2006Annual Report.pdf

THIS FILING IS
Item 1: 00 An Initial (Original)
Submission
OR D Resubmission No.
r .
FERC FINANCIAL REPORT
FERC FORM No.1: Annual Report of
Major Electric Utilities, Licensees
and Others and Supplemental
Form 3-Q: Quarterly Financial Report
These reports are mandatory under the Federal Power Act, Sections 3, 4(a), 304 and 309, and
18 CFR 141.1 and 141.400. Failure to report may result in crim inal fines, civil penalties and
other sanctions as provided by law. The Federal Energy Regulatory Commission does not
consider these reports to be of confidential nature
. ,
Form 1 Approved
OMB No. 1902-0021
(Expires 7/31/2008)
Form 1-F Approved
OMB No. 1902-0029
(Expires 6/30/2007)
Form 3-0 Approved
OMB No. 1902-0205
(Expires 6/30/2007)
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Exact Legal Name of Respondent (Company)
Idaho Power Company End of
Year/Period of Report
2006/04
FERC FORM No.1/3-Q (REV. 02-04)
Deloitte
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Deloitte & Touche llP
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INDEPENDENT AUDITORS' REPORT
Idaho Power Company
Boise, Idaho
We have audited the balance sheet-regulatory basis ofIdaho Power Company (the "Company ) as of
December 31 , 2006, and the related statements of income-regulatory basis; retained eamings-
regulatory basis; cash flows-regulatory basis, and accumulated comprehensive income, comprehensive
income, and hedging activities-regulatory basis for the year ended December 31 , 2006, 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 , 2006, and the
results of its operations and its cash flows for the year ended December 31 , 2006, 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.
LL t7
February 28, 2007
Member of
Deloitte Touche Tohmatsu
INSTRUCTIONS FOR FILING FERC FORM NOS. 1 and 3-
GENERAL INFORMATION
Purpose
FERC Form No.1 (FERC Form 1) is an annual regulatory requirement for Major electric utilities, licensees and others
(18 C.R. 9 141.1). FERC Form No. 3-0 ( FERC Form 3-0)is a quarterly regulatory requirement which supplements the
annual financial reporting requirement (18 C.R. 9 141.400). These reports are designed to collect financial and
operational information from electric utilities, licensees and others subject to the jurisdiction of the Federal Energy
Regulatory Commission. These reports are also considered to be non-confidential public use forms.
II. Who Must Submit
Each Major electric utility, licensee, or other, as classified in the Commission s Uniform System of Accounts
Prescribed for Public Utilities and Licensees Subject To the Provisions of The Federal Power Act (18 C.R. Part 101),
must submit FERC Form 1 (18 C.R. 9141.1), and FERC Form 3-0 (18 C.R. 9141.400).
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).
III.What and Where to Submit
(a) Submit FERC Forms 1 and 3-0 electronically through the forms submission software. Retain one copy of each report
for your files. Any electronic submission must be created by using the forms submission software provided free by the
Commission at its web site: http://www.ferc.Qov/docs-filinQ/eforms/form-1/elec-subm-soft.asp. The software is
used to submit the electronic filing to the Commission via the Internet.
(b) The Corporate Officer Certification must be submitted electronically as part of the FERC Forms 1 and 3-0 filings.
(c) Submit immediately upon publication, by either eFiling or mail, two (2) copies to the Secretary of the Commission, the
latest Annual Report to Stockholders. Unless eFiling the Annual Report to Stockholders, mail the stockholders report to
the Secretary of the Commission at:
Secretary
Federal Energy Regulatory Commission
888 First Street, NE
Washington, DC 20426(d) For the CPA Certification Statement, submit within 30 days after filing the FERC Form 1 , a letter or report (not
applicable to filers classified as Class C or Class D prior to January 1, 1984). The CPA Certification Statement can be
either eFiled or mailed to the Secretary of the Commission at the address above.
FERC FORM 1 & 3-Q (ED. 03-07)
The CPA Certification Statement should:
Attest to the conformity, in all material aspects, of the below listed (schedules and pages) with the
Commission s applicable Uniform System of Accounts (including applicable notes relating thereto and the
Chief Accountant's published accounting releases), and
Be signed by independent certified public accountants or an independent licensed public accountant
certified or licensed by a regulatory authority of a State or other political subdivision of the U. S. (See 18
R. ~~ 41.10-41.12 for specific qualifications.
Reference Schedules Paaes
Comparative Balance Sheet
Statement of Income
Statement of Retained Earnings
Statement of Cash Flows
Notes to Financial Statements
110-113
114-117
118-119
120-121
122-123
The following format must be used for the CPA Certification Statement unless unusual circumstances or conditions,
explained in the letter or report, demand that it be varied. Insert parenthetical phrases only when exceptions are
reported.
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.
The letter or report must state which, if any, of the pages above do not conform to the Commission s requirements.
Describe the discrepancies that exist.
(f) Filers are encouraged to file their Annual Report to Stockholders, and the CPA Certification Statement using eFiling.
To further that effort, new selections, "Annual Report to Stockholders " and "CPA Certification Statemenf' have been
added to the dropdown "pick list" from which companies must choose when eFiling. Further instructions are found on the
Commission s website at http://www.terc.Qov/help/how-to.asp
(g) Federal, State and Local Governments and other authorized users may obtain additional blank copies of
FERC Form 1 and 3-0 free of charge from http://www.ferc.aov/docs-filina/eforms/form-1 /form-pdf and
http://www.ferc.aov/docs-filina/eforms.asP#3Q-aas
IV. When to Submit:
FERC Forms 1 and 3-0 must be filed by the following schedule:
FERC FORM 1 & 3-a (ED. 03-07)
a) FERC Form 1 for each year ending December 31 must be filed by April 18th of the following year (18 CFR 9 141.1), and
b) FERC Form 3-0 for each calendar quarter must be filed within 60 days after the reporting quarter (18 C.R. 9
141.400).
V. Where to Send Comments on Public Reporting Burden.
The public reporting burden for the FERC 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. The public reporting burden for
the FERC Form 3-0 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: Information Clearance Officer); 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. 93512 (an.
FERC FORM 1 & 3-a (ED. 03-07)iii
GENERAL INSTRUCTIONSI. Prepare this report in conformity with the Uniform System of Accounts (18 CFR Part 101) (USofA). Interpret
all accounting words and phrases in accordance with the USofA.II. Enter in whole numbers (dollars or MWH) only, except where otherwise noted. (Enter cents for averages and
figures per unit where cents are important. The truncating of cents is allowed except on the four basic financial statements
where rounding is required.) The amounts shown on all supporting pages must agree with the amounts entered on the
statements that they support. When applying thresholds to determine significance for reporting purposes, use for balance
sheet accounts the balances at the end of the current reporting period, and use for statement of income accounts the
current year s year to date amounts.III Complete each question fully and accurately, even if it has been answered in a previous report. Enter the
word "None" where it truly and completely states the fact.IV. For any page(s) that is not applicable to the respondent, omit the page(s) and enter "
" "
NONE," or "Not
Applicable" in column (d) on the List of Schedules, pages 2 and 3.
V. Enter the month, day, and year for all dates. Use customary abbreviations. The "Date of Report" included in the
header of each page is to be completed only for resubmissions (see VII. below).VI. Generally, except for certain schedules, all numbers, whether they are expected to be debits or credits, must
be reported as positive. Numbers having a sign that is different from the expected sign must be reported by enclosing the
numbers in parentheses.
VII For any resubmissions, submit the electronic filing using the form submission software only. Please explain
the reason for the resubmission in a footnote to the data field.
VIII. Do not make references to reports of previous periods/years or to other reports in lieu of required entries,
except as specifically authorized.IX. Wherever (schedule) pages refer to figures from a previous period/year, the figures reported must be based
upon those shown by the report of the previous period/year, or an appropriate explanation given as to why the different
figures were used.
Definitions for statistical classifications used for completing schedules for transmission system reporting are as follows:
FNS - Firm Network Transmission Service for Self. "Firm " means service that can not be interrupted for economic reasons
and is intended to remain reliable even under adverse conditions. "Network Service" is Network Transmission Service as
described in Order No. 888 and the Open Access Transmission Tariff. "Self" means the respondent.
FNO - Firm Network Service for Others. "Firm " means that service cannot be interrupted for economic reasons and is
intended to remain reliable even under adverse conditions. "Network Service" is Network Transmission Service as
described in Order No. 888 and the Open Access Transmission Tariff.
LFP - for Long-Term Firm Point-to-Point Transmission Reservations. "Long-Term" means one year or longer and" firm
means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse
conditions. "Point-to-Point Transmission Reservations" are described in Order No. 888 and the Open Access
Transmission Tariff. For all transactions identified as LFP, provide in a footnote the
FERC FORM 1 & 3-a (ED. 03-07)
termination date of the contract defined as the earliest date either buyer or seller can unilaterally cancel the contract.
OLF - Other Long-Term Firm Transmission Service. Report service provided under contracts which do not conform to the
terms of the Open Access Transmission Tariff. "Long-Term" means one year or longer and "firm" means that service
cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. For all
transactions identified as OLF, provide in a footnote the termination date of the contract defined as the earliest date either
buyer or seller can unilaterally get out of the contract.
SFP - Short-Term Firm Point-to-Point Transmission Reservations. Use this classification for all firm point-to-point
transmission reservations, where the duration of each period of reservation is less than one-year.
NF - Non-Firm Transmission Service, where firm means that service cannot be interrupted for economic reasons and is
intended to remain reliable even under adverse conditions.
OS - Other Transmission Service. Use this classification only for those services which can not be placed in the
above-mentioned classifications, such as all other service regardless of the length of the contract and service FERC Form.
Describe the type of service in a footnote for each entry.
AD - Out-of-Period Adjustments. Use this code for any accounting adjustments or "true-ups" for service provided in prior
reporting periods. Provide an explanation in a footnote for each adjustment.
DEFINITIONS
I. Commission Authorization (Comm. Auth.) -- The authorization of the Federal Energy Regulatory Commission, or any
other Commission. Name the commission whose authorization was obtained and give date of the authorization.
II. Respondent -- The person, corporation, licensee, agency, authority, or other Legal entity or instrumentality in whose
behalf the report is made.
FEAC FORM 1 & 3-a (ED. 03-07)
EXCERPTS FROM THE LAW
Federal Power Act, 16 U.C. ~ 791 a-825r
Sec. 3. The words defined in this section shall have the following meanings for purposes of this Act, to with:
(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 shall 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 and 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 fore bay reservoirs directly connected therewith , the primary line or lines transmitting power there
from 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 the utilization of the water 'resources of any region to
be developed, the water-power industry and its relation to other industries and to interstate or foreign commerce, and
concerning the location, capacity, development -costs, and relation to markets of power sites; ... to the extent the
Commission may deem necessary or useful for the purposes of this Act"
Sec. 304. (a) Every Licensee and every public utility shall file with the Commission such annual and other periodic or
special* reports as the Commission may be rules and regulations or other prescribe as necessary or appropriate to assist
the Commission in the -proper administration of this Act The Commission may prescribe the manner and FERC Form in
which such reports salt 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
FERC FORM 1 & 3-a (ED. 03-07)
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 FERC Form or FERC 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
The Commission may assess up to $1 million per day per violation of its rules and regulations. See
FPA ~ 316(a) (2005), 16 U.c. ~ 825o(a).
FERC FORM 1 & a (ED. 03-07)vii
IDENTIFICATION
01 Exact Legal Name of Respondent 02 Year/Period of Report
Idaho Power Company End of 2006/04
03 Previous Name and Date of Change (if name changed during year)
/ /
04 Address of Principal Office at End of Period (Street, City, State, Zip Code)
1221 W Idaho Street, P.O. Box 70 Boise, ID 83707-0070
05 Name of Contact Person 06 Title of Contact Person
Darrel Anderson Senior VP of Admin Ser & CFO
07 Address of Contact Person (Street, City, State, Zip Code)
1221 W Idaho Street, P.O. Box 70 Boise, ID 83707-0070
08 Telephone of Contact Person,lncluding 09 This Report Is 10 Date of Report
Area Code (1) 00 An Original (2) D A Resubmission (Mo, Da, Yr)
[phone] 04/18/2007
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 infonmation contained in this report, confonm in all material
respects to the Uniform System of Accounts.
01 Name 03 Signature 04 Date Signed
Darrel Anderson (Mo, Da, Yr)
02 Title
Senior VP of Admin Ser & CFO Darrel Anderson 04/18/2007
Title 18, U.C. 1001 makes it a crime for any person to knowingly and willingly to make to any Agency or Department of the United States any
false, fictitious or fraudulent statements as to any matter within its jurisdiction.
FERC FORM NO. 1/3-
REPORT OF MAJOR ELECTRIC UTILITIES LICENSEES AND OTHER
FERC FORM No.1I3-Q (REV. 02-04)Page 1
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2006/04
(2)0 A Resubmission 04/18/2007
LIST OF SCHEDULES (Electric Utility)
Enter in column (c) 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)
1 Generallnformation 101
Control Over Respondent 102
Corporations Controlled by Respondent 103
Officers 104
5 Directors 105
6 Important Changes During the Year 108-109
7 Comparative Balance Sheet 110-113
8 Statement of Income for the Year 114-117
9 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
Transmission Service and Generation Interconnection Study Costs 231 None
Other Regulatory Assets 232
Miscellaneous Deferred Debits 233
Accumulated Deferred Income Taxes 234
Capital Stock 250-251
Other Paid. in Capital 253
Capital Stock Expense 254
Long-Term Debt 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
FERC FORM NO.1 (ED. 12-96)Page 2
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2006/04
(2)0 A Resubmisslon 04/18/2007
LIST OF SCHEDULES (Electric Utility) (continued)
Enter in column (c) 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)
Accumulated Deferred Income Taxes-Accelerated Amortization Property 272-273
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 ISO/ATOs 331 None
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
Amounts included in ISO/RTO Settlement Statements 397 None
Purchase and Sale of Ancillary Services 398 None
Monthly Transmission System Peak Load 400
Monthly ISO/RTO Transmission System Peak Load 400a None
Electric Energy Account 401
Monthly Peaks and Output 401
Steam Electric Generating Plant Statistics 402-403
Hydroelectric Generating Plant Statistics 406-407
Pumped Storage Generating Plant Statistics 408-409 None
Generating Plant Statistics Pages 410-411
Transmission Line Statistics Pages 422-423
Transmission Lines Added During the Year 424-425
FERC FORM NO.1 (ED. 12-96)Page 3
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2006/04
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) DA Resubmission 04/18/2007
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
No.
(a)
Reference
Page No.
(b)
426-427
450
RemarksTitle of Schedule
(c)
67 Substations
68 Footnote Data
Stockholders' Reports Check appropriate box:
(!J Four copies will be submitted
No annual report to stockholders is prepared
FERC FORM NO.1 (ED. 12-96)Page 4
Name of Respondent
Idaho Power Company
This Report Is:
(1) 00 An Original(2) D A Resubmission
Date of Report
(Mo Oa, Yr)
04/18/2007
Year/Period of Report
End of 2006/04
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 Administrative Services and CFO, Idaho Power Company
1221 W. Idaho Street, P.O. Box 70, Boise, Idaho 83707-0070
2. Provide the name of the State under the laws of which respondent is incorporated, and date of incorporation.
If incorporated under a special law, give reference to such law. If not incorporated, state that fact and give the type
of organization and the date organized.
Idaho, June 30, 1989
3. If at any time during the year the property of respondent was held by a receiver or trustee, give (a) name of
receiver or trustee, (b) date such receiver or trustee took possession, (c) the authority by which the receivership or
trusteeship was created, and (d) date when possession by receiver or trustee ceased.
Not Applicable
4. State the classes or utility and other services furnished by respondent during the year in each State in which
the respondent operated.
Class of Utility Service
Electric
State
Idaho
Oregon
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) !XI No
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, Da, Yr)
04/18/2007
Year/Period of Report
End of 2006/04
CONTROL OVER RESPONDENT
1. If any corporation, business trust, or similar organization or a combination of such organizations jointly held
control over V'1e repondent at the end of the year, state name of controlling corporation or organization, manner in
which control was held, and extent of control. If control was in a holding company organization, show the chain
of ownership or control to the main parent company or organization. If control was held by a trustee(s), state
name of trustee(s), name of beneficiary or beneficiearies for whom trust was maintained, and purpose of the trust.
Idaho Power Company is a subsidiary of IDACORP, INC
IDACORP owns 100% of Idaho Power Companys Common Stock.
IDACORP is a public utility Holding Company incorporated effective 10-1998
FERC FORM NO.1 (ED. 12-96)Page 102
Name of Respondent This
'0ort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2006/04
(2) (j A Resubmission 04/18/2007
C JRPORATIONS CONTROLLED BY RESPONDENT
1. Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent
at any time during the year. If control ceased prior to end of year, give particulars (details) in a footnote.
2. If control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, naming
any intermediaries involved.
3. If control was held jointly with one or more other interests, state the fact in a footnote and name the other interests.
Definitions
1. See the Uniform System of Accounts for a definition of control.
2. Direct control is that which is exercised without interposition of an intermediary,
3. Indirect control is that which is exercised by the interposition of an intermediary which exercises direct control.
4. Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where the
voting control is equally divided between two holders, or each party holds a veto power over the other. Joint control may exist by
mutual agreement or understanding between two or more parties who together have control within the meaning of the definition of
control in the Uniform System of Accounts, regardless of the relative voting rights of each party.
Line Name of Company Controlled Kind of Business Percent Voting Footnote
No,Stock Owned Ref.
(a)(b)(c)(d)
Direct Control
Idaho Energy Resources Company Coal mining and mineral 100%
development
FERC FORM NO.1 (ED. 12-96)Page 103
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2006/04
(2) Ei A Resubmission 04/18/2007
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 Iitie Name Of umcer S,!\ary
No,for Year
(a)(b)(c)
President and Chief Executive Officer J. laMont Keen 450,000
Sr Vice President, Administrative Services & CFO Darrel T. Anderson 280,000
Sr Vice President, Power Supply James C. Miller 280 000
Sr Vice President, General Counsel and Secretary Thomas Saldin 265,000
Sr Vice President, Delivery Dan Minor 250,000
Vice President, Regulatory Affairs Ric Gale 200 00014 i
, ,
Dennis Gribble 178 00016 A. Bryan Kearney 000
Vice President, Human Resources Luci McDonald 175 000
Vice President, Public Affairs Greg Panter 175,000
Steven R. Keen 210,000
Vice President and Chief Risk Officer Lori Smith 170 000
Vice President, Engineering and Operations Lisa Grow 150,000
Vice President, Customer Service and Regional Ops Warren Kline 150,000
Naomi Crafton-Shankel 135 000
FERC FORM NO.1 (ED. 12-96)Page 104
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
FOOTNOTE DATA
ISchedule Page: 104 Line No.14 Column:
Appointed VP and Chief Information Officer June 1, 2006.
Relinquished Vice President and Treasurer June 1 , 2006.
ISchedule Page: 104 Line No.16 Column:
Resigned as Vice President and Chief Information Officer June 1, 2006.
ISchedule Page: 104 Line No.22 Column:
Appointed Vice President and Treasurer June 1, 2006.
Also President of IDACORP Financial Services, appointed September 8 , 1998.
ISchedule Page: 104 Line No.: 30 Column:
Appointed to newly created position September 21, 2006
Relinquished Director of Audit Services September 21, 2006.
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 2006/04(2) DA Resubmission 04/18/2007
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,
Name (an!1 :ritle) 01 ulrector J-'nnclpal tjuslness Address(a)(b)
Rotchford L. Barker O. Box 2080, Cody, Wyoming 82414
Christine King AMI Semiconductor, Inc.
2300 Buckskin Rd M/S #3, Pocatello,Idaho 83201
Jack K. Lemley Lemley & Associates, Inc.
604 N. 16th, Boise, Idaho 83702
Gary Michael'"O. Box 1718, Boise, Idaho 83701
Jon H. Miller O. Box 1557, Boise, Idaho 83701
Peter S. O'Neill'"100 N. 9th SI., Suite 200, Boise, Idaho 83702
Jan B. Packwood 900 W, Bogus View Drive, Eagle, Idaho 83616
J. laMont Keen, President and Chief Executive Officer Idaho Power Company, 1221 W. Idaho Street,
O. Box 70, Boise, Idaho 83707-0070
Richard G, Reiten Pacwest Center, 1211 SW Fifth Ave., Suite 1600
Portland, Oregon 97204
Joan Smith 2309 S.W. First Avenue, No. 1141 , Portland, Oregon 97201
Robert A. Tinstman ...4433 W. Ouail Point Court, Boise, Idaho 83703
Thomas Wilford Alscott Inc, P.O. Box 70001 , Boise, Idaho 83701
FERC FORM NO.1 (ED. 12-95)Page 105
This Page Intentionally Left Blank
Name of Respondent
Idaho Power Company
Date of Report
04/18/2007
YearlPeriod of Report
End of 2006/Q4
This Report Is:(1) ~ An Original(2) D A Resubmission
1M aRTANT CHANGES DURING THE QUARTERNEAR
Give particulars (details) concerning the matters indicated below. Make the statements explicit and precise, and number them in
accordance with the inquiries. Each inquiry should be answered. Enter "none
" "
not applicable," or "NA" where applicable. If
information which answers an inquiry is given elsewhere in the report, make a reference to the schedule in which it appears.
1. Changes in and important additions to franchise rights: Describe the actual consideration given therefore and state from whom the
franchise rights were acquired. If acquired without the payment of consideration, state that fact.
2. Acquisition of ownership in other companies by reorganization, merger, or consolidation with other companies: Give names of
companies involved, particulars concerning the transactions, name of the Commission authorizing the transaction, and reference to
Commission authorization.
3. Purchase or sale of an operating unit or system: Give a brief description of the property, and of the transactions relating thereto,
and reference to Commission authorization, if any was required. Give date journal entries called for by the Uniform System of Accounts
were submitted to the Commission.
4. Important leaseholds (other than leaseholds for natural gas lands) that have been acquired or given, assigned or surrendered: Give
effective dates, lengths of terms, names of parties, rents, and other condition. State name of Commission authorizing lease and give
reference to such authorization.
5. Important extension or reduction of transmission or distribution system: State territory added or relinquished and date operations
began or ceased and give reference to Commission authorization, if any was required. State also the approximate number of
customers added or lost and approximate annual revenues of each class of service. Each natural gas company must also state major
new continuing sources of gas made available to it from purchases, development, purchase contract or otherwise, giving location and
approximate total gas volumes available, period of contracts, and other parties to any such arrangements, etc.
6. Obligations incurred as a result of issuance of securities or assumption of liabilities or guarantees including issuance of short-term
debt and commercial paper having a maturity of one year or less. Give reference to FERC or State Commission authorization, as
appropriate, and the amount of obligation or guarantee.
7. Changes in articles of incorporation or amendments to charter: Explain the nature and purpose of such changes or amendments.
8. State the estimated annual effect and nature of any important wage scale changes during the year.
9. State briefly the status of any materially important legal proceedings pending at the end of the year, and the results of any such
proceedings culminated during the year.
10. Describe briefly any materially important transactions of the respondent not disclosed elsewhere in this report in which an officer
director, security holder reported on Page 106, voting trustee, associated company or known associate of any of these persons was a
party or in which any such person had a material interest.
11. (Reserved.
12. If the important changes during the year relating to the respondent company appearing in the annual report to stockholders are
applicable in every respect and furnish the data required by Instructions 1 to 11 above, such notes may be included on this page.
13. Describe fully any changes in officers, directors, major security holders and voting powers of the respondent that may have
occurred during the reporting period.
14. In the event that the respondent participates in a cash management program(s) and its proprietary capital ratio is less than 30
percent please describe the significant events or transactions causing the proprietary capital ratio to be less than 30 percent, and the
extent to which the respondent has amounts loaned or money advanced to its parent, subsidiary, or affiliated companies through a
cash management program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio.
PAGE 108 INTENTIONALLY LEFT BLANK
SEE PAGE 109 FOR REQUIRED INFORMATION.
FERC FORM NO.1 (ED. 12-96)Page 108
Name of Respondent This Report is:Date of Report YearlPeriod of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
IMPORTANT CHANGES DURING THE OUARTER/YEAR (Continued)
1. Relicensing costs closed to accunt 302 - $2,667,162 for Mid Snake Power Plant-Idaho.
2, None
3, None
4, None
5. New Transmission Lines:
Chestnut to Happy Valley - 138Kvline #471 2.78 miles
Caldwell to willis - 138Kv line #474 5.67 miles
Additions to existing Lines:
Nampa Tap 230 Kv line #711 3.12 miles
Line 459 138Kv - Replaces portion of Line #202, 69Kv 16 miles
DistributionwillisCartwright
Happy ValleyEckert
Stations:
6. Issued $116,300,000 variable rate Pollution Control Revenue Bonds, maturing July 15,
2026. Commission authorization for IPUC IPC-E-06-14, OPUC UF4227 WPSC 20005-29-ES-06.
For additional information see footnote for pages 256.1 line #8.
7. None
8. On December 29, 2006 a general wage increase of 3.0%.
9. See pages 123.to 123.
10. None
11. None
12. None
13. Refer to pages 104 & 105 for changes in officers and directors. There were a number
of changes in Major Security Holders in 2006. Top ten institutional shareholders list
saw one change from 3rd quarter to 4th quarter. In 4th quarter Fisher Investments
replaced pzena Investment Management on the top ten list.
14. None
I FERC FORM NO.1 (ED. 12-96)Page 109.
Name of Respondent
Idaho Power Company
Line
No.Title of Account
(a)
UTILITY PLANT
Ref.
Page No.
(b)
Year/Period of Report
End of
Prior Year
End Balance
12/31
(d)
2006/04
--~----'-
586,503,680
210,094 019
796,597 699
1,406,209,952
390,387,747
390,387,747
36,762 206
3,479,972 995
149,814 313
629,787,308
364 640 116
265,147 192
265,147 192
025,159
27,337 666
72,797 583
583,874
510 000
42,750
48,687 442
522,187
830,007
860,636
833,238
637,084
11,494 190
28,705,792
This Report Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) D A Resubmission 04/18/2007
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Current Year
End of Ouarter/Year
Balance
(c)
200-201
200-201
UtilityPlant(101-106 114)
Construction Work in Progress (107)
TOTAL Utility Plant (Enter Total of lines 2 and 3)
(Less) Accum. Provo for Depr. Amort. Depl. (108, 110, 111 , 115)
Net Utility Plant (Enter Total of line 4 less 5)
Nuclear Fuel in Process of Ref" Conv.Enrich., and Fab. (120.
Nuclear Fuel Materials and Assemblies-Stock Account (120.
Nuclear Fuel Assemblies in Reactor (120.
Spent Nuclear Fuel (120.
Nuclear Fuel Under Capital Leases (120.
(Less) Accum. Provo for Amort. of Nucl. Fuel Assemblies (120.
Net Nuclear Fuel (Enter Total of lines 7-11 less 12)
Net Utility Plant (Enter Total of lines 6 and 13)
Utility Plant Adjustments (116)
Gas Stored Underground - Noncurrent (117)
OTHER PROPERTY AND INVESTMENTS
Nonutility Property (121)
(Less) Accum. Provo for Depr. and Amort. (122)
Investments in Associated Companies (123)
Investment in Subsidiary Companies (123.
(For Cost of Account 123., See Footnote Page 224, line 42)
Noncurrent Portion of Allowances
Other Investments (124)
Sinking Funds (125)
Depreciation Fund (126)
Amortization Fund - Federal (127)
Other Special Funds (128)
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)
CURRENT AND ACCRUED ASSETS
Cash and Working Funds (Non-major Only) (130)
Cash (131)
Special Deposits (132-134)
Working Fund (135)
Temporary Cash Investments (136)
Notes Receivable (141)
Customer Accounts Receivable (142)
Other Accounts Receivable (143)
(Less) Accum. Provo for Uncollectible Acct.-Credit (144)
Notes Receivable from Associated Companies (145)
Accounts Receivable from Assoc. Companies (146)
Fuel Stock (151)
Fuel Stock Expenses Undistributed (152)
Residuals (Elec) and Extracted Products (153)
Plant Materials and Operating Supplies (154)
Merchandise (155)
Other Materials and Supplies (156)
Nuclear Materials Held for Sale (157)
Allowances (158.1 and 158.
200-201
202-203
202-203
122
224-225
228-229
227
227
227
227
227
227
202-203/227
228-229
FERC FORM NO.1 (REV. 12-03)Page 110
Name of Respondent This Report Is:Date of Report Year/Period of Report
Idaho Power Company (1)(ZJ An Original (Mo, Oa, Yr)
(2)A Resubmission 04/18/2007 End of 2006/04
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)Continued)
Line Current Year Prior Year
Ref.End of OuarterNear End BalanceNo.Title of Account Page No.Balance 12/31
(a)(b)(c)(d)
(Less) Noncurrent Portion of Allowances
Stores Expense Undistributed (163)227 316 011 745,428
Gas Stored Underground - Current (164.
Liquefied Natural Gas Stored and Held for Processing (164.164.
Prepayments (165)952 014 532,437
Advances for Gas (166-167)
Interest and Dividends Receivable (171)28,192
Rents Receivable (172)
Accrued Utility Revenues (173)365 181 905,298
Miscellaneous Current and Accrued Assets (174)
Derivative Instrument Assets (175)244 432
(Less) Long-Term Portion of Derivative Instrument Assets (175)
Derivative Instrument Assets - Hedges (176)
(Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176
Total Current and Accrued Assets (Lines 34 through 66)176,687 367 215,496,511
DEFERRED DEBITS
Unamortized Debt Expenses (181)786,336 128 248
Extraordinary Property Losses (182.230
Unrecovered Plant and Regulatory Study Costs (182.230
Other Regulatory Assets (182.232 378,846,883 418,241 190
Prelim, Survey and Investigation Charges (Electric) (183)416 116 187 483
Preliminary Natural Gas Survey and Investigation Charges 183.
Other Preliminary Survey and Investigation Charges (183.
Clearing Accounts (184)361,477 300,821
Temporary Facilities (185)
Miscellaneous Deferred Debits (186)233 124 388,934 087,452
Def. Losses from Disposition of Utility PIt. (187)
Research, Devel. and Demonstration Expend. (188)352-353
Unamortized Loss on Reaquired Debt (189)760,653 032 339
Accumulated Deferred Income Taxes (190)234 117 138,886 103,660 136
Unrecovered Purchased Gas Costs (191)
Total Deferred Debits (lines 69 through 83)645,699,285 629,637 669
TOTAL ASSETS (lines 14-16, 32, 67, and 84)293,709,187 183 078 955
FERC FORM NO.1 (REV. 12-03)Page 111
Name of Respondent This Report is:Date of Report Year/Period of Report
Idaho Power Company (1)(XJ An Original (mo, dB, yr)
(2)A Rresubmission 04/18/2007 end of 2006/04
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
Line Current Year Prior Year
No,Ref.End of OuarterlYear End Balance
Title of Account Page No.Balance 12/31
(a)(b)(c)(d)
PROPRIETARY CAPITAL
Common Stock Issued (201)250-251 877 030 877 030
Preferred Stock Issued (204)250-251
Capital Stock Subscribed (202, 205)252
Stock Liability for Conversion (203, 206)252
Premium on Capital Stock (207)252 530 757 435 483,707 552
Other Paid-In Capital (208-211)253
Installments Received on Capital Stock (212)252
(Less) Discount on Capital Stock (213)254
(Less) Capital Stock Expense (214)254 096,925 096,925
Retained Earnings (215, 215., 216)118-119 354 624 872 321 453,283
Unappropriated Undistributed Subsidiary Earnings (216,118-119 49,451 103 802,850
(Less) Reaquired Capital Stock (217)250-251
Noncorporate Proprietorship (Non-major only) (218)
Accumulated Other Comprehensive Income (219)122(a)(b)737 12~425,324
Total Proprietary Capital (lines 2 through 15)024,876,392 937 318,466
LONG-TERM DEBT
Bonds (221)256-257 955,460,000 955,460,000
(Less) Reaquired Bonds (222)256-257
Advances from Associated Companies (223)256-257
Other Long-Term Debt (224)256-257 31,585,000 585,000
Unamortized Premium on Long-Term Debt (225)
(Less) Unamortized Discount on Long-Term Debt-Debit (226)097 272 325,109
Total Long-Term Debt (lines 18 through 23)983 947 728 983 719,891
OTHER NONCURRENT LIABILITIES
Obligations Under Capital Leases - Noncurrent (227)
Accumulated Provision for Property Insurance (228.
Accumulated Provision for Injuries and Damages (228.665 706 191,411
Accumulated Provision for Pensions and Benefits (228.100,944 15/361 444
Accumulated Miscellaneous Operating Provisions (228.4)
Accumulated Provision for Rate Refunds (229)227,492
Long-Term Portion of Derivative Instrument Liabilities
Long-Term Portion of Derivative Instrument Liabilities - Hedges
Asset Retirement Obligations (230)911 220 10,079 335
Total Other Noncurrent Liabilities (lines 26 through 34)115,748,575 632,190
CURRENT AND ACCRUED LIABILITIES
Notes Payable (231)52,200,000
Accounts Payable (232)697 801 435,649
Notes Payable to Associated Companies (233)101,115
Accounts Payable to Associated Companies (234)110,966 152 888
Customer Deposits (235)125,192 103,299
Taxes Accrued (236)262-263 225,75/183 706
Interest Accrued (237)12,324,003 104,406
Dividends Declared (238)
Matured Long-Term Debt (239)
FERC FORM NO.1 (rev. 12-03) Page 112
Name of Respondent This Report is:Date of Report Year/Period of Report
Idaho Power Company (1)IX)An Original (mo, dB, yr)
(2)A Rresubmission 04/18/2007 end of 2006/Q4
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDIT~ntinued)
Line Current Year Prior Year
No.Ref.End of QuarterlYear End Balance
Title of Account Page No.Balance 12/31
(a)(b)(c)(d)
Matured Interest (240)
Tax Collections Payable (241)015 825 997 689
Miscellaneous Current and Accrued Liabilities (242)779 126 834,534
Obligations Under Capital Leases-Current (243)
Derivative Instrument Liabilities (244)462 637
(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)215 941,307 194 913 286
DEFERRED CREDITS
Customer Advances for Construction (252)085 511 427,988
Accumulated Deferred Investment Tax Credits (255)266.267 69,113,142 68,786,273
Deferred Gains from Disposition of Utility Plant (256)
Other Deferred Credits (253)269 25,567 500 672,479
Other Regulatory Liabilities (254)278 225,731 042 276 567 305
Unamortized Gain on Reaquired Debt (257)
Accum. Deferred Income Taxes-Accel. Amort.(281)272-277
Accum. Deferred Income Taxes-Other Property (282)573,951 058 586 260,338
Accum. Deferred Income Taxes-Other (283)32,746 932 780 739
Total Deferred Credits (lines 56 through 64)953,195,185 042,495,122
TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65)293,709,181 183 078 955
FERC FORM NO.1 (rev. 12-03)Page 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 2006/Q4(2) n A Resubmission 04/18/2007
STATEMENT OF INCOME
Quarterly
1. Enter in column (d) the balance for the reporting quarter and in column (e) the balance for the same three month period for the prior year.
2. Report in column (f) the quarter to date amounts for electric utility function; in column (h) the quarter to date amounts for gas utility, and in 0) the
quarter to date amounts for other utility function for the current year quarter.
3. Report in column (9) the quarter to date amounts for electric utility function; in column (i) the quarter to date amounts for gas utility, and in (k) the
quarter to date amounts for other utility function for the prior year quarter.
4. If additional columns are needed place them in a footnote.
Annual or Quarterly if applicable
5. Do not report fourth quarter data in columns (e) and (f)
6. Report amounts for accounts 412 and 413, Revenues and Expenses from Utility Plant Leased to Others, in another utility columnin a similar manner to
a utility department. Spread the amount(s) over lines 2 thru 26 as appropriate. Include these amounts in columns (c) and (d) totals.
7. Report amounts in account 414, Other Utility Operating Income, in the same manner as accounts 412 and 413 above.
8. Report data for lines 8, 10 and 11 for Natural Gas companies using accounts 404.404,404,407.1 and 407.
Line Total Total Current 3 Months Prior 3 Months
No.Current Year to Prior Year to Ended Ended
(Ref,Date Balance for Date Balance for Quarterly Only Quarterly Only
Title of Account Page No.QuarterlYear QuarterlYear No 4th Quarter No 4th Quarter
(a)(b)(c)(d)(e)
1 UTILITY OPERATING INCOME
2 Operating Revenues (400)300-301 930,618,611 849,075,951 183 552,357 228 581,120
3 Operating Expenses
4 Operation Expenses (401)320-323 566,729,405 505 272,123 117 304,233 125,858 524
5 Maintenance Expenses (402)320-323 64,719,689 538,848 13,889,728 15,396 567
6 Depreciation Expense (403)336-337 803,410 933,330 082027 22,847 069
7 Depreciation Expense for Asset Retirement Costs (403.336-337
8 Amort. & Depl. of Utility Plant (404-405)336-337 089,661 574 137 277 290 2,447,409
9 Amort. of Utility Plant Acq, Adj, (406)336-337 22,723 22,723 681 681
Amort, Property Losses, Unrecov Plant and Regulatory Study Costs (407)
Amort. of Conversion Expenses (407)
Regulatory Debits (407,391 371 191,442 312 213,167
(Less) Regulatory Credits (407.820,743
Taxes Other Than Income Taxes (408,262-263 661 413 20,856,185 704436 056,843
Income Taxes - Federal (409,262-263 52,572,378 853,588 210 395 822,632
- Other (409,262-263 194,257 931,316 1,454 076 528,126
Provision for Deferred Income Taxes (410,234, 272-277 231 898 279,913 161,474 23,282,389
(Less) Provision for Deferred Income Taxes-Cr, (411.234, 272-277 646,675 648,054 938,756 357,162
InvestmentTax Credit Adj. - Net (411.266 326,869 950 116 287 244 108,747
(Less) Gains from Disp. of Utility Plant (411,46,144
Losses from Disp. of Utility Plant (411.7)591
(Less) Gains from Disposition of Allowances (411,257 817 173,359 22,458
Losses from Disposition of Allowances (411.
Accretion Expense (411.10)
TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24)801,283 196 738 716,710 160,102 836 190,476 092
Net Util Oper Inc (Enter Tot line 2 less 25) Carry to Pg117 line 27 129 335,415 110,359,241 449 521 38,105,028
FERC FORM NO. 1/3-Q (REV. 02.04)Page 114
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2006/04(2) n A Resubmission 04/18/2007
STATEMENT OF INCOME FOR THE YEAR (Continued)
9. Use page 122 for important notes regarding the statement of income for any account thereof,
10. Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a material amount may need to be
made to the utility's customers or which may result in material refund to the utility with respect to power or gas purchases. State for each year effected
the gross revenues or costs to which the contingency relates and the tax effects together with an explanation of the major factors which affect the rights
of the utility to retain such revenues or recover amounts paid with respect to power or gas purchases.
11 Give concise explanations concerning significant amounts of any refunds made or received during the year resulting from settlement of any rate
proceeding affecting revenues received or costs incurred for power or gas purches, and a summary of the adjustments made to balance sheet, income
and expense accounts.
12. If any notes appearing in the report to stokholders are applicable to the Statement of Income, such notes may be included at page 122.
13. Enter on page 122 a concise explanation of only those changes in accounting methods made during the year which had an effect on net income,
including the basis of allocations and apportionments from those used in the preceding year. Also, give the appropriate dollar effect of such changes.
14. Explain in a footnote if the previous year s/quarter's figures are different from that reported in prior reports,
15. If the columns are insufficient for reporting additional utility departments, supply the appropriate account titles report the information in a footnote to
this schedule.
ELECTRIC UTILITY GAS UTILITY OTHER UTILITY
Current Year to Date Previous Year to Date Current Year to Date Previous Year to Date Current Year to Date Previous Year to Date Line
(in dollars)(in dollars)(in dollars)(in dollars)(in dollars)(in dollars)No.
(g)
(h) (i)
(j)
(k) (I)
566,729,405 505 272 123
64,719 689 538 848
803,410 933,330
089,661 574,137
22,723 22,723
10,391 371 191 442
820,743
661,413 856,185
572 378 64,853,588
194,257 931,316
231 898 279,913
646,675 58,648,054
326,869 950,116
144
591
257,817 173,359
801 283,196 738,716,710
129,335 415 110,359 241
FERC FORM NO.1 (ED. 12-96)Page 115
This Page Intentionally Left Blank
Name of Respondent
Idaho Power Company
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/18/2007
STATEMENT OF INCOME FOR THE YEAR (continued)
TOTAL
Year/Period of Report
End of 2006/04
Title of Account
(a)
(Ref.
Page No.
(b)
Current Year
(c)
Previous Year
(d)
Prior 3 Months
Ended
Quarterly Only
No 4th Quarter
(f)
Line
No.
27 Net Utility Operating Income (Carried forward from page 114)
28 Other Income and Deductions
29 Other Income
30 Nonutilty Operating Income
31 Revenues From Merchandising, Jobbing and Contract Work (415)
32 (Less) Costs and Exp. of Merchandising, Job, & Contract Work (416)
33 Revenues From Nonutility Operations (417)
34 (Less) Expenses of Nonutility Operations (417,
35 Nonoperating Rental Income (418)
36 Equity in Earnings of Subsidiary Companies (418,
37 Interest and Dividend Income (419)
38 Allowance for Other Funds Used During Construction (419,
39 Miscellaneous Nonoperating Income (421)
40 Gain on Disposition of Property (421,
41 TOTAL Other Income (Enter Total of lines 31 thru 40)
42 Other Income Deductions
43 Loss on Disposition of Property (421.
44 Miscellaneous Amortization (425)
45 Donations (426.1)
46 Life Insurance (426.
47 Penalties (426,
48 Exp. for Certain Civic, Political & Related Activities (426.4)
49 Other Deductions (426.
50 TOTAL Other Income Deductions (Total of lines 43 thru 49)
51 Taxes Applic. to Other Income and Deductions
52 Taxes Other Than Income Taxes (408,
53 Income Taxes-Federal (409,
54 Income Taxes-Other (409.
55 Provision for Deferred Inc. Taxes (410.
56 (Less) Provision for Deferred Income Taxes-Cr. (411.
57 InvestmentTax Credit Adj,Net (411,
58 (Less) Investment Tax Credits (420)
59 TOTAL Taxes on Other Income and Deductions (Total of lines 52-58)
60 Net Other Income and Deductions (Total of lines 41 50,59)
61 Interest Charges
62 Interest on Long-Term Debt (427)
63 Amort. of Debt Disc, and Expense (428)
64 Amortization of Loss on Reaquired Debt (428.1)
65 (Less) Amort, of Premium on Debt-Credit (429)
66 (Less) Amortization of Gain on Reaquired Debt-Credit (429,
67 Interest on Debt to Assoc. Companies (430)
68 Other Interest Expense (431)
69 (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432)
70 Net Interest Charges (Total of lines 62 thru 69)
71 Income Before Extraordinary Items (Total of lines 27 60 and 70)
72 Extraordinary Items
73 Extraordinary Income (434)
74 (Less) Extraordinary Deductions (435)
75 Net Extraordinary Items (Total of line 73 less line 74)
76 Income Taxes-Federal and Other (409.
77 Extraordinary Items After Taxes (line 75 less line 76)
78 Net Income (Total of line 71 and 77)
129,335,415 110,359,241 449,521 38,105,028r-----
--- ---,---..--- -~--
273,822 986,557 471 178 543 363
001 750 553 933 417 929 493,272
117 924 125,826 22,623 46,669
374 582 285,293 143 760 103 641
318 036 991 034
119 648,253 874 042 529 166 101 508
108 574 192 922 440,849 750,571
092 152 950,151 271 044 711 617
189,612 069,732 341 555 200,886
738 521
056,425 386,489 529 717 753,667
r _..
..._---~
106 328
340
340 573 834 533,964 199,967 142 885
547 211 508 334,074 180 794
307
267 336 351,382 257085 332,885
954,457 637 585 184 397 319 048
250 723 724 767 307 375 975 612
262-263 742 37,228 611 375
262-263 206 660 042 859 504 251 238 911
262-263 071 244,977 029 294
234, 272-277 234,191 213,137 329,507 339,566
234, 272-277 955 602 817 329 494,429 473 869
BOO 25B 720 872 742,591 322 545
20,605,960 940,850 964,933 100,600
,..- -, ,---- -,.....
53,744 453 53,339,531 13,265,582 13,547 882
1 ,023500 262,733 250,756 257 590
184936 1 ,160 697 314,413 290 174
340 415 386,020 061
340 002 342 103 151 1 ,91 8,522 715 544
026,460 790,871 242 226 998 431
012 186 54,461 261 507 047 13,816,820
929 189 838,830 16,907,407 30,388 808
----,--,--
262-263
93,929,189 838,830 907,407 30,388 808
FERC FORM NO. 1/3-Q (REV. 02-04)Page 117
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2006/Q4
This ~rt Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) DA Resubmission 04/18/2007
STATEMENT OF RETAINED EARNINGS
1. Do not report Lines 49-53 on the quarterly version.
2. Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriated
undistributed subsidiary earnings for the year.
3. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436
- 439 inclusive). Show the contra primary account affected in column (b)
4. State the purpose and amount of each reservation or appropriation of retained earnings.
5. List first account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow
by credit, then debit items in that order.
6. Show dividends for each class and series of capital stock.
7. Show separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Earnings.
8. Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be
recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated.
9. If any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.
Line
No,
Item
(a)
UNAPPROPRIATED RETAINED EARNINGS (Account 216)
1 Balance-Beginning of Period
2 Changes
3 Adjustments to Retained Eamings (Account 439)
9 TOTAL Credits to Retained Earnings (Acct. 439)
15 TOTAL Debits to Retained Earnings (Acct. 439)
16 Balance Transferred from Income (Account 433 less Account 418.
17 Appropriations of Retained Earnings (Acct. 436)
22 TOTAL Appropriations of Retained Earnings (Acct. 436)
23 Dividends Declared-Preferred Stock (Account 437)
29 TOTAL Dividends Declared-Preferred Stock (Acct. 437)
30 Dividends Declared-Common Stock (Account 438)
31 Common Stock $2.50 par Value
36 TOTAL Dividends Declared-Common Stock (Acct. 438)
37 Transfers from Acct 216,, Unapprop. Undistrib. Subsidiary Earnings
38 Balance - End of Period (Total 1 16,22,37)
APPROPRIATED RETAINED EARNINGS (Account 215)
Current Previous
QuarterlYear QuarterlY ear
Contra Primary Year to Date Year to Date
Account Affected Balance Balance
(b)(c)(d)
8IIEi.mI!ii1
I du
' -----
, "__d--,
__~.---
280,936 964 788
----~ ~------- -------'-- ------
____u
,,"",--,----"--'" -------
109,347 ( 50,689,544)
109,347 ( 50 689,544)
353 080,906 319,909,317
'--==
1--===~n ..,
'-'-=-=
FERC FORM NO. 1/3-Q (REV. 02-04)Page 118
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2006/Q4
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) A Resubmission 04/18/2007
STATEMENT OF RETAINED EARNINGS
1. Do not report Lines 49-53 on the quarterly version.
2. Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriated
undistributed subsidiary earnings for the year.
3. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436
- 439 inclusive). Show the contra primary account affected in column (b)
4. State the purpose and amount of each reservation or appropriation of retained earnings.
5. List first account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow
by credit, then debit items in that order.
6. Show dividends for each class and series of capital stock.
7. Show separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Earnings.
8. Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be
recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated.
9. If any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.
Line
No.
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., 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)
Item
(a)
Current Previous
QuarterlY ear QuarterlY ear
Contra Primary Year to Date Year to Date
Account Affected Balance Balance
(b)(c)(d)
r~--
~ ---..,-,...-,
543,966
1 ,543,966
354 624 872
543,966
543,966
321,453,283r---u- -
------'----~-'-'--
39,802 850
648,253
30,928,808
874,042
49,451 103 802,850
FERC FORM NO. 1/3-Q (REV. 02-04)Page 119
Name of Respondent
Idaho Power Company
This ~ort Is:(1) ~An Original
(2) A Resubmission
STATEMENT OF CASH FLOWS
Date of Report
(Mo, Da, Yr)
04/18/2007
Year/Period of Report
End of 2006/Q4
(1) Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items as
investments, fixed assets, intangibles, etc,
(2) Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and CashEquivalents at End of Period" with related amounts on the Balance Sheet.
(3) Operating Activities - Other: Include gains and losses pertaining to operating activities only, Gains and losses pertaining to investing and financing activities should be reported
in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid,
(4) Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes to
the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconciliation of the
dollar amount of leases capitalized with the plant cost.
Line
No,
Description (See Instruction No.1 for Explanation of Codes)Current Year to Date
QuarterlY ear
(b)
Previous Year to Date
QuarterlY ear
(c)(a)
1 Net Cash Flow from Operating Activities:
2 Net Income (Line 78(c) on page 117)
3 Noncash Charges (Credits) to Income:
4 Depreciation and Depletion
5 Amortization of (see note)
8 Deferred Income Taxes (Net)
9 Investment Tax Credit Adjustment (Net)
10 Net (Increase) Decrease in Receivables
11 Net (Increase) Decrease in Inventory
12 Net (Increase) Decrease in Allowances Inventory
13 Net Increase (Decrease) in Payables and Accrued Expenses
14 Net (Increase) Decrease in Other Regulatory Assets
15 Net Increase (Decrease) in Other Regulatory Liabilities
16 (Less) Allowance for Other Funds Used During Construction
17 (Less) Undistributed Earnings from Subsidiary Companies
18 Other (provide details in footnote): (see note)
22 Net Cash Provided by (Used in) Operating Activities (Total 2 thru 21)
24 Cash Flows from Investment Activities:
25 Construction and Acquisition of Plant (including land):
26 Gross Additions to Utility Plant (less nuclear fuel)
27 Gross Additions to Nuclear Fuel
28 Gross Additions to Common Utility Plant
29 Gross Additions to Nonutility Plant
30 (Less) Allowance for Other Funds Used During Construction
31 Other (provide details in footnote): Sale of Emission Allowance
34 Cash Outflows for Plant (Total of lines 26 thru 33)
599,987
326,869
814 073
12,306,638
972,335
950,117
885,165
430,070
~~Ii~~~~l~~t s~~~lfQj;r:r; ~1,
24,376,845
40,201 156
57,333,724
092,152
648 253
34,355,903
112 357
10,837,689
950,151
874,042
667,692
134 366 446 176 665,211
36 Acquisition of Other Noncurrent Assets (d)
37 Proceeds from Disposal of Noncurrent Assets (d)
39 Investments in and Advances to Assoc. and Subsidiary Companies
40 Contributions and Advances from Assoc. and Subsidiary Companies
41 Disposition of Investments in (and Advances to)
42 Associated and Subsidiary Companies
44 Purchase of Investment Securities (a)
45 Proceeds from Sales of Investment Securities (a)
~,-, ._-~-"-~--"---
217 813 466 183,073,929
200 675
026,460 790,871
322 948 757,625
210,516 978 115 307 850
507
919
r----~-
~--
978 726
777 593
333,932
120,025 599
FERC FORM NO.1 (ED. 12-96)Page 120
Name of Respondent
Idaho Power Company
This ~ort Is:(1) ~An Original(2) A Resubmission
STATEMENT OF CASH FLOWS
Date of Report
(Mo, Da, Yr)
04/18/2007
Year/Period of Report
End of 2006/Q4
(1) Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items as
investments, fixed assets, intangibles, etc.
(2) Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and Cash
Equivalents at End of Period" with related amounts on the Balance Sheet.
(3) Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing activities should be reported
in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid.
(4) Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies, Provide a reconciliation of assets acquired with liabilities assumed in the Notes to
the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconciliation of the
dollar amount of leases capitalized with the plant cost.
(a)
Current Year to Date
QuarterlY ear
(b)
Previous Year to Date
QuarterlY ear
(c)
Line
No.
Description (See Instruction No.1 for Explanation of Codes)
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):
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):
66 Net Increase in Short-Term Debt (c)
67 Other (provide details in footnote):
68 Capital Infusion
70 Cash Provided by Outside Sources (Total 61 thru 69)
551 536 116,424
116 300 000 000 000
32,944,405
049,883
196,294 288 60,000,000
72 Payments for Retirement of:
73 Long-term Debt (b)
74 Preferred Stock
75 Common Stock
76 Other (provide details in footnote):
78 Net Decrease in Short-Term Debt (c)
80 Dividends on Preferred Stock
81 Dividends on Common Stock
82 Net Cash Provided by (Used in) Financing Activities
83 (Total of lines 70 thru 81)
85 Net Increase (Decrease) in Cash and Cash Equivalents
86 (Total of lines 22 57 and 83)
88 Cash and Cash Equivalents at Beginning of Period
90 Cash and Cash Equivalents at End of period
, -------- -..
--- r." --,-
----
116 300 000 000 000
445,891
368,593
109,346 -50,689,544
2,404 300 314 067
FERC FORM NO.1 (ED. 12-96)Page 121
This Page Intentionally Left Blank
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
FOOTNOTE DATA
ISchedule Page: 120 Line No.Column: b
Plant
Regulatory Assets
Unamortized Debt ExpenseUnamortized DiscountWater Rights
$ 9,066 939
193,160
130,563
227,837
042,009
Total
ISchedule Page: 120 Line No.
$14 660,508
Column: b
Other Non-cash Adj to Net Income
Asset Impairment
Unbilled Revenues
Gain on Sale of Assets
Other Current Liabilities
Other Long Term Assets
Other Long-Term Liabilities
133,562
046,713
540,117
(11,751,251)
(2,309,505)
332 238
10,996,966
Total
ISchedule Page: 120 Line No.
