2004Annual Report.pdf

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Item 1.
THIS FILING IS
An Initial (Original)
Submission
OR D Resubmission No.
Form 1 Approved
OMB No. 1902-0021
(Expires 6/30/2007)
Form 1-F Approved
OMB No. 1902-0029
(Expires 6/30/2007)
Form 3-0 Approved
OMB No. 1902-0205
(Expires 6/30/2007)
FERC FINANCIAL REPORT
FERG Fq~M 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
Exact Legal Name of Respondent (Company)
Idaho Power Company End of
Year/Period of Report
2004/04
1 FERC FORM No.1/3-Q (REV. 02-04)
Deloitte Deloitte & Touche llP
Suite 1700
101 South Capitol Boulevard
Boise, 1083702-7717
USA
Tel: + 1 208 342 9361
www.deloitte.com
INDEPENDENT AUDITORS' REPORT
Idaho Power Company
Boise, Idaho
We have audited the balance sheet-regulatory basis of Idaho Power Company (the "Company ) as or-
December 31 , 2004, 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 , 2004, 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 financial 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 financial 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 of the 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 , 2004, and the
results of its operations and its cash flows for the year ended December 3 1 , 2004, 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.
b~
LLII
March 8, 2005
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.
III. 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
I Subject To the Provisions of The
Federal Power Act (18 CFR 101), must submit Form 1 as prescribed in 18 CFR Part 141.1. Each Nonmajor electric 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
. 3-0 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 of total 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).
I Nonmajor means having in each of the three '
previous caiendar years, total annual sales of 10,000 megawatt hours or more
111. 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.
I (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
6.ccounts (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
I 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
Com parative Balance Sheet 110'- 113
Statement 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
I 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
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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 J-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
collections 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 (an.
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FERC FORM NO.1 (REV. 12-99)Page ii
GENERAL INSTRUCTIONSI. 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
. I
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.
1111 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 "NA,
" "
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
I 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
I 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 1/3-0 software and send a letter identifying which pages in the form have been
evised. Send the letter to the Office of the Secretary.
I VIII. Do not make references to reports of previous periods/years or to other reports in lieu of required entries, except as specifically authorized.
oX. 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.
Jefinitions for statistical classifications used for completing schedules for transmission system reporting are as follows:
I FNS - Firm Network Transmission Service for Self. "Firm" means service that can not be interrupted for economic reasons and is intended to remain reliable
i :wen 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.
I FNO - Firm
Network Service for Others. "Firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under
~dverse conditions. "Network Service" is Network Transmission Service as described in Order No. 888 and the Open Access Transmission Tariff.
: _
FP - for Long-Term Firm Point-to-Point Transmission Reservations. "Long-Term" means one year or longer and "firm" means that service cannot be
nterrupted 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
! iefined as the earliest date either buyer or seller can unilaterally cancel the contract.
! )IF - 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
~arliest date either buyer or seller can unilaterally get out of the contract.
. 3FP - Short-Term Firm Point-to-Point Transmission Reservations. Use this classification for all firm point-to-point transmission reservations, where the
I duration of each period of reservation is less than one-year.\JF - Non-Firm Transmission Service, where firm means that service cannot be interrupted for economic reasons and is intended to remain reliable even
mder 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.
1.0 - Out-of-Period Adjustments. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an
~xplanation in a footnote for each adjustment.
II)EFINITIONS
Commision Authorization (Comm. Auth.) - The authorization of the Federal Energy Regulatory Commission, or any other Commission. Name the
I ~mmission whose
authorization was obtained and give date of the authorization
I. 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\PaQe iii
EXCERPT S FROM T HE 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"
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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 r "
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 .... "
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FERC FORM NO. 1/3-
REPORT OF MAJOR ELECTRIC UTiliTIES liCENSEES AND OTHER
IDENTIFICATION
01 Exact Legal Name of Respondent
Idaho Power Company
03 Previous Name and Date of Change (if name changed during year)
Idaho Power Com pany
04 Address of Principal Office at End of Period (Street, City, State, Zip Code)
1221 W Idaho Street, P.O. Box 70 Boise, 1083707-0070
05 Name of Contact Person
Darrel Anderson
02 Year/Period of Report
End of 2004/04
/ /
06 Title of Contact Person
Senior VP of Admin Ser & CFO
f 07 Address of Contact Person (Street, City, State, Zip Code)
1221 W Idaho Street, P.O. Box 70 Boise, 10 83707-0070
08 Telephone of Contact Person,/ncluding 09 This Report Is
Area Code (1) 00 An Original
[phone]
(2) D A Resubmission
10 Date of Report
(Mo, Oa, Yr)
04/22/2005
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.
I O~~~~~nderson 03 Signature
-. - ~
02 Title J;:7 Senior VP of Admin Ser & CFO Darrel Anderson 04/22/2005
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.
04 Date Signed
(Mo, Oa, Yr)
I=I=~r I=n~M Nn 1/~_(~I=V 07.0.4\P::l()~ 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 2004/04(2) n A Resubmission 04/22/2005
LIST OF SCHEDULES (Electric Utility)
Enter in column (6) the terms "none,
" "
not applicable," or "NA," 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 Earnings 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-~n 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
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Name of Respondent This
wort
Is:Date of Report . Year/Period of Report
Idaho Power Company (1 ) An Original (Mo, Da. Yr)End of 2004/04(2) 0 A Resubmission 04/22/2005
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
Purchases and Sales of Ancillary Services 398
Monthly Transmission System Peak Load 400
Electric Energy Account 401
Monthly Peaks and Output 401
Steam Electric Generating Plant Statistics (Large Plants)402-403
Hydroelectric Generating Plant Statistics (Large Plants)406-407 None
Pumped Storage Generating Plant Statistics (Large Plants)408-409
Generating Plant Statistics (Small Plants)410-411
Transmission line Statistics 422-423
Transmission Lines Added During 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
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Name of Respondent
Idaho Power Company
This Report Is:
(1) 00 An Original(2) D A Resubmission
Date of Report
(Mo, Oa, Yr)
04/22/2005
Year/Period of Report
End of 2004/04
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
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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
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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 class~s or utility and other services furnished by respondent during the year in each State in which
the respondent operated.
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Class of Utility Service
Electric
State
Idaho
Oregon
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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) D Yes... Enter the date when such independent accountant was initially engaged:(2) ~
FERC FORM No.1 (ED. 12-87)PAGE 101
Name of Respondent
Idaho Power Company
This Report Is:
(1) 00 An Original(2) D A Resubmission
Date of Report
(Mo, Oa, Yr)
04/22/2005
Year/Period of Report
End of 2004/04
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 trustwas 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.
DACORP is a public utility Holding Company incorporated effective 10-1998
FERC FORM NO.1 CEO. 12-96)Page 102
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I Name of Respondent This Report Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) ~ An Original (Mo. Da, Yr)End of 2004/04(2) 0 A Resubmission 04/22/2005
CORPORATIONS CONTROLLED BY RESPONDENT
1. Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent
3t any time during the year. If control ceased prior to end of year, give particulars (details) in a footnote.
12. If control wa~ by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, naming'3ny 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.
I Definitions
I. See the Uniform System of Accounts for a definition of control.
~. 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
oting control is equally divided between two holders, or each party holds a veto power over the other. Joint control may exist by
nutual 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.
.ine Name of Company Controlled Kind of Business Percent Voting Footnote
I No
Stock Owned Ref.(a)(b)(c)(d)
Direct Control
Idaho Energy Resources Company Coal mining and mineral 100%
development
: 24
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Name of Respondent This Report Is:Date of Report Year/Period of Report
Idaho Power Company (1) ~ An Original (Mo, Da, Yr)End of 2004/04
(2) D A Resubmission 04/22/2005
OFFICERS
1. 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.
2. 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)
President ar:ld Chief Executive Officer Jan B. Packwood 580,000
President and Chief Operating Officer J. LaMont Keen 350 000
Vice President, General Counsel and Secretary Robert W. Stahman (1)200,000
Sr Vice President, Power Supply James C. Miller 250,000
Sr Vice President, General Counsel and Secretary Thomas Said in (2)53,800
Senior Vice President Administration & CFO Darrel T Anderson 210,000
Vice President, Power Supply John P Prescott (3)101 700
Vice President and.Chief Information Officer A. Bryan Kearny 183,000
Vice President Delivery Dan Minor 170,000
Vice President, Human Resources Luci McDonald 800
Vice President, Regulatory Affairs Ric Gale 140,000
Vice President, Public Affairs Greg Panter 138,000
Vice President, Treasurer Dennis Gribble 139,300
Vice President, Finance and Chief Risk Officer Lori Smith 135,000
(1) Resigned January 2005
(2) Took office October 2004
(3) Resigned July 2004
~. . .
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Com pany (1 ) An Original (Mo, Da, Yr)End of 2004/04(2) nA Resubmission 04/22/2005
DIRECTORS
1. 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.
2. Designate members of the Executive Committee by a triple asterisk and the Chairman of the Executive Committee by a double asterisk.
Lme ~ameTan9 Title) ot Director Principal Business AddressNo.(a)(b)
Ratchford 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, Chairman of the Board***O. Box 1557, Boise, Idaho 83701
Peter S. O'Neill Neill Enterprises, Inc.
871 E. Park center Blvd., Boise, Idaho 83706
Jan B. Packwood President and CEO **Idaho Power Company, 1221 W. Idaho Street,
O. Box 70, Boise, Idaho 83707-0070
J. LaMont Keen President and Chief Operating Officer Idaho power Company, 1221 W. Idaho Street,
O. Box 70. Boise, Idaho 83707-0070
Robert A. Tinstman ***4433 W. Quail Point Court, Boise, Idaho, 83703
Christopher L. Culp (1)1400 North Lake Shore Drive,#8B, Chicago, IL 60610
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 (2)2309 S.W. Avenue. No. 1141, Portland, OR 97201
(1) Resigned January 2005.
(2) Took Office December 2004
FERC FORM NO.1 fED. 12-95)Page 105
Name of Respondent
Idaho Power Company
Date of Report Year/Period of Report
End of 2004/Q4
This Report Is:(1) An Original
(2) 0 A Resubmission 04/22/2005
IMPORTANT CHANGES DURING THE OUARTERIYEAR
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.
,.-.u
, .
r '
PAGE 108 INTENTIONALLY LEFT BLANK
SEE PAGE 109 FOR REQUIRED INFORMATION.
l.. ,
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 04/22/2005 2004/04
IMPORTANT CHANGES DURING THE OUARTERIYEAR (Continued)
1. Relicensing costs closed to account 302 $1,253,778
2. Three new distribution substations in service March 2004, Midrose, Star & Valli vue.
3. New transmission line connects Caldwell, Garnet & Locust Substation - 20.1 miles.
4. None
5. None
6. Issued $55 million of 5.50% First Mortgage Bonds maturing 08-16-34, Issued 08-16-
under OPUC Order UF4196, Wyoming Docket 2005-ES-03-24 and IPUC case #IPC-E-03-3.
Issued $50 million of 5.875% First Mortgage Bonds maturing 03-15-34, Issued 03-26-04
under OPUC Order UF4196, Wyoming Docket 200S-ES-03-24 and IPUC case #IPC-E-03-3.
7. None
8. On December 29, 2004 a general wage increase of 3.5%.
9. See pages 123.8 thru 123.
10. None
11. None
12. None
I FERC FORM NO.1 (ED. 12-96)Page 109.
Name of Respondent This Report Is:Date of Report Year/Period of Report
Idaho Power Company (1)(ZI An Original (Mo, Da Yr)
(2)A Resubmlssion 04/22/2005 End of 2004/04
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)200-201 327,451.494 222,666,339
Construction Work in Progress (107)200-201 151 651,719 96,086,154
TOTAL Utility Plant (Enter Total of lines 2 and 3)3.479,103,213 318,752,493
(Less) Accum. Provo for Depr. Amort. Depl. (108, 110, 111, 115)200-201 316 124,554 239,604,536
Net Utility Plant (Enter Total of line 4 less 5)162,978,659 079,147,957
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 (120.4)
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)162,978,659 079,147,957
Utility Plant Adjustments (116)122
Gas Stored Underground - Noncurrent (117)
OTHER PROPERTY AND INVESTMENTS
Nonutility Property (121)828,002 828,832
(Less) Accum. Provo for Depr. and Amort. (122)
Investments in Associated Companies (123)
Investment in Subsidiary Companies (123.224-225 36,544,480 27,417,179
(For Cost of Account 123.1, See Footnote Page 224, line 42)
Noncurrent Portion of Allowances 228-229
Other Investments (124)32,458,340 225
Sinking Funds (125)
Depreciation Fund (126)
Amortization Fund - Federal (127)
Other Special Funds (128)507,094 23,054 733
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)337,916 51,314,969
CURRENT AND ACCRUED ASSETS
Cash and Working Funds (Non-major Only) (130)
Cash (131)359,186 409,251
Special Deposits (132-134)
Working Fund (135)57,457 80,657
Temporary Cash Investments (136)17,236,000 508,000
Notes Receivable (141)11,863,100 12,982,368
Customer Accounts Receivable (142)45,440,589 43,693,876
Other Accounts Receivable (143)201 303 840,397
(Less) Accum. Provo for Uncollectible Acct.-Credit (144)363,426 1,465,615
Notes Receivable from Associated Companies (145)
Accounts Receivable from Assoc. Companies (146),297,952 143,083
Fuel Stock (151)227 6,450,733 228,205
Fuel Stock Expenses Undistributed (152)227
Residuals (Elec) and Extracted Products (153)227
Plant Materials and Operating Supplies (154)227 25,378,777 18,788,326
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
r' ~
f .
, .
Name of Respondent This Report Is:Date of Report Year/Period of Report
Idaho Power Company (1)(ZJ An Original (Mo, Da, Yr)
(2)A Resubm ission 04/22/2005 End of 2004/04
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)Continued)
Line Current Year Prior Year
No.Ref.End of QuarterlY ear End Balance
Title of Account Page No.Balance 12/31
(a)(b)(c)(d)
(Less) Noncurrent Portion of Allowances
Stores Expense Undistributed (163)227 685,830 966,741
Gas Stored Underground - Current (164.
liquefied Natural Gas Stored and Held for Processing (164.164.
Prepayments (165)28,448,966 26,834 791
Advances for Gas (166-167)
Interest and Dividends Receivable (171)52,040 218
Rents Receivable (172)
Accrued Utility Revenues (173)33,832.290 30,868,672
Miscellaneous Current and Accrued Assets (174)
Derivative Instrument Assets (175)87,506
(Less) Long-Term Portion of Derivative Instrument Assets (175)
I 65 Derivative Instrument Assets - Hedges (176)
(Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176
I 67 Total Current and Accrued Assets (lines 34 through 66)175,028,303 148,885,970
I 68 DEFERRED DEBITS
Unamortized Debt Expenses (181)741 547 500,343
I 70 Extraordinary Property Losses (182.230
UnreCovered Plant and Regulatory Study Costs (182.230
Other Regulatory Assets (182.232 438,780,828 434 028,467
Prelim. Survey and Investigation Charges (Electric) (183)91,953 91,953
Preliminary Natural Gas Survey and Investigation Charges 183.
I 75 Other Preliminary Survey and Investigation Charges (183.
Clearing Accounts (184)12,057 143,007
I 77 Temporary Facilities (185)
Miscellaneous Deferred Debits (186)233 83,272.850 98,056,892
Def. Losses from Disposition of Utility PIt. (187)
Research. Devel. and Demonstration Expend. (188)352-353
Unamortized Loss on Reaquired Debt (189)15,193,036 16,386,031
Accumulated Deferred Income Taxes (190)234 72.712,115 337 131
Unrecovered Purchased Gas Costs (191)
Total Deferred Debits (lines 69 through 83)617,804,386 616,257 810
I 85 TOTAL ASSETS (lines 14-16. 32, 67. and 84)053,149,264 895,606,706
FERC FORM NO.1 (REV. 12-03\Paae 111
Name of Respondent This Report is:Date of Report Year/Period of Report
Idaho Power Company (1)An Original (mo, da, yr)
(2)A Rresubmission 04/22/2005 end of 2004/04
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
Line Current Year Prior Year
Ref.End of QuarterlY ear End BalanceNo.Title of Account Page No.Balance 12/31
(a)(b)(c)(d)
PROPRIETARY CAPITAL
Common Stock Issued (201)250-251 97.877,030 97,877 030
Preferred Stock Issued (204)250-251 366,400
Capital Stock Subscribed (202, 205)252
Stock Liability for Conversion (203, 206)252
Premium on Capital Stock (207)252 483.707,554 397,965.246
Other Paid-In Capital (208-211)253 265,534
Installments Received on Capital Stock (212)252
(Less) Discount on Capital Stock (213)254
(Less) Capital Stock Expense (214)254 096.925 686,058
Retained Earnings (215, 215.1, 216)118-119 309,178,039 297,996,861
Unappropriated Undistributed Subsidiary Earnings (216.118-119 30,928,808 22,738,561
(Less) Reaquired Capital Stock (217)250-251
Noncorporate Proprietorship (Non-major only) (218)
Accumulated Other Comprehensive Income (219)122(a)(b)887.774 629,165
Total Proprietary Capital (lines 2 through 15)918,706,732 863,894,409
LONG-TERM DEBT
Bonds (221)256-257 955,460,000 .900,460.000
(Less) Reaquired Bonds (222)256-257
Advances from Associated Companies (223)256-257
Other Long-Term Debt (224)256-257 585,000 32,690,015
Unamortized Premium on Long-Term Debt (225)
(Less) Unamortized Discount on Long-Term Debt-Debit (226)135,446 205,072
Total Long-Term Debt (lines 18 through 23)983,909,554 930,944,943
OTHER NONCURRENT LIABILITIES
Obligations Under Capital Leases - Noncurrent (227)
Accumulated Provision for Property Insurance (228.
Accumulated Provision for Injuries and Damages (228.1 ,797,494 831,488
Accumulated Provision for Pensions and Benefits (228.10,592,032 929,788
Accumulated Miscellaneous Operating Provisions (228.4)12,015.187
Accumulated Provision for Rate Refunds (229)400,102 514,466
Long-Term Portion of Derivative Instrument Liabilities
Long-Term Portion of Derivative Instrument Liabilities - Hedges
Asset Retirement Obligations (230)287,789 139,812
Total Other Noncurrent Liabilities (lines 26 through 34)22,077,417 25,430,741
CURRENT AND ACCRUED LIABILITIES
Notes Payable (231)
Accounts Payable (232)72.530,597 717,259
Notes Payable to Associated Companies (233)20,469.707 021,024
Accounts Payable to Associated Companies (234)278,488 75,401
Customer Deposits (235)000,351 295,924
Taxes Accrued (236)262-263 40,280,158 52,867,442
Interest Accrued (237)13.742,553 12,892,588
Dividends Declared (238)
Matured Long-Term Debt (239)
r::s::~~ r::n~M NO 1 Irt:t.v 1 ?-n~\P;lne 112
f..
. r
Name of Respondent This Report is:Date of Report Year/Period of Report
Idaho Power Company (1)An Original (mo, da, yr)
(2)A Rresubmlssion 04/22/2005 end of 2004/04
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDIT~ntinued)
Line
Current Year Prior Year
No.
Ref.Eridof OuarterlYear End Balance
Title of Account Page No.Balance 12/31
(a)(b)(c)(d)
Matured Interest (240)
Tax Collections Payable (241)111,305 812,200
Miscellaneous Current and Accrued Liabilities (242)17,015,195 19,598,441
Obligations Under Capital Leases-Current (243)
Derivative Instrument Liabilities (244)445 89,923
(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)167,428,799 141,370,202
DEFERRED CREDITS
Customer Advances for Construction (252)15,073,749 11,658.799
Accumulated Deferred Investment Tax Credits (255)266-267 66.836,156 67,788.977
Deferred Gains from Disposition of Utility Plant (256)
Other Deferred Credits (253)269 56.257,710 55,025,978
Other Regulatory Liabilities (254)278 209.105,349 190,734,675
I 61 Unamortized Gain on Reaquired Debt (257)
62.Accum. Deferred Income Taxes-Accel. Amort.(281)272-277
I 63 Accum. Deferred Income Taxes-Other Property (282)585,543,346 569,434 622
Accum. Deferred Income Taxes-Other (283)28,210,452 39.323,361
Total Deferred Credits (lines 56 through 64)961,026,762 933,966,412
TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16.24,35,54 and 65)053,149,264 895,606.707
.-.-.- .- .
FERC FORM NO- 1 (rev. 12-03\Paae 113
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1 ) An Original (Mo. Da, Yr)End of 2004/04(2) DA Resubmission 04/22/2005
STATEMENT OF INCOME
1 . Enter in column (e) operations for the reporting quarter and in column (f) the operations for the same three month period for the prior
year.
2. Report in Column (g) year to date amounts for electric utility function; in column (i) the year to date amounts for gas utility, and in (k)
the year to date amounts for the other utility function for the current quarter/year.
3. Report in Column (h) year to date amounts for electric utility function; in column U) the year to date amounts for gas utility, and in (I)
the year to date amounts for the other utility function for the previous quarter/year.
4. If additional columns are needed place them in a footnote.
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.QuarterlY ear QuarterlY ear No 4th Quarter No 4th Quarter
(a)(b)(c)(d)(e)
UTILITY OPERATING INCOME
Operating Revenues (400)300-301 800,822,106 780,381,662 176,034,120 235,768,467
Operating Expenses
Operation Expenses (401)320-323 523,328,322 477,670,013 119,897,939 175 660,145
Maintenance Expenses (402)320-323 58,404 718 62,798,431 12,945,287 335,983
Depreciation Expense (403)336-337 90,986,890 87,913,155 23,201,849 741 884
Depreciation Expense for Asset Retirement Costs (403.336-337
...
Amort. & Depl. of Utility Plant (404405)336-337 10,050,731 846,878 199,122 614 692
Amort. of Utility Plant Acq. Adj. (406)336-337 22,723 723 681 681
Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407)
Amort. of Conversion Expenses (407)
Regulatory Debits (407.19,944 986 986
(Less) Regulatory Credits (407.18,949,682 14,418,138 4,451,768
Taxes Other Than Income Taxes (408.262-263 19,090,214 20,752,763 553,897 593,285
Income Taxes - Federal (409.262-263 16,305,814 40,987,586 860,503 11,143,156
- Other (409.262-263 273,792 251 532 785,371 181 777
Provision for Deferred Income Taxes (410.234, 272-277 28,170,120 049,257 15,887,587 903,465
(Less) Provision for Deferred Income Taxes-Cr. (411.234~ 272-277 45,142,816 62,485,541 7,403,600 10,162;516
Investment Tax Credit Adj. - Net (411.4)266 952,821 229,367 492,368 153,483
(Less) Gains from Disp. of Utility Plant (411.249
Losses from Disp. of Utility Plant (411.071 20,012 310
(Less) Gains from Disposition of AI~owances (411.158,330 106,845 127,763
Losses from Disposition of Allowances (411.
Accretion Expense (411.10)
TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24)688,402,102 685,903,885 152,295,748 199,997,409
Net Util Oper Inc (Enter Tot line 2 less 25) Carry to Pg117 Iine 27 112,420,004 94,477,777 23,738,372 35,771 058
~ ."'-
l. ,
cccr cnDU t.ln 1":Ln 'D~V n?n.&\P::.nA 11.&
Name of Respondent
Idaho Power Company
ELECTRIC UTILITY
Current Year to Date Previous Year to Date(in pollars) (in dollars)
(g)
(h)
523,328,322
58,404 718
90,986,890
477 670,013
62,798,431
87,913,155
10,050,731
22,723
846 878
22,723
19,944
18,949,682
19,090,214
16,305,814
273,792
28,170,120
45,142,816
952,821
20,752 763
40,987 586
251,532
41,049 257
62,485,541
229,367
071
158,330
20,012
106,845
688,402,102
112,420,004
685,903,885
94,477 777
eCDr enDI"I...n "I tcn "I'LOII:\
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) A Resubmission 04/22/2005
STATEMENT OF INCOME FOR THE YEAR (Continued)
Year/Period of Report
End of 2004/04
GAS UTI LlTY
Current Year to Date Previous Year to Date(in dollars) (in dollars)(i) OTHER UTILITY
Current Year to Date Previous Year to Date(in dollars) (in dollars)(k) (I)
Line
No.
P".nA "I "II:
y.,
This Page Intentionally Left Blank
I..
\.. .
, Name of Respondent This
wort
Is:Date of Report Y ear/Pe~od of Report(1 ) An Original (Mo, Da. Yr)End of 2004/04j Idaho Power Company (2) DA Resubmission 04/22/2005
STATEMENT OF INCOME FOR THE YEAR (continued)
Line TOTAL Current 3 Months Prior 3 Months
No.Ended Ended
(Ref.Quarterly Only Quarterly Only
Title of Account Page No.Current Year Previous Year No 4th Quarter No 4th Quarter
(a)(b)(c)(d)(e)
Net Utility Operating Income (Carried forward from page 114)112,420,004 94,477,777 23,738,372 35,771,058
Other Income and Deductions
Other Income
Nonutilty Operating Income
Revenues From Merchandising, Jobbing and Contract Work (415)3,427,754 337 845 966,866 968,046
(Less) Costs and Exp. of Merchandising, Job. & Contract Work (416)388,329 153,982 020,637 760,580
Revenues From Nonutility Operations (417)110,035 739 32,473
(Less) Expenses of Nonutility Operations (417.279,748 471,049 130,157 -63,502
Nonoperating Rental Income (418)136 201 -448
Equity in Earnings of Subsidiary Companies (418.119 190,247 10,047,927 896,387 617,211
Interest and Dividend Income (419)2,412,553 3,406,756 644 914 696,560
Allowance for Other Funds Used During Construction (419.904 027 384,923 965,556 912,162
Miscellaneous Nonoperating Income (421)624 756 500,487 709,058 978,345
Gain on Disposition of Property (421.469 258 11,433 58,702 218,996
TOTAL Other Income (Enter Total of lines 31 thru 40)20,468,417 19,064,541 121 338 726,267
Other Income Deductions
Loss on Disposition of Property (421.207 115 092
Miscellaneous Amortization (425)340
Donations (426.340 538 360 616,439 182 972 143,214
Life Insurance (426.671,031 247 517 104,539 13,419
Penalties (426.
Exp. for Certain Civic, Political & Related Activities (426.4)550,041 461 80'9 277 365 150,174
Other Deductions (426.13,923,708 680,702 542,772 200,000
TOTAL Other Income Deductions (Total of lines 43 thru 49)14,348,285 511,433 898,685 1,487,061
Taxes Applic. to Other Income and Deductions
Taxes Other Than Income Taxes (408.262-263 38,712 049 15,669 695
Income Taxes-Federal (409.262-263 144,957 13,728,193 514,146 95,233
Income Taxes-Other (409.262-263 43,666 663,709 104 968 24,474
Provision for Deferred Inc. Taxes (410.234, 272-277 586,407 129,204 452,395 382 669
(Less) Provision for Deferred Income Taxes-Cr. (411.234, 272-277 5,482,592 29,991,831 218,938 480,332
Investment Tax Credit Adj. -Net (411.
(Less) Investment Tax Credits (420)
TOTAL Taxes on Other Income and Deductions (Total of lines 52-58)668,850 6,449,676 868,240 739
Net Other Income and Deductions (Total of lines 41 50, 59)788,982 20,002,784 354,413 209,467
Interest Charges
Interest on Long-Term Debt (427)50,317 585 54,645,483 13,144,737 12,639,648
Amort. of Debt Disc. and Expense (428)188,137 113,620 305,413 300,653
Amortization of Loss on Reaquired Debt (428.192,994 287 891 290,174 290,174
(Less) Amort. of Premium on Debt-Credit (429)
(Less) Amortization of Gain on Reaquired Debt-Credit (429.
Interest on Debt to Assoc. Companies (430)340 256,468 83,628 109,517 837
Other Interest Expense (431)340 598,490 069273 517,553 339,815
(Less) Allowance for Borrowed Funds Used During Construction-Cr. (432)952,809 310,120 834,090 656,660
Net Interest Charges (Total of lines 62 thru 69)51,600,865 55,889,775 13,533,304 985,467
Income Before Extraordinary Items (Total of lines 27, 60 and 70)70,608,121 58,590 786 14,559,481 26,995 058
Extraordinary Items
Extraordinary Income (434)
(Less) Extraordinary Deductions (435)
Net Extraordinary Items (Total of line 73 less line 74)
Income Taxes-Federal and Other (409.262-263
Extraordinary Items After Taxes (line 75 less line 76)
Net Income (Total of line 71 and 77)70,608,121 58,590,786 14,559,481 26,995,058
~~n'" ~n..... o..n 04 ,., n '...r=" 1\., t\A\D......... 44"7
Name of Respondent This (!Jort Is:Date of Report Year/Period of Report
Idaho Power Company (1 ) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/22/2005
STATEMENT OF RETAINED EARNINGS
1. Do not report Lines 49-53 on the quarterly version.
Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriated
undistributed subsidiary earnings for the year.
' 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.
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.
If any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.
Current Previous
QuarterlY ear QuarterlY ear
Contra Primary Year to Date Year to Date
Line Item Account Affected Balance Balance
No.(a)(b)(c)(d)
UNAPPROPRIATED RETAINED EARNINGS (Account 216)
1 Balance-Beginning of Period 296.452,895 316,065,712
Changes
Adjustments to Retained Earnings (Account 439)
Redemption of Preferred Stock 888 289
TOTAL Credits to Retained Earnings (Acct. 439)888,289
- .
TOTAL Debits to Retained Earnings (Acct. 439)
Balance Transferred from Income (Account 433 less Account 418.62.417 874 48,542,859
Appropriations of Retained Earnings (AcGt. 436)
21 .
TOTAL Appropriations of Retained Earnings (Acct. 436)
Dividends Declared-Preferred Stock (Account 437)
4% Preferred (par value $100)238 437 394 510,038)
68% Serial Preferred (par value $100)238 021 815
07% Serial Preferred (par value $100)238 1,475,750 152,000)
767,500)
TOTAL Dividends Declared-Preferred Stock (Acct. 437)934 959 3,429,538)
Dividends Declared-Common Stock (Account 438)
$2.50 Par Value 46,413,448 64.726,138)
TOTAL Dividends Declared-Common Stock (Acct. 438)46,413,448 64,726,138)
Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings
Balance - End of Period (Total 1 ,15,16.22.29.36,37)307.634,073 296,452,895
APPROPRIATED RETAINED EARNINGS (Account 215);rl~.J1..fl.-
. ,\,~!, ,
CCDi' CI'\DU"'I'\ 11"2-1'\ IDC\I n"_nA\D......... ""0
Name of Respondent
, Idaho Power Company
Year/Period of Report
End of 2004/04
This ~ort Is: Date of Report(1) ~An Original (Mo, Da. Yr)(2) A Resubmission 04/22/2005
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.
Is. Explain in 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 reportto stockholders are applicable to this statement, include them on pages 122-123.
. I Line Item
(a)
Current Previous
QuarterlY ear QuarterlY ear
Contra Primary Year to Date Year to Date
Account Affected Balance Balance
(b)(c)(d)
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)
22,738,561
190,247
12,690,634
1D,047 927
. -
30,928,808 22,738,561
..........,.. .............. ........
A'" 1"'\ ""~\' n., nA\D__- A.oft
Name of Respondent This
wort
Is: Date of Report Year/Period of Report
Idaho Power Company (1 ) An Original (Mo, Da, Yr)End of 2004/04
(2) Fi A Resubmission 04/22/2005
STATEMENT OF CASH FLOWS
(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 Description (See Instruction No.1 for Explanation of Codes)Current Year to Date Previous Year to Date
No.QuarterlY ear QuarterlY ear
(a)(b) .(c)
Net Cash Flow from Operating Activities:
Net Income (Line 78(c) on page 117)70,608.121 58.590,786
Noncash Charges (Credits) to Income:
Depreciation and Depletion 90,986,890 107,764,506
Amortization of c:c:
~/ ...:'.' ,
'7'~:..,-c,::2,463,983
Deferred Income Taxes (Net)21.373,450 46,516,708
Investment Tax Credit Adjustment (Net)952,821 229,366
Net (Increase) Decrease in Receivables 049,547 21,640,701
Net (Increase) Decrease in Inventory 587 583 2,418,095
Net (Increase) Decrease in Allowances Inventory
Net Increase (Decrease) in Payables and Accrued Expenses 14,699,394 37,935,220
Net (Increase) Decrease in Other Regulatory Assets 122,666 64,278,170
Net Increase (Decrease) in Other Regulatory Liabilities 334 354 1,441,315
(Less) Allowance for Other Funds Used During Construction 904,027 384,923
(Less) Undistributed Earnings from Subsidiary Companies 127,301 12,309,546
Other (provide details in footnote):
Unbilled Revenues 845,213
Other than temporary decline in market value of investments 408,259
Other Net 12,355,504
Net Cash Provided by (Used in) Operating Activities (Total 2 thru 21)186,342,542 175,472,983
Cash Flows from Investment Activities:
Construction and Acquisition of Plant (including land):
Gross Additions to Utility Plant (less nuclear fuel)187 333,369 144,936,000
Gross Additions to Nuclear Fuel
Gross Additions to Common Utility Plant
Gross Additions to Nonutility Plant
(Less) Allowance for Other Funds Used During Construction 952.809 310,120
Other (provide details in footnote):
Cash Outflows for Plant (Total of lines 26 thru 33)190,286,178 148,246,120
Acquisition of Other Noncurrent Assets (d)
Proceeds from Disposal of Noncurrent Assets (d)831 221 557
Investments in and Advances to Assoc. and Subsidiary Companies
Contributions and Advances from Assoc. and Subsidiary Companies
Disposition of Investments in (and Advances to)
Associated and Subsidiary Companies
Purchase of Investment Securities (a) 295,355,514
Proceeds from Sales of Investment Securities (a)266,331.185
y ,((,\ '
, I
" '~~~" ~"'~.. ".'" ..
,~n .. "I n~\D~"'A .. .,n
Name of Respondent
Idaho Power Company
This ~ort Is: Date of Report(1) ~ An Original (Mo, Da, Yr)(2) 0 A Resubmission 04/22/2005
STATEMENT OF CASH FLOWS
Year/Period of Report
End of 2004/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 tQvesting 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)
46 Loans Made or Purchased
47 Collections on Loans
49 Net (Increase) Decrease in Receivables
50 Net (Increase) Decrease in Inventory
51 Net (Increase) Decrease in Allowances Held for Speculation
52 Net Increase (Decrease) in Payables and Accrued Expenses
53 Other (provide details in footnote):
54 Note reveivable payment to parent
55 Other Net
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):
I 69
: 70 Cash Provided by Outside Sources (Total 61 thru 69)
I 75
I 78 Net Decrease in Short-Term Debt (c)
I 79
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)
88 Cash and Cash Equivalents at Beginning of Period
90 Cash and Cash Equivalents at End of period
39.409
21,827 722
321
219,349,085 126,294 162
105 000,000 189,800,000
39,986,708
Net Increase in Short-Term Debt (c)
Other (provide details in footnote):
11.448,683
202,368,683 229,786 708
Payments for Retirement of:
Long-term Debt (b)
Preferred Stock
Common Stock
Other (provide details in footnote):
50,000,000
52,350,828
209,800,000
859,941
. ".... .... ...
)7'~\1'~;~ ,,490,613
186,800
131 588
823,248
46.413.448
3.429,538
726,138
46,661,278 837 910
13,654,735 659,089
997,908 12,656,997
652,643 997,908
CCClI' cnClLUI t.Jn 1 tcn 1"_Q~\
p".,..... ...,..
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubm ission 04/22/2005 2004/04
FOOTNOTE DATA
Column: b!schedule Page: 120 Line No.: 5
Idaho Power Company
NOTE 1
12 Months Ended
12/31/2004
Amortization of
Plant
Regulatory Assets
Unamoritzed Debt Expense
Unamoritzed Discount
Other
10,028,008
092,539
987 010
394 122
551
564 230
Line No.: 18 Column: b!Schedule Page: 120
NOTE 2
Unbilled Revenues
Impairment of Assets
Other - Net
(2,963,617)
075,434
578 507
15,690 324
12 Months Ended
12/31/2004
Cash Flow from Operating Activities (Other)
~chedule Page: 120
NOTE 3
Line No.: 67 Column: b
12 Months Ended
12/31/2004
Cash Flow from Financing Activities (Other)
Capital Infusion from IDACORP, Inc. (parent)85,920 000
920,000
!Schedule Page: 120
NOTE 4
Line No.: 76 Column: b
12 Months Ended
12/31/2004
Cash Flow from Financing Activities (Other)
Retirement of REA Notes
Other - Net
(1,105 015)
014 866)
119,881)
IFERC FORM NO.1 (ED. 12-Page 450.
Name of Respondent
Idaho Power Company
Date of Report
04/22/2005
Year/Period of Report
End of 2004/Q4
This Report Is:(1) An Original
(2) 0 A Resubmlssion
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 creQits 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 INTENTIONALLY LEFT BLANK
SEE PAGE 123 FOR REQUIRED INFORMATION.
- --
l- .
f~'
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 04/22/2005 2004/04
NOTES TO FINANCIAL STATEMENTS (Continued)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
.-'
Nature of Business
Idaho Power Company is an electric utility engaged in the generation, transmission, distribution, sale and purchase of electric energy. IPC
is regulated by the Federal Energy Regulatory Commission (FERC) and the state regulatory commissions of Idaho and Oregon. IPC is the
parent of Idaho Energy Resources Co., 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-l reporting purposes.
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 accoWlting releases, which is a comprehensive basis of accoWlting other than generally accepted
accoWlting principles.
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.
Management Estimates
:Management makes estimates and assumptions when preparing financial statements in conformity with accoWlting principles generally
accepted in the United States of .America. These estimates and assumptions affect the reported amoWlts 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
, ..
\l1owance for FWlds Used
During Construction (AFDC) and indirect charges for engineering, supervision and similar overhead items. J\.faintenance and repairs
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 2.96 percent in 2004 and 2.99 percent in 2003.
Long-lived assets are periodically reviewed for impairment when events or changes in circumstances indicate that the carrying amoWlt of an
asset may not be recoverable as prescribed under Statement of Financial..-\ccounting Standards (SF AS) 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
AFDC 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. IPC's weighted-average monthly AFDC rates for
2004 and 2003 were 6.9 percent and 8.3 percent, respectively. IPC's reductions to interest expense for AFDC were $3 million for both
2004 and 2003. Other income included $4 million and $3 million for 2004 and 2003, respectively.
Revenues
In order to match revenues with associated expenses, IPC accrues Wlbilled revenues for electric services delivered to customers but not yet
billed at month-end. IPC collects franchise fees and similar taxes rc:tlated to energy consumption. These amounts are recorded as liabilities
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 04/22/2005 2004/04
NOTES TO FINANCIAL STATEMENTS (Continued)
until paid to the taxing authority. None of these collections are reported on the income statement as revenue or expense.
Power Cost Adjustment
IPC has a Power Cost Adjustment (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 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 (lPUC), the regulatory authority having principal jurisdiction, IPC'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
The following table illustrates the effect on net income if the fair value recognition provisions of SFAS 123 had been applied to stock-based
employee compensation:
Net income, as reported
Add: Stock-based employee compensation expense included in
reported net income, net of related tax effects
Deduct: Total stock-based employee compensation expense determined
under fair value based method for all awards ,net of related tax effects
Pro forma net income
2004 2003
(thousands of dollars)
608 591
276 (56)
977 073
907 462
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.
Regulation of Utility 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 economic effects of regulation can result in regulated
companies recording costs that have been, or are expected to be, allowed in the rate-making process in a period different from the period
in which the costs would be charged to expense 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.
Comprehensive Income
Comprehensive income includes net income, unrealized holding gains and losses on marketable securities, IPC'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 IPC's
IFERC FORM NO.1 (ED. 12-88)Page 123.
",,' ",,"",'" ""'-
Name of Respondent
' .,, "
This Reportis:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/22/2005 2004/04
NOTES TO FINANCIAL STATEMENTS (Continued)
accumulated other comprehensive loss balance at December 31:
Unrealized holding gains on securities
tvfinimum ension liability adjustment
Total
2004 2003
(thousands of dollars)538 $ 3 676426) (6 306)
(888) $ (2 630)
Adopted Accounting Pronouncement
In January 2004, IPC adopted Financial ,Accounting Standards Board (FASB) Interpretation (FIN) 46R, "Consolidation of Variable Interest
Entities - an interpretation of ARB No. 51 " which addresses consolidation by business enterprises of VIEs, which have one or more of the
following characteristics:
The equity investment at risk is not sufficient to pennit the entity to finance its activities without additional subordinated financial
support provided by any parties, including the equity holders;
The equity investors lack one or more of the following essential characteristics of a controlling financial interest:
a. The direct or indirect ability to make decisions about the entity s activities through voting rights or similar rights;
The obligation to absorb the expected losses of the entity;
The right to receive the expected residual returns of the entity; and
The equity investors have voting rights that are not proportionate to their economic interests, and the activities of the entity
involve or are conducted on behalf of an investor with a disproportionately small voting interest.
IPC evaluated its investments, contracts and other potential variable interests that would be subject to the provisions of FIN 46R, and
determined that the adoption did not have a material effect on its financial statements.
New Accounting Pronouncements
SFAS 151: In November 2004, the FASB issued SFAS 151
, "
Inventory Costs " which clarifies the accounting for certain inventory-related
costs. SFAS 151 is effective for inventory costs incurred during fiscal years beginning after June 15 2005, and is not expected to have a
material effect on IPC's financial statements.
SF AS 153: In December 2004, the FASB issued SF AS 153
, "
Exchanges of Nonmonetary Assets " which amends existing guidance on
accounting for nonmonetary transactions. SF AS 153 is effective for exchanges occurring in fiscal periods beginning after June 15, 2005
and is not expected to have a material effect on IPC's financial statements.
SFAS 123(R): In December 2004, the FASB issued SEAS 123 (revised 2004), "Share-Based Payments " which revises SFAS 123 and
supersedes APB 25 and its related implementation 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. SEAS 123(R) focuses primarily on accounting for transactions in which an entity obtains employee services in
share-based payment transactions.
Under the provisions of SF AS 123(R), the fair value of all stock options must be reported as an expense on the financial statements. IPC
currendy apply the measurement provisions of APB 25 and the disclosure-only provisions of SF AS 123. SFAS 123(R) also changes other
measurement, timing and disclosure rules relating to share-based payments.
SF AS 123(R) is effective for most public entities as of the beginning of the first interim or annual reporting period beginning after June 15
2005. IPC expects to adopt SF AS 123(R) on July 1, 2005, and adoption is expected to decrease IPC's pre-tax income by approximately $0.
million in 2005. Stock-based compensation arrangements are discussed in Note 9.
