2009Annual Report.pdf

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Form 1.Apved
OMS No. 1902-0021
(Expires 2/29/2009)
Form 1-F Approved
OMS No. 1902-0029
(Expires 2/28/2009)
Form 3-Q Approved
OMS No. 1902-0205
(Expires 2/28/2009)
THIS FILING IS
ltem 1: 00 An Initial (Original)
Submission
OR 0 Resubmission No.
zo m i 9 AM 8: 2 I
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 Energy Regulatory Commission does not
consider these reports to be of confidential nature
Exact Legal Name of Respondent (Company)
Idaho Power Company
YearlPeriod of Report
End of 2009/Q4
FERC FORM No.1/3-Q (REV. 02-04)
Deloitte.Deloitte & Touche LLP
Suite 1700
101 South Capitol Boulevard
Boise, ID 83702-7734
USA
Tel: [phone]
Fax: [phone]
www.deloitte.com
INDEPENDENT AUDITORS' REPORT
Idaho Power Company
Boise, Idaho
We have audited the balance sheet - regulatory basis ofIdaho Power Company (the "Company") as of
December 31, 2009, and the related statements of income - regulatory basis; retaned earnings -
regulatory basis; cash flows - regulatory basis, and accumulated other comprehensive income,
comprehensive income, and hedging activities - regulatory basis, for the year ended December 31, 2009,
included on pages 110 through 123 ofthe accompanying Federal Energy Regulatory Commission Form 1.
These financial statements are the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with auditing standards generally accepted in the United States of
America. Those standards require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit includes consideration of
internal control over financial reporting as a basis for designing audit procedures that are appropriate in
the circumstances, but not for the purose of expressing an opinion on the effectiveness of the Company's
internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes
examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our audit provides a reasonable
basis for our opinion.
As discussed in Note 1, these financial statements were prepared in accordance with the accounting
requirements of the Federal Energy Regulatory Commssion as set forth in its applicable Uniform System
of Accounts and published accounting releases, which is a comprehensive basis of accounting other than
accounting principles generally accepted in the United States of America.
In our opinion, such regulatory-basis financial statements present fairly, in all material respects, the
assets, liabilities, and proprietary capital of the Company as of December 31, 2009, and the results of its
operations and its cash flows for the year ended December 31, 2009, in accordance with the accounting
requirements of the Federal Energy Regulatory Commission as set forth in its applicable Uniform System
of Accounts and published accounting releases.
This report is intended solely for the information and use of the board of directors and management of the
Company and for filing with the Federal Energy Regulatory Commission and is not intended to be and
should not be used by anyone other than these specified parties.
/J ~ ~ L L"I
February 23, 2010
Member of
Deloitte Touche Tohmatsu
..
IDENTIFICATION
01 Exact Legal Name of Respondent 02 Year/Period of Report
Idaho Power Company End of 2009/04
03 Previous Name and Date of Change (if name changed during year)/ /
04 Address of Principal Offce 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 Exec 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) IX An Original (2) 0 A Resubmission (Mo,Da, Yr)
[phone] 04/1212010
ANNUAL CORPORATE OFFICER CERTIFICATION
The undersigned offcer certifies that:
I have examined this report and to the best of my knowledge, information, and belief all statements of fact contained in this report are corrct statements
of the business affirs of the respondent and the financial statements, and other financial information contained in this report, conform in all material
repect to the Uniform System of Accunts.
01 Name 03 Signature 04 Date Signed
Darrel Anderson (Mo,Da, Yr)
02 Title
Executive VP of Admin Ser & CFO Darrel Anderson 04/1212010
Title 18, U.S.C. 1001 makes it a crme for any person to knowingly and willngly to make to any Agency or Departent ofthe United States any
false, fictitious or fraudulent statements as to any matter within its jurisdiction.
FERC FORM NO. 1/3-Q:
REPORT OF MAJOR ELECTRIC UTILITIES LICENSEES AND OTHER
FERC FORM No.1/3-Q (REV. 02-04)Page 1
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idao Power Company (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) ri A Resubmission 041212010
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 Corprations Controlled by Respondent 103
4 Ofcers 104
5 Directors 105
6 Information on Formula Rates 106(a)(b)
7 Importt Changes During the Year 108-109
8 Comparative Balance Sheet 110.113
9 Statement of Income for the Year 114-117
10 Statement of Retaned Eamings for th Year 118.119
11 Statement of Cash Flows 120-121
12 Notes to Financial Statements 122-123
13 Statement of Accum Comp Income, Comp Income, and Hedging Actvities 122(a)(b)
14 Summary of Utilty Plant & Accumulated Provision for Dep, Amort & Dep 200201
15 Nuclear Fuel Materials 202-203 None
16 Electric Plant in Service 204207
17 Electric Plant Leased to Oters 213 None
18 Electric Plant Held for Future Use 214
19 Construction Work in Progress-Electric 216
20 Accumulated Provision for Depreciation of Elecric Utilit Plant 219
21 Investment of Subsidiary Companies 224-225
22 Materials and Supplies 227
23 Allowances 228(ab)-229(ab)None
24 Extraordinary Propert Losses 230
25 Unrecovered Plant and Regulatory Study Costs 230
26 Transmission Servce and Generation Interconnection Study Costs 231 None
27 Oter Regulatory Assets 232
28 Miscellaneous Deferred Debits 233
29 Accumulated Deferred Income Taxes 234
30 Capta Stock 250-251
31 Other Paid-in Capital 253
32 Captal Stock Expense 254
33 Long- Term Debt 256-257
34 Reconcilation of Reported Net Income with Taxble Inc for Fed Inc Tax 261
35 Taxes Accrued, Prepaid and Charged During the Year 262-263
36 Accumulated Deferred Investment Tax Credits 266-267
FERC FORM NO.1 (ED. 12-96)Page 2
Name of Respondent This i!0rt Is:Date of Report YearWenOO Of Heport
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) n A Resubmission 04/1212010
LI sT OF SCHEDULES (Electric Utilty) (continued)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Line Title of Schedule Reference Remarks
No.Page No.