$ 9,988,840
Column: b
Other Long-Term assets
Other Long- Term Liabilities
$(3 057,669)
117,678
Total $(2,939,991)
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent
Idaho Power Company
Date of Report
04/18/2007
Year/Period of Report
End of 2006/04
This Report Is:
(1) (29 An Original(2) D A Resubmission
NOTES TO FINANCIAL STATEMENTS
1, Use the space below for important notes regarding the Balance Sheet, Statement of Income for the year, Statement of Retained
Earnings for the year, and Statement of Cash Flows, or any account thereof. Classify the notes according to each basic statement
providing a subheading for each statement except where a note is applicable to more than one statement.
2. Furnish particulars (details) as to any significant contingent assets or liabilities existing at end of year, including a brief explanation of
any action initiated by the Internal Revenue Service involving possible assessment of additional income taxes of material amount, or of
a claim for refund of income taxes of a material amount initiated by the utility. Give also a brief explanation of any dividends in arrears
on cumulative preferred stock.
3. For Account 116, Utility Plant Adjustments, explain the origin of such amount, debits and credits during the year, and plan of
disposition contemplated, giving references to Cormmission orders or other authorizations respecting classification of amounts as plant
adjustments and requirements as to disposition thereof.
4. Where Accounts 189, Unamortized Loss on Reacquired Debt, and 257, Unamortized Gain on Reacquired Debt, are not used, give
an explanation, providing the rate treatment given these items. See General Instruction 17 of the Uniform System of Accounts.
5. Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such
restrictions.
6. If the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders are
applicable and furnish the data required by instructions above and on pages 114-121 , such notes may be included herein.
7, For the 30 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 30 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 REOUIRED INFORMATION.
FERC FORM NO.1 (ED. 12-96)Page 122
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Nature of Business
Idaho Power Company (IPC), a wholly-owned subsidiary of IDACORP Inc., (IDACORP) is an electric utility with a service territory
covering approximately 24,000 square miles in southern Idaho and eastern Oregon. IPC is regulated by the 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.
Basis of Presentation
These financial statements were prepared in accordance with the accounting requirements of FERC as set forth in its applicable
Uniform System of Accounts and published accounting releases, which is a comprehensive basis of accounting other than generally
accepted accounting principles.
In December 2006, IPC adopted the recognition provisions of Statement of Financial Accounting Standards No. 158
, "
Employers
Accounting for defined Benefit Pension and Other Postretirement Plans - an amendment ofFASB Statements No. 87, 88, 106, and
132 (R)." This adoption resulted in a difference of generally accepted accounting principles (GAAP) and the accounting requirements
of FERc. Under GAAP, the reduction of the minimum pension liability is recorded directly to accumulated other comprehensive
income and under the accounting requirements of FERC, the reduction of the minimum pension liability is recorded through current
year comprehensive income.
Management Estimates
Management makes estimates and assumptions when preparing financial statements in conformity with accounting principles generally
accepted in the United States of America. These estimates and assumptions, including those related to rate regulation, benefit costs,
contingencies, litigation, asset impaiID1ent, income taxes, unbilled revenues and bad debt, affect the reported amounts of assets and
liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of
revenues and expenses during the reporting period. These estimates involve judgments with respect to, among other things, future
economic factors that are difficult to predict and are beyond management's control. As a result, actual results could differ from those
estimates.
System of Accounts
The accounting records of IPC conform to the Uniform System of Accounts prescribed by the FERC and adopted by the public utility
commissions of Idaho, Oregon and Wyoming.
Regulation of Utility Operations
IPC follows Statement of Financial Accounting Standards (SFAS) SFAS 71
, "
Accounting for the Effects of Certain Types of
Regulation, " and its financial statements reflect the effects of the different rate-making principles followed by the jurisdictions
regulating IPC. The application of SF AS 71 by IPC can result in IPC recording expenses in a period different than the period the
expense would be recorded by an unregulated enterprise. When this occurs, costs are deferred as regulatory assets on the balance sheet
and recorded as expenses in the periods when those same amounts are reflected in rates. Additionally, regulators can impose
regulatory liabilities upon a regulated company for amounts previously collected from customers and for amounts that are expected to
be refunded to customers.
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 or over-recovered portion , is then included in the calculation of the next year s PCA.
The effects of applying SFAS 71 are discussed in more detail in Note II
- "
Regulatory Matters.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand and highly liquid temporary investments with maturity dates at date of acquisition 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) X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmisslon 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
three months or less.
Derivative Financial Instruments
Financial instruments such as commodity futures, forwards, options and swaps are used to manage exposure to commodity price risk in
the electricity market. The objective of the risk management program is to mitigate the risk associated with the purchase and sale of
electricity and natural gas. The accounting for derivative financial instruments that are used to manage risk is in accordance with the
concepts established by SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," as amended.
Property, Plant and Equipment and Depreciation
The cost of utility plant in service represents the original cost of contracted services, direct labor and material, Allowance for Funds
Used During Construction (AFDC) and indirect charges for engineering, supervision and similar overhead items. Maintenance and
repairs of property and replacements and renewals of items determined to be less than units of property are expensed to operations.
Repair and maintenance costs associated with planned major maintenance are recorded as these costs are incurred. For utility property
replaced or renewed, the original cost plus removal cost less salvage is charged to accumulated provision for depreciation, while the
cost of related replacements and renewals is added to property, plant and equipment.
All utility plant in service is depreciated using the straight-line method at rates approved by regulatory authorities. Annual
depreciation provisions as a percent of average depreciable utility plant in service approximated 2.75 percent in 2006, and 2.91 percent
in 2005.
Long-lived assets are periodically reviewed for impairment when events or changes in circumstances indicate that the carrying amount
of an asset may not be recoverable as prescribed under SFAS 144 "Accounting for the Impairment or Disposal of Long-Lived Assets
SF AS 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.
Revenues
Operating revenues for IPC related to the sale of energy are generally recorded when service is rendered or energy is delivered to
customers. IPC accrues unbilled revenues for electric services delivered to customers but not yet billed at period-end. IPC collects
franchise fees and similar taxes related to energy consumption. These amounts are recorded as liabilities until paid to the taxing
authority. None of these collections are reported on the income statement as revenue or expense.
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'
weighted-average monthly AFDC rates for 2006 and 2005 were 7.6 percent and 7.4 percent, respectively. IPC's reductions to interest
expense for AFDC were $4 million for 2006 and $3 million for 2005. Other income included $6 million and $5 million of AFDC for
2006 and 2005, respectively.
Income Taxes
The liability method of computing deferred taxes is used on all temporary differences between the book and tax basis of assets and
liabilities and deferred tax assets and liabilities are adjusted for enacted changes in tax laws or rates. Consistent with orders and
directives of the Idaho Public Utilities Commission (IPUC), the regulatory authority having principal jurisdiction, 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
I FERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
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
Effective January 1,2006, IPC adopted SFAS No. 123 (revised 2004), "Share-Based Payment" (SFAS 123(R)) using the modified
prospective application method. SFAS l23(R) changes measurement, timing and disclosure rules relating to share-based payments,
requiring that the fair value of all share-based payments be expensed. The adoption of SFAS l23(R) did not have a material impact
IPC's financial statements for the year ended December 31, 2006.
IPC's Consolidated Statements of Income for the year ended December 31 , 2005 do not reflect any changes from the adoption of
SFAS I 23(R). In those years, stock based employee compensation was accounted for under the recognition and measurement
principles of Accounting Principles Board (APB) Opinion 25, "Accounting for Stock Issued to Employees," and related
interpretations.
The following table illustrates what net income and earnings per share would have been had the fair value recognition provisions of
SFAS 123 been applied to stock-based employee compensation in 2005 and 2004 (in thousands of dollars, except for per share
amounts):
IPC
Net income, as reported
Add: Stock-based employee compensation expense included in
reported net income, net of related tax effects
Deduct: Stock-based employee compensation expense determined
under fair value based method for all awards
net of related tax effects
Pro fonna net income
2005 2004
839 70,608
108 276
568 977
379 69,907
For purposes of these pro forma calculations, the estimated fair value of the options, restricted stock and performance shares is
amortized to expense over the vesting period. The fair value of the restricted stock and performance shares is the market price of the
stock on the date of grant. The fair value of an option award is estimated at the date of grant using a binomial option-pricing model.
Expense related to forfeited options is reversed in the period in which the forfeit occurs.
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 amounts related to pension plans. In 2006
IPC adopted SF AS 158 "Accounting for Pension and Postretirement Costs - an amendment ofFAS 87, 88, 106, and 132(R)" which
required the company to record additional amounts related to pension plans in other comprehensive income. SFAS 158 is discussed in
more detail in Note 9. Prior to December 2005, other comprehensive income included the additional minimum liability related to a
deferred compensation plan for certain senior management employees and directors. The following table presents IPC's accumulated
other comprehensive loss balance at December 31
Unrealized holding gains on securities
Defined benefit ension lans
Total
2006 2005
(thousands of dollars)311
(7,048)
737)
725
(6,150)
(3,425)
Other Accounting Policies
Debt discount, expense and premium are deferred and being amortized over the tenns of the respective debt issues.
IFERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Reclassifications
Certain items previously reported for years prior to 2006 have been reclassified to conform to the current year s presentation. Net
income and shareholders' equity were not affected by these reclassifications.
New Accounting Pronouncements
FIN 48: In June 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 48, "Accounting for
Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109" (FIN 48), to create a single model to address accounting
for uncertainty in tax positions. FIN 48 prescribes a minimum recognition threshold that a tax position is required to meet before being
recognized in a company s financial statements and also provides guidance on derecognition, measurement, classification, interest and
penalties, accounting in interim periods, disclosure, and transition. FIN 48 is effective for fiscal years beginning after December 15
2006.
IPC will adopt FIN 48 in the first quarter of 2007, as required. The cumulative effect of adopting FIN 48 will be recorded as an
adjustment to 2007 opening retained earnings. IPC has not yet completed its evaluation of the effects the adoption of FIN 48 will have
on its financial position or results of operations.
SFAS 157: In September 2006, the FASB issued SFAS 157, "Fair Value Measurements." SFAS 157 defines fair value, establishes a
framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value
measurements. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15,2007, and interim
periods within those fiscal years. IPC is currently evaluating the impact of adopting SFAS 157 on its financial statements.
SFAS 159: In February 2007, the FASB issued SFAS No. 159, "The Fair Value Option for Financial Assets and Financial Liabilities-
Including an Amendment ofFASB Statement No. 115" (SFAS 159). This standard permits an entity to choose to measure many
financial instruments and certain other items at fair value. Most of the provisions in SFAS 159 are elective; however, the amendment
to SF AS No. 115
, "
Accounting for Certain Investments in Debt and Equity Securities," applies to all entities with available-for-sale
and trading securities. The fair value option established by SFAS 159 permits all entities to choose to measure eligible items at fair
value at specified election dates. A business entity will report umealized gains and losses on items for which the fair value option has
been elected in earnings at each subsequent reporting date. The fair value option: (a) may be applied instrument by instrument, with a
few exceptions, such as investments otherwise accounted for by the equity method; (b) is irrevocable (unless a new election date
occurs); and (c) is applied only to entire instruments and not to portions of instruments. SFAS 159 is effective as of the beginning of
an entity's first fiscal year that begins after November 15,2007. Early adoption is permitted as of the beginning of the previous fiscal
year provided that the entity makes that choice in the first 120 days of that fiscal year and also elects to apply the provisions of SF
No. 157, IPC is currently evaluating the impact of SFAS 159.
2. INCOME TAXES:
A reconciliation between the statutory federal income tax rate and the effective tax rate is as follows:
2006 2005
(thousand of dollars)
Federal income tax expense at
35% statutory rate
Change in taxes resulting from:
Equity earnings of subsidiary companies
AFDC
Investment tax credits
Repair allowance
Removal costs
Pension accrual
Capitalized overhead costs
Tax accounting method change
IFERC FORM NO.1 (ED. 12-88)
$ 48,408 $39,861
377)
542)
(3,513)
(2,450)
(1,912)
902
940)
122
(3,106)
(2,709)
(3,295)
(1,750)
(1,490)
276
Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Settlement of prior years' tax returns
State income taxes, net of federal benefit
Depreciation
Other, net
Total income tax expense
199)
501
757
(378)
$ 44 379 $
(2)
847
603
816
051
Effective tax rate 32.36.
The items comprising income tax are as follows:
Income taxes cuITently payable (receivable):
Federal
State
Total
Income taxes defeITed:
Federal
State
Total
Investment tax credits:
DefeITed
Restored
Total
Total income taxe expense
2006 2005
(thousands of dollars)
$ 48 366 65,896
286 177
53,652 75,073
(9,960)(29,891)
360 (5,081)
(9,600)(34 972)
840 374
513)(3,424)
327 950
$ 44 379 051
Components of the net defeITed tax liability are as follows:
2006 2005
(thousands of dollars)
DefeITed tax assets:
Regulatory liabilities 825 $627
Advances for construction 212 881
DefeITed compensation 381 276
Emission allowances 12,175 380
Retirement benefits 26,392
Other 13,154 14,496
Total 117 139 103,660
DefeITed tax liabilities:
Property, plant and equipment 230,361 240,144
Regulatory assets 343,590 346,116
Conservation programs 4,437 705
PCA 384 17,410
Retirement benefits 18,055
Other 871 666
Total 606,698 610 041
Net defeITed tax liabilities 489,559 506,381
FERC FORM NO.ED. 12-Page 123,
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Status of Audit Proceedings
In March 2005, the Internal Revenue Service (IRS) began its examination of IDACORP's 2001-2003 tax years. On October 13 2006,
the IRS issued its examination report and assessment for those years. With the exception of IPC's capitalized overhead costs method,
discussed below, the IRS and IDACORP were able to settle all issues. The $1.6 million federal tax assessment for the settled issues
was paid in November 2006. Interest charges and state income taxes have been accrued and are expected to be paid during 2007.
Settlement of the agreed issues decreased 2006 income tax expense by $6.2 million at IPC as the assessed deficiency was less than
amounts previously accrued.
The IRS disallowed IPC's capitalized overhead cost method for uniform capitalization (the simplified service cost method) on the
basis that IPC's self-constructed assets were not produced on a "routine and repetitive" basis as defined by Rev. Rul. 2005-53. The
disallowance resulted in a federal tax assessment of $45 million. In November 2006 IDACORP filed a formal protest and request for
an appeals conference. Also in November 2006, IDACORP made a refundable deposit of the disputed tax with the IRS to stop the
accrual of interest. In December 2006, the IRS examination team filed its rebuttal to IDACORP's protest. In January 2007,
IDACORP was notified that its case has been assigned to the IRS Appeals Office. IDACORP cannot predict the timing or outcome of
this process, but believes that an adequate provision for income taxes and related interest charges has been made for this issue.
The simplified service cost method was also used for IPC's 2004 tax year. While 2004 is not currently under examination, it is likely
the IRS will take the same position for 2004 as it did for 2001-2003; however, it is not likely that this position will result in a federal
income tax assessment primarily due to the mitigating effect of accelerated tax depreciation.
On July 7 , 2006, the IRS issued its examination report for Bridger Coal Company s 2001-2003 tax years. Bridger Coal is a partnership
investment owned one-third by IPC. The audit resulted in net favorable adjustments to Bridger Coal's tax returns for those years. As a
result of the settlement, IPC was able to decrease 2006 income tax expense by $1.9 million.
In 2004, IPC settled federal income tax deficiencies for the years 1999 and 2000 related to its partnership investment in the Bridger
Coal Company. Applicable state tax return amendments were completed in 2004 and settled. Finalization of these examinations
resulted in deficiencies that were less than previously accrued, enabling IDACORP to decrease income tax expense by $1.7 million in
2004.
Capitalized overhead costs
Generally, section 263A of the Internal Revenue Code of 1986, as amended, requires the capitalization of all direct costs and indirect
costs, including mixed service costs, which directly benefit or are incurred by reason of the production of property by a taxpayer. The
simplified service cost method, a "safe harbor" method, is one of the methods provided by the section 263A treasury regulations for the
calculation of mixed service cost capitalization. IPC adopted the simplified service cost method for both the self-construction of utility
plant and production of electricity beginning with its 2001 federal income tax return,
On August 2 2005, the IRS and the Treasury Department issued guidance interpreting the meaning of "routine and repetitive" for
purposes of the simplified service cost and simplified production methods of the Internal Revenue Code section 263A uniform
capitalization rules. The guidance was issued in the form of a revenue ruling (Rev, Rul. 2005-53) which is effective for all open tax
years ending prior to August 2, 2005, and proposed and temporary regulations (the "Temporary Regulations ) which are effective for
tax years ending on or after August 2,2005. Both pieces of guidance take a more restrictive view of the definition of self-constructed
assets produced by a taxpayer on a "routine and repetitive" basis than did treasury regulations in effect at the time IPC changed to the
simplified service cost method.
For IPC, the simplified service cost method produced a current tax deduction for costs capitalized to electricity production that are
capitalized into fixed assets for financial accounting purposes. Deferred income tax expense had not been provided for this deduction
because the prescribed regulatory tax accounting treatment does not allow for inclusion of such deferred tax expense in current rates.
Rate regulated enterprises are required to recognize such adjustments as regulatory assets if it is probable that such amounts will be
recovered from customers in future rates.
As discussed in "Status of Audit Proceedings" above, the IRS has disallowed IPC's use of the simplified service cost method for the
IFERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
tax years 2001-2003 on the basis of Rev. Rul. 2005-53. As a result, the IRS has assessed a $45 million tax liability. IDACORP is in
the process of appealing the IRS's assessment. Because of the nature of the issue, IDACORP's exposure with respect to this matter
may be less than the tax assessed plus applicable interest charges. Additionally, after resolution IDACORP will likely amend its 2005
federal income tax return and its 2005 method change application to account for the effects that such resolution has on !PC's new
uniform capitalization method (discussed below). This amendment is not expected to have a material negative impact on !PC's
consolidated financial position, results of operations, or cash flows.
With respect to tax year 2005 and future tax years, the Temporary Regulations, as drafted, preclude !PC from using the simplified
service cost method for its self-constructed assets. Under the Temporary Regulations, !PC is required to use another allowable section
263A method for its indirect costs, including mixed service costs. As a result of the Temporary Regulations, !PC made changes to its
overall section 263A uniform capitalization method of accounting. In September 2006, the changes were adopted with an automatic
method change request included in 2005 federal income tax return. The uniform capitalization methodology adopted for 2005 and
subsequent years involves the use of the specific identification, burden rate, and step-allocation methods of accounting. The methods
used are allowable under both the final and temporary section 263A regulations.
As with the simplified service cost method, the new uniform capitalization methodology produces an annual tax deduction for costs
that are not required to be capitalized under section 263A as well as costs capitalized into the production of electricity. The method,
while producing a beneficial result, is not as favorable as the simplified service cost method. Changing the uniform capitalization
method resulted in a net charge to !PC's 2006 income tax expense of $6.1 million. The estimated 2006 tax deduction produced a $3.
million tax benefit for the year. The change in method did not have a material effect on !PC's 2006 cash flows. The accounting and
regulatory treatment for the new method is the same as previously used for the simplified service cost method.
3. COMMON STOCK:
Dividend Restrictions: !PC's articles of incorporation contain restrictions on the payment of dividends on its common stock if
preferred stock dividends are in arrears. On September 20, 2004, !PC redeemed all of its outstanding preferred stock. Also, certain
provisions of credit facilities contain restrictions on the ratio of debt to total capitalization.
!PC must obtain the approval of the Oregon Public Utility Commission (OPUC) before it could directly or indirectly loan funds or
issue notes or give credit on its books to IDACORP.
In December 2006, IDACORP contributed $47 million of additional equity to !Pc. No additional shares of !PC common stock were
issued.
4. LONG-TERM DEBT
The following table summarizes long-term debt at December 31:2006 2005
(thousands of dollars)
First mortgage bonds:
7.38% Series due 2007
20% Series due 2009
60% Series due 20 II
75% Series due 2012
25% Series due 20136% Series due 2032
5.50% Series due 2033
50% Series due 2034
875% Series due 2034
30% Series due 2035
Total first mortgage bonds
Pollution control revenue bonds:
IFERC FORM NO.1 (ED. 12-88)
000
80,000
120 000
100 000
000
100 000
70,000
50,000
55,000
60,000
785 000
80,000
80,000
120,000
100 000
70,000
100,000
70,000
50,000
55,000
60,000
785 000
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 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Variable Auction Rate Series 2003 due 2024 (a) 49,800
Variable Auction Rate Series 2006 due 2026 (a) 116 300
05% Series 1996A due 2026 68,100Variable Rate Series I 996B due 2026 24 200Variable Rate Series 1996C due 2026 24 000Variable Rate Series 2000 due 2027 4 360 4,360Total pollution control revenue bonds 170,460 170,460American Falls bond guarantee 19,885 19,885Milner Dam note guarantee 11 700 11 700
Unamortized premium (discount) - net (3 097) (3,325)
Total long-term debt $ 983,948 $ 983,720(a) Humboldt County and Sweetwater County Pollution Control Revenue bonds are secured by first mortgage bonds,
bringing the total first mortgage bonds outstanding at December 31, 2006, to $951.1 million.
49,800
At December 31 , 2006, the maturities for the aggregate amount of long-term debt outstanding were (in thousands of dollars):
2007 2008 2009 2010 2011 Thereafter
IPC 81,064 $064 $064 $064 $121,064 $701 725
At December 31 2006 and 2005, the overall effective cost of IPC's outstanding debt was 5.71 percent and 5.84 percent, respectively.
On October 3, 2006, IPC completed a tax-exempt bond financing in which Sweetwater County, Wyoming issued and sold $116.
million aggregate principal amount of its Pollution Control Revenue Refunding Bonds Series 2006, The bonds will mature on July 15
2026. The $116.3 million proceeds were loaned by Sweetwater County to IPC pursuant to a loan agreement, dated as of October I,
2006, between Sweetwater County and IPC. On October 10, 2006, the proceeds of the new bonds, together with certain other moneys
ofIPC, were used to refund Sweetwater County's Pollution Control Revenue Refunding Bonds Series I 996A, Series 1996B and Series
1996C totaling $116.3 million. The regularly scheduled principal and interest payments on the Series 2006 bonds, and principal and
interest payments on the bonds upon mandatory redemption on determination of taxability, are insured by a financial guaranty
insurance policy issued by AMBAC Assurance Corporation. IPC and AMBAC have entered into an Insurance Agreement, dated as of
October 3, 2006, pursuant to which IPC has agreed, among other things, to pay certain premiums to AMBAC and to reimburse
AMBAC for any payments made under the policy. To secure its obligation to make principal and interest payments on the loan made
to IPC, IPC issued and delivered to a trustee IPC's First Mortgage Bonds, Pollution Control Series C, in a principal amount equal to
the amount of the new bonds.
Long-Term Financing
IPC has in place a registration statement that can be used for the issuance of an aggregate principal amount of $240 million of first
mortgage bonds (including medium-term notes) and unsecured debt.
In January 2007, the IPC Board of Directors approved an increase of the maximum amount of first mortgage bonds issuable by IPC to
$1.5 billion. The amount issuable is also restricted by property, earnings and other provisions of the mortgage and supplemental
indentures to the mortgage. IPC may amend the indenture and increase this amount without consent of the holders of the first
mortgage bonds. The indenture requires that IPC's net earnings must be at least twice the annual interest requirements on all
outstanding debt of equal or prior rank, including the bonds that IPC may propose to issue. Under certain circumstances, the net
earnings test does not apply, including the issuance of refunding bonds to retire outstanding bonds that mature in less than two years or
that are of an equal or higher interest rate, or prior lien bonds.
As of December 31 , 2006, IPC could issue under the mortgage approximately $559 million of additional first mortgage bonds based on
unfunded property additions and $452 million of additional first mortgage bonds based on retired first mortgage bonds. At December
, 2006, unfunded property additions were approximately $1.0 billion.
The mortgage requires IPC to spend or appropriate 15 percent of its annual gross operating revenues for maintenance, retirement or
IFERC FORM NO.1 (ED. 12-88) Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
amortization of its properties. IPC may, however, anticipate or make up these expenditures or appropriations within the five years that
immediately follow or precede a particular year.
The mortgage secures all bonds issued under the indenture equally and ratably, without preference, priority or distinction. IPC may
issue additional first mortgage bonds in the future, and those first mortgage bonds will also be secured by the mortgage. The lien of
the indenture constitutes a first mortgage on all the properties of IPC, subject only to certain limited exceptions including liens for
taxes and assessments that are not delinquent and minor excepted encumbrances. Certain of the properties of IPC are subject to
easements, leases, contracts, covenants, workmen s compensation awards and similar encumbrances and minor defects and clouds
common to properties. The mortgage does not create a lien on revenues or profits, or notes or accounts receivable, contracts or choses
in action, except as permitted by law during a completed default, securities or cash, except when pledged, or merchandise or equipment
manufactured or acquired for resale. The mortgage creates a lien on the interest of IPC in property subsequently acquired, other than
excepted property, subject to limitations in the case of consolidation, merger or sale of all or substantially all of the assets of IPc.
5. FAIR VALUE OF FINANCIAL INSTRUMENTS:
The estimated fair value of IPC's financial instruments has been determined using available market information and appropriate
valuation methodologies. The use of different market assumptions and/or estimation methodologies may have a material effect on the
estimated fair value amounts.
Cash and cash equivalents, customer and other receivables, notes payable, accounts payable, interest accrued and taxes accrued are
reported at their carrying value as these are a reasonable estimate of their fair value. The estimated fair values for notes receivable
long-term debt and investments are based upon quoted market prices of the same or similar issues or discounted cash flow analyses asappropriate.
December 31, 2006 December 31, 2005Carrying Estimated Carrying EstimatedAmount Fair Value Amount Fair Value
(thousands of dollars)
Assets:
Notes receivable 853 679 047 876
Investments 28,040 28,040 137 137
Liabilities:
Long-term debt 987,045 978,491 987,045 003,651
6. NOTES PAYABLE:
IPC has a $200 million credit facility that expires on March 31, 2010. Commercial paper may be issued up to the amounts supported
by the bank credit facilities. Under this facility the company 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. At
December 31 , 2006, IPC had regulatory authority to incur up to $250 million of short-term indebtedness. Balances and interest rates
of IPC's short-term borrowings were as follows at December 31 (in thousands of dollars):
2006 2005
(thousands of dollars)
Balances:
At the end of year
Average during the year
Weighted-average interest rate:
At the end of year
Average during the year
IFERC FORM NO.1 (ED. 12-88)
200
211 123
50%
50%83%
Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
7. COMMITMENTS AND CONTINGENCIES:
Purchase Obligations:
As of December 31 , 2006, IPC had agreements to purchase energy from 92 cogeneration and small power production (CSPP) facilities
with contracts ranging from one to 30 years. Under these contracts IPC is required to purchase all of the output from the facilities
inside the IPC service territory. For projects outside the IPC service territory, IPC is required to purchase the output that it has the
ability to receive at the facility s requested point of delivery on the IPC system. IPC purchased 911,132 megawatt-hours (MWh) at a
cost of $54 million in 2006 and 715,209 MWh at a cost of $46 million in 2005.
At December 31 2006, IPC had the following long-term commitments relating to purchases of energy, capacity, transmission rights
and fuel:
2007 2008 2009 2010 2011 Thereafter
(thousands of dollars)
Cogeneration and small power production 45,130 $76,538 $76,538 $79,830 $79,830 $064 718
Power and transmission rights 80,175 16,351 390 781 754 315
Fuel 54,395 035 28,885 941 821 005
Guarantees
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,
2006. Bridger Coal Company has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs.
Bridger Coal Company and IPC expect that the fund will be sufficient to cover all such costs. Because of the existence of the fund, the
estimated fair value of this guarantee is minimal.
Legal Proceedings
From time to time IDACORP and IPC are a party to legal claims, actions and complaints in addition to those discussed below.
IDACORP and IPC believe that they have meritorious defenses to all lawsuits and legal proceedings. Although they will vigorously
defend against them, they are unable to predict with certainty whether or not they will ultimately be successful. However, based on the
companies' evaluation, they believe that the resolution of these matters, taking into account existing reserves, will not have a material
adverse effect on IDACORP's or IPC's 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. Wah Chang s complaint is based on allegations relating to the
western energy situation. These allegations include bid rigging, falsely creating congestion and misrepresenting the source and
destination of energy. The plaintiff seeks compensatory damages of $30 million and treble damages.
On September 8, 2004, this case was transferred and consolidated with other similar cases currently pending before the Honorable
Robert H. Whaley sitting by designation in the U.S. District Court for the Southern District of California. The companies' filed a
motion to dismiss the complaint which the court granted on February 11 2005. Wah Chang appealed the dismissal to the U.S. Court
of Appeals for the Ninth Circuit on March 10,2005. The Ninth Circuit set a briefing schedule on the appeal, requiring Wah Chang
opening brief to be filed by July 6, 2005. On May 18,2005 , Wah Chang filed a motion to stay the appeal or in the alternative to
voluntarily dismiss the appeal without prejudice to reinstatement. The companies opposed the motion and filed a cross-motion asking
the Court to summarily affirm the district court s order of dismissal. On July 8, 2005, the Ninth Circuit denied Wah Chang s motion
and also denied the companies' motion for summary affirmance without prejudice to renewal following the filing ofWah Chang
opening brief. Wah Chang s opening brief was filed on September 21 , 2005. On October 11 , 2005 the companies, along with the
other defendants, filed a motion to consolidate this appeal with Wah Chang v. Duke Energy Trading and Marketing currently pending
before the Ninth Circuit. On October 18,2005, the Ninth Circuit granted the motion to consolidate and established a revised briefing
schedule. The companies filed an answering brief on November 30, 2005. Wah Chang s reply brief was filed on January 6, 2006.
I FERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
The appeal has been fully briefed and oral argument is scheduled for April 10, 2007. The companies intend to vigorously defend their
position in this proceeding and believe this matter will not have a material adverse effect on their consolidated financial positions
results of operations or cash flows.
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. Whaley sitting by designation in the U.S. District Court for the Southern District of California. The companies' filed a
motion to dismiss the complaint which the court granted on February 11 2005, The City of Tacoma appealed to the u.S. Court of
Appeals for the Ninth Circuit on March 10, 2005.
On August 9,2005, the companies moved for summary affirmance of the district court's order dismissing the City of Tacoma
complaint. The City of Tacoma filed a response to the companies' motion for summary affirmance on August 24, 2005. The Ninth
Circuit denied the companies' motion for summary affirmance on November 3, 2005. The appeal has been fully briefed and oral
argument is scheduled for April 10, 2007. The companies intend to vigorously defend their position in this proceeding and believe this
matter will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.
Western Energy Proceedings at the FERC:
California Power Exchange Chargeback:
As a component of 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 (CaIPX), a California non-profit public benefit corporation. The CaIPX, at that time,
operated a wholesale electricity market in California by acting as a clearinghouse through which electricity was bought and sold.
Pursuant to the participation agreement, IPC could sell power to the CalPX under the terms and conditions of the CalPX Tariff. Under
the participation agreement, if a participant in the CaIPX defaulted on a payment, the other participants were required to pay their
allocated share of the default amount to the CaIPX. The allocated shares were based upon the level of trading activity, which included
both power sales and purchases, of each participant during the preceding three-month period.
On January 18, 200 I , 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, 200 I, IPC
terminated its participation agreement with the CaIPX. On February 8, 2001 , the CalPX sent a further invoice for $5 million, due on
February 20, 2001, as a result of alleged payment defaults by Southern California Edison, Pacific Gas and Electric Company and
others. However, because the CalPX owed IPC $11 million for power sold to the CalPX in November and December 2000, IPC did
not pay the February 8 invoice. The CalPX later reversed IPC's payment of the January 18,2001 invoice, but on June 20, 2001
invoiced IPC for an additional $2 million. The CalPX owed 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 believed that the default invoices were not proper and that IPC owed no further amounts to the CaIPX. IPC pursued all available
remedies in its efforts to collect amounts owed to it by the CaIPX. On February 20, 2001, IPC filed a petition with the FERC to
intervene in a proceeding that requested the FERC to suspend the use of the CalPX chargeback methodology and provide for further
oversight in the CaIPX's implementation of its default mitigation procedures.
A 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, 200 I , the CalPX filed for
Chapter II 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.
IFERC FORM NO.1 (ED. 12-88)Page 123.
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(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
The FERC issued an order on April 6, 200 I requiring the CalPX to rescind all chargeback actions related to Pacific Gas and Electric
Company s and Southern California Edison s liabilities. Shortly after the issuance of that order, the CalPX segregated the CalPX
chargeback amounts it had collected in a separate account. The CalPX claimed it would await further orders from the FERC and the
bankruptcy court before distributing the funds that it collected under its chargeback tariff mechanism. On October 7, 2004, the FERC
issued an order determining that it would not require the disbursement of chargeback funds until the completion of the California
refund proceedings. On November 8, 2004, IE, along with a number of other parties, sought rehearing of that order. On March IS,
2005, the FERC issued an order on rehearing confirming that the CalPX was to continue to hold the chargeback funds, but solely to
offset seller-specific shortfalls in the seller s CalPX account at the conclusion of the California refund proceeding. Balances were to
be returned to the respective sellers at the conclusion of a seller s participation in the refund proceeding.
Based upon the Offer of Settlement filed with the FERC on February 17, 2006 between the California Parties and IE and IPC discussed
below in "California Refund " the California Parties supported a motion filed by IE and !PC with the FERC seeking an Order Directing
Return of Chargeback Amounts then held by the CalPX totaling $2.27 million. In the May 22, 2006 order approving the Settlement
the FERC granted the IE and IPC motion for return of chargeback funds held by the CaIPX. On June 1,2006, IE received
approximately $2.5 milIion from the CalPX representing the return of $2.27 milIion in chargeback funds plus interest.
California Refund:
In April 200 I , the FERC issued an order stating that it was establishing price mitigation for sales in the California wholesale electricity
market. Subsequently, in a June 19,2001 , order, the FERC expanded that price mitigation plan to the entire western United States
electrically interconnected system. That plan included the potential for orders directing electricity sellers into California since October
, 2000, to refund portions of their spot market sales prices if the FERC determined that those prices were not just and reasonable, and
therefore not in compliance with the Federal Power Act. The June 19 order also required all buyers and sellers in the Cal ISO market
during the subject time frame to participate in settlement discussions to explore the potential for resolution of these issues without
further FERC action. The settlement discussions failed to bring resolution of the refund issue and as a result, the FERC's Chief
Administrative Law Judge submitted a Report and Recommendation to the FERC recommending that the FERC adopt the
methodology set forth in the report and set for evidentiary hearing an analysis of the Cal ISO's and the CaIPX's spot markets to
determine what refunds may be due upon application of that methodology.
On July 25, 2001 , the FERC issued an order establishing evidentiary hearing procedures related to the scope and methodology for
calculating refunds related to transactions in the spot markets operated by the Cal ISO and the CalPX during the period October 2
2000, through June 20, 2001 (Refund Period).
The 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, were expected to increase the offsets
to amounts still owed by the Cal ISO and the CalPX to the companies. Calculations remained uncertain because (I) the FERC had
required the Cal ISO to correct a number of defects in its calculations, (2) it was unclear what, if any, effect the ruling of the Ninth
Circuit in Bonneville Power Administration v. FERC, described below, might have on the ISO's calculations, and (3) the FERC had
stated that if refunds would prevent a seller from recovering its California portfolio costs during the Refund Period, it would provide
an opportunity for a cost showing by such a respondent.
, along with a number of other parties, filed an application with the FERC on April 25, 2003, seeking rehearing of the March 26
2003, order. On October 16,2003, the FERC issued two orders denying rehearing of most contentions that had been advanced and
directing the Cal ISO to prepare its compliance filing calculating revised Mitigated Market Clearing Prices and refund amounts within
five months.
Two avenues of activity have proceeded on largely but not entirely independent paths, converging from time to time. The Cal ISO
continued to work on its compliance refund calculations while the appellate litigation and litigation before the FERC regarding, among
other things, cost filings, fuel cost allowance offsets, emissions offsets, cost-based recovery offsets, and allocation methods continued.
IFERC FORM NO.1 (ED. 12-88)Page 123.
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(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubm ission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Originally, the Cal ISO was to complete its calculation within five months of the FERC's October 16,2003, order. The Cal ISO
compliance filing has since been delayed numerous times. The Cal ISO has been required to update the FERC on its progress monthly,
In its most recent status report, filed February 22, 2007, the Cal ISO reported that it has completed publishing settlement statements
reflecting the basic refund calculations, and is currently in a "financial adjustment" phase, in which it calculates adjustments to its
refund data to account for fuel cost allowance offsets, emissions offsets, cost-based recovery offsets, and interest on amounts unpaid
and refunds, The Cal ISO estimates that it will take approximately 10 additional weeks to complete the financial adjustment phase
including applicable review and comment periods. The Cal ISO estimates that it will have completed its calculations by May 2007
subject to such additional time as may be required if unanticipated delays are encountered. The potential expansion of the FERC
refund proceedings due to the Ninth Circuit orders and the disposition of additional settlements which the Ninth Circuit has announced
it expects to be filed at the FERC in the near future may affect the finality of any Cal ISO calculations. At present, IDACORP and IPC
are not able to predict when the Ninth Circuit mandates may issue, how the FERC will proceed in connection with the possible
expansion of the proceedings, the nature and content of as yet un-filed settlements or the extent to which the Cal ISO calculation
process may be disrupted.
On December 2, 2003, IDACORP petitioned the U.S. Court of Appeals for the Ninth Circuit for review of the FERC's orders, and
since that time, dozens of other petitions for review have been filed. The Ninth Circuit consolidated IE's and the other parties
petitions with the petitions for review arising from earlier FERC orders in this proceeding, bringing the total number of consolidated
petitions to more than 100. The Ninth Circuit held the appeals in abeyance pending the disposition of the market manipulation claims
discussed below and the development of a comprehensive plan to brief this complicated case. Certain parties also sought further
rehearing and clarification before the FERC. On September 21 , 2004, the Ninth Circuit convened case management proceedings, a
procedure reserved to help organize complex cases. On October 22, 2004, the Ninth Circuit severed a subset of the stayed appeals in
order that briefing could commence regarding cases related to: (1) which parties are subject to the FERC's refund jurisdiction under
section 20 l(f) of the Federal Power Act; (2) the temporal scope ofrefunds under section 206 of the Federal Power Act; and (3) which
categories of transactions are subject to refunds. Oral argument was held on April 12-2005. On September 6, 2005, the Ninth
Circuit issued a decision on the jurisdictional issues concluding that the FERC lacked refund authority over wholesale electric energy
sales made by governmental entities and non-public utilities. On August 2, 2006, the Ninth Circuit issued its decision on the
appropriate temporal reach and the type of transactions subject to the FERC refund orders and concluded, among other things, that all
transactions at issue in the case that occurred within or as a result of the CalPX and the Cal ISO were the proper subject of refund
proceedings; refused to expand the refund proceedings into the bilateral markets including transactions with the California Department
of Water Resources; approved the refund effective date as October 2, 2000, but also required the FERC to consider whether refunds
including possibly market-wide refunds, should be required for an earlier time due to claims that some market participants had violated
governing tariff obligations (although the decision did not specify when that time would start, the California Parties generally had
sought further refunds starting May I, 2000); and effectively expanded the scope of the refund proceeding to transactions within the
CalPX and Cal ISO markets outside the 24-hour spot market and energy exchange transactions. The IDACORP settlement with the
California Parties approved by the FERC on May 22, 2006, and discussed below anticipated the possibility of such an outcome and
attempted to provide that the consideration exchanged among the settling parties also encompass the settling parties' claims in the
event of such expansion of the proceedings.
The Ninth Circuit subsequently issued orders deferring the time for seeking rehearing of its order and holding the consolidated
petitions for review in abeyance for a limited time in order to create an opportunity for unusual mediation proceedings managed jointly
by the Court Mediator and FERC officials. The Ninth Circuit has since extended the deferral for the mediation effort.
IDACORP believes that these decisions should have no material effect on IDACORP under the terms of the IDACORP Settlement
with the California Parties approved by the FERC on May 22, 2006.
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. El Paso, et al. The
CPUC's complaint alleged that the El Paso companies manipulated California energy markets by withholding pipeline transportation
capacity into California in order to drive up natural gas prices immediately before and during the California energy crisis in
2000-200 I. The settlement will result in the payment by El Paso of approximately $1.69 billion. Duke claimed that the relief afforded
by the settlement was duplicative of the remedies imposed by the FERC in its March 26, 2003, order changing the gas cost component
IFERC FORM NO.1 (ED. 12-88)Page 123.
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(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
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 alIowed for petitions, a number of parties, including IE, filed
petitions for review of the FERC's order with the Ninth Circuit. These petitions have since been consolidated with the larger number
of review petitions in connection with the California refund proceeding.
On March 20, 2002, the California Attorney General filed a complaint with the FERC against various selIers 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 remanding the matter to the FERC to consider whether the FERC should exercise remedial power (including some form of
refunds) when a market participant failed to submit reports that the FERC relies on to conflfm the justness and reasonableness of rates
charged. On December 28, 2006, a number of sellers have filed a certiorari petition to the U.S. Supreme Court. The u.S. Supreme
Court has not yet acted on that petition. On February 16,2007, the Ninth Circuit announced that it was continuing to withhold the
mandate until April 27, 2007.
In June 2001 , IPC transferred its non-utility wholesale electricity marketing operations to IE. Effective with this transfer, the
outstanding receivables and payables with the CalPX and the Cal ISO were assigned from IPC to IE. At December 31, 2005, with
respect to the CalPX chargeback and the California refund proceedings discussed above, the CalPX and the Cal ISO owed $14 million
and $30 million, respectively, for energy sales made to them by IPC in November and December 2000.
On August 8, 2005, the FERC issued an Order establishing the framework for filings by sellers who elected to make a cost showing.
On September 14 2005, IE and IPC made a joint cost filing, as did approximately thirty other sellers. On October 11 2005, the
California entities filed comments on the IE and IPC cost filing and those made by other parties. IPC and IE submitted reply
comments on October 17,2005. The California entities filed supplemental comments on October 24 2005 and IPC and IE filed
supplemental reply comments on October 27, 2005.
In December of 2005, IE and IPC reached a tentative agreement with the California Parties settling matters encompassed by the
California Refund proceeding including IE's and IPC's cost filing and refund obligation. On January 20, 2006, the Parties filed a
request with the FERC asking that the FERC defer ruling on IE's and IPC's cost filing for thirty days so the parties could complete and
file the settlement agreement with the FERC. On January 26, 2006, the FERC granted the requested deferral of a ruling on the cost
filing and required that the settlement be filed by February 17, 2006. On February 17, 2006, IE and IPC jointly filed with the
California Parties (Pacific Gas & Electric Company, San Diego Gas & Electric Company, Southern California Edison, the California
Public Utilities Commission, the California Electricity Oversight Board, the California Department of Water Resources and the
California Attorney General) an Offer of Settlement at the FERC. Other parties had until March 9, 2006 to elect to become additional
settling parties. A number of parties, representing substantially less than the majority potential refund claims, chose to opt out of the
settlement.
On March 27, 2006, the FERC issued an order rejecting the IE/IPC cost filing and on April 26, 2006, IE and IPC sought rehearing of
the rejection. By order of April 27, 2006, the FERC tolled the time for what otherwise would have been required by statute to be a
decision on the request for rehearing,
On May 12, 2006, the FERC issued an order determining the method that should be used to alIocate amounts approved in cost filings,
approving the methodology that IE and IPC and others had advocated prior to the time IE and IPC entered into the February 17, 2006
settlement - alIocating cost offsets to buyers in proportion to the net refunds they are owed through the Cal ISO and CalPX markets.
On June 12 2006, the California Parties requested rehearing, urging the FERC to allocate the cost offsets to all purchasers from the
Cal ISO and CalPX markets and not just to that limited subset of purchasers who are net refund recipients. On July 12, 2006, the
FERC tolled the time to act on the request for rehearing and has not issued orders on rehearing since that time. IDACORP and IPC are
unable to predict how or when the FERC might rule on the request for rehearing.
IFERC FORM NO.1 (ED. 12-88)Page 123,
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
After consideration of comments, the FERC approved the February 17, 2006, Offer of Settlement on May 22, 2006. Under the terms
of the settlement, IE and IPC assigned $24.25 million of the rights to accounts receivable from the Cal ISO and CalPX to the
California Parties to pay into an escrow account for refunds to settling parties. Amounts from that escrow not used for settling parties
and $1,5 million of the remaining IE and IPC receivables that are to be retained by the CalPX are available to fund, at least partially,
payment of the claims of any non-settling parties if they prevail in the remaining litigation of this matter. Any excess funds remaining
at the end of the case are to be returned to IDACORP. Approximately $10.25 million of the remaining IE and IPC receivables was
paid to IE and IPC under the settlement.
On June 21 , 2006, the Port of Seattle, Washington filed a request for rehearing of the FERC order approving the settlement. On July
10,2006, IPC and IE and the California Parties filed a response to Port of Seattle s request for rehearing. On October 5,2006, the
FERC issued an order denying the Port of Seattle s request for rehearing. On October 24 2006, the Port of Seattle petitioned the U.
Court of Appeals for the Ninth Circuit for review of the FERC order denying their request for rehearing of the FERC order approving
the settlement. The Ninth Circuit consolidated that review petition with the large number of review petitions already consolidated
before it. On January 23, 2007, IPC and IE filed a motion to sever the Port of Seattle s petition for review from the bulk of cases
pending in the Ninth Circuit with which it had been consolidated. IPC and IE also filed a motion to dismiss the Port of Seattle
petition for review. The Port of Seattle filed their answers in opposition to the motion to sever and the motion to dismiss on February
, 2007, and IPC and IE replied on February 12, 2007. IDACORP and IPC are not able to predict when or how the Ninth Circuit
might rule on the motions.
Prior to December of 2005 , IE had accrued a reserve of $42 million. This reserve was calculated taking into account the uncertainty of
collection from the CalPX and Cal ISO. In the fourth quarter of 2005, following the tentative agreement with the California Parties, IE
reduced this reserve by $9.5 million to $32 million. Following payment of the $10.25 million to IE and IPC in June 2006, IE further
reduced the reserve by $24.9 million to $7.1 million. This reserve was calculated taking into account several unresolved issues in the
California refund proceeding.
Market Manioulation:
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 200 I.
On March 3 2003, the California Parties (certain investor owned utilities, the California Attorney General, the California Electricity
Oversight Board and the CPUC) filed voluminous documentation asserting that a number of wholesale power suppliers, including IE
and IPC, had engaged in a variety of forms of conduct that the California Parties contended were impermissible. Although the
contentions of the California Parties were contained in more than II compact discs of data and testimony, approximately 12,000 pages
IE and IPC were mentioned only in limited contexts with the overwhelming majority of the claims of the California Parties relating to
the conduct of other parties.
The California Parties urged the FERC to apply the precepts of its earlier decision, to replace actual prices charged in every hour
starting January I, 2000 through the beginning of the existing refund period (October 2, 2000) with a Mitigated Market 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 testimony.
In its March 26, 2003 order, discussed above in "California Refund," the FERC declined to generically apply its refund detenninations
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 I
2000 and June 20, 2001 , including IPC, to show cause why certain trading practices did not constitute gaming or anomalous market
behavior in violation of the Cal ISO and the CalPX Tariffs. The Cal ISO was ordered to provide data on each entity s trading practices
within 21 days of the order, and each entity was to respond explaining their trading practices within 45 days of receipt of the Cal ISO
data. IPC submitted its responses to the show cause orders on September 2 and 4 2003. On October 16,2003, IPC reached
agreement with the FERC Staff on the two orders commonly referred to as the "gaming" and "partnership" show cause orders.
Regarding the gaming order, the FERC Staff determined it had no basis to proceed with allegations of false imports and paper trading
I FERC FORM NO.1 (ED. 12-88)Page 123,
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(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
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. Originally, eight parties requested rehearing of the FERC's March 3, 2004
order. 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 of the parties contend that the scope of the proceedings initiated by the FERC was too
narrow. Other parties contend that the orders initiating the show cause proceedings were impermissible. Under the rules for
multidistrict litigation, a lottery was held and although these cases were to be considered in the District of Columbia Circuit by order of
February 10, 2005, the District of Columbia Circuit transferred the proceedings to the Ninth Circuit. The FERC had moved the
District of Columbia Circuit to dismiss these petitions on the grounds of prematurity and lack of ripeness and finality. The transfer
order was issued before a ruling from the District of Columbia Circuit and the motions, if renewed, will be considered by the Ninth
Circuit. The Ninth Circuit has consolidated this case with other matters and are holding them in abeyance. IPC is not able to predict
the outcome of the judicial determination of these issues.
The settlement between the California Parties and IE and IPC discussed above in the California Refund proceeding approved by the
FERC on May 22,2006, results in the California Parties and other settling parties withdrawing their requests for rehearing of IPC'
and IE's settlement with the FERC Staff regarding allegations of "gaming . On October 11, 2006, the FERC issued an Order denying
rehearing of its earlier approval of the "gaming" allegations, thereby effectively terminating the FERC investigations as to IPC and IE
regarding bidding behavior, physical withholding of power and "gaming" without finding of wrongdoing. On October 24, 2006, the
Port of Seattle appealed the FERC order to the U.S. Court of Appeals for the Ninth Circuit.
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 I , 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.
a letter dated May 12 2004, the FERC's Office of Market Oversight and Investigations advised that it was terminating the
investigation as to IPC. In March 2005, the California Attorney General, the CPUC, the California Electricity Oversight Board and
Pacific Gas and Electric Company sought judicial review in the Ninth Circuit of the FERC's termination of this investigation as to IPC
and approximately 30 other market participants. IPC has moved to intervene in these proceedings. On April 25, 2005, Pacific Gas and
Electric Company sought review in the Ninth Circuit of another FERC order in the same docketed proceeding confirming the agency
earlier decision not to allow the participation of the California Parties in what the FERC characterized as its non-public investigative
proceeding.
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 intervened in
this FERC proceeding, asserting on March 3, 2003 that its six-month forward contract, for which performance had been completed
should be treated as a spot market contract for purposes of the FERC' s consideration of refunds and requested 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
IFERC FORM NO.1 (ED. 12-88)Page 123.
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(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
defending vigorously against Grays Harbor s refund claims.
In addition, the Port of Seattle, the City of Tacoma and the City of Seattle made filings with the FERC on March 3, 2003, claiming that
because some market participants drove prices up throughout the west through acts of manipulation, prices for contracts throughout the
Pacific Northwest market should be re-set starting in May 2000 using the same factors the FERC would use for California markets.
Although the majority of these claims are generic, they named a number of power market suppliers, including IPC and IE, as having
used parking services provided by other parties under FERC-approved tariffs and thus as being candidates for claims of improperly
having received congestion revenues from the Cal ISO. On June 25, 2003, after having considered oral argument held earlier in the
month, the FERC issued its Order Granting Rehearing, Denying Request to Withdraw Complaint and Terminating Proceeding, in
which it terminated the proceeding and denied claims that refunds should be paid. The FERC denied rehearing on November 10,
2003, triggering the right to file for review. The Port of Seattle, the City of Tacoma, the City of Seattle, the California Attorney
General, the CPUC and Puget Sound Energy, Inc. filed petitions for review in the Ninth Circuit. These petitions have been
consolidated. Grays Harbor did not file a petition for review, although it sought to intervene in the proceedings initiated by the
petitions of others. On July 21, 2004, the City of Seattle submitted 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 sought to introduce before the FERC consisted of audio tapes of what purports to be Enron trader conversations containing
inflammatory language. Under Section 313(b) of the Federal Power Act, a court is empowered to direct the introduction of additional
evidence if it is material and could not have been introduced during the underlying proceeding. On September 29, 2004, the Ninth
Circuit denied the City of Seattle s motion for leave to adduce evidence, without prejudice to renewing the request for remand in the
briefing in the Pacific Northwest refund case. Briefing was completed on May 25, 2005, and oral argument was held on January 8,
2007. The Settlement approved by the FERC on May 22, 2006, resolves all claims the California Parties have against IE and IPC in
the Pacific Northwest refund proceeding. The settlement with Grays Harbor resolves all claims Grays Harbor has against IE and IPC
in this proceeding. IE and IPC are unable to predict the outcome as to all other parties in this proceeding.
In separate western energy proceedings, the Ninth Circuit issued two decisions on December 19,2006 reviewing the FERC's decisions
not to require repricing of certain long term contracts. Those cases originated with individual complaints against specified sellers
which did not include IE or IPc. The Ninth Circuit remanded to the FERC for additional consideration the agency s use of restrictive
standards of contract review. In its decisions, the Ninth Circuit also questioned the validity of the FERC's administration of its
market-based rate regime. IDACORP and IPC are unable to predict whether parties to that case will seek a writ of certiorari or how or
when the FERC might respond to these decisions.
Shareholder Lawsuit: On May 26, 2004 and June 22, 2004, respectively, two shareholder lawsuits were filed 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 aI., 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 ofIdaho. The
named defendants in each suit, in addition to IDACORP, are Jon H. Miller, Jan B. Packwood, J. LaMont Keen and Darcel 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 lO(b) and 20(a)
of the Securities Exchange Act of 1934, as amended, and Rule IOb-5, thereby causing investors to purchase IDACORP'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: (I) 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 account 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 IDACORP'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
2004, IDACORP and the directors and officers named above were served with a purported consolidated complaint captioned Powell,
et al. v. IDACORP, Inc., et aI., which was filed in the u.S. District Court for the District of Idaho.
I FERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
The new complaint alleged 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 IE financial outlook, in violation of Rule
IOb-5, thereby causing investors to purchase IDACORP's common stock at artificially inflated prices. The new complaint alleged that
IDACORP failed to disclose and misrepresented the following material adverse facts which were known to it or recklessly disregarded
by it: (I) IDACORP falsely inflated the value of energy contracts held by IE in order to report higher revenues and profits; (2)
IDACORP permitted IPC to inappropriately grant native load priority for certain energy transactions to IE; (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 Act; (4) IDACORP failed to file 1 182 contracts that IPC assigned to IE 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) IDACORP failed to ensure that IE
provided appropriate compensation from IE to IPC for certain affiliated energy transactions; and (6) IDACORP permitted
inappropriate sharing of certain energy pricing and transmission information between IPC and IE. These activities allegedly allowed
IE 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, and the plaintiffs filed their opposition to the
consolidated motion to dismiss on March 28, 2005. IDACORP and the other defendants filed their response to the plaintiffs
opposition on April 29, 2005 and oral argument on the motion was held on May 19, 2005.
On September 14 2005 , Magistrate Judge Mikel H. Williams of the U.S. District Court for the District of Idaho issued a Report and
Recommendation that the defendants' motion to dismiss be granted and that the case be dismissed. The Magistrate Judge determined
that the plaintiffs did not satisfactorily plead loss causation (i.e., a causal connection between the alleged material misrepresentation
and the loss) in conformance with the standards set forth in the recent United States Supreme Court decision of Dura Pharmaceuticals
Inc. v, Broudo, 544 U.S.336, 125 S. Ct. 1627 (2005). The Magistrate Judge also concluded that it would be futile to afford the
plaintiffs an opportunity to file an amended complaint because it did not appear that they could cure the deficiencies in their pleadings,
Each party filed objections to different parts of the Magistrate Judge s Report and Recommendation.
On March 29, 2006, the U.S. District Court for the District of Idaho (Judge Edward J. Lodge) issued an Order in this case (Powell v,
IDACORP) adopting the Report and Recommendation of Magistrate Judge Williams issued on September 14 2005 , granting the
defendants' (IDACORP and certain of its officers and directors) motion to dismiss because plaintiffs failed to satisfy the pleading
requirements for loss causation, However, Judge Lodge modified the Report and Recommendation and ruled that plaintiffs had until
May 1 2006, to file an amended complaint only as to the loss causation element. On May 1 2006, the plaintiffs filed an amended
complaint. The defendants filed a motion to dismiss the amended complaint on June 16,2006, asserting that the amended complaint
still failed to satisfy the pleading requirements for loss causation. Briefing on this most recent motion to dismiss was completed on
August 28, 2006, and oral argument was held on February 26, 2007.
IDACORP and the other defendants intend to defend themselves vigorously against the allegations. IDACORP cannot, however,
predict the outcome of these matters.
Western Shoshone National Council: On April 10, 2006, the Western Shoshone National Council (which purports to be the
governing body of the Western Shoshone Nation) and certain of its individual tribal members filed a First Amended Complaint and
Demand for Jury Trial in the u.S. District Court for the District of Nevada, naming IPC and other unrelated entities as defendants.
Plaintiffs allege that IPC's ownership interest in certain land , minerals, water or other resources was converted and fraudulently
conveyed from lands in which the plaintiffs had historical ownership rights and Indian title dating back to the 1860's or before.
Although it is unclear from the complaint, it appears plaintiffs' claims relate primarily to lands within the state of Nevada. Plaintiffs
seek a judgment declaring their title to land and other resources, disgorgement of profits from the sale or use of the land and resources,
a decree declaring a constructive trust in favor of the plaintiffs of IPC's assets connected to the lands or resources, an accounting of
money or things of value received from the sale or use of the lands or resources, monetary damages in an unspecified amount for waste
and trespass and a judgment declaring that IPC has no right to possess or use the lands or resources.
On May 1,2006, IPC filed an Answer to plaintiffs' First Amended Complaint denying all liability to the plaintiffs and asserting certain
affirmative defenses including collateral estoppel and res judicata, preemption, impossibility and impracticability, failure to join all
I FERC FORM NO.1 (ED. 12-88)Page 123.
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(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
real and necessary parties, and various defenses based on untimeliness. On June 19,2006, IPC filed a motion to dismiss plaintiffs
First Amended Complaint, asserting, among other things, that the Court lacks subject matter jurisdiction and that plaintiffs failed to
join an indispensable party (namely, the United States government). Briefing on the motion to dismiss was completed on September
28,2006. Newly decided authority from the United States Court of Federal Claims in further support of lPC's motion to dismiss was
filed on January 3, 2007. The Court has yet to act on the IPC motion to dismiss, IPC intends to vigorously defend its position in this
proceeding, but is unable to predict the outcome of this matter.
Sierra Club Lawsuit - Bridger: In February 2007, the Sierra Club and the Wyoming Outdoor Council filed a complaint against
PacifiCorp in federal district court in Cheyenne, Wyoming for alleged violations of the Clean Air Act's opacity standards (alleged
violations of air pollution permit emission limits) at the Jim Bridger coal fired plant ("Plant") in Sweetwater County, Wyoming. IPC
has a one-third ownership interest in the Plant. PacifiCorp owns a two-thirds interest and is the operator of the Plant. The complaint
alleges thousands of violations and seeks declaratory and injunctive relief and civil penalties of $32,500 per day per violation as well
as the costs of litigation, including reasonable attorney fees. IPC believes there are a number of defenses to the claims and intends
vigorously defend its interest in this matter, but is unable to predict its outcome and is unable to estimate the impact this may have on
its consolidated financial positions, results of operations or cash flows.
8. STOCK-BASED COMPENSATION:
IDACORP has three share-based compensation plans. IDACORP's employee plans are the 2000 Long-Term Incentive and
Compensation Plan (LTICP) and the 1994 Restricted Stock Plan (RSP). These plans are intended to align employee and shareholder
objectives related to IDACORP's long-term growth. IDACORP also has one non-employee plan, the Director Stock Plan (DSP). The
purpose of the DSP is to increase directors' stock ownership through stock-based compensation.
The LTICP for officers, key employees and directors permits the grant of nonqualified stock options, incentive stock options, stock
appreciation rights, restricted stock, restricted stock units, performance units, performance shares and other awards. The RSP permits
only the grant of restricted stock or performance-based restricted stock. At December 31, 2006, the maximum number of shares
available under the LTICP and RSP were 1 688 562 and 104,325, respectively.
The following table shows the compensation cost recognized in income and the tax benefits resulting from these plans, as well as the
amounts allocated to IPC for those costs associated with IPC's employees (in thousands of dollars):
Compensation cost
Income tax benefit
2006
1,458
570
2005
178
No equity compensation costs have been capitalized.
Stock awards: Restricted stock awards have vesting periods of up to four years. Restricted stock awards entitle the recipients to
dividends and voting rights, and unvested shares are restricted to disposition and subject to forfeiture under certain circumstances. The
fair value of restricted stock awards is measured based on the market price of the underlying common stock on the date of grant and
charged to compensation expense over the vesting period based on the number of shares expected to vest.
Performance-based restricted stock awards have vesting periods of three years. Performance awards entitle the recipients to voting
rights, and unvested shares are restricted to disposition, subject to forfeiture under certain circumstances, and subject to meeting
specific performance conditions. Based on the attainment of the performance conditions, the ultimate award can range from zero to
150 percent of the target award. For awards granted prior to 2006, dividends were paid to recipients at the time they were paid on the
common stock. Beginning with the 2006 awards, dividends are accumulated and will be paid out only on shares that eventually vest.
The performance goals for the 2006 awards are independent of each other and equally weighted, and are based on two metrics
cumulative earnings per share (CEPS) and total shareholder return (TSR) relative to a peer group. The fair value of the CEPS portion
is based on the market value at the date of grant, reduced by the loss in time-value of the estimated future dividend payments, using an
expected quarterly dividend of $0.30. The fair value of the TSR portion is estimated using a statistical model that incorporates the
IFERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
probability of meeting perfo1l11ance targets based on historical returns relative to the peer group. Both performance goals are measured
over the three-year vesting period and are charged to compensation expense over the vesting period based on the number of shares
expected to vest.
A summary of restricted stock and performance share activity is presented below. IPC share amounts represent the portion of
IDACORP amounts related to IPC employees:
Nonvested shares at December 31 , 2004
Shares granted
Shares forfeited
Shares vested
Nonvested shares at December 31, 2005
Shares granted
Shares forfeited
Shares vested
Nonvested shares at December 31, 2006
Number of
Shares
120,323
87,620
(24 804)
(251 )
182 888
112 146
(91,538)
(19 200)
184,296
Weighted-
average
Grant date
Fair value
$ 30.
29.
38.
31.21
28.
25.
26.
30.39
28.32
At December 31, 2006, IDACORP had $1.9 million of total unrecognized compensation cost related to nonvested share-based
compensation that was expected to vest. IPC's share of this amount was $1,7 million. These costs are expected to be recognized over
a weighted-average period of 1.91 years. IDACORP uses original issue and/or treasury shares for these awards.
Stock options: Stock option awards are granted with exercise prices equal to the market value of the stock on the date of grant. The
options have a term of 10 years from the grant date and vest over a five-year period. Upon adoption of SFAS I 23(R) on January 1
2006, the fair value of each option is amortized into compensation expense using graded-vesting. Beginning in 2006, stock options are
not a significant component of share-based compensation awards under the LTICP.
The fair values of all stock option awards have been estimated as of the date of the grant by applying a binomial option pricing model.
The application of this model involves assumptions that are judgmental and sensitive in the determination of compensation expense,
The following key assumptions were used in determining the fair value of options granted:
Dividend yield, based on current dividend and stock price on grant date
Expected stock price volatility, based on IDACORP historical volatility
Risk-free interest rate based on u.S. Treasury composite rate
ected term based on the SEC "sim lified" method
2006
18%
92%
50 years
2005
23%
22%
ears
IPC's stock option transactions are summarized below. IPC share amounts represent the portion of IDACORP amounts related to IPC
employees:
Weighted
W eighted-Average Aggregate
Number Average Remaining Intrinsic
Exercise Contractual Value
Shares Price Term (OOOs)
952 600 32.38 371
157 837 29.
Outstanding at December 31, 2004
Granted
Exercised
IFERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Forfeited (16 300)30.
ired
Outstanding at December 31 , 2005 094 137 32.
Granted
Exercised (320 821)29,
Forfeited (142 625)28,
ired (11,600)39.
Outstanding at December 31, 2006 619,091 33.
Vested or expected to vest at December 31 , 2006 603 152 33.
Exercisable at December 31, 2006 407,826 36.
634
385
227
292
The following table presents information about options granted and exercised (in thousands of dollars, except for weighted-average
amounts):
Weighted-average grant-date fair value
Fair value of options vested
Intrinsic value of options exercised
Cash received from exercises
Tax benefits realized from exercises
IPC
2006 2005
275 390
883
614
127
As of December 31, 2006, there was $0.3 million of total unrecognized compensation cost related to stock options. These costs are
expected to be recognized over a weighted average period of 2.51 years. IDACORP uses original issue and/or treasury shares to
satisfy exercised options.
9. BENEFIT PLANS:
SFAS 158
In December 2006 IPC adopted the recognition provisions of Statement of Financial Accounting Standards No. 158, "Employers
Accounting for Defined Benefit Pension Plans and Other Postretirement Plans - an amendment ofFASB Statements No. 87, 88, 106,
and 132(R).
The following table presents the incremental effect of applying SFAS 158 on individual line items in the Consolidated Balance Sheets
of IPC at December 31 , 2006:
13 , 444
377,367
42,979
3,404,805
Adjustments
(thousands of dollars)
(4,136) $
46,181
(1,720)
40,325
After
Application of
Statement 158
Before
Application of
Statement 158
Prepayments
Noncurrent regulatory assets
Other current assets
Total assets
308
423,548
41,259
445 130
Other current liabilities
Noncurrent deferred income taxes
Other liabilities
Total other liabilities
21,197
504 260
133,122
940,999
375
(5,748)
46,714
40,966
572
498,512
179,836
981 965
I FERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmisslon 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Accumulated other comprehensive income (loss)
Total shareholders' equity
721)
127 199
(3,016)
(3,016)
(5,737)
124,183
In accordance with regulatory accounting treatment under SF AS 71, amounts that otherwise would have been recorded in accumulated
other comprehensive income have been recorded as regulatory assets for both the pension and postretirement plans.
The measurement provisions of SFAS 158 are not required to be adopted until 2008 and require that a company measure its plan assets
and benefit obligations as of its balance sheet date. IPC already uses a December 31 measurement date for its plans, so adoption of the
measurement provisions of SFAS 158 is not expected to have a material effect on IPC's results of operations or cash flows.
Pension Plans
IPC has a noncontributory defined benefit pension plan covering most employees. The benefits under the plan are based on years of
service and the employee s final average earnings. IPC's policy is to fund, with an independent corporate trustee, at least the minimum
required under the Employee Retirement Income Security Act of 1974 (ERISA) but not more than the maximum amount deductible for
income tax purposes. IPC was not required to contribute to the plan in 2006 or 2005. The market-related value of assets for the plan is
equal to the fair value of the assets. Fair value is determined by utilizing publicly quoted market values and independent pricing
services depending on the nature of the asset, as reported by the trustee/custodian of the plan.
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.
The following table summarizes the changes in benefit obligations and plan assets of these plans:
Pension Plan Deferred Compensation Plan
2006 2005 2006 2005
(thousands of dollars)
Change in benefit obligation:
Benefit obligation at January I 406,049 374 333 723 645
Service cost 14,476 129 473 170
Interest cost 22,340 21,126 327 151
Actuarial loss (gain)827)399 857)799
Benefits paid (14 439)(13 938)352)(2,312)
Plan amendments 552 270
Benefit obligation at December 31 425 599 406 049 41,866 723
Change in plan assets:
Fair value at January I 368 053 356,217
Actual return on plan assets 310 25,774
Employer contributions
Benefit payments (14,439)(13,938)
Fair value at December 31 400,924 368,053
Unfunded status at end of year (24 675)(37,996)(41,866)(42 723)
Unrecognized actuarial loss 43,806 13,553
Unreco nIzed rior service cost 118 1,414
Net amount recognized (24 675)10,928 (41,866)(27,756)
Amounts recognized in the statement of
financial position consist of:
Current liabilities 375)
FERC FORM NO.ED. 12-88 Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Noncurrent liabilities (24 675)(39,491)
Prepaid (accrued) pension cost 10,928 (39,268)
Intangible asset 1,414
Accumulated other comprehensive income 10,098
Net amount recognized (24,675)10,928 (41 866)(27 756)
Amounts recognized in accumulated other
comprehensive Income consist of:
Net loss 356 853
Prior service cost 4,455 720
Subtotal 28,811 573
Less amount recorded as regulatory asset (28,811)
Net amount recognized in accumulated
other com rehensive income 573
Accumulated benefit obligation 350,434 340,007 38,634 39,268
The following table shows the components of net periodic benefit cost for these plans:
Pension Plan Deferred Com ensation Plan
2006 2005 2006 2005
(thousands of dollars)
Service cost 14,476 129 1,473 170
Interest cost 340 126 327 151
Expected return on assets (30 817)(29,690)
Amortization of net loss 129 844 689
Amortization of prior service cost 664 771 245 228
Amortization of transition asset (126)310
Net periodic pension cost 792 210 889 548
Changes in the Deferred Compensation Plan minimum liability increased other comprehensive income by $2 million in 2006 (prior to
the effect of adopting SFAS 158), decreased other comprehensive income by $1 million in 2005.
In 2007, IPC expects to recognize as components of net periodic benefit cost $1.4 million from amortizing amounts recorded in
accumulated other comprehensive income as of December 31 , 2006, relating to the pension and deferred compensation plans. This
amount consists of $0,6 million of prior service cost for the pension plan and $0.6 million of net loss and $0.2 million of prior service
cost for the deferred compensation plan.
The following table summarizes the expected future benefit payments of these plans:
Pension Plan
Deferred Compensation Plan
2007 2008 2009 2010 2011 2012-2016
$ 15 070 $ 16,127 $ 17,354 $ 18 858 $ 20,462 $ 133,740
$ 2 438 $ 2,546 $ 2,797 $ 2,997 $ 3,059 $ 16 963
Plan Asset Allocations: IPC's pension plan and postretirement benefit plan weighted average asset allocations at December 31, 2006
and 2005, by asset category are as follows:
Asset Category
I FERC FORM NO.1 (ED. 12-88)
Pension
Plan2006 2005
Postretirement
Benefits2006 2005
Page 123,
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Equity securities 68% 66%Debt securities 24 Real estate Other (a) 100Total 100% 100% 100%
(a) The postretirement benefit plan assets are primarily life insurance contracts.
100
100%
Pension Asset AUocation 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
Micro-Cap Stocks
Cash and Cash Equivalents
12%
12%
12%
International Growth Stocks
International Value Stocks
Intermediate- Term Bonds
Short-Term Bonds
Core Real Estate
Private Equity
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 ofrealized 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.
Allowable plan investments include stocks and stock funds, investment-grade bonds and bond funds, core real estate funds, private
equity funds, and cash and cash equivalents. With the exception of real estate holdings and private equity, investments must be readily
marketable so that an entire holding can be disposed of quickly with only a minor effect upon market price. Uncovered options, short
sales, margin purchases, letter stock and commodities are prohibited.
Rate-of-return projections for plan assets are based on historical risk/return relationships among asset classes. The primary measure is
the historical risk premium each asset class has delivered versus the return on lO-year U.S. Treasury Notes. This historical risk
premium is then added to the current yield on 10-year u.S. Treasury Notes, and the result provides a reasonable prediction of future
investment performance. Additional analysis is performed to measure the expected range of returns, as well as worst-case and
best-case scenarios. Based on the current low interest rate environment, current rate-of-return expectations are lower than the nominal
returns generated over the past 20 years when interest rates were generally much higher.
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. This
worst-case" modeling, in addition to cash flow matching and diversification by asset class and investment style, provides the basis for
managing the risk associated with investing portfolio assets.
Postretirement Benefits
IPC maintains a defined benefit postretirement plan (consisting of health care and death benefits) that covers all employees who were
enrolled in the active group plan at the time of retirement as well as their spouses and qualifying dependents, Benefits for employees
who retire after December 31 2002, are limited to a fixed amount, which wilIlimit the growth of IPC's future obligations under this
I FERC FORM NO.1 (ED. 12-88) Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
NOTES TO FINANCIAL-STATEMENTS (Continued)
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
Amortization of prior service cost
Amortization of net loss
Net periodic postretirement benefit cost
2006
1,463
3,426
(2,523 )
040
(535)
812
683
2005
392
381
486)
040
(535)
754
546
The folloWIng table summarizes the changes in benefit obligation and plan assets (in thousands of dollars):
2006 2005
Change in accumulated benefit obligation:
Benefit obligation at January I 63,633 105
Service cost 463 392
Interest cost 426 381
Actuarial (gain) loss (2,445)(9,186)
Benefits paid (3,164)(2,934)
Plan amendments (125)
Benefit obligation at December 31 913 633
Change in plan assets:
Fair value of plan assets at January I 29,893 29,723
Actual return on plan assets 158 127
Employer contributions 004 800
Benefits paid (2,428)(1,757)
Fair value of lan assets at December 31 32,627 893
Funded status at end of year (30,286)(33,740)
UnrecognIzed prior serVIce cost (3,677)
Unrecognized actuarial loss 15,978
Unrecognized transition obligatIOn 280
Accrued benefit obligations included in nonCUITent liabilities (30,286)159)
Amounts recognized in accumulated other comprehensive income consist of:
Net loss
Prior service cost (credit)
Transition obligation
Subtotal
Less amount recognized in regulatory assets
Less amount included in deferred tax assets
Net amount recognized in accumulated other comprehensive income
086
142)
240
21,184
(17,370)
814)
In 2007, IPC expects to recognize as components of net periodic benefit cost $2.0 million from amortizing amounts recorded in
accumulated other comprehensive income as of December 31 , 2006 relating to the postretirement plan. This amount consists of $0.5
million of net loss, ($0.5) million of prior service cost and $2.0 million of transition obligation.
IFERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Medicare Act: The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Act) was signed into law in
December 2003 and established a prescription drug benefit, as well as a federal subsidy to sponsors of retiree health care benefit plans
that provide a prescription drug benefit that is at least actuarially equivalent to Medicare s prescription drug coverage. The measure of
net periodic benefit cost for the year ended December 31, 2004 does not reflect any amount associated with the subsidy.
The following table summarizes the expected future benefit payments of the postretirement benefit plan and expected Medicare Part D
subsidy receipts (in thousand of dollars):
2007 2008 2009 2010 2011 2012-2016
Expected benefit 100 200 300 500 700 25,300
payments*
Expected Medicare Part D
subsidy receipts 600 600 700 800 800 200
*Expected benefit payments are net of expected Medicare Part D subsidy receipts.
The assumed health care cost trend rate used to measure the expected cost of benefits covered by the plan was 6.75 percent in 2006
and 2005. A one-percentage point change in the assumed health care cost trend rate would have the following effect (in thousands of
dollars):
1- Percentage-Pointincrease decrease
Effect on total of cost components
Effect on accumulated postretirement benefit obligation
258
2,409
(195)
(1,897)
The following table sets forth the weighted-average assumptions used at the end of each year to determine benefit obligations for all
IPC-sponsored pension and postretirement benefits plans:
Discount rate
Expected long-term rate of return on assets
Rate of compensation increase
Medical trend rate
Expected working lifetime (years)
Pension
Benefits2006 200585% 5.5% 8.5% 4.
Postretirement
Benefits2006 200585% 5.5% 8.
75%75%
The following table sets forth the weighted-average assumptions used to determine net periodic benefit cost for all IPC-sponsored
pension and postretirement benefit plans:
Discount rate
Expected long-term rate of return on assets
Rate of compensation increase
Medical trend rate
Expected working lifetime (years)
Pension
Benefits2006 20056% 5.75%5% 8.5% 4.
Employee Savings Plan
IFERC FORM NO.1 (ED. 12-88)Page 123.
Postretirement
Benefits2006 20056% 5.75%5% 8.
75%75%
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
IPC has an Employee Savings Plan that complies with Section 40 I (k) of the Internal Revenue Code and covers substantially all
employees. IPC matches specified percentages of employee contributions to the plan. Matching contributions amounted to $4 million
in both 2006 and 2005.
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. The post
employment benefit amounts included in other deferred credits on IPC's consolidated balance sheets at December 31 are $4.0 million
and $3.8 million for 2006 and 2005, respectively.
10. 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 2006 and 2005 (in thousands of dollars):
2006 2005
Balance Avg Rate Balance Avg Rate
Production 592,790 2.55%563 008 54%
TransmissIOn 606,947 580,382
Distribution 097 390 046,880
General and Other 286 567 286,797
Total in service 583,694 75%3,477,067 91%
Accumulated provision for depreciation (l,406,21O)364,640)
In service - net 177 ,484 112,427
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, IPC's proportionate share of direct operation and
maintenance expenses applicable to the projects is included in the Consolidated Statements of Income. These facilities, and the extent
of lPC's participation , were as follows at December 31 , 2006 (in thousands of dollars):
Utility Construction Accumulated
Plant In Work in Provision for
Name of Plant Location Service Progress Depreciation
Jim Bridger Units 1-Rock Springs, WY 468,032 890 270 302 707
Boardman Boardman, OR 69,109 476 47,284
Valmy Units 1 and 2 Winnemucca, NV 316,075 10,527 203,188 261
IPC's wholly-owned subsidiary, Idaho Energy Resources Co., is a joint venturer in Bridger Coal Company, which operates the mine
supplying coal to the Jim Bridger generating plant. lPC's coal purchases from the joint venture were $52 million and $43 million in
2006 and 2005, respectively.
IPC has contracts to purchase the energy from four PURPA qualified facilities that are 50 percent owned by Ida-West. lPC's power
purchases from these facilities were $8 million in 2006 and $7 million annually in 2005.
n. REGULATORY MATTERS:
Regulatory Assets and Liabilities
The following is a breakdown of IPC's regulatory assets and liabilities (in thousands of dollars):
As of December 31, 2006
As 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 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Remaining Not Pending December
Amortization Earning Earning Regulatory 2006 2005
Descri tion Period a Return a Return Treatment Total Total
Regulatory Assets:
Income Taxes 343 590 $
- $
343,590 $346,117
SFAS 158 (l)46,181 46,181
Conservation 2010 349 349 592
PCA Deferral 32,251
Oregon Deferral (2)559 559 29l
Asset Retirement
Obligations (3)206 Il,206 363
Tax Settlement 994
Order
Grid West Loans 932 302 290
Various
Other thru 2008 390 463 853 633
Total 354 403,372 $302 $425,028 $418,241
Regulatory Liabilities:
Income Taxes 825 $
- $
4l,825 $627
Conservation 2007 328 328 6,535
PCA Accrual (4)2007 (11 852)27,025 15,173
Asset Retirement
Obligations (3)156 162 156 162 152,683
Deferred ITC 69,114 69,114 68,786
IPUC Settlement
Order 021
BPA Settlement 124 124 393
EmIssion Allowance 118 118 70,034
Various
Other thru 2007
Total (3,400) $294,126 $118 $294,844 $345,109
(I )See Note 9
(2) Capped at 10 percent increase per year.
(3)See Note 14
(4)Includes $69 million of emission allowances, of which $42.1 million earns a return and $27,0 million does
not.
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 investments. If IPC is not
allowed recovery of these investments, it would be required to write off the applicable portion of regulatory assets and the financial
effects could be significant.
Deferred Power Supply Costs
Idaho: 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.
Idaho Load Growth Adjustment Rate (LGAR): In April 2006 IPC filed a petition with the IPUC requesting modification of one
IFERC FORM NO.1 (ED. 12-88) Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
component of its PCA referred to as the Load Growth Adjustment Rate. The LGAR subtracts the cost of serving new Idaho retail
customers from the power supply costs IPC is allowed to include in its PCA.
The LGAR was set at $16.84 per megawatt-hour when the PCA began in 1993, This amount was established as the projected marginal
cost of serving each new customer and is subtracted from each year s PCA expense. In its April 2006 petition, IPC requested using the
embedded cost of serving the new load rather than the projected marginal cost and to lower the rate to $6.81 per megawatt-hour. The
IPOC Staff recommended against changing to the embedded cost approach; IPOC Staff also recommended increasing the rate to
$40.87 per megawatt hour.
On January 9, 2007, the IPOC issued its final order in this matter. The IPOC maintained the marginal cost methodology and set the
new LGAR at $29.41 per megawatt-hour. The new rate becomes effective on April 1, 2007 and will first affect customer rates on June
2008.
The impact of the new LGAR on IPC will ultimately be determined by future load growth. Assuming an average 40 megawatt load
growth, the new rate would result in approximately $10.3 million subtracted from the next PCA, a pre-tax increase of $4.4 million over
the current amount. The impact of the new LGAR can be partially offset by IPC through more frequent general rate case filings with
the IPOC or from less customer growth. In its order the IPOC stated that it expected IPC to update its load growth adjustment in all
future general rate cases.
Oregon: The timing of recovery of Oregon power supply cost deferrals is subject to an Oregon statute that specifically limits rate
amortizations of deferred costs to six percent per year. IPC is currently amortizing through rates power supply costs associated with
the western energy situation of 200 I. Full recovery of the 2001 deferral is not expected until 2009. For the 2005-2006 deferral, a
settlement stipulation drafted by the OPOC Staff provides that, instead of being amortized into rates, the deferral should be offset with
the Oregon jurisdictional share of proceeds from the sale of S02 emission allowances and the benefit that IPC will receive from
income taxes already paid on the sale of those allowances. An order is expected from the OPUC during the first quarter of 2007.
Emission Allowances: During 2005 and 2006, IPC sold 78,000 S02 emission allowances for approximately $81.6 million (before
income taxes and expenses) on the open market. After subtracting transaction fees, the total amount of sales proceeds to be allocated
to the Idaho jurisdiction was approximately $76.8 million ($46.8 million net of tax, assuming a tax rate of approximately 39 percent).
The IPOC allowed IPC to retain ten percent, or approximately $4.7 million after tax, of the emission allowance net proceeds as a
shareholder benefit. The remaining 90 percent of the sales proceeds ($69.1 million) plus a carrying charge will be recorded as a
customer benefit. This customer benefit will be reflected in PCA rates during the June 1 2007, through May 31 , 2008, PCA rate year.
The carrying charge will be calculated on $42.1 million, the net-of-tax amount allocable to Idaho jurisdiction customers.
As discussed above, a stipulation is currently before the OPUC which would offset S02 emission allowance proceeds against the
2005-2006 balance of Oregon deferred power supply costs. The stipulation allows for IPC to retain ten percent of the proceeds from
emission allowance sales as a shareholder benefit.
Through allowance year 2006, IPC has approximately 36,000 excess allowances.
Deferred (Accrued) Net Power Supply Costs:
IPC's deferred net power supply costs consisted of the following at December 31 (in thousands of dollars):
Idaho PCA current year:
Deferral for the 2006-2007 rate year
Accrual for the 2007-2008 rate year*
Idaho PCA true-up awaiting recovery (refund):
Authorized May 2005
Authorized May 2006
Oregon deferral:
2001 costs
2005 costs
2006 2005
684
(3,484)
28,567
(11 689)
670 8,411
889 880
Page 123.I FERC FORM NO.1 (ED. 12-88)
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Total (accrual) deferral $ (5,614) $ 43,542
*Includes $69 million of emission alIowance sales to be credited to the customers during the 2007-2008
PCA year
Fixed Cost Adjustment Mechanism (FCA)
On January 27, 2006, IPC filed with the IPUC for authority to implement a rate adjustment mechanism that would adjust rates
downward or upward to recover fixed costs independent from the volume of IPC's energy sales. This filing is a continuation of a 2004
case that was opened to investigate the financial disincentives to investment in energy efficiency by IPC. This true-up mechanism
would be applicable only to residential and small general service customers. The first FCA rate change under this proposal would
occur on June 1 2007, coincident with IPC's PCA rate change. The accounting for the FCA will be separate from the PCA. As part
of the filing, IPC proposes a three percent cap on any rate increase to be applied at the discretion of the IPUe.
On March 6, 2006, the IPUC reviewed IPC's proposal and acknowledged the intent of IPC and the IPUC Staff to initiate and engage in
settlement discussions. The IPUC Staff presented an alternate view of IPC' s proposal. Three workshops were held in 2006 and the
parties have agreed in concept to a three-year pilot beginning at the first of the year and a stipulation was filed December 18, 2006.
The stipulation calIs for the implementation of a FCA mechanism pilot program as proposed by IPC in its original application with
additional conditions and provisions related to customer count and weather normalization methodology, recording of the FCA deferral
amount in reports to the IPUC and detailed reporting of DSM activities. The pilot program began on January I , 2007, and will run
through 2009, with the first rate adjustment to occur on June I, 2008, and subsequent rate adjustments to occur on June 1 of each year
thereafter during the term of the pilot program. The deadline for filing written comments with respect to the stipulation and the use of
modified procedure was January 31 , 2007. A final order is expected from the IPUC in the first quarter of 2007.
12. INVESTMENTS:
The following table summarizes IPC's investments as of December 31 (in thousands of dollars):
Investments:
Equity method investment
A vailable-for-sale equity securities
Executive deferred compensation
Other investments
Total investments
2006 2005
223 38,764
21,548 21,137
492 201
025
267 127
Equity Method Investments
IPC, through its subsidiary Idaho Energy Resources Co., 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 IPC's earnings of unconsolidated equity-method investments (in thousands of dolIars):
Bridger Coal Company
2006$ 9,347
2005
$ 10,369
The folIo wing table presents summarized income statement information for Bridger Coal Company (in thousands of dollars):
Operating revenues
Operating expenses
Net Income
2006 2005
154 910 128 015
126 869 909
28,041 31,106
Page 123.I FERC FORM NO.1 (ED. 12-88)
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
The following table presents summarized balance sheet information for Bridger Coal Company (in thousands of dollars):
2006 2005
Assets
Current assets 47,723 26,442
Noncurrent assets 325 252 262,909
Total Assets 372,975 289,351
Liabilities
Current liabilities 28,250 17,728
Noncurrent liabilities 158 054 155 330
Total Liabilities 186 304 173 058
Joint venture ca ital 186,671 116,293
Total Liabilities and Joint Venture Capital 372,975 289,351
Investments in Debt and Equity Securities
Investments in debt and equity securities are accounted for in accordance with SFAS 115, "Accounting for Certain Investments in Debt
and Equity Securities." Those investments classified as availab1e-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 umealized gains or losses on available-for-sale
securities are included in other comprehensive income.
The following table summarizes investments in equity securities (in thousands of dollars):
2006 2005
Gross Gross Gross Gross
Unrealized Unrealized Fair Unrealized Unrealized Fair
Gain Loss Value Gain Loss Value
A vai1able- for-sale securities 2,474 $322 $21,548 $925 $497 $21,137
The following table summarizes sales of available-for-sale securities (in thousands of dollars):
2006 2005 2004
Proceeds from sales 20,778 120 026 266 331
Gross realized gains from sales 774 850 044
Gross realized losses from sales 280 643 634
Additionally, these investments are evaluated to determine whether they have experienced a decline in market value that is considered
other-than-temporary. IPC analyzes securities in loss positions as of the end of each reporting period. Any security with an umealized
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 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 has not recognized any other-than-temporary impairments in 2006 or 2005.
The following table summarizes information regarding securities that were in an umealized loss position at the end of each year, but
for which no other-than-temporary impairment was recognized (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 Resubmisslon 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Less than 12 monthsAggregate AggregateUnrealized Related FairLoss Value
12 months or longerAggregate Aggregate
Unrealized Related FairLoss Value
2006:
A vailable for sale equity securities 241 879 $621
2005:
Available for sale equity securities 215 731 282 1,423
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. At December 31 , 2006, II available-for-sale in an unrealized loss position.
None of these securities had unrealized loss positions of greater than 20 percent. At December 31,2005, nine available-for-sale were
in an unrealized loss position. Two available-for-sale securities had unrealized loss positions of greater than 20 percent. IPC does not
consider these investments to be other-than-temporarily impaired at December 31, 2006 or 2005.
13. ASSET RETIREMENT OBLIGATIONS:
On January 1 2003 , IPC adopted SFAS 143
, "
Accounting for Asset Retirement Obligations," requiring legal obligations associated
with the retirement of property, plant and equipment to be recognized as a liability at fair value when incurred and when a reasonable
estimate of the fair value of the liability can be made. Under SFAS 143, when a 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. As a rate-regulated entity, IPC records
regulatory assets and liabilities instead of accretion, depreciation and gains or losses. This treatment was approved by Order No.
29414 from the IPUC. The regulatory assets recorded under this order do not earn a return on investment.
On December 31, 2005, IPC adopted FIN 47, which clarifies the scope and timing of liability recognition for conditional asset
retirement obligations (AROs). The interpretation requires that a liability be recorded for the fair value of an ARO, if the fair value is
estimable, even when the obligation is dependent on a future event. FIN 47 further clarified that uncertainty surrounding the timing
and method of settlement of the obligation should be factored into the measurement of the conditional ARO rather than affect whether
a liability should be recognized.
Upon adoption of FIN 47, two AROs were identified at IPC. The obligations at IPC are the result of PCB removals at its distribution
facilities and the reclamation and removal costs of one of its jointly owned coal-fired generation facilities. These AROs were recorded
in March 2006 when they became measurable. IPC recorded an ARO liability of $2.2 million, fixed assets of $0.5 million,
accumulated depreciation of $0.4 million and a regulatory asset of $2.1 million.
Other AROs previously identified and recorded under FAS 143 relate to removal costs identified at two of IPC's jointly owned
coal-fired generation facilities. IPC has AROs associated with its transmission system and hydro facilities, however, due to the
indeterminate removal date, the fair value of the associated liabilities currently cannot be estimated and no amounts are recognized in
the consolidated financial statements.
The regulated operations of IPC also collect removal costs in rates for certain assets that do not have associated AROs. The adoption
of SFAS 143 required IPC to redesignate these removal costs as regulatory liabilities. As of December 31, 2006, IPC had $156
million of such costs recorded as regulatory liabilities on its Consolidated Balance Sheet.
The following table presents the changes in the aggregate carrying amount of AROs (in thousands of dollars):
Balance at beginning of year
I FERC FORM NO.1 (ED. 12-88)
2006
10,079
2005$ 9,288
Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Accretion expense
Revisions in estimated cash flows
Liability incurred
Balance at end of year
628 531
260
204
911 079
14. RELATED PARTY TRANSACTIONS (IPC):
IDACORP
IPC performs corporate functions such as financial, legal and management services for IDACORP and its subsidiaries. IPC charges
IDACORP for the costs of these services based on service agreements and other specifically identified costs. IPC billed IDACORP $4
million in 2006 and 2005 for these services.
IDACOMM
IPC provides project management and engineering services to IDACOMM. IDACOMM also pays joint use fees to IPc. Total fees
charged to IDACOMM were $0.1 million in 2006 and $0.3 million in 2005.
Ida-West
IPC purchases all of the power generated by four of Ida-West's hydroelectric projects. IPC paid $8 million in 2006 and $7 million per
year in 2005 and 2004.
15. OTHER INCOME AND EXPENSE:
The following table presents the components of Other Income and Other Expense (in thousands of dollars):
2006 2005
Other income:
Allowance for funds used during construction-equity 092 950
Investment income, net 8,489 6,424
Gain on extinguishment of debt
Other 614 747
Total 18,195 121
Other expense:
Security plan pension expense 889 548
Other 670 3,458
Total 559 006
IFERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2006/Q4
(2) Ei A Resubmission 04/18/2007
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, A~ D HEDGING ACTIVITIES
1, Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate.
2. Report in columns (f) and (g) the amounts of other categories of other cash flow hedges.
3. For each category of hedges that have been accounted for as "fair value hedges , report the accounts affected and the related amounts in a footnote.
Line Item Unrealized Gains and Minimum Pension Foreign Currency Other
No.Losses on Available-Liability adjustment Hedges Adjustments
for-Sale Securities (net amount)
(a)(b)(c)(d)(e)
1 Balance of Account 219 at Beginning of
Preceding Year 537 792)5,425,566
2 Preceding QtrNr to Date Reclassifications
from Acct 219 to Net Income 1 ,355,332
3 Preceding QuarterNear to Date Changes in
Fair Value 457 455 724 764
4 Total (lines 2 and 3)812 787 724 764
5 Balance of Account 219 at End of
Preceding QuarterNear 725 005)150 330
6 Balance of Account 219 at Beginning of
Current Year 725,005)150 330
7 Current QtrNr to Date Reclassifications
from Acct 219 to Net Income 127,497
8 Current Quarter/Year to Date Changes in
Fair Value 713,442)150 330)048 073
9 Total (lines 7 and 8)1,414 055 150 330)048,073
Balance of Account 219 at End of Current
QuarterNear 310,950)048 073
FERC FORM NO.1 (NEW 06-02)Page 122a
Name of Respondent This R ort Is: Date of Report Year/Period of Report(1) An Original (Mo, Da, Yr) End 2006/04Idaho Power Company (2) DA Resubmission 04/18/2007
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, A D HEDGING ACTIVITIES
Line
No.
Other Cash Flow
Hedges
Interest Rate Swaps
Other Cash Flow
Hedges
(Specify)
Totals for each
category of items
recorded in
Account 219
(h)(f)
(g)
887 774
1 ,355,332
182 219
537 551
3,425 325
3,425,325
127,497
184 301
311 798
737 123
FERC FORM NO.1 (NEW 06-02)Page 122b
Net Income (Carried
Forward from
Page 117, Line 78)
Total
Com prehensive
Income
(i)
This Page Intentionally Left Blank
IS ~o s: a e 0 epo(1) ~An Original (Mo, Da, Yr)(2) A Resubmission 04/18/2007
SUMMA Y OF UTILITY PLANT AND ACCUM LATED PROVISIONS
FOR DEPRECIATION, AMORTIZATION AND DEPLETION
Report in Column (c) the amount for electric function, in column (d) the amount for gas function, in column (e), (f), and (g) report other (specify) and in
column (f) common function.
End of
(a)
Total Company for the
Current Year/Quarter Ended
(b)
Electric
(c)
Line
No.
Classification
1 Utility Plant
2 In Service
3 Plant in Service (Classified)
4 Property Under Capital Leases
5 Plant Purchased or Sold
----
584 148,359 584 148,359
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
584 148 359 584 148 359
809 770
210,094 019
454 449
796 597 699
1,406 209,952
390 387 747
809,770
210 094,019
454 449
796,597 699
1,406,209,952
390,387 747
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 26,32)
----------"
-327 581
1 ,406,209,952
327 581
1 ,406 209 952
FERC FORM NO.1 (ED. 12-89)Page 200
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2006/04
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) A Resubmission 04/18/2007
ELECTRI 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 ccount a ance ItlonsNo. Beginning of Year
1 1. INTANGIBLE PLANT
2 (301) Organization
3 (302) Franchises and Consents
4 (303) Miscellaneous Intangible Plant
5 TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)
6 2. PRODUCTION PLANT
7 A. Steam Production Plant
8 (310) Land and Land Rights
9 (311) Structures and Improvements
10 (312) Boiler Plant Equipment
11 (313) Engines and En ine-Driven Generators
12 (314) Turbo enerator Units
13 (315) Accesso Electric Equipment
14 (316) Misc. Power Plant Equipment
15 (317) Asset Retirement Costs for Steam Production
16 TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)
17 B. Nuclear Production Plant
18 (320) Land and Land Rights
19 (321) Structures and Improvements
20 (322) Reactor Plant Equipment
21 (323) Turbogenerator Units
22 (324) Accessory Electric Equipment
23 (325 Misc. Power Plant Equipment
24 (326) Asset Retirement Costs for Nuclear Production
25 TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24)
26 C. H draulic Production Plant
27 (330) Land and Land Rights
28 (331) Structures and Improvements
29 (332) Reservoirs, Dams, and Waterways
30 (333) Water Wheels, Turbines, and Generators
31 (334) Accesso Electric Equipment
32 (335) Misc. Power Plant Equipment
33 (336) Roads, Railroads, and Bridges
34 (337) Asset Retirement Costs for Hydraulic Production
35 TOTAL H draulic Production Plant (Enter Total of lines 27 thru 34)
36 D. Other Production Plant
37 (340) Land and Land Rights
38 (341) Structures and Improvements
39 (342) Fuel Holders, Products, and Accessories
40 (343) Prime Movers
41 (344) Generators
42 (345) Accessory Electric Equipment
43 (346 Misc. Power Plant Equipment
44 (347) Asset Retirement Costs for Other Production
45 TOTAL Other Prod, Plant (Enter Total of lines 37 thru 44)
46 TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45)
68,230
19,396 545
50,277,981
69,742 756
070
315,082
322 444
631,456
f ,--,----------,-
-,-----,~----
370,319
130,393,210
493,554,906
414 787
16,388,465
122,505,166
129,469
12,943,071
633,334
825,529,475
513 151
229,740
355,278
203,234
20,104 655
f"-
' '--'---'""-----
924 472 598 979
130,044 154 733,010
243 998,118 622,923
185 687 563 1 ,794,280
36,464 633 362 384
14,816,368 774 079
950,430
631 885 738 15,885,655
402,745
338,800 068
518,875 736
29,370,402 586,631
60,940,312 15,945,150
680,376 302
341 403 43,842
105 592,913 541 593
563,008,126 531 903
FERC FORM NO.1 (REV. 12-05)Page 204
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) DA Resubmission 04/18/2007
ELECTRIC PLANT IN SERVICE (Account 101 , 102, 103 and 106) (Continued)
distributions of these tentative classifications in columns (c) and (d), including the reversals of the prior years tentative account distributions of these
amounts. Careful observance of the above instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount of
respondent's plant actually in service at end of year.
7. Show in column (f) reclassifications or transfers within utility plant accounts, Include also in column (f) the additions or reductions of primary account
classifications arising from distribution of amounts initially recorded in Account 102, include in column (e) the amounts with respect to accumulated
provision for depreciation, acquisition adjustments, etc., and show in column (f) only the offset to the debits or credits distributed in column (f) to primary
account classifications,
8. For Account 399, state the nature and use of plant included in this account and if substantial in amount submit a supplementary statement showing
subaccount classification of such plant conforming to the requirement of these pages.
9. For each amount comprising the reported balance and changes in Account 102, state the property purchased or sold, name of vendor or purchase
and date of transaction. If proposed journal entries have been filed with the Commission as required by the Uniform System of Accounts, give also dateRetirements Adjustments Transfers Balance at Line
End ~J)Year No,
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2006/04
271 303
4,485,105
370 319
130,536 694
505,458,266
432,374 122,585 943
61,359,209
13,086,514
836,568
838,233,513
211 835
7,400,617
- ,-- "" ,~.. ', '' _---- , '
87,117
22,523,451
133,690,047
244,621,041
187,440,908
36,805,775
15,590,447
950,430
40,935
21,242
149,294 647,622 099
~--,~--,-----~--
200,000
402,745
301 732
520 611
29,957,033
61,685,462
681 678
385,245
200 000
749,911
106,934,506
592,790,118
FERC FORM NO.1 (REV. 12-05)Page 205
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2006/04
No.(a)
47 3. TRANSMISSION PLANT
48 (350) Land and Land Rights
49 (352) Structures and Improvements
50 (353) Station Equipment
51 (354) Towers and Fixtures
52 (355) Poles and Fixtures
53 (356) Overhead Conductors and Devices
54 (357) Underground Conduit
55 (358) Underground Conductors and Devices
56 (359) Roads and Trails
57 (359,1) Asset Retirement Costs for Transmission Plant
58 TOTAL Transmission Plant (Enter Total of lines 48 thru 57)
59 4, DISTRIBUTION PLANT
60 (360) Land and Land Ri hts
61 (361) Structures and Improvements
62 (362) Station Equipment
63 (363) Storage Batte Equipment
64 (364) Poles, Towers, and Fixtures
65 (365) Overhead Conductors and Devices
66 (366) Under round Conduit
67 (367) Under round Conductors and Devices
68 (368) Line Transformers
69 (369) Services
70 (370) Meters
71 (371) Installations on Customer Premises
72 (372) Leased Prope on Customer Premises
73 (373) Street Lightin and Signal S stems
74 (374) Asset Retirement Costs for Distribution Plant
75 TOTAL Distribution Plant (Enter Total of lines 60 thru 74)
76 5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT
77 (380) Land and Land Ri hts
78 (381) Structures and Improvements
79 (382) Computer Hardware
80 (383) Computer Software
81 (384) Communication Equipment
82 (385) Miscellaneous Re ional Transmission and Market-Operation Plant
83 (386) Asset Retirement Costs for Regional Transmission and Market Oper
84 TOTAL Transmission and Market Operation Plant (Total lines 77 thru 83)
85 6. GENERAL PLANT
86 (389) Land and Land Rights
87 (390) Structures and Improvements
88 (391) Office Furniture and Equipment
89 (392) Transportation E uipment
90 (393) Stores Equipment
91 (394) Tools, Shop and Garage Equipment
92 (395) Laboratory Equipment
93 (396) Power Operated Equipment
94 (397) Communication Equipment
95 (398) Miscellaneous Equipment
96 SUBTOTAL (Enter Total of lines 86 thru 95)
97 (399) Other Tan ible Property
98 (399.1) Asset Retirement Costs for General Plant
99 TOTAL General Plant (Enter Total of lines 96 97 and 98)
100 TOTAL (Accounts 101 and 106)
101 (102) Electric Plant Purchased (See Instr. 8)
102 (Less) (102) Electric Plant Sold (See Instr. 8)
103 (103) Experimental Plant Unclassified
104 TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103)
807 969
33,134 805
235,849 248
79,294,427
92,201,304
114 775 572
944,894
720 354
585,786
18,709,053
608 583
464 620
318,351
~-----'-~
580,381 676 816 124
148,221 540,881
19,894 059 642,340
138,465,096 890 761
190,454,812 916 758
96,250,454 930,330
610,525 310 695
153 861,516 353,362
293,685,856 223 988
559,893 104 603
388,983 162 843
560,296 113,016
000,780 130,097
370,187
046,880,491 65,608,099r---~-------~
603,829
61,374 695
49,623,248
530,686
973,761
165 345
260,297
263,004
26,090,518
622,806
217 508,189
156 936
295,717
767 192
305,863
18,765
197,336
791 787
494 772
347 912
525,004
18,901 284
217,508,189
3,477 521 238
18,901 284
170,488 866
3,477 ,521,238 170,488 866
FERC FORM NO.1 (REV. 12-05)Page 206
Name of Respondent
Idaho Power Company
Retirements
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/18/2007
ELECTRIC PLANT IN SERVICE (Account 101 , 102, 103 and 106) (Continued)Adjustments Transfers Balance at
End 9f Year
(g)
Year/Period of Report
End of 2006/04
605
644 354
28,752 863
782 554
245,790,680
98,003 480
282,453
120,016,810
310,268
223 382
318,351
250,609 606,947 191
---~--"--------,----
263
1 ,397,499
607 315
20,494,136
142,958,358
1 ,669,990
1 ,261 ,783
288,371
866,016
147 819
392,086
929,694
39,279
194,701,580
98,919,001
43,632,849
162,348,862
318,762,025
51,272,410
52,622 132
634,033
63,807 067 070
370,187
097 389,95815,098,632
-- '""_
n' '
.., ,
_,m, _m"
" , ,.. ,.., "',-- ,-
- n
_, """."- "'--------- ---,... _
279,334
17,040,309
785,800
10,165
140 394
290 949
450 791
241 602
243,067
21,482,411
760,765
391,078
350,131
050,749
982,361
222 287
761 135
306 985
196 828
904 743
214 927 062
482,411
63,861,745
214 927 062
584 148,359
63,861 745 584 148 359
Une
No,
100
101
102
103
104
FERC FORM NO.1 (REV. 12-05)207Page
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2006/04
(2) Fi A Resubmission 04/18/2007
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 and Location
No.Of Pro
rerty
in T is Account in UtilitY Service End of Year(b) (c) (d)
1 Land and Rights:
2 Boise Operations Center 12/31/82 768,377
3 Production 185 246
4 Transmission Stations 360,819
5 Transmission Lines 69,263
6 Distribution Stations 047 880
Boise Operations Center 12/31/82 785
Boise Mechanical and Electrical Shop 12/31/01 000
Transmission Stations 12/31/81 178,094
Distribution Stations 80,306
Column B if no date listed it is various
Other Property:
47 Total 809,770
FERC FORM NO.1 (ED. 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 2006/04
(2) Fi A Resubmission 04/18/2007
CONSTRUCTION WORK IN PROGRESS - - ELE( TRIC (Account 107)
1. Report below descriptions and balances at end of year of projects in process of construction (107)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $100 000, whichever is less) may be grouped.
