2007Annual Report.pdf

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Item 1: 00 An Initial (Original)
Submission
OR 0 Resubmission No.
Form 1~Approved
OMS No. 1902-0021
(Expires 7/31/2008)
Form 1-F Approved
OMS No. 1902-0029
(Expires 6/30/2007)
Form 3-Q Approved
OMB No. 1902-0205
(Expires 6/30/2007)
THIS FILING IS
FERC FINANCIAL REPORT
FERC FORM No.1: Annual Report of
Major Electric Utilities, Licensees
and Others and Supplemental
Form 3-Q: Quarterly Financial Report
These report are mandatory under the Federal Power Act, Sections 3, 4(a), 304 and 309, and
18 CFR 141.1 and 141.400. Failure to report may result in criminal fines, civil penalties and
other sanctions as provided by law. The Federal Energy Regulatory Commission does not
consider these report to be of confidential nature
Exact Legal Name of Respondent (Company)
Idaho Power Company
Year/Period of Report
End of 2007/Q4
FERC FORM No.113-Q (REV. 02-04)
1SIDA~POq¡
An IDACORP Company
8: \ ';)
April l8, 2008
Idaho Public Utilities Commission
472 West Washington Street
Boise, ID 83720
To Whom It May Concern:
Enclosed is an original and two copies ofIdaho Power Company's Anual Report FERC Form 1,
which includes the "Idaho Section" covering Idaho operations.
Also enclosed, as additional information for your use, is one copy each:
. FERC Form 1, with "Idaho Section" unbound
· IDACORP Inc. and Idaho Power Company SEC Form 10-K
Each year a copy of the EIA-860 is also included, however, this year the Deparment of Energy
is modifying the software used to generate the report. There is no indication when the report wil
be available.
The above reports are for the year ended December 31, 2007.
Yours very truly,~o(2~
Senior Vice President - Administrative
Services and Chief Financial Officer
DA:dva
Enclosure
P.O. Box 70 (B3707)
1221 W. Idaho St.
Boise. 10 B3702
Deloille Deloite & Touche LLP
Suite 1700
101 South Capitol Boulevard
Boise, 1083702-7734
USA
Tel: [phone]
Fax: [phone]
ww.deloitte.com
,j Q. \ 4
1 ?'''\ U'')(\('0 ¡',vR \ \Ludu n' .
INDEPENDENT AUDITORS' REPORT
Idaho Power Company
, Boise, Idaho
We have audited the balance sheet-regulatory basis ofIdaho Power Company (the "Company") as of
Decembe 31, 2007, and the related statements of income-regulatory basis; retained earings-
regulatory basis; cash flows-regulator basis, and accumulated comprehensive income, comprehensive
income, and hedging activities-regulatory basis for the year ended December 31, 2007, included on
pages 1 10 through 123 of the accompanying Federl Energy Regulatory Commission Form 1. These
financial statements are the responsibility of the Company's maagement. Our responsibility is to express
an opinion on these financial statements based on our audit.
We conducted our audit in accordace with auditing stadards generlly accepted in the United States of
Amerca. Those standads require that we plan and perorm the audit to obtain reasonable assurnce
about whether the financial statements are free of materal misstatement. An audit includes considertion
of interal control over financial reprtng as a basis for designing audit procedures tht are approprate
in the circumtances, but not for the purose of expressing an opinion on the effectiveness of the
Company's interal control over financial reporting. Accordingly, we express no such opinion. An audit
also includes examining, on a test basis, evidence supportng the amunts and disclosures in the financial
statements, assessing the accounting prnciples used and significant estimates made by maagement, as
well as evaluatig the overll financial sttement presentation. We believe tht our audit provides a
reasonable basis for our opinion.
As discussed in Note 1, these financial stateents were prepared in accordance with the accounting
requirements of the Federl Energy Regulatory Commssion as set fort in its applicable Uniform System
of Accounts and published accountig releases, which is a comprehensive basis of accounting other than
accounting prnciples generally accepted in the United States of Amerca.
In our opinion, such regulatory-basis financial statements present fairly, in all materal respects, the
assets, liabilities, and proprietary capital of Idaho Power Company as of December 31, 2007, and the
results of its operations and its cash flows for the year ended December 31, 2007, in accordance with the
accounting requirements of the Federl Energy Regulatory Commission as set forth in its applicable
Uniform System of Accounts and published accounting releases.
Ths reprt is intended solely for the informtion and use of the board of directors and maagement of
Idaho Power Company and for fiing with the Federal Energy Regulatory Commssion and is not
intended to be and should not be used by anyone other than these specified pares.
b~+T~ Lt.1'
. Febru 27,2008
Member of
Deloitte Touce Tohmatsu
INSTRUCTIONS FOR FILING FERC FORM NOS. 1 and 3-Q
GENERAL INFORMATION
I.Purpose
FERC Form No. 1 (FERC Form 1) is an annual regulatory requirement for Major electric utilties, licensees and others
(18 C.F.R. § 141.1). FERC Form No. 3-Q( FERC Form 3-Q)is a quarterly regulatory requirement which supplements the
annual financial reporting requirement (18 C.F.R. § 141.400). These reports are designed to collect financial and
operational information from electric utilties, licensees and others subject to the jurisdiction of the Federal Energy
Regulatory Commission. These reports are also considered to be non-onfidential public use forms.
II. Who Must Submit
Each Major electric utilty, licensee, or other, as classified in the Commission's Uniform System of Accounts
Prescribed for Public Utilities and Licensees Subject To the Provisions of The Federal Power Act (18 C.F.R. Part 101),
must submit FERC Form 1 (18 C.F.R. § 141.1), and FERC Form 3-Q (18 C.F.R. § 141.400).
Note: Major means having, in each of the three previous calendar years, sales or transmission service that
exceeds one of the following:
(1) one millon 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).
II. What and Where to Submit
(a) Submit FERC Forms 1 and 3-Q electronically through the forms submission softare. Retain one copy of each report
for your files. Any electronic submission must be created by using the forms submission software provided free by the
Commission at its web site: http://ww.ferc.gov/docs-filng/eforms/form-1/elec-subm-soft.asp. The software is
used to submit the electronic filing to the Commission via the Internet.
(b) The Corporate Officer Certification must be submitted electronically as part of the FERC Forms 1 and 3-Q filngs.
(c) Submit immediately upon publication, by either eFiling or mail, two (2) copies to the Secretary of the Commission, the
latest Annual Report to Stockholders. Unless eFilng the Annual Report to Stockholders, mail the stockholders report to
the Secretary of the Commission at:
Secretary
Federal Energy Regulatory Commission
888 First Street, NE
Washington, DC 20426
(d) For the CPA Certifcation Statement, submit within 30 days after filng the FERC Form 1, a letter or report (not
applicable to filers classified as Class C or Class D prior to January 1, 1984). The CPA Certification Statement can be
either eFiled or mailed to the Secretary of the Commission at the address above.
FERC FORM 1 & 3-Q (ED. 03-07)
The CPA Certification Statement should:
a) Attest to the conformity, in all material aspects, of the below listed (schedules and pages) with the
Commission's applicable Uniform System of Accounts (including applicable notes relating thereto and the
Chief Accountant's published accounting releases), and
b) Be signed by independent certified public accountants or an independent licensed public accountant
certified or licensed by a regulatory authority of a State or other political subdivision of the U. S. (See 18
C.F.R. §§ 41.10-41.12 for specific qualifications.)
Reference Schedules Pages
Comparative Balance Sheet
Statement of Income
Statement of Retained Earnings
Statement of Cash Flows
Notes to Financial Statements
110-113
114-117
118-119
120-121
122-123
e) The following format must be used for the CPA Certification Statement unless unusual circumstances or conditions,
explained in the letter or report, demand that it be varied. Insert parenthetical phrases only when exceptions are
reported.
.In connection with our regular examination of the financial statements of _ for the year ended on which we have
reported separately under date of , we have also reviewed schedules
of FERC Form NO.1 for the year filed with the Federal Energy Regulatory Commission, for
conformity in all material respects with the requirements of the Federal Energy Regulatory Commission as set forth in its
applicable Uniform System of Accounts and published accounting releases. Our review for this purpose included such
tests of the accounting records and such other auditing procedures as we considered necessary in the circumstances.
Based on our review, in our opinion the accompanying schedules identifed 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 Accunts and published accounting releases."
The letter or report must state which, if any, of the pages above do not conform to the Commission's requirements.
Describe the discrepancies that exist.
(f) Filers are encouraged to file their Annual Report to Stockholders, and the CPA Certification Statement using eFitng.
To further that effort, new selections, "Annual Report to Stockholders," and .CPA Certifcation Statement" have been
added to the dropdown .pick list" from which companies must choose when eFitng. Further instructions are found on the
Commission's website at http://ww.ferc.gov/help/how-to.asp.
(g) Federal, State and Local Governments and other authorized users may obtain additional blank copies of
FERC Form 1 and 3-0 free of charge from http://ww.ferc.gov/docs-filng/eforms/form-1/form-1.pdf and
http://ww.ferc.gov/docs-filng/eforms.asP#3Q-gas .
IV. When to Submit:
FERC Forms 1 and 3-0 must be filed by the following schedule:
FERC FORM 1 & 3-Q (ED. 03-07)ii
a) FERC Form 1 for each year ending December 31 must be filed by April 18th of the following year (18 CFR § 141.1), and
b) FERC Form 3-0 for each calendar quarter must be filed within 60 days after the reporting quarter (18 C.F.R. §
141.400).
V. Where to Send Comments on Public Reporting Burden.
The public reporting burden for the FERC Form 1 collection of information is estimated to average 1,144
hours per response, including the time for reviewing instructions, searching existing data sources, gathering and
maintaining the data-needed, and completing and reviewing the collection of information. The public reporting burden for
the FERC Form 3-Q collection of information is estimated to average 150 hours per response.
Send comments regarding these burden estimates or any aspect of these collections of information, including
suggestions for reducing burden, to the Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC
20426 (Attention: Information Clearance Offcer); and to the Ofice of Information and Regulatory Affairs, Office of
Management and Budget, Washington, DC 20503 (Attention: Desk Offcer for the Federal Energy Regulatory
Commission). No person shall be subject to any penalty if any collection of information does not display a valid control
number (44 U.S.C. § 3512 (a)).
FERC FORM 1 & 3-Q (ED. 03-07)ii
GENERAL INSTRUCTIONS
i. Prepare this report in conformity with the Uniform System of Accounts (18 CFR Part 101) (USofA). Interpret
all accounting words and phrases in accordance with the USofA.
II. Enter in whole numbers (dollars or MWH) only, except where otherwise noted. (Enter cents for averages and
figures per unit where cents are important. The truncating of cents is allowed except on the four basic financial statements
where rounding is required.) The amounts shown on all supporting pages must agree with the amounts entered on the
statements that they support. When applying thresholds to determine signifcance for reporting purposes, use for balance
sheet accounts the balances at the end of the current reporting period, and use for statement of income accounts the
current year's year to date amounts.
li Complete each question fully and accurately, even if it has been answered in a previous report. Enter the
word "None" where it truly and completely states the fact.
iv. For any page(s) that is not applicable to the respondent, omit the page(s) and enter "NA," "NONE," or "Not
Applicable" in column (d) on the List of Schedules, pages 2 and 3.
V. Enter the month, day, and year for all dates. Use customary abbreviations. The "Date of Report" included in the
header of each page is to be completed only for resubmissions (see vii. below).
Vi. Generally, except for certain schedules, all numbers, whether they are expected to be debits or credits, must
be reported as positive. Numbers having a sign that is different from the expected sign must be reported by enclosing the
numbers in parentheses.
VII For any resubmissions, submit the electronic filing using the form submission softare only. Please explain
the reason for the resubmission in a footnote to the data field.
Vti. Do not make references to reports of previous periods/years or to other reports in lieu of required entries,
except as specifcally authorized.
IX. Wherever (schedule) pages refer to figures from a previous period/year, the figures reported must be based
upon those shown by the report of the previous period/year, or an appropriate explanation given as to why the diferent
figures were used.
Definitions for statistical classifications used for completing schedules for transmission system reporting are as follows:
FNS - Firm Netwrk Transmission Service for Self. "Firm" means service that can not be interrupted for economic reasons
and is intended to remain reliable even under adverse conditions. "Network Service" is Network Transmission Service as
described in Order No. 888 and the Open Access Transmission Tarif. "Self' means the respondent.
FNO - Firm Network Service for Others. "Firm" means that service cannot be interrupted for economic reasons and is
intended to remain reliable even under adverse conditions. "Network Service" is Network Transmission Service as
described in Order No. 888 and the Open Access Transmission Tariff.
LFP - for Long-Term Firm Point-to-Point Transmission Reservations. "Long-Term" means one year or longer and" firm"
means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse
conditions. "Point-to-Point Transmission Reservations" are described in Order No. 888 and the Open Access
Transmission Tariff. For all transactions identified as LFP, provide in a footnote the
FERC FORM 1 & 3-Q (ED. 03-07)iv
termination date of the contract defined as the earliest date either buyer or seller can unilaterally cancel the contract.
OlF - Other long-Term Firm Transmission Service. Report service provided under contracts which do not conform to the
terms of the Open Access Transmission Tarif. "long-Term" means one year or longer and "firm" means that service
cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. For all
transactions identified as OlF, provide in a footnote the termination date of the contract defined as the earliest date either
buyer or seller can unilaterally get out of the contract.
SFP - Short-Term Firm Point-to-Point Transmission Reservations. Use this classification for all firm point-to-point
transmission reservations, where the duration of each period of reservation is less than one-year.
NF - Non-Firm Transmission Service, where firm means that service cannot be interrupted for economic reasons and is
intended to remain reliable even under adverse conditions.
OS - Other Transmission Service. Use this classification only for those services which can not be placed in the
above-mentioned classifcations, such as all other service regardless of the length of the contract and service FERC Form.
Describe the type of service in a footnote for each entry.
AD - Out-of-Period Adjustments. Use this code for any accounting adjustments or "true-ups" for service provided in prior
reporting periods. Provide an explanation in a footnote for each adjustment.
DEFTNITIÕNS------~- . .---------
l. Commission Authorization (Comm. Auth.) - The authorization of the Federal Energy Regulatory Commission, or any
ther Commission. Name the commission whose authorization was obtained and give date of the authorization.
ehalf the report is made.
--,.__.. . ~...__......_-,,-,..._.-_-_.,----~--------- .~--.,,--._-_._--_._---_._,---_..__...'---,.._,,-.._--. . _.~-_.-
FERC FORM 1 & 3-Q (ED. 03-07)v
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 with:
(3) 'Corporation' means any corporation, joint-stock company, partnership, association, business trust,
organized group of persons, whether incorporated or not, or a receiver or receivers, trustee or trustees of any of the
foregoing. It shall not include 'municipalities, as hereinafter defined;
(4) 'Person' means an individual or a corporation;
(5) 'Licensee, means any person, State, or municipality Licensed under the provisions of section 4 of this Act,
and any assignee or successor in interest thereof;
(7) 'municipality means a city, county, irrigation district, drainage district, or other political subdivision or
agency of a State competent under the Laws thereof to carr and the business of developing, transmitting, unitizing, or
distributing power; ......
(11) "project' means. a complete unit of improvement or development, consisting of a power house, all water
conduits, all dams and appurtenant works and structures (including navigation structures) which are a part of said unit, and
all storage, diverting, or fore bay reservoirs directly connected therewith, the primary line or lines transmitting power there
from to the point of junction with the distribution system or with the interconnected primary transmission system, all
miscellaneous structures used and useful in connection with said unit or any part thereof, and all water rights,
rights..f-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 develope, 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 utilty shall file with the Commission such annual and other periodic or
special* reports as the Commission may be rules and regulations or other prescribe as necessary or appropriate to assist
the Commission in the -proper administration of this Act. The Commission may prescribe the manner and FERC Form in
which such reports salt be made, and require from such persons specific answers to all questions upon which the
Commission may need information. The Commission may require that such reports shall include, among other things, full
information as to assets and Liabilties, capitaliztion, net investment, and reduction thereof, gross receipts, interest due
and paid, depreciation, and other reserves, cost of project and other facilties, cost of maintenance and operation of the
project and other facilties, 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*.10
FERC FORM 1 & 3-Q (ED. 03-07)vi
"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 carr out the provisions of this Act. Among other
things, such rules and regulations may define accounting, technical, and trade terms used in this Act; and may prescribe
the FERC Form or FERC Forms of all statements, declarations, applications, and reports to be filed with the Commission,
the information which they shall contain, and the time within which they shall be field..."
General Penalties
The Commssion may assess up to $1 millon per day per violation of its rules and regulations. See
FPA § 3l6(a) (2005), 16 U.S.C. § 8250(a).
FERC FORM 1 & 3-Q(ED. 03-07)vii
FERC FORM NO.1/3-Q:
REPORT OF MAJOR ELECTRIC UTILITIES LICENSEES AND OTHER
IDENTIFICATION
01 Exact Legal Name of Respondent 02 Year/Penod of Report
Idaho Power Company End of 2007/04
03 Previous Name and Date of Change (if name changed during year)
1 1
04 Address of Principal Office at End of Period (Street, City, State, Zip Code)
1221 W Idaho Street, P.O. Box 70 Boise, ID 83707-0070
05 Name of Contact Person 06 Title of Contact Person
Darrel Anderson Senior VP of Admin Ser & CFO
07 Address of Contact Person (Street, City, State, Zip Code)
1221 W Idaho Street, P.O. Box 70 Boise, ID 83707-0070
08 Telephone of Contact Person,lncluding 09 This Report Is 10 Date of Report
Area Code
(1) !X An Original (2) 0 A Resubmission (Mo, Da, Yr)
[phone] 04/11/2008
ANNUAL CORPORATE OFFICER CERTIFICATION
Th undersigned officer certifies that:
I have examined this reprt and to the bet of my knwledge, information, and belief all statements of fact cotained in this rert are corrt statements
of the business affairs of the respodent and the financial statements, and other financial information contained in this report, conform in all material
repes to the Uniform System of Accounts.
01 Name 03 Signature 04 Date Signed
Darrel Anderson (Mo, Da, Yr)
02 Title
senior VP of Admin ser & CFO Darrel Anderson 0411/2008
Title 18, U.S.C. 1001 makes it a crime for any person to knowingly and wilingly to make to any Agency or Department of the United States any
false, fictitious or fraudulent statements as to any matter wiin its jurisdiction.
FERC FORM No.1/3-Q (REV. 02-04)Page 1
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) Ei A Resubmission 041112008
LIST OF SCHEDULES (Electric Utiit)
Enter in column (c) the terms .none, D .not applicable," or DNA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are Dnone," .not applicable," or DNA..
Line Title of Schedule Reference Remarks
No.Page No.
(a)(b)(c)
1 Generai Information 101
2 Control Over Respondent 102
3 Corporations Controlled by Respondent 103
4 Oficers 104
5 Directors 105
6 Importnt Changes During the Year 108-109
7 Comparative Balance Sheet 110-113
8 Statement of Income for the Year 114-117
9 Statement of Retained Earnings for the Year 118-119
10 Statement of Cash Flows 120-121
11 Notes to Financial Statements 122-123
12 Statement of Accum Comp Incme, Comp Income, and Hedging Activities 122(a)(b)
13 Summary of Utilty Plant & Accumulated Provisions for Dep, Amort & Dep 200-201
14 Nuclear Fuel Materials 202-203 None
15 Electric Plant in Service 204-207
16 ElectriC Plant Leased to Others 213 None
17 Electric Plant Held for Future Use 214
18 Construction Work in Progress-Electric 216
19 Accumulated Provision for Depreciation of Electric Utility Plant 219
20 Investment of Subsidiary Companies 224-225
21 Materials and Supplies 227
22 Allowances 228-229 None
23 Extraordinary Propert Losses 230
24 Unrecovered Plant and Regulatory Study Costs 230
25 Transmission Service and Generation Interconnecion Study Costs 231 None
26 Oter Regulatory Assets 232
27 Miscellaneous Deferred Debits 233
28 Accumulated Deferred Income Taxes 234
29 Capital Stock 250-251
30 Oter Paid-in Capital 253
31 Capital Stock Expense 254
32 Long-Term Debt 256-257
33 Recncilation of Reported Net Income with Taxble Inc for Fed Inc Tax 261
34 Taxes Accrued, Prepaid and Charged During the Year 262-263
35 Accumulated Deferred Investment Tax Credits 266-267
36 Oter Deferred Credits 269
FERC FORM NO.1 (ED. 12-96)Page 2
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) 0 A Resubmission 04/111008
L13T OF SCHEDULES (Electric Utilit) (continued)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Une Title of Schedule Reference Remarks
No.Page No.
(a)(b)(c)
37 Accumulated Deferred Incoe Taxes-Accelerated Amortization Propert 272-273
38 Accumulated Deferred Income Taxes-Other Propert 274-275
39 Accumulated Deferred Income Taxes-Other 276-277
40 Other Regulatory uabilities 278
41 Electric Operating Revenues 30301
42 Sales of Electricity by Rate Schedules 304
43 Sales for Resale 310-311
44 Electric Operation and Maintenance Expnses 320-323
45 Purchased Power 326-327
46 Transmission of Electricit for Others 328-330
47 Transmission of Electricit by ISO/RTOs 331 None
48 Transmission of Electricity by Others 332
49 Miscellaneous General Expenses-Electric 335
50 Dereciation and Amortization of Elecric Plant 336-337
51 Regulatory Commission Expnses 350-351
52 Research, Development and Demonstration Activties 352-353
53 Distribution of Salaries and Wages 354355
54 Common Utilit Plant and Expenses 356 None
55 Amounts included in ISO/RTO Settlement Statements 397 None
56 Purchase and Sale of Ancilary Services 398 None
57 Monthly Transmission System Peak Load 400
58 Monthly ISO/RTO Transmission System Peak Load 40a None
59 Electric Energy Account 401
60 Monthly Peaks and Outut 401
61 Steam Electric Generating Plant Statistics 402-403
62 Hydroeletric Generating Plant Statistics 40407
63 Pumped Storage Generating Plant Statistics 408-409
64 Generating Plant Statistic Pages 410-11
65 Transmission Line Statistics Pages 422-423
66 Transmission Lines Added During the Year 424-425
FERC FORM NO.1 (ED. 12-96)Page 3
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2007/Q4
This ~rt Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) ri A Resubmission 0411/2008
LIST OF SCHEDULES (Electric Utilty) (continued)
Enter in column (c) the terms "none," "not applicable,. or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
(a)
Reference
Page No.
(b)
426-427
450
RemarksLine
No.
Title of Schedule
(c)
67 Substations
68 Footnote Data
Stockholders' Reports Check appropriate box:
I! Four copies wil be submitted
o No annual report to stockholders is prepared
FERC FORM NO.1 (ED. 12-9)Page 4
Name of Respondent
Idaho Power Company
This Report Is:
(1) IX An Original
(2) 0 A Resubmission
Date of Report
(Mo, Da, Yr)
04/11/2008
Year/Period of Report
End of 2oo7/Q4
GENERAL INFORMATION
1. Provide name and title of officer having custody of the general corporate books of account and address of
office where the general corporate books are kept, and address of offce where any other corporate books of account
are kept, if different from that where the general corporate books are kept.
Darrel Anerson Senor Viae President of Adnistrative Serviaes and CFO, idaho Pow Cc:
1221 W. ida Street, P.O. Box 70, Boise. idao 83707-0070
2. Provide the name of the State under the laws of which respondent is incorporated, and date of incorporation.
If incorporated under a special law, give reference to such law. If not incorporated, state that fact and give the tye
of organization and the date organized.
Idah, JUe 30, 1989
3. If at any time during the year the property of respondent was held by a receiver or trustee, give (a) name of
receiver or trustee, (b) date such receiver or trustee took possession, (c) the authority by which the receivership or
trusteeship was created, and (d) date when possession by receiver or trustee ceased.
Not Apliaable
4. State the classes or utilty and other services furnished by respondent during the year in each State in which
the respondent operated.
Class of Utility ServiaeEleatria.
StateIdaoOreg
5. Have you engaged as the principal accountant to audit your financial statements an accountant who is not
the principal accountant for your previous year's certified financial statements?
(1) 0 Yes...Enter the date when such independent accountant was initially engaged:
(2) IX No
FERC FORM No.1 (ED. 12-87)PAGE 101
Name of Respondent
Idaho Power Company
This Report Is:
(1 ) IX An Original
(2) 0 A Resubmission
Date of Report
(Mo, Da, Yr)
04/11/2008
Year/Period of Report
End of 2007/Q4
CONTROL OVER RESPONDENT
1. If any corporation, business trust, or similar organization or a combination of such organizations jointly held
control over the repondent at the end of the year, state name of controllng corporation or organization, manner in
which control was held, and extent of control. If control was in a holding company organization, show the chain
of ownership or control to the main parent company or organization. If control was held by a trustee(s), state
name of trustee(s), name of beneficiary or beneficiearies for whom trust was maintained, and purpose of the trust.
Idaho Power Company is a subsidiary of IDACORP, INC
IDACORP owns 100% of Idaho Power Company's Common Stock.
IDACORP is a public utilty Holding Company incorporated effective 10-1-1998
FERC FORM NO.1 (ED. 12-9)Pag 102
Name of Respondent This~rtIS:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) Ei A Resubmission 0411/2008
C )RPORA TIONS CONTROLLED BY R SPONDENT
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. Indirec 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 part holds a veto power over the other. Joint control may exist by
mutual agreement or understanding between two or more parties who together have control within the meaning of the definition of
control in the Uniform System of Accounts, regardless of the relative voting rights of each party.
Line Name of Company Controlled Kind of Business Percent Voting Footnoe
No.Stock Owed Ref.
(a)(b)(c)(d)
1 Direct Control
2 Idaho Energy Resources Company Coal mining and mineral 100%
3 development
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. 12-9)Page 103
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) Fi A Resubmission 04/11/2008
OFFICERS
1.Report below the name, title and salary for each executive officer whose salary is $50,000 or more. An "executive officer" of a
respondent includes its president, secretary, treasurer, and vice president in charge of a principal business unit, division or function
(such as sales, administration or finance), and any other person who performs similar policy making functions.
2.If a change was made during the year in the incumbent of any position, show name and total remuneration of the previous
incumbent, and the date the change in incumbency was made.
Line iitie Name or Utticer . ~ai.ary
No.
for Year
(a)(b)(c)
1
2 President and Chief Executive Officer J. LaMont Keen 500,000
3
4 Sr Vice President, Administrative Services & CFO Darrel T. Anderson 310,000
5
6 Sr Vice President, Power Supply James C. Miller 295,000
7
8 Sr Vice President, General Counsel and Secretary Thomas Said in 285,000
9
10 Sr Vice President, Delivery Dan Minor 270,000
11
12 Vice President, Regulatory Affairs Ric Gale 220,000
13
14 Vice President and Chief Information Oficer Dennis Gribble 188,000
15
16 Vice President, Human Resources Luci McDonald 190,000
17
18 Vice President, Public Affairs Greg Panter 195,000
19
20 Vice President and Treasurer Steven R. Keen 210,000
21
22 Vice President and Chief Risk Oficer Lori Smith 185,000
23
24 Vice President, Engineering and Operations Lisa Grow 165,000
25
26 Vice President, Customer Service and Regional Ops Warren Kline 165,000
27
28 Vice President, Audit and Compliance Naomi Crafton.Shankel 142,000
29
30 Corporate Secretary Patrick Harrington 155,000
31
32
33
34
35
36
37
38
39
40
41
42
43
44
n.._.. ..nll
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) 0 A Resubmission 0411/2008
DIRECTORS
1. Report below the information called for concerning each direcor 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 Exective Committee by a doble asterisk.
LNg Name (anø .ritie) or uirector principai tjusiness Aooress
(a)(b)
1 Rotchford L. Barker (1)P.O. Box 2080, COdy, Wyoming 82414
2
3 Judith A Johansen 2786 Glenmorrie Dr. Lake Oswego, Oregon 97034
4
5 Christine King AMI Semiconductor, Inc.
6 2300 Buckskin Rd MIS #3, Pocatello,Idaho 83201
7
8 Gary Michael '"P.O. Box 1718, Boise, Idaho 83701
9
10 Jon H. Miler '"P.O. Box 1557, Boise, Idaho 83701
11
12 Peter S. O'Neil '*'100 N. 9t St., Suite 200, Boise, Idaho 83702
13
14 Jan B. Packwd 90 W. Bogus View Drive, Eagle, Idaho 83616
15
16 J. laMont Keen, President and Chief Executive Oficer*'Idaho Power Company, 1221 W. Idaho Street,
17 P.O. Box 70, Boise, Idaho 83707.0070
18
19 Richard G. Reiten Pacwest center, 1211 SW Fift Ave., Suite 1600
20 Portland, Orego 97204
21
22 Joan Smith 2309 S.W. First Avenue, No. 1141, Portand, Oregon 97201
23
24 Robert A. Tinstman '"443 W. Quail Point Court, Boise, Idaho 83703
25
26 Thomas Wilford Alscott Inc, P.O. Box 70001, Bose, Idaho 83701
27
28
29 (1) Retired in May 17, 2007.
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
FERC FORM NO.1 (ED. 12-95)Page 105
Name of Respondent
Idaho Power Company
This Report Is:
(1) (2 An Original
(2) 0 A Resubmission
1M ORTANT CHANGES DURING THE QUARTERNEAR
Date of Report Year/Period of Report
End of 2007/Q404/11/2008
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 liabilties 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
part or in which any such person had a material interest.
11. (Reserved.)
12. If the important changes during the year relating to the respondent company appearing in the annual report to stockholders are
applicable in every respect and furnish the data required by Instructions 1 to 11 above, such notes may be included on this page.
13. Describe fully any changes in officers, directors, major security holders and voting powers of the respondent that may have
occurred during the reporting period.
14. In the event that the respondent participates in a cash management program(s) and its proprietary capital ratio is less than 30
percent please describe the significant events or transactions causing the proprietary capital ratio to be less than 30 percent, and the
extent to which the respondent has amounts loaned or money advanced to its parent, subsidiary, or affilated companies through a
cash management program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio.
PAGE 108 INTENTIONALLY LEFT BLANK
SEE PAGE 109 FOR REQUIRED INFORMATION.
FERC FORM NO.1 (ED. 12-96)Page 108
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 0411112008 2007/04
IMPORTANT CHANGES DURING THE OUARTERNEAR (Continued)
1. Relicensing costs closed to account 302 - $60,000 to Shoshone Bannock Tribe for
distribution line right-of-way - Idaho.
2. None
3. None
4. None
5. New Transmission Lines:
Borah to Hunt
Horse Flat to McCall 1
Bennet t Mtn to Danskin
230Kv 68.24 miles
38Kv 34.56 milesPower 230Kv 5.51 miles
Additions to Existing Lines:
Taps added to Spring Valley, Cartwright and Hidden Spring Substations 138Kv 9.69miles.
Distribution Stations:
Spring Valley Substation
Starkey Substation
138Kv
138/69Kv
6. On June 22,2007, IPC issued $140 million of its 6.30% First Mortgage Bonds, Secured
Medium-Term Notes, Series F, due June 15,2037. IPC used the pet proceeds to pay down
outstanding commercial paper, which had increased to $164 million in June 2007 because of
increased capital expenditures. Commission Authorization IPUC IPC-E-07-06, OPUC UF4238 and
WPSC 2005-30-ES-7.
On October 18,2007, IPC issued $100 million of its 6.25% First Mortgage Bonds, Secured
Medium-Term Notes, Series G, due October 15,2037. IPC used the net proceeds to retire $80
million of 7.38% First Mortgage Bonds due December 1,2007, and paid down outstanding
commericial paper. Commission Authorization IPUC IPC-E-06-28, OPUC UF 4211 and WPSC
20005~ES-4-27 .
7.None
8. On December 29, 2007 a general wage increase of 3. 25% .
9. See Pages 123.15 to 123.20
10.None
11.None
12.None
13.Refer to pages 104 & 105 for changes in officers and directors. There were a numer of
changes in Major Security Holders in 2006. The top ten institutional shareholders list saw
one change from 3rd quarter to 4th quarter. In the 4th quarter Thales Fund Management
replaced Brandwine Global Investment Mgmt on the top ten list.
14. Idaho Power and its unregulated parent, IDACORP, have seperate cash management
programs. (Seperate bank accounts, liquidity facilities, short-term debt and investment
programs). No money has been loaned or advanced from Idaho Power to IDACORP through a cash
management program.
IFERC FORM NO.1 (ED. 12-96) Page 109.1
Name of Respondent This Report Is: Date of Report Year/Period of Report
(1) 1: An Original (Mo, Da, Yr)
(2) 0 A Resubmission 0411/2008 End of 2007/04
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Idaho Power Company
Line
No.Title of Accunt
(a)
UTILITY PLAT
Ref.
Page No.
(b)
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
47
48
49
50
51
52
200-201
200-201
Utilty Plant (101-106, 114)
Construction Work in Progress (107)
TOTAL Utiity Plant (Enter Total of lines 2 and 3)
(Less) Accum. Provo for Depr. Amort. Depl. (108, 110, 111, 115)
Net Utilty Plant (Enter Total of line 4 less 5)
Nuclear Fuel in Process of Ref., Conv.,Enrich., and Fab. (120.1)
Nuclear Fuel Materials and Assemblies-Stock Account (120.2)
Nuclear Fuel Assemblies in Reactor (120.3)
Spent Nuclear Fuel (120.4)
Nuclear Fuel Under Capital Leases (120.6)
(Less) AcculT. Provo for Amort. of Nucl. Fuel Assemblies (120.5)
Net Nuclear Fuel (Enter Total of lines 7-11 less 12)
Net Utilty Plant (Enter Total of lines 6 and 13)
Utilty Plant Adjustments (116)
Gas Stored Underground - Noncurrent (117)
OTHER PROPERTY AND INVESTMENTS
Nonutilit Propert (121)
(Less) Accum. Provo for Depr. and Amort. (122)
Investments in Associated Companies (123)
Investment in Subsidiary Companies (123.1)
(For Cost of Account 123.1, See Footnote Page 224, line 42)
Noncurrent Portion of Allowances
Oter Investments (124)
Sinking Funds (125)
Depreciation Fund (126)
Amortization Fund - Federal (127)
Other Special Funds (128)
Special Funds (Non Major Only) (129)
Long-Term Portion of Derivative Assets (175)
Long-Term Portion of Derivative Assets - Hedges (176)
TOTAL Other Propert and Investments (Lines 18-21 and 23-31)
CURRENT AND ACCRUED ASSET
Cash and Working Funds (Non-major Only) (130)
Cash (131)
Speial Deposits (132-134)
Working Fund (135)
Temporary Cash Investments (136)
Notes Receivable (141)
Customer Accounts Receivable (142)
Other Accounts Receivable (143)
(Less) Accum. Provo for Uncollectible Acct.-Credit (144)
Notes Receivable from Associated Companies (145)
Accounts Receivable from Assoc. Copanies (146)
Fuel Stock (151)
Fuel Stock Expenses Undistributed (152)
Residuals (Elec) and Extracted Products (153)
Plant Materials and Operating Supplies (154)
Merchandise (155)
Other Materials and Supplies (156)
Nuclear Materials Held for Sale (157)
Allowances (158.1 and 158.2)
200201
202-203
202-203
122
224-225
228-229
227
227
227
227
227
227
202-2031227
228-229
Current Year
End of OuarterNear
Balance
(c)
3,799,704,78
257,589,90
4,057,294,689
1,468,831,768
2,588,462,921
Prior Year
End Balance
12/31
(d)
3,586,503,680
210,094,019
3,796,597,699
1,406,209,952
2,390,387,747
o
o
o
o
o
o
o
2,390,387,747
o
o
888,87
--- - --~---~~~-- ---
55,937,107
976,937
o
o
51,914,196- --~ ---- -- - ~-- - -
2,908,31
44,840,
35,85
2,403,00
5,975,46
62,122,20
7,080,171
1,305,058
21,527,62
o
3,696
o
o
o
28,039,959
o
o
o
80,934,788
o
1,189,450
510,000
57,850
1,157,000
6,717,530
54,218,159
10,081,728
968,073
9,154,480
o
15,173,831
o
o
36,762,206
o
o
o
o
FERC FORM NO.1 (REV. 12-03)Page 110
Name of Respondent This Report Is:Date of Report Year/Period of Report
Idaho Power Company (1 )(Z An Original (Mo,Da, Yr)
(2)0 A Resubmission 04/11/008 End of 2007/04
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)Continued)
Line Current Year Prior Year
No.Ref.End of OuarterlYear End Balance
Title of Account Page No.Balance 12/31
(a)(b)(c)(d)
53 (Less) Noncurrent Portion of Allowances 0 0
54 Stores Exense Undistributed (163)227 1,898,952 2,316,011
55 Gas Stored Underground - Current (164.1)0 0
56 Liqueied Natural Gas Stored and Held for Processing (164.2-164.3)0 0
57 Prepayments (165)9,119,846 8,952,014
58 Advances for Gas (166-167)0 0
59 Interest and Dividends Receivable (171)611 0
60 Rents Receivable (172)0 0
61 Accrued Utilit Revenues (173)36,314,344 31,365,181
62 Miscellaneous Current and Accru Assets (174)0 0
63 Derivative Instrument Assets (175)586,202 0
64 (Less) Log-Term Portion of Derivative Instrument Assets (175)33,160 0
65 Derivative Instrument Assets - Hedges (176)0 0
66 (Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176 0 0
67 Total Current and Accrued Assets (Lines 34 through 66)252,113,29 176,687,367
68 DEFERRED DEBITS
69 Unamortized Debt Exenses (181)13,390,497 9,786,33
70 Extraordinary Propert Losses (182.1)230 0 0
71 Unrecovered Plant and Regulatory Study Costs (182.2)230 0 0
72 Other Regulatory Assets (182.3)232 448,227,917 378,846,883
73 Prelim. Survey and Investigation Charges (Electric) (183)454,15:3 416,116
74 Preliminary Natural Gas Survey and Investigation Charges 183.1)0 0
75 Other Preliminary Survey and Investigation Charges (183.2)0 0
76 Clearing Accounts (184)480,899 361,477
77 Temporary Facilties (185)0 0
78 Miscellaneous Deferred Debits (186)233 73,222,18:3 124,388,934
79 Def. Losses from Dispoition of Utilty PIt. (187)0 0
80 Research, Devel. and Demonstration Exend. (188)352-353 36,000 0
81 Unamortized Loss on Reaquired Debt (189)13,548,821 14,760,653
82 Accumulated Deferred Income Taxes (190)234 106,047,151 117,138,886
83 Unrecvered Purchased Gas Costs (191)0 0
84 Total Deferred Debit (lines 69 through 83)655,407,621 645,699,285
85 TOTAL ASSETS (lines 14-16, 32, 67, and 84)3,580,919,553 3,293,709,187
FERC FORM NO.1 (REV. 12-03)Page 111
Name of Respondent This Report is:Date of Report Year/Period of Report
Idaho Power Company (1 )IX An Original (mo, da, yr)
(2)0 A Rresubmission 04111/2008 end of 2007/04
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
Line Current Year Prior Year
Ref.End of OuarterNear End Balance
No.Title of Account Page No.Balance 12/31
(a)(b)(c)(d)
1 PROPRIETARY CAPITAL
2 Common Stock Issued (201)250-251 97,877,030 97,877,030
3 Preferred Stock Issued (204)250-251 0 0
4 Capital Stock Subscribed (202, 205)252 0 0
5 Stock Liabilty for Conversion (203, 206)252 0 0
6 Premium on Capital Stock (207)252 581,757,435 530,757,435
7 Other Paid-In Capital (208-211)253 0 0
8 Installments Received on Capital Stock (212)252 0 0
9 (Less) Discount on Capital Stock (213)254 0 0
10 (Less) Capital Stock Expense (214)254 2,096,925 2,096,925
11 Retained Earnings (215, 215.1, 216)118-119 388,826,291 354,624,872
12 Unappropriated Undistributed Subsidiary Earnings (216.1)118-119 53,474,014 49,451,103
13 (Less) Reaquired Capital Stock (217)250-251 0 0
14 Noncorporate Proprietorship (Non-major only) (218)0 0
15 Accumulated Other Comprehensive Income (219)122(a)(b)-6,156,500 -5,737,123
16 Total Proprietary Capital (lines 2 through 15)1,113,681,345 1,024,876,392
17 LONG-TERM DEBT
18 Bonds (221)256-257 1,115,460,000 955,460,000
19 (Less) Reaquired Bonds (222)256-257 0 0
20 Advances from Associated Companies (223)256-257 0 0
21 Other Long-Term Debt (224)256-257 30,521,364 31,585,000
22 Unamortized Premium on Long-Term Debt (225)0 0
23 (Less) Unamortized Discount on Long-Term Debt-Debit (226)3,409,345 3,097,272
24 Total Long-Term Debt (lines 18 through 23)1,142,572,019 983,947,728
25 OTHER NONCURRENT LIABILITIES
26 Obligations Under Capital Leases - Noncurrent (227)0 0
27 Accumulated Provision for Property Insurance (228.1)0 0
28 Accumulated Provision for Injuries and Damages (228.2)660,554 665,706
29 Accumulated Provision for Pensions and Benefits (228.3)81,470,279 78,643,708
30 Accumulated Miscellaneous Operating Provisions (228.4)916,667 0
31 Accumulated Provision for Rate Refunds (229)2,397,165 1,227,492
32 Long-Term Portion of Derivative Instrument Liabilties 0 0
33 Long-Term Portion of Derivative Instrument Liabilities. Hedges 0 0
34 Asset Retirement Obligations (230)14,514,992 12,911,220
35 Total Other Noncurrent Liabilties (lines 26 through 34)99,959,657 93,448,126
36 CURRENT AND ACCRUED LIABILITIES
37 Notes Payable (231)136,585,000 52,200,001
38 Accounts Payable (232)81,922,232 83,697,801
39 Notes Payable to Associated Companies (233)0 0
40 Accounts Payable to Associated Companies (234)724,321 1,110,966
41 Customer Deposits (235)1,159,232 1,125,192
42 Taxes Accrued (236)262-263 2,845,258 40,225,757
43 Interest Accrued (237)18,761,346 12,324,003
44 Dividends Declared (238)0 0
45 Matured Long-Term Debt (239)0 0
I:I:Rr. I:ORM NO 1 IrAv 1 ?-o:n Pace 112
Name of Respondent This Report is:Date of Report Vear/Period of Report
Idaho Power Company (1 )~An Original (mo, da, yr)
(2) 0 A Rresubmission 04/11/2008 end of 2007/Q4
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITß)tinued)
Line Current Year Prior Year
No.Ref.End of QuarterNear End Balance
Title of Account Page No.Balance 12/31
(a)(b)(c)(d)
46 Matured Interest (240)0 0
47 Tax Collections Payable (241)2,534,420 2,015,825
48 Miscellaneous Current and Accrued Liabilties (242)59,832,828 19,404,370
49 Obligations Under Capital Leases-Current (243)0 0
50 Derivative Instrument Liabilties (244)171,234 1,462,637
51 (Less) Long-Term Portion of Derivative Instrument Liabilities 0 0
52 Derivative Instrument Liabilties - Hedges (245)0 0
53 (Less) Long-Term Portion of Derivative Instrument Liabilties-Hedges 0 0
54 Total Current and Accrued Liabilities (lines 37 through 53)304,535,871 213,566,552
55 DEFERRED CREDITS .
56 Customer Advances for Construction (252)33,261,676 26,085,511
57 Accumulated Deferred Investment Tax Credits (255)266-267 71,000,710 69,113,142
58 Deferred Gains from Disposition of Utilty Plant (256)0 0
59 Other Deferred Credits (253)269 20,838,443 50,242,704
60 Other Regulatory Liabilties (254)278 203,756,794 225,731,042
61 Unamortized Gain on Reaquired Debt (257)0 0
62 Accum. Deferred Income Taxes-Accel. Amort.(281)272-277 0 0
63 Accum. Deferred InCome Taxes-Other Propert (282)535,627,552 573,951,058
64 Accum. Deferred Income Taxes-Other (283)55,685,486 32,746,932
65 Total Deferred Credits (lines 56 through 64)920,170,661 977,870,389
66 TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65)3,580,919,553 3,293,709,187
~
i:i:I::l(~ i:nRM i\n 1 frAU 1?-n~\Paae 113
Name of Respondent This ~rtIS:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/04
(2) FiA Resubmission 04/11/2008
STATEMENT OF INCOME
Ouarterly
1. Enter in column (d) the balance for the reporting quarter and in column (e) the balance for the same three month period for the prior year.
2. Report in column (f) the quarter to date amounts for electric utilty function; in column (h) the quarter to date amounts for gas utiity, and in ü) the
quarter to date amounts for other utility function for the current year quarter.
3. Report in column (g) the quarter to date amounts for electric utility function; in column (i) the quarter to date amounts for gas utilty, and in (k) the
quarter to date amounts for other utilty function for the prior year quarter.
4. If additional columns are needed place them in a footnote.
Annual or Quarterly if applicable
5. Do not report fourth quarter data in columns (e) and (f)
6. Report amounts for accounts 412 and 413, Revenues and Expenses from Utilty Plant Leased to Others, in another utility columnin a similar manner to
a utility department. Spread the amount(s) over lines 2 thru 26 as appropriate. Include these amounts in columns (c) and (d) totals.
7. Report amounts in account 414, Other Utilty Operating Income, in the same manner as accounts 412 and 413 above.
8. Report data for lines 8, 10 and 11 for Natural Gas companies using accounts 404.1,404.2,404.3,407.1 and 407.2.
Line Total Total Current 3 Months Prior 3 Months
No.Current Year to Prior Year to Ended Ended
(Ret)Date Balance for Date Balance for Quarterly Only Quarterly Only
Title of Account Page No.QuarterlY ear QuartrlY ear No 4th Quarter No 4th Quarter
(a)(b)(c)(d)(e)(n
1 UTILITY OPERATING INCOME
2 Operating Revenues (400)300-301 875,401,235 930,618,611
3 Operating Expenses
4 Operation Expenses (401)320-323 532,394,837 566,729,405
5 Maintenance Expenses (402)320-323 68,163,077 64,719,689
6 Depreciation Expense (403)336-337 94,999,200 90,803,410
7 Depreciation Expense for Asset Retirement Costs (403.1)336-337
8 Amort. & Depl. of Utility Plant (404-405)336-337 8,095,753 9,089,661
9 Amort. of Utiity Plant Acq. Adj. (406)336-337 -22,723 -22,723
10 Amort. Propert Losses, Unrecov Plant and Regulatory Study Costs (407)
11 Amort. of Conversion Expenses (407)
12 Regulatory Debits (407.3)21,246 10,391,371
13 (Less) Regulatory Credits (407.4)-2,093,195
14 Taxes Other Than Income Taxes (408.1)262-263 17,633,417 18,661,413
15 Income Taxes - Federal (409.1)262-263 2,627,990 52,572,378
16 - Other (409.1)262-263 -6,572,551 5,194,257
17 Provision for Deferred Income Taxes (410.1)234, 272-277 44,230,688 -2,231,898
18 (Less) Provision for Deferred Income Taxes-Cr. (411.1)234, 272-277 9,243,213 6,646,675
19 Investment Tax Credit Adj. . Net (411.4)266 1,887,569 326,869
20 (Less) Gains from Disp. of Utility Plant (411.6)46,144
21 Losses from Disp. of Utilit Plant (411.7)
22 (Less) Gains from Disposition of Allowances (411.8)2,754,122 8,257,817
23 Losses from Disposition of Allowances (411.9)
24 Accretion Expense (411.10)
25 TOTAL Utilty Operating Expenses (Enter Total of lines 4 thru 24)753,554,363 801,283,196
26 Net Util Oper Inc (Enter Tot line 2 less 25) Carry to Pg117,line 27 121,846,872 129,335,415
""=r:,,' i:ni:,.. i\n 1/o:_n lel:\1 O?OA\Paoe 114
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2007/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/11/2008
STATEMENT OF INCOME FOR THE YEAR (Continued)
9. Use page 122 for important notes regarding the statement of income for any account thereof.
10. Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a material amount may need to be
made to the utilty's customers or which may result in material refund to the utiity with respect to power or gas purchases. State for each year effected
the gross revenues or costs to which the contingency relates and the tax effects together with an explanation of the major factors which affect the rights
of the utilty to retain such revenues or recover amounts paid with respect to power or gas purchases.
11 Give concise explanations concerning significant amounts of any refunds made or received during the year resulting from settlement of any rate
proceeding affecting revenues received or costs incurred for power or gas purches, and a summary of the adjustments made to balance sheet, income,
and expense accounts.
12. If any notes appearing in the report to stokholders are applicable to the Statement of Income, such notes may be included at page 122.
13. Enter on page 122 a concise explanation of only those changes in accounting methods made during the year which had an effect on net income,
including the basis of allocations and apportionments from those used in the preceding year. Also, give the appropriate dollar effect of such changes.
14. Explain in a footnote if the previous year's/quarter's figures are different from that reported in prior reports.
15. If the columns are insufficient for reporting additional utilty departments, supply the appropriate account titles report the informationiri a footnote to
this schedule.
ELECTRIC UTILITY
Current Year to Date Previous Year to Date
(in dollars) (in dollars)(g) (h)
GAS UTILITY
Current Year to Date Previous Year to Date
(in dollars) (in dollars)(i) OJ
Une
No.
2,754,122 8,257,817
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
8,095,753
-22,723
9,089,661
-22,723
21,246
-2,093,195
17,633,417
2,627,990
-6,572,551
44,230,688
9,243,213
1,887,569
10,391,371
18,661,413
52,572,378
5,194,257
-2,231,898
6,646,675
326,869
46,144
753,554,363
121,846,872
801,283,196
129,335,415
......,. ron".. iun .. iet' .. "_01:\PllOA 111,
This Page Intentionally Left Blank
0--=
.W
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) 0 A Resubmission 04/11/2008
STA EMENT OF INCOME FOR THE YEAR (continued)
Line TOTAL . Current ~ Montns Prior 3 Months
No.Ended Ended
(Ref.)Quarterly Only Quarterly Only
Title of Account Page No.Current Year Previous Year No 4th Quarter No 4th Quarter
(a)(b)(c)(d)(e)(f)
27 Net Utilty Operating Income (Carried forward Irom page 114)121,846,872 129,335,415
28 Other Income and Deductons
29 Other Income
30 Nonutilty Operating Income
31 Revenues From Merchandising, Jobbing and Contract Work (415)2,706,143 2,273,822
32 (Less) Costs and Exp. 01 Merchandising, Job. & Contract Work (416)2,066,936 2,001,750
33 Revenues From Nonutilty Operations (417)102,798 117,924
34 (Less) Expenses of Nonutilit Operations (417.1)-515,188 374,582
35 Nonoperating Rental Income (418)-2,553 -318
36 Equity in Earnings 01 Subsidiary Companies (418.1)119 4,022,911 9,648,253
37 Interest and Dividend Income (419)3,819,829 3,108,574
38 Allowance lor Other Funds Used During Construction (419.1)5,995,175 6,092,152
39 Miscellaneous Nonoperatig Income (421)6,514,689 5,189,612
40 Gain on Disposition 01 Propert (421.1)321,364 2,738
41 TOTAL Other Income (Enter Total 01 lines 31 thru 40)21,928,608 24,056,425
42 Other Income Deductions
43 Loss on Disposition 01 Propert (421.2)
44 Miscellaneous Amortization (425)340
45 Donations (426.1)340 478,611 573,834
46 Life Insurance (426.2)-200,209 -547,211
47 Penalties (426.3)919,811 2,307
48 Exp. lor Certain Civic, Politcal & Related Activities (426.4)886,146 1,267,336
49 Other Deductions (426.5)4,528,200 6,954,457
50 TOTAL Other Income Deductions (Total 01 lines 43 thru 49)6,612,559 8,250,723
51 Taxes Applic. to Other Income and Deductions
52 Taxes Other Than Income Taxes (408.2)262-263 35,980 35,742
53 Income Taxes-Federal (409.2)262-263 1,749,032 -4,206,660
54 Income Taxes-Other (409.2)262-263 370,373 92,071
55 Provision lor Delerred Inc. Taxes (410.2)234, 272-277 1,552,871 1,234,191
56 (Less) Provision lor Deferred Income Taxes-Cr. (411.2)234, 272-277 1,905,495 1,955,602
57 Investment Tax Credit Adj.-Net (411.5)
58 (Less) Investment Tax Credits (420)
59 TOTAL Taxes on Other Income and Deductions (Total 01 lines 52-58)1,802,761 -4,800,258
60 Net Other Income and Deductions (Total 01 lines 41, 50, 59)13,513,288 20,605,960
61 Interest Charges
62 Interest on Long-Term Debt (427)58,097,082 53,744,453
63 Amort. of Debt Dis. and Expense (428)1,081,816 1,023,500
64 Amortization of Loss on Reaquired Debt (428.1)1,211,832 1,184,936
65 (Less) Amort. 01 Premium on Debt-Credit (429)
66 (Less) Amortization 01 Gain on Reaquired Debt-Credit (429.1)
67 Interest on Debt to Assoc. Companies (430)340 83,415
68 Other Interest Expense (431)340 5,987,54 4,002,342
69 (Less) Allowance lor Borrowed Funds Used During Constructon-Cr. (432)7,597,141 4,026,460
70 Net Interest Charges (Total 01 lines 62 thru 69)58,781,135 56,012,186
71 Income Before Extraordinary Items (Total 01 lines 27, 60 and 70)76,579,025 93,929,189
72 Extraordinary Items
73 Extraordinary Income (434)
74 (Less) Extaordinary Deductions (435)
75 Net Extraordinary Items (Total of line 73 less line 74)
76 Income Taxes-Federal and Other (409.3)262-263
77 Extraordinary Items After Taxes (line 75 less line 76)
78 Net Income (Total of line 71 and 77)76,579,025 93,929,189
-_.._ .."""... .in .,~ n /rt~\, ftl)nJl\P~nA 117
Name of Respondent
Idaho Power Company
Date of Report
(Mo, Da, Yr)
04111/2008
INGS
Year/Period of Report
End of 2007/04
This ~ort Is:
(1) ~An Original
(2) A Resubmission
STATEMENT OF RETAINED EAR
1. Do not report Lines 49-53 on the quarterly version.
2. Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriated
undistributed subsidiary earnings for the year.
3. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436
- 439 inclusive). Show the contra primary account affected in column (b)
4. State the purpose and amount of each reservation or appropriation of retained earnings.
5. List firs account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow
by credit, then debit items in that order.
6. Show dividends for each class and series of capital stock.
7. Show separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Earnings.
8. Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be
recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated.
9. If any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.
Line ItemNo. (a)
UNAPPROPRIATED RETAINED EARNINGS (Account 216)
1 Balance-Beginning of Period
2 Changes
3 Adjustments to Retained Earnings (Account 439)
4
5
6
7
8
9 TOTAL Credit to Retained Earnings (Acct. 439)
10 FIN 48 Adjustment
11
12
13
14
15 TOTAL Debits to Retained Earnings (Acct. 439)
16 Balance Transferred from Income (Account 433 less Account 418.1)
17 Appropriations of Retained Eamings (Acct. 436)
18
19
20
21
22 TOTAL Appropriations of Retained Earnings (Acct. 436)
23 Dividends Declared-Preferred Stock (Account 437)
24
25
26
27
28
29 TOTAL Dividends Declared-Preferred Stock (Acc. 437)
30 Dividends Declared-Common Stock (Account 438)
31 Common Stock Dividends $2.50 Par Value
32
33
34
35
36 TOTAL Dividends Declared-Common Stock (Acct. 43)
37 Transfers from Acct 216.1, Unapprop. Undistrib. Subidiary Earnings
38 Balance - End of Period (Total 1,9,15,16,22,29,36,37)
APPROPRIATED RETAINED EARNINGS (Account 215)
Contra Primary
Account Affected
(b)
Current
OuarterlYear
Year to Date
Balance
(c)
Previous
OuarterlYear
Yearto Date
Balance
(d)
I---- ~------~~
---- ~-- r -- ~- - --- --- ---- - ----~ ~-- r ---- --~-- -- - -- -~--- -
15,135,588
----- - -- r --- ------- -- - ----- - ~ ---
15,135,588
72,556,114 84,280,936
- - - - ¡-~ - ------- --- -- - --
- -- - i - -- - --- ---
238 -53,490,283 ( 5t,109,347)
-53,490,283 51,109,347)
- - - i - -- - -- - - -- -- - - ---- - --- - -387,282,325 353,080,906
FERC FORM NO. 113 (REV. 02-()Page 118
Name of Respondent
Idaho Power Company
Year/Perio of Report
End of 2007/Q4
This ~ort Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmission 04/11/2008
STATEMENT OF RETAINED EARNINGS
1. Do not report Lines 49-53 on the quarterly version.
2. Report all changes in appropriated retained earnings, unappropnated retained earnings, year to date, and unappropriated
undistnbuted subsidiary earnings for the year.
3. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436
- 439 inclusive). Show the contra primary account affected in column (b)
4. State the purpose and amount of each reservation or appropriation of retained earnings.
5. List first account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow
by credit, then debit items in that order.
6. Show dividends for each class and senes of capital stock.
7. Show separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Earnings.
8. Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropnation is to be
recurrent, state the number and annual amounts to be reserved or appropnated as well as the totals eventually to be accumulated.
9. If any notes appeanng in the report to stockholders are applicable to this statement, include them on pages 122-123.
Current Previous
QuarterlY ear QuarterlY ear
Contra Primary Year to Date Year to Date
Line Item Account Affected Balance Balance
No.(a)(b)(c)(d)
39
40
41
42
43
44
45 TOTAL Appropriated Retained Earnings (Account 215)
APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.1)
46 TOTAL Approp. Retained Eamings-Amort. Reserve, Federal (Acct. 215.1)
47 TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46)
48 TOTAL Retained Earnings (Acct. 215, 215.1, 216) (Total 38, 47) (216.1)
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account
Report only on an Annual Basis, no Quarterly
49 Balance-Beginning of Year (Debit or Credit)
50 Equity in Earnings for Year (Credit) (Accunt 418.1)
51 (Less) Dividends Received (Debit)
52
53 Balance-End of Year (TotalUnes 49 thru 52)
- --- - T -~ - ~
-~ - r- ~- -- ~ - ----- -- - -r--- -- - -- -~ -
1,54,966
1,54,966
388,826,291
1,543,966
1,54,966
354,624,872
49,451,103
4,022,911
39,802,850
9,648,253
53,474,014 49,451,103
FERC FORM NO. 113 (REV. 02-0)Page 119
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/04
(2) n A Resubmission 04/11/2008
STATEMENT OF CASH FLOWS
(1) Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items as
investments, fixed assets, intangibles, etc.
(2) Information about noncash investing and financing activities must be provided in the Notes to the Financal statements. Also provide a recnciliation between "Cash and Cash
Equivalents at End of Period" with related amounts on the Balance Sheet.
(3) Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertining to investing and financing activities should be reported
in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid.
(4) Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilties assumed in the Notes to
the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USaf A General Instruction 20; instead provide a reconciliation of the
dollar amount of leases capitalized with the plant cost.
Line Description (See Instruction NO.1 for Explanation of Codes)Current Year to Date Previous Year to Date
No.OuarterlYear OuarterlYear
(a)(b) (c)
1 Net Cash Flow from Operating ActivitiéS:==2 Net Income (Line 78(c) on page 117)
3 Noncash Charges (Credits) to Income:
4 Depreciation' and Depletion 94,999,200 90,803,410
5 Amortization of 12,500,338 14,660,508
6
7
8 Deferred Income Taxes (Net)35,380,117 -9,599,987
9 Investment Tax Credit Adjustment (Net)1,142,301 326,869
10 Net (Increase) Decrease in Receivables -12,548,004 3,814,073
11 Net (Increase) Decrease in Inventory -6,285,284 -12,306,638
12 Net (Increase) Decrease in Allowances Inventory
13 Net Increase (Decrease) in Payables and Accrued Expenses -7,717,708 -24,376,845
14 Net (InCrease) Decrease in Other Regulatory Assets -105,234,939 40,201,156
15 Net Increase (Decrease) in Other Regulatory Liabilties -22,854,309 -57,333,724
16 (Less) Allowance for Other Funds Used During Construction 5,995,175 6,092,152
17 (Less) Undistributed Earnings from Subsidiary Companies 4,022,911 9,648,253
18 Other (provide details in footnote):29,227,514 9,988,840
19
20
21
22 Net Cash Provided by (Used in) Operating Activities (Total 2 thru 21)85,170,165 134,366,446
23
24 Cash Flows from Investment Activities:
25 Construction and Acquisition of Plant (including land):
26 Gross Additions to Utiity Plant (less nuclear fuel)-279,621,563 -217,813,466
27 Gross Additions to Nuclear Fuel
28 Gross Additions to Common Utility Plant
29 Gross Additions to Nonutilily Plant
30 (Less) Allowance for Other Funds Used During Construction 7,597,141 4,026,460
31 Other (provide details in footnote): Sale of Emiossion Allowance 19,845,542 11,322,948
32
33
34 Cash Outflows for Plant (Total of lines 26 thru 33)-267,373,162 -210,516,978
35
36 Acquisition of Other Noncurrent Assets (d)-89,507
37 Proceeds from Disposal of Noncurrent Assets (d)525,994 34,919
38
39 Investments in and Advances to Assoc. and Subsidiary Companies -12,373,146
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)-24,348,700 -17,978,726
45 Proceeds from Sales of Investment Secunties (a)26,110,459 20,777,593
....l"~rnn....in of Il:n 1~ OC\P::n.. 10)n
Name of Respondent
Idaho Power Company
This~rtls:
(1) ~ An Original
(2) A Resubmission
STATEMENT OF CASH FLOWS
Date of Report
(Mo, Da, Yr)
04/11/2008
Year/Period of Report
End of 2007/04
(1) Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items as
investments. fixed assets, intangibles, etc.
(2) Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and Cash
Equivalents at End of Period" with related amounts on the Balance Sheet.
(3) Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing activities should be reported
in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid.
(4) Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes to
the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USaf A General Instruction 20; instead provide a reconcilation of the
dollar amount of leases capitalized with the plant cost.
Line
No.
Description (See Instruction NO.1 for Explanation of Codes)
(a)
Current Year to Date
OuarterlYear
(b)
Previous Year to Date
QuarterlYear
(c)
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):
54 Refundable deposit for tax related liabilities
55
56 Net Cash Provided by (Used in) Investing Activities
57 Total of lines 34 thru 55)
58
59 Cash Flows from Financing Activities:
60 Proceeds from Issuance of:
61 Long-Term Debt (b)
62 Preferred Stock
63 Common Stock
64 Other (provide details in footnote):
65
66 Net Increase in Short-Term Debt (c)
67 Other (provide details in footnote):
68 Capital Infusion
69
70 Cash Provided by Outside Sources (Total 61 thru 69)
71
72 Payments for Retirement of:
73 Long-term Debt (b)
74 Preferred Stock
75 Common Stock
76 Other (provide details in footnote):
77
78 Net Decrease in Short-Term Debt (c)
79
80 Dividends on Preferred Stock
81 Dividends on Common Stock
82 Net Cash Provided by (Used in) Financing Activities
83 (Total of lines 70 thru 81)
84
85 Net Increase (Decrease) in Cash and Cash Equivalents
86 (Total of lines 22,57 and 83)
87
88 Cash and Cash Equivalents at Beginning of Period
89
90 Cash and Cash Equivalents at End of period
-789,874
551,536
-43,926,946
240,000,000 116,300,000
84,385,000 32,944,405
51,000,000 47,049,883
375,385,000 196,294,288
-81,063,636 -116,300,000
-883,004 -2,939,991
-53,490,283 -51,109,346
5,347,167 2,404,300
~~",. r't"rI.....n .. ien 1 "_Q~\P~nA 1?1
This Page Intentionally Left Blank
-=
:'
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/11/2008 2007/Q4
FOOTNOTE DATA
¡Schedule Page: 120 Line No.: 5Plant
Regulatory Assets
Unamortized Debt expense
Unamortized discountWater Rights
Total
¡Schedule Page: 120 Line No.: 18
Non-Cash Pension expense
Unbilled Revenue
Gain on Sale of Assets
Gain on Sale of Utility
Other Current Liabilities
Other Long-term Assets
Other Long-Term Liabilities
Total
Column:b
$ 8,073,0303,715,904
(565,131)234,527
1,042,008
$12,500,338
Column: b
$ 6,868,159(4,949,163)
(4,268,101)
(321, 364)15,750,5772,147,078
14,000,328
l
$29,227,514
Column:b
$(336,404)
(546,600)
¡Schedule Page: 120 Line No.: 76
Other Long-term assets
Other Long-term liabilities
Total
.
$ (883,004)
IFERC FORM NO.1 (ED. 12-87) Page 450.1
Name of Respondent
Idaho Power Company
Date of Report Year/Period of Report
End of 2007/04
This Report Is:
(1) ~ An Original
(2) 0 A Resubmission
NOTES TO FINANCIAL STATEMENTS
1. Use the space below for important notes regarding the Balance Sheet, Statement of Income for the year, Statement of Retained
Earnings for the year, and Statement of Cash Flows, or any account thereof. Classify the notes according to each basic statement,
providing a subheading for each statement except where a note is applicable to more than one statement.
2. Furnish particulars (details) as to any significant contingent assets or liabilties 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 utiity. Give also a brief explanation of any dividends in arrears
on cumulative preferred stock.
3. For Account 116, Utiliy Plant Adjustments, explain the origin of such amount, debits and credits during the year, and plan of
disposition contemplated, giving references to Cormmission orders or other authorizations respecting classification of amounts as plant
adjustments and requirements as to disposition thereof.
4. Where Accounts 189, Unamortized Loss on Reacquired Debt, and 257, Unamortized Gain on Reacquired Debt, are not used, give
an explanation, providing the rate treatment given these items. See General Instruction 17 of the Uniform System of Accounts.
5. Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such
restrictions.
6. If the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders are
applicable and furnish the data required by instructions above and on pages 114-121, such notes may be included herein.
7. For the 30 disclosures, respondent must provide in the notes sufficient disclosures so as to make the interim information not
misleading. Disclosures which would substantially duplicate the disclosures contained in the most recent FERC Annual Report may be
omitted.
8. For the 30 disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurred
which have a material effect on the respondent. Respondent must include in the notes significant changes since the most recently
completed year in such items as: accounting principles and practices; estimates inherent in the preparation of the financial statements;
status of long-term contracts; capitalization including significant new borrowings or modifications of existing financing agreements; and
changes resulting from business combinations or dispositions. However were material contingencies exist, the disclosure of such
matters shall be provided even though a significant change since year end may not have occurred.
9. Finally, if the notes to the financial statements relating to the respondent appearing in the annual report to the stockholders are
applicable and furnish the data required by the above instructions, such notes may be included herein.
04111/2008
PAGE 122 INTENTIONALLY LEFT BLANK
SEE PAGE 123 FOR REOUIRED INFORMATION.
.
i:i:R~ i:nRM Nn 1 lFD 12.96\Page 122
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Moi Da, Yr)
Idaho Power Company (2)A Resubmission 04/11/2008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Nature of Business
Idaho Power Company (IPC), a wholly-owned subsidiary of IDA CORP, Inc., (IDACORP) is an electric utility with a service territory
covering approximately 24,000 square miles in southern Idaho and eastern Oregon. IPC is regulated by the PERC and the state
regulatory commssions of Idaho and Oregon. IPC is the parent of Idaho Energy Resources Co., a joint venturer in Bridger Coal
Company, which supplies coal to the Jim Bridger generating plant owned in par by ipe.