(a)(b)(c)
37 Other Deferred Credits 269
38 Accumulated Deferred Income Taxes-Accelerated Amortization Propert 272-273
39 Accumulated Deferred Income Taxes-Oher Propert 274-275
40 Accumulated Deferred Income Taxes-Other 276-277
41 Other Regulatory Liabilities 278
42 Electric Operating Revenues 300301
43 Sales of Electricity by Rate Schedules 304
44 Sales for Resale 310-311
45 Electric Operation and Mantenance Expenses 320-323
46 Purchased Power 326-327
47 Transmission of Electricit for Others 328-330
48 Trasmission of Electricity by ISOIRTOs 331 None
49 Transmission of Electricity by Others 332
50 Miscellaneous General Expenses-Electric 335
51 Depreciation and Amortization of Electric Plant 336-337
52 Regulatory Commission Expenses 350-351
53 Research, Development and Demonstration Actvities 352-353
54 Distributon of Salarés and Wages 354-355
55 Common Utilty Plant and Expenses 356 None
56 Amounts included in ISOIRTO Settement Statements 397 None
57 Purchase and Sale of Ancilary Services 398 None
58 Monthly Transmission System Peak Load 400
59 Monthly ISOIATO Transmission System Peak Load 400a None
60 Electric Energy Account 401
61 Monthly Peaks and Output 401
62 Steam Electric Generating Plant Statistics 402-403
63 Hydroelectric Generating Plant Statistics 406-407
64 Pumped Storage Generating Plant Statistics 408-409 None
65 Generating Plant Statistics Pages 410-411
66 Transmission Line Statistics Pages 422-423
FERC FORM NO.1 (ED. 12-96)Page 3
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2009/Q4
This ~rt Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) DA Resubmission 041212010
LI T OF SCHEDULES (Electric Utilty) (continued)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Une
No.
Title of Schedule Reference
Page No.
(b)
424.425
426-427
429
45
Remarks
(a)
67 Tranmission Unes Added During the Year
68 Substatins
69 Transactons with Associated (Affliated) Compaies
70 Footnote Data
Stockholders' Reports Check appropriate box:
rgTWO copies will be submitted
o No annual report to stockhoders is prepare
(c)
FERC FORM NO.1 (ED. 12-96)Page 4
Name of Respondent
Idaho Power Company
This Report Is:
(1) IX An Original
(2) 0 A Resubmission
Date of Report
(Mo, Da, Yr)
04/1212010
Year/Period of Report
End of 2009/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.
Darrel Anderson Executive Vice President of Adnistrative Services and CFO, Idao Power Couiany
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.
Idaho, 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 Aplicable
4. State the classes or utilty and other services furnished by respondent during the year in each State in which
the respondent operated.
Class of utility SericeElectric
"
State
Idao
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) 00 No
FERC FORM NO.1 (ED. 12-87)PAGE 101
Name of Respondent
Idaho Power Company
This Report Is:
(1 ) IX An Original
(2) 0 A Resubmission
Date of Report
(Mo, Da, Yr)
04121010
Year/Period of Report
End of 2oo9/Q4
CONTROL OVER RESPONDENT
1. If any corporation, business trust, or similar organization or a combination of such organizations jointly held
control over the repondent at the end of the year, state name of contlling 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.
Idaho Power Company is a subsidiary of IDACORP, INC
IDACORP owns 100% of Idaho Power Company's Commo Stoc.
IDACORP is a public utilty Holding Company incorpraed eff 10-1-1998
FERC FORM NO.1 (ED. 12-96)Page 102
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company
(1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) DA Resubmission 04112/2010
C JRPORA TIONS CONTROLLED BY R SPONDENT
1. Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent
at any time during the year. If control ceased prior to end of year, give particulars (details) in a footnote.
2. If control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, naming
any intermediaries involved.
3. If control was held jointly with one or more other interests, state the fact in a fotnote and name the other interests.
Definitions
1. See the Uniform System of Accunts for a definition of control.
2. Direc 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 effecively control or direc action without the consent of the other, as where the
voting control is equally divided between two holders, or each part holds a veto power over the other. Joint control may exist by
mutual agreement or understanding between two or more parties who together have control within the meaning of the definition of
control in the Uniform System of Accounts, regardless of the relative voting rights of each party.
Line Name of Company Controlled Kind of Business Percent Voting Footnote
No.Stock Owned Ref.
(a)(b)(c)(d)
1 Direct Control
2 Idaho Energy Resources Company Coal mining and mineral 100%
3 development
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
FERC FORM NO.1 (ED. 12-96)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 2009/Q4
(2) nA Resubmission 04/121010
OFFICERS
1. Report below the name, title and salary for each exective offcer whose salary is $50,00 or more. An "execve offcet' of a
respondent indudes 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 pernns similar policy making functons.
