2008Annual Report.pdf

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Form 1 Approved
"" OMS No. 1902-0021
(Expires 2/29/2009)
r.. form 1-F Approvedi; te_~.:i. 902-0029
20M . (Expires 2ì28/2009)-v., APR pprm 3-0 Approved
ò'M~&9et-0205
212~~009)
THIS FILING IS
Item 1: lI An Initial (Original)
Submission
OR 0 Resubmission No.
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FERC FINANCIAL REPORT
FERC FORM No.1: Annual Report of
Major Electric Utilities, Licensees
and Others and Supplemental
Form 3-Q: Quarterly Financial Report
These reports are mandatory under the Federal Power Act, Sections 3, 4(a), 304 and 309, and
18 CFR 141.1 and 141.400. Failure to report may result in criminal fines, civil penalties and
other sanctions as provided by law. The Federal Enery Regulatory Commission does not
consider these reports to be of confidential nature
Exact Legal Name of Respondent (Company)
Idaho Power Company
I FERC FORM NO.1/3-Q (REV. 02-04)
Year/Period of Report
End of 2008/04
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Deloitte.('i: \1..1 i.. .
Deloitte & Touche LLP
Suite 1700
101 South Capitol Boulevard
Boise, 1083702-7734
USA
Tel: [phone]
Fax: [phone]
ww.deloitte.com
iUß~~PR 20 M'\ 8: 42
INDEPENDENT AUDITORS' REPORT
Idaho Power Company
Boise, Idaho
We have audited the balance sheet - regulatory basis of Idaho Power Company (the "Company") as of
Decembe 31, 2008, and the related statements of income - regulatory basis; retaned earings -
regulatory basis; cash flows - regulatory basis, and accumulated other comprehensive income,
comprehensive income, and hedgig activities - regulatory basis, for the year ended. December 31, 2008,
included on pages 110 though 123 of the accompanyig Feder Energy Regulatory Commssion Form1.
These financial statements are the responsibility of the Company's maagement. Our respnsibility is to
express an opinion on these fiancial statements based on our audit.
We conducted our audit in accordance with auditig stadards generlly accepted in the United States of
Amerca. Those stadards require that we plan and perorm the audit to obtain reasonable assurce about
whether the financial statements are free of material misstatement. An audit includes considertion of
interal control over financial reportng as a basis for designing audit procedurs that are appopriate in
the circumtaces, but not for the purse of expressing an opinion on the effectiveness of the Company's
interal control over fiancial reprtg. Accordingly, we express no such opinion. An audit also includes
exaing, on a test basis, evidence supportg the amounts and disclosures in the finacial stateents,
assessing the accountig principles used and significant estimates made by maagement, as well as
evaluatig the overll fiancial statement presentation. We believe that our audit provides a reasonable
basis for our opinion.
As discussed in Note 1, these fiancial sttements wer prepared in accordance with the accounting
requirements ofthe Federl Energy Regulatory Commssion as set fort in its applicable Uniform System
of Accounts and published accounting releases, which is a comprehensive basis of accountig other th
accountig priciples generlly accepted in the United States of Amerca.
hi our opinion, such regulatory-basis financial statements present fairly, in all mateal respcts, the
assets, liabilties, and proprieta capital of the Company as of Decembe 31,2008, and the results of its
opertions and its cash flows for the year ended December 31, 2008, in accordance with the accountig
requirements of the Federl Energy Regulatory Commssion as set forh in its applicable Uniform System
of Accounts and published accountig releases.
Ths report is intended solely for the information and use of the board of directors and maagement of the
Company and for filing 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~ +- -r~ LL.tp
Februar 25,2009
Member of
Deloitte Touche Tohmatsu
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FERC FORM NO. 1/3-Q:
REPORT OF MAJOR ELECTRIC UTILITIES LICENSEES AND OTHER
IDENTIFICATION
01 Exact Legal Name of Respondent 02 YearlPeriod of Report
Idaho Power Company End of 2008/04
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) rx An Original (2) 0 A Resubmission (Mo, Da, Yr)
[phone] 04/15/2009
ANNUAL CORPORATE OFFICER CERTIFICATION
The undersigned offcer certifes that:
I have examined this report and to the best of my knowledge, information, and belief all statements of fact contained in this report are correct statements
of the business affairs of the respondent and the financial statements, and other financial information contained in this report, conform in all material
respects to the Uniform System of Accounts.
-
01 Name 03 Signature 04 Date Signed
Darrel Anderson (Mo, Da, Yr)
02 Title
Senior VP of Admin Ser & CFO Darrel Anderson 04/15/2009
Title 18, U.S.C. 1001 makes it a crime for any person to knowingly and willngly to make to any Agency or Department of the United States any
false, fictitious or fraudulent statements as to any matter within its jurisdiction.
FERC FORM No.1/3-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 2008/Q4
(2) Fi A Resubmission 04/15/2009
LIST OF SCHEDULES (Electric Utilty)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Line Title of Schedule Reference Remarks
No.Page No.
(a)(b)(c)
1 General Information 101
2 Control Over Respondent 102
3 Corporations Controlled by Respondent 103
4 Offcers 104
5 Directors 105
6 Important Changes During the Year 108-109
7 Comparative Balance Sheet 110-113
8 Statement of Income for the Year 114-117
9 Statement of Retained Earnings for the Year 118-119
10 Statement of Cash Flows 120-121
11 Notes to Financial Statements 122-123
12 Statement of Accum Comp Income, Comp Income, and Hedging Actvities 122(a)(b)
13 Summary of Utilty Plant & Accumulated Provisions for Dep, Amor & 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 Electrc Plant Held for Future Use 214
18 Construction Work in Progress-Electric 216
19 Accumulated Provision for Depreciation of Electrc 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 Interconnection 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 Other Paid-in Capital 253
31 Capital Stock Expense 254
32 Long-Term Debt 256-257
33 Reconciliation of Reported Net Income with Taxable 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 Other Deferred Credits 269
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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 2008/Q4
(2) 0 A Resubmission 04/15/2009
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
certin pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Line Title of Schedule Reference Remarks
No.Page No.
(a)(b)(c)
37 Accumulated Deferred Income Taxes-Accelerated Amortization Property 272-273
38 Accumulated Deferred Income Taxes-Other Propert 274-275
39 Accumulated Deferred Income Taxes-Other 276-277
40 Other Regulatory Liabilties 278
41 Electric Operating Revenues 300-301
42 Sales of Electricity by Rate Schedules 304
43 Sales for Resale 310-311
44 Electrc Operation and Maintenance Expenses 320-323
45 Purchased Power 326-327
46 Transmission of Electricity for Others 328-330
47 Transmission Of Electricity by ISO/RTOs 331 None
48 Transmission of Electrcity by Others 332
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49 Miscellaneous General Expenses-Electric 335
50 Depreciation and Amortization of Electric Plant 336-337
51 Regulatory Commission Expenses 350-351
I 52 Research, Development and Demonstration Activities 352-353
53 Distribution of Salaries and Wages 354-355
54 Common Utility Plant and Expenses 356 None
I 55 Amounts included in ISO/RTO Settement Statements 397 None
56 Purchase and Sale of Ancilary Services 398 None
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57 Monthly Transmission System Peak Load 400
58 Monthly ISO/RTO Transmission System Peak Load 400a None
59 Electric Energy Account 401
60 Monthly Peaks and Output 401
61 Steam Electric Generating Plant Statistics 402-403
62 Hydroelectric Generating Plant Statistics 406-407
63 Pumped Storage Generating Plant Statistics 408-409
64 Generating Plant Statistics Pages 410-411
I 65 Transmission Line Statistics Pages 422-423
66 Transmission Lines Added During the Year 424-425
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FERC FORM NO.1 (ED. 12-96)Page 3
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2008/Q4 I
I
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) Ei A Resubmission 04/15/2009
LIST OF SCHEDULES (Electric Utiity) (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
Remarks ILine
No.
Title of Schedule
(c)
I67 Substations
68 Footnote Data
Stockholders' Reports Check appropriate box:
Q9 Four copies wil be submitted
o No annual report to stockholders is prepared
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FERC FORM NO.1 (ED. 12-96)Page 4
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Name of Respondent
Idaho Power Company
This Report Is:
(1) IX An Original
(2) 0 A Resubmission
Date of Report
(Mo, Da, Yr)
04115/2009
Year/Period of Report
End of 2008/Q4
GENERAL INFORMATION
1. Provide name and title of offcer having custody of the general corporate books of account and address of
offce 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.
Darrei Anderson Senior Vice President of Adnistrative Services and CFO, Idao Power Company
1221 W. Idao 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 type
of organization and the date organized.
Idao, June 30, 1989
3. If at any time during the year the propert 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 Appiicabie
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 Utiiity service
Eiectric StateIdao
Oregon
5. Have you engaged as the principal accountant to audit your financial statements an accountant who is not
the principal accountant for your previous year's certified financial statements?
(1) 0 Yes...Enter the date when such independent accountant was initially engaged:
(2) IX No
FERC FORM No.1 (ED. 12-S7)PAGE 101
End of 2008/Q4
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Name of Respondent
Idaho Power Company
This Report Is:
(1) IX An Original
(2) 0 A Resubmission
Date of Report
(Mo,Da, Yr)
04/1512009
Year/Period of Report
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 corpration 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.I
Idaho Power Company is a subsidiary of IDACORP, INC I
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IDACORP owns 100% of Idaho Power Company's Common Stock.
IDACORP is a public utility Holding Company incorporated effective 10-1-1998
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FERC FORM NO.1 (ED. 12-96)Page 102 I
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Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/Q4
(2) DA Resubmission 04/15/2009
CORPORATIONS CONTROLLED BY RESPONDENT
1. Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent
at any time during the year. If control ceased prior to end of year, give particulars (details) in a footnote.
2. If control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, naming
any intermediaries involved.
3. If control was held jointly with one or more other interests, state the fact in a footnote and name the other interests.
Definitions
1. See the Uniform System of Accounts for a definition of control.
2. Direct control is that which is exercised without interposition of an intermediary.
3. Indirect control is that which is exercised by the interposition of an intermediary which exercises direct control.
4. Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where the
voting control is equally divided between two holders, or each party holds a veto power over the other. Joint control may exist by
mutual agreement or understanding between two or more parties who together have control within the meaning of the definition of
control in the Uniform System of Accounts, regardless of the relative voting rights of each party.
Line Name of Company Controlled Kind of Business Percent Voting FootnoteNo.Stock Owned Ref.(a)(b)(c)(d)
1 Direct Control
2 Idaho Energy Resources Company Coal mining and mineral 100%
3 development
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JERe FORM NO.1 (ED. 12-96)Page 103
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/Q4
(2) FiA Resubmission 04/15/2009
OFFICERS
1. Report below the name, title and salary for each executive offcer whose salary is $50,000 or more. An "executive offcet' 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 Tille Name of Offcer :-al,ry
No.for Year
(a)(b)(c)
1
2 President and Chief Executive Offcer J. LaMont Keen 600,000
3
4 Sr Vice President, Administrative Services & CFO Darrel T. Anderson 340,000
5
6 Sr Vice President, Power Supply James C. Miller 300,000
7
8 Sr Vice President, General Counsel and Secretary Thomas Saldin 300,000
9
10 Sr Vice President, Delivery Dan Minor 290,000
11
12 Vice President, Regulatory Affairs Ric Gale 230,000
13
14 Vice President and Chief Information Offcer Dennis Gribble 198,000
15
16 Vice President, Human Resources Luci McDonald 205,000
17
18 Vice President, Public Affairs (1)Greg Panter 170,833
19
20 Vice President and Treasurer Steven R. Keen 215,000
21
22 Vice President and Chief Risk Offcer Lori Smith 194,000
23
24 Vice President, Engineering and Operations Lisa Grow 180,000
25
26 Vice President Public Affairs (2)Jeffrey Malmen 30,000
27
28 Vice President, Customer Service and Regional Ops Warren Kline 177,500
29
30 Vice President, Audit and Compliance Naomi Crafton-Shankel 154,000
31
32 Corporate Secretary Patrick Harrington 155,000
33
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35 (1) Retired 9/30/2008
36 (2) Appointed Vice President Public Affairs 10/1/08
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FERC FORM NO.1 (ED. 12-96)Page 104 I
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Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/04
(2) FiA Resubmission 04/15/2009
.DIRECTORS
1. Report below the information called for concerning each director of the respondent who held office at any time during the year. Include in coumn (a), abbreviated
titles of the directors who are offcers of the respondent.
2. Designate members of the Executive Committee by a triple asterisk and the Chairman of the Executive Committee by a double asterisk,
Line-Name (anÇl Titie) of Director Principal Business AddressNo. .(a)(b)
1
2 Judith A Johansen 2786 Glenmorrie Dr. Lake Oswego, Oregon 97034
3
4 Christine King Standard Microsystems Corporation
5 80 Arkay Dr, Hauppauge, NY 11788
6
7 Gary Michael ***P,O. Box 1718, Boise, Idaho 83701
8
9 Jon H, Miler ***P.O. Box 1557, Boise, Idaho 83701
10
11 Peter S, O'Neil ***100 N. 9th St., Suite 200, Boise, Idaho 83702
12
13 Jan B, Packwood 900 W. Bogus View Drive, Eagle, Idaho 83616
14
15 J. LaMont Keen, President and Chief Executive Offcer**Idaho Power Company, 1221 W. Idaho Street,
16 P.O. Box 70, Boise, Idaho 83707-0070
17
18 Richard G. Reiten Pacwest Center, 1211 SW Fifh Ave., Suite 1600
19 Portland, Oregon 97204
20
21 Joan Smith 2309 S.w. First Avenue, No. 1141, Portland, Oregon 97201
22
23 Robert A. Tinstman ***4433 W. Ouail Point Court, Boise, Idaho 83703
24
25 Thomas Wilford Alscott Inc, P.O. Box 70001, Boise, Idaho 83701
26
27 Richard Dahl 11659 Presila Road, Santa Rosa Valley Ca, 93012
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I FERC FORM NO.1 (ED. 12-95)Page 105
Name of Respondent
Idaho Power Company
Date of Report Year/Period of Report
End of 2008/Q4
This Report Is:
(1) ~ An Original
(2) 0 A Resubmission
IMPORTANT CHANGES DURING THE QUARTERl EAR
04/15/2009
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 propert, and of the transactions relating thereto,
and reference to Commission authorization, if any was required. Give date journal entries called for by the Uniform System of Accounts
were submitted to the Commission.
4. Important leaseholds (other than leaseholds for natural gas lands) that have been acquired or given, assigned or surrendered: Give
effective dates, lengths of terms, names of parties, rents, and other condition. State name of Commission authorizing lease and give
reference to such authorization.
5. Important extension or reduction of transmission or distribution system: State territory added or relinquished and date operations
began or ceased and give reference to Commission authorization, if any was required. State also the approximate number of
customers added or lost and approximate annual revenues of each class of service. Each natural gas company must also state major
new continuing sources of gas made available to it from purchases, development, purchase contract or otherwise, giving location and
approximate total gas volumes available, period of contracts, and other parties to any such arrangements, etc.
6. Obligations incurred as a result of issuance of securities or assumption of liabilities or guarantees including issuance of short-term
debt and commercial paper having a maturity of one year or less. Give reference to FERC or State Commission authorization, as
appropriate, and the amount of obligation or guarantee.
7. Changes in articles of incorporation or amendments to charter: Explain the nature and purpose of such changes or amendments.
8. State the estimated annual effect and nature of any important wage scale changes during the year.
9. State briefly the status of any materially importnt legal proceedings pending at the end of the year, and the results of any such
proceedings culminated during the year.
10. Describe briefly any materially important transactions of the respondent not disclosed elsewhere in this report in which an officer,
director, security holder reported on Page 106, voting trustee, associated company or known associate of any of these persons was a
party or in which any such person had a material interest.
11. (Reserved.)
12. If the important changes during the year relating to the respondent company appearing in the annual report to stockholders are
applicable in every respect and furnish the data required by Instructions 1 to 11 above, such notes may be included on this page.
13. Describe fully any changes in offcers, directors, major security holders and voting powers of the respondent that may have
occurred during the reporting period.
14. In the event that the respondent participates in a cash management program(s) and its proprietary capital ratio is less than 30
percent please describe the significant events or transactions causing the proprietary capital ratio to be less than 30 percent, and the
extent to which the respondent has amounts loaned or money advanced to its parent, subsidiary, or affiliated companies through a
cash management program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio.
PAGE 1 08 INTENTIONALLY LEFT BLANK
SEE PAGE 109 FOR REQUIRED INFORMATION.
FERC FORM NO.1 (ED. 12-96)Page 108
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I Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2009 2008/Q4
IMPORTANT CHANGES DURING THE QUARTERIEAR (Continued)I
I i.There was a retirement of $60,000
way,that was fully amortized.
2.None
I 3.None
of the old Shoshone Bannock distribution right of
I 4. None
5. Additions to Existing Lines:
Tap added to transmission line 213 to Adroam 69Kv 5.6 miles added.
I Upgrade transmission lines from 69kv to 138 kv:
Line 473 138Kv 11.73 miles, replaces line 203 69Kv
Line 470 138Kv 24.19 miles, replaces line 236 69Kv
I Distribution Stations:
Poleline Substation
Hillsdale Substation
I 6. On July 10, 2008, IPC issued $120 million of its 6.025% First Mortgage Bonds Secured
Medium~Term Notes, Series H due July 15, 2018. Commission Authorization OPUC 08-105 IPUC
#3048.
I On April 3, 2008 entered into a Selling Agency Agreement (see page 123.9) Commission
Authorization OPUC 07-151 IPUC #30294.
I 7. None
II 8. On December 31, 2008 a general wage increase of 3%.
9. See Pages 123.17 to 123.22
I 10. None
11. NoneI
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12. None
13. Refer to pages 104 & 105 for changes in officers and directors. There were a number of
changes in Major Security holders in 2008. The top ten institutional shareholders list saw
two changes from 3rd quarter to 4th quarter. In the 4th quarter Deutche Investment
Management Americas and Integrity Asset Management LLC, replaced Lord Abbett & Co LLC and
Dimensional Fund Advisors, Inc.I 14. Idaho Pwer 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.I
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IFERC FORM NO.1 (ED. 12-96) Page 109,1
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This Report Is: Date of Report Year/Period of Report
(1) ix An Original (Mo, Da, Yr)
(2) 0 A Resubmission 04/15/2009 End of 2008/04
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Name of Respondent
Idaho Power Company I
Prior Year
End Balance
12/31
(d)
ILine
No.Title of Account
(a)
UTILITY PLANT
Ref.
Page No,
(b)
Current Year
End of OuarterNear
Balance
(c)I
4,036,452,062
207,662,162
4,244,114,224
1,505,119,564
2,738,994,660
o
o
o
o
o
o
o
2,738,994,660
o
o
3,799,704,789
257,589,900
4,057,294,689
1,468,831,767
2,588,462,922
o
°
°
°
o
o
o
2,588,462,922
o
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786,896
----~-~~
888,877
°
o
55,937,107 I
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Utilty Plant (101-106, 114)
Construction Work in Progress (107)
TOTAL Utility Plant (Enter Total of lines 2 and 3)
(Less) Accum. Provo for Depr. Amort, Depl. (108, 110, 111, 115)
Net 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) Accum. Prov, for Amort. of Nucl. Fuel Assemblies (120.5)
Net Nuclear Fuel (Enter Total oflines 7-11 less 12)
Net Utility Plant (Enter Total of lines 6 and 13)
Utilty Plant Adjustments (116)
Gas Stored Underground - Noncurrent (117)
OTHER PROPERTY AND INVESTMENTS
Nonutiity 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.Allowaoces
Other Investments (124)
Sinking Funds (125)
Depreciation Fund (126)
Amortization Fund - Federal (127)
Other Special Funds (128)
Special Funds (Non Major Only) (129)
Long-Term Portion of Derivative Assets (175)
Long-Term Portion of Derivative Assets - Hedges (176)
TOTAL Other Property and Investments (Lines 18-21 and 23-31)
CURRENT AND ACCRUED ASSETS
Cash and Working Funds (Non-major Only) (130)
Cash (131)
Special Deposits (132-134)
Working Fund (135)
Temporary Cash Investments (136)
Notes Receivable (141)
Customer Accounts Receivable (142)
Other Accounts Receivable (143)
(Less) Accum. Provo for Uncollectible Acct.-Credit (144)
Notes Receivable from Associated Companies (145)
Accounts Receivable from Assoc. Companies (146)
Fuel Stock (151)
Fuel Stock Expenses Undistributed (152)
Residuals (Elec) and Extracted Products (153)
Plant Materials and Operating Supplies (154)
Merchandise (155)
Other Materials and Supplies (156)
Nuclear Materials Held for Sale (157)
Allowances (158.1 and 158.2)
200-201
200-201
200-201
202-203
202-203
122
224-225
228-229
227
227
227
227
227
227
202-203/227
228-229
o
60,058,187-~~-~~-
I
-~~-- ------~-~~-
o
948,473
o
o
o
19,129,856
o
o
o
80,923,412
o
2,819,926
675,912
41,350
280,000
1,549,041
64,433,173
6,557,937
1,723,936
26,579,771
-2,011
16,851,868
o
o
44,405,727
o
o
o
o
o
4,846
o
o
o
28,071,728
o
33,160
o
84,935,718
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o
2,908,319
44,840,534
35,850
2,403,000
5,975,468
62,122,209
7,080,171
1,305,058
21,527,626
o
17,267,629
o
o
41,370,751
o
o
o
o
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IFERC FORM NO.1 (REV. 12-03)Page 110
I Name of Respondent
I
Idaho Power Company
This Report Is: Date of Report
(1) (Z An Onginal (Mo, Da, Yr)
(2) 0 A Resubmission 04/15/2009 End of
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBIT~ontinued)
2008/04
YearlPeriod of Report
Line
I No.
53
I 54
55
56
57
I 58
59
60
I 61
62
63
64
I 65
66
67
I 68
69
70
I 71
72
73
74
I 75
76
77
I 78
79
80
81I82
83
84
I 85
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I FERC FORM NO.1 (REV. 12-03)
Title of Account
(a)
(Less) Noncurrent Portion of Allowances
Stores Expense Undistributed (163)
Gas Stored Underground - Current (164.1)
Liquefied Natural Gas Stored and Held for Processing (164.2-164.3)
Prepayments (165)
Advances for Gas (166-167)
Interest and Dividends Receivable (171)
Rents Receivable (172)
Accrued Utilty Revenues (173)
Miscellaneous Current and Accrued Assets (174)
Derivative Instrument Assets (175)
(Less) Long-Term Portion of Derivative Instrument Assets (175)
Derivative Instrument Assets - Hedges (176)
(Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176
Total Current and Accrued Assets (Lines 34 through 66)
DEFERRED DEBITS
Unamortized Debt Expenses (181)
Extraordinary Propert Losses (182.1)
Unrecovered Plant and Regulatory Study Costs (182.2)
Other Regulatory Assets (182,3)
Prelim. Survey and Investigation Charges (Electric) (183)
Preliminary Natural Gas Survey and Investigation Charges 183.1)
Other Preliminary Survey and Investigation Charges (183,2)
Clearing Accounts (184)
Temporary Facilties (185)
Miscellaneous Deferred Debits (186)
Def. Losses from Disposition of Utilty PIt. (187)
Research, Devel. and Demonstration Expend. (188)
Unamortized Loss on Reaquired Debt (189)
Accumulated Deferred Income Taxes (190)
Unrecovered Purchased Gas Costs (191)
Total Deferred Debits (lines 69 through 83)
TOTAL ASSETS (lines 14-16, 32, 67, and 84)
Ref.
Page No.
(b)
Current Year
End of OuarterlYear
Balance
(c)
Prior Year
End Balance
12/31
(d)
o
5,715,442
o
o
9,865,355
o
o
o
43,933,916
o
652,080
o
o
o
222,635,551
o
1,898,952
o
o
9,119,846
o
611
o
36,314,34
o
586,202
33,160
o
o
252,113,294
227
---~----- -~
14,263,910 13,390,497
230 0 0
230 0 0
232 697,644,724 448,227,917
7,232,442 454,153
0 0
0 0
486,154 480,898
0 0
233 63,059,804 73,222,183
0 0
352-353 0 36,000
12,841,023 13,548,821
234 167,646,855 106,047,150
0 0
963,174,912 655,407,619
4,005,728,535 3,580,919,553
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 04/15/2009 end of 2008/04
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
Line Current Year Prior Year
No.Ref.End of OuarterNear End Balance
Title of Accunt 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)252 618,757,435 581,757,435
7 Other Paid-I n 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)118-119 424,451,953 388,826,291
12 Unappropriated Undistributed Subsidiary Earnings (216.1)118-119 57,595,094 53,474,014
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)-8,706,615 -6,156,499
16 Total Proprietary Capital (lines 2 through 15)1,187,877,972 1,113,681,346
17 LONG-TERM DEBT
18 Bonds (221)256-257 1,401,560,000 1,115,460,000
19 (Less) Reaquired Bonds (222)256-257 166,100,000 0
20 Advances from Associated Companies (223)256-257 0 0
21 Other Long-Term Debt (224)256-257 29,457,727 30,521,364
22 Unamortized Premium on Long-Term Debt (225)0 0
23 (Less) Unamortized Discount on Long-Term Debt-Debit (226)3,163,279 3,409,345
24 Total Long-Term Debt (lines 18 through 23)1,261,754,448 1,142,572,019
25 OTHER NONCURRENT LIABILITIES
26 Obligations Under Capital Leases - Noncurrent (227)0 0
27 Accumulated Provision for Propert Insurance (228.1)0 0
28 Accumulated Provision for Injuries and Damages (228.2)1,965,108 660,554
29 Accumulated Provision for Pensions and Benefits (228.3)253,645,884 81,470,279
30 Accumulated Miscellaneous Operating Provisions (228.4)916,667 916,667
31 Accumulated Provision for Rate Refunds (229)13,344,853 2,397,165
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)12,414,695 14,514,992
35 Total Other Noncurrent Liabilities (lines 26 through 34)282,287,207 99,959,657
36 CURRENT AND ACCRUED LIABILITIES
37 Notes Payable (231)112,850,000 136,585,000
38 Accounts Payable (232)94,937,929 81,922,232
39 Notes Payable to Associated Companies (233)0 0
40 Accounts Payable to Associated Companies (234)765,831 724,321
41 Customer Deposits (235)311,092 1,159,231
42 Taxes Accrued (236)262-263 -42,412,650 2,845,258
43 Interest Accrued (237)16,674,614 18,761,346
44 Dividends Declared (238)0 0
45 Matured Long-Term Debt (239)0 0
FERC FORM NO.1 (rev. 12-03)Page 112
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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 04/15/2009 end of 2008/Q4
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDIl(eatinued)
Line Current Year Prior Year
No.Ref,End of QuarterlYear End Balance
Title of Account Page No.Balance 12/31
(a)(b)(c)(d)
46 Matured Interest (240)0 °
47 Tax Collections Payable (241)1,329,837 2,534,420
48 Miscellaneous Current and Accrued Liabilties (242)37,600,238 59,832,828
49 Obligations Under Capital Leases-Current (243)°0
50 Derivative Instrument Liabilities (244)2,652,850 171,234
51 (Less) Long-Term Portion of Derivative Instrument Liabilities 0 0
52 Derivative Instrument Liabilities - Hedges (245)0 0
53 (Less) Long-Term Portion of Derivative Instrument Liabilties-Hedges 0 0
54 Total Current and Accrued Liabilties (lines 37 through 53)224,709,741 304,535,870
55 DEFERRED CREDITS
56 Customer Advances for Construction (252)30,033,657 33,261,676
57 Accumulated Deferred Investment Tax Credits (255)266-267 73,270,077 71,000,710
58 Deferred Gains from Disposition of Utility Plant (256)0 0
59 Other Deferred Credits (253)269 29,939,135 20,838,443
60 Other Regulatory Liabilities (254)278 203,648,107 203,756,794
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 Property (282)580,306,037 535,627,552
64 Accum. Deferred Income Taxes-Other (283)131,902,154 55,685,486
65 Total Deferred Credits (lines 56 through 64)1,049,099,167 920,170,661
66 TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65)4,005,728,535 3,580,919,553
FERC FORM NO.1 (rev. 12-03)Page 113
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Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) An Original (Mo. Da, Yr)End of 2008/Q4
(2) Fi A Resubmission 04/15/2009
STATEMENT OF INCOME
Quarterly
1. Enter in column (d) the balance for the reporting quarter and in column (e) the balance for the same three month period for the prior year.
2. Report in column (f) the quarter to date amounts for electrc utility function; in column (h) the quarter to date amounts for gas utilty, and in u) the
quarter to date amounts for other utiity 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 utility function for the prior year quarter.
4. If additional columns are needed place them in a footnote.
Annual or Quarterly if applicable
5. Do not report fourt 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 utilty departent. 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 accnts 412 and 413 above.
8. Report data for lines 8, 10 and 11 for Natural Gas companies using accunts 404.1, 404.2, 404.3, 407.1 and 407.2.
Line Total Total Currnt 3 Months Prior 3 Months
No.Currnt Year to Prior Year to Ended Ended
(Ref.)Date Balance for Date Balance for Quarterl Only Quarterly Only
Title of Account Page No.QuarterIYear QuarterlY ear No 4th Quarter No 4th Quarter
(a)(b)(c)(d)(e)(D
1 UTILITY OPERATING INCOME
2 Operating Revenues (400)300-301 956,075,564 875,401,235
3 Operating Expenses
4 Operation Expenses (401)320-32 581,17,704 532,394,837
5 Maintenance Expenses (402)320-323 68,638,630 68,163,077
6 Depreciation Expense (403)336-337 96,637,583 94,999,200
7 Depreciation Expense for Asset Retirement Costs (403.1)336-337
8 Amort, & Depl. of Utility Plant (404-405)336-337 5,482,388 8,095,753
9 Amort. of Utility Plant Acq. Adj. (406)336.337 -22,723 -22,723
10 Amort, Properl Losses, Unrecov Plant and Regulatory Study Costs (407)
11 Amort, of Conversion Expenses (407)
12 Regulatory Debits (407,3)21,246
13 (Less) Regulatory Credit (407.4)3,781,013 -2,093,195
14 Taxes Other Than Income Taxes (408.1)262-263 19,083,954 17,633,417
15 Income Taxes - Federal (409.1)262-263 -1,816,783 2,627,990
16 - Other (409.1)262-263 -4,930,646 -6,572,551
17 Provision for Deferred Incme Taxes (410.1)234, 272-277 111,854,164 44,230,688
18 (Less) Provision for Deferred Income Taxes-Cr. (411.1)234, 272-277 71,534,676 9,243,213
19 InvestmentTax Credit Adj, - Net(411.4)266 2,269,367 1,887,569
20 (Less) Gains from Disp. of Utility Plant (411.6)11,632
21 Losses from Disp. of Utilit Plant (411.7)
22 (Less) Gains from Disposition of Allowances (411.8)504,115 2,754,122
23 Losses from Dispositon of Allowances (411.9)
24 Accretion Expense (411.10)
25 TOTAL Utiit Operating Expenses (Enter Total of lines 4 thru 24)802,542,202 753,554,363
26 Net Util Oper Inc (Enter Tot line 2 less 25) Carr to Pg117,line 27 153,533,362 121,846,872
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i:i:Rr. i:ORM NO. 1/3-0 IREV. 02-04\Paae 114
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2008/Q4
This ~ort Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2009
STATEMENT OF INCOME FOR THE YEAR (Continued)
9. Use page 122 for importnt 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 utilty 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 settement 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.
112. 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 accunting 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.
114. Explain in a footnote if the previous yeats/quarter's figures are different from that reported in prior report.
. 15. If the columns are insuffcient for reporting additional utility departments, supply the appropriate account titles report the information in a footnote to
this schedule.
I ELECTRIC UTILITY
Current Year to Date Previous Year to Date
(in dollars) (in dollars)~) ~)
GAS UTILITY
Current Year to Date Previous Year to Date
(in dollars) (in dollars)0) 0)
OTHER UTILITY
Currnt Year to Date Previous Year to Date
(in dollars) (in dollars)(k) (I)Line
No.
I
581,177,704
68,638,630
96,637,583
532,394,837
68,163,077
94,999,200
I 504,115 2,754,122
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
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I
5,482,388
-22,723
8,095,753
-22,723
I
3,781,013
19,083,954
-1,816,783
-4,930,646
111,854,164
71,534,676
2,269,367
11,632
21,246
-2,093,195
17,633,417
2,627,990
-6,572,551
44,230,688
9,243,213
1,887,569
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153,533,362
753,554,363
121,846,872
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FFRC FORM NO.1 lED. 12-96\Page 115
Name of Respondent
Idaho Power Company
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2009
STATEMENT OF INCOME FOR THE YEAR (continued)
TOTALLine
No.
Year/Period of Report
End of 2008/Q4 I
Previous Year
(d)
urrent 3 Months
Ended
Quarterly Only
No 4th Quarter
(e)
Prior Months
Ended
Quarterly Only
No 4th Quarter
(I)I
I
Title of Account
(a)
(Ref.)
Page No.
(b)
27 Net Utility Operating Income (Carred forward from page 114)
28 Other Income and Deductons
29 Other Income
30 Nonutilty Operating Income
31 Revenues From Merchandising, Jobbing and Contrct Work (415)
32 (Less) Costs and Exp. of Merchandising, Job. & Contrct Work (416)
33 Revenues From Nonutilty Operations (417)
34 (Less) Expenses of Nonutilit Operations (417.1)
35 Nonoperating Rental Income (418)
36 Equity in Eamings of Subsidiary Companies (418.1)
37 Interest and Dividend Income (419)
38 Allowance for Oter Funds Used During Constrcton (419,1)
39 Miscellaneous Nonoperating Income (421)
40 Gain on Disposition of Propert (421.1)
41 TOTAL Other Income (Enter Total of lines 31thru 40)
42 Other Income Deductons
43 Loss on Dispositin of Propert (421.2)
44 Miscllaneous Amortzation (425)
45 Donations (426,1)
46 Life Insurance (426,2)
47 Penalties (426.3)
48 Exp. for Certin Civic, Political & Related Actvities (426.4)
49 Other Deductions (426.5)
50 TOTAL Oter Income Deductons (Total of lines 43thru 49)
51 Taxes Applic. to Other Income and Deductons
52 Taxes Oter Than Income Taxes (408.2)
53 Income Taxes-Federal (409.2)
54 Income Taxes-Other (409.2)
55 Provision for Deferred Inc, Taxes (410.2)
56 (Less) Provision for Deferred Income TaxesCr. (411.2)
57 Investment Tax Credit Adj.-Net (411.5)
58 (Less) InvestmentTax Credit (420)
59 TOTAL Taxes on Other Income and Deductons (Total of lines 52-58)
60 Net Other Income and Deductions (Total of lines 41,50,59)
61 Interest Charges
62 Interest on Long-Term Debt (427)
63 Amort. of Debt Disc, and Expense (428)
64 Amortzation of Loss on Reaquired Debt (428,1)
65 (Less) Amort. of Premium on Debt-Credit (429)
66 (Less) Amortzation of Gain on Reaquired Debt-Creit (429.1)
67 Interest on Debt to Assoc. Companies (430)
68 Other Interest Expense (431)
69 (Less) Allowance for Borrwed Funds Used During Constrctn-Cr. (432)
70 Net Interet Charges (Total of lines 62thru 69)
71 Income Before Extraordinary Items (Total of lines 27, 60 and 70)
72 Extrordinary Items
73 Extrordinary Income (434)
74 (Less) Extrordinary Deductions (435)
75 Net Extraordinary Items (Total of line 73 less line 74)
76 Income Taxes-Federal and Oter (409.3)
77 Extrordinary Items After Taxes (line 75 less line 76)
78 Netlncome (Total of line 71 and 77)
119
Current Year
(c)
153,533,362
1,523,301
1,253,357
75,270
-1,567,569
-14,913
4,121,080
3,894,223
3,141,017
608,609
3,051,506
16,714,305
121,846,872 I
2,706,144
2,066,935
102,98
-515,189
-2,553
4,022,911
3,819,829
5,995,175
6,514,689
321,364
21,928,611
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" 10"" wi: v::i; x'" "/0 ,,'rfu'l A;;I
340
340 405,900
-381,000
426,409
1,273,313
4,817,233
6,541,855
478,611
-200,209
919,811
886,146
4,528,201
6,612,560
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262-263
262-263
262-263
234,272-277
234,272-277
31,465
3,078,590
615,804
1,203,011
4,822,172
106,698
10,065,752
I35,980
1,749,032
370,373
1,552,871
1,905,495 I
1,802,761
13,513,290
I~i ,
66,145,498 58,097,083
1,099,817 1,081,816
707,798 1,211,833
340
340 8,611,213 5,987,546
7,080,140 7,597,141
69,484,186 58,781,137
94,114,928 76,579,025
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262-263
94,114,928
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FERC FORM NO. 1/3.0 (REV. 02-04)Page 117
76,579,025 I
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This Page Intentionally Left Blank
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2008/04 IThis ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2009
STATEMENT OF RETAINED EARNINGS
1. Do not report Lines 49-53 on the quarterly version.
2. Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriated
undistributed subsidiary earnings for the year.
3. Each credit and debit during the year should be identified as to the retained earnings accunt in which recorded (Accunts 433, 436
- 439 inclusive). Show the contra primary accunt 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 dividel1ds for each class and series of capital stoc.
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.
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Line ItemNo. (a)
UNAPPROPRIATED RETAINED EARNINGS (Accunt 216)
1 Balance-Beginning of Period
2 Changes
3 Adjustments to Retained Earnings (Account 439)
4
5
6
7
8
9 TOTAL Credits to Retained Earnings (Acc. 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 Earnings (Acct. 436)
18
19
20
21
22 TOTAL Appropriations of Retained Earnings (Acc. 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. 438)
37 Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings
38 Balance - End of Period (Total 1,9, 15,16,22,29,36,37)
Contra Primary
ccunt Affcted
(b)
Current
OuarterlYear
Year to Date
Balance
(c)
Previous
OuarterlYear
Year to Date
Balance
(d)
I
- -~---I---~- --~~._------~r--~r---~I
I
I
15,135,588 I
I~--89,993,848
15,135,588
72,556,114 I
~----~I
I
I
--1-----I
FERC FORM NO.1/3.Q (REV. 02"(4)Page 118
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2008/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2009
STATEMENT OF RETAINED EARNINGS
11. 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 (Accunts 433, 436
- 439 inclusive). Show the contra primary account affected in column (b)
4. State the purpose and amount of each reservation or appropriation of retained earnings.
5. List first account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow
by credit, then debit items in that order.
6. Show dividends for each class and series of capital stock.
7. Show separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Earnings.
8. Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be
recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated.
9. If any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.
Item
(a)
APPROPRIATED RETAINED EARNINGS (Account 215)
39
40
41
42
43
44
45 TOTAL Appropriated Retained Earnings (Accunt 215)
APPROP. RETAINED EARNINGS - AMORT, Reserve, Federal (Account 215.1)
46 TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 215.1)
47 TOTAL Approp. Retained Earnings (Acct, 215, 215.1) (Total 45,46)
48 TOTAL Retained Earnings (Acc. 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 Equit in Earnings for Year (Credit) (Account 418.1)
51 (Less) Dividends Received (Debit)
52
53 Balance-End of Year (Total lines 49 thru 52)
Contra Primary
ccount Affected
(b)
Current
QuarterlYear
Year to Date
Balance
(c)
Previous
QuarterlYear
Year to Date
Balance
(d)--~----I------- - ---- ---- -----
----~-----~------
1,543,966
1,543,966
424,451,953
1,543,966
1,543,966
388,826,291¡-------------~----
53,474,014
4,121,080
49,451,103
4,022,911
57,595,094 53,474,014
FERC FORM NO. 1/3-Q (REV. 02-04)Page 119
Name of Respondent
Idaho Power Company
This ~ort Is:(1) ~An Original
(2) A Resubmission
STATEMENT OF CASH FLOWS
Date of Report
(Mo, Da, Yr)
04/15/2009
Year/Period of Report
End of 2008/Q4 I
I(1) Codes to be used:(a) Net Proceds 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 Cas
Equivalents at End of Period" with related amounts on the Balance Sheet
(3) Operating Activities ~ Other: Include gains and losses pertining to operating activities only. Gains and losses pertaining to investing and financing activities should be report
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 outfow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes to
the Financial Statements. 00 not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconcilation of the
dollar amount of leases capitalized with the plant cost
I
ILine
No,
Description (See Instruction NO.1 for Explanation of Codes)Current Year to Date
QuarterlYear
(b)
Previous Year to Date
QuarterlYear
(c)(a)
Net Cash Flow from Operating Activities:
Net Income (Line 78(c) on page 117)
Noncash Charges (Credits) to Income:
Depreciation and Depletion
Amortization of
I1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22 Net Cash Provided by (Used in) Operating Activities (Total 2 thru 21)
23
24
25
26
27
28
29
30
31
32
33
34 Cash Outflows for Plant (Total of lines 26 thru 33)
35
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I35,380,117
1,142,301
-12,548,004
-6,285,284
24,923,640
1,373,356
-1,930,182
-6,435,706
Deferred Income Taxes (Net)
Investment Tax Credit Adjustment (Net)
Net (Increase) Decrease in Receivables
Net (Increase) Decrease in Inventory
Net (Increase) Decrease in Allowances Inventory
Net Increase (Decrease) in Payables and Accrued Expenses
Net (Increase) Decrease in Other Regulatory Assets
Net Increase (Decrease) in Other Regulatory Liabilities
(Less) Allowance for Other Funds Used During Construction
(Less) Undistributed Earnings from Subsidiary Companies
Other (provide details in footnote):
I
-7,717,708
-105,234,939
-22,854,309
5,995,175
4,022,911
29,227,514
-28,488,583
-60,996,430
-3,071,792
3,141,017
4,121,080
112,~83
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121,386,224
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85,170,165
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-279,621,563
I
7,597,141 I19,845,542
-267,373,162 I
Cash Flows from Investment Activities:
Construction and Acquisition of Plant (including land):
Gross Additions to Utilty Plant (less nuclear fuel)
Gross Additions to Nuclear Fuel
Gross Additions to Common Utiity Plant
Gross Additions to Nonutiity Plant
(Less) Allowance for Other Funds Used During Construction
Other (provide details in footnote): Sale of Emission Allowances
-236,464,054
7,080,140
2,958,500
-240,585,694
- ---- - - -.- ~- i~---;-c~---- -- .
5,784,800 525,994 I
-12,373,146 I
-24,348,700 I
4,100,665 26,110,459 I
36 Acquisition of Other Noncurrent Assets (d)
37 Proceeds from Disposal of Noncurrent Assets (d)
38
39 Investments in and Advances to Assoc. and Subsidiary Companies
40 Contributions and Advances from Assoc, and Subsidiary Companies
41 Disposition of Investments in (and Advances to)
42 Associated and Subsidiary Companies
43
44 Purchase of Investment Securities (a)
45 Proceeds from Sales of Investment Securities (a)
FERC FORM NO.1 (ED. 12-96)Page 120
I Name of Respondent
Idaho Power Company
This ~ort Is:
(1) ~An Original
(2) A Resubmission
STATEMENT OF CASH FLOWS
Date of Report
(Mo, Da, Yr)
04/15/2009
Year/Period of Report
End of 2008/Q4
I (1) Codes to be used:(a) Net Proceds 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 actvities must be provided in the Notes to the Financial statements. Also provide a recncilation between "Cash and Cas
Equivalents at End of Period" with related amounts on the Balance Sheet.
(3) Operating Activities - Other: Include gains and losses pertining to operating activities only. Gains and losses pertining to investing and financing actvities should be report
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 outfow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes to
the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconciliation of the
dollar amount of leases capitalized with the plant cost
I
I Line
No.
Description (See Instruction NO.1 for Explanation of Codes)
(a)
Currnt Year to Date
QuarterlYear
(b)
Previous Year to Date
QuarterlYear
(c)
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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 Pay abies and Accrued Expenses
53 Other (provide details in footnote):
54 Tax deposit withdrawal
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): Capital Infusion
68
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
-7,449,788 -789,874
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I 43,926,946 -43,926,946
I
I
290,000,000 240,000,000
I
I 37,000,000
84,385,000
51,000,000
I 327,000,000 375,385,000
I -167,163,636 -81,063,636
I -2,150,077 -883,004
-32,687,145
I -54,368,186 -53,490,283
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FERC FORM NO.1 (ED. 12-96)Page 121
This Page Intentionally Left Blank
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Note 1 Amortization
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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 04115/2009 2008/04
FOOTNOTE DATA
Column:b . _. '.C-..¡
_".. _ _..______~--
Year Ended 12131/08
Plant
Regulatory assets
Unamortized debt expense
Unamortized discount
Water rights
5,459,665
3,706,837
(172,725)
246,065
3,169,282
12,409,124
~---_.~-- .... ._---- .-.. -----_.-cheduJe Page: 120.. Li'!f!_NfJ~;,!t!__.Column: b
Note 2 Cash Flow from Operating Activities (Other)----:.-______J
Year Ended 12131/08
Non-cash pension expense
Gain on sale of emission allowancs
Loss on liquidation of money market
Gain on sale of non-utility propert
Unbilled revenues
Impairment of security plan assets
Other noncash adjustments to net income
Other current liabilties
Other long-term assets
Other long-term liabilties
3,512,857
(504,115)
156,030
(3,112,406)
(7,619,571 )
6,829,456
1,000,000
(6,130,315)
1,491,800
4,488,647
112,383
IFERC FORM NO.1 (ED. 12-87) Page 450.1
This Report Is:
(1) 12 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 accrding 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 signifcant contingent assets or liabilities existing at end of year, including a brief explanation of
any action initiated by the Internal Revenue Service involving possible assessment of additional income taxes of material amount, or of
a claim for refund of income taxes of a material amount initiated by the utilit. Give also a brief explanation of any dividends in arrears
on cumulative preferred stock.
3. For Account 116, Utility Plant Adjustments, explain the origin of such amount, debits and credits during the year, and plan of
disposition contemplated, giving references to Cormmission orders or other authorizations respecting classification of amounts as plant
adjustments and requirements as to disposition thereof.
4. Where Accounts 189, Unamortized Loss on Reacquired Debt, and 257, Unamortized Gain on Reacquired Debt, are not used, give
an explanation, providing the rate treatment given these items. See General Instruction 17 of the Uniform System of Accounts.
5. Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such
restrictions.
6. If the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders are
applicable and furnish the data required by instructions above and on pages 114-121, such notes may be included herein.
7. For the 3Q disclosures, respondent must provide in the notes sufcient disclosures so as to make the interim information not
misleading. Disclosures which would substantially duplicate the disclosures contained in the most recent FERC Annual Report may be
omitted.
8. For the 3Q disclosures, the disclosures shall be provided where events subseuent 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 modifcations 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.
04/15/2009 IName of Respondent
Idaho Power Company
Date of Report Year/Period of Report
End of 2008/Q4
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PAGE 122 INTENTIONALLY LEFT BLANK
SEE PAGE 123 FOR REQUIRED INFORMATION.I
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FERC FORM NO.1 (ED. 12-96)Page 122 I
I Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2009 2008/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)I
I 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
I
Idaho Power Company (IPC) a wholly-owned subsidiar of IDACORP, Inc., (IDA CORP) is an electric utility with a service territory
covering approximately 24,000 square miles in sou1hern Idaho and eastern Oregon. IPC is regulated by the FERC and the state
regulatory commissions of Idaho and Oregon. IPC is the parent of Idaho Energy Resources Co. (IERCo), a joint ventuer in Bridger
Coal Company, which supplies coal to the Jim Bridger generating plant owned in par by IPC.
I Management Estimates
Management makes estimites and assumptions when preparing financial statements in conformity wi1h accounting principles generally
accepted in the United States of America. These estimates and assumptions include those related to rate regulation, retirement
benefits, contingencies, litigation, asset impairment, income taes, unbiled revenues and bad debt. These estimates and assumptìons
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 diffcult to predict and are beyond management's control. As a result,
actual results could differ from those estimates.
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System of Accounts
The accounting records of IPC conform to the Uniform System of Accounts prescribed by tæ FERC and adopted by the public utilty
commissions of Idaho, Oregon and Wyoming.
I
Regulation of Utilty Operations
IPC follows Statement of Financial Accounting Standards (SFAS) 71, Accountingfor the Effects of Certain Types of Regulation, and
its financial statements reflect the effects ofthe differentratemaking principles followed by the jurisdictions regulating IPC. The
application of SF AS 71 sometimes results in IPC recording expenses in a different period than when an unregulated enterprise would
record the expenses. In these circumstances, the expenses are deferred as regulatory assets on the balance sheet and recorded on the
income statement when recovered in rates. Additionally, regulators can impose regulatory liabilties upon a regulated company for
amounts previously collected from customers and for amouits that are expected to be refuded to customers. The effects of applying
SFAS 71 are discussed in more detail in Note 6.
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Cash and Cash Equivalents
Cash and cash equivalents include cash on hand and highly liquid temporar investments with maturity dates at date of acquisition of
three months or less.
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Derivative Financial Instruments
Financial instrents 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 instrments that are used to manage risk is in accordance with the
concepts established by SFAS 133, Accountingfor Derivative Instruments and Hedging Activities, as amended.
I
I
Property, Plant and Equipment and Depreciation
The cost of utility plant in service represents the original cost of contrcted services, direct labor and material, Allowance for Foods
Used During Construction (AFUDC) and indirect charges for engineering, supervision and similar overhead items. Repair and
maintenance costs associated with planned major maintenance are expensed as the costs are incurred, as are maintenance and repairs of
propert and replacements and renewals of items determined to be less tha units of propert. For utility propert 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 propert, plant and equipment.I
I
All utilty plant in service is depreciated using the stright-line method at rates approved by regulatory authorities. Annual
depreciation provisions as a percent of average depreciable utilty plant in service approximated 2.73 percent in 2008 and 2.95 percent
in 2007.
I
Long-lived assets are periodically reviewed for impairment wæn events or changes in circumstances indicate that the caring amount
of an asset may not be recoverable as prescribed under SFAS 144. SFAS 144 requires that if the sum of the undiscounted expected
IFERC FORM NO.1 (ED. 12-88) Page 123.1
I
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2009 2008104
NOTES TO FINANCIAL STATEMENTS (Continued)
future cash flows from an asset is less than the carring value of the asset, impairment must be recognzed in the financial statements.
There were no impairments of long-lived assets in 2008.
Allowance for Funds Used During Construction
AFUDC represents the cost of financing constrtion projects with borrwed funds an 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 propert through
increased revenues resulting from a higher rate base and higher depreciation expense. The component of AFUDC attibutable 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 AFUDC rates for 2008 and 2007 were 52 percent and 6.8 percent, respectively. IPC's reductions to
interest expense for AFUDC were $7 millon for 2008 and $8 milion for 2007. Other income included $3 milion and $6 milion of
AFUDC for 2008 and 2007, 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 electrc services delivered to customers but not yet biled at period-end. IPC collects
frchise fees and similar taxes related to energy conswnption. These amounts are recorded as liabilties 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 liabilties 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 liabilties is recognized in income in the period that includes the enactment date.
Consistent with orders and directives of the Idaho Public Utilties Commission (lPUC), 1he regulatory au1hority 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 bok lives on coal-fired generation facilities and properties
acquired after 1980. On other facilties, deferred income taxes ar 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 taes are not
provided for those income ta timing differences where the prescribed regulatory accounting methds do not provide for current
recovery in rates. Regulated enterprises are required to recognize such adjustments as regulatory assets or liabilties if it is probable
that such amounts wil be recovered from or returned to customers in futu rates.
The state of Idaho allows a three-percent investment tax credit on qualifying plant additions. Investment tax credits eared on
regulated assets are deferred and amortized to income over the estimated servce lives of the related properties. Credits earned on
non-regulated assets or investments are recognized in the year eared.
Income taxes are discussed in more detail in Note 2.
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 certain senior management employees and directors called the Senior
Management Security Plan (SMSP). The following table presents IPC's accumulated other comprehensive loss balance at December
31 (net of tax):
Unrealized holding gains on available-for-sale securties
SMSP
Total
2008 2007
(thousands of dollars)
$$568
(6,724)
(6,156)
(8,707)
(8,707)$$
IFERC FORM NO.1 (ED. 12..S) Page 123.2
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I Name of Respondent This Report is:Date of Report Year/PeriodofReport
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2009 20081Q4
NOTES TO FINANCIAL STATEMENTS (Continued)I
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Other Accounting Policies
Debt discount, expense and premium are deferred and being amortized over the tenns of the respective debt issues.
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New Accounting Pronouncements
SFAS 141(R): In December 2007, the Financial Accounting Stadards Board (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 statemems the identifiable assets acquired, the liabilities assumed, and any noncontrolling
interest in the acquiree; (2) recognizes and measures the goodwil acquired in the business combination or a gain from a bargain
purchase; and (3) detennines what infonnation 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 15,2008. An entity may not apply
it before that date. The adoption of SF AS 141 (R) did not have a material impact on the consolidated fmancial statements of IPC.I
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SF AS 160: In December 2007, the FASB issued SF AS 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. SF AS 160 is effective for fiscal
years beginning on or after December 15, 2008. An entity may not apply it before that date. The adoption of SF AS 160 did not have a
material impact on the consolidated financial statements ofIPC.I
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SFAS 161: In March 2008, the FASB issued SFAS 161, Disclosures about Derivative Instruments and Hedging Activities-an
amendment of FASB Statement No. 133. SF AS 161 encourages, but does not require, comparative disclosures for earlier periods at
initial adoption. SF AS 161 changes the disclosure requiremems for derivative instrments and hedging activities. Entities are required
to provide enhanced disclosures about (1) how and why an entity uses derivative instrents, (2) how derivative intrments and
related hedged items are accounted for under Statement 133 and its related interpretations, and (3) how derivative instnnents and
related hedged items affect an entity's financial position, fmancial perfonnance, and cash flows. SFAS 161 is effective for financial
statements issued for fiscal years and interim periods beginnng after November 15, 2008, with early application encouraged. The
adoption of SF AS 161 did not have a material impact on the consolidated financial statements of IPC.I
I SFAS 163: In May 2008, the FASB issued SFAS 163, Accountingfor Financial Guarantee Insurance Contracts-an interpretation
ofFASB Statement No. 60. SFAS 163 is generally effective for finacial statements issued for fiscal years begiming after December
15, 2008. SFAS 163 did not impact the consolidated fmancial statements of IPC.
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FSP EITF 03-6- 1: In June 2008, the F ASB issued FSP EITF 03-6-1, Determining Whether Instruments Granted in Share-Based
Payment Transactions Are Participating Securities. Under the guidance in FSP EITF 03-6- i, unvested share-based paymem awards
that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and shall
be included in the computation of earngs per share pursuant to the two-class method described in SF AS No. 128, Earnings per
Share. FSP EITF 03-6-1 is effective for financial statements issued for fiscal year beginning after December 15, 2008. All
prior-period earnings per share data presented must be adjusted retrospectively, an early application is not pennitted. The adoption of
EITF 03-6- i did not have a material impact on the consolidated financial statements of IPC.I
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FSP FAS 142-3: In April 2008, the FASB issued FASB Staff Position (FSP) FAS 142-3, Determination of the Useful Life of
Intangible Assets. FSP FAS 142-3 removes the requirement of SF AS 142, Goodwil and Other Intangible Assets, for an entity to
consider, when detennining the useful life of an acquired intangible asset, whether the intangible asset can be renewed without
substantial cost or material modifications to the existing tenns and conditions associated with the intangible asset. FSP F AS 142-3
replaces the previous useful-life assessment criteria with a requirement that an. entity consider its own experience in renewing similar
arangements. If the entity has no relevant experience, it would consider market paricipant assumptions regarding renewaL. FSP F AS
142-3 is effective for financial statements issued for fiscal year beginning after December 15,2008. The adoption ofFSP FAS 142-3
did not have a material impact on the consolidated financial statements of IPC.
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2. INCOME TAXES:
The components of the net deferred tax liabilty are as follows:
IFERC FORM NO.1 (ED. 12-88) Page 123,3
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2008 2007
(thousands of dollars)
Deferred tax assets:
Regulatory liabilties $44,341 $42,968
Advances for constrction 9,305 10,172
Deferred compensation 17,052 16,423
Emission allowances 6,921
Retirement benefits 85,034 20,753
Other 15,029 8,810
Total 170,761 106,047
Deferred tax liabilties:
Propert, plant and equipment 246,424 227,338
Regulatory assets 333,882 308,290
Conservation programs 1,901 3,169
PCA 62,820 45,008
Retirement benefits 69,334 6,945
Other 961 563
Total 715,322 591,313
Net deferred tax liabilties $544,561 $485,266
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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 04/15/2009 2008/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
A reconcilation between the statutory federal income tax rate and the effective tax rate is as follows:
2008 2007
(thousands of dollars)
Computed income taxes based on
statutory federal income tax rate $45,511 $38,947
Change in taxes resulting from:
Equity earnings of subsidiar
companies (1,442)(1,408)
AFUDC (3,577)(4,757)
Capitalized interest 1,729 2,289
Investment tax credits (3,490)(3,578)
Repair allowance (2,450)(2,450)
Removal costs (2,954)(3,787)
Pension accrual 1,022
Capitalized overhead costs (4,200)(4,200)
Tax accounting method change
Uncertain tax positions (13,475)(3,346)
Settlement of prior years' tax
returns 11,994
State income taxes, net of
federal benefit 4,601 6,618
Depreciation 5,562 7,576
Oter, net (1,892)1,771
Total income tax expense $35,917 $34,697
Effective ta rate 27.6%31.2%
2008 2007
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The items comprising income tax expense are as follows:
IFERC FORM NO.1 (ED. 12-88) Page 123.4
I Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)Idaho Power Company (2)A Resubmission 04/15/2009 2008104
NOTES TO FINANCIAL STATEMENTS (Continued)I
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Income taes currently payable:
Federal $14,024 $7,963
State (3,602)(6,202)
Total 10,422 1,761
Income taxes deferred:
Federal 33,906 28,412
State 2,794 6,223
Total 36,700 34,635
Uncertain ta positions:
Federal (12,763)(3,345)State (712)(241)
Total (13,475)(3,586)
Investment ta credits:
Deferred 5,760 5,465
Restored (3,490)(3,578)
Total 2,270 1,887
Total income tax expense $35,917 $34,697
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I IDACORP's tax allocation agreement provides that each member of its consolidated group compute its income taxes on a separate
company basis. Amounls payable or refundable are settled through IDACORP.
I FIN 48
IPC adopted F ASB Interpretation No. 48, Accountingfor Uncertainty in Income Taxes - an interpretation ofF ASB Statement No. 109
(FIN 48) on January I, 2007, as required. IPC recorded an increase of $ I 5.1 millon to 2007 opening retained earnings for the
cumulative effect of adopting FIN 48. A reconciliation of the begining and ending amount of unrecognized tax benefits is as follows
(in thousands of dollars):I
I Balance at Januar I,
Additions for tax positions of prior years
Reductions for tax positions of prior years
Settlements with taxing authorities
Balance at December 3 I,
$
2008
17,594
1,280
(10,426)
(4,329)
4,119
$
2007
21,180
848
(4,434)
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$$17,594
Ifrecognized, the $4.1 milion balance of unrecognized ta benefits would affect IPC's effective tax rates.
Since 2006, IPC has been disputing the Internal Revenue Service's (IRS) disallowance ofIPC's use of the simplified servce cost
method (SSCM) of uniform capitalization for tax year 200 i -2004. The dispute has been under review with the IRS Appeals Offce.
In December 2008, the Appeals Offce informed IDACORP that the SSCM settlement computations were complete. IDACORP
reviewed the fmal computations and agreed to the result. The settlement was submited to the U.S. Congress Joint Committee on
Taxation (JCT) for review in Januar 2009.I
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In November 2006, IDA CORP made a $44.9 milion refundable tax deposit with the IRS related to the disputed income tax assessment
for SSCM. In May 2008, IDACORP withdrew $20 milion from the deposit. Approximately $21 milion from the deposit was applied
to the settled income tax deficiency and interest charges with the remaining balance refunded to IDACORP.
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The IRS completed its examination of IDACORP's 2004 tax year D1 August 2008 and its 2005 tax year in October 2008. The 2004
examination report was submitted for JCT review as par of the SSCM settlement and the 2005 report was submitted in November
2008. IDACORP expects the JCT review process for 200 I -2005 to be completed in 2009. As of December 31, 2008, all uncertain tax
positions related to tax years 200 I -2005 were considered effectively settled.
The IRS began examining IPC's current method of uniform capitalization in December 2008. IDACORP expects that the examination
IFERC FORM NO.1 (ED. 12-88) Page 123.5 I
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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 04/15/2009 2008104
NOTES TO FINANCIAL STATEMENTS (Continued)
wil be completed during 2009. Resolution would result in a decrease to IPC's unrecognized tax benefits of$4.1 milion.
IPC recognizes interest accrued related to unrecognized tax benefits as interest expense and penalties as other expense. Durng the
years ended December 31, 2008 and 2007, IPC recognized a net reduction in interest expense of$O.l million and $1 milion,
respectively. IPC had accrued interest of $0.2 millon and $5.5 milion as of December 31,2008 and 2007, respectively. No penalties
are accrued.
IPC is subject to examination by their major tax jurisdictions - U.S. federal and state of Idaho. The open tax years for federal and
Idaho are 2006-2008 and 2005-2008, respectively. The IRS began its examination of 2006 in December 2008. IDACORP and IPC
are unable to predict the outcome of this examination.
3. COMMON STOCK AND STOCK-BASED COMPENSATION:
Dividend Restrictions: IPC's articles of incorporation contain restrctions on the payment of dividends on its common stock if
preferred stock dividends are in arrears. IPC has no outstading preferred stock. Also, certin provisions of credit facilities contain
restrictions on the ratio of debt to total capitalization.
IPC must obtain the approval of the Oregon Public Utilty Commission (OPUC) before it could directly or indirectly loan funds or
issue notes or give credit on its books to IDACORP.
IPC Common Stock
In 2008 and 2007, IDACORP contrbuted $37 milion and $51 milion respectively, of additional equity to 1PC. No additional shares
ofIPC common stock were issued.
Stock-Based Compensation
Through its parent company, IDACORP, IPC has three share-based compensation plans. IDACORP's employee plans are the 2000
Long- Tenn Incentive and Compensation Plan (L TICP) and the 1994 Restrcted Stock Plan (RSP). These plans are intended to align
employee and shareholder objectives related to IDACORP's long-tenn growth. IDACORP also has one non-employee plan, the
Director Stock Plan (DSP). The purpose of the DSP is to increase directors' stock ownership through stock-based compensation.
The L TICP for officers, key employees and directors pennits the grant of non qualified stock options, incentive stock options, stock
appreciation rights, restricted stock, restricted stock units, pedonnance inits, perfonnance shares and other awards. The RSP pennits
only the grant of restricted stock or pedonnance-based restrcted stock. At December 31, 2008, the maximum number of shares
available under the LTICP and RSP were 1,568,551 and 68,027, respectively.
The following table shows the compensation cost recognized in income and the tax benefits resulting from these plans, as well as the
amounts allocated to IPC for those costs associated with IPC's employees (in thusands of dollars):
IPC
Compensation cost
Income tax benefit
2008
$ 3,683
$ 1,440
2007
$ 2,473
$ 967
No equity compensation costs have been capitalized.
Stock awards: Restrcted stock awards have vesting periods of up to four years. Restrcted stock awards entitle the recipients to
dividends and voting rights, and unvested shares are restricted to disposition and subject to fodeiture under certain circumstances. The
fair value of restrcted 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 shars expected to vest.
Pedonnance-based restrcted stock awards have vesting periods of three years. Pedonnance awards entitle the recipients to voting
rights, and unvested shares are restrcted to disposition, subject to forfeiture under certain circumstances, and subjectto meeting
IFERC FORM NO.1 (ED. 12-88) Page 123.6
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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 04/15/2009 2008/04
NOTES TO FINANCIAL STATEMENTS (Continued)
I specific perfonnance conditions. Based on the attainment of the perfonnance 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. Begining with the 2006 awards, dividends are accumulated and wil be paid out only on shares that eventually vest.
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The perfonnance goals for the 2008 awards are independent of each other and equally weighted, an are based on two metrcs,
cumulative earings 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 futue dividend payments, using an
expected quarerly dividend of $0.30. The fair value of the TSR portion is estimated using a statistical model that incorporates the
probability of meeting perfonnance targets based on historical returns relative to the peer group. Both perfonnance 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.I
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A summar of restricted stock and perfonnance share activity is presented below. IPC share amounts represent the portion of
IDACORP amounts related to IPC employees:
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Nonvested shares at January 1, 2008
Shares granted
Shares forfeited
Shares vested
Nonvested shares at December 3 i, 2008
Number of
Shares
243,496
124,031
(40,024)
(24,246)
303,257 $I
I The total fair value of shares vested during the years ended December 31,2008 and 2007 was $0.8 milion and $0.9 milion,
respectively. At December 31, 2008, IPC had $2.7 milion of total unrecognized compensation cost related to nonvested share-based
compensation that was expected to vest. IPC's share of this amount was $2.5 milion. These costs are expected to be recognized over
a weighted-average period of 1.70 years. IPC uses IDACORP original issue and/or treasur shares for these awards.
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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 tenn of 10 years from the grnt date and vest over a five-year period. 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.
I
The fair values of all stock option awards have been estimated as of the date of the grt by applying a binomial option pricing modeL.
The application of this model involves assumptions that are judgmental and sensitive in the detennination of compensation expense.
No options were grnted in 2008 or 2007.
The following table presents infonnation about options granted and exercised (in thousands of dollars, except for weighted-average
amounts):I
I Weighted-average grant-date fair value
Fair value of options vested
Intrinsic value of options exercised
Cash received from exercises
Tax benefits realized from exercises
IPC
2008 2007
$$
353 579
182 II
707 40
71 4I
I As of December 31, 2008, there was less than $0. i milion of total unrecognized compensation cost related to stock options. These
IFERC FORM NO.1 (ED. 12-88) Page 123.7
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IPC's transactions in IDACORP are summarzed below:
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Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2S An Original (Mo, Da, Yr)
Idaho Power Company I (2) A Resubmission 04/15/2009 2008/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
costs are expected to be recognized over a weighted average penod of 0.6 years. IPC uses IDACORP onginal issue and/or treasury
shares to satisfY exercised options.