FSP FAS 106-2: See Note 10 for a discussion of this FSP, which relates to postretirement benefit obligations.
amortized over the terms of the res ective debt issues.
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 04/22/2005 2004/04
NOTES TO FINANCIAL STATEMENTS (Continued)l "
Reclassifications
Certain items previously reported for years prior to 2004 have been reclassified to conform to the current year s presentation. Net income
and shareholders' equity were not affected by these reclassifications.
2. INCOME TAXES:
A reconciliation between the statutory federal income tax rate and the effective tax rate is as follows:
' ,
2004 2003
(thousands of dollars)
394 703
867)517)
400)343)
295)397)
450)450)
244)101)
237 456
658)658)
(16 457)
. (1 460)208)
100 859
350 237
697 020
947 561
26.
Computed income taxes based on statutory federal income tax rate
Change in taxes resulting from:
Equity earnings of subsidiary companies
AFDC
Investment tax credits
Repair allowance
Removal Cost
Pension Accrual
Capitalized overhead costs
Regulatory Tax Liability
Settlement of prior years tax returns
State income taxes, net of federal benefit
Deprecia tion
Other, Net
Total (benefit) provision for income taxes
Effective tax rate
I; ;
The provision for income taxes consists of the following:2004 2003
(thousands of dollars)
Income taxes currently payable (receivable):
Federal
State
Total
Income tax credits:
Federal
State
Total
Investment tax credits:
Federal
State
Total
451
318
769
716
915
631
(17 318)
551)
869
(36 015)
284)
299
700
653
(953)
627
398
229
\ ,
Total (benefit) provision for income taxs 947 561
The tax effects of significant items comprising the Company s net deferred tax liabilities are:2004 2003
(thousands of dollars)
Deferred tax assets:
Regulatory liability
IFERC FORM NO.1 (ED. 12-
447 024
Page 123.4
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 04/22/2005 2004/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Advances for construction
Deferred compensation
Other
Total
Deferred tax liabilities:
Property, plant and equipment
Regulatory asset
Conservation programs
PCA
Other
Total
357 162
324 385
584 329
712 900
241 324 238 602
344 220 330 833
972 310
516 529
722 047
613 754 614 321
541 042 547 421Net deferred tax laibilities
Regulatory Settlement
In Settlement No., as more fully discussed in Note 12, 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 cost tax method IPC adopted in the 2001
IDACORP federal income tax return. ..-\s a result of Settlement No., a $16 million regulatory tax liability was reversed to income tax
expense in the third quarter of 2004.
American Jobs Creation Act of 2004: In October 2004, the president signed into law the American Jobs Creation Act of 2004 (the Act),
which may have tax implications for IPC One provision of the Act with potential implications for the companies relates to manufacturing
tax incentives for the production of electricity beginning in 2005. Taxpayers will be able to deduct a percentage (three percent in 2005 and
2006, six percent in 2007 through 2009 and nine percent in 2010 and thereafter) of the lesser of their qualified production activities income
or their taxable income. Management is currendy reviewing this and other aspects of the Act to determine the impact on the company.
3. COMMON STOCK:
In December 2004, IDACORP contributed $86 million of additional equity to IPC No additional shares ofIPC common stock were
issued in this transaction.
In December 2003, IPC issued 1 538 461 shares of $2.50 par value common stock to IDACORP for $40 million. Each share of IPe's
common stock is entided to one vote.
Dividend Restrictions
IPe's articles of incorporation contain restrictions on the payme~t 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 direcdy or indirectly loan funds or issue
notes or give credit on its books to IDACORP.
4. PREFERRED STOCK OF IDAHO POWER COMPANY:
The number of shares of IPC preferred stock outstanding at December 31 were as follows:
Shares Outstanding at
December 312004 2003
Preferred stock:
Cwnulative, $100 par value:
4% preferred stock (authorized 215 000 shares)
Serial preferred stock, 7.68% Series (authorized 150 000 shares)
Serial preferred stock, cwnulative, without par value, total of 3 000 000 shares authorized:
07% Series, $100 stated value (authorized 250 000 shares)
I FERC FORM NO.1 (ED. 12-88)
123 664
150 000
250 000
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 04/22/2005 2004/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Total 523 664
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
of7.68% preferred stock and $103.18 per share for the 250 000 shares of7.07% preferred stock, plus accumulated and unpaid dividends.
During 2003 IPC reacquired and retired 10 263 shares of 4% preferred stock.
5. LONG-TERM DEBT:
The following table summarizes long-term debt at December 31:2004 2003
(thousands of dollars)
First mortgage bonds:
Series due 200483 % Series due 200538 % Series due 200720 % Series due 200960 % Series due 201175 % Series due 201225 % Series due 2013
Series due 20325.50 % Series due 20335.50 % Series due 2034875 % Series due 2034
Total first mortgage bonds
Pollution control revenue bonds:
Variable Auction Rate Series 2003 due 2024 (a)05 % Series 1996A due 2026
000
000 000
000 000
( .
000 000
120 000 120 000
100 000 100 000
000 000
100 000 100 000
000 000
000
000
785 000 730 000
800 800
100 100
Variable Rate Series 1996B due 2026 24 200 24 200
Variable Rate Series 1996C due 2026 24 000 24 000Variable Rate Series 2000 due 2027 4 360 4 360
Total pollution control revenue bonds 170 460 170 460REA notes 1 105.American Falls bond guarantee 19 885 19 885
1-Wner Dam note guarantee 11 700 11 700
Unamortized premium! discount - net (3 135) (2 205)Total 983 910 930 868
Current maturities of long-term debt (60 000) (50 000)
Total long-term debt $ 923 910 $ 880 868
(a) Humboldt County Pollution Control Revenue bonds are secured by fl:rst mortgage bonds, bringing the total of fl:rst
mortgage
bonds outstanding at December 31 2004 to $834.8 million.
At December 31 , 2004, the maturities for the aggregate amount oElong-term debt outstanding were (in thousands of dollars):
2005 2006 2007 2008 2009 Thereafter
IPC 000 064 064 064 760 718
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
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 04/22/2005 2004/04
NOTES TO FINANCIAL STATEMENTS (Continued)
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 .A.mbac 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 2004, the auction rate was 1.85 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 J\farch 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 I\lortgage 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 FirstMortgage Bonds 6.40%
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 JYlortgage 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 of IPC's outstanding preferred stock. .At December 31 , 2004, $55 million remained available to beissued on this shelf registration statement.
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.
On August 17 2004, IPC redeemed all $1 million of its Rural Electrification ..\dministration notes.
At December 31, 2004 and 2003, the overall effective cost of all of IPC's outstanding debt was 5.69 percent and 5.71 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
2004, IPC could issue under the mortgage approximately $699 million of additional first mortgage bonds based on unfunded property
additions and $392 million of additional flrst mortgage bonds based on retired first mortgage bonds. At December 31 2004, unfunded
property additions, which consist of electric property, were approximately $1.1 billion.
6. FAIR VALUE OF FINANCIAL INSTRUMENTS:
The estimated fair value of IPC's financial instruments has been detennined 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 is based upon quoted market prices of the same or similar issues or discounted cash flow analyses as appropriate.
December 31 2004 December 31 2003Carrying Estimated Carrying EstimatedAmount Fair Value Amount Fair Value
(thousands of dollars)
Assets:
Notes receivable
Investments
946
155
877
155
145
438
159
438
Liabilities:
Long-term debt 987 045 008 369 933 150 957 399
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 04/22/2005 2004/04
NOTES TO FINANCIAL STATEMENTS (Continued)
7. NOTES PAYABLE:
-1.t December 31 , 2004, 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 16 2007. Under this facility IPC pays a facility fee on the commitment, quarterly in arrears, based on its
rating for senior unsecured long-term debt securities without third-party credit enhancement as provided by Moody s and S&P. IPe's
conunercial paper may be issued up to the amounts supported by the bank credit facilities. There was no commercial paper outstanding at
December 31 , 2004 or 2003.
8. COMMITMENTS AND CONTINGENCIES:
-1.S of December 31 , 2004, IPC had agreements to purchase energy from 71 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 which IPC has the ability to
receive at the facility s requested point of delivery on the IPC system. IPC purchased 677 868 megawatt-hours (M\X'h) at a cost of $40
million in 2004 and 654 131 :MWh at a cost of$38 million in 2003.
f- .
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 , 2004.
Bridger Coal Company has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs and expects 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 various 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 it will vigorously defend against them, it is unable to predict with
certainty whether or not it will ultimately be successful. However, based on the company s evaluation, it believes that the resolution of
these matters will not have a material adverse effect on IPe's financial positions , results of operations or cash flows.
Legal Proceedings
Alves Dairy: On :May 18 2004, Herculano and Frances Alves, dairy operators from Twin Falls, Idaho, brought suit against IPC in Idaho
State District Court, Fifth Judicial District, Twin Falls County. The plaintiffs seek unspecified monetary damages for negligence and
nuisance (allegedly allowing electrical current to flow in the earth, injuring the plaintiffs' right to use and enjoy their property and adversely
affecting their dairy herd). On July 16, 2004, IPC filed an answer to J\1r. and l\1rs. Alves' complaint, denying all liability to the plaintiffs, and
asserting certain affirmative defenses. The parties have begun discovery in the case. No trial date has been scheduled. On December 14
2004, IPC flied a motion with the District Court for permission to appeal the court s denial of IPe's Motion to Disqualify the trial judge
for cause. The District Court granted the motion for permissive appeal. On February 16, 2005, IPC filed a motion for permissive appeal
with the Idaho Supreme Court. If granted, the Supreme Court will determine whether the District Court properly refused to disqualify the
trial judge for cause.
t /
" , ,
IPC intends to vigorously defend its position in this proceeding and believes this matter, with insurance coverage, will not have a material
adverse effect on its consolidated frnancial position, results of operations or cash flows.
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) filed a lawsuit in the Superior Court of the State of Washington, for the County of Grays
Harbor, against IDACORP, IPC and IE. On l\farch 9, 2001, Grays Harbor entered into a 20 l\fegawatt (M\X') purchase transaction with
IPC for the purchase of electric power from October 1 , 2001 through March 31, 2002, at a rate of $249 per:MWh. 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 had this action removed from the state court to the U.S. District Court for the Western District of Washington 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 .L-\ppeal, appealing the final judgment of
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 04/22/2005 2004/04
NOTES TO FINANCIAL STATEMENTS (Continued)
dismissal to the U.S. Court of Appeals for the Ninth Circuit. On August 10, 2004, the Ninth Circuit affirmed 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 fonnation
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
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 fl11al 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 the California energy crisis currently pending before the Honorable Robert H. Whaley,
sitting by designation in the Southern District of California and presiding over Multidistrict Litigation Docket No. 1405, regarding
California \Xlholesale Electricity Antitrust Litigation. On 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 asks 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 \Xlhaley. Grays Harbor is opposing transfer, however, and the Judicial Panel on Multidistrict
Litigation has yet to finally rule on the transfer. IDACORP, IE and IPC have not responded to the amended complaint as a response is not
yet required. The companies plan to file a motion to dismiss the complaint. The companies intend to vigorously defend their position on
remand and believe this matter will not have a material adverse effect on their consolidated fl11ancial positions, results of operations or cash
flows.
Port of Seattle: On 1fay 21 2003 , the Port of Seattle, a Washington municipal corporation, filed a lawsuit against 20 energy finns
including IPC and IDACORP, 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 exc~usively within the jurisdiction of th~ 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 IPC and
IDACORP'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. 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 these matters 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 ofTDY Industries, Inc., filed 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. Will 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. %aley, sitting by designation in the Southern District of California and presiding over Multidistrict Litigation Docket No. 1405
regarding California \Xlholesale Electricity Antitrust Litigation. IDACORP, IE and IPC have not answered the complaint, as a response is
not yet required. The companies, along with the other defendants, subsequently filed a motion to dismiss the complaint, which was heard
on January 20, 2005. By order dated February 11 2005, the court granted the companies' and other defendants ' motion to dismiss. The
companies intend to vigorously defend their position in this proceeding and believe these matters will not have a material adverse effect on
their consolidated financial 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 IDACORP, 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. %aley, sitting by designation in the Southern District of California and presiding over Multidistrict Litigation Docket No. 1405
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 04/22/2005 2004/04
NOTES TO FINANCIAL STATEMENTS (Continued)
regarding California \Vholesale Electricity Antitrust Litigation. IDACORP, IE and IPC have not answered the complaint, as a response is
not yet required. The companies, along with the other defendants, filed a motion to dismiss the complaint which was taken under
submission by the court, without oral argument. By order dated February 11 , 2005, the court granted the companies' and other defendants
motion to dismiss. The companies intend to vigorously defend their position in this proceeding and believe these matters will not have a
material adverse effect on their consolidated financial positions, results of operations or cash flows.
State of California Anorney General: The California .Attorney General filed the complaint in this case in the California Superior Court in
San Francisco on May 30 2002. This is one of thirteen virtually identical cases brought by the Attorney General against various sellers of
power in the California market, seeking civil penalties pursuant to California s Unfair Competition Law, Business and Professions Code
Section 17200. Section 17200 defines unfair competition as any "unlawful, unfair or fraudulent business act or practice. .
. .
" The Attorney
General alleges that IPC engaged in unlawful conduct by violating the Federal Power Act in two respects: (1) by failing to file its rates with
the FERC and (2) charging unjust and unreasonable rates. The Attorney General alleged that there were "thousands of. . . sales or
purchases" for which IPC failed to file its rates, and that IPC charged unjust and unreasonable rates on "thousands of occasions." Pursuant
to Business and Professions Code Section 17206, the Attorney General seeks civil penalties of up to $2 500 for each alleged violation.
June 25, 2002, IPC removed the action to federal court, and on July 25 2002, the Attorney General filed a motion to remand back to state
court. On 1larch 25 2003 , the court denied the Attorney General's motion to remand and granted IPC's motion to dismiss the case based
upon grounds of federal preemption and the filed-rate doctrine. On March 28, 2003, the Attorney General filed a Notice of Appeal to the
S. Court of Appeals for the Ninth Circuit, appealing the court s decision granting IPC's motion to dismiss. Briefing on the appeal was
completed in October 2003. On October 12, 2004, the Ninth Circuit unanimously affirmed the order denying remand and dismissing all of
the Attorney General's actions , including the action against IPc. The Attorney General did not file a petition for rehearing in the Ninth
Circuit and has not sought review from the U.S. Supreme Court. As a result, the Ninth Circuit s October 12, 2004 decision is final.
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, LLc., Reliant Energy Etiwanda, LLc., Reliant
Energy Ellwood, LL.c., Reliant Energy Mandalay, LLc. and Reliant Energy Coolwater, LLc. (collectively, Reliant); and Duke Energy
Trading and 11arketing, LLc., Duke Energy Morro Bay, LL.c., Duke Energy Moss Landing, LLc., Duke Energy South Bay, LL.c. and
Duke Energy Oakland, LLC. (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.
Plaintiffs asserted various claims that the defendants violated the California Antitrust 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 seek 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 seek 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 Califo~a, Reliant seeks 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 throughthe 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, have 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
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 Appeals 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 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. Cross-defendant, Powerex Corp., sought Rehearing En
Banc at the Ninth Circuit arguing that while it is a government entity, it is not immune from suit but should be permitted to litigate in
federal rather than state court. If the case is returned to state court, the companies, and other cross-defendants, intend to re-file their
motions to dismiss in state court, which had been filed in federal court but never ruled upon. The companies believe these matters will not
i. '
I FERC 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 04/22/2005 2004/04
NOTES TO FINANCIAL STATEMENTS (Continued)
have a material adverse effect on their consolidated fl1lancial positions, results of operations or cash flow.
Western Energy Proceedings at the FERC:
California Power Exchange Chargeback:
As a component of IPC' s non-utility energy trading in the State of California, IPC, in January 1999, entered into a participation agreement
with the California Power Exchange (CalPX), 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 amoW1t to the CalPX. 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 CalPX. 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 IPC's payment of the January 18 , 2001 invoice, but onJW1e 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 amoW1ts 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 CalPX's implementation of its default mitigation procedures.
-\ 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 April 2001 , Pacific Gas and Electric Company filed 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.
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 claims it is awaiting further orders from the FERC and the
bankruptcy court before distributing the funds that it collected under its chargeback tariff mechanism. Although certain parties to the
California refund proceeding urged the FERC's Presiding Administrative Law Judge to consider the chargeback amounts in his
determination of who owes what to whom, in his Certification of Proposed Findings on California Refund Liability, he concluded that the
matter already was pending before the FERC for disposition. On October 7, 2004, the FERC issued an order detennining 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. The FERC has not yet acted on the requests for rehearing.
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 aJW1e 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 CalPX's spot markets to determine what refunds may be due
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 04/22/2005 2004/04
NOTES TO FINANCIAL STATEMENTS (Continued)
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).
This case had been complicated by an .August 13, 2002 FERC Staff Report which included the recommendation to replace the published
California indices for gas prices that the FERC previously established as just and reasonable for calculating a Mitigated Market Clearing
Price to calculate refunds with other published indices for producing basin prices plus a transportation allowance. The FERC Staffs
recommendation is grounded on speculation that some sellers had an incentive to report exaggerated prices to publishers of the indices
resulting in overstated published index prices. The FERC Staff based its speculation in large part on a statistical correlation analysis of
Henry Hub and California prices. IE, in conjunction with others, submitted comments on the FERC Staff recommendation - asserting that
the staffs conclusions were incorrect because the staffs correlation study ignored evidence of normal market forces and scarcity that
created the pricing variations that the staff observed, rather than improper manipulation of reported prices.
The Administrative 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 affirmed 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
findings 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 CaIPX to the companies. Calculations remain uncertain because the FERC has required the Cal ISO to
correct a number of defects in its calculations and because 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. As a result, IE
is unsure of the impact this ruling will have on the refunds due from California. However, as to potential refunds, if any, IE believes its
exposure is likely to be offset by amounts due from California entities.
, along with a number of other parties, filed an application with the FERC on April 25, 2003 seeking rehearing of the j\larch 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 1\1itigated 1\1arket Clearing Prices and refund amounts within five months. The
Cal ISO has since requested additional time to complete its compliance filings. By order of February 3, 2004, the FERC granted additional
time. In a February 10, 2004 report to the FERC, the Cal ISO asserted its belief that it would complete re-running the data and financial
clearing of amounts due by .August 2004, subject to a number of events that must occur in the interim, including FERC disposition of a
number of pending issues. This Cal ISO compliance filing has since been delayed until at least April 2005. The Cal ISO is required to
update the FERC on its progress monthly. After receipt of the compliance filing, the FERC will consider cost-based filings from sellers to
reduce their refund exposure.
1 '
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 limited issues of: (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. Petitioners and petitioner-intervenors, including IE, filed opening briefs regarding the latter two issues on December 23, 2004.
The FERC filed its respondent s brief on January 31 , 2005, and petitioners and petitioner-intervenors, including IE, filed their reply briefs
on March 1 2005. Oral argument is scheduled for April 12-, 2005.
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
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, Oa, Yr)
Idaho Power Company (2)A Resubmission 04/22/2005 2004/04
NOTES TO FINANCIAL STATEMENTS (Continued)
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 EI Paso of some $1.69 billion. Duke claimed that the relief afforded by the settlement was duplicative of the remedies
imposed by the FERC in its l\Jarch 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. 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 , 2004, 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 $42 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 , 2004, 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 financial position, results of operations or cashflows.
On l\1arch 20, 2002, the California Attorney General filed a complaint with the FERC against various sellers in the wholesale power market
including IE and IPC, alleging that the FERC's market-based rate requirements violate the Federal Power Act, 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 Appeals 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 fonn 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.
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 I\farch 3, 2003, the California Parties (certain investor owned utilities, the California Attorney General, the California Electricity
OversigHt Board and the cpuq filed volwninous documentation asserting that a number oEwholesale power suppliers, including IE and
IPC, had engaged in a variety of fonns 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 in limited contexts with the overwhelming majority of the claims of the California Parties relating to the conduct of other
parnes.
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 Mitigated I\farket Clearing Price, seeking approximately $8 billion
in refunds to the Cal ISO and the CaIPX. On March 20, 2003, numerous parties, including IE and IPC, submitted briefs and responsive
testlmony.
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
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, Oa , Yr)
Idaho Power Company (2)A Resubmission 04/22/2005 2004/04
NOTES TO FINANCIAL STATEMENTS (Continued)
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 settle allegations
of circular scheduling. IPC believed that it had defenses to the circular scheduling allegation but determined that the cost of settlement 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" settlement 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 dle 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
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
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. The company is not able to predict the outcome of the judicial determination
of these issues.
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 :MWh 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 tenninating the investigation as to IPc.
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 Administrative Law Judge s recommendations. The Administrative Law Judge s recommended findings 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
has 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.
, "
k -
In addition, the Port of Seattle, the City of Tacoma and the City of Seatde 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 the claims of these parties 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 ftle for review. The Port of Seatde, the City of Tacoma, the City of Seatde, 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. The ,FERC has certified the
record to the Ninth Circuit. On July 21 2004, the City of Seattle submitted to the Ninth Circuit in the Pacific Northwest refund petition
I FERC 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 04/22/2005 2004/04
NOTES TO FINANCIAL STATEMENTS (Continued)
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 consists
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. The City of Seattle also requested that the current briefing
schedule, which required briefs to be filed by August 5, 2004, be delayed. On September 29, 2004, the Ninth Circuit denied the City of
Seattle s motion for leave to adduce evidence, without prejudice to renewing the request for remand in the briefing in the Pacific Northwest
. refund case. Petitioner s briefs were filed January 14 2005, Petitioner-intervenors briefs were filed on February 14, 2005 and Respondent
brief is due March 30, 2005 and Respondent-intervenor s briefs and the briefs of any non-aligned intevenors are due April 29, 2005.
Petitioners reply briefs are due 42 days after service of respondent s briefs. Petitioner-intervenors' briefs are due 56 days after service of
respondent s briefs. A date for oral argument has not yet been set.
The companies are unable to predict the outcome of these matters.
On July 21 , 2004, Californians for Renewable Energy, Inc. (CARE) filed a motion with the FERC in connection with the California Refund
proceedings, the Pacific Northwest refund proceedings and the show cause proceedings, both gaming and partnership, including those in
which IPC was the respondent. CARE has participated in many of the FERC proceedings dealing with California energy matters, having
appointed itself as a representative of low-income communities and other groups that it claims are otherwise not represented. The FERC
permitted CARE to participate in the cases as an intervenor. In its current motion, CARE requests that the FERC radically restructure its
approach to California and western energy proceedings involving the events of 2000 and 2001 by revoking market-based rate authority
from the date of their approvals, replacing market-based rates with cost-of-service rates by requiring refunds back to the date of the orders
granting market-based rate a\,lthority, revising long-term energy contracts negotiated during 2000 and 2001 (it appears that the contracts
that CARE identified do not include any to which IPC is a party), deferring further refund settlements, establishing a direct pass-through
refund mechanism for California conswners and having "previously executed settlement agreements rejected.CARE also requested that
the FERC revoke market-based rates for those entities identified in the June 25, 2003 show cause orders, which would include IPc. IPC
defended itself in response to this motion and is unable to predict how the FERC will respond to CARE's motion. On September 9, 2004
CARE filed a motion to withdraw its July 21, 2004 pleading. By operation oflaw, the withdrawal was effective September 24 2004.
Shareholder Lawsuits: On J\lay 26, 2004 and June 22, 2004, respectively, two shareholder lawsuits were flied against IDACORP and
certain of its directors and officers. The lawsuits, captioned Powell, et al. v. IDACORP, Inc., et al. and Shorthouse, et al. v. IDACORP
Inc., et at, raise largely similar allegations. The lawsuits are putative class actions brought on behalf of purchasers of IDACORP stock
between February 1 2002 and June 4, 2002, and were filed in the U.S. District Court for the District of Idaho. The named defendants in
each suit, in addition to IDACORP, are Jon H. :Miller, J an B. Packwood, J. La:Mont Keen and Darre! T. Anderson.
The complaints alleged that, during the purported class period, IDACORP and/or certain of its officers and/ or directors made materially
false and misleading statements or omissions about the company s financial outlook in violation of Sections 10(b) and 20(a) of the Securities
Exchange Act of 1934, as amended, and Rule 10b-, thereby causing investors to purchase the company s common stock at artificially
inflated prices. More specifically, the complaints alleged that IDACORP failed to disclose and misrepresented the following material
adverse facts which were known to defendants or recklessly disregarded by them: (1) IDACORP failed to appreciate the negative impact
that lower volatility and reduced pricing spreads in the western wholesale energy market would have on its marketing subsidiary, IE; (2)
IDACORP would be forced to limit its origination activities to shorter-term transactions due to increasing regulatory uncertainty and
continued deterioration of creditworthy counterparties; (3) IDACORP failed to discount for the fact that IPC may not recover from the
lingering effects of the prior year s regional drought and (4) as a result of the foregoing, defendants lacked a reasonable basis for their
positive statements about IDACORP and their earnings projections. The Powell complaint also alleged that the defendants' conduct
artificially inflated the price of the company s common stock. The actions seek an unspecified amount of damages, as well as other forms
of relief. By order dated August 31, 2004, the court consolidated the Powell and Shorthouse cases for pretrial purposes, and ordered the
plaintiffs to file a consolidated complaint within 60 days. On November 1 , 2004, IDACORP and the directors and officers named above
were served with a purported consolidated complaint captioned Powell et al. v. IDACORP, Inc. et at, which was filed in the U.S. DistrictCourt for the District of Idaho.
The new complaint alleges that during the class period IDACORP and/ or certain of its officers and/or directors made materially false and
misleading statements or omissions about its business operations, and specifically the IDACORP Energy financial outlook, in violation of
Rule 10b-, thereby causing investors to purchase IDA-CORP's common stock at artificially inflated prices. The new complaint alleges that
IDACORP failed to disclose and misrepresented the following material adverse facts which were known to it or recklessly disregarded by it:
(1) IDACORP falsely inflated the value of energy contracts held by IDA-CORP Energy in order to report higher revenues and profits; (2)
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 04/22/2005 2004/04
NOTES TO FINANCIAL STATEMENTS (Continued)
IDACORP permitted IPC to inappropriately grant native load priority for certain energy transactions to IDACORP Energy; (3) IDACORP
failed to file 13 ancillary service agreements involving the sale of power for resale in interstate commerce that it was required to file under
Section 205 of the Federal Power ..\ct; (4) IDA CORP failed to file 1 182 contracts that IPC assigned to IDACORP Energy for the sale of
power for resale in interstate commerce that IPC was required to file under Section 203 of the Federal Power Act; (5) ID..\CORP failed to
ensure that ID..-\CORP Energy provided appropriate compensation from IDACORP Energy to IPC for certain affiliated energy
transactions; and (6) IDACORP permitted inappropriate sharing of certain energy pricing and transmission information between IPC and
IDACORP Energy. These activities allegedly allowed IDACORP Energy to maintain a false perception of continued growth that inflated
its earnings. In addition, the new complaint alleges that those earnings press releases, earnings release conference calls, analyst reports and
revised earnings guidance releases issued during the class period were false and misleading. The action seeks an unspecified amount of
damages, as well as other forms of relief. IDACORP and the other defendants filed a consolidated motion to dismiss on February 9, 2005
which is now pending.
ID..\CORP and the other defendants intend to defend themselves vigorously against the allegations. The company cannot, however
predict the outcome of these matters.
t .
Other Legal Issues
Idaho Power Company Transmission Line Rights-of-Way Across Fort Hall Indian Reservation: IPC has multiple transmission
lines that cross the Shoshone-Bannock Tribes' Fort Hall Indian Reservation near the city ofPocatello in southeastern Idaho. IPC has been
working since 1996 to renew four of the right-of-way permits (for five of the transmission lines), which have stated permit expiration dates
between 1996 and 2003. IPC filed ~pplications with the U.S. Department of the Interior, Bureau of Indian Affairs, to renew the four
rights-of-way for 25 years, including payment of the independently appraised value of the rights-of-way to the tribes (and the tribal allottees
who own portions of the rights-of-way). Due to the lack of definitive legal guidelines for valuation of the permit renewals, IPC is in the
process of negotiating mutually acceptable renewal terms with the tribes and allottees. The parties are pursuing a possible 23-year renewal
of the permits (including all pre-renewal periods) for a total payment of approximately $7 million to the tribes and allottees. IPC, the tribes
and the Bureau of Indian Affairs are currently working through the process of finalizing the agreement, including obtaining the requisite
consents from the allottees. The parties hope to obtain the required consents early in 2005. On December 27, 2004, IPC filed an
application with the IPUC seeking an accounting order regarding the treatment of this transaction. On February 28, 2005, the IPUC issued
an order approving IPC's application procedure.
9. STOCK-BASED COMPENSATION:
The maximum number of shares available under the LTICP is 2 050 000. In 2004 and 2003, IDACORP granted to IPC employees
110 500 343 000 and 230 000 stock options, respectively, with an exercise price equal to the market price of IDA CORP's stock on the date
of grant. In accordance with APB 25, no compensation costs have been recognized for the option awards.
Stock option transactions are summarized as follows:
2004 2003 v-:-:
Weighted Weighted
Number average Number average
exercise exercise
shares pnce shares nce
Outstanding beginning of year 889 800 32.50 594 000 38.
Granted 110 500 31.21 343 000 22.
Exercised 200)22.
Forfeited (40 500)32.(47 200)36.42
Outstanding end of year 955 600 32.41 889 800 32.
Exercisable 374 800 35.43 211 ,600 37.
The following table summarizes information about stock options outstanding at December 31 , 2004:
Outstanding Exercisable
Weighted
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 04/22/2005 2004/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Weighted average Weighted
average remalmng average
Number exercIse contractual Number exercIse
Exercise Price Ran of shares nce life of shares nce
$22.92 - $31.21 428 800 24.80 years 000 22.
$35.81 - $40.526 800 38.45 29 ears 310 800 38.
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 2004 and 2003, total compensation accrued under the Restricted Stock
Plan was less than $1 million annually.
The following table summarizes restricted stock activity:
2004 2003
Shares outstanding - beginning of year 454 192
Shares granted 806 945
Shares forfeited (24 014)889)
Shares issued
Shares outstanding - end of year 118 246 454
Weighted average fair value of current year stock
ants on ant date 31.21 $22.
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. IPe'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 maximum amount deductible for
income tax purposes. IPC was not required to contribute to the plan in 2004 and 2003, and does not expect to make a contribution in
2005. 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 Compensation Plan2004 2003 2004 2003
(thousands of dollars)
Change in benefit obligation:
Benefit obligation at January
Service cost
Interest cost
Actuarial loss (gain)
Benefits paid
Plan amendments
Benefit oblip;ation at December 31
Change in plan assets:
Fair value at January
IFERC FORM NO.1 (ED. 12-88)
339 121 $ 294 881 870 792
809 173 358 212
437 463 312 414
626 420 225)786
(13 660)(13 345)670)369)
529
374 333 339 121 645 870
335 229 282 531
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 04/22/2005 2004/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Funded status
Unrecognized actuarial loss
Unrecognized prior service cost
Unrecognized net transition liability
Net amount recognized
Amounts recognized in the statement of
financial position consist of:
Prepaid (accrued) pension cost
Intangible asset
Accwnulated other comprehensive income
Net amount recogniz
Accwnulated benefit obligation
648 043
(13 660)(13 345)
356 217 335 229
(18 116)892)(38 645)(38 870)
491 577 443 547
889 660 372 010
(126)(389)310 923
138 956 (25 520)(23 390)
138 956 (36 110)(35 676)
682 933
908 353
138 956 (25 520)(23 390)
316 498 - $ 284 910 110 676
Actual return on plan assets
Employer contributions
Benefit payments
Fair value at December 31
The following table shows the components of net periodic benefit cost for these plans:
Deferred
Pension Plan Compensation Plan2004 2003 2004 2003
(thousands of dollars)
Service cost
Interest cost
Expected return on assets
Recognized net actuarial loss
.Amortization of prior service cost
.I.-\mortizanon of transition asset
Net periodic pension cost
(benefit)
$ 1 358
312
212
414
, .
809
437
(27 935)
173
463
(23 445)
361
729
(263)
018
878
(361)
613
$ 4 800
744
(345)
613
638
770
(263)
818
Changes in the Deferred Compensation Plan minimwn liability increased other comprehensive income by $1 million in 2004 and decreased
other comprehensive income by $1 million in 2003.
The following table summarizes the expected future benefit payments of these plans (in thousands):
Pension Plan
Deferred Compensation
Plan
2005
13 ,846
$ 2 296
2006
$ 14 277
$ 2 345
2007
$ 14 996
$ 2 461
2008
$ 16 018
$ 2 551
2009 2010-2014
$ 17 244 $ 110 833
$ 2 721 $ 15 041
Plan Asset Allocations: IPC's pension plan and postretirement benefit plan weighted average asset allocations at December 31 2004 and
2003, by asset category are as follows:
Asset Category
Equity securities
Debt securities
Real estate
Other (a)
I FERC FORM NO.1 (ED. 12-
Pension Postretirement
Plan Benefits
2004 2003 2004 2003
69%69%
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 04/22/2005 2004/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Total 100%100%100%100%
(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
Intermediate-Term 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 return (defined 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 IPC'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. The baseline risk measure is a 60 percent S&P 500
stocks and a 40 percent Lehman Aggregate bond portfolio.
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 real returns adjusted for inflation for each asset ciass, based on a
recognized index established for the asset class being measured. Historical real returns are then adjusted to include an inflation premium
based on the current inflation environment. IPC currently uses a three percent inflation assumption in the asset modeling process.
IPC'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. TIUs "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. TIUs amendment will limit the growth of IPC'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
Amortization of unrecognized transition obligation
2004
400
974
294)
040
2003
207
017
930)
040
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 04/22/2005 2004/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Amortization of prior service cost
Recognized actuarial loss
Net periodic postretirement benefit cost
(523)
489
086
(563)
402
173
The following table summarizes the changes in benefit obligation and plan assets (in thousands of dollars):
Effect on total of cost components 220 (170)
Effect on accumulated postretirement benefit obligation $ 1 996 $ (1 625)
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:
2004 2003
090 267
400 207
974 017
201 780
997)181)
437
105 090
603 . 22 522
301 081
577 961
758)961)
723 603
(41 382)(40 487)
087)047)
559 854
320 360
590)320)
,,:
Percentage-Pointincrease decrease
Change in accumulated benefit obligation:
Benefit obligation at January
Service cost
Interest cost
Actuarialloss
Benefits paid
Plan .Amendments
Benefit obligation at December 31
Change in plan assets:
Fair value of plan assets at January
Actual return on plan assets
Employer contributions
Benefits paid
Fair value of plan assets at December 31
Funded status
Unrecognized prior service cost
Unrecognized actuarial loss
Unrecognized transition obligation
Accrued benefit obligations included with other deferred credits
The assumed health care cost trend rate used to measure the expected cost of benefits covered by the plan was 6.75 percent in 2004 and
2003. A one-percentage point change in the assumed health care cost trend rate would have the following effect (in thousands of dollars):
Discount rate
Expected long-term rate of retum on assets
Rate of compensation increase
Medical trend rate
Expected working lifetime (years)
Pension
Benefits2004 2003
75% 6.15%5 8.5 4.
Postretirement
Benefits2004 2003
75% 6.15%5 8.
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:
Pension Pos tretirement
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 04/22/2005 2004/04
NOTES TO FINANCIAL STATEMENTS (Continued)
1:.
Discount rate
Expected long-term rate of return on assets
Rate of compensation increase
1\1edical trend rate
Expected working lifetime (years)
Benefits Benefits
2004 2003 2004 2003
15%75%6.15%75%
8.5 8.5 8.5
4.5
FSP F AS 106-1 and FSP F AS 106-
In January and :May 2004, the FASB released FSP FAS 106-1 and FSP FAS 106-
, "
Accounting and Disclosure Requirements Related to
the l\fedicare Prescription Drug, Improvement and Modernization Act of 2003.
The Medicare Prescription Drug, Improvement and l\lodernization Act of 2003 (1vledicare Act) was signed into law in December 2003 and
establishes 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.
FSP FAS 106-2 provides guidance on accounting for the effects of the Medicare Act for employers that sponsor postretirement health care
plans that provide prescription drug benefits and requires those employers to provide certain disclosures regarding the effect of the federal
subsidy provided by the Medicare Act. Under FSP FAS 106-, IPC elected to defer accounting for the effects of the Medicare Act. This
deferral remained in effect until the appropriate effective date of FSP FAS 106-
FSP FAS 106-2 was effective for the first interim or annual period beginning after June 15 2004. However, for entities that did not
recognize a significant impact, delayed recognition of the effects of the Medicare .Act until the next regularly scheduled measurement date
following the issuance of FSP FAS 106-2 was required.
The measures of accumulated postretirement benefit obligation and net periodic benefit cost do not reflect any amount associated with the
subsidy, because IPC initially determined that the effect of the :Medicare Act would not be material. Regulations published on January 28
2005 proviq.e more flexibility in determining actuarial equivalence to l\1edicare of the benefits provided by the plan than was initially
estimated by IPC's actuaries. Based on these new regulations , IPC es~ates that the accumulated postretirement benefit obligation as of
January 1, 2005 will be reduced by $6 million, and 2005 periodic postretirement benefit cost will decrease by $1 million.
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 tlie plan. Matching contributions amounted to $3 million in both 2004
and 2003.
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
IPUC 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 balance sheets at December 31 (in thousands of
dollars):
Included with regulatory assets
Included with other deferred credits
2004
$ 3 924
2003
403
. 4 079
...
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 2004 and 2003 (in thousands of dollars):
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 04/22/2005 2004/04
NOTES TO FINANCIAL STATEMENTS (Continued)
2004
Production
Transmission
Distribution
General and Other
Total in service
Accumulated rovision for de reciation
In service - net
Balance
482 517
560 303
992 248
289 748
324 816
316 125
008 691
Rate
2.5 1 %
10.
96%
2003
Balance
456 954
526 887
952 979
283 408
220 228
239 604)
980 624
Rate
62%
6.51
99%
IPC has interests in three jointly-owned generating facilities. Under the joint operating agreements, each participating utility is responsible
for financing its share of construction, operating and leasing costs. IPe'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 IPe's
participation, were as follows at December 31 , 2004 (in thousands of dollars):
U till ty Construction Accumulated
Plant In Work in Provision for
Name of Plant Location Service Progress reciation DID
Jim Bridger Units 1-Rock Springs, WY 442 367 310 255 229 707
Boardman Boardman, OR 116 277 275
Valm Units 1 and 2 Winnemucca, NV 310 917 889 184 025 261
IPe'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 $47 million in 2004 and $44
million in 2003.
IPC has contracts to purchase the energy from four Public Utilities Regulatory Policy Act of 1978 (pURPA) Qualified Facilities that are 50
percent owned by Ida-West. Power purchased from these facilities amounted to $7 million, annually in 2004 and 2003.
12. REGULATORY MATTERS:
General Rate Case
Idaho: IPC filed its Idaho general rate case with the IPUC on October 16 2003. IPC originally requested approximately $86 million
annually in additional revenue, an average 17.7 percent increase to base rates. On rebuttal, IPC lowered its overall requested increase to
$70 million annually, an average of 14.5 percent. The IPUC approved an increase of $25 million in IPe's electric rates , an average of 5.
percent, in an order issued on May 25, 2004. The rate increase became effective on June 1 2004.
In the order, the IPUC approved a return on equity of 10.25 percent, compared to the 11.2 percent IPC requested, an overall rate of return
of 7.9 percent, compared to the 8.3 percent requested by IPC The IPUC reduced the $1.55 billion in rate base requested for IPe's Idaho
jurisdiction to $1.52 billion.
Additionally, the IPUC approved higher rates for residential and small-commercial customers during the summer months to encourage
conservation. The 12.6 percent higher summer rate applies to montWy usage over 300 kilowatt-hours. The IPUC also ordered time-of-use
rates to be phased in for industrial customers, asked IPC to submit a proposal for a conservation program for industrial customers and
ordered increased low-income weatherization funding of $1 million annually.
The IPUC also noted two other issues to be addressed in separate proceedings and potentially handled in workshops instead of formal
hearings. These issues are: (1) investigating approaches to removing financial disincentives to IPC for investing in cost effective energy
efficiency and clean distributed generation and (2) investigating various cost of service issues raised in the general rate case, including those
associated with load growth. During the year, initial workshops were held on both issues.
The IPUC disallowed several costs in the Idaho general rate case order, including $12 million annually related to the detennination of IPe's
income tax expense, $8 million of incentive payments capitalized in prior years and $1 million of capitalized pension expense. On June 15
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 04/22/2005 2004/04
NOTES TO FINANCIAL STATEMENTS (Continued)
2004, IPC f1led with the IPUC a petition for reconsideration of these and other items. On July 13 2004, the IPUC granted this petition in
part, agreeing to reconsider the issue relating to the detennination of IPC's income tax expense and, in light of the IPUC Staff's
computational errors, ordering rates increased by approximately $3 million on or before August 1 , 2004. IPC recorded an impairment of
assets of $9 million related to the disallowed incentive payments and the disallowed capitalized pension expenses.
Qn September 28, 2004, the IPUC issued separate orders approving two Settlement Agreements entered into on August 16, 2004 between
IPC and the IPUC Staff.
Settlement No., approved by the IPUC in Order No. 29601 , relates to the calculation of IPC's taxes for purposes of test year income tax
expense. In the Idaho general rate case order, the IPUC adopted the use of a historic five-year average income tax rate to calculate IPC's
income tax expense. Settlement No.1 approved the modification of the general rate case order to utilize IPC's statutory income tax rates
to compute test year income tax expense. As a result, IPC will compute and record monthly during the period June 1 2004 through May
2005 a regulatory asset (with interest accrued at a rate of one percent per annum) of approximately $12 million. Rates will increase on
June 1 2005 to reflect the ongoing impact of the tax expense. .Approximately $7 million of.this amount was recorded in 2004 as other
operating revenue. Settlement No.1 allows IPC to continue its compliance with the normalization provisions of the Internal Revenue
Code of 1986, as amended, and associated Treasury Regulations, and will allow IPC to continue to receive the benefits of accelerated
depreciation.
Settlement No., approved by the IPUC in Order No. 29600, resolved outstanding issues related to: (1) an unplanned outage at one of the
two units of the North Valmy Steam Electric Generating Plant (Valmy) in the summer of 2003, (2) a matter relating to the expense
adjustment rate for growth component of the PCA and (3) regulatory accounting issues related to a tax accounting method change in 2002.
In Settlement No., IPC and the IPUC Staff agreed that the IPUC will not examine the cost of replacement power and a possible PCA
adjustment resulting from the Valmy outage, and the expense adjustment rate for growth component of the PCA will continue at its
existing value until IPC's next general rate case. In September 2004, as a result of the order, IPC established a regulatory liability of $19
million with a charge to PCA expense. A monthly credit of approximately $804 000 will be included in the PCA from June 2004 through
May 2006, which will reduce this regulatory liability. Also in September 2004, IPC reversed a $16 million regulatory tax liability by reducing
income tax expense. This regulatory tax liability was established in 2002 when IPC changed its tax accounting method for capitalized
overhead costs.