2. If a change was made during the year in the incumbent of any position, show name and total reunertion of the previous
incumbent, and the date the change in incumbency was made.
I Line ntie -Name of Offcer .~a~ary
No.(a)
forè;ear
(b)c)
1
2 President and Chief Executive Offcer J. LaMont Keen 600,000
3
4 Executive VP, Administratie services & CFO(4)Darrl T. Anderson 340,000
5
6 Sr Vice President, Power Supply (1)James C. Miller 215,000
7
8 Sr Vice President, General Counsel and Secretary (3)Thomas Saldin 89,000
9
10 Executive Vice President, Operations (4)Dan Minor 340,000
11
12 Vic President, Regulatory Affirs Ric Gale 230,000
13
14 Vice President and Chief Information Ofcer Dennis Gribble 198,000
15
16 Vice President, Human Resources Luci McDonald 205,000
17
18 Vice President and Treasurer Steven R. Keen 215,000
19
20 Senior Vice President, General Counsel (2)Rex Blackbum 215,000
21
22 Vic President and Chief Risk Offcer Lori Smith 194,00
23
24 Senior Vice President, Power Supply (4)Lis Grow 220,000
25
26 Vice President Public Affirs Jeffrey Malmen 180,000
27
28 Vice President, Customer Service and Regional Ops Warrn Kline 177,500
29
30 Vice President Engineering & Operations (4)Vem Porter 175,000
31
32 Vice President, Audit and Compliance Naomi Crafton-5hankel 154,000
33
34 Corporate Secretary Patri Harrington 155,000
35
36
37 (1) Retired 813112009
38 (2) Appointed Senior VP, General Counsel 4/1/09
39 (3) Retired 3131109
40 (4) Effctive 10/1/09
41
42
43
44
FERC FORM NO.1 (ED. 12-96)Page 104
Name of Respondent This i!0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) riA Resubmission 04/1212010
DIRECTORS
1. Rep below the information callec for conceming each direcor of the respondent who held offce at any time during the year. Include in column (a), abbreviated
title of the direcors who are offcers of the respondent.
2. Designate members of the Executive Committee by a triple asterisk and the Chairman of the Executive Commitee by a double asterisk.
ILÑ~.Name (ançi.l itie) of Director ..nncipal BuSiness Address
(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 Stephen Allred 4642 W Dawson Dr Meridian, Id 83646
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, Portand, Oregon 97201
22
23 Robert A. Tinstman ***4433 W. Quail 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
28
29
30
31
32
33
34
35
36
37
38
39
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FERC FORM NO.1 (ED. 12-95)Page 105
Name of Respondent Date of Report
---~.
This (lrt Is:Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2009/04
(2) ri A Resubmission 0411212010
INFORMATION ON FORMULA RA ES
FERC Rate ScheduleIarff Number FERC Proeeding
Does the respondent have formula rates?~ Yes
o No
1. Please list the Commission accepted formula rates including FERC Rate Schedule or Tariff Number and FERC proceeding (i.e. Docket No)
accepting the rate(s) or changes in the accepted rate.
I Line
No.FERC Rate Schedule or Tariff Number FERC Proeeing
1 FERC Electric Tariff First revised Volumne NO.6 FERC Docket No. ER06-787-002,003
2
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FERC FORM NO.1 (NEW. 12..S)Page 106
Name of Respondent This~rtIS:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo. Da, Yr)End of 2009/Q4
(2) Fi A Resubmission 04/1212010
INFORMATION ON FORMULA RATES
FERC Rate SchedulefTariff Number FERC Proceeding
Does the respondent fie with the Commission annual (or more frequent)(2 Yesfilings containing the inputs to the formula rate(s)?
D No
2. If yes, provide a listing of such filngs as contaned on the Commission's eUbrary website
Formula Rate FERC Rate
Line Doument Date Schedule Number or
No.Accession No.\ Filed Date Docket No. Description Tariff Number
1 2009082-5128 08/28/2009 ER09-1641-000 Idaho Power Company's FERC Electric Tariff
2 2009-2010 Annual first revised Volumne
3 informational filng
4 under ER09-1641
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FERC FORM NO.1 (NEW. 12-8)Page 106a
This Page Intentionally Left Blank
Name of Respondent This mort Is:Date of Report YeadPeriod of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) n A Resubmission 04/1212010
INFORMATION ON FORMULA RATES
Formula Rate Variances
1. If a respondent does not submit such filings then indicate in a footnote to the applicable Form 1 schedule where formula rate inputs differ from
amounts reported in the Form 1.
2. The footnote should provide a narrative description explaining how the "rate' (or billing) was derived if diferent from the reprted amount in the
Form 1.
3. The footnote should explain amounts excluded from the ratebase or where labor or other allocation factors. operating expenses, or other items
impacting formula rate inputs differ from amounts reported in Form 1 schedule amounts.
4. Where the Commission has provided guidance on formula rate input. the specific proceeding should be noted in the footnote.