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 include those related to rate regulation, benefit costs,
contingencies, litigation, asset impairment, income taxes, unbiled revenues and bad debt. These estimates and assumptions affect the
reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements,
and the reported amounts of revenues and expenses during the reporting period. These estimates involve judgments with respect to,
among other things, future economic factors that are difficult to predict and are beyond management's control. As a result, actual
results could differ from those estimates.
System of Accounts
The accounting records of IPC conform to the Uniform System of Accounts prescribed by the FERC and adopted by the public utility
commissions of Idaho, Oregon and Wyoming.
Regulation of Utilty Operations
IPC follows SFAS 71, "Accounting for the Effects of Certain Types of Regulation, " and its financial statements reflect the effects of
the different rate-making principles followed by the jurisdictions regulating ipe. The application of SFAS 71 by IPC can result in IPC
recording expenses in a period different than the period the expense would be recorded by an unregulated enterprise. When this
occurs, costs are deferred as regulatory assets on the balance sheet and recorded as expenses in the periods when those same amounts
are reflected in rates. Additionally, regulators can impose regulatory liabilities upon a regulated company for amounts previously
collected from customers and for amounts that are expected to be refunded to. customers.
IPC has a Power Cost Adjustment (PCA) mechanism that provides for annual adjustments to the rates charged to its Idaho retail
customers. These adjustments are based on forecasts of net power supply costs, which are fuel and purchased power less off-system
sales, and the true-up of the prior year's forecast. During the year, approximately 90 percent of the difference between the actual and
forecasted costs is deferred with interest. The ending balance of this deferral, called the true-up for the current year's portion and the
true-up of the true-up for the prior years' unrecovered or over-recovered portion, is then included in the calculation of the next year's
PCA.
The effects of applying SFAS 71 are discussed in more detail in Note 6 - "Regulatory Matters."
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand and highly liquid temporary investments with maturity dates at date of acquisition of
three months or less.
Derivative Financial Instruments
Financial instruments such as commodity futures, forwards, options and swaps are used to manage exposure to commodity price risk in
the electricity market. The objective of the risk management program is to mitigate the risk associated with the purchase and sale of
electricity and natural gas. The accounting for derivative financial instruments that are used to manage risk is in accordance with the
concepts established by SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," as amended.
Property, Plant and Equipment and Depreciation
The cost of utility plant in service represents the original cost of contracted services, direct labor and material, Allowance for Funds
Used During Construction (AFDC) and indirect charges for engineering, supervision and similar overhead items. Maintenance and
repairs of property and replacements and renewals of items determined to be less than units of property are expensed to operations.
Repair and maintenance costs associated with planned major maintenance are recorded as these costs are incurred. For utilty property
¡FERt FORM NO.1 (ED. 12-88)Page 123.1
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04111/2008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
replaced or renewed, the original cost plus removal cost less salvage is charged to accumulated provision for depreciation, while the
cost of related replacements and renewals is added to property, plant and equipment.
All utility plant in service is depreciated using the straight-line method at rates approved by regulatory authorities. Annual
depreciation provisions as a percent of average depreciable utility plant in service approximated 2.95 percent in 2007 and 2.75 percent
in 2006.
Long-lived assets are periodically reviewed for impairment when events or changes in circumstances indicate that the carrying amount
of an asset may not be recoverable as prescribed under SFAS 144. SFAS 144 requires that if the sum ofthe undiscounted expected
future cash flows from an asset is less than the carrying value of the asset, an impairment must be recognized in the financial
statements.
Allowance for Funds Used During Construction
AFC represents the cost of financing construction projects with borrowed funds and equity funds. While cash is not realized
currently from such allowance, it is realized under the rate-making process over the service life of the related property through
increased revenues resulting from a higher rate base and higher depreciation expense. The component of AFC 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 AFC rates for 2007 and 2006 were 6.8 percent and 7.6 percent respectively. IPC's reductions to interest
expense for AFDC were $8 iillon for 2007 and $4 milion for 2006. Other income included $6 milion and $6 milion of AFC for
2007and 2006, respectively.
Revenues
Operating revenues for IPC related to the sale of energy are generally recorded when service is rendered or energy is delivered to
customers. IPC accrues unbiled revenues for electric services delivered to customers but not yet biled at period-end. IPC collects
franchise fees and similar taxes related to energy consumption. These amounts are recorded as liabilities until paid to the taxing
authority. None of these collections are reported on the income statement as revenue or expense.
Income Taxes
IPC accounts for income taxes under the asset and liabilty method, which requires the recognition of deferred tax assets and liabilities
for the expected future tax consequences of events that have been included in the financial statements. Under this method, deferred tax
assets and liabilities are determined based on the differences between the financial statements and tax basis of assets and liabilities
using enacted tax rates in effect for the year in which the differences are expected to reverse. The effect of a change in tax rates on
deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.
Consistent with orders and directives ofthe 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 wil be recovered from or returned to customers in future rates. See Note 2 for more information.
The state of Idaho allows a three-percent investment tax credit on qualifying plant additions. Investment tax credits earned on
regulated assets are deferred and amortzed to income over the estimated service lives of the related properties. Credits earned on
non-regulated assets or investments are recognized in the year eared.
Stock. Based Compensation
Effective January 1,2006, IPC adopted SFAS No. 123 (revised 200), "Share-Based Payment" (SFAS 123(R)) using the modified
prospective application method. SFAS 123(R) changes measurement, tiiing and disclosure rules relating to share-based payments,
requiring that the fair value of all share-based payments be expensed. The adoption of SFAS 123(R) did not have a material impact on
IPC's financial statements for the year ended December 31, 2006.
IFERC FORM NO.1 (EO. 12-88)Page 123.2
Name of Respondent This Report is:Date of Report YearlPeriod of Report
(1) XAn Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/11/2008 2oo7/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Comprehensive Income
Comprehensive income includes net income, unrealized holding gains and losses on available-for-sale marketable securities and
amounts related to a deferred compensation plan for certin senior management employees and directors. The following table presents
IPC's accumulated other comprehensive loss balance at December 31 (net of tax):
Unrealized holding gains on available-for-sale securities
Deferred compensation plan
Total
$
200 200
(thousnds of dollars)568 $
(6,724)
(6,156)
1,311
(7,048)
(5,737)$$
Other Accounting Policies
Debt discount, expense and premium are deferred and being amortized over the terms of the respective debt issues.
Reclasifications
Certain items previously reported for years prior to 2007 have been reclassified to conform to the curent year's presentation. Net
income and shareholders' equity were not affected by these reclassifications.
New Accounting Pronouncements
SFAS 157: In September 200, the FASB issued SFAS 157, "Fair Value Measurements." SFAS 157 defines fair value, establishes a
framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value
measurements. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15,2007, and interim
periods within those fiscal years. IPC adopted SFAS 157 on January 1,2008, and IPC does not expect SFAS 157 to have a material
impact on its financial statements.
SFAS 159: In Februar 2007, the FASB issued SFAS No. 159, "The Fair Value Option for Financial Assets and Financial Liabilties
- Including an Amendment of FASB Statement No. 115" (SF AS 159). This standard permts an entity to choose to measure many
financial instruments and certain other items at fair value. Most of the provisions in SFAS 159 are elective; however, the amendment
to SFAS NO.1 is, "Accounting for Certain Investments in Debt and Equity Securities, " applies to all entities with available-for-sale
and trading securities. The fair value option established by SFAS 159 permits all entities to choose to measure eligible items at fair
value at specified election dates. A business entity will report unrealized gains and losses on items for which the fair value option has
been elected in earnings at each subsequent reporting date. The fair value option: (a) may be applied instrument by instrment, with a
few exceptions, such as investments otherwise accounted for by the equity method; (b) is irrevocable (unless a new election date
occurs); and (c) is applied only to entire instruments and not to portions of instruments. SFAS 159 is effective as of the beginning of
an entity's first fiscal year that begins after November 15,2007. IPC adopted SFAS 159 on January 1,2008 and did not elect the fair
value option for any existing eligible items. However, IPC wil continue to evaluate items on a case-by-case basis for consideration of
the fair value option.
SFAS 141(R): In December 2007 the FASB issued SFAS 141(R), "Business Combinations (Revised December 2007)." SFAS 141(R)
establishes principles and requirements for how an acquirer in a business combination: 1) recognizes and measures in its financial
statements the identifiable assets acquired, the liabilities assumed, and any noncontrollng interest in the acquiree; 2) recognizes and
measures the goodwil acquired in the business combination or a gain from a bargain purchase; and 3) determines what information to
disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS
141(R) applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual
reporting period beginning on or after December is, 2008. An entity may not apply it before that date. IPC is curently evaluating the
impact of SFAS 14l(R).
SFAS 160: In December 2007 the FASB issued SFAS 160, "Noncontrollng Interests in Consolidated Financial Statements." Among
other things, SFAS 160 establishes a standard for the way noncontrollng interests (also called minority interests) are presented in
consolidated financial statements and standards for accounting for changes in ownership interests. SFAS 160 is effective for fiscal
years beginning on or after December 15,2008. An entity may not apply it before that date. IPC is curently evaluating the impact of
SFAS 160.
IFERC FORM NO.1 (ED. 12-88) Page 123.3
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo. Da, Yr)
Idaho Power Company (2)A Resubmission 04111/2008 2007/04
NOTES TO FINANCIAL STATEMENTS (Continued)
FSP FIN 39.1: In April 2007 the FASB issued FASB Staff Position No. FI 39-1 (FSP FIN 39-1), "Amendment of FASB
Interpretation No. 39" (FIN 39). FSP FI 39-1 modifies FI 39, "Offsetting of Amounts Related to Certain Contracts," and permits
reporting entities to offset receivables or payables recognized upon payment or receipt of cash collateral against fair value amounts
recognized for derivative instruments that have been offset under a master netting arangement. FSP FIN 39-1 requires disclosure of a
reporting entity's accounting policy (to offset or not offset) as well as amounts recognized for the right to reclaim cash collateral, or the
obligation to return cash collateral, that have been offset against net derivative positions. FSP FIN 39-1 is effective for fiscal years
beginning after November 15,2007. IPC adopted FSP FIN 39-1 on January 1,2008 and its adoption did not have a material impact on
its financial statements.
EITF Issue No. 06.11: In June 2007, the FASB ratified Emerging Issues Task Force Issue No. 06-11, "Accounting for Income Tax
Benefits of Dividends on Share-Based Payment Awards" (EITF 06-11), which requires income tax benefits from dividends or dividend
equivalents that are charged to retained earnings and are paid to employees for equity classified awards and outstanding equity share
options to be recognized as an increase in additional paid-in capital and to be included in the pool of excess tax benefits available to
absorb potential future tax deficiencies on share-based payment awards. EITF 06-11 became effective on Januar 1, 2008. The
adoption of EITF 06-11 is not expected to have a material impact on IPC's financial statements.
2. INCOME TAXES:
The components of the net deferred tax liabilty are as follows:
A reconciliation between the statutory federal income tax rate and the effective tax rate is as follows:
2007 2006
(thousands of dollars)
38,947 $ 48,408Computed income taxes based on statutory federal income tax rate $
Change in taxes resulting from:
Equity earings of subsidiary companiesAFC
IFERC FORM NO.1 (ED.
12-S8) Page 123.4
(i,408)
(4,757)
(3,377)
(3,542)
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/11/2008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Capitalized Interest
Investment tax credits
Repair allowance
Removal Cost
Pension Accrual
Capitalized overhead costs
Tax accounting method change
Uncertain Tax Positions
Settlement of prior years tax returs
State income taxes, net of federal benefit
Depreciation
Other, Net
Total income tax expense
Effective tax rate
2,289
(3,578)
(2,450)
(3,787)
1,022
(4,200)
o
(3,346)
o
6,618
7,576
1,771
$ 34,697 $
31.2 %
1,394
(3,513)
(2,450)
(1,912)
1,902
(2,940)
6,122
o
(6,199)
7,820
5,757
(3,091)
44,379
32.1 %
The items comprising income tax expense are as follows:
2007 2006
(thousands of dollars)
Income taxes currently payable (receivable):
Federal $7,963 $48,366
State (6,202)5,286
Total 1,761 53,652
Income taxes deferred:
Federal 28,412 (9,960)
State 6,223 360
Total 34,635 (9,600)
Uncertain Tax Positions:
Federal (3,345)0
State (241)0
Total (3,586)0
Investment tax credits:
Deferred 5,465 3,840
Restored (3,578)(3,513)
Total 1,887 327
Total income tax expense $34,697 $44,379
IDACORP's tax allocation agreement provides that each member of its consolidated group compute its income taxes on a separate
company basis. Amounts payable or refundable are settled through IDACORP.
FIN 48
IPC adopted FASB Interpretation No. 48, "Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No.
109" (FIN 48) on January 1,2007, as required. IPC recorded an increase of $15.1 milion to opening retained earnings for the
cumulative effect of adopting FIN 48. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows
(in thousands of dollars):
Balance at January 1, 2007
Additions for tax positions of prior years
Reductions for tax positions of prior years
$21,180
848
(4,434)
IFERC FORM NO.1 (ED. 12-88)Page 123.5
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/11/2008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
$17,594Balance at December 31, 2007
If recognized, the $ 17.6 milion balance of unrecognized tax benefits would affect IPC's effective tax rate.
IPC is disputing the Internal Revenue Service's (IRS) disallowance of IPC's use of the simplified service cost method (SSCM) of
uniform capitalization for tax years 2001-2003. The dispute is under review with the IRS Appeals Office. In December 2007, the
Appeals Office informed IDACORP that the IRS had completed their review of IPC's SSCM settlement computations. After
evaluating the IRS review findings, IPC adjusted its measurement for the SSCM uncertain tax position which resulted in a $4.4 millon
reduction of the accrued liability for this item. IDACORP expects that the appeals process and the U.S. Congress Joint Committee on
Taxation review process wil be completed during 2008. The expected resolution would result in a decrease to IPC's unrecognized tax
benefits of $ i 3.6 milion.
IPC recognizes interest accrued related to unrecognized tax benefits as interest expense and penalties as other expense. FIN 48 allows
companies to change their accounting policy election for interest and penalties upon adoption of the standard. IPC had classified
interest as income taxes prior to the adoption of FIN 48. IPC's 2007 interest expense includes a $1 milion net reduction for interest
related to unrecognized tax benefits. The reduction was due primarily to the decrease in IPC's interest accrual for the SSCM uncertain
tax position. As of December 31,2007, IPC had accrued interest of $5.5 millon. No penalties are accrued.
IPC is subject to examination by its major tax jurisdictions - U.S. federal and state ofIdaho - for tax years 2004 through 2006. The
IRS began its examination of these years in November 2007. IPC is unable to predict the outcome of this examination.
3. COMMON STOCK AND STOCK.BASED COMPENSATION:
Dividend Restrictions: IPC's articles of incorporation contain restrictions on the payment of dividends on its common stock if
preferred stock dividends are in arrears. IPC has no outstanding preferred stock. Also, certain provisions of credit facilities contain
restrictions on the ratio of debt to total capitalization.
IPC must obtain the approval of the Oregon Public Utility Commssion (OPUC) before it could directly or indirectly loan funds or
issue notes or give credit on its books to IDACORP.
IPC Common Stock
In 2007 and 2006, IDACORP contributed $51 milion and $47 million, respectively, of additional equity to IPC. No additional shares
of IPC common stock were issued.
Stock-Based Compensation
Through its parent company, IDACORP, IPC has three share-based compensation plans. IPC's employee plans are the 2000
Long-Term Incentive and Compensation Plan (LTICP) and the 1994 Restricted Stock Plan (RSP). These plans are intended to align
employee and shareholder objectives related to IDACORP's long-term growt. IDACORP also has one non-employee plan, the
Director Stock Plan (DSP). The purpse of the DSP is to increase directors' stock ownership through stock-based compensation.
The LTlCP for officers, key employees and directors permits the grant of nonqualified stock options, incentive stock options, stock
appreciation rights, restricted stock, restricted stock units, performance units, performance shares and other awards. The RSP permits
only the grant of restricted stock or performance-based restricted stock. At December 31,2007, the maximum number of IDACORP
shares available under the LTlCP and RSP were 1,611,355 and 108,595, respectively.
The following table shows the compensation cost recognized in income and the tax benefits resulting from these plans, for those costs
associated with IPC's employees (in thousands of dollars):
Compensation cost
Income tax benefit
2007
$ 2,473
$ 967
2006
$ 1,458
$ 570
IFERC FORM NO.1 (ED. 12-88)Page 123.6
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/111008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
No equity compensation costs have been capitalized.
Stock awards: Restricted stock awards have vesting periods of up to four years. Restricted stock awards entitle the recipients to
dividends and voting rights, and unvested shares are restrcted to disposition and subject to forfeiture under certain circumstances. The
fair value of restricted stock awards is measured based on the market price of the underlying common stock on the date of grant and
charged to compensation expense over the vesting period based on the number of shares expected to vest.
Performance-based restricted stock awards have vesting periods of three years. Performance awards entitle the recipients to voting
rights, and unvested shares are restricted to disposition, subject to forfeiture under certain circumstances, and subject to meeting
specific performance conditions. Based on the attainment of the performance conditions, the ultimate award can range from zero to
150 percent of the target award. For awards granted prior to 2006, dividends were paid to recipients at the time they were paid on the
common stock. Beginning with the 2006 awards, dividends are accumulated and wil be paid out only on shares that eventually vest.
The performance goals for the 2007 awards are independent of each other and equally weighted, and are based on two metrics,
cumulative earnings per share (CEPS) and total shareholder return (TSR) relative to a peer group. The fair value of the CEPS portion
is based on the market value at the date of grant, reduced by the loss in time-value of the estimated future dividend payments, using an
expected quarterly dividend of $0.30. The fair value of the TSR portion is estimated using a statistical model that incorporates the
probability of meeting performance targets based on historical returns relative to the peer group. Both performance goals are measured
over the three-year vesting period and are charged to compensation expense over the vesting period based on the number of shares
expected to vest.
A summary of restricted stock and performance share activity is presented below.
Nonvested shares at December 31, 2006
Shares granted
Shares forfeited
Shares vested
Nonvested shares at December 31, 2007
Number of
Shares
184,296
88,519
(4,764)
(24,555)
243,496
Weighted-
Average
Grant Date
Fair Value
$ 28.32
28.94
31.09
31.6
$ 28.20
The total fair value of shares vested during the years ended December 31, 2007 and 2006 was $0.9 milion and $0.6 milion,
respecti vely. At December 31, 2007, IPC had $2.3 millon of total unrecognized compensation cost related to non vested share-based
compensation that was expected to vest. These costs are expected to be recognized over a weighted-average period of 1.64 years. IPC
uses IDACORP original issue and/or treasury shares for these awards.
Stock options: Stock option awards are granted with exercise prices equal to the market value of the stock on the date of grant. The
options have a term of 10 years from the grant date and vest over a five-year period. Upon adoption of SFAS 123(R) on January 1,
2006, the fair value of each option is amortized into compensation expense using graded-vesting. Beginning in 2006, stock options are
not a significant component of share-based compensation awards under the LTICP.
The fair values of all stock option awards have been estimated as of the date of the grant by applying a binomial option pricing modeL.
The application of this model involves assumptions that are judgmental and sensitive in the determination of compensation expense.
The following key assumptions were used in determning the fair value of options granted:
2007 2006
3.7%
18%
4.92%
Dividend yield, based on current dividend and stock price on grant date
Expected stock price volatility, based on IDACORP historical volatilty
Risk-free interest rate based on U.S. Treasury composite rate
IFERC FORM NO.1 (ED. 12-88) Page 123.7
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo. Da. Yr)
Idaho Power Company (2)A Resubmission 04/11/2008 2007/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Expected term based on the SEC "simplified" method 6.50 years
The following table presents information about options granted and exercised (in thousands of dollars, except for weighted-average
amounts):
Weighted-average grant-date fair value
Fair value of options vested
Intrinsic value of options exercised
Cash received from exercises
Tax benefits realized from exercises
$
2007 2006
$
579
11
40
4
1,275
2,883
9,614
1,127
As of December 31, 2007, there was $0.1 million of total unrecognized compensation cost related to stock options. These costs are
expected to be recognized over a weighted average period of 0.8 years. IPC uses IDACORP original issue and/or treasury shares to
satisfy exercised options.
IPC's transactions in IDACORP stock are summarized below.
Number
of
Shares
Weighted-
Average
Exercise
Price
Weighted
Average
Remaining
Contractual
Term
Aggregate
Intrinsic
Value
(OOOs)
619,091 $
(1,412)
(1,636)
(4,800)
611,243 $
33.84
28.37
28.44
39.91
33.75
5.71 $3,385Outstanding at December 31, 2006
Exercised
Forfeited
Expired
Outstanding at December 31, 2007 4.71 $2,310
Vested or expected to vest at December 31, 2007
Exercisable at December 31, 2007
600,362 $
490,139 $
33.85
35.12
4.68 $
4.31 $
2,234
1,459
4. LONG-TERM DEBT
The following table summarizes long-term debt at December 31:
2007 2006
(thousands of dollars)
First mortgage bonds:
7.38% Series due 2007
7.20% Series due 2009
6.60% Series due 201 1
4.75% Series due 2012
4.25% Series due 2013
6% Series due 2032
5.50% Series due 2033
5.50% Series due 2034
5.875% Series due 2034
5.30% Series due 2035
6.30% Series due 2037
$$80,000
80,000
120,000
100,000
70,000
100,000
70,000
50,000
55,000
60,000
80,000
120,00
100,000
70,000
100,000
70,000
50,000
55,000
60,000
140,000
I FERC FORM NO.1 (ED. 12-88)Page 123.8
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2) A Resubmission 04/11/2008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
6.25% Series due 2037
Total first mortgage bonds
Pollution control revenue bonds:
Variable Auction Rate Series 2003 due 2024 (a)
Variable Auction Rate Series 2006 due 2026 (a)
Variable Rate Series 2000 due 2027
Total pollution control revenue bonds
American Falls bond guarantee
Milner Dam note guarantee
Unamortized premium (discount) - net
100,000
945,000 785,00
49,800
116,300
4,360
170,460
19,885
10,636
(3,409)
49,800
116,300
4,360
170,460
19,885
11,700
(3,097)
Total long-term debt $1,142,572 $983,948
(a) Humboldt County and Sweetwater County Pollution Control Revenue bonds are secured by first mortgage bonds, bringing the
total first mortgage bonds outstanding at December 3 i, 2007, to $ i .11 i billon.
At December 31, 2007, the maturíties for the aggregate amount of long-term debt outstanding were (in thousands of dollars):
2008 2009 2010 2011 2012 Thereafter
$1,064 $ 81,064 $ 1,064 $ 121,064 $101,064 $840,661
At December 31, 2007 and 2006, the overall effective cost of IPC's outstanding debt was 5.72 percent and 5.71 percent, respectively.
On June "22, 2007, IPC issued $140 milion of its 6.30% First Mortgage Bonds, Secured Medium-Term Notes, Series F, due June 15,
2037. IPC used the net proceeds to pay down outstanding commercial paper, which had increased to $164 milion in June 2007
because of increased capital expenditures.
On October 18, 2007, IPC issued $100 millon of its 6.25% First Mortgage Bonds, Secured Medium-Term Notes, Series G, due
October 15,2037. IPC used the net proceeds to retire $80 milion of7.38% First Mortgage Bonds due December 1,2007, and paid
down outstanding commercial paper.
On October 3, 2006, IPC completed a tax-exempt bond financing in which Sweetwater County, Wyoming issued and sold $116.3
milion aggregate principal amount of íts Pollution Control Revenue Refunding Bonds Series 2006. The bonds wil mature on July 15,
2026. The $1 16.3 milion proceeds were loaned by Sweetwater County to IPC pursuant to a loan agreement, dated as of October 1,
2006, between Sweetwater County and IPC. On October 10, 2006, the proceeds of the new bonds, together with certain other moneys
of IPC, were used to refund Sweetwater County's Pollution Control Revenue Refunding Bonds Series 1996A, Series 1996B and Series
1996C totaling $116.3 milion. The regularly scheduled principal and interest payments on the Series 2006 bonds, and principal and
interest payments on the bonds upon mandatory redemption on determination of taxability, are insured by a financial guaranty
insurance policy issued by Ambac Assurance Corporation. IPC and Ambac entered into an Insurance Agreement, dated as of October
3,2006, pursuant to which IPC has agreed, among other things, to pay certain premiums to Ambac and to reimburse Ambac for any
payments made under the policy. To secure its obligation to make principal and interest payments on the loan made to IPC, IPC issued
and delivered to a trustee IPC's First Mortgage Bonds, Pollution Control Series C, in a principal amount equal to the amount of the
new bonds. The Humboldt County series 2003 $49.8 millon bonds have a similar financial guaranty insurance policy from Ambac.
On January 18,2008, Fitch Ratings, Inc. announced that it had downgraded Ambac's insurer financial strength rating to "AA" from
"AAA" and was keeping the rating on negative watch. Fitch also downgraded the Humboldt bonds and Sweetwater bonds to "AA"
from "AAA" S&P and Moody's ratings for the bonds remain unchanged. However, Moody's placed Ambac'sinsurance financial
strength rating on review for possible downgrade on January 16,2008 and, as a result of this review, Moody's-rated securties that are
guaranteed by Ambac were also placed under review for possible downgrade, except those with higher public underlying ratings. S&P
also placed Ambac's financial strength, financial enhancement and issuer credit ratings on CreditWatch with negative implications on
Page 123.9IFERC FORM NO.1 (ED. 12-88)
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/111008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
January 18,2008. On February 25, 2008, S&P affirmed Ambac's "AAA" financial strength and financial enhancement ratings, but
retained the negative watch.
The maximum interest rate is 14 percent for the Sweetwater bonds and at specified rates capped at 12 percent for the Humboldt bonds.
On February 27, 2008, auctions were held for both series of pollution control bonds. The Sweetwater bonds had a successful auction
establishing a new interest rate of 7.95 percent. The Humboldt bonds expenenced a "failed auction" which resulted in a new interest
rate of 5.464 percent (currently based on LIBOR multiplied by 1.75) and the Humboldt bonds continuing to be held by the current
holders.
Long-Term Financing
IPC has in place a registration statement that can be used for the issuance of an aggregate principal amount of $350 milion of first
mortgage bonds (including medium-term notes) and unsecured debt.
In January 2007, the IPC Board of Directors approved an increase of the maximum amount of first mortgage bonds issuable by IPC to
$1.5 bilion. The amount issuable is also restricted by property, earnings and other provisions of the mortgage and supplemental
indentures to the mortgage. ipC may amend the indenture and increase this amount without consent of the holders of the first
mortgage bonds. The indenture requires that IPC's net earnings must be at least twice the annual interest requirements on all
outstanding debt of equal or prior rank, including the bonds that IPC may propose to issue. Under certain circumstances, the net
earnings test does not apply, including the issuance of refunding bonds to retire outstanding bonds that mature in less than two years or
that are of an equal or higher interest rate, or prior lien bonds.
As of December 31, 2007, IPC could issue under the mortgage approximately $535 millon of additional first mortgage bonds based on
unfunded property additions and $532 milion of additional first mortgage bonds based on retired first mortgage bonds. At December
31, 2007, unfunded property additions were approximately $900 millon.
The mortgage requires IPC to spend Or appropriate 15 percent of its annual gross operating revenues for maintenance, retirement or
amortization of its properties. IPC may, however, anticipate or make up these expenditures or appropriations within the five years that
immediately follow or precede a particular year.
The mortgage secures all bonds issued under the indenture equally and ratably, without preference, priority or distinction. IPC may
issue additional first mortgage bonds in the future, and those first mortgage bonds wil also be secured by the mortgage. The lien. of
the indenture constitutes a first mortgage on all the properties of IPC, subject only to certain limited exceptions including liens for
taxes and assessments that are not delinquent and minor excepted encumbrances. Certin of the properties of IPC are subject to
easements, leases, contracts, covenants, workmen's compensation awards and similar encumbrances and minor defects and clouds
common to properties. The mortgage does not create a lien on revenues or profits, or notes or accounts receivable, contracts or choses
in action, except as permitted by law during a completed default, securties or cash, except when pledged, or merchandise or equipment
manufactured or acquired for resale. The mortgage creates a lien on the interest of IPC in property subsequently acquired, other than
excepted property, subject to limitations in the case of consolidation, merger or sale of all or substantially all of the assets of ipc.
5. NOTES PAYABLE:
IPC has a $300 milion credit facilty which expires on April 25, 2012. Commercial paper may be issued up to the amounts supported
by the bank credit facilities. Under these facilties the companies pay a facility fee on the commitment, quarterly in arears, based on
its rating for senior unsecured long-term debt securities without third-pary credit enhancement as provided by Moody's and S&P. At
December 31,2007, IPC had regulatory authority to incur up to $450 milion of short-term indebtedness. Balances and interest rates
of IPC's short-term borrowings were as follows at December 31 (in thousands of dollars):
2007 2006
(thousand of dollars)
Balances: .
At the end of year
Average during the year
Weighted-average interest rate:
IFERC FORM NO.1 (ED. 12-88)
$
$
136,585 $
96,890 $
52,200
14,211
Page 123.10
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2) A Resubmission 04/11/2008 2oo7/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
At the end of year
A verage during the year
5.56%
5.54%
5.50%
5.50%
6. REGULA TORY MATTERS:
Regulatory Assets and Liabilties
The following is a breakdown of !PC's regulatory assets and liabilities (in thousands of dollars):
As of December 31, 2007
Total
Remaining Not Pending as of
Amortization Earnng Earng Regulatory 2007 December
Description Period a Return a Return Treatment Total 31,2006
Regulatory Assets:
Income Taxes $$309,902 $-$309,902 $343,590
Benefit Plans (I)17,765 17,765 46,181
Deferred Pension
Costs (1)2,797 2,797
Conservation 2010 8,107 8,107 1l,349
PCA Deferral 2008 92,323 92,323
Oregon Deferral (2)5,100 5,100 9,559
Asset Retirement
Obligations (3)12,188 12,188 1l,206
Grid West Loans 60 746 302 1,108 1,290
Other Through 2010 121 429 550 1,853
Total (4)$105,711 $343,827 $302 $449,840 $425,028
Regulatory Liabilities:
Income Taxes $-$44,580 $-$44,580 $41,825
Conservation 2008 1,893 1,893 6,328
PCA Accrual 15,173
FCA Deferral 2,145 2,145
Asset Retirement
Obligations (3)155,314 155,314 156,162
Deferred ITC 71,001 71,001 69,ll4
BPA Settlement 2008 851 851 2,124
Emission Allowance 4,1l8
Other 586 586
Total (5)$2,744 $273,626 $-$276,370 $294,844
(I)See Note 8.
(2)Capped at 10 percent increase per year.
(3)See Note 12.
(4)Includes $172 reported in other current assets on the balance sheets.
(5)Includes $2,166 reported in other current liabilities on the balance sheets.
In the event that recovery of costs through rates becomes unlikely or uncertain, SF AS 71 would no longer apply. If !PC were to
discontinue application of SF AS 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.
General Rate Case
Idaho: On May 12,2006, the IPUC issued an order approving a settlement of !PC's general rate case filed in October 2005. The
order approved an average increase 00.2 percent in base rate, or $18 millon in revenues, effective June 1,2006.
Deferred (Accrued) Net Power Supply Costs
I FERC FORM NO.1 (ED. .12-88)Page 123.11
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/11/2008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Idaho: IPC has a Power Cost Adjustment (PCA) mechanism that provides for annual adjustments to the rates charged to its Idaho
retail customers. These adjustments are based on forecasts of net power supply costs, which are fuel and purchased power less
off-system sales, and the true-up of the prior year's forecast. Durng the year, 90 percent of the difference between the actual and
forecasted costs is deferred with interest. The ending balance of this deferral, called the true-up for the current year's portion and the
true-up of the true-up for the prior years' unrecovered portion, is then included in the calculation of the next year's PCA.
On May 31, 2007, the IPUC approved IPC's 2007-2008 PCA fiing. The fiing increased the PCA component of customers' rates
from the then existing level, which was $46.8 milion below base rates, to a level that is $30.7 milion above those base rates. This
$77.5 milion increase is net of $69.1 millon of proceeds from sales of excess S02 emission allowances. The new rates became
effecti ve June i, 2007.
On June 1,2006, IPC implemented the 2006-2007 PCA, which reduced the PCA component of customers' rates from the then-existing
level, which was recovering $76.7 milion above then-existing base rates, to a level that was $46.8 millon below those base rates, a
decrease of approximately $123.5 million.
Idaho Load Growth Adjustment Rate (LGAR): On Januar 9,2007, the IPUC issued an order resetting IPC's LGAR to $29.41 per
MWh, effective April 1, 2007. The LGAR subtracts the cost of serving additional Idaho retail load from the net power supply costs
IPC is allowed to include in its PCA. The order revised the LGAR from the original rate of $16.84 per MWh set when the PCA began
in 1993. This amount was established as the projected additional variable energy costs attributable to load growth and was subtracted
from each year's PCA expense. In its petition, IPC had requested the use of the embedded cost of serving new load and a rate of $6.81
per MWh, but the IPUC in its order determined to use the projected marginal cost, which resulted in a higher LGAR.
Emission Allowances: During 2007, IPC sold 35,000 S02 emission allowances for a total of $19.6 milion, after subtracting
transaction fees. The sales proceeds to be allocated to the Idaho jurisdiction are approximately $18.5 milion ($11.3 milion net of
tax,
assuming a tax rate of approximately 39 percent). On Januar 15,2008, a workshop was held to discuss whether the customer share of
the Idaho jurisdictional portion of the 2007 sales proceeds should once again be included as a PCA credit or used to reduce investment
costs in wind development, green tags, or other options that would provide longer term customer benefits. Because the workshop
participants were unable to reach a consensus regarding the use of the S02 emission allowance proceeds, the IPUC determined that the
case would proceed under modified procedure. Written comments were due February 25, 2008.
In 2005 and early 2006, IPC sold 78,000 S02 emission allowances for a total of $81.6 million, after subtracting transaction fees. The
sales proceeds to be allocated to the Idaho jurisdiction are approximately $76.8 milion ($46.8 milion net of tax, assuming a tax rate of
approximately 39 percent). On May 12,200, the IPUC approved a stipulation that allowed IPC to retain ten percent as a shareholder
benefit with the remaining 90 percent plus a carying charge recorded as a customer benefit. This customer benefit is included in IPC's
PCA calculations as a credit to the PCA true-up balance and is currently reflected in PCA rates during the June 1, 2007 through May
31, 2008 PCA rate year.
Oregon: On April 30, 2007, IPC filed for an accounting order with the OPUC to defer net power supply costs for the period of May
1, 2007, through April 30, 2008, in anticipation of higher than "normal" power supply expenses. In the Oregon general rate case,
"normal" power supply expenses were set at a negative number (meaning that under normal water conditions IPC should be able to sell
enough surplus energy to pay for all fuel and purchased power expenses and stil have revenue left over to offset other costs). !PC
requested authorization to defer an estimated $5.7 milion, which is Oregon's jurisdictional share of the excess power supply costs.
IPC also requested that it earn its Oregon authorized rate of return on the deferred balance and recover the amount through rates in
future years, as approved by the OPUC. !PC is awaiting an order from the OPUc.
On April 28,2006, IPC fied for an accounting order with the OPUC to defer net power supply costs for the period of May 1,2006,
through April 30,2007. IPC requested authorization to defer an estimated $3.3 millon, which is Oregon's jurisdictional share ofthe
excess power supply costs. IPC also requested that it ear its Oregon authorized rate of return on the deferred balance and recover the
amount through rates in future years, as approved by the OPUc. On April 25, 2007, a tentative settlement agreement was reached on
the deferral application with the OPUC Staff and the Citizens' Utility Board in the amount of $2 milion. The parties also agreed that
IPC would file an application for an Oregon PCA mechanism. The settlement stipulation was approved by the OPUC on December
13,2007.
IFERC FORM NO.1 (ED. 12-88)Page 123.12
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2) A Resubmission 04/11/2008 2007/04
NOTES TO FINANCIAL STATEMENTS (Continued)
The timing of recovery of Oregon power supply cost deferrals is subject to an Oregon statute that specifically limits rate amortizations
of deferred costs to six percent per year. IPC is currently amortizing through rates power supply costs associated with the western
energy situation of 2001. Full recovery of the 2001 deferral is not expected until 2009. The 2006-2007 and the 2007-2008 deferrals
would have to be amortized sequentially following the full recovery of the 2001 deferraL.
IPC's deferred (accrued) net power supply costs consisted of the following at December 31 (in thousands of dollars):
2007 2006
Idaho PCA current year:
Accrual for the 2007-2008 rate year (1) $ $
Deferral for the 2008-2009 rate year (2) 85,732
Idaho PCA true-up awaiting recovery (refund):
Authorized May 2006Authorized May 2007 6,591
Oregon deferral:2001 costs 2,993
2005 costs2006 costs 2,107Total deferral (accrual) $ 97,423 $
(I) The 2007-2008 PeA adjustment included $69 millon of emission allowance sales to be credited to customers.
(2) The 2008-2009 PCA deferral balance includes $ i 7 millon of emission allowance sales in 2007.
(3,484)
(11,689)
6,670
2,889
(5,614)
Fixed Cost Adjustment Mechanism (FCA)
On January 27, 2006, IPC fied with the IPUC for authority to implement a rate adjustment mechanism that would adjust rates
downward or upward to recover fixed costs independent of the volume of IPC' s energy sales. This filing was a continuation of a 2004
case that was opened to investigate the financial disincentives to investment in energy efficiency by IPC. This true-up mechanism
would be applicable only to residential and small general service customers. The accounting for the FCA wil be separate from the
PCA. IPC proposed a three percent cap on any rate increase to be applied at the discretion of the IPUC.
IPC and the IPUC Staff agreed in concept to a three-year pilot program beginning January 1, 2007, and a stipulation was filed on
December 18,2006. The stipulation called for the implementation of a FCA mechanism pilot program as proposed by IPC in its
original application with additional conditions and provisions related to customer count and weather normalization methodology,
recording of the FCA deferral amount in reports to the IPUC and detailed reporting of demand side management (DSM) activities.
The IPUC approved the stipulation on March 12,2007. The pilot program began retroactively on January 1,2007, and wil run
through 2009, with the first rate adjustment to occur on June 1,2008, and subsequent rate adjustments to occur on June 1 of each year
thereafter during the term of the pilot program. IPC accrued $2.1 millon of FCA expense in 2007.
Open Access Transmission Tariff (OA TT)
On March 24, 2006, IPC submitted a revised OATT fiing with the FERC requesting an increase in transmission rates. In the fiing
IPC proposed to move from a fixed rate to a formula rate, which allows for transmission rates to be updated each year based on FERC
Form 1 data. The formula rate request included a rate of retur on equity of 11.25 percent. The proposed rates would have produced
an annual revenue increase for the FERC jurisdiction of approximately $13 millon based on 200 test year data. The FERC accepted
IPC's rates, effective June 1,2006, subject to adjustment to conform to SFAS 109 tax accounting requirements, which lowered the
estimated annual increase in revenues to approximately $11 milion.
On August 8, 2007, the FERC approved a settlement agreement fied in June 2007 by the parties on all issues except the treatment of
contracts for transmission service that contain their own terms, conditions and rates and that were in existence before the
implementation of OATT in 1996 (Legacy Agreements). The effect of this settlement was to reduce the estimated FERC jurisdictional
annual revenue increase from $11 million to approximately $8.2 millon based on 200 test year data. The settlement agreement
required that amounts collected in excess of the new rates for the June 1,2006 through July 31, 2007 period be refunded with interest
to customers. These refunds totaled approximately $1.7 millon and were paid in August 2007.
Hearings were held before the FERC in June 2007 regarding the treatment of the Legacy Agreements. IPC's position was that the
IFERC FORM NO.1 (ED. 12-88) Page 123.13
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04111/2008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
revenue IPC receives under the Legacy Agreements should be credited against the total transmission revenue requirement attributed to
OATT customers and that the contract demands of the Legacy Agreements should not be included in the load divisor of the rate
formula. The intervenors in the proceeding took the position that such contract demands should be included in the load divisor, rather
than being revenue credited.
On August 31, 2007, the FERC Presiding Administrative Law Judge (ALJ) issued an initial decision (Initial Decision) with respect to
the treatment of the Legacy Agreements, which is on file and publicly available at FERC Docket No. ER06-787. In the Initial
Decision, the ALJ concluded that (i) the Legacy Agreements should be included in the load divisor of the rate formula and (ii) the
revenue IPC receives under the Legacy Agreements should not be credited against the total transmission revenue requirement
attributed to OATT customers. If the Initial Decision is implemented, IPC estimates that this ruling will reduce the estimated FERC
jurisdictional annual revenue increase (based on 2004 test year data) to $6.8 millon.
IPC has appealed the Initial Decision to the FERC. However, if the Initial Decision is implemented, IPC would make additional
refunds, including interest, of approximately $2.4 milion for the June 1,2006 through December 31, 2007 period. IPC has reserved
this entire amount. IPC expects to pursue recovery of amounts not received pursuant to a final order in this proceeding through
additional proceedings at the FERC or through the state ratemaking process. IPC is awaiting a final FERC order.
Pension Expense
In the 2003 Idaho general rate case, the IPUC disallowed recovery of pension expense because there were no curent contributions
being made to the plan. On March 20, 2007, IPC fied a request with the IPUC to clarify that IPC can consider future contributions
made to the pension plan a recoverable cost of service. An order approving this application would not determine the methodology of
recovery but would permit IPC to record a regulatory asset related to pension costs. On June 1,2007, the IPUC issued its order
authorizing IPC to account for its defined benefit pension expense on a cash basis, and to defer and account for accrued pension
expense under SFAS 87, "Employers' Accounting for Pensions," as a regulatory asset. The IPUC acknowledged that it is appropriate
for IPC to seek recovery in its revenue requirement of reasonable and prudently incurred pension expense based on actual cash
contributions. IPC wil begin deferring pension expense to a regulatory asset account to be matched with revenue when future pension
contributions are recovered through rates. The deferral of pension expense did not begin until $4.1 milion of past contributions stil
recorded on the balance sheet at December 31, 2006, were expensed. For 2007, approximately $2.8 milion was deferred to a
regulatory asset beginning in the third quarter. IPC did not request a carying charge to be applied to the deferral of the accrued SF AS
87 expense.
7. COMMITMENTS AND CONTINGENCIES:
Purchase Obligations:
As of December 31, 2007, IPC had agreements to purchase energy from 94 cogeneration and small power production (CSPP) facilties
with contracts ranging from one to 30 years. Under these contracts IPC is required to purchase all of the output from the facilities
inside the IPC service territory. For projects outside the IPC service territory, IPC is required to purchase the output that it has the
ability to receive at the facility's requested point of delivery on the IPC system. IPC purchased 777 ,147 megawatt-hours (MWh) at a
cost of $45 milion in 2007and 911,132 MWh at a cost of $54 milion in 2006.
At December 31, 2007, IPC had the following long-term commtments relating to purchases of energy, capacity, transmission rights
and fuel:
2008 2009 2010 2011 2012 Thereafter
(thousands of dollars)
Cogeneration and small
power production $75,813 $99,246 $99,246 $103,435 $103,435 $1,511,405
Power and transmission
rights 37,884 4,971 4,971 2,619 2,619 11,433
Fuel 54,290 44,465 24,478 25,214 6,636 54,466
In addition, IPC has the following long-term coinitments for lease guarantees, maintenance and services, and industry related fees.
IFERC FORM NO.1 (ED. 12-88)Page 123.14
Name of Respondent This Report is:Date of Report Year/Periodof Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/11/2008 20071Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
2008 2009 2010 2011 2012 Thereafter
(thousands of dollars)
Operating leases $2,568 $3,336 $3,336 $1,368 $1,368 $5,719
Maintenance and service
agreements 49,777 4,006 4,006 804 804 3,584
FERC and other industry
related fees 4,133 3,990 3,990 3,884 3,884 19,493
Guarantees
IPC has agreed to guarantee the performance of reclamation activities at Bridger Coal Company of which Idaho Energy Resources Co.,
a subsidiary of IPC, owns a one-third interest. This guaantee, which is renewed each December, was $60 millon at December 31,
2007. Bridger Coal Company has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs.
Bridger Coal Company and IPC expect that the fund wil be suffcient to cover all such costs. Because of the existence of the fund, the
estimated fair value of this guarantee is minimaL.
Legal Proceedings
From time to time IPC is party to legal claims, actions and complaints in addition to those discussed below. Although they wil
vigorously defend against them, they are unable to predict with certainty whether or not they wil ultimately be successfuL. However,
based on the companies' evaluation, they believe that the resolution of these matters, taking into account existing reserves, wil not
have a material adverse effect on IPC's consolidated financial positions, results of operations or cash flows.
Wah Chang: On May 5, 2004, Wah Chang, a division ofTDY Industries, Inc., fied two lawsuits in the U.S. District Court for the
District of Oregon against numerous defendants. IDACORP, IE and IPC are named as defendants in one of the lawsuits. The
complaints allege violations of federal antitrust laws, violations of the Racketeer Influenced and Corrupt Organizations Act, violations
of Oregon antitrust laws and wrongful interference with contracts. Wah Chang's complaint is based on allegations relating to the
western energy situation. These allegations include bid rigging, falsely creating congestion and misrepresenting the source and
destination of energy. The plaintiff seeks compensatory damages of $30 million and treble damages.
On September 8, 2004, this case was transferred and consolidated with other similar cases currently pending before the Honorable
Robert H. Whaley sitting by designation in the U.S. Distrct Court for the Southern District of California. The companies' fied a
motion to dismiss the complaint which the court granted on February 11,2005. Wah Chang appealed the dismissal to the U.S. Court
of Appeals for the Ninth Circuit on March 10,2005. On November 20, 2007, the Ninth Circuit affrmed the dismissaL. On December
10, 2007, Wah Chang fied Petitions for Rehearing and Rehearing En Banc with the U.S. Cour of Appeals for the Ninth Circuit (Ninth
Circuit), which were denied on Januar 15,2008. If Wah Chang decides to seek Supreme Court review, time for filing its petition for
certiorari will expire on April 14,2008. The companies cannot predict whether Wah Chang wil seek certiorari or whether the
Supreme Court wil grant it. The companies intend to vigorously defend their position in this proceeding and believe this matter will
not have a material adverse effect on their consolidated financial positions, results of operations, or cash flows.
Western Energy Proceedings at the FERC:
California Power Exchange Chargeback:
As a component of IPC' s non-utilty energy trading in the state of California, IPC entered into a participation agreement in January
1999 with the California Power Exchange (CaIPX), a California non-profit public benefit corporation which at the time operated a
wholesale electricity market in California. Under the participation agreement, if a participant in the CalPX defaulted on a payment, the
other participants were required to pay an allocated share of the default amount to the CalPX based upon the level of trading activity of
each participant during the preceding three-month period.
On January 18,2001, the CalPX sent IPC a "default share invoice" for $2 millon as a result of a Southern California Edison payment
default of $215 milion for power purchases. IPC made this payment. On January 24, 2001, IPC termnated its participation
agreement with the CaIPX. On Februar 8,2001, the CaIPX sent a furer invoice for $5 million as a result of alleged payment
defaults by Southern California Edison, Pacific Gas and Electric Company and others. However, because the CalPX owed IPC more
than the claimed amount for power sold to the CaIPX in November and December 2000, IPC did not pay the February 8 invoice. IPC
I FERC FORM NO.1 (ED. 12-88)Page 123.15
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/11/2008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
essentially discontinued energy trading with the CalPX and the California Independent System Operator (Cal ISO) in December 2000.
A preliminary injunction was granted by a federal judge in the U.S. District Court for the Central District of California enjoining the
CalPX from declaring any CalPX paricipant in default under the terms of the CalPX Tariff. On March 9, 2001, the CalPX filed for
Chapter 11 protection with the U.S. Bankrptcy Court, Central Distrct of California.
In April 2001, Pacific Gas and Electric Company fied for bankruptcy. The CalPX and the Cal ISO were among the creditors of
Pacific Gas and Electric Company.
The FERC issued an order on April 6, 2001 requiring the CalPX to rescind all chargeback actions related to Pacific Gas and Electric
Company's and Southern California Edison's liabilties but, on October 7,200, the FERC issued an order determining that it wöuld
not require the disbursement of chargeback funds until the completion of the Californa refund proceedings.
When the FERC approved a settlement of the California Refund matters among IE and the California Parties on May 22, 2006, the
FERC also directed the CalPX to return the chargeback funds held by the CaIPX. On June 1,2006, IE received
approximately $2.5
milion from the CalPX representing the return of $2.27 milion in chargeback funds plus interest.
California Refund:
In April 2001, the FERC issued an order stating that it was establishing price mitigation for sales in the California wholesale electricity
market. In a June 19,2001 order, the FERC expanded that price mitigation plan to the entire western United States electrically
interconnected system. That plan included the potential for orders directing electricity sellers into California since October 2, 2000 to
refund portions of their spot market sales prices if the FERC determned that those prices were not just and reasonable. After
settlement discussions failed to bring resolution to the refund issues, the FERC established evidentiary hearings on July 25, 2001 to
calculate refunds related to transactions in the spot markets operated by the Cal ISO and the CalPX during the period October 2, 2000,
through June 20, 2001 (Refund Period).
On December 12,2002, a FERC Administrative Law Judge issued a Certfication of Proposed Findings on California Refund Liability
and the FERC largely affirmed the recommendations of its Administrative Law Judge on March 26, 2003, but modified the judge's
finding to enlarge refunds when it found that actual maket prices paid for gas did not reliably reflect the prices that should have
prevailed in competitive gas markets. The FERC also directed the Cal ISÖ to recalculate prices and determine the amount of "refunds"
due to the organized California electricity markets. In the context of these cases, since most sellers had not been paid by the Cal ISO
or the CaIPX, the term "refunds" means a reduction in the amount due to sellers for power sold.
IE, along with a number of other parties, sought rehearing and judicial review of the FERC's orders.
Since that time, the Cal ISO has engaged in a detailed review of its books and records and the various adjustments the FERC has
ordered to calculate "refunds." That process has taken more than four years and is not yet complete.
While those calculations were being performed, litigation before the FERC continued regarding a variety of matters that would affect
the level of refunds, including among other things, cost fiings, fuel cost allowance offsets, emissions offsets, cost-oased recovery
offsets, and allocation methods.
As the FERC issued more orders and denied rehearing, more petitions for review were fied by IE and other parties. The United States
Court of Appeals for the Ninth Circuit consolidated IE's and the other paries' petitions with the petitions for review arising from
earlier FERC orders in this proceeding, bringing the total number of consolidated petitions to more than two hundred. The Ninth
Circuit held the appeals in abeyance pending the disposition of the market manipulation claims discussed below and the development
of a comprehensive plan to brief this complicated case. The Ninth Circuit severed a subset of the stayed appeals sö that briefing cöuld
commence regarding cases related to: (1) which parties are subject to the FEC's refund jurisdiction under section 201(f) of the FPA;
(2) the temporal scope of refunds under section 206 of the FP A; and (3) which categories of transactions are subject to refunds.
On September 6, 2005, the Ninth Circuit issued a decision on the jurisdictional issues concluding that the PERC lacked refund
authority OYer wholesale electric energy sales made by governmental entities and non-public utilties. On August 2, 2006, the Ninth
Circuit issued its decision on the appropriate temporal reach and the type of transactions subject to the PERC refund orders and among
Page 123.16IFERC FORM NO.1 (ED. 12-88)
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/11/2008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
other things (i) concluded that all transactions at issue in the case that occured within or as a result of the CalPX and the Cal iso were
the proper subject of refund proceedings; (ii) refused to expand the refund proceedings into the bilateral markets including transactions
with the California Department of Water Resources; (iii) approved the refund effective date as October 2,2000, but also required the
FERC to consider whether refunds, including possibly market-wide refunds, should be required for an earlier time due to claims that
some market participants had violated governing taiff obligations (although the decision did not specify when that time would start,
the California Parties generally had sought futher refunds starng May 1,2000); and (iv) effectively expanded the scope of the refund
proceeding to transactions within the CalPX and Cal iso markets outside the 24"'hour spot market and energy exchange transactions.
While the refund proceedings were pending before the FERC, the California Attorney General fied a complaint with the FERC against
sellers in the wholesale power market, including IE and IPC, alleging that the FERC's market-based rate requirements violate the FP A,
and, even if the market-based rate requirements were valid, that the quarerly transaction reports filed by sellers did not contain the
transaction-specific information mandated by the FP A and the FERC. The complaint sought refunds for an expanded time when
compared to the basic refund proceeding. The PEC dismissed the complaint but on September 9,200, the Ninth Circuit concluded
that although market-based tariffs are permissible under the FPA, the matter should be remanded to the FERC to consider whether the
FERC should exercise remedial power (including some form of refunds) when a market participant failed to submit reports. On
December 28, 2006, a number of sellers filed a certiorari petition to the U.S. Supreme Court. The Supreme Court declined to grant
certiorari and the matter has now been remanded to the FERC.
On August 8, 2005, the FERC issued an order establishing the framework for filings by sellers who elected to make a cost showing to
reduce their refund exposure. On September 14,2005, IE and IPC made a joint cost fiing, as did approximately thirty other sellers.
That filing was contested by the California Parties (pacific Gas and Electric Company, San Diego Gas & Electric Company, Southern
California Edison Company, the California Public Utilties Commission, the California Electricity Oversight Board, the California
Department of Water Resources and the California Attorney General).
While the appeals of the California Attorney General's complaint were pending, and prior to the August 2, 2006 decision of the Ninth
Circuit and the FERC action on the cost filing, IPC and IE reached a settlement with the California Parties that was approved by the
FERC on May 22, 2006. That settlement anticipated the possibility of the outcome of the appeals discussed above and resolved the
settling parties' claims in the event of the expansion of all of the refund proceedings as the Ninth Circuit ordered. Under the terms of
the settlement, IE and IPC assigned $24.25 millon of the rights to accounts receivable from the Cal iSO and CalPX to the California
Parties to pay into an escrow account for refunds to settling paries. Amounts from that escrow not used for settling parties and $1.5
milion of the remaining IE and IPC receivables that are to be retained by the CallX are available to fund, at least partially, payment of
the claims of any non-settling parties if they prevail in the remaining litigation of this matter. Any excess funds remaining at the end of
the case are to be returned to IDACORP. Approximately $10.25 millon of the remaining IE and IPC receivables was paid to IE and
IPC under the settlement.
Although IPC and IE had reached a settlement with the California Paries, some parties representing a small portion of the total refund
exposure did not join the settlement. On March 27, 200, the FERC rejected the IEC cost fiing and IE and IPC sought rehearing of
the rejection. By order of April 27, 2006, the FERC tolled the time for what otherwise would have been required by statute to be a
decision on the request for rehearing. That request remains pending before the FERC. IE and IPC are unable to predict how or when
the FERC might rule on the request for rehearing.
On June 21, 2006, the Port of Seattle, Washington fied a request for rehearng of the FERC order approving the IPC and IE/California
Parties settlement. On October 5, 2006, the FERC denied the Port of Seattle's request for rehearing and on October 24, 200, the Port
of Seattle petitioned the U.S. Court of Appeals for the Ninth Circuit for review of the FERC orders approving the settlement. On
October 25, 2007 the Ninth Circuit lifted the stay as to the Port of Seattle's appeal along with two other cases with which the Port of
Seattle's petition remains consolidated and severed the thee cases from the remainder ofthe consolidated cases. The Ninth Circuit
established a briefing schedule which curently concludes in late June 2008 for these three cases. A date for argument has not yet been
scheduled. IPC and IE are unable to predict when or how the Ninth Circuit might rule on Port of Seattle's petition for review.
Prior to December 2005, IE had accrued a reserve of $42 millon for this matter. This reserve was calculated taking into account the
uncertainty of collection from the CalPX and Cal iso. In the fourth quater of 2005, following the tentative agreement with the
California Parties, IE reduced this reserve by $9.5 milion to $32 millon. Following payment of the $10.25 milion to IE and IPC in
June 2006, IE further reduced the reserve by $24.9 millon to $7.1 millon. This reserve was calculated takng into account several
IFERC FORM NO.1 (ED. 12-88) Page 123.17
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/111008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
unresolved issues in the California refund proceeding.
Market Manipulation:
On March 3, 2003, the California Parties asserted that a number of wholesale power suppliers, including IE and IPC, had engaged in a
variety of forms of conduct that the California Paries contended were impermssible. IE and IPC were mentioned only in limited
contexts with the overwhelming majority of the claims of the California Pares relating to the conduct of other parties. On March 20,
2003, numerous parties, including IE and IPC, submitted briefs and responsive testimony.
In a March 26, 2003 order, the FERC declined to generically apply its refund determinations to sales by all market participants,
although it stated that it reserved the right to provide remedies for the market against parties shown to have engaged in proscribed
conduct.
On June 25, 2003, the FERC ordered over 50 entities that paricipated in the western wholesale power markets between January 1,
2000 and June 20, 2001, including IPC, to show cause why certain trading practices did not constitute gaming or anomalous market
behavior in violation of the Cal iso and the CalPX Tariffs. On October 16, 2003, IPC and IE reached agreement with the FERC Staff
on the two orders commonly referred to as the "gaming" and "parnership" show cause orders. The FERC Staff submitted a motion to
the FERC to dismiss the "parnership" proceeding because materials submitted by IPC demonstrated that IPC did not engage in
impermissible parnership market behavior. The motion to dismiss the "partnership" proceeding was approved by the FERC in an
order issued on January 23, 2004 and rehearing of that order was not sought within the time allowed by statute. Regarding the gaming
order, the FERC Staff determined it had no basis to proceed with most of the allegations and IPC agreed to pay $83,373 to settle
allegations of circular scheduling. IPC believed that it had defenses to the circular scheduling allegation but determined that the cost
of settlement was less than the cost of litigation. In the settlement, IPC did not admit any wrongdoing or violation of any law. The
"gaming" settlement was approved by the FERC on March 3, 2004.
Some parties have sought review of what they claim are the excessively narow or excessively broad scope of the show cause orders,
and the Ninth Circuit has consolidated those claims with the other matters and are holding them in abeyance. The Port of Seattle is the
only party to appeal the orders of the FERC approving the gamng settement and, like the dozens of other appeals pending before the
Ninth Circuit, IPC is not able to predict when that appeal wil be considered or the outcome of the judicial determination of these
issues.
On June 25,2003, the FERC also issued an order instituting an investigation of anomalous bidding behavior and practices in the
western wholesale power markets. In this investigation, the FERC was to review evidence of alleged economic withholding of
generation. The FERC determned that all bids into the CalPX and the Cal ISO markets for more than $250 per MWh for the time
period May 1,2000, through October 1,2000, would be considered prima facie evidence of economic withholding. The FERC Staff
issued data requests in this investigation to over 60 market paricipants including IPC. IPC responded to the FERC's data requests. In
a letter dated May 12,2004, the FERC's Office of Market Oversight and Investigations advised that it was termnating the
investigation as to IPC. In March 2005, the California Attorney General, the California Public Utilties Commission, the California
Electricity Oversight Board and Pacific Gas and Electric Company sought judicial review in the Ninth Circuit of the FERC's
termination of this investigation as to IPC and approximately 30 other market parcipants. IPC has moved to intervene in these
proceedings. On April 25, 2005, Pacific Gas and Electric Company sought review in the Ninth Circuit of another PERC order in the
same docketed proceeding confirming the agency's earlier decision not to allow the paricipation of the California Parties in what the
FERC characterized as its non-public investigative proceeding. Formal orders holding these cases in abeyance have expired and the
Ninth Circuit has not established a briefing or decision schedule. IPC is able to predict when the Ninth Circuit wil schedule briefing
or decision on these cases or how it may decide them.
Pacific Northwest Refund:
On July 25, 2001, the FERC issued an order establishing another proceeding to determine whether there may have been unjust
and
unreasonable charges for spot market sales in the Pacific Nortwest during the period December 25,2000 through June 20, 2001. A
FERC Administrative Law Judge submitted recommendations and findings to the PERC on September 24, 2001 concluding 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 refunds should be allowed. On December 19, 2002, the FERC reopened the
proceedings to allow the submission of additional evidence related to alleged manipulation of the power market by market paricipants.
Parties alleging market manipulation were to submit their claims to the FERC and responses were due on March 20, 2003. The Public
IFERC FORM NO.1 (ED. 12-88)Page 123.18
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/11/2008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Utilities District No. 1 of Grays Harbor, which had executed a six-month forward contract with IPC for which performance had been
completed, intervened in this FERC proceeding, asserting that its contract should be treated as a spot market contract for purposes of
the FERC's consideration of refunds and requested refunds from IPC of $5 millon. Grays Harbor did not suggest that there was any
misconduct by IPC or IE. The companies submitted responsive testimony defending vigorously against Grays Harbor's refund claims.
In addition, the Port of Seattle, the City of Tacoma and the City of Seattle made fiings with the FERC on March 3, 2003, claiming that
because some market paricipants drove prices up throughout the west though acts of manipulation, prices for contracts throughout the
Pacific Northwest market should be re-set staring in May 200 using the same factors the FERC would use for California markets. On
June 25, 2003, after having considered oral argument held earlier in the month, the FERC terminated the proceeding and denied claims
that refunds should be paid. The FERC denied rehearing on November 10, 2003, triggering the right to fie for review. The Port of
Seattle, the City of Tacoma, the City of Seattle, the Californa Attorney General, the California Public Utilities Commission and Puget
Sound Energy, Inc. fied petitions for review in the Ninth Circuit. Grays Harbor terminated its paricipation in the case when Grays
Harbor and IPC reached a settlement. On August 24, 2007, the Ninth Circuit issued an opinion in the appeal, remanding to the FERC
the orders that declined to require refunds. The Ninth Circuit's opinion instrcted the FERC to consider whether evidence of market
manipulation submitted by the petitioners for the period Januar 1,200 to June 21, 2001 would have altered the agency's conclusions
about refunds and directed the FERC to include sales to the California Deparment of Water Resources in the proceeding. A number
of parties have sought rehearing of the Ninth Circuit's decision. IPC is unable to predict when the Ninth Circuit wil rule on the
requests for rehearing or the outcome of these matters.
In separate western energy proceedings, the Ninth Circuit issued two decisions on December 19,2006 regarding the FEC's decisions
not to require repricing of certain long term contracts. Those cases originated with individual complaints against specified sellers
which did not include IE or ipc. The Ninth Circuit remanded to the FERC for additional consideration the agency's use of restrictive
standards of contract review. In its decisions, the Ninth Circuit also questioned the validity of the FERC's administration of its
market-based rate regime. The United States Supreme Court has granted certiorar in one of the cases. IPC is unable to predict how or
when the Supreme Court wil rule, or how the FERC might respond to any such decision or how any such decision might affect the
outcome of the Pacific Northwest proceeding.
Western Shoshone National Council: On April 10,2006, the Western Shoshone National Council (which purports to be the
governing body of the Western Shoshone Nation) and certain of its individual trbal members filed a First Amended Complaint and
Demand for Jury Trial in the U.S. District Court for the District of Nevada, naming IPC and other unrelated entities as defendants.
Plaintiffs allege that IPC's ownership interest in certin land, minerals, water or other resources was converted and fraudulently
conveyed from lands in which the plaintiffs had historical ownership rights and Indian tite dating back to the 1860's or before.
On May 1,2006, IPC fied an Answer to plaintiffs' First Amended Complaint denying all liability to the plaintiffs and asserting certain
affrmative defenses including collateral estoppel and res judicata, preemption, impossibilty and impracticabilty, failure to join all
real and necessary parties, and various defenses based on untimeliness. On June 19,2006, IPC fied a motion to dismiss plaintiffs'
First Amended Complaint, asserting, among other things, that the Court lacks subject matter jurisdiction and that plaintiffs failed to
join an indispensable party (namely, the United States governent). On May 31, 2007, the U.S. District Court granted the defendants'
motion to dismiss stating that the plaintiffs' claims are bared by the finality provision of the Indian Claims Commission Act. On June
8,2007, plaintiffs fied a motion for reconsideration. On January 18,2008, the District Cour denied plaintiffs' motion for
reconsideration, and on January 25, 2008 entered judgment in favor of IPC. On January 24, 2008, plaintiffs fied a Notice of Appeal to
the Ninth Circuit. IPC and plaintiffs have not yet fied briefs on appeal, although briefing is curently scheduled for completion in
April 2008. Oral argument on the appeal has not yet been scheduled. IPC intends to vigorously defend its position in this proceeding,
but is unable to predict the outcome of this matter or estimate the impact it may have on IPC's consolidated financial position. results
of operations or cash flows.
Sierra Club Lawsuit. Bridger: In February 2007, the Sierra Club and the Wyoming Outdoor Council fied a complaint against
PacifiCorp in federal district court in Cheyenne, Wyoming alleging violations of air quality opacity standards at the Jim Bridger coal
fired plant (Plant) in Sweetwater County, Wyoming. Opacity is an indication of the amount of light obscured in the flue gas of a power
plant. A formal answer to the complaint was fied by PacifiCorp on April 2, 2007, in which PacifiCorp denied almost all of the
allegations and asserted a number of affirmative defenses. IPC is not a party to this proceeding but has a one-third ownership interest
in the Plant. PacifiCorp owns a two-thirds interest and is the operator of the Plant. The complaint alleges thousands of violations by
PacifiCorp and seeks a declaration that PacifiCorp has violated opacity limits, a permanent injunction ordering PacifiCorp to comply
with such limits, civil penalties of up to $32,500 per day per violation reimbursement of the plaintiffs costs of litigation, including
¡FERC FORM NO.1 (ED. 12-88)Page 123.19
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) lÇ An Original (Mo, Oa, Yr)
Idaho Power Company (2)A Resubmission 04/11/2008 20071Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
reasonable attorney fees.
The U.S. District Court has set this matter for trial commencing in April 2008. Discovery in the matter was completed on October 15,
2007. Also in October 2007, the plaintiffs and defendant fied cross-motions for sumary judgment on the alleged opacity permit
status of this matter. The court has not yet ruled on these motions. lPC is unable to predict the outcome of this matter or estimate the
impact it may have on their consolidated financial positions, results of operations or cash flows.
Sierra Club Notice of Intent to File Suit - Boardman: On January 15, 2008, the Oregon Chapter of the Sierra Club, the Northwest
Environmental Defense Center, Friends of the Columbia Gorge, Columbia Riverkeeper, and Hells Canyon Preservation Council
(collectively, Sierra Club) provided a 60-day notice to Portland General Electric Company (PGE) of intent to file suit. Sierra Club
alleges violations of opacity standards at the Boardman coal-frred power plant located in Morrow County, Oregon of
which IPC owns
ten percent. PGE owns 65 percent and is the operator of the plant. Sierra furer alleges various violations of the Clean Air Act,
related federal regulations and the Oregon State Implementation Plan relating to PGE' s construction and operation of the plant. Sierra
Club has not yet commenced litigation. Sierra Club alleges thousands of opacity permit limit violations by PGE from and before 2003,
and claims that it wil seek a declaration that PGE has violated opacity limits, a permanent injunction ordering PGE to comply with
such limits, and civil penalties of up to $32,500 per day per violation.
IPC intends to monitor the status of this matter but is unable to predict its outcome or what effect this matter may have on its
consolidated financial position, results of operations or cash flows.
Renfro Dairy: On September 28, 2007, the principals of Renfro Dairy in Canyon County, Idaho filed a lawsuit in the Dìstrict Court
of the Third Judicial District of the State of Idaho against IDACORP and LPC. The plaintiffs' complaint asserts claims for negligence,
negligence per se, gross negligence, nuisance, and fraud. The claims are based on allegations that from 1972 until at least March 2005,
IPC discharged "stray voltage"' from its electrical facilities that caused physical harm and injury to the plaintiffs' dairy herd. Plaintiffs
seek compensatory damages of not less than $1 milion.