Weighted
Weighted-Average Aggregate
Number Average Remaining Intrinsic
of Exercise Contractual Value
Shares Price Term (OOOs)IPC
Outstanding at December 31, 2007 611,243 $33.75 4.71 $2,310
Exercised (30,700)23.04
Forfeited (3,547)30.14
Outstanding at December 3 i, 2008 576,996 $34.34 3.67 $611
Vested or expected to vest at December 3 i, 2008 575,420 $34.35 3.66 $611
Exercisable at December 31,2008 526,105 $34.75 3.46 $611
4. LONG-TERM DEBT
The following t~ble summarzes long-term debt at December 31 :
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2008 2007
(thousands of dollars)First mortgage bonds:$$
7.20%Series due 2009 80,000 80,000
6.60%Series due 2011 120,000 120,000
4.75%Series due 2012 100,000 100,000
4.25%Series due 2013 70,000 70,000
6.025% Senes due 2018 120,000
6%Series due 2032 100,000 100,000
5.50%Series due 2033 70,000 70,000
5.50%Series due 2034 50,000 50,000
5.875% Series due 2034 55,000 55,000
5.30%Series due 2035 60,000 60,000
6.30%Series due 2037 140,000 140,000
6.25%Series due 2037 100,000 100,000
Total first mortgage bonds 1,065,000 945,000
Pollution control revenue bonds:
Vanable Rate Senes 2003 due 2024(1)49,800 49,800
Vanable Rate Series 2006 due 2026(1)116,300 116,300
Varable Rate Series 2000 due 2027 4,360 4,360
Total pollution control revenue bonds 170,460 170,460
Amencan Falls bond guarantee 19,885 19,885
Milner Dam note guarntee 9,573 10,636
Unamortized discount - net (3,163)(3,409)Term Loan Credit Facilty 166,100
Purchase of pollution control revenue bonds (166,100)
Total long-term debt $1,261,755 $1,142,572
IFERC FORM NO.1 (ED. 12-88) Page 123.8
I Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2009 2008/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)I
I (\ )Humboldt County and Sweetwater County Pollution Control Revenue bonds are secured by first mortgage bonds, bringing the
total first mortgage bonds outstandi ng at December 3 i, 2008, to $ i .23 i bi Ilion.
I At December 31, 2008, the maturities for the aggregate amount of long-term debt outstanding were (in thousands of dollars):
I 2009 2010 2011 2012 2013 Thereafter
IPC $ 81,064 $ 1,064 $ 121,064 $ 101,064 $ 71,064 $ 886,435
I At December 3 1,2008 and 2007, the overall effective cost oflPC's outstanding debt was 5.59 percent and 5.72 percent, respectively.
I
Long-Term Financing
On April 3,2008, IPC entered into a Selling Agency Agreement with each ofBanc of America Securities LLC, BNY Capital Markets,
Inc., J.P. Morgan Securities Inc., KeyBanc Capital Markets Inc., Lazard Capital Markets LLC, Piper Jaffray & Co., RBC Capital
Markets Corporation, SunTrust Robinson Humphrey, Inc., Wachovia Capital Markets, LLC, Wedbush Morgan Securities Inc. and
Wells Fargo Securities, LLC in connection with the issuance and sale by IPC from time to time of up to $350 millon aggregate
principal amount of First Mortgage Bonds, Secured Medium-Term Notes, Series H. On July 10,2008, IPC issued $120 milion of its
6.025% First Mortgage Bonds, Secured Medium-Term Notes, Series H, due July 15, 2018. IPC used the net proceeds to pay down
short-term debt As of December 31, 2008, IPC has $230 milion remaining on a shelf registration statement that can be used for the
issuance of first mortage bonds and unsecured debt
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In January 2007, the IPC Board of Directors approved an increase of the maximum amountoffirst mortgage bonds issuable by IPC to
$1.5 bilion. The amount issuable is also restricted by propert, 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 aiiual 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
earings 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.
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I As of December 31, 2008, IPC could issue under the mortgage approximately $528 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. These
amounts are furher limited by the $1.5 bilion restriction discussed above. At December 31, 2008, unfunded propert additions were
approximately $880 milion.I
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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.
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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. Certain of the properties of IPC are subject to
easements, leases, contracts, covenants, workmen's compensation awards and similar encumbrances and minor defects and clouds
common to properties. The mortgage does not create a lien on revenues or profits, or notes or accounts receivable, contracts or choses
in action, except as permitted by law during a completed default, securities or cash, except when pledged, or merchandise or equipment
manufactured or acquired for resale. The mortgage creates a lien on the interest of IPC in propert subsequently acquired, other than
excepted propert, subject to limitations in the case of consolidation, merger or sale of all or substantially all of the assets of IPe.
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Pollution Control Revenue Refunding Bonds
On April 3,2008, IPC made a mandatory purchase of the $49.8 millon Hwnboldt County, Nevada Pollution Control Revenue
Refunding Bonds (Idaho Power Company Project) Series 2003 and the $ I 16.3 milion Sweetwater County, Wyoming Pollution
IFERC FORM NO.1 (ED. 12-88) Page 123,9
I
Name of Respondent This Report is:Date of Report YearlPeriod of Report
(1) 2Ç An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2009 2008/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
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Control Revenue Refunding Bonds (Idaho Power Company Project) Senes 2006 (together, the Pollution Control Bonds). IPC initiated
this trnsaction in order to adjust the interest rate penod of the pollution control bonds from an auction interest rate period to a weekly
interest rate period, effective April 3, 2008. The pollution control bonds remain outstanding and have not been retired or cancelled.
The maximum interest rate is 14 percent for the Sweetwater bonds and at specified rates capped at i 2 percent for the Humboldt bonds.
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The regularly scheduled principal and interest payments on the Senes 2006 bonds and principal and interest payments on the bonds
upon mandatory redemption on determination of taxabilty are insured by a financial guaranty insurace policy issued by Ambac
Assurance Corporation.
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Term Loan Credit Agreement
IPC entered into a $170 milion Term Loan Credit Agreement, dated as of April I, 2008, with JPMorgan Chase Bank, N .A., as
administrative agent and lender, and Bank of America, N.A., Union Bank of Cali fomi a, N.A. and Wachovia Bank NationalAssociation, as lenders. The Term Loan Credit Agreement provided for the issuance of term loans by the lenders to IPC on April I,
2008, in an aggregate principal amO\ß1t of $170 millon. The loans were due on March 31, 2009 and could be prepaid but not
reborrowed. IPC used $166.1 milion of the proceeds from the loans to effect the mandatory purchase on April 3, 2008, of the
Pollution Control Bonds (as discussed above under "Pollution Contrl Revenue Refunding Bonds") and $3.9 milion to pay interest,
fees and expenses incurred in connection with the Pollution Control Bonds and the Term Loan Credit Agrement.
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On February 4, 2009, IPC entered into a new $170 millon Term Loan Credit Agreement with JPMorgan Chase Bank, N.A., as
administrative agent and lender, Bank of America, NA., Union Ban, N.A. and Wachovia Bank, National Association, as lenders.
IPC used the proceeds to repay the above mentioned Term Loan Credit Agreement. The loans are due on February 3, 2010, but are
subject to earlier payment if IPC remarkets the pollution control revenue refuding bonds discussed below. The loans may be prepaid
but may not be reborrowed.
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The loans bear interest at either a floating rate or a Eurodollar rate. The floating rate is equal to (i) the highest of (a) the prie rate
announced by JPMorgan Chase Bank on such day, (b) the sum of (I) the federal fuds effective rate in effect on such day plus (2) 0.5
percent per anum and (c) an amount equal to (1) the LIBO Reference Rate on such day plus (2) i percent plus (ii) the applicable
margin. The Eurodollar rate is (i) the rate published on the Reuters BBA Libor Rates Page 3750 (or on any successor or substitute
page) for dollar deposits with a comparable maturty pius (ii) the applicable margi. The LIBO Reference Rate is the rate appearng on
the Reuters BBA Libor Rates Page 3750 (or on any successor or substitute page) as the rate for United States dollar deposits for a one
month interest period. The applicable margin is curently 2 percent for Eurodollar advances and i percent for floating rate advances,
but may be increased or decreased based upon the ratings assigned to IPC's senior unsecured debt by Moody's and S&P.
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The new Term Loan Credit Agreement is a short-term arngement however, $ i 66.1 millon was classified as long-term debt as
allowed by SFAS NO.6 Classifcation a/Short-Term Obligations Expected to Be Refinanced. IPC has the abilty to refinance the
loans on a long-term basis by utilizing its credit facilty, provided that the aggregate of the commitments utilizing the credit facilit and
commercial paper outstanding does not exceed $300 milion. The remaining $3.9 milion of the loans is classified as short-term debt.
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5. NOTES PAYABLE:IIPC has a $300 milion credit facilty that expires on April 25, 20 I 2. 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 withut third-part credit enhancement as provided by Moody's and S&P. At
December 31, 2008 no loans were outstanding on IPC's facility.I
IAt December 31, 2008, IPC had regulatory authonty 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 dollar):
IPC
2008 2007
(thousands of dollars)I
Balances:
At the end of year
IFERC FORM NO.1 (ED. 12-88)
$112,850 $136,585 I
Page 123,10
I
I Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~An Original (Mo, Da, Yr)
Idaho Power Company (2) A Resubmission 04/15/2009 2008/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)I
I Average during the year $151,192 $96,890
Weighted-average interest rate:
At the end of year 4.89%5.56%
I A verage during the year 3.97%5.54%
6. REGULATORY MATTERS:
I Regulatory Assets and Liabilties
The following is a breakdown oflPC's regulatory assets and liabilities (in thousands of dollars):
I Total Total
Remaining Not as of as of
Amortization Earning Earning December December
I Description Period a Return a Return 31,2008 31,2007
Regulatory Assets:
Income Taxes $-$335,644 $335,644 $309,902
I Benefit Plans(l)177,348 177,348 17,765
Deferred Pension Costs(l)10,583 10,583 2,797
Conservation 2010 3,942 4,864 8,806 8,107
I PCA Deferral 2009 140,821 140,821 92,323
FCA Deferral 2,721 2,721
Oregon Deferral(2)2,878 2,878 5,100
I Oregon PCAM Deferral(3)5,400 5,400
Asset Retirement 10,907 10,907 12,188
Obligations( 4)
I Grid West Loans 2013 65 922 987 1,108
Mark -to- Market Liabilties 3,074 3,074 171
Other 2010 77 160 237 379
Total(5)$155,904 $543,502 $699,406 $449,840
I Regulatory Liabilities:
Income Taxes $-$46,102 $46,102 $44,580
I Conservation 197 2 199 1,893
FCA Accrual (prior year)2009 1,105 1,105 2,145
Removal Costs(4)156,837 156,837 155,314
I Mark-to-Market Assets 652 652 586
Other 514 514 851
I Total(6)$197 $205,212 $205,409 $205,369
(I)See Note 8.
(2)Amortization capped at 10 percent of gross Oregon revenue per year.
I (3)Amortization capped at 6 percent of gross Oregon revenue per year beginning after the Oregon Deferral amortization is completed.
(4)See Note 12.
(5)Includes $3,074 and $172 for 2008 and 2007, respectively, reported in other current assets on the balance sheets.
(6)Includes $2,413 and $2,166 for 2008 and 2007, respectively, reported in other current liabilities on the balance sheets,
I In the event that recovery of costs through rates becomes unlikely or uncertain, SF AS 7 I would no longer apply. If IPC were to
discontinue application of SF AS 7 I for some or all of its operations, then these items may represent strnded 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.I
I FERC FORM NO.1 (ED. 12-88)Page 123,11
I
Name of Respondent This Report is:Date of Report Year/Perid of Report
(1) ~An Original (Mo, Da, Yr)
Idaho Power Company (2) A Resubmission 04115/2009 2008/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
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Idaho Rate Cases
2008 General Rate Case: On January 30, 2009, the IPUC issued an order approving an average annual increase in Idaho base rates,
effective Februar 1,2009, of 3. 1 percent (approximately $20.9 millon annually), a return on equity of 10.5 percent and an overall
rate of return of 8. 18 percent. On Februar 19,2009, IPC fied a request for reconsideration with the IPUC. In its fiing, IPC asked
the IPUC to reconsider four areas having a Idaho jurisdictional combined revenue requirement impact of approximately $8 milion
annually. Included in these areas is an item that relates to a $3.3 milion expense credit received in 2006 as a result of successful
litigation with the FERC and other federal agencies (FERC Credit). In the order, the IPUC directed IPC to refund the FERC Credit to
customers over a five year period, thereby reducing IPC's anual revenue requirement by approximately $0.7 milion during such
period. IPC believes that this was contr to Idaho law. IfIPC is unsuccessful in its challenge of the IPUC's ruling on FERC fees, it
wil recognize a loss for some or all of this amount.
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2007 General Rate Case: On June 8, 2007, IPC fied an application with the IPUC requesting an average rate increase of 10.35
percent ($63.9 milion anually). On February 28, 2008, the IPUC approved a settlement stipulation that included an average increase
in base rates of 5.2 percent (approximately $32. I milion annually), effective March 1, 2008. The settlement did not specify an overall
rate of return or a return on.equity.
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Danskin CTl Power Plant Rate Case: On March 7, 2008, IPC fied an application with the IPUC requesting recovery of
constrction costs associated with the gas-fired Danskin CTI plant located near Mountain Home, Idaho. Danskin cn began
commercial operations on March 1 1, 2008. IPC requested adding to rate base approximately $65 milion attbutable to the cost of
constrcting the generating facilty and the related trsmission and interconnection facilities, which would have resulted in a base
rate increase of 1.39 percent, or approximately $9 milion in annual revenues.
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On May 30, 2008, the IPUC authorized IPC to add to its rate bae $64.2 milion for the Danskin cn plant and related facilties,
effective June 1,2008, resulting in a base rate increase of i .37 percent, or $8.9 milion in annual revenues. Costs not approved in this
order wil be included in future filings.I
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Deferred Net Power Supply Costs
IPC's deferred net power supply costs consisted of th following at December 31 (in thousands of dollars):
2008 2007
Idaho PCA current year:
Deferrl for the 2008-2009 rate yearll)$$85,732
Deferral for the 2009-2010 rate year 93,657
Idaho PCA tre-up awaiting recovery:
Authorized May 2007 6,591
Authorized May 2008 47,164
Oregon deferral:
2001 costs 1,663 2,993
2006 costs 1,215 2,107
2008PCAM 5,400
Total deferral $149,099 $97,423
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(I) The 2008-2009 peA deferrl balance is reduced by $16.5 milion of emission allowance sales in 2007.
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IIdaho: IPC has a PCA mechanism that provides for annual adjustments to the rates charged to its Idaho retail customers. The PCA
trcks IPC's actual net power supply costs (fuel and purhased power less off-system sales) and compares these amounts to net power
supply costs currently being recovered in retail rates.
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The annual adjustments are based on two components:
· A forecast component, based on a forecast of net power supply costs in the coming year as compared to net power supply
costs in base rates; and
IFERC FORM NO.1 (ED. 12-88) Page 123.12
I
I 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 04/15/2009 2008/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)I
I · A tre-up component, based on the difference between the previous year's actual net power supply costs and the previous
year's forecast. This component also includes a balancing mechanism so that, over time, the actual collection or refund of
authorized tre-up dollars matches the amounts authorized. The tre-up component is calculated monthly, and interest is applied
to the balance.
Prior to Februar 1, 2009, the PCA mechanism provided that 90 percent of deviations in power supply costs were to be reflected in
IPC's rates for both the forecast and the tre-up components.I
I 2008-2009 PCA: On May 30, 2008, the IPUC approved IPC's 2008-2009 PCA and an increase to existing revenues of$73.3 milion,
effective June 1,2008, which resulted in an average rate increase to IPC's customers of 10.7 percent. The IPUC's order adopted an
IPUC Staff proposal to use a "normal" forecast for power supply costs. Th revenue increase is net of $16.5 milion of gains from the
2007 sale of excess S02 emission allowances, including interest, which the IPUC ordered be applied against the PCA.I
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2007-2008 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 millon above those
base rates. This $77.5 milion increase was net of $69.1 milion of proceeds from sales of excess SOi emission allowances. The new
rates became effective June 1,2007.
I Emission Allowances: During 2007, IPC sold 35,000 S02 emission allowances for a total of$I 9.6 milion. The sales proceeds
allocated to the Idaho jursdiction were approximately $18.5 milion. On April 14,2008, the IPUC ordered that $16.4 millon of these
proceeds, including interest, be used to help offset the PCA tre-up balances from the 2007-2008 PCA. The order also provided that
$0.5 milion may be used to fund an energy education progr.I
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In 2005 and early 2006, IPC sold 78,000 S02 emission allowances for a total of $8 1.6 millon. The sales proceeds allocated to the
Idaho jurisdiction were approximately $76.8 milion. On May 12,2006, the IPUC approved a stipulation that allowed IPC to retain
ten percent as a shareholder benefit with the remaining 90 percent plus a caring charge recorded as a customer benefit. This
customer benefit was used to partially offset the PCA true-up balance and was reflected in PCA rates in effect from June 1, 2007, to
May 31,2008.
Oregon: On April 30, 2007, IPC fied for an accounting order with the OPUC to defer net power supply costs for the period from
May 1, 2007, through April 30, 2008, in anticipation of higher than "normal" (higher than base) power supply expenses. In the filing,
IPC included a forecast of Oregon's jursdictional share of excess power supply costs of$5.7 milion. A hearing is set for April 16,
2009.I
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On April 28, 2006, IPC fied for an accounting order with the OPUC to defer net power supply costs for the period of May 1,200,
through April 30, 2007. A settlement agreement was reached wi1h the OPUC Staff and the Citizens' Utilty Board in the amount of $2
milion, which was approved by 1he OPUC on December 13,2007.
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The timing of future recovery of Oregon power supply cost deferrals is subject to an Oregon statute that specifically limits rate
amortizations of deferred costs to six percent of gross Oregon revenue per year. IPC is currently amortizing through rates power
supply costs associated with the western energy situation of 2000 and 2001, which is discussed furher under "Note 7 - LEGAL AND
ENVIRONMENTAL ISSUES - Western Energy Proceeding at the FERC." Full recovery ofthe 2001 deferrl is not expected until
2009. The 2006-2007 and the 2007-2008 deferrals would have to be amortized sequentially following 1he full recovery of the 2001
deferraL.
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Oregon Power Cost Recovery Mechanism: On August 17,2007, IPC fied an application with the OPUC requesting the approval of a
power cost recovery mechanism similar to the Idaho PCA. A joint stipulation was fied with the OPUC on March 14,2008, and the
OPUC approved the stipulation on April 28, 2008.
I The stipulation and OPUC order established a power cost recovery mechanism with two components: the annual power cost update
(APeU) and the power cost adjustment mechanism (PCAM). The combination of the APCU and the PCAM allows IPC to recover
excess net power supply costs in a more timely fashion than though the previously existing deferrl process.
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I FERC FORM NO.1 (ED. 12-88)Page 123.13
I
Name of Respondent This Report is:Date of Report Year/Perid of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2009 2008/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
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APCU: The APCU allows IPC to reestablish its Oregon base net power supply costs annually, separate from a general rate case, and
to forecast net power supply costs for the upcoming water year. The APCU has two components: the "October Update," where each
October IPC calculates its estimated nonnalized net power supply expenses for lle following April through March test period, and the
"March Forecast," where each March IPC fies a forecast of its expected net power supply expenses for the same test period, updated
for a number of variables including the most recent stram flow data and future wholesale electrc prices. On June I of each year, rates
are adjusted to reflect costs calculated in the APCU.
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On October 29, 2007, IPC fied the October Update portion of its 2008 APCU with the OPUC reflecting the estimated net power
supply expenses for the April 2008 through March 2009 test period. On March 24, 2008, IPC submitted testimony to the OPUC
revising its calculation of the October Update to confonn to the methodology agreed to by the paries in the stipulation. IPC also
submitted the March Forecast, reflecting expected hydroelectrc generating conditions and forward prices for the April 2008 through
March 2009 test period. The expected power supply costs of $ 150 milion represented an increase of approximately $23 millon over
the October Update.
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On May 20, 2008, the OPUC approved IPC's 2008 APCU (comprising both the October Update and the March Forecast) with the new
rates effective June 1,2008. The approved APCU resulted in a $4.8 milion, or 15.69 percent, increase in Oregon revenues.I
On October 23,2008, IPC filed the October Update portion of its 2009 APCU with the OPUC. The filing, combined with
supplemental testimony fied on December 1,2008, reflects that revenues associated with IPC's base net power supply costs would be
increased by $ 1.6 milion over the previous October Update, an average 4.55 percent increase. The October Update wil be combined
with the March Forecast portion of the 2009 APeU, with fmal rates expected to become effective on June 1,2009.
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PCAM: The PCAM is a tre-up to be fied annually in Februar. The filing calculates the deviation between actul net power supply
expenses incurred for the preceding calendar year and the net power supply expenses recovered through the APCU for the same
period. Under the PCAM, IPC is subject to a portion of the business risk or benefit associated with this deviation through application
of an asymmetrical deadband (or mnge of deviations) within which IPC absorbs cost increases or decreases. For deviations in actual
power supply costs outside of the deadband, the PCAM provides for 90/10 sharng of costs and benefits between customers and IPC.
However, a collection wil occur only to the extentthat it results in IPC's actual return on equity (ROE) for the year being no greater
than 100 basis points below IPC's last authorized ROE. A refund wil occur only to the extent that it results in IPC's actual ROE for
that year being no less than 100 basis points above IPC's last authorized ROE. The PCAM rate is then added to or subtracted from the
APCU rate, with new combined rates effective each Jme i.
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On October 6, 2008, the OPUC provided an order clarfying that the PCAM is a deferral under the Oregon statute. IPC expects that
deferrls under the PCAM component wil be subject to the six percent limitation on annual amortization discussed above. IPC had
$5.4 milion deferred under the PCAM as of December 3 1,2008.
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IFixed Cost Adjustment Mechanism (FCA)
On March 12,2007, the IPUC approved the implementation of a FCA mechanism pilot program for IPC's residential and small
general service customers. The FCA is a rate mechanism designed to remove IPC's disincentive to invest in energy effciency
programs by separating (or decoupling) the recovery of fixed costs from the vaiable kilowatt-hour charge and linking it instead to a set
amount per customer. In the FCA, for each customer class, the number of customers is multiplied by a fixed cost per customer. The
cost per customer is based on IPC's revenue requirement as established in a general rate case. This authorized fixed cost recovery
amount is compared to the amount of fixed costs actually recovered by IPC. The amount of over- or under-recovery is then returned to
or collected from customers in a subsequent rate adjustment. The pilot progra began on Januar 1,2007, and runs through 2009,
with the first rate adjustment occurrng on June I, 2008, and subsequent rate adjustments occuring on June I of each year during its
tenn.
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IOn March 14,2008, IPC filed an application requesting a $2.4 milion rate reduction under the FCA pilot progrm for the net
over-recovery of fixed costs duri 2007. On May 30, 2008, the IPUC approved the rate reduction of $2.4 milion to be distributed to
residential and small general service customer classes equally on an energy used basis durng the June I, 2008, through May 3 I, 2009,
FCA year. IPC deferred $2.5 milion of FCA net under-recovery of fixed costs during 2008.I
Idaho Energy Effciency Rider (Rider) Prudency Review
I FERC FORM NO.1 (ED. 12-88) Page 123.14
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I
I Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2009 2008/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)I
I IPC's Rider is the chief funding mechanism for IPC'ginvestmeTt in conservation, energy efficiency and demand response programs.
Effective June 1,2008, IPC collects 2.5 percent of base revenues, or approximately $17 millon annually, under the Rider. Prior to
that date, IPC collected 1.5 percent of base revenues, with funding caps for residential and irrigation customers.
I In the 2008 general rate case, IPC requested that the IPUC explicitly find that IPC's expenditures between 2002 and 2007 of $29
milion of funds obtained from the Rider were prudently incurred and would, therefore, no longer be subject to potential disallowance.
The IPUC Staff recommended that the IPUC defer a prudency determination for these expenditures untillPC was able to provide a
comprehensive evaluation package of its programs and efforts. IPC contended that suffcient information had already been provided to
the IPUC Staff for review.I
I On February 18,2009, IPC fied a stipulation with the IPUC reflecting an agreement with the IPUC Staff on $ 14.3 milion of the Rider
funds. The IPUC Staff agreed that this portion of the Rider expenditures were prudently incurred. IPC and the IPUC Staff agreed to
continue to exchange information and discuss settlement with regard to the remaining $ 1 4.7 milion, and IPC wil fie a pleading with
the IPUC by April I, 2009 seeking a prudency detennination on the remainder. If resolution with respect to the remaining $ 1 4.7
milion cannot be reached in the proceedings stemming from the April 1 fiing, IPC and the IPUC Staff wil recommend a procedure to
allow the IPUC to make such a detennination.I
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Open Access Transmission Tariff (OA TT)
On March 24, 2006, IPC submitted a revised OA IT 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 trnsmission rates to be updated each year based on
financial and operational data IPC files annually with the FERC in its Form 1. The formula rate request included a rate of return on
equity of 1 1.25 percent. IPC's fiing was opposed by several affected parties. Effective June 1,2006, the FERC accepted IPC's
proposed new rates, subject to refund pending the outcome of the hearing and settlement process.
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I On August 8,2007, the FERC approved a settlement agreement by the parties on all issues except the treatment of contracts for
transmission servce that contain their own terms, conditions and rates that were in existence before the implementation ofOATT in
1996 (Legacy Agreements). This settlement reduced IPC's proposed new rates and, as a result, approximately $1.7 milion collected
in excess of the settlement rates between JlDe 1, 2006, and July 3 i, 2007, was refunded with interest in August 2007. As par of the
settlement agrement, the FERC established an authorized rate of return on equity of 10.7 percent.I
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On August 31,2007, the FERC Presiding Administrative Law Judge (AU) issued an initial decision (Initial Decision) with respect to
the treatment of the Legacy Agreements, which would have further reduced the new transmission rates. IPC, as well as the opposing
parties, appealed the Initial Decision to the FERe. If implemented, the Initial Decision would have required IPC to make additional
refunds, including interest, of approximately $5.4 millon (including $0.4 millon of interest) for the June 1, 2006, through December
31, 2008, period. I PC previously reserved this entire amount.
I On January 15,2009, the FERC issued an Order on Initial Decision (FERC Order), which upheld the Initial Decision of the AU in
most respects, but modified the Initial Decision in one respect that is unfavorable to IPe. The decision requires IPC to reduce its
transmission servce rates to FERC jurisdictional customers. Furhermore, IPC is required to make refunds to FERC jurisdictional
transmission customers in the total amount of$13.3 milion (including $1.1 milion in interest) for the period since the new rates went
into effect in June 2006. Based on the FERC Order IPC has reserved an additional $7.9 millon (including $0.7 millon in interest) in
the fourth quarter of2008, bringing the total reserve amount to $13.3 milion. Prior to the FERC Order, the FERC jurisdictional
transmission revenues (net of the $5 millon reserve) recorded in the last seven months of2006, all of 2007 and 2008 were $8.1
millon, $13.3 millon and $15.8 milion, respectively. Under the FERC Order, the transmission revenues would have been $6.4
milion in the last seven month of 2006, $1 i milion in 2007 and $12.6 milion in 2008. Refunds were made on February 25, 2009.
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IPC fied a request for rehearing with the FERC on February 17,2009. IPC believes that the treatment ofthe Legacy Agreements
conflcts with precedent. The rehearing request asserts that the FERC order is in error by: (1) requiring IPC to include the contrct
demands associated with the Legacy Agreements in the OA IT formula rate divisor rather than crediting the revenue from the Legacy
Agreements against IPC's transmission revenue requirement; (2) concluding that IPC must include the contract demands associated
with the Legacy Agreements ratherthan the customers' coincident peak demands; (3) concluding that the transmission rate contained
in one or more of the Legacy Agreements was not a discounted rate; (4) failing to consider the non-monetar benefits received by IPC
from the Legacy Agreements; (5) concluding that the services provided under the Legacy Agreements are finn services and thereforeI
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I FERC FORM NO.1 (ED. 12-88)Page 123.15
Name of Respondent Th is Report is:Date of Report Year/Period of Report
(1) ~ An Onginal (Mo, Da, Yr)Idaho Power Company (2)A Resubmission 04/15/2009 2008/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
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should be handled for rate purposes in the same maer as firm services mder the OA TT; and (6) failing to affinn the rate treatment
that has been used for the Legacy Agreements for approximately 30 years.I
Pension Expense
In the 2003 Idaho general rate case, the IPUC disallowed recovery of pension expense because there were no current cash
contributions being made to the pension plan. On March 20,2007, IPC requested that the IPUC clarify that IPC can consider future
cash contributions made to the pension plan a recoverable cost of service. On June 1,2007, the IPUC issued an order authorizing IPC
to account for its defined benefit pension expense on a cash basis, and to defer and account for pension expense under SF AS 87,
Employers' Accountingfor Pensions, as a regulatory asset. The IPUC acknowledged that it is appropriate for IPC to seek recovery in
its revenue requirement of reasonable and pruently incurrd pension expense based on actual cash contrbutions. The regulatory asset
created by this order is expected to be amortized to expense to match the revenues received when future pension contrbutions are
recovered through rates. The deferrl of pension expense did not begin until $4. i milion of past contrbutions stil recorded on the
balance sheet at December 3 1,2006, were expensed. For 2007, approximately $2.8 milion was deferred to a regulatory asset
beginning in the third quarer. In 2008, $7.9 milion of pension expense was deferred. IPC did not request a carring charge on the
deferral balance.
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7. COMMITMENTS AND CONTINGENCIES:I
IPurchase Obligations:
As of December 3 i, 2008, IPC had signed agreements to purchase energy from 92 CSPP facilties with contrcts raging from one to
30 years. Seventy-nine of these facilties, with a combined nameplate capacity of267 megawatts (MW), were on-line at the end of
2008; the other 13 facilities under contract, with a combined nameplate capacity of 190 MW, are projected to come on-line during
2009 and 2010. The majority of the new facilities wiD be wind resources which wil generate on an intermittent basis. Durng 2008,
IPC purchased 756,014 megawatt-hours (MWh) from these projects at a cost of $45.9 milion, resulting in a blended price of6.1 cents
per kilowatt hour. IPC purchased 777, 147 megawatt-hour at a cost of $45 miDion in 2007.
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At December 3 I, 2008, IPC had the following long-term commitments relating to purchases of energy, capacity, trnsmission rights
and fuel:
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2009 2010 2011 2012 2013 Thereafter
(thousands of dollars)Cogeneration and small
power production $73,684 $76,150 $95,579 $97,234 $94,888 $1,334,434
Power and transmission
rights 84,040 19,013 15,035 2,655 2,655 10,455
Fuel 65,808 27,179 26,891 6,895 9,664 90,320
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In addition, IPC has the following long-tenn commitments for lease guarantees, equipment, maintenance and services, and industr
related fees.I
ì
2009 2010 2011 2012 2013 Thereafter
(thousands of dollars)
Operating leases $3,081 $2,754 $2,327 $1,799 $1,795 $22,654
Equipment, maintenance,
and service agreements 82,075 23,284 21,820 1,783 1,724 6,896
FERC and other industr
related fees 3,922 3,922 3,922 3,922 3,922 19,612
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Guarantees
IPC has agreed to guarantee the perfonnance of reclamation activities at Bridger Coal Company of which Idaho Energy Resources Co.,
IFERC FORM NO.1 (ED. 12-88) Page 123.16
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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 04/15/2009 2008/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)I
I a subsidiary of IPC, owns a one-third interest. This guarantee, which is renewed each December, was $60 millon at December 3 I,
2008. Bridger Coal Company has a reclamation trst 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.I Legal Proceedings
Western Energy Proceedings at the FERC: Throughout this report, the term "western energy situation" is used to refer to the
California energy crisis that occurred during 2000 and 2001, and the energy shortages, high prices and blackouts in the western United
States. High prices for electricity in California and in western wholesale markets during 2000 and 2001 caused numerous purchasers
of electricity in those markets to initiate proceedings seeking refunds. Some of these proceedings (the western energy proceedings)
remain pending before the FERC or on appeal to the United States Cour of Appeals for the Ninth Circuit (Ninth Circuit).
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There are pending in the Ninth Circuit approximately 200 petitions for review of numerous FERC orders regarding the western energy
situation, including the California refund proceeding, show cause orders with respect to contentions of market manipulation, and the
Pacific Northwest proceedings. Decisions in these appeals may have implications with respect to other pending cases, including those
to which IDACORP, IPC or IE are parties. IDA CORP, IPC and IE intend to vigorously defend their positions in these proceedings,
but are unable to predict the outcome of these matters, except as otherwise stated below, or estimate the impact they may have on their
consolidated financial positions, results of operations or cash flows.
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California Refud: This proceeding originated with an effort by agencies of the State of California and investor owned utilties in
California to obtain refuds for a portion of the spot market sales from sellers of electricity into California markets from October 2,
2000, through June 20, 200 I. In April 200 I, the FERC issued an order stating that it was establishing a price mitigation plan for sales
in the California wholesale electricity market. The FERC's order also included the potential for directing electrcity sellers into
California from October 2, 2000, through June 20, 2001, to refud portions of their spot market sales prices if the FERC determined
that those prices were not just and reasonable. In July 200 I, the FERC initiated the California refund proceeding including evidentiary
hearings to determine the scope and methdology for determining refunds. After evidentiary hearings, the FERC issued an order on
refund liabilty on March 26, 2003, and later denied the numerous requests for rehearing. The FERC also required the California
Independent System Operator (Cal ISO) to make a compliance filing calculating refund amounts. That compliance filing ha been
delayed on a number of occasions and has not yet been fied with the FERC.
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IE and other paries petitioned the Ninth Circuit forreview of the FERC's orders on California refunds. As additional.FERC orders
have been issued, further petitions for review have been filed by potential refund payors, including IE, potential refund recipients and
governmental agencies. These cases have been consolidated before the Ninth Circuit. Since the initiation ofthese cases, the Ninth
Circuit has convened a series of case management proceedings to organize these complex cases, while identifying and severing discrete
cases that can proceed to briefing and decision and staying action on all of the other consolidated cases.
In its October 2005 decision in the first of the severed cases, the Ninth Circuit concluded that the FERC lacked refund authorit over
wholesale electrical energy sales made by governmental entities and non-public utilties. In its August 2006 decision in the second
severed case, the Ninth Circuit ruled that all trnsactions that occurred within the California Power Exchange (CalPX) and the Cal ISO
markets were proper subjects of the refund proceeding, refused to expand the proceedings into the bilateral market, approved the
refund effective date as October 2, 2000, and required the FERC to consider claims that some market participants had violated
governing tariff obligations at an earlier date than the refund effective date and expanded the scope of the refund proceeding to include
trnsactions within the CalPX and Cal ISO markets outside the limited 24-hour spot market and energy exchange transactions. These
latter aspects of the decision exposed sellers to increased claims for potential refunds.
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In 2005, the FERC established a framework for sellers wanting to demonstrate that the generally applicable FERC refund methodology
interfered with the recovery of costs. IE and IPC made such a cost filing but it was rejected by the FERC in March 2006. IE and IPC
requested rehearing of that rejection and 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 rehearng, but its effect is confined to the minority of market paricipants that opted not to join
the settlement described below. Accordingly, IE and IPC believe this matter wil not have a material adverse effect on their
consolidated financial positions, results of operations or cash flows.
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On February 17,2006, IE and IPC jointly fied with the California Paries (Pacific Gas & Electrc Company, San Diego Gas & Electrc
IFERC FORM NO.1 (ED. 12-SS) Page 123.17
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 04/15/2009 2008/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
I
Company, Southern California Edison Company, the California Public Utilities Commission, the Californa Electricity Oversight
Board, the California Departent of Water Resources and the California Attorney General) an Offer of Settlement at the FERC settling
matters encompassed by the California refund proceeding, as well as other FERC proceedings and investigations relating to the
western energy matters, including IE's and IPC's cost filing and refund obligation. A number of other paries, representing a small
minority of potential refund claims, chose to opt out of the settlement. Under the terms of the settlement, IE and IPC assigned $24.25
milion of the rights to accounts receivable from the Cal ISO and CalPX to the California Paries to pay into an escrow account for
refunds to settling parties. Amounts from that escrow not used for settling paries and $ 1.5 milion of the remaining IE and IPC
receivables that are to be retained by the CalPX are available to fund, at least parially, payment of th claims of any non-settling
parties ifthey prevail in the remaining litigation of this matter. Any excess fuds remaining at the end of the case are to be returned to
IPC and IE. Approximately $ I 0.25 milion of the remaining IE and IPC receivables was paid to IE and IPC under the settlement. In
addition, the California Parties released IE and IPC from other claims stemming from the western energy market dysfuctions. The
FERC approved the Offer of Settlement on May 22, 2006.
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On October 24, 2006, the Port of Seattle petitioned 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 and severed the three
cases from the remainder ofthe consolidated cases. On December 2, 2008, the Ninth Circuit fied an order dismissing the Port of
Seattle petitions for review. That dismissal order is now finaL.
Market Manipulation: As part of the California refund proceeding discussed above and the Pacific Northwest refund proceeding
discussed below, the FERC issued an order permittng discovery and the submission of evidence regarding market manipulation by
sellers during the western energy situation. On June 25, 2003, the FERC ordered more than 50 entities that participated in the western
wholesale power markets between Januar I, 2000, and June 20, 200 I, including IPC, to show cause why certain trading practices did
not constitute gaming ("gaming") or other forms of proscribed market behavior in concert with another part ("parership") in
violation of the Cal ISO and CalPX Tariffs. In 2004, the FERC dismissed the ''partership'' show cause proceeding against IPC. The
order dismissing IPC from the "partnership" proceedings was not the subject of rehearing requests and is now finaL. Later in 2004, the
FERC approved a settlement of the "gaming" proceeding without finding of wrongdoing by IPC. The Port of Seattle was the only
par to appeal the FERC orders approving the "gaming" settlement. On December 8, 2008, the Ninth Circuit issued an order
dismissing that appeaL. The dismissal order is now finaL.
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The orders establishing the scope of the show cause proceedings ar presently the subject of review petitions in the Ninth Circuit. In
addition to the two show cause orders, on June 25, 2003, the FERC also issued an order instituting an investigation of anomalous
bidding behavior and practices in the western wholesale markets for the time period May I, 2000, through October I, 2000, to enable
it to review evidence of economic witlnolding of generation. IPC, along with more than 60 other market participants, responded to the
FERC data requests. The FERC terminated its investigations as to IPC on May 12,2004. Although California government agencies
and California investor-owned utilties have appealed the FERC's termination ofthis investigation as to IPC and more than 30 other
market paricipants, the claims regarding the conduct encompassed by these investigations were released by these paries in the
California refund settlement discussed above. IE and IPC are unable to predict the outcome of these matters, but believe that the
releases govern any potential claims that might arise and that this mattr wil not have a material adverse effect on their consolidated
fmancial positions, results of operations or cash flows.
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Pacific Northwest Refund: On July 25, 2001, the FERC issued an order establishing a proceeding separate from the California refund
proceeding to determine whether there may have been unjust and unreasonable charges for spot market sales in the Pacific Northwest
during the period December 25,2000, through June 20,2001, because the spot maret in the Pacific Northwest was affected by the
dysfunction in the California market. In late 200 I, a FERC Administrtive Law Judge concluded that the contrcts at issue were
governed by the substantially more stnct Mobile-Sierra standard of review rather thn the just and reasonable standard, that the Pacific
Northwest spot markets were competitive and that refunds should not be allowed. After the Judge's recommendation was issued, tæ
FERC reopened the proceeding to allow the submission of additional evidence directly to the FERC related to alleged manipulation of
the power market by market paricipants. In 2003, the FERC terminated the proceeding and declined to order refunds. Multiple parties
fied petitions for review in the Ninth Circuit and in 2007 the Ninth Circuit issued an opinion, 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
would have altered the agency's conclusions about refunds and directed the FERC to include sales to the California Deparment of
Water Resources proceeding. A number of paries have sought rehearing of the Ninth Circuit's decision. IE and IPC intend to
vigorously defend their positions in this proceeding, but are 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.
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IFERC FORM NO.1 (ED. 12-88) Page 123.18
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Name of Respondent This Report is:Date of Report Year/Perid of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2009 2008104
NOTES TO FINANCIAL STATEMENTS (Continued)
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In separate western energy proceedings, the Ninth Circuit issued two decisions on December 19, 2006, regarding the FERC's decision
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. On June 26, 2008, the U.S. Supreme Court issued a decision in one of these cases, Morgan Stanley Capital
Group Inc. v. Public Utility Distrct NO.1 of Snohomish County (No. 06-1457) (Snohomish), and revisited and clarfied the
Mobile-Sierra doctrine in the context of fixed-rate, forward power contrcts. At issue was whether, and under what circumstances, 1he
FERC could modify the rates in such contrcts on the grounds that there was a dysfuctional market at the time the contrcts were
executed. In its decision, the Supreme Court disagreed with many of1he conclusions reached by the Ninth Circuit and upheld the
application of the Mobile-Sierra doctrine even in cases in which it is alleged that the markets were dysfunctionaL. The Supreme Court
nonetheless directed the return of the case to the FERC to (i) consider whether the challenged rates in the case constituted an excessive
burden on consumers either at the time the contrcts were formed or during the term of the contracts relative to the rates that could
have been obtained after elimination of the dysfuctional maret and (ii) clarify whether it found the evidence inadequate to support a
claim that one of the paries to a contrct under consideration engaged in unlawful market manipulation that altered the playing field
for the particular contrct negotiations-that is, whethr there was a causal connection between allegedly unlawful activity and the
contract rate. On November 3, 2008, the Ninth Circuit vacated its earlier decision and remanded the case to the FERC for furher
proceedings consistent with the Supreme Court's decision. On December 18,2008, the FERC issued its order on remand, establishing
settlement proceedings and paper hearing procedures to supplement the record and permit it to respond to the questions specified by
the Supreme Cour.
I This decision is expected to have general implications for contracts in the wholesale electrc markets regulated by the FERC, and
particular implications for forward power contrcts in such markets. The Snohomish decision upholds the application of the
Mobile-Sierra doctrine to fixed-rate, forward power contrcts even in allegedly dysfuctional markets.
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IPC and IE have asserted the Mobile-Sierra doctrine in the Pacific Northwest proceeding, involving spot market contrcts in an
allegedly dysfunctional market. IDACORP, IPC and IE are unable to predict how the FERC wil rule on Snohomish on remand or how
this decision will affect the outcome of the Pacific Northwest proceeding.
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Western Shoshone National Council: On April 10,2006, the Western Shoshone National Council (which purports to be the
governing body of the Western Shoshone Nation) and certain of its individual tribal members fied a Firt Amended Complaint and
Demand for Jury Trial in the U.S. District Court for the District of Nevada, naming IPC and other unrelated entities as defendants.
Plaintiffs allege that IPC's ownership interest in certain land, minerals, water or other resources was convertd and fraudulently
conveyed from lands in which the plaintiffs had historical ownership rights and Indian title dating back to the 1860's or before.
On May 31,2007, the U.S. District Court granted the defendants' motion to dismiss stating that the plaintiffs' claims are barred by th
finality provision of the Indian Claims Commission Act. Plaintiffs fied a motion for reconsideration which the Distrct Court denied.
On Januar 25, 2008, the Distrct Court entered judgment in favor of IPC. Plaintiffs filed a Notice of Appeal to the Ninth Circuit. The
paries have fied briefs on appeaL. 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 mattr 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 Sierr Club and the Wyoming Outdoor Council fied a complaint against
PacifiCorp in federal district court in Cheyenne, Wyoming allegÙ1g violations of air quality opacity standards at the Jim Bridger coal
fired plant in Sweetwater County, Wyoming. Opacity is an indication of the amount of light obscured in the flue gas ofa power plant.
A formal answer to the complaint was fied by PacifiCorp on April 2, 2007, in which PacifiCorp denied almost all of 1he allegations
and asserted a number of affrmative defenses. IPC is not a part to this proceeding but has a one-third ownership interest Ù1 the Plant.
PacifiCorp owns a two-thirds interest and is the operator of the Plant. The complaint alleges thousands of opacity permit limit
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, and reimbursement ofthe plaintiffs costs
of litigation, including reasonable attorney fees.
Discovery in the matter was completed on October 15,2007. Also in October 2007, the plaintiffs and defendant fied cross-motions
for summar judgment on the alleged opacity compliance status of the Plant The court has not yet ruled on these motions. On July 7,I
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IFERC FORM NO.1 (ED. 12-88) Page 123.19
2008, the plaintiffs filed a motion requesting the cour to schedule a date for oral argument on the pending motions for summary
judgment. On July 17,2008, PacifiCorp fied an opposition to plaintiffs' motion based on the court's order on Initial Pretrial
Conference, which stated that "dispositive motions wil be decided on tli bnefs without oral argument." On November 19, 2008, the
plaintiffs fied a motion to refer the pending motions for summa judgment to magistrate judge for recommendation decision. On
December 2,2008, PacifiCorp fied an opposition to plaintiffs motion. The court has yet to rule on either motion fied by plaintifs.
IPC continues to monitor the status of this matter but is unable to predict the outcome of this matter or estimate the impact it may have
on its consolidated financial position, results of operations or cash flows.
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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 04/15/2009 2oo81Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
I
Sierra Club Lawsuit - Boardman: On September 30, 2008, Sierra Club and four other non-profit corporations fied a complaint
against Portland General Electric Company (pGE) in the U.S. District Court for the District of Oregon alleging opacity permit limit
violations at the Boardman coal-fired power plant located in Morrow County, Oregon. The complaint also alleges violations of the
Clean Air Act, related federal regulations and the Oregon State Implementation Plan relating to PGE's constrction and operation of
the plant. The complaint seeks a declartion that PGE has violated opacity limits, a permanent injunction ordering PGE to comply
with such limits, injunctive reliefrequinng PGE to remediate alleged environmental daage and ongoing impacts, civil penalties of up
to $32,500 per day per violation and the plaintiffs' cost of litigation, including reasonable attorney fees. IPC is not a par to this
proceeding but has a 10 percent ownership interest in the Boardman plant. PGE owns 65 percent and is the operator of the plant.
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IOn December 5, 2008, PGE filed a motion to dismiss nine of the twelve claims asserted by plaintiffs in their complaint, alleging
among other arguments that certin claims are bared by the statute of Iimilations or fail to state a claim upon which the court can grt
relief. Plaintiffs' response to the motion is due March 6, 2009, and PGE's reply is due Apnl3, 2009. IPC intends to monitor the status
ofthis mattr but is unable to predict its outcome or what effect this matter may have on its consolidated fmancial position, results of
operations or cash flows.I
Snake River Basin Adjudication: IPC is engaged in the Snake River Basin Adjudication (SRBA), a general strea adjudication,
commenced in 1987, to define the nature and extent of water nghts in the Snake River basin in Idaho, including the water rights of
IPC. The initiation of the SRBA resulted from the Swan Falls Agreement, an agrement entered into by IPC and the Governor and
Attorney General of Idaho in October 1984 to resolve litigation relating to IPC's water nghts at its Swan Falls project. IPC has fied
claims to its water nghts for hydropower and other uses in the SRBA. Oter water users in the basin have also fied claims to water
nghts. Parties to the SRBA may fie objections to water right claims tht adversely affect or injure their claimed water nghts and the
Idaho District Cour for the Fifth Judicial Distrct, which has jurisdiction over SRBA matters, then adjudicates the claims and
objections and enters a decree defining a par's water nghts. IPC has fied claims for all of its hydropower waternghts in the SRBA,
is actively protecting those water rights, and is objecting to claims that may potentially injure or affect those water rights. One such
claim involves a notice of claim of ownership fied on December 22, 2006, by the State of Idaho, for a portion of the water rights held
by IPC that are subject to the Swan Falls Agreement.
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On May 10, 2007, in order to protect its claims and the availabilty of water for power purpses at its facilties, and in response to the
claim of ownership fied by the State of Idaho, ~PC fied a complaint and petition for declartory and injunctive relief regarding the
status and nature of IPC's water nghts and the respective nghts and responsibilties of the paries under the Swan Falls Agrement.
The complaint was fied in the Idaho Distrct Cour for the Fift Judicial District, the court with jursdiction over the SRBA, against the
State ofIdaho, the Governor, the Attorney General, the Idaho Deparent of Water Resources (IDWR) and the Director of the IDWR.
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In conjunction with the fiing of the complaint and petition, ~PC filed motions with the court to stay all pending proceedings involving
the water rights ofIPC and to consolidate those proceedings into a single action where all issues relating to the Swan Falls Agreement
can be determined.I
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~PC alleged in the complaint, among other things, that contrry to the parties' belief at the time the Swan Falls Agrement was entered
into in 1984, the Snake River basin above Swan Falls was over-appropnated and as a consequence there was not in 1984, and there
currently is not, water available for new upstream uses over and above the minimum flows established by the Swan Falls Agrement;
that because of this mutual mistake of fact relating to the over-appropnation of the basin, the Swan Falls Agreement should be
reformed; that the state's December 22,2006, claim of ownership to IPC's water nghts should be denied; and that the Swan Falls
Agreement did not subordinate IPC's water rights to aquifer recharge.
Page 123.20
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On April 18, 2008, the court issued a Memorandum Decision and Order on Cross-Motions for Summar Judgmelt upholding the Swan
I FERC FORM NO.1 (ED. 12-88)
I Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2009 2008/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)I
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Falls Agreement. Under the Swan Falls Agreement, water rights in excess of the minimum flows established by ~ agreement are held
in trst by the State of Idaho for the use and benefit of IPC and the people of the State of Idaho. Water above these minimum flows is
available for subsequent consumptive beneficial uses that are approved in accordance with state law. The court further held that to the
extent that the state is not meeting the minimum flows or it is anticipated that the minimum flows wiD not be met, lPC's water rights
that are held in trust are not available for subsequent appropriations and that any appropriations already in place may be subject to
curtailment in order to meet the minimin flows. The court found that it was not necessary to address the issue of nntual mistake of
fact relating to the over-appropriation of the basin because it found that it was water rights that were the subject of the trust
arrangement and not the water itself. The court also stated that issues relating to water availabilit relate to the administration of water
rights and should be addressed, as necessar, in an administrative action before the IDWR.I
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The court did not decide the issue of whether the Swan Falls Agreement subordinated lPC's water rights to groundwater recharge. The
State of Idaho and IPC fied summary judgment motions on the recharge issue and completed briefing on the issue. The court held a
hearing on December 4, 2008 on the summary judgment motbns. After argument, the court took the matter under advisement. IPC is
unable to predict how the court wil rule on the issue of whether the Swan Falls Agreement subordinated IPC's water rights to
groundwater recharge. Based upon recent developments, however, resolution of that issue is not expected to have a significant effect
on the availability of water to IPC's hydropower facilities. IPC is cooperating with the State ofIdaho and other water users through an
advisory committee in the development ofthe CAMP to protect and enhance water levels in the Eastern Snake Plain Aquifer (ESPA)
and the connected Snake River. Many CAMP committee members had early expectations 1hat groundwater recharge would be a
significant component of the plan and while many believe that groundwater recharge is a very high-priority issue, further study and
review has revealed that significant groundwater recharge is not feasible due to the complex hydrogeology of the ESPA, the lack of
infrastructure, and the requirement of compliance with water quality and other environmental standards. IPC is currently engaged in a
3 to 5 year pilot study, in cooperation with IDWR and water users, to detennine the temporal and spatial impacts and/or benefits of
recharging, a maximin of 30,000 acre-feet of water downstream of American Falls Reservoir on the ESP A Aquifer and the Snake
River.
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IPC has also fied an action in federal court against the United States Bureau of Reclamation to enforce a contract right for delivery of
water to its hydropower projects on the Snake River. In 1923, IPC and the United States entered into a contract that facilitated the
development of the American Falls Reservoir by the United States on the Snake River in southeast Idaho. This 1923 contract entitles
IPC to 45,000 acrefeet of primary storage capacity in the reservoir and 255,000 acre-feet of secondary storage that was to be available
to IPC between October I of any year and June 10 of the following year as necessary to maintain specified flows at IPC's Twin Falls
power plant below Milner Dam. IPC believes that the United States has failed to deliver this secondary storage, at the specified flows,
since 2001. As a result, IPC fied an action in the U.S. District Cour of Federal Claims in Washington, D.C. on October 15,2007 to
recover damages from the United States for the lost generation resulting from the reduced flows. On September 30, 2008, IPC fied an
amended complaint in which IPC seeks, in addition to damages for breach of the 1923 contract, a prospective declaration of
contractual rights so as to prevent the United States from continued failure to fulfill its contractual and fiduciary duties to IPC. On
October 2,2008, the court set a discovery schedule requiring that discovery be completed and pre-trial motions filed by October 1,
2009. The court wil then set the matter for triaL. IPC is unable to predict the outcome of this action or what effect this matter may
have on its consolidated financial position, results of operations or cash flows.
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Renfro Dairy: On September 28,2007, the principals of Renfro Dairy in Canyon County, Idaho fied a lawsuit in the District Cour
of the Third Judicial District of the State of Idaho against IDACORP and IPC. The plaintiffs' complaint asserts claims for negtigence,
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 facilties that caused physical hann and injury to the plaintiffs' dairy herd. Plaintiffs
seek compensatory damages of not less Han $ i milion.
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On June 9, 2008, IDACORP and IPC fied a motion to dismiss the complaint, contending that the court lacks jurisdiction over the
matter because plaintiffs have failed to exhaust administrative remedies before the IPUC. The motion to dismiss was argued and
submitted on September 25,2008. On October 30, 2008, the court issued a decision grnting the motion to dismiss. On November 13,
2008, plaintiffs fied a motion to reconsider the court's decision. On December 22,2008, the court denied the plaintiffs motion to
reconsider. On February 20,2009, plaintiffs fied a notice of appeal of the court's dismissal of the action. 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.
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IFERC FORM NO.1 (ED. 12-88) Page 123,21
I
Name of Respondent This Report is:Date of Report Year/Perid of Report
(1) ~ An Original (Mo, Da, Yr)Idaho Power Company (2)A Resubmission 04/15/2009 2008/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
I
Oregon Trail Heights Fire: On August 25, 2008, a fire ignited beneath an IPC distribution line in Boise, Idaho. It was fanned by
high winds and spread rapidly, resulting in one death, the destrction of 10 homes and damage or alleged fire related losses to
approximately 30 others. Following the investigation, the Boise Fire Departent determined that the fire was linked to a piece of line
hardware on one ofIPC's distribution poles and that high winds contributed to the fire and its resultant damage.
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IIPC has received claims from a number of the homeowners and their insurers and is contiuing its investigation of these claims. IPC is
insured up to policy limits against liability for claims in excess of its self-insured retention. IPC has accrued a reserve for any loss that
is probable and reasonably estimable, including insurce deductibles, and believes this matter wil not have a material adverse effect
on its consolidated financial position, results of operations or cash flows.I
Other Legal Proceedings: From time to time IPC is par to legal claims, actions and complaints in addition to those discussed above.
Although they wil vigorously defend against them, they are unable to predict with certinty 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 financial position, results of operations or cash flows.
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8. BENEFIT PLANS:I
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SFAS 158
In December 2006, IDACORP and IPC adopted the recognition provisions of Statement of Financial Accounting Standards No. 158,
Employers' Accountingfor Defined Benefit Pension Plans and Other Postretirement Plans - an amendment ofFASB Statements No.
87,88, 106, and 132(R).
The measurement provisions of SF AS 158 were adopted as of January 1, 2008 and require that IPC measure its plan assets and benefit
obligations as of its balance sheet date. IPC already used a December 3 I measuremeIt date for its plans, so adoption of the
measurement provisions of SF AS 158 did not have any effect on IPC's results of operations or cash flows.I
Pension Plans
IPC has a noncontrbutory 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 Securty Act of i 974 (ERSA) but not more than the maximum amoui deductible for
income tax puroses. IPC was not required to contrbute to the plan in 2008 and 2007. The market-related value of assets for the plan
is equal to the fair value of the assets. Fair value is detennined by utilzing publicly quoted market values and independent pricing
services depending on the nature of the asset, as reported by the trtee/custodian of the plan.
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In addition, IPC has a nonqualified, deferrd compensation plan for certain senior management employees and directors called tæ
Senior Management Security Plan (SMSP). At December 31,2008 and 2007, approximately $39.9 millon and $48.2 milion,
respectively, of life insurance policies and investments in marketable securiies, all of which are held by a trstee, were designated to
satisfy the projected benefit obligation of the plan but do not qualify as plan assets in the actuarial computation of the funded status.
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IThe following table summarizes the changes in benefit obligations and plan assets of these plans:
Pension Plan SMSP
2008 2007 2008 2007
(thousands of dollars)
$420,526 $425,599 $43,153 $41,866
14,920 15,213 1,278 1,409
26,393 24,457 2,669 2,372
19,547 (29,585)3,376 (87)
(16,970)(15,158)(2,644)(2,700)
561 293
464,416 420,526 48,393 43,153
Page 123.22
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IChange in benefit obligation:
Benefit obligation at Januar 1
Service cost
Interest cost
Actuarial loss (gain)
Benefits paid
Plan amendments
Benefit obligation at December 3 1
Change in plan assets:
IFERC FORM NO.1 (ED. 12-88)
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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 04/15/2009 2008/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Fair value at January I
Actual return on plan assets
Benefits paid
Fair value at December 31
Funded status at end of year
Amounts recognized in the statement of
financial position consist of:
Other current liabilties
Noncurrent liabilities (1)
Net amount recognized
Amounts recognized in accumulated other
comprehensive income consist of:
Net loss
Prior service cost
Subtotal
Less amount recorded as regulatory asset
Net amount recognized in accumulatedother comprehensive income $ $ $ 14,297
Accumulated benefit obligation $ 385,002 $ 346,477 $ 44,275
(I) Noncurrent liabilities are contained in IPC's Balance Sheets under "Other liabilities" and ..Other deferred credits," respectively.
407,970
(95,676)
(16,970)
295,324
(169,092)
400,924
22,204
(15,158)
407,970
(12,556)$$$(48,393)
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$(2,883)
(45,510)
(48,393)
$$
(169,092)
(169,092)$
(12,556)
(12,556) $$
$155,289
3,155
158,444
(158,444)
$$5,954
3,805
9,759
(9,759)
12,088
2,209
14,297I
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I The following table shows the components of net periodic benefit cost for these plans:
Pension Plan SMSP
2008 2007 2008 2007
(thousands of dollars)
Service cost $14,920 $15,213 $1,278 $1,409
Interest cost 26,393 24,457 2,669 2,372
Expected return on assets (34,112)(33,387)Amortization of net loss 489 566
Amortization of prior service cost 650 650 192 173
Net periodic pension cost $7,851 $6,933 $4,628 $4,520
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$(43,153)
$(2,596)
(40,557)
$(43,153)
$9,200
1,841
11,041
$11,041
$39,851
In 2009, IPC expects to recognize as components of net periodic benefit cost $10 milion from amortizing amounts recorded in
accumulated other comprehensive income (or as a regulatoiy asset for the pension plan) as of December 3 I, 2008, relating to the
pension and SMSP plans. This amount consists of$8.5 milion of net loss and $0.6 milion of prior service cost for the pension plan
and $0.7 milion of net loss and $0.2 milion of prior service cost for the SMSP.
The following table summarizes the expected future benefit payments of these plans:
2009 2010 2011 2012
(thousands of dollars)
20,525 $ 22,464 $
3,165 $ 3,276 $
2013 2014-2017
Pension Plan
SMSP
$
$
17,616 $
2,963 $
18,968 $
3,122 $
24,655 $
3,473 $
157,832
19,863
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.I
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The net periodic postretirement benefit cost was as follows (in thousands of dollars):
IFERC FORM NO.1 (ED. 12-88) Page 123.23
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 04/15/2009 2008/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
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2008 2007
Service cost $1,154 $1,368
Interest cost 3,498 3,512
Expected retu on plan assets (2,899)(2,777)
Amortization of unrecognized transition obligation 2,040 2,040
Amortization of prior service cost (535)(535)
Amortization of net loss 403
Net periodic postretirement benefit cost $3,258 $4,011
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The following table summarzes the chanes in benefit obligation and plan assets (in thousands of dollars):
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I20082007
Change in accumulated benefit obligation:Benefit obligation at Januar 1 $
Service cost
Interest cost
Actuarial (gain) loss
Benefits paid( 1 )
Benefit obligation at December 31
Change in plan assets:
Fair value of plan assets at Januar I
Actual return on plan assets
Employer contributions
Benefits paid( 1 )
Fair value of plan assets at December 3 I
Funded status at end of year (included in noncurent liabilities)(2) $
(I) Benefits paid are net of$I,927 and $1,646 of plan participant contributions, and $421 and $405 of
Medicare Par D subsidy receipts for 2008 and 2007, respectively.
(2) Noncurrent liabilities are contained in "Other deferred credits" for IPC.
56,826
1,154
3,498
1,656
(3,486)
59,648
$62,913
1,368
3,512
(7,431)
(3,536)
56,826
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I35,096
(7,834)
1,507
(3,486)
25,283
(34,365)
32,627
3,129
2,876
(3,536)
35,096
(21,730)
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Amounts recognized in accumulated other comprehensive income consist of:
Net loss
Prior service cost (credit)
Trasition obligation
Subtotal
Less amount recognized in regulatory assets
Less amount included in deferred tax assets
Net amount recognized in accumulated other comprehensive income
$16,289 $3,900
(2,072)(2,607)
8,160 10,200
22,377 11,493
(18,904)(8,006)
(3,473)(3,487)
$$
In 2009, IPC expects to recognize as components of net periodic benefit cost $2.3 milion from amortizing amounts recorded in
accumulated other comprehensive income as of December 3 I, 2008 relating to the postretirement plan. This amount consists of ($0.5)
milion of prior service cost, $0.8 milion of net loss and $2.0 milion of trsition obligation.
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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 drg coverage.I
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The following table summarizes the expected futie benefit payments of the postretirement benefit plan and expected Medicare Par D
subsidy receipts (in thousands of dollars):
IFERC FORM NO.1 (ED. 12-88) Page 123,24
I Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2009 2008/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)I
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2009 2010 2011 2012 2013 2014-2018
Expected benefit $4,100 $4,300 $4,400 $4,500 $4,700 $24,800
payments(1 )
Expected Medicare Part D
subsidy receipts $500 $600 $600 $700 $800 $4,000
(1 )Expected benefit payments are net of expected Medicare Part 0 subsidy receipts.
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The assumed health care cost trend rate used to measure the expected cost of health benefits covered by the plan was 10 percent and
6.75 percent in 2008 and 2007, respectively. The assumed health care cost trend rate for 2008 is assumed to decrease gradually to 5
percent over ten years, and remain at that leveL. The assumed dental cost trend rate used to measure the expected cost of dental
benefits covered by the plan was 5 percent and 6.75 percent in 2008 and 2007, respectively. A I-percentage point change in the
assumed health care cost trend rate would have the following effect (in thousands of dollars):I
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I -Percentage-Point
Increase Decrease
Effect on total of cost components
Effect on accumulated postretirement benefit obligation
$
$
245
2,136
$
$
(187)
(1,700)
The following table sets forth the weighted-average assumptions used at the end of each year to detennine benefit obligations for all
IPC-sponsored pension and postretirement benefits plans:
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Discount rate
Rate of compensation increase
Medical trend rate
Dental trend rate
Measurement date
Pension
Benefits
2008 2007
6.1% 6.4%
4.5% 4.5%
Postretirement
Benefits
2008 2007
6.1% 6.4%
12/31/08 12/31/07
10.0%
5.0%
12/31/08
6.75%
6.75%
12/31/07
The following table sets forth the weighted-average assumptions used to detennÌle net penodic benefit cost for all IPC-sponsored
pension and postretirement benefit plans:
Discount rate
Expected long-tenn rate of return on assets
Rate of compensation increase
Medical trend rate
Dental trend rate
Pension
Benefits
2008 2007
6.4% 5.85%
8.5% 8.5%
4.5% 4.5%
Postretirement
Benefits
2008 2007
6.4% 5.85%
8.5% 8.5%
10.0%
5.0%
6.75%
6.75%
Plan Asset Allocations: IPC's pension plan and postretirement benefit plan weighted average asset allocations at December 31,2008
and 2007, by asset category are as follows:I
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Pension
Plan
Postretirement
Benefits
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 04/15/2009 2008/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
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IAsset Category
Equity securities 58%65%-%-%
Debt securities 28 22
Real estate 12 10
Other(1 )2 3 100 100
Total 100%100%100%100%
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(i) The postretirement benefit plan assets are primarily life insurance contracts.IPension 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
10%
11%
10%
5%
5%
3%
3%
International Growth Stocks
International Value Stocks
Intennediate- Tenn Bonds
Short- Tenn Bonds
Core Real Estate
Absolute Return
Private Equity
7%
7%
13%
10%
9%
4%
3%
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Assets are rebalanced as necessary to keep the portfolio close to target allocations.I
IThe plan's principal investment objective is to maximize total return (defined as the sum of realized interest and dividend income and
realized and unrealized gain or loss in market price) consistent with prudent parameters of risk and the liability profie 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:I
· Detennine if the investments have the potential to earn the rate of return assumed in the actuarial liability calculations.
· Match the cash flow needs of the plan. IPC sets cash allocations sufficient to cover the current year benefit payments and
bond allocations sufficient to cover at least five years of benefit payments. IPC then utilizes growth instrments (equities, real
estate, venture capital) to fund the longer-tenn liabilties of the plan.
· Maintain a prudent risk profie consistent with ERISA fiduciary standards.
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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.
Rate-of-return projections for plan assets are based on historical risk/return relationships among asset classes. The primary measure is
the historical risk premium each asset class has delivered versus the return on 10-year 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 offuture
investment perfonnance. Additional analysis is perfonned to measure the expected range of returns, as well as worst~ase and
best-case scenarios. Based on the curent low interest rate environment, current rate-of-return expectations are lower than the nominal
returns generated over the past 20 years when interest rates were generally much higher.I
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IPC's asset modeling process also utilizes historical market returs to measure the portfolio's exposure to a "worst-case" market
scenario, to detennine how much perfonnance could vary from the expected "average" perfonnance over various time periods. This
"worst-case" modeling, in addition to cash flow matching and diversification by asset class and investmeit style, provides the basis for
managing the risk associated with investing portfolio assets.
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 contribttions to the plan. Matching contributions amounted to $5 milion
and $5 milion in 2008 and 2007, respectively.
IFERC FORM NO.1 (ED. 12-88) Page 123,26
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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 04/15/2009 2008/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
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Postemployment Benefits
IPC provides certain benefits to fonner or inactive employees, their beneficiaries and covered dependents after employment but before
retirement. These benefits include salar continuation, health care and life insurce 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 amoiits included in other deferred credits on IPC' s consolidated balance sheets at December 3 i, 2008 and 2007
are $3.7 milion and $3.5 milion, respectively.
Pension Protection Act
In 2006, the Pension Protection Act of2006 (the Act), which affects the maner in which many companies, including IDACORP and
IPC, administer their pension plans was signed into law. The Act made changes to a varety 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 pennanently extended the pension law changes made by the Economic Growth and Tax
Relief Reconcilation Act of2001, which had been scheduled to sunset on December 31,2010. This legislation became effective on
January 1,2008.I
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In accordance with the Act, companies are required to be 94 percent funded for their outstanding qualifed pension obligations as of
Januar 1,2009, in order to avoid a scheduled series of required annual contrbutions. As of December 3 1,2007, qualified pension
liabilties were nearly fully funded; however, recent stock market perfonnance has reduced the value of pension assets during 2008.
Therefore, under curent provisions of the Act, IPC wil need to make additional contrbutions to become fully fided over a period of
seven years. Based on the value of pension assets and interest rates as of December 3 i, 2008, the estimated contrbutions would be
approximately $45 milion in 2010 and $33 milion for each of201 i, 2012, and 2013. These estimates reflect the initial relief
measures as passed by Congress; however, additional measures are being proposed, which may impact imrrdiate fuding
requirements.