Line
No.Page No(s).Schedule Column Line No
1 N/A
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FERC FORM NO.1 (N~W. 12-0)Page 106
Name of Respondent
Idaho Power Company
Date of Report Year/Period of Report
End of 2oo9/Q4
This Report Is:
(1) ~ An Original
(2) 0 A Resubmission
1M ORrANT CHANGES DURING THE QUARTERIEAR
Give particulars (details) concerning the matters indicaed below. Make the statements explicit and precise, and number them in
accrdance 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 frnchise rights: Descbe 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 descrption 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 Accunts
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 distbuon system: State terrory added or relinquished and date operations
began or ceased and give reference to Commission authoriation, if any was reuired. State also the approximate number of
customers added or lost and approximate annual revenues of each dass of service. Each natural gas company must also state major
new continuing sources of gas made available to it from purcases, development, purchase contract or otherwise, giving location and
approximate total gas volumes available, period of contracts, and other parties to any such arrangements, etc.
6. Obligations incurred as a result of issuance of securities or assumption of liabilties or guarantees including issuance of short-term
debt and commercial paper having a maturity of one year or less. Give reference to FERC or State Commission authorization, as
appropriate, and the amount of obligation or guarantee.
7. Changes in articles of incorporation or amendments to charter: Explain the nature and purpse of such changes or amendments.
8. State the estimated annual effect and nature of any important wage scle changes during the year.
9. State briefly the status of any materially important legal predings pending at the end of the year, and the results of any such
procedings culminated during the year.
10. Describe briefly any materially importnt transactions of the respondent not discled elseere in this report in which an offcer,
director, security holder reported on Page 106, voting trustee, assoced company or known associate of any of these persons was a
part or in which any such person had a material interest.
11. (Reserved.)
12. If the important changes during the year relating to the respondent company appearing in the annual report to stockholders are
applicable in every respect and furnish the data required by Instructions 1 to 11 above, such notes may be included on this page.
13. Describe fully any changes in offcers, directors, major security holders and voting powers of the respondent that may have
occrred during the reporting period.
14. In the event that the respondent partcipates in a cash management program(s) and its proprietary capital ratio is less than 30
percent please describe the signifcant 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 affliated companies through a
cash management program(s). Additionally, please descrbe plans, if any to regain at least a 30 percent proprietary ratio.
04/1212010
PAGE 108 INTENTIONALLY LEFT BLANK
SEE PAGE 109 FOR REQUIRED INFORMATION.
FERC FORM NO.1 (ED. 12-96)Page 108
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/1212010 2009/Q4
IMPORTANT CHANGES DURING THE QUARTERIEAR (Continued)
1. Reclassified Non-AMI meters to allow accelerated recovery:
Idaho $ 41,108,626 over 36 monthsOregon 2,063,431 over 18 months
New station ènergized 2009 - Hubbard station 230 Kv switching station - Ada County
2. None
3. None
4. None
5. Addition to existing lines:
Line 446 Pingree to Haven 138Kv 0.8 miles of new double circuit.
Line 446 Pingree to Haven 138Kv converted 10.9 miles of line from 46Kv to 138Kv.
Line 525 Don - Hoku 138Kv buile 2.97 miles single circuit 138Kv.
Line 525 Hoku - Alameda 138kv built 3.4 miles of single circuit.
Line 723 Danskin - Hubbard 230Kv built 39.46 miles of single circuit 230Kv.
6. On March 30, 2009 IPC issued $100 millon of its 6.15% First Mortgage Bonds due April
1, 2019. Commission Authorization OPUC #4244 and IPUC IPC-E-07-19.
On November 20, 2009 IPC issued $130 million of its 4.50% First Mortgage Bonds due
March 1, 2020. Commission Authorization OPUC #4244 and IPUC IPC-E-07-19.
7. None
8. Effective 12/27/08 a 3.0% general wage increase was approved.
9. See pages 123.18 to 123.22
10. None
11. None
12. None
13. Refer to pages 104 & 105 for changes in officers and directors. There were a numbèr of
changes in the major security holders in 2009. The top ten institutional shareholders list
saw 4 changes from 3rd quarter to 4th quarter. In the 4th quarter First Eagle Investment
Management, Blackrock Institutional Trust Company, Northern Trust Investments and Fisher
investments replaced Arnhold & S. Bleichroeder Advisors LLC, Barclays Global Investors,
AllianceBernstein L. P. and TIAA-CREF.
14. Idaho Power and its unregulated parent, IdaCorp have seperate cash management
programs. (Seperate bank accounts, liquidity facilities, short-term debt and investment
programs). No money has been loaned or advanced from Idaho Power to IdaCorp through a cash
management program.
IFERC FORM NO.1 (ED. 12-96) Page 109.1
This Report Is: Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
(2) 0 A Resubmission 04/1212010 End of 2009/04
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Name of Respondent
Idaho Power Company
Line
No.Title of Accunt
(a)
UTILITY PLANT
Ref.
Page No.