Plaintiffs have not yet served their complaint on IDACORP or IPC. If the action is pursued by the plaintiffs, the companies intend to
vigorously defend their position in this proceeding and believe this matter wil not have a material adverse effect on their consolidated
financial positions, results of operations or cash flows.
8. BENEFIT PLANS:
SFAS 158
In December 2006 IPC adopted the recognition provisions of Statement of Financial Accounting Stadards No. 158, "Employers'
Accounting for Defined Benefit Pension Plans and Other Postretirement Plans - an amendment of FASB Statements No. 87, 88, 106.
and 132(R)."
The measurement provisions of SFAS 158 are not required to be adopted until 2008 and require that a company measure its plan assets
and benefit obligations as of its balance sheet date. IPC already uses a December 31 measurement date for its plans, so adoption of the
measurement provisions of SFAS 158 is not expected to have a material effect on IPC's results of operations or cash flows.
Pension Plans
IPC has a noncontributory defined benefit pension plan covering most employees. The benefits under the plan are based on years of
service and the employee's final average earnings. IPC's policy is to fund, with an independent corporate trustee, at least the minimum
required under the Employee Retirement Income Security Act of 1974 (ERISA) but not more than the maximum amount deductible for
income tax purposes. IPC was not required to contrbute to the plan in 2007 or 2006. The market-related value of assets for the plan is
equal to the fair value of the assets. Fair value is determned by utilizing publicly quoted market values and independent pricing
services depending on the nature of the asset, as reported by the trustee/custodian of the plan.
In addition, IPC has a nonqualified, deferred compensation plan for certain senior management employees and directors. This plan
was financed by purchasing life insurance policies and investments in marketable securities, all of which are held by a trustee. The
cash value of the policies and investments exceed the projected benefit obligation of the plan but do not qualify as plan assets in the
actuarial computation of the funded status.
/FERC FORM NO.1 (ED. 12-88)Page 123.20
Name of Respondent
Idaho Power Company
This Report is:
(1 ) ~ An Original
2) A Resubmission
NOTES TO FINANCIAL STATEMENTS Continued)
Date of Report Year/Period of Report
(Mo, Da, Yr)
04/11/2008 2007/Q4
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/11/2008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Prior to the adoption of SFAS 158, changes in the Deferred Compensation Plan minimum liability increased other comprehensive
income by $2 milion in 2006.
In 2008, IPC expects to recognize as components of net periodic benefit cost $1.3 million from amortizing amounts recorded in
accumulated other comprehensive income as of December 31, 2007, relating to the pension and deferred compensation plans. This
amount consists of $0.6 milion of prior service cost for the pension plan and $0.5 millon of net loss and $0.2 millon of prior service
cost for the deferred compensation plan.
The following table summarizes the expected future benefit payments of these plans:
2008 2009 2010 2011 2012 2013-2017
(thousands of dollrs)
Pension Plan $16,507 $17,610 $18,959 $20,512 $22,448 $145,577
Deferred Compensation Plan $2,672 $2,859 $3,085 $3,142 $3,236 $18,435
Plan Asset Allocations: IPC's pension plan and postretirement benefit plan weighted average asset allocations at December 31, 2007
and 2006, by asset category are as follows:
Pension
PlanAsset Category 2007 2006Equity securities 65% 68%Debt securities 22 24Real estate 10 7Other (a) 3 1Total 100% 100%
(a) The postretirement benefit plan assets are primarly life insurance contracts.
Postretirement
Benefits
2007 2006-% -%
100 100
100% 100%
Pension Asset Allocation Policy: The target allocations for the portfolio by asset class are as follows:
Large"Cap Growth Stocks
Large-Cap Core Stocks
Large-Cap Value Stocks
Small-Cap Growth Stocks
Small-Cap Value Stocks
Micro-Cap Stocks
Cash and Cash Equivalents
12% International Growt Stocks
12% International Value Stocks
12 % Intermediate- Term Bonds
5% Short-Term Bonds
5% Core Real Estate
3% Private Equity
3%
7%
7%
13%
10%
9%
2%
Assets are rebalanced as necessary to keep the portfolio close to taget allocations.
The plan's principal investment objective is to maximize total retur (defined as the sum of realized interest and dividend income and
realized and unrealized gain or loss in market price) consistent with prudent parameters of risk and the liabilty profile of the portfolio.
Emphasis is placed on preservation and growth of capital along with adequacy of cash flow sufficient to fund current and future
payments to pensioners.
There are three major goals in IPC's asset allocation process:
. Determine if the investments have the potential to ear the rate of retu assumed in the actuarial liability calculations.
. Match the cash flow needs of the plan. IPC sets cash allocations suffcient to cover the current year benefit payments and
bond allocations sufficient to cover at least five years of benefit payments. IPC then utilzes growth instruments (equities, real
estate, venture capital) to fund the longer-term liabilties of the plan.
. Maintain a prudent risk profile consistent with ERISA fiduciar standards.
IFERC FORM NO.1 (ED. 12-88) Page 123.22
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2i An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/11/008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Allowable plan investments include stocks and stock funds, investment-grade bonds and bond funds, core real estate funds, private
equity funds, and cash and cash equivalents. With the exception of real estate holdings and private equity, investments must be readily
marketable so that an entire holding can be disposed of quickly with only a minor effect upon market price. Uncovered options, short
sales, margin purchases, letter stock and commodities are prohibited.
Rate~of-return projections for plan assets are based on historical risk/retur relationships among asset classes. The primary measure is
the historical risk premium each asset class has delivered versus the return on lO-year U.S. Treasury Notes. This historical risk
premium is then added to the current yield on lO-year U.S. Treasury Notes, and the result provides a reasonable prediction of future
investment performance. Additional analysis is performed to measure the expected range of returns, as well as worst-case and
best-case scenarios. Based on the current low interest rate environment, curent rate-of-return expectations are lower than the nominal
returns generated over the past 20 years when interest rates were generally much higher.
IPC's asset modeling process also utilizes historical market returs to measure the portolio's exposure to a "worst-case" market
scenario, to determine how much performance could vary from the expected "average" performance over various time periods. This
"worst-case" modeling, in addition to cash flow matching and diversification by asset class and investment style, provides the basis for
managing the risk associated with investing portfolio assets.
Postretirement Benefits
IPC maintains a defined benefit postretirement plan (consisting of health care and death benefits) that covers all employees who were
enrolled in the active group plan at the time of retirement as well as their spouses and qualifying dependents. Benefits for employees
who retire after December 31, 2002, are limited to a fixed amount, which wil limit the growth of IPC' s future obligations under this
plan.
The net periodic postretirement benefit cost was as follows (in thousands of dollars):
2007 2006
Service cost $1,368 $1,463
Interest cost 3,512 3,426
Expected return on plan assets (2,777)(2,523)
Amortization of unrecognized transition obligation 2,040 2,040
Amortization of prior service cost (535)(535)
Amortization of net loss 403 812
Net periodic postretirement benefit cost $4,011 $4,683
The following table summarizes the changes in benefit obligation and plan assets (in thousands of dollars):
Change in accumulated benefit obligation:
Benefit obligation at January 1
Service cost
Interest cost
Actuarial (gain) loss
Benefits paid
Benefit obligation at December 31
2007 2006
$62,913 $63,633
1,368 1,463
3,512 3,426
(7,431)(2,445)
(3,536)(3,164)
56,826 62,913
32,627 29,893
3,129 3,158
2,876 2,00
(3,536)(2,428)
35,096 32,627
Page 123.23
Change in plan assets:
Fair value of plan assets at January 1
Actual return on plan assets
Employer contributions
Benefits paid
Fair value of plan assets at December 31
IFERC FORM NO.1 (ED. 12-88)
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/11/2008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Funded status at end of year (included in noncurrent liabilities)$(21,730)$(30,286)
Amounts recognized in accumulated other comprehensive income consist of:
Net loss
Prior service cost (credit)
Transition obligation
Subtotal
Less amount recognized in regulatory assets
Less amount included in deferred tax assets
Net amount recognized in accumulated other comprehensive income
$3,900 $12,086
(2,607)(3,142)
10,200 12,240
11,493 21,184
8,006 17,370
3,487 3,814
$$
In 2008, IPC expects to recognize as components of net periodic benefit cost $1.5 millon from amortizing amounts recorded in
accumulated other comprehensive income as of December 31, 2007 relating to the postretirement plan. This amount consists of ($0.5)
millon of prior service cost and $2.0 milion of transition obligation.
Medicare Act: The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Act) was signed into law in
December 2003 and established a prescription drug benefit, as well as a federal subsidy to sponsors of retiree health care benefit plans
that provide a prescription drug benefit that is at least actuarially equivalent to Medicare's prescription drug coverage.
The following table summarizes the expected future benefit payments of the postretirement benefit plan and expected Medicare Part D
subsidy receipts (in thousand of dollars):
2008 2009 2010 2011 2012 2013.2017
Expected benefit $ 4,100
payments*
Expected Medicare Part
D
$ 4,300 $ 4,400 $ 4,600 $ 4,800 $ 25,600
subsidy receipts $500 $500 $600 $600 $700 $4,600
*Expected benefit payments are net of expected Medicare Part D subsidy receipts.
The assumed health care cost trend rate used to measure the expected cost of benefits covered by the plan was 6.75 percent in 2007
and 2006. 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
Increase J)ecrease
Effect on total of cost components
Effect on accumulated postretirement benefit obligation
$
$
258
2,144
$
$
(195)
(1,696)
The following table sets forth the weighted-average assumptions used at the end of each year to determine benefit obligations for all
IPC-sponsored pension and postretirement benefits plans:
Discount rate
Pension
Benefits
2007 2006
6.4% 5.85%
Postretirement
Benefits
2007 2006
6.4% 5.85%
IFERC FORM NO.1 (ED. 12-88)Page 123.24
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) lÇ An Original (Mo, Da, Yr)
Idaho Power Company (2) A Resubmission 04/11/2008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Rate of compensation increase
Medical trend rate
Measurement date
4.5%4.5%
12/31/07
6.75%
12/31/06 12/31/07
6.75%
12/31/06
The following table sets forth the weighted-average assumptions used to determne net periodic benefit cost for all IPC-sponsored
pension and postretirement benefit plans:
Discount rate
Expected long-term rate of return on assets
Rate of compensation increase
Medical trend rate
Pension
Benefits
2007 2006
5.85% 5.6%
8.5% 8.5%
4.5% 4.5%
Postretirement
Benefits
2007 2006
5.85% 5.6%
8.5% 8.5%
6.75%6.75%
Employee Savings Plan
IPC has an Employee Savings Plan that complies with Section 401(k) of the Internal Revenue Code and covers substantially all
employees. IPC matches specified percentages of employee contrbutions to the plan. Matching contributions amounted to $5 million
in 2007 and $4 mìlion in 2006.
Postemployment Benefis
IPC provides certain benefits to former or inactive employees, their beneficiaries and covered dependents after employment but before
retirement. These benefits include salary continuation, health care and life insurance for those employees found to be disabled under
IPC's disability plans and health care for surviving spouses and dependents. IPC accrues a liability for such benefits. The post
employment benefit amounts included in other deferred credits on IPC's consolidated balance sheets at December 31 are $3.5 milion
and $4.0 millon for 2007 and 2006, respectively.
Pension Protection Act
In 2006, the Pension Protection Act of 2006 (the Act), which affects the manner in which many companies, including IDACORP and
IPC, administer their pension plans was signed into law. The Act made changes to a variety of rules that apply to employee benefit
plans, including those dealing with minimum funding requirements of defined benefit pension plans and plan investments of defined
contribution pension plans. The Act also permanently extended the pension law changes made by the Economic Growth and Tax
Relief Reconciliation Act of2001, which had been scheduled to sunset on December 31, 2010. This legislation became effective on
January 1,2008. Due to the funded status and funding policy ofIPC's pension plan, the Act is not expected to have a material impact
on the results of operations, financial condition, cash flows or liquidity of IPC when it was implemented.
9. PROPERTY PLANT AND EQUIPMENT AND JOINTLY -OWNED PROJECTS:
The following table presents the major classifications of IPC' s utìlty plant in service, annual depreciation provisions as a percent of
average depreciable balance and accumulated provision for depreciation for the years 2007 and 2006 (in thousands of dollars):
2007 200
Balance AvgRate Balance Avg Rate
Production $1,639,710 2.52%$1,592,790 2.55%
Transmission 684,399 2.13 606,947 2.18
Distribution 1,175,429 2.58 1,097,390 2.60
General and Other 296,801 8.29 286,567 6.74
Total in service 3,796,339 2.95%3,583,694 2.75%
Accumulated provision for depreciation (1,468,832)(1,406,210)
In service - net $2,327,507 $2,177,484
IFERC FORM NO.1 (ED. 12-88)Page 123.25
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/111008 2oo7/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
IPC has interests in three jointly-owned generating facilities. Under the joint operating agreements, each participating utility is
responsible for financing its share of construction, operating and leasing costs. IPC's proportionate share of direct operation and
maintenance expenses applicable to the projects is included in the Consolidated Statements of Income. These facilities, and the extent
of IPC's participation, were as follows at December 31, 2007 (in thousands of dollars):
Utilty Construction Accumulated Owner
Plant In Work in Provision for ship
Name of Plant Location Service Progress Depreciation %MW*
Jim Bridger Units 1-4 Rock Springs, WY $474,759 $8,802 $271,777 33 771
Boardman Boardman, OR 70,294 161 49,288 10 64
Valmy Units 1 and 2 Winnemucca, NV 331,371 6,958 213,430 50 284
*IPC share of nameplate capacity
IPC's wholly-owned subsidiary, Idaho Energy Resources Co., is ajoint venturer in Bridger Coal Company, which operates the mine
supplying coal to the Jim Bridger generating plant. IPC's coal purchases from the joint venture were $51 milion and $52 millon in
2007 and 2006, respectively.
IPC has contracts to purchase the energy from four PURA qualified facilties that are 50 percent owned by Ida-West. IPC's power
purchases from these facilities were $8 milion annually in 2007 and 2006.
10. INVESTMENTS:
The following table summarizes IPC's investments as of December 31 (in thousands of dollars):
2007 2006
IPC Investments:
Equity method investment
Available-for-sale equity securities
Executive deferred compensation
Other investments
Total IPC investments
$76,451
21,445
6,627
5
104,528
$62,223
21,548
6,492
4
90,267
Equity Method Investments
IPC, through its subsidiary Idaho Energy Resources Co., is a 33 percent owner of Bridger Coal Company, which supplies coal to the
Jim Bridger generating plant owned in part by ipc. Ida-West, though separate subsidiaries, owns 50 percent of each of the following
electric generation projects: South Forks Joint Venture; Hazeltonlilson Joint Venture and Snow Mountain Hydro LLC.
IFS invests in affordable housing developments that are accounted for in accordance with APB 18, "The Equity Method of Accounting
for Investments in Common Stock" and Emerging Issues Task Force Issue 94-1, "Accounting for Tax Benefits ResuLting from
Investments in AffordabLe Housing Projects, " and are presented as Investments on the Consolidated Balance Sheets. All projects are
reviewed periodically for impairment.
The following table presents IPC's earnings (loss) of unconsolidated equity-method investments (in thousands of dollars):
Bridger Coal Company (IPe)
2007
$ 5,553
2006
$ 9,347
The following table presents summarized income statement information for Bridger Coal Company (in thousands of dollars):
Operating revenues
Operating expenses
IFERC FORM NO.1 (ED. 12-88)
$
2007
153,126
136,468
2006
$ 154,910
126,869
Page 123.26
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) c An Original (Mo, Da, Yr)
Idaho Power Company (2) A Resubmission 04/11/2008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Net Income $16,658 $28,041
The following table presents summarized balance sheet information for Bridger Coal Company (in thousands of dollars):
2007 2006
Assets
Current assets
Noncurrent assets
Total Assets
$58,672
330,583
389,255
$47,723
325,252
372,975$$
Liabilties
Current liabilities
Noncurrent liabilties
Total Liabilities
Joint venture capital
Total Liabilities and Joint Venture Capital
$25,372
134,529
159,901
229,353
389,254
$28,250
158,054
186,304
186,671
372,975$$
Investments in Debt and Equity Securities
Investments in debt and equity securities are accounted for in accordance with SFAS 115, "Accounting for Certain Investments in Debt
and Equity Securities." Those investments classified as available-for-sale securities are reported at fair value, using either specific
identification or average cost to determine the cost for computing gains or losses. Any unrealized gains or losses on available-for-sale
securities are included in other comprehensive income.
Investments classified as held-to-maturity securities are reported at amortized cost. Held-to-maturity securities are investments in debt
securities for which the company has the positive intent and ability to hold the securities until maturity. These debt securities have
maturities ranging from 2008 through 2025.
The following table summarizes investments in equity securities (in thousands of dollars):
2007 2006
Gross Gross Gross Gross
Unrealized Unrealized Fair Unrealized Unrealized Fair
Gain Loss Value Gain Loss Value
A vailable- for-sale
securities (IPC)$1,059 $128 $21,445 $2,474 $322 $21,548
The following table summarizes sales of available-for-sale securities (in thousands of dollars):
2007 2006
Proceeds from sales
Gross realized gains from sales
Gross realized losses from sales
$26,110
2,093
762
$20,778
3,774
280
Additionally, these investments are evaluated to determne whether they have experienced a decline in market value that is considered
other-than-temporary. IPC analyzes securities in loss positions as of the end of each reporting period. Any security with an unrealized
loss of more than 20 percent is evaluated for other-than-temporary impairment. A securty wil generally be written down to market
value if it has an unrealized loss of 20 percent or more for more than nine months. If additional information is available that indicates
a security is other-than-temporarily impaired, it wil be written down prior to the nine-month time period. In the alternative, if a
IFERC FORM NO.1 (ED. 12-88)Page 123.27
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2) A Resubmission 04/11/2008 2007/Q4
NOTES TO FINANCiAl STATEMENTS (Continued)
security has been impaired for more than nine months but available information indicates that the impairment is temporary, the security
will not be written down. IPC has not recognized any other-than-temporary impairments in 2007 or 2006.
The following table summarizes information regarding securities that were in an unrealized loss position at the end of each year, but
for which no other-than-temporary impairment was recognized (in thousands of dollars).
Less than 12 months
Aggregate Aggregate
Unrealized Related FairLoss Value
12 months or longer
Aggregate Aggregate
Unrealized Related FairLoss Value
2007 Available-for-sale equity securities $128 $1,059 $$
2006 Available-for-sale equity securities $241 $3,879 $81 $621
The available-for-sale equity securities in unrealized loss positions are diversified investments in common stock of various companies
used to fund IPC's Senior Management Security Plan. The held-to-maturity debt securities in unrealized loss positions are bonds,
whose market values fluctuate based on the interest rate environment. At December 31, 2007, one available-for-sale and two
held-to-maturity securities were in an unrealized loss position. None of these securities had unrealized loss positions of greater than 20
percent. At December 31, 2006, eleven available-for-sale and six held40-maturity securities were in an unrealized loss position. None
of these securities had unrealized loss positions of greater than 20 percent. IPC does not consider these investments to be
other-than-temporarily impaired at December 31, 2007 or 2006.
11. FAIR VALUE OF FINANCIAL INSTRUMENTS:
The estimated fair value of IPC's financial instrments has been determned 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, deposits, customer and other receivables, notes payable, accounts payable, interest accrued and taxes
accrued are reported at their carrying value as these are a reasonable estimate of their fair value. The estimated fair values for notes
receivable, long-term debt and investments are based upon quoted market prices of the same or similar issues or discounted cash flow
analyses as appropriate.
Liabilties:
Long-term debt
December 31, 2007 December 31, 2006
Carrying Estimated Carrying Estimated
Amount Fair Value Amount Fair Value
(thousands of dollars)
$4,859 $4,907 $5,853 $5,679
23,848 23,848 28,040 28,040
$1,145,981 $1,136,042 $987,045 $978,491
Assets:
Notes receivable
Investments
12. ASSET RETIREMENT OBLIGATIONS (ARO):
SFAS 143, "Accounting for Asset Retirement Obligations," as amended and interpreted, requires that legal obligations associated with
the retirement of property, plant and equipment be recognized as a liability at fair value when incurred and when a reasonable estimate
of the fair value of the liability can be made. Under SFAS 143, when a liability is initially recorded, the entity increases the carrying
IFERC FORM NO.1 (ED. 12-88) Page 123.28
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/11/2008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
amount of the related long-lived asset to reflect the future retirement cost. Over time, the liability is accreted to its present value and
paid, and the capitalized cost is depreciated over the useful life of the related asset. If, at the end of the asset's life, the recorded
liability differs from the actual obligations paid, a gain or loss would be recognized. As a rate-regulated entity, IPC records regulatory
assets or liabilities instead of accretion, depreciation and gains or losses. This treatment was approved by Order No. 29414 from the
IPUC. The regulatory assets recorded under this order do not earn a retur on investment.
IPC's recorded AROs relate to: removal ofPCB-contanated equipment at its distrbution facilities and the reclamation and removal
costs at its jointly owned coal-fired generation facilties. In 2007 changes in estimates were identified at IPC and IPC's jointly owned
coal-fired generation facilities resulting in a net increase in liability of $0.9 milion.
IPC has AROs associated with its transmission system and hydroelectric facilties; however, due to the indeterminate removal date, the
fair value of the associated liabilities currently cannot be estimated and no amounts are recognized in the consolidated financial
statements.
The regulated operations of IPC also collect removal costs in rates for certin assets that do not have associated AROs. The adoption
of SFAS 143 required IPC to redesignate these removal costs as regulatory liabilties. Costs recorded as regulatory liabilities on IPC's
Consolidated Balance Sheet as of December 31, 2007 and 2006, were $155 milion and $156 milion, respectively.
The following table presents the changes in the aggregate carying amount of AROs (in thousands of dollars):
IPC
2007 2006
Balance at beginning of year $12,911 $10,079
Accretion expense 692 628
Revisions in estimated cash flows 920
Liability incurred 2,204
Liability settled (8)
Balance at end of year $14,515 $12,911
13. RELATED PARTY TRANSACTIONS (IPC):
IDA CORP
IPC performs corporate functions such as financial, legal and management services for IDACORP and its subsidiaries. IPC charges
IDACORP for the costs of these services based on service agreements and other specifically identified costs. For these services IPC
biled IDACORP $2 millon in 2007 and $4 mìllon in 2006.
Ida-West
IPC purchases all of the power generated by four of Ida-West' s hydroelectrc projects located in Idaho. IPC paid $8 milion in both
2007 and 2006.
IFERC FORM NO.1 (ED. 12-88) Page 123.29
This Page Intentionally Left Blank
;..~
...
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/11/2008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Ida-West
IPC purchases all of the power generated by four ofIda-Wests hydroelectrc projects located in Idao. IPC paid $8 milion in both
2007 and 2006.
IFERC FORM NO.1 (ED. 12-SS) Page 123.30
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1 ) An Original (Mo, Da, Yr)End of 2007/Q4
(2) Ei A Resubmission 04/111008
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
1. Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate.
2. Report in columns (f) and (g) the amounts of other categories of other cash flow hedges.
3. For each category of hedges that have been accounted for as "fair value heges", report the accunts affected and the related amounts in a footnote.
Une Item Unrealized Gains and Minimum Pension Foreign Currency Other
No.Losses on Available-Uability adjustment Hedges Adjustments
for-Sale Securities (net amount)
(a)(b)(c)(d)(e)
1 Balance of Account 219 at Beginning of
Preceding Year 2,725,005 (6,150,330)
2 Preceing QtrlYr to Date Reclassifcations
frm Acc 219 to Net Income (2,127,497)
3 Preceding QuarterlYearto Date Changes in
Fair Value 713,442 6,150,330 (7,048,073)
4 Total (lines 2 and 3)(1,414,055)6,150,330 (7,048,73)
5 Balance of Accnt 219 at End of
Preceding QuarterlYear 1,310,950 (7,Q8,073)
6 Balance of Account 219 at Beginning of
Current Year 1,310,950 (7,048.073)
7 Current QtrlYr to Date Reclassifcations
frm Acet 219 to Net Incme (922.013)450,330
8 Curent QuarterlY ear to Date Changes in
Fair Value 178,312 (126,006)
9 Total (lines 7 and 8)(743,701)324,324
10 Balance of Accunt 219 at End of Current
QuarterlY ear 567,249 (6,723,749)
FERC FORM NO.1 (NEW 06-02)Page 122a
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2oo7/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da. Yr)
(2) A Resubmission 04111/2008
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
Une
No.
Other Cash Flow
Hedges
Interest Rate Swaps
Other Cash Flow
Hedges
(Specify)
Totals for each
category of items
recrded in
Accunt 219
(h)
( 3,425.325)
( 2,127,497)
( 184.301)
( 2,311.798)
( 5.737.123)
( 5,737,123)
( 471,683)
52,306
( 419.377)
( 6,156,500)
(f)(g)
1
2
3
4
5
6
7
8
9
10
Net Income (Carred
Forwrd frm
Page 117, Une 78)
Total
Comprehensive
Incme
(I)0)
FERC FORM NO.1 (NEW 0602)Page 122b
This Page Intentionally Left Blank
,.~
:'i
is:!0 s:(1) ~An Original
(2) A Resubmission
SUMMA Y OF UTILITY PLANT AND ACCUM LATED PROVISIONS
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Report in Column (c) the amount for electric function, in column (d) the amount for gas funcion, in column (e), (f), and (g) report other (specify) and in
column (f) common function.
End of
(a)
Total Company for the
Current YeaúQuarter Ended
(b)
Electric
(c)
Une
No.
Classification
Utilty Plant
2 In Service
3 Plant in Service (Classified)
4 Propert Under Capital Leases
5 Plant Purchased or Sold
6 Completed Construction not Classified
7 Experimental Plant Unclassified
8 Total (3 thru 7)
9 Leased to Others
10 Held for Future Use
11 Constrtion Work in Progress
12 Acquisiton Adjustments
13 Total Utility Plant (8 thru 12)
14 Accum Prov for Depr, Amort, & Depl
15 Net Utilit Plant (13 less 14)
16 Detail of Accum Prov for Depr, Amort & Depl
17 In Service:
18 Depreciation
19 Amort & Depl of Producing Nat Gas Land/Land Right
20 Amort of Underground Storage Land/Land Rights
21 Amort of Oter Utilit Plant
22 Total In Service (18 thru 21)
23 Leased to Oters
24 Depreciation
25 Amortization and Depletion
26 Total Leased to Oters (24 & 25)
27 Held for Future Use
28 Depreciation
29 Amortiztion
30 Total Held for Future Use (28 & 29)
31 Abandonment of Leases (Natural Gas)
32 Amort of Plant Acquisition Adj
33 Total Accum Prov (equals 14) (22,26,30,31,32)
3,796,793,711 3,796,793,711
3,796,793,711 3,796,793,711
3,365,527
257,589,90
-454,449
4,057,294,689
1,46,831,768
2,588,462,921
-350,303
1,468,831,768
-350,303
1,468,831,768
FERC FORM NO.1 (ED. 12-89)Page 200
Name of Respondent This~rtIS:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) Fi A Resubmission 0411/2008
ELECTRI PLANT IN SERVICE (Account 101, 102, 103 and 106)
1.Report below the original cost of electric plant in service according to the prescribe accunts.
2. In addition to Account 101, Electric Plant in Servce (Classified), this page and the next include Account 102, Electric Plant Purchased or Sold;
Account 103, Experimental Electric Plant Unclassified; and Account 106, Completed Construction Not Classified-Electric.
3. Include in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year.
4. For revisions to the amount of initial asset retirement costs capitalized, included by primary plant account, increases in column (c) additions and
reductions in column (e) adjustments.
5. Enclose in parentheses credit adjustments of plant accunts to indicte the negative effec of such accounts.
6. Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in column (c). Also to be included
in column (c) are entries for reversals of tentative distributions of prior year reported in column (b). Ukewise, 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 entr to the account for accumulated depreciation provision. Include also in column (d)
ine Account ~No.Bemng 01 Yea,
(a)(b) (c)
1 1. INTANGIBLE PLANT
2 301) Organization 62,160 -56,457
3 (302) Franchises and Consents 21,711,627 60,002
4 (303) Miscellaneous Intanoible Plant 50,320,243 6,491,116
5 TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)72,094,030 6,494,661
6 2. PRODUCTION PLANT
7 A. Steam Production Plant
8 (310) Land and Land Riahts 1,370,319
9 /311) Structures and Improvements 130,536,694 964,932
10 /312) Boiler Plant Equipment 505,458,266 24,736,981
11 (313) Enoines and Enoine-Driven Generators
12 (314) Turbogenerator Units 122,585,94 7,674,363
13 (315) Accessory Electric Eauioment 61,359,209 309,204
14 (316) Misc. Power Plant Equipment 13,086,514 1,942,279
15 (317) Asset Retirement Cost for Steam Production 3,836,568 894,668
16 TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)838,233,513 36,522,427
17 B. Nuclear Production Plant
18 (320) Land and Land Riahts
19 (321) Structures and Improvements
20 (322) Reactor Plant Equipment
21 (323) Turbenerator Units
22 (324) Accessory Electric Equipment
23 (325) Misc. Power Plant Equipment
24 (326) Asset Retirement Cots for Nuclear Production
25 TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24)
26 C. Hydraulic Production Plant
27 (330) Land and Land Rights 22,523,451 4,906,033
28 I (331) Structures and Improvements 133,690,047 11,955,032
29 (332) Reservoirs, Dams, and Waterwys 244,621,041 1,461,865
30 (333) Water Wheels, Turbines, and Generators 187,440,908 480,338
31 (334) Accessory Electric EQuipment 36,805,775 941,185
32 I (335) Misc. Power Plant EQuipment 15,590,447 701,236
33 (336) Roads, Railroads, and Bridoes 6,950,430 542,255
34 (337) Asset Retirement Costs for Hydraulic Producion
35 TOTAL Hvdraulic Production Plant (Enter Total of lines 27 thru 34)647,622,099 20,987,944
36 D. Other Production Plant
37 (340) Land and Land Rights 402,745
38 (341) Strucures and Improvements 5,301,732 464,215
39 (342) Fuel Holders, Products, and Accessories 3,520,611 245,078
40 34) Prime Movers 29,957,033 28,495,093
41 (34) Generators 61,685,462 -40,203,12S
42 (345) Accessory Electric Equipment 4,681,678 9,373,969
43 (34) Misc. Power Plant Equipment 1,385,245 872,982
44 347) Asset Retirement Costs for Other Production
45 TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44)106,934,50 -751,791
46 TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45)1,592,790,118 56,758,580
FERC FORM NO.1 (REV. 12-GS)Page 204
This ~rt Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmission 04/11/2008
ELECTRIC PLANT IN SERVICE (Account 101,102,103 and 106) (Continued)
distributions of these tentative classifications in columns (c) and (d), including the reversals of the prior years tentative account distributions of these
amounts. Careful observance of the above instructions and the texts of Accounts 101 and 106 Will avoid serious omissions of the reported amount of
respondent's plant actually in service at end of year.
7. Show in column (f) reclassifications or transfers witin utilty plant accounts. Include also in column (f) the additios or reductions of primary account
classifications arising from distribution of amounts initially recorded in Account 102, include in column (e) the amounts With respect to accumulated
provision for depreciation, acquisition adjustments, etc., and show in column (f) only the offset to the debits or credits distributed in column (f) to primary
account classifications.
8. For Account 399, state the nature and use of plant included in this account and if substantial in amount submit a supplmentary statement showing
subaccount classification of such plant conforming to the requirement of these pages.
9. For each amount comprising the reported balance and changes in Account 102, state the property purhased 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 Accunts, give also dateRetirements Adjustments Transfers Balance at UneEnd lif)Year No.
Name of Respondent
Idaho Power Company
YearlPeriod of Report
End of 2007/Q4
57,744
5,475,988
1,370,319
131,44,882
524,719,259
3,326,718
62,678
401,099
126,933,588
61,605,735
14,627,694
4,731,236
865,431,7139,324,227
27,131,877
145,349,44
246,057,90
187,855,934
37,573,489
16,288,729
7,492,685
859,977 667,750,066
14,854,734
-15,200,000
402,745
5,765,947
3,765,689
43,597,392
36,682,33
14,055,647
2,258,227
-34,266
9,838,938
106,527,981
1,639,709,760
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 (REV. 12-()205Page
Name of Respondent This~rtIS:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) Fi A Resubmission 04/11/2008
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)
ILine Account ~No.(a)
B"9"'I"" olVea,(b) (c)
47 3. TRANSMISSION PLANT
48 (350) Land and Land Rights 28,752,863 2,341,500
49 (352) Structures and Improvements 36,782,554 3,528,731
50 (353) Station Equipment 245,790,680 19,364,986
51 (354) Towers and Fixtures 98,003,480 23,794,427
52 (355) Poles and Fixtures 77,282,453 11,453,638
53 356) Overhead Conductors and Devices 120,016,810 19,772,786
54 (357) Underground Conduit
55 358) Underground Conductors and Devices
56 (359) Roads and Trails 318,351
57 (359.1) Asset Retirement Costs for Transmission Plant
58 TOTAL Transmission Plant (Enter Total of lines 48 thru 57)606,947,191 80,256,068
59 4. DISTRIBUTION PLANT
60 (360) land and Land Riahts 4,607,315 -221,040
61 (361) Structures and Improvements 20,494,136 1,175,996
62 (362) Station Equipment 142,958,358 9,392,314
63 (363) Storage Battery Eauipment
64 . (364) Poles, Towers, and Fixtures 194,701,580 11,386,049
65 (365) Overhead Conductors and Devices 98,919,001 9,243,475
66 I (3f6) Underground Conduit 43,632,849 2,652,267
67 . (367) Underground Conductors and Devices 162,348,862 10,048,775
68 (368) Line Transformers 318,762,025 40,578,706
69 (369) Services 51,272,410 3,061,264
70 ! (370) Meters 52,622,132 4,936,677
71 (371) Installations on Customer Premises 2,634,033 139,954
72 (372) Leased Propert on Customer Premises
73 . (373) Street Lighting and Signal Systems 4,067,070 128,960
74 (374) Asset Retirement Costs for Distribution Plant 370,187 -110,923
75 TOTAL Distribution Plant (Enter Total of lines 60 thru 74)1,097,389,958 92,412,474
76 5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT
77 I (380) Land and Land Rights
78 (381) Structures and Improvements
79 (382) Computer Hardware
80 (383) Computer Softre
81 384) Communication Eauipment
82 (385) Miscellaneous Regional Transmission and Market Opration Plant
83 (386) Asset Retirement Costs for Regional Transmission and Market Oper
84 TOTAL Transmission and Market Operation Plant (Total lines 77 thru 83)
85 6. GENERAL PLANT
86 (389) Land and Land Rights 8,760,765 146,931
87 1390) Strucures and Imorovements 64,391,078 5,135,502
88 391) Ofice Furniture and Equipment 37,350,131 8,194,723
89 (392) Transportation Equipment 51,050,749 7,196,442
90 (393) Stores Equioment 982,361 185,107
91 (394) Tools, Shop and Garage Eauipment 4,222,287 289,705
92 (395) Laboratory Equipment 9,761,135 634,673
93 (396) Power Operated Equipment 7,306,985 1,403,340
94 (397) Communication Equipment 28,196,828 158,705
95 (398) Miscellaneous Equipment 2,904,743 179,122
96 SUBTOTAL (Enter Total of lines 86 thru 95)214,927,062 23,524,250
97 (399) Oter Tanaible propert
98 (399.1) Asset Retirement COts for General Plant
99 TOTAL General Plant (Enter Total of lines 96, 97 and 98)214,927,062 23,524,250
100 TOTAL (Accounts 101 and 106)3,584,148,359 259,446,033
101 (102) Electric Plant Purchased (See Instr. 8)
102 (Less) (102) Electric Plant Sold (See Instr. 8)
103 (103) Experimental Plant Unclassified
104 TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103)3,584,148,359 259,446,033
FERC FORM NO.1 (REV. 12-DS)Page 206
Name of Respodent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) ñ A Resubmission 0411/2008
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)
Line(d) (e (f) End tg)Year No.
4792 31,094,271 48
56,989 40,254,296 49
2,177,755 262,977,911 50
56,209 121,741,698 51
375,227 88,360,86 52
137,462 139,652,134 53
,54
55
318,351 56
57
2,803,734 68,399,525 58
59
493 4,38,782 60
12,680 21,657,452 61
667,925 151,682,747 62
63
2,145,266 203,942,363 64
1,650,661 106,511,815 65
155,959 46,129,157 66
1,243,316 171,154,321 67
6,699,825 352,640,90 68
44,996 53,887,678 69
1,235,877 56,322,932 70
41,007 2,732,980 71
72
74,757 4,121,273 73
259,264 74
14,373,762 1,175,428,670 75
76
77
78
79
80
81
82
83
84
85
34,566 8,873,130 86
734,902 68,791,678 87
7,349,071 38,195,783 88
990,416 57,256,775 89
92,789 1,074,679 90
101,766 4,410,226 91
163,390 10,232,418 92
361 8,709,96 93
2,462,397 25,893,136 94
57,807 3,026,058 95
11,987,465 226,463,847 96
97
98
11,987,46 226,463,847 99
46,800,681 3,796,793,711 100
101
102
103
46,800,681 3,796,793,711 104
FERC FORM NO.1 (REV. 12-()Page 207
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) DA Resubmission 04111/2008
ELECTRIC PLANT HELD FOR FUTURE USE (Account 105)
1. Report separately each property held for future use at end of the year having an original cost of $250,000 or more.Group other items of property held
for future use.
2. For property having an original cost of $250,000 or more previously used in utility operations, now held for future use, give in column (a), in addition to
other required information, the date that utility use of such propert was discontinued, and the date the original cost was transferred to Account 105.
Line Descri¡:tion ana Location ~No.Of proterty in T is Account in Utilty Service End of Year
(a (b) (c) (d)
1 Land and Rights:
2 Boise Operations Center 12131/82 768,377
3 Production 185,246
4 Transmission Stations 360,819
5 Transmission Lines 69,263
6 Distribution Stations 1,137,976
7 BeaconLight Substation (1)12130/02 465,662
8
9
10 Boise Operations Center 12131/82 72,785
11 Boise Mechanical and Electrical Shop 12131/01 47,000
12 Transmission Stations 12131/81 178,094
13 Distribution Stations 80,306
14
15
16
17
18
19 Column B if no date listed it is various
20
21 Other Property:
22
23
24
25
26
27 (1) a portion of Beacon Light was classified in
28 account 101000 in the prior year. In 2007 it
29 was reclassified to account 105000.
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47 Total 3,365,528
1:1:01" I:nou..1" 1 ii:n 1 ?_QI:\Paae 214
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) Fi A Resubmission 04/11/2008
CONSTRUCTION WORK IN PROGRESS. . ELE(TRIC (Account 107)
1. Report below descriptions and balances at end of year of projects in process of construction (107)
2. Show items relating to 'research, development, and demonstrtion" projects last, uner 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 groupd.
line Description of Project Construction work in progress -
No.Eletric (Accout 107)
(a)(b)
1 DANSKIN UNIT #1 - 160 MW CT (2 47,664,001
2 ROLLUP RELIC COST BROWNLEE 37,166,859
3 ROLLUP RELIC COST HELLS CANYON 25,469,840
4 ROLLUP RELIC COST OXBOW 11,672,742
5 T7230601 DANSKIN.HUBBARD 230 K 8,932,442
6 HELLS CANYON RELICENSING OUTSI 8,342,890
7 CIAC LIABILITY RECLASS 7,226,739
8 TURBINE BLADES AND VANES. CAP 5,745,426
9 VALMY UNDISTRIBUTED WORK ORDER 3,922,799
10 DANSKIN-BENNETI 230 KV 3,021,500
11 CRBU0601 SERIES CAPACITOR 2,813,120
12 AP ACCRUAL ESTIMATE 2,798,000
13 WQ . ONGOING HELLS CANYON RELI 2,679,679
14 PURCHASE STAR PROPERTY FOR NOR 2,629,980
15 LOWER MALAD FISH PASSAGE 2,561,437
16 INSTALL 230KV PHASE SHIFTER AT 2,277,515
17 MAINFRAME UPGRADE 2,234,580
18 BUILD NEW POLE LINE SUBSTATION 2,149,526
19 MOBILE WORKFORCE MANAGEMENT 20 2,076,833
20 ENTERPRISE STORAGE 2,074,637
21 BRIDGER UNDISTRIBUTED WORK ORO 2,032,908
22 HCC RELICENSING FISH2004 FEASI 1,768,35
23 DNPR0601 NETWORK 1,442,887
24 SPVYOS02-NEW 138-12.5KV SUBSTA 1,418,087
25 REL-HELLS CANYON COMPLEX FY200 1,404,93
26 DNPR-MNJl REBUILD LINE 919 Wi 1,380,996
27 PURCHASE MCCALL PROPERTY FOR 0 1,358,663
28 VALMY 3434 U1 OVERFIRE AIR SY 1,34,83
29 HUBBARD NEW 230 KV SWITCHING S 1,330,097
30 LINE 470 CONSTRUCTION NWMS-MCA 1,328,047
31 VALMY 98196159 RELINE EVAPORAT 1,298,792
32 #3 CONTROL AND EQUIPMENT UPGRA 1,236,191
33 NWTF 138 KV TAP 1,191,093
34 COST CENTER 317 DELIVERY CAPIT 1,183,991
35 REPLACE METALCLAD 1,183,464
36 MCAL0503-CONVERT 69KV TO 138KV 1,154,869
37 342 COST CENTER DELIVERY CAPIT 1,153,474
38 REPLACE NMPA METALCLAD SECT.1 1,093,80
39 WATER MGMT-SHOP BUILDING PURCH 1,076,468
40 DNPR0601 OPERATIONS 990,887
41 LINE 470 CONSTRUCTION STKY - TMR 987,211
42 326-COST CENTER DELIVERY CAPIT 958,530
43 TOTAL 257,589,900
FERC FORM NO.1 (ED. 12-87)Page 216
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/04
(2) Fi A Resubmission 04/11/2008
CONSTRUC ION WORK IN PROGRESS - - ELEI TAlC (Account 107)
1. Report below descriptions and balances at end of year of projec in process of construion (107)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $100,000, whichever is less) may be grouped.
Line Description of Project Construction work in progress -
No.Electric (Account 107)
(a)(b)
1 BMPR - 230KV LINE TERMINAL 945,082
2 RIVER ENG.-HELLS CANYON CONTIN 938,195
3 MPSN - MIDPOINT EAST RAS UPGRA 922,068
4 HCC RELIC ENSING, FISH2004 ANAD 875,996
5 ROLLUP RELIC COST SWAN FALLS 875,241
6 SWAN FALLS RELICENSING 85,969
7 DONN0701 INSTALL 80MVAR 138KV 845,909
8 RIVER ENG.-HELLS CANYON CONTIN 815,091
9 HCC RELICENSING, FISH2004 REDB 804,872
10 OP. HYDRO. - PHASE V STREAM FLO 728,096
11 HCC RELICENSING, FISH200 INST 724,668
12 JIM BRIDGER RAS-A AND RAS-B 723,455
13 PAYROLL & IBNR ACCRUAL 699,383
14 MS SOL SERVER CLUSTER 689,058
15 392 COST CENTER DELIVERY CAPIT 669,330
16 341 COST CENTER DELIVERY CAPIT 642,430
17 REL-HCC OREGON REAUTHORIZATION 635,001
18 PASSPORT NEW USER INTERFACE 624,926
19 IPCO'CONVERT HAVN TO 138 KV 622,739
20 NWMS0501 - CONVERT TO 138KV 615,205
21 CARD ACCESS CONTROL SYSTEM 606,310
22 418-CC DELIVERY CAPITAL OVERHE 597,416
23 390 COST CENTER DELIVERY CAPIT 596,099
24 PURCHASE #4 TURBINE RUNNER 592,358
25 34 COST CENTER DELIVERY CAPIT 591,075
26 IPCO/BOIS-0141200 DOWNTOWN CA 546,241
27 HCC RELICENSING FISH2004 RESID 542,226
28 LEGAL DEPT. LABOR FOR RELICENS 527,986
29 LEADERSHIP TRANSFORMATION 509,937
30 BUILD NEW ADRIAN SUBSTATION AT 509,180
31 CONSTRUCTION ACCOUNTING CAPITA 497,493
32 415-CC DELIVERY CAPITAL OVERHE 472,478
33 335-COST CENTER DELIVERY CAPIT 455,863
34 LSPO LICENSE ART 414 REC - REN 451,045
35 REL - SWAN FALLS FY200 CAPITA 445,941
36 NETORK BACKBONE UPGRADE 44,938
37 33-COST CENTER DELIVERY CAPIT 425,249
38 T7230701 OPGW DANSKIN-HUBBARD 417,864
39 BRIDGER 2oo8C002 U4 REHEATER R 416,467
40 578 COST CENTER DELIVERY CAPIT 413,098
41 577 COST CENTER DELIVERY CAPIT 406,107
42 ROW FOR T404 - 138 KV TO CHERR 401,466
43 TOTAL 257,589,900
FERC FORM NO.1 (ED. 12-87)Page 216.1
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/04
(2) FiA Resubmission 04/11/2008
CONSTRUCTION WORK IN PROGRESS - - ELEl TRIC (Account 107)
1. Report below descriptions and balances at end of year of projects in process of construcion (107)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $100,000, whichever is less) may be grouped.
Line Description of Project Construcion work in progress.
No.Electric (Account 107)
(a)(b)
1 IPCO'UPGRADE PNGE TO FACILITAT 401,208
2 COST CENTER 316 DELIVERY CAPIT 400,193
3 LINE 438, PERMITIING & ROW FOR 389,393
4 IPCO'PURCHASE ROW FOR LINE #22 383,794
5 COM - REC BAKER CO SETLEMENT 382,166
6 300T GANTRY CRANE MODERNIZATIO 377,118
7 HAILEY TEAM CAP OH WORK ORDER 371,870
8 IPCO/HBND-041 REBUILD APPROX 3 368,204
9 BRIDGER 2oo7Cl77 U3 BURNER COR 365,661
10 WO SWAN FALLS RELICENSING.CAPI 358,028
11 WHITETAIL SUBDIVISION-LINE EXT 357,466
12 CAPITAL OVERHEADS FOR CADD & A 352,990
13 BRIDGER 2007C042 U3 WATERWALl 349,570
14 BRIDGER 2OO7C174 U3 REPL LOWER 340,588
15 TFOC SILVERS BUILDING GARAGE A 336,080
16 REC - BAKER COUNTY SETLEMENT 328,660
17 CDAL-013 TRANSFER TO NEW COAL.326,755
18 HOMEDALE SUBSTATION UPGRADE LA 323,822
19 MPSN0703 - REBUILD 311 Z S&C CI 316,200
20 ADEL0702 - ADD THERMAL DETECTI 315,505
21 GOODING TEAM CAP OH WORK ORDER 309,48
22 LINE 43, RIGHT OF WAY, VICTOR 294,860
23 BRDY0702 - REPLACE CONDENSER C 293,956
24 IDAHO POWER PACIFICORP JOINT V 293,673
25 BRIDGER 207C041 U3 WALLBLOWER 290,377
26 VALMY 9819244 PURCHASE BALANC 276,795
27 REPLACE #5 VOLTAGE REGULATOR &274,069
28 CAll CENTER LABOR HOURS FOR LI 272,453
29 IPCO REBUILD 2 MI NORTH OF NOR 270,297
30 Delivery Overheads 269,832
31 IPCOIBOIS.021/200 DOWNTOWN CA 266,780
32 CJ STRIKE: #1 TURBINE RUNNER 263,514
33 TWINWEST TEAM CAP OH WORK ORDE 261,203
34 SWAN FALLS RELICENSING FISH200 258,694
35 RC RELOCATE BOIS 257,64
36 585 COST CENTER DELIVERY CAPIT 254,93
37 575 COST CENTER DELIVERY CAPIT 251,809
38 BRIDGER 2007C809 REPL U3 UPPER 250,379
39 EASTGATE SUBSTATION - ADD FEED 247,210
40 ENHANCED LAW ENFORCEMENT PER S 246,492
41 STATION APP. LAB EQUIP. 2007 243,299
42 381 -COST CENTER DELIVERY CAPI 243,141
43 TOTAL 257,589,900
FERC FORM NO.1 (ED. 12-87)Page 216.2
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Onginal (Mo, Da, Yr)End of 2007/04
(2) Fi A Resubmission 0411/2008
CONSTRUC ION WORK IN PROGRESS - - ELEI TRIC (Accunt 107)
1. Report below descriptions and balances at end of year of projects in proess 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.
Une Descnption of Project Costruction work in progress -
No.Electnc (Account 107)
(a)(b)
1 REL - REC SWAN FALLS RELICENSI 241,140
2 SIEM - SECURITY INFORMATION EV 231,965
3 REMOTE DEVICE SECURITY & MANAG 231,671
4 TERR: HCC RELIC ENSING 228,389
5 OLD CUTTERS SUBDIVISION-RESIDE 228,264
6 100-COST CENTER DELIVERY CAPIT 226,784
7 LINE #902, REPLACE LEANING STR 224,239
8 ADAMSFAM TEAM CAP OH WORK ORDE 219,688
9 PORT AUTHORITY & WIRELESS DEPL 217,157
10 MOSCA SECA SUB #1- PRI & SEC T 217,155
11 CDAL ADD VTRY 138 LINE TERMINA 211,752
12 410-CC DELIVERY CAPITAL OVERHE 211,301
13 DELIVERY WORK ORDER RECON PROJ 210,63
14 DELIVERY CAPITAL OVERHEADS FOR 209,917
15 IPCO SIPN 0412006 CABLE REPLA 207,947
16 VALMY 98191438 ETAPRO PERFORMA 207,394
17 455-COST CENTER DELIVERY CAPIT 207,197
18 BRIDGER 2007C159 COAL PILE L1G 206,584
19 LSPO LICENSE ART 414 REC - RIV 206,512
20 MC CALL ENGINEERING EMERGENCY 201,197
21 AFTS0702 - REPAIR CABLE TRAYS 199,101
22 WEB SITE REDESIGN 198,447
23 334-COST CENTER DELIVERY CAPIT 197,461
24 COST CENTER 310 DELIVERY CAPIT 197,337
25 BRIDGER 2007C036 INSTZOLOBOSS 196,201
26 BOARDMAN 22163 UPG DCS TO OVAT 195,609
27 BEARING COOLERS, CLOSED LOOP S 194,841
28 370 -COST CENTER DELIVERY CAPI 193,850
29 L-406, MTN HM JCT- UPPER SALMO 193,340
30 TOOL EXP TRANS TO CONST 188,428
31 420-CC DELIVERY CAPITAL OVERHE 188,268
32 153 COST CENTER DELIVERY CAPIT 186,666
33 BRIDGER 2007C234 REPL D10 DOZE 185,786
34 BRIDGER 2007C063 U3 SH HEAVY W 184,840
35 TFEAST TEAM CAP OH WORK ORDER 184,036
36 FALLS - RELAY REPLACEMENT 183,967
37 IPCO- ELMR 042 SINGLE PHASE RE 183,425
38 BRIDGER 2007C911 PLANT SECURIT 182,511
39 BORAOS01 BORA-MPSN 345KV THER 182,207
40 MINI CASSIA TEAM CAP OH WORK 0 181,310
41 NEW MEADOWS EAST NEW 00 ACSR 0 178,354
42 LAKE SHORE SUBSTATION - PURCHA 178,055
43 TOTAL 257,589,900
FERC FORM NO.1 (ED. 12-87)Page 216.3
Name of Responent This ~ort Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/04
(2) Fi A Resubmission 04/11/2008
CONSTRUCTION WORK IN PROGRESS - - ELE( TRIC (Account 107)
1. Report below descriptions and balances at end of year of projects in process of construction (107)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $100,000, whichever is less) may be grouped.
Une Description of Project Construction work in progress -
No.Electric (Account 107)
(a)(b)
1 PO AG DSR LAB EOUIPMENT-ION 176,203
2 ETGT-018, INSTALL NEW OH FEEDE 175,225
3 REL - REC HCC RELICENSING PROC 173,992
4 CITY OF KETCHUM-RELOCATE OIH T 170,977
5 L-103, AFTS-BNCK 46KV, PATROL 170,049
6 IPCOIVRY 0131 F60/2007 CABLE 169,105
7 324-COST CENTER DELIVERY CAPIT 168,860
8 IPCO-NEW FEEDER POLN 012 TO 25 168,84
9 BRIDGER 2007C105 REPL PLANT CO 168,510
10 856 COST CENTER DELIVERY CAPIT 168,428
11 458-COST CENTER DELIVERY CAPIT 168,221
12 EKRT-041 ADD PHASES, SPLIT LOA 167,743
13 378 -COST CENTER DELIVERY CAPI 165,192
14 404 COST CENTER DELIVERY CAPIT 164,052
15 BRIDGER 2007C157 U2 NEURAL NET 163,592
16 DNPR0601 INTERCONNECT 163,255
17 2007 PC PURCHASES - CAPITAL RE 162,212
18 BORA: RAS C & 0 COMMUNICATIONS 159,927
19 PERRY VANPATTEN TIME WORK ORDE 158,724
20 375 COST CENTER DELIVERY CAPIT 157,901
21 JIM BRIDGER SUBSTATION CAPITAL 156,602
22 MICRON, ADDITIONAL 3750 KVA 155,229
23 BRIDGER 2OO7C201 U4 EXCITATION 153,250
24 REPLACE UNIT TRASHRACK 153,153
25 AFTS0701 - REPL 11 AB SWITCHES 149,145
26 CRIMSON PT #5 148,621
27 584 COST CENTER DELIVERY CAPIT 148,459
28 VALLEY CLUB WEST NINE SUBD-HAI 145,683
29 UI VERSION J IMPLEMENTATION 141,328
30 T711041-HPVY 230KV DOUBLE CIR 140,499
31 210-COST CENTER DELIVERY CAPIT 136,922
32 BRIDGER 2OO7C727 REPL BOILER B 136,630
33 IPCO.PERMIT 1 PURCHASE ROW FOR 136,615
34 353 COST CENTER DELIVERY CAPIT 136,033
35 BRIDGER 2007C184 COAL SILO LIN 134,34
36 BUILD NEW DRAFT TUBE GATES FOR 134,207
37 COST CENTER 318 DELIVERY CAPIT 132,468
38 HSDL-NEW STATION 128,438
39 IPCO-NEW FEEDER POLN 011 TO GR 128,409
40 COST CENTER 329 DELIVERY CAPIT 126,228
41 RIVER ENG.SWAN FALLS RELICENSI 125,242
42 JT GREYHAWK SUB 1-L1NDER & HUB 125,110
43 TOTAL 257,589,90
FERC FORM NO. 1 (ED. 12-87)Page 216.4
Name of Respondent ThisWrtlS:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/04
(2) EjA Resubmission 0411/2008
CONSTRUCTION WORK IN PROGRESS - - ELEl TRIC (Account 107)
1. Reprt below descriptions and balances at end of year of projects in proess of construction (107)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $100,000, whichever is less) may be grouped.
Line Description of Project Construction work in progress -
No.Electric (Account 107)
(a)(b)
1 MPSN: RAS C & D COMMUNICATIONS 125,073
2 IPCO/ NMPA-019 RECONDUCTOR 1.5 124,058
3 L1NE#220 69 KV TSPQ-MTCY -2007 123,369
4 NEW UNIT 7573 - CC 848 BRET JU 122,732
5 POLE LINE SUBSTATION LAND ACQU 122,556
6 FRMT0701 - REPLACE 131H WITH A 122,521
7 345 COST CENTER DELIVERY CAPIT 121,878
8 BRIDGER 2007C197 REPL 41 FEEDW 121,740
9 IPCO-EDEN041-RELlABLlTY MAINTE 120,982
10 BOARDMAN 24554 REWIND GENERATO 120,659
11 KINPORT: RAS C & D COMMUNICATI 120,310
12 INTERWOVEN LICENSES 119,075
13 300 COST CENTER DELIVERY CAPIT 116,566
14 377 -COST CENTER DELIVERY CAPI 116,492
15 356 COST CENTER DELIVERY CAPIT 115,150
16 TERR: DC POWDER RIVER IRRIGATI 114,129
17 OXBOW FISH HATCHERY EXPANSION 114,055
18 OUT OF WARRANTY SERVER REPLACE 113,937
19 VALE-013 REBUILD 3 MI FROM R53 113,428
20 BRIDGER 2007C190 REAL TIME CON 113,247
21 IPCO/FLTP12-DAMAGE DUE TO FIRE 111,898
22 BRIDGER 2007C211 U4 CLEAN AIR 111,609
23 CEDAR CROSSING SUBD #1-117 LO 110,469
24 421-CC DELIVERY CAPITAL OVERHE 110,468
25 IPCOIRELOCATE RG60/INST NEW RE 109,681
26 CJ STRIKE: ADMIN COMPLEX 108,938
27 COST CENTER 290 DELIVERY CAPIT 108,324
28 IPCO/BOBN 042/ F1 09/2007 CABL 106,974
29 BRIDGER 2007C079 U2 REPL 10 CO 106,687
30 SPC TEST EQUIPMENT-POCATELLO 105,53
31 HOMESTEAD ROAD WORK ASSOCIATED 105,230
32 VM WARE 3.0 104,617
33 CANYON REGION MANAGER LABOR AN 104,468
34 BOARDMAN 23686 INSTALL TRAININ 104,322
35 ELKHORN SPRINGS - SUN VALLEY/103,902
36 MPSN0702 - REPLACE 230KV BREAK 103,137
37 IPCO-MCAL42 SUBSTATION GETAWAY 102,124
38 BRIDGER 2007C186 U1 MERCURY CE 101,913
39 BRIDGER 2007C188 U2 MERCURY CE 101,867
40 BRIDGER 2007C187 U3 MERCURY CE 101,867
41 BRIDGER 2007C185 U4 MERCURY CE 101,867
42 1998 NEAR EAST IDAHO VESTED I 101,493
43 TOTAL 257,589,900
FERe FORM NO.1 (ED. 12-87)Page 216.5
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/04
(2) Fi A Resubmission 04/11/2008
CONSTRUCTION WORK IN PROGRESS - - ELEe TRIC (Account 107)
1. Report below descriptions and balances at end of year of projects in process of construction (107)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Accnt 107 of the Uniform System of Accounts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $100,000, whichever is less) may be grouped.
Line Description of Project Construction work in progress -
No.Electnc (Accoun 107)
(a)(b)
1 EEM SOFTARE 101,446
2 BTLR-REPLACE FEEDER RELAYS 100,068
3 OTHER MINOR PROJECTS -13,169,367
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
3B
39
40
41
42
43 TOTAL 257,589,900
FERC FORM NO.1 (ED. 12.117 Page 216.6
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2007/04
This ~rt Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 0411/2008
ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTIUTY PLANT (Account 108)
1. Explain in a footnote any important adjustments during year.
2. Explain in a footnote any difference between the amount for book cost of plant retired, Line 11, column (c), and that reported for
electric plant in service, pages 204-207, column 9d), excluding retirements of non-depreciable propert.
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.
ine
No.
em
114,301
97,996,546
(a)
1 Balance Beginning of Year
2 Depreciation Provisions for Year, Charged to
(403) Depreciation Exense
4 (403.1) Depreciation Expense for Asset
Retirement Costs
5 (413) Exp. of Elec. PIt. Leas. to Others
6 Transporttion Exenses-Clearing
Oter Clearing Accounts
Oter Accounts (Specif, details in footnote):
Fuel Stock
TOTAL Deprec. Prav for Year (Enter Total of
lines 3 thru 9)
11 Net Charges for Plant Retired:
1 Bok Cost of Plant Retired
Salvage (Credit)
TOTAL Net Chrgs. for Plant Ret. (Enter Total
of lines 12 thru 14)
Other Debit or Cr. Items (Describe. details in
footnote):
38,671,143
10,817,357
13,131,002
36,357,498
Bok Cost or Asset Retirement Costs Retired
Balance End of Year (Enter Totals of lines 1,
10,15,16, and 18)
1,430,468,593
Steam Producion
Secion B. Balance at End of Year Acording to Functional Classificaion
43,430,501 43,430,501
Hydraulic Production-Conventional
Hydraulic Production-Pumpe Storage
Other Production
Transmission
251,n9,017
12,615,688
221,027,699
424,878,403
27 Regional Transmissio and Market Operation
2 General
29 TOTAL (Enter Total of lines 20 thru 28)
86,737,285
1,43,468,593
ci:a,. cnau Nn 1 iai:v 1 ?.n\PllnA ?1Q
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2) A Resubmission 04/111008 2007/04
FOOTNOTE DATA
rr~-~'~~~-----~-~'-~------~ ..¡Sedule Page: 219 Line No.: 14 Column: c
Relocation reimbursements, Up--ancdown~_osts and damage insurance claims
¡Schedule Page: 219 Line No.: 16 . Column: c
Accumulated Provision for ~ depreciation on Asset Retirement Obligation
Embedded removal in Accumulated Provision for Depreciation
. _ n~_____---J
$631,685.--- ~
$ (172;-522)
(848,442)
$ (1, 020,964)
I FERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)
End of 2007/04
(2) Fi A Resubmission 0411/208
INVESTMENTS IN SUBSIDIARY COMPANIES Account 123.1)
1.Report below investments in Accounts 123.1, investments in Subsidiary Compaies.
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 whethr the advanc is a note or open accunt. 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.
une Description of Investment Date Acquired Date Of Amount of .investment at
No.(a)
MaMit Beginning of Year
(b)(d)
1 Idaho Energy Resources Company
2 Common Stock -02101174 500
3 Capitl contributions 2,462,594
4 Equity in earnings 49,451,102
5
6 Subtotal Idaho Energy Resources Company 51,914,196
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 Total Cost of Account 123.1 $2,463,0931 TOTAL 51,914,196
FERC FORM NO.1 (ED. 12-89)Page 224
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)
End of 2oo7/Q4
(2) FiA Resubmission 04/11/2008
INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1) (Continued)
4. For any securities, notes, or accounts that were pledged designate such securities, notes, or accunts 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 los represented by the difference between cost of the investment (or
the oter amount at which carried in the books of account if difference from cost) and the sellng price thereof, not including interest adjustment includible
in column (f).
8. Report on Une 42, column (a) the TOTAL cost of Account 123.1
t:quit in ::uosiaiary Hevenues tor Year Amount ot investment at Gain or Loss from Investmem UneEaminWi)of Year
(f)
End lg)Year Disp~edof No.
1
500 2
2,462,594 3
4,022,911 53,474,013 4
5
4,022,911 55,937,107 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
4,022,911 55,937,107 42
PERC FORM NO.1 (ED. 12-8)Page 225
This Page Intentionally Left Blank
~
...
Name of Respondent This~rtIS:Date of Report YearlPeri of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)2007/04(2) D A Resubmission 04/11/2008 End of
MATERIALS AND SUPPLIES
1. For Account 154, report the amount of plant materials and operating supplies under the primary functional classifications as indicated in column (a);
estimates of amounts by function are acceptable. In column (d), designate the department or departents which use the class of materiaL.
2. Give an explanation of importnt 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.
Une Account Balance Balance Departent or
No.Beginning of Year End of Year Departments which
Use Material
(a)(b)(c)(d)
1 Fuel Stock (Accunt 151)15,173,831 17,267,629 Electric
2 Fuel Stock Exnses Undistributed (Account 152)
3 Residuals and Extracted Products (Account 153)
4 Plant Materials and Operating Supplies (Account 154)
5 Assigned to - Construction (Estimated)
6 Assigned to - Operations and Maintenance
7 Production Plant (Estimated)12,191,263 12,737,352
8 Transmission Plant (Estimated)8,189,143 9,429,545
9 Distributon Plant (Estimated)15,527,757 18,595,934
10 Regional Transmission and Market Operation Plant
(Estimated)
11 Assigned to - Oter (provide details in footnote)854,04 607,920
12 TOTAL Account 154 (Enter Total of lines 5 thru 11)36,762,206 41,370,751 Elecric
13 Merchandise (Account 155)
14 Other Materials and Supplies (Account 156)
15 Nuclear Materials Held for Sale (Account 157) (Not
applic to Gas Util)
16 Stores Exense Undistributed (Account 163)2,316,011 1,898,952 Elecric
17
18
19
20 TOTAL Materials and Supplies (Per Balance Sheet)54,252,04 60,537,332
FERC FORM NO.1 (REV. 12-()Page 227
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) FiA Resubmission 04/11/2008
EXTRAORDINARY PROPERTY LOSSES (Account 182.1)
Line Descrip.tion of Extraordinary Loss rotal Losses WRITTEN OFF DURING YEAR Balance at No.(Include in the description the date of Amount RecognisedC~mis~o~ Autoiiz~ion to use Acc 182.1 of Loss During Year Account Amount End of Year an peno 0 amortization (mo, yr to mo, yr).)Charged
(a)(b)(c)(d)(e)(f)
1 None
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20 TOTAL
FERC FORM NO.1 (ED. 12-8)Page 2308
Name of Respondent This wort Is:Date of Report Year/Period of Reprt
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) Fï A Resubmission 0411/2008
UNRECOVERED PLANT AND REGULATORY STUDY COSTS (182.2)
Line Description of Unrecovered Plant Total Costs WRITTEN OFF DURING YEAR Balance at No.and Regulatory Study Costs (Include Amount Recognisedin the description of costs, the date of of Charges During Year Account Amount End of Year
Commission Authorization to use Acc 182.2 Charged
and period of amortization (mo, yr to mo, yr)J
(d)(e)(f)(a)(b)(c)
21 None
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
49 TOTAL
FERC FORM NO.1 (ED. 12-8)Page 230
Name of Respondent This~rtIS:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) FiA Resubmission 0411/2008
o HER REGULATORY ASSETS (Account 182.3)
1. Report below the particulars (details) called for conc~ming other regulatory assets, including rate order docket number, if applicable.
2. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $50,000 which ever is less), may be grouped
by classes.
3. For Regulatory Assets being amortized, show period of amortization.
Line Description and Purpose of Balance at Debits CREDITS Balance at end of
No.Other Regulatory Assets Beginning of Wríen on During wolten on During Current QuarterlY ear
Current the QuartrlY ear the Period
QuartrlY ear Accunt Chargd Amount
(a)(b)(c)(d)(e)(f)
1 Asst Retirment Obligations - IPUC 11,206,05 1,613,431 230 691,422 12,188,065
2 Ordr 1129414 - OPUC Order 1104-585
3
4 L T & ST Mark to Market 1,462,637 4,36,170 244 5,656,573 171,234
5
6 Fin 48 Unfunded.Noncurrnt-IPUC Ordr 29601 7,196,711 Various 44,264,451 .37,067,740
7
8 Regulatory Unfunded Accmulated Deferred Income Tax 343,58,65 _.=22,559,94 357,913,795
9
10 PCA Deferrl Idaho - IPUC order 30047 161,34,98 75,618,247 85,731,733
11 (amort peri 6108 thru 5109)
12
13 Prior Year PCA . Idaho .IPUC order 30325 76,60,72 401 70,012,186 6,590,536
14 (amort period 6107 thru 5/08)
15
16 Idaho. Demand Side Management -IPUC order 11,34,143 401 3,242,604 8,106,539
17 1127660 (amort peri 7/98 thru 6/10)
18
19 Excess Power Deferral 06107 . IPUC ordr 2,106,816 2,106,816
20 07.555
21
22 Excess Power Amortization - OPUC Orderil06-û70 6,670,347 2,68,150 254 6,361,893 2,992,60
23 (Capp at 10% per year until full amort)
24
25 5euri Cost 2001.2002 . IPUC Order 1128975 196,825 401 196,825
26 (amort period 1/03 -12/07)
27
28 Securi Cots 2003 . IPUC Orr #28975 137,58 401 68,794 68,794
29 (amort period 1/04 -12/08)
30
31 Professonal Fees -IPUC order #2505 21,246 407 21,246
32 (Amort perid 1/03 thru 12/07)
33 .
