2002Annual Report.pdf

THIS FILING IS (CHECK ONE BOX FOR EACH ITEM)
Item 1:An Initial (Original)
Submission
OR Resubmission No. ____
Item 2:An Original Signed Form OR Conformed Copy
Form Approved
OMB No. 1902-0021
(Expires 3/31/2005)
FERC Form No. 1:
ANNUAL REPORT OF MAJOR ELECTRIC
UTILITIES, LICENSEES AND OTHERS
This report is mandatory under the Federal Power Act, Sections 3, 4(a), 304 and 309,
and 18 CFR 141.1. Failure to report may result in criminal fines, civil penalties and other
sanctions as provided by law. The Federal Energy Regulatory Commission does not
consider this report to be of a confidential nature.
X
FERC FORM No.1 (REV. 12-98)
Exact Legal Name of Respondent (Company)Year of Report
Dec. 31, 2002Idaho Power Company
INSTRUCTIONS FOR FILING THE
FERC FORM NO. 1
GENERAL INFORMATION
I.Purpose
This form is a regulatory support requirement (18 CFR 141.1). It is designed to collect financial and
operational information from major electric utilities, Licensees and others subject to the jurisdiction of the
Federal Energy Regulatory Commission. This report is also secondarily considered to be a nonconfidential public use
form supporting a statistical publication (Financial Statistics of Selected Electric Utilities), published by the
Energy Information Administration.
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 CFR 101), must
submit this form.
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 this form electronically through the Form 1 Submission Software and an original and six (6)
conformed paper copies, properly filed in and attested, to:
Office of the Secretary
Federal Energy Regulatory Commission
888 First Street, NE.
Room 1A
Washington, DC 20426
Retain one copy of this report for your files.
Include with the original and each conformed paper copy of this form the subscription statement required by 18
C.F.R. 385.2011(c)(5). Paragraph (c)(5) of 18 C.F.R. 385.2011 requires each respondent submitting data
electronically to file a subscription stating that the paper copies contain the same information as the electronic
filing, that the signer knows the contents of the paper copies and electronic filing, and that the contents as
stated in the copies and electronic filing are true to the best knowledge and belief of the signer.
(b) Submit, immediately upon publication, four (4) copies of the Latest annual report to stockholders and any
annual financial or statistical report regularly prepared and distributed to bondholders, security analysts, or
industry associations. (Do not include monthly and quarterly reports. Indicate by checking the appropriate box on
Page 4, List of Schedules, if the reports to stockholders will be submitted or if no annual report to stockholders
is prepared.) Mail these reports to:
Chief Accountant
Federal Energy Regulatory Commission
888 First Street, NE.
Washington, DC 20426
(c) For the CPA certification, submit with the original submission, or within 30 days after the filing date for
this form, a Letter or report (not applicable to respondents classified as Class C or Class D prior to January 1,
1984):
(i) Attesting to the conformity, in all material aspects, of the below listed (schedules and) pages with
the Commission's applicable Uniform Systems of Accounts (including applicable notes relating thereto and the Chief
Accountant's published accounting releases), and
(ii) Signed by independent certified public accountants or an independent Licensed public accountant
certified or Licensed by a regulatory authority of a State or other political subdivision of the U. S. (See 18 CFR
41.10-41.12 for specific qualifications.)
FERC FORM NO. 1 (REV. 12-99)Page i
GENERAL INFORMATION (continued)
III. What and Where to Submit (Continued)
(c) Continued
Reference
Schedules Pages
Comparative Balance Sheet 110-113
Statement of Income 114-117
Statement of Retained Earnings 118-119
Statement of Cash Flows 120-121
Notes to Financial Statements 122-123
When accompanying this form, insert the Letter or report immediately following the cover sheet. When submitting
after the filing date for this form, send the letter or report to the office of the Secretary at the address
indicated at III (a).
Use the following format for the Letter or report unless unusual circumstances or conditions, explained in
the Letter or report, demand that it be varied . Insert parenthetical phrases only when exceptions are reported.
In connection with our regular examination of the financial statements of ____________ for the year ended on
which we have reported separately under date of ____________. We have also reviewed schedules
_____________________________________ of FERC Form No. 1 for the year filed with the Federal Energy Regulatory
Commission, for conformity in all material respects with the requirements of the Federal Energy Regulatory
Commission as set forth in its applicable Uniform System of Accounts and published accounting releases. Our review
for this purpose included such tests of the accounting records and such other auditing procedures as we considered
necessary in the circumstances.
Based on our review, in our opinion the accompanying schedules identified in the preceding paragraph (except as
noted below) conform in all material respects with the accounting requirements of the Federal Energy Regulatory
Commission as set forth in its applicable Uniform System of Accounts and published accounting releases.
State in the letter or report, which, if any, of the pages above do not conform to the Commission's
requirements. Describe the discrepancies that exist.
(d) Federal, State and Local Governments and other authorized users may obtain additional blank copies to meet
their requirements free of charge from:
Public Reference and Files Maintenance Branch
Federal Energy Regulatory Commission
888 First Street, NE. Room 2A ES-1
Washington, DC 20426
[phone]
IV. When to Submit
Submit this report form on or before April 30th of the year following the year covered by this report.
V. Where to Send Comments on Public Reporting Burden
The public reporting burden for this collection of information is estimated to average 1,217 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. Send comments regarding this burden
estimate or any aspect of this collection of information, including suggestions for reducing this burden, to the
Federal Energy Regulatory Commission, 888 First Street N.E., Washington, DC 20426 (Attention: Mr. Michael Miller,
CI-1); 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 this collection of information does not display a valid control number. (44 U.S.C. 3512(a)).
FERC FORM NO. 1 (REV. 12-99)Page ii
GENERAL INSTRUCTIONS
I. Prepare this report in conformity with the Uniform System of Accounts (18 CFR 101) (U.S. of A.). Interpret
all accounting words and phrases in accordance with the U. S. of A.
II. Enter in whole numbers (dollars or MWH) only, except where otherwise noted. (Enter cents for averages and
figures per unit where cents are important. The truncating of cents is allowed except on the four basic financial
statements where rounding is required.) The amounts shown on all supporting pages must agree with the amounts
entered on the statements that they support. When applying thresholds to determine significance for reporting
purposes, use for balance sheet accounts the balances at the end of the current reporting year, and use for
statement of income accounts the current year's amounts.
III. Complete each question fully and accurately, even if it has been answered in a previous annual report. Enter
the word "None" where it truly and completely states the fact.
IV. For any page(s) that is not applicable to the respondent, omit the page(s) and enter "NA," "NONE," or "Not
Applicable" in column (d) on the List of Schedules, pages 2, 3, and 4.
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). The date of the resubmission
must be reported in the header for all form pages, whether or not they are changed from the previous filing.
VI. Generally, except for certain schedules, all numbers, whether they are expected to be debits or credits, must
be reported as positive. Numbers having a sign that is different from the expected sign must be reported by
enclosing the numbers in parentheses.
VII. For any resubmissions, submit the electronic filing using the Form 1 Submission Software and an original and
six (6) conformed paper copies of the entire form, as well as the appropriate number of copies of the subscription
statement indicated at instruction III (a). Resubmissions must be numbered sequentially on the cover page of the
paper copies of the form. In addition, the cover page of each paper copy must indicate that the filing is a
resubmission. Send the resubmissions to the address indicated at instruction III (a).
VIII. Do not make references to reports of previous years or to other reports in lieu of required entries, except
as specifically authorized.
IX. Wherever (schedule) pages refer to figures from a previous year, the figures reported must be based upon
those shown by the annual report of the previous year, or an appropriate explanation given as to why the different
figures were used.
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DEFINITIONS
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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.
FERC FORM NO. 1 (REV. 12-99)Page iii
EXCERPTS FROM THE LAW
Federal Power Act, 16 U.S.C. 791a-825r)
"Sec. 3. The words defined in this section shall have the following meanings for purposes of this Act, to wit:
...(3) "Corporation" means any corporation, joint-stock company, partnership, association, business trust,
organized group of persons, whether incorporated or not, or a receiver or receivers, trustee or trustees of any of
the foregoing. It shalt not include 'municipalities, as hereinafter defined;
(4) "Person" means an individual or a corporation;
(5) "Licensee" means any person, State, or municipality Licensed under the provisions of section 4 of this Act,
and any assignee or successor in interest thereof;
(7) "Municipality" means a city, county, irrigation district, drainage district, or other political subdivision
or agency of a State competent under the Laws thereof to carry an the business of developing, transmitting,
unitizing, or distributing power;..."
(11) "Project" means a complete unit of improvement or development, consisting of a power house, all water
conduits, all dams and appurtenant works and structures (including navigation structures) which are a part of said
unit, and all storage, diverting, or forebay reservoirs directly connected therewith, the primary line or Lines
transmitting power therefrom to the point of junction with the distribution system or with the interconnected
primary transmission system, all miscellaneous structures used and useful in connection with said unit or any part
thereof, and all water rights, rights-of-way, ditches, dams, reservoirs, Lands, or interest in Lands the use and
occupancy of which are necessary or appropriate in the maintenance and operation of such unit;
"Sec. 4. The Commission is hereby authorized and empowered:
(a) To make investigations and to collect and record data concerning 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 my prescribe the
manner and form in which such reports shalt be made, and require from such persons specific answers to all
questions upon which the Commission may need information. The Commission may require that such reports shall
include, among other things, full information as to assets and Liabilities, capitalization, net investment, and
reduction thereof, gross receipts, interest due and paid, depreciation, and other reserves, cost of project and
other facilities, cost of maintenance and operation of the project and other facilities, cost of renewals and
replacement of the project works and other facilities, depreciation, generation, transmission, distribution,
delivery, use, and sale of electric energy. The Commission may require any such person to make adequate provision
for currently determining such costs and other facts. Such reports shall be made under oath unless the Commission
otherwise specifies."
"Sec. 309. The Commission shall have power to perform any and all acts, and to prescribe, issue, make, and rescind
such orders, rules and regulations as it may find necessary or appropriate to carry out the provisions of this Act.
Among other things, such rules and regulations may define accounting, technical, and trade terms used in this Act;
and may prescribe the form or forms of all statements, declarations, applications, and reports to be filed with the
Commission, the information which they shall contain, and the time within which they shall be filed..."
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General Penalties
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"Sec. 315. (a) Any licensee or public utility which willfully fails, within the time prescribed by the Commission,
to comply with any order of the Commission, to file any report required under this Act or any rule or regulation of
the Commission thereunder, to submit any information of document required by the Commission in the course of an
investigation conducted under this Act ... shall forfeit to the United States an amount not exceeding $1,000 to be
fixed by the Commission after notice and opportunity for hearing..."
Page ivFERC FORM NO. 1 (ED. 12-91)
IDENTIFICATION
FERC FORM NO. 1:
ANNUAL REPORT OF MAJOR ELECTRIC UTILITIES, LICENSEES AND OTHER
1221 W Idaho Street, P.O. Box 70 Boise, ID 83707-0070
01 Exact Legal Name of Respondent
(1) An Original (2) A ResubmissionX
02 Year of Report
Dec. 31, 2002Idaho Power Company
03 Previous Name and Date of Change (if name changed during year)
04 Address of Principal Office at End of Year (Street, City, State, Zip Code)
05 Name of Contact Person 06 Title of Contact Person
07 Address of Contact Person (Street, City, State, Zip Code)
08 Telephone of Contact Person,Including
Area Code
09 This Report Is 10 Date of Report
(Mo, Da, Yr)
ATTESTATION
The undersigned officer certifies that he/she has examined the accompanying report: that to the best of his/her knowledge, information, and belief,
all statements of fact contained in the accompanying report are true and the accompanying report is a correct statement of the business and
affairs of the above named respondent in respect to each and every matter set forth therein during the period from and including January 1 to
and including December 31 of the year of the report.
01 Name
02 Title
03 Signature 04 Date Signed
(Mo, Da, Yr)
Title 18, U.S.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.
/ /
1221 W Idaho Street, P.O. Box 70 Boise, ID 83707-0070
Darrel Anderson VP, CFO & Treasurer
[phone] 04/30/2003
Darrel Anderson
VP, CFO & Treasurer
04/30/2003
FERC FORM No.1 (ED. 12-91)Page 1
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
LIST OF SCHEDULES (Electric Utility)
Idaho Power Company X
04/30/2003
2002
Line
No.
Title of Schedule Reference
Page No.
Remarks
(c)(b)(a)
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".
101General Information 1
102Control Over Respondent 2
103Corporations Controlled by Respondent 3
104Officers 4
105Directors 5
108-109Important Changes During the Year 6
110-113Comparative Balance Sheet 7
114-117Statement of Income for the Year 8
118-119Statement of Retained Earnings for the Year 9
120-121Statement of Cash Flows 10
122-123Notes to Financial Statements 11
122(a)(b)Statement of Accum Comp Income, Comp Income, and Hedging Activities 12
200-201Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep 13
None202-203Nuclear Fuel Materials 14
204-207Electric Plant in Service 15
None213Electric Plant Leased to Others 16
214Electric Plant Held for Future Use 17
216Construction Work in Progress-Electric 18
219Accumulated Provision for Depreciation of Electric Utility Plant 19
224-225Investment of Subsidiary Companies 20
227Materials and Supplies 21
None228-229Allowances 22
230Extraordinary Property Losses 23
230Unrecovered Plant and Regulatory Study Costs 24
232Other Regulatory Assets 25
233Miscellaneous Deferred Debits 26
234Accumulated Deferred Income Taxes 27
250-251Capital Stock 28
253Other Paid-in Capital 29
254Capital Stock Expense 30
256-257Long-Term Debit 31
261Reconciliation of Reported Net Income with Taxable Inc for Fed Inc Tax 32
262-263Taxes Accrued, Prepaid and Charged During the Year 33
266-267Accumulated Deferred Investment Tax Credits 34
269Other Deferred Credits 35
272-273Accumulated Deferred Income Taxes-Accelerated Amortization Property 36
FERC FORM NO. 1 (ED. 12-96)Page 2
LIST OF SCHEDULES (Electric Utility) (continued)
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31, Idaho Power Company X
04/30/2003
2002
Line
No.
Title of Schedule Reference
Page No.
Remarks
(c)(b)(a)
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".
274-275Accumulated Deferred Income Taxes-Other Property 37
276-277Accumulated Deferred Income Taxes-Other 38
278Other Regulatory Liabilities 39
300-301Electric Operating Revenues 40
304Sales of Electricity by Rate Schedules 41
310-311Sales for Resale 42
320-323Electric Operation and Maintenance Expenses 43
326-327Purchased Power 44
328-330Transmission of Electricity for Others 45
332Transmission of Electricity by Others 46
335Miscellaneous General Expenses-Electric 47
336-337Depreciation and Amortization of Electric Plant 48
350-351Regulatory Commission Expenses 49
352-353Research, Development and Demonstration Activities 50
354-355Distribution of Salaries and Wages 51
None356Common Utility Plant and Expenses 52
401Electric Energy Account 53
401Monthly Peaks and Output 54
402-403Steam Electric Generating Plant Statistics (Large Plants) 55
406-407Hydroelectric Generating Plant Statistics (Large Plants) 56
None408-409Pumped Storage Generating Plant Statistics (Large Plants) 57
410-411Generating Plant Statistics (Small Plants) 58
422-423Transmission Line Statistics 59
424-425Transmission Lines Added During Year 60
426-427Substations 61
450Footnote Data 62
Stockholders' Reports Check appropriate box:
Four copies will be submitted
No annual report to stockholders is prepared
X
FERC FORM NO. 1 (ED. 12-96)Page 3
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
GENERAL INFORMATION
Idaho Power Company X
04/30/2003 2002
Idaho, June 30, 1989
Darrel Anderson Vice President, CFO and Treasurer, Idaho Power Company
1221 W. Idaho Street, P.O. Box 70, Boise, Idaho 83707-0070
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.
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.
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.
4. State the classes or utility and other services furnished by respondent during the year in each State in which
the respondent operated.
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) Yes...Enter the date when such independent accountant was initially engaged:
(2) NoX
Not Applicable
Class of Utility Service State
Electric Idaho
" Oregon
FERC FORM No.1 (ED. 12-87)PAGE 101
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
CONTROL OVER RESPONDENT
Idaho Power Company X
04/30/2003 2002
1. If any corporation, business trust, or similar organization or a combination of such organizations jointly held
control over the repondent at the end of the year, state name of controlling corporation or organization, manner in
which control was held, and extent of control. If control was in a holding company organization, show the chain
of ownership or control to the main parent company or organization. If control was held by a trustee(s), state
name of trustee(s), name of beneficiary or beneficiearies for whom trust was maintained, and purpose of the trust.
Idaho Power Company is a subsidiary of IdaCorp.
IdaCorp owns 100% of Idaho Power Company's Common Stock.
IdaCorp is a public utility Holding Company incorporated effective 10-1-1998
Page 102FERC FORM NO. 1 (ED. 12-96)
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
CORPORATIONS CONTROLLED BY RESPONDENT
Idaho Power Company X
04/30/2003
2002
Line
No.
Name of Company Controlled Kind of Business Percent Voting
Stock Owned
(c)(b)(a)
Footnote
Ref.
(d)
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.
1 Direct Control
Coal mining and mineral 100% 2 Idaho Energy Resources Company
development 3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
FERC FORM NO. 1 (ED. 12-96)Page 103
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
OFFICERS
Idaho Power Company X
04/30/2003
2002
Line
No.
Title Name of Officer Salaryfor Year(c)(b)(a)
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.
1
President and Chief Executive Officer 580,000Jan B. Packwood 2
3
Executive Vice President, Marketing & Sales 46,154Richard Riazzi (1) 4
5
President and Chief Operation Officer 350,000J. LaMont Keen 6
7
Vice President, General Counsel and Secretary 200,000Robert W. Stahman 8
9
Sr Vice President, Delivery 250,000James C. Miller 10
11
Vice President, Chief Finance Officer and Treasurer 185,000Darrel T Anderson 12
13
Vice President, Corporate Services 152,000Clifford N. Olson (2) 14
15
Vice President , Power Supply 174,000John P Prescott 16
17
Vice President, Human Resources 159,000Marlene K Williams 18
19
Vice President and Chief Information Officer 183,000Bryan A Kearny 20
21
Vice President, Regulatory Affairs 140,000Ric Gale 22
23
Vice President, Public Affairs 138,000Greg Panter 24
25
26
27
28
(1) Moved to subsidiary Company 2-1-2002 29
30
(2) Retired December 2002 31
32
33
34
35
36
37
38
39
40
41
42
43
44
FERC FORM NO. 1 (ED. 12-96)Page 104
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
DIRECTORS
Idaho Power Company X
04/30/2003
2002
Line Name (and Title) of Director Principal Business Address(b)(a)No.
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.
P.O. Box 2080, Cody Wyoming 82414 Rotchford L. Barker 1
2
3
Breezley Investments, 3625 U.S. Bancorp Tower, Roger L. Breezley (1) 4
Portland, Oregon 97208 5
6
2375 N. Towerview Lane, Boise, Idaho 83702 John B. Carley *** 7
8
9
10
Lemley & Associates, Inc. Jack K. Lemley *** 11
1508 N. 13th, Boise, Idaho 83702 12
13
Global, Inc., 900 W. Jefferson Street, Boise, Idaho 83702 Evelyn Loveless 14
15
P.O. Box 1718 Boise Idaho 83701 Gary Michael 16
17
P.O. Box 1557, Boise, Idaho 83701 Jon H. Miller, Chairman of the Board*** 18
19
O'Neill Enterprises, Inc. Peter S. O'Neill 20
871 E. Parkcenter Blvd., Boise, Idaho 83706 21
22
Idaho Power Company, 1221 W. Idaho Street,Jan B. Packwood President and CEO ** 23
P.O. Box 70, Boise, Idaho 83707-0070 24
25
4433 W. Quail Point Court, Boise, Idaho, 83703Robert A. Tinstman *** 26
27
1400 North Lake Shore Drive,#8B, Chicago, IL 60610Christopher L. Culp 28
29
30
31
32
(1) Retired August 2002. 33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
FERC FORM NO. 1 (ED. 12-95)Page 105
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report Year of Report
Dec. 31,
IMPORTANT CHANGES DURING THE YEAR
Idaho Power Company X 04/30/2003 2002
PAGE 108 INTENTIONALLY LEFT BLANK
SEE PAGE 109 FOR REQUIRED INFORMATION.
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.
FERC FORM NO. 1 (ED. 12-96)Page 108
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/30/2003
Year of Report
Dec 31, 2002
IMPORTANT CHANGES DURING THE YEAR (Continued)
1. None
2. None
3. None
4. None
5. None
6.$100 million of 4.75% First Mortgage Bonds maturing 11/15/12, issued 11/15/02 under OPUC
UF 4181,Order No 01-817 Wyoming Docket #20005-ES-01-23,Record No.6838 and IPUC Case
#ICP-E-01-27, Order No. 28848.
$100 million of 6.00% First Mortgage Bonds maturing 11/15/12, issued 11/15/02 under OPUC
UF 4181,Order No 01-817 Wyoming Docket #20005-ES-01-23,Record No.6838 and IPUC Case
#ICP-E-01-27, Order No. 28848.
7. None
8. On December 29, 2002 a 3% General Wage Increase
9. See pages 123.9 through 123.14
10. None
11. None
12. None
FERC FORM NO. 1 (ED. 12-96)Page 109
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
X
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line
No.
Title of Account
(a)
Ref.
Page No.
(b)
Balance at
Beginning of Year
(c)
Balance at
End of Year
(d)
Idaho Power Company 04/30/2003 2002
UTILITY PLANT 1
3,089,299,7222,991,861,487200-201Utility Plant (101-106, 114) 2
92,481,65486,009,543200-201Construction Work in Progress (107) 3
3,181,781,3763,077,871,030TOTAL Utility Plant (Enter Total of lines 2 and 3) 4
1,294,961,0781,220,002,130200-201(Less) Accum. Prov. for Depr. Amort. Depl. (108, 111, 115) 5
1,886,820,2981,857,868,900Net Utility Plant (Enter Total of line 4 less 5) 6
00202-203Nuclear Fuel (120.1-120.4, 120.6) 7
00202-203(Less) Accum. Prov. for Amort. of Nucl. Fuel Assemblies (120.5) 8
00Net Nuclear Fuel (Enter Total of line 7 less 8) 9
1,886,820,2981,857,868,900Net Utility Plant (Enter Total of lines 6 and 9) 10
00122Utility Plant Adjustments (116) 11
00Gas Stored Underground - Noncurrent (117) 12
OTHER PROPERTY AND INVESTMENTS 13
1,050,3891,388,096221Nonutility Property (121) 14
00(Less) Accum. Prov. for Depr. and Amort. (122) 15
00Investments in Associated Companies (123) 16
15,107,63312,574,662224-225Investment in Subsidiary Companies (123.1) 17
(For Cost of Account 123.1, See Footnote Page 224, line 42) 18
00228-229Noncurrent Portion of Allowances 19
26,88167,616Other Investments (124) 20
20,968,704255,212Special Funds (125-128) 21
37,153,60714,285,586TOTAL Other Property and Investments (Total of lines 14-17,19-21) 22
CURRENT AND ACCRUED ASSETS 23
4,974,7395,543,687Cash (131) 24
00Special Deposits (132-134) 25
82,84936,935Working Fund (135) 26
7,599,40937,416,187Temporary Cash Investments (136) 27
12,637,6559,761,917Notes Receivable (141) 28
56,947,24558,702,410Customer Accounts Receivable (142) 29
2,694,1122,259,483Other Accounts Receivable (143) 30
1,566,3461,500,000(Less) Accum. Prov. for Uncollectible Acct.-Credit (144) 31
21,827,72233,686,906Notes Receivable from Associated Companies (145) 32
6,077,1343,830,298Accounts Receivable from Assoc. Companies (146) 33
6,942,9208,726,387227Fuel Stock (151) 34
00227Fuel Stock Expenses Undistributed (152) 35
00227Residuals (Elec) and Extracted Products (153) 36
18,938,66720,705,724227Plant Materials and Operating Supplies (154) 37
00227Merchandise (155) 38
00227Other Materials and Supplies (156) 39
00202-203/227Nuclear Materials Held for Sale (157) 40
00228-229Allowances (158.1 and 158.2) 41
00(Less) Noncurrent Portion of Allowances 42
2,519,7802,573,824227Stores Expense Undistributed (163) 43
00Gas Stored Underground - Current (164.1) 44
00Liquefied Natural Gas Stored and Held for Processing (164.2-164.3) 45
32,818,56531,897,278Prepayments (165) 46
00Advances for Gas (166-167) 47
7,51421,101Interest and Dividends Receivable (171) 48
00Rents Receivable (172) 49
35,713,88537,400,421Accrued Utility Revenues (173) 50
00Miscellaneous Current and Accrued Assets (174) 51
00Derivative Instrument Assets (175) 52
FERC FORM NO. 1 (ED. 12-94)Page 110
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
X
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line
No.
Title of Account
(a)
Ref.
Page No.
(b)
Balance at
Beginning of Year
(c)
Balance at
End of Year
(d)
Idaho Power Company 04/30/2003 2002
(Continued)
00Derivative Instrument Assets - Hedges (176) 53
208,215,850251,062,558TOTAL Current and Accrued Assets (Enter Total of lines 24 thru 53) 54
DEFERRED DEBITS 55
5,067,2016,346,670Unamortized Debt Expenses (181) 56
00230Extraordinary Property Losses (182.1) 57
00230Unrecovered Plant and Regulatory Study Costs (182.2) 58
499,305,339599,241,273232Other Regulatory Assets (182.3) 59
91,66890,719Prelim. Survey and Investigation Charges (Electric) (183) 60
00Prelim. Sur. and Invest. Charges (Gas) (183.1, 183.2) 61
-272,774-33,501Clearing Accounts (184) 62
00Temporary Facilities (185) 63
97,170,248105,580,011233Miscellaneous Deferred Debits (186) 64
00Def. Losses from Disposition of Utility Plt. (187) 65
00352-353Research, Devel. and Demonstration Expend. (188) 66
11,795,67310,583,354Unamortized Loss on Reaquired Debt (189) 67
36,905,11940,575,302234Accumulated Deferred Income Taxes (190) 68
00Unrecovered Purchased Gas Costs (191) 69
650,062,474762,383,828TOTAL Deferred Debits (Enter Total of lines 56 thru 69) 70
2,782,252,2292,885,600,872TOTAL Assets and Other Debits (Enter Total of lines 10,11,12,22,54,70) 71
FERC FORM NO. 1 (ED. 12-94)Page 111
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
X
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
Line
No.
Title of Account
(a)
Ref.
Page No.
(b)
Balance at
Beginning of Year
(c)
Balance at
End of Year
(d)
Idaho Power Company 04/30/2003 2002
PROPRIETARY CAPITAL 1
94,030,87894,030,878Common Stock Issued (201) 2 250-251
53,392,700104,387,200Preferred Stock Issued (204) 3 250-251
00Capital Stock Subscribed (202, 205) 4 252
00Stock Liability for Conversion (203, 206) 5 252
361,824,690361,837,614Premium on Capital Stock (207) 6 252
123,232-2,954,854Other Paid-In Capital (208-211) 7 253
00Installments Received on Capital Stock (212) 8 252
00(Less) Discount on Capital Stock (213) 9 254
2,710,1154,143,734(Less) Capital Stock Expense (214) 10 254
317,609,678307,533,744Retained Earnings (215, 215.1, 216) 11 118-119
12,690,6349,322,512Unappropriated Undistributed Subsidiary Earnings (216.1) 12 118-119
00(Less) Reaquired Capital Stock (217) 13 250-251
-7,109,1230Accumulated Other Comprehensive Income (219) 14 122(a)(b)
829,852,574870,013,360TOTAL Proprietary Capital (Enter Total of lines 2 thru 13) 15
LONG-TERM DEBT 16
920,460,000797,460,000Bonds (221) 17 256-257
00(Less) Reaquired Bonds (222) 18 256-257
00Advances from Associated Companies (223) 19 256-257
32,769,72832,847,509Other Long-Term Debt (224) 20 256-257
00Unamortized Premium on Long-Term Debt (225) 21
2,405,0471,029,295(Less) Unamortized Discount on Long-Term Debt-Debit (226) 22
950,824,681829,278,214TOTAL Long-Term Debt (Enter Total of lines 16 thru 21) 23
OTHER NONCURRENT LIABILITIES 24
00Obligations Under Capital Leases - Noncurrent (227) 25
00Accumulated Provision for Property Insurance (228.1) 26
1,936,0411,500,000Accumulated Provision for Injuries and Damages (228.2) 27
1,847,8242,520,328Accumulated Provision for Pensions and Benefits (228.3) 28
12,015,1871,036,253Accumulated Miscellaneous Operating Provisions (228.4) 29
00Accumulated Provision for Rate Refunds (229) 30
15,799,0525,056,581TOTAL OTHER Noncurrent Liabilities (Enter Total of lines 24 thru 29) 31
CURRENT AND ACCRUED LIABILITIES 32
10,500,000282,000,000Notes Payable (231) 33
51,827,939108,545,330Accounts Payable (232) 34
2,652,6123,203,999Notes Payable to Associated Companies (233) 35
52,0406,931,117Accounts Payable to Associated Companies (234) 36
1,185,637157,453Customer Deposits (235) 37
84,172,122-15,067,246Taxes Accrued (236) 38 262-263
12,399,44712,891,444Interest Accrued (237) 39
65544,378Dividends Declared (238) 40
00Matured Long-Term Debt (239) 41
00Matured Interest (240) 42
848,562788,787Tax Collections Payable (241) 43
21,628,36515,916,801Miscellaneous Current and Accrued Liabilities (242) 44
00Obligations Under Capital Leases-Current (243) 45
FERC FORM NO. 1 (ED. 12-89)Page 112
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
X
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
Line
No.
Title of Account
(a)
Ref.
Page No.
(b)
Balance at
Beginning of Year
(c)
Balance at
End of Year
(d)
Idaho Power Company 04/30/2003 2002
(Continued)
91,2350Derivative Instrument Liabilities (244) 46
00Derivative Instrument Liabilities - Hedges (245) 47
185,358,614415,412,063TOTAL Current & Accrued Liabilities (Enter Total of lines 32 thru 44) 48
DEFERRED CREDITS 49
10,505,59511,025,745Customer Advances for Construction (252) 50
67,559,61168,015,922Accumulated Deferred Investment Tax Credits (255) 51 266-267
00Deferred Gains from Disposition of Utility Plant (256) 52
50,367,12446,815,756Other Deferred Credits (253) 53 269
46,687,33245,940,464Other Regulatory Liabilities (254) 54 278
00Unamortized Gain on Reaquired Debt (257) 55
625,297,646594,042,767Accumulated Deferred Income Taxes (281-283) 56 272-277
800,417,308765,840,654TOTAL Deferred Credits (Enter Total of lines 47 thru 53) 57
00 58
00 59
00 60
00 61
00 62
00 63
00 64
00 65
00 66
00 67
00 68
00 69
00 70
2,782,252,2292,885,600,872TOTAL Liab and Other Credits (Enter Total of lines 14,22,30,45,54) 71
FERC FORM NO. 1 (ED. 12-89)Page 113
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
STATEMENT OF INCOME FOR THE YEAR
Idaho Power Company X
04/30/2003
2002
Line
Previous Year
(c)(b)(a)
Account
No.Current Year
TOTAL
(d)
(Ref.)
Page No.
1. Report amounts for accounts 412 and 413, Revenue and Expenses from Utility Plant Leased to Others, in another Utility column (i,
k, m, o) in a similar manner to a utility department. Spread the amount(s) over Lines 02 thru 24 as appropriate. Include these amounts
in columns (c) and (d) totals.
2. Report amounts in account 414, Other Utility Operating income, in the same manner as accounts 412 and 413 above.
3. Report data for lines 7,9, and 10 for Natural Gas companies using accounts 404.1, 404.2, 404.3, 407.1 and 407.2.
4. Use pages 122-123 for important notes regarding the statement 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 the major factors which affect the rights of the utility to 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
UTILITY OPERATING INCOME 1
300-301 912,311,553 867,047,420Operating Revenues (400) 2
Operating Expenses 3
320-323 659,681,485 566,346,327Operation Expenses (401) 4
320-323 55,876,578 54,599,254Maintenance Expenses (402) 5
336-337 80,689,086 85,193,315Depreciation Expense (403) 6
336-337 6,673,063 8,519,658Amort. & Depl. of Utility Plant (404-405) 7
336-337 -22,723 -22,723Amort. of Utility Plant Acq. Adj. (406) 8
Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407) 9
Amort. of Conversion Expenses (407) 10
Regulatory Debits (407.3) 11
(Less) Regulatory Credits (407.4) 12
262-263 19,693,396 19,952,735Taxes Other Than Income Taxes (408.1) 13
262-263 -52,618,236 75,166,820Income Taxes - Federal (409.1) 14
262-263 -14,479,363 9,726,454 - Other (409.1) 15
234, 272-277 126,997,151 27,310,757Provision for Deferred Income Taxes (410.1) 16
234, 272-277 48,412,782 114,691,926(Less) Provision for Deferred Income Taxes-Cr. (411.1) 17
266 1,966,044 -456,312Investment Tax Credit Adj. - Net (411.4) 18
194,097(Less) Gains from Disp. of Utility Plant (411.6) 19
12,328 12,328Losses from Disp. of Utility Plant (411.7) 20
116,843 93,955(Less) Gains from Disposition of Allowances (411.8) 21
Losses from Disposition of Allowances (411.9) 22
835,745,087 731,562,732TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 22) 23
76,566,466 135,484,688Net Util Oper Inc (Enter Tot line 2 less 23) Carry fwd to P117,line 25 24
FERC FORM NO. 1 (ED. 12-96)Page 114
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
STATEMENT OF INCOME FOR THE YEAR (Continued)
Idaho Power Company X
04/30/2003
2002
Line
Previous Year
(i)(h)(e)
ELECTRIC UTILITY No.Current Year
OTHER UTILITY
(j)
GAS UTILITY
Previous YearCurrent Year Previous Year Current Year
(f)(g)
resulting from settlement of any rate proceeding affecting revenues received or costs incurred for power or gas purchases, and a
summary of the adjustments made to balance sheet, income, and expense accounts.
7. If any notes appearing in the report to stockholders are applicable to this Statement of Income, such notes may be included on
pages 122-123.
B. Enter on pages 122-123 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
approximate dollar effect of such changes.
9. Explain in a footnote if the previous year's figures are different from that reported in prior reports.
10. If the columns are insufficient for reporting additional utility departments, supply the appropriate account titles, lines 2 to 23, and
report the information in the blank space on pages.122-123 or in a footnote.
1
867,047,420 912,311,553 2
3
566,346,327 659,681,485 4
54,599,254 55,876,578 5
85,193,315 80,689,086 6
8,519,658 6,673,063 7
-22,723 -22,723 8
9
10
11
12
19,952,735 19,693,396 13
75,166,820 -52,618,236 14
9,726,454 -14,479,363 15
27,310,757 126,997,151 16
114,691,926 48,412,782 17
-456,312 1,966,044 18
194,097 19
12,328 12,328 20
93,955 116,843 21
22
731,562,732 835,745,087 23
135,484,688 76,566,466 24
FERC FORM NO. 1 (ED. 12-96)Page 115
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
STATEMENT OF INCOME FOR THE YEAR (Continued)
Idaho Power Company X
04/30/2003 2002
Line
Previous Year
(o)(n)(k)
OTHER UTILITY
No.Current Year
OTHER UTILITY
(p)
OTHER UTILITY
Previous YearCurrent Year Previous Year Current Year
(l)(m)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
FERC FORM NO. 1 (ED. 12-96)Page 116
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
STATEMENT OF INCOME FOR THE YEAR (Continued)
Idaho Power Company X
04/30/2003 2002
Line
Previous Year
(c)(b)(a)
Account
No.Current Year
TOTAL
(d)
(Ref.)
Page No.
135,484,688 76,566,466Net Utility Operating Income (Carried forward from page 114) 25
Other Income and Deductions 26
Other Income 27
Nonutilty Operating Income 28
1,992,219 1,889,291Revenues From Merchandising, Jobbing and Contract Work (415) 29
1,871,836 1,806,575(Less) Costs and Exp. of Merchandising, Job. & Contract Work (416) 30
Revenues From Nonutility Operations (417) 31
2,764,304 9,399(Less) Expenses of Nonutility Operations (417.1) 32
-1,768 -8,182Nonoperating Rental Income (418) 33
119 10,368,122 6,893,568Equity in Earnings of Subsidiary Companies (418.1) 34
3,148,119 4,342,243Interest and Dividend Income (419) 35
333,060 752,108Allowance for Other Funds Used During Construction (419.1) 36
2,203,829 91,622,074Miscellaneous Nonoperating Income (421) 37
-329,175 871,309Gain on Disposition of Property (421.1) 38
13,078,266 104,546,437TOTAL Other Income (Enter Total of lines 29 thru 38) 39
Other Income Deductions 40
2,678 19,029Loss on Disposition of Property (421.2) 41
340Miscellaneous Amortization (425) 42
340 2,715,164 3,600,701Miscellaneous Income Deductions (426.1-426.5) 43
2,717,842 3,619,730TOTAL Other Income Deductions (Total of lines 41 thru 43) 44
Taxes Applic. to Other Income and Deductions 45
262-263 39,656 -9,987Taxes Other Than Income Taxes (408.2) 46
262-263 -5,679,551 10,237,523Income Taxes-Federal (409.2) 47
262-263 -1,128,109 1,935,300Income Taxes-Other (409.2) 48
234, 272-277 1,695,784 26,070,988Provision for Deferred Inc. Taxes (410.2) 49
234, 272-277 -3,878,547 1,876,330(Less) Provision for Deferred Income Taxes-Cr. (411.2) 50
Investment Tax Credit Adj.-Net (411.5) 51
(Less) Investment Tax Credits (420) 52
-1,193,673 36,357,494TOTAL Taxes on Other Income and Deduct. (Total of 46 thru 52) 53
11,554,097 64,569,213Net Other Income and Deductions (Enter Total lines 39, 44, 53) 54
Interest Charges 55
51,127,383 55,704,367Interest on Long-Term Debt (427) 56
964,219 1,027,776Amort. of Debt Disc. and Expense (428) 57
1,417,179 1,312,943Amortization of Loss on Reaquired Debt (428.1) 58
(Less) Amort. of Premium on Debt-Credit (429) 59
(Less) Amortization of Gain on Reaquired Debt-Credit (429.1) 60
340 652,515 843,507Interest on Debt to Assoc. Companies (430) 61
340 6,331,567 7,745,906Other Interest Expense (431) 62
2,374,774 3,736,839(Less) Allowance for Borrowed Funds Used During Construction-Cr. (432) 63
58,118,089 62,897,660Net Interest Charges (Enter Total of lines 56 thru 63) 64
88,920,696 78,238,019Income Before Extraordinary Items (Total of lines 25, 54 and 64) 65
Extraordinary Items 66
Extraordinary Income (434) 67
(Less) Extraordinary Deductions (435) 68
Net Extraordinary Items (Enter Total of line 67 less line 68) 69
262-263Income Taxes-Federal and Other (409.3) 70
Extraordinary Items After Taxes (Enter Total of line 69 less line 70) 71
88,920,696 78,238,019Net Income (Enter Total of lines 65 and 71) 72
FERC FORM NO. 1 (ED. 12-96)Page 117
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
STATEMENT OF RETAINED EARNINGS FOR THE YEAR
Idaho Power Company X
04/30/2003
2002
Line Amount
(c)(b)(a)
Item
Contra Primary
No.Account Affected
1. Report all changes in appropriated retained earnings, unappropriated retained earnings, and unappropriated undistributed
subsidiary earnings for the year.
2. 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)
3. State the purpose and amount of each reservation or appropriation of retained earnings.
4. 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.
5. Show dividends for each class and series of capital stock.
6. Show separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Earnings.
7. 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.
8. If any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.
UNAPPROPRIATED RETAINED EARNINGS (Account 216)
305,989,778 1 Balance-Beginning of Year
2 Changes
3 Adjustments to Retained Earnings (Account 439)
4
-711,555216 5 Retirement of Flexible Auction Preferred Stock
6
7
8
-711,555 9 TOTAL Credits to Retained Earnings (Acct. 439)
10
11
12
13
14
15 TOTAL Debits to Retained Earnings (Acct. 439)
78,552,574216 16 Balance Transferred from Income (Account 433 less Account 418.1)
17 Appropriations of Retained Earnings (Acct. 436)
18
19
20
21
22 TOTAL Appropriations of Retained Earnings (Acct. 436)
23 Dividends Declared-Preferred Stock (Account 437)
-564,076437 24 4% Preferred (par value $100)
-1,103,625437 25 Auction Rate Preferred, Series A (stated value $100,000)
-1,152,000437 26 7.68% Serial Preferred (par value $100)
-1,767,500437 27 7.07% Serial Preferred (par value $100,000)
28
-4,587,201 29 TOTAL Dividends Declared-Preferred Stock (Acct. 437)
30 Dividends Declared-Common Stock (Account 438)
-70,177,884 31 $2.50 Par Value
32
33
34
35
-70,177,884 36 TOTAL Dividends Declared-Common Stock (Acct. 438)
7,000,000216 37 Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings
316,065,712 38 Balance - End of Year (Total 1,9,15,16,22,29,36,37)
APPROPRIATED RETAINED EARNINGS (Account 215)
39
FERC FORM NO. 1 (ED. 12-96)Page 118
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
STATEMENT OF RETAINED EARNINGS FOR THE YEAR
Idaho Power Company X
04/30/2003
2002
Line Amount
(c)(b)(a)
Item
Contra Primary
No.Account Affected
1. Report all changes in appropriated retained earnings, unappropriated retained earnings, and unappropriated undistributed
subsidiary earnings for the year.
2. 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)
3. State the purpose and amount of each reservation or appropriation of retained earnings.
4. 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.
5. Show dividends for each class and series of capital stock.
6. Show separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Earnings.
7. 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.
8. If any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.
40
41
42
43
44
45 TOTAL Appropriated Retained Earnings (Account 215)
APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.1)
1,543,966 46 TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 215.1)
1,543,966 47 TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46)
317,609,678 48 TOTAL Retained Earnings (Account 215, 215.1, 216) (Total 38, 47)
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account 216.1)
9,322,512 49 Balance-Beginning of Year (Debit or Credit)
10,368,122 50 Equity in Earnings for Year (Credit) (Account 418.1)
7,000,000 51 (Less) Dividends Received (Debit)
52
12,690,634 53 Balance-End of Year (Total lines 49 thru 52)
FERC FORM NO. 1 (ED. 12-96)Page 119
1. If the notes to the cash flow statement in the respondents annual stockholders report are applicable to this statement, such notes should be included
in page 122-123. Information about non-cash investing and financing activities should be provided on Page 122-123. Provide also on pages 122-123 a
reconciliation between "Cash and Cash Equivalents at End of Year" with related amounts on the balance sheet.
2. Under "Other" specify significant amounts and group others.
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 on Page 122-123 the amount of interest paid (net of amounts capitalized) and income taxes paid.
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
STATEMENT OF CASH FLOWS
Idaho Power Company X
04/30/2003
2002
Line Description (See Instruction No. 5 for Explanation of Codes)Amounts
(b)(a)No.
1 Net Cash Flow from Operating Activities:
88,920,696 2 Net Income
3 Noncash Charges (Credits) to Income:
85,334,384 4 Depreciation and Depletion
11,541,352 5 Amortization of
6
7
-81,357,140 8 Deferred Income Taxes (Net)
-456,311 9 Investment Tax Credit Adjustment (Net)
-4,643,397 10 Net (Increase) Decrease in Receivables
3,604,568 11 Net (Increase) Decrease in Inventory
12 Net (Increase) Decrease in Allowances Inventory
75,738,603 13 Net Increase (Decrease) in Payables and Accrued Expenses
170,347,278 14 Net (Increase) Decrease in Other Regulatory Assets
1,023,878 15 Net Increase (Decrease) in Other Regulatory Liabilities
333,060 16 (Less) Allowance for Other Funds Used During Construction
3,817,819 17 (Less) Undistributed Earnings from Subsidiary Companies
18 Other (provide details in footnote):
1,686,536 19 Unbilled Revenues
17,106,484 20 Other Amort and Other - Net
979,519 21 Other than Temp Decline in Market Value of Investments
365,675,571 22 Net Cash Provided by (Used in) Operating Activities (Total 2 thru 21)
23
24 Cash Flows from Investment Activities:
25 Construction and Acquisition of Plant (including land):
-125,277,281 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
2,374,773 30 (Less) Allowance for Other Funds Used During Construction
31 Other (provide details in footnote):
32
33
-127,652,054 34 Cash Outflows for Plant (Total of lines 26 thru 33)
35
36 Acquisition of Other Noncurrent Assets (d)
337,707 37 Proceeds from Disposal of Noncurrent Assets (d)
38
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
43
44 Purchase of Investment Securities (a)
45 Proceeds from Sales of Investment Securities (a)
FERC FORM NO. 1 (ED. 12-96)Page 120
4. Investing Activities include at Other (line 31) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilities
assumed on pages 122-123. Do not include on this statement the dollar amount of Leases capitalized per US of A General Instruction 20; instead
provide a reconciliation of the dollar amount of Leases capitalized with the plant cost on pages 122-123.
5. Codes used:
(a) Net proceeds or payments.(c) Include commercial paper.
(b) Bonds, debentures and other long-term debt.(d) Identify separately such items as investments, fixed assets, intangibles, etc.
6. Enter on pages 122-123 clarifications and explanations.
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
STATEMENT OF CASH FLOWS
Idaho Power Company X
04/30/2003
2002
Line Description (See Instruction No. 5 for Explanation of Codes)Amounts
(b)(a)No.
