounts included in this account according to captions which, together with brief explanations,
disclose the general nature of the transactions which gave rise to the reported amounts.
l~r "(W)
unt
Account 208 - Donations received from stockholders
Account 209 - Reduction in par or stated value of Capital Stock
Account 210 - Gain on reacquired Capital Stock
Account 211 - Miscellaneous paid-in Capital
TOTAL
FERC FORM NO.1 (ED. 12-87)Page 253
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2005/04(2)D A Resubmission 04/18/2006
CAPITAL STOCK EXPENSE (Account 214)
1. Report the balance at end of the year of discount on capital stock for each class and series of capital stock.
2. If any change occurred during the year in the balance in respect to any class or series of stock, attach a statement giving particulars
(details) of the change. State the reason for any charge-off of capital stock expense and specify the account charged.
Line t..;lass ana ::series or ::stock Balance at t:nd Of Year
No.(a)(b)
Common Stock 096 925
Explanation of Changes during the year:
22 TOTAL 096 925
FERC FORM NO.1 (ED. 12-87)Page 254b
Name of Respondent
Idaho Power Company
YearlPeriod of Report
End of 2005/04
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) D A Resubmisslon 04/18/2006
LONG-TERM DEBT (Account 221, 222, 223 and 224)
1. Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds, 222,
Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt.
2. In column (a), for new issues, give Commission authorization numbers and dates.
3. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
4. For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate
demand notes as such. Include in column (a) names of associated companies from which advances were received.
5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
6. In column (b) show the principal amount of bonds or other long-term debt originally issued.
7. In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
8. For column (c) the total expenses should be listed first for each issuance, then the amount of premiu!'1 (in parentheses) or discount.
Indicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted.
9. Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year. Also , give in a footnote the date of the Commission s authorization of treatment other than as
specified by the Uniform System of Accounts.
Line
No.
Class and Series of Obligation, Coupon Rate
(For new issue, give commission Authorization numbers and dates)
(a)
Principal Amount
Of Debt issued
(b)
Total expense
Premium or Discount
(c)
1 Account 221:
First Mortgage Bonds:
3 5.50% Series due 2033
6 7.38% Series Due 2007
8 7.20% Series due 2009
000,000 728 701
36,400 D
80,000,000 807,871
80,000,000 572,246
10 5.30% Series Due 2035 (Idaho IPC-04-
11 OPUC UF 4211 WPSC 2005-ES-04-27)
14 5.83% Series due 2005
16 6.60% Series due 2011
18 4.25%Series due 2013
60,000 000 408,411 D
000,000 508,801
120 000,000 860,502
000,000 641,201
374 500 D
21 4.75% Series due 2012
24 6.00% Series due 2032
27 5.875% Series due 2034
30 5.50% Series due 2034
32 Pollution control Revenue Bonds
100 000,000 944 356
047 617 D
100,000,000 069,356
543,244 D
55,000,000 524,419
383,322 D
50,000,000 746,961 D
33 TOTAL 047 045,000 15,375,604
FERC FORM NO.1 (ED. 12-96)Page 256
Name of Respondent This Report Is:Date of Report Year/Period of Report
Idaho Power Company (1) ~AnOriginal (Mo, Da, Yr)End of 2005/04
(2)DA Resubmission 04/18/2006
LONG-TERM DEBT (Account 221,222 223 and 224) (Continued)
10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term
advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13. If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose of the pledge.
14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of
year, describe such securities in a footnote.
15. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427 , interest on
Long-Term Debt and Account 430, Interest on Debt to Associated Companies.
16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
AMORTIZATION PERIOD ul!(s(an~:lIn LineNominal Date Date of (Total amount outstan ing without Interest for Year No.of Issue Maturity Date From Date To reduction for amounts held by Amount
(d)(e)(f)
(g)
reSP?~dent)(i)
05-01-04-01-05-01-03-31-000 000 850,000
12/1/00 12/1/07 12/1/00 12/1/07 80,000,000 904 000
11/23/99 12/1/09 1/1/00 1/1/10 80,000,000 760,000
08/26/05 08/26/35 08/26/05 08/26/35 60,000 000 104.167
09/09/98 09/09/05 09/09/98 09/09/05 2,409,733
03/02/01 03/02/11 03/02/01 03/02/11 120,000,000 920 000
05/01/03 10/01/13 05/01/03 09/29/13 000,000 975,000
11/15/02 11/15/12 11/15/02 11/15/12 100,000,000 750,000
11/15/02 11/15/32 11/15/02 11/15/32 100,000 000 000,000
8/16/04 8/16/34 8/16/04 8/16/34 55,000,000 750,000
3/26/04 3/15/34 3/26/04 3/15/34 50,000,000 224,481
987 045 000 53,339 531
FERC FORM NO.1 (ED. 12-96)Page 257
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2005/04
(2)D A Resubmission 04/18/2006
LONG-TERM DEBT (Account 221 222 223 and 224)
1. Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221 , Bonds, 222
Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt.
2. In column (a), for new issues, give Commission authorization numbers and dates.
3. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
4. For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate
demand notes as such. Include in column (a) names of associated companies from which advances were received.
5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
6. In column (b) show the principal amount of bonds or other long-term debt originally issued.
7. In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
8. For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
Indicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted.
9. Fumish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year. Also, give in a footnote the date of the Commission s authorization of treatment other than as
specified by the Uniform System of Accounts.
Line Class and Series of Obligation, Coupon Rate Principal Amount Total expense,
No.(For new issue, give commission Authorization numbers and dates)Of Debt issued Premium or Discount
(a)(b)(c)
1 6.05% Series 96A due 2026 68,100,000 571,895
471 252 D
4 Series 96B due 2026 24,200,000 124 587
6 Series 96C due 2026 24,000,000 123,561
8 Port of Morrow Variable due 2027 360,000 188,545
Humboldt Variable due 2024 49,800,000 697 856
Subtotal Account 221 015,460,000 15,375,604
Account 224:
Bond Guarantee - American Falls 19,885,000
Note Guarantee - Milner Dam 11,700 000
Subtotal Account 224 585,000
Account 222: Required Bonds
Account 223: Advances for Associated Companies
TOTAL 047,045,000 15,375,604
FERC FORM NO.1 (ED. 12-96)Page 256.
Name of Respondent This Report Is:Date of Report Year/Period of Report
Idaho Power Company (1) ~An Original (Mo, Da, Yr)End of 2005/04
(2)0 A Resubmission 04/18/2006
LONG-TERM DEBT (Account 221,222, 223 and 224) (Continued)
10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term
advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13. If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose of the pledge.
14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of
year, describe such securities in a footnote.
15. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on
Long-Term Debt and Account 430, Interest on Debt to Associated Companies.
16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
AMORTIZATION PERIOD uutstancJin Line
Nominal Date Date of (Total amount outstan ing without Interest for Year No.of Issue Maturity Date From Date To reduction for amounts held by Amount
(d)(e)(f)
(g)
resP?Ment)(i)
07/25/96 07/15/26 07/25/96 07/15/26 68,100 000 120,050
07/25/96 07/15/26 07/25/96 07/15/26 200 000 621 934
07/25/96 07/15/26 07/25/96 07/15/26 000,000 613,815
5/17/00 2/1/27 5/17/00 2/1/27 360,000 130,082
10/22/03 12/01/24 11/01/03 12/01/24 49,800 000 206 269
955,460,000 53,339,531
4/26/00 2/1/25 19,885,000
02/10/92 700,000
585,000
987,045,000 53,339,531
FERC FORM NO.1 (ED. 12-96)Page 257.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2) A Resubmission 04/18/2006 2005/04
FOOTNOTE DATA
ISchedule Page: 256 Line No.
Redeemed in September 2005
Column: h
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report Is: Date of Report YearlPeriod of ReportIdaho Power Company (1) ~ An Original (Mo, Da , Yr) End of 2005/04
(2) D A Resubmission 04/18/2006
RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TAXES
1. Report the reconciliation of reported net income for the year with taxable income used in computing Federal income tax accruals and show
computation of such tax accruals. Include in the reconciliation, as far as practicable, the same detail as furnished on Schedule M-1 of the tax return for
the year. Submit a reconciliation even though there is no taxable income for the year. Indicate clearly the nature of each reconciling amount.
2. If the utility is a member of a group which files a consolidated Federal tax return, reconcile reported net income with taxable net income as if a
separate return were to be field, indicating, however, intercompany amounts to be eliminated in such a consolidated return. State names of group
member, tax assigned to each group member, and basis of allocation, assignment, or sharing of the consolidated tax among the group members.
3. A substitute page, designed to meet a particular need of a company, may be used as Long as the data is consistent and meets the requirements of
the above instructions. For electronic reporting purposes complete Line 27 and provide the substitute Page in the context of a footnote.
14 Income Recorded on Books Not Included in Return
19 Deductions on Return Not Charged Against Book Income
Particulars Details)
(a)
Line
No.
1 Net Income for the Year (Page 117)
27 Federal Tax Net Income
28 Show Computation of Tax:
29 Tentative Federal Tax ~ 35%
201 733,384
70,606,684
FERC FORM NO.1 (ED. 12-96)Page 261
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2006 2005/Q4
FOOTNOTE DATA
Schedule Paae: 261 Line No.Column:
004003-CONSTRUCTION ADV-252 354 239
004004-CIAC AS TAXABLE INC CLOSED TO 000 000
PLANT
004005-AVOIDED COST INT CAP 653 876
00401 O-EMISSION ALLOW ANCE-254.409-411 034 111
004013-CIAC AS TAXABLE INC IN ACCT 107 449 922
004016-CIAC TAXABLE INCOME-ACCT 253.575 (932 920)
004017-JOINT USE FEE REC'D B41NC 635
BOOKED-253.050
004018-LlNDEN FEEDER DEPOSITS-253.206 200 658
004019-IDWR STREAMFLOW GUAGING (10,002)
CONTRACT -242.312
004501-ROY AL TY INCOME BTL 109 000
004506-CIAC-MERIDIAN GOLD (56 560)
004507 -CIAC-M ICRON-DRAM (612 316)
004512-CIAC-SEATTLE CITY LIGHT (81 31
Total 108,168,331
Schedule Page: 261 Line No.Column:
1T0tai Federal and State taxes deducted on books 050,522
005001-BAD DEBT EXPENSE (530 188)
005008-GAIN/LOSS ON REACQUIRED DEBT-DEFERRED 549 856
00501 O-SFAS 112-POST -EMPL Y BEN 182/253 (306,445)
005014-0VERACCRUED VACATION-ACCT 242 681 136
005017-INJURIES & DAMAGES 652 588
005019-DIRECTORS FEES DEF 257,414
005023-PENSION ACCR TO 926200 646,460
005024-MEALS (50% NON-DEDUCTIBLE) CHRGD TO RE.266,000
005025-MILNER FALLING WATER - REV ACCRL 264 100
005027-AMORTIZATION OF ACCOUNT 114 (22 723)
~05028-0REGON OPER PROPERTY TAX ADJ 188
1o05033-NONVEBA PEN&BEN-Acct 228 (52 221)
005035-PCA EXPENSE DEFERRAL 287 698
1o05039-POST RETIREE BENEFIT- FAS106-ACCT 182 45,400
005044-RESTRICTED STOCK PLAN-COMP 177 044
005047-0THER EMPLOYEE'S L T DEFERRED COMP-228 198 811
005049-253-FERC SETTLEMENT RESERVE 000 000)
005050-186-BAD DEBT RESERVE-FINANCING PRGMS 440
005051-PUC ORDER 29505 - PROFESSIONAL FEES 906
005501-SEC PLAN-NET INS COSTS (403 353)
005502-128-SMSP-MRKT CHG OF RABBIINVSTMNTS (17 974)
005503-128-EDC-UNRLZD GN/LS FRM RABBI TRUST 538)
~05504-NONDEDUCTIBLE POLITICAL EXP-426.4 250 000
1o05505-SEC PLAN-BENEFIT ACCR 236 353
1O05516-NONDEDUCTIBLE POLITICAL EXP-O&M ACCTS 100 000
1o05531-RATE CASE DISALLOWANCES-REVERSE AMORT (296,299)
Total 56,081,175
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2006 2005/04
FOOTNOTE DATA
Schedule Page: 261 Line No.Column:
007002-GAIN ON SALE OF BOC 970
007007-0THER REGULATORY LlABILITIES-254 (79,268)
007501-REVERSE EQUITY EARNINGS OF SUBSIDIARIES 874 042
007502-ALLOWANCE FOR OFUDC 950,151
007503-ALLOWANCE FOR BFUDC 790,871
007504-RECLASS TAX EXEMPT INTEREST - FED & IDAHO 737
007504-RECLASS TAX EXEMPT INTEREST - FED ONLY 663 779
007514-COLl-INSURANCE PROCEEDS 747 596
Total 17,981,878
Schedule Page: 261 Line No.Column:
008001-VEBA-POST RET BNFTS-TRUST-ACCT 228 (2,622,821)
0O8009-DEPR FOR TAX GT OR L T BOOK 309 259)
008015-INTEREST RATE HEDGE - 181.134 723,000
008020-CONSERV A TION PROGRAMS 242 613)
008025-MANUFACTURING DEDUCTION-ORE NOT ALLWD 3,498,529
008027-NEVADA OPERATING PROPERTY TAX ADJ (22 609)
008034-REMOV AL COSTS 258 133
008035-REPAIR ALLOWANCE 000,000
008038-0REGON EXCESS PWR SUPPLY COSTS (656 933)
008039-ST TAX-NOT DEDUCTED ON PRIOR RETURN 253
008041-AM FALLS - UNAMORTIZED DEBT EXP (47 999)
p08042-GAIN/LOSS ON REACQUIRED DEBT -(610 841)
J08045-ST TAX-AUDIT STTLMNTS PAID THIS YR 144
J08057-REORGANIZATION COSTS-ACCT 182 (754 055)
J08071-PHOTOVOL TAlC STARTUP COSTS-ACCT 182 984)
J08072-INTANGIBLE ASSET-LABOR DEDUCT-107-FED ONLY 391 000
J08074-INCREMENTAL SECURITY COSTS DEDUCTED (238,227)
D08077-PP INS & OTR EXP (1 YR OR LESS)-165 (338,557)
008501-COLl-TAX ADJ FROM BOOKS (746 182)
008504-0REGON NONOP PROPERTY TAX ADJUST (141)
p08508-DEPR ADJ - NONOP - OTHER PROPERTY - NEW 255
PN10016-DIV PAID DED PUB UTIL 300,000
STATE INCOME TAX DEDUCTED ON FEDERAL RETURN 779,981
Total 16,373,074
IFERC FORM NO.(ED. 12-87)Page 450.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2005/04
(2)D A Resubmission 04/18/2006
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during
the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the
actual, or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.
Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes.
3. Include in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other
than accrued and prepaid tax accounts.
4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
Line Kind ofTax BALANCE AT BEGINNING OF YEAR :1~xes ~~taS Adjust-C arged
No.(See instruction 5)Taxes Accrued Prepaid Taxes ~nng ~ring ments(Account 236)(Include In Account 165)ear ear
(a)(b)(c)(d)(e)(f)
1 Federal:
2 Income 25,635,654 65,896,447 40,642,030
3 Social Security - (FOAB)338,547 333 954 320,596
4 Unemployment 523 111 311 108,598
Subtotal Federal 26,007 724 75,341 712 50,071,224
7 State of Idaho:
8 Property 313,501 13,266,589 12,485 781
9 Income 713,686 8,417 558 861,911
KWH 90,271 1,408,414 1,402,524
Unemployment 396 231 840 218,841
Regulatory Commission 670,843 670,843
Business License - Sho Ban 150 150 150
Subtotal Idaho 11,125,854 150 995 394 18,640,050
State of Oregon
Property 023,101 010 365 974,036
Income 948,764 524,980 304 983
Regulatory Commission 99,689 99,689
Unemployment 768 132 043
Franchise 120,381 481 887 479,634
Subtotal Oregon 070 913 023 101 137,053 879,385
State of Montana:
Property 115 93,497 86,918
Subtotal Montana 115 93,497 86,918
State of Nevada:
Property 220,963 441 929 865.897 064 253
Unemployment
Business Tax 241 241
Subtotal Nevada 220,972 441 929 866 138 064,503
State of Wyoming
Corporate License 043 043
Property 443 504 992 799 939,830
Subtotal Wyoming 443 504 995,842 942 873
misc states franchise
TOTAL 40,280,158 1,465,180 95,966 155 73,700,904
FERC FORM NO.1 (ED. 12-96)Page 262
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2005/04
(2)0 A Resubmission 04/18/2006
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued)
5. If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year
identifying the year in column (a).
6. Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments
by parentheses.
7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending
transmittal of such taxes to the taxing authority.
8. Report in columns (i) through (I) how the taxes were distributed. Report in column (I) only the amounts charged to Accounts 408.1 and 409.
pertaining to electric operations. Report in column (I) the amounts charged to Accounts 408.1 and 109.1 pertaining to other utility departments and
amounts charged to Accounts 408.2 and 409.2. Also shown in column (I) the taxes charged to utility plant or other balance sheet accounts.
9. For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Line
(Taxes accrued Prepaid Taxes Electric Extraordinary Items Adjustments to Ret.Other No.
ACCO
~m 236)
(Incl. in Account 165)(Account 408.1, 409.(Account 409.Earnings (Account 439)
(h)(i)
(j)
(k)(I)
50.890,071 853,588 042,859
351 904 333,954
36,235 111,311
51,278,210 298,853 042 859
094,309 13,233,414 33,175
269,333 188 145 229,413
96,161 1,408,414
21,395 231 840
670 843
150
17,481 198 150 732.656 262,588
986,772 006,312 053
168,761 513 307 673
99,689
856 132
122,634 481 887
292 251 986,772 121.327 15,726
694 93,497
46,694 93,497
419,320 865,897
241
419,320 866 138
043
496,473 992,799
496,473 995 842
183 706 1,406,242 640,941 325,064
FERC FORM NO.1 (ED. 12-96)Page 263
Name of Respondent This 0ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2005/04
(2)0 A Resubmission 04/18/2006
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during
the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the
actual, or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2, Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.
Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes.
3. Include in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other
than accrued and prepaid tax accounts.
4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
L..Ine Kind of Tax BALANCE AT BEGINNING OF YEAR ::.b~xes ~~i~s Adjust-C argedNo,(See instruction 5)Taxes Accrued Prepaid Taxes ~nng ~ring ments(Account 236)(Include In Account 165)ear ear
(a)(b)(c)(d)(e)(f)
1 Other States Income 371,076 233,755 15,951
2 Payroll Adjustment 697,236
TOTAL 280,158 1,465 180 966 155 700,904
FERC FORM NO.1 (ED. 12-96)Page 262.
Name of Respondent This
'0ort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2005/04
(2)0 A Resubmission 04/18/2006
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued)
5. If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year
identifying the year in column (a).
6. Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments
by parentheses.
7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending
transmittal of such taxes to the taxing authority.
8. Report in columns (i) through (I) how the taxes were distributed. Report in column (I) only the amounts charged to Accounts 408.1 and 409.
pertaining to electric operations. Report in column (I) the amounts charged to Accounts 408.1 and 109.1 pertaining to other utility departments and
amounts charged to Accounts 408.2 and 409.2. Also shown in column (I) the taxes charged to utility plant or other balance sheet accounts.
9. For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Line
(Taxes accrued Prepaid Taxes Electric Extraordinary Items Adjustments to Ret.Other No.Acco
~8J 236)
(Incl. in Account 165)(Account 408., 409.(Account 409.Earnings (Account 439)
(h)(i)(k)(I)
588,880 229,864 891
697 236
72,183,706 1,406,242 640,941 325,064
FERC FORM NO.1 (ED. 12-96)Page 263.
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2005/04
This Report Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) DA Resubmission 04/18/2006
ACCUMULA ED DEFERRED INVESTMENT TAX REDITS (Account 255)
Report below information applicable to Account 255. Where appropriate, segregate the balances and transactions by utility and
non utility operations. Explain by footnote any correction adjustments to the account balance shown in column (g).lnclude in column (i)
the average period over which the tax credits are amortized.Line Account Balance at Beginning Deferred for YearS bd' . . of YearNo. l)vlSIOns (b) ccoun o. mounla) (c) (d)
1 Electric Utility
23%
34%
47%
510%
611%
541 183
8 TOTAL
9 Other (List separately
and show 3%, 4%, 7%,
10% and TOTAL)
10 Line 6 Co! A 11%
12 State of Idaho
36,204,352
1,428,762
661,860
66,836,157
411.4 373,779
373,779
411.4
M - '
- ------ -----
661 860 411.4 373,779 411.4 293,
FERC FORM NO.1 (ED. 12-89)Page 266
Name of Respondent
Idaho Power Company
This Report Is: Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
End of 2005/04
(2) D A Resubmission 04/18/2006
ACCUMULATED D FERRED INVESTMENT TAX CRED TS (Account 255) (continued)
Balance at End Avera~e Period
of Year of AI ocation
to Income
385,680
34,256 810 18.
1,401,677 52.
742,106 21.
68,786,273
ADJUSTMENT EXPLANATION Line
No.
742,106
FERC FORM NO.1 (ED. 12-89)Page 267
Name of Respondent This Report Is:Date of Report Year/Period of Report
Idaho Power Company (1) ~An Original (Mo, Da, Yr)End of 2005/04
(2)0 A Resubmission 04/18/2006
OTHER DEFFERED CREDITS (Account 253)
1, Report below the particulars (details) called for concerning other deferred credits.
2, For any deferred credit being amortized, show the period of amortization.
3. Minor items (5% of the Balance End of Year for Account 253 or amounts less than $10,000, whichever is greater) may be grouped by classes,
Line Description and Other Balance at DEBITS Balance at
No.Deferred Credits Beginning of Year Contra Amount Credits End of Year
Account(a)(b)(c)(d)(e)(f)
Joint Pole Use 261 664 400 993,772 197 776 465,668
Bureau of Land Mngt Rents/ROW . . Footriote 273 316 285,116 011 800
Point to Point Transmission Study 851 309 . Footnote 150,963 429,584 129,930
FTV 266,666 400 400,000 000 000 866,666
Linden Feeder 128 831 N/A 200,658 329,489
SWIP Deposit N/A 600,000 600,000
IDACOMM Dark Fiber N/A 000 000
Sho Ban Trans ROW N/A 2,428,334 2,428,334
Delivery Accruals 232 63,177 134 850 71,673
Construction Work In Progress 932 920 107 015 313 652,289 569,896
Customer Level Pay 137,600 232 875,957 873,461 135,104
US Airforce Photovoltaic Generator 168,571 107 600 63,986 203,957
Security Plan 25,519,945 Footnote 311 647 548,000 756,298
FERC Settlement Reserve 000,000 . Footnote 166,666 166 666
Milner Falling Water 192,857 N/A 264 100 3,456,957
Postretirement Benefits 990 894 401 345 950 8,477 653,421
Benefit Plan - Minimum Liability 590,068 N/A 921,420 511,488
Directors Deferred Compensation 216,385 232 231 147 488 560 3,473,798
TOTAL 56,257 710-856,508 271 277 672,479
FERC FORM NO.1 (ED. 12-94)Page 269
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company 1(2)A Resubmisslon 04/18/2006 2005/04
FOOTNOTE DATA
ISchedu/e Page: 269 Line No.232 213,494107 59 823
273,316
Column:
ISchedule Page: 269
232
400
401
Line No.
750
395
818
150 963
ISchedule Page: 269 Line No.232 1 ,953,160241 358,487
311 647
Column:
Column:
ISchedule Page: 269 Line No.182 166 666254 2 000,000
166,666
Column:
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2005/04
This Report Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) D A Resubmission 04/18/2006
ACCUMULATED DEFERRED INCOME TAXES - ACCELERATED AMORTIZATION PROPERTY (Account 281)
1. Report the information called for below concerning the respondent's accounting for deferred income taxes rating to amortizable
property .
2. For other (Specify),include deferrals relating to other income and deductions.
CHANGES DURING YEAR
Line
No.
Account Balance at
Beginning of Year
(a)
1 Accelerated Amortization (Account 281)
2 Electric
(b)
Amounts Debited
to Account 410.
(c)
Amounts Credited
to Account 411.
(d)
3 Defense Facilities
4 Pollution Control Facilities
5 Other (provide details in footnote):
8 TOTAL Electric (Enter Total of lines 3 thru 7)
9 Gas
10 Defense Facilities
11 Pollution Control Facilities
12 Other (provide details in footnote):
15 TOTAL Gas (Enter Total of lines 10 thru 14)
17 TOTAL (Acct 281) (Total of 8,15 and 16)
18 Classification of TOTAL
19 Federal Income Tax
20 State Income Tax
NOTES
FERC FORM NO.1 (ED. 12-96)Page 272
This Report Is: Date of Report
(1) f!)An Original (Mo, Da, Yr)
(2) 0 A Resubmission 04/18/2006
ACCUMULATED DEFERRED INCOME TAXES ACCELERATED AMORTIZATION PROPERTY (Account 281) (Continued)
3. Use footnotes as required.
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2005/04
CHANGES DURING YEAR
Amounts Debited Amounts Credited
to Account 410.to Account 411.
ADJUSTMENTS
Amount
Balance at
End of Year
Line
No.
Debits
~~~--~ ~-----~
NOTES (Continued)
FERC FORM NO.1 (ED. 12-96)Page 273
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2005/04
This Report Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)(2) DA Resubmission 04/18/2006
ACCUMULATED DEFFERED INCOME TAXES - OTHER PROPERTY (Account 282)
1. Report the information called for below concerning the respondent's accounting for deferred income taxes rating to property not
subject to accelerated amortization
2. For other (Specify),include deferrals relating to other income and deductions.
CHANGES DURING YEAR
Line
No.
Account Balance at
Beginning of Year
(a)(b)
Amounts Debited
to Account 410.
(c)
Amounts Credited
to Account 411.
(d)
1 Account 282
2 Electric
360 356 125
585,283,075
260,271
617,721
12,449,497
921 744
13,636,6005 TOTAL (Enter Total oflines 2 thru 4)
6 Non-Operating Property
9 TOTAL Account 282 (Enter Total of lines 5 thru
10 Classification of TOTAL
585,543,346 12,449,497 13,636,600
~--
11 Federal Income Tax
12 State Income Tax
494,281,323
91,262,023
12,242,919
206,578
13,636,600
NOTES
FERC FORM NO.1 (ED. 12-96)Page 274
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2005/04
This Report Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) 0 A Resubmission 04/18/2006
ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282) (Continued)
3. Use footnotes as required.
CHANGES DURING YEAR
Amounts Debited Amounts Credited
to Account 410.to Account 411.
ADJUSTMENTS
Amount
Balance at
End of Year
Line
No.
Debits
182 2,473 54 182
2,473,
2,473,
164,
309,191
370,495 099,
160,
~~-~---
NOTES (Continued)
FERC FORM NO.1 (ED. 12-96)Page 275
This Page Intentionally Left Blank
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2006 2005/04
FOOTNOTE DATA
Schedule Paae: 274 Line No.Column:
2005 Changes during Year Adjustments Debits Adjustments 2005
Credits
(282) "Other" Items Beginning DR to CRto DR to CR to Acct.Acct.Ending
Line Balance 410.411.410.411.credited Amount debited Amount Balance
Repair Allowance 222 385 169,200 53,185
Bridger 427 257 102,400 324 857
N. Valmy 886,766 76,500 810,266
FERC Jurisdictional 818,502 818 502
Taxable CIAC in CWIP Bal.523,007)(3,307,473)900,166 (5,730,646)
CIAC Taxable Income-Acct (326,522)85,531 (326,522)85,531
253.575
Misc Software Develop Costs 154 971 (999,462)(844,491)
Intangible Asset-Labor 8,476,197 603 683 079,880
Deduction
FASB 109 344,219,576 182 2,473,547 182 370,605 346,116,634
TOTAL 360 356,125 (1,617 721)921,744 2,473,547 370,605 359,713,718
IFERC FORM NO.ED. 12-87)Page 450.
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2005/04
This Report Is: Date of Report(1) I!J An Original (Mo, Da, Yr)
(2) DA Resubmission 04/18/2006
ACCUMULATED DEFFERED INCOME TAXES - OTHER (Account 283)
1. Report the information called for below concerning the respondent's accounting for deferred income taxes relating to amounts
recorded in Account 283.
2. For other (Specify),include deferrals relating to other income and deductions.
(a)
Balance at
Beginning of Year
(b)
Line
No.
Account
1 Account 283
2 Electric
5 Ferc Order 144A 075,138 550,082
897 883
9 TOTAL Electric (Total of lines 3 thru 8)
10 Gas
17 TOTAL Gas (Total of lines 11 thru 16)
387,706
19 TOTAL (Acct 283) (Enter Total of lines 9,17 and 18)
20 Classification of TOTAL
21 Federal Income Tax
22 State Income Tax
23 Local Income Tax
23,491 216
719,235
447 857
622,855
12,094,117
2,428,982
NOTES
FERC FORM NO.1 (ED. 12-96)Page 276
This Report Is: Date of Report
(1) 0 An Original (Mo, Da, Yr)
(2) 0 A Resubmission 04/18/2006
ACCUMULATED DEFERRED INCOME TAXES - OTHER (Account 283) (Continued)
3. Provide in the space below explanations for Page 276 and 277. Include amounts relating to insignificant items listed under Other.
4. Use footnotes as required.
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2005/04
CHANGES DURING YEAR
Amounts Debited Amounts Credited
to Account 410.to Account 411.
ADJUSTMENTS
Debits Balance at
End of Year
(k)
525,056
219 219 59,916
59,916
23,955,330
23,430,274
~~-~---
047
047
39,288
39,288 59,916
350,465
780,739
~---
201
717
330
950
338
262
654
19,863,985
916,754
NOTES (Continued)
FERC FORM NO.1 (ED. 12-96)Page 277
Line
No.
This Page Intentionally Left Blank
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2006 2005/Q4
FOOTNOTE DATA
Schedule Page: 276 Line No.Column:
2005 Changes during Year Adjustments Debits Adjustments 2005
Credits
(283) Other Electric:Beginning DR to CR to DR to CR to Acct.Acct.Ending
Balance 410.411.410.411.credited Amount debited Amount Balance
Line
Loss on Reacquired Debt (1,014 614)214 967 229,581)
Conservation Programs 972 343 267,700 704,643
PCA Expense Deferral 845 093 292,173 141 298 995,966
PV Startup Costs 776 776
Post Retiree Benefits 749 17,749
Reorganization Costs 294 798 294 798
Incremental Security Costs 317 911 93,135 224 776
FERC Order 2000 Costs 880 073 880,073
Oregon Excess Power Costs 670 874 778,539 035 367 4,414 046
Professional Fees - IPUC 23,522 391
Order 29505 16,131
Unrealized gains on Mkt 219 219 59,916 949,274
Securities 889,358
TOTAL 28,897,883 10,070,712 15,073 181 916 955 330
ISchedule Page: 276 Line No.Column:
Changes during Year Adjustments Debits Adjustments Credits
Beginning DR to CR to DR to CR to Acct.Acct.Ending
Balance 410.411.410.411.credited Amount debited Amount Balance
Advance Coal Royalties 367 232 614 326 666
047
Oregon Non-Op Prop Tax 820 808
Adj
Unrealized Gain/Loss 19,654 (3,338)22,991
From Rabbi Trust
Total 387 706 047 39,288 350,465
IFERC FORM NO.(ED. 12-87)Page 450.
Name of Respondent This Report Is:Date of Report Year/Period of Report
Idaho Power Company (1)!!IAn Original (Mo, Da, Yr)End of 2005/Q4
(2)DA Resubmlssion 04/18/2006
OTHER REGULATORY LIABILITIES (Account 254)
1. Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if
applicable.
2. Minor items (5% of the Balance in Account 254 at end of period, or amounts less than $50 000 which ever is less),may be grouped
by classes.
3. For Regulatory Liabilities being amortized, show period of amortization.
Balance at Begining DEBITS Balance at End
Line Description and Purpose of of Current of Current
No,Other Regulatory Liabilities QuarterlY ear Account Amount Credits QuarterlY earCredited
(a)(b)(c)(d)(e)(f)
Market to Market Short Term 507 175 771,026 927,951 244,432
Idaho 1999 - NEEA (Nw energy efficiency act)13,040)N/A 13,040
Demand Side Management Rider 29026 813722 &t~.F;~~t~t;620,108 953,227 146,841
Demand Side Management Rider OR ~!~);~~'iii~~~W 36,447 251 281 214 834
BPA Credit-Residential- Idaho 233,436 ~?;K~liiQikWili 930,590 13,538,508 841 354
BPA Credit-Residential- Oregon 40,940 ~,~:~tiibt~~\~l 592,292 551 352
BPA Credit-Farm -Idaho 542,856 142 799,699 791 248 534 405
BPA Credit-Farm - Oregon 16,130 142 68,536 384 16,978
BPA Credit - Conservation 255,966 ;;,~~Z€rf~~)!frif 643,506 561 206 173,666
Pre94 Demand Side Management Order 148,607 254 156 988 381
IPUC Order 29600 13,670,833 182 650000 020,833
OPUC Order 04-283 100,000 182 100,000
Emission Sales Pre Tax 232 22,129 70,001,420 69,979 291
Emission Sales Interest - Idaho N/A 691 45,691
Emission Sales Interest - Oregon N/A 129 129
29,306Boise Operation Center 276 EQciblol~:'
" -
970
FERC Settlement RSV
;;"
fC(iidQt~,;+i':000 000 000 000
Unfunded Accumulated Deferred Income Tax 40,447 293 N/A 180,153 627,446
Asset Retirement Oblication - Removal Cost 147,699,823 N/A 983 276 152,683,099
TOTAL 209,105,349 37,423,291 104 885,247 276,567 305
FERC FORM NO. 1/3.Q (REV 02-04)Page 278
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2006 2005/04
FOOTNOTE DATA
ISchedule Page: 278 Line No.142 1 532 992154 524 824184 1,886232 3,246 343254 311,477401 2,586
620,108
ISchedule Page: 278
142
154
182
232
421
Column:
Line No.