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9. PROPERTY PLANT AND EQUIPMENT AND JOINTLY -OWNED PROJECTS:
The following table presents the major classifications of IPC's utility plant in service, annual depreciation provisions as a percent of
average depreciable balance and accumulated provision for depreciation for the years 2008 and 2007 (in thousands of dollars):
2008 2007
Balance AvgRate Balance Avg Rate
Production $1,736,670 2.34%$1,639,710 2.52%
Trasmission 742,871 2.11 684,399 2.13
Distribution 1,254,048 2.50 1,175,429 2.58
General and Other 296,545 7.53 296,801 8.29
Total in service 4,030,134 2.73%3,796,339 2.95%
Accumulated provision for depreciation (1,505,120)(1,468,832)
In service - net $2,525,014 $2,327,507
IPC has interests in three jointly-owned generating facilities. Under the joint operating agreements, each participating utilty is
responsible for financing its share of constrction, operating and leasing costs. IPC's proportionate share of direct operation and
maintenance expenses applicable to the projects is included in the Consolidated Statements ofIncome.
These facilties, and the extent of IPC' s participation, were as follows at December 31, 2008 (in thousands of dollars):
Utilty Construction Accumulated Owner
I Plant In Work in Provision for ship
Name of Plant Service Progress Depreciation %MW(l)
Jim Bridger Units 1-4 $495,321 $16,403 $279,296 33 771
I Boardman 70,924 477 50,914 10 64
Valm Units i and 2 336,783 8,041 212,791 50 284
FERC FORM NO.1 Page 123.27
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IPC Investments:
Equity method investment
A vailable- for-sale equity securties
Executive deferred compensation
Other investments
Total IPC investments
$86,433
14,451
4,679
948
106,511
$76,451
21,445
6,627
5
104,528
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Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2S An Original (Mo, Da, Yr)
Idaho Power Company i2) A Resubmission 04115/2009 2008/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
(I)¡PC share of nameplate capacity
IPC's wholly-owned subsidiary IERCo, is a joint venturer in Bridger Coal Company, which operates the mine supplying coal to the
jim Bridger generating plant. IPC's coal purchases from the joint ventue were $63 milion, and $51 milion in 2008 and 2007,
respectively.
IPC has contracts to purchase the energy from four PURPA qualified facilities that are 50 percent owned by Ida-West, a wholly-owned
subisidary of IDA CORP. IPC's power purchases from these facilties were $8 milion in 2008 and 2007.
10. INVESTMENTS:
The following table summarizes IPC's investmeits as of December 31 (in thousands of dollars):
2008 2007
Equity Method Investments
IPC, through its subsidiary IERCo, is a 33 percent owner of Bridger Coal Company, which supplies coal to the jim Bridger generating
plant owned in part by IPC.
The following table presents IPC's earings (loss) of unconsolidated equity-method investments (in thusands of dollars):
Bridger Coal Company (IPe)
2008
$ 6,772
2007
$ 5,553_
The following table presents summarzed income statement information for Bridger Coal Company (in thousands of dollar):
Operating revenues
Operating expenses
Net Income
2008
$ 187,560
167,245
$ 20,315
2007
$ 153,126
136,468
$ 16,658
The following table presents summarized balance sheet information for Bridger Coal Company (in thousands of dollars):
2008 2007
Assets
Current assets $64,569 $58,672
Noncurrent assets 318,266 330,583
Total Assets $382,835 $389,255
Liabilties
Current liabilties $25,182 $25,372
Noncurrent liabilties 98,355 134,529
Total Liabilties 123,537 159,901
Joint venture capital 259,298 229,353
IFERC FORM NO.1 (ED. 12-88) Page 123.28
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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 04/15/2009 2008/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
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Total Liabilities and Joint Venture Capital $382,835 $389,254
Investments in Debt and Equity Securities
Investments in debt and equity securities are accounted for in accordance with SF AS 115, Accountingfor 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 detennine the cost for computing gains or losses. Any inealized gains or losses on available-for-sale
securities are included in other comprehensive income.
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Investments classified as held-to-matuity securities are reported at amortized cost. Held-to-maturity securities ar investments in debt
securities for which the company has the positive intent and abilty to hold the securities until matuity. These debt securities have
maturities ranging from 2009 through 2025.
The following table summarizes investmerts in debt and equity securities (in thousands of dollars):I
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2008 2007
Gross Gross Gross Gross
Unrealized Unrealized Fair Unrealized Unrealized Fair
Gain Loss Value Gain Loss Value
Available-for-sale
securities (IPC)$-$- $14,45 I $1,059 $128 $21,445
The following table summarizes sales of available- for-sale sewrities (in thousands of dollars):
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2008 2007
Proceeds from sales
Gross realized gains from sales
Gross realized losses from sales
$$26,110
2,093
762
Additionally, these investments are evaluated to detennine whether they have experienced a decline in market value that is considered
other-than-temporar. IPC analyzes securities in loss positions as of the end of each reporting period. Due to recent market conditions
IPC reviewed securities in a loss position and detennined that due to the severity of the losses and the volatilty of the market an
other-than-temporary ñnpairent should be recorded. At December 3 1,2008, four avaIlable-for-sale and six held-to-maturit
securities were in an unrealized loss position. The available-for-sale equity securities in unrealized loss positions are in broadly
diversified index fuds used to fund IPC's SMSP. The held-to-maturity debt securties in inealized loss positions are bonds, whose
market values fluctuate based on the interest rate environment. The available-for-sale securities were in unrealized loss positions of at
least 32 percent and were deemed other-than-temporarly impaired and written down $6.8 milion to fair market value at December 31,
2008. IPC did not recognize any other-than-temporary impainnents in 2007.
The following table summarizes infonnation regarding securities that were in an unrealized loss position at the end of each year, but
for which no other-than-temporary impainnent 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
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2007:
A vailable-for-sale equity securities (IPC) $128 $ 1,059 $$
11. FAIR VALUE MEASUREMENTS:
IFERC FORM NO.1 (ED. 12-88) Page 123.29
FASB Staff Position 157-2, Effective Date ofFASB Statement No. 157 (FSP 157-2) delayed the implementation of SF AS 157 for
nonfinancial assets and nonfinancial liabilties, except for items that are recognized or disclosed at fair value in the financial statements
on a recurng basis (at least annually). The delay is intended to allow the Board of Directors and constituents additional time to
consider the effect of varous implementation issues that have arsen, or that may arise, from the application of SFAS 157. In
accordance with FSP 157-2, fPC did not apply the provisions of SF AS 157 to asset retirement obligations.
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Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2009 2008/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
IPC partially adopted the provisions of SF AS 157, Fair Value Measurements (SFAS 157) on Januar 1,2008. SFAS 157 defines fair
value, establishes a framework for measuring fair value, establishes a fair value hierarchy based on the quality of inputs used to
measure fair value and enhances disclosure requirement for fair value measurements.
The following tables present infonnation about IDACORP's and IPC's assets and liabilities measured at fair value on a recurring basis
as of December 3 1,2008 (in thousands of dollar). IDACORP's and IPC's assessment of the si1lificance ofa particular input to the
fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the
fair value hierarchy.
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Quoted Prices Significant Signifcant
in
Active Markets Other Unobservable
for Identical Observable Inputs
Assets (Levell)Inputs (Level 2)(Level 3) Total
Assets:
Derivatives $652 $$$652
Money market funds 1,224 1,224
Trading securities 4,679 4,679
A vail able- for-sale securities 14,451 14,451
Liabilities:
Derivatives $$(2,653)$$(2,653)
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In accordance with SF AS 157, IPC have categorized their financial instrments, based on the priority of the inputs to the valuation
technique, into a three-level fair value hierachy. The fair value hierachy gives the highest priority to quoted prices in active markets
for identical assets or liabilties (Level i) and the lowest priority to unobservable inputs (Level 3). If the inputs used to measure the
financial instrments fall within different levels ofthe hierarchy, the categorization is based on the lowest level input that is significant
to the fair value measurement of the instrment
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Financial assets and liabilties recorded on the Consolidated Balance Sheets are categorized based on the inputs to the valuation
techniques as follows:
Level 1: Financial assets and liabilties whose values are based on unadjusted quoted prices for identical assets or liabilties in an
active market that IPC has the abilty to access.
Level 2: Financial assets and liabilties whose values are based on the following:
a) Quoted prices for similar assets or liabilities in active markets;
b) Quoted prices for identical or similar assets or liabilties in non-active markets;
c) Pricing models whose inputs are observable for substantially the full tenn of the asset or liabilty;
d) Pricing models whose inputs are derived principally from or corroborated by observable market data though
correlation or other means for substantially the full tenn of the asset or liabilty.I
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IPC Level 2 inputs are based on quoted market prices adjusted for location using corroborated, observable market data.
Level 3: Financial assets and liabilties whose values are based on prices or valuation techniques that require inputs that are both
IFERC FORM NO.1 (ED. 12-88) Page 123.30
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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 04/15/2009 2008/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
I unobservable and significant to the overall fair value measurement. These inputs reflect management's own assumptions about the
assumptions a market paricipant would use in pricing the asset or liabilty.
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IPC's derivatives are contracts entered into as par of our management ofloads and resources. Electricity swaps are valued on the
Intercontinental Exchange with quoted prices in an active market. Natural gas derivative valuations are performed using New York
Mercantile Exchange (NYMEX) pricing, adjusted for basis location, which are also quoted under NYMEX. Trading securities
consists of employee-directed investments reId in a Rabbi Trust and are related to an executive deferred compensation plan.
A vailable-for-sale securities are related to the SMSP and are held in a Rabbi Trust and are actively traded money market and equity
funds with quoted prices in active markets.
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I The following tables present the carring value and estimated fair value of other fmancial instrents that are not reported at fair
value, 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 caring value
as these are a reasonable estimate of their fair value. The estimated fair values for notes receivable and long-term debt are based upon
quoted market prices of the same or similar issues or discounted cash flow analyses as appropriate.I
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Notes receivable
Liabilities:
Long-term debt
December 31,2008 December 31, 2007
Carrying Estimated Carrying EstimatedAmount Fair Value Amount Fair Value
(thousands of dollars)
$ 259 $ 282 $ 4,859 $ 4,907
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$ 1,268,818 $ 1,191,476 $ 1,145,981 $ 1,272,627
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IPC adopted the provisions of SF AS 159, The Fair Value Optionfor Financial Assets and Financial Liabilties - Including an
Amendment ofF ASB Statement 115 (SF AS i 59) on Januar I, 2008. SF AS 159 permits an entity to choose to measure many
financial instrments and certain other items at fair value. Most of the provisions in SF AS 159 are elective; however, the amendment
to SFAS i 15, Accountingfor 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 i 59 permits all entities to choose to measure eligible items at fair value
at specified election dates. A business entity reports unrealized gains and losses on items for which the fair value option has been
elected in earings at each subsequent reporting date. The fair value option: (a) may be applied instrment by instrment, with a few
exceptions, such as investments otherwse 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 instruents. IPC did not elect the fair value option for any existing
eligible items, but may consider the fair value option on a case-by-case basis in the future.
12. ASSET RETIREMENT OBLIGATIONS (ARO):
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SFAS 143, Accountingfor Asset Retirement Obligations, as amended and interpreted, requires that legal obligations associated with
the retirement of propert, plant and equipment be recognized as a liability at fair value when incurrd and when a reasonable estimate
of the fair value of the liabilty can be made. Under SFAS 143, when a liabilty is initially recorded, the entity increases the caring
amount of the related long-lived asset to reflect the future retirement cost. Over time, the liabilty 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, as approved by Order No. 29414 from the IPUC. The
regulatory assets recorded under this order do not earn a return on investment.
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I IPC's recorded AROs relate to the removal of Polychlorinated biphenyls-contaminated equipment at its distrbution facilties and the
reclamation and removal costs at its jointly owned coal-fired generation facilities. In 2008, changes in estimates for both of these
facilities resulted in a net decrease of $2.6 millon in the recorded ARO.I
IFERC FORM NO.1 (ED. 12-88) Page 123.31
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IFERC FORM NO.1 (ED. 12-88) Page 123.32
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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 04/15/2009 2008/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
IPC also has AROs associated with its trnsmission system and hydroelectrc facilities; however, due to the indeterminate removal
date, the fair value of the associated liabilties cWTently cannot be estimted and no amounts are recognized in the consolidated
financial statements.
The regulated operations of IPC also collect removal costs in rates for certain assets that do not have associated AROs. The adoption
of SF AS 143 required IPC to redesignate these removal costs as regulatory liabilties. Costs recorded as regulatory liabilties on
IDACORP's and IPC's Consolidated Balance Sheets as of December 31,2008 and 2007, were $157 milion and $155 milion,
respectively.
The following table presents the changes in the caring amount of AROs (in thousands of dollar):
Balance at beginning of year $
Accretion expense
Revisions in estimated cash flows
Liability settled
Balance at end of year $
2008 2007
14,515 $12,911
701 692
(2,627)920
(174)(8)
12,415 $14,515
13. RELATED PARTY TRANSACTIONS (IPC):
IDACORP
IPC performs corporate functions such as financial, legal and management services for IDA CORP and its subsidiaries. IPC charges
IDA CORP for the costs of these services based on service agreements and other specifically identified costs. For these services IPC
biled IDACORP $1 milion and $2 milion in 2008 and 2007, respectively.
Ida-West
IPC purchases all of the power generated by four oflda-Wests hydroelectrc projects located in Idaho. IPC paid $8 milion in 2008
and 2007.
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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 2008/Q4
(2) DA Resubmission 04/15/2009
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 "fir value hedes", report the accounts affcted and the related amounts in a footnote.
Line Item Unrealized Gains and Minimum Pension Foreign Currency Other
No.Losses on Available-Liabilty adjustment Hedges Adjustments
for-Sale Securities (net amount)
(a)(b)(c)(d)(e)
1 Balance of Account 219 at Beginning of
Preceding Year 1,310,950 (7,048,073)
2 Preceding QtrlYr to Date Reclassifcations
from Acct 219 to Net Income (922,013)450,330
3 Preceding QuarterlYear to Date Changes in
Fair Value 178,312 (126,005)
4 Total (lines 2 and 3)(743,701)324,325
5 Balance of Account 219 at End of
Preceding QuarterlYear 567,249 (6,723,748)
6 Balance of Account 219 at Beginning of
Current Year 567,249 (6,723,748)
7 Current QtrlYr to Date Reclassifications
from Acct 219 to Net Income 4,159,139 414,660
8 Current QuarterlYear to Date Changes in
Fair Value (4,726,364)(2,397,551)
9 Total (lines 7'and 8)(567,225)(1,982,891)
10 Balance of Account 219 at End of Current
QuarterlYear 24 (8,706,639)
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FERC FORM NO.1 (NEW 06-02)Page 122a I
I Name of RespondentIdaho Power Company
Year/Period of Report
End of 2008/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2009
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
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I Other Cash Flow
Line Hedges
No.Interest Rate Swaps
I (f)
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2
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5
I 6
7
8
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I FERC FORM NO.1 (NEW 06-02)
Other Cash Flow
Hedges
(Specif)
Totals for each
category of items
recorded in
Account 219
(h)
( 5,737,123)
( 471,683)
52,307
( 419,376)
( 6,156,499)
( 6,156,499)
4,573,799
7,123,915)
2,550,116)
8,706,615)
(g)
Net Income (Carried
Forward from
Page 117, Line 78)
Total
Comprehensive
Income
(i)(j)
Page 122b
This Page Intentionally Left Blank
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I IS ~o 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 function, in column (e), (f), and (g) report other (specify) and in
column (f) common function.
End of
I
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(a)
Total Company for the
Current YeadQuarter Ended
(b)
Electric
(c)I
Line
No,
Classification
I
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 Unclassifed
8 Total (3 thru 7)
9 Leased to Others
10 Held for Future Use
11 Construction Work in Progress
12 Acquisition Adjustments
13 Total Utility Plant (8 thru 12)
14 Accum Prov for Depr, Amort, & Depl
15 Net Utiity 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 LandlLand Right
20 Amort of Underground Storage Land/Land Rights
21 Amort of Other Utilty Plant
22 Total In Service (18 thru 21)
23 Leased to Others
24 Depreciation
25 Amortization and Depletion
26 Total Leased to Others (24 & 25)
27 Held for Future Use
28 Depreciation
29 Amortization
30 Total Held for Future Use (28 & 29)
31 Abandonment of Leases (Natural Gas)
32 Amort of Plant Acquisition Adj
33 Total Accum Prov (equals 14) (22,26,30,31,32)
----~-~~
4,030,588,348 4,030,588,348I
I
4,030,588,348 4,030,588,348
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6,318,163
207,662,162
-454,449
4,244,114,224
1,505,119,564
2,738,994,660
6,318,163
207,662,162
-454,449
4,244,114,224
1,505,119,564
2,738,994,660I- ~--- --~-----
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-373,026
1,505,119,564
-373,026
1,505,119,564
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I FERC FORM NO.1 (ED. 12-89)Page 200
Name of Respondent
Idaho Power Company
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2009
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106)
1. Report below the original cost of electric plant in service according to the prescribed accunts,
2. In addition to Account 101, Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant Purchased or Sold;
Account 103, Experimental Electric Plant Unclassified; and Account 106, Completed Construction Not Classified-Electric.
3. Include in column (c) or (d), as appropriate, corrctions of additions and retirements for the currnt or preceding year.
4, For revisions to the amount of initial asset retirement costs capitalized, included by primary plant account, increases in column (c) additions and
reductions in column (e) adjustments.
5. Enclose in parentheses credit adjustments of plant accounts to indicate the negative effct of such accounts.
6. Classify Account 106 according to prescribed accunts, on an estimated basis if necssary, and include the entries in column (c), Also to be included
in column (c) are entries for reversals of tentative distributions of prior year reported in column (b). Likewise, if the respondent has a significant amount
of plant retirements which have not been classifed to primary accounts at the end of the year, include in column (d) a tentative distribution of such
retirements, on an estimated basis, with appropriate contra entry to the account for accumulated depreciation provision. Include also in column (d)ine ccount a ance A itions
No Beginning of Year. W 00
1 1. INTANGIBLE PLANT
2 (301) Or anization
3 (302) Franchises and Consents
4 (303) Miscellaneous Intangible Plant
5 TOTAL Intan ible Plant (Enter Total of lines 2,3, and 4
6 2. PRODUCTION PLANT
7 A. Steam Production Plant
8 (310) Land and Land Ri hts
9 (311) Structures and Improvements
10 (312) Boiler Plant Equi ment
11 (313) En ines and Engine-Driven Generators
12 (314) Turbogenerator Units
13 (315) Accessory Electric Equipment
14 (316) Misc. Power Plant Equipment
15 (317) Asset Retirement Costs for Steam Production
16 TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)
17 B. Nuclear Production Plant
18 (320) Land and Land Rights
19 (321) Structures and Improvements
20 (322) Reactor Plant Equipment
21 (323) Turbogenerator Units
22 324) Accesso Electric Equipment
23 (325) Misc, Power Plant E uipment
24 (326) Asset Retirement Costs for Nuclear Production
25 TOTAL Nuclear Production Plant Enter Total of lines 18 thru 24
26 C. H draulic Production Plant
27 (330) Land and Land Ri hts
28 (331) Structures and Improvements
29 (332) Reservoirs, Dams, and Waterways
30 (333) Water Wheels, Turbines, and Generators
31 (334) Accessory Electric Equipment
32 (335 Misc. Power PLant Equipment
33 (336) Roads, Railroads, and Bridges
34 (337 Asset Retirement Costs for Hydraulic Production
35 TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34)
36 D. Other Production Plant
37 (340) Land and Land Ri hts
38 (341) Structures and Improvements
39 (342) Fuel Holders, Products, and Accssories
40 (343) Prime Movers
41 (344) Generators
42 (345 Accesso Electric Equipment
43 (346) Misc. Power Plant E uipment
44 (347) Asset Retirement Costs for Other Production
45 TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44)
46 TOTAL Prod. Plant Enter Total of lines 16,25,35, and 45)
Year/Period of Report
End of 2008/04 I
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5,703
21,771,624
49,014,582
70,791,909
50,244
2,560
9,44,368
9,497,172
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~~----- --~-~ ----~-
I1,370,320
131,443,882 3,332,215
I524,719,259 19,563,633
126,933,587 7,071,713
61,605,735 1,416,574 I14,627,692 2,414,071
4,731,236 -369,234
865,431,711 33,428,972~ -~-~---~---
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27,131,877 1,523,291
145,349,446 6,000,910 I246,057,906 3,474,423
187,855,934 484,283
37,573,489 3,971,251 I16,288,729 1,189,254
7,492,685
667,750,066 I16,643,412, ~---~--
402,746
5,765,947
3,765,689
43,597,392
36,682,334
14,055,647
2,258,227
4,656,059
1,564,891
48,133,339
-44,466
3,867,501
1,539,837
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106,527,982
1,639,709,759
59,317,161
109,389,545 I
Page IFERCFORM NO.1 (REV. 12-05)204
YearlPeriod of Report
End of 2008/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2009
ELECTRIC PLANT IN SERVICE (Account 101,102,103 and 106) (Continued)
I distributions of these tentative classifications in columns (c) and (d), including the reversals of the prior years tentative account distributions of theseamounts. Careful observance of the above instructions and the texts of Accounts 101 and 106 wil avoid serious omissions of the reported amount of
respondent's plant actually in service at end of year.
I 7. Show in column (f) reclassifications or transfers within utility plant accounts, Include also in column (f) the additions or reductions of primary account
classifications arising from distribution of amounts initially recorded in Account 102, include in column (e) the amounts with respect to accumulated
provision for depreciation, acquisition adjustments, etc., and show in column (f) only the offset to the debits or credits distributed in column (f) to primary
account classifications.
8. For Account 399, state the nature and use of plant included in this account and if substantial in amount submit a supplementary statement showing
subaccount classifcation 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 propert purchased or sold, name of vendor or purchase,
and date of transaction, If proposed journal entries have been filed with the Commission as required by the Uniform System of Accounts, give also dateRetirements Adjustments Transfers Balance at LineEnd l!f)Year No.
I Name of RespondentIdaho Power Company
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I 55,947
21,714,184
33,064,583
54,834,714
60,000
25,394,367
25,454,367
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----~---~-------~~-~--~-- ------~~- -------- --------- ---- - - - - - - - - -- - - - --
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266,953
7,669,836
1,370,320
134,509,144
536,613,056
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1,444,724
860,134
698,604
132,560,576
62,162,175
16,343,159
4,362,002
887,920,43210,940,251
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28,655,168
151,277,057
249,507,983
188,274,619
41,330,716
17,467,963
7,492,685I
73,299
24,346
65,598
214,024
10,020
I 387,287 684,006,191---~-~~--~-----~-~ --~------
I 241,306
402,746
10,422,006
5,330,580
91,489,425
36,237,868
17,237,981
3,623,146I685,167
174,918
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1,101,391
12,428,929
164,743,752
1,736,670,375
I FERC FORM NO.1 (REV. 12-05)Page 205
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
Name of Respondent
Idaho Power Company
47 3, TRANSMISSION PLANT
48 (350) Land and Land Rights
49 (352) Structures and Improvements
50 (353) Station Equipment
51 (354) Towers and Fixtures
52 (355) Poles and Fixtures
53 (356) Overhead Conductors and Devices
54 (357) Underground Conduit
55 (358) Underground Conductors and Devices
56 (359) Roads and Trails
57 (359,1) Asset Retirement Costs for Transmission Plant
58 TOTAL Transmission Plant (Enter Total of lines 48 thru 57)
59 4, DISTRIBUTION PLANT
60 (360) Land and Land Ri hts
61 (361) Structures and Improvements
62 (362) Station Equipment
63 (363) Stora e Batte Equipment
64 (364) Poles, Towers, and Fixtures
65 (365) Overhead Conductors and Devices
66 (366) Under round Conduit
67 (367) Under round Conductors and Devices
68 (368) Line Transformers
69 (369) Services
70 (370 Meters
71 (371) Installations on Customer Premises
72 (372) Leased Property on Customer Premises
73 (373) Street Lightin and Signal Systems
74 (374) Asset Retirement Costs for Distribution Plant
75 TOTAL Distribution Plant (Enter Total of lines 60 thru 74)
76 5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT
77 (380) Land and Land Rights
78 (381) Structures and Improvements
79 (382) Computer Hardware
80 383) Computer Softare
81 (384) Communication E uipment
82 (385) Miscellaneous Regional Transmission and Market 0 eration Plant
83 (386) Asset Retirement Costs for Re ional Transmission and Market Oper
84 TOTAL Transmission and Market 0 eration Plant (Total lines 77 thru 83)
85 6. GENERAL PLANT
86 (389) Land and Land Rights
87 (390) Structures and Improvements
88 (391) Offce Furniture and Equipment
89 392) Transportation Equipment
90 (393) Stores Equipment
91 (394) Tools, Shop and Gara e Equipment
92 (395) Laborato Equipment
93 (396) Power 0 erated Equipment
94 (397) Communication E uipment
95 (398) Miscellaneous Equi ment
96 SUBTOTAL (Enter Total of lines 86 thru 95)
97 (399) Other Tangible Propert
98 (399.1) Asset Retirement Costs for General Plant
99 TOTAL General Plant (Enter Total of lines 96, 97 and 98
100 TOTAL (Accounts 101 and 106
101 (102 Electric Plant Purchased (See Instr. 8)
102 (Less) (102) Electric Plant Sold (See Instr. 8)
103 (103) Experimental Plant Unclassified
104 TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103)
Line
No.
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2009
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)ccount a ance
Beginning of YearW 00 IYear/Period of Report
End of 2008/04
I
I31,094,271
40,254,296
262,977 ,911
121,741,698
88,360,864
139,652,134
3,573,713
1,041,187
25,222,555
15,244,442
5,331,099
11,603,174 I
318,351 I
684,399,525 62,016,170I--~--~-~---~~--~I4,385,782
21,657,452
151,682,747
334,889
2,885,280
15,847,465 I203,942,364
106,511,815
46,129,157
171,154,321
352,640,906
53,887,678
56,322,932
2,732,980
8,693,766
11,800,654
1,353,959
8,912,213
35,194,821
2,099,689
3,631,951
155,034
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4,121,273
259,264
1,175,428,671
89,095
-26,894
90,971,922 I---~-- ~- -~------ ~
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68,791,677
38,195,783
57,256,775
1,074,679
4,410,227
10,232,418
8,709,964
25,893,136
3,026,058
226,463,847
1,955,245
3,097,321
11,585,956
5,634,408
136,651
571,472
910,339
309,378
1,460,308
1,234,348
26,895,426
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226,463,847
3,796,793,711
26,895,426 I298,770,235
298,770,235 I
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3,796,793,711
FERC FORM NO.1 (REV. 12-05)206Page
I Name of RespondentIdaho Power Company
I Retirements
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2009
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)Adjustments Transfers Balance at
End l!f)Year
Year/Period of Report
End of 2008/Q4
I 2,297
21,264
2,099,126
64,506
555,010
802,568
34,665,687
41,274,219
286,101,340
136,921,634
93,136,953
150,452,740I
I 318,351
3,544,771 742,870,924
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5,593
27,667
306,213
4,715,078
24,515,065
167,223,999I2,050,267
1,522,602
65,918
556,861
6,008,815
429,602
970,061
351,216
210,585,863
116,789,867
47,417,198
179,509,673
381,826,912
55,557,765
58,984,822
2,536,798
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I 57,435 4,152,933
232,370
1,254,048,34312,352,250~----~~ ---~ --~----~-------------~-- - ------
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484,603
3,876,887
4,459,265
28,843
172,987
430,282
345,591
1,242,638
154,185
11,195,281
10,828,375
71,404,395
45,904,852
58,431,918
1,182,487
4,808,712
10,712,475
8,673,751
26,110,806
4,106,221
242,163,992
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11,195,281
64,975,598
242,163,992
4,030,588,348
64,975,598 4,030,588,348
I FERC FORM NO.1 (REV. 12-05) Page 207
Line
No.
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
97
98
99
100
101
102
103
104
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/Q4
(2) FiA Resubmission 04/15/2009
ELECTRIC PLANT HELD FOR FUTURE USE (Account 105)
1. Report separately each propert held for future use at end of the year having an oriinal cost of $250,000 or more.Group other items of propert held
for future use.
2. For propert having an original cost of $250,000 or more previously used in utilit operations, now held for future use, give in column (a), in addition to
other required information, the date that utilty use of such propert was discontinued, and the date the original cost was transferred to Accunt 105.
Line Description and Location ~No,OfProlerty in T is Account in Utility Service End of Year(a (b) (c) (d)
1 Land and Rights:
2 Boise Operations Center 12131/82 768,377
3 Production 112,703
4 Transmission Stations 429,822
5 Transmission Lines 68,619
6 Distribution Stations 1,157,999
7 Beacon Light Substation (1)1210/02 465,662
8 Homedale Substation 219/08 109,453
9 North River Operations Center 1131/08 2,630,412
10 Boise Operations Center 12/31/82 72,785
11 Boise Mechanical and Electrical Shop 12/31/01 47,000
12 Transmission Stations 12/31/81 178,094
13 Distribution Stations 61,518
14 Homedale Substation 219/08 215,719
15
16
17
18
19 Column B if no date listed it is various
20
21 Other Propert:
22
23
24
25
26
27 (1) a portion of Beacon Light was classifed 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 6,318,163
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FERC FORM NO.1 (ED. 12-96)Page 214 I
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Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/Q4
(2) FiA Resubmission 04/15/2009
CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
1. Report below descriptions and balances at end of year of projects in process of construction (107)
2, Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $100,000, whichever is less) may be grouped.
Line Description of Project Construction work in progress -
No.Electric (Accunt 107)
(a)(b)
1 ROLLUP RELIC COST BROWNLEE 40,342,807
2 ROLLUP RELIC COST HELLS CANYON 27,627,540
3 ROLLUP RELIC COST OXBOW 12,682,103
4 HELLS CANYON RELICENSING OUTSI 9,430,117
5 VALMY UNDISTRIBUTED WORK ORDER 6,137,283
6 CIAC LIABILITY RECLASS 6,022,349
7 CAPITALIZE RENEWED RIW CONTRAC 5,901,983
8 TURBINE BLADES AND VANES - CAP 5,879,617
9 DNPR06010PERATIONS 4,696,909
10 BRIDGER UNDISTRIBUTED WORK ORO 4,144,315
11 NEW OPERATIONS CENTER (§ LAKE F 3,898,514
12 HUBBARD NEW 230 KV SWITCHING S 3,881,974
13 GATEWAY WEST 500KV LINE 3,686,522
14 WQ - ONGOING HELLS CANYON RELI 3,276,768
15 IPCO.CONVERT HAVN TO 138 KV 2,527,819
16 MPSN - MIDPOINT EAST RAS UPGRA 2,039,604
17 BRIDGER 2007C207 U3 S02 EM IS C 1,917,087
18 HCC RELICENSING FISH2004 FEASI 1,870,234
19 BOARDMAN - HEMINGWAY 500 KV LI 1,848,052
20 JIM BRIDGER RAS-A AND RAS-B 1,711,403
21 REL-HELLS CANYON COMPLEX FY200 1,618,941
22 CJ STRIKE: #1 TURBINE RUNNER 1,551,344
23 HMWY - BUILD HEMINGWAY 5001230 1,474,063
24 ETGT0703 -INCREASE T132 AND R 1,395,188
25 342 COST CENTER DELIVERY CAPIT 1,366,017
26 BRIDGER 2007C189 U1 S02 EM IS C 1,364,664
27 IPCO.UPGRADE PNGE TO FACILITAT 1,289,859
28 HCC RELICENSING, FISH2004 INST 1,269,901
29 COST CENTER 317 DELIVERY CAPIT :1,228,396
30 HCC RELICENSING, FISH2004 REDB 1,136,664
31 HCC RELICENSING, FISH2004 ANAD 1,123,075
32 WEB SITE REDESIGN 1,103,510
33 ROLLUP RELIC COST SWAN FALLS 1,088,739
34 CAPITAL REGION CONVERSION TO A 1,021,319
35 SWAN FALLS RELICENSING 1,012,279
36 PAYROLL & IBNR ACCRUAL 896,085
37 RIVER ENG.-HELLS CANYON CONTIN 862,986
38 326-COST CENTER DELIVERY CAP IT 856,664
39 BROWNLEE LOCAL SERVICE UPGRADE 854,703
40 BRIDGER 2007C812 SODA LIQUOR S 835,409
41 BRIDGER 2008C102 U1 GENERATOR 831,690
42 BRIDGER 2008C123 U1 TURBIN UPG 831,529
43 TOTAL 207,662,162
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I 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 Oriinal (Mo, Da, Yr)End of 2008/Q4
(2) DA Resubmission 04/15/2009
CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
1. Report below descriptions and balances at end of year of projects in process of construction (107)
2, Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3. Minor projects (5% of the Balance End of the Year for Accunt 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 REL-HCC OREGON REAUTHORIZATION 811,243
2 BRIDGER 2007C191 U2 S02 EM IS C 808,892
3 LEGAL DEPT. LABOR FOR RELICENS 765,891
4 PURCHASE #4 TURBINE RUNNER 750,479
5 BUILD NEW ADRIAN SUBSTATION AT 700,142
6 T7230701 OPGW DANSKIN-HUBBARD 646,583
7 341 COST CENTER DELIVERY CAPIT 627,577
8 418-CC DELIVERY CAPITAL OVERHE 626,271
9 392 COST CENTER DELIVERY CAPIT 613,484
10 REL - SWAN FALLS FY2004 CAPITA 606,870
11 577 COST CENTER DELIVERY CAPIT 601,961
12 HCC RELICENSING FISH2004 RESID 597,977
13 BRIDGER 2007C206 FAN BAY ROAD 594,137
14 578 COST CENTER DELIVERY CAPIT 576,076
15 BRIDGER 2008C090 U2 REHEATER 0 558,488
16 CONSTRUCTION ACCOUNTING CAPITA 555,252
17 VALMY 98208581 U2 GENERATOR RE 549,524
18 ST LUKES MVRMC-POLELINE & GRAN 548,850
19 BEACON LIGHT SITE WORK, FENCE,546,198
20 343 COST CENTER DELIVERY CAPIT 539,718
21 415-CC DELIVERY CAPITAL OVERHE 537,081
22 VALMY 98210178 INSTALL PRODUCT 536,698
23 PHASE 2 AMI- AMI METER CONTRAC 519,319
24 LINE 438, PERMITIING & ROW FOR 502,933
25 335-COST CENTER DELIVERY CAPIT 497,948
26 IPCO*L1NE #46 PNGE-HAVN CONVE 496,813
27 390 COST CENTER DELIVERY CAPIT 489,938
28 BOISE PLAZA LEASE 483,484
29 GEN PCB & METAL CLAD REPLACEME 464,011
30 WQ SWAN FALLS RELICENSING-CAPI 456,204
31 CAPITAL (DELOVHD)409,378
32 COST CENTER 316 DELIVERY CAPIT 408,250
33 ROW FOR T 404 - 138 KV TO CHERR 403,191
34 REC - BAKER COUNTY SETILEMENT 399,000
35 BEARING COOLERS, CLOSED LOOP S 398,296
36 455-COST CENTER DELIVERY CAPIT 391,956
37 336-COST CENTER DELIVERY CAPIT 384,627
38 IPCO/HBND-041 REBUILD APPROX 3 382,574
39 CHQ 5 REMODEL FURNITURE 382,499
40 MORA-042 FEEDER WORK 8.5 MILES 369,495
41 IT SERVICE MANAGEMENT SOFTWARE 366,317
42 BRIDGER 2007C911 PLANT SECURIT 357,206
43 TOTAL 207,662,162.
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FERC FORM NO.1 (ED. 12-87)Page 216.1 I
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Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/Q4
(2) QA Resubmission 04/15/2009
CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
1, Report below descriptions and balances at end of year of projects in process of construction (107)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $100,000, whichever is less) may be groupe,
Line Description of Project Construction work in progress -
No,Electric (Account 107)
(a)(b)
1 HAILEY TEAM CAP OH WORK ORDER 356,095
2 ACCUFILE TAX APPLICATION REPLA 355,949
3 TERR: HCC RELICENSING 348,234
4 WYE ADD AMI EQUIPMENT 346,218
5 ENHANCED LAW ENFORCEMENT PER S 338,654
6 DELIVERY WORK ORDER RECON PROJ 334,767
7 381 -COST CENTER DELIVERY CAPI 327,484
8 IPCO-CITY OF KETCHUM/IMPROVE L 325,980
9 EEM SOFTWARE 323,552
10 575 COST CENTER DELIVERY CAPIT 317,440
11 MORA STATION MODIFICATIONS AS 317,185
12 CHQ 5 REMODEL 309,169
13 LINE 438, RIGHT OF WAY, VICTOR 305,769
14 REPLACE POWER CENTERS ON PLANT 303,233
15 GOODING TEAM CAP OH WORK ORDER 295,304
16 BOARDMAN 24554 REWIND GENERATO 289,783
17 ORACLE SOA HARDWARE 285,354
18 VALMY 98218173 U2 PULVERIZER U 284,506
19 BORA0501 BORA-MPSN 345KV THER 284,156
20 SWAN FALLS RELICENSING FISH200 279,719
21 153 COST CENTER DELIVERY CAPIT 278,675
22 T7110401-HPVY 230KV DOUBLE CIR 276,036
23 IPCO/BOIS-02112006 DOWNTOWN CA 273,479
24 REL - REC SWAN FALLS RELICENSI 272,926
25 AFTS0701 - REPL 11 AB SWITCHES 270,821
26 Delivery Overheads 269,832
27 ENTERPRISE CONTENT MANAGEMENT 262,521
28 NEW RESTROOM, SEWER AND WATER 261,809
29 ORACLE SOA SUITE 260,683
30 TWINWEST TEAM CAP OH WORK ORDE 248,465
31 BRIDGER 2007C706 FLYASH LOADIN 247,796
32 USTICK ADD AMI EQUIPMENT 247,397
33 BRIDGER 2008C064 U2 EXCITATION 246,837
34 ADAMSFAM TEAM CAP OH WORK ORDE 243,434
35 1 OO-COST CENTER DELIVERY CAP IT 242,489
36 IPCO.PERMIT / PURCHASE ROW FOR 239,462
37 334-COST CENTER DELIVERY CAPIT 239,178
38 TFSN015 REPLACE GETAWAY CABLE 238,735
39 REBUILD ADEL 301A--COMPLETE/L 236,375
40 STATE ADD AMI EQUIPMENT 230,599
41 AMI IT SOFTARE 229,387
42 BRIDGER 2007C213 SOOT BLOWER C 226,467
43 TOTAL 207,662,162
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I 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 Original (Mo, Da, Yr)End of 2008/Q4
(2) DA Resubmission 04/15/2009
CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (AccounI107)
1. Report below descriptions and balances at end of year of projects in process of construction (107)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $100,000, whichever is less) may be grouped.
Line Description of Project Construction work in progress -
No.Electric (Account 107)
(a)(b)
1 41Q-CC DELIVERY CAPITAL OVERHE 224,597
2 324-COST CENTER DELIVERY CAPIT 219,865
3 NERC CRITICAL INFRASTRUCTURE P 219,689
4 STATIC EXCITER #1 UNIT (PURCHA 213,901
5 TFEAST TEAM CAP OH WORK ORDER 212,709
6 COST CENTER 310 DELIVERY CAPIT 211,663
7 BOARDMAN 24226 PURCH SPARE GEN 211,424
8 BRIDGER 2008C124 U1 REHEATER R 211,390
9 LONG VALLEY OPERATION CENTER F 210,867
10 FRMT0701 - REPLACE 131H WITH A 206,403
11 REL - REC HCC RELICENSING PROC 200,927
12 585 COST CENTER DELIVERY CAPIT 199,318
13 SUPERVALU DATA CENTER- ON-SITE 199,196
14 PQ IR CAMERAS 197,232
15 420-CC DELIVERY CAPITAL OVERHE 196,739
16 BORA: RAS C & 0 COMMUNICATIONS 196,248
17 375 COST CENTER DELIVERY-CAPIT 196,090
18 HOMESTEAD ROAD WORK ASSOCIATED 194,725
19 JIM BRIDGER SUBSTATION CAPITAL 193,255
20 404 COST CENTER DELIVERY CAPIT 193,143
21 TOOL EXP TRANS TO CONST 188,428
22 DELIVERY CAPITAL OVERHEADS FOR 187,992
23 MINI CASSIA TEAM CAP OH WORK 0 186,042
24 SEMINIS VEG SEED-1811 E FLORID 185,853
25 CROSS ARM CHANGE OUT BUBG-42 183,333
26 IPCO- RELlBALlTY AND MAINTENANC 182,569
27 IPCO*INSTALL 69 KV LINE TERMIN 181,876
28 COST CENTER 329 DELIVERY CAP IT 177,157
29 378 -COST CENTER DELIVERY CAPI 176,180
30 WATER RIGHTS ACQUISITION: COT 175,958
31 FALL CHINOOK POPULATION VIABIL 175,699
32 KENNISON DAIRY CONDUCTOR UPGRA 173,236
33 RE-ROUTE BOBN-CDWL 230KV TO H 170,851
34 DESIGN, BUILD, INSTALL UNIT #2 167,933
35 L-252, GOLDEN VALLEY LOOP, PAT 163,911
36 BEACON LIGHT 138-KVTAP-PERMIT 158,814
37 IPCO/ COAL 015/ F42/2008 CABL 158,711
38 300 COST CENTER DELIVERY CAPIT 158,427
39 BRIDGER 2008C085 U4 S02 & PM E 158,282
40 BRIDGER 2008C049 U4 OVATION CO 157,601
41 BRIDGER 2008C117 U1 APH BASKET 156,537
42 MPSN: RAS C & 0 COMMUNICATIONS 156,245
43 TOTAL 207,662,162
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FERC FORM NO.1 (ED. 12-87)Page 216.3
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Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/Q4
(2) r=A Resubmission 04/15/2009
CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
1. Report below descriptions and balances at end of year of projects in process of construction (107)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $100,000, whichever is less) may be groupe.
Line Description of Project Construction work in progress -
No.Electric (Account 107)
(a)(b)
1 856 COST CENTER DELIVERY CAPIT 156,118
2 -INSTALL COMMUNICATIONS FROM 155,482
3 353 COST CENTER DELIVERY CAPIT 154,802
4 COST CENTER 318 DELIVERY CAPIT 153,797
5 IPCOI GARY 0111 F32/2008 CABL 153,152
6 CALL CENTER LABOR HOURS FOR LI 152,823
7 AGING INFRASTRUCTURE TOOL INTE 152,014
8 IPCO- RELlABLlTY WOOD PIN REPL 148,964
9 IPCO/ITD CITY OF DONNELLY RO 148,227
10 PQ ENGINEERS & TECH TEAM 2008 147,030
11 IPCO- PICABO MOUNTAINI REPLACE 145,697
12 CARO-012 REBUILD-2.5 MILES-TO 145,327
13 #2 PURCHASE STATIC EXCITATION 142,008
14 VALMY 98219937 PA FAN CAPITAL 141,713
15 AMI EQUIPMENT (g GROVE SUBSTATI 140,711
16 MORA0602 - COMMUNICATIONS UPGR 140,621
17 T7250801 HMWY-BOMT DBL CRT 230 140,007
18 GOODING RURAL ADD T052 TRANSFO 138,761
19 L-210, BOBN-GFRY 69KV, PATROL 138,699
20 BORA 304A BREAKER REPLACEMENT 136,838
21 KINPORT: RAS C & D COMMUNICATI 136,025
22 IPCOIIDOT KEY#8743 7TH AVE. NO 134,437
23 458-COST CENTER DELIVERY CAPIT 134,171
24 356 COST CENTER DELIVERY CAPIT 133,413
25 PURCHASE AND IMPLEMENT SYNERGE 133,247
26 2008 TEST EQUIPMENT-CAPITAL 132,041
27 CCTV STANDARDIZATION PROJECT-P 131,249
28 579 COST CENTER DELIVERY CAPIT 130,607
29 210-COST CENTER DELIVERY CAPIT 130,605
30 IPCOI MOVE FACILITIES FROM 17T 129,796
31 584 COST CENTER DELIVERY CAPIT 127,392
32 LNSG-EXPAND YARD & LANDSCAPE 126,623
33 IPCO- DIXI031 FDR RLBL TY 1 R17 125,826
34 BRIDGER 2008C042 BCP MOTOR REW 124,923
35 VALMY 98211919 U1 BOnOM ASH P 121,109
36 377 -COST CENTER DELIVERY CAPI 120,452
37 TFSB PARKING & TRANSFORMER STO 120,293
38 AFTS0501 AFTS-MDKA THERMAL DE 116,417
39 HILL INSTALL T132, CKT SWITCHE 114,532
40 BRIDGER 2008C069 VIBRATION MON 113,956
41 HYDA-UPGRADE PORTABLE TRANSFOR 113,557
42 AMI EQUIPMENT (g GARY SUBSTATIO 112,534
43 TOTAL 207,662,162
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I FERC FORM NO.1 (ED. 12-S7)Page 216.4
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/Q4
(2) FiA Resubmission 04/15/2009
CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
1. Report below descriptions and balances at end of year of projects in process of construction (107)
2. Show items relating to "research, development, and demonstration" projecs 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 Accunt 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 PURCHASE & INSTALL DIESEL BACK 111,926
2 AMI EQUIPMENT (§ EKRT 107,691
3 DNPR0602 COMMUNICATION UPGRADE 107,541
4 IPCO/BOBN-044/F-137/2007 CABLE 107,038
5 APPARATUS SERVER -- HARDWARE 106,863
6 BRIDGER 2007C209 U4 S02 EMIS C 105,134
7 EMET0701 REPLACE T132 104,433
8 KENNISON DAIRY CONDUCTOR UPGRA 104,308
9 W1LS-WGNR 138 KV LINE ROW LINE 103,511
10 VALMY 98200467 REPL COAL BELTS 103,221
11 CANYON REGION MANAGER LABOR AN 102,694
12 1998 NEAR EAST IDAHO VESTED I 101,493
13 LINE 328 WARM LAKE TAP REPAIR 100,598
14 345 COST CENTER DELIVERY CAP IT 100,556
15 OTHER MINOR PROJECTS -16,062,667
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 TOTAL 207,662,162
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FERC FORM NO.1 (ED. 12-87)Page 216.5 I
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This Page Intentionally Left Blank
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2008/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2009
ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108)
1. Explain in a footnote any important adjustments during year.
2. Explain in a footnote any difference between the amount for book cost of plant retired, Line 11, column (c), and that reported for
electric plant in service, pages 204-207, column 9d), excluding retirements of non-depreciable 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.
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ine
No.
em I
(a)
Balance Beginning of Year
2 Depreciation Provisions for Year, Charged to
3 (403) Depreciation Expense
4 (403,1) Depreciation Expense for Asset
Retirement Costs
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5 (413) Exp. of Elec. PIt. Leas. to Others
6 Transportation Expenses-Clearing
7 Other Clearing Accounts
8 Other Accounts (Specify, details in footnote):
9 Fuel Stock
10 TOTAL Deprec. Prov for Year (Enter Total of
lines 3 thru 9)
11 Net Charges for Plant Retired:
12 Book Cost of Plant Retired
13 Cost of Removal
14 Salvage (Credit)
15 TOTAL Net Chrgs. for Plant Ret. (Enter Total
of lines 12 thru 14)
16 Other Debit or Cr. Items (Describe, details in
footnote):
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113,509
99,862,335
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17
18 Book Cost or Asset Retirement Costs Retired
19 Balance End of Year (Enter Totals of lines 1,
10,15,16, and 18)
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1,486,751,090 1,486,751,090 I
Section B. Balances at End of Year According to Functional Classification
20 Steam Production 442,070,073 442,070,073
21 Nuclear Production
22 Hydraulic Production-Conventional 264,025.839 264,025,83
23 Hydraulic Production-Pumped Storage
24 Other Production 17,474,253 17,474,253
25 Transmission 230,292,212 230,292,212
26 Distribution 441,040,082 441,040,082
27 Regional Transmission and Market Operation
28 General 91,848,631 91,848,631
29 TOTAL (Enter Total of lines 20 thru 28)1,486,751,090 1,486,751,090
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FERC FORM NO.1 (REV. 12-05)Page 219
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Name of Respondent This Report is:Date of Report YearlPeriod of Report
(1) 2S An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2009 20081Q4
FOOTNOTE DATA
I$chedule Pa~ß19-m Line No.: 14 Column: c----------------~.~~_-~~-=--~-===-=~=_---.=_-=_----- - m__ ----i
Relocation reimbursements, Up and down costs and damage insurance claims $720,911
!.chedule Pf!ge: 21!_Line No.: 16 Column: c____________..__.__ ____----~------...... - -----.-------~--JAccumulated Provision for Depreciation on Asset Retirement Obligation $ 459,618
Embedded removal in Accumulated provision for Depreciation (1,523,871)
$ (1,064,253)
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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 2008/Q4(2) QA Resubmission 04/15/2009
INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1)
1.Report below investments in Accounts 123.1, investments in Subsidiary Companies.
2, Provide a subheading for each company and List there under the information called for below. Sub - TOTAL by company and give a TOTAL in
columns (e),(f),(g) and (h)
(a) Investment in Securities - List and describe each securi 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 subjec to repayment, but which are not subject to
current settlement. With respect to each advance show whether the advance is a note or open account. List each note giving date of issuance, maturity
date, and specifying whether note is a renewal.
3. Report separately the equit in undistributed subsidiary earnings since acquisition. The TOTAL in column (e) should equal the amount entered for
Account 418,1.
ine Description of Investment Date Acquired Date Of Amount of Investment at
No.(a)(b)
Mal~ity Beginning of Year
(d)
1 Idaho Energy Resources Company
2 Common Stock 02/01174 500
3 Capital contributions 2,462,594
4 Equity in earnings 53,474,013
5
6 Subtotal Idaho Energy Resources Company 55,937,107
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 $2,463,0941 TOTAL 55,937,107
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FERC FORM NO.1 (ED. 12-89)Page 224 I
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Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/Q4(2) FiA Resubmission 04/15/2009
INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1) (Continued)
4. For any securities, notes, or accounts that were pledged designaté such securities, notes, or accounts in a footnote, and state the name of pledgee
and purpose of the pledge.
5. If Commission approval was required for any advance made or security acquired, designate such fact in a footnote and give name of Commission,
date of authorization, and case or docket number.
6. Report column (f) interest and dividend revenues form investments, including such revenues form securities disposed of during the year.
7. In column (h) report for each investment disposed of during the year, the gain or loss represented by the diference between cost of the .investment (or
the other 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 Line 42, column (a) the TOTAL cost of Accunt 123.1
Equity in Subsidiary Revenues for Year Amount of Investment at Gain or Loss from Investment LineEarnin~s of Year
(f)
End tifYear DisP?~td of No.e)g)
1
500 2
2,462,594 3
4,121,080 57,595,093 4
5
4,121,080 60,058,187 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
4,121,080 60,058,187 42
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I FERC FORM NO.1 (ED. 12-89)Page 225
This Page Intentionally Left Blank
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Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)2008/Q4(2)DA Resubmission 04/15/2009 End of
MATERIALS AND SUPPLIES
1. For Account 154, report the amount of plant materials and operating supplies under the primary functional classifications as indicated in column (a);
estimates of amounts by function are acceptable. In column (d), designate the department or departments which use the class of materiaL.
2. Give an explanation of important inventory adjustments during the year (in a footnote) showing general classes of material and supplies and the
various accounts (operating expenses, clearing accounts, plant, etc.) affected debited or credited. Show separately debit or credits to stores expense
clearing, if applicable,
Line Account Balance Balance Department or
No,Beginning of Year End of Year Departments which
Use Material
(a)(b)(c)(d)
1 Fuel Stock (Account 151)17,267,629 16,851,868 Electric
2 Fuel Stock Expenses Undistributed (Account 152)
3 Residuals and Extracted Products (Account 153)
4 Plant Materials and Operating Supplies (Account 154)
5 Assigned to - Construction (Estimated)
6 Assigned to - Operations and Maintenance
7 Production Plant (Estimated)12,737,352 13,785,883
8 Transmission Plant (Estimated)9,429,545 9,182,847
9 Distribution Plant (Estimated)18,595,934 20,839,000
10 Regional Transmission and Market Operation Plant
(Estimated)
11 Assigned to - Other (provide details in footnote)607,920 597,997
12 TOTAL Account 154 (Enter Total of lines 5 thru 11)41,370,751 44,405,727 Electric
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 Expense Undistributed (Account 163)1,898,952 5,715,442 Electric
17
18
19
20 TOTAL Materials and Supplies (Per Balance Sheet)60,537,332 66,973,037
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I FERC FORM NO.1 (REV. 12-05)
Page 227
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/Q4
(2) ri A Resubmission 04/15/2009
OTHER REGULATORY ASSETS (Accunt 182.3)
1. Report below the particulars (details) called for conceirning 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 Descrption and Purpose of Balance at Debits CREDITS Balance at end of
No.Other Regulatory Assets Beginning of wnnen on uuring wnnen on uunng Current QuarterlY ear
Currnt the QuarterlY ear the Period
QuarterlYear Accunt Charged Amount
(a)(b)(c)(d)(e)(f)
1 Idaho DSM Rider - IPUC Order #29026 7.188,54 254 3,246,227 3,942.318
2
3 Fixed Cost Adjusment (FCA) Order #30267 4.657.142 254 1,935,924 2,721,218
4
5 IPUC Grid West loans -IPUC order #30157 745,742 401 186,435 559.307
6 (amort period 1/07 -12/11)
7
8 FERC Grid West Expense 302.117 116.87 401 55,878 363,116
9 FERC Docket #AC03-78-D00
10
11 Oregon PCAM Def order 08-238 5,399,657 5.399.657
12
13 Asset Retirment Obligations - IPUC 12.188,065 928,016 230 2,209,539 10,906,542
14 Order #29414 - OPUC Order#04-585
15
16 L T & ST Mark to Market 17,23 4.028.601 244 1,126,205 3,073,630
17
18 Fin 48 Unfunded-Noncurrent-IPUC Order 29601 ( 37.067,740)38,80,873 282 8,903,384 -7,170,251
19
20 Regulatory Unfunded Accumulated Deferrd Income Tax 357,913,795 166'572'96~14,407,255 510,079,505
21
22 PCA Deferrl Idaho -IPUC order 30047 85.731,733 170,950,587~163,025,112 93,657,208
23 (amort period 6/08 thru 5/09)
24
25 Prior Year PCA - Idaho - IPUC order 30325 6,590,53 127,508,162 401 86,934,777 47,163,921
26 (amort period 6/07 thru 5/08)
27
28 Idaho - Demand Side Management - IPUC order 8.106.539 401 3,242,604 4,863,935
29 #27660 (amort period 7/98 thru 6/10)
30
31 Excess Power Deferral 06/07 - IPUC order 2,106,816 2.194,558 254 3,086,676 1,214,698
32 07-555
33
34 Excess Power Amortzation - OPUC Order#06-D70 2.992,60 . 2.010,01__3,339,341 1,663,273
35 (Capped at 10% per year until full amort)
36
37 Security Costs 2003 - IPUC Order #28975 68,794 401 68.794
38 (amort period 1/04 - 12/08)
39
40 OPUC Grid West Loans - OPUC Orer #083 60,407 4,58 64,995
41
42 Unfunded SFAS 106 Lia 30256 -IPUC Order #30256 8,006,409 12,464,601 228 1,567,074 18,903,936
43
44 TOTAL 448,227,917 542,905,448 293,488,641 697,644,724
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FERC FORM NO. 1/3.. (REV. 02-0\Page 232
I Name of Respondent
This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/04
(2)o A Resubmission 04/15/2009
I
OTHER REGULATORY ASSETS (Account 182.3)
1. Report below the particulars (details) called for conc~rning other regulatory assets, including rate order docket number, if applicable.
2. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $50.000 which ever is less), may be grouped
by classes.
3. For Regulatory Assets being amortized, show period of amortization.
Line Description and Purpose of Balanæat Debits CREDITS Balance at end of
No.Other Regulatory Assets Beginning of Wnllen on uunng wnnen on uunng Current QuarterlY ear
Current the QuarterlY ear the Period
QuarterlY ear Accunt Charged Amount
(a)(b)(c)(d)(e)(f)
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1 PS & I Coal Plant - Order #29904 235,859 401 85,767 150,092
2 (amort period 10/2007 thru 9/10)
3
I 4 Minor items(7)75,007 80,266 various 67,649 87,624
5
6
I 7
8 .
9
I 10
11
12
I 13
14
15
I 16
17
18
I 19
20
21
I 22
23
24
I 25
26
27
I 28
29
30
I 31
32
33
I 34
35
36
I 37
38
39
I 40
41
42
I 43
44 TOTAL 448,227,917 542,905,448 293,488,641 697,644,724
",eDt' "'I'D" 1011' ~ 1'1-1' lel:\I n?..A\Paae 232.1
Name of Respondent This Report is:Date of Report Year/Perid of Report
(1) ~ An Original (Mo, Da, Yr)Idaho Power Company (2)A Resubmission 04115/2009 2008/04
FOOTNOTE DATA
~chedule Page:23?~ Line No.:20'-CoÎumn: dAccount 228 $ 703,807
Account 282 13,638,348Account 401 65,100
Total $ 14,407,255============
~chedule Page: 232Account 182 ..
Account 254
Account 401
Line No.: 22 Column: d
$ 124,101,21123,264,092
15,659,809
Total $ 163,025,112=============~._._~.._-~--_._------.~-_._---_._--~ -_.._._.__.._-----_.-~chedule Page: 232 . Line No.: 34 Column: d
Account 254 - $ 898,486Account 401 2,440,855
Total $3,339,341=============
I FERC FORM NO.1 (ED. 12-87)Page 450.1
I
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/Q4
(2) FiA Resubmission 04/15/2009
MISCELLANEOUS DEFFERED DEBITS (Account 186)
1.Report below the particulars (details) called for concerning miscellaneous deferred debits.
2.For any deferred debit being amortized, show period of amortization in column (a)
3. Minor item (1% of the Balance at End of Year for Account 186 or amounts less than $50,000, whichever is less) may be grouped by
classes.
Line Description of Miscellaneous Balance at Debits CREDITS Balance at
No,Deferred Debits Beginning of Year ~ccount.Amount End of Year Char&ed
(a)(b)(c)(d (e)(f)
1 Rents - Riahts of way 137,573 137,573
2
3 2008 Poll Control Bond Refin 169,409 131 8,328 161,081
4
5 Advance prepaid coal royalties 1,657,049 131 76,533 1,580,516
6
7 Security plan 25,920,430 2,537,506 165&426 3,704,186 24,753,750
8
9 American Falls bond refinance 249,814 401 14,552 235,262
10 (amort period 4/00 thru 7/26)
11
12 Prepaid Credit Facility 640,032 431 193,597 446,435
13
14 ComDany owned Life Insurance 4,921,300 1,193,489 426 1,386,274 4,728,515
15
16 American Falls water rights 17,800,983 401 1,042,009 16,758,974
17 (amort period 1/06 thru 12/25
18
19 Milner bond auarantee 11,700,000 1,063,636 253 3,190,909 9,572,727
20
21 Southwest intertie project -6,417,011 253 3,465,186 2,951,825
22 riaht of way costs
23
24 CSPP receivable 270,767 2,460 143 273,227
25
26 American Falls - bond refinance 823,985 401 47,999 775,986
27 (35 vear amortization)
28
29 Shelf Registration - 2008 144,517 1,500,608 181 1,645,125
30
31 Transmission Deposit-PacifCorp 2,354,100 525,000 131 2,217,225 661,875
32
33 Prepaid PeoplesoflPassport 51,343 156,671 401 73,808 134,206
34
35 Valmy Power Plant 260,973 480,250 various 731,276 9,947
36
37 Boardman Power Plant 149,444 149,444
38
39 Minor Items & Job Orders (8)9,879 33,526 Various 41,717 1,688
40
41
42
43
44
45
46
47 Misc. Work in Progress
48 Ueferred Regulatory Comm.
Expenses (See pages 350 - 351)
49 TOTAL 73,222,183 63,059,804
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I FERC FORM NO.1 (ED. 12-94)Page 233
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2008/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04115/2009
ACCUMULATED DEFERRED INCOME TAXES (Accunt 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.
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ine
No.
Description and Location I
(a)IElectric
Emission Allowances 6,920,940
10,171,997
16,363,769
-3,114,188
9,305,479
21,074,809 I
TOTAL Electric (Enter Total of lines 2 thru 7)
Gas
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Other
TOTAL Gas (Enter Total of lines 10 thru 15
Notes
14,873,945
106,047,150
17,642,299
167,646,855
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FERC FORM NO.1 (EO. 12-88)Page 234
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I Sclledule f'age: 2:l,t. Line Ni!~;l_ _.çCJll!!n: a
(Note 1):
I Post Retiree Benefits-VEBARate Case Disallowance
Other Employee's Long Term Deferred Compensation
IRS Interest Expense
I FAS 123R - Stock Based Compensation. SFAS112 - Post Retirement Benefits
Provision For Rate Refunds
I Non-VEBA Pension and Benefits
. Linden Feeder Deposits
Delivery Accruals
Bonus Deferral
I Total Other Electric
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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 04/15/2009 2008104
FOOTNOTE DATA
Ending Balance
4,056,404.55
3,112,707.91
2,590,725.18
2,148,245.00
1,333,711.47
1,184,641.05
937,172.05
762,810.30
164,403.47
129,130.02
(56,181.86)
16,363,769.14
Ending Balance
4,929,292.29
2,996,869.81
1,829,071.70
2,090,777.00
2,316,810.74
1,044,455.76
5,217,171.07
662,313.05
0.00
(5,646.49)
(6,306.02)
21,074,808.91
Column: al§chedu/f!f'age; 2~~. Line No.: 7
(Note 2):
FASB 109 Accounting
FAS 158 - Pension
FAS 158 - Postretirement Plan
Minimum Pension Liabilty
Total Other
Beginning Balance
42,967,558.09
3,815,137.55
6,616,913.51
4,316,889.45
57,716,498.60
Ending Balance
44,340,912.95
61,943,744.74
10,863,821.80
5,589,976.57
122,738,456.06
~heciiiie Page: 234. Lin~N.~.L1L.
(Note 3):
Senior Management Security Plan
FAS115 SMSP Impairment
Micron-CIAC
Meridian Gold Contributions
Bridger Sierra Reserve-Legal Fee's
Loss on Pioneer Land Write-down
Seattle City Light-CIAC
Total Non Electric
Column: a
Beginning Balance
12,554,517.13
0.00
2,001,223.02
174,791.41
97,737.50
45,351.37
324.49
14,873,944.92
Ending Balance
12,912,429.52
2,669,975.82
1,764,125.52
152,678.89
97,737.50
45,351.37
0.00
17,642,298.62
Page 450.1IFERC FORM NO.1 (ED. 12-87)
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/04(2) OA Resubmission 04115/2009
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 1D-K Report Form filing, a specific reference to report form (i.e., year and
company title) may be reported in column (a) provided the fiscal years for both the 1D-K report and this report are compatible.
2. Entries in column (b) should represent the number of shares authorized by the articles of incorporation as amended to end of year.
Line Class and Series of Stock and Number of shares Par or Stated Call Price at
No.Name of Stock Series Authorized by Charter Value per share End of Year
(a)(b)(c)(d)
1 Account 201
2 Common Stock registered on New York 50,000,000 2.50
3 and Pacific Stock Exchange
4 Total Common Stock 50,000,000 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
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FERC FORM NO.1 (ED. 12-91)Page 250
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I FERC FORM NO.1 (ED. 12-SS)
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/Q4
(2) FiA Resubmission 04/15/2009
CAPITAL STOCKS (Account 201 and 204) (Continued)
3. Give particulars (details) concerning shares of any class and series of stock authorized to be issued by a regulatory commission
which have not yet been issued.
4. The identification of each class of preferred stock should show the dividend rate and whether the dividends are cumulative or
non-cumulative.
5. State in a footnote if any capital stock which has been nominally issued is nominally outstanding at end of year.
Give particulars (details) in column (a) of any nominally issued capital stock, reacquired stock, or stock in sinking and other funds which
is pledged, stating name of pledgee and purposes of pledge.
OUTSTANDING PER BALANCE SHEET HELD BY RESPONDENT Line(Total amount outstanding without reduction AS REACQUIRED STOCK (Account 217)IN SINKING AND OTHER FUNDS No.for amounts held by respondent)
Shares Amount Shares Cost Shares Amount(e)(f)(g)(h)(i)u)
1
39,150,812 97,877030 2
3
39,150,812 97,877,030 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
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Page 251
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/04
(2) DA Resubmission 04/15/2009
OTHER PAID-IN CAPITAL (Accounts 208-211, inc.)
Report below the balance at the end of the year and the information specifd below for the respective other paid-in capital accunts. Provide a
subheading for each accunt 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 entries effecting such
change,
(a) Donations Received from Stockholders (Account 208)-State amount and give brief explanation of the origin and purpose of each donation.
(b) Reduction in Par or Stated value of Capital Stock (Accunt 209): State amount and give brief explanation of the capital change which gave rise to
amounts reported under this caption including identifcation with the class and seris of stock to which related.
(c) Gain on Resale or Cancellation of Reacquired Capital Stock (Accunt 210): Report balance at beginning of year, credits, debits, and balance at end
of year with a designation of the nature of each credit and debit identified by the class and series of stock to which related.
(d) Miscellaneous Paid-in Capital (Account 211)-Classif amounts included in this accunt accrding to captions which, together with brief explanations,
disclose the general nature of the transactions which gave rise to the reported amounts.
I~ie 'f:r Ary)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 Capital
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
40 TOTAL
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FERC FORM NO.1 (ED. 12-87)Page 253
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Name of Respondent This (!0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/Q4
(2) DA Resubmission 04/15/2009
CAPITAL STOCK EXPENSE (Account 214)
1.Report the balance at end of the year of discount on capital stock for each class and series of capital stock.
2. If any change occurred during the year in the balance in respect to any class or series of stock, attach a statement giving particulars
(details) of the change. State the reason for any charge-off of capital stock expense and specify the account charged.
I Line Class and Series of Stock -ßãfance at End of Year
No.(a)(b)
1 Common Stock 2,096,925
2
3
4
5
6
7
8
9
10 Explanation of Changes during the year:
11
12
13
14
15
16
17
18
19
20
21
22 TOTAL 2,096,925
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I FERC FORM NO.1 (ED. 12-87)Page 254b
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/Q4(2) OA Resubmission 04/15/2009
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 authonzation numbers and dates.
3. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
4. For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate
demand notes as such. Include in column (a) names of associated companies from which advances were received.
5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
6. In column (b) show the principal amount of bonds or other long-term debt originally issued.
7. In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
8. For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
Indicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted.
9. Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year. Also, give in a footnote the date of the Commission's authorization of treatment other than as
specified by the Uniform System of Accounts.