The final result of IPC's general rate case was a $40 million increase to the base Idaho jurisdictional revenue requirement, comprised of $25
million in the initial order, $3 million related to computational errors and $12 million in the order approving Settlement No.
On March 2, 2005, IPC made a rate filing with the IPUC to include the investment associated with the construction of the Bennett
Mountain Power Plant in Idaho retail rates.
Oregon: On September 21 2004, IPC filed an application with the OPUC to increase general rates an average of 17.5 percent or
approximately $4 million annually. IPC's filing includes a request to introduce summer and non-summer rates similar to proposals that
were approved in the Idaho general rate case. IPC has not filed for a change to its overall rates in Oregon since 1995.
On October 19 2004, the OPUC suspended IPC's request for a period of time not to exceed nine months from October 20 , 2004 to
investigate the propriety and reasonableness of the request. A pre-hearing conference and public meeting was held on November 18, 2004.
The hearing schedule called for a settlement conference, which began on February 14 2005 and an evidentiary hearing to begin on May 23
2005. IPC is unable to predict what rate relief the OPUC will grant.
Deferred Power Supply Costs
IPC's deferred net power supply costs consisted of the following at December 31 (in thousands of dollars):
Oregon deferral
Idaho PCA current year net power supply cost deferrals:
Deferral for 2004-2005 rate year
Deferral for 2005-2006 rate year
Irrigation Lost Revenues
Idaho PCA true-up awaiting recovery:
Remaining true-up authorized May 2003
I FERC FORM NO.1 (ED. 12-88)
2004 2003
047 620
664
778
290
646
Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Oa, Yr)
Idaho Power Company (2)A Resubmission 04/22/2005 2004/04
NOTES TO FINANCIAL STATEMENTS (Continued)
415
530
Remaining true-up authorized l\fay 2004
Total deferral 930
Idaho: IPC has a 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 portions, is then included in the calculation of the next year s PCA.
On April 15, 2004, IPC 6led 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 IPC's filing with additional instructions for
IPC and the IPUC Staff to examine the cost of replacement power attributable to the unplanned outage at the Valrny plant in 2003. Based
on the order approving Settlement No., discussed above, the IPUC will not examine the costs related to this outage.
.r
On May 15 2003, the IPUC issued Order No. 29243 approving IPC's 2003-2004 PCA filing, with a small adjustment to the original filing.
As approved, IPC'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 of lost 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 1-fay
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 entided 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 IPUC denial of the recovery of lost revenues and
remanded the matter to the IPUC to determine the amount oElost 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 will be included as part
IPC's annual PCA beginning June 1 2005.
Oregon: On 1-1arch 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 the low water conditions IPC is currendy experiencing. The net system power supply costs included in
this filing was $169 million. IPC is proposing to use the same methodology for this deferral filing that was accepted in 2002 for Oregon
share of IPC's 2001 net power supply expenses.
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 \vill recover
approximately $3 million annually.
r /
':.
Wind Down of Energy Marketing
IDACORP announced in 2002 that IE would wind down its energy marketing operations.
matters were identified that required resolution with the FERC, the IPUC and the OPUc.
jurisdictions.
In connection with the wind down, certain
These matters were resolved in all three
Idaho: In an IPUC proceeding that began in May 2001 , IPC, the IPUC staff and several interested customer groups worked cooperatively
to determine the appropriate compensation IE should provide to IPC for certain transactions between the affiliates. The IPUC has issued
several orders since then regarding these matters. Order No. 28852 issued on September 28, 2001 covered the time period prior to
February 2001. Order No. 29026 covered the rime period from March 2001 through ~farch 2002. The IPUC also approved IPC's ongoing
hedging and risk management strategies in Order No. 29102 issued on August 28, 2002. This order formalized IPC's agreement to
implement a numb~r of changes to its existing practices for managing risk and initiating hedging purchases and sa~es. The $5.8 million in
benefits related to the FERC settlement were included in the 2003-2004 PCA and credited to Idaho retail customers in accordance with the
PCA methodology. The parties to the proceeding have executed a settlement agreement providing that an additional $5.5 million be flowed
through the PCA mechanism to the Idaho retail customers from April 2003 through December 2005. This agreement was filed with the
IPUC on February 17 2004 and approved on March 15 2004.
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 04/22/2005 2004/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Oregon: Following IPC's settlement with the IPUC on issues related to IPC's past relationship with IE , IPC approached the OPUC to
setde the issue of fair compensation to Oregon customers related to the terminated Electricity Supply Management Services Agreement
between IPC and IE, as well as any other issues relating to transactions between IPC and IE. On October 4, 2004, IPC filed a petition with
the OPUC requesting an accounting order approving a settlement stipulation and authorizing IPC to credit its existing deferral balance of
excess power supply costs. In the propp sed settlement, IPC agrees to continue the $7 700 monthly credit to customers that began in July
2001 through December 2005, and to reduce the existing excess power supply cost deferral balance by a one time credit of $100 000 on
January 1, 2005. The OPUC issued Order No. 04-683 approving this setdement on November 22, 2004.
r .
Regulatory Assets and Liabilities
The following is a breakdown of IPC's regulatory assets and liabilities (in thousands of dollars):
Income taxes
Conserva tion
Employee benefits
PCA deferral and amortization
Oregon deferral and amortization
Derivatives
-\.sset retirement obligations
Deferred investment tax credits
IPUC settlement order
Irrigation lost revenues
BP.A. settlement
Incremental security costs 813OPUC settlement 100Other 815 ..149 1 508 Total $ 438 781 $ 275 941 $ 434 029 $ 258 524
The regulatory assets related to income taxes and asset retirement obligations do not earn a current return on investment.
information on the asset retirement obligations amounts, see Note 17.
. .
Assets
344 220
836
193
047
2004
Liabilities
$ 40 447
205
Assets
330 833
108
993
310
620
125
456
2003
Liabilities
$ 41 024
288
372 147 700
836
671
142 595
789
119
290
833 735
076
For further
In the event that recovery of costs through rates becomes unlikely or uncertain, SF AS 71 would no longer apply. If IPC were to
discontinue application of SFAS 71 for some or all of its operations, then these items may represent stranded investm~nts.)f IPC is not
allowed recovery of these investments, it would be required to write off the applicable portion of regulatory assets and the financial effectscould be significant. . u
FERC Market-Based Rate Authority
IPC has FERC-approved market-based rate authority, which permits IPC to sell electric energy at market-based rates rather than
cost-based rates. The FERC requires periodic reviews of the conditions under which this market-based rate authority is granted to ensure
that the rates charged thereunder are just and reasonable. On April 14, 2004, the FERC issued an order commencing a market power
analysis of all companies with market':'based rate authority; including IPc. In September 2004, IPC filed a revision of its previously
approved (October 9, 2003) market power analysis, which it supplemented in September and October. On March 3 , 2005, the FERC
issued an order accepting IPC's market power analysis. IPC is required to file another market power analysis on or before March 3, 2008.
13. INVESTMENTS:
I FERC FORM NO.1 (ED. 12-88)Page 123.25
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 04/22/2005 2004/04
NOTES TO FINANCIAL STATEMENTS (Continued)
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
2004 2003
650
544 417
505 438
002 617
808
509 486
' ,
Equity Method Investments
IPC is the sole owner of Idaho Energy Resources Co. (IERCO). 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
2004
190
2003
048
Investments in Debt and Equity Securities
Investments in debt and equity securities are accounted for in accordance with SEAS 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
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.
Investments classified as held-to-maturity securities are reported at amortized cost. Held-to-maturity securities are investments in debt
securities for which the company has the positive intent and ability to hold the securities until maturity. These debt securities have
maturities ranging from 2005 through 2009.
The following table summarizes investments in debt and equity securities (in thousands of dollars):
2004 . 2003
Gross Gross Gross Gross
Unrealized Unrealized Fair Unrealized Unrealized
Gain Loss Value Gain Loss
. .
Fair
Value
Available-for-sale securities (IPC)530 $256 155 665 276 438
The following table summarizes sales of available-for-sale securities (in thousands of dollars):
2004.2003
Proceeds from sales
Gross realized gains from sales
Gross realized losses from sales
$ 266 331
044
634
040
046
169
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. A security will generally be written down to market value if it
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 04/22/2005 2004/04
NOTES TO FINANCIAL STATEMENTS (Continued)
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. IPC recognized other-than-temporary impairments of $0.6 million and $1 million in 2003 and 2002, respectively. These declines are
included in other income in the Consolidated Statements of Income. For 2004, it was determined there were no other-than-temporary
declines in market value.
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 AggregateUnrealized Related FairLoss Value
Less than 12 months
Aggregate AggregateUnrealized Related FairLoss Value
12 months or longer
2004:
Available for sale equity securities (IPC)181 934 362
2003:
Available for sale equity securities (IPC)200 577 359
The available-for-sale equity securities in unrealized loss positions are diversified investments in common stock of various companies used
to fund IPC's Senior Management Security Plan. The held-to-maturity debt securities in unrealized loss positions are mainly
yield-to-maturity bonds, whose market values fluctuate based on the interest rate environment.-...-\t December 31 , 2004, ten
available-for-sale and 14 held-to-maturity securities were in an unrealized loss position. At December 31, 2003, seven available-for-sale and
13 held-to-maturity securities were in an unrealized loss position. All unrealized losses were less than 20 percent. IPC has the ability and
intent to hold the equity securities for a reasonable period of time sufficient for a forecasted recovery of fair value and do not consider
these investments to be other-than-temporarily impaired at December 31, 2004 or 2003.
14. ASSET RETIREMENT OBLIGATIONS:
.-. ._---
On January 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. ...-\.n 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: \Vhen
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. -\S 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 IPU C. The regulatory assets recorded under this order do not earn a return on
investment.
IPC performed detailed assessments of the applicability and implications of SFAS 143 and identified AROs related to two of IPC's joindy
owned coal-fired generation facilities and IPC's transmission and distribution facilities. Upon adoption, IPC recorded an ARO of $7
million, fixed assets of $2 million, accumulated depreciation of $1 million and a regulatory asset of ~6 million. These amounts do not
include an amount for the transmission and distribution facilities, because; based on the indeterminate life of these assets, an ARO
calculation cannot be made.
The regulated operations of IPC also collect removal costs in rates for certain assets that do not have associated Mas. The adoption of
SFAS 143 required IPC to redesignate these removal costs as regulatory liabilities. As of December 31, 2004, IPC had $148 million of such
costs recorded as regulatory liabilities on its Balance Sheet.
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 04/22/2005 2004/04
NOTES TO FINANCIAL STATEMENTS (Continued)
An ARO also exists for the reclamation of the Bridger Coal mine property, which is leased by Bridger Coal Company, an equity-method
investee ofIPc. .As Bridger Coal Company has a March 31 fiscal year end, it adopted SFAS 143 on Apri.l1 , 2003. Upon adoption of SF
143, IPC did not record a net change in its investment in Bridger Coal Company, as Bridger Coal Company also is applying regulatory
accounting, recording regulatory assets and liabilities instead of accretion, depreciation and,gains or losses.
The following table presents the changes in the aggregate carrying amoWlt of MOs (in thousands of dollars):
2004 2003
Balance at beginning of year 140
Amount recorded on adoption 743
Accretion expense 421 397
",.
Revisions in estimated cash flows 727
Balance at end of year 288 140
15. RELATED PARTY TRANSACTIONS:
IDACO RP
In exchange for the transfer of Energy 1farketing to IE in June 2001 , IPC received a partnership interest in IE, which was then transferred
to IDACORP in exchange for notes receivable from IDACORP totaling approximately $76 million. The notes receivable were due over
periods of one to ten years, bore interest at IDACORP's overall variable short-term borrowing rate and were paid in full in 2003.
IPC performs corporate functions such as f111ancial, 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 and 3 million in 2004 and 2003, respectively, for these services.
The following table presents IPe's sales to and purchases from IE for the years ended December 31:
Sales to IE
Purchases from IE
IDACOMM
IPC provides project management and engineering services to IDACO1Uvf. IDACO1fM: also pays joint use f~es to IPc.
charged to IDACOMM were $0.3 million and $0.3 million in 2004 and, 2003, respectively.
2004 2003
(thousands of dollars)$ 2 268
Total fees
. .
Ida-West
IPC purchases all of the power generated by four of Ida-West s hydroelectric projects. IPC paid $7 million per year in 2004 and 2003.
I FERC FORM NO.1 (ED. 12-Page 123.
This Page Intentionally Left Blank
Name of Respondent This R ort Is: Date of Report Year/Period of Report(1) An Original (Mo, Da. Yr) End 2004/04Idaho Power Company (2) LJ A Resubmission 04/22/2005
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
No.
Item
(a)
1 Balance of Account 219 at Beginning of
Preceding QuarterlY ear
2 Preceding QuarterlY ear Reclassification
from Account 219 to Net Income
3 Preceding QuarterlY ear Changes in Fair
Value
4 Total (lines 2 and 3)
5 Balance of Account 219 at End of
Preceding QuarterlY ear / Beginning of
6 Current QuarterlY ear Reclassifications from
Account 219 to Net Income
7 Current OuarterlYear Changes in Fair Value
8 Total (lines 6 and 7)
9 Balance of Account 219 at End of Current
QuarterlY ear
CJ::DI" I:I"'IDII 11.11"'1 .. II\JJ::\AI n&Ln?\
Unrealized Gains and
Losses on Available-
for-Sale Securities
(b)
Foreign Currency
Hedges
Other
Adjustments
Minimum Pension
Liability adjustment
(net amount)
(c)(d)(e)
133,481 975.642
166.576
976,593)
810,017)
330,059
330,059
676.536)305,701
195,783
057.039)
861,256)
880.135)
880.135)
537 792)5,425,566
'- .
D..,.... .. ??.
Name of Respondent This ~ort Is: Date of Report Year/Period of Report(1) ~An Original (Mo, Da. Yr) End of 2004/04Idaho Power Company (2) A Resubmission 04/22/2005
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
Line
No.
" j
Other Cash Flow
Hedges
Interest Rate Swaps
Totals for each
category of items
recorded in
Account 219
(h)
109,123
166,576
646,534 )
4,479,958)
629,165
195,783
937,174)
741,391)
887 774
Other Cash Flow
Hedges
(Specify)
(f)
(g). _..-. ...
FERC FORM NO.1 (NEW 06-02)P~nA 122h
Net Income (Carried
Forward from
Page 117, Line 72)
Total
Com prehensive
Income
(i)
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) A Resubmission 04/22/2005
SUMMARY 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.
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2004/04
(a)
Total Company for the
CuITent YearlOuarter Ended
(b)
Electric
(c)Line
No.
Classification
Utility Plant
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
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
282,135
316,124,554
325 270,233
325,270,233
635.710
151,651,719
454,449
3,479,103.213
316,124,554
162,978,659
282,135
316,124,554
\ .
325,270,233
325,270.233
635.710
151.651,719
454,449
3,479,103,213
316,124,554
162,978,659
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) (22,26.31,32)
~~~r. F=nRM NO 1 fI:n 12.R~\Page 200
Name of Respondent
Idaho Power Company
This ~ort Is: Date of Report(1) ~ An Original (Mo, Da. Yr)(2) A Resubmission 04/22/2005
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Other (Specify) Other (Specify) Other (Specify)
Year/Period of Report
End of 2004/04
Gas Common
(d)(e)(f)(h)
J:J:~r J:n~M NO IF=n 17-R~\Pace 201
Line
No.
- 20
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1 ) An Original (Mo, Da, Yr)End of 2004/04(2) DA Resubmission 04/22/2005
ELECTRll, 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)
....
ine Account Balance Additions
No.Beginning of Year
(a)(b)(c)
1. INTANGIBLE PLANT
(301) Organization 703
(302) Franchises and Consents 9,431,537 737,485
(303) Miscellaneous Intangible Plant 62,357,443 594,415
TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)794 683 331,900
2. PRODUCTION PLANT
A. Steam Production Plant
(310) Land and Land Rights 282,073
(311) Structures and Improvements 129,615,530 387,606
(312) Boiler Plant Equipment 460 580,217 15,907 337
(313) Engines and Engine-Driven Generators
(314) Turbogenerator Units 112,666,050 949,232
(315) Accessory Electric Equipment 081,431 25,543
(316) Misc. Power Plant Equipment 12,469,665 290,505
(317) Asset Retirement Costs for Steam Production 060,293 714 827
TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)779,755,259 275,050
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 13,935,724
(331) Structures and Improvements 127,904,128 250,581
(332) Reservoirs, Dams, and Waterways 242,747,168 723,010
(333) Water Wheels, Turbines, and Generators 184,436,422 327,214
(334) Accessory Electric Equipment 35,567,465 835,885
(335) Misc. Power PLant Equipment 13,921,838 278,599
(336) Roads, Railroads, and Bridges 933,691 16,739
(337) Asset Retirement Costs for Hydraulic Production
TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34)625,446,436 4,432,028
D. Other Production Plant
(340) Land and Land Rights 219,037
(341) Structures and Improvements 1 ,207,423
(342) Fuel Holders, Products, and Accessories 676,666
(343) Prime Movers 765,800
(344) Generators 43,902,850 839
(345) Accessory Electric Equipment 1,484,491 693,056
(346) Misc. Power Plant Equipment 2,495,933 16,943
. 1
CCDI" cnD" ...n .. IDC\I
.. .,_
n':t\P:an"?n.4
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1 ) An Original (Mo, Da, Yr)End of 2004/04(2) DA Resubmission 04/22/2005
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 date
Retirements Adjustments Transfers Balance at Line
End ~f Year No.(d)(e)(f)
703
10,169.022
372.019 579,839
372,019 76,754,564
282,073
130,003,136
476,487,554
116,615,282
61,106,974
546 12,692,624
775,120
67,546 800,962,763
13,935,724
006 129,090,703
64,632 243,405,546
411 206 185 352,430
203,428 36,199,922
217 166,220
950,430
777,489 629,100,975
219,037
207 423
676,666
765,800
43,894,011
177,547
512.876
CeDI" cnDU ~n 1 /DCV 1 ?_n':\\P~n,"?n~
. Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1 ) An Original (Mo. Da, Yr)End of 2004/04
(2) D A Resubmission 04/22/2005
ELECTRIC PLANT IN SERVICE (Account 101,102,103 and 106) (Continued)
....ine 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)51,752,200 701 160
TOTAL Prod. Plant (Enter Total of lines 16, 25,35, and 45)1,456,953,895 26,408,238
3. TRANSMISSION PLANT
(350) land and Land Rights 21.544,591 864,639
(352) Structures and Improvements .. d. .31.091,076 244,279
(353) Station Equipment 212,659,800 16,981 383
(354) Towers and Fixtures 66,963,061 690,407
(355) Poles and Fixtures 88,514 840 719,921
(356) Overhead Conductors and Devices 105,794,879 851,156
(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)526,886.598 35.351,785
4. DISTRIBUTION PLANT
(360) land and Land Rights 856,375 519
(361) Structures and Improvements 16,411 ,186 337,987
(362) Station Equipment 127,254,783 272,139
(363) Storage Battery Equipment
(364) Poles, Towers, and Fixtures 180,886,200 171,179
(365) Overhead Conductors and Devices 94,018,650 089,880
(366) Underground Conduit 35.554,518 753,303
(367) Underground Conductors and Devices 136,740,442 11,821,122
(368) Line Transformers . 264;816,827 19,261,035
(369) Services 46,992,042 385,991
(370) Meters 40,201 148 021,048
(371) Installations on Customer Premises 284,690 234 712
(372) Leased Property on Customer Premises
(373) Street Lighting and Signal Systems 961,700 51,941
(374) Asset Retirement Costs for Distribution Plant
TOTAL Distribution Plant (Enter Total of lines 60 thru 74)952,978,561 56,631,874
5. GENERAL PLANT
(389) land and Land Rights 601 230 12,206
(390) Structures and Improvements 58,714 075 884,680
(391) Office Furniture and Equipment 54,512,568 787,640
(392) Transportation Equipment 43,214 649 783,867
(393) Stores Equipment 971,547 42,959
(394) Tools, Shop and Garage Equipment 564,226 391,919
(395) Laboratory Equipment 879,874 761,848
(396) Power Operated Equipment 170,547 181,643
(397) Communication Equipment 25,337,886 572,265
(398) Miscellaneous Equipment 102,526 265,917
SUBTOTAL (Enter Total of lines 77 thru 86)212 069,128 16,684,944
(399) Other Tangible Property
(399.1) Asset Retirement Costs for General Plant
TOTAL General Plant (Enter Total of lines 87, 88 and 89)212,069,128 16,684,944
TOTAL (Accounts 101 and 106)220,682,865 140,408,741
(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)220,682,865 140,408.741
~r::D'" ~I"'\Da. 11.'1"\
"'
ID!:\I
"".
n'2\P::an",?nf\
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/22/2005
ELECTRIC PLANT IN SERVICE (Account 101 102,103 and 106) (Continued)
Retirements Adjustments Transfers Balance at Line
(d)(e)(f)
End ~f Year No.
52,453,360
845 035 1,482 517,098
22,409,167
28,117 307,238
332,399 228,308,784
80,221 76,573,247
309,685 925,076
184 774 111,461,261
318,351
935,259 560 303,124
054 18,722,119
676,851 129 850,071
294,426 185,762,953
972,409
--.
- 94-,-136,12.
93,924 39,213,897
745,979 147 815,585
095,884 272,981,978
193,848 46,412,203
765,563 47,456,633
35,720 2,483,682
44,694 968,947
362,237 992,248,198
51,178 562,258
392 033 206,722
292 854 52,007,354
167 348 831,168
593 006,913
123,549 832,596
411,692 230,030
567 324 623
809,426 26,100,725 85
23,583 344 860
15,306,823 213,447,249
15,306,823 213,447,249
35,821,373 325,270,233
35,821,373 325,270,233
I=I=~r I=n~M tJn 1 (~I=V 1?_P~nA ?n7
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1 ) An Original (Mo, Da, Yr)End of 2004/04(2) DA Resubmission 04/22/2005
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 Description arid Location Date Ori~inallY Included Date Expected to be used Balance at
No.Of Prorerty
in T is Account in Utiliw Service End of Year
(b)(c)(d)
Land and Rights:
Boise Operations Center 12/31/82 768.377
Production 229,433
Transmission Stations 360,819
Transmission Lines 73,987
Distribution Stations 755,054
Other Property:
Boise Operations Center 12/31/82 72,785
Boise Mechanical and Electrical Shop 12/31/01 000
Transmission Stations 12/31/81 178,094
Distribution Stations 150,161
Column B if no date listed it is various
Column C is unknown
Total 635,710
r .
I=I=Rr. I=ORM NO.1 11::0- 12-96\Page 214
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2004/04(2) nA Resubmission 04/22/2005
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 -
I No.
Electric (Account 107)
(a)(b)
BENNETT MOUNTAIN POWER PLANT C 079,528
ROLLUP RELIC COST BROWNLEE 26,189,523
ROLLUP RELIC COST HELLS CANYON 18,036,588
ROLLUP RELIC COST OXBOW 168,601
LCST0201 ADD T231, COWL LINE 719,258
HELLS CANYON RELICENSING OUTSI 583,911
RTSN0301 NEW SWITCHING STATION 092,174
ROLLUP RELIC COST LOW MALAD 748,987
LINE #470, 2ND 138KV LINE TO M 556,034
CAPITALIZED SPARE PARTS 2004 B 545,664
NAMPA - ADD 230KV TRANSFORMER 1 ,452,158
BRIDGER UNDISTRIBUTED WORK ORD 1,426,277
RIGHT OF WAY/PERMITTING BENNET 368,352
BOBN03021NSTALL 230 KV 60 MVA 243,820
TERR HELLS CANYON RELlCENSING-199,021
BMPR0301 BENNETT MT. POWER PLA 135,063
VALMY UNDISTRIBUTED WORK ORDER 103,199
ROLLUP RELIC COST UP MALAD 098,733
BOARDMAN UNDISTRIBUTED WORK OR 006,529
342 COST CENTER DELIVERY CAPIT 954 331
HCC ENGINEERING RELICESNING ST 871,633
598 COST CENTER DELIVERY CAPIT 786,255
418-COST CENTER DELIVERY CAPIT 706,031
EMS/ADVANCED APPLICATION PROJE 632,230
HCC SUPPORT - 2004 631,999
NAMPA TAP ROW ACOUISITION 596,352
CAPITALIZED SPARE PARTS 2004 0 575,124
COST CENTER 316 DELIVERY CAPIT 548,352
BRIDGER 2005C100 U2 3 4 SDCC H 531,189
GENERATION OVERHEADS 525,683
RELICENSING: HCC SEDIMENT & GE 511 338
HCC RELICENSING FISH2004 FEASI 490,010
REL-HCC SEDIMENTATION STUDIES 454,600
WO ONGOING HELLS CANYON RELICE 433,621
390 COST CENTER DELIVERY CAPIT 431 040
FSH-DEV. WHITE STURGEON CONSER 427 004
577 COST CENTER DELIVERY CAPIT
- -..-
424 967
BRIDGER 2005CO07 REWIND #2 MAl 424,311
360 COST CENTER DELIVERY CAPIT 422,001
HELLS CANYON COMPLEX 418,294
FISH2004 CAPITAL PAHSIMEROI SP 417,610
BRIDGER 2005CO03 U2 CONTROLS U 412,028
TOTAL 151,651,719
FERC FORM NO- 1 IED- 12-87\Paae 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 2004/04(2) n A Resubmission 04/22/2005
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)
336-COST CENTER DELIVERY CAPIT 409,535
PAYROLL & IBNR ACCRUAL 402,675
HCC RESERVOIR/DISCHARGE WO 395,600
HELLS CANYON RELICENSING 390,653
RIGHT OF WAY. LINE 470, HORSE 383,997
FISH-HCC-REDBAND TROUT/BULL TR 364 283
COST CENTER 310 DELIVERY CAPIT 344 325
FISH-HELLS CANYON INSTREAM FLO 336,578
410-COST CENTER DELIVERY CAPIT 332,489
HCC RELICENSING, FISH2004 REDB 329,220
343 COST CENTER DELIVERY CAPIT 324,369
HRFT0201 NEW STN 322,838
CONTINGENCY FUNDS FOR VOICE AN 319,185
415-COST CENTER DELIVERY CAPIT 313,604
392 COST CENTER DELIVERY CAPIT 311,488
REL-HELLS CANYON COMPLEX FY200 310,442
324-COST CENTER DELIVERY CAPIT . 295,651
CALL CENTER LABOR HOURS FOR LI 291,147
REL - FLOW MODELING 290,710
CONSTRUCTION ACCOUNTING CAPITA 285,543
IPCO-RECONDUCTOR MIDVALE 011 F 284,468
NEW UNIT 8865 - ETHAN MORGAN -278,792
IPCO-RECONDUCTOR NWPM 011 4 MI 269 974
Delivery Overheads 269,832
BSU SECOND FEEDER-INSTALL SECO 262,707
HAILEY TEAM CAP OH WORK ORDER 262,302
BRIDGER 2005C068 REPL 01 RAW W 261,633
CMBG-012 REBUILD 6 MI 8A & 4 260,705
CHO PBX - EMERGENCY POWER EXTE 260,021
CAPITAL OVERHEADS FOR CADD & A 259,720
COST CENTER 320 DELIVERY CAPIT 257,669
IDAHO 252 ACCOUNT ADJUSTING EN 254,889
COST CENTER 270 TIME WORK ORDE 254,747
IPCO-RECONDUCTOR EMET 013 FROM 254 109
RELICENSING: SWAN FALLS 246,647
WO-HCC TMDU401-2003-CAPITAL 241 278
REL HCC BAKER COUNTY SETTLEMEN 239,698
COST CENTER 317 DELIVERY CAPIT 236,152
575 COST CENTER DELIVERY CAPIT 229,010
IPCO-KARCHER RD EXIT RELOCATIO 226,222
370 -COST CENTER DELIVERY CAPI 223,018
FISH-HCC-ANADROMOUS FISH BELOW 221,197
TOTAL 151,651 719
r "
.,..~ .
1.:.-
L ,
~J:~r. I=n~M ~n ,~n ?R7\P:!InA 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 2004/04(2) DA Resubmission 04/22/2005
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) maybe grouped.
Line Description of Project Construction work in progress -
No.Electric (Account 107)
(a)(b)
STKY 138KV SWITCHING STATION 219,046
404 COST CENTER DELIVERY CAPIT 215,981
BRIDGER 2005C094 REPL 11 FEEDW 212 334
COST CENTER 321 DELIVERY CAPIT 210,720
328-COST CENTER DELIVERY CAPIT 208,689
BRIDGER 2005CO02 REPL 21 FEEDW 203 265
TELECOM/DATA TEAM - REMOTE ACC 200,507
REC-HCC RELICENSING PROCESS 200 318
420-COST CENTER DELIVERY CAPIT 197 771
HCC RELICENSING, FISH2004 ANAD 196,394
COST CENTER 318 DELIVERY CAPIT 195,841
MPSN0306 UPGRADE COMM FOR BMPR 195,402
HAILEY OPERATIONS DESIGN/CONST 188,690
TOOL EXP TRANS TO CONST 188,428
100-COST CENTER DELIVERY CAPIT 187 109
CHERRY STATION 184 010
REL - SWAN FALLS FY2004 CAPITA 180 746
152 COST CENTER DELIVERY CAPIT 180,347
337-COST CENTER DELIVERY CAPIT 180,279
BOARDMAN 21870 REWIND GENERA TO 178,952
334-COST CENTER DELIVERY CAPIT 178,948
HILEX POLY CO LLC-40 W 100 S/J 178 334
REPLACE T131 176,886
IPCO-POLE REPLACEMENT ON LINE 175,851
VMWARE ENVIRONMENT 174 970
DELIVERY CAPITAL OVERHEADS FOR 172 371
FIREWALL UPGRADE 170 048
NEW UNIT 6704 - LARRY ADAMS -168 626
159 COST CENTER DELIVERY CAPIT 168,363
UPGRADE CHO PBX TO NEW VERSION 167,646
326-COST CENTER DELIVERY CAPIT 166,534
ADAMSFAM TEAM CAP OH WORK ORDE 165,727
LINE #902, BOISE BENCH-MIDPOIN 163,842
GOODING TEAM CAP OH WORK ORDER 162,177
PURCHASE "FUEL CELL" FOR FOOTH 161,051
BOARDMAN 21670 REPL PRIMARY AI 160,282
BOARDMAN 21435 INSTALL NEW STA 159,455
TFEAST TEAM CAP OH WORK ORDER 159,362
335-COST CENTER DELIVERY CAPIT 159,248
455-COST CENTER DELIVERY CAPIT 157 729
LINE #438 CDAL-LCST IMPROVE RO 157,660
327-COST CENTER DELIVERY CAPIT .157,527
TOTAL 151,651 719
I:I::DI' I:nDIl fI..n of tl:n ""'-$17\D"",... ?1R?
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/22/2005
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 157,436
TWINWEST TEAM CAP OH WORK ORDE 157,232
OREGON REAUTHORIZATION - HELLS 153,550
PTSN -INSTALL 230 KV SHUNT CA 151,303
NEXUS ENERGY SOFTWARE IMPLEMEN 150,747
PASSPORT ICF BO'S:MR. CATALOG,146,413
375 COST CENTER DELIVERY CAPIT 146,244
GLANBIA FOODS INC-1572 E HIGHW 143,309
REL-HCC OREGON REAUTHORIZATION 142,246
NEW UNIT 8866 - BRET JUDY - BO 140,518
WO-HCC MITIGATION-RESERVOIR AE 139,632
SOX SOFTWARE PROJECT 139,313
BRIDGER 2001CO04 U2 COUTANT SL 138,699
210-COST CENTER DELIVERY CAPIT 136,794
LINE #912, BOISE BENCH-MIDPOIN 134,303
TERR HELLS CANYON COMPLEX TRAN 131,925
MISCELLANEOUS DELIVERY HARDWAR 130,371
FISH-MALADS FISH PROJECTS-2002 129,943
SWAN FALLS RELICENSING INITIAL 126,767
LINE 438, RIGHT OF WAY, VICTOR 125,832
IPCO* INSTALL SPOILERS- LUCKY 122,889
OXBOW HATCHERY CAPITAL EXPANSI 122,154
FISH-HCC-RESIDENT FISH-2003-119,505
BRIDGER 2006CO03 U2 REHEATER L 119,505
MINI CASSIA TEAM CAP OH WORK 0 119,395
VILLAGERS 2004 CHANGE OUT VAUL 119,268
WO-HCC MITIGATION-TURBINE VENT 119,151
COST CENTER 290 DELIVERY CAPIT 118,993
STORAGE - ADD MAINFRAME TO SAN 117,997
REC-SWAN FALLS RELICENSING PRO 117 674
CORRECTION WORK ORDER FOR BOC 117 546
MID-SNAKE SUPPORT (PM&E) 2004 117 ,332
377 -COST CENTER DELIVERY CAPI 116,751
REL - GEOMORPHOLOGY 115,986
NEW UNIT 6698 - DAN SCHLEDEWIT 115,765
BRIDGER 2001CO04 U2 & 3 BURNER 115,493
CLIENT SVRS MGR - MICROSOFT PR 115,480
NEWMAN GROUP - OMS/GIS SERVER 114,883
HCC REUCENSING FISH2004 RESID 114 823
BUHL0204 RESOLVE BUS CLEARANCE 113,687
STORAGE MANAGEMENT SOFTWARE 113,566
SRCK INSTALL SCADA 111,170
TOTAL 151,651,719
r .
L .
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I:CCf" cncu...n 1 ,cn 1 ?_R7\P;lnA 216_
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1 ) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/22/2005
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)
NEW UNIT 6699 - DAN SCHLEDEWIT 110,922
IPCO/ETGT-011 BUILD NEW FEEDER 110,878
378 -COST CENTER DELIVERY CAPI 109,859
REPLACE UNIT TRASH RACK 109,525
PAHSIMEROI HATCHERY-CAPITAL-109,345
576 COST CENTER DELIVERY CAPIT 106,694
PURCHASE AND INSTALL AN ADDITI 103,765
BORA 345KV CIRCUIT SWITCHER RE 101,877
FISH-HCC-FEASIBILITY OF REINTR 101,254
NORTHRIDGE IX SUBD.75-LOTS ON 101,186
CH06 REMODEL TENANT SPACE 101 116
NEW UNIT 6701 - GUY JOHNSTON -100,882
431-COST CENTER DELIVERY CAPIT 100,580
OTHER MINOR WORK ORDERS 393,765
--.._..
TOTAL 151 651,719
I:I:Dr z:nDU ~n 11:1"\ 1 ?_R7\Pace 216_
Name of Respondent This i!Jort Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) An Original.(Mo, Da, Yr)End of 2004/04
(2) Fi A Resubmission 04/22/2005
ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108)
Explain in a footnote any important adjustments during year.
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.
Section A. Balances and Changes During Year
Line Item !;:8~~)~lc t'lant In eleCtriC t-"Ian~ HelC t::lec~lc I ~(WntNo.ervlce for Future Use Lease to thers
(a)(b)(c)(d)(e)
1 Balance Beginning of Year 205,223,473 205,223,473
Depreciation Provisions for Year, Charged to
3 (403) Depreciation Expense 90,986,890 90,986,890
(403.1) Depreciation Expense for Asset
Retirement Costs
(413) Exp. of Elec. PIt. Leas. to Others
Transportation Expenses-Clearing
Other Clearing Accounts 2,494,007 2,494,007
Other Accounts (Specify, details in footnote):
Acct 151 Fuel Stock 108,409 108,409
TOTAL Deprec. Prov for Year (Enter Total of 93,589,306 93,589,306
lines 3 thru 9)
Net Charges for Plant Retired:
Book Cost of Plant Retired 982,230 982,230
Cost of Removal 832,015 832,015
Salvage (Credit)970,889 70889
, "",.)",,
TOTAL Net Chrgs. for Plant Ret. (Enter Total 31,179,326 179,326
of lines 12 thru 14)
IItiii~l\i'11Other Debit or Cr. Items (Describe, details in 4,454 047 " '454'1141.
footnote):
Book Cost or Asset Retirement Costs Retired
Balance End of Year (Enter Totals of lines 1 1 ,272 087,500 1 ,272,087,500
10, 15, 16, and 18)
Section B.Balances at End of Year According to Functional Classification
Steam Production 385,155,364 385,155,364
Nuclear Production
Hydraulic Production-Conventional 217 545,265 217,545,265
Hydraulic Production-Pumped Storage
Other Production 664 338 664,338
Transmission 196,980,645 196,980,645
Distribution 385,008,939 385,008,939
General 81,732,949 8"1 732,949
TOTAL (Enter Total of lines 20 thru 27)272,087 500 272,087,500
"". "
t .
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!:~D'" !:I"\DU "11"\ 1 ID!:\I Ln':l\P:ana ?10
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 04/22/2005 2004/04
FOOTNOTE DATA
!,schedule Page: 219 Line No..14 Column:
elocation reimbursements, Up and Down costs and damage and insurance claims $266,766.
~chedu/e Page: 219 Line No.16 Column:
Accumulated Provision for Depreciation on Asset Retirement
Embedded removal in Accumulated Provision for Depreciation
Disallowed capital cost from the 2003 Idaho rate case
Total
Obligation $ (483,665)$ 5,104,848$ (9,075,230)
$ (4,454,047)
I FERC FORM NO.1 (ED. 12-Page 450.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2004/04(2) nA Resubmission 04/22/2005
INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.
1. Report below investments in Accounts 123.1, 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
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.
ILine Description of Investment Date Acquired Date Of Amount at Investment at
No.(2fity
Beginning of Year(a)(b)(d)
Idaho Energy Resources Company
Common Stock 02/01/74 500
Capital contributions 2,462,594
Equity in earnings 954,085
Subtotal Idaho Energy Resources 27,417 179
po_,
liT otal Cost of Account 123.1 $2,463,0931 TOTAL 27,417 179
, -
L '
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gO\P::an~ ??A
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da. Yr)
End of 2004/04(2) DA Resubmission 04/22/2005
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 (f).
8. Report on Line 42, column (a) the TOTAL cost of Account 123.
Equity in Subsidiary Revenues tor Year Amount of Investment at Gain or Loss from Investment LineEamin
1s of Year (f)
End ~f Year DiSP
?ised of No.
500
2,462 594
127,301 34,081 386
127 301 36,544,480
127 301 36,544,480
CCD,.. cnD.. "11"\ of Icn of ,,)_GO\C""..... ")").:
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)2004/04(2) D A Resubmission 04/22/2005 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)228,205 6,450,733 Electric
Fuel Stock Expenses Undistributed (Account 152)
Residuals and Extracted Products (Account 153)
Plant Materials and Operating Supplies (Account 154)
Assigned to - Construction (Estimated)
Assigned to - Operations and Maintenance
Production Plant (Estimated)899,572 10,372,441
Transmission Plant (Estimated)631,113 805,201
Distribution Plant (Estimated)057 507 10,171,811
Assigned to - Other (provide details in footnote)200,134 29,324
TOTAL Account 154 (Enter Total of lines 5 thru 10)18,788,326 25.378,777 Electric
Merchandise (Account 155)
Other Materials and Supplies (Account 156)
Nuclear Materials Held for Sale (Account 157) (Not
applic to Gas Util)
Stores Expense Undistributed (Account 163)966,741 685,830 Electric
32,515,340TOTAL Materials and Supplies (Per Balance Sheet)25,983,272
! .; .
FERC FORM NO.1 (ED. 12-96)Page 227
This Page Intentionally Left Blank
! .
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1 ) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/22/2005
EXTRAORDINARY PROPERTY LOSSES (Account 182.
Line Description of Extraordinary Loss Total Losses WRITTEN OFF DURING YEAR Balance atNo.(Include in the description the date of Amount Recognised AccountCommissio~ Authorization to use Acc 182.of Loss During Year Amount End of Yearand period 0 amortization (mo, yr to mo, yr).Charged
(a)(b)(c)(d)(e)(f)
None
TOTAL
. .\ :, ...
... ... ... ,... po .... ... . .
.. . .... .. / """ ... ....... .. \
P~na 230a
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1 ) An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/22/2005
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 Year
Commission Authorization to use Acc 182.Charged
and period of amortization (mo, yr to mo, yr))(f)(a)(b)(c)(d)(e)
None
26 .
TOTAL
, . ,---- ---..
u...., ..
",- ..'" "..,
Paae 230b
Name of Respondent This
wort
Is:Date of Report YearlPeriod of Report
Idaho Power Company (1 ) An Original (Mo, Da, Yr)End of 2004/04(2) nA Resubmission 04/22/2005
OTHER REGULATORY ASSETS (Account 182.
1. Report below the particulars (details) called for conc~rning 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 vvnnen OfT uunng vvnnen OfT uunng Current QuarterN ear
Current the QuarterN ear the Period
OuarterN ear Account Charged Amount
(a)(b)(c)(d)(e)(f)
Meridian Periodic Payments - IPUC 6,455 677 783,462 108 866,646 372,493
order#25533(amort period 1/96 thru 12/03)
Postretirement Benefits - IPUC order #25550 590,200 401 544 800 45,400
(amort period 2/95 thru 01/05)
Reorganization Costs -IPUC order 26216 508,112 401 754,057 754 055
OPUC order #95-1262 (amort 01/96 thru 12/05)
Regulatory Unfunded Accumulated Deferred Income Tax 330 832,743 15,339,388 282 952 556 344 219,575
Power Cost Adjustment -IPUC order #27516 58,309 992 79,238,072.'.F08tnb~.'
. .
103,538,693 34,009 371
(amort period 5/01 thru 05/02)
Idaho - Demand Side Management - IPUC order 076,955 401 242,604 834 351
#27660 (amort period 7/98 thru 6/10)
FAS112 Post Employment Benefits 402,536 401 371 508 31,028
(Amort period 4/03 thru 3/04)
Excess Power Amortization - Oregon 13,620 313 016,865 401 589,681 12,047,497
(Amort period $1.6 mill per yr until full amort)
Security Costs 2001-2002 728,766 527#b6tTiOt~'
.. . """'
219,899 553,394
(Amort period 1/03 thru 12/07)
""""'"""",,"""""'" ..... ....... ..... ..... ............... ...
Security Costs -Incremental
. .... ...
259,783FOOtnOte
"""""" .
347 339
... ." .... .. ....
539,260451,704.