34 IPUC Grid West loans. IPUC order 1130157 932,m 401 186,43 745,742
35 (amort period 1/07 . 12/11)
36
37 OPUC Grid West loans - OPUC Ordr 1106-483 56,007 4,40 60,407
38
39 FERC Grid West Expnse 30,117 302,117
40 FERC Docket II AC03-78.000
41
42 Unfnded SFAS 106 lia 30256 -IPUC Orer 113056 17,031,607 228 9,025,198 8,006,409
43
44 TOTAL 378,846,883 310,289,698 240,908,664 44,227,917
PERC FORM NO. 113 (REV. 02-()Page 232
Name of Respondent This~rtIS:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/04
(2) Fi A Resubmission 04/11/2008
o HER REGULATORY ASSETS (Account 182.3)
1. Report below the particulars (details) called for concarning other regulatory assets, including rate order docket number, if applicable.
2. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $50,000 which ever is less), may be grouped
by classes.
3. For Regulatory Assets being amortized, show period of amortization.
Line Description and Purpose of Balance at Debits CREDITS Balance at end of
No.Other Regulatory Assets Beginning of Wnth ott Dunng -Wrmen òtt During Curnt QuartrlYear
Current the QuartrlY ear the Period
QuarterlY ear Accunt Chargd Amount
(a)(b)(c)(d)(e)(f)
1 Excess Power Deferrd - Oregòn 2,889,117 87,806 254 2,976,923
2 OPUC Ordr 1/ 05-870
3
4 PS & I Coal Plant. Order li 257,301 401 21,442 235,859
5 (amrt peri 1012007 thru 9/10)
6 Minor itms 33,96 45,519 various 4,481 75,007
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44 TOTAL 378,84,883 310,289,698 240,90,664 44,227,917
FERC FORM NO. 1J3 (REV. 020()Page 232.1'
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04111/2008 2oo7/Q4
FOOTNOTE DATA
I$cheiii.iiipa232~~.'TJiiiiNo::.8~:.Cin:cr:.Account 282 $ (3,615,944)Account 182 (18,944,000)
_~-=..~_=- ---==-~~---=~::._=-___J
Total
~chedule Page: 232
Account 182
Account 232
$ (22, S59, 944)
Line No.: 10 Column: ci
$ (42,115,280)
(33,502,967)
._-~~---_._~-~.~-~~_.~
Total (75,618,247)
IFERC FORM NO.1 (ED. 12-87) Page 450.1
Name of Respondent This~rtIS:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) Fi A Resubmission 04/11/2008
M SCElLANEOUS DEFFERED DEBITS (Account 186)
1.Report below the particulars (details) called for conceiming miscellaneous deferred debits.
2.For any deferred debit being amortized, show period of amortization in column (a)
3. Minor item (1 % of the Balance at End of Year for Account 186 or amounts less than $50,000, whichever is less) may be grouped by
classes.
line Description of Miscellaneous Balance at Debits CREDITS Balance at
No.Deferred Debits Beginning of Year ~pc~F Amount End of YearChar
(a)(b)(c)(d (e)(f)
1 Advance prepaid coal rovalties 1,773,561 131 116,512 1,657,049
2
3 Security plan 28,102,337 2,392,108 165,426 4,574,015 25,920,430
4
5 American Falls bond refinance 264,366 401 14,552 249,814
6 (amort period 4/00 thru 7/26)
7
8 Prepaid Credit Facilty 430,723 386,177 431 176,868 640,032
9
10 Company owned life Insurance 5,952,711 810,350 131,426 1,841,761 4,921,300
11
12 American Falls water rights 18,842,991 401 1,042,008 17,800,983
13 (amort period 1/06 thru 12/25
14
15 Milner bond guarantee 11,700,000 11,700,00
16
17 Soutwest intertie proiect -6,374,574 42,437 6,417,011
18 right of way costs
19
20 CSPP receivable 652,662 143 381,895 270,767
21
22 American Falls - bond refinance 871,984 401 47,999 823,98
23 (35 year amortization)
24
25 Shelf Registration - 2008 144,517 144,517
26
27 Transmission Deposit-PacifiCofP 1,078,850 1,892,125 131 616,875 2,35,100
28
29 Prepaid Peoplesoflassoort 95,586 401 44,243 51,34
30
31 Adiustment to Unfunded Pension 46,181,245 182 46,181,245
32
33 Transmission - General Studies 342,200 5,731,573 various 6,073,773
34
35 06 Sweetter Refi Cots 1,678,248 1,651,940 181, 186 3,330,188
36 (Amor period 2-2007 to 7-2026)
37
38 Valmy Power Plant 1,128,52~various 867,551 260,973
39
40 Minor Items & Job Orders (10)46,896 206,513 various 243,530 9,879
41
42
43
44
45
46
47 Misc. Work in Progress
48 IDeferreà Reguiatory COmm.
Expenes (See pages 350 - 351)
49 TOTAL 124,388,934 73,222,183
PERC FORM NO.1 (ED. 12-9)Page 233
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2oo7/Q4
This ~ort Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmission 04111/2008
ULATED DEFERRED INCOME TAX S (Account 190)
1. Report the information called for below concerning the respondent's accounting for deferred income taxes.
2. At Other (Specify), include deferrals relating to other income and deductions.
ine
No.
ocation
(a)
Electric
Emission Allowances
Advances for Construction
12,175,361
9,211,519
13,118,190
6,920,941
10,171,998
16,363,768
TOTAL Electric (Enter Total of lines 2 thru 7)
Gas
Other
TOTAL Gas (Enter Total of lines 10 thru 15
14,416,632
117,138,886
14,873,945
106,047,151
Notes
FERC FORM NO.1 (ED. 12-88)Page 234
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2) A Resubmission 04/111008 2007/04
FOOTNOTE DATA
~ule Page:234T.iñe No.:.~...-Coiii!in: a .~_=..~
(Note 1):
Post Retiree Benefts-VEBA
Rate Case Disallowance
Othe Employee's Long Term Deferred Compensation
IRS Interest Expense
FAS 123R - Stock Based Compensation
SFAS112 - Post Retirement Benefits
Provision For Rate Refunds
Non-VEBA Pension and Benefits
Linden Feeder Deposits
Delivery Accruals
Bonus Deferrl
American Falls Fallng Water Contract
City of Eagle
Restrcted Stock Plan
Begnning Balance
$3,367,220
3,228,546
2,538,014
585,567
1,306,630
479.888
853,341
164,403
5,692
407,373
20,891
160,625
.._.==~
Ending Baiimce
$4,056,405
3,112,708
2,590,724
2,148,245
1,333,711
1,184,641
937,172
762,810
164,403
129,130
(56,182)
Total Other Electc $13,118,190 $16,363,768
¡Schedule Page: 234 Line Nõ-:~f_. cojuiiin:a=~__.______ _.____~.. ----~~__ _.- '..-==:
(Other):
FASB 109 Accunting
FAS 158 - Pension
FAS 158. Postretirement Plan
Minimum Pension LibiUty
Total Other
Beginning Balance
$41,825,257
11,263,649
10,603,161
4,525,117
$68,217,184
¡Schedule Page: 234 Line No.: 17 Column: a
(Other Non Electric):
Senior Management Security Plan
Micron-CIAC
Meridian Gold Contributions
Start-up and Organization Costs
Seattle City Light-CIAC
Loss on Pioneer Land Write-ow
Bridger Seirr Reserve-Legal Fees
Total Non Electrc
Beginning Balance
$11,842,893
2,239,495
196,904
75,447
16,542
45,351
$14,416,632
Ending Balance
$42,967,558
3,815,138
6,616,914
4,316,889
$57,716,499
----~:J
Ending Balance
$12,554,517
2,001,223
174,791
324
45,351
97,739
$14,873,945
IFERC FORM NO.1 (ED. 12-87) Page 450.1
Name of Respondent This 'ìrt Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) Fi A Resubmission 04/11/2008
CAPITAL STOCKS (Account 201 and 204)
1. Report below the particulars (details) called for concerning common and preferred stock at end of year, distinguishing separate
series of any general class. Show separate totals for common and preferred stock. If information to meet the stock exchange reporting
requirement outlined in column (a) is available from the SEC 10-K Report Form filng, a specific reference to report form (Le., year and
company title) may be reported in column (a) provided the fiscal years for both the 10-K report and this report are compatible.
2. Entries in column (b) should represent the number of shares authorized by the articles of incorporation as amended to end of year.
Line Class and Series of Stock and Number of shares Par or Stated Call Price at
No.Name of Stock Series Autorized by Charter Value per share End of Year
(a)(b)(c)(d)
1 Account 201
2 Common Stock registered on New York 50,000,000 2.50
3 and Pacific Stock Exchange
4 Total Common Stock 50,00,000 2.50
5
6 Account 204 - None
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. 12-91)Page 250
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da. Yr)End of 2007/Q4
(2) Ei A Resubmission 04/111008
CAPITAL STOCKS (Account 201 and 204) (Continued)
3. Give particulars (details) concerning shares of any class and series of stock authorized to be issued by a regulatory commission
which have not yet been issued.
4. The identification of each class of preferred stock should show the dividend rate and whether the dividends are cumulative or
non-cumulative.
5. State in a footnote if any capital stock which has been nominally issued is nominally outstanding at end of year.
Give particulars (details) in column (a) of any nominally issued capital stock, reacquired stock, or stock in sinking and other funds which
is pledged, stating name of pledgee and purposes of pledge.
OUTSTANDING PER BALANCE SHEET HELD BY RESPONDENT Line
(Total amount outtanding wihout reduction AS REACQUIRED STOCK (Account 217)IN SINKING AND OTHER FUNDS No.for amounts held by respondent)
Sl1ares Amount ::Ilares ~!lst . Sh¡ues Amount
(e)(f)(g)(h)(i)OJ
1
39,150,812 97,8n,030 2
3
39,150,812 97,8n,030 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. 12-8)Page 251
Name of Respondent This (!0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/04
(2) Ei A Resubmission 04/11/200
OTHER PAID-IN CAPITAL (Accounts 208-211, inc.)
Report below the balance at the end of the year and the information speified below for the repective 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 reconcilation 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 entnes 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 wi the class and series of stock to which related.
(c) Gain on Resale or Cancellation of Reacquired Capitl Stock (Accunt 210): Reprt balanc at beinning 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 senes of stock to which related.
(d) Miscellaneous Paid-in Capital (Account 211 )-Classif amounts included in this accunt according to captions which, together with brief explanations,
disclose the general nature of the transactions which gave rise to the reported amounts.
~e ii~r A"?unto.
1 Account 208 - Donations received from stockholders
2
3 Account 209 - Reduction in par or stated value of Capital Stock
4
5 Account 210 - Gain on reacquired Capital Stock
6
7
8 Account 211 - Miscellaneous paid-in Capitl
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 TOTAL
FERC FORM NO.1 (ED. 12-87)Page 253
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/04
(2) Fi A Resubmission 04/11/2008
CAPITAL STOCK EXPENSE (Accunt 214)
1. Report the balance at end of the year of discount on capital stock for each class and series of capital stock.
2. If any change occurred during the year in the balance in respect to any class or series of stock, attach a statement giving particulars
(details) of the change. State the reason for any charge-off of capital stock expense and specify the account charged.
Une ciass ana series of Stock Balance at Ena Of Year
No.(a)(b)
1 Common Stock 2,096,925
2
3
4
5
6
7
8
9
10 Exlanation of Changes during the year:
11
12
13
14
15
16
17
18
19
20
21
22 TOTAL 2,09,925
FERe FORM NO.1 (ED. 12-87)Page 254b
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/04
(2) Fi A Resubmission 0411112008
LONG-TERM DEBT (Account 221, 222, 223 and 224)
1. Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds, 222,
Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt.
2. In column (a), for new issues, give Commission authorization numbers and dates.
3. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
4. For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate
demand notes as such. Include in column (a) names of associated companies from which advances were received.
5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
6. In column (b) show the principal amount of bonds or other long-term debt originally issued.
7. In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
8. For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
Indicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted.
9. Fumish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year. Also, give in a footnote the date of the Commission's authorization of treatment other than as
specified by the Uniform System of Accounts.
Una Class and Series of Obligation, Coupon Rate Principal Amount Total expense,
No.(For new issue, give commission Authorization numbers and dates)Of Debt issued Premium or Discount
(a)(b)(c)
1 Account 221:
2 First Mortgage Bonds:
3 5.50% Series due 2033 70,000,000 728,701
4 36,400 D
5
6 7.38% Series Due 2007 80,000,000
7
8 7.20% Series due 2009 80,000,000 572,246
9
10 5.30% Series Due 2035 60,00,000 408,411 D
11 3,844,739
12
13 6.60% Series due 2011 120,000,000 860,502
14
15 4.25%Series due 2013 70,000,000 641,201
16 374,500 D
17
18 4.75% Series due 2012 100,000,000 94,356
19 1,047,617 D
20
21 6.00% Series due 2032 100,000,00 1,069,356
22 543,244 D
23
24 5.875% Series due 2034 55,000,000 585,759
25 383,322 D
26
27 5.50% Series due 2034 50,000,000 746,961 D
28 524,419
29
30 6.30% Series due 2037 )IPUC IPC-E-07-06 1,495,799
31 OPUC UF 4238 WPSC 2005-3G-ES-7)273,721 D
32
33 TOTAL .987,04,000 19,666,627
FERC FORM NO.1 (ED. 12-96)Page 256
Name of Respondent This~rtIS:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/04
(2) ñ A Resubmission 04/11/2008
LONG-TERM DEBT (Account 221, 222, 22 and 224) (Continued)
10.Identify separate undisposed amounts applicable to issues which were redeemed in pnor years.
11. Explain any debits and credits other than debited to Account 428, Amortization and Expnse, 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 dunng year, (b) interest added to principal amount, and (c) principle repaid
dunng year. Give Commission authorization numbers and dates.
13. If the respondent has pledged any of its long-term debt seurities 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). Expiain 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) conceming any long-term debt authorized by a regulatory commission but not yet issued.
AMORTIZATION PERIOD uintançil'r Une
Nominal Date Date of (Total amount outsta ing without Interest for Year No.
of Issue Maturity Date From Date To reduction for amount tield by Amount
(d)(e)(f)(g)
respymtent)
(i)
1
2
05101/03 04101/33 05/01/03 0331133 70,000,000 3,850,000 3
4
5
12/1/00 12/01/07 12/01/00 12/01/07 5,439,510 6
7
11/23/99 12/01/09 01/01100 01/01110 80,000,00 5,760,00 8
9
0826/05 08126/35 08126/05 08/26/35 60,000,000 3,180,00 10
11
12
03/02/01 03/02/11 03/02/01 03/02/11 120,000,000 7,920,000 13
14
05101/03 10/01/13 05101/03 09/29/13 70,OOO,OOC 2,975,000 15
16
17
11/15102 11/15112 11115102 11/15112 100,OO,OOC 4,750,000 18
19
20
11/15102 11/15/32 11/15102 11115132 100,000,000 6,000,000 21
22
23
08116/04 08116/34 08116/04 08116/34 55,oo,OÒ 3,231,250 24
25
26
0316/04 03/15134 03/26/04 0315/34 50,000,000 2,750,000 27
28
29
6/22/07 6/1512037 6/22/07 6/15/2037 140,000,000 4,630,500 30
31
32
1,145,981,364 58,097,082 33
FERC FORM NO.1 (ED. 12-9)Page 257
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) Fi A Resubmission 0411112008
LONG-TERM DEBT (Accunt 221, 222, 223 and 224)
1. Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds, 222,
Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt.
2. In column (a), for new issues, give Commission authorization numbers and dates.
3. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
4. For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate
demand notes as such. Include in column (a) names of assiated companies from which advances were received.
5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
6. In column (b) show the principal amount of bonds or other long-term debt originally issued.
7. In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
8. For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
Indicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted.
9. Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year. Also, give in a footnote the date of the Commission's authorization of treatment other than as
specified by the Uniform System of Accounts.
Line Class and Series of Obligation, Coupon Rate Prncipal Amount Total expnse,
No.(For new issue, give commission Authoriztion numbers and dates)Of Debt issued Premium or Discount
(a)(b)(c)
1 6.25% Series due 2037 ( IPUC IPC-E-06-28 1,141,489
2 OPUC UF 4211 WPSC 20oo5-ES-4-27)266,188 D
3
4 Series 96B due 2026
5
6 Port of Morrow Variable due 2027 4,360,000 188,545
7
8 Humboldt Variable due 2024 49,800,000 1,697,856
9
10 Sweetwater Variable due 2026 116,300,000 820,043
11 471,252 D
12 Subtotal Account 221 955,460,000 19,66,627
13
14 Account 224:
15 Bond Guarantee - American Falls 19,885,000
16
17 REA Notes
18
19 Note Guarantee - Milner Dam 11,700,000
20
21 Subtotal Account 224 31,585,000
22
23 Accunt 222: Required Bonds
24 Account 223: Advances for Associated Companies
25
26
27
28
29
30
31
32
33 TOTAL 987,045,000 19,666,627
FERC FORM NO.1 (ED. 12-9)Page 256.1
Name of Respondent ThiS~rtIS:Date of Report YearlPeriod of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/04
(2) Fi A Resubmission 04111/2008
LON 3-TERM DEBT (Account 221, 222, 22 and 224) (Continued)
10.Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term
advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13. If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose of the pledge.
14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of
year, describe such securities in a footnote.
15. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on
Long-Term Debt and Account 430, Interest on Debt to Associated Companies.
16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
AMORTIZATION PERIOD Outstaf1CJins Line
Nominal Date Date of (Totl amount outstan ing without Interest for Year No.
of Issue Matunty Date From Date To reduction for amounts held by Amount
(d)(e)(f)(g)
respYR,dent)
(i)
10118107 101151037 10118107 10/1512037 100,000,000 1,267,361 1
2
3
07/25196 07/15/26 07/25196 07/15126 596 4
5
05117/00 02/01/27 05117/00 02/01/27 4,360,000 175,605 6
7
10/22/03 12/01/24 11/01/03 12/01124 49,800,000 1,833,848 8
9
10/3106 7115/26 10/3/06 711512026 116,300,000 4,333,551 10
11
1,115,460,000 58,097,221 12
13
14
0426/00 2/1125 19,885,60(15
16
-139 17
18
0210/92 10,636,36'19
20
30,521,364 -139 21
22
23
24
25
26
27
28
29
30
31
32
1,145,981,364 58,097,082 33
FERC FORM NO.1 (ED. 12-96)Page 257.1
Name of Respondent ThisWrtlS:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) ¡= A Resubmission 04111/2008
RECONCILIATION OF REP( RTED NET INCOME WITH TAXABL INCOME FOR FEDERAL INCOME TAXES
1. Report the reconcilation of reported net income for the year wit table incme used in computing Federal income tax accruals and show
coputtion of such tax accruals. Include in the reconcilation, as far as practicable, the same detail as furnished on Schedule M-l 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 reconcilng amount.
2. If the utilit is a member of a group which files a consolidated Federal tax return, reconcile reported net income with taxable net income as if a
separate return were to be field, indicating, however, intercompany amounts to be eliminated in such a consolidated return. State names of group
member, tax assigned to each group member, and basis of allocation, assignment, or sharing of the consolidated tax among the group members.
3. A substitute page, designed to meet a particular need of a company, may be used as Long as the data is consistent and meets the requirements of
the above instructions. For electronic reporting purposes complete Line 27 and provide the substitute Page in the context of a footnote.
LIne particuiars. (DetailS)Amount
No.(a)(b)
1 Netlncome for the Year (Page 117)76,579,025
2
3
4 Taxable Income Not Reported on Books
5 See Footnote
6
7
8
9 Deductions Recrded on Books Not Deducted for Return
10 See Foonote
11
12
13
14 Income Recorded on Books Not Included in Return
15 See Footnote f
16
17
18
19 Deducions on Return Not Charged Against Book Income
20 See Footnote
21
22
23
24
25
26
27 Federal Tax Net Income 27,101,941
28 Show Coputtion of Tax:
29 rrenative Federal Tax ~ 35%9,485,679
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
FERC FORM NO.1 (ED. 12-9)Page 261
This Page Intentionally Left Blan
~
.~
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2) A Resubmission 04/111008 2oo7/Q4
FOOTNOTE DATA
fSéicile Page:'.'-u-Ifne No.: 5 ._.Co¡unin~b--==_~~~:m.._-__-------"----..._:m. .__=--==~J004003-CONSTRUCTION ADV-252 2,917,340
004004-CIAC AS TAXBLE INC CLOSED TO PLANT 30,000,000004005-AVOIDED COST INT CAP 6,539,451
00401 O-EMISSION ALLOWANCE-254.409-411 (13,440,132)
004013-CIAC AS TAXBLE INC IN ACCT 107 9,469,354
004020-ENGINEERING FEES-CLOSED TO PLANT 1,632,541
004021-ENGINEERING FEES-IN AGCT 107-FED ONLY (12,267)004501-ROYALTY INCOME BTL 100,000004506-CIAC-MERIDIAN GOLD (56,560)004507-CIAC-MICRON-DRAM (608,470)004512-CIAC-SEATTLE CITY LIGHT (41,482)Total 36,559,775
I ._~---~--_.~---_.Schedule Page: 261 Line No.:. 10_._ Column: b ____
Total Federal and State taxes deducted on books
005001-BAD DEBT EXPENSE
005008-GAIN/LOSS ON REACQUIRED DEBT-DEFERRED
005010-SFAS 112-POST -EMPL Y BEN 182/253
005014-0VERACCRUED VACATION-ACCT 242
005017-INJURIES & DAMAGES
005019-DIRECTORS FEES DEF
005022-GAPITALIZED OVERHEADS
005023-PENSION ACCR TO 926200
005024-MEALS (50% NON-DEDUCTIBLE) CHRGD TO R.E.
005025-MILNER FALLING WATER - REV AGCRL
005027 -AMORTIZATION OF ACCOUNT 114
005028-0REGON OPER PROPERTY TAX ADJ
005033-NONVEBA PEN&BEN-Acct 228
005035-PCA EXPENSE DEFERRAL
005043-AMERICAN FALLS - FALLING WATER CONTRACT-FT
005047-0THER EMPLOYEE'S L T DEFERRED COMP-228
005050-186-BAD DEBT RESERVE-FINANCING PRGMS
005051-PUG ORDER 29505 - PROFESSIONAL FEES
005052-AMORTIZATION OF ACCOUNT 181
005053-FAS 123R-STOCK BASED COMPENSATION
005054-IPUC GRID WEST LOANS-ACCT 182
005055-0PUC GRID WEST LOANS-ACGT 182
005057 -INTERVENOR FUNDING ORDERS-ACCT 182
005058-FIXED COST ADJUSTMENT (FCA)-ACCT 182
005059-PS & I COSTS-COAL & CHP PLANTS-WRITE OFF
005501-SEC PLAN-NET INS COSTS
005503-128-EDC-UNRLZD GN/LS FRM RABBI TRUST
005504-NONDEDUCTIBLE POLITICAL EXP-426.4
005505-SEC PLAN-BENEFIT ACCR
005510-FINES & PENALTIES-OPERATING-CHRGD TO R.E.
005516-NONDEDUCTIBLE POLITICAL EXP-O&M ACCTS
005531-RA TE CASE DISALLOWANCES-REVERSE AMORT
005532-DELIVERY ACCRUALS-253.550
005536-VEBA INCOME TAXES
005537-BRIDGER SIERRA RESERVE-LEGAL FEE'S-228.4
Total
_ _~ -- - -- ~-_~J
34,697,263
336,985
504,035
(312,031)
420,187
353,982
287,447
(12,000,000)
2,919,438
500,000
(714,918)
(22,723)
(4,018)
(231,565)
(97,251,403)
1,042,009
134,829
(1,706)
21,246
92,448
1,408,339
186,435
(4,400)
(52,604)
2,145,403
(258,262)
(254,430)
20,683
895,713
1,820,242
669,811
100,000
(296,299)
158,786
8,200
250,000
(62,430,878)
I FERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
Idaho Power Company I (2) A Resubmission 04/11/2008 20071Q4
FOOTNOTE DATA
~hedule Page: 261' LineNO.:~Column:-b __~-~=:=~= -~==-=-==-~-=:_-:===~= ...-==:----1
007009-PROVISION FOR RATE REFUNDS-ACCT 229 (1,169,674)
007501-REVERSE EQUITY EARNINGS OF SUBSIDIARIES 4,022,911007502-ALLOWANCE FOR OFUDC 5,995,175007503-ALLOWANCE FOR BFUDC 7,597,141
007509-SECURITY PLAN-INSURANCE PROCEEDS 1,202,946007514-COLl-INSURANCE PROCEEDS 368,625007518-IRS INTEREST INCOME 388,588Total 18,405,712
¡Schedule Page: 261 Line No.: 20 '.. Column:¡'~--~~____________,~__-=- ~___J
008001-VEBA-POST RET BNFTS-TRUST-ACCT 228 (1,762,847)
008009-DEPR FOR TAX GT OR LT BOOK (5,258,723)
008016-VEBA-POST RET BNFTS-TRUST-MEDICARE PART D 803,000008020-CONSERVATION PROGRAMS (3,242,604)008025-MANUFACTURING DEDUCTION 1,116,887
008027-NEVADA OPERATING PROPERTY TAX ADJ 7,262008034-REMOVAL COSTS 10,819,971008035-REPAIR ALLOWANCE 7,000,000
008038-0REGON EXCESS PWR SUPPLY COSTS (3,571,969)
008039-ST TAX-NOT DEDUCTED ON PRIOR RETURN 207,179
008041-AM FALLS - UNAMORTIZED DEBT EXP (47,999)
008042-GAIN/LOSS ON REACQUIRED DEBT-FT (707,798)
008059-SFTWR COSTS-MISC-1 07 -FED ONLY 1,000,000
008072-INTANGIBLE ASSET-LABOR DEDUCT -1 07-FED ONLY 2,700,000
008074-INCREMENTAL SECURITY COSTS DEDUCTED (265,619)
008071-PP INS & OTR EXP (1 YR OR LESS)-165 52,662008501-COLl-TAXADJ FROM BOOKS (1,005,148)
008504-0REGON NONOP PROPERTY TAX ADJUST (1,218)008508-DEPR ADJ - NONOP - OTHER PROPERTY - NEW 3,887
008702-FAS123R RESTRICTED STOCK DIVIDENDS 354,425ONI0016-D1V PAID DED PUB UTIL 300,000IRS INTEREST EXPENSE 1,008,190
STATE INCOME TAX DEDUCTED ON FEDERAL RETURN (4,309,269)Total 5,200,269
I FERC FORM NO.1 (ED. 12-87)Page 450.2
Name of Respondent This mort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) ri A Resubmission 0411/2008
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
1. Give particulars (details) of the combined prepaid and accrued ta accounts and show the total taes 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 subivision can readily be ascertained.
,..ine Kind of Tax BALANCE AT BEGINNING OF YEAR ~~es le~~Adjust-C argedNo.(See instruction 5)Taxes Accrued ~repala i axes ~ring ~ring ments
(Account 236)(Include in Account 165)ear ear
(a)(b)(c)(d)(e)(f)
1 Federal:
2 Income 24,271,360 -21,881,577 5,165,847
3 Social Securi - (FOAB)381,573 10,995,817 10,960,220
4 Unemployment 39,547 126,114 122,638
5 Subtotal Federal 24,692,480 -10,759,646 16,248,705
6
7 State of Idaho:
8 Propert 4,744,361 75 10,029,025 9,053,722
9 Income 7,546,331 -14,226,720 -5,218,719
10 KWH 92,992 1,490,284 1,282,559
11 Unemployment 18,600 231,339 230,218
12 Regulatory Commission 1,599,171 1,599,171
13 Business License - Sho Ban 150 150 150
14 Subtotal Idaho 12,402,284 225 -876,751 6,947,101
15
16 State of Oregon
17 Propert 1,003,085 2,010,673 2,014,692
18 Non-Operating Propert 1,937 2,655 1,437
19 Income 928,546 -924,316 71,171
20 Regulatory Commission 109,195 109,195
21 Unemployment 1,474 16,603 17,178
22 Franchise 126,401 505,272 506,460
23 Subtotal Oregon 1,056,421 1,005,022 1,720,082 2,720,133
24
25 State of Montana:
26 Propert 49,639 93,297 96,518
27 Subtotal Montana 49,639 93,297 96,518
28
29 State of Nevada:
30 Propert 411,955 870,048 877,309
31 Business Tax 100 100
32 Subtotal Nevada 411,955 870,148 877,409
33
34 State of Wyoming
35 Corprate License 2,911 2,911
36 Propert 514,075 956,616 992,383
37 Subtotal Wyoming 514,075 959,527 995,294
38 cnher States Incoe 1,510,858 -1,510,694 1,515
39 Payroll Adjustment -11,369,873
40
41 TOTAL 40,225,757 1,417,202 -20,873,91 Q 27,886,675
FERC FORM NO.1 (ED. 12-96)Page 262
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) Fi A Resubmission 04/11/2008
TAXES ACel UED, PREPAID AND CHARGED DU ING YEAR (Continued)
5. If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year,
identifying the year in column (a).
6. Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments
by parentheses.
7. Do not include on this page entries with respect to deferred incoe taxes or taxes collected through payroll deductions or otherwise pendin
transmitl of such taxes to the taxing authority.
8. Report in columns (i) through (I) how the taxes were distributed. Report in column (I) only the amounts charged to Accounts 408.1 and 409.1
pertaining to electric operations. Report in column (i) the amounts charged to Accounts 408.1 and 109.1 pertaining to other utilty departments and
amounts charged to Accounts 408.2 and 409.2. Also shown in column (i) the taxes charged to utilty plant or other balance sheet accounts.
9. For any tax appoioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Line
(Taxes accrued Prepaid Taxes Electric Extraordinary Items AdjUstments to Ret.Other No.
ACCO~8J 236)(Incl. in Account 165)(Account 408.1, 409.1)(Account 409.3)Earnings (Account 439)
(h)(i)OJ (k)(i)
1
-2,776,06 6,214,288 -29,821,53~
417,170 10,995,817 3
43,023 126,114 4
-2,315,871 17,336,219 -29,821,538 1,725,673 5
6
7
5,719,815 225 9,995,700 ~-1,461,670 -6,449,912 -8,119,462 9
300,717 1,490,284 10
19,721 231,339 11
1,599,171 12
150 150 13
4,578,583 375 6,866,732 -8,119,462 375,979 14
15
16
1,007,104 2,008,018 ~719 2,655 18
-66,941 4,774 -946,512 19
109,195 20
899 16,603 21
125,213 505,272 22
59,171 1,007,823 2,64,517 -94,512 20,077 23
24
25
46,418 93,297 26
46,418 93,297 27
28
29
419,217 870,048 30
100 31
419,217 870,148 32
33
34
2,911 35
478,308 956,616 36
478,308 959,527 37
-1,351 -127,413 -1,389,090~
-11,369,873 39
40
2,845,258 1,427,415 17,275,154 -40,276,602 2,127,538 41
FERC FORM NO.1 (ED. 12-9)Page 26
This Page Intentionally Left Blank
,-~
.~
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo. Da. Yr)
Idaho Power Company (2) A Resubmission 04/11/2008 20071Q4
FOOTNOTE DATA
rscheduleJiage: 262.' .. iineNo.:2COïumn:1 .
Account 409.2 $1~749,032234 (23,359)
----~----~::~~_=_=~===_=__=__J
Total $1,725,673
-l
____ --- ___==
rScheduie Page: 262Account 408.2
fSule Page: 262Account 409.2
234
Line No.: 8 Column: j
$ 33,325
Line No.: 9 Column: i
$ 346,857
(4,203)
Total $ 342,654
~---------Scedule Page: 262 _Account 408.2
rsedule Page: 262Account 409.2
234
Column: iLine No.: 17
__i__ 2,655
Line No.: 19
$ 17,636
(214 )
-J
-~----==~---~-~Column: i
Total $ 17,422
¡sule Page: 262 __ Line No.: 38 Column: iAccount 409.2 $ 5,880234 (71)_-=
Total $ 5,809
r¡cheiiie Page: 262 Line No.: 40 Column: i --------- . -_.-----1
This footnote is 'for the total of Column I. The total of column I should total back to the
sum on lines 14, 15 & 16 on page 114 column C. For the year 2007 this cross-check will not
work as the total on lines 14-16 on page 114 is $3,586,298 higher. This amount represents
an amount booked for the accounting of Fin #48. When FIN #48 is booked it does use account
409.1 however it does not use account 236. Therefore it will show up on page 114 but not
on pages 262 and 263.
I FERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) ñ A Resubmission 04111/2008
ACCUMULA ED DEFERRED INVESTMENT TAX REDITS (Accunt 255)
Report below information applicable to Account 255. Where appropriate, segregate the balances and transactions by utilty and
non utilty 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.,
i,-ine Account Balance at Beginning Deferred for Year AiiocatiOns to
No.SUbdlxlsions of Year Current Year's Income Adjustments~(c) (d) (e) (f) g
1 Electric Utilty
23%
::4%1,232,965 152,17E
A 7%
E 10%32,350,078 1,875,091
E 11%1,374,592 27,08f
7 Other State 34,155,507 411.4 5,465,795 411.4 l,523,86E
E TOTAL 69,113,142 5,465,795 3,578,22E
9 Other (List separately
and show 3%, 4%, 7%,
10% and TOTAL)
10 Line 6 Col A 11%
11
12 State of Idaho 34,155,507 411.4 5,465,795 411.4 1,523,86E
13
14
15
16 .
17
18
19
20
21
22
23
24
25
26
27
2E
3C
31
32
3:
3"
3E
3E
3i
3f
36
4C
41
4::
4:
44
4E
4E
4i
48
FERC FORM NO.1 (ED. 12-89)Page 266
Name of Respondent ThiS~port Is:Date of Report Year/Period of Report
Idaho Power Company (1)An Original (Mo, Da, Yr)End of 2007/04
(2)A Resubmission 04/11/2008
ACCUMULATED 0 FER RED INVESTMENT TAX CRED S (Account 255) (continuéd)
~ADJUSTMENT EXPLANATION Lineof Year of AI ocation No.to Incomeh i -
1
2
1,080,787 8.10 3
4
30,474,981 17.25 5
1,347,507 50.75 6
38,097,436 22.41 7
71,000,711 8
9
10
11
38,097,436 12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
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
This Page Intentionally Left Blan
.V
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) Ei A Resubmission 04/11/2008
o HER DEFFERED CREDITS (Account 253)
1.Report below the partculars (details) called for concerning '?ther 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.
Une Description and Other Balance at DEBITS Balance at
No.Deferred Credits Beginning of Year Contra Amount Credits End of Year
(a)(b)
Account
(c)(d)(e)(f)
1 Bureau of Land Mngt RentsROW 5,129,477 107 758,017 804,524 5,175,984
2
3 Point to Point Transmission Study 509,930 232,253 2,890,341 6,642,869 4,262,458
4
5 FT 5,066,666 454 400,639 1,000,000 5,666,027
6
7 Linden Feeder 420,523 420,523
8
9 SWIP Deposit 1,000,000 500,000 1,500,00
10
11 City of Eagle 53,437 232 186,181 132,744
12
13 Fin 48 Various 13,896,564 4,726,583 -9,169,981
14
15 Fin 48 Interest 431 1,113,132 311,082 -802,050
16
17 Sho Ban Trans ROW 315,00 242 7,500 307,50
18
19 Delivery Accruals 19,308 253 693,251 932,375 258,432
20
21 Customer Level Pay 2,028,970 142 1,959,997 1,757,662 1,826,635
22
23 US Airforce Photovoltaic Generator 244,147 44,591 288,738
24
25 Securit Plan 24,675,204 228 29,861,039 5,185,83
26
27 Milner Fallng Water 3,721,057 34,719 4,069,776
28
29 Postretirement Benefits 3,342,191 926 312,031 3,030,160
30
31 Directors Deferred Compensation 3,716,793 232 289,911 577,359 4,004,241
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47 TOTAL 50,242,703 52,368,603 22,96,34 20,838,44
FERe FORM NO.1 (ED. 12-9)Page 269
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2oo71Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/11/2008
ACCUMULATED DEFERRED INCOME TAXES - ACCELERATED AMORTIZATION PROPER (Account 281)
1. Report the information called for below concerning the respondent's accounting for deferred income taxes rating to amortizable
propert.
2. For other (Specify),include deferrals relating to other income and deductions.
CHANGES DURING YEAR
Une
No.
Account Balance at
Beginning of Year Amounts Debited
to Account 410.1
(c)
Amounts Credited
to Account 411.1
(d)(a)
1 Accelerated Amortization (Account 281)
2 Electric
3 Defense Facilities
4 Pollution Control Facilties
5 Other (provide details in footnote):
6
7
8 TOTAL Electric (Enter Total of lines 3 thru 7)
9 Gas
10 Defense Facilities
11 Polluton Control Facilties
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 Loal Income Tax
(b)
NOTES
FERC FORM NO.1 (ED. 12-9)Page 272
Name of Respondent
Idaho Power Company
ACCUMULATED DEFERRED INCO
3. Use footnotes as required.
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/11/2008
E TAXES _ ACCELERATED AMORT ZATION PROPERTY (Account 281) (Continued)
Year/Period of Report
End of 2007/Q4
CHANGES DURING YEAR
Amounts Debited Amounts Credited
to Account 410.2 to Account 411.2
ADJUSTMENTS
Amount
Balance at
End of Year
Line
No.Debits
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
NOTES (Continued)
FERC FORM NO.1 (ED. 12-9)Page 273
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2007/Q4
This ~rt Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmission 04111/2008
ACCUMULATED DEFFERED INCOME TAXES - OT ER PROPERTY (Account 282)
1. Report the information called for below concerning the respondent's accounting for deferred income taxes rating to propert not
subject to accelerated amortization
2. For other (Specify),include deferrals relating to other income and deductions.
CHANGES DURING YEAR
Line
No.
Account Balance at
Beginning of Year Amounts Debited
to Account 410.1
(c)
Amounts Credited
to Account 411.1
(d)(a)(b)
1 Account 282
2 Electric
3 Gas
4 Other
5 TOTAL (Enter Total of lines 2 thru 4)
6 Non-Operating Propert
7 Other - FASB 109
8
9 TOTAL Account 282 (Enter Total of lines 5 thru
10 Classification of TOTAL
11 Federal Income Tax
12 State Income Tax
13 Locl Income Tax
230,117,962 5,401,035 8,426,116
230,117,962
243,44
34,589,653
5,401,035 8,426,116
573,951,058 5,401,035 8,426,116
485,101,346
88,849,712
5,375,340
25,695
8,426,116
NOTES
FERC FORM NO.1 (ED. 12-9)Page 274
Name of Respondent
Idaho Power Company
This F30rt Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmission 04/1112008
E TAXES - OTHER PROPERTY (Account 282) (Continued)
Year/Period of Report
End of 2007/Q4
ACCUMULATED DEFERRED INCO
3. Use footnotes as required.
CHANGES DURING YEAR
Amounts Debited Amounts Credited
to Account 410.2 to Account 411.2
ADJUSTMENTS
Amount
Balance at
End of Year
Line
No.Debits
NOTES (Continued)
ÆRC FORM NO.1 (ED. 12-9)Page 275
This Page Intentionally Left Blan
,--=
."T
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2) A Resubmission 04/111008 2007/04
FOOTNOTE DATA
ISliëdu/e eiiie:27-liio~T- Colúmn:IC--" --~===~_ -==-=~~_____---~__====-==-~-=l
Page 274 & 275 - Accumulated Deferred Income Taxes - Other
Proøert (Account 282)
Changes duóng Year
I
Adjustments I Adjustments I
I2,007 Debits Credits 2,007
Beginning DR to CR to DR to CRto Acct.Acct.Ending
Line Account Balance 410.1 411.1 410.2 411.2 CR.Amt dr.Amount Balance
No.(a)b c d e f a h i i k
Line Accelerated Depreciation
12:219,454,281 3,898,285 8,235,357 215,117,209
Intangible Asset-Labor
Deduction 11,327,736 924,761 12,252,496
FERC Juósdictional
7,818,502 7,818,502
N. Valmy
733,766 76,500 657,266
Bódger
222,457 102,400 120,057
Engineering Fees in Acct
107 (35,263)4,293 11,859 (42,828)
Misc Softre Develop
Costs (2,565,535)3,443,205 877,670
Taxable CIAC in CWIP -
Bal.(6,837,9&2)(2,869,509\(9,707,491 \
TOTAL Line 2 0.00 0.00 0.00
230,117,961 5,401,035 8,426,116 -227,092,881
IFERC FORM NO.1 (ED. 12-S7) Page 450.1
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2007/Q4
This ~ort Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmission 0411/2008
ACCUMULATED DEFFERED INCOME TAXES - OTHER (Accunt 283)
1. Report the information called for below concerning the respondent's accounting for deferred income taxes relating to amounts
recorded in Account 283.
2. For other (Specify),include deferrals relating to other income and deductions.
1 Account 283
(a)
Balance at
Begnning of Year
(b)
Line
No.
Account
5
6
7
9 TOTAL Electric (Total of lines 3 thru 8)
10 Gas
11
12
13
14
15
16
17 TOTAL Gas (Total of lines 11 thru 16)
18
19 TOTAL (Acct 283) (Enter Totai of lines 9,17 and 18)
20 Classification of TOTAL
21 Federal Income Tax
22 State Income Tax
23 Local Income Tax
352,332
27,44,632
5,303,300
30,739,892
5,905,209
1,838,745
384,559
NOTES
FERC FORM NO.1 (ED. 12-96)Page 276
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2007/Q4
This ~ort Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmission 04111/2008
ACCUMULATED DEFERRED INCOME TAXES - OTHE (Account 283) (Continue
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.
ADJUSTMENTS
Line
No.
47,920,162
11,586,798
11,586,798
7,309,437
55,229,599
120,655
23,178
33,787
6,491
9,719,643
1,867,155
46,712,00
8,973,482
NOTES (Continue)
FERC FORM NO.1 (ED. 12-96)Page 277
This Page Intentionally Left Blank
-=
.-n
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2) A Resubmission 04/111008 2007/Q4
FOOTNOTE DATA
~--~---~~_. --~_. ~.._----_. --_._-~-~Schedule Page: 276 Line No.: 3 Column: a
Page 276 & 277 - Accumulated Deferred Income Taxes. --
-----1
Other (Account 283)
Changes dunng Year Adjustments Adjustments
2,007 Debits Credits 2,007
Beginning DR to CRto DR CRto Acct.Acc.Ending
to
Une Account Balance 410.1 411.1 410.2 411.2 or Amount dr Amount Balance
No.(a)b c d e f a h i i k
Line 3:PCA Expnse Deferrl 4,646,703 36,956,236 (1,064,201)
42,667,139
Conseration Programs 4,436,949 0 1,267,697
3,169,251
Oregon Excess Power 3,737,272 (444,523)951,938
Costs 2,340,811
IPUC Gnd West Loans 364,435 0 72,887
291,548
Loss on Reacquired Debt 197,052 0 197,053
0
Incremental Secunty 130,739 0 103,84
Costs 26,895
FERC Gnd West 118,113 0 0
Expense 118,113
OPUC Gnd West Loans 21,896 1,720
23,616
Prof Fees - IPUC Order 8,306 0 8,306
29505 -
Intervenor Funding 0 20,566 0
Order 20,566
Fixed Cost Adjustment 0 0 838,745
(838,745)
PS & I Costs - Coal &
CHP Plants-Wnte Of 0 111,102 10,135 100,96
FERC order 144a (163,100)(163,100)-
TOTAL Line 3 -
13,498,365 36,64,101 2,223,304 .--47,920,162
Schedule Page: 276 Line No.: 8 Column: a
--_...-.-_..__._._,----._-
11,263,649 -190 7,448,512 190Line 8:FAS 158 - Pension -3,815,138
FAS 158 - Postrtirement 6,790,908 186/190 3,66,803 1861190
Plan -3,130,106
Unrealized gains on Mkt 841,677 219 477,483 219
Secunties -364,194
TOTAL Line 8 -
18,896,235 ---11,586,798 -7,309,437
__J
Schedule Page: 276
------------_.,~._"'-~-----_._---_._~------_._._._._--
Line No.: 18 Column: a ----_...-~--~-_.-"-~--- -.. ..__.._---_.
~Ine Advance Coal Royalties 287,571 0 39,802
~8:247,769
IRS Interest Income 0 151,918 0
151,918
Oregon Non-Op Prop Tax 757 0 476
Adj 281
Unrealized Gain/Loss From 64,004 (8,086)0
Rabbit Trust 55,918
TOTAL Line 18 -
352,332 --143,833 40,278 -455,887
-=
IFERC FORM NO.1 (ED. 12-S7) Page 450.1
This Page intentionally Left Blan
,-~
."r
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/04
(2) DA Resubmission 04/1112008
o HER REGULATORY LIABILITIES (Account 254)
1. Report below the particulars (details) called for conceming other regulatory liabilities, including rate order docket number, if
applicable.
2. Minor items (5% of the Balance in Account 254 at end of period, or amounts less than $50,000 which ever is less),may be grouped
by classes.
3. For Regulatory Liabilties being amortized, show period of amortization.
Balance at Begining DEBITS Balance at End
Line Description and Purpse of of Current of Current
No.Oter Regulatory Liabilties OuarterlYear Account Amount Credits OuarterlYearCredited
(a)(b)(c)(d)(e)(f)
1 Market to Market Short Term 175 50,04 1,061,O8 553,042
2
3 Demand Side Management Rider 29026 5,934,46 varius 16,861,66 12,410,28(1,483,073
4
5 Demand Sid Management Rider OR 393,731 varius 64,458 66,95 410,226
6
7 FAS 133 - Market to Market 33,16l 33,160
8
9 Oter Deferred Credit - PCA ( 11,851,702)182 1,933,284 13,78,981
10
11 Fixed Cost Adjustment. 30267 407,431 111,491 2,256,894 2,145,403
12
13 BPA Credit-Residential-ldaho 1,110,65 131,142,400 11,03,319 9,94,616 14,955
14
15 BPA Credit-Residential- Oregon 63,36 131,142,400 65,471 417,418 -178,685
16
17 BPA Credit-Farm . Idaho 923,749 131,142 12,On 74,246 985,918
18
19 BPA Credit-Farm. Orgon 26,458 142 30 2,38 28,538
20
21 Emissn Sales Interest. Idaho 27,025,013 182 87,55,99 6O,52,98 1
22
23 Emiion Sales Interes - Orgon 4,118,00 182 7,313,23 3,195,23(
24
25 Unfunded Accumulated Deferred Income Tax 41,825,27 1,142,301 42,967,558
26
27 Asst Retirement Oblicatin - Removal Cost 158,182,04 108 1,83,118 99,67!155,313,605
28
29
30
31
32
33
34
35
36
37
38
39
40
41 TOTAL 225,731,042 128,479,45 106,505,209 203,756,794
FERC FORM NO. 113-0 (REV 02-0)Page 278
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2007/Q4
This ~ort Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmission 0411/2008
ELECTRIC OPERATING REVENUES ( ccount 400)
1. The following instuctions generally apply to the annual version of these pages. Do not report quarterl data in columns (c), (e), (f), and (g). Unbilled revenues and MWH
related to unbilled revenues need not be reported separately as required in the annual version of these pages.
2. Report below operating revenues for each prescribe account, and manufactured gas revenues in total.
3. Report number of customers, columns (f) and (g), on the basis of meters, in addition to the number of flat rate accounts; except that where separate meter readings are added
for billng purpses, one customer should be counted for each group of meters added. The -average number of cus10mers means the average of twlve figures at the close of
each month.
4. If increases or decreases from previous period (columns (c),(e), and (g)), are not deried from previously reported figures, explain any inconsistencies in a footnote.
(a)
Operating Revenues Year
to Date Quarterll Annual
(b)
Operating Revenues
Previous year (no Quarterl)
(c)
line
No.
Title of Account
1 Sales of Electricity
2 (440) Residential Sales
3 (442) Commercial and Industrial Sales
4 Small (or Comm.) (See Instr. 4)
5 large (or Ind.) (See Instr. 4)
6 (44) Public Street and Highway lighting
7 (44) Oter Sales to Public Authorities
8 (44) Sales to Railroads and Railways
9 (448) Interdepartmental Sales
10 TOTAL Sales to Ultimate Consumers
11 (447) Sales for Resale
12 TOTAL Sales of Electricity
13 (less) (449.1) Provision for Rate Refunds
14 TOTAL Revenues Net of Provo for Refunds
15 Other Operating Revenues
16 (450) Forfeited Discounts
17 (451) Miscellaneous Service Revenues
18 (453) Sales of Water and Water Power
19 (45) Rentfrom Electric Propert
20 (455) Interdepartental Rents
21 (456) Other Elecric Revenues
22 (456.1) Revenues from Transmission of Electricity of Others
23 (457.1) Regional Control Service Revenues
24 (457.2) Miscellaneous Revenues
25
26 TOTAL Oter Operating Revenues
27 TOTAL Electric Operating Revenues
256,206,389
101,409,337
2,479,808
231,430,314
102,958,015
2,392,957
668,303,232
154,94,157
823,251,389
1,075,534
822,175,855
636,374,840
260,717,491
897,092,331
1,211,251
895,881,080~- -~ - - --- ---- - --
4,050,513 5,424,893
19,035,198 16,858,178
13,910,578
16,229,091
12,454,460
53,225,380
875,401,235
34,737,531
930,618,611
FERC FORM NO. 1J3-Q (REV. 12-05)Page 30
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2007/Q4
This ~rt Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 0411/2008
E ECTRIC OPERATING REVENUES (Account 400)
5. Commercial and industrial Sales, Account 442, may be classified according to the basis of classification (Small or Commercial, and Large or Industrial) regularly used by th
respondent if such basis of classification Is not generally greater than 100 Kwof demand. (See Account 442 of the Uniform System of Accounts. Exain basis of classifcation
in a footnote.)
6. Se pages 108.109, Important Changes During Period, for impornt new terrtory added and importnt rate increase or decreases.
7. For Lines 2,4,5,and 6, see Page 30 for amounts relating to unbiled revenue by accounts.
8. Includ unmetered sales. Provide details of such Sales in a footnote.
MEGAWATT HOURS SOLD
Year to Date Quarterly/Annual Amount Previous year (no Quartrly)(d) (e)
AVG.NO. CUSTOMERS PER MONTH Line
Current Year (no Quarterly) Previous Year (no Quarterly) No.(f) (g)
5
6
7
8
9
14,541,825 13,939,314 477,094 10
2,743,647 5,820,823 11
17,285,472 19,760,137 4n,094 12
13
17,285,472 19,760,137 477,094 14
Line 12, column (b) includes $
Line 12, column (d) includes
4,992,047 of unbiled revenues.
14,715 MWH relating to unbiled revenues
FERC FORM NO.113 (REV. 12-GS)Page 301
This Page Intentionally Left Blank
,-..
:i
Name of Respondent ThisWrtlS:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) Fi A Resubmission 04/11/2008
SALES OF ELECTRICITY BY RATE S( HEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data uner each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue accunt 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 bils rendered during the year divided by the number of billng periods during the year (12
if all billngs are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional reiienue biled pursuant thereto.
6. Report amount of unbiled revenue as of end of year for each applicble revenue account subheading.
ine ...umDer ana ime OT Hate scneouie Mvvn ::oia Mevenue Average Numoer ~vvn_oT ::aies 'l~'golder
No.(a)(b)(c)
of C~~\omers per?~stomer
(f)
1 440 - Residential Sales:
2 01 - Residential 5,212,066 305,027,941 397,139 13,124 0.0585
3 04 - Residential - EW 966 54,761 61 15,836 0.0567
4 05 - Residential - TOD 1,29C 74,392 86 15,000 0.05n
5 15 - Dusk to dawn lighting 2,49€44,707 0.1766
6 Unbiled Revenues 10,34E 2,609,891 0.2522
7 Total 44 5,227,16€308,207,698 397,286 13,157 0.0590
8
9 442-Commercial & Industrial Sales
10 07 - General service 205,731 14,963,806 32,594 6,312 0.0727
11 09 - General service 414,201 14,543,557 145 2,856,600 0.0351
12 09 - General service 3,266,47E 135,415,311 26,733 122,189 0.0415
13 09 - General service 2,44 86,175 2 1,224,00 0.0352
14 15 - Dusk to Dawn Light 3,885 606,368 0.1561
15 19 - Uniform rate contract 2,186,000 67,007,083 117 18,683,761 0.0307
16 19 - Uniform rate contracts 8,483 289,54 1 8,483,000 0.0341
11 19 - Uniform rate contracts 171,591 4,832,098 5 34,318,200 0.0282
18 24 - Irrigation Pumping 1,906,104 87,854,039 17,961 106,089 0.0461
19 25 - Irrigation Pumping -Time of 17,557 823,734 75 234,093 0.0469
20 40 - General service 14,075 752,826 1,154 12,197 0.0535
21 Commercial & Industrial & Unbil 1,088,611 30,441,186 3 362,870,333 0.0280
22 Total 442 9,285,170 357,615,726 78,796 117,838 0.0385
23
24 44 - Public Street Lighting:
25 40 - General service 2,6n 143,716 64 4,16::0.057
26 41 - Street lighting 21,782 2,165,079 149 146,18f 0.0994
27 42 - Traffic control lighting 5,03C 171,01:3 220 22,86'0.030
28 Total 44 29,48~2,479,808 1,012 29,139 0.0841
29
3C
31
3;,
3:
34
35
36
37
38
39
40
41 TOTAL Biled 14,527,11 663,311,18E 477,094 30,44~0.045
42 Total Unbiled Rev.(See Instr. 6)14,71 4,992,047 0 C 0.339~
43 TOTAL 14,541,82 668,30,232 4n,094 30,48C 0.046C
FERC FORM NO.1 (ED. 12-9S)Page 30
Name of Respondent This~rtIS:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) ri A Resubmission 04111/2008
SALES FOR RESALE (Account 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( i.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 onginal contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is servce 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 reliabilty 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 interrpted 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 reliabilty of
servce, aside from transmission constraints, must match the availabilty and reliabilty of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERCRate Averaae Actual Demand (MW)
No.(Footnote Affilations)Classifi-Schedule or Monthly illng l\Vera~Aver~
cation Tariff Number Demand (MW)Monthly NC Deman!Monthly C emand
(a)(b)(c)(d)(e)(1)
1 Raft River Rural Electric RQ V6-44 9.425 9.425 0.000
2 Raft River Rural Electric RQ V6-4 0.000 0.000 0.000
3 City of Weiser RQ V6-53 0.000 0.000 0.000
4
5 Arizona Public Service Co.OS WSPP 0.000 0.000 0.000
6 Arizona Public Service Co.SF WSPP 0.000 0.000 0.000
7. Avista Corp. - WWP Div.OS WSPP 0.000 0.000 0.000
8 Avista Corp. - WWP Div.SF WSPP 0.000 0.000 0.00
9 Avista Corp. - WWP Div.SF V6-0 0.000 0.000 0.000
10 Avista Energy, inc.OS WSPP 0.000 0.000 0.00
11 Avista Energy, Inc.OS WSPP 0.000 0.000 0.000
12 Avista Energy, Inc.SF WSPP 0.000 0.000 0.000
13 Barclays Bank PLC SF WSPP 0.00 0.000 0.000
14 Bear Energy LP SF WSPP 0.00 0.000 0.000
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12-9)Page 310
This ~rt Is: Date of Report
(1) IlAn Original (Mo, Da, Yr)
(2) A Resubmission 04/11/2008
SALES FOR RESALE Account 447) (Continued)
OS - for other service. use this category only for those servces which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD . for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements Ro sales together and report them starting at line number one. After listing all Ro sales, enter "Subtotal - Ro"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-Ro" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tanfs under
which service, as identified in column (b), is provided.
6. For requirements Ro sales and any type of-servce involving demand chargs imposed on a monthly (or Longer) basis, enter the
average monthly biling 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 typs 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 bils rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other tys of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bils rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-Ro grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - Ro" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-Ro" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2007/Q4
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges (h+i+j)No.
($)($)
(g)(h)(i)(k)
57,422 1
2
14 3
4
85 5
11,282 6
400 7
15,63 8
9
66,560 10
11
94,909 4,848,857 12
61,812 2,734,089 13
20,400 1,187,850 14
57,436
2,686,211
493,689
o
1,169,617
143,885,041
307,635
9,092,175
1,970,941
152,977,216
2,743,647 493,689 145,054,658 9,399,810 154,94,157
FERe FORM NO.1 (ED. 12-90)Page 311
Name of Respondent Thisoo0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2007/04
(2) ñ A Resubmission 04/1112008
SALES FOR RESALE (Account 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( Le., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affilation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RO - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the reliabilty 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 RO service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that 'intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Averaße Actual Demand (MW)
No.(Footnote Affilations)Classifi-Schedule or Monthly i\lng Avera~e Aver~
cation Tariff Number Demand (MW)Monthly NC Deman Monthly C emand
(a)(b)(c)(d)(e)(f)
1 Benton County PUD SF WSPP O.OO 0.000 0.000
2 Black Hills Power Inc.OS WSPP O.OOC 0.00 0.000
3 Black Hils Power Inc.OS WSPP 0.000 0.000 0.000
4 Black Hils Power Inc.SF WSPP O.OOC 0.000 0.000
5 Bonnevile Power Administration OS WSPP O.O()0.000 0.000
6 Bonneville Power Administration SF WSPP 0.000 0.000 0.000
7 BP Energy Company SF WSPP O.OOC 0.000 0.000
8 Burbank, Cit of OS WSPP 0.000 0.000 0.000
9 Calpine Energy Services, L.P.SF WSPP O.OOC O.OO(0.000
10 cargil Power Markets LLC OS WSPP O.OOC O.OO(0.000
11 cargil Power Markets LLC OS WSPP 0.000 O.OO(0.000
12 Cargill Power Markets LLC SF WSPP O.OOC O.OO(0.000
13 Chelan Co PUD SF WSPP O.OOC 0.00 0.000
14 Citigroup Energy Inc.SF WSPP O.OOC 0.00(O.OO(
Subtotal RO C 0 0
Subtotal non-RO 0 0 0
Totl (I 0 0
FERC FORM NO.1 (ED. 12-9)Page 310.1
This :!0rt Is: Date of Report
(1) !!An Original (Mo, Da, Yr)
(2) A Resubmission 0411/2008
S LES FOR RESALE (Account 447) (Continued
as - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RO sales together and report them starting at line number one. After listing all RO sales, enter "Subtotal - RO"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-ROD in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RO sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billng 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.
Foonote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bils 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 RQlNon-RO grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RO" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
Year/Period of Report
End of 2007/04
Name of Respondent
Idaho Power Company
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)ül (k)
1,495 41,800 1
2
330 3
10,735 4
3,447 5
47,610 6
190,45 7
93 8
594 9
10
12,532 11
142,605 8,160,168 12
526 18,195 13
128,275 6,84,757 14
57,436
2,686,211
493,689
o
493,689
1,169,617
143,885,041
307,635
9,092,175
9,399,810
1,970,941
152,977,216
154,948,1572,743,647 145,05,658
FERC FORM NO.1 (ED. 12-9)Page 311.1
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) nA Resubmission 04111/2008
SALES FOR RESALE (Account 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( Le., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RO - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the reliabilty 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 RO service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duratin 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 availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Compay or Public Authority Statistical FERC Rate Averaße Actual Demand (MW)
No.(Footnote Affilations)Classifi-Schedule or Monthly iIing Avera~e Avera~
cation Tariff Number Demand (MW) Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Clatskanie PUD SF WSPP 0.00(;O.OOC 0.000
2 Conoc Phillps Company OS WSPP O.OOC 0.000 0.000
3 Conoco Phillps Company SF WSPP O.OOC O.OOC 0.000
4 Constellation Energy Commodities Gr SF WSPP O.OOC 0.000 0.000
5 Coral Power, LLC OS WSPP 0.000 0.000 0.000
6 Coral Power, LLC OS WSPP 0.000 O.OOC 0.000
7 Coral Power, LLC OS WSPP 0.000 O.OOC 0.000
8 Coral Power, LLC SF WSPP 0.000 O.OO 0.000
9 Credit Suisse Energy LLC SF WSPP O.OOC 0.00 0.000
10 DB Energy Trading, LLC SF WSPP O.OOC 0.000 0.000
11 Douglas County PUD SF WSPP O.OOC O.OOC 0.000
12 Energy Autority, The SF WSPP O.OOC 0.000 O.OOC
13 Eugene Water & Electric Board SF WSPP O.OOC O.OOC 0.00
14 Fortis Energy Marketing & Trading G SF WSPP O.OOC O.OOC 0.000
Subtotal RQ C 0 0
Subtotal non-RQ C 0 0
Total (I 0 0
FERC FORM NO.1 (ED. 12-9)Page 310.2
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) n A Resubmission 04/11/2008
SALES FOR RESALE (Account 447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RO sales together and report them starting at line number one. After listing all RO sales, enter .Subtotal . RO"
in column (a). The remaining sales may then be listed in any order. Enter .Subtotal-Non-RO" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tarif Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identiied in column (b), is provided.
6. For requirements RO sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly biling 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 ¡ncolumn (g) the megawatt hours shown on bils rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Exlain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bils rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RO grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The .Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RO. amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MeWatt Hours REVENUE Total ($)Una
Sold Demand Charges Energy Charges Oter Charges (h+i+j)No.
($)($)($)
(g)(h)(i)OJ (k)
792 40,736 4O,73S 1
567'O94~213 2
9,159 567,094 3
75,251 ~5,391,395 4
4,057 143,921 5
5,300 6
27,702 1,617,998 7
121,537 6,281,368 6,281,36 8
60,000 3,596,700 3,596,700 9
29,475 1,476,256 1,476,25S 10
34 11
102 12
5,852 300,894 300,894 13
29,800 1,957,700 1,957,700 14
57,436 493,689 1,169,617 307,635 1,970,941
2,686,211 0 143,885,041 9,092,175 152,977,216
2,743,647 493,68 145,054,658 9,39,810 154,94,157
FERe FORM NO.1 (ED. 12-9)Page 311.2
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2007/04
(2) ¡= A Resubmission 04111/2008
SALES FOR RESALE (Account 447)
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges dunng 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 affilation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the onginal contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the reliabilty 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 servce 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 availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty 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.
Une Name of Company or Public Autority Statistical FERC Rate Averaße Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly illing -Avera~e Aver~
cation Tari Number Demand (MW) Monthly NC Deman Monthly C emand
(a)(b)(c)(d)(e)(f)
1 Franklin County P.U.D.SF WSPP 0.000 0.000 0.000
2 Grant County P.U.D.SF WSPP 0.000 0.000 0.000
3 Grays Harbr PUD OS WSPP 0.000 0.000 0.000
4 Grays Harbor PUD SF WSPP 0.000 0.00 0.000
5 Highland Energy LLC SF WSpp 0.000 0.00 0.00
6 J. Aron & Company SF WSPP 0.000 0.000 0.000
7 Lehman Brothers Commodity Services,SF WSPP 0.000 0.000 0.000
8 Morgan Stanley Capitl Group Inc.OS WSPP 0.00 0.000 0.000
9 Morgan Stanley Capital Group Inc.OS WSPP O.OOC 0.000 0.000
10 Morgan Stanley Capital Group Inc.SF WSPP O.OOC 0.000 0.000
11 Northern california Power Agency OS WSPP O.OOC 0.00 0.000
12 Northem California Power Agency OS WSPP O.OOC 0.000 0.000
13 Northern California Power Agency SF WSPP 0.000 0.000 0.000
14 NorthWestern Energy IF 147 0.000 0.000 0.000
Subtotal RQ C 0 0
Subtotal non-RQ C 0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12-9)Page 310.3
Name of Respondent This ~lOrt Is:Date of Report Year/Period of Report
Idaho Power Company (1)~An Original (Mo, Da, Yr)End of 2007/Q4
(2)A Resubmission 04/11/2008
S LES FOR RESALE (Account 447) (Continued)
as - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Descnbe the nature
of the service in a foonote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements Ro sales together and report them starting at line number one. After listing all Ro sales, enter "Subtotal - Ro"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-Ro" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements Ro sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billng 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 houny (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 bils rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bils rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the ROINon-Ro grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - Ro" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-Ro" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(I)OJ (k)
240 6,000 6,000 1
84 23,582 23,582 2
25 2,125 3
166 4
6,200 366,140 366,140 5
50,400 2,503,322 2,503,322 6
8,200 408,372 408,372 7
41,897 8
1,463 91,847 9
170,604 11,050,822 11,050,822 10
867 56,76€11
1,121 79,914 12
807 37,714 37,714 13
68,878 3,688,463 3,688,~14
57,436 493,689 1,169,617 307,635 1,970,941
2,686,211 0 143,885,041 9,092,175 152,977,216
2,743,647 493,68 145,054,658 9,39,810 154,94,157
FERC FORM NO.1 (ED. 12-9)Pag 311.
Name of Respondent ThiswrtlS:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo. Da. Yr)End of 2007/04
(2) Fï A Resubmission 04/11/200
SALES FOR RESALE (Account 447)
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affilation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the reliabilty 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 availabilty and reliabilty 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" mèans
Longer than one year but Less than five years.
Line Name of Company or Public Authorit Statistical FERC Rate Averaße Actual Demand (MW)
No.(Footnote Affilations)Classifi-Schedule or Monthly illng AVera~e Aver~
cation Tariff Number Demand (MW) Monthly NC Deman Monthly C emand
(a)(b)(c)(d)(e)(f)
1 NortWestem Energy SF WSPP 0.000 0.000 0.000
2 NorthWestern Energy IF 147 0.000 0.000 0.000
3 Okanogan County P.U.D.SF WSPP 0.000 0.000 0.000
4 Pacific Northwest Generating Cooper SF WSPP 0.000 0.000 0.000
5 PacifiCorp Inc.OS WSPP 0.000 0.000 0.000
6 PacifiCorp Inc.OS WSPP 0.000 0.000 0.000
7 PacifiCorp Inc.SF T-7 0.00 0.000 0.000
8 PacifiCorp Inc.SF WSPP 0.000 0.000 0.00
9 PacifiCorp Inc.SF V6-13 0.000 0.00 0.000
10 Portland General Electric Company OS WSPP 0.000 0.000 0.000
11 Portland General Electric Company OS WSPP 0.000 0.000 0.000
12 Portland General Electric Company SF WSPP 0.000 0.000 0.000
13 Portland General Electric Company SF VB-54 0.000 0.00 0.000
14 Powerex Corp.OS WSPP 0.000 0.000 0.000
Subtotal RO 0 0 0
Subtotal non-RO 0 0 0
Total (J 0 0
FERC FORM NO.1 (ED. 12-9)Page 310.4
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2007/Q4
his Re ort s: Date of Report
(1) An Original (Mo, Da, Yr)
(2) A Resubmission 04/11/2008
S LES FOR RESALE (Account 447 (Continued)
as - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for servce provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RO sales together and report them starting at line number one. After listing all RO sales, enter "Subtotal - RO"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RO" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RO sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billng 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 tyes 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 bils rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bils rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the ROINon-RO grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RO" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Sold
(g)
REVENUE
Energy Charges
($)
(i)
Total ($)
(h+i+j)
(k)
Oter Charges
($)
OJ
Demand Charges
($)
(h)
100 10,000
37
1,187
1,727
178
190,002
1,798
n,871
57,436
2,686,211
493,689
o
307,635
9,092,175
9,399,810
1,970,941
152,9n,216
154,94,157
1,169,617
143,885,041
2,743,647 493,689 145,054,658
Page 311.4
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2007/04
(2) r= A Resubmission 041112008
SALES FOR RESALE (Account 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( i.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 affilation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty 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.