46 Loans Made or Purchased
47 Collections on Loans
48
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):
11,859,184 54 Note Receivable Payment from Parent
-2,269,862 55 Other Net
56 Net Cash Provided by (Used in) Investing Activities
-117,725,025 57 Total of lines 34 thru 55)
58
59 Cash Flows from Financing Activities:
60 Proceeds from Issuance of:
200,000,000 61 Long-Term Debt (b)
62 Preferred Stock
63 Common Stock
64 Other (provide details in footnote):
65
66 Net Increase in Short-Term Debt (c)
67 Other (provide details in footnote):
68
69
200,000,000 70 Cash Provided by Outside Sources (Total 61 thru 69)
71
72 Payments for Retirement of:
-77,000,000 73 Long-term Debt (b)
-50,214,798 74 Preferred Stock
75 Common Stock
-2,165,088 76 Other (provide details in footnote): Other Net
-2,094,000 77 First Mortgage Bond Redemtion Cost
-272,051,387 78 Net Decrease in Short-Term Debt (c)
79
-4,587,201 80 Dividends on Preferred Stock
-70,177,884 81 Dividends on Common Stock
82 Net Cash Provided by (Used in) Financing Activities
-278,290,358 83 (Total of lines 70 thru 81)
84
85 Net Increase (Decrease) in Cash and Cash Equivalents
-30,339,812 86 (Total of lines 22,57 and 83)
87
42,996,809 88 Cash and Cash Equivalents at Beginning of Year
89
12,656,997 90 Cash and Cash Equivalents at End of Year
FERC FORM NO. 1 (ED. 12-96)Page 121
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report Year of Report
Dec. 31,
NOTES TO FINANCIAL STATEMENTS
Idaho Power Company X 04/30/2003 2002
PAGE 122 INTENTIONALLY LEFT BLANK
SEE PAGE 123 FOR REQUIRED INFORMATION.
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.
FERC FORM NO. 1 (ED. 12-96)Page 122
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/30/2003
Year of Report
Dec 31, 2002
NOTES TO FINANCIAL STATEMENTS (Continued)
NOTES TO THE FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Nature of Business
Idaho Power Company (IPC) is regulated by the Federal Energy Regulatory Commission (FERC) and the state regulatory
commissions of Idaho and Oregon and is engaged in the generation, transmission, distribution, sale and purchase of
electric energy. IPC is the parent of Idaho Energy Resources Co., (IERCO) a joint venturer in Bridger Coal Company,
which supplies coal to the Jim Bridger generating plant owned in part by IPC. IERCO is not consolidated for FERC
Form-1 reporting purposes. Effective June 11,2001 IPC transferred its non-utility wholesale electricity marketing
operations ("Energy Marketing") to IdaCorp Energy (IE). Energy Marketing net assets transferred consist primarily of
energy trading contracts and trading accounts receivable and accounts payable.
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.
System of Accounts
The accounting records of IPC conform to the Uniform System of Accounts prescribed by the FERC and adopted by the
public utility commissions of Idaho, Oregon and Wyoming.
Management Estimates
Management makes estimates and assumptions when preparing financial statements in conformity with accounting
principles generally accepted in the United States of America. These estimates and assumptions affect the reported
amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial
statements, and the reported amounts of revenues and expenses during the reporting period. These estimates involve
judgments with respect to, among other things, future economic factors that are difficult to predict and are beyond
management's control. As a result, actual results could differ from those estimates.
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 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 3.00 percent in
2002 and 2.98 percent in 2001.
FERC FORM NO. 1 (ED. 12-88)Page 123
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/30/2003
Year of Report
Dec 31, 2002
NOTES TO FINANCIAL STATEMENTS (Continued)
Allowance for Funds Used During Construction
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 higher rate base
and higher depreciation expense. The component of AFDC attributable to borrowed funds is included as a reduction to
interest expense, while the equity component is included in other income. IPC's weighted-average monthly AFDC rates
for 2002 and 2001 were 4.3 percent and 5.4 percent, respectively. IPC's reductions to interest expense for AFDC were $2
million and $4 million, and other income included $0.3 million and $1 million for 2002 and 2001, respectively.
Revenues
In order to match revenues with associated expenses, IPC accrues unbilled revenues for electric services delivered to
customers but not yet billed at month-end.
Power Cost Adjustment
IPC has a Power Cost Adjustment (PCA) mechanism that provides for annual adjustments to the rates charged to its
Idaho retail electric customers. These adjustments, which take effect annually in May, are based on forecasts of net
power supply expenses 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 a true-up, is then
included in the calculation of the next year's PCA adjustment.
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).
The State of Idaho allows a three-percent investment tax credit (ITC) upon certain qualifying plant additions. ITC's
earned on regulated assets are deferred and amortized to income over the estimated service lives of the related properties.
Credits earned on non-regulated assets or investments are recognized in the year earned.
Stock-Based Compensation
At December 31, 2002, two stock-based employee compensation plans existed, which are described more fully in Note 8.
These plans are accounted for under the recognition and measurement principles of Accounting Principles Board (APB)
Opinion 25, "Accounting for Stock Issued to Employees," and related interpretations. Grants of restricted stock are
reflected in net income based on the market value at the award date, or the year-end price for shares not yet vested. No
FERC FORM NO. 1 (ED. 12-88)Page 123.1
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/30/2003
Year of Report
Dec 31, 2002
NOTES TO FINANCIAL STATEMENTS (Continued)
stock-based employee compensation cost is reflected in net income for stock options, as all options granted under these
plans had an exercise price equal to the market value of the underlying common stock on the date of grant.
The following table illustrates the effect on net income if the fair value recognition provisions of SFAS 123, "Accounting
for Stock-Based Compensation," had been applied to stock-based employee compensation:
2002 2001
(thousands of dollars)
Net income, as reported $88,920 $78,238
Add: Stock-based employee compensation expense included
in reported net income, net of related tax effects (10)403
Deduct: Total stock-based employee compensation expense
determined under fair value based method for all awards,
net of related tax effects 1,837 1,603
Pro forma net income $87,073 $77,038
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 three months or less.
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid (received) during the period for:2002
Income taxes $(17,974)
Interest (net of amount capitalized)56,167
Investments
Investments in marketable securities are accounted for in accordance with SFAS 115, "Accounting for Certain
Investments in Debt and Equity Securities." These investments are classified as available-for-sale securities, and are
reported at fair value, using either specific identification or average cost to determine the cost for computing gains or
losses. Any unrealized gains or losses on available-for-sale securities are included in other comprehensive income.
Additionally, these investments are evaluated to determine whether they have experienced a decline in market value that
is considered other than temporary. Other than temporary declines in market value are included in other income.
Regulation of Utility Operations
IPC follows SFAS 71, "Accounting for the Effects of Certain Types of Regulation," and its financial statements reflect
the effects of the different rate making principles followed by the various jurisdictions regulating IPC. The economic
effects of regulation can result in regulated companies recording costs that have been or are expected to be allowed in the
ratemaking process in a period different from the period in which the costs would be charged to expense by an
unregulated enterprise. When this occurs, costs are deferred as regulatory assets in the balance sheet and recorded as
expenses in the periods when those same amounts are reflected in rates. Additionally, regulators can impose liabilities
upon a regulated company for amounts previously collected from customers and for amounts that are expected to be
refunded to customers (regulatory liabilities).
FERC FORM NO. 1 (ED. 12-88)Page 123.2
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/30/2003
Year of Report
Dec 31, 2002
NOTES TO FINANCIAL STATEMENTS (Continued)
Comprehensive Income
Comprehensive income includes net income, unrealized holding gains (losses) on marketable securities, IPC's
proportionate share of unrealized holding gains (losses) on marketable securities held by an equity investee, and the
changes in additional minimum liability under a deferred compensation plan for certain senior management employees
and directors.
Adopted Accounting Standards
In June 2001, the Derivative Implementation Group of the Financial Accounting Standards Board (FASB) issued
Implementation Issue C-15, "Normal Purchases and Normal Sales Exception for Option-Type Contracts and Forward
Contracts in Electricity," concluding that contracts subject to book-outs were not eligible for the normal purchase and
sales exception in SFAS 133. Therefore, certain contracts were recorded as derivatives in prior periods. However, this
Implementation Issue was revised in October 2001 and December 2001, and now allows these contracts to qualify for the
exception. This revision applies only to electric utilities, due to the unique nature of the industry. IPC completed an
evaluation of the effect of this revised Implementation Issue on its treatment of booked-out contracts and determined that
contracts previously classified as derivatives were exempt. This change did not have a material effect on IPC's financial
statements.
New Accounting Pronouncements
In June 2001, the FASB issued SFAS 143, "Accounting for Asset Retirement Obligations," which addresses financial
accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated
asset retirement costs. An obligation may result from the acquisition, construction, development and the normal
operation of a long-lived asset. SFAS 143 requires an entity to record the fair value of a liability for an asset retirement
obligation (ARO) in the period in which it is incurred. When the liability is initially recorded, the entity increases the
carrying amount of the related long-lived asset to reflect the future retirement cost. Over time, the liability is accreted to
its present value and paid, and the capitalized cost is depreciated over the useful life of the related asset. If at the end of
the asset's life the recorded liability differs from the actual obligations paid, a gain or loss would be recognized at that
time. As a rate-regulated entity, IPC expects to record regulatory assets and liabilities instead of accretion, depreciation
and gains or losses, if the criteria for such treatment are met. SFAS 143 is effective beginning in 2003.
A detailed assessment of the applicability and implications of SFAS 143 has been performed. AROs related to IPC's
three jointly owned coal-fired generation facilities, its transmission and distribution facilities and the Bridger Coal mine,
which is owned by an equity-method investee, have been identified. When adopted in 2003, IPC expects to record ARO
liabilities of $12 million and fixed assets of $6 million, with the offset to regulatory assets. These amounts do not include
an amount for the transmission and distribution facilities, because, based on the indeterminate life of these assets, an
ARO calculation cannot be made.
In June 2002, the FASB issued SFAS 146, "Accounting for Costs Associated with Exit or Disposal Activities." The
standard requires companies to recognize costs associated with exit or disposal activities when they are incurred, rather
than at the date of a commitment to an exit or disposal plan. Examples of costs covered by the standard include lease
termination costs and certain employee severance costs that are associated with a restructuring, discontinued operation,
plant closing or other exit or disposal activity. This standard supersedes EITF Issue No. 94-3, "Liability Recognition for
Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a
Restructuring)." SFAS 146 is to be applied prospectively to exit or disposal activities initiated after December 31, 2002.
The adoption of SFAS 146 is not expected to have a material effect on IPC's financial statements.
FERC FORM NO. 1 (ED. 12-88)Page 123.3
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/30/2003
Year of Report
Dec 31, 2002
NOTES TO FINANCIAL STATEMENTS (Continued)
In November 2002, the FASB issued Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for
Guarantees, Including Indirect Guarantees of Indebtedness of Others." This Interpretation elaborates on the disclosures
to be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that
it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the
fair value of the obligation undertaken in issuing the guarantee. The initial recognition and measurement provisions of
this Interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002,
irrespective of the guarantor's fiscal year-end. The disclosure requirements in this Interpretation are effective for financial
statements of interim or annual periods ending after December 15, 2002. The adoption of this Interpretation is not
expected to have a material effect on IPC's financial statements.
In January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities." This
Interpretation clarifies the application of Accounting Research Bulletin No. 51, "Consolidated Financial Statements," to
certain entities in which equity investors do not have the characteristics of a controlling financial interest or in which
equity investors do not bear the residual economic risks. The Interpretation applies to variable interest entities in which
an enterprise obtains an interest after that date. It applies in the fiscal year or interim period beginning after June 15,
2003 to variable interest entities in which an enterprise holds a variable interest that was acquired before February 1,
2003. IPC has determined that it is not reasonably possible that they will be required to consolidate or disclose
information about a variable interest entity upon the effective date of this Interpretation.
Common Stock
The outstanding shares of IPC's common stock were exchanged on a share-for-share basis into common stock of
IDACORP, Inc. (IDACORP) on October 1, 1998 and are no longer actively traded. IPC's preferred stock and debt
securities were unaffected.
Other Accounting Policies
Debt discount, expense and premium are being amortized over the terms of the respective debt issues.
2. INCOME TAXES:
IPC's effective tax rate for the year ended December 31, 2002 decreased from 38.9 percent in 2001 to a benefit of 4.9
percent in 2002. Tax benefit items occurring in 2002 include a tax accounting method change and the settlement of a
partnership audit, which resulted in a decrease to tax expense.
A reconciliation between the statutory federal income tax rate and the effective rate is as follows:
2002 2001
(thousands of dollars)
Computed income taxes based on statutory federal income tax rate $29,660 $44,820
Change in taxes resulting from:
Equity earnings of subsidiary companies (3,629)(2,413)
AFDC (948)(1,571)
Investment tax credits (3,179)(3,169)
Repair allowance (2,450)(2,800)
Removal cost (815)(329)
Capitalized overhead costs (3,500)-
Tax accounting method change (31,162)-
Settlement of prior years tax returns - -
FERC FORM NO. 1 (ED. 12-88)Page 123.4
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/30/2003
Year of Report
Dec 31, 2002
NOTES TO FINANCIAL STATEMENTS (Continued)
State income taxes (net of federal reduction)3,946 4,315
Depreciation 8,940 9,790
Other (1,041)1,177
Total (benefit) provision for income taxes $(4,178)$49,820
Effective tax rate (4.9)%38.9%
The provision for income taxes consists of the following:
2002 2001
(thousands of dollars)
Income taxes currently payable (receivable):
Federal $69,487 $(42,381)
State 8,598 (12,544)
Total 78,085 (54,925)
Income taxes deferred:
Federal (76,352)85,692
State (5,455)17,087
Total (81,807)102,779
Investment tax credits:
Deferred 2,723 5,135
Restored (3,179)(3,169)
Total (456)1,966
Total (benefit) provision for income taxes $(4,178)$49,820
The tax effects of significant items comprising IPC's net deferred tax liabilities are as follows:
2002 2001
(thousands of dollars)
Deferred tax assets:
Regulatory liabilities $41,013 $41,290
Advances for construction 3,758 3,941
Other 19,802 (4,655)
Total 64,573 40,576
Deferred tax liabilities:
Property, plant and equipment 230,935 250,180
Regulatory assets 327,934 209,832
Conservation programs 10,427 11,138
PCA 53,324 113,605
Other 30,346 9,288
Total 652,966 594,043
Net deferred tax liabilities $588,393 $553,467
FERC FORM NO. 1 (ED. 12-88)Page 123.5
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/30/2003
Year of Report
Dec 31, 2002
NOTES TO FINANCIAL STATEMENTS (Continued)
3. PREFERRED STOCK OF IDAHO POWER COMPANY:
The number of shares of IPC preferred stock outstanding at December 31, 2002 and 2001 were as follows:
Shares Outstanding at
December 31,Call Price
2002 2001 Per Share
Preferred stock:
Cumulative, $100 par value:
4% preferred stock (authorized 215,000 shares)133,927 143,872 $104.00
Serial preferred stock, 7.68% Series (authorized
150,000 shares 150,000 150,000 $102.97
Serial preferred stock, cumulative, without par value,
total of 3,000,000 shares authorized:
7.07% Series, $100 stated value (authorized
250,000 shares) (a)250,000 250,000 $100.354 - $103.535
Auction rate preferred stock, $100,000 stated value
(authorized 500 shares) -500
Total 533,927 544,372
(a)The preferred stock is not redeemable prior to July 1, 2003.
IPC redeemed its auction rate preferred stock in August 2002 for $50 million using short-term borrowings.
During 2002 and 2001 IPC reacquired and retired 9,945 and 6,784 shares of 4% preferred stock. As of December 31,
2002, the overall effective cost of all outstanding preferred stock was 7.03 percent.
4. LONG-TERM DEBT:
The following table summarizes long-term debt at December 31:
2002 2001
(thousands of dollars)
First mortgage bonds:
6.85% Series due 2002 $- $27,000
6.40% Series due 2003 80,000 80,000
8 % Series due 2004 50,000 50,000
5.83% Series due 2005 60,000 60,000
7.38% Series due 2007 80,000 80,000
7.20% Series due 2009 80,000 80,000
6.60% Series due 2011 120,000 120,000
4.75% Series due 2012 100,000 -
Maturing 2023 through 2032 with rates ranging from
6.00% to 8.75%180,000 130,000
Total first mortgage bonds 750,000 627,000
Pollution control revenue bonds:
8.30% Series 1984 due 2014 49,800 49,800
6.05% Series 1996A due 2026 68,100 68,100
Variable Rate Series 1996B due 2026 24,200 24,200
Variable Rate Series 1996C due 2026 24,000 24,000
Variable Rate Series 2000 due 2027 4,360 4,360
FERC FORM NO. 1 (ED. 12-88)Page 123.6
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/30/2003
Year of Report
Dec 31, 2002
NOTES TO FINANCIAL STATEMENTS (Continued)
Total pollution control revenue bonds 170,460 170,460
REA notes 1,185 1,263
American Falls bond guarantee 19,885 19,885
Milner Dam note guarantee 11,700 11,700
Unamortized premium/discount - net (2,405)(1,029)
Total 950,825 829,279
Current maturities of long-term debt (80,084)(27,078)
Total long-term debt $870,741 $802,201
At December 31, 2002, the maturities for the aggregate amount of long-term debt outstanding were (in thousands of
dollars):
2003 $80,084
2004 50,077
2005 60,079
2006 82
2007 81,228
Thereafter 679,275
Total $950,825
On March 23, 2000, IPC filed a $200 million shelf registration statement that could be used for first mortgage bonds
(including medium-term notes), unsecured debt or preferred stock. On December 1, 2000, IPC issued $80 million of
Secured Medium-Term Notes, Series C, 7.38% Series due 2007. Proceeds were used in January 2001 for the early
redemption of $75 million First Mortgage Bonds 9.50% Series due 2021. On March 2, 2001, IPC issued $120 million of
Secured Medium-Term Notes, Series C, 6.60% Series due 2011 with the proceeds used to reduce short-term borrowing
incurred in support of ongoing long-term construction requirements. No amounts remain to be issued on this shelf
registration statement.
On August 16, 2001, IPC filed a $200 million shelf registration statement that could be used for first mortgage bonds
(including medium-term notes), unsecured debt or preferred stock. On November 15, 2002, IPC issued $200 million of
secured medium-term notes. This issuance of medium-term notes was divided into two series. The first was $100
million First Mortgage Bonds 4.75% Series due 2012 and the second was $100 million First Mortgage Bonds 6.00%
Series due 2032. Proceeds were used to pay down IPC short-term borrowings.
In August 2001, $25 million First Mortgage Bonds 9.52% Series due 2031 were redeemed early. Also, in March 2002,
$50 million First Mortgage Bonds 8.75% Series due 2027 were redeemed early using short-term borrowings.
The amount of first mortgage bonds issuable by IPC is limited to a maximum of $900 million and by property, earnings
and other provisions of the mortgage and supplemental indentures thereto. IPC may amend the indenture and increase
this amount without consent of the holders of the first mortgage bonds. Substantially all of the electric utility plant is
subject to the lien of the indenture.
Pollution Control Revenue Bonds, Series 1984, due December 1, 2014, are secured by First Mortgage Bonds, Pollution
Control Series A, which were issued by IPC and are held by a Trustee for the benefit of the bondholders.
On April 26, 2000, at the request of IPC, the American Falls Reservoir District issued its American Falls Refunding
FERC FORM NO. 1 (ED. 12-88)Page 123.7
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/30/2003
Year of Report
Dec 31, 2002
NOTES TO FINANCIAL STATEMENTS (Continued)
Replacement Dam Bonds, Series 2000, in the aggregate principal amount of $20 million for the purpose of refunding on
April 26, 2000 a like amount of its bonds dated May 1, 1990. IPC has guaranteed repayment of these bonds.
On May 17, 2000, tax exempt Pollution Control Revenue Refunding Bonds Series 2000, in the aggregate principal
amount of $4 million, were issued by Port of Morrow, Oregon for the purpose of refunding on August 1, 2000, a like
amount of its Pollution Control Revenue Bonds, Series 1978.
At December 31, 2002 and 2001, the overall effective cost of all outstanding first mortgage bonds and pollution control
revenue bonds was 6.51 percent and 6.97 percent, respectively.
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, fixed rate long-term debt and investments and other property are based upon quoted market prices of
the same or similar issues or discounted cash flow analyses as appropriate.
December 31, 2002 December 31, 2001
Carrying Estimated Carrying Estimated
Amount Fair Value Amount Fair Value
(thousands of dollars)
Assets:
Notes receivable $9,646 $10,063 $12,009 $11,207
Investments and other property 20,401 20,401 16,729 16,729
Liabilities:
Fixed rate long-term debt 953,230 1,015,612 830,508 867,808
6. NOTES PAYABLE:
At December 31, 2002, IPC had regulatory authority to incur up to $350 million of short-term indebtedness. IPC has a
$200 million credit facility that expires March 25, 2003. Under this facility IPC pays a facility fee on the commitment,
quarterly in arrears, based on IPC's corporate credit rating. IPC's commercial paper may be issued up to the amounts
supported by the bank credit facilities.
Balances and interest rates of short-term borrowings were as follows at December 31 (in thousands of dollars):
2002 2001
Balance $10,500 $282,000
Effective interest rate 1.65%2.10%
FERC FORM NO. 1 (ED. 12-88)Page 123.8
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/30/2003
Year of Report
Dec 31, 2002
NOTES TO FINANCIAL STATEMENTS (Continued)
7. COMMITMENTS AND CONTINGENT LIABILITIES:
IPC is currently purchasing energy from 67 on-line cogeneration and small power production facilities with contracts
ranging from one to 30 years. Under these contracts IPC is required to purchase all of the output from these facilities.
During the year ended December 31, 2002, IPC purchased 692,414 MWh at a cost of $44 million.
IPC has agreed to guarantee the performance of reclamation activities at Bridger Coal Company of which Idaho Energy
Resources Company, a subsidiary of IPC, owns a one-third interest. This guarantee, which is renewed each December,
was $60 million at December 31, 2002.
From time to time IPC is a party to various other legal claims, actions and complaints not discussed below. IPC believes
that they have meritorious defenses to all lawsuits and legal proceedings in which they are defendants and will vigorously
defend against them although they are unable to predict with certainty whether or not they will ultimately be successful.
However, based on our evaluation, management believes that the resolution of these matters will not have a material
adverse effect on IPC's financial positions, results of operations or cash flows.
Legal Proceedings
Public Utility District No. 1 of Grays Harbor County, Washington: On October 15, 2002, Public Utility District No.
1 of Grays Harbor County, Washington (Grays Harbor) filed a lawsuit in the Superior Court of the State of Washington,
for the County of Grays Harbor, against IDACORP, IPC and IDACORP Energy (IE). On March 9, 2001, Grays Harbor
entered into a 20-MW purchase transaction with IPC for the purchase of electric power from October 1, 2001 through
March 31, 2002, at a rate of $249 per MWh. In June 2001, with the consent of Grays Harbor, IPC assigned all of its
rights and obligations under the contract to IE. In its lawsuit, Grays Harbor alleges that the assignment was void and
unenforceable, and seeks restitution from IE and IDACORP, or in the alternative, Grays Harbor alleges that the contract
should be rescinded or reformed. Grays Harbor seeks as damages an amount equal to the difference between $249 per
MWh and the "fair value" of electric power delivered by IE during the period October 1, 2001 through March 31, 2002.
IDACORP, IPC and IE had this action removed from the state court to the United States District Court for the Western
District of Washington at Tacoma. On November 12, 2002, the companies filed a motion to dismiss Grays Harbor's
complaint, asserting that the Federal District Court lacked jurisdiction as the matter is preempted under the FPA by the
FERC. The court ruled in favor of the companies' motion to dismiss and dismissed the case with prejudice on January
28, 2003.
State of California Attorney General: The California Attorney General (AG) filed the complaint in this case in the
California Superior Court in San Francisco on May 30, 2002. This is one of thirteen virtually identical cases brought by
the AG against various sellers of power in the California market, seeking civil penalties pursuant to California's unfair
competition law - California Business and Professions Code Section 17200. Section 17200 defines unfair competition as
any "unlawful, unfair or fraudulent business act or practice . . . ." The AG alleges that IPC engaged in unlawful conduct
by violating the Federal Power Act (FPA) in two respects: (1) by failing to file its rates with the FERC as required by the
FPA; and (2) charging unjust and unreasonable rates in violation of the FPA. The AG alleges that there were "thousands
of . . . sales or purchases" for which IPC failed to file its rates, and that IPC charged unjust and unreasonable rates on
"thousands of occasions." Pursuant to Business and Professions Code Section 17206, the AG seeks civil penalties of up
to $2,500 for each alleged violation. On June 25, 2002, IPC removed the action to federal court, and on July 25, 2002,
the AG filed a motion to remand back to state court. The court previously denied the AG's prior motions to remand back
to state court in the companion cases. The court heard IPC's Motion to Dismiss on September 26, 2002. The court has
FERC FORM NO. 1 (ED. 12-88)Page 123.9
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/30/2003
Year of Report
Dec 31, 2002
NOTES TO FINANCIAL STATEMENTS (Continued)
not yet ruled on the Motion to Dismiss. IPC intends to vigorously defend its position in this proceeding and believes this
matter will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.
Wholesale Electricity Antitrust Cases I & II: These cross-actions against IE and IPC emerge from multiple California
state court proceedings first initiated in late 2000 against various power generators/marketers by various California
municipalities and citizens, including California Lieutenant Governor Cruz Bustamante and California legislator Barbara
Matthews in their personal capacities. Suit was filed against entities including Reliant Energy Services, Inc., Reliant
Ormond Beach, L.L.C., Reliant Energy Etiwanda, L.L.C., Reliant Energy Ellwood, L.L.C., Reliant Energy Mandalay,
L.L.C., and Reliant Energy Coolwater, L.L.C. (collectively, Reliant); and Duke Energy Trading and Marketing, L.L.C.,
Duke Energy Morro Bay, L.L.C., Duke Energy Moss Landing, L.L.C., Duke Energy South Bay, L.L.C., Duke Energy
Oakland, L.L.C. (collectively, Duke). While varying in some particulars, these cases made a common claim that Reliant,
Duke and certain others (not including IE or IPC) colluded to influence the price of electricity in the California wholesale
electricity market. Plaintiffs asserted various claims that the defendants violated California Antitrust Law (the Cartwright
Act), Business & Professions Code Section 16720, et seq., and California's Unfair Competition Law, Business &
Professions Code Section 17200, et seq. Among the acts complained of are bid rigging, information exchanges,
withholding of power, and various other wrongful acts. These actions were subsequently consolidated, resulting in the
filing of Plaintiffs' Master Complaint (PMC) in San Diego Superior Court on March 8, 2002.
On April 22, 2002, more than a year after the initial complaints had been filed, two of the original defendants, Duke and
Reliant, filed separate cross-complaints against IPC and IE, and approximately 30 other cross-defendants. Duke and
Reliant's cross-complaints seek indemnity from IPC, IE and the other cross-defendants for an unspecified share of any
amounts they must pay in the underlying suits because, they allege, other market participants like IPC and IE engaged in
the same conduct at issue in the PMC. Duke and Reliant also seek declaratory relief as to the respective liability and
conduct of each of the cross-defendants in the actions alleged in the PMC. Reliant has also asserted a claim against IPC
for alleged violations of the California Unfair Competition Law, Business and Professions Code Section 17200, et seq.
As a buyer of electricity in California, Reliant seeks the same relief from the cross-defendants, including IPC, as that
sought by plaintiffs in the PMC as to any power Reliant purchased through the California markets.
Some of the newly added defendants (foreign citizens and federal agencies) removed that litigation to federal court. IPC
and IE, together with numerous other defendants added by the cross-complaints, have moved to dismiss these claims, and
those motions were heard in September 2002, together with motions to remand the case back to state court filed by the
original plaintiffs. On December 13, 2002, the Federal District Court granted Plaintiffs' Motion to Remand to State
Court, and Defendants' Motion to Stay the Remand Order while they appeal the Order. As a result of the various
motions, no trial date is set at this time. The companies cannot predict the outcome of this proceeding, nor can they
evaluate the merits of any of the claims at this time but they intend to vigorously defend this lawsuit.
Idaho Rivers United: On December 10, 2002, Idaho Rivers United filed a complaint against IPC in U.S. District Court
for the District of Idaho. The complaint alleges that IPC violated the Clean Water Act by discharging an amount of
dredged and fill material into the navigable waters of the Snake River in excess of that allowed by a Section 404 permit
issued by the U.S. Army Corps of Engineers. The action relates to work completed by IPC, pursuant to a Section 404
permit issued by the Corps on September 3, 1999, in the area of the tailrace downstream of IPC's Bliss hydroelectric
project on the Snake River in Idaho. Idaho Rivers United asks the court to impose civil penalties on IPC under sections
309(d) and 505(a) of the Clean Water Act [33 U.S.C. Sections 1319(d) and 1365(a)], require IPC to pay for any remedial
or restoration work necessary to amend any environmental harm caused by the alleged violation, and pay reasonable
attorney fees. IPC received an extension of time in which to respond to the complaint and is having settlement
discussions with Idaho Rivers United.
FERC FORM NO. 1 (ED. 12-88)Page 123.10
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/30/2003
Year of Report
Dec 31, 2002
NOTES TO FINANCIAL STATEMENTS (Continued)
IPC cannot predict the outcome of this proceeding, nor can it evaluate the merits of any of the claims at this time but it
intends to vigorously defend this lawsuit.
California Energy Situation: As a component of IPC's non-utility energy trading in the state of California, IPC, in
January 1999, entered into a participation agreement with the California Power Exchange (CalPX), a California
non-profit public benefit corporation. The CalPX, at that time, operated a wholesale electricity market in California by
acting as a clearinghouse through which electricity was bought and sold. Pursuant to the participation agreement, IPC
could sell power to the CalPX under the terms and conditions of the CalPX Tariff. Under the participation agreement, if
a participant in the CalPX exchange defaulted on a payment to the exchange, the other participants were required to pay
their allocated share of the default amount to the exchange. The allocated shares were based upon the level of trading
activity, which included both power sales and purchases, of each participant during the preceding three-month period.
On January 18, 2001, the CalPX sent IPC an invoice for $2 million - a "default share invoice" - as a result of an alleged
Southern California Edison (SCE) payment default of $215 million for power purchases. IPC made this payment. On
January 24, 2001, IPC terminated the participation agreement. On February 8, 2001, the CalPX sent a further invoice for
$5 million, due February 20, 2001, as a result of alleged payment defaults by SCE, Pacific Gas and Electric Company
(PG&E) 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 8th invoice. IPC essentially discontinued energy trading with CalPX and
the California Independent System Operator (Cal ISO) in December 2000.
IPC believes that the default invoices were not proper and that IPC owes no further amounts to the CalPX. IPC has
pursued all available remedies in its efforts to collect amounts owed to it by the CalPX. On February 20, 2001, IPC filed
a petition with FERC to intervene in a proceeding that requested the FERC to suspend the use of the CalPX charge back
methodology and provides for further oversight in the CalPX's implementation of its default mitigation procedures.
A preliminary injunction was granted by a Federal Judge in the Federal District Court for the Central District of
California enjoining the CalPX from declaring any CalPX participant in default under the terms of the CalPX Tariff. On
March 9, 2001, the CalPX filed for Chapter 11 protection with the U.S. Bankruptcy Court, Central District of California.
In April 2001, PG&E filed for bankruptcy. The CalPX and Cal ISO were among the creditors of PG&E. To the extent
that PG&E's bankruptcy filing affects the collectibility of the receivables from the CalPX and Cal ISO, the receivables
from these entities are at greater risk.
The FERC issued an order on April 6, 2001 requiring the CalPX to rescind all chargeback actions related to PG&E's and
SCE's liabilities. Shortly after that time, the CalPX segregated the CalPX chargeback amounts it had collected in a
separate account. The CalPX claims it is awaiting further orders of the FERC and the bankruptcy court before
distributing the funds that it collected under its chargeback tariff mechanism. Although certain parties to the California
refund proceeding urged the FERC's Presiding Administrative Law Judge to consider the chargeback amounts in his
determination of who owes what to whom, in his Certification of Proposed Findings on California Refund Liability, he
concluded that the matter already was pending before the FERC for disposition.
Also in April 2001, the FERC issued an order stating that it was establishing price mitigation for sales in the California
wholesale electricity market. Subsequently, in its June 19, 2001 order, the FERC expanded that price mitigation plan to
the entire western United States electrically interconnected system. That plan included the potential for orders directing
electricity sellers into California since October 2, 2000 to refund portions of their spot market sales prices if the FERC
determined that those prices were not just and reasonable, and therefore not in compliance with the Federal Power Act.
The June 19 order also required all buyers and sellers in the Cal ISO market during the subject time-frame to participate
FERC FORM NO. 1 (ED. 12-88)Page 123.11
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/30/2003
Year of Report
Dec 31, 2002
NOTES TO FINANCIAL STATEMENTS (Continued)
in settlement discussions to explore the potential for resolution of these issues without further FERC action. The
settlement discussions failed to bring resolution of the refund issue and as a result, the FERC's Chief Administrative Law
Judge submitted a Report and Recommendation to the FERC recommending that the FERC adopt the methodology set
forth in the report and set for evidentiary hearing an analysis of the Cal ISO's and the CalPX's spot markets to determine
what refunds may be due 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. As to potential refunds, if any, IE believes its exposure is likely
to be offset by amounts due from California entities. Multiple parties have filed requests for rehearing and petitions for
review. The latter--more than 60--have been consolidated by the United States Court of Appeals for the Ninth Circuit and
held in abeyance while the FERC continues its deliberations. The Ninth Circuit also directed the FERC to permit the
parties to adduce additional evidence respecting market manipulation and although the California Parties (the California
Attorney General, other state agencies and the California Investor Owned Utilities) have requested specific procedures to
implement that requirement, the FERC has not yet acted on that request.
On November 20, 2002, the FERC issued an order allowing the parties to the California refund proceeding to conduct
discovery for one hundred days into market manipulation by various sellers during the Western power crises of 2000 and
2001. At the conclusion of the discovery period parties alleging market manipulation are to submit their claims to the
FERC and parties have until March 20, 2003 to submit evidence or comments in response, including assertions that
cross-examination is warranted.
This case had been further complicated by an August 13, 2002 FERC staff (Staff) Report which included the
recommendation to replace the published California indices for gas prices that the FERC previously established as just
and reasonable for calculating a Mitigated Market Clearing Price (MMCP) to calculate refunds with other published
indices for producing basin prices plus a transportation allowance. Staff's recommendation is grounded on speculation
that some sellers had an incentive to report exaggerated prices to publishers of the indices, resulting in overstated
published index prices. Staff bases its speculation in large part on a statistical correlation analysis of Henry Hub and
California prices. If FERC accepts the Staff recommendation, the total amount of refunds could roughly double over
earlier estimates. IE, in conjunction with others, submitted comments on the Staff recommendation - asserting that Staff's
conclusions were incorrect in part on the basis of the fact that the Staff's correlation study ignored evidence of normal
market forces and scarcity which created the pricing variations which Staff observed, rather than improper manipulation
of reported prices. Beyond soliciting comments on the Staff recommendation, the FERC has not decided whether or how
to proceed with consideration of a change in the gas pricing methodology which it previously approved.
Based upon that order and subject to possible modification based upon revision of the gas indices to be used, the Cal ISO
would then be directed by the FERC to calculate revised refund amounts due from sellers of spot market power into the
CalPX and Cal ISO during the refund period.
The Administrative Law Judge issued a Certification of Proposed Findings on California Refund Liability on December
12, 2002. The FERC has indicated the intention to largely conclude work on the California refund matters, including
Judge Birchman's decision, the gas pricing component of its MMCP methodology and claims of market manipulation,
before the end of the first quarter of 2003.
On March 3, 2003, a group of California parties, including the California Attorney General, the California Public Utilities
Commission, the California Electricity Oversight Board, SCE and PG&E, filed materials with the FERC claiming that
wholesale power suppliers manipulated the California market during 2000-2001. They seek approximately $8 billion in
FERC FORM NO. 1 (ED. 12-88)Page 123.12
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/30/2003
Year of Report
Dec 31, 2002
NOTES TO FINANCIAL STATEMENTS (Continued)
refunds for the state's ratepayers. A number of wholesale power suppliers were named in the filings, including IPC. IPC
intends to vigorously defend in this matter, but they are unable to predict the outcome of this proceeding.
In addition, the July 25, 2001 FERC order established 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 (ALJ) submitted recommendations and findings to the FERC on
September 24, 2001. The ALJ 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 ALJ's decision is a recommendation to the commissioners of the FERC. Multiple
parties have submitted comments to the FERC respecting the ALJ's recommendations. The ALJ's recommended findings
are pending at the FERC. The City of Tacoma and the Port of Seattle requested that the docket be reopened to allow the
submission of additional evidence related to alleged manipulation of the power market by Enron and others. IE opposed
that request. By order issued December 19, 2002, the FERC reopened the docket to allow interested parties to take
additional discovery and present additional evidence related to alleged market manipulation and its intent on spot market
sales in the Pacific Northwest. As is the case in the California refund proceeding, at the conclusion of the discovery
period, parties alleging market manipulation are to submit their claims to the FERC and parties have until March 20,
2003 to submit evidence or comments in response, including assertions that cross-examination is warranted. Grays
Harbor, whose civil litigation claims were dismissed, as noted above, has injected itself into the FERC proceedings
asserting in discovery requests that its six month forward contract, for which performance has been completed, should be
treated as a spot market contract for purposes of the FERC's consideration of refunds. Grays Harbor filed testimony on
March 3, 2003 requesting refunds from IPC of $5 million. The company intends to defend vigorously.
In addition, the Port of Seattle, the City of Tacoma and Seattle City Light 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. These parties did not suggest any misconduct by IE or IPC. IE and IPC expect
to defend against these generic claims, but are unable to predict the outcome of this matter.
IPC transferred its non-utility wholesale electricity marketing operations to IE in June 2001 effective June 1, 2001.
Effective with this transfer, the outstanding receivables and payables with the CalPX and Cal ISO were assigned from
IPC to IE. At December 31, 2002, the CalPX and Cal ISO owed IE $14 million and $30 million, respectively, for energy
sales made to them by IPC in November and December 2000. IE has accrued a reserve of $42 million against these
receivables.
Washington Retail Consumer Class Action Complaint: The complaint in this case was filed on December 20, 2002 in
the United States District Court for the Western District of Washington at Seattle, against various entities, including IPC.
The complaint was served on IPC on February 3, 2003. This action seeks class action status on behalf of all persons and
businesses residing in Washington who were purchasers of electrical and/or natural gas energy from any period beginning
in January 2000 to the present. The complaint alleges claims under the Washington Consumer Protection Act, RCW
19.86, as well as common law claims of fraud by concealment, negligence and for an accounting. The complaint asserts
that the defendants, including IPC, engaged in, among other things, unfair and deceptive acts, in violation of the Federal
Power Act, by (a) withholding the supply of energy; (b) misrepresenting the amount of its energy supplies; (c) exercising
improper control over the energy markets; and (d) manipulating the price of energy markets resulting in energy rates
being unjust, unreasonable and unlawful. The plaintiff seeks certification of a class action, equitable and injunctive
relief, an accounting, treble damages, attorneys' fees and costs. On February 3, 2003, another defendant, Reliant, moved
to transfer the case to the Judge who is presiding over MDL No. 1405. IPC's response to the complaint is due within 30
days from the date of service. IPC intends to vigorously defend against this lawsuit and believes this matter will not have
FERC FORM NO. 1 (ED. 12-88)Page 123.13
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/30/2003
Year of Report
Dec 31, 2002
NOTES TO FINANCIAL STATEMENTS (Continued)
a material adverse effect on its financial position, results of operations or cash flows.
Oregon Retail Consumer Class Action Complaint: The complaint in this case was filed on December 16, 2002 in the
Circuit Court of the State of Oregon for the County of Multnomah, against various entities, including IPC. The complaint
was served on IPC on February 7, 2003. The case was removed by another defendant, Reliant, to the United States
District Court, District of Oregon on February 4, 2003. The complaint seeks class action status on behalf of all persons
and businesses residing in Oregon who were purchasers of electrical and/or natural gas energy from any period beginning
in January 2000 to the present. The complaint alleges claims under the Oregon Unfair Trade Practices Act, ORS 646.605
et seq. in addition to claims of fraud by concealment, negligence and for an accounting. The complaint asserts that the
defendants, including IPC, engaged in, among other things, unfair and deceptive acts, in violation of the Federal Power
Act, by (a) withholding the supply of energy; (b) misrepresenting the amount of its energy supplies; (c) exercising
improper control over the energy markets; and (d) manipulating the price of energy markets resulting in energy rates
being charged to Oregon energy consumers that were unjust, unreasonable and unlawful. The plaintiff seeks certification
of a class action, equitable and injunctive relief, an accounting, attorneys' fees and costs. The action was recently
removed to federal court, and IPC intends to seek an extension of time to respond. IPC intends to vigorously defend
against this lawsuit and believes this matter will not have a material adverse effect on its financial position, results of
operations or cash flows.
8. STOCK-BASED COMPENSATION:
IPC participates in two stock-based compensation plans of IDACORP that are intended to align employee and
shareholders objectives related to the long-term growth of IPC.
IDACORP adopted the 2000 Long Term Incentive and Compensation Plan (LTICP) for officers, key employees and
directors including those of IPC. The LTICP 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.
Stock option transactions are summarized as follows:
2002 2001
Weighted Weighted
Number average Number average
of exercise of exercise
shares price shares price
Outstanding beginning of year 477,000 $37.79 220,000 $35.81
Granted 244,950 39.50 257,000 39.48
Exercised - - - -
Cancelled ----
Outstanding end of year 721,950 $38.37 477,000 $37.79
Exercisable 139,400 $37.16 44,000 $35.81
The outstanding options have a range of exercise prices from $35.81 to $40.31. As of December 31, 2002, the weighted
average remaining contractual life is 8.3 years.
FERC FORM NO. 1 (ED. 12-88)Page 123.14
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/30/2003
Year of Report
Dec 31, 2002
NOTES TO FINANCIAL STATEMENTS (Continued)
IDACORP also has a restricted stock plan for certain key employees including those of IPC. Each grant made under this
plan has a three-year restricted period, and the final award amounts depend on the attainment of cumulative EPS
performance goals. At December 31, 2002 there were 201,539 IDACORP shares remaining available under this plan.
Restricted stock awards are compensatory awards and IPC accrues compensation expense (which is charged to
operations) based upon the market value of the granted shares. For the years 2002 and 2001, total compensation accrued
under the plan was less than $1 million annually.
The following table summarizes restricted stock activity for the years 2002 and 2001:
2002 2001
Shares outstanding - beginning of year 53,878 52,719
Shares granted 37,197 20,311
Shares forfeited (179)(474)
Shares issued (18,767)(18,678)
Shares outstanding - end of year 72,129 53,878
Weighted average fair value of current year
stock grants on grant date $38.64 $38.02
9. BENEFIT PLANS:
Pension Plans
IPC has a noncontributory defined benefit pension plan covering most employees. The benefits under the plan are based
on years of service and the employee's final average earnings. IPC's policy is to fund with an independent corporate
trustee at least the minimum required under the Employee Retirement Income Security Act of 1974 but not more than the
maximum amount deductible for income tax purposes. IPC was not required to contribute to the plan in 2002 and 2001.
The trustee invests the plan assets primarily in listed stocks (both U.S. and foreign), fixed income securities and
investment grade real estate.
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 shows the components of net periodic benefit cost for these plans:
Deferred Compensation
Pension Plan Plan
2002 2001 2002 2001
(in thousands of dollars)
Service cost $9,548 $7,978 $944 $624
Interest cost 18,684 17,634 2,108 2,039
Expected return on assets (28,797)(30,117)- -
FERC FORM NO. 1 (ED. 12-88)Page 123.15
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/30/2003
Year of Report
Dec 31, 2002
NOTES TO FINANCIAL STATEMENTS (Continued)
Recognized net actuarial (gain) loss - (3,179)498 281
Amortization of prior service cost 729 708 (353)(345)
Amortization of transition asset (263)(263)613 613
Net periodic pension (benefit) cost $(99)$(7,239)$3,810 $3,212
The following table summarizes the changes in benefit obligation and plan assets of these plans:
Pension Plan Deferred Compensation Plan
2002 2001 2002 2001
(in thousands of dollars)
Change in projected benefit obligation:
Benefit obligation at January 1 $273,208 $241,281 $30,405 $27,876
Service cost 9,548 7,978 944 624
Interest cost 18,684 17,634 2,108 2,039
Actuarial loss (gain)6,823 18,560 4,490 2,352
Benefits paid (13,382)(12,586)(2,507)(2,420)
Plan amendments - 341 352 (66)
Benefit obligation at December 31 294,881 273,208 35,792 30,405
Change in plan assets:
Fair value at January 1 326,266 340,789 - -
Actual return on plan assets (30,353)(1,936)- -
Employer contributions - - - -
Benefit payments (13,382)(12,586)- -
Fair value at December 31 282,531 326,267 - -
Funded status (12,350)53,059 (35,792)(30,405)
Unrecognized actuarial loss (gain)34,116 (31,857)12,505 8,513
Unrecognized prior service cost 6,860 7,589 630 (75)
Unrecognized net transition liability (652)(916)1,536 2,149
Net amount recognized $27,974 $27,875 $(21,121)$(19,818)
Amounts recognized in the statement of
financial position consist of:
Prepaid (accrued) pension cost $27,974 $27,875 $(33,120)$(28,500)
Intangible asset - - 2,166 2,074
Accumulated other comprehensive income - - 9,833 6,608
Net amount recognized $27,974 $27,875 $(21,121)$(19,818)
The following table sets forth the assumptions used at the end of each year for all IPC-sponsored pension and
postretirement benefit plans:
Pension Benefits Postretirement Benefits
2002 2001 2002 2001
Discount rate 6.75%7.0%6.75%7.0%
Expected long-term rate of return on assets 8.5 9.0 8.5 9.0
Annual salary increases 4.5 4.5 - -
FERC FORM NO. 1 (ED. 12-88)Page 123.16
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/30/2003
Year of Report
Dec 31, 2002
NOTES TO FINANCIAL STATEMENTS (Continued)
Employee Savings Plan
IPC has an Employee Savings Plan which complies with Section 401(k) of the Internal Revenue Code and covers
substantially all employees. IPC matches specified percentages of employee contributions to the plan. Matching
contributions amounted to $4 million in each of 2002 and 2001.
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, their spouses and qualifying dependents.