Professional Fees - IPUC order #29505 80,110 4073 19,944 166
(Amort Period 1-03 thru 12-07)
IPUC Order 29601 118,562 N/A 118,562
(Amort Period 6/05 thru 5/06)
Power cost Adjustment - IPUC Order 29670 182,954 N/A 182,954
(Amort Period 6/05 thru 5/06)
Irrigation Lost Revenue -IPUC Order 29669 13,289,763 N/A 13,289,763
(Amort Period 6/05 thru 5/06)
Minor items (2)155,834 114 865 Various 268,263 2.436
TOTAL 434,028,467 121 660,272 116,907,911 438,780 828
I;'
. .
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---- ---....- ~.- - .'--" --....
D....... ')"2')
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 04/22/2005 2004/04
FOOTNOTE DATA
!Schedule Page: 232 Line No.
401 51 610 165.253 2,000,000.
254 5 629 167.
1823 44 285,289.4210 14 073.
103 538 694.
!Schedule Page: 232 Line No..401 215,448.4210 1 083.4171 3,368.
219 899.
Column: d
Column: d
!schedule Page: 232 Line No.401 88,975.1823 352,412.131 94 318.4210 864.232 2,691.
539,260.
Column: d
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent
Idaho Power Company
This ~ort Is: Date of Report(1) I!J An Original (Mo, Da, Yr)(2) n A Resubmission 04/22/2005
MISCELLANEOUS DEFFERED DEBITS (Account 186)
1. Report below the particulars (d~tails) called for conc~rning 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.
Year/Period of Report
End of 2004/04
(a)
Regional Transmsn Org - (RTO)
3 Advance prepaid coal royalties
Benefits plan - intangible asst
Security Plan
American Falls bond refinance
11 Expense of Issue
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 Floating Rate Note
33 Irrigation Lost Revenue.
35 Minor Items & Job Orders (4)
37 Humbolt Refinance
39 Valmy Power Plant
41 Customer Svcs Finance Program
43 Stock Valuation
(b)
558,394
(c)
~ccounfCharged
(d)
651 292 '
..
Footnote;':
CREDITS
Amount
(e)
Balance at
End of Year
Line
No.
Description of Miscellaneous
Deferred Debits
Balance at
Beginning of Year
Debits
958,572
(f)
251,114
374 674 131 197,845 176,829
933,273 253 251,449 681 824
27,546,101 237,436 426 607,711 28,175,826
308 023 059 401 20,612 293,470
128 785 190,780.Footnote 319,565
077 714 140,689 426 628,865 589,538
19,885,000 19,885,000
11,700 000 11,700,000
255,403 30,703 286,106
( .
820,481 143 431 220 389,261
015,981 401 999 967 982
151 875 151,875
. --- .
135,273 Fodtnote;;iJiI;'551 896 583,377
015,187 182 12,015,187
295 33,206,710 .f;ddtOof~j;;33,157,435 20,980
722 096 549 ;EoQtnofe;'729,645
195,407 830,801 401 046,670 20,462
371 793
.. . .... .
251 ,730 nFootnofe'i;;;483,393 140,130
25,000 214 25,000
47 Misc. Work in Progress
48 I Deterred Regulatory Comm.Expenses (See pages 350 - 351)
49 TOTAL 98,056,892 83,272,850 l -
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.t I~"" .t., nA\D__-
........
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Oa, Yr)
Idaho Power Company (2)A Resubmission 04/22/2005 2004/04
FOOTNOTE DATA
chedule Pa e: 233 Line No.Column: d
232 18,867
124 752,309
401 187 396
958,572
chedule Pa e: 233 Line No..Column: d
186 143,017
146 176,548
319,565
chedule Pa e: 233 Line No.Column: d
181 524,419
232 073
401 23,404
551 896
chedule Pa e: 233 Line No.Column: d
131 951 173
142 151 ,166
232 35,586
186 104
141 395
401 . 8,011
157,435
Is.chedule Pa e: 233 Line No.Column: d
181 698,285
186
401 333
729,645
chedule Pa e: 233 Line No.Column: d
131 252,406
141 207,943
142 23,044
483,393
IFERC FORM NO.1 (ED. 12-Page 450.
Nam e of Respondent
Idaho Power Company
This ~ort Is: Date of Report(1) ~ An Original (Mo, Da, Yr)(2) A Resubmission 04/22/2005
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.
Yeat/Period of Report
End of 2004/04
(.,
ine
No.
escription an ocation
, ,
(a)
Electric
Advances for Construction
3 FASB 109 Accounting
162,170
41,023,911
357,402
40,447 291
Other
TOTAL Electric (Enter Total of lines 2 thru 7)
Gas
45,186 081 45,804 693
, ,
Other
TOTAL Gas (Enter Total of lines 10 thru 15
.~m ~.t~efi~fY):.;;". 8.~~Dqt~'dt; .t?elb
~;:.
ji.'
TOTAL (Acct 190) (Total of lines 8,16 and 17)
151 050
337 131
907,422
72,712 115
r .'
Notes
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FFRr'. F=ORM ,NO 1 lI::n 17.RR\Pace 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 04/22/2005 2004/04
FOOTNOTE DATA
~chedule 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
FERC Settlement Reserve
SFAS112 - Post Retirement Benefits
Non-VEBA Pension and Benefits
Post Retiree Benefits-VEBA
SHOBAN Transmission Right of Way Expense
Restricted Stock Plan
Meridian Gold Contributions
Dark Fiber Contracts
Seattle City Light-CIAC
. Start-up and Organization Costs
Other Regulatory Liabilities
Loss on Pioneer Lando Write-down
SMSP-Market Change of Rabbi Investments
Bonus Deferral
Beginning Balance
144 234.
047 637.
959,943.40
241 098.47
563 799.
112 094.41
950,421.
344 118.
98,934.
263,239.
111 819.
681.
532 014.
351.
223 334.
562 673.52)
16,151 049.
Ending Balance
977 022.
3,482 677.
3,432,123.
717 223.
346,499.
781 899.
157,159.
926 069.
867 674.
339,874.
275,928.
241 ,127.
101 285.
80,030.
75,446.
999.
351.
026.
26,907,421.
I FERC FORM NO.1 (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 2004/04(2) 0 A Resubmission 04/22/2005
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 (i.e., 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 50,000,000
and Pacific Stock Exchange
Total Common Stock 50,000,000
Account 204
On September 20.2004 the company redeemed
all of its outstanding preferred stock
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Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2004/04(2) DA Resubmission 04/22/2005
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 REACOUIRED STOCK (Account 217)IN SINKING AND OTHER FUNDS No.for amounts held by respondent)
Shares Amount Shares ~ost Shares Amount(e)(f)
(g)
(h)(i)
41,458,503 97,877,030
41,458,503 97,877 030
r-r-........ po,.......
........ .. ,..... ............- -- ...""..
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2004/04(2) DA Resubmission 04/22/2005
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.
Ljne (~r AmountNo.(b)
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
TOTAL
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FERC FORM NO.1 (ED. 12-87\Pa~e 253
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo. Da, Yr)End of 2004/04(2) n A Resubmission 04/22/2005
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.
Tine Class and Series of Stock Balance at End of Year
No.(a)(b)
Common Stock 096 925
Preferred Stock:(1)
Explanation of Changes during the year:
(1) On September 20,2004 the company redeemed all of its oustanding preferred stock.
See note on pages 122.5 thru 123.6 for additional information.
. -.. --
22 TOTAL 096,925
~~n'" ~I"'\n.. ..11"'\ 041 '~I"\ 041'" D"P\D__- ~J::AI""
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1 ) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/22/2005
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. 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 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)
Account 221:
First Mortgage Bonds:
50% Series due 2033 70,000 000 728,701
36,400 D
38% Series Due 2007 80,000 000 807,871
- ,'-'
20% Series due 2009
-- -
80,000,000 572,246
00% Series due 2004 50,000 000 463,337
400,000 D
83% Series due 2005 60,000,000 508,801
60% Series due 2011 120,000,000 ,860,502
25%Series due 2013 70,000,000 641 201
374 500 D
75% Series due 2012 100,000,000 944,356
047 617 D
00% Series due 2032 100,000,000 069,356
543,244 D
50% Series due 2034 (Idaho IPC-03-3, Oregon UF 4196,55,000,000 524,419
Wyoming 2005-es-03-24)383,322 D
875 Series due 2034 (idaho IPC-03-3, Oregon UF 4196 50,000,000 746,961 D
Wyoming 2005-es-03-24)
Pollution control Revenue Bonds
05% Series 96A due 2026 68,100,000 571,895
TOTAL 038,959,184 15,830,530
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S::S::l:Pr s::nI:PM....n 1 IS::" 1 ?QR\D--- -'C.c:!
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1 ) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/22/2005
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 uutstarKfjn 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 Amountresp~ndent)(d)(e)(f)
(g)
(i)
05-01-04-01-05-01-03-31-70,000 000 850.000
12/1/00 12/1/07 12/1/00 12/1/07 80,000,000 904,000
7 "-
11/23/99 12/1/09 1/1/00 1/1/10 80,000,000 760,000
03/25/92 03/15/04 03/21/92 03/15/04 833,333
09/09/98 09/09/05 09/09/98 09/09/05 60,000,000 3,498,000
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 70,000,000 975,000
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 55,000,000 100,694
3/26/04 3/15/34 3/26/04 3/15/34 50,000,000 1 ,218,488
07/25/96 07/15/26 07/25/96 07/15/26 68,100,000 120,050
987,045,000 50.317 585
1:1:1)(' s:nl)u ~n 1 n::n 1?_QR\D-_-
.,~.,.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2004/04(2) DA Resubmission 04/22/2005
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. 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 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)
471 252 D
Series 96B due 2026 24,200,000 124 587
Series 96C due 2026 000,000 123,561
Port of Morrow Variable due 2027 360,000 188,545
Humboldt Variable due 2024 49,800,000 1 ,697,856
Subtotal Account 221 1 ,005,460,000 15,830,530
Account 224:
Other Long-Term Debt
Bond Guarantee - American Falls 19,885,000
Note Guarantee - Milner Dam 700,000
REA Notes 914,184
Subtotal Account 224 33,499,184
Account 222 - Reacquired Bonds
Account 223 - Advances from Associated Com panies
TOTAL 038 959,184 15,830,530
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Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1 ) An Original (Mo, Da, Yr)End of 2004/04
(2) CIA Resubmission 04/22/2005
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 uutstanCfin 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 Amountresp~ndent)(d)(e)(f)
(g)
(i)
07/25/96 07/15/26 07/25/96 07/15/26 24,200,000 326,149
07/25/96 07/15/26 07/25/96 07/15/26 24,000,000 320,419
5/17/00 2/1/27 5/17/00 2/1/07 360,000 95,954
1 0/22/03 12/01/24 11/01/03 12/01/24 49,800,000 624 173
955,460,000 50,296,260
-....
4/26/00 2/1/25 19,885,000
02/1 0/92 11,700,000
325
31,585,000 325
987,045,000 317 585
FFRr. FORM Nn 1 IFn 1 ?QR\D"",..u.. ')1:;:7 1
Nam e of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/22/2005 2004/04
FOOTNOTE DATA
!schedule Page: 256 Line No.10 Column.' h
edeemed March 2004.
!schedule Page: 256.Line No.19 Column: h
Redeemed August 2004.
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IFERC FORM NO.1 (ED. 12-Page 450.
Name of Respondent This R
(!J
ort Is: Date of Report YearlPeriod of Report(1) An Original (Mo, Da, Yr) End 2004/04Idaho Power Company (2) n A Resubmission 04/22/2005
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.Line Particulars (Details)No. (a)
1 Net Income for the Year (Page 117)
4 Taxable Income Not Reported on Books
5F.ootQ9t~1'~
::; .' "
1/.
Amount
(b)
70,608 121
""""""" "::::",.",..
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""""':,:".)"',),::,'",.
28,759,330
9 Deductions Recorded on Books Not Deducted for Return
10 - .:;i!, i
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14 Income Recorded on Books Not Included in Return
~"""""""
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;;.::
;;.;;,J:!lil'11;;;f!:f:;17 ,526,153
",""
19 Deductions on Return Not Charged Against Book Income:jMi 35,391 378
27 Federal Tax Net Income
28 Show Computation of Tax:
29 Tenative Federal Tax ~ 35%
73,398,445
25,689,456
FERC FORM NO- 1 IED- 12-96\Pace 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 04/22/2005 2004/04
FOOTNOTE DATA
'Schedule Paqe: 261 Line No.Column:
004003-CONS i RUC ; ION AOV-252 3,414 950
0O4004-CiAC AS TAXABLE iNC CLOSED TO PLANT 000,000
004005-AVOIOEO COST INT CAP 2.492,873
004013-CIAC TAXABLE INCOME IN ACCT 107 149,933
004016-CIAC TAXABLE INCOME-ACCT 253.575 436,910
004017-JOIN I USE FEE REC'O B4 INC (85,768)
BOOKED-253.050
004501-ROYAL TY iNCOME 109 150
004506-CIAC-tv1!::RIDIAN GOLD (56,560)
004507 -CIAC-MI CRON- DRAM (620,846)
004512-CIAC-SEA I TLE CiTY LIGHT-NEW
(81 312)
Total 28,759 330
ISchedule Page: 261 Line No.Column:
Total Federal and State taxes deducted on books 946,525
005001-BAD Dt:BT EXPENSE (102 190)
005008-GAIN/LOSS ON REACQUIRED 549,856
DEBT-DEFERRED
00501 O-Si- AS 112-POST -EMPL Y BEN 182/253 115,271
005014-0VERACCRUED VACATION-ACCT 242 219.071
005017-iNJURIES & DAr\,1AGES 076,005)
005019-01RECTORS FEES DEF 209,465
005022-CAPIT AUZED OVERHEADS (10.450 000)
005023-PENSION ACCR i 0 926200 535,000
005024-MEALS (50% NON-DEDUCTIBLE) CHRGD TO 290,000
RE.
005025-MILNER FALLING WATER ;" REV ACCRL 264 100
005027-Arv10RTIZATION OF ACCOUNT 114 (22,723)
005028-0REGON OPER PROPERTY TAX ADJ (45,145)
0O5033-NONVEBA PEN&BEN-Acct 228 (62 291)
005035-PCA EXPENSE DEFERRAL 16,265.811
D05039-POST RETIREE BdJEF!T- r-AS106-ACCT 182 544,800
005042-REV SHOBAN TRANS ROW EXPENSE 869,355
005044-RESTRICTED STOCK PLAN-CaMP 452 729
GO5047-0THER EMPLOYEE'S L T DEFERRED COMP-228 385 347
005049-253-FERC SETTLEMENT RESERVE (2,000 000)
D05050-186-BAD DEBT RESERVE-FINANCING PRGMS (25,875)
005051-PUC ORDER 29505 - PROFESSIONAL FEES (60,166)
005501-SEC PLAN-NET INS COSTS (521.251)
005502-128-SMSP-MRKT CHG OF RABB! INVSTMNTS (553,286)
005503-128-i::DC-UNRLZD GNfLS i-Rrv1 RABBI TRUST (38 370)
005504-NONDEDUCTIBLE POLITICAL EXP-426.4 250,000
GOSSOS-SEC PLAN-BENEFf! ACCR 130.167
005516-NONDEDUCTIBLE POLITICAL EXP-O&M ACCTS 100,000
0O5518-STARTUP & ORGANIZATION COSTS (600)
0O5531-RATE CASE DISALLOWANCES 778,931
-L. c
Total 26,948,526
Schedule Page: 261 Line No.Column:
P07002-GAIN ON SALE OF BOC 31.970
~07007-0THER REGULATORY LlABILITIES-254 225 258
007501-REVERSE EQUITY EARNINGS OF 190,247
SUBSIDIARIES
007502-ALLOWANCE FOR OFUDC 904 027
0O7503-ALLOWANCE FOR BFUDC 952,809
I FERC 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 04/22/2005 2004/04
FOOTNOTE DATA
0O7504-RECLASS TAX EXEMPT INTEREST - FED &781
IDAHO
007504-RECLASS TAX EXEMPT INTEREST - FED ONLY 234 848
0O7514-COLl-INSURANCE PROCEEDS 9aO 213
Total 17,526,153
Schedule Page.261 Line No.Column:
OOaOO1-VEBA-POST RET BNFTS-TRUST-ACCT 165 339,189)
008009-DEPR FOR TAX GT OR L T BOOK 18,059.869
008020-CONSt:RVATION PROGRAMS 247 604)
008027-NEVADA OPERATING PROPERTY TAX ADJ (35,729)
008034-REMOV AL COSTS 553 551
0O8035-REPAIR ALLOWANCE 000.000
a08038-0REGON EXCESS PWR SUPPLY COSTS 672,816)
008039-S I TAX-NOT DEDUCTEDON PRIOR RE I URN 867
0O8041-AM FALLS - UNAMORTIZED DEBT EXP (47 999)
008042-GAIN/LOSS ON Rt:ACQUIRED DEBT-(643,139)
0O8045-ST TAX-AUDIT STTUVINTS PAID TH!S YR 506.827
008057-REORGANIZAT!ON COSTS-ACCT 182 (754 057)
0O8062-FERC ORDER 2000 cas; S (307.280)
0O8071-PHOTOVOL TAlC STARTUP COSTS-ACCT 182 (23,808)
008072-INTANGIBLE ASSET-LABOR DEDUCT-FED 514 000
ONLY
0O8074-iNCREMENTAL SECURiTY COSTS DEDUCTED (262 929)
0O8077-P? INS & OTR EXP (1 YR OR LESS)-165 181 677
0O8501-COLl-TAX ADJ FROM BOOKS (443,137)
008504-0REGON NONOP PROPERTY TAX ADJUST
0O8508-DEPRADJ - NONOP - OTHER PROPERTY -039
NEW
008533-iNTEREST ON IRS TN( DEFICIt:NCIES 2.227 113
ONiO016-DIV PAID Dt:D PUB UTIL 300,000
STATE INCOME TAX DEDUCTED ON FEDERAL 773,084
RETURN
Total 35,391,378
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1 ) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/22/2005
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 dur~ngthe 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.
lline Kind of Tax BALANCE AT BEGINNING OF YEAR J axes ~X~S Adjust-Charged aidNo.(See instruction 5)1 axes Accrued Prepaid Taxes ~nng ~ring ments .(Account 236)(Include In Account 165)ear ear(a)(b)(c)(d)(e)(f)
Federal:
Income 42,209,969 16,450,770 33,025,085
Social Security - (FOAB)164 357,712 020,330
Unemployment 138,4 78 105,011
Subtotal Federal 42,211 189 946,960 41,150,426
State of Idaho:
Property 935,957 675,885 12,298,341
Income 358,871 824 261 2,469,446
KWH 85,123 356,460 351,312
Unemployment 105,445 079
Regulatory Commission 642,858 642 858
Business License - Sho Ban 150 150 150
Subtotal Idaho 379,981 150 21,605,059 17,859,186
State of Oregon
Property 977 919 010,196 055,379
Income 135,775 337,835 524 846
Regulatory Commission 91,460 91,460
Unemployment 25,469 23,701
Franchise 111 677 461 080 452,376
Subtotal Oregon 247,452 977,919 926,040 147 762
State of Montana:
Property 38,746 80,322 78,953
Subtotal Montana 38,746 80,322 78,953
State of Nevada:
Property 238,828 477,657 920,201 902,337
Unemployment
Business Tax 588 588
Subtotal Nevada 238,828 477,657 920,864 902,991
State of Wyoming
Corporate License 719 719
Property 483,980 887,007 927,484
Subtotal Wyoming 483,980 889,726 930,203
misc states franchise
.-..
TOTAL 52,867,442 1,455,726 897 154 64,121,072
. '
f .
! .
FERC FORM NO.1 (ED. 12-96)Page 262
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2004/04(2) DA Resubmission 04/22/2005
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 ~ustments to ~et.Other No.Acco~nt 236)(Incl. in Account 165)(Account 408., 409.(Account 409.Earnings (Account 439)(h) (i)(k)(I)
25,635,654 16,305,814 It\..
338,547 357 712
33,523 138,478
26,007 724 24,802,004 144 956
313 501 11,675,885
713,686 783,393
90,271 356,460
396 105,445
642 858
150 150
11,125,854 150 21,564,191 40,868
023,101 010,196
948,764 335,737
91,460
768 25,469
120,381 461,080
070,913 023,101 923,942 098
40,115 441,929 80,322
40,115 441 929 80,322
220,963 920,201
588
220,972 920,864
443,504
719
887 007
443,504 889,726
40,280,158 1.465,180 42,708,532 188 622
FERC FORM NO.1 (ED. 12-96)Page 263
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
I daho Power Com pany (1 ) An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/22/2005
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 ~ccrued,
(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 kinQ of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
Line Kind of Tax BALANCE AT BEGINNING OF YEAR .I axes Adjust-Charged aidNo.(See instruction 5)1axes Accru~9 prepatd I axes ~nng ~ring ments(Account 236)(Include In Account 165)ear ear
(a)(b)(c)(d)(e)(f)
Other States Income 267 266 155,362 552
Payroll Adjustment 627 178
TOTAL 867,442 1,455,726 42,897 154 64,121 072
r .
f '
e' ~
'- -
I=FRC'- Fn.RM NO- 1 (ED. 12-96\P~nA 'f\~;t 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 2004/04(2) n A Resubmission 04/22/2005
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~nt 236)(Incl. in Account 165)(Account 408., 409.(Account 409.Earnings (Account 439)
(h)(i)
(j)
(k)(I)
371 076 154 662
---
627,178
40,280,158 1,465.180 42,708.532 188,622
FERC FORM NO.1 (ED. 12-96)Page 263.
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 04/22/2005 2004/04
FOOTNOTE DATA
!schedule Page: 262Account 409.Line No.Column: I
d';.
!schedule Page: 262
!schedule Page: 262
Line No.Column: I
Line No.Column: I
Line No.Column: I ~chedule Page: 262. 1
r '
I .
I FERC FORM NO.1 (ED. 12-87)Page 450.
This Page Intentionally Left Blank
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1 ) An Original (Mo, Da, Yr)End of 2004/04(2) DA Resubmission 04/22/2005
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). Include in column (i)
the average period over which the tax credits are amortized.
iCine Account Balance at Beginning Deferred for Year AlTocations 10
No.SUbd
l~~sions
of Year Current Years Income Adjustments(c) (d) (e) (f)
1 Electric Utility
23%
34%695,295 154 112
510%38,137,309 932 957
1.455,846 27,08l1
500,527 411.4 341 679 411.4 1, 180,34E
8 TOTAL 67,788,977 341,679 294.49~
9 Other (List separately
and show 3%, 4%, 7%,
10% and TOTAL)
Line 6 cot A 11 %
State of Idaho 500,527 411.4 341 679 411.4 , 180,34E
r -
- ,( ,, "
1=1=~r. I=ORM NO 1 IFn 1 ~-R~\Pace . 266
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1 ) An Original (Mo, Da, Yr)End of 2004/04(2) DA Resubmission 04/22/2005
ACCUMULATED D_FERRED INVESTMENT TAX CRED T'S (Account 255) (continued)
Balance at End Avera~e Period ADJUSTMENT EXPLANATION Line
of Year of AI ocation No.to Income
541,183 11.
36,204,352 19.
1,428,762 53.
27,661,860 22.45
66,836,157
27,661 860
E::ror- E::no&. ..,n .. n:n
.. "
aD\D"",u,. 7"7
Name of Respondent This
wort
Is:Date of Report Year/Period of Report(1 ) An Original (Mo, Da, Yr)End of 2004/04Idaho Power Company (2) D A Resubmission 04/22/2005
OTHER DEFFERED CREDITS (Account 253)
Report below the particulars (details) called for concerning C?ther deferred credits.
For any deferred credit being amortized, show the period of amortization.
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
(b)Account(a)(c)(d)(e)(f)
Point to Point Transmission Study 185,971.808,891 5,474,229 851 309.Footnote.
FTV Footnote;866.667 133,333 266.666
FASB 133 Mark to Market 35,110 1823 104 816 69,706
Linden Feeder N/A 128,831 128,831
Joint Pole Use 502,751 ,.;.Pootr1ofe'
,\\.
023,505 782,418 261,664
Customer Level Pay 811 345 142 673,265 999,520 137 600
US Airforce Photovoltaic Generator 135,593 431 161 33,139 168,571
Security Plan 23.389,778 232 669 833 800,000 25,519,945
FERC Settlement Reserve 000,000 1823 000,000 000,000
Milner Falling Water 928,757 N/A 264 100 192,857
Postretirement Benefits 247 131 401 256,237 990,894
Benefit Plan,- Minimum Liability 12,286,612'
.;.
fi:)pb1Ote
';;
696 544 10,590,068
Directors Deferred Compensation 006,920 232 234 054 443,519 216 385
Construction Work In Progress 496,010 107 496,010 932,920 932,920
, 46
TOTAL 55,025,978 17,829,983 19,061,715 56,257,710
:. .:. ..! .
f:CC,.. E:I"\CU "'11"\
..
tcn
.. ,)-
riA\P::InQ 269
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 04/22/2005 2004/04
FOOTNOTE DATA
',schedule Page: 269 Line No.
400 10 000
232 5 181 323
142 617 568
808,891
!Schedule Page: 269 Line No.
165 466 667
146 400,000
866 667
Column:
Column:
!Schedule Page: 269 Line No.
400 1 021 900232 1 605
023,505
',schedule Page: 269 Line No.
219 880 135
190 564 960
186 251 449
696 544
Column:
Column:
i -
FERC FORM NO.1 (ED. 12-Page 450.
Name of Respondent
Idaho Power Company
This ~ort Is: Date of Report(1) ~ An Original (Mo, Da, Yr)(2) A Resubmission 04/22/2005
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.
Year/Period of Report
End of 2004/04
Line
No.
CHANGES DURING YEAR
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
21 Local Income Tax
L .
NOTES
FERC FORM NO.1 (ED. 12-96)Page 272
Name of Respondent
Idaho Power Company
This ~ort Is: Date of Report Year/Period of Report(1) ~An Original (Mo, Da, Yr) End of 2004/04(2) A Resubmission 04/22/2005
ACCUMULATED DEFERRED INCOME TAXES ACCELERATED AMORTIZATION PROPERTY (Account 281) (Continued)
3. Use footnotes as required.
CHANGES DURING YEAR
Amounts Debited Amounts Credited
to Account 410.to Account 411.
ADJUSTMENTS
Balance at Line
End of Year No.
(k)
Debits
(h)
Credits
Account
Debited
(i)
Amount
(e)(f)
Account
Credited
(g)
Amount
NOTES (Continued)
FERC FORM NO.1 (ED. 12-96)Page 273
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) A Resubmission 04/22/2005
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.
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2004/04
Balance at
Beginning of Year
CHANGES DURING YEARLine
No.
Account Amounts Debited
to Account 410.
(c)(a)(b)
1 Account 282
2 Electric
3 Gas
349,145.406
569,162,618
272,003
5 TOTAL (Enter Total of lines 2 thru 4)
6 Non-Operating Property
9 TOTAL Account 282 (Enter Total of lines 5 thru
10 Classification of TOTAL
11 Federal Income Tax
569.434,621 '
856,166
13.914 064
13,914,064
Amounts Credited
to Account 411.
(d)
680,052
11,180,440
11,180,440
180.440480,583,747
850,87512 State Income Tax
13 Local Income Tax
NOTES
FERC FORM NO.1 (ED. 12-96)Page 274
13,875.512
38,552
1 :
\...
Name of Respondent
Idaho Power Company
This ~ort Is: Date of Report(1) ~AnOriginal . (Mo, Da. Yr)(2) A Resubmission 04/22/2005
ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282) (Continued)
3. Use footnotes as required.
Year/Period of Report
End of 2004/04
CHANGES DURING YEAR
Amounts Debited Amounts Credited
to Account 410.to Account 411.
ADJUSTMENTS
(h)
Credits
Account
Debited
(i)
Amount
Balance at
End of Year
Line
No.
Debits
(e)(f)
Account
Credited
(g)
Amount
(k)
182 668.961182
668,961
NOTES (Continued)
L I
=ERC FORM NO.1 (ED. 12-96)Page 275
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 04/22/2005 2004/04
FOOTNOTE DATA
Ischedule Pac. e: 274 Line No.Column:
Changes during Year Adjustments Adjustments
Debits Credits
Beginning DR to CRto Acct.Acct Ending
Balance 410.411.410.411.credit Amount debi Amount Balance
ted
Repair
Allowance 391 585 169 200 222 385
Bridger
529,657 102.400 427 257
N. Valmy
963 266 76,500 886,766
FERC
Jurisdictional 705,967 112 535 818 502
Taxable
CIACin 651 298)273 742 (854 549)523,007)
CWIP Bal.
CIAC
Taxable (173,604)(326 522)(173 604)(326,522)
Income-Acct
253.575
Misc
- -
Software 469 284 (314 313)154 971
Develop
Costs
. ..
Intangible
Asset-La bor 077,806 601 608)8,476,198
Deduction
- -
FASB 109
330 832 743 182 668 961 182 055 794 344 219 575
349 145,406 856,166) (680,052)668,961 055,794 360,356,125
/1'
r" .
I FERC FORM NO.1 (ED. 12-87)Page 450.
This Page Intentionally Left Blank
This ~ort Is: Date of Report(1) ~An Original (Mo, Da. Yr)(2) A Resubmission 04/22/2005
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.
Year/Period of Report
End of 2004/04
Name of Respondent
Idaho Power Company
(a)
Balance at
Beginning of Year
(b)
Line
No.
Account
1 Account 283
2 Electric
5 Ferc Order 144A 941,979 133,158
12,257.454 23,181 640
9 TOTAL Electric (Total of lines 3 thru 8)
10 Gas
17 TOTAL Gas (Total of lines 11 thru 16)
18 :Pth~~;f'
~~'
f\Jat~r,
. .
404 571
19 TOTAL (Acct 283) (Enter Total of lines 9,17 and 18)
20 Classification of TOTAL
21 Federal Income Tax 32.841,872
6.481.489
10,282,215
975.239
19,579.171
735,627
i... .
22 State Income Tax
23 Local Income Tax
NOTES t, .
FERC FORM NO.1 lED. 12-96)Pace .276
Name of Respondent
Idaho Power Company
This ~ort Is: Date of Report(1) ~An Original (Mo. Da, Yr)(2) A Resubmission 04/22/2005
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.
YearlPeriod of Report
End of 2004104
CHANGES DURING YEAR
Amounts Debited Amounts Credited
to Account 410.to Account 411.
ADJUSTMENTS
Debits Balance at
End of Year
(k) ,
Line
No.
075,137
26.331
26,331
43,196
43,196 39.552 852
387,706
28,210,452
NOTES (Continued)
FERC FORM NO.1 lED. 12-96\P~aA ')77
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 04/22/2005 2004/04
FOOTNOTE DATA
ISchedule Page: 276 Line No.Column:
Changes during Year Adjustments Adjustments
Debits Credits
Beginning DR to CR to CR to Acct.Acct.Ending
Balance 410.411.410.411.credit Amount debit Amount Balance
Loss on
Reacquired 841,951 856,565 014 614)
Debt
Conservation
Programs 310 361 338 017 972 343
PCA
Expense 204 211 826 688 18,185 845 093
Deferral
PV Startup
Costs 1 0,083 308 776
Post Retiree
Benefits 230 739 212 990 749
Reorganizati
on Costs 589 596 294 799 294 798
Incremental
Security 420 703 (20 552)82,240 317 911
Costs
FERC Order
2000 Costs 000 204 173,228 293 359 880 073
Oregon
Excess 324 861 250 800 904 787 670 874
Power Costs
Professional
Fees - IPUC 290 768 23,522
Order 29505
Unrealized
gains on Mkt 928,058 219 39,552 219 852 889,358
Securities
860,769 257,45423 181,640 39,552 852 28,897 883
: '
ISchedule Page: 276 Line No.Column:
Changes during Year Adjustments Adjustments
Debits Credits
Beginning DR to CRto DR to CR to Acct.Acct Ending
Balance 410.411.410.411.credit Amount debi Amount Balance
ted
Advance
Coal 399 113 10,791 42,672 367,232
Royalties
Oregon
I FERC FORM NO.1 (ED. 12 87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Origir (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/22/2005 2004/04
FOOTNOTE DATA
Non-Op Prop 805 820
Tax Adj
Unrealized
Gain/loss 653 15,524 523 19,653
From Rabbit
Trust
404 571 26,330 196 387 706
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This (!Jort Is:Date of Report Year/Period of Report
Idaho Power Company (1 ) An Original (Mo, Da, Yr)End of 2004/04(2) riA Resubmission 04/22/2005
OTHER REGULATORY LIABILITIES (Account 254)
1. Report below the particulars (details) called for conc~rning 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 175 664 206 751,713 87,507
Idaho 1999 - NEEA (Nw energy efficiency act)183,291 232 201,815 484 13,040
Demand Side Management Rider 29026 273,891
/""'
FoOtr1'ot~'928 575 468.406 813,722
FAS133 Market to Market 175 687603 687 603
,..
BPA Credit-Residential-Idaho 077 901 FOotnote.'
...
12,380,060 12,535.595 233,436
.., ...... ....
BPA Credit-Residential- Oregon 196 .Footnote;j:.F 545,246 534.990 40,940
BPA Credit-Farm -Idaho 580.788 131 447,216 409,284 542 856
BPA Credit-Farm - Oregon 802 142 101,630 92.958 16,130
BPA Credit - Conservation 653,139
."',
$;;1).195.714 798.541 255,966
Pre94 Demand Side Management Order 177534 1823 160 15,233 148,607
IPUC Order 29600 If;'
.:'
;;!!;;I 929,167 38,600.000 13,670.833
OPUC Order 04-283 N/A 100 000 100,000
..", ..,..
Boise Operation Center 93.247 .~!FootJiO~:31.970 61,277
Unfunded Accumulated Deferred Income Tax 023.911 190 576.619 ..40,447.292
Asset Retirement Oblication - Removal Cost 142,594,975 N/A 104,848 147.699.823
TOTAL 190,734,675 46.733,981 65,104,655 209 105,349
r '
\.. ., '
L '
rCD,.. enDU fI..n 11"'-_IDC\I n'LnA\P~n'" 278
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Oa, Yr)
Idaho Power Company (2)A Resubmission 04/22/2005 2004/04
FOOTNOTE DATA
chedule Pa e: 278 Line No.Column:
131
461 890
142
246,508
154
72,235
184
616
232
124,982
921
069
253
473
254
13,803
928,575
chedule Pa e: 278 Line No.Column:
131 925
142 12,373,134
380 060
chedule Pa e: 278 Line No.Column:
131
172
142
545,075
545,246
chedule Pa e: 278 Line No.17.Column:
131
204
154
12,858
158
145
232
176,448
254
059
195,714
chedule Pa e: 278 Line No.Column:
1823
. _
637 208
401 19,291 958
929,167
FERC FORM NO.1 (ED. 12-87)Page 450.
f - .
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 Resu bm ission 04/22/2005 2004/04
FOOTNOTE DATA
~chedule Page: 278
163
Line No.Column:
320
401
402
21 ,740
910
, .
970
IFERC FORM NO.1 (ED. 12-Page 450.
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2004/04
This ~ort Is: Date of Report(1) ~ An Original (Mo, Da, Yr)(2) A Resubmission 04/22/2005
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 unbilled 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.
r:.
! .
(a)
Operating Revenues Year Operating Revenues
to Date Quarterly/Annual Previous year (no Quarterly)
(b)(c)
t..
247,425,040 263,803,176
111 797,200 128,619,992
300,038 625,742
Line
No.
Title of Account
1 Sales of Electricity
2 (440) Residential Sales
(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
(445) Other Sales to Public Authorities
(446) Sales to Railroads and Railways
(448) Interdepartmental Sales
10 TOTAL Sales to Ultimate Consumers
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
16 (450) Forfeited Discounts
635,835.518
121,147,646
756.983,164
114 364
758,097,528
670,968 759
572,857
742,541 616
514,466
741,027,150.
17 (451) Miscellaneous Service Revenues
18 (453) Sales of Water and Water Power
19 (454) Rent from Electric Property
20 (455) Interdepartmental Rents
21 (456) Other Electric Revenues
214 833 391,006
18,085,801 529,569
20,423,944 18,433,937 r .
li.
26 TOTAL Other Operating Revenues
27 TOTAL Electric Operating Revenues
42,724,578
800,822,106
39,354 512
780,381 662
FF=Rr.. FORM Nn 1 (F=n 1 ?QR\Paae 300
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2004/04
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) A Resubmission 04/22/2005
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 Ouring 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 unbilled 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)(d) (e)
AVG.NO. CUSTOMERS PER MONTH Line
Current Year (no Quarterly) Previous Year (no Quarterly) No.(ij
(g)
296,407
334 955
890
317,441
206,182
29,432 501
13,239,589
885,350
16,124 939
433,465 420,43912,980 031
829,940
14,809,971 433,465 420,439
16,124,939 433,465 420,43914,809 971
Line 12, column (b) includes $
Line 12, column (d) includes
929,513
54.757
of unbilled revenues.
MWH relating to unbilled revenues
J:FIU'. J:ORM NO 1 IFn 12.Qf\\Pace ~n1
414
f '
r..
This Page Intentionally Left Blank
l .
: .\. .
Name of Resp~ndent This ~ort Is:Date of Report YearlPeriod of Report
Idaho Power Company (1') An Original (Mo, Da, Yr)End of 2004/04(2) DA Resubmission 04/22/2005
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.
,Line NumDer ana Iitle or Kate scneawe Mvvn ~ola Kevenue Average Numoer IS vvn or ~ales ~wg~e lderof cus~omers Per T~stomer, No.,(a)(b)(c)(d (f)
1 440 - Residential Sales:
2 01 - Residential 546,209 271,359,665 360,462 12,612 0597
3 03 - Residential-Mastered Metere
4 84 - Residential-Net Metering
5 15 - Dusk to dawn lighting 2.427 524,019 2159
6 Unbilled Revenues 701 2,429,556 0766
7 Total 440 580,337 274 313,240 360,462 707 0599
9 442-Commercial & Industrial Sales
07 - General service 305,861 22.109,466 35,821 539 0723
09 - General service 201 323 137 762 375 18,161 176,275 0430
10 - Large power winter service
84 - General Service - Net Meter
15 - Dusk to dawn lighting 787 730,598 1929
19 - Uniform rate contracts 268,266 79,921,273 117 19,386,889 0352
21 - Interruptible irrigation
22 - Limited use Prairie Power
24 - Irrigation Pumping 703,587 82,842,092 164 99,253 0486
25 - Irrigation Pumping -Time of 59.364 810,854 142 418,056 0473
40 - General service 14,590 877,776 094 13,336 0602
Commercial & Industrial & Unbill 074 584 167,806 358,194,667 0299
Total 442 631,362 359,222.240 72,502 119.050 0416
444 - Public Street Lighting:
32 - Shielded Streel Lighting 152 15,000 2101
40 - General service 236 74,412 290 262 0602
41 - Street lighting 17,637 890,911 138 127,804 1072
42 - Traffic control lighting 002 331 563 125,028 0368
Total 444 27,890 300.038 501 55,669 0825
-:-
TOTAL Billed 13, 184 83~632,906,005 433,465 30,417 0480
Total Unbilled Rev.(See Instr. 6)75/929,513 0535
TOTAL 13.239 58S 635.835,518 433,465 30,54~0480
FERC FORM NO.1 (ED. 12-95)Page 304
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 2004/04(2) nA Resubmission 04/22/2005
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" meaAS 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 sl;Jpplier 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 illing Avera Avera
cation Tariff Number Demand (MW)Monthly NC Demam Monthly CP . em and
(a)(b)(c)(d)(e)(f)
Raft River Rural Electric V6-44 869 869 768
City of Weiser V6-037 996 334
American Electric Power Service Cor WSPP 000 000 000
Arizona Public Service Co.WSPP 000 000 000
Arizona Public Service Co.. SF WSPP 000 000 000
Avista Corp. - WWP Div.WSPP 000 000 000
Avista Corp. - WWP Div.WSPP 000 000 000
Avista Energy, Inc.WSPP 000 000 000
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
t .
l. ,
rrn" el"\n.. "11"\ ... Irn ...., nn\D~...", ~1n
Name of Respondent This (8Jort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2004/04
(2)0 A Resubmission 04/22/2005
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-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.
G. 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 (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (GO-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (GO-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 m. Explain in a footnote all components of the amount shown in column m. 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
i 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)
680 164,103
::~::~~:_~~pqq
304,316
50,651 401 228 995,689
92,800 954,600 954,600
14,927 754,985 754,985
657,695 388,720 27,388,720
100 100 100
4,400 191 700 191,700
158 42,005 42,005
200 82,700 82,700
604 20,340 20,340
108 85,680 85,680
215 451 273 451,273
40,937 508,660 508,660
114 084 4,487 265 4,487,265
104 331 565,331 391,792 342,882 300,005
781 019 114 539,811 307,830 117,847,641
885 350 565,331 116 931 603 650 712 121,147,646
FERC FORM NO.1 (ED. 12-90)Page 311
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2004/04(2) DA Resubmission 04/22/2005
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.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)
BP Energy Company WSPP 000 000 000
BP Energy Company WSPP 000 000 000
Burbank, City of WSPP 000 000 000
Calpine Energy Services, loP.WSPP 000 000 000
Calpine Energy Services, loP.WSPP 000 000 000
Cargill Power Markets LLC WSPP 000 000 000
Cargill Power Markets LLC WSPP 000 000 000
Chelan Co PUD WSPP 000 000 000
Chelan Co PUD WSPP 000 000 000
Clatskanie PUD WSPP 000 000 000
Clatskanie PUD WSPP 000 000 000
Colton, City of 000 000 000
Conoco Phillips Company WSPP 000 000 000
Conoco Phillips Company WSPP 000 000 000
Subtotal RO
Subtotal non-ROo
Total
lH'
............. ,.,.,....... .'1"\
.. ,~'"
.." nn\D.,....a ~1n_
I .
I Name of Respondent This ~ort Is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)End of 2004/04! Idaho Power Company (2)DA Resubmission 04/22/2005
SALES FOR RESALE (Account 447) (Continued)
I 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.
I 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
I "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 averagemonthly 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
I 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.
18. 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-RQ grouping (see instruction 4), and then totaled on
I 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)
150 680 680
20,800 897 700 897 700
400 17,700 17,700
070 65,853 65,853
800 112,750 112,750
396 614 614
105,922 4,434,090 4,434,090
069 525 34,525
200 7,400 7,400
249 652 652
200 000 000
19,354 570,036 570,036
732 15,034 15,034
200 168,600 168,600
104 331 565,331 391 792 342,882 300,005
781 019 114 539,811 307,830 117,847,641
885,350 565 331 116,931 603 650,712 121,147 646
FERC FORM NO.1 (ED. 12-90)Page 311.