726
077
849
779
36,447
ISchedule Page: 278 Line No.131 4 558142 13,926 032
13,930,590
Column:
Column:
ISchedule Page: 278 Line No.131 100142 592 192
592 292
!Schedule Page: 278
154
232
254
401
Column:
Line No.
883
627 354
247
643,506
ISchedule Page: 278 Line No.163 320401 21 740402 9 911
970
ISchedule Page: 278 Line No.253 1 333 333182 666 667
000 000
Column:
Column:
Column:
IFERC FORM NO.1 (ED. 12-Page 450.
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2005/04
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) 0 A Resubmission 04/18/2006
ELECTRIC OPERATING REVENUES (Account 400)
1, The following instructions generally apply to the annual version of these pages, Do not report quarterly data in columns (c), (e), (f), and (g), Unbilled revenues and MWH
related to un billed revenues need not be reported separately as required in the annual version of these pages.
2, Report below operating revenues for each prescribed account, and manufactured gas revenues in total.
3, Report number of customers, columns (f) and (g), on the basis of meters, in addition to the number of flat rate accounts: except that where separate meter readings are added
for billing purposes, one customer should be counted for each group of meters added, The -average number of customers means the average of twelve figures at the close of
each month.
4, If increases or decreases from previous period (columns (c),(e), and (g)), are not derived from previously reported figures, explain any inconsistencies in a footnote.
(a)
Operating Revenues Year
to Date Quarterly/Annual
(b)
Operating Revenues
Previous year (no Quarterly)
(c)
Line
No.
Title of Account
1 Sales of Electricity
2 (440) Residential Sales
3 (442) Commercial and Industrial Sales
4 Small (or Comm.) (See Instr. 4)
5 Large (or Ind.) (See Instr. 4)
6 (444) Public Street and Highway Lighting
7 (445) Other Sales to Public Authorities
8 (446) Sales to Railroads and Railways
9 (448) Interdepartmental Sales
10 TOTAL Sales to Ultimate Consumers
247,103,087
118,259,189
2,419,886
247,425 040
111 797,200
300,038
11 (447) Sales for Resale
12 TOTAL Sales of Electricity
13 (Less) (449.1) Provision for Rate Refunds
14 TOTAL Revenues Net of Provo for Refunds
15 Other Operating Revenues
667,269,798
142,794,426
810,064 224
400,102
810,464,326
635,835,518
121 147 646
756 983,164
114 364
758,097 528
16 (450) Forfeited Discounts
17 (451) Miscellaneous Service Revenues 5,475,745 214,833
17,912 109 18,085,801
15,223,771 20,423,944
18 (453) Sales of Water and Water Power
19 (454) Rent from Electric Property
20 (455) Interdepartmental Rents
21 (456) Other Electric Revenues
26 TOTAL Other Operating Revenues
27 TOTAL Electric Operating Revenues
38,611 625
849,075,951
724 578
800 822,106
FERC FORM NO.1 (ED. 12-96)Page 300
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2005/Q4
This Report Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) DA Resubmission 04/18/2006
ELECTRIC OPERATING REVENUES (Account 400)
5. Commercial and industrial Sales, Account 442, may be classified according to the basis of classification (Small or Commercial, and Large or Industrial) regularly used by the
respondent if such basis of classification is not generally greater than 1000 Kw of demand, (See Account 442 of the Uniform System of Accounts, Explain basis of classification
in a footnote,
6, See pages 108-109, Important Changes During Period, for important new territory added and important rate increase or decreases,
7, For Lines 2,4,and 6, see Page 304 for amounts relating to un billed revenue by accounts,
8, Include unmetered sales. Provide details of such Sales in a footnote.
MEGAWATT HOURS SOLD
Year to Date Quarterly/Annual Amount Previous year (no Quarterly)
(e)
AVG.NO. CUSTOMERS PER MONTH Line
Current Year (no Quarterly) Previous Year (no Quarterly) No.(f)
(g)
077,227 296,407 74,448 382
3,422,616 334 955 129 120
28,694 890 640 501
13,288,812 13,239,589 448,819 433,465
773,852 885,350
16,062,664 16,124 939 448,819 433,465
16,062 664 124,939 448,819 433,465
Line 12, column (b) includes $
Line 12, column (d) includes
4,495,436
48,366
of unbilled revenues.
MWH relating to unbilled revenues
FERC FORM NO.1 (ED. 12-96)Page 301
This Page Intentionally Left Blank
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2005/04
(2)0 A Resubmission 04/18/2006
SALES OF ELECTRICITY BY RATE SCHEDULES
1, Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2, Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12
if all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
..Ine NumDer ano Iltle Of Kate scneoUie Mvvn ::;010 Kevenue Average NumDer ISvvn of :;iales ~W~~~lderNo.(a)(b)(c)of c%\omers Per re\\stomer
(f)
1 440 - Residential Sales:
2 01 - Residential 729,187 296 136,551 373,493 12,662 0626
3 04 - Residential - EW 562 35,844 11,240 0638
4 05 - Residential- TOD 665 43,291 271 0651
5 15 - Dusk to dawn lighting 446 444,643 1818
6 Unbilled Revenues 27,415 827,307 1031
7 Total 440 760,275 299,487 636 373,602 742 0629
9 442-Commercial & Industrial Sales
07 - General service 307,914 961,410 36,468 8,443 0746
09 - General service 266,464 145,132.336 18,923 172,619 0444
10 - Large power winter service
84 - General Service - Net Meter
15 - Dusk to dawn lighting 848 622,529 1618
19 - Uniform rate contracts 351 174 558,253 129 18,226,155 0360
21 - Interruptible irrigation
24 - Irrigation Pumping 1,448,667 75,280,240 17,818 304 0520
25 - Irrigation Pumping -Time of 18,282 957,915 124 147,435 0524
40 - General service 14,332 852,898 115 12,854 0595
Commercial & Industrial & Unbill 089,162 996,695 0321
Total 442 8,499,843 365,362,276 577 113,974 0430
444 - Public Street Lighting:
32 - Shielded Streel Lighting
40 - General service 614 96,085 405 985 0595
41 - Street lighting 19,595 030,820 142 137 993 1036
42 - Traffic control lighting 7,485 292,981 80,484 0391
Total 444 28,694 2,419 886 640 834 0843
TOTAL Billed 13,240,44€662,774 362 448,501 0501
Total Unbilled Rev.(See Instr. 6)48,36€4,495,436 092
TOTAL 13,288,81.667 269,798 448,60e 050~
FERC FORM NO.1 (ED. 12-95)Page 304
Name of Respondent This
ooort Is:
Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/04
(2)0 A Resubmission 04/18/2006
SALES FOR RESALE (Account 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( i., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the suppliers service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Avera Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly iIIing Avera Avera
fJ5cationTariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Raft River Rural Electric V6-869 869 155
City of Weiser V6-53 027 001 528
American Electric Power Service Cor WSPP 000 000 000
Arizona Public Service Co.WSPP 000 000 000
5 Arizona Public Service Co.WSPP 000 000 000
6 Avista Corp. - WWP Div.WSPP 000 000 000
7 Avista Corp. - WWP Div.WSPP 000 000 000
8 Avista Energy, Inc.WSPP 000 000 000
9 Avista Energy, Inc.WSPP 000 000 000
Benton County PUD WSPP 000 000 000
Black Hills Power Inc.WSPP 000 000 000
Black Hills Power Inc.WSPP 000 000 000
Bonneville Power Administration WSPP 000 000 000
Bonneville Power Administration WSPP 000 000 000
Subtotal RO
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310
Name of Respondent This Report Is:Date of Report Year/Period of Report
Idaho Power Company (1)(8J An Original (Mo, Da, Yr)End of 2005/04
(2)D A Resubmission 04/18/2006
SALES FOR RESALE (Account 447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RO sales together and report them starting at line number one. After listing all RO sales, enter "Subtotal - RO"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RO" in column (a) after this Listing. Enter
Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RO sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RO/Non-RO grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page
401 , line 23. The "Subtotal - Non-RO" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)(g)
(h)(i)(k)
56,093 174 071 188,333 3~o06 365,404
51,513 526 036 147,277
." ""
385,155 059 068
76,400 857,310 857 310
675 417,705 417 705
277,424 12,675,590 12,675 590
200 200
600 136,000 136,000
409 706 18,706
342 12,836 12,836
125 990 990
34,738 303,150 303,150
14,585 502,233 502,233
22,428 935 265 935,265
25,376 1 ,424 760 1 ,424 760
107,606 700,107 335,610 388,755 3,424,472
666,246 135,814 674 555,280 139 369,954
773 852 700,107 138,150,284 944,035 142 794 426
FERC FORM NO.1 (ED. 12-90)Page 311
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/04
(2)0 A Resubmission 04/18/2006
SALES FOR RESALE (Account 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( Le., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the suppliers service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date ofthe contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Avera Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly iIIing Avera Average
cation Tariff Number Demand (MW)Monthly NC Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 BP Energy Company WSPP 000 000 000
2 Burbank, City of WSPP 000 000 000
3 Burbank, City of WSPP 000 000 000
4 Calpine Energy Services, loP.WSPP 000 000 000
5 Cargill Power Markets LLC WSPP 000 000 000
6 Cargill Power Markets LLC WSPP 000 000 000
7 Chelan Co PUD WSPP 000 000 000
8 Chelan Co PUD WSPP 000 000 000
9 Clatskanie PUD WSPP 000 000 000
Clatskanie PUD WSPP 000 000 000
Colton, City of 000 000 000
Constellation Energy Commodities Gr WSPP 000 000 000
Constellation Energy Commodities Gr WSPP 000 000 000
Coral Power, LLC WSPP 000 000 000
Subtotal RO
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da. Yr)End of 2005/04
(2)D A Resubmission 04/18/2006
SALES FOR RESALE (Account 447) (Continued)
as - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RO sales together and report them starting at line number one. After listing all RO sales, enter "Subtotal - RO"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line ofthe schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RO sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP demand is the maximum
metered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (50-minute
integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (t) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-ot-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RO/Non-RO grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page
401 , line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)(g)
(h)(i)(k)
114,169 442,446 5,442,446
725 725
225 500 500
626 37,800 37,800
1,493 149,850 149,850
78,468 198,962 198,962
391 14,486 14,486
200 114 100 114,100
628 38,761 38,761
400 000 17,000
10,256 293,363 293,363
998 75,794 75,794
890 333,775 333,775
112 950 708,087 708,087
107 606 700.107 335,610 388,755 3,424,472
666,246 135,814 674 555,280 139 369,954
773,852 700 107 138,150,284 944,035 142 794 426
FERC FORM NO.1 (ED. 12-90)Page 311.
Name of Respondent This
0'ort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/04
(2)D A Resubmission 04/18/2006
SALES FOR RESALE (Account 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( Le., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the suppliers service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Avera Actual Demand (MW)
Classifi-Schedule or Monthly iIIing 7Wera AverageNo,(Footnote Affiliations)cation Tariff Number Demand (MW)Monthly NC Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 EI Paso Electric Company WSPP 000 000 000
2 ENMAX Energy Marketing Inc.WSPP 000 000 000
3 Eugene Water & Electric Board WSPP 000 000 000
4 Eugene Water & Electric Board WSPP 000 000 000
5 Franklin County P.WSPP 000 000 000
6 Grant County P.WSPP 000 000 000
7 Grant County P.U.D.WSPP 000 000 000
8 Grays Harbor PUD WSPP 000 000 000
9 J. Aron & Company WSPP 000 000 000
Morgan Stanley Capital Group Inc.WSPP 000 000 000
Morgan Stanley Capital Group Inc.WSPP 000 000 000
Northern California Power Agency WSPP 000 000 000
NorthWestern Energy 147 000 000 000
NorthWestern Energy 147 000 000 000
Subtotal RO
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
Name of Respondent This ooort Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/04
(2)0 A Resubmission 04/18/2006
SALES FOR RESALE (Account 447) (Continued)
as - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RO sales together and report them starting at line number one. After listing all RO sales, enter "Subtotal - RO"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RO" in column (a) after this Listing. Enter
Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RO sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (t) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (D. Explain in a footnote all components of the amount shown in column (D. Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RO/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401 , line 23. The "Subtotal - Non-RO" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)(g)
(h)(i)(k)
205 200 16,200
200 42,000 000
710 29,480 29,480
12,000 514,300 514 300
350 350
402 19,765 765
800 300 39,300
968 968
200 426 650 426,650
300 113,872 113,872
187,737 10,024 784 024,784
092 380,124 380,124
58,617 554 850 554,850
'C.514,620
107 606 700,107 335,610 388,755 3,424,472
666 246 135,814 674 555,280 139,369,954
773,852 700,107 138 150,284 944 035 142 794,426
FERC FORM NO.1 (ED. 12-90)Page 311.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/Q4
(2)0 A Resubmission .04/18/2006
SALES FOR RESALE (Account 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( Le., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Avera Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly iIIing l-wera AveracationTariff Number Demand (MW)Monthly NC Deman Monthly CP emanc
(a)(b)(c)(d)(e)(f)
1 NorthWestern Energy WSPP 000 000 000
2 Pacific Northwest Generating Cooper WSPP 000 000 000
3 Pacific Northwest Generating Cooper wSPP 000 000 000
4 PacifiCorp Inc.WSPP 000 000 000
5 PacifiCorp Inc.000 000 000
6 PacifiCorp Inc.WSPP 000 000 000
7 PacifiCorp Inc.WSPP 000 000 000
8 Pinnacle West Capital Corporation WSPP 000 000 000
9 Pinnacle West Capital Corporation WSPP 000 000 000
Portland General Electric Company WSPP 000 000 000
Portland General Electric Company WSPP 000 000 000
Portland General Electric Company WSPP 000 000 000
Powerex Corp.WSPP 000 000 000
Powerex Corp.WSPP 000 000 000
Subtotal RQ
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
Name of Respondent This Report Is:Date of Report Year/Period of Report
Idaho Power Company (1)lKJ An Original (Mo, Da, Yr)End of 2005/04
(2)D A Resubmission 04/18/2006
SALES FOR RESALE (Account 447) (Continued)
as - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQn in column (a) after this Listing. Enter
Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the suppliers system reaches its monthly peak. Demand reported in columns (e) and (t) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (D. Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401 , line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)(g)
(h)(i)
(j)
(k)
540 540
245 13,750 13,750
200 161 850 161 850
38,250
207 13,338 13,338
606 854,164 854 164
114,400 509,135 509,135
437 40,336 40,336
800 387,450 387,450
810
50,902 266,314 266,314
187 083 532 956 532,956
65,989 385,575 385,575
461 657 25,447,906 25,447 906
107 606 700 107 335 610 388 755 3,424,472
666,246 135 814,674 555 280 139,369,954
773,852 700,107 138,150,284 944 035 142,794,426
FERC FORM NO.1 (ED. 12-90)Page 311.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/04
(2)D A Resubmission 04/18/2006
SALES FOR RESALE (Account 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( Le., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Avera Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly iIIing Avera AveracationTariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 PPL Montana, LLC WSPP 000 000 000
PPL Montana, LLC WSPP 000 000 000
PPL Montana, LLC WSPP 000 000 000
PPM Energy, Inc.WSPP 000 000 000
5 PPM Energy, Inc.WSPP 000 000 000
Public Service Co. of Colorado WSPP 000 000 000
7 Public Service Co. of Colorado WSPP 000 000 000
Public Service Company of New Mexic WSPP 000 000 000
Public Service Company of New Mexic WSPP 000 000 000
Puget Sound Energy, Inc.WSPP 000 000 000
Puget Sound Energy, Inc.WSPP 000 000 000
Rainbow Energy Marketing Corporatio WSPP 000 000 000
Salt River Project WSPP 000 000 000
Seattle City Light WSPP 000 000 000
Subtotal RO
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
Name of Respondent This Report Is:Date of Report Year/Period of Report
Idaho Power Company (1)(KJ An Original (Mo, Da, Yr)End of 2005/04
(2)0 A Resubmission 04/18/2006
SALES FOR RESALE (Account 447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
5. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP demand is the maximum
metered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (50-minute
integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (t) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (D. Explain in a footnote all components of the amount shown in column (D. Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page
401 , line 23. The "Subtotal - Non-RO" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges (h+i+j)No.
($)($)($)(g)
(h)(i)(k)
600
229 150,046 150,046
23,960 235,246 235,246
840 27,853 27,853
51,800 831 500 831,500
208 199,224 199,224
23,400 058,890 058,890
015 188,425 188,425
200 65,800 65,800
20,047 055,511 055,511
243 325 670 325,670
21,625 043,095 043 095
710 80,080 80,080
10,992 738,621 738,621
107 606 700 107 335,610 388 755 3,424,472
666,246 135,814,674 555 280 139 369,954
773,852 700,107 138 150,284 944,035 142 794 426
FERC FORM NO.1 (ED. 12-90)Page 311.
Name of Respondent This i:8)ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/04
(2)D A Resubmission 04/18/2006
SALES FOR RESALE (Account 447)
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( Le., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
line Name of Company or Public Authority Statistical FERC Rate Avera Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly iIIing Avera Avera
cation Tariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Seattle City light WSPP 000 000 000
2 Sempra Energy Trading Corporation WSPP 000 000 000
3 Sempra Energy Trading Corporation WSPP 000 000 000
4 Snohomish County PUD WSPP 000 000 000
5 Snohomish County PUD WSPP 000 000 000
6 SUEZ Energy Marketing NA, Inc.WSPP 000 000 000
7 SUEZ Energy Marketing NA, Inc.WSPP 000 000 000
8 Tacoma Power WSPP 000 000 000
9 Tractebel Energy Marketing, Inc.WSPP 000 000 000
Tractebel Energy Marketing, Inc.WSPP 000 000 000
TransAlta Energy Marketing (U.) I WSPP 000 000 000
TransAlta Energy Marketing (U.) I WSPP 000 000 000
Utah Associated Municipal Power Sys WSPP 000 000 000
Utah Associated Municipal Power Sys WSPP 000 000 000
Subtotal RO
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
Name of Respondent This
wort
Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/04
(2)D A Resubmission 04/18/2006
SALES FOR RESALE (Account 447) (Continued)
as - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RO sales together and report them starting at line number one. After listing all RO sales, enter "Subtotal - RO"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RO" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RO sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (t) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RO/Non-RO grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RO" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)(g)
(h)(i)(k)
623 536 858 536,858
275 275
256 319 13,614,374 13,614 374
018 281,635 281 635
912 66,870 66,870
534 390,713 390 713
585 522,270 522,270
705 38,600 38,600
350 15,800 15,800
000 084,300 084,300
16,462 637 087 637,087
625 778,545 778,545
192 286,345 286,345
820 040 60,040
107,606 700,107 335,610 388,755 3,424,472
666,246 135,814 674 555,280 139,369 954
773,852 700,107 138,150,284 944,035 142,794,426
FERC FORM NO.1 (ED. 12-90)Page 311.
Name of Respondent This
0ort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/Q4
(2)0 A Resubmission 04/18/2006
SALES FOR RESALE (Account 447)
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RO - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RO service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Avera Actual Demand (MW)
Classifi-Schedule or Monthly illing Avera AveraNo.(Footnote Affiliations)cation Tariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
2 Bad Deb Write off
OS Sales: NON Firm Sales
Subtotal RQ
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/04
(2)D A Resubmission 04/18/2006
SALES FOR RESALE (Account 447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (t) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)(g)
(h)(i)(k)
650 650
107,606 700,107 335,610 388,755 3,424,472
666,246 135,814 674 555,280 139,369 954
773 852 700,107 138,150 284 944,035 142 794 426
FERC FORM NO.1 (ED. 12-90)Page 311.
This Page Intentionally Left Blank
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da , Yr)
Idaho Power Company (2)A Resubmission 04/18/2006 2005/04
FOOTNOTE DATA
ISchedu/e Page: 310 Line No.Column:
(1) Customer Charge
ISchedu/e Page: 310 Line No.Column:
(3) Network Transmission Charges
ISchedu/e Page: 310.Line No.14 Column:
(2) Capacity and Penalty Charge
ISchedu/e Page: 310.Line No.Column:
(4) Spinning or Operating Reserves
ISchedu/e Page: 310.Line No.10 Column:
(4) Spinning or Operating Reserves
ISchedule Page: 310.Line No.Column:
(4) Spinning or Operating Reserves
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report Is:Date of Report Year/Period of Report
Idaho Power Company (1) l!)An Original (Mo, Da, Yr)End of 2005/04
(2)0 A Resubmission 04/18/2006
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line Account
IIiiIIIiINo.urrent ear Previous Year
(a)(b) (c)
1. POWER PRODUCTION EXPENSES
A. Steam Power Generation
Operation
(500) Operation Supervision and Engineering 277 646 1,187 136
(501) Fuel 98,982,043 98,387,370
(502) Steam Expenses 895,514 333,426
(503) Steam from Other Sources
8 (Less) (504) Steam Transferred-Cr.
9 (505) Electric Expenses 610,776 558,515
(506) Miscellaneous Steam Power Expenses 795,112 868,516
(507) Rents 325,176 710,713
(509) Allowances
TOTAL Operation (Enter Total of Lines 4 thru 12)115,886,267 113,045,676
Maintenance
(510) Maintenance Supervision and Engineering 130,215 859,869
(511) Maintenance of Structures 421 603 358,798
(512) Maintenance of Boiler Plant 855,366 12,665,232
(513) Maintenance of Electric Plant 612 002 182,203
(514) Maintenance of Miscellaneous Steam Plant 240,867 076,141
TOTAL Maintenance (Enter Total of Lines 15 thru 19)25,260,053 142,243
TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 & 20)141 146,320 137,187,919
B. Nuclear Power Generation
Operation
(517) Operation Supervision and Engineering
(518) Fuel
(519) Coolants and Water
(520) Steam Expenses
(521) Steam from Other Sources
(Less) (522) Steam Transferred-Cr.
(523) Electric Expenses
(524) Miscellaneous Nuclear Power Expenses
(525) Rents
TOTAL Operation (Enter Total of lines 24 thru 32)
Maintenance
(528) Maintenance Supervision and Engineering
(529) Maintenance of Structures
(530) Maintenance of Reactor Plant Equipment
(531) Maintenance of Electric Plant
(532) Maintenance of Miscellaneous Nuclear Plant
TOTAL Maintenance (Enter Total of lines 35 thru 39)
TOTAL Power Production Expenses-Nuc. Power (Entr tot lines 33 & 40)
C. Hydraulic Power Generation
Operation
(535) Operation Supervision and Engineering 556,943 4,421,651
(536) Water for Power 266 568 016,995
(537) Hydraulic Expenses 163,818 792,153
(538) Electric Expenses 264 687 245,717
(539) Miscellaneous Hydraulic Power Generation Expenses 894 576 528,085
(540) Rents 359,290 379,919
TOTAL Operation (Enter Total of Lines 44 thru 49)20,505,882 19,384 520
FERC FORM NO.1 (ED. 12-93)Page 320
This Report Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)(2) DA Resubmission 04/18/2006
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.Line Account Amount for
51 C. Hydraulic Power Generation (Continued)
52 Maintenance
53 (541) Mainentance Supervision and Engineering
54 (542) Maintenance of Structures
55 (543) Maintenance of Reservoirs, Dams, and Waterways
56 (544) Maintenance of Electric Plant
57 (545) Maintenance of Miscellaneous Hydraulic Plant
58 TOTAL Maintenance (Enter Total of lines 53 thru 57)
59 TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 & 58)
60 D. Other Power Generation
61 Operation
62 (546) Operation Supervision and Engineering
63 (547) Fuel
64 (548) Generation Expenses
65 (549) Miscellaneous Other Power Generation Expenses
66 (550) Rents
67 TOTAL Operation (Enter Total of lines 62 thru 66)
68 Maintenance
69 (551) Maintenance Supervision and Engineering
70 (552) Maintenance of Structures
71 (553) Maintenance of Generating and Electric Plant
72 (554) Maintenance of Miscellaneous Other Power Generation Plant
73 TOTAL Maintenance (Enter Total of lines 69 thru 72)
74 TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73)
75 E. Other Power Supply Expenses
76 (555) Purchased Power
77 (556) System Control and Load Dispatching
78 (557) Other Expenses
79 TOTAL Other Power Supply Exp (Enter Total of lines 76 thru 78)
80 TOTAL Power Production Expenses (Total of lines 21 , 41, 59, 74 & 79)
81 2. TRANSMISSION EXPENSES
82 Operation
83 (560) Operation Supervision and Engineering
84 (561) Load Dispatching
85 (562) Station Expenses
86 (563) Overhead Lines Expenses
87 (564) Underground Lines Expenses
88 (565) Transmission of Electricity by Others
89 (566) Miscellaneous Transmission Expenses
90 (567) Rents
91 TOTAL Operation (Enter Total of lines 83 thru 90)
92 Maintenance
93 (568) Maintenance Supervision and Engineering
94 (569) Maintenance of Structures
95 (570) Maintenance of Station Equipment
96 (571) Maintenance of Overhead Lines
97 (572) Maintenance of Underground Lines
98 (573) Maintenance of Miscellaneous Transmission Plant
99 TOTAL Maintenance (Enter Total of lines 93 thru 98)
100 TOTAL Transmission Expenses (Enter Total of lines 91 and 99)
101 3. DISTRIBUTION EXPENSES
102 Operation
103 (580) Operation Supervision and Engineering
Name of Respondent
Idaho Power Company
YearlPeriod of Report
End of 2005104
Amount forPrevious Year
(c)
275,738 058,293
899,749 004,778
683,950 032,152
2,466,384 268,044
854 670 642 221
180,491 005,488
686,373 27,390,008
390,680 391 835
181,468 874,063
231 162 170,854
342,401 298,934
145,711 735,686
194 230
255,394 123,893
30,292 69,240
428 740 240,994
714 620 434 357
860,331 170,043
222 310,315 195,642,193
77,483 106,362
023,410 082 749
221 364 388 236,831 304
397 057,412 407 579,274
013,395 031 371
971 942 909,482
591,008 686,223
515,152 544 172
657 106 8,441 863
297,608 17,854
565 610 176 624
16,611 821 807,589
695,940 653 160
184
688,845 009 973
908,500 356,489
16,446 878
377 915 027,500
989,736 23,835,089
FERC FORM NO.1 (ED. 12-93)Page 321
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2005/04
This Report Is: Date of Report
(1) Q9 An Original (Mo, Da, Yr)(2) DA Resubmission 04/18/2006
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.Line Account Amount for
(a)(b)
104 3. DISTRIBUTION Expenses (Continued)
105 (581) Load Dispatching
106 (582) Station Expenses
107 (583) Overhead Line Expenses
108 (584) Underground Line Expenses
109 (585) Street Lighting and Signal System Expenses
110 (586) Meter Expenses
111 (587) Customer Installations Expenses
112 (588) Miscellaneous Expenses
113 (589) Rents
114 TOTAL Operation (Enter Total of lines 103 thru 113)
115 Maintenance
116 (590) Maintenance Supervision and Engineering
117 (591) Maintenance of Structures
118 (592) Maintenance of Station Equipment
119 (593) Maintenance of Overhead Lines
120 (594) Maintenance of Underground Lines
121 (595) Maintenance of Line Transformers
122 (596) Maintenance of Street Lighting and Signal Systems
123 (597) Maintenance of Meters
124 (598) Maintenance of Miscellaneous Distribution Plant
125 TOTAL Maintenance (Enter Total of lines 116 thru 124)
126 TOTAL Distribution Exp (Enter Total of lines 114 and 125)
127 4. CUSTOMER ACCOUNTS EXPENSES
128 Operation
129 (901) Supervision
130 (902) Meter Reading Expenses
131 (903) Customer Records and Collection Expenses
132 (904) Uncollectible Accounts
133 (905) Miscellaneous Customer Accounts Expenses
134 TOTAL Customer Accounts Expenses (Total of lines 129 thru 133)
135 5. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
136 Operation
137 (907) Supervision
138 (908) Customer Assistance Expenses
139 (909) Informational and Instructional Expenses
140 (910) Miscellaneous Customer Service and Informational Expenses
141 TOTAL Cust. Service and Information. Exp. (Total lines 137 thru 140)
142 6. SALES EXPENSES
143 Operation
144 (911) Supervision
145 (912) Demonstrating and Selling Expenses
146 (913) Advertising Expenses
147 (916) Miscellaneous Sales Expenses
148 TOTAL Sales Expenses (Enter Total of lines 144 thru 147)
149 7. ADMINISTRATIVE AND GENERAL EXPENSES
150 Operation
151 (920) Administrative and General Salaries
152 (921) Office Supplies and Expenses
153 (Less) (922) Administrative Expenses Transferred-Credit
AmountfprPrevious Year
(c)
536,857
945,089
967 382
733,935
120,630
108,887
773,447
603,412
157,873
792,543
395,937
950,120
481 870
670,619
151,313
127,933
545,521
997 634
150,421
22,080,049
91,162
69,106
629,976
10,928,110
109,939
321 335
378 751
773,149
230,529
16,532,057
324,600
66,616
932,915
11,137 680
245,264
259,850
494 696
953,983
178 232
269,236
39,349,285
494 549
723,518
292 260
556,140
28,055
16,094 522
426,782
724,432
290,028
009,866
051
17,445,057
763,679
620,257
313,453
346,134
525
732,850
397 962
281,012
575,566
,----------
40,438,326
16,117 873
23,657,334
232,476
14,719,947
26,358,321
FERC FORM NO.1 (ED. 12-93)Page 322
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2005/04
This Report Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) 0 A Resubmission 04/18/2006
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.Line Account Amount forCurrent Yearo. (a) (b)
154 7. ADMINISTRATIVE AND GENERAL EXPENSES (Continued)
155 (923) Outside Services Employed
156 (924) Property Insurance
157 (925) Injuries and Damages
158 (926) Employee Pensions and Benefits
159 (927) Franchise Requirements
160 (928) Regulatory Commission Expenses
161 (929) (Less) Duplicate Charges-Cr.
162 (930.1) General Advertising Expenses
163 (930.2) Miscellaneous General Expenses
164 (931) Rents
165 TOTAL Operation (Enter Total of lines 151 thru 164)
166 Maintenance
167 (935) Maintenance of General Plant
168 TOTAL Admin & General Expenses (Total of lines 165 thru 167)
169 TOTAL Elec Op and Maint Expn (Tot 80 100,126,134 141 148,168)
Amount forPrevious Year
(c)
823,980
866 971
711,625
956,720
300
009 949
056,785
207,907
996,017
26,676,544
075
976,930
120,381
856 141
800
78,250 732
118,315
959,515
12,291
82,600,481
3,473,712
81,724,444
564 810,971
525,892
85,126,373
581 733,040
FERC FORM NO.1 (ED. 12-93)Page 323
Name of Respondent This Report Is:Date of Report Year/Period of Report
Idaho Power Company (1)lKJ An Original (Mo, Da, Yr)End of 2005/04
(2)D A Resubmission 04/18/2006
~CHA$ED POWER hAccount 555)ncludlng power exc anges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average Average
cation Tariff Number Demand (MW)Monthly NCP Demanc Monthly CP Demand
(a)(b)(c)(d)(e)(f)
COGENERATION AND SMALL POWER
Willis and Betty Deveny
3 James B. Howell/CHI
4 ~t~~,
~~'
~~.9.*~~~i:~~,ij);,
. "'
942
5 Owyhee Irrigation District
Mitchell Butte
Owyhee Dam
Tunnel #1
Reynolds Irrigation District
Clifton E. Jenson
Snake River Pottery
White Water Ranch
John R LeMoyne
David R Snedigar
Total
FERC FORM NO.1 (ED. 12-90)Page 326
Name of Respondent This
ooort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/04
(2)0 A Resubmission 04/18/20060 ccou~t 55
~~)
(l,;OntinuedJ(Including power exc ange )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (50-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
5. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received , enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total G+k+l)No.Received Delivered
($)($)
of Settlement ($)
(g)
(h)(i)(I)(m)
79~50,19~50,199
04E 267 17.267 172
58C 576,498 214 68E 791 186
72~447 08~447 089
19,039 313,265 313,265
17,49/898,901:898,906
20'83,264 83,264
500 759 22,259
38e 24,68e 685
561 35,35,967
35,14.35,142
151 76,131:76,136
918,389 110,013 327,466 815,124 219,383,501 111 690 222 310,31e
FERC FORM NO.1 (ED. 12-90)Page 327
Name of Respondent
Idaho Power Company
This Report Is:
(1) (8J An Original
(2) 0 A Resubmission
PURCHASED POWER IAccount 555)(Including power exchanges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
Date of Report
(Mo, Da , Yr)
04/18/2006
Year/Period of Report
End of 2005/04
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
1 Mud Creek Hydro, Inc
2 ,~!m::i!+Vt~~~~~iP~~i~~f~;:~;:\;;;;;';;;~;~~'
~;'
j*~~f1
3 Curry Cattle Company
4 Branchflower Company
5 Big Wood Canal Company
Black Canyon
Jim Knight
Sagebrush
9 tFi~~~;~~~I9E11tJ1nJ;1~rii'~J:
:, .::;
0:!