The net periodic postretirement benefit cost was as follows (in thousands of dollars):
2002 2001
Service cost $927 $831
Interest cost 3,648 3,589
Expected return on plan assets (2,320)(2,343)
Amortization of unrecognized transition obligation 2,040 2,040
Amortization of prior service cost (563)(563)
Recognized actuarial (gain)/loss 487 -
Net periodic post-retirement benefit cost $4,219 $3,554
The following table summarizes the changes in benefit obligation and plan assets (in thousands of dollars):
2002 2001
Change in accumulated benefit obligation:
Benefit obligation at January 1 $53,650 $48,806
Service cost 927 831
Interest cost 3,648 3,589
Plan amendments - 600
Actuarial loss 2,029 3,296
Benefits paid (2,987)(3,472)
Benefit obligation at December 31 57,267 53,650
Change in plan assets:
Fair value of plan assets at January 1 25,184 26,071
Actual (loss) return on plan assets (3,837)(2,004)
Employer contributions 4,262 4,413
Benefits paid (3,087)(3,296)
Fair value of plan assets at December 31 22,522 25,184
Funded status (34,745)(28,466)
Unrecognized prior service cost (5,610)(6,173)
Unrecognized actuarial loss (gain)18,627 10,828
Unrecognized transition obligation 20,400 22,440
Accrued benefit obligations included with other deferred credits $(1,328)$(1,371)
FERC FORM NO. 1 (ED. 12-88)Page 123.17
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/30/2003
Year of Report
Dec 31, 2002
NOTES TO FINANCIAL STATEMENTS (Continued)
The assumed health care cost trend rate used to measure the expected cost of benefits covered by the plan is 6.75%. A
one-percentage point change in the assumed health care cost trend rate would have the following effect (in thousands of
dollars):
1-Percentage-Point 1-Percentage-Point
increase decrease
Effect on total of service and interest cost components $261 $(204)
Effect on accumulated postretirement benefit obligation $2,477 $(2,008)
Postemployment Benefits
IPC provides certain benefits to former or inactive employees, their beneficiaries and covered dependents after
employment but before retirement. These benefits include salary continuation, health care and life insurance for those
employees found to be disabled under IPC's disability plans and health care for surviving spouses and dependents. IPC
accrues a liability for such benefits. In accordance with an IPUC order, the portion of the liability attributable to
regulated activities in Idaho as of December 31, 1993, was deferred as a regulatory asset, and is being amortized over ten
years.
The following table summarizes postemployment benefit amounts included in IPC's balance sheets at December 31 (in
thousands of dollars):
2002 2001
Included with regulatory assets $698 $1,032
Included with other deferred credits $(2,941)$(3,010)
10. UTILITY PLANT IN SERVICE 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 2002 and 2001 (in
thousands of dollars):
2002 2001
Balance Avg Rate Balance Avg Rate
Production $1,433,627 2.63%$1,424,777 2.58%
Transmission 485,349 2.30 460,149 2.30
Distribution 902,985 3.31 854,445 3.34
General and Other 265,004 6.16 250,259 6.12
Total in service 3,086,965 3.00%2,989,630 2.98%
Accumulated provision for depreciation (1,294,961)(1,220,002)
In service - net $1,792,004 $1,769,628
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 Statements of Income. These
facilities, and the extent of IPC's participation, are as follows at December 31, 2002:
FERC FORM NO. 1 (ED. 12-88)Page 123.18
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/30/2003
Year of Report
Dec 31, 2002
NOTES TO FINANCIAL STATEMENTS (Continued)
Company Ownership
Utility Construction Accumulated
Plant In Work in Provision for
Name of Plant Location Service Progress Depreciation %MW
(thousands of dollars)
Jim Bridger Units 1-4 Rock Springs, WY $410,694 $306 $233,367 33 707
Boardman Boardman, OR 64,613 4,865 40,274 10 55
Valmy Units 1 and 2 Winnemucca, NV 303,157 3,283 164,995 50 261
IPC's wholly owned subsidiary, Idaho Energy Resources Company, is a joint venturer in Bridger Coal Company, which
operates the mine supplying coal for the Jim Bridger steam generation plant. Coal purchased by IPC from the joint
venture amounted to $44 million in 2002 and $43 million in 2001.
IPC has contracts to purchase the energy from four Public Utilities Regulatory Policy Act Qualified Facilities that are 50
percent owned by Ida-West. Power purchased from these facilities amounted to $7 million in 2002 and $6 million in
2001.
11. REGULATORY MATTERS:
Wind Down of Energy Marketing
IDACORP announced on June 21, 2002 that IE would wind down its power marketing operations. In connection with the
wind down, certain matters were identified that require resolution with the FERC or the IPUC. Matters that need to be
resolved with the FERC include:
A utility such as IPC is entitled to transmission priority for its retail customers, while transmission for trading
transactions must be purchased under the utility's open access tariff on the same basis as third parties. It appears
that in some transactions this distinction was not observed;
Certain transactions between a utility and an affiliate are required to have prior FERC approval. Such prior
approval was not sought for some electricity transactions between IE and IPC, such as spinning reserves and load
following services, which are common industry services; and
Although IPC informed the FERC before IE was split off from IPC that it intended to move the utility's power
marketing business to IE, IPC's power marketing contracts were assigned without formally obtaining the requisite
prior approval of the FERC.
IE and IPC voluntarily contacted the FERC in September 2002 to discuss these matters. Since September, the FERC has
made several requests for certain documents and other information all of which, except for those requests which have
been deferred, IE and IPC have supplied. IE and IPC made additional filings with the FERC in November 2002, which
included requests for approval of certain electricity transactions, the assignment of certain contracts between IPC and IE
and termination of the Electricity Supply Management Services Agreement entered into between IPC and IE in June
2001.
On February 26, 2003, the FERC approved the assignment of certain wholesale power and transmission services
agreements from IPC to IE. The FERC also found that IPC violated Section 203 of the Federal Power Act (FPA) by
assigning the agreements in June 2001 without seeking prior approval from the FERC. The FERC noted that
noncompliance with Section 203 of the FPA may prompt the FERC in certain instances to impose remedies as a condition
of its approval; however, no such remedies were imposed in the FERC order.
FERC FORM NO. 1 (ED. 12-88)Page 123.19
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/30/2003
Year of Report
Dec 31, 2002
NOTES TO FINANCIAL STATEMENTS (Continued)
Should the FERC conclude that its regulations or rate schedules were not complied with, it has significant discretion as to
the appropriate remedies, if any. The FERC's remedial authority includes the authority to require refunds, to order
equitable relief, to suspend the authorization to sell wholesale power at market-based rates, and, in some instances, to
impose monetary penalties.
In an IPUC proceeding that has been underway since May 2001, IPC and the IPUC staff have been working to determine
the appropriate compensation IE should provide to IPC as a result of transactions between the affiliates. Similar state
regulatory issues relating to the period prior to February 2001 were determined by the IPUC in Order No. 28852 issued
on September 28, 2001. The IPUC ruled on these transactions again in Order No. 29026 for the time period from March
2001 through March 2002. The IPUC also approved IPC's ongoing hedging and risk management strategies in Order No.
29102 issued August 28, 2002. This formalized IPC's agreement to implement a number of changes to its existing
practices for managing risk and initiating hedging purchases and sales. In the same order, the IPUC directed IPC to
present a resolution or a status report to the IPUC no later than December 20, 2002 on additional compensation due to the
utility for the use of its transmission system and other capital assets by IE and any remaining transfer pricing issues. On
December 20, 2002, a status report was filed with the IPUC reporting no significant developments. IPC committed to
providing another status report to the IPUC on March 20, 2003.
IDACORP does not believe that resolution of these transactions will have any adverse impact on its ongoing operations.
However, because it cannot be predicted at this point what regulatory actions might be taken or when, it cannot be
determined what effect there may be on earnings and whether it will be material.
As previously disclosed, the FERC filing made on May 14, 2001, with respect to the pricing of real-time energy
transactions between IPC and IE, is still under review by the FERC. For the period June 2001 through March 2002, IE
paid IPC approximately $6 million, which was calculated based upon the pricing methodology for the period that was
most favorable to IPC. This amount was credited to Idaho retail customers through the PCA. An additional $1 million
has been paid to IPC for the period April 2002 through July 2002 based upon the same pricing methodology. However,
until the FERC takes final action on this filing, rates for real-time transactions between IE and IPC are subject to
adjustment.
However on April 15, 2003 annual PCA filing with the IPUC, IPC included some additional compensation related to one
of the issues, in anticipation of settlement with the FERC. As a result of the anticipated FERC settlement, IE paid IPC an
additional $2 million for spinning reserves and load following services. IPC proposed that the additional compensation be
flowed through the 2003-2004 PCA. Other state regulatory issues are expected to be addressed following the conclusion
of the FERC review.
Deferred Power Supply Costs
IPC's deferred power supply costs consist of the following at December 31, 2002 and 2001 (in thousands of dollars):
2002 2001
Oregon deferral $14,172 $14,866
Idaho PCA current year power supply cost deferrals:
Deferral for 2001-2002 rate year -78,395
Deferral for 2002-2003 rate year 8,910 -
Irrigation load reduction program -69,586
Astaris load reduction agreement 27,160 62,247
FERC FORM NO. 1 (ED. 12-88)Page 123.20
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/30/2003
Year of Report
Dec 31, 2002
NOTES TO FINANCIAL STATEMENTS (Continued)
Idaho PCA true-up awaiting recovery:
Irrigation and small general service deferral for recovery in
the 2003-2004 rate year 12,049 -
Industrial customer deferral for recovery in the 2003-2004 rate year 3,744 -
Remaining true-up authorized October 2001 -36,500
Remaining true-up authorized May 2001 -42,895
Remaining true-up authorized May 2002 74,253 -
Total deferral $140,288 $304,489
Idaho: IPC has a PCA mechanism that provides for annual adjustments to the rates charged to its Idaho retail customers.
These adjustments, which take effect in May, are based on forecasts of net power supply expenses 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 a true-up, is then included in the calculation of the next year's PCA
adjustment.
So far in the 2002-2003 PCA rate year actual power supply costs have exceeded those anticipated in the forecast. Below
normal water conditions are still impacting power supply costs even though power supply prices are significantly lower.
In addition an Irrigation Load Reduction Program was completed in the 2001-2002 PCA rate year and the Astaris
Voluntary Load Reduction costs have decreased, both reducing the PCA regulatory account balance from $290 million as
of December 31, 2001 to $126 million as of December 31, 2002.
On May 13, 2002, the IPUC issued Order No. 29026 related to the 2002-2003 PCA rate filing. The order granted
recovery of $255 million of excess power supply costs, consisting of:
$209 million of voluntary load reduction and power supply costs incurred between March 1, 2001 and March 31,
2002.
$28 million of excess power supply costs forecasted for the period April 2002 through March 2003.
$18 million of unamortized costs previously approved for recovery beginning October 1, 2001. The amount
authorized in October 2001 totaled $49 million. This order spreads the remaining October 2001 rate increase,
which would have ended in September 2002, through May 2003.
The order also:
Denied recovery of $12 million of lost revenues resulting from the Irrigation Load Reduction Program, and $2
million of other costs IPC sought to recover.
Deferred recovery of $12 million of costs related to irrigation and small general service customers. In June
2002, the IPUC issued Order No. 29065 deferring an additional $4 million applicable to certain industrial
customers. The $16 million will be recovered during the 2003-2004 PCA rate year, and IPC will earn a six
percent carrying charge on the balance.
Denied IPC's request to issue $172 million in Energy Cost Recovery Bonds, which would have spread the
recovery of that amount over three years.
Discontinued the IPUC-required three-tiered rate structure for residential customers.
Authorized a separate surcharge to collect approximately $3 million annually to fund future conservation
programs.
The IPUC had previously issued Order No. 28992 on April 15, 2002 disallowing the lost revenue portion of the Irrigation
FERC FORM NO. 1 (ED. 12-88)Page 123.21
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/30/2003
Year of Report
Dec 31, 2002
NOTES TO FINANCIAL STATEMENTS (Continued)
Load Reduction Program. IPC believes that the IPUC's order is inconsistent with Order No. 28699, dated May 25, 2001,
that allowed recovery of such costs, and IPC filed a Petition for Reconsideration on May 2, 2002. On August 29, 2002,
the IPUC issued Order No. 29103 denying the Petition for Reconsideration. As a result of this order, approximately $12
million was expensed in September 2002. IPC still believes it should be entitled to receive recovery of this amount and
has asked the Idaho Supreme Court to review the IPUC's decision. If successful, IPC would record any amount recovered
as revenue.
In the May 2001 PCA filing, IPC requested recovery of $227 million of power supply costs. The IPUC subsequently
issued Order No. 28772 authorizing recovery of $168 million, but deferring recovery of $59 million pending further
review. The approved amount resulted in an average rate increase of 31.6 percent. After conducting hearings on the
remaining $59 million, the IPUC in Order No. 28552 authorized recovery of $48 million plus $1 million of accrued
interest, beginning in October 2001. The remaining $11 million not recovered in rates from the PCA filing was written
off in September 2001.
In October 2001, IPC filed an application with the IPUC for an order approving inclusion in the 2002-2003 PCA of costs
incurred for the Irrigation Load Reduction Program and the FMC/Astaris Load Reduction Agreement. These two
programs were implemented in 2001 to reduce demand and were approved by the IPUC and the OPUC. The costs
incurred in 2001 for these two programs were $70 million for the Irrigation Load Reduction Program and $62 million for
the FMC/Astaris Load Reduction Agreement. The IPUC subsequently issued Order No. 28992 authorizing IPC to
include direct costs it has accrued in the programs, subject to later adjustments in the 2002-2003 PCA year. As
mentioned earlier, the IPUC also denied IPC's request to recover lost revenues experienced from the Irrigation Load
Reduction Program.
The May 2000 PCA rate adjustment increased Idaho general business customer rates by 9.5 percent, and resulted from
forecasted below-average hydroelectric generating conditions. Overall, the PCA adjustment increased general business
revenue by approximately $38 million during the 2000-2001 rate period.
Oregon: IPC has also filed applications with the OPUC to recover calendar year 2001 extraordinary power supply costs
applicable to the Oregon jurisdiction. In two separate 2001 orders, the OPUC has approved rate increases totaling six
percent, which is the maximum annual rate of recovery allowed under Oregon state law. These increases are recovering
approximately $2 million annually. The Oregon deferred balance is $14 million as of December 31, 2002.
Regulatory Assets and Liabilities
The following is a breakdown of IPC's regulatory assets and liabilities for the years 2002 and 2001:
2002 2001
Assets Liabilities Assets Liabilities
(thousands of dollars)
Income taxes $327,934 $41,013 $209,832 $41,290
Conservation 24,450 4,402 28,324 3,524
Employee benefits 1,909 -2,825 -
PCA deferral and amortization 126,116 -289,623 -
Oregon deferral and amortization 14,172 -14,866 -
Derivatives 91 -47,781 -
Other 4,634 1,272 5,991 1,126
Deferred investment tax credits -67,560 -68,016
Total $499,306 $114,247 $599,242 $113,956
FERC FORM NO. 1 (ED. 12-88)Page 123.22
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/30/2003
Year of Report
Dec 31, 2002
NOTES TO FINANCIAL STATEMENTS (Continued)
At December 31, 2002, IPC had $3 million of regulatory assets, primarily SFAS 112, "Employers Accounting for
Postemployment Benefits" benefits and reorganization costs, that were not earning a return on investment (excluding the
$328 million that relates to income taxes). The amortization period is three to four years.
In the event that recovery of costs through rates becomes unlikely or uncertain, SFAS 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.
12. RELATED PARTY TRANSACTIONS:
In exchange for the transfer of Energy Marketing to IE in June 2001, IPC received a partnership interest in IE, which was
then transferred to IDACORP in exchange for notes receivable from IDACORP totaling approximately $76 million. This
amount represents the historical book value of the transferred Energy Marketing net assets on May 31, 2001 of $21
million and retained intercompany tax liabilities of $55 million. The notes receivable are due over periods of one to ten
years and bear interest at IDACORP's overall variable short-term borrowing rate, which was 1.8 percent at December 31,
2002. The balance of this note at December 31, 2002 is approximately $22 million, including accrued interest.
In September 2002, IPC borrowed $100 million from IDACORP in order to repay a like amount of floating rate notes.
This amount was repaid, with interest, on November 15, 2002.
In 2002 and 2001, IPC paid IE approximately $2 million annually under the Electricity Supply Management Services
Agreement. IPC and IE requested termination of this agreement in a November 2002 FERC filing.
The following table presents IPC's sales to and purchases from IE for the years ended December 31:
2002 2001
(thousands of dollars)
Sales to IE $27,182 $21,288
Purchases from IE 13,665 34,843
FERC FORM NO. 1 (ED. 12-88)Page 123.23
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS
Idaho Power Company X
04/30/2003
2002
Line
No.(b)(a)
Classification Total Electric
(c)
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Utility Plant 1
In Service 2
3,087,419,093 3,087,419,093Plant in Service (Classified) 3
Property Under Capital Leases 4
Plant Purchased or Sold 5
Completed Construction not Classified 6
Experimental Plant Unclassified 7
3,087,419,093 3,087,419,093Total (3 thru 7) 8
Leased to Others 9
2,335,078 2,335,078Held for Future Use 10
92,481,654 92,481,654Construction Work in Progress 11
-454,449 -454,449Acquisition Adjustments 12
3,181,781,376 3,181,781,376Total Utility Plant (8 thru 12) 13
1,294,961,078 1,294,961,078Accum Prov for Depr, Amort, & Depl 14
1,886,820,298 1,886,820,298Net Utility Plant (13 less 14) 15
Detail of Accum Prov for Depr, Amort & Depl 16
In Service: 17
1,269,613,653 1,269,613,653Depreciation 18
Amort & Depl of Producing Nat Gas Land/Land Right 19
Amort of Underground Storage Land/Land Rights 20
25,584,115 25,584,115Amort of Other Utility Plant 21
1,295,197,768 1,295,197,768Total In Service (18 thru 21) 22
Leased to Others 23
Depreciation 24
Amortization and Depletion 25
Total Leased to Others (24 & 25) 26
Held for Future Use 27
Depreciation 28
Amortization 29
Total Held for Future Use (28 & 29) 30
Abandonment of Leases (Natural Gas) 31
-236,690 -236,690Amort of Plant Acquisition Adj 32
1,294,961,078 1,294,961,078Total Accum Prov (equals 14) (22,26,30,31,32) 33
FERC FORM NO. 1 (ED. 12-89)Page 200
(g)
Common
(h)
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS
Idaho Power Company X
04/30/2003
2002
Line
No.
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Gas Other (Specify)
(d)(e)(f)
Other (Specify)Other (Specify)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
FERC FORM NO. 1 (ED. 12-89)Page 201
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
NUCLEAR FUEL MATERIALS (Account 120.1 through 120.6 and 157)
Idaho Power Company X
04/30/2003
2002
Line
No.
Description of item Balance
(c)(b)(a)
Changes during YearBeginning of Year Additions
1. Report below the costs incurred for nuclear fuel materials in process of fabrication, on hand, in reactor, and in cooling; owned by the
respondent.
2. If the nuclear fuel stock is obtained under leasing arrangements, attach a statement showing the amount of nuclear fuel leased, the
quantity used and quantity on hand, and the costs incurred under such leasing arrangements.
Nuclear Fuel in process of Refinement, Conv, Enrichment & Fab (120.1) 1
Fabrication 2
Nuclear Materials 3
Allowance for Funds Used during Construction 4
(Other Overhead Construction Costs, provide details in footnote) 5
SUBTOTAL (Total 2 thru 5) 6
Nuclear Fuel Materials and Assemblies 7
In Stock (120.2) 8
In Reactor (120.3) 9
SUBTOTAL (Total 8 & 9) 10
Spent Nuclear Fuel (120.4) 11
Nuclear Fuel Under Capital Leases (120.6) 12
(Less) Accum Prov for Amortization of Nuclear Fuel Assem (120.5) 13
TOTAL Nuclear Fuel Stock (Total 6, 10, 11, 12, less 13) 14
Estimated net Salvage Value of Nuclear Materials in line 9 15
Estimated net Salvage Value of Nuclear Materials in line 11 16
Est Net Salvage Value of Nuclear Materials in Chemical Processing 17
Nuclear Materials held for Sale (157) 18
Uranium 19
Plutonium 20
Other (provide details in footnote): 21
TOTAL Nuclear Materials held for Sale (Total 19, 20, and 21) 22
FERC FORM NO. 1 (ED. 12-89)Page 202
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
NUCLEAR FUEL MATERIALS (Account 120.1 through 120.6 and 157)
Idaho Power Company X
04/30/2003
2002
Line
No.
Balance
(f)(e)(d)
Changes during Year
End of YearAmortizationOther Reductions (Explain in a footnote)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
FERC FORM NO. 1 (ED. 12-89)Page 203
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106)
Idaho Power Company X
04/30/2003
2002
Line
No.
Account Balance Additions
(c)(b)(a)
Beginning of Year
1. Report below the original cost of electric plant in service according to the prescribed accounts.
2. In addition to Account 101, Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant Purchased or Sold;
Account 103, Experimental Electric Plant Unclassified; and Account 106, Completed Construction Not Classified-Electric.
3. Include in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year.
4. Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such accounts.
5. Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in column (c). Also to be included
in column (c) are entries for reversals of tentative distributions of prior year reported in column (b). Likewise, if the respondent has a significant amount
of plant retirements 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)
reversals of tentative distributions of prior year of unclassified retirements. Show in a footnote the account distributions of these tentative classifications
in columns (c) and (d), including the reversals of the prior years tentative account distributions of these amounts. Careful observance of the above
1 1. INTANGIBLE PLANT
5,703 9,093 2 (301) Organization
7,986,088 -776,660 3 (302) Franchises and Consents
52,886,199 7,273,666 4 (303) Miscellaneous Intangible Plant
60,877,990 6,506,099 5 TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)
6 2. PRODUCTION PLANT
7 A. Steam Production Plant
1,275,203 8 (310) Land and Land Rights
128,777,026 331,640 9 (311) Structures and Improvements
443,607,191 6,016,413 10 (312) Boiler Plant Equipment
11 (313) Engines and Engine-Driven Generators
109,330,890 1,050,126 12 (314) Turbogenerator Units
61,467,797 132,208 13 (315) Accessory Electric Equipment
12,574,083 191,055 14 (316) Misc. Power Plant Equipment
757,032,190 7,721,442 15 TOTAL Steam Production Plant (Enter Total of lines 8 thru 14)
16 B. Nuclear Production Plant
17 (320) Land and Land Rights
18 (321) Structures and Improvements
19 (322) Reactor Plant Equipment
20 (323) Turbogenerator Units
21 (324) Accessory Electric Equipment
22 (325) Misc. Power Plant Equipment
23 TOTAL Nuclear Production Plant (Enter Total of lines 17 thru 22)
24 C. Hydraulic Production Plant
13,935,724 25 (330) Land and Land Rights
126,853,319 372,006 26 (331) Structures and Improvements
242,582,952 108,594 27 (332) Reservoirs, Dams, and Waterways
181,422,886 720,648 28 (333) Water Wheels, Turbines, and Generators
34,495,211 993,630 29 (334) Accessory Electric Equipment
13,588,183 270,177 30 (335) Misc. Power PLant Equipment
6,933,691 31 (336) Roads, Railroads, and Bridges
619,811,966 2,465,055 32 TOTAL Hydraulic Production Plant (Enter Total of lines 25 thru 31)
33 D. Other Production Plant
213,791 4,976 34 (340) Land and Land Rights
852,850 353,512 35 (341) Structures and Improvements
1,637,976 36,701 36 (342) Fuel Holders, Products, and Accessories
747,458 17,399 37 (343) Prime Movers
40,868,666 2,013,950 38 (344) Generators
1,193,280 53,872 39 (345) Accessory Electric Equipment
FERC FORM NO. 1 (ED. 12-95)Page 204
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31, Idaho Power Company X
04/30/2003
2002
Line
No.
Account Balance Additions
(c)(b)(a)
Beginning of Year
2,419,087 70,337 40 (346) Misc. Power Plant Equipment
47,933,108 2,550,747 41 TOTAL Other Prod. Plant (Enter Total of lines 34 thru 40)
1,424,777,264 12,737,244 42 TOTAL Prod. Plant (Enter Total of lines 15, 23, 32, and 41)
43 3. TRANSMISSION PLANT
13,887,850 2,856,954 44 (350) Land and Land Rights
29,065,022 -1,298,280 45 (352) Structures and Improvements
184,645,277 19,614,480 46 (353) Station Equipment
55,140,863 2,026,652 47 (354) Towers and Fixtures
80,179,114 1,218,127 48 (355) Poles and Fixtures
96,912,093 5,399,938 49 (356) Overhead Conductors and Devices
50 (357) Underground Conduit
51 (358) Underground Conductors and Devices
318,352 52 (359) Roads and Trails
460,148,571 29,817,871 53 TOTAL Transmission Plant (Enter Total of lines 44 thru 52)
54 4. DISTRIBUTION PLANT
3,437,394 -488,109 55 (360) Land and Land Rights
13,306,974 1,639,108 56 (361) Structures and Improvements
102,170,691 18,604,866 57 (362) Station Equipment
58 (363) Storage Battery Equipment
166,092,613 7,758,051 59 (364) Poles, Towers, and Fixtures
86,633,411 4,296,184 60 (365) Overhead Conductors and Devices
28,582,949 3,105,331 61 (366) Underground Conduit
119,073,667 7,264,137 62 (367) Underground Conductors and Devices
248,883,111 7,601,197 63 (368) Line Transformers
42,622,542 2,364,052 64 (369) Services
37,736,793 2,261,146 65 (370) Meters
2,086,143 167,608 66 (371) Installations on Customer Premises
67 (372) Leased Property on Customer Premises
3,818,844 147,122 68 (373) Street Lighting and Signal Systems
854,445,132 54,720,693 69 TOTAL Distribution Plant (Enter Total of lines 55 thru 68)
70 5. GENERAL PLANT
8,750,596 155,334 71 (389) Land and Land Rights
56,337,128 2,497,684 72 (390) Structures and Improvements
48,986,891 5,889,073 73 (391) Office Furniture and Equipment
37,257,775 6,018,873 74 (392) Transportation Equipment
881,755 130,215 75 (393) Stores Equipment
3,415,716 244,010 76 (394) Tools, Shop and Garage Equipment
8,699,229 252,000 77 (395) Laboratory Equipment
6,270,802 150,444 78 (396) Power Operated Equipment
17,370,676 2,488,210 79 (397) Communication Equipment
1,864,816 148,177 80 (398) Miscellaneous Equipment
189,835,384 17,974,020 81 SUBTOTAL (Enter Total of lines 71 thru 80)
82 (399) Other Tangible Property
189,835,384 17,974,020 83 TOTAL General Plant (Enter Total of lines 81 and 82)
2,990,084,341 121,755,927 84 TOTAL (Accounts 101 and 106)
85 (102) Electric Plant Purchased (See Instr. 8)
86 (Less) (102) Electric Plant Sold (See Instr. 8)
87 (103) Experimental Plant Unclassified
2,990,084,341 121,755,927 88 TOTAL Electric Plant in Service (Enter Total of lines 84 thru 87)
FERC FORM NO. 1 (ED. 12-95)Page 206
(f)
Transfers Balance at
End of Year
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31, Idaho Power Company X
04/30/2003
2002
Line
No.(g)
Adjustments
(e)
Retirements
(d)
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)
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.
6. 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.
7. 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.
8. For each amount comprising the reported balance and changes in Account 102, state the property purchased or sold, name of vendor or purchase,
and date of transaction. If proposed journal entries have been filed with the Commission as required by the Uniform System of Accounts, give also date
of such filing.
1
14,796 2
7,187,053 -22,375 3
59,927,118 232,747 4
67,128,967 -22,375 232,747 5
6
7
1,275,203 8
129,075,597 33,069 9
447,854,954 1,768,650 10
11
110,042,239 338,777 12
61,027,350 572,655 13
11,751,373 1,013,765 14
761,026,716 3,726,916 15
16
17
18
19
20
21
22
23
24
13,935,724 25
127,165,329 59,996 26
242,690,541 1,005 27
182,143,534 28
35,409,750 79,091 29
13,847,718 10,642 30
6,933,691 31
622,126,287 150,734 32
33
218,767 34
1,206,362 35
1,674,677 36
764,857 37
42,882,616 38
1,237,106 10,046 39
FERC FORM NO. 1 (ED. 12-95)Page 205
(f)
Transfers Balance at
End of Year
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31, Idaho Power Company X
04/30/2003
2002
Line
No.(g)
Adjustments
(e)
Retirements
(d)
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)
2,489,424 40
50,473,809 10,046 41
1,433,626,812 3,887,696 42
43
16,744,441 363 44
27,646,052 -3,371 117,319 45
200,612,201 35,895 3,683,451 46
57,167,515 47
81,188,301 208,940 48
101,672,563 639,468 49
50
51
318,352 52
485,349,425 32,524 4,649,541 53
54
2,975,680 26,440 45 55
14,863,264 -26,440 56,378 56
119,804,701 -77,144 893,712 57
58
172,814,562 1,036,102 59
90,242,432 687,163 60
31,606,072 82,208 61
125,663,779 674,025 62
255,276,409 1,207,899 63
44,796,600 189,994 64
38,840,241 1,157,698 65
2,214,787 38,964 66
67
3,885,961 80,005 68
902,984,488 -77,144 6,104,193 69
70
8,559,930 346,000 71
56,881,558 3,371 1,956,625 72
50,192,775 38,230 4,721,419 73
41,581,200 1,695,448 74
1,011,970 75
3,529,126 1,288 131,888 76
8,733,278 4,918 222,869 77
6,394,561 26,685 78
19,445,327 413,559 79
1,999,676 19,188 32,505 80
198,329,401 66,995 9,546,998 81
82
198,329,401 66,995 9,546,998 83
3,087,419,093 24,421,175 84
85
86
87
3,087,419,093 24,421,175 88
FERC FORM NO. 1 (ED. 12-95)Page 207
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
ELECTRIC PLANT LEASED TO OTHERS (Account 104)
Idaho Power Company X
04/30/2003
2002
Line
No.
Name of Lessee Description of
(b)(a)
(Designate associated companieswith a double asterisk)Property Leased CommissionAuthorization(c)
ExpirationDate ofLease(d)
Balance atEnd of Year(e)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO. 1 (ED. 12-95)Page 213
47 TOTAL
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
ELECTRIC PLANT HELD FOR FUTURE USE (Account 105)
Idaho Power Company X
04/30/2003 2002
Line Description and Location Date Originally Included Balance at
End of Year(c)(b)(a)Of Property in This Account
Date Expected to be used
in Utility Service (d)No.
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.
Land and Rights: 1
12/31/82Boise Operations Center 768,377 2
3
Production 152,419 4
5
Transmission Stations 509,893 6
7
Transmission Lines 86,981 8
9
Distribution Stations 409,412 10
11
12
13
14
15
16
17
18
19
20
Other Property: 21
12/31/82Boise Operations Center 72,785 22
12/31/01Boise Mechanical and Electrical Shop 47,000 23
12/31/81Transmission Stations 178,094 24
Distribution Stations 110,117 25
26
27
28
29
30
Column B if no date listed it is various 31
32
Column C is unknown 33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO. 1 (ED. 12-96)Page 214
47 Total 2,335,078
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
Idaho Power Company X
04/30/2003
2002
Line
No.
Description of Project Construction work in progress -
(b)(a)
Electric (Account 107)
1. Report below descriptions and balances at end of year of projects in process of construction (107)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $100,000, whichever is less) may be grouped.
19,534,582RELIC COST BROWNLEE 1
13,527,111RELIC COST HELLS CANYON 2
6,046,519RELIC COST OXBOW 3
1,543,373BROWNLEE-OXBOW 230KV UPGRADE 4
1,403,418RELIC COST LOW MALAD 5
1,392,752LINE 710, LCST-CDWL 230 KV 6
1,337,243BRIDGER UNDISTRIBUTED WORK ORDER 7
883,937ROLLUP RELIC COST UP MALAD 8
802,432BRIDGER 2000C064 FGD POND GEOTHERMAL 9
787,201KUNA-KUNA JUNCTION 138KV TRANS 10
767,158BRIDGER 2002C011 U3 CONTROLS 11
695,186VALMY UNDISTRIBUTED WORK ORDER 12
626,865VALMY 24046 U1 BAG REPLACEMENT 13
617,569WYEE-CONVERT SUBSTATION TO 138 14
611,730CAPITAL SECURITY COSTS HELLS 15
558,545BMRS0101-INSTALL DIGITAL MW 16
505,799IPCO*INSTALL BOULDER TAP 17
456,398HELLS CANYON RELICENSING 18
445,995BOBN - UPGRADE SO11 & SO12 CON 19
427,902BRIDGER 2002C012 SO3 FLUE GAS 20
420,705REPLACE AUDIX WITH UNITY 21
408,114CONSTRUCTION ACCOUNTING CAPITAL 22
397,474HCC RESERVOIR DISCHARGE 23
382,170HELLS CANYON COMPLEX BOTANICAL 24
378,930REL - FLOW MODELING 25
374,205NEW KUNA 138KV STATION 26
369,227HCC RELICENSING PROCESS/DRAFT 27
363,683HELLS CANYON COMPLEX MULE DEER 28
359,514BOBN0204 REPLACE 202A 29
353,449HELLS CANYON COMPLEX - RELICEN 30
338,052FISHERIES-HCC WHITE STURGEON 31
333,892BRDY-BORA LINE RELAY UPGRADE 32
333,673PAET-013 ADD RIVER CROSSING 33
324,822UNIT #2 OR #3 REWIND 34
315,301HELLS CANYON COMPLEX TERR. PRE 35
306,796OBPR0103-INSTALL DIGITAL MW 36
305,008WATER QUALITY-SNAIL DELISTING 37
297,177SNAIL CONSERVATION PLAN-FY2002 38
293,255FISHERIES-HCC ANADROMOUS FISH 39
285,125CLOVERDALE-BETHEL COURT-WYE 13 40
274,388VALMY 24885 3600 & 3601 PCB 41
268,882LINES CONSTRUCTION - CAPITAL 42
FERC FORM NO. 1 (ED. 12-87)Page 216
43 TOTAL 92,481,654
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
Idaho Power Company X
04/30/2003
2002
Line
No.
Description of Project Construction work in progress -
(b)(a)
Electric (Account 107)
1. Report below descriptions and balances at end of year of projects in process of construction (107)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $100,000, whichever is less) may be grouped.
264,557REL - SEDIMENT PROJECTS 1
263,751BROWNLEE-OXBOW 230KV UPGRADE 2
258,308VALMY 24047 U1 SUPERHEATER TUB 3
257,488ROLLUP RELIC COST BLISS 4
254,889IDAHO 252 ACCOUNT ADJUSTING 5
251,842CAPITAL OVERHEADS FOR CADD 6
249,694ROLLUP RELIC COST SHOSHONE FALLS 7
247,835HBMW DIGITAL MW PROJECT 8
247,233FISHERIES-HCC REDBAND TROUT 9
246,407BOBN 230KV SERIES CAPACITOR 10
246,300BOARDMAN UNDISTRIBUTED WORK ORDER 11
244,034BRIDGER 2002C061 U 1 2 & 3 COA 12
242,600EMS COMPUTERS FOR DISPATCH 13
235,890WESR R061 - REWIND 69 KV REGUL 14
235,090REPLACE COMPAQ 2500 SERVERS 15
226,898VALMY 25499 #2 COOLING TOWER 16
226,162HAILEY TEAM CAP OH WORK ORDER 17
225,807SALMON DIESEL CONTROL AND GOV. 18
225,199IVRU DEVELOPMENT - CAPITAL WORK ORDER 19
222,407WATER QUALITY-BASELINE MONITOR 20
221,844HELLS CANYON COMPLEX CULTURAL 21
217,006TERY - STUDY & SCOPE 22
216,595TRANSFER REAL TIME TRADING FUN 23
215,869BORA-BRDY LINE RELAY UPGRADE 24
207,677DATA CENTER CABLING PROJECT 25
206,799VALMY 22601 #1 BURNER MANAGMEN 26
205,961ROLLUP RELIC COST LOWER SALMON 27
205,366STATION APP 2002 LAB EQUIPMENT 28
199,807HAILEY OPERATIONS DESIGN/CONST 29
195,422BLPR0104-INSTALL DIGITAL MW 30
194,817SBMW0102-INSTALL DIGITAL MW 31
193,829BSPO-ADD MICROWAVE COMMUNICATION 32
192,134BEACON LIGHT SUBSTATION 33
191,761DONN T131 - REWIND FAILED TRAN 34
189,210DUFN0201-REPLACE 101Z 35
188,837GOSHEN C341 REPLACEMENT 36
188,428TOOL EXP TRANS TO CONST 37
188,257BDSS - REWIND TRANSFORMER IPCO 38
187,980MOBILE #6 REPAIR WORKORDER 39
182,875GOODING TEAM CAP OH WORK ORDER 40
179,255STAR0101 PURCHASE PROPERTY FOR 41
177,692MULTIFUNCTIONAL COPIERS 42
FERC FORM NO. 1 (ED. 12-87)Page 216.1
43 TOTAL 92,481,654
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
Idaho Power Company X
04/30/2003
2002
Line
No.
Description of Project Construction work in progress -
(b)(a)
Electric (Account 107)
1. Report below descriptions and balances at end of year of projects in process of construction (107)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $100,000, whichever is less) may be grouped.
177,234LSMW DIGITAL MW PROJECT 1
176,317DELIVERY CAPITAL OVERHEADS 2
175,000INDUSCONNECT FRAMEWORK 3
172,971LNDN INSTALL DCC IN STATION 4
172,264ADAMSFAM TEAM CAP OH WORK ORDE 5
171,916WATER QUALITY-HCC 401/TMDL-FY2 6
170,588BOBN DIGITAL MW PROJECT 7
170,521KUNA BUY PROPERTY FOR NEW KUNA 8
169,945BOC/M&E REMODEL '02 9
168,086ROLLUP RELIC COST C J STRIKE 10
167,617REPLACE DONN-KPRT 1 SKBU RELAY 11
167,328MIDROSE SUBSTATION- ACQUIRE AN 12
166,832FRMT - SCOPE FOR IMPROVED RELI 13
164,762SUN VALLEY CO. 14
164,130GARY INSTALL DCC IN STATION 15
164,041TWINWEST TEAM CAP OH WORK ORDE 16
163,626PICABO 450 MHZ RADIO REPLACEME 17
159,992IPCO/WESR-012/REBUILD/UPGRADE 18
159,905NEW UNIT 8368 - ETHAN MORGAN 19
159,869HELLS CANYON COMPLEX 20
158,640MPSN0201-RTU REPLACEMENT 21
156,715BRIDGER 2002C017 SOOTBLOWER CO 22
154,767VALMY 25025 #2 BURNER NOX IMPR 23
153,585BDSS - REWIND TRANSFORMER IPCO 24
153,029POMW-SCOPE ADDING COMMUNICATION 25
152,394ENVIRO DATA BASE DEVELOPMENT 26
150,036FISHERIES-HCC INSTREAM FLOW 27
149,382DELIVERY PC'S 2002 28
149,327CONSULTING FEES FOR MERIDIAN 29
149,228NAMPA HOUSE PURCHASE 30
147,961HELLS CANYON COMPLEX NON-GAME 31
143,555FERC UNLICENSE MIDPOINT BORAH 32
140,849BOBN GRVE LINE PROTECTION 33
139,835OREGON REAUTHORIZATION - HELLS 34
139,480VARI0201 450 MHZ RADIO REPLACE 35
138,775ADIC UPGRADE 36
138,699BRIDGER 2001C004 U2 COUTANT 37
137,026IPCO-TFSN-014 2002 CABLE REPLACE 38
136,043WATER QUALITY-HCC MITIGATION 39
135,701BDSS- REWIND IPCO#366-01 TRANS 40
134,531FICON CHANNELS 41
133,276KUNA-KUNA JCT. EASEMENTS 42
FERC FORM NO. 1 (ED. 12-87)Page 216.2
43 TOTAL 92,481,654
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
Idaho Power Company X
04/30/2003
2002
Line
No.
Description of Project Construction work in progress -
(b)(a)
Electric (Account 107)
1. Report below descriptions and balances at end of year of projects in process of construction (107)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $100,000, whichever is less) may be grouped.
132,753REL - GEOMORPHOLOGY 1
130,459UPGRADE DATA CTR. SWITCHES 2
130,191SECURE ACCESS MANAGEMENT (SSO) 3
129,446PURCHASE GPS UNITS FOR FEEDER 4
128,418BOISE BENCH SECURITY 5
128,298FISHERIES-HCC RESIDENT FISH-FY 6
126,665IPCO-CITY OF KETCHUM-WARM SPRINGS 7
126,549UPGRADE BOC & M & E 8
124,529BOULDER SUBSTATION TRANSMISSION 9
123,563REL - BANK STABILIZATION 10
122,440PASB DIGITAL MW PROJECT 11
119,995LINE #470, 2ND 138KV LINE 12
119,736MNJ1 REPLACE 101A PCB 13
119,322IPCO-LINE 233 REFURBISH WEISER 14
117,866BRIDGER 2001C084 AIR BELTS 15
117,759BOBN0201-BUILD BLAST WALL 16
117,732VALMY 22602 #2 REHEAT TUBE 17
117,678FISHERIES-PAHSIMEROI CAPITAL 18
117,546CORRECTION WORK ORDER FOR BOC 19
117,385VTRY INSTALL DCC IN STATION 20
116,739FINANCE PC'S, PRINTERS, SCANNE 21
116,631ACES HARDWARE UPGRADE 22
116,477TFSB DIGITAL MW PROJECT 23
115,493BRIDGER 2001C004 U2 & 3 BURNER 24
112,077WEB TEAM SERVER 25
111,885BOBN CONSOLIDATION REMODEL 26
111,630TERMINAL SERVER/CITRIX 27
111,513TFEAST TEAM CAP OH WORK ORDER 28
111,434PHOENIX PROJECT: AM/FM/OMS 29
110,731MINI CASSIA TEAM CAP OH WORK 30
110,419TSP #3 UPGRAGE COMPLETION 31
109,708EAGL TO STAR TRANSMISSION LINE 32
109,334BOISE AIR TERMINAL INSTALL 33
107,421BSMW-NEW MICROWAVE RELAY SITE 34
106,674IPCO: CAMBRIDGE - MCCALL 69KV 35
105,781JMSN-CWVY 69KV, ADD SECTIONALI 36
103,903CRANE CREEK 011 LETHA AREA REB 37
103,327VALMY 22594 U2 GEN / EXCITOR 38
103,171IPCO*LINE #701-POWDER RIVER 39
102,866IPCO-MORA-045 F-47,F-45 & F-45 40
102,540MEDIA MOSAIC E-LEARNING PROJECT 41
102,394VALMY 20170 SERVICE AIR SYSTEM 42
FERC FORM NO. 1 (ED. 12-87)Page 216.3
43 TOTAL 92,481,654
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
Idaho Power Company X
04/30/2003
2002
Line
No.
Description of Project Construction work in progress -
(b)(a)
Electric (Account 107)
1. Report below descriptions and balances at end of year of projects in process of construction (107)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $100,000, whichever is less) may be grouped.
101,478TOOL CORRAL USE ONLY 2002 1
101,151JNTA-DWSY 69KV, SECTIONALIZER 2
11,177,400OTHER MINOR WORK ORDERS 3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO. 1 (ED. 12-87)Page 216.4
43 TOTAL 92,481,654
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108)
Idaho Power Company X
04/30/2003
2002
Line
No.
Item Total
(c)(b)(a)(d)
Section A. Balances and Changes During Year
(c+d+e)Electric Plant inService Electric Plant Held for Future Use Electric PlantLeased to Others
(e)
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.
Balance Beginning of Year 1,202,919,298 1,202,919,298 1
Depreciation Provisions for Year, Charged to 2
(403) Depreciation Expense 85,174,683 85,174,683 3
(413) Exp. of Elec. Plt. Leas. to Others 4
Transportation Expenses-Clearing 3,041,785 3,041,785 5
Other Clearing Accounts 6
Other Accounts (Specify, details in footnote): 7
Fuel Stock 159,701 159,701 8
TOTAL Deprec. Prov for Year (Enter Total of
lines 3 thru 8)
88,376,169 88,376,169 9
Net Charges for Plant Retired: 10
Book Cost of Plant Retired 23,842,021 23,842,021 11
Cost of Removal 2,286,092 2,286,092 12
Salvage (Credit) 4,446,299 4,446,299 13
TOTAL Net Chrgs. for Plant Ret. (Enter Total
of lines 11 thru 13)
21,681,814 21,681,814 14
Other Debit or Cr. Items (Describe, details in
footnote):
15
16
Balance End of Year (Enter Totals of lines 1,
9, 14, 15, and 16)
1,269,613,653 1,269,613,653 17
Steam Production 434,025,860 434,025,860 18
Section B. Balances at End of Year According to Functional Classification
Nuclear Production 19
Hydraulic Production-Conventional 236,498,187 236,498,187 20
Hydraulic Production-Pumped Storage 21
Other Production 2,527,421 2,527,421 22
Transmission 185,425,734 185,425,734 23
Distribution 351,657,228 351,657,228 24
General 59,479,223 59,479,223 25
TOTAL (Enter Total of lines 18 thru 25) 1,269,613,653 1,269,613,653 26
FERC FORM NO. 1 (ED. 12-88)Page 219
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1)
Idaho Power Company X
04/30/2003 2002
Line
No.
Description of Investment Date Acquired
(c)(b)(a)
Amount of Investment atBeginning of YearDate Of
Maturity (d)
1. Report below investments in Accounts 123.1, investments in Subsidiary Companies.
2. Provide a subheading for each company and List there under the information called for below. Sub - TOTAL by company and give a TOTAL 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 418.1.
Idaho Energy Resources Company 1
50002/01/74Common Stock 2
2,462,594Capital contributions 3
10,111,568Equity in earnings 4
5
12,574,662Subtotal Idaho Energy Resources 6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
FERC FORM NO. 1 (ED. 12-89)Page 224
42 Total Cost of Account 123.1 $TOTAL 12,574,662 2,463,094
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1) (Continued)
Idaho Power Company X
04/30/2003 2002
Line
No.
Equity in Subsidiary
Earnings of Year
Revenues for Year Amount of Investment at
End of Year
Gain or Loss from Investment
Disposed of(e)(f)(g)(h)
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 123.1
1
500 2
2,462,594 3
12,644,539 7,000,000 9,532,971 4
5
15,107,633 7,000,000 9,532,971 6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
FERC FORM NO. 1 (ED. 12-89)Page 225
42 9,532,971 7,000,000 15,107,633
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
MATERIALS AND SUPPLIES
Idaho Power Company X
04/30/2003 2002
Line
No.