(b)
Current Year
End of OuarterNear
Balance
(c)
Prior Year
End Balance
12/31
(d)
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
1,335,96
- --- - ~ ------ -- -- -
o
65,015,441
786,896
o
o
60,058,187-- ----- ----- --- ----
o
266,768
o
o
94,473
o
o
o
19,129,856
o
o
o
80,923,412-- --- ---- ~- --~ -----
o
43,342,060
o
o
o
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
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
Utilit Plant (101-106, 114)
Construction Work in Progress (107)
TOTAL Utilit Plant (Enter Total of lines 2 and 3)
(Less) Aceum. Provo for Depr. Amort. Depl. (108, 110, 111, 115)
Net Utility Plant (Enter Total of line 4 less 5)
Nuclear Fuel in Process of Ref., Conv.,Enrich., and Fab. (120.1)
Nuclar Fuel Materials and Assemblies-Stock Accunt (120.2)
Nuclear Fuel Assemblies in Reactor (120.3)
Spent Nuclear Fuel (120.4)
Nuclear Fuel Under Capital Leases (120.6)
(Less) Aceum. Provo for Amort. of Nucl. Fuel Assemblies (120.5)
Net Nuclear Fuel (Enter Total of lines 7-11 less 12)
Net Utilty Plant (Enter Total of lines 6 and 13)
Utilty Plant Adjustments (116)
Gas Stored Underground - Noncurrent (117)
OTHER PROPERTY AND INVESTMENTS
Nonutility Propert (121)
(Less) Aceum. Provo for Depr. and Amort. (122)
Investmnts in Associated Companies (123)
Investment in Subsidiary Companies (123.1)
(For Cost of Account 123.1, See Footnote Page 224, line 42)
Noncurrent Portion of Allowances
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 Porton of Deriative Assets (175)
Long-Term Porton of Derivative Assets - Hedges (176)
TOTAL Other Propert and Investmnts (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 Accunts Receivable (142)
Other Accounts Receivable (143)
(Less) Aceum. Provo for Uncollectible Acc.-Credit (144)
Notes Receivable frm Associated Companies (145)
Accunts Receivable from Assoc. Companies (146)
Fuel Stock (151)
Fuel Stock Expenses Undistribute (152)
Residuals (Elec) and Extracted Products (153)
Plant Materials and Operating Supplies (154)
Merchandise (155)
Oter Materials and Supplies (156)
Nuclear Materials Held for Sale (157)
Allowances (158.1 and 158.2)
200-201
200201
200-201
202-203
202-203
224-225
228-229
227
227
227
227
227
227
202-203/227
228-229
FERC FORM NO.1 (REV. 12-03)Page 110
Name of Respondent
Idaho Power Company
Line
No.Ref.
Page No.
(b)
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)
Miscllaneous Current and Accued 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 Acced 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 Deferrd Debits (186)
Def. Losses from Disposition of Utilit Pit. (187)
Research, Devel. and Demonstration Expend. (188)
Unamortized Loss on Reaquired Debt (189)
Accmulated Deferred Income Taxes (190)
Unrecovered Purchased Gas Costs (191)
Total Deferre Debits (lines 69 through 83)
TOTAL ASSETS (lines 14-16, 32,67, and 84)
234
Year/Period of Report
262,96,07
2009/04
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-- ~---- - ~- ~_---- - -
58,492,87
15,439,92
170,110,97
This Report Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) 0 A Resubmission 04/1212010 End of
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)Continued)
Current Year
End of OuarterlYear
Balance
(c)
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
227
230a
230b
232
233
352-353
14,263,910
o
o
697,64,724
7,232,442
o
o
486,154
o
63,059,804
o
o
12,841,023
167,646,855
o
963,174,912
4,005,728,535
FERC FORM NO.1 (REV. 12-G3)Page 111
Name of Respondent This Report is:Date of Report Year/Period of Report
Idaho Power Company (1 )~An Original (mo, da, yr)
(2)0 A Resubmission 04/1212010 end of 2009/04
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
Line Current Year Prior Year
No.Ref.End of QuarterlY ear End Balance
Title of Account Page No.Balance 12131
(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)0 0
5 Stock liabilty for Conversion (203, 206)0 0
6 Premium on Capita Stock (207)638,757,43 618,757,435
7 Other Paid-In Capital (208-211)253 0 0
8 Installments Received on Capital Stoc (212)252 0 0
9 (less) Discount on Capital Stock (213)254 0 °
10 (less) capital Stock Expense (214)254b 2,096,925 2,096,925
11 Retained Eamings (215, 215.1, 216)118-119 485,143,115 424,451,953
12 Unappropriated Undistributed Subsidiary Eamings (216.1)118-119 62,552,348 57,595,094
13 (less) Reaquired Caital Stock (217)250-251 0 0
14 Noncorprate Proprietorship (Non-major only) (218)0 0
15 Accumulated Oter Comprehensive Income (219)122(a)(b)-8,266,66:-8,706,615
16 Total Proprietary capital (lines 2 through 15)1,273,966,340 1,187,877,972
17 lONG-TERM DEBT
18 Bonds (221)256-257 1,385,460,00 1 ,401,560,000
19 (less) Reaquired Bonds (222)256-257 C 166,100,000
20 Advances from Associated Compaies (223)256-257 C 0
21 Oter long-Term Debt (224)256-257 28,394,091 29,457,727
22 Unamortzed Premium on long-Term Debt (225)(°
23 (less) Unamortized Discount on long-Term Debt-Debit (226)3,060,74E 3,163,279
24 Tota long-Term Debt (lines 18 through 23)1,410,793,343 1,261,754,44
25 OTHER NONCURRENT LIABILITIES
26 Obligations Under Capital leases - Noncurrent (227)0 °
27 Accumulated Provision for Propert Insurance (228.1)0 0
28 Accumulated Provision for Injuries and Damages (228.2)3,412,806 1,965,108
29 Accumulated Provision for Pensions and Benefi (228.3)279,806,510 253,645,884