Name of Respondent This ~ort Is:Date of Report . Year/Period of Report
Idaho Power Company (1)' X An Original (Mo, Da, Yr)End of 2004/04
(2)0 A Resubm ission 04/22/2005
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 illing Avera Avera
cation Tariff Number Demand (MW)Monthly NC Demanc Monthly CP emand
(a)(b)(c)(d)(e)(f)
Constellation Energy Commodities Gr WSPP 000 000 000
Constellation Power Source, Inc.WSPP 000 000 000
Constellation Power Source, Inc.WSPP 000 000 000
Coral Power, LLC WSPP 000 000 000
Coral Power, LLC WSPP 000 000 000
EI Paso Electric Company WSPP 000 000 000
ENMAX Energy Marketing Inc.WSPP 000 000 000
ENMAX Energy Marketing Inc.WSPP 000 000 000
Entergy-Koch Trading, LP WSPP 000 000 000
Eugene Water & Electric Board WSPP 000 000 000
Eugene Water & Electric Board WSPP 000 000 000
Franklin County P.U.D.WSPP 000 000 000
Grant County P .WSPP 000 000 000
Grays Harbor PUD WSPP 000 000 000
Subtotal RO
Subtotal non-RO
Total
r- -
r '
l.,
, i
----. -.................. .. ,....... .... ....,
n__- ~1n?
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1 ) X An Original (Mo, Oa, Yr)End of 2004/04(2) 0 A Resubmission 04/22/2005
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.
16, For requirements
RQ sales and "ny 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 (f). Monthly NCP demand is the maximum
I metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minuteintegration) 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.
18. 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 W. Explain in a footnote all components of the amount shown in column W. 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
I the Last -
line of the schedule. The "Subtotal - ROn 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)
(j)
(k)
12,800 707,050 707,050
608 22,077 22,077
25,000 160,720 160,720
184 184
83,600 390,650 390,650
320 320
208 208
600 56,200 56,200
15,200 515,700 515,700
123 113,214 113,214
10,560 363,330 363,330
167 875 875
943 93,167 93,167
533 12,569 12,569
300,005104,331 565,331 391,792 342,882
781 019 114,539,811 307,117,847,641
885,350 565,331 116 931 603 650,712 121 147,646
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 2004/04
(2)D A Resubmission 04/22/2005
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 f~r 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.
. .
'. uu.'",u '
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)
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, L.L.C.V6-000 000 000
Pacific Northwest Generating Cooper WSPP 000 000 000
Pacific Northwest Generating Cooper WSPP 000 000 000
PacifiCorp Inc.WSPP 000 000 000
PacifiCorp Inc.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
PPL Montana. LLC WSPP 000 000 000
Subtotal RO
Subtotal non-
Total
f .
, .
........." ~"...a.
""'" ..
fen
...,
nn\1:)""..... ~10.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1 ) X An Original (Mo, Oa, Yr)End of 2004/04
(2) D A Resubmission 04/22/2005
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
i non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
i oflhe 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 explanC)tion 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"
I in column (a). The remaining
sales may then be iisted 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 (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
I 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.
18. 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 RQ/Non-RQ grouping (see instruction 4), and then totaled on
I the Last -
line of the schedule. The "Subtotal - RQn 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)
600 60,800 60,800
362 141,145 141,145
285,781 12,217,078 12,217 078
033 316 316
44,231 1 ,972, 815 _!ij~~~9~~~~.9 280,645
885 59.822 59,822
000 217,450 217,450
12,522 502,047 502,047
62,767 809,850 809,850
60,415 217,726 217 726
95,775 718,382 718,382
50,445 765,915 765,915
371,900 15,079,120 15,079,120
535 130,263 130,263
104 331 565,331 391,792 342,882 300,005
781,019 114,539,811 307,830 117,847,641
885,350 565,331 116 931,603 650 712 121,147,646
FERC FORM NO.1 (ED. 12-90)Page 311.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2004/04
(2)D A Resubmission 04/22/2005
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)
No.(Footnote Affiliations)Classifi-Schedule or Monthly illing Avera Avera
cation Tariff Number Demand (MW)Monthly NC Demanc Monthly CP emand
(a)(b)(c)(d)(e)(f)
PPL Montana, LLC WSPP 000 000 000
PPM Energy, Inc.WSPP 000 000 000
PPM Energy, Inc.WSPP 000 000 000
Public Service Co. of Colorado wspp 000 000 000
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 . OS WSPP 000 000 000
Rainbow Energy Marketing Corporatio WSPP 000 000 000
San Diego Gas and Electric WSPP 000 000 000
Seattle City Light WSPP 000 000 000
Seattle City Light WSPP 000 000 000
Subtotal RO
Subtotal non-
Total
~ ,
r '
l.. ,
rro,.. rnoa. 8.,n of Irn of., nn\D"""a ~1 0_
I 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 2004/04
(2)0 A Resubmission 04/22/2005
SALES FOR RESALE (Account 447) (Continued)
I 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
ot the service in a footnote.
I AD - for Out-ot-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"
I 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.
16. 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 averagemonthly coincident peak (CP)
. demand in column (f). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP demand is the maximum
I 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.
18. 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 m. Explain in a footnote all components ot the amount shown in column W. 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
I 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)
600 472,031 472,031
619 20.288 20,288
56,600 289,500 289,500
5,452 209,527 209,527
20,000 910,920 910,920
981 39,800 39,800
12,000 551,480 551,480
125 125
600 219,200 219,200
825 825
520 530,700 530,700
800 30,600 30,600
131 423,855 423,855
800 278,600 278,600
104 331 565,331 391,792 342,882 300,005
781 019 114 539,811 307.830 117 847,641
~85,350 565,331 116 931 603 650,712 121 147,646
FERC FORM NO.1 (ED. 12-90)Page 311.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr) End of 2004/04(2) 0 A Resubmission 04/22/2005
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 iaentified 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 outof 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)
Sempra Energy Trading Corporation WSPP 000 000 000
Sempra Energy Trading Corporation WSPP 000 000 000
Sierra Pacific Power Company WSPP 000 000 000
Snohomish County PUD WSPP 000 000 000
Snohomish County PUD WSPP 000 000 000
Tacoma Power WSPP 000 000 000
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
Tri-State Generation and Transmissi WSPP 000 000 000
Utah Associated Municipal Power Sys WSPP 000 000 000
Utah Associated Municipal Power Sys WSPP 000 000 000
Utah Municipal Power Agency V6.;18 000 000 000
Subtotal RO
Subtotal non-
Total
r- -
,,-.
r. '
l. .
~~o,.. ~nD.. I.ln -t I~n -t "'t nn\D",...... ~1n_!ii
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1 ) X An Original (Mo, Da, Yr)End of 2004/04
(2)0 A Resubmission 04/22/2005
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 - 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 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 (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 charg.es in column (h), energy charges in column (i), and the total of any other types ot 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-RQ grouping (see instruction 4), and then totaled on
the Last -line ot 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)
293 52,864 52,864
250,674 10,398,059 10,398,059
125 125
6,409 244 625 244 625
400 800 800...
620 620
364 157,368 157,368
30,520 071 870 071 870
594 280,379 280,379
600 126,050 126,050
329 87,843 87,843
061 320,782 320,782
120 47,520 47,520
4,400 4,400
104 331 565,331 391,792 342,882 300,005
781 019 114 539,811 307,830 117 847 641
885,350 565,331 116,931 603 650,712 121,147 646
I:'
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 2004/04
(2)D A Resubmission 04/22/2005
. 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
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 fwera Avera
cation Tariff Number Demand (MW)Monthly NC Deman!Monthly CP emand
(a)(b)(c)(d)(e)(f)
Western Area Power Administration WSPP 000 000 000
Subtotal RO
Subtotal non-
Total
I. '
CCOl" 1:1"\0" t.l1"\ 1 tcn 1'LOn\P::anp 310.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Oa, Yr)End of 2004/04
(2)D A Resubmission 04/22/2005
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-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 (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)
i the total charge shown on bills rendered to the purchaser.
Ig. 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-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)
2,400 2,400
.--
104 331 565,331 391,792 342,882 300,005
781,019 114 539,811 307,830 117,847,641
885,350 565,331 116,931 603 650 712 121 147,646
FERC FORM NO.1 (ED. 12-90)Page 311.
This Page Intentionally Left Blank
r ..
l. .
i..
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 04/22/2005 2004/04
FOOTNOTE DATA
!schedule Page: 310 Line No..Column:
ustomer Charge
'rschedule Page: 310 Line No.Column:
etwork transmission charges
'rschedule Page: 310.Line No.Column:
Capaci ty and penalty charge
I "
i '
FERC FORM NO.1 (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 2004/04
(2) (JA Resubmission 04/22/2005
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line Account ~moun~or Amount for
No.urrent ear Previous Year
(a)(b)(c)
1. POWER PRODUCTION EXPENSES
A. Steam Power Generation
Operation
(500) Operation Supervision and Engineering 187,136 861,643
(501) Fuel 98,387,370 223,588
(502) Steam Expenses 333,426 617,830
(503) Steam from Other Sources
(Less) (504) Steam Transferred-Cr.
(505) Electric Expenses 558.515 306.920
(506) Miscellaneous Steam Power Expenses 868.516 533,153
(507) Rents 710,713 576,580
(509) Allowances
TOTAL Operation (Enter Total of Lines 4 thru 12)113,045,676 105,119,714
Maintenance
(510) Maintenance Supervision and Engineering 859,869 029,957
(511) Maintenance of Structures 358,798 323,838
(512) Maintenance of Boiler Plant 12.665,232 12,467,878
(513) Maintenance of Electric Plant 182 203 682 227
(514) Maintenance of Miscellaneous Steam Plant 076,141 374 982
TOTAL Maintenance (Enter Total of Lines 15 thru 19)24,142,243 25,878.882
TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 & 20)137 187.919 130,998,596
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 1.1.'111""~.tlllw"'....~11.~(.t0fl"~fEtll.'
Operation 1~I~illl~fllf.J~!'11~iI1Ik.IJI!t....t.ik1ltt'I..'I.I~IJI"JI
(535) Operation Supervision and Engineering 4,421 651 825,351
(536) Water for Power 016,995 796,233
(537) Hydraulic Expenses 792,153 615,743
(538) Electric Expenses 245,717 133,793
(539) Miscellaneous Hydraulic Power Generation Expenses 528,085 824 092
(540) Rents 379,919 374 008
TOTAL Operation (Enter Total of Lines 44 thru 49)19,384,520 16,569,220
r '
r -
, -
l ,
r '
L '
l -
1=8=~~ I=n~M Nn f8=n ?Q~\Paae 320
Name of Respondent This (!J6rt Is:Date of Report Year/Period of Report
Idaho Power Company (1 ) An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/22/2005
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line Account ~moun~or Amount for
No.urrent ear Previous Year
(a)(b)(c)
C. Hydraulic Power Generation (Continued)
Maintenance
(541) Mainentance Supervision and Engineering 058,293 134 906
(542) Maintenance of Structures 004 778 187 642
(543) Maintenance of Reservoirs, Dams, and Waterways 032,152 795,499
(544) Maintenance of Electric Plant 268,044 608,366
(545) Maintenance of Miscellaneous Hydraulic Plant 642,221 236,821
TOTAL Maintenance (Enter Total of lines 53 thru 57)005,488 963,234
TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 & 58)390,008 24,532,454
D. Other Power Generation
Operation
(546) Operation Supervision and Engineering 391,835 476,255
(547) Fuel 874 063 674,170
(548) Generation Expenses 170,854 162,122
(549) Miscellaneous Other Power Generation Expenses 298,934 302,448
(550) Rents
TOTAL Operation (Enter Total of lines 62 thru 66)735,686 614,995
Maintenance
(551) Maintenance Supervision and Engineering 230
(552) Maintenance of Structures 123,893 151 970
(553) Maintenance of Generating and Electric Plant 69,240 127,718
(554) Maintenance of Miscellaneous Other Power Generation Plant 240,994 289,779
TOTAL Maintenance (Enter Total of lines 69 thru 72)434,357 569,467
TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73)170,043 184,462
E. Other Power Supply Expenses
(555) Purchased Power 195,642,193 150,979,849
(556) System Control and Load Dispatching 106,362 24,902
(557) Other Expenses 082,749 72,250,173
TOTAL Other Power Supply Exp (Enter Total of lines 76 thru 78)236,831 304 223,254 924
TOTAL Power Production Expenses (Total of lines 21, 41, 59, 74 & 79)407,579,274 385,970,436
2. TRANSMISSION EXPENSES
Operation
(560) Operation Supervision and Engineering 031 371 615,056
(561) Load Dispatching 909,482 788,312
(562) Station Expenses 686 223 546,777
(563) Overhead Lines Expenses 544 172 656,409
(564) Underground Lines Expenses
(565) Transmission of Electricity by Others 8,441 863 5,424,722
(566) Miscellaneous Transmission Expenses 17,854 284,850
(567) Rents 176,624 399,624
TOTAL Operation (Enter Total of lines 83 thru 90)17,807 589 13,715,750
Maintenance wjll~~flf~'IIII;ltwltI11jl~lllj8f.~I.llil~i."'J!.r.j
(568) Maintenance Supervision and Engineering 653,160 739 753
(569) Maintenance of Structures 337
(570) Maintenance of Station Equipment 009,973 679,028
(571) Maintenance of Overhead Lines 356,489 298,159
(572) Maintenance of Underground Lines
(573) Maintenance of Miscellaneous Transmission Plant 878 79,716
TOTAL Maintenance (Enter Total of lines 93 thru 98)027,500 796,993
100 TOTAL Transmission Expenses (Enter Total of lines 91 and 99). 23,835,089 19,512,743
101 3. DISTRIBUTION EXPENSES
102 Operation
103 (580) Operation Supervision and Engineering 608,681 341,973
FERC FORM NO- 1 lED. 12.93\Paae 321
Name of Respondent This (!Jort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da. Yr)End of 2004/04(2) 0 A Resubmission 04/22/2005
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line Account ~mountltor Amount for
No.urrent ear Previous Year(a)(b)(c)
104 3. DISTRIBUTION Expenses (Continued)
105 (581) Load Dispatching 395,937 231 ,796
106 (582) Station Expenses 950,120 853,609
107 (583) Overhead Line Expenses 3,481 870 369,643
108 (584) Underground Line Expenses 670,619 818,655
109 (585) Street Lighting and Signal System Expenses 151,313 128,348
110 (586) Meter Expenses 127,933 722 236
111 (587) Customer Installations Expenses 545,521 488,959
112 (588) Miscellaneous Expenses 997 634 753,921
113 (589) Rents 150,421 142,994
114 TOTAL Operation (Enter Total of lines 103 thru 113)22,080,049 23,852,134
115 Maintenance
116 (590) Maintenance Supervision and Engineering 66,616 35,636
117 (591) Maintenance of Structures
118 (592) Maintenance of Station Equipment 932.915 863,970
119 (593) Maintenance of Overhead Lines 11,137 680 12,101,013
120 (594) Maintenance of Underground Lines 245,264 378,903
121 (595) Maintenance of Line Transformers 259,850 770,641
122 (596) Maintenance of Street Lighting and Signal Systems 494 696 375,407
123 (597) Maintenance of Meters 953 983 1,425,510
124 (598) Maintenance of Miscellaneous Distribution Plant 178.232 240,673
125 TOTAL Maintenance (Enter Total of lines 116 thru 124)17,269,236 20,191,774
126 TOTAL Distribution Exp (Enter Total of lines 114 and 125)39.349,285 44,043,908
127 4. CUSTOMER ACCOUNTS EXPENSES
128 Operation
129 (901) Supervision 426,782 399.173
130 (902) Meter Reading Expenses 724,432 696,330
131 (903) Customer Records and Collection Expenses 290,028 695,931
132 (904) Uncollectible Accounts 009,866 957 930
133 (905) Miscellaneous Customer Accounts Expenses 051 126,081
134 TOTAL Customer Accounts Expenses (Total of lines 129 thru 133)445,057 17,875,445
135 5. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
136 Operation
137 (907) Supervision 313,453 402.335
138 (908) Customer Assistance Expenses 346,134 029,669
139 (909) Informational and Instructional Expenses 525 155
140 (910) Miscellaneous Customer Service and Informational Expenses 732,850 631,830
141 TOTAL Cust. Service and Information. Exp; (Total lines 137 thru 140)397 962 063,989
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 45,232,476 30,340 516
152 (921) Office Supplies and Expenses 719.947 13,579,471
153 (Less) (922) Administrative Expenses Transferred-Credit 26,358,321 28,579,776
t .
f~"
l..
FFRC'". FORM NO 1 (Fl). 12.Q3\Paae 322
Name of Respondent
Idaho Power Company
This ~ort Is: Date of Report(1) ~ An Original (Mo. Da, Yr)(2) A Resubmission 04/22/2005
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.ne Account Amount forNo Current Year(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)
Year/Period of Report
End of 2004/04
, .
056,785
207 907
996,017
26,676 544
075
976,930
331 006
925,932
900,634
27,781,551
725
882,273
118,315
959 515
12,291
82,600,481
560,508
839,679
39,324
62,603,843
525,892
85,126,373
581 733,040
398,080
65,001,923
540,468,444
FERC FORM NO.1 (ED. 12~93)Page 323
This ~ort Is:(1) ~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 (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)
04/22/2005
Year/Period of Report
End of 2004/04
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 "intermedia~e-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 Cogeneration & Small Power Producers
Willis and Betty Deveny
3 James B. Howell/CHI
~~fu,~~~ESQ~9~~~~d~t~~iei;jj;
" '. ..
5 Owyhee Irrigation District
Mitchell Butte
Owyhee Dam
Tunnel #1
9 Reynolds Irrigation District
10 Clifton E. Jenson
11 Snake River Pottery
12 White Water Ranch
13 John R LeMoyne
14 David R Snedigar
' LU
Total
FERC FORM NO- 1 IEO- 12.90\
FERC Rate
Schedule or
Tariff Number
(c)
Actual Demand (MW)'Average Average
Monthly NCP Demanc Monthly CP Demand(e) (f)
Average
Monthly Billing
Demand (MW)
(d)
N/A
N/A
942Mw
N/A N/AN/A N/A
N/A
N/A
N/A
N/A
05Mw
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
(1 )
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
(1 )
N/A
N/A
N/A
N/A
Paae 326
\ ,
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1 ) X An Original (Mo, Da, Yr)End of 2004/04(2)0 A Resubmission 04/22/2005
r'U -(Ct-lll rr-i ~\--.. -. x. ccount 55~~) (Continued)nc u Ing power exchange
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 (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 (f)
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
I out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
I 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)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.
18. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must 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.
I 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 ($)
(g)
(h)(i)
(j)
(I)(m)
86E 55,611 55,611
271 276, 73~276,739
41 ,78C 576,498 301,318 877,816
959 437,61 a 437 610
18,402 202,481 202,481
7,481 691,4le 691,475
1,474 103,531 103,531
265 17,500 5,454 22,954
404 25,661 25,661
62E 39,98E 39.988
63E 546 546
287 83,029 83,029
259,876 205,930 266 815.124 192,715,345 111 ,724 195,642,193
FERC FORM NO.1 (ED. 12-90)Page 327
Name of Respondent This (8Jort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da. Yr)" End of 2004/04
(2)D A Resubmission 04/22/2005
~A$ED POWER hAccount 555)nc udlng 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)
Mud Creek Hydro, Inc N/A N/A N/A
Rim View Trout Company N/A N/A N/A
Curry Cattle Com pany 084Mw (1)(1)
Branchflower Company N/A N/A N/A
Big Wood Canal Company
Black Canyon N/A N/A N/A
Jim Knight N/A N/A N/A
Sagebrush N/A N/A N/A
Fisheries Development N/A N/A N/A
Shorock Hydro Inc.
Shoshone Cspp N/A N/A N/A
Shoshone #2 N/A N/A N/A
Rock Creek #1 Joint Venture 732Mw (1)(1)
Richard Kaster
Total
r .
J:J:JU'- J:n~M Nn 1 lJ:n 1 ?Qn\Pace 326.
. '
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2004/04(2)D A Resubmission 04/22/2005
PL
,...." .. '
(1-
.../ t"'
~ -'- .
ccount
~~)
(Continued)Including power exchange
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
I 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, (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)
i 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
I 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)
I 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.
18. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must f(~ported 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 DelivereQ on Page 401 , line 13.
9, Footnote entries as required and provide explanations following all required data,
I 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
($)
\f?
of Settlement ($)
(g)
(h)(i)(m)
33~20,309 20,309
1 ,46~49,97C 49,970
' -,---..
648 26,796 12,092 38,888
889 59,12e 59,125
26~17,89€17,896
572 39,917 39,917
67E 271 47.271
801 501 27,501
39E 99,71E 99,718
242 79.831 79,831
971 552.508 173,83i 726,345
259,876 205,930 351 266 815,124 192,715,345 111 ,724 195,642, 19~
FERC FORM NO.1 (I;D. 12.90)Page 327.
Nam e of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho 'Power Company (1) X An Original (Mo, Da, Yr)End of 2004/04
(2)0 A Resubmission 04/22/2005
PURCHASED POWER hAccount 555)(Including 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.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 reliabrlity 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 ofthe 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 N/A N/A N/A
Briggs Creek N/A N/A N/A
David McCollum N/A N/A N/A
K. Hydro Mud Creek S & S N/A N/A N/A
AllanNemon Ravenscroft .488Mw (1)(1)
William Arkoosh N/A N/A N/A
Clear Springs Food Inc.N/A N/A N/A
Koyle Hydro Inc.N/A N/A N/A
Kasel & Witherspoon N/A N/A N/A
Lateral 10 Ventures N/A N/A N/A
Crystal Springs Hydro N/A N/A N/A
Pigeon Cove Power 389 (1)(1)
Consolidated Hydro Inc. Enel
GeoBon #2 N/A N/A N/A
Total
r -
i.~
C -
'( -
FERC FORM NO.1 IED- 12.90\Paae 326.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2004/04
(2)0 A Resubmission 04/22/2005
PU ~C, "'
(i""(1' .
\:.
ccoun\~g~~~ (Continued)nc u Ing power exchange)
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
I 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
I 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.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
I 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)
I 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.
18. 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 ~age 401 , line 13.
9, Footnote entries as required and provide explanations following all required data.
I 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)
628 103,875 103,875
698 236,083 236.083
768 48,085 48,085
306 83.07C 83,070
095 155,672 24,49C 180,162
219 163.118 163,118
602 274.842 274,842
729 203,304 203,304
739 251.705 251,705
5,422 332,886 332,886
6,4 73 399,580 399,580
622 486,150 129,946 616,096
012 150,087 150.087
259,876 205,930 351,266 815,124 192.715,345 111 ,724 195,642,193
FERC FORM NO.1 lED. 12-90)Page 327.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2004/04(2) DA Resubmission 04/22/2005
PURCHASED POWER ~Account 555)(Including 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 se"rvice 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 AveragecationTariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
Barber Dam N/A N/A N/A
Rock Creek #2 N/A N/A N/A
Dietrich Drop N/A N/A N/A
Lowline #2 N/A N/A N/A
Cedar Draw/little Mac Power Co.N/A N/A N/A
South Forks Joint Venture (5)N/A N/A N/A
little Wood River Irrigation Dis N/A N/A N/A
Marco Rancher s Irrigation Inc.N/A N/A N/A
Faulkner Brothers Hydro Inc.N/A N/A N/A
Magic Reservoir Hydro N/A N/A N/A
Bypass limited N/A N/A N/A
SE Hazelton A LP N/A N/A N/A
Jerry L McMillan N/A N/A N/A
Lemhi HydroPower Company N/A N/A N/A
Total
If.
~ ""
l: -
FFRC FORM NO- 1 IED- 12-Paae 326.
I -
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2004/04
(2)0 A Resubmission 04/22/2005
PL.. tc".. 'l 'do
ccou
Rt ~~1
(Continued)nc u Ing 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 amonnthly (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 (f). Monthly
NCP demand is the maximum metered hourly (GO-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (GO-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f)
I 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)
I the total charge shown on bills received as settlement by the respondent.
For power e)(changes, 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)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
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)
11,389 544,74c 544,748
125 247,18~247,189
083 460,867 460,867
357 462,73E 462,736
777 289.899 289,899
24,561 667 38E 667,386
3,41 E 240,42E 240,426
75~107.66C 107,660
76S 205,954 205.954
60E 62E 64,626
318 196,197 196,197
20,45E 962,32C 962,320
13E 574 574
134 79,842 79,842
259,876 205,930 351,266 815,124 192,715,345 111 ,724 195,642,192
FERC FORM NO.1 lED. 12-90\Paae 327.
This ~ort Is:(1) ~An Original
(2) D A Resubmission
PURCHASEO POWER (Account 555)ncludlng 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, Oa. Yr)
04/22/2005
Year/Period of Report
End of 2004/04
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)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)Average Average
Monthly NCP Demam Monthly CP Demand(e) (f)1 J R SimplotCo. Blind Canyon Hydro City of Boise City of Hailey City of Pocatello
~ryiJ"ilr~!~Yctr9"g~~~I~J;~lt
" ,"",' ,,. '
. LU
: . :i~~;:~~
Pristine Springs Inc.
10 Vaagen Brothers Lumber Inc.
11 Horseshoe Bend Hydro
12 Contractors Power Group Inc.
13 Rupert Cogeneration Partners
14 Glenns Ferry Cogeneration Partne
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
Total
FERC FORM NO- 1 (ED- 12.Paae 326.
Name of Respondent Jhis ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1 ) X An Original (Mo, Da, Yr)End of 2004/04(2) . 0 A Resubmission 04/22/2005
PI., "-',.. '
(1-.../ t-"
~. _../:
\ccou
Rt ~l)
(Continued)ncludlng power exc ange
AD - tor out-ot-period adjustment. Use this code tor 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
i 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 (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 (f)
I must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
160 Report in column (g) the
megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatlhours
of power exchanges received and delivered, used as the basis for settlement. Do not ~eport net exchange.
7. Report demand charges in column 0). energy charges in column (k), and the total of any other types ot charges, including
J out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
I 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)
i include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by theagreement, 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
i 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.
I 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 ($)
(g)
(h)(i)
(j)
(I)(m)
61 ,429 669,93C 669 930
991 182,678 182,679
330 19, 70~19,703
06E 066
661 115,241 115,241
42,958 514,08~514 089
23.55E 1 ,490,32~1,490,323
20,40E 292,17=292,175
85=39, 70~39,709
62C 134,53C 134 530
40,01 2,485,75f 2,485,758
007 186.25~186.252
80,79C 816,91C 816,910
83, 78~001 ,55~001,552
259.876 205,930 351,266 815,124 192,715,345 111 ,724 195,642, 19~
FERC FORM NO.1 (ED. 12-90)Page 327.
I nt ftlS:'~ 'Uate of Keport(1): ~An Original:
, ',- ' (Mo, Da, Yr)
(2t ,EJAResubmission,
:'".....
04/22/2005...
PURCHA$ED POWERlAccount 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:
1 : " Ncupe,ofHespondent, '' I', ,;.. ", ,: "
Idahc) Power Company,i :
, ,;. """""-',,"'""',' ,' ',.. ..,.." '-I .., ',' " '""'" , ";". ,earwenoa Of KepOrt
End of 2004/04
.. "'V"_'d
.',.":"",""",.",,,,,~,- "
Co--" ""'
-'-
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.
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.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
1 Lewandowski Farms
2 Tasca - Nampa
3 Tasca- Twin Falls
Pristine Springs Inc #3
5- Ted S. SorensonfTiber Dam
6 Other Purchased Power
7 American Electric Power Service
Statistical
Classifi-
cation
(b)
Line
No.
8 Anaheim, City of
9 Arizona Public Service Co.
10 Arizona Public SerVice Co.
11 Avista Corp. - WWP Div.
12 Avista Corp. - WWP Div.
13 Avista Energy, Inc.
14 Avista Energy, Inc.
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 Demam Monthly CP Demand(e) (f)
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
Page 326.
- "'l-
lName of Respondent
")': (', ,~; '" 'This ;ort Is: ,, Date of Report', , "Year/Period of Report ( "
I~a~9:~o'!".~r,~k~p;:1,ny (H, X ~t;\ .original (Mo, Da, Yr) :.. c ' ;2004/04
.. "" .., , ,
" End, of.." .' , ,--
(2)"DAResubmission-
' ' "' ;
04/22/2005 '
.. ', ,, .- ", ' ," ,""'- '.. -" ,
c" ,
" '"" ,..
PU ~ct-
'"'
~ . cco~t ~~~~ (vontmuea)Including power ex 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 (f)
I 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)
I include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the. i agreement, provide an explanatory footnote.
Is,
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.
I 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 ($)
(g)
(h)(i)
(j)
(I)(m)
170/88~883
, ..
86E 66,57E 66,576
52,071 52,071
24,96~1, 129,56E 129,568
112 80C 031,510 031 510
039 039
631 231,41~231,414
106,080 192 22C 192 220
19,829 838,849 838,849
81f 448,01 448 017
35,341 1,418,O4C 1,418,040
16,40C 701,95C 701,950
259,876 205,930 351,266 815,124 192,715,345 111,724 195,642,192
FERC FO&M NO.1 (ED. 12-90)
..
Page 327.
Name of Respondent This
ooort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of ,2004/04
(2)D A Resubmission 04/22/2005
~A$ED POWER wccount 555)nc udmg 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 abbre~iate 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 Demanc Monthly CP Demand
(a)(b)(c)(d)(e)(f)
Benton County PUD WSPP N/A N/A N/A
Benton County PUD WSPP N/A N/A N/A
Black Hills Power Inc.WSPP N/A N/A N/A
Black Hills Power Inc.WSPP N/A N/A N/A
Bonneville Power Administration WSPP N/A N/A N/A
Bonneville Power Administration WSPP N/A N/A N/A
BP Energy Company WSPP N/A N/A N/A
BP Energy Company WSPP N/A N/A N/A
Burbank, City of WSPP N/A N/A N/A
Calpine Energy Services, loP.WSPP N/A N/A N/A
Calpine Energy Services, loP.WSPP N/A N/A N/A
Cargill Power Markets LLC WSPP N/A N/A N/A
Cargill Power Markets LLC WSPP N/A N/A N/A
Chelan Co PUD WSPP N/A N/A N/A
Total
f"'
r~'"
L .
~. .! .
l,. .
FERC FORM NO.lED. 12-90\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 2004/04(2)0 A Resubmission 04/22/2005
P L R(" TI
- -; ~~.. ~.'.'.~
ccount ~g~~) (l,;ontlnued)nclu Ing power exchange
AD - for out-at-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 (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 (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 m, 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 amountin 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)
02~46,605 46,605
00C 80,640 80,640
261 . 1 ,997,21~997,215
51~350,433 350,433
49,89€192.57L1 192,574
287 85L 1 0,365,03~10,365 034
20C 200
97~003,56~003,569
20C 80C 800
78E 73,57E 73,576
26,797 165,081 165,081
02E 32,01C 32,010
39,67C 829,44~829,445
499,46~499,464
259,876 205,930 351,266 815,124 192,715,345 111 724 195.642, 19~
FERC FORM NO. 1 lED. 12-90)Page 327.
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 2004/04(2)0 A Resubmission 04/22/2005
~CHASED POWER ~Account 555)Including 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, a~ide 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 AveragecationTariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
Clatskanie PUD WSPP N/A N/A N/A
Clatskanie PUD WSPP N/A N/A N/A
Conoco Phillips Company WSPP N/A N/A N/A
Constellation Energy Commodities WSPP N/A N/A N/A
Constellation Power Source, Inc.WSPP N/A N/A N/A
Constellation Power Source, Inc.WSPP N/A N/A N/A
Coral Power, LLC WSPP N/A N/A N/A
Coral Power, LLC WSPP N/A N/A N/A
Douglas County PUD WSPP N/A N/A N/A
Douglas County PUD WSPP N/A N/A N/A
EI Paso Electric Company WSPP N/A N/A N/A
EI Paso Electric Company WSPP N/A N/A N/A
ENMAX Energy Marketing Inc.SF WSPP N/A N/A N/A
Entergy-Koch Trading, LP WSPP N/A N/A N/A
Total
.. .
FERC FORM NO.1 (ED. 12-90\Paae 326.
J Name of Respondent This ~ort Is:Date of Report Year/Period of Report
jldaho Power Company (1) X An Original (Mo, Da, Yr)End of 2004/04
(2)D A Resubmission 04/22/2005
PL.. ~L.. '0 l'1-" . ""''.'.~ ccou
~8~~) (Contlnueo)nc U Ing power exc ange
I 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
I 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
I NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demandduring 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.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
I of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.7. Report demand charges in column m, 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)
I 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.
18. 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.
- -
I 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)
140 02C 020
200 49,100 49,100
175 339 339
800 605 200 605,200.
675 675
63,130 847 13::847,133
251 58,21-4 58,214
167 225 271 365 271 365
385 15,135 15,135
197 144,870 144,870
215 34::343
400 18,40C 18,400
200 60,700 60,700
60C 163,200 163,200
259,876 205,930 351,266 815,124 192,715,345 111 724 195,642,193
FERC FORM NO.1 (ED. 12-90)Page 327.
Nam e of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da. Yr)End of 2004/04(2)0 A Resubmission 04/22/2005
~CHASED POWER hAccount 555)( ncluding 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., 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 AveragecationTariff Number Demand (MW)Monthly NCP Demanc Monthly CP Demand
(a)(b)(c)(d)(e)(f)
Eugene Water & Electric Board WSPP N/A N/A N/A
Eugene Water & Electric Board WSPP N/A N/A N/A
Franklin County P.WSPP N/A N/A N/A
Franklin County P .WSPP N/A N/A N/A
Grant County P .WSPP N/A N/A N/A
Grant County P .WSPP N/A N/A N/A
Grays Harbor PUD WSPP N/A N/A N/A
J. Aron & Company WSPP N/A N/A N/A
J. Aron & Company WSPP N/A N/A N/A
Mirant Americas Energy Marketing WSPP N/A N/A N/A
Morgan Stanley Capital Group Inc wspp N/A N/A N/A
Morgan Stanley Capital Group Inc WSPP N/A N/A N/A
Nevada Power Company wSPP N/A N/A N/A
Nevada Power Company WSPP N/A N/A N/A
Total
r~'
,. ," '
t.,
r '
. :.
FERC FORM NO.1 (ED. 12-90)Page 326.
, '
Name of Respondent This
ooort
Is:Date of Report Year/Period of Report
I Idaho Power
Company (1 ) X An Original (Mo, Da, Yr)End of 2004/04
(2)0 A Resubmission 04/22/2005
r'U '~I .. '~iicfl ,1-'"""""
g.
ccount 55~~~ (L;ontlnued)Including power exchange)
I 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 (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.
. 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 OJ, 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)
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,
d 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.
OJ'
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)
655 33,885 33,885
200 269,550 269,550
941 39,902 39,903
600 60C 72,600
69€72,76e 72,765
80C 36,000 36,000
,46e 63,722 63,722
160 92C 920
38,200 970,400 970,400
200 146 600 146,600
5,402 188 931 188,931
567,732 25,~69,76~25,969,763
145 285,685 285,685
225 75C 750
259,876 205,930 351,266 815,124 192,715,345 111,724 195,642,193
FERC FORM NO.lED. 12.90)Page 327.
N~~e,of~espondent '," ~~ir ~:~~ 1
9~9 ~1 :
:,,'' .'Date of Report Year/Period of R~port . .. '
, 1;,i
, .
(Mo, Da,Yr)2004/04,
! ,..
End ofl~ah9. ~9~erP~~p~flY,
' q " ,;
C:'":'i::
';:),
(2);OA Resubrnission
' '' "
04/22/2005.,'IC,
' ', ", ', ', ,' .'
~C~A~ED POWER hAccou~t 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., 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 r .
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)
NorthPoint Energy Solutions Inc.WSpp N/A N/A N/A
NorthWestern Energy, LLC.
",'
WSPP N/A N/A N/A
I ,NorthWestern Energy, LLC.WSpp N/A N/A N/A
NorthWestern Energy, LLC.V6-N/A N/A N/A
Okanogan County P.WSPP N/A N/A N/A
Pacific Northwest Generating Coo WSPP N/A N/A N/A
Pacific Northwest Generating Coo WSPP N/A N/A N/A
PacifiCorp Inc.WSPP N/A N/A N/A
PacifiCorp Inc.WSPP N/A N/A N/A
Portland General Electric Com pan WSPP N/A N/A N/A
Portland General Electric Com pan WSPP N/A N/A N/A
Powerex Corp.WSPP N/A N/A N/A
Powerex Corp.WSPP N/A N/A N/A
PPL Montana, LLC WSPP N/A N/A N/A
Total
FERC FOR~ NO.:1 (ED. 12-90)Page 326.
.. ----.-' '- , :;~'" \i' i ~~Is (g)~~~g
i~al
' "", ~~~g~~~)ort , '" ,~~:r:eri~d ~~~j~:..
)c\'
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(2f DA'Resubm tssiOn' ,.. ,: 04/22/2005
UL, ~(.".. ..,......."'1' 1J
~......'.\.'_
ccount9~9)\ (l,;Ontmued)dncluding power exchanges)
AD - for out-af-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.
' .Naq1e'of-:Respondent " "" ,, ., - ".... " ,
lda~9 eo.Yt~r.GqI11P~ny
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation far 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 (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 (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 G), 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
i 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 requir~d data.
- --, ..--,.. ,- - -
POWER EXCHANGESMegaWatt Hours
Purchased MegaWatt Hours MegaWatt HoursReceived Delivered
(g)
(h) (i)
135
36C
42~
48,457
16C
03C
80C
84,
59,121
27,57C
186,90€
17,88E
161,80~
79,87~
COST/SETTLEMENT OF POWER
Demand Charges
" -'
Energy Charges Other Charges
~I ~~~
' -
\'1
80E
122,96C
16,82E
930,867
38C
50,06~
32,400
048,513
556,97E
196,803
973,972
985,4H
689,02C
554,30~
UneTotal Q+k+l)
of Settlement ($)
(m)
805
122 960
16,825
930,867
380
50,065
32,400
048,513
556,975
196,803
973,972
985,415
689,020
554 304
. -, j
259,876 192,715,345 111 ,72~195,642, 19~205,930 . 351,266 815,124
FERC FO~M NO. t(ED. 12-90)Page 327.
Name of Resp~r)dent ThiS
'OOortIS:,,' ,, Date ot Keport , y ~ar/l""enOQ ,OT~~pOn: ,,-
(1):' XA~.9riginaf
' "
- (Mo, Da, Yr)End of ?QO4/04Idaho Powe~C()inp~ny ,1,
(2)1 ' 0 A Resubmissiorf
!' - "
04/22/2005
" ,,' -;, ,, ;" -
~ED POWERchACCOU)t 555)
nc u Ing power ex anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving 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 footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter 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 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 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 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 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 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)
PPL Montana, LLC WSPP N/A N/A N/A
PPL Montana, LLC WSPP N/A N/A N/A
PPM Energy, Inc.WSPP N/A N/A N/A
PPM Energy, .Inc.WSPP N/A N/A N/A
Public Service Co. of Colorado WSPP N/A N/A N/A
Public Service Co. of Colorado WSPP N/A N/A N/A
Public Service Company of New Me WSPP N/A N/A N/A
Public Service Company of New Me WSPP N/A N/A N/A
Puget Sound Energy, Inc.WSPP N/A N/A N/A
Puget Sound Energy, Inc.WSPP N/A N/A N/A
Rainbow Energy Marketing Corpora WSPP N/A N/A N/A
Rainbow Energy Marketing Corpora WSPP N/A N/A N/A
Rocky Mountain Generation WSPP N/A N/A N/A
Salt River Project WSPP N/A N/A N/A
Total
FERC FORM NO.1 (ED. 12-90)Page '326.10-
; ~ '
:17;~:-;~w;:pJ~::~y.U)IS ~~~~~girJar /, .' rJ~~ g~~~~)
ort
, (2Y DAResubmission"""" ':: '
:04/22/2005 ,
, ,
Pl,. ~(... "l t""'
~" -'""'- ,
ccouot 555),(0 ntanued)
In u Ing power exChangeS)
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.
, ,. "Y earwenoo, aT K~p'On: , ' ,
End of ; 2004/04 :
' '""', ,! ,. ,
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 (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.
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,
POWER EXCHANGESMegaWatt HoursPurchased MegaWatt Hours MegaWatt Hours" I Received Delivered
(g)
(h) (i)
36,535
115,896
24,24S
80,37E
88E
20,400
19,941
80C
95~
18,990
16,585
31,94f
136
51€
COST/SETTLEMENT OF POWER
Energy Charges Other Charges
($) ($)
(k)
1 ,499,706
738,991
953,382
603,731
73,420
867,400
755,811
96,160
206,41 e
803,91 ~
639,604
297,14C
12f
267,16€
LineTotal ij+k+l) No
of Settlement ($)
(m)
1,499,706
738,991
953,382
603,731
73,420
867,400
755,811
96,160
206,418
803,919
639,604
297,140
128
267,166
Demand Charges
259,876 '111 ,724 195,642,19~205,930 351,266 815,124 192,715,345
FERC FORM NO.,1(ED.12-90)Page 327.
Name of Respondent This
ooort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2004/04
(2)0 A Resubmission 04/22/2005
~C~~$ED POWER ~ccou~t 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., 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
y~ar 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)
Seattle City Light Wspp N/A N/A N/A
Seattle City Light WSPP N/A N/A N/A
Sempra Energy Trading Corporatio Wspp N/A N/A N/A
Sempra Energy Trading Corporatio WSPP N/A N/A N/A
Sierra Pacific Power Company WSPP N/A N/A N/A
Sierra Pacific Power Company WSPP N/A N/A N/A
Silicon Valley Power WSPP N/A N/A N/A
Snohomish County PUD WSPP N/A N/A N/A
Snohomish County PUD WSPP N/A N/A N/A
Tacoma Power WSPP N/A N/A N/A
Tacoma Power WSPP N/A N/A N/A
Tractebel Energy Marketing, Inc.WSPP N/A N/A N/A
Tractebel Energy Marketing, Inc.WSPP N/A N/A N/A
TransAlta Energy Marketing (U.WSPP N/A N/A N/A
Total
1, '
Ir'
i \
fr'
if'
.If'
" "
"1, .
~..
1'1
I '
s=-=~t". I=n~u t.ln 1 lI=n 1 ?Qn\Paae 326.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
. Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2004/04
(2)0 A Resubmission 04/22/2005
P\'" ~C!-I/\
~ d~""",~y~~coun\~8~~) (continued)nc U mg power exchange
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 (SO-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (SO-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.
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.
I 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 ($)
(g)
(h)(i)(I)(m)
145 579,471 579,471
12,521 518,749 518,749
1,495 121 095 121,095
399,594 18,403,48C 18,403,480
943 338,5ge 338,595
61S 174 56~174,569
80C 35,600 35,600
6ge 297 861 297,861
80C 260,50C 260,500
155 134,42e 134,425
201 174,152 174,152
741 164,957 164,957
29,60C 297,55C 1 ,297 550
11,48e 466,04~466,043
259,876 205,930 351,266 815,124 192,715,345 111,724 195,642 193
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2004/04
(2)0 A Resubm ission 04/22/2005
~CHA$ED POWER hAccount 555)Including power exc anges)
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.