Account Balance Balance
(c)(b)(a)
Department or
Departments which
(d)
Beginning of Year End of Year
Use Material
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.
8,726,387 Electric 6,942,920 1 Fuel Stock (Account 151)
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
9,818,076 9,613,389 7 Production Plant (Estimated)
3,280,507 2,756,570 8 Transmission Plant (Estimated)
6,779,958 5,697,117 9 Distribution Plant (Estimated)
827,183 871,591 10 Assigned to - Other (provide details in footnote)
20,705,724 Electric 18,938,667 11 TOTAL Account 154 (Enter Total of lines 5 thru 10)
12 Merchandise (Account 155)
13 Other Materials and Supplies (Account 156)
14 Nuclear Materials Held for Sale (Account 157) (Not
applic to Gas Util)
2,573,824 Electric 2,519,780 15 Stores Expense Undistributed (Account 163)
16
17
18
19
32,005,935 28,401,367 20 TOTAL Materials and Supplies (Per Balance Sheet)
FERC FORM NO. 1 (ED. 12-96)Page 227
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
Allowances (Accounts 158.1 and 158.2)
Idaho Power Company X
04/30/2003 2002
Line
No.
Allowances Inventory Current Year
(b)(a)
(Account 158.1)No.Amt.
(c)
No.
(d)
Amt.
(e)
1. Report below the particulars (details) called for concerning allowances.
2. Report all acquisitions of allowances at cost.
3. Report allowances in accordance with a weighted average cost allocation method and other accounting as prescribed by General
Instruction No. 21 in the Uniform System of Accounts.
4. Report the allowances transactions by the period they are first eligible for use: the current year’s allowances in columns (b)-(c),
allowances for the three succeeding years in columns (d)-(i), starting with the following year, and allowances for the remaining
succeeding years in columns (j)-(k).
5. Report on line 4 the Environmental Protection Agency (EPA) issued allowances. Report withheld portions Lines 36-40.
2003
Balance-Beginning of Year 1
2
Acquired During Year: 3
Issued (Less Withheld Allow) 4
Returned by EPA 5
6
7
Purchases/Transfers: 8
9
10
11
12
13
14
Total 15
16
Relinquished During Year: 17
Charges to Account 509 18
Other: 19
20
Cost of Sales/Transfers: 21
22
23
24
25
26
27
Total 28
Balance-End of Year 29
30
Sales: 31
Net Sales Proceeds(Assoc. Co.) 32
Net Sales Proceeds (Other) 33
Gains 34
Losses 35
Allowances Withheld (Acct 158.2)
Balance-Beginning of Year 36
Add: Withheld by EPA 37
Deduct: Returned by EPA 38
Cost of Sales 39
Balance-End of Year 40
41
Sales: 42
Net Sales Proceeds (Assoc. Co.) 43
Net Sales Proceeds (Other) 44
Gains 45
Losses 46
FERC FORM NO. 1 (ED. 12-95)Page 228
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
Allowances (Accounts 158.1 and 158.2)
Idaho Power Company X
04/30/2003 2002
Line
No.
(f)(j)
No.Amt.
(g)
No.
(h)
Amt.
(i)
No.Amt.No.Amt.
(k)(l)(m)
Future Years Totals
(Continued)
6. Report on Lines 5 allowances returned by the EPA. Report on Line 39 the EPA’s sales of the withheld allowances. Report on Lines
43-46 the net sales proceeds and gains/losses resulting from the EPA’s sale or auction of the withheld allowances.
7. Report on Lines 8-14 the names of vendors/transferors of allowances acquire and identify associated companies (See "associated
company" under "Definitions" in the Uniform System of Accounts).
8. Report on Lines 22 - 27 the name of purchasers/ transferees of allowances disposed of an identify associated companies.
9. Report the net costs and benefits of hedging transactions on a separate line under purchases/transfers and sales/transfers.
10. Report on Lines 32-35 and 43-46 the net sales proceeds and gains or losses from allowance sales.
2004 2005
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO. 1 (ED. 12-95)Page 229
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
EXTRAORDINARY PROPERTY LOSSES (Account 182.1)
Idaho Power Company X
04/30/2003
2002
Line
No.
(c)(b)(a)(d)
Description of Extraordinary Loss[Include in the description the date ofCommission Authorization to use Acc 182.1and period of amortization (mo, yr to mo, yr).]
Total Amount of Loss
LossesRecognisedDuring Year
WRITTEN OFF DURING YEAR
AccountCharged Amount
Balance at
End of Year
(f)(e)
None1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
FERC FORM NO. 1 (ED. 12-88)Page 230a
20 TOTAL
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
UNRECOVERED PLANT AND REGULATORY STUDY COSTS (182.2)
Idaho Power Company X
04/30/2003
2002
Line
No.
(c)(b)(a)(d)
Description of Unrecovered Plant Total Amount of Charges
CostsRecognisedDuring Year
WRITTEN OFF DURING YEAR
AccountCharged Amount
Balance at
End of Year
(f)(e)
and Regulatory Study Costs [Include
in the description of costs, the date of
Commission Authorization to use Acc 182.2
and period of amortization (mo, yr to mo, yr)]
None21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
FERC FORM NO. 1 (ED. 12-88)Page 230b
49 TOTAL
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
OTHER REGULATORY ASSETS (Account 182.3)
Idaho Power Company X
04/30/2003
2002
Line
No.
Description and Purpose of Debits CREDITS
Account
(c)(b)(a)
Balance at
End of Year
(d)
Other Regulatory Assets
Charged
Amount
(e)
1. Report below the particulars (details) called for concerning other regulatory assets which are created through the rate making actions
of regulatory agencies (and not includable in other accounts)
2. For regulatory assets being amortized, show period of amortization in column (a)
3. Minor items (5% of the Balance at End of Year for Account 182.3 or amounts less than $50,000, whichever is less) may be grouped
by classes.
886,307 886,307401Meridian Periodic Payments - IPUC 1
order #25533(amort period 1/96 thru 12/03) 2
3
490,681 537,772401Meridian Initial Buyout - ID IPUC order #25533 4
(amort period 1/96 thru 12/03) 5
6
43,833 43,833401Meridian Periodic Payments - OR order #96-166 7
(amort period 1/96 thru 12/03) 8
9
544,800 1,135,000401Postretirement Benefits - IPUC order #25550 10
(amort period 2/95 thru 01/05) 11
12
754,057 2,262,169401Reorganization Costs - IPUC order 26216 13
OPUC order #95-1262 (amort 01/96 thru 12/05) 14
15
3,151,095 327,933,448282 121,252,607Regulatory Unfunded Accumulated Deferred Income 16
17
274,581,080 83,162,307 236,452,723Power Cost Adjustment - IPUC order #27516 18
(amort period 5/01 thru 05/02) 19
20
55,560 46,300401Oregon pre-1994 Conservation -OPUC 21
# 98448 (amort period 10/98 thru 10/03) 22
23
23,808 49,600401Photovoltaic Startup IPUC order #25880 24
(Amort period 2/96 thru 1/06) 25
26
3,242,604 24,319,559401Idaho - Demand Side Management - IPUC order 27
#27660 (amort period 7/98 thru 6/10) 28
29
48,373,473 91,235 683,306FAS133 Mark to Market 30
31
371,508 774,044401FAS112 Post Employment Benefits 32
(Amort period 2/95 thru 1/05) 33
34
76,253,930 27,160,315182 41,167,983Astaris Buyback Program - Idaho 35
36
12,049,057 12,049,057Irrigation Deferral Order #29026 37
(Amort period 4/03 thru 3/04) 38
39
3,744,467 3,744,467PCA Industrial Customers Order #29065 40
(Amort period 4/03 thru 3/04) 41
42
43
FERC FORM NO. 1 (ED. 12-94)Page 232
44 TOTAL 431,992,523 411,422,065 499,305,339
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
OTHER REGULATORY ASSETS (Account 182.3)
Idaho Power Company X
04/30/2003
2002
Line
No.
Description and Purpose of Debits CREDITS
Account
(c)(b)(a)
Balance at
End of Year
(d)
Other Regulatory Assets
Charged
Amount
(e)
1. Report below the particulars (details) called for concerning other regulatory assets which are created through the rate making actions
of regulatory agencies (and not includable in other accounts)
2. For regulatory assets being amortized, show period of amortization in column (a)
3. Minor items (5% of the Balance at End of Year for Account 182.3 or amounts less than $50,000, whichever is less) may be grouped
by classes.
1,135,663 14,171,691401 14,290,285Excess Power Amortization - Oregon 1
(Amort period $1.6 mill per yr until full amort) 2
3
891,420 891,420Security Costs 2001-2002 4
(Amort period 1/03 thru 12/07) 5
6
1,513,666 46,815Various 1,460,675Minor items (6) 7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
FERC FORM NO. 1 (ED. 12-94)Page 232.1
44 TOTAL 431,992,523 411,422,065 499,305,339
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/30/2003
Year of Report
Dec 31, 2002
FOOTNOTE DATA
Schedule Page: 232 Line No.: 18 Column: c
Account 182 $ 78,530,832
Account 557 195,876,681
Account 431 173,567
Schedule Page: 232 Line No.: 30 Column: c
Account 232 $ 40,491,221
Account 253 7,882,252
FERC FORM NO. 1 (ED. 12-87)Page 450
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
MISCELLANEOUS DEFFERED DEBITS (Account 186)
Idaho Power Company X
04/30/2003
2002
Line
No.
Description of Miscellaneous Debits CREDITS
Account
(c)(b)(a)
Balance at
End of Year
(d)
Deferred Debits Amount
(e)
Balance at
Beginning of Year
(f)
Charged
1. Report below the particulars (details) called for concerning miscellaneous deferred debits.
2. For any deferred debit being amortized, show period of amortization in column (a)
3. Minor item (1% of the Balance at End of Year for Account 186 or amounts less than $50,000, whichever is less) may be grouped by
classes.
1,218,855 1,769,343 66,830 617,318Regional Transmsn Org - (RTO) 1
2
2,740,662 2,547,852 4,422,810 4,230,000 131Advance prepaid coal royalties 3
4
2,073,981 2,166,101 92,120Benefits plan - intangible asst 5
6
30,606,683 26,892,863 6,320,010 2,606,190Security Plan 7
8
336,998 322,557 14,446 5 401American Falls bond refinance 9
10
105,666 143,354 37,688 146Expense of Issue 11
12
8,994,825 8,406,461 1,169,168 580,804Company owned Life Insurance 13
14
19,885,000 19,885,000American Falls water rights 15
16
11,700,000 11,700,000Milner bond guarantee 17
18
6,192,413 6,229,420 7,395 44,402 232Southwest intertie project - 19
right of way costs 20
21
3,234,334 2,262,117 972,217143CSPP receivable 22
23
1,111,558 1,063,920 47,638401American Falls - bond refinance 24
(35 year amortization) 25
26
16,755,157 31,812,348 15,057,191Security Plan Trust 27
28
484,887 2,057,299 83,069 1,655,481Shelf Registration 29
30
236,424 4,688 363,372 131,636Floating Rate Note 31
32
12,015,187 12,015,187Irrigation Lost Revenue 33
34
-97,432 -152,560 21,387,833 21,332,705 VariousMinor Items & Job Orders (6) 35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO. 1 (ED. 12-94)Page 233
49 TOTAL
47 Misc. Work in Progress
48 Deferred Regulatory Comm.
Expenses (See pages 350 - 351)
105,580,011 97,170,248
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/30/2003
Year of Report
Dec 31, 2002
FOOTNOTE DATA
Schedule Page: 233 Line No.: 1 Column: d
Account 131 $ 306
Account 232 66,524
Schedule Page: 233 Line No.: 7 Column: d
Account 128 $ 140,737
Account 131 909,990
Account 186 3,868,485
Account 426 1,400,798
Schedule Page: 233 Line No.: 13 Column: d
Account 131 $ 554,710
Account 426 614,458
Schedule Page: 233 Line No.: 27 Column: d
Account 128 $ 20,621,615
Account 131 2,814,857
Account 186 480,009
Account 211 2,643,514
Account 232 203,101
Account 283 1,552,024
Account 419 119,344
Account 421 1,493,324
Account 426 1,884,560
Schedule Page: 233 Line No.: 29 Column: d
Account 131 40
Account 186 83,029
Schedule Page: 233 Line No.: 31 Column: d
Account 232 197
Account 431 363,175
FERC FORM NO. 1 (ED. 12-87)Page 450
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
ACCUMULATED DEFERRED INCOME TAXES (Account 190)
Idaho Power Company X
04/30/2003
2002
Line
No.
Description and Location Balance of Begining
(c)(b)(a)
Balance at Endof Year of Year
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.
Electric 1
3,758,549 3,940,601Contributions in Aid of Construction 2
41,012,859 41,289,868FASB 109 Accounting 3
4
5
6
Other 7
44,771,408 45,230,469TOTAL Electric (Enter Total of lines 2 thru 7) 8
Gas 9
10
11
12
13
14
Other 15
TOTAL Gas (Enter Total of lines 10 thru 15 16
-7,866,289 -4,655,167Other (Specify) See note 1 Below 17
36,905,119 40,575,302TOTAL (Acct 190) (Total of lines 8, 16 and 17) 18
Notes
(1) Other: Beginning Balance Ending Balance
Security Plan $ 7,331,077 $ 8,284,729
Bonus Deferral (5,331,091) (5,285,937)
Contigent Liability-Accident Reserve 98,063 0.00
' Contigent Liability-Marketing 4,197,075 4,197,075
FERC Settlement Reserve 0.00 1,537,557
SMSP-Market Change of Rabbi Investments 0.00 384,217
Donations Not Deducted in 2001 347,444 0.00
Idaho Public Utilities-Rate refund 1,360,302 1,020,870
Mark to Market-Energy Trading (21,425,081) (27,667,943)
Meridian Gold Contributions 309,646 286,422
Micron-CIAC 3,503,147 3,226,473
' Minimum Pension Liability 2,592,190 3,856,760
Non VEBA Pension & Benefits 888,492 977,195
Other EE's Long Term Deferred Comp 100,107 203,726
Pioneer Land (write down) 45,502 45,502
Post Retirement benefits (335,561) (456,827)
Restricted Stock Plan 659,915 449,871
Seattle City Light-CIAC 176,070 144,175
SFAS112-Post Employment Benefits 731,369 850,104
Start Up and Organization Costs 96,168 79,742
FERC FORM NO. 1 (ED. 12-88)Page 234
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
CAPITAL STOCKS (Account 201 and 204)
Idaho Power Company X
04/30/2003
2002
Line
No.
Class and Series of Stock and Number of shares
(c)(b)(a)
Call Price at
End of Year
Par or Stated
Value per share
(d)
Name of Stock Series Authorized by Charter
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.
Account 201 1
2.50 50,000,000 Common Stock registered on New York 2
and Pacific Stock Exchange 3
2.50 50,000,000Total Common Stock 4
5
Account 204 6
104.00 100.00 215,000 4% Preferred Stock 7
8
Serial Preferred Stock: 9
102.97 100.00 150,000 7.68% Series (cumulative) 10
11
103.53 100.00 250,000 7.07% Series (cumulative) 12
13
300.00 615,000Total Preferred Stock 14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO. 1 (ED. 12-91)Page 250
AS REACQUIRED STOCK (Account 217)
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
CAPITAL STOCKS (Account 201 and 204) (Continued)
Idaho Power Company X
04/30/2003
2002
Line
No.
OUTSTANDING PER BALANCE SHEET HELD BY RESPONDENT
IN SINKING AND OTHER FUNDS
Shares(g)Cost(h)Shares SharesAmount
(Total amount outstanding without reduction
for amounts held by respondent)
Amount(e)(f)(i)(j)
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.
1
94,030,878 37,612,351 2
3
94,030,878 37,612,351 4
5
6
9,945 172,354 13,392,700 133,927 7
8
9
15,000,000 150,000 10
11
25,000,000 250,000 12
13
9,945 172,354 53,392,700 533,927 14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO. 1 (ED. 12-88)Page 251
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31, Idaho Power Company X
04/30/2003
2002
Line Item Amount(b)(a)
OTHER PAID-IN CAPITAL (Accounts 208-211, inc.)
No.
Report below the balance at the end of the year and the information specified below for the respective other paid-in capital accounts. Provide a
subheading for each account and show a total for the account, as well as total of all accounts for reconciliation with balance sheet, Page 112. Add more
columns for any account if deemed necessary. Explain changes made in any account during the year and give the accounting entries effecting such
change.
(a) Donations Received from Stockholders (Account 208)-State amount and give brief explanation of the origin and purpose of each donation.
(b) Reduction in Par or Stated value of Capital Stock (Account 209): State amount and give brief explanation of the capital change which gave rise to
amounts reported under this caption including identification with the class and series of stock to which related.
(c) Gain on Resale or Cancellation of Reacquired Capital Stock (Account 210): Report balance at beginning of year, credits, debits, and balance at end
of year with a designation of the nature of each credit and debit identified by the class and series of stock to which related.
(d) Miscellaneous Paid-in Capital (Account 211)-Classify amounts included in this account according to captions which, together with brief explanations,
disclose the general nature of the transactions which gave rise to the reported amounts.
Account 208 - Donations received from stockholders 1
2
Account 209 - Reduction in par or stated value of Capital Stock 3
4
Account 210 - Gain on reacquired Capital Stock 5
764,225Balance January 1, 2001 6
7
4% Preferred Stock (par value $100): 8
994,500Par Value of retired Capital Stock - 9,945 shares 9
12,925Transfer Premium on Capital Stock (account 207) - 9,945 shares 10
-23,329Transfer Capital Stock expenses (account 214) - 9,945 shares 11
-824,728Cost of retired Capital Stock (account 217) - 9,945 shares 12
13
-800,360Write off for retirement of Auction Preferred stock 14
15
0Account 211 16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
FERC FORM NO. 1 (ED. 12-87)Page 253
40 TOTAL 123,233
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/30/2003
Year of Report
Dec 31, 2002
FOOTNOTE DATA
Schedule Page: 253 Line No.: 16 Column: b
The 2001 balance for the Minimum Pension Liability for Deferred Compensation and
Unrealized Gains and Losses on Available-for-Sale Securities (OCI - 4,508,136 and 789,057)
was reclassified to Account 219.
FERC FORM NO. 1 (ED. 12-87)Page 450
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
CAPITAL STOCK EXPENSE (Account 214)
Idaho Power Company X
04/30/2003
2002
Line
No.
Class and Series of Stock Balance at End of Year
(b)(a)
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.
2,071,924Common Stock 1
2
Preferred Stock: 3
314,0504% (1) 4
33,8597.68% Serial 5
290,2827.07% Serial 6
Flexible Auction Series (2) 7
8
9
Explanation of Changes during the year: 10
11
12
13
(1) Charge off amount of capital stock expense applicable to retirement of 9,945 shares 14
account 210 $ 172,354 15
16
(2) Flexible Auction Series was redeemed in August 2002 17
18
19
20
21
FERC FORM NO. 1 (ED. 12-87)Page 254b
22 TOTAL 2,710,115
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
LONG-TERM DEBT (Account 221, 222, 223 and 224)
Idaho Power Company X
04/30/2003
2002
Line
No.
Class and Series of Obligation, Coupon Rate
(c)(b)(a)
Total expense,
Premium or Discount
Principal Amount
Of Debt issued(For new issue, give commission Authorization numbers and dates)
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.
Account 221: 1
First Mortgage Bonds: 2
240,493 27,000,0006.85% Series due 2002 3
4
667,636 80,000,0006.40% Series due 2003 5
6
807,871 80,000,0007.38% Series Due 2007 7
8
572,246 80,000,0007.20% Series due 2009 9
10
463,337 50,000,0008.00% Series due 2004 11
400,000 12 D
13
2,508,801 60,000,0005.83% Series due 2005 14
15
860,502 120,000,0006.60% Series due 2011 16
17
767,636 80,000,0007.50% Series due 2023 18
614,400 19 D
20
563,337 50,000,0008 3/4% Series due 2027 21
187,500 22 D
23
944,356 100,000,0004.75% Series due 2012(Idaho Commission Case ICP-E-01-27, 24
1,047,617Oregon Commission UF4181,Wyoming Docket #20005-ES-01-23 (11-15-02) 25 D
26
1,069,356 100,000,0006.00% Series due 2032(Idaho Commission Case ICP-E-01-27, 27
543,244Oregon Commission UF4181,Wyoming Docket #20005-ES-01-23(11-15-02) 28 D
29
30
31
32
FERC FORM NO. 1 (ED. 12-96)Page 256
33 TOTAL 1,052,384,184 15,973,393
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
LONG-TERM DEBT (Account 221, 222, 223 and 224)
Idaho Power Company X
04/30/2003
2002
Line
No.
Class and Series of Obligation, Coupon Rate
(c)(b)(a)
Total expense,
Premium or Discount
Principal Amount
Of Debt issued(For new issue, give commission Authorization numbers and dates)
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.
1
Pollution control Revenue Bonds 2
3
4
2,235,221 49,800,0008.30% Valmy due 2014 5
6
7
571,895 68,100,0006.05% Series 96A due 2026 8
471,252 9 D
10
124,587 24,200,000Series 96B due 2026 11
12
13
123,561 24,000,000Series 96C due 2026 14
15
188,545 4,360,000Port of Morrow Variable due 2027 16
17
15,973,393 997,460,000Subtotal Account 221 18
19
Account 224: 20
Other Long-Term Debt 21
22
21,425,000Bond Guarantee - American Falls 23
24
19,885,000Bond Guarantee - American Falls 25
26
11,700,000Note Guarantee - Milner Dam 27
1,914,184REA Notes 28
54,924,184Subtotal Account 224 29
30
Account 222 - Reacquired Bonds 31
Account 223 - Advances from Associated Companies 32
FERC FORM NO. 1 (ED. 12-96)Page 256.1
33 TOTAL 1,052,384,184 15,973,393
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
LONG-TERM DEBT (Account 221, 222, 223 and 224) (Continued)
Idaho Power Company X
04/30/2003
2002
Line
No.Nominal Date
of Issue
Date of
Maturity
AMORTIZATION PERIOD
Date From Date To
Outstanding(Total amount outstanding without
reduction for amounts held byrespondent)
Interest for Year
Amount
(d)(e)(f)(g)(h)(i)
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.
1
2
1,387,12510/01/0210/02/9610/01/0210/02/96 3
4
80,000,000 5,120,00005/01/0304/28/9305/01/0304/28/93 5
6
80,000,000 5,904,00012/1/0712/1/0012/1/0712/1/00 7
8
80,000,000 5,760,0001/1/101/1/0012/1/0911/23/99 9
10
50,000,000 4,000,00003/15/0403/21/9203/15/0403/25/92 11
12
13
60,000,000 3,498,00009/09/0509/09/9809/09/0509/09/98 14
15
120,000,000 7,920,00003/02/1103/02/0103/02/1103/02/01 16
17
80,000,000 6,000,00005/01/2304/28/9305/01/2304/28/93 18
19
20
911,45803/15/2703/25/9203/15/2703/25/92 21
22
23
100,000,000 606,94411/15/1211/15/0211/15/1211/15/02 24
25
26
100,000,000 766,66711/15/3211/15/0211/15/3211/15/02 27
28
29
30
31
32
FERC FORM NO. 1 (ED. 12-96)Page 257
33 953,229,728 51,127,384
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
LONG-TERM DEBT (Account 221, 222, 223 and 224) (Continued)
Idaho Power Company X
04/30/2003
2002
Line
No.Nominal Date
of Issue
Date of
Maturity
AMORTIZATION PERIOD
Date From Date To
Outstanding(Total amount outstanding without
reduction for amounts held byrespondent)
Interest for Year
Amount
(d)(e)(f)(g)(h)(i)
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.
1
2
3
4
49,800,000 4,133,40012/01/1412/20/8412/01/1412/20/84 5
6
7
68,100,000 4,120,05007/15/2607/25/9607/15/2607/25/96 8
9
10
24,200,000 431,29007/15/2607/25/9607/15/2607/25/96 11
12
13
24,000,000 416,02207/15/2607/25/9607/15/2607/25/96 14
15
4,360,000 114,8622/1/075/17/002/1/275/17/00 16
17
920,460,000 51,089,818 18
19
20
21
22
03/01/90 23
24
19,885,0002/1/254/26/00 25
26
11,700,00002/10/92 27
1,184,728 37,566 28
32,769,728 37,566 29
30
31
32
FERC FORM NO. 1 (ED. 12-96)Page 257.1
33 953,229,728 51,127,384
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/30/2003
Year of Report
Dec 31, 2002
FOOTNOTE DATA
Schedule Page: 256 Line No.: 3 Column: h
The 6.85% Series was redeemed in October 2002.
Schedule Page: 256 Line No.: 21 Column: h
The 8.75% Series was redeemed in March 2002
FERC FORM NO. 1 (ED. 12-87)Page 450
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TAXES
Idaho Power Company X
04/30/2003
2002
Particulars (Details)
(b)(a)
Amount Line
No.
1. Report the reconciliation of reported net income for the year with taxable income used in computing Federal income tax accruals and show
computation of such tax accruals. Include in the reconciliation, as far as practicable, the same detail as furnished on Schedule M-1 of the tax return for
the year. Submit a reconciliation even though there is no taxable income for the year. Indicate clearly the nature of each reconciling amount.
2. If the utility is a member of a group which files a consolidated Federal tax return, reconcile reported net income with taxable net income as if a
separate return were to be field, indicating, however, intercompany amounts to be eliminated in such a consolidated return. State names of group
member, tax assigned to each group member, and basis of allocation, assignment, or sharing of the consolidated tax among the group members.
3. A substitute page, designed to meet a particular need of a company, may be used as Long as the data is consistent and meets the requirements of
the above instructions. For electronic reporting purposes complete Line 27 and provide the substitute Page in the context of a footnote.
88,920,696Net Income for the Year (Page 117) 1
2
3
Taxable Income Not Reported on Books 4
19,150,235 5
6
7
8
Deductions Recorded on Books Not Deducted for Return 9
161,061,834 10
11
12
13
Income Recorded on Books Not Included in Return 14
32,165,730 15
16
17
18
Deductions on Return Not Charged Against Book Income 19
17,553,177 20
21
22
23
24
25
26
Federal Tax Net Income 27
219,413,857Show Computation of Tax: 28
76,794,850Tenative Federal Tax 219,413,857 @ 35% 29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
FERC FORM NO. 1 (ED. 12-96)Page 261
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/30/2003
Year of Report
Dec 31, 2002
FOOTNOTE DATA
Schedule Page: 261 Line No.: 5 Column: b
Construction ADV-252 $ -520,150
CIAC as taxable inc to closed plant 19,136,699
Avoided cost int cap 1,809,848
Retirements-record tax gain/loss -750,000
CIAC as taxable inc in Acct 107 210,557
Royalty income 109,150
CIAC-Meridian Gold -59,206
CIAC-Micron-DRAM -705,351
CIAC-Seattle City Light-New -81,312
Total $ 19,150,235
Schedule Page: 261 Line No.: 10 Column: b
Total Federal & State taxes Ded on Books $ -4,177,535
Bad debt expense 66,346
Gain/Loss on Reacquired Debt-deferred 868,392
SFAS 112-Post-Emply Ben 302,701
Overaccrued Vacation 436,118
Prin portion--air lease 138,915
Injuries & Damages 436,041
Excess benefits plan -1,128,192
Directors Fees Deferred 208,837
Capitalized Overheads -10,000,000
Pension Accrual -74,250
Meals (50% Non-Deductible) charded to R.E. 300,000
Milner Falling Water-Rev Accrual 264,100
Amortization of Acccount 114 -22,723
Oregon Operating Property Tax Adjustment 52,378
Nonveba Pension & Benefits 226,140
PCA Expense Deferral 167,849,679
Post Retiree Benefit-FAS106- 544,800
Sun Valley Fac--Rev Amort 12,328
Restricted Stock Plan-Comp -535,486
Cont Liability-Accident Reserve -250,000
Other Employee's LT Deferred Comp 264,166
Bonus Deferral -275,558
Ferc Settlement Reserve 3,919,840
SEC Plan Net Ins Costs -1,097,786
SMSP-Market Change of Rabbi Investments 979,519
EDC-Unrealized Gain/Loss from Rabbi Trust 5,571
Nondeductible Political Expense 250,000
SEC Plan Benefit Accrual 2,431,236
Nondeductible Fines & Penalties -109,672
Nondeductible Political Exp 100,000
StartUp & Organizational Costs -38,300
Donations Not Deducted this Year -885,771
Total $ 161,061,834
FERC FORM NO. 1 (ED. 12-87)Page 450
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/30/2003
Year of Report
Dec 31, 2002
FOOTNOTE DATA
Schedule Page: 261 Line No.: 15 Column: b
Gain on Sale of BOC $ 31,970
Other Regulatory Liabilities 865,346
Reverse Equity Earnings of Subsidiaries 10,368,122
Allowance for OFUDC 333,060
Allowance for BFUDC 2,374,773
Security Plan-Insurance Proceeds 2,276,941
Mark to Market-Energy Trading 15,915,518
Total $ 32,165,730
Schedule Page: 261 Line No.: 20 Column: b
VEBA-Post Retirement Benefits $ 268,838
Depreciation for Tax GT or LT book -11,879,213
Conservation Programs -3,882,831
Nevada Operation Property Tax Adjustment -15,368
Removal Costs 2,327,303
Repair Allowance 7,000,000
Oregon Excess Power Supply Costs -693,934
American Falls-Unamortized Debt Expense -47,638
Gain/Loss on Reacquired Debt 2,080,713
Meridian Contract Buyout -384,569
Reorganization Costs -754,057
Misc 186 Adjustments -247,718
Software costs Misc-107 700,000
Ferc Order 2000 Costs 550,488
Photovoltaic Startup Costs -23,808
Research & Develop Deduct 5,000,000
Incremental Security Costs Deducted 830,898
PP Ins & Other Expense (1 Yr or Less) 2,764,741
COLI_Tax Adjustment from Books -549,573
Oregon Nonoperation Property Tax Adjustment 107
Depreciation Adjustment-Non Op-Other Property 32,192
Dividends Paid Ded Pub Utility 79,000
State Income Tax Deducted on Federal Return 14,397,606
Total $ 17,553,177
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
Idaho Power Company X
04/30/2003
2002
Line
No.
Kind of Tax
(See instruction 5)
BALANCE AT BEGINNING OF YEAR
Taxes Accrued(Account 236)Prepaid Taxes(Include in Account 165)
TaxesChargedDuringYear
TaxesPaid During
Adjust-
mentsYear(a)(b)(c)(d)(e)(f)
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.
Federal: 1
-25,281,710 69,449,702 -16,024,609Income 2
8,284,489 8,284,494Social Security - (FOAB) 3
102,660 102,660 -722Unemployment 4
Environmental 5
-16,894,561 77,836,856 -16,025,331 Subtotal Federal 6
7
State of Idaho: 8
12,166,651 12,278,415 5,600,298Property 9
3,958,608 7,439,026 -6,369,918Income 10
1,413,250 1,407,846 95,437KWH 11
190,270 190,269Unemployment 12
1,714,256 1,714,256Regulatory Commission 13
Motor Vehicle License 14
150 150 150Business License - Sho Ban 15
19,443,185 23,029,962 150 -674,183 Subtotal Idaho 16
17
State of Oregon 18
1,969,091 2,021,362 1,032,158Property 19
10 808,924 39,624Income 20
93,470 93,470Regulatory Commission 21
8,900 8,586Unemployment 22
456,242 452,904 112,265Franchise 23
2,527,713 3,385,246 1,032,158 151,889 Subtotal Oregon 24
25
State of Montana: 26
84,768 85,799 41,820Property 27
84,768 85,799 41,820 Subtotal Montana 28
29
State of Nevada: 30
956,330 964,014 483,973 265,787Property 31
63 63Unemployment 32
100 100Mountain City License 33
-588 588Elko County Franchise 34
1,536 1,536Regulatory Commission 35
Business Tax 36
958,029 965,125 483,973 266,375 Subtotal Nevada 37
38
39
40
1,516,281
FERC FORM NO. 1 (ED. 12-96)Page 262
TOTAL41 98,040,412 7,271,899 -15,067,246
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
Idaho Power Company X
04/30/2003
2002
Line
No.
Kind of Tax
(See instruction 5)
BALANCE AT BEGINNING OF YEAR
Taxes Accrued(Account 236)Prepaid Taxes(Include in Account 165)
TaxesChargedDuringYear
TaxesPaid During
Adjust-
mentsYear(a)(b)(c)(d)(e)(f)
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.
State of Wyoming 1
2,856 2,856Corporate License 2
1,048,524 922,617 587,216Property 3
1,051,380 925,473 587,216 Subtotal Wyoming 4
5
78 50misc states franchise 6
7
101,307 350,395 584,968Other States Income 8
-8,538,494Payroll Adjustment 9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
1,516,281
FERC FORM NO. 1 (ED. 12-96)Page 262.1
TOTAL41 98,040,412 7,271,899 -15,067,246
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued)
Idaho Power Company X
04/30/2003
2002
Line
No.(Taxes accrued
BALANCE AT END OF YEAR
Prepaid Taxes Electric(Account 408.1, 409.1)Extraordinary Items
(Account 409.3)
Adjustments to Ret.OtherEarnings (Account 439)
(g)(h)(i)(j)(k)(l)Account 236)(Incl. in Account 165)
DISTRIBUTION OF TAXES CHARGED
5. If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year,
identifying the year in column (a).
6. Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments
by parentheses.
7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending
transmittal of such taxes to the taxing authority.
8. Report in columns (i) through (l) how the taxes were distributed. Report in column (I) only the amounts charged to Accounts 408.1 and 409.1
pertaining to electric operations. Report in column (l) 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 (l) 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.
1
-5,717,119 75,166,821 78,706,803 2
8,284,494 5 3
102,660 -722 4
5
-5,717,119 83,553,975 78,706,086 6
7
8
12,278,415 5,712,062 9
-1,006,620 8,445,646 -2,889,500 10
1,407,846 90,033 11
190,269 -1 12
1,714,256 13
14
150 150 15
-1,006,620 24,036,582 150 2,912,594 16
17
18
2,021,362 979,887 19
-86,777 895,701 848,538 20
93,470 21
8,586 -314 22
452,904 108,928 23
-86,777 3,472,023 979,887 957,152 24
25
26
85,799 42,851 27
85,799 42,851 28
29
30
964,014 468,605 258,102 31
63 32
100 33
-588 34
1,536 35
36
965,125 468,605 258,102 37
38
39
40
FERC FORM NO. 1 (ED. 12-96)Page 263
41 1,448,642 104,885,639 -6,845,227 84,172,122
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued)
Idaho Power Company X
04/30/2003
2002
Line
No.(Taxes accrued
BALANCE AT END OF YEAR
Prepaid Taxes Electric(Account 408.1, 409.1)Extraordinary Items
(Account 409.3)
Adjustments to Ret.OtherEarnings (Account 439)
(g)(h)(i)(j)(k)(l)Account 236)(Incl. in Account 165)
DISTRIBUTION OF TAXES CHARGED
5. If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year,
identifying the year in column (a).
6. Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments
by parentheses.
7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending
transmittal of such taxes to the taxing authority.
8. Report in columns (i) through (l) how the taxes were distributed. Report in column (I) only the amounts charged to Accounts 408.1 and 409.1
pertaining to electric operations. Report in column (l) 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 (l) 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.
1
2,856 2
922,617 461,309 3
925,473 461,309 4
5
50 -28 6
7
-34,711 385,106 834,056 8
-8,538,494 9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO. 1 (ED. 12-96)Page 263.1
41 1,448,642 104,885,639 -6,845,227 84,172,122
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/30/2003
Year of Report
Dec 31, 2002
FOOTNOTE DATA
Schedule Page: 262 Line No.: 2 Column: l
409.2 $ -5,679,551
107 -37,568
Schedule Page: 262 Line No.: 10 Column: l
409.2 $ -1,006,620
Schedule Page: 262 Line No.: 20 Column: l
409.2 $ -86,777
Schedule Page: 262.1 Line No.: 8 Column: l
409.2 $ -34,711
FERC FORM NO. 1 (ED. 12-87)Page 450
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255)
Idaho Power Company X
04/30/2003
2002
Line
No.
Account Balance at Beginning
(c)(b)(a)
of YearSubdivisions AdjustmentsDeferred for Year Allocations toCurrent Year's Income
Account No.Amount Account No.Amount(d)(e)(f)(g)
Report below information applicable to Account 255. Where appropriate, segregate the balances and transactions by utility and
nonutility operations. Explain by footnote any correction adjustments to the account balance shown in column (g).Include in column (i)
the average period over which the tax credits are amortized.
Electric Utility 1
3% 2
4% 2,020,362 158,018 3
7% 4
10% 42,475,810 2,178,434 5
1,505,953 25,053 6
255 22,013,798 2,722,422 411 817,228 7
TOTAL 68,015,923 2,722,422 3,178,733 8
Other (List separately
and show 3%, 4%, 7%,
10% and TOTAL)
9
Line 6 col A 11% 10
11
State of Idaho 255 22,013,798 2,722,422 411 817,228 12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
FERC FORM NO. 1 (ED. 12-89)Page 266
Balance at End
(i)(h)
of Year
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255) (continued)
Idaho Power Company X
04/30/2003
2002
Line
No.
ADJUSTMENT EXPLANATIONAverage Periodof Allocation
to Income
1
2
1,862,344 12.79 3
4
40,297,376 19.50 5
1,480,900 60.11 6
23,918,992 26.94 7
67,559,612 8
9
10
11
23,918,992 12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
FERC FORM NO. 1 (ED. 12-89)Page 267
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
OTHER DEFFERED CREDITS (Account 253)
Idaho Power Company X
04/30/2003
2002
Line
No.
Description and Other DEBITS
Credits
Account(c)(b)(a)
Balance at
End of Year
(d)
Deferred Credits Amount
(e)
Balance at
Beginning of Year Contra
(f)
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.
536,407Point to Point Transmission Study 906,152 1,244,757 875,012131 1
2
FTV 400,000 1,150,000 750,000400 3
4
7,253,478FASB 133 Mark to Market 23,296,547 30,550,0251823 5
6
2,078,918Customer Level Pay 3,138,189 2,481,032 1,421,761142 7
8
70,247US Airforce Photovoltaic Generator 103,056 33,809 1,000431 9
10
19,817,999Security Plan 21,121,043 3,810,000 2,506,956 11
12
FERC Settlement Reserve 3,919,840 3,919,840 13
14
2,400,557Milner Falling Water 2,664,657 264,100 15
16
3,010,101Postretirement Benefits 2,941,295 400,394 469,200401 17
18
8,682,496Benefit Plan - Minimum Liability 11,998,503 3,316,007 19
20
2,965,553Directors Deferred Compensation 3,174,389 447,997 239,161131 21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO. 1 (ED. 12-94)Page 269
47 TOTAL 40,364,483 36,813,115 50,367,124 46,815,756
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/30/2003
Year of Report
Dec 31, 2002
FOOTNOTE DATA
Schedule Page: 269 Line No.: 11 Column: c
Account 232 $ 2,265,408
Account 241 241,265
Account 401 283
FERC FORM NO. 1 (ED. 12-87)Page 450
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
ACCUMULATED DEFERRED INCOME TAXES - ACCELERATED AMORTIZATION PROPERTY (Account 281)
Idaho Power Company X
04/30/2003
2002
Line
No.
Account
(a)(b)(c)(d)
Balance at
Beginning of Year
CHANGES DURING YEAR
Amounts Debited Amounts Credited
to Account 410.1 to Account 411.1
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.
1 Accelerated Amortization (Account 281)
2 Electric
3 Defense Facilities
4 Pollution Control Facilities
5 Other (provide details in footnote):
6
7
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):
13
14
15 TOTAL Gas (Enter Total of lines 10 thru 14)
16
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
FERC FORM NO. 1 (ED. 12-96)Page 272
NOTES
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
ACCUMULATED DEFERRED INCOME TAXES _ ACCELERATED AMORTIZATION PROPERTY (Account 281) (Continued)
Idaho Power Company X
04/30/2003
2002
Line
No.
CHANGES DURING YEAR ADJUSTMENTS
Balance at
End of Year
Debits CreditsAmounts Debited
to Account 410.2
Amounts Credited
to Account 411.2 Account
Credited
Amount
Debited
Account Amount
(e)(f)(h)(j)(k)(g)(i)
3. Use footnotes as required.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
FERC FORM NO. 1 (ED. 12-96)Page 273
NOTES (Continued)
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
ACCUMULATED DEFFERED INCOME TAXES - OTHER PROPERTY (Account 282)
Idaho Power Company X
04/30/2003
2002
Line
No.
Account
(a)(b)(c)(d)
Balance at
Beginning of Year
CHANGES DURING YEAR
Amounts Debited Amounts Credited
to Account 410.1 to Account 411.1
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.
Account 282 1
Electric 235,515,614 9,297,208 31,460,329 2
Gas 3
Other than Liberalized Depr 224,246,829 3,253,547 348,100 4
TOTAL (Enter Total of lines 2 thru 4) 459,762,443 12,550,755 31,808,429 5
Non-Operating Property 249,872 6
7
8
TOTAL Account 282 (Enter Total of lines 5 thru 460,012,315 12,550,755 31,808,429 9
Classification of TOTAL 10
Federal Income Tax 386,747,360 12,675,776 31,808,429 11
State Income Tax 73,264,955 -125,021 12
Local Income Tax 13
FERC FORM NO. 1 (ED. 12-96)Page 274
NOTES
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282) (Continued)
Idaho Power Company X
04/30/2003
2002
Line
No.
CHANGES DURING YEAR ADJUSTMENTS
Balance at
End of Year
Debits CreditsAmounts Debited
to Account 410.2
Amounts Credited
to Account 411.2 Account
Credited
Amount
Debited
Account Amount
(e)(f)(h)(j)(k)(g)(i)
3. Use footnotes as required.
1
213,352,493 2
3
182 345,253,787182 118,101,511 4
558,606,280 118,101,511 5
12,627 278 262,221 6
7
8
12,627 278 558,868,501 118,101,511 9
10
10,535 232 469,158,190 101,533,180 11
2,093 46 89,710,312 16,568,331 12
13
FERC FORM NO. 1 (ED. 12-96)Page 275
NOTES (Continued)
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/30/2003
Year of Report
Dec 31, 2002
FOOTNOTE DATA
Schedule Page: 274 Line No.: 2 Column: b
Back in 1999 the ending balance on page 275 line 2 was misstated by $100,000. This
balance has been carried forward ever since 1999 and has had an error of $100,000 all
these years.
Schedule Page: 274 Line No.: 4 Column: b
Col B Col C Col D Col G Col I Col J Col K
Repair $729,985 $169,200 $560,785
Bridger 734,457 102,400 632,057
N. Valmy 1,116,266 76,500 1,039,766
FERC 7,024,671 343,692 7,368,363
CIAC -4,116,321 1,323,507 -2,792,814
Software 700,000 155,674 855,674
R & D 8,225,834 1,430,674 9,656,508
FASB 109 209,831,937 182 182 118,101,511 327,933,448
Total $224,246,829 $3,253,547 $348,100 $118,101,511 $345,253,787
FERC FORM NO. 1 (ED. 12-87)Page 450
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
ACCUMULATED DEFFERED INCOME TAXES - OTHER (Account 283)
Idaho Power Company X
04/30/2003
2002
Line
No.
Account
(a)(b)(c)(d)
Balance at
Beginning of Year
CHANGES DURING YEAR
Amounts Debited Amounts Credited
to Account 410.1 to Account 411.1
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.
Account 283 1
Electric 2
4,835 9,671Bald Mountain 3
150,847 320,166Meridian buyout contracts 4
-115,100 -813,037Ferc Order 144A 5
6
7
81,275,240 14,135,240 134,041,209 Other 8
81,315,822 14,135,240 133,558,009TOTAL Electric (Total of lines 3 thru 8) 9
Gas 10
11
12
13
14
15
16
TOTAL Gas (Total of lines 11 thru 16) 17
472,443 Other 18
81,315,822 14,135,240 134,030,452TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18) 19
Classification of TOTAL 20
67,821,852 11,792,880 111,687,415Federal Income Tax 21
13,493,970 2,342,360 22,343,037State Income Tax 22
Local Income Tax 23
FERC FORM NO. 1 (ED. 12-96)Page 276
NOTES
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
ACCUMULATED DEFERRED INCOME TAXES - OTHER (Account 283) (Continued)
Idaho Power Company X
04/30/2003
2002
Line
No.
CHANGES DURING YEAR ADJUSTMENTS
Balance at
End of Year
Debits CreditsAmounts Debited
to Account 410.2
Amounts Credited
to Account 411.2 Account
Credited
Amount DebitedAccount Amount
(e)(f)(h)(j)(k)(g)(i)
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.
1
2
4,836 3
169,319 4
-697,937 5
6
7
66,519,158219219 382,051 8
65,995,376 382,051 9
10
11
12
13
14
15
16
17
433,769 42,815 4,141 18
66,429,145 42,815 4,141 382,051 19
20
55,305,473 35,727 3,455 320,698 21
11,123,672 7,088 686 61,353 22
23
FERC FORM NO. 1 (ED. 12-96)Page 277
NOTES (Continued)
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/30/2003
Year of Report
Dec 31, 2002
FOOTNOTE DATA
Schedule Page: 276 Line No.: 8 Column: b
Col B Col C Col D Col G Col H Col I Col K
Loss Reacq Debt $1,432,295 $340,627 $1,091,668
Conservation Prog 11,137,666 811,865 1,523,040 10,426,491
PCA Exp Deferral 113,604,610 12,372,170 78,211,206 47,765,573
PV Startup Costs 28,794 9,339 19,456
Post Employment 658,902 213,698 445,204
Reorg Costs 1,183,114 295,779 887,335
Incr Security Costs 6,454 325,920 332,373
FERC Order 2000 478,096 215,929 694,025
Oregon Excess Power 5,831,041 409,356 681,551 5,558,846
Unrealized Gain Mkt -319,763 219 -382,051 219 -701,814
Total $134,041,209 $14,135,240 $81,275,240 $-382,051 $66,519,158
Schedule Page: 276 Line No.: 18 Column: b
Col B Col E Col F Col K
Advance Coal Royalties $474,495 $6,326 $42,814 $438,007
Oregon non-Op Prop Tax Adj 784 1 783
Unrealized G/L from Rabbi Trust -2,836 -2,185 -5,021
Total $472,443 $4,141 $42,815 $433,769
FERC FORM NO. 1 (ED. 12-87)Page 450
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
OTHER REGULATORY LIABILITIES (Account 254)
Idaho Power Company X
04/30/2003
2002
Line
No.