30 Accumulated Miscellaneous Operating Provisions (228.4)916,667 916,667
31 Accumulated Provision for Rate Refunds (229)9,894,071 13,34,853
32 long-Term Porton of Derivative Instrument Liabilties 0 0
33 long-Term Portion of Derivative Instrument Liabilties - Hedges 0 0
34 Asset Retirement Obligations (230)16,239,594 12,414,695
35 Total Oter Noncurrent liablities (lines 26 through 34)310,269,654 282,287,207
36 CURRENT AND ACCRUED LIABILITIES
37 Notes Payabe (231)0 112,850,000
38 Accounts Payable (232)81,164,595 94,937,929
39 Notes Payable to Associated Companies (233)0 0
40 Accounts Payable to Associated Companies (234)1,735,649 765,831
41 Custoer Depoits (235)464,233 311,092
42 Taxes Accrued (236)262-263 -3,253,921 -42,412,65
43 Interest Accrued (237)20,383,712 16,674,614
44 Dividends Declared (238)C 0
45 Matured long-Term Debt (239)(0
FERC FORM NO.1 (rev. 12-03) Page 112
Name of Respondent This Report is:Date of Report Year/Period of Report
Idao Power Company (1 )~An Original (mo, da, yr)
(2)0 A Resubmission 04/12/2010 end of 2009/04
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITß)ntinued)
Line Current Year Prior Year
No.Ref.End of OuarterlYear End Balance
Title of Account Page No. Balance 12/31
(a)(b)(c)(d)
46 Matured Interest (240)C 0
47 Tax Collections Payable (241)1,963,189 1,329,837
48 Miscellaneous Current and Accrued Liabilties (242)29,912,569 37,600,238
49 Obligations Under Capital Leases-Current (243)C 0
50 Derivative Instrument Liabilties (244)280,459 2,652,850
51 (Less) Long-Term Portion of Derivative Instrument Liabilities C 0
52 Derivative Instrument Liabilties - Hedges (245)0 0
53 (Less) Long-Term Portion of Derivative Instrument Liabilties-Hedges 0 0
54 Tota Current and Accrued Liabilities (lines 37 through 53)132,650,479 224,709,741
55 DEFERRED CREDITS
56 Customer Advances for Construction (252)25,180,998 30,033,657
57 Accumulated Deferred Investment Tax Credits (255)266-267 73,505,525 73,270,077
58 Deferred Gains from Disposition of Utilty Plant (256)0 0
59 Oter Deferred Credits (253)269 19,363,271 29,939,135
60 Other Regulatory Liabilties (254)278 49,478,079 203,648,107
61 Unamortzed Gain on Reaquired Debt (257)C 0
62 Accum. Deferred Income Taxes-Accel. Amort.(281)272-277 0 0
63 Accum. Deferred Income Taxes-Other Propert (282)664,169,740 580,306,037
64 Accum. Deferred Income Taxes-oher (283)109,412,363 131,902,154
65 Tota Deferred Credits (lines 56 through 64)941,109,976 1,049,099,167
66 TOTAL LIABILITIES AND STOCKHOLDER EOUITY (lines 16, 24, 35, 54 and 65)4,068,789,79'l 4,005,728,535
FERC FORM NO.1 (rev. 12-03)Page 113
Name of Respondent This ~ort Is:Date of Report YeaúPeriod of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) DA Resubmission 041212010
STATEMENT OF INCOME
Quarterly
1. Report in column (c) the currnt year to date balance. Column (c) equals the total of adding the data in column (g) plus the data in column (i) plus the
data in column (k). Report in column (d) similar data for the previous year. This informtin is reported in the annual filing only.
2. Enter in column (e) the balance for the reporting quarter and in column (f) the balance for the same thre month perid for the prior year.
3. Report in column (g) the quarter to date amounts for elect utlit functon; in column (i) the quartr to date amounts for gas utilit, and in column (k)
the quarter to date amounts for other utility functon for the currnt year quarter.
4. Report in column (h) the quarter to date amounts for electric utilit functon; in column u) the quarter to date amounts for gas utilty, and in column (I)
the quarter to date amounts for other utility function for the prior year quarter.
5. 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 fr Utilit Plant Leased to Oters, in another utilit columnin a similar manner to
a utility departent. Spread the amount(s) over lines 2 thru 26 as appropriate. Includ these amounts in columns (c) and (d) totals.
7. Report amounts in account 414, Other Utilty Operating Income, in the same manner as accunts 412 and 413 above.
Line Total Totl Currt 3 Months Poor 3 Months
No.Curr Yea to Pri Year to Ende Ended
(Ref.)Dat Banc fo Dat Banc for Quarterl Only Quart Only
Title of Account Page No.Qui1rNear Quai1rNear No 4th Quarter No 4th Quart
(a)(b)(c)(d)(e)(~
1 UTILITY OPERATING INCOME
2 Opeting Revenue (400)30-301 1,045,996,381 956,075,56
3 Operaing Expenses
4 Opetion Expense (401)320-323 638,94,792 581,17,704
5 Maintenance Expese (402)3223 69,45,827 68,638,630
6 Depreiatio Expense (403)337 103,587,447 96,637,583
7 Depreti Expense for Asset Retirent Cosls (403.1)336-7
8 Amort. & Dept. of Utilit Plant (404-405)336-337 7,061,06 5,482,388
9 Amort of Utlit Plat Acq. Adj. (406)33337 -22,723 -22,723
10 Amort. Propert Losse, Unre Plant and Regulat Stuy Co (407)
11 Amort. of Conversio Expense (407)
12 Regultory Debit (407.3)
13 (Les) Regulatory Creit (407.4)3,781,013
14 Taxes Oter Than Incme Taxes (408.1)262-263 21,069,235 19,083,954
15 Income Taxes - Federal (409.1)262-26 15,555,36 -1,816,783
16 - Oter (409.1)262-26 1,547,326 -4,930,646
17 Provision for Deferr Incoe Taxes (410.1)23,'0.m 76,729,161 111,854,164
18 (Les) Proision for Defer Income Taxes-Cr. (411.1)234,'0.m 63,176,136 71,534,676