Line Description of Project Construction work in progress -
No,Electric (Account 107)
(a)(b)
ROLLUP RELIC COST BROWNLEE 742 257
ROLLUP RELIC COST HELLS CANYON 23,814,989
LINE 722, CONSTRUCT NEW BORAH-039,645
ROLLUP RELIC COST OXBOW 10,907,067
HELLS CANYON RELICENSING OUTSI 873,420
LINE 470 HRFT-STKY 138 KV 964,764
BRIDGER UNDISTRIBUTED WORK ORD 818,241
HELLS CANYON COMPLEX STURGILL 067 939
STKY 138KV SWITCHING STATION 066,505
VALMY 31818 U1 DCS UPGRADE PRO 949,832
HAPPY VALLEY SUBSTATION 002,336
DANSKIN UNIT #1 - 160 MW CT 864 384
LINE #470, 2ND 138KV LINE TO M 846,454
PAHSIMEROI HATCHERY EXPANSION 634,080
EMS/ADVANCED APPLICATION PROJE 591,861
CIAC LIABILITY RECLASS 187,429
VALMY UNDISTRIBUTED WORK ORDER 924,420
BUILD 138-KV LlNE-CHUT TO HPVY 840,124
WO ONGOING HELLS CANYON RELICE 668,628
CARTWRIGHT SUBSTATION 585,266
HCC RELICENSING FISH2004 FEASI 513,500
MIDPOINT - NEW 345KV, 175 MVAR 330,623
BORAH - NEW 345KV, 150 MVAR CA 312,994
VALMY 33397 #2 - DCS INSTALL 164,276
REL-HELLS CANYON COMPLEX FY200 120,690
342 COST CENTER DELIVERY CAPIT 070,726
BORAH - NEW 230 KV TERMINAL 060,702
REPLACE METALCLAD 028,023
POPULATION VIABILITY MODEL - W 943 616
VALMY 34534 U1 OVERFIRE AIR SY 939,348
COST CENTER 317 DELIVERY CAP IT 935,234
ROLLUP RELIC COST SWAN FALLS 820,228
LINE #426'RE-RATE LINE FOR BOR 808,088
BOMT-INCREASE 138/69KV CAPACIT 800 782
RIVER ENG.HELLS CANYON CONTIN 795,509
CLOVERDALE USTICK DOUBLE CIRCU 790,821
418-CC DELIVERY CAPITAL OVERHE 757,169
OMS UPGRADE OPSCENTRICITY 1.692 589
BOARDMAN UNDISTRIBUTED WORK OR 630,359
BKAT-MRDN CONVERT T202 TO 138K 625,141
VALMY 34086 U1 TURBINE OVERHAU 607,293
Line 722, ROW/Easements 606,015
TOTAL 210,094 019
FERC FORM NO.1 (ED. 12-87)Page 216
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2006/04(2) DA Resubmission 04/18/2007
CONSTRUCTION WORK IN PROGRESS - - ELEI TRIC (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)
HCC RELICENSING, FISH2004 ANAD 601 807
HCC RELICENSING, FISH2004 REDB 589,092
BANNER BANK FURNITURE 568,704
MAINT - LINE 951 MPSN-BORA 345 564,601
MIDPOINT 500 KV LINE RELAY REP 548,946
REPLACE NMPA METALCLAD SECT,531 576
BRIDGER 2007CO04 REFURBISH U1 518 760
SWAN FALLS RELICENSING 516,267
HCC RELICENSING, FISH2004 INST 508,509
390 COST CENTER DELIVERY CAPIT 498,706
CONSTRUCTION ACCOUNTING CAPITA 493,835
IPCO/BOBN-041 REBUILD CENTERVI 487,739
#3 CONTROL AND EOUIPMENT UPGRA 475,469
LINE 441 MODIFICATION FOR LlNE4 469,421
IPCO-CSCD-011 REBUILD SOUTH AR 469,256
OPe HYDRO. - PHASE IV STREAMFL 464,296
NETWORK SWITCH REPLACEMENT 463 718
343 COST CENTER DELIVERY CAPIT 462,192
REL-HCC OREGON REAUTHORIZATION 460 866
LINE #438 CDAL-LCST IMPROVE RO 458 439
TRASH REMOVAL STRUCTURES 451 166
ORACLE RAC 445 794
RELOCATE ON POLELINE RD IN TWI 433,800
IPCO-CSCD-013 REBUILD FROM CAS 422,261
VALMY 34120 #1 PULVERIZER UPGR 417 293
NEW BOULDER 041 FEEDER 406,774
IPCO-CSCD-013-2006 BI 405,339
TRANSRELAY REPLACEMENT 400,897
HCC RELICENSING FISH2004 RESID 393,958
577 COST CENTER DELIVERY CAPIT 389,907
415-CC DELIVERY CAPITAL OVERHE 380,370
324-COST CENTER DELIVERY CAPIT 374 629
341 COST CENTER DELIVERY CAPIT 362,960
MPSN0603 REPLACE 30SA BREAKER 362,643
336-COST CENTER DELIVERY CAPIT 362,427
2006 ADMINISTRATIVE SERVICES P 358,621
INSTALL 230KV PHASE SHIFTER AT 346,218
392 COST CENTER DELIVERY CAPIT 340,247
ROW FOR T404 -138 KVTO CHERR 338,311
PAYROLL & IBNR ACCRUAL 335 991
BUILD NEW POLE LINE SUBSTATION 331 799
COST CENTER 316 DELIVERY CAPIT 328,308
TOTAL 210 094,019
FERC FORM NO.1 (ED. 12-87)Page 216.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2006/04
(2) CIA Resubmission 04/18/2007
CONSTRUCTION WORK IN PROGRESS - - ELEC TRIC (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)
HAILEY TEAM CAP OH WORK ORDER 327,450
CALL CENTER LABOR HOURS FOR LI 325,011
REL - SWAN FALLS FY2004 CAPITA 319 166
LINE 470 STKY-MCAL 138KV 317 016
BOC ELEVATOR INSTALLATION 316,617
KPRT 230KV RELAY UPGRADE 315 318
IPCO-MCAL-041-REBUILD MAIN TRU 311,410
IPCO/HPVY-012 BUILD NEW FEEDER 304,467
335-COST CENTER DELIVERY CAPIT 302 351
LEGAL DEPT LABOR: HELLS CANYON 299,582
BDSS-PURCHASE SPARE 138-13KV 297 416
MORA REPLACE T132 WITH NEW 44,297,078
IPCO, MALPEGROVE RD. - FRANKLI 296,882
BARBER FLATS LAND SWAP-OXBOW 292,457
LEGAL DEPT. LABOR FOR RELICENS 291 030
KENYON - RELAY REPLACEMENT 285,342
IPCO/BOIS-014/2006 DOWNTOWN CA 285,283
PNUF-041 REBUILD 2 MILES OF 3 283,769
CAPITAL OVERHEADS FOR CADD & A 283 660
COM - REC BAKER CO SETTLEMENT 271,848
IPCO/HALY-015/F-18 TO IC-12 -270,267
BNR4 - BANNER BANK COMMUNICATI 270,075
Delivery Overheads 269,832
DELIVERY CAPITAL OVERHEADS FOR 267,047
MCAL0503-CONVERT 69KV TO 138KV 264,461
585 COST CENTER DELIVERY CAPIT 263,973
NEW UNIT 6719 (CC 345) ADDL CR 262 708
458-COST CENTER DELIVERY CAPIT 260 734
575 COST CENTER DELIVERY CAPIT 258 144
JT MESSINA MEADOWS 256,308
ADAMSFAM TEAM CAP OH WORK ORDE 255,046
578 COST CENTER DELIVERY CAPIT 254,943
GOODING TEAM CAP OH WORK ORDER 251 690
VALMY 34087 REPL HVAC ROOF 250 332
VALMY 34084 #2 CLARIFIER FILTE 250 144
IPCO/HOLY-WESR 69KV - LINE 215 247 024
RELOCATE T412 STR. 59-65 (TERT 243 520
OPERATIONAL DATA STORE 241 342
LINE 438, RIGHT OF WAY, VICTOR 240 969
WO SWAN FALLS RELICENSING-CAPI 237 956
SPVY0502-NEW 138-12.5KV SUBSTA 237 826
AUD UPGRADE PROJECT 236,242
TOTAL 210 094,019
FERC FORM NO.1 (ED. 12-87)Page 216.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2006/Q4
(2) n A Resubmission 04/18/2007
CONSTRUCTION WORK IN PROGRESS - - ELE( TRIC (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)
BOISE BENCH - KING 138 KV LINE 235,771
BRIDGER 2006C036 GREEN RIVER S 232 127
IPCO-RENFRO DAIRY-21351 ARENA 231 725
IPCO-CARTWRIGHT 012 BUILD NEW 229 714
420-CC DELIVERY CAPITAL OVERHE 228,908
100-COST CENTER DELIVERY CAPIT 226,991
327-COST CENTER DELIVERY CAPIT 224 138
JIM BRIDGER RAS-A AND RAS-218,075
2006 PC PURCHASES - CORPORATE 217 391
CDWL-INSTALL T132 215,810
SWAN FALLS RELICENSING FISH200 215,246
370 -COST CENTER DELIVERY CAPI 212 188
326-COST CENTER DELIVERY CAPIT 210,563
LINE 903 MAINTENANCE 210,144
TWINWEST TEAM CAP OH WORK ORDE 201 130
404 COST CENTER DELIVERY CAP IT 199 969
410-CC DELIVERY CAPITAL OVERHE 199 107
334-COST CENTER DELIVERY CAPIT 198 549
RIGHT OF WAY, TRANSMISSION LlN 193,128
ACHD/IPCO FRANKLIN ROAD REBUI 193 076
HELLS CANYON INFRASTRUCTURE 191 894
KING - REPLACE PCB SHUNT CAPAC 191 751
IPCO/GRVE-015/2006 DOWNTOWN CA 190,188
328-COST CENTER DELIVERY CAPIT 188,607
TOOL EXP TRANS TO CONST 188,428
BRIDGER 2007CCA3 U3 LOW NOX MO 186 700
455-COST CENTER DELIVERY CAPIT 186,327
NWMS0501 - CONVERT TO 138KV 185,452
REL - REC SWAN FALLS RELICENSI 184 461
IPCO-CARTWRIGHT 011 BUILD NEW 182 879
IPCO/ONTO19 REPLACE BAD UG PR 181 019
BRDY 230KV RELAY UPGRADE 181 003
UPGRADE CANEL GATE HOISTS 179 955
PRMA-041 REBUILD 3 MI TO 00 AC 179 545
BRIDGER 2007C036 INST ZOLOBOSS 176,690
PQ AG DSR LAB EQUIPMENT-ION 176 203
MINI CASSIA TEAM CAP OH WORK 0 175 082
UPGRADE MV90 TO MV90XI 173 934
WESR-014 REPLACE 2 MI. ANNEAL 173,639
IDOT/IPCO CLOVERDALE R & HWY 2 173,284
REPLACE #5 VOLTAGE REGULATOR &172 795
CHQ 9 EXECUTIVE AREA REMODEL 169,669
TOTAL 210,094 019
FEAC FOAM NO.1 (ED. 12-87)Page 216.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2006/04(2) DA Resubmission 04/18/2007
CONSTRUCTION WORK IN PROGRESS - - ELEI TRIC (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)
375 COST CENTER DELIVERY CAPIT 165,386
381 -COST CENTER DELIVERY CAPI 163 371
ZLOG - ADD NEW FEEDER 013 161 230
CHO 2 BUILDINGS FURNITURE 159 795
IPCO/ELMR-041NARIOUS DEVICES/159,146
REL - REC HCC RELICENSING PROC 158,267
ENHANCED LAW ENFORCEMENT PER S 157 822
856 COST CENTER DELIVERY CAPIT 155,435
HCC WILDLIFE AND BOTANICAL 155,402
COC YARD PAVING 154,151
337-COST CENTER DELIVERY CAPIT 150 187
BANNER BANK 149 472
CITY OF KETCHUM-8TH ST RELOCAT 148 675
BRIDGER 2006C149 CONTINUOUS BI 148,437
TERR: HCC RELICENSING 148 004
378 -COST CENTER DELIVERY CAPI 146,949
WESR-011 REPLACE 2.5 MILES W/145,894
IPCO-ANTONIO AVELAR DAIRY-3835 145,745
LOWER MALAD FISH PASSAGE 145,701
FILER 46KV BREAKER 145,213
JIM BRIDGER SUBSTATION CAPITAL 145.040
VALMY 34083 #2 PULVERIZER UPGR 144 092
153 COST CENTER DELIVERY CAPIT 142,715
LSPO LICENSE ART 414 REC - RIV 142,382
COMPLIANCE- TRASH RAKE 141 935
BOC YARD IMPROVEMENT '141 493
#2 STATIC EXCITATION PURCHASE 140,671
BORA 230KV RELAY UPGRADE 140,401
IPCO/WESR-013/REBUILD 3.25 MIL 139 441
377 -COST CENTER DELIVERY CAPI 139 312
SERVER REPLACEMENT - OUT OF WA 138,504
WAN CISCO 7206 ROUTER REPLACEM 137 783
REPLACE UNIT #1 VOLTAGE REGULA 137 392
IPCO/BOIS-021/2006 DOWNTOWN CA 135,818
WHISPERING PINES SUBDV. - POWE 132 920
VULNERABLITY ASSESSMENT (ASLC 131 064
VALMY 34080 U1 BOTTOM ASH RECY 130 053
INVESTMENT RECOVERY ASPHALT PA 129 282
IPCO-VAN VLIET AND KENNINGTON 129 264
STAUFFER ESTATES-104 E 50 N/J 128 956
VALLEY CLUB WEST NINE SUBD-HAI 128,213
LOGISTIC LICENSE SERVER (LLS)127,208
TOTAL 210 094,019
FERC FORM NO.1 (ED. 12-87)Page 216.
This Page Intentionally Left Blank
Name of Respondent This l!Jort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2006/Q4
(2) Fi A Resubmission 04/18/2007
CONSTRUCTION WORK IN PROGRESS - - ELE~ TRIC (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)
210-COST CENTER DELIVERY CAPIT 127,193
BRIDGER 2006C073 U4 REPL LOWER 125,444
TFEAST TEAM CAP OH WORK ORDER 124 737
JT CHARTER POINTE #10-URD SERV 124 692
TFSN-013 & 014 FEEDER GETAWAY 123,676
376 -COST CENTER DELIVERY CAPI 123,516
VALMY 31701 TURB LUBE OIL CENT 123,483
CHARTER POINTE #1 O-OVERHEAD UP 122,186
360 COST CENTER DELIVERY CAPIT 120 617
300 COST CENTER DELIVERY CAPIT 118,392
VALMY 32692 RAIL CAR DIST FEED 118,330
COWBOY TRAILER PARK- PHASE 3 0 118,326
COST CENTER 310 DELIVERY CAPIT 115,957
COST CENTER 310 DELIVERY CAPIT 115,783
RIVER ENG-SWAN FALLS RELICENSI 115,615
345 COST CENTER DELIVERY CAPIT 114,180
OXBOW FISH HATCHERY EXPANSION 113,612
382 -COST CENTER DELIVERY CAPI 112,127
PURCHASE STAR PROPERTY FOR NOR 111,457
DIDSON CAMERA' ,111 054
REPLACE UNIT #2 VOLTAGE REGULA 110,993
VALMY 34078 U1 COOLING TOWER T 110,447
HR COMPETENCY MANAGEMENT SYSTE 108,837
LINE #602, BLACKFOOT-GOSHEN 16 108,387
CIRRUS POINTE BY THE LAKE - PH 108,215
IPCO/NOVINIUM PILOT/BOBN-044-107 887
2006 PC PURCHASES - CAPITAL RE 107,529
IPCO/HPVY-013 BUILD NEW FEEDER 107,359
REC - BAKER COUNTY SETTLEMENT 106,389
BOBN-041 REBUILD .75 MILE AND 105,867
BOBN - REPLACE 138KV BREAKER 0 105,143
HELLS CANYON CULTURAL 104,932
GSHN - REPLACE 171 A 104,737
NEW UNIT 6729- 36' SERVICE BUC 103,225
BOARDMAN 22163 UPG DCS TO OVAT 103,064
2006 PC PURCHASES - SOUTHERN R 102,347
ELKHORN SPRINGS - SUN VALLEY/101,096
OTHER MINOR WORK ORDERS 549,383
CONSTRUCTION WIP CIAC CONTRA 206 080
TOTAL 210,094 019
FERC FORM NO.1 (ED. 12-87)Page 216.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2006/04
(2) D A Resubmission 04/18/2007
ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108)
1. Explain in a footnote any important adjustments during year.
2. Explain in a footnote any difference between the amount for book cost of plant retired, Line 11 , column (c), and that reported for
electric plant in service, pages 204-207, column 9d), excluding retirements of non-depreciable property.
3. The provisions of Account 108 in the Uniform System of accounts require that retirements of depreciable plant be recorded when
such plant is removed from service. If the respondent has a significant amount of plant retired at year end which has not been recorded
and/or classified to the various reserve functional classifications, make preliminary closing entries to tentatively functionalize the book
cost of the plant retired. In addition, include all costs included in retirement work in progress at year end in the appropriate functional
classifications.
4. Show separately interest credits under a sinking fund or similar method of depreciation accounting.
Section A. Balances and Changes During Year
I LIne nem i8~)clec
S~lc r-,~m In
clE1cmc ':"Iant. !"tela ~~ggl
fo c!iN~~rsNo.ervlce for Future Use(a)(b)(c)(d)(e)
1 Balance Beginning of Year 333,025,502 333 025,502
2 Depreciation Provisions for Year, Charged to
3 (403) Depreciation Expense 803,410 90,803,410
(403,1) Depreciation Expense for Asset
Retirement Costs
5 (413) Exp. of Elec. PIt. Leas. to Others
6 Transportation Expenses-Clearing 738,380 738,380
7 Other Clearing Accounts
8 Other Accounts (Specify, details in footnote):
Fuel Stock 108 561 108,561
TOTAL Deprec, Prov for Year (Enter Total of 650,351 93,650,351
lines 3 thru 9)
Net Charges for Plant Retired:
Book Cost of Plant Retired
Cost of Removal
Salvage (Credit)108,059
TOTAL Net Chrgs. for Plant Ret. (Enter Total 55,935,848 55 935,848
of lines 12 thru 14)
Other Debit or Cr. Items (Describe, details in 931,424
footnote):
Book Cost or Asset Retirement Costs Retired
1 S Balance End of Year (Enter Totals of lines 1 367,808,581 367 808,581
10,15,16, and 18)
Section B.Balances at End of Year According to Functional Classification
Steam Production 420 177 111 420,177 111
Nuclear Production
Hydraulic Production-Conventional 240,328,423 240,328,423
Hydraulic Production-Pumped Storage
24 Other Production 366,353 366 353
25 Transmission 210 074,912 210,074 912
26 Distribution 411,582,068 411,582,068
27 Regional Transmission and Market Operation 279 714 279,714
28 General
29 TOTAL (Enter Total of lines 20 thru 28)367 808 581 367 808 581
FERC FORM NO.1 (REV. 12-05)Page 219
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
FOOTNOTE DATA
ISchedule Page: 219 Line No.: 14 Column:
Relocation reimbursements, Up and down costs and damage and insurance claims $ 889,944.
ISchedule Page: 219 Line No.16 Column:c
Accumulated provision for Depreciation on Asset Retirement Obligation $ (547 524)
Embedded removal in Accumulated provision for Depreciation 3,478,950
-----------
$2,931,424
I FERC 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 2006/Q4(2) DA Resubmission 04/18/2007
INVESTMENTS IN SUBSIDIARY COMPANIES Account 123.
1. Report below investments in Accounts 123., investments in Subsidiary Companies.
2. Provide a subheading for each company and List there under the information called for below. Sub - TOTAL by company and give a TOTAL in
columns (e),(f),(g) and (h)
(a) Investment in Securities - List and describe each security owned. For bonds give also principal amount, date of issue, maturity and interest rate.
(b) Investment Advances - Report separately the amounts of loans or investment advances which are subject to repayment, but which are not subject to
current settlement. With respect to each advance show whether the advance is a note or open account. List each note giving date of issuance, maturity
date, and specifying whether note is a renewal.
3. Report separately the equity in undistributed subsidiary earnings since acquisition.The TOTAL in column (e) should equal the amount entered for
Account 418.
Ine uescnptlon or Investment Date Acquired Date Of Amount Of .Investment at
No.(a)(b)Mity
Beginning of Year
(d)
1 Idaho Energy Resources Company
2 Common Stock 02/01/74 500
3 Capital contributions 462 594
4 Equity in earnings 049 315
Subtotal Idaho Energy Resources Company 43,512,409
Total Cost of Account 123.1 $2,463 0931 TOTAL 512,409
FERC FORM NO.1 (ED. 12-89)Page 224
Name of Respondent This
'0ort
Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2006/04(2) FjA Resubmission 04/18/2007
INVESTMENT 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.
t:qUlty In Subsidiary Revenues for Year Amount of Investment at Gain or Loss from Investment Line
Eamin~s of Year End fJ)year Disp~sed of No.(f)
500
2,462 594
8,401 ,787 451 102
.. ,",.. , ,-,
914 196
8,401 787 914 196
FERC FORM NO.1 (ED. 12-89)Page 225
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
FOOTNOTE DATA
ISchedule Page: 224 Line No.Column:
Instruction 3 says this number should equal Account 418.1 The difference between what is
reported on page 224 Col E and 418.1 is $1,246,465. This amount has been reported in OCI,
account 219
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)2006/04(2)0 A Resubmission 04/18/2007 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)
1 Fuel Stock (Account 151)11 ,494 190 15,173,831 Electric
2 Fuel Stock Expenses Undistributed (Account 152)
3 Residuals and Extracted Products (Account 153)
4 Plant Materials and Operating Supplies (Account 154)
5 Assigned to - Construction (Estimated)
6 Assigned to - Operations and Maintenance
7 Production Plant (Estimated)11 ,238,406 191,263
8 Transmission Plant (Estimated)465 632 189 143
9 Distribution Plant (Estimated)12,235 598 15,527,757
Regional Transmission and Market Operation Plant
(Estimated)
Assigned to - Other (provide details in footnote)766,156 854,043
TOTAL Account 154 (Enter Total of lines 5 thru 11)28,705,792 762 206 Electric
Merchandise (Account 155)
Other Materials and Supplies (Account 156)
Nuclear Materials Held for Sale (Account 157) (Not
applic to Gas Util)
16 Stores Expense Undistributed (Account 163)745,428 316 011 Electric
TOTAL Materials and Supplies (Per Balance Sheet)945,410 252 048
FERC FORM NO.1 (REV. 12-05)Page 227
Name of Respondent This
0ort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2006/04
(2) LJ A Resubmission 04/18/2007
EXTRAORDINARY PROPERTY LOSSES (Account 182.
Line DescriRtion of Extraordinary Loss Losses WRITTEN OFF DURING YEAR Balance atTotalNo.(Include in the description the date of Amount Recognisedcommis~ Authorization to use Acc 182.of Loss During Year Account Amount End of Yearand perio 0 amortization (mo, yr to mo, yr).Charged
(a)(b)(c)(d)(e)(f)
1 None
20 TOTAL
FERC FORM NO.1 (ED. 12-88)Page 230a
Name of Respondent This
'0ort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2006/04(2) DA Resubmission 04/18/2007
UNRECOVERED PLANT AND REGULATORY STUDY COSTS (182.
Line Description of Unrecovered Plant WRITTEN OFF DURING YEAR Balance atTotalCostsNo.and Regulatory Study Costs (Include Amount Recognised
in 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))
(a)(b)(c)(d)(e)(f)
None
TOTAL
FERC FORM NO.1 (ED. 12-88)Page 230b
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2006/04
(2) n A Resubmission 04/18/2007
0 HER 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 Written oft During Written oft Dunng Current OuarterlYear
Current the OuarterlYear the Period
OuarterlYear Account Charged Amount
(a)(b)(c)(d)(e)(f)
Asset Retirment Obligations - IPUC 363 188 842,868 11,206,056
Order #29414 - OPUC Order #04-585
LT & ST Mark to Market 979,296 244 516,659 1,462,637
Tax Settlement - IPUC Order 29601 993 958 898 16~892 121
(Amort period 6/05 thru 5/06)
Regulatory Unfunded Accumulated Deferred Income Tax 346 116,633 235,763 282 762,742 343,589,654
Power Cost Adjustment - IPUC order 33,561 270 314475,47-348036 741
#27660 (amort period 6/05 thru 5/07)
Idaho - Demand Side Management - IPUC order 591 747 401 242 604 349 143
#27660 (amort period 7/98 thru 6/10)
Excess Power Amortization - OR OPUC Order#06-070 8,411 118 682,926 401 2,423697 670,347
(Capped at 10% per year until full amort)
Security Costs 2001-2002 - IPUC Order #28975 375 109 401 178 284 196,825
(amort period 1/03 -12/07)
Security Costs 2003 - IPUC Order #28975 199,840 339 401 84,591 137 588
(amort period 1/04 -12/08)
Professional Fees - IPUC order #29505 260 473 4073 487 246
(Amort period 1/03 thru 12/07)
IPUC Grid West Loans -IPUC order #30157 938,743 124 566 932,177
(amort period 1/07 -12/11)
OPUC Grid West Loans - OPUC Order #06.483 332 131 325 56,007
FERC Grid West Expense 302 117 302 117
FERC Docket # AC03-78-000
PCA Unbilled Amortization Reserve ( 1 309 994)550,57~240,585
(Reversed June 2006)
Excess Power Deferred - Oregon (see lines 18-19)879 446 182,371 401 172 700 889 117
OPUC Order # 05-870
Minor items 615 969 401 615 33,969
TOTAL 418 241 190 333,181 410 372 575 717 378,846 883
FERC FORM NO. 1/3-Q (REV. 02-04)Page 232
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
FOOTNOTE DATA
Schedule Pa e: 232 Line No.: 6 Column: d
254 $ 432 621
4073 5,458,679
4210 810
$5,892 121
Schedule Pa e: 232 Line No.: 11 Column: d
232 $ 39,513,704
254 168,405,008
4073 165,784
431 438,756
401 80,977,504
1823 535 985
$348,036,741
Schedule Pa e: 232 Line No.: 37 Column: d
232
473
$1,120,293
120.292
$2,240,585
I FERC 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 2006/04(2) nA Resubmission 04/18/2007
M SCELLANEOUS DEFFERED DEBITS (Account 186)
1. Report below the particulars (details) 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.
Line Description of Miscellaneous Balance at Debits CREDITS Balance at
No.Deferred Debits Beginning of Year Amount End of YearChar~ed
(a)(b)(c)(e)(f)
Regional Transmsn Org . (RTO)251 115 251,115
Advance prepaid coal royalties 976 053 131 202,492 773 561
Benefits plan - intangible asst 413,253 253 1,413 253
Security plan 28,585 485 958 997 2,442 145 28,102 337
American Falls bond refinance 278,918 401 14,552 264 366
(amort period 4/00 thru 7/26)
Prepaid Credit Facility 623,721 543,132 431 736 130 430,723
Company owned Life Insurance 815,336 640,626 503 251 952,711
American Falls water riahts 19,885,000 401 042 009 18,842,991
(amort period 1/06 thru 12/25
Milner bond guarantee 700,000 700,000
Southwest intertie project -333,391 183 374,574
right of way costs
CSPP receivable 016,847 143 364 185 652,662
American Falls - bond refinance 919,983 401 999 871 984
(35 year amortization)
Transmission Deposit-PacifiCorp 295,375 783,475 078,850
Prepaid PeoplesofVPassport 162 005 401 66,419 95,586
Adjustment to Unfunded Pension 993,497 190 812,252 181 245
Transmission. General Studies 342,241 186 342 200
06 Sweetwater Refi Costs 787 090 108 842 678,248
(Amort period 2-2007 to 7-2026)
Minor Items & Job Orders (10)025 934 717 Various 880,796 896
Misc. Work in Progress
Deterred Regulatory Comm.
Expenses (See pages 350 - 351)
TOTAL 82,087,452 124 388,934
FERC FORM NO.1 (ED. 12-94)Page 233
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
FOOTNOTE DATA
Schedule Pa e: 233 Line No.Column: d
4265 949,916
186 96,798
186 204.401
$2,251 115
Schedule Pa e: 233 Line No.Column: d
4262 $1,018,678
165 1.423.467
442 145
Schedule P e: 233 Line No.Column: d
4262 $1,089,572
131 302,548
419 604
186 105.427
503,151
Schedule Pa e: 233 Line No.Column: d
1867 $ 21,411
131 87.431
$108,842
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent
Idaho Power Company
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) A Resubmission 04/18/2007
ACCUMULATED DEFERRED INCOME TAX S (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.
Year/Period of Report
End of 2006/04
Ine
No.
ocatlon
(a)
Electric
Emission Allowances
Advances for Construction
5 Other Electric (See footnote)
175 361
211 519
118,190
13,717,218
103,660 136
14,416,632
117 138 886
Notes
FERC FORM NO.1 (ED. 12-88)Page 234
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
FOOTNOTE DATA
ISchedule Page: 234 Column: bLine No.
(Other):
Post Retiree Benefits-VEBA
Rate Case Disallowance
Other Employee s Long Term Deferred Compensation
SFAS112 - Post Retirement Benefits
Non-VEBA Pension and Benefits
FAS 123R - Stock Based Compensation
Provision For Rate Refunds
American Falls Falling Water Contract
Linden Feeder Deposits
Restricted Stock Plan
City of Eagle
Delivery Accruals
Dark Fiber Contracts
Other Regulatory Liabilities
Total Other Electric
ISchedule Page: 234 Line No.: 7 Column:
(Other):
FASB 109 Accounting
FAS 158 - Pension
FAS 158 - Postretirement Plan
Minimum Pension Liability
Total Other
Beginning Balance
$ 1 893,065
316,285
2,424 225
037,355
905,653
128,814
215,673
101 285
83,990
$ 10,106,346
Beginning Balance
$41 627,445
947 905
$45,575,350
Ending Balance
$ 3,367 220
228,546
538,014
306,630
853,341
585,567
479,888
407 373
164,403
160,625
20,891
692
$13,118,190
Ending Balance
$41,825,257
11 ,263,649
10,603,160
525,117
$68,217 183
ISchedule Page: 234 Line No.: 17 Column:
(Other Non Electric):
Senior Management Security Plan
Micron-CIAC
Meridian Gold Contributions
Start-up and Organization Costs
Seattle City Light-CIAC
Loss on Pioneer Land Write-down
Total Non Electric
Beginning Balance
$10,851,325
2,477 838
219,016
75,447
48,241
45,351
Ending Balance
$11,842 893
239,495
196,904
75,447
16,542
45,351
$13,717,218 $14,416,632
IFERC 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 2006/04
(2) Ei A Resubmission 04/18/2007
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 000,000
and Pacific Stock Exchange
4 Total Common Stock 50,000,000
6 Account 204 - None
FERC FORM NO.1 (ED. 12-91)Page 250
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2006/Q4(2) 0 A Resubmission 04/18/2007
CAPITAL STOCKS (Account 201 and 204) (Continued)
3. Give particulars (details) concerning shares of any class and series of stock authorized to be issued by a regulatory commission
which have not yet been issued.
4. The identification of each class of preferred stock should show the dividend rate and whether the dividends are cumulative or
non-cumulative.
5. State in a footnote if any capital stock which has been nominally issued is nominally outstanding at end of year.
Give particulars (details) in column (a) of any nominally issued capital stock, reacquired stock, or stock in sinking and other funds which
is pledged, stating name of pledgee and purposes of pledge.
OUTSTANDING PER BALANCE SHEET HELD BY RESPONDENT Line
(Total amount outstanding without reduction AS REACQUIRED STOCK (Account 217)IN SINKING AND OTHER FUNDS No.for amounts held by respondent)
ares Amount ares q!Jst Shwes Amount(e)(f)
(g)
(h)(i)
150,812 877 030
39,150 812 877 030
FERC FORM NO.1 (ED. 12-88)Page 251
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2006/04(2) DA Resubmission 04/18/2007
OTHER PAID-IN CAPITAL (Accounts 208-211 , inc.
Report below the balance at the end of the year and the infonmation 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.
LIne l~r
"(g)
untNo.
Account 208 - Donations received from stockholders
Account 209 - Reduction in par or stated value of Capital Stock
Account 210 - Gain on reacquired Capital Stock
Account 211 - Miscellaneous paid-in Capital
TOTAL
FERC FORM NO.1 (ED. 12-87)Page 253
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2006/04
(2)0 A Resubmission 04/18/2007
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.
I LIne Class and Series of Stock Balance at t:na or year
No.(a)(b)
1 Common Stock 096,925
Explanation of Changes during the year:
22 TOTAL 096 925
FERC FORM NO.1 (ED. 12-87)Page 254b
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2006/04
(2) Fi A Resubmission 04/18/2007
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)
1 Account 221:
2 First Mortgage Bonds:
3 5.50% Series due 2033 70,000 000 728,701
36,400 D
6 7.38% Series Due 2007 80,000 000 807 871
8 7.20% Series due 2009 000,000 572,246
30% Series Due 2035 60,000 000 408,411 D
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
875% Series due 2034 55,000 000 524,419
383 322 D
50% Series due 2034 000,000 746 961 D
Pollution control Revenue Bonds
05% Series 96A due 2026
Series 96B due 2026
TOTAL 987,045,000 12,866,803
FERC FORM NO.1 (ED. 12-96)Page 256
Name of Respondent This
'0ort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2006/04(2) DA Resubmission 04/18/2007
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 uutstanaln Line
Nominal Date Date of (Total amount outstan ing without Interest for Year No.
of Issue Maturity Date From Date To reduction for amounts held by Amount
(d)(e)(f)
(g)
reSP?h\dent)
(I)
05/01/03 04/01/33 05/01/03 03/31/33 70,000 000 850,000
12/1/00 12/01/07 12/01/00 12/01/07 000,000 904 000
11/23/99 12/01/09 01/01/00 01/01/10 80,000 000 760,000
08/26/05 08/26/35 08/26/05 08/26/35 60,000,000 180 000
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
08/16/04 08/16/34 08/16/04 08/16/34 55,000 000 231 250
03/26/04 03/15/34 03/26/04 03/15/34 50,000,000 750,000
07/25/96 07/15/26 07/25/96 07/15/26 ~~!~i~~~ W'1iJ;':~'iW~ ~\)j1~t'ti ~~~~\t~~204,452
~:!"", ,
iW.ft'
'"-
~'r~'fj!;
07/25/96 07/15/26 07/25/96 07/15/26 ~~~~t(i:i~gm~~m_~672 283W,v".:...:
,:'
" ,J':..'i',,"~L.
: ,",:, :..
987 045 000 744,453
FERC FORM NO.1 (ED. 12-96)Page 257
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2006/04(2) 0 A Resubmission 04/18/2007
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)
Series 96C due 2026
Port of Morrow Variable due 2027 360,000 188,545
Humboldt Variable due 2024 800,000 697,856
8 Sweetwater Variable due 2026 (IPC-06-116 300,000 820,043
OPUC UF 4227 WPSC 20005-29-ES-06)471,252 D
Subtotal Account 221 955,460 000 12,866,803
Account 224:
Bond Guarantee - American Falls 19,885,000
REA Notes
Note Guarantee - Milner Dam 700,000
Subtotal Account 224 585,000
Account 222: Required Bonds
Account 223: Advances for Associated Companies
TOTAL 987 045,OOC 12,866 803
FERC FORM NO.1 (ED. 12-96)Page 256.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Me, Da, Yr)End of 2006/04(2) DA Resubmission 04/18/2007
LONG-TERM DEBT (Account 221 , 222, 22 and 224) (Continued)
10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term
advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13. If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose of the pledge.
14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of
year, describe such securities in a footnote.
15. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on
Long-Term Debt and Account 430, Interest on Debt to Associated Companies.
16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
AMORTIZATION PERIOD Ul!tstandln Line
Nominal Date Date of (Total amount outstan ing without Interest for Year No.of Issue Maturity Date From Date To reduction for amounts held by Amount
(d)(e)(f)
(g)
respy~dent)(i)
07/25/96 07/15/26 07/25/96 07/15/26 665,076
05/17/00 02/01/27 05/17/00 02/01/27 360 000 166 187
10/22/03 12/01/24 11/01/03 12/01/24 49,800,000 694,871
10/3/06 7/15/26 10/3/06 7/15/2026 021,473
955,460,000 53,744,592
04/26/00 2/1/25 19,885 000
139
02/10/92 700,000
585,000 139
987 045 000 744,453
FERC FORM NO.1 (ED. 12-96)Page 257.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
FOOTNOTE DATA
ISchedule Page: 256 Line No.30 Column: h
See Footnote for page 257-1 Line 8.
ISchedule Page: 256 Line No.32 Column: h
See footnote for page 257-1 Line 8.
ISchedule Page: 256.Line No.Column: h
see footnote for page 257-1 Line 8.
ISchedule Page: 256.Line No.Column: h
On October 3,2006, IPC completed a tax-exempt bond financing in which Sweetwater County, Wyoming issued and sold
$116.3 million aggregate principal amount of its Pollution Control Revenue Refunding Bonds (Idaho Power Company
Project) Series 2006. The bonds will mature on July 15, 2026. The $116.3 million proceeds were loaned by Sweetwater
County to IPC pursuant to a loan agreement, dated as of October 1, 2006, between Sweetwater County and IPC. On
October 10, 2006, the proceeds of the new bonds, together with certain other moneys of IPC, were used to refund
Sweetwater County s Pollution Control Revenue Refunding Bonds (Idaho Power Company Project) Series 1996A, Series
1996B and Series 1996C totaling $116.3 million. The regularly scheduled principal and interest payments on the Series
2006 bonds, and principal and interest payments on the bonds upon mandatory redemption on determination of taxability,
are insured by a financial guaranty insurance policy issued by AMBAC Assurance Corporation. IPC and AMBAC have
entered into an Insurance Agreement, dated as of October 3, 2006, pursuant to which IPC has agreed, among other
things, to pay certain premiums to AMBAC and to reimburse AMBAC for any payments made under the policy. To secure
its obligation to make principal and interest payments on the loan made to IPC, IPC issued and delivered to a trustee IPC'
First Mortgage Bonds, Pollution Control Series C, in a principal amount equal to the amount of the new bonds
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This R ort Is: Date of Report YearlPeriod of Report(1) An Original (Mo, Da, Yr) End 2006/Q4Idaho Power Company (2) DA Resubmission 04/18/2007
RECONCILIATION OF REP RTED NET INCOME WITH TAXABL 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 retum 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.
Ine
No.
1 Net Income for the Year (Page 117)
4 Taxable Income Not Reported on Books
5 See Footnote
mount
(b)
93929189
l~Jm~~U~~~~;i
9 Deductions Recorded on Books Not Deducted for Return
10 See Footnote
~~;
~W;f~if;%IDf~ii~;~~:f
14 Income Recorded on Books Not Included in Return
15 See Footnote ~ig~~i~~~~H~~~ic~~E
19 Deductions on Return Not Charged Against Book Income
20 See Footnote ~illt'j~~~~~lf~~; ~
27 Federal Tax Net Income
28 Show Computation of Tax:
29 Tentative Federal Tax ~ 35%
158,674 773
55,536 171
FERC FORM NO.1 (ED. 12-96)Page 261
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
FOOTNOTE DATA
ISchedule Page: 261 Line No.: 5 Column: b
004003-CONSTRUCTION ADV-252
004004-CIAC CLOSED TO PLANT
004005-AVOIDED COST INT CAP
004010-EMISSION ALLOW ANCE-254.409-411
004013-CIAC AS TAXABLE INC IN ACCT 107
004017-JOINT USE FEE REC'D B41NC BOOKED-253.050
004018-LlNDEN FEEDER DEPOSITS-253.206
004019-IDWR STREAMFLOW GUAGING CONTRACT-242.312
004020-ENGINEERING FEES CLOSED TO PLANT
004021-ENGINEERING FEES IN ACCT 107
004022-CITY OF EAGLE-ACCT 253.209
004501-ROY AL TY INCOME BTL
004506-CIAC-MERIDIAN GOLD
004507 -CIAC-MICRON-DRAM
004512-CIAC-SEATTLE CITY LIGHT
Total
ISchedule Page: 261
$ 6,657 523
080,229
983 765
(38,891 098)
4,437 515
(88,200)
034
29,366
1,497 908
100,750
53,437
100,000
(56,560)
(608,652)
(81 312)
$ 11 305,705
Line No.: 10 Column: b
Total Federal and State taxes deducted on books
005001-BAD DEBT EXPENSE
005008-GAIN/LOSS ON REACQUIRED DEBT-DEFERRED
00501 a-SF AS 112-POST -EMPL Y BEN 182/253
005014-0VERACCRUED V ACA TION-ACCT 242
005017-INJURIES & DAMAGES
005019-DIRECTORS FEES DEF
005022-CAPIT ALiZED OVERHEADS
005023-PENSION ACCR TO 926200
005024-MEALS (50% NON-DEDUCTIBLE) CHRGD TO RE.
005025-MILNER FALLING WATER - REV ACCRL
005027-AMORTIZATION OF ACCOUNT 114
005028-0REGON OPER PROPERTY TAX ADJ
005033-NONVEBA PEN&BEN-Acct 228
005035-PCA EXPENSE DEFERRAL
005043-AMERICAN FALLS FALLING WATER CONTRACT
005044-RESTRICTED STOCK PLAN-COMP
005047-0THER EMPLOYEE'S LT DEFERRED COMP-228
005048-BONUS DEFERRAL-232
005050-186-BAD DEBT RESERVE-FINANCING PRGMS
005051-PUC ORDER 29505 - PROFESSIONAL FEES
005052-AMORTIZATION OF ACCOUNT 181
005053-FAS 123R-STOCK BASED COMPENSATION
005054-IPUC GRID WEST LOANS-ACCT 182
005055-0PUC GRID WEST LOANS-ACCT 183
005056-FERC GRID WEST EXP-ACCT 182
005501-SEC PLAN-NET INS COSTS
005502-128-SMSP-MRKT CHG OF RABBIINVSTMNTS
005503-128-EDC-UNRLZD GNILS FRM RABBI TRUST
005504-NONDEDUCTIBLE POLITICAL EXP-426.4
005505-SEC PLAN-BENEFIT ACCR
005510-FINES AND PENALTIES
005516-NONDEDUCTIBLE POLITICAL EXP-O&M ACCTS
IFERC FORM NO.1 (ED. 12-87) Page 450.
$ 44 378,930
134,835
549,856
688,770
698,941
(920,977)
242,996
(12,000,000)
5,433,988
300,000
264,100
(22 723)
(18,269)
(133,809)
356,345
042 009
(141 749)
291 ,057
(183,380)
(29,337)
20,013
136,345
497,805
(932 177)
(56,007)
(302,117)
(349,485)
(104 905)
300,000
536,305
307
100,000
Name of Respondent This Report is:Date of Report YearlPeriod of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/Q4
FOOTNOTE DATA
005531-RA TE CASE DISALLOWANCES-REVERSE AMORT
005532-DELIVERY ACCRUALS-253.550
005536-VEBA INCOME TAXES
Total
(296,299)
(209,316)
12,232
$ 64 286,284
ISchedule Page: 261 Line No.15 Column: b
007002-GAIN ON SALE OF BOC
007009-PROVISION FOR RATE REFUNDS-ACCT 229
007501-REVERSE EQUITY EARNINGS OF SUBSIDIARIES
007502-ALLOWANCE FOR OFUDC
007503-ALLOWANCE FOR BFUDC
007504-RECLASS TAX EXEMPT INTEREST - FED ONLY
007514-COLl-INSURANCE PROCEEDS
Total
$ 29 306
227,492)
648,252
092 152
026,460
511 322
561,550
$ 20,641,550
ISchedule Page: 261 Line No.20 Column: b
008001-VEBA-POST RET BNFTS-TRUST-ACCT 228
008009-DEPR FOR TAX GT OR L T BOOK
008016-VEBA-POST RETIRE BENEFITS-TRUST-MEDICARE PART 0
008020-CONSERV A TION PROGRAMS
008022-263A 481 (a)-FACTS & CIRCUMSTANCES (87-04)
008025-MANUFACTURING DEDUCTION-ORE NOT ALLWD
008027-NEVADA OPERATING PROPERTY TAX ADJ
008034-REMOVAL COSTS
008035-REPAIR ALLOWANCE
008038-0REGON EXCESS PWR SUPPLY COSTS
008039-ST TAX-NOT DEDUCTED ON PRIOR RETURN
008041-AM FALLS - UNAMORTIZED DEBT EXP
008042-GAIN/LOSS ON REACQUIRED DEBT-
008045-ST TAX-AUDIT STTLMNTS PAID THIS YR
008062-FERC ORDER 2000 COSTS
008072-INTANGIBLE ASSET-LABOR DEDUCT-107-FED ONLY
008074-INCREMENTAL SECURITY COSTS DEDUCTED
008077-PP INS & OTR EXP (1 YR OR LESS)-165
008501-COLl- T AX ADJ FROM BOOKS
008504-0REGON NONOP PROPERTY TAX ADJUST
008508-DEPR ADJ - NONOP - OTHER PROPERTY - NEW
ON10016-DIV PAID OED PUB UTIL
STATE INCOME TAX DEDUCTED ON FEDERAL RETURN
Total
$ (2 870,698)
(12 563,248)
794 000
(3,242 604)
(13,673,245)
219,707
(7,365)
5,462,628
000,000
731 100)
(503,266)
(47 999)
278,169
(2,251 ,115)
700,000
(240,536)
1 ,390,589
(804 951 )
(20)
125
300,000
991,785
$ (9,795,144)
------------------------
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This 'mort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2006/04
(2)D A Resubmission 04/18/2007
TAXES ACCRUED, PREPAID AND CHA GED DURING YEAR
1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during
the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the
actual, or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.
Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes.
3. Include in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other
than accrued and prepaid tax accounts.
4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
ILine Kind of Tax BALANCE AT BEGINNING OF YEAR
::1~xes ~;IaS Adjust-C argedNo.(See instruction 5)Taxes AccruE;Jd t"repai.a I axes ~nng ~ring ments(Account 236)(Include In Account 165)ear ear(a)(b)(c)(d)(e)(f)
Federal:
Income 50,890,071 47,417,184 035,895
3 Social Security - (FOAB)351 904 898 117 868,447
4 Unemployment 36,235 117 591 114 279
Subtotal Federal 278,210 432 892 84,018,621
7 State of Idaho:
8 Property 094 309 366 708 11,716,731
9 Income 269,333 815,467 538,469
KWH 96,161 058,404 061 573
Unemployment 395 262,673 265,469
Regulatory Commission 682 342 682 342
Business License - Sho Ban 150 150 150
Subtotal Idaho 17,481 198 150 19,185,744 264 734
State of Oregon
Property 986 772 992 276 010 525
Income 168,761 321 268 561,483
Regulatory Commission 102,377 102 377
Unemployment 856 305 17,688
Franchise 122 634 503 988 500,221
Subtotal Oregon 292,251 986 772 938 214 192 294
State of Montana:
Property 46,694 363 96,418
Subtotal Montana 46,694 99,363 96,418
State of Nevada:
Property 419,320 857 398 850,033
Business Tax 100 100
Subtotal Nevada 419,320 857,498 850,133
State of Wyoming
Corporate License 144 144
Property 496,473 028,150 010 548
Subtotal Wyoming 496,473 031 294 013,692
Other States Income 588 880 623 399
Payroll Adjustment 10,293,932
TOTAL 183 706 406 242 218,450 113,481,291
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 2006/04
(2)0 A Resubmission 04/18/2007
TAXES ACCI UED, PREPAID AND CHARGED DURING YEAR (Continued)
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).
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 t~xes 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 Het.Other No.
Acco~nt 236)(Incl. in Account 165)(Account 408., 409.(Account 409.Earnings (Account 439)
(h)(i)(k)(I)
271 360 572,378 I:~r~~~
;' ,
.. ~Jf'
" '
0' -1---381 573 898 117
547 117 591
692 480 588 086 155 194
744 361 10,334 859
546,331 899 888
.. ,
992 058,404
600 262 673
682,342
150 150
12,402 284 225 19,238,316 572
005,022 988,384
928 546 325 560
102 377
1,474 305
126,401 503 988
056,421 005,022 938,614 400
639 363
639 363
411,955 857 398
100
411,955 857,498
144
514 075 028 150
514 075 031 294
510 858 191 117!!,,"'
J"'
~j',,~'
~ '&ii1~~.ftf~ii~~,
~ ..
293 932
40,225 757 417 202 76,428 048 209 598
FERC FORM NO.1 (ED. 12-96)Page 263
This Page Intentionally Left Blank
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
FOOTNOTE DATA
ISchedule Page: 262Account 409.
234
Line No.Column: I$(4,206,659)
(948,535)
-----------
Total $(5,155,194)
-----------------------
Schedule Page: 262 Line No.Column: I
Account 408.
Schedule Pa e: 262 Line No.Column: I
Account 409.86,225
234 (170,646)
----------
Total (84,421)
--------------------
Schedule Page: 262 Line No.Column: I
Account 408.
Schedule Pa e: 262 Line No.Column: I
Account 409.385
234 (8,677)
---------
Total (4,292)
ISchedule Page: 262
Account 409.
234
Line No.
$ 1 461
(2,893 )
Column: I
---------
Total $ (1,432)
------------------
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2006/04
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) A Resubmission 04/18/2007
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
nonutilityoperations. 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.rne Account a ance at egmmngNo Subdivisions of Year(a) (b)
510%
611%
1 Electric Utility
23%
34%385,680
7 Other - State
8 TOTAL
9 Other (List separately
and show 3%, 4%, 7%,
10% and TOTAL)
10 Line 6 Col A 11%
256 810
1,401 677
742 106
68,786 273
411 840 143
840,143
411
~-~~--
742 106 411 840,143 411 426,
FERC FORM NO.1 (ED. 12-89)Page 266
Name of Respondent
Idaho Power Company
ACCUMULATED D
Date of Report Year/Period of Report
(Mo, Da, Yr) End of 2006/04
04/18/2007
S (Account 255) (continued)
ADJUSTMENT EXPLANATION Line
No.
232 965
32,350,078
374 592
155,507
69,113,142
-~-,,-~--
34,155,507
FERC FORM NO.1 (ED. 12-89)Page 267
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmisslon 04/18/2007
0 HER DEFFERED CREDITS (Account 253)
1, Report below the particulars (details) called for concerning other deferred credits.
2. For any deferred credit being amortized, show the period of amortization.
3. Minor items (5% of the Balance End of Year for Account 253 or amounts less than $10 000, whichever is greater) may be grouped by classes,
Line Description and Other Balance at DEBITS Balance at
No.Deferred Credits Beginning of Year Contra Amount Credits End of Year
(b)Account(a)(c)(d)(e)(f)
Joint Pole Use 465,668 :=;C""'" .n
~;~~
647 889 182,221
Bureau of Land Mngt Rents/ROW 011,800 770,740 888,417 129,477
~!:" '~ , '
Point to Point Transmission Study 129 930 350 875 730 875 509 930
:.'; , . ,
FTV 866 666 800 639 000,639 066,666
Linden Feeder 329,489 107 499 102,533 420,523
SWIP Deposit 600,000 400,000 000 000
IDACOMM Dark Fiber 000 454 000
City of Eagle 53,437 53,437
Sho Ban Trans ROW 2,428,333 242 211 666 098,333 315,000
Delivery Accruals 71,673 112,223 59,858 19,308
Construction Work In Progress 569 896 107 435 240 10,865,344
Customer Level Pay 135,105 142 646,234 540,099 028,970
US Airforce Photovoltaic Generator 203 957 190 244 147
Security Plan 756,298 645,347 889,050
Milner Falling Water 456,957 264 100 721 057
Postretirement Benefits 653,421 688 770 342,191
Benefit Plan - Minimum Liability 511,488 228 511,488
Directors Deferred Compensation 3,473 798 232 327,488 570,483 716 793
TOTAL 672 479 68,479 328 26,374,349 25,567 500
FERC FORM NO.1 (ED. 12-94)Page 269
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
FOOTNOTE DATA
ISchedule Page: 269 Line No.Column:
454
143
242
Total
$ (399,340)
(508,720)
(739.829)
$(1 647 889)
Line No.Column: ISchedule Page: 269
107
232
253
107
Total
$ (131 296)
206,458)
(432,403)
(583)
$(1 770,740)
ISchedule Page: 269 Line No.
232
242
Total
Column:
$(1 106,500)
(244,375)
$(1 350,875)
Schedule Page: 269 Line No.Column:
454 $(400,639)
242 (400,000)
Total $(800,639)
Schedule P e: 269 Line No.Column:
232 $ (96,769)
107 (14 676)
401 (778)
Total $(112 223)
Schedule Page: 269 Line No.Column:
Total
232
241
228
$ (1 949,291)
(403,452)
(30,292,604)
$(32,645,347)
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2006/04
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) DA Resubmission 04/18/2007
ACCUMULATED DEFERRED INCOME TAXES - ACCELERATED AMORTIZATION PROPERTY (Account 281)
1. Report the information called for below concerning the respondent's accounting for deferred income taxes rating to amortizable
property.
2. For other (Specify),include deferrals relating to other income and deductions.
CHANGES DURING YEARLine
No.
Account Balance at
Beginning of Year
(a)
1 Accelerated Amortization (Account 281)
2 Electric
(b)
Amounts Debited
to Account 410.
(c)
Amounts Credited
to Account 411.
(d)
3 Defense Facilities
4 Pollution Control Facilities
5 Other (provide details in footnote):
8 TOTAL Electric (Enter Total of lines 3 thru 7)
9 Gas
10 Defense Facilities
11 Pollution Control Facilities
12 Other (provide details in footnote):
15 TOTAL Gas (Enter Total of lines 10 thru 14)
17 TOTAL (Acct 281) (Total of 8 15 and 16)
18 Classification of TOTAL
19 Federal Income Tax
20 State Income Tax
21 Local Income Tax
NOTES
FERC FORM NO.1 (ED. 12-96)Page 272
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2006/Q4
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) A Resubmission 04/18/2007
ACCUMULATED DEFERRED INCOME TAXES - ACCELERATED AMORT ZATION PROPERTY (Account 281) (Continued)
3. Use footnotes as required.
CHANGES DURING YEAR
Amounts Debited Amounts Credited
to Account 410.to Account 411.
ADJUSTMENTS
Amount
Balance at
End of Year
Line
No.
Debits
r--'
~------~
NOTES (Continued)
FERC FORM NO.1 (ED. 12-96)Page 273
Name of Respondent
Idaho Power Company
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) DA Resubmission 04/18/2007
ACCUMULATED DEFFERED INCOME TAXES - OT ER 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.
Year/Period of Report
End of 2006/04
Line
No.
CHANGES DURING YEAR
Account Balance at
Beginning of Year
(a)(b)
Amounts Debited
to Account 410.
(c)
Amounts Credited
to Account 411.
(d)
1 Account 282
2 Electric
3 Gas
Other
5 TOTAL (Enter Total of lines 2 thru 4)
6 Non-Operating Property
7 Other - FASB 109
239 876 397
267 308
346,116,633
580,695 11,339,130
9 TOTAL Account 282 (Enter Total of lines 5 thru
10 Classification of TOTAL
586 260,338 580,695 339,130
11 Federal Income Tax
12 State Income Tax
495,099,794
160,544
563,016
17,679
11,339 130
13 Local Income Tax
NOTES
FERC FORM NO.1 (ED. 12-96)Page 274
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2006/04
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) A Resubmission 04/18/2007
ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282) (Continued)
3. Use footnotes as required.
CHANGES DURING YEAR
Amounts Debited Amounts Credited
to Account 410.to Account 411.
ADJUSTMENTS
Amount
Credits
AccountDebited
(i)
Amount
Balance at
End of Year
Line
No.Debits
NOTES (Continued)
FERC FORM NO.1 (ED. 12-96)Page 275
This Page Intentionally Left Blank
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
FOOTNOTE DATA
Schedule Paae: 274 Line No.Column: b
006 Changes during Year Adjustments Debits Adjustments 2006
Credits
Beginning DR to CR to DR to CR to Acct.Acct.Ending
Line Account Balance 410.411.1 410.411.Amt Amt Balance
No.(a)
Line 2:Accelerated Depreciation 226 279 313 907 961 732 993 219,454,280
Intangible Asset-Labor Ded 079,880 247 856 11,327 736
FERC Jurisdictional 818,502 818 502
N. Valmy 810,266 76,500 733,766
Bridger 324 857 102,400 222 457
CIAC Taxable Inc-Acct 253.575 531 85,531
Repair Allowance 185 53,185
Engineering Fees in Acct 107 (35,263)(35,263)
Misc Software Develop Costs (844,491)721 045)565 535)
Taxable CIAC in CWIP Bal.730 646)(818 815)288,522 16,837,982)
TOTAL Line 2 239 876 397 580,695 339,131 230 117 961
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent
Idaho Power Company
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/18/2007
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 2006/04
(a)
Balance at
Beginning of Year
(b)
Line
No.