Line Class and Series of Obligation, Coupon Rate Principal Amount Total expense,No,(For new issue, give commission Authorization numbers and dates)Of Debt issued Premium or Discount
(a)(b)(c)
1 Account 221:
2 First Mortgage Bonds:
3 5.50% Series due 2033 70,000,000 728,701
4
36,400 D
5
6 7,38% Series Due 2007 80,000,000
7
8 7.20% Series due 2009 80,000,000 572,2469
10 5.30% Series Due 2035 60,000,000 408,411 D
11 3,844,73912-
13 6.60% Series due 2011 120,000,000 860,50214
15 4.25%Series due 2013 70,000,000 641,20116374,500 D
17
18 4,75% Series due 2012 100,000,000 944,356191,047,617 D20
21 6.00% Series due 2032 100,000,000 1,069,35622543,244 D23
24 5.875% Series due 2034 55,000,000 585,75925383,322 D26
27 5.50% Series due 2034 50,000,000 746,961 D28524,41929
30 6.30% Series due 2037 1,495,79931273,721 D32
33 TOTAL 987,045,000 21,296,747
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FERC FORM NO.1 (ED. 12-96)Page 256 I
I Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/Q4
(2) DA Resubmission 04/15/2009
LONG-TERM DEBT (Account 221,222,223 and 224) (Continued)
10.Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Accunt 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 pnncipal 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 iong-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 Accunt 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 uuisian!J1ns LineNominal Date Date of (Total amount outstan ing without Interest for Year No.of Issue Maturity Date From Date To reduction for amounts held by Amount
(d)(e)(f)(g)
respy~dent)
(i)
1
2
05/01/03 04/01/33 05/01/03 03131133 70,000,000 3,850,000 3
4
5
1211/00 12101/07 12/01/00 12/01/07 -27,510 6
7
11123/99 12/01109 01/01/00 01/01/10 80,000,000 5,760,000 8
9
08/26/05 08/26/35 08/26/05 08/26/35 60,000,000 3,180,000 10
11
12
03/02/01 03/02/11 03/02/01 03/02111 120,000,000 7,920,00 13
14
05/01/03 10/01/13 05/01/03 09/29113 70,000,000 2,975,000 15
16
17
11/15/02 11/15/12 11/15/02 11/15/12 100,000,000 4,750,000 18
19
20
11/15/02 11/15/32 11/15/02 11/15/32 100,000,000 6,000,000 21
22
23
08116104 08/16/34 08116/04 08/16/34 55,000,000 3,231,250 24
25
26
03126/04 03/15/34 03/26/04 03/15/34 50,000,000 2,750,000 27
28
29
6122/07 6/15/2037 6/22/07 6/15/2037 140,000,000 8,820,000 30
31
32
1,264,917,727 66,145,498 33
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I FERC FORM NO.1 (ED. 12-96)Page 257
Name of Respondent This (lort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/Q4
(2) FiA Resubmission 04/15/2009
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 respec 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 Accunts.
Line Class and Series of Obligation, Coupon Rate Principal Amount Total expense,
No.(For new issue, give commission Authorization numbers and dates)Of Debt issued Premium or Discount
(a)(b)(c)
1 6.25% Series due 2037 1,141,489
2 266,188 D
3
4 Port of Morrow Variable due 2027 4,360,000 188,545
5
6 Humboldt Variable due 2024 49,800,000 1,697,856
7
8 Sweetwater Variable due 2026 116,300,000 820,043
9 471,252 D
10
11 6.025 % Series Due 2018 OPUC 08-1051PUC #30487 1,630,120
12
13 2008 Credit Facilty OPUC 07-151 IPUC #30294
14 Subtotal Account 221 955,460,000 21,296,747
15
16 Account 222 - Reaquired Bonds
17 Humbolt PC Revenue
18
19 Sweetwater PC Revenue
20 Subtotal Account 222
21
22 Account 223: Advances for Associated Companies
23
24 Account 224:
25 Bond Guarantee - American Falls 19,885,000
26
27 REA Notes
28
29 Note Guarantee - Milner Dam 11,700,000
30 Subtotal Account 224 31,585,000
31
32
33 TOTAL 987,045,000 21,296,747
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FERC FORM NO.1 (ED. 12-96)Page 256.1 I
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Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/04
(2) FiA Resubmission 04/15/2009
LONG-TERM DEBT (Account 221, 222, 223 and 224) (Continued)
10.Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term
advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13. If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose of the pledge.
14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of
year, describe such securities in a footnote.
15. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on
Long-Term Debt and Account 430, Interest on Debt to Associated Companies.
16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
AMORTIZATION PERIOD outstannins LineNominal Date Date of (Total amount outstan ing without Interest for Year No.of Issue Maturity Date From Date To reduction for amounts held by Amount
(d)(e)(f)(g)
resP?~fent)
(i)
10/18/07 10/15/2037 10/18/07 10/15/2037 100,000,000 6,250,000 1
2
3
05/17/00 02/01/27 05/17/00 02/01/27 4,360,000 135,091 4
5
10/22103 12/01/24 11/01/03 12/01/24 49,800,000 693,790 6
7
10/3/06 7/15/26 10/3/06 7/1512026 116,300,000 2,030,166 8
9
10
7/10/08 7/15/18 7/0108 7/15/08 120,000,000 3,434,250 11
12
4/1/08 3/31/09 4/1/08 3/31/09 166,100,000 4,393,600 13
1,401,560,000 66,145,637 14
15
16
-49,800,000 17
18
-116,300,000 19
-166,100,000 20
21
22
23
24
04/26/00 2/1/25 19,885,000 25
26
-139 27
28
02/10/92 9,572,727 29
29,457,727 -139 30
31
32
1,264,917,727 66,145,498 33
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Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/Q4
(2) DA Resubmission 04/15/2009
RECONCILIATION OF REPORTED NET INCOME WITH TAXBLE INCOME FOR FEDERAL INCOME TAXES
1. Report the reconciliation of reported net income for the year with taxable income used in computing Federal income tax accruals and show
computation of such tax accruals. Include in the reconciliation, as far as practicable, the same detail as furnished on Schedule M-1 of the tax return for
the year. Submit a reconciliation even though there is no taxable income for the year. Indicate clearly the nature of each reconcilng amount.
2, If the utility is a member of a group which files a consolidated Federal tax return, reconcile reported net income with taxable net income as if a
separate return were to be field, indicating, however, intercompany amounts to be eliminated in such a consolidated return. State names of group
member, tax assigned to each group member, and basis of allocation, assignment, or sharing of the consolidated tax among the group members.
3. A substitute page, designed to meet a particular need of a company, may be used as Long as the data is consistent and meets the requirements of
the above instructions, For electronic reporting purposes complete Line 27 and provide the substitute Page in the context of a footnote.
Line Particulars (Details)Amount
No,(a)(b)
1 Net Income for the Year (Page 117)94,114,928
2
3
4 axable Income Not Reported on Books
5 68,986,908
6
7
8
9 Deductions Recorded on Books Not Deducted for Return
10 23,313,008
11
12
13
14 Income Recorded on Books Not Included in Return
15 3,804,84
16
17
18
19 Deductions on Return Not Charged Against Book Income
20 58,362,619
21
22
23
24
25
26
27 Federal Tax Net Income 77,621,363
28 Show Computation of Tax:
29 Tenative Federal Tax (g35%27,167,477
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
FERC FORM NO.1 (ED. 12-96)Page 261
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Name of Respondent This Report is:Date of Report YearlPeriod of Report
(1) is An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2009 2008/Q4
FOOTNOTE DATA
Schedule page:-261_LineNo.: 5 Column: b
004003-CONSTRUCTION ADV-252
0040Q4-CIAC AS TAXBLE INC CLOSED TO PLANT
004005-AVOIDED COST INT CAP
004006-RETIREMENTS-RECORD TAX GAINILOSS
004010-EMISSION ALLOWANCE-254.409-411
004013-CIAC AS TAXBLE INC IN ACCT 107
004018-L1NDEN FEEDER DEPOSITS-253.206
004020-ENGINEERING FEES-GLOSED TO PLANT
004021-ENGINEERING FEES-IN ACCT 107-FED ONLY
004501-ROYALTY INCOME BTL
004506-CIAC-MERIDIAN GOLD
004507 -CIAC-MICRON-DRAM
004512-CIAC-SEATTLE CITY LIGHT
Total
(2,475,768)
29,000,000
4,940,208
(2,000,000)
40,669,016
(1,063,720)
(420,523)
1,620,274
(716,724)
100,000
(56,560)
(608,469)
(826)
68,986,908
- .-----. ---~-~-irShedule Page: 261 Line No.: 10 Column: b
005001-BAD DEBT EXPENSE
005010-SFAS 112-POST-EMPLY BEN 182/253
005014-0VERACCRUED VACATION-ACCT 242
005017-INJURIES & DAMAGES
005019-DIRECTORS FEES DEF
005022-CAPITALIZED OVERHEADS
005024-MEALS (50% NON-DEDUCTIBLE) CHRGD TO R.E.
005025-MILNER FALLING WATER - REV ACCRL
005027-AMORTIZATION OF ACCOUNT 114
005028-0REGON OPER PROPERTY TAX ADJ
005033-NONVEBA PEN&BEN-Acct 228
005035-PCA EXPENSE DEFERRAL
005043-AMERICAN FALLS - FALLING WATER CONTRACT-FT
005047-0THER EMPLOYEE'S LT DEFERRED COMP-228
005050-186-BAD DEBT RESERVE-FINANCING PRGMS
005052-AMORTIZATION OF ACCOUNT 181
005053-FAS 123R-STOCK BASED COMPENSATION
005054-IPUC GRID WEST LOANS-ACCT 182
005055-0PUC GRID WEST LOANS-ACCT 182
005056-FERC GRID WEST EXP-ACCT 182
005057-INTERVENER FUNDING ORDERS-ACCT 182
005058-FIXED COST ADJUSTMENT (FCA)-ACCT 182
005059-PS & I COSTS-COAL & CHP PLANTS-WRITE OFF
005060-0REGON-PCAM (POWER COST ADJ MECHANISM)
005501-SEC PLAN-NET INS COSTS
005503-128-EDC-UNRLZD GNILS FRM RABBI TRUST
005504-NONDEDUCTIBLE POLITICAL EXP-426.4
005505-SEC PLAN-BENEFIT ACCR
005516-NONDEDUCTIBLE POLITICAL EXP-O&M ACCTS
005531-RATE CASE DISALLOWANCES-REVERSE AMORT
005532-DELIVERY ACCRUALS-253.550
005539-FAS115 SMSP IMPAIRMENT
Total
418,877
(358,576)
257,944
1,253,352
(27,556)
(12,000,000)
600,000
(619,723)
(22,723)
(37,557)
(257,059)
(51,056,694)
219,181
(1,948,212)
(4,461)
140,900
2,542,842
186,435
(4,588)
(61,000)
(24,703)
(3,761,843)
97,853
(5,399,657)
(302,480)
1,141,566
1,273,314
1,983,519
100,000
(296,299)
(91,775)
6,829,456
(23,313,008)
IFERC FORM NO.1 (ED. 12-87) Page 450.1
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Name of Respondent This Report is:Date of Report Year/Perid of Report
(1) 2S An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2009 2008/Q4
FOOTNOTE DATA
~chedule Page: 261 Line No.: 15 Column: b
007009-PROVISION FOR RATE REFUNDS-ACCT 229
007501-REVERSE EOUITY EARNINGS OF SUBSÐlARIES
007502-ALLOWANCE FOR OFUDC
007503-ALLOWANCE FOR BFUDC
007509-SECURITY PLAN-INSURANCE PROCEEDS
007514-COLl-INSURANCE PROCEEDS
007518-IRS INTEREST INCOME
Total
(10,947,688)
4,121,080
3,141,017
7,080,140
628,234
170,651
(388,588)
3,804,846
Isched"ìePage: 261 Line' No.: 20 Column: b ~. ~. - .._~~~---- ~-----
i
008001-VEBA-POST RET BNFTS-TRUST-ACCT 228
008009-DEPR FOR TAX GT OR LT BOOK
008016-VEBA-POST RET BNFTS-TRUST-MEDICARE PART 0
008020-CONSERVATION PROGRAMS
008025-MANUFACTURING DEDUCTION
008027-NEVADA OPERATING PROPERTY TAX ADJ
008034-REMOVAL COSTS
008035-REPAIR ALLOWANCE
008038-0REGON EXCESS PWR SUPPLY COSTS
008039-ST TAX-NOT DEDUCTED ON PRIOR RETURN
008041-AM FALLS - UNAMORTIZED DEBT EXP
008042-GAIN/LOSS ON REACQUIRED DEBT-FT
008059-SFTW COSTS-MISC-107-FED ONLY
008072-INTANGIBLE ASSET-LABOR DEDUCT-107-FED ONLY
008074-INCREMENTAL SECURITY COSTS DEDUCTED
008077-PP INS & OTR EXP (1 YR OR LESS)-165
008501-COLl-TAX ADJ FROM BOOKS
008504-0REGON NONOP PROPERTY TAX ADJUST
008508.DEPR ADJ - NONOP - OTHER PROPERTY - NEW
008703-IPCO -162 (M) $1m THRESHOLD
ON10016-DIV PAID OED PUB UTIL
IRS INTEREST EXPENSE
STATE INCOME TAX DEDUCTED ON FEDERAL RETURN
Total
(2,232,734)
44,604,054
646,000
(3,242,604)
1,726,426
24,642
8,439,209
7,000,000
(1,158,317)
(13,168)
(47,999)
(707,798)
1,000,000
2,532,000
(68,794)
856,870
(186,662)
35
(326,269)
(674,346)
300,000
146,994
(254,920)
58,362,619
I FERC FORM NO.1 (ED. 12-87)Page 450.2
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/Q4
(2) n A Resubmission 04/15/2009
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during
the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the
actual, or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.)
Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes.
3. Include in column (d) taxes charged during the year, taxes charged to operations and other accunts through (a) accruals credited to taxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other
than accrued and prepaid tax accounts.
4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertined.
ILine Kind ofTax BALANCE AT BEGINNING OF YEAR ,iaxes i¡s~~p Adjust-ChargedNo.(See instruction 5)Taxes Accrued Prepai.d Taxes ~nng ~ring ments(Account 236)(Include in Account 165)ear ear
(a)(b)(c)(d)(e)(f)
1 Federal:
2 Income -2,776,064 -5,158,387 36,345,148
3 Social Security - (FOAB)417,170 11,476,651 11,893,412
4 Unemployment 43,023 124,895 167,954
5 Subtotal Federal -2,315,871 6,443,159 48,406,514
6
7 State of Idaho:
8 Property 5,703,852 225 10,969,659 11,694,806
9 Non-Operating 15,963 29,992 30,959
10 Income -1,461,670 -3,790,374 -1,454,04
11 KWH 300,717 1,559,972 1,765,494
12 Unemployment 19,721 175,196 188,713
13 Regulatory Commission 1,728,039 1,728,039
14 Business License - Sho Ban 150 150 150
15 Subtotal Idaho 4,578,583 375 10,672,634 13,954,117
16
17 State of Oregon
18 Property 1,007,104 2,052,307 2,089,865
19 Non-Operating Property 719 1,473 1,508
20 Income -66,941 118,545 264,053
21 Regulatory Commission 119,843 119,843
22 Unemployment 899 12,554 13,467
23 Franchise 125,213 541,650 529,157
24 Subtotal Oregon 59,171 1,007,823 2,846,372 3,017,893
25
26 State of Montana:
27 Property 46,418 198,721 146,009
28 Subtotal Montana 46,418 198,721 146,009
29
30 State of Nevada:
31 Property 419,217 883,099 907,740
32 Business Tax 100 100
33 Subtotal Nevada 419,217 883,199 907,840
34
35 State of Wyoming
36 Corporate License .3,075 3,075
37 Property 478,308 1,027,339 991,977
38 Subtotal Wyoming 478,308 1,030,414 995,052
39 Other States Income -1,351 54,853 21,768
40 Payroll Adjustment -11,789,296
41 TOTAL 2,845,258 1,427,415 10,340,056 67,449,193
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FERC FORM NO.1 (ED. 12-96)Paae 262
I Name of Respondent This i!0rt Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/Q4
(2) 0 A Resubmission 04/15/2009
I
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued)
5. If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year,
identifying the year in column (a).
6. Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments
I
by parentheses.
7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwse pending
transmittal of such taxes to the taxing authority.
8. Report in columns (i) through (I) how the taxes were distributed. Report in column (I) only the amounts charged to Accounts 408.1 and 409,1
pertaining to electric operations. Report in column (I) the amounts charged to Accounts 408.1 and 109.1 pertining to other utility departents and
I amounts charged to Accounts 408.2 and 409.2. Also shown in column (I) the taxes charged to utilty plant or other balance sheet accunts.
9. For any tax apportioned to more than one utilty department or account, state in a footnote the basis (necessity) of apportioning such tax.
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BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Line
(Taxes accrued Preid T"", ~ EM"'';"'''' lie""AOJustments to Ket.Other No.
Account 236)(Inci. in Account 165) (Account 408.1,409.1) (Account 409.3)Earnings (Account 439)
(g)(h) (i) ü)(k)(I)
1
I -44,279,599 10,945,612 ~409 11,476,651 3
-36 124,895 4
I -44,279,226 22,547,158 -16,103,999 5
6
7
I 4,978,404 -75 10,969,659 8
14,996 ~-3,798,000 -4,350,732
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95,195 1,559,972 11
6,204 175,196 12
1,728,039 13
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150 150 14
1,296,799 75 10,082,284 590,350 15
16
17
1,044,661 2,052,307 18
754 ~-212,449 89,700 20
119,843 21
-14 12,554 22
137,706 541,650 23
-74,757 1,045,415 2,816,054 30,318 24
25
26
99,130 198,721 27
99,130 198,721 28
29
30
443,859 883,099 31
100 32
443,859 883,199 33
34
35
3,075 36
513,670 1,027,339 37
513,670 1,030,414 38
31,734 42,742 ~-11,789,296 40
-42,412,650 1,489,349 25,811,276 -15,471,220 41
FERC FORM NO.1 (ED. 12-96)Page 263
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I Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ó An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2009 2008/Q4
FOOTNOTE DATAI
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~cheduletlj~1~2~__Line No.: 1 Column: i ------.- _._ ......_._
This footnote is for the total of Column I on page 263. The total of column I and the
amounts associated with accounts 408.1 & 409.1 in column I should total back to the sum of
Lines 14,15 & 16 on page 114. For the year 2008 this cross-check will not work as the
total of lines 14-16 on page 114 is $13,474,751 lower than line 41 page 263. This
difference represents an amount booked for the accounting of FIN #48. When FIN #48 was
booked it does use account 409.1, however the other side is not associated with accounts
236 or 165. The offset resides in FERC accounts 190xxx and various other accounts.
Therefor~_t~~~mount J=_0.E.Fi~J48 show up on page 114 but will not be on pages 262& 263.
'Schedule Page: 262 Line No.: 2 Column: i
Account 409.2 '$ 3,618,591
134.1 (19,107,159)234 (75,431)
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Total $ (16, 103, 999)
:ScheC!ci/e Pa.ge: 262 Line No.: 9 Column: iAccount 408. $ ---"2g;9~2.~=~=~---
iSchiú:J'¡iePage: 262 ---Line No.: 10 Column: i
Account40§.2 $ 573,9-28234 (13,570)
Total $ 560,358
§clJe~ule F'~: 262Account 408.2.'._._- - _.~.-
Schedule Page: 262
Account 409.2 -
234
Line No.: 19 Column: i
$i,473
Line No.: 20 Column: i
-- -$--- . 29 ,535-~---'-
( 690)
Total $28,845
. --"-----,-
Schedule Page: 262Account4Ù9.2
234
Line No.: 39 Column: i
"':$ ---1'2--41---------
(230)
Total $12,111
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IFERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2008/Q4
Date of Report
(Mo, Da, Yr)
04/15/2009
ACCUMULA ED DEFERRED INVESTMENT TAX REDITS (Account 255)
Report below information applicable to Account 255. Where appropriate. segregate the balances and transactions by utility and
nonutilityoperations. Explain by footnote any correction adjustments to the account balance shown in column (g).lnclude in column (i)
the average period over which the tax credits are amortized.ine Account alance at eginning
No Subdivisions of Year. (a¡ (b)
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1 Electric Utility
23%
34%
47%
510%
611%
7 Other-State
8 TOTAL
9 Other (List separately
and show 3%, 4%, 7%,
10% and TOTAL)
10 Line 6 Col A 11 %
11
12 State of Idaho
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
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1,080,786 139,291 I
30,474,981
1,347,508
38,097,435
71,000,710
411,4 5,759,370
5,759,370
411.4
1,751,095
27,085
1,572,532
3,490,003
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38,097,435 411.4 5,759,370 411.4 1,572,532
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FERC FORM NO.1 (ED. 12-89)Page 266 I
I Name of RespondentIdaho Power Company
ACCUMULATED D
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I Line
No.
I 941,495 7,76
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28,723,886
1,320,423
42,284,273
73,270,077
17.4
49.75
24.23
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-~--- - - - ----------~~------
Date of Report
(Mo, Da, Yr)
04/15/2009
S (Account 255) (continued)
ADJUSTMENT EXPLANATION
Year/Period of Report
End of 2008/Q4
1
2
3
4
5
6
7
8
9
I 42,284,273
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IFERC FORM NO.1 (ED. 12-89) Page 267
10
11
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
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44
45
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47
48
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Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/Q4
(2) FiA Resubmission 04/15/2009
OTHER DEFFERED CREDITS (Account 253)
1.Report below the particulars (details) called for concerning other deferred credits,
2.For any deferred credit being amortized, show the period of amortization,
3.Minor items (5% of the Balance End of Year for Account 253 or amounts less than $10,000, whichever is greater) may be grouped by classes.
Line Description and Other Balance at DEBITS Balance at
No.Deferred Credits Beginning of Year Contra Amount Credits End of Year
(b)
Account
(a)(c)(d)(e)(f)
1 Bureau of Land Mngt Rents/ROW 5,175,984 107,232 1,557,401 7,057,048 10,675,631
2
3 Point to Point Transmission Study 4,262,458 186,242 7,067,645 5,241,440 2,436,253
4
5 FTV 5,666,027 454 400,000 639 5,266,666
6
7 Linden Feeer 420,523 242 420,523
8
9 SWIP Deposit 1,500,000 186,4211 6,500,000 5,940,000 940,000
10
11 Fin 48 -9,169,981 various 220,586 9,390,567
12
13 Fin 48 Interest -802,050 various 282,084 1,084,134
14
15 Sho Ban Trans ROW 307,500 242 15,000 292,500
16
17 Delivery Accruals 258,432 107,401 1,037,977 978,509 198,964
18
19 Customer Level Pay 1,826,635 142 1,444,094 671,963 1,054,504
20
21 US Airforce Photovoltaic Generator 288,738 415 298,556 41,750 31,932
22
23 Milner Fallng Water 4,069,776 186 3,226,139 1,542,780 2,386,417
24
25 Postretirement Benefits 3,030,160 401 358,576 2,671,584
26
27 PURPA Cogen Deposit 8,000 8,000
28
29 Directors Deferred Compensation 4,004,241 232 637,440 609,883 3,976,684
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47 TOTAL 20,838,443__23,466,021 32,566,713 29,939,135
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IERC FORM NO.1 (ED. 12-94)Page 269
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2008/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2009
ACCUMULATED DEFFERED INCOME TAXES - OTHER PROPERTY (Account 282)
1. Report the information called for below concerning the respondent's accunting for deferred income taxes rating to property not
subject to accelerated amortization
2. For other (Specify),include deferrals relating to other income and deductions.
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Account Balance at
Beinning of Year Amounts Debited
to Account 410.1
(c)
Amounts Credited
to Account 411.1
(d)
ILine
No.
CHANGES DURING YEAR
(a)(b)I1 Account 282
2 Electric
3 Gas
4 Other
5 TOTAL (Enter Total of lines 2 thru 4)
6 Non-Operating Property
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
- -- - - ------ -- ~~~-~--
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227,092,879 26,585,367 7,254,569
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7,254,569
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227,092,879
244,578
308,290,095
26,585,367
535,627,552 26,585,367 7,254,569 I- - ---- - -- - -----~-----~~
453,140,171
82,487,381
26,429,765 7,233,367
I155,602 21,202
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NOTES
FERC FORM NO.1 (ED. 12-96)Page 274
I Name of RespondentIdaho Power Company
I
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2009
ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282) (Continued)
3. Use footnotes as required.
Year/Period of Report
End of 2008/Q4
I CHANGES DURING YEARAmounts Debited Amounts Credited
to Account 410.2 to Account 411,2
I
ADJUSTMENTS
I
Debits
Amount
Balance at
End of Year
Line
No.
I
I
-127,55
6,676,39 182 32,268,65
5
6
7
8
9
o
490,549,18 11
89,756,85 12
-127,555 6,676,392 32,268,65~-~----~~~------~~--~------~-- ---- ~-~--~- ---~ -- ~ ---- -------
-107,00
-20,55
98,165
18,858
6,661,848
14,54
25,079,631
7,189,02I
I NOTES (Continued)
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I FERC FORM NO.1 (ED.
12-96)Page 275
This Page Intentionally Left Blank
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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 04/15/2009 2008/Q4
FOOTNOTE DATA
I
I
S~lJedule Elge: 274 Lj!!e Ng~: 2 Column: b_Page 274 & 275 - Accumulated Deferred Income Taxes - Other
I
Property (Account 282)
Changes during Year Adjustments Adjustments
2008 Debits Credits 2008
Beginning DR to CRto 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 j k
Line Accelerated Depreciation
12:215,117,208 30,779,455 7,174,557 238,722,106
Intangible Asset-Labor
Deduction 12,252,496 637,828 12,890,324
FERC Jurisdictional
7,818,502 (7,818,502)0
N. Valmy
657,266 76,500 580,766
Bridger
120,057 102,400 17,657
Engineering Fees in Acct
107 (42,828)30,201 273,414 (286,041)
Misc Softare Develop
Costs 877,669 (383,042)494,627
Taxable CIAC in CWIP
Bal.19,707,491)3,339,427 (372,302)(5,995,762)
TOTAL Line 2 0,00 0.00 0.00227,092,879 26,585,367 7,254,569 -246,423,677
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IFERC FORM NO.1 (ED. 12-87) Page 450.1
I
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2008/Q4 IThis ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2009
ACCUMULATED DEFFERED INCOME TAXES - OTHER (Account 283)
1. Report the information called for below concerning the respondent's accounting for deferred income taxes relating to amounts
recorded in Account 283.
2. For other (Specify),include deferrals relating to other income and deductions.
I
(a)
Balance at
Beginning of Year
(b)
Iline
No.
Account
1 Account 283 I
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 Total of lines 9,17 and 18)
20 Classification of TOTAL
21 Federal Income Tax
22 State Income Tax
23 Local Income Tax
455,886
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39,995,137 27,581,705
7,683,164 5,298,513 I
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4
5
6
7
7,309,438
46,712,004
8,973,482
NOTES
FERC FORM NO.1 (ED. 12-96)Paae 276
I Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2008/Q4
This ~ort is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2009
ACCUMULATED DEFERRED INCOME TAXES - OTHER (Account 283) (Continued)
I 3. Provide in the space below explanations for Page 276 and 277. Include amounts relating to insignificant items listed under Other.4. Use footnotes as required.
I ADJUSTMENTS
I
Balance at
End of Year
(k)
Line
No.
I
62,718,244
I
364,179
364,179
62,388,995
62,388,995
69,334,254
132,052,498
4
5
6
7
8
9
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I------~--~~---~---~-~-----------~-
-101,368
-19,473
407,172
78,219
305,501
58,678
52,335,264
10,053,732
11
12
13
14
15
16
17
-150,344 18
131,902,154 19
°
110,646,659 21
21,255,495 22
23
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I -120,841
-120,841
485,389
485,389 364,179 62,388,995
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r~-- --~~----.--~----~------- ------ -------- ---~---- ~ --
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NOTES (Continued)
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I FERC FORM NO.1 (ED. 12-96)Page 277
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 04115/2009 2008/Q4
FOOTNOTE DATA
W'hedule Page: 276- Line No.: 3 . -Co¡iimii:~_~~-
Page 276 & 277 - Accumulated Deferred Income Taxes-
Other (Account 283)
Changes during Year Adjustments Adjustments
2008 Debits Credits 2008
Beginning DR to CR to DR CRto Acct.Acct.Ending
to
Line Account Balance 410.1 411,1 410.2 411.2 cr Amount dr Amount Balance
No.(a)b c d e f a h i i kine3:PCA Expense Deferral 42,667,139 44,993,134 31,606,268 56,054,005
Conservation Programs 3,169,251 0 1,267,696 1,901,555
Oregon Excess Power
Costs 2,340,811 501,408 1,301,44 1,540,773
Oregon PCAM 0 2,110,996 2,110,996IPUC Grid West Loans 291,548 0 72,887 218,661
Incremental Security 26,895 0 26,895
Costs
FERC Grid West 118,113 40,228 16,380 141,961Expense
OPUC Grid West Loans 23,616 1,794 0 25,410Intervenor Funding 20,566 26,707 17,050 30,223Orders
Fixed Cost Adjustment (838,745)0 (1,470,693)631,948PS & I Costs - Coal &
CHP Plants-Write Off 100,968 4,033 42,289 62,712
TOTAL Line 3 47,920,162 47,678,300 32,880,218 -62,718,244
---
~------------.._--"--_...__.._-~_.._---_.._._---'-i¡Schedule Page: 276 Line No.: 8 Column: a
¡Line 8:FAS 158 - Pension 3,815,138 190 0 190 58,128,607 61,943,745
FAS 158 - Postretirement 3,130,106 186/190 o 186/190 4,260,388 7,390,494Plan
Unrealized gains on Mkt 364,194 219 364,179 219 -15Securities..
TOTAL Line 8 7,309,438 ----364,179 62,388,995 69,334,254
---~--------- ----._-.- _.~_._._---------- --_..-_._.-.--~--_.-.. -_.----.---. .._._-_._--_.__._--_.'----,--_.__. .
S~IJ~dule Page: 276 Line No.: 18 Column: a ~~_..._------~- _.' '--~ -_._----_........_..Line Advance Coal Royalties 247,769 31,06 39,095 239,738
18:
IRS Interest Income 151,918 (151,918)0 0
Oregon Non-Op Prop Tax 282 13 0 295Adj
Unrealized Gain/Loss From 55,917 0 446,295 (390,377)Rabbit Trust
TOTAL Line 18 455,886 (120,841)485,390 -(150,344)---
IFERC FORM NO.1 (ED. 12-87)Page 450.1
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Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/Q4
(2) OA Resubmission 04/15/2009
OTHER REGULATORY LIABILITIES (Account 254)
1. Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if
applicable.
2. Minor items (5% of the Balance in Account 254 at end of penod, or amounts less than $50,000 which ever is less),may be grouped
by classes.
3. For Regulatory Liabilities being amortized, show period of amortization.
Balance at Begining DEBITS Balance at EndLineDescription and Purpose of of Current of Current No.Other Reguiatory Liabilties QuarterlYear ~ccount Amount Credits QuarterlYearCredited
(a)(b)(c)(d)(e)(f)
1 Market to Market Short Term 553,042 175 7,941,395 8,040,43 652,080
2
3 Demand Side Manaement Rider 29026 1,483,074 various 24,033,666 22,550,59
4
5 Demand Side Management Rider OR 410,225 various 668,305 45,90 196,27
6
7 FAS 133 - Market to Market 33,160 175 4,072,587 4,039,42
8
9 Fixed Cost Adjustment - 30267 2,145,03 254,4074 7,050,779 4,905,37
10
11 Fixed Cost Adjustment- Prior Yr Def 254,4074 1,295,779 2,400,55 1,104,779
12
13 SPA Credit-Residential - Idaho 14,956 254,440 2,265 1,36~14,055
14
15 SPA Credit-Residential - Oreon (178,685)143 536,273 714,95!
16
17 SPA Creit-Farm -Idaho 985,918 442 991,395 5,47
18
19 SPA Credit-Farm - Oregon 28,538 442 28,695 15
20
21 Emission Sales IEEP- Order #30529 500,001 500,000
22
23 Unfunded Accumulated Deferred Income Tax 42,967,558 1,373,35 44,340,913
24
25 ID WAQC Carryover- Order # 29505 1,97 1,977
26
27 Asset Retirement Oblication - Removal Cost 155,313,605 108 42,269 1,56,14(156,837,476
28
29
30
31
32
33
34
35
36
37
38
39
40
41 TOTAL 203,756,794 46,663,408 46,554,721 203,648,107
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I FERC FORM NO. 1/3.Q (REV 02-04)Page 278
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/Q4
(2) fjA Resubmission 04/15/2009
ELECTRIC OPERATING REVENUES (Accunt 400)
1. The following instructions generally apply to the annual version of these pages. Do not report Quarterly data in columns (c). (e). (f). and (g), Unbiled revenues and MWH
related to unbiled revenues need not be reported separately as required in the annual version of these pages.
2, Report below operating revenues for each prescribed acunt, and manufared gas revenues in total.
3. Report number of customers, columns (f) and (g). on the basis of meter. in addition to the number of flat rate accunts; except that where separate meter readings are adde
for billng purposes, one customer should be counted for each group of meters added. The -average number of customers means the average of twelve figures at the close of
each month.
4. If increases. or decreases from previous period (columns (c).(e), and (g)), are not derived from previously reported figures, explain any inconsistencies in a footnote.
Line Title of Account Oprating Revenues Year Operating Revenues
No.to Date Quarterly/Annual Previous year (no Quarterly)
(a)(b)(c)
1 Sales of Electricity
2 (440) Residential Sales 353,261,718 308,207,698
3 (442) Commercial and Industrial Sales
4 Small (or Comm.) (See Instr, 4)305,854,293 256,206,389
5 Large (or Ind.) (See Instr, 4)122,302,388 101,409,337
6 (444) Public Street and Highway Lighting 2,892,343 2.479,808
7 (445) Other Sales to Public Authorities
8 (446) Sales to Railroads and Railways
9 (448) Interdepartmental Sales
10 TOTAL Sales to Ultimate Consumers 784,310,742 668,303,232
11 (447) Sales for Resale 121,428,825 154,948,157
12 TOTAL Sales of Electricity 905,739,567 823,251.389
13 (Less) (449.1) Provision for Rate Refunds 9,979,836 1,075,534
14 TOTAL Revenues Net of Provo for Refunds 895,759,731 822,175,855
15 Other Operating Revenues
16 (450) Forfited Discounts
17 (451) Miscellaneous Service Revenues 3,669,976 4,050,513
18 (453) Sales of Water and Water Power
19 (454) Rent from Electric Propert 18,889,639 19,035,198
20 (455) Interdepartmental Rents
21 (456) Other Electric Revenues 19,432,928 13,910,578
22 (456.1) Revenues from Transmission of Electricity of Others 18,323,290 16,229,091
23 (457.1) Regional Control Service Revenues
24 (457.2) Miscellaneous Revenues
25
26 TOTAL Other Operating Revenues 60,315,833 53,225,380
27 TOTAL Electric Operating Revenues 956,075,564 875,401,235
FERC FORM NO. 1/3.Q (REV. 12-05)
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Page 300 I
I Name of Respondent
Idaho Power Company
I
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2009
ELECTRIC OPERATING REVENUES (Accunt 400)
5. Commercial and industrial Sales, Accunt 442, may be classified accrding 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 Accunt 442 of the Uniform System of Accunts, Explain basis of classification
in a footnote.)
6, See pages 108-109, Important Changes During Period, for important new terrory added and important rate increase or decreases.
7, For lines 2,4,5,and 6, se Page 304 for amounts relating to unbiled revenue by accounts.
8, Include un metered sales. Provide details of such Sales in a footnote.
Year/Period of Report
End of 2008/Q4
I
I MEGAWATI HOURS SOLD
Year to Date Quarterly/Annual Amount Previous year (no Quarterly)(d) (e)
AVG.NO, CUSTOMERS PER MONTH Line
Current Year (no Quarterly) Previous Year (no Quarterly) No.(n (g)
I
I 5,860,422
3,355,202
30,833
5,831,537
3,453,633
29,489
80,636
122
1,257
78,670
126
1,012
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I 14,543,714
2,047,603
16,591,317
14,541,825 484,535 477,094
2,743,647
17,285,472 484,535 477,094
17,285,472 484,535 477,094
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16,591,317
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I Line 12, column (b) includes $
Line 12, column (d) includes
6,080,350 of unbiled revenues.
-4,999 MWH relating to unbiled revenues
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I FERC FORM NO. 113-Q (REV. 12.(5)Page 301
4
5
6
7
8
9
10
11
12
13
14
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/04
(2) DA Resubmission 04/15/2009
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricit 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 accunt, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bils rendered during the year divided by the number of billng periods during the year (12
if all bilings are made monthly),
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbiled revenue as of end of year for each applicable revenue accunt subheading.
..ine I\lUmDer ano I lle or Kate scneauie Mvvn .,010 l'evenue l\verage Numoer ~vvnßI ,?aies KKrJ~isircr
No.ofC~~omers Per ~ustomer(a)(b)(c)e)(f)1 440 - Residential Sales:
2 01 - Residential 5,277,646 348,722,617 402,382 13,116 0.0661
3 04 - Residential - EW 900 57,850 56 16,071 0.0643
4 05 - Residential - TOO 1,289 83,747 82 15,720 0,0650
5 15 - Dusk to dawn lighting 2,502 476,724 0.1905
6 Unbiled Revenues 14,920 3,920,780 0.2628
7 Total 440 5,297,257 353,261,718 402,520 13,160 0.0667
8
9 442-Commercial & Industrial Sales
10 07 - General service 188,765 15,426,300 32,264 5,851 0.0817
11 09 - General service 422,850 18,115,721 159 2,659,434 0.0428
12 09 - General service 3,315,897 163,806,595 28,635 115,799 0.0494
13 09 - General service 2,788 117,478 2 1,394,000 0.0421
14 15 - Dusk to Dawn Light 3,825 648,274 0.1695
15 19 - Uniform rate contracts 2,148,969 80,861,009 113 19,017,425 0.0376
16 19 - Uniform rate contracts 7,84 330,453 1 7,844,000 0,0421
17 19 - Uniform rate contracts 151,643 5,133,221 5 30,328,600 0,0339
18 24 - Irrigation Pumping 1,921,607 105,689,562 18,401 104,429 0.0550
19 40 - General service 14,051 871,726 1,178 11,928 0.0620
20 Commercial & Industrial & Unbil 1,037,385 37,156,342 0.0358
21 Total 442 9,215,624 428,156,681 80,758 114,114 0.0465
22
23 444 - Public Street Lighting:
24 40 - General service 2,633 163,839 742 3,549 0.0622
25 41 - Street lighting 24,224 2,561,549 237 102,211 0.1057
26 42 - Traffc control lighting 3,976 166,955 278 14,302 0.0420
27 Total 444 30,833 2,892,343 1,257 24,529 0.0938
28
29
30
31
32
33
34
35
36
37
38
39
41 TOTAL Biled 14,548,713 778,230,392 484,53~30,026 0.053542Total Unbiled Rev.(See Instr. 6)-4,999 6,080,350 0 0 -1.2163
43 TOTAL 14,543,714 784,310,742 484,535 30,016 0.05391
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FERC FORM NO.1 (ED. 12-95)Page 304 I
I Name of RespondentIdaho Power Company
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) riA Resubmission 04/15/2009
SALES OF ELECTRICITY BY RATE SCHEDULES
Year/Period of Report
End of 2008/Q4
11. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh percustomer, 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
I 300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
I customers.
4, The average number of customers should be the number of bils rendere during the year divided by the number of biling 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 revenue biled pursuant thereto,
I 6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line Numoer ana IllIe or l"aie Scneauie Mvvn ;:010 l"evenue Average NumoerNo. (a) (b) (c) of cu(~\omers ~VVn_OTyaleSPer Ci.stomer
(e)
ryrA~'S~kr
(f)
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40
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I 14,548,71~
-4,999
14,543,714
778,230,392
6,080,350
784,310,742
Page 304
484,535
o
484,535
30,026
°
30,016
0.0535
-1.2163
0,0539
41 TOTAL Biled
42 Total Unbiled Rev.(See Instr. 6)
I 43 TOTALFERC FORM NO.1 (ED. 12-95)
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 2008/04
(2)o A Resubmission 04/15/2009
. SALES FOR RESALE (Account 447)
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this service in its system resource planning). In addition, the 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 availability 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" 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 Affliations)Classifi-Schedule or Monthly iIing lwera~e Avera~cation Tariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Raft River Rural Electric RO V6-9.433 9.433 8.145
2 Raft River Rural Electric RO V6-nla n/a n/a
3
4 Arizona Public Service Co.SF WSPP n/a n/a n/a
5 Avista Corp. - WWP Div.SF WSPP n/a n/a n/a
6 Barclays Bank PLC SF WSPP n/a n/a n/a
7 Bear Energy LP SF WSPP n/a n/a n/a
8 Black Hils Power Inc.OS WSPP n/a n/a n/a
9 Black Hills Power Inc.OS WSPP n/a n/a n/a
10 Black Hils Power Inc.SF WSPP n/a n/a n/a
11 Bonneville Power Administration OS WSPP n/a n/a n/a
12 Bonnevile Power Administration SF T-7 n/a n/a n/a
13 Bonnevile Power Administration SF WSPP n/a n/a n/a
14 BP Energy Company SF WSPP n/a n/a n/a
Subtotal RO 0 0 0
Subtotal non-RO 0 0 0
Total ~0 0
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FERC FORM NO.1 (ED. 12-90l Paae 310
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) D A Resubmission 04/15/2009
SALES FOR RESALE (Account 447) (Continued)
S - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
n-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
ears. Provide an explanation in a footnote for each adjustment.
. Group requirements RO sales together and report them starting at line number one. After listing all RO sales, anter "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)
. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
hich 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
verage monthly biling demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
onthly coincident peak (CP)
emand in column (t). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
'ntegration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t) must be in megawatts.
ootnote any demand not stated on a megawatt basis and explain.
. Réport 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
ut-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
he total charge shown on bils rendered to the purchaser.
. 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
01, line 23. The "Subtotal - Non-RO" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
01,iine 24.
O. Footnote entries as required and provide explanations following all required data.
Year/Period of Report
End of 2008lQ4
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges (h+i+j)No.
($)($)
(g)(h)(i)(k)
57,311 656,585 1,459,683 2,122,268 1
362,963 2
3
72,803 1,921,438 1,921,43 4
14,524 834,078 834,078 5
67,600 3,268,590 3,268,590 6
50,350 2,938,077 2,938,077 7
5,852 8
30,805 1,586,200 9
7,940 531,847 10
5,440 165,920 11
33 790 790 12
69,259 4,139,910 4,139,910 13
207,917 13,726,957 13,726,957 14
7,750,580
2,485,231
118,943,594
121,428,825
57,311
1,990,923
2,048,234
656,585
o
656,585
1,459,683
111,561,977
113,021,660
368,963
7,381,617
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FERC FORM NO.1 (ED. 12-90)Page 311
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) n A Resubmission 04/15/2009
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 electncity ( i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and ''frm'' means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Averaße Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly illng Avera~e Avera~cation Tariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 British Columbia Transmission Corp.SF T-7 n/a n/a n/a
2 Cargil Power Markets LLC OS WSPP n/a n/a n/a
3 Cargil Power Markets LLC SF WSPP n/a n/a n/a
4 Chelan Co PUD SF WSPP n/a n/a n/a
5 Citigroup Energy Inc.SF WSPP n/a n/a n/a
6 Clatskanie PUD SF WSPP n/a n/a n/a
7 Conoco Philips Company SF WSPP n/a n/a n/a
8 Constellation Energy Commodities Group,OS WSPP n/a n/a n/a
9 Constellation Energy Commodities Group,OS WSPP n/a n/a n/a
10 Constellation Energy Commodities Group,SF WSPP n/a n/a n/a
11 Coral Power, LLC OS WSPP n/a n/a n/a
12 Coral Power, LLC OS WSPP n/a n/a n/a
13 Coral Power, LLC OS WSPP n/a n/a n/a
14 Coral Power, LLC SF WSPP n/a n/a n/a
Subtotal RO 0 0 0
Subtotal non-RO 0 0 0
Total 0 0 0
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FERC FORM NO.1 lED. 12.90\Paae 310.1
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) D A Resubmission 04/15/2009
SALES FOR RESALE (Account 447) (Continued)
as - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tanff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly 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 (t). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
I 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
I out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
1401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
Year/Period of Report
End of 2008/Q4
Name of Respondent
Idaho Power Company
I
1
I
MegaWatt Hours
Sold
(g)
REVENUE
Energy Charges
($)
(i)
Other Charges
($)
m
57
1,729,27
6,490,596
25,600
3,161,396
80,200
31,900
265,465
223,301
8,079,780
740,716
87,34
1,818,13
208,535
Total ($)
(h+i+j)
(k)
Demand Charges
($)
(h)
57
6,490,596
25,600
3,161,396
80,200
31,900
118,346
423
46,867
1,400
400
7,645
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136,292
10,206
I
27,109
4,092 208,535
I 656,585
o
656,585
1,459,683
111,561,977
113,021,660
368,963
7,381,617
7,750,580
2,485,231
118,943,594
121,428,825
57,311
1,990,923
I 2,048,234
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FERC FORM NO.1 (ED. 12-90)Page 311.1
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
Name of Respondent This io0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2008/Q4
(2) 0 A Resubmission 04/15/2009
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 affliation 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 suppliets service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "frm" 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 contrct.
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 reliabiliy of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Averaße Actual Demand (MW)
No.(Footnote Affliations)Classif-Schedule or Monthly iIing Povera~e Avera~cation Tariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 DB Energy Trading, LLC SF WSPP n/a n/a n/a
2 EI Paso Electric Company SF WSPP n/a n/a n/a
3 Energy Authority, The SF WSPP n/a n/a n/a
4 Eugene Water & Electric Board SF WSPP n/a n/a n/a
5 Fortis Energy Marketing & Trading GP SF WSPP n/a n/a n/a
6 Grant County P.U.D.SF WSPP n/a n/a n/a
7 Highland Energy LLC OS WSPP n/a n/a n/a
8 Highland Energy LLC SF WSPP n/a n/a n/a~LF V6-61 n/a n/a n/a
10 IBERDROLA RENEWABLES, Inc.OS WSPP n/a n/a n/a
11 IBERDROLA RENEWABLES, Inc.SF WSPP n/a nla n/a
12 Integrys Energy Services, Inc.OS WSPP n/a n/a n/a
13 Integrys Energy Services, Inc.SF WSPP n/a nla n/a
14 J. Aron & Company SF WSPP n/a n/a n/a
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
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F:F:Rr. FORM NO 1 (ED. 12.90\Paae 310.2
I Name of Respondent This 'r0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2008/Q4
(2) n A Resubmission 04/15/2009
SALES FOR RESALE (Account 447) (Continued)
I OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
I
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RO sales together and report them starting at line number one. After listing all RO sales, enter "Subtotal- RO"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RO" in column (a) after this Listing. Enter
"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 taris 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
I 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.
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
I out-of-period adjustments, in column G). Explain in a footnote all components of the amount shown in column G). 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
I 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.
I
MegaWatt Hours REVENUE Total ($)Line
I Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)(j (k)
1,400 67,000 67,000 1
I 178 4,323 4,323 2
684 18,234 18,234 3
5,442 325,686 325,686 4-
I 32,852 1,898,047 1,898,047 5
6,845 402,650 402,650 6
235 7
I 5,085 282,360 282,360 8
26,446 9
1,720 10
I 74,683 4,456,726 4,456,726 11
486 12
84,378 4,679,152 4,679,152 13
I 2,800 190,550 190,550 14
I 57,311 656,585 1,459,683 368,963 2,485,231
1,990,923 0 111,561,977 7,381,617 118,943,594
2,048,234 656,585 113,021,660 7,750,580 121,428,825I
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FERC FORM NO.1 (ED. 12-90)Page 311.2
Name of Respondent This (80rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) 0 A Resubmission 04/15/2009
SALES FOR RESALE (Account 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( Le., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "frm" 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" 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 Affliations)Classifi-Schedule or Monthly iIing Avera~e Average
cation'Tariff Number Demand (MW)Monthly NC Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 J.P. Morgan Ventures Energy Corporation SF WSPP n/a n/a n/a
2 Lehman Brothers Commodity Services, Inc SF WSpp n/a n/a n/a
3 Morgan Stanley Capital Group Inc.OS WSPP n/a n/a n/a
4 Morgan Stanley Capital Group Inc.SF WSPP n/a n/a n/a
5 NorthWestern Energy OS WSPP n/a n/a n/a
6 Pacific Nortwest Generating Cooperativ SF WSPP n/a n/a n/a
7 PacifiCorp Inc.OS WSPP n/a n/a n/a
8 PacifiCorp Inc.SF T-7 n/a n/a n/a
9 PacifiCorp Inc.SF WSPP n/a n/a n/a
10 Portland General Electric Company OS WSPP n/a n/a n/a
11 Portland General Electric Company OS WSPP n/a n/a n/a
12 Portland General Electric Company SF WSPP n/a n/a n/a
13 Powerex Corp.OS WSPP n/a n/a n/a
14 Powefex Corp.OS WSPP n/a n/a n/a
Subtotal RO 0 0 0
Subtotal non-RO 0 0 0
Total 0 0 0
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i=i=IU: i=ORM NO.1 (ED. 12.90\Paae 310.3
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) 0 A Resubmission 04/15/2009
SALES FOR RESALE (Account 447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
5. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP demand is the maximum
metered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (50-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (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 bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
Year/Period of Report
End of 2008/Q4
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)0)(k)
8,200 414,100 414,100 1
5,334 114,338 114,338 2
92,133 3
45,816 2,801,280 4
423 5
400 32,900 6
1,971,398 7
294 19,014 8
34,632 1,995,643 9
38,383 10
1,900 106,400 11
13,001 681,935 12
1,734,317 13
I 91,849 5,679,851 14
I 57,311 656,585 1,459,683 368,963 2,485,231
1,990,923 0 111,561,977 7,381,617 118,943,594
I 2,048,234 656,585 113,021,660 7,750,580 121,428,825
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FERC FORM NO.1 (ED. 12-90)Page 311.3
Name of Respondent This io0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) n A Resubmission 04/15/2009
SALES FOR RESALE (Account 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) trnsacted 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 affliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classifcation Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer~ The availability and 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" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERCRate Averaße Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly iIing . ~vera~e Avera~
cation Tariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Powerex Corp.SF WSPP n/a n/a n/a
2 PPL EnergyPlus, LLC OS WSPP n/a n/a n/a
3 PPL EnergyPlus, LLC OS WSPP n/a n/a n/a
4 PPL EnergyPlus, LLC SF WSPP n/a n/a n/a-
5 PPM Energy, Inc.OS WSPP n/a n/a n/a
6 PPM Energy, Inc.SF WSPP n/a n/a n/a
7 Prudential Bache Commodities, LLC OS -n/a n/a n/a
8 Public Service Co. of Colorado OS WSPP n/a n/a n/a
9 Public Service Co. of Colorado SF WSPP n1a n/a n/a
10 Puget Sound Energy, Inc.SF WSPP n/a n/a n/a
11 Rainbow Energy Marketing Corporation OS WSPP n/a n/a n/a
12 Rainbow Energy Marketing Corporation OS WSPP n/a n/a n/a
13 Rainbow Energy Marketing Corporation SF WSPP n/a n1a n/a
14 Sacramento Municipal Utility District SF WSPP n/a n/a n/a
Subtotal RO 0 0 0
Subtotal non-RO 0 0 0
Total 0 0 0
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i:i:rlr. i:nRM Nn 1 ii=n 1?Qo\Paae 310.4
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2008/Q4
This ~ort Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2009
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 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.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly 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 (t). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)ü)(k)
239,380 12,791,331 12,791,331 1
70,472 2
176 1,760 3
16,395 640,820 4
9,82 5
52,200 2,992,20 6
-345,380 7
640 24,320 8
4,000 214,636 9
55,219 2,932,891 10
422,601 11
6,066 211,246 12
11,409 456,343 456,343 13
400 18,000 18,000 14
57,311 656,585 1,459,683 368,963 2,485,231
1,990,923 0 111,561,977 7,381,617 118,943,594
2,048,234 656,585 113,021,660 7,750,580 121,428,825
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FERC FORM NO.1 (ED. 12-90)Page 311.4
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2008/Q4
(2) r=A Resubmission 04/15/2009
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 affliation 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 additon, 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 "frm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the 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 Affliations)Classifi-Schedule or Monthly iIing l\vera~e Avera~
cation Tariff Number Demand (MW)Monthly NC Deman Monthly CP · emand
(a)(b)(c)(d)(e)(f)
1 Seattle City Light SF WSPP n/a n/a n/a
2 Sempra Energy Solutions SF WSPP n/a n/a n/a
3 Sempra Energy Trading Corporation OS WSPP n/a n/a n/a
4 Sempra Energy Trading Corporation SF WSPP n/a n/a n/a
5 Sempra Energy Trading LLC SF WSPP n/a n/a n/a
6 Shell Energy North America (US), L.P.OS WSPP n/a n/a n/a
7 Shell Energy North America (US), L.P.OS WSPP n/a n/a n/a
8 Shell Energy North America (US), L.P.SF WSPP n/a n/a n/a
9 Sierra Pacific Power Company OS WSPP n/a n/a n/a
10 Sierra Pacific Power Company OS WSPP n/a n/a n/a
11 Sierra Pacific Power Company SF T-7 n/a n/a n/a
12 Sierra Pacific Power Company SF WSPP n/a n/a n/a
13 Silicon Valley Power SF WSPP n/a n/a n/a
14 Snohomish County PUD SF WSPP nla n/a n/a
Subtotal RQ o .0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
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i:i:Rr. i:ORM NO_ 1 (ED. 12.90\Paae 310.5
I Name of Respondent
This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2008/Q4
(2) ¡= A Resubmission 04/15/2009
SALES FOR RESALE (Account 447) (Continued)
I OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
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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
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"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identif 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
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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 (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
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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
I 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
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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.
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MegaWatt Hours REVENUE Total ($)Line
I Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(9)(h)(i)0)(k)
17,685 1,143,800 1,143,800 1
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400 23,176 23,176 2748'80~44,350 3
10,400 748,800 4
I 184,438 10,482,086 10,482,086 5
11,110 ' - .'Ø!.348,167 6
122,21C 7
I 26,160 1,084,912 1,084,912 8
1,319,220 9
138 8,280 10
I 151 8,489 8,489 11
2,917 181,197 181,197 12
800 68,000 68,000 13
I 4,847 220,635 220,635 14
I 57,311 656,585 1,459,683 368,963 2,485,231
1,990,923 0 111,561,977 7,381,617 118,943,594
2,048,234 656,585 113,021,660 7,750,580 121,428,825I
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FERC FORM NO.1 (ED. 12-90)Page 311.5
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2008/Q4
(2) D A Resubmission 04/15/2009
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 electcity ( 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 affliation 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 suppliets service to its own ultimate consumers.
LF - for tong~term service. "Long~term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate~term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU ~ for Long~term service from a designated generating unit. "Long~term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availabilty and reliability of designated unit
IU ~ for intermediate-term service from a designated generating unit The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Averaße Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly illng Avera~e AveragecationTariff Number Demand (MW)Monthly NC Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 SUEZ Energy Marketing NA, Inc.SF WSPP n/a n/a n/a
2 TransAlta Energy Marketing (U.S.) Inc.OS WSPP n/a n/a n/a
3 TransAlta Energy Marketing (U.S.) Inc.SF WSPP n/a n/a n/a
4 UBS Securities LLC OS -n/a n/a n/a
5
6
7
8
9
10
11
12
13
14
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
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FERC FORM NO.1 lED. 12.90\Page 310.6
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Name of Respondent This 'O0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2008/Q4
(2) OA Resubmission 04/15/2009
SALES FOR RESALE (Account 447) (Continued)
as - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
5. For requirements RQ 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 (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP demand is the maximum
metered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (50-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on 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-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23, The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)(j)(k)
2,000 146,300 146,300 1
2.628.208=422 2
48,767 2,628,208 3
-173,409 4~~5
6
7
8
9
10
11
12
13
14
57,311 656,585 1,459,683 368,963 2,485,231
1,990,923 0 111,561,977 7,381,617 118,943,594
2,048,234 656,585 113,021,660 7,750,580 121,428,825
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I FERC FORM NO.1 (ED. 12-90)Page 311.6
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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 04/15/2009 2008/Q4
FOOTNOTE DATA
:Schedule P~: 310___line-'1-,!.~'L_ Column:i - ~J
1- ...--. ... ....._- .----.-- .------ .-~-.---.. .-.- ---. -..,Schedule Page: 310 L!,!e_l!Q~ 2 . Column: j _ ____~m___
Network Transmission Charges
'§ç!J~dule F'aJi~;~!l!._ .~lr'f!Jltl-;- 8_. ~ç~'!_ni~;i __ ____ ____-===_.._
Financial Transmission Losses
'§c.lJ~dule Page: 310_ ... L.ine,No.: 9 Column: iNon-firm Sales --~-----flh~d,!~ef'~ge,;~1!L Line No.: 11.. c.~~l.tr!!:L_____ m_ _ ___ _m__~_Uni t Contingent
~I!~dulef'~ge::l1 oI~lk'iflõ.:2-~Çti~~,nn: iFinancial Transmission Losses
'sc.hedùle p~_ii 310:1 . _ l"Iri~_No.~IJ_~-çplumn;.!. ___m~_:_-_-~:__~Uni t Contingent
fßchediiiit'~!1i3iiJ.1__l.ine No.:-Ö__Çcjlumn: j
Financial Transmission Losses
~C/Jer¡lJ¡fi Page: 310.1- Line No-:' Column: iUni t Contingent
fßcliediile Page: 31ii.1~IiÎIeNO::--12---Column: ifinarieTäTT ransmIssIonLOes- ---- -
'sc.!!_e,dule_F'!lgii~!Q.1. Linel!C!'L!~ çoll.nin;T-----.---Non-firm Sales -_.~._.._.._._._._---._._..,._--- -_._--_.._--~-_._--~._-_._-- .---- -~....._----_._.
¡Schedule Page: 310.2 Line No.: 7 Column: j
Financial Transmission Losses
~dule Page:Tiii¡-- Line No.~!~ __Ç:oiiimii:a- .. '.-.~~_~:~-
Contract expires 5/31/2013
ISchedule-p'ag~ 31 O.~___ line l!f!~: 9_ . ~~/umn:I~~ __m_ .-_ .. __m____Spiiming or Op~E"'ting__R~~e~,:~s .__._______..._._..
iSchedule,F'a.g~ 310.2 Line No.: 10 Colu"!n;I
Financial Transmission Losses
&hedulePage:3io.'2 -LineNO':-l2- Column: i
Financial Transmission Losses
I$chedulee¡g_~ 31(!~~__T.-&~No:~i~ ç.il~niij:JFinancial Transmission Losses
~che¡¡iijepaiie:310.3 L!'!f!_No.: 5 ~mtolu!!n:j _ ... --.---~---~--- ------.
Financial Transmission Losses
~_Ii~!l!!~f!_!!!lge,: 310.~ ~_Üne i¡o.;X Column: i
Financial Transmission Lossesr- .. .-.----- -- -~- ----.--.--¡Schedule Page: 310.3~_L!'!f! No.:_10 CO!t¿'!n:L
Financial Transmission Losses
ISc.lJflr!,!Ie,Pt!g~: 3,10.3-ljrie -''!5!'.: 11 Column: i---. ~~=~~=~~~=~~__Non-firm Sales
~chediiI~f~ge: 310.j'IineNo.-:13--' Co/ùmn: j
Financial Transmission Losses
~heil'!~~~!l1le,:31i).f .I.ne No.: 14 Coluiiiii:T---"-Non-firm Sales
lschedulePage:310.4 .'TiieuNo.-:2 Columii:j ---------FInancial Träñ-smission Losses- ---
'lcheduJe Page:31Ó.4-- I.~No~:~~~dCotumn: iNon-firm Sales
~chedule ii:3f:¡'-' Line No.-:s--'Ci:iiiiii:i
Financial Transmissro-n-i.o-sses
~chedule!,age:j10.4 Line No.: 7 Column: j
IFERC FORM NO.1 (ED. 12-87)
.-.-.----------.--- _.- i__________J
.~-J-----
j
-- --- - -__-------~~~__~_~_----_=J
__._______~~_ ~-----~.-. -~_J
----~~~
----J
-------- -- _-=_-_ - ~~ ----~- _ ______J
-~_~I
--.-.--~~_~~----- . ..- ---- - J
.1
Page 450.1
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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 04/15/2009 2008/Q4
FOOTNOTE DATA
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Prudential Bache Commodities,
~hedulePaiie:310.4L¡iieNo.:9--
Non':IiimSãleš--- -
~ç~eèiu¡e -Page:310.4_.-Une No.: 1 i Colu'!!J:i -,,----
Financial Transmission Losses
f$chediiifi Page:- 310.4 ....UiieNo.:-¡2---Columil: iNon-firm Sales ---. ..- -- -. ,,--
!Schedule Page: 310.5 Úne ÑO::3" Column¿i ..-'
FInancIäi Transmissi-on Losses--- --.-----~--
~-_._._-_._-----_._---~--------_._--_._..._---~chedule Page: 310.5 . Line No.: 6 Colunin: i _ ____
'Qnit Contingent - - ___-._~~~_______ _ ____________________.____.__
~chedule F!tlge:~Jn~~_ _ Line. NQ;_7. .çC!IJrrIJ:j.
Financial Transmission Losses~~---------_.._-_._---~edule Page: 310.5..Line!!()~:J! Column:j
Financial Transmission Losses
~ç,IJ~d'!e-.age: l10.S.d__J.Iiie No.: 10 Column: iNon-firm Sales
~chei:uie Page: 310.6 . Line No.: 2 C~/u"lIJ:jFinanciaT 'Ti-a-nsmission - Loss-es
i -~-_.----_.-----.-.--------..-- --------..-..Schedule Page: 310.6 Line No.: 4 Column:j
Insti tutional Futres Client -Account Agreement ¡,jJh UBS,~t~-cr-Marcll¡r,-2(fu£_
~chedule Page: 310.6 -Üne No::S--Column: g ___m
In referEmceto the total ME;gaWatt Hours sold, page-:3Il-¿oes-not rnatCFi-page 301
column d by 631 MegaWatt hours due to an adjustment that was made to statistics
books for total sales for resale.
~L_ç¿ Fiitures Account _Dot:umeri_t.'?ated Sefltem_b~£~, 2008Column: i ___J
---_.~~
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_ ____--
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line 11, .-
in our
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IFERC FORM NO.1 (ED. 12-87) Page 450,2
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2008/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2009
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnote.Line Account Amount forNo Current Year. W ~
1 1. POWER PRODUCTION EXPENSES
2 A. Steam Power Generation
3 Operation
4 (500) Operation Supervision and Engineering
5 (501) Fuel
6 (502) Steam Expenses
7 (503) Steam from Other Sources
8 (Less) (504) Steam Transferred-Cr.
9 (505) Electric Expenses
10 (506) Miscellaneous Steam Power Expenses
11 (507) Rents
12 (509) Allowances
13 TOTAL Operation (Enter Total of Lines 4 thru 12)
14 Maintenance
15 (510) Maintenance Supervision and Engineering
16 (511) Maintenance of Structures
17 (512) Maintenance of Boiler Plant
18 (513) Maintenance of Electric Plant
19 (514) Maintenance of Miscellaneous Steam Plant
20 TOTAL Maintenance (Enter Total of Lines 15 thru 19)
21 TOTAL Power Production Ex enses-Steam Power (Entr Tot lines 13 & 20)
22 B. Nuclear Power Generation
23 Operation
24 (517) Operation Supervision and Engineerin
25 (518) Fuel
26 (519) Coolants and Water
27 (520) Steam Expenses
28 (521) Steam from Other Sources
29 (Less) (522) Steam Transferred-Cr.