Description and Purpose of DEBITS
CreditsAccount
(c)(b)(a)
Balance at
End of Year
(d)
Other Regulatory Liabilities Amount
(e)Credited
1. Reporting below the particulars (Details) called for concerning other regulatory liabilities which are created through the rate-making
actions of regulatory agencies (and not includable in other amounts)
2. For regulatory Liabilities being amortized show period of amortization in column (a).
3. Minor items (5% of the Balance at End of Year for Account 254 or amounts less than $50,000, whichever is Less) may be grouped
by classes.
Idaho 1999 - NEEA (Nw energy efficiency act) 1,219,797131 1
2,367,578 728,760 609,332254 2
3
Demand Side Management Rider 29026 53,713131 4
83,686142 5
198,222254 6
1,351,473 1,808,295 121,201401 7
8
BPA Credit-Residential - Idaho 13,675131 9
992,235 19,646,178 19,235,702142 10
11
BPA Credit-Residential - Oregon 288131 12
60,743 762,592 724,406142 13
14
BPA Credit-Farm - Idaho 89,227 3,951,892 4,204,085142 15
16
BPA Credit-Farm - Oregon 4,486 210,166 215,366142 17
18
BPA Credit - Conservation 156,748131 19
448,490 264,156254 20
21
Pre94 Demand Side Management Order 235,024 235,024 22
23
24
Boise Operation Center 125,217 31,970401 25
26
27
Unfunded Accumulated Deferred Income Tax 41,012,859 495,143 772,152190 28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO. 1 (ED. 12-94)Page 278
41 TOTAL 27,838,050 27,904,499 46,687,332
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
ELECTRIC OPERATING REVENUES (Account 400)
Idaho Power Company X
04/30/2003
2002
Line
No.
Title of Account
(c)(b)(a)
Amount for Previous YearAmount for Year
OPERATING REVENUES
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 increases or decreases from previous year (columns (c),(e), and (g)), are not derived from previously reported figures, explain any
inconsistencies in a footnote.
Sales of Electricity 1
260,251,206(440) Residential Sales 305,827,216 2
(442) Commercial and Industrial Sales 3
233,620,438Small (or Comm.) (See Instr. 4) 286,812,049 4
154,317,682Large (or Ind.) (See Instr. 4) 176,648,064 5
2,419,039(444) Public Street and Highway Lighting 2,747,434 6
(445) Other Sales to Public Authorities 7
(446) Sales to Railroads and Railways 8
(448) Interdepartmental Sales 9
650,608,365TOTAL Sales to Ultimate Consumers 772,034,763 10
219,966,420(447) Sales for Resale 55,031,087 11
870,574,785TOTAL Sales of Electricity 827,065,850 12
-1,823,627(Less) (449.1) Provision for Rate Refunds 13
872,398,412TOTAL Revenues Net of Prov. for Refunds 827,065,850 14
Other Operating Revenues 15
(450) Forfeited Discounts 16
3,255,111(451) Miscellaneous Service Revenues 3,355,823 17
(453) Sales of Water and Water Power 18
17,954,524(454) Rent from Electric Property 19,213,988 19
(455) Interdepartmental Rents 20
18,703,506(456) Other Electric Revenues 17,411,759 21
22
23
24
25
39,913,141TOTAL Other Operating Revenues 39,981,570 26
912,311,553TOTAL Electric Operating Revenues 867,047,420 27
FERC FORM NO. 1 (ED. 12-96)Page 300
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
ELECTRIC OPERATING REVENUES (Account 400)
Idaho Power Company X
04/30/2003
2002
Line
No.
MEGAWATT HOURS SOLD
Number for Previous YearNumber for Year
AVG.NO. CUSTOMERS PER MONTH
Amount for Year Amount for Previous Year
(d)(e)(f)(g)
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 basis of classification in a footnote.)
5. See pages 108-109, Important Changes During Year, for important new territory added and important rate increase 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.
1
4,306,996 331,275 339,764 4,386,794 2
3
4,772,190 66,646 67,622 5,253,004 4
3,924,637 115 115 3,225,781 5
27,202 255 327 28,489 6
7
8
9
13,031,025 398,291 407,828 12,894,068 10
2,387,206 2,068,504 11
15,418,231 398,291 407,828 14,962,572 12
13
15,418,231 398,291 407,828 14,962,572 14
FERC FORM NO. 1 (ED. 12-96)Page 301
Line 12, column (b) includes $ of unbilled revenues.
Line 12, column (d) includes MWH relating to unbilled revenues
-168,653
-1,757
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
SALES OF ELECTRICITY BY RATE SCHEDULES
Idaho Power Company X
04/30/2003
2002
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Number
of Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
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.
1 440 - Residential Sales:
4,423,109 339,750 13,019 0.0696 307,956,575 2 01 - Residential
3,272 14 233,714 0.0669 218,805 3 03 - Residential-Mastered Metere
36 0.0692 2,491 4 84 - Residential-Net Metering
2,450 0.2727 668,101 5 15 - Dusk to dawn lighting
-42,073 0.0718 -3,018,756 6 Unbilled Revenues
4,386,794 339,764 12,911 0.0697 305,827,216 7 Total 440
8
9 442-Commercial & Industrial Sales
287,633 33,599 8,561 0.0793 22,816,411 10 07 - General service
3,125,975 17,935 174,295 0.0539 168,396,169 11 09 - General service
77 3 25,667 0.5963 45,918 12 10 - Large power winter service
14 0.0536 750 13 84 - General Service - Net Meter
3,801 0.2456 933,664 14 15 - Dusk to dawn lighting
2,159,231 111 19,452,532 0.0439 94,711,656 15 19 - Uniform rate contracts
16 21 - Interruptible irrigation
1 1 1,000 0.3120 312 17 22 - Limited use Prairie Power
1,728,223 15,034 114,954 0.0513 88,574,555 18 24 - Irrigation Pumping
87,785 0.0492 4,316,308 19 25 - Irrigation Pumping -Time of
15,478 1,050 14,741 0.0756 1,170,532 20 40 - General service
1,070,567 0.0771 82,493,838 21 Commercial & Industrial & Unbill
8,478,785 67,733 125,180 0.0547 463,460,113 22 Total 442
23
24 444 - Public Street Lighting:
31 1 31,000 0.2089 6,476 25 32 - Shielded Streel Lighting
780 130 6,000 0.0758 59,096 26 40 - General service
18,347 132 138,992 0.1216 2,230,645 27 41 - Street lighting
9,333 64 145,828 0.0483 451,217 28 42 - Traffic control lighting
29 Public Lighting
28,491 327 87,128 0.0964 2,747,434 30 Total 444
31
32
33
34
35
36
37
38
39
40
12,894,068 772,034,763 0 0 0.0598
-17,576 -1,686,536 0 0 0.0960
12,911,644 773,721,299 0 0 0.0599
FERC FORM NO. 1 (ED. 12-95)Page 304
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
SALES FOR RESALE (Account 447)
Idaho Power Company X
04/30/2003 2002
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate
Monthly Billing
Average
(d)
Statistical
cation
Classifi-Schedule orTariff Number Demand (MW)
(e)(f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
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.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Raft River Rural Electric 8.4129.4219.421V6-44RQ 1
City of Weiser 8.5179.2129.212V6-32RQ 2
AEP Service Corp.0.0000.0000.000WSPPSF 3
Bonneville Power Administration 0.0000.0000.000WSPPOS 4
Bonneville Power Administration 0.0000.0000.000WSPPSF 5
BP Energy Company 0.0000.0000.000WSPPOS 6
BP Energy Company 0.0000.0000.000WSPPSF 7
Chelan Co PUD 0.0000.0000.000WSPPSF 8
Clatskanie PUD 0.0000.0000.000-OS 9
Clatskanie PUD 0.0000.0000.000-SF 10
Colton, City of 0.0000.0000.00084LF 11
Duke Energy Trading and Marketing 0.0000.0000.000WSPPOS 12
Dynegy Power Marketing, Inc.0.0000.0000.000WSPPSF 13
Enron Power Marketing 0.0000.0000.000WSPPSF 14
FERC FORM NO. 1 (ED. 12-90)Page 310
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
SALES FOR RESALE (Account 447)
Idaho Power Company X
04/30/2003 2002
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate
Monthly Billing
Average
(d)
Statistical
cation
Classifi-Schedule orTariff Number Demand (MW)
(e)(f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
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.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Enron Power Marketing (2)0.0000.0000.000WSPPSF 1
Entergy-Koch Trading, LP 0.0000.0000.000WSPPSF 2
Eugene Water & Electric Board 0.0000.0000.000WSPPOS 3
Eugene Water & Electric Board 0.0000.0000.000WSPPSF 4
Franklin County P.U.D.0.0000.0000.000WSPPOS 5
Grant County P.U.D.0.0000.0000.000WSPPOS 6
Grant County P.U.D.0.0000.0000.000WSPPSF 7
IDACORP Energy L.P.0.0000.0000.000V6-48SF 8
IDACORP Energy L.P (2)0.0000.0000.000V6-48SF 9
Mieco, Inc.0.0000.0000.000WSPPOS 10
Mieco, Inc.0.0000.0000.000WSPPSF 11
Morgan Stanley Capital Group Inc.0.0000.0000.000WSPPSF 12
NorthWestern Energy, L.L.C.0.0000.0000.000WSPPOS 13
NorthWestern Energy, L.L.C.0.0000.0000.000WSPPSF 14
FERC FORM NO. 1 (ED. 12-90)Page 310.1
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
SALES FOR RESALE (Account 447)
Idaho Power Company X
04/30/2003 2002
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate
Monthly Billing
Average
(d)
Statistical
cation
Classifi-Schedule orTariff Number Demand (MW)
(e)(f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
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.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Pacific Northwest Generating Cooper 0.0000.0000.000WSPPOS 1
PacifiCorp Inc.0.0000.0000.000WSPPOS 2
PacifiCorp Inc.0.0000.0000.000WSPPSF 3
Pinnacle West Capital Corporation 0.0000.0000.000WSPPSF 4
Portland General Electric Company 0.0000.0000.000WSPPOS 5
Portland General Electric Company 0.0000.0000.000WSPPSF 6
Powerex Corp.0.0000.0000.000WSPPOS 7
Powerex Corp.0.0000.0000.000WSPPSF 8
PPL Montana, LLC 0.0000.0000.000WSPPOS 9
PPL Montana, LLC 0.0000.0000.000WSPPSF 10
Public Service Co. of Colorado 0.0000.0000.000WSPPOS 11
Public Service Comp of New Mexico 0.0000.0000.000WSPPOS 12
Public Service Comp of New Mexico 0.0000.0000.000WSPPSF 13
Puget Sound Energy, Inc.0.0000.0000.000WSPPOS 14
FERC FORM NO. 1 (ED. 12-90)Page 310.2
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
SALES FOR RESALE (Account 447)
Idaho Power Company X
04/30/2003 2002
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate
Monthly Billing
Average
(d)
Statistical
cation
Classifi-Schedule orTariff Number Demand (MW)
(e)(f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
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.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Puget Sound Energy, Inc.0.0000.0000.000WSPPSF 1
Reliant Energy Services, Inc.0.0000.0000.000WSPPSF 2
Salt River Project 0.0000.0000.000WSPPOS 3
Seattle City Light 0.0000.0000.000WSPPOS 4
Seattle City Light 0.0000.0000.000WSPPSF 5
Sempra Energy Trading Corp 0.0000.0000.000WSPPSF 6
Sierra Pacific Power Company 0.0000.0000.000WSPPOS 7
Sierra Pacific Power Company 0.0000.0000.000WSPPSF 8
Snohomish County PUD 0.0000.0000.000WSPPOS 9
Snohomish County PUD 0.0000.0000.000WSPPSF 10
TransAlta Energy Marketing (U.S.) I 0.0000.0000.000WSPPSF 11
Tri-State Generation and Transmissi 0.0000.0000.000WSPPSF 12
Utah Associated Municipal Power Sys 0.0000.0000.00075LF 13
Utah Associated Municipal Power Sys 0.0000.0000.000WSPPOS 14
FERC FORM NO. 1 (ED. 12-90)Page 310.3
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
SALES FOR RESALE (Account 447)
Idaho Power Company X
04/30/2003 2002
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate
Monthly Billing
Average
(d)
Statistical
cation
Classifi-Schedule orTariff Number Demand (MW)
(e)(f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
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.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Washington, UT, City of 0.0000.0000.00074LF 1
Western Area Power Administration 0.0000.0000.000WSPPOS 2
Williams Energy Marketing & Trading 0.0000.0000.000WSPPSF 3
4
5
6
7
8
9
10
11
12
13
14
FERC FORM NO. 1 (ED. 12-90)Page 310.4
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
SALES FOR RESALE (Account 447) (Continued)
Idaho Power Company X
04/30/2003 2002
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)
Total ($)REVENUE
($)($)($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total'' in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (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 RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
1,164,923 174,307 3,000 1,342,230 54,988 1
1,025,877 365,897 570 1,392,344 51,294 2
1,284,988 1,284,988 52,850 3
99,005 99,005 4,073 4
50,300 50,300 1,600 5
9,700 9,700 300 6
379,500 379,500 10,000 7
394,200 394,200 10,841 8
2,850 2,850 150 9
7,020 7,020 240 10
712,214 712,214 24,934 11
25,910 25,910 780 12
488,800 488,800 20,800 13
2,139,000 2,139,000 74,400 14
FERC FORM NO. 1 (ED. 12-90)Page 311
2,190,800
44,788,684
46,979,484
106,282
1,962,222
2,068,504
3,570 2,734,574
0
3,570
52,296,513
55,031,087
540,204
7,507,829
8,048,033
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
SALES FOR RESALE (Account 447) (Continued)
Idaho Power Company X
04/30/2003 2002
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)
Total ($)REVENUE
($)($)($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total'' in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (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 RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
2,571,200 2,571,200 87,200 1
338,660 338,660 10,400 2
10,610 10,610 450 3
175,200 175,200 5,400 4
525 525 35 5
8,000 8,000 400 6
3,900 3,900 200 7
16,993,428 2,356,529 19,349,957 811,039 8
183,986 1,371,300 1,555,286 1 9
2,100 2,100 50 10
286,300 286,300 8,200 11
1,597,504 1,597,504 43,376 12
222,795 222,795 6,981 13
70,500 70,500 2,400 14
FERC FORM NO. 1 (ED. 12-90)Page 311.1
2,190,800
44,788,684
46,979,484
106,282
1,962,222
2,068,504
3,570 2,734,574
0
3,570
52,296,513
55,031,087
540,204
7,507,829
8,048,033
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
SALES FOR RESALE (Account 447) (Continued)
Idaho Power Company X
04/30/2003 2002
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)
Total ($)REVENUE
($)($)($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total'' in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (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 RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
32,526 32,526 1,267 1
250,185 250,185 9,795 2
1,980,661 1,980,661 79,180 3
2,465,200 2,465,200 87,200 4
226,468 226,468 9,060 5
1,884,863 1,884,863 60,150 6
277,030 277,030 11,767 7
617,888 617,888 22,825 8
32,482 32,482 1,009 9
151,640 151,640 3,830 10
39,734 39,734 999 11
31,600 31,600 1,024 12
75,000 75,000 2,200 13
15,796 15,796 683 14
FERC FORM NO. 1 (ED. 12-90)Page 311.2
2,190,800
44,788,684
46,979,484
106,282
1,962,222
2,068,504
3,570 2,734,574
0
3,570
52,296,513
55,031,087
540,204
7,507,829
8,048,033
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
SALES FOR RESALE (Account 447) (Continued)
Idaho Power Company X
04/30/2003 2002
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)
Total ($)REVENUE
($)($)($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total'' in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (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 RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
66,400 66,400 2,200 1
14,600 14,600 400 2
2,900 2,900 100 3
127,502 127,502 5,076 4
513,885 513,885 20,346 5
49,600 49,600 1,200 6
4,320 4,320 216 7
1,786 1,786 94 8
53,550 53,550 1,605 9
18,000 18,000 800 10
268,810 268,810 7,400 11
120,122 120,122 242 12
6,449,067 3,480,750 9,929,817 399,870 13
1,499 1,499 50 14
FERC FORM NO. 1 (ED. 12-90)Page 311.3
2,190,800
44,788,684
46,979,484
106,282
1,962,222
2,068,504
3,570 2,734,574
0
3,570
52,296,513
55,031,087
540,204
7,507,829
8,048,033
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
SALES FOR RESALE (Account 447) (Continued)
Idaho Power Company X
04/30/2003 2002
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)
Total ($)REVENUE
($)($)($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total'' in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (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 RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
419,650 299,250 718,900 28,694 1
13,050 13,050 290 2
524,675 524,675 25,550 3
4
5
6
7
8
9
10
11
12
13
14
FERC FORM NO. 1 (ED. 12-90)Page 311.4
2,190,800
44,788,684
46,979,484
106,282
1,962,222
2,068,504
3,570 2,734,574
0
3,570
52,296,513
55,031,087
540,204
7,507,829
8,048,033
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/30/2003
Year of Report
Dec 31, 2002
FOOTNOTE DATA
Schedule Page: 310 Line No.: 1 Column: j
Customer Charge
Schedule Page: 310 Line No.: 2 Column: j
Schedule Page: 310 Line No.: 11 Column: a
Schedule Page: 310.3 Line No.: 13 Column: a
Schedule Page: 310.4 Line No.: 1 Column: a
FERC FORM NO. 1 (ED. 12-87)Page 450
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31, Idaho Power Company X
04/30/2003
2002
Line
No.
Account Amount for
(c)(b)(a)
Current Year Previous YearAmount for
If the amount for previous year is not derived from previously reported figures, explain in footnote.
1. POWER PRODUCTION EXPENSES 1
A. Steam Power Generation 2
Operation 3
(500) Operation Supervision and Engineering 4 1,050,676 1,013,741
(501) Fuel 5 95,371,284 98,346,451
(502) Steam Expenses 6 5,499,015 3,747,655
(503) Steam from Other Sources 7
(Less) (504) Steam Transferred-Cr. 8
(505) Electric Expenses 9 1,445,746 1,039,067
(506) Miscellaneous Steam Power Expenses 10 5,520,974 3,810,131
(507) Rents 11 626,935 732,669
(509) Allowances 12
TOTAL Operation (Enter Total of Lines 4 thru 12) 13 109,514,630 108,689,714
Maintenance 14
(510) Maintenance Supervision and Engineering 15 1,871,602 1,855,715
(511) Maintenance of Structures 16 167,964 153,018
(512) Maintenance of Boiler Plant 17 8,734,101 8,450,566
(513) Maintenance of Electric Plant 18 3,464,403 2,808,027
(514) Maintenance of Miscellaneous Steam Plant 19 8,055,570 8,872,260
TOTAL Maintenance (Enter Total of Lines 15 thru 19) 20 22,293,640 22,139,586
TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 & 20) 21 131,808,270 130,829,300
B. Nuclear Power Generation 22
Operation 23
(517) Operation Supervision and Engineering 24
(518) Fuel 25
(519) Coolants and Water 26
(520) Steam Expenses 27
(521) Steam from Other Sources 28
(Less) (522) Steam Transferred-Cr. 29
(523) Electric Expenses 30
(524) Miscellaneous Nuclear Power Expenses 31
(525) Rents 32
TOTAL Operation (Enter Total of lines 24 thru 32) 33
Maintenance 34
(528) Maintenance Supervision and Engineering 35
(529) Maintenance of Structures 36
(530) Maintenance of Reactor Plant Equipment 37
(531) Maintenance of Electric Plant 38
(532) Maintenance of Miscellaneous Nuclear Plant 39
TOTAL Maintenance (Enter Total of lines 35 thru 39) 40
TOTAL Power Production Expenses-Nuc. Power (Entr tot lines 33 & 40) 41
C. Hydraulic Power Generation 42
Operation 43
(535) Operation Supervision and Engineering 44 3,372,540 4,140,933
(536) Water for Power 45 3,208,010 3,027,065
(537) Hydraulic Expenses 46 4,507,941 4,948,636
(538) Electric Expenses 47 1,279,305 944,540
(539) Miscellaneous Hydraulic Power Generation Expenses 48 1,723,166 1,678,676
(540) Rents 49 303,528 383,569
TOTAL Operation (Enter Total of Lines 44 thru 49) 50 14,394,490 15,123,419
FERC FORM NO. 1 (ED. 12-93)Page 320
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31, Idaho Power Company X
04/30/2003
2002
Line
No.
Account Amount for
(c)(b)(a)
Current Year Previous YearAmount for
If the amount for previous year is not derived from previously reported figures, explain in footnote.
C. Hydraulic Power Generation (Continued) 51
Maintenance 52
(541) Mainentance Supervision and Engineering 53 1,081,340 995,121
(542) Maintenance of Structures 54 1,010,625 1,263,109
(543) Maintenance of Reservoirs, Dams, and Waterways 55 503,908 738,221
(544) Maintenance of Electric Plant 56 2,047,239 2,141,465
(545) Maintenance of Miscellaneous Hydraulic Plant 57 2,131,428 2,223,081
TOTAL Maintenance (Enter Total of lines 53 thru 57) 58 6,774,540 7,360,997
TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 & 58) 59 21,169,030 22,484,416
D. Other Power Generation 60
Operation 61
(546) Operation Supervision and Engineering 62 168,973 311,907
(547) Fuel 63 2,947,157 4,524,143
(548) Generation Expenses 64 503,585 325,877
(549) Miscellaneous Other Power Generation Expenses 65 326,432 405,666
(550) Rents 66 5,138,643 18,372
TOTAL Operation (Enter Total of lines 62 thru 66) 67 9,084,790 5,585,965
Maintenance 68
(551) Maintenance Supervision and Engineering 69 55 933
(552) Maintenance of Structures 70 14,535 163,166
(553) Maintenance of Generating and Electric Plant 71 260,333 222,325
(554) Maintenance of Miscellaneous Other Power Generation Plant 72 351,528
TOTAL Maintenance (Enter Total of lines 69 thru 72) 73 274,923 737,952
TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73) 74 9,359,713 6,323,917
E. Other Power Supply Expenses 75
(555) Purchased Power 76 584,209,158 142,102,234
(556) System Control and Load Dispatching 77 743,677 11,024
(557) Other Expenses 78 -174,120,475 173,448,997
TOTAL Other Power Supply Exp (Enter Total of lines 76 thru 78) 79 410,832,360 315,562,255
TOTAL Power Production Expenses (Total of lines 21, 41, 59, 74 & 79) 80 573,169,373 475,199,888
2. TRANSMISSION EXPENSES 81
Operation 82
(560) Operation Supervision and Engineering 83 1,951,573 1,774,243
(561) Load Dispatching 84 2,380,097 2,416,264
(562) Station Expenses 85 1,247,486 1,837,539
(563) Overhead Lines Expenses 86 546,695 568,785
(564) Underground Lines Expenses 87
(565) Transmission of Electricity by Others 88 1,521,950 2,213,424
(566) Miscellaneous Transmission Expenses 89 435,479 420,442
(567) Rents 90 1,323,777 1,648,202
TOTAL Operation (Enter Total of lines 83 thru 90) 91 9,407,057 10,878,899
Maintenance 92
(568) Maintenance Supervision and Engineering 93 838,863 774,852
(569) Maintenance of Structures 94 262 57,644
(570) Maintenance of Station Equipment 95 3,146,988 1,447,053
(571) Maintenance of Overhead Lines 96 2,457,952 2,291,863
(572) Maintenance of Underground Lines 97
(573) Maintenance of Miscellaneous Transmission Plant 98 13,399 9,359
TOTAL Maintenance (Enter Total of lines 93 thru 98) 99 6,457,464 4,580,771
TOTAL Transmission Expenses (Enter Total of lines 91 and 99) 100 15,864,521 15,459,670
3. DISTRIBUTION EXPENSES 101
Operation 102
(580) Operation Supervision and Engineering 103 3,382,658 3,363,654
FERC FORM NO. 1 (ED. 12-93)Page 321
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31, Idaho Power Company X
04/30/2003
2002
Line
No.
Account Amount for
(c)(b)(a)
Current Year Previous YearAmount for
If the amount for previous year is not derived from previously reported figures, explain in footnote.
3. DISTRIBUTION Expenses (Continued) 104
(581) Load Dispatching 105 2,625,877 2,354,991
(582) Station Expenses 106 1,346,156 1,373,812
(583) Overhead Line Expenses 107 3,777,453 3,592,457
(584) Underground Line Expenses 108 2,542,445 2,353,356
(585) Street Lighting and Signal System Expenses 109 373,290 371,306
(586) Meter Expenses 110 4,724,574 6,075,032
(587) Customer Installations Expenses 111 525,628 491,519
(588) Miscellaneous Expenses 112 3,714,463 3,660,582
(589) Rents 113 166,530 169,860
TOTAL Operation (Enter Total of lines 103 thru 113) 114 23,179,074 23,806,569
Maintenance 115
(590) Maintenance Supervision and Engineering 116 89,333 64,762
(591) Maintenance of Structures 117 2,162 6,000
(592) Maintenance of Station Equipment 118 2,781,089 2,636,012
(593) Maintenance of Overhead Lines 119 10,872,200 10,914,719
(594) Maintenance of Underground Lines 120 1,383,311 1,180,556
(595) Maintenance of Line Transformers 121 1,669,217 1,408,730
(596) Maintenance of Street Lighting and Signal Systems 122 66,535 273,422
(597) Maintenance of Meters 123 1,734,298 1,491,396
(598) Maintenance of Miscellaneous Distribution Plant 124 208,850 161,683
TOTAL Maintenance (Enter Total of lines 116 thru 124) 125 18,806,995 18,137,280
TOTAL Distribution Exp (Enter Total of lines 114 and 125) 126 41,986,069 41,943,849
4. CUSTOMER ACCOUNTS EXPENSES 127
Operation 128
(901) Supervision 129 612,115 412,133
(902) Meter Reading Expenses 130 4,293,139 4,367,046
(903) Customer Records and Collection Expenses 131 8,932,866 6,873,881
(904) Uncollectible Accounts 132 3,606,470 4,765,303
(905) Miscellaneous Customer Accounts Expenses 133 2,341 2,266
TOTAL Customer Accounts Expenses (Total of lines 129 thru 133) 134 17,446,931 16,420,629
5. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES 135
Operation 136
(907) Supervision 137 160,783 265,513
(908) Customer Assistance Expenses 138 8,275,752 7,838,129
(909) Informational and Instructional Expenses 139 18,251 25
(910) Miscellaneous Customer Service and Informational Expenses 140 295,187 487,125
TOTAL Cust. Service and Information. Exp. (Total lines 137 thru 140) 141 8,749,973 8,590,792
6. SALES EXPENSES 142
Operation 143
(911) Supervision 144
(912) Demonstrating and Selling Expenses 145
(913) Advertising Expenses 146
(916) Miscellaneous Sales Expenses 147
TOTAL Sales Expenses (Enter Total of lines 144 thru 147) 148
7. ADMINISTRATIVE AND GENERAL EXPENSES 149
Operation 150
(920) Administrative and General Salaries 151 33,743,434 29,332,171
(921) Office Supplies and Expenses 152 15,501,063 17,149,539
(Less) (922) Administrative Expenses Transferred-Credit 153 18,801,480 18,948,998
FERC FORM NO. 1 (ED. 12-93)Page 322
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31, Idaho Power Company X
04/30/2003
2002
Line
No.
Account Amount for
(c)(b)(a)
Current Year Previous YearAmount for
If the amount for previous year is not derived from previously reported figures, explain in footnote.
7. ADMINISTRATIVE AND GENERAL EXPENSES (Continued) 154
(923) Outside Services Employed 155 5,047,875 4,581,162
(924) Property Insurance 156 2,239,668 2,862,999
(925) Injuries and Damages 157 2,954,301 2,764,991
(926) Employee Pensions and Benefits 158 10,589,654 18,547,555
(927) Franchise Requirements 159 1,575 1,750
(928) Regulatory Commission Expenses 160 3,515,247 3,473,789
(929) (Less) Duplicate Charges-Cr. 161
(930.1) General Advertising Expenses 162 836,839 578,126
(930.2) Miscellaneous General Expenses 163 1,411,712 1,316,830
(931) Rents 164 32,292 28,169
TOTAL Operation (Enter Total of lines 151 thru 164) 165 57,072,180 61,688,083
Maintenance 166
(935) Maintenance of General Plant 167 1,269,016 1,642,670
TOTAL Admin & General Expenses (Total of lines 165 thru 167) 168 58,341,196 63,330,753
TOTAL Elec Op and Maint Expn (Tot 80, 100, 126, 134, 141, 148, 168) 169 715,558,063 620,945,581
FERC FORM NO. 1 (ED. 12-93)Page 323
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
PURCHASED POWER (Account 555)
Idaho Power Company X
04/30/2003 2002
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate
Monthly Billing
Average
(d)
Statistical
cation
Classifi-Schedule or
Tariff Number Demand (MW)
(e)(f)
(Footnote Affiliations)
Actual Demand (MW)
Average Average
Monthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Cogeneration and Small Power Producers 1
N/AN/AN/AWillis and Betty Deveny -LU 2
N/AN/AN/AJames B Howell -LU 3
N/AN/A4.942MwTamarack Energy Partnership -LU 4
Owyhee Irrigation District 5
N/AN/AN/A Mitchell Butte -LU 6
N/AN/AN/A Owyhee Dam -LU 7
N/AN/AN/A Tunnel #1 -LU 8
N/AN/AN/AReynolds Irrigation District -LU 9
N/AN/A.05MwClifton E. Jenson -LU 10
N/AN/AN/ASnake River Pottery -LU 11
N/AN/AN/AWhite Water Ranch -LU 12
N/AN/AN/AJohn R LeMoyne -LU 13
N/AN/AN/ADavid R Snedigar -LU 14
FERC FORM NO. 1 (ED. 12-90)Page 326
Total
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
PURCHASED POWER (Account 555)
Idaho Power Company X
04/30/2003 2002
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate
Monthly Billing
Average
(d)
Statistical
cation
Classifi-Schedule or
Tariff Number Demand (MW)
(e)(f)
(Footnote Affiliations)
Actual Demand (MW)
Average Average
Monthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
N/AN/AN/AMud Creek Hydro -LU 1
N/AN/AN/ARim View Trout Company -OS 2
N/AN/A.084MwCurry Cattle Company -LU 3
N/AN/AN/ABranchflower Company -LU 4
Big Wood Canal Company 5
N/AN/AN/A Black Canyon -LU 6
N/AN/AN/A Jim Knight -LU 7
N/AN/AN/A Sagebrush -LU 8
N/AN/AN/AFisheries Development -OS 9
Shorock Hydro 10
N/AN/AN/A Shoshone -LU 11
N/AN/AN/A Shoshone #2 -LU 12
N/AN/A1.732MwRock Creek Joint Venture -LU 13
N/AN/AN/ARichard Kaster 14
FERC FORM NO. 1 (ED. 12-90)Page 326.1
Total
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
PURCHASED POWER (Account 555)
Idaho Power Company X
04/30/2003 2002
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate
Monthly Billing
Average
(d)
Statistical
cation
Classifi-Schedule or
Tariff Number Demand (MW)
(e)(f)
(Footnote Affiliations)
Actual Demand (MW)
Average Average
Monthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
N/AN/AN/A Box Canyon -LU 1
N/AN/AN/A Briggs Creek -LU 2
N/AN/AN/AJ D McCollum -LU 3
N/AN/AN/AZions Credit Corp / Mud Creek S -LU 4
N/AN/A.488MwVernon Ravenscroft -LU 5
N/AN/AN/AWilliam Arkoosh -LU 6
N/AN/AN/AClear Springs Food Inc.-LU 7
N/AN/AN/AKoyle Hydro Inc.-LU 8
N/AN/AN/AKasel & Witherspoon -LU 9
N/AN/AN/ALateral 10 Ventures -LU 10
N/AN/AN/ACrystal Springs Hydro -LU 11
N/AN/A1.389Pigeon Cove Power -LU 12
N/AN/AN/ANotch Butte Hydro Co Inc.-LU 13
Consolidated Hydro Inc. 14
FERC FORM NO. 1 (ED. 12-90)Page 326.2
Total
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
PURCHASED POWER (Account 555)
Idaho Power Company X
04/30/2003 2002
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate
Monthly Billing
Average
(d)
Statistical
cation
Classifi-Schedule or
Tariff Number Demand (MW)
(e)(f)
(Footnote Affiliations)
Actual Demand (MW)
Average Average
Monthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
N/AN/AN/A Barber Dam -LU 1
N/AN/AN/A Rock Creek II -LU 2
N/AN/AN/A Dietrich Drop -LU 3
N/AN/AN/A Lowline #2 -LU 4
N/AN/AN/ACedar Draw/ Little Mac Power -LU 5
N/AN/AN/ASouth Forks Joint Venture -LU 6
N/AN/AN/ALittle Wood River Irrigation Dis -LU 7
N/AN/AN/ARancher's Irrigation District -LU 8
N/AN/AN/AFaulkner Brothers Hydro Inc.-LU 9
N/AN/AN/AMagic Reservoir Hydro -LU 10
N/AN/AN/ABypass Limited -LU 11
N/AN/AN/ASE Hazelton A LP -LU 12
N/AN/AN/AJerry L McMillan -OS 13
N/AN/AN/ALemhi HydroPower Company -LU 14
FERC FORM NO. 1 (ED. 12-90)Page 326.3
Total
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
PURCHASED POWER (Account 555)
Idaho Power Company X
04/30/2003 2002
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate
Monthly Billing
Average
(d)
Statistical
cation
Classifi-Schedule or
Tariff Number Demand (MW)
(e)(f)
(Footnote Affiliations)
Actual Demand (MW)
Average Average
Monthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
N/AN/AN/AJ R Simplot -LU 1
N/AN/AN/ABlind Canyon Hydro -LU 2
N/AN/AN/ACity of Boise -LU 3
N/AN/AN/ACity of Hailey -LU 4
N/AN/AN/ACity of Pocatello -LU 5
N/AN/AN/AMarysville Hydro Partners -LU 6
N/AN/AN/AWilson Power Company -LU 7
N/AN/AN/AHazelton Power Company -LU 8
N/AN/AN/APristine Springs -LU 9
N/AN/AN/AVaagen Brothers Lumber Inc.-LU 10
N/AN/AN/AHorseshoe Bend Hydro -LU 11
N/AN/AN/AContractors Power Group Inc.-LU 12
N/AN/AN/ARupert Cogeneration Partners -LU 13
N/AN/AN/AGlenns Ferry Cogeneration Partne -LU 14
FERC FORM NO. 1 (ED. 12-90)Page 326.4
Total
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
PURCHASED POWER (Account 555)
Idaho Power Company X
04/30/2003 2002
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate
Monthly Billing
Average
(d)
Statistical
cation
Classifi-Schedule or
Tariff Number Demand (MW)
(e)(f)
(Footnote Affiliations)
Actual Demand (MW)
Average Average
Monthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
N/AN/AN/ALewandowski Farms -OS 1
N/AN/AN/ATasco - Nampa -OS 2
N/AN/AN/ATasco - Twin Falls -OS 3
Energy Differences 4
5
Other Purchased Power 6
N/AN/AN/AAEP Service Corp.WSPPOS 7
N/AN/AN/AAEP Service Corp.WSPPSF 8
N/AN/AN/AAvista Corp. - WWP Div.WSPPOS 9
N/AN/AN/AAvista Corp. - WWP Div.WSPPSF 10
N/AN/AN/AAvista Energy, Inc.WSPPOS 11
N/AN/AN/AAvista Energy, Inc.WSPPSF 12
N/AN/AN/ABenton County PUD WSPPOS 13
N/AN/AN/ABenton County PUD WSPPSF 14
FERC FORM NO. 1 (ED. 12-90)Page 326.5
Total
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
PURCHASED POWER (Account 555)
Idaho Power Company X
04/30/2003 2002
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate
Monthly Billing
Average
(d)
Statistical
cation
Classifi-Schedule or
Tariff Number Demand (MW)
(e)(f)
(Footnote Affiliations)
Actual Demand (MW)
Average Average
Monthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
N/AN/AN/ABonneville Power Administration WSPPOS 1
N/AN/AN/ABonneville Power Administration WSPPSF 2
N/AN/AN/ABP Energy Company WSPPSF 3
N/AN/AN/ACargill-Alliant, LLC WSPPOS 4
N/AN/AN/AChelan Co PUD WSPPOS 5
N/AN/AN/AChelan Co PUD WSPPSF 6
N/AN/AN/AClatskanie PUD SF 7
N/AN/AN/AConstellation Power Source, Inc.WSPPOS 8
N/AN/AN/ADouglas County PUD WSPPOS 9
N/AN/AN/ADynegy Power Marketing, Inc.WSPPSF 10
N/AN/AN/AEl Paso Electric Company WSPPOS 11
N/AN/AN/AEl Paso Electric Company WSPPSF 12
N/AN/AN/AEl Paso Merchant Energy, L.P.WSPPSF 13
N/AN/AN/AEnron Power Marketing WSPPSF 14
FERC FORM NO. 1 (ED. 12-90)Page 326.6
Total
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
PURCHASED POWER (Account 555)
Idaho Power Company X
04/30/2003 2002
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate
Monthly Billing
Average
(d)
Statistical
cation
Classifi-Schedule or
Tariff Number Demand (MW)
(e)(f)
(Footnote Affiliations)
Actual Demand (MW)
Average Average
Monthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
N/AN/AN/AEnron Power Marketing WSPPSF 1
N/AN/AN/AEntergy-Koch Trading, LP WSPPSF 2
N/AN/AN/AEugene Water & Electric Board WSPPOS 3
N/AN/AN/AFranklin County P.U.D.WSPPOS 4
N/AN/AN/AFranklin County P.U.D.WSPPSF 5
N/AN/AN/AGrant County P.U.D.WSPPOS 6
N/AN/AN/AGrant County P.U.D.WSPPSF 7
N/AN/AN/AGrays Harbor PUD WSPPOS 8
N/AN/AN/AGrays Harbor PUD WSPPSF 9
N/AN/AN/AIDACORP Energy L.P.V6-48SF 10
N/AN/AN/AIDACORP Energy L.P.V6-48SF 11
N/AN/AN/AMieco, Inc.WSPPSF 12
N/AN/AN/AMorgan Stanley Capital Group Inc WSPPSF 13
N/AN/AN/ANevada Power Company WSPPOS 14
FERC FORM NO. 1 (ED. 12-90)Page 326.7
Total
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
PURCHASED POWER (Account 555)
Idaho Power Company X
04/30/2003 2002
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate
Monthly Billing
Average
(d)
Statistical
cation
Classifi-Schedule or
Tariff Number Demand (MW)
(e)(f)
(Footnote Affiliations)
Actual Demand (MW)
Average Average
Monthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
N/AN/AN/ANorthPoint Energy Solutions Inc.WSPPOS 1
N/AN/AN/ANorthWestern Energy, L.L.C.WSPPOS 2
N/AN/AN/ANorthWestern Energy, L.L.C.WSPPSF 3
N/AN/AN/APacifiCorp Inc.WSPPOS 4
N/AN/AN/APacifiCorp Inc.WSPPSF 5
N/AN/AN/APacifiCorp Power Marketing, Inc.WSPPOS 6
N/AN/AN/APacifiCorp Power Marketing, Inc.WSPPSF 7
N/AN/AN/APG&E Energy Trading - Power LP WSPPSF 8
N/AN/AN/APinnacle West Capital Corporatio WSPPOS 9
N/AN/AN/APinnacle West Capital Corporatio WSPPSF 10
N/AN/AN/APortland General Electric Compan WSPPOS 11
N/AN/AN/APortland General Electric Compan WSPPSF 12
N/AN/AN/APortland General Electric Compan SF 13
N/AN/AN/APowerex Corp.WSPPOS 14
FERC FORM NO. 1 (ED. 12-90)Page 326.8
Total
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
PURCHASED POWER (Account 555)
Idaho Power Company X
04/30/2003 2002
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate
Monthly Billing
Average
(d)
Statistical
cation
Classifi-Schedule or
Tariff Number Demand (MW)
(e)(f)
(Footnote Affiliations)
Actual Demand (MW)
Average Average
Monthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
N/AN/AN/APowerex Corp.WSPPSF 1
N/AN/AN/APPL Montana, LLC WSPPOS 2
N/AN/AN/APPL Montana, LLC WSPPSF 3
N/AN/AN/APublic Service Co. of Colorado WSPPOS 4
N/AN/AN/APublic Service Company of New Me WSPPOS 5
N/AN/AN/APublic Service Company of New Me WSPPSF 6
N/AN/AN/APuget Sound Energy, Inc.WSPPOS 7
N/AN/AN/APuget Sound Energy, Inc.WSPPSF 8
N/AN/AN/ARocky Mountain Generation WSPPOS 9
N/AN/AN/ASalt River Project WSPPOS 10
N/AN/AN/ASeattle City Light WSPPOS 11
N/AN/AN/ASeattle City Light WSPPSF 12
N/AN/AN/ASierra Pacific Power Company WSPPOS 13
N/AN/AN/ASierra Pacific Power Company WSPPSF 14
FERC FORM NO. 1 (ED. 12-90)Page 326.9
Total
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
PURCHASED POWER (Account 555)
Idaho Power Company X
04/30/2003 2002
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate
Monthly Billing
Average
(d)
Statistical
cation
Classifi-Schedule or
Tariff Number Demand (MW)
(e)(f)
(Footnote Affiliations)
Actual Demand (MW)
Average Average
Monthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
N/AN/AN/ASnohomish County PUD WSPPOS 1
N/AN/AN/ASnohomish County PUD WSPPSF 2
N/AN/AN/ATacoma Power WSPPOS 3
N/AN/AN/ATacoma Power WSPPSF 4
N/AN/AN/ATractebel Energy Marketing, Inc.WSPPSF 5
N/AN/AN/ATransAlta Energy Marketing (U.S.WSPPOS 6
N/AN/AN/ATransAlta Energy Marketing (U.S.WSPPSF 7
N/AN/AN/ATri-State Generation and Transmi WSPPOS 8
N/AN/AN/ATri-State Generation and Transmi WSPPSF 9
N/AN/AN/ATurlock Irrigation District WSPPOS 10
N/AN/AN/ATurlock Irrigation District WSPPSF 11
N/AN/AN/AUtah Associated Municipal Power WSPPOS 12
N/AN/AN/AUtah Associated Municipal Power WSPPSF 13
N/AN/AN/AWestern Area Power Administratio WSPPOS 14
FERC FORM NO. 1 (ED. 12-90)Page 326.10
Total
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
PURCHASED POWER (Account 555)
Idaho Power Company X
04/30/2003 2002
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate
Monthly Billing
Average
(d)
Statistical
cation
Classifi-Schedule or
Tariff Number Demand (MW)
(e)(f)
(Footnote Affiliations)
Actual Demand (MW)
Average Average
Monthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
N/AN/AN/AWestern Area Power Administratio WSPPOS 1
N/AN/AN/AVoluntary Irrigation Load Reduct -OS 2
N/AN/AN/AAstaris, LLC -OS 3
N/AN/AN/AInsurance Recovery -OS 4
5
Power Exchanges 6
City of Seattle 71EX 7
PPL Montana, LLC 70EX 8
Bonneville Power Adm WSPPEX 9
Sierra Pacific Power Company WSPPEX 10
Bonneville Power Administration -EX 11
Montana Power Co.-EX 12
NorthWestern Energy, L.L.C.-EX 13
PacifiCorp Inc.-EX 14
FERC FORM NO. 1 (ED. 12-90)Page 326.11
Total
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
PURCHASED POWER (Account 555)
Idaho Power Company X
04/30/2003 2002
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate
Monthly Billing
Average
(d)
Statistical
cation
Classifi-Schedule or
Tariff Number Demand (MW)
(e)(f)
(Footnote Affiliations)
Actual Demand (MW)
Average Average
Monthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Seattle City Light -EX 1
Sierra Pacific Power Company -EX 2
Other Transactions 3
Acctg Valuation of City 4
of Seattle Exchange 5
Acctg Valuation of Sierra 6
Pacific Power Co Exchange 7
8
9
10
11
12
13
14
FERC FORM NO. 1 (ED. 12-90)Page 326.12
Total
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
PURCHASED POWER(Account 555) (Continued)
Idaho Power Company X
04/30/2003 2002
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($)($)($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered
(l)(m)
of Settlement ($)
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 (l). Explain in a footnote all components of the amount shown in column (l). 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 (l)
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.
1
49,077 49,077 2 748
251,766 251,766 3 3,886
1,576,498 1,401,787 2,978,285 4 41,638
5
412,226 412,226 6 5,611
1,120,878 1,120,878 7 17,348
685,905 685,905 8 7,539
105,296 105,296 9 1,496
17,500 7,184 24,684 10 291
25,094 25,094 11 402
42,312 42,312 12 682
34,639 34,639 13 644
92,609 92,609 14 1,444
FERC FORM NO. 1 (ED. 12-90)Page 327
2,855,620 477,026 496,849 2,812,891 137,796,388 1,492,955 142,102,234
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
PURCHASED POWER(Account 555) (Continued)
Idaho Power Company X
04/30/2003 2002
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($)($)($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered
(l)(m)
of Settlement ($)
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 (l). Explain in a footnote all components of the amount shown in column (l). 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 (l)
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.
22,803 22,803 1 376
24,950 24,950 2 1,578
24,563 15,738 40,301 3 639
59,753 59,753 4 913
5
19,149 19,149 6 295
50,801 50,801 7 777
65,107 65,107 8 976
13,752 13,752 9 809
10
121,975 121,975 11 1,615
119,731 119,731 12 1,861
552,508 252,034 804,542 13 10,225
14
FERC FORM NO. 1 (ED. 12-90)Page 327.1
2,855,620 477,026 496,849 2,812,891 137,796,388 1,492,955 142,102,234
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
PURCHASED POWER(Account 555) (Continued)
Idaho Power Company X
04/30/2003 2002
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($)($)($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered
(l)(m)
of Settlement ($)
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 (l). Explain in a footnote all components of the amount shown in column (l). 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 (l)
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.