10 Shorock Hydro Inc.11 Shoshone Cspp12 Shoshone #2
13 Rock Creek #1 Joint Venture
14 Richard Kaster
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)Average Average
Monthly NCP Deman Monthly CP Demand(e) (f)
084
;:;'
?i\~'~ OS
"":.;",..:,
732
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/04
(2)D A Resubmission 04/18/2006ED ccou~t 55
~~,
(ContinUed)(Including power exc ange )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (50-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
5. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line ofthe schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered
($)($)
of Settlement ($)
(g)
(h)(i)(I)(m)
32!20,24.20,242
22!58,92~58,925
56'26,796 69~36,495
84!56,56,209
331 22,35!22,358
111 77,840'844
94'66,83,66,833
19:49,192
89(128 691 128,691
78€118,4H 118,419
77~552 508 150,78~703,292
918 389 110,013 327,466 815,124 219 383 501 111 690 222,310,311
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/Q4
(2)D A Resubmission 04/18/2006
~C~~ED POWER hAccount 555)nc u Ing power exc anges)
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories. such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
Box Canyon
Briggs Creek
3 David McCollum
HK Hydro Mud Creek S & S
AlianNemon Ravenscroft .488
6 William Arkoosh
7 Clear Springs Food Inc.
8 Koyle Hydro Inc.
9 Kasel & Witherspoon
Lateral 10 Ventures
Crystal Springs Hydro
Pigeon Cove Power 389
Consolidated Hydro Inc. Enel
GeoBon #2
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/04
(2)D A Resubmission 04/18/2006
PURCHA~~D ~QW~~Sf.ccouRt 55
~~)
ll,;ontinUed)Including power exc ange
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (50-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
5. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered
($)($)
of Settlement ($)
(g)
(h)(i)(I)(m)
73€109,46~109,464
62E 233,761 233,761
73~34,17€176
1 ,28~78,62~78,622
51~155 672 26, 10~181 775
98E 218,84C 218,840
541 259 15E 259 155
971 209,38~209,383
60e 237, 14~237 143
01 ,509,509 903
7,46~480,86C 480,860
38~486 150 110,259 596,409
65~195 73'i 195,735
918 389 110 013 327,466 815 124 219,383,501 111 690 222,310,31'i
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This Report Is:Date of Report Year/Period of Report
Idaho Power Company (1)!K) An Original (Mo, Da, Yr)End of 2005/04
(2)D A Resubmission 04/18/2006
PU~CHA$ED POWER hAccount 555)( ncludlng power exc anges)
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
Enter the name of the seller or other party in an exchange transaction in column (a).Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
Barber Dam
Rock Creek #2
Dietrich Drop
Lowline #2
Cedar Draw/Little Mac Power Co.
6 South Forks Joint Venture (5)
7 Little Wood River Irrigation Dis
8 Marco Ranchers Irrigation Inc.
9 Faulkner Brothers Hydro Inc.
Magic Reservoir Hydro
Bypass Limited
SE Hazelton A LP
~~~'
::I;V;~~'M~~r;
;;;,
;~;;;,;~;;;;;;i.'.
", ,, ,,
Lemhi HydroPower Company
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/04
(2)0 A Resubmission 04/18/2006
PUKl,;HA~~Ml .1-':..
.,.~;'.\
AccouHt 55~L\(Contlnued)Including power exc anges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.
Received Delivered
($)($)
of Settlement ($)
(g)
(h)(i)(I)(m)
841 484 06-4 484 064
31!292 70e 292,705
31C 665,29-4 665,294
34~431.49~431.492
20.326,20~326,203
85(601,601 292
2713 447.46~447.463
01E 130,30(130,306
791 210,57E 210,575
18C 662,652 662 652
23,23~203 545 203,545
19,84C 983,206 983,206
11f 649 649
255 90,76.1 763
918,389 110,013 327.466 815 124 219,383,501 111 690 222 310,311;
FERC FORM NO.1 (ED. 12-90)Page 327.
This Report Is:
(1) IKJAn Original(2) 0 A Resubmission
PURCHASED POWER (Account 555)(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
Name of Respondent
Idaho Power Company
Date of Report
(Mo, Da, Yr)
04/18/2006
Year/Period of Report
End of 2005/Q4
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
J R Simplot Co.
Blind Canyon Hydro
City of Hailey
City of Pocatello
Pristine Springs Inc.
9 Vaagen Brothers Lumber Inc.
10 Horseshoe Bend Hydro
11 Contractors Power Group Inc.
12 Rupert Cogeneration Partners
13 Glenns Ferry Cogeneration Partne
14 ;f~"~PW~~i.F:~!'iii~~;,~:
' .' .
Total
FERC FORM NO.1 (ED. 12-90)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Actual Demand (MW)Average Average
Monthly NCP Deman Monthly CP Demand(e) Average
Monthly Billing
Demand (MW)
(d)
)OS
. .
Page 326.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
Idaho Power Company
(1) X An Original (Mo, Da, Yr)End of 2005/04
(2)D A Resubmission 04/18/2006
P" ow' "'~ncrt..2YY~~J.ACcou~t 55
~~)
(ContlnUed)Including power exc ange )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (50-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (9) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.
Received Delivered
($)
of Settlement ($)
(g)
(h)(i)(I)(m)
61,67C 825,171 825,175
3,49~251,481 251,486
31C 221 91,226
44,95'633,91'633,915
22'1,475,10~1,475,109
19,65'303,53E 303,536
891 42,99f 998
22,378,83.378,832
33,29~223,98~223,983
921 259,37'259,374
87~898,898,573
78~4,433,00C 4,433 000
23,10,10,219
918,389 110,013 327,466 815,124 219,383 501 111 690 222,310,
FERC FORM NO.1 (ED. 12-90)Page 327.
This ~ort Is:(1) ~An Original
(2) D A Resubmission
PUR A$ED POWER (Account 555)(lnc udmg power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
Name of Respondent
Idaho Power Company
Date of Report
(Mo, Da, Yr)
04/18/2006
Year/Period of Report
End of 2005/04
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classifi-
cation
'OS
10 Arizona Public Service Co.
11 ::~~P,~~.:i~~~i:;;~,~i~~&:ii\)~0,j:~;~,-;~;i; AD
12 t\l!$~i~~;~~~~'R;6g:
:;"
:;Y:i\;;'
:\!'~';;;:j;
13 Avista Corp. - WWP Div.
14 :~w'~i:~Rmiii~~lm~fi'W;
;~'
ri;:XO:'
:,.,
' SF
Total
FERC FORM NO.1 (ED. 12-90)
FERC Rate
Schedule or
Tariff Number
(c)
Actual Demand (MW)Average Average
Monthly NCP Deman Monthly CP Demand(e) (f)
Average
Monthly Billing
Demand (MW)
(d)
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
Page 326.
Name of Respondent This
ooort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/04
(2)0 A Resubmission 04/18/2006
PO RCHA~~gl Accou~t 55~~) (Continued)Including power exc ange )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the suppliers system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l)No.
Received Delivered
($)($)
of Settlement ($)
(g)
(h)(i)
(j)
(I)(m)
85f 858
24.69(690
1,41.35f 358
70'345,345,267
18,004 726 726 247
68,OOC 210,68C 210,680
33"333
64f 140,56C 140,560
34,47"1,491 ,01 ~1,491,012
350 350
740 202,60C 202,600
207
925 925
918 389 110,013 327,466 815,124 219,383 501 111,690 222,310,315
FERC FORM NO.1 (ED. 12-90)Page 327.
This Report Is:(1) ~An Original
(2) 0 A Resubmission
PURCHASED POWER (Account 555)(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
Name of Respondent
Idaho Power Company
Date of Report
(Mo, Da, Yr)
04/18/2006
YearlPeriod of Report
End of 2005104
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No.
Statistical
Classifi-
cation
(b)
Name of Company or Public Authority
(Footnote Affiliations)
(a)
1 Avista Corp. - WWP Div.
2 i~~)~:~~t6j,g~i~1(:fFt::2;:c~/(;'X:(;~;;~c
!;~;"
:H;
3 Avista Energy, Inc.
4 ;~~9J9~;~~fg~m:~~\;;.~q~-
5 Benton County PUD
8 ;'
9 Black Hills Power Inc.
1 0 r~9'~~~~j~~~W!~JIW;t\)m~~9:
11 Bonneville Power Administration
12 Bonneville Power Administration
13 BP Energy Company
14 ~~lpi~:~~~r~~.\~~I~H~,;~;'
" .
;;;:;:;OS
etOS
Total
FERC FORM NO.1 (ED. 12-90)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)Average Average
Monthly NCP Deman Monthly CP Demand(e) (f)
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
Page 326.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/04
(2)D A Resubmission 04/18/2006
PURCHATI~gl . Accou~t 55~L\((.;ontinued)Including'power exc anges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line ofthe schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l)No.Received Delivered
($)($)
of Settlement ($)
(g)
(h)(i)
(j)
(I)(m)
34C 188,30(188 300
82~488,72f 488 728
9,4H 759,759,61S
84!39,33!335
80(121,400 121,400
5f:280 280
32,76S 823 720 823,720
80C 20C 42,200
00C 87,40C 87,400
951 000,37f 000,378
22~11,321 323
209,47'9,455 151 9,455,153
115 55C 984,07f 984 078
60(312, 10~312,109
918,389 110,013 327,466 815,124 219,383 501 111 690 222 310
FERC FORM NO.1 (ED. 12-90)Page 327.
This Report Is:
(1) (K) An Original(2) DA Resubmission
PURCHASED POWER (Account 555)(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
Name of Respondent
Idaho Power Company
Date of Report
(Mo, Da, Yr)
04/18/2006
Year/Period of Report
End of 2005/04
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Statistical
Classifi-
cation
(b)
4 Cargill Power Markets LLC 5 Chelan Co PUD
6 Chelan Co PUD
;~~~:ft~~~'i~~3~~M;i~:~E~t~";;;:Hj;::,i;;;;:'O:"P): 8 Clatskanie PUD
9 ;~~~I\~q:~",.~mm.~~~~?:::'
;:. :
:;\:":, OS
10 Constellation Energy Commodities
11 Coral Power, LLC 12:RgY91~~~"w;e.\!p::; 13 Douglas County PUD
14 Douglas County PUD
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
1 Calpine Energy Services, L.
2 ;'
Total
FERC FORM NO.1 (ED. 12-90)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)Average Average
Monthly NCP Deman Monthly CP Demand(e) (f)
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
Page 326.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/04
(2)D A Resubmission 04/18/2006
PU RCHA~~D P.PW~~tAccouHt 55~~) (Continued)Including power exc ange
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total G+k+l)No.Received Delivered
($)($)
of Settlement ($)
(g)
(h)(i)(I)(m)
OO(186,50(186,500
351
??(
770
00(000
46,91C 526,54E 526,545
22~229
60(235,20(235,200
59E 83(830
43,75!43,755
94,69,951 69,951
13,80(170,80(170,800
296,80f 173,72(173,720
02!025
11/117
00(63,5Oc 500
918,389 110,013 327 466 815,124 219,383 501 111 690 222,310,
FERC FORM NO.1 (ED. 12-90)Page 327.
This Report Is:(1) IKJ An Original
(2) D A Resubmission
PURCHASED POWER (Account 555)(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
Name of Respondent
Idaho Power Company
Date of Report
(Mo, Da, Yr)
04/18/2006
Year/Period of Report
End of 2005/04
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services , where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No.
Statistical
Classifi-
cation
(b)
: ,,' '
: OS
, , '-- ':,,
;: OS
""', "
:OS
Name of Company or Public Authority
(Footnote Affiliations)
(a)
1 EI Paso Electric Company
ig~9g~~~t~~~~~~~~~;:E;:'?'
\:;',
3 Eugene Water & Electric Board
4 .~~~!,:~:~q~tY;)p.~~:;!)J~~tf!if'
;~:::"
.':Y:~'
:. :";:--
5 Franklin County P.
6 i~~n~~~ilW;ffJYJ~~t"~~(:~f~5;
7 Grant County P.
8 Grant County P.
9;~~V-$'11~fqO$~~~~:;:7'
::::"';- '
10 Grays Harbor PUD
11 J. Aron & Company
12 '~~~~$f3nl~~I~p!~I~~~:lriq
, ": "
13 Morgan Stanley Capital Group Inc
14N;~~~~~.P~~f;~iriP:~Q:~'L :,
' - "
Total
FERC FORM NO.1 (ED. 12-90)
FERC Rate
Schedule or
Tariff Number
(c)
Actual Demand (MW)Average Average
Monthly NCP Deman ~ Monthly CP Demand(e) (f)
Average
Monthly Billing
Demand (MW)
(d)
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
Page 326.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/04(2)D A Resubmission 04/18/2006
PU ~CHA~~1J. Accou~t 55~Vt;ontinUed)Includlng power exc ange )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (50-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
5. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total G+k+l)No.Received Delivered
($)
\~l
of Settlement ($)
(g)
(h)(i)(m)
80C 883,90(883 900
46C 32,72f 728
79C 182,94C 182 940
25C 250
80(64,80C 800
51C 100,61 C 100 610
26~262
72S 143,540 143,540
52e 22,42::1 22,423
80C 45,20C 45,200
60,60(237,39C 237 390
313,45S 313,459
474 65~399,64S 25,399,649
21f 138,27e 138,275
918,389 110,013 327,466 815,124 219,383,501 111 690 222,310,
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This Report Is:Date of Report Year/Period of Report
Idaho Power Company (1)!KJ An Original (Mo, Da, Yr)End of 2005/04
(2)D A Resubmission 04/18/2006
~CHA$ED POWER hAccount 555)( ncludlng power exc anges)
Report all power purchases made during the year.Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
Enter the name of the seller or other party in an exchange transaction in column (a).Do not abbreviate or truncate the name or use
acronyms.Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service.Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning).In addition, the reliability of reqUIrement service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for long-term firm service.Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service).This category should not be used for long-term firm service firm service
which meets the definition of RQ service.For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit.Long-term" means five years or longer.The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity.Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service.Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year.Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
~~~ ~~
n~1Il~ffRJ~t: i#ti ~~~;j1ttT: "
\;~
M;~WSPP
NorthWestern Energy, LL.
NorthWestern Energy, LLC.WSPP
NorthWestern Energy, LLC.V6-
~~ff9~~~~!~~~~;~:c::
:::
WSPP
Pacific Northwest Generating Coo WSPP
WSPP
' ,
,!1i?".
. ',',', ":';)_:::
WSPP
11 PacifiCorp Inc.WSPP
Pinnacle West Capital Corp WSPP
~~~~,
~~~~~~~t~~~:~p,~~!1$ ;'
; ~:': ~
WSPP
Portland General Electric Company
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo. Da, Yr)End of 2005/Q4
(2)0 A Resubmission 04/18/2006
PU ~CHA~~p P.PWE~~~ccouRt 55
~~~
(ContinUed)Including power exc ange )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m)the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total U+k+l)No.Received Delivered
($)($)
of Settlement ($)
(g)
(h)(i)(I)(m)
284 65,22C 220
30~304
71=282 82~282 825
54,052 973,44~973 445
56C 560
40C 200 200
89,94~354 971 354 971
13f 711 711
850 850
900 900
120,864 11~864 115
85,77=146,12~146,125
29,13~1 ,942,94~942,949
53:;532
918,389 110 013 327,466 815,124 219 383 501 111 690 222,310,31~
FERC FORM NO.1 (ED. 12-90)Page 327.
This Report Is:
(1) lKJAn Original
(2) 0 A Resubmission
PURCHASED POWER (Account 555)(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
Name of Respondent
Idaho Power Company
Date of Report
(Mo, Da, Yr)
04/18/2006
Year/Period of Report
End of 2005/Q4
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
1 Portland General Electric Company
Statistical
Classifi-
cation
(b)
Line
No.
2 ~9~Tk~~~\~;~:r~~;;i~~~\~~ff;!;~;t';:fJ?17'n:~:;ti)~;\~P: OS
3 Powerex Corp.
4 PPL Montana, LLC
5 '
10 PPM Energy, Inc.
11 j~~~!~~~Bt~J~m~.~~9~I'
;?,;::
;~~!;! OS
12 Public Service Co. of Colorado
13 ~1!~IJ~~~~:~~w~~~wdM~~::~?~':k~:J OS
14 Public Service Company of New Mexico
Total
FERC FORM NO.1 (ED. 12-90)
FERC Rate
Schedule or
Tariff Number
(c)
Actual Demand (MW)Average Average
Monthly NCP Deman Monthly CP Demand(e) (f)
Average
Monthly Billing
Demand (MW)
(d)
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
Page 326.
Name of Respondent This
'0ort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/04
(2)0 A Resubmission 04/18/2006
I-'U ~cHA W~~Jf-ccou ~t 55~~) (ContinUed)
(1ncluding power exc ange
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RO purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (50-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
5. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l)No.Received Delivered
($)($)
of Settlement ($)
(g)
(h)(i)
(j)
(I)(m)
68f O07 2OE 007 205
59f 921 78l 921,784
65,13~984,41 ~984,415
103,584 609,48f 609,488
23,90S 1,481 693 1,481,693
40C 60C 600
74C 740
111 27E 344 93C 344 930
65.241 50C 241 500
102,451 764,424 764,424
16~77€776
80C 820,45C 820,450
505 19,96"965
121 673,673,303
918,389 110,013 327,466 815,124 219 383,501 111 690 222,310,31'i
FERC FORM NO.1 (ED. 12-90)Page 327.
This Report Is:(1) (gJ An Original
(2) 0 A Resubmission
PURCHASED POWER (ACCount 555)(Including power exchanges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
Name of Respondent
Idaho Power Company
Date of Report(Mo, Da, Yr)
04/18/2006
Year/Period of Report
End of 2005/Q4
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
1 ~~'1.~~~Ii.j~~~~B'
~~~,
1~~\~~1ijVli!1:;~~~ OS
2 Puget Sound Energy, Inc.
3 ~irl~9!~'~~j~,..~~~1~iiW;~t.~ij,;m~ OS
4 Rainbow Energy Marketing Corpora
5 ~1~~~~mr~~i~~fi~ij(~iJ(t~;);~i~:('s;1;'Kk::~:::i2j OS
6 Salt River Project
~~~IW.iJ&l:~~~':;~f);~;~i:f:iAH;,l:;%;W;~:::i;;ti \~.;l;i'j OS8 Seattle City Light
9 Seattle City Light
10 Sempra Energy Solutions
11 ;~~,t~PX~J:~~~t~YJtrfflB~t~j\';i~; OS
12 Sempra Energy Trading Corporatio
13 ii~~!:r~S~-~~~~~?'t~~e~~tt;;.":i:;~:e;:";;:;;(~~ OS
14 Sierra Pacific Power Company
Total
FERC FORM NO.1 (ED. 12-90)
FERC Rate
Schedule or
Tariff Number
(c)
Actual Demand (MW)Average Average
Monthly NCP Deman I Monthly CP Demand(e) (f)
Average
Monthly Billing
Demand (MW)
(d)
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
Page 326.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/04
(2)0 A Resubmission 04/18/2006
DL ,~, "'
(1""'" P.oWEF~J~~cou
~t 55
~~)
(Continued)Including power exc ange
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules , tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (D, energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total U+k+l)No.
Received Delivered
($)($)
of Settlement ($)
(g)
(h)(i)(I)(m)
586 33'586,335
79(355 81C 355,810
07!69,32'69,324
00(762,86!762,860
17~192,69(192,690
52'525
88~272 80(272 800
34~346
3,45(206 10(206 100
201 87,40(87,400
62:.622
446,77"23,201,23,201,693
32"125,42~125,425
009
918,389 110,013 327,466 815 124 219 383,501 111,690 222 31 0,31 ~
FERC FORM NO.1 (ED. 12-90)Page 327.
This ~ort Is:(1) ~An Original(2) 0 A Resubmission
PURCHASED POWER (Account 555)(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
Name of Respondent
Idaho Power Company
Date of Report
(Mo, Da, Yr)
04/18/2006
Year/Period of Report
End of 2005104
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition , the reliability of requirement service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No,
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
3 Snohomish County PUD4 ~_.'
:~:::::~
~'~~rlf~~~\;:QjW~~~;;~g21 OS
5 SUEZ Energy Marketing NA, Inc.
6 Wi€.let~fJpff!&jp;~;i;r\l~~i;i~~~:il;~;~i~'~i~~ OS
7 Tacoma Power
Total
FERC FORM NO.1 (ED. 12-90)
FERC Rate
Schedule or
Tariff Number
(c)
Actual Demand (MW)Average Average
Monthly NCP Deman Monthly CP Demand(e) (f)
Average
Monthly Billing
Demand (MW)
(d)
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
Page 326.
Name of Respondent This
ooort Is:
Date of Report YearlPeriod of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/Q4
(2)DA Resubmission 04/18/2006
PU ~CHA
~~(
Q PPWE~J.~ccou~t 55
~~)
(ContinUed)Including power exc ange )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received , enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l)No.Received Delivered
($)($)
of Settlement ($)
(g)
(h)(i)
(j)
(I)(m)
850 850
359,359 369
33/369 76'i 369 765
36S 184 210 184 210
20,60C 128 350 128 350
071 390,22'i 390,225
11/117
653,77~653,772
30,30,744
000 626,00C 626,000
6,49S 448,448 179
169,52E 678,93e 678,935
24C 240
40C 18.2OC 200
918,389 110,013 327,466 815.124 219 383,501 111,690 222,310,31
FERC FORM NO.1 (ED. 12-90)Page 327.
This Report Is:
(1) IKJAn Original
(2) 0 A Resubmission
PURCHASED POWER (Account 555)(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy. capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
Name of Respondent
Idaho Power Company
Date of Report
(Mo, Da, Yr)
04/18/2006
Year/Period of Report
End of 2005/04
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
1 :,.
::;;~
5,.'!!I..m ~Jt~j~:\~g~~:~;~';i OS
2 POWER EXCHANGES
3 Anaheim, City
4 Avista Energy Inc
5 Puget Sound Energy, Inc.
6 Sierra Pacific Power Company
7 '
10 ,
11 OTHER TRANSACTIONS
12 City of Exchange
13 Mountain Power Plant Test Power
Total
FERC FORM NO.1 (ED. 12-90)
FERC Rate
Schedule or
Tariff Number
(c)
Actual Demand (MW)Average Average
Monthly NCP Deman Monthly CP Demand(e) (f)
Average
Monthly Billing
Demand (MW)
(d)
WSPP
WSPP
WSPP
WSPP
Page 326.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/Q4
(2)0 A Resubmission 04/18/2006
PURCHA~~p Accou~t 55~VContinUed)Including power exc ange )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
B. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total U+k+l)No.Received Delivered
($)
\~l
of Settlement ($)
(g)
(h)(i)(m)
1 ,51~515
600 43,200
800 800
672 672
854 9,456
8,457
40,046 249 065
775 . 10
502 000 502 000
594 515 594 515
918,389 110 013 327,466 815,124 219,383,501 111 690 222,310,31~
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2006 2005/04
FOOTNOTE DATA
'Schedule Page: 326 Line No.Column:
The Tamarack Energy Partnership demand readings are taken from an electronic demand
recorder provided by Idaho Power Company. The actual demand is not used in tetermining the
cost of energy.
ISchedule Page: 326.Line No.Column:
Non Firm Purchases
ISchedule Page: 326.Line No.Column:
Non Firm Purchases
ISchedule Page: 326.Line No.13 Column:
Non Firm Purchases
ISchedule Page: 326.Line No.Column:
Ida-West, a subsidiary of IdaCorp, has partial ownership of these projects.
ISchedule Page: 326.4 Line No.Column: Ida-West, a subsidiary of IdaCorp, has partial ownership of these projects.
!Schedule Page: 326.Line No.Column:
Ida-West a subsidiary of IdaCorp has partial ownership of these proj ects.
ISchedule Page: 326.Line No.14 Column:
Non Firm Purchases
'Schedule Page: 326.Line No.Column:
Non Firm Purchases
ISchedule Page: 326.Line No.Column:
Non Firm Purchases
ISchedule Page: 326.Line No.Column:
Non Firm Purchases
ISchedule Page: 326.Line No.Column:
Non Firm Purchases
!Schedule Page: 326.Line No.Column:
Non Firm Purchases
'Schedule Page: 326.Line No.Column:
Non Firm Purchases
'Schedule Page: 326.Line No.11 Column:
2004 Price adjustment
ISchedule Page: 326.Line No.12 Column:
Non Firm Purchases
ISchedule Page: 326.Line No.14 Column:
Spinning or Operating Reserves
ISchedule Page: 326.Line No.Column:
Non Firm Purchases
ISchedule Page: 326.Line No.Column:
Non Firm Purchases
ISchedule Page: 326.Line No.Column:
Non Firm Purchases
ISchedule Page: 326.Line No.Column:
Non Firm Purchases
'Schedule Page: 326.Line No.Column:
Non Firm Purchases
'Schedule Page: 326.Line No.10 Column:
Non Firm Purchases
ISchedule Page: 326.Line No.14 Column:
Non Firm Purchases
ISchedule Page: 326.Line No.Column:
Non Firm Purchases
ISchedule Page: 326.Line No.Column:
Non Firm Purchases
Page 450.IFERC FORM NO.1 (ED. 12-87)
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2006 2005/04
FOOTNOTE DATA
!Schedu/e Page: 326.Line No.Column: Non Firm Purchases
'Schedule Page: 326.Line No.Column: Non Firm Purchases
!Schedu/e Page: 326.Line No.12 Column:
Non Firm Purchases
'Schedule Page: 326.Line No.Column:
Non Firm Purchases
'Schedule Page: 326.Line No.Column:
Non Firm Purchases
ISchedule Page: 326.Line No.Column:
Non Firm Purchases
ISchedu/e Page: 326.Line No.Column:
Non Firm Purchases
'Schedule Page: 326.Line No.12 Column:
Non Firm Purchases
ISchedu/e Page: 326.Line No.14 Column:
Non Firm Purchases
ISchedu/e Page: 326.Line No.Column:
Non Firm Purchases
ISchedu/e Page: 326.Line No.Column:
on Firm Purchases
!schedule Page: 326.Line No.Column:
on Firm Purchases
!Schedule Page: 326.Line No.Column:
Spinning or Operating Reserves
ISchedu/e Page: 326.Line No.10 Column:
Spinning or Operating Reserves
'Schedule Page: 326.Line No.13 Column:
Non Firm Purchases
ISchedu/e Page: 326.10 Line No.Column:
Non Firm Purchases
ISchedu/e Page: 326.10 Line No.Column:
Non Firm Purchases
ISchedule Page: 326.10 Line No.Column:
Non Firm Purchases
ISchedule Page: 326.10 Line No.Column:
Non Firm Purchases
'Schedule Page: 326.10 Line No.Column:
Non Firm Purchases
'Schedule Page: 326.10 Line No.11 Column:
Non Firm Purchases
ISchedu/e Page: 326.10 Line No.13 Column:
Non Firm Purchases
ISchedule Page: 326.11 Line No.Column:
Non Firm Purchases
ISchedu/e Page: 326.11 Line No.Column:
Non Firm Purchases
ISchedu/e Page: 326.11 Line No.Column:
Non Firm Purchases
ISchedule Page: 326.11 Line No.Column:
Non Firm Purchases
'Schedule Page: 326.11 Line No.11 Column:
Non Firm Purchases
'Schedule Page: 326.11 Line No.13 Column:
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2006 2005/04
FOOTNOTE DATA
Non Firm Purchases
ISchedu/e Page: 326.12 Line No.Column:
Spinning or Operating Reserves
ISchedu/e Page: 326.12 Line No.Column: Non Firm Purchases
ISchedu/e Page: 326.12 Line No.Column:
Non Firm Purchases
ISchedu/e Page: 326.12 Line No.Column:
Non Firm Purchases
ISchedule Page: 326.12 Line No.Column:
Non Firm Purchases
ISchedule Page: 326.12 Line No.11 Column:
Non Firm Purchases
ISchedule Page: 326.12 Line No.13 Column:
Non Firm Purchases
ISchedule Page: 326.12 Line No.14 Column:
Non Firm Purchases
ISchedule Page: 326.13 Line No.Column:
Non Firm Purchases
ISchedule Page: 326.13 Line No.Column:
Scheduled losses not removed with loss transactions.
ISchedule Page: 326.13 Line No.Column:
Scheduled losses not removed with loss transactions.
ISchedu/e Page: 326.13 Line No.Column:
Scheduled losses not removed with loss transactions.
ISchedule Page: 326.13 Line No.10 Column:
Scheduled losses not removed with loss transactions.
IFERC FORM NO.1 (ED. 12-Page 450.
This Page Intentionally Left Blank
Year/Period of Report
End of 2005/Q4
This Report Is: Date of Report
(1) IKIAn Original (Mo, Da, Yr)
(2) D A Resubmission 04/18/2006
I N IT R THER Account 456(Including transactions referred to as 'wheeling
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, lFP - "long-Term Firm Point to Point
Transmission Service, OlF - Other long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, as - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Name of Respondent
Idaho Power Company
Line
No.
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Bonneville Power Administration - OTEC
Bonneville Power Administration - US
Bonneville Power Administration - Ra
Bonneville Power Administration - PF
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Bonneville Power Administration
Bonneville Power Administration
Bonneville Power Administration
14 Arizona Public Service
15 Arizona Public Service
16 Aron - Goldman Sachs
17 Aron - Goldman Sachs
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Oregon Trails Electric Co-op
United States Bureau of Reclamati
Raft River Electric Co-op
Priority Firm Customers
Vigilante
Milner Irrigation District
Bonneville Power Administration
PacifiCorp West
United States Bureau of Indian Af
PacifiCorp West
PacifiCorp West
PacifiCorp West
Avista
Sierra Pacific Power
PacifiCorp East
Bonneville Power Administration
Sierra Pacific Power
Statistical
Classifi-
cation
(d)
FNO
FNO
FNO
FNO
elF
elF
elF
FNO
elF
elF
elF
elF
lFP
Name of Respondent This Report Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) IKJ An Original (Mo, Da, Yr)End of 2005/04
(2)D A Resubmission 04/18/2006
1::i::i U .~!"' I:.LEc I RI~ITY t-yR l.?THI:.K ::i (J' ccount 456)(continued)(Including transactions reffered to as 'wheeling
In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
Report receipt and delivery locations for all single contract path, "point to point" transmission service.In column (t), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract.In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
Report in column (i) and (j) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billing TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand MegaWatt Hours Megawatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered(e)(f)
(g)
(h)(i)
(j)
~"'"Z*"""~~I!J,~~~;e!';:N.258,035 258 035
,.. '
o ..
" --
r:;;~"'-
," ""
;~.;,1~ft.174 246 174,24€
~~~;~~:~
181 992 181,99~
\, !~J'&" '
.':-
723,046 723,04€~i;,",;~,~f&~"";;r~,,
Bannack Tap Vigilante Electric C
Legacy Minidoka, Idaho Various in Idaho 885 88"
Legacy LYPK LGBP
125 12"
Legacy LaGrande, Oregon Various in Idaho 13.475 13.47"
Legacy (414)JBSN ENPR 214 127 214 127
Legacy (440)JBSN ENPR 19,726 72€
Legacy (433)BOBR JBSN 162 623 162 621
BOBR LOLO 000 00C
BOBR M345 182 78,182
IPCO BOBR 800 80C
BOBR LGBP
BOBR M345 518 51E
775,766 775,76E
FERC FORM NO.1 (ED. 12-90)Page 329
Name of Respondent This
wort
Is:Date of Report Year!Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005!04
(2)0 A Resubmission 04!18!2006
TRAN~Mr~S!.ON OF ELE,CTRIGITY ~9R u Account 456)
(Including transactions referred to as 'wheeling
1. Report all transmission of electricity, Le., wheeling, provided for other electric utilities, cooperatives, other public authorities
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, lFP - "long-Term Firm Point to Point
Transmission Service, OlF - Other long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, as - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line Payment By Energy Received From Energy Delivered To Statistical
No.(Company of Public Authority)(Company of Public Authority)(Company of Public Authority)Classifi-
(Footnote Affiliation)(Footnote Affiliation)(Footnote Affiliation)cation
(a)(b)(c)(d)
Aron - Goldman Sachs NorthWestern! PacifiCorp East PacifiCorp East
Aron - Goldman Sachs NorthWestern! PacifiCorp East Sierra Pacific Power
Aron - Goldman Sachs Bonneville Power Administration PacifiCorp East
Aron - Goldman Sachs Bonneville Power Administration Sierra Pacific Power
Aron - Goldman Sachs Avista Sierra Pacific Power
Avista Energy, Inc.Bonneville Power Administration Sierra Pacific Power
Black Hills Power PacifiCorp West Sierra Pacific Power
Bonneville Power Administration Bonneville Power Administration Sierra Pacific Power
Bonneville Power Administration Avista Sierra Pacific Power
Cargill Power Markets PacifiCorp East PacifiCorp West
Cargill Power Markets PacifiCorp East Sierra Pacific Power
Cargill Power Markets PacifiCorp West PacifiCorp East
Cargill Power Markets PacifiCorp West PacifiCorp West
Cargill Power Markets PacifiCorp West Sierra Pacific Power
Cargill Power Markets NorthWestern! PacifiCorp East PacifiCorp East
Cargill Power Markets NorthWestern! PacifiCorp East Sierra Pacific Power
Cargill Power Markets PacifiCorp West PacifiCorp East
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.