30 (523) Electric Expenses
31 (524) Miscellaneous Nuclear Power Expenses
32 (525) Rents
33 TOTAL Operation (Enter Total of lines 24 thru 32)
34 Maintenance
35 (528) Maintenance Supervision and Engineering
36 (529) Maintenance of Structures
37 (530) Maintenance of Reactor Plant Equipment
38 (531) Maintenance of Electric Plant
39 (532) Maintenance of Miscellaneous Nuclear Plant
40 TOTAL Maintenance (Enter Total of lines 35 thru 39)
41 TOTAL Power Production Expenses-Nuc. Power (Entr tot lines 33 & 40)
42 C. Hydraulic Power Generation
43 Operation
44 (535) Operation Supervision and Engineering
45 (536) Water for Power
46 (537) Hydraulic Expenses
47 (538) E.lectric Expenses
48 (539) Miscellaneous Hydraulic Power Generation Expenses
49 (540) Rents
50 TOTAL Operation (Enter Total of Lines 44 thru 49)
51 C. Hydraulic Power Generation (Continued)
52 Maintenance
53 (541) Mainentance Supervision and Engineering
54 (542) Maintenance of Strctures
55 (543) Maintenance of Reservoirs, Dams, and Waterw s
56 (544) Maintenance of Electric Plant
57 (545) Maintenance of Miscellaneous Hydraulic Plant
58 TOTAL Maintenance (Enter Total of lines 53 thru 57)
59 TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 & 58)
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IAmount forPrevious Year
(c)
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1,650,283 1,664,872
132,015,165 114,837,238
7,376,689 6,840,109
1,817,960 2,109,889
7,737,497 8,068,234
469,699 295,774
151,067,293 133,816,116
2,567,722 2,580,248
398,714 649,264
14,205,043 14,630,060
4,301,150 5,685,377
4,322,931 5,934,851
25,795,560 29,479,800
176,862,853 163,295,916
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5,602,490 5,235,531
I7,355,741 5,057,110
9,978,475 9,469,966
1,312,586 1,391,453
3,091,676 2,825,559 I431,893 419,652
27,772,861 24,399,271
1,885,154 1,875,540 I
1,362,031 1,281,835
808,311 541,034 I2,495,503 2,090,274
3,135,803 2,763,207
9,686,802 8,551,890
37,459,663 32,951,161 I
FERC FORM NO.1 lED. 12.93)P?rie 320
I Name of Respondent This (!0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/Q4
(2) n A Resubmission 04/15/2009
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
Ilf the amount for previous year is not derived from previously reported figures, explain in footnote.U"e ÄO"el ~No urrent ear Previous Year. (a) (b) (c)
60 D. Other Power Generation
61 Operation62 (546) Operation Supervision and Engineering 372,614 341,622
63 (547) Fuel 17,387,509 19,484,750
64 (548) Generation Expenses 404,456 381,996
65 (549) Miscellaneous Other Power Generation Expenses 530,176 464,825
66 (550) Rents
67 TOTAL Operation (Enter Total of lines 62 thru 66)18,694,755 20,673,193
68 Maintenance
69 (551) Maintenance Supervision and Engineering 213
70 (552) Maintenance of Structures 162,376 220,421
I 71 (553) Maintenance of Generating and Electric Plant 198,271 42,703
72 (554) Maintenance of Miscellaneous Other Power Generation Plant 509,219 645,761
73 TOTAL Maintenance (Enter Total of lines 69 thru 72)870,079 908,885
74 TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73)19,564,834 21,582,078
I 75 E. Other Power Supply Exoenses
76 (555) Purchased Power 231,137,298 289,484,213
77 (556) System Control and Load Dispatching 77,979 77,489
78 557) Other Expenses -44,906,304 -118,678,522
79 TOTAL Other Power Supplv Exp (Enter Total of lines 76 thru 78)186,308,973 170,883,180
80 TOTAL Power Production Expenses (Total of lines 21, 41, 59, 74 & 79)420196323 388,712,335
81 2. TRANSMISSION EXPENSES
I 82 Operation
83 (560) Operation Supervision and Engineerino 2,404,396 2,334,833
84 (561) Load Dispatchino 87,197 51,610
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85 (561.1) Load Dispatch-Reliabilty 1,517
86 (561.2) Load Dispatch-Monitor and Operate Transmission System 1,635,606 2,042,253
87 (561.3) Load Dispatch-Transmission Service and Scheduling 1,069,383 1,098,119
88 (561.4) Scheduling, System Control and Disoatch Services
I 89 (561.5) Reliabilitv, Planning and Standards Development
90 (561.6) Transmission Service Studies
91 (561.7) Generation Interconnection Studies 90,292 66,918
92 (561.8) Reliabiltv, Planning and Standards Development Services
I 93 (562) Station Expenses 1,805,491 1,748,408
94 (563) Overhead Lines Expenses 735,577 924,264
95 (564) Underground Lines Expenses
I 96 (565) Transmission of Electricity by Others 7,250,299 10,469,725
97 (566) Miscellaneous Transmission Expenses 465,343 622,227
98 567) Rents 1,085,343 1,163,462
99 TOTAL Operation (Enter Total of lines 83 thru 98)16,630,444 20,521,819
I 100 Maintenance
101 (568) Maintenance Supervision and Engineering 431,690 442,117
102 (569) Maintenance of Structures 111
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103 (569.1) Maintenance of Computer Hardware 98,395 123,219
104 (569.2) Maintenance of Computer Softare 328,872 307,535
105 (569.3) Maintenance of Communication Equipment 24,333 21,369
106 (569.4) Maintenance of Miscellaneous Regional Transmission Plant
I 107 (570) Maintenance of Station Equipment 2,706,580 2,899,130
108 (571) Maintenance of Overhead Lines 3,367,619 2,341,428
109 (572) Maintenance of Underground Lines
110 (573) Maintenance of Miscellaneous Transmission Plant 272 2,527
I 111 TOTAL Maintenance (Total of lines 101 thru 110)6,957,761 6,137,436
112 TOTAL Transmission Expenses (Total of lines 99 and 111)23,588,205 26,659,255
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FERC FORM NO.1 (ED. 12.93)Page 321
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/Q4
(2) Fi A Resubmission 04/1512009
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line Accunt ~No.urrent ear Previous Year
(a)(b) (c)
113 3. REGIONAL MARKET EXPENSES
114 Operation
115 (575.1) Operation Supervision
116 (575.2) Day-Ahead and Real-Time Market Faciltation
117 (575.3) Transmission Rights Market Faciltation
118 (575.4) Capacity Market Faciltation
119 (575.5) Ancillary 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 115thru 122)
124 Maintenance
125 (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 Regional Transmission and Market Op Expns (Total 123 and 130)
132 4. DISTRIBUTION EXPENSES
133 Operation
134 (580) Operation Supervision and Engineering 3,321,954 3,350,727
135 (581) Load Dispatching 3,110,301 3,049,911
136 (582) Station Expenses 1,143,619 1,120,906
137 (583) Overhead Line Expenses 3,346,471 3,432,084
138 (584) Underground Line Exoenses 2,034,228 2,120,824
139 (585) Street Lighting and Signal System Expenses 130,886 148,817
140 (586) Meter Expenses 4,636,934 4,526,254
141 (587) Customer Installations Expenses 1,398,175 1,371,291
142 (588) Miscellaneous Expenses 5,464,167 5,533,555
143 (589) Rents 456,147 644,840
144 TOTAL Operation (Enter Total of lines 134 thru 143)25,042,882 25,299,209
145 Maintenance
146 (590) Maintenance Supervision and Engineering 319,660 262,635
147 (591) Maintenance of Structures 2,323
148 (592) Maintenance of Station Equipment 3,534,603 3,493,145
149 (593) Maintenance of Overhead Lines 13,759,196 12,504,013
150 (594) Maintenance of Underground Lines 1,235,321 1,351,055
151 (595) Maintenance of Line Transformers 445,190 169,689
152 (596) Maintenance of Street Liohting and Signal Systems 665,088 476,928
153 (597) Maintenance of Meters 862,861 927,906
154 (598) Maintenance of Miscellaneous Distribution Plant 354,999 127,981
155 TOTAL Maintenance (Total of lines 146 thru 154)21,179,241 19,313,352
156 TOTAL Distribution Expenses (Total of lines 144 and 155)46,222,123 44,612,561
157 5. CUSTOMER ACCOUNTS EXPENSES
158 Operation
159 (901) Supervision 341,842 454,931
160 (902) Meter Reading Exoenses 5,752,965 5,422,623
161 (903) Customer Recods and Collecton Expenses 11,773,961 8,177,910
162 (904) Uncollectible Accounts 3,681,954 2.009,863
163 (905) Miscellaneous Customer Accounts Expenses 468 336
164 TOTAL Customer Accounts Expenses (Total of lines 159 thru 163)21,551,190 16,065,663
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FERC FORM NO.1 (ED. 12-93)Page 322
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2008/Q4
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This ~ort Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2009
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.Line Accunt Amount forNo ~~. (a) (b)
165 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
166 Operation
167 (907) Supervision
168 (908) Customer Assistance Expenses
1169 (909) Informational and Instructional Expenses170 (910) Miscellaneous Customer Service and Informational Expenses
171 TOTAL Customer Service and Information Expenses (Total 167 thru 170)
172 7. SALES EXPENSES
173 Operation
174 (911) Supervision
175 (912) Demonstrating and Sellng Expenses
176 (913) Advertising Expenses
177 (916) Miscellaneous Sales Expenses
178 TOTAL Sales Ex enses (Enter Total of lines 174 thru 177)
179 8. ADMINISTRATIVE AND GENERAL EXPENSES
180 Operation
181 (920) Administrative and General Salaries
182 (921) Offce Supplies and Ex enses
183 (Less) (922) Administrative Expenses Transferred-Credit
184 (923) Outside Services Employed
185 (924) Propert Insurance
186 (925) Injuries and Damages
187 (926) Employee Pensions and Benefits
188 (927) Franchise Requirements
189 (928) Re ulato Commission Ex enses
190 (929) Less) Duplicate Charges-Cr.
191 (930.1) General Advertising Expenses
192 (930.2) Miscellaneous General Expenses
193 (931) Rents
194 TOTAL Operation (Enter Total of lines 181 thru 193)
195 Maintenance
196 (935) Maintenance of General Plant
197 TOTAL Administrative & General Ex enses (Total of lines 194 and 196)
198 TOTAL Elec Op and Maint Ex ns (Total 80,112,131,156,164,171,178,197)
Am.ountfprPrevious Year
(c)
299,410
27,674,740
301,871
21,911,476
860,302
28,834,452
884,228
23,097,575
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57,537,274
14,791,345
22,736,029
13,597,223
3,103,669
7,548,140
22,840,421
1,549
4,832,197
49,783,914
17,790,599
27,708,517
11,232,903
3,159,426
5,448,359
27,872,099
1,200
6,030,254
4,149,187
109,424,041
649,816,334
3,771,715
101,410,525
600,557,914I
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FERC FORM NO.1 (ED. 12-93)Page 323
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 2008/04
(2) riA Resubmission 04/15/2009
PURCHA~ED POWER wccount 555)
(Inclu 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 În a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction 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 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 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
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.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No,(Footnote Affliations)Classifi-Schedule or Monthly Billng Average AveragecationTarif Number Demand (MW)Monthly NCP Demanc Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Wills and Betty Deveny/Shinglecreek LU -N/A N/A N/A
2 James B, Howell 1 CHI Elkcreek LU -N/A N/A N/A
3 TaniarackEnergypartrship LU -4.942Mw ......I., ......
4 Owyhee Irrigation District
5 Mitchell Butte LU -NlA N/A N/A
6 Owyhee Dam LU -N/A N/A N/A
7 Tunnel #1 LU -N/A N/A N/A
8 Reynolds Irrigation District LU -N/A N/A NlA
9 Clifton E. Jenson/Birchcreek LU -.05Mw ..'10 Snake River Pottery LU -N/A N/A N/A
11 White Water Ranch LU -N/A N/A N/A
12 John R LeMoyne LU -N/A N/A N/A
13 David R Snedigar LU -N/A N/A N/A
14 Mud Creek White Hydro, Inc LU -N/A N/A N/A
Total
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FERC FORM NO.1 (ED. 12-90)Page 326 I
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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 2008/Q4
(2) OA Resubmission 04/15/2009
ccou~t~~~~L (Continued)"l1ncíudlng power exc anges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average 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 (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (6D-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawattours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0). energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on 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.
MeaWatt Hours POWER EXCHANGES COST/SETILEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.
Received Delivered ($)($)($)of Settlement ($)
(g)(h)(i)0)(k)(I)(m)
868 59,199 59,199 1
3,379 247,077 247,077 2
31,361 1,576,498 1,121,933 2,698,431 3
4
6,542 123,714 123,714 5
20,135 215,656 215,656 6
11,123 1,110,391 1,110,391 7
1,099 80,252 80,252 8
298 17,500 7,723 25,223 9
372 24,499 24,499 10
716 47,137 47,137 11
617 34,002 34,002 12
1,345 92,351 92,351 13
485 31,690 31,690 14
3,716,429 106,826 288,567 2,815,124 225,793,335 2,528,839 231,137,2913
FERC FORM NO.1 (ED. 12-90)Page 327
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 2008/Q4
(2) nA Resubmission 04/15/2009
PU~CHAa1ED POWER ~Account 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 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 affliation 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 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 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 availabilit and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expec 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.
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 Affliations)Classifi-Schedule or Monthly Biling Average AveragecationTarif Number Demand (MW)Monthly NCP Demam Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Rim View Trout Company -NlA N/A N/A
2 Curry Cattle Company LU -.084Mw -3 BranchfiowerfTrout 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 -N/A N/A N/A
7 Sagebrush LU -N/A N/A N/A
8 Fisheries Development I~:õ~"""'":_N/A N/A N/Ax .~
9 Shorock Hydro Inc.
10 Shoshone Cspp LU -N/A N/A N/A
11 Shoshone #2 LU -NlA N/A N/A
12 Rock Creek #1 Joint Venture LU -1.732Mw (TiT ii",,l"
13 Richard Kaster
14 Box Canyon LU -N/A N/A N/A
Total
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FERC FORM NO.1 (ED. 12-90)Page 326.1 I
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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 2008/Q4
(2)OA Resubmission 04/15/2009
, .. ,.., '(í :~: CCouRt~~~Ltcontlnued)Including power exc anges)
AD ~ for out~of~period adjustment. Use this code for any accounting adjustments or ''true~ups'' for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
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 (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (6o-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out~of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on 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/SETILEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l)No,
Received Delivered ($)($~($)of Settlement ($)
(g)(h)(i)(j)(k (I)(m)
1,299 51,195 51,195 1
559 26,796 15,258 42,054 2
831 56,279 56,279 3
4
335 22,717 22,717 5
1,326 92,686 92,686 6
511 35,010 35,010 7
958 39,45C 39,450 8
9
1,534 119,56~119,562 10
2,184 144,965 144,965 11
6,486 552,508 173,303 725,811 12
13
1,687 107,783 107,783 14
3,716,429 106,826 288,567 2,815,124 225,793,335 2,528,839 231,137,298
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FERC FORM NO.1 (ED. 12-90)Page 327.1
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 2008/Q4
(2) OA Resubmission 04/15/2009
PU~CHAJrED POWER hAccou~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, capacit, etc.) and any settlements for imbalance 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 affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the suppliets servce 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 transacton 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 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 availabilit and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classif Schedule or Monthly Billng . Average AveragecaonTari Number Demand (MW)Monthly NCP Demanc Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Briggs Creek LU -N/A N/A N/A
2 David McCollum/Canyon Springs LU -N/A N/A N/A
3 HK Hydro Mud Creek S & S LU -N/A N/A N/A
4 Allan RavenscroftMalad River LU -,488Mw
5 Willam Arkoosh/Litlewood LU -N/A N/A N/A
6 Clear Springs Food Inc.LU -N/A N/A N/A
7 Koyle Hydro Inc.LU -N/A N/A N/A
8 Kasel & Witherspoon LU -N/A N/A N/A
9 Lateral 10 Ventures LU -N1A N/A N/A
10 Crystal Springs Hydro LU -N/A N/A N/A
11 Pigeon Cove Power LU -1.389 -12 Consolidated Hydro Inc. 1 Enel -
13 GeoBon#2 LU -N/A N/A N/A
14 Barber Dam LU -N/A N/A N/A
Total
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FERC FORM NO.1 (ED. 12-90)Page 326.2 I
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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 2008/Q4
(2) OA Resubmission 04/15/2009
ccou~tÆ~~i \ (l,ontlnueO)
'li'ncluding poWer exc anges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average 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 (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (6D-minute integration) in which the suppliets system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on 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 bills received as settlement by the respondent. For power exchanges, report in column (m) the setlement
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/SETILEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total U+k+l)No.Received Delivered ($)($)($)of Settlement ($)
(g)(h)(i)(j (k)(I)(m)
3,549 233,539 233,539 1
802 32,314 32,314 2
1,523 107,236 107,236 3
1,810 155,672 49,306 204,978 4
3,294 239,152 239,152 5
3,493 286,718 286,718 6
2,873 231,390 231,390 7
3,596 270,026 270,026 8
8,60 537,129 537,129 9
8,111 534,976 534,976 10
8,262 486,150 190,931 677,081 11
12
2,961 219,43-219,434 13
11,131 559,519 559,519 14
3,716,429 106,826 288,567 2,815,124 225,793,335 2,528,839 231,137,29S
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FERC FORM NO.1 (ED. 12-90)Page 327.2
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 2008/04
(2) ¡=A Resubmission 04/15/2009
PU~CHA&iED POWER hAccount 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 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 affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be 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 firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expe 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 Affliations)Classifi-Schedule or Monthly Billng Average AveragecationTarif Number Demand (MW)Monthly NCP Deman!Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Rock Creek #2 LU -N/A N/A N/A
2 Dietrich Drop LU -N/A N/A N/A
3 Lowline#2 LU -N/A N/A N/A
4 Little Mac Power CoJCedar Draw LU -N/A N/A N/A
5 South Forks Joil'lVéiiture/Lowline Cana ..LU -N/A N/A N/A
6 Little Wood River Irrigation District LU -N/A N/A N/A
7 Marco Rancher's Irrigation Inc.LU -N/A N/A 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 -N/A N/A N/A
12 Claudia BurkhardUSunshine Power OS -N/A 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
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FERC FORM NO.1 (ED. 12-90)Page 326.3 I
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Name of Respondent This~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) ~An Original (Mo, Da, Yr)End of 2008/Q4
(2)A Resubmission 04/15/2009
ccou~t.SSSL (c.ontlnU80)(Includinò' power exc anges)
AD - for out-of-period adjustment. Use this code for any accunting 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 appropnate
designation for the contract. On separate lines, list all FERC rate schedules, tanfs 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 (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (6D-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on 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/SETILEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total U+k+l)No.Received Delivered ($)($)($)of Settlement ($)
(g)(h)(i)ü)(k)(i)(m)
6,483 322,354 322,354 1
12,681 683,227 683,227 2
9,797 508,947 508,947 3
3,394 219,234 219,234 4
27,983 1,971,611 1,971,611 5
3,865 287,088 287,088 6
2,581 172,577 172,577 7
3,179 235,858 235,858 8
8,729 464,027 464,027 9
26,290 1,387,073 1,387,073 10
22,840 1,151,559 1,151,559 11
73 3,072 3,072 12
1,349 100,500 100,500 13
69,79S 3,780,446 3,780,446 14
3,716,429 106,826 288,567 2,815,124 225,793,335 2,528,839 231,137,29S
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FERC FORM NO.1 (ED. 12-90)Page 327.3
Name of Respondent This ÏË0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2008/Q4(2) nA Resubmission 04/15/2009
PU~CH~ED POWER hAccou1t 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 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 affliation 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 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 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 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 services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availabilit and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expec 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 servics 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 Affliations)Classif-Schedule or Monthly Biling Average AveragecationTarif Number Demand (MW)Monthly NCP Demanc Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Blind Canyon Hydro LU -N/A N/A N/A
2 City of Hailey LU -NlA N/A N/A
-~~-N/A N/A N/A
-N/A N/A N/A5 LU -N/A N/A N/A6 LU -NlA N/A N/A:.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 N/A N/A
10 Contractors Power Group IncJMile 28 LU -N/A N/A N/A
11 Rupert Cogeneration Partners/Magic Val LU -N/A N/A N/A
12 Tasco - Nampa ~N/A N/A N/A
13 Pristine Springs Inc # 3 LU -N/A N/A N/A
14 Ted S. SorensonfTber Dam LU -N/A N/A N/A
Total
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FERC FORM NO.1 (ED. 12-90)Page 326.4 I
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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 2008/Q4
(2) OA Resubmission 04/15/2009
, ~ ,~,ccouHt~~~~i\ (l,onlinuea)
'lincluding power exc anges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropnate
designation for the contract. On separate lines, list all FERC rate schedules, tanfs 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 (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (SO-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (SD-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
S. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on 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 (j+k+l)No.Received Delivered ($)($~($)of Selliement ($)
(g)(h)(i)(j)(k (i)(m)
3,892 320,216 320,216 1
129 8,793 8,793 2
1,246 87,381 87,381 3
49,731 3,186,605 3,186,605 4
25,863 1,769,188 1,769,188 5
22,212 1,520,161 1,520,161 6
848 46,452 46,452 7
24,334 1,620,71C 1,620,710 8
40,147 2,680,900 2,680,900 9
3,454 234,480 234,480 10
64,432 3,895,813 3,895,813 11
608 24,961 24,961 12
1,371 73,520 73,520 13
27,649 1,304,455 1,304,455 14
3,716,429 106,826 288,567 2,815,124 225,793,335 2,528,839 231,137,298
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I FERC FORM NO.1 (ED. 12-90)Page 327.4
Name of Respondent This ~rtIS:Date of Report YearlPeriod of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2008/Q4
(2) OA Resubmission 04/15/2009
PU~CHAeHED POWER hAccount 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 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 affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction 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 servce.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 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
service, 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 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 Affliations)Classifi-Schedule or Monthly Billng Average '.AveragecationTarif Number Demand (MW)Monthly NCP Demanl Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Fossil Gulch Wind LU -NlA N/A N/A
2 G2 Energy Hidden Hollow LU -NlA N/A N/A
3 Horseshoe Bend Wind/United Materials LU -N/A N/A N/A
4 Horseshoe Bend Wind/United Materials ,. -NlA N/A N/A
5 Horseshoe Bend Wind/United Materials ~~~..NlA NlA N/A..
6 Riverside Hydro Mora Drop LU -N/A NlA N/A
7 J.M. Miler/Sahko Hydro LU -N/A N/A N/A
8 D.R Johnson Lumber/Co Gen Co SF -N/A N/A N/A
9 Twin Faiis Energy/Lowline Midway Hydro LU -N/A N/A N/A
10 US Geothermal/ Raft River Geothermal#LU -N/A N/A N/A
11 Bennett Creek Wind Farm LU -N/A N/A N/A
12 Bettencourt DryCreek Biofactory LU -NlA NlA N/A
13 Big Sky Dairy Digester LU -N/A N/A N/A
14 Hot Springs Wind Farm LU -N/A N/A N/A
Total
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FERC FORM NO.1 (ED. 12-90)Page 326.5 I
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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 2008/Q4
(2) riA Resubmission 04/15/2009
ccouRt.~~~L (Continued)(InCluding power exc anges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average 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 (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (5D-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
5. Report in column (g) the megawatthours shown on 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 Q+k+l)No.Received Delivered ($)($)($)of Settlement ($)
(g)(h)(i)Q)(k)(I)(m)
28,347 1,378,52!i 1,378,525 1
21,476 1,038,028 1,038,029 2
19,387 919,966 919,966 3
-4 4
-6 5
4,290 233,02C 233,020 6
82 2,683 2,683 7
23,193 1,973,521:1,973,528 8
9,015 572,614 572,614 9
18,141 875,205 875,209 10
5,049 243,594 243,594 11
2,306 84,516 84,516 12
312 10,252 10,252 13
3,543 120,611 120,611 14
3,716,429 106,826 288,567 2,815,124 225,793,335 2,528,839 231,137,29~
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I FERC FORM NO.1 (ED. 12-90)Page 327.5
Name of Respondent This Re ort Is:Date of Report Year/Period of Report
Idaho Power Company (1)X An Original (Mo, Da, Yr)End of 2008/Q4
(2)A Resubmission 04/15/2009
PU~C~AdTED POWER hAccount 555)( nc u ing power exc anges)
1. Report all power purchases made during the year. Also report exchanges of elecricity (i.e., transactions involving a balancing of
debits and credits for energy, capacit, etc.) and any settlements for imbalance 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 affliation the respondent has with the seller.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service.Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction 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 service expect that "intermiate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availabilit and reliabilit 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 Affliations)Classif-Schedule or Monthly Billng Average Average
cation Tarif Number Demand (MW)Monthly NCP Demanc Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Other Purchased Power
2 Arizona Public Service Co.SF WSPP N/A N/A NlA
3 Avista Corp. - WW Div.SF T-12 N/A N/A N/A
4 Avista Corp. - WW Div.
jci~~p
N/A N/A N/A
5 Avista Corp, - WW Div.N/A N/A N/A
6 Avista Corp. - WW Div.":WSPP N/A N/A N/A
7 Barclays Bank PLC SF WSPP N/A N/A N/A
8 Bear Energy LP SF WSPP N/A N/A N/A
9 Benton County PUD SF WSPP N/A N/A N/A
10 Black Hils Power Inc.~N/A N/A N/A
11 Black Hils Power Inc.N/A N/A N/A
12 Bonneville Power Administration ~if1Kl;l~êWSPP N/A N/A N/A
13 Bonnevile Power Administration SF WSPP NlA N/A N/A
14 BP Energy Company SF WSPP N/A N/A N/A
Total
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FERC FORM NO.1 (ED. 12.90)Page 326.6 I
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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 2008/Q4
(2) nA Resubmission 04/15/2009
ccou~t.~~~L (Continued), ~ .~, '''(íncluding power exc anges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or 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: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 (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the suppliets system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on 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 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/SETILEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges other Charges Total (j+k+l)No.Received Delivered ($)($~($)of Settement ($)
(g)(h)(i)(j)(k (I)(m)
1
169,121 10,623,41:3 10,623,413 2
67 3,589 3,589 3
100 100 4
60,217 3,214,317 3,214,317 5
624,528 624,528 6
76,40C 3,901,100 3,901,100 7
83,000 4,526,500 4,526,500 8
390 27,620 27,620 9
56,844 3,167,3741 3,167,374 10
12,02 637,104 637,104 11
125 9,375 9,375 12
76,908 4,085,88C 4,085,880 13
83,378 6,338,062 6,338,062 14
3,716,429 106,826 288,567 2,815,124 225,793,335 2,528,839 231,137,29E
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I FERC FORM NO.1 (ED. 12-90)Page 327.6
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 2008/Q4
(2) OA Resubmission 04115/2009
PU~CHA&iED POWER hAccount 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 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 affliation 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 service expe that "intermiate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the 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 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 place 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 Averagè Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly Billng Average AveragecationTarif Number Demand (MW)Monthly NCP Deman,Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Cargil Power Markets LLC SF WSPP NlA N/A N/A
2 Chelan Co PUD SF WSPP N/A N/A N/A
3 Citigroup Energy Inc.SF WSPP N/A N/A N/A
4 Clatskanie PUD SF WSPP NlA N/A N/A
5 Constellation Energy Commodities Group SF WSPP N/A N/A N/A
6 Coral Power, LLC "".WSPP N/A N/A N/A;",'
7 Coral Power, LLC SF WSPP N/A N/A N/A
8 DB Energy Trading, LLC SF WSPP N/A N/A N/A
9 Douglas County PUD SF WSPP N/A N/A N/A
10 EI Paso Electric Company SF WSPP N/A N/A N/A
11 Energy Authority, The SF WSPP NlA N/A N/A
12 Eugene Water & Electric Board SF WSPP N/A N/A N/A
13 Fortis Energy Marketing & Trading GP SF WSPP NlA N/A N/A
14 Franklin County P.U.D.SF WSPP N/A N/A N/A
Total
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FERC FORM NO.1 (ED. 12-90)Page 326.7 I
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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 2008/Q4
(2) ÕA Resubmission 04/15/2009
-,ccouRt 55~L. (Continued)
11ncluding power exc an¡¡ès)
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 (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (SO-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the suppliets system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts, Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the setlement
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/SETILEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l)No,Received Delivered ($)($~($)of Settlement ($)
(g)(h)(i)(j)(k (I)(m)
118,696 7,222,625 7,222,625 1
7,618 137,20C 137,200 2
169,800 13,608,67C 13,608,670 3
1,600 8,00 8,000 4
124,497 8,121,588 8,121,588 5
235 9,400 9,400 6
30,551 2,155,04C 2,155,040 7
13,800 467,910 467,910 8
6,602 157,169 157,169 9
600 36,200 36,200 10
7,078 247,420 247,420 11
6,800 472,200 472,200 12
169,000 11,505,60C 11,505,600 13
130 9,120 9,120 14
3,716,429 106,826 288,567 2,815,124 225,793,335 2,528,839 231,137,29~
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FERC FORM NO.1 (ED. 12-90)Page 327.7
Name of Respondent This~rtIS:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2008/Q4
(2) ¡=A Resubmission 04/15/2009
PU~CHAJlED POWER hAccount 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, capacit, 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 affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractal terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the 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 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 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 services, where the duraion 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 availabilit and reliability of
service, aside from transmission constraints, must match the availabilit and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expec 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 caegories, 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 Statisticl FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly Biling Average . ÄveragecationTarif Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Grant County P.U.D.SF WSPP N/A N/A N/A
2 Grays Harbor PUD SF WSPP N/A N/A N/A
3 Highland Energy LLC SF WSPP N/A N/A N/A
4 IBERDROLA RENEWABLES, Inc.SF WSPP N/A N/A N/A
5 Integrys Energy Services, Inc.i~~wspp NlA N/A N/A(loA? . ,,:~:.:,~, . ~~.':i
6 Integrys Energy Services, Inc.SF WSPP N/A N/A N/A
7 J. Aron & Company SF WSPP NlA N/A N/A
8 J.P, Morgan Ventures Energy Corporatio SF WSPP N/A N/A N/A
9 Lehman Brothers Commodity Services, In SF WSPP NlA N/A N/A
10 Morgan Stanley Capital Group Inc.SF WSPP N/A N/A N/A
11 Nevada Power Company SF WSPP N/A N/A N/A
12 NorthWestern Energy SF T-7 N/A N/A N/A
13 NorthWestern Energy SF WSPP N/A N/A N/A
14 Pacifc Northwest Generating Cooperati SF WSPP N/A N/A N/A
Total
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FERC FORM NO.1 (ED. 12-90)Page 326.8 I
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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 2008/04
(2) ñA Resubmission 04/15/2009
ccou~t.~~~L (Continued)'lIncludinò" power exc anges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tarifs 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 (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (6Q.minute integration) in which the suppliets system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on 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 bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total U+k+l)No.Received Delivered ($)($~($)of Settlement ($)
(g)(h)(i)u)(k (I)(m)
2,566 103,231 103,237 1
230 15,590 15,590 2
934 19,350 19,350 3
126,602 8,315,212 8,315,212 4
350 26,950 26,950 5
93,60C 7,336,256 7,336,256 6
7,600 559,10C 559,100 7
200 7,810 7,810 8
12,40C 629,60C 629,600 9
166,856 10,063,891 10,063,897 10
125 9,600 9,600 11
86 4,735 4,735 12
3,155 165,81C 165,810 13
1,400 99,000 99,000 14
3,716,429 106,826 288,567 2,815,124 225,793,335 2,528,839 231,137,29f
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I FERC FORM NO.1 (ED. 12-90)Page 327.8
Name of Respondent This~rtIS:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) OA Resubmission 04/15/2009
PU~CHA&ED POWER hAccount 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 imbalance 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 affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classifcation Cod based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
ecnomic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third partes 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 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 cotract.
IF - for intermediate-term firm service.The same as LF service expec that "intermiate-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 availability and reliabilit of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expec 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 place 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 Affliations)Classifi-Schedule or Monthly Biling Average AveragecationTarif Number Demand (MW)Monthly NCP Deman!Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 PacifiCorp Inc.SF T-13 N/A NlA N/A
2 PacifiCorp Inc,SF WSPP N/A N/A NlA
3 PacifiCorp Inc."';~"'..~wsPP NlA N/A N/A
4 Portland General Electric Company SF T-14 NlA N/A N/A
5 Portland General Electric Company ..;wspp NlA N/A N/A
6 Portland General Electric Company SF WSPP N/A N/A N/A
7 Powerex Corp..,.WSPP NlA N/A N/A~. ,. \,....!
8 Powerex Corp.SF WSPP N/A N/A N/A
9 PPL EnergyPlus, LLC LF WSPP N/A N/A N/A
10 PPL EnergyPlus, LLC ~N/A N/A NlA
11 PPL EnergyPlus, LLC NlA N/A N/A
12 PPM Energy, Inc.SF WSPP N/A N/A N/A
13 Prudential Bache Commodities, LLC i-N/A N/A N/A
14 Public Service Company of New Mexico SF WSPP N/A N/A N/A
Total
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FERC FORM NO.1 (ED. 12-90)Page 326.9 I
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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 2008/Q4
(2) OA Resubmission 04/15/2009
ccouRt~~~i\ (i;ontlnUea¡(Including power exc anges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average 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 (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (60minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (SD-minute integration) in which the suppliets system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
S. 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 bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l)No.Received Delivered ($)($)($)of Settlement ($)
(g)(h)(i)(j)(k)(I)(m)
304 13,501 13,501 1
143,341 8,466,561 8,466,563 2
549,297 549,297 3
97 5,772 5,772 4
400 23,050 23,050 5
62,756 4,563,844 4,563,84 6
4,000 284,800 284,800 7
126,033 8,835,440 8,835,440 8
102,256 4,550,392 4,550,392 9
6,314 419,771 419,777 10
47,197 2,590,749 2,590,749 11
24,816 1,610,88"1,610,882 12
116,272 116,272 13
580 32,23C 32,230 14
3,716,429 106,826 288,567 2,815,124 225,793,335 2,528,839 231,137,298
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I FERC FORM NO.1 (ED. 12-90)Page 327.9
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 2008/Q4
(2) nA Resubmission 04/15/2009
PU~C~~ED POWER hAccount 555)nc u ing power exc anges)
1. Report all power purchases made during the year. Also report exchanges of electricity (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 affliation 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 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 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 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)Classif-Scheule or Monthly Biling Average AveragecationTarif Number Demand (MW)Monthly NCP Demam Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Puget Sound Energy, Inc.SF T-9 NlA N/A NlA
2 Puget Sound Energy, Inc.SF WSPP N/A N/A N/A
3 Raft River Energy I LLC N/A NlA N/A
4 Rainbow Energy Marketing Corporation :ç WSPP N/A N/A N/A;':'è'"
5 Rainbow Energy Marketing Corporation SF WSPP N/A N/A N/A
6 Seatte City Light SF WSPP N/A N/A N/A
7 Sempra Energy Trading Corporation SF WSPP N/A N/A N/A
8 Sempra Energy Trading LLC SF WSPP N/A N/A N/A
9 Sempra Energy Trading LLC p N/A N/A N/A
10 Shell Energy North America (US), L.P.WSPP N/A N/A N/A
11 Sierra Pacific Power Company SF 55 N/A N/A N/A
12 Sierra Pacific Power Company ~ß1~~t'¡WSPP N/A N/A N/A
13 Sierra Pacific Power Company SF WSPP N/A N/A N/A
14 Sierra Pacific Power Company ¥i1Ôyji.\lS pD N/A N/A N/A
Total
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FERC FORM NO.1 (ED. 12-90)Page 326.10 I
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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 2008/04
(2) OA Resubmission 04/15/2009
ccou~t.~~~L \ (I,onbnueo)(Including power exc anges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or ''true-ups'' for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average 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 (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on 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/SETILEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total Ö+k+l)No.Received Delivered ($)($)($)of Settlement ($)
(g)(h)(i)ö)(k)(I)(m)
102 5,722 5,722 1
21,982 1,457,078 1,457,078 2
67,620 3,845,524 3,845,524 3
4,683 249,580 249,580 4
1,275 42,195 42,195 5
10,972 687,985 687,985 6
58,000 3,682,OOC 3,682,000 7
189,200 13,640,66C 13,640,660 8
190,632 190,632 9
13,356 480,501 480,501 10
53 2,642 2,642 11
2,421 58,880 58,880 12
9,434 386,14E 386,145 13
21,128 21,128 14
3,716,429 106,826 288,567 2,815,124 225,793,335 2,528,839 231,137,298
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I FERC FORM NO.1 (ED. 12-90)Page 327.10
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 2008/Q4
(2) OA Resubmission 04115/2009
PU~CHAd1ED POWER hAccount 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 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 affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service 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 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
service, aside from transmission constraints, must match the availabilty and reliabilit 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 Affliations)Classif-Schedule or Monthly Biling Average AveragecationTari Number Demand (MW)Monthly NCP Deman!Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Snohomish County PUD SF WSPP N/A N/A N/A
2 SUEZ Energy Marketing NA, Inc.SF WSPP NlA N/A N/A
3 Tacoma Power SF WSPP N/A N/A N/A
4 Telocaset Wind Power Partners LLC LU APP-A NlA N/A NlA
5 TransAlta Energy Marketing (U.S.) Inc,SF WSPP N/A N/A N/A
6 Tucson Electric Power Company SF WSpp N/A N/A N/A
7 UBS AG, London Branch SF WSPP N/A N/A N/A
8 UBS Securities LLC
lC~~
N/A N/A N/A
9 Western Area Power Administration r.AL N/A N/A N/A
10 Net Metering Customers NlA N/A N/A
11 Power Exchanges
12 Bonnevile Power Administration
jjJl,. - "'. . ~ ..,.;....
13 NorthWestern Energy -"''
14 PacifiCorp Inc.
Total
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FERC FORM NO.1 (ED. 12-90)Page 326.11 I
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Name of Respondent This 7Ë0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2008/Q4
(2) OA Resubmission 04/15/2009
ccouRt 55~L ((;ontinueo)
(Including power exc anges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average 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 (1). For all other types of service, enter NA in columns (d), (e) and (1). 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 (1)
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 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 Une
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total fj+k+l)No.Received Delivered ($)($~($)of Settlement ($)
(g)(h)(i)u)(k (I)(m)
16,045 768,27S 768,279 1
475 38,475 38,475 2
4,121 251,966 251,966 3
268,207 13,333,64f 13,333,647 4
34,916 1,739,976 1,739,976 5
13 1,105 1,105 6
47,375 2,584,000 2,584,000 7
-183,872 -183,872 8
1 14 14 9
477 32,081 32,081 10
11
60,313 15,705 12
3,768 13
45,759 258,872 14
3,716,429 106,826 288,567 2,815,124 225,793,335 2,528,839 231,137,291:
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I FERC FORM NO.1 (ED. 12-90)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 2008/Q4
(2) r=A Resubmission 04/15/2009
PU~CHAJlED POWER hAccount 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 imbalance 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 affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the 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 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 identifed as LF, provide in a footnote the termination date of the contractdefined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate.term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be place 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. Descrbe 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 Affliations)Classifi-Schedule or Monthly Biling Average AveragecationTarif Number Demand (MW)Monthly NCP Deman(Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Puget Sound Energy, Inc.Jili2Sierra Pacific Power Company
3 Utah Associated Municipal Pówer System ",:':~ 'tw:~~~tè:\.
4 Other Transactions
5 Power Plant Test Power
6
7
8
9
10
11
12
13
14
Total
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FERC FORM NO.1 (ED. 12-90)Page 326.12 I
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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 2008/04
(2) ÕA Resubmission 04/15/2009
ccouHt.~~~L (ContinUed).~, "11ncludlng power exc añges)
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), identif 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 (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the suppliets system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on 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/SETILEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered ($)($)($)of Settlement ($)
(g)(h)(i)0)(k)(I)(m)
516 1
10,222 2
238 3
4
1,210,754 1,210,754 5
6
7
8
9
10
11
12
13
14
3,716,429 106,826 288,567 2,815,124 225,793,335 2,528,839 231,137,29E
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I FERC FORM NO.1 (ED. 12-90)Page 327.12
---..~~-~------ --- ~-=-..~-=- ----- --:J
. ----.-----------_~===_=~~=~.- ----------1
- ---~---=-- -- -------_._-------===:~~-=------I
----._-- ---J
_____.__-=.J
-"l
----.-~-=i
_ _______~=J
------:J
_.____J
---~==.-------------_____________=
-..--------J
_______=:
______=i
.... ---..---.----Jownership of these projects.- ____.____-====----=:
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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 04/15/2009 2008104
FOOTNOTE DATA
--.-.--~~~=-~-=__~-.----=iare taken from an electronic demand
demand is not used in determining the cost
i
i
--'---ï- - _._------~_.-'
IFERC FORM NO.1 (ED. 12-87)
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Name of Respondent This Report is:Date of Report YearlPeriod of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04115/2009 2008/Q4
FOOTNOTE DATA
....._=:
--~ ~_.:~=~_~~-~==J
¡Schedule Page: 326.6 Line No.: 12 Column: b
Non Firm Purchases ~--
ISchedu/e-Page:326:¡ LineNo:Ti; -Coilimn:'" ..Non-Firff Purchases---------~ ._______._._~_._H._._.__._
~edu~!~S~.;_ 3~~.~ Line No~_S.__"Çolumn: b
Non Firm Purchases
~!!~clulë7jage:-326:9--'-ITii;::3_--£0Ium'l:p__.__~"'u .-.- .--==~~~.-==_':=' -.
Financial Transmission Losses
~eduJ~f'~Q~'3_26:!_ LinfJ~~~-5" Column: b ___'.H_' .Non Firm Purchases
~hedu/e piige:-326:g--UneNo::7' Column: bNon Firm Purchases
ISchedu/e Page: 326.9 Line NO::1ii--COiumn: b
Non Firm Purchases
~edu/e Page: 326.9 -Tiie No.: _!~m_.ç~!umn~_1l_m_____,,_.__.______n __H__ . _ _mm _. _.._..__....._
Prudential Bache Commodities, LLC Futures Account Document, dated September 4, 2008.
~chedu/e Page: 326.10 Line No.: 3 Column: fi-' ___.____,,_________~__n_____n -------Unavailable
~hedu/e Page: 326.10 _ Line No.:_~__Column: bNon Firm Purchases
~dule ~tJge:-326.10 LineNo:-:9-Coiiiiiiii:ii----.-.ISDA Master Agreement dated February 21, 2008.
ISchedule Page: 3~6.10 Line No.: 12 Column: b
Non Firm Purchases
ISchedu/e Page: 326.10 Line No.: 14 Colurn'?;' b_ ._. ______.m__ _________m
Financial Transmission Losses
~chedu/e Page: 326.11 Line No.: 8 Column: b
Institutional Futures Client Account Agreement with UBS, dated March 8, 2006.
l$chedule Page: 326.J!_ Line No.: 10_3~0Iumn: b ____-==~==~-==- ..________________~.- - - ___
Schedule 84 Net Metering
~chedule Page:32.11 Line No.: 12 Column: b ._.___________u__._u__m_________
Scheduled losses not removed with loss transactions.
~chedule Page: 326.11' Lin~.!i~:~J3._ Column: b ._._
Scheduled losses not removed wi th loss transactions.
~cheiiage:- 326. 11._ Lineiio-:14-- Column: b_~____===.~=:=.====:=u....:m=d:.=-_-.=d-=:-
Scheduled losses not removed with loss transactions.
I§chedule-Page: 326.12 . Line No.: 1 Column;_"____________.._______
Scheduled losses not removed with loss transactions.
~ciiedu!fJ Page: 326.12 . Line-No.:2" Column: b.. u__.... ---
Scheduled losses not removed wi th loss transactions.i~------_._--_.__.. ..-.---.-echedule!!age: 326.12_. Line No.: 3 Column: b
Scheduled losses not removed with loss transactions.
----=~.:
_.__..__.._J
. Un' .- .=.:~. ____J
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~~
.____.. ____._______. ._______._._____=-=:.=_=J
_.m______ ---,,-._- .-=.-.~:==.==-:
~===:.=~-_=====~-==-_====_==~=:.m- ..-.. ..----:=
_ __________===-:
_.~-J
--J
.___=______:~::-:=.J
____=.J. ---:=
.:. _____________._.:.-: OJ
----==_==______:-----J
:_=:~:-
IFERC FORM NO.1 (ED. 12-87) Page 450.2
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 2008/Q4
(2) DA Resubmission 04/15/2009
i I,OF ELSCTKIl¿11 y t:YK ~~~ccount 4~O.1 J
(Including trnsactons referred to as 'weeling')
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or trncate name or use acronyms. Explain in a footnote
any ownership interest in or affliation 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 reportng 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 Affliation)(Footnote Affliation)(Footnote Affliation)cation
(a)(b)(c)(d)
1 Bonnevile Power Administration - OTEC Bonnevile Power Administrtion Oregon Trails Electric Co-op FNO
2 Bonnevile Power Administrtion - OTEC AD
3 Bonneville Power Administration - USBR Bonnevile Power Administration United States Bureau of Rec FNO
4 Bonnevile Power Administration - USBR AD
5 Bonnevile Power Administration - Raft Bonnevile Power Administrtion Raft River Electric Co-p FNO
6 Bonnevile Power Administrtion - Raft AD
7 Bonnevile Power Administration - PF Bonneville Power Administration Pnority Firm Customers FNO
8 Bonnevile Power Administrtion - PF AD
9 Milner Irrigation District United States Bureau of Rec Milner Irrigation District OLF
10 City of Seatte Seatte City Light Bonnevile Power Administration OS
11 Cargill Seattle City Light Bonnevile Power Administration OS
12 PacifiCorp PacifiCorp West PacifiCorp West FNO
13 PacifiCorp AD
14 United States Bureau of Indian Affairs Bonnevile Power Administrtion US Bureau of Indian Affairs OS
15 Pacificorp Power Marketing PacifiCorp West PacifiCorp West OS
16 Black Hils Power PacifiCo West Bonnevile Power Administration NF
17 Black Hils Power PacifiCorp West Sierr Pacific Power NF
18 Bonnevile Power Admin.Bonnevile Power Administrtion Bonnevile Power Administration NF
19 Bonnevile Power Admin.Bonnevile Power Administrtion Avista NF
20 Bonneville Power Admin.Bonnevile Power Administration Sierr Pacific Power NF
21 Bonnevile Power Admin.Avista Bonnevile Power Administration NF
22 Bonnevile Power Admin.AD
23 Cargil Power Markets (INCL REDIR)PacifiCorp East PacifiCorp West NF
24 Cargil Power Markets (INCL REDIR)PacifiCorp East Bonnevile Power Administrtion NF
25 Cargil Power Markets (INCL REDIR)PacifiCorp East Sierr Pacific Power NF
26 Cargil Power Markets (INCL REDIR)PacifiCorp East Sierr Pacific Power SFP
27 Cargil Power Markets (INCL REDIR)PacifiCorp East PacifiCorp West NF
28 Cargil Power Markets (INCL REDIR)PacifiCorp East PacifiCorp West NF
29 Cargil Power Markets (INCL REDIR)PacifiCor East NortWestem/PacifiCorp East NF
30 Cargil Power Markets (INCL REDIR)PacifiCorp East Bonnevile Power Administration NF
31 Cargil Power Markets (INCL REDIR)PacifiCorp East Bonnevile Power Administration SFP
32 Cargil Power Markets (INCL REDIR)PacifiCorp East Avista NF
33 Cargill Power Markets (INCL REDIR)PacifiCorp East Sierra Pacific Power NF
34
TOTAL
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FERC FORM NO.1 (ED. 12-90)Page 328 I
This ~ort Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) 0 A Resubmission 04/15/2009ccoun 5 ontinue
(Including transactions reffered to as 'weeling')
IS. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contractdesignations 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
I 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.
17. 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 ü) the total megawatthours received and delivered.
I Name of RespondentIdaho Power Company
Year/Period of Report
End of 2008/Q4
I
I FERC Rate Point of Receipt Point of Delivery
Schedule of (Subsatation or Other (Substation or Other
1
Tariff Number Designation)Designation)
(e)(f)(g)
5
I:
5
I:
5
110
Minidoka, Idaho Various in Idaho
10
I:
LaGrande, Oregon Various in Idaho
15
JBSN ENPR
JBSN LGBP
5 JBSN M345
I:LGBP LGBP
LGBP LOLO
5 LGBP M345
I:LOLO LGBP
5 BOBR JBSN
I:BOBR LGBP
BOBR M345
5 BOBR M345
I:BORA ENPR
BORA ENPR
5 BORA JEFF
I:BORA LGBP
BORA LGBP
5 BORA LOLO
15 BORA M345
I FERC FORM NO.1 (ED. 12.90)329Page
Billng TRASFER OF ENERGY LineDemandMegaaUoursMegaaU Hours No.
(MW)Received Delivered
(h)(i)ü)
390,858 1
2
203,696 3
4
253,612 5
6
826,802 7
8
9,246 9
30,631 10
279,635 11
2,130 12
13
16,541 14
2,522 15
1,885 16
300 17
1,053 18
4,667 19
1,120 20
5,386 21
22
30 23
20,336 24
48,898 25
20,527 26
7,066 27
11,784 28
25 29
16,393 30
1,280 31
24 32
901 33
34
0 5,036,540
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 2008/Q4
(2) nA Resubmission 04/15/2009
I:Ll:v fRICJI Y i-UK u.' i-i: (~l~ccount 400.1)
(IncludinQ transactions referred to as 'wheelin ')
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authoriies,
qualifying facilities, non-traditional utiit 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 affliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, lFP - "long-Term Firm Point to Point
Transmission Service, OlF - Other long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line Payment By Energy Received From Energy Delivered To Statistical
No.(Company of Public Authority)(Company of Public Authorit)(Company of Public Authority)Classifi-
(Footnote Affliation)(Footnote Affliation)(Footnote Affliation)cation
(a)(b)(c)(d)
1 Cargil Power Markets (INCL REDIR)PacifiCorp East Sierra Pacific Power SFP
2 Cargil Power Markets (INCL REDIR)PacifiCorp East Bonneville Power Administration NF
3 Cargil Power Markets (lNCL REDIR)PacifCorp East NorthWesternlPacifCorp East SFP
4 Cargil Power Markets (INCL REDIR)PacifiCorp West PacifCorp East NF
5 Cargil Power Markets (INCL REDIR)PacifiCorp West PaciCorp East SFP
6 Cargil Power Markets (INCL REDIR)PacifiCorp West PacifCorp East NF
7 Cargil Power Markets (INCL REDIR)PacifCorp West Sierr Pacific Power NF
8 Cargil Power Markets (INCL REDIR)NortWesternlPacifCorp East PacifCorp East NF
9 Cargil Power Markets (INCL REDIR)NorthWesternlPacifCorp East PacifCorp East NF
10 Cargil Power Markets (INCL REDIR)PacifCorp West PacifCorp East NF
11 Cargil Power Markets (INCL REDIR)PacifCorp West PacifiCorp West NF
12 Cargil Power Markets (INCL REDIR)PacifCorp West .Idaho Power Company NF
13 Cargil Power Markets (INCL REDIR)PacifCorp West Bonnevile Power Administration NF
14 Cargill Power Markets (INCL REDIR)PacifiCorp West Sierra Pacific Power NF
15 Cargil Power Markets (INCL REDIR)NorthWesternlPacifiCorp East Sierra Pacifc Power NF
16 Cargil Power Markets (INCL REDIR)Bonnevile Power Administration PaciiCorp East NF
17 Cargil Power Markets (INCL REDIR)Bonnevile Power Administration PacifiCorp East NF
18 Cargil Power Markets (INCL REDIR)Bonneville Powr Administration PacifCorp West NF
19 Cargil Power Markets (INCL REDIR)Bonnevile Powr Administration Sierra Pacific Power NF
20 Cargill Power Markets (INCL REDIR)Avista PacifCorp East NF
21 Cargil Power Markets (INCL REDIR)Avista PacifiCorp East SFP
22 Cargil Power Markets (INCL REDIR)Avista PacifiCorp West NF
23 Cargil Power Markets (INCL REDIR)Avista Sierra Pacific Power NF
24 Cargil Power Markets (INCL REDIR)Sierra Pacific Power PacifiCorp East NF
25 Cargil Power Markets (INCL REDIR)Sierra Pacific Power PacifiCorp East SFP
26 Cargil Power Markets (INCL REDIR)Sierra Pacific Power PacifiCorp East NF
27 Cargil Power Markets (INCL REDIR)Sierra Pacific Power PacifiCorp East SFP
28 Cargil Power Markets (INCL REDIR)Sierra Pacific Power PacifiCorp East SFP
29 Cargil Power Markets (INCL REDIR)Sierra Pacifc Power Idaho Power Company SFP
30 Cargil Power Markets (INCL REDIR)Sierra Pacific Power Bonnevile Power Administration NF
31 Cargil Power Markets (INCL REDIR)Sierra Pacifc Power Bonneville Power Administration SFP
32 Cargil Power Markets (INCL REDIR)Sierra Pacific Power Bonnevile Power Administration NF
33 Cargil Power Markets (INCL REDIR)Sierra Pacific Power Avista NF
TOTAL
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FERC FORM NO.1 (ED. 12-90)Page 328.1 I
I
Name of Respondent This ø0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2008/Q4
(2)o A Resubmission 04/15/2009
QF i- Y FQK v i t1i:K~ ,(fJ ccount 45ö)((;Ontlnuec
I
(Including transactions reffered to as 'wteeling')
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.
I
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (t), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
I
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.
1
I FERC Rate Point of Receipt Point of Delivery Billng TRANSFER OF ENERGY Line
Schedule of (Subsatation or Other (Substation or Other Demand MegaWatt Hours MegaWatt Hours No.
1
Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)(g)(h)(i)ü)
5 BORA M345 192 19 1
5 BORA PF 220 22(2
I:BRDY HTSP 170 17(3
ENPR BOBR 139,253 139,25 4
5 ENPR BOBR 951 951 5
5 ENPR BORA 61,103 61,10 6
5 ENPR M345 5C 5C 7
5 HTSP BOBR 4,398 4,39E 8
I:HTSP BRDY 106 10E 9
JBSN BRDY 131 131 10
5 JBSN ENPR 7 11
I:JBSN IPCO 84 84 12
JBSN LGBP 8,270 8,270 13
5 JBSN M345 6,281 6,281 14
I:JEFF M345 36 3E 15
LGBP BOBR 1,837 1,83 16
5 LGBP BORA 88 8E 17
I:LGBP JBSN 1,324 1,324 18
LGBP M345 10,299 10,29~19
5 LOLO BOBR 8,290 8,29(20
5 LOLO BOBR 4,511 4,511 21
5 LOLO JBSN 195 19~22
5 LOLO M345 801 801 23
5 LYPK BOBR 24,583 24,58~24
5 LYPK BOBR 14,789 14,78~25
5 LYPK BORA 73,143 73,14~26
I:LYPK BORA 1,232 1,23~27
LYPK BRDY 170 17(28
5 LYPK IPCO 566 566 29
I:LYPK LGBP 2,540 2,54C 30
LYPK LGBP 696 69E 31
5 LYPK LGBP 15,242 15,24..32
15 LYPK LOLO 150 15(33
34
0 5,036,540 5,036,540
I
FERC FORM NO.1 (ED. 12-90)Page 329.1
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 2008/Q4
(2) ñ A Resubmission 04/1512009
-.ri T , ~~~ccnt 45tì.1)
(Including trnsctons referred to as 'wheeling')
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultmate customers for the quarter.
2. Use a separate line of data for each distinct type oftransmission 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 trncate name or use acronyms. Explain in a footnote
any ownership interest in or affliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classifcation 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 reportng periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line Payment By Energy Reæived From Energy Delivered To Statistical
No.(Company of Public Authority)(Company of Public Authority)(Company of Public Authority)Classifi-
(Footnote Affliation)(Footnote Affliation)(Footnote Affliation)cation
(a)(b)(c)(d)
1 Cargil Power Markets (INCL REDIR)Sierr Pacific Power Sierr Pacific Power NF
2 Cargil Power Markets (INCL REDIR)Sierr Pacific Powr Sierr Pacific Power SFP
3 Cargil Power Markets (INCL REDIR)Sierra Pacific Power PacifiCorp East NF
4 Cargil Power Markets (INCL REDIR)Sierra Pacific Power PacifiCorp East NF
5 Cargil Power Markets (INCL REDIR)Sierra Pacific Power PacifiCorp East NF
6 Cargil Power Markets (INCL REDIR)Sierra Pacific Power PacifiCorp West NF
7 Cargil Power Markets (INCL REDIR)Sierra Pacific Powr Bonnevile Power Administration NF
8 Cargil Power Markets (INCL REDIR)Sierra Pacific Power Bonnevile Power Administration NF
9 Cargil Power Markets (INCL REDIR)PacifiCorp East PacifiCorp East NF
10 Cargil Power Markets AD
11 Constellation Energy PacifiCorp East Sierr Pacific Power NF
12 Constellation Energy PacifiCorp East Sierr Pacific Power SFP
13 Constellation Energy NortWestemlPacifiCo East PacifiCorp East NF
14 Constellation Energy Avista Sierra Pacific Power NF
15 Constellation Energy Avista Sierr Pacific Power SFP
16 Constellation Energy Sierra Pacific Power PacifiCorp East NF
17 Constellation Energy PacifiCorp East PacifiCorp East NF
18 Constellation Energy Idaho Power Company PacifiCorp East NF
19 Constellation Energy Idaho Power Company Sierra Pacific Power NF
20 Coral Power PacifiCorp East Sierra Pacific Power NF
21 Coral Power PacifiCorp East PacifiCorp West NF
22 Coral Power PacifiCorp East Bonnevile Power Administration NF
23 Coral Power PacifiCorp East Avista NF
24 Coral Power PacifiCorp East Sierr Pacific Power NF
25 Coral Power PacifiCorp East Sierr Pacific Power NF
26 Coral Power PacifiCorp West Sierra Pacific Power NF
27 Coral Power NorthWestern/PacifiCorp East PacifiCorp East NF
28 Coral Power PacifiCorp West Bonnevile Power Administration NF
29 Coral Power PacifCorp West Sierr Pacific Power NF
30 Coral Power Idaho Power Company Sierr Pacific Power NF
31 Coral Power NortWestemlPacifiCor East Bonneville Power Administration NF
32 Coral Power NortWestem/PacifiCorp East Sierra Pacific Power NF
33 Coral Power Bonnevile Power Administrtion PacifiCorp East NF
34
TOTAL
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FERC FORM NO.1 (ED. 12-90)Page 328.2 I
I 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 2008/04
(2) Õ A Resubmission 04/15/2009
i i l.!" 1=1 Y , .v ccunt 456)(Continued)
I
(Including transactions reffered to as 'wheeling')
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
I
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 specifed in the
contract.
I
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 ü) the total megawatthours received and delivered.
I
FERC Rate Point of Receipt Point of Delivery Billng TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand MegaWatt Hours Megawatt Hours No.
Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)(g)(h)(i)0)
5 LYPK M345 67,363 67,36~1
5 LYPK M345 75,098 75,09f 2
5 M345 BOBR 22 2~3
5 M345 BORA 42 4~4
5 M345 BRDY 65 6"5
5 M345 ENPR 305 30~6
5 M345 LGBP 619 6H 7
5 M345 PF 6 €8
I:MLCK BOBR 1,024 1,02~9
10
5 BOBR M345 14,131 14,131 11
I:BOBR M345 1,180 1,18C 12
HTSP BOBR 1,003 1,00.13
5 LOLO M345 42,063 42,06.14
I:LOLO M345 13,667 13,66 15
LYPK BOBR 80 8(16
5 MLCK BOBR 400 40(17
5 OBBLPR BOBR 400 40(18
5 OBBLPR M345 864 86'19
5 BOBR M345 28,685 28,68!20
5 BORA ENPR 50 5(21
5 BORA LGBP 87 8 22
5 BORA LOLO 40 41 23
I:BORA M345 4,797 4,791 24
BRDY M345 940 94(25
5 ENPR M345 90 9(26
I:HTSP BRDY 295 29~27
JBSN LGBP 802 80~28
5 JBSN M345 232 23 29
I:JBWT M345 26,488 26,481 30
JEFF LGBP 1,338 1,33f 31
5 JEFF M345 478 47f 32
15 LGBP BOBR 880 88(33
34
0 5,036,540 5,036,54
I
FERC FORM NO.1 (ED. 12-90)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 2008/Q4
(2) ri A Resubmission 04/15/2009
OFi:r fUK '-." 'yJ,.'~~ccunt 45ö.l)
(Including trnsactons referred to as 'weeling')
1. Report all transmission of electrcity, Le., wheeling, provided for other electrc utilties, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line Payment By Energy Received From Energy Delivered To Statistical
No.(Company of Public Authority)(Company of Public Authority)(Company of Public Authority)Classifi-
(Footnote Affliation)(Footnote Affliation)(Footnote Affliation)cation
(a)(b)(c)(d)
1 Coral Power Bonnevile Power Administrtion Sierr Pacific Power NF
2 Coral Power Avista PacifiCor East NF
3 Coral Power Avista Sierr Pacific Power NF
4 Coral Power Sierr Pacific Power Bonnevile Power Administration NF
5 Coral Power Sierr Pacific Power Bonneville Power Administration NF
6 Coral Power PacifiCorp East PacifiCorp East NF
7 Coral Power PacifiCorp East PacifiCorp East NF
8 Coral Power AD
9 Highland Energy PacifiCorp East Bonnevile Power Administration NF
10 Highland Energy PacifiCorp East Bonneville Power Administration NF
11 Integrys Energy PacifiCorp West Bonnevile Power Administration NF
12 Integrys Energy Bonneville Power Administrtion Sierr Pacific Power NF
13 Morgan Stanley Capital Grp (INCL REDIR)PacifiCorp East Bonneville Power Administrtion NF
14 Morgan Stanley Capital Grp (INCL REDIR)PacifiCorp East Sierra Pacific Power NF
15 Morgan Stanley capital Grp (INCL REDIR)PaciCorp East PacifiCorp West NF
16 Morgan Stanley Capital Grp (INCL REDIR)PacifiCorp East Bonnevile Power Administration NF
17 Morgan Stanley Capital Grp (INCL REDIR)PacifiCorp East Bonnevile Power Administration NF
18 Morgan Stanley Capital Grp (INCL REDIR)PacifiCorp East PacifiCorp West NF
19 Morgan Stanley Capital Grp (INCL REDIR)PacifiCorp East NortWestern/PacifiCorp East NF
20 Morgan Stanley Capital Grp (INCL REDIR)PacifiCorp East Bonnevile Power Administration NF
21 Morgan Stanley Capital Grp (INCL REDIR)PacifiCorp West PacifiCorp East NF
22 Morgan Stanley Capital Grp (INCL REDIR)PacifiCorp West PacifiCorp East NF
23 Morgan Stanley Capital Grp (INCL REDIR)PacifiCorp West Sierr Pacific Power NF
24 Morgan Stanley Capital Grp (INCL REDIR)NorthWestemJPacifiCorp East PacifiCorp East NF
25 Morgan Stanley Capital Grp (INCL REDIR)NortWestemlacifiCorp East PacifiCorp East NF
26 Morgan Stanley Capital Grp (INCL REDIR)PacifiCorp West Sierr Pacific Power NF
27 Morgan Stanley Capital Grp (INCL REDIR)PacifiCorp West PacifiCorp West NF
28 Morgan Stanley Capital Grp (INCL REDIR)PacifiCorp West Bonnevile Power Administration NF
29 Morgan Stanley Capital Grp (INCL REDIR)Bonnevile Power Administration PacifiCo East NF
30 Morgan Stanley Capital Grp (INCL REDIR)Bonnevile Power Administration PacifiCorp East NF
31 Morgan Stanley Capital Grp (INCL REDIR)Bonnevile Power Administrtion PacifiCorp East NF
32 Morgan Stanley Capital Grp (INCL REDIR)Bonnevile Power Administration PacifiCorp West NF
33 Morgan Stanley Capital Grp (INCL REDIR)Bonnevile Power Administration Sierra Pacific Power NF
34
TOTAL
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I
I
I
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I
FERC FORM NO.1 (ED. 12-90)Page 328.3 I
I
I
Name of Respondent This 780rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2008/Q4
(2) 0 A Resubmission 04/15/2009
i aF ELECI KI.~II Y , '.~ yi ccount 456)(Continued)(Including transactions reffered to as 'wheeling')
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of 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 0) 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 MegaWatt Hours Megawatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)(g)(h)(i)ü)
5 LGBP M345 10,202 10,20::1
5 LOLO BOBR 65 6"2
5 LOLO M345 642 64~3
5 LYPK LGBP 733 73 4
5 M345 LGBP 4,613 4,61 5
5 MLCK BOBR 67 6 6
5 MLCK BRDY 7,592 7,59~7
5 8
5 BOBR LGBP 20 2 9
5 BORA LGBP 87 81 10
5 JBSN LGBP 125 12 11
5 LGBP M345 25 2~12
5 BOBR LGBP 2,813 2,81~13
5 BOBR M345 -6,184 6,18-14
5 BORA ENPR 1,169 1,16£15
5 BORA LGBP 123 12~16
5 BORA LGBP 210 21C 17
5 BRDY ENPR 783 78 18
5 BRDY HTSP 49 4~19
5 BRDY LGBP 3,677 3,67 20
5 ENPR BOBR 898 89~21
5 ENPR BRDY 1,079 1,07 22
5 ENPR M345 300 300 23
5 HTSP BOBR 210 21C 24
5 HTSP BRDY 375 37"25
5 JBSN M345 570 57C 26
5 JBSN ENPR 90 9C 27
5 JBSN LGBP 8,878 8,8n 28.
5 LGBP BOBR 2,382 2,38 29
5 LGBP BORA 1,002 1,00 30
5 LGBP BRDY 2,988 2,98~31
5 LGBP JBSN 415 41!:32
5 LGBP M345 428 42 33
34
0 5,036,540 5.036,54C
I
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I
I
FERC FORM NO.1 (ED. 12-90)Page 329.3
Name of Respondent ThiswrtlS:Date of Report YearlPeriod of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2008/Q4
(2)o A Resubmission 04/1512009
i I.OF ELE,CTKIl¿1 i Y J.~ccunt 4:Jb.l)
(Including trnsactions referred to as 'wheeling')
1. Report all transmission of electricity, Le., wheeling, provided for other electrc utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utiity 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 authonty. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affliation 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 onginal 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 Pointto PointTransmission
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 reportng 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 Affliation)(Footnote Affliation)(Footnote Affliation)cation
(a)(b)(c)(d)
1 Morgan Stanley Capital Grp (INCL REDIR)Avista PacifiCorp East NF
2 Morgan Stanley Capital Grp (INCL REDIR)Avista PacifiCorp West NF
3 Morgan Stanley Capital Grp (INCL REDIR)Avista Sierr Pacific Power NF
4 Morgan Stanley Capital Grp (INCL REDIR)Sierr Pacific Power Bonnevile Power Administration NF
5 Morgan Stanley Capital Grp (INCL REDIR)PacifiCorp East PacifiCorp East NF
6 Morgan Stanley Capital Grp AD
7 Northwestern Energy PacifiCorp East PacifiCorp East SFP
8 Pacificorp Power Marketing PacifiCorp East PacifiCorp East NF
9 Pacificorp Power Marketing PacifiCorp East PacifiCorp West NF
10 Pacificorp Power Marketing PacifiCorp East Sierra Pacific Power NF
11 Pacificorp Power Marketing PacifiCor East PacifiCorp West NF
12 Pacificorp Power Marketing PacifiCorp East PacifiCorp West NF
13 Pacificorp Power Marketing PacifiCorp East PacifiCorp East NF
14 Pacificorp Power Marketing PacifiCorp East PacifiCorp West NF
15 Pacificorp Power Marketing PacifiCorp West PacifiCorp East NF
16 Pacificorp Power Marketing PacifiCorp West PacifiCorp East SFP
17 Pacificorp Power Marketing PacifCorp West PacifiCorp East NF
18 Pacificorp Power Marketing PacifiCorp West PacifiCorp East NF
19 Pacificorp Power Marketing Idaho Power Company PacifiCorp West NF
20 Pacificorp Power Marketing PacifiCorp West PacifiCorp East NF
21 Pacificorp Power Marketing PacifiCorp West PacifiCorp East SFP
22 Pacificorp Power Marketing PacifiCorp West Siena Pacific Power NF
23 Pacificorp Power Marketing Idaho Power Company PacifiCorp East NF
24 Pacificorp Power Marketing Idaho Power Company PacifiCorp East SFP
25 Pacificorp Power Marketing Idaho Power Company PacifiCorp East NF
26 Pacificorp Power Marketing Idaho Power Company PacifiCorp East LFP
27 Pacificorp Power Marketing Idaho Power Company PacifiCorp East NF
28 Pacificorp Power Marketing Avista PacifiCorp West NF
29 Pacificorp Power Marketing AD
30 Portland General Electric PacifiCorp East Bonnevile Power Administration NF
31 Portland General Electric PacifiCorp East Bonnevile Power Administrtion NF
32 Portand General Electric NorthWestern/PacifiCorp East Bonnevile Power Administration NF
33 Portland General Electric NorthWesternlPacifiCorp East Bonnevile Power Administration NF
34
TOTAL
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I
FERC FORM NO.1 (ED. 12-90)Page 328.4 I
I Name of Respondent
This ø0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2008/Q4
(2)D A Resubmission 04/15/2009
I OF 1=1 '-;.V ccount 456)(Continued)
I
(Including transactions reffered to as 'wlìeeling')
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.
I
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.
I
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 megawatt. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and G) the total megawatthours received and delivered.
1
1 FERC Rate Point of Receipt Point of Delivery Biling TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand MegaWatt Hours Megawatt Hours No.