100,311 100,311 1 1,627
238,240 238,240 2 3,804
55,440 55,440 3 812
87,763 87,763 4 1,276
155,672 29,950 185,622 5 1,215
208,161 208,161 6 2,962
293,260 293,260 7 3,636
248,307 248,307 8 3,186
255,563 255,563 9 3,496
371,201 371,201 10 6,110
432,997 432,997 11 7,026
486,150 164,023 650,173 12 7,654
187,042 187,042 13 2,634
14
FERC FORM NO. 1 (ED. 12-90)Page 327.2
2,855,620 477,026 496,849 2,812,891 137,796,388 1,492,955 142,102,234
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
PURCHASED POWER(Account 555) (Continued)
Idaho Power Company X
04/30/2003 2002
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($)($)($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered
(l)(m)
of Settlement ($)
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 (l). Explain in a footnote all components of the amount shown in column (l). 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 (l)
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.
479,570 479,570 1 10,303
245,505 245,505 2 5,287
662,244 662,244 3 13,187
436,757 436,757 4 8,952
307,804 307,804 5 5,114
1,701,112 1,701,112 6 25,032
218,450 218,450 7 3,031
131,072 131,072 8 2,083
166,080 166,080 9 2,302
171,355 171,355 10 4,031
1,146,578 1,146,578 11 23,379
946,597 946,597 12 20,298
2,301 2,301 13 146
72,119 72,119 14 1,010
FERC FORM NO. 1 (ED. 12-90)Page 327.3
2,855,620 477,026 496,849 2,812,891 137,796,388 1,492,955 142,102,234
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
PURCHASED POWER(Account 555) (Continued)
Idaho Power Company X
04/30/2003 2002
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($)($)($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered
(l)(m)
of Settlement ($)
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 (l). Explain in a footnote all components of the amount shown in column (l). 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 (l)
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.
7,051,149 7,051,149 1 89,881
209,280 209,280 2 3,340
62,820 62,820 3 1,040
8,832 8,832 4 132
101,158 101,158 5 1,490
2,267,711 2,267,711 6 38,076
1,506,888 1,506,888 7 23,138
1,330,998 1,330,998 8 20,462
38,861 38,861 9 930
1,163,634 1,163,634 10 27,261
2,555,701 2,555,701 11 38,943
244,513 244,513 12 3,738
5,079,131 5,079,131 13 85,093
5,126,374 5,126,374 14 85,835
FERC FORM NO. 1 (ED. 12-90)Page 327.4
2,855,620 477,026 496,849 2,812,891 137,796,388 1,492,955 142,102,234
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
PURCHASED POWER(Account 555) (Continued)
Idaho Power Company X
04/30/2003 2002
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($)($)($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered
(l)(m)
of Settlement ($)
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 (l). Explain in a footnote all components of the amount shown in column (l). 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 (l)
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.
550 550 1 21
16,802 16,802 2 1,648
3
4 7
5
6
750 750 7 25
2,135,291 2,135,291 8 74,271
232,222 232,222 9 11,073
83,815 83,815 10 5,800
232,062 232,062 11 7,795
59,535 59,535 12 2,113
59,398 59,398 13 2,491
54,880 54,880 14 3,400
FERC FORM NO. 1 (ED. 12-90)Page 327.5
2,855,620 477,026 496,849 2,812,891 137,796,388 1,492,955 142,102,234
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
PURCHASED POWER(Account 555) (Continued)
Idaho Power Company X
04/30/2003 2002
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($)($)($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered
(l)(m)
of Settlement ($)
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 (l). Explain in a footnote all components of the amount shown in column (l). 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 (l)
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.
684,766 684,766 1 29,651
4,783,582 4,783,582 2 184,145
19,320 19,320 3 1,200
5,150 5,150 4 200
3,465 3,465 5 165
69,850 69,850 6 3,200
40,800 40,800 7 1,600
12,600 12,600 8 300
3,520 3,520 9 320
213,600 213,600 10 9,600
4,000 4,000 11 175
2,100 2,100 12 420
1,575,800 1,575,800 13 64,600
2,362,200 2,362,200 14 74,400
FERC FORM NO. 1 (ED. 12-90)Page 327.6
2,855,620 477,026 496,849 2,812,891 137,796,388 1,492,955 142,102,234
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
PURCHASED POWER(Account 555) (Continued)
Idaho Power Company X
04/30/2003 2002
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($)($)($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered
(l)(m)
of Settlement ($)
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 (l). Explain in a footnote all components of the amount shown in column (l). 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 (l)
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.
3,571,600 3,571,600 1 87,200
303,330 303,330 2 11,400
1,120 1,120 3 80
30,985 30,985 4 1,190
14,280 14,280 5 880
95,260 95,260 6 3,077
409,500 409,500 7 18,000
43,060 43,060 8 1,555
62,930 62,930 9 3,960
17,107,571 17,107,571 10 1,028,524
-4,038,775 -4,038,775 11 -1
18,340 18,340 12 800
5,283,924 5,283,924 13 177,224
11,450 11,450 14 600
FERC FORM NO. 1 (ED. 12-90)Page 327.7
2,855,620 477,026 496,849 2,812,891 137,796,388 1,492,955 142,102,234
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
PURCHASED POWER(Account 555) (Continued)
Idaho Power Company X
04/30/2003 2002
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($)($)($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered
(l)(m)
of Settlement ($)
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 (l). Explain in a footnote all components of the amount shown in column (l). 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 (l)
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.
5,400 5,400 1 300
193,436 193,436 2 9,150
377,853 377,853 3 10,375
542,696 542,696 4 18,602
191,749 191,749 5 5,711
54,058 54,058 6 2,186
1,596 1,596 7 124
34,300 34,300 8 2,000
17,550 17,550 9 900
1,946,061 1,946,061 10 53,550
183,421 183,421 11 5,678
1,685,835 1,685,835 12 49,045
14,728 14,728 13 1,000
187,078 187,078 14 5,109
FERC FORM NO. 1 (ED. 12-90)Page 327.8
2,855,620 477,026 496,849 2,812,891 137,796,388 1,492,955 142,102,234
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
PURCHASED POWER(Account 555) (Continued)
Idaho Power Company X
04/30/2003 2002
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($)($)($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered
(l)(m)
of Settlement ($)
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 (l). Explain in a footnote all components of the amount shown in column (l). 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 (l)
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.
80,700 80,700 1 2,250
602,426 602,426 2 21,629
1,495,873 1,495,873 3 49,678
13,137 13,137 4 675
19,325 19,325 5 675
315 315 6 9
251,519 251,519 7 9,875
411,637 411,637 8 16,463
92,214 92,214 9 5,751
26,755 26,755 10 1,375
25,820 25,820 11 1,035
14,400 14,400 12 800
5,613 5,613 13 231
54,478 54,478 14 3,302
FERC FORM NO. 1 (ED. 12-90)Page 327.9
2,855,620 477,026 496,849 2,812,891 137,796,388 1,492,955 142,102,234
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
PURCHASED POWER(Account 555) (Continued)
Idaho Power Company X
04/30/2003 2002
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($)($)($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered
(l)(m)
of Settlement ($)
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 (l). Explain in a footnote all components of the amount shown in column (l). 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 (l)
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.
116,015 116,015 1 4,420
6,300 6,300 2 200
77,200 77,200 3 2,975
7,575 7,575 4 425
362,500 362,500 5 10,000
242,706 242,706 6 8,752
218,925 218,925 7 10,500
26,330 26,330 8 1,350
2,460 2,460 9 120
3,435 3,435 10 245
56,978 56,978 11 3,495
413,422 413,422 12 19,646
130,844 130,844 13 4,809
16,070 16,070 14 1,265
FERC FORM NO. 1 (ED. 12-90)Page 327.10
2,855,620 477,026 496,849 2,812,891 137,796,388 1,492,955 142,102,234
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
PURCHASED POWER(Account 555) (Continued)
Idaho Power Company X
04/30/2003 2002
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($)($)($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered
(l)(m)
of Settlement ($)
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 (l). Explain in a footnote all components of the amount shown in column (l). 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 (l)
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.
123,118 123,118 1 6,086
3,184 3,184 2
50,787,302 50,787,302 3
15,735 15,735 4
5
6
70,800 126,000 7
108,000 118,800 8
71,900 68,400 9
26,824 26,824 10
7,939 66,970 11
135 12
6 13
199,035 69,565 14
FERC FORM NO. 1 (ED. 12-90)Page 327.11
2,855,620 477,026 496,849 2,812,891 137,796,388 1,492,955 142,102,234
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
PURCHASED POWER(Account 555) (Continued)
Idaho Power Company X
04/30/2003 2002
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($)($)($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered
(l)(m)
of Settlement ($)
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 (l). Explain in a footnote all components of the amount shown in column (l). 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 (l)
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.
467 1
12,210 2
3
4
1,474,184 1,474,184 5
6
3,036 3,036 7
8
9
10
11
12
13
14
FERC FORM NO. 1 (ED. 12-90)Page 327.12
2,855,620 477,026 496,849 2,812,891 137,796,388 1,492,955 142,102,234
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/30/2003
Year of Report
Dec 31, 2002
FOOTNOTE DATA
Schedule Page: 326 Line No.: 4 Column: a
Schedule Page: 326.1 Line No.: 2 Column: b
Schedule Page: 326.1 Line No.: 9 Column: b
Schedule Page: 326.3 Line No.: 6 Column: a
Schedule Page: 326.3 Line No.: 13 Column: b
Schedule Page: 326.4 Line No.: 6 Column: a
Schedule Page: 326.4 Line No.: 7 Column: a
Schedule Page: 326.4 Line No.: 8 Column: a
Schedule Page: 326.5 Line No.: 1 Column: b
Schedule Page: 326.5 Line No.: 2 Column: b
Schedule Page: 326.5 Line No.: 3 Column: b
Schedule Page: 326.7 Line No.: 1 Column: a
Schedule Page: 326.7 Line No.: 11 Column: a
Schedule Page: 326.8 Line No.: 13 Column: a
Schedule Page: 326.11 Line No.: 2 Column: b
Schedule Page: 326.11 Line No.: 3 Column: b
Schedule Page: 326.11 Line No.: 4 Column: b
Schedule Page: 326.11 Line No.: 11 Column: b
Schedule Page: 326.11 Line No.: 12 Column: b
Schedule Page: 326.11 Line No.: 13 Column: b
Schedule Page: 326.11 Line No.: 14 Column: b
Schedule Page: 326.12 Line No.: 1 Column: b
Schedule Page: 326.12 Line No.: 2 Column: b
FERC FORM NO. 1 (ED. 12-87)Page 450
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)
Idaho Power Company X
04/30/2003 2002
Line
No.
Payment By
(c)(b)(a)(d)
Statistical
cation
Classifi-
(Footnote Affiliation)
(Including transactions referred to as 'wheeling')
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)
Energy Received From Energy Delivered To
1. Report all transmission of electricity, i. e., wheeling, provided for other electric utilities, cooperatives, municipalities, other public
authorities, qualifying facilities, non-traditional utility suppliers and ultimate customers.
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:
LF - for Long-term firm transmission service. "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
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.
SF - for short-term firm transmission service. Use this category for all firm services, where the duration of each period of commitment
for service is less than one year.
Bonneville Power Administration Bonneville Power Administration Oregon Trails Electric Co-op LF 1
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration LF 2
Bonneville Power Administration Bonneville Power Administration Vigilante LF 3
Milner Irrigation District Bureau of Reclamation Milner Irrigation District LF 4
City of Seattle City of Seattle Bonneville Power Administration LF 5
United States Bureau of Indian Affairs Bonneville Power Administration United States Bureau of Indian Af LF 6
Aquilla Power Corporation Aquilla Power Corporation PacifiCorp OS 7
Arizona Public Service/Pinnacle West Arizona Public Service/Pinnacle W Bonneville Power Administration LF 8
Arizona Public Service/Pinnacle West Arizona Public Service/Pinnacle W Northwestern LF 9
Arizona Public Service/Pinnacle West Arizona Public Service/Pinnacle W Bonneville Power Administration OS 10
BC Hydro (Powerx)BC Hydro (Powerx)Nevada Power Company/Sierra Pacif OS 11
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration OS 12
City of Idaho Falls Bonneville Power Administration Northwestern OS 13
City of Seattle City of Seattle Bonneville Power Administration AD 14
Conoco Bonneville Power Administration Northwestern OS 15
IdaCorp Energy Idaho Power Company Various OS 16
Mirant Americas Energy Marketing, LP Mirant Americas Energy Marketing,PacifiCorp OS 17
FERC FORM NO. 1 (ED. 12-90)Page 328
TOTAL
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)
Idaho Power Company X
04/30/2003 2002
Line
No.
Payment By
(c)(b)(a)(d)
Statistical
cation
Classifi-
(Footnote Affiliation)
(Including transactions referred to as 'wheeling')
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)
Energy Received From Energy Delivered To
1. Report all transmission of electricity, i. e., wheeling, provided for other electric utilities, cooperatives, municipalities, other public
authorities, qualifying facilities, non-traditional utility suppliers and ultimate customers.
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:
LF - for Long-term firm transmission service. "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
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.
SF - for short-term firm transmission service. Use this category for all firm services, where the duration of each period of commitment
for service is less than one year.
Montana Power Company Montana Power Company PacifiCorp - East OS 1
Morgan Stanley Capital Group, Inc.Morgan Stanley Capital Group, Inc Nevada Power Company/Sierra Pacif OS 2
Nevada Power Company/Sierra Pacific Powe Nevada Power Company/Sierra Pacif Nevada Power Company/Sierra Pacif OS 3
PacifiCorp PacifiCorp PacifiCorp - East OS 4
PacifiCorp PacifiCorp PacifiCorp OS 5
PacifiCorp - Imnaha PacifiCorp PacifiCorp LF 6
Public Service Colorado Public Service Colorado Bonneville Power Administration OS 7
Puget Sound Power & Light Puget Sound Power & Light Bonneville Power Administration OS 8
Transalta Energy PacifiCorp PacifiCorp - East OS 9
TXU Northwestern PacifiCorp - East OS 10
El Paso El Paso El Paso AD 11
12
13
14
15
16
17
FERC FORM NO. 1 (ED. 12-90)Page 328.1
TOTAL
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
Idaho Power Company X
04/30/2003 2002
Line
No.
(Including transactions reffered to as 'wheeling')
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(f)
Point of Delivery
(Substation or Other
(g)
Billing
Demand
(MW)
(h)
TRANSFER OF ENERGY
MegaWatt Hours
Received(i)Delivered(j)
MegaWatt HoursDesignation)
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
nonfirm 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.
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.
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.
LaGrande, OregonLegacy Various in Oregon 714 260,702 260,702 1
LaGrande, OregonLegacy Various in Idaho 2,058 1,088,502 1,088,502 2
Bannack Tap5 Vigilante Electric C 4 3
Minidoka, IdahoLegacy Various in Idaho 8,472 8,472 4
Lucky Peak, IdahoLegacy LaGrande, Oregon 591 11,227 9,355 5
LaGrande, OregonLegacy Various in Idaho 11 16,150 16,150 6
Enterprise, Oregon5 Borah or Brady, Idah 100 100 7
Borah or Kinport, Id5 LaGrande, Oregon 231,869 231,869 8
Borah or Kinport, Id5 Lolo, Montana 77,290 77,290 9
Various in Idaho5 Varrious in Idaho 92,757 92,757 10
Various in Idaho5 Midpoint, Idaho 79,178 79,178 11
Various in Idaho5 Various in Idaho 3,147 3,147 12
LaGrande, Oregon5 Borah or Brady, Idah 17,698 17,698 13
Various in Idaho5 LaGrande, Oregon 14
LaGrande, Oregon5 Borah or Brady, Idah 5 5 15
Various in Idaho5 Various in Idaho 663,510 663,510 16
Various in Idaho5 Jim Bridger, Wyoming 115 115 17
FERC FORM NO. 1 (ED. 12-90)Page 329
3,378 4,712,790 4,710,918
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
Idaho Power Company X
04/30/2003 2002
Line
No.
(Including transactions reffered to as 'wheeling')
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(f)
Point of Delivery
(Substation or Other
(g)
Billing
Demand
(MW)
(h)
TRANSFER OF ENERGY
MegaWatt Hours
Received(i)Delivered(j)
MegaWatt HoursDesignation)
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
nonfirm 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.
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.
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.
Various in Idaho5 Borah or Brady, Idah 17,241 17,241 1
Various in Idaho5 Humbolt, Nevada 286,611 286,611 2
Various in Idaho5 Humbolt, Nevada 1,254,577 1,254,577 3
Jim Bridger, WyomingLegacy Various in Idaho 512,283 512,283 4
Enterprise, Oregon5 Various in Idaho 84,839 84,839 5
Enterprise, Oregon5 Pine Creek, Oregon 2,289 2,289 6
Borah or Kinport, Id5 Lolo, Montana 385 385 7
Hot Spings5 Lolo, Montana 100 100 8
Enterprise, Oregon5 Borah or Brady, Idah 3,718 3,718 9
Lolo, Montana5 Borah or Brady, Idah 25 25 10
Various in Idaho5 Various in Idaho 11
12
13
14
15
16
17
FERC FORM NO. 1 (ED. 12-90)Page 329.1
3,378 4,712,790 4,710,918
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
Idaho Power Company X
04/30/2003 2002
Line
No.
(m)(l)(k)(n)
(k+l+m)
Total Revenues ($)
(Including transactions reffered to as 'wheeling')
($)
Energy Charges
($)
(Other Charges)Demand Charges
($)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
8. Report in column (i) and (j) the total megawatthours received and delivered.
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. Provide total amounts in column (i) through (n) as the last Line. Enter "TOTAL" in column (a) as the Last Line. The total amounts
in columns (i) and (j) must be reported as Transmission Received and Delivered on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
1,285,366 1,285,366 1
2,942,300 3,993,413 228,156 822,957 2
15,000 15,000 3
13,725 13,725 4
845,130 849,990 4,860 5
53,653 53,653 6
359 359 7
1,093,724 1,093,724 8
364,575 364,575 9
437,537 437,537 10
314,242 314,242 11
10,033 10,033 12
37,623 37,623 13
-4,553 -4,553 14
20 20 15
2,356,783 2,356,783 16
429 429 17
FERC FORM NO. 1 (ED. 12-90)Page 330
5,141,449 16,392,941 228,453 11,023,039
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
Idaho Power Company X
04/30/2003 2002
Line
No.
(m)(l)(k)(n)
(k+l+m)
Total Revenues ($)
(Including transactions reffered to as 'wheeling')
($)
Energy Charges
($)
(Other Charges)Demand Charges
($)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
8. Report in column (i) and (j) the total megawatthours received and delivered.
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. Provide total amounts in column (i) through (n) as the last Line. Enter "TOTAL" in column (a) as the Last Line. The total amounts
in columns (i) and (j) must be reported as Transmission Received and Delivered on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
62,398 62,398 1
789,399 789,399 2
3,444,311 3,444,311 3
802,112 802,112 4
442,006 442,006 5
14,580 14,580 6
283 283 7
1,478 1,478 8
14,342 14,342 9
123 123 10
-10 -10 11
12
13
14
15
16
17
FERC FORM NO. 1 (ED. 12-90)Page 330.1
5,141,449 16,392,941 228,453 11,023,039
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/30/2003
Year of Report
Dec 31, 2002
FOOTNOTE DATA
Schedule Page: 328 Line No.: 1 Column: a
Schedule Page: 328 Line No.: 1 Column: e
Schedule Page: 328 Line No.: 2 Column: a
Schedule Page: 328 Line No.: 2 Column: m
Schedule Page: 328 Line No.: 3 Column: a
Schedule Page: 328 Line No.: 3 Column: e
Schedule Page: 328 Line No.: 4 Column: a
Schedule Page: 328 Line No.: 5 Column: a
Schedule Page: 328 Line No.: 5 Column: m
Schedule Page: 328 Line No.: 6 Column: a
Schedule Page: 328 Line No.: 8 Column: a
Schedule Page: 328 Line No.: 9 Column: a
Schedule Page: 328 Line No.: 14 Column: m
Schedule Page: 328.1 Line No.: 4 Column: a
Schedule Page: 328.1 Line No.: 11 Column: m
FERC FORM NO. 1 (ED. 12-87)Page 450
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
Idaho Power Company X
04/30/2003
2002
Line
No.
Name of Company or Public
(c)(b)(a)
Authority (Footnote Affiliations)
TRANSFER OF ENERGY
Magawatt-hoursReceived
Magawatt-
Deliveredhours
EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
DemandCharges($)
(d)
EnergyCharges
(e)
($)
OtherCharges($)
(f)($)
Total Cost of
Transmission
(g)
(Including transactions referred to as "wheeling")
1. Report all transmission, i.e., wheeling of electricity provided to respondent by other electric utilities, cooperatives, municipalities, or
other public authorities during the year.
2. In column (a) report each company or public authority that provide 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.
3. Provide in column (a) subheadings and classify transmission service purchased form other utilities as: "Delivered Power to
Wheeler" or "Received Power from Wheeler."
4. Report in columns (b) and (c) the total Megawatthours received and delivered by the provider of the transmission service.
5. In columns (d) through (g), report expenses as shown on bills or vouchers rendered to the respondent. In column (d), provide
demand charges. In column (e), provide energy charges related to the amount of energy transferred. In column (f), provide 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 (f). Report in column (9) the total charge shown on bills rendered to the respondent. If no
monetary settlement was made, enter zero ("0") column (g). 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. Provide a total amount in columns (b) through (g) as the last Line. Energy provided by
the respondent for the wheeler’s transmission tosses should be reported on the Electric Energy Account, Page 401. If the respondent
received power from the wheeler, energy provided to account for Losses should be reported on Line 19. Transmission By Others
Losses, on Page 401. Otherwise, Losses should be reported on line 27, Total Energy Losses, Page 401.
7. Footnote entries and provide explanations following all required data.
Delivered Power to 1
10,006 10,006 5,672 5,672Benton County PUD 2
43,500 1,776 41,724 504,934 504,934Bonneville Power Admin 3
350 350 200 200Clatskanie PUD 4
280 280 160 160Franklin County PUD 5
3,230 3,230 18,910 18,910Grays Harbor PUD 6
611,834 611,834IdaCorp Energy 7
596 596 128 128Northwest Energy 8
9,582 9,582 1,569 1,569PacifiCorp Inc 9
6,155 6,155 3,300 3,300Seattle City Light 10
748 748 108 108Sierra Pacific Power Co 11
583 583 259 259Snohomish County PUD 12
13
Rec'd Power from 14
49,980 49,980 17,035 17,035Avista Corp 15
7,500 7,500 4,120 4,120Benton County PUD 16
FERC FORM NO. 1 (ED. 12-90)Page 332
1,375,448 1,375,448 1,158,852 1,054,572 2,213,424TOTAL
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
Idaho Power Company X
04/30/2003
2002
Line
No.
Name of Company or Public
(c)(b)(a)
Authority (Footnote Affiliations)
TRANSFER OF ENERGY
Magawatt-hoursReceived
Magawatt-
Deliveredhours
EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
DemandCharges($)
(d)
EnergyCharges
(e)
($)
OtherCharges($)
(f)($)
Total Cost of
Transmission
(g)
(Including transactions referred to as "wheeling")
1. Report all transmission, i.e., wheeling of electricity provided to respondent by other electric utilities, cooperatives, municipalities, or
other public authorities during the year.
2. In column (a) report each company or public authority that provide 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.
3. Provide in column (a) subheadings and classify transmission service purchased form other utilities as: "Delivered Power to
Wheeler" or "Received Power from Wheeler."
4. Report in columns (b) and (c) the total Megawatthours received and delivered by the provider of the transmission service.
5. In columns (d) through (g), report expenses as shown on bills or vouchers rendered to the respondent. In column (d), provide
demand charges. In column (e), provide energy charges related to the amount of energy transferred. In column (f), provide 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 (f). Report in column (9) the total charge shown on bills rendered to the respondent. If no
monetary settlement was made, enter zero ("0") column (g). 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. Provide a total amount in columns (b) through (g) as the last Line. Energy provided by
the respondent for the wheeler’s transmission tosses should be reported on the Electric Energy Account, Page 401. If the respondent
received power from the wheeler, energy provided to account for Losses should be reported on Line 19. Transmission By Others
Losses, on Page 401. Otherwise, Losses should be reported on line 27, Total Energy Losses, Page 401.
7. Footnote entries and provide explanations following all required data.
913,504 376 913,128 639,360 639,360Bonneville Power Admin 1
7,080 7,080 3,640 3,640Grant County PUD 2
217,681 13,681 204,000 105,236 105,236Northwestern Energy 3
310,824 310,824 60,600 60,600PacifiCorp Inc 4
16,650 16,650 8,732 8,732Seattle City Light 5
3,341 3,341 1,485 1,485Snohomish County PUD 6
7
8
9
10
11
12
13
14
15
16
FERC FORM NO. 1 (ED. 12-90)Page 332.1
1,375,448 1,375,448 1,158,852 1,054,572 2,213,424TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year of Report
Dec. 31,
MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Idaho Power Company X 04/30/2003 2002
Line Description Amount
(b)(a)No.
18,154Industry Association Dues 1
Nuclear Power Research Expenses 2
Other Experimental and General Research Expenses 3
Pub & Dist Info to Stkhldrs...expn servicing outstanding Securities 4
1,014,929Oth Expn >=5,000 show purpose, recipient, amount. Group if < $5,000 5
18,020Rotheford Barker 6
18,040John Carley 7
19,540Jack Lemley 8
18,690Gary Michael 9
17,520Peter O'Neil 10
19,540Robert Tinstman 11
18,020Evelyn Loveless 12
15,515Christopher Culp 13
7,760Roger Breezley (1) 14
36,000Jon Miller 15
16
17
18
Miscellaneous General Management 19
35,000Listing Services-New York Stock Exchange 20
1,000Pacific Stock Exchange 21
22
Memberships: 23
50Assessors Convention 24
21,939Associated Taxpayers of Idaho 25
100Idaho Cattlemen Assoc 26
2,500Idaho Mining Assoc 27
1,200Idaho Water Users Assoc.,Inc 28
100Idaho Wool Growers 29
125Ntl. Assoc. of Investors Corp 30
1,000Oregonians for Food and Shelter 31
28,704Pacific NW Utilities 32
1,000Western Coal Transportation 33
2,384Wyoming Taxpayers Association 34
35
36
37
38
39
(1) Reiteired 8/2002 40
41
42
43
44
45
1,316,830
FERC FORM NO. 1 (ED. 12-94)Page 335
46 TOTAL
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Account 403, 404, 405)
Idaho Power Company X
04/30/2003
2002
Line
No.Functional Classification Depreciation
(c)(b)(a)
Amortization of Total
(Except amortization of aquisition adjustments)
A. Summary of Depreciation and Amortization Charges
Expense
(Account 403)
Limited Term Elec-
tric Plant (Acc 404)
Amortization ofOther Electric
Plant (Acc 405)
(d)(e)
1. Report in Section A for the year the amounts for: (a) Depreciation Expense (Account 403); (b) Amortization of Limited-Term Electric
Plant (Account 404); and (c) 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.
8,519,346Intangible Plant 8,519,346 1
23,350,222Steam Production Plant 23,350,222 2
Nuclear Production Plant 3
12,065,031Hydraulic Production Plant-Conventional 12,064,719 312 4
Hydraulic Production Plant-Pumped Storage 5
1,588,354Other Production Plant 1,588,354 6
10,830,656Transmission Plant 10,830,656 7
28,957,208Distribution Plant 28,957,208 8
8,402,156General Plant 8,402,156 9
Common Plant-Electric 10
93,712,973TOTAL 85,193,315 8,519,658 11
Account 404
Balance to be 2002 Balance to be Remaining months of
Amortized Amortization amortized 12/31/02 amortization 12/31/02
(1) 61,540 15,372 46,168 43
(2) 12,000 12,000 60,000 60
(3) 6,907,568 206,712 581,127 -
(4) 34,455,335 8,273,322 24,087,463 -
(5) 283,838 12,252 261,357 266
Total 8,519,658
(1) T E Roach development archaeological study, FERC & Oregon license costs (temination date July 31, 2005).
(2) Shoshone-Bannock Tribe license and use agreement (termination date December 31, 2023).
(3) Middle snake relicensing costs (amortized over a 30-year liscense period).
(4) Computer software packages (amortized over a 60 month period from date of purchase).
(5) American Falls dam road rebuild (termination date February 28, 2025).
FERC FORM NO. 1 (ED. 12-88)Page 336
B. Basis for Amortization Charges
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
Idaho Power Company X
04/30/2003
2002
Line
No.Account No.
(c)(b)(a)(d)(e)
C. Factors Used in Estimating Depreciation Charges
Depreciable
Plant Base
(In Thousands)
Estimated
Avg. Service
Life
Net
Salvage
(Percent)
Applied
Depr. rates
Mortality
Curve
Type
Average
Remaining
Life(f)(g)(Percent)
45.00 2.20 30.00Life Span310.00 196 12
39.00 -17.00 2.97 28.30Life Span311.00 129,006 13
41.00 -21.00 3.51 28.90Life Span312.10 78,150 14
39.00 -17.00 2.99 27.90Life Span312.20 365,659 15
25.00 5.00 3.91 24.10Life Span312.30 4,045 16
39.00 -18.00 3.24 28.50Life Span314.00 110,042 17
39.00 -16.00 3.01 27.90Life Span315.00 61,027 18
39.00 -16.00 4.16 23.40Life Span316.00 10,378 19
7.00 25.00 11.03 4.20R2.5316.40 238 20
7.00 15.00 12.53 4.70R2.5316.50 17 21
14.00 30.00 5.05 11.40R0.5316.70 22 22
20.00 40.00 3.05 14.30R1.0316.80 1,133 23
Subtotal Steam 759,913 24
75.00 -19.00 1.88 45.60Life Span331.00 127,165 25
80.00 1.56 44.00Life Span332.10 19,460 26
76.00 -29.00 2.49 41.50Life Span332.20 217,630 27
39.00 2.61 38.70Life Span332.30 5,600 28
74.00 1.55 45.60Life Span333.00 182,144 29
74.00 -10.00 1.92 40.60Life Span334.00 35,374 30
75.00 -5.00 1.59 46.50life Span335.00 13,894 31
77.00 1.53 45.30Life Span336.00 6,934 32
Subtotal Hydro 608,201 33
30.00 2.74 30.00Life Span341.00 1,206 34
30.00 3.52 30.00Life Span342.00 1,675 35
30.00 3.32 30.00Life Span343.00 765 36
30.00 3.24 30.00Life Span344.00 42,883 37
30.00 3.22 30.00Life Span345.00 1,237 38
30.00 3.31 30.00Life Span346.00 2,479 39
Subtotal Other 50,245 40
70.00 1.45 51.70R5.0350.00 15,669 41
40.00 -25.00 3.23 22.60R5.0352.00 27,646 42
40.00 5.00 2.43 26.40R4.0353.00 200,612 43
60.00 1.69 45.70L4.0354.00 57,168 44
45.00 -25.00 2.85 27.70R4.0355.00 81,185 45
50.00 10.00 1.85 30.60R5.0356.00 101,673 46
70.00 1.52 29.70R5.0359.00 318 47
Subtotal Transmission 484,271 48
45.00 -25.00 2.83 31.30R2.0361.00 14,863 49
40.00 5.00 2.43 26.00R2.5362.00 119,805 50
FERC FORM NO. 1 (ED. 12-95)Page 337
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
Idaho Power Company X
04/30/2003
2002
Line
No.Account No.
(c)(b)(a)(d)(e)
C. Factors Used in Estimating Depreciation Charges
Depreciable
Plant Base
(In Thousands)
Estimated
Avg. Service
Life
Net
Salvage
(Percent)
Applied
Depr. rates
Mortality
Curve
Type
Average
Remaining
Life(f)(g)(Percent)
35.00 -15.00 3.35 24.50L2.0364.00 172,815 12
45.00 -10.00 2.48 34.00R1.0365.00 90,242 13
50.00 2.02 40.60R2.5366.00 31,606 14
30.00 3.38 22.00R4.0367.00 125,667 15
25.00 5.00 3.92 15.30R4.0368.00 255,276 16
25.00 -20.00 4.94 14.90R5.0369.00 44,797 17
35.00 2.90 25.40L2.0370.00 38,840 18
10.00 30.00 7.00 9.00LO371.10 359 19
13.00 7.89 8.40LO371.20 1,856 20
25.00 -15.00 4.70 17.10L2.0373.00 3,886 21
Subtotal Distribution 900,012 22
60.00 1.68 59.50R4.0390.11 24,083 23
45.00 2.22 36.50R1.5390.12 26,043 24
20.00 -5.00 5.37 13.50R3.0390.20 6,755 25
20.00 5.00 4.82 15.00R0.5391.10 10,814 26
8.00 5.00 12.21 4.50R2.0391.20 33,310 27
8.00 5.00 12.21 4.50R2.0391.21 6,139 28
8.00 15.00 10.76 5.50R0.5392.10 241 29
15.00 50.00 3.79 15.00S2.0392.30 1,855 30
7.00 25.00 11.03 4.20R2.5392.40 14,080 31
7.00 15.00 12.53 4.70R2.5392.50 318 32
14.00 30.00 5.12 9.50R0.5392.60 18,915 33
14.00 30.00 5.05 11.40R0.5392.70 3,233 34
17.00 30.00 4.20 11.90R1.0392.90 2,950 35
25.00 15.00 3.44 19.10R0.5393.00 1,012 36
20.00 10.00 4.60 13.30L3.0394.00 3,529 37
20.00 5.00 4.83 13.90R5.0395.00 8,733 38
20.00 40.00 3.05 14.30R1.0396.00 6,348 39
25.00 -10.00 4.46 19.40L2.0397.10 6,985 40
20.00 5.14 12.00L3.0397.20 8,431 41
20.00 5.16 11.60L4.0397.30 3,163 42
20.00 -10.00 5.50 19.50L2.0397.40 866 43
17.00 5.00 5.72 11.50L1.5398.00 2,000 44
Subtotal General 189,803 45
Total Plant 2,992,445 46
47
48
49
50
FERC FORM NO. 1 (ED. 12-95)Page 337.1
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
REGULATORY COMMISSION EXPENSES
Idaho Power Company X
04/30/2003
2002
Line
No.
Description Assessed by
(c)(b)(a)
Total Expense forExpenses
of
(d)
(Furnish name of regulatory commission or body the Regulatory
docket or case number and a description of the case)Commission Utility Current Year(b) + (c)
Deferredin Account
182.3 at Beginning of Year
(e)
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.
Federal Energy Regulatory Commission: 1
Annual administrative charges 2,835,971 2,835,971 2
3
General Regulatory Expenses: 4
Other Expenses 473,861 473,861 5
6
Regulatory Commission Expenses - Idaho 7
Intervenor Funding (various cases) 32,314 32,314 8
Other Expenses 109,833 109,833 9
10
Regulatory Commission Expenses - Oregon 11
Other Expenses -210 -210 12
13
Regulatory Commission Expenses - Nevada 14
General Regulatory Expenses 22,020 22,020 15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
FERC FORM NO. 1 (ED. 12-96)Page 350
46 TOTAL 2,835,971 637,818 3,473,789
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
REGULATORY COMMISSION EXPENSES (Continued)
Idaho Power Company X
04/30/2003
2002
Line
No.
(j)(i)(f)(k)(l)
EXPENSES INCURRED DURING YEAR AMORTIZED DURING YEAR
CURRENTLY CHARGED TO
Department AccountNo.(g)
Amount
(h)
Deferred to
Account 182.3
Contra
Account Amount Deferred in Account 182.3
End of Year
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.
1
Electric 2 2,835,971928
3
4
Electric 5 473,861928
6
7
Electric 8 32,314928
Electric 9 109,833928
10
11
Electric 12 -210928
13
14
Electric 15 22,020928
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
FERC FORM NO. 1 (ED. 12-96)Page 351
46 3,473,789
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES
Idaho Power Company X
04/30/2003
2002
Line
No.
Description
(b)(a)
Classification
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.(Identify
recipient regardless of affiliation.) For any R, D & D work carried with others, show separately the respondent's cost for the year and cost chargeable to
others (See definition of research, development, and demonstration in Uniform System of Accounts).
2. Indicate in column (a) the applicable classification, as shown below:
Classifications:
A. Electric R, D & D Performed Internally: (3) Transmission
(1) Generation a. Overhead
a. hydroelectric b. Underground
i. Recreation fish and wildlife (4) Distribution
ii Other hydroelectric (5) Environment (other than equipment)
b. Fossil-fuel steam (6) Other (Classify and include items in excess of $5,000.)
c. Internal combustion or gas turbine (7) Total Cost Incurred
d. Nuclear B. Electric, R, D & D Performed Externally:
e. Unconventional generation (1) Research Support to the electrical Research Council or the Electric
f. Siting and heat rejection Power Research Institute
A. Electric R, D & D Performed internally: 1
(1) Generation 2
Acoustic Flow Meter - Brownlee e. unconventional generation 3
Water Forecasting Model 4
Winter Kennedy Calibration 5
Remote PDA Testing Pilot 6
7
8
9
Northwest Energy Efficiency Alliance 10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
FERC FORM NO. 1 (ED. 12-87)Page 352
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES (Continued)
Idaho Power Company X
04/30/2003
2002
Line
No.
AMOUNTS CHARGED IN CURRENT YEAR
(e)(c)
Costs Incurred Internally
Current Year
Costs Incurred Externally
Current Year
(d)
Account Amount
(f)
Unamortized
Accumulation
(g)
(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.
1
2
12,893 3107 12,893
81,379 4107 81,379
12,598 5535 12,598
91,685 6107 91,685
7
8
9
10 1,277,274 107 1,277,274
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
FERC FORM NO. 1 (ED. 12-87)Page 353
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
DISTRIBUTION OF SALARIES AND WAGES
Idaho Power Company X
04/30/2003
2002
Line
No.
Classification
(c)(b)(a)
Direct Payroll Allocation of Total
(d)
Distribution Payroll charged forClearing Accounts
Report below the distribution of total salaries and wages for the year. Segregate amounts originally charged to clearing accounts to
Utility Departments, Construction, Plant Removals, and Other Accounts, and enter such amounts in the appropriate lines and columns
provided. In determining this segregation of salaries and wages originally charged to clearing accounts, a method of approximation
giving substantially correct results may be used.
Electric 1
Operation 2
6,955,668Production 3
4,653,347Transmission 4
13,203,110Distribution 5
8,514,591Customer Accounts 6
3,091,725Customer Service and Informational 7
Sales 8
25,747,427Administrative and General 9
62,165,868TOTAL Operation (Enter Total of lines 3 thru 9) 10
Maintenance 11
4,886,525Production 12
2,339,445Transmission 13
7,221,547Distribution 14
496,583Administrative and General 15
14,944,100TOTAL Maint. (Total of lines 12 thru 15) 16
Total Operation and Maintenance 17
11,842,193Production (Enter Total of lines 3 and 12) 18
6,992,792Transmission (Enter Total of lines 4 and 13) 19
20,424,657Distribution (Enter Total of lines 5 and 14) 20
8,514,591Customer Accounts (Transcribe from line 6) 21
3,091,725Customer Service and Informational (Transcribe from line 7) 22
Sales (Transcribe from line 8) 23
26,244,010Administrative and General (Enter Total of lines 9 and 15) 24
80,149,719 3,039,751 77,109,968TOTAL Oper. and Maint. (Total of lines 18 thru 24) 25
Gas 26
Operation 27
Production-Manufactured Gas 28
Production-Nat. Gas (Including Expl. and Dev.) 29
Other Gas Supply 30
Storage, LNG Terminaling and Processing 31
Transmission 32
Distribution 33
Customer Accounts 34
Customer Service and Informational 35
Sales 36
Administrative and General 37
TOTAL Operation (Enter Total of lines 28 thru 37) 38
Maintenance 39
Production-Manufactured Gas 40
Production-Natural Gas 41
Other Gas Supply 42
Storage, LNG Terminaling and Processing 43
Transmission 44
Distribution 45
Administrative and General 46
TOTAL Maint. (Enter Total of lines 40 thru 46) 47
FERC FORM NO. 1 (ED. 12-88)Page 354
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31, Idaho Power Company X
04/30/2003
2002
Line
No.
Classification
(c)(b)(a)
Direct Payroll Allocation of Total
(d)
Distribution Payroll charged forClearing Accounts
DISTRIBUTION OF SALARIES AND WAGES (Continued)
Total Operation and Maintenance 48
Production-Manufactured Gas (Enter Total of lines 28 and 40) 49
Production-Natural Gas (Including Expl. and Dev.) (Total lines 29, 50
Other Gas Supply (Enter Total of lines 30 and 42) 51
Storage, LNG Terminaling and Processing (Total of lines 31 thru 52
Transmission (Lines 32 and 44) 53
Distribution (Lines 33 and 45) 54
Customer Accounts (Line 34) 55
Customer Service and Informational (Line 35) 56
Sales (Line 36) 57
Administrative and General (Lines 37 and 46) 58
TOTAL Operation and Maint. (Total of lines 49 thru 58) 59
Other Utility Departments 60
Operation and Maintenance 61
80,149,719 3,039,751 77,109,968TOTAL All Utility Dept. (Total of lines 25, 59, and 61) 62
Utility Plant 63
Construction (By Utility Departments) 64
28,577,712 28,577,712Electric Plant 65
Gas Plant 66
Other (provide details in footnote): 67
28,577,712 28,577,712TOTAL Construction (Total of lines 65 thru 67) 68
Plant Removal (By Utility Departments) 69
Electric Plant 70
Gas Plant 71
Other (provide details in footnote): 72
TOTAL Plant Removal (Total of lines 70 thru 72) 73
Other Accounts (Specify, provide details in footnote): 74
772,008 772,008Misc Deferred & Regulatory assets 75
12,295,832 12,295,832Paid Absences 76
2,256,888 2,256,888Expense of non-utility operations 77
361 361Other Clearing Accounts 78
79
80
81
82
83
84
85
86
87
88
89
90
91
92
93
94
15,325,089 15,325,089TOTAL Other Accounts 95
124,052,520 3,039,751 121,012,769TOTAL SALARIES AND WAGES 96
FERC FORM NO. 1 (ED. 12-88)Page 355
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
COMMON UTILITY PLANT AND EXPENSES
Idaho Power Company X
04/30/2003 2002
1. Describe the property carried in the utility's accounts as common utility plant and show the book cost of such plant at end of year classified by
accounts as provided by Plant Instruction 13, Common Utility Plant, of the Uniform System of Accounts. Also show the allocation of such plant costs to
the respective departments using the common utility plant and explain the basis of allocation used, giving the allocation factors.
2. Furnish the accumulated provisions for depreciation and amortization at end of year, showing the amounts and classifications of such accumulated
provisions, and amounts allocated to utility departments using the Common utility plant to which such accumulated provisions relate, including
explanation of basis of allocation and factors used.
3. Give for the year the expenses of operation, maintenance, rents, depreciation, and amortization for common utility plant classified by accounts as
provided by the Uniform System of Accounts. Show the allocation of such expenses to the departments using the common utility plant to which such
expenses are related. Explain the basis of allocation used and give the factors of allocation.
4. Give date of approval by the Commission for use of the common utility plant classification and reference to order of the Commission or other
authorization.
FERC FORM NO. 1 (ED. 12-87)Page 356
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
ELECTRIC ENERGY ACCOUNT
Idaho Power Company X
04/30/2003
2002
Line
No.
Item
(a)(b)(a)(b)
Line
No.MegaWatt Hours Item MegaWatt Hours
Report below the information called for concerning the disposition of electric energy generated, purchased, exchanged and wheeled during the year.
SOURCES OF ENERGY1
Generation (Excluding Station Use):2
7,242,811Steam3
Nuclear4
6,068,478Hydro-Conventional5
Hydro-Pumped Storage6
43,433Other7
Less Energy for Pumping8
13,354,722Net Generation (Enter Total of lines 3
through 8)
9
2,855,620Purchases10
Power Exchanges:11
477,026Received12
496,849Delivered13
-19,823Net Exchanges (Line 12 minus line 13)14
Transmission For Other (Wheeling)15
4,712,790Received16
4,710,918Delivered17
1,872Net Transmission for Other (Line 16 minus
line 17)
18
Transmission By Others Losses19
16,192,391TOTAL (Enter Total of lines 9, 10, 14, 18
and 19)
20
DISPOSITION OF ENERGY21
12,894,068Sales to Ultimate Consumers (Including
Interdepartmental Sales)
22
106,282Requirements Sales for Resale (See
instruction 4, page 311.)
23
1,962,222Non-Requirements Sales for Resale (See
instruction 4, page 311.)
24
Energy Furnished Without Charge25
Energy Used by the Company (Electric
Dept Only, Excluding Station Use)
26
1,229,819Total Energy Losses27
16,192,391TOTAL (Enter Total of Lines 22 Through
27) (MUST EQUAL LINE 20)
28
FERC FORM NO. 1 (ED. 12-90)Page 401a
(d)
Day of Month
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
MONTHLY PEAKS AND OUTPUT
Idaho Power Company X
04/30/2003 2002
Line
No.Total Monthly Energy Megawatts
(c)(b)(a)
Hour
(e)
MONTHLY PEAK
Month
NAME OF SYSTEM:
Monthly Non-Requirments
Sales for Resale &
Associated Losses (See Instr. 4)
1. 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 in column (b) the system's energy output for each month such that the total on Line 41 matches the total on Line 20.
3. Report in column (c) a monthly breakdown of the Non-Requirements Sales For Resale reported on Line 24. include in the monthly amounts any
energy losses associated with the sales so that the total on Line 41 exceeds the amount on Line 24 by the amount of losses incurred (or estimated) in
making the Non-Requirements Sales for Resale.
4. Report in column (d) the system's monthly maximum megawatt Load (60-minute integration) associated with the net energy for the system defined as
the difference between columns (b) and (c)
5. Report in columns (e) and (f) the specified information for each monthly peak load reported in column (d).
(f)
January 29 29 2,131 418,746 8 AM 1,614,296
February 30 5 2,074 112,210 8 AM 1,165,978
March 31 4 1,917 260,652 8 AM 1,310,521
April 32 18 1,719 207,684 8 AM 1,161,689
May 33 30 2,365 136,529 5 PM 1,314,295
June 34 26 2,822 63,697 4 PM 1,454,941
July 35 12 2,963 86,813 4 PM 1,687,221
August 36 15 2,529 110,695 6PM 1,504,329
September 37 3 2,310 165,481 6 PM 1,291,805
October 38 31 1,934 164,615 8 AM 1,218,042
November 39 1 1,912 62,902 8 AM 1,125,493
December 40 19 1,942 172,198 7 PM 1,343,781
FERC FORM NO. 1 (ED. 12-90)Page 401b
41 TOTAL 16,192,391 1,962,222
BoardmanJim Bridger
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31, Idaho Power Company X
04/30/2003 2002
Line
No.