Name of Respondent This
ooort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/04
(2)0 A Resubmission 04/18/2006
TRA Ol qF E!-ECTR!~ITY FgR qTHERS ,(Account 456)(Continued)(Including transactions reffered to as 'wlieeling
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path
, "
point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billing TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand MegaWatt Hours MegaWatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered(e)(f)
(g)
(h)(i)
HTSP BOBR 169 16~
HTSP M345 150 15C
LGBP BOBR
LGBP M345 635 63E
LOLO M345 221 221
LGBP M345
JBSN M345
LGBP M345 820 82C
LOLO M345 299 29E
BOBR ENPR 276 27E
BOBR M345 400 40C
ENPR BOBR 944 18,94~
ENPR JBSN 647
ENPR M345 70,720 70,72C
HTSP BOBR 247
HTSP M345 695 69'
JBSN BOBR 23,327 23,32(
775,766 775,76E
FERC FORM NO.1 (ED. 12-90)Page 329.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/04
(2)0 A Resubmission 04/18/2006
IOF ELECTRICITY FOR VIIIL ""t-ccount 456)(Includil1Q transactions referred to as 'wheelin '
1. Report all transmission of electricity, Le., wheeling, provided for other electric utilities, cooperatives, other public authorities
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, lFP - "long-Term Firm Point to Point
Transmission Service, OlF - Other long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, as - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line Payment By Energy Received From Energy Delivered To Statistical
No.(Company of Public Authority)(Company of Public Authority)(Company of Public Authority)Classifi-
(Footnote Affiliation)(Footnote Affiliation)(Footnote Affiliation)cation
(a)(b)(c)(d)
1 Cargill Power Markets PacifiCorp West PacifiCorp West
Cargill Power Markets PacifiCorp West Bonneville Power Administration
Cargill Power Markets PacifiCorp West Sierra Pacific Power
Cargill Power Markets Bonneville Power Administration PacifiCorp East
Cargill Power Markets Bonneville Power Administration PacifiCorp West
Cargill Power Markets Bonneville Power Administration Sierra Pacific Power
Cargill Power Markets Avista Sierra Pacific Power
Cargill Power Markets Sierra Pacific Power Bonneville Power Administration
9 Morgan Stanley Capital Group PacifiCorp East Bonneville Power Administration
Morgan Stanley Capital Group PacifiCorp East Sierra Pacific Power
Morgan Stanley Capital Group PacifiCorp West Sierra Pacific Power
Morgan Stanley Capital Group NorthWestern/ PacifiCorp East PacifiCorp East
Morgan Stanley Capital Group NorthWestern/ PacifiCorp East Sierra Pacific Power
Morgan Stanley Capital Group NorthWestern/ PacifiCorp East PacifiCorp East
Morgan Stanley Capital Group Bonneville Power Administration PacifiCorp East
Morgan Stanley Capital Group Bonneville Power Administration Sierra Pacific Power
Morgan Stanley Capital Group Avista PacifiCorp East
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.
Name of Respondent This
wort
Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) X An Original (Mo, Da , Yr)End of 2005/04
(2)0 A Resubmission 04/18/2006
I KAN;:,MISS),U '! QF EL T FgR U I Ht:t'(;:' ,(Accounf456J(C'ontinuecJ)(Includina transactions reffered to as 'wlieeling
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path
, "
point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billing TRANSFER OF ENERGY Line
Schedule of (Subsatation or Other (Substation or Other Demand MegaWatt Hours MegaWatt Hours No.
Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)
(g)
(h)(i)
JBSN ENPR 247
JBSN LGBP 90,867 861
JBSN M345 33,154 33,15~
LGBP BOBR 994 99~
LGBP JBSN
LGBP M345 39,603 39,60~
LOLO M345 555 55f
M345 LGBP 283 28~
BOBR LGBP 009 OO!J
BOBR M345 536 53€
ENPR M345 400 40C
HTSP BOBR 18,219 18,21~
HTSP M345 383 38~
JEFF BOBR 168 16E
LGBP BOBR 154
LGBP M345 119
LOLO BOBR 914 91'
775,766 775,761
FERC FORM NO.1 (ED. 12-90)Page 329.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/04
(2)D A Resubmission 04/18/2006
N OF ELECTRIC,lTY FOR UI Nt K::)~~Ccount 456)(Including transactions referred to as 'wheelin '
1. Report all transmission of electricity, Le., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, lFP - "long-Term Firm Point to Point
Transmission Service, OlF - Other long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, as - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line Payment By Energy Received From Energy Delivered To Statistical
No.(Company of Public Authority)(Company of Public Authority)(Company of Public Authority)Classifi-
(Footnote Affiliation)(Footnote Affiliation)(Footnote Affiliation)cation
(a)(b)(c)(d)
1 Morgan Stanley Capital Group Avista Sierra Pacific Power
2 Morgan Stanley Capital Group Seattle City Light/Idaho Power C Bonneville Power Administration
3 Morgan Stanley Capital Group Seattle City Light/Idaho Power C Sierra Pacific Power
Pacificorp Power Marketing PacifiCorp East PacifiCorp West
5 Pacificorp Power Marketing PacifiCorp East NorthWestern/ PacifiCorp East
6 Pacificorp Power Marketing PacifiCorp East PacifiCorp West
7 Pacificorp Power Marketing PacifiCorp West PacifiCorp East
8 Pacificorp Power Marketing PacifiCorp West Sierra Pacific Power
Pacificorp Power Marketing NorthWestern/ PacifiCorp East PacifiCorp East
Pacificorp Power Marketing PacifiCorp West PacifiCorp East
Pacificorp Power Marketing PacifiCorp West Sierra Pacific Power
Portland General Electric PacifiCorp East Bonneville Power Administration
Portland General Electric PacifiCorp West PacifiCorp East
Portland General Electric NorthWestern/ PacifiCorp East PacifiCbrp East
Portland General Electric NorthWestern/ PacifiCorp East Bonneville Power Administration
Portland General Electric NorthWestern/ PacifiCorp East Bonneville Power Administration
Portland General Electric NorthWestern/ PacifiCorp East PacifiCorp East
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/04
(2)D A Resubmission 04/18/2006
TRANSMISS.l.O QF ELECTR!~ITY FgR qTHERS~Acqount 456)(l,;ontlnued)(IncludlnQ transactions reffered to as 'wheeling
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path
, "
point to point" transmission service. In column (t), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation , or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billing TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand MegaWatt Hours Megawatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)
(g)
(h)(i)
(j)
LOLO M345 581 581
LYPK LGBP
LYPK M345 256 25f
BOBR ENPR 915
BOBR HTSP 339 339
BOBR M500 662 66~
ENPR BOBR 170,760 170 76C
ENPR M345 12,147 12,141
HTSP BOBR 170 17C
JBSN BOBR 931 931
JBSN M345 77,565 56E
BOBR LGBP 585 58E
ENPR BOBR
HTSP BOBR 678 67f
HTSP LGBP 263
JEFF LGBP 132 13~
MLCK BOBR 720 72C
775,766 775,76E
FERC FORM NO.1 (ED. 12-90)Page 329.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/04
(2)D A Resubmission 04/18/2006
rv-\.....,v,ISS!PN.oF EL~CTRlqTY 1;'9R OTHERS ~Account 456)
(Including transactions referred to as 'wheeling
1. Report all transmission of electricity, Le., wheeling, provided for other electric utilities, cooperatives, other public authorities
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, lFP - "long-Term Firm Point to Point
Transmission Service, OlF - Other long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line Payment By Energy Received From Energy Delivered To Statistical
No.(Company of Public Authority)(Company of Public Authority)(Company of Public Authority)Classifi-
(Footnote Affiliation)(Footnote Affiliation)(Footnote Affiliation)cation
(a)(b)(c)(d)
1 Powerex Corporation PacifiCorp East PacifiCorp West
Powerex Corporation PacifiCorp East NorthWestern! PacifiCorp East
3 Powerex Corporation PacifiCorp East Bonneville Power Administration
Powerex Corporation PacifiCorp East Avista
5 Powerex Corporation PacifiCorp East Sierra Pacific Power
6 Powerex Corporation PacifiCorp West PacifiCorp East
7 Powerex Corporation PacifiCorp West PacifiCorp West
8 Powerex Corporation PacifiCorp West Sierra Pacific Power
9 Powerex Corporation NorthWestern! PacifiCorp East PacifiCorp East
Powerex Corporation NorthWestern! PacifiCorp East Bonneville Power Administration
Powerex Corporation NorthWestern/ PacifiCorp East Sierra Pacific Power
Powerex Corporation Idaho Power Company PacifiCorp East
Powerex Corporation PacifiCorp West PacifiCorp East
Powerex Corporation PacifiCorp West PacifiCorp West
Powerex Corporation PacifiCorp West NorthWestern! PacifiCorp East
Powerex Corporation PacifiCorp West Bonneville Power Administration
Powerex Corporation PacifiCorp West Sierra Pacific Power
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.
Name of Respondent This ooort Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/Q4
(2)0 A Resubmission 04/18/2006
TRA I QF ELE T FgR qTHE"S ,(Account 456)(Contlnued)
(Including transactions reffered to as 'wtieelina;
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billing TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand lVregaWatfHours Megawatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)
(g)
(h)(i)
(j)
BOBR ENPR 782 78~
BOBR HTSP 015 01E
BOBR LGBP 102,327 102,
BOBR LOLO 373 37~
BOBR M345 8,416 8,41E
ENPR BOBR 68,481 68,481
ENPR JBSN 177 17/
ENPR M345 039 036
HTSP BOBR 790 79C
HTSP LGBP 133 , 13~
HTSP M345 858 85E
IPCO BOBR 837
JBSN BOBR 10,309 1 O,30~
JBSN ENPR
JBSN HTSP 393
JBSN LGBP 110 270 110,27(
JBSN M345 198 19~
775,766 775 761
FERC FORM NO.1 (ED. 12-90)Page 329.
Name of Respondent This
wort
Is:Date of Report Year!Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005!04
(2)D A Resubmission 04!18!2006
TRA F ELE;CTRIC,ITY FOR OTHERS lAccount 456)(Including transactions referred to as 'wheeling
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, lFP - "long-Term Firm Point to Point
Transmission Service, OlF - Other long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, as - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line Payment By Energy Received From Energy Delivered To Statistical
No.(Company of Public Authority)(Company of Public Authority)(Company of Public Authority)Classifi-
(Footnote Affiliation)(Footnote Affiliation)(Footnote Affiliation)cation
(a)(b)(c)(d)
1 Powerex Corporation NorthWestem! PacifiCorp East Bonneville Power Administration
2 Powerex Corporation Bonneville Power Administration PacifiCorp East
3 Powerex Corporation Bonneville Power Administration PacifiCorp West
4 Powerex Corporation Bonneville Power Administration Sierra Pacific Power
5 Powerex Corporation Avista PacifiCorp East
6 Powerex Corporation Avista Bonneville Power Administration
7 Powerex Corporation Avista Sierra Pacific Power
8 Powerex Corporation Sierra Pacific Power PacifiCorp East
9 Powerex Corporation Sierra Pacific Power Bonneville Power Administration
PP & L Montana PacifiCorp West NorthWestern! PacifiCorp East
PP & L Montana NorthWestern! PacifiCorp East PacifiCorp East
PP & L Montana NorthWestern! PacifiCorp East Bonneville Power Administration
PP & L Montana PacifiCorp West NorthWestern! PacifiCorp East
PP & L Montana PacifiCorp West Bonneville Power Administration
PP & L Montana PacifiCorp West NorthWestern! PacifiCorp East
PP & L Montana NorthWestern! PacifiCorp East PacifiCorp East
PP & L Montana NorthWestern! PacifiCorp East PacifiCorp East
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.
Name of Respondent This
ooort Is:
Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/04
(2)0 A Resubmission 04/18/2006
~! ELECTR!~II y r-yR qTHEK::i!Account 456)(Continued)(Including transactions reffered to as 'wtieeling
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service , as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (t), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billing TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand Megawatt Hours MegaWatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered(e)(f)
(g)
(h)(i)
JEFF LGBP 365 36~
LGBP BOBR 26,947 26,
LGBP JBSN 870 87C
LGBP M345 946 94(
LOLO BOBR 578 578
LOLO LGBP
LOLO M345 606 60E
M345 BOBR 228 22E
M345 LGBP 16,249 24~
ENPR HTSP
HTSP BOBR 36,981 36,981
HTSP LGBP
JBSN HTSP
JBSN LGBP
JBSN MLCK 125 12"
JEFF BOBR
JEFF BOBR 842 84.
775,766 775,76E
FERC FORM NO.1 (ED. 12-90)Page 329.
Name of Respondent This
wort
Is:Date of Report Year!Period of Report
Idaho Power Company (1) X An Original (Mo, Da. Yr)End of 2005!04
(2)D A Resubmission 04!18!2006
TRAN~fv1ISSION OF ELECTRIc;JTY FOR OTHER:?JAccount 456)(Including transactions referred to as 'wheeling
1. Report all transmission of electricity, Le., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, lFP - "long-Term Firm Point to Point
Transmission Service, OlF - Other long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line Payment By Energy Received From Energy Delivered To Statistical
No.(Company of Public Authority)(Company of Public Authority)(Company of Public Authority)Classifi-
(Footnote Affiliation)(Footnote Affiliation)(Footnote Affiliation)cation
(a)(b)(c)(d)
PP & L Montana NorthWestern! PacifiCorp East Bonneville Power Administration
PP & L Montana NorthWestern! PacifiCorp East Avista
PP & L Montana Bonneville Power Administration Sierra Pacific Power
PP & L Montana Sierra Pacific Power PacifiCorp East
PP & L Montana Sierra Pacific Power Bonneville Power Administration
PP & L Montana NorthWestern! PacifiCorp East Bonneville Power Administration
PPM Energy PacifiCorp East PacifiCorp West
PPM Energy PacifiCorp East Bonneville Power Administration
PPM Energy PacifiCorp East Sierra Pacific Power
PPM Energy NorthWestern! PacifiCorp East Sierra Pacific Power
PPM Energy Bonneville Power Administration PacifiCorp East
PPM Energy Bonneville Power Administration Sierra Pacific Power
Public Service of Colorado Bonneville Power Administration PacifiCorp West
Puget Sound Energy NorthWestern! PacifiCorp East PacifiCorp East
Puget Sound Energy NorthWestern! PacifiCorp East Bonneville Power Administration
Puget Sound Energy NorthWestern! PacifiCorp East Avista
Puget Sound Energy Avista Bonneville Power Administration
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/04
(2)D A Resubmission 04/18/2006
TRANSMISS)OI\! QF ELECTRIc:;ITY FpR QTHERS ,(Account 456)(Continuedi(Including transactions reffered to as 'wheeling
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path
, "
point to point" transmission service. In column (f), report the
designation for the substation , or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation , or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billing TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand MegaWatt Hours MegaWatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)
(g)
(h)(i)
JEFF LGBP 304 30-
JEFF LOLO
LGBP M345
M345 BOBR 100 10C
M345 LGBP 650 65C
MLCK LGBP 206
BOBR ENPR
BOBR LGBP 541 60,541
BOBR M345 485 48'
HTSP M345 272 272
LGBP BOBR 793 79~
LGBP M345 272 272
LGBP JBSN
HTSP BOBR 042 042
HTSP LGBP 671 671
HTSP LOLO 512 512
LOLO LGBP 024 02-
775,766 775 76E
FERC FORM NO.1 (ED. 12-90)Page 329.
Name of Respondent This
18rrt
Is:Date of Report Year!Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005!04
(2)0 A Resubmission 04!18!2006
TRAN~MI~SION OF ELECTRICITY FOR OTHERS tAccount 456)(Including transactions referred to as 'wheeling
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, lFP - "long-Term Firm Point to Point
Transmission Service, OlF - Other long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line Payment By Energy Received From Energy Delivered To Statistical
No.(Company of Public Authority)(Company of Public Authority)(Company of Public Authority)Classifi-
(Footnote Affiliation)(Footnote Affiliation)(Footnote Affiliation)cation
(a)(b)(c)(d)
Puget Sound Energy Sierra Pacific Power Bonneville Power Administration
2 Rainbow Energy Marketing Company NorthWestern! PacifiCorp East PacifiCorp East
3 Rainbow Energy Marketing Company PacifiCorp West Bonneville Power Administration
4 Sierra Pacific Power PacifiCorp East Sierra Pacific Power
Sierra Pacific Power PacifiCorp West PacifiCorp East
Sierra Pacific Power PacifiCorp West Sierra Pacific Power
Sierra Pacific Power NorthWestern! PacifiCorp East PacifiCorp East
Sierra Pacific Power NorthWestern! PacifiCorp East Sierra Pacific Power
Sierra Pacific Power Idaho Power Company PacifiCorp West
Sierra Pacific Power Idaho Power Company Bonneville Power Administration
Sierra Pacific Power Idaho Power Company Avista
Sierra Pacific Power PacifiCorp West PacifiCorp East
Sierra Pacific Power PacifiCorp West Bonneville Power Administration
Sierra Pacific Power PacifiCorp West Sierra Pacific Power
Sierra Pacific Power NorthWestern! PacifiCorp East PacifiCorp East
Sierra Pacific Power NorthWestern! PacifiCorp East Sierra Pacific Power
Sierra Pacific Power Bonneville Power Administration PacifiCorp East
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/Q4
(2)D A Resubmission 04/18/2006
11"(A1'\I;'MI~~!.u .~!' ELECTRICITY FQR qTHE~S ,(Accounf456)(Continued)(Including transactions reffered to as 'wheeling
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path
, "
point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and 0) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billing TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand 'lVfegaWatt Hours Megawatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)
(g)
(h)(i)
M345 LGBP 779 77~
HTSP BOBR 605 60f
JBSN LGBP 400 40C
BOBR M345 17,437 17,43
ENPR BOBR 23,112 23,11 ~
ENPR M345 159,884 159 88~
HTSP BOBR 146 214 146,21~
HTSP M345 21,531 21,531
IPCO ENPR 600 60C
IPCO LGBP 2,450 2,45C
IPCO LOLO 265 265
JBSN BOBR 400 40C
JBSN LGBP 800 80C
JBSN M345 821 40,821
JEFF BOBR
JEFF M345 349,667 349
LGBP BOBR 120 12(
775,766 775,76E
FERC FORM NO.1 (ED. 12-90)Page 329.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo. Da, Yr)End of 2005/04
(2)0 A Resubmission 04/18/2006
TRANSMI SSLON OF ELE;CTRI~ITY ~9R OJ"HERS l~ccount 456)(Including transactions referred to as 'wheeling
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, lFP - "long-Term Firm Point to Point
Transmission Service , OlF - Other long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line Payment By Energy Received From Energy Delivered To Statistical
No.(Company of Public Authority)(Company of Public Authority)(Company of Public Authority)Classifi-
(Footnote Affiliation)(Footnote Affiliation)(Footnote Affiliation)cation
(a)(b)(c)(d)
1 Sierra Pacific Power Bonneville Power Administration Sierra Pacific Power
Sierra Pacific Power Avista Sierra Pacific Power
Sierra Pacific Power Seattle City Light/Idaho Power C Sierra Pacific Power
Sierra Pacific Power Sierra Pacific Power PacifiCorp East
Sierra Pacific Power Sierra Pacific Power NorthWestern/ PacifiCorp East
Sierra Pacific Power Sierra Pacific Power Bonneville Power Administration
7 TransAlta Energy Marketing NorthWestern/ PacifiCorp East Sierra Pacific Power
8 TransAlta Energy Marketing Bonneville Power Administration Sierra Pacific Power
9 TransAlta Energy Marketing Sierra Pacific Power Bonneville Power Administration
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/04
(2)D A Resubmission 04/18/2006
~ qF E!-ECTRlPTY FgR qTHERS~Account 456)(Contlnued)(Including transactions reffered to as 'wheeling
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path
, "
point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billing TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand Megawatt Hours MegaWatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered(e)(f)
(g)
(h)(i)
LGBP M345 170,793 170,
LOLa M345 434,917 434
LYPK M345 225 976 225,97€
M345 BOBR 455 45~
M345 HTSP 876 87€
M345 LGBP 003 003
HTSP M345 106 101:
LGBP M345
M345 LGBP
775.766 775,76E
FERC FORM NO.1 (ED. 12-90)Page 329.
Name of Respondent This Report Is:Date of Report Year/Period of Report
Idaho Power Company (1)~An Original (Mo, Da, Yr)End of 2005/04
(2)D A Resubmission 04/18/2006
I::;::;!~I u,t- ~LE\,; I RI~ITY F~K L? I, H~K~ JAccount 456) (ContinUed)(Including transactions reffered to as 'wheeling
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers.In column (k), provide revenues from demand
charges related to the billing demand reported in column (h).In column (I), provide revenues from energy charges related to the
amount of energy transferred.In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments.Explain in a footnote all components ofthe amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a).If no monetary settlement was made, enter zero (11011) in column
(n).Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and 0) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 and 17, respectively.
11.Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)
(k+l+m)No.
(k)(I)(m)(n)
633,086 621,992 094
776 593 300,027 476 566
343,830 296 165 47,665
380 161 305,052 109
15,000 15,000
060 060
fij'i) ~k'liii~WflJftllli~~ffifq:~J~6J;860
164 6,440 10,604
169 54,169
320,478 320,478
754 37,754
333 264 333,264
934 28,934
565 523 565,523
787 787
109 109
087 087
207 003 598,124 860 809,987
FERC FORM NO.1 (ED. 12-90)Page 330
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/04
(2)0 A Resubmission 04/18/2006
F EI,.ECTRI~ITY FQR QTHER;5 JAccount 456) (Continued)(Including transactions reffered to as 'wheeling
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered , including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and m must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 and 17 , respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)
(k+l+m)No.
(k)(I)(m)(n)
681 681
604 604
302 302
647 647
891 891
883 883
051 051
33,559 33,559
845 845
374 374
045 26,045
326,177 326 177
649 649
042 042
107 590 107 590
207,003 11,598,124 860 14,809,987
FERC FORM NO.1 (ED. 12-90)Page 330.
Name of Respondent This
ooort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/04
(2)D A Resubmission 04/18/2006
"ss
ig~ I OF ELEGI KI~ITY FOR
\J II "-"" (Account 456) (Continued)
Including transactions reffered to as 'wlieeling
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)
(k+l+m)No.
(k)(I)(m)(n)
10,364 10,364
419,100 419 100
152 914 152 914
18,421 18,421
111 111
182 658 182 658
560 560
918 918
943 943
17,933 933
581 581
72,028 72,028
9,421 9,421
664 664
12,469 12,469
377 377
613 613
207,003 598,124 860 809,987
FERC FORM NO.1 (ED. 12-90)Page 330.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Me, Da, Yr)End of 2005/04
(2)D A Resubmission 04/18/2006
TRANSMISSIQ lo.F ELECTRII,j11 Y r-yR OTHER~S !Account 456)\CcmtinuOOJ(Including transactions reftered to as 'wheeling
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and 0) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)
(k+l+m)No.
(k)(I)(m)(n)
297 297
316 316
012 012
233,723 233.723
526 526
997 38,997
768 766 768,766
686 686
765 765
53,714 53,714
349,200 349 200
245 245
166 166
048 37,048
1,459 1 ,459
280 280
994 994
207 003 598,124 860 809,987
FERC FORM NO.1 (ED. 12-90)Page 330.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/Q4
(2)D A Resubmission 04/18/2006
I KAN::sMI::S::S!~1 u.f ~LE\,; I RlylTY t-~K l! I, H~R~LAcqount 456) (Continued)(Including transactions reffered to as 'wheeling
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and m must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)
(k+l+m)No.
(k)(I)(m)(n)
507 507
10,750 10,750
545,908 545,908
23,330 23,330
899 899
365,342 365,342
944 944
224 276 224 276
41,559 559
044 044
577 577
4,465 4,465
54,998 998
097 097
588,284 588,284
056 056
207 003 598,124 860 14,809,987
FERC FORM NO.1 (ED. 12-90)Page 330.
Name of Respondent This
mort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da , Yr)End of 2005/Q4
(2)D A Resubmission 04/18/2006
TRANSMISSiON Of ELEI." I 1'(11,-11 T FYR l.? I, HER;:; ~Acc;ount 456) (c.;ontlnued)(Including transactions reffered to as 'wheeling
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and m must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)
(k+l+m)No.
(k)(I)(m)(n)
947 947
143 761 143 761
36,651 651
506 531 506,531
084 084
320 320
56,582 582
216 216
687 86,687
275 275
145,429 145,429
256 256
106 106
492 492
244 244
207,003 598,124 860 14,809,987
FERC FORM NO.1 (ED. 12-90)Page 330.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/04
(2)D A Resubmission 04/18/2006
i!qN OF ELECTRICITY FQR 1..11 , """'.... ccount 456)\C'ontlnued)(Including transactions reffered to as 'wheeling
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and U) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)I Line
($)($)($)
(k+l+m)No.
(k)(I)(m)(n)
128 128
236 236
287 287
393 393
556 556
810 810
255 255
266 166 266,166
132 132
196 196
883 883
196 196
254 254
31,056 31,056
369 369
258 258
516 516
207 003 598,124 860 809 987
FERC FORM NO.1 (ED. 12-90)Page 330.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/04
(2)0 A Resubmission 04/18/2006
TRANSMI cLECTRlqTY FQR QTHER~ ~ccount 456) (L;ontinued)(Including transactions reffered to as 'wheeling
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and 0) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)
(k+l+m)No.
(k)(I)(m)(n)
3,435 3,435
787 787
691 691
265 265
808 808
635,107 635 107
580,806 580,806
85,528 85,528
383 383
732 732
914 914
589 589
178 178
162,153 162 153
179 179
388 982 388,982
477 477
207 003 598 124 860 809,987
FERC FORM NO.1 (ED. 12-90)Page 330.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/04
(2)0 A Resubmission 04/18/2006
TRAN::iMISS!9N. Of ELEt; I KI~ITy' FQR QTHt:K;:; JAC~~~t 456) (Continued)
(Including transactions reffered to as 'wheeling
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and m must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)
(k+l+m)No.
(k)(I)(m)(n)
678.441 678.441
727,620 727 620
897 644 897,644
807 807
3.480 3.480
35,763 35,763
249 249
589 589
207,003 598,124 860 14,809,987
FERC FORM NO.1 (ED. 12-90)Page 330.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2006 2005/04
FOOTNOTE DATA
ISchedu/e Page: 328 Line No.Column: h
Line 1 - The network service agreement between Idaho Power and the Bonneville Power Administration for the Oregon Trail Electric
Cooperative expires September 30 , 2011.
The billing demand for network service is the customer s demand at the time of Idaho Power Company transmission system
peak and varies by month.
!Schedu/e Page: 328 Line No.Column: h
Line 2 - The network service agreement between Idaho Power and the Bonneville Power Administration for the USBR expires
December 31 2014.
The billing demand for network service is the customer s demand at the time of Idaho Power Company transmission system
peak and varies by month.
'Schedule Page: 328 Line No.Column: h
Line 3 - The network service agreement between Idaho Power and the Bonneville Power Administration for Raft River expires
September 30,2011.
The billing demand for network service is the customer s demand at the time of Idaho Power Company transmission system
peak and varies by month.
ISchedu/e Page: 328 Line No.Column: h
Line 2 - The network service agreement between Idaho Power and the Bonneville Power Administration for the USBR expires
December 31 2014.
The billing demand for network service is the customer s demand at the time of Idaho Power Company transmission system
peak and varies by month.
ISchedu/e Page: 328 Line No.Column:
Line 5 - The agreement between Idaho Power and the Bonneville Power Administration expires September 30,2016.
ISchedu/e Page: 328 Line No.Column:
Line 6 - The contract between Idaho Power and the Milner Irrigation District will automatically renewed on December 31.2004 for a five
year term unless either party provides prior notice.
ISchedule Page: 328 Line No.Column:
Line 7 - The agreement between Idaho Power and the City of Seattle expires December 31 2007. Contract demand for 2005 is zero.
ISchedu/e Page: 328 Line No.Column:
Monthly customer charge.
ISchedu/e Page: 328 Line No.Column:
Line 8 -The contract between Idaho Power and PacifiCorp -Imnaha expires on September 30,2010.
ISchedu/e Page: 328 Line No.Column:
Line 9 - The agreement between Idaho Power and the United States Department of the Interior, Bureau of Indian Affairs is subject to
termination upon 90 days written notice by the Bureau.
,Schedule Page: 328 Line No.10 Column:
Line 10, 11 and 12 - The contract between Idaho Power and PacifiCorp is for the life of Bridger project per 1992 Restated
Transmission Service Agreement (RTSA) FERC filing 3/9/92.
ISchedu/e Page: 328 Line No.11 Column:
The contract between Idaho Power and PacifiCorp is for the life of Bridger project per 1992 Restated Transmission Service Agreement (RTSA) FERC
filing 3/9/92.
,Schedule Page: 328 Line No.12 Column:
Line 10, 11 and 12 - The contract between Idaho Power and PacifiCorp is for the life of Bridger project per 1992 Restated Transmission Service
Agreement (RTSA) FERC filing 3/9/92.
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report Is:Date of Report Year/Period of Report
Idaho Power Company (1) ~An Original (Mo, Da, Yr)End of 2005/04
(2)0 A Resubmission 04/18/2006
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
(Including transactions referred to as "wheeling
1. Report all transmission, i.e. wheeling or electricity provided by other electric utilities cooperatives, municipalities, other public
authorities, qualifying facilities, and others for the quarter.
2. In column (a) report each company or public authority that provided transmission service.Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions ofthe service as follows:
FNS - Firm Network Transmission Service for Self, lFP - long-Term Firm Point-to-Point Transmission Reservations. OlF - Other
long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the
demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all
other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all
components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no
monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement,
including the amount and type of energy or service rendered.
6. Enter "TOTAL n in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Line TRANSFER OF ENERGY EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHER
No.Name of Company or Public Statistical Magawatt-Magawan-emana !';nergy !Jrner Total Cost oftiourstioursChar?eS Charres Charres Tran
1~ssion
Authority (Footnote Affiliations)Classification Received Delivered(a)(b)(c)(d)(e)(f)
(g)
Delivered Power to Whir
1i~_'1~Wti~~~:LFP 141 759 141 759 331,190 331 190
4 Northwestern Energy 11.494 11.494 53,562 53.562
5 Okanogan County 224 224 448 448
6~~;~~~ill%~~'1I SFP 008 19,008 -47,520 -47 520
7 Seattle City Light 616 616 664 664
Received Power from Whl
Avista Corp WWP Div 53,842 842 285,293 285,293
Avista Corp WWP Div SFP 248,797 248 797 233,030 233,030
Benton County PUD 008 008 108 108
Bonneville Power Admin 068 068 128,071 128 071
:~~vil~~ITli~f:j::iij;;;g:::J.~;:i;i~'LFP 366,569 366 569 796,762 796 762
TOTAL 683.311 683 311 331,952 321.469 685 657 106
FERC FORM NO. 1/3-Q (REV. 02-04)Page 332
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2005/04
(2)0 A Resubmlssion 04/18/2006
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
(Including transactions referred to as "wheeling
1. Report all transmission, Le. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public
authorities, qualifying facilities, and others for the quarter.
2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions ofthe service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the
demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all
other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all
components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no
monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement,
including the amount and type of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Line TRANSFER OF ENERG'I EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHER
No.Name of Company or Public Statistical Magawatt-Magawan-
!:!.
emana ~nergy \-liner Total Cost ofliourslioursCharresCharresCharresTrans~ssionAuthority (Footnote Affiliations)Classification Received Delivered
(a)(b)(c)(d)(e)(f)
(g)
1 Clatskanie PUD 592 592 588 588
2 Grays Harbor PUD 200 200 350 350
3 Northwestern Energy LLC SFP 440 12,440 41,861 861
4 ~.l~tl~~~~:~~~~.LFP 103 567 103 567 204 000 138 218 138
5 Okanogan County PUD 891 891 782 782
6 PacifiCorp Inc 383 383 452 924 452 924
7 PacifiCorp Inc SFP 233,950 233,950 714 185 714 185
8 Portland General Elect 952 952 596 596
9 PPL Montana, LLC SFP 125,670 125,670 673,200 673,200
Seattle City Light 62,422 62,422 164,402 164,402
Sierra Pacific Power Co 760 4,760 8,732 732
Snohomish County PUD 197 870 197 870 447 754 447 754
Tacoma Power 36,245 36,245 301 86,301
Other 685 685
TOTAL 683 311 683,311 331 952 321,469 685 657 106
FERC FORM NO. 1/3-Q (REV. 02-04)Page 332.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2006 2005/04
FOOTNOTE DATA
!Schedule Page: 332 Line No.Column:
(1) Bonneville Power Administration LFP 9/30/2016
ISchedule Page: 332 Line No.Column:
Idaho Power sold transmission back to PPL Montana LLC after Idaho Power previouslypurchased trasmission.