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 (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 r~main 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 AveragecationTariff Number Demand (MW)Monthly NCP Demanc Monthly CP Demand
(a)(b)(c)(d)(e)(f)
TransAlta Energy Marketing (U.WSPP N/A N/A N/A
TransCanada Power WSPP N/A N/A N/A
Tri-State Generation and Transmi WSPP N/A N/A N/A
Turlock Irrigation District WSPP N/A N/A N/A
Utah Associated Municipal Power WSPP N/A N/A N/A
Western Area Power Administratio WSPP N/A N/A N/A
Anaheim, City of WSPP
Morgan Stanley Capital Group Inc WSPP
Puget Sound Energy,lnc.WSPP
Sierra Pacific Power Company WSPP
tl::=~iK~i:~~t~
Total
"',
r:'
' ," ,\: .
t.,
~I=Rr. FORM NO 1 lED. 12.90\Paae 326.
I Name of Respondent This ~ort Is:Date of Report Year/Period of Report
\ Idaho Power Company (1 ) X An Original (Mo, Da, Yr)End of 2004/04
(2)0 A Resubmission 04/22/2005
Pl.. "'"" '
~-'
d' _.
'.\~,
ccountb
~g~)
(COntinued)nc u Ing power exchange
I 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
I NCP demand is the maximum metered hourly
(GO-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (GO-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.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
I 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)
I 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.
18. 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.
, . ---
I 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 ($)
(g)
(h)(i)(I)(m)
195,400 630,550 630,550
467 19,579 19,579
775 99,51 99,518
1~5 9ge 4~95
76C 60,058 60,058
105 045 045
102,470 87,860
240 240
13,922 13,922
52,136 9,477
869
35,125 220,826
12,034
259,876 205,930 351,266 815,124 192,715,345 111,724 195,642, 19~
FERC FORM NO.1 lED. 12-90)Page 327.
Name of Respondent This 'OOort Is:Date of Report Year/Period of Report
Idaho Power Company (1 ) X An Original (Mo, Da, Yr)End of 2004/04
(2) D A Resubmission 04/22/2005
~A$ED POWER hAccount 555)nc udlng 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., 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 qf 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)
Other Transactions
Acctg Valuation of Anaheim I
City of Exchange
Power Exchanges
All statistical classification of OS
is Non-Firm Purhcases.
Total
~ -\, - -
FFRC'. FORM NO- 1/EO. 12.90\Paae 326.
i .
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 2004/04(2)D A Resubmission 04/22/2005
PU "'"" .. "
(1-1 d
:- . -.
:X, ccouRt t)t)~~) (Continued)nc u mg 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
I 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
I average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and .(f). Monthly
I NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demandduring 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.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
I of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange... 1. Report demand charges in column m, 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)
I 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.
18. 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.
-..
I MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER LineMegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total G+k+l)Purchased No.Received Delivered
($)($)
of Settlement ($)
(g)
(h)(i)(I)(m)
111.724 111 724
259.876 205,930 351 ,266 815,124 192,715,345 111,724 195,642.19~
FERC FORM NO.1 (ED. 12-90)Page 327.
1:'
" ,
This Page Intentionally Left Blank
t .
v':;
.... '\ '
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/22/2005 2004/04
FOOTNOTE DATA
!schedule Page: 326 Line No.Column:
The Tamarak Energy Partnership demand readings are taken from an electronic demandrecorder provided by Idaho Power Company. The actual demand is not used in tetermining the
ost of energy.
!Schedule Page: 326 Line No.Column: navailable
!schedule Page: 326 Line No.Column:
navailable
!schedule Page: 326.Line No.: 6 Column:
da-West, a subsidiary of IdaCorp, has partial ownership of these proj ects.
!schedule Page: 326.Line No.: 7 Column:
da-West, a subsidiary of IdaCorp, has partial ownership of these projects.
!schedule Page: 326.4 Line No.: 8 Column:
da-West a subsidiary of IdaCorp has partial ownership of these proj ects.
!Schedule Page: 326.12 Line No.11 Column:
cheduled losses not removed with loss transactions.
!schedule Page: 326.12 Line No.: 12 Column:
Scheduled losses not removed with loss transactions.
!schedule Page: 326.12 Line No.: 13 Column:
cheduled losses not removed with loss transactions.
~chedule Page: 326.12 Line No.: 14 Column:
Scheduled losses not removed with loss transactions.
FERC FORM NO.1 (ED. 12-Page 450.
Name of Respondent
Idaho Power Company
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
1 ,a9qne\fiI!~'.I?()wer A~r:riihi~tf~tion...+..a;r;t~Lli
2 :,~()i1n~vill~.J?p~"~9!!tihi~tratiOQ7u.$.
3 .
' .
a()nij~villePP~f~~91inistrati9~+Rai..
4 ."13()nri~villE!\~9~r~~miMistr~ti9r1.RPF1,j.;t.
BbhrevHl~Fr
14 Arizona Public Service
15 Arizona Public Service
16 Arizona Public Service
17 Boneville Power Administration
Line
No.
go;tpi~C9 "
g~ci~;89rp
Arizona Public Service
TOTAL
I=I=Rr'. FORM NO 1 fI:::n 1?Qn\
This ~ort Is:(1) ~An Original(2) DA Resubmission
Date of Report
(Mo, Da, Yr)
04/22/2005
Year/Period of Report
End of 2004/04
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Bonneville Power Administratio
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Oregon Trails Electric Co~op
United States Bureau of Reclama
ccount(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)
ln column (d) enter a Statistical Classification code based or:'! 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.
Bonneville Power Administratio
.~.
.. Bonneville Power Administratio Raft River Electric Co-op
Priority Firm Customers
Vigilante
Milner Irrigation District
Bonneville Power Administration
PacifiCorp West
United States Bureau of Indian
PacifiCorp West
PacifiCorp West
PacifiCorp West
Bonneville Power Administration
Bonneville Power Administratio
Bonneville Power Administratio
United States Bureau of Reclam
Seattle City Light
PacifiCorp West
Bonneville Power Administratio
PacifiCorp West
PacifiCorp West
PacificCorp East
PacifiCorp East
PacifiCorp East
PacifiCorp East
Bonneville Power Administratio
Avista
Avista
Sierra Pacific Power
PacifiCorp East
Sierra Pacific Power
Paoe 328
I.. ..
i: "
Statistical
Classifi-
cation
(d)
FNO
FNO
FNO
FNO
elF
elF
elF
FNO
elF
elF
elF
'c.
\. .
! "
Name of Respondent This (8Jort Is:Date of Report Year/Period of Report
Idaho Power Company (1 ) X An Original (Mo, Da, Yr)End of 2004/04(2)0 A Resubmission 04/22/2005
T I '\T"OF ELEC.I KI~II y t-!.)K l! I HI::K:S (P ccount ontmuedT(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 U) the total megawatthours received and delivered.
I 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)
259,381 259,381
186,714 186,71L1
214,992 214,99~
700,151 700,151
Bannack Tap Vigilante Electric
Minidoka, Idaho Various in Idaho 927 92~
LYPK LGBP 767
160 16C
LaGrande, Crego Various in Idaho 15,493 15,493
JBSN ENPR 196,200 196,200
JBSN ENPR 11,989 11,989
BOBR JBSN 253,761 253,761
BOBR LGBP 12,000 12,00C
BOBR LOLO 725 72~
BOBR M345 224,400 224,40C
LGBP BOBR 13,900 13,90C
LOLO M345 812 812
597 529 594,76~
8=8=~r.. I=n~M hln 1 (I=n 1 ?Qn\P~lJA 329
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2004/04
(2)D A Resubmission 04/22/2005
I ~OF t:Lt;L; I KI~II Y tUK U J Ht:.K ~ccount 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) ~he 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 Paym ent 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)
Cargill Power Markets PacifiCorp East NorthWestern/PacifiCorp East
Cargill Power Markets PacifiCorp East Bonneville Power Administration
Cargill Power Markets PacifiCorp East Avista
Cargill Power Markets PacifiCorp East Sierra Pacific Power
Cargill Power Markets PacifiCorp West PacifiCorp East NF'
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
Cargill Power Markets PacifiCorp West Bonneville Power Administration
Cargill Power Markets PacifiCorp West Sierra Pacific Power
Cargill Power Markets Bonneville Power Administratio PacifiCorp East
Cargill Power Markets Bonneville Power Administratio PacifiCorp West
Cargill Power Markets Bonneville Power Administratio Sierra Pacific Power
Cargill Power Markets Avista PacifiCorp East
Cargill Power Markets Avista Sierra Pacific Power
TOTAL
f :
Ie. '
I::I::Ct" .I::ncu "In .. fcn .. "'-tin'P~nA 328_
,. .
Name of Respondent This (8Jort Is:Date of Report Year/Period of Report
Idaho Power Company (1 ) X An Original (Mo, Da. Yr)End of 2004/04
(2)0 A Resubmission 04/22/2005
To"..OF ~I I-f KI~II Y r~K L! I Mt::K
~ ,
(Pccount l'l"'l-i )t~ ontlnued)(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 seNice, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path
, "
point to point" transmission seNice. 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
I (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 seNice 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 U) the total megawatthours received and delivered.
I 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)
BOBR HTSP 175 17~
BOBR LGBP 10,561 10,561
BOBR LOLO
BOBR M345 950 95C
ENPR BOBR 97,856 85E
ENPR JBSN 813 81~
ENPR M345 215 215
HTSP BOBR
HTSP M345 352 352
JBSN BOBR 200 200
JBSN LGBP 46,140 46,14C
JBSN M345 42,261 42,261
LGBP BOBR 519
LGBP JBSN 300 .30C
LGBP M345 40,294 40,294
LOLO BOBR 133 133
LOLO M345 198 19€
597,529 594, 76~
FERC FORM NO.lED. 12-90\Pace 329.
Name of Respondent This (8Jort Is:Date of Report Year/Period of Report
Idaho Power Company (1 ) X An Original (Mo, Da, Yr)End of 2004/04
(2)D A Resubmission 04/22/2005T. V" JI\j OF ~I ~r I KI~II Y ~OR G, '
"- ,,",
~~ccount 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)
Cargill Power Markets Sierra Pacific Power PacifiCorp East
J. Aron - Goldman Sachs PacifiCorp East Bonneville Power Administration
J. Aron - Goldman Sachs PacifiCorp East Sierra Pacific Power
J. Aron - Goldman Sachs NorthWestern/PacifiCorp East Sierra Pacific Power
J. Aron - Goldman Sachs Bonneville Power Administratio PacifiCorp East
J. Aron - Goldman Sachs Bonneville Power Administratio Sierra Pacific Power
J. Aron - Goldman Sachs Avista Sierra Pacific Power
J. Aron - Goldman Sachs Sierra Pacific Power PacifiCorp East
J. Aron - Goldman Sachs Sierra Pacific Power PacifiCorp West
J. Aron - Goldman Sachs Sierra Pacific Power Bonneville Power Administration
Morgan Stanley Capital Group PacifiCorp East NorthWestern/PacifiCorp East
Morgan Stanley Capital Group PacifiCorp East Bonneville Power Administration
Morgan Stanley Capital Group PacifiCorp East Avista
Morgan Stanley Capital Group PacifiCorp East Sierra Pacific Power
Morgan Stanley Capital Group PacifiCorp West PacifiCorp East
Morgan Stanley Capital Group PacifiCorp West Sierra Pacific Power
Morgan Stanley Capital Group NorthWestern/PacifiCorp East Sierra Pacific Power
TOTAL
, f
\ .
1=1=~r.. I=O~M NO 1 fF:n 12-~n\Pace 328.
, .
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1 ) X An Original (Mo, Da. Yr)End of 2004/04(2)0 A Resubmission 04/22/2005
OF 1=1 K.I~II Y t-~K U I Ht:K (I~ ccount '" ontlnued)(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
: (9) 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.
i 8. Report in column (i) and U) the total megawatthours received and delivered.
I 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)
M345 BOBR 400 40C
BOBR LGBP
BOBR M345 017 01i
HTSP M345 352 352
LGBP BOBR
LGBP M345 822 822
LOLO M345 326 32€
M345 BOBR
M345 ENPR
M345 LGBP 770 77C
BOBR HTSP 192 192
BOBR LGBP 846 84€
BOBR LOLO 304 30.c1
BOBR M345 84,610 61C
ENPR BOBR 456 45E
ENPR M345 876 87E
HTSP M345 852 852
597 529 594 76~
FERC FORM NO.lED. 12.90\Paae 329.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1 ) X An Original (Mo, Da, Yr)End of 2004/04
(2)0 A Resubmission 04/22/2005
I v OF ~I I-r I KIL;l I Y FOR UI HI::K~~~Ccount 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)
Morgan Stanley Capital Group Bonneville Power Administratio Sierra Pacific Power
Morgan Stanley Capital Group Avista PacifiCorp East
Morgan Stanley Capital Group Avista Sierra Pacific Power
Morgan Stanley Capital Group Seattle City Light PacifiCorp East
Morgan Stanley Capital Group Seattle City Light NorthWestem/PacifiCorp East
Morgan Stanley Capital Group Seattle City Light Bonneville Power Administration
Morgan Stanley Capital Group Seattle City Light Sierra Pacific Power
Pacificorp Power Marketing PacifiCorp East PacifiCorp West
Pacificorp Power Marketing PacifiCorp East NorthWestem/PacifiCorp East
Pacificorp Power Marketing PacifiCorp East Sierra Pacific Power
Pacificorp Power Marketing PacifiCorp West PacifiCorp East
Pacificorp Power Marketing PacifiCorp West Sierra Pacific Power
Pacificorp Power Marketing PacifiCorp West PacifiCorp East
Pacificorp Power Marketing PacifiCorp West Sierra Pacific Power
Pacificorp Power Marketing Bonneville Power Administratio PacifiCorp East
Portland General Electric PacifiCorp East Bonneville Power Administration
Portland General Electric NorthWestem/PacifiCorp East Bonneville Power Administration
TOTAL
. -! "
1',
F=I=Rr. FORM NO 1 (FD. 12-90\PaQe 328.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2004/04
(2)D A Resubmission 04/22/2005
Of ELEGI KIL;l I Y FgR U I Ht=K~ ,(Jlccount 4:JnU( ontlnued)
(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 U) 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
I Tariff Number Designation)Designation)(MW)Megawatt Hours Megawatt~ours No.
Received Delivered
(e)(f)
(g)
(h)(i)
LGBP M345 974 97.:1
LOLO BOBR 304 30.:1
LOLO M345 337 337
LYPK BOBR 11,517 517
LYPK HTSP 392 392
LYPK LGBP 10,165 1 0, 165
LYPK M345 176,977 176,977
BOBR ENPR 107,354 107,35~
BOBR HTSP 23,994 23,99~
BOBR 8aCM345800
ENPR BOBR 147 348 147,349
ENPR M345 14,133 133 .. 12
JBSN BOBR 194,529 194,52E
JBSN M345 29,510 29,51C
LGBP BOBR
BOBR LGBP 100 10C
JEFF LGBP
.. --
814 814
597 529 594 762
FFRI". FORM NO.1 tED_. 12-90\Paae 329.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2004/04(2)D A Resubmission 04/22/2005T. ~" . OF ELEl,; I KIl,;l I Y ~9R U I r:II::~~ (~ccount 4:)6)(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 tran~mission 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)
Powerex Corp.PacifiCorp East PacifiCorp West
Powerex Corp.PacifiCorp East NorthWestem/PacifiCorp East
Powerex Corp.PacifiCorp East PacifiCorp West
Powerex Corp.PacifiCorp East Bonneville Power Administration
Powerex Corp.PacifiCorp East Avista
Powerex Corp.PacifiCorp East Sierra Pacific Power
Powerex Corp.PacifiCorp West PacifiCorp East
Powerex Corp.PacifiCorp West PacifiCorp West
Powerex Corp.PacifiCorp West Sierra Pacific Power
Powerex Corp.NorthWestem/PacifiCorp East PacifiCorp East
Powerex Corp.NorthWestern/PacifiCorp East PacifiCorp West
Powerex Corp.NorthWestern/PacifiCorp East Bonneville Power Administration
Powerex Corp.NorthWestern/PacifiCorp East Sierra Pacific Power
Powerex Corp.PacifiCorp West PacifiCorp East
Powerex Corp.PacifiCorp West NorthWestem/PacifiCorp East
Powerex Corp.PacifiCorp West Bonneville Power Administration
Powerex Corp.PacifiCorp West Sierra Pacific Power
TOTAL
- -~. ~.. .
FERC FORM NO.1 (ED. 1 90\Pace 328.
Name of Respondent This (8Jort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2004/04(2)0 A Resubmission 04/22/2005
OF ~I ~r I KI~II Y t-!,)K U I Ht:K
~ ,
(Account ontmued)(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 (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 U) 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)
BOBR ENPR 829 82~
BOBR HTSP 256 25E
BOBR JBSN 120 12C
BOBR LGBP 50,394 50,39~
BOBR LOLa 306 30E
BOBR M345 624 62L
ENPR BOBR 26,435 26,43e
ENPR JBSN
ENPR M345 12,446 12,446
HTSP BOBR 175 175
HTSP JBSN 239 239
HTSP LGBP 391 391
HTSP M345 657 651
JBSN BOBR 1,435 1 ,43e
JBSN HTSP
. 5 JBSN LGBP 81,829 81,829
JBSN M345 19,070 19,07C
597 529 594 76~
F=F=J?r.. F=nJ?M Nn 1 (F=n 12-Qrn Pace 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 2004/04
(2)0 A Resubmission 04/22/2005
UI- t:Lt::.(.;It'm..,~.11 T tUK.U-'HI::.t"(~.L~ccount456)(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)
Powerex Corp.NorthWestern/PacifiCorp East PacifiCorp East
Powerex Corp.NorthWestern/PacifiCorp East Sierra Pacific Power
Powerex Corp.Bonneville Power Administratio PacifiCorp East
Powerex Corp.Bonneville Power Administratio PacifiCorp West
Powerex Corp.Bonneville Power Administratio Sierra Pacific Power
Powerex Corp.Avista PacifiCorp East
Powerex Corp.Avista Sierra Pacific Power
Powerex Corp.Sierra Pacific Power PacifiCorp East
Powerex Corp.Sierra Pacific Power PacifiCorp West
Powerex Corp.Sierra Pacific Power Bonneville Power Administration
Powerex Corp.NorthWestern/PacifiCorp East Bonneville Power Administration
PP & L Montana PacifiCorp East Bonneville Power Administration
PP & L Montana NorthWestern/PacifiCorp East PacifiCorp East
PP & L Montana NorthWestern/PacifiCorp East Bonneville Power Administration
PP & L Montana NorthWestern/PacifiCorp East Avista
PP & L Montana NorthWestern/PacifiCorp East PacifiCorp East
PP & L Montana NorthWestern/PacifiCorp East Bonneville Power Administration
TOTAL
r;' '
r '
t: '
I;,
\, .
J=J=Rt"- J:nRM Nn 1 n::n 1".~0\Pace 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 2004/04
(2)D A Resubmission 04/22/2005
,I OF ELEC-I KI\';II Y t-'gK l! I HI=K
;:) ,
(,I) ccount LL"'n Jt! ontlnued)(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 U) 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 BOBR
JEFF M345 054 O5~
LGBP BOBR 33,825 33,82~
LGBP JBSN 1 ,463 1 ,46~
LGBP M345 11,615 61 ~
LOLO BOBR 740 74C
LOLO M345 4,494 4,49~
M345 BOBR 156 156
M345 ENPR
M345 LGBP 14,478 14,4 78
MLCK LGBP
BOBR LGBP 303 303
HTSP BOBR 135 13~
HTSP LGBP 245 24~
HTSP LOLO 552 552
JEFF BOBR 131
. .
:16
JEFF LGBP ,400 1,40C
597,529 594,76J
I .
FFRC'. FORM NO 1 (FD- 12.90\Pace 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 2004/04
(2)0 A Resubmission 04/22/2005
I 'V 11\.1 OF ELEC-I KI~II y FOR U I Ht:K~1~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 o(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 Generallnstruction 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 NorthWestem/PacifiCorp East Sierra Pacific Power
PP & L Montana Sierra Pacific Power NorthWestem/PacifiCorp East
PPM Energy PacifiCorp East PacifiCorp West
PPM Energy PacifiCorp East Bonneville Power Administration
PPM Energy PacifiCorp East Sierra Pacific Power
PPM Energy PacifiCorp West PacifiCorp East
PPM Energy NorthWestem/PacifiCorp East PacifiCorp East
PPM Energy PacifiCorp West PacifiCorp East
PPM Energy PacifiCorp West Bonneville Power Administration
PPM Energy Bonneville Power PacifiCorp East
PPM Energy Avista PacifiCorp East
Public Service of Colorado PacifiCorp East Bonneville Power Administration
Public Service of Colorado PacifiCorp West PacifiCorp West
Public Service of Colorado Bonneville Power PacifiCorp West
Puget Sound Energy Marketing NorthWestem/PacifiCorp East Bonneville Power Administration
Sempra Energy Trading Corp PacifiCorp West PacifiCorp East
Sempra Energy Trading Corp PacJfiCorp West Sierra Pacific Power
TOTAL
\ .
r=r=~t". s:n~M Nn 1 n=n 17.Qn\Paae 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 2004/04
(2)D A Resubmission 04/22/2005
I. ~..01- ~I j;;, I KI~II Y F9R OTHERS ,(pccount Ll"'hlll ontlnued)(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.
~. 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 U) 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 M345
M345 HTSP
BOBR ENPR 183 183
BOBR LGBP 18,645 18,645
BOBR M345
ENPR BOBR
HTSP BOBR 175 17e
JBSN BOBR 125 12e
JBSN LGBP 360 36C
LGBP BOBR 060 060
LOLO BOBR 825 825
BOBR LGBP 200 20C
ENPR JBSN 113 112
LGBP JBSN 171 171
HTSP LGBP 935 93e
ENPR BOBR 22,725 22,725
ENPR M345 423 423
597,529 594,76:1
, ,
I '
FFRr. FORM NO 1 lED. 12.Paae 329.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2004/04
(2)0 A Resubmission 04/22/2005
\". OF ELEGI KICII Y FOR U I Ht= ~s ~~ccount 4bb)(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)
Sempra Energy Trading Corp Avista PacifiCorp East
Sempra Energy Trading Corp Avista Sierra Pacific Power
Sierra Pacific Power PacifiCorp East Sierra Pacific Power
Sierra Pacific Power PacifiCorp West Sierra Pacific Power
Sierra Pacific Power NorthWestem/PacifiCorp East Sierra Pacific Power
Sierra Pacific Power PacifiCorp West Sierra Pacific Power
Sierra Pacific Power NorthWestem/PacifiCorp East Sierra Pacific Power
Sierra Pacific Power Bonneville Power Administratio Sierra Pacific Power
Sierra Pacific Power Avista PacifiCorp East
Sierra Pacific Power Avista Sierra Pacific Power
Sierra Pacific Power Sierra Pacific Power NorthWestem/PacifiCorp East
Sierra Pacific Power Sierra Pacific Power Bonneville Power Administration
TransAlta Energy Marketing (US) Inc.NorthWestem/PacifiCorp East PacifiCorp East
TransAlta Energy Marketing (US) Inc.Avista Sierra Pacific Power
TOTAL
r .,
L ,
CCDr cnDU tJn 1 ll=n 1 ?_on\Pace 328.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
aho Power Company (1 ) X An Original (Mo, Da, Yr)End of 2004/04
(2)D A Resubmission 04/22/2005
I ~~t- j.;1 1-1 I KI\,,;II Y FQR
~ " "-"'"" ,
(Jlccount LI."'nlll ontmued)(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 (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 U) 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)
LOLO BOBR 991 991
LOLO M345 685 68e
BOBR M345 197,428 197,42E
ENPR M345 70,538 70.538
HTSP M345 48,553 48.553
JBSN M345 48,580 48,58C
JEFF M345 230,432 230,432
LGBP M345 51 E),926 515,92f
LOLO BOBR 568 56E
LOLO M345 289,364 289,364
M345 HTSP 819 819
M345 LGBP 319 319
HTSP BOBR
. ..
LOLO M345 105 10e
597 529 594 762
ree,.. I:neu J..In 1 n::n ?Qn\P~n~ 329.
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2004/04
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) D A Resubmission 04/22/2005
. 11 OF ELEL; I KI(;II Y FOR U 1 HI::K:) (Account 4:)0) ((;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 (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.
Demand Charges
($)
(k)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERSEnergy Charges (Other Charges)
($) ($)
(I) (m)
279,511
374,661
42,880
887 845
507,398
881,871
415,463
533,475
15,000
221
860
922
108,230
436,242
22,570
536,729
62,364
45,344
166,201
72.238
612
Total Revenues ($)
(k+l+m)
(n)
786,909
256,532
458,343
1,421 320
15,000
221
4;~f?9
621
142
301
...
_i~~~()~
436,242
22,570
536,729
62,364
45.344
166,201
72,238
612
996,867 152,983 58,948 16,208,798
--...- ................... ..
,....... .... ftft\D_..... ~~n
Line
No.
l '
. r
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2004/04(2)0 A Resubmission 04/22/2005
If OF j;;1 ~( I KII.jII Y FgR qT -!L~~ !Account 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)
965 965
58,264 58,264
221 221
275 16,275
539,865 539,865
4,485 4,485
50,839 50,839
138 138
12,976 12,976
23,171 23,171
254 551 254 551
233,151 233,151
30,448 30,448
655 655
222,299 222,299
22,801 22,801
609 609
996,867 12,152,983 58,948 16,208,798
1:1:01' 1:1"\0" "11"\ .. 'I:n
.. .,-
on\D"'n... ~~n-
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 2004/04(2) 0 A Resubmission 04/22/2005
o.F E~EC'I KI',JII Y F9R U I t1I::.K~ !ACcount 450) ll,;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 rendere~, 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)
207 207
174 174
769 769
305 305
. 304 304
10,459 10,459
208 208
148 148
854 854
691 691
35,447 35,447
094 094
304 610 304,610
642 642
754 754
10,268 10,268
996 867 12,152 983 58,948 16,208,798
r .
. :
CCDI" cnDU tdn 1 fcn 1 ?-on\P::IOA 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 2004/04
(2)D A Resubmission 04/22/2005
Ir OF ELEC-I KI~II Y FQR I..? I Mt:K;J !Account 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 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 ($)Line
($)($)($)
(k+l+m)No.
(k)(I)(m)(n)
107 107
295 295
813 813
41,463 41,463
15,812 15,812
36,596 36,596
637 149 637 149
421 068 421,068
110 110
138 138
577,938 577,938
55,433 55,433
762,986 762,986
115.745 115,745
378 378
18,177 18,177
996,867 152,983 58,948 16,208,798
f .
- -
~~o~ '=1"\0.. ~II"\ .. ,~n ...., nn\D........ ":t":tn ":t
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 2004/04
(2)D A Resubmission 04/22/2005
T, ","II OF ELEGI KIl;l I Y FQR ClI Ht:K:S (Account 455) (l;ontmued)(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 allother 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 ($)Line
($)($)($)
(k+l+m)No.
(k)(I)(m)(n)
310 310
22,126 22.126
624 624
261 986 261.986
591 591
18.840 18,840
137,429 137,429
250 250
64,704 64,704
910 910
243 243
17,629 629
13,813 13,813
7,460 7,460
270 270
425,409 425,409
140 99,140
996,867 152,983 58,948 208,798
- .
Jr.
--....... -................ .. ,...... .... ....,
D.._.... -:t'\n
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2004/04
(2)0 A Resubmission 04/22/2005
TF'V~,u.t" ELEC-I Klvll Y r(JK ~ I Mt:.K;:i !Account 4:)0) (l;ontmued)(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 ($)Line
($)($)($)
(k+l+m)No.
(k)(I)(m)(n)
437 437
26,275 26,275
175,848 175,848
606 606
60.384 60,384
046 046
23,363 23,363
811 811
275 275
75,267 75,267
260 260
15,569 15,569
396 396
591 591
621 621
385 385
110 110
996,867 12,152,983 58,948 16,208,798
~r"""'" ~I"\.n.. "11"\.
..
,~n ..., nn\D"".."" ~~n!i\
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2004/04
(2)D A Resubmission 04/22/2005
OF ELEGI KIl,;ITYFQR OTHt:K~ ~Account 456) (l,;ontmued)(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 ($)Line
($)($)($)
(k+l+m)No.
(k)(I)(m)(n)
147 147
693 693
70,574 70,574
367 367
662 662
473 473
363 363
797 797
10,693 10,693
863 863
13,431 13,431
738 738
740 740.
267,668 267,668
982 982
996,867 152,983 948 16,208,798
rrl~"" ~noa. I..n " lII::n "., nn\D.."... 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 2004/04
(2)D A Resubmission 04/22/2005
OF ~I 1-1 t~Jyll Y r~H. ~ IntK~ !ACcount 4bo) (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 U) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 ~nd 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)
105,901 105,901
625 625
660,871 660,871
236,119 236,119
162,526 162 526
162,617 162,617
771 349 771,349
727,012 727 012
5~249 249
968,618 968,618
741 741
763 763
497 497
816 816
996 867 152 983 948 16,208,798
~~o,.. r:-I"\n.. ...'" I~n 4" nn\D"",.... ::\::\0.
r ..
v '
This P~ge Intentionally Left Blank
.- .-. -
._w
r '
\ -
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Oa, Yr)
Idaho Power Company (2)A Resubmission 04/22/2005 2004/04
FOOTNOTE DATA
'rschedule Page: 328 Line No.Column:
The network service agreement between Idaho Power and the Bonnefille Power Aqrninistration
for the Oregon Trail Electric Cooperative expires September 30,2011. The billing demand
for the network service is the customer s demand at the time of Idaho power Company
ransmission system peak and varies by month.
~chedule Page: 328 Line No.Column:
The network service agreement between Idaho Power and the Bonneville Power Administration
for the USBR expires December 31, 2004.
The billing demand for network service is the customer s demand at the time of Idaho Power
ransmission system peak and varies by month.
~chedule Page: 328 Line No.Column:
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
ransmission system peak and varies by month.
~chedule Page: 328 Line No.Column:
~chedule Page: 328 Line No.Column:
The agreement between Idaho Power and the Bonneville Power Administration expires
eptember 30, 2016.
~chedule Page: 328 Line No.Column:
The contract between Idaho Power and the Milner Irrigation District will automatically
renew on December 31,2004 . for a five year term unless either party provides prior notice.
~chedule Page: 328 Line No.Column:
The agreement between Idaho Power and the City of Seattle explres December 31, 2007.
ontract demand for 2004 was zero.
~chedule Page: 328 Line No.Column:
onthly customer charge.
~chedule Page: 328 Line No.Column:
The contract between Idaho Power and PacifiCorp - Imnaha expires on September 30, 2010.
~chedule Page: 328 Line No.Column:
The agreement between Idaho Power and the United States Department of the Interior, Bureau of Indian Affairs is subject to termination upon 90 days
ritten notice by the Bureau.
'rschedule Page: 328 Line No.Column:
his was a 2003 invoice that was not booked until 2004.
'rschedule Page: 328 Line No.10 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.
'rschedule Page: 328 Line No.11 Column:
~chedule Page: 328 Line No.12 Column:
I FERC FORM NO.1 (ED. 12-87)Page 450.
This ~ort Is: Date of Report(1) ~ An Original (Mo, Da, Yr)
(2) D A Resubmission 04/22/2005
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 ~ransmission 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 of the 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't'No. Name of Com or Public Statistical Magawatt- Magawan-liours liours
Authority. (Foot te Affiliations) Classification Received Delivered(b) (c) (d)
1 Delivered Power to Whir
2B9Q9~yjnep~~rAam~
Clatskanie PUD
Northwestern Energy
Northwestern Energy
6 Okanogan County
Seattle City Light
Sierra Pacific Power Co
Nam e of Respondent
Idaho Power Company
9 Snohornish County PUD
11 Received Power from Whl
LFP 163,446
040
594
100,930
160
840
920
120
163,446
040
594
100,930
160
840
920
120
12 Avista Corp WWP Div
13 Avista Corp WWP Div
14 Bonneville Power Admin
15 't36h~~Cj~pow~rI~drhi~j;::
:(.
i:;
' '
16 Clatskanie PUD
SFP
LFP
160,323
574 602
25,514
315,878
344
160,323
574,602
25,514
315,878
344
TOTAL 052,977 052,977
FFRC'.. FORM NO. 1/:!-O (REV. 02-04\Paae 332
Year/Period of Report
End of 2004/04
EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERDemana ~nergy Utner Total Cost ofChargeS Charges Charges Trans ssion
($) ($) ($)
(e) (f)
(g)
49,446
980
7,428
547,400
320
13,900
75,801
10,368
008,122
070,798
130,906
025,142
630
261 588 180,275
49,446
980
7,428
547,400
320
13,900
75,801
10,368
r '
008,122
070,798
130,906
025,142
630
441,863
Name of Respondent
Idaho Power Company.
Year/Period of Report
End of 2004/04
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) n A Resubmission 04/22/2005
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 onthe original contractual terms and conditions of the 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'No. Name of Com or Public Statistical Magawatt- Magawan-tiours tiours
Authority (Footnote Affiliations) Classification Received Delivered(a) (b) (c) (d)
1 Northwestern Energy LLC SFP 15,624 15,624
2NqrthlN~~~mg.gW9yL4G;;.i:i:;i;;?ki- LFP 103,567 103,567
3 Okanogan County PUD NF 3,648 3,648
PacifiCorp Inc NF 73,163 73,163
PacifiCorp Inc SFP 311 229 311,2296p~~9ml-
Portland General Elect
Seattle City Light
Sierra Pacific Power Co . NF
10 Snohomish County PUD
11 Tacoma Power
280
9,412
102
89,823
21,418
280
9,412
102
89,823
21,418
EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERVemana !:.nergy :umer Total Cost ofCharges Charges Charges Trans ssion
($) ($) ($)
(e) (f)
(g)
71,400 71,40013,464 200,464296 7,296
625,972 625,972
323,834 2.323,834
29,006 -006
20,880 20,880
23,803 23,803
30,280 30,280
173,693 173,693006 47,006
187,000
TOTAL 052,97 ,052,977 261 588 180,275 8,441,863
FERC FORM NO. 1/3-0 (REV. 02-04\PaQe 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 04/22/2005 2004/04
FOOTNOTE DATA
!schedule Page: 332 Line No.Column:
(1) Bonneville Power Administration LFP 9/30/2016
/' ,
~chedule Page: 332 Line No.15 Column:
(2) Bonneville Power Administration LFP 7/25/2011
~chedule Page: 332.Line No.Column:
(3)Norhtwestern Energy, L.C. LFP Contract can be terminated at anytime, with 30 days
rior notice
~chedule Page: 332.Line No.Column:
(4)(a) Adjustment of ($28,838.10) to Pacificorp Inc in May 2003. Pacificorp did not remove
amount from invoice creating overpayment.
(4) (b) Adjustment of ($167.68) for Pacificorp losses in December 2003.
"- '
L '
FERC FORM NO.1 (ED. 12-87)
l, -
Page 450.
I Name of Respondent This ~ort Is:Date of Rep'ort Year/Period of Report
Idaho Power Company (1 ) An Original (Mo, Da, Yr)End of 2004/04
(2) A Resubmission 04/22/2005
MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
! Line Descri)tion Amount
I No.(b)
Industry Association Dues 22,592
Nuclear Power Research Expenses
Other Experimental and General Research Expenses
Pub & Dist Info to Stkhldrs...expn servicing outstanding Securities
Oth Expn ;:.=5,000 show purpose, recipient, amount. Group if.:: $5,000 377 375
Rotheford Barker 19,963
Jack Lemley 20,596
Gary Michael 772
John Miller 39,000
Peter O'Neill 19,560
Richard Reiten 16,695
Thomas Wilford 13,515
Robert Tintsman 21,270
Christopher Culp 19,020
Joan Smith 619
Chambers of Commerce & Other Civic Organizations 74,879
Memberships:
Associated Taxpayers of Idaho 15,939
Association of Idaho Cities 560
Baker County Unlimited 500
Idaho Association of Counties 800
Idaho Water Users Association 200
National Hydropower Assoc 20,173
Northwest Hydroelectric 300
Pacific NW Utilities 36,686
Utility Economic Development 495
Utility Wind Interest Group 000
West Associates 28,374
Western Energy Institute 40,000
Wyoming Taxpayers Association 125
Miscellaneous General Management:
New York Stock Exchange 38,157
Pacific Exchange 850
Standard & Poor 89,500
TOTAL 959,515
~~n"" ~I"\O.. 1.,1"\ of 11I::n .. ") nA\I)~n... ~~I\
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/22/2005
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 of the 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, r-eport 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 xpe.nse Retirement Costs Electric Plant Other Electric Total
(Account 403)(Account 403.1 )(Account 404)Plant (Acc 405)
(a)(b)(c)(d)(e)(f)
1 Intangible Plant 10,050,419 10,050,419
Steam Production Plant 22,416,607 22,416,607
3 Nuclear Production Plant
4 Hydraulic Production Plant-Conventional 506,866 312 12.507 178
5 Hydraulic Production Plant-Pumped Storage
6 Other Production Plant 1,481,062 1,481 062
7 Transmission Plant 11,795,378 795,378
8 Distribution Plant 25,115,076 25,115,076
9 General Plant 671 901 17.671,901
Common Plant-Electric
TOTAL 90,986,890 10,050,731 101,037 621
B. Basis for Amortization Charges
Account 404
. Balance to be 2004 Balance to be Remaining months of
Amortized Amortization amortized 12/31/03 amortization 12/31/04
(1)364 15,372 992
(2)48,000 12,000 36,000
(3)341,155 297,576 8,443,567
(4)25,298.196 713.531 20,179,079
(5)259,334 12,252 247 082 242
Total 971 049 10,050,731 28,914 721
(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).
(5) American Falls dam road rebuild (termination date February 28,2025).
!": -. ' .
S:1=~r s:n~M Nn 1 '~J:V 1 ?n':t\PaGe 336
I .
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1 ) An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/22/2005
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreclaDie t:stlmatea Net Appllea MOrtality Average
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
(In Th(~)andS)ife (Percent)(Percent)
r~e
Life
(a)(d)(e)(0)
310.203 75.R4.19.
311.130,003 90.10.S1.18.
312.78,929 55.10.R3.19.
312.393,642 70.10.R1.18.
312.917 25.20.R3.16.40
314.116,615 50.10.SO.17.20
315.107 65.S1.17.
316.214 45.RO.16.40
316.40 232 25.L3.5.40
316.25.L3.
316.17.25.3.45 S2.
316.192 14.35.LO.9.40
317.000 775
Subtotal Steam 799,884
331.129,091 100.20.S1.36.
332.19,460.85.10.S4.31.40 .
332.218,345 85.10.S4.34.
332.600 39.1.44 S~UARE 63.
333.185,352 80.R3.38.
334.36,164 47.R1.28.
335.146 100.SO.34.
336.950 75.R3.34.
Subtotal Hydro 615,108
341.207 35.S~UARE 34.
342.677 35.S~UARE 33.
343.766 35.S~UARE 34.
344.43,894 35.S~UARE 34.
345.177 35.S~UARE 34.
346.570 35.S~UARE 34.
Subtotal Other 291
350.981 65.R3.52.
352.307 60.20.R3.48.
353.228,309 45.SO.32.
354.76,573 60.30.2.45 S4.37.
355.89,925 55.60.R2.39.
356.111,461 60.20.R2.41.40
359.319 65.R3.27.
Subtotal Transmission 558,875
361.18,722 55.20.R2.40.
FERC FORM NO.1 (REV. 12-03\PaQe 337
~ .
This Page Intentionally Left Blank
1 ,
l -
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1 ) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/22/2005
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreclable t:stlmated Net Appllea Mortality Average
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
(In Thousands)Life (Pergfnt)(per;)nt)r~e 7~)(a)(bf (c)
362.129,850 50.01.43.
364.185 763 41.50.R1.29.
365.136 46.30.R2.29.
366.39,214 60.25.R2.51.
367.147 816 37.10.S1.28.
368.272,982 35.R2.27.
369.46,412 30.30.S2.20.
370.47,457 30.L2.19.
371.359 28.42 S5.
371.124 11.20.11.RO.
373.969 20.20.R1.10.
Subtotal Distribution 988,804
390.25,377 100.S1.38.
390.743 50.R3.36.
390.086 25.S3.16.
391.10,812 20.S~UARE
391.16,599 20.S~UARE
391.201 18,005 34.48 S~UARE
391.553 16.S5.
391.211 039 31.S5.
392.293 25.L3.
392.989 15.50.S2.15.
392.40 14,789 25.3.45 L3.
392.. 422
...
- 9.25.8.45 L3.
392.19,821 17.25.S2.10.
392.3,487 17.25.S2.
392.029 30.25.S1.21.
393.007 25.S~UARE
394.833 20.S~UARE
395.230 20.S~UARE
396.325 14.35.LO.
397.693 15.11.S~UARE
397.13,155 15.SOU ARE 7.40
397.980 15.S~UARE
397.40 273 10.16.45 S~UARE
398.345 15.S~UARE
Subtotal General 204 885
Total Plant 219 847
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 2004/04(2) DA Resubmission 04/22/2005
REGULA TORY COMMISSION EXPEN
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
Current Year 182.docket or case number and a description of the case)Commission Utility (b) + (c)Beginning 0 Year
(a)(b)(c)(d)(e)
Federal Energy Regulatory Commission:
Annual administrative charges 3,417,660 3,417 660
General Regulatory Expenses:
Other Expenses 313,229 313,229
Regulatory Commission Expenses - Idaho
Intervenor Funding (various cases)40,000 40,000
Lost Revenue AppeaIIPC-01-550 550
General Rate Case IPC-15,400 15,400
Other Expenses 19,458 19,458
Oregon Hydro - Fees Amortization 158,506 158,506
Regulatory Commission Expenses - Oregon
Other Expenses 12,127 12,127
...
TOTAL 576,166 400,764 976,930
l .