Account
1 Account 283
949 275
9 TOTAL Electric (Total of lines 3 thru 8)
10 Gas
17 TOTAL Gas (Total of lines 11 thru 16)
350,465
19 TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18)
20 Classification of TOTAL
21 Federal Income Tax
22 State Income Tax
23 Local Income Tax
19,863,985
916 754
599,008
-883,481
877,783
622,362
NOTES
FERC FORM NO.1 (ED. 12-96)Page 276
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2006/04
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) A Resubmission 04/18/2007
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.
CHANGES DURING YEAR
Amounts Debited Amounts Credited
to Account 410.to Account 411.
ADJUSTMENTS
Balance at
End of Year
(k)
Line
No.
13,498,365
107 597
107,597
054,557
054,557
896,235
32,394 600
~-----~-~----
492
492
359
359 107 597 18,054 557
352,332
746,932
606
886
165 90,260
17,337
15,145 139
909,418
27,443,632
303,300
~-------~-"---'
NOTES (Continued)
FERC FORM NO.1 (ED. 12-96)Page 277
This Page Intentionally Left Blank
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
FOOTNOTE DATA
Schedule Paae: 276 Line No.: 3 Column:
2006 Changes during Year Adjustments Adjustments 2006
Debits Credits
Other Electric (283)Beginning DR to CR to CRto Acct.Acct.Ending
Line Account Balance 410.411.1 410.411.credite Amount debite Amou Balance
No.(a)
Line 3:
PCA Expense Deferral 995 966 764 810)584,453 646 703
Conservation Programs 704 643 267 696 4,436 949
Oregon Excess Power Casts 414 046 254 390 931 163 737 272
IPUC Grid West Loans 364,435 364,435
Loss on Reacquired Debt (1,229,581)641 599 214 966 197 052
Incremental Security Costs 224 776 038 130 739
FERC Grid West Expense 118 113 118,113
OPUC Grid West Loans 896 896
Professional Fees - IPUC Order
29505 16,131 824 306
FERC Order 2000 Costs 880 073 (118,113)761 961
FERC Order 144A (525,056)(361 956)(163,100\
TOTAL Line 3
22,480,999 (5,482 489)500,146 13,498,365
Schedule Page: 276 Line No.: 8 Column:
I line 8:
FAS 158 - Pension
190 11 ,263,649 11,263,649
FAS 158 - Postretirement Plan 186/190 790,909 790 908
Unrealized gains on Market Securities 949,275
219 107 598 219 841 677
TOTAL Line 8 949 275
107 598 18,054 558 18,896,235
Schedule Page: 276 Line No.: 18 Column:
Page 274 - Accumulated Deferred Income Taxes - Other Property (Account 282)
2006 Changes during Year Adjustments Adjustments 2006
Debits Credits
Beginning DRto CRto DR to CRto Ace!.Ace!.Ending
line Account Balance 410.411.410.411.credited Amount debited Amount Balance
No.(a)
line 18: Advance Coal Royalties 326,666 39,095 287 571
Oregon Non-Op Prop Tax Adj 808 757
Unrealized Gainlloss From Rabbit Trust 22,991 (5,492)(46 505)004
TOTAL line 18 350,465 (5,492)(7,359)352,332
IFERC FORM NO.1 (ED. 12-87)Page 450.
This Page Intentionally Left Blank
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2006/Q4
(2) (JA Resubmission 04/18/2007
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 QuarterIYear ~ccount Amount Credits QuarterlY earCredited
(a)(b)(c)(d)(e)(f)
Market to Market Short Term 244,432 175 368,821 124389
-'"
934,462Demand Side Management Rider 29026 146 841 . :O::1J!228 977 016 598
Demand Side Management Rider OR 214 834 302 997 481 894 393,731
,: ' . ,:~ '
Other Deferred Credit- PCA 1823 162793 803 150 942 101 851 702
BPA Credit-Residential- Idaho 841 354 805,810 18,075 11~110 658
BPA Credit-Residential- Oregon 682431 745 63,368
BPA CredR-Farm - Idaho 534405-923016 312 360 923 749
BPA Credit-Farm - Oregon 978 142 533 013 26,458
BPA Credit- Conservation 173,666--992,418 818 752
IPUC Order 29600 020,833 182 020 833
Emission Sales Pre Tax 979,291 80,727249 10,747 958
Emission Sales Interest- Idaho 691-727033 706 355 025,013
Emission Sales Interest- Oregon 129 108 871 118 000
Boise Operation Center 306 306
Unfunded Accumulated Deferred Income Tax 627446 282 811 263,622 825,257
Asset Retirement Oblication - Removal Cost 152 683099 3,478 949 156 162,048
41 TOTAL 276,567 305 281,744 038 230,907 775 225,731 042
FERC FORM NO. 1/3-Q (REV 02-04)Page 278
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
FOOTNOTE DATA
Schedule Pa e: 278 Line No.Column:
107 120
131
142 1,401 723
154 099,031
165 298
184 907
232 344 746
242 127 700
254 203,867
401 36,564
$ 11 ,228,977
Schedu/e Page: 278 Line No.Column:
142 53,440
154 878
165 607
184 469
232 230,143
242 820
254 726
401 880
421
302,997
Schedu/e Page: 278 Line No.Column:
131 310
142 17,402 446
143 400,054
805,810
Schedu/e Page: 278 Line No.Column:
131
142 681 122
143 223
682,431
Schedule Pa e: 278 Line No.Column:
131
142 923,014
1 ,923,016
Schedu/e Page: 278 Line No.Column:
143 14,454
154 791
232 912 686
242 31,348
254 009
401 112
431
992,418
Schedule Page: 278 Line No.Column:
FERC FORM NO.ED. 12-Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
FOOTNOTE DATA
$ 80,725,147
102
$ 80,727 249
ISchedule Page: 278 Line No.182 $ 617 203431 109,831
$ 727 033
182
232
Column:
ISchedule Page: 278163
401
402
Line No.: 27
293
928
085
29,306
Column:
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2006/04
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) A Resubmission 04/18/2007
, E ECTRIC 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.
(a)
Operating Revenues Year
to Date Quarterly/Annual
(b)
Operating Revenues
Previous year (no Quarterly)
(c)
Line
No.
Title of Account
1 Sales of Electricity
2 (440) Residential Sales
3 (442) Commercial and Industrial Sales
4 Small (or Comm.) (See Instr. 4)
5 Large (or Ind.) (See Instr. 4)
6 (444) Public Street and Highway Lighting
7 (445) Other Sales to Public Authorities
8 (446) Sales to Railroads and Railways
9 (448) Interdepartmental Sales
10 TOTAL Sales to Ultimate Consumers
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
299,487 636
231 430,314
102 958,015
392,957
247 103,087
118 259 189
2,419,886
636,374,840
260,717 491
897,092,331
211 251
895,881 080
667 269 798
142,794,426
810 064 224
400,102
810,464 326
15 Other Operating Revenues
16 (450) Forfeited Discounts
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
5,424 893 5,475 745
16,858,178 912 109
12,454,460 223,771
22 (456.1) Revenues from Transmission of Electricity of Others
23 (457.1) Regional Control Service Revenues
24 (457.2) Miscellaneous Revenues
26 TOTAL Other Operating Revenues
27 TOTAL Electric Operating Revenues
737,531
930,618,611
38,611 625
849 075 951
FERC FORM NO. 1/3-Q (REV. 12-05)Page 300
Name of Respondent
Idaho Power Company
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) DA Resubmission 04/18/2007
E ECTRIC OPERATING REVENUES (Account 400)
Year/Period of Report
End of 2006/Q4
5. Commercial and industrial Sales, Account 442, may be classified according to the basis of classification (Small or Commercial, and Large or Industrial) regularly used by the
respondent if such basis of classification is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of Accounts. Explain basis of classification
in a footnote.
6. See pages 108-109, Important Changes During Period, for important new territory added and important rate increase or decreases.
7. For lines 2 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.(f)
(g)
368,218 077 227 76,343 448
3,475 157 422 616 130 129
172 28,694 789 640
939 314 13,288,812 464 969 448,819
820,823 773 852
760 137 062,664 464 969 448,
19,760,137 16,062,664 464,969 448 819
Line 12, column (b) includes $
Line 12, column (d) includes
215,836
28,191
of unbilled revenues.
MWH relating to un billed revenues
FERC FORM NO. 1/3-0 (REV. 12-05)Page 301
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 2006/04(2) DA Resubmission 04/18/2007
SALES OF ELECTRICITY BY RATE HEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12
if all billings are made'monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Ine l'IUmDer ana Ime or Hate scneoule Mvvn ;:'010 Hevenue Average'Nurfiber KWnot tiales 1(w~~e rlrNo.(a)(b)(c)of cus~omers Per 9~stomer
(f)
1 440 - Residential Sales:
2 01 - Residential 084 646 303 353 321 387 552 120 0597
3 04 - Residential - EW 097 982 15,451 0592
05 - Residential - TOD 34;1 80,291 16,000 0597
5 15 - Dusk to dawn lighting 2,458 440 548 1792
6 Unbilled Revenues 778 345,588 1995
7 Total 440 067 767 299 593 554 387 701 071 0591
9 442-Commercial & Industrial Sales
07 - General service 267 332 19,557,378 577 731 0732
09 - General service 362 545 096,260 132 746,553 0361
09 - General service 102,085 128 573 864 22,425 138,332 0414
09 - General service 844 108,463 1,422,000 0381
15 - Dusk to Dawn Light 867 614 063 1588
19 - Uniform rate contracts 126 165 982,257 121 17,571,612 0320
19 - Uniform rate contracts 439 301 301 8,439,000 0357
19 - Uniform rate contracts 189,629 323,486 37,925,800 0281
24 - Irrigation Pumping 617,905 659,508 965 90,059 0437
25 - Irrigation Pumping -Time of 17,556 782,417 113 155 363 0446
40 - General service 045 775,900 129 440 0552
Commercial & Industrial & Unbill 130 96;:26,613,432 376,987,667 0235
Total 442 843 375 334 388,329 76,473 115,640 0378
444 - Public Street Lighting:
40 - General service 923 105 556 510 771 0549
41 - Street lighting 58E 088,98'146 141 000 1015
42 - Traffic control lighting 663 198,416 133 579 0350
Total 444 28,172 392 957 789 35,706 0849
TOTAL Billed 13,911 642,590,676 464,96!046
Total Un billed Rev.(See Instr. 6)28,191 215,836 220
TOTAL 939,31~636 374,840 464 97~045
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 2006/04(2)D A Resubmission 04/18/2007
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:
RO - 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 RO service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Avera Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly iIIing Avera Avera
cation Tariff Number Demand (MW)Monthly NC Deman Monthly CP em and
(a)(b)(c)(d)(e)(I)
1 Raft River Rural Electric V6-573 573 675
Raft River Rural Electric V6-n/a n/a
3 Raft River Rural Electric V6-n/a n/a n/a
4 City of Weiser V6-055 051 830
8 American Electric Power Service Cor Wspp n/a n/a n/a
Arizona Public Service Co.WSPP n/a n/a n/a
Arizona Public Service Co.WSPP n/a n/a n/a
Arizona Public Service Co.WSPP n/a n/a n/a
Arizona Public Service Co.WSPP n/a n/a n/a
Avista Corp. - WWP Div.WSPP n/a n/a n/a
Avista Corp. - WWP Div.WSPP n/a n/a n/a
Subtotal RO
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310
This ~ort Is: Date of Report
(1) I2U An Original (Mo, Da, Yr)(2) DA Resubmission 04/18/2007
SALES FOR RESALE (Account 447) (Continued)
as - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RO sales together and report them starting at line number one. After listing all RO sales, enter "Subtotal - RO"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RO" in column (a) after this Listing. Enter
Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RO sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (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 (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RO/Non-RO grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page
401 , line 23. The "Subtotal - Non-RO" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2006/04
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)(g)
(h)(i)(k)
628 256,028 1,470,832
93,593
50,325 920,472
000 197,130
185 375
000 000
127
686,194 519,003
441 431 890
115 274 985 274 985
108,970
711,853
783 696 175 142
248,955,228
526,433
276,992
485,271
257 232 220
820,823 783,696 251,130,370 803,425 260,717,491
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 2006/04
(2)D A Resubmission 04/18/2007-
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 Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
Avista Energy, Inc.WSPP n/a nla nla
Avista Energy, Inc.WSPP n/a nla n/a
Avista Energy, Inc.WSPP n/a nla n/a
Avista Energy, Inc.WSPP nla n/a n/a
Barclays Bank PLC WSPP n/a nla n/a
Benton County PUD WSPP nla n/a n/a
7 Black Hills Power Inc.WSPP nla nla n/a
8 Black Hills Power Inc.wSPP n/a n/a nla
Black Hills Power Inc.WSPP n/a n/a n/a
Bonneville Power Administration WSPP nla n/a n/a
Bonneville Power Administration wSPP nla n/a n/a
Bonneville Power Administration WSPP n/a nla n/a
BP Energy Company wSPP n/a nla nla
BP Energy Company wSPP n/a n/a n/a
Subtotal RO
Subtotal non-
Total
FEAC FORM NO.1 (ED. 12-90)Page 310.
This ~ort Is: Date of Report(1) l2S.JAn Original (Mo, Da, Yr)
(2) A Resubmission 04/18/2007
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-ROu in column (a) after this Listing. Enter
Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RO sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RO grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - ROu 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.
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2006/04
MegaWatt Hours
Sold
599,223
929,
20,003
975
204
13,675
537
908,42
1,498,438
2,400
1 ,525,490
649 005
330,000
785
REVENUE
Energy Charges
($)
(i)
Other Charges
($)
Total ($)
(h+i+j)
(k)
(g)
Demand Charges
($)
(h)
790
95,490
330,709
600
317
981
871
36,933
58,883
000
491
108,970
711 853
783 696 175,142
248,955 228
526,433
276,992
3,485,271
257,232 220
820,823 783,696 251,130,370 803,425 260,717,491
FERC FORM NO.1 (ED. 12-90)Page 311.
Line
No.
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 2006/Q4
(2)DA Resubmission 04/18/2007
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:
RO - 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 RO service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Avera Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly iIIing Avera Avera
cation Tariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 BP Energy Company WSPP n/a n/a n/a
Burbank, City of WSPP n/a n/a nla
Burbank, City of WSPP n/a n/a nla
4 Calpine Energy Services, loP.WSPP nla nla n/a
5 Cargill Power Markets LLC WSPP n/a nla n/a
6 Cargill Power Markets LLC WSPP n/a n/a nla
7 Cargill Power Markets LLC WSPP n/a nla nla
8 Chelan Co PUD WSPP n/a n/a nla
9 Chelan Co PUD WSPP n/a n/c nla
Citigroup Energy Inc.WSPP n/a n/a nla
Clatskanie PUD WSPP n/a nla n/a
Clatskanie PUD WSPP n/a n/a n/a
Conoco Phillips Company WSPP n/a nla n/a
Conoco Phillips Company WSPP n/a n/a n/a
Subtotal RQ
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
This ~ort Is: Date of Report(1) l!.IAn Original (Mo, Da, Yr)
(2) DA Resubmission 04/18/2007
SALES FOR RESALE (Account 447) (Continued)
as - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RO sales together and report them starting at line number one. After listing all RO sales, enter "Subtotal - RO"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RO" in column (a) after this Listing. Enter
Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RO sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (6D-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (6D-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 (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RO grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-ROD amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
4D1 iine 24.
10. Footnote entries as required and provide explanations following all required data.
Year/Period of Report
End of 2006/04
Name of Respondent
Idaho Power Company
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)(g)
(h)(i)(k)
344 935 18,333,250 333,250
098 45,
681 374,300
645 19,662
527 869
4,47
122 677 101 800
222 725
200 800
200 659,
855 35,605
600 100
019 100,
600 800 17,
108,970
711 853
783 696 175,142
248,955,228
526,433
276 992
485 271
257,232,220
820,823 783,696 251,130,370 803,425 260,717,491
FERC FORM NO.1 (ED. 12-90)Page 311.
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 2006/04
(2)DA Resubmission 04/18/2007
SALES FOR RESALE (Account 447)
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RO - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RO service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Avera Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly iIIing Avera Avera
cation Tariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Constellation Energy Commodities Gr WSPP n/a nla nla
Constellation Energy Commodities Gr WSPP nla n/a nla
Coral Power, LLC WSPP nla n/a n/a
Coral Power, LLC WSPP n/a n/a n/a
DB Energy Trading, LLC WSPP n/a n/a n/a
6 DB Energy Trading, LLC WSPP nla nla n/a
Douglas County PUD WSPP n/a n/a n/a
8 EI Paso Electric Company WSPP n/a n/a n/a
9 Eugene Water & Electric Board WSPP n/a nla n/a
Eugene Water & Electric Board WSPP nla n/a nla
Franklin County P.WSPP n/a n/a n/a
Grant County P.U.D.V6-n/a n/a n/a
Grant County P.WSPP n/a n/a n/a
Grant County P.WSPP nla n/a n/a
Subtotal RO
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2006/04
This ~ort Is: Date of Report(1) l!J An Original (Mo, Da, Yr)
(2) DA Resubmission 04/18/2007
SALES FOR RESALE (Account 447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RO sales together and report them starting at line number one. After listing all RO sales, enter "Subtotal - RO"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-ROw in column (a) after this Listing. Enter
Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RO sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (50-minute
integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RO grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - ROo 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
Sold
104,090
153,327
240
775
78,100
REVENUE
Energy Charges
($)
(i)
Other Charges
($)(j)
Total ($)
(h+i+j)
(k)
(g)
Demand Charges
($)
(h)
550
767 306
18,625
861,123
500
845 510
285
47,377
362
89,834
400
600
100
564
625
105
975
800
108 970
711 853
783,696 175,142
248,955,228
526,433
276 992
485,271
257 232 220
820,823 783,696 251,130,370 803,425 260,717,491
FERC FORM NO.1 (ED. 12-90)Page 311.
Line
No.
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 2006/04
(2)D A Resubmission 04/18/2007
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:
RO - 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 RO service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that 'intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Avera Actual Demand (MW)
Classifi-Schedule or Monthly illing AVera AveraNo.(Footnote Affiliations)cation Tariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Grays Harbor PUD WSPP nla nla n/a
J. Aron & Company WSPP n/a nla nla
3 Los Angeles Department of Water and WSPP n/a n/a n/a
4 Morgan Stanley Capital Group Inc.WSPP nla nla n/a
5 Morgan Stanley Capital Group Inc.WSPP nla n/a n/a
6 Morgan Stanley Capital Group Inc.WSPP n/a n/a nla
7 Morgan Stanley Capital Group Inc.WSPP nla nla n/a
8 Northern California Power Agency WSPP n/a n/a nla
9 Northern California Power Agency WSPP n/a n/a n/a
Northern California Power Agency WSPP n/a n/a nla
NorthWestern Energy 147 nla n/a n/a
NorthWestern Energy 147 nla n/a n/a
NorthWestern Energy WSPP n/~nla n/a
Pacific Northwest Generating Cooper WSPP n/a nla nla
Subtotal RO
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.4
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) DA Resubmission 04/18/2007
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)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RO/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - Rap 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.
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2006/04
MegaWatt Hours
Sold
050
105,050
38,40
046,40
835 968
132,47
271
286 695
103,767
508,
545 475
13,730
890
REVENUE
Energy Charges
($)
(i)
Other Charges
($)
Total ($)
(h+i+j)
(k)
(g)
Demand Charges
($)
(h)
000
800
19,200
883
711,372
829
554
848
268
108 970
711 853
3,485,271
257 232,220
783,696 175 142
248 955,228
526 433
276,992
820 823 803,425 260,717,491783,696 251,130,370
FERC FORM NO.1 (ED. 12-90)Page 311.
Line
No.
Name of Respondent This '(g)ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007
SALES FOR RESALE (Account 447)
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( i., 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 (i.e., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of 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 Avera Avera
cation Tariff Number Demand (MW)Monthly NC Deman Monthly CP em and
(a)(b)(c)(d)(e)(f)
1 Pacific Northwest Generating Cooper WSPP nla n/a n/a
2 PacifiCorp Inc.WSPP n/a n/a n/a
3 PacifiCorp Inc.WSPP nla nla nla
4 PacifiCorp Inc.WSPP nla n/a nla
5 PacifiCorp Inc.V6-n/a nla n/a
6 PacifiCorp Inc.n/a n/a n/a
7 Pinnacle West Capital Corporation WSPP n/a n/a n/a
8 Portland General Electric Company WSPP n/a n/a n/a
9 Portland General Electric Company WSPP nla n/a n/a
Portland General Electric Company WSPP n/a n/a n/a
Portland General Electric Company V6-54 n/a nla n/a
Powerex Corp.WSPP nla n/a n/a
Powerex Corp.WSPP nla n/a n/a
Powerex Corp.WSPP nla nla n/a
Subtotal RO
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) DA Resubmission 04/18/2007
SALES FOR RESALE (Account 447) (Continued)
as - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups. for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RO sales together and report them starting at line number one. After listing all RO sales, enter 'Subtotal - RO"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RO" in column (a) after this Listing. Enter
Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RO sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the 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
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 (D. Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RO grouping (see instruction 4), and then totaled on
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.
Name of Respondent
Idaho Power Company
YearlPeriod of Report
End of 2006104
MegaWatt Hours
Sold
(g)
REVENUE
Energy Charges
($)
(i)
Total ($)
(h+i+j)
(k)
Other Charges
($)
Demand Charges
($)
(h)
600 030
18,761
219,064
215
1,400
364
148,280
905
677,132 25,726,304
108,970
711,853
783,696 175 142
248 955,228
526,433
276 992
3,485,271
257 232 220
820,823 783,696 251,130,370 803,425 260,717,491
FERC FORM NO.1 (ED. 12-90)Page 311.
Line
No.
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 2006/04(2) 0 A Resubmission 04/18/2007
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:
RO - 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 RO service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Avera Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly iIIing Avera Avera
cation Tariff Number Demand (MW)Monthly NC Deman Monthly CP em and
(a)(b)(c)(d)(e)(f)
1 PPL Montana, LLC WSPP n/a nla n/a
2 PPL Montana, LLC WSPP n/a n/a n/a
3 PPL Montana, LLC WSPP n/a n/a n/a
4 PPL Montana, LLC V6-n/a nla nla
5 PPM Energy, Inc.WSPP n/a n/a n/a
6 PPM Energy, Inc.WSPP n/a n/a n/a
7 PPM Energy, Inc.WSPP nla nla n/a
8 Public Service Co.of Colorado WSPP n/a n/a n/a
9 Public Service Co. of Colorado WSPP n/a n/a nla
Public Service Company of New Mexic WSPP nla nla nla
Public Service Company of New Mexic WSPP n/a n/a n/a
Puget Sound Energy, Inc.WSPP nla n/a n/a
Puget Sound Energy, Inc.WSPP n/a nla n/a
Rainbow Energy Marketing Corporatio WSPP n/a nla nla
Subtotal RO
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
Year/Period of Report
End of 2006/04
This ~ort Is: Date of Report(1) l2S..)An Original (Mo, Da, Yr)
(2) DA Resubmission 04/18/2007
SALES FOR RESALE (Account 447) (Continued)
as - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups' for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RO sales together and report them starting at line number one. After listing all RO sales, enter .Subtotal - RO'
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RO" in column (a) after this Listing. Enter
Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RO sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (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 (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RO/Non-RO grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RO" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
Name of Respondent
Idaho Power Company
MegaWatt Hours
Sold
(g)
REVENUE
Energy Charges
($)
(i)
Other Charges
($)(j)
Demand Charges
($)
(h)
9,425
658
521
163,100
045
200
853
3,400
23,416
76,142
167
108 970
711 853
783 696 175,142
248 955,228
526,433
276,992
820,823 783,696 251 130,370 803,425
FERC FORM NO.1 (ED. 12-90)Page 311.
Total ($)
(h+i+j)
(k)
19,457
350 671
559,40
63,455
111 661
926,306
450
95,
44,466
141 250
907 915
346,801
120 868
485,271
257 232 220
260,717,491
Line
No.
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 2006/04
(2)DA Resubmission 04/18/2007
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 Deman Monthly CP emand
(a)(b)(c)(d)(e)(I)
1 Rainbow Energy Marketing Corporatio WSPP n/a n/a n/a
2 Sacramento Municipal Utility Distri WSPP n/a n/a n/a
3 Salt River Project WSPP nla n/a n/a
4 Seattle City Light WSPP n/a n/a n/a
5 Seattle City Light WSPP n/a n/a n/a
6 Sempra Energy Trading Corporation WSPP nla n/a n/a
7 Sempra Energy Trading Corporation WSPP nla n/a nla
8 Sempra Energy Trading Corporation WSPP n/a n/a n/a
9 Sempra Energy Trading Corporation WSPP n/a n/a n/a
Sierra Pacific Power Company WSPP n/a n/a n/a
Sierra Pacific Power Company WSPP nla n/a n/a
Sierra Pacific Power Company n/a n/a n/a
Snohomish County PUD WSPP n/a n/a n/a
Snohomish County PUD WSPP n/a n/a nla
Subtotal RO
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) DA Resubmission 04/18/2007
SALES FOR RESALE (Account 447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RO sales together and report them starting at line number one. After listing all RO sales, enter "Subtotal - RO"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RO" in column (a) after this Listing. Enter
Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RO sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RO grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-ROo 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.
Year/Period of Report
End of 2006/04
Name of Respondent
Idaho Power Company
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)(g)
(h)(i)(k)
375 481 675 481 675
200 700 700
125 10,
13,797 554
650 380 450
505 874 902
221 952
292 869
821 161 33,994,471
536 547 360
799,249
111
10,519 423,
100 119 250 119 250
108,970
711 853
783.696 175 142
248 955 228
526 433
276,992
485 271
257 232,220
820,823 783,696 251,130 370 803,425 260,717 491
FERC FORM NO.1 (ED. 12-90)Page 311.
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 2006/Q4
(2)0 A Resubmission 04/18/2007
SALES FOR RESALE (Account 447)
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for tong-term service. 'Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of 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 ~vera Avera
cation Tariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Southern California Edison WSPP nla n/a n/a
SUEZ Energy Marketing NA, Inc.WSPP nla n/a nla
SUEZ Energy Marketing NA, Inc.WSPP n/a nla nla
Tacoma Power WSPP nla n/a nla
5 TransAlta Energy Marketing (U.) I WSPP n/a n/a n/a
6 TransAlta Energy Marketing (U.) I WSPP nla n/a n/a
7 TransAlta Energy Marketing (U.) I WSPP n/a n/a n/a
8 UBS AG, London Branch WSPP nla n/a nla
9 Utah Associated Municipal Power Sys WSPP n/a nla n/a
Utah Associated Municipal Power Sys WSPP n/a n/a nla
Utah Associated Municipal Power Sys WSPP n/a n/a n/a
LESS BAD DEBT WRITE-OFF
Subtotal RQ
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
Year/Period of Report
End of 2006/04
This ~ort Is: Date of Report(1) l2SJ An Original (Mo, Da, Yr)
(2) DA Resubmission 04/18/2007
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 Ra sales together and report them starting at line number one. After listing all Ra sales, enter "Subtotal - Ra'
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-Ran 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 Ra 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 0), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-Ra grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - Ran amount in column (g) must be reported as Requirements Sales For Resale on Page
401 , line 23. The "Subtotal - Non-Ra" 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.
Name of Respondent
Idaho Power Company
MegaWatt Hours
Sold
REVENUE
Energy Charges
($)
(i)
Other Charges
($)(j)(g)
Demand Charges
($)
(h)
614
94,404
246
275 725
560
205
498
890 605 705
108,970
711,853
783,696 175 142
248,955,228
820,823 783,696 251 130,370
FERC FORM NO.1 (ED. 12-90)Page 311.
526,433
276,992
803,425
Total ($)
(h+i+j)
(k)
114 202
093,638
162
159,278
11,388,156
403,030
127
27,552
605,705
3,485,271
257 232 220
260,717 491
Line
No.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmlssion 04/18/2007 2006/04
FOOTNOTE DATA
ISchedule Page: 310 Line No.Column: j
Customer Charge
ISchedule Page: 310 Line No.Column: j
Network Transmission Charges
'Schedule Page: 310 Line No.Column: i
Prior year adjustment.
ISchedule Page: 310 Line No.Column: j
Network transmission charges.
ISchedule Page: 310 Line No.Column: i
Non-Firm sales.
ISchedule Page: 310 Line No.10 Column: ;
Unit Contingent.
ISchedule Page: 310 Line No.11 Column: j
Financial Transmission Losses.
ISchedule Page: 310 Line No.13 Column: ;
Non-Firm sales.
ISchedule Page: 310.Line No.Column: iNon-Firm Sales.
ISchedule Page: 310.Line No.Column: i
Unit Contingent.
ISchedule Page: 310.Line No.Column: j
Financial T~anmission Losses.
ISchedule Page: 310.Line No.Column: ;
Non-Firm Sales.
ISchedule Page: 310.Line No.Column: j
Financial Transmission Losses.
ISchedule Page: 310.Line No.Column: i
Non-Firm Sales.
'Schedule Page: 310.Line No.10 Column: i
Unit Contingent.
ISchedule I'age: 310.Line No.11 Column: i
Non-Firm Sales.
ISchedule Page: 310.Line No.13 Column: i
Unit Contingent.
Schedule Page: 310.Line No.14 Column: i
Non-Firm Sales.
ISchedule Page: 310.Line No.Column: i
Non-Firm Sales.
ISchedule Page: 310.Line No.Column: i
Non-Firm Sales.
ISchedule Page: 310.Line No.Column: j
Financial Transmission Losses.
ISchedule Page: 310.Line No.Column: i
Non-Firm Sales.
Schedule Page: 310.Line No.Column: i
Non-Firm Sales.
Schedule Pa e: 310.Line No.11 Column: ;
Non-Firm Sales.
ISchedule Page: 310.Line No.13 Column: i
Non-Firm Sales.
ISchedule Page: 310.Line No.Column: i
Non-Firm Sales.
ISchedule Page: 310.Line No.Column: i
Non-Firm Sales.
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
FOOTNOTE DATA
ISchedule Page: 310.Line No.: 5 Column: i
Unit Contingent.
ISchedule Page: 310.Line No.: 7 Column: i
Non-Firm Sales.
ISchedule Page: 310.Line No.: 8 Column: i
Non-Firm Sales.
ISchedule Page: 310.Line No.Column: i
Non-Firm Sales.
ISchedule Page: 310.Line No.: 11 Column: i
Non-Firm Sales.
ISchedule Page: 310.Line No.12 Column: j
Spinning or Operating Reserves.
ISchedule Page: 310.Line No.13 Column: i
Non-Firm Sales.
ISchedule Page: 310.Line No.: 1 Column: i
Non-Firm Sales.
\Schedule Page: 310.4 Line No.Column: i
Unit Contingent.
ISchedule Page: 310.Line No.: 5 Column: j
Financial Transmission Losses.
ISchedule Page: 310.Line No.: 6 Column: i
Non-Firm Sales.
ISchedule Page: 310.4 Line No.: 8 Column: i
Unit Contingent.
ISchedu/e Page: 310.Line No.Column: i
Non-Firm Sales.
ISchedule Page: 310.4 Line No.12 Column: j
Capacity and Penalty Charge.
ISchedu/e Page: 310.4 Line No.13 Column: i
Non-Firm Sales.
ISchedule Page: 310.Line No.: 14 Column: i
Non-Firm Sales.
ISchedule Page: 310.Line No.: 2 Column: j
Financial Transmission Losses.
ISchedu/e Page: 310.Line No.: 3 Column: i
Non-Firm Sales.
ISchedule Page: 310.Line No.: 5 Column: j
Spinning or operating Reserves.
ISchedu/e Page: 310.Line No.: 8 Column: j
Financial Transmission Losses.
ISchedule Page: 310.Line No.: 9 Column: i
Non-Firm Sales.
ISchedule Page: 310.Line No.: 11 Column: j
Spinning or Operating Reserves.
ISchedu/e Page: 310.Line No.: 12 Column: j
Financial Transmission Losses.
ISchedule Page: 310.Line No.: 13 Column: i
Non-Firm Losses.
ISchedule Page: 310.Line No.: 1 Column: j
Financial Transmission Losses.
ISchedule Page: 310.Line No.: 2 Column: i
Non-Firm Sales.
'Schedule Page: 310.Line No.: 4 Column: j
Spinning or Operating Reserves.
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 04/18/2007 2006/04
FOOTNOTE DATA
ISchedule Page: 310.Line No.Column: j
Financial Transmission Losses.
'Schedule Page: 310.Line No.Column: iNon-Firm Sales.
ISchedule Page: 310.Line No.Column: iNon-Firm Sales.
ISchedule Page: 310.Line No.10 Column: iNon-Firm Sales.
ISchedule Page: 310.Line No.12 Column: iNon-Firm Sales.
'Schedule Page: 310.Line No.14 Column: i
Non-Firm Sales.
ISchedule Page: 310.Line No.Column: iNon-Firm Sales.
ISchedule Page: 310.Line No.Column: iNon-Firm Sales.
ISchedule Page: 310.Line No.Column: i
Unit Contingent.
ISchedu/e Page: 310.Line No.Column: j
Financial Transmission Losses.
ISchedule Page: 310.Line No.Column: iNon-Firm Sales.
ISchedule Page: 310.Line No.: 10. Column: i
Unit Contingent.
ISchedu/e Page: 310.Line No.11 Column: j
Financial Transmission Losses.
ISchedule Page: 310.Line No.13 Column: iNon-Firm Sales.
ISchedu/e Page: 310.Line No.Column: iNon-Firm Sales.
ISchedule Page: 310.Line No.Column: iNon-Firm Sales.
ISchedu/e Page: 310.Line No.Column: iNon-Firm Sales.
ISchedule Page: 310.Line No.Column: j
Financial Transmission Losses.
Schedule Pa e: 310.Line No.Column: iNon-Firm Losses.
Schedu/e P e: 310.Line No.Column: i
Unit Contingent.
ISchedule Page: 310.Line No.10 Column: iNon-Firm Sales.
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2006/04
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/18/2007
ELE TRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnote.Line Account Amount for
1 1. POWER PRODUCTION EXPENSES
2 A. Steam Power Generation
3 Operation
4 (500) Operation Supervision and Engineering
5 (501) Fuel
6 (502) Steam Expenses
7 (503) Steam from Other Sources
8 (Less) (504) Steam Transferred-Cr.
9 (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 Maintenance
15 (510) Maintenance Supervision and En ineering
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 Production Expenses-Steam Power (Entr Tot lines 13 & 20)
22 B. Nuclear Power Generation
23 Operation
24 (517) Operation Su ervision and Engineerin
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 Maintenance
35 (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-Nuc. Power (Entrtot lines 33 & 40)
42 C. H draulic Power Generation
43 Operation
44 (535) Operation Supervision and Engineering
45 (536) Water for Power
46 (537) H draulic Expenses
47 (538) Electric Expenses
48 (539) Miscellaneous Hydraulic Power Generation Expenses
49 (540) Rents
50 TOTAL Operation (Enter Total of Lines 44 thru 49)
51 C. H draulic Power Generation (Continued)
52 Maintenance
53 (541) Mainentance Supervision and Engineering
54 (542) Maintenance of Structures
55 (543) Maintenance of Reservoirs, Dams, and Waterways
56 (544) Maintenance of Electric Plant
57 (545) Maintenance of Miscellaneous Hydraulic Plant
58 TOTAL Maintenance (Enter Total of lines 53 thru 57)
59 TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 & 58)
Amount forPrevious Year
(c)
712 505 277,646
107 519,847 982 043
107,143 895,514
444,277 610 776
142,999 795,112
248,624 325,176
126 175,395 115,886 267
-~,.. -,--~~
525,470
408,848
377,469
433 882
575 617
321 286
153,496 681
130,215
421 603
855,366
612,002
240,867
260,053
141 146,320'_m_'..__-----,
- ,-,- -..-----,--..---, --
- mo.,_- m_'_-- u o_o._, " ,
,--,--- --- ....,____- _
n ,.. ",,o --
---
" m o,--
522,312
937 659
258,502
387,391
2,407,071
409,491
21,922,426
556,943
266,568
163,818
264 687
894,576
359,290
20,505,882
871 365
193,327
946 682
138 733
213 655
363,762
31,286 188
275,738
899 749
683 950
466 384
854 670
180,491
686 373
FERC FORM NO.1 (ED. 12-93)Page 320
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2006/04
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/18/2007
ELECTRIC OPERATION AND MAINTENANCE PENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.Line Account Amount for
60 D. Other Power Generation
61 Operation
62 (546) Operation Supervision and Engineering
63 (547) Fuel
64 (548) Generation Expenses
65 (549) Miscellaneous Other Power Generation Expenses
66 (550) Rents
67 TOTAL Operation (Enter Total of lines 62 thru 66)
68 Maintenance
69 (551) Maintenance Supervision and Engineering
70 (552) Maintenance of Structures
71 (553) Maintenance of Generating and Electric Plant
72 (554) Maintenance of Miscellaneous Other Power Generation Plant
73 TOTAL Maintenance (Enter Total of lines 69 thru 72)
74 TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73)
75 E. Other Power Supply Expenses
76 (555) Purchased Power
77 (556) S stem Control and Load Dispatching
78 (557) Other Expenses
79 TOTAL Other Power Suppl Exp (Enter Total of lines 76 thru 78)
80 TOTAL Power Production Expenses (Total of lines 21 , 41 , 59, 74 & 79)
81 2. TRANSMISSION EXPENSES
82 Operation
83 (560) 0 eration Supervision and En ineering
84 (561 Load Dispatchin
85 (561.1) Load Dispatch-Reliabili
86 (561.2) Load Dispatch-Monitor and Operate Transmission System
87 (561.3) Load Dispatch-Transmission Service and Scheduling
88 (561.4) Scheduling, System Control and Dispatch Services
89 (561.5) Reliability, Plannin and Standards Development
90 (561.6) Transmission Service Studies
91 (561.7) Generation Interconnection Studies
92 (561.8) Reliability, Plannin and Standards Development Services
93 (562) Station Expenses
94 (563) Overhead Lines Expenses
95 (564) Under round Lines Ex enses
96 (565) Transmission of Electrici bOthers
97 (566) Miscellaneous Transmission Expenses
98 (567) Rents
99 TOTAL Operation (Enter Total of lines 83 thru 98)
100 Maintenance
101 (568) Maintenance Supervision and Engineerin
102 569) Maintenance of Structures
103 (569.1) Maintenance of Computer Hardware
104 (569.2) Maintenance of Computer Software
105 (569.3) Maintenance of Communication Equipment
106 (569.4) Maintenance of Miscellaneous Re ional Transmission Plant
107 (570) Maintenance of Station Equipment
108 (571) Maintenance of Overhead Lines
109 (572) Maintenance of Under round Lines
110 (573) Maintenance of Miscellaneous Transmission Plant
111 TOTAL Maintenance (Total of lines 101 thru 110)
112 TOTAL Transmission Expenses (Total of lines 99 and 111)
Amount forPrevious Year
(c)
322 341
498 309
290 352
297,218
390 680
181 468
231,162
342 401
8,408,220 145,711
173
176,972
124 319
392,516
693 980
102 200
194
255,394
292
428,740
714 620
860,331
--...., ,...,."...",~~--"" "" ""'-'-~--__'__....
283,439,877
76,140
27,304,586
256 211 431
450 096,500
222 310,315
483
023,410
221 364 388
397,057,412
537,078
166,233
565
1 ,525,337
765,078
013,395
971 942
29,062
866 905 591 008
869 797 515 152
638 680 657 106
270 768 297,608
152 152 565,610
17,821 655 16,611 821
460,937 695,940
68,184
98,980
93,345
757
900,424 688,845
257,538 908,500
31,222 16,446
848 203 377 915
23,669,858 989,736
FERC FORM NO.1 (ED. 12-93)Page 321
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2006/04
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) A Resubmission 04/18/2007
ELECTRIC OPERATION AND MAINTENANCE E PENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.Line Account Amount forCurrent Yearo. (a)(b)
113 3. REGIONAL MARKET EXPENSES
114 Operation
115 (575.1) Operation Supervision
116 (575.2) Da -Ahead and Real-Time Market Facilitation
117 (575.3) Transmission Rights Market Facilitation
118 (575.4) Capaci Market Facilitation
119 (575.5) Ancillary Services Market Facilitation
120 (575.6) Market Monitoring and Compliance
121 (575.7) Market Facilitation, Monitoring and Compliance Services
122 (575.8) Rents
123 Total Operation (Lines 115 thru 122)
124 Maintenance
125 (576.1) Maintenance of Structures and Improvements
126 (576.2) Maintenance of Computer Hardware
127 (576.3) Maintenance of Computer Software
128 (576.4) Maintenance of Communication Equipment
129 (576.5 Maintenance of Miscellaneous Market Operation Plant
130 Total Maintenance (Lines 125 thru 129)
131 TOTAL Re ional Transmission and Market Op Expns (Total 123 and 130)
132 4. DISTRIBUTION EXPENSES
133 Operation
134 (580) Operation Supervision and Engineerin
135 (581) Load Dispatching
136 (582) Station Expenses
137 583) Overhead Line Expenses
138 (584) Underground Line Expenses
139 (585) Street Lighting and Signal S stem Expenses
140 (586) Meter Expenses
141 (587 Customer Installations Expenses
142 (588) Miscellaneous Expenses
143 (589) Rents
144 TOTAL Operation (Enter Total of lines 134 thru 143)
145 Maintenance
146 (590) Maintenance Supervision and En ineerin
147 (591) Maintenance of Structures
148 (592) Maintenance of Station Equipment
149 (593) Maintenance of Overhead Lines
150 (594) Maintenance of Underground Lines
151 (595) Maintenance of Line Transformers
152 (596) Maintenance of Street Lighting and Si nal Systems
153 (597) Maintenance of Meters
154 (598) Maintenance of Miscellaneous Distribution Plant
155 TOTAL Maintenance (Total of lines 146 thru 154)
156 TOTAL Distribution Expenses (Total of lines 144 and 155)
157 5. CUSTOMER ACCOUNTS EXPENSES
158 Operation
159 (901) Supervision
160 (902) Meter Readin Expenses
161 (903) Customer Records and Collection Expenses
162 (904) Uncollectible Accounts
163 (905) Miscellaneous Customer Accounts Expenses
164 TOTAL Customer Accounts Expenses (Total of lines 159 thru 163)
Amount forPrevious Year
(c)
--- ,
' n n "
...
, n
- '..,- ,..---..... _
051 138 845,031
020,110 536,857
159,883 945,089
856,696 967 382
042,167 733,935
154 596 120,630
288,265 108,887
148,759 773 447
589,808 603,412
149 968 157 873
24,461 390 792,543
223 168 91,162
69,106
826,028 629,976
11,020,129 10,928,110
114 786 109,939
583,246 321 335
711 171 378,751
895,593 773,149
148,970 230,529
523,091 532,057
984,481 38,324,600
537,023 494,549
254 777 723 518
10,146,625 292,260
848,490 556,140
373 28,055
787,288 16,094 522
FERC FORM NO.1 (ED. 12-93)Page 322
This Page Intentionally Left Blank
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2006/04
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/18/2007
ELECTRIC OPERATION AND MAINTENANCE E PENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.Line Account Amount for
(a)(b)
165 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
166 Operation
167 (907) Supervision
168 (908) Customer Assistance Expenses
169 (909) Informational and Instructional Expenses
170 (910) Miscellaneous Customer Service and Informational Expenses
171 TOTAL Customer Service and Information Expenses (Total 167 thru 170)
172 7. SALES EXPENSES
173 Operation
174 (911) Supervision
175 (912) Demonstrating and Selling Expenses
176 (913) Advertising Expenses
177 (916) Miscellaneous Sales Expenses
178 TOTAL Sales Expenses (Enter Total of lines 174 thru 177)
179 8. ADMINISTRATIVE AND GENERAL EXPENSES
180 Operation
181 (920) Administrative and General Salaries
182 (921) Office Supplies and Expenses
183 (Less) (922) Administrative Expenses Transferred-Credit
184 (923) Outside Services Emplo ed
185 (924) Property Insurance
186 (925) Injuries and Dama es
187 (926) Emplo ee Pensions and Benefits
188 (927) Franchise Requirements
189 (928) Re ulatory Commission Expenses
190 (929) (Less) Duplicate Charges-Cr.
191 (930.1) General Advertising Expenses
192 (930.2) Miscellaneous General Expenses
193 (931) Rents
194 TOTAL Operation (Enter Total of lines 181 thru 193)
195 Maintenance
196 (935) Maintenance of General Plant
197 TOTAL Administrative & General Expenses (Total of lines 194 and 196)
198 TOTAL Elec Op and Maint Expns (Total 80 112 131,156,164 171,178,197)
Amount forPrevious Year
(c)
-"-" "--,, ,----,--
288,822
047,316
200
847 736
184,074
281 012
575,566
763 679
620,257
,..._-
48,935,653
665 999
324 259
149,646
945,897
152,000
241 894
000
976,225
40,438,326
16,117 873
23,657 334
823,980
866,971
711 625
22,956 720
300
009 949
,~, _
___n
'--""~-'"
107,310
901,158
003
757 526
120 381
856 141
800
78,250 732
969 367
86,726 893
631 449 094
473,712
724 444
564 810,971
FERC FORM NO.1 (ED. 12-93)Page 323
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 2006/04
(2)D A Resubmission 04/18/2007
PU~CHA$ED POWER ~Accou~t 555)( ncludlng power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and 'firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy. capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Willis and Betty Deveny N/A N/A N/A
2 James B. Howell/CHI N/A N/A N/A~LU 942Mw N/A N/A
4 Owyhee Irrigation District
Mitchell Butte N/A N/A N/A
Owyhee Dam N/A N/A N/A
Tunnel #1 N/A N/A N/A
Reynolds Irrigation District N/A N/A N/A
Clifton E. Jenson 05Mw N/A N/A
Snake River Pottery N/A N/A N/A
White Water Ranch N/A N/A N/A
John R LeMoyne N/A N/A N/A
David R Snedigar N/A N/A N/A
Mud Creek Hydro, Inc N/A N/A N/A
Total
FERC FORM NO.1 (ED. 12-90)Page 326
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)D A Resubmission 04/18/2007
CCOU~~9?~~) (Contlnueo)(Including power exc ange )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (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 (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received , enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered
($)
of Settlement ($)
(g)
(h)(i)(I)(m)
851 26E 265
59E 238 84E 238,848
17/1 ,576,498 160 06~736,567
90E 127 39E 127 398
33,92E 1 ,899, 17~899,179
23,57C 2,438 94~438 942
747
29:0 500 50C 23,000
42~20E 27,208
9Of 906
62;:34,212 212
23E 64'1 644
43E 07~27.072
964 024 757 268,856 815,124 277 707 878 916 875 283,439
FERC FORM NO.1 (ED. 12-90)Page 327
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)0 A Resubmission 04/18/2007
~CHA~ED POWER hAccou~t 555)(nclu Ing 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:
RO - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Rim View Trout Company
...
N/A N/A N/A
2 Curry Cattle Company 084Mw N/A N/A
3 Branchflower Company N/A N/A N/A
4 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
8 Fisheries Development
...
N/A N/A N/A
9 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 N/A N/A
Richard Kaster
Box Canyon N/A N/A N/A
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007
ccount
~g~~\
(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
identified in column (b), is provided.
5. For requirements RO purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (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 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
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.
Received Delivered
($)\~?
of Settlement ($)
(g)
(h)(i)(m)
29~48,3Oi 305
63.26,796 12,39!19.1
62,297
33!27'22,276
501 101 141 101 147
3Of 19~193
971 24'35,24'
20:153,39(153,390
43E 149,52E 149,526
10,60/552,508 201 754,255
63(102 69!102 695
964 024 757 268,856 815 124 277 707 878 916,875 283,439,871
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)0 A Resubmission 04/18/2007
PU~C~A$ED POWER ~Accou~t 555)( nc u Ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition , the reliability of requirement service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman I Monthly CP Demand
(a)(b)(c)(d)(e)(f)
Briggs Creek N/A N/A N/A
2 David McCollum N/A N/A N/A
3 HK Hydro 1 Mud Creek S & S N/A N/A N/A
4 AlianNemon Ravenscroft 488Mw N/A N/A
5 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 N/A N/A
Consolidated Hydro Inc. 1 Enel
GeoBon #2 N/A N/A N/A
Barber Dam N/A N/A N/A
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)0 A Resubmission 04/18/2007
ccou~t
~g~\
(Contlnuea)(Including power exc ange )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (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 (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l)No.
Received Delivered
($)($)
of Settlement ($)
(g)
(h)(i)
(j)
(I)(m)
231 84E 231 846
671 83'83~
491 567
92'155 672 55,07~210,745
4,46~312 711 312 711
52'263 87'263,87E
294 171 294,177
931 266,98(266 980
8,42!525,38!525 385
20'585,481 585,481
58~486 150 127 371 613 52E
08~282,59~282 593
18,581 842,OBE 842 088
964,02~757 268 856 815 12~277 707 87E 916,875 283,439,
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007
~CHA~ED POWER ~Accou~t 555)(nclu 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:
RO - 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 RO 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)
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
4 Cedar Draw/Little Mac Power Co.N/A N/A N/A~LU N/A N/A N/A
6 Little Wood River Irrigation Dis N/A N/A N/A
Marco Rancher s Irrigation Inc.N/A N/A N/A
8 Faulkner Brothers Hydro Inc.N/A N/A N/A
9 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. f
Lemhi HydroPower Company N/A N/A N/A
J R Simplot Co.N/A N/A N/A
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2006/Q4
(2)D A Resubmission 04/18/2007
ccou~tEi~~~) (Continued)\lncludmg' power exc ange
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RO purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (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
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l)No.
Received Delivered
($)($)
of Settlement ($)
(g)
(h)(i)
(j)
(I)(m)
75S 400,86C 400 86C
74::679,63~679 632
457,07~457 079
68~352 352,615
24,97~747,46(747,460
68€495,54~495 549
34::150,09-'1 150 09-'1
35S 250 67C 250,670
40~1 ,444 54€444,546
25,38.294,17€294 176
21,84(062,30€062 306
18~12(120
24::87,20E 205
75,75E 627 95(627 950
964 024 99,757 268 856 815,12-'1 277 707 878 916 875 283,439 87 I
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent
Idaho Power Company
Date 01 Report
(Mo, Da, Yr)
04/18/2007
Year/Period of Report
End 01 2006/Q4
This ~ort Is:(1) ~An Original
(2) 0 A Resubmission
PURCHASED POWER IAccou(lt 555)(Including power excl1anges)
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 - lor 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 01 Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classili-Schedule or Monthly Billing verage verage
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Deman
(a)(b)(c)(d)(e)(I)
1 Blind Canyon Hydro N/A N/A N/A
2 City 01 Hailey N/A N/A N/A
3 City 01 Pocatello N/A N/A N/A
N/A N/A N/A
N/A N/A N/A
N/A N/A N/A
Pristine Springs Inc. #1 N/A N/A N/A
Vaagen Brothers Lumber Inc.N/A N/A N/A
Horseshoe Bend Hydro N/A N/A N/A
Contractors Power Group Inc.N/A N/A N/A
Rupert Cogeneration Partners N/A N/A N/A
Glenns Ferry Cogeneration Partne N/A N/A N/A
Lewandowski Farms N/A N/A N/A
14 Tasco - Nampa N/A N/A N/A
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007
ccount 55~~) ((,;ontlnueoj(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
identified in column (b), is provided.
5. For requirements RO purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (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 (D, energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total G+k+l)No.
Received Delivered
($)($)
of Settlement ($)
(g)
(h)(i)(I)(m)
977 366 12C 366,120
79~794
1 ,40~98,61C 610
72E 277,23E 277,235
622,44.1 ,622,442
21,89"1,424 144 1,424,144
86C 42,04.042
28~1 ,070,46~070,464
46E 981 56E 981 566
96~261,551 261 557
88.736,40 736,407
69,84C 143 143,010
15~8,4H 416
53~783 783
964 024 757 268,856 815 124 277 707 878 916,875 283,439
FERC FORM NO.1 (ED. 12-90)Page 327.4
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 2006/04
(2)D A Resubmission 04/18/2007
PU~CHAcffiED POWER ~Accou~t 555)
(nclu 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
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)
Pristine Springs Inc # 3 N/A N/A N/A
Ted S. SorensonfTiber Dam N/A N/A N/A
Fossil Gulch Wind N/A N/A N/A
G2 Energy Hidden Hollow N/A N/A N/A
Horseshoe Bend Wind/United Mater N/A N/A N/A
Horseshoe Bend Wind/United Mater N/A N/A N/A
Riverside Hydro Mora Drop N/A N/A N/A
8 J.M. Miller/Sahko Hydro N/A N/A N/A
9 D.R. Johnson Lumber/Co Gen Co N/A N/A N/A
American Electric Power Service WSPP N/A N/A N/A
Arizona Public Service Co.WSPP N/A N/A N/A
Arizona Public Service Co.WSPP N/A N/A N/A
Avista Corp. - WWP Div.N/A N/A N/A
Avista Corp. - WWP Div.N/A N/A N/A
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
I daho Power Company (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007
ccount 5~~~\ (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
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
1:l1e 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 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)
1:he total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.
Received Delivered
($)($)
of Settlement ($)
(g)
(h)(i)(I)(m)
19E 58,237
30,83E 384,6OE 384,605
021 211 391 211 391
193,193,715
15,745,06;745,O6~
19'56,471 56,476
721
68,121 942,581 942 586
80(975 62(975,62C
10,89f 202 11'202,11~
114 293,47~293,47~
81,420 81,420
081 081
964 02~99,757 268 856 815,12l 277,707 878 916 875 283,439,
FERC FORM NO.1 (ED. 12-90)Page 327.