\Schedule Page: 332 Line No.16 Column:
(2) Bonneville Power Administration LFP 7/25/2011
ISchedule Page: 332.Line No.Column:
(3)Norhtwestern Energy, L.C. LFP Contract can be terminated at anytime, with 30 days
prior notice
IFERC FORM NO.1 (ED. 12-Page 450.
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2005/04(2)0 A Resubmission 04/18/2006
MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line DeSCri)tion Amount
No.(b)
Industry Association Dues 315,826
Nuclear Power Research Expenses
Other Experimental and General Research Expenses
Pub & Dist Info to Stkhldrs...expn servicing outstanding Securities 215 647
Oth Expn ::-=5,000 show purpose, recipient, amount. Group if c:: $5,000 725,836
Rotheford Barker 25,171
Jack Lemley 15,833
Jon Miller 000
Gary Michael 30,625
Peter O'Neill 28,000
Richard Reiten 297
Thomas Wilford 22,500
Robert Tintsman 27,500
Christopher Culp 835
Joan Smith 19,458
Chambers of Commerce & Other Civic Organizations 106
Memberships:
Associated Taxpayers of Idaho 21,252
Corporate Executive Board 20,000
Idaho Assoc of Commerce and Industry 9,400
Idaho Assoc of Counties 700
Idaho Mining Association 500
National Association of Investors 000
National Hydropower Assoc 21,182
Pacific Northwest Utilities 35,559
The Conference Board 500
University of Idaho 10,500
Utility Wind Interest Group 000
West Associates 580
Western Energy Institute 000
Wyoming Taxpayers Assoc 635
Miscellaneous General Management:
Moody s Investor Service 750
New York Stock Exchange 13,867
Pacific Stock Exchange 782
Standard & Poor 83,300
TOTAL 856,141
FERC FORM NO.1 (ED. 12-94)Page 335
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2005/04
(2) 0 A Resubmission 04/18/2006
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Account 403,404,405)
(Except amortization of aquisition adjustments)
1. Report in section A for the year the amounts for: (b) Depreciation Expense (Account 403; (c) Depreciation Expense for Asset
Retirement Costs (Account 403.1; (d) Amortization of Limited-Term Electric Plant (Account 404); and (e) Amortization of Other Electric
Plant (Account 405).
2. Report in Section 8 the rates used to compute amortization charges for electric plant (Accounts 404 and 405). State the basis used to
compute charges and whether any changes have been made in the basis or rates used from the preceding report year.
3. Report all available information called for in Section C every fifth year beginning with report year 1971 , reporting annually only changes
to columns (c) through (g) from the complete report ofthe preceding year.
Unless composite depreciation accounting for total depreciable plant is followed, list numerically in column (a) each plant subaccount
account or functional classification, as appropriate, to which a rate is applied. Identify at the bottom of Section C the type of plant
included in any sub-account used.
In column (b) report all depreciable plant balances to which rates are applied showing subtotals by functional Classifications and showing
composite total. Indicate at the bottom of section C the manner in which column balances are obtained. If average balances, state the
method of averaging used.
For columns (c), (d), and (e) report available information for each plant subaccount, account or functional classification Listed in column
(a). If plant mortality studies are prepared to assist in estimating average service Lives, show in column (f) the type mortality curve
selected as most appropriate for the account and in column (g), if available, the weighted average remaining life of surviving plant.
composite depreciation accounting is used, report available information called for in columns (b) through (g) on this basis.
4. If provisions for depreciation were made during the year in addition to depreciation provided by application of reported rates, state at
the bottom of section C the amounts and nature of the provisions and the plant items to which related.
A. Summary of Depreciation and Amortization Charges
Depreciation Amortization of
Line ~reciation Expense for Asset Limited Term Amortization of
No.Functional Classification xpense Retirement Costs Electric Plant Other Electric Total
(Account 403)(Account 403.(Account 404)Plant (Acc 405)
(a)(b)(c)(d)(e)(f)
1 Intangible Plant 573,690 573,690
2 Steam Production Plant 23,062.474 23,062.474
3 Nuclear Production Plant
4 Hydraulic Production Plant-Conventional 558,923 447 559,370
5 Hydraulic Production Plant-Pumped Storage
6 Other Production Plant 598.425 598.425
7 Transmission Plant 12.490 634 12.490 634
8 Distribution Plant 26,576,747 26,576,747
9 General Plant 942.426 15,942.426
Common Plant-Electric 296 299 296,299
11 TOTAL 92,933,330 574 137 101 507.467
B, Basis for Amortization Charges
Account 404
Balance to be 2005 Balance to be Remaining months of
Amortized Amortization amortized 12/31/05 amortization 12/31/05
(1)992 992
(2)36,000 000 24,000
(3)8.443,567 361 293 659,523
(4)20,179 079 035,506 007 166
(5)247 082 252 234,830 230
(6)144 094 340,123 264
TOTAL 28,914 720 574 137 37,265 642
(1) T E Roach development archaeological study, FERC & Oregon license costs (temination date July 31 , 2005).
(2) Shoshone-Bannock Tribe license and use agreement (termination date December 31, 2023).
(3) Middle snake relicensing costs (amortized over a 30-year liscense period).
(4) Computer software packages (amortized over a 60 month period from date of purchase).
FERC FORM NO.1 (REV. 12-03)Page 336
Name of Respondent This
wort
Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2005/Q4
(2)0 A Resubmission 04/18/2006
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreclacle tSlimarea Ner Appllea MOrtality Average
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
(a)(In Th~~fandS)7~f (Perr~nt)(Percent)r~e 7~~(e)
310.203 75.R4.19.
311.130 393 90.10.S1.18.
312.79,045 55.10.R3.19.
312.410,593 70.10.R1.18.
312.917 25.20.R3.16.40
314.122,505 50.10.3.46 SO.17.
315.61,130 65.S1.17.
316.156 45.RO.16.40
316.25.L3.
316.40 226 25.L3.
316.116 25.8.45 L3.
316.251 17.25.S2.
316.135 14.35.LO.
317.000 633
Subtotal Steam 824 362
331.129,998 100.20.S1.36.
332.19,460 85.10.54.31.40
332.218,938 85.10.54.34.
332.600 69.1.44 SQUARE 63.
333.185,688 80.R3.38.
334.36,429 47.R1.28.
335.852 100.SO.34.
336.950 75.R3.34.
Subtotal Hydro 617 915
341.339 35.SQUARE 34.
342.519 35,SQUARE 33.
343.29,370 35.SQUARE 34.
344.60,940 35.SQUARE 34.
345.680 35.SQUARE 34.
346.342 35.SQUARE 34.
Subtotal Other 105,190
350.22,097 65.R3.52.
350.529 24.SQUARE 24.
352.135 60.20.R3.48.
353.235,849 45.SO.32.
354.79,295 60.30.2.45 54.37.
355.92,201 55.60.R2.39.
356.114,776 60.20.R2.41.40
50 359.318 65.R3.27.
FERC FORM NO.1 (REV. 12-03)Page 337
Name of Respondent This
0ort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2005/Q4
(2)D A Resubmission 04/18/2006
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreclaDle t:stlmatea Net ApPJiea Mortality Average
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
la\(In Th~~~andS)7~~
(Pe
rg~nt)
(pe
r~~nt)
y/?,e 7~f
Subtotal Transmission 581 200
361.19,894 55.20.R2.40.
362.138,465 50.01.43.
364.190,455 41.50.R1.29.
365.96,250 46.30.R2.29.
366.611 60.25.R2.51.
367.153 861 37.10.S1.28.
368.293,686 35.R2.27.
369.48,560 30.30.S2.20.
370.50,389 30.L2.19.
371.359 28.42 S5.
371.201 11.20.11.RO.
373.001 20.20.R1.10.
Subtotal Distribution 039 732
390.798 100.S1.38.
390.388 50.R3.36.
390.192 25.S3,16.
391.261 20.SQUARE
391.18,826 20.SQUARE
391.201 709 34.48 SQUARE
391,764 16.S5.
391.211 063 31.S5.
392.293 25.L3.
392.580 15.50.S2.15.
392.40 16,359 25.3.45 L3.
392.518 25.9.45 L3.
392.20,613 17.25.S2.10.
392.853 17.25.S2.
392.314 30.25.S1.21.
393.974 25.SQUARE
394.208 20.SQUARE
395.260 20.SQUARE
396.263 14.35.LO.
397.648 15.11.SQUARE
46 397.13,230 15.SQUARE 7.40
397.879 15.SQUARE
48 397.40 334 10.16.45 SQUARE
49 398.623 15.SQUARE
50 Subtotal General 208,950
FERC FORM NO.1 (REV. 12-03)Page 337.
Name of Respondent This 0ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2005/04
(2)0 A Resubmission 04/18/2006
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreclaDle t:snmatea Net Appllea Mortality Average
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
(a)
(In Th
?~fandS)7~f (perg;nt)(per;jnt)r~e 7~r
Total Plant 377,349
FERC FORM NO.1 (REV. 12-03)Page 337.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2005/04
(2)0 A Resubmission 04/18/2006
REGULATORY COMMISSION EXPENSES
1. Report particulars (details) of regulatory commission expenses incurred during the current year (or incurred in previous years, if
being amortized) relating to format cases before a regulatory body, or cases in which such a body was a party.
2. Report in columns (b) and (c), only the current year s expenses that are not deferred and the current year s amortization of amounts
deferred in previous years.
Line Description Assessed by Expenses Total Deferred
No.(Furnish name of regulatory commission or body the Regulatory Expense for in Account
Commission Current Year 18;2.docket or case number and a description of the case)Utility (b) + (c)Beginning 0 Year
(a)(b)(c)(d)(e)
1 Federal Energy Regulatory Commission:
Annual administrative charges 570,833 570,833
5 Regulatory Commission Expenses - Idaho
Intervenor Funding (various cases)500 500
Lost Revenue AppeaIIPC-01-4,400 4,400
General Rate Case 2005 141,236 141,236
Emission Allowance 369 37,369
Other Expenses
Oregon Hydro - Fees Amortization 158 506 158,506
Regulatory Commission Expenses - Oregon
General Rate Case 718 718
Other Expenses 18,348 18,348
TOTAL 729,339 280 610 009 949
FERC FORM NO.1 (ED. 12-96)Page 350
Name of Respondent This Report Is:Date of Report Year/Period of Report
Idaho Power Company (1) ~AnOriginal (Mo, Da, Yr)End of 2005/04(2)D A Resubmission 04/18/2006
REGULATORY COMMISSION EXPENSES (Continued)
3. Show in column (k) any expenses incurred in prior years which are being amortized. List in column (a) the period of amortization.
4. List in column (f), (g), and (h) expenses incurred during year which were charged currently to income, plant, or other accounts.
5. Minor items (less than $25,000) may be grouped.
EXPENSES INCURRED DURING YEAR AMORTIZED DURING YEAR
CURRENTLY CHARGED TO Deferred to Contra Amount Deferred in Line
Department I-\c
Rfo~m Amount Account 182.Account Account 182.No.End of Year
(f)
(g)
(h)(i)
(j)
(k)(I)
electric 928 570 833
electric 928 500
electric 928 4,400
electric 928 141 236
electric 928 369
electric 928
electric 928 158,506
electric 928 718
electric 928 18,348
009 949
FERC FORM NO.1 (ED. 12-96)Page 351
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2005/Q4
(2)0 A Resubmission 04/18/2006
RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES
1. Describe and show below costs incurred and accounts charged during the year for technological research , development, and demonstration (R, D &
D) project initiated, continued or concluded during the year. Report also support given to others during the year for jointly-sponsored projects.(ldentify
recipient regardless of affiliation.) For any R, D & D work carried with others, show separately the respondent's cost for the year and cost chargeable to
others (See definition of research, development, and demonstration in Uniform System of Accounts).
2. Indicate in column (a) the applicable classification, as shown below:
Classifications:
A. Electric R, D & D Performed Internally:(3) Transmission
(1) Generation a. Overhead
a. hydroelectric b. Underground
i. Recreation fish and wildlife (4) Distribution
ii Other hydroelectric (5) Environment (other than equipment)
b. Fossil-fuel steam (6) Other (Classify and include items in excess of $5,000.
c. Internal combustion or gas turbine (7) Total Cost Incurred
d. Nuclear B. Electric, R, D & D Performed Externally:
e. Unconventional generation (1) Research Support to the electrical Research Council or the Electric
f. Siting and heat rejection Power Research Institute
Line Classification Description
No.(a)(b)
1 A. Electric R, D & D Performed internally:
(1) Generation
e. unconventional generation Air Conditioning Cool Credit
Energy Star Northwest Homes
Oregon Residential Weather Sch 78
Residential Education Initiative
Savings with a Twist
Weatherization Asistance for Qualified Customers
Commercial Building Efficiency Program
Commercial Education Initiative
Oregon Commercial Audit Sch 82
Oregon School Efficiency
School Operator Training
Industrial Efficiency
Irrigation Efficiency
Irrigation Efficiency Rewards Program
Irrigation Peak Clipping
Distribution Efficiency Initiative
EEAG Meetings
NEEA
Other Conservation & Renewable Discounts
Small ProjecUEducation funds
DSM Analysis & Accounting
(7)
B. 4 Research Support to Others BPA Energy House Calls
BPA Rebate Advantage
Total R, D&D
FERC FORM NO.1 (ED. 12-87)Page 352
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2005/04
(2)0 A Resubmission 04/18/2006
RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES (Continued)
(2) Research Support to Edison Electric Institute
(3) Research Support to Nuclear Power Groups
(4) Research Support to Others (Classify)
(5) Total Cost Incurred
3. Include in column (c) all R, D & D items performed internally and in column (d) those items performed outside the company costing $5,000 or more,
briefly describing the specific area of R, D & D (such as safety, corrosion control, pollution, automation, measurement, insulation, type of appliance, etc.
Group items under $5,000 by classifications and indicate the number of items grouped. Under Other, (A (6) and B (4)) classify items by type of R, D & D
activity.
4. Show in column (e) the account number charged with expenses during the year or the account to which amounts were capitalized during the year
listing Account 107, Construction Work in Progress, first. Show in column (f) the amounts related to the account charged in column (e)
5. Show in column (g) the total unamortized accumulating of costs of projects. This total must equal the balance in Account 188, Research
Development, and Demonstration Expenditures, Outstanding at the end of the year.
6. If costs have not been segregated for R. D &D activities or projects, submit estimates for columns (c), (d), and (f) with such amounts identified by
Est."
7. Report separately research and related testing facilities operated by the respondent.
Costs Incurred Internally Costs Incurred Externally AMOUNTS CHARGED IN CURRENT YEAR Unamortized Line
Curren\ Year Current Year Account Amount Accumulation No,
(d)(e)(f)
(g)
754,062 754 062
253 105 253,105
612 612
110 110
73,152 152
502,759 502 759
194,066 194 066
3,497 3,497
5,450 5,450
750 750
128,076 128,076
119,696 119 696
30,881 881
1,468,281 1.468,281
552 21,552
191 191
476,891 476,891
103,786 103,786
896 896
162 504 162 504
375,733 375,733
46,299 46,299
324 403 422,032 746.435
FERC FORM NO.1 (ED. 12-87)Page 353
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2005/04
This Report Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) D A Resubmission 04/18/2006
DISTRIBUTION OF SALARIES AND WAGES
Report below the distribution of total salaries and wages for the year. Segregate amounts originally charged to clearing accounts to
Utility Departments, Construction, Plant Removals, and Other Accounts, and enter such amounts in the appropriate lines and columns
provided. In determining this segregation of salaries and wages originally charged to clearing accounts, a method of approximation
giving substantially correct results may be used.
(a)
Direct PayrollDistribution
(b)
TotalLine
No.
Classification
Electric
Operation
Production
Transmission
Distribution
6 Customer Accounts
7 Customer Service and Informational
8 Sales
Administrative and General
10 TOTAL Operation (Enter Total of lines 3 thru 9)
11 Maintenance
12 Production
13 Transmission
14 Distribution
15 Administrative and General
16 TOTAL Maint. (Total of lines 12 thru 15)
17 Total Operation and Maintenance
18 Production (Enter Total of lines 3 and 12)
19 Transmission (Enter Total of lines 4 and 13)
20 Distribution (Enter Total of lines 5 and 14)
21 Customer Accounts (Transcribe from line 6)
22 Customer Service and Informational (Transcribe from line 7)
23 Sales (Transcribe from line 8)
24 Administrative and General (Enter Total of lines 9 and 15)
25 TOTAL Oper. and Maint. (Total of lines 18 thru 24)
26 Gas
27 Operation
28 Production-Manufactured Gas
29 Production-Nat. Gas (Including Expl. and Dev.
30 Other Gas Supply
31 Storage, LNG Terminaling and Processing
32 Transmission
33 Distribution
34 Customer Accounts
35 Customer Service and Informational
36 Sales
37 Administrative and General
38 TOTAL Operation (Enter Total of lines 28 thru 37)
39 Maintenance
40 Production-Manufactured Gas
41 Production-Natural Gas
42 Other Gas Supply
43 Storage, LNG Terminaling and Processing
44 Transmission
45 Distribution
46 Administrative and General
47 TOTAL Maint. (Enter Total of lines 40 thru 46)
10,784 125
5,420,004
14,733,226
648,239
945,542
16,639 337
887 916
967 734
648,239
945,542
FERC FORM NO.1 (ED. 12-88)Page 354
Name of Respondent
Idaho Power Company
This Report Is: Date of Report
(1) 0 An Original (Mo, Da, Yr)(2) 0 A Resubmission 04/18/2006
DISTRIBUTION OF SALARIES AND WAGES (Continued)
Year/Period of Report
End of 2005/Q4
Line
No.
Classification Direct PayrollDistribution
(b)
Total
(a)
48 Total Operation and Maintenance
49 Production-Manufactured Gas (Enter Total of lines 28 and 40)
50 Production-Natural Gas (Including Expl. and Dev.) (Total lines 29,
51 Other Gas Supply (Enter Total of lines 30 and 42)
52 Storage, LNG Terminaling and Processing (Total of lines 31 thru
53 Transmission (Lines 32 and 44)
54 Distribution (Lines 33 and 45)
55 Customer Accounts (Line 34)
56 Customer Service and Informational (Line 35)
57 Sales (Line 36)
58 Administrative and General (Lines 37 and 46)
59 TOTAL Operation and Maint. (Total of lines 49 thru 58)
60 Other Utility Departments
61 Operation and Maintenance
62 TOTAL All Utility Dept. (Total of lines 25, 59, and 61)
63 Utility Plant
64 Construction (By Utility Departments)
65 Electric Plant
66 Gas Plant
67 Other (provide details in footnote):
68 TOTAL Construction (Total of lines 65 thru 67)
69 Plant Removal (By Utility Departments)
70 Electric Plant
71 Gas Plant
72 Other (provide details in footnote):
73 TOTAL Plant Removal (Total of lines 70 thru 72)
74 Other Accounts (Specify, provide details in footnote):
75 Paid Absences
76 Other Work in Progress
77 Other
78 Other clearing Accounts
95 TOTAL Other Accounts
96 TOTAL SALARIES AND WAGES
91,997,326 91,997,326r---~-
36,506,612 3,447 556 39,954,168
506,612 447 556 39,954 168
000 952
261 059
172,848
20,258
14,000,952
261 059
172,848
258
19,455,117
147 959,055 3,447 556
19,455,117
151,406 611
FERC FORM NO.1 (ED. 12-88)Page 355
Name of Respondent
Idaho Power Company
This ~ort Is: Date of Report(1) l2SJAn Original (Mo, Da, Yr)(2) DA Resubmission 04/18/2006
MONTHLY TRANSMISSION SYSTEM PEAK LOAD
(1) Report the monthly peak load on the respondent's transmission system. If the respondent has two or more power systems which are not physically
integrated, furnish the required information for each non-integrated system.
(2) Report on Column (b) by month the transmission system s peak load.
(3) Report on Columns (c) and (d) the specified information for each monthly transmission - system peak load reported on Column (b).
(4) Report on Columns (e) through G) by month the system' monthly maximum megawatt load by statistical classifications. See General Instruction for the
definition of each statistical classification.
Year/Period of Report
End of 2005/04
NAME OF SYSTEM: Idaho Power Company
Line
No.Month
(a)
1 January
2 February
3 March
4 Total for Quarter 1
5 April
6 May
7 June
8 Total for Quarter 2
9 July
10 August
11 September
12 Totallor Quarter 3
13 October
14 November
15 December
16 Total for Quarter 4
17 Total for Year to
DatelYear
Monthly Peak
MW - Total
Day of Hour of
Monthly MonthlyPeak Peak
(d)(b)
2,46
321
10,
911
Firm Network Firm Network Long-Term Firm Other Long-Short-Term Firm Other
Service for Self Service for Point-to-point Term Firm Point-to-point Service
Others Reservations Service Reservation
(e)(f)
(g)
(f)(f)(f)
052 169 376
072 175 376
805 147 376
929 491 128 155
160 141 142
306 179
979 265
7,445 585 216
960 286 476
812 261 476
392 232 401 100
164 779 353 100
744 157 401
059 179 401
332 197 401
135 533 203
673 388 759 511
FERC FORM NO. 113-Q (NEW. 07-04)Page 400
Name of Respondent
Idaho Power Company
This Report Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) DA Resubmission 04/18/2006
ELECTRIC ENERGY ACCOUNT
YearlPeriod of Report
End of 2005/Q4
Line
No.
Item
Report below the information called for concerning the disposition of electric energy generated, purchased, exchanged and wheeled during the year.
(a)
1 SOURCES OF ENERGY
2 Generation (Excluding Station Use):
3 Steam
4 Nuclear
5 Hydro-Conventional
6 Hydro-Pumped Storage
7 Other
8 Less Energy for Pumping
9 Net Generation (Enter Total of lines 3
through 8)
10 Purchases
11 Power Exchanges:
12 Received
13 Delivered
14 Net Exchanges (Line 12 minus line 13)
15 Transmission For Other (Wheeling)
16 Received
17 Delivered
18 Net Transmission for Other (Line 16 minus
line 17)
19 Transmission By Others Losses
20 TOTAL (Enter Total of lines 9,10, 14, 18
and 19)
FERC FORM NO.1 (ED. 12-90)
MegaWatt Hours
(b)
Page 401a
Line
No.
Item
(a)
21 DISPOSITION OF ENERGY
22 Sales to Ultimate Consumers (Including
Interdepartmental Sales)
23 Requirements Sales for Resale (See
instruction 4, page 311.
24 Non-Requirements Sales for Resale (See
instruction 4, page 311.
25 Energy Furnished Without Charge
26 Energy Used by the Company (Electric
Dept Only, Excluding Station Use)
27 Total Energy Losses
28 TOTAL (Enter Total of Lines 22 Through
27) (MUST EQUAL LINE 20)
MegaWatt Hours
(b)
13,288,812
107,606
666,246
155,803
218,467
This Report Is: Date of Report
(1) IKI An Original (Mo, Da, Yr)(2) 0 A Resubmission 04/18/2006
MONTHLY PEAKS AND OUTPUT
(1) Report the monthly peak load and energy output. If the respondent has two or more power which are not physically integrated, furnish the required
information for each non- integrated system.
(2) Report on line 2 by month the system s output in Megawatt hours for each month.
(3) Report on line 3 by month the non-requirements sales for resale. Include in the monthly amounts any energy losses associated with the sales.
(4) Report on line 4 by month the system s monthly maximum megawatt load (60 minute integration) associated with the system.
(5) Report on lines 5 and 6 the specified information for each monthly peak load reported on line 4.
Name of Respondent
Idaho Power Company
YearlPeriod of Report
End of 2005104
NAME OF SYSTEM:IDAHO POWER COMPANY - SYSTEM LOAD
Line Monthly Non-Requirments MONTHLY PEAKSales for Resale &No.Month Total Monthly Energy Associated Losses Megawatts (See Instr. 4)Day of Month Hour
(a)(b)(c)(d)(e)(f)
29 January 1.461,872 226,364 063 7PM
30 February 211 886 154 706 072 8AM
31 March 289.493 234,721 812 8AM
32 April 108 096 107,649 796 8AM
33 May 541.433 523,541 863 6PM
34 June 655 077 382,243 622 4PM
35 July 874.482 232,642 961 4PM
36 August 679 139 140,582 815 5PM
37 September 378.417 188,000 394 6PM
38 October 229.496 177 730 746 8AM
39 November 247 378 109.444 063 8AM
40 December 541 698 188,624 345 8AM
TOTAL 218.467 666,246
FERC FORM NO.1 (ED. 12-90)Page 401b
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2006 2005/04
FOOTNOTE DATA
ISchedule Page: 401 Line No.
Included in energy losses
Column: b
IFERC FORM NO.1 (ED. 12-Page 450.
Name of Respondent This Report Is:Date of Report Year/Period of Report
Idaho Power Company (1) ~An Original (Mo, Da, Yr)2005/Q4(2)D A Resubmission 04/18/2006 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)
Report data for plant in Service only.Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more.Report in
this page gas-turbine and internal combustion plants of 10 000 Kw or more, and nuclear plants.Indicate by a footnote any plant leased or operated
as a joint facility.If net peak demand for 60 minutes is not available, give data which is available, specifying period.If any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant.If gas is used and purchased on a
therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct.Quantities of fuel burned (Line 38) and average cost
per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20,If more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
Line Item Plant Plant
No.Name: Jim Bridger Name:Boardman
(a)(b)(c)
Kind of Plant (Internal Comb, Gas Turb, Nuclear Steam Steam
Type of Constr (Conventional, Outdoor, Boiler, etc)Semi-Outdoor Boiler Conventional
Year Originally Constructed ~~~f~ ~;wJ.I~~~~i~ii~~~.~~!f;f~j~'~I~li~~i~'i~_;
Year Last Unit was Installed 1979 1980
Total Installed Cap (Max Gen Name Plate Ratings-MW)$Jfi~~~J11?41i~i?~~i~~I't.~1i~~\'~~!-ti.wl'*~t~~~~~iif~JX~~~t~'t~1~f ,
. .
Net Peak Demand on Plant - MW (60 minutes)698
Plant Hours Connected to Load 8760 6233
Net Continuous Plant Capability (Megawatts)
When Not Limited by Condenser Water :~0ii!~) ;f?~~J;i~~iPJ1i1~~1~~~ r~i~$!.!~if~~i:~~~~~it~j~~~~W~Jt ~1 ~~i ~~~y~~~1~;
When Limited by Condenser Water
Average Number of Employees
Net Generation, Exclusive of Plant Use - KWh 4937603000 357180000
Cost of Plant: Land and Land Rights 494358 106610
Structures and Improvements 63103766 13616489
Equipment Costs 383227840 54897896
Asset Retirement Costs
Total Cost 446825964 68620995
Cost per KW of Installed Capacity (line 17/5) Including 579.9169 1224.2818
Production Expenses: Oper, Supv, & Engr 112008 753718
Fuel 61522539 4612849
Coolants and Water (Nuclear Plants Only)
Steam Expenses 4118142
Steam From Other Sources
Steam Transferred (Cr)
Electric Expenses
Misc Steam (or Nuclear) Power Expenses 5283967 217308
Rents 133759 149158
Allowances
Maintenance Supervision and Engineering 96600 1952145
Maintenance of Structures
Maintenance of Boiler (or reactor) Plant 10733492
Maintenance of Electric Plant 4146747
Maintenance of Misc Steam (or Nuclear) Plant 1063755 15071
Total Production Expenses 87211009 7700249
Expenses per Net KWh 0177 0216
Fuel: Kind (Coal, Gas, Oil, or Nuclear)Coal Oil Coal Oil
Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear -indicate)Tons Barrels Tons Barrels
Quantity (Units) of Fuel Burned 2784574 12263 210613 742
Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)9315 14000 8359 138800
Avg Cost of Fuel/unit, as Delvd f.b, during year 20.914 000 83.825 20.919 000 83.393
Average Cost of Fuel per Unit Burned 21.886 000 35.716 20.623 000 57.535
Average Cost of Fuel Burned per Million BTU 170 000 074 234 000 866
Average Cost of Fuel Burned per KWh Net Gen 012 000 000 013 000 000
Average BTU per KWh Net Generation 10564.000 000 000 9870.000 000 000
FERC FORM NO.1 (REV. 12-03)Page 402
Name of Respondent This Report Is:Date of Report Year/Period of Report
Idaho Power Company (1) ~An Original (Mo, Da, Yr)2005/04(2)0 A Resubmission 04/18/2006 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses.10.For IC and GT plants, report Operating Expenses, Account Nos.
547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32
, "
Maintenance of Electric Plant." Indicate plants
designed for peak load service.Designate automatically operated plants.11.For a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant.However, if a gas-turbine unit functions in a combined
cycle operation with a conventional steam unit, include the gas-turbine with the steam plant.12.If a nuclear power generating plant, briefly explain by
footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units
used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the
report period and other physical and operating characteristics of plant.
Plant Plant Plant Line
Name:Valmy Name:Danskin Name:Bennett Mountain No.
(d)(e)(f)
Steam Gas Turbine Gas Turbine
Outdoor Conventional Conventional_l~~;2001 2005
1985 2001 2005
W!!fEi ~4~fB;j;Ji~~~tf0 ~:; ~~%u!r~;;:ifi~~~ ~l!~ibl~~~~~;r t 90.172.
286 167
8760 295 372
100000 171900
1953610000 10550000 56222000
769351 402745
53672955 4314768 1012073
252006875 46919633 52042639
306449181 51637146 53054712
1080.9495 573.7461 307.0296
411920 133678 34625
32846655 1436293 2744349
2777372
1610776 133523 94828
1293837 94071 119768
42258
81469 110596 118078
421603 13676 6460
5121874 218967 126113
1465255
162041
46235060 2140804 3244221
0237 2029 0577
Coal Oil Gas Gas
Tons Barrels MCF MCF
947851 5703 156347 467919
9988 138778 1038 1038
33.003 000 88.298 187 000 000 865 000 000
34.118 000 81.262 187 000 0.000 865 000 000
725 000 13.941 850 000 000 650 000 000
017 000 000 136 000 000 049 000 000
9611.000 000 000 15383.000 000 000 8639.000 000 000
FERC FORM NO.1 (REV. 12-03)Page 403
This Page Intentionally Left Blank
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2006 2005/04
FOOTNOTE DATA
ISchedule Page: 402 Line No.Column: b
This footnote applies to lines 3 and 4. The Jim Bridger Power
Plant consists of four equal units constructed jointly by Idaho
Power Company and Pacific Power and Light Company, with Idaho
owning 1/3 and PacifiCorp owning 2/3. Unit #1 was placed in
commercial operation November 30, 1974, Unit #2 December 1, 1975,
Unit #3 September 1, 1976, and Unit #4 November 29, 1979.
ISchedule Page: 402 Line No.Column:
This footnote applies to lines 3 and 4. The Boardman plant
consists of one unit constructed jointly by Portland General
Electric Company, Idaho Power Company, and Pacific Northwest
Generating Company, with Idaho Power Company owning 10%. The
unit was placed in commercial operation August 3, 1980.
ISchedule Page: 402 Line No.Column: d
This footnote applies to lines 3 and 4. The Valmy plant consists
of two units constructed jointly by Sierra Pacific Power Company
and Idaho Power Company, with Sierra owning 1/2 and Idaho owning
1/2. Unit #1 was placed in commercial operation December 11, 1981
and Unit #2 May 21, 1985.
ISchedule Page: 402 Line No.Column: b
This footnote applies to line 5 and lines 12 through 43.
Information reflects Idaho Power Company s share as explained
in note for line 3 page 402 column
ISchedu/e Page: 402 Line No.Column:
This footnote applies to line 5 and lines 12 through 43.
Information reflects Idaho Power Company s share as explained
in note on line 3 page 402 column C
ISchedule Page: 402 Line No.Column: d
This footnote applies to line 5 and lines 12 through 43.
Information reflects Idaho Power Company s share as explained
in note for line 3 page 403 column
ISchedule Page: 402 Line No.Column: b
This footnote applies to lines 9, 10, and 11. PacifiCorp
as operator of the plant will report thisinformation.
!Schedule Page: 402 Line No.Column:
This footnote applies to lines 9, 10, and 11. Portland General
Electric Company, as operator will report this information.
ISchedule Page: 402 Line No.Column: d
This footnote applies to lines 9, 10, and 11. Sierra Pacific
Power, as operator of the plant, will report this information.
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent
Idaho Power Company
YearlPeriod of Report
End of 2005/04
This Report Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) 0 A Resubmission 04/18/2006
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Large plants are hydro plants of 10 000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
a footnote. If licensed project, give project number.
3, If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
(a)
FERC Licensed Project No. 2736
Plant Name: American Falls
(b)
FERC Licensed Project No. 1975
Plant Name: Bliss
(c)
Line
No.