FERC FORM NO.1 CEO. 12-96)Page 350
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/22/2005
REGULA TORY 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 ACCOUnt Amount Account 182.Account Account 182.No.No.End of Year
(f)
(g)
(h)(i)(k)(I)
electric 928 3,417 660
electric 928 313:229
electric 928 40,000
electric 928 550
electric 928 15,400
electric 928 19.458
electric 928 158,506
electric 928 12,129
976,932
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 2004/04
(2)0 A Resubmission 04/22/2005
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)
A. Electric R, D & D Performed internally:
(1) Generation
e. unconventional generation Air Conditiioning Cycling Pilot
Irrigation Peak Clipping
5 'Energy STAR Homes Northwest
Commercial Efficiency Program
Air Care+Pilot
Industrial Efficiency Program
Irrigation Efficiency Program
School Building Operator training
Small project/Education Funds
EEAG
- ,
DSM Analysis
Other DSM Costs
(7) Costs Incurred
B. 4 Research Support to Others BPA Conservation & Renewable discount
Northwest Energy Efficiency Alliance
Low Income Weatherization Assistance
36 '
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 2004/04(2) 0 A Resubmission 04/22/2005
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, 0 & 0 items performed intemally and in column (d) those items performed outside the company costing $5.000 or more,
briefly describing the specific area of R, 0 & 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, 0 & 0
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 &0 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)
273,973 273,973
319,424 319,424
129,825 129,825
28,821 28,821
187,473 187,473
73,188 73,188
43,969 43,969
23,449 23,449
3,448 448
138,249 138,249
300,000 300,000
000,000 000,000
200,000 200,000
500,000 500,000
. nO_-
1 ,521 ,891 700,000 221,891
FERC FORM NO.1 (ED. 12-87)Page 353
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2004/04
This ~ort Is: Date of Report(1) ~ An Original (Mo, Da, Yr)(2) A Resubmission 04/22/2005
DISTRIBUTION OF SALARIES AND WAGES
Report below the distribution of total salaries and wage~ 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.
Line
No.
Classification Direct PayrollDistribution Total
(a)(d)
Electric
Operation
Production
Transmission
Distribution
Customer Accounts
Customer Service and Informational
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 oflines 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 Terminating 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)
10,277,882
5,430,894
14,410,861
874,850
896.235
740,915
l .
l . .
FERC FORM NO.1 (ED. 12-88)Page 354
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1)An Original (Mo, Da, Yr)End 2004/04
(2)n A Resubmission 04/22/2005
DISTRIBUTION SALARIES AND WAGES (Continued)
Line Classification Direct Payroll Allocation of TotalNo.Distribution Payroll charged forClearin
1 Accounts(a)(b)(d)
Total Operation and Maintenance
Prod uctio n-Ma n ufa ctu red Gas (Enter Total of lines and 40)
Production-Natural Gas (Including Expl.and Dev.(Total lines
Other Gas Supply (Enter Total of lines and 42)
Storage,LNG Terminaling and Processing (Total of lines thru
Transmission (Lines and 44)
Distribution (Lines and 45)
Customer Accounts (Line 34)
Customer Service and Informational (Line 35)IlItIMI'jlllrl.i!~I'..Jlftt1l1.lrllllt~ftlj'
Sales (Line 36)
Administrative and General (Lines and 46)
TOTAL Operation and Maint.(Total of lines 49 thru 58)
Other Utility Departments
Operation and Maintenance
TOTAL All Utility Dept.(Total of lines 25,59,and 61)89,489 917 3,416,157 92,906,074
'irft~lillllr..II!fiillillllll!.jiil.lfl.'.'l..i..".~J1111~ilrf~~'f.iUtilityPlant
Construction (By Utility Departments)
Electric Plant 579,868 34,579 868
Gas Plant
Other (provide details in footnote):
TOTAL Construction (Total of lines thru 67)579,868 34,579,868
Plant Removal (By Utility Departments)
Electric Plant
Gas Plant
Other (provide details footnote):
TOTAL Plant Removal (Total of lines thru 72)
Other Accounts (Specify,provide details footnote):
Misc Deferred Regulatory assets 151,861 151 861
Paid Absences 15,037 256 15,037 256
Other Accounts 399,737 399,737
84'
TOTAL Other Accounts 20,588,854 20,588,854
TOTAL SALARIES AND WAGES 144,658,639 3,416,157 148,074 796
FERC FORM NO.1 (ED. 12-88)Page 355
Nam e of Respondent This (8Jort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2004/04(2) DA Resubmission 04/22/2005
MONTHL Y 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 U) by month the system' monthly maximum megawatt load by statistical classifications. See General Instruction for
the definition of each statistical classification.
NAME OF SYSTEM:Idaho Power Company
line Monthly Peak Day of Hour of Firm Network Firm Network Long-Term Firm Other Long-Short-Term Firm Other
No.Month MW - Total Monthly Monthly Service for Self Service for Point-to-point Term Firm Point-to-point Service
Peak Peak Others Reservations Service Reservation
(a)(b)(c)(d)(e)(f)
(g)
(f)(f)(f)
1 January 601 196 174 150
2 February 2,43~072 180 100
3 March 2,47i 877 150 305 140
4 Total for Quarter 145 504 463 390
5 April 64f 661 185 347 420
6 May 981 083 226 107 290
7 June 52C 2l1 843 137 347 190
8 Total for Quarter 587 548 801 900
9 July 14 -825 290 301 100
August 301 769 134 301 100
September 01~2,364 223 949 125
Total for Quarter 88-958 647 551 325
October 2,45C 25 735 149 376 190
November 744 061 172 376 132
December 2;603 033 166 376
Total for Quarter 829 487 128 347
Total for Year to 34,26,519 186 943 962
FERC FORM NO. 1I3-Q (NEW. 07-04)Page 400
This Page Intentionally Left Blank
i .
Name of Respondent
Idaho Power Company
This ~ort Is:
(1 ) ~ An Original(2) A Resubmission
ELECTRIC ENERGY ACCOUNT
Date of Report(Mo, Da, Yr)
04/22/2005
Year/Period of Report
End of 2004/04
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)
597
594,
17,461,
Page 401 a
Line
No.
Item
(a)
21 DISPOSITION OF ENERGY
22 Sales to Ultimate Consumers (Including
Interdepartmental Sales)
23 ReqlJirements Sales for Resale (See
instr~ction 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 EOUAL LINE 20)
MegaWatt Hours
(b)
13.239,589
104,331
781,019 r .
336,236
17,461,175
( ,
t .
This ~ort Is:
(1 ) ~ An Original(2) A Resubmission
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
Date of Report
(Mo, Da, Yr)
04/22/2005
Year/Period of Report
End of 2004/04
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 334,017 72,251 196 7PM
30 February 1 ,258,704 140,373 072 8AM
31 March 1,455,063 431 ,459 877 8AM
32 April 370,496 ' 335,462 758 9AM
33 May 1,493,443 302,534 109 7PM
34 June 750,724 315,058 843 5PM
35 July 780,638 191 534 825 6PM
36 August 683,160 221,018 792 6PM
37 September 525,329 353,612 395 5PM
38 October 173,703 99,934 735 8AM
39 November 1 ,202,388 106 834 063 8AM
40 December 1,433,510 210,950 033 7PM
TOTAL 17,461 175 781 019
FERC FORM NO.1 (ED. 12-90)Page 401b
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1 ) An Original (Mo, Oa, Yr)2004/04(2)0 A Resubmission 04/22/2005 End of
. ,
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Report data for plant in Service only.2. 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.3. Indicate by a footnote any plant leased or operated
as a joint facility.4. If net peak demand for 60 minutes is not available, give data which is available, specifying period.5. If any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant.6. 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.7. 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 20.8. 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 i::itC._;,;i1~O'
Year Last Unit was Installed 1979 1980
Total Installed Cap (Max Gen Name Plate Ratings-MW)
Net Peak Demand on Plant - MW (60 minutes)701
Plant Hours Connected to Load 8784 6448
Net Continuous Plant Capability (Megawatts)
When Not Limited by Condenser Water
When Limited by Condenser Water
Average Number of Employees
Net Generation, Exclusive of Plant Use - KWh 4924715000 353543000
Cost of Plant: Land and Land Rights 494358 106610
Structures and Improvements 62837544 13575473
Equipment Costs 363944819 51815464
Asset Retirement Costs
Total Cost 427276166 65497547
Cost per KW of Installed Capacity (line 17/5) Including 554.5440 1168.5557
Production Expenses: Oper. Supv, & Engr 104062 821222
Fuel 62790590 4409531
Coolants and Water (Nuclear Plants Only)
Steam Expenses 2749435
Steam From Other Sources
Steam Transferred (Cr)
Electric Expenses
Misc Steam (or Nuclear) Power Expenses 4565813 145173
Rents 268376 A31771
Allowances
Maintenance Supervision and Engineering 1477 2670682
Maintenance of Structures
Maintenance of Boiler (or reactor) Plant 8174881
Maintenance of Electric Plant 4257391
Maintenance of Misc Steam (or Nuclear) Plant 2880164 26742
Total Production Expenses 85792189 8505121
Expenses per Net KWh 0174 0241
Fuel: Kind (Coal, Gas, Oil, or Nuclear)COAL OIL COAL OIL
Unit (Coal-tons/Oil-barrel/Gas-m cf/Nuclear -indicate)TONS BARRELS TONS BARRELS
Quantity (Units) of Fuel Burned 2803820 17886 207426 1196
Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)9306 140000 8405 138800
Avg Cost of Fuel/unit, as Oelvd f.b. during year 21.129 54.548 000 19.261 55.509 000
Average Cost of Fuel per Unit Burned 22.012 53.435 000 20.920 46.053 000
Average Cost of Fuel Burned per Million BTU 183 088 000 245 898 000
Average Cost of Fuel Burned per KWh Net Gen 013 000 000 012 000 000
Average BTU per KWh Net Generation 10618.000 000 000 9882.000 000 000
f :
'0.
'ii.
:,,, '
FERC FORM NO.1 (REV. 12-03)Page 402
Name of Respondent This ~ort Is:Date of Report Year/Period of Report(1) An Original (Mo, Da, Yr)2004/04jldahO Power Company (2) DA Resubmission 04/22/2005 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
9. 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: Va/my Name: Danskin Name:No.
(d)(e)(f)
Steam Gas Turbine
Outd90r . Conventional
?"\,,,::'.
2001
,,:.,:.:!., ,', ..".,..,..
1985 2001
:.:.":.
90.
",,'.. . ".
268
8676 398
100000
2003174000 21798000
681106 219037
53590120 1195464
251142150 50128220
305413376 51542721
1077.2959 572.6969 0000
261852 112088
31187249 4861198
2583991
1558514 135246
1157530 131621
10566 .
187711
358798 90459
4490351 39808
924812 164266
169235
42890609 5534686
0214 2539 0000
I COAL OIL GAS
TONS BARRELS MCF
I 969246 5933 47779
10267 138778 1038
. 30.538 63.218 000 15.067 000 000 000 000 000
31.792 57.627 000 15.067 000 000 000 000 000
11.548 887 000 14.510 000 000 000 000 000
10.016 000 000 101 000 000 000'000 000
9953.000 000 000 6944.000 000 000 000 000 000
-ERC FORM NO.1 (REV. 12-03)Page 403
This Page Intentionally Left Blank
\~ "
1 '
l ,
Name of Respondent This Report is:Date of Report Year/Period Report
(1) An Original (Mo, Da, Yr)
Idaho Power Com pany (2)A Resubmission 04/22/2005 2004/04
FOOTNOTE DATA
!schedule 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 Idahoowning 1/3 and Paci f iCorp owning 2/3. Unit # 1 was placed in
commercial operation November 30, 1974, Unit #2 December 1, 1975,
nit #3 September 1, 1976, and Unit #4 November 29, 1979.
!schedule 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
uni t was placed in commercial operation August 3, 1980.
!schedule 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
nd Unit #2 May 21, 1985.
!schedule 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
!schedule 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
n note on line 3 page 402 column C
!schedule Page: 402 Line No.: 5-Column: d
This footnote applies to line 5 and lines 12 through 43.
Information reflects Idaho Power Company s share as explained
n note for line 3 page 403 column
~chedule Page: 402 Line No.Column: b
This footnote applies to lines 9, 10, and 11. PacifiCorp
as operator of the plant will report this
nformation.
~chedule Page: 402 Line No.Column:
This footnote applies to lines 9, 10, and 11. Portland General
lectric Company, as operator will report this information.
~chedule 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.
. I
I .
; ', ., .
IFERC FORM NO.1 (ED. 12-Page 450.
Name of Respondent This (!Jort Is: Date of Report ' Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)2004/04(2)D A Resubmission 04/22/2005 End of
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.
Line Item FERC Licensed Project No.2736 FERC Licensed Project No.1975
No.Plant Name: American Falls Plant Name: Bliss
(a)(b)(c)
Kind of Plant (Run-of-River or Storage)
":::
Run-of-River
,.,.
Plant Construction type (Conventional or Outdoor)Outdoor Outdoor
Year Originally Constructed 1978 1949
Year Last Unit was Installed 1978 1950
Total installed cap (Gen name plate Rating in MW)92.75.
Net Peak Demand on Plant-Megawatts (60 minutes)
Plant Hours Connect to Load 743 783
Net Plant Capability (in megawatts)
(a) Under Most Favorable Oper Conditions 112
(b) Under the Most Adverse Oper Conditions
Average Number of Employees
Net Generation, Exclusive of Plant Use - Kwh 199,617,000 281,658,000
Cost of Plant
Land and Land Rights 875,615 463,556
Structures and Improvements 812,406 664 675
Reservoirs, Dams, and Waterways 242,904 7,428,168
Equipment Costs 30,886 109 536,751
Roads, Railroads. and Bridges 306,333 486,477
Asset Retirement Costs
TOTAL cost (Total of 14 thru 19)48,123,367 15,579.627
Cost perKW of Installed Capacity (line 20 /5)521.3799 207.7284
Production Expenses
Operation Supervision and Engineering 158,940 356,447
Water for Power 853,891 218,122
Hydraulic Expenses 101 824 202.245
Electric Expenses 40,445 19,225
Misc Hydraulic Power Generation Expenses 163,236 87,762
Rents 137 784
Maintenance Supervision and Engineering 125,350 158
Maintenance of Structures 115,888 66,180
Maintenance of Reservoirs, Dams, and Waterways 139 155,345
Maintenance of Electric Plant 216,826 250,067
Maintenance of Misc Hydraulic Plant 122,032 131,434
Total Production Expenses (total 23 thru 33)898,708 556,769
Expenses per net KWh 0095 0055
. ;
r: :
I :c' ,
. .
FERC FORM NO.1 (REV. 12-03)Page 406
Name of Respondent
Idaho Power Company
Year/Period of ReportThis ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) 0 A Resubmission 04/22/2005
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.
End of 2004/04
FERC Licensed Project No.
Plant Name: Brownlee
(d)
1971 FERC Licensed Project No. 2848
Plant Name: Cascade
(e)
FERC Licensed Project No.
Plant Name: Oxbow
1971 Line
No.
Storage
Outdoor Outdoor Outdoor
1958 1983 1961
1980 1984 1961
585.40 12.42 190.
652 221
784 784 784
728 220
220 202
881,325,000 35,715,000 825,345,000
654 942 82,142 866,938
30,023.963 364 154 835,132
66,742,791 145,630 30,375,714 16.
51,284 102 12,376,598 14,782 645
518,444 122,668 565,842
154,224,242 23,091,192 56,426,271
263.4510 859.1942 296.9804
479,095 152,303 322,180
188,501 91,046 116 813
359,462 150,916 239,650
286,600 66,038 271,044
480,191 238,127 339,334
209,671 100 36,004
158.354 43,012 158,037
174,315 706 159,819
'--
148,368 444 90,684
360,693 52,862 254,516
420,459 134,505 334,645
265,709 957,059 322,726
0017 0268 0028
FERC FORM NO.1 (REV. 12-03)Page 407
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1 ) An Original (Mo, Da, Yr)2004/04(2)D A Resubmission 04/22/2005 End of
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.
Line Item FERC Licensed Project No.1971 FERG Licensed Project No.2726
No.Plant Name: Hells Canyon Plant Name: Malad
(a)(b)(c)
........
Kind of Plant (Run-of-River or Storage)
..'
.(iW
Plant Construction type (Conventional or Outdoor)Outdoor Outdoor
Year Originally Constructed 1967 1948
Year Last Unit was Installed 1967 1948
Total installed cap (Gen name plate Rating in MW)391.21.
Net Peak Demand on Plant-Megawatts (60 minutes)432 160
Plant Hours Connect to Load 784 779
Net Plant Capability (in megawatts)
(a) Under Most Favorable Oper Conditions 450
(b) Under the Most Adverse Oper Conditions 137
Average Number of Employees
Net Generation, Exclusive of Plant Use -Kwh 623,901,000 154,935,000
Cost of Plant
Land and Land Rights 563,504 205,375
Structures and Improvements 2,402,435 143.622
Reservoirs, Dams, and Waterways 52,511,953 371 066
Equipment Costs 14,999,231 948,654
Roads, Railroads, and Bridges 819 192 304,683
Asset Retirement Costs
TOTAL cost (Total of 14 thru 19)72,296,315 973,400
Cost per KW of Installed Capacity (line 20 / 5)184.6649 412.1911
Production Expenses
Operation Supervision and Engineering 185,519 71,368
Water for Power 78,624 459,280
Hydraulic Expenses 143,330 44,822
Electric Expenses 264 61,502
Misc Hydraulic Power Generation Expenses 245,179 546
Rents 60,150
Maintenance Supervision and Engineering 149,323 304
Maintenance of Structures 40,251 736
Maintenance of Reservoirs, Dams, and Waterways 224,556 36,420
Maintenance of Electric Plant 203,526 172,398
Maintenance of Misc Hydraulic Plant 576,093 66,236
Total Production Expenses (total 23 thru 33)973,815 001,612
Expenses per net KWh 0012 0065
FERC FORM NO.1 (REV. 12-03)Page 406.
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2004/04
This ~ort Is: Date of Report(1) ~An Original (Mo, Oa, Yr)
(2) D A Resubmission 04/22/2005
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.
Plant Name: C J Strike
(d)
2055 FERC licensed Project No.
Plant Name: Swan Falls
(e)
503 FERC Licensed Project No.
Plant Name: Twin Falls
Line
No.
Run-of-River Run-of-River Run-of-River
Outdoor Conventional Conventional
1952 1910 1935
1952 1994 1995
82.25.52.
780 784 5,471
355,512,000 113,034 000 33,363,000
052,202 675 255,499
700,432 25,151 154 10,808,047
742 555 13,641,459 908,304
022 775 30,351,406 20,434 828
238 871 835,946 917 603
21,756,835 70,031 640 41,324,281
262.7637 801.2656 783.5472
725,094 204,746 231,814
267 364 71,526 68,312
877,434 169,172 123,005
37,635 21,646 34,630
203,500 104 923 111,180
60,400 117 996
67,031 41 ,245 32,001
59,790 69,748 37,654
143,294 19,765 28,273
146,578 128,449 131,135
200,071 121 549 112,144
788,191 959,886 911,144
0078 0085 0273
: j
FERC FORM NO.1 (REV. 12-03)Page 407.
Name of Respondent This (!Jort Is:Date of Report Year/Period of Report
Idaho Power Company (1 ) An Original (Mo, Da, Yr)2004/04(2)0 A Resubmission 04/22/2005 End of
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.
Line Item FERC Licensed Project No.2777 FERC Licensed Project No.2778
No.Plant Name: Upper Salmon Plant Name: Shoshone Falls
(a)(b)(c)
Kind of Plant (Run-of-River or Storage)Run-of-River Run-of-River
Plant Construction type (Conventional or Outdoor)Outdoor Conventional
Year Originally Constructed 1937 1907
Year Last Unit was Installed 1947 1921
Total installed cap (Gen name plate Rating in MW)34.12.
Net Peak Demand on Plant-Megawatts (60 minutes)
Plant Hours Connect to Load 783 724
Net Plant Capability (in megawatts)
(a) Under Most Favorable Oper Conditions
(b) Under the Most Adverse Oper Conditions
Average Number of Employees
Net Generation, Exclusive of Plant Use - Kwh 182,226,000 81,083,000
Cost of Plant
Land and Land Rights 172,970 311,407
Structures and Improvements 1,442,507 138,033
Reservoirs, Dams, and Waterways 936,469 512,401
Equipment Costs 598.895 068,295
Roads, Railroads, and Bridges 29,359 51,383
Asset Retirement Costs
TOTAL cost (Total of 14 thru 19)10,180,200 081 519
Cost per KW of Installed Capacity (line 20 295.0783 326.5215
Production Expenses
Operation Supervision and Engineering 342.582 88,176
Water for Power 73,172 33,954
Hydraulic Expenses 229,964 62,383
Electric Expenses 16,298 15,951
Misc Hydraulic Power Generation Expenses 122,726 66,526
Rents
Maintenance Supervision and Engineering 45,051 375
Maintenance of Structures 55.813 23,843
Maintenance of Reservoirs, Dams, and Waterways 54,841 301
Maintenance of Electric Plant 133,869 88,002
Maintenance of Misc Hydraulic Plant 147,367 55,186
Total Production Expenses (total 23 thru 33)221,683 462,722
Expenses per net KWh 0067 0057
. \
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) 0 A Resubmission 04/22/2005
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.
Year/Period of Report
End of 2004/04
FERC Licensed Project No. 1971
Plant Name: Common Facilities
(d)
FERC Licensed Project No. 2061
Plant Name: Lower Salmon
(e)
FERC Licensed Project No.
Plant Name: Milner
2899 Line
No.
Run-of-River Run-of-River
Outdoor Conventional
1949 1992
1949 1992
60.59.45
783 697
185,011,000 19,423,000
80,646 403,335 138,100
11,894 976 860,907 10,327 358
13,556,785 473,870 17,147,049
014,463 6,419,204 27,529,862 17"
99,051 88,693 501 877
26,645,921 14,246,009 55,644,246
0000 237.4335 935.9840
22 '
473 989,489 109,916
147,847 346,950
606,918 352,157 72,247
153,741 41 ,224
15~ ,632 149,474
157 379
58,234 32,336
116,270 38,489
85,689 986
186,673 56,744
127 898 37,522
606,445 370,787 895,267
0000 0128 0976
~ I
" "
FERC FORM NO.1 (REV. 12-03)Page 407.
t'
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 04/22/2005 2004/04
FOOTNOTE DATA
~chedule Page: 406 Line No.Column:
American Falls generating capacity is dependent upon water releases controlled by the
Uni ted States Bureau of Reclamation.
~chedule Page: 406 Line No.Column:
Cascade generating capacity is dependent upon water releases controlled by the United
tates Bureau of Reclamation.
~chedule Page: 406 Line No.Column:
pstream storage in Brownlee Reservoir.
~chedule Page: 406.Line No.Column:
Upstream storage in Brownlee Reservoir
~chedule 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 2004/04(2) D A Resubmission 04/22/2005
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 Install~d ca~acity ~et PeaK Net GenerationName of Plant Orig.Name Plate atin~Demand Excluding Cost of Plant
No.Const.(In MW)Plant Use
(a)(b)(c)(60
(8jin.(e)(f)
Hydro:
Clear lakes 1937 15,799 718,350
Thousand Springs 1912 555 691,209
Internal Combustion:
Salmon Diesel (1)1967 136 901,055
(1) Salmon units are classified as standby.
-. - -
f .
r ''to. ;
FERC FORM NO.1 (REV. 12-03)Page 410
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1 ) X An Original (Mo, Da, Yr)End of 2004/04(2) DA Resubmission 04/22/2005
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 Mamtenance Kind of Fuel (per Million Btu)
(g)
(h)(i)(k)No.
687 340 13,927 64,476
533,092 180,969 368
. 6
180,211 Diesel
-- - -- --- --- --- -
41
-- -
FERC FORM NO.1 (REV. 12-03)Page 411
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1 ) An Original (Mo, Da, Yr)End of 2004/04(2) DA Resubmission 04/22/2005
TRANSMISSION LINE STATISTICS
1. Report information concerning transmission lines, cost of Ii':les, 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.
11-"" TION ~T.dr...i= .(KV)LENG~H ~ole wiles)Line (i "''7 I I~""'-Type ofn Icate wtiere ~Io t e s
cf Num berNo.other than u dergroun lines
60 cvcle, 3 ohase)Supporting report circuit miles)
Operating un :structure ::".truG~ures CircuitsFromDesignedStructureof Line of Another
(a)(b)(c)Desi~nated Line
(d)(e)
(g)
(h)
Boardman Slatt 500.500.S Tower
Borah Midpoint 345.500.S Tower 85.
Jim Bridger Goshen 345.345.S Tower 225.
State Line Midpoint 345.345.S Tower 76.
Kinport Borah 345.345.S Tower 27.
Midpoint Borah #1 345.345.H Wood 79.
Midpoint Borah #2 345.345.H Wood 77.
Adelaide Tap Adelaide 345.345.H Wood
Quartz LaGrande 230.230.H Wood 46.23
Midpoint Hunt 230.230.S Tower
Brady Antelope 230.230.H Wood 56.
Brady Treasureton 230.230.H Wood
Brady #1 & #2 Kinport 230.230.S Tower 18.
Jim Bridger Point of Rocks 230.230.H Wood
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 4.46
Boise Bench Caldwell 230.230.H Wood 33.
Boise Bench Cloverdale 230.230.S Tower 16.
Boardman Dalreed Sub 230.230.H Wood
Brownlee 714 Oxbow 230.230.SP Steel 10.
Caldwell Ontario 230.230.H Wood 27.
Caldwell Ontario 230.230.S Tower
Boise Bench Midpoint #1 230.230.S Tower
Boise Bench Midpoint #1 230.230.H Wood 108.
Brownlee Quartz Jct 230.230.S Tower 1.52
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.
Boise Bench Midpoint #2 230.230.S Tower 3.42
TOTAL 4,703.11.152
) ,
FERC FORM NO.1 (ED. 12-87)Page 422
Name of Respondent This (!Jort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2004/04(2) DA Resubmission 04/22/2005
TRANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. ~eport 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 sale 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 G) to (I) on the book cost at end of year.
l,;U~ I OF LINE (Include in Column UJ Land,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and cl~aring 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)
?X1780 ACSR 446,708 446 708
1272 ACSR 56,381 21,776,998 22,033,379
1272 ACSR 483,309 15,722,638 16,205,947
, 1795 ACSR 571,979 10,996,449 11.568,428
1272 ACSR 344 220 028,033 372,253
i j715.5 ACSR 283,14J 5,422,574 705 717
V15.ACSR 851 983,183 048 034
! .
' 715.5 ACSR 51,448 347,946 399,394
\795 ACSR 51,414 175,013 226,427
. ,
' 715.5 ACSR 14~395,951 405,096
, ,
(.1272 ACSR 108,301 328,646 2,436 947
j 1795 ACSR 186 186
~ 15.5 ACSR 18,82~969,476 988,305
, 1272 ACSR 19C 525 52,715
, . 2X954 ACSR 676,831:20,246,910 923 748
1715.5 ACSR 347,96~012,372 360,334
715.5 ACSR
....
1272 ACSR 899 212,523 214,422
1590 ACSR 138,236 138,236
11272 ACSR 817,054 761,586 578.640
715.5 ACSR
1272 ACSR 999,02E 532,790 531 816
795 MC 80,895 80,895
. j54 ACSR 16,463,438 16,463,438
, (X954 ACSR 194 76~593,156 787,919
1272 ACSR
" :
1715.5 ACSR 336,186 3,404 693 740,879
715.5 ACSR
, '
V95 ACSR 42,99~782,886 825,881
. 1795 ACSR
jVARIOUS 261,22c 994 996 256,225
1272 ACSR 03~191 291 197 324
715.5 ACSR 820 64E 682,329 502,975
20,341,978 269,491 947 289,833,925 502,879 017,527 176 624 10,697 030
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 2004/04
(2) FiA Resubmission 04/22/2005
TRANSMISSION LINE STATISTICS
1. Report information concerning transmission lines, cost of lit:1es. 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.
TION \7("jrT .llr..~JRVY LENGJii ~ole wiles)Line (I '"'
~ I ,.'""'Type ofn lcate ere ~lr:I t e s NumberNo.other than u dergroun lines
60 cvcle. 3 ohase)Supporting report circuit miles)
un ~tfUcture ~truG~ures CircuitsFromOperatingDesignedStructureof Line of Another
Desi
r~ated
Line(a)(b)(c)(d)(e)
(g)
(h)
1 Boise Bench Midpoint #2 230.230.H Wood 101.
Oxbow Pallette Jct 230.230.S Tower 20.
Pallette Jct Imnaha 230.230.H Wood 23.
Hells Canyon Palette Jct 230.230.S Tower
5 Brownlee Boise Bench 230.230.S Tower 102.
Boise Bench Midpoint #3 230.230.H Wood 106.
Palette Jct Enterprise 230.230.H Wood 28.
Borah Brady #2 230.230.S Tower 0.43
Borah Brady #2 230.
. -
230.HWood
Borah Brady #1 230.230.H Wood
Goshen State Line 161.161.00 H Wood 90.
Don Goshen 161.161.00 S Tower
Don Goshen 161.0(161.00 H Wood 46.
American Falls Power Plant Adelaide 1 ~8.138.H Wood 84.40
American Falls Power Plant Adelaide 138.138.S P Wood
Minidoka Loop Adelaide -c- 138.
138.S Tower
Nampa Caldwell 138.138.S P Wood 10.
Upper Salmon Mountain Home Jet 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 60.
Mountain Home AFB Tap 138.138.H Wood'
Ontario Quartz 138.138.H Wood 73.
King American Falls PP 138.138.S Tower 1.02
King American Falls PP 138.138.H Wood 141.72
King American Falls PP 138.138.S P Wood
TOTAL 703.11.152
~ .
r:':'
! .
FERC FORM NO.1 (ED. 12-87)Page 422.
Name of Respondent This (!Jort Is:Date of Report Year/Period of Report
Idaho Power Company (1 ) An Original (Mo, Da, Yr)End of 2004/04
(2) D A Resubmission 04/22/2005
TRANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. ~eport 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 sale 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 rentJor year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns U) 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.
VARIOUS
1272 ACSR 23,308 032,869 056,177
1272 ACSR 138,477 208,587 347 064
1272 ACSR 10,731 253,156 263,893
954 ACSR 170,694 555,559 726,253
715.5 ACSR 246,660 589,451 836,111
. 1272 ACSR 122 633,094 684 216
1272 ACSR 06B 200,632 203,700
715.5 ACSR
1272 ACSR 10,064 180,008 190,072
250 COPPER 16,15:648,382 664 537
715.5 ACSR 76,041 623,921 699,962
397.5 ACSR
~50 COPPER 26,50,346,862 373,369
~50 COPPER
1715.5 ACSR 15,088 249,232 264,320
i795 AAC 157,432 1,489,068 646,500
795 ACSR 687 696,746 744,433
~ARIOUS
~95 ACSR 43,56B 764,183 807,751
95 AAC 270,822 557 504 828,327
VARIOUS 564 932 447,402 012 334
VARIOUS
VARIOUS
VARIOUS 76,82.:378,401 1,455,224
VARIOUS 30,918 318,876 349,794
397.5 ACSR 955 955
. VARIOUS 34,42B 1,486,208 520,636
715.5 ACSR 134,494 943,879 078,373
715.5 ACSR
715.5 ACSR
20,341 978 269,491,947 289,833,925 502,879 017,527 176,624 10,697 03C
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 2004/04(2) n A Resubmission 04/22/2005
TRANSMISSION LINE STATISTICS
1. Report information concerning transmission lines, cost of Ii':les, 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.
IIUN Y(11 I AC.;!- .(K~)LENGJii ~ole miles)Line
"":' .
Wi;Type of Numbern lca e ere hiD t e sc? pfNo.other than u dergroun lines
60 cycle, 3 chase)Supporting report circuit miles)
un ~tf':lcture ~truG~ures CircuitsFromOperatingDesignedStructureof Line of AnotherDesi
pD'ated
Line(a)(b) '(c)(d)(e)
(g)
(h)
Duffin Clawson 138.138.H Wood
American Falls Brady Tie 138.138.H Wood
Upper Salmon A-King 138.138.H Wood
Upper Salmon B Wells 138.138.H Wood 125.
King Wood River 138.138.H Wood 73.
Boise Bench Grove 138.138.S P Wood 10.
Quartz John Day 138.138.H Wood 67.
Sinker Creek Tap 138.138.H Wood
Mora Cloverdale 138.138.H Wood
Mora Cloverdale 138.138.S P Wood 22.47
Stoddard Jct Stoddard Sub 138.138.S P Steel
Fossil Gulch Tap 138.138.H Wood 1.95
Wood River Midpoint 138.138.H Wood 52.
Wood River Midpoint 138.138.S P Wood 16.
Oxbow McCall 138.138.H Wood 38.49
Oxbow McCajl 138.138.S P Wood 1.70
Lowell Jct Nampa 138.138.S P Wood
Hunt Milner 138.138.S P Wood 19.40
Strike Bruneau Bridge 138.138.H Woodc 13.47
American Falls Kramer Sub 138.138.S P Wood 18.43
Pingree Haven 138.138.S P Wood 11.77
Midpoint Twin Falls 138.138.S P Wood 25.
Twin Falls Russett 138.138.S P Wood
Blackfoot Aiken 138.138.S P Wood
Peterson Tendoy 138.138.H Wood 57.
Eastgate Tap Eastgate 138.138.S P Wood
Boise Bench Mora 138.138.H Wood 11.
Bowmont-Caldwell Simplot Sub 138.138.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
Cloverdale - 712 712 - Wye 138.138.S P Steel
Butler Wye 138.138.S P Steel
Valivue Tap 138.138.S P Steel
TOTAL 703.11.152
F -
. '
FERC FORM NO.1 (ED. 12-87)Page 422.
i:-
Name of Respondent This 7!Jort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/22/2005
TRANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. ~eport 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 sale 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 UJ 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)
14\0 191 309,827 314 018
1954 ACSR 13,539 13,539
, 50 COPPER 741 93,073 95,814
IVARIOUS 28,49C 745,804 774 294
!vARIOUS 173 68~364 244 537 927
ARIOUS 225,60~629,593 855,195
~97.5 ACSR 362,416 2,454,589
~ARIOUS 199 219
.:0715.ACSR 1,448,71/648,182 096,899
,v ARIOUS
- -
1272 ACSR
1250 COPPER 45C 63,439 63,889
397.5 ACSR 281,06~374 306 655,370
- ,
- ~97.5 ACSR
P97.5 ACSR 84, 18~752,478 836,661
397.5 ACSR
715.5 ACSR 211 131 1,452,119 663,250
~ 5.5 ACSR 32~079,781 083,105
397.5 ACSR 14,921 587,404 602,331
715.5 ACSR 13,73L 991,714 005,448
~97.5 ACSR 213 778,092 789,305
IVARIOUS 54,84f 959 215 014,063
715.5 ACSR 16,79C 206,158 222,948
1715.5 ACSR 13,61E 456,919 470,535
b97.5 ACSR 395,69E 3,449,949 845,645
115.5 ACSR 45,98S 054 909 100,898
715.5 ACSR 69i 632,718 647,415
95 MC 49,642 49,642
: 795 MC 489,031 139,599 628,636
1272 ACSR 935,72~811 708 747,433
1272 ACSR 681 551 319 586,006
15.5 ACSR 087,968 087 968
. 1272 ACSR 140,41~709,148 849,560
795 ACSR 471 76~059,039 530,808
95 ACSR 351,497 351,497
20,341,978 269,491,947 289,833,925 502,879 017 527 176,624 10,697 03C
i:.
FERC FORM NO.1 (ED. 12-87)Page 423.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1 ) An Original (Mo, Da, Yr)End of 2004/04
(2) D A Resubmission 04/22/2005
TRANSMISSION LINE STATISTICS
1. Report information concerning transmission lines, cost of lir:'es, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmis.sion 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.
ATION yo~ T AGE ,(KV)LENG~H role miles)Line Type of(Indicate wliere ~lr:I t e as
cf Number
No.other than u dergroun lines
60 cycle. 3 phase)Supporting report circuit miles)
un :::itructure qtruG~ures Circuits
From Operating Designed Structure of Line of Another
(a)(b)(c)Desi~nated Line
(d)(e)
(g)
(h)
1 Kinport Don #1 138.138.S Tower 1.24
Twin Falls PP Tap 138.138.H Wood
American Falls PP Amercian Falls Trans ST 138.138.S P Steel
Lower Salmon King Tie 138.138.H Wood
C J Strike Strike Jct 138.138.S Tower
Strike Jct - Mo.untain Home Jct 138:00 138.H Wood 26.
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 4.43
Bliss King 138.138.H Wood 10.44
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 3.28
69 Kv Lines 69.69.H Wood 166.
69 Kv Lines 69.69.S P Wood 034.
46 Kv Lines 46.46.S P Wood 429.
- ---.--- -
Expenses of all Lines
TOTAL 703.62 11.152
t:" ,
. r
(- .
I :
FERC FORM NO.1 (ED. 12-87)Page 422.
I Name of Respondent This ~ort Is:Date of Report Year/Period of Report(1 ) An Original (Mo, Da, Yr)End of 2004/04Idaho Power Company (2) 0 A Resubmission 04/22/2005
TRANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. ~eport 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)
18. 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
I 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. Qesignate 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.
110. Base the plant cost figures called for in columns U) to (I) on the book cost at end of year.
co::; I Ul- LINt: (Include in Column U) 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)
/715.5 ACSR , 17~212,777 213,951
250 COPPER 53,888 53,946
!15.5 ACSR 76,560 76,560
p97.5 ACSR 4,406 4,406
1715.5 ACSR 074 253,872 254 946
397.5 ACSR 35= . 475,486 479,841 ' 6
~15.5 ACSR 29,90~1,488,107 518,009
715.5 ACSR
~15.5 ACSR 152,852 152 859
715.5 ACSR 62C 445,666 451,286
715.5 ACSR 81~183,606 186,420
~97.5 ACSR 88~261 511 274,396
~97.5 ACSR 97€63,404 65.382
IV ARIOUS 858,87~30,340,629 199,508
!vARIOUS
!vARIOUS 176,265 7,420,974 597 239
502,879 017,527 176,624 697 03C
20,341,978 269,491,947 289,833,925 502,879 017,527 176,624 10,697,03C
FERC FORM NO.1 (ED. 12-87)Page 423.
Nam e of Respondent
Idaho Power Company
Year/Period of Report
End of 2004/04
This ~ort Is: Date of Report(1) ~ An Original (Mo, Da, Yr)(2) 0 A Resubmission 04/22/2005
TRANSMISSION LINES ADDED DURING YEAR
1. Report below the information called for concerning 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 theLine LINE I TION TIne -sm- .- vr' IINl3 S' RUCTURE ~IRr'l "TS PER STRUGTURLength AverageNo. From To i Type Number per Present UltimateMiles Miles(c) (d) (e)
08 SP Wood
SP Wood
00 SP Steel
82 SP Steel
(a)
1 Boise Bench
2 Eagle
3 Butler
(b)(f)
(g)
Butler
Star
20.
, Wye 22.
26.4 Vallivie Tap
r '
44 TOTAL
FERC FORM NO.1 (REV. 12-03\
68.
Page 424
Name of Respondent This (!Jort Is:Date of Report Year/Period of Report
Idaho Power Company (1 ) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/22/2005
TRANSMISSION LINES ADDED DURING YEAR (Continued)
costs. Designate, however, if estimated amounts are r~ported. 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.
II I UK~LINE cas T LineVoltage
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)
1272 ACSR Vert 6'138 34,687 139,913 411,406 586,006
715 ACSR 040,48S 47,480 087 968
795 ACSR Vert 6'138 471 769 682 75S 376,280 530,808
795 ACSR Vert 6'138 272,092 79,405 351,497
11 .
506,456 135,252 914 571 556,279
FERC FORM NO.1 (REV. 12-03)- Page 425
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo. Da. Yr)End of 2004/04(2) D A Resubmission 04/22/2005
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)
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.
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.
Chestnut distribution 138.13.
Clear Lake - attended transmission 46.
I!"'
I. .
FERC FORM NO.1 (ED. 12-96)Page 426
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da. Yr)End of 2004/04(2) D A Resubmission 04/22/2005
SUBSTATIONS (Continued)
5. Show in columns (1),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 sale 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 S~bstation Number of Number of CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
(In Service) (In MVa)Transformers Spare Total Capacity No.In Service Transform ers Type of Equipment Number of Units (In MVa)
(f)
(g)
(h)(i)(k)
300
130
398
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 2004/04(2) 0 A Resubmission 04/22/2005
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)
Cliff transm Ission 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.
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.
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 138.36.
Grindstone distribution 35.12.
Grove distribution 138.12.
Hagerman distribution 46.12.
Hailey distribution 138.12.
Haven distribution 46.34.
Hewlett Packard distribution 138.13.
FERC FORM NO.1 (ED. 12-96) .Page 426.
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) XAn Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/22/2005
SUBSTATIONS (Continued)
5. Show in columns (I), U), 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 EOUIPMENT 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)
(j)
(k)
160
. .
101 . 6
160
, .
t..
. I
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1 ) X An Original (Mo. Da. Yr)End of 2004/04(2) DA Resubmission 04/22/2005
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)
Hidden Springs distribution 138.13.
Highland distribution 138.13.09
Hill distribution 138.12.
Homedale distribution 69.12.
Horseshoe Bend distribution 35.12.
Horseshoe Bend distribution 69.12.
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;00 '13.
Lamb distribution 138.13.
Lansing distribution 69.13.
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.
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.f .
FERC FORM NO.1 (ED. 12-96)Page 426.
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 2004/04(2) DA Resubmission 04/22/2005
SUBSTATIONS (Continued)
5. Show in columns (I), U), 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 EOUIPMENT 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)
300
180
180
600
360
120
720
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 2004/04(2) 0 A Resubmission 04/22/2005
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)
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.
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.
Salmon distribution 69.34.12.
Shoshone distribution 46.13.
Shoshone distribution 46.
Shoshone Falls - attached transmission 46.
Shoshone Falls - attached transmission 46.
Silver distribution 138.34.
Simplot 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 2004/04(2)0 A Resubmission 04/22/2005
SUBSTATIONS (Continued)
5. Show in columns (I), m, 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 EOUIPMENT Line
(In Service) (In MVa)Transform ers Spare Total Capacity No.In Service Transformers Type of Equipment Number of Units (In MVa)
(f)
(g)
(h)(i)(k)
1000
300
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
daho Power Com pany
(1) X An Original (Mo, Da, Yr)End of 2004/04
(2)0 A Resubmission 04/22/2005
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)
Sinker Creek distribution 138.34.
Siphon distribution 138.34.
South Park distribution 46.13.
Star distribution 69.13.
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.
Terry distribution 138.12.
Thousand Springs - attended transmission 46.
Thousand Springs - attended transmission 2.40
T oponis 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.
Valley View 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
Montana:
Peterson transmission 138.38.12.
Nevada:
Valmy - attended transmission 345.21.
Wells transmission 138.69.12.
"'~ .! .
I..
l .
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1 ) X An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/22/2005
SUBSTATIONS (Continued)
5. Show in columns (I), m, 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 accountsI 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 EOUIPMENT 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)
150
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2004/04(2) D A Resubmission 04/22/2005
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)
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.
. 15 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 82 unattended.
L .
'- .
FERC FORM NO.1 (ED. 12-96)Page 426.