This ~ort Is:(1) ~An Original
(2) D A Resubmission
PURCHASED POWER IAccou(1t 555)Iinciuding power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
Name of Respondent
Idaho Power Company
Date of Report
(Mo, Da, Yr)
04/18/2007
Year/Period of Report
End of 2006/04
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 RO 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.
(a)
1 Avista Corp. - WWP Div.
2 Avista Corp. - WWP Div.
3 Avista Corp. - WWP Div.
4 Avista Energy, Inc.
5 Avista Energy, Inc.
6 Avista Energy, Inc.
7 Barclays Bank PLC
8 Benton County PUD
9 Benton County PUD
10 Black Hills Power Inc.
11 Black Hills Power Inc.
12 Bonneville Power Administration
13 Bonneville Power Administration
14 Bonneville Power Administration
Statistical FERC Rate Average Actual Demand (MW)
Classifi-Schedule or Monthly Billing verage verage
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(b)(c)(d)(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
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
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)0 A Resubmission 04/18/2007
ccou
Rt
~g~~)
(Continued)M '~(includ;ng pOwer exc ange )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RO purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (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.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total G+k+l)No.Received Delivered
($)
\~l
of Settlement ($)
(g)
(h)(i)(m)
15,83~634,44C 634 44C
321 251 69/251,69/
497 888 497,88!
15,56~654,42 654,427
250 250
55,981 223,72;223,723
00(55(61,550
70,65,971 971
591 79i 795
69E 428 38'428,384
29'285,43'285 434
114 54:885,541 885,549
757 655 1,757 65E
192,02~632,701 632,707
964 02'757 268 856 815,124 277 707,878 916,875 283,439,
FERC FORM NO.1 (ED. 12-90)Page 327.
Name 01 Respondent This 'OOort Is:Date 01 Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End 01 2006/04
(2) Fi A Resubmission 04/18/2007
PU~CHA~ED POWER hAccou~t 555)
(nclu Ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and 'firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Class ili- Schedule or Monthly Billing Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman ~ Monthly CP Demanc
(a)(b)(c)(d)(e)(I)
1 Bonneville Power Administration 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
4 Calpine Energy Services, loP.WSPP N/A N/A N/A
5 Calpine Energy Services, loP.~wspp N/A N/A N/A
6 Cargill Power Markets LLC WSPP N/A N/A N/A
7 Cargill Power Markets LLC SF WSPP N/A N/A N/A
8 Chelan Co PUD
' , ~
WSPP N/A N/A N/A
9 Chelan Co PUD SF WSPP N/A N/A N/A
Chelan Co PUD
cSPP
N/A N/A N/A
Citigroup Energy Inc.~ WSPP N/A N/A N/ASF WSPP N/A N/A N/ACitigroup Energy Inc.
:' :WSPPClatskanie PUD N/A N/A N/A
Clatskanie PUD SF WSPP N/A N/A N/A
Total
FERC FORM NO.1 (ED. 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 2006/04
(2)D A Resubmission 04/18/2007
ccouRt 55~~) (l,;ontlnueo), v ,...., '~
\inCiuding power exc ange )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (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 (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered
($)($)
of Settlement ($)
(g)
(h)(i)(I)(m)
46~20,48.20,482
472,15E 811 ,72E 31,811 725
40C 18,00C 18,000
501 5,401 401
60C 327,00C 327,000
21C 164 24~164 249
70E 507 78C 507 78C
15C 10,20C 10,200
20,20C 505,75C 505,750
64E 648
45C 23,85C 23,850
00C 117 80C 117,800
36C 360
2,40C 115 70C 115,700
964 024 757 268 856 815,124 277 707 878 916 875 283,439
FERC FORM NO.1 (ED. 12-90)Page 327.
This ~ort Is:(1) ~An Original(2) DA Resubmission
PURCHASED POWER IAccoul)t 555)(Including power excl'1anges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
Name of Respondent
Idaho Power Company
Date of Report
(Mo, Da, Yr)
04/18/2007
Year/Period of Report
End of 2006/04
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.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 verage verage
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Conoco Phillips Company WSPP N/A N/A N/A
2 Conoco Phillips Company WSPP N/A N/A N/A
3 Constellation Energy Commodities WSPP N/A N/A N/A
4 Coral Power, LLC WSPP N/A N/A N/A
5 DB Energy Trading, LLC WSPP N/A N/A N/A
6 Douglas County PUD WSPP N/A N/A N/A
7 Douglas County PUD WSPP N/A N/A N/A
8 Douglas County PUD WSPP N/A N/A N/A
9 EI Paso Electric Company WSPP N/A N/A N/A
10 EI Paso Electric Company WSPP N/A N/A N/A
11 Eugene Water & Electric Board WSPP N/A N/A N/A
12 Eugene Water & Electric Board WSPP N/A N/A N/A
13 Franklin County P.WSPP N/A N/A N/A
14 Franklin County P.WSPP N/A N/A N/A
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)D A Resubmission 04/18/2007
CCOUR\~g~~) (continued)Jlncluding power exc ange )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups. for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RO purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (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 (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.
Received Delivered
($)($)
of Settlement ($)
(g)
(h)(i)(I)(m)
207,62E 207 625
00C 475,85C 475,850
44C 313 313 307
305 60C 726,30C 21,726,300
80C 37,55(550
48C 60C 600
80C 156,00C 156 000
16E 49E 6,495
601 252 12(252 120
56C 39,535 39,535
13,20C 452,750 452,750
19,99~19,992
376 68,91 C 68,910
964 024 757 268,856 815 124 277 707 878 916,875 283,439
FERC FORM NO.1 (ED. 12-90)Page 327.
This ~ort Is:(1) ~An Original
(2) A Resubmission
PURCHASED POWER IAccou(1t 555)(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
Name of Respondent
Idaho Power Company
Date of Report
(Mo, Da, Yr)
04/18/2007
Year/Period of Report
End of 2006/Q4
RO - 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 RO service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
1 Grant County P.
2 Grant County P.
3 Grant County P.
4 Grays Harbor PUD
5 Grays Harbor PUD
6 J. Aron & Company
7 Los Angeles Department of Water
8 Morgan Stanley Capital Group Inc
9 Morgan Stanley Capital Group Inc
10 Nevada Power Company
11 Northem California Power Agency
12 NorthWestern Energy
13 NorthWestern Energy
14 NorthWestern Energy
Line
No.
Total
FERC FORM NO.1 (ED. 12-90)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Actual Demand (MW)verage verage
Monthly NCP Deman Monthly CP Deman(e) (f)
Average
Monthly Billing
Demand (MW)
(d)
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
Page 326.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)0 A Resubmission 04/18/2007
, M "'(1 :'WE ccou~t 55~~) (Continued)Including po er exc ange
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c). identify the FERC Rate Schedule Number or Tariff. or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service. as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (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 (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l)No.
Received Delivered
\'J
of Settlement ($)
(g)
(h)(i)(m)
761 80'91 ,80~
OO(274 35(274 350
421 421
80!13,97!13,975
93,102,241 102 245
20(449,30(449,300
00(000
176,64::176 643
296,001,92'001 923
36'16,46C 16,460
00C 000
19E 85,20!205
27~151 159
51'51~
964 024 99,757 268,856 815,12L 277,707 878 916 875 283,439
FERC FORM NO.1 (ED. 12-90)Page 327.
This ~ort Is:(1) ~An Original
(2) D A Resubmission
PURCHASED POWER IAccout:1t 555)
(Including power excl'1anges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
Name of Respondent
Idaho Power Company
Date of Report
(Mo, Da, Yr)
04/18/2007
Year/Period of Report
End of 2006/04
RO - 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 RO 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)verage verage
Monthly NCP Deman Monthly CP Deman(e) (f)
1 NorthWestern Energy
2 Okanogan County P.
Pacific Northwest Generating Coo
Pacific Northwest Generating Coo
5 PacifiCorp Inc.
6 PacifiCorp Inc.
7 PacifiCorp Inc.
8 PacifiCorp Inc.
9 PacifiCorp Inc.
10 PacifiCorp Inc.
11 Pinnacle West Capital Corporatio
12 Pinnacle West Capital Corporatio
13 Portland General Electric Com pan
14 Portland General Electric Com pan 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
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. 12-90)Page 326.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)D A Resubmission 04/18/2007
ccounf55~~~ (Contlnueo)(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
identified in column (b), is provided.
5. For requirements RO purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (50-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
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 Iine 13.9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total G+k+l)No.
Received Delivered
($)($)
of Settlement ($)
(g)
(h)(i)(I)(m)
95,61.034,73'034 733
23C 30(300
23!231 23C
001 65,80!80C
50C 500
86!643 521 643,521
133,471 591 58'591,585
27!12,27.
13,035 13,035
557 582 557,582
19,92C 920
3,40C 142,80C 142,800
691 23,41!23,4H
851 011 96,011 962
964 024 99,757 268 856 815 12~277 707 878 916 875 283,439
FERC FORM NO.1 (ED. 12-90)Page 327.
This ~rt Is:(1) ~An Original(2) A Resubmission
PURCHA$ED POWER (Accou(1t 555)(Including power excl1anges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
Name of Respondent
Idaho Power Company
Date of Report
(Mo, Da, Yr)
04/18/2007
Year/Period of Report
End of 2006/04
RO - 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.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
1 Portland General Electric Com pan
2 Portland General Electric Com pan
3 Portland General Electric Com pan
4 Powerex Corp.
5 Powerex Corp.
6 PPL Montana, LLC
7 PPL Montana, LLC
8 PPL Montana, LLC
9 PPM Energy, Inc.
10 PPM Energy, Inc.
11 Public Service Co. of Colorado
12 Public Service Co. of Colorado
13 Public Service Company of New Me
14 Public Service Company of New
Line
No.
Total
FERC FORM NO.1 (ED. 12-90)
Statistical FERC Rate Average
Classifi-Schedule or Monthly Billing
cation Tariff Number Demand (MW)
(b)(c)(d)
WSPP N/A N/A
N/A N/A
WSPP N/A N/A
WSPP N/A N/A
WSPP N/A N/A
WSPP N/A N/A
WSPP N/A N/A
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
N/A
N/A
N/A
N/A
Page 326.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)0 A Resubmission 04/18/2007
. CCOUR\~3~~) ((jontlnueo)(Including power exc ange )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (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 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 amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered
($)($)
of Settlement ($)
(g)
(h)(i)(I)(m)
230,982,15E 982,155
99C 990
500 50C
32,55~382 382 647
108,437,63.437 632
12,614,67-4 614 674
08/087 11-4 087,114
103,58-4 609,48E 609,488
11,42E 511 991 511 991
110,563 14C 563,143
211 892 84~892,842
30,40C 909,70C 909,700
76C 267 93E 267,935
20C 485,15C 485,150
964 024 99,757 268 856 815 124 277 707 878 916,875 283,439 87 (
FERC FORM NO.1 (ED. 12-90)Page 327.
This ~ort Is:
(1) l2U An Original(2) DA Resubmission
PURCHASED POWER IAccou(1t 555)(Including power excl'langesJ
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
Name of Respondent
Idaho Power Company
Date of Report
(Mo, Da, Yr)
04/18/2007
Year/Period of Report
End of 2006/04
RO - 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 RO 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 verage veragecationTariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Public Service Company of New Me WSPP N/A N/A N/A
2 Puget Sound Energy, Inc.WSPP N/A N/A N/A
3 Puget Sound Energy, Inc.WSPP N/A N/A N/A
4 Puget Sound Energy, Inc.N/A N/A N/A
5 Rainbow Energy Marketing Corpora WSPP N/A N/A N/A
6 Rainbow Energy Marketing Corpora WSPP N/A N/A N/A
7 Salt River Project WSPP N/A N/A N/A
8 Salt River Project WSPP N/A N/A N/A
9 Seattle City Light WSPP N/A N/A N/A
10 Seattle City Light WSPP N/A N/A N/A
11 Seattle City Light WSPP N/A N/A N/A
12 Sempra Energy Solutions WSPP N/A N/A N/A
13 Sempra Energy Trading Corporatio ,. WSPP N/A N/A N/A
14 Sempra Energy Trading Corporatio WSPP N/A N/A N/A
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This 'OOort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)0 A Resubmission 04/18/2007
~ M '~~ncrl ccou~t 55~~) (GOntinued)Including power exc ange )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RO purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (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 (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l)No.Received Delivered
($)($)
of Settlement ($)
(g)
(h)(i)
(j)
(I)(m)
480 480
20,82E 036,036,027
74~039 039 133
2,76/2,76/
181 00€181 006
599 770,42~770,423
83~120,42~120,422
20C 60C 600
32,76~894 76E 894 768
351:355
941 635,311 635 311
2,40C 10C 100
52~00C 000
592,41E 786,401 41,786,401
964 024 99,757 268,856 815,12~277 707 878 916,875 283,439,
FERC FORM NO.1 (ED. 12-90)Page 327.
This ~ort Is:(1) ~An Original(2) DA Resubmission
PURCHASED POWER (Accou(1t 555)(Including power excl'langes)
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:
Date of Report
(Mo, Da, Yr)
04/18/2007
Year/Period of Report
End of 2006/04
Name of Respondent
Idaho Power Company
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 verage verage
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Deman
(a)(b)(c)(d)(e)(f)
1 Sierra Pacific Power Company WSPP N/A N/A N/A
2 Sierra Pacific Power Company WSPP N/A N/A N/A
3 Sierra Pacific Power Company WSPP N/A N/A N/A
4 Sierra Pacific Power Company N/A N/A N/A
5 Sierra Pacific Power Company . WSPP N/A N/A N/A
6 Silicon Valley Power WSPP N/A N/A N/A
7 Snohomish County PUD WSPP N/A N/A N/A
8 Snohomish County PUD WSPP N/A N/A N/A
9 Southern California Edison WSPP N/A N/A N/A
10 Southwestern Public Service Comp WSPP N/A N/A N/A
11 SUEZ Energy Marketing NA, Inc.WSPP N/A N/A N/A
12 SUEZ Energy Marketing NA, Inc.WSPP N/A N/A N/A
13 Tacoma Power WSPP N/A N/A N/A
14 Tacoma Power WSPP N/A N/A N/A
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)D A Resubmission 04/18/2007
ccount 55~~) (l,;ontlnueo)(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
identified in column (b), is provided.
5. For requirements RO purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (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 (D, energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.
Received Delivered
($)($)
of Settlement ($)
(g)
(h)(i)(I)(m)
06f 206 71~206,713
806 806
28,05(298,08f 298,088
52~525
257 257
40C 18,50(18,500
791,46€791 466
86~231,08C 231,080
40(50(25,500
20(00(00C
02E 105,56(105,560
70C 550,46C 550,460
531 82E 531 825
37~37~
964,024 757 268 856 815 124 277 707 878 916,875 283,439 87
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)D A Resubmission 04/18/2007
~CHA~ED POWER hAccou~t 555)
(nclu Ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Tacoma Power WSPP N/A N/A N/A
TransAlta Energy Marketing (U.~wspp N/A N/A N/A
3 TransAlta Energy Marketing (U.SF WSPP N/A N/A N/A
4 Tri-State Generation and Transmi WSPP N/A N/A N/A
5 Tucson Electric Power Company WSPP N/A N/A N/A
6 Tucson Electric Power Company SF WSPP N/A N/A N/A
7 UBS AG, London Branch .WSPp N/A N/A N/A
8 Utah Associated Municipal Power '" WSPP N/A N/A N/A
9 Utah Associated Municipal Power SF WSPP N/A N/A N/A
Western Area Power Administratio WSPP N/A N/A N/A
Net Metering Customers N/A N/A N/A
BAD DEBT WRITE-OFF N/A N/A N/A
Power Exchanges
Avista Energy, Inc.wSPP
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)D A Resubmission 04/18/2007Y '~ Y' ccount 456)(Contlnued)(Including transactions reffered to as 'wheeling
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path
, "
point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billing TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand Megawatt Hours Megawatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered(e)(f)
(g)
(h)(i)
HTSP BOBR 711 711
JBSN HTSP
HTSP M345 100
JBSN LGBP 229 22E
LGBP JBSN 247
BOBR M345 225 22E
LGBP M345 325 32"
HTSP JBSN 632 1 :63~
LGBP BOBR 618
BOBR LGBP 445 44E
BOBR LGBP
HTSP BOBR 811 811
IPCO BOBR 400
LGBP BOBR 296 29E
LOLO M345 978 97~
HTSP BOBR 986 98E
ENPR M345 726 72E
ENPR BOBR 36,197 191
ENPR BOBR 155 , 15E
LGBP M345 116
LGBP M345 18,279 18,27E
ENPR BOBR 150 15C
LYPK M345 264 26~
IPCO LOLO 000 OOC
IPCO BOBR 200
M345 LGBP 495 49E
IPCO LGBP 664 66~
MLCK BOBR 440 44C
JBSN M345 700 19,70C
ENPR M345 232 11 ,23~
ENPR M345 200 20C
HTSP M345 265
HTSP BOBR 547 55,
BOBR M345 67,912 91"
483,108 483,10E
FERC FORM NO.1 (ED. 12-90)Page 329.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2006/04(2) DA Resubmission 04/18/2007
UI- cLtol,; I HI~II Y I-UH v I'~ ,ciJ:"~ccounf456-:-f)(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)
Sierra Pacific Power Bonneville Power Administratio Sierra Pacific Power
Sierra Pacific Power Bonneville Power Administratio Sierra Pacific Power STF
Sierra Pacific Power NorthWestern/PacifiCorp East Sierra Pacific Power
Sierra Pacific Power Avista Sierra Pacific Power
Sierra Pacific Power Avista Sierra Pacific Power STF
TransAlta Energy Marketing PacifiCorp East NorthWestern/PacifiCorp East
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.
Name of Respondent This 'OOort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007
t:Lt:v I NI!-,II Y (fJ ccount 45t:i)(l,;ontlnueo)(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 (j) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billing TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand Megawatt Hours MegaWatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered(e)(f)
(g)
(h)(i)
LGBP M345 214 907 214
LGBP M345 2,400 2,40(
JEFF M345 297 156 297, 151
LOLa M345 406,795 406,79E
LOLa M345 200 2OC
BOBR HTSP
483,1 OS 483,10E
FERC FORM NO.1 (ED. 12-90)Page 329.
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 2006/04
(2)D A Resubmission 04/18/2007
u.':' ~I,-~L , CU Y' , ccount 40ti) ILontlnueo)(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.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)L..Ine
($)($)($)
(k+l+m)No.
(k)(I)(m)(n)
005 921 300 105 705 816
029,983 259 954 724
530,638 503 143 033,781
187 604 639,147 548,457
12,500 12,500
836 836
860
553 816 369
173 173
224 731 224,731
13,395 13,395
262,809 262,809
'. '
774,632
105 105
832 58,832
310 22,310
116 116
332 332
337 26,337
155 155
615 615
992 992
074 074
464 464
1 ,430 430
142 142
178 178
262 262
315 315
787 787
050 050
937 937
827,372 099,237 769,772 12,156,837
FERC FORM NO.1 (ED. 12-90)Page 330
Name of Respondent This ooort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)0 A Resubmission 04/18/2007I o.f FI Y ,(ACCount 456) (ContinUed)(Including transactions reffered to as 'wlieeling
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)LIne
($)($)($)
(k+l+m)No.
(k)(I)(m)(n)
278 278
881 881
771 771
13,505 13,505
012 012
19,437 19,437
216 216
919 33,919
43,461 43,461
270 270
342 198 342,198
33,250 250
392,166 392 166
419,466 419,466
165 165
179 179
220 220
249 249
249 249
543 543
567 567
873 873
091 091
990 990
203 203
534 534
079 079
113 113
216 216
512 512
12,508 508
367 367
887 21,887
65,884 884
827,372 099 237 769,772 156 837
FERC FORM NO.1 (ED. 12-90)Page 330.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)0 A Resubmission 04/18/2007
, L..L.L..V I Hlvll Y FgR ~ I. MI:.H~ .(~ ccount 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)
154,081 154 081
299 290 299,290
596,420 596,420
408 408
450 450
525 525
870 870
23,904 23,904
27,361 361
193,954 193 954
265 395 265 395
531,402 531,402
496 496
396 396
136 136
172 172
186 186
186 186
232 232
419 419
442 442
991 991
125 125
339 339
018 018
3,423 3,423
865 865
581 581
018 018
827,372 099,237 769,772 12,156,837
FERC FORM NO.1 (ED. 12-90)Page 330.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2006/Q4
(2)D A Resubmission 04/18/2007o.f FI II Y FgR '-':"
,....., ".. .
ccount 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)
552 552
641 641
701 701
334 334
599 599
046 12,046
366 366
13,858 858
900 14,900
221 221
486 17,486
23,434 23,434
155 25,155
512 512
381 33,381
48,542 48,542
49,974 49,974
167 71,167
095 095
574 574
109 619 109,619
830 830
155,518 155 518
174 556 174 556
750 750
373,404 373,404
335 335
349 349
576 576
876 876
013 013
5,452 5,452
7,468 7,468
827,372 099,237 -1,769,772 12,156 837
FERC FORM NO.1 (ED. 12-90)Page 330.
Name of Respondent This 'OOort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2006/Q4
(2)D A Resubmission 04/18/2007
':-~~ MI""I T t-YH '-! I. m:M!=' l"!ccount 450) (vontlnUeC)(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.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)
(k+l+m)No.
(k)(I)(m)(n)
12,938 938
129 129
257 257
589 589
635 635
151 151
3,408 3,408
198 198
307 307
887 80,887
164 164
774 774
307 307
7,474 474
175 175
893 893
928 84,928
166,916 166 916
500 500
145,212 145 212
197,330 197,330
391 391
688 688
605 605
126 126
6,499 6,499
939 939
960 960
51,314 314
950 950
270 45,270
066 066
144,686 144 686
176 894 176,894
827 372 099,237 769,772 156,837
FERC FORM NO.1 (ED. 12-90)Page 330.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)D A Resubmission 04/18/2007
. OF ELECTHILiII Y FgR U I, MtH~ ,(Account 456) (Continued)(Including transactions reffered to as 'wlieeling
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and 0) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)
(k+l+m)No.
(k)(I)(m)(n)
548,421 548 421
609 609
774 016 774 016
987 065 987 065
83,473 83,473
578 578
827,372 099 237 769,772 156,837
FERC FORM NO.1 (ED. 12-90)Page 330.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
FOOTNOTE DATA
ISchedule 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 Company
transmission system pear and varies by month.
ISchedule Page: 328 Line No.: 2 Column:
The network service agreement between Idaho Power and the Bonneville Power Administration
for the USBR expires December 31,2014. The billing demand for network service is the
customer I s demand at the time of Idaho Power Company transmission system peak and varies
by month.
ISchedule Page: 328 Line No.: 3 Column:
The Network service agreement between Idaho Power and the Bonneville Power Administration
for Raft River expires September 30, 2011. The billing demand for network service is the
customer s at the time of Idaho Power Company transmission system peak and varies by
month.
ISchedule Page: 328 Line No.Column:
The network service agreement between Idaho Power and the Bonneville Power Administration
for th Priority Firm customers expires December 31, 2011. The billing demand for network
service is the customer s demand at the time of Idaho Power Company transmission system
pead and varies by month.
ISchedule Page: 328 Line No.: 5 Column:
The agreement between Idaho Power and the Bonneville Power Administration expires
September 2016.
ISchedule Page: 328 Line No.: 6 Column:
The contract between Idaho Power and the Milner Irrigation District will expire December
31, 2007.
ISchedule Page: 328 Line No.: 7 Column:
The agreement between Idaho Power Company and the City of Seattle expires December 31,
2007.
ISchedule Page: 328 Line No.: 7 Column: Monthly customer charge.
ISchedule Page: 328 Line No.: 13 Column:
Adjustment for potential billing error for years 2000 thru 2006.
IFERC FORM NO.(ED. 12-87) Page 450.
Year/Period of Report
End of 2006/04
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) DA Resubmission 04/18/2007
TRANS ISSION OF ELECTRICITY BY OTHERS (Account 565)
(Including transactions referred to as "wheeling
1. Report all transmission, Le. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public
authorities, qualifying facilities, and others for the quarter.
2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions 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 (9) 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.
Name of Respondent
Idaho Power Company
LineNo. Name of Company or Public
Authority (Footnote Affiliations)
(a)
1 Avista Corp. WWp Div
2 Avista Corp - WWP Div
10 NorthWestern Energy
11 PacifiCorp Inc.
12 PacifiCorp Inc.
13 PPl Montana LLC
14 Seattle City Light
15 Sierra Pacific Power Co
16 Snohomish County PUD
TOTAL
FERC FORM NO. 1/3-0 (REV. 02-04)
Statistical
Classification
(b)
SFP
LFP
LFP
264 264
21 ,64B 21 ,648
754 754
SFP 844 90,844
LFP 106 B47 106,847
902 902
SFP 135 834 135 834
634 36,634
788 7B8
346 440 346,440
EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERnergy er Total Cost ofCharges Charges Trans ission
($) ($)
(f)
(g)
686,324 686,324
630,000
233 416
54,036
35,B91
336
56,973
744 600
218 889
15,380
549 989
089 192
800
128,290
307
916,728
630,000
992 256
43,596
28,925
60,336
56,973
744,600
204 000 14,889
549,989
089,192
676 703,644 239 835695201676765
Page 332
638,680
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2006/04(2) nA Resubmission 04/18/2007
TRANSMISSION OF ELECTRICITY BY OTHE S (Account 565)
(Including transactions referred to as "wheeling
1. Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public
authorities, qualifying facilities, and others for the quarter.
2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions 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 EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHER
No.Name of Company or Public Statistical Magawatt-Magawan-h'.emana t;:nergy utner Total Cost of
tiours tiours Charpes Charpes Charpes Trans~sslonAuthority (Footnote Affiliations)Classification Received Delivered
(a)(b)(c)(d)(e)(f)
(g)
1 Tacoma Power 632 632 245 129 245,129
TOTAL 676 676 765 703,644 695,201 239 835 638,680
FERC FORM NO. 1/3-Q (REV. 02-04)Page 332.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubm ission 04/18/2007 2006/04
FOOTNOTE DATA
ISchedule Page: 332 Line No.: 3Contract Expiration date is
ISchedule Page: 332 Line No.
Ancillary Services.
ISchedule Page: 332 Line No.: 4 Column:
Contact Expiration Date is 7/16/2011.
ISchedu/e Page: 332 Line No.: 4 Column: g
Ancillary Services.
'Schedule Page: 332 Line No.Column: g
Ancillary Services.
ISchedule Page: 332 Line No.Column:
Contract can be terminated at anytime,
ISchedule Page: 332 Line No.: 10 Column: gTransmission Study Fee.
ISchedule Page: 332 Line No.13 Column: gResale Transmission.
'Schedule Page: 332 Line No.: 15 Column: g
Ancillary Services.
Column: 9/30/2016
Column: g
with 30 days prior notice.
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent
I This 7ijort Is:
Date of ReRort Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2006/04
(2) A Resubmission 04/18/2007
MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line DeSCri
ftion
AmountNo.(b)
Industry Association Dues 331 304
Nuclear Power Research Expenses
Other Experimental and General Research Expenses
Pub & Dist Info to Stkhldrs...expn servicing outstanding Securities 122,197
Oth Expn ::-=5,000 show purpose, recipient, amount. Group if .:; $5,000 lii~~fI~~-
Rotchford Barker 26,294
Christine King 710
Jack Lemley 595
Jon Miller 328
Gary Michael 29,375
Peter O'Neill 26,100
Richard Reiten 752
Thomas Wilford 875
Robert Tintsman 250
Joan Smith 17,905
Jan Packwood 125
Chambers of Commerce & Other Civic Organizations 690
Associated Taxpayers of Idaho 252
Association of Idaho Cities 750
Corporate Executive Board 72,150
Eastern Oregon Visitor Association 500
Idaho Association of Commerce and Industry 9,400
Idaho Mining Association 025
Idaho Water Users 200
Misc Memberships (6)135
National HydroPower Assoc 25,214
Oregonians For Food & Shelter 320
Pacific Nw Utilities 919
The Conference Board 625
Utility Wind Interest Group 000
West Associates 580
Western Electricity Coordiniating Council 376,570
Western Energy Institute 000
Wyoming Taxpayers Assoc 783
Miscellaneous General Management:
New York Stock Exchange 205
PR Newswire 380
TOTAL 901 158
FERC FORM NO.1 (ED. 12-94)Page 335
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 2006/04
(2)DA Resubmission 04/18/2007
ccou~t 55~~) (l;ontlnueo)l1ncluding' power exc ange
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (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.
G. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered
($)($)
of Settlement ($)
(g)
(h)(i)(I)(m)
11 C 663 98C 663,980
06C 101 ,30C 101 300
223,222,14,222,257
40C 23,94E 946
36E 516
001 214 80C 214 80C
13,96C 665,02C 665,020
13E 331:335
32C 80C 800
800 800
964 024 757 268 856 815 124 277 707 878 916 875 283,439,
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 2006/04
(2)0 A Resubmission 04/18/2007
PU~CHA~ED POWER ~Accou~t 555)
(nclu Ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demanc
(a)(b)(c)(d)(e)(f)
1 Sierra Pacific Power Company WSPP
2 Black Hills Power Inc.
Bonneville Power Administration
NorthWestern Energy, LLC.
PacifiCorp Inc.
Puget Sound Energy, Inc.
Sierra Pacific Power Company
Total
FERC FORM NO.1 (ED. 12-90)Page 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 2006/Q4
(2)D A Resubmission 04/18/2007
ccount 55~~) (L;ontlnueo)(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
identified in column (b), is provided.
5. For requirements RO purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (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 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total G+k+l)No.Received Delivered
($)($)
of Settlement ($)
(g)
(h)(i)(I)(m)
034 034
52,829 966
242
024 234 608
12,206
964 024 99,757 268,856 815,124 277 707 878 916 875 283,439
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
FOOTNOTE DATA
ISchedule Page: 326 Line No.Column:
The Tamarack Energy Partnership demand readings are taken from an electronic demand
recorder provided by Idaho Power Company. The actual demand is not used in determining the
cost of energy.
'Schedule Page: 326.Line No.Column: b
Non-Firm Purchases.
'Schedule Page: 326.Line No.: 8 Column: b
Non-Firm Purchases.
'Schedule Page: 326.Line No.: 5 Column:
Ida-West a subsidiary of IdaCorp the parent of Idaho Power Company has partial ownershipof these proj ects .
ISchedule Page: 326.Line No.: 12 Column: b
Non-Firm Purchases.
ISchedule Page: 326.4 Line No.Column:
Ida-West a Subsidiary of IdaCorp the Parent of Idaho Power Company has partial ownershipof thest proj ects .
'Schedule Page: 326.4 Line No.Column:
Ida-West a susidiary of IdaCorp the Parent of Idaho Power Company, has partial ownershipof these proj ects .
ISchedule Page: 326.Line No.Column:
Ida-West a subsidiary of IdaCorp the Parent of Idaho Power Company has partial ownershipof these proj ects .
ISchedule Page: 326.4 Line No.: 13 Column: bNon-Firm Purchases.
'Schedule Page: 326.4 Line No.: 14 Column: b
Non-Firm Purchases.
ISchedule Page: 326.Line No.: 6 Column: b
Energy difference between mountain and pacific time schedules.
ISchedule Page: 326.Line No.11 Column: bNon-Firm Purchases.
ISchedule Page: 326.Line No.13 Column: b
Spinning or Operating Reserves.
ISchedule Page: 326.Line No.Column: bNon-Firm Purchases.
'Schedule Page: 326.Line No.: 3 Column: b
Financial Transmission Losses.
ISchedule Page: 326.Line No.: 4 Column: bNon-Firm Purchases.
ISchedule Page: 326.Line No.Column: b
Spinning or Operating Reserves.
ISchedule Page: 326.Line No.: 8 Column: b
Non-Firm Purhcases.
ISchedule Page: 326.Line No.10 Column: bNon-Firm Purchases.
ISchedule Page: 326.Line No.12 Column: bNon-Firm Purchases.
ISchedule Page: 326.Line No.: 13 Column: b
Spinning or Operating Reserves.
ISchedule Page: 326.Line No.Column: b
Non-Firm Purchases.
ISchedule Page: 326.Line No.Column: bNon-Firm Purchases.
ISchedule Page: 326.Line No.Column: bNon-Firm Purchases.
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 04/18/2007 2006/04
FOOTNOTE DATA
'Schedule Page: 326.Line No.11 Column: bNon-Firm Purchases.
!Schedule Page: 326.Line No.13 Column: b
Non-Firm Purchases.
ISchedule Page: 326.Line No.Column: bNon-Firm Purchases.
ISchedule Page: 326.Line No.Column: bNon-Firm Purchases.
ISchedule Page: 326.Line No.Column: b
Non-Firm Purchases.
(Schedule Page: 326.Line No.11 Column: bNon-Firm purhcases.
ISchedule Page: 326.Line No.13 Column: bNon-Firm purhcases.
ISchedu/e Page: 326.Line No.Column: b
Non-Firm Purchases.
ISchedule Page: 326.Line No.Column: b
Non-Firm Purchases.
ISchedu/e Page: 326.Line No.Column: b
Non-Firm Purchases.
ISchedu/e Page: 326.Line No.Column: b
Non-Firm Purchases.
ISchedule Page: 326.Line No.: 10 Column: b. Non-Firm Purchases.
ISchedule Page: 326.Line No.11 Column: b
Non-Firm Purchases.
ISchedule Page: 326.Line No.12 Column: bNon-Firm Purchases.
ISchedule Page: 326.10 Line No.Column: b
Non-Firm Purchases.
ISchedule Page: 326.10 Line No.Column: b
Non-Firm Purchases.
ISchedule Page: 326.10 Line No.Column: b
2005 Price Adjustment.
Schedule Pa e: 326.10 Line No.Column: b
Non-Firm Purchases.
Schedule Page: 326.10 Line No.Column: b
Spinning or Operating Reserves.
ISchedu/e Page: 326.10 Line No.: 10 Column: b
Financial Transmission Losses.
ISchedule Page: 326.10 Line No.11 Column: b
Non-Firm Purchases.
ISchedule Page: 326.10 Line No.13 Column: b
Energy received from PGE in lieu of Boardman generation in accordance
energy agreement between PGE and Idaho Power, dated 11/17/1989.
ISchedu/e Page: 326.10 Line No.14 Column: b
Non-Firm Purchases.
ISchedule Page: 326.11 Line No.Column: b
Spinning or Operating Reserves.
ISchedu/e Page: 326.11 Line No.Column: b
Non-Firm Purchases.
ISchedu/e Page: 326.11 Line No.Column: b
Non-Firm Purchases.
ISchedule Page: 326.11 Line No.Column: b
Non-Firm Purchases.
IFERC FORM NO.1 (ED. 12-87)
wi th the Assured"
Page 450.
This Page Intentionally Left Blank
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmlssion 04/18/2007 2006/04
FOOTNOTE DATA
ISchedule Page: 326.11 Line No.11 Column: bNon-Firm Purchases.
ISchedule Page: 326.11 Line No.13 Column: bNon-Firm Purchases.
ISchedule Page: 326.12 Line No.Column: b
Spinning or Operating Reserves.
ISchedule Page: 326.12 Line No.Column: bNon-Firm Purchases.
ISchedule Page: 326.12 Line No.Column: bNon-Firm Purchases.
ISchedule Page: 326.12 Line No.Column: b
Non-Firm Purchases.
ISchedule Page: 326.12 Line No.Column: bNon-Firm Purchases.
ISchedule Page: 326.12 Line No.13 Column: b
Non-Firm Purchases.
ISchedule Page: 326.13 Line No.Column: bNon-Firm Purchases.
ISchedule Page: 326.13 Line No.Column: b
Spinning or Operating Reserves.
ISchedule Page: 326.13 Line No.Column: b
Financial Transmission Losses.
ISchedule Page: 326.13 Line No.Column: bNon-Firm Purchases.
ISchedule Page: 326.13 Line No.10 Column: bNon-Firm Purchases.
ISchedule Page: 326.13 Line No.11 Column: bNon-Firm Purchases.
ISchedule Page: 326.13 Line No.13 Column: bNon-Firm Purchases.
ISchedule Page: 326.14 Line No.Column: bNon-Firm Purchases.
(Schedule Page: 326.14 Line No.Column: bNon-Firm Purchases.
ISchedule Page: 326.14 Line No.Column: bNon-Firm Purchases.
ISchedule Page: 326.14 Line No.Column: b
Non - Firm Purchases.
ISchedule Page: 326.15 Line No.Column: b
Scheduled losses not removed with loss transactions.
ISchedule Page: 326.15 Line No.Column: b
Scheduled losses not removed with loss transactions.
ISchedule Page: 326.15 Line No.Column: b
Scheduled losses not removed wi th loss transactions.
ISchedule Page: 326.15 Line No.Column: b
Scheduled losses not removed with loss transactions.
ISchedule Page: 326.15 Line No.Column: b
Scheduled losses not removed with loss transactions.
ISchedule Page: 326.15 Line No.Column: b
Scheduled losses not removed with loss transactions.
IFERC 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) X An Original (Mo, Da, Yr)End of 2006/04
(2)D A Resubmission 04/18/2007
~"~.'~ ,
ccount45o.(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)
Bonneville Power Administratio Oregon Trails Electric Co-op FNO
Bonneville Power Administratio United States Bureau of Reclama FNO
Bonneville Power Administratio Raft River Electric Co-op FNO
Bonneville Power Administratio Priority Firm Customers FNO
Bonneville Power Administratio Vigilante elF
United States Bureau of Reclam Milner Irrigation District elF
Seattle City Light Bonneville Power Administration elF
PacifiCorp PacifiCorp West PacifiCorp West FNO
United States Bureau of Indian Affai Bonneville Power Administratio United States Bureau of Indian
Pacificorp Power Marketing PacifiCorp West PacifiCorp West elF
Pacificorp Power Marketing PacifiCorp West PacifiCorp West elF
Pacificorp Power Marketing PacifiCorp East PacifiCorp West elF
Pacificorp Power Marketing PacifiCorp West PacifiCorp West
Arizona Public Service Idaho Power Company PacifiCorp East
Arizona Public Service PacifiCorp East Sierra Pacific Power
Arizona Public Service PacifiCorp East Sierra Pacific Power STF
Avista Corp.PacifiCorp East Avista
Avista Energy, Inc.Sierra Pacific Power Bonneville Power Administration
Avista Energy, Inc.NorthWestern/PacifiCorp East Sierra Pacific Power
Avista Energy, Inc.Bonneville Power Administratio Sierra Pacific Power
Avista Energy, Inc.PacifiCorp East Sierra Pacific Power
Black Hills Power PacifiCorp West NorthWestern/PacifiCorp East
Black Hills Power Bonneville Power Administratio PacifiCorp West
Black Hills Power PacifiCorp West Bonneville Power Administration
Black Hills Power PacifiCorp East Bonneville Power Administration
Boneville Power Admin.PacifiCorp West Sierra Pacific Power
Boneville Power Admin.B9!lneville Power Administratio Sierra Pacific Power
Cargill Power Markets NorthWestern/PacifiCorp East Sierra Pacific Power
Cargill Power Markets PacifiCorp East Bonneville Power Administration
Cargill Power Markets Idaho Power Company PacifiCorp East
Cargill Power Markets PacifiCorp West NorthWestem/PacifiCorp East
Cargill Power Markets Bonneville Power Administratio PacifiCorp West
Cargill Power Markets PacifiCorp West NorthWestern/PacifiCorp East
Cargill Power Markets PacifiCorp West PacifiCorp West
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007
':'"-~., :~
J I Y
;"" ":' '
ccount 456)(Conllnued)(Including transactions reffered to as 'wheeling
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path
, "
point to point" transmission service. In column (f), report the
designation for the substation , or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billing TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand MegaWatt Hours MegaWatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)
(g)
(h)(i)
326,466 326,46€
191 34"i 191 34"i
184 368 184 36€
763,201 763 201
Bannack Tap Vigilante Electric
Minidoka, Idaho Various in Idaho 923 92.
LYPK LGBP
111 111
LaGrande, Oregon Various in Idaho 810 81C
JBSN ENPR 170 17C
JBSN ENPR 362 36~
BOBR JBSN 70,938 70,93€
JBSN ENPR
IPCO BOBR 075 07E
BOBR M345 46,598 59E
BOBR M345 112 11~
BOBR LOLO
M345 LGBP
HTSP M345
LGBP M345 137
BOBR M345 852 1 0,85~
JBSN HTSP
LGBP JBSN 199 19~
JBSN LGBP 644 64;:
BOBR LGBP 994 99'
JBSN M345
LGBP M345 234 234
HTSP M345
BOBR LGBP
IPCO BOBR
JBSN HTSP
LGBP JBSN 150 15C
ENPR HTSP 200 20C
JBSN ENPR 750
483,108 483 10E
FERC FORM NO.1 (ED. 12-90)Page 329
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/200701- t:OH U I t:lt:N ~~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 Idaho Power Company Bonneville Power Administration
Cargill Power Markets PacifiCorp West PacifiCorp East
Cargill Power Markets Avista Sierra Pacific Power
Cargill Power Markets Bonneville Power Administratio Sierra Pacific Power STF
Cargill Power Markets PacifiCorp East NorthWestern/PacifiCorp East
Cargill Power Markets NorthWestern/PacifiCorp East PacifiCorp East
Cargill Power Markets PacifiCorp West Sierra Pacific Power
Cargill Power Markets PacifiCorp West PacifiCorp West
Cargill Power Markets Bonneville Power Administratio PacifiCorp East
Cargill Power Markets PacifiCorp West Bonneville Power Administration
Cargill Power Markets PacifiCorp West PacifiCorp East
Cargill Power Markets PacifiCorp West PacifiCorp East STF
Cargill Power Markets PacifiCorp East Sierra Pacific Power
Cargill Power Markets PacifiCorp West Sierra Pacific Power
Morgan Stanley Capital Group PacifiCorp East Avista
Morgan Stanley Capital Group PacifiCorp West PacifiCorp West
Morgan Stanley Capital Group Idaho Power Company Bonneville Power Administration
Morgan Stanley Capital Group Avista PacifiCorp East
Morgan Stanley Capital Group Seattle City Light Avista
Morgan Stanley Capital Group Idaho Power Company PacifiCorp East
Morgan Stanley Capital Group Avista Sierra Pacific Power
Morgan Stanley Capital Group PacifiCorp West PacifiCorp East
Morgan Stanley Capital Group NorthWestem/PacifiCorp East Sierra Pacific Power
Morgan Stanley Capital Group PacifiCorp West PacifiCorp East
Morgan Stanley Capital Group PacifiCorp East NorthWesternJPacifiCorp East
Morgan Stanley Capital Group PacifiCorp West Bonneville Power Administration
Morgan Stanley Capital Group PacifiCorp East PacifiCorp West
Morgan Stanley Capital Group Bonneville Power Administratio Sierra Pacific Power
Morgan Stanley Capital Group PacifiCorp West Sierra Pacific Power
Morgan Stanley Capital Group Bonneville Power Administratio PacifiCorp East
Morgan Stanley Capital Group Seattle City Light Bonneville Power Administration
Morgan Stanley Capital Group PacifiCorp East Bonneville Power Administration
Morgan Stanley Capital Group Seattle City Light PacifiCorp East
Morgan Stanley Capital Group NorthWesternlPacifiCorp East PacifiCorp East
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)0 A Resubmission 04/18/2007
IH!~II Y r-YH ~ I Mt:H (P ccount 456)(l.;Ontinued)
(Including transactions reffered to as 'wtieeling
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path
, "
point to point" transmission service. In column (t), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and Q) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billing TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand Megawatt Hours Megawatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)
(g)
(h)(i)
(j)
IPCO LGBP 815 81!:
JBSN BOBR 930 93C
LOLO M345 290 29C
LGBP M345 573 57.:
BOBR HTSP 241 241
HTSP BOBR 703 70.:
JBSN M345 947
ENPR JBSN 6,462 6,46.
LGBP BOBR 280 28C
JBSN LGBP 434 8,43~
ENPR BOBR 45,573 45,57~
ENPR BOBR 25,955 25,95"
BOBR M345 74,713 74,71~
ENPR M345 79,914 79,91'
BOBR LOLO
ENPR JBSN 71:
IPCO LGBP
LOLO BOBR 104 10~
LYPK LOLO 104 10~
IPCO BOBR 227
LOLO M345 237
ENPR BOBR 365 36E
HTSP M345 456 451
JBSN BOBR 832 83~
BOBR HTSP 921 921
JBSN LGBP 1,477 1,47
BOBR ENPR 705 7OE
LGBP M345 719
ENPR M345 762 76~
LGBP BOBR 140 14C
LYPK LGBP 228 22E
BOBR LGBP 513
LYPK BOBR 148 14E
HTSP BOBR 538 53E
483,108 483,1 Of
FERC FORM NO.1 (ED. 12-90)Page 329.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007
ur t:LI;:.L; I HIL:I I Y t:\,JH UI HI: Ht;l~ccount 456.(Including transactions referred to as 'wheeling
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line Payment By Energy Received From Energy Delivered To Statistical
No.(Company of Public Authority)(Company of Public Authority)(Company of Public Authority)Classifi-
(Footnote Affiliation)(Footnote Affiliation)(Footnote Affiliation)cation
(a)(b)(c)(d)
Morgan Stanley Capital Group PacifiCorp East Sierra Pacific Power
Morgan Stanley Capital Group Seattle City Light Sierra Pacific Power
Morgan Stanley Capital Group Seattle City Light Sierra Pacific Power
Pacificorp Power Marketing Sierra Pacific Power PacifiCorp East
Pacificorp Power Marketing NorthWestem/PacifiCorp East PacifiCorp East
Pacificorp Power Marketing Sierra Pacific Power PacifiCorp West
Pacificorp Power Marketing PacifiCorp East PacifiCorp West
Pacificorp Power Marketing PacifiCorp West PacifiCorp East
Pacificorp Power Marketing PacifiCorp West Sierra Pacific Power
Pacificorp Power Marketing PacifiCorp West Sierra Pacific Power
Pacificorp Power Marketing PacifiCorp East PacifiCorp West
Pacificorp Power Marketing PacifiCorp West PacifiCorp East
Portland General Electric NorthWestern/PacifiCorp East Bonneville Power Administration
Portland General Electric Sierra Pacific Power Bonneville Power Administration
Portland General Electric PacifiCorp East Bonneville Power Administration
Portland General Electric NorthWestern/PacifiCorp East Bonneville Power Administration
Powerex Corp.PacifiCorp West PacifiCorp West
Powerex Corp.Bonneville Power Administratio Idaho Power Company
Powerex Corp.PacifiCorp East PacifiCorp East
Powerex Corp.NorthWestern/PacifiCorp East PacifiCorp East
Powerex Corp.Sierra Pacific Power PacifiCorp East
Powerex Corp.PacifiCorp West Avista
Powerex Corp.NorthWestem/PacifiCorp East PacifiCorp West
Powerex Corp.Sierra Pacific Power NorthWestemlPacifiCorp East
Powerex Corp.Sierra Pacific Power PacifiCorp West
Powerex Corp.PacifiCorp East PacifiCorp West
Powerex Corp.Avista PacifiCorp West
Powerex Corp.PacifiCorp East NorthWestern/PacifiCorp East
Powerex Corp.PacifiCorp West NorthWestern/PacifiCorp East
Powerex Corp.PacifiCorp West PacifiCorp West
Powerex Corp.Avista PacifiCorp East STF
Powerex Corp.Sierra Pacific Power Idaho Power Company
Powerex Corp.NorthWestern/PacifiCorp East Sierra Pacific Power
Powerex Corp.PacifiCorp West PacifiCorp East
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.
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 2006/04
(2)D A Resubmission 04/18/2007I QF II Y FQR ~ I MtH::i,(J ccount 456)(Continuea)(Including transactions reffered to as 'wheeling
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path
, "
point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and 0) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billing TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand MegaWatt Hours MegaWatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)
(g)
(h)(i)
(j)
BOBR M345 64,402 64,40~
LYPK M345 893 40,89~
LYPK M345 333,491 333,491
M345 BOBR 136 13E
HTSP BOBR 150 15(
M345 ENPR 175 17!
BOBR M500 625 62=
JBSN BOBR 973 97~
JBSN M345 126 12E
ENPR M345 691 691
BOBR ENPR 519 88,
ENPR BOBR 177 242 177 ,24~
HTSP LGBP
M345 LGBP 150 15C
BOBR LGBP 422 42.
JEFF LGBP 948 94E
JBSN M500
LGBP IPCO
MLCK BOBR
JEFF BOBR
M345 BOBR
JBSN LOLO
JEFF ENPR
M345 HTSP
M345 ENPR
BOBR JBSN
LOLO JBSN 213 21'
BOBR JEFF 242
JBSN JEFF 288 28E
JBSN ENPR 649 64~
LOLO BOBR 736 73E
M345 IPCO 831 831
JEFF M345 985 98!
JBSN BOBR 079 071
483,108 483,10E
FERC FORM NO.1 (ED. 12-90)Page 329.
Name of Respondent This 'Wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)0 A Resubmission 04/18/2007.oF II Y ,:"UH U! t:lt H ~~ccount 45t:!.(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)
Powerex Corp.NorthWestern/PacifiCorp East Bonneville Power Administration
Powerex Corp.PacifiCorp West Sierra Pacific Power
Powerex Corp.NorthWestem/PacifiCorp East Sierra Pacific Power
Powerex Corp.PacifiCorp East Avista
Powerex Corp.PacifiCorp East PacifiCorp West
Powerex Corp.Avista Sierra Pacific Power
Powerex Corp.Avista Sierra Pacific Power STF
Powerex Corp.PacifiCorp West PacifiCorp West
Powerex Corp.Bonneville Power Administratio PacifiCorp West
Powerex Corp.NorthWestern/PacifiCorp East Bonneville Power Administration
Powerex Corp.PacifiCorp East Sierra Pacific Power STF
Powerex Corp.Bonneville Power Administratio PacifiCorp East
Powerex Corp.PacifiCorp West NorthWestern/PacifiCorp East
Powerex Corp.Idaho Power Company PacifiCorp East
Powerex Corp.PacifiCorp East Idaho Power Company
Powerex Corp.Idaho Power Company Bonneville Power Administration
Powerex Corp.PacifiCorp East NorthWestem/PacifiCorp East
Powerex Corp.Sierra Pacific Power Bonneville Power Administration
Powerex Corp.PacifiCorp West PacifiCorp East
Powerex Corp.NorthWestern/PacifiCorp East PacifiCorp East
Powerex Corp.Bonneville Power Administratio Sierra Pacific Power
Powerex Corp.Bonneville Power Administratio Sierra Pacific Power STF
Powerex Corp.PacifiCorp West Bonneville Power Administration
Powerex Corp.PacifiCorp West Sierra Pacific Power
Powerex Corp.PacifiCorp West Sierra Pacific Power STF
Powerex Corp.PacifiCorp East Bonneville Power Administration
PP & L Montana Avista Sierra Pacific Power
PP & L Montana PacifiCorp East Bonneville Power Administration
PP & L Montana Bonneville Power Administratio PacifiCorp West
PP & L Montana PacifiCorp West PacifiCorp West
PP & L Montana NorthWestern/PacifiCorp East Avista
PP & L Montana Avista PacifiCorp West
PP & L Montana NorthWestern/PacifiCorp East Bonneville Power Administration
PP & L Montana NorthWestern/PacifiCorp East PacifiCorp East
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007
Y ccount 456)(t;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 (j) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billing TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand Megawatt Hours Megawatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered(e)(f)
(g)
(h)(i)
(j)
JEFF LGBP 1,409 1,40!
JBSN M345 1,428 1,421
HTSP M345 656 65!
BOBR LOLa 792 79::
BOBR ENPR 064 06'
LOLa M345 596 59E
LOLa M345 288 281
ENPR JBSN 980 98(
LGBP JBSN 204 20'
HTSP LGBP 488 3,48!
BOBR M345 760 76(
LGBP BOBR 039 03!
JBSN HTSP 409 5,4m
IPCO BOBR 916
BOBR IPCO 178 171
IPCO LGBP 10,438 10,431
BOBR HTSP 10,746 74E
M345 LGBP 15,303 15,30~
ENPR BOBR 513 51~
HTSP BOBR 19,046 04E
LGBP M345 29,981 981
LGBP M345 725 721
JBSN LGBP 441 441
ENPR M345 296 29E
ENPR M345 400
BOBR LGBP 293 29~
LOLa M345
BOBR LGBP
LGBP JBSN 100 10C
ENPR JBSN 739
JEFF LOLa 825
LOLa JBSN 151 151
JEFF LGBP 564 56'
HTSP BOBR 142 14::
483,108 483,101
FERC FORM NO.1 (ED. 12-90)Page 329.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)D A Resubmission 04/18/2007
~, . ~ ccounf'456.