19 Investt Tax Credit Adj. - Net (411.4)26 235,447 2,269,367
20 (Les) Gains frm Disp. of Utilit Plant (411.6)11,632
21 Losses from Disp. of Utilit Plant (411.)
22 (Less) Gains fr Dispositon of Allowance (411.8)297,616 504,115
23 Loses frm Dispoti of Allowance (411.9)
24 Accretion Expense (411.10)
25 TOTAL Utity Operati Expenses (Enter Total of lines 4 thru 24)870,694,192 802,542,202
26 Net Util Oper Inc (Enter Tot line 2 le 25) Carr to Pg117,line 27 175,302,189 153,533,362
FERC FORM NO. 1/3-0 (REV. 02-04)Page 114
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/1212010
STATEMENT OF INCOME FOR THE YEAR (Continued)
9. Use page 122 for important notes regarding the statement of income for any accunt thereof.
10. Give concise explanations conceming unsettled rate proceedings where a contingency exists such that refunds of a material amount may nee to be
made to the utility's customers or which may result in material refund to the utility wit 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 affct the rights
of the utilit to retain such revenues or recver amounts paid with respect to power or gas purchases.
11 Give concise explanations conceming signifcant amounts of any refunds made or received during the year resulting from settlement of any rate
proceeding affcting revenues received or costs incurred for power or gas purches, and a summary of the adjustments made to balance sheet, income,
and expense accunts.
12. If any notes appearing in the report to stokholders are applicable to the Statement of Income, such notes may be included at page 122.
13. Enter on page 122 a concise explanation of only those changes in accunting methods made during the year which had an effec on net income,
including the basis of allocations and apportionments frm those used in the preceing year. Also, give the appropriate dollar effect of such changes.
14. Explain in a footnote if the previous year's/quarter's figures are diffrent from that reported in prior report.
15. If the columns are insuffcient for reporting additional utilit departnts, supply the appropriate accunt titles report the information in a footnote to
this schedule.
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2009/Q4
ELECTRIC UTILITY
Current Year to Date Previous Year to Date
(in dollars) (in dollars)(g) (h)
GAS UTILIT
Current Year to Date Previous Year to Date
(in dollars) (in dollars)(i) 0)
Line
No.
297,616 504,115
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
638,946,792
69,458,827
103,587,447
581,177,704
68,638,630
96,637,583
7,061,068
-22,723
5,482,388
-22,723
21,069,235
15,555,364
1,547,326
76,729,161
63,176,136
235,447
3,781,013
19,083,954
-1,816,783
-4,930,646
111,854,164
71,534,676
2,269,367
11,632
870,694,192
175,302,189
802,542,202
153,533,362
FERC FORM NO.1 (ED. 12-96)Page 115
Name of Respondent
Idaho Power Company
Line
No.
Title of Accunt
(a)
This ~ort Is: bate of Report
(1) ~An Original (Mo, Oa, Yr)
(2) A Resubmission 041121010
MENT OF INCOME FOR THE YEAR (continued)
TOTAL
(Ref.)
Page No.
(b)
119
262-263
262-26
262-26
234, 272-27
234, 272-27
262-263
YearlPeriod of Report
End of 2009/Q4
Previous Year
(d)
no nt
Ended
Quart Only
No 4th Qu
(ij
- --- ------ -- -- -- ---- ~--- -- - -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
3,051.50
16,714,305
3,973
- -- - - - - - -- - - --- ---- ---- - -
405,90
-381,00
426,409
1,273,313
4,817,233
6,541,855
31.465
3,078,590
615,804
1,203,011
4,822,172
1,716,723
19,189,109~----~--~-~--~---~-106,698
10,065,752
----- ---- -- - ---- -- --- ---- --
73,269,850
1,225,978
n6,937
2,057,420
5,397,871
71,932,314
122,558,984
66,145,498
1,099,817
707,798
8,611,213
7,080,140
69,484,186
94,114,928~---~----~----
122,558,984
FERC FORM NO. 1/3.Q (REV. 02-()
94,114,928
27 Net Utlit Opting Income (Carr nar frm pae 114)
28 Oter Incme and Deductons
29 Oter Incme
30 Nonutlty Operating Income
31 Revenues Fro Merchandising, Jobbing and Cotrct Wor (415)
32 (Less) Costs and Exp. of Mercandising, Job. & Contrct Wor (416)
33 Revenue From Nonutilit Opraions (417)
34 (Les) Expens of Nonutilit Operatis (417.1)
35 Nonopeting Rental Income (418)
36 Equit .in Earnings of Subsidiary Companies (418.1)
37 Intert and Dividnd Income (419)
38 Allo for Ot Funds Used Dunng Constn (419.1)
39 MiceDaneous Nonoperating Inco (421)
40 Gain on Dispoitin of Prpe (421.1)
41 TOTAL Ot Inc (Enter Total of lines 31 thru 40)
42 Otr Incoe Deducns
43 Loss on Dispoitin of Propert (421.2)
44 Misclaneous Amortzation (425)
45 Donatins (426.1)
46 Lif Insurance (426.2)
47 Penalt (426.3)
48 Exp. for Certin Civic, Politcal & Relate Actities (426.4)
49 Oter Deuctns (426.5)
50 TOTAL Oter inc Deuctns (Total of line 43 thru 49)