Item
(b)(a)(c)
Plant
Name:
Plant
Name:
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in
this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated
as a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a
therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 37) and average cost
per unit of fuel burned (Line 40) must be consistent with charges to expense accounts 501 and 547 (Line 41) as show on Line 19. 8. If more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
SteamSteam 1 Kind of Plant (Internal Comb, Gas Turb, Nuclear
ConventionalSemi-Outdoor Boiler 2 Type of Constr (Conventional, Outdoor, Boiler, etc)
19801974 3 Year Originally Constructed
19801979 4 Year Last Unit was Installed
56.05770.50 5 Total Installed Cap (Max Gen Name Plate Ratings-MW)
59700 6 Net Peak Demand on Plant - MW (60 minutes)
69508760 7 Plant Hours Connected to Load
00 8 Net Continuous Plant Capability (Megawatts)
00 9 When Not Limited by Condenser Water
00 10 When Limited by Condenser Water
00 11 Average Number of Employees
3526080004945008000 12 Net Generation, Exclusive of Plant Use - KWh
106610487488 13 Cost of Plant: Land and Land Rights
1343913262044801 14 Structures and Improvements
50588732336012330 15 Equipment Costs
64134474398544619 16 Total Cost
1144.2368517.2545 17 Cost per KW of Installed Capacity (line 5)
639184131088 18 Production Expenses: Oper, Supv, & Engr
511805960977531 19 Fuel
00 20 Coolants and Water (Nuclear Plants Only)
01829393 21 Steam Expenses
00 22 Steam From Other Sources
00 23 Steam Transferred (Cr)
00 24 Electric Expenses
1663021216170 25 Misc Steam (or Nuclear) Power Expenses
41846395703 26 Rents
00 27 Allowances
16987767483 28 Maintenance Supervision and Engineering
00 29 Maintenance of Structures
05808682 30 Maintenance of Boiler (or reactor) Plant
02247069 31 Maintenance of Electric Plant
133438694418 32 Maintenance of Misc Steam (or Nuclear) Plant
805412781007537 33 Total Production Expenses
0.02280.0164 34 Expenses per Net KWh
Coal Oil Coal Oil 35 Fuel: Kind (Coal, Gas, Oil, or Nuclear)
Tons Barrels Tons Barrels 36 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)
2837767 0 14860 201685 0 1404 37 Quantity (units) of Fuel Burned
9110 0 140000 8697 0 138800 38 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
20.572 0.000 32.587 23.417 0.000 33.735 39 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
20.516 0.000 39.273 23.275 0.000 38.256 40 Average Cost of Fuel per Unit Burned
1.126 0.000 6.679 1.338 0.000 6.561 41 Average Cost of Fuel Burned per Million BTU
0.000 0.012 0.000 0.000 0.015 0.000 42 Average Cost of Fuel Burned per KWh Net Gen
0.000 10474.000 0.000 0.000 9973.000 0.000 43 Average BTU per KWh Net Generation
FERC FORM NO. 1 (ED. 12-95)Page 402
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 24 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 31, "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.
DanskinValmy
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)
Idaho Power Company X
04/30/2003 2002
Line
No.
(e)(f)
Plant
Name:
Plant
Name:
(d)
Plant
Name:
(Continued)
Steam Gas Turbine 1
Outdoor Conventional 2
1981 2001 3
1985 2001 4
0.00283.50 90.00 5
0272103 6
08756753 7
00100000 8
000 9
000 10
003 11
0194519500043368000 12
0681105218768 13
0535216641194403 14
024407485348386719 15
029827762249799890 16
0.00001052.1257 553.3321 17
024346968349 18
0322508614521761 19
000 20
019182620 21
000 22
000 23
01039067253390 24
02427660295948 25
02185040 26
000 27
01494560 28
0153018144 29
026418840 30
05609580 31
01644990 32
0417676385139592 33
0.00000.0215 0.1185 34
Coal Oil Gas 35
Tons Barrels MCF 36
873279 0 3694 0 0 05450240 0 37
10875 0 138778 0 0 010290 0 38
36.172 0.000 37.107 0.000 0.000 0.0008.538 0.000 0.000 39
35.569 0.000 36.691 0.000 0.000 0.0008.538 0.000 0.000 40
1.635 0.000 6.295 0.000 0.000 0.0008.296 0.000 0.000 41
0.000 0.017 0.000 0.000 0.000 0.0000.000 0.104 0.000 42
0.000 9775.000 0.000 0.000 0.000 0.0000.000 12567.000 0.000 43
FERC FORM NO. 1 (ED. 12-88)Page 403
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/30/2003
Year of Report
Dec 31, 2002
FOOTNOTE DATA
Schedule Page: 402 Line No.: 3 Column: b
Schedule Page: 402 Line No.: 3 Column: c
Schedule Page: 402 Line No.: 3 Column: d
Schedule Page: 402 Line No.: 5 Column: b
Schedule Page: 402 Line No.: 5 Column: c
Schedule Page: 402 Line No.: 5 Column: d
Schedule Page: 402 Line No.: 9 Column: b
Schedule Page: 402 Line No.: 9 Column: c
Schedule Page: 402 Line No.: 9 Column: d
FERC FORM NO. 1 (ED. 12-87)Page 450
1975
Bliss
2736
American Falls
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
Idaho Power Company X
04/30/2003 2002
Line
No.
Item FERC Licensed Project No.
(b)(a)(c)
Plant Name:
FERC Licensed Project No.
Plant Name:
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 plan, report on line 11 the approximate average number of employees assignable to each
plant.
Run-of-River Run-of-RiverKind of Plant (Run-of-River or Storage) 1
Outdoor OutdoorPlant Construction type (Conventional or Outdoor) 2
1978 1949Year Originally Constructed 3
1978 1950Year Last Unit was Installed 4
92.30 75.00Total installed cap (Gen name plate Rating in MW) 5
73 60Net Peak Demand on Plant-Megawatts (60 minutes) 6
4,819 8,760Plant Hours Connect to Load 7
0 0Net Plant Capability (in megawatts) 8
112 80 (a) Under Most Favorable Oper Conditions 9
0 74 (b) Under the Most Adverse Oper Conditions 10
4 4Average Number of Employees 11
209,541,000 298,680,000Net Generation, Exclusive of Plant Use - Kwh 12
0 0Cost of Plant 13
875,615 463,556 Land and Land Rights 14
11,812,406 647,382 Structures and Improvements 15
4,242,904 7,428,168 Reservoirs, Dams, and Waterways 16
30,804,885 6,463,550 Equipment Costs 17
306,333 486,477 Roads, Railroads, and Bridges 18
48,042,143 15,489,133 TOTAL cost (Total of 14 thru 18) 19
520.4999 206.5218 Cost per KW of Installed Capacity (line 5) 20
0 0Production Expenses 21
199,983 123,571 Operation Supervision and Engineering 22
826,835 159,401 Water for Power 23
81,923 59,926 Hydraulic Expenses 24
24,983 14,185 Electric Expenses 25
162,757 78,143 Misc Hydraulic Power Generation Expenses 26
168 2,739 Rents 27
62,471 43,493 Maintenance Supervision and Engineering 28
201,724 56,973 Maintenance of Structures 29
11,012 55,390 Maintenance of Reservoirs, Dams, and Waterways 30
140,419 112,333 Maintenance of Electric Plant 31
102,778 111,050 Maintenance of Misc Hydraulic Plant 32
1,815,053 817,204 Total Production Expenses (total 22 thru 32) 33
0.0087 0.0027 Expenses per net KWh 34
FERC FORM NO. 1 (ED. 12-88)Page 406
2726
Malad
1971
Hells Canyon
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
Idaho Power Company X
04/30/2003 2002
Line
No.
Item FERC Licensed Project No.
(b)(a)(c)
Plant Name:
FERC Licensed Project No.
Plant Name:
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 plan, report on line 11 the approximate average number of employees assignable to each
plant.
Storage Run-of-RiverKind of Plant (Run-of-River or Storage) 1
Outdoor OutdoorPlant Construction type (Conventional or Outdoor) 2
1967 1948Year Originally Constructed 3
1967 1948Year Last Unit was Installed 4
391.50 21.77Total installed cap (Gen name plate Rating in MW) 5
421 25Net Peak Demand on Plant-Megawatts (60 minutes) 6
8,760 8,697Plant Hours Connect to Load 7
0 0Net Plant Capability (in megawatts) 8
450 24 (a) Under Most Favorable Oper Conditions 9
137 21 (b) Under the Most Adverse Oper Conditions 10
4 2Average Number of Employees 11
1,620,733,000 165,052,000Net Generation, Exclusive of Plant Use - Kwh 12
0 0Cost of Plant 13
1,563,504 205,376 Land and Land Rights 14
1,710,021 2,122,897 Structures and Improvements 15
52,511,953 3,371,066 Reservoirs, Dams, and Waterways 16
14,226,490 2,806,524 Equipment Costs 17
819,192 304,683 Roads, Railroads, and Bridges 18
70,831,160 8,810,546 TOTAL cost (Total of 14 thru 18) 19
180.9225 404.7104 Cost per KW of Installed Capacity (line 5) 20
0 0Production Expenses 21
282,584 90,455 Operation Supervision and Engineering 22
34,031 373,963 Water for Power 23
190,817 45,516 Hydraulic Expenses 24
65,453 40,913 Electric Expenses 25
112,442 43,518 Misc Hydraulic Power Generation Expenses 26
58,781 16 Rents 27
100,486 14,288 Maintenance Supervision and Engineering 28
53,695 13,074 Maintenance of Structures 29
24,571 32,282 Maintenance of Reservoirs, Dams, and Waterways 30
166,866 17,410 Maintenance of Electric Plant 31
463,115 43,598 Maintenance of Misc Hydraulic Plant 32
1,552,841 715,033 Total Production Expenses (total 22 thru 32) 33
0.0010 0.0043 Expenses per net KWh 34
FERC FORM NO. 1 (ED. 12-88)Page 406.1
2778
Shoshone Falls
2777
Upper Salmon
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
Idaho Power Company X
04/30/2003 2002
Line
No.
Item FERC Licensed Project No.
(b)(a)(c)
Plant Name:
FERC Licensed Project No.
Plant Name:
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 plan, report on line 11 the approximate average number of employees assignable to each
plant.
Run-of-River Run-of-RiverKind of Plant (Run-of-River or Storage) 1
Outdoor ConventionalPlant Construction type (Conventional or Outdoor) 2
1937 1907Year Originally Constructed 3
1947 1921Year Last Unit was Installed 4
34.50 12.50Total installed cap (Gen name plate Rating in MW) 5
34 13Net Peak Demand on Plant-Megawatts (60 minutes) 6
8,760 8,492Plant Hours Connect to Load 7
0 0Net Plant Capability (in megawatts) 8
39 13 (a) Under Most Favorable Oper Conditions 9
32 11 (b) Under the Most Adverse Oper Conditions 10
4 2Average Number of Employees 11
193,119,000 84,464,000Net Generation, Exclusive of Plant Use - Kwh 12
0 0Cost of Plant 13
172,970 311,407 Land and Land Rights 14
1,403,295 1,138,033 Structures and Improvements 15
3,517,649 512,401 Reservoirs, Dams, and Waterways 16
4,582,633 2,030,100 Equipment Costs 17
29,359 51,383 Roads, Railroads, and Bridges 18
9,705,906 4,043,324 TOTAL cost (Total of 14 thru 18) 19
281.3306 323.4659 Cost per KW of Installed Capacity (line 5) 20
0 0Production Expenses 21
225,604 77,169 Operation Supervision and Engineering 22
26,935 8,391 Water for Power 23
129,491 18,612 Hydraulic Expenses 24
18,293 10,900 Electric Expenses 25
109,730 53,657 Misc Hydraulic Power Generation Expenses 26
40 39 Rents 27
53,730 33,188 Maintenance Supervision and Engineering 28
35,589 33,026 Maintenance of Structures 29
30,731 3,017 Maintenance of Reservoirs, Dams, and Waterways 30
241,213 52,432 Maintenance of Electric Plant 31
106,335 51,318 Maintenance of Misc Hydraulic Plant 32
977,691 341,749 Total Production Expenses (total 22 thru 32) 33
0.0051 0.0040 Expenses per net KWh 34
FERC FORM NO. 1 (ED. 12-88)Page 406.2
1971
Brownlee Oxbow
1971
Cascade
2848
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
Idaho Power Company X
04/30/2003 2002
FERC Licensed Project No.
(e)(d)(f)
Plant Name:
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No.
Plant Name:
Line
No.
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.
Run-of-River StorageStorage 1
Outdoor OutdoorOutdoor 2
1983 19611958 3
1984 19611980 4
12.42 190.00585.40 5
12 219641 6
8,760 8,7608,760 7
0 00 8
14 220728 9
1 202220 10
2 57 11
722,000 822,572,0001,839,334,000 12
0 00 13
82,142 866,9385,654,942 14
7,364,154 9,615,32330,080,032 15
3,145,630 30,230,85066,699,271 16
12,683,831 14,659,09150,220,969 17
122,668 565,842518,444 18
23,398,425 55,938,044153,173,658 19
1,883.9312 294.4108261.6564 20
0 00 21
121,732 333,520669,363 22
28,394 34,23075,267 23
22,753 234,586482,553 24
45,538 179,482207,098 25
66,499 102,493249,338 26
118 35,212204,857 27
69,718 171,176136,499 28
24,750 235,911168,689 29
361 217,10151,244 30
64,897 191,613243,729 31
51,333 308,703431,970 32
496,093 2,044,0272,920,607 33
0.6871 0.00250.0016 34
FERC FORM NO. 1 (ED. 12-88)Page 407
2055
C J Strike Twin Falls
18
Swan Falls
503
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
Idaho Power Company X
04/30/2003 2002
FERC Licensed Project No.
(e)(d)(f)
Plant Name:
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No.
Plant Name:
Line
No.
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.
Run-of-River Run-of-RiverRun-of-River 1
Conventional ConventionalOutdoor 2
1910 19351952 3
1994 19951952 4
25.00 52.7482.80 5
19 3685 6
8,757 7,0178,760 7
0 00 8
26 5489 9
14 5084 10
4 55 11
112,913,000 43,211,000363,607,000 12
0 00 13
51,675 255,4992,052,202 14
25,118,690 10,808,0472,666,522 15
13,583,476 7,908,3049,739,793 16
30,204,371 19,756,9976,760,098 17
835,946 1,917,603222,132 18
69,794,158 40,646,45021,440,747 19
2,791.7663 770.6949258.9462 20
0 00 21
218,728 317,727578,854 22
19,641 23,09745,679 23
105,314 100,310169,199 24
23,477 18,21913,933 25
79,991 138,101136,453 26
6,988 1,02170,981 27
55,167 50,76545,175 28
66,155 55,52688,921 29
44,857 90,29661,123 30
136,127 197,37376,588 31
137,270 70,690124,612 32
893,715 1,063,1251,411,518 33
0.0079 0.02460.0039 34
FERC FORM NO. 1 (ED. 12-88)Page 407.1
1971
Common Facilities Milner
2899
Lower Salmon
2061
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
Idaho Power Company X
04/30/2003 2002
FERC Licensed Project No.
(e)(d)(f)
Plant Name:
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No.
Plant Name:
Line
No.
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.
Run-of-River Run-of-River 1
Outdoor Conventional 2
1949 1992 3
1949 1992 4
60.00 59.450.00 5
43 140 6
8,760 6,2310 7
0 00 8
70 590 9
63 10 10
7 20 11
193,582,000 24,915,0000 12
0 00 13
403,335 138,10080,646 14
839,658 10,327,35810,990,609 15
6,458,575 17,141,80913,556,785 16
6,304,851 27,329,297974,268 17
88,693 501,87799,051 18
14,095,112 55,438,44125,701,359 19
234.9185 932.52210.0000 20
0 00 21
705,448 195,0560 22
44,691 1,326,4220 23
145,270 100,9073,020,580 24
125,513 39,5480 25
146,969 174,7860 26
1,227 1,3810 27
49,136 65,3870 28
69,854 37,3350 29
16,394 49,5810 30
172,220 230,8080 31
109,673 50,2790 32
1,586,395 2,271,4903,020,580 33
0.0082 0.09120.0000 34
FERC FORM NO. 1 (ED. 12-88)Page 407.2
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/30/2003
Year of Report
Dec 31, 2002
FOOTNOTE DATA
Schedule Page: 406 Line No.: 1 Column: b
Schedule Page: 406 Line No.: 1 Column: e
Schedule Page: 406 Line No.: 1 Column: f
Schedule Page: 406.1 Line No.: 1 Column: b
Schedule Page: 406.1 Line No.: 1 Column: c
FERC FORM NO. 1 (ED. 12-87)Page 450
FERC Licensed Project No.
Plant Name:
(b)
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
PUMPED STORAGE GENERATING PLANT STATISTICS (Large Plants)
Idaho Power Company X
04/30/2003 2002
Line
No.
Item
(a)
1. Large plants and pumped storage plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operating under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
a footnote. Give project number.
3. If net peak demand for 60 minutes is not available, give the which is available, specifying period.
4. If a group of employees attends more than one generating plant, report on line 8 the approximate average number of employees assignable to each
plant.
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."
1 Type of Plant Construction (Conventional or Outdoor)
2 Year Originally Constructed
3 Year Last Unit was Installed
4 Total installed cap (Gen name plate Rating in MW)
5 Net Peak Demaind on Plant-Megawatts (60 minutes)
6 Plant Hours Connect to Load While Generating
7 Net Plant Capability (in megawatts)
8 Average Number of Employees
9 Generation, Exclusive of Plant Use - Kwh
10 Energy Used for Pumping
11 Net Output for Load (line 9 - line 10) - Kwh
12 Cost of Plant
13 Land and Land Rights
14 Structures and Improvements
15 Reservoirs, Dams, and Waterways
16 Water Wheels, Turbines, and Generators
17 Accessory Electric Equipment
18 Miscellaneous Powerplant Equipment
19 Roads, Railroads, and Bridges
20 Total cost (total 13 thru 19)
21 Cost per KW of installed cap (line 20/line4)
22 Production Expenses
23 Operation Supervision and Engineering
24 Water for Power
25 Pumped Storage Expenses
26 Electric Expenses
27 Misc Pumped Storage 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 Pumped Storage Plant
34 Production Exp Before Pumping Exp (23 thru 33)
35 Pumping Expenses
36 Total Production Exp (total 34 and 35)
37 Expenses per KWh (line 36/line 9)
FERC FORM NO. 1 (ED. 12-88)Page 408
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No.
Plant Name:
(d)
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
PUMPED STORAGE GENERATING PLANT STATISTICS (Large Plants) (Continued)
Idaho Power Company X
04/30/2003 2002
Line
No.
FERC Licensed Project No.
Plant Name:
(e)(c)
6. Pumping energy (Line 10) is that energy measured as input to the plant for pumping purposes.
7. Include on Line 35 the cost of energy used in pumping into the storage reservoir. When this item cannot be accurately computed leave Lines 35, 36
and 37 blank and describe at the bottom of the schedule the company's principal sources of pumping power, the estimated amounts of energy from each
station or other source that individually provides more than 10 percent of the total energy used for pumping, and production expenses per net MWH as
reported herein for each source described. Group together stations and other resources which individually provide less than 10 percent of total pumping
energy. If contracts are made with others to purchase power for pumping, give the supplier contract number, and date of contract.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
FERC FORM NO. 1 (ED. 12-88)Page 409
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
GENERATING PLANT STATISTICS (Small Plants)
Idaho Power Company X
04/30/2003 2002
Line
No.
Name of Plant
Installed Capacity
(c)(b)(a)
Cost of Plant
Net PeakDemand
(d)
Year
Orig.Const.
Name Plate Rating
(In MW)MW(60 min.)
Net GenerationExcludingPlant Use
(e)(f)
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.
Hydro: 1
2.50 2.0 15,022 1,037,4371937 Clear Lakes 2
8.80 6.7 49,316 4,535,2031912 Thousand Springs 3
4
5
Internal Combustion: 6
5.00 5.5 65 663,4791967 Salmon Diesel (1) 7
49,799,8892001 Danskin 8
9
10
11
12
13
14
15
16
17
(1) Salmon units are classified as standby. 18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO. 1 (ED. 12-87)Page 410
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
GENERATING PLANT STATISTICS (Small Plants) (Continued)
Idaho Power Company X
04/30/2003 2002
Line
No.(i)(h)(g)(j)(k)(l)
Plant Cost Per MW
Inst Capacity
Operation
Exc'l. Fuel
Production Expenses
Fuel Maintenance Kind of Fuel Fuel Costs (in cents
(per Million Btu)
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.
1
19,449 414,975 2 89,578
354,932 515,364 3 90,332
4
5
6
132,696 7Diesel
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO. 1 (ED. 12-87)Page 411
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
TRANSMISSION LINE STATISTICS
Idaho Power Company X
04/30/2003
2002
Line
No.
(c)(b)(a)(d)(e)
DESIGNATION
From To
(f)(g)
VOLTAGE (KV)(Indicate whereother than
60 cycle, 3 phase)
Operating Designed
Type of
Supporting
Structure
LENGTH (Pole miles)(In the case of underground linesreport circuit miles)
On Structureof LineDesignated
On Structuresof AnotherLine
Number
Of
Circuits
(h)
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
S Tower 500.00 500.00 1.78 1 1 Boardman Slatt
2
S Tower 500.00 345.00 85.44 1 3 Borah Midpoint
S Tower 345.00 345.00 225.88 1 4 Jim Bridger Goshen
S Tower 345.00 345.00 76.15 2 5 State Line Midpoint
S Tower 345.00 345.00 27.30 1 6 Kinport Borah
H Wood 345.00 345.00 79.55 1 7 Midpoint Borah #1
H Wood 345.00 345.00 77.97 2 8 Midpoint Borah #2
H Wood 345.00 345.00 2.66 2 9 Adelaide Tap Adelaide
10
H Wood 230.00 230.00 46.42 1 11 Quartz LaGrande
S Tower 230.00 230.00 0.60 2 12 Midpoint Hunt
H Wood 230.00 230.00 56.49 1 13 Brady Antelope
H Wood 230.00 230.00 0.11 1 14 Brady Treasureton
S Tower 230.00 230.00 18.48 2 15 Brady #1 & #2 Kinport
H Wood 230.00 230.00 1.40 1 16 Jim Bridger Point of Rocks
S Tower 230.00 230.00 74.10 1 17 Brownlee Ontario
S P Wood 230.00 138.00 5.35 1 18 Mora Bowmont
H Wood 230.00 138.00 10.85 1 19 " "
H Wood 230.00 230.00 2.78 1 20 Jim Bridger Point of Rocks
S Tower 230.00 230.00 4.46 1 21 Boise Bench Caldwell
H Wood 230.00 230.00 33.75 1 22 " " "
S Tower 230.00 230.00 15.69 2 23 Boise Bench Cloverdale
H Wood 230.00 230.00 1.67 1 24 Boardman Dalreed Sub
H Wood 230.00 230.00 27.34 1 25 Caldwell Ontario
S Tower 230.00 230.00 3.26 1 26 " " "
S Tower 230.00 230.00 0.86 1 27 Boise Bench Midpoint #1
H Wood 230.00 230.00 108.47 1 28 " " "
S Tower 230.00 230.00 1.52 1 29 Brownlee Quartz Jct
H Wood 230.00 230.00 41.65 1 30 " " "
S Tower 230.00 230.00 100.09 2 31 Brownlee Boise Bench #1 & #2
S Tower 230.00 230.00 10.44 2 32 Oxbow Brownlee
S Tower 230.00 230.00 3.42 1 33 Boise Bench Midpoint #2
H Wood 230.00 230.00 101.94 1 34 " " "
S Tower 230.00 230.00 20.14 2 35 Oxbow Pallette Jct
FERC FORM NO. 1 (ED. 12-87)Page 422
36 TOTAL 4,656.75 147
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
TRANSMISSION LINE STATISTICS
Idaho Power Company X
04/30/2003
2002
Line
No.
(c)(b)(a)(d)(e)
DESIGNATION
From To
(f)(g)
VOLTAGE (KV)(Indicate whereother than
60 cycle, 3 phase)
Operating Designed
Type of
Supporting
Structure
LENGTH (Pole miles)(In the case of underground linesreport circuit miles)
On Structureof LineDesignated
On Structuresof AnotherLine
Number
Of
Circuits
(h)
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
H Wood 230.00 230.00 24.57 2 1 Pallette Jct Imnaha
S Tower 230.00 230.00 8.27 2 2 Hells Canyon Palette Jct
S Tower 230.00 230.00 102.56 2 3 Brownlee Boise Bench
H Wood 230.00 230.00 106.65 1 4 Boise Bench Midpoint #3
H Wood 230.00 230.00 29.62 1 5 Palette Jct Enterprise
S Tower 230.00 230.00 0.43 1 6 Borah Brady #2
H Wood 230.00 230.00 3.59 1 7 " "
H Wood 230.00 230.00 3.96 1 8 Borah Brady #1
9
H Wood 161.00 161.00 90.44 1 10 Goshen State Line
S Tower 161.00 161.00 2.40 2 11 Don Goshen
H Wood 161.00 161.00 46.53 2 12 " "
13
H Wood 138.00 138.00 84.82 2 14 American Falls Power Plant Adelaide
S P Wood 138.00 138.00 2.58 2 15 " "
S Tower 138.00 138.00 1.54 2 16 Minidoka Loop "
S P Wood 138.00 138.00 10.79 2 17 Nampa Caldwell
H Wood 138.00 4.41 1 18 Upper Salmon Mountain Home Jct
H Wood 138.00 138.00 54.59 1 19 " "
H Wood 138.00 138.00 30.94 1 20 "Cliff
S P Wood 138.00 138.00 2.12 1 21 Eastgate Russet
S Tower 138.00 138.00 1.00 2 22 Brady Fremont
H Wood 138.00 138.00 27.98 2 23 " "
S P Wood 138.00 138.00 20.64 2 24 " "
H Wood 138.00 138.00 85.20 2 25 King Lower Malad
H Wood 138.00 138.00 60.87 2 26 Emmett Jct Payette
H Wood 138.00 138.00 6.23 1 27 Mountain Home AFB Tap
H Wood 138.00 138.00 73.61 1 28 Ontario Quartz
S Tower 138.00 138.00 1.02 2 29 King American Falls PP
H Wood 138.00 138.00 135.81 1 30 " "
S P Wood 138.00 138.00 3.71 1 31 " "
32
33
H Wood 138.00 138.00 6.28 1 34 Duffin Clawson
H Wood 138.00 138.00 0.38 1 35 American Falls Brady Tie
FERC FORM NO. 1 (ED. 12-87)Page 422.1
36 TOTAL 4,656.75 147
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
TRANSMISSION LINE STATISTICS
Idaho Power Company X
04/30/2003
2002
Line
No.
(c)(b)(a)(d)(e)
DESIGNATION
From To
(f)(g)
VOLTAGE (KV)(Indicate whereother than
60 cycle, 3 phase)
Operating Designed
Type of
Supporting
Structure
LENGTH (Pole miles)(In the case of underground linesreport circuit miles)
On Structureof LineDesignated
On Structuresof AnotherLine
Number
Of
Circuits
(h)
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
H Wood 138.00 138.00 6.05 1 1 Upper Salmon A-B King
H Wood 138.00 138.00 125.70 1 2 Upper Salmon B Wells
H Wood 138.00 138.00 73.98 1 3 King Wood River
S P Wood 138.00 138.00 10.48 2 4 Boise Bench Grove
H Wood 138.00 138.00 67.45 1 5 Quartz John Day
H Wood 138.00 138.00 2.80 1 6 Sinker Creek Tap
H Wood 138.00 138.00 2.57 1 7 Mora Cloverdale
S P Wood 138.00 138.00 22.50 1 8 " "
S P Steel 138.00 138.00 3.80 1 9 Stoddard Jct Stoddard Sub
H Wood 138.00 138.00 2.08 1 10 Fossil Gulch Tap
H Wood 138.00 138.00 53.22 2 11 Wood River Midpoint
S P Wood 138.00 138.00 16.74 2 12 " "
H Wood 138.00 138.00 38.61 1 13 Oxbow McCall
S P Wood 138.00 138.00 1.73 1 14 " "
S P Wood 138.00 138.00 6.60 2 15 Lowell Jct Nampa
S P Wood 138.00 138.00 19.62 1 16 Hunt Milner
H Wood 138.00 138.00 13.51 1 17 Strike Bruneau Bridge
S P Wood 138.00 138.00 18.42 2 18 American Falls Kramer Sub
S P Wood 138.00 138.00 11.77 1 19 Pingree Haven
S P Wood 138.00 138.00 25.42 2 20 Midpoint Twin Falls
S P Wood 138.00 138.00 1.73 1 21 Twin Falls Russett
S P Wood 138.00 138.00 6.36 2 22 Blackfoot Aiken
H Wood 138.00 138.00 57.27 1 23 Peterson Tendoy
S P Wood 138.00 138.00 7.39 1 24 Eastgate Tap Eastgate
H Wood 138.00 138.00 13.28 2 25 Boise Bench Mora
S P Wood 138.00 138.00 0.54 1 26 Bowmont-Caldwell Simplot Sub
S P Wood 138.00 138.00 6.81 1 27 Gary Lane Eagle
S P Steel 138.00 138.00 7.01 1 28 Locust Grove Blackcat Sub
S P Steel 138.00 138.00 2.97 2 29 Boise Bench Butler Sub
S Tower 138.00 138.00 1.42 2 30 Kinport Don #1
H Wood 138.00 138.00 1.03 1 31 Twin Falls PP Tap
S P Steel 138.00 138.00 0.43 1 32 American Falls PP Amercian Falls Trans ST
H Wood 138.00 138.00 0.25 1 33 Lower Salmon King Tie
S Tower 138.00 138.00 4.48 2 34 C J Strike Strike Jct
H Wood 138.00 138.00 26.72 1 35 Strike Jct Mountain Home Jct
FERC FORM NO. 1 (ED. 12-87)Page 422.2
36 TOTAL 4,656.75 147
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
TRANSMISSION LINE STATISTICS
Idaho Power Company X
04/30/2003
2002
Line
No.
(c)(b)(a)(d)(e)
DESIGNATION
From To
(f)(g)
VOLTAGE (KV)(Indicate whereother than
60 cycle, 3 phase)
Operating Designed
Type of
Supporting
Structure
LENGTH (Pole miles)(In the case of underground linesreport circuit miles)
On Structureof LineDesignated
On Structuresof AnotherLine
Number
Of
Circuits
(h)
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
1
H Wood 138.00 0.06 1 2 Strike Jct Bowmont
S Tower 138.00 138.00 0.36 1 3 " "
H Wood 138.00 138.00 68.45 1 4 Strike Jct Bowmont
H Wood 138.00 138.00 4.51 2 5 Lucky Peak Lucky Peak Jct
H Wood 138.00 138.00 0.29 1 6 Bliss King
H Wood 138.00 138.00 10.57 1 7 " "
S P Wood 138.00 138.00 1.36 1 8 Milner Deadend Milner PP
H Wood 138.00 138.00 1.00 1 9 Swan Falls Tap
10
11
12
H Wood 115.00 115.00 3.41 1 13 Hines BPA (Harney)
14
15
H Wood 69.00 69.00 233.85 1 16 69 Kv Lines
S P Wood 69.00 69.00 936.44 1 17 69 Kv Lines
18
19
S P Wood 46.00 46.00 434.16 1 20 46 Kv Lines
21
22
23
24
25
26
27
28
29 Expenses of all Lines
30
31
32
33
34
35
FERC FORM NO. 1 (ED. 12-87)Page 422.3
36 TOTAL 4,656.75 147
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
TRANSMISSION LINE STATISTICS (Continued)
Idaho Power Company X
04/30/2003
2002
Line
No.
COST OF LINE (Include in Column (j) Land,
Size of
Conductor
and Material
Land rights, and clearing right-of-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES
Operation
Expenses
Maintenance Rents TotalLandConstruction and
Other Costs
Total Cost
(i)(j)(k)(l)(m)(n)(o)(p)Expenses Expenses
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
446,7082X1780 ACSR 446,708 1
2
22,033,3791272 ACSR 21,776,998 256,381 3
15,998,9161272 ACSR 15,515,607 483,309 4
11,568,428795 ACSR 10,996,449 571,979 5
6,372,2531272 ACSR 6,028,033 344,220 6
5,486,080715.5 ACSR 5,425,266 60,814 7
6,084,006715.5 ACSR 6,019,155 64,851 8
399,394715.5 ACSR 347,946 51,448 9
10
2,122,943795 ACSR 2,071,529 51,414 11
405,096715.5 ACSR 395,951 9,145 12
2,436,9471272 ACSR 2,328,646 108,301 13
6,186795 ACSR 6,186 14
988,305715.5 ACSR 969,476 18,829 15
52,7151272 ACSR 51,525 1,190 16
15,960,9372X954 ACSR 14,658,240 1,302,697 17
800,082715.5 ACSR 770,560 29,522 18
715.5 ACSR 19
214,4221272 ACSR 212,523 1,899 20
3,570,6401272 ACSR 2,761,586 809,054 21
715.5 ACSR 22
9,586,7701272 ACSR 6,610,447 2,976,323 23
80,895795 AAC 80,895 24
5,573,5262X954 ACSR 5,378,763 194,763 25
1272 ACSR 26
3,617,408715.5 ACSR 3,381,261 236,147 27
715.5 ACSR 28
1,825,881795 ACSR 1,782,886 42,995 29
795 ACSR 30
14,093,901VARIOUS 13,458,530 635,371 31
1,036,2681272 ACSR 1,030,235 6,033 32
4,572,065715.5 ACSR 4,369,305 202,760 33
VARIOUS 34
1,907,3711272 ACSR 1,884,063 23,308 35
FERC FORM NO. 1 (ED. 12-87)Page 423
36 15,908,723 240,346,731 256,255,454 5,179,735 3,076,074 1,648,202 9,904,011
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
TRANSMISSION LINE STATISTICS (Continued)
Idaho Power Company X
04/30/2003
2002
Line
No.
COST OF LINE (Include in Column (j) Land,
Size of
Conductor
and Material
Land rights, and clearing right-of-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES
Operation
Expenses
Maintenance Rents TotalLandConstruction and
Other Costs
Total Cost
(i)(j)(k)(l)(m)(n)(o)(p)Expenses Expenses
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
1,331,7321272 ACSR 1,193,255 138,477 1
1,225,5841272 ACSR 1,214,847 10,737 2
5,961,567954 ACSR 5,790,873 170,694 3
4,806,404715.5 ACSR 4,563,114 243,290 4
1,684,2161272 ACSR 1,633,094 51,122 5
203,7001272 ACSR 200,632 3,068 6
715.5 ACSR 7
190,0721272 ACSR 180,008 10,064 8
9
654,246250 COPPER 638,091 16,155 10
1,827,438715.5 ACSR 1,751,397 76,041 11
397.5 ACSR 12
13
2,378,450250 COPPER 2,351,943 26,507 14
250 COPPER 15
264,320715.5 ACSR 249,232 15,088 16
1,667,802795 AAC 1,510,370 157,432 17
1,667,952795 ACSR 1,620,265 47,687 18
VARIOUS 19
807,751795 ACSR 764,183 43,568 20
828,327795 AAC 557,504 270,823 21
3,990,657VARIOUS 3,425,725 564,932 22
" 23
" 24
1,356,180" 1,279,357 76,823 25
1,350,941" 1,320,023 30,918 26
1,955397.5 ACSR 1,955 27
1,494,539VARIOUS 1,460,111 34,428 28
4,032,020715.5 ACSR 3,897,526 134,494 29
715.5 ACSR 30
715.5 ACSR 31
32
33
314,0184\0 309,827 4,191 34
13,539954 ACSR 13,539 35
FERC FORM NO. 1 (ED. 12-87)Page 423.1
36 15,908,723 240,346,731 256,255,454 5,179,735 3,076,074 1,648,202 9,904,011
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
TRANSMISSION LINE STATISTICS (Continued)
Idaho Power Company X
04/30/2003
2002
Line
No.
COST OF LINE (Include in Column (j) Land,
Size of
Conductor
and Material
Land rights, and clearing right-of-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES
Operation
Expenses
Maintenance Rents TotalLandConstruction and
Other Costs
Total Cost
(i)(j)(k)(l)(m)(n)(o)(p)Expenses Expenses
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
84,472250 COPPER 81,732 2,740 1
1,774,294VARIOUS 1,745,804 28,490 2
2,342,795" 2,169,112 173,683 3
1,899,065" 1,673,463 225,602 4
2,489,403397.5 ACSR 2,397,230 92,173 5
77,219VARIOUS 77,199 20 6
6,113,307715.5 ACSR 4,811,134 1,302,173 7
VARIOUS 8
1272 ACSR 9
63,889250 COPPER 63,439 450 10
6,649,731397.5 ACSR 6,368,667 281,064 11
397.5 ACSR 12
1,822,847397.5 ACSR 1,738,664 84,183 13
397.5 ACSR 14
1,078,063715.5 ACSR 950,694 127,369 15
1,074,263715.5 ACSR 1,070,939 3,324 16
601,022397.5 ACSR 586,095 14,927 17
1,005,448715.5 ACSR 991,714 13,734 18
789,305397.5 ACSR 778,092 11,213 19
3,004,038VARIOUS 2,949,190 54,848 20
222,948715.5 ACSR 206,158 16,790 21
461,918715.5 ACSR 448,302 13,616 22
3,845,645397.5 ACSR 3,449,949 395,696 23
1,103,560715.5 ACSR 1,057,571 45,989 24
647,415715.5 ACSR 632,718 14,697 25
49,642795 AAC 49,642 26
2,454,637795 AAC 1,965,600 489,037 27
3,928,1691272 ACSR 2,992,444 935,725 28
565,2831272 ACSR 554,887 10,396 29
213,951715.5 ACSR 212,777 1,174 30
53,946250 COPPER 53,888 58 31
76,560715.5 ACSR 76,560 32
4,406397.5 ACSR 4,406 33
254,946715.5 ACSR 253,872 1,074 34
479,841397.5 ACSR 475,486 4,355 35
FERC FORM NO. 1 (ED. 12-87)Page 423.2
36 15,908,723 240,346,731 256,255,454 5,179,735 3,076,074 1,648,202 9,904,011
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
TRANSMISSION LINE STATISTICS (Continued)
Idaho Power Company X
04/30/2003
2002
Line
No.
COST OF LINE (Include in Column (j) Land,
Size of
Conductor
and Material
Land rights, and clearing right-of-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES
Operation
Expenses
Maintenance Rents TotalLandConstruction and
Other Costs
Total Cost
(i)(j)(k)(l)(m)(n)(o)(p)Expenses Expenses
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
1
1,518,009715.5 ACSR 1,488,107 29,902 2
715.5 ACSR 3
4
152,859715.5 ACSR 152,852 7 5
VARIOUS 6
451,286715.5 ACSR 445,666 5,620 7
186,420715.5 ACSR 183,606 2,814 8
274,396397.5 ACSR 261,511 12,885 9
397.5 ACSR 10
11
12
65,382397.5 ACSR 63,404 1,978 13
14
15
25,773,706VARIOUS 25,050,301 723,405 16
" 17
18
19
7,306,436VARIOUS 7,130,171 176,265 20
21
22
23
24
25
26
27
28
9,904,011 1,648,202 3,076,074 5,179,735 29
30
31
32
33
34
35
FERC FORM NO. 1 (ED. 12-87)Page 423.3
36 15,908,723 240,346,731 256,255,454 5,179,735 3,076,074 1,648,202 9,904,011
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
TRANSMISSION LINES ADDED DURING YEAR
Idaho Power Company X
04/30/2003
2002
Line
No.
(c)(b)(a)(d)(e)
LINE DESIGNATION
From To
LineLength
inMiles
SUPPORTING STRUCTURE
Type AverageNumber per
Miles
CIRCUITS PER STRUCTURE
Present Ultimate
(f)(g)
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 (l) to (o), it is permissible to report in these columns the
1 No New Lines Added for 2002
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
FERC FORM NO. 1 (ED. 12-86)Page 424
44 TOTAL
Total
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
TRANSMISSION LINES ADDED DURING YEAR (Continued)
Idaho Power Company X
04/30/2003
2002
Line
No.
(k)(j)(h)(l)(m)
CONDUCTORS
Size Configuration
Voltage
KV
LINE COST
Land and Poles, Towers
and Fixtures
Conductors
(n)(o)
Specification and Spacing (Operating)Land Rights and Devices(i)
costs. Designate, however, if estimated amounts are reported. Include costs of Clearing Land and Rights-of-Way, and Roads and
Trails, in column (l) 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.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
FERC FORM NO. 1 (ED. 12-86)Page 425
44
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
SUBSTATIONS
Idaho Power Company X
04/30/2003 2002
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
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).
Adelaide 138.00 345.00 13.80transmission 1
Aiken 13.00 46.00distribution 2
Alameda 12.50 46.00" 3
" 12.50 138.00" 4
American Falls PP - attended 13.80 138.00transmission 5
American Falls 46.00 138.00 13.80" 6
Artesian 13.00 46.00distribution 7
Bannock Creek 12.50 46.00" 8
Bethel Court 13.00 69.00" 9
Black Cat 13.09 138.00" 10
Blackfoot 12.50 46.00" 11
" 38.00 138.00 13.80" 12
Bliss - attended 13.80 138.00transmission 13
Blue Gulch 34.50 138.00distribution 14
Boise Bench - attended 34.50 138.00distribution 15
" 69.00 138.00 13.80transmission 16
" 138.00 230.00 13.80" 17
Boise Cascade Emmett CSPP 13.00 69.00distribution 18
Boise Cascade 1 13.00 69.00" 19
Boise 13.00 138.00" 20
Borah 138.00 345.00 13.80transmission 21
Bowmont 7.20 38.00distribution 22
" 34.50 138.00" 23
" 69.00 138.00 13.80" 24
Brady 12.50 46.00transmission 25
" 138.00 230.00 13.80" 26
Brownlee - attended 13.80 230.00transmission 27
Bruneau Bridge 34.50 138.00distribution 28
Buckhorn 38.00 69.00" 29
Bucyrus 7.20 46.00" 30
Buhl 13.00 46.00" 31
Burley Rural 13.00 69.00" 32
Butler 13.00 138.00" 33
Caldwell 13.00 138.00" 34
" 69.00 138.00 13.00" 35
" 138.00 230.00 12.50transmission 36
Canyon Creek 34.50 138.00distribution 37
" 69.00 138.00 12.50" 38
Cascade Power Plant - attended 4.60 69.00Transmission 39
Chestnut 13.00 138.00distribution 40
FERC FORM NO. 1 (ED. 12-96)Page 426
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
SUBSTATIONS
Idaho Power Company X
04/30/2003 2002
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
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).
Clear Lake - attended 2.30 46.00transmission 1
Cliff 38.00 69.00 12.50" 2
Cloverdale 13.00 138.00Transmission 3
" 69.00 138.00 12.50" 4
Dale 13.00 69.00Distribution 5
" 34.50 138.00" 6
" 46.00 138.00 12.50" 7
Danskin 12.00 138.00Transmission 8
Don 7.60 138.00Distribution 9
" 7.60 138.00" 10
" 13.80 138.00 7.20" 11
" 13.80 138.00" 12
DRAM 13.00 138.00" 13
" 138.00 230.00 13.80" 14
Duffin 34.50 138.00" 15
Eagle 13.00 138.00" 16
Eastgate 13.00 138.00" 17
Eden 34.50 138.00" 18
" 46.00 138.00 12.50" 19
Elkhorn 12.00 138.00distribution 20
Elmore 34.50 138.00Transmission 21
" 69.00 138.00 12.50" 22
Emmett 12.50 138.00distribution 23
" 69.00 138.00 12.50" 24
Falls 12.50 46.00" 25
Filer 12.50 46.00" 26
Flying H 2.40 69.00" 27
Fort Hall 12.50 46.00" 28
Fossil Gulch 13.80 138.00 4.60" 29
" 34.50 138.00" 30
Fremont 38.00 69.00 12.50transmission 31
Gary 13.00 138.00distribution 32
Gem 13.00 69.00distribution 33
Golden Valley 12.50 69.00" 34
Gowen Substation 36.00 138.00" 35
Grindstone 12.50 35.00" 36
Grove 12.50 138.00" 37
Hagerman 12.50 46.00" 38
Hailey 12.50 138.00" 39
Haven 34.50 46.00" 40
FERC FORM NO. 1 (ED. 12-96)Page 426.1
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
SUBSTATIONS
Idaho Power Company X
04/30/2003 2002
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
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).
Hewlett Packard 13.10 138.00Distribution 1
Hidden Springs 13.09 138.00" 2
Highland 13.09 138.00" 3
Hill 12.50 138.00" 4
Homedale 12.50 69.00" 5
Horseshoe Bend 12.50 35.00Distribution 6
" 12.50 69.00" 7
" 25.00 69.00" 8
Houston 13.00 69.00" 9
Hulen 13.00 46.00distribution 10
Hunt 138.00 230.00 13.80transmission 11
Hydra 34.50 138.00distribution 12
Island 12.50 69.00" 13
Jerome 12.50 46.00" 14
" 12.50 138.00" 15
Julion Clawson 34.50 138.00" 16
Joplin 13.00 138.00" 17
Karcher 13.09 138.00" 18
Kenyon 12.50 69.00" 19
Ketchum 12.50 138.00" 20
Kinport 46.00 161.00 13.00transmission 21
" 138.00 230.00 12.50" 22
" 138.00 230.00 13.80" 23
" 230.00 345.00 13.80" 24
Kramer 34.50 138.00distribution 25
" 13.00 138.00" 26
Lamb 13.09 138.00distribution 27
Lansing 13.00 69.00" 28
Linden 13.00 138.00" 29
Locust 34.50 138.00" 30
" 138.00 230.00 13.00transmission 31
Lower Malad - attended 7.20 138.00transmission 32
Lower Salmon - attended 13.80 138.00" 33
Map Rock 12.50 69.00distribution 34
McCall 12.50 69.00" 35
" 35.00 138.00" 36
" 69.00 138.00 12.50" 37
Meridian 13.00 138.00" 38
Micron 12.50 138.00" 39
Midpoint 138.00 230.00 12.50transmission 40
FERC FORM NO. 1 (ED. 12-96)Page 426.2
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
SUBSTATIONS
Idaho Power Company X
04/30/2003 2002
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
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).