(Including transactions referred to as 'wheeling
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, lFP - "long-Term Firm Point to Point
Transmission Service, OlF - Other long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, as - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups' for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line Payment By Energy Received From Energy Delivered To Statistical
No.(Company of Public Authority)(Company of Public Authority)(Company of Public Authority)Classifi-
(Footnote Affiliation)(Footnote Affiliation)(Footnote Affiliation)cation
(a)(b)(c)(d)
PP & L Montana NorthWestern/PacifiCorp East PacifiCorp East
PPM Energy PacifiCorp West NorthWestern/PacifiCorp East
PPM Energy NorthWestem/PacifiCorp East Sierra Pacific Power
PPM Energy PacifiCorp West Bonneville Power Administration
PPM Energy Bonneville Power Administratio PacifiCorp West
PPM Energy PacifiCorp East Sierra Pacific Power
PPM Energy Bonneville Power Administratio Sierra Pacific Power
PPM Energy NorthWestern/PacifiCorp East PacifiCorp West
PPM Energy Bonneville Power Administratio PacifiCorp East
PPM Energy PacifiCorp East Bonneville Power Administration
Puget Sound Energy PacifiCorp East Bonneville Power Administration
Puget Sound Energy NorthWestern/PacifiCorp East PacifiCorp East
Sempra Energy Trading Corp Idaho Power Company PacifiCorp East
Sempra Energy Trading Corp Bonneville Power Administratio PacifiCorp East
Sempra Energy Trading Corp Avista Sierra Pacific Power
Sempra Energy Trading Corp NorthWestem/PacifiCorp East PacifiCorp East
Sempra Energy Trading Corp PacifiCorp West Sierra Pacific Power
Sempra Energy Trading Corp PacifiCorp West PacifiCorp East
Sempra Energy Trading Corp PacifiCorp West PacifiCorp East STF
Sempra Energy Trading Corp Bonneville Power Administratio Sierra Pacific Power
Sempra Energy Trading Corp Bonneville Power Administratio Sierra Pacific Power STF
Sierra Pacific Power PacifiCorp West PacifiCorp East
Sierra Pacific Power Seattle City Light Sierra Pacific Power
Sierra Pacific Power Idaho Power Company Avista
Sierra Pacific Power Idaho Power Company PacifiCorp East
Sierra Pacific Power Sierra Pacific Power Bonneville Power Administration
Sierra Pacific Power Idaho Power Company Bonneville Power Administration
Sierra Pacific Power PacifiCorp East PacifiCorp East
Sierra Pacific Power PacifiCorp West Sierra Pacific Power
Sierra Pacific Power PacifiCorp West Sierra Pacific Power
Sierra Pacific Power PacifiCorp West Sierra Pacific Power STF
Sierra Pacific Power NorthWestern/PacifiCorp East Sierra Pacific Power
Sierra Pacific Power NorthWestern/PacifiCorp East PacifiCorp East
Sierra Pacific Power PacifiCorp East Sierra Pacific Power
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
FOOTNOTE DATA
ISchedule Page: 335 Column: bLine No.
Recipient
Pete Wilson
AMBAC Assurance Corp
Amort of Prepaid Exp
Business Plus
Deutsche Bank
Deutsche Bank Trust
Georgeson ShareholderGlobal Insight
J P Morgan Trust
Misc Customers
Option Expense
Port of Morrow
Prepaid Contract Acctg
RSP, PS, TSR & DSP
Union Bank of California
Wells Fargo Shareowner ServiceOther i terns under $ 5, 000
Purpose
2005 Annual Report
Annual premium on Humbolt
Deutche BankContribution
Broker Fees
Fee Humbol t County
Letter of AgreementData Subscription
Sweetwater & PC Bonds
WECC
Directors Restriced Stock
Port of Morrow Bond Manage
Amort of Deutsche Bank
Directors Restricted Stock
Sweetwater & PC Bonds
Wells Fargo - Transfer
Misc
Total
Amount
$ 49,450
52,290
12,233
000
190,499
000
10,764
23,391
15,265
365
32,995
475
23,760
10,683
13,887
29,304
289
--------
$493,650
-------------
IFERC 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 2006/04
(2) n A Resubmission 04/18/2007
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. If
composite depreciation accounting is used, report available information called for in columns (b) through (g) on this basis.
4. If provisions for depreciation were made during the year in addition to depreciation provided by application of reported rates, state at
the bottom of section C the amounts and nature of the provisions and the plant items to which related.
A. Summary of Depreciation and Amortization Charges
Depreciation Amortization of
Line ~reciation Expense for Asset Limited Term Amortization of
No.Functional Classification xpense Retirement Costs Electric Plant Other Electric Total
(Account 403)(Account 403.(Account 404)Plant (Acc 405)
(a)(b)(c)(d)(e)(f)
1 Intangible Plant 089,661 089,661
2 Steam Production Plant 23,623,910 623 910
3 Nuclear Production Plant
4 Hydraulic Production Plant-Conventional 606,566 606 566
5 Hydraulic Production Plant-Pumped Storage
6 Other Production Plant 035,377 035,377
( Transmission Plant 905,223 905,223
8 Distribution Plant 27,682,064 682,064
S Regional Transmission and Market Operation 246 569 246,569
General Plant 296,299 296,299
Common Plant-Electric
TOTAL 90,803,410 089 661 99,893,071
B. Basis for Amortization Charges
Account 404
Balance to be 2006 Balance to be Remaining months of
Amortized Amortization amortized 12/31/06 amortization 12/31/06
(1)000 000 12,000
(2)659,523 400,503 13,283 905
(3)18,007 166 376 719 726 106
(4)234 830 12,252 222 578 218
(5)340,123 288 187 051 936 252
TOTAL 37 265,642 089,661 33,296 528
(1) Shoshone-Bannock Tribe license and use agreement (termination date December 31 , 2023).
(2) Middle snake relicensing costs (amortized over a 30-year liscense period).
(3) Computer software packages (amortized over a 60 month period from date of purchase).
(4) American Falls dam road rebuild (termination date February 28, 2025).
(5) Shoshone-Bannock Right of Way (termination date December 31 , 2028).
FERC FORM NO.1 (REV. 12-03)Page 336
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2006/Q4(2) nA Resubmission 04/18/2007
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreclaOie I:.SIlmaIea !'leI Appnea Monamy Average
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
(a)
(In Th
?~)
sandS)
7~f (perJ)ent)(pe
r~~nt)ree 7~f
310.203 75.R4.19.
311.130,537 90.10.S1.18.
312.980 55.10.R3.19.
312.423,501 70.10.R1.18.
312.977 25.20.R3.16.40
314.122 586 50.10.00 3.46 SO.17.
315.359 65.S1.17.
316.307 45.RO.16.40
316.25.L3.
316.40 226 25.L3.5.40
316.124 25.8.45 L3.
316.251 17.25.S2.
316.115 14.35.LO.9.40
317.000 837
Subtotal Steam 837 062
331.133 690 100.20.S1.36.
332.19,460 85.10.00 1.93 S4.31.40
332.219,561 85.10.00 S4.34.
332.600 69.SQUARE 63.
333.187,441 80.R3.38.
334.36,770 47.R1.28.
335.15,624 100.SO.34.
336.950 75.R3.34.
Subtotal Hydro 625,096
341.00 302 35.SQUARE 34.
342.521 35.SQUARE 33.
343.29,957 35.SQUARE 34.
344.685 35.SQUARE 34.
345.682 35.SQUARE 34.
346.386 35.SQUARE 34.
Subtotal Other 106,533
350.22,455 65.R3.52.
350.838 24.SQUARE 24.
352.779 60.20.R3.48.
353.245,791 45.SO.32.
354.98,004 60.30.S4.37.
355.77,282 55.60.R2.39.
49 356.120 017 60.20.R2.41.40
50 359.318 65.R3.27.
FERC FORM NO.1 (REV. 12-03)Page 337
This Page Intentionally Left Blank
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2006/Q4(2) DA Resubmission 04/18/2007
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreclaDie I::sumatea Net APPIl60 MOrtality Average
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
(In Th
~~)
sandS)7~f
(pe
rJ~nt)(per~~nt)r~e Life
la)la)
Subtotal Transmission 604 484
361.20,494 55.20.R2.40.
362.142 958 50.01.43.
364.194,702 41.50.R1.29.
365.919 46.30.R2.29.
366.43,632 60.25.R2.51.
367.162,350 37.10.S1.28.
368.318,765 35.R2.27.
369.272 30.30.S2.20.
370.52,622 30.L2.19.
371.359 28.S5.
371.275 11.20.11.RO.
373.067 20.20.R1.10.
374.370
Subtotal Distribution 092,785
390.25,833 100.S1.38.
390.31,213 50.R3.36.
390.34E 25.S3.16.
391.20.SQUARE
391.22,696 20.SQUARE
391.868 16.S5.
392.323 25.1.78 L3.
392.580 15.50.S2.15.
392.40 830 25.L3.
392.52~25.9.45 L3.
392.22,448 17.25.S2.10.
392.796 17.25.S2.
392.551 30.25.S1.21.
393.982 25.SQUARE
394.222 20.SQUARE
395.761 20.SQUARE
396.307 14.35.LO.
397.914 15.11.SQUARE
397.17,234 15.SQUARE 7.40
397.623 15.SQUARE
397.40 1,426 10.16.45 SQUARE
398.910 15.SQUARE
Subtotal General 206 172
Total Plant 3,472,132
FERC FORM NO.1 (REV. 12-03)Page 337.
Name of Respondent This
0ort
Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2006/04(2) DA Resubmission 04118/2007
REGULATORY 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 . O\,!ferred
No.(Furnish name of regulatory commission or body the Regulatory Expense for In Account
Commission Current Year 18;2.3 adocket or case number and a description of the case)Utility (b) + (c)Beginning 0 Year
(a)(b)(c)(d)(e)
1 Federal Energy Regulatory Commission:
Annual administrative charges 470 901 470 907
General Regulatory Expenses - Other 987 136 987 136
6 Regulatory Commission Expenses - Idaho
Other Expenses 10,417 10,417
9 Oregon Hydro - Fees Amortization 158,50E 158 506
Regulatory Commission Expenses - Oregon
General Rate Case 064 46,064
Other Expenses 245 009 245,006
TOTAL 312,401 288,626 976 225
FERC FORM NO.1 (ED. 12-96)Page 350
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2006/04
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) 0 A Resubmission 04/18/2007
REGULATORY COMMISSION EXPENSES (Continued)
3. Show in column (k) any expenses incurred in prior years which are being amortized. List in column (a) the period of amortization.
4. List in column (f), (g), and (h) expenses incurred during year which were charged currently to income, plant, or other accounts.
5. Minor items (less than $25 000) may be grouped.
AMORTIZED DURING YEAR
(h)
Deferred to
Account 182.
(i)
Contra
Account Amount
(k)
Deferred inAccount 182.
End of Year
(I)
Line
No.
Electric 928 10,417
Electric 928 470,907
Electric 928 987 136
Electric 928 158 506
Electric
Electric
928
928 245,009
---------,..." ".........
976 225
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 2006/04
(2)DA Resubmission 04/18/2007
RESEARCH, DEVELOPMENT, AND DEMONS RATION 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, 0 & 0 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, 0 & 0 Performed Intemally:a. Overhead
(1) Generation b. Underground
a. hydroelectric (3) Distribution
i. Recreation fish and wildlife (4) Regional Transmission and Market Operation
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, 0 & 0 Performed Externally:
e. Unconventional generation (1) Research Support to the electrical Research Council or the Electric
f. Siting and heat rejection Power Research Institute
(2) Transmission
Line Classification Description
No.(a)(b)
1 A. Electric R, D & 0 Performed internally:
(1) Generation
e. unconventional generation Air Conditioning Cool Credit
Irrigation Peak Rewards
Energy Star Northwest Homes
Oregon Weatherization
Residential Retrofit - Cooling
Residential Retrofit - Lighting
Weatherization Asistance Idaho
Building Efficiency Program
Commercial Retrofit
Oregon School Efficiency
Industrial Efficiency
Irrigation Efficiency Rewards Program
NEEA
Distribution Efficiency Initiative
Small ProjecVEducation funds
DSM Analysis & Accounting
(7)
B. 4 Research Support to Others BPA Energy House Calls
BPA Rebate Advantage
BPA Residential Education Initative
BPA Commercial Education Initiative
BPA Other C&RD and CRC
Total R, D&D
FERC FORM NO.1 (ED. 12-87)Page 352
Name of Respondent This
wort
Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2006/04
(2)D A Resubmission 04/18/2007
RESEARCH, DE VELOPMENT, AND DEMONSTRATION ACTIVITIES (Continued)
(2) Research Support to Edison Electric Institute
(3) Research Support to Nuclear Power Groups
(4) Research Support to Others (Classify)
(5) Total Cost Incurred
3. Include in column (c) all R, D & D items performed internally and in column (d) those items performed outside the company costing $5 000 or more
briefly describing the specific area of R, D & D (such as safety, corrosion control, pollution, automation, measurement, insulation, type of appliance, etc.
Group items under $5,000 by classifications and indicate the number of items grouped. Under Other, (A (6) and B (4)) classify items by type of R, D & D
activity.
4. Show in column (e) the account number charged with expenses during the year or the account to which amounts were capitalized during the year
listing Account 107, Construction Work in Progress, first. Show in column (f) the amounts related to the account charged in column (e)
5. Show in column (g) the total unamortized accumulating of costs of projects. This total must equal the balance in Account 188, Research
Development, and Demonstration Expenditures, Outstanding at the end of the year.
6. If costs have not been segregated for R, D &D activities or projects, submit estimates for columns (c), (d), and (f) with such amounts identified by
Est."
7. Report separately research and related testing facilities operated by the respondent.
Costs Incurred Internally Costs Incurred Externally AMOUNTS CHARGED IN CURRENT YEAR Unamortized Line
Curren, Year Current Year Account Amount Accumulation No.
(d)(e)(1)(9)
235,476 235,476
324,418 324 418
469,609 469 609
126 126
17 , 444 17 ,444
298,754 298 754
1 ,455 373 1 ,455,373
374,008 374,008
819 31,819
24,379 24,379
625,407 625,407
779,620 779 620
930,455 930,455
306 306
459 459
309 685 309,685
336,701 336,701
52,673 673
56,727 56,727
663 663
124 956 124 956
10,908,338 575 720 11,484 058
FERC FORM NO.1 (ED. 12-87)Page 353
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2006/04
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/18/2007
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.
(a)
13,955 231
13,597 666
858,358
26,526,155
187 137
Line
No.
Classification Direct PayrollDistribution Total
Electric
Operation
Production
4 Transmission
Regional Market
Distribution
7 Customer Accounts
8 Customer Service and Informational
9 Sales
10 Administrative and General
11 TOTAL Operation (Enter Total of lines 3 thru 10)
12 Maintenance
13 Production
14 Transmission
15 Regional Market
16 Distribution
17 Administrative and General
18 TOTAL Maintenance (Total of lines 13 thru 17)
19 Total Operation and Maintenance
20 Production (Enter Total of lines 3 and 13)
21 Transmission (Enter Total of lines 4 and 14)
22 Regional Market (Enter Total of Lines 5 and 15)
23 Distribution (Enter Total of lines 6 and 16)
24 Customer Accounts (Transcribe from line 7)
25 Customer Service and Informational (Transcribe from line 8)
26 Sales (Transcribe from line 9)
27 Administrative and General (Enter Total of lines 10 and 17)
28 TOTAL Opere and Maint. (Total of lines 20 thru 27)
29 Gas
30 Operation
31 Production-Manufactured Gas
32 Production-Nat. Gas (Including Expl. and Dev.
33 Other Gas Supply
34 Storage, LNG Terminaling and Processing
35 Transmission
36 Distribution
37 Customer Accounts
38 Customer Service and Informational
39 Sales
40 Administrative and General
41 TOTAL Operation (Enter Total of lines 31 thru 40)
42 Maintenance
43 Production-Manufactured Gas
44 Production-Natural Gas (Including Exploration and Development)
45 Other Gas Supply
46 Storage, LNG Terminaling and Processing
47 Transmission
FERC FORM NO.1 (ED. 12-88)Page 354
Name of Respondent
Idaho Power Company
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) A Resubmission 04/18/2007
DIST IBUTION OF SALARIES AND WAGES (Continued)
Year/Period of Report
End of 2006/04
Line
No.
Classification
(a)
Direct PayrollDistribution
(b)
Total
48 Distribution
49 Administrative and General
50 TOTAL Maint. (Enter Total of lines 43 thru 49)
51 Total Operation and Maintenance
52 Production-Manufactured Gas (Enter Total of lines 31 and 43)
53 Production-Natural Gas (Including Expl. and Dev.) (Total lines 32
54 Other Gas Supply (Enter Total of lines 33 and 45)
55 Storage, LNG Terminaling and Processing (Total of lines 31 thru
56 Transmission (Lines 35 and 47)
57 Distribution (Lines 36 and 48)
58 Customer Accounts (Line 37)
59 Customer Service and Informational (Line 38)
60 Sales (Line 39)
61 Administrative and General (Lines 40 and 49)
62 TOTAL Operation and Maint. (Total of lines 52 thru 61)
63 Other Utility Departments
64 Operation and Maintenance
65 TOTAL All Utility Dept. (Total of lines 28, 62, and 64)
66 Utility Plant
67 Construction (By Utility Departments)
68 Electric Plant
69 Gas Plant
70 Other (provide details in footnote):
71 TOTAL Construction (Total of lines 68 thru 70)
72 Plant Removal (By Utility Departments)
73 Electric Plant
74 Gas Plant
75 Other (provide details in footnote):
76 TOTAL Plant Removal (Total of lines 73 thru 75)
77 Paid Absences
78 Preliminary Survey & Investigation
79 Other Accounts
95 TOTAL Other Accounts
96 TOTAL SALARIES AND WAGES
190 282 208 190,282 208
~--------
654 243 695,383 349 626
654 243 695,383 349,626r--
734 187
734 187
15,977 142
866
473,621
734 187
734 187
15,977 142
41,866
473 621
20,492 629
252 163 267 695 383
20,492 629
255 858 650
FERC FORM NO.1 (ED. 12-88)Page 355
This Page Intentionally Left Blank
Name of Respondent
Idaho Power Company
This ~ort Is: Date of Report(1) I2$J An Original (Mo, Da, Yr)
(2) 0 A Resubmission 04/18/2007
M NTHL 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 0) by month the system' monthly maximum megawatt load by statistical classifications. See General Instruction for
the definition of each statistical classification.
Year/Period of Report
End of 2006/04
NAME OF SYSTEM: Idaho Power Company
Line
No.Month
(a)
1 January
2 February
3 March
Total for Quarter 1
5 April
6 May
7 June
8 Total for Quarter 2
9 July
10 August
11 September
12 Total for Quarter 3
13 October
Total for Quarter 4
Total Year to
DatelYear
Monthly Peak
MW - Total
Day of Hour of
Monthly MonthlyPeak Peak
(d)
800
900
800
Firm Network Firm Network Long-Term Firm Other Long-Short-Term Firm Other
Service for Self Service for Point-to-point Term Firm Point-to-point Service
Others Reservations Service Reservation
(e)(f)
(g)
(h)(i)
(j)
810 172 376 276
281 182 401
824 161 401 290
915 515 178 617
560 126 376 329
351 243 376 515
043 304 376 400
954 673 128 244
084 285 376
912 263 376
557 235 376 150
553 783 128 300
969 376 100
226 203 376
337 194 376
532 570 12B 100
954 541 562 261
(b)
391
FERC FORM NO. 1/3-Q (NEW. 07-04)Page 400
Name of Respondent
Idaho Power Company
This ~ort Is:(1) ~An Original(2) A Resubmission
ELECTRIC ENERGY ACCOU T
Date of Report
(Mo, Da, Yr)
04/18/2007
Year/Period of Report
End of 2006/04
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)
Page 401a
Line
No.
Item
(a)
21 DISPOSITION OF ENERGY
22 Sales to Ultimate Consumers (Including
Interdepartmental Sales)
23 Requirements Sales for Resale (See
instruction 4, page 311.
24 Non-Requirements Sales for Resale (See
instruction 4, page 311.
25 Energy Furnished Without Charge
26 Energy Used by the Company (Electric
Dept Only, Excluding Station Use)
27 Total Energy Losses
28 TOTAL (Enter Total of Lines 22 Through
27) (MUST EOUAL LINE 20)
MegaWatt Hours
(b)
13,939,314
108 970
711 853
1 ,254 358
014,495
Name of Respondent
Idaho Power Company
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) D A Resubm ission 04/18/2007
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.
Year/Period of Report
End of 2006/04
NAME OF SYSTEM:Idaho Power Company
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 833 137 581 968 079 8AM
30 February 700,010 581 137 144 8AM
31 March 889,922 750 188 946 9AM
32 April 888,476 901 443 740 8AM
33 May 092 719 841 211 552 7PM
June 031 575,510 050 6PM
930,652 179,104 084 6PM
778,926 232,949 914 6PM
566 053 352 904 578 6PM
383,410 284 088 997 8AM
283 111 140 164 226 8AM
636 325 291 187 318 8AM
TOTAL 014,495 711 853
FERC FORM NO.1 (ED. 12-90)Page 401b
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)2006/Q4(2)0 A Resubmission 04/18/2007 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 Kwor 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 bumed (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 fumish 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 ===z=::;-.'f?'
, " '" " " " ," . ~"
Year Last Unit was Installed 1979 1980
Total Installed Cap (Max Gen Name Plate Ratings-MW)
~:
,i,
:' ," ,, ' " ," "
Net Peak Demand on Plant - MW (60 minutes)747
Plant Hours Connected to Load 8760 4362
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 4961791000 241557000
Cost of Plant: Land and Land Rights 494358 106610
Structures and Improvements 63198975 13664764
Equipment Costs 391410334 54705143
Asset Retirement Costs
Total Cost 455103667 68476517
Cost per KW of Installed Capacity (line 17/5) Including 590.6602 1066.2802
Production Expenses: Oper, Supv, & Engr 136088 864657
Fuel 69637027 3429448
Coolants and Water (Nuclear Plants Only)
Steam Expenses 4221854
Steam From Other Sources
Steam Transferred (Cr)
Electric Expenses
Misc Steam (or Nuclear) Power Expenses 6127655 236070
Rents 187296 8426
Allowances
Maintenance Supervision and Engineering 74915 2439498
Maintenance of Structures
Maintenance of Boiler (or reactor) Plant 7691267
Maintenance of Electric Plant 2636581
Maintenance of Misc Steam (or Nuclear) Plant 4458699 14663
Total Production Expenses 95171382 6992762
Expenses per Net KWh 0192 0289
Fuel: Kind (Coal, Gas, Oil, or Nuclear)Coal Oil COAL Oil
Unit (Coal-tons/Oil-barreVGas-mcf/Nuclear-indicate)Tons Barrels Tons Barrels
Quantity (Units) of Fuel Burned 2803247 12663 145051 801
Avg Heat Cont - Fuel Burned (btulindicate if nuclear)9219 140000 8359 138800
Avg Cost of Fuel/unit, as Delvd f.b. during year 23.617 99.638 000 21.752 96.777 000
Average Cost of Fuel per Unit Bumed 23.339 99.574 000 21.393 80.269 000
Average Cost of Fuel Burned per Million BTU 12.660 16.935 000 280 13.773 000
Average Cost of Fuel Burned per KWh Net Gen 014 000 000 014 000 000
Average BTU per KWh Net Generation 10432.000 000 000 10058.000 000 000
FERC FORM NO.1 (REV. 12-03)Page 402
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)2006/04(2) D A Resubmission 04/18/2007 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:Bennett Mountain No.
(d)(e)(f)
Steam Gas Turbine Gas Turbine
Outdoor Conventional Conventional~~i'1iJij~~-~qii; '
:':~ .~;~:":'
2001 2005
1985 2001 2005
90.172.
264 192
8646 376 329
100000 163980
., ~'
1744910000 23372000 49343000
769351 402745
53672955 4276833 1012941
256370535 47533651 52807282
310812841 52213229 53820223
1096.3416 580.1470 311.4596
711761 141783 46418
34453372 3355948 4118517
2885289
1444277 150923 137818
1779274 101088 143723
52902
11056
408848 94791 77024
7686202 52638 22178
1797301 252430 101399
102255
51332537 4149601 4647077
0294 1775 0942
Coal Oil Gas Gas
Tons Barrels MCF MCF
851079 5769 332425 468929
9777 138778 1035 1038
38.185 101.561 000 10.095 000 000 783 000 000
37.481 100.466 000 10.095 000 000 783 000 000
901 17.237 000 726 000 000 8.461 000 000
020 000 000 144 000 000 083 000 000
9634.000 000 000 14764.000 000 000 9865.000 000 000
FERC FORM NO.1 (REV. 12-03)Page 403
This Page Intentionally Left Blank
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2i An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
FOOTNOTE DATA
ISchedule Page: 402 Line No.: 3 Column: b
This footnote applies to lines 3 and 4. The Jim Bridger Power
Plant consists of four equal units constructed jointly by Idaho
Power Company and Pacific Power and Light Company, with Idaho
owning 1/3 and PacifiCorp owning 2/3. Unit #1 was placed in
commercial operation November 30 , 1974, Unit #2 December 1, 1975,
Unit #3 September 1, 1976, and Unit #4 November 29, 1979.
ISchedule Page: 402 Line No.: 3 Column:
This footnote applies to lines 3 and 4. The Boardman plant
consists of one unit constructed jointly by Portland General
Electric Company, Idaho Power Company, and Pacific Northwest
Generating Company, with Idaho Power Company owning 10%. The
unit was placed in commercial operation August 3, 1980.
ISchedule Page: 402 Line No.: 3 Column: d
This footnote applies to lines 3 and 4. The Valmy plant consists
of two units constructed jointly by Sierra Pacific Power Company
and Idaho Power Company, with Sierra owning 1/2 and Idaho owning
1/2. Unit #1 was placed in commercial operation December 11 , 1981
and Unit #2 May 21, 1985.
ISchedule Page: 402 Line No.: 5 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
ISchedule Page: 402 Line No.: 5 Column:
This footnote applies to line 5 and lines 12 through 43.
Information reflects Idaho Power Company s share as explained
in note on line 3 page 402 column C
ISchedule Page: 402 Line No.: 5 Column: d
This footnote applies to line 5 and lines 12 through 43.
Information reflects Idaho Power Company s share as explained
in note for line 3 page 403 column
ISchedule Page: 402 Line No.Column: b
This footnote applies to lines 9, 10, and 11. PacifiCorp
as operator of the plant will report thisinformation.
'Schedule Page: 402 Line No.: 9 Column:
This footnote applies to lines 9, 10, and 11. Portland General
Electric Company, as operator will report this information.
ISchedule Page: 402 Line No.Column: d
This footnote applies to lines 9, 10 , and 11. Sierra Pacific
Power, as operator of the plant, will report this information.
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2006/04
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) D A Resubmission 04/18/2007
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Large plants are hydro plants of 10,000 Kwor 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
No.
Item
(a)
FERC Licensed Project No. 2736
Plant Name: American Falls
(b)
FERC Licensed Project No. 1975
Plant Name: Bliss
(c)
1 Kind of Plant (Run-of-River or Storage)
2 Plant Construction type (Conventional or Outdoor)
3 Year Originally Constructed
4 Year Last Unit was Installed
5 Total installed cap (Gen name plate Rating in MW)
6 Net Peak Demand on Plant-Megawatts (60 minutes)
7 Plant Hours Connect to Load
8 Net Plant Capability (in megawatts)
(a) Under Most Favorable Oper Conditions
10 (b) Under the Most Adverse Oper Conditions
11 Average Number of Employees
12 Net Generation, Exclusive of Plant Use - Kwh
13 Cost of Plant
14 Land and Land Rights
15 Structures and Improvements
16 Reservoirs, Dams, and Waterways
17 Equipment Costs
18 Roads, Railroads, and Bridges
19 Asset Retirement Costs
20 TOTAL cost (Total of 14 thru 19)
21 Cost per KW of Installed Capacity (line 20/ 5)
22 Production Expenses
23 Operation Supervision and Engineering
24 Water for Power
25 Hydraulic Expenses
26 Electric Expenses
27 Misc Hydraulic Power Generation Expenses
28 Rents
29 Maintenance Supervision and Engineering
30 Maintenance of Structures
31 Maintenance of Reservoirs, Dams, and Waterways
32 Maintenance of Electric Plant
33 Maintenance of Misc Hydraulic Plant
34 Total Production Expenses (total 23 thru 33)
35 Expenses per net KWh
Run-of-River
Outdoor
1949
1950
75.
735
Outdoor
1978
1978
92.
109
973
---, ., -, , , "---, .
, n
---
112
349 840 000 372 214,000
----" ,.. ,--,------
875,318
11,857,401
242 904
110,315
306 333
48,392,271
524.2933
676,645
666,848
480,784
827,455
486,477
16,138,209
215.1761
" '" .' _' ,. ""
175,674
064,072
152 208
186
224 081
146
99,464
96,801
545
204 262
851
142 290
0090
605,398
237 349
560 962
33,765
134 188
830
105,550
52,872
23,948
193,411
206 273
156,546
0058
FERC FORM NO.1 (REV. 12-03)Paae 406
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2006/04
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) DA Resubmission 04/18/2007
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: Brownlee
(d)
FERC Licensed Project No. 2848
Plant Name: Cascade
(e)
1971FERC Licensed Project No.
Plant Name: Oxbow
1971
Storage'
Outdoor
1958
1980
585.40
745
760
Outdoor
1983
1984
12.
758
1961
1961
190.
218
760
- ,-' ,, '
_0,
- .-- , """'-",- --- '--
" n
- "...-----,
728
220
926 140,000 56,406,000
220
202
238 175,000
~----- ----,,-~~,---,- "" ~-----_.._-------,
545,447
30,069 955
66,871 141
51,669,986
518,444
161 674 973
276.1786
82,142
364 154
145 630
12,426,390
122,668
23,140,984
863.2032
866,939
830,938
30,375 714
14,832 256
565,842
56,471 689
297.2194' u
'""- "
0 - 'O'--
.. ",-----"" --, ".,""-, ." _
486,181
139,680
448,182
355,284
336,157
228 395
360,368
200,492
384 516
285,759
763,373
988,387
0014
253,942
67,314
233 083
212 036
193,327
122
242 395
314,054
345
151 880
312 430
046 928
0017
122,489
864
151,833
536
133,863
105
143
854
598
100 570
74,902
800 757
0142
FERC FORM NO.1 (REV. 12-03)Page 407
Line
No.
Name of Respondent
Idaho Power Company
YearlPeriod of Report
End of 2006/04
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) DA Resubmission 04/18/2007
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
a footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
(a)
FERC Licensed Project No. 1971
Plant Name: Hells Canyon
(b)
FERC Licensed Project No. 2726
Plant Name: Malad
(c)
Line
No.
Item
1 Kind of Plant (Run-of-River or Storage)
2 Plant Construction type (Conventional or Outdoor)
3 Year Originally Constructed
4 Year Last Unit was Installed
5 Total installed cap (Gen name plate Rating in MW)
6 Net Peak Demand on Plant-Megawatts (60 minutes)
7 Plant Hours Connect to Load
8 Net Plant Capability (in megawatts)
(a) Under Most Favorable Oper Conditions
10 (b) Under the Most Adverse Oper Conditions
11 Average Number of Employees
12 Net Generation, Exclusive of Plant Use - Kwh
13 Cost of Plant
14 Land and Land Rights
15 Structures and Improvements
16 Reservoirs, Dams, and Waterways
17 Equipment Costs
18 Roads, Railroads, and Bridges
19 Asset Retirement Costs
20 TOTAL cost (Total of 14 thru 19)
21 Cost per KW of Installed Capacity (line 20/5)
22 Production Expenses
23 Operation Supervision and Engineering
24 Water for Power
25 Hydraulic Expenses
26 Electric Expenses
27 Misc Hydraulic Power Generation Expenses
28 Rents
29 Maintenance Supervision and Engineering
30 Maintenance of Structures
31 Maintenance of Reservoirs, Dams, and Waterways
32 Maintenance of Electric Plant
33 Maintenance of Misc Hydraulic Plant
34 Total Production Expenses (total 23 thru 33)
35 Expenses per net KWh
Outdoor
1948
1948
21.
752
, -- ", ,-- ,_'_" ,' ,-- ,-
~o_- . u
___- --,-,"" ,,---
450
137
548,078,000 172,947 000
1 ,558,955
2,403,495
665,106
082,679
819 192
72,529,427
185.2603
205,376
516 767
371 066
211 940
304 683
609,832
441.4254
- .., "
. o
' .
, ,o..
, '' -- --.. -
232 138
831
208,063
128,515
185,916
63,689
205,759
31,898
132,191
205,347
519,781
978,128
0008
104 822
438,550
133 282
431
55,291
987
10,898
363
45,306
891
008 821
0058
FERC FORM NO.1 (REV. 12-03)Page 406.
Name of Respondent
Idaho Power Company
YearlPeriod of Report
End of 2006/04
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) DA Resubmission 04/18/2007
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. 2055
Plant Name: C J Strike
(d)
FERC Licensed Project No.
Plant Name: Swan Falls
(e)
FERC Licensed Project No.
Plant Name: Twin Falls
503
Run-of-River
Outdoor
1952
1952
82.
760
Run-of-River
Conventional
1935
1995
52.
755
Run-of-River
Conventional
1910
1994
25.
748
"" ", "- ,-
"" 'm
- '- -, ------'-' ,- ,.. '
482,845,000 150,325,000133516000
~--~---
0'__' --
-----'------------ -,- ~------
505,508
789,969
764 916
364 871
238 871
23,664 135
285.7987
51,675
25,223,736
641 459
376 612
835,946
70,129,428
805.1771
255,499
10,808,047
932,716
20,494,470
917 603
41 ,408,335
785.1410
"-_, "--'__---..-,- ,...
n,---
' "...,
859 171
245 377
364 137
275
324,413
884
161 741
286
133,527
103,892
368,813
724,516
0077
189,378
48,499
154 510
43,657
137 524
056
36,016
153
557
861
78,233
794,444
0053
199,490
48,011
144,657
35,037
113,466
539
246
551
83,310
178 315
141,340
108 962
0083
FERC FORM NO.1 (REV. 12-03)Page 407.
Line
No.
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2006/04
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) D A Resubmission 04/18/2007
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Large plants are hydro plants of 10 000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
a footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
(a)
FERC Licensed Project No. 2777
Plant Name: Upper Salmon
(b)
FERC Licensed Project No. 2778
Plant Name: Shoshone Falls
(c)
Line
No.
Item
1 Kind of Plant (Run-of-River or Storage)
2 Plant Construction type (Conventional or Outdoor)
3 Year Originally Constructed
4 Year Last Unit was Installed
5 Total installed cap (Gen name plate Rating in MW)
6 Net Peak Demand on Plant-Megawatts (60 minutes)
7 Plant Hours Connect to Load
8 Net Plant Capability (in megawatts)
(a) Under Most Favorable Oper Conditions
10 (b) Under the Most Adverse Oper Conditions
11 Average Number of Employees
12 Net Generation, Exclusive of Plant Use - Kwh
13 Cost of Plant
14 Land and Land Rights
15 Structures and Improvements
16 Reservoirs, Dams, and Waterways
17 Equipment Costs
18 Roads, Railroads, and Bridges
19 Asset Retirement Costs
20 TOTAL cost (Total of 14 thru 19)
21 Cost per KW of Installed Capacity (line 20 / 5)
22 Production Expenses
23 Operation Supervision and Engineering
24 Water for Power
25 Hydraulic Expenses
26 Electric Expenses
27 Misc Hydraulic Power Generation Expenses
28 Rents
29 Maintenance Supervision and Engineering
30 Maintenance of Structures
31 Maintenance of Reservoirs, Dams, and Waterways
32 Maintenance of Electric Plant
33 Maintenance of Misc Hydraulic Plant
34 Total Production Expenses (total 23 thru 33)
35 Expenses per net KWh
Run-of-River
Outdoor
1937
1947
34.
753
Run-of-River
Conventional
1907
1921
12.
760--u
- "- --"',, "
215,141 000 98,994 0000 ,-----
--- ---- -- ", '-' ,-,-,--,.,._- -,---
172,970
1 ,538,577
642 118
563,186
29,359
12,946,210
375.2525
311,407
139 956
512 402
221 828
383
236 976
338.9581
, ,- --- -" ,. ,"",
338,582
558
314 032
18,513
150 366
139,433
69,305
67,754
206,376
161,528
524 447
0071
104,765
778
100,925
950
012
540
214
956
938
309
524,415
0053
FERC FORM NO.1 (REV. 12-03\Paae 406.
Name of Respondent
Idaho Power Company
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) DA Resubmission 04/18/2007
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Unifonm 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 2006/04
FERC Licensed Project No. 1971
Plant Name: Common Facilities
(d)
FERC Licensed Project No. 2061
Plant Name: Lower Salmon
(e)
2899FERC Licensed Project No.
Plant Name: Milner
Run-of-River
Outdoor
1949
1949
60.
Run-of-River
Conventional
1992
1992
59.45
748
, _..., '
--_u,
256,817,000 138,982 000
____,_-----
" n
--.._'
---__.._~_n__'_n_
. .'--'------ "--,--,--
114 367
15,744,184
13,556,785
155 344
051
30,669,731
0000
403,335
888 303
602 823
493,114
88,693
14,476,268
241.2711
138 100
10,326,813
147 050
27,574 118
501 876
687 957
936.7192
. '' ,..." "."," "" ".-'_'"
..n__'__."'_
774 092
78,072
852 164
0000
748,221
94,332
406,261
155,398
193,365
235
177 235
293
843
256 010
153,733
298 926
0090
106 566
337 830
529
46,156
141 358
1,461
36,436
38,311
013
69,660
093
916,413
0138
FERC FORM NO.1 (REV. 12-03)Page 407.
Line
No.
This Page Intentionally Left Blank
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/18/2007 2006/04
FOOTNOTE DATA
ISchedule Page: 406 Line No.Column: b
American Falls generating capacity is dependent upon water releases controlled by the
Uni ted States Bureau of Reclamation.
ISchedule Page: 406 Line No.Column:
Cascade generating capacity is dependent upon water releases controlled by the United
States Bureau of Reclamation.
ISchedule Page: 406 Line No.Column: f
Upstream storage in Brownlee Reservoir.
ISchedule Page: 406.Line No.Column: b
Upstream storage in Brownlee Reservoir
ISchedule 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 2006/04
(2)DA Resubmission 04/18/2007
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 I~stall~d ca~aclty (\jet Peak Net GenerationName of Plant Orig.Name Plate atin Demand Excluding Cost of Plant
No.Const.(InMW)MVV Plant Use
(a)(b)(c)(60(Hjln.(e)(f)
Hydro:
Clear Lakes 1937 2.4 15,691 00e 1 ,734 386
Thousand Springs 1912 12.50,415,000 697 635
Internal Combustion:
Salmon Diesel (1)1967 144 901 055
(1) Salmon units are classified as standby.
FERC FORM NO.1 (REV. 12-03)Page 410
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 2006/04
(2)0 A Resubmission 04/18/2007
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 t-ue!Maintenance Kind of Fuel (per Million Btu)No.
(g)
(h)(i)(k)(I)
693 754 824 78,860
533 822 113,423 171 934
180 211 Diesel
FERC FORM NO.1 (REV. 12-03)Page 411
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2006/Q4
(2) Fi A Resubmission 04/18/2007
TRANSMISSION LINE STATIST
1. Report information concerning transmission lines, cost of li':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.
LENG~H rOle rviles)Line lVI'll
(Indicate wtiere Type of NumberNo.~lr:I t e ascP pother than u dergroun lines
60 cvcle, 3 nhase)Supporting report circuit miles)
From vn ~!rl,Jc!ure ::itru~~~res CircuitsOperatingDesignedStructureof Line of 'lllot er
DeSi
ajated
Ine(a)(b)(c)(d)(e)
(g)
(h)
1 Boardman Slatt 500.500.S Tower 1.79
3 Borah Midpoint 345.500.S Tower 85.
4 Jim Bridger Goshen 345.345.S Tower 226.
5 State Line Midpoint 345.345.S Tower 76.
6 Kinport Borah 345.345.S Tower 27.
7 Midpoint Borah #1 345.345.H Wood 79.
8 Midpoint Borah #2 345.345.H Wood 77.59
9 Adelaide Tap Adelaide 345.345.H Wood
Quartz LaGrande 230.230.H Wood 46.
Midpoint Hunt 230.230.S Tower
Brady Antelope 230.230.H Wood 56.
Brady Treasureton 230.230.H Wood
Brady #1 & #2 Kinport 230.230.S Tower 1B.
Jim Bridger Point of Rocks 230.230.H Wood
Brownlee Ontario 230.230.S Tower 72.
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
Boise Bench Caldwell 230.230.H Wood 33.
Boise Bench Cloverdale 230.230.S Tower 15.
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
Bennett Mtn PP Rattlesnake TS 230.230.SP Steel
Boise Bench Midpoint #1 230.230,S Tower
Boise Bench Midpoint #1 230.230.H Wood 108.
Brownlee Quartz Jct 230.230.S Tower
Brownlee Quartz Jct 230.230.H Wood 41.
Brownlee Boise Bench #1 & #2 230.230.S Tower 99.
Oxbow Brownlee 230.230.S Tower 10.
TOTAL 570.11.160
FERC FORM NO.1 (ED. 12-87)Page 422
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2006/04(2) nA Resubmission 04/18/2007
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 sole owner but which the respondent operates or shares in the operation of, fumish 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 0) to (I) on the book cost at end of year.
vV;:' I VI" LINt:: (include In Column (j) Land,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total LineOther Costs Expenses Expenses (0)Expenses No.(i)(k)(I)(m)(n)
(p)
X1760 ACSR 446 706 446 706
1272 ACSR 256 361 776,998 033 379
1272 ACSR 463,15,740 14/16,223,456
95 ACSR 571 97!10,996,449 566,426
1272 ACSR 344,22C 026,033 372 253
15.5 ACSR 263,5,436 624 721
15.5 ACSR 651 045,455 110,306
15.5 ACSR 51,347 946 399 394
95 ACSR 51,414 310 541 361 955
715.5 ACSR 14~998,452 007,59/
1272 ACSR 106,301 536,324 644 625
1795 ACSR 186 186
1715.5 ACSR 18,82!969 476 968,305
1272 ACSR 19C 51,525 52,715
X954 ACSR 676,831 246 910 21,923746
15.5 ACSR 347 96,012 372 360,334
15.5 ACSR
1272 ACSR B9!212 523 214 422
1590 ACSR 136 231 755,911 894,147
1272 ACSR 133 695,395 829 352
15.5 ACSR
1272 ACSR 999,534,651 533 677
1795 AAC 60,895 60,895
1954 ACSR 34,026,470 16,060 644
I2X954 ACSR 194 902,042 096 605
1272 ACSR
1272 ACSR 701 666,354 746,055
15.5 ACSR 336 722,502 056 666
15.5 ACSR
95 ACSR 795,462 846,530
95 ACSR
~ARIOUS 269,411 991,Q43 260,454
1272 ACSR 162,550 166 563
600,566 295,621 093 322 221 661 163 918 749 697 120 66~034 27!
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 2006/Q4(2) n A Resubmission 04/18/2007
TRANSMISSION LINE STATIST
1. Report information concerning transmission lines, cost of Ii~es, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts.Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121 , Nonutility Property.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line IIUI'l LENG~H role miles)(Indicate where Type of ~lrI t e a~ of NumberNo.other than u dergroun lines
60 cycle, 3 phase)Supporting report circuit miles)
From un ~!rl:lcIUre u~,tj.t!U~fWeS CircuitsOperatingDesignedStructureof Line of Anot erDesi~)ated Line(a)(b)(c)(d)(e)
(g)
(h)
1 Boise Bench Midpoint #2 230.230.S Tower 3.42
2 Boise Bench Midpoint #2 230.230.H Wood 102.
3 Oxbow Pallette Jct 230.230.S Tower 20.
4 Pallette Jct Imnaha 230.230.H Wood 24.43
5 Hells Canyon Palette Jct 230.230.S Tower
6 Brownlee Boise Bench 230.230.S Tower 102.
7 Boise Bench Midpoint #3 230.230.H Wood 106.
8 Palette Jct Enterprise 230.230.H Wood 29.
9 Borah Brady #2 230.230,S Tower
Borah Brady #2 230.230.H Wood
Borah Brady #1 230.230.H Wood
Goshen State Line 161.161.H Wood 90.
Don Goshen 161.161.S Tower
Don Goshen 161.161.H Wood 46.
American Falls Power Plant Adelaide 138.138.H Wood
American Falls Power Plant Adelaide 138.0(138.SPWood
Minidoka Loop Adelaide 138.138.S Tower 1.11
Nampa Caldwell 138.138.SPWood
Upper Salmon Mountain Home Jct 138.H Wood
Upper Salmon Mountain Home Jct 138.138.H Wood 49.
Upper Salmon Cliff 138.138.H Wood 30.
Eastgate Russet 138.138.00 S P Wood
Brady Fremont 138.138.S Tower
Brady Fremont 138.138.H Wood 24.
Brady Fremont 138.138.SPWood 24.
King Lower Malad 138.138.H Wood 84.
Emmett Jct Payette 138.138.H Wood 62.
Mountain Home AFB Tap 138.138.H Wood
Ontario Quartz 138.138.H Wood 73.
King American Falls PP 138.138.S Tower 1.03
King American Falls PP 138.138.H Wood 146.40
King American Falls PP 138.138.SPWood
Duffin Clawson 138.138.H Wood
TOTAL 570.11.02 160
FERC FORM NO.1 (ED. 12-87)Page 422.
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2006/04
(2)D A Resubmission 04/18/2007
RANSMISSION LINE STATISTICS (( ontinued)
7. Do not report the same transmission line structure twice. F!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 sole owner but which the respondent operates or shares in the operation of, fumish 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 0) to (I) on the book cost at end of year.
INF Iinciude In Column U) Land,l,,;U~1 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)
15.5 ACSR 227 654,772 882 597
VARIOUS
1272 ACSR 30!075,638 098,946
1272 ACSR 138,47.233,942 372,419
1272 ACSR 10,252 130 262,867
954 ACSR 170 694 620,492 791,186
15.5 ACSR 247 875 963 123,820
1272 ACSR 51,12.631 895 683,017
1272 ACSR 226,250 229,318
715.5 ACSR
1272 ACSR 10,180 008 190 072
1250 COPPER 648,382 664,537
15.5 ACSR 76,041 622 852 69B 893
97.5 ACSR
50 COPPER 346 862 373 369
50 COPPER
15.5 ACSR 249 232 264,320
95 AAC 157 794,059 951,491
95 ACSR 47,696 746 744,433
VARIOUS
795 ACSR 764 183 807 751
1795 AAC 270 82~557 504 828,327
~ARIOUS 564 93~542 654 107 586
ARIOUS
VARIOUS
VARIOUS 76,398,534 1,475,357
VARIOUS 30,327 120 358 038
397.5 ACSR 95'955
VARIOUS 34,421 502 877 537 305
715.5 ACSR 148,550,548 699,462
715.5 ACSR
1715.5 ACSR
~\O 191 309,827 314 018
600 568 295 621 093 322 221 661 163,918 749 697 120664 11 ,034 27~
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 2006/Q4
(2) Ei A Resubmission 04/18/2007
TRANSMISSION LINE STATISTICS
1. Report infonmation concerning transmission lines, cost of li~es, 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 Unifonm System of Accounts.Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line IUN LENGJ,H role miles)(Indicate wHere Type of
WJt e ascfpf NumberNo.other than u Clergroun lines
60 cvcle, 3 chase)Supporting report circuit miles)
From Operating Designed
un ~lfl,JcIUre I ugf~~~1~~~s CircuitsStructureof LineDesi
U)ated
Line(a)(b)(c)(d)(e)
(g)
(h)
1 American Falls Brady Tie 138.138.H Wood
2 Upper Salmon A-King 138.138.H Wood
3 Upper Salmon B Wells 138.138.H Wood 125.
4 King Wood River 138.138.H Wood 73.
5 Boise Bench Grove 13B.138.SPWood 10.
6 Quartz John Day 138.138.H Wood 67.
7 Sinker Creek Tap 138.138.H Wood
8 Mora Cloverdale 138.138.H Wood
9 Mora Cloverdale 138.138.S P Wood 22.
Stoddard Jct Stoddard Sub 138.138.S P Steel
Fossil Gulch Tap 138.138.H Wood 1.95
Wood River Midpoint 138.13B.H Wood 53.
Wood River Midpoint 138.138.SPWood 16.
Oxbow McCall 138.138.H Wood 38.
Oxbow McCall 138.138.SPWood
Lowell Jct Nampa 138.138.SPWood
Hunt Milner 138.138.S P Wood 19.40
Strike Bruneau Bridge 138.138.H Wood 13.47
American Falls Kramer Sub 138.138.SPWood 18.
Pingree Haven 138.138.S P Wood 11.
Midpoint Twin Falls 138.13B.S P Wood 25.
Twin Falls Russett 138.138.SPWood
Blackfoot Aiken 138.138.SPWood
Peterson Tendoy 138.138.H Wood 57.
Eastgate Tap Eastgate 138.138.S P Wood
Boise Bench Mora 138.138.H Wood 13.
Bowmont-Caldwell Simplot Sub 138.138.SPWood
Gary Lane Eagle 138.13B.S P Wood
Locust Grove Blackcat Sub 138.138.S P Steel
Boise Bench Butler 138.138.SPWood
Eagle Star 138.SPWood
Karcher Sub Zilog Tap 138.138.S P Steel
Cloverdale - 712 712 - Wye 138.138.S P Steel
Butler Wye 13B.138.S P Steel
Horseflat Starkey 138.138.S P Steel
TOTAL 570.11.160
FERC FORM NO.1 (ED. 12-87)Page 422.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2006/04(2) DA Resubmission 04/18/2007
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 sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (I) on the book cost at end of year.
COST OF LINE (Include In Column (j) Land EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total LineOther Costs Expenses Expenses (0)Expenses No.(I)(k)(I)(m)(n)
(p)
954 ACSR 921 921
?50 COPPER 741 93,073 81~
ARIOUS 28,49(745 804 774 29~
ARIOUS 173,68 355 148 528,831
ARIOUS 225,60,629,855 195
97.5 ACSR 92,362,416 454 589
ARIOUS 199 219
1715.5 ACSR 736,433,141 169 37'
!VARIOUS
1272 ACSR
50 COPPER 45(63,439 63,889
97.5 ACSR 281,06'374,306 655 370
97.5 ACSR
97.5 ACSR 18,752,478 836,661
97.5 ACSR
15.5 ACSR 211,131 445,893 657 024
15.5 ACSR OB8 540 091 864
397.5 ACSR 587,404 602,331
15.5 ACSR 13,73'052 549 066 283
397.5 ACSR 21~778 092 789,305
VARIOUS 54,958 765 013 613
715.5 ACSR 16,206 158 222,948
J15.ACSR 13,456 919 470 535
p97.5 ACSR 395 691 449,949 845 645
1715.5 ACSR 45,054 909 100 898
15.5 ACSR 632,718 647 415
95 AAC 49,642 49,642
95 AAC 489 957 948 446 985
1272 ACSR 935,884 136 819,861
1272 ACSR 838,605 B73 292
715.5 ACSR 909,433 909 433
1795 AAC 443 805 486 840
1272 ACSR 140,41 709 148 849 560
1795 ACSR 134 471 1,405,436 539 907
~54 ACSR 416 92!546 481,471
600,568 295,621 093 322,221 661 163 918 749,697 120,664 034 271
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 2006/Q4
(2) D A Resubmission 04/18/2007
TRANSMISSION LINE STATIST
1. Report infonmation 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 Unifonm 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.
(Indicate .J.~;'J
LENG~H role miles)Line Type of ~Io t e ascf of NumberNo.other than u dergroun lines
60 cvcle, 3 chase)Supporting report circuit miles)
un ~:nv~~ure '=!.Iru~~~res CircuitsFromOperatingDesignedStructureof Anot erDesi
(Wated
Line(a)(b)(c)(d)(e)
(g)
(h)
1 Chestnut Happy Valley 13B.138.S P Steel
2 Caldwell Willis 138.13B.S P Steel
3 Caldwell Willis 138.138.S P Steel 1.59
4 Caldwell Willis 138.138.S P Wood
5 Valivue Tap 138.138.S P Steel
6 Kinport Don #1 138.138.S Tower
7 Twin Falls PP Tap 138.138.H Wood
8 American Falls PP Amercian Falls Trans ST 138.138.S P Steel
9 Lower Salmon King Tie 138.138.H Wood
C J Strike Strike Jct 138.0 138.S Tower
Strike Jct Mountain Home Jct 138.138.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.SPWood 1.31
Swan Falls Tap 138.138.H Wood
Hines BPA (Harney)115.115.H Wood
69 Kv Lines 69.69.H Wood 166.
69 Kv Lines 69.69.S P Wood 958.43
46 Kv Lines 46.46.S P Wood 411.
TOTAL 570.11.160
FERC FORM NO.1 (ED. 12-87)Page 422.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2006/04(2) nA Resubmission 04/18/2007
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 sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (I) on the book cost at end of year.
IJU::i I ur- 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)
1272 ACSR 100,161 100 161
1272 ACSR 168,140,418 30B 643
1795 ACSR
1795 ACSR
95 ACSR 351,497 351 497
15.5 ACSR 171 212 777 213 951
50 COPPER 53,888 53,946
15.5 ACSR 76,560 76,560
97.5 ACSR 4,406 4,406
15.5 ACSR 07'253,872 254 946
97.5 ACSR 35!524,571 528 926
15.5 ACSR 90,689,967 719 869
15.5 ACSR
15.5 ACSR 279,481 279,488
15.5 ACSR 964,435 970 055
15.5 ACSR 814 183,606 186,420
397.5 ACSR 261 511 274396
~97.5 ACSR 63,404 65,382
./ARIDUS 928,32,944 846 33,873 836
./ARIOUS
VARIOUS 176,976 960 153 225
736 736 253
163,918 749 691 120,664 034
26,600 568 295,621 093 322,221 661 163 918 749 697 120 664 034,
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 2006/04
(2) Ei A Resubmission 04/18/2007
RANSMISSION 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 the
Line LINt::IUN '-In..III'IIl:I I nuL. I un!::l,;IHl,;UII;:; t"t::HLe!lgth
No.From Type Numbefper Present UltimateMilesMiles
(a)(b)(c)(d)(e)(f)
(g)
1 Horse Flat Starkey SP Steel 1.00
2 Caldwell Willis SP Steel 19.
SP Steel 19.