Item
1 Kind of Plant (Run-of-River or Storage)
2 Plant Construction type (Conventional or Outdoor)
3 Year Originally Constructed
4 Year Last Unit was Installed
5 Total installed cap (Gen name plate Rating in MW)
6 Net Peak Demand on Plant-Megawatts (60 minutes)
7 Plant Hours Connect to Load
8 Net Plant Capability (in megawatts)
(a) Under Most Favorable Oper Conditions
10 (b) Under the Most Adverse Oper Conditions
11 Average Number of Employees
12 Net Generation, Exclusive of Plant Use - Kwh
13 Cost of Plant
14 Land and Land Rights
15 Structures and Improvements
16 Reservoirs, Dams, and Waterways
17 Equipment Costs
18 Roads, Railroads, and Bridges
19 Asset Retirement Costs
20 TOTAL cost (Total of 14 thru 19)
21 Cost per KW of Installed Capacity (line 20
22 Production Expenses
23 Operation Supervision and Engineering
24 Water for Power
25 Hydraulic Expenses
26 Electric Expenses
27 Misc Hydraulic Power Generation Expenses
28 Rents
29 Maintenance Supervision and Engineering
30 Maintenance of Structures
31 Maintenance of Reservoirs, Dams, and Waterways
32 Maintenance of Electric Plant
33 Maintenance of Misc Hydraulic Plant
34 Total Production Expenses (total 23 thru 33)
35 Expenses per net KWh
~t~1g~'It.~~~~~~~i~'~~~fE '
:'~
~~lti4.J
Outdoor
1978
1978
92.
988
Run-of-River
Outdoor
1949
1950
75.
585
112
224 948,000 287 702,000r---------
'- ~. .. . -. --~--~-_.
875,318
797 544
242,904
31,069,025
306,333
48,291 124
523.1974
463,556
666,849
7,428,401
536,751
486,477
15,582,034
207.7605
,------------- --- -- -------~--~,--
198,972
037,569
232,283
35,513
178,011
141
169,493
734
866
294 999
55,012
267,593
0101
468,653
255,122
425,918
213
352
858
53,040
38,503
106
157,058
175,983
684,806
0059
FERC FORM NO.1 (REV. 12-03)Page 406
Name of Respondent
Idaho Power Company
This ~ort Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) D A Resubmission 04/18/2006
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
Year/Period of Report
End of 2005/04
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses.
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No.
Plant Name: Brownlee
(d)
FERC Licensed Project No. 2848
Plant Name: Cascade
(e)
1971FERC Licensed Project No.
Plant Name: Oxbow
1971 Line
No.
Outdoor Outdoor Outdoor
1958 1983 1961
1980 1984 1961
585.40 12.42 190.
747 216
760 744 750
~----,---~-
728
220
958,064,000
220
202
825,345,00037,584 000
-~---------- -----,--...,-,---,----,--- ----,-----~' ,--,-----,------ --,---
654 942
30,031.407
66,828,805
574 157
518.444
154 607 755
264.1062
82,142
364,154
145,630
12,426,390
122 668
23,140 984
863.2032
866,938
867 937
375,714
14,834,106
565,842
56,510,537
297.4239
-,-~---'----"-'-'----'- ----,"--~---~--,-----,---,------,---,-----
504 229
167 326
394 965
328.479
227 555
182 713
253,550
153 732
3.456
623.494
526.617
366 116
0017
112 029
65,868
113,776
016
99,596
102
35,864
13,853
203
96,356
57,848
656 511
0175
285.494
703
218 279
219,699
146,717
36,852
155,513
137.440
919
189,364
414,904
893,884
0023
FERC FORM NO.1 (REV. 12-03)Page 407
Name of Respondent
Idaho Power Company
YearlPeriod of Report
End of 2005/04
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) 0 A Resubmission 04/18/2006
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
a footnote. If licensed project, give project number.
3, If net peak demand for 60 minutes is not available, give that which is available specifying period,
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
(a)
FERC Licensed Project No. 1971
Plant Name: Hells Canyon
(b)
FERC Licensed Project No. 2726
Plant Name: Malad
(c)
Line
No.
Item
1 Kind of Plant (Run-of-River or Storage)
2 Plant Construction type (Conventional or Outdoor)
3 Year Originally Constructed
4 Year Last Unit was Installed
5 Total installed cap (Gen name plate Rating in MW)
6 Net Peak Demand on Plant-Megawatts (60 minutes)
7 Plant Hours Connect to Load
8 Net Plant Capability (in megawatts)
(a) Under Most Favorable Oper Conditions
10 (b) Under the Most Adverse Oper Conditions
11 Average Number of Employees
12 Net Generation, Exclusive of Plant Use - Kwh
13 Cost of Plant
14 Land and Land Rights
15 Structures and Improvements
16 Reservoirs, Dams, and Waterways
17 Equipment Costs
18 Roads, Railroads, and Bridges
19 Asset Retirement Costs
20 TOTAL cost (Total of 14 thru 19)
21 Cost per KWof Installed Capacity (line 20
22 Production Expenses
23 Operation Supervision and Engineering
24 Water for Power
25 Hydraulic Expenses
26 Electric Expenses
27 Misc Hydraulic Power Generation Expenses
28 Rents
29 Maintenance Supervision and Engineering
30 Maintenance of Structures
31 Maintenance of Reservoirs, Dams, and Waterways
32 Maintenance of Electric Plant
33 Maintenance of Misc Hydraulic Plant
34 Total Production Expenses (total 23 thru 33)
35 Expenses per net KWh
Outdoor
1967
1967
391.
445
688
Outdoor
1948
1948
21.
695
~---
450
137
589,522,000 158,637 000
I _.,.
---_.,----,---_.'----
558,955
2,414 069
619,458
15,059,339
819 192
72,471 013
185.1111
205,375
564,034
371 066
080,461
304 683
525,619
437.5571
,-,,-- --~
-___'__m_
_"___-
241,985
82,158
195,773
129,110
154 149
568
186,501
29,887
111 775
292,817
620,591
106,314
0013
118 566
490 071
161 898
397
50,458
844
762
846
883
111 565
144 290
0072
FERC FORM NO.1 (REV. 12-03)Page 406.
Name of Respondent
Idaho Power Company
This Report Is: Date of Report(1) (!I An Original (Mo, Da, Yr)(2) OA Resubmission 04/18/2006
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
Year/Period of Report
End of 2005/04
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses.
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No. 2055
Plant Name: C J Strike
(d)
FERC Licensed Project No.
Plant Name: Swan Falls
(e)
503 FERC Licensed Project No.
Plant Name: Twin Falls
Line
No.
Run-of-River
Outdoor
1952
1952
82.
755
Run-of-River
Conventional
1910
1994
25.
748
Run-of-River
Conventional
1935
1995
52.
793
~---'-~~-
383,049 000 119,851 000 54.446,000
~.--,---,-,----,-,. .., ." ,~--- -----~----~---
052,202
717 647
742,555
262 249
238 871
22,013 524
265.8638
675
238,298
13,641,459
30,351,406
835,946
70,118,784
804.7514
255,499
808,047
908,304
20,474,214
917,603
41,363,667
784.2940
-'---"-------"'- "'-'-------~~-~-,-
795,055
310,979
246,867
36,491
234 567
875
885
59,335
185,351
142 735
103,625
253,765
0085
185,425
68,284
202,846
30,781
96,303
288
43,125
190
825
114,923
100 746
938,736
0078
234 800
78,611
209 507
33,734
141,058
270
866
019
398
846
67,224
891,333
0164
FERC FORM NO.1 (REV. 12-03)Page 407.
Name of Respondent
Idaho Power Company
YearlPeriod of Report
End of 2005/04
This Report Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) 0 A Resubmission 04/18/2006
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
a footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
(a)
FERC Licensed Project No. 2777
Plant Name: Upper Salmon
(b)
FERC Licensed Project No. 2778
Plant Name: Shoshone Falls
(c)
Line
No.
Item
1 Kind of Plant (Run-of-River or Storage)
2 Plant Construction type (Conventional or Outdoor)
3 Year Originally Constructed
4 Year Last Unit was Installed
5 Total installed cap (Gen name plate Rating in MW)
6 Net Peak Demand on Plant-Megawatts (60 minutes)
7 Plant Hours Connect to Load
8 Net Plant Capability (in megawatts)
(a) Under Most Favorable Oper Conditions
10 (b) Under the Most Adverse Oper Conditions
11 Average Number of Employees
12 Net Generation, Exclusive of Plant Use - Kwh
13 Cost of Plant
14 Land and Land Rights
15 Structures and Improvements
16 Reservoirs, Dams, and Waterways
17 Equipment Costs
18 Roads, Railroads, and Bridges
19 Asset Retirement Costs
20 TOTAL cost (Total of 14 thru 19)
21 Cost per KWof Installed Capacity (line 20
22 Production Expenses
23 Operation Supervision and Engineering
24 Water for Power
25 Hydraulic Expenses
26 Electric Expenses
27 Misc Hydraulic Power Generation Expenses
28 Rents
29 Maintenance Supervision and Engineering
30 Maintenance of Structures
31 Maintenance of Reservoirs, Dams, and Waterways
32 Maintenance of Electric Plant
33 Maintenance of Misc Hydraulic Plant
34 Total Production Expenses (total 23 thru 33)
35 Expenses per net KWh
Run-of-River
Outdoor
1937
1947
34.
753
Run-of-River
Conventional
1907
1921
12.
760
~--
190,867,000 82,726,000
~~-----'---'- -----------,----
172,970
1,499,664
314 125
758,636
29,359
774 754
312.3117
311,407
138 033
512,401
985,438
51,383
998,662
319.8930
--''-"--~-
330,231
76,447
303,476
16,637
113,586
99,661
66,898
213,718
103,879
284,723
609,256
0084
124 505
49,254
187,448
13,879
51,443
32,296
045
378
60,417
54,927
611,617
0074
FERC FORM NO.1 (REV. 12-03)Page 406.
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2005/04
This Report Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) DA Resubmission 04/18/2006
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts, Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses.
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No. 1971
Plant Name: Common Facilities
(d)
FERC Licensed Project No. 2061
Plant Name: Lower Salmon
(e)
2899FERC Licensed Project No,
Plant Name: Milner
Run-of-River
Outdoor
1949
1949
60.
751
Run-of-River
Conventional
1992
1992
59.45
381
~~~
196.441 000 641 000
'___
00', 0_'0
- --~- -- _'---
0 ---
- '------- -----------,~-------~--------,-----
-- 0,
'__-
984
786,853
13,556 785
078 219
051
26,592,892
0000
403,335
871.235
6.472,580
6.487 548
88,693
323 391
238.7232
138,100
10,336.453
147 049
576 509
501,877
55,699 988
936.9216
---,,---------'----'-- ~------
___m_- o,
--~---~-----,-"-"-,------------
660 018
143
689,161
0000
824 897
140,225
444 131
123.457
149,319
187
58,711
118,864
44,083
140,209
129 331
174.414
0111
132.476
354 943
124 246
48.450
148,509
1.412
23.494
33,661
859
093
323
009.466
0564
Line
No.
FERC FORM NO.1 (REV. 12-03)Page 407.
This Page Intentionally Left Blank
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da , Yr)
Idaho Power Company (2)A Resubmission 04/18/2006 2005/04
FOOTNOTE DATA
ISchedu/e Page: 406 Line No.Column: b
American Falls generating capacity is dependent upon water releases controlled by the
Uni ted States Bureau of Reclamation.
!Schedu/e Page: 406 Line No.Column:
Cascade generating capacity is dependent upon water releases controlled by the United
States Bureau of Reclamation.
ISchedu/e Page: 406 Line No.Column:
Upstream storage in Brownlee Reservoir.
ISchedu/e Page: 406.Line No.Column: b
Upstream storage in Brownlee Reservoir
ISchedu/e Page: 406.Line No.Column:
Lower Malad maximum demand 15, 000 Kw, Upper Malad maximum demand 9, 000 Kw non-coincident.
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/04
(2)D A Resubmission 04/18/2006
GENERATING PLANT STATISTICS (Small Plants)
1. Small generating plants are steam plants of, less than 25 000 Kw; internal combustion and gas turbine-plants, conventional hydro plants and pumped
storage plants of less than 10 000 Kw installed capacity (name plate rating).2. Designate any plant leased from others, operated under a license from
the Federal Energy Regulatory Commission, or operated as a joint facility, and give a concise statement of the facts in a footnote. If licensed project,
give project number in footnote.
Line Year Installed Ca~acity Net Peak Net GenerationName of Plant Orig.Name Plate atin!Demand Excluding Cost of Plant
No.Const.(InMW)(6~aVn.Plant Use
(a)(b)(c)(e)(f)
Hydro:
Clear Lakes 1937 238 730,795
Thousand Springs 1912 52,050 691 209
Internal Combustion:
Salmon Diesel (1)1967 901 055
(1) Salmon units are classified as standby.
FERC FORM NO.1 (REV. 12-03)Page 410
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/04
(2)0 A Resubmission 04/18/2006
GENERATING PLANT STATISTICS (Small Plants) (Continued)
3. List plants appropriately under subheadings for steam, hydro, nuclear, internal combustion and gas turbine plants. For nuclear, see instruction 11
Page 403.4. If net peak demand for 60 minutes is not available, give the which is available, specifying period.5. If any plant is equipped with
combinations of steam, hydro internal combustion or gas turbine equipment, report each as a separate plant. However, if the exhaust heat from the gas
turbine is utilized in a steam turbine regenerative feed water cycle, or for preheated combustion air in a boiler, report as one plant.
Plant Cost (Incl Asset Operation Production Expenses Fuel Costs (in cents LineRetire. Costs) Per MW Exc l. Fuel Fuel Maintenance Kind of Fuel (per Million Btu)
(g)
(h)(i)(k)(I)No.
692,318 97,668 129,876
533,092 76,130 85,426
180,211 Diesel
FERC FORM NO.1 (REV. 12-03)Page 411
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2005/Q4
(2)0 A Resubmission 04/18/2006
TRANSMISSION LINE STATISTICS
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts.Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line DESIGNATION VOLTAGE (KV)Type of LE~G
;hH ~ole WileS)(Indicate wliere ~I)t e sera Number
No.other than u dergroun lines
60 cvcle, 3 chase)Supporting report circuit miles)
UffSfructure ~tI1J1h~res CircuitsFromOperatingDesignedStructureof Line of Anot erDesi
PDated
Line(a)(b)(c)(d)(e)
(g)
(h)
1 Boardman Slatt 500.500,S Tower
3 Borah Midpoint 345.500.S Tower 85,
4 Jim Bridger Goshen 345.345,S Tower 226,
5 State Line Midpoint 345.345.S Tower 76.
6 Kinport Borah 345.345,S Tower 27,
7 Midpoint Borah #1 345.345.H Wood 79,
8 Midpoint Borah #2 345.345,H Wood 77.59
9 Adelaide Tap Adelaide 345,345.H Wood
Quartz LaGrande 230.230,H Wood 46.
Midpoint Hunt 230.230,S Tower
Brady Antelope 230.230,H Wood 56.44
Brady Treasureton 230,230.H Wood
Brady #1 & #2 Kinport 230,230,S Tower 18,
Jim Bridger Point of Rocks 230,230.H Wood 1.40
Brownlee Ontario 230.230,S Tower 74.
Mora Bowmont 138.230.S P Wood
Mora Bowmont 138,230.H Wood 10.
Jim Bridger Point of Rocks 230.230.H Wood
Caldwell 710 Locust 230,230,SP Steel 18,
Boise Bench Caldwell 230,230,S Tower 4.40
Boise Bench Caldwell 230,230,H Wood 33,
Boise Bench Cloverdale 23M 230.S Tower 15.
Boardman Dalreed Sub 230.230.H Wood 1.68
Brownlee 714 Oxbow 230,230.SP Steel 10.
Caldwell Ontario 230,230,H Wood 27,
Caldwell Ontario 230.230.S Tower
Bennett Mtn PP Rattlesnake TS 230,230.SP Steel 4.48
Boise Bench Midpoint #1 230,230,S Tower
Boise Bench Midpoint #1 230.230,H Wood 108,
Brownlee Quartz Jct 230,230,S Tower
Brownlee Quartz Jct 230.230,H Wood 41,
Brownlee Boise Bench #1 & #2 230.230.S Tower 99,
Oxbow Brownlee 230,230.S Tower 10.
TOTAL 690.11.02 156
FERC FORM NO.1 (ED. 12-87)Page 422
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2005/04
(2)D A Resubmisslon 04/18/2006
TRANSMISSION LINE STATISTICS (Continued)
7, Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns OJ to (I) on the book cost at end of year.
COST OF LINE (Include in Column OJ Land,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total LineOther Costs Expenses Expenses (0)Expenses No.(i)(k)(I)(m)(n)
(p)
2X1780 ACSR 446,708 446,708
1272 ACSR 256,381 776,998 033 379
1272 ACSR 483,30~740,328 16,223 637
95 ACSR 571 ,97~996,449 568,428
1272 ACSR 344,22C 028,033 372,253
15.5 ACSR 283 5,440 990 724,133
15,5 ACSR 64,851 047 015 111 866
15.5 ACSR 51,44/347 946 399,394
795 ACSR 51,414 317 071 368,485
15,5 ACSR 14E 001 738 010 883
1272 ACSR 108,301 328,646 2,436 947
1795 ACSR 186 186
1715.5 ACSR 82c 969,476 988,305
1272 ACSR 19C 525 715
2X954 ACSR 676,831 246,910 21,923 748
715,5 ACSR 347 012,372 360 334
715,5 ACSR
1272 ACSR 212,523 214,422
1590 ACSR 138,23€755,911 894 147
1272 ACSR 817 05/761 586 578 640
15.5 ACSR
1272 ACSR 999,02!532,790 531 816
95 MC 895 80,895
~54 ACSR 16,463,767 463,767
2X954 ACSR 194 902 042 096 805
1272 ACSR
1272 ACSR 701 666,354 748,055
715,5 ACSR 336,18€689,418 025 604
715,5 ACSR
795 ACSR 99!1,782 886 825,881
95 ACSR
VARIOUS 261 22!997 000 258 229
1272 ACSR 191 291 197 324
916 298 286,562 651 312,478 949 5,798,097 620 886 565 610 984
FERC FORM NO.1 (ED. 12-87)Page 423
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2005/Q4
(2)0 A Resubmission 04/18/2006
TRANSMISSION LINE STATISTICS
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines indude all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts.Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission,
4. Exclude from this page any transmission lines for which plant costs are included in Account 121 , Nonutility Property.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line DESIGNATION yO!. TAGE,(KV)Type of LENG~H ~ole ~ileS)(Indicate wtiere ~IIJ t e s
cf NumberNo.other than u dergroun lines
60 cvcle, 3 chase)Supporting report circuit miles)
un ~tructure ~tru~~~res CircuitsFromOperatingDesignedStructureof Line 0 Anot er
(a)(b)(c)(e)Desi
onated
Line
(d)
(g)
(h)
1 Boise Bench Midpoint #2 230.230.S Tower 3.42
2 Boise Bench Midpoint #2 230.230.H Wood 102.
3 Oxbow Pallette Jct 230.230,S Tower 20.
4 Pallette Jct Imnaha 230.230.H Wood 23.
5 Hells Canyon Palette Jct 230,230.S Tower
6 Brownlee Boise Bench 230.230,S Tower 102,
7 Boise Bench Midpoint #3 230,230.H Wood 106.
8 Palette Jct Enterprise 230.230.H Wood 28,
9 Borah Brady #2 230.230.S Tower 0.43
Borah Brady #2 230.230.H Wood
Borah Brady #1 230.230.H Wood
Goshen State Line 161,161.00 H Wood 90.49
Don Goshen 161.0C 161.00 S Tower
Don Goshen 161.0C 161.00 H Wood 46,
American Falls Power Plant Adelaide 138.138.H Wood 80.
American Falls Power Plant Adelaide 138.0!138.S P Wood
Minidoka Loop Adelaide 138.138.S Tower 1.11
Nampa Caldwell 138.138.S P Wood 10,
Upper Salmon Mountain Home Jct 138.H Wood
Upper Salmon Mountain Home Jct 138.138,H Wood 49.
Upper Salmon Cliff 138,138.H Wood 30,
Eastgate Russet 138.138.S P Wood
Brady Fremont 138,138,S Tower 1.00
Brady Fremont 138.138.H Wood 24,
Brady Fremont 138.138,S P Wood 24,
King Lower Malad 138,138,H Wood 84.
Emmett Jct Payette 138,138.H Wood 62,
Mountain Home AFB Tap 138,138.H Wood
Ontario Quartz 138,138,H Wood 73,
King American Falls PP 138.138.S Tower
King American Falls PP 138,138,H Wood 146.40
King American Falls PP 138,138,S P Wood
Duffin Clawson 138.138.H Wood
TOTAL 690.11.02 156
FERC FORM NO.1 (ED. 12-87)Page 422.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2005/04
(2)D A Resubmission 04/18/2006
TRANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (I) on the book cost at end of year.
COST OF LINE (Include in Column (j) Land,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total LineOther Costs Expenses Expenses (0)Expenses No.(I)
(j)
(k)(I)(m)(n)
(p)
1715.5 ACSR 227 82'5,413 410 641,235
VARIOUS
1272 ACSR 23.301 032 869 056,177
1272 ACSR 138.47 220,528 359,005
1272 ACSR 252,130 262,867
954 ACSR 170 69/555,559 726,253
15,5 ACSR 247 899,440 147 297
1272 ACSR 633,094 684 216
1272 ACSR 200,632 203,700
15.5 ACSR
1272 ACSR 10,064 180,008 190,072
250 COPPER 16,15~648,382 664 537
1715,5 ACSR 041 622,852 698,893
p97.5 ACSR
~50 COPPER 26,501 346.862 373,369
50 COPPER
15.5 ACSR 15,081 249,232 264 320
95 AAC 157,43.533,646 691 078
95 ACSR 47,696 746 744,433
VARIOUS
95 ACSR 43,561 764,183 807 751
95 AAC 270,557,504 828,327
iVARIOUS 564 443.959 008,891
VARIOUS
Iv'ARIOUS
VARIOUS 377,411 1,454 234
VARIOUS 30,911 316,460 347 378
397.5 ACSR 95'955
~ARIOUS 34,421 1,486,208 520,636
1715.5 ACSR 148 91/282 784 4,431,698
1715.5 ACSR
1715,5 ACSR
~\O 191 309,827 314,018
25,916,298 286,562 651 312,478,949 798,097 620 886 565,610 984
FERC FORM NO.1 (ED. 12-87)Page 423.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2005/Q4
(2)D A Resubmission 04/18/2006
TRANSMISSION LINE STATISTICS
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts.Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line DESIGNATION VOLTAGE (KV)Type of LENGJ,H ~ole WileS)(Indicate where hiD t e 5J
Number
No.other than u dergroun lines
60 cvcle, 3 Dhase)Supporting report circuit miles)
l-on ~tructure ~tl1J(ttures CircuitsFromOperatingDesignedStructureof Line of Al')otherDesip;ated Line(a)(b)(c)(d)(e)
(g)
(h)
1 American Falls Brady Tie 138.138.H Wood
2 Upper Salmon A-King 138,138,H Wood
3 Upper Salmon B Wells 138.138.H Wood 125.
4 King Wood River 138.138,H Wood 73.
5 Boise Bench Grove 138,138.S P Wood 10.47
6 Quartz John Day 138.138.H Wood 67,
7 Sinker Creek Tap 138,138,H Wood
8 Mora Cloverdale 138,138.H Wood
9 Mora Cloverdale 138.138,S P Wood 22,
Stoddard Jct Stoddard Sub 138.138.S P Steel 3.80
Fossil Gulch Tap 138.138,H Wood
Wood River Midpoint 138.138,H Wood 53.
Wood River Midpoint 138.O!138.S P Wood 16.
Oxbow McCall 138.O!138.H Wood 38,
Oxbow McCall 138.138.S P Wood
Lowell Jct Nampa 138,138,S P Wood
Hunt Milner 138.138.S P Wood 19.40
Strike Bruneau Bridge 138,138.H Wood 13.48
American Falls Kramer Sub 138.138,S P Wood 18,
Pingree Haven 138.138.S P Wood 11.
Midpoint Twin Falls 138,138.S P Wood 25.
Twin Falls Russett 138.138,S P Wood
Blackfoot Aiken 138.O!138.S P Wood
Peterson Tendoy 138.O!138.H Wood 57,
Eastgate Tap Eastgate 138.138.S P Wood
Boise Bench Mora 138.01 138.H Wood 13.14
Bowmont-Caldwell Simplot Sub 138.O!138,S P Wood
Gary Lane Eagle 138.138,S P Wood
Locust Grove Blackcat Sub 138.138.S P Steel
Boise Bench Butler 138,138,S P Wood
Eagle Star 138,S P Wood
Karcher Sub Zilog Tap 69.138.S P Steel
Cloverdale - 712 712 - Wye 138,138,S P Steel
Butler Wye 138.O!138,S P Steel
Horseflat Tap 138.O!138.S P Steel
TOTAL 690.11,156
FERC FORM NO.1 (ED. 12-87)Page 422.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2005/04
(2)D A Resubmission 04/18/2006
TRANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (I) on the book cost at end of year.
COST OF LINE (Include in Column (j) Land EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total LineOther Costs Expenses Expenses (0)Expenses No.(i)
(j)
(k)(I)(m)(n)
(p)
954 ACSR 96,921 921
250 COPPER 741 93,073 95,814
VARIOUS 28,49C 745 804 774 294
VARIOUS 173,357,968 531,651
VARIOUS 225,60"629,593 855,195
397.5 ACSR 362,416 2,454 589
VARIOUS 199 219
15,5 ACSR 727,471 250 571 978 042
VARIOUS
1272 ACSR
?50 COPPER 45C 439 63,889
397.5 ACSR 281 06L 374 306 655,370
~97.5 ACSR
397.5 ACSR 752,478 836,661
~97,5 ACSR
1715.5 ACSR 211 131 1,421 002 632 133
1715,5 ACSR 324 077 727 081 051
~97.5 ACSR 587,404 602,331
15.5 ACSR 13,7J.j 052 549 066,283
97.5 ACSR 11 ,21~778,092 789,305
ARIOUS 841 958 765 013,613
15,5 ACSR 16,79C 206 158 222,948
15.5 ACSR 13,61E 456 919 470,535
97,5 ACSR 395,69E 3,449 949 845,645
15.5 ACSR 45,054 909 100,898
15.5 ACSR 14,69,632 718 647,415
95 AAC 49,642 642
95 AAC 489,031 963,865 2,452 902
1272 ACSR 935,72E 825 718 761,443
1272 ACSR 827 093 861,780
15.5 ACSR 942 956 942 956
95 AAC 423,821 423,821
1272 ACSR 140,41~709,148 849 560
95 ACSR 473,87E 068,446 542,321
954 ACSR 58,005 58,005
25,916,298 286,562,651 312,478 949 798,097 620,886 565 610 984
FERC FORM NO.1 (ED. 12-87)Page 423.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2005/04
(2)D A Resubmission 04/18/2006
TRANSMISSION LINE STATISTICS
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts.Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5, Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line DESIGNATION VOLTAGE (KV)Type of LENG
J.H ~ole wileS)(Indicate wliere ~1r:1 t 5J c NumberNo.other than u dergroun lines
60 cvcle, 3 chase)Supporting report circuit miles)
From Operating Designed On ~tfl:lcture I ugf~~~1h~rs CircuitsStructureof LineDesi
pfjated
Line(a)(b)(c)(d)(e)
(g)
(h)
1 Valivue Tap 138.138,S P Steel
2 Kinport Don #1 138,138.S Tower 1.24
3 Twin Falls PP Tap 138.138,H Wood
4 American Falls PP Amercian Falls Trans ST 138.138.S P Steel
5 Lower Salmon King Tie 138.138,H Wood
6 C J Strike Strike Jct 138,138,S Tower
7 Strike Jct Mountain Home Jct 138.0 138,H Wood 26,
9 Strike Jct Bowmont 138.H Wood
Strike Jct Bowmont 138,138,S Tower
Strike Jct Bowmont 138.138,H Wood 68,
Lucky Peak Lucky Peak Jct 138,138,H Wood
Bliss King 138,138,H Wood 10.
Milner Deadend Milner PP 138.138.S P Wood 1.31
Swan Falls Tap 138,138,H Wood
Hines BPA (Harney)115.115.H Wood
6S Kv Lines 69.69,H Wood 166.
69 Kv Lines 69,69.S P Wood 003,
46 Kv Lines 46,46,S P Wood 428,
Government Agency ROWs
TOTAL 690.11.02 156
FERC FORM NO.1 (ED. 12-87)Page 422.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2005/04
(2)D A Resubmission 04/18/2006
TRANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns m to (I) on the book cost at end of year.
COST OF LINE (Include in Column (j) Land,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total LineOther Costs Expenses Expenses (0)Expenses No.(i)
(j)
(k)(I)(m)(n)
(p)
95 ACSR 351,497 351.497
15.5 ACSR 17~212,777 213,951
?50 COPPER 53,888 53,946
15,5 ACSR 76,560 76,560
397,5 ACSR 4,406 4,406
15.5 ACSR 253,872 254 946
397.5 ACSR 355 525,528 529 883
715.5 ACSR 29,90"501 004 530,906
715.5 ACSR
1715,5 ACSR 279,481 279,488
1715.5 ACSR 62C 954,169 959,789
1715,5 ACSR 81l 183,606 186,420
397,5 ACSR 12.88!261 511 274,396
397.5 ACSR 97S 63,404 65,382
VARIOUS 928 99C 025,493 954,483
VARIOUS
VARIOUS 176,26!648 221 824,486
5,718,718,852
798,097 620,886 565 610 984,591
916 298 286,562,651 312,478,949 798,097 620 886 565 610 984
FERC FORM NO.1 (ED. 12-87)Page 423.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2005/04
(2)D A Resubmission 04/18/2006
TRANSMISSION LINES ADDED DURING YEAR
1. Report below the information called for conceming Transmission lines added or altered during the year.It is not necessary to report
minor revisions of lines.
2. Provide separate subheadings for overhead and under- ground construction and show each transmission line separately. If actual
costs of competed construction are not readily available for reporting columns (I) to (0), it is permissible to report in these columns the
Line LINE DESIGNATiON Line SUPPORTING STRUCTURE CIRCUITS PER STRUCTUR
No.From
Le!1gth
Type AVerage Present UltimateNumber perMilesMiles
(a)(b)(c)(d)(e)(f)
(g)
1 Eagle Star SP Wood 15,
2 Karcher Zilog Tap SP Steel 18,
3 Bennett Mtn Rattlesnake SP Steel 12.
TOTAL 45.
FERC FORM NO.1 (REV. 12-03)Page 424
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2005/04
(2)0 A Resubmission 04/18/2006
TRANSMISSION LINES ADDED DURING YEAR (Continued)
costs. Designate, however, if estimated amounts are reported. Include costs of Clearing Land and Rights-of-Way, and Roads and
Trails, in column (I) with appropriate footnote, and costs of Underground Conduit in column (m).
3. If design voltage differs from operating voltage, indicate such fact by footnote; also where line is other than 60 cycle, 3 phase
indicate such other characteristic.
CONDUCTORS Voltage LINE COST Line
Size Specification conf~uration Land and Poles, Towers Conductors Asset Total No.and pacing (Operating)Land Rights and Fixtures and Devices Retire. Costs(h)(i)(k)(I)(m)(n)(0)
(p)
795 AAC Vert 6' 138 846.81"096,141 942 956
795 AAC Vert 6' 259 18~164 638 423,821
1272 ACSR Vert 9' 230 81,701 894 771 811 748,055
701 000,541 032 590 114 832
FERC FORM NO.1 (REV. 12-03)Page 425
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/04
(2)0 A Resubmission 04/18/2006
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation , designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
Adelaide transmission 345.138.13.
Aiken distribution 46.13.
Alameda distribution 46.13.
Alameda distribution 138.13.
American Falls PP - attended transmission 138.13.
American Falls transmission 138.46.12.
Artesian distribution 46.13.
Bannock Creek distribution 46.13.
Bennett Mountain Power Plant transmission 230.18.
Bennett Mountain Power Plant transmission 18.
Bethel Court distribution 138.13.
Black Cat distribution 138.13.
Blackfoot distribution 46.12.
Blackfoot distribution 138.38.13.
Bliss - attended transmission 138.13.
Blue Gulch distribution 138.34.
Boise Bench - attended distribution 138.34.
Boise Bench - attended transmission 138.69.13.
Boise Bench - attended transmission 230.138.13.
Boise Cascade Emmett CSPP distribution 69.13.
Boise distribution 138.13.
Borah transmission 345.230.13.
Bowmont distribution 69.46.
Bowmont distribution 138.34.
Bowmont distribution 138.69.13.
Brady transmission 46.12.
Brady transmission 230.138.13,
Brownlee - attended transmission 230.13.
Bruneau Bridge distribution 138.34.
Buckhorn distribution 69.35.
Bucyrus distribution 46.
Buhl distribution 46.13.
Burley Rural distribution 69.13.
Butler distribution 138.13.
Caldwell distribution 138.13.
Caldwell distribution 138.69.13.
Caldwell transmission 230.138.12.
Canyon Creek distribution 138.34.
Canyon Creek distribution 138.69.12.
Cascade Power Plant - attended transmission 69.
FERC FORM NO.1 (ED. 12-96)Page 426
Name of Respondent This ooort Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/Q4
(2)0 A Resubmission 04/18/2006
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transfonners Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units (In MVa)
(f)(0)(h)(i)
(j)
(k)
300
135
130
374
450
300
734
240
FERC FORM NO.1 (ED. 12-96)Page 427
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/04
(2)0 A Resubmission 04/18/2006
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
Chestnut distribution 138.13.
Clear Lake - attended transmission 46.
Cliff transmission 138.46.12.
Cloverdale transmission 138.13.
Cloverdale transmission 138.69.12.
Dale distribution 69.13.
Dale distribution 138.34.
Dale distribution 138.46.12.
Danskin transmission 138.12.
Don distribution 138.
Don distribution 138.13.