Midpoint 230.00 345.00 13.80Transmission 1
" 345.00 500.00" 2
Milner 38.00 69.00 13.80distribution 3
" 38.00 69.00 7.20" 4
" 34.50 138.00" 5
Milner PP - attended 13.80 138.00transmission 6
Moonstone 34.50 138.00distribution 7
Mora 34.50 138.00" 8
Moreland 12.50 46.00" 9
" 34.50 46.00 12.50" 10
Mountain Home 12.50 69.00Distribution 11
Mountain Home Air Force Base 12.50 69.00" 12
" 12.50 138.00" 13
Nampa 12.50 69.00" 14
" 12.50 138.00" 15
" 69.00 138.00 12.50" 16
New Meadows 35.00 69.00distribution 17
New Plymouth 12.50 69.00" 18
Parma 12.50 69.00" 19
" 34.50 69.00" 20
Paul 34.50 138.00 12.50" 21
Payette 12.50 138.00" 22
Pingree 46.00 138.00 12.50" 23
" 36.00 138.00" 24
Pleasant Valley 34.50 138.00" 25
Pocatello 12.50 46.00" 26
Portneuf 36.20 138.00" 27
Rockford 12.50 46.00" 28
Russett 12.50 138.00" 29
Sailor Creek 13.80 138.00 4.60" 30
" 34.50 138.00" 31
Salmon 12.50 69.00" 32
" 34.50 69.00 12.50" 33
Shoshone 13.00 46.00" 34
" 7.20 46.00" 35
Shoshone Falls - attached 2.30 46.00transmission 36
" 6.60 46.00" 37
Silver 34.50 138.00distribution 38
Simplot 12.50 138.00distribution 39
Sinker Creek 34.50 138.00" 40
FERC FORM NO. 1 (ED. 12-96)Page 426.3
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
SUBSTATIONS
Idaho Power Company X
04/30/2003 2002
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
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).
Siphon 34.50 138.00Distribution 1
South Park 13.00 46.00" 2
State 12.50 69.00" 3
Stoddard 13.00 138.00" 4
Strike Power Plant - attended 13.80 138.00transmission 5
Sugar 34.50 138.00distribution 6
Swan Falls - attended 6.90 138.00Transmission 7
Taber 12.50 46.00distribution 8
Terry 12.50 138.00" 9
Thousand Springs - attended 6.90 46.00transmission 10
" 46.00 69.00 2.30" 11
Toponis 34.50 138.00distribution 12
Twin Falls 13.00 138.00" 13
" 46.00 138.00 12.50" 14
Twin Falls PP - attended 7.20 138.00transmission 15
" 13.20 138.00" 16
Upper Malad - attended 7.20 46.00" 17
Upper Salmon- attended 7.20 138.00" 18
Ustick 12.50 138.00distribution 19
Victory 12.50 138.00" 20
Ware 12.50 69.00" 21
Weiser 12.50 69.00" 22
" 69.00 138.00 12.50" 23
Wye 12.50 69.00distribution 24
Zilog 12.50 69.00" 25
26
27
The above are all State of Idaho 28
29
Montana: 30
Peterson 38.00 138.00 12.50transmission 31
32
Nevada: 33
Valmy - attended 21.30 345.00transmission 34
Wells 69.00 138.00 12.50" 35
36
Oregon: 37
Boardman - attended 24.00 500.00transmission 38
Cairo 12.50 69.00distribution 39
Hells Canyon - attended 13.80 230.00transmission 40
FERC FORM NO. 1 (ED. 12-96)Page 426.4
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
SUBSTATIONS
Idaho Power Company X
04/30/2003 2002
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
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).
Hines 115.00 138.00 12.50Transmission 1
Malheur Butte 34.50 69.00 12.50distribution 2
Nyssa 12.50 69.00" 3
Ontario 12.50 138.00" 4
" 69.00 138.00 12.50" 5
" 138.00 230.00 12.50" 6
Ore-Ida 12.50 69.00distribution 7
Oxbow - attended 38.00 69.00 12.50transmission 8
" 13.80 230.00" 9
Oxbow Attended 138.00 230.00 13.80transmission 10
Quartz 69.00 138.00 12.50transmission 11
" 80.00 138.00 12.50" 12
Vale 13.09 69.00distribution 13
14
Wyoming: 15
Jim Bridger - attended 22.00 345.00transmission 16
17
18
19
20
21
22
Transformers-distribution substations under 10,000 23
KVA 85 unattended. 24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO. 1 (ED. 12-96)Page 426.5
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
SUBSTATIONS
Idaho Power Company X
04/30/2003 2002
Line
No.Number of Units
(g)(f)(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service)(In MVa)
Number of
Transformers
In Service
Spare Type of Equipment
Number of
Transformers (In MVa)
(i)(j)
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.
300 2 1
20 2 2
15 1 3
18 1 4
72 1 5
25 1 6
10 1 7
10 1 8
12 1 9
15 1 10
30 2 11
130 3 1 12
69 3 13
15 1 14
48 2 15
90 4 16
398 4 17
12 1 18
10 1 19
67 3 20
450 3 1 21
8 3 22
18 1 23
25 1 24
6 25
300 3 26
734 5 1 27
30 2 28
20 1 29
13 4 30
20 2 31
12 1 32
48 2 33
32 2 34
50 2 35
240 2 36
15 1 37
8 1 38
12 1 39
48 2 40
FERC FORM NO. 1 (ED. 12-96)Page 427
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
SUBSTATIONS
Idaho Power Company X
04/30/2003 2002
Line
No.Number of Units
(g)(f)(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service)(In MVa)
Number of
Transformers
In Service
Spare Type of Equipment
Number of
Transformers (In MVa)
(i)(j)
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.
4 1 1
25 3 1 2
48 2 3
50 2 4
1 5
24 1 6
25 1 7
96 2 8
172 12 1 9
54 3 10
15 1 11
26 1 12
101 6 13
160 2 14
36 2 15
35 2 16
36 2 17
24 1 18
15 1 19
15 2 20
16 1 21
30 2 22
15 1 23
25 1 24
17 2 25
10 1 26
15 2 27
10 1 28
8 1 29
15 1 30
50 3 1 31
20 1 32
17 2 33
10 1 1 34
18 1 35
10 2 36
48 2 1 37
12 2 38
20 1 39
12 1 40
FERC FORM NO. 1 (ED. 12-96)Page 427.1
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
SUBSTATIONS
Idaho Power Company X
04/30/2003 2002
Line
No.Number of Units
(g)(f)(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service)(In MVa)
Number of
Transformers
In Service
Spare Type of Equipment
Number of
Transformers (In MVa)
(i)(j)
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.
20 1 1
8 1 2
18 1 3
24 1 4
15 2 5
6 1 6
12 1 7
5 1 8
10 1 9
10 1 10
300 3 11
24 1 12
12 1 13
10 1 14
20 1 15
30 2 16
15 1 17
12 1 18
20 2 19
42 2 20
8 21
180 1 22
180 1 23
600 3 24
12 1 25
18 1 26
15 1 27
12 1 28
33 2 29
48 2 30
180 1 31
15 1 32
70 4 33
10 1 34
8 1 35
18 1 36
30 1 37
36 2 38
48 4 39
120 1 40
FERC FORM NO. 1 (ED. 12-96)Page 427.2
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
SUBSTATIONS
Idaho Power Company X
04/30/2003 2002
Line
No.Number of Units
(g)(f)(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service)(In MVa)
Number of
Transformers
In Service
Spare Type of Equipment
Number of
Transformers (In MVa)
(i)(j)
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.
720 2 1
1000 4 2
75 3 1 3
8 3 1 4
16 1 5
36 1 6
12 1 7
33 2 8
8 1 9
10 3 1 10
12 1 11
1 12
18 1 13
1 14
42 2 15
25 1 16
10 4 17
10 1 18
10 1 19
12 1 20
36 2 21
22 3 22
50 3 23
22 2 24
42 2 25
36 2 26
18 1 27
14 2 28
18 1 29
15 2 30
15 1 31
10 1 4 32
10 3 1 33
1 34
1 1 35
3 1 36
10 1 37
12 1 38
15 1 39
12 1 40
FERC FORM NO. 1 (ED. 12-96)Page 427.3
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
SUBSTATIONS
Idaho Power Company X
04/30/2003 2002
Line
No.Number of Units
(g)(f)(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service)(In MVa)
Number of
Transformers
In Service
Spare Type of Equipment
Number of
Transformers (In MVa)
(i)(j)
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.
33 2 1
10 1 2
33 2 3
15 1 4
83 3 5
10 1 6
18 1 7
5 1 8
42 3 9
8 1 10
5 3 11
18 1 12
40 2 13
23 2 14
9 1 15
72 1 16
8 1 17
36 4 18
44 2 19
24 1 20
10 1 21
20 2 22
25 1 23
51 3 24
25 2 25
26
27
28
29
30
30 3 1 31
32
33
150 1 34
26 4 35
36
37
55 1 38
12 1 39
500 3 1 40
FERC FORM NO. 1 (ED. 12-96)Page 427.4
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year of Report
Dec. 31,
SUBSTATIONS
Idaho Power Company X
04/30/2003 2002
Line
No.Number of Units
(g)(f)(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service)(In MVa)
Number of
Transformers
In Service
Spare Type of Equipment
Number of
Transformers (In MVa)
(i)(j)
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.
40 1 1
10 3 2
20 2 3
38 2 4
55 3 5
240 2 6
15 1 7
10 3 1 8
244 2 9
100 1 10
30 2 11
133 4 12
10 1 13
14
15
748 1 16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO. 1 (ED. 12-96)Page 427.5
INDEX
Schedule Page 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-ii
FERC FORM NO. 1 (ED. 12-93)Index 1
INDEX (continued)
Schedule Page No.
Deferred
credits, other ................................................................................... 269
debits, miscellaneous ............................................................................ 233
income taxes accumulated - accelerated
amortization property ........................................................................ 272-273
income taxes accumulated - other property .................................................... 274-275
income taxes accumulated - other ............................................................. 276-277
income taxes accumulated - pollution control facilities .......................................... 234
Definitions, this report form ........................................................................ iii
Depreciation and amortization
of common utility plant .......................................................................... 356
of electric plant ................................................................................ 219
336-337
Directors ............................................................................................ 105
Discount - premium on long-term debt ............................................................. 256-257
Distribution of salaries and wages ............................................................... 354-355
Dividend appropriations .......................................................................... 118-119
Earnings, Retained ............................................................................... 118-119
Electric energy account .............................................................................. 401
Expenses
electric operation and maintenance ........................................................... 320-323
electric operation and maintenance, summary ...................................................... 323
unamortized debt ................................................................................. 256
Extraordinary property losses ........................................................................ 230
Filing requirements, this report form
General information .................................................................................. 101
Instructions for filing the FERC Form 1 ............................................................. i-iv
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
Index 2FERC FORM NO. 1 (ED. 12-95)
INDEX (continued)
Schedule Page No.
Interest
charges, paid on long-term debt, advances, etc ............................................... 256-257
Investments
nonutility property .............................................................................. 221
subsidiary companies ......................................................................... 224-225
Investment tax credits, accumulated deferred ..................................................... 266-267
Law, excerpts applicable to this report form .......................................................... iv
List of schedules, this report form .................................................................. 2-4
Long-term debt ................................................................................... 256-257
Losses-Extraordinary property ........................................................................ 230
Materials and supplies ............................................................................... 227
Miscellaneous general expenses ....................................................................... 335
Notes
to balance sheet ............................................................................. 122-123
to statement of changes in financial position ................................................ 122-123
to statement of income ....................................................................... 122-123
to statement of retained earnings ............................................................ 122-123
Nonutility property .................................................................................. 221
Nuclear fuel materials ........................................................................... 202-203
Nuclear generating plant, statistics ............................................................. 402-403
Officers and officers' salaries ...................................................................... 104
Operating
expenses-electric ............................................................................ 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
Index 3FERC FORM NO. 1 (ED. 12-95)
INDEX (continued)
Schedule Page No.
Plant - electric
accumulated provision for depreciation ........................................................... 219
construction work in progress .................................................................... 216
held for future use .............................................................................. 214
in service ................................................................................... 204-207
leased to others ................................................................................. 213
Plant - utility and accumulated provisions for depreciation
amortization and depletion (summary) ............................................................. 201
Pollution control facilities, accumulated deferred
income taxes ..................................................................................... 234
Power Exchanges .................................................................................. 326-327
Premium and discount on long-term debt ............................................................... 256
Premium on capital stock ............................................................................. 251
Prepaid taxes .................................................................................... 262-263
Property - losses, extraordinary ..................................................................... 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 ................................................................................. 118-119
statement of, for the year ................................................................... 118-119
unappropriated ............................................................................... 118-119
Revenues - electric operating .................................................................... 300-301
Salaries and wages
directors fees ................................................................................... 105
distribution of .............................................................................. 354-355
officers' ........................................................................................ 104
Sales of electricity by rate schedules ............................................................... 304
Sales - for resale ............................................................................... 310-311
Salvage - nuclear fuel ........................................................................... 202-203
Schedules, this report form .......................................................................... 2-4
Securities
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
Index 4FERC FORM NO. 1 (ED. 12-90)
INDEX (continued)
Schedule Page 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
Index 5FERC FORM NO. 1 (ED. 12-90)
Page
Number
12-
ANNUAL REPORT
IDAHO SUPPLEMENT TO FERC FORM 1
MULTI-STATE ELECTRIC COMPANIES
INDEX
Title
Statement of Income for the Year
Taxes Allocated to Idaho
Notes and Accounts Receivable
Accumulated Provision for Uncollectible Accounts
Receivables from Associated Companies
Gain or Loss on Disposition of Property
Professional or Consultative Services
Electric Plant in Service
Electric Operating Revenues
Electric Operation and Maintenance Expenses
Number of Electric Department Employees
Idaho Power Company
STATE OF IDAHO. ALLOCATED
An Original
STATEMENT OF INCOME FOR THE YEAR
1. Report amounts for accounts 412 and 413, Revenue and Expenses from Utility Plant Leased to 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, 9, and 10 for Natural Gas companies using accounts 404., 404., 404., 407., and 407.
4. Use page 122 for important notes regarding the state ment of income or any account thereof.
5. Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a
material amount may need to be made to the utility's customers or which may result in a material refund to the utility
with respect to power or gas purchases. State for each year affected the gross revenues or costs to which the contingency
relates and the tax effects together with an explanation of retain such revenues or recover amounts paid with respect
to power and gas purchases.
6. Give concise explanations concerning significant amounts of any refunds made or received during the year.
Line
No.
Account
(Ref.
Page
No.
(b)(c)
TOTAL
Current Year Previous Year
(d)(a)
UTILITY OPERATING INCOME
Operating Revenues (400).....................................................,.................................
Operating Expenses
Operation Expenses (401)..........................................................................,..........
Maintenance Expenses (402)................................................................................
Depreciation Expense (403)...................................................................................
Amort. & Dep!. of Utility Plant (404-405)................................................................
Amort. of Utility Plant Acq. Adj. (406)....................................................................
Amort. of Property Losses, Unrecovered Plant and
Regulatory Study Costs (407)..............................................................................
Amort. of Conversion Expenses (407)...................................................................
Regulatory Debits (407.3)......................................................................................
(Less) Regulatory Credits (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).....................................................
761 053
125 353
662 062
(104 770,411)
(547 120)
812 863 190 $
518 963 603
850,797
77,444 065
626,461
TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 22).....................668 115 863
Net Utility Operating Income (Enter Total of line 2 less 23)
(Carry forward to page 11 , line 27).....................................................................144 747 327 $
IDAHO SUPPLEMENT Page 1
December 2002
841 902,029
600 260 172
747,414
251 218
745 196
17,485 363
(76,740 642)
(21 117 310)
114 610 737
867 361
767,109 510
74,792 519
Idaho Power Company
STATE OF IDAHO. ALLOCATED
An Original December 31, 2002
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
605 090
241
182,605
(7,838,260)
43,676
14,695,239 .
096 308
855
714,256
208 718
761 053
90,125 353
662 062
(104 770,411)
(547,120)
14,230 936
IDAHO SUPPLEMENT Page 2
STATE OF IDAHO
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 12-31-02)
Directors, officers, and employees - $855 081
Other Accounts Receivable - Account 143: (at 12-31-02)
Directors, officers, and employees - $ (71)
Line Item Utility
Customers
Officers
and
Employees
(d)
No.(a)
(b)
397,455Ba!. beginning of year
Provo for uncollectibles
for year......................................................
Accounts written off....................................
Coli. of accounts
written off..................................................
Adjustments (explain).................................
346
- $- $
1,463,801 $Balance end of year....................................
IDAHO SUPPLEMENT Page 3
Balance
Beginning of
Year
(b)
761,917 $
702,410
259,483
723 810
500 000
223 810 $
Other
(e)
102 545 $
102,545 $
December 2002
Balance
End of
Year
(c)
637 655
947 245
694 113
279 013
566 346
712 667
Total
(f)
500 000
346
566 346
Idaho Power Company
STATE OF IDAHO
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)
Totals for YearDebits Credits(c) (d)
Balance
End of Year
(e)No.(a)
Account 145:
322,893 $827 722Idacorp686906 $8,463 709 $
Account 146:
IDACORP Energy..................... $ 2 962 526.870 556 $573,069 $260 013
IDACORP Financial Services.........281 281
Ida-West Energy
Company........................................167 167
Rocky Mountain Communication 299,480 883 775 899 879 283 376
IDACORP, Inc..........................287 911 656 507 762,916 181 502
IDACORP Energy Solutions.........264 933 143 343 076
Total Account 146.......................... $830 298 $25,410 838 $242 145 $077 134
IDAHO SUPPLEMENT Page 4
December 31 2002
Interest
For Year
(f)
Idaho Power Company
STATE OF IDAHO
An Original
STATE OF IDAHO - TOTAL SYSTEM DATA
GAIN OR LOSS ON DISPOSITION OF PROPERTY (Account 421.1 and 421.
1. Give a brief description of property creating the gain or loss. Include name of party acquiring the property (when
acquired by another utility or associated company) and the date transaction was completed. Identify property
by type; Leased, Held for Future Use, or Nonutility.
2. Individual gains or losses relating to property with an original cost of less than $50 000 may be grouped, with the
number of such transactions disclosed in column (a).
3. Give the date of Commission approval of journal entries in column (b), when approval is required. Where approval
is required but has not been received, give explanation following the item in column (a). (See account 102, Utility
Plant Purchased or Sold.
Line Description of Property
Original Cost
of Related
Property
(b)
Date Journal
Entry Approved
(When Required)
(c)(d)
Acct421.
No.(a)
Gain on disposition of
property:
346 000 345 995State Street Office Sale
Miscellaneous items (3)363 (16 820)
Total gain............................................................. $346 363 329 175
Loss on disposition of
property: (3 items)034
Total loss.......................................................... $034
IDAHO SUPPLEMENT Page 5
December 31, 2002
Acct 421.
(e)
678
678
Idaho Power Company
STATE OF IDAHO
An Original December 31, 2002
STATE OF IDAHO - TOTAL SYSTEM DATA
PROFESSIONAL OR CONSULTATIVE SERVICES -ITEMS $10 000 AND OVER
Line PAYEE SERVICE TYPE Amount
No.(a)(b)(c)
ANDERSON PERRY & ASSOCIATES Legal Services 347
BARKER, ROSHOL T & SIMPSON LLP Legal Services 165 866
BIDART & ROSS INC Management Services 914
BLACKBURN & JONES Management Services 141 661
BLACKFIN TECHNOLOGY INC Management Services 000
BLANK & ASSOCIATES Management Services 019
BLUE HERON CONSULTING INC Programming Services 724
BOESCH & COMPANY Govermental Relations Counsel 000
BRENNEMAN, JOHN Govermental Relations Counsel 372
BUFFINGTON, JOHN M Geomorphology Report 950
BURKE CSA Customer Survery Services 176 228
BUSINESS LEGAL CONSULTING Legal Services 233
CAMBRIDGE ENERGY RESEARCH Management Services 32,300
CENTER FOR WATER RESEARCH Environmental Services 159 655
CH2M HILL Management Services 018
CHARLES RIVER ASSOCIATES INCORP Management Services 223 876
CHAVEZ WRITING & EDITING Data Processing Services 239
CHRISTOPHER F HOPPER Legal Services 862
CHURCH, JOHN S Economic analysis Services 000
CONNOLLY & SMYSER CHTD Management Services 180
CORNERSTONE SYSTEMS INC Programming Services 147 500
DAVID EVANS AND ASSOCIATES Management Services 549
DAVIS WRIGHT TREMAINE LLP Legal Services 255 237
DELOITTE & TOUCHE LLP Accounting Services 668 152
DRI-WEFA Management Services 000
DUNNE, THOMAS Geomorphology Report 800
EAMES, MATT C Management Services 21,454
ECOS CONSULTING Management Services 042
EOP GROUP Management Services 347
EVANS KEANE Management Services 859
FISHPRO Environmental Services 069
FRAMATOME AND DE&S, INC Management Services 112 795
GENERAL RELIABILITY Management Services 000
HALL FARLEY OBERRECHT & B Legal Services 633
HDR ENGINEERING , INC Engineering Services 190 790
HERNDON, STEVEN L Relicensing Services 000
HOLLAND CONSULTING GROUP Management Services 711
J D POWER AND ASSOCIATES Management Services 000
JBR ENVIRONMENTAL CONSULTANTS Environmental Services 804
KNOWBLAUCH, WAYNE A Management Services 026
LE BOEUF LAMB GREENE Management Services 249 187
LITCHFIELD CONSULTING GROUP Management Services 738
MARSH USA INC Management Services 000
MCFAIN & ASSOC RESEARCH INC Customer Survery Services 762
MILLER BATEMAN LLP Legal Services 167 073
NAVIGANT CONSULTING, INC Management Services 000
NIELSEN GROUP INC Customer Load Survey 308 681
PB POWER Engineenng Services 817
PEGASUS HEAL THCARE TECHNOLOGY Management Services 350
IDAHO SUPPLEMENT
Page 6
Idaho Power Company
STATE OF IDAHO
An Original December 31, 2002
STATE OF IDAHO - TOTAL SYSTEM DATA
PROFESSIONAL OR CONSULTATIVE SERVICES -ITEMS $10 000 AND OVER
Line PAYEE SERVICE TYPE Amount
No.(a)(b)(c)
PERKINS COlE LLP Legal Services 13,460
POWER ENGINEERS Engineering Services 142,642
RALSTON & ASSOCIATES Engineering Services 837
RIDDELL WILLIAMS P.Legal Services 000
RISK ADVISORY Management Services 060
RIVERSIDE TECHNOLOGY Environmental Services 142
SALLADAY & DAVIS Environmental Services 685
SALLADAY, GLANCE Legal Services 659
SCHWABE WILLIAMSON & WYATT Management Services 55,424
SEAVISUAL CONSULTING Management Services 019
SIDLEY AUSTIN BROWN AND WOOD Management Services 176 021
SIMONS & ASSOCIATES INC Management Services 66,458
SORENSEN CONSULTING SERVICES Management Services 388
STEPTOE & JOHNSON LLP Legal Services 311 211
STOEL RIVES LLP Legal Services 570
STONEHART ASSOCIATES INC Management Services 120
TETRA TECH EM INC Environmental Services 382 885
U S GEOLOGICAL SURVEY Environmental Studies 270
UTILITIES INTERNATIONAL Management Services 406
UTILITY RESOURCES Management Services 711
VAN NESS FELDMAN Management Services 388 935
WEST CONSULTANTS Engineering Services 42,403
YTURRI, ROSE, BURNHAM, BENTZ Legal Services 978
Page 6-A
IDAHO SUPPLEMENT
Idaho Power Company
STATE OF IDAHO
An Original December 31, 2002
PROFESSIONAL OR CONSULTATIVE SERVICES
ITEMS $5.000 OR MORE BUT LESS THAN $10,000
PAYEE
ATER, WYNNE LLP
BLACK & VEATCH
DHIINC
EVANS RANGE RECLAMATION
HAGEN DAVID
IBM
IVEY & BAUER
JONES CHARTERED
SANDS ANDERSON MARKS & MILLER
SHARP & SMITH
STONE, R H
SUPER, ARLIN
PREDOMINANT
NATURE OF SERVICE
MANAGEMENT SERVICES
MANAGEMENT SERVICES
ENVIRONMENTAL STUDIES
MANAGEMENT SERVICES
MANAGEMENT SERVICES
MANAGEMENT SERVICES
MANAGEMENT SERVICES
LEGAL SERVICES
LEGAL SERVICES
ENGINEERING SERVICES
MANAGEMENT SERVICES
MANAGEMENT SERVICES
AMOUNT
949
464
555
040
975
251
780
775
148
544
177
375
IDAHO SUPPLEMENT Page 6-B
Idaho Power Company
STATE OF IDAHO - ALLOCATED
An Original
ELECTRIC PLANT IN SERVICE (Accounts 101 , 102, 103 and 106)
December 31 2002
1. Report below the original cost of electric plant in service according to the prescribed accounts.
2. In addition to Account 101 , Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant
Purchased or Sold; Account 103, Experimental Electric Plant Unclassified; and Account 106, Completed Construction
Not Classified - Electric.
3. Include in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year.
4. Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such accounts.
5. Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in
column (c) . Also to be included in column (c) are entries for reversals of tentative distributions of prior year reported in
column (b). Likewise, if the respondent has a significant amount of plant retirements the end of the year, include in
column (d) a tentative distribution of such retirements, on an estimated basis, with appropriate contra entry to the account
for accumulated depreciation provision. Include also in column (d) reversals of tentative distributions of prior year of un-
classified retirements. Attach supplemental statement showing the account distributions of these tentative classifications in
columns (c) and (d), including the reversals of the prior years tentative account distributions of these amounts. Careful ob-
servance of the above instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount
of respondent's plant actually in serVIce at end of year.
Line
No.
Account
(a)
1. INTANGIBLE PLANT
(301) Organization........................................................................................................
(302) Franchises and Consents.........................................................."""""""""""'"
(303) Miscellaneous Intangible Plant...........................................................................
TOTAL Intangible Plant (Enter Total of lines 2, 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.............................................................................
TOTAL Steam Production Plant (Enter Total of lines 8 thru 14).................................
B. Nuclear Production Plant
(320) Land and Land Rights.........................................................................................
(321) Structures and Improvements.................................................................,...........
(322) Reactor Plant Equipmenl......................................................"""""""""""""""
(323) Turbogenerator Units..........................................................................................
(324) Accessory Electric Equipment......................................................."""""""""'"
(325) Misc. Power Plant Equipment............................................................................
TOTAL Nuclear Production Plant (Enter Total of lines 17 thru 22).............................
C. Hydraulic Production Plant
(330) Land and Land Rights...........................................................................,.............
(331) Structures and Improvements.................................................................,...........
(332) Reservoirs, Dams, and Waterways.....................................................................
(333) Water Wheels, Turbines, and Generators..........................................................
(334) Accessory Electric Equipment............................................................................
(335) Misc. Power Plant Equipment..............................................................,.............
(336) Roads, Railroads, and Bridges...........................................................................
TOTAL Hydraulic Production Plant (Enter Total of lines 25 thru 31)..........................
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..............................................."""""""""""""'"
Page 7
IDAHO SUPPLEMENT
Balance at
Beginning of year
(b)
161
227 781
47,864,471
097 414
693 199 238
567 549 422
Additions
(c)
Idaho Power Company
STATE OF IDAHO - ALLOCATED
An Original December 31 2002
ELECTRIC PLANT IN SERVICE (Accounts 101 , 102, 103 and 106) (Continued)
6. Show in column (I) reclassifications or transfers within utility plant accounts. Include also in column
(I) the additions or reductions of primary account classifications arising from distribution of amounts
initially recorded in Account 102. In showing the clearance of Account 102, include in column (e) the
amounts with respect to accumulated provision for depreciation, acquisition adjustments , etc., and show
in column (I) only the offset to the debits or credits distributed in column (I) to primary account classifications.
7. 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.
8. 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.
412 (301)
514 471 (302)
318 994 (303)
846 876
(310)
(311)
(312)
(313)
(314)
(315)
(316)
699 476 737
(320)
(321)
(322)
(323)
(324)
(325)
(330)
(331)
(332)
(333)
(334)
(335)
(336)
571 810 235
(340)
(341)
Ofu,."oo"""'- 0"' '"'" '"' of,.., ""'".(342)
(343)
(344)
(345)
Page 8
IDAHO SUPPLEMENT
Idaho Power Company
STATE OF IDAHO. ALLOCATED
An Original
Line
ELECTRIC PLANT IN SERVICE (Accounts 101 , 102, 103 and 106) (Continued)
No.
Account
(a)
(346) Misc. Power Plant Equipment.............................................................................
TOTAL Other Production Plant (Enter Total of lines 34thru 40)..............................
TOTAL Production Plant (Enter Total of lines 15,, and 41)............................
3. TRANSMISSION PLANT
(350) Land and Land Rights..........................................................................................
(352) Structures and Improvements...........................................................................,..
(353) Station Equipment.................................................................."...........................
(354) Towers and Fixtures.............................................................................................
(355) Poles and Fixtures............................................................................,...................
(356) Overhead Conductors and Devices......................................................................
(357) Underground Conduit....................................................................................,.....
(358) Underground Conductors and Devices................................................................
(359) Roads and Trails............................................................................................."...
TOTAL Transmission Plant (Enter Total of lines 44 thru 52)....................................
4. DISTRIBUTION PLANT
(360) Land and Land Rights........................................................................................,.
(361) Structures and Improvements....................................................................,.........
(362) Station Equipment.................................................................,.............................
(363) Storage Battery Equipment..................................................................................
(364) Poles, Towers, and Fixtures..........................................................,......................
(365) Overhead Conductors and Devices......................................................................
(366) Underground Conduit..................................................................,........................
(367) Underground Conductors and Devices................................................................
(368) Line Transformers................................................................................................
(369) Services................................................................................................................
(370) Meters....................................................................................,..............................
(371) Installations on Customer Premises....................................................................
(372) Leased Property on Customer Premises.............................................................
(373) Street Lighting and Signal Systems.....................................................................
TOTAL Distribution Plant (Enter Total of lines 55 thru 68).......................................
5. GENERAL PLANT
(389) Land and Land Rights......................................................................................"..
(390) Structures and Improvements........................................................,.....................
(391) Office Furniture and Equipment.........................................................................,
(392) Transportation Equipment..............................................................................,.....
(393) Stores Equipment........................................................................................"......
(394) Tools, Shop, and Garage Equipmenl...................................................................
(395) Laboratory Equipment.......................................................................................,.
(396) Power Operated Equipmenl.......................................................................,.........
(397) Communication Equipment.................................................................................
(398) Miscellaneous Equipment.................................................................................".
SUBTOTAL (Enter Total of lines 71 thru 80).............................................................
(399) Other Tangible Property..................................................................................,....
TOTAL General Plant (Enter Total of lines 81 and 82)............................................
TOTAL (Accounts 101 and 106)..........................................................................
(102) Electric Plant Purchased ..............................,...................................................,..
(Less) (102) Electric Plant Sold.....................................................................................
(103) Experimental Plant Unclassified.......................................................................,...
TOTAL Electric Plant in Service................................................................................ $
Page 9
IDAHO SUPPLEMENT
Balance at
Beginning of year
(b)
891,388
304 640 048
439 654
070 377
152 434 562
45,883 182
64,895 165
568 613
253 137
378 544 689
238 044
539 229
96,441 563
151 630 460
310 419
28,055 847
116 255 035
225 942,526
269 963
35,945 582
850 356
594 453
796 073 478
919 696
987 723
335 417
720,020
798,029
091,382
873 207
675 368
15,721,270
687 745
171 809 857
171 809,857
706 165 486
706 165 486
December 31, 2002
Additions
(c)
Idaho Power Company
STATE OF IDAHO. ALLOCATED
An Original December 31 2002
ELECTRIC PLANT IN SERVICE (Accounts 101 , 102, 103 and 106) (Continued)
Balance at line
Retirements Adjustments Transfers End of Year
(d)(e)(I)
(g)
No.
(346)
391 611
317 678,584
13,771,426 (350)
22,798 079 (352)
165 084 935 (353)
394,555 (354)
169 045 (355)
033 641 (356)
(357)
(358)
252,181 (359)
397 503 863
807 735 (360)
992 993 (361)
112,946 325 (362)
(363)
158 178 712 (364)
954 626 (365)
032 480 (366)
122 900 635 (367)
231 845 484 (368)
437 018 (369)
941,798 (370)
972,626 (371)
(372)
681,962 (373)
842,692 395
758 870 (389)
51,558 446 (390)
495 614 (391)
689 931 (392)
917 267 (393)
198 861 (394)
915 997 (395)
796 142 (396)
625 587 (397)
812 541 (398)
179 769 256
(399)
179 769 256
798 490 974
(102)
(103)
798 490 974
Page 10
IDAHO SUPPLEMENT
Idaho Power Company
STATE OF IDAHO - ALLOCATED
An Original
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
No.
Amount for
Current Year
(a)
Sales of Electricity(440) Residential .Sales....................................................................
(442) Commercial and Industrial Sales
Small (or Commercial)(See Instr. 4) (1 )..........................................
Large (or Industrial)(See Instr. 4) (2)..............................................
Non-Juristictional Sales - Embarcadero - (allocated)....................
(444) Public Street and Highway Lighting.........................................
(445) Other Sales to Public Authorities.............................................
(446) Sales to Railroads and Railways...............................
..............
(448) Interdepartmental Sales...........................................................
TOTAL Sales to Ultimate Consumers.........................................
(447) Sales for Resale - Opportunity....Non-Firm Only....................
TOTAL Sales of Electricity..........................................................
(449.1) Provision for Rate Refunds.................................................
TOTAL Revenue Net of Provision for Refunds............................
(b)
296 274 337
277 574 779
169 021 742
636 203
745 507 061 .
37,425 361
782 932,422
782 932,422
Other Operating Revenues
(450) Forfeited Discounts.................................................................
(451) Miscellaneous Service Revenues............................................
(453) Sales of Water and Water Power............................................
(454) Rent from Electric Property.....................................................
(455) Interdepartmental Rents..........................................................
(456) Other Electric Revenues.........................................................709 860
328 243
892 664
930 768
812 863,190
TOTAL Other Operating Revenues.............................................
TOTAL Electric Operating Revenues..........................................
(1) Commercial and Industrial sales - Small- under 1 000 KW and includes all irrigation customers.
(2) Commercial and Industrial sales - Large - 1 000 KW and over.
Page 11
IDAHO SUPPLEMENT
December 31 , 2002
Amount for
Previous Year
(c)
250 774 139
224,852 716
146 522,467
299,433
624 448 755
185 532 680
809,981,435
823 627
811 805 062
237,418
739 389
120,160
096 967
841 902 029
Idaho Power Company
STATE OF IDAHO - ALLOCATED
An Original December 31 , 2002
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 Kwof 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
Current Year
Amount for
Previous Year
(e)
Amount for
Current Year
Number for
Previous Year
(d)(f)
(g)
197 803 194 117 127,872 326 788 318 076
057 033 033
982,938 946
581,583 827
666 993 888
167
107
178
107
574 180 208 245 306 232
265 349 353 ..
891 233 207
156 582 560
391 913 832
601,490,547
993,404 379
390 368 380 593
N/A N/A
390 368 380 593
. Includes $ (1 676 699) unbilled revenues.
.. Includes (18 187 010) KWH relating to unbilled revenues.
lines 6, 12 & 17 through 27 are on an "allocated" basis.
Page 11a
IDAHO SUPPLEMENT
Line
No.
ldaho power \,;ompany
STATE OF IDAHO - ALLOCATED
An original
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnotes.
I ,-me
No.Account
(a)
1. PUWt:H IIUI"II
A. Steam Power Generation
3 Operation
(500) Operation Supervision and Engineering..........................................................................
(501) Fuel................................................................................................................................
(502) Steam Expenses.............................................................................................................
(503) Steam from Other Sources.............................................................................................
(Less) (504) Steam Transferred-Cr........................................................................,.................
(505) Electric Expenses...........................................................................................................
10 (506) Miscellaneous Steam Power Expenses..........................................................................
11 (507) Rents..............................................................................................................................
12 (509) Allowances.....................................................................................................................
TOTAL Operation (Enter Total of lines 4 thru 12)...............................................................
14 Maintenance
15 (510) Maintenance Supervision and Engineering.....................................................................
16 (511) Maintenance of Structures.............................................................................................
17 (512) Maintenance of Boiler Plant............................................................................................
18 (513) Maintenance of Electric Plant.........................................................................................
19 (514) Maintenance of Miscellaneous Steam Plant...................................................................
TOTAL Maintenance (Enter Total of Lines 15 thru 19).......................................................
TOTAL Power Production Expenses-Steam Power (Enter Total of lines 13 and 20).........22 B. Nuclear Power Generation
23 Operation24 (517) Operation Supervision and Engineering..........................................................................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...............................................................
..............................................................
TOTAL Operation (Enter Total of lines 24 thru 32)............................................................
34 Maintenance35 (528) Maintenance Supervision and Engineering.....................................................................36 (529) Maintenance of Structures.............................................................................................
37 (530) Maintenance of Reactor Plant Equipment.......................................................................
38 (531) Maintenance of Electric Plant.........................................................................................
39 (532) Maintenance of Miscellaneous Nuclear Plant.................................................................
TOTAL Maintenance (Enter Total of lines 35 thru 39).......................................................
TOTAL Power Production Expenses-Nuclear Power (Enter Total of lines 33 and 40).......42 C. Hydraulic Power Generation
43 Operation44 (535) Operation Supervision and Engineering..........................................................................45 (536) Water for Power.............................................................................................................46 (537) Hydraulic Expenses........................................................................................................47 (538) Electric Expenses...........................................................................................................48 (539) Miscellaneous Hydraulic Power Generation Expenses....................................................49 (540) Rents..............................................................................................................................
TOTAL Operation (Enter Total of lines 44 thru 49)............................................................
Page 12
IDAHO SUPPLEMENT
Amount tor
Current Year
(b)
931 752 $
913 734
3,435 969
953 923
501,977
673 413
99,410 767
705 629
140 642
740 357
570 012
154 693
311,334
119 722,101
805 639
782 243
548,402
867 914
542,909
352,547
899,654
December 31, 2002
Amount tor
Previous Year
(c)
962,083
821,776
016 622
320 464
055 445
574 072
750 463
713 789
153 801
966 872
156 857
376 324
367 643
120 118 106
088 060
937,511
127,831
169 395
577,869
277 935
178 600
Idaho Power ~ompllny
STATE OF IDAHO. ALLOCATED
An original
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnotes.
rune
No.Account
(a)51 ~. t1yaraullc Power-Ueneratlon \l,;onllnueaj
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 Plan!...............................................................
TOTAL Maintenance (Enter Total of lines 53 thru 57).........................................................
TOTAL Power Production Expenses-Hydraulic Power (Enter Total of lines 50 and 58).......
61 Operation62 (546) Operation Supervision and Engineering..........................................................................63 (547) Fuel................................................................................................................................64 (548) Generation Expenses.................................................................................................,...65 (549) Miscellaneous Other Power Generation Expenses.........................................................66 (550) Rents..............................................................................................................................
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 Plan!.......................................
TOTAL Maintenance (Enter Total of lines 69 thru 72)........................................................
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...............................................................................".............................
TOTAL Other Power Supply Expenses (Enter Total of lines 76 thru 78).............................
TOTAL Power Production Expenses (Enter Total of lines 21 , 41 , 59, 74, and 79)...............81 2. TRANSMISSION EXPENSES82 Operation
83 (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..............................................................................................................................
TOTAL Operation (Enter Total of lines 83 thru 90)..............................................................
92 Maintenance
93 (568) Maintenance Supervision and Engineenng.....................................................................
94 (569) Maintenance of Structures.............................................................................................95 (570) Maintenance of Station Equipmen!.................................................................................96 (571) Maintenance of Overhead Lines.....................................................................................97 (572) Maintenance of Underground Lines................................................................................98 (573) Maintenance of Miscellaneous Transmission Plan!........................................................
TOTAL Maintenance (Enter Total of lines 93 thru 98).........................................................
100 TOTAL Transmission Expenses (Enter Total of lines 91 and 99)........................................
102 Operation
103 (580) Operation Supervision and Engineering..........................................................................
Page 13
IDAHO SUPPLEMENT
Amount Tor
Current Year
(b)
914 638 $
160,952
678 515
965,955
043 284
763 345
662,999
286,681
136 220
2!18 740
372,857
886
111,384
858
149 970
203 886
323 097
677 810
789 194
-129 931 369
132
159,420 867
289 362,368
435 536 662
1,453 115
008 771
512,121
463 498
023 634
344 344
349,887
155 371
634,608
47,536
190,788
867,621
665
748 218
903 589
139 063
December 31, 2002
AmoUnt lor
Previous Year
(c)
990 161
925 409
461,418
872 587
951 706
201,282
379 883
154 725
682 961
459 322
298 907
705 353
301 268
309
237 678
251 038
552 306
531,853 029
680 970
(159 438 637)
373,095 362
521 145 657
605 476
986 221
029 866
448 094
385 516
358 250
089,015
902,438
690,097
217
598 007
014 639
11,023
313 982
216,420
151 571
Idaho Power Company
STATE OF IDAHO. ALLOCATED
An Original
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnotes.
No.Account
(a)104 3. UI" ,~~ (l;onunued)
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 Engmeering.....................................................................
117 (591) Maintenance of Structures.............................................................................................
118 (592) Maintenance of Station Equipment.................................................................................
119 (593) Maintenance of Overhead Lines.....................................................................................
120 (594) Maintenance of Underground Lines................................................................................
121 (595) Maintenance of Line Transformers...............................................................................
122 (596) Maintenance of Street Lighting and Signal Systems.......................................................
123 (597) Maintenance of Meters.................................................................................................,.
124 (598) Maintenance of Miscellaneous Distribution Plant............................................................
125 TOTAL Maintenance (Enter Total of lines 116 thru 124).....................................................
TOTAL Distribution Expenses (Enter Total of lines 114 and 125)........................................126
127 4. CUSTOMER ACCOUNTS EXPENSES
128 Operation
129 (901) Supervision.....................................................................................................................
130 (902) Meter Reading Expenses................................................................................................
131 (903) Customer Records and Collection Expenses..................................................................
132 (904) Uncollectible Accounts..............................................................."."""""""""""""""'"
133 (905) Miscellaneous Customer Accounts Expenses.................................................................
134 TOTAL Customer Accounts Expenses (Enter Total of lines 129 thru 133)..........................
135 5. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
136 Operation
137 (907) Supervision.....................................................................................................................
138 (908) Customer Assistance Expenses.....................................................................................
139 (909) Informational and Instructional Expenses.......................................................................
140 (910) Miscellaneous Customer Service and Informational Expenses.......................................
141 TOTAL Cust. Servic~ and Informational Expenses (Enter Total of lines 137 thru 140).........
142 6. SALES EXPENSES
143 Operation
144 (911) Supervision.....................................................................................................................
145 (912) Demonstrating and Selling Expenses..............................................................................
146 (913) Advertising Expenses.....................................................................................................
147 (916) Miscellaneous Sales Expenses.......................................................................................
148 TOTAL Sales Expenses (Enter Total of lines 144 thru 147)................................................
149 7. ADMINISTRATIVE AND GENERAL EXPENSES
150 Operation
151 (920) Administrative and General Salaries...............................................................................
152 (921) Office Supplies and Expenses........................................................................................
153 (Less) (922) Administrative Expenses Transferred-Credit......................................................
Page 14
IDAHO SUPPLEMENT
Amount lor
Current Year
(b)
224 209 $
295 166
306 712
303,426
351 814
778 095
437,777
3,416 166
158,518
22,410 947
60,438
649
2,485 110
046 558
155 509
279,428
259 068
418 499
150 887
861 146
272 092
392,987
131,419
581 296
576 002
164
683,869
240 026
085 731
440,365
766 146
926 665
743,120
(17,395 007)
lJecember 31, 2002
AmOUnt lor
Previous Year
(c)
2,475 593
270,672
3,466 781
484 836
351 356
500 318
466 219
460 708
155 153
783 206
230
037
625 142
978,029
351 967
515,358
625
651 978
194 582
464,949
248 156
583 674
073 822
537,156
307,248
214
504 114
145,764
502,692
443
267,645
933,543
955,226
220 216
(17 247,920)
Idaho Power company An Original uecemlJer '11 , 2002
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnotes.
Amount lor Amount lor
No.Account Current Year Previous Year
(a)(b)(c)
104 (L;OntinUec)
155 (923) Outside Services Employed............................................................................................205,465 630 771
156 (924) Property Insurance..........................................................................................,..............599 148 030 349
157 (925) Injuries and Damages.....................................................................................................538 237 710 188
158 (926) Employee Pensions and Benefits...................................................................................026,486 714 635
159 (927) Franchise Requirements.....................................................................................,..........750 575
160 (928) Regulatory Commission Expenses.................................................................................752,148 704,160
161 (929) Duplicate Charges-Cr............................................................,........................................
162 (930.1) General Advertising Expenses.....................................................................................530 714 767 691
163 (930.2) Miscellaneous General Expenses................................................................................208 838 295 063
164 (931)Rents........................................................................................................................,.....533 226
165 TOTAL Operation (Enter Total of lines 151 thru 164).........................................................,.163 097 811 179
166 Maintenance
167 (935)Maintenance of General Plant........................................................................................488 945 148 519
168 TOTAL Administrative and General Expenses (Enter Total of lines 165
thru 167)....................................................................................,..................................652 042 959 698
169 TOTAL Electric Operation and Maintenance Expenses (Enter Total of
lines 80 100 126 134 141 148, and 168)...................................................................568 814,400 651 007 587
ST ATE OF IDAHO - ALLOCATED
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 respondenfs 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, 2002
2 Total Regular Full-Time Employees.........................................................................................653
3 Total Part-Time and Temporary Employees.............................................................................
4 Total Employees......................................................................................................................687
Page 15
IDAHO SUPPLEMENT