Une Name of Company or Public Authorit Statistical FERC Rate Averaf¡Actual Demand (MW)
No.(Footnote Affiliations)Ciassifi-Schedule or Monthly ming Avera~e Aver~
cation Tariff Number Demand (MW) Monthly NC Demaii Monthly C emanc
(a)(b)(c)(d)(e)(f)
1 Powerex Corp.as WSPP O.OOC O.OOC 0.000
2 Powerex Corp.SF WSPP O.OOC 0.000 0.000
3 PPL EnergyPlus, LLC as WSPP O.OOC 0.000 0.000
4 PPL EnergyPlus, LLC SF WSPP O.OOC O.OOC 0.000
5 PPL Montana, LLC as WSPP O.OOC 0.00 0.000
6 PPL Montana, LLC as WSPP O.OOC 0.000 0.000
7 PPL Montana, LLC as WSPP O.ooC O.OOc 0.000
8 PPL Montana, LLC SF WSPP 0.000 O.OO 0.000
9 PPL Montana, LLC SF V6-57 O.OOC O.OOc O.OOC
10 PPM Energy, Inc.as WSPP O.ooC o-:0.000
11 PPM Energy, InC.SF WSPP 0.000 o.OOC 0.000
12 Public Service Co. of Colorado SF WSPP O.OOC o-:ri 0.000
13 Public Service Company of New Mexic SF WSPP O.OOC O.OOC 0.000
14 Puget Sound Energy, Inc.as WSPP 0.000 O.OOC O.OOC
Subtotal RO 0 0 0
Subtotal non-RO 0 0 0
Total (J 0 0
FERC FORM NO.1 (ED. 12-9)Page 310.5
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2007/04
his Re rt s: Date of Report
(1) X An Original (Mo, Da, Yr)
(2) A Resubmission 04/11/2008
SALES FOR RESALE (Account 447) (Continued
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RO sales together and report them starting at line number one. After listing all RO sales, enter "Subtotal - RO"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RO" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which servce, as identified in column (b), is provided.
6. For requirements RO sales and any tye of-service involvng demand charges imposed on a monthly (or Longer) basis, enter the
average monthly biling demand in column (d), the average monthly non-eoincident 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 bils rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other typs of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bils rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RO/Non-RO grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal- RO" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RO" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 ,¡ine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Sold
(g)
Demand Charges
($)
(h)
REVENUE
Energy Charges
($)
(i)
2,935
142,125
223
35
1,010
14,979
176,209
2,567
1,665
1,325
Total ($)
(h+i+j)
(k)
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
57,436
2,686,211
493,689
o
493,689
1,169,617
143,885,041
307,635
9,092,175
2,743,647 145,054,65 9,399,810
FERC FORM NO.1 (ED. 12-90)Page 311.5
1,970,941
152,977,216
154,94,157
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2007/04
(2) ¡= A Resubmission 04/11/2008
SALES FOR RESALE (Account 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( Le., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affilation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RO - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the reliabilty 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 RO service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU . for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availabilty and reliabilty of
service, aside from transmission constraints, must match'the availabilty and reliabilty of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Autorit Statistical FERC Rate Averaße Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly illing Avera~e Aver~
cation Tari Number Demand (MW)Monthly NC Deman Monthly C emand
(a)(b)(c)(d)(e)(f)
1 Puget Sound Energy, Inc.SF T-7 0.000 0.000 0.000
2 Puget Sound Energy, Inc.SF WSPP 0.000 0.000 0.000
3 Rainbow Energy Marketing Corporatio OS WSPP 0.000 0.000 0.000
4 Rainbow Energy Marketing Corporatio OS WSPP 0.000 0.000 0.000
5 Rainbow Energy Marketing Corporatio SF WSPP 0.000 0.000 0.000
6 Salt River Project OS WSPP 0.000 0.000 0.000
7 Salt River Project SF WSPP 0.000 0.000 0.000
8 Seattle City Light SF WSPP O.OOC O.OOC 0.000
9 Sempra Energy Trading Corpation OS WSPP O.OOC o.ooe 0.000
10 Sempra Energy Trading Corporation OS WSPP O.OOC o.ooe 0.000
11 Sempra Energy Trading Corpration SF WSPP o.ooc o.ooe 0.000
12 Sempra Energy Trading LLC SF WSPP O.OOC 0.000 0.000
13 Sierra Pacific Power Company OS WSPP O.OOC 0.000 0.000
14 Sierra Pacific Power Company OS WSPP 0.000 o.ooe 0.000
Subtotal RO 0 0 0
Subtotal non-RO 0 0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12-90)Page 310.6
Name of Respondent
Idaho Power Company
VearlPeriod of Report
End of 2007/Q4
his ~rt Is: Date of Report
(1) ~An Original (Mo, Da, Vr)
(2) A Resubmission 04/11/2008
S LES FOR RESALE (Account 447 Continued)
as - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RO sales together and report them starting at line number one. After listing all RO sales, enter "Subtotal - RO"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RO" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RO sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billng 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 bils 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 0). Report in column (k)
the total charge shown on bils rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RO/Non-RO grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RO" amount in column (9) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Sold
(g)
REVENUE
Energy Charges
($)
(i)
Total ($)
(h+i+j)
(k)
Oter Charges
($)
0)
Demand Charges
($)
(h)
13
59,125
750
2,859,917
283
16,400
200
158
22,289
12,105
218,629
41,800
33
57,436
2,686,211
493,689
o
493,689
1,169,617
143,885,041
145,05,658
307,635
9,092,175
1,970,941
152,977,216
2,743,647 9,399,810 154,94,157
FERC FORM NO.1 (ED. 12-9)Page 311.6
Une
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
Name of Respondent This (g0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2007/04
(2) n A Resubmission 04/11/2008
SALES FOR RESALE (Account 447)
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule.Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affilation 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 reliabilty 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 availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LUservice except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Averaße Actual Demand (MW)
No.(Footnote Affilations)Classifi-Schedule or Monthly iIing A\fera~e AveraPB
cation Tariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Sierra Pacific Power Company SF T-7 0.000 0.000 0.000
2 Sierra Pacific Power Company SF WSPP 0.000 0.000 0.000
3 Snohomish County PUD OS WSPP 0.000 0.000 0.000
4 Snohomish County PUD SF WSPP 0.000 0.000 0.000
5 Southern California Edison SF WSPP 0.000 0.000 0.000
6 SUEZ Energy Marketing NA, Inc.SF WSPP 0.000 0.000 0.000
7 Tacoma Power SF WSPP 0.000 0.000 0.000
8 TransAIt Energy Marketing (U.S.)SF WSPP O.OOC 0.00 0.000
9 Tri-State Generation and Transmissi OS WSPP O.OOC 0.000 0.000
10 Tucson Elecric Power Company SF WSPP O.OOC 0.000 0.000
11 UBS AG, London Branch SF WSPP O.OOC 0.00 0.000
12 Utah Associated Municipal Power Sys OS WSPP 0.000 0.000 0.000
13 Western Area Power Administration SF WSPP 0.000 0.000 0.000
14 LESS BAD DEBT WRITE-OFF 0.000 0.000 0.000
Subtotal RO 0 0 0
Subtotal non-RO 0 0 0
Total 0 0 0
FERe FORM NO.1 (ED. 12-9)Page 310.7
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) Õ A Resubmission 0411/2008
Si LES FOR RESALE (Account 447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categones, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Descnbe 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 pnor reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RO sales together and report them starting at line number one. After listing all RO sales, enter "Subtotal - RO"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RO" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tarifs under
which service, as identified in column (b), is provided.
6. For requirements RO sales and any type of-service involving demand chargs imposed on a monthly (or Longer) basis, enter the
average monthly biling 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 bils 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 bils rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RO grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RO" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10. Footnote entnes as required and provide explanations following all required data.
MegaWatt Hour REVENUE Total ($)Line
Sold Demand Charges Energy Charges Oter Charges (h+i+j)No.
($)($)($)
(9)(h)(i)OJ (k)
21 1,209 1,208 1
6 40 40E 2
50 3,9O 3
16,961 658,44 658,44 4
255 13,417 13,41 i 5
36,228 1,867,806 1,867,806 6
222 7
131,985 6,53,160 6,534,1&8
40 ~2,8OC 9
136 4,427 10
25,400 ~1,347,46 11
32 1,69~12
4,515 212,550 212,55C 13
14
57,436 493,689 1,169,617 307,635 1,970,941
2,686,211 0 143,885,041 9,092,175 152,977,216
2,743,647 493,689 145,05,658 9,39,810 154,948,157
FERC FORM NO.1 (ED. 12-90)Page 311.7
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2) A Resubmission 04/11/2008 2007/Q4
FOOTNOTE DATA
~ç¡"ei-'fiige:310-Tine No::1uOColumn:T.' _U-~=~-=-=-======--==------
Customer Charge
rsdu/~ Page: 310 Line No.: 2 _ Co¡iiiii:T~__~~=--~-_~=~~~--------Network Transmission charges.
¡Schedule Page: 310Tie No.: 3 Column: j U. -=~___-=-======-=--~-:-==--- ...
Prior Year Adjustment.~~hedu/e Page: 310 _ Line No.: 5 .. ColurJri: i~~=--~=-~---=---===--=~-__--
Non- Firm Sales.
rsdu/e Page: 310 -Line No.:7Colum..: T--=___~~-~.-==~~~==----- ~.Non-Firm Sales.
~ëhedule Page: 310- Line No.: 9 Column:T-.~=-~~_ ______------ --.--_._=-_
Spinning or Operating Reserves.
~u/e Page: ~10_ Line No.: 10 Column: i ---~===-_ --------------=~-~=~__..
Unit Contingent.~hedu/e Page: 310 .. L¡¡'eNO¡;cohiii:C---.-.--n_-~_-----~ ......--...--.__ .... .--"3Financial Transmission Losses .- -------------- ..- ------
lSch~~u/e Page:~10.:L_Line No.: 2 . __Colulrn: i-:======~===-___=~=~___=___~.-:J
Financial Transmission Losses.
rsedule Page: 310.1 Line N0.:_LColumn: i~_____________ ----_-==-~~~--=~_=:Non-Firm Sales.¡Schedule Page: 310.1 Line No.: 5Coli:l_-==_=--=--~- ___~=~~=-~--~-.J
Non-Firm Sales.
¡Schedule Page: 310.1 Line No.: 8 Column: L___=~~--------==---n------== ---1
Non- Firm Sales.
~hedu/e Page: 310.1 Line No.: 10_ Column:¡------- ----~====._ _--
Financial Transmission Losses.
¡Schedule Page: 310.1 Line No.: 11- Coluii. - --~=~------=i
Non-Firm Sales.
¡Schedule Page: 310.2 Line No.: 2 Column: j --=-~----___.______ u__ ---=:~
Financial Transmission Losses.
rschedule Page: 310.2unNØ5 .Cohiirn: ;~~_~.-----~~=-------~===-------:J
Unit Contingent.
!ßchedule Page: 310.2 Line No~:6--COiiii-:-j ---- .---~---_u________=i
Financial Transmission Losses.fSedu/e Page: 310.2 Line No.: 7 Column: i .--~____ ~___---____~
Non- Firm Sales.Ii ...---.--------........--.----. ~-.¡schedu/e "age: 310~_~ _ Line No.: 3 _Colu'!'!L_Non-Firm Sales.~ .._-_._-_.__.---_._----_._..~hedu/e Page: 310.3 Line No.: 8 Column: i__
Financial Transmission Losses.
f§du/e Page: 310~f Line No.: 9 columiïT-..__.__.___________u___________..Non-Firm Sales.
¡Schedule Page: 310.3 Line No.:1- Columñ:¡------
Unit Contingent .' ""-,-----
rSCiJedu/e Page: 310.3 _ Line No.: 12 COlumn: 1...--~_d_~_ -- --==-____~=-=-=:-_-..-_=.=i
Non- Firm Sales.
fSi!u/ePage: 310.4 LkiNo.: 2 .-Column: j .--- .u..___.._.~__________n_______m__
Capaci ty . and Penalty Charge. - -~-~-..- -..---------..--...------~-----.~.-..-.~..,---
¡su/e Page:310~~ Line No.: 5 COII¿trn:j .-.--n_-~==~__n~m_~___===__._n~~Financial Transmission Losses.
~hedu/ePage: 310.~__ Line'fio.:_!_ C~/umn:I=-===~=:~=-~-~=__ -__~___'___~.- __=:-Non-Firm Sales.
rschediige10.4 LiiiiJ:T_Colulln: j __-:~_~=:~===__~~=-=..~~-
Spinning or Operating Reserves.
I FERC FORM NO.1 (ED. 12-87)
=i
. -.--~_~_:=
. .. - ---~~=~-=-=
._~=-=~
_=.
----_._~
..---=-=_=-__ -.--==... - ~_ .-==_~==__.J
"'--."J
=J
-=i
Page 450.1
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
Idaho Power Company I (2) A Resubmission 04/11/2008 2007/04
FOOTNOTE DATA
fSdule Page: 310.4 Line No.: 10 _ CO/l.lTn_:I~~~_-~~---~~~__~==---~-~~__~--~~----~
Financial Transmission Losses.~chedule Page: 310.4 Line No.: 11 Columii:/~ d_____~__~____~ --=-=-~__J
Non-Firm Sales.
fSedule Page: 310.4 Line No.: 13 Column: j _____
Spinning or Operating Reserves.
~chedule Page: 310.4 Line No.: 14 Colum~______
Financial Transmission Losses.
fSdule Page: 310.5 Line No.: 1 Column: iNon-Firm Sales.
¡Schedule Page: 310.5 Line No.: 3 Column: j
Financial Transmission Losses.
¡Schedule Page: 310.5 Line No.: 5 Column: i
Unit Contingent.
!Schedule Page: 310.5 Line No.--Ciii--
Financial Transmission Losses.
¡Schedule Page: 310.5 Line No.: 7 Column: i
Non-Firm Sales.
I .------ .--..-------~-.Schedule Page: 310.5 Line No.: 9 Column: j
Spinning or Operating Reserves.
¡Schedule Page: 310.5 Line No.: 10 Column: j
Financial Transmission Losses.
~chedule Page: 310.5 Line No.: 14 Column: iNon-Firm Sales.
¡Schedule Page: 310:6 Line No.: 3 Column: j
Financial Transmission Losses.
¡Schedule Page: 310.6 Line No.: 4 Column: i
Non- Firm Sales. .
~chedu/e Page: 310.6 - Line No.: 6 Column: i -----
Non-Firm Sales.
f$8du/e Page: 310.tS Line No.: 9 Column: i
Uni t Contingent.
¡Scheule Page: 310:6 Line No.: 10Çolu~n: j ___________~
Financial Transmission Losses.
~chedule Page: 310.6 Line No.: 13 Colutrn: j ____~__
Financial Transmission Losses.
~hedu/e Page: 310.6 Line No.: 14 Column: i -~~--__Non-Firm Sales. ___________~______
¡Schedule Page: 31ji:7 Line No.-:T---iii-----------Non- Firm Sales. -- ------~-----'-
¡Scheule Page: 310.7 Line No.: 9 Column: i
Non-Firm Sales. -
¡Schedule Page: 310.7 Line No.: 12 Column: i ._____
Non-Firm Sales.
~-----~-~~
----~-~:~...._--~
____==__.___::
-~
-=i-- ----::
'-'.'--=i
=:
--==
----~~~--J---------- ~
----~
-----J
.__=-____J
----J----- ~
___~=____~=__.=
IFERC FORM NO.1 (ED. 12-87) Page 450.2
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2007/Q4
This '30rt Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/11/2008
ELE TRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnote.Line Account Amount forN Current Yearo. (a) (b)
1 1. POWER PRODUCTION EXPENSES
2 A. Steam Power Generation
3 Operation
4 (500) 0 ration Supervision and En ineerin
5 (501) Fuel
6 502) Steam Expenses
7 (503) Steam from Other Sources
8 (Less (504) Steam Transferred-Cr.
9 (505 Electric Expenses
10 (506) Miscellaneous Steam Power Expenses
11 (507) Rents
12 (509 Allowances
13 TOTAL Operation Enter Total of Lines 4 thru 12)
14 Maintenance
15 (510) Maintenance Su rvision and En ineering
16 511 Maintenance of Strctures
17 (512) Maintenance of Boiler Plant
18 (513 Maintenance of Electric Plant
19 (514) Maintenance of Miscellaneous Steam Plant
20 TOTAL Maintenance (Enter Total of Lines 15 thru 19)
21 TOTAL Power Production E enses-Steam Power (Entr Tot lines 13 & 20
22 B. Nuclear Power Generation
23 0 eration
24 (517) 0 eration Su ervision and En ineering
25 518) Fuel
26 (519 Colants and Water
27 (520) Steam enses
28 (521 Steam from Other Sources
29 (Less) (522) Steam Transferred-Cr.
30 (523) Electric Expenses
31 (524) Miscellaneous Nuclear Power Expenses
32 525) Rents
33 TOTAL Operation Enter Total of lines 24 thru 32)
34 Maintenance
35 (528 Maintenance Supervision and En ineerin
36 (529 Maintenance of Strctures
37 (530 Maintenance of Reactor Plant E uipment
38(531 Maintenance of Electric Plant
39 532) Maintenance of Miscellaneous Nuclear Plant
40 TOTAL Maintenance (Enter Total of lines 35 thru 39)
41 TOTAL Power Producion Expenses-Nuc. Power Entr tot lines 33 & 40
42 C. Hydraulic Power Generation
43 Operation
44 (535) Operation Supervision and En ineerin
45 536) Water for Power
46 (537 H draulic Expenses
47 538) Electric Exnses
48 (539) Miscellaneous Hydraulic Power Generation Expenses
49 (54) Rents
50 TOTAL Operation (Enter Total of Lines 44 thru 49
51 C. H draulic Power Generation Continued)
52 Maintenance
53 541) Mainentance Supervsion and En ineerin
54 (542) Maintenance of Structures
55 (543) Maintenance of Reservoirs, Dams, and Waterwa s
66 (54 Maintenance of Electric Plant
57 (54) Maintenance of Miscellaneous H draulic Plant
58 TOTAL Maintenance (Enter Total of lines 53 thru 57)
59 TOTAL Power Production Expenses"H draulic Power (tot of lines 50 & 58)
AmounUorPrevious Year
(c)
1,664,872 1,712,505
114,837,238 107,519,847
6,840,109 7,107,143
2,109,888 1,44,277
8,068,234 8,142,999
295,774 248,624
133,816,115 126,175,395
2,580,247 2,525,470
649,26 408,848
14,630,059 15,377,469
5,685,377 4,43,882
5,934,851 4,575,617
29,479,798 27,321,286
163,295,913 153,496,681
5,235,531
5,057,110
9,469,966
1,391,453
2,825,559
419,652
24,399,271
4,522,312
4,937,659
8,258,502
1,387,391
2,407.071
409,491
21,922,426
1,875,54
1,281,835
541,03
2,090,274
2,763,207
8,551,890
32,951,161
1.871,365
1,193,327
946,682
2.138,733
3.213,655
9,363,762
31.286,188
FERC FORM NO.1 (ED. 12-93)Page 320
Name of Respondent This~rtIS:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)En of 2007/04
(2) Fi A Resubmission 04111/2008
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line Account ~No.".. ea, ..'" Yea
(a)(b) (c)
60 D. Other Power Generation
61 Operation
62 (546) Operation Supervision and Enoineering 341,622 322,341
63 1(547) Fuel 19,48,750 7,498,309
64 (548) Generation Expenses 381,996 290,352
65 (549) Miscellaneous Other Power Generation Expenses 46,825 297,218
66 (550) Rents
67 TOTAL Operation (Enter Total of lines 62 thru 66)20,673,193 8,408,220
68 Maintenance
69 (551) Maintenance Supervision and Engineerino 173
70 I (552) Maintenance of Structures 220,422 176,972
71 (553) Maintenance of Generatino and Electric Plant 42,703 124,319
72 I (554) Maintenance of Miscellaneous Other Power Generation Plant 645,761 392,516
73 TOTAL Maintenance (Enter Total of lines 69 thru 72)908,886 693,980
74 TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73)21,582,079 9,102,2QQ
75 E. Other Power Supply Exnses
76 (555) Purchased Power 289,484,214 283,439,877
77 (556) System Control and Load Dispatchino 77,489 76,140
78 (557) Other Expenses -118,678,522 -27,304,586
79 TOTAL Other Power Supplv Exo (Enter Total of lines 76 thru 78)170,883,181 256,211,431
80 TOTAL Power Production Expnses (Total of lines 21, 41, 59, 74 & 79)388,712,334 450,096,500
81 2. TRANSMISSION EXPENSES
82 Operation
83 (560) Operation Supervision and Enaineerina 2,334,833 2,537,078
84 I (561) Load Dispatchino 51,610 1,166,233
85 1(561.1) Load Dispatch-Reliabilit 565
86 (561.2) Load Dispatch-Moitor and Operate Transmission System 2,042,253 1,525,337
87 I (561.3) Load Dispatch-Transmission Service and SChedulino 1,098,119 765,078
88 (561.4) Scheduling, System Control and Dispatch Services
89 (561.5) Reliabilit, Plannina and Standards Development
90 (561.6) Transmission Service Studies
91 (561.7) Generation Interconnecion Studies 66,918 29,062
92 561.8) Reliabilit, Plannina and Standards Develooment Services
93 (562) Station Expenses 1,748,409 1,866,905
94 563) Overhead Lines Exenses 924,264 869,797
95 (56) Underground Lines Expenses
96 565) Transmission of Elecricitv bv Others 10,469,726 7,63,680
97 566) Miscellaneous Transmission Exnses 622,227 270,768
98 (567) Rents 1,163,462 1,152,152
99 TOTAL Operation (Enter Total of lines 83 thru 98)20,521,821 17,821,655
100 Maintenance
101 (568) Maintenance Suoervision and Engineering 442,117 460,937
102 569) Maintenance of Strucures 111
103 (569.1) Maintenance of Computer Hardware 123,219 98,980
104 (569.2) Maintenance of Computer Softare 307,535 93,34
105 (569.3) Maintenance of Communication Equipment 21,369 5,757
106 569.4) Maintenance of Miscellaneous Regional Transmission Plant
107 (570) Maintenance of Station Equipment 2,899,130 2,900,424
108 (571) Maintenance of Overhead Lines 2,341,428 2,257,538
109 572) Maintenance of Underground Lines
110 (573) Maintenance of Miscellaneous Transmission Plant 2,527 31,222
111 TOTAL Maintenance (Total of lines 101 thru 110)6,137,436 5,848,203
112 TOTAL Transmission Exenses (Total of lines 99 and 111)26,659,257 23,669,858
FERC FORM NO.1 (ED. 12-93)Page 321
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) Fi A Resubmission 04111/2008
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line Account ~No.urrent ear Previous Year
(a)(b) (c)
113 3. REGIONAL MARKET EXPENSES
114 Operation
115 (575.1) Operation Supervision
116 575.2) Dav-Ahead and Real-Time Market Faciltation
117 (575.3) Transmission Riohts Market Faciltation
118 (575.4) Capacity Market Facilitation
119 (575.5) Ancilary Services Market Facilitation
120 (575.6) Market Monitoring and Compliance
121 (575.7) Market Faciltation, Monitoring and Compliance Services
122 (575.8) Rents
123 Total Operation (Lines 115 thru 122)
124 Maintenance
125 I (576.1) Maintenance of Structures and Improvements
126 (576.2) Maintenance of Computer Hardware
127 (576.3) Maintenance of Computer Softare
128 ,(576.4) Maintenance of Communication Equipment
129 (576.5) Maintenance of Miscellaneous Market Operation Plant
130 Total Maintenance (Lines 125 thru 129)
131 TOTAL Reoional Transmission and Market Op Expns (Total 123 and 130)
132 4. DISTRIBUTION EXPENSES
133 Operation
134 (580) Operation Supervision and Engineering 3,350,727 3,051,138
135 I (581) Lod Dispatchino 3,049,911 3,020,110
136 (582) Station Expenses 1,120,906 1,159,883
137 (583) Overhead Line Exenses 3,432,084 3,856,696
138 (584) Underoround Line Expenses 2,120,824 2,042,167
139 (585) Street Lighting and Signal System Exenses 148,817 154,596
140 (586) Meter Expenses 4,526,255 4,288,265
141 ! (581) Customer Installations Expnses 1,371,291 1,148,759
142 ! (588) Miscellaneous Expenses 5,533,555 5,589,808
143 (589) Rents 64,84 149,968
144 TOTAL Operation (Enter Total of lines 134 thru 143)25,299,210 24,461,3~
145 Maintenance
146 (590) Maintenance Supervision and Enoineerino 262,635 223,168
147 (591) Maintenance of Strucures
148 (592) Maintenance of Station Eeiuipment 3,493,145 2,826,028
149 (593) Maintenance of Overhead Lines 12,504,013 11,020,129
150 594) Maintenance of Underaround Lines 1,351,054 1,114,786
151 (595) Maintenance of Line Transformers 169,689 583,246
152 (596) Maintenance of Street Licitino and Sional Systems 476,928 711,171
153 597) Maintenance of Meters 927,906 895,593
154 (598) Maintenance of Miscellaneous Distribution Plant 127,981 148,970
155 TOTAL Maintenance (Total of lines 146 thru 154)19,313,351 17,523,091
156 TOTAL Distribution Expenses (Total of lines 144 and 155)44,612,561 41,984,481
157 5. CUSTOMER ACCOUNTS EXPENSES
158 Operation
159 (901) Supervision 454,931 537,023
160 (902) Meter Readino Expenses 5,422,624 5,254,77
161 (903) Customer Records and Collection Expenses 8,177,910 10,146,625
162 (904) Uncollectible Accounts 2,009,863 2,84,490
163 (905) Miscellaneous Customer Accunts Excenses 336 373
164 TOTAL Customer Accounts Expnses (Total of lines 159 thru 163)16,065,664 18,787,288
FERt FORM NO.1 (ED. 12-93)Page 322
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2007/04
This ~ort Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmission 04/11/2008
ELECTRIC OPERATION AND MAINTENANCE E PENSES (Continued
If the amount for previous year is not derived from previously reported figures, explain in footnote.Une Account Amount forNo ~~. ~Amount forPrevious Year
(c)
301,871
21,911,476
288,822
9,047,316
200
847,736
10,184,074
49,783,914
17,790,599
27,708,517
11,232,903
3,159,426
5,448,358
27,872,099
1,200
6,030,254
48,935,653
14,665,999
29,324,259
8,149,64
2,94,897
5,152,00
29,241,894
2,000
976,225
thru 193)
3,771,715
101 ,41 0,523
600,557,914
3,969,367
86,726,893
631,449,094
FERC FORM NO.1 (ED. 12-93)Page 323
Name of Respondent This
'ìrt
Is: Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) Õ A Resubmission 0411/2008
PU~C~AJlED POWER ~Accou~t 555)nc u ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part 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 affilation 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 servce 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 reliabilty 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 availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affilations)Classifi-SChedule or Monthly Bilin~Average Average
cation Tariff Number Demand (MW Monthly NCP Deman Montly CP Demand
(a)(b)(c)(d)(e)(f)
1 Wilis and Bett Deveny/Shinglecr .LU -N/A N/A N/A
2 James B. Howell i CHI Elkcreek LU -N/A N/A N/A~LU -4.942Mw N/A N/A
4 Owhee Irrigatin District
5 Mitchell Bute LU -N/A N/A NlA
6 Owee Dam LU -N/A NlA N/A
7 Tunnel #1 LU -N/A N/A NlA
8 Reynolds Irrigation District LU -N/A N/A NlA
9 Clifton E. Jenson/Birchcreek LU -.05Mw NlA N/A
10 Snake River Pottery LU -N/A NlA N/A
11 White Water Ranch LU -N/A NlA NlA
12 John R LeMoyne LU -N/A N/A NlA
13 David R Snedigar LU -NlA N/A N/A
14 Mud Creek White Hydro, Inc LU -N/A N/A NlA
Total
FERC FORM NO.1 (ED. 12-9)Page 326
Name of Respondent This WrtIS:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) Õ A Resubmission 04/11/2008
CCOU~\~g~~ (i;OnnnueO¡'ìliicluding power exc ang )
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 Tarif, 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 tye of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average biling 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 bils 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 tyes of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data,
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.
Received Delivered ($)\t~WI
of Settlement ($)
(g)(h)(i)Ol (m)
62~40,24 40,247 1
3,44E 218,14E 218,14E 2
34,W 1,576,498 1,068,5H 2,64,01A 3
4
6,08E 110,7()110,704 5
23,85f 43,92 433,924 6
12,56C 1,198,651l 1,198,659 7
1,081l 77,39€77,396 8
25E 17,5OC 5,15E 22,655 9
401 26,011l 26,019 10
491 32,501 32,507 11
64C 34,75E 34,756 12
1,23€80,89 80,897 13
33 20,765 20,761l 14
5,195,964 104,827 293,024 2,815,124 285,857,825 811,265 289,.48,214
FERC FORM NO.1 (ED. 12-9)Page 327
Name of Respondent This~rtIS:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) Õ A Resubmission 04111/2008
PU~C~~ED POWER hAccou~t 555)
( nc ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricit (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 affilation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RO . for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliabilty of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RO service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF . for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU . for long-term service from a designated generating unit. "Long-term" means five years or longer. The availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty 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, capacit, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Autority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affilations)Classifi-Schedule or Monthly Billin~Average Average
cation Tarif Number Demand (MW Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Rim View Trout Company ~NlA NlA NlA
2 Curry Cattle Company .08Mw N/A N/A
3 Branchflower Company LU -N/A N/A N/A
4 Big Wood Canal Company
5 Black Canyon LU -N/A N/A N/A
6 Jim Knight LU -NlA NlA NlA
7 Sagebrush LU -N/A N/A NlA
8 Fisheries Development N/A N/A NlA
9 Shorock Hydro Inc.
10 Shoshone Cspp LU -N/A NlA N/A
11 Shoshone #2 LU -N/A N/A N/A
12 Rock Creek #1 Joint Venture LU -1.732Mw N/A N/A
13 Richard Kaster
14 Box Canyon LU -N/A N/A N/A
Total
FERC FORM NO.1 (ED. 12-9)Page 326.1
Name of Respondent 1 his oo0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) ri A Resubmission 04/11/2008
ccoun\~Bgl) (l,ontlnU60¡1lncludmii pôwer exchanae )
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 servce, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of servce involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billng 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 suppliets 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 bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other tyes of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certin credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.
Received Delivered ~l \t~~'l
of Settlement ($)
(g)(h)(i)(m)
1,36(58,22,58,227 1
63 26,79E 12,81'39,61C 2
84 57,12!57,125 3
4
311 21,70 21,707 5
1,35¡93,081 93,08€6
1,111 76,7H 76,7H!7
89 37,641 37,64 8
9
1,73¡122,9~122,98l!10
2,071 137,26 137,267 11
7,3O€552,508 147,04~69,5&12
13
1,65f 103,46f 103,~14
5,195,96 104,827 293,024 2,815,12~285,857,82E 811,26f 289,48,21'
FERC FORM NO.1 (ED. 12-9)Page 327.1
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) Fí A Resubmission 04/1112008
PU~C~AdTED POWER ~Accou~t 555)nc u ing por exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part 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 affilation 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 servce 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 reliabilty 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 servce is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty 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.
Une Name of Company or Public Autority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affilations)
Classifi-Schedule or Monthly Billng Average Average
cation Tarif Number Demand (MW) Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Briggs Creek LU -N/A N/A NlA
2 David McCollum/canyon Springs LU -N1A N/A NlA
3 H.K. Hydro Mud Creek S & S LU -N/A N/A N/A
4 Allan RavenscroftMalad River LU -.488Mw N/A NlA
5 Willam Arkoosh Uttlewod LU -N/A N1A NlA
6 Clear Springs Foo Inc.LU -N/A NlA N/A
7 Koyle Hydro Inc.LU -N1A N/A N/A
8 Kasel & Witherspon LU -N1A N/A N/A
9 Lateral 10 Ventures LU .NlA N/A N/A
10 Crystal Springs Hydro LU -N/A N/A N/A
11 Pigeon Cove Power LU -1.389 N/A NlA
12 Consolidated Hydro Inc. 1 Enel -
13 GeoBon #2 LU -N/A NlA N/A
14 Barber Dam LU -N1A N/A N/A
Total
FERC FORM NO.1 (ED. 12-90)Page 326.2
Name of Respondent This~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) i=A Resubmission 04111008
CCOU~\~g~l1 (Continued)ncludiñ~i power exc añãe )
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 billng 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 bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bils recived as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETLEMENT OF POWER Une
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Oter Charges Total (J+I)No.
Received Delivered ($)
\~~\fl
of Settlement ($)
(g)(h)(i)0)(m)
3,59(231,61f 231,61e 1
67.28,22~28,22::2
1,17.75,31¡75,317 3
1,73.155,67:1 34,00 190,51E 4
3,3Of 24O,1~240,15::5
3,48f 265,5H 265,51C 6
2,44f 179,43 179,43 7
3,751 257,36€257,36E 8
5,43(329,581 329,58f 9
6,4m 412,32-412,32~10
7,3h 486,150 127,891 614,041 11
12
3,02~219,5~219,58:13
10,43 504,47~504,47~14
5,195,9&104,827 293,024 2,815,12~285,857,82f 811,265 289,484,21-
FERC FORM NO.1 (ED. 12-9)Page 327.2
Name of Respondent ThiS~IOrt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Onginal (Mo, Da, Yr)End of 2007/Q4
(2)A Resubmission 0411/2008
PUUC~~ED POWER ~Accou~t 555)
nc ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affilation the respondent has with the seller.
3.In column (b), enter a Statistical Classification Code base on the original contractual terms and conditions of the service as follows:
RQ - for reuirements 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 definiton 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 servce 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 availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty of the designated unit.
IU . for intermediate-term service from a designated generating unit.The same as LU servce expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involvng 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 servce regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Autority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Rock Creek #2 LU -NlA NlA NlA
2 Dietrich Drop LU -N/A N/A N/A
3 Lowline#2 LU -NlA N/A NlA
4 Little Mac Power Co.lCedar Draw LU .N/A N/A N/A
~U -N/A N/A NlA
6 Little Woo River Irngation Dist LU -N/A NlA N/A
7 Marco Rancher's Irrigation Inc.LU -NlA NlA N/A
8 Faulkner Brothers Hydro Inc.LU -N/A N/A N/A
9 Magic Reservoir Hydro LU -N/A N/A N/A
10 Bypass Limited LU -N/A N/A N/A
11 SE Hazelton A LP LU -NlA NlA NlA
12 Claudia BurkhardSunshine Power NlA N/A N/A
13 Lemhi Hydro Power Co.lSchaffner LU -N/A N/A N/A
14 J R Simplot Co.LU -N/A N/A N/A
Total
FERC FORM NO.1 (ED. 12-9)Page 326.3
Name of Respondent ThiSwrtlS:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) ri A Resubmission 04/11/2008
cco~~fig~l~ (Continued)'(including pöwer exc anaè )
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 biling 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 tyes 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 bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other typs of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expnses, 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.
MegWatt Hours POWER EXCHANGES COST/SETLEMENT OF POWER Une
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered
~I \~~\'1
of Settlement ($)
(g)(h)(i)(m)
5,48(264,19E 264,19E 1
12,67.654,35~65,35~2
9,24l 46,28-46,2ai 3
4,25.266,12~266,1~4
25,7/X 1,791,921 1,791,921 5
3,02~184,01~184,01;6
1,98E 128,491 128,41*7
3,44~252,23l 252,23E 8
10,351 502.161 502,16E 9
27,88 1.388-:1,388,00 10
24,OOE 1.144,02~1,144,OZ 11
5 2,34 2,34 12
1,33~92,841 92,84 13
68,801 3,629,59:3,629,59:14
5,195,9~104,827 293.024 2,815,12A 285,857,82~811,265 289,48,21~
FERC FORM NO.1 (ED. 12-9)Page 327.3
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) D A Resubmission 0411/2008
PU~CHAJlED POWER ~Accou~t 555)nclu ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affilation 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 servce is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliabilty of requirement servce must
be the same as, or second only to, the suppliets 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 delivenes 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 availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty 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 servce in a footnote for each adjustment.
Une Name of Company or Public Autority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billng Average Average
cation Tari Number Demand (MW) Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Blind Canyon Hydro LU .N/A N/A N/A
2 Cit of Hailey LU .NlA NlA NlA
-~.N/A NlA N/A
.N/A N/A N/A5 LU -NlA N/A N/A6 . W -N/A N/A NlA
7 Pristine Springs Inc. #1 LU -N/A N/A N/A
8 Vaagen Brothers Lumber Inc.LU .N/A N/A N/A
9 Horseshoe Bend Hydro LU -NlA NlA N/A
10 Contractors Power Group Inc./Mile LU -NlA NlA N/A
11 Rupert Cogeneration Partners W -N/A NlA N/A
12 Glenns Ferry Cogeneration Parter LU -N/A NlA NlA
13 Lewandowski Farms ..NlA N/A NlA
14 Tasco - Nampa N/A N/A N/A
Total
FERCFORM NO.1 (ED. 12-9)Page 326.4
Name of Respondent This i~rrt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2007/04
(2) A Resubmission 04/11/2008
.- v .vl ''(ñèlr'- ccou~ã~8gS) (0 ntinued)
nc udlnQ power exc ange )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups. for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils 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 tyes of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (9) 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,
tine 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COSTISCILEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Oter Charges Total (j+k+l)No.
Received Delivered ~l \t~\fl
of Settlement ($)
(g)(h)(i)(m)
4,45f 34,08C 343,080 1
18:.12,21C 12,210 2
1,48:.103,66f 103,668 3
42,3~2,46,16E 2,468,16Eì 4
26,81:.1,753,57!1,753,579 5
23,67~1,54,30C 1,54,300 6
92E 48,754 48,754 7
20,36~1,423,13€1,423,13S 8
46,12:.2,957,451 2,957,451 9
3,69'244,81E 244,81Eì 10
50,74C 3,090,61::3,090,613 11
54,101 3,176,01~3,176,01:2 12
6C 2,67E 2,67E 13
:w 14'45C 14,450 14
5,195,964 104,827 293,024 2,815,124 285,857,825 811,265 289,48,214
FERe FORM NO.1 (ED. 12-90)Page 327.4
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) OA Resubmission 0411112008
PU~CHAdTED POWER ~Accou~t 5 5)nclu ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affilation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RO - for requirements service. Requirements service is servce which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliabilty of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RO service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF . for intermediate-term firm service. The same as LF service expec that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm servces, where the duration of each periOd of commitment for service is one
year or less.
LU - for long-term servce from a designated generating unit. "Long-term" means five years or longer. The availabilit and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty 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 involvng 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 servces which cannot be placed in the above-defined categories, such as all
non-firm servce regardless of the Length of the contract and servce from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Copany or Public Authorit Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affilations)Classifi.Schedule or Monthly Biling Average Average
cation Tariff Number Demand (MW)Monthly NCP Demarn Monthly CP Demanc
(a)(b)(c)(d)(e)(f)
1 Pristine Springs Inc # 3 LU -N/A N/A NlA
2 Ted S. Sorenson/iber Dam LU N/A NlA NlA
3 Fossil Gulch Wind LU -N/A N/A N/A
4 G2 Energy Hidden Hollow LU N/A NlA NlA
5 Horseshoe Bend WincJnited Materi LU NlA NlA NlA
6 Horseshoe Bend Wind/United Materi NlA NlA NlA
7 Horseshoe Bend Wind/United Materi N/A N/A NlA
8 Riverside Hydro Mora Drop LU NlA N/A NlA
9 J.M. MilerlSahko Hydro LU N/A N/A N/A
10 D.R. Johnson Lumber/Co Gen Co SF N/A N/A N/A
11 Twin Falls Energy 1 Lowline Midwa LU
12 US Geothermal 1 Raft River Geothe LU
13 Other Purchased Power
14 Arizona Public Service Co.SF WSPP N/A NlA NlA
Total
FERC FORM NO.1 (ED. 12-9)Page 326.5
Name of Respondent This
~rrtls:
Date of Report Year/Period of Report
Idaho Power Company (1)X An Original (Mo, Da, Yr)End of 2007/04
(2)A Resubmission 04/11/2008
CCOUR\~g~¿) (Continued)- lIñclùdíng' pôwer exc ange )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups. for service proVided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average biling 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 bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETLEMENT OF POWER Une
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energ Charges Other Charges Total 0+k+1)No.
Received Delivered ($)\i~\~l
of Settement ($)
(g)(h)(i)OJ (m)
1,40E 72,96E 72,96€1
29,91C 1,386,3H 1,386,315 2
23,33~1,120,52~1,120,52~3
18,321 914,88!914,88E 4
21,77~1,038,35~1,038,353 5
E 6
~7
4,62~196,20C 196,200 8
92.39,36~39,362 9
35,411 2,290,17C 2,290,170 10
3,19E 203,88€203,886 11
7,221 346,62~346,623 12
13
140,811 8,718,10~8,718,102 14
5,195,964 104,827 293,024 2,815,124 285,857,825 811,265 289,48,214
FERC FORM NO. 1 (ED. 12-9)Page 327.5
Name of Respondent This 78rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2007/04
(2) tiA Resubmission 04/11/2008
PU~CH~ED POWER ~Accu~t 555)
( ncl ing power exc anges
1.Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a).Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affilation the respondent has with the seller.
3. In column (b), enter a Statístical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service.Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliabilty 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 fröm third parties to maintain deliveries of LF servce). 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 availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty 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 servce in a footnote for each adjustment.
Une Name of Company or Public Autorit Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affilations)Classifi-Schedule or Monthly Biling Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Avista Corp. - WWP Div.SF T-12 N/A NlA N/A
2 Avista Corp. - WWP Div.
~I;:::
N/A N/A N/A
3 Avista Corp. - WWP Div.N/A N/A N/A
4 AVÎsta Corp. - WWP Div.. ..;.;WSPP N/A N/A N/A':1, _~)f
5 Avista Energy, inc.N/A NlA NlA
6 Avista Energy, Inc.SF WSPP N/A NlA N/A
7 Barclays Bank PLC SF WSPP N/A NlA N/A
8 Bear Energy LP SF WSPP N/A N/A N/A
9 Benton County PUD ~WSPP N/A N/A NlA/;,
10 Benton County PUD SF WSPP N/A NlA N/A
11 Black Hils Power Inc.'IiiWSpp N/A N/A N/A'4.":
12 Black Hils Power Inc.SF WSPP N/A N/A N/A
13 Bonnevile Power Administration WSPP N/A N/A NlA8
14 Bonnevile Power Administration SF WSPP N/A N/A N/A
Total
FERCFORM NO.1 (ED. 12-90)Page 326.6
Name of Respondent ThisWrtlS:Date of Report Year/Penod of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) Õ A Resubmission 0411/2008
,CCOUR~~~S\ (vontlnuel:'Tinauding' õöWer exc ange )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billng 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 bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of PQwer exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other tyes of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
.
MegaWatt Hours POWER EXCHANGES COST/SETLEMENT OF POWER Une
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Oter Charges Total O+k+l)No.
Received Delivered ~l \t~\fl
of Settlement ($)
(g)(h)(i)(m)
10E 5,36 5,36A 1
77C 37,06f 37,06 2
20,361 686,9Z 686,922 3
852,647 852,641 4
2,82 149,~149,78~5
35,09!1,684,871 1,684,871 6
233,32!13,282,57f 13,282,57f 7
1,20(68,20 68,20C 8
2!X 11,s8 11,58C 9
5,371 239,89 239,89C 10
26,13 1,489,381 1,489,381 11
8,85:505,84.505,84 12
11,08'697,5~697,572 13
113,65 4,136,87C 4,736,870 14
5,195,964 104,827 293,024 2,815,12~285,851,82f 811,26f 289,484,21.1
FERC FORM NO.1 (ED. 12-9)Page 327.6
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Onginal (Mo, Da, Yr)End of 2007/Q4
(2) n A Resubmission 04/11/2008
PU~C~AciED POWER Ilccou~t 555)nc u ing por exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Exlain in a footnote any ownership interest or affilation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RO - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliabilty of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RO service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term. means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term. means five years or longer. The availabilty and reliability of
service, aside from transmission constraints, must match the availabilty and reliabilty of the designated unit.
IU . for intermediate-term service from a designated generating unit.The same as LU servce 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 servces 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.
Une Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affilations)Classifi-Schedule or Monthly Biling Average Average
cation Tarif Number Demand (MW) Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 BP Energy Copany IFWSPP N/A N/A N/A
2 BP Energy Company SF WSPP NlA N/A NlA
3 BP Energy Company WSPP NlA NJA N/A
4 Calpine Energy Services, L.P.SF WSPP N/A N/A NlA
5 Cargil Power Markets LLC ::;*WSPP N/A N/A N/A
6 Cargil Power Markets LLC SF WSPP N/A N/A N/A
7 Chelan Co PUD i=NlA N/A NlA
8 Citigroup Energy Inc.SF d~::::NlA N/A N/A
9 Citigroup Energy Inc.N/A NJA N/A
10 Clatskanie PUD N/A N/A NJA
11 Clatskanie PUD SF WSPP N/A NJA N/A
12 Conoc Philips Company SF WSPP N/A N/A NlA
13 Constellation Energy Commodities SF WSPP N/A N/A N/A
14 Coral Power, LLC SF WSPP N/A N/A N/A
Total
FERC FORM NO.1 (ED. 12-9)Page 326.7
Name of Respondent ThiS~lOrt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2007/04
(2)A Resubmission 04/11/2008
ccouR;R~S) (Continued)
'nñcludina power exc an e )
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 biling 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 bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (i)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.
Received Delivered ~l ($~
\~l
of Settlement ($)
(g)(h)(i)(k (m)
41 2,79f 2,7ge 1
430,08C 26,441,13 26,441,13~2
378 37f 3
7,31~373,06C 373,06C 4
8~3,88~3,885 5
23,98f 1,267,53C 1,267,530 6
8,23~341,67~341,675 7
10C 9,5(9,500 8
98,74 4,917,3~4,917,363 9
1C 930 930 10
1,60l 76,611 76,611 11
2,525 282,27E 282,275 12
167,800 8,530,981 8,530,981 13
219,760 10,402,311 10,402,311 14
5,195,96 104,827 293,024 2,815,124 285,857,825 811,265 289,484,214
FERC FORM NO.1 (ED. 12-9)Page 327.7
Name of Respondent This
Wrt
Is: Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) Fî A Resubmission 0411/2008
PU~C~AciED POWER ~Accou~t 555)nc u ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part 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 affilation 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 reliabilty 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 availabilty and reliability of
servce, aside from transmission constraints, must match the availability and reliabilty 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 electricit. 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.
Une Name of Company or Public Authorit Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affilations)Classifi-Schedule or Monthly Billing Average Average
cation Tari Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Credit Suisse Energy LLC SF WSPP NlA N/A N/A
2 DB Energy Trading, LLC SF WSPP N/A N/A N/A
3 Douglas County PUD SF WSPP N/A NlA N/A
4 EI Paso Electric Company SF WSPP N/A N/A N/A
5 Energy Authority, The SF WSPP NlA NlA NlA
6 Eugene Water & Electric Board ~WSPP N/A N/A NlA-'.t
7 Eugene Water & Elecric Board SF WSPP N/A NlA N/A
8 Fortis Energy Marketing & Trading SF WSPP N/A N/A N/A
9 Franklin County P.U.D.,WSPP N/A N/A N/A
10 Franklin County P.U.D.SF WSPP N/A N/A NlA
11 Grant County P.U.D.tt,lYjWSPP N/A N/A N/A
12 Grant County P.U.D.SF WSPP N/A N/A N/A
13 Grays Harbor PUD N/A N/A N/A
14 Grays Harbor PUD SF WSPP N/A N/A N/A
Total
FERC FORM NO.1 (ED. 12-90)Page 326.8
Name of Respondent This R~)(rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) ==A Resubmission 04/11/2008
cco~ti~g~S) (Gontinueci)ncludiní:f pOwer exc ange )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identifed 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 billng 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 tyes 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 bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETLEMENT OF POWER Line
Purchased MegWatt Hours MegaWatt Hours Demand Charge Energy Charges Otr Charges Total Ü+k+l)No.
Received Delivered ~l \t~~~l
of Settlement ($)
(g)(h)(i)(m)
37,231 2,559,05C 2,559,05C 1
40(22,90(22,90C 2
2,40~99,51~99.515 3
68~47,16~47,16E 4
2,95!116,32C 116,320 5
5(3,40(3,4O 6
12,42C 697,84 697,847 7
19,60C 1,068,80(1,068,800 8
20C 8,755 8,755 9
1,52~76,121 76,121 10
14,88(393,08C 393,OSC 11
21,51(1,O85,6~1,085,66E 12
19E 8,84~8,84E 13
4,77~237,37(237,37C 14
5,195,96 104,827 293,024 2,815,124 285,857,825 811,265 289,48,214
FERC FORM NO.1 (ED. 12-9)Page 327.8
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) n A Resubmission 0411/2008
PU~C~~ED POWER ~Accou~t 5 5)no ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part 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 affilation the respondent has with the seller.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RO - for requirements service. Requirements service is servce which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning).In addition, the reliabilty of requirement service must
be the same as, or second only to, the supplier's service to its own ultmate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RO service. For all transaction identifed 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 servce 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 availabilty and reliabiliy of
service, aside from transmission constraints, must match the availabiliy and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public AuthOrit Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)
Classifi-Schedule or Monthly Billng Average Average
cation Tarif Number Demand (MW)Monthly NCP Demarn Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Highland Energy LLC SF WSPP N/A NlA NlA
2 J. Aron & Company SF WSPP N/A N/A N/A
3 Lehman Brothers Commodity Service SF WSPP N/A NlA N/A
4 Los Angeles Department of Water a SF WSPP N/A N/A NlA
5 Morgan Stanley Capital Group Inc.lwSPP N/A N/A N/A
6 Morgan Stanley Capital Group Inc.SF WSPP N/A N/A N/A
7 Nevada Power Company SF WSPP NlA N/A N/A
8 NorthWestem Energy SF T-7 N/A N/A N/A
9 NortWestern Energy .'WSPP N/A N/A N/A
10 NortWestern Energy SF WSPP N/A NlA N/A
11 NorthWestern Energy IF 242 N/A NlA NlA
12 Okanogan County P.U.D.SF WSPP N/A N/A N/A
13 Pacific Norhwest Generating Coop SF WSpp NlA N/A NlA
14 PacifiCorp Inc.SF T-13 N/A N/A N/A
Total
FERC FORM NO.1 (ED. 12-90)Page 326.9
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2007/04
(2) r= A Resubmission 04/11/2008
ccoun\~g~l) (0 ntinued)- niieJudíng' power exchañge )
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), identiy 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 billng 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 bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other tys of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (i)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegWatt Hours POWER EXCHANGeS COST/SETLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Oter Charges Total O+k+l)No.
Received Delivered ~I \~~\'1
of Settlement ($)
(g)(h)(i)(m)
32f 18,82f 18,825 1
36,40C 1,552,70C 1,552,7()2
65,80C 2,815,55~2,815,552 3
39 48,66f 48,665 4
22f 10,77C 10,77C 5
93,96~5,604,15~5,60,15:1 6
1,06f 58,12C 58,12C 7
14 7,OQ.7,004 8
30~14,84~14,849 9
2,371 109,40f 109,408 10
65,820 3,257,201 3,257,201 11
24C 5,52C 5,520 12
9,OOC 364,150 364,150 13
82C 40,8~40,862 14
5,195,964 104,827 293,024 2,815,124 285,857,825 811,265 289,484,214
FERC FORM NO.1 (ED. 12-9)Page 327.9
Name of Respondent This~rtIS:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) n A Resubmission 04111/2008
PU~C~~ED POWER ttccou~t 555)
nc ing poer exc anges
1.Report all power purchases made during the year.Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part 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 affilation 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 reliabilty 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 servce is one
year or less.
LU - for long-term service from .a designated generating unit."Long-term" means five years or longer. ¡he availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" meanS
longer than one year but less than five years.
EX - For exchanges of electricity.Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardl.ess of the Length of the contract and service from designated units of Less than one year.Descnbe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affilations)Classifi-Schedule or Monthly Bilin~Average Average
cation Tariff Number Demand(MW Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Pacif.iCorp Inc..',WSPP N1A N1A N/A
2 PacifiCorp Inc.SF WSPP N1A N/A N/A
3 PacifiCorp Inc.,WSPP N1A N/A N/A
4 Portland General Electric Company SF T-14 N/A N/A N/A
5 Portland General Electric Company N/A N/A N/A
6 Portland General Electric Company ')!~WSPP N/A N/A N/A
7 Portland General Electric Company SF WSPP N/A N1A N/A
8 Powerex Corp.i~WSpp N/A N1A N/A'i1't
9 Powerex Corp.SF WSPP N/A N/A N/A
10 PPL EnergyPlus, LLC SF WSPP N/A N/A N/A
11 PPL Montana, LLC LF WSPP N/A N/A N/A
12 PPL Montana, LLC -r¡*;;,~'WSPP N1A N/A N/A
13 PPL Montana, LLC SF WSPP N/A N/A N/A
14 PPM Energy, Inc.'~;ii~WSPP N/A N/A N/A
Total
FERC FORM NO.1 (ED. 12-90)Page 326.10
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) ñ A Resubmission 04/111008
CCOU~\~~l) ((.ontlnUec¡.1Irìcluding pÖwer exc añge )
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 servce, 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 biling 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 bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.
Received Delivered ($)
\t~\fl
of Setlement ($)
(g)(h)(i)OJ (m)
18,201 965,~965,~1
476,55E 26,743,88.26,743,88~2
1,618,117 1,618,11 3
21~10,8H 10,8H 4
2,11.31,17E 31,178 5
5,32C 295,34C 295,340 6
121,12.6,787,87~6,787,873 7
1,04E 91,96:91,963 8
176,82E 10,654,30E 10,654,3OS 9
36,68'2,236,13E 2,236,138 10
103,584 4,609,48E 4,609,488 11
14,368 706,34~706,349 12
122,911 5,753,6~5,753,694 13
1,051 59,72E 59,725 14
5,195,964 104,827 293,024 2,815,124 285,857,825 811,265 289,48,214
FERC FORM NO.1 (ED. 12-90)Page 327.10
Name of Respondent This~rtIS:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo. Da, Yr)End of 2007/Q4
(2) n A Resubmission 0411/2008
PU~CHAdfED POWER ~Accou~t 555)nclu ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electncity (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 part 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 affilation 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 servce 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 availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty 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 electncity. 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 servce. Use this category only for those services which cannot be placed in the above-defined categones. 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.
Une Name of Company or Public Authorit Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affilations)Classifi-Schedule or Monthly Billng Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 PPM Energy, Inc.SF WSPP N/A N/A N/A
2 Public Service Co. of Colorado SF WSPP N/A N/A N/A
3 Public Service Company of New Mex SF WSPP N/A N/A N/A
4 Puget Sound Energy, Inc.SF T-9 N/A N/A N/A
5 Puget Sound Energy, Inc.,';,wSPP N/A N/A N/A
6 Puget Sound Energy, Inc.SF WSPP N/A N/A N/A
7 Rainbow Energy Marketing Corporat WSPP NlA N/A N/A
8 Rainbow Energy Marketing Corprat SF WSPP N/A N/A N/A
9 Salt River Project SF WSPP N/A N/A N/A
10 San .Diego Gas and Electric SF WSPP N/A N/A N/A
11 Seattle Cit Light '(1.iWSPP N/A N/A N/A
12 Seattle City Light SF WSPP NlA N/A .N/A
13 Sempra Energy Solutions SF WSPP N/A N/A N/A
14 Sempra Energy Trading Corporation SF WSPP N/A NlA N/A
Total
FERe FORM NO.1 (ED. 12-9)Page 326.11
Name of Respondent This~rtIS:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) Õ A Resubmission 04/11/2008
.-.. .vl '7iìièll'- cco~ti~8~l) (l' minued)Inc uding power exe an e
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, tarifs or contract designations under which service, as
identifed in column (b), is provided.
5. For requirements RQ purchases and any ty of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billng 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 bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-penod adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETLEMENT OF POWER Line
Purchase MegWatt Hours MegaWatt Hours Demand Charges Energ Charges Oter Charges Totl (j+k+l)No.
Received Delivered ~l \~~Wl
of Settlement ($)
(g)(h)(i)(m)
150,545 9,301,79C 9,301,79C 1
46,04E 2,408,59~2,408,595 2
6,67E 44,99 44,991 3
19£9,59C 9,59C 4
1,121 53,64E 53,64£5
46,35:¡2,315,56~2,315,56 6
4,69:¡241,39~241,393 7
6,18C 261,6n 261,675 8
3,05E 240,11C 240,110 9
80C 47,100 47,100 10
1,30C 74,090 74,090 11
39,96E 1,861,960 1,851,960 12
40 15,900 15,90 13
374,32.23,84,42E 23,84,426 14
5,196,964 104,827 293,024 2,816,124 285,867,825 811,266 289,48,214
FERC FORM NO.1 (ED. 12-9)Page 327.11
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) n A Resubmission 04/1112008
PU~CHA&iED POWER ~Accou~t 555)nclu ing power exc anges
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involvng 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 part 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 onginal contractual terms and conditions of the service as follows:
RO - for requirements service.Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF . for long-term firm service."Long-term" means five years or longer and "firm" means that servce cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RO service.For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each penod 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 availabilty and reliabilit of
service, aside from transmission constraints, must match the availabilty and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expct 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 categones, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authori Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)
Classifi-SChedule or Monthly Biling Average Average
cation Tarif Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Sempra Energy Trading LLC SF WSPP N/A N/A NlA
2 Sierra Pacific Power Company SF 55 N/A N/A N/A
3 Sierra Pacific Power Company SF WSPP NlA NlA N/A
4 Sierra Pacific Power Company .wspp NlA N/A NlA'91
5 Sierra Pacific Power Company 'Wspp NlA N/A NlA
6 Silcon Valley Power SF WSPP N/A N/A N/A
7 Snohomish County PUD ~WSPP N/A N/A N/A
8 Snohomish County PUD SF WSPP N/A N/A N/A
9 Southern California Edison SF WSPP N/A N/A NlA
10 SUEZ Energy Marketing NA, Inc.c,WSPP N/A N/A N/A
11 suez Energy Marketing NA, Inc.SF WSPP N/A N/A N/A
12 Tacoma Power iWSPP N/A N/A N/A
13 Tacoma Power SF WSPP N/A N/A N/A
14 Telocaset Wind Power Parters LLC LU APP-A N/A N/A N/A
Total
FERC FORM NO.1 (ED. 12-9)Page 326.12
Name of Respondent lhis R~IOrt Is:Date of Report Year/Period of Report
Idaho Power Company (1) ~An Original (Mo, Da, Yr)End of 2007/04
(2)A Resubmission 04/11/2008
ccou~i~~l\ Iv ntinueo)ncludini:i pÖwer exc ange )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups. for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average biling 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 tys 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 bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on bils received as settlement by the respodent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (i)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETLEMENT OF POWER Une
Purchased MegaWatt Hours MegaWatt Hours Demand Charge Energy Charges Oter Charges Total 0+k+1)No.
Received Delivered ~l \~~~fl
of Settlement ($)
(g)(h)(i)(m)
207,40-14,302,53(14,302,53C 1
9 4,671 4,67S 2
5,031 211,98(211,9B(3
36C 36C 4
6,63f 6,63f 5
60C 24,55(24,55C 6
7H 42,55C 42,55C 7
16,981 580,60f 580,60f 8
80C 46,OOC 46,OOC 9
25C 14,05C 14,05C 10
17,4H 1,055,7H 1,055,71C 11
2,04f 93,78C 93,780 12
5,69:314,49'314,49'13
16,93-741,43¡741,432 14
5,195,964 104,827 293,024 2,815,124 285,857,82f 811,265 289,484,21-
FERC FORM NO.1 (ED. 12-9)Page 327.12
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2007/04
(2) 0 A Resubmision 04/11/2008
PU~CHAdfED POWER hAccou~t 555)nclu ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliabilty 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 availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty of the designated unit.
IU . for intermediate-term servce from a designated generating unit. The same as LU servce expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other servce. 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.
Une Name of Company or Public Autority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affilations)Classifi-Scedule or Monthly Billng Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 TransAlta Energy Marketing (U.S.)-,Wspp NlA N/A N/A
2 TransAlta Energy Marketing (U.S.)SF WSPP N/A N/A N/A
3 Tucson Elecric Power Company SF WSPP N/A NlA N/A
4 UßS AG, London Branch SF WSPP N/A NlA N/A
5 UBS Securities LlC
6 Uth Associated Municipal Power S SF WSPP N/A N/A N/A
7 Westem Area Power Administration SF WSPP NlA N/A N/A
8 Westem Area Power Administration SF WSPP NlA N/A N/A
9 Net Metering Customers ~N/A N/A N/A
10 BAD DEBT WRITE-OFF
11 Power Exchanges .12 Bonneville Power Administration
13 Citigroup Energy Inc.
14 Coral Power, LLC
Total
FERC FORM NO.1 (ED. 12-90)Page 326.13
Name of Respondent This I
~
ort Is:Date of Report Year/Period of Report
Idaho Power Company (1)An Original (Mo, Da, Yr)End of 2007/Q4
(2)A Resubmission 04/11/2008
,.. '~"~i1iiClI' CCOUR\~ggS\ ((.ontinued)Inc uding- oówer exc ange )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in pnor 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, tanffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any tye of servce involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average biling 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 suppliets 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 bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (i)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (9) 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 entnes as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.
Received Delivered ($)
~~~\'l
of Settement ($)
(g)(h)(i)OJ (m)
1,391 64,84C 64,S4C 1
145,341 6,951,901 6,951,901 2
2,40(166,70C 166,70C 3
277,60(13,176,70C 13,176,70C 4
5
12!4,5H 4,515 6
2!1,32~1,32E 7
61 3,32~3,32E 8
361 24,6()24,604 9
-1,666,87~-1,666,872 10
11
57,713 20,93 12
17 13
78 14
5,195,964 104,827 293,024 2,815,124 285,857,82E 811,26f 289,484,21¿
FERC FORM NO.1 (ED. 12-9)Page 327.13
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) ñ A Resubmission 0411/2008
PU~CHAciED POWER ~Accou~t 555)nclu ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affilation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliabilty 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 servce 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 availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non.firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the servce in a footnote for each adjustment.
Une Name of Company or Public Authorit Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affilations)Classifi-Schedule or Monthly Billng Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 NortWestern Energy
2 PacifiCorp inc.-
3 Puget Sound Energy, Inc.
4 Sierra Pacific Power Company
5 Uth Associated Municipal Power S
6
7
8
9
10
11
12
13
14
Total
FEAC FORM NO.1 (ED. 12-9)Page 326.14
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) ri A Resubmission 0411/2008
cco~tl~ggS) (Continued)'7lñcludlng- pówer exc añge
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 tye of service involving demand charges imposed on a rnonnthly (or longer) basis, enter
the monthly average billng 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 bils rendered to the respondent. Report in columns (h) and (i) the megawattours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certin credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETLEMENT OF POWER Une
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.
Received Delivered ~l \~~\fl
of Settlement ($)
(g)(h)(i)(m)
5,529 1
46,219 250,742 2
795 3
15,817 4
5 5
6
7
8
9
10
11
12
13
14
5,195,964 104,827 293,024 2,815,124 285,857,825 811,265 289,48,21.1
FERC FORM NO.1 (ED. 12-90)Page 327.14
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2) A Resubmission 04111/2008 2007/Q4
FOOTNOTE DATA
¡Schedule Page: 326M-Line No.: 3 Coiii:a--~ M -----~====_~~~----~--~=~___=~~___ i
The Tamarack Energy Partnership demand readings are taken from an electronic demand
recorder provided by Idaho power Company. The actual demand is not used in determining the
cost of energy.
~chedulePage: 326.1 Line No.: 1 Column: b
Non-Firm Purchases.
ISchedUie Page: 326.1 Line No.: 8 Column: b----- -..Non-Form Purchases-.-' -
rsdule Page: 326.3_ Line No.: 5 Column: a
Ida-West, a subsidiary of Idaho Power Company has partial ownership iñ these
¡Schedule eage: 326.3 __ Line No.: 12 Column: bNon-Firm Purchases.
~dulePage: 326.4 Line No.: 4 Column: a ......--------------
Ida-west, a subsidiary of Idaho Power Company, has partial ownership of
¡sdule Page: 326.4 Line Nò.: 5 Column: a ____ . .Ida-West, a subsidiary of Idaho Power Company, has partial ownership of
¡Schedule Page: 326.4 - Line No.: 6 Column: a--
Ida~West, a subsidiary of Idaho Power Company, hasparUal ownership of these
¡Schedule p'age: 326.4_ Line No.: 13 Column: b__
Non-Firm Purchases.
¡SChedule Page: 326.4 Line No.: 14 Column: b
Non-Firm Purchases.
ISchedule Page: 326.5 Line No.: 6 Column: b
Energy difference between mountain and pacific time schedules.
rShedule Page: 326.5 Line No.: 7 Column: b
Energy Difference between scheduled and actual receipt~.
¡sdule Page: 326.6 Line No.: 2 Column: bNon-Firm Purchases.
ISchedule Page: 326.6 Line No.: 4 Column: b
Financial Transmission Losses.
~chedule Page: 326:6 ... Line No.: 5 Column: b
Non- Firm Purchases.
r¡ecule Page: 326.6 Line No.: 9 Column: b
Non- Firm Purchases.
~ule Page: 326.6 Line No.: 11 Column: b __~~----~--Non-Firm Purchases.
~chedule Page: 326.6 . .. Line No.: 13 Column: bNon-Firm Purchases~---.---. --,-.~--_._---~,..
~chedule Page: 326.7 Line No.: 1 Column: bNon..FirmPurchases. - -----.~~--
~edule Page:3r__=-Line No.: 3 Column: b --=_:==__
Liquidated Damages.
¡Schedule Page: 326. 7 . Line No.: 5 Column: bNon-Firm Purchases.
~hëdule Page:_ 326. 7 Line No.: 8 Column: b . ___
Non-Firm Purchases.
¡Schedule Page: 326.7 Line No.: 10 Column: b ____Non-Firm Purchases.
ISchedule Page: 326.8 Line No.: 6 Column: ,,--Non~Firm Purchases-.
rSchedule Page:l!fj~~_ Line No.: 9 nu Ci~----' ..--Non-Firm Purchases.
IScheduleJfiiiii:326:8_ Line No.T1f Colum,,;b--:===----- ----------------::____Non-Firm Purchases.
---~-==------==:
____=.----~
projects.
____~_. .-::
------- =i
these projects. M_.-----.=
these ~prects-.. :~projects.
____-.
--: -i
_____J_-::
from small power producers._____~___________=J.________::
--------=-==---~::_----~
=i::
-----------~---_.._=-=~
.._------=~
__===:::
______-=_- _..=:
__--~ _ --=i
------:=- _J
u--c---=i
:==-.._____:==-:J..____:=:
II FERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2) A Resubmission 04/11/2008 20071Q4
FOOTNOTE DATA
fShedule P~e: 326.~ LineNo.: 13 __u~(Jlumn: b _==___~=~_-~=--======-~_===_===:-==-Non-Firm Purchases.~i:. -_._----,----,----_.~_._-~--...-.._-~edule Page: 326.9 Line No.: 5 CoIumn;L_________Non-Firm Purchases.
1l~lJedule eage: 326.9 Line No.: 9Non-Firm Purchases.
rshedulee~e: 326.10 Line No.: 1 Column: b_=_===_________:=_----
Non- Firm Purchases.
~hedule Page: 326.10 LineN"3-- Columfi----.:=___
Financial Transmission Losses.