, .
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/22/2005
SUBSTATIONS (Continued)
5. Show in columns (I), m, 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 EOUIPMENT 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)
500
240
244 2 -
100
133
748
- ,
FERC FORM NO.1 (ED. 12-96)Page 427.
INDEX
Schedule Paqe No.
262-263
234
272-277
Accrued and prepaid taxes
........................................ ............................
Accumulated Deferred Income Taxes .."
,."............................................
Accumulated provisions for depreciation of
common utility plant
utili ty plant
.... . . .
utili ty plant (summary)
Advances
from associated companies
. .. . . . . . . . . . . . .. . . . . . . . . . . . .. . .. . . . . . . .. . . . .. . . . . .. .
356
219
200-201
. .. . . .. . . . .. . . . . . . . . . . . ... .. .... . . .. . . .. . .. ... .. . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . .. . . . . '. . . . .. '. . . . . . .. . . . . . . . . . . .. . . . . . . . . . . . . . .. . . . . .
256-257
22S":229
. . . . . . . . . . . . . . . . . .. . '. . . . . . .
Allowances
. . . . . . . . . . . . . . . .. .. . .. . . . . ... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization
miscellaneous
. . . . .. . . .. . . . . . .. ... . . . . . . .. . . .. . . . . . . . .. . . ...
340
202-203
l1S-119
of nuclear fuel
. . . . . . . .,. . . . . . . . . . . . .. . . .. . .. .. .. . . . . . .. .. . . . . . . . . .. . . . . . .. . . . . . .
of Retained EarningsAppropriations
Associated Companies
advances from
.........................
corporations controlled by respondent
control over respondent
............
interest on debt to
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . .. . . . . . . .. .. . . . . . . . . . . . . . ...... . . . .... . .. .
256-257
103
102
256-257
. . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . .. ... .. .. . . . . ... ...... . . . . . .... ., . .. . . . .. . . . . . . . . . . . . . . .. . . . . .. . . . '. . . . . . . . . . . . . . . . . . . .
Attestation
.. . .. . . . . . . . . . . .. . .................................................................
Balance sheet
comparative
............................
notes to
....... ...,... ......
Bonds
110-113
122-123
256-257
251
254
252
251
252
120-121
. . . . . . . . . . . . . . .. .. . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . '. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Capi tal
expense
Stock
. . . . . . . . . . . . . . . . . . . .. . . . . . . ...................................... . . . . . . . . . . . . . . . .. . . . . . .. ., . . . . . .. . . . . . . ...... .. .. ... . . . . . . . . . . . . . . . . . . . . . . . .
premiums
...................................
reacquired" ........................
subscribed
. . . . . . . . . . . . . . . . . . . . .. . .. . .. . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . ..... . . ... . . . . .. . .. . . . . . . .. .. .. . . . . .. . .. . .
Cash
. . . . . . . . . . . . . . . . . . . . . . .. . . . . .. . . . . . . . . . . . .
flows,statement
Change s
important
Construction
........................................................................
10S-109during year
work in progress
work in progress
work in progress
Control
common utility plant
.. . . . . . . . . . . . . .
electric .....................
....,.
other utility departments
356
216
200-201
. . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . .... . . ... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . .
corporations controlled by respondent
over respondent
Corporation
controlled by
incorporated
CPA, background information on
CPA Certification, this report
. . . . . ..., . ., . . .. . . . . . . . . . . . . . . . . . . . . .. . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .... . .. . . . . . . . . . . ....,. .,. . . . . . . . . .... .. . . .. . . . . . . .,.. . . . . . .. . . .. . .. . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . .. . . .. . . . . . . . . .... . . . . . .. . . .. . . . . . . . . .. . . . . . . . .. . . . . . . . .. .. . . . . .. . . . . .
form
. . . . . .. . . . . . . . . .. ... . . . . . .. . . . . .
FERC FORM (ED. 12-93)IndexNO.
103
102
103
101
101
i-ii
INDEX (continued)
Schedule
Deferred
Paqe No.
credits,other
. . . .. . . . . . . . . ... . . . . . . ... . . . .. .. . . . . . .. . . . . . . . . . .. ... . ... . . . . . . . ... . . .
269
233debits, miscellaneous ................................................
income taxes accumulated - accelerated
amortization property ............................................................,...........
income taxes accumulated - other property
............... .............................. . . . . . . . . . . .. .
income taxes accumulated - other
. . . .,.. . .. .. . . . . .. . . . .. . . .. . . . .. ....... . . . . . .,.. . . . . .. . . .
272-273
274-275
276-277
234income taxes accumulated - pollution control facilities
Definitions, this report form ..."
'.'"
Depreciation and amortization
of common utility plant ......................................................,."
...
of electric plant
...................,.......... "...",.". . . . . . . .. .. . . . . . .. . . . .. . . . .. . . .. . .. . .. .. . . . . . . . . . .,. .. . .. . . . . . .
iii
356
219
336-337
105
Discount - premium on long-term debt
....................................... ..............
256-257
Distiibution of salaries and wages
........................... ",.",..
354-355
Dividend appropriations "
.,..",.",..".,. ............. .........
118-119
Earnings, Retained
......,..... .................... ............................
118-119
Electric energy account
............ .................................... ....... ......
401
Expenses
electric operation and maintenance
electric operation and maintenance,
unamortized debt
. . . . . . . . . .
Directors
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
swnmary
........................... . . . . .. . . . . . . . . . . ................
320-323
323
. . .. . . . . . ..
256
230
.. .... .. . . . ... . . . . . . . . . . . . . . .. . . .. .... . . . . . . .. . .. . . . .. .. . . .. . .. .. . .. .. ..
Extraordinary property losses
........................................................................
Filing requirements, this report form
General information "
,.",..."....". . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
101
Instructions for filing the FERC Form 1
Generating plant statistics
hydroelectric (large) .....................
....... ...................
406-407
pumped storage (large)
............................. .."" ........................
408-409
small plants .................................................
............. ......
410-411
steam-electric (large) ...........................................
...........,. ......
402-403
Hydro-electric geJlerating plant statistics ......................................................
. .
406.
":':_
407
Identification ................................................................. "101
108-109
.. .. . .. . . . . .. ... . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . .
i-iv
Important changes during year
. .... . . . . .. .... .. . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income
statement of, by departments
.................................. ..........................
statement of, for the year (see also revenues) ................d..
.......................
deductions, miscellaneous amortization
......................................... . . . . ... . . . . . . . . . . . .. . . .. . . .
114-117
114-117
340
340
. . . . ..
340
. . . . ..
101
deductions, other income deduction
deductions, other interest charges
Incorporation information
............... .. .. . . . . . .. .. . . . . . . . . . . . . . . .. . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
FERC FORM NO.1 (ED. 12-95)Index
INDEX (continued)
Schedule PaQe No.
Interest
charges,
Investments
. .. . . . ... . .. . . . . ., . . . . .. . . . . .. . . . . . . . . . .. . . . . . .
256-257paid on long-term debt,advances,etc
nonutili ty
subsidiary
Investment tax
. . . . . . .. . . . .. .. . ..
221
224-225
266-267
property
. ... . . . . . . . . .. . . . . . . . . . . . . .. . . .. . ...
companies
........... ...... ................................
credits, accumulated deferred
.......................... .............
Law, excerpts applicable to this report form
..................
List of schedules, this report form
................,
Long-term debt
.................. ................
Losses-Extraordinary property
.................................
Materials and supplies
...,..... "
Miscellaneous general expenses
.................... .........
Notes
... . . . . . . . .. .. . . . . .. . . .. . . .. . . . . . . . . . . .. . . . . . . . . . ... ..
2-4
256-257
. .. . . . . . .. ... ..
230
. . . . . . . ... . . . . . . . ..
227
.... . .,
335
. . . . . . . . . . . . .. . . . . . . . . . ... . . . . . .... . . . .. . . . . . . ... . . . . . . . . . . .. .. .
to balance sheet
................
122-123
122-123
......................
122-123
122-123
221
202-203
402-403
. . . . . . . . . . . . . . . . . ..
104
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
to statement of changes in financial position
.... .. . . . . .. . . . . .. . . . ., . .
to statement of income
................................,.......
to statement of retained earnings
............................,
Nonutility property
................. ........
Nuclear fuel materials
...... .......... ...... ......
Nuclear generating plant, statistics "
Officers and officers I salaries
......... . . . . . . . . . . . ... . . . . ., . . . . . ., . ... . . . . . .. ... . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . .. . . .. .. .. . . . .
Operating
expenses-electric
expens e s - e 1 e ct r i c
Other
paid-in capital
.....................
donations received from stockho~ders
. . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . .. . . . . . .
320-323
323( s urnrna ry )
. .. . . . .. . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ... . ... . . . . . . . . ... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. ... . . . ... .. ...............................
gains on resale or cancellation of reacquired
capital stock
........................................................,.... ..................
miscellaneous paid-in capital "
" ...................................
reduction in par or stated value of capital st6ck
......... ...... .........................
regulatory assets
...... ............. ............................. .....,.........
regulatory liabilities
......... ..................,. .....................................
Peaks, monthly, and output
........ "'" .....................................
Plant, Common utility
accumulated provision for depreciation
...........................................................
acquisition adjustments
............ "'" ...,..... ...................
allocated to utility departments
......... ...... .....................................
completed construction not classified "
................................................
construction work in progress "
.................................... .......
expenses
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
held for future use
in service
. . . . . . .. . . .. . ... . . . . . . '" . . . . . . . . . . . .. . . . . . . . . . . . . . .. . . ... . . . . . . ... . . . . . .. . . .. . . . . .. . . . . .. . . . . . . . . . . .. . . . .. . . .. . .. . . . .... . . . . . . ... .. ..... . . . . . ..
leased to others
Plant data
. . . . . . . . .... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . .. .. . . .. . . ... . . . . . .............................................
336-337
401-429
. . . . . . . . . . . . . . . . . . . . . . .
FERC FORM NO.1 (ED. 12-95)Index
.r '
253
253
253
253
253
232
278
401
356
356
356
356
356
356
356
356
356
INDEX (continued)
Schedule
Plant - electric
Paoe No.
accumulated provision for depreciation ...........................................................219
construction work in progress ....................................................................216
held for future use
...................... ................................................
214
in service ................................... ............................................204-207
213leased to others
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Plant - utility and accumulated provisions for depreciation
amortization and depletion (summary) .............................................................
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 .....................................................................230
Pumped 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
201
Reconciliation of reported net income with taxable income
from Federal income taxes ......................................................................261
Regulatory cornrnission expenses deferred ..............................................................233
Regulatory cornrnission expenses for year ..........................................................350-351
Research, development and demonstration activities ............................................... 352-353
Retained Earnings
amortization reserve Federal .....................................................................119
appropriated .................................................................................118-119
statement of, for the year ...................................................................118-119
unappropriated ...............................................................................118-119
Revenues - el,ectric operating ....................................................................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 ..........................................................................2-4
Sec::urities
Supplies - materials and
.............................................................................
250-251
120-121
114-117
118-119
402-403
426
227
exchange registration
........................................................................
Statement of Cash Flows
..........................................................................
Statement of income for the year ..................
....................,...........................
Statement of retained earnings for the year
.......................... ........................
Stearn-electric generating plant statistics
........................... ........................
Substations ......................................................................................
FERC FORM NO.1 (ED. 12-90)Index
INDEX (continued)
Schedule Paqe No.
.........................................................................
262-263
.........................................................................
262-263
and accumulated
................................................,............
234
272-277
reconciliation of net income with taxable income for
............................................
261
Transformers, line - electric
.......................................................................
429
Transmission
Taxes
accrued and prepaid
charged during year
on income, deferred
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
r- .
FERC FORM NO.lED. 12-90)Index
Page
Number
12-
December 31, 2004
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
STATE 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 Oth~rs, 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, 9, and 10 for Natural Gas companies using accounts 404.1, 404.2, 404.3, 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. & Depl. of Utility Plant (404-405)..........................................................
Amort. of Utility Plant Acq. Adj. (406)...............................................................
Amort. of Propert~ Losses, Unrecovered Plant and
Regulatory Study Costs (407)..................... .......... ............. .........
""""""""'"
Amort. of Conversion Expenses (407)..............................................................
Regulatory Debits (407.3).................................................""""""""""""""'"
(Less) Regulatory Credits (407.4).................... ......................... ............ ....
.......
Taxes Other Than Income Taxes (408.1 )... ........
.......... ........ .................. ..........
Income Taxes - Federal (409.
).......................................... ........"....... ............
- 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)...............................................................
In A un C:IIDDI CUCt.JT P~rT~
(Ref.
Page
No.
(b)
December 31, 2004
I 0
r '
TOTAL
Current Year Previous Year(c) (d)
756,779,337 $
491,365,712
54,187,809
84,052,059
092,999
19.944
(18,949.682)
17,219,724
839.912
958,131
( 18,569,538)
(1,042,465)
643.174,605
113,604,732 $
731 203,284
440,309.898
57,428,728
80,134,589
841,860 r '
18,563,551
464 805
397,483
(24,823,835)
265,614
l ~
l.
636,582,693
t ;
94,620,591
Idaho Power Company
STATE OF IDAHO. ALLOCATED
An Original December 31, 2004
TAXES ALLOCATED TO IDAHO
Kind of Tax
Taxes Other Than Income Taxes:
Labor Related:
FICA..................................................................
FUT A.......... .........................
..........."................
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 - NeL..............
Total Taxes Allocated to Idaho,..............................
Taxes Charged
Durinq Year
786,151
129,008
122 030
(8,037 189)
284,541
090,597
266
642,859
198,460
17,219,724
17,839,912
958,131
(18,569,538)
( 1 042,465)
23,405 764
11"\ .. un ~llnnl r=..r=a.IT 'D ::HT co
STATE OF IDAHO. ALLOCATED
An OriginalIdaho Power Company
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,
Jobbing &
Contract
Work
(c)
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)
Line Accounts
No.(a)
Notes Receivable (Account 141
)................................................................................................ $
Customer Accounts Receivable (Account 142)................................................
....................."'"
Other Accounts Receivable (Account 143)...... ........ .................... .........
.... ................ ....."...........
(Disclose any capital stock subscription received)
TotaL.... .......... ...... ...... ......,..... ........ ... .....,...... .,...... ......... ......... ..... .......... ... ....
..... ....... ...........
Less: Accumulated Provision for Uncollectible
Accounts-Cr. (Account 144)...... ........... ""'" ........... ............ ..... ......... .........."..... ........ ...........
Total, Less Accumulated Provision for
Uncollectible Accounts........................................................................................................ $
Notes Receivable - Account 141: (at 12-31-04)
Directors, officers, and employees - $ 7,269,296
Other Accounts Receivable - Account 143: (at 12-31-04)
Directors, officers, and employees - $ 4 705
Line Item Utility
Customers
Officers
and
Employees
(d)
No.(a)
(b)
566,346Bal. beginning of year
Provo for uncollectibles
for year... .............. .......... ......... ........ ......
Accounts written oft.................................
Call. of accounts
written oft.......... ............... ............ ..........
Adjustments (explain)..............................
100,731
Balance end of year.................................667,077 $
- $.- -..- -..--. ------
n""......... "::I
Balance
Beginning of
Year
(b)
12,982,368 $
43,693,876
840,398
61,516,641
1 ,465.615
60,051,025 $
Other
(e)
(256,433) $
(47,218)
- $
(303,651) $
December 31 , 2004
Balance
End of
Year
(c)
11,863,100
45,440 589
201,303
62,504,992 r .
363,426
61,141,566
Total
(f)
309,913
53,513
363,426
Idaho Power Company
STATE OF IDAHO - ALLOCATED
An Original
RECEIVABLES FROM ASSOCIATED COMPANIES (Accounts 145,146)
1. Report particulars of notes and accounts receivable from associated companies at end of year.
2. Provide s~parate 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
Balance
Beginning
of Year
(b)
Totals for YearDebits Credits(c) (d)
Particulars
No.(a)
Account 145:
Account 146:
$ 496,630.12 $. 3.965,422 $Rocky Mountain Communication 370,026
IOACORP, Inc......................... $ 646,452.58 $ 51,707,422 $ 51 148,356
IDACORP Energy Solutions........ 224,886 $224,479
Total Account 146........................ $143.083 $ 55,897,730 $ 55,742,861
In,U-In ~IIPPI I=MI=NT 'P;:JO'P 4
Balance
End of Year
(e)
92,026
205,519
407
297 952
December 31, 2004
Interest
For Year
(f)
r '
r .
This Page Intentionally Left Blank r "
t j
L ,
Idaho Power Company
STATE OF IDAHO - ALLOCATED
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,OOO'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
Original Cost
of Related
Property
(b)(d)
Date Journal
Entry Approved
(When Required)
(c)
Description of Property Acct 421.
No.(a)
Gain on disposition of
property:
(254,712)
(212,782)
Stoddard Sub Excess Land Sale
BOBN Trans Stn Land Sale
415,885
830
- n
Miscellaneous items (2)764)
Total gain......................................................... $416,715 (469,258)
Loss on disposition of
property:
Homedate Operations Center Sale 51,178
Total loss...................................................... .178
InAloIn ~llggl ~U~t.IT P;:Iap t;
December 31, 2004
Acct 421.
(e)
207
207
Idaho Power Company
STATE OF IDAHO - ALLOCATED
An Original
STATE OF IDAHO - TOTAL SYSTEM DATA
PROFESSIONAL OR CONSULTATIVE SERVICES -ITEMS $10,000 AND OVER
Line PAYEE SERVICE TYPE Amount
No.(a)(b)(c)
ACCOUNTEMPS Management Services 20,355
ADECCO Mapping Services 52,840
AERO-GRAPHICS Mapping Services 230,621
ALRUS CONSULTING Govermental Relationship Services 000
ASHLEY LAND SERVICES Environmental Services 15,098
AURORA CONSULTING GROUP Management Services 172 185
BARKER, ROSHOL T & SIMPSON LLP Legal Services 88.525
BIDART & ROSS INC Management Services 76,715
BLACKBURN & JONES LLP Legal Services 293,596
BLANK & ASSOCIATES P.Management Services 108,193
BLUE WORLD INFORMATION TECHNOL Management Services 78,705
BOISE BUSINESS CONSULTING, INC Management Services 209,980
BRICKLEY, SEARS & SORETI, P.Legal Services 51,297
BROWN RUDNICK BERLACK ISRAELS legal Services 36,000
BROWNSTEIN HYATI & FARBER, PC Environmental Services 441 196
BURKE CSA Customer Service Survey 40,000
BURKE INCORPORATED Customer Service Survey 135,000
BUSINESS LEGAL CONSULTING Management Services 13,005
CARDWELL CONSULTING INC Management Services 50,993
CH2M HILL Engineering Services 887
CHARLES G FORSTER, P E Engineering Services 11,479
CHARLES RIVER ASSOCIATES INCOR Management Services 12,341
CHURCH, JOHN S Economic Services 72,000
CITIGATE DATA CONSULTING, LLC Management Services 12,769
COMMVAUL T SYSTEMS, INC Management Services 27,500
CONNOLLY & SMYSER, CHTD Management Services 75,428
CORNERSTONE SYSTEMS INC Computer Support Services 601,892
CRI ADVANTAGE Computer Support Services 74,100
CYBERMA TION INC Computer Support Services 15,149
D J RESEARCH Management Services 16,208
DAVIS WRIGHT TREMAINE LLP Legal Services 913,362
DC ENGINEERING, PC Engineering Services 26,844
DELOITIE & TOUCHE AcCounting~ervices 412,564
DELOITTE & TOUCHE LLP Accounting Services 445,996
DELOITTE TAX LLP Accounting Services 46,749
DESERET RESEARCH INSTITUTE Management Services 175,109
DEVINE, TARBELL & ASSOC INC Environmental Services 44,232
DHIINC Environmental Services 45,427
ECOANAL YSTS INC Environmental Services 42,811
ENERGY INVESTMENTS MANAGEMENT,Management Services 15,000
ENVIRONMENTAL ENGINEERING Engineering Services 20,978
EOP GROUP Govermental Relationship Services 270,000
ERNST & YOUNG LLP Management Services 019,119
EVANS KEANE Legal Services 24,4 79
FA DEN BROCK, P.Engineering Services 18,084
.- ...- -..--. -..-.-
Page 6
December 31,2004
r: .
L i
Idaho Power Company
STATE OF IDAHO. ALLOCATED
An Original December 31, 2004
STATE OF IDAHO - TOTAL SYSTEM DATA
PROFESSIONAL OR CONSULTATIVE SERVICES -ITEMS $10 000 AND OVER
Line PAYEE SERVICE TYPE Am ount
No.(a)(b)(c)
GJORDING & FOUSER, PLLC Management Services 939
GJORDING, GARRETT & FOUSER Management Services 12,643
HALL FARLEY OBERRECHT & B Legal Services 135,128
HDR ENGINEERING, INC Engineering Seivices 41,752
HDR INC Engineering Services 597
HIRST, ERIC Management Services 13,913
HOLLAND CONSULTING GROUP Management Services 85,705
HUSTON DVM, RICHARD V Management Services 15,991
INTERMOUNTAIN TECHNOLOGY GROUP Computer Support Services 103,097
IOWA INSTITUTE OF HYDRAULICS Engineering Services 508,314
J D POWER AND ASSOCIATES Management Services 27,000
JAMS INC Management Services 18,390
JBR ENVIRONMENTAL CONSULTANTS Environmental Services 18,432
JUB ENGINEERS Engineering Services 91 ,575
KNOBLAUCH, WAYNE A Management Services 22,228
LANE, V MICHAEL Management Services 17,018
LE BOEUF LAMB GREENE Management Services 751,643
LITCHFIELD CONSULTING GROUP Management Services 17,762
MARSH ADVANTAGE AMERICA Management Services 17,040
MARSHALL & ASSOCIATES Management Services 64,520
MCFAIN & ASSOC RESEARCH INC Customer Service Survey 23,160
MERCURY INTERACTIVE CORP Computer Support Services 30,000
MERRILL & MERRILL CHARTERED Legal Services 11,571
MILLER BATEMAN LLP Legal Services 047
MOBLEY ENGINEERING INC Engineering Services 48.088
NEXUS ENERGY SOFTWARE Management Services 505,642
NIELSEN GROUP INC, THE Customer Service Survey 403,155
PARR WADDOUPS BROWN GEE AND La Environmental Services 43,649
PERKINS COlE LLP Legal Services 130,863
POWER ENGINEERS INC Engineering Services 20,117
POWERCET CORPORATION Management Services 22,069
PRICEW A TERHOUSE COOPERS LLP Accounting Services 25,000
PUBLIC OPINION STRATEGIES LLC Management Services 15,000
RALSTON & ASSOCIATES Engineering Services 18,035
RIDDELL WILLIAMS P.Legal Services 438,785
RIGHT MANAGEMENT CONSULTANTS Management Services 15,000
RIGHT SYSTEMS, INC Management Services 44,375
RIPLEY, LARRY D Management Services 35,150
RIVERSIDE TECHNOLOGY INC Environmental Services 52,797
ROBERTW WOOD, PC Management Services 16,416
SALLADAY & DAVIS Legal Services 185,987
SERVICE OUALITY MEASUREMENT GR Customer Service Survey 15,289
SMITH, CURTIS D Cloud Seeding Services 10,076
STATE OF IDAHO Management Services ~o,ooo
Page 6A
InAun ~IIDDI CUC"'T
Idaho Power Company
STATE OF IDAHO. ALLOCATED
An Original December 31,2004
STATE OF IDAHO - TOTAL SYSTEM DATA
PROFESSIONAL OR CONSULTATIVE SERVICES -ITEMS $10,000 AND OVER
Line PAYEE SERVICE TYPE Amount
No.(a)(b)(c)
STEPTOE & JOHNSON LLP Legal Services 425,699
STETSON P.E., LAVERNE E.Management Services 10,771
STONE, R H Management Services 40,670
SULLIVAN & CROMWELL Legal Services 100,748
SUMMIT BLUE CONSULTING LLC Legal Services 25,210
SUNGARD PLANNING SOLUTIONS Management Services 20,193
THELEN REID AND PRIEST LLP Legal Services 22,023
TREASURE VALLEY LEGAL SERVICES Legal Services 46,618
TRIVUE Management Services 46,230
UNIVERSITY OF IDAHO Environmental Services 27,370
100 VAILE, SCOTLUND Management Services 25,000
101 VAN NESS FELDMAN Legal Services 567,264
102 VAN WINKLE ENVIRONMENTAL CONSU Environmental Services 11,900
103 VOITH HYDRO INC Environmental Services 000
104 WEATHER MODIFICATION INC Cloud Seeding Services 29,413
105 ZGA ARCHITECTS & PLANNERS Architectural Services 18,354
106
107
108
109
110
111
112
113
114
115
116
117
118
119
120
121
122
123
124
125
126
127
128
129
130
131
132
133
Page 68
".. ..
un C!llnnl 1::...1::.."..
, '
L:;
Idaho Power Company
STATE OF IDAHO - ALLOCATED
An Original December 31. 2004
PROFESSIONAL OR CONSULTATIVE SERVICES
ITEMS $5.000 OR MORE BUT LESS THAN $10.000
Line PREDOMINANT
No.PAYEE NATURE OF SERVICE AMOUNT
A TER, WYNNE LLP Legal Services 285
BOISE STATE UNIVERSITY Management Services 870
COMPLIANCE SYSTEMS LEGAL GROUP Legal Services 366
ENVENTURE, INC Management Services 193
EQUENT INC Management Services 938
ESRIINC Geodata base Services 975
FIEDLER, FRITZ Engineering Services 528
GENERAL ELECTRIC POWER SY Management Services 830
ICF ENERGY SOLUTIONS, INC . Management Services 500
JEFFREY H BRAA TNE PHD Environmental Services 5,426
JONES, GLEDHILL, HESS, ANDREWS Legal Services 073
MALGREN, KEN Legal Services 248
MCCONNAUGHEY, DOUGLAS Legal Services 500
MCMILLIAN ELDRIDGE Management Services 831
MORGAN ANGEL & ASSOCIATES Lobby Services 9,488
PARAGON CONSULTING SERVICES Engineering Services 970
SMITHSONIAN INSTITUTE Environmental Services 329
SPENCER CONSULTING Management Services 580
SPF WATER ENGINEERING, LLC Environmental Services 903
STATISTICAL DESIGN Engineering Services 087
U S GEOLOGICAL SURVEY Management Services 510
UTILITY RESOURCES Management Services 050
WOOD CRAPO, LLC Legal Services 375
.- ...- ..... ........ ..............
Page 6C
Idaho Power Company
STATE OF IDAHO - ALLOCATED
An Original
ELECTRIC PLANT IN SERVICE (Accounts 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. 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
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
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 Balance at
Beginning of year
(b)No.
Account
(a)
1. INTANGIBLE PLANT
(301) Organization........................................................................................,........
(302) Franchises and Consents.......................................
.......................................
(303) Miscellaneous Intangible Plant...... ....... ......
..".............. ..................... ............
TOTAL Intangible Plant (Enter Total of lines 2,3. 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 Equipment...........
:.......................................................
(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 Equipment.......................................................................
(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 Equipment....................................................................
Page 7
579,376,950
180
566 111
56,635,603
65,206 894
722,319,606
.- .. ...... .... ........ ...............
December 31 2004
r .
r ~
Additions
(c)
~. .
Idaho Power Company
STATE OF IDAHO. ALLOCATED
An Original
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. 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 (f) only the offset to the debits or credits distributed in column (f) 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.
Retirements
(d)
Adjustments
(e)
Transfers
(f)
Balance at
End of Year
(g)
Page 8
InAl-ln c:.IIDDI r::Ur::NT
258
375,034
61,381 345
70,761 637
558 441
756,558,877
594 274 308
(301
(302)
(303)
(310)
(311 )
(312)
(313)
(314)
(315)
(316)
(317)
(320)
(321 )
(322)
(323)
(324)
(325)
(326)
(330)
(331 )
(332)
(333)
(334)
(335)
(336)
(337)
(340)
(341 )
(342)
(343)
(344)
(345)
(345)
December 31, 2004
Line
No.
Idaho Power Company
STATE OF IDAHO. ALLOCATED
An Original r' .December 31, 2004
ELECTRIC PLANT IN SERVICE (Accounts 101, 102 103 and 106) (Continued)
Line Balance at
Account Beginning of year Additions
No.(a)(b)(c)
(346) Misc. Power Plant Equipment.........
...............................,....... ...... .... ......... .....
TOTAL Other Production Plant (Enter Total of lines 37 thru 44)...........................940,207
TOTAL Production Plant (Enter Total of lines 16, 25, 35, and 45).........................349,636 764
3. TRANSMISSION PLANT
(350) Land and Land Rights....................................................................................657,376
(352) Structures and Improvements........ ..............,..... .,.......... ....................... .........25,510.923
(353) Station Equipment........................................................................................173,794,729
(354) Towers and Fixtures......... ...
;..... .................. ..".... .................... ........... ...........
55,210,899
(355) Poles and Fixtures... ........
....................... ........ ......... ................ ........ .............
70,863,543
(356) Overhead Conductors and Devices................
"""""""'" ............... ........ .........
85,947 993
(357) Underground Conduit....................................................................................
(358) Underground Conductors and Devices........... .........
........"........... .... ...............
(359) Roads and Trails. ........... .................
.................................. ....... .... ..... .............
250,695
(359.1) Asset Retirement Costs for Transmission Plant.....................................
TOTAL Transmission Plant (Enter Total of lines 48 thru 57).................................429,236,159
4. DISTRIBUTION PLANT
(360) Land and Land Rights....................................................................................624,498
(361) Structures and 1m provements.................................................. .....
.................
15,395,780
(362) Station Equipment........................................................................................119,482,754
(363) Storage Battery Equipment........ ...................... ......... ............. .... ............... .....
(364) Poles, Towers, and Fixtures......... ......."... ............. ................. ....... "'" ........"..164 829,925
(365) Overhead Conductors and Devices.................................................................103,989
(366) Underground Conduit.............................................................................,......952,167
(367) Underground Conductors and Devices........... ............ .... ................... ........ ."...133 917,957
(368) Line Transformers..........................................................................................240,553,773
(369) Services.............................................................................,..........................530,098
(370) Meters...........................................................................................................38,282,432
(371) Installations on Customer Premises................................................................034 861
(372) Leased Property on Customer Premises.........................................................
(373) Street Lighting and Signal Systems................................................................759,099
(374) Asset Retirement Costs for Distribution Plant.........................................
TOTAL Distribution Plant (Enter Total of lines 60 thru 74)....................................888,467,332
5. GENERAL PLANT
(389) Land and Land Rights....................................................................................811,992
(390) Structures and Improvements... .............. ................... ..............
.............."......
53,326,546
(391) Office Furniture and Equipment......................................................................510,563
(392) Transportation Equipment.............................................................................249,328
(393) Stores Equipment.............................................................,...........................882,399
(394) Tools, Shop, and Garage Equipment..............................................................237 177
(395) Laboratory Equipment...................................................................................065,068
(396) Power Operated Equipment..... ........ .......
......."............... .................. ......, ......
604 345
(397) Communication Equipment...........................................................................23,012,914
(398) Miscellaneous Equipment.............................................................................909,601
SUBTOTAL (Enter Total of lines 77 thru 86)........................................................192,609,933
(399) Other Tangible Property...... ....... ............ ............ ............. .................... ...........
(399.1) Asset Retirement Costs for General Plant.........................................
TOTAL General Plant (Enter Total of lines 87 88 and 89)...................................192,609,933
TOTAL (Accounts 101 and 106)..... ....... ............ ....... ..."......
.........................
925,157 082
(102) Electric Plant Purchased...............................................................................
(Less) (102) Electric Plant Sold.. ......... ......,.......... ....". ""'" ............ ..... ............. .......
(103)' Experimental Plant Unclassified.......... ............. ..... .........
........"....... ...............
TOTAL Electric Plant in Service..........................................................................925,157,082
InAJ.ln C::IIDDI ~U~t\lT
Page 9
r '
r .
r ;
. .
L ,
Idaho Power Company
STATE OF IDAHO - ALLOCATED
An Original December 31, 2004
ELECTRIC PLANT IN SERVICE (Accounts 101 , 102, 103 and 106) (Continued)
Balance at Line
Retirements Adjustments Transfers End of Year
(d)(e)(f)(9)No.
(346)
549 572
1,400 382,756
18,967,406 (350)
513,448 (352)
192 783,834 (353)
65,195,492 (354)
353,999 (355)
540,014 (356)
(357)
(358)
258'820 (359)
(359.
471 613,012
236,450 (360)
558,946 (361)
121 883,650 (362)
(363)
169,651 555 (364)
163.932 (365)
38,597 249 (366)
145,041,107 (367)
247 888,244 (368)
43,848,501 (369)
45,244 916 (370)
221,384 (371)
(372)
761 277 (373)
(374)
926,097 210
893,724 (389)
55,505,835 (390)
946,665 (391)
40,408 870 (392)
928,294 (393)
533,350 (394)
509,357 (395)
830.803 (396)
062,804 .(397)
161 775 (398)
196 781,476
(399)
(399.
196 781,476
065,636,092
(102)
(102)
(371)
065,636,092
InAL.ln C:IIDDI i:Ui:to.IT
Page 10
Idaho Power Company
STATE OF IDAHO - ALLOCATED
An Original December 31 2004
f '
1 ,
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 ttrle 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.
- -
No.
OPERATING REVENUESAmount for Amount forCurrent Year Previous Year
(a)
Sales of Electricity
(440) Residential Sales... ......... .... ..........
..... """ """""""'" ..........
(442) Commercial and Industrial Sales
Small (or Commercial)(See Instr. 4) (1 ).....................................
Large (or Industrial)(See Instr. 4) (2)..........................................
(444) Public Street and Highway Lighting...........
,.........................
(445) Other Sales to Public Authorities.............................
;..........
(446) Sales to Railroads and Railways.........................................
(448) Interdepartmental Sales......... ........ ...........
......, ...."... ..........
TOTAL Sales to Ultimate Consumers.....................................
(447) Sales for Resale - Opportunity....Non-Firm Only................
TOTAL Sales of Electricity......................................................
(449.1) Provision for Rate Refunds.............................................
TOTAL Revenue Net of Provision for Refunds........................
Other Operating Revenues
(450) Forfeited Discounts.. ........ ... .............
.... .... ........................ ...
(451) Miscellaneous Service Revenues.......................................
(453) Sales of Water and Water Power.......................................
(454) Rent from Electric Property.................................................
(455) Interdepartmental Rents.....................................................
(456) Other Electric Revenues.....................................................
(c)(b)
266,499,664264,432,685
254,652,452
121,183,306
517,165
237,670,029
103,211,741
194,234 r' ,
607,508.689 *
110,451,320
717 960,009
114,364
719,074,373
644 852,588
894 912
699,747 500
(1,514,466)
698,233,034
r '
177,891 353,527
L ;
16,096,192 15,356,794
17,430,881 14,259,926 r '
I. :
704,963
756,779,337
32,970,248
731,203,282
TOTAL Other Operating Revenues.........................................
TOTAL Electric Operating Revenues......
,................................ $
(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
In A un ellOOI E:au:1o.1T
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.
December 31,2004
KILOWATT HOURS SOLD AVERAGE NUMBER OF CUSTOMERS PER MONTH
Amount for
Current Year
Number for
Previous Year
Amount for
Previous Year
Amount for
Current Year
(d)(e)(f)
389 994 071 238,675,325 347 384
092 937 686
064 574 997
037 680
120 316 621
963 550 790
536,450
638
112
480
574 544,434 **
717 422 630
291 967 064
351 079 186
686 106 716
037 185 902
415 614
N/A
415 614
* Includes $ (2 784 492) unbilled revenues.
** Includes 51 163,975 KWH relating to un billed revenues.
Lines 11 through 21 are on an "allocated" basis.
Page 11a
IDAHO SUPPLEMENT
(g)
336 204
66,047
107
392
402 750
N/A
402 750
Line
No.
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.
Ine
No.
. team
Operation
(500) Operation Supervision and Engineering........................................................................
(501) Fuel................... ...,........ ......" ................
......................................................................"
(502) Steam Expenses. ...... ..................
...... ...... """"""'" ..... ....,......... ........ ....... ...... .........."...
(503) Steam from Other Sources...........................................................................................
(Less) (504) Steam Transferred-Cr........................................................................................
(505) Electric Expenses.................. ........... ..........."........
""""""""'" ....... ...... .......................
10 (506) Miscellaneous Steam Power Expenses........................................................................
11 (507) Rents...................... ............... ........
...... ..................... ""'" ....... ................... ........... ........
12 (509) Allowances....... ..... .............. ."...... ........,. ...........
..................... ................ .......................
13 TOTAL Operation (Enter Total of lines 4 thru 12)............................................................
14 Maintenance15 (510) Maintenance Supervision and Engineering...................................................................
16 (511) Maintenance of Structures................ .....,.............. ..... .........
..... ...... ................ ...........,...
17 (512) Maintenance of Boiler Plant.....
...................................................................................,..
18 (513) Maintenance of Electric Plant......................................................................................
19 (514) Maintenance of Miscellaneous Steam Plant..................................................................20 TOTAL Maintenance (Enter Total of Lines 15 thru 19)....................................................21 TOTAL Power Produc~ion Expenses-Steam Power (Enter Total of lines 13 and 20)......22 B. Nuclear Power Generation 23 Operation
24 (517) Operation Supervision and Engirieering........................................................................
25 (518) Fuel.... ............... ......... ....................... ......................... ........... ..........,....... ....".. ..............26 (519) Coolants and Water............................. ........................... ............
.......... ........... ............,
27 (520) Steam Expenses.... ......
........... ........ ..... ................. .......,. ................. .,. ..... .........., ...........
28 (521) Steam from Other Sources...........................................................................................29 (Less). (522) Steam Transferred-Cr. ........... .... .... ....... .......
.......................... ......... ..... ....... .......
30 (523) Electric Expenses... ..
.... ............. .......... .......... """""" ..... ....... ..... ...".. ......... .............."..
31 (524) Miscellaneous Nuclear Power Expenses......................................................................32 (525) Rents...... ............ .....
...... ...................... ...... """"""""" ....... .......". ......,. ......... ....... .....".
33 TOTAL Operation (Enter Total of lines 24 thru 32).........................................................
34 Maintenance35 (528) Maintenance Supervision and Engineering................ .....
;............. ............... ..... ............
36 (529) Maintenance of Structures....... ....... .....
.......... ...... ............. ............. ...............................
37 (530) Maintenance of Reactor Plant Equipment......................
:..............................................
38 (531) Maintenance of Electric Plant.................................................................................
:......
39 (532) Maintenance of Miscellaneous Nuclear Plant................................................................40 TOTAL Maintenance (Enter Total of lines 35 thru 39).....................................................41 TOTAL Power Production Expenses-Nuclear Power (Enter Total of lines 33 and 40)....42 C. Hydraulic Power Generation43 Operation 44 (535) Operation Supervision and Engineering............... .......... ............
................... ...... ..........
45 (536) Water for Power. ..."................. ............... .......
....... ........... ...... .............. .... .....................
46 (537) Hydraulic Expenses..................................................................................................,...
47 (538) Electric Expenses................ ................ ..........
................................ .... ......... .."....... .......
48 (539) Miscellaneou~ Hydraulic Power Generation Expenses
:................................................
49 (540) Rents........................................................"""""""""""""""""""""""""""'".....,.....50 TOTAL Operation (Enter Total of lines 44 thru 49).........................................................
Page 12
....au,.,. ~..nn. ~..~"IT
December 31, 2004
\ -
r- ,
121,417 798,177
92,660,616 86,820,441
029,304 266,006
r .
1,470,502 208,406
543,638 272,906
671,368 534 110
701,548
338,935
943,969
886,517
905,848
176,063
794,616
6,416,142
175,791
388,132
358,887
880,434
299,985
11;515,052
244,350
979,069
r :
f:'
542,537
516,608
202,095
048,760
689,732
346,459
Idaho Power Company
STATE OF IDAHO - ALLOCATED
An Original
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
December 31, 2004
If the amount for previous year is not derived from previously reported figures, explain in footnotes.
No.
. y rau IC ower eneratlon
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 Plant.............................................................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 Generation61 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 Maintenance69 (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 Operation83 (560) Operation Supervision and Engineering........................................................................84 (561) Load Dispatching.........................................................""""".""""""""""'."".""""'"
85 (562) Station Expenses.................. ....... .........................
....,...... ,."""""., ............. .......... ........
86 (563) Overhead Line Expenses.... ......
............ '.'" .........".. """"". """"." ........... .,........ ..... ......
87 (564) Underground Line 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........................................................................
Page 13
InAun ~IIDDI CIUC~T
999,707 $
949,154
975,013
140,578
2,495,950
051,310
100,162
736,904
2,411 961
072,061
370,143
590,362
161,183
282,385
441 175
228,350
150,035
280,169
140,776
117 ,832
268,435
709,826 315,730
2,482,481 304,418
1,423,846 264,093
456,328 532,675
950,494 998,502
15,028 232,057
832 087 140,225
549,772 602,651
277
541,620 189,417
976,089 864 952
631 942
368,098 115,740
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)
ontinu
105 (581) Load Dispatching......... ...........
......"..................................... """"" ...,.... .... ......... .... ......
106 (582) Station Expenses.... ................. ..............."............ ................................. .....
......... .........
107 (583) Overhead Line Expenses................................................................................."...........
1 08 (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 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 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 14
.n. A un ~. '00' 1:...1:.....,.
253,438 $
891,829
194 716
640,328
143,396
935,551
487,909
664,454
140,393
62,175
752,978
10,219,142
222,685
235,963
468,812
909,523
166,351
408,079
4,489,463
910,379
850,386
(5,776)
306,135
174.632
299
715,731
42,139,149
13.713,290
(24 555,748)
December 31, 2004
.--'
099,164
801,475
088,077
762,626
121,784
4,496,854
435,492
364,414
133,314
I: :
r :'
33,224
689,054
11,089,857
351,494
608,411
356,209
357 473
224,381
380,359
4,425,988
332,812
811,198
120,411
390,866
829,273
149
613,818
27,972,058
12,519,423
(26,348.765)
Idaho Power Company
STATE OF IDAHO. ALLOCATED
An Original December 31, 2004
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnotes.
Account
(a)
Ine
No.
ontlnu
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 Maint Exp (Total of 80,100,126 134 141 148,168).................
574 191 $
979,099
585,966
852 207
075
301 815
914 854
581,993
596,141
25,612,849
725
670,019
110,224
825,509
11 ,331
516,752
696,069
35,716
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, 2004
Total Regular Full-Time Employees....................................................................,...................757
Total Part-Time and T emporary Employees...........................................................................
Total Employees. ............ ......... ................. .......... .................. ...... ................
""""""'" .............
802
Page 15
IOAlotn !;lJPPLFMFNT