1
Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)(g)(h)(i)ü)
5 LOLO BOBR 118 11f 1
5 LOLO JBSN 42 4 2
5 LOLO M345 274 27'3
5 M345 LGBP 757 751 4
5 MLCK BRDY 5,560 5,56 5
5 6
5 BRDY LOLO 126 12(7
5 BOBR BOBR 170 17(8
I:BOBR ENPR 41,744 41,74 9
BOBR M345 1,200 1,20 10
5 BORA ENPR 62,592 62,59~11
I:BORA ENPR 11,091 11,091 12
BRDY BRDY 142 14'"13
5 BRDY ENPR 6,770 6,77(14
I:ENPR BOBR 29,610 29,61(15
ENPR BOBR 875 87~16
5 ENPR BORA 950 95(17
I:ENPR BRDY 2,065 2,06!18
HCPR ENPR 59 5!19
5 JBSN BOBR 52,500 52,50(20
5 JBSN BOBR 10,733 10,73.21
5 JBSN M345 4,885 4,88 22
5 JBWT BOBR 76,576 76,57 23
5 JBWT BOBR 12,058 12,05 24
5 JBWT BORA 115,937 115,93.25
5 JBWT BORA 31,992 31,99~26
I:JBWT BRDY 266,273 266,27'27
LOLO ENPR 961 961 28
5 29
I:BOBR LGBP 355 35"30
BORA LGBP 539 53 31
5 HTSP LGBP 120 12 32
15 JEFF LGBP 9,407 9,40 33
34
0 5,036,540 5,036,54~
I
FERC FORM NO.1 (ED. 12-90)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 2008/04
(2) t: A Resubmission 04/15/2009
i I.Ut- t:Ltl; I t\1~11 T r:ut\ \".".'~ ,..,.!.'~~ccunt 4bö.l)
(Including trnsactions referred to as 'wheeling')
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the enties 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 affliation 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 reportng 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 Affliation)(Footnote Affliation)(Footnote Affliation)cation
(a)(b)(c)(d)
1 Portand General Electric Bonnevile Power Administrtion Idaho Power Company NF
2 Portand General Electric Sierra Pacific Power Bonnevile Power Administration NF
3 Portland General Electric PacifiCorp East PacifiCorp East NF
4 Portland General Electric AD
5 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp East PacifiCorp West NF
6 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp East NortWestem/PacifiCorp East NF
7 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp East PacifiCorp West SFP
8 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp East Bonneville Power Administration NF
9 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp East Bonnevile Power Administration SFP
10 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp East Sierr Pacific Power SFP
11 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp East PacifCorp East NF
12 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp East PacifiCorp West NF
13 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp East Bonneville Power Administration NF
14 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp East Bonnevile Power Administration SFP
15 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp East Avista NF
16 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp East Sierr Pacific Power NF
17 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp East PacifiCorp West NF
18 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp East Bonnevile Power Administration NF
19 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp East Bonnevile Power Administration SFP
20 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp East Avista NF
21 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp West PacifiCorp East NF
22 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp West PacifiCorp East SFP
23 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp West PacifiCorp East NF
24 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp West PacifiCorp East SFP
25 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp West PacifiCorp East NF
26 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp West PacifiCorp West NF
27 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp West Sierr Pacific Power NF
28 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp West Sierr Pacific Power SFP
29 Powerex Corp. (INCLUDES REDIRECTS)NortWestemlPacifiCorp East PacifiCorp East NF
30 Powerex Corp. (INCLUDES REDIRECTS)NortWestemlPacifiCorp East PacifiCorp East SFP
31 Powerex Corp. (INCLUDES REDIRECTS)NortWestemlPacifiCorp East Sierr Pacific Power NF
32 Powerex Corp. (INCLUDES REDIRECTS)NorthWestem/PacifiCorp East Sierra Pacific Power SFP
33 Powerex Corp. (INCLUDES REDIRECTS)NorthWestern/PacifiCorp East PacifiCorp East NF
34
TOTAL
I
I
1
I
1
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I
1
1
I
I
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I
I
1
I
I
FERC FORM NO.1 (ED. 12-90)Page 328.5 I
I Name of Respondent
This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2008/Q4
(2) n A Resubmission 04/15/2009
'- . 1=1 F!-R \. i , ,.., '.OJ ,\r ccunt 456)(ContlnueâY
I
(Including transactions reffered to as 'weeling')
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 identifed in column (d), is provided.
I
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 ü) the total megawattours received and delivered.
I
I FERC Rate Point of Receipt Point of Delivery Biling TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand MegawatfRours MegaWatt Hours No.
I
Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)(g)(h)(i)ü)
5 LGBP IPCO 34 3~1
5 M345 LGBP 64 64 2
I:MLCK BRDY 8,847 8,841 3
.~4
5 BOBR ENPR 121 121 5
I:BOBR HTSP 464 46'6
BOBR JBSN 301 301 7
5 BOBR LGBP 43,342 43,34~8
I:BOBR LGBP 99 9!:9
BOBR M345 41,053 41,05~10
5 BORA BRDY 1,933 1,93~11
I:BORA ENPR 1,768 1,76f 12
BORA LGBP 66,149 66,14£13
5 BORA LGBP 1,200 1,20C 14
I:BORA LOLO 3,172 3,17~15
BORA M345 1,009 1,OO!:16
5 BRDY ENPR 15 11 17
I:BRDY LGBP 4,671 4,671 18
BRDY LGBP 5,266 5,261 19
5 BRDY LOLO 257 25 20
I:ENPR BOBR 90,322 90,32.21
ENPR BOBR 12,991 12,991 22
5 ENPR BORA 19,360 19,36(23
I:ENPR BORA 3,545 3,54'24
ENPR BRDY 16,702 16,70:25
5 ENPR JBSN 176 171 26
I:ENPR M345 2,612 2,61 27
ENPR M345 61,042 61,O4~28
5 HTSP BOBR 27,937 27,931 29
I:HTSP BOBR 482 48.30
HTSP M345 2,620 2,62(31
5 HTSP M345 30,444 30,44.32
15
HTSP BRDY 3,589 3,58~33
34
C 5,036,540 5,036,54~
1 FERC FORM NO.1 (ED. 12-90)Page 329.5
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 2008/Q4
(2) 0 A Resubmission 04/1512009
i i:UK U.I .... "."'.Y; ccunt 4::ö.l )(Including trnsactions referred to as 'wheeling')
1. Report all transmission of electricity, Le., wheeling, provided for other electric utiities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of trnsmission 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 trncate name or use acronyms. Explain in a footnote
any ownership interest in or affliation the respondent has with the entities listed in columns (a), (b) or (c)
4.ln 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 Energ Received From Energy Delivered To Statistical
No.(Company of Public Authority)(Company of Public Authonty)(Company of Public Authority)Classifi-
(Footnote Affliation)(Footnote Affliation)(Footnote Affliation)cation
(a)(b)(c)(d)
1 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp West PacifiCorp East NF
2 Powerex Corp. (INCLUDES REDIRECTS)PacifiCor West PacifiCorp West NF
3 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp West NorthWestem/PacifiCorp East NF
4 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp West Bonnevile Power Administration NF
5 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp West Avista NF
6 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp West Sierr Pacific Power NF
7 Powerex Corp. (INCLUDES REDIRECTS)PacifiCo West PacifiCorp West NF
8 Powerex Corp. (INCLUDES REDIRECTS)Idaho Powr Company PacifiCorp West NF
9 Powerex Corp. (INCLUDES REDIRECTS)Idaho Power Company Bonnevile Power Administrtion NF
10 Powerex Corp. (INCLUDES REDIRECTS)Idaho Power Company Avista NF
11 Powerex Corp. (INCLUDES REDIRECTS)Idaho Power Company Sierra Pacific Power NF
12 Powerex Corp. (INCLUDES REDIRECTS)NorthWestern/PacifiCorp East PacifiCorp East NF
13 Powerex Corp. (INCLUDES REDIRECTS)NorthWesternlPacifiCorp East PacifiCorp East NF
14 Powerex Corp. (INCLUDES REDIRECTS)NorthWestern/PacifiCorp East PacifiCorp West NF
15 Powerex Corp. (INCLUDES REDIRECTS)NorthWestern/PacifiCorp East PacifiCorp West NF
16 Powerex Corp. (INCLUDES REDIRECTS)NortWestern/PacifiCorp East Bonnevile Power Administration NF
17 Powerex Corp. (INCLUDES REDIRECTS)NortWestemlPacifiCo East Avista NF
18 Powerex Corp. (INCLUDES REDIRECTS)NortWestemlPacifiCo East Sierr Pacific Power NF
19 Powerex Corp. (INCLUDES REDIRECTS)Bonnevile Powr Administrtion PacifiCorp East NF
20 Powerex Corp. (INCLUDES REDIRECTS)Bonneville Power Administrtion PacifiCorp East SFP
21 Powerex Corp. (INCLUDES REDIRECTS)Bonneville Power Administration PacifiCorp East NF
22 Powerex Corp. (INCLUDES REDIRECTS)Bonneville Power Administration PacifiCorp East NF
23 Powerex Corp. (INCLUDES REDIRECTS)Bonneville Power Administration PacifiCorp West NF
24 Powerex Corp. (INCLUDES REDIRECTS)Bonnevile Power Administration Sierra Pacific Power NF
25 Powerex Corp. (INCLUDES REDIRECTS)Bonneville Power Administration Sierra Pacific Power SFP
26 Powerex Corp. (INCLUDES REDIRECTS)Avista PacifiCorp East NF
27 Powerex Corp. (INCLUDES REDIRECTS)Avista PacifiCorp East SFP
28 Powerex Corp. (INCLUDES REDIRECTS)Avista PacifiCorp East NF
29 Powerex Corp. (INCLUDES REDIRECTS)Avista PacifiCorp West NF
30 Powerex Corp. (INCLUDES REDIRECTS)Avista PacifiCorp West NF
31 Powerex Corp. (INCLUDES REDIRECTS)Avista Bonneville Power Administration NF
32 Powerex Corp. (INCLUDES REDIRECTS)Avista Sierr Pacific Power NF
33 Powerex Corp. (INCLUDES REDIRECTS)Avista Sierra Pacific Power SFP
34
TOTAL
I
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I
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I
FERC FORM NO.1 (ED. 12-90)Page 328.6 I
I
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 2008/Q4
(2) n A Resubmission 04/15/2009
t:Lt:l'1 KIYII Y FQR L!! Nt:K.~(Jl ccount 456)(Continued)
I
(Including transactions reffered to as 'wheeling')
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
I
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.
I
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 G) the total megawatthours received and delivered.
I
I FERC Rate Point of Receipt Point of Delivery Billng TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand MegaWatt Hours MegaWatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)(g)(h)(i)0)
JBSN BRDY 759 75~1
5 JBSN ENPR 2,202 2,20"2
I:JBSN JEFF 12 1 3
JBSN LGBP 56,155 56,15e 4
5 JBSN LOLO 218 21E 5
I ~JBSN M345 3,673 3,67.6
5 JBSN M500 450 45C 7
I:
JBWT ENPR 363 36 8
JBWT LGBP 9,769 9,76~9
JBWT LOLO 82 8 10
5 JBWT M345 130 13C 11
I 5 JEFF BOBR 2,542 2,54"12
~JEFF BORA 226 22E 13
5 JEFF ENPR 29 2~14
I l5 JEFF JBSN 607 601 15
5 JEFF LGBP 1,620 1,62C 16
5 JEFF LOLO 195 19~17
I 15 JEFF M345 2,350 2,35C 18
5 LGBP BOBR 10,225 10,22'19
5 LGBP BOBR 240 240 20
I 15 LGBP BORA 21,515 21,51c 21
is LGBP BRDY 46 4E 22
I:
LGBP JBSN 3,837 3,831 23
LGBP M345 20,566 20,56E 24
LGBP M345 8,196 8,19E 25
5 LOLO BOBR 992 99 26
I:LOLO BOBR 5,559 5,55~27
LOLO BORA 2,015 2,01~28
5 LOLO ENPR 30 30 29
I:LOLO JBSN 172 172 30
LOLO LGBP 113 11~31
5 LOLO M345 27,590 27,59C 32
15
LOLO M345 5,354 5,354 33
34
I
0 5,036,540 5,036,54C
FERC FORM NO.1 (ED. 12-90)Page 329.6
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 2008/Q4
(2) DA Resubmission 04/151009
'.ui- T '. .i~ccunt 400.1)
(Including transactons referred to as 'wheeling')
1. Report all transmission of electricity, Le., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utilit 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 affliation 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 contrctual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, lFP - "Long-Term Firm Point to Point
Transmission Service, OlF - Other long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line Payment By Energy Received From Energy Delivered To Statistical
No.(Company of Public Authority)(Company of Public Authority)(Company of Public Authority)Classifi-
(Footnote Affliation)(Footnote Affliation)(Footnote Affliation)cation
(a)(b)(c)(d)
1 Powerex Corp. (INCLUDES REDIRECTS)Sierra Pacific Powr PacifiCorp East NF
2 Powerex Corp. (INCLUDES REDIRECTS)Sierra Pacific Power Bonnevile Power Administration NF
3 Powerex Corp. (INCLUDES REDIRECTS)Sierr Pacific Power Sierr Pacific Power NF
4 Powerex Corp. (INCLUDES REDIRECTS)Sierra Pacific Power PacifiCorp East NF
5 Powerex Corp. (INCLUDES REDIRECTS)Sierra Pacific Power PacifiCorp West NF
6 Powerex Corp. (INCLUDES REDIRECTS)Sierr Pacific Power Bonneville Power Administration NF
7 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp East PacifiCorp East NF
8 Powerex Corp. (INCLUDES REDIRECTS)PacifiCorp East PacifiCorp East NF
9 Powerex Corp.AD
10 PPL EnergyPlus, LLC (EPLU)PacifiCorp East Bonnevile Power Administration NF
11 PPL EnergyPlus, LLC (EPLU)PacifiCorp East Bonnevile Power Administration NF
12 PPL EnergyPlus, LLC (EPLU)NorthWestem/PacifiCorp East PacifiCorp East NF
13 PPL EnergyPlus, LLC (EPLU)NorthWestern/PacifiCorp East PacifiCorp East NF
14 PPL EnergyPlus, LLC (EPLU)PacifiCorp West Bonnevile Power Administration NF
15 PPL EnergyPlus, LLC (EPLU)NorthWestern/PacifiCorp East PacifiCorp East NF
16 PPL EnergyPlus, LLC (EPLU)NorthWestem/PacifiCorp East Bonneville Power Administration NF
17 PPL EnergyPlus, LLC (EPLU)NorthWesternPacifiCorp East Avista NF
18 PPL EnergyPlus, LLC (EPLU)PacifiCorp East PacifiCorp East NF
19 PPL EnergyPlus, LLC (EPLU)PacifiCorp East PacifiCorp East NF
20 PPL EnergyPlus, LLC (EPLU)AD
21 PPM Energy PacifiCorp East Bonnevile Power Administration NF
22 PPM Energy PacifCorp East Bonneville Power Administration NF
23 PPM Energy PacifiCo West Bonneville Power Administration NF
24 PPM Energy Bonnevile Power Administrtion PacifiCorp East NF
25 PPM Energy Sierra Pacific Power Bonnevile Power Administrtion NF
26 PPM Energy AD
27 Puget Sound Energy NortWestem/PacifiCorp East PacifiCorp East NF
28 Puget Sound Energy NortWesternPacifiCorp East PacifiCorp East NF
29 Puget Sound Energy PacifiCorp East PacifiCorp East NF
30 Puget Sound Energy AD
31 Rainbow Energy Marketing Company PacifiCorp East Sierr Pacific Power NF
32 Rainbow Energy Marketing Company PacifiCorp East Sierr Pacific Power SFP
33 Rainbow Energy Marketing Company PacifiCorp West Sierra Pacific Power SFP
34
TOTAL
I
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I
I
I
I
I
I
FERC FORM NO.1 (ED. 12-90)IPage 328.7
I 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 2008/Q4
(2)D A Resubmission 04/15/2009
i l:Lt:lJ I KI.!-II Y F9R L!! Ht:K.~ 1". ccount 456)((;OntlnUed)
(Including transactions reffered to as 'wneeling')
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.
I
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.
I
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.
I
I FERC Rate Point of Receipt Point of Delivery Biling TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand MegaWatt Hours MegaWatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)(g)(h)(i)u)
5 LYPK BOBR 128 121 1
5 LYPK LGBP 20 2(2
I:LYPK M345 48 4 3
M345 BOBR 1,152 1,15~4
5 M345 ENPR 14 1~5
I:M345 LGBP 11,743 11,74~6
MLCK BOBR 11,027 11,021 7
5 MLCK BRDY 6,058 6,051 8
I:,9
BOBR LGBP 983 98 10
5 BRDY LGBP 108 101 11
I:HTSP BOBR 326 32t 12
HTSP BRDY 2 :.13
5 JBSN LGBP 133 13 14
5 JEFF BOBR 115 11 15
5 JEFF LGBP 10,707 10,70¡16
5 JEFF LOLO 750 751 17
I:MLCK BOBR 8,029 8,02~18
MLCK BRDY 14,503 14,50~19
5 20
I:BOBR LGBP 2,542 2,54'21
BORA LGBP 667 667 22
5 ENPR LGBP 80 8e 23
I:LGBP BOBR 1,135 1,13~24
M345 LGBP 100 10 25
5 26
I:HTSP BOBR 1,032 1,03.27
HTSP BRDY 435 43 28
5 MLCK BRDY 12,854 12,85¿29
I:30
BOBR M345 2,622 2,62'31
5 BOBR M345 32,797 32,797 32
15
ENPR M345 1,377 1,377 33
34
0 5,036,540 5,036,54(
I FERC FORM NO.1 (ED. 12-90)Page 329.7
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 2008/Q4
(2) nA Resubmission 04/15/2009
ioi..:'- 11'(1;_11 T _ lI~ccunt 456.1)
(IncludinQ transactions referred to as 'wheeling')
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line Payment By Energy Received From Energy Delivered To Statistical
No.(Company of Public Authority)(Company of Public Authority)(Company of Public Authority)Classifi-
(Footnote Affliation)(Footnote Affliation)(Footnote Affliation)cation
(a)(b)(c)(d)
1 Rainbow Energy Marketing Company NorthWesternlacifiorp East PacifCorp East NF
2 Rainbow Energy Marketing Company NorthWesternlaciCorp East PacifiCorp East SFP
3 Rainbow Energy Marketing Company NorthWestern/PacifCorp East PacifiCorp East NF
4 Rainbow Energy Marketing Company PacifCorp West NorthWesternlPacifiCorp East NF
5 Rainbow Energy Marketing Company PacifCorp West Bonnevile Power Administration NF
6 Rainbow Energy Marketing Company PacifCorp West Sierra Pacific Power NF
7 Rainbow Energy Marketing Company NorthWesternlacifCorp East Bonnevile Power Administration NF
8 Rainbow Energy Marketing Company NorthWesternlPacifCorp East Avista NF
9 Rainbow Energy Marketing Company NorthWestern/PacifiCorp East Sierra Pacific Power NF
10 Rainbow Energy Marketing Company NorthWestern/PacifiCorp East Bonnevile Power Administration NF
11 Rainbow Energy Marketing Company Bonnevile Power Administration PacifiCorp West NF
12 Rainbow Energy Marketing Company Bonneville Powr Administration Sierr Pacific Power NF
13 Rainbow Energy Marketing Company Bonnevile Power Administration Sierra Pacific Power SFP
14 Rainbow Energy Marketing Company Avista PacifiCorp West NF
15 Rainbow Energy Marketing Company Avista Sierra Pacific Power NF
16 Rainbow Energy Marketing Company Avista Sierra Pacific Power SFP
17 Rainbow Energy Marketing Company Sierra Pacifc Power Bonneville Power Administration NF
18 Rainbow Energy Marketing Company PacifCorp East PacifiCorp East NF
19 Rainbow Energy Marketing Company PacifiCorp East PacifiCorp East NF
20 Seatte City Light NF
21 Sempra Energy Trading Corp NorthWestern/PacifiCorp East PacifiCorp East SFP
22 Sempra Energy Trading Corp PacifiCorp East PacifiCorp East NF
23 Sempra Energy Trading Corp LFP
24 Sierra Pacific Power (INCL REDIR)PacifiCorp East PacifiCorp West NF
25 Sierra Pacifc Power (INCL REDIR)PacifiCorp East Sierra Pacific Power NF
26 Sierra Pacific Power (INCL REDIR)PacifCorp East Sierra Pacific Power SFP
27 Sierra Pacific Power (INCL REDIR)PacifiCorp East Bonnevile Power Administration NF
28 Sierra Pacific Power (INCL REDIR)PacifiCorp East Sierra Pacific Power NF
29 Sierra Pacific Power (INCL REDIR)PacifiCorp East Sierra Pacifc Power SFP
30 Sierra Pacific Power (INCL REDIR)PacifiCorp West Sierra Pacific Power NF
31 Sierra Pacifc Power (INCL REDIR)NorthWestern/PacifCorp East PacifiCorp East NF
32 Sierra Pacific Power (INCL REDIR)NorthWesternlPacifiCorp East PacifiCorp East NF
33 Sierra Pacific Power (INCL REDIR)PacifiCorp West PacifiCorp East NF
TOTAL
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I
I
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I
I
FERC FORM NO.1 (ED. 12-90)Page 328.8 I
I Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) n A Resubmission 04/15/2009
L!!" ~. ~ l? I H~K.:: ,(Il ccount 4oti)((.ontlnueo)
I (Including transactions reftered to as 'wheeling')
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
I 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.
I 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 u) the total megawatthours received and delivered.
I
1 FERC Rate Point of Receipt Point of Delivery Billng TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand MegaWatt Hours MegaWatt Hours No.
I
Tariff Number Designation)Designation)(MW)Received Delivered(e)(f)(g)(h)(i)0)
5 HTSP BOBR 10,918 10,91E 1
5 HTSP BOBR 3,687 3,681 2
I:HTSP BRDY 3,592 3,59~3
JBSN JEFF 650 65(4
5 JBSN LGBP 52 5~5
I:JBSN M345 131 131 6
JEFF LGBP 720 72C 7
5 JEFF LOLO 272 27~8
I:JEFF M345 852 8~9
JEFF OTEC 25 2-10
5 LGBP JBSN 571 571 11
I:LGBP M345 5,74£5,74~12
LGBP M345 16,215 16,211 13
5 LOLO JBSN 25 21 14
I:LOLO M345 25,041 25,041 15
LOLO M345 43,397 43,39,16
5 M345 LGBP 1,046 1,041 17
I:MLCK BOBR 240 24C 18
MLCK BRDY 400 40C 19
5 20
I:HTSP BOBR 16,644 16,64~21
MLCK BOBR 25 2"22
5 23
I:BOBR JBSN 25 2~24
BOBR M345 10,048 10,04f 25
5 BOBR M345 49,165 49,161 26
I 5 BORA LGBP 2,200 2,20(27
5 BORA M345 11,779 11,77~28
5 BORA M345 5,200 5,20(29
I 5 ENPR M345 1,567 1,56 30
5 HTSP BOBR 48,434 48,43'31
5 HTSP BRDY 2,110 2,11(32
I 5 JBSN BOBR 600 60(33
34
I
(5,036,540 5,036,54
FERC FORM NO. 1 (ED. 12-90)Page 329.8
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 2008/Q4
(2) n A Resubmission 04/15/2009
i __._ I KIl¿l I Y F:9R U, ccum 400.1)
(Including trnsactons referred to as 'wheeling')
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilties, cooperatives, other public authorities,
qualifying facilities, 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 contrctual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Netwrk Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line Payment By Energy Received From Energy Delivered To Statistical
No.(Company of Public Authority)(Company of Public Authorty)(Company of Public Authority)Classifi-
(Footnote Affliation)(Footnote Affliation)(Footnote Affliation)cation
(a)(b)(c)(d)
1 Sierra Pacific Power (INCL REDIR)PacifiCorp West PacifiCorp East NF
2 Sierra Pacific Power (INCL REDIR)PacifiCo West Idaho Power Company NF
3 Sierra Pacific Power (INCL REDIR)PacifiCorp West Bonnevile Power Administration NF
4 Sierra Pacific Power (INCL REDIR)PacifiCorp West Sierr Pacific Power NF
5 Sierra Pacific Power (INCL REDIR)NorthWestem/PacifiCorp East PacifiCorp East NF
6 Sierra Pacific Power (INCL REDIR)NorthWestern/PacifiCorp East Sierr Pacific Power NF
7 Sierr Pacific Power (INCL REDIR)Bonnevile Power Administration PacifiCorp East NF
8 Sierra Pacific Power (INCL REDIR)Bonnevile Power Administration Sierr Pacific Power NF
9 Sierra Pacific Power (INCL REDIR)Bonnevile Power Administrtion Sierr Pacific Power SFP
10 Sierra Pacific Power (INCL REDIR)Avista PacifiCorp East NF
11 Sierra Pacific Power (INCL REDIR)Avista Sierr Pacific Power NF
12 Sierra Pacific Power (INCL REDIR)Avista Sierr Pacific Power SFP
13 Sierra Pacific Power (INCL REDIR)Sierr Pacific Power PacifiCorp East NF
14 Sierra Pacific Power (INCL REDIR)Sierr Pacific Power PacifiCorp East NF
15 Sierra Pacific Power (INCL REDIR)Sierra Pacific Power PacifiCorp West NF
16 Sierra Pacific Power (INCL REDIR)Sierra Pacific Power NorthWestern/PacifiCorp East NF
17 Sierra Pacific Power (INCL REDIR)Sierr Pacific Power Bonnevile Power Administration NF
18 Sierra Pacific Power (INCL REDIR)PacifiCorp East PacifiCorp East NF
19 Sierra Pacific Power (INCL REDIR)PacifiCorp East PacifiCorp East NF
20 Sierr Pacific Power (INCL REDIR)Idaho Power Company Idaho Power Company NF
21 Sierra Pacific Power AD
22 TransAlta Energy Marketing PacifiCo East Bonnevile Power Administration NF
23 TransAlta Energy Marketing PacifiCorp East PacifiCorp East NF
24 Utah Associated Municipal Power Systems PacifiCorp East Sierra Pacific Power NF
25 Utah Associated Municipal Power Systems PacifiCorp East Sierra Pacific Power NF
26
27
28
29
30
31
32
33
34
TOTAL
I
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I
I
I
I
I
FERC FORM NO.1 (ED. 12-90)Page 328.9 I
I Name of Respondent This Report Is:Date of Report Year/Period of Report
Idaho Power Company (1) 0An Original (Mo, Da, Yr)End of 2008/Q4
(2)D A Resubmission 04/15/2009
i _~_~ I KI,~II Y i-YK ll! ._, '.~ ccount 456)(Continued)
I
(Including transactions reffered to as 'wH'eeling')
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.
I
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 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 u) the total megawatthours received and delivered.
I
I FERC Rate Point of Receipt Point of Delivery Biling TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand MegaWatt Hours MegaWatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)(g)(h)(i)0)
5 JBSN BRDY 150 15C 1
5 JBSN IPCO 36 3E 2
5 JBSN LGBP 200 20C 3
5 JBSN M345 47,354 47,350 4
5 JEFF BOBR 146 14E 5
I:JEFF M345 129,276 129,21t 6
LGBP BOBR 920 92C 7
5 LGBP M345 54,167 54,161 8
I:LGBP M345 475 47e 9
LOLO BOBR 992 99.10
5 LOLO M345 58,075 58,07~11
I:LOLO M345 28,832 28,83~12
M345 BOBR 641 641 13
5 M345 BRDY 60 6C 14
I:M345 JBSN 497 ,491 15
M345 JEFF 874 874 16
5 M345 LGBP 14,700 14,10C 17
I:MLCK BOBR 39,546 39,54E 18
MLCK BRDY 1,884 1,88A 19
5 OBBLPR IPCO 128 12f 20
I:21
BORA LGBP 122 12.22
5 MLCK BOBR 100 10C 23
I:BOBR M345 2,650 2,65C 24
BORA M345 3,984 3,984 25
26
I 27
28
29
I 30
31
32
I 33
34
0 5,036,540 5,036,54C
I FERC FORM NO.1 (ED. 12-90)Page 329.9
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2008/Q4
(2) n A Resubmission 04/15/2009
i U.f ELEl;l 1"1.1,11 Y FQR u i ,..":- lr CCU'!t 456) (i;ontinued)
(Including trnsactons reffered to as 'wfieeling')
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 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 settement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and 0) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)(k+l+m)No.
(k)(I)(m)(n)
1,419,857 -275,411 1,144,446 1
-17,193 -17,193 2
1,117,728 -134,236 1,043,492 3
-8,537 -8,537 4
627,795 13,886 641,681 5
-9,022 -9,022 6
2,569,661 79,793 2,649,454 7
-32,678 -32,678 8
14,978 14,978 9
-57,845 -57,845 10
150,297 150,297 11
6,589 1,407 7,996 12
-87 -87 13
54,602 54,602 14
7,984 7,984 15
17,969 17,969 16
2,860 2,860 17
2,730 2,730 18
12,100 12,100 19
2,904 2,90 20
13,964 13,964 21
-2,016 -2,016 22
87 87 23
58,990 58,990 24
141,825 141,825 25
59,559 59,559 26
20,497 20,497 27
34,182 34,182 28
73 73 29
47,551 47,551 30
3,714 3,714 31
70 70 32
2,613 2,613 33
34
5,788,715 12,534,575 0 18,323,290
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FERC FORM NO.1 (ED. 12-90)Page 330
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Name of Respondent This~rtIS:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2008/Q4
(2) ¡= A Resubmission 0411512009
. u,!' FQR L! i. ni:t(~ lAccunt 45ö) (l,ontinueo)
I
(Including trnsactions reffered to as 'wheeling')
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
I 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
I
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.
I
I REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)(k+l+m)No.
(k)(I)(m)(n)
557 557 1
638 638 2
493 493 3
403,936 403,936 4
2,759 2,759 5
177,244 177,244 6
145 145 7
12,757 12,757 8
307 307 9
380 380 10
20 20 11
244 244 12
23,989 23,989 13
18,220 18,220 14
104 104 15
5,329 5,329 16
255 255 17
I 3,841 3,841 18
29,875 29,875 19
24,044 24,044 20
13,089 13,089 21
566 566 22
2,323 2,323 23
I 71,298 71,298 24
42,910 42,910 25
212,160 212,160 26
I 3,583 3,583 27
.493 493 28
1,642 1,642 29
I 7,356 7,356 30
2,019 2,019 31
44,225 44,225 32
I 435 435 33
34
5,788,715 12,534,575 0 18,323,290I
FERC FORM NO.1 (ED. 12-90)Page 330.1
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 2008/Q4
(2) n A Resubmission 04/15/2009
i ......" I KIl,l I Y FQR u i ,..,',.. lr ccu'!t 456) (i;(mtlnUed)
(Including transactions reffered to as 'wheeling')
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 billing demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on 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 u) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)(k+l+m)No.
(k)(I)(m)(n)
195,346 195,346 1
217,897 217,897 2
64 64 3
122 122 4
189 189 5
885 885 6
1,796 1,796 7
17 17 8
2,970 2,970 9
-23,567 -23,567 10
42,622 42,622 11
3,559 3,559 12
3,025 3,025 13
126,872 -126,872 14
41,223 41,223 15
241 241 16
1,206 1,206 17
1,206 1,206 18
2,606 2,606 19
90,343 90,343 20
157 157 21
274 274 22
126 126 23
15,108 15,108 24
2,961 2,961 25
283 283 26
929 929 27
2,526 2,526 28
731 731 29
83,423 83,423 30
4,214 4,214 31
1,505 1,505 32
2,772 2,772 33
34
5,788,715 12,534,575 0 18,323,290
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IFERC FORM NO.1 (ED. 12-90)Page 330.2
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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 2008/Q4
(2) 0 A Resubmission 04/15/2009
T i-~K ~ i. ,~.,~ x: ccunt 4bö) (L;ontinued)
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(Including transactions reffered to as 'wlieelinQ')
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 bills or vouchers rendered, including
I 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
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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.
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I REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
I
($)($)($)(k+l+m)No.
(k)(I)(m)(n)
32,131 32,131 1
205 205 2
I 2,022 2,022 3
2,309 2,309 4
14,529 14,529 5
211 211 6
23,911 23,911 7
-572 -572 8
114 114 9
496 496 10
486 486 11
97 97 12
9,257 9,257 13
20,349 20,349 14
3,847 3,847 15
405 405 16
691 691 17
2,577 2,577 18
161 161 19
12,100 12,100 20
2,955 2,955 21
3,551 3,551 22
987 987 23
691 691 24
1,234 1,234 25
1,876 1,876 26
296 296 27
29,214 29,214 28
7,838 7,838 29
I 3,297 3,297 30
9,832 9,832 31
1,366 1,366 32
I 1,408 1,408 33
34
5,788,715 12,534,575 0 18,323,290
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FERC FORM NO.1 (ED. 12-90)Page 330.3
Name of Respondent ThiS~IS:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2008/Q4
(2) 0 A Resubmission 04/15/2009
i _.,_~ I KI.yll Y i-YK L! ccunt 456) (Continued)
(Including trnsactions reffered to as 'wlieeling')
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 billing demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on 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 u) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectvely.
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)
388 388 1
138 138 2
902 902 3
2,491 2,491 4
18,296 18,296 5
-669 -669 6
1,029 1,029 7
727 727 8
178,524 178,524 9
5,132 5,132 10
267,683 267,683 11
47,432 47,432 12
607 607 13
28,953 28,953 14
126,631 126,631 15
3,742 3,742 16
4,063 4,063 17
8,831 8,831 18
252 252 19
224,523 224,523 20
45,901 45,901 21
20,891 20,891 22
327,487 327,487 23
51,568 51,568 24
495,820 495,820 25
136,818 136,818 26
1,138,751 1,138,751 27
4,110 4,110 28
-37,679 -37,679 29
985 985 30
1,496 1,496 31
333 333 32
26,106 26,106 33
34
5,788,715 12,534,575 0 18,323,290
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FERC FORM NO.1 (ED. 12-90)Page 330.4
I Name of Respondent
This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2008/Q4
(2) Õ A Resubmission 04/15/2009
~ ~.,~~ I KI.yll y' FQR ~ i. ccunt 456) (Continued)
(Including trnsactions reffered to as 'weeling')
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 settement, 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.
I
I REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
I ($)($)($)(k+l+m)No.
(k)(I)(m)(n)
94 94 1
1,787 1,787 2
I 24,552 24,552 3
-788 -788 4
513 513 5
I 1,967 1,967 6
1,276 1,276 7
183,755 183,755 8
I 420 420 9
174,051 174,051 10
8,195 8,195 11
I 7,496 7,496 12
280,449 280,449 13
5,088 5,088 14
I 13,448 13,448 15
4,278 4,278 16
64 64 17
I 19,803 19,803 18
22,326 22,326 19
1,090 1,090 20
I 382,934 382,934 21
55,077 55,077 22
82,080 82,080 23
I 15,030 15,030 24
70,811 70,811 25
746 746 26
I 11,074 11,074 27
258,797 258,797 28
118,443 118,443 29
I 2,044 2,044 30
11,108 11,108 31
129,072 129,072 32
I 15,216 15,216 33
34
5,788,715 12,534,575 0 18,323,290I
FERC FORM NO.1 (ED. 12-90)Page 330.5
Name of Respondent ThiS~IS:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2008/Q4
(2) M A Resubmission 04/15/2009
L U.f i i y . i l/l ccunt 456) (Continued)(Including trnsactions reffered to as 'wheeling')
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 settement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and 0) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)(k+l+m)No.
(k)(I)(m)(n)
3,218 3,218 1
9,336 9,336 2
51 51 3
238,078 238,078 4
924 924 5
15,572 15,572 6
1,908 1,908 7
1,539 1,539 8
41,417 41,417 9
348 348 10
551 551 11
10,7n 10,n7 12
958 958 13
123 123 14
2,573 2,573 15
6,868 6,868 16
827 827 17
9,963 9,963 18
43,350 43,350 19
1,018 1,018 20
91,216 91,216 21
195 195 22
16,268 16,268 23
87,193 87,193 24
34,748 34,748 25
4,206 4,206 26
23,568 23,568 27
8,543 8,543 28
127 127 29
729 729 30
479 479 31
116,972 116,972 32
22,699 22,699 33
34
5,788,715 12,534,575 0 18,323,290
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FERC FORM NO.1 (ED. 12-90)Page 330.6
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Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2008/Q4
(2)o A Resubmission 04/15/2009
: u.~ T i-lJ ccount 45ti) (i;ontinuea)
I
(Including transactions reffered to as 'wfieelina')
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 biling demand reported in column (h). In column (I), provide revenues from energy charges related to the
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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
I
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.
I
I REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
I
($)($)($)(k+l+m)No.
(k)(I)(m)(n)
543 543 1
85 85 2
I 204 204 3
4,884 4,884 4
59 59 5I49,786 49,786 6
46,751 46,751 7
25,684 25,684 8
I -31,619 -31,619 9
2,569 2,569 10
282 282 11
I 852 852 12
5 5 13
348 348 14
I 301 301 15
27,984 27,984 16
1,960 1,960 17
I 20,985 20,985 18
37,905 37,905 19
-646 -646 20
I 9,443 9,443 21
2,478 2,478 22
297 297 23
I 4,216 4,216 24
371 371 25
-97 -97 26
I 5,346 5,346 27
2,253 2,253 28
66,588 66,588 29
I -4,147 -4,147 30
9,225 9,225 31
115,392 115,392 32
I 4,845 4,845 33
34
5,788,715 12,534,575 0 18,323,290I
FERC FORM NO.1 (ED. 12-90)Page 330.7
Name of Respondent ThiS~IS:Date of Report Year/Period of Report
Idaho Power Company (1) X An Onginal (Mo, Da, Yr)End of 2008/04
(2)o A Resubmission 04/1512009
. O.r 1=1 T , ~' , '" ',' ,~, ':- ~ccunt 456) (Continued)
(Including trnsactions reffered to as 'wIeeling')
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 entiy Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and 0) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)(k+l+m)No.
(k)(I)(m)(n)
38,413 38,413 1
12,972 12,972 2
12,638 12,638 3
2,287 2,287 4
183 183 5
461 461 6
2,533 2,533 7
957 957 8
2,998 2,998 9
88 88 10
2,009 2,009 11
20,227 20,227 12
57,050 57,050 13
88 88 14
88,103 88,103 15
152,686 152,686 16
3.680 3,680 17
84 844 18
1,407 1,407 19
1,879,637 1,879,637 20
97,457 97,457 21
146 146 22
-3,602 -3,602 23
78 78 24
31,245 31,245 25
152,883 152,883 26
6,841 6,841 27
36,628 36,628 28
16,170 16,170 29
4,873 4,873 30
150,610 150,610 31
6,561 6,561 32
1,866 1,866 33
34
5,788,715 12,534,575 0 18,323,290
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FERC FORM NO.1 (ED. 12-90)Page 330.8
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Name of Respondent This 780rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2008/04
(2)D A Resubmission 04/15/2009
L."'L.v' KI.yll Y i-YK L! ccount 455) ((;OnbnUeO)
(Including transactions reffered to as 'wheeling')
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)
466 466 1
112 112 2
622 622 3
147,252 147,252 4
454 454 5
401,997 401,997 6
2,861 2,861 7
168,438 168,438 8
1,477 1,477 9
3,085 3,085 10
180,590 180,590 11
89,659 89,659 12
1,993 1,993 13
187 187 14
1,545 1,545 15
2,718 2,718 16
45,711 45,711 17
122,973 122,973 18
5,858 5,858 19
398 398 20
-24,824 -24,824 21
307 307 22
251 251 23
8,841 8,841 24
13,292 13,292 25
26
27
28
29
30
31
32
33
34
5,788,715 12,534,575 0 18,323,290
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FERC FORM NO.1 (ED. 12-90)Page 330.9
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 04/15/200 2008/Q4
FOOTNOTE DATA
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~chiiu/~-eagi;:-328 u_l!!~No.~1 Column:-e--.---------- ---
5, Open Access Transmission Tariff, Volume 5, first revision
¡scheiiii/iii~i¡¡:-.328 Line No.: 1 Coiuiiñ-:h---- --==________________n_ .---.-
The network service agreement between Idaho Power and the Bonneville Power Administration for the Oregon Trail Electric Cooperative expires
September 30, 2011.
~chec!ule Page:- 328 Line No.: 2 ColumÏÎ:h---
OA TT rate adjustments fied for periods prior to 2008
fSch~dule Page: 328 Line No.: 3 Column: -h~---- ::- ..- .___n__
The network service agreement between Idaho Power and the Bonneville Power Administration for the USBR expires December 31, 2014.
The biling demand for network service is the._~.!stomets demand at the time of Idaho Power Comp~ tra.!sJ1ission_s'yi¡t~rr peak and varies by month,
¡Schedule PageL328 Line No.: 4 _ Column: h__ ..__ __ _ ___ I
OA TT rate adjustments filed for periods prior to 2008
~chedule Page: 328 Line No.: 5 Columñ-:h----------~~=~==~_=_______________________
The network service agreement between Idaho Power and the Bonnevile Power Administration for Raft River expires September 30,2011.
The billn demand fOr network service is the customets demand at the time of Idaho PoweE Com~y transmission system peak and varies bY'!~n!ti,chedule Page: 328 Line No.: 6 _ Column: h__ __n_____. __________________J
OA TT rate adjustments filed for periods prior to 2008
~edule Page: 328 Line No.: 7 . Column: h _-.-- --- _________.____ _J
The network service agreement between Idaho Power and the Bonnevile Power Administration for the Priority Firm Customers expires December 31,
2011. The billng demand for network service is the customets demand at the time of Idaho Power Company transmission system peak and varies by
month.
r¡dule Page:'328 Line No.: 8 Column: h
OA TT rate adjustments filed for periods prior to 2008
ISchedule Page: 328.__ Line No.: 9Coiúmn: e
Legacy, contract prior to the Open Access Transmission Tariff
'lchedule Page: 328 Line No.: 9 - Column: h U --------=~-_=-..-----
The contract between Idaho Power and the Milner Irrigation District expires December 31,2012.
~chedule Page: 32B---11ne No.: 10 Column: h --- _..______________~___.__u ---:=
The agreement between Idaho Power and the City of Seattle expires December 31,2017. Beginning May 1, 2008, Cargill is responsibleforthe--
payment of Lucky Peak imbalance.
f§hedule Page: 328 Line No.: 11 Cõlumn: h-._.---- ... .----.---- J
The agreement between Ida'ho Power and the City of Seattle expires December 31, 201T Beginning May1,-20Õa,Cargill is responsible fòd'he --
payment of Lucky Peak imbalance.
~¡:eduiePage:328 Line No.: 12 Column: h ____________________
The contract between Idaho Power and PacifiCorp -Imnaha expires on September 30, 2010,
~chedule l'age: ~~8__L.!'!fl_N0.: 13 Column: h---
OATT rate adjustments filed for periods prior to 2008
~hedUiaiie: 328__ LilJf!N0.:14_=_fol'!mn: e
Legacy, contract prior to the Open Access Transmission Tarif
~h!!dule piiiie: 328._u.L.!'!f!_N0.: 14 - Column: h ..... _ __________.._~~~=--:~=-==-. - __n.n___ .1
The agreement between Idaho Power and the United States Department ofthe Interior, Bureau of Indian Affairs is subject to termination upon 90 days
written notice by the Bureau.
~che.duie P~ge:328 Line No.: 15 __Column: e
Legacy, contract prior to the Open Access Transmission Tariff
!Scheduië Page: 328LTniiNeiS--Column: h ___un_un -- --.------.-.-- --
The contract between Idaho Power and PacifCorp is for the lif of Briger pròjec per 1992 Restated Transmission Service Agreement (RTSA) FERC
filing 3/9/92.
ISchfJdule ~age: 32~_ _l.jlJfl_NO.: 22 ---Ca¡iiiii;-~:_=~~==-_____
OA TT rate adjustments fied for periods prior to 2008
~her!iJie pag 32(l__JJne .NO.: 10 ___Cõ/umn:h.:--=---
OA TT rate adjustments filed for periods prior to 2008____~____
iScheiiiileiiãge: 328.~__ Line No.: BCoiumn: h
OA TT rate adjustments filed for periods prior to 2008
,§ç.lJ.flCJiiie Pa9.e:)_2.!!~'!__ L.ilJ!N~~: f:- CaTiim,;: b.
OA TT rate adjustments filed for periods prior to 2008
__ ______________i I
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. --------:~_=_:=d-:-=J
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IFERC FORM NO.1 (ED. 12-87) Page 450.1
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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 04/15/2009 2008/Q4
FOOTNOTE DATA
IScheciiie7iaiie:'32S:4. Line No.: 29 Column: h
OA TT rate adjuStmentS filed för periods prior to 2008 _._.___._....___d.__._._____.______.... ._.-
~ed~!~Page: 328ß Lin~_No.: 4 Column: h
OATT rate adjustments filed for periods prior to 2008
ISchiiiiiii-Page: 328.7 Line No.-: 9 Column: h ~-=--__-==. _ __
OAn rate adjustments filed for periods prior to 2~_~__._________.____.______.._______~~_.._._
~chedule Page: 328.7 Line No.: 20_ Colu"!,!: h.__ ._______
OA n rate adjustments filed for periods prior to 2008
ISchejlulePiile: 328.7__ldfJ!Lllt!~¿26 Column: h
OA n rate adjustments filed for periods prior to 2008
1§Cif¡ieiiïlePie:328.7 Line No.: 30 Column: h-..-----------
OA n rate adjustments filed for periods prior to 2008
I$chedule Pari'e: 328.8 Line No.: 23 Column: h~___u____
OA n rate adjustments filed for periods prior to 2008~_._._--_._-- _._-------------~_.__._-_._---._.-- - ----,,-----_._-_._----,Schedule Page: 328.9 Line No.: 21 Column: h
OA n rate adjustments filed for periods prior to 2008
_____~.~.___._~_______ ____._J
_._----~
IFERC FORM NO.1 (ED. 12-87) Page 450.2
Name of Respondent This (!rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008lQ4
(2) Ei A Resubmission 0411512009
TRANSMISSION OF ELECTRICITY BY OTHERS (Accunt 565)
(Including transactions referred to as "weeling")
1. Report all transmission, Le. wheeling or electricity provided by other electric utilties, cooperatives, municipalities, other public
authorities, qualifying facilities, and others for the quarter.
2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on 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 ENERGY EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHER
No.Name of Company or Public Statistical Magawatt-Magawan-h'~mana .Energy _\-Iner Total Cost of
lioUfS liours Charpes Charpes Charres Trans'$issionAuthority (Footnote Affliations)Classification Receivea Delivered ($($($
(a)(b)(c)(d)(e)(f)(g)~hl
1 Avista Corp - WWp Div NF 105,567 105,567 547,988 547,988
2 Avista Corp - WWP Div SFP 250,347 250,347 890,77 890,77
3 Bonnevile Power Admin 469,247 469,247 1,195,541 1,195,541
4 Bonnevile Power Admin 53,856 53,856
5 Bonnevile Power Admin NF 13,366 13,366 72,485 72,485
6 Bonnevile Power Admin SFP 339,360 339,360 1,568,238 1,568,238
7 Bonnevile Power Admin OS -7,88
8 Bonnevile Power Admin OS 5,000
9 Bonnevile Power Admin OS 3,279
10 Calpine Energy Serv L.P OS -391
Eugene Water & Eleet OS
Ii -5,57211
12 JP Morgan Ventures Engr SFP 16,200 16,200 30,816 30,816
13 Nortwestem Energy NF 7,488 7,488 38,350 38,350
14 NortWesem Energy SFP 83,337 83,337 696,214 696,214
15 NortWestern Energy -112,770 112,770 212,800 86,509 299,309
16 NortWestern Energy OS .ß5,920
TOTAL 1,629,30 1,629,307 1,462,197 6,004,472 -216,370 7,250,299
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FERC FORM NO. 1/3-Q (REV. 02-0)Page 332
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/04
(2) 0 A Resubmission 04/15/2009
TRANSMISSION OF ELECTRICITY BY OTHERS (Accunt 565)
(Including transactons referred to as "wheeling")
1. Report all transmission, Le. wheeling or electricity próvided by other electric utilties, cooperatives, municipalities, other public
authorities, qualifying facilities, and others for the quarter.
2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
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Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the
demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all
I other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all
components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no
monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement,
including the amount and type of energy or service rendered.
I 6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Line TRANSFER OF ENERGY EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHER
I No.Name of Company or Public Statistical Magawatt-Magawau-!l~mana ,tnergy .~mer Total Cost of
RtìOUrs d
tìours Char¡ies Char¡ies Char¡ies Trans'$issionAuthority (Footnote Affliations)Classification eceive Delivered ($($($
(a)(b)(c)(d)(e)(f)(g)~hl
1 PacifCorp Inc.NF 31,360 31,360 198,556 198,556
2 PacifCorp Inc,SFP 107,761 107,761 911,250 911,250
3 PacifiCorp Inc.46,762 46,762 746,847 746,847
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4 PacifCorp Inc.as .-2,605
5 PacifiCorp Inc,as 3,137
6 Powerex Corp.as -27,375
I 7 Seatte Cit Light NF 3,204 3,204 10,330 10,330
8 Seatt City Light SFP 17,150 17,150 84,772 84,772
9 Sierr Pacific Power Co NF 13,534 13,534 96,091 96,091-
I 10 Sierr Pacifi Power Co SFP 3,600 3,600 7,200 7,200
5,400
.
5,0011Snohomish County PUD NF 2,400 2,400
12 Snohomish County PUD SFP 4,704 4,704 8,817 8,817
I 13 Tacoma Power NF 1,150 1,150 3,838 3,838
14 T ransAlta Energy Mark as -98,135
15
I 16
I TOTAL 1,629,30 1,629,307 1,462,197 6,004,472 .216,370 7,250,299
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FERC FORM NO. 1/3-Q (REV. 02-0)Page 332.1
This Page Intentionally Left Blank
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Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Dat Yr)
Idaho Power Company (2)A Resubmission 04/15/2009 2008/04
FOOTNOTE DATA
'Schedy!elJage: 332__...LineNQ~;_.~ __ _Coll!I!!!:~__
Contract Expires 9/30/2016
rschedulePage:33-- Line No.: 4 Column: bContract Expires' 7/16/2011-
~,._~dule Pafifi332 --Line No.: 7 Column: 9
Unauthorized Increase Charge
~c.hedule f'age:m~~~Line ~'!:L~_Ç'!~u-"!!TJL9Processing Fee
¡Schedule Page: 332 Liiie No.: 9 Column: g~~_~-_~~.-.-------------- -- .. .----
Transmission Study Fee
r5chedLi!e. Page: 332-line N~:=-1Q. Column:ii' n_U__________ ___~n______
Resale Transmission
~cheèiiiie-Page;.~~2'- - i.iieNo::-f'f -coliiin:g~-----'
Resale Transmission
ISchedule Page: 332 Line No.: 15 Column: b
COntrat can be terminated-at anytime, with 30 days prior notice
rschedule Page; 33imTiê-¡;o.:-16--'Column: g__________._
Rate Refund
~£.,.edulê-Pige:-332.1. _ Line No.:3---Co/~~~_ tJ~~=~~=-=---_---m-_-.-nm -Contract Expires6-!01/1009________________
~chedule.eag~; 332.1 Line No.: 4 Column: g__________u_.
Unauthorized Increase Charge
~hedule Page: 332.", -Line. lio..:~
Transmission Study Fee
~e.rlulePie:-332~__Line No.:6- Column: g____ _ ______
Resale Transmission
~chedulëPage: 332.T--Lieiio.:1;rn Column: g_u_u___
Resale Transmission
--j
------.J
-- ---=_~~=~-I
------1
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_ J
.. __ J
------.-. . ..-.-------...-~-----J
--_._----=~==~==----_._._---~=_._..._-=--==-==~_.j
___ I
__(;,!ILI'!TJL9___________ .__m__._________ _____ ______
IFERC FORM NO.1 (ED. 12-87) Page 450,1
Name of Respondent This ~ort Is:Date of Rep'ort YearlPeriod of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/04
(2) n A Resubmission 04/15/2009
MISCELLANEOUS GENERAL EXPENSES (Accunt 930.2) (ELECTRIC)
Line DescrltiOn Amount
No.(a (b)
1 Industry Association Dues 369,096
2 Nuclear Power Research Expenses
3 Other Experimental and General Research Expnses
4 Pub & Dist Info to Stkhldrs...expn servicing outstanding Securities 172,168
Oth Expn ::=5,000 show purpose, recipient, amount. Grop if c: $5,000 "
5 M
6 Richard Dahl 17,200
7 Christine King 45,591
8 Jon Miler 100,800
9 Gary Michael 69,600
10 Richard Reiten 47,052
11 Joan Smith 61,648
12 Jan Packwoo 42,000
13 Judith Johansen 51,600
14 Peter O'Neil 63,360
15 Thomas Wilford 52,800
16 Robert Tintsman 66,181
17
18 Chambers of Commerce & Other Civic Organizations 99,006
19 Associated Taxpayers of Idaho 21,252
20 Corporate Executive Board 42,814
21 Eastern Oregon Visitor Association 1,500
22 Idaho Association of Counties 1,255
23 Idaho Association of Commerce & Industr 10,000
24 Idaho Economic Development Association 1,000
25 Idaho Mining Assocaition 6,960
26 Misc Memberships (3)1,300
27 National Assoc of Corp 4,500
28 National HydroPower Assoc 28,805
29 Pacific NW Utilties -35,810
30 The Conference Board 3,200
31 University of Idaho 10,950
32 Utility Wind Interest Group 5,000
33 West Associates 22,580
34 Western Energy Institute 40,599
35 Western Electricity Coordiniating Council 598,809
36 Wyoming Taxpayers Assoc 1,500
37
38 Misc General Management:
39 New York Stock Exchange 45,567
40 PR Newswire 13,991
41
42 .
43
44
45
46 TOTAL 3,515,410
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FERC FORM NO.1 tED. 12-94\Paae 335
I Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)Idaho Power Company (2)A Resubmission 04/15/2009 2008/Q4
FOOTNOTE DATAI
I jSclJeiiiireI?~_~~5 Line No.:-S--Recipient
Amac Assurance Corp
I Bank of New YorkBroadridge Finc Solution
Deutche Bank
E Source
I Jet ClearingJP MorganGlobal Insight
Laurel Hill Advsiory
Port of Morrow
Shareholder. Com
Stock Based Comp
Original Issue Shares
Thompson Financial
Union Bank of Calif
Wells Fargo
I Mise entries/AmortOther items under $5,000
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Total
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IFERC FORM NO.1 (ED. 12-87)
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~=JColumn:b--_._~.-Purpose
Annual Prem
Port Morrow- PC
Proxy & Bulletin
Broker Fees
Membership
Travel Expense
Am Falls- PRTData Subscription
Proxy Printer
Port of Morrow bond
Shareholder Webcasting
Stock expnese
Mgmt Expense
Analyst Service
PC Bond exp
Transfer & Fees
Misc
Misc
$
Amount
98,810
10,854
58,158
133,105
30,536
19,627
30,860
25,027
80,160
5,475
16,989
442,757
14,400
68,404
13,927
128,342
125,869
56,616
$1,359,916
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 2008/Q4
(2) n A Resubmission 04/15/2009
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLAT (Accunt 403, 404, 405)
(Except amorzation 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) Amortzation of Other Electric
Plant (Account 405).
2. Report in Section 8 the rates used to compute amortization charges for electric plant (Accounts 404 and 405). State the basis used to
compute charges and whether any changes have been made in the basis or rates used from the preceding report year.
3. Report all available information called for in Section C every fifth year beginning with report year 1971, reporting annually only changes
to columns (c) through (g) from the complete report of the preceding year.
Unless composite depreciation accounting for total depreciable plant is followed, list numerically in column (a) each plant subaccount,
account or functional classification, as appropriate, to which a rate is applied. Identify at the bottom of Section C the type of plant
included in any sub-account used.
In column (b) report all depreciable plant balances to which rates are applied showing subtotals by functional Classifications and showing
composite total. Indicate at the bottom of section C the manner in which column balances are obtained. If average balances, state the
method of averaging used.
For columns (c), (d), and (e) report available information for each plant subaccount, account or functional classification Listed in column
(a). If plant mortality studies are prepared to assist in estimating average service Lives, show in column (f) the type mortality curve
selected as most appropriate for the account and in column (g), if available, the weighted average remaining life of surviving plant. If
composite depreciation accounting is used, report available information called for in columns (b) through (g) on this basis.
4. If provisions for depreciation were made during the year in addition to depreciation provided by application of reported rates, state at
the bottom of section C the amounts and nature of the provisions and the plant items to which related.
A. Summary of Depreciation and Amorttion Charges
Depreciation Amortzation of
Line ~Ciation Exense for Aset Limited Tenn Amortization of
No.Functional Classification ense Retirement Costs Electrc Plant Other Electric Total
(Accunt 403)(Accunt 403.1)(Account 404)Plant (Acc 405)
(a)(b)(c)(d)(e)(f)
1 Intangible Plant 5,482,388 5,482,388
2 Steam Production Plant 20,407,583 20,407,583
3 Nuclear Production Plant
4 Hydraulic Production Plant-Conventional 13,871,109 13,871,109
5 Hydraulic Production Plant-Pumped Storage
6 Other Production Plant 4,350,691 4,350,691
7 Transmission Plant 14,972,859 14,972,859
8 Distribution Plant 30,298,045 30,298,045
~ Regional Transmission and Market Operation
10 General Plant 13,033,596 13,033,596
11 Common Plant-Electrc -296,300 -296,300
12 TOTAL 96,637,583 5,482,388 102,119,971
B. Basis for AmOrtzation Charges
Accunt 404
Balance to be 2008 Balance to be Remaining months of
Amortized Amortizati2n amortzed 12131/08 amorttion 12131/08
(1 )60,000 12,000 48,000 48
(2)12,803,025 480,872 12,322,343 -
(3)13,801,327 4,701,329 18,185,632 -
(4)5,763,749 288,187 5,475,561 228
TOTAL 32,428,100 8,095,753 32,428,100
(1) Shoshone-Bannock Tribe license and use agreement (termination date December 31,2023).
(2) Middle snake relicensing costs (amortzed over a 3D-year license period).
(3) Computer softre packages (amortzed over a 60 month period from date of purchase).
(4) Shoshone-Bannoc Right of Way (tennination date December 31,2028).
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FERC FORM NO.1 (REV. 12-03)Page 336
I Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/Q4
(2) nA Resubmission 04/15/2009
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DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreciaoie t:stimatea Net Appiiea MOrtlitY Average
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
I (a)(In Th~~fandS)~~l (Pergrnt)(pergrnt)Tr~e
7~r
12 310.00 203 75.00 1.98 R4.0 21.80
13 311.00 134,509 100.00 -10.00 2.12 S1.0 23.30
14 312.10 77,220 60.00 -7.00 2.18 R3.0 22.60
15 312.20 455,185 70.00 -5.00 2.38 R1.5 22.30
16 312.30 4,208 25.00 20.00 2.70 R3.0 12.20
17 314.00 132,561 50.00 -10.00 2.78 SO.5 20.30
18 315.00 62,162 65.00 -5.00 1.01 S1.5 22.20
19 316.00 14,533 50.00 -7.00 0.77 RO.5 20.80
20 316.10 59 10.00 -5.00 0.04 L2.5 7.60
21 316.40 226 10.00 25.00 1.53 L2.5
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22 316.50 79 10.00 25.00 0.01 L2.5 8.20
23 316.70 81 19.00 25.00 3.63 S2.0 16.70
24 316.80 1,365 16.00 30.00 7.61 SO.O 9.30
I 25 317.000 4,362
26 Subtotal Steam 886,753
27 331.00 151,277 100.00 -25.00 2.48 R2.5 32.10
I 28 332.10 19,461 90.00 -20.00 2.07 S4.0 27.20
29 332.20 224,575 90.00 -20.00 2.04 S4.0 29.80
30 332.30 5,472 2.03 SQUARE 28.60
I 31 333.00 188,27'i 80.00 -5.00 1.85 R3.0 33.00
32 334.00 41,29'i 50.00 -5.00 2.91 R1.5 25.30
33 335.00 16,441 90.00 1.97 R2.0 30.50
I 34 335.10 41 15.00 2.42 SQUARE 12.30
35 335.20 392 20.00 3.53 SQUARE 10.70
36 335.30 629 5.00 13.65 SQUARE 2.00
I 37 336.00 7,493 75.00 1.91 R3.0 30.40
38 Subtotal Hydro 655,351
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39 341.00 10,422 35.00 3.36 SQUARE 30.40
40 342.00 5,331 35.00 3.10 SQUARE 32.40
41 343.00 91,48~35.00 3.37 SQUARE 29.70
I 42 344.00 36,231:35.00 2.97 SQUARE 33.80
43 345.00 17,238 35.00 3.11 SQUARE 28.30
44 346.00 3,615 35.00 3.22 SQUARE 29.50
I 45 Subtotal Other 164,333
46 350.20 25,291 65.00 1.51 R3.0 54.20
47 350.21 4,363 65.00 1.50 R3.0 63.70
1
48 352.00 41,274 60.00 -30.00 1.68 R3.0 47.30
49 353.00 286,101 45.00 -5.00 2.06 R1.0 35.40
50 354.00 136,922 65.00 -25.00 1.96 S3.0 48.60
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FERC FORM NO.1 (REV. 12-03)Page 337
Name of Respondent ThisWrtlS:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/Q4
(2) 0 A Resubmission 04/15/2009
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreCiaole t:siimatea Net Appiiea MOrtlity Average
No.Account No.Plant Base Avg. Servce Salvage Depr. rates Curve Remaining
Cal
(In Th(~fandS)7~l (Percint)(per~nt)Tr8e
~~r
12 355.00 93,137 55.00 -60.00 2.81 R2.0 36.70
13 356.00 150,453 65.00 -30.00 1.92 R1.5 48.30
14 359.00 318 65.00 0.98 R3.0 23.80
15 Subtotal Transmission 737,859
16 361.00 24,515 65.00 -30.00 1.85 R2.5 52.60
17 362.00 167,224 50.00 -5.00 189.00 RO.5 42.10
18 364.00 210,586 44.00 -50.00 3.29 R1.5 31.50
19 365.00 116,790 47.00 -40.00 2.95 RO.5 35.10
20 366.00 47,417 60.00 -20.00 1.95 R2.0 51.20
21 367.00 179,51 50.00 -15.00 1.97 50.5 41.10
22 368.00 381,827 37.00 5.00 1.67 R1.0 30.80
23 369.00 55,551 35.00 -40.00 3.09 R2.5 25.60
24 370.00 53,995 20.00 6.95 01.0 11.90
25 370.10 4,990 15.00 6.76 S3.0 14.40
26 371.10 5€10.00 -5.00 3.68 54.0 1.40
27 371.20 2,48:1 15.00 -5.00 0.63 R2.0 13.90
28 373.00 4,153 25.00 -25.00 4.09 R1.5 13.90
29 374.00 232
30 Subtotal Distribution 1,249,334
31 390.11 26,257 100.00 -5.00 2.38 S1.5 33.60
32 390.12 36,065 50.00 -5.00 2.24 L2.0 36.30
33 390.20 9,083 30.00 2.58 S3.0 20.80
34 391.10 14,561 20.00 4.97 SQUARE 10.30
35 391.20 26,653 5.00 24.37 SQUARE 2.10
36 391.21 4,691 7.00 13.96 L4.0 3.90
37 392.10 415 10.00 25.00 6.23 L2.5 5.90
38 392.30 2,580 8.00 50.00 8.62 S2.5 4.30
39 392.40 19,804 10.00 25.00 3.58 L2.5 7.30
40 392.50 567 10.00 25.00 1.49 L2.5 8.60
41 392.60 27,048 19.00 25.00 3.69 52.0 12.00
42 392.70 4,100 19.00 25.00 2.39 S2.0 11.90
43 392.90 3,918 30.00 25.00 1.99 S1.5 21.10
44 393.00 1,182 25.00 5.40 SQUARE 9.70
45 394.00 4,816 20.00 4.84 SQUARE 11.70
46 395.00 10,712 20.00 5.39 SQUARE 10.20
47 396.00 8,674 16.00 30.00 6.95 SO.O 7.00
48 397.10 6,486 15.00 6.16 SQUARE 7.70
49 397.20 14,906 15.00 6.99 SQUARE 9.60
50 397.30 2,937 15.00 8.36 SQUARE 6.60
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FERC FORM NO.1 CREV.12-G3l Page 337.1
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Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/Q4
(2) 0 A Resubmission 04/15/2009
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreciaoie t:srimateo Net Appiieo Morriiy Average
No.Account No.Plant Base Avg. Service Salvage'Depr. rates Curve Remaining
(In Tho~fandS)7~l (pergrnt)(per;rnt)TYKe
7~r(a)(b
12 397.40 1,782 10.00 8.20 SQUARE 5.60
13 398.00 4,106 15.00 9.57 SQUARE 6.90
14 Subtotal General 231,343
15 Total Plant 3,924,973
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
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FERC FORM NO.1 (REV. 12-03)Page 337.2
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/Q4
(2) FiA Resubmission 04115/2009
REGULATORY COMMISSION EXPENSES
1. Report particulars (details) of regulatory commission expenses incurred during the current year (or incurred in previous years, if
being amortized) relating to format cases before a regulatory body, or cases in which such a body was a part.
2. Report in columns (b) and (c), only the current yeats expenses that are not deferred and the current yeats amortization of amounts
deferred in previous years.
Line Description Assessed by Expenses Total Deferred.
No.(Furnish name of regulatory commission or body the Regulatory of Expense for in Account
Commission Current Year 182.3 aldocket or case number and a description of the case)Utilty (b) + (c)Beginning 0 Year
(a)(b)(c)(d)(e)
1 Federal Energy Regulatory Commission:
2 Annual admin charges assessed by FERC 2,732,698 2,732,698
3
4 General Regulatory Expenses and
5 Various other Dockets 1,550,625 1,550,625
6
7 Regulatory Commission Expenses - Idaho
8 Expenses and various other Dockets 198,618 198,618
9
10 Oregon Hydro - Fees Amortization 158,506 158,506
11
12 Regulatory Commission Expenses - Oregon
13 Expenses and various other Dockets 191,750 191,750
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 2,891,204 1,940,993 4,832,197
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FERC FORM NO.1 (ED. 12-96)Page 350 I
I Name of RespondentIdaho Power Company
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2009
REGULATORY COMMISSION EXPENSES (Continued)
Show in column (k) any expenses incurred in prior years which are being amortized. List in column (a) the period of amortization.
List in column (f), (g), and (h) expenses incurred during year which were charged currently to income, plant, or other accounts.
Minor items (less than $25,000) may be grouped.
Year/Period of Report
End of 2008/Q4
13.4.
5.
I AMORTIZED DURING YEAR
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Electric
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I Electric
I Electric
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(h)
Deferred to
Account 182.3
(i)
Contra
Account
')
Amount
(k
Deferred inAccount 182.3
End of Year
(I)
Line
No.
928 198,618
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
928 2,732,698
928 1,550,625
928 158,506
928 191,750
I FERC FORM NO.1 (ED. 12-96)
-
4,832,197 46
Page 351
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/Q4
(2) FiA Resubmission 04/15/2009
RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES
1. Describe and show below costs incurred and accounts charged during the year for technological research, development, and demonstration (R, D &
D) project initiated, continued or concluded during the year. Report also support given to others during the year for jointly-sponsored projects,(ldentif
recipient regardless of affliation.) For any R. D & D work carried with others, show separately the respondent's cost for the year and cost chargeable to
others (See definition of research, development, and demonstration in Uniform System of Accunts).
2. Indicate in column (a) the applicable classifcation, as shown below:
Classifications:
A. Electric R, D & D Performed Internally:a. Overhead
(1) Generation b. Underground
a. hydroelectric (3) Distribution
i. Recreation fish and wildlife (4) Regional Transmission and Market Operation
ii Other hydroelectric (5) Environment (other than equipment)
b, Fossil-fuel steam (6) Other (Classify and include items in excess of $5,000,)
c. Internal combustion or gas turbine (7) Total Cost Incurred
d, Nuclear B. Electric, R, D & D Performed Externally:
e. Unconventional generation (1) Research Support to the electrical Research Council or the Electric
f, Siting and heat rejection Power Research Institute
(2) Transmission
Line Classifcation Description
No.(a)(b)
1 A. Electric R, D & D Performed internally:
2 (1) Generation Residential
3 e, unconventional generation Air Conditioning Cool Credit
4 Energy Effcient Lighting
5 Energy House Calls
6 Energy Star Northwest Homes
7 Heating & Cooling Effciency
8 Home Products
9 Home Weatherition Pilot
10 Insulation retrofit
11 Oregon Residential Weatheriation
12 Rebate Advantage
13 WAQC
14
15 Commercial/Industrial
16 Building Effciency
17 Easy Upgrades
18 Holiday Lighting
19 Holiday Lighting
20 Custom Effcincy
21
22 Irrgation
23 Irration Effciency Rewards
24 Irriation Peak Rewards
25
26 NEEA
27 Other Programs and Activities
28 DSM Accounting & Analysis
29 Other indirect program expenses
30
31
32
33 Total R, D&D
34
35
36
37 ,
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FERC FORM NO.1 (ED. 12-87)Page 352 I
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/Q4
(2) FiA Resubmission 04/15/2009
RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES (Continued)
(2) Research Support to Edison Electric Institute
(3) Research Support to Nuclear Power Groups
(4) Research Support to Others (Classify)
(5) Total Cost Incurred
3. Include in column (c) all R, 0 & 0 items performed internally and in column (d) those items performed outside the company costing $5,000 or more,
briefly describing the specifc area of R, 0 & 0 (such as safety, corrosion control, pollution, automation, measurement, insulation, type of appliance, etc,).