IlchedulePage: 326._10 Line No.: 5 Ciii;¡--------____ ---~_____
Energy received from PGE in lieu of Boardman generation in accordance with the
energy agreement between PGE and Idaho Power, Dated 11/17/1989.
lSedule l!age: 326.10 Line No.: 6 Column: b __-=____ ________u__Non-Firm Purchases.
~eduie Page: 326.10 iii NO.:B--Column: ,,---------
Non- Firm Purchases.
~edule Page: 326.10 Line No.: 12 Column: bNon-Firm Purchases.
¡Schedule Page: 326.10 Line No.: 14 Column: bNon-Firm Purchases. ---~.-.---~--_._._,-,._._-._----~--'--
~edule Page: 326.11 Line No.: 5 Column: bNon-Firm Purchases.
¡Schedule ~age: 326.11 Line No.: 7 Column: b
Non- Firm Purchases.
Išchedule ~age: 326.11 Line No.: 11 Column: bNon-Firm Purchases.
fSedule Page: 326.1~n__ Line No.: 4 Column: b
Spinning or Operating Reserves.
¡Schedule Pa,iè:~~6.12 _ Line No.: 5 Column: b
Financial Transmission Losses.
Ilch!KulePage: 326.12 Line No.: 7 Column: b-=======___
Non- Firm Purchases.
lSëdule Page: 326.12--i.fneNo.-;--WCOumn: b u~:=~~--- __u________ _~~-. --i
Non- Firm Purchases.
fSedule Page: 326.1Z---'Line No.: 12 Column: b _u-=-=--_______________~~ ---_~Non-Firm Purchases.
Išcheule Page: 32~.13 Line No.: 1 Column: bNon-Firm Purchases.
r¡fiiiiiiiiPage: 326._13. Line No.: 5 Coiiiinn:-----.~-------_==_~-------___=__ __=.Institutional_Jutures Client Account ~greerr~rit_ with UBS.i-~at~c: March_~_~006 .u________
Išchedule Page: 326.13 Line No.: 9 Column: b .____~___________.____~__~Schedule 84 Net Metering.
¡Schedule Paiie: 326._!~__L.ine No.: 12 Column: b..' -- .u_
Scheduled losses not removed with loss transactions.~hedè Page: 326.13 -_ -Line No.: 13 Column:-b _ . _-::==- __===-===-. ___J
Scheduled losses not removed with loss transactions.
lSedule ,!age: 326.13 Line No.: 14 - Column: b -===_-~=~==_--=___--:_:-- __~_:====__--u _:--:J
Scheduled losses not removed with loss transactions.
rsedu/~Page: 326.14 . Line No.: 1 Column: b _n_____ ___ ___ __----- ==_==_-==-J
Scheduled losses not removed with loss transactions.
ISChØdule PaRe: 3~r¡.14 Line No:: 2 Column: b:=_-~:====_---=:~~_--__=_ ===~J
Scheduled losses not removed with loss transactions.
fSChiiUiaiLe: 326.14 Line No.: 3 Column: b _:-----_-:===_===: .=:==: ~_:-:~:==_:-----j
Scheduled losses not removed with loss transactions.
I
:::J
. __-====-=___-====-===--:=
Column: b ---.:_====-:~___:==-=--==_~__:=~ J
====:~_.._J
-~=~~==_--- --~-=___=:'=:
"--
"Assured"
___.....=.
.--=-_==--------===-=~_____==__-. __I
__~._:=
---_~----3
__-=-=--___ ....___-=___-=__~_______~=:
------ _ . --1
J
___~~__
~------_~_.~===~=_-J
__ _______~ .__._~---._J
----:J
I FERC FORM NO.1 (ED. 12-87)Page 450.2
This Page Intentionally Left Blank
"
-5
!f
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/11/2008 2007/Q4
FOOTNOTE DATA
~cheduliiPage: 326.14 . Line No.: 4 . CØimn:"- .Scheduled - losses- ñot removed with los-s transactions.
~Ødule Page: 326.14-iÎne No.: 5 Column: b ___
Scheduled losses not removed with loss transactions.
.-=~===___===~---".~'==
i
IFERC FORM NO.1 (ED. 12-87) Page 450.3
Name of Respondent lhis~rtIS:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) Õ A Resubmission 0411/2008
........ i NI~II T i:UH u.' t:t H.t)n¡~CCunt 456.1 )
(Including transactions referred to as 'wheelin '
1. Report all transmission of electricit, i.e., wheeling, provided for other electric utiliies, cooperatives, other public authorities,
qualifying facilties, non-traditonal utilty suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entiies 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 affilation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS . Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line Payment By Energy Received From Energy Delivered To Statistical
No.(Company of Public Authorit)(Company of Public Authority)(Company of Public Autority)Classifi-
(Footnote Affilation)(Footnote Affilation)(Footnote Affilation)cation
(a)(b)(c)(d)
1 Bonneville Power Administration - OT Bonnevile Power Administratio Oregon Trails Elecric Co-op FNO
2 Bonneville Power Administration - OT AD
3 Boneville Power Administration - US Bonnevile Power Administratio United States Bureau of Reclama FNO
4 Bonnevile Power Administration - US AD
5 Bonnevile Power Administration - Ra Bonnevile Power Administratio Raft River Electric Co-op FNO
6 Bonnevile Power Administration - Ra AD
7 Bonnevile Power Administration - PF Bonneville Power Administratio Priority Firm Customers FNO
8 Bonnevile Power Administration - PF AD
9 Milner Irrigation District United States Bureau of Reclam Milner Irrigation District OlF
10 City of Seattle Seattle Cit Light Bonnevile Power Administration OlF
11 PacifiCorp PacifiCorp West PacifiCorp West FNO
12 PacifiCorp PacifiCorp West PacifiCorp West AD
13 United States Bureau of Indian Affai Bonnevile Power Administratio United States Bureau of Indian OS
14 Pacificorp Power Marketing AD
15 Pacificrp Power Marketing PacifiCorp West PacifiCor West OS
16 Pacificrp Power Marketing PacifiCorp East PacifiCorp West OS
17 Avista Energy, Inc.Sierra Pacific Power PacifiCorp East NF
18 Avista Energy, Inc.PacifiCorp East Sierr Pacific Power NF
19 Avista Energy, Inc.NorthWesternacifiCorp East Sierra Pacific Power NF
20 Avista Energy, Inc.NortWestemlPacifiCorp East PacifiCorp East NF
21 Avista Energy, Inc.Avista Sierra Pacific Power NF
22 Avista Energy, Inc.Bonnevile Power Administratio Sierra Pacific Power NF
23 Avista Energy, Inc.AD
24 Black Hills Power Bonneville Power Administrtio PacifiCorp West NF
25 Black Hills Power PacifiCorp West Bonnevile Power Administration NF
26 Black Hils Power AD
27 Bonevile Power Admin.NortWestemlPacifCorp East PacifiCorp East NF
28 Bonevile Power Admin.PacifiCorp West Bonnevile Power Administration NF
29 Boneville Power Admin.Avista Sierra Pacific Power NF
30 Bonevile Power Admin.PacifiCorp East Bonneville Power Administration NF
31 Bonevile Power Admin.PacifiCorp West Sierra Pacific Power NF
32 Bonevile Power Admin.PacifiCorp West Bonnevile Power Administrtion NF
33 Boneville Power Admin.Avista Bonnevile Power Administration NF
34 Bonevile Power Admin.Bonnevile Power Administratio Sierra Pacific Power NF
TOTAL
FERCFORM NO.1 (ED. 12-90)Page 328
Name of Respondent
Idaho Power Company
Date of Report
(Mo, Da, Yr)
04/11/2008
Year/Period of Report
End of 2007/Q4
ccoun
(Includin transactions reffered to as 'wteelin ')
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list a/l FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for a/l single contract path, .point to point" transmission servce. 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 biling demand that is specifed in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and ü) the total megawatthours received and delivered.
FERCRate Point of Receipt Point of Delivery Billng TRANSFER OF ENERGY UneSchedule of (Subsatation or Oter (Substation or Other Demand No.Tariff Number Designation)Designation)(MW)
(e)(f)(g)(h)
389,447 389,44 1
5 2
5 -88,744 -88,7 3
5 4
5 226,163 5
5 6
5 756,307 756,30 7
5 8
Minidok, Idaho Various in Idaho 8,687 8,68 9
LYPK LGBP 10
2,085 11
12
LaGrande, Oregon Various in Idaho 15,97 13
14
JBSN ENPR 6,031 15
BOBR JBSN 91,797 16
5 M345 BOBR 10 17
5 BOBR M34 30 18
5 HTSP M345 32 19
5 HTSP BOBR 972 20
5 LOLO M345 1,847 21
5 LGBP M345 3,501 22
5 23
5 LGBP JBSN 24
5 JBSN LGBP 25
5 26
5 HTSP BOBR 27
ENPR LGBP 28
LOLO M345 29
BOBR LGBP 30
ENPR M345 31
JBSN LGBP 32
LOLO LGBP 33
LGBP M345 34
4,052,56
FERC FORM NO.1 (ED. 12-9)Page 329
Name of Respondent ThisWrtlS:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) ri A Resubmission 04/11/2008
.ur- ii y i=OR U.i ccount 456.1)
(Includinò- transactions referred to as 'wheelina')
1.Report all transmission of electricity, i.e., wheeling, provided for other electric utilties, cooperatives, other public authorities,
qualiying facilties, non-traditional utilty suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involvng the entities listed in column (a), (b) and (c).
3.Report in column (a) the company or public authorit 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 affilation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, lFP - 'long-Term Firm Point to Point
Transmission Service, OlF - Other long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or Utrue-ups' for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Une Payment By Energy Received From Energy Delivered To Statistical
No.(Company of Public Authori)(Company of Public Autority)(Company of Public Authorit)Classifi-
(Footnote Affilation)(Footnte Affilatin)(Footnote Affiliation)cation
(a)(b)(c)(d)
1 Bonevile Power Admin.AD
2 Cargill Power Markets (INCLUDES REDI Sierra Pacific Power Bonnevile Power Administration NF
3 Cargil Power Markets (INCLUDES REDI Sierra Pacific Power PacifiCorp West NF
4 Cargil Power Markets (INCLUDES REDI Bonneville Power Administratio Idaho Power Company NF
5 Cargil Power Markets (INCLUDES REDI NortWesternPacifiCorp East Sierra Pacific Power NF
6 Cargil Power Markets (INCLUDES REDI Bonnevile Power Administratio PacifiCorp West NF
7 Cargil Power Markets (INCLUDES REDI Avista Idaho Power Company NF
8 Cargil Power Markets (INCLUDES REDI PacifiCorp East Idaho Power Company NF
9 Cargill Power Markets (INCLUDES REDI PacifiCorp East NorthWesternPacifiCorp East NF
10 Cargil Power Markets (INCLUDES REDI PacifiCorp East PacifiCorp West NF
11 Cargil Power Markets (INCLUDES REDI PacifCorp West Avista NF
12 Cargil Power Markets (INCLUDES REDI Bonnevile Power Administratio PacifiCorp East NF
13 Cargil Power Markets (INCLUDES REDI PacifiCorp East PacifiCorp East NF
14 Cargil Power Markets (INCLUDES REDI Avista PacifiCorp East NF
15 Cargil Power Markets (INCLUDES REDI NorthWesternPacifiCorp East Sierra Pacific Power NF
16 Cargil Power Markets (INCLUDES RED I PacifiCorp West PacifiCorp East NF
17 Cargil Power Markets (INCLUDES REDI Avista Sierra Pacific Power NF
18 Cargil Power Markets (INCLUDES REDI Bonneville Power Administratio Sierra Pacific Power NF
19 Cargil Power Markets (INCLUDES REDI NorthWesternPacifiCorp East PacifiCorp East NF
20 Cargil Power Markets (INCLUDESREDI PacifiCorp West Bonneville Power Administration NF
21 Cargil Power Markets (INCLUDES REDI PaciflCorp East Bonneville Power Administration NF
22 Cargil Power Markets (INCLUDES RED I PacifiCorp West Sierra Pacific Power NF
23 Cargil Power Markets (INCLUDES REDI PacifiCorp West Sierra Pacific Power NF
24 cargill Power Markets (INCLUDES REDI PacifiCorp West PacifiCorp East NF
25 Cargil Power Markets (INCLUDES REDI PacifiCorp East Sierra Pacific Power NF
26 Cargil Power Markets (INCLUDES REDI PacifiCorp East Sierra Pacific Power SFP
27 cargil Power Markets (INCLUDES REDI AD
28 Citigroup Energy NortWesternPacifiCorp East PacifiCorp East NF
29 Citigroup Energy Bonnevile Power Administratio PacifiCorp East NF
30 Conoco Phillps NorthWesternPacifiCorp East Sierra Pacific Power NF
31 Conoco Phillps Bonnevile Power Administratio Sierra Pacific Power NF
32 Coral Power PacifiCorp East PacifiCorp East NF
33 Coral Power NorthWesternlPacifiCorp East PacifiCorp East NF
34 Coral Power PacifiCorp East Avista NF
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.1
Name of Respondent This :,ort Is:Date of Report Year/Period of Report
Idaho Power Company (1 )X An Original (Mo, Da, Yr)End of 2007/Q4
(2)
=A Resubmission 041111008
i-YH,- ".., ,.v.\pccount 456)(GOntinuédT
(Includino transactions reffered to as 'wneeliñcii)
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 biling demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and 0) the total megawatthours received and delivered.
FERCRate Point of Receipt Point of Delivery Biling TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand MegaWatt Hours Megavvaul1urs No.
Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)(g)(h)(i)(i)
5 1
5 M345 LGBP 25 2f 2
5 M345 ENPR 35 Sf 3
5 LGBP IPCO 50 5C 4
5 JEFF M345 57 5 5
5 LGBP JBSN 59 5~6
5 LOLO IPCO 6S 6E 7
5 BOBR IPCO 125 12f 8
5 BOBR HTSP 336 33E 9
5 BOBR JBSN 44 44 10
5 JBSN LOLO 678 6713 11
5 LGBP BOBR 826 826 12
5 MLCK BOBR 84 845 13
5 LOLO BOBR 1,64 1,64 14
5 HTSP M3 2,347 2,341 15
5 JBSN BOBR 6,101 6,101 16
5 LOLO M345 12,426 12,42E 17
5 LGBP M345 17,666 17,66E 18
5 HTSP BOBR 22,983 22,98~19
5 JBSN LGBP 28,892 28,89~20
5 BOBR LGBP 31,495 31,49f 21
5 JBSN M345 59,375 59,37f 22
5 ENPR M34 115,512 115,5U 23
5 ENPR BOBR 131,737 131,73 24
5 BOBR M34 195,737 195,73 25
5 BOBR M34 27,705 27,70f 26
5 27
5 HTSP BOBR 294 2~28
5 LGBP BOBR 588 5813 29
5 HTSP M34 51 51 30
5 LGBP M34 120 120 31
5 MLCK BOBR 105 105 32
5 HTSP BOBR 170 170 33
5 BOBR LOLO 173 17:3 34
0 4,052,567 4,052,567
FERC FORM NO.1 (ED. 12-9)Page 329.1
Name of Respondent ThiS~ort Is:Date of Report Yea~Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2007/04
(2)A Resubmission 04/11/200
01 t:Ltli i ni~i IT.. ~&~ccount 45.1)
(Including transactions referred to as 'wheelin '
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilties, non-traditional utilty suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affilation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "long-Term Firm Point to Point
Transmission Service, OlF - Other long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Une Payment By Energy Received From Energy Delivered To Statistical
No.(Company of Public Authority)(Company of Public Authority (Company of PubliC Authority)Classifi-
(Footnote Affilation)(Footnote Affilation)(Footnote Affilation)cation
(a)(b)(c)(d)
1 Coral Power Bonnevile Power Administratio Sierra Pacific Power NF
2 Coral Power PacifiCorp East Bonneville Power Administration NF
3 Coral Power PacifiCorp East Sierra Pacific Power NF
4 Energy Authorit, The NF
5 Integrys Energy NF
6 Morgan Stanley Capital Group (INCLUD PacifiCorp West PacifiCorp West NF
7 Morgan Stanley Capital Group (INCLUD PacifiCorp West PacifCorp West NF
8 Morgan Stanley Capital Group (INCLUD PacifiCorp West Sierra Pacific Power NF
9 Morgan Stanley Capitl Group (INCLUD PacifiCorp East Avista NF
10 Morgan Stanley Capitl Group (INCLUD Sierr Pacific Power Bonneville Power Administration NF
11 Morgan Stanley Capitl Group (INCLUD Avist PacifiCorp East NF
12 Morgan Stanley Capital Group (INCLUD PacifiCorp West PacifiCorp East NF
13 Morgan Stanley Capital Group (INCLUD Bonnevile Power Administratio Sierra Pacific Power NF
14 Morgan Stanley Capital Group (INCLUD PacifCorp West Bonnevile Power Administration NF
15 Morgan Stanley Capital Group (INCLUD Bonnevile Power Administratio PacifiCorp East NF
16 Morgan Stanley Capital Group (INCLUD PacifiCorp East Bonneville Power Administration NF
17 Morgan Stanley Capitl Group (INCLUD PacifiCorp East Sierra Pacific Power NF
18 Morgan Stanley Capital Group (INCLUD PacifiCorp East PacifiCorp West NF
19 Morgan Stanley Capitl Group (INCLUD Avista Sierra PaCific Power NF
20 Morgan Stanley Capitl Group (INCLUD PacifiCorp West PacifiCorp East NF
21 Morgan Stanley Capital Group (INCLUD AD
22 Pacificorp Power Marketing Avista Sierra Pacific Power NF
23 Pacificorp Power Marketing PacifiCorp West Sierr Pacific Power NF
24 Pacificorp Power Marketing PacifiCorp East PacifiCorp West NF
25 Pacificorp Power Marketing PacifiCorp Wes PacifCorp East NF
26 Pacificorp Power Marketing PacifiCorp West PacifiCorp East NF
27 Pacificorp Power Marketing PacifiCorp East Sierra Pacific Power NF
28 Pacificorp Power Marketing PacifiCorp East Sierra Pacific Power SFP
29 Pacificorp Power Marketing AD
30 Portland General Electric NorthWesternacifiCorp East PacifiCorp East NF
31 Portland General Electric Sierra Pacific Power Bonnevile Power Administration NF
32 Portland General Electric Bonnevile Power Administratio Sierra Pacific Power NF
33 portand General Electric NortWestemlPacifiCorp East Sierra Pacific Power NF
34 Portland General Elecric PacifiCorp East Bonneville Power Administration NF
TOTAL
FERC FORM NO. 1 (ED. 12-90)Page 328.2
Name of Respondent This 1i ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2)A Resubmission 04/111008
"'!-'- n!,:' , y" FOR u i i ,i;n", .\' cco~~t 456)(Contlnued)(Including transactions reffered to as 'wteelinQ'
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 biling demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billng TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand MegawãlfHours Megawatt HOurs No.Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)(g)(h)(i)(j)
5 LGBP M345 216 21E 1
5 BOBR LGBP 890 89C 2
5 BOBR M345 3,237 3,231 3
5 4
5 5
5 ENPR JBSN 25 2f 6
5 JBSN ENPR 45 4f 7
5 JBSN M345 268 26~8
5 BOBR LOLa 33 33€9
5 M34 LGBP 355 35f 10
5 LOLO BOBR 421 421 11
5 JBSN BOBR 592 59~12
5 LGBP M345 66 66~13
5 JBSN LGBP 1,272 1,27~14
5 LGBP BOBR 2,67E 2,67f 15
5 BOBR LGBP 2,75e 2,75E 16
5 BOBR M345 3,171:3,17 17
5 BOBR ENPR 3,975 3,97/18
5 LOLO M34 5,58:3 5,58:19
5 ENPR BOOR 7,24t 7,24f 20
5 21
5 LOLa M345 57 5,22
5 JBSN M34 5,875 5,87f 23
5 BOBR ENPR 22,901 22,901 24
5 ENPR BOBR 36,32f 36,32f 25
5 JBSN BOBR 53,919 53,91~26
5 BOBR M345 25,221 25,221 27
5 BOBR M345 85,604 85,6Q¿28
5 29
5 JEFF BOBR 65 6f 30
5 M345 LGBP 31:3 31.31
5 LGBP M34 31€31E 32
5 JEFF M345 356 35E 33
5 BOBR LGBP 1,002 1,00.34
~4,052,56;4,052,564
FERCFORM NO.1 (ED. 12-9)Page 329.2
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2007/04
(2) ri A Resubmissio 04/11/2008
L;L.L.V i HILiII Y i=OR u ccount 456.1 )
(Including transactions referred to as 'wheelirièi')
1. Report all transmission of electricity, Le., wheeling, provided for other electric utilties, cooperatives, other public authorities,
qualifying facilties, non-traditional utilty suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission servce 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 affilation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, lFP - "long-Term Firm Point to Point
Transmission Service, OlF - Other long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF . non.firm transmission service, OS . Other Transmission Service and AD - Out-of.Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line Payment By Energy Received From Energy Delivered To Statistical
No.(Company of Public Autority)(Company of Public Autority)(Company of Public Authority)Classifi.
(Footnote Affilation)(Footnote Affilation)(Footnote Affiliation)cation
(a)(b)(c)(d)
1 Portland General Electric Bonnevile Power Administratio PacifiCorp East NF
2 Portland General Electric NorthWestern/PacifiCorp East Bonneville Power Administration NF
3 Portland General Electric AD
4 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp East NortWesternPacifiCorp East NF
5 Powerex Corp. (INCLUDES REDIRECTS)Sierra Pacific Power PacifiCorp East NF
6 Powerex Corp. (INCLUDES REDIRECTS)Avista PacifiCorp West NF
7 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp Eat NorthWesternPacifiCorp East NF
8 Powerex Corp. (INCLUDES REDIRECTS)NorthWesternacifiCorp East Bonnevile Power Administration NF
9 Powerex Corp. (INCLUDES REDIRECTS)Sierra Pacific Power PacifiCorp West NF
10 Powerex Corp. (INCLUDES REDIRECTS)NorthWesternPacifiCorp East PacifiCorp West NF
11 Powerex Corp. (INCLUDES REDIRECTS)Seattle City Light NorthWestern/PacifiCorp East NF
12 Powerex Corp. (INCLUDES REDIRECTS)Seattle City Light Avista NF
13 Powerex Corp. (INCLUDES REDIRECTS)Seattle City Light PacifiCorp West NF
14 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp West PacifiCorp West NF
15 Powerex Corp. (INCLUDES REDIRECTS)Idaho Power Company Bonnevile Power Administration NF
16 Powerex Corp. (INCLUDES REDIRECTS)Sierra Pacific Power PacifiCorp West NF
17 Powerex Corp. (INCLUDES REDIRECTS)NortWestern/PacifiCorp East Sierra Pacific Power NF
18 Powerex Corp. (INCLUDES REDIRECTS)NorthWesternPacifiCorp East PacifiCorp East NF
19 Powerex Corp. (INCLUDES REDIRECTS)Bonneville Power Administrtio Idaho Power Company NF
20 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp West NorthWesternPacifiCorp East NF
21 Powerex Corp. (INCLUDES REDIRECTS)Bonnevile Power Administratio PacifiCorp West NF
22 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp East PacifiCorp West NF
23 Powerex Corp. (INCLUDES REDIRECTS)NortWesternPacifiCorp East Sierra Pacific Power NF
24 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp East PacifiCorp West NF
25 Powerex Corp. (INCLUDES REDIRECTS)NorthWesternPacifiCorp East PacifiCorp West NF
26 Powerex Corp. (INCLUDES REDIRECTS)Seattle City Light PacifiCorp East NF
27 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp East Avista NF
28 Powerex Corp. (INCLUDES REDIRECTS)NortWestern/PacifiCorp East Bonnevile Power Administration NF
29 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp West PacifiCorp East NF
30 Powerex Corp. (INCLUDES REDIRECTS)Sierr Pacific Power BonneviUe Power Administration NF
31 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp East PacifiCorp West NF
32 Powerex Corp. (INCLUDES REDIRECTS)Seattle City Light Bonnevile Power Administration NF
33 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp West Sierra Pacific Power NF
34 Powerex Corp. (INCLUDES REDIRECTS)Bonnevile Power Administratio PacifiCorp East NF
TOTAL
FERC FORM NO.1 (ED. 12-9)Page 328.3
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) n A Resubmission 04/11/2008
i ui- 1:U::J';1 MI~II Y , ,(1 ccount 456)(GOntlnuec)
. (Including transactions reftered to as 'wteelina')
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 servce, as identiied 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 billng demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billng TRANSFER OF ENERGY Une
Schedule of (Subsatation or Oter (Substation or Oter Demand MegaWatt Hours MegaWatt Hours No.
Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)(g)(h)(i)OJ
5 LGBP BOBR 1,846 1,S4E 1
5 JEFF LGBP 4,004 4,O~2
5 3
5 BOBR JEFF 22 2~4
5 M34 BOBR 24 2~5
5 LOLO JBSN 25 2E 6
5 BOBR HTSP 120 12C 7
5 HTSP LGBP 135 13!8
5 M345 ENPR 175 17E 9
5 JEFF JBSN 196 19E 10
5 LYPK JEFF 216 216 11
5 LYPK LOLO 216 216 12
5 LYPK M500 265 265 13
5 JBSN ENPR 293 29:3 14
5 IPCO LGBP 460 46C 15
5 M345 M500 497 49,16
5 HTSP M345 661 661 17
5 JEFF BOBR 86S 86~18
5 LGBP IPCO 928 92E 19
5 JBSN JEFF 943 ~20
5 LGBP JBSN 1,158 1,15~21
5 BOBR JBSN 1,275 1,27f 22
5 JEFF M345 1,321 1,321 23
5 BOBR ENPR 1,363 1,3~24
5 JEFF M500 1,410 1,41C 25
5 LYPK BOBR 2,072 2,07~26
5 BOBR LOLO 3,121 3,121 27
5 JEFF LGBP 4,212 4,21~28
5 JBSN BOBR 4,436 4,43E 29
5 M34 LGBP 4,86:3 4,8~30
5 BOBR M500 5,46 5,46 31
5 LYPK LGBP 6,309 6,308 32
5 JBSN M345 7,71:3 7,71~33
5 LGBP BOBR 12,798 12,79E 34
0 4,052,567 4,052,561
FERC FORM NO.1 (ED. 12-9)Page 329.3
Name of Respondent ThiswrtlS:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) 0 A Resubmission 0411/2008IOF i-UH U.I ccount 45ö.l )
(IncludinQ trnsactions referred to as 'wheelirièi')
1. Report all transmission of electricity, Le., wheeling, provided for other electric utilties, cooperatives, other public authoriies,
qualiying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS . Firm Network Transmission Service for Self, lFP - "long-Term Firm Point to Point
Transmission Service, OlF - Other long-Term Firm Transmission Servce, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups. for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line Payment By Energy Received From Energy Delivered To Statistical
No.(Company of Public Authority)(Company of Public Authority)(Company of Public Authority)Classifi-
(Footnote Affiliation)(Footnote Affilation)(Footnote Affiliation)cation
(a)(b)(c)(d)
1 Powerex Corp. (INCLUDES REDIRECTS)Avista PacifiCorp East NF
2 Powerex Corp. (INCLUDES REDIRECTS)Avista Sierra Pacific Power NF
3 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp East PacifiCorp East NF
4 Powerex Corp. (INCLUDES REDIRECTS) PacifiCorp West PacifiCorp West NF
5 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp West Bonnevile Power Administration NF
6 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp East Sierra Pacific Power NF
7 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp East Sierra Pacific Power SFP
8 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp West PacifiCorp East NF
9 Powerex Corp. (INCLUDES REDIRECTS)NortWestemlPacifiCorp East PacifiCorp East NF
10 Powerex Corp. (INCLUDES REDIRECTS)PacifCorp West Sierra Pacific Power NF
11 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp East Bonneville Power Administration NF
12 Powerex Corp. (INCLUDES REDIRECTS)Bonnevile Power Administration Sierra Pacific Power NF
13 Powerex Corp. (INCLUDES REDIRECTS)Bonnevile Power Administration Sierra Pacific Power SFP
14 Powerex Corp. (INCLUDES REDIRECTS)Seattle City Light Sierra Pacific Power NF
15 Powerex Corp. (INCLUDES REDIRECTS)Seattle City Light Sierra Pacific Power SFP
16 Powerex Corp. (INCLUDES REDIRECTS)AD
17 PP & L Montana NortWesternPacifiCorp East PacifiCorp East NF
18 PP & L Montana Bonneville Power Administration PacifiCorp West NF
19 PP & L Montana PacifiCorp East PacifiCorp East NF
20 PP & L Montana NortWestemlPacifiCorp East PacifiCorp East NF
21 PP & L Montana NorthWestemlPacifiCorp East Bonnevile Power Administration NF
22 PP & L Montana AD
23 PPM Energy PacifiCorp East PacifiCorp East NF
24 PPM Energy Bonnevile Power Administration PacifiCorp West NF
25 PPM Energy PacifiCorp West PacifiCorp East NF
26 PPM Energy PacifiCorp East Bonnevile Power Administration NF
27 PPM Energy PacifiCorp West Bonnevile Power Administration NF
28 PPM Energy Bonnevile Power Administration PacifiCorp East NF
29 PPM Energy AD
30 Puget Sound Energy Sierra Pacific Power Bonnevile Power Administration NF
31 Puget Sound Energy PacifiCorp East PacifiCorp East NF
32 Puget Sound Energy NortWestemlPacifiCorp East PacifiCorp East NF
33 Puget Sound Energy AD
34 Rainbow Energy Marketing Company Avista Sierra Pacific Power NF
TOTAL
FERC FORM NO.1 (ED. 12-9)Page 328.4
Name of Respondent ThiS~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1 )An Original (Mo, Da, Yr)End of 2007/Q4
(2)A Resubmission 0411112008
i QF ELEl, i H!~II Y ,(~ ccount 456)(ContlnUec)
(Including transactions reffered to as 'wleelina')
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 specifed in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specifed in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Biling TRANSFER OF ENERGY Une
Schedule of (Subsatation or Oter (Substation or Other Demand "legáWalfHours Megawatt HOUrs No.
Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)(g)(h)(i)(j)
5 LOLO BOBR 20,44 20,44 1
5 LOLO M34 28,699 28,69~2
5 MLCK BOBR 29,651 29,651 3
5 JBSN M500 34,146 34,14E 4
5 JBSN LGBP 41,638 41,63E 5
5 BOBR M34 25,95S 25,95f 6
5 BOBR M34 19,438 19,43E 7
5 ENPR BOBR 51,512 51,51~8
5 HTSP BOBR 69,785 69,78f 9
5 ENPR M345 84,927 84,92 10
5 BOBR LGBP 91,394 91,39~11
5 LGBP M345 97:0 97,09E 12
5 LGBP M345 9,392 9,392 13
5 LYPK M345 191,400 191,4OC 14
5 LYPK M34 59,927 59,921 15
5 16
5 HTSP BOBR 420 42(17
5 LGBP JBSN 67C 67(18
5 MLCK BOOR 1,647 1,64,19
5 HTSP BOBR 1,80C 1,80(20
5 JEFF LGBP 2,798 2,79l 21
5 22
5 MLCK BOBR 7€71 23
5 LGBP JBSN 15~154 24
5 ENPR BOOR 37~37:25
5 BOBR LGBP n1 ni 26
5 JBSN LGBP 1,08S 1,081 27
5 LGBP BOBR l,92C 1,92(28
5 29
5 M345 LGBP 5C 5C 30
5 MLCK BOBR 135 13f 31
5 HTSP BOBR 21,758 21,75E 32
5 33
5 LOLO M345 32 3.34
Cl 4,052,567 4,052,56j
FERC FORM NO.1 (ED. 12-9)Page 329.4
Name of Respondent ThiswrtlS:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) ri A Resubmision 04111/2008! OF ~UH U ,I ccount 456.1)
(Including transactions referred to as 'wheeliíig')
1.Report all transmission of electricity, Le., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilties, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service.Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms.Explain in a footnote
any ownership interest in or affilation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Servce for Self, lFP - "long-Term Firm Point to Point
Transmission Service, OlF - Other long-Term Firm Transmission Servce, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, as - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line Payment By Energy Received From Energy Delivered To Statistical
No.(Company of Public Authority)(Company of Public Autonty)(Company of Public Authorit)Classifi-
(Footnote Affilation)(Footnote Affliation)(Footnote Affilation)cation
(a)(b)(c)(d)
1 Rainbow Energy Marketing Company NortWestemlacifiCorp East Bonnevile Power Administration NF
2 Rainbo Energy Marketing Company NortWestemlPacifiCorp East PacifiCorp East NF
3 Rainbow Energy Marketing Company Bonnevile Power Administration Sierra Pacific Power NF
4 Sempra Energy Trading Corp PacifiCorp Wes Sierra Pacific Power NF
5 Sempra Energy Trading Corp NorthWestemlacifiCorp East PacifiCorp East NF
6 Sempra Energy Trading Corp NorthWestemlPacifiCorp East PacifiCorp East SFP
7 Sempra Energy Trading Corp PacifiCorp West PacifiCorp East NF
8 Sempra Energy Trading Corp Bonneville Power Administration PacifiCorp East NF
9 Sempra Energy Trading Corp Avista PacifiCorp East NF
10 Sempra Energy Trading Corp Bonneville Power Administratio Sierr Pacific Power NF
11 Sempra Energy Trading Corp Avista Sierra Pacific Power NF
12 Sempra Energy Trading Corp AD
13 Sierra Pacific Power (INCLUDES REDIRE Sierra Pacific Power Avista NF
14 Sierra Pacific Power (INCLUDES REDIRE NorthWesternlacifiCorp East PacifiCorp East NF
15 Sierr Pacific Power (INCLUDES REDIRE Avista PacifiCorp East NF
16 Sierra Pacific Power (INCLUDES REDIRE Idaho Power Company Bonnevile Power Administration NF
17 Sierra Pacific Power (INCLUDES REDIRE Bonnevile Power Administration PacifiCorp East NF
18 Sierra Pacific Power (INCLUDES REDIRE Sierra Pacific Power Bonneville Power Administration NF
19 Sierra Pacific Power (INCLUDES REDIRE PacifiCorp West PacifiCorp East NF
20 Sierra Pacific Power (INCLUDES REDIRE PacifiC East PacifiCorp East NF
21 Sierra Pacific Power (INCLUDES REDIRE NorthWestemlPacifiCorp East Sierra Pacific Power NF
22 Sierr Pacific Power (INCLUDES REDIRE PacifiCorp West Sierr Pacific Power NF
23 Sierra Pacific Power (INCLUDES REDIRE NortWestemlPacifiCorp East PacifiCorp East NF
24 Sierra Pacific Power (INCLUDES REDIRE PacifiCorp West Sierra Pacific Power NF
25 Sierr Pacific Power (INCLUDES REDIRE Bonneville Powr Administration Sierra Pacific Power NF
26 Sierra Pacific Power (INCLUDES REDIRE Bonnevile Power Administration Sierra PacifiC Power SFP
27 Sierra Pacific Power (INCLUDES REDIRE NorthWestemlPacifiCorp East Sierra Pacific Power NF
28 Sierra Pacific Power (INCLUDES REDIRE Avista Sierra Pacific Power NF
29 Sierra Pacific Power (INCLUDES REDIRE PacifiCorp East Sierra pacific Power NF
30 Sierra Pacific Power (INCLUDES REDIRE PacifiCorp East Sierra Pacific Power SFP
31 Sierra Pacific Power (INCLUDES REDIRE AD
32 Transalta AD
33 Utah Associated Municipal Power Syste PacifiCorp East Sierra Pacifi Power NF
34
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.5
This Re IOrt Is: Date of Report
(1) -IX An Original (Mo, Da, Yr)
(2) ë A Resubmission 04/1112008! L!!' -~~ ~~ iYF9J ccount 45t5)(liontlnued)
(IncludinQ transactions reffered to as 'wteelina')
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 billng demand that is specified in the firm transmission servce contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and ü) the total megawatthours received and delivered.
Year/Period of Reprt
End of 2007/04
Name of Respondent
Idaho Power Company
FERC Rate Point of Receipt Point of Delivery Biling TRANSFER OF ENERGY Line
Schedule of (Subsatation or Other (Substation or Other Demand MegaWatt Hours MegaWatt Hours No.
Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)(g)(h)(i)0)
5 JEFF LGBP 400 40(1
5 HTSP BOBR 2,400 2,40(2
5 LGBP M345 47,646 47,64 3
5 ENPR M345 2,833 2,8~4
5 HTSP BOBR 3,915 3,9H 5
5 HTSP BOBR 633 63~6
5 ENPR BOBR 4~4,63~7
5 LGBP BOBR 6,08C 6,08(8
5 LOLO BOBR 11,38E 11,38~9
5 LGBP M345 11,973 11,97~10
5 LOLO M345 12,688 12,68!11
5 12
5 M345 LOLO 50 5t 13
5 JEFF BOBR 15E 151 14
5 LOLO BOBR 280 28(15
5 IPCO LGBP 400 4OC 16
5 LGBP BOBR 71E 71!17
5 M345 LGBP 73E 731 18
5 JBSN BOBR 866 861 19
5 MLCK BOBR 2,550 2,55(20
5 HTSP M34 3,17C 3,17(21
5 ENPR M345 10,355 10,351 22
5 HTSP BOBR 25,00 25,001 23
5 JBSN M345 48,OSC 48,05t 24
5 LGBP M345 100,113 100,11'25
5 LGBP M345 1,520 1,52C 26
5 JEFF M345 115,85f 115,85f 27
5 LOLO M345 131,907 131,901 28
5 BOBR M345 129,715 129,71E 29
5 BOBR M345 47,901 47,901 30
5 31
5 32
5 BOBR M345 152 15:33
34
Cl 4,052,567 4,052,56
FERC FORM NO.1 (ED. 12-9)Page 329.5
Name of Respondent ThiS'(rtIS:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) Õ A Resubmission 04/11/2008
i ~ ........ '''Y'' Y t-9H ~ '. ' ,.., .~ cc~~t ntinued)
(Includina transactions reftered to as 'wfeelincl
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 billng 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 bils 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 bils rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and 0) mustbe reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Totl Revenues ($)Line
($)($)($)(k+l+m)No.
(k)(I)(m)(n)
1,351,834 -14,828 1,337,006 1
-72,555 -72,555 2
1,148,212 1,65 1,149,866 3
-34,997 -34,997 4
654,366 -92,085 562,281 5
-39,784 -39,784 6
2,507,72C -31,654 2,476,066 7
-163,835 -163,835 8
14,073 14,073 9
4,860 10
7,28:3 1,624 8,907 11
-371 -371 12
54,185 54,185 13
-437,356 -47,356 14
20,114 20,114 15
313,865 313,865 16
57 57 17
171 171 18
183 183 19
5,545 5,545 20
10,536 10,536 21
19,971 19,971 22
-7,729 -7,729 23
17 17 24
1,625 1,625 25
-405 -405 26
64 64 27
531 531 28
1,683 1,683 29
3,278 3,278 30
5,340 5,34 31
8,318 8,318 32
8,346 8,34 33
82,036 82,036 34
5,412,058 10,812,173 4,860 16,229,091
FEAC FORM NO.1 (ED. 12-9)Page 33
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) ñA Resubmission 04/11/2008
i I ui- t:Lt:ÇI NIV" T r-YN ~.. .... .~ lAccount 456) (vontinueci
(IncludinCl transactions reftered to as 'wneeliñeí')
9. In column (k) through (n), report the revenue amounts as shown on bils or vouchers. In column (k). provide revenues from demand
charges related to the billng 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 bils 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 bils rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and ü) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)(k+l+m)No.
(k)(I)(m)(n)
-155 -155 1
107 107 2
150 150 3
215 215 4
245 245 5
253 253 6
292 292 7
537 537 8
1,44 1,44 9
1,907 1,907 10
2,913 2.913 11
3,548 3,54 12
3,630 3,630 13
7,071 7,071 14
10,082 10,082 15
26,208 26,208 16
53,378 53,378 17
75,888 75,88 18
98,728 98,728 19
124,111 124,111 20
135,293 135,293 21
255,057 255,057 22
496,204 496,204 23
565,901 56,901 24
840,826 840,826 25
119,012 119,012 26
-70,304 -70,304 27
650 650 28
1,300 1,300 29
336 336 30
790 790 31
265 265 32
430 430 33
437 437 34
5,412,05 10,812,173 4,86 16,229,091
FEAC FOAM NO.1 (ED. 12-90)Page 33.1
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2)D A Resubmission 0411/2008
t-YH \. ~ CCOUnt 400) \umnnueo)
(Including transactions reftered to as 'wIeeling:r
9. In column (k) through (n), report the revenue amounts as shown on bils or vouchers. In column (k), provide revenues from demand
charges related to the biling 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 bils 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 bils rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and (j must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)une
($)($)($)(k+l+m)No.
(k)(I)(m)(n)
54 546 1
2,250 2,250 2
8,183 8,183 3
13 13 4
293 293 5
101 101 6
182 182 7
1,086 1,086 8
1,362 1,362 9
1,439 1,439 10
1,706 1,706 11
2,399 2,399 12
2,687 2,687 13
5,155 5,155 14
10,840 10,84 15
11,177 11,177 16
12,871 12,871 17
16,108 16,108 18
22,625 22,625 19
29,372 29,372 20
-65,64 -65,646 21
562 562 22
51,780 51,780 23
201,841 201,841 24
320,156 320,156 25
475,223 475,223 26
222,289 222,289 27
754,48 754,48 28
-68,812 -68,812 29
284 284 30
1,368 1,368 31
1,389 1,389 32
1,556 1,556 33
4,378 4,378 34
5,412,058 10,812,173 4,860 16,229,091
FERC FORM NO.1 (ED. 12-90)Page 330.2
Name of Respondent ThiS~IOrt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
(2)A Resubmission 04/11/2008
...... nivll Y i-VH U i Ht:H~ ccount 456) (Continued)
(Including transactions reflered to as i eelina')
9. In column (k) through (n), report the revenue amounts as shown on bils or vouchers. In column (k), provide revenues from demand
charges related to the biling 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 bils or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and ü) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. . Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)I Line
($)($)($)(k+I+m)No.
(k)(I)(m)(n)
8,066 8,066 1
17,495 17,495 2
-131 -131 3
89 89 4
97 97 5
101 101 6
48 483 7
54 54 8
704 704 9
789 789 10
869 869 11
869 869 12
1,067 1,067 13
1,179 1,179 14
1,851 1,851 15
2,000 2,00 16
2,660 2,660 17
3,498 3,498 18
3,735 3,735 19
3,795 3,795 20
4,665 4,665 21
5,132 5,132 22
5,317 5,317 23
5,486 5,486 24.
5,675 5,675 25
8,339 8,339 26
12,561 12,561 27
16,952 16,952 28
17,85 17,85 29
19,573 19,573 30
21,991 21,991 31
25,392 25,392 32
31,04 31,043 33
51,509 51,509 34
5,412,058 10,812,173 4,86 16,229,091
FERC FORM NO.1 (ED. 12-90)Page 330.3
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2007/04
(2) ñ A Resubmission 04/11/2008
ui- I:LI:(; I niyi I T 1" ccount 456) ((;ontinU90)
. (Including transactions reffered to as 'wfeeUnìi'ï
9. In column (k) through (n), report the revenue amounts as shown on bils or vouchers. In column (k), provide revenues from demand
charges related to the billng 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 bils 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 bils rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and 0) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Oter Charges)Total Revenues ($)Line
($)($)($)(k+I+m)No.
(k)(i)(m)(n)
82,283 82,283 1
115,508 115,508 2
119,339 119,339 3
137,431 137,431 4
167,584 167,584 5
104,46 104,46 6
78,234 78,234 7
207,325 207,325 8
280,870 280,870 9
341,814 341,814 10
367,842 367,842 11
390,792 390,792 12
37,801 37,801 13
770,346 770,34 14
241,194 241,194 15
-91,770 -91,770 16
1,33 1,334 17
2,128 2,128 18
5,232 . 5,232 19
5,718 5,718 20
8,88 8,888 21
-3,726 -3,726 22
427 427 23
865 865 24
2,095 2,095 25
4,33 4,330 26
6,117 6,117 27
10,784 10,784 28
-4,040 -4,040 29
201 201 30
542 542 31
87,367 87,367 32
-155 -155 33
100 100 34
5,412,058 10,812,173 4,860 16,229,091
FERC FORM NO.1 (ED. 12-90)Page 33.4
Name of Respondent ThiS~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2)A Resubmission 0411/2008
"I o.f , . ~ "' lACCOUI~'ntinued)
(Includino transactions reflered to as 'wheelino'
9. In column (k) through (n), report the revenue amounts as shown on bils or vouchers. In column (k), provide revenues from demand
charges related to the biling 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 bils 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 bils rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and 0) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Otr Charges)Total Revenues ($)Une
($)($)($)(k+I+I)No.
(k)(I)(m)(n)
1,255 1,255 1
7,528 7,528 2
149,44 149,44 3
21,095 21,095 4
29,152 29,152 5
4,713 4,713 6
34,499 34,499 7
45,273 45,273 8
84,806 84,806 9
89,154 89,154 10
94,478 94,478 11
-65,318 -65,318 12
159 159 13
493 493 14
891 891 15
1,273 1,273 16
2,275 2,275 17
2,338 2,338 18
2,755 2,755 19
8,113 8,113 20
10,085 10,085 21
32,94 32,94 22
79,555 79,555 23
152,868 152,868 24
318,503 318,503 25
4,836 4,83 26
368,594 368,594 27
419,653 419,653 28
412,679 412,679 29
152,394 152,394 30
-118,313 -118,313 31
-60 -60 32
579 579 33
34
5,412,058 10,812,173 4,86 16,229,091
FERC FORM NO.1 (ED. 12-90)Page 330.5
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/11/2008 20071Q4
FOOTNOTE DATA
fScheePie: 328 Line-No-:0¡-' ~- CØi-e---- ~~-- _ ---:::: - -------l
This footnote applies to all Rate schedule or Tariff number in column E that are listed as
a number 5. Number 5 indicates Open Access Transmission tariff, Volume 5, first revision.
r¡ei--e: 328 Line No.: 1 Column: h-~---- - .-._______~
The network service agreement between Idaho Power and the Bonneville Power Administration
for the Oregon Trail Electric Cooperative expires September 30, 2011. The billing demand
for network service is the customer's demand at the time of Idaho power Company
transmission system peak and varies by month.
f§iiiiiiiiiiiiiPage: 328 Line No::- 2 Column: h __J
The network service agreement between Idaho Power and the Bonneville Power Administration
for the Oregon Trail Electric Cooperative expires September 30, 2011. The billing demand
for network service is the customer's demand at the time of Idaho Power Company
transmission system peak and varies by month.
¡Schedule Page: 328--Tiio~: 3 Column: h --'--~~----~---------=:
The network service agreement between Idaho Power and the Bonneville Power Administration
for the USBR expires December 31,2014. The billing demand for network service is the
customer's demand at the time of Idaho Power Company transmission system peak and varies
by month.
¡Schedule Page: 328L.ii-No.:-4 . Column: h
The network service agreement between
for the USBR expires December 31,2014.
customer's demand at the time of Idaho
month.¡Schedule Page: 328 Line No.: 5 Column: h J
The network service agreement between Idaho Power and the Bonneville Power Administration
for Raft River expires September 30,2011. The billing demand for network service is the
customer's demand at the time of Idaho power Company transmission system peak and varies
by month.
¡Schedule Page: 328-_M"-f!No.: 6 _ Column: h __~__ -----J
The network service agreement between Idaho Power and the Bonneville Power Administration
for Raft River expires September 30,2011. The billing demand for network service is the
customer's demand at the time of Idaho power Company transmission system peak and varies
by month.
~chedu/e Page: 328 : Line No.: 7 Column: h --~------------==
The network service agreement between Idaho Power and the Bonneville Power Administaration
for the Priority Firm Customers expires December 31,2011. The billing demand for network
service is the customer's demand at the time of Idaho power Company transmission system
peak and varies by month.~hecule Page: 328 .. Line No.: 8 Column: h ---_=i
The network service agreement between Idaho Power and the Bonnevill Power Administratin
for the Priority Firm Customers expires December 31,2011. The billing demand for network
service is the customer's demand at the time of Idaho Power Company transmission system
peak and varies by month.
¡Schedule Page: 328-- Line No.: 9 Column: e
Contract prior to the Open Access Transmission Tariff.
¡Schedule Page:328- Line No.: 9 ___ Column: h
The contract between Idaho Power and the Milner Irrigation District expires
2007.¡Schedule P;Jge: 328 Line No.: 10Colii- _______:---=:=-=-=:Contract prior to the__ Open Access Transmission TarlX!_:_________
¡Schedule Page: 328 Line No.: 10 Column: h_________ ...==
The agreement between Idaho Power and the City of Seattle expires _Q~~_~~e:r)1, 20Q_2.:______
fSedule Page: 328--TJii-Ne: 10 CrJ/uinn:-m ______~~~_~__ ________u_~____________=iMonthly Customer Charge.
I FERC FORM NO. 1 (ED. 12..87) Page 450.1 I
---~--....-.
Idaho power and the Bonneville Power Administration
The billing demand for network service is the
Power Company transmissin system peak and varies by
__.____~_=:
.--------=:December 31,
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/11/2008 20071Q4
FOOTNOTE DATA
!Shedule Page: 328-Une No.: 11-COimn: h------- ____~~__~----- --=____~~~~~-J
Th~contrac~ betw~e-ñ--IdahoPower and P~cIfi~~rp =- Imnah¡: expires on aeptember 30, 2010._1
!Shedule Page: 328 Line No.: 12 Column: h --
The contract between Idaho Power and PacifiCorp - Imnaha expires on September 30, 2015-:¡Schedule Page: 328 Line No.: 13 Column: e ':=
Contract prior to the Open- Access TransiuIssII1Iff. --.-------- ..
!Schedule Page: 328 Line No.: 13 Column: h. ---- ==The agreement between Idaho Power and the United States Department of the Interior, Bureau
of Indian Affairs is subject to termination upon 90 days written notice by the bureau.
¡Schedule Page: 328 Line No.: 14 Column: e
Contract prior to the Open Access Transmission Tariff.
¡Schedule Page: 328 Line No.: 14 Column: h .
The contract between Idaho Power and PacifiCorp is for the life of Bridger project per
1992 Restated Transmissin Service Agreement (RSTA) FERC_ filing 3/9/92~
¡Schedule Page: 328 Line No.: 15 Column: e
Contract prior to the Open Access Transmission Tariff.
¡Schedule Pa~ 328 Line No.: 15 Column: h
The contract between Idaho Power and PacifiCorp is for the life of Bridger project per
1992 Restated Transmission Service Agreement (RTSA) FERC filing 3/9/92.
J
~
=:
~
rSchedule Page: 328 -~TiiieNo.:--"6 Column:e
Contract prior to the Open Access Transmission Tariff.
¡Schedule Page: 328 Line No.: 16 Column: h _ .
The contract between Idaho Power and PacifiCorp is for the life
1992 Reatated Transmission Service Agreement (RTSA) FERC filing
-==----------~
1of Bridger proj ect per3/9/92.
IFERC FORM NO.1 (ED. 12-S7) Page 450.2
Name of Respondent This ~rtIS:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) 0 A Resubmission 04/11/2008
TRANSMISSION OF ELECTRICITY BY OTHE S (Accunt 565)
(Including transactions referred to as "wheeling')
1. Report all transmission, Le. wheeling or electricity provided by other electric utilties, cooperatives, municipalities, other public
authorities, qualiying facilties, and others for the quarter.
2. In column (a) report each company or public authorit that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, lFP - long-Term Firm Point-ta-Point Transmission Reservations. OlF - Other
long-Term Firm Transmission Service, SFP . Short-Term Firm Point-ta- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bils or vouchers rendered to the respondent. In column (e) report the
demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all
other charges on bils or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all
components of the amount shown in column (g). Report in column (h) the total charge shown on bils rendered to the respondent. If no
monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement,
including the amount and type of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Line TRANSFER OF ENERG't EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHER
No.Name of Company or Public Statistical Magawatt-MagawaU.hI.emana ~nergy c~~~;~s Total Cot oftìouTstìoursCharrsCharreSTrans~iSSionAuthorit (Footnote Affilations)Classification Received Delivered ($($($
(a)(b)(c)(d)(e)(f)(g)
1 Avista Corp. WWp Div NF 197,176 197,176 831,466 831,466
2 Avist Corp. WWP Div SFP 33,223 33,223 828,659 828,659
3 BonneviHe Power Admin 520,163 520,163 1,25,632 1,225,632
4 BonneviUe Power Admin 53,892 53,892
5 Bonneville Power Admin NF 58,901 58,901 310,072 310,072
6 Bonneville Power Admin SFP 544,201 54,201 1,694,950 1,694,950
1 Bonneville Power Admin OS 16,794
8 Morgan Stanley Cap Grp NF 10,688 10,688 30,520 30,520
9 Norwestem Energy NF 10,596 10,596 55,467 55,467
10 NortWesern Energy SFP 121,244 121,244 785,298 785,298
11 NortWestern Energy ~109,355 109,355 211,079 18,462 229,541
12 PacifiCorp Inc.392,993 392,993 1,759,729 1,759,729
13 PacifCor Inc.SFP 282,349 282,349 1,126,212 1,126,212
14 Pacifrp Inc.--24,675 24,675 759,375 759,375
15 PacifiCorp Inc.OS 2,819
16 PPL Montana LLC NF -26,660
TOTAL 2,900,701 2,90,708 1,490,603 9,040,462 -61,339 10,469,726
FERC FORM NO. 113 (REV. 02-()Page 332
Name of Respondent This~rtIS:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/04
(2) 0 A Resubmission 04/11/2008
TRANSfI ISSION OF ELECTRICITY BY OTHE S (Account 565)
(Including transactions referred to as "wheeling")
1. Report all transmission, Le. wheeling or electricity pròvided by other electric utîlties, cooperatives, municipalities, other public
authorities, qualifying facilties, and others for the quarter.
2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affilation with the
transmission service provider. Use additional columns as necessary to report all companies or public authoriies that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS. Firm Network Transmission Service for Self, lFP - long-Term Firm Point-to-Point Transmission Reservations. OlF - Other
long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF . Non-Firm Transmission
Servce, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bils or vouchers rendered to the respondent. In column (e) report the
demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all
other charges on bils or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all
components of the amount shown in column (g). Report in column (h) the total charge shown on bils rendered to the respodent. If no
monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non "monetary settlement,
including the amount and tye of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Line TRANSFER OF EN ERG\' EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHER
No.Name of Company or Public Statistical Magawan-Magawau-'l~mano .Energy J.n:ner Total Cost ofnoursnoursCharrasCharraschí¥)Jes Trans~iSSionAutority (Footnote Affiliations)Classification Received Delivered ($($
~g)(a)(b)(c)(d)(e)(f)
1 Sealte Cit light NF 47,749 47,749 166,751 166,751
2 Sierr Paci Power Co NF 3,282 3,282 16,699 16,699
3 Sierr Pacific Power Co SFP 521 521 8,393 8,393
4 Snohomish County PUD NF 187,373 187,373 476,661 476,661
5 Tacoma Power NF 51,219 51,219 17,748 171,748
6 TransAlt Energy Mark NF -49,740
7 Unitd Mat Great Falls NF -4,552
8
9
10
11
12
13
14
15
16
TOTAL 2,900,70 2,900,708 1,490,603 9,04,48 -61,33 10,469,726
FERC FORM NO.113-Q (REV. 02-()Pag 332.1
This Page Intentionally Left Blank
,-~
."'
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company ì2) A Resubmission 04/11/2008 2oo71Q4
FOOTNOTE DATA
¡Schedule Page: 332 _ LineNO~:3-- ColUmn:bContract expires on 9/30/2016 .________________~____
~edu/e Page: 332 Line No.: 4 Column: b
Contract expires on 7/16/2011.
~ède/e Page: 332 Line No.: 7 -- Column:s_ _~~-_~===~_-=_==___-~____Unauthorized increase charge.
I$hedu/e Page: 332 Line No.: 11 Column: b-Contract can be terminated at anytime, with 30 days prior notice.
f$chedu/e Page: 332 Line No.: 14 Column: b____________Contract expires on 6/1/2009._______________________________
¡Schedule Page: 332- Line No.: 15 Column: g____n.________...__Transmission Study Fee.
~chedu/e Page: 332 Line No.: 16 Column: g _n__~_____._______..____
Resale Transmission.
i¡edu/e Page: 332.1 Line No.: 6 Column: gResale Transmission.
I!chedu/e Page: 332.1 Line No.: 7 Column: g_______ __________ ____Resale Transmission.
_~--~-__~~=-=:=J
____._ __---=
__.____________ ..____1
_.________~~=_
~__~=:
I
___J
------J
__J
I FERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent This ?i0rt Is:Date of ReP.rt Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/04
(2) 0 A Resubmission 04/11/2008
MISCELLNEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line DescriltiOn Amount
No.(a (b)
1 Industry Association Dues 362,971
2 Nuclear Power Research Expenses
3 Other Experimental and General Research Expenses
4 Pub & Dist Info to Stkhldrs...expn servicing outstanding Securities 270,020
5 Oth Expn =-=5,000 show purpose, recipient, amount. Group if -e $5,000
6 Rotchford Barker 17,596
7 Christine King 34,720
8 Jon Miller 76,453
9 Gary Michael 60,352
10 Richard Reiten 34,571
11 Joan Smith 47,718
12 Jan Packwod 31,600
13 Judith Johansen 29,963
14 Peter O'neill 48,333
15 Thomas Wilford 44,125
16 Robert Tintsman 47,488
17 Chambers of Commerce & Other Civic Organizations 85,610
18
19 Associated Taxpyers of Idaho 21,252
20 Association of Idaho Cities 750
21 Corporate Executive Board 146,095
22 Eastern Oregon Vsisitor Association 1,125
23 Idaho Association of Counties 2,250
24 Idaho Association of Commerce and Industry 10,000
25 Idaho Economic Development Association 1,000
26 Idaho Mining Association 2,640
27 Idaho Water Users 1,200
28 Misc Memberships (6)5,320
29 National HydroPower Assoc 23,602
30 Pacific NW Utilties 35,810
31 The Conference Board 2,850
32 Utilty Wind Interest Group 5,000
33 West Associates 22,580
34 Western Electricity Cordiniating Council 759,871
35 Wyoming Taxayers Assoc 1,500
36
37 Miscellaneous General Management:
38 New York Stock Exchange 37,461
39 PR Newswire 9,942
40
41
42
43
44
45
46 TOTAL 3,497,158
FERC FORM NO.1 (ED. 12-94)Page 335
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2S An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/11/2008 2007/Q4
FOOTNOTE DATA
IScheilePe: 33(YJo.: 5~-Column: b ~~ .=-=-=~~U_________~=-_--=~~____Recipient Purpose
Pete Wilson Design Annual ReportDeutsche Bank Broker Fees
Deutsche Bank Trust Fee Humbol t CountyGeorgeson Shareholder Letter of Agreement
Global Insight Data SubscriptionOption Expense Directors Rest Stock
Port of Morrow Port of Morrow Bond
Union Bank of Calif Sweetwater & PC Bonds
Wells Fargo S/o Service Wells Fargo TransferBroadridge Finc Solutions Proxy & Bulletin svc
Shareholder. com Shareholder WebcastingThompson Financial Analyst Service
Workorder Change Adj
Other itmes under $5,000
$
Amount
7,737
427,127
16,630
62,595
25,662
41,5645,475
10,260
140,157
51,211
14,727
15,300
489,288-92,343Misc
Total $ 1,215,390
IFERC FORM NO.1 (ED. 12-S7) Page 450.1
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) Fi A Resubmission 04/11/2008
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Account 403,404,405)
(Except amortization of aquisition adjustments)
1. Report in section A for the year the amounts for: (b) Depreciation Expense (Account 403; (c) Depreciation Expense for Asset
Retirement Costs (Account 403.1; (d) Amortization of Limited-Term Electric Plant (Account 404); and (e) Amortization of Other Electric
Plant (Account 405).
2. Report in Section 8 the rates used to compute amortization charges for electric plant (Accounts 404 and 405). State the basis used to
compute charges and whether any changes have been made in the basis or rates used from the preceding report year.
3.Report all available information called for in Section C every fifth year beginning with report year 1971, reporting annually only changes
to columns (c) through (g) from the complete report of the preceding year.
Unless composite depreciation accounting for total depreciable plant is followed, list numerically in column (a) each plant subaccount,
account or functional classification, as appropriate, to which a rate is applied. Identify at the bottom of section C the type of plant
included in any sub-account used.
In column (b) réport all depreciable plant balances to which rates are applied showing subtotals by functional Classifications and showing
composite total. Indicate at the bottom of section C the manner in which column balances are obtained.If average balances, state the
method of averaging used.
For columns (c), (d), and (e) report available information for each plant subaccount, account or functional classification Listed in column
(a).If plant mortality studies are prepared to assist in estimating average service Lives, show in column (f) the type mortality curve
selected as most appropriate for the account and in column (g), if available, the weighted average remaining life of surviving plant.If
composite depreciation accounting is used, report available information called for in columns (b) through (g) on this basis.
4. If provisions for depreciation were made during the year in addition to depreciation provided by application of reported rates, state at
the bottom of section C the amounts and nature of the provisions and the plant items to which related.
A. Summary of Depreciation and Amortization Charges
Depreciation Amortization of
Line DÏEreCiation Expense for Asset Limited Term Amortization of
No.Functional Classification xpense Retirement Costs Electric Plant Other Electric Total
(Account 403)(Account 403.1)(Account 404)Plant (Acc 405)
(a)(b)(c)(d)(e)(f)
1 Intangible Plant 8,095,753 8,095,753
2 Steam Production Plant 24,012,280 24,012,280
3 Nuclear Production Plant
4 Hydraulic Production Plant-Conventional 12,809,053 12,809,053
5 Hydraulic Production Plant-Pumped Storage
6 Other Production Plant 3,044,614 3,044,614
7 Transmission Plant 13,722,782 13,722,782
8 Distribution Plant 29,220,567 29,220,567
9 Regional Transmission and Market Operation
10 General Plant 12,486,203 12,486,203
11 Common Plant-Electric -296,299 -296,299
12 TOTAL 94,999,200 8,095,753 103,094,953
B. Basis for Amortization Charges
Account 404
Balance to be 2007 Balance to be Remaining months of
Amortized Amortization amortized 12/31/07 amortization 12/31/07
(1 )12,000 12,000 60,000 60
(2)13,283,905 480,871 12,803,025 -
(3)13,726,109 7,310,611 13,801,327 -
(4)222,578 4,084 -218
(5)6,051,936 288,187 5,763,749 240
TOTAL 33,296,528 8,095,753 32,428,100
(1) Shoshone-Bannock Tribe license and use agreement (termination date December 31,2023).
(2) Middle snake relicensing costs (amortized over a 3O-year license period).
(3) Computer software packages (amortized over a 60 month period from date of purchase).
(4) American Falls dam road rebuild.
(5) Shoshone-Bannock Right of Way (termination date December 31, 2028).
D!lnø ":':i:
Name of Respondent This
Wrt
Is: Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) FiA Resubmission 04/11/2008
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreciaoie . EStlmateCl Net Appiiea ~öl1aliy Average
No.Account No.Plant Base Avg. Service Salvage D~r. rates Curve Remaining
ral (In Th?~)sandS)7~r (perg)ent)( er~)ent)Tyge 7~l
12 310.00 203 75.00 2.27 R4.0 19.20
13 311.00 131,444 90.00 -10.00 2.59 S1.0 18.30
14 312.10 77,341 55.00 -10.00 2.76 R3.0 19.10
15 312.20 443,170 70.00 -10.00 2.89 R1.5 18.10
16 312.30 4,208 25.00 20.00 2.77 R3.0 16.40
17 314.00 126,934 50.00 -10.00 3.46 SO.5 17.20
18 315.00 61,606 65.00 2.16 S1.5 17.80
19 316.00 13,023 45.00 3.07 RO.5 16.40
20 316.10 59 9.00 25.00 1.78 L3.0 9.00
21 316.40 226 9.00 25.00 3.44 L3.0 5.40
22 316.50 124 9.00 25.00 8.45 L3.0 3.50
23 316.70 80 17.00 25.00 4.26 S2.5 8.10
24 316.80 1,115 14.00 35.00 7.01 LO.5 9.40
25 317.000 4,731
26 Subtotal Steam 864,264
27 331.00 145,330 100.00 -20.00 2.37 S1.0 36.80
28 332.10 19,460 85.00 -10.00 1.93 S4.0 31.40
29 332.20 220,997 85.00 -10.00 1.93 S4.0 34.10
30 332.30 5,600 69.00 1.44 SQUARE 63.60
31 333.00 187,856 80.00 -5.00 1.83 R3.0 38.00
32 334.00 37,537 47.00 2.85 R1.5 28.00
33 335.00 16,325 100.00 1.86 SO.O 34.90
34 336.00 7,493 75.00 1.95 R3.0 34.70
35 Subtotal Hydro 640,598
36 341.00 5,697 35.00 2.84 SQUARE 34.50
37 342.00 3,766 35.00 2.83 SQUARE 33.90
38 343.00 43,597 35.00 2.88 SQUARE 34.50
39 344.00 36,682 35.00 2.84 SQUARE 34.50
40 345.00 14,056 35.00 2.79 SQUARE 34.50
41 346.00 2,258 35.00 2.88 SQUARE 34.50
42 Subtotal Other 106,056
43 350.20 24,453 65.00 1.54 R3.0 52.30
44 350.21 4,063 24.00 4.09 SQUARE 24.00
45 352.00 40,254 60.00 -20.00 1.29 R3.0 48.00
46 353.00 262,978 45.00 -5.00 2.12 SO.5 32.70
47 354.00 121,742 60.00 -30.00 2.45 S4.0 37.30
48 355.00 88,361 55.00 -60.00 2.94 R2.0 39.90
49 356.00 139,652 60.00 -20.00 1.96 R2.0 41.40
50 359.00 318 65.00 1.07 R3.0 27.00
......" ,."',.... loin 1 /DI:\I i,,_n'2\Pane ~~7
This Page Intentionally Left Blank
~
."?