SP Wood 19.
6 Cloverdale Blackcat SP Wood 18.
7 Nampa Tap SP Steel 12.
TOTAL 13.88.
FERC FORM NO.1 (REV. 12-03)Page 424
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2006/04
(2) EjA Resubmission 04/18/2007
TRAN MISSION 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.
Voltage Line
Size Specification Conf~uration Land and Poles, Towers Conductors Asset Total No.and pacing (Operating)Land Rights and Fixtures and Devices Retire. Costs(h)(i)(k)(I)(m)(n)(0)
(p)
954 ACSR Vert 6' 138 416 925 54€481,471
1272 ACSR Vert 6' 138 168,225 387 752 638 308,642
795 AAC TVS 7'138
795 AAC TVS 7'138
795 ACSR TVS 7'138 118 359 426,951 185,324 730 639
1272 ACSR Vert 12' 230 317 306 504,432 654 254 813
020 815 384 134 370 616 6,775,565
FERC FORM NO.1 (REV. 12'()3)Page 425
Name of Respondent This 'Wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007
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.
Bennett Mountain Power Plant transmission 230.18.
Bennett Mountain Power Plant transmission 18.
Bethel Court distribution 138.13.
Black Cat distribution 138.13.
Blackfoot distribution 46.12.
Blackfoot distribution 138.38.13.
Bliss - attended transmission 138.13.
Blue Gulch distribution 138.34.
Boise Bench - attended distribution 138.34.
Boise Bench - attended transmission 138.69.13.
Boise Bench - attended transmission 230.138.13.
Boise 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.
Cascade Distribution 69.13.
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 2006/Q4
(2)DA Resubmission 04/18/2007
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT LineTransformersSpare(In Service)(In MVa)In Service Transformers Type of Equipment Number of Units Total Capacity No.
(In MVa)
(f)
(g)
(h)(i)
(j)
(k)
300
135
130
374
450
300
734
240
FERC FORM NO.1 (ED. 12-96)Page 427
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)D A Resubmission 04/18/2007
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
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
Chestnut distribution 138.13.
Clear Lake - attended transmission 46.
Cliff transmission 138.46.12.
Cloverdale transmission 138.13.
Cloverdale transmission 138.69.12.
Dale distribution 69.13.
Dale distribution 138.34.
Dale distribution 138.46.12.
Danskin transmission 138.12.
Don distribution 138.
Don distribution 138.13.
Don distribution 138.13.
DRAM distribution 138.13.
DRAM distribution 230.138.13.
Duffin distribution 138.34.
Eagle distribution 138.13.
Eastgate distribution 138.13.
Eckert distribution 138.36.
Eden distribution 138.34.
Eden distribution 138.46.12.
Elkhorn distribution 138.12.
Elmore transmission 138.34.
Elmore distribution 138.69.12.
Emmett distribution 138.12.
Emmett distribution 138.69.12.
Falls distribution 46.12.
Filer distribution 46.12.
Flying H distribution 69.2.40
Fort Hall distribution 46.12.
Fossil Gulch distribution 138.13.
Fossil Gulch distribution 138.34.
Fremont transmission 138.46.12.
Gary distribution 138.13.
Gem distribution 69.13.
Golden Valley distribution 69.12.
Gowen Substation distribution 138.35.
Grindstone distribution 35.12.
Grove distribution 138.12.
Hagerman distribution 46.12.
Hailey distribution 138.12.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2006/Q4
(2)DA Resubmission 04/18/2007
SUBSTATIONS (Continued)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transform ers Spare Total Capacity No.In Service Transformers Type of Equipment Number of Units (In MVa)
(f)
(g)
(h)(i)
(j)
(k)
134
160
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This 'OOort Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2006/04
(2) 0 A Resubmission 04/18/2007
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)
1 Haven distribution 46.34.
Hewlett Packard distribution 138.13.
Hidden Springs distribution 138.13.
Highland distribution 138.13.
Hill distribution 138.12.
Homedale distribution 69.12.
Horse Flat transmission 230.138.13.
Horseshoe Bend distribution 35.12.
Horseshoe Bend distribution 69.36.
Horseshoe Bend distribution 69.25.
Houston distribution 69.13.
Hulen distribution 46.13.
Hunt transmission 230.138.13.
Hydra distribution 138.34.
Island distribution 69.12.
Jerome distribution 138.12.
Julion Clawson distribution 138.34.
Joplin distribution 138.13.
Karcher distribution 138.13.
Kenyon distribution 69.12.
Ketchum distribution 138.12.
Kinport transmission 161.46.13.
Kinport transmission 230.138.12.
Kinport transmission 230.138.13.
Kinport transmission 345.230.13.
Kramer distribution 138.34.
Kramer distribution 138.13.
Kuna distribution 138.13.
Lake Fork distribution 138.36.
Lake Fork transmission 138.69.12.
Lamb distribution 138.13.
Lansing distribution 69.13.
Lincoln distribution 138.13.
Linden distribution 138.13.
Locust distribution 138.34.
Locust transmission 230.138.13.
Lower Malad - attended transmission 138.
Lower Salmon - attended transmission 138.13.
Map Rock distribution 69.12.
McCall distribution 69.12.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2006/Q4
(2)DA Resubmission 04/18/2007
SUBSTATIONS (Continued)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT LineTransformersSpare
(In Service)(In MVa)In Service Transformers Type of Equipment Number of Units Total Capacity No.
(In MVa)
(f)(9)(h)(i)
(j)
(k)
100
300
180
180
600
360
FERC FORM NO.1 (ED. 12-96)Page 427.
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 2006/04(2) 0 A Resubmission 04/18/2007
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)
McCall distribution 138.35.
McCall distribution 138.69.12.
Meridian distribution 138.13.
Micron distribution 138.12.
Midpoint transmission 230.138.12.
Midpoint transmission 345.230.13.
Midpoint transmission 500.345.
Midrose distribution 138.13.
Milner distribution 69.38.13.
Milner distribution 69.38.
Milner distribution 138.34.
Milner PP - attended transmission 138.13.
Moonstone distribution 138.34.
Mora distribution 138.34.
Moreland distribution 46.12.
Moreland distribution 46.34.12.
Mountain Home distribution 69.12.
Mountain Home Air Force Base distribution 69.12.
Mountain Home Air Force Base distribution 138.12.
Nampa distribution 230.138.13.
Nampa distribution 138.12.
Nampa distribution 138.69.12.
New Meadows distribution 69.35.
New Plymouth distribution 69.12.
Notch Butte distribution 13.
Parma distribution 69.12.
Parma distribution 69.34.
Paul distribution 138.34.12.
Payette distribution 138.12.
Pingree distribution 138.46.12.
Pingree distribution 138.36.
Pleasant Valley distribution 138.34.
Pocatello distribution 46.12.
Portneuf distribution 138.36.
Portneuf distribution 46.35.
Rockford distribution 46.12.
Russett distribution 138.12.
Sailor Creek distribution 138.13.
Sailor Creek distribution 138.34.
Salmon distribution 69.12.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2006/Q4
(2)D A Resubmission 04/18/2007
SUBSTATIONS (Continued)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service)(In MVa)Transformers Spare Total Capacity No.In Service Transformers Type of Equipment Number of Units
(In MVa)
(I)
(g)
(h)(i)(k)
120
720
750
180
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 2006/04
(2)D A Resubmission 04/18/2007
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)
Salmon distribution 69.34.12.
Shoshone distribution 46.13.
Shoshone distribution 46.
Shoshone Falls - attended transmission 46.
Shoshone Falls - attended transmission 46.
Silver distribution 138.34.
Simplot distribution 138.12.
Sinker Creek distribution 138.34.
Siphon distribution 138.34.
South Park distribution 46.13.
Star distribution 138.13.
Starley Transmission 138.69.12.
State distribution 69.12.
Stoddard distribution 138.13.
Strike Power Plant - attended transmission 138.13.
Sugar distribution 138.34.
Swan Falls - attended transmission 138.
Taber distribution 46.12.
Ten Mile distribution 138.13.
Terry distribution 138.12.
Thousand Springs - attended transmission 46.
Thousand Springs - attended transmission 2.40
Toponis distribution 138.34.
Twin Falls distribution 138.13.
Twin Falls distribution 138.46.12.
Twin Falls PP - attended transmission 138.
Twin Falls PP - attended transmission 138.13.
Upper Malad - attended transmission 46.
Upper Salmon- attended transmission 138.
Ustick distribution 138.12.
Vallivue distribution 138.13.
Victory distribution 138.12.
Ware distribution 69.12.
Weiser distribution 69.12.
Weiser distribution 138.69.12.
Wilder distribution 69.13.
Willis distribution 138.13.
Wye distribution 138.13.
Zilog distribution 138.13.
FERC FORM NO.1 (ED. 12-96)Page 426.4
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 2006/Q4
(2)D A Resubmission 04/18/2007
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties. and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Total Capacity No.In Service Transformers Type of Equipment Number of Units
(In MVa)
(f)
(g)
(h)(i)
(j)
(k)
FERC FORM NO.1 (ED. 12-96)Page 427.
This ~ort Is:(1) l!.I An Original
(2) D A Resubmission
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).
Name of Respon~ent
Idaho Power Company
Date of Report
(Mo, Da, Yr)
04/18/2007
Line
No.Name and Location of Substation Character of Substation Primary
(c)(a)(b)
2 The above are all State of Idaho
4 Montana:
5 Peterson
7 Nevada:
8 Valmy - attended
9 Wells
11 Oregon:
12 Boardman - attended
13 Cairo
14 Hells Canyon - attended
15 Hines
16 Malheur Butte
17 Nyssa
18 Ontario
19 Ontario
20 Ontario
21 Ore-Ida
22 Oxbow - attended
23 Oxbow - attended
24 Oxbow - attended
25 Quartz
26 Quartz
27 Vale
29 Wyoming:
30 Jim Bridger - attended
37 Transformers-distribution substations under 10,000
38 KVA 89 unattended.
transmission 230.
transmission
transmission
345.
138.
transmission
distribution
500.
69.
230.
138.
69.
69.
138.
138.
230.
69.
69.
230.
230.
138.
230.
69.
transmission
transmission
distribution
distribution
distribution
distribution
distribution
distribution
transmission
transmission
transmission
transmission
transmission
distribution
transmission 345.
FERC FORM NO.1 (ED. 12-96)Page 426.
Year/Period of Report
End of 2006/Q4
VOLTAGE (In MVa)
Secondary
(d)
69.
21.
69.
24.
12.
13.
115.
34.
12.
12.
69.
138.
12.
38.
13.
138.
69.
138.
13.
22.
Tertiary
(e)
13.
12.
12.
12.
12.
12.
12.
13.
12.
13.
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 2006/Q4(2) n A Resubmission 04/18/2007
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service)(In MVa)
Transformers Spare Total Capacity No.In Service Transformers Type of Equipment Number of Units
(In MVa)
(f)
(g)
(h)(i)(k)
150
500
240
244
100
100
748
354
FERC FORM NO.1 (ED. 12-96\PaQe 427.
INDEX
Schedule Paae No.
Accrued and prepaid taxes ...........................................,......................,.....262-263
Accumulated Deferred Income Taxes ..........................,......................,.......,....,...,.234
272-277
Accumulated provisions for depreciation of
common utility plant .......................,.....,....................................."
........
356
utility plant .............................."
..............,................,....................
219
utility plant (summary) ..................,.....,.......,......"
......................,......
200-201
Advances
from associated companies .........................,..........,...............................256-257
Allowances ,....................................,....,......"
..............................,..,..
228-229
Amortization
miscellaneous ....................................................,...............................340
of nuclear fuel .........................................,....................................202-203
Appropriations of Retained Earnings ...................,..........................................118-119
Associated Companies
advances from ........................................,.......................................256-257
corporations controlled by respondent .............................,..............................103
control over respondent .......,............................................,.,.................,.102
interest on debt to .......................,.......................,..........................256-257
Attestation ..........................................,..,.....,........................................ i
Balance sheet
comparative "
...................,........
110-113
notes to "
...........,...,...............
122-123
Bonds ..,..................................,......................................................256-257
Capital Stock ........................................,........,......................................251
expense ......................,.......................,............,......,.......................254
premiums ...................................,...........,.........................................252
reacquired ......................................,............,.,.................................251
subscribed ............,................,..........,..........................,...............,...252
Cash flows , statement of ......................,............,..............,.....,................120-121
Changes
important during year ........................................................................108-109
Construction
work in progress - common utility plant ..........,...............................................356
work in progress - electric "
................
216
work in progress - other utility departments ......................................."........ 200-201
Control
corporations controlled by respondent ......................................,.....................103
over respondent ...............................,..........,.......................................102
Corporation
controlled by ....................................,.............,.................................103
incorporated ..............................................................,......................101
CPA, background information on ...,...........................,..................................,....101
CPA Certification, this report form ..........,..........................,"........... i-
FERC FORM NO.(ED. 12-93)Index
INDEX (continued)
Schedule
Deferred
Paqe No.
credits, other ............................,......................................................269
debits, miscellaneous ............................................................................233
income taxes accumulated - accelerated
property "
..................
272-273
accumulated - other property ..................................................,. 274-275
accumulated - other .............................................................276-277
accumulated - pollution control facilities ............................,............. 234
Definitions, this report form ".................. iii
Depreciation and amortization
of common utility plant ..............................................,...........................356
of electric plant ......................................,.........................................219
336-337
Directors ..............,.............................................................................105
Discount - premium on long-term debt .............................................................256-257
Distribution of salaries and wages ....................................................,..........354-355
Dividend appropriations ..........................................................................118-119
Earnings, Retained "
.........................
118-119
Electric energy account .....................................................,........................401
amortization
income taxes
income taxes
income taxes
Expenses
electric operation and maintenance "
.....
320-323
electric operation and maintenance, summary .............................,........................ 323
unamortized debt "
...........................
256
Extraordinary property losses "
..................
230
Filing requirements, this report form
General information .............................................,....................................101
Instructions for filing the FERC Form 1 "
,,"
....... i-
Generating plant statistics
hydroelectric (large) ............................,...........................................406-407
pumped storage (large) .........................................,.............................408-409
small plants ..,..............................................................................410-411
steam-electric (large) "
.................
402-403
Hydro-electric generating plant statistics ..............................................,........ 406-407
Identification ....,..................................................................................101
Important changes during year "
..............
108-109
Income
statement of. by departments .................................................................114-117
statement of, for the year (see also revenues) ............................................... 114-117
deductions, miscellaneous amortization ..................................................,........340
deductions, other income deduction ...............................................................340
deductions, other interest charges ....................,..........................................340
Incorporation information .................................................,..........................101
FERC FORM NO.(ED. 12-95)Index
INDEX (continued)
Schedule Paqe No.
Interest
charges. paid on long-term debt, advances, etc ............................................... 256-257
Investments
nonutility property "
........................
221
subsidiary companies "
...................
224-225
Investment tax credits, accumulated deferred ..................................................... 266-267
Law, excerpts applicable to this report form ".... iv
List of schedules, this report form "
............
Long-term debt "
.............................
256-257
Losses-Extraordinary property "
..................
230
Materials and supplies "
.........................
227
Miscellaneous general expenses .......................................................................335
Notes
to balance sheet "
.......................
122-123
to statement of changes in financial position "" 122-123
to statement of income "
.................
122-123
to statement of retained earnings ............................................................122-123
Nonutility property ............,.....................................................................221
Nuclear fuel materials ...........................................................................202-203
Nuclear generating plant, statistics .............................................................402-403
Officers and officers ' salaries "
................
104
Operating
expenses-electric "
......................
320-323
expenses-electric (summary) "
................
323
Other
paid-in capital "
.............................
253
donations received from stockholders .............................................................253
gains on resale or cancellation of reacquired
capital stock "
.............................,..................................................
253
miscellaneous paid-in capital "
..............
253
reduction in par or stated value of capital stock ................................................253
regulatory assets "
..........................
232
regulatory liabilities "
.....................
278
Peaks , monthly, and output "
.....................
401
Plant, Common utility
accumulated provision for depreciation "
.....
356
acquisition adjustments ..........................................................................356
allocated to utility departments ......,..........................................................356
completed construction not classified "
......
356
construction work in progress "
..............
356
expenses .........................................................................................356
held for future use "
........................
356
in service "
.................................
356
leased to others "
...........................
356
Plant data "
'.......................,......................................................
336-337
401-429
FERC FORM NO.1 (ED. 12-95)Index
INDEX (continued)
Schedule
Plant - electric
Paae No.
accumulated provision for depreciation ...,............................................"
.....
219
construction work in progress ....................................................,...............216
held for future use ..............,...............................................................214
in service ....................................................,..............................204-207
leased to others ..............................................,..................................213
plant - utility and accumulated provisions for depreciation
amortization and depletion (summary) ....................................................,........201
Pollution control facilities, accumulated deferred
income taxes ................................................,....................................234
Power Exchanges .............................................,....................................326-327
Premium and discount on long-term debt .....................................................,.........256
Premium on capital stock ..................................................,..........................251
Prepaid taxes "
..............................
262-263
Property - losses, extraordinary "
,.",,"...............
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
Reconciliation of reported net income with taxable income
from Federal income taxes .................................................,....................261
Regulatory commission expenses deferred ....................................................,.........233
Regulatory commission expenses for year ..........................................................350-351
Research, development and demonstration activities ............................................... 352-353
Retained Earnings
amortization reserve Federal .....................................................,...............119
appropriated ............................................,...................................,
statement of , for the year ..................................................,................
unappropriated ................................................,........................,.....
Revenues - electric operating ................................................,..................,
118-119
118-119
118-119
300-301
Salaries and wages
directors fees ..........,........................................................................105
distribution of ..................,...........................................................354-355
officers
' ..............................................,.........................................
104
Sales of electricity by rate schedules .....................................................,.........304
Sales - for resale ..................,............................................................310-311
Salvage - nuclear fuel .......................,...................................................202-203
Schedules, this report form .....................................................,....................
Securi ties
exchange registration ........................................,...............................250-251
Statement of Cash Flows ...................................................,......................120-121
Statement of income for the year .................................,...............................114-117
Statement of retained earnings for the year ...................................................... 118-119
Steam-electric generating plant statistics .......................................,............... 402-403
Substations ....................,.....................................................................426
Supplies - materials and .........................................,...................................227
FERC FORM NO.(ED. 12-90)Index
INDEX (continued)
Schedule Paae No.
Taxes
accrued and prepaid .........................................................................262-263
charged during year .........................................................................262-263
on income, deferred and accumulated .............................................................234
272-277
reconciliation of net income with taxable income for ............................................ 261
Transformers, line - electric .......................................................................429
Transmission
lines added during year .....................................................................424-425
lines statistics ............................................................................422-423
of electricity for others ...................................................................328-330
of electricity by others ........................................................................332
Unamortized
debt discount ...............................................................................256-257
debt expense ................................................................................256-257
premium on debt .............................................................................256-257
Unrecovered Plant and Regulatory Study Costs
......................................................
230
FERC FORM NO.(ED. 12-90)Index
Page
Number
12-
December 31,2006
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
Inl\ut"\ ...,11:11:11 con:,,""
Idaho Power Company
ST ATE OF IDAHO. ALLOCATED
An Original
Line
No.
STATEMENT OF INCOME FOR THE YEAR
1. Report amounts for accounts 412 and 413, Revenue and Expenses from Utility Plant Leased to Others, in another utility
column (i o) in a similar manner to a utility department. Spread the amount(s) over lines 01 thru 24 as appropriate.
Include these amounts in columns (c) and (d) totals.
2. Report amounts in account 414, Other Utility Operating Income, in the same manner as accounts 412 and 413 above.
3. Report data for lines 7 , and 10 for Natural Gas companies using accounts 404.404.404.407.1, and 407.
4. Use page 122 for important notes regarding the state ment of income or any account thereof.
5. Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a
material amount may need to be made to the utility's customers or which may result in a material refund to the utility
with respect to power or gas purchases. State for each year affected the gross revenues or costs to which the contingency
relates and the tax effects together with an explanation of retain such revenues or recover amounts paid with respect
to power and gas purchases.
6. Give concise explanations concerning significant amounts of any refunds made or received during the year.
Account
(Ref.
Page
No.
(b)
TOTAL
Current Year Previous Year(c) (d)(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 Property Losses, Unrecovered Plant and
Regulatory Study Costs (407).........................................................................
Amort. of Conversion Expenses (407)...............................................................
Regulatory Debits/Credits (407.3 & 407.4)........................................................
Taxes Other Than Income Taxes (408.1)..........................................................
Income Taxes - Federal (409.1 )........................................................................
- Other (409.1).....................................................................................
Provision for Deferred Income Taxes (410.1 & 411.1) Net...............................
Investment Tax Credit Adj. - Net (411.4)...........................................................
(Less) Gains from Disp. of Utility Plant (411.6).................................................
Losses from Disp. of Utility Plant (411.7)..........................................................
(Less) Gains from Disposition of Allowances (411.8)........................................
Losses from Disposition of Allowances (411.9).................................................
391 374
840 362
51,553 061
093,547
(8,706,428)
320 531
876,469 532 $
532,371 073
277 132
214 083
587 822
TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 22)..................752 942,558
Net Utility Operating Income (Enter Total of line 2 less 23)
(Carry forward to page 11 , line 27)................................................................123 526 975 $
In41-1n ~IIPPI I=MI=NT Paae 1
Dece~r31 , 2006
802,914,413
474 244 701
287 956
895 690
781 326
370 700
828 248
059 990
235 170
(35 537 390)
016,462
695 182 852
107 731 561
Idaho Power Company
STATE OF IDAHO - ALLOCATED
An Original December 31, 2006
TAXES ALLOCATED TO IDAHO
Kind of Tax
Taxes Other Than Income Taxes:
Labor Related:
FICA..................................................................
FUTA.................................................................
State Unemployment........................................
Payroll Deduction & Loading.............................
Total Labor Related................................
Property Taxes......................................................
Kilowatt-hour Tax.............................. ................. ...
Licenses................................................................
Regulatory Commission Fees...............................
Irrigation PIC.........................................................
Total Taxes Other Than Income Taxes...................
Federal Income Taxes............................................
State Income Taxes................................................
Deferred Income Taxes..........................................
Investment Tax Credit Adjustment - Net.................
Total Taxes Allocated to Idaho................................
Taxes Charged
Durinq Year
243 878
109 818
262,407
613 531 )
573
196 881
722 950
213
682 342
232,404
840 362
553 061
093 547
706,428)
320 531
101 073
.~ AI'~ ... ,......, ",...::UT P""nA
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 12-31-06)
Directors, officers, and employees - $979 158
Other Accounts Receivable - Account 143: (at 12-31-06)
Directors, officers, and employees - $ 3 336
Line Item Utility
Customers
Officers
and
Employees
(d)
No.(a)
(b)
763,415 $Bal. beginning of year
Provo for uncollectibles
for year...................................................
Accounts written off..................................
Coli. of accounts
written off...............................................
Adjustments (explain)...............................
823
833 238 $
- $
Balance end of year..................................
"",un COIIDDI CUC,,",Pac:re 3
Balance
Beginning of
Year
(b)
522 187 $
830 007 $
860 636 $
833 238
(833 238) $
Other
(e)
105 334
501
- $
134 835 $
December 31, 2006
Balance
End of
Year
(c)
717,530
218 159
081 728
968 073
(968 073)
Total
(f)
868 749
324
968 073
Idaho Power Company
ST ATE 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 separate headings and totals for accounts 145, Notes Receivable from Associated Companies, and 146
Accounts Receivable from Associated Companies, in addition to a total for the combined accounts.
3. For notes receivable list each note separately and state purpose for which received. Show also in column
(a) date of note, date of maturity and interest rate.
4. If any note was received in satisfaction of an open account, state the period covered by such open account.
5. Include in column (f) interest recorded as income during the year, including interest on accounts and notes
held at any time during the year.
6. Give particulars of any notes pledged or discounted, also of any collateral held as guarantee of payment
of any note or account.
Line Particulars
Balance
Beginning
of Year
(b)
Balance
End of Year
(e)
Totals for YearDebits Credits
(~
No.(a)
Account 145:
Account 146:
678 $126 648 $226 326 $Rocky Mountain Communication
IDACORP, Inc.......................... $537,406 $69,488 057 $950 651
077 299 $Total Account 146........................ $637 084 $714 383 $
In.!u../o !':IIPPI FMENT Paae 4
December 31 , 2006
Interest
For Year
(f)
Idaho Power Company
ST ATE 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 $50 000 may be grouped, with the
number of such transactions disclosed in column (a).
3. Give the date of Commission approval of journal entries in column (b), when approval is required. Where approval
is required but has not been received, give explanation following the item in column (a). (See account 102, Utility
Plant Purchased or Sold.
Line Description of Property
Original Cost
of Related
Property
(b)
Date Journal
Entry Approved
(When Required)
(c)(d)
Acct 421.
No.(a)
Gain on disposition of
property:
109 303Willis Sub disposal of original property
893)Dike Power Site reclassify to account 101 539
Misc Items 330
738)Total gain.......................................................... $179 171
Total loss................................................. .....,
,..... LJ" "'" "".,.. "'II""'IT Paae 5
December 31, 2006
Acct 421.
(e)
155
Idaho Power Company
STATE OF IDAHO. ALLOCATED
An Original December 31, 2006
STATE OF IDAHO - TOTAL SYSTEM DATA
PROFESSIONAL OR CONSULTATIVE SERVICES -ITEMS $10 000 AND OVER
Line PAYEE SERVICE TYPE Amount
No.(a)(b)(c)
ADECCO Mapping Services 659
AERO-GRAPHICS Mapping Services 206
ASCENTIUM CORPORATION PM Consultant 774
ASHLEY LAND SERVICES Environmental Services 779
ATER. WYNNE LLP Legal Services 289,313
BAKER, KEN Management Services 500
BARKER, ROSHOL T & SIMPSON LLP Legal Services 244 768
BERBER, GAYNOL LEE Legal Services 000
BIDART & ROSS INC Management Services 72,726
BLACKBURN & JONES LLP Legal Services 216 201
BLANK & ASSOCIATES P.Computer Support Services 111 085
BOISE COURTYARD BY MARRIOTT Consulting Services 12,400
BRENNEMAN, JOHN Lobby Services 728
BRIGHAM YOUNG UNIVERSITY Environmental Services 124
BROWN RUDNICK BERLACK ISRAELS Lobby Services 000
BROWNSTEIN HYATT & FARBER, PC Legal Services 899,408
BUSINESS LEGAL CONSULTING Legal Services 960
CAPITOLWEST PUBLIC POLICY Consulting Services 000
CAPROCK GROUP INC, THE Management Services 000
CASCADE ENERGY ENGINEERING INC Engineering Services 663
CH2M HILL Engineering Services 82,106
CHAVEZ WRITING & EDITING, INC Management Services 825
CHURCH, JOHN S Economic Services 72,000
COMMUNICATIONS ET AL Advertising Services 256
COMMVAUL T SYSTEMS, INC Environmental Services 000
CONNOR CLAIMS SPECIALISTS Management Services 009
CORNERSTONE SYSTEMS INC Computer Support Services 503 950
CRI ADVANTAGE Computer Support Services 240
CTA ARCHITECTS Architect Services 820
CUMMINS & BARNARD, INC.Environmental Services 141 820
DAVID EVANS AND ASSOCIATES Management Services 123 056
DAVIS WRIGHT TREMAINE LLP Legal Services 687 246
DEAN & CARTER PLLC Legal Services 023
DELOITTE & TOUCHE LLP Accounting Services 203 589
DESERT RESEARCH INSTITUTE EnVIronmental Services 557
DHIINC Environmental Services 102
EAGLE CAP CONSULTING INC Environmental Services 112,043
ECOANAL YSTS INC EnVIronmental Services 120 069
EIDAM AND ASSOCIATES Engineering Services 219
EMPLOYEASE INC.Consulting Services 56,658
ENERNEX CORPORATION Consulting Services 127 042
ENGLAND CONSULTING Consulting Services 37,950
ERNST & YOUNG LLP Accounting Services 121,554
EVANS KEANE Management Services 882
EVANS RANGE RECLAMATION Management Services 16,413
.~ - ""...
roo .~~, "."::~I'T
Page 6
Idaho Power Company
STATE OF IDAHO - ALLOCATED
An Original December 31, 2006
STATE OF IDAHO - TOTAL SYSTEM DATA
PROFESSIONAL OR CONSULTATIVE SERVICES -ITEMS $10 000 AND OVER
Line PAYEE SERVICE TYPE Amount
No.(a)(b)(c)
GJORDING & FOUSER, PLLC Management Services 189
GORDON LAW OFFICES TRUST ACCOU Legal Services 235
HALL FARLEY OBERRECHT & B Legal Services 124
HARDESTY, REBECCA Environmental Services 905
HDR ENGINEERING, INC Engineering Services 274
HISTORY ASSOCIATES, INC.Consulting Services 205 115
HOPKINS RODEN CROCKETT HANSEN Lobby Services 894
HR MANAGEMENT SOLUTIONS LLC Management Services 688
HYQUAL Management Services 805
IBM Computer Support Services 551
IDAHO STATE UNIVERSITY Environmental Services 339
INTERMOUNTAIN TECHNOLOGY GROUP Computer Support Services 462 002
JUB ENGINEERS Engineering Services 988
LE BOEUF LAMB GREENE Legal Services 099 367
LOWDER, LONNIE Legal Services 000
MALANDRO COMMUNICATION INC Consulting Services 769 231
MAPFRAME CORPORATION Computer Support Services 845
MARSH ADVANTAGE AMERICA Management Services 039
MERRILL & MERRILL CHARTERED Legal Services 618
MILLER BATEMAN LLP Legal Services 166 668
MODERN MANAGEMENT INC Management Services 568
MUSSETTER ENGINEERING INC Engineering Services 843
MWH AMERICAS, INC.Management Services 329
NIELSEN GROUP INC, THE Consulting Services 148 176
NOVELL, INC.Environmental Services 91,425
ORACLE CORPORATION Computer Support Services 295
PAINE, HAMBLEN, COFFIN , BROOK Management Services 69,425
PARR WADDOUPS BROWN GEE AND LO Environmental Services 42,479
PERKINS COIELLP Legal Services 824
PERSONNEL PLUS Management Services 448
PLANNEDSCAPE Consulting Services 564
POWER ENGINEERS INC Engineering Services 205 235.47
QUAKER LANE ASSOCIATES Management Services 37,779.
RESOLVE, INC Management Services 22,963.
RIDDELL WILLIAMS P.Legal Services 113 639.
RIVERSIDE TECHNOLOGY INC Management Services 294 883.
RLW ANAL YTICS, INC Environmental Services 017.
ROBERT J RIETH Legal Services 816.
ROSEMARY BRENNAN CURTIN, INC Management Services 94,202.40
SAINT ALPHONSUS REGIONAL MEDIC Medical Consulting 28,420.
SALLADAY & DAVIS Legal Services 758.
SCIENCE APPLICATIONS INTE Environmental Services 12,832.
SMITH, CURTIS D Cloud Seeding Services 325.
SOFTWARE AG INC Computer Support Services 137 080.
Page 6A
IDAHO SUPPLEMENT
Idaho Power Company
STATE OF IDAHO - ALLOCATED
An Original December 31, 2006
STATE OF IDAHO - TOTAL SYSTEM DATA
PROFESSIONAL OR CONSULTATIVE SERVICES -ITEMS $10 000 AND OVER
Line PAYEE SERVICE TYPE Amount
No.(a)(b)(c)
SPATIAL NETWORK SOLUTIONS Management Services 37,489
SPL WORLDGROUP INC Computer Support Services 343,488
STAHMAN, ROBERTW Legal Services 913
STANLEY ASSOCIATES, INC Management Services 030
STATE OF IDAHO FISH & GAME Environmental Services 809
STEPTOE & JOHNSON LLP Legal Services 422 592
STOEL RIVES LLP Legal Services 312
SULLIVAN & CROMWELL Management Services 194 852
SUMMIT BLUE CONSULTING LLC Consulting Services 218
SWANSON ENTERPRISES LLC Consulting Services 12,265
100 SWCA, INC Environmental Services 997
101 SYSTEM PROTECTION SERVICES, PL Engineering Services 357
102 TOWERS PERRIN HR SERVICES Management Services 190 892
103 TREASURE VALLEY LEGAL SERVICES Legal Services 728
104 UNIVERSITY OF IDAHO EnVIronmental Services 134 205
105 VAN NESS FELDMAN Legal Services 614,862
106 VAN WINKLE ENVIRONMENTAL CONSU Environmental Services 348
107 YTURRI, ROSE, BURNHAM, BENTZ Legal Services 954
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
,... A'"" ro, ,.,." ",u",.rT
Idaho Power Company
STATE OF IDAHO - ALLOCATED
An Original December 31, 2006
PROFESSIONAL OR CONSULTATIVE SERVICES
ITEMS 000 OR MORE BUT LESS THAN 000
Line PREDOMINANT
No.PAYEE NATURE OF SERVICE AMOUNT
AMEC EARTH & ENVIRONMENTAL, IN Environmental Services 9,488
ASPEN GROVE ECOLOGICAL SERVICE Environmental Services 706
BLUE WORLD INFORMATION TECHNOL Management Services 264
BRICKLEY, SEARS & SOREIT, Legal Services 500
CAPITAL BRIDGE Management Services 608
DC ENGINEERING, PC Engineering Services 650
DEVINE, TARBELL & ASSOC INC Environmental Services 784
ECOS CONSULTING Consulting Services 200
ENGINEERING INCORPORATED Engineering Services 060
ENGLAND CONSTRUCTION Engineering Services 100
GARRAD HASSAN AMERICA INC Environmental Services 755
MATERIALS TESTING & INSPE Management Services 812
PACIFIC INTERNATIONAL ENGINEER Engineering Services 229
PLATEAU SYSTEMS LTD Management Services 250
RAIN SHADOW RESEARCH, INC Environmental Services 189
RAPIDIGM INC Computer Consulting Services 546
SCOTTSDALE RESORT & CONFERENCE Management Services 7,490
SOUTH LANDSCAPE ARCHITECTS Engineering Services 564
THORNTON CONSULTING Management Services 151
TROUTMAN SANDERS LLP Legal Services 000
ZGA ARCHITECTS & PLANNERS Architectural Services 630
InAun cO! IDDI I=IU:NT
Page 6C
This Page Intentionally Left Blank
Id8ho Power Company
STATE OF IDAHO. ALLOCATED
An Orlgl",,'December 31, 2006
ELECTRIC PLANT IN SERVICE (Accounts 1
1. Report below the original cost of electric plant in service according to the prescribed accounts,
2, In addition to Account 101 , Electric Plant in Service (Classified). this page and the next include Account 102, Electric Plant
Purchased or Sold; Account 103, Experimental Electric PI8nt Unclassified; and Account 106, Completed Construction
Not Classilied . Electric.
3. Include in column (c) or (d), as appropriate. corrections 01 additions and retirements lor the current or preceding year,
4. Enclose In parentheses credit adjustments of plant accounts to indicate the negative effect 01 such accounts.
5. Classify Account 106 according to prescribed accounts, on en 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 signnicant amount of plant retirements the end of the year, Include in
column (d) a tentative distribution of such retirements, on an estimated basis, w"h appropriate contra entry to the account
lor accumulated depreciation provision. Include also in column (d) reversals of tentative distributions of prior year 01 un-
classified retirements, Attach supplemental statement showing the account distributions 01 these tentative classnications in
columns (c) and (d), including the reversals 01 the prior years tentative account distributions of these amounts. Careful ob-
servance of the above instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount
of respondent's plant actually in service at end of year.
.-...- -..--, _..-.~
Line
No.
Account
(a)
1. iNTANGIBLE PLANT
(301) Organization......
...................... ...................... """..""'. ..... ..... .....,. .......
(302) Franchises and Consents,................,.......................".,.,.,.......,
...............,.".,.
(303) Miscellaneous Intangible Plant...........................,.........
...........,.,....,... "...".'"
TOTAL Intangible Plant (Enter Total 01 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 lor Steam Production..
..........,...... .......,.......,""'"
TOTAL Steam Production Plant (Enter Total of lines 8thru 15)....,..........,.........
...
B. Nuclear Production Plant
(320) land and Land Rights...,.,....
...............,..,........, ,......,.... .,.,..,...,. ,.............
(321) Structures and Improvements.,
......,.......".......,.............,.....,.......,..,.....""......"
(322) Reactor Plant Equipment...........,...,
..,...............,..............,..... .....................
(323) Turbogenerator Un"s..............,..........,
.................,......, ,.......,..,.,.,.................."
(324) Accessory Electric Equipment.....,
...."....,....",...........".,....."....',.,....,.....",..,..,'
(325) Misc. Power Plant Equipment..................................... ..
......,...,..... .....,..
(326) Asset Retirement Costs for Nuclear Production.............
.........,.................
TOTAL Nuclear Production Plant (Enter Total 01 lines 17thru 24).,. ,
................
C. Hydraulio Production Plant
(330) land and land Rights..,
.................................,...,.....,.... ........,... ..... ,..........
(331) Structures and Improvements........
............... ,........"'.".".""'." .....,.......
(332) Reservoirs, Dams, and Waterways................., ...... ,
......,.... .....' ,......
(333) WaterWheels, 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,
........, ,...' ....,.............. ,.... ,..... ....................".
P8ge 7
Balance at
Beginning 01 year
(b)
Additions
(c)
945
894,190
383 713
340 848
430 383
779 416 892
596 589 744
Idaho Power Company
STATE OF IDAHO. ALLOCATED
An Original
k 102, 103 and 106)
Show in column (I) reclassifications or transfers within utility plant accounts. Include also in column
(I) the additions or reductions of primary account classijications arising from distribution of amounts
initially recorded in Account 102. In showing the clearance of Account 102, Include in column (e) the
amounts with respect to accumulated provision for depreciation, acquisition adjustments, etc., and show
in column (I) only the offset to the debits or credits distributed in column (I) to primary account classifications,
For Account 399, state the nature and use of plant included in this account and if substantial in amount
submit a supplementary statement showing subaccount classification of such plant conforming to the
requirements of these pages.
For each amount comprising the reported balance and changes in Account 102, state the property purchased
or sold, name of vendor or purchaser, and date of transaction, If proposed journal entries have been filed
with the Commission as required by the Uniform System of Accounts, give also date of such filing.
Balance at Line
Retirements Adjustments Transfers End of Year
(d)(e)(I)
(g)
No.
529 (301)
553 832 (302)
571 649 (303)
183 011
(310)
(311)
(312)
(313)
(314)
(315)
(316)
982 426 (317)
793 884 294
(320)
(321)
(322)
(323)
(324)
(325)
(326)
(330)
(331)
(332)
(333)
(334)
(335)
(336)
(337)
613 086 985
(340)
(341)
(342)
(343)
(344)
(345)
(345)
PageS
,~...- _..~~, ~..~.~
December 31, 2006
Idaho Power ComptOny
STATE OF IDAHO - ALLOCATED
An Original December 31, 2006
ELECTRIC PLANT IN SERVICE (Accounts 101 102 103 and 106) (Continued)
LIne Balance at
Account Beginning 01 year Additions
No.(a)(b)(c)
(346) Misc, Power Plant Equipment
...,'.,........."'".....................................,...........'.....
TOTAL Other Production Plant (Enter Total of lines 37 thru 44)..,...............,....,.......694 684
TOTAL Production Plant (Enter Total 01 lines 16 , and 45)............................475 701 320
3, TRANSMISSION PLANT
(350) Land and land Rights............................................,..........,...................
..............
047,463
(352) Structures and Improllements........,
.....................................................,........,...
117 792
(353) Station Equipment..........,..........,.......,..,..."........."
........'..,........,...................,
199 533 892
(354) Towers and Fixtures.............,...................,...
""""""...,.,....,..'..."'"............,.......
67,625 521
(355) Poles and Fixtures....,..
,..........,.......,......."................................................
76,407 981
(356) Overhead Conductors and Devices..
...... .....""""""""'...,."""'".............. ....
515357
(357) Underground Condu~....,......
'........."'"....,.......................,,..........'...... ....
(358) Underground Conductors and Devices.....................
..............,....,,........
(359) Roads and Trails...................
,......,.",....................,.....,........'..........................
259,238
(359.1) Asset Retirement Costs for Transmission Plant..
'.. ....,..........'.................
TOTAL Transmission Plant (Enter Total of lines 48 thru 57),..............
,..'..'......
489 507 245
DISTRIBUTION PLANT
(360) Land and Land Rights......................................
.............,...,..... ......,...................
719 974
(361) Structures and Improllements......".....,.....
..................................................
660 144
(362) Station Equipment....................................."...
,......,......,........,.,..................,....
129,980 459
(363) Storage Battery Equipment......................,
...........................................,.......
(364) Poles, Towers, and Fixtures....................
............................,,....,..,....'..............,
174 103 722
(365) OVerhead Conductors and Devices..............................
"""....,....'"..........,..
295 291
(366) Underground Conduit...................................
...................................................
992 386
(367) Underground Conductors and Devices................,
.................,...,""'"...............
151 082,701
(368) Line Translormers..
..."..,.......'........'............................".......,."..............
266 919 861
(369) Services..,..............,....,....,
'...............,....,..........,.............................
946 816
(370) Meters....,..
....,..'........'.........................................................,..........
48,247 223
(371) Installations on Customer Premises,..
...... ,.........,.....""'",............,....
291 375
(372) Leased Property on Customer Premises..................,......,...
......,..........
(373) Street Lighting and Signal Systems..,....,..
..... ..,'....'........"'"...........
798 654
(374) Asset Retirement Costs for Distribution Piant.....
,,""""'..,.............
TOTAL Distribution Plant (Enter Total of lines 60 thru 74).........,
.....................
978 038 606
5, GENERAL PLANT
(389) Land and Land Rights................
".....",".........""""""".........,..,.."..............,....,
937 421
(390) Structures and Improvements....................,
.....,..............................,..............
620 933
(391) Office Furniture and Equipment.......,......,
.................................."...,.','.........
779 692
(392) Transportation Equipment............,
".....,..,........,..............,...".....................
849 209
(393) Stores Equipment...,.........,.............
...........................''.......""""".....,..........
898 339
(394) Tools, Shop, and Garage Equipment...,..,..,....
..................................,..,..,.....'...
842 719
(395) Laboratory Equipment.....,........
'....".................,..............,..........,..."................,..
543 043
(396) Power Operated Equipment..........,
.........."...,.......,.....".,...........................
700 450
(397) Communication Equipment............
.............,.....................,................
069,684
(398)Miscellaneous Equipment..............
..... ......... ..,".....,...,..,......,.......''.........,
419 657
SUBTOTAL (Enter Total 01 lines 77 thru 86)....,........
........,......'.........,..........,
200 661 147
(399) Other Tangible Property..
....................,...................,.............................,..
(399.1) Asset Retirement Costs lor General Plant.....
..........,...,.........,.... ....
TOTAL General Plant (Enter Total of lines 87, 88 and 89).....
........................,.....
200 661,147
TOTAL (Accounts 101 and 106)...............,
.....".................."""'"
208 249 165
(102) Electric Plant Purchased....
...............,.....................'............................,..
(Less) (102) Electric Plant Sold,........
....'.............,."..,."...,.,.......,...,"'"......................
(103) E"Perimental Plant Unclassified..................
.....,......................,'...............
TOTAL Electric Plant in Service........
'......................"....,'......"..".......,........,......
208 249 165
Page 9
.- ...- -..--. _u_.-
IdBho Power Compllny
STATE OF IDAHO - ALLOCATED
An Original
ELECTRIC PLANT IN SERVICE (Accounts 101, 102, 103 and 106) (Continued)
Balance at Une
Retirements Adjustments Transfers End of Year
(d)(e)(I)(9)No.
(346)
101 232 115
508 203 394
675 658 (350)
520 034 (352)
210 231 053 (353)
489 667 (354)
309 387 (355)
102 055 096 (356)
(357)
(358)
261,954 (359)
(359.
517 542 847
341 499 (360)
267 383 (361)
134544 631 (362)
(363)
178 077 556 (364)
808 497 (365)
012,125 (366)
159 571 691 (367)
289 800 410 (368)
616 312 (369)
592,870 (370)
358293 (371)
(372)
860 189 (373)
(374)
025 851 456
108,134 (389)
594 282 (390)
567 743 (391)
47,247 737 (392)
909 180 (393)
907 749 (394)
033 982 (395)
762 653 (396)
096 312 (397)
688 355 (398)
198,916 128
(399)
(399.
198 916 128
317,696 836
(102)
(102)
(371)
317 696 836
Page 10
,". u~ ~"DD' """.IT
December 31,2006
Idaho Power Company
ST ATE OF IDAHO. ALLOCATED
An Original December 31,2006
ELECTRIC OPERATING REVENUES (Account 400)
1. Report below operating revenues for each prescribed account, and manufactured gas revenues in total.
2. Report number of customers, columns (f) and (g), on the basis of meters, in addition to the number of flat rate
accounts; except that where separate meter readings are added for billing purposes, one customer should be counted
for each group of meters added. The average number of customers means the average of twelve figures at the close
of each month.
3. If previous year (columns (c), (e) and (g). are not derived from previously reported figures, explain any
inconsistencies in a footnote.
OPERATING REVENUES
Amount for Amount for
No.Current Year Previous Year
(a)(b)(c)
Sales of Electricity
(440) Residential Sales.................................................................289 068 594 289 325 450
(442) Commercial and Industrial Sales
Small (or Commercial)(See Instr. 4) (1)......................................221 723 109 237 308 467
Large (or Industrial)(See Instr. 4) (2)...........................................623 913 107 515 732
(444) Public Street and Highway Lighting......................................290 770 312,403
(445) Other Sales to Public Authorities.........................................
(446) Sales to Railroads and Railways..........................................
(448) Interdepartmental Sales.......................................................
TOTAL Sales to Ultimate Consumers.......................................606 706 387 636,462,052
(447) Sales for Resale - Opportunity....Non-Firm Only.................242 715 342 130 947 067
TOTAL Sales of Electricity........................................................849,421 730 767 409 119
(449.1) Provision for Rate Refunds..............................................211 251)400 102
TOTAL Revenue Net of Provision for Refunds.........................848,210,479 767 809 221
Other Operating Revenues
(450) Forfeited Discounts..............................................................
(451) Miscellaneous Service Revenues.........................................368 289 5,415 794
(453) Sales of Water and Water Power.........................................
(454) Rent from Electric Property..................................................142 580 930 432
(455) Interdepartmental Rents......................................................
(456) Other Electric Revenues......................................................748 184 758 967
TOTAL Other Operating Revenues..........................................259 054 105 192
TOTAL Electric Operating Revenues........................................876 469 532 802 914,413
(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
IrJAHO SUPPLEMENT
Idaho Power Company
STATE OF IDAHO - ALLOCATED
An Original Dec~ber 31 2006
ELECTRIC OPERATING REVENUES (Account 400) (Continued)
4. Commercial and Industrial Sales, Account 442, may be classified according to the basis of classification
(Small or Commercial, and Large or Industrial) regularly used by the respondent if such basis of classification
is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of Accounts. Explain
5. See page 108, Important Changes During Year, for important new territory added and important rate increases or
decreases.
6. For lines 2, 4, 5, and 6, see page 304 for amounts relating to unbilled revenue by accounts.
7. Include unmetered sales. Provide details of such sales in a footnote.
KILOWATT HOURS SOLD AVERAGE NUMBER OF CUSTOMERS PER MONTH
Amount for Amount for Amount for Number for Line
Current Year Previous Year Current Year Previous Year No.
(d)(e)(f)
(g)
868 383 891 569 022 693 374 527 360,484
170 019 354 880 517 406 71,472 642
170 158 215 135 239 312 122 121
27,402 244 802 162 768 619
235 963 704 ..612,581 573 446 889 430 866
5,492 528 583 611 581 658 NfA NfA
728,492 287 224 163 231 446 889 430 866
. Includes $ -009 627 unbilled revenues.
.. Includes 084 846 KWH relating to unbilled revenues.
Lines 11 through 21 are on an "allocated" basis.
Page11a
IDAHO SUPPLEMENT
Idaho Power Company
STATE OF IDAHO - ALLOCATED
An Original December 31 2006
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnotes.
,-Ine Amount for Amoum lor
No.Account Current Year Previous Year
(a)(b)(c)
1. POWt:H
,.~~~~;::
A. ;::Heam t"ower \jenerauon
Operation
(500) Operation Supervision and Engineering...................................................................621 185 206 279
(501) Fuel.........................................................................................................................101,451 974 196 241
(502) Steam Expenses......................................................................................................706 052 492,450
(503) Steam from Other Sources...........................................................,..........................
(Less) (504) Steam Transferred-Cr...................................................................................
(505) Electric Expenses....................................................................................................362 769 516 621
(506) Miscellaneous Steam Power Expenses...................................................................,708,765 6,415 549
(507) Rents.......................................................................................................................235 366 307 012
(509) Allowances..............................................................................................................
TOTAL Operation (Enter Total of lines 4 thru 12)........................................................119 066 112 109 134 1:'3
Maintenance
(510) Maintenance Supervision and Engineering..............................................................390 796 011 225
(511) Maintenance of Structures...........................................................""""""""""""""387,046 398 053
(512) Maintenance of Boiler Plant.....................................................................................509 643 928 572
(513) Maintenance of Electric Plant..................................................................................183 656 283 963
(514) Maintenance of Miscellaneous Steam Plant.............................................................331 618 171 554
TOTAL Maintenance (Enter Total of Lines 15 thru 19)................................................""""25',802;758 23,f93 3!jf
TOTAL Power Production Expenses-Steam Power (Enter Total of lines 13 and 20)...144,666 670 132 927 521
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 Engineenng..............................................................
(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-Nuclear Power (Enter Total of lines 33 and 40).
C. Hydraulic Power Generation
Operation
(535) Operation Supervision and Engineering...................................................................280 591 301 903
(536) Water for Power......................................................................................................674 353 028 245
(537) Hydraulic Expenses.................................................................................................818 109 707 802
(538) Electric Expenses............................................................................,.......................312 063 193 152
(539) Miscellaneous Hydraulic Power Generation Expenses.............................................278 711 788 748
(540) Rents.......................................................................................................................387 654 339 221
TOTAL Operation (Enter Total of lines 44 thru 49).....................................................751,482
Page 12
In41-1n !::IIPPI ~M~NT
Idaho Power Company
STATE OF IDAHO. ALLOCATED
An Original December 31, 2006
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnotes.
No.Account
(a)51 C. Hydraulic Power Generation (Continued)52 Maintenance53 (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 Operation62 (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 Expenses76 (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 , and 79)........81 2. TRANSMISSION EXPENSES82 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 Maintenance93 (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..................................................................
305 152
075 143
274 538
281 369
164
167 535
117 540
371,585
163 362
010 532
596 812
738 876
698 144
539 804
346 029
432 874
209 525
251,009
320 471
393 040
169 741
480 807
917 736
623
586 972
860
274 825
603 680
853,198 592,185
Page 13
.- -..- -..--. -..-.-
Idaho Power Company
STATE OF IDAHO. ALLOCATED
An Original December 31 , 2006
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnotes.
1L..lne AmOUnt Tor AmOUnt Tor
No.Account Current Year Previous Year
(a)(b)(c)
104 3. DISTRIBUTION EXPENSES (Continued)
105 (581) Load Dispatching..................................................................................................... $
106 (582) Station Expenses.....................................................................................................
107 (583) Overhead Line Expenses............................................................"""""""""""""'"108 (584) Underground Line Expenses....................................................................................
109 (585) Street Lighting and Signal System Expenses...........................................................
110 (586) Meter Expenses.......................................................................................................111 (587) Customer Installations Expenses.............................................................................
112 (588) Miscellaneous 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......................................................................oO""""""""""
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).................................1'27 4. CUSTOMER ACCOUNTS EXPENSES
) ;~8 Operation
129 (901) Supervision..............................................................................................................
130 (902) Meter Reading Expenses.........................................................................................
131 (903) Customer Records and Collection Expenses............................................................
'32 (904) Uncollectible Accounts.............................................................................................
(905) Miscellaneous Customer Accounts Expenses..........................................................
TOTAL Customer Accounts Expenses (Enter Total of lines 129 thru 133)...................
5. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
Operation
(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.................................................
847 658 $
091,619
544,944
008,479
146 732
122 897
028 502
227 173
140 239
011 442
385 842
887 177
726 164
703 802
114 536
934 241
692 207
300 696
147,491
208 690
659 704
129 328
096 396
530,254
674,996
861 056
133 375
167
820
2,468 821
039 765
090 650
292 049
359 616
740 287
215 370
1 :'3:'15 544
3::1 tI"IU tltI::I
512 985
958 009
753 911
770 604
356
"""'
000
471 754
449,433
922 800
389 879
596
2150 4152
281,641
822 366
192
826 658
~30 1:I:'1
273 766
354 446
743 988
701 139
696 615
(27,386 005)
712,128
031 267
(22,062 446)
Page 14
In41-1n ~IIPPI I=MI=NT
Idaho Power Company
STATE OF IDAHO - ALLOCATED
An Original December 31 2006
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnotes.
Account
(a)
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) 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 Maintenance167 (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)..............
610 977 $
744 172
811 467
309 084
000
(316 513)
296 517
662,273
326 569
21,409 065
300
335 147
100 217
775,497
705
112 265
731 007
506
204 656
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 2006 December 31 , 2005
2 Total Regular Full-Time Employees....................................................""""""""""""""'"871 774
3 Total Part-Time and Temporary Employees.......................................................................
4 Total Employees.................................................."""""""""""""""""""""""""""""""909 803
Page 15
InAHO SUPPLEMENT