Group items under $5,000 by classifications and indicate the number of items grouped, Under Other, (A (6) and B (4)) classify items by type of R, 0 & 0
activity.
4, Show in column (e) the account number charged with expenses during the year or the accunt to which amounts were capitalized during the year,
listing Account 107, Construction Work in Progress, first. Show in column (f) the amounts related to the account charged in column (e)
5. Show in column (g) the total unamortized accumulating of costs of projects, This total must equal the balance in Accunt 188, Research,
Development, and Demonstration Expenditures, Outstanding at the end of the year.
6. If costs have not been segregated for R, 0 &0 activities or projects, submit estimates for columns (c), (d), and (f) with such amounts identified by
"Est."
7. Report separately research and related testing facilties operated by the respondent.
Costs Incurred Internally Costs Incurred Externally AMOUNTS CHARGED IN CURRENT YEAR Unamortized LineCurrelc~ Year Current Year Account Amount Accumulation No.
(d)ee)(f)(g)
1
2
2,969,377 2,969,377 3
1,018,292 1,018,292 4
484,379 484,379 5
302,061 302,061 6
473,551 473,551 7
250,860 250,860 8
52,807 52,807 9
123,454 123,454 10
7,417 7,417 11
90,888 90,888 12
1,419,475 1,419,475 13
-14
15
1,055,009 1,055,009 16
2,992,261 2,992,261 17
28,782 28,782 18
58 58 19
4,045,671 4,045,671 20
21
22
2,103,702 2,103,702 23
1,431,840 1,431,840 24
25
942,014 942,014 26
421,317 421,317 27
957,904 957,904 28
22,402 22,402 29
30
31
32
21,193,521 21,193,521 33
34
35
36
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I FERC FORM NO.1 (ED. 12-87)Page 353
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2008/Q4 IThis ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2009
DISTRIBUTION OF SALARIES AND WAGES
Report below the distribution of total salaries and wages for the year. Segregate amounts originally charged to clearing accunts to
Utility Departments, Construction, Plant Removals, and Other Accunts. and enter such amounts in the appropriate lines and columns
provided. In determining this segregation of salaries and wages originally charged to clearing accunts, a method of approximation
giving substantially correct results may be used.
1
(a)
Direct Payroll
Distribution
(b)
1Line
No.
Classification Total
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 Production
14 Transmission
15 Regional Market
16 Distribution ~
17 Administrative and General
18 TOTAL Maintenance (Total of lines 13 thru 17)
19 Total Operation and Maintenance
20 Production (Enter Total of lines 3 and 13)
21 Transmission (Enter Total of lines 4 and 14)
22 Regional Market (Enter Total of Lines 5 and 15)
23 Distribution (Enter Total of lines 6 and 16)
24 Customer Accounts (Transcribe from line 7)
25 Customer Service and Informational (Transcribe from line 8)
26 Sales (Transcribe from line 9)
27 Administrative and General (Enter Total of lines 10 and 17)
28 TOTAL OpeL and Maint (Total of lines 20 thru 27)
29 Gas
30 Operation
31 Production-Manufactured Gas
32 Production-Nat Gas (Including Expl. and Dev.)
33 Other Gas Supply
34 Storage, LNG Terminaling and Processing
35 Transmission
36 Distribution
37 Customer Accounts
38 Customer Service and Informational
39 Sales
40 Administrative and General
41 TOTAL Operation (Enter Total oflines 31 thru 40)
42 Maintenance
43 Production-Manufactured Gas
44 Production-Natural Gas (Including Exploration and Development)
45 Other Gas Supply
46 Storage, LNG Terminaling and Processing
47 Transmission
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FERC FORM NO.1 (ED. 12-88)Page 354 I
I Name of RespondentIdaho Power Company
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2009
DISTRIBUTION OF SALARIES AND WAGES (Continued)
Year/Period of Report
End of 2008/04
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Direct PayrollDistribution
(b)
TotalLineClassification
No.
1 (a)
48 Distribution
49 Administrative and General
I 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,
I 54 Other Gas Supply (Enter Total of lines 33 and 45)
55 Storage, LNG Terminaling and Processing (Total of lines 31 thru
56 Transmission (Lines 35 and 47)
1
57 Distribution (Lines 36 and 48)
58 Customer Accounts (Line 37)
59 Customer Service and Informational (Line 38)
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60 Sales (Line 39)
61 Administrative and General (Lines 40 and 49)
62 TOTAL Operation and Maint. (Total of lines 52 thru 61)
63 Other Utilit Departments
1
64 Operation and Maintenance
65 TOTAL All Utilty Dept. (Total of lines 28, 62, and 64)
66 Utilty Plant
1
67 Construction (By Utility Departments)
68 Electric Plant
69 Gas Plant
70 Other (provide details in footnote):
I 71 TOTAL Construction (Total of lines 68 thru 70)
72 Plant Removal (By Utilty Departments)
73 Electric Plant
I 74 Gas Plant
75 Other (provide details in footnote):
76 TOTAL Plant Removal (Total of lines 73 thru 75)
I 77 Other Accounts (Specif, provide details in footnote):
78 Paid Absences
79 Preliminary Survey & Investigations
80 Other Clearing Accounts
I 81 Stores Expense
82 Other Work in Progress
83 Other Accounts
I 84
85
86
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88
89
90
1
91
92
93
I 94
95 TOTAL Other Accounts
96 TOTAL SALARIES AND WAGES
103,842,753 103,842.753~-----------
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46,570,459 46,570,459
46,570,459 46,570,459,-----------~----
17,835,747
338,737
2,564,709
4.227,652
2,039,481
4,021,412
17,835,747
338,737
2,564,709
4,227,652
2,039,481
4.021,412
31,027,738
181,440,950
31,027,738
181,440,950
I FERC FORM NO.1 (ED. 12-88)Page 355
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Name of Respondent
Idaho Power Company
This Report Is: Date of Report
(1) (KAn Original (Mo, Da, Yr)
(2) OA Resubmission 04/15/2009
MONTHLY TRANSMISSION SYSTEM PEAK LOAD
.1 (1) Report the monthly peak load on the respondent's transmission system. If the respondent has two or more power systems which are not physicallyintegrated, 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).
I (4) Report on Columns (e) through ü) by month the system' monthly maximum megawatt load by statistical classifications. See General
Instruction for
the definition of each statistical classification.
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Year/Period of Report
End of 2008/Q4
I NAME OF SYSTEM:Line Monthly Peak
No. Month MW - TotalI(a)(b)
I
1 January
2 February
3 March
4 Total for Quarter 1
5 April
6 May
7 June
8 Total for Quarter 2
9 July
10 August
11 September
12 Total for Quarter 3
13 October
14 November
15 December
16 T ola for Quarter 4
.17 Total Year to
DateIYear
3,361
3,13
2,90
9,39
2,83
3,38
4,33
10,55
4,24
4,04
2,66
10,94
2,89
2,84
3,30
9,05
~~~::-' ~%/jji\ ~ oV ~ ~
I .~~ii",,, " "ÝI
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39,94
Firm Network Firm Network Long-Term Firm Oter Long- Short-Term Firm Other
Service for Self Servic for Point-ta-point Term Firm Point-to-point Service
Others Reservations Service Reservation
(e)(f)(g)(h)(i)ü)
2,213 241 677 230
1,989 204 677 263
1,663 179 720 341
5,865 624 2,074 834
1,010 183 785 854
1,718 284 793 591
2,781 344 793 419
5,509 811 2,371 1,864
2,887 349 775 229
2,903 293 77 75
1,321 199 757 388
7,111 841 2,303 692
1,752 189 702 255
1,814 243 702 87
2,168 313 70 125
5,734 745 2,104 467
24,219 3,021 8,852 3,857
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i:i:Rr. i:ORM NO. 1/3-0 (NEW. 07-04\Paae 400
Name of Respondent
Idaho Power Company
This ~ort Is:
(1) ~An Original
(2) A Resubmission
ELECTRIC ENERGY ACCOUNT
Date of Report
(Mo, Da, Yr)
04/15/2009
Year/Period of Report
End of 2008/Q4 I
IReport below the information called for concerning the disposition of electric energy generated, purchased, exchanged and wheeled during the yèar.
Line Item
No.
(a)
1 SOURCES OF ENERGY
2 Generation (Excluding Station Use):
3 Steam
4 Nuclear
5 Hydro-Conventional
6 Hydro-Pumped Storage
7 Other
8 Less Energy for Pumping
9 Net Generation (Enter Total of lines 3
through 8)
10 Purchases
11 Power Exchanges:
12 Received
13 Delivered
14 Net Exchanges (Line 12 minus line 13)
15 Transmission For Other (Wheeling)
16 Received
17 Delivered
18 Net Transmission for Other (Line 16 minus
line 17)
19 Transmission By Others Losses
20 TOTAL (Enter Total of lines 9, 10, 14, 18
and 19)
MegaWatt Hours
(b)
7,278,84
6,908,211
217,152
106,826
288,567
-181,741~
5,036,540
6,397
17,945,292
Line
No,
Item MegaWatt Hours
I(b)
14,543,714 I
57,311
1,990,923 I
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1,353,344 I17,945,292
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IFERC FORM NO.1 (ED. 12-90)Page 401a
(a)
21 DISPOSITION OF ENERGY
22 Sales to Ultmate Consumers (Including
Interdepartmental Sales)
23 Requirements Sales for Resale (See
instruction 4, page 311.)
24 Non-Requirements Sales for Resale (See
instruction 4, page 311.)
25 Energy Fumished Without Charge
26 Energy Used by the Company (Electric
Dept Only, Excluding Station Use)
27 Total Energy Losses
28 TOTAL (Enter Total of Lines 22 Through
27) (MUST EQUAL LINE 20)
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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 2008/Q4
(2) OA Resubmission 04/15/2009
MONTHLY PEAKS AND OUTPUT
(1) Report the monthly peak load and energy output. If the respondent has two or more power which are not physically integrated, furnish the required
information for each non- integrated system.
(2) Report on line 2 by month the system's output in Megawatt hours for each month,
(3) Report on line 3 by month the non-requirements sales for resale. Include in the monthly amounts any energy losses associated with the sales.
(4) Report on line 4 by month the system's monthly maximum megawatt load (60 minute integration) associated with the system.
(5) Report on lines 5 and 6 the specified information for each monthly peak load reported on line 4.
NAME OF SYSTEM:Idaho Power Company
Line Monthly Non-Requirments MONTHLY PEAKSales for Resale &
No.Month Total Monthly Energy Associated Losses Megawatts (See Instr. 4)Day of Month Hour
(a)(b)(c)(d)(e)(f)
29 January 1,555,985 147,250 2,464 24 8AM
30 February 1,292,413 82,137 2,270 5 8AM
31 March 1,439,647 270,922 2,028 3 8AM
32 April 1,240,090 120,346 1,993 1 8AM
33 May 1,516,309 183,831 2,577 19 6PM
34 June 1,661,334 188,126 3,214 30 3PM
35 July 1,891,764 126,428 3,121 3 4PM
36 August 1,782,755 151,934 3,012 7 4PM
37 September 1,475,251 207,119 2,297 18 6PM
38 October 1,279,586 164,444 2,000 1 6PM
39 November 1,226,019 111,665 1,973 24 8AM
40 December 1,584,139 236,721 2,396 17 8AM
41 TOTAL 17,945,292 1,990,923
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I FERC FORM NO.1 (ED. 12-90)Page 401b
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Name of Respondent This Report is:Date of Report Year/Perid of Report
(1) ~ An Original (Mo. Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2009 20081Q4
FOOTNOTE DATA
~ßhedule tage:-4in. LifJf!No.: 16_.~QI'lIß'::~b--~-___~____ _.=-~___ _______._ ___
Page 329 column i differs from 401 by 6,397 reported for Lucky Peak variation and BPA
Energy Imbalance schedules on page 401. The numbers that are shown on page 328-330 are for
456 wheeling only, but on page 401 they have to be adjusted for 447 transmission.
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) An Original (Mo, Da, Yr)2008/Q4(2)DA Resubmission 04/15/2009 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Report data for plant in Service only.2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in
this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants,3, Indicate by a footnote any plant leased or operated
as a joint facility.4, If net peak demand for 60 minutes is not available, give data which is available, specifing period.5. If any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant.6. If gas is used and purchased on a
therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct.7. Quantities of fuel burned (Line 38) and average cost
per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20.8. If more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
Line Item Plant Plant
No.Name: Jim Brir 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 ;,.;Jtt:#0. ~,..~:= ',..~~
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)717 60
7 Plant Hours Connected to Load 8784 7209
8 Net Continuous Plant Capability (Megawatts)o 0
9 When Not Limited by Condenser Water
10 When Limited by Condenser Water o 0
11 Average Number of Employees 0 0
12 Net Generation, Exclusive of Plant Use - KWh 513854000 402636000
13 Cost of Plant: Land and Land Rights 494358 106610
14 Structures and Improvements 63859321 13794057
15 Equipment Costs 418119517 56385936
16 Asset Retirement Costs 0 0
17 Total Cost 482473196 70286603
18 Cost per KW of Installed Capacity (line 17/5) Including 626,1820 1094.4659
19 Production Expenses: Oper, Supv, & Engr 149839 926650
20 Fuel 84210935 6023661
21 Coolants and Water (Nuclear Plants Only)0 0
22 Steam Expenses 4170172 0
23 Steam From Other Sources 0 0
24 Steam Transferred (Cr)0 0
25 Electric Expenses 0 0
26 Misc Steam (or Nuclear) Power Expenses 5836936 272497
27 Rents 419846 0
28 Allowances 0 0
29 Maintenance Supervision and Engineering 52262 2515460
30 Maintenance of Structures .0 0
31 Maintenance of Boiler (or reactor) Plant 8248488 0
32 Maintenance of Electric Plant 2499711 0
33 Maintenance of Misc Steam (or Nuclear) Plant 3981568 13876
34 Total Production Expenses 109569757 9752144
35 Expenses per Net KWh 0.0213 0.0242
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)Coal Oil Coal Oil
37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)Tons Barrels Tons Barrels
38 Quantity (Units) of Fuel Burned 2870982 14542 0 237858 637 0
39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)9263 140000 0 8346 138800 0
40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 28.599 135.187 0.000 24.118 170.788 0.000
41 Average Cost of Fuel per Unit Burned 28.166 56.726 0.000 23.993 119,861 0.000
42 Average Cost of Fuel Burned per Millon BTU 1.515 9.648 0,000 1.430 20.560 0,000
43 Average Cost of Fuel Burned per KWh Net Gen 0,016 0.000 0.000 0,015 0.000 0.000
44 Average BTU per KWh Net Generation 10404.000 0.000 0.000 9922.000 0.000 0.000
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FERC FORM NO.1 (REV. 12-03)Page 402 I
I
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)2008/Q4(2)D A Resubmission 04/15/2009 End of
I
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
9. Items under Cost of Plant are based on U. S. of A. Accunts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos.
547 and 549 on Line 25 "Electrc Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant."lndicate plants
I
designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined
cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by
footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cot units
I used for the various components of fuel cot; and (c) any other informative data conceming plant type fuel used, fuel enrichment tye and quantity for the
report period and other physical and operating characteristics of plant.Plant Plant Plant Line
Name: Valmy Name: Danskin Name: Bennett Mountain No.
I (d)(e)(f)
Steam Gas Turbine Gas Turbine 1
Outdoor Conventional Conventional 2
2001 2005 3
1985 2001 2005 4
262.76 172.80 5
375 285 196 6
8554 746 322 7
0 261427 164159 8
0 0 9
0 0 10
0 8 4 11
1737664000 167976000 49056000 12
769351 402745 0 13
56855766 8954495 1455553 14
273173513 100952129 52070571 15
0 0 0 16
330798630 110309369 53526124 17
1166.8382 419.8104 309.7577 18
573795 146426 42012 19
41780567 12317741 5037853 20
0 0 0 21
3206517 0 0 22
0 0 0 23
0 0 0 24
1817960 204781 189740 25
I 1628064 261868 111357 26
49853 0 0 27
0 0 0 28
I 0 0 0 29
398714 99832 57815 30
5956555 85361 86618 31
I
1801439 423624 85247 32
327487 0 0 33
57540951 13539633 5610642 34
0.0331 0.0806 0.1144 35
I Coal Oil Gas Gas 36
Tons Barrels MCF MCF 37
870880 9916 0 1570200 0 0 512253 0 0 38
I
9802 138778 0 1038 0 0 1038 0 0 39
43.859 139.262 0.000 7.845 0.000 0.000 9.835 0.000 0.000 40
43.107 140.821 0.000 7.845 0.000 0.000 9.835 0.000 0.000 41
I
2.238 24.160 0.000 7.558 0.000 0.000 9.475 0.000 0.000 42
0.024 0.000 0.000 0.073 0.000 0.000 0.103 0.000 0.000 43
9686.000 0.000 0.000 9703.000 0.000 0.000 10839.000 0.000 0.000 44
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FERC FORM NO.1 (REV. 12-03)Page 403
This Page Intentionally Left Blank
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I Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2009 2008/Q4
FOOTNOTE DATAI
I
I
~l1edule!!llg~; 4ii2~ Line No.:3-Co7Utin:b_~~__~__m__==-_-mm-_-m-__~~~--~~~~-~~.~- --= -- --~-~~JThis 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.
~hedule Page;~ 402 Line No.: 3 Colümn: c ~~m~_ . ~ ___"~____'__'____~m_~_~~"_
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.
~dule Page: 402 ~ Line No.: 3 Column: d ~_m~~~~
This footnote applies to lines 3 and 4. Th~ 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.
fSedule Page: 402 Line No.: 5 cijfü"iii:iiu --~---- -~-- _==-_~_u --- -- ------~~--~--~ ~-=:This footnote applies to line 5 and lines 12 through 43.
Information reflects Idaho Power Company's share as explained
in note for line 3 page 402 column B.
I§~hedule Page: 402 Line No.: 5. Column: cThis 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
~dule Page: 402 Line~No.: 5 Column: d .___________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.
~hêdule Page: 402 Line No.: 9 Column: b m___~ ~-~__u~__~~__._~..___~~_.~====- _n_ m" "'-~---=J
This footnote applies to lines 9, 10, and 11. PacifiCorp
as operator of the plant will report this
information.
~!!cLule Page: 402 LineNo.:9~-~Co¡iiiiii:c--~------~-~~m-~~_m~~~ ~~------..---~~~---- ~-=-=_=:
This footnote applies to lines 9, 10, and 11. Portland General
Electric Company, as operator will report this information.~~__.__.~.__u_.~~._.._~._~__~_._ .-~----. .___________~~___d. .--.--~-~.-~~d-.-l~checLule Page: 402 Line No.: 9 Column: d . . . . .__~_~__~____~___~~_______~ n__--
This footnote applies to lines 9, 10, and 11. sIerra Pacific
Power, as operator of the plant, will report this information.
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IFERC FORM NO.1 (ED. 12-S7) Page 450.1
Name of Respondent
Idaho Power Company
YearlPeriod of ReportThis ~ort Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) D A Resubmission 04/15/2009
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Large plants are hydro plants of 10,000 Kwor more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
a footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifyng 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.
End of 2008/Q4 I
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(a)
FERC Licensed Projec No. 2736
Plant Name: American Falls
(b)
FERC Licensed Project No. 1975
Plant Name: Bliss
(c)
ILine
No.
Item
1 Kind of Plant (Run-of-River or Storage)
2 Plant Construction type (Conventional or Outdoor)
3 Year Originally Constructed
4 Year Last Unit was Installed
5 Total installed cap (Gen name plate Rating in MW)
6 Net Peak Demand on Plant-Megawatt (60 minutes)
7 Plant Hours Connect to Load
8 Net Plant Capabilty (in megawatt)
9 (a) Under Most Favorable Oper Conditions
10 (b) Under the Most Adverse Oper Conditions
11 Average Number of Employees
12 Net Generation, Exclusive of Plant Use - Kwh
13 Cost of Plant
14 Land and Land Rights
15 Structures and Improvements
16 Reservoirs, Dams, and Waterwys
17 Equipment Costs
18 Roads, Railroads, and Bridges
19 Asset Retirement Costs
20 TOTAL cost (Total of 14 thru 19)
21 Cost per KW of Installed Capacity (line 20 1 5)
22 Production Expenses
23 Operation Supervision and Engineering
24 Water for Power
25 Hydraulic Expenses
26 Electric Expenses
27 Misc Hydraulic Power Generation Expenses
28 Rents
29 Maintenance Supervision and Engineering
30 Maintenance of Structures
31 Maintenance of Reservoirs, Dams, and Waterways
32 Maintenance of Electric Plant
33 Maintenance of Misc Hydraulic Plant
34 Total Production Expenses (total 23 thru 33)
35 Expenses per net KWh
Run-of-River
Outdoor
1949
1950
75.00
67
8,784
I
IOutdoor
1978
1978
92.30
95
5,506 I--- -- ~~-~- - --~----~~.
----~ --------- -- -----~~~-~~~~--
109
o
4
264,778,000
76
1
4
315,334,000
I
I
875,318
11,807,207
4,293,075
31,399,514
839,276
o
49,214,390
533.2003
740,154
967,473
8,213,695
7,277,392
486,477
o
17,685,191
235.8025
I
139,773
2,309,584
83,304
38,202
241,429
156
116,889
100,254
3,785
279,656
135,909
3,448,941
0.0130
724,988
433,728
469,608
54,806
183,946
3,057
101,733
58,081
7,771
238,805
108,885
2,385,408
0.0076
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FERC FORM NO.1 (REV. 12-03)Page 406
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2008/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) 0 A Resubmission 04/15/2009
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
18,069,223 82,142 1,210,187
31,245,788 7,364,154 9,956,831
66,787,436 3,145,630 30,375,714
52,577,131 12,729,814 15,788,644
518,444 122,668 565,842
0 0 0
169,198,022 23,44,408 57,897,218
289.0298 1,887.6335 304.7222
750,163 172,275 372,539
448,065 105,669 205,834
760,847 177,126 363,156
331,519 82,474 191,076
537,499 136,528 243,686
237,758 113 40,826
435,098 69,737 200,140
255,345 42,690 290,134
280,498 3,317 9,028
396,062 128,839 186,019
723,775 87,519 404,437
5,156,629 1,006,287 2,506,875
0.0024 0.0213 0.0026
FFRC FORM NO.1 IREV.12.03\Paae 407
Name of Respondent
Idaho Power Company
YearlPeriod of Report
End of 2008/Q4 IThis ~ort Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) 0 A Resubmission 04/15/2009
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 specifyng 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.
I
(a)
FERC Licensed Project No. 1971
Plant Name: Hells Canyon
(b)
FERC Licensed Project No. 2726
Plant Name: Malad
(c)
I
ILine
No.
Item
1 Kind of Plant (Run-of-River or Storage)
2 Plant Construction type (Conventional or Outdoor)
3 Year Originally Constructed
4 Year Last Unit was Installed
5 Total installed cap (Gen name plate Rating in MW)
6 Net Peak Demand on Plant-Megawatts (60 minutes)
7 Plant Hours Connect to Load
8 Net Plant Capabilty (in megawatts)
9 (a) Under Most Favorable Oper Conditions
10 (b) Under the Most Adverse Oper Conditions
11 Average Number of Employees
12 Net Generation, Exclusive of Plant Use - Kwh
13 Cost of Plant
14 Land and Land Rights
15 Structures and Improvements
16 Reservoirs, Dams, and Waterways
17 Equipment Costs
18 Roads, Railroads, and Bridges
19 Asset Retirement Costs
20 TOTAL cost (Total of 14 thru 19)
21 Cost per KW of Installed Capacity (line 20 1 5)
22 Production Expenses
23 Operation Supervision and Engineering
24 Water for Power
25 Hydraulic Expenses
26 Electric Expenses
27 Misc Hydraulic Power Generation Expenses
28 Rents
29 Maintenance Supervision and Engineering
30 Maintenance of Structures
31 Maintenance of Reservoirs, Dams, and Waterways
32 Maintenance of Electric Plant
33 Maintenance of Misc Hydraulic Plant
34 Total Producton Expenses (total 23 thru 33)
35 Expenses per net KWh
Outdoor
1967
1967
391.50
441
8,784
I
I1948
1948
21.77
26
8,784
I- -~---- ~ --~--~-----~-~-~~~~
445
137
5
1,885,251,000
25
21
1
158,613,000
I
- - - ----~--- ~------~I
1,865,984
2,413,190
52,700,383
15,231,708
819,192
o
73,030,457
186.5401
205,376
2,671,314
6,219,827
4,091,287
304,683
o
13,492,487
619.7743
I
I
~------~~ ~~ ~~----- -----~---~-~I
347,537
201,877
350,702
146,405
251,693
68,206
237,745
49,940
16,160
276,698
603,525
2,550,488
0.0014
134,202
583,708
158,683
57,328
78,084
o
46,887
12,000
26,115
32,814
88,090
1,217,911
0.0077
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I
i:i:Rr. i:ORM NO_ 1 (REV. 12..3\Paae 406.1
Year/Period of Report
End of 2008/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) 0 A Resubmission 04/15/2009
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
. The items under Cost of Plant represent accunts or combinations of accounts prescrbed 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 cobinations of steam, hydro, internal combustion engine, or gas turbine equipment.
Name of Respondent
Idaho POwer Company
FERC Licensed Project No. 503
Plant Name: Swan Falls
(e)
FERC Licensed Project No. 18
Plant Name: Twin Falls
Line
No.
FERC Licensed Project No. 2055
Plant Name: C J Strike
(d)
Run-ot-River
Outdoor
1952
1952
82.80
84
8,762
Run-of-River
Conventional
Run-ot-River
Conventional
3,353,651 51,675 255,499
6,049,184 25,357,052 10,823,950
10,201,230 13,856,887 7,908,870
7,460,833 30,378,323 20,598,630
248,183 835,946 1,917,603
°0 0
27,313,081 70,479,883 41,504,552
329.8681 2,819.1953 786.9653
1,015,212 252,191 201,677
757,997 162,357 132,692
1,318,885 181,279 110,028
33,863 28,083 36,660
391,877 131,425 146,334
69,656 8,074 1,131
260,710 92,665 17,834
164,018 119,589 9,598
228,392 59,632 2,489
569,022 86,032 28,543
271,564 119,377 53,012
5,081,196 1,240,704 739,998
0.0132 0.0108 0.0100
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i:i:R~ i:ORM NO 1 (REV. 12-03\Paae 407.1
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) 0 A Resubmission 04/15/2009
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.
IName of Respondent
Idaho Power Company
YearlPeriod of Report
End of 2008/Q4
I
I
(a)
FERC Licensed Project No. 2777
Plant Name: Upper Salmon
(b)
FERC Licensed Project No. 2778
Plant Name: Shoshone Falls
(c)
ILine
No.
Item
I
1 Kind of Plant (Run-of-River or Storage)
2 Plant Construction type (Conventional or Outdoor)
3 Year Originally Constrcted
4 Year Last Unit was Installed
5 Total installed cap (Gen name plate Rating in MW)
6 Net Peak Demand on Plant-Megawatt (60 minutes)
7 Plant Hours Connect to Load
8 Net Plant Capabilty (in megawatts)
9 (a) Under Most Favorable Oper Conditions
10 (b) Under the Most Adverse Oper Conditions
11 Average Number of Employees
12 Net Generation, Exclusive of Plant Use - Kwh
13 Cost of Plant
14 Land and Land Rights
15 Structures and Improvements
16 Reservoirs, Dams, and Waterwys
17 Equipment Costs
18 Roads, Railroads, and Bridges
19 Asset Retirement Costs
20 TOTAL cost (Total of 14 thru 19)
21 Cost per KW of Installed Capacity (line 20 1 5)
22 Production Expenses
23 Operation Supervision and Engineering
24 Water for Power
25 Hydraulic Expenses
26 Electrc Expenses
27 Misc Hydraulic Power Generation Expenses
28 Rents
29 Maintenance Supervision and Engineering
30 Maintenance of Structures
31 Maintenance of Reservoirs, Dams, and Waterways
32 Maintenance of Electrc Plant
33 Maintenance of Misc Hydraulic Plant
34 Total Production Expenses (total 23 thru 33)
35 Expenses per net KWh
Run-of-River
Outdoor
1937
1947
34.50
36
8,784
Run-of-River
Conventional
1907
1921
12.50
13
4,206
I
I~---~~~-~---~~--------~-----~~
-- -- ---- - ---~----~~~---~---
39
32
4
210,736,000
14
11
2
47,665,000
I
I
200,112
1.83,850
4,960,389
6,637,152
29,359
o
13;661,862
395.9960
311,407
1,212,177
512,402
4,589,586
51,383
°
6,676,955
534.1564
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I
_ ~___ ____~~~____~~~ft__~I
406,588
184,357
333,729
24,606
160,667
o
92,052
71,669
63,154
74,886
125,669
1,537,377
0.0073
254,415
177,585
254,108
21,816
131,944
30
99,967
28,922
40,933
56,241
73,255
1,139,216
0.0239
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I
I
I
I
..i=n,. rol'b.. ..in .. IDI:\I .... n")\D~,..a AnA;?
This ~ort Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) D A Resubmission 04/15/2009
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accunts. Production Expnses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Exenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
Year/Period of Report
End of 2008/Q4
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.
Run-of-River
Outdoor
1949
1949
60.00
50
8,784
Run-of-River
Conventional
114,367 422,168 138,100
25,988,200 2,728,103 10,336,682
13,556,785 6,960,182 17,147,050
1,253,321 6,941,771 27,640,547
99,051 88,693 501,877
0 0 0
41,011,724 17,140,917 55,764,256
0.0000 285.6820 938.0026
0 762,677 78,026
0 279,859 1,376,313
4,964,233 354,852 39,769
0 143,579 35,923
138,233 190,367 117,086
0 1,321 1,565
0 51,138 41,659
0 114,790 19,783
0 4,208 32,438
0 33,590 65,665
100,144 108,944 75,851
5,202,610 2,045,325 1,884,078
0.0000 0.0097 0.0359
FERC FORM NO.1 lREV.12-Ð3)Paae 407.2
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I Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2009 2008104
FOOTNOTE DATAI
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IS . . --.--~------.-..-..-----.-.--.-..-- --...--_.. -.-----.------- ---.----- ._-.-....-_.---...-.-- --- --- ---.--------.---------, ehedule Page: 40~_.._ Line No.: 1 Colum'1: b ___. .._________~_n ._....._... ..... ... ...__.____ ..... u_ . ¡
American Falls generating capacity is dependent upon water releases controlled by theUni ted States Bureau of Reclamation.
rschiilePage:~06 _~i~ê-';¡O:: 1 ~_~~~Tij!!~-~-~-. _ . _ ____
Cascade generating capacity is dependent
States Bureau of Reclamation.
~edu¡iPge:-4i'_ Line No.: J.___Column: f
Upstream storage in Brownlee Reservoir.
~tiedule Page: 406.t__ Lin.!__No.;J Column: b ________ ____ ______._ . _
Upstream storage in Brownlee Reservoir
~~~edule l!age~~rJ6.1." . ll!!~No.:!___Ç.olumn:_~_____
Lower Malad maximum demand 15, 000 Kw, Upper Malad
---- =-=-==~upon water releases controlled by the United
____________. -----...----.-.---=-..
i
ì_ _____..____--___..____.__.___.....__.J
-~----~
maximum demand 9, 000 Kw non-coincident.
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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) X An Original (Mo, Da, Yr)End of 2008/04
(2) OA Resubmission 04/15/2009
GENERATING PLANT STATISTICS (Small Plants)
1, Small generating plants are steam plants of, less than 25,000 Kw; internal combustion and gas turbine-plants, conventional hydro plants and pumped
storage plants of less than 10,000 Kw installed capacity (name plate rating).2, Designate any plant leased from others, operated under a license from
the Federal Energy Regulatory Commission, or operated as a joint facility, and give a concise statement of the facts in a footnote, If licensed project,
give project number in footnote.
Line Year Instaiie \ja~aci ~et Peak Net GenerationName of Plant Orig.Name Plate atin~Demand Excluding Cost of PlantNo.Const.(In MW)(6~a1n.)Plant Use
(a)(b)(c)(e)(f)
1 Hydro:
2 Clear Lakes 1937 2.50 2.2 16,198 1,759,032
3 Thousand Springs 1912 8.80 7.0 52,227 4,730,494
4
5
6 Internal Combustion:
7 Salmon Diesel (1)1967 5.00 5.0 120 901,055
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
FERC FORM NO.1 (REV. 12-03)
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Page 410 I
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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 2008/Q4
(2) OA Resubmission 04/15/2009
GENERATING PLANT STATISTICS (Small Plants) (Continued)
3. List plants appropriately under subheadings for steam, hydro, nuclear, internal combustion and gas turbine plants, For nuclear, see instruction 11,
Page 403, 4. If net peak demand for 60 minutes is not available, give the which is available, specifying period.5. If any plant is equipped with
combinations of steam, hydro internal combustion or gas turbine equipment, report each as a separate plant However, if the exhaust heat from the gas
turbine is utilized in a steam turbine regenerative feed water cycle, or for preheated combustion air in a boiler, report as one plant
Plant Cost (Incl Asset Operation Production Expenses Fuel Costs (in cents LineRetire. Costs) Per MW Exc'l. Fuel i-uei Maintenance Kind of Fuel (per Millon Btu)
(g)(h)(i)(j)(k)(i)
No.
1
703,613 100,971 104,993 2
537,556 40,665 69,995 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
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34
35
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I FERC FORM NO.1 (REV. 12-03)Page 411
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/Q4
(2) OA Resubmission 04/15/2009
TRANSMISSION LINE STATISTICS
1, Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater, Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts.Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Accunt 121, Nonutilit Property.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a difrent type of construction need not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line, Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
I ATIONLine (Indicate w~~~Type of LENG~H ~oie WileS)~11l t e s30 NumberNo,other than u dergroun lines
60 cvcle 3 Dhase)Supporting report circuit miles)Of
From To Operating Designed un ~iri,ciure I U~Vtuii.~res CircuitsStructureofLln~o not erDesirna ed ine(a)(b)(c)(d)(e)(g)(h)
1 Boardman Slatt 50.0(500.00 STower 1.79 1
2
3 Borah Midpoint 345,0(500.00 STowr 84.97 1
4 Jim Bridger Goshen 345,0(345.00 STower 226.17 1
5 State Line Midpoint 345,0(345.00 STower 76.08 2
6 Kinport Borah 345,0(345.00 STower 27.26 1
7 Midpoint Borah #1 345,0(345.00 HWood 79.28 1
8 Midpoint Borah #2 345.0l 345.00 HWood 7759 2
9 Adelaide Tap Adelaide 345.0(345.00 HWood 2.67 2
10
11 Quart LaGrande 230.0(230.00 HWoo 46,23 1
12 Midpoint Hunt 230.0(230.00 STowr 0.53 2
13 Brady Antelope 230.0(230.00 HWood 56.29 1
14 Brady Treasureton 230.0(230,00 HWood 0.13 1
15 Brady #1 & #2 Kinport 230.0(230,00 STower 17.94 2
16 Jim Bridger Point of Rocks 230.0(230,00 HWoo 1,40 1
17 Brownlee Ontario 230,OL 230.00 STowr 72.70 1
18 Mora Bowmont 138,00 230,00 SPWood 9,90 1
19 Mora Bowmont 138.00 230,00 HWood 10.77 1
20 Jim Bridger Point of Rocks 230.00 230.00 HWood 2.79 1
21 Caldwell 710 Locust 230.00 230.00 SPSteel 18.60 1
22 Boise Bench Caldwell 23Q.l 230.00 STower 7,58 1
23 Boise Bench Caldwell 230.0(230.00 HWoo 33.53 1
24 Boise Bench Cloverdale 230.0(230.00 STower 15.98 2
25 Boardman Dalreed Sub 230.0(230,00 HWood 1.68 1
26 Brownlee 714 Oxbow 230.0C 230,00 SP Steel 11,13 2
27 Caldwell Ontario 230.0(230.00 HWood 27,11 1
28 Caldwell Ontario 230.0(230.00 STower 3.28 1
29 Bennett Mtn PP Rattlesnake TS 230.0(230.00 SPSteel 4,48 1
30 Borah Hunt 230.0C 230.00 HSleel 68,23 1
31 Danskin Hubbard 230,OC 230,00 HSleel 36,24 1
32 Danskin Hubbard 230,OC 230,00 SPSteel 1.90 1
33 Danskin Hubbard 230.0C 230,00 SPSleel 1,30 2
34 Danskin Bennett Mtn 230.0C 230.00 SPSteel 2,30 1
35 Boise Bench Midpoint #1 230.0C 230.00 STower 0,86 1
36 TOTAL 4,726,77 11.02 173
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FERC FORM NO.1 (ED. 12-87)Page 422 I
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Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/Q4
(2) FiA Resubmission 04/15/2009
TRANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, fumish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specif whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns 0) to (i) on the book cost at end of year.
COST OF LINE (Include In l,oiumn U) Land,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total LineOther Costs Expenses Expenses
(0)Expenses No.(i)0)(k)(I)(m)(n)(p)
X1780ACSR 446,708 446,708 1
2
1272 ACSR 256,381 21,76,998 22,033,379 3
1272 ACSR 483,30~15,888,761 16,372,070 15,882,152 16,365,461 32,247,6P 4
95 ACSR 571,97~10,996,449 11,568,28 5
272 ACSR 344,22C 6,028,033 6,372,253 6
15,5 ACSR 283,143 5,779,608 6,062,751 5,763,958 6,047,101 11,811,O5~7
15.5ACSR :64,851 7,786,556 7,851,407 7,684,278 7,749,129 15,433,401 8
15.5 ACSR 51,44!347,946 399,394 9
10
95 ACSR 51,41/2,411,863 2,463,277 2,494,190 2,545,604 5,039,7~11
15,5 ACSR 9,141 998,452 1,007,597 12
1272 ACSR 108,301 2,502,500 2,610,801 13
95 ACSR 6,186 6,186 14
15,5 ACSR 18,82!969,476 988,305 15
1272 ACSR 1,19(51,525 52,715 16
X954ACSR 1,676,838 20,266,395 21,943,233 17
15,5 ACSR 347,96..2,012,372 2,360,334 2,011,502 2,359,464 4,370,966 18
15.5 ACSR 19
272 ACSR 1,89~212,523 214,422 20
1590 ACSR 2,138,236 8,755,911 10,894,147 21
1272 ACSR 1,134,421 5,699,649 6,834,070 1,464,007 5,396,300 6,860,307 13,720,614 22
15.5 ACSR 23
1272 ACSR 3,062,812 6,583,109 9,645,921 6,582,253 9,645,065 16,227,318 24
95AAC 80,895 80,895 25
54 ACSR 34,17 16,026,470 16,060,644 26
X954ACSR 194,763 5,925,083 6,119,846 5,890,298 6,085,061 11,975,359 27
272 ACSR 28
272 ACSR 81,701 1,666,354 1,748,055 29
590 ACSR 618,217 22,439,850 23,058,067 624,917 22,468,004 23,092,921 46,185,842 30
1590 Lapwing 9,666,096 9,666,096 31
1590 Lapwing 32
1590 Lapwing 33
590 Lapwing 3,293,005 3,293,005 34
15.5 ACSR 336,181 3,776,64 4,112,650 4,100,683 4,436,869 8,537,552 35
28,566.45 369,747,512 398,313,957 6,773,672 199,328,849 227,309,396 433,11,917 36
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I FERC FORM NO.1 (ED. 12-87)Page 423
Name of Respondent This l!0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/Q4
(2) OA Resubmission 04/15/2009
TRANSMISSION LINE STATISTICS
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage,
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts.Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission,
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutilty Property.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines, Minor portions of a transmission line of a 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
respect to such structures are included in the expenses reported for the line designated.
Line DESIGNATION :.(KV)Type of LENG~H ~ole Wiles)(Indicate wtire hill t e sa 0 NumberNo.other than u dergroun hnes
60 cvcle 3 Dhase)Supporting report circuit miles)Of
From To Operating Designed ! un ~(rnClUre unf~ri:i~res CircuitsStructureotLlneo 1)0 erDesir;ated Line(a)(b)(c)(d)(e)(g)(h)
1 Boise Bench Midpoint #1 23O,()230.00 HWood 108.11 1
2 Brownlee Quart Jct 23O,()230.00 STowr 1.52 1
3 Brownlee Quart Jct 23O.()230.00 HWoo 41.71 1
4 Brownlee Boise Bench #1 & #2 23O.()230.00 STowr 99.97 2
5 Oxbow Brownlee 230.0(230.00 STowr 10.23 2
6 Boise Bench Midpoint #2 230.0(230.00 STowr 3.42 1
7 Boise Bench Midpoint #2 230.0(230.00 HWood 102.53 1
8 Oxbow Pallette Jct 230.0(230.00 STower 20.21 2
9 Pallette Jct Imnaha 230.0l 230.00 HWood 24.43 2
10 Hells Canyon Palette Jct 230.0(230.00 STowr 8.24 2
11 Brownlee Boise Bench 230,0(230.00 STower 102.27 2
12 Boise Bench Midpoint #3 23O.0l 230.00 HWood 106.34 1
13 Palette Jct Enterprise 230.0l 230.00 HWood 29.08 1
14 Borah Brady #2 230.0l 230.00 STower 0,41 1
15 Borah Brady #2 230.0(230.00 HWood 3,58 1
16 Borah Brady #1 230.0(230.00 HWoo 3.83 1
17
18 Goshen State Line 161.00 161.00 HWood 90.49 1
19 Don Goshen 161,0i 161.00 STower 2.39 2
20 Don Goshen 161.0U 161,00 HWood 48.43 2
21
22 American Falls Power Plant Adelaide 138,OU 138,00 HWood 9.84 2
23 American Falls Power Plant Adelaide 138.00 138.00 SPWood 0.12 2
24 Minidoka Loop Adelaide 138,00 138.00 STower 1.07 2
25 Nampa Caldwell 138.00 138.00 SPWoo 10.73 2
26 Upper Salmon Mountain Home Jct 138.00 138.00 HWoo 53.61 1
27 Upper Salmon Cliff 138.0U 138.00 HWood 30.80 1
28 Eastgate Russet 138,0(138.00 SPWood 2.09 1
29 Brady Fremont 138.0(138.00 STowr 0,98 2
30 Brady Fremont 138.0(138.00 HWood 24,32 2
31 Brady Fremont 138.01 138,00 SPWoo 24.35 2
32 King Lower Malad 138,01 138,00 HWood 84.92 2
33 Emmett Jct Payette 138.01 138.00 HWood 66.44 2
34 Mountain Home AFB Tap 138.01 138.00 HWood 6,20 1
35 Ontario Quart 138,01 138,00 HWood 73.42 1
36 TOTAL 4,726.77 11,02 173
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FERC FORM NO.1 (ED. 12-87)Page 422.1 I
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Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/Q4
(2) FiA Resubmission 04/15/2009
TRANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines, If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, fum ish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10, Base the plant cost figures called for in columns u) to (i) on the book cost at end of year.
\"u;: I ur LINE (IneJde in Column u) Land,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total LineOther Costs Expenses Expenses
(0)
EXJ)nses No.(i)u)(k)(I)(m)(n)(p)
15,5 ACSR 1
1795 ACSR 53,061 2,011,507 2,064,575 2
95 ACSR 3
~ARIOUS 269,431 7,991,043 8,260,474 288,607 8,279,650 8,568,257 4
1272 ACSR 14,81C 1,182,550 1,197,360 5
~5.5ACSR 227,82~5,764,129 5,991,954 5,861,700 6,089,525 11,951,225 6
~ARIOUS 7
1272 ACSR 23,30E 2,075,244 2,098,552 8
h272ACSR 138,471 1,263,618 1,402,095 9
127 ACSR 10,731 1,252,130 1,262,867 10
954 ACSR 170,69~5,620.92 5,791,186 184,817 5,805,309 5,990,12€11
15.5 ACSR 247,857 4,954,729 5,202,586 5,416,132 5,663,989 11,080,121 12
1272 ACSR 51,12.1,631,895 1,683,017 13
1272 ACSR 3,06!226,250 229,318 '"31,992 235,060 467,052 14
15.5 ACSR 15
272 ACSR 10,0&1 339,595 349,659 311,349 321,413 632,76~16
17
;i50COPPER 16,15!648,382 664,537 18
15,5 ACSR 76,041 1,652,914 1,728,955 19
397.5 ACSR 20
21
~OCOPPER 26,501 2,388,737 2,415,244 2,397,774 2,424,281 4,822,055 22
50 COPPER 23
15.5 ACSR 15,08!249,232 264,320 21,326 249,233 270,559 541,18 24
95AAC 157,43.1,954,139 2,111,571 1,753,582 1,911,014 3,664,596 25
95 ACSR 47,681 1,858,259 1,905,946 48,370 2,544,748 2,593,118 5,186,236 26
95 ACSR 43,561 764,183 807,751 27
95AAC 270,82'557,504 828,327 28
íiARIOUS 564,93.3,557,039 4,121,971 3,593,335 4,158,267 7,751,602 29
vARIOUS 30
ARIOUS 31
ARIOUS 76,82 1,622,351 1,699,174 1,797,737 1,874,560 3,672,297 32
ARIOUS 30,91E 2,291,614 2,322,532 2,416,389 2,447,307 4,863,696 33
97,5 ACSR 1,95E 1,955 34
ARIOUS 34,21 1,552,878 1,587,306 1,551,834 1,586,262 3,138,09E 35
28,566,445 369,747,512 398,313,957 6,773,672 199,328,849 227,309,396 433,411,917 36
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I FERC FORM NO.1 (ED. 12-87)Page 423.1
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/04
(2) fjA Resubmission 04/15/2009
TRANSMISSION LINE STATISTICS
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts.Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4, Exdude 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 wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one ty of supporting structure, indicte the mileage of each type of construction
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 trnsmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line, Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line luN YOI,TAGE(KV)Type of LE~G~H roie 'Piles)
(Indicate where l;'8t e asd'0 NumberNo.other than u ergroun lines Of60 cide 3 ohase \Supporting report circuit miles)
From To Operating Designed un ~(rl;c(ure unf~u~h~res CircuitsStructureDeof.Llne
o 110 er
(a)(b)(c)s'lated ine
(d)(e)(g)(h)
1 King American Falls PP 138.0(138.00 STowr 1.03 2
2 King American Falls PP 138.0(138.00 HWood 145.99 1
3 King American Falls PP 138.0(138.00 SPWood 3,71 1
4 Duffn Clawson 138.0(138.00 HWood 6.22 1
5 American Falls Brady Tie 138.0(138.00 HWood 0.33 1
6 Upper Salmon A-B King 138.0(138.00 HWood 5.88 1
7 Upper Salmon B Wells 138.0(138,00 HWood 125.58 1
8 King Wood River 138.0(138.00 HWood 73.56 1
9 Boise Bench Grove 13fó(138.00 SPWood 10,44 2
10 Ouart John Day 138.0(138.00 HWood 67.31 1
11 Sinker Creek Tap 138.0(138.00 HWood 2.80 1
12 Mora Cloverdale 138.0(138.00 HWood 2.57 1
13 Mora Cloverdale 138.0(138.00 SPWoo 22.37 1
14 Mora Cloverdale 138.0(138,00 SPSteel 0.96 2
15 Stoddard Jct Stoddard Sub 138.0(138.00 SPSteel 3,80 1
16 Fossil Gulch Tap 138.0(138.00 HWoo 1.95 1
17 Wood River Midpoint 138,OL 138.00 HWoo 53.06 .
2
18 Wood River Midpoint 138,OU 138.00 SPWoo 16.69 2
19 Oxbow McCall 138.0U 138.00 HWood 38.47 1
20 Oxbow McCall 138.0U 138,00 SPWood 2.32 1
21 Lowell Jct Nampa 138,OU 138,00 SPWood 7,57 2
22 Hunt Milner 138.00 138,00 SPWood 19,39 1
23 Strike Bruneau Bridge 138.0(138.00 HWoo 13.48 1
24 American Falls Kramer Sub 138.0(138.00 SPWood 18.40 2
25 Pingree Haven 138.0l 138.00 SPWoo 11,75 1
26 Midpoint Twin Falls 138.0(138,00 SPWood 25,14 2
27 Twin Falls Russett 138.0(138,00 SPWood 1.72 1
28 Blackfoot Aiken 138.0l 138,00 SPWood 6.17 2
29 Peterson Tendoy 138.0C 138.00 HWood 57,22 1
30 Eastgate Tap Eastgate 138.0(138.00 S PWood 7.30 1
31 Boise Bench Mora 138.0(138,00 HWood 13.17 2
32 Bowmont-Caldwell SimplotSub 138,00 138.00 SPWood 0,51 1
33 Gary Lane Eagle 138.0(138.00 SPWood 6.53 1
34 Locust Grove Blackcat Sub 138.0(138.00 SP Steel 9.93 2.98 1
35 Boise Bench Butler 138,OL 138,00 SPWood 0.08 4.02 1
36 TOTAL 4,726.77 11.02 173
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FERC FORM NO.1 (ED. 12-87)Page 422.2 I
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/Q4
(2) FiA Resubmission 04/15/2009
TRANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such 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 party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specif whether lessee is an associated company.
10. Base the plant cost figures called for in columns ü) to (I) on the book cost at end of year.
COST OF LINE (Include in Column ü) Land,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total LineOther Costs Expenses Expenses
(0)
Expenses No.(i)ü)(k)(I)(m)(n)(p)
15,5 ACSR 148,914 5,54,203 5,693,117 6,854,888 7,003,802 13,858,69C 1
15.5 ACSR 2
15.5 ACSR 3
10 4,191 309,827 314,018 4
954 ACSR 96,921 96,921 5
050 COPPER 2,741 93,073 95,814 6
~ARIOUS 28,49(1,745,804 1,774,294 2,102,923 2,131,413 4,234,336 7
MARIOUS 173,68 2,355,148 2,528,831 2,691,460 2,865,143 5,556,603 8
~ARIOUS 225,60 1,630,589 1,856,191 1,660,128 1,885,730 3,545,858 9
ß97.5ACSR 92,17 2,362,416 2,454,589 10
WARIOUS 21 77,199 77,219 11
15.5 ACSR 2,225,22(6,996,618 9,221,844 2,266,792 8,046,783 10,313,575 20,627,15C 12
~ARIOUS 13
95AAC 14
272 ACSR 15
i?50COPPER 451 63,439 63,889 16
397.5 ACSR 281,061 6,374,306 6,655,370 6,390,048 6,671,112 13,061,160 17
397,5 ACSR 18
397,5 ACSR 109,89~2,314,194 2,424,093 2,417,537 2,527,436 4,94,973 19
397.5 ACSR 20
15.5 ACSR 211,131 1,493,264 1,704,395 1,488,956 1,700,087 3,189,043 21
15.5 ACSR 3,32~1,187,302 1,190,626 1,195,361 1,198,691 2,394,052 22
397.5 ACSR 14,92 587,404 602,331 23
15.5 ACSR 13,73-1,052,549 1,066,283 24
97,5 ACSR 11,21 778,092 789,305 18,223 778,091 796,314 1,592,628 25
VARIOUS 54,84f 2,958,765 3,013,613 26
15,5 ACSR 16,79C 206,158 222,948 27
15.5 ACSR 13,61t 456,919 470,535 477162 490,778 967,94C 28
97.5 ACSR 395,696 3,49,949 3,845,645 29
15.5 ACSR 45,98~1,058,898 1,104,887 30
15.5 ACSR 14,691 627,703 642,400 627,920 642,617 1,270,537 31
95AAC 49,642 49,62 32
95AAC 489,031 1,944,888 2,433,925 33
1272 ACSR 935,72'3,610,071 4,545,796 34
1272 ACSR 34,68 838,605 873,292 35
28,566,445 369,747,512 398,313,957 6,773,672 199,328,849 227,309,396 433,411,917 36
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I FERC FORM NO.1 (ED. 12-87)Page 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 2008/Q4
(2) OA Resubmission 04/15/2009
TRANSMISSION LINE STATISTICS
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater, Report transmission lines below these voltages in group totals only for each voltage.
2, Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts.Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Propert,
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6, Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
DESI~NA IIUNLine (Indicate w~~';Type of LENG~H ~ole miles)
h~t e s30f NumberNo.other than u ergroun lines
Of60 cvcle 3 Dhase \Supporting report circuit miles)
From To Operating Designed I vn qlfl,ciure I vnf;:tru~hu.res CircuitsStructureof Line o -triot erDesil;ated ine(a)(b)(c)(d)(e)(g)(h)
1 Eagle Star 138.0(138.00 SPWood 6,35 1
2 Karcher Sub Zilog Tap 138.0(138.00 S PSteel 2,09 1
3 Cloverdale -712 712 -Wye 138.OC 138.00 S P Stee 0.21 4,02 1
4 Butler Wye 138.0C 138.00 S P Steel 2.85 1
5 Horseflat Starkey 138.0(138.00 HWood 33.60 1
6 Starkey Mccll 138.0(138.00 S PSteel 2.08 2
7 Starkey Mccall 138.0(138.00 HWood 3,80 1
8 Starkey Mccall 138.0(138.00 S PSteel 1.50 1
9 Starkey Mccall 138.0(138.00 SPWood 17.61 1
10 Chestnut Happy Valley 138.0C 138.00 S PSteel 2.78 1
11 Garnet Ward 138.00 5.25 '
12 McCall Lake Fork 138.0C 138.00 SPWood 8.83 1
13 McCall Lake Fork 138,0(138.00 SSteel 2.90
14 Caldwell Wills 138.OC 138.00 Sr'Steel 1.30 1
15 Caldwell Willis 138.OC 138.00 S P Stee 1.59 1
16 Caldwell Wills 138.OC 138.00 SPWood 0.87 1
17 Valivue Tap 138.OC 138.00 S P Steel 0.80 2
18 Kinport Don #1 138.0(138.00 STower 1.24 2
19 Twin Falls PP Tap 138.0C 138.00 HWood 0.82 1
20 American Falls PP Amercian Falls Trans ST 138,OC 138.00 S PSteel 0,37 1
21 Lower Salmon King Tie 138.0(138.00 HWood 0,22 1
22 C J Strike Strike Jct 138.0(138.00 STower 4,31 2
23 Strike Jct Mountain Home Jct 138.0C 138.00 HWood 26.70 1
24 Strike Jct Bowmont 138.00 HWood 0,05 1
25 Strike Jet Bowmont 138.0C 138.00 STower 0.36 1
26 Strike Jct Bowmont 138.OC 138.00 HWood 68.22 1
27 Lucky Peak Lucky Peak Jct 138.0(138.00 HWood 4.43 2
28 Bliss King 138.0(138.00 HWood 10.4 1
29 Milner Deadend Milner PP 138.0(138.00 SPWood 1.31 1
30 Swan Falls Tap 138,0(138.00 HWood 0.95 1
31
32
33
34 Hines BPA (Harney)115,O(115.00 HWood 3.28 1
35
36 TOTAL 4,726.77 11,02 173
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FERC FORM NO.1 (ED. 12-87)Page 422.3 I
I
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/Q4
(2) FiA Resubmission 04/15/2009
TRANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such 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. Specify whether lessor, co-owner, or
other party is an associated company,
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10, Base the plant cost figures called for in columns ü) to (I) on the book cost at end of year.
COST OF LINE (Include in Column OrLand,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 UneOther Costs Expenses Expenses
(0)
Expenses No,(i)ü)(k)(I)(m)(n)(p)
15.5 ACSR 2,909,433 2,909,433 1
95AAC 43,031 443,805 486,840 2
1272 ACSR 140,41,709,148 849,560 3
95 ACSR 134,471 1,405,436 1,539,907 4
15.5 ACSR 657,88~19,860,558 20,518,441 5
15.5 ACSR 6
15.5 ACSR 7
15.5 ACSR 8
15.5 ACSR 9
272 ACSR 78,57!1,821,921 1,900,500 10
40,58(40,580 11
15.5 ACSR 399,781 4,731,449 5,131,230 331,539 4,662,028 4,993,567 9,987,134 12
13
1272 ACSR 168,22'2,141,218 2,309,443 14
95 ACSR 15
95 ACSR 16
95 ACSR 351,497 351,497 17
15.5 ACSR 1,174 212,77 213,951 18
50 COPPER 5f 53,889 53,947 19
15.5 ACSR 76,560 76,560 20
97.5 ACSR 4,406 4,406 21
15,5 ACSR 1,074 253,872 254,946 22
97,5 ACSR 4,35~524,571 528,926 2,537,731 2,542,086 5,079,817 23
15,5 ACSR 29,90¿1,776,898 1,806,800 86,651 1,859,070 1,945,721 3,891,442 24
15.5 ACSR 25
26
15,5 ACSR 279,81 279,488 27
15.5 ACSR 5,621 964,435 970,055 28
15.5 ACSR 2,81'183,606 186,420 29
97,5 ACSR 12,88!261,511 274,396 30
31
32
33
97,5 ACSR 1,97f 63,404 65,382 34
35
28,566,445 369,747,512 398,313,957 6,773,672 199,328,849 227,309,396 433.11,917 36
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IFERC FORM NO.1 (ED. 12-87)Page 423.3
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/Q4
(2) FiA Resubmission 04/15/2009
TRANSMISSION LINE STATISTICS
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts.Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Accunt 121, Nonutilty Property.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines, Minor portions of a transmission line of a 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
respect to such structures are included in the expenses reported for the line designated.
Line DESIGNATION
(Indicate w~~YJ Type of LENG~H role 'Viles)
~iat e asao NumberNo.other than u ergroun lines Of60 cvcle 3 Dhase)Supporting report circuit miles)
From To Operating Designed un ~trl,cture ' untsulmres CircuitsStructureof Line o toot erDesir;ated ine(a)(b)(c)(d)(e)(9)(h)
1
2 69 Kv Lines 69.0(69.00 HWoo 166.31 1
3 69 Kv Lines 69.0(69.00 SPWoo 923.11 1
4
5
646 Kv Lines 46.0(46.00 SPWoo 412,07 1
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 TOTAL 4,726,77 11.02 173
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FERC FORM NO.1 (ED. 12-87)Page 422.4 I
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Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/Q4
(2) FiA Resubmission 04/15/2009
TRANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line, Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines, If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specif whether lessee is an associated company.
10. Base the plant cost figures called for in columns ü) to (I) on the book cost at end of year.
l,V~ i VI" LINE (InCfude inThlumn ü) Land,EXPENSES, EXCEPT DEPRECIATION AND TAXi:S
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total LineOther Costs Expenses Expenses Expenses(i)ü)(k)(I)(m)(n)(0)(p)No.
1
WARIOUS 928,99(36,062,02 36,991,692 1,438,423 39,551,848 40,990,271 81,980,54~2
IVARIOUS 3
4
5
VARIOUS 176,26~8,585,338 8,761,603 9,587,492 9,763,757 19,351,249 6
7
5,736,25 5,736,253 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
28,56,445 369,747,512 398,313,957 6,77,672 199,328,849 227,309,396 433,411,917 36
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I FERC FORM NO.1 (ED. 12-87)Page 423.4
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/Q4
(2) DA Resubmission 04/15/2009
TRANSMISSION LINES ADDED DURING YEAR
1.Report below the information called for concerning Transmission lines added or altered during the year.It is not necessary to report
minor revisions of lines.
2. Provide separate subheadings for overhead and under- ground construdion and show each transmission line separately. If actual
costs of competed construdion are not readily available for reportng columns (I) to (0), it is permissible to report in these columns the
Line L1N~ n~c;i ATluN L~~9th ::Ut-PUK IINI. ::IKUi;TuR~l;IKi;UITS t-~SIWlll;IUR
No..l\verageFromToinTypeNumber per Present UltimateMilesMiles(a)(b)(c)(d)(e)(f)(g)
1 Adrian Tup Adrian Sub 5.65 SPWood 19,60 1 1
2 Starkey Mccall 17.61 SPWood 17.60 1 1
3 Starkey Mccall 3.80 HWood 6,58 1 1
4 Starkey Mccall 2.08 SP Steel 17.60 2 2
5 Starkey Mccall 1.50 SP Steel 17.60 1 1
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 TOTAL 30,64 78.98 6 6
FERC FORM NO.1 (REV. 12-03)
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Page 424 I
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Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2008/04
(2) FiA Resubmission 04115/2009
TRANSMISSION LINES ADDED DURING YEAR (Continued)
costS. Designate, however, if estimated amounts are reported. Include costs of Clearing Land and Rights-of-Way, and Roads and
Trails, in column (I) with appropriate footnote, and costs of Underground Conduit in column (m).
3. If design voltage differs from operating voltage, indicate such fact by footnote; also where line is other than 60 cycle, 3 phase,
indicate such other characteristic.
Voltage LIN~l,U::1 LineSizeSpecifcationConf~uration KV Land and Poles, Towers Conductors Asset Total No.
and pacing (Oper~ting)LandcFights and Fixtures and Devices Retire, Costs(h)(i)(j)(k I)(m)(n)(0)(p)
397,5 ACSR TVS5'69 13,254 1,091,584 1.104,838 2,209,676 1
715.5 ACSR TVS 7'138 9,697 6,715,361 6,725,058 13.450,116 2
715,5 ACSR Hor 16'138 3
715,5 ACSR TVSDC6'138 4
715,5 ACSR TVS 7'138 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
22,951 7,806,945 7,829,896 15,659,792 44
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I FERC FORM NO.1 (REV.
12-03)Page 425
Name of Respondent ThiS~IS:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2008/Q4
(2)D A Resubmission 04/15/2009
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 accrding to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 Adelaide trnsmission 345.00 138.00 13.80
2 Aiken distribution 46.00 13.00
3 Alameda distribution 46.00 13.00
4 Alameda distrbution 138.00 13.00
5 American Falls PP - attended trnsmission 138.00 13.80
6 American Falls trnsmission 138.00 46.00 12.50
7 Artesian distrbution 46.00 13.00
8 Bannock Creek distrbution 46.00 13.00
9 Bennett Mountain Power Plant trnsmission 230.00 18.00
10 Bennett Mountain Power Plant trnsmission 18.00 4.16
11 Bethel Court distrbution 138.00 13.00
12 Black Cat distrbution 138.00 13.09
13 Blackfoot distrbution 46.00 12.50
14 Biackfoot distrbution 161.00 46.00 12.47
15 Bliss - attended trnsmission 138.00 13.80
16 Blue Gulch distrbution 138.00 34.50
17 Boise Bench - attended distrbution 138.00 34.50
18 Boise Bench - attended trnsmission 138.00 69.00 13.80
19 Boise Bench - attended trnsmission . 230.00 138.00 13.80
20 Boise distrbution 138.00 13.00
21 Borah trnsmission 345.00 230.00 13.80
22 Bowmont distrbution 69.00 46.00 6.90
23 Bowmont distrbution 138.00 34.50
24 Bowmont trnsmission 138.00 69.00 13.80
25 Brady transmission 46.00 12.50
26 Brady trnsmission 230.00 138.00 13.80
27 Brownlee - attended trnsmission 230.00 13.80
28 Bruneau Bridge distrbution 138.00 34.50
29 Buckhorn distrbution 69.00 35.00
30 Bucyrus distrbution 46.00 7.20
31 Buhl distrbution 46.00 13.00
32 Burley Rural distribution 69.00 13.00
33 Butler distrbution 138.00 13.00
34 Caldwell distribution 138.00 13.00
35 Caldwell distribution 138.00 69.00 13.00
36 Caldwell transmission 230.00 138.00 12.50
37 Canyon Creek distribution 138.00 34.50
38 Canyon Creek transmission 138.00 69.00 12.50
39 Cascade Power Plant - attended trnsmission 69.00 4.60
40 Cascade Distribution 69.00 13.10
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FERC FORM NO.1 lED. 12.96)Paae 426
I
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 2008/Q4
(2) 0 A Resubmission 04/15/2009
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of GI-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 Total Capacity No.In Service Transformers Type of Equipment Number of Units
(In ~~a)
(f)(g)(h)(i)u)(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
8 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
75 3 35
240 2 36
15 1 37
1 38
12 1 39
10 1 40
.
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FERC FORM NO.1 (ED. 12.96)Paae 427
Name of Respondent This 0000 Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2008/04
(2)o A Resubmission 04/1512009
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 Chestnut distrbution 138.00 13.00
2 Clear Lake - attended transmission 46.00 2.30
3 Cliff trnsmission 138.00 46.00 12.50
4 Cloverdale Distrbution 138.00 13.00
5 Dale distrbution 69.00 13.00
6 Dale distrbution 138.00 34.50
7 Dale Transmission 138.00 46.00 12.50
8 Danskin trnsmission 230.00 138.00 13.80
9 Danskin distrbution 18.00 4.16
10 Danskin trnsmission 138.00 12.00
11 Don distrbution 138.00 7.60
12 Don distrbution 138.00 13.20
13 Don distribution 138.00 13.00
14 Don distrbution 14.00
15 DRAM distrbution 138.00 13.00
16 DRAM distrbution 230.00 138.00 13.80
17 Duffn distrbution 138.00 34.50
18 Eagle distrbution 138.00 13.00
19 Eastgate distrbution 138.00 13.00
20 Eckert distrbution 138.00 36.20
21 Eden distrbution 138.00 34.50
22 Eden distrbution 138.00 46.00 12.50
23 Elkhorn distrbution 138.00 12.00
24 Elmore trnsmission 138.00 34.50
25 Elmore distrbution 138.00 69.00 12.50
26 Emmett distrbution 138.00 12.50
27 Emmett Transmission 138.00 69.00 12.50
28 Falls distrbution 46.00 12.50
29 Filer distrbution 46.00 12.50
30 Flying H distrbution 69.00 2.40
31 Fort Hall distribution 46.00 12.50
32 Fossil Gulch distribution 138.00 34.50
33 Fremont transmission 138.00 46.00 12.50
34 Gary distribution 138.00 13.00
35 Gem distribution 69.00 13.00
36 Golden Valley distrbution 69.00 12.50
37 Gowen Substation distrbution 138.00 35.00
38 Grindstone distrbution 35.00 12.50
39 Grove distrbution 138.00 12.50
40 Hagerman distribution 46.00 12.50
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i:i:ør- i:OØM NO 1 ii:n 1?QI;\Pane 426.1
I
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2008/Q4
(2)D A Resubmission 04/15/2009
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other part is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Total Capacity No.In Service Transformers Type of Equipment Number of Units
(In MVa)
(f)(g)(h)(i)0)(k)
48 2 1
4 1 2
16 3 1 3
48 2 4
9 5
27 1 6
25 1 7
14 1 1 8
6 1 9
96 2 10
1 11
108 6 1 12
26 1 13
80 6 14
134 8 15
160 2 16
36 2 17
38 2 18
36 2 19
18 1 20
24 1 21
15 1 22
15 2 23
17 1 24
30 2 25
15 1 26
25 1 27
17 2 28
10 1 29
15 2 30
10 1 1 31
15 1 32
50 3 1 33
36 2 34
17 2 35
10 1 1 36
24 1 37
10 2 38
72 3 39
15 2 1 40
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FERC FORM NO.1 tED. 12.96\Paae 427.1
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2008/Q4
(2) ri A Resubmission 04/15/2009
SUBSTATIONS
1.Report below the information called for conceming substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether trnsmission or distribution and whether
attended or unattended. At the end of the page, summarize accrding to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 Hailey distribution 138.00 12.50
2 Happey Valley distrbution 138.00 13.09
3 Haven distrbution 46.00 34.50
4 Haven trnsmission 138.00 46.00
5 Hewlett Packard distrbution 138.00 13.10
6 Hidden Springs distrbution 138.00 13.09
7 Highland distrbution 138.00 13.09
8 Hil distribution 138.00 12.50
9 Hillsdale distrbution 138.00
10 Homedale distrbution 69.00 12.50
11 Horse Flat transmission 230.00 138.00 13.80
12 Horseshoe Bend distrbution 35.00 12.50
13 Horseshoe Bend distrbution 69.00 36.20
14 Horseshoe Bend distrbution 69.00 25.00
15 Huston distrbution 69.00 13.00
16 Hulen distrbution 46.00 13.00
17 Hunt trnsmision 230.00 138.00 13.80
18 Hydra distrbution 138.00 34.50
19 Island distrbution 69.00 12.50
20 Jerome distribution 138.00 12.50
21 Julion Clawson distrbution 138.00 34.50
22 Joplin distrbution 138.00 13.00
23 Joplin distrbution 138.00 35.00
24 Karcher distrbution 138.00 13.09
25 Kenyon distrbution 69.00 12.50
26 Ketchum distrbution 138.00 12.50
27 Kinport transmission 161.00 46.00 13.00
28 Kinport transmission 230.00 138.00 12.50
29 Kinport transmission 230.00 138.00 13.80
30 Kinport transmission 345.00 230.00 13.80
31 Kramer distribution 138.00 34.50
32 Kramer distribution 138.00 13.00
33 Kuna distribution 138.00 13.00
34 Lake Fork distribution 138.00 36.20
35 Lake Fork transmission 138.00 69.00 12.50
36 Lamb distrbution 138.00 13.09
37 Lansing distrbution 69.00 13.00
38 Lincoln distrbution 138.00 13.00
39 Linden distribution 138.00 13.00
40 Locust distrbution 138.00 34.50
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i:i:Rr. i:nRM Nn 1 IFn 12.Q6\Paae 426.2
I Name of Respondent
This (80rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2008/Q4
(2) n A Resubmission 04/15/2009
SUBSTATIONS (Continued)
I 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
I
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 part is an associated company.