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) ¡= A Resubmission 04/11/2008
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreciaoie cstlmatea Net Appiieo MOrtality Average
No.Account No.Plant Base Avg. Service Salvage D~r. rates Curve Remaining
(a)(In Th?~~andS)7~f (pergrnt)( er~)ent)Tyge
7~f
12 Subtotal Transmission 681,821
13 361.00 21,657 55.00 -20.00 2.05 R2.5 40.70
14 362.00 151,683 50.00 1.64 01.0 43.60
15 364.00 203,942 41.00 -50.00 3.67 R1.5 29.80
16 365.00 106,512 46.00 -30.00 3.25 R2.0 29.50
17 366.00 46,129 60.00 -25.00 2.04 R2.0 51.90
18 367.00 171,154 37.00 -10.00 2.73 51.5 28.60
19 368.00 352,642 35.00 5.00 1.73 R2.0 27.10
20 369.00 53,888 30.00 -30.00 3.69 S2.0 20.50
21 370.00 56,323 30.00 4.06 L2.0 19.70
22 371.10 359 8.00 28.42 S5.0 2.30
23 371.20 2,374 11.00 -20.00 11.85 RO.5 7.00
24 373.00 4,121 20.00 -20.00 5.75 R1.0 10.90
25 374.00 259
26 Subtotal Distribution 1,171,043
27 390.11 26,486 100.00 -5.00 2.27 S1.5 38.50
28 390.12 33,804 50.00 -5.00 2.17 R3.0 36.00
29 390.20 8,590 25.00 3.85 53.0 16.90
30 391.10 13,173 20.00 9.66 SQUARE 7.70
31 391.20 22,563 5.00 20.00 SQUARE 5.00
32 391.21 2,460 6.00 16.67 S5.0 6.00
33 392.10 356 9.00 25.00 1.78 L3.0 7.90
34 392.30 2,580 15.00 50.00 3.79 52.0 15.00
35 392.40 19,739 9.00 25.00 3.45 L3.0 6.90
36 392.50 578 9.00 25.00 9.45 L3.0 9.00
37 392.60 25,961 17.00 25.00 4.72 52.5 10.20
38 392.70 4,150 17.00 25.00 4.26 S2.5 7.90
39 392.90 3,892 30.00 25.00 1.93 S1.0 21.90
40 393.00 1,075 25.00 7.89 SQUARE 8.70
41 394.00 4,410 20.00 8.31 SQUARE 8.10
42 395.00 10,232 20.00 6.53 SQUARE 9.80
43 396.00 8,710 14.00 35.00 6.99 LO.5 7.70
44 397.10 6,090 15.00 11.61 SQUARE 5.70
45 397.20 15,453 15.00 9.99 SQUARE 7.40
46 397.30 2,894 15.00 9.99 5QUARE 6.70
47 397.40 1,458 10.00 16.45 SQUARE 5.20
48 398.00 3,026 15.00 8.50 SQUARE 8.80
49 Subtotal General 217,680
50 Total Plant 3,681,462
~~"',. ~n"''' Mn 1 IDC" 1 ?_n"l\Paoe ~~71
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/04
(2) n A Resubmission 0411/2008
R GULATORY COMMISSION EXPEN ES
1. Report particulars (details) of regulatory commission expenses incurred dunng the current year (or incurred in previous years, if
being amortized) relating to format cases before a regulatory body, or cases in which such a body was a party.
2. Report in columns (b) and (c), only the current year's expenses that are not deferred and the current year's amortization of amounts
deferred in previous years.
Line Description Assessed by Expenses Total . uererrea.
No.(Furnish name of regulatory commission or body the Regulatory of Expense for in Account
Current Year .18~.3 a¡docket or case number and a description of the case)Commission Utilty (b) + (c)Beginning 0 Year
(a)(b)(c)(d)(e)
1 Federal Energy Regulatory Commission:
2 Annual admin charges assessed by FERC 2,980,908 2,980,908
3
4 General Regulatory Expenses and
5 Various other Dockem 2,455,978 2,455,971:
6
7 Regulatory Commission Expenses -Idaho
8 Expenses and various other Dockets 250,641 250,641
9
10 Oregon Hydro - Fees Amortization 158,506 158,50€
11
12 Regulatory Commission Expenses - Oregon
13 Exenses and various other Dockets 184,221 184,221
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 TOTAL 3,139,414 2,890,840 6,030,254
FERC FORM NO.1 (ED. 12-96)Page 35
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) Fi A Resubmission 0411/2008
REG ULA TORY COMMISSION EXPENSEl (Continued)
3.Show in column (k) any expenses incurred in prior years which are being amortized. List in column (a) the period of amortization.
4. List in column (f), (g), and (h) expenses incurred dunng year which were charged currently to income, plant, or other accounts.
5. Minor items (less than $25,000) may be grouped.
EXPENSES INCURRED DURING YEAR AMORTIZED DURING YEAR
CURRENTLY CHARGED TO Deferred to Contra Amount Deferred in Line
Department l\c~~m Amoum Account 182.3 Account Account 182.3 No.End of Year
(f)(h)(i (0 (k)(I)
1
Electric 928 2,980,908 2
3
Electric 928 2,455,978 4
5
6
Elecric 928 250,641 7
8
9
Electric 928 158,506 10
11
Electric 928 184,221 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
6,030,254 46
FERC FORM NO.1 (ED. 12-96)Page 351
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/04
(2) Ei A Resubmission 04/11/2008
RESEARCH, DEVELOPMENT, AND DEMONS RATION ACTIVITIES
1. Describe and show below costs incurred and accounts charged during the yer for technological research, development, and demonstration (R, 0 &
D) project initiated, continued or concluded during the year. Report also support given to others during the year for jointly-sponsored projects.(ldentify
recipient regardless of affilation.) For any R, 0 & 0 work carried with others, show separately the respondent's cost for the year and cost chargeable to
others (See definition of research, development, and demonstration in Uniform System of Accounts).
2. Indicate in column (a) the applicable classification, as shown below:
Classifications:
A. Electric R, 0 & 0 Performed Internally:a. Overhead
(1) Generation b. Underground
a. hydroelectric (3) Distributon
i. Recreation fish and wildlife (4) Regional Transmision and Market Operation
Ii Other hydroelectric (5) Enviroment (other than equipment)
b. Fossil-fuel steam (6) Other (Classify and include items in excess of $5,000.)
c. Internal combustion or gas turbine (7) Total Cost Incurred
d. Nuclear B. Electric, R, 0 & 0 Performed Exemally:
e. Unconventional generation (1) Research Support to the electrical Research Council or the Electric
f. Siting and heat rejection Power Research Institute
(2) Transmission
Line Classification Description
No.(a)(b)
1 A. Electric R, 0 & 0 Performed internally:
2 (1) Generation
3 e. unconventional generation Air Conditioning Cool Credit
4 Appliance Program
5 Change a Light Spring 2007
6 Energy House Calls
7 Irrigation Peak Rewards
8 Energy Star Northwest Homes
9 Heating & Cooling Efficiency
10 Oregon Weatherization
11 Rebate Advantage
12 Residentil Retrofit - Lighting
13 Savings with a Twist 2006
14 Weatherization Asistance Idaho
15 Building Efficiency Program
16 Easy Upgrades - Commercial
17 Oregon Commercial Audit
18 Industrial Custom Efficiency
19 Irrigation Efficiency Rewards Program
20 NEEA
21 Commercial Education Initiative
22 Other C&RD/CRC Renewable
23 Distribution Efficiency Initiative
24 Small ProjectEducation funds
25 DSM Analyis & Accunting
26 DSM Direct Proram Overhead
27 Energy Efficiency Advisory Group
28 Other
29
30
31
32 Total R, 0&0
33
34
35
36
37
FERC FORM NO.1 (ED. 12-87)Page 352
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) Fi A Resubmission 04/1112008
RESEARCH, DE VELOPMENT, AND DEMONSTRATION ACTIVITIES (Continual)
(2) Research Support to Edison Electric Institute
(3) Research Support to Nuclear Power Groups
(4) Research Support to Others (Classif)
(5) Total Cost Incurred
3. Include in column (c) all R, D & D items performed internally and in column (d) those items performed outide 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, tye 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 duóng 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 projec. This totl must equal the balance in Account 188, Research,
Development, and Demonstration Exenditures, 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 (1) with such amounts identified by
"Est."
7. Report seprately research and related testing facilties operated by the respodent.
Costs Incurred Intemally Costs Incurred Exernally AMOUNTS CHARGED IN CURRENT YEAR Unamortized Line
Curretc~ Year Current Year A~)unt Amount Accumulation No.
ld)(f)(g)
1
2
2,426,154 2,426,15~3
9,275 9,27E 4
232,331 232,331 5
336,372 336,372 6
1,615,881 1,615,881 7
475,04 475,044 8
488,211 488,211 9
3,781 3,781 10
89,269 89,269 11
316,218 316,218 12
9,096 9,096 13
1,323,624 1,323,624 14
669,032 669,032 15
711,494 711,494 16
1,981 1,981 17
3,161,866 3,161,86E 18
2,001,961 2,001,961 19
893,340 893,34 20
26,823 26,82~21
31,64 31,64 22
8,987 8,98/23
7,520 7,52C 24
732,503 732,5OC 25
56,909 56,9m 26
2,597 2,597 27
30,462 30,462 28
29
30
31
15,662,376 15,662,37E 32
33
34
35
36
FERC FORM NO.1 (ED. 12-87)Page 353
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2007/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/1112008
DISTRIBUTION OF SALARIES AND AGES
Report below the distribution of total salaries and wage!? for the year. Segregate amounts originally charged to clearing accounts to
Utilty 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.
1 Electric
2 Operation
3 Production
4 Transmission
5 Regional Market
6 Distribution
7 Customer Accounts
8 Customer Service and Informational
9 Sales
10 Administrative and General
11 TOTAL Operation (Enter Total of lines 3 thru 10)
12 Maintenance
13 Producion
14 Transmission
15 Regional Market
16 Distribution
17 Administrative and General
18 TOTAL Maintenance (Total of lines 13 thru 17)
19 Total Operation and Maintenance
20 Production (Enter Total of lines 3 and 13)
21 Transmission (Enter Total of lines 4 and 14)
22 Regional Market (Enter Total of Lines 5 and 15)
23 Distribution (Enter Total of lines 6 and 16)
24 Customer Accounts (Transcribe from line 7)
25 Customer Service and Informational (Transcribe from line 8)
26 Sales (Transcribe from line 9)
27 Administrative and General (Enter Total of lines 10 and 17)
28 TOTAL Oper. and Maint. (Total of lines 20 thru 27)
29 Gas
30 Operation
31 Producion-Manufactured Gas
32 Production-Nat. Gas (Including Expl. and Dev.)
33 Other Gas Supply
34 Storage, LNG Terminaling and Processing
35 Transmission
36 Distribution
37 Customer Accounts
38 Customer Service and Informational
39 Sales
40 Administrative and General
41 TOTAL Operation (Enter Total of lines 31 thru 40)
42 Maintenance
43 Production-Manufactured Gas
44 Production-Natural Gas (Including Exploration and Development)
45 Oter Gas Supply
46 Storage, LNG Terminaling and Processing
47 Transmission
a)
Direct PayrollDistribution
(b)
TotalLine
No.
Classification
FERC FORM NO.1 (ED. 12-8)Page 354
Name of Respondent
Idaho Power Company
This ~ort Is:
(1) ~An Original
(2) A Resubmission
IBUTION OF SALARIES AND WAGDIST
Date of Report
(Mo, Da, Yr)
04/11/2008
S (Continued)
Year/Period of Report
End of 2007/Q4
Une
No.
Classification
(a)
48 Distribution
49 Administrative and General
50 TOTAL Maint. (Enter Total of lines 43 thru 49)
51 Total Operation and Maintenance
52 Production-Manufactured Gas (Enter Total of lines 31 and 43)
53 Production-Natural Gas (Including Expl. and Dev.) (Total lines 32,
54 Oter Gas Supply (Enter Total of lines 33 and 45)
55 Storage, LNG Terminaling and Processing (Total of lines 31 thru
56 Transmission (Unes 35 and 47)
57 Distribution (Unes 36 and 48)
58 Customer Accounts (Une 37)
59 Customer Service and Informational (Une 38)
60 Sales (Une 39)
61 Administrative and General (Unes 40 and 49)
62 TOTAL Operation and Maint. (Total of lines 52 thru 61)
63 Oter Utilty Departments
64 Operation and Maintenance
65 TOTAL All Utilty Dept. (Total of lines 28,62, and 64)
66 Utility Plant
67 Construction (By Utilty Departments)
68 Electric Plant
69 Gas Plant
70 Other (provide details in footnote):
71 TOTAL Construcion (Total of lines 68 thru 70)
72 Plant Removal (By Utilty Departments)
73 Electric Plant
74 Gas Plant
75 Other (provide details in footnote):
76 TOTAL Plant Removal (Total of lines 73 thru 75)
77 Other Accounts (Specif, provide details in footnote):
78 Paid Absences
79 Preliminary Survey & Investigations
80 Oter Accounts
81
82
83
84
85
86
87
88
89
90
91
92
93
94
95 TOTAL Other Accunts
96 TOTAL SALARIES AND WAGES
17,092,558
72,706
6,811,728
17,092,558
72,706
6,811,728
23,976,992
173,971,688
23,976,992
177,966,6483,994,960
FERC FORM NO.1 (ED. 12-8)Page 355
This Page Intentionally Left Blank
,.-"
."1
Name of Respondent
Idaho Power Company
his 1!0rt Is: Date of Report
(1) IlAn Original (Mo, Da, Yr)
(2) A Resubmission 04/11/2008
M NTHLY TRANSMISSION SYSTEM PEAK LOAD
(1) Report the monthly peak load on the respondent's transmission system. If the respondent has two or more power systems which are not physically
integrated, furnish the required information for each non-integrated system.
(2) Report on Column (b) by month the transmission system's peak load.
(3) Report on Columns (c ) and (d) the specified information for each monthly transmission - system peak load reported on Column (b).
(4) Report on Columns (e) through OJ by month the system' monthly maximum megawatt load by statistical classifications. See General Instrucion for
the definition of each statistical classification.
Year/Period of Report
End of 2007/Q4
NAME OF SYSTEM: Idaho Power Company
Une
No.Month
(a)
1 Janary
2 Februry
Totl for Quarter 1
Total for Quarter 2
Tot for Quartr 4
Tot Year 10
Dalelear
Monthly Peak Day of Hour of Firm Network Firm Network Long-Term Fir
MW-Total Monthly Monthly Service fOr Self Serv for Point-to-point
Peak Peak Ots Reservatins
(b)(g)
.
1,81
1,705
1,43
4,960
1,463
2,209
2,661
6,333
2,868
1,817
1,530
6,215
292
1,969
1,862
4,123
Oter Long-
Term Firm
Servic
(h)
Short-Term Firm
Point-to-point
Reservation
(i)0)
38,18 21,631 2,796
Oter
Service
474
54
539
1,559
354
264
308
926
30
1,047
1,148
2,504
1,430
140
363
1,933
6,922
FERC FORM NO. 113-0 (NEW. 07-J4)Page 40
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) Fi A Resubmission 04111/2008
ELECTRIC ENERGY ACCOU~ T
Report below the information called for conceming the disposition of electric energy generated, purchased, exchanged and wheele during the year.
Line Item MegaWatt Hours Line Item MegaWatt Hours
No.No.
(a)(b)(a)(b)
1 SOURCES OF ENERGY 21 DISPOSITION OF ENERGY
2 Generation (Excluding Station Use):22 Sales to Ultimate Consumers (Including 14,541,825
3 Steam 7,144,279 Interdepartmental Sales)
4 Nuclear 23 Requirements Sales for Resale (See 57,436
5 Hydro-Conventional 6,181,322 instruction 4, page 311.)
6 Hydro-Pumped Storage 24 Non-Requirements Sales for Resale (See 2,686,211
7 Oter 222,410 instruction 4, page 311.)
8 Less Energy for Pumping 25 Energy Furnished Without Charge
9 Net Generation (Enter Total of lines 3 13,548,011 26 Energy Used by the Copany (Electric
through 8)Dept Only, Excluding Station Use)
10 Purchases 5,195,984 27 Total Energy Losses 1,258,845
11 Power Exchanges:28 TOTAL (Enter Total of Lines 22 Through 18,54,317
12 Received 104,827 27) (MUST EQUAL LINE 20)
13 Delivered 293,02-4
14 Net Exchanges (Line 12 minus line 13)-188,191
15 Transmission For Other (Wheeling)
16 Received 4,052,567
17 Delivered 4,06,02S
18 Net Transmission for Other (Line 16 minus -11,461
line 17)
19 Transmission By Oters Losses
20 TOTAL (Enter Total oflines 9,10,14,18 18,54,311
and 19)
FERC FORM NO.1 (ED. 12-90)Page 401a
Name of Respondent This e ort Is:Date of Report Year/Period of Report
Idaho Power Company (1 )X An Original (Mo, Da, Yr)End of 2007/04
(2)== A Resubmission 04/11/2008
MONTHLY PEAKS AND OUTPUT
(1) Report the monthly peak load and energy output. If the respondent has two or more power which are not physically integrated, furnish the required
information for each non- integrated system.
(2) Report on line 2 by month the system's output in Megawatt hours for each month.
(3) Report on line 3 by month the non-requirements sales for resale. Include in the monthly amounts any energy losses associated with the sales.
(4) Report on line 4 by month the system's monthly maximum megawatt load (60 minute integration) associated with the system.
(5) Reprt on lines 5 and 6 the specified information for each monthly peak load reported on line 4.
NAME OF SYSTEM:Idaho Power Company
Un Monthly Non-Requirments MONTHLY PEAKSales for Resale &
No.Month Total Monthly Energy Associated Losses Megawatts (See Instr. 4)Day of Month Hour
(a)(b)(c)(d)(e)(f)
25 January 1,745,492 363,384 2,422 16 8AM
3C February 1,318,82a 211,820 2,268 2 8AM
31 March 1,463,24S 372,625 2,023 1 7PM
32 April 1,297,582 212,871 1,937 30 6PM
3~May 1,455,149 92,335 2,48 31 7PM
3.June 1,736,261 207,301 3,009 28 6PM
3E July 1,991,363 175,571 3,193 13 4PM
3f August 1,806,531 205,281 2,904 1 7PM
37 September 1,462,172 226,921 2,695 3 7PM
3a OCtober 1,34,230 232,723 1,838 31 8AM
39 November 1,317,419 145,751 2,130 30 8AM
40 December 1,607,042 239,628 2,287 11 8AM
41 TOTAL 18,54,317 2,686,211
i:i:ar. i:nau Nn 1 ii=n 1 ~-M\Paae 401b
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)2007/Q4(2)o A Resubmission 0411112008 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Report data for plant in Service only.2. Large plants are steam plants wit installed capacity (name plate rating) of 25,000 Kwor more. Report in
this page gas-turbine and internal cobustion plants of 10,000 Kw or more, and nuclear plants.3. Indicate by a footnte any plant leased or operated
as a joint facilty.4. If net peak demand for 60 minutes is not available, give data which is available, specifying perio.5. If any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant.6. If gas is used and purchased on a
therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost
per unit of fuel bumed (Line 41) must be consistent with charges to expense accunts 501 and 547 (Line 42) as show on Line 20.8. If more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
Line Item Plant Plant
No.Name: Jim Briger Name: Boardman
(a)(b)(c)
1 Kind of Plant (Internal Comb, Gas Turb, Nuclear Steam Steam
2 Type of Constr (Conventional, Outdoor, Boiler, etc)Semi-Outdoor Boiler Conventional
3 Year Originally Constructed
4 Year Last Unit was Installed 1979 1980
5 Total Installed Cap (Max Gen Name Plate Ratings-MW)
6 Net Peak Demand on Plant - MW (60 minutes)716 60
7 Plant Hours Connected to Load 8759 7703
8 Net Continuous Plant Capabilty (Megawatts)0 0
9 When Not Limited by Condenser Water
10 When Limited by Condenser Water 0 0
11 Average Number of Employees 0 0
12 Net Generation, Exclusive of Plant Use - KWh 5027859000 436616000
13 Cost of Plant: Land and Land Rights 494358 106610
14 Strutures and Improvements 63385775 13754891
15 Equipment Costs 397769026 55799812
16 Asset Retirement Costs 0 0
17 Total Cost 461649159 69661313
18 Cost per KW of Installed Capacit (line 17/5) Including 599.1553 1084.7293
19 Prouction Expenses: Oper, Supv, & Engr 142655 833210
20 Fuel 72804161 6291429
21 Coolants and Water (Nuclear Plants Only)0 0
22 Steam Expenses 404307 0
23 Steam From Oter Sources 0 0
24 Steam Transferred (Cr)0 0
25 Electric Expenses 0 0
26 Misc Steam (or Nuclear) Power Exenses 6132445 253061
27 Rents 247399 0
28 Allowances 0 0
29 Maintenance Supervision and Engineering 290118 2288516
30 Maintenance of Strucures 0 0
31 Maintenance of Boiler (or reactor) Plant 8049032 0
32 Maintenance of Electric Plant 2707127 0
33 Maintenance of Misc Steam (or Nuclear) Plant 5623393 16285
34 Total Production Expenses 10039637 9682501
35 Expenses per Net KWh 0.0199 0.0222
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)Coal Oil Coal Oil
37 Unit (Coal-tons/Oil-barreVGas-mcf/Nuclear-indicate)Tons Barrels Tons Barrels
38 Quantity (Units) of Fuel Burned 2855550 21655 0 261586 617 0
39 Avg Heat Cont - Fuel Bumed (btulndicate if nuclear)9096 140000 0 8357 138800 0
40 Avg Cost of Fuel/unit, as Delvd to.b. during year 24.015 97.825 0.000 23.746 93.920 0.000
41 Average Cost of Fuel per Unit Burned 24.020 68.725 0.000 22.522 89.275 0.000
42 Average Cost of Fuel Bumed per Milion BTU 1.324 11.688 0.00 1.36 15.308 0.000
43 Average Cost of Fuel Bumed per KWh Net Gen 0.014 0.00 0.000 0.014 0.000 0.000
44 Average BTU per KWh Net Generation 10330.000 0.000 0.000 9901.000 0.000 0.000
FERC FORM NO.1 (REV. 12-G3)Page 402
Name of Respondent This~rtIS:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)2007/Q4(2)o A Resubmission 04/11/2008 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Oter Power Supply Expenses.10. For IC and GT plants, report Operating Expnses, Account Nos.
547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants
designed for peak load service. Designate automatically operated plants.11. For a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined
cycle operation wi 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 tye and quanti for the
reprt period and other physical and operating characteristics of plant.
Plant Plant Plant Line
Name: Valmy Name:Danskin Name:Bennett Mountain No.
(d)(e)(f)
Steam Gas Turbine Gas Turbine 1
==Conventional Conventional 2
2001 2005 3
2001 2005 4
91.80 172.80 5
288 94 192 6
8561 567 1219 7
0 90471 164159 8
0 0 9
0 0 0 10
0 7 4 11
167984000 383000 183930000 12
769351 402745 0 13
5402963 4276833 1388528 14
274317434 4759492 51875802 15
0 0 0 16
329389748 52273970 532640 17
1161.8686 569.432 308.2427 18
689008 158224 40876 19
35741649 446961 15019887 20
0 0 0 21
2796802 0 0 22
0 0 0 23
0 0 0 24
2109888 182179 196417 25
1682728 1335 144253 26
48376 0 0 27
0 0 0 28
1613 0 0 29
649264 128229 90697 30
6581028 18979 3525 31
2978251 418715 158696 32
295173 0 0 33
53573780 5476842 156551 34
0.3189 0.1428 0.0851 35
Coal Oil Gas Gas 36
Tons Barrels MCF MCF 37
817341 7610 0 580326 0 0 1859933 0 0 38
9689 138778 0 1038 0 0 1038 0 0 39
40.917 105.774 0.000 7.646 0.000 0.000 8.076 0.000 0.00 40
41.108 103.332 0.000 7.846 0.000 0.000 8.076 0.000 0.000 41
2.081 17.727 0.000 7.366 0.000 0.000 7.780 0.000 0.000 42
0.021 0.000 0.000 0.116 0.000 0.000 0.082 0.000 0.000 43
9638.000 0.000 0.000 15709.000 0.000 0.000 10496.000 0.000 0.000 44
FERC FORM NO.1 (REV. 12-()Page 403
This Page Intentionally Left Blank
.~
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/11/2008 2oo7/Q4
FOOTNOTE DATA
~~du/ePag~4jj2-UÎJe--jo!;3 _çoiiimii_:j!_=~~=-.-=-=~==-=-=:_=-~==.-~'_ _---=-=__._
This footnote applies to lines 3 and 4. The Jim Bridger Power
Plant consists of four equal units constructed jointly by Idaho
Power Company and Pacific Power and Light Company, with Idaho
owning 1/3 and PacifiCorp owning 2/3. Unit #1 was placed in
commercial operation November 30, 1974, Unit #2 December 1, 1975,
Unit #3 September 1, 1976, and Unit #4 November 29, 1979.
iScheciuïe Page: 402 Line No.: 3 Column: c_..- ----
This footnote applies to lines 3 and 4. The Boardman plant
consists of one unit constructed jointly by Portland General
Electric Company, Idaho Power Company, and Pacific Northwest
Generating Company, with Idaho Power Company owning 10%. The
unit was placed in commercial operation August 3, 1980.~u/e !!agé: 402 __ Line No.:~ Column: d __~=~~=-____________
This footnote applies to lines 3 and 4. The Valmy plant consists
of two units constructed jointly by Sierra Pacific Power Company
and Idaho Power Company, with Sierra owning 1/2 and Idaho owning
1/2. Unit #1 was placed in commercial operation December 11, 1981
and Unit #2 May 21, 1985.
~hedu/e Page: 402 __Line No.: 5 .Çolumn:Lm ----------
This footnote applies to line 5 and lines 12 through 43.
Information reflects Idaho Power Company's share as explainedin note fo:r_ line _ 3 page 402column_~______._________ ________
rSchedule. Page: 402 Line No.: 5 Column: c__
This footnote applies to line 5 and lines 12 through 43.
Information reflects Idaho Power Company's share as explained
in note on line 3 page 402 column C
¡sedule Page: 402__ Line No.: 5 Column: d . . ---- _ _____._~--
This footnote applies to line 5 and lines 12 through 43.
Information reflects Idaho Power Company's share as explained
in note for line 3 page 403 column D.
¡Schedule Page: 402.- Line No.: 9 Column: b__
This footnote applies to lines 9, 10, and 11. PacifiCorp
as operator of the plant will report thisinformation.
f$edu/e Page: 402- _ Line No.: 9 Column: c - __------- --- -
This footnote applies to lines 9, 10, and 11. Portland General
Electric Company, as operator will report this information.
fSchedule Page: 402 -- i.ne¡¡¡'-::9-Co¡umii:d~_=______ ___ ___~.=-~-------- -
This footnote applies to lines 9, 10, and 11. Sierra Pacific
Power, as operator of. the plant, will report this information.
-----l
_______ _ --~=-_===~.~.==J
-"-~J
::~~_~~m__J
-----~~
..1
IFERC FORM NO. 1 (ED. 12-S7) Page 450.1
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)2007/04
(2) 0 A Resubmission 04/11/2008 End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1.Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
a footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Line Item FERC Licensed Project No.2736 FERC Licensed Project No.1975
No.Plant Name: American Falls Plant Name: Bliss
(a)(b)(c)
1 Kind of Plant (Run-of-River or Storage)Run-of-River Run-of-River
2 Plant Construction type (Conventional or Outdoor)Outdoor Outdoor
3 Year Originally Constructed 1978 1949
4 Year Last Unit was Installed 1978 1950
5 Total installed cap (Gen name plate Rating in MW)92.30 75.00
6 Net Peak Demand on Plant-Megawatts (60 minutes)88 68
7 Plant Hours Connect to Load 6,868 8,753
8 Net Plant Capabilty (in megawatts)
9 (a) Under Most Favorable Oper Conditions 109 76
10 (b) Under the Most Adverse Oper Conditions 0 1
11 Average Number of Employees 4 4
12 Net Generation, Exclusive of Plant Use - Kwh 262,405,000 318,932,000
13 Cost of Plant
14 Land and Land Rights 875,318 676,645
15 Structures and Improvements 11,974,476 719,557
16 Reservoirs, Dams, and Waterways 4,293,075 8,186,692
17 Equipment Costs 31,152,568 7,072,055
18 Roads, Railroads, and Bridges 839,276 486,477
19 Asset Retirement Costs 0 0
20 TOTAL cost (Total of 14 thru 19)49,134,713 17,141,426
21 Cost per KW of Installed Capacity (line 20 / 5)532.3371 228.5523
22 Production Expenses
23 Operation Supervision and Engineering 175,578 614,245
24 Water for Power 2,002,227 169,300
25 Hydraulic Expenses 105,920 461,767
26 Electric Expenses 40,511 45,533
27 Misc Hydraulic Power Generation Expenses 256,085 164,574
28 Rents 152 2,969
29 Maintenance Supervision and Engineering 104,858 105,578
30 Maintenance of Structures 82,178 42,046
31 Maintenance of Reservoirs, Dams, and Waterways 4,547 26,534
32 Maintenance of Electric Plant 187,945 120,220
33 Maintenance of Misc Hydraulic Plant 148,018 101,091
34 Total Production Expenses (total 23 thru 33)3,108,019 1,853,857
35 Expenses per net KWh 0.0118 0.0058
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2007/Q4
This ~rt Is: Date of Report
(1) IlAn Original (Mo, Da, Yr)
(2) DA Resubmission 04/11/2008
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No. 1971
Plant Name: Brownlee
(d)
FERC Licensed Project No. 2848
Plant Name: Cascade
(e)
FERC Licensed Project No. 1971
Plant Name: Oxbow
Line
No.
Storage
Outdoor
1958
1980
585.40
635
8,760
Run-of-River
Outdoor
1983
1984
12.42
12
8,638
Storage
Outdoor
1961
1961
190.00
218
8,760
17,086,224 82,142 1,137,645
30,545,607 7,364,154 9,974,169
66,925,091 3,145,630 30,375,714
51,770,609 12,733,856 15,230,301
518,444 122,668 565,842
0 0 0
166,845,975 23,448,450 57,283,671
285.0119 1,887.9589 301.4930
545,976 133,673 276,741
154,784 104,795 72,024
677,644 231,329 327,120
362,369 82,658 200,901
414,223 172,312 224,199
231,040 110 39,673
351,817 92,000 269,736
144,385 11,200 310,949
53,887 14,008 158,676
457,981 132,808 134,363
510,214 84,150 400,134
3,904,320 1,059,043 2,414,516
0.0021 0.0285 0.0031
I"___ An"7
Name of Respondent This~rtIS:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)2007/Q4
(2) D A Resubmission 041111008 End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1.Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facilty, indicate such facts in
a footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Line Item FERC Licensed Project No.1971 FERC Licensed Project No.2726
No.Plant Name: Hells Canyon Plant Name: Malad
(a)(b)(c)
1 Kind of Plant (Run-of-River or Storage)Storage Run-of-River
2 Plant Construction type (Conventional or Outdoor)Outdoor Outdoor
3 Year Originally Constructed 1967 1948
4 Year Last Unit was Installed 1967 1948
5 Total installed cap (Gen name plate Rating in MW)391.50 21.77
6 Net Peak Demand on Plant-Megawatts (60 minutes)405 26
7 Plant Hours Connect to Load 8,760 8,760
8 Net Plant Capabiliy (in megawatts)
9 (a) Under Most Favorable Oper Conditions 445 25
10 (b) Under the Most Adverse Oper Conditions 137 21
11 Average Number of Employees 5 1
12 Net Generation, Exclusive of Plant Use. Kwh 1,560,339,000 163,575,000
13 Cost of Plant
14 Land and Land Rights 1,558,955 205,376
15 Structures and Improvements 2,403,495 2,516,767
16 Reservoirs, Dams, and Waterways 52,511,953 3,531,422
17 Equipment Costs 15,117,778 3,378,169
18 Roads, Railroads, and Bridges 819,192 304,683
19 Asset Retirement Costs 0 0
20 TOTAL cost (Total of 14 thru 19)72,411,373 9,936,417
21 Cost per KW of Installed Capacity (line 20 / 5)184.9588 456.4271
22 Production Expenses
23 Operation Supervision and Engineering 274,365 101,726
24 Water for Power 73,903 519,539
25 Hydraulic Expenses 312,773 113,376
26 Electric Expenses
.'.'131,879 62,926
27 Misc Hydraulic Power Generation Expenses 240,367 62,154
28 Rents 66,279 0
29 Maintenance Supervision and Engineering 225,473 57,416
30 Maintenance of Structures 61,720 48,213
31 Maintenance of Reservoirs, Dams, and Waterways 86,692 5,197
32 Maintenance of Electric Plant 130,349 47,500
33 Maintenance of Misc Hydraulic Plant 614,676 75,005
34 Total Production Expenses (total 23 thru 33)2,218,476 1,093,052
35 Expenses per net KWh 0.0014 0.0067
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)2007/Q4
(2) D A Resubmission 04/11/2008 End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1.Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facilty, indicate such facts in
a footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Line Item FERC Licensed Project No.27n FERC Licensed Project No.2n8
No.Plant Name: Upper Salmon Plant Name: Shoshone Falls
(a)(b)(c)
1 Kind of Plant (Run-of-River or Storage)Run.of-River Run-of-River
2 Plant Construction type (Conventional or Outdoor)Outdoor Conventional
3 Year Originally Constructed 1937 1907
4 Year Last Unit was Installed 1947 1921
5 Total installed cap (Gen name plate Rating in MW)34.50 12.50
6 Net Peak Demand on Plant-Megawatts (60 minutes)39 13
7 Plant Hours Connect to Load 8,760 5,546
8 Net Plant Capabilty (in megawatts)
9 (a) Under Most Favorable Oper Conditions 39 14
10 (b) Under the Most Adverse Oper Conditions 32 11
11 Average Number of Employees 4 2
12 Net Generation, Exclusive of Plant Use. Kwh 226,157,000 55,613,000
13 Cost of Plant
14 Land and Land Rights 172,970 311,407
15 Structures and Improvements 1,546,638 1,199,262
16 Reservoirs, Dams, and Waterways 4,777,191 512,402
17 Equipment Costs 6,437,887 2,315,859
18 Roads, Railroads, and Bridges 29,359 51,383
19 Asset Retirement Costs 0 0
20 TOTAL cost (Total of 14 thru 19)12,964,045 4,390,313
21 Cost per KW of Installed Capacity (line 20/5)375.7694 351.2250
22 Production Expenses
23 Operation Supervision and Engineering 351,438 131,564
24 Water for Power 60,683 34,510
25 Hydraulic Expenses 276,909 137,674
26 Electric Expenses 19,882 12,568
27 Misc Hydraulic Power Generation Expenses 169,612 69,950
28 Rents 0 29
29 Maintenance Supervision and Engineering 97,478 116,802
30 Maintenance of Structures 80,176 154,659
31 Maintenance of Reservoirs, Dams, and Waterways 33,990 3,759
32 Maintenance of Electric Plant 126,595 29,785
33 Maintenance of Misc Hydraulic Plant 98,962 64,942
34 Total Production Expenses (total 23 thru 33)1,315,725 756,242
35 Expenses per net KWh 0.0058 0.0136
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2007/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) D A Resubmission 04/11/2008
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accunts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Oter Expenses classified as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No. 2055
Plant Name: C J Strike
(d)
FERC Licensed Project No. 503
Plant Name: Swan Falls
(e)
FERC Licensed Project No.
Plant Name: Twin Falls
f
18 Line
No.
Run-of.River
Outdoor
1952
1952
82.80
85
8,758
Run-of-River
Conventional
1910
1994
25.00
22
8,759
Run-of-River
Conventional
1935
1995
52.74
39
8,571
3,302,043 51,675 255,499
2,892,897 25,232,769 10,808,047
10,033,408 13,856,887 7,932,716
7,418,814 30,378,323 20,598,630
248,183 835,946 1,917,603
0 0 0
23,895,345 70,355,600 41,512,495
288.5911 2,814.2240 787.1159
887,694 295,748 217,274
243,786 71,831 50,130
1,240,232 272,165 125,511
31,576 28,026 42,004
328,197 145,994 146,282
67,657 7,843 1,098
164,237 67,429 33,919
101,516 59,448 32,Q8
68,828 61,827 3,749
182,046 68,838 59,769
208,808 101,617 58,604
3,524,577 1,180,766 770,388
0.0090 0.0100 0.0088
---- --_.. ..- .. ,--,. .." "",\D~fto An'71
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2007/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)(2) DA Resubmissìon 04/11/2008
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No. 1971
Plant Name: Common Facilties
(d)
FERC Licensed Project No. 2061
Plant Name: Lower Salmon
(e)
FERC Licensed Project No. 2899
Plant Name: Milner
Line
No.
0.00
o
o
Run-of-River
Outdoor
1949
1949
60.00
47
8,760
Run-of-River
Conventional
1992
1992
59.45
40
6,400
114,367 403,707 138,100
25,941,940 1,362,364 10,326,813
13,556,785 6,603,461 17,147,050
1,183,136 6,877,680 27,574,117
99,051 88,693 501,877
0 0 0
40,895,279 15,335,905 55,687,957
0.0000 255.5984 936.7192
0 1,109,770 114,144
0 160,154 1,338,577
4,322,824 728,507 70,875
0 183,038 44,885
0 264,588 145,513
0 1,283 1,520
3,189 112,586 59,065
0 77,497 41,526
0 5,945 6,698
0 235,429 145,639
76,676 113,718 65,904
4,402,689 2,992,515 2,034,346
0.0000 0.0139 0.0304
.._-- .."""".. ..'" .. 'nr!\1 .oll'.n~\D'!fto Aft7"
This Page Intentionally Left Blan
-=
:"
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2) A Resubmission 04111/2008 2007/04
FOOTNOTE DATA
¡Schedule Page: 406 Line No.: 1 Column: b
American Falls generating capacity is dependent upon water releases controlled by the
United States Bureau of Reclamation.
¡Schedule Page: 406 Line No.: 1 Column: e
Cascade generating capacity is dependent upon water releases controlled by the United
States Bureau of Reclamation.
¡Schedule Page: 406 Line No.: 1 Column: f
Upstream storage in Brownlee Reservoir.
¡Schedule Page: 406.1 Line No.: 1 Column: b
Upstream storage in Brownlee Reservoir
¡Schedule Page: 406.1 Line No.: 1 Column: cLower Malad maximum demand 15,000 Kw, Upper Malad maximum demand 9,000 Kw non-coincident.
IFERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent ThiS~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
(2)A Resubmission 04/11/2008
GENERATING PLANT STATISTICS (Small Plants)
1. Small generating plants are steam plants of, less than 25,000 Kw; internal combustion and gas turbine-plants. conventional hydro plants and pumped
storage plants of less than 10,00 Kw installed capacity (name plate rating).2. Designte any plant leased from others, operated under a license from
the Federal Energy Regulatory Commission, or operated as a joint facilit, and give a cocise statement of the facts in a footnote. If licensed project,
give project number in footnote.
Una Year .instaiiec va~~!!y fiet Peak Net GenerationName of Plant Orig.Name Plate atin Demand Excluding Cost of Plant
No.eost.(InMW)MW Plant Use
(a)(b)(c)(60(m1n.)(e)(f)
1 Hydro:
2 Clear Lakes 1937 2.50 2.3 17,091 1,759,032
3 Thousand Springs 1912 8.80 6.2 52,82E 4,730,494
4
5
6 Intemal Combustion:
7 Salmon Diesel (1)1967 5.00 5.0 134 901,055
8
9
10
11 (1) Salmon units are classified as standby.
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
E:i=al" E:naM Nn 1 iai=v 1 ~..'n PAnA 410
Name of Respondent This
Wrt
Is: Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) Õ A Resubmission 04111/2008
GENERATING PLANT STATISTICS (Small Plants) (Continued)
3. Ust 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, speifying period.5. If any plant is equipped wit
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 utilzed in a steam turbine regenerative feed water cycle, or for preheated combustion air in a boiler, report as one plant.
Plant Cost (Incl Asset Operation I"roauction i:xpenses Fuel Costs (in cents UneRetire. Costs) Per MW Exc'l. Fuel f"uei Maintenance Kind of Fuel (per Milion Btu)
(g)(h)(i)ül (k)(i)
No.
1
703,613 78,458 55,138 2
537,55 117,552 71,48 3
4
5
6
180,211 Diesel 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 (REV. 12-Ðl Paae 411
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) Ei A Resubmission 0411/2008
TRANSMISSION UNE STATIST CS
1. Report information concerning transmission lines, cost of Iines, and expenses for year. Ust each transmission line having nominal voltge 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 Propert.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wo or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more thn one type of supporting structure, indicate the mileage of each tye of construction
by the use of brackets and extra lines. Minor portions of a transmision line of a diferent tye of construction need not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total poe miles of each transmission line. Show in column (f) the pole miles of line on strucures the cost of which is
reported for the line designated; conversely, show in column (g) the pole mile 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 ocupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Une IKVI Type of LEn~Ji~ ~gie .wileS)
(Indicate w1ere NumberNo.other than u ëlergrounifiines
60 cvcle, 3Dhasel Supporting report circuit miles)Of
From To Operating Designed un ~lrt,ciure urif~i.h~res CircuitsStructureof.Un~a l)ot er
(a)(b)(c)DeS1aja ed ne
(d)(e)(g)(h)
1 Boardman Slatt 500.0!500.00 STower 1.79 1
2
3 Borah Midpoint 345.01 500.00 STower 85.17 1
4 Jim Bridger Goshen 345.!345.00 STower 226.17 1
5 State Une Midpoint 345.01 345.00 STower 76.8 2
6 Kinport Borah 345.01 345.00 STower 27.31 1
7 Midpoint Borah #1 345.0(345.00 HWood 79.36 1
8 Midpoint Borah #2 345.01 345.00 HWood n.59 2
9 Adelaide Tap Adelaide 345.0(345.00 HWood 2.67 2
10
11 Quart LaGrande 230.01 230.00 HWoo 46.24 1
12 Midpoint Hunt 230.0C 230.00 STower 0.60 2
13 Brady Antelope 23D.C 230.00 HWoo 56.44 1
14 Brady Treasureton 23O.0C 230.00 HWood 0.13 1
15 Brady #1 & #2 Kinport 23O.0C 230.00 STower 18.2 2
16 Jim Bridger Point of Rocks 23O.0C 230.00 HWoo 1.40 1
17 Brownlee Ontario 230.01 230.00 STower 72.72 1
18 Mora Bowmont 138.0C 230.00 SPWood 9.86 1
19 Mora Bowmont 138.0C 230.00 HWood 10.n 1
20 Jim Bridger Point of Rocks 230.0C 230.00 HWood 2.79 1
21 caldwell 710 Locust 230.01 230.00 SP Steel 18.59 1
22 Boise Bench Caldwell 23O.0C 230.00 STower 7.52 1
23 Boise Bench Caldwell 230.01 230.00 HWoo 33.53 1
24 Boise Bench Cloverdale 230.01 230.00 STower 15.99 2
25 Boardman Dalreed Sub 230.01 230.00 HWoo 1.68 1
26 Brownlee 714 Oxbw 230.01 230.00 SP Steel 11.13 2
27 caldwell Ontario 230.01 230.00 HWoo 27.11 1
28 Caldwell Ontario 23O.0C 230.00 STower 3.31 1
29 Bennett Mtn PP Rattlesnake TS 23O.0C 230.00 SP Steel 4.48 1
30 Borah Hunt 230.0C 230.00 H Stel 6824 1
31 Boise Bench Midpoint #1 23O.0C 230.00 STower 0.86 1
32 Boise Bench Midpoint #1 230.0C 230.00 HWoo 108.11 1
33 Brownlee QuartJct 23O.0C 230.00 STower 1.52 1
34 Brownlee QuartJct 230.0(230.00 HWoo 41.71 1
35 Brownlee Boise Bench #1 & #2 230.0(230.00 STower 99.99 2
36 TOTAL 4,678.8S 11.02 161
i:i:i:r. i:ni:ii Nn 1 ii:n 1?..7\PlIim 422
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) 0 A Resubmission 04111/2008
RANSMISSION LINE STATISTICS ((ontinued)
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one fine. 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 fine or portion thereof for which the respondent is not the sole owner. If such propert 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 oprates or shares in the operation of, fumish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-ownr, basis of sharing
expnses of the Line, and how the expnses borne by the respondent are accunted for, and accounts affected. Specify whether lessor, co-owner, or
other part is an associated company.
9. Designate any transmission fine leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns OJ to (i) on the bok cost at end of year.
\Jv;: I ... ....... (InCIUOe in Column (j Lana,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of.way)
Conductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total LineOter Costs Expenses Exenses (0)E~nses No.(i)OJ (k)(I)(m)(n)(p)
°X1780ACSR 446,708 446,708 1
2
272 ACSR 256,381 21,776,99l 22,033,375 3
272 ACSR 483,301 15,888,761 16,372,070 4
!75ACSR 571,97 10,996,44~11,568,428 5
272 ACSR 34,221 6,028,O~6,372,2~6
15.5ACSR 283,14:5,779,601 6,06,751 7
15.5 ACSR 64,851 7,786,55E 7,851,40 8
15.5ACSR 51,oW 347,94t 399,39'9
10
!7ACSR 51,41 2,411,86~2,463,27i 11
15.5 ACSR 9,14 998,45~1,007,59 12
272 ACSR 108,301 2,502,500 2,610,801 13
~95ACSR 6,186 6,186 14
15.5 ACSR 18,825 969,476 988,305 15
272 ACSR 1,19(51,525 52,715 16
?X954 ACSR 1,676,83f 20,266,395 21,943,23:17
15.5 ACSR 347,96~2,012,372 2,360,33 18
15.5 ACSR 19
272 ACSR 1,89~212,52~214,422 20
590 ACSR 2,138,23€8,755,911 10,894,14 21
1272 ACSR 1,134,421 5,699,649 6,834,07C 22
715.5 ACSR 23
1272 ACSR 3,062,81~6,583,109 9,645,921 24
795AAC 80,895 80,89f 25
954 ACSR 34,m 16,026,7~16,060,00 26
?X954 ACSR 194,76~5,925,08~6,119,84 27
h272 ACSR 28
h272ACSR 81,701 1,666,35 1,748,055 29
h590ACSR 618,21 22,439,85C 23,058,06 30
1715.5 ACSR 336,18E 3,776,464 4,112,650 31
~15.5ACSR 32
!7ACSR 53,06E 2,011,50 2,06,57f 33
17 ACSR 34
~ARIOUS 269,431 7,991,O~8,260,474 35
28,516,168 350,073,050 378,589,218 13,765,08~2,786,071 1,053,886 17,605,O4 36
i:i:a,. i:nau Nn 1u=n 1?..7\p",,, 423
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da. Yr)End of 2007/04
(2) Fi A Resubmission 0411/2008
TRANSMISSION LINE STATIST CS
1. Report information concerning transmission lines, cost of Iines, and expenses for year. List each transmission line having nominal voltge 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, Nonutilty Property.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wo 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 costruction
by the use of brackets and extra lines. Minor portions of a transmission line of a diferent 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
respet to such structures are included in the expenses reported for the line designated.
Line (Indicate wtere Type of LEnGJi~ ~gie JlileS)NumbeNo.other thn u 1gergrounìfllnes
60 cvcle 3 Dhasel Supporting report circuit miles)Of
From To I un ~tructure unf~~fi~res CircuitsOperatingDesignedStructureof Lin~o I)ot er
(a)(b)(c)(e)Desialaed ine
(d)(g)(h)
1 Oxbow Brownlee 230.0C 230.00 STower 10.23 2
2 Boise Bench Midpoint #2 23O.0C 230.00 STower 3.42 1
3 Boise Benh Midpoint #2 23O.0C 230.00 HWoo 102.53 1
4 Oxbow Pallette Jct 23O.0C 230.00 STower 20.25 2
5 Pallette Jct Imnaha 23O.0C 230.00 HWoo 24.43 2
6 Hells Canyon PaletteJct 230.0C 230.00 STower 8.24 2
7 Brownlee Boise Bench 230.01 230.00 STower 102.30 2
8 Boise Bench Midpoint #3 23O.0l 230.00 HWoo 106.34 1
9 Palette Jct Enterprise 230.i 230.00 HWoo 29.8 1
10 Borah Brady #2 23O.0C 230.00 STower 0.43 1
11 Borah Brady #2 230.0C 230.00 HWood 3.58 1
12 Borah Brady #1 23O.0C 230.00 HWoo 3.98 1
13
14 Goshen State Line 161.0C 161.00 HWood 90.50 1
15 Don Goshen 161.0C 161.00 STower 2.39 2
16 Don Goshen 161.0C 161.00 HWood 46.4~2
17
18 American Falls Power Plant Adelaide 138.0l 138.00 HWoo 9.84 2
19 American Falls Power Plant Adelaide 138.01 138.00 SPWoo 2.56 2
20 Minidoka Lop Adelaide 138.01 138.00 STower 1.11 2
21 Nampa Caldwell 138.01 138.00 SPWood 10.73 2
22 Upper Salmon Mountain Home Jct 138.00 HWood 53.40 1
23 Upper Salmon Clif 138.1 138.00 HWoo 30.80 1
24 Eastgate Russet 136.01 138.00 S PWOod 2.30 1
25 Brady Fremont 138.01 138.00 STower 1.00 2
26 Brady Fremont 138.01 136.00 HWoo 24.32 2
27 Brady Fremont 138.01 138.00 S PWoo 24.35 2
28 King Lower Malad 136.01 138.00 HWood 84.91 2
29 EmmettJct Payette 138.01 138.00 HWood 66.20 2
30 Mountain Home AFB Tap 138.1 138.00 HWoo 6.21 1
31 Ontario Quart 136.0(138.00 HWoo 73.41 1
32 King American Falls PP 138.01 138.00 STower 1.0~2
33 King American Falls PP 138.01 138.00 HWoo 146.40 1
34 King American Falls PP 138.0(138.00 SPWood 3.71 1
35 Dufin Clawson 138.0(138.00 HWood 6.22 1
36 TOTAL 4,678.88 11.02 161
eenl" eI'D.. ....1 1 ieft 1 "l..D"7\D..,... 499_1
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Onginal (Mo, Da, Yr)End of 2oo7/Q4
(2) n A Resubmission 04/11/2008
RANSMISSION LINE STATISTICS (( ontinued)
7. Do not report the same transmission line struture twice. Report lower voltage Lines and higher voltage lines as one line. Designate in a foonote if
you do not include Lower voltage lines with higher voltage lines. If tw 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 propert 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 ownrship by respondent in the line, name of co-owner, basis of sharing
expnses of the Line, and how the expenses borne by the respndent are accounted for, and accunts affected. Specif whether lessor, co-owner, or
other part 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 whther lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (i) on the bok cost at end of year.
vu~ i ui- LINt: (inCIUde in Column ül Land,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land nghts, and clearing right-of-way)
Coductor
and Matenal Land Construction and Total Cost Operation Maintenance Rents Total LineOther Costs Expenses Expenses Exnses(i)(j)(k)(I)(m)(n)(0)(p)No.
272 ACSR 14,811 1,182,55C 1,197,36C 1
15.5 ACSR 227,82!5,764,12E 5,991,954 2
VARIOUS 3
272 ACSR 23,301 2,075,244 2,098,552 4
272 ACSR 138,47 1,263,618 1,402,095 5
272 ACSR 10,73 1,252,130 1,262,861 6
954 ACSR 17D,9'5,620,492 5,791,186 7
15.5 ACSR 247,85 4,954,721 5,202,58E 8
1272 ACSR 51,12.1,631,895 1,683,01 ¡9
1272 ACSR 3,061 226,25C 229,31E 10
15.5 ACSR 11
1272 ACSR 10,0&33,595 349,65E 12
13
12o COPPER 16,15 648,~664,53.14
15.5 ACSR 76,041 1,652,91~1,728,95!15
ß97.5ACSR 16
17
?50COPPER 26,50 2,388,731 2,415,244 18
250 COPPER 19
15.5 ACSR 15,08€249,23~264,32C 20
!75AAC 157,43~1,954,139 2,111,571 21
!795ACSR 47,68 1,858,259 1,905,946 22
!75ACSR 43,56E 764,18 807,751 23
95AAC 270,82~557,504 828,327 24
ARIOUS 564,9~3,557,039 4,121,971 25
ARIOUS 26
ARIOUS 27
ARIOUS 76,82 1,622,351 1,699,174 28
ARIOUS 30,91E 2,291,61~2,32,532 29
97.5 ACSR 1,95!1,955 30
l/ARIOUS 34,421 1,552,871 1,587,3O 31
15.5 ACSR 148,91 5,54,20~5,693,111 32
15.5 ACSR 33
15.5 ACSR 34
\0 4,191 30,827 314,01S 35
28,516,161 350,073,050 378,589,21E 13,765,om 2,786,07t 1,053,886 17,605,04(36
FERC FORM NO.1 tED. 12-87\Paae 423.1
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) 0 A Resubmission 04/11/2008
TRANSMISSION LINE STATIST CS
1. Report information concerning transmission lines, cost of lInes, and expenses for year. List each transmission line having nominal voltge of 132
kilovolt or greater. Report transmission lines below these voltges 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 co are included in Account 121, Nonutilty Property.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wo or steel; (2) H-frame wod, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one ty of supporting strucure, indicate the mileage of each tye of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of constrution 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 strutures are included in the expnses reported for the line designated.
LENGJr rOle 'VileS)Line (Indicate wtere Type of ~IIJ t e ai¡ 0 NumberNo.other than u ë1ergroun Iines Of60 cvcle 3 ohase)Supporting report circuit miles)
I un ~lfyclUe uriftu~h~res CircuitsFromToOperatingDesignedStrucureof Lin~a not erDesi8laedine(a)(b)(c)(d)(e)(g)(h)
1 American Falls Brady Tie 138.(138.00 HWoo 0.33 1
2 Upper Salmon A-B King 138.0(138.00 HWoo 5.88 1
3 Uppr Salmon B Wells 138.0C 138.00 HWood 125.61 1
4 King Wood River 138.0(138.00 HWoo 73.57 1
5 Boise Bench Grove 138.0(138.00 SPWood 10.47 2
6 Quart John Day 138.0(138.00 HWood 67.31 1
7 Sinker Creek Tap 138.0(138.00 HWood 2.8~1
8 Mora Cloverdale 138.0(138.00 HWood 2.57 1
9 Mora Cloverdale 138.0(138.00 SPWood 22.37 1
10 Stoddard Jct Stoddard Sub 138.0(138.00 S P Steel 3.80 1
11 Fossil Gulch Tap 138.0(138.00 HWoo 1.95 1
12 Wood River Midpoint 138.0C 138.00 HWoo 53.06 2
13 Woo River Midpoint 138.0(138.00 SPWood 16.74 2
14 Oxbow McCall 138.0(138.00 HWood 38.47 1
15 Oxbow McCall 138.01 138.00 SPWood 2.50 1
16 LowellJct Nampa 138.01 138.00 SPWoo 7.59 2
17 Hunt Milner 138.0 138.00 SPWood 19.40 1
18 Strike Bruneau Bridge 138.0C 138.00 HWood 13.47 1
19 American Falls Kramer Sub 138.0(138.00 SPWood 18.41 2
20 Pingree Haven 138.0(138.00 SPWood 11.75 1
21 Midpoint Twin Falls 138.0(138.00 SPWood 25.13 2
22 Twin Falls Russett 138.0C 138.00 SPWoo 1.72 1
23 Blackfoot Aiken 138.0(138.00 SPWood 6.17 2
24 Peterson Tendoy 138.0C 138.00 HWood 57.2€1
25 Eastgate Tap Eastgate 138.0(138.00 SPWood 7.32 1
26 Boise Bench Mora 138.0(138.00 HWood 13.14 2
27 Bowmont-Caldwell SimplotSub 138.0C 138.00 SPWood 0.51 1
28 Gary Lane Eagle 138.0(138.00 SPWoo 6.44 1
29 Locust Grove Blackcat Sub 138.0(138.00 S P Stel 9.92 2.98 1
30 Boise Bench Butler 138.0C 138.00 SPWood 0.08 4.02 1
31 Eagle Star 138.00 SPWoo 6.35 1
32 Karcher Sub ZilogTap 138.0C 138.00 S P Steel 2.09 1
33 Cloverdale - 712 712-Wye 138.0(138.00 S P Steel 0.24 4.02 1
34 Butler Wye 138.0C 138.00 S P Steel 2.86 1
35 Horseflat Starkey 138.0C 138.00 S P Steel 34.56 1
36 TOTAL 4,678.88 11.02 161
r:r:Rr. r:nRM Nn 1 tr:n 1'..7\PIUIA 422.2
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) Fi A Resubmission 04/11/2008
RANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. Report Lower voltage Unes and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage Iines. If tw 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 propert is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, fumish a succinct statement expiaining 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 affeced. Specif whether lessor, co-owner, or
other part 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. Specif whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j to (I) on the book cost at end of year.
liU~1 . (inclUde in Column ul Land,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total Line
Other Costs Exnses Expenses
(0)
EJCnses No.(i)ul (k)(i)(m)(n)(p)
954 ACSR 96,921 96,921 1
!)50COPPER 2,741 93,07.:95,814 2
VARIOUS 28,9(1,745,804 l,n4,294 3
VARIOUS 173,68 2,355,148 2,528,831 4
VARIOUS 225,60.l,63Q,8~1,856,191 5
397.5 ACSR 92,17i 2,362,416 2,45,589 6
WARIOUS 2(n,199 n,2H 7
15.5 ACSR 2,225,22(6,996,618 9,21,84 8
ivARIOUS 9
1272 ACSR 10
b50COPPER 45(63,43~63,889 11
ß97.5ACSR 281,06'6,374,30E 6,655,370 12
ß97.5ACSR 13
ß97.5ACSR 109,891 2,314,194 2,424,09~14
ß97.5ACSR 15
15.5 ACSR 211,131 1,493,264 1,704,39~16
15.5 ACSR 3,32 1,187,30 1,190,626 17
397.5 ACSR 14,92 587,404 602,331 18
15.5 ACSR 13,734 1,052,549 1,066,283 19
397.5 ACSR 11,21.:n8,092 789,305 20
VARIOUS 54,84E 2,958,765 3,013,613 21
15.5 ACSR 16,79C 206,158 222,948 22
15.5 ACSR 13,61E 456,919 470,535 23
397.5 ACSR 395,69E 3,449,949 3,845,645 24
15.5 ACSR 45,98~1,058,898 l,104,88f 25
15.5 ACSR 14,69 627,703 642,400 26
95AAC 49,642 49,642 27
95AAC 489,03 1,944,888 2,433,925 28
1272 ACSR 935,721 3,610,071 4,545,79E 29
1272 ACSR 34,68 838,605 873,29.30
15.5 ACSR 2,909,433 2,909,~31
95AAC 43,031 443,805 486,84C 32
272 ACSR 140,41~709,148 849,56C 33
95 ACSR 134,471 1,405,436 1,539,90 34
954ACSR 648,18E 13,145,19f 13,793,383 35
28,516,168 35,073,050 378,589,218 13,765,08.:2,786,071 1,053,886 17,605,04t 36
i:i:a~ i:nau Nn 1 ii=n 1~-A7\PAft 423.2
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) Fi A Resubmission 0411/2008
TRANSMISSION LINE STATIST CS
1. Report information concerning transmission lines, cost of Iines, 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, Nonutilit Propert.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wod, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one tye 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 include in the expenses reported for the line deignated.
Line IIUN
(Indicate w1ere Type of LE~GlH role WileS)
No.
~rit e ascl0 Numberòterthanu ëlergroun lines
60 cvcle, 3 ohase)Supporting report circuit miles)Of
From To Designed Oh~trUCture I unf~u~~~res CircuitsOperatingStructureof. Line o 1"0 er
(a)(b)(c)(e)
Desi~)ated ine
(d)(g)(h)
1 Chestnut Happy Valley 138.0C 138.00 S PSteel 2.78 1
2 McCall Lake Fork 138.0C 138.00 SPWoo 8.70 1
3 138.0(138.00 SSteel 2.90
4 Caldwell Wills 138.0C 138.00 S P Steel 1.30 1
5 Caldwell Wilis 138.0C 138.00 S P Steel 1.59 1
6 Caldwell Wills 138.0C 138.00 SPWoo 0.82 1
7 ValivueTap 138.0(138.00 S P Stel 0.82 2
8 Kinport Don #1 138.0(138.00 STower 1.24 2
9 Twin Falls PP Tap 138.0(138.00 HWoo 0.82 1
10 American Falls PP Amercian Falls Trans ST 138.0(138.00 S P Stel 0.38 1
11 Lower Salmon King Tie 138.0C 138.00 HWoo 0.22 1
12 C J Strike Strike Jct 138.0C 138.00 STower 4.31 2
13 Strike Jet Mountain Home Jct 138.0C 138.00 HWood 26.69 1
14 Strike Jct Bowmont 138.00 HWoo 0.05 1
15 StrikeJct Bowmont 138.0(138.00 STower 0.36 1
16 Strike Jet Bowmont 138.0(138.00 HWood 68.14 1
17 Lucky Peak Lucky Peak Jct 138.01 138.00 HWoo 4.43 2
18 Bliss King 138.1l 138.00 HWood 10.44 1
19 Milner Deadend MilnerPP 138.1l 138.00 SPWood 1.31 1
20 Swan Falls Tap 138.01 138.00 HWoo 0.95 1
21
22
23
24 Hines BPA (Harney)115.01 115.00 HWood 3.28 1
25
26
27 69 Kv Lines 69.01 69.00 HWoo 166.31 1
28 69 Kv Lines 69.1l 69.00 SPWood 943.39 1
29
30
31 46 Kv Lines 46.0C 46.00 SPWoo 412.25 1
32
33
34
35
36 TOTAL 4,678.88 11.02 161
eCD,. enD.. ..in 1 ien 1"_R"7 D..ft.. 422.:l
Name of Respondent This ~rtIS:Date of Report Year/Penod of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) Ei A Resubmission 04/111008
RANSMISSION LINE STATISTICS (( ontinued)
7. Do not report the same transmission line structure twice. ~eport Lower voltage Lines and higher voltge lines as one line. Designate in a footnote if
you do not include Lower voltage lines wit higher voltage lines. If tw 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 transmissio line or portion thereof for Which the respondent is not the sole owner. If such propert 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. Specif Whether lessor, co-owner, or
other part 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 assoiated company.
10. Base the plant cost figures called for in columns ul to (I) on the bok cost at end of year.
I,U::I ~ ....~_ (InCIUOe in \,lumn OJ Lana,EXPENSES, EXCEPT DEPRECIATION AND TAXESSize of Land rights, and clearing right-of-way)
Conducor
and Material Land Construction and Total Cost Operation Maintenance Rents Total LineOter Costs Expenses Expses Expenses(i)(j)(k)(I)(m)(n)(0)(p)No.
272 ACSR 78,57!1,821,921 1,900,50(1
15.5 ACSR 399,781 4,731,449 5,131,23(2
3
272ACSR 168,22!2,141,218 2,309,44.4
95 ACSR 5
795 ACSR 6
95 ACSR 351,49 351,497 7
15.5 ACSR 1,17'212,m 213,951 8
50 COPER 51 53,889 53,94 9
15.5 ACSR 76,560 76,560 10
97.5 ACSR 4,406 4,40 11
15.5 ACSR 1,07~253,872 254,94 12
97.5 ACSR 4,35E 524,571 528,92t 13
15.5 ACSR 29,90.1,776,89S 1,806,80(14
15.5 ACSR 15
16
15.5 ACSR 279,481 279,48 17
1715.5 ACSR 5,62(964,435 970,055 18
1715.5 ACSR 2,81l 183,606 186,20 19
~7.5ACSR 12,88!261,511 274,391 20
21
22
23
~7.5ACSR 1,971 63,40~65,382 24
25
26
VARIOUS 928,99C 36,062,702 36,991,692 27
VARIOUS 28
29
30
VARIOUS 176,26!8,585,33 8,761,60~31
32
5,736,25.5,736,25~33
34
13,765,083 2,786,071 1,053,88E 17,60,04C 35
28,516,161 35,073,050 378,589,21E 13,765,083 2,786,071 1,053,88 17,605,00 36
FERC FORM NO.1 (ED. 12-87)Page 423.3
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da. Yr)End of 2oo7/Q4
(2) Ei A Resubmission 0411/2008
RANSMISSION LINES ADDED DURING YEAR
1. Report below the information called for concerning T.ransmission lines added or altered during the year.It is not necessary to report
minor revisions of lines.
2. Provide separate subheadings for overhead and under. ground construction and show each transmission line separately. If actual
costs of competed construction are not readily available for reporting columns (I) to (0), it is permissible to report in these columns the
Line iiui"l . Lllltl.liNG ::Le!lgth
No.From To in Typ Number per Present UltimateMilesMiles
(a)(b)(c)(d)(e)(f)(g)
1 Borah Hunt 68.24 H Steel 6.50 1 1
2
3 McCall Lake Fork 8.70 SPWoo 18.28 1 1
4 2.90 S PSteel 18.28 1 1
5
6
7
8
5
10
11
12
1~
14
15
16 .
17
18
19
20
21
22
23
24
25
26
27
28
29
3C
31
32
33
3l
3f
3t
37
3a
39
40
41
42
43
44 TOTAL 79.84 43.06 3 ~
i:DI" s:nDal un 1 IDi:\I 1 ,)"i'l\D..".. 424
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/04
(2) n A Resubmission 04111/2008
TRAN MISSION LINES ADDED DURING Y AR (Continue)
costS. Designate, however, if estimated amounts are r~ported. Include costs of Clearing Land and Rights-of-Way, and Roads and
Trails, in column (I) with appropriate footnote, and costs of Underground Conduit in column (m).
3. If design voltage differs from operating voltage, indicate such fact by footnote; also where line is other than 60 cycle, 3 phase,
indicate such other characteristic.
Voltage LINI:l;U::1 Line
Size Speification Conf~uration KV Land and Poles, Towers Conductors Asset Total No.
and pacing (Operating)Land (~ights and Fixtures and Devices Retire. Costs
(p)(h)(i)(i)(k)(m)(n)(0)
1590 ACSR Hor22'230 618,217 15,814,751 6,625,099 23,058,067 1
2
715.5 ACSR TVS7'131 399,781 2,361,94 2,369,502 5,131,230 3
715.5 ACSR TVS6'13f 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
1,017,998 18,176,691 8,994,601 28,189,297 44
FERC FORM NO.1 (REV. 12-03)Page 425
Name of Respondent This~rtIS:Date of Reprt YeadPeriod of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/04
(2)o A Resubmission 04/111008
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 Adelaide transmission 345.00 138.00 13.80
2 Aiken distribution 46.00 13.00
3 Alameda distribution 46.00 13.00
4 Alameda distribution 138.00 13.00
5 American Falls PP - attended transmission 138.00 13.80
6 American Falls transmission 138.00 46.00 12.50
7 Artesian distribution 46.00 13.00
8 Bannock Creek distributon 46.00 13.00
9 Bennett Mountain Power Plant transmission 230.00 18.00
10 Bennett Mountain Power Plant transmission 18.00 4.16
11 Bethel Court distributn 138.00 13.00
12 Black Cat distribution 138.00 13.09
13 Blackfoot distribution 46.00 12.50
14 Blackfoot distribution 161.00 46.00 12.47
15 Bliss - attended transmission 138.00 13.80
16 Blue Gulch distribution 138.00 34.50
17 Boise Bench - attended distribution 138.00 34.50
18 Boise Bench - attended transmission 138.00 69.00 13.80
19 Boise Bench - attended transmission 230.00 138.00 13.80
20 Boise distribution 138.00 13.00
21 Borah transmission 345.00 230.00 13.80
22 Bowmont distrbuion 69.Oc 46.00 6.90
23 Bowmont distrbutio 138.()C 34.50
24 Bowmont distributio 138.00 69.00 13.80
25 Brady transmission 46.0C 12.50
26 Brady transmission 230.00 138.00 13.80
27 Brownlee - attended transmission 230.0(13.80
28 Bruneau Bridge distribuion 138.00 34.50
29 Buckhrn distributio 69.00 35.00
30 Bucyrus distribution 46.0C 7.20
31 Buhl distbution 46.00 13.00
32 Burley Rural distbution 69:0(13.00
33 Butler distribution 138.0C 13.00
34 Caldwell distribution 138.00 13.00
35 Caldwell distribution 138.00 69.00 13.0C
36 Caldwell transmission 230.00 138.00 12.50
37 Canyon Creek distribution 138.00 34.50
38 Canyon Creek distribution 138.00 69.00 12.50
39 Cascade Power Plant - attended transmission 69.00 4.60
40 Cascade Distribution 69.00 13.10
eeD" enb.. ..in 1 iel" 1')..\D.... 426
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2)o A Resubmission 04/11/2008
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxilary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties. and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Une
(In Service) (In MVa)
Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Unit
(In MVa)
(f)(g)(h)(I)(j (k)
300 2 1
20 2 2
15 1 3
18 1 4
72 1 5
25 1 6
10 1 7
10 1 8
135 1 9
5 1 10
15 1 11
24 1 12
30 2 13
130 4 1 14
69 3 15
15 1 16
42 2 17
75 3 18
494 4 19
67 3 20
450 3 1 21
8 3 22
18 1 23
50 2 24
6 25
300 3 26
734 5 1 27
30 2 28
20 1 29
6 1 4 30
20 2 31
12 1 32
48 2 33
39 2 1 34
50 2 1 35
240 2 36
15 1 37
1 38
12 1 39
10 1 40
i:i:a~ i:naM Nn 1 (Fn 1~..\Paoa 427
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1 )~An Original (Mo, Da, Yr)End of 2007/Q4
(2)A Resubmission 04111/2008
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summanze according to function the capacities reported for the individual stations in
column (f).