Don distribution 138.13.
DRAM distribution 138.13.
DRAM distribution 230.138.13.
Duffin distribution 138.34.
Eagle distribution 138.13.
Eastgate distribution 138.13.
Eckert distribution 138.36.
Eden distribution 138.34.
Eden distribution 138.46.12.
Elkhom distribution 138.12.
Elmore transmission 138.34.
Elmore distribution 138.69.12.
Emmett distribution 138.12.
Emmett distribution 138.69.12.
Falls distribution 46.12.
Filer distribution 46.12.
Flying H distribution 69.2.40
Fort Hall distribution 46.12.
Fossil Gulch distribution 138.13.
Fossil Gulch distribution 138.34.
Fremont transmission 138.46.12.
Gary distribution 138.13.
Gem distribution 69.13.
Golden Valley distribution 69.12.
Gowen Substation distribution 138.35.
Grindstone distribution 35.12.
Grove distribution 138.12.
Hagerman distribution 46.12.
Hailey distribution 138.12.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/Q4
(2)DA Resubmission 04/18/2006
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
Increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units (In MVa)
(f)
(g)
(h)(i)(k)
134
160
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/04
(2)0 A Resubmission 04/18/2006
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
Haven distribution 46.34.
Hewlett Packard distribution 138.13.
Hidden Springs distribution 138.13.
Highland distribution 138.13.
Hill distribution 138.12.
Homedale distribution 69.12.
Horse Flat transmission 230.138.13.
Horseshoe Bend distribution 35.12.
Horseshoe Bend distribution 69.36.
Horseshoe Bend distribution 69.25.
Houston distribution 69.13.
Hulen distribution 46.13.
Hunt transmission 230.138.13.
Hydra distribution 138.34.
Island distribution 69.12.
Jerome distribution 138.12.
Julion Clawson distribution 138.34.
Joplin distribution 138.13.
Karcher distribution 138.13.
Kenyon distribution 69.12.
Ketchum distribution 138.12.
Kinport transmission 161.46.13.
Kinport transmission 230.138.12.
Kinport transmission 230.138.13.
Kinport transmission 345.230.13.
Kramer distribution 138.34.
Kramer distribution 138.13.
Kuna distribution 138.13.
Lake Fork distribution 138.36.
Lake Fork transmission 138.69.12.
Lamb distribution 138.13.
Lansing distribution 69.13.
Lincoln distribution 138.13.
Linden distribution 138.13.
Locust distribution 138.34.
Locust transmission 230.138.13.
Lower Malad - attended transmission 138.
Lower Salmon - attended transmission 138.13.
Map Rock distribution 69.12.
McCall distribution 69.12.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/Q4
(2)0 A Resubmission 04/18/2006
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Total Capacity No.In Service Transformers Type of Equipment Number of Units
(h)(i)
(j)
(In MVa)
(f)
(g)
(k)
100
300
180
180
600
360
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This
wort
Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/04
(2)0 A Resubmission 04/18/2006
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page. summarize according to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
McCall distribution 138.35.
McCall distribution 138.69.12.
Meridian distribution 138.13.
Micron distribution 138.12.
Midpoint transmission 230.138.12.
Midpoint transmission 345.230.13.
Midpoint transmission 500.345.
Midrose distribution 138.13.
Milner distribution 69.38.13.
Milner distribution 69.38.
Milner distribution 138.34.
Milner PP - attended transmission 138.13.
Moonstone distribution 138.34.
Mora distribution 138.34.
Moreland distribution 46.12.
Moreland distribution 46.34.12.
Mountain Home distribution 69.12.
Mountain Home Air Force Base distribution 69.12.
Mountain Home Air Force Base distribution 138.12.
Nampa distribution 230.138.
Nampa distribution 138.12.
Nampa distribution 138.69.12.
New Meadows distribution 69.35.
New Plymouth distribution 69.12.
Notch Butte distribution 13.
Parma distribution 69.12.
Parma distribution 69.34.
Paul distribution 138.34.12.
Payette distribution 138.12.
Pingree distribution 138.46.12.
Pingree distribution 138.36.
Pleasant Valley distribution 138.34.
Pocatello distribution 46.12.
Portneuf distribution 138.36.
Portneuf distribution 46.35.
Rockford distribution 46.12.
Russett distribution 138.12.
Sailor Creek distribution 138.13.
Sailor Creek distribution 138.34.
Salmon distribution 69.12.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This
wort
Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/Q4
(2)D A Resubmission 04/18/2006
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)
Transformers Spare Total Capacity No.In Service Transformers Type of Equipment Number of Units (In MVa)
(f)
(g)
(h)(i)
(j)
(k)
120
720
1000
180
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This
wort
Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/04
(2)0 A Resubmission 04/18/2006
SUBSTATIONS
1. Report below the information called for conceming substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale , may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
Salmon distribution 69.34.12.
Shoshone distribution 46.13.
Shoshone distribution 46.
Shoshone Falls - attended transmission 46.
Shoshone Falls - attended transmission 46.
Silver distribution 138.34.
Simplot distribution 138.12.
Sinker Creek distribution 138.34.
Siphon distribution 138.34.
South Park distribution 46.13.
Star distribution 138.13.
State distribution 69.12.
Stoddard distribution 138.13.
Strike Power Plant - attended transmission 138.13.
Sugar distribution 138.34.
Swan Falls - attended transmission 138.
Taber distribution 46.12.
Ten Mile distribution 138.13.
Terry distribution 138.12.
Thousand Springs - attended transmission 46.
Thousand Springs - attended transmission 2.40
Toponis distribution 138.34.
Twin Falls distribution 138.13.
Twin Falls distribution 138.46.12.
Twin Falls PP - attended transmission 138.
Twin Falls PP - attended transmission 138.13.
Upper Malad - attended transmission 46.
Upper Salmon- attended transmission 138.
Ustick distribution 138.12.
Vallivue distribution 138.13.
Victory distribution 138.12.
Ware distribution 69.12.
Weiser distribution 69.12.
Weiser distribution 138.69.12.
Wilder distribution 69.13.
Wye distribution 138.13.
Zilog distribution 69.12.
The above are all State of Idaho
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2)D A Resubmission 04/18/2006
SUBSTATIONS (Continued)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
Increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT LineTransformersSpare(In Service) (In MVa)In Service Transformers Type of Equipment Number of Units Total Capacity No.
(In MVa)
(f)
(g)
(h)(i)(k)
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This
wort
Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/Q4
(2)0 A Resubmission 04/18/2006
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
Montana:
Peterson transmission 138.38.12.
Nevada:
Valmy - attended transmission 345.21.
Wells transmission 138.69.12.
Oregon:
Boardman - attended transmission 500.24.
Cairo distribution 69.12.
Hells Canyon - attended transmission 230.13.
Hines transmission 138.115.12.
Malheur Butte distribution 69.34.12.
Nyssa distribution 69.12.
Ontario distribution 138.12.
Ontario distribution 138.69.12.
Ontario distribution 230.138.12.
Ore-Ida distribution 69.12.
Oxbow - attended transmission 69.38.12.
Oxbow - attended transmission 230.13.
Oxbow - attended transmission 230.138.13.
Quartz transmission 138.69.12.
Quartz transmission 138.80.12.
Vale distribution 69.13.
Wyoming:
Jim Bridger - attended transmission 345.22.
Transformers-distribution substations under 10,000
KVA 83 unattended.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2005/Q4
(2)D A Resubmission 04/18/2006
SUBSTATIONS (Continued)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Total Capacity No.In Service Transformers Type of Equipment Number of Units (In MVa)
(f)
(g)
(h)(i)(k)
150
500
240
244
100
133
748
FERC FORM NO.1 (ED. 12-96)Page 427.
INDEX
Schedule Paqe No.
Accrued and prepaid taxes ................................................,.......................262-263
Accumulated Deferred Income Taxes ....................................................................234
272-277
Accumulated provisions for depreciation of
conunon utility plant .............................................................................356
utility plant "
..............................
219
utility plant (sununary) ...................
...................................................
200-201
Advances
from associated companies .........................,..........................................256-257
Allowances ............,..........................................................................228-229
Amortization
miscellaneous "
,,"..............................
340
of nuclear fuel "
........................
202-203
Appropriations of Retained Earnings ........................................,.....................118-119
Associated Companies
advances from ................,...............................................................256-257
corporations controlled by respondent ............................................................103
control over respondent ..........................................................................102
interest on debt to "
,,"....................
256-257
Attestation "
,,"
............,......................... i
Balance sheet
comparative "
............................
110-113
notes to .....................................................................................122-123
Bonds ............................................................................................256-257
Capital Stock ....................,...................................................................251
expense .................,........................................................................254
premiums ...................................,.....................................................252
reacquired .............,.........................................................................251
subscribed "
.................................
252
Cash flows, statement of ...........,.............................................................120-121
Changes
important during year "
..................
108-109
Construction
work progress
work in progress
work progress
Control
- common utility plant ..........................................................356
- electric .......................,..............................................216
- other utility departments ................................................. 200-201
corporations controlled by respondent ............................................................103
over respondent ..................................................................................102
Corporation
controlled by .......................,............................................................103
incorporated .....................................................................................101
CPA, background information on ..........................................,............................101
CPA Certification, this report form ...............................,................................. i-ii
FERC FORM NO.1 (ED. 12-93)Index
INDEX (continued)
Schedule Page No.
Deferred
credits, other "
.............................
269
debits, miscellaneous .....................................,......................................233
income taxes accumulated - accelerated
amortization property ........................................................................272-273
income taxes accumulated - other property .............................,...................... 274-275
income taxes accumulated - other ...................................................,.........276-277
income taxes accumulated - pollution control facilities .......................................,.. 234
Definitions, this report form ......................................................................,. iii
Depreciation and amortization
of common utility plant "
....................
356
of electric plant "
..........................
219
336-337
Directors ............................................................................................105
Discount - premium on long-term debt .............................................................256-257
Distribution of salaries and wages ..........................,....................................354-355
Dividend appropriations ..........................................................................118-119
Earnings, Retained .....................................................,.........................118-119
Electric energy account ..............................................................................401
Expenses
electric operation and maintenance ...........................................................320-323
electric operation and maintenance, summary ....................................................., 323
unamortized debt .................................................................................256
Extraordinary property losses ........................................................................230
Filing requirements, this report form
General information ..................................................................................101
Instructions for filing the FERC Form 1 "....... i-
Generating plant statistics
hydroelectric (large) ...................................,....................................406-407
pumped storage (large) .......................................................................408-409
small plants .................................................................................410-411
steam-electric (large) .......................................................................402-403
Hydro-electric generating plant statistics ...............................................,....... 406-407
Identification "
.................................
101
Important changes during year "
..............
108-109
Income
statement of, by departments "
...........
114-117
statement of, for the year (see also revenues) ............................................... 114-117
deductions, miscellaneous amortization "
.....
340
deductions, other income deduction "
.........
340
deductions, other interest charges "
.........
340
Incorporation information "
......................
101
FERC FORM NO.(ED. 12-95)Index
INDEX (continued)
Schedule Paae No.
Interest
charges, paid on long-term debt, advances, etc ....................,.......................... 256-257
Investments
nonutility property ................................................,.............................221
subsidiary companies ....................................................,....................224-225
Investment tax credits, accumulated deferred "
'"
266-267
Law , excerpts applicable to this report form ..........................,............................... iv
List of schedules, this report form "
,,"............
2-4
Long-term debt ................,..................................................................256-257
Losses-Extraordinary property ................................................,.......................230
Materials and supplies ................................................,..............................227
Miscellaneous general expenses ..........................................,............................335
Notes
to balance sheet .............................................................................122-123
to statement of changes in financial position ................................................ 122-123
to statement of income ......................................,................................122-123
to statement of retained earnings ............................,...............................122-123
Nonutility property "
............................
221
Nuclear fuel materials .............................................,.............................202-203
Nuclear generating plant, statistics ........................................,....................402-403
Officers and officers ' salaries ......................................................................104
Operating
expenses-electric
expenses-electric
Other
paid-in capital "
............................
253
donations received from stockholders ..................................................,..........253
............................................................................
320-323
(summary) .............................................,........................323
gains on resale or cancellation of reacquired
capital stock ....................................................,...............................253
miscellaneous paid-in capital .....................................................,..............253
reduction in par or stated value of capital stock ...............................,................ 253
regulatory assets ,,"
..........................
232
regulatory liabilities ..........,................................................................278
Peaks, monthly, and output ....................................,......................................401
Plant, Common utility
accumulated provision for depreciation ..................................,........................356
acquisition adjustments ..........................................................................356
allocated to utility departments .................................................................356
completed construction not classified ...................................,........................356
construction work in progress ....................................................................356
expenses .....................................................,...................................356
held for future use ...................,..........................................................356
in service "
.................................
356
leased to others ..................................................,..............................356
Plant data "
.............................
336-337
401-429
FERC FORM NO.1 (ED. 12-95)Index
INDEX (continued)
Schedule Paqe No.
Plant - electric
accumulated provision for depreciation .....................................................,.....219
construction work in progress ....................................................................216
held for future use ..............................................................................214
in service ........,..........................................................................204-207
leased to others ...............................................,.................................213
Plant - utility and accumulated provisions for depreciation
amortization and depletion (summary) .............................................................201
Pollution control facilities, accumulated deferred
income taxes "
...............................
234
Power Exchanges "
............................
326-327
Premium and discount on long-term debt "
.........
256
Premium on capital stock .,...........................................................................251
Prepaid taxes ....................................................................................262-263
Property - losses, extraordinary .....................................................................230Pumped storage generating plant statistics ." 408-409
Purchased power (including power exchanges) "326-327
Reacquired capital stock ..............,..............................................................250
Reacquired long-term debt ...................................,....................................256-257
Receivers ' certificates ..........,...............................................................256-257
Reconciliation of reported net income with taxable income
from Federal income taxes ......................................................................261
Regulatory commission expenses deferred ..............................................................233
Regulatory commission expenses for year "
....
350-351
Research, development and demonstration activities .............................................,. 352-353
Retained Earnings
amortization reserve Federal ...................................,.................................119
appropriated ...................................................,.."
statement of, for the year ...................................................................
unappropriated ......................................................"
Revenues - electric operating ....................................................................
118-119
118-119
118-119
300-301
Salaries and wages
directors fees ...................................................................................105
distribution of ..........................................,...................................354-355
officers
' ...................................................,....................................
104
Sales of electricity by rate schedules ....................,..........................................304
Sales - for resale ...............................................................................310-311
Salvage - nuclear fuel ...........,...............................................................202-203
Schedules, this report form ..........................................................................
Securi ties
exchange registration ........................................................................250-251
Statement of Cash Flows ....................................................,.....................120-121
Statement of income for the year "
...........
114-117
Statement of retained earnings for the year ...................................................... 118-119
Steam-electric generating plant statistics .402-403
Substations ...............,..........................................................................426
Supplies - materials and .............................................................................227
FERC FORM NO.(ED. 12-90)Index
INDEX (continued)
Schedule Paqe No.
Taxes
accrued and prepaid .........................................................................262-263
charged during year .........................................................................262-263
on income, deferred and accumulated .............................................................234
272-277
reconciliation of net income with taxable income for ..................,......................... 261
Transformers, line - electric .......................................................................429
Transmission
lines added during year .....................................................................424-425
lines statistics ............................................................................422-423
of electricity for others ...................................................................328-330
of electricity by others ........................................................................332
Unamortized
debt discount "
.........................
256-257
debt expense ................................................................................256-257
premium on debt .............................................................................256-257
Unrecovered Plant and Regulatory Study Costs
......................................................
230
FERC FORM NO.(ED. 12-90)Index
Page
Number
12-
December 31 , 2005
ANNUAL REPORT
IDAHO SUPPLEMENT TO FERC FORM 1
MULTI-STATE ELECTRIC COMPANIES
INDEX
Title
Statement of Income for the Year
Taxes Allocated to Idaho
Notes and Accounts Receivable
Accumulated Provision for Uncollectible Accounts
Receivables from Associated Companies
Gain or Loss on Disposition of Property
Professional or Consultative Services
Electric Plant in Service
Electric Operating Revenues
Electric Operation and Maintenance Expenses
Number of Electric Department Employees
.- -"- -. .--. -..-.-
Idaho Power Company
ST ATE OF IDAHO - ALLOCATED
An Original
STATEMENT OF INCOME FOR THE YEAR
1, Report amounts for accounts 412 and 413, Revenue and Expenses from Utility Plant Leased to Others, in another utility
column (i o) in a similar manner to a utility department. Spread the amount(s) over lines 01 thru 24 as appropriate,
Include these amounts in columns (c) and (d) totals,
2. Report amounts in account 414, Other Utility Operating Income, in the same manner as accounts 412 and 413 above.
3, Report data for lines 7,, and 10 for Natural Gas companies using accounts 404., 404., 404., 407.1, and 407.
4, Use page 122 for important notes regarding the state ment of income or any account thereof,
5. Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a
material amount may need to be made to the utility's customers or which may result in a material refund to the utility
with respect to power or gas purchases. State for each year affected the gross revenues or costs to which the contingency
relates and the tax effects together with an explanation of retain such revenues or recover amounts paid with respect
to power and gas purchases.
6. Give concise explanations concerning significant amounts of any refunds made or received during the year.
Line
No.
Account
(a)
UTILITY OPERATING INCOME
Operating Revenues (400),........................"........,....,...........,.,.."..............".......
Operating Expenses
Operation Expenses (401).............,........,........................"................................
Maintenance Expenses (402)............................""..........,......,..........,.."...........
Depreciation Expense (403)..............,.................,................,............................
Amort. & Dep!. of Utility Plant (404-405)......,..,..,..........,................................,..
Amort. of Utility Plant Acq, Adj. (406)..................,..........................................,..
Amort. of Property Losses, Unrecovered Plant and
Regulatory Study Costs (407),........".....,...".,....,.........,....,......,.....",...,.......",
Amort. of Conversion Expenses (407)................................,........,.....................
Regulatory Debits/Credits (407.3 & 407.4)................,.........,...................,.........
Taxes Other Than Income Taxes (408.1)........,.............................,..............,....
Income Taxes - Federal (409,1)............,........,..................................................
- Other (409.1)........,........,..........................................,........................
Provision for Deferred Income Taxes (410.1 & 411,1) Net...............................
Investment Tax Credit Adj. - Net (411.4)..........................,................................
(Less) Gains from Disp, of Utility Plant (411.6).........,.......................................
Losses from Disp. of Utility Plant (411.7)....,.............,.......................................
(Less) Gains from Disposition of Allowances (411.8),.............................,..,......
Losses from Disposition of Allowances (411,9)....................,.................,....,.....
TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 22)............,.....
Net Utility Operating Income (Enter Total of line 2 less 23)
(Carry forward to page 11 , line 27)............,..,.....................,...................,......
,- .,,- -.,--. ----.-
n""..... 1
(Ref.
Page
No,
(b)
December 31 , 2005
TOTAL
Current Year Previous Year(c) (d)
802 914 413 $
474 244 701
287 956
895 690
781 326
370 700
828 248
059 990
235 170
(35 537 390)
016,462
695 182 852
107 731 561
756 779 337
491 365 712
187,809
052,059
092 999
(18 929 738)
219 724
839 912
958 131
(18 569 538)
042,465)
643 174 605
113 604 732
Idaho Power Company
STATE OF IDAHO. ALLOCATED
An Original December 31, 2005
TAXES ALLOCATED TO IDAHO
Kind of Tax
Taxes Other Than Income Taxes:
Labor Related:
FICA............................................,....................,
FUTA................................................................'
State Unemployment.......................................
Payroll Deduction & Loading............................
Total Labor Related...............................
Property Taxes.....................................................
Kilowatt-hour Tax.................................................
Licenses..............................................................,
Regulatory Commission Fees.................,............
Irrigation PIC........................................................
Total Taxes Other Than Income Taxes.................
Federal Income Taxes...........................................
State Income Taxes...............................................
Deferred Income Taxes.........................................
Investment Tax Credit Adjustment - Net................
Total Taxes Allocated to Idaho..............................
Taxes Charged
Durina Year
704 694
103,807
234 985
043,485)
817 822
160,927
242
670 843
175 414
828 248
059 990
235 170
(35,537 390)
016 462
602 480
IDAHO SUPPLEMENT Page 2
Idaho Power Company
ST ATE OF IDAHO
An Original December 31,2005
NOTES AND ACCOUNTS RECEIVABLE
Summary for Balance Sheet
Show separately by footnote the total amount of notes and accounts receivable
from directors, officers, and employees included in Notes Receivable (Account
141) and Other Accounts Receivable (Account 143)
Balance Balance
Line Accounts Beginning of End of
Year Year
No,(a)(b)(c)
Notes Receivable (Account 141)......................................................................................".......863 100 522 187
Customer Accounts Receivable (Account 142).......................................".........,..............,..,.......45,440 589 830 007
Other Accounts Receivable (Account 143),...................,....,.,...,...........,.",.."."""""""""""""'"201 303 860 636
(Disclose any capital stock subscription received)
TotaL"""..".........,..............""..,...,.,....,......."....,.",.,...."..................,...."",.,.............',..........504 991 212 830
Less: Accumulated Provision for Uncollectible
Accounts-Cr, (Account 144)..................,.............."..,.....".......,........",'.,......,..............",.......1 ,363,426 833 238
Total, Less Accumulated Provision for
Uncollectible Accounts"",..................,..,.,.....".......,..........."...."...................",.....,..............141 566 379 592
Notes Receivable - Account 141: (at 12-31-05)
Directors, officers, and employees - $812,291
Other Accounts Receivable - Account 143: (at 12-31-05)
Directors, officers, and employees - $1 ,422
ACCUMULATED PROVISION FOR UNCOLLECTIBLE ACCOUNTS - CR. (Account 144)
1. Report below the information called for concerning this accumulated provision,
2, Explain any important adjustments of subaccounts.
3. Entries with respect to officers and employees shall not include items for utility services.
Mdse
Line Item Utility Jobbing &Officers Other Total
Customers Contract and
No,(a)Work Employees
(b)(c)(d)(e)(f)
Bal. beginning of year 309 913 (546,498)763 415
Prov, for uncollectibles
for year......,....""....",..,.....".."..,............513 310 823
Accounts written of1.......,..........................
CoiL of accounts
written off....................",.....................,..
Adjustments (explain)",.............."",...,.,...
Balance end of year.......,.............,......,.....1 ,363,426 (530 188)833 238
,.-.ftun """"" I::"I::~""Pacre 3
Idaho Power Company
STATE OF IDAHO
An Original
1. Report particulars of notes and accounts receivable from associated companies at end of year.
RECEIVABLES FROM ASSOCIATED COMPANIES (Accounts 145, 146)
2. Provide separate headings and totals for accounts 145, Notes Receivable from Associated Companies, and 146,
Accounts Receivable from Associated Companies, in addition to a total for the combined accounts.
3. For notes receivable list each note separately and state purpose for which received. Show also in column
(a) date of note, date of maturity and interest rate.
4. If any note was received in satisfaction of an open account, state the period covered by such open account
5. Include in column (f) interest recorded as income during the year, including interest on accounts and notes
held at any time during the year.
6. Give particulars of any notes pledged or discounted, also of any collateral held as guarantee of payment
of any note or account
Line Particulars
tlalance
Beginning
of Year
(b)
LreOits
(d)
Totals for Year Balance
End of Year
(e)
ueDlts
(c)No.(a)
Account 145:
Account 146:
Rocky Mountain Communication 92,025 $310,428 $302,775 $99,678
205,519 $IDACORP lnc........,................. $66,708,406 $67,376,519 $537,406
407 $IDACORP Energy Solutions,....... 407 $
Total Account 146........................ :Ii 297,952 :Ii O',UIO O"" :Ii t)(tJ(~,(Ul :Ii 637 084
IDAHO SUPPLEMENT Page 4
December 31,2005
Interest
For Year
(f)
This Page Intentionally Left Blank
Idaho Power Company
STATE OF IDAHO
An Original
STATE OF IDAHO - TOTAL SYSTEM DATA
GAIN OR LOSS ON DISPOSITION OF PROPERTY (Account 421,1 and 421.
1, Give a brief description of property creating the gain or loss. Include name of party acquiring the property (when
acquired by another utility or associated company) and the date transaction was completed, Identify property
by type; Leased, Held for Future Use, or Nonutility,
2, Individual gains or losses relating to property with an original cost of less than $50.000 may be grouped, with the
number of such transactions disclosed in column (a),
3. Give the date of Commission approval of journal entries in column (b), when approval is required. Where approval
is required but has not been received, give explanation following the item in column (a). (See account 102, Utility
Plant Purchased or Sold.
Line Description of Property
unglnal (;ost
of Related
Property
(b)
uateJOumaf
Entry Approved
(When Required)
(c)(d)
Acct 421.
No,(a)
Gain on disposition of
property:
(14 637)15.158American Falls House Sale - operating
Buyer: Cesareo Rodriguez August 2005
JUMP Substation (reclassify Acctg Entry)
November 2005
63,565 (13 026)
Miscellaneous items (2)764)
Total gain,.................,..,................,.....,.........,.. $78,723 :Ii
Loss on disposition of
property:
Retire PC's & Software previously
held by IdaCorp energy December 2005
106,328
Total loss,...................,....,..,..........,..........,... :Ii 106,328
IDAHO SUPPLEMENT Page 5
December31 2005
Acct 421.
(e)
106 328
:Ii lUti,;j;.!t)
Idaho Power Company
ST ATE OF IDAHO
An Original December 31, 2005
STATE OF IDAHO - TOTAL SYSTEM DATA
PROFESSIONAL OR CONSULTATIVE SERVICES -ITEMS $10 000 AND OVER
Line PAYEE SERVICE TYPE Amount
No.(a)(b)(0)
ADECCO Mapping Services 900
AERO-GRAPHICS Mapping Services 957
ASCENTIUM CORPORATION PM Consultant 130 669
ASHLEY LAND SERVICES Environmental Services 112 971
ATER, WYNNE LLP Legal Services 130 397
AURORA CONSULTING GROUP Management Services 927
AUTODESK INC Management Services 925
BCON WSA INTERNATIONAL, INC Management Services 625
BIDART & ROSS INC Management Services 207
BLACKBURN & JONES LLP Legal Services 235 645
BLUE WORLD INFORMATION TECHNOL Management Services 32,296
BOISE BUSINESS CONSULTING, INC Management Services 188
BOISE STATE UNIVERSITY Management Services 594
BRENNEMAN, JOHN Lobby Service 302
BROWN RUDNICK BERLACK ISRAELS Lobby Service 000
BROWNSTEIN HYATT & FARBER, PC Legal Services 664 157
BUSINESS LEGAL CONSULTING Legal Services 641
CAMINUS CORPORATION Customer Service Support 316
CAPROCK GROUP INC, THE Management Services 000
CASCADE ENERGY ENGINEERING INC Engineering Services 030
CH2M HILL Engineering Services 102
CHAVEZ WRITING & EDITING, INC Management Services 235
CHURCH, JOHN S Economic Services 000
CONNOLLY & SMYSER, CHTD Management Services 178
CONNOR CLAIMS SPECIALISTS Management Services 037
CORNERSTONE SYSTEMS INC Computer Support Services 586 518
CRI ADVANTAGE Computer Support Services 433
CTA ARCHITECTS Architect Service 117
DAVID EVANS AND ASSOCIATES Management Services 934
DAVIS WRIGHT TREMAINE LLP Legal Services 997 720
DELOITTE & TOUCHE Accounting Services 906 466
DELOITTE TAX LLP Accounting Services 165
DESERT RESEARCH INSTITUTE Environmental Services 267 833
DEVELOPMENT DIMNENSIONS Computer Support Services 320
DEVINE, TARBELL & ASSOC INC Environmental Services 519
DHIINC Environmental Services 120
EAGLE CAP CONSULTING INC Environmental Services 184 055
ECOANAL YSTS INC Environmental Services 465
ELECTRONIC DATA SOLUTIONS Computer Support Services 135
ENGINEERING & HYDROSYSTEMS, IN Engineering Services 092
EOP GROUP Consulting Services 000
ERNST & YOUNG LLP Accounting Services 197 183
FOUND LAKE CONSULTING INC Environmental Services 229
GARRAD HASSAN AMERICA INC Environmental Services 809
GLOBAL INSIGHT Management Services 956
Page 6
.- .. .- -. .--. ~..~.~
Idaho Power Company
ST ATE OF IDAHO
An Original December 31 2005
STATE OF IDAHO - TOTAL SYSTEM DATA
PROFESSIONAL OR CONSULTATIVE SERVICES -ITEMS $10 000 AND OVER
Line PAYEE SERVICE TYPE Amount
No.(a)(b)(c)
GOLDER ASSOCIATES Environmental Services 721
GRID WEST Management Services 220 648
HALL FARLEY OBERRECHT & B Legal Services 523
HDR ENGINEERING, INC Engineering Services 547 081
HR MANAGEMENT SOLUTIONS LLC Management Services 669
HUMPHREYS, DENISE C Management Services 517
HYQUAL Management Services 845
IDACORP INC Management Services 866
INDUSTRIAL HYGIENE RESOURCES Management Services 606
INTERMOUNTAIN TECHNOLOGY GROUP Computer Support Services 122,413
INTERWOVEN INC Management Services 000
IOWA INSTITUTE OF HYDRAULICS Engineering Services 336
JAY H HULET & HIS ATTORNEY Legal Services 218
JBR ENVIRONMENTAL CONSULTANTS Environmental Services 575
JUB ENGINEERS Engineering Services 43,474
KPMG LLP Management Services 000
LE BOEUF LAMB GREENE Legal Services 851,491
MARSH ADVANTAGE AMERICA Management Services 840
MCMILLEN & ASSOCIATE, INC.Management Services 17,419
MCMILLEN ENGINEERING, LLC Engineering Services 128 120
MCMILLIAN ELDRIDGE Engineering Services 642
MILLER BATEMAN LLP Legal Services 103 240
MOSAIC COMPANY Information Security Service 500
MWH AMERICAS, INC,Management Services 540
NAVIGANT CONSULTING INC Consulting Services 000
NELSON & ASSOCIATES Management Services 600
NEXUS ENERGY SOFTWARE Computer Support Services 000
NIELSEN GROUP INC, THE Consulting Services 245 112
NORTH COUNTRY RESOURCES , INC Management Services 967
NORTH WIND, INC.Management Services 412
NORTHWEST RESEARCH GROUP Management Services 920
ORACLE Computer Support Services 138 977
OSI SOFTWARE Computer Support Services 900
PARR WADDOUPS BROWN GEE AND LO Environmental Services 367
PEARL MEYER & PARTNERS Management Services 630
PERKINS COlE LLP Legal Services 147 387
PERSONNEL PLUS Management Services 851
PGP CORPORATION Management Services 250
PHONE PRO Management Services 296
POWER ENGINEERS INC Engineering Services 727
POWERCET CORPORATION Management Services 028
Page 6A
,..."u,...~, ""'" ",..",o.rT
Idaho Power Company
STATE OF IDAHO
An Original December 31, 2005
STATE OF IDAHO - TOTAL SYSTEM DATA
PROFESSIONAL OR CONSULTATIVE SERVICES -ITEMS $10 000 AND OVER
Line PAYEE SERVICE TYPE Amount
No.(a)(b)(c)
PUBLIC OPINION STRATEGIES LLC Management Services 500
RAIN SHADOW RESEARCH, INC Management Services 553
RAPIDIGM INC Computer Support Services 179
RESOLVE, INC Management Services 218 251
RIDDELL WILLIAMS P.Legal Services 619
RIGHT SYSTEMS, INC Management Services 315
RIPLEY, LARRY 0 Legal Services 075
RIVERSIDE TECHNOLOGY INC Management Services 269 010
ROBERT J RIETH Legal Services 304
ROSEMARY BRENNAN CURTIN, INC Management Services 121
SALLADAY & DAVIS Legal Services 026
SCIENCE APPLICATIONS INTE Environmental Services 189
SMITH, CURTIS 0 Cloud Seeding Services 63,454
100 SOFTWARE AG INC Computer Support Services 181 170
101 SPATIAL NETWORK SOLUTIONS Management Services 340
102 SPL WORLDGROUP CONSULTING INC Computer Support Services 136
103 SPL WORLDGROUP INC Computer Support Services 11 ,446
104 STAHMAN , ROBERT W Legal Services 171 650
105 STATE OF IDAHO FISH & GAME Environmental Services 918
106 STATISTICAL DESIGN Management Services 314
107 STEPTOE & JOHNSON LLP Legal Services 334 590
108 STOEL RIVES LLP Legal Services 876
109 STONE, R H Management Services 045
110 STORAGETEK Management Services 856
111 STRATA GEOTECH ENGINEERING Engineering Services 998
112 SULLIVAN & CROMWELL Legal Services 160 156
113 SWCA, INC Environmental Services 513
114 TETRA TECH EM INC Environmental Services 232
115 THORNTON CONSULTING Management Services 679
116 TOWERS PERRIN HR SERVICES Management Services 760
117 TREASURE VALLEY LEGAL SERVICES Legal Services 591
118 TRUST ACCOUNT OF ALLEN & MCLAN Legal Services 160 000
119 UNIVERSITY OF IDAHO Environmental Services 348
120 UTILITY RESOURCES Management Services 946
121 VAN NESS FELDMAN Legal Services 542 035
122 WOOD CRAPO, LLC Legal Services 001
123 YTURRI, ROSE, BURNHAM, BENTZ Legal Services 259
124 ZGA ARCHITECTS & PLANNERS Architectural Services 31,443
Page 68
.~...~ ~. .~~. ~..~~~
Idaho Power Company
STATE OF IDAHO
An Original December 31 2005
PROFESSIONAL OR CONSULTATIVE SERVICES
ITEMS 000 OR MORE BUT LESS THAN 000
Line PREDOMINANT
No,PAYEE NATURE OF SERVICE AMOUNT
ASCENTIUM Consulting Services 412
ARMSTRONG PLANNING Planning Service 180
E TRADE Management Services 312
EMC CORPORATION Technical Services 025
ENVINTA Management Services 500
ENVIRONMENTAL ENGINEERING Environmental Services 348
EPIS, INC Management Services 500
EVANS KEENE Management Servic;:es 5,452
FIRE CAUSE ANALYSIS Engineering Services 5,478
GJORDING & FOUSER, PLLC Management Services 621
HOPKINS RODEN CROCKET Lobby Services 900
IDAHO SAND & GRAVEL Engineering Services 000
INTERACTION CONSULTING Management Services 138
INTERMOUNTAIN CLAIMS, INC Investigation Services 692
JEFFREY H BRAATNE PHD Medical Consulting 200
JONES, GLEDHILL, HESS, ANDREWS Management Services 903
LITCHFIELD CONSULTING GROUP Management Services 983
KEN MALGREN Investigation Services 276
MILLIGAN PHD, JAMES Medical Consulting 923
RW BECK Legal Services 189
SMITHSONIAN INSTITUTE Environmnetal Services 599
TERRACON Management Services 081
TOWERS PERRIN HR SERVICES Management Services 760
VAN WINKLE ENVIRONMENTAL CONSULT Management Services 100
YR SERVICES Management Services 022
"'AU'"' ,,"nn' """""IT
Page 6C
Idaho Power Company
ST ATE OF IDAHO - ALLOCATED
An Original December 31 2005
ELECTRIC PLANT IN SERVICE (Accounts 1
1, Report below the original cost of electric plant in service according to the prescribed accounts,
2. In addition to Account 101 , Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant
Purchased or Sold; Account 103, Experimental Electric Plant Unclassified; and Account 106, Completed Construction
Not Classified - Electric,
3, Include in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year,
4. Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such accounts.
5. Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in
column (c) , Also to be included in column (c) are entries for reversals of tentative distributions of prior year reported in
column (b), Likewise, if the respondent has a significant amount of plant retirements the end of the year, include in
column (d) a tentative distribution of such retirements, on an estimated basis, with appropriate contra entry to the account
for accumulated depreciation provision. Include also in column (d) reversals of tentative distributions of prior year of un-
classified retirements. Attach supplemental statement showing the account distributions of these tentative classifications in
columns (c) and (d), including the reversals of the prior years tentative account distributions of these amounts, Careful ob-
servance of the above Instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount
of respondent's plant actually in service at end of year,
Line
No.
Account
(a)
1. INTANGIBLE PLANT
(301) Organization...",..",....................,..............."......,...,.."....,....................,...,'"
(302) Franchises and Consents..,....."...,.....................,..,.........................'...,.........
(303) Miscellaneous Intangible Plant...............................,..............,..........,'.,.........
TOTAL Intangible Plant (Enter Total of lines 2 , and 4)...................................,
....
2. PRODUCTION PLANT
A, Steam Production Plant
(310) land and land Rights,..............,.,..............................,........................,.........
(311) Structures and Improvements,......",..,..............,...............,.......'.,.............'.',
(312) Boiler Plant Equipment...",..""..........................",.............,...",.."..".........,.
(313) Engines and Engine Driven Generators,............---..............................,.........,
(314) Turbogenerator Units",...,.."....".,..,.,.......",..,..........,....,.....,.,.,...,.........',......
(315) Accessory Electric Equipment",............,."...,...,..."..............".......,..".........,
(316) Misc. Power Plant Equipment.................,..........................---........................
(317) Asset Retirement Costs for Steam Production.................. ..".. ......."........
TOTAL Steam Production Plant (Enter Total of lines 8 thru 15).....................,........
B. Nuclear Production Plant
(320) land and land Rights.....,.......................,....................,....,....................,......
(321) Structures and Improvements......................,.............",...,..................,....,....
(322) Reactor Plant Equipment.......,.,.,.............,...,.,.....,..........,.................'"........
(323) Turbogenerator Units..,.,.,.".".,........................,..."...,...........,..........,...........'
(324) Accessory Electric Equipment..,."..............,.........."...............,...........,....,....,
(325) Misc, Power Plant EquipmenL,....,.......................................,...........,..........
(326) Asset Retirement Costs for Nuclear Production......,...................... ..--........
TOTAL Nuclear Production Plant (Enter Total of lines 17 thru 24).........,................
C, Hydraulic Production Plant
(330) land and land Rights................,......,................,......,...................................
(331) Structures and Improvements,..,.....,..,...............,.......,...,........,..,.........,.."..
(332) Reservoirs, Dams, and Waterways..........,............,.............,.........................,
(333) Water Wheels, Turbines, and Generators.....,.........,.....,................................
(334) Accessory Electric Equipment......,.,........,.,.,................................'..,...........'
(335) Misc. Power Plant EquipmenL...............,............,.......................................
(336) Roads, Railroads, and Bridges...............................................................,......
(337) Asset Retirement Costs for Hydraulic Production......,....,...........................
TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34),..........,............
D. Other Production Plant
(340) land and land Rights..,................,...............................................---..........,..
(341) Structures and Improvements..."................,........,............,......,..,...........,.....
(342) Fuel Holders, Products and Accessories,......,..,..................................,..........
(343) Prime Movers""",.,...."",..".",........",.."......,",..........,.""....".............,,""'"
(344) Generators....",."".".........".."".,.......".".,....'.,.'",...'"""".........,........"",...,
(345) Accessory Electric Equipment...,........".......,....,.....,.",.........,......,.....',........,
(346) Misc Power Plant EquipmenL.....,..............,.........,.............,.........,..............
Page 7
,~.,'~~"~~.~..~.,...
Balance at
Beginning of year
(b)
258
375 034
381 345
761,637
558,441
756 558 877
594 274 308
Additions
(c)
Idaho Power Company
ST ATE OF IDAHO - ALLOCATED
An Original December 31, 2005
102 103 and 106)
Show in column (I) reclassifications or transfers within utility plant accounts. Include also in column
(I) the additions or reductions of primary account classifications arising from distribution of amounts
initially recorded in Account 102- In showing the clearance of Account 102, include in column (e) the
amounts with respect to accumulated provision for depreciation, acquisition adjustments, etc., and show
in column (I) only the offset to the debits or credits distributed in column (I) to primary account classifications.
For Account 399, state the nature and use of plant included in this account and if substantial in amount
submit a supplementary statement showing subaccount classification of such plant conforming to the
requirements of these pages,
For each amount comprising the reported balance and changes in Account 102, state the property purchased
or sold, name of vendor or purchaser, and date of transaction. If proposed journal entries have been filed
with the Commission as required by the Uniform System of Accounts, give also date of such filing.
Balance at Line
Retirements Adjustments Transfers End of Year
(d)(e)(I)
(g)
No.
62,945 (301)
894,190 (302)
383 713 (303)
340 848
(310)
(311)
(312)
(313)
(314)
(315)
(316)
430 383 (317)
779,416 892
(320)
(321)
(322)
(323)
(324)
(325)
(326)
(330)
(331)
(332)
(333)
(334)
(335)
(336)
(337)
596 589 744
(340)
(341)
(342)
(343)
(344)
(345)
(345)
Page 8
,- ---- -----. ----.-
Idaho Power Company
STATE OF IDAHO - ALLOCATED
An Original December 31, 2005
Line
ELECTRIC PLANT IN SERVICE (Accounts 101 , 102, 103 and 106) (Continued)
No,
Account
(a)
(346) Misc. Power Plant EquipmenL........,...................,........................................
TOTAL Other Production Plant (Enter Total of lines 37 thru 44)...........................
TOTAL Production Plant (Enter Total of lines 16 , and 45).........................
3. TRANSMISSION PLANT
(350) Land and Land Rights............,..,.....,..............................................................
(352) Structures and Improvements.............................,........,..,.........",...........,......
(353) Station Equipment............,......................................................,................,...
(354) Towers and Fixtures.........,........"............,..........."...,...,...,............................
(355) Poles and Fixtures.............................................................,...........................
(356) Overhead Conductors and Devices..........................................................,......
(357) Underground Conduit......................"...............................,...........",..............
(358) Underground Conductors and Devices............................................,..,............
(359) Roads and Trails,....".,........,.,...........".,.........."........,.,.........."",.......,.."......,
(359.1) Asset Retirement Costs for Transmission Plant..........,.........,.................
TOTAL Transmission Plant (Enter Total of lines 48 thru 57)................,................
4. DISTRIBUTION PLANT
(360) Land and Land Rights..............................,................,..,.................................
(361) Structures and Improvements.............................................,.....,.................,..
(362) Station Equipment..........,.......",.".....................................................,.,........
(363) Storage Battery Equipment..........,............,.,...........,.....,...,.,.......,............."..
(364) Poles, Towers, and Fixtures........,....,.......................................,.....................
(365) Overhead Conductors and Devices..............................,..................,...............
(366) Underground Conduit....................,..........,.......,............,.............,..........,.,....
(367) Underground Conductors and Devices.................,.......................,.........,........
(368) Line Transformers.."".,................,........,.".....,.,........,......""",....,...,.......,."...
(369) Services..""...".......".",.."..."...,.,........
............,......."",.,.....,.".....",,""""'"
(370) Meters....,..,..."......",...........".........................,........".,.,..,..."..,..."."........"..,
(371) Installations on Customer Premises.....................................,.......................,..
(372) Leased Property on Customer Premises.........................................................
(373) Street Lighting and Signal Systems.................................,....................,..,......
(374) Asset Retirement Costs for Distribution Plant.....................,...................
TOTAL Distribution Plant (Enter Total of lines 60 thru 74)...,............,....,..............
5, GENERAL PLANT
(389) Land and Land Rights......,..................,.............,............................,...............
(390) Structures and Improvements.....,...""....",."......,.."...,......,.."".,""""""""'"
(391) Office Fumiture and EquipmenL.............,..................................................,..
(392) Transportation Equipment.,...........".............,........",......,........'.',.......'...,......
(393) Stores Equipment..."...........,...........",....,.....",.......',......'..',..,......,..........',...
(394) Tools, Shop, and Garage EquipmenL..,........................,.........,........,.........,..
(395) Laboratory Equipment"....."....................,.,.,."....,.",....,..,...,.....,.....",...,,"'."
(396) Power Operated Equipment"..,........"............,.......".....,..,.".......'",........,."..
(397) Communication Equipment",...........,............,........"......"",.,."..,...,.,.'..',.,.".
(398) Miscellaneous Equipment....""".,..,..""..,.....",..,.....,.......,..,.......,.",.......,.....
SUBTOTAL (Enter Total of lines 77 thru 86)..........,..............................,.............,
(399) Other Tangible Property..,.....,........"..,..,.......................,....,.....,........,............
(399,1) Asset Retirement Costs for General Plant......................................,..
TOTAL General Plant (Enter Total of lines 87 88 and 89),.....,......,......,........,.....
TOTAL (Accounts 101 and 106)...........,...............,........,....................,.........
(102) Electric Plant Purchased
,......,......,.............................................,.........."......
(Less) (102) Electric Plant Sold...............,...........................,..,................................
(103) Experimental Plant Unclassified.........,....",..,.,....."........,.",........,.....".,.,......,
TOTAL Electric Plant in Service......,........,..,..,........,.....................................,.....
Page 9
- -, ,--, -- ----
Balance at
Beginning of year
(b)
549 572
400 382 756
967,406
513 448
192,783 834
195 492
353 999
540 014
258 820
471 613 012
236 450
558 946
121 883 650
169 651 555
163 932
597 249
145 041 107
247 888 244
848 501
244 916
221 384
761 277
926 097 210
893 724
505 835
946 665
408 870
928 294
533 350
509 357
830 803
062,804
161 775
196 781,476
196 781,476
065 636 092
065 636 092
Additions
(c)
Idaho Power Company
ST ATE OF IDAHO - ALLOCATED
An Original December 31 , 2005
ELECTRIC PLANT IN SERVICE (Accounts 101 , 102, 103 and 106) (Continued)
Balance at Line
Retirements Adjustments Transfers End of Year
(d)(e)(f)
(g)
No.
(346)
694 684
1,475 701 320
047,463 (350)
117 792 (352)
199 533 892 (353)
625 521 (354)
76,407 981 (355)
515 357 (356)
(357)
(358)
259 238 (359)
(359.
489 507 245
719 974 (360)
660 144 (361)
129 980 459 (362)
(363)
174 103 722 (364)
295 291 (365)
992 386 (366)
151 082 701 (367)
266 919 861 (368)
946 816 (369)
247 223 (370)
291 375 (371)
(372)
798 654 (373)
(374)
978 038 606
937,421 (389)
620 933 (390)
779 692 (391)
849 209 (392)
898 339 (393)
842 719 (394)
543 043 (395)
700 450 (396)
069 684 (397)
419 657 (398)
200 661 147
(399)
(399.
200 661 147
208 249 165
(102)
(102)
(371)
208 249 165
Page 10
.- ...- -..--. -..-..-
Idaho Power Company
STATE OF IDAHO - ALLOCATED
An Original December 31, 2005
ELECTRIC OPERATING REVENUES (Account 400)
1, Report below operating revenues for each prescribed account, and manufactured gas revenues in total.
2. Report number of customers, columns (f) and (g), on the basis of meters, in addition to the number of flat rate
accounts; except that where separate meter readings are added for billing purposes, one customer should be counted
for each group of meters added. The average number of customers means the average of twelve figures at the close
of each month.
3, If previous year (columns (c), (e) and (g). are not derived from previously reported figures, explain any
inconsistencies in a footnote.
OPERATING REVENUES
Amount for Amount for
No,Current Year Previous Year
(a)(b)(c)
Sales of Electricity
(440) Residential Sales.....""...........,......,...,...,.",........",..,..........,289 325 450 264,432 685
(442) Commercial and Industrial Sales
Small (or Commercial)(See Instr. 4) (1),..,.........,..............,.........237 308,467 237 670 029
Large (or Industrial)(See Instr. 4) (2).......,................,..,...............107 515 732 103 211 741
(444) Public Street and Highway Lighting.........................,............312,403 194 234
(445) Other Sales to Public Authorities.....,............,............,.........
(446) Sales to Railroads and Railways..............---.........................
(448) Interdepartmental Sales......,.,......,..."".,.....",..............".....
TOTAL Sales to Ultimate Consumers.........................,.............636,462,052 607 508 689
(447) Sales for Resale - Opportunity,...Non-Firm Only....,............130 947 067 110 451 320
TOTAL Sales of Electricity....................................................,...767,409 119 717 960 009
(449.1) Provision for Rate Refunds................................,............,400 102 114 364
TOTAL Revenue Net of Provision for Refunds.................,.......767 809 221 719 074 373
Other Operating Revenues
(450) Forfeited Discounts....."".............,..",......,..,....,.......,'.',.......
(451) Miscellaneous Service Revenues.........................................5,415 794 177 891
(453) Sales of Water and Water Power.....,........................,..........
(454) Rent from Electric Property...............................,..,............,..930 432 096 192
(455) Interdepartmental Rents"......,.".....",....,."..,......"",.........,.'
(456) Other Electric Revenues......................................................758 967 430 881
TOTAL Other Operating Revenues...........................,..............105 192 704 963
TOTAL Electric Operating Revenues.................................,......802 914 413 756 779 337
(1) Commercial and Industrial sales - Small - under 1 000 KW and includes all irrigation customers,
(2) Commercial and Industrial sales - Large - 1 000 KW and over.
Page 11
.- -..- _00__'
-..-.-
Idaho Power Company
STATE OF IDAHO - ALLOCATED
An Original
ELECTRIC OPERATING REVENUES (Account 400) (Continued)
4. Commercial and Industrial Sales, Account 442, may be classified according to the basis of classification
(Small or Commercial, and Large or Industrial) regularly used by the respondent if such basis of classification
is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of Accounts. Explain
5. See page 108, Important Changes During Year, for important new territory added and important rate increases or
decreases.
6. For lines 2, 4, 5, and 6, see page 304 for amounts relating to unbilled revenue by accounts.
7. Include unmetered sales. Provide details of such sales in a footnote.
KILOWATT HOURS SOLD
December 31 , 2005
AVERAGE NUMBER OF CUSTOMERS PER MONTH
Amount for
Current Year
Amount for
Previous Year
Amount for
Current Year
Number for
Previous Year
(d)(e)(f)
569 022 693 389 994 071 360,484
880 517,406
135 239 312
802 162
092 937 686
064 574 997
037 680
642
121
619
612 581 573 ..
611 581 658
224 163 231
574 544,434
717,422 630
291 967 064
430 866
N/A
430 866
* Includes $ 4 256 023 unbilled revenues.
.. Includes 45 901 297 KWH relating to un billed revenues.
Lines 11 through 21 are on an "allocated" basis.
Page 11a
IDAHO SUPPLEMENT
(g)
347 384
638
112
480
415 614
N/A
415 614
Line
No.
Idaho Power Company
STATE OF IDAHO - ALLOCATED
An Original December 31 2005
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnotes.
Ine Amount TOr Amount Tor
No,Account Current Year Previous Year
(a)(b)(c)
~n....'"-" ,....,IIUI'II....". ....."
"'........
A, :steam t-'ower (,jeneratlon
Operation
(500) Operation Supervision and Engineering"........,.,.......,.."...."..,........",.......,.',.........,...,..206 279 121,417
(501) FueL.........."........",."...."......",........."".............,................,...........,.....................""....93,196 241 660 616
(502) Steam Expenses""....""",.....................................,,......,.."...........,........."""""""""'"6,492,450 029 304
(503) Steam from Other Sources.......,.".....................,..",.,........"....."""""""",""""""""'"
(Less) (504) Steam Transferred-Cr.,.."............,...........................",........".........,........"..."....
(505) Electric Expenses.................,................................................,......,......,......,..,.,...........,516 621 1,470 502
(506) Miscellaneous Steam Power Expenses...,.........,....",..........,..........,...........".....,.....,....6,415,549 543 638
(507) Rents,..,.."....,.............,.......,..........................
......"...................,..................................
307 012 671 368
(509) Allowances..",.........,.....,......,......",.......,.........................................",........."......,..,..,.,.
TOTAL Operation (Enter Total of lines 4 thru 12).........................................,............,.....IU"
, """
, 10'"1Ub,496 845
Maintenance
(510) Maintenance Supervision and Engineering....,.....................,............."........",.........,....011 225 701 548
(511) Maintenance of Structures..............,........---...............................................................,..398 053 338 935
(512) Maintenance of Boiler Planl...,...............................,........................,........,......,............,928 572 943 969
(513) Maintenance of Electric Planl...,.......,..............,....................,............,.......................,...283 963 886 517
(514) Maintenance of Miscellaneous Steam PlanL.........................,.....................................171 554 905 848
TOTAL Maintenance (Enter Total of Lines 15 thru 19).........................,..........,............,..~;j,l9;j 36 it.it.01
TOTAL Power Production Expenses-Steam Power (Enter Total of lines 13 and 20)......1;j~9~f b~1
B. Nuclear Power Generation
Operation
(517) Operation Supervision and Engineering..........."......,.,.......".....................",......,.........'
(518) FueL.................""......".....,..............,........,..,.......,......,.,........."........,...........................
(519) Coolants and Water."...,...,.,.................,..,.........,..............,.....,.............,..........."..,.,.....
(520) Steam Expenses...,.".....,..,......,................,....."."","""""""""""""""""""""""'"....,
(521) Steam from Other Sources..,......................,..,...............",.....,..,......,...,........,............".
(Less) (522) Steam Transferred-Cr...............,............,........,..,.................,..........."........,.......
(523)Electric Expenses,...,.".........,.........................,..............,..................,...........".,.......,....
(524) Miscellaneous Nuclear Power Expenses.......,..,..",.......",.,......,.,........",........".........."
(525)Rents.",..,.",....,...,.,."..,...,..............,...,.....,.""......".........,........",.........,......,",........,..,.
TOTAL Operation (Enter Total of lines 24 thru 32)....................,....,...............................
Maintenance
(528) Maintenance Supervision and Engineering....,...............,.............,.............................,..
(529) Maintenance of Structures...,..........".."..,..,.."....,.........",...,"""""""""""""""""""'"
(530) Maintenance of Reactor Plant Equipmenl.....................................................................
(531) Maintenance of Electric Planl.........................................".......................,......,.............,
(532) Maintenance of Miscellaneous Nuclear PlanL.......................,..........,........,................,
TOTAL Maintenance (Enter Total of lines 35 thru 39).....................................................
TOTAL Power Production Expenses-Nuclear Power (Enter Total of lines 33 and 40)....
Hydraulic Power Generation
Operation
(535) Operation Supervision and Engineering..........,..,....................,...,.......,..........,........."...301 903 176 063
(536) Water for Power",.,.....,..................,......".........,.,......",....."...........,......",.......,.......,.,',.028 245 794 616
(537)Hydraulic Expenses..",..,....,.,.........,....,....,..,....."..,..".,..."....,.".,...,......"....,..".."...,""707 802 6,416 142
(538) Electric Expenses"",.....,....,..,.,............."".."............",....".,..........,...........,....,...,.,....,.193 152 175 791
(539) Miscellaneous Hydraulic Power Generation Expenses.....................,........,..................1 ,788 748 388 132
(540) Rents....,......".",...."",.,...,.......,."...,.",.......,.""...."...",.""..".""",...,.".....,',...'....'",....339 221 358 887
TOTAL Operation (Enter Total of lines 44 thru 49)......................................................,..359 072 309;631
Page 12
Idaho Power Company
STATE OF IDAHO - ALLOCATED
An Original
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
December 31 2005
If the amount for previous year is not derived from previously reported figures, explain in footnotes.
No,
, y rau IC ower enera on
52 Maintenance
53 (541) Maintenance Supervision and Engineering..,..............,.................................................54 (542) Maintenance of Structures.......................,.........................""""""""""""""""""""'"
55 (543) Maintenance of Reservoirs, Dams, and Waterways....,.............,....,................,...........,56 (544) Maintenance of Electric Plant...............................................,........................................
57 (545) Maintenance of Miscellaneous Hydraulic PlanL......................,..........................,........58 TOTAL Maintenance (Enter Total of lines 53 thru 57)...,..,............,...............---.................59 TOTAL Power Production Expenses-Hydraulic Power (Enter Total of lines 50 and 58)...60 D. Other Power Generation
61 Operation
62 (546) Operation Supervision and Engineering....,.............................................................,.....63 (547) FueL.....---,...,........."",.."".,..."......,.......,..",.".,.......,..."...........,......,...,..............,.........,
64 (548) Generation Expenses.........................................",.."...,.."""""""""""""""""""""""65 (549) Miscellaneous Other Power Generation Expenses..........,............................................
66 (550) Rents.."..,....,."..".,..........,.............................,...,...........""."......,.,...........,.,.",.,..'........67 TOTAL Operation (Enter Total of lines 62 thru 66)............................,.........................,....
68 Maintenance
69 (551) Maintenance Supervision and Engineering.......,..,........................................................
70 (552) Maintenance of Structures......,.......,.............................................."..................,.,...,....
71 (553) Maintenance of Generating and Electric Plant.........,....................................................
72 (554) Maintenance of Miscellaneous Other Power Generation Plant...............................,.....73 TOTAL Maintenance (Enter Total of lines 69 thru 72)..............................................,.......74 TOTAL Power Production Expenses-Other Power (Enter Total of lines 67 and 73).........75 E Other Power Supply Expenses
76 (555) Purchased Power.......,............"............"............."."""""""""""""""""""""""""""77 (556) System Control and Load Dispatching....,........,.........,..................,.......,.....,........,........78 (557) Other Expenses..."..................................,.........".,...,.."""""""""""""""""""""""'"79 TOTAL Other Power Supply Expenses (Enter Total of lines 76 thru 78)............,.............80 TOTAL Power Production Expenses (Enter Total of lines 21, 41, 59, 74, and 79)...........81 2, TRANSMISSION EXPENSES
82 Operation
83 (560) Operation Supervision and Engineering...........................................,.......................,....84 (561) Load Dispatching.,..............................,.,.................,...".........."........................,...........
85 (562) Station Expenses...."....",.,...,.,........,.......,........,.,"""""""""""""""""""""""""""."86 (563) Overhead Line Expenses..,.,.",..,......,......,....,...."...."..........."..,..".....,.",.."........,.......,87 (564) Underground Une Expenses."............................"..,.,...,."..........,......,...."",..........,.,.",88 (565) Transmission of Electricity by Others...............,..,............,.............,.........................,..,89 (566) Miscellaneous Transmission Expenses............."..........,......,........."......,.....................
90 (567) Rents"......,.",....,.,..,.."".,............",......."",""""""""""""""""""""""""",..""'.....',,91 TOTAL Operation (Enter Total of lines 83 thru 90)...........................................................
92 Maintenance93 (568) Maintenance Supervision and Engineering................,..................................................94 (569) Maintenance of Structures,.......................,..........,.,..,."......,.."".,....................,............
95 (570) Maintenance of Station EquipmenL....................................,.......,.................,.............
96 (571) Maintenance of Overhead Lines...............................,................,...........,.......................
97 (572) Maintenance of Underground Lines...............................................................,..............98 (573) Maintenance of Miscellaneous Transmission PlanL.....................,......,........,........,....99 TOTAL Maintenance (Enter Total of lines 93 thru 98)..,....................................................100 TOTAL Transmission Expenses (Enter Total of lines 91 and 99).....................................
101 3, DISTRIBUTION EXPENSES
102 Operation
103 (580) Operation Supervision and Engineering.......................................,................................
Page 13
1n41-1n !::IIPPI FMFNT
368 857
937 048
218 019
316 913
363
370 143
590,362
161 183
282 385
698 144
539 804
346 029
432 874
709 826
2,482,481
1 ,423 846
456 328
586 972
860
274 825
603 680
549 772
541 620
976 089
871 631
592 185 368 098
Idaho Power Company
STATE OF IDAHO - ALLOCATED
An Original
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnotes.
No.Account
(a)1U4 3,
'-'" ....",
onllnuoo)
105 (581) Load Dispatching.,.......",.........,.............................,,..............,......."....,......................"
106 (582) Station Expenses.........,....,......,..........,......................................'.'.....,............,..........'"
107 (583) Overhead Une Expenses...............,..............................................................................
108 (584) Underground Line Expenses..............................,...........................""""""""""""""'"
109 (585) Street Lighting and Signal System Expenses...................,...............................,...........
110 (586) Meter Expenses.......,...................,..,..,........"....".......,..........,...................,..."..............
111 (587) Customer Installations Expenses,.................,...............................................................
112 (588) Miscellaneous Distribution Expenses..........,..,....,.........................................................
113 (589) Rents."".",.,.,.,.....".......",...",...................',............'"'......"......,...........,..,,..................114 TOTAL Operation (Enter Total of lines 103 thru 113)..........................,....,......................
115 Maintenance
116 (590) Maintenance Supervision and Engineering..,..,...........,.....,..,..............,.........................
117 (591) Maintenance of Structures....................................,................,........,........,..........,.........
118 (592) Maintenance of Station Equipmen!........................................................,......................
119 (593) Maintenance of Overhead Lines....................................................................................
120 (594) Maintenance of Underground Lines.....,.....................,..............,..,...............................,
121 (595) Maintenance of Line Transformers......................,......,.................................................
122 (596) Maintenance of Street Lighting and Signal Systems........................................,............
123 (597) Maintenance of Meters.,.........................................................................,..,...................
124 (598) Maintenance of Miscellaneous Distribution Plan!...,.................,....................................125 TOTAL Maintenance (Enter Total of lines 116 thru 124)..,.....................,..........................126 TOTAL Distribution Expenses (Enter Total of lines 114 and 125)....................................127 4, CUSTOMER ACCOUNTS EXPENSES
128 Operation
129 (901) Supervision..,..,.,....,."................,....................,.
..,.,.......,.,...."..,...............,."....,,"""""
130 (902) Meter Reading Expenses...............................,...,............,....,.......................,................
131 (903) Customer Records and Collection Expenses........,.......................................................
132 (904) Uncollectible Accounts........................................ .....'",...,................................,...........,
133 (905) Miscellaneous Customer Accounts Expenses.........................................,....,............,..134 TOTAL Customer Accounts Expenses (Enter Total of lines 129 thru 133)..........,...........,135 5. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
136 Operation
137 (907) Supervision....,....."..............".........................".........'"""""...............",..,................,..
138 (908) Customer Assistance Expenses........,...............,..........................................................
139 (909) Informational and Instructional Expenses......,.......,..............,....................,..................
140 (910) Miscellaneous Customer Service and Informational Expenses.......................,.............141 TOTAL Cust. Service and Informational Expenses (Enter Total of lines 137 thru 140)......142 6, SALES EXPENSES
143 Operation
144 (911) Supervision.""................"....................".............,."............."................."........."........
145 (912) Demonstrating and Selling Expenses........................................,.................................,
146 (913) Advertising Expenses,................................"..,.......................................,...........",.....',
147 (916) Miscellaneous Sales Expenses............,.............."".............,............",...,.,...,."............148 TOTAL Sales Expenses (Enter Total of lines 144 thru 147).............................................149 7, ADMINISTRATIVE AND GENERAL EXPENSES
150 Operation
151 (920) Administrative and General Salaries............................................................,...---..........
152 (921) Office Supplies and Expenses........................,........,................,..,..,.......,...................
153 (Less) (922) Administrative Expenses Transferred-Credit.............. ,
,........,..........'..'.............
Page
.- .. '- -..--. _u -..~
Amount ror
Current Year
(b)
385 842 $
887 177
726 164
703 802
114 536
934 241
692 207
300 696
147 491
454 342
167
820
2,468 821
039 765
090 650
292 049
359 616
740 287
215 370
471 754
449 433
922 800
389 879
596
260 462
273 766
354 446
743 988
712 128
031,267
(22 062,446)
December 31, 2005
Amount lOr
Previous Year
(c)
253,438
891 829
194 716
640 328
143 396
935 551
487 909
664,454
140 393
2U,I2U 112
175
752 978
219 142
222 685
235 963
468 812
909 523
166 351
U",I 00:::1::I
"'0 /0//41
408 079
4,489 463
910 379
850 386
776)
306 135
174 632
299
715 731
o:::u I ,11::11
139 149
713 290
(24 555 748)
Idaho Power Company
STATE OF IDAHO - ALLOCATED
An Original December 31, 2005
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnotes,
Account
(a)
No,
on Inu
155 (923) Outside Services Employed,.......................................,....,..................................,.......
156 (924) Property Insurance..,.................",.....,...........,..........,........"",....,....",...................,..,...,
157 (925) Injuries and Damages........,................,........,..,..",.................",..,..,..,..,..,..,........,......",
158 (926) Employee Pensions and Benefits...............,..........,..........,.........,..................................
159 (927) Franchise Requirements........,................,.......",.."..,.............""..",........................'.....
160 (928) Regulatory Commission Expenses.................,............,..,......".........,.......,...................
161 (929) Duplicate Charges-Cr..,....,...............,.."....,...........,........."",.....,......,""""""""""""'"
162 (930.1) General Advertising Expenses........................""..............,....,....,......................,.......
163 (930.2) Miscellaneous General Expenses........,..,....,..,...................,..,..,...................,..,.........
164 (931) Rents..,........"...."....................,..................,....,.............."....,.............. ,
'.......................
165 TOTAL Operation (Enter Total of lines 151 thru 164)............,.....,..,.....................,.......,...
166 Maintenance
167 (935) Maintenance of General Plant,....,.,..,.",.............,.."""""".......,......'",."",...,...,....."""168 TOTAL Admin and General Expenses (Enter Total of lines 165-167)..........,..,....,......169 TOTAL Elec Op and MaintExp (Total of 80, 100, 126, 134, 141 , 148, 168)....,....,.......
296 517 $
662 273
326 569
21,409 065
300
335 147
574 191
979 099
585 966
852 207
075
301 815
112,265
731 007
506
110 224
825 509
331
IDAHO ONLY
NUMBER OF ELECTRIC DEPARTMENT EMPLOYEES
1 , The data on number of employees should be reported for the payroll period ending nearest to October 31
or any payroll period ending 60 days before or after October 31,
2, If the respondent's payroll for the reporting period includes any special construction personnel, include
such employees on line 3, and show the number of such special construction employees in a footnote,
3, The number of employees assignable to the electric department from joint functions of combination utilities
may be determined by estimate, on the basis of employee equivalents. Show the estimated number of equiv-
alent employees attributed to the electric department from joint functions,
Payroll Period Ended (Date)....,....,..,.."........"......",.............,..,....".................,.................',..,December 31 , 2005 December 31 2004
2 Total Regular Full-Time Employees,..,..........",.......""..........,....,..."""",...........,.....,.....""....774 757
3 Total Part-Time and Temporary Employees.........,............,........,..............................,............
4 Total Employees,...""""......"..,..........""......".......",..,..,........,....,..,'.........,.......,......,........,...,803 802
Page 15
.-...- _..~~. _.._..~