I
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)
Transformers Spare Total Capacity No.
I In Service Transformers Type of Equipment Number of Units
(In MVa)
(f)(g)(h)(i)ü)(k)
20 1 1
I
18 1 2
12 1 3
1 4
I
20 1 5
8 1 6
18 1 7
I
24 1 8
24 1 9
20 2 10
I
100 1 11
5 1 12
12 1 13
I 5 1 14
10 1 15
10 1 16
I 300 3 17
24 1 18
12 1 19-
I 40 2 20
30 2 21
.15 1 22
I 18 1 23
12 1 24
20 2 25
I 42 2 26
7 27
180 1 28
I 180 1 29
600 3 1 30
12 1 31
I 18 1 32
15 1 33
18 1 34
I 15 1 35
18 1 36
12 1 37
I 10 1 38
33 2 39
48 2 40
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i:1=1:U" i:oi;M NO 1 t~n 1?Qf¡\Paoe 427.2
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 2008/Q4
(2) 0 A Resubmission 04/15/2009
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 accrding to functon 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 Locust transmission 230.00 138.00 13.00
2 Lower Malad - attended trnsmission 138.00 7.20
3 Lower Salmon - attended trnsmission 138.00 13.80
4 Map Rock distribution 69.00 12.50
5 McCall distrbution 69.00 12.50
6 McCall distrbution 138.00 35.00
7 McCall trnsmission 138.00 69.00 13.09
8 Meridian distrbution 138.0C 13.00
9 Micron distrbution 138.00 12.50
10 Midpoint trnsmission 230.00 138.00 13.80
11 Midpoint transmission 345.00 230.00 13.80
12 Midpoint transmission 500.00 345.00
13 Midrose distrbution 138.00 13.09
14 Milner distrbution 138.00 69.00 12.47
15 Milner distrbution 69.00 46.00 6.90
16 Milner distrbution 138.00 34.50
17 Milner PP - attended trnsmission 138.00 13.80
18 Moonstone distrbution 138.00 34.50
19 Mora distrbution 138.00 34.50
20 Moreland distrbution 46.00 12.50
21 Moreland distrbution 46.00 34.50 12.50
22 Mountain Home distrbution 69.00 12.50
23 Mountain Home Air Force Base distribution 69.00 12.50
24 Mountain Home Air Force Base distribution 138.00 12.50
25 Nampa distrbution 230.00 138.00 13.80
26 Nampa distrbution 138.00 12.50
27 New Meadows distrbution 69.00 35.00
28 New Plymouth distribution 69.00 12.50
29 Notch Butte distrbution 13.00 7.56
30 Orchard distrbution 69.00 13.00
31 Orchard distrbution 69.00 35.00 12.47
32 Parma distribution 69.00 12.50
33 Parma distribution 69.00 34.50
34 Paul distribution 138.00 34.50 12.50
35 Payette distribution 138.00 12.50
36 Pingree transmission 138.00 46.00 12.50
37 Pingree distribution 138.00 36.00
38 Pleasant Valley distrbution 138.00 34.50
39 Pocatello distribution 46.00 12.50
40 Portneuf distribution 138.00 36.20
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FERC FORM NO.1 lED. 12-96)Paae 426.3
I
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2008/Q4
(2) n A Resubmission 04/15/2009
SUBSTATIONS (Continued)
I 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
I
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 part is an associated company.
I
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)
Transformers Spare Total Capacity No.
I
In Service Transformers Type of Equipment Number of Units
(In MVa)
(f)(g)(h)(i)ü)(k)
360 2 1
I
15 1 2
70 4 3
10 1 4
I
8 1 5
18 1 6
30 1 7
I
36 2 8
48 4 9
120 1 10
I
720 2 11
750 3 1 12
18 1 13
I
100 4 14
10 4 15
16 1 16
I
36 1 17
12 1 18
39 2 19
I
13 2 20
10 3 1 21
15 1 22
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1 23
18 1 24
180 1 25
I
50 3 26
12 1 27
10 1 28
I
11 1 29
4 1 30
16 4 31
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10 1 32
12 1 33
36 2 34
I
22 3 35
50 3 36
22 2 37
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42 2 38
36 2 39
18 1 40
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i:i:Dr i:nDM Nn 1 (i:n 1?Q~\Pane 427.3
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 2008/Q4
(2) D A Resubmission 04/15/2009
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 accrding to function the capacities reported for the individual stations in
column (t).
Une VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 Porteuf distrbution 46.00 35.00
2 Rockford distrbution 46.00 12.50
3 Russett distrbution 138.00 12.50
4 Sailor Creek distrbution 138.00 2.40
5 Sailor Creek distrbution 138.00 34.50
6 Salmon distrbution 69.00 12.50
7 Salmon distrbution 69.00 34.50 12.50
8 Shoshone distrbution 46.00 13.00
9 Shoshone distrbution 46.00 7.20
10 Shoshone Falls - attended trnsmission 46.00 2.30
11 Shoshone Falls - attended trnsmission 46.00 6.60
12 Silver distrbution 138.00 34.50
13 Simplot distrbution 138.00 12.50
14 Sinker Creek distribution 138.00 34.50
15 Siphon distrbution 138.00 34.50
16 South Park distrbution 46.00 13.00
17 Star distrbution 138.00 13.00
18 Starkey Transmission 138.00 69.00 12.50
19 State distrbution 69.00 12.50
20 Stoddard distrbution 138.00 13.00
21 Strike Power Plant - attended trnsmission 138.00 13.80
22 Sugar distribution 138.00 34.50
23 Swan Falls - attended trnsmission 138.00 6.90
24 Taber distrbution 46.00 12.50
25 Ten Mile distrbution 138.00 13.09
26 Terry distrbution 138.00 12.50
27 Thousand Springs - attended trnsmission 46.00 6.90
28 Thousand Springs - attended trnsmission 7.00 2.40
29 Toponis distrbution 138.00 34.50
30 Twin Falls distrbution 138.00 13.00
31 Twin Falls trnsmission 138.00 46.00 12.50
32 Twin Falls PP - attended trnsmission 138.00 7.20
33 Twin Falls PP - attended trnsmission 138.00 13.20
34 Upper Malad - attended transmission 46.00 7.20
35 Upper Salmon- attended transmission 138.00 7.20
36 Ustick distrbution 138.00 12.50
37 Vallvue distribution 138.00 13.09
38 Victory distrbution 138.00 12.50
39 Ware distrbution 69.00 12.50
40 Weiser distribution 69.00 12.50
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FERC FORM NO.1 lED. 12-96\Paae 426.4
I Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2008/Q4
(2) 0 A Resubmissíon 04/15/2009
SUBSTATIONS (Continued)
I 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 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)(g)(h)(i)ü)(k)
1 1
14 2 2
18 1 3
15 2 4
15 1 5
10 1 4 6
10 3 1 7
I
10 1 1 8
2 3 9
3 1 10
10 1 11
12 1 12
15 1 13
I
12 1 14
33 2 15
10 1 16
I 18 1 17
18 1 18
33 2 19
I
15 1 20
83 3 21
20 2 22
I
18 1 23
5 1 24
24 1 25
I
42 3 26
8 1 27
2 1 28
I
18 1 29
44 2 30
33 2 31
9 1 32
72 1 33
8 1 34
I 36 4 35
44 2 36
18 1 37
I 24 1 38
12 1 39
20 2 40
I
FERC FORM NO.1 tED. 12-96\Paae 427.4
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2008/Q4
(2) 0 A Resubmission 04/15/2009
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 Weiser transmission 138.00 69.00 12.50
2 Wilder distrbution 69.00 13.00
3 Wills distribution 138.00 13.09
4 Wye distrbution 138.00 13.00
5 Zilog distrbution 138.00 13.09
6
7
8 The above are all State of Idaho
9
10 Montana:
11 Peterson trnsmission 230.00 69.00 13.20
12
13 Nevada:
14 Valmy - attended trnsmission 345.00 21.30
15 Wells trnsmission 138.00 69.00 12.50
16
17 Oregon:
18 Boardman - attended trnsmission 500.00 24.00
19 Cairo distrbution 69.00 12.50
20 Hells Canyon - attended transmission 230.00 13.80
21 Hines transmission 138.00 115.00 12.50
22 Malheur Butte distrbution 69.00 34.50 12.50
23 Nyssa distrbution 69.00 12.50
24 Ontario distrbution 138.00 12.50
25 Ontario distrbution 138.00 69.00 12.50
26 Ontario distribution 230.00 138.00 13.80
27 Ore-Ida distrbution 69.00 12.50
28 Oxbow - attended trnsmission 138.00 69.00 13.00
29 Oxbow - attended trnsmission 230.00 13.80
30 Oxbow - attended trnsmission 230.00 138.00 13.80
31 Quart transmission 138.00 69.00 12.50
32 Quart trnsmission 230.00 138.00 13.00
33 Vale distribution 69.00 13.09
34
35 Wyoming:
36 Jim Bridger - attended trnsmission 345.00 22.00
37
38
39
40
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i:i:Rr. i:ORM NO.1 lED. 12-96\Paae 426.5
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 2008/Q4
(2) Õ A Resubmission 04/15/2009
SUBSTATIONS (Continued)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other part is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Servce) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units
(In MVa)
(f)(g)(h)(i)0)(k)
25 1 1
10 1 2
18 1 3
56 3 4
24 1 5
6
7
8
9
10
20 2 2 11
12
13
150 1 14
20 3 1 15
16
17
55 1 18
12 1 19
501 4 20
40 1 21
8 3 1 22
20 2 23
38 2 24
75 3 1 25
240 2 26
15 1 27
10 3 1 28
244 2 29
100 1 30
30 2 31
100 3 1 32
10 1 33
34
35
748 1 36
37
38
39
40
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FERC FORM NO.1 lED. 12.96)Paae 427.5
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 2008/Q4
(2)o A Resubmission 04/15/2009
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (t).
Une VOLTAGE (In MVa)
No.Name and Loction of Substation Character of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1
2
3 Transformers-distrbution substations under 10,000
4 KVA 88 unattended.
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
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i=i=Rr. i=ORM NO.1 lED. 12.96\Paae 426.6
I Name of Respondent
This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2008/Q4
(2) Õ A Resubmission 04/15/2009
I
. SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
I
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, .c-owner, or other part is an associated company.
I
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.
I In Service Transformers Number of Units
(In MVa)
(f)(g)(h)(i)0)(k)
1
I
2
3
350 4
5
6
7
I
8
9
10
I
11
12
13
I
14
15
16
I
17
18
19
I
20
21
22
I
23
24
25
1
26
27
28
I
29
30
31
I
32
33
34
I 35
36
37
I
38
39
40
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iiiiDI" iinDM i\n 1 ii=n 1?_QR\Paae 427.6
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Page
Number
2
3
3
4
5
6
7-10
11
12-15
15
IDAHO SUPPLEMENT
December 31,2008
ANNUAL REPORT
IDAHO SUPPLEMENT TO FERC FORM 1
MUL TI.STATE ELECTRIC COMPANIES
INDEX
Title
Statement of Income for the Year
Taxes Allocated to Idaho
Notes and Accounts Receivable
Accumulated Provision for Uncollectible Accounts
Receivables from Associated Companies
Gain or Loss on Disposition of Property
Professional or Consultative Services
Electric Plant in Service
Electric Operating Revenues
Electric Operation and Maintenance Expenses
Number of Electric Department Employees
Idaho Power Company
STATE OF IDAHO. ALLOCATED
An Original
STATEMENT OF INCOME FOR THE YEAR
December 31,2008
1. Report amounts for accounts 412 and 413, Revenue and Expenses from Utilty Plant Leased to Others, in another utility
column (i,k,m,o) in a similar manner to a utilty department. Spread the amount(s) over lines 01 thru 24 as appropriate.
Include these amounts in columns (c) and (d) totals.
2. Report amounts in account 414, Other 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 accunts 404.1, 404.2, 404.3, 407.1, and 407.2,
4. Use page 122 for important notes regarding th state ment of income or any accunt thereof.
5. Give concise explanations concerning unsett rate procdings whre a contingncy exists such that refunds of a
material amount may need to be made to the utlits customers or which may result in a material refund to the utilty
with respect to power or gas purchases. State for each year affeced the gross revenues or costs to which the contingency
relates and the tax effects together with an explanation of retain such revenues or recover amounts paid with respect
to power and gas purchases.
6. Give concise explanations concerning significant amounts of any refunds made or received during the year.
Line
No,
Account
(Ket.'
Page TOTAL
No.t;urrent Year Previous Year
(b)(c)(d)
11 $910,245,287 $841,478,350
15 550,991,682 517,569,128
15 64,078,869 63,803,165
89,690,866 88,365,074
4,622,992 4,925,898
(a)
1 UIILIIY
2 Operating Revenues (400).,....................................,...........................................
3 Operating Expenses
4 Operation Expenses (401)............................................................................,....
5 Maintenance Expenses (402)....................................................................,.......
6 Depreciation Expense (403)..............................................................................
7 Amort. & Depl. of Utilty Plant (40405)....... ...... ......... ..... ........... ... ... .... ............
8 Amort. of Utility Plant Acq. Adj. (406)................................................................
9 Amort. of Property Losses, Unrecovered Plant and
10 Regulatory Study Costs (407).........................................................................
11 Amort. of Conversion Expnses (407)...............................................................
12 Regulatory Debits/Credits (407.3 & 407,4)........................................................
13 Taxes Other Than Income Taxes (408.1 )..........................................................
14 Income Taxes - Federal (409.1)........................................................................
15 - Other (409.1 )........................,............................................................
16 Provision for Deferred Income Taxes (410.1 & 411.1) Net..........................
17 Investment Tax Credit Adj. - Net (411.4)...........................................................
18 (Less) Gains from Disp. of Utility Plant (411.6)..................................................
19 Losses from Disp. of Utilty Plant (411. 7)...........................................................
20 (Less) Gains from Disposition of Allowances (411.8).........................................
21 Losses from Disposition of Allowances (411.9).................................................
22
23 TOTAL Utilty Operating Expenses (Enter Total of lines 4 thru 22)..................
24
25 Net Utilit Operating Income (Enter Total of line 2 le 23)
26 (Carr forward to page 11, line 27)................................................................
2
2
2
2
2
(3,781,013)
17,214,058
(1,876,222)
(5,091,963)
41,638,625
2,343,614
759,831,509
2,114,441
15,922,687
2,592,539
(6,483,885)
34,515,479
1,862,104
725,186,631
$150,413,778 $116,291,719
IDAHO SUPPLEMENT Page i
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Idaho Power Company
STATE OF IDAHO
An Original December 31, 2008
TAXES ALLOCATED TO IDAHO
Kind of Tax
Taxes Other Than Income Taxes:
Labor Related:
FiCA..........................,.......................................,
FUTA.................................................................
State Unemployment.........................................
Payroll Deduction & Loading............................
Total Labor Related................................
Property Taxes..... ...... ..... ............. .... ....................
Kilowatt-hour Tax.. .............. .................... ........... ...
Licenses...............................................................
Regulatory Commission Fees...............................
Irngation p~c........ ............... ..... .......................... ...
Total Taxes Other Than Income Taxes.... .......... ....
Federal Income Taxes..... ...................... .................
State Income Taxes.... ..... ... .......... ..........................
Deferred Income Taxes... ....... ............ ............ ..... ...
Investment Tax Credit Adjustment - Net............ ...
Taxes Charged
Dunng Year
$ 10,762,704
117,126
176,070
(11,055,900)
°
13,987,518
1,242,360
3,169
1,728,039
252,972
17,214,058
(1,876,222)
(5,091,963)
41,638,625
2,343,614
Total Taxes Allocated to Idaho... ................ ............ $ 54,228, 112
IDAHO SUPPLEMENT Page 2
Idaho Power Company
STATE OF IDAHO
An Original December 31, 2008
NOTES AND ACCOUNTS RECEIVABLE
Summary for Balance Sheet
Show separately by footnote the total amount of notes and accunts receivable
from directors, offcers, and employees inCluded in Notes Receivable (Accunt
141) ånd Other Accounts Receivable (Accunt 143)
Line Accounts
Liaiance
Beginning of
Year
(b)
:',l:f:',4bll :I
62,122,209
7,080,171
75,177,848 $
1,305,058
73,872,789 $
Liaiance
End of
Year
(c)
1,:il:,U41
64,433,173
6,557,937
72,540,152
1,723,936
70,816,216
ACCUMULATED PROVISION FOR UNCOLLECTIBLE ACCOUNTS - CR. (Account 144)
1. Report below the information called for concerning this accumulated provision,
2. Explain åny important adjustments of subaccounts.
3, Entries with respect to officers and employees shall not inClude items tor utilty services.
Mdse,
Jobbing &
Contrct
Work
(c)
No,
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
(a)
Notes Receivable (Account 141)............,...........,..............................................,",........"...,......., :¡
Customer Accounts Receivable (Accunt 142)..,.....................................,.......,...,...........,...........
Other Accounts Receivable (Account 143)................................................................... ".............
(Disclose any capital stock subscnption received)
Total,....,.,...........,.....,......,............................,.......,.................,........................,..................... $
Less: Accumulated Provision for Uncollecible
Accounts-Cr. (Account 144),...,."................,........,..............................,............................,',..
Total, Less Accumulated Provision for
Uncollectible Accounts..."...,.............,... ......,..,....,. ............,.......... .................,.......,. ............, $
Notes Receivable - Account 141: (at 12-31-08)
Directors, offcers, and employees - $232,483
Other
(e)
Total
(I)
Other Accunts Receivable - Account 143: (at 12-31-08)
Directors, offcers, and employees - $ 2,246
$331,180 1,494,812
229,124
;¿1
22 Bal. beginning of year $ 1,163,632 $
23 Provo for uncollectibles
24 for year................................................... 141,427
25 Accounts wrten off..................................
26 Coli. of accounts
27 written off.................................... ............
28 Adjustments (explain)...............................
29
30
31
32 Balance end of year.... ............. ..... ....... .....:I 1 ,305,058 :I
33
- :I 1,723,936
IDAHO SUPPLEMENT Page 3
Line Item Utlit
Customers
Offcers
and
Employees
(d)
No.(a)
87,697
- :I 418,877 :I
(b)
$
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Idaho Power Company
STATE OF IDAHO
An Original December 31, 2008
RECEIVABLES FROM ASSOCIATED COMPANIES (Accunts 145, 146)
1. Report particulars of notes and accounts receivable from associated companies at end of year.
2, Provide separate headings and totals for accounts 145, Notes Receivable from Associated Companies, and 146,
Accounts Receivable from Associated Companies, in addition to a total for the combined accounts.
3. For notes receivable list each note separately and state purpose for which received. Show also in column
(a) date of note, date of maturity and interest rate,
4, If any note was received in satisfaction of an open account, state the period covered by such open accunt.
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.
Balance
Line Particulars Beginning Totals for Year Balance Interest
of Year Deois ""reOis End of Year For Year
No,(a)(b)(c)(d)(e)(f)
1 Account 145:
2
3 IERCO...........,........................$21,527,626 $48,593,324 $43,541,179 $26,579,771
4
5
6
7
8
9
10 Total Account 145....................21,527,626 4lS,5!:J,324 43,541,179 26,579,771
11
12 Account 146:
13
14
15
16 IPACORP, Inc..........................$-$3,274,632 $3,276,644 $(2,011)
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31 Total Account 146........................:I - :I 3,274,632 :I 3,i'7 ~.(2,011)
32
IDAHO SUPPLEMENT Page 4
Idaho Power Company
STATE OF IDAHO
An Original December 31,2008
STATE OF IDAHO - TOTAL SYSTEM DATA
GAIN OR LOSS ON DISPOSITION OF PROPERTY (Account 421.1 and 421.2)
1. Give a brief description of propert creating the gain or loss, Include name of part acquiring the propert (when
acquired by another utility or associated company) and the date transaction was completed. Identif propert
by type; Leased, Held for Future Use, or Nonutilit.
2. Individual gains or losses relating to propert wih an oriinal cost of less than $50,000 may be grouped, with the
number of such transactions disclosed in column (a).
3. Give the date of Commission approval of joumal entes in column (b). whn approval is required. Where approval
is required but has not been received. give explanation following the item in column (a). (See account 102, Utility
Plant Purchased or Sold,)
Line Description of Property
Onginal Cost
of Related
Propert
(b)
Date Journal
Entry Approved
(Whn Required)
(c)(e)
Acct 421.1 Acct421.2
(d)No,(a)
1 Gain on disposition of
2 property:
3
4 Inkom Junction
5
6 Gain on sale of SWIP
7
8 Misc Items (2)
9
10
11
12
13
14 Total gain.......................................................... $
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31 Totalloss....................................................... . $
217/2008 $78,72817,796
619/2008 $3,011,3273.65,186
64,479 (38.548)
$3,051,5063,547,461
$o u
IDAHO SUPPLEMENT Page 5
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Idaho Power Company
STATE OF IDAHO
An Original December 31, 2008
STATE OF IDAHO - TOTAL SYSTEM DATA
PROFESSIONAL OR CONSULTATIVE SERVICES -ITEMS $10,000 AND OVER
Line Amountrr i;i;lYI-t:
No.(a)(b)(c)
1 AERO-GRAPHICS Mapping Services $47,682
2 BARKER, ROSHOLT & SIMPSON LLP Legal Services 502,770
3 BIOART & ROSS INC Management Services 32,350
4 BLUE HERON CONSULTING, INC Legal Services 269,942
5 BOUILLON INTEGRATED SYSTEMS, i Computer Support Services 96,160
6 BRENNEMAN, JOHN Lobby Services 73,053
7 BRIGHAM YOUNG UNIVERSITY Environmental Services 45,000
8 BROWN RUDNICK BERLACK ISRAELS Lobby Services 72000
9 BROWNSTEIN HYATT & FARBER, P C Legal Services 2,405,630
10 BUREAU OF LAND MANAGEMENT Environmental Services 130,000
11 CADMUS GROUP INC, THE Architect Services 58,256
12 CASCADE ENERGY ENGINEERING INC Engineering Services 84,347
13 CEDARCRESTONE INC Computer Support Services 64,800
14 CHURCH, JOHN S Economic Services 78,000
15 CLEAREDGE PARTNERS INC Computer Support Services 79,500
16 COMMVAUL T SYSTEMS, INC Computer Support Services 22,000
17 COMSYS INFORMATION TECHNOLOGY Computer Support Services 518,100
18 CORNERSTONE SYSTEMS INC Computer Support Services 1,239,569
19 CSHQA Architect Services 106,326
20 CTA ARCHITECTS Architect Services 13,443
21 DAVID EVANS AND ASSOCIATES Management Services 98,670
22 DAVIS WRIGHT TREMAINE LLP Legal Services 505,494
23 DELOITTE & TOUCHE Accounting Servics 321,884
24 DEVINE, TARBELL & ASSOC INC Engineering Services 20,308
25 DEWEY & LEBOEUF Legal Services 3,823,131
26 DHIINC Environmental Services 71,996
27 ECOANAL YSTS INC Environmental Services 194,083
28 ECOTOPE Architect Services 34,142
29 EMC CORPORATION Computer Support Services 23,309
30 ENTERPRISE ELECTRIC, INC.Management Services 18,677
31 ERNST & YOUNG LLP Accunting Services 27,785
32 EVANS KEANE Legal Services 13,151
33 FALASH & ROSS CONSTRUCTION INC Management Services 14,749
34 GILBERT, DAN D Meteorological Services 28,600
35 GLOBAL INSIGHT Environmental Services 25,057
36 HARDESTY, REBECCA Environmental Services 105,214
37 HONEYWELL INTERNATIONAL INC Environmental Servics 10,115
38 HOPKINS RODEN CROCKETT HANSEN Lobby Services 72000
39 HR MANAGEMENT SOLUTIONS LLC Management Services 19,594
40 HYQUAL Environmental Services 110,047
41 INTERMOUNTAIN TECHNOLOGY GROUP Computer Support Services 30,720
42 IOWA INSTITUTE OF HYDRAULICS Consulting Services 11,735
43 JONES AND SWARTZ PLLC Legal services 226,146
44 JUB ENGINEERS Engineering Services 27,306
45 KPMG LLP Accunting Services 133,554
pa e ti9
IDAHO SUPPLEMENT
Idaho Power Company
STATE OF IDAHO
An Original December 31, 2008
STATE OF IDAHO - TOTAL SYSTEM DATA
PROFESSIONAL OR CONSULTATIVE SERVICES - ITEMS $10,000 AND OVER
Line PAYEE ....., v,,,.. TYPE Amount
No.(a)(b)(c)
46 L CONWAY CONSULTING, INC Consulting Services $37,327
47 MAGIC WATER Consulting Services 14,904
48 MANAGEMENT NORTHWEST Legal Services 68,655
49 MCCLURE ENGINEERING Engineering Services 18,000
50 MCDOWELL & RACKNER PC Legal Services 148,229
51 MIRANDE, MICHAEL Legal servics 76,712
52 MODULA4 LLC Computer Support Services 22,497
53 MODUS ARCHITECTURE Aritec Serics 319,487
54 MOEN, MONICA B Legal servs 10,439
55 MUSGROVE ENGINEERING PA Enginering Services 19,478
56 NEXANTINC Computr Support Services 109,332
57 NIELSEN GROUP INC, THE Consulting Services 134,793
58 OFFICE ENVIRONMENT COMPAN Management Services 18,697
59 OLIVER, RUSSELL & ASSOC. INC Environmental Services 15,000
60 OREGON STATE DEPARTMENT OF ENE Environmental Servs 50,000
61 PAINE, HAMBLEN, COFFIN, BROOK Management services 338,396
62 PAPPALARDO CONSTRUCTION Construn services 19,448
63 PARR WADDOUPS BROWN GEE AND LO Environmental Servces 108,183
64 PEAK SCIENCE COMMUNICATIONS Management servs 60,993
65 PEASLEY TRANSFER & STORAGE CO Managemnt servs 25,054
66 PHONE PRO Managemnt Servces 15,553
67 PINK ELEPHANT CORP Computer Support Servics 12,826
68 PLANNEDSCAPE Consultng Services 45,620
69 PORTLAND ENERGY CONSERVATION,Environmental Services 169,477
70 PUBLIC OPINION STRATEGIES LLC Management Services 16,000
71 RWBECK Consultng Services 70,356
72 RIDDELL WILLIAMS P.S.Legal Servces 27,391
73 RIPLEY, LARRY D Legal services 20,300
74 RIVERSIDE TECHNOLOGY INC Management Services 119,792
75 S G S STATISTICAL SERVICES Consulting Services 14,250
76 SALLADAY & DAVIS Legal Services 64,671
77 SCIENCE APPLICATIONS INTE Environmental Services 12,848
78 SOFTARE AG INC Computer Support Services 109,760
79 SOLID QUALITY LEARNING LLC Computer Support Servics 28,319
80 SOS STAFFING SERVICES Management Services 24,466
81 SPHERION STAFFING AND RECRUITI Management Services 236,704
82 SPINK BUTLER LLP Legal Services 19,411
83 ST LUKES REGIONAL MEDICAL Consultng Servics 10,000
84 STATE OF IDAHO FISH & GAME Environmental Services 100,000
85 STATISTICAL DESIGN Consulting Services 33,681
86 STEPTOE & JOHNSON LLP Legal Services 317,682
87 STOEL RIVES LLP Legal Services 88,458
88 STRUCTURED Engineering Services 100,035
89 SULLIVAN & CROMWELL Management services 169,362
Page6A
IDAHO SUPPLEMENT
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Idaho Power Company
STATE OF IDAHO
An Original December 31,2008
STATE OF IDAHO - TOTAL SYSTEM DATA
PROFESSIONAL OR CONSULTATIVE SERVICES - ITEMS $10,000 AND OVER
Une -1" I 1;1;V.., 'v IV.. TYPE Amount
No.(a)(b)(c)
90 SWCA, INC Environmental Services 19,292
91 TEKSYSTEMS Computer Support Services 248,353
92 TETRA TECH INC Consulting Services 11,851
93 TOWERS PERRIN HR SERVICES Management Services 43,303
94 TREASURE VALLEY LEGAL SERVICES Legal Services 67,776
95 TROUT, JONES, GLEDHILL, FUHRMA Legal Services 19,070
96 UNIVERSITY OF IDAHO Environmental Services 93,400
97 VAN NESS FELDMAN Legal services 921,135
98 VAN WINKLE ENVIRONMENTAL CONSU Environmental Services 15,400
99 WEATHER DECISION TECHNOLOGIES Meteorological Services 17,936
100 WEATHER MODIFICATION INC Cloud Seeding Services 274,392
101 YTURRI& ROSE& BURNHAM& BENTZ Legal Services 65,544
1 I TOT AL 17,146,431
IDAHO SUPPLEMENT Page 68
Idaho Power Company
STATE OF IDAHO
An Original DecØfber31,2008
PROFESSIONAL OR CONSULTATIVE SERVICES
ITEMS $5,000 OR MORE BUT LESS THAN $10,000
Line PREDOMINANT
No,PAYEE NATURE OF SERVICE AMOUNT
1 BAKER, KEN Management Services 5,000
2 BINDA, CHERYL E Consulting Services 8,025
3 CEDAR CREST CORP Computer Support Services 7,826
4 CERTUS SOFTWARE INC Computer Supprt Servces 6,375
5 CONNOR CLAIMS SPECIALISTS Consulng Servics 6,882
6 CORPORATE EXECUTIVE BOARD Management Se~8,850
7 DATA ONE LLC Computr Support Servces 5,853
8 ECOS CONSULTING Consulting Servics 5,771
9 FINANCIAL CONCEPTS AND APPLICA Manageme Services 6,100
10 GJORDING & FOUSER, PLLC Manament Seric 6,111
11 HALL FARLEY OBERRECHT & B Legal Services 8,864
12 HEINZ FROZEN FOODS Consultng Servics 6,186
13 HOLLAND LAW OFFICE, PC Legal Servces 7,125
14 MERCER HEALTH & BENEFITS Consulting Services 9,000
15 MILLER BATEMAN LLP Legal Servics 8,459
16 NEUROLOGICAL ASSOCIATES Environmental services 7,374
17 PACIFICORP Consultng Servic 5,338
18 PANTER, GREGORY W Loby Servces 9,000
19 PLATEAU SYSTEMS LTD Coputr Support Services 9,600
20 POWER ENGINEERS INC Engineng Serice 9,039
21 QUANTECLLC Computr Support Servce 6,121
22 SMITH, CURTIS D Meteroic Servs 7,546
23 STAHMAN, ROBERT W Legal Servce 5,500
24 SWANSON ENTERPRISES LLC Managent Servce 5,517
25 TOOTHMAN-ORTON ENGINEERING Engineerig Services 8,049
26 TREASURE VALLEY ENGINEERS INC Engineering Services 8,100
27 UTZ,AARON D Environmental services 6,956
28 WRUBLE WILDLAND SERVICES Environmental services 8,333
29
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40
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This Page Intentionally Left Blank
No.
Accunt
(a)
t:alance at
Beinning of year
(b)
Additions
(c)
I
December 31, 2008
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Idaho Power Company
STATE OF IDAHO. ALLOCATED
An Original
ELECTRIC PLANT IN SERVICE (Accunts 101, 102, 103 and 106)
1. Report below the oriinal cost of elecc plnt in servic acrding to the precribed accunts.
2. In addition to Accnt 101, Elecric Plant in Service (Classifed), this page and the next include Accunt 102, Electric Plant
Purchased or Sold; Accunt 103, Experimentl Elecri Plant Unclssifed; and Accunt 106, Completed Construction
Not Classifed - Electri,
3. Include in column (c) or (d), as appropriate, corrctons of additions and reirements for the current or preceding year.
4. Enclose in parentheses credit adjustments of plant accunts to indicate the negative efec of such acunts,
5. Classify Account 106 accrding to prescrbed accunts, on an estimated basis if necssary, and include the entries in
column (c) ,Also to be included in column (c) are entries for reversals oftentative distributons of prir year reported in
column (b). Likewise, if the respondent has a signifcant amount of plant retirements the end of the year, include in
column (d) a tentaive distribution of such rerements, on an esmated basis, wih approprite contra entry to the account
for accumulaed deprecatn prosio. Include alo in coumn (d) reversal of tene distriutions of prior year of un-
classifed retirements, Attach supplementl stement showng the acunt distribu of these tentative classificions in
columns (c) and (d), including the reve of the pri yers tente accnt disribuns of these amounts. Carefulob-
servance of the above instrctns and th tex of Accnt 101 and 106 will avoid serius omissions of the reported amount
of respondent's plant acually in servic at end of year.
Line1 1.
2 (301) Organizion,......,.............,......,.................................,...... ........,..... .,...,...".......
3 (302) Franchises and Consents",....,.......,',.........,',.............................,.,..,....,',..."...,'
4 (303) Miscellaneous Intangible Plant....."..,.........,.,..................................,...... .,"',.....
5 TOTAL Intangible Plant (Enter Total of lines 2,3, and 4)..........................................6 2. PRODUCTION PLANT
7 A. Steam Proucon Plant
8 (310) Land and Land Right........................................................................................
9 (311) Structures and Improvement...........................................................................
10 (312) Boiler Plant Equipment......,.............."........"....,.........................".,..........".."....
11 (313) Engines and Engine Drien Geerars............................................................
12 (314) Turbogeneraor Units....................".....".............".....................................,..,...,
13 (315) Accssory Electric Equipment..,.....,..................,......................"..............,........
14 (316) Misc, Power Plant Equipment...........................................................................,
15 (317) Asset Retirement Costs for Steam Productn... ............... ............ ...... .....
16 TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)................................17 B, Nuclear Prouction Plnt
18 (320) Land and Land Rights........................................................................................
19 (321) Structures and Improvements,....,...,..,',..........,..............................."..,.....".....,
20 (322) Reacor Plant Equipment......................".........."...............................................
21 (323) Turbogenerator Units.,..,',.....................,........................................................,...
22 (324) Accssory Eleri Equipment..............................,....,....,........,....,..,.................
23 (325) Misc. Power Plant Equipment............................................................................
24 (326) Asset Retrement Cost for Nucl Prouctn... ... ... ...... ........... ... ...... ... ..
25 TOTAL Nuclear Producn Plant (Enter Tot of lines 17 thru 24)............................26 C. Hydraulic Proucton Plnt
27 (330) Land and Land Rights............................................................................... .........
28 (331) Structures and Improvements...........................................................................
29 (332) Reservoirs, Dams, and Waterways............................. ...... ................................
30 (333) Water Wheels, Turbines, and Generators............................. .......... ............. ....
31 (334) Accessory Electric EquipmenL..........."............,.,",................................,',.,..
32 (335) Misc, Powr Plant EquipmenL.........................................................................
33 (336) Roads, Railroads, and Bridges....... ........................................ ...........................
34 (337) Asset Retirement Costs for Hydraulic Proucton... ... ... ... ... ... ..... ... ... .., ... ...
35 TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34).........................
36 D. Other Proucon Plant
37 (340) Land and Land Rights........................................................................................
38 (341) Structures and Improvements,..................................,.,",..,.,..,......,',..,..............
39 (342) Fuel Holers, Proucts and Accsoris..........................................................
40 (343) Prime Movers...,............................"..,.......,",...............,',..,..,.............................
41 (344) Generaors......,',........,..,.....,......................."............,',..,",..,.......,.....................
42 (345) Accssry Electric EquipmenL...................... ................... ........... ...........".......
43 (346) Misc Power Plant EquipmenL................................ ............................ ............
~age7
$ 5,289
20,729,010
45,458,188
00,''''',''01
4,751,512
824,234,217
0"". ''','0''0
IDAHO SUPPLEMENT
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Idaho Power Company
STATE OF IDAHO. ALLOCATED
An Original Deember 31, 2008
ELECTRIC PLANT IN SERVICE (Accunts 101, 102, 103 and 106) (Continued)
Show in column (I) reclassifcaions or transfers wihin utility plant accounts. Include also in column
(I) the additions or reductons of primary accunt classifcans arising from distribution of amounts
initally recorded in Accunt 102. In showing the clearance of Account 102, include in column (e) the
amounts wih respect to accmulated provision for deprecon, acuisitn adjustments, etc" and show
in column (I) only the ofset to the debits or credits distributed in column (I) to primary accunt classifcaions,
For Accunt 399, state the nature and use of plant included in this acunt and if substntial in amount
submit a supplementary statement showng subaunt classifcation of such plant conforming to the
requirements of these pages.
For each amount comprising the reported balance and changes in Accunt 102, ste the property purchased
or sold, name of vendor or purchaser, and date of transaction. If propos journal entris have ben filed
wih the Commission as reuired by the Uniform System of Accunts, give also date of such fiUng.
I:aianceat Line
Retrements Adjustments Transfers End of Year
(d)(e)(I)(g)No,
1
$51,819 (301)2
20,695,155 (302)3
30,625,097 (303)4
51,372,071 5
6
7
(310)8
(311)9
(312)10
(313)11
(314)12
(315)13
(316)14
4,378,761 (317)15
v~v,..~,v 'v 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
35
36
(340)37
(341)38
(342)39
(343)40
(344)41
(345)42
(345)43
..age II
IDAHO SUPPLEMENT
Idaho Powr Company
STATE OF IDAHO. ALLOCATED
An Original December 31, 2008
ELECTRIC PLANT IN SERVICE (Accunts 101, 102, 103 and 106) (Contnued)
Line i:aiance at
Account Beginning of year Additions
No.(a)(b)(c)
44 1(345) MiSC. power piant E:qulpmenL...........................,..............................................
45 TOTAL Other Producon Plant (Enter Total at lines 37 thru 44).............................;¡1 UL,4;(0,:iU;'
46 TOTAL Producton Plant (Enter Toll oflines 16, 25, 35, and 45)..........................1,"01,4.:.:,140
47 3, TRNSMISSION PLANT
48 (350) land and land Rights.,.........,................,.......,',........,.........................................26,624,995
49 (352) Structures and Improements...............,",........,............,',........,..,.,...............,...34,464,805
50 (353) Statn Equipment...............................................,.............................................224,406,655
51 (354) Towers and Fixures................,.......................".."...................."...............,.."....104,698,993
52 (355) Pols and Fixure.............................................."....................................,.......,.73,602,511
53 (356) Overhead Conductors and Devic...................................................................118,628,677
54 (357) Underground Conduit.........,.................,."...,......................."."...........................
55 (358) Underground Conductors and Devices",..........."..... ,.,.....,.."..,...... .......,..,........
56 (359) Roads and Trails"",',........................................,....,"',...............,.....................,..261,238
57 (359,1) Asset Retirement Costs for Transmission Plant.... ... ... .............. ... ... ......
58 TOTAL Transmission Plant (Enter Tot at fines 48 thru 57)...................................ao"",ool,OI"
59 4. DISTRIBUTION PLANT
60 (360) land and land Rights.",.....................................,...........................................,...4,177,113
61 (361) Structures and Improement...........,........................,.......................................20,581,394
62 (362) Station Equiment.,......,',..........................................,.....................,..........,........144,293,516
63 (363) Storage Batery Equipment...."................................,",...............................,.......
64 (364) Poles, Tow, and Fixures....................,.,........................................................187,646,959
65 (365) Overhead Conductors and Devi.,.............".........................,..................."...99,310,499
66 (366) Underground Conuil..."..............,.............................,...................."..................45,493,283
67 (367) Underground Conducor and Des...... ...... ..................................................168,166,353
68 (368) Line Transformers,..,......,......"......................,....,................................................320,594,439
69 (369) Services......,....,',....,......................................,.....,.."...........................................51,079,812
70 (370) Meters.",..,..,',..."....,........ ..................,.......,.........................................................53,914,672
71 (371) Installations on Customer Premises...............,..,.,..............................................2,446,858
72 (372) leased Propert on Customer Premises...........................................................
73 (373) Street Lighting and Signal Systems....................................................................3,916,181
74 (374) Asset Retirement Costs for Distbution Plant........,.., ...... ..... ..................
75 TOTAL Distributin Plant (Enter Toll at fines 60 thru 74).......................................1, LUL,521 ,UILU
76 5. GENERAL PLANT
77 (389) land and land Rights........................,..,....,.................................".............,.......8,229,314
78 (390) Struures and Improvement..............................,",.................,',.".............."...63,800,301
79 (391) Ofce Furnure and Equipment..........................................................................35,424,379
80 (392) Transpon Equipment.....,.............,.......,.......................................................53,102,346
81 (393) Stores Equipmnt..........................,..,.....,"',...................,.....,.............,..............,996,702
82 (394) Tools, Shop, and Garage Equipment...............................................................4,090,231
83 (395) laboratory Equipment.......,.......,.....,...,...,",..,........................,...........,...............9,489,976
84 (396) Powr Operaed Equipment.,.............,..,""',................,......,.......,",..................8,077,988
85 (397) Communicaion Equipment....,..,........"...................,......,...,....,"',..".,..........."...24,014,386
86 (398) Miscelaneous Equipment...,...,",..,......,.....,...........,.............,......,",......,',...,..,...2,806,494
87 SUBTOTAL (Enter Total of lines 77 thru 86)............................................................L 'U,U~L,
88 (399) Other Tangible Propert........,......................,..,",................................................
89 (399.1) Asset Retirement Costs for General Plant..,...... ...... .............. ...... ......
90 TOTAL General Plant (Enter Tot at tines 87, 88 and 89).....................................;(1 u,u;';(,11 (
91 TOTAL (Accunts 101 and 106)....."......"...........................................,............,3,521,955, (UO
92 (102) Elecric Plant Purcased .....,..........................,",........,.....................,......"........,
93 (less) (102) Electri Plant Sold....................................................................................
94 (103) Exrimentl Plant Unclas,......,....,....,........... ......,........,"",.....,..,",...........
95
96 TOTAL Electric Plant in Service..,............................"..............................................:I ;',:i21,!ltíO,fUtí
t"ageii
IDAHO SUPPLEMENT
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Idaho POwer Company
STATE OF IDAHO. ALLOCATED
An Original Deember 31, 2008
ELECTRIC PLANT IN SERVICE (Accunts 101, 102, 103 and 106) (Continued)
Baiance at Line
Retirements Adjustments Transfers End otVear
(d)(e)(f)(9)No.
(340)44
:I ,~, ,u '~.'uu 45
1,555,391,322 46
47
29,508,846 (350)48
35,140,814 (352)49
242,900,194 (353)50
117,045,225 (354)51
77,089,121 (355)52
126,757,259 (356)53
(357)54
(358)55
259,733 (359)56
(359.1)57
O;¿ll,/Ui,l!1;¿58
59
4,477,141 (360)60
23,233,750 (361)61
158,476,358 (362)62
(363)63
193,280,200 (364)64
108,838,821 (365)65
46,743,899 (366)66
176,439,252 (367)67
347,244,209 (368)68
52,673,244 (369)69
56,487,653 (370)70
2,319,885 (371)71
(372)72
3,943,911 (373)73
(374)74
1,114, i:'1l,3;¿3 75
76
10,029,463 (389)77
66,136,218 (390)78
42,518,018 (391)79
54,120,84 (392)80
1,095,243 (393)81
4,453,928 (394)82
9,922,115 (395)83
8,033,807 (396)84
24,184,365 (397)85
3,803,267 (398)86
;¿;¿4,;¿!1/,;¿oll 87
(399)88
(399.1)89
224,297,258 90
3,133,lI;¿U,1I0 91
(102)92
(102)93
(371)94
95
:I 3,133,!1;¿U,lItl 96
Page 10
IDAHO SUPPLEMENT
STATE OF IDAHO - ALLOCATED
An OriginalIdaho Power Company December 31,2008
ELECTRIC OPERATING REVENUES (Account 400)
1, Report below operating revenues for each prescribed account, and manufactured gas revenues in total.
2. Report number of customers, columns (f) and (g), on the basis of meters, in addition to the number of flat rate
accounts; except that where separate meter readings are added for biling purposes, one customr should be counted
for each group of meters added. The average number of customers means the average of twelve figures at the close
of each month.
3. If previous year (columns (c), (e) and (g), are not derive from previously reorted figures, explain any
inconsistencies in a footnote,
OPERATING REVENUES
No.
Amount for
Current Year
Amount for
Previous Year
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
(a)
Sales of Electricit
(440) Residential Sales.................................................."............. $
(442) Commercial and Industrial Sales
Small (or Commercial)(See Instr. 4) (1)......................................
Large (or Industril)(Se Instr. 4) (2)...........................................
(444) Public Stree and Highwy Lightng......................................
(445) Other Sale to Public Authories.........................................
(446) Sales to Railroads and Railwys..........................................
(448) Interdepartmental Sale.......................................,...............
TOTAL Sales to Ultimate Consumers.......................................
(447) Sales for Resale - Opportunity.... Non-Firm Only.................
TOTAL Sales of Electricit.......................................................
(449) Provision for Rate Refunds.................................................
TOTAL Revenue Net of Proviion for Refund.........................
Other Operating Revenues
(45) Foneited Discunts.............................................................,
(451) Miscellaneous Service Revenue.........................................
(453) Sales of Water and Water Powr.........................................
(454) Rent from Electric Propert..................................................
(45) Interdepartmental Rents........,..........,.........,..........,.............
(456) Other Electic Revenues......................................................24,347,160
(b)(c)
341,596,320 $297,428,947
294,564,569
113,125,182
2,784,169
245,919,592
92,303,177
2,374,374
752,070,239 *
113,059,123
865,129,362
(5,876,173)
859,253,189
638,026,089
159,135,233
797,161,322
(1,075,534)
796,085,788
3,611,150 3,996,236
16,916,322 17,049,167
30,464,627
TOTAL Other Operting Revenue..........................................
TOTAL Electric Opeing Revenues........................................ $
50,992,098
910,245,287 $
45,392,562
841,478,350
(1) Commercial and Industrial sales - Small - under 1,000 KW and includes all irrigation customers.
(2) Commercial and Industrial sales - Large - 1,000 KW and over.
Page 11
IDAHO SUPPLEMENT
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Idaho Power Company
STATE OF IDAHO . ALLOCATED
An Original Dece~r 31, 2008
ELECTRIC OPERATING REVENUES (Account 400) (Continued)
4. Commercial and Industrial Sales, Accunt 442, may be classified accrding to the basis of classifiction
(Small or Commercial, and Large or Industral) regularly used by the respondent if such basis of classification
is not generally greater than 1000 Kw of demand. (See Accunt 442 of the Uniform System of Accunts, Explain
5. See page 108, Important Changes During Year, for important new terrtory added and important rate increases or
decreases.
6. For lines 2, 4,5, and 6, see page 304 for amounts relating to un billed revenue by accunts.
7. Include unmetered sales. Provide details of such sales in a footnote.
KILOWATT HOURS SOLD AVERAGE NUMBER OF CUSTOMERS PER MONTH
Amount for
Current Year
Amount fo
Previous Year
Amount for
Current Year
Number for
Previous Year
(d)(e)(f)(g)
Line
No.
5,093,471,949 389,177 383,9925,027,203,909
5,648,670,010
3,101,515,627
29,990,161
5,622,131,528
3,170,394,452
28,637,063
75,605
114
1,237
73,726
118
992
13,873,647,747 ..
1,946,246,652
15,819,894,399
13,848,366,952
2,603,995,368
16,452,362,320
466,133 458,828
N/A N/A
466,133 446,889
. Includes $ 6,002,049 unbiled revenues.
.. Includes 3,265,671 KWH relating to unbiled revenues.
Lines 11 through 21 are on an "allocated" basis,
1
2
3
4
5
6
7
8
9
10
11
12
13
Page 11a
IDAHO SUPPLEMENT
Idaho Power Company
STATE OF IDAHO - ALLOCATED
An Original
1
December 31,2008
IELECTRIC OPERATION AND MAINTENANCE EXPENSES
IIT tne amount Tor previous year iS not oenvea from previousiy repori Tigures, expiain in TootnOteS,
Line
No.Accunt Previous Year
(cJ(a)
1 1, POWER PRODUCTION EXPENSES
L PI, ",ieam 'U"'::I
3 Operation
4 (500) Operation Supervision and Engineering..................... ............... .................................
5 (501) FueL...................................... ........,., ...,...........,......................................................,....
6 (502) Steam Expenses",....... ......, ........., ................... ................. .......,... ............ .....,..,.,' ........
7 (503) Steam from Other Sources........................................ ........................... .....................
8 (Less) (504) Steam Transferred.Cr....................................,........,..,..........".."....,..............,...
9 (505) Elecric Expenses.................,.................,.......................................".............................
10 (506) Miscellaneous Steam Power Expenses.......................................................................
11 (507) Rents.,.,',..................................,.............,',.....,.,."........,...,.".,............,...........................
12 (509) Allowances,....."............................................................................................................
13 TOTAL Operation (Enter Total of lines 4 thru 12)............................................................
14 Maintenance
15 (510) Maintenance Supervision and Engineering..................................................................
16 (511) Maintenance of Strctures.............,',.............. .....................,...................................,....
17 (512) Maintenance of Boiler PlanL.......................................................................................
18 (513) Maintenance of Elecric PlanL....................................................................................
19 (449) Provision for Rate Refunds..........................................................................................
20 TOTAL Maintenance (Enter Total of Lines 15 thru 19)....................................................
21 TOTAL Power Prouction Expenses-Steam Power (Enter Total of lines 13 and 20)....
22 B, Nuclear Power Generation
23 Operation
24 (517) Operation Supervision and Enginering........................... ...........................................
25 (518) Fuel.....,"',.,',.."..".,......,"",....................,"',...,...".,..,"',.."................,.....,.,....................
26 (519) Coolants and Water......,...,............................................,',...........,",.............................
27 (520) Steam Expenses......... ........,',.., ..,..". '" "',................................ ,. ......,....,",....,',..,""'" ".
28 (521) Steam from Other Sourcs... ........ .................. .................................. ........ ....,.. ....,'" .....
29 (Less) (522) Steam Transferred.Cr,......,......,..................................................,......................
30 (523) Electric Expenses............................"..............................................,..................,..........
31 (524) Miscllaneous Nuclear Power Expenses....................................................................,
32 (525) Rents.....................,..,.........,........,..................,......... .........,..............,............................
33 TOTAL Operation (Enter Total of lines 24 thru 32).........................................................
34 Maintenance
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
(528) Maintenance Supervision and Engineering.......................................,......,",..,.............
(529) Maintenance Of Structures.. .............,',......................................................."...."..........
(530) Maintenance of Reactor Plant EquipmenL.................................................................
(531) Maintenance of Electric Plant...........,...........................................................,.............,.
(532) Maintenance of Miscellaneous Nuclear PlanL...........................................................
TOTAL Maintenance (Enter Total of lines 35 thru 39)....................................................
TOTAL Power Producton Expenses-Nuclear Powr (Enter Total of lines 33 and 40).
C. Hydraulic Power Generation
Operation
(535) Operation Supervision and Engineering................ .....................................................
(536) Water for Power,.....,.."..,........,..............., .....,................................................,.............
(537) Hydraulic Expenses" ...,.......................,....................,...........................................,.......
(538) Elec Expenses.."........................................,.....................,.............."..,..................,'
(539) Miscellaneous Hydraulic Power Generation Expenses.......... ....... .......... ...... ........ ......
(540) Ren........,..."......,""',...........,...,..............,.........,..,.,",."."............,.........,...........,.........
TOTAL Operation (Enter Total of lines 44 thru 49)........................................................,
Current Year
(oJ I
$1,572,838 $1,585,144
125,486,116 108,989,376
7,011,862 6,491,790
1,728,050 2,002,446
7,374,383 7,681,857
447,656 281,610
143,620,904 127,032,223
2,447,221 2,456,682
380,003 618,172
13,502,507 13,885,052
4,088,429 5,395,860
4,120,059 5,650,640
24,:i31S,219 28,006,406
168,159,122 155,038,629
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5,338,835
7,010,542
9,510,192
1,250,030
2,946,587
411,625
26,467,811
I4,984,055
4,814,932
9,016,462
1,323,535
2,690,247
399,555 1
Page 12 I
IDAHO SUPPLEMENT I
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Idaho Power Company
STATE OF IDAHO. ALLOCATED
An Original December 31,2008
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ELECTRIC OPERATION AND MAINTENANCE EXPENSES
IT Ine amount Tor previous year is not oeriveo Trom previousiy reportea ngures, expiain in TOOInOteS.
..ii'..
No.Accunt Current Year Previous Year
(a)(D)\c)
51 C.Hydraulic Power Generation (Continued)
52 Maintenance
53 (541) Maintenance Supervision and Engineenng......................,..........................,..................$1.796.685 $1.785.723
54 (542) Maintenance of Structures........,',..............."......,............,...............................................1,298.112 1.220,450
55 (543) Maintenance of Resrvoirs, Dams, and Waterwys.......................................................770.378 515,125
56 (544) Maintenance of Elecric Plant............................,...................................."......"...,..........2.375,483 1,988.155
57 (545) Maintenance of Miscellaneous Hydraulic PlanL...........................................................2.988,642 2.630,881
58 TOTAL Maintenance (Enter Total of lines 53 thru 57)........................................................0. '''v.''''''
59 TOTAL Power Production Expenses-Hydraulic Power (Enter Totl of lines 50 and 58)...::::,öl:f ,111 ::1,::Öl:,11l:
60 D. Oter Power Generation
61 Operation
62 (546) Opration Supervsion and Engineering.........................................................................355,128 325.262
63 (547) FueL................................................................................................................................16,527,579 18,492,527
64 (548) Generation Expenses...".............................,..........................,............... ,..........".............385.160 363.281
65 (549) Miscellaneous Other Power Generation Expses........................................................505.295 442,565
66 (550) Rents...................,.....................................................................,...............,.......................0 -
67 TOTAL Operation (Enter Total of line 62 thru 66).............................................................If,/ f::. 1 ö::
68 Maintenance
69 (551) Maintenance Supervision and Engineering....................................................................203 .
70 (552) Mai,ntenance of Structres...........".................,..........,.,.............................."..............,....154,756 209,865
71 (553) Maintenanc of Generating and Elecric PlanL.............................................................188,740 40,597
72 (554) Maintenance of Miscellaneous Oter Power Generation PlanL...................................485,322 614,836
73 TOTAL Maintenance (Enter Total of lines 69 thru 72)....,......................,....................."...,ls;/!/,u;/l LSÖ::.;/!/LS
74 TOTAL Power Producton Expnses-Oter Power (Enter Total of lines 67 and 73)..........18.6U2.183 2U.48LS,!/34
75 E. Other Power Supply Expenses
76 (555) Purchased Power..................................................................,."........,',............................219,713,102 288,699,422
77 (556) Sysem Control and Load Dispatching............................................................................74,320 73,778
78 (557) Oter Expnses,...,................................................................ ,."......."......................,.......(42,798,888)(112,995.170)
79 TOTAL Oter Power Supply Expenses (Enter Total of lines 76 thru 78)...........................1 fÖ,l:OO,::::4 175,778,030
80 TOTAL Power Producton Expnses (Enter Total of lines 21 , 41 , 59, 74, and 79)............::l:l:,44Ö,i:::U ::O;¿,Öf4, n::
81 2. TRANSMISSION EXPENSES
82 Operation
83 (56) Operatin Supervision and Engineenng...................................... ...................................2,034,871 1,987,843
84 (561) Load Dispatching....................................................................,',.....,................................2,469.165 2,806,393
85 (562) Station Expenses..........."..................,....,...."...................................................................1,532.864 1,491.967
86 (563) Overhead Line Expenses...........,........,....... ,..........................,..".....................................620,324 784,669
87 (56) Underground Une Expenses,..........,....".... ...,...........,.,............,..............,.......................
88 (565) Transmission of Elecicity by Oters..............................................................................6,891.722 9.936,576
89 (56) Miscellaneus Transmission Expenses..........................,...............................................393,825 529.755
90 (567) Rents.................................................................................................................................918,540 990,555
91 TOTAL Operation (Enter Total of lines 83 thru 90).............................................................14.lsö1,::1;/10.::;¿ ,/::o
92 Maintenance
93 (568) Maintenance Supervision and Engineenng...,..................,',.....,',..........."........"...........,365.345 376,412
94 (569) Maintenance of Strctures................,..,.,............,..,........ ....."........,......"...."',...,,...,... .....384.492 387,193
95 (570) Maintenance of Station Equipment..,....,....................................................".....,',.,',........2,297,887 2,473,911
96 (571) Maintenance of Overhead Lines.,.............................. .......,',............,',.............,.,',.........,.2.839.970 1,987.795
97 (572) Maintenance of Underground Lines.........................................,......"..............................
98 (573) Maintenance of Miscellaneous Transmission Plant.......................................................230 2.151
99 TOTAL Maintenance (Enter Total of lines 93 thru 98)........................................................::,lSlSf,!/;/::::,;¿;¿f,4ö;/
100 TOTAL Transmission Expenses (Enter Total of lines 91 and 99)......................................20,749,235 23,/55.22U
101 3.DISTRIBUTION EXPENSES
102 Operation
103 (580) Operation Supervision and Engineering..............................,...............,......,.............,',..,3,110.903 3,141.021
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I Page 13
IDAHO SUPPLEMENT
Idaho Power Company
STATE OF IDAHO - ALLOCATED
An Original
I
Deember 31, 2008
IELECTRIC OPERATION AND MAINTENANCE EXPENSES
If tne amount for previous year is not oenveo from previousiy reporteo rigures, expiain in fOOtnotes.I
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No.Accunt
(a)
1 04 3. DISTRIBUTION EXPENSES (Continued)
105 (581) Load Dispatching..............."......................................,..............................................,....
106 (582) Station Expenses..............................,.................,..........,.......,..................................,...
107 (583) Overhead Line Expenses..................................................,.....,..............................,......
108 (584) Underground Line Expenses........................,..............................................,.............,..
109 (585) Street Lighting and Signal System Expenses.......................................:.......................
110 (586) Meter Expenses.........................,......................,',..........,......................................".......
111 (587) Customer Installations Expenses.........................,..,......................... ...........................
112 (588) Miscellaneous Distribution Expenses,...,.,........................,.......................................,...
113 (589) Rents....................................,.........................................................................................
114 TOTAL Operation (Enter Total of lines 103 thru 113)......................................................
115 Maintenance
116 (590) Maintenance Supervision and Enginering..................................................................
117 (591) Maintenance of Strctures....................,.... ,............,............... ................. ....... ..............
118 (592) Maintenanc of Station EquipmeL................................,..,.,.,.,..................................
119 (593) Maintenanc of Overhead Lines........................................,..,.......................................
120 (594) Maintenance of Undrground Lines..........................,..................................................
121 (595) Maintenance of Line Transformers.....................,.....................................,...................
122 (596) Maintenance of Street Lighting and Signal Systems..........,.......,.................................
123 (597) Maintenance of Meters....................................,",............,.....................,............,',....,...
124 (598) Maintenance of Miscellaneous Distrbuton PlanL......................................................
125 TOTAL Maintenance (Enter Total of lines 116 thru 124).,................,...............................
126 TOTAL Distribution Expenses (Enter Total of line 114 and 125)....................................
127 4. CUSTOMER ACCOUNTS EXPENSES
128 Operation
129 (901) Supervision".................,.,",.,..............,'".."....,....,",...............,..,',...........................,.....
130 (902) Meter Reading Expenses..............................................................................................
131 (903) Customer Records and Collecon Exse...............................................................
132 (904) Uncollectible Accunts.....,.........,",........................,.,""............,....,.,.,...,...".........,.,.....
133 (905) Miscllaneous Customer Accnts Exns..............,........ ............................. .........
134 TOTAL Customer Accounts Expnses (Enter Total of lines 129thru 133)......................
135 5. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
136 Operation
137 (907) Supervision.......... .........,',., .......,.,..... ........ .............. .... ............. ....................... ......... ......
138 (908) Customer Assistance Expenses. .................... ..... ............ ......,.., ,..................,.....".....,"
139 (909) Informational and Instructional Expnses.....................................................................
140 (910) Miscellaneous Customer Service and Informational Expenses..................................
141 TOTAL Cust Service and Informational Expenses (Enter Total of lines 137 thru 140)....
142 6. SALES EXPENSES
143 Operation
144 (911) Supervision........,...,.."..........................................,........................,...,',..., ,...................
145 (912) Demonstrating and sellng Expenses.......................................................................,...
146 (913) Advertising Exnses,..,.................................."..........,.....,........................, .................
147 (916) Miscellaneous sales Expenses...................................................................................
148 TOTAL Sales Expenses (Enter Total of lines 144 thru 147),................. ............ ......,......
149 7. ADMINISTRATIVE AND GENERAL EXPENSES
150 Operation
151 (920) Administrtive and General Saaries",....................,.....................................,..............
152 (921) Offce Supplies and Expenses....... ............ .......................................... ...... .......... .........
153 (Less) (922) Administrative Expenses Transferred-CrediL............. ...................................
"mOUrtTor
Current Year Previous Year
(0)(C)
$2,955,162 $2,906,722
1,083,795 1,066,301
3,088,294 3,172,327
2,000,668 2,085,453
124,298 141,411
4,440,626 4,332,721
1,278,622 1,227,727
5,117,017 5,187,236
427,167 604,482
23,525,553 23,865,402
299,351 246,198
2,202 -
3,349,705 3,322,976
12,697,688 11,557,647
1,214,941 1,328,521
404,868 154,268
631,613 453,194
826,332 888,231
324,644 114,582
19,r01,::0 18,065,618
43,377,897 41,931,U1I1
326,498 435,360
5,428,979 5,146,950
11,328,761 7,866,032
3,524,430 1,876,639
448 320
2U,5U9,115 15,325,300
297,076 299,100
27,459,029 21,710,324
0 0
853,596 876,111
2ti,öu9,ru2 22,885,534
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53,957,955
13,871,196
(21,321,650)
I46,724,352
16,697,245
(26,005,639)IPage 14
IDAHO SUPPLEMENT I
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Idaho Power Company
STATE OF IDAHO. ALLOCATED
An Original December 31, 2008
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
IT tne amount Tor previous year is not aeriveo Trom previousiy reponea riguresi expiain in TOOtnOtes,
I Line
No,Accunt Current Year Previous Year
(a)(0)(C)
154 7. ADMINISTRATIVE AND GENERAL EXPENSES (Continued)
155 (923) Outside Services Employed.......................................................................................$12,751,357 $10,542,564
156 (924) Propert Insurance.....................................................................................................2,899,818 2,957,019
157 (925) Injuries and Damages.... ............................................................................................7,078,580 5,113,519
158 (926) Employee Pensions and Benefits. ..... ...... ............................. ...............,"'" .............,.,...21,419,548 26,159,168
159 (927) Franchise Requirements............"........................................................................-.....1,549 1,200
160 (928) Regulatory Commission Expenses.......... ........ ....."........... ........,....,...........................4,251,098 5,332,170
161 (929) Duplicate Charges-Cr........... ..........,"',...... ........... ...... ................. ......... ..... ....................
162 (930,1) General Advertising Expenses........................ .................. .............,........................222,095 487,897
163 (930.2) Miscellaneous General Expenses"..................,....................,",.....,',.......................3,296,721 3,282,233
164 (931) Rents............,',.....".."..,.................,.,.............,...,.,',.................,"',.....,............,.,...,........6,323 10,731
165 TOiAL Operation (Enter Total of lines 151 thru 164)......................................................~i:,4;;,O~U 91,302,458
166 Maintenance
167 (935) Maintenance of General Plant".....................,....,.................."........................,...........3,843,061 3,498,047
168 TOTAL Admin and General Expenses (Enter Total oflines 165-167).......................1u:',2ff,601 94,800,506
169 TOTAL Elec Op and Maint Ex (Total of 80,100,126,134,141,148,168)......... .......:i 615,070,551 :I 581,372,293
IUAHUUNLT
NUMI:t:K UI" t:Lt:l, I KIl, Ut:t'AK I Mt:N I t:Mt'LUTt:t:~
1. I ne aaia on numoer OT empioyees snouia oe reponea Tor tne payroii penoo enaing nearest to Uctooer ;j1,
or any payroii perioo enaing bU aays oeTore or aner UCooer ;J1.
:.. IT tne responaenrs payroii Tor tne reponing perioo inciuaes any speiai construCtion personnei, inciuae
sucn empioyees on line ;J, ana snow tne numoer OT sucn specai construction empioyees in a TootnOte,
;j. i ne numoer or empioyees assignaoie to tne elecric aepanment rrom Joint Tuncnons OT comoination utiltieS
may oe aeterminea oy estimate, on tne oasis OT empioyee equivaients, ~now tne estlmateo numoer OT equiv-
aient empioyees anriouteo to tne eiectric aepanment Trom Joint runctions.
1 Payroll Period Ended (Date)........................................................................December 31, 2008 Dember 31, 2007
2 Total Regular Full-Time Employees.....2,006 1,968
3 Total Part.Time and Temporary Employees....................................20 29
4 Total Employees..............................2,026 1,997
Page 15
IDAHO SUPPLEMENT