Une VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 Chestnut distribution 138.0C 13.00
2 Clear Lake - attended transmission 46.00 2.30
3 Cliff transmission 138.00 46.00 12.50
4 Cloverdale transmission 138.0C 13.00
5 Dale distribution 69.00 13.00
6 Dale distribution 138.00 34.50
7 Dale disribution 138.00 46.00 12.50
8 Danskin transmission 138.00 12.00
9 Don distribution 138.00 7.60
10 Don distribution 138.00 13.20
11 Don distribution 138.00 13.00
12 DRAM distribution 138.00 13.00
13 DRAM distribution 230.00 138.00 13.80
14 Dufin distribution 138.00 34.50
15 Eagle distribution 138.00 13.00
16 Eastgate distribution 138.00 13.00
17 Eckert distribution 138.00 36.20
18 Eden distribution 138.00 34.50
19 Eden distribution 138.0(46.00 12.50
20 Elkhorn distribution 138.00 12.00
21 Elmore transmission 138.00 34.50
22 Elmore distribution 138.00 69.00 12.50
23 Emmett distribution 138.00 12.50
24 Emmett distribution 138.00 69.00 12.50
25 Falls distribution 46.00 12.50
26 Filer distribution 46.00 12.50
27 Flying H distribution 69.00 2.40
28 Fort Hall distribution 46.00 12.50
29 Fossil Gulch distribution 138.00 2.40 4.60
30 Fossil Gulch disribution 138.00 34.50
31 Fremont transmission 138.00 46.00 12.50
32 Gary distribution 138.00 13.00
33 Gem distribution 69.00 13.00
34 Golden Valley distribution 69.00 12.50
35 Gowen Substation distribution 138.00 35.00
36 Grindstone distribution 35.00 12.50
37 Grove distribution 138.0C 12.50
38 Hagerman distribution 46.00 12.50
39 Hailey distribution 138.0C 12.50
40 Happey Valley distribution 138.0C 13.09
PERC FORM NO.1 lED. 12-96\Paae 426.1
Name of Respondent ThIS~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2)A Resubmission 04/11/2008
SUBSTATIONS (Continued)
5. Show in columns (1),0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxilary 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 equ.ipment 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 part, 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 part is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)
Transformers Spare Typ of Equipment Total Capacity No.In Service Transformers Number of Units
(f)(0)(h)(i)ul
(In m~a)
48 2 1
4 1 2
16 3 1 3
48 2 4
10 5
27 1 6
25 1 7
96 2 8
18 1 9
164 10 5 10
26 1 1 11
134 8 12
160 2 13
36 2 14
38 2 15
36 2 16
18 1 17
24 1 18
15 1 19
15 2 20
17 1 21
30 2 22
15 1 23
25 1 24
17 2 25
10 1 26
15 2 27
10 1 1 28
8 1 29
15 1 30
50 3 1 31
36 2 32
17 2 33
10 1 1 34
24 1 35
10 2 36
72 3 37
12 2 38
20 1 39
18 1 40
i:i:Ar- i:nAIJ Nn 1 ii:n 1 ,..\PRaii 427.1
Name of Respondent ThiS~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2007/04
(2)A Resubmission 04/11/2008
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summanze according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 Haven distnbution 46.00 34.50
2 Hewlett Packard distnbution 138.00 13.10
3 Hidden Springs distnbution 138.00 13.09
4 Highland distribution 138.00 13.09
5 Hil distnbution 138.00 12.50
6 Homedale distributon 69.00 12.50
7 Horse Flat transmission 230.00 138.00 13.80
8 Horseshoe Bend distribution 35.00 12.50
9 Horseshoe Bend distribution 69.00 36.20
10 Horseshoe Bend distribution 69.00 25.00
11 Huston distribution 69.00 13.00
12 Hulen distribution 46.00 13.00
13 Hunt transmission 230.00 138.00 13.80
14 Hydra distnbution 138.0C 34.50
15 Island distribuion 69.0C 12.50
16 Jerome distribution 138.00 12.50
17 Julion Clawson distributon 138.00 34.50
18 Joplin distribution 138.00 13.00
19 Joplin distribution 138.0(35.00 18.00
20 Karcher distribution 138.00 13.09
21 Kenyon distribution 69.00 12.50
22 Ketchum distribution 138.00 12.50
23 Kinport transmission 161.00 46.00 13.00
24 Kinport transmission 230.00 138.00 12.50
25 Kinport transmission 230.00 138.00 13.80
26 Kinport transmission 34.00 230.00 13.80
27 Kramer distnbution 138.00 34.50
28 Kramer distribution 138.00 13.00
29 Kuna distribution 138.00 13.00
30 Lake Fork distribution 138.00 36.20
31 Lake Fork transmission 138.00 69.00 12.50
32 Lamb distnbution 138.00 13.09
33 Lansing distribution 69.00 13.00
34 Lincoln distnbution 138.00 13.00
35 Linden distnbution 138.00 13.00
36 Locust distribution 138.00 34.50
37 Locust transmission 230.00 138.00 13.00
38 Lower Malad. attended transmission 138.00 7.20
39 Lower Salmon - attended transmission 138.00 13.80
40 Map Rock distribution 69.00 12.50
IFRr. FORM NO_ 1/(;0_ 12-A6\PilaR 426.2
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2007/04
(2) ri A Resubmisslon 04111/2008
SUBSTATIONS (Continued)
5. Show in columns (1),0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxilary 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 part, 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.
Capacit of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EOUIPMENT Une
(In Service) (In MVa)Transformers Spare Total Capacity No.In Service Transformers Typ of Equipment Number of Units
(In MVa)
(1)(0)(hI (I)(j)(k)
12 1 1
20 1 2
8 1 3
18 1 4
24 1 5
20 2 6
100 1 7
5 1 8
12 1 9
5 1 10
10 1 11
8 1 1 12
300 3 13
24 1 14
12 1 15
20 ,1 16
30 2 17
15 1 18
1 19
12 1 20
20 2 21
42 2 22
7 23
180 1 24
180 1 25
600 3 1 26
12 1 27
18 1 28
15 1 29
18 1 30
15 1 31
18 1 32
12 1 33
11 1 34
33 2 35
48 2 36
360 2 37
15 1 38
70 4 39
10 1 40
i:i:Ar- i:nAM Nn 1 ii:n 19.GR\PRlI 427.2
Name of Respondent This
(grtIS:
Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo. Da. Yr)End of 2007/Q4
(2) 0 A Resubmission 04/11/2008
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 McCall distribution 69.00 12.50
2 McCall distribution 138.00 35.00
3 McCall distribution 138.00 69.00 12.50
4 Meridian distribution 138.00 13.00
5 Micron distribution 138.00 12.50
6 Midpoint transmission 230.00 138.00 13.80
7 Midpoint trnsmission 345.00 230.00 13.80
8 Midpoint transmission 500.00 345.00
9 Midrose distribution 138.00 13.09
10 Milner distribution 138.00 69.00 13.80
11 Milner distribution 69.00 46.00 7.20
12 Milner distribution 138.00 34.50
13 Milner PP - attended transmission 138.00 13.80
14 Moonstone distribution 138.00 34.50
15 Mora distribution 138.0C 34.50
16 Moreland distibutn 46.00 12.50
17 Moreland distribution 46.0C 34.50 12.50
18 Mountain Home distribution 69.0C 12.50
19 Mountain Home Air Force Base distribution 69.00 12.50
20 Mountain Home Air Force Base distribution 138.OC 12.50
21 Nampa distribution 230.0C 138.00 13.80
22 Nampa distribution 138.00 12.50
23 New Meadows distrbution 69.00 35.00
24 New Plymouth distribution 69.00 12.50
25 Notch Bute distribution 13.00 7.56
26 Panna distribution 69.0C 12.50
27 Panna distributon 69.0C 34.50
28 Paul distribution 138.0C 34.50 12.50
29 Payette distribution 138.0C 12.50
30 Pingree distribution 138.00 46.00 12.50
31 Pingree distribution 138.00 36.00
32 Pleasant Valley distribution 138.00 34.50
33 Pocatello distribution 46.00 12.50
34 Portneuf distribution 138.00 36.20
35 Portneuf distribution 46.00 35.00
36 Rockford distribution 46.00 12.50
37 Russett distribution 138.0C 12.50
38 Sailor Creek distribution 138.0C 2.40
39 Sailor Creek distribution 138.0C 34.50
40 Salmon distribution 69.00 12.50
131''' enD.. un 1 ien 1')_QA\D...... 42fl.~
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) 0 A Resubmission 04/11/2008
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxilary 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
penod 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 part is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)
Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units
(In MVa)
(f)(a)(h)(i)(j (k)
8 1 1
18 1 2
30 1 3
36 2 4
48 4 5
120 1 6
720 2 7
750 3 1 8
18 1 9
75 3 1 10
8 3 1 11
16 1 12
36 1 13
12 1 14
39 2 15
13 2 16
10 3 1 17
15 1 18
1 19
18 1 20
180 1 21
50 3 22
8 3 1 23
10 1 24
11 1 25
10 1 26
12 1 27
36 2 1 28
22 3 29
50 3 30
22 2 31
42 2 32
36 2 33
18 1 34
1 35
14 2 36
18 1 37
15 2 38
15 1 39
10 1 4 40
i:i:al" i:nau Nn 1 ii:n 1 ?.Q\PRnA 427.3
Name of Respondent This oo0rt Is:Date of Reprt Year/Period of Report
Idaho Power Company (1) X An Onginal (Mo, Da, Yr)End of 2007/04
(2) 0 A Resubmission 04111008
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
Primary Seconary Tertiary
(a)(b)(c)(d)(e)
1 Salmon distribution 69.00 34.50 12.50
2 Shoshone distribution 46.00 13.00
3 Shoshone distnbution 46.00 7.20
4 Shoshone Falls. attended transmision 46.00 2.30
5 Shoshone Falls - attended transmission 46.00 6.60
6 Silver distribution 138.00 34.50
7 Simplot distribution 138.00 12.50
8 Sinker Creek distribution 138.00 34.50
9 Siphon distnbution 138.00 34.50
10 South Park distribution 46.00 13.00
11 Star distribution 138.00 13.00
12 Starkey Transmission 138.00 69.00 12.50
13 State distnbution 69.00 12.50
14 Stoddard distnbution 138.00 13.00
15 Strike Power Plant - attended transmission 138.00 13.80
16 Sugar distnbution 138.00 34.50
17 Swan Falls - attended transmission 138.00 6.90
18 Taber distribution 46.00 12.50
19 Ten Mile distribution 138.00 13.09
20 Terry distribution 138.00 12.50
21 Thusand Springs - attended transmission 46.00 6.90
22 Thousand Springs. attended transmission 7.00 2.40
23 Toponis distribution 138.00 34.50
24 Twin Falls distnbution 138.00 13.00
25 Twin Falls distnbution 138.00 46.00 12.5Q
26 Twin Falls PP . attended transmission 138.00 7.20
27 Twin Falls PP . attended transmission 138.00 13.20
28 Upper Malad. attended transmission 46.00 7.20
29 Upper Salmon- attended transmission 138.00 7.20
30 Ustick distribution 138.00 12.50
31 Vallvue distribution 138.00 13.09
32 Victory distribution 138.00 12.50
33 Ware distribution 69.00 12.50
34 Weiser distnbution 69.00 12.50
35 Weiser distnbution 138.00 69.00 12.50
36 Wilder distribution 69.00 13.00
37 Wilis distribution 138.00 13.09
38 Wye distribution 138.00 13.00
39 Zilog distnbution 138.00 13.09
40
f:I=Rr. I=ORM NO_ 1 11=0. 1?.Q\PAali 426.4
Name of Respondent This i-:.ort Is:Date of Report Year/Period of Report
Idaho Power Company (1).c An Original (Mo, Da, Yr)End of 2007/04
(2)A Resubmission 04/11/2008
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectiiers, condensers, etc.and auxilary 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 shanng expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EOUIPMENT Une
(In Service) (In MVa)
Transformers Spare Total Capacity No.In Service Transformers Type of Equipment Number of Units
(In MVa)
(f)(0)(h)(i)(i)(k)
10 3 1 1
10 1 1 2
2 3 3
3 1 4
10 1 5
12 1 6
15 1 7
12 1 8
33 2 9
10 1 10
18 1 11
18 1 12
33 2 13
15 1 14
83 3 15
20 2 16
18 1 17
5 1 18
24 1 19
42 3 20
8 1 21
2 1 22
18 1 23
40 2 24
33 2 25
9 1 26
72 1 27
8 1 28
36 4 29
44 2 30
18 1 31
24 1 32
12 1 33
20 2 34
25 1 35
10 1 36
18 1 37
56 3 38
24 1 39
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FFRr. FORM NO. 1 lIED. 12-9\Psae 427.4
Name of Respondent This '00rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) n A Resubmission 04/11/2008
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1
2 The above are all State of Idaho
3
4 Montana:
5 Peterson transmission 230.00 69.00 13.20
6
7 Nevada:
8 Valmy - attended transmission 345.00 21.30
9 Wells transmission 138.0C 69.00 12.50
10
11 Oregon:
12 Boardman - attended transmission 500.0C 24.00
13 Cairo distribution 69.00 12.50
14 Hells Canyon - attended transmission 230.00 13.80
15 Hines transmission 138.0C 115.00 12.50
16 Malheur Bute distribution 69.00 34.50 12.50
17 Nyssa distribution 69.00 12.50
18 Ontario distribution 138.0C 12.50
19 Ontario distribution 138.00 69.00 12.50
20 Ontario distribution 230.00 138.00 13.80
21 Ore-Ida distribution 69.00 12.50
22 Oxbw - attended transmission 138.00 69.00 13.00
23 Oxbow - attended transmission 230.00 13.80
24 Oxbw - attended transmission 230.00 138.00 13.80
25 Quart transmission 138.00 69.00 12.50
26 Quart transmission 230.00 138.00 13.00
27 Vale distribution 69.00 13.09
28
29 Wyoming:
30 Jim Bridger - attended transmission 345.00 22.00
31
32
33
34
35
36
37 Transformers-distribution substations under 10,000
38 KVA 89 unattended.
39
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i:i:Dr. i:nDM Nn 1 ii:n 1 ~.Q\PAn", 426.5
Name of Respondent This~rtIS:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) D A Resubmission 04111/2008
SUBSTATIONS (Cotinued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxilary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Lin
(In Servce) (In MVa)Transformers Spare Total Capacity No.In Service Transformers Type of Equipment Number of Units
(In MVa)
(f)(g)(h)(i)(j (k)
1
2
3
4
20 2 2 5
6
7
150 1 8
20 3 1 9
10
11
55 1 12
12 1 13
501 4 14
40 1 15
10 3 16
20 2 17
38 2 18
75 3 1 19
240 2 20
15 1 21
10 3 1 22
244 2 23
100 1 24
30 2 25
100 3 1 26
10 1 27
28
29
748 1 30
31
32
33
34
35
36
37
351 38
39
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i:I:DI" I:nD.. un 1 ti:n 1,,_aA\D..ftA 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
utili ty plant (sumary) ...................................................................... 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 -
work in progress -
work in progress -
Control
common utility plant .......................................................... 356
electric ...................................................................... 216
other utility departments ................................................. 200-201
corporations controlled by respondent ............................................................ 103
over respondent .................................................................................. 102
Corporation
controlled by .......................................................................,............ 103
incorporated ..................................................................................... 101
CPA, background information on ....................................................................... 101
CPA Certification, this report form ................................................................. i-ii
FERC FORM NO.1 (ED. 12-93)Index 1
INDEX (continued)
Schedule
Deferred
credits, other ................................................................................... 269
debits, miscellaneous ............................................................................ 233
income taxes accumulated - accelerated
Page No.
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 coiion 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
Dividenci appropriations .......................................................................... 118-119
Earnings, Retained ............................................................................... 118-119
Electric energy account .............................................................................. 401
Expenses
electric operation and maintenance ........................................................... 320-323
electric operation and maintenance, sumary ...................................................... 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
FERC FORM NO.1 (ED. 12-95)Index 2
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
FERC FORM NO.1 (ED. 12-95)Index 3
INDEX (continued)
Schedule
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 (sumary) ............................................................. 201
Pollution control facilities, accumulated deferred
income taxes ..................................................................................... 234
Page No.
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 i 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
FERC FORM NO.1 (ED. 12-90)Index at
INDEX (continued)
Schedule Page No.
Taxes
accrued and prepaid
charged during year
on income, deferred
.............................................................................................................................................. ..262-263
262-263.................................................................................... ..... ..................................... ..... ...........
and accumulated ............................................................. 234
272-277
reconciliation of net income with taxable income for ............................................ 261
Transformers, line - electric ....................................................................... 429
Transmission
lines added during year ..................................................................... 424-425
lines statistics ............................................................................ 422-423
of electricity for others ................................................................... 328-330
of electricity by others ........................................................................ 332
Unamortized
debt discount ............................................................................... 256-257
debt expense ................................................................................ 256-257
premium on debt ............................................................................. 256-257
Unrecovered Plant and Regulatory Study Costs ........................................................ 230
FERC FORM NO.1 (ED. 12-90)Index 5
IDAHO POWER COMPANY
IDAHO SUPPLEMENT
REPORT TO FERC FORM 1
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Page
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2
3
3
4
5
6
7-10
11
12-15
15
Deoember 31, 2007
ANNUAL REPORT
IDAHO SUPPLEMENT TO FERC FORM 1
MULTI-TATE 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 Assciated 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 SUPPLEMENT
Idaho Power Company
STATE OF IDAHO. ALLOCATED
An Original December 31,2007
STATEMENT OF INCOME FOR THE YEAR
1. Report amounts for accounts 412 and 413, Revenue and Exnses from Utility Plant Leased to Others, in another utilty
column (i,k,m,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) totas.
2. Report amounts in account 414, Other Utilty 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 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 utilty's customers or which may result in a material refund to the utilty
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 retan 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)
TOTAL
Current Year Previous Year(c) (d)(a)
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
UTILITY OPERATING INCOME
Operating Revenues (400)..................................................................................
Operating Expenses
Operation Exenses (401).,...............................................................................
Maintenance Expenses (402)............................................................................
Depreciation Expense (403)..............................................................................
Amort. & Depl. of Utilty Plant (404-405)...........................................................
Amort. of Utility Plant Acq. Adj. (406)................................................................
Amort. of Property Losses, Unrecovered Plant and
Regulatory Study Costs (407).........................................................................
Amort. of Conversion Exnses (407)...............................................................
Regulatory Debits/Credits (407.3 & 407.4)........................................................
Taxes Other Than Income Taxes (408.1)..........................................................
Income Taxes - Federal (409.1)........................................................................
- Other (409.1).....................................................................................
Provision for Deferred Income Taxes (410.1 & 411.1) Net..........................
Investment Tax Credit Adj. - Net (411.4)...........................................................
(Less) Gains from Disp. of Utiity Plant (411.6).................................................
Losses from Disp. of Utiity Plant (411.7). ......................... .............. ..................
(Less) Gains from Disposition of Allowances (411.8)........................................
Losses from Disposition of Allowances (411.9).................................................
2
2
2
2
2
2,114,441
15,922,687
2,592,539
(6,483,885)
34,515,479
1,862,104
876,469,53211$841,478,350 $
inawn !'IIPPI i:Mi:NT Paqe 1
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15
517,569,128
63,803,165
88,365,074
4,925,898
TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 22)..................725,186,631 752,942,558
Net Utility Operating Income (Enter Total of line 2 less 23)
(Carry forard to page 11, line 27)................................................................$116,291,719 $123,526,975
532,371,073
60,277,132
84,214,083
587,822
10,391,374
16,840,362
51,553,061
5,093,547
(8,706,428)
320,531
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Idaho Power Company
STATE OF IDAHO. ALLOCATED
An Original December 31, 2007
TAXES ALLOCATED TO IDAHO
Kind of Tax
Taxes Charged
During Year
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 p~c.................................. .......................
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...............................
IDAHO SUPPLEMENT Page 2
Idaho Power Company
STATE OF IDAHO - ALLOCATED
An Original December 31,2007
NOTES AND ACCOUNTS RECEIVABLE
Summary for Balance Sheet
Show separately by footnote the total amount of notes and accounts receivabe
from directors, officers, and employees included in Notes Receivable (Account
141) and Other Accounts Receivable (Account 143)
Line AccountsNo. (a)
1 Notes Receivable (Account 141).................................................................................................
2 Customer Accounts Receivable (Account 142)............................................................................
3 Other Accounts Receivable (Account 143)..................................................................................
4 (Disclose any capital stock subscription received)
5 Total......................................................................................................................................
6
7 Less: Accumulated Provision for Uncollectible
8 Accounts-Cr. (Account 144)..................................................................................................
9
10 Tota, Less Accumulated Provision for
11 Uncollectible Accounts............... ................................ .... .... ......... ........... ..............................
12
13
14 Notes Receivable - Account 141: (at 12-31-07)
15 Directors, offcers, and employees - $ 4,453,176
16
17
18 Other Accounts Receivable - Account 143: (at 12-31-07)
19 Directors, offcers, and employees - $ 4,311
20
Balance Balance
Beginning of End of
Year Year
(b)(c)
$6,717,530 $5,975,468
54,21B,159 $62,122,209
10,081,728 $7,080,171
$71,017,417 $75,177,848
968,073 l,305,05B
$70,049,344 $73,872,789
ACCUMULATED PROVISION FOR UNCOLLECTIBLE ACCOUNTS - CR. (Account 144)
1. Report below the information called for concerning this accumulated provision.
2. Exlain any important adjustments of subaccounts.
3. Entries with respect to offcers and employees shall not include items for utilty services.
Mdse,
Jobbing &
Contract
Work
(c)
Line Utilty
Customers
Offcers
and
Employees
(d)
Other TotaItem
No.(a)
(e)(f)
21
22
23
24
25
26
27
28
29
30
31
32
33
(b)
$294,883 1,163,632868,749 $$
42,103 141,427
Bal. beginning of year $
Provo for uncollectibles
for year...................................................
Accounts written off..................................
CalL. of accounts
written off...............................................
Adjustments (explain)...............................
99,324
Balance end of year....... ........ ............ ....... $968,073 $- $1,305,058
in.oi-n !'IIPPI i:Mi:NT Paae 3
. $336,985 $
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Idaho Power Company
STATE OF IDAHO - ALLOCATED
An Original Deoember 31, 2007
RECEIVABLES FROM ASSOCIATED COMPANIES (Accounts 145, 146)
I 1. Report particulars of notes and accounts receivable from associated companies at end of year.
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2. Provide separate headings and totals for accounts 145, Notes Receivae from Associated Companies, and 146,
Accounts Receivable from Associated Companies, in addition to a tota for the combined accounts.
3. For notes receivable list each note separately and state purpoe for which received. Show also in column
(a) date of note, date of maturity and interest rate.
I 4. If any note was received in satisfaction of an open account, state the period covered by such open account.
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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.
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Balance
Line Particulars Beginning Totals for Year Balance Interest
of Year Debits Credits End of Year For Year
No.(a)(b)(c)(d)(e)(f)
1 Account 145:
2
3 IERCO....................................$9,154,480 $44,578,462 $32,205,316 $21,527,626
4
5
6
7
8
9,
10 Tota Account 145................. ...9,154,480 44,578,462 32,205,316 21,527,626
11
12 Account 146:
13
14
15
16 IDACORP, Inc.... .,. ............. ......$-$58,114,469 $58,114,469 $-
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31 Total Account 146........................$-$58,114,469 $58,114,469 $-
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InAi-n i:IIPPLEMENT Page 4
Idaho Power Company
STATE OF IDAHO. ALLOCATED
An Original
I
December 31, 2007
ISTATE OF IDAHO. TOTAL SYSTEM DATA
GAIN OR LOSS ON DISPOSITION OF PROPERTY (Account 421.1 and 421.2)I
1. Give a brief description of property creating the gain or loss. Include name of party acquiring the property (when
acquired by another utilty or associated compay) and the date transaction was completed. Identify property
by type; Leased, Held for Future Use, or Nonutilty.I
2. Individual gains or losses relating to propert with an original cost of less than $50,000 may be grouped, with the
number of such transactions disclosed in column (a).I3. 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, Utilty
Plant Purchased or Sold.)I
Line Description of Property
Original Cost
of Related
Propert
(b)
Date Journal
Entr Approved
(When Required)
(c)(d)(e)I
Acct 421.1 Acct 421.2
No.(a)
Gain on disposition of
property:
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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
10/24/2007 $48,872$62,967CJ Strike Power Plant- Disposal of
excess land
CJ Strike Power Plant- Disposal of
excess land
105,000 11/15/2007 72,339 I
36,663 200,153Misc Items (4)
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$Total gain.......................................................... $321,364204,630
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Idaho Power Company
STATE OF IDAH - ALLOCATED
An Original Oecember 31, 2007
STATE OF IDAHO - TOTAL SYSTEM DATA
PROFESSIONAL OR CONSULTATIVE SERVICES -ITEMS $10,000 AND OVER
Line PAYEE SERVICE TYPE Amount
No.(a)(b)(c)
1 ADECCO Mapping Servces $38,095
2 ADP Accounting Services 51,170
3 ADVANCED SYSTEMS GROUP Computer Suppot Services 14,063
4 AERO-GRAPHICS Mapping Services 15,506
5 AMEC EARTH & ENVIRONMENTAL, IN Environmental Services 14,146
6 ASCENTIUM CORPORATION PM Consultant 15,863
7 ATER, WYNNE LLP Legal Services 36,858
8 BARKER, ROSHOLT & SIMPSON LLP Legal Services 317,271
9 BIOART & ROSS INC Management Services 70,722
10 BLACKBURN & JONES LLP Legal Servces 147,939
11 BLUE HERON CONSULTING, INC Legal Services 297,000
12 BOUILLON INTEGRATED SYSTEMS, I Computer Suppot Servces 23,950
13 BRENNEMAN, JOHN Lob Services 73,907
14 BRIGHAM YOUNG UNIVERSITY Environmental Services 50,500
15 BROWN RUDNICK BERLACK ISRAELS Loby Serces 54,000
16 BROWNSTEIN HYAn & FARBER, PC Legal Servces 1,338,228
17 CASCADE ENERGY ENGINEERING INC Engineering Servces 76,360
18 CERTUS SOFTARE INC Consultng Services 24,069
19 CHRISTENSEN REALTY INVESTMENT,Parking Services 11,880
20 CHURCH, JOHN S Economic Services 72,000
21 COMSYS INFORMATION TECHNOLOGY Computer Support Services 176,949
22 CORNERSTONE SYSTEMS INC Computer Suppo Servces 548,871
23 CRI ADVANTAGE Computer Suppt Services 130,915
24 CTA ARCHITECTS Architect Servces 66,210
25 CUMMINS & BARNARD, INC.Environmenta Services 58,539
26 DAVID EVANS AND ASSOCIATES Management Servces 92,327
27 DAVIS WRIGHT TREMAINE LLP Leg Services 785,720
28 DEAN & CARTER PLLC Legal Servces 11,439
29 DELolnE & TOUCHE Accounting Services 717,738
30 DELolnE & TOUCHE LLP Accounting Servces 99,186
31 DEUTSCHE BANK TRUST CO Acconting Services 15,297
32 DEVELOPMENT DIMNENSIONS Management Servces 10,910
33 DEWEY & LEBOEUF Legal Servces 708,845
34 DHIINC Environmental Servces 91,513
35 ECOANAL YSTS INC Environmenta Services 188,829
36 ECOS CONSULTING Consulting Servces 133,665
37 EMC CORPORATION Computer Supprt Services 11,258
38 ENERNEX CORPORATION Consulting Servces $7,553
39 ERNST & YOUNG LLP Accounting Services 158,665
40 EVERGREEN CONSULTING GROUP, LL Consulting Servces 22,845
41 FINANCIAL CONCEPTS AND APPLICA Accounting Services 12,225
42 GJORDING & FOUSER, PLLC Management Services 22,440
43 GLAHE & ASSOCIATES INC Environmenta Servces 27,540
44 GLOBAL INSIGHT Environmenta Services 25,662
45 H CHARLES DURICK Consulting Services 21,575
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in 1\ un "".11:1 i:..i:NT
Page 6
Idaho Power Company
STATE OF IDAHO - ALLOCATED
An Original December 31, 2007
STATE OF IDAHO - TOTAL SYSTEM DATA
PROFESSIONAL OR CONSULTATIVE SERVICES -ITEMS $10,000 AND OVER
Line PAYEE SERVICE TYPE Amount
No.(a)(b)(c)
46 HALL FARLEY OBERRECHT & B Legal Services $42,439
47 HARDESTY, REBECCA Environmenta Services 58,929
48 HDR ENGINEERING, INC Engineering Services 20,453
49 HOPKINS RODEN CROCKET HANSEN Lobby Services 72,175
50 HR MANAGEMENT SOLUTIONS LLC Management Servces 13,500
51 HUNTLEY PARK LLP Legl Services 80,000
52 IBM Computer Support Services 523,021
53 IDAHO STATE UNIVERSITY Environmenta Services 17,759
54 INNOVATIVE CLAIM SOLUTIONS Management Services 30,025
55 INTERMOUNTAIN TECHNOLOGY GROUP Computer Support Servces 108,807
56 J R SIMPLOT COMPANY Management Services 20,000
57 JUB ENGINEERS Engineering Services 86,495
58 L CONWAY CONSULTING, INC Consultng Services 27,817
59 LAMB WESTON Mangement Services 10,000
60 LE BOEUF LAMB GREENE Legal Services 2,157,252
61 LIGHTING DESIGN LAB Management Services 10,000
62 MALANDRO COMMUNICATION INC Consulting Servces 566,851
63 MAPFRAME CORPORATION Computer Suppo Services 103,800
64 MARSH ADVANTAGE AMERICA Management Servces 12,000
65 MATERIALS TESTING & INSPE Management Services 19,409
66 MCDOWELL & RACKNER PC Leg Services 127,631
67 MICON INC Computer Supp Services 42,422
68 MICROSOFT CORP Computer Supp Services 283,321
69 MILLER BATEMAN LLP Leg Serce 167,544
70 MWH AMERICAS, INC.Management Servces 96,860
71 NEXTAXIOM TECHNOLOGY INC Consulting Services 20,687
72 NEXUS ENERGY SOFTARE Management Servces 45,400
73 NIELSEN GROUP INC, THE Consulting Services 144,645
74 NORTHWEST POWER AND CONSERVATI Environmental Services 43,000
75 ORACLE CORPORATION Computer Support Servces 71,305
76 PACIFIC INTERNATIONAL ENGINEER Engineering Servces 50,175
77 PAINE, HAMBLEN, COFFIN, BROOK Management Servces 32,967
78 PARR WADDOUPS BROWN GEE AND LO Environmental Services 113,105
79 PARSONS BRINCKERHOFF QUADE Management Services 17,176
80 PEARSON'S WRITING, EDITING, &Management Servces 70,552
81 PINK ELEPHANT CORP Computer Support Services 24,843
82 PLANEDSCAPE Consulting Servces 60,858
83 PORTLAND ENERGY CONSERVATION,Environmenta Services 200,349
84 POWER ENGINEERS INC Engineering Servces 14,768
85 QUANTEC LLC Consulting Servces 21,845
86 RESOURCE DATA, INC Computer Support Services 10,815
87 RIDDELL WILLIAMS P.S.Legal Services 108,639
88 RIGHT SYSTEMS, INC Management Services 30,240
89 RIPLEY, LARRY D Legal Services 22,150
Page6A
tr'\l\ut" QIIDDI C".Cli1T
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Idaho Power Company
STATE OF IDAHO. ALLOCATED
An Original December 31, 2007
STATE OF IDAHO - TOTAL SYSTEM DATA
PROFESSIONAL OR CONSULTATIVE SERVICES -ITEMS $10,000 AND OVER
Line PAYEE SERVICE TYPE Amount
No.(a)(b)(c)
90 RIVERSIDE TECHNOLOGY INC Management Services 551,254
91 S G S STATISTICAL SERVICES Accounting Services 16,000
92 SALLADAY & DAVIS Legl Services 45,998
93 SCIENCE APPLICATIONS INTE Environmenta Services 12,143
94 SOFTARE AG INC Computer Support Services 120,000
95 SOLID QUALITY LEARNING LLC Management Servces 15,695
96 SOUTH LANDSCAPE ARCHITECTS Engineering Servces 10,097
97 SPHERION STAFFING AND RECRUITI Employment Services 49,768
98 SPL WORLDGROUP INC Computer Support Services 119,149
99 ST ALPHONSUS REGIONAL MEDICAL Environmenta Servces 10,000
100 STAHMAN, ROBERT W Legal Servces 17,000
101 STATE OF IDAHO FISH & GAME Environmental Servces 50,000
102 STATISTICAL DESIGN Management Services 25,047
103 STEPTOE & JOHNSON LLP Legal Servces 1,374,110
104 STOEL RIVES LLP Legal Servces 41,137
105 SULLIVAN & CROMWELL Management Services 213,292
106 SUMMIT BLUE CONSULTING LLC Consulting Servces 21,330
107 SWCA, INC Environmental Services 165,808
108 TEKSYSTEMS Computer Supp Services 131,015
109 TETRA TECH INC Computer Suppt Services 22,783
110 THE LITGATION DOCUMENT GROUP Management Servces 18,576
111 TOOTHMAN.ORTON ENGINEERING Engineering Services 51,767
112 TOWERS PERRIN HR SERVICES Management Servces 136,989
113 TREASURE VALLEY LEGAL SERVICES Legal Servces 73,336
114 US BUREAU OF RECLAMATION Environmental Servces 40,000
115 UNIVERSITY OF IDAHO Environmenta Services 32,330
116 VAN NESS FELDMAN Legal Services 1,184,465
117 VAN WINKLE ENVIRONMENTAL CONSU Environmenta Servces 24,000
118 WEATHER MODIFICATION INC Cloud Seeding Servces 63,099
119 WEBMETHODS Computer Supprt Services 14,871
120 WELLENS FARWELL INC Management Servces 560,322
121 WESTERN WEED SERVICE INC Management Services 23,545
122
123
124
125
126
127
128
129
130
131
132
133 TOTAL 17,957,200
Page6B
InJ\un ~IIDDI i:ui:1\
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Idaho Power Company
STATE OF IDAH - ALLOCATED
An Original
IPROFESSIONAL OR CONSULTATIVE SERVICES
ITEMS $5,000 OR MORE BUT LESS THAN $10,000
Line PREDOMINANT
No.PAYEE NATURE OF SERVICE AMOUNT
1 AMERICAN GEOTECHNICS, INC Engineering Servces 7,470
2 BAKER, KEN Manageent Servces 9,090
3 BUSINESS LEGAL CONSULTING Lega Servces 5,709
4 CALIFORNIA ISO Environmenta Servce 6,250
5 CHAVEZ SURVEY RESEARCH, INC Customer Survey Servces 8,864
6 DC ENGINEERING, PC Engineering Servces 7,000
7 E'TRAOE Accounting Services 6,309
8 FALTER PHD, C. MICHAEL Management Servces 7,992
9 FURNITURE PER QUOTE Management Services 9,248
10 GILBERT, DAN D Meteorological Services 9,951
11 HISTORY ASSOCIATES, INC.Consultng Services 7,786
12 INTERMOUNTAIN CLAIMS, INC Claim Services 6,704
13 KEMAINC Management Services 5,927
14 MERCER HUMAN RESOURCE CONSUL TI Consulting Services 6,350
15 MOEN, MONICA B Legal Services 9,124
16 MUSSElER ENGINEERING INC Engineering Serves 9,983
17 PARADIGM LEARNING, INC Management Servce 8,690
18 PERSONNEL PLUS Employment Servces 7,444
19 PHONE PRO Consulting Servces 8,011
20 PLATEAU SYSTEMS L TO Management Services 6,200
21 SORRENTO LACTALlS, INC Management Services 9,258
22 SOUND CHOICE, INC Management Servces 5,157
23 SUSAN STIMPSON Management Servces 6,500
24 UNIVERSAL MANAGEMENT SOLUTIONS Management Servces 7,000
25 UTAH YAMAS CONTROLS Management Services 5,376
26 YAMAS CONTROLS INTERMOUNTAIN,Management Services 8,960
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
40
41
42
43
44
45 TOTAL 196,351
iniu.in !'IIPPI FMFNT
Page 6C
December 31. 2007
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Idaho Power Company
8T ATE OF IDAHO. AlLOCATED
An Original
Balance at
Beginning of year
(b)
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December 31, 2007
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ELECTRIC PLANT IN SERVICE (Accounts 101, 102, 103 and 106)
1. Report below the origina cost of elecric plant in service acrding to the prescnbed accounts.
2. I n addition to Account 101, Electric Plant in service (Clasified), thi pae an the next include Account 102, Electric Plant
Purchaed or Sold; Account 103, Expenmental Elecnc Plan Unclasifie; an Account 106, Completed Construction
Not Classified - Electnc.
3. Include in Column (c) or (d), as appropnate, correcions of additions an retirements for the current or preceding year.
4. Enclose in parenthees credit adjustments of plan accounts to indicae the negative effect of such accounts.
5 Classify Account 106 according to prescribed acounts, on an estimated basis if necessary, and include the entries in
column (c) . Also to be included in column (c) are entries for reversal 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 bais, 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.
No.
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
Line
Account
(a)
1. IN IANlili:LE PLANT
(301) Organizatiön. ..... ......... ................... ...... ......... ......... ...... ..........
(302) Franchises and Consents.... ............. ....... .......... ... .... .............. .......
(303) Miscellaneous Intangible Plant............................. ............... ........... ......
TOTAL Intanible Plant (Enter Total of line 2, 3, an 4)................ ............ ". ...
2. PRODUCTION PLANT
A. steam Production Plant
(310) Land and Land Rights ........ . .... ... ......... ....... ...... ... ...... ...... .... ..........
(311) struclures and Improvements... ....... ........... .... .. .............. .............
(312) Boiler Plan Equipment.. .. ........... ...... ........ .... ........ . ......... .. .... ..'
(313) Engines and Engine Driven Generators. ... ......... .. ............. . ..... ......
(314) Turbogenerator Units..... .... ..... ..... ...... ....... ...... . .. ...........
(315) Accessory Electnc Equipment... ..... ....... ..... .... ........................
(316) Misc. Power Plant Equipment. ... .............. ... ...... ................................
(317) Asset Retirement Costs for Steam Production.. ........... ....... ... ...
TOTAL steam Production Plant (Enter Total of line 8 thru 15). ......... ... .......
B. Nuclear Production Plan
(320) Lan and Land Rights............. ......................................... ..... ..... ............
(321) structures and Improvements. ........................... ................ ..... .........
(322) Reactor Plan Equipment.... .... .... ........... .............. .... ....... ..... .... ..... . .....
(323) Turbogenerator Units..... ....... .... ............. ... ...... ... ... ........ ........ .......
(324) Accesory Electric Equipment. ............... . ... ...... .......... ......
(325) Misc. Power Plant Equipment... .. ........... ..... ...... . .... . ... ....
(326) Asset Retirement Costs for Nuclear Production. .... .... ........ ......... ....
TOTAL Nuclear Production Plant (Enter Total of lines 17thru 24).... .............
C. Hydraulic Production Plant
(330) Land and Land Rights... .... ........... . . ....
(331) structures and Improvements............ .. ... ... .... ............... ... ............. ...
(332) Reservoirs, Dams, and Waterways........... ............ ............. ....... .......... ..
(333) Water Wheels, Turbines, and Generators.. . ................. .......
(334) Accessory Electric Equipment................ ........ .... ........... .....................
(335) Misc. Power Plant Equipment... ..... ......... ..... ...... ........... . ...... ............
(336) Roads, Railroads, and Bndges... ........... .... ......... ... .... ...... ......... ........
(337) Asset Retirement Costs for Hydraulic Production........... .........................
TOTAL Hydraulic Production Plant (Enter Total of line 27thru 34)................... .
D. Other Production Plant
(340) Land and Lan Rights................ ............... ...............................................
(341) structures an Improvements.......................... ................................. ........
(342) Fuel Holders, Products and Accessones........... .............. ...... ..................
(343) Prime Movers.. . ........... ........... ......... ... .... ........ .......... .... ..............
(344) Generators.. . ......... .. .... ....... ." ...... .. ..... ........ .... ............
(345) Accessory Electric Equipment.. ........... ................... .... ......
(346) Misc Power Plant Equipment. ... .......... ........ . ..... ........... ..... .. ...
Page 7
Additions
(c)
$ 57,529
20,553,832
46,571,649
67,183,011
3,982,426
793,884,294
613,086,985
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Idaho Power Com pany
STATE OF IDAHO. ALLOCATED
An Original Decem ber 31, 2007
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ELECTRIC PLANT IN SERVICE (Accounts 101, 102, 103 and 106) (Continued)
Show in column (I) reclassifications or transfers within utility plant accounts. Include also in column
(f) the add~ions or reductions of primary account classifications ariing from distribution of amounts
initially recorded in Account 102. In showing the clearance of Account 102, include in column (e) the
amounts with respe to accumulated provision lor depreciation, acquisition adjustments, etc., and show
in column (I) only the offset to the deb~s or cred~s distributed in column (f) to primary account classifications.
For Account 399, state the nature and use of plant included in this account and ~ substantial in amount
submit a supplementar statement showing subaccount class~ication of such plant conforming to the
requirements 01 these pages.
For each amount comprising the reported balance and changes in Account 102, state the property purchaed
or sold, name of vendor or purchaer, and dae of transaction. If propoed journal entries haVe been fied
with the Commission as required by the Un~orm System of Accounts, give also date of such filng.
Balane at Line
Retirements Adjustments Tranfers End of Year
(d)(e)(f)(g)No.
1
$5,289 (301)2
20,729,010 (302)3
45,458,188 (303)4
66,192,487 5
6
7
(310)8
(311)9
(312)10
(313)11
(314)12
(315)13
(316)14
4,751,512 (317)15
824,234,217 16
17
(320)18
(321)19
(322)20
(323)21
(324)22
(325)23
(326)24
25
26
(330)27
(331)28
(332)29
(333)30
(334)31
(335)32
(336)33
(337)34
635,772,428 35
36
(340)37
(341)38
(342)39
(343)40
(344)41
(345)42
(345)43
Page 8
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inAwn !'IIPPI i:Mi:NT
Idaho Power Company
STATE OF IDAHO. AlLOCATED
An Original
Balance at
Beginning of year
(b)
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December 31, 2007
I
Additions I
(c)
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Line
ELECTRIC PLANT IN SERVICE (Accounts 101, 102, 103 and 106) (Continued)
No.
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83
84
85
86
87
88
89
90
91
92
93
94
95
96
Account
(a)
$ 101,232,115
1,508,203,394
24,675,658
31,520,034
210,231,053
84,489,667
64,309,387
102,055,096
261,954
517,542,847
4,341,499
19,267,383
134,544,631
178,077,556
91,808,497
43,012,125
159,571,691
289,80,410
48,616,312
50,592,870
2,358,293
3,860,189
1,025,851,456
8,108,134
59,594,282
34,567,743
47,247,737
909,180
3,907,749
9,033,982
6,762,653
26,096,312
2,68,355
198,916,128
198,916,128
3,317,696,836
$ 3,317,696,836
in AUI" ellDDI I:Ilø:ldT
(346) Misc. Power Plant Equipment.. ............................. ..... .... . ....................
TOTAL Other Productipn Plant (Enter Total of line 37 thru 44).. ...................
TOTAL Production Plant (EnterTotal of line 16, 25, 35, and 45).... ........ ........
3. TRANSMISSION PLANT
(350) Land and Land Rights.. ............ ............... ............ ......... . .... ....
(352) Structures and Improvements.. ........... ..... .... ..... ......... ....... ............
(353) Station Equipment. ......... ..... .......... ...... ..... ... .......... ....... .......
(354) Towers and Fixures...... ... ...................... ... ........ . ........ ............... . ....
(355) Poles and Fixtures.......................................................... .... ................
(356) Overhead Conductors an Device.. ....... ....... ..... .... ....... ........ .... ........... ....
(357) Underground Condu~ .... .......... ................ ... ........ ......... ....... ..... .......... .....
(358) Underground Conductors and Oevices.......... ................. ..... .. . ..........
(359) Roads and Trails........................... ........ ..... .............. ..... ..... ..........
(359.1 ) Asset Retirament Costs for Transmission Plant. ......... ..... ... ..... .....
TOTAL Transmission Plant (Enter Total of lines 48 thru 57)..... ......... ..... ........
4. DISTRIBUTION PLANT
(360) Land and Land Rights.. ............ .... ....... . ....
(361) Structures and Improvements. .... ........ .......
(362) Station Equipment. ......
(363) Storage Battery Equipment.
(364) Poles, Towers, and Fixture..
(365) Overhead Conductors and Oevices.. ............. ..... ............ ........
(366) Underground Conduit.... ........... .................. ... ...... ...... ..........
(367) Underground Conductors an Oevices.......... ..... .... ......... .........
(368) Line Transformers......................................................... .. ..........................
(369) Services.. .... .................. ... ................... ........ ............... ............. ........
(370) Meters. ...... ...... .... ....... .................................................. ....... .............. ...
(371) Installations on Customer Premises................. ......... .................... ........
(372) Leased Property on Customer Premises.............. ... .................. ..... .......
(373) Street Lighting and Signal Systems..... ...... ......................
(374) Asset Retirement Costs for Oistribution Plant..... ........... .......... ........
TOTAL Distribution Plant (Enter Total of line 60 thru 74)....... .................
5. GENERAL PLANT
(389) Land and Land Rights.. .... .............. .......... ..... ............ ..........................
(390) Structures and Improvements. .... ...... ....... ...... ....... ......
(391) Ofice Furniture and Equipment.......... ..... .... ..... ........ ........... . ... ...
(392) Tranportation Equipment................... ......... ............... .......
(393) Stores Equipment. ..... .......... .............. ........... .... .......
(394) Tools, Shop, and Garage Equipment..... .. ...... ................ ....... .......... .....
(395) Laboratory Equipment. ...... ... .......... .. .... ....... .. ......... ............ . ..... ..... . ....
(396) Power Operated Equipment. ... .......... ........... ...... ....... ....... ...... ....... ....... .....
(397) Communication Equipment......... . ... ........ ... ...... ...... .............. .................
(398) Miscellaneous Equipment.................................... ........................... ...........
SUBTOTAL (Enter Total 01 lines 77 thru 86).............. ..... ................................
(399) Other Tangible Property........... ......... .. ........... ........................ ................
(399.1) Asset Reiirement Costs for Genera Plant....... ............. .... ....... ......
TOTAL General Plant (Enter Total of line 87, 88 and 89)....... ....................
TOTAL (Accounts 101 and 106)..... ................ ...... ....... ....... .............
(102) Electric Plant Purchaed.. . . ..... .. ..... .......... ... ....................
(Less) (102) Electric Plan Sold........... ...... ..... ........ ........ .... ... ..... ..............
(103) Experimental Plant Unclassified. ... .. ........ ....... ...
TOTAL Electric Plant in Service.........
t'age9
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Idaho Power Company
STATE OF IDAHO. ALLOCATED
An Original December 31, 2007
ELECTRIC PLA IN SERVICE (Accounts 101,102,103 an 106) (Continued)
Balance at Line
Retirements Adjustments Traners End of Year
(d)(e)(f)(9)No.
(346)44
,$101,426,503 45
1,561,433,146 46
47
26,624,995 (350)46
34,464,805 (352)49
224,406,655 (353)50
104,698,993 (354)51
73,602,511 (355)52
116,628,677 (356)53
(357)54
(356)55
261,236 (359)56
(359.1)57
582,687,874 58
59
4,177,113 (360)60
20,581,394 (361)61
144,293,516 (362)62
(363)63
187,646,959 (364)64
99,310,499 (365)65
45,493,263 (366)66
166,166,353 (367)67
320,594,439 (366)66
51,079,612 (369)69
53,914,672 (370)70
2,446,856 (371)71
(372)72
3,916,181 (373)73
(374)74
1,101,621,080 75
76
6,229,314 (389)77
63,600,301 (390)76
35,424,379 (391)79
53,102,346 (392)60
996,702 (393)61
4,090,231 (394)62
9,469,976 (395)83
6,077,986 (396)64
24,014,366 (397)65
2,606,494 (398)66
210,032,117 67
(399)68
(399.1)69
210,032,117 90
3,521,966,706 91
(102)92
(102)93
(371)94
95
$3,521,966,706 96
Pag 10
inl\ul' e:IIDDI I:IJa=..
Idaho Power Company
STATE OF IDAHO. ALLOCATED
An Original December 31, 2007
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 additon to the number of flat rate
accounts; except that where separate meter readings are add for billng purpoes, one customer should be counted
for each group of meters added. The average number of customers meas 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 repoed figures, explain any
inconsistencies in a footnote.
OPERATING REVENUES
Amount for Amount for
No.Current Year Previous Year
(a)(b)(c)
1 Sales of Electricity
2 (440) Residential Sales.................................................................$297,428,947 $289,068,594
3 (442) Commercial and Industrial Sales
4 Small (or Commercial)(See Instr. 4) (1)......................................245,919,592 221,723,109
5 Large (or Industrial)(See Instr. 4) (2)...........................................92,303,177 93,623,913
6 (444) Public Street and Highway Lighting......................................2,374,374 2,290,770
7 (445) Other Sales to Public Authorities.........................................
8 (446) Sales to Railroads and Railways..........................................
9 (448) Interdepartmental Sales.......................................................
10 TOTAL Sales to Ultimate Consumers.......................................638,026,089 .606,706,387
11 (447) Sales for Resale. Opptunity....Non.Firm Only.................159,135,233 242,715,342
12 TOTAL Sales of Electricity........................................................797,161,322 849,421,730
13 (449.1) Provision for Rate Refunds. ..... ............ ...... .......... ....... .....(1,075,534)(1,211,251)
14 TOTAL Revenue Net of Provision for Refunds.........................796,085,788 848,210,479
15 Other Operating Revenues
16 (450) Forfeited Discounts..............................................................
17 (451) Miscellaneous Service Revenues.........................................3,996,236 5,368,289
18 (453) Sales of Water and Water Power.........................................
19 (454) Rent from Electric Propert..................................................17,049,167 15,142,580
20 (455) Interdepartmenta Rents......................................................
21 (456) Other Electric Revenues......................................................24,347,160 7,748,184
22
23
24
25 TOTAL Other Operating Revenues..........................................45,392,562 28,259,054
26 TOTAL Electric Operating Revenues........................................$841 ,478,350 $876,469,532
(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
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Idaho Power Company
STATE OF IDAHO - ALLOCATED
An Original December 31,2007
ELECTRIC OPERATING REVENUES (Account 400) (Continued)
4. Commercial and Industrial Sales, Account 442, may be classified according to the basis of classification
(Small or Commercial, and Large or Industrial) regularly used by the respondent if such basis of classification
is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of Accounts. Explain
5. See page 108, Importnt Changes During Year, for important new territory added and impotant rate increases or
decreases.
6. For lines 2,4,5, and 6, see page 304 for amounts relating to unbiled revenue by accounts.
7. Include unmetered sales. Provide details of such saes in a footnote.
KILOWATT HOURS SOLD AVERAGE NUMBER OF CUSTOMERS PER MONTH
Amount for Amount for Amount for Number for Line
Current Year Previous Year Current Year Previous Year No.
(d)(e)(f)(g)
1
5,027,203,909 4,868,383,891 383,992 374,527 2
3
5,622,131,528 5,170,019,354 73,726 71,472 4
3,170,394,452 3,170,158,215 118 122 5
28,637,063 27,402,244 992 768 6
7
8
9
13,848,366,952 ..13,235,963,704 458,828 446,889 10
2,603,995,368 5,492,528,583 N/A N/A 11
16,452,362,320 18,728,492,287 458,828 446,889 12
13
. Includes $ 4,657,755 unbiled revenues.
.. Includes 13,733,012 KWH relating to unbilled revenues.
Lines 11 through 21 are on an "allocated" basis.
Page 11a
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Idaho Power Company
STATE OF IDAHO. ALOCATED
An Original DecEmber 31, 2007
IELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount fo previous yea is not derved from previously reped figures. exlain in footnotes.
iune Amoumror Amoumror
No.Account Current Yea Previous Yea
(a)(b)(c)
1 1. t-UW
~A. ::ieam t-ower l.eneraiion
3 Operation
4 (500) Operation Supervision and Engineering................................................................$1,585.144 $1.621,185
5 (501) FueL...................................................................................................................108.989,376 101,451,974
6 (502) Steam Expenses... ......... ... ........... ........... ...... .... .... ........................................... ...6,491,790 6,706.052
7 (503) Stea from Other Sources.............. ....................................................................
8 (Less) (504) Steam Transferred-Cr................................................................................
9 (505) Electric Expenses....................... ................................................... ......................2.002,446 1.362,769
10 (506) Miscellaneous Stea Power Expenses.............. ................... ................................7,681,857 7,708.765
11 (507)Rents..................................................................................................................281,610 235,366
12 (509) Allowances..........................................................................................................
13 TOTAL Operation (Enter Total of lines 4 thru 12).....................................................12/,032.223 1n:l.Ul:!j,ll~
14 Maintenance
15 (510) Maintenance Supervision and Engineeng............................................................2,456,682 2,390.796
16 (511) Maintenance of Structures....................................................................................618.172 387,046
17 (512) MaintenanCe of Boiler Plant..................................................................................13.885.052 14,509.643
18 (513) Maintenance of Electric Plan!.............................................................................5.395.860 4,183.656
19 (514) Maintenance of Miscellaneous Stea Plan!........................................................5.650,640 4.331,618
20 TOTAL Maintenance (Enter Total of Lines 15 thru 19)..............................................,~O,l:U;:./Ol:
21 TOTAL Power Production Expnses-Stea Power (Enter Tota of lines 13 and 20)..,I 44.l:l:0.l:/U
22 B. Nuclea Power Generation
23 Operation
24 (517) Operation Supervision and Engineering................................................................
25 (518) FueL...................................................................................................................26 (519) Cooants and Water.............................................................................................
27 (520) Steam Expenses..... ........... ............ .....................................................................
28 (521) Steam from Other .sources..................................................................................
29 (Less) (522) Stea Transfered-Cr................................................................................
30 (523) Electric Expenses................................................................................................
31 (524) Miscellaneous Nuclear Power Exense...............................................................
32 (525) Rents...... ............................................................................................................
33 TOTAL Operation (Enter Total of lines 24 thru 32)..................................................
34 Maintenance
35 (528) Maintenance Superision and Engineering............................................................
36 (529) Maintenance of Structures....................................................................................37 (530) Maintenance of Reactor Plant Equipmen!...........................................................
38 (531) Maintenance of Electric Plant...............................................................................39 (532) Maintenance of Miscellaneous Nuclea. Plan!.......................................................
40 TOTAL Maintenance (Enter Total of lines 35 thru 39)..............................................
41 TOTAL Power Production Expenses-Nuclea Power (Enter Total of lines 33 and 40)
42 C. Hydraulic Power Generation
43 Operation
44 (535) Operation Supervision and Engineeng................................................................4,984.055 4.280,591
45 (536) Water for Power..................................................................................................4,814,932 4,674,353
46 (537) Hydraulic Expses.............................................................................................9.016,462 7,818,109
47 (538) Electric Expenses................................................................................................1.323,535 1.312,063
48 (539) Miscellaneous Hydraulic Power Generation Expense. ............. ...... ...... '" ..............2.690,247 2.278,711
49 (540) Rents............... ...................................................................................................399,555 387.654
50 TOTAL Operation (Enter Total of lines 44 thru 49)..................................................23,228,787 2U,/01.4i:~
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Idaho Power Company
ST ATE OF IDAHO. ALLOCATED
An Original Deembe 31, 2007
I
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous yea is not derive frm previously reorted figures. exlain in footnotes.
ine Amoumior Amoumior
No.Account Current Yea Previous Yea
(a)(b)(c)
51 C. Hydraulic Power Generation (Continued)
52 Maintenance
53 (541) Maintenance Supervision and Engineering............................................................$1.785.723 $1.771.573
54 (542) Maintenance of Strctures....................................................................................1,220,450 1.129,692
55 (543) Maintenance of Reseoirs. Dams. and Waterays...............................................515.125 896.199
56 (544) Maintenance of Electric Plant............................................... ................................1.988.155 2.022.387
57 (545) Maintenance of Miscellaneous Hydraulic Plant....................................................2.630.881 3.042.284
58 TOTAL Maintenance (Enter Tota of lines 53 thru 57)................................................tl."I4U.;:;:;:tl.tlti,.1;:4
59 TOTAL Power Production Expenses-Hydraulic Power (Enter Tota of lines 50 and 58 31;369,119 '::.t:il;:.ti1tl
60 D. Other Power Generation
61 Operation
62 (546) Operation Supervision and Engineeng................................................................325,262 305.152
63 (547) Fuel....................................................................................................................18.492,527 7.075.143
64 (548) Generation Expnse...........................................................................................363.281 274.538
65 (549) Miscellaneos Other Power Generation Expse........ .........................................442,565 281.369
66 (550) Rents..................................................................................................................0 -
67 TOTAL Operation (Enter Tota of lines 62 thru 66)....................................................HI,ti';:i ,WVU,4UI
68 Maintenance
69 (551) Maintenance Supervision and Engineeng............................................................a 164
70 (552) Maintenance of Structures....................................................................................209.865 167.535
71 (553) Maintenance of Generating and Eleclnc Plant.....................................................40.597 117.540
72 (554) Maintenance of Miscellaneos Other Power Genation Plat..............................614.836 371.585
73 TOTAL Maintenance (Enter Tota of lines 69 thru 72)...............................................-Sso29fr ti~tl.i:,;:
74 TOTAL Power Production ExpensesOther Power (Enter Tota of lines 67 and 73).....20.488,934 i:.~::;:,u,a
75 E. Other Power Supply Expenses
76 (555) Purchas Power................................................................................................288.699,422 267,452,726
77 (556) System Control and Load Dispatching..................................................................73.778 72,080
78 (557) Other Expenses...................................................................................................(112.995,170)(25.848,541 )
79 TOTAL Other Power Supply Expense (Enter Total of lines 76 thru 78).....................II~.'i:,u;:u ,.. I.tlltl.,tla
80 TOTAL Power Production Expenses (Enter Tota of lines 21,41. 59, 74, and 79)........,'"..,..,171,774
81 2. TRANSMISSION EXPENSES
82 Operation
83 (560) Operation Superision and Engineeng................................................................1,987,843 2,163,362
84 (561) Load Dispatching.................................................................................................2,806.393 3,010.532
85 (562) Station Expenses...... .......... .... ............... ... ......... ................. ........ ........ ........ .........1.491.967 1,596.812
86 (563) Overhead Line Expense.....................................................................................784.669 738.876
87 (564) Underground Line Expenses................................................................................
88 (565) Transmisson of Electricity by Others....................................................................9.936.576 7.207.592
89 (566) Miscellaneous Trasmisson Expenses.................................................................529.755 230,883
90 (567) Rents..................................................................................................................990,555 982,438
91 TOTAL Opertion (Enter Tota of lines 83 thru 90)....................................................Itl.~".'~l:1 ;),::"U.4::tl
92 Maintenance
93 (568) Maintenance Supervision and Engineeing... ... ................ .... ... ......... ........ ..............376.412 393.040
94 (569) Maintenance of Structure....................................................................................387.193 169.741
95 (570) Maintenance of Station Equipment..... ........ ....... ............... ....... ........... ... ...............2.473.911 2,480.807
96 (571) Maintenance of Overhea Lines............................................................................1.987.795 1.917.736
97 (572) Maintenance of Underground Lines......... ............. .......................... .......... ..... ........
98 (573) Maintenance of Miscellaneos Transmisson Plant..............................................2.151 26,623
99 TOTAL Maintenance (Enter Tota of lines 93thru 98)................................................5.22f,4ti,4,~tll,~4l:
100 TOTAL Transmission Expense (Enter Total of lines 91 and 99)................................';:.f~~,"U ,
101 3. DISTRIBUTION EXPENSES
102 Operation
103 (580) Operation Supeision and Engineering...... ... ... .................. ................... .......... .....3,141.021 2.853.198
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Idaho Power Company
STATE OF IDAHO - ALLOCATED
An Original December 31, 207
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous yea is not derved from previously repored figures, explain in footnotes.
ine Amount tor Amount tor
No.Account Current Year Previous Year
(a)(b)(c)
104 3.DISTRIBUTION EXPENSES (Continued)
105 (581) Load Dispatching.................................................................................................$2,906,722 $2,847,658
106 (582) Station Expenses....................................... ...................... ............................ ........1,066,301 1,091,619
107 (583) Overhead Line Expenses............................ ................................... ............. .........3,172,327 3,544,944
108 (584) Underground Line Expense................................................................................2,085,453 2,008,479
109 (585) Street Lighting and Signal System Expense........................................................141,411 146,732
110 (586) Meter Expenses...................................................................................................4,332,721 4,122,897
111 (587) Customer Installations Expense..........................................................................1,227,727 1,028,502
112 (588) Miscellaneous Distribution Expenses....................................................................5,187,236 5.227,173
113 (589) Rents......................................... .........................................................................604,482 140,239
114 TOTAL Operation (Enter Tota of lines 103 thru 113)...............................................,;:,llbti,402 ~"IUIII~'
115 Maintenance
116 (590) Maintenance Supervision and Engineering............................................................246,198 208,690
117 (591) Maintenance of Structures....................................................................................0 -
118 (592) Maintenance of Station Equipment............................................................ .........3,322,976 2,659,704
119 (593) Maintenance of Overhead Lines............................................................................11,557,647 10,129,328
120 (594) Maintenance of Underground Lines.......................................................................1,328,521 1,096,396
121 (595) Maintenance of Line Transformers........................................................................154,268 530,254
122 (596) Maintenance of Street Lighting and Signal Systems......................................... .....453,194 674,996
123 (597) Maintenance of Meters.................................... .....................................................888,231 861,056
124 (598) Maintenance of Miscellaneous Distribution Plant.................................................114,582 133,375
125 TOTAL Maintenance (Enter Tota of lines 116 thru 124)............................................11l,Ub:i,blll lb,,::;:,IiUU
126 TOTAL Distribution Expense (Enter Tota of lines 114 and 125)...............................41,931,019 "l:,;::i,242
127 4. CUSTOMER ACCOUNTS EXPENSES
128 Operation
129 (901) Supervision.................. ....... .... ...... ...... ..... ......... ................ ......... .......... ........... ....435,360 512,985
130 (902) Meter Reading Expense......... ...... ...... ...... ......... ............ ............ .......... .......... .....5,146,950 4,958,009
131 (903) Customer Reords and Collection Expenses.. ..... ............ ......... ... ......... ........... ......7,866,032 9,753,911
132 (904) Uncollectible Accounts.........................................................................................1,876,639 2,770,604
133 (905) Miscellaneous Customer Accounts Expense.......................................................320 356
134 TOTAL Customer Accounts Expense (Enter Tota of lines 129 thru 133)..................i:;,;:,:;,;:uu 1 f,:::::i,llbb
135 5. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
136 Operation
137 (907) Supervision........... ................ ..... ......... ..................... .... ........... ............ ................299,100 281,641
138 (908) Customer Assistance Expense...... ........ ............... '" ......... .......... ......... ...............21,710,324 8,822,366
139 (909) Informational and Instructional Expense..............................................................0 192
140 (910) Miscellaneous Customer Service and Infoational Expense...............................876,111 826,658
141 TOTAL Cust. Service and Informational Expenses (Enter Tota of lines 137 thru 140)..22,555,534 9,930,Il:;f
142 6. SALES EXPENSES
143 Operation
144 (911) Supervision.........................................................................................................
145 (912) Demonstrating and Sellng Expenses....................................................................
146 (913) Adverising Expenses...........................................................................................
147 (916) Miscellaneous Sales Expenses.............................................................................
148 TOTAL Sales Expense (Enter Total of lines 144 thru 147).......................................
149 7. ADMINISTRATIVE AND GENERAL EXPENSES
150 Operation
151 (920) Administrative and General Salares.... ........................ ............ .......... ......... ..........46,724,352 45,701,139
152 (921) Offce Supplies and Expenses...... ... ..... ........... ...... ............ ....... ..... ... ... ............. ....16,697,245 13,696,615
153 (Less) (922) Administrative Expense Translerred-Credit............... ........ .......................(26,005,639)(27,386,005)
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Idaho Power Company
STATE OF IDAHO. ALLOCATED
An Original December 31, 207
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnotes.
ioe Amount lor Amouni iu
No.Account Current Yea Previos Yea
(a)(b)(c)
154 7. ADMINISTRATIVE AND GENERAL EXPENSES (Continued)
155 (923) Outside Services Employed.................................................................................$10,542,564 $7,610,977
156 (924) Propert Insurance..............................................................................................2,957,019 2,744,172
157 (925) Injunes and Damages.................. ....................... ..... ....... ........ .............................5,113,519 4,811,467
158 (926) Employee Pensions and Benefits..... ......... ........... ..... .............. .......... ..... ... ... ... .....26,159,168 27,309,084
159 (927) Franchise Requirements..... ............. .......... ........ ............... ............ ... ...... ...... ........1,20 2,00
160 (928) Regulatory Commisson Expenses....... ........... ................ .............. .... ......... ..........5,332,170 (316,513)
161 (929) Duplicate ChargesCr...........................................................................................
162 (930.1) General Adversing Expenses...,.......................................................................487,897 100,217
163 (930.2) Miscellaneous General Expenses.......................................................................3,282,233 1,775,497
164 (931) Rents..................................................................................................................10,731 3,705
165 TOTAL Operation (Enter Tota of lines 151 thru 164)................................................~1,~u¡Q8 ,,
166 Maintenance
167 (935) Maintenance of General Plant...............................................................................3,498,047 3,673,670
168 TOTAL Admin and General Expse (Enter Total of lines 165.167)......................94,l$,506 Ill,I2ti,U24
169 TOTAL Elec Op and Maint Exp (Total of 80, 100, 126, 134, 141, 148, 168).............:I 561,::12,29::~$5ll2,ti4tl,2Uti
IDAHO ONLY
NUMBER OF ELECTRIC DEPARTMENT EMPLOYEES
1. The data on number of employees should be reported for the payroll penod ending neaest to October 31,
or any payroll penod ending 60 days before or atter OCtober 31.
2. If the resondent's payroll for the reporting period includes any special construction personnel, include
such employees on line 3, and show the number of such specia constrction employee in a footnote.
3. The number of employee asgnable to the electric dearment from joint functions of combination utilties
may be determined by estimate, on the bais of employee equivalents. Show the estimated number of equiv-
alent employees attributed to the electnc deparent from joint functions.
1 Payroll Period Ended (Date)..........................................................................................
2 Total Reular Full-Time Employees...............................................................................
3 Total Par-Time and Temporar Employee..... ............ .............. ..... ..... ..... .... ......... ........
4 Total Employee......... .... ... .... .......... ...... ........... ... ...... ...... ..... ............. ...... .....................
December 31, 2007 Deember 31, 2006
1,871
38
1,968
29
1,997 1,909
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