51 Taxes Applic. to Oter Incme and Deuctns
52 Taxes Oter Than Income Taxes (40.2)
53 Income Taxes-Fedral (409.2)
54 Inco Taxes-Otr (409.2)
55 Provision fo Derr Inc. Taxes (410.2)
56 (Less) Proion for Defer Income TaxesCr. (411.2)
57 InvesentTax Creit Adj.-Net (411.5)
58 (Less) Invesent Tax Creits (420)
59 TOTAL Taxes on Other Income and Deuctns (Total of lines 52-58)
60 Net Oter Income and Deuctons (Total of lines 41,50,59)
61 Inteest Charges
62 Inteest on Long-Teo Debt (427)
63 Amort of Debt Disc. and Expense (428)
64 Amozatio of Lo on Reaquired Debt (428.1)
65 (Less) Amo. of Premium on Debt-Creit (429)
66 (Less) Amortzatin of Gain on Reaquire Debt-Creit (429.1)
67 Intet on Debt to Assoc. Companies (43)
68 Otr Interet Expese (431)
69 (Less) Allowanc for Borred Funds Used Dunng Constctn-Cr. (432)
70 Net Interst Charges (Totl of line 62 thru 69)
71 Income Before Extrorinary Items (Total of lines 27, 60 and 70)
72 Extrordinary Items
73 Extrorinary Income (434)
74 (Les) Extrordinary Deucts (435)
75 Net Extrinry Items (Tota of line 73 les line 74)
76 Income Taxes-Federl and Other (409.3)
77 Exrdinary Items After Taxes (line 75 less line 76)
78 Net Income (Total of line 71 and 77)
Page 117
Current Year
(c)
175,302,189
782,667
737,018
66,599
1,076,858
-8,226
4,957,254
5,214,598
7,554,922
7,178,192
122,587
24,05,717
420,891
-4,197,136
328,368
1,050,861
5,541,928
3,148,885
34,431
1,681,539
352,526
3,224,256
3,576,029
This Page Intentionally Left Blank
This ~ort Is: Date of Report
(1) ~An Oriinal (Mo, Da, Yr)
(2) A Resubmission 04121010
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 identifed as to the retained earnings accunt in which rerded (Accounts 433, 436
- 439 inclusive). Show the contra primary account afeced in column (b)
4. State the purpse and amount of each reservation or appropriation of retained earnings.
5. List first account 439, Adjustments to Retained Earnings, reflecing adjustments to the opening balance of retained eamings. 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 accunt 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
recurrnt, 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.
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2009/Q4
Line ItemNo. (a)
UNAPPROPRIATED RETAINED EARNINGS (Accunt 216)
1 Balance-Beginning of Period
2 Changes
3 Adjustments to Retained Earnings (Accunt 439)
4
5
6
7
8
9 TOTAL Credits to Retained Eamings (Acc. 439)
10
11
12
13
14
15 TOTAL Debits to Retained Eamings (Acc. 439)
16 Balance Transferred from Income (Accunt 433 less Accunt 418.1)
17 Appropriations of Retained Eamings (Acc. 436)
18
19
20
21
22 TOTAL Appropriations of Retained Earnings (Acc. 436)
23 Dividends Declared-Preferred Stock (Accunt 437)
24
25
26
27
28
29 TOTAL Dividends Declared-Preferred Stock (Acc. 437)
30 Dividends Declared-Common Stock (Accunt 438)
31 Common Stock Dividends $2.50 Par Value
32
33
34
35
36 TOTAL Dividends Declared-Common Stock (Acct. 438)
37 Transfers from Acc 216.1, Unapprop. Undistrib. Subsidiary Earnings
38 Balance - End of Period (Total 1,9,15,16,22,29,36,37)
APPROPRIATED RETAINED EARNINGS (Account 215)
Contr Primary
ccunt Affed
(b)
Current
QuarterlYear
Year to Date
Balance
(c)
Previous
QuarterlYear
Year to Date
Balance
(d)
I------_~~..
-- ~I ---- -- - ---- - ---~--------r ------~---~-
117,601,730 89.993,848- ----1-- --- --------- -- -
r--~-----~-~--
-----¡~_---_~-
238 -56,910,568 ( 54,368,186)
-56,910,568 54,368,186)
I~--~==483,599,149 422,907,987
FERC FORM NO. 1/3.0 (REV. 02.0)Page 118
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2oo9/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/1212010
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 identifed as to the retained earnings account in which recorded (Accounts 433, 436
- 439 indusive). Show the contra primary account affected in column (b)
4. State the purpse and amount of each reservation or appropriation of retained earnings.
5. List first account 439, Adjustments to Retained Eamings, reflecting adjustments to the opening balance of retained eamings. 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 accunt 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 resered or appropriated as well as the totals eventually to be accmulated.
9. If any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.
Line
No.
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 (Acc. 215.1)
47 TOTAL Approp. Retained Eamings (Acc. 215, 215.1) (Total 45,46)
48 TOTAL Retained Eamings (Acc. 215, 215.1, 216) (Total 38, 47) (216.1)
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Accunt
Report only on an Annual Basis, no Quarterly
49 Balance-Beginning of Year (Debit or Credit)
50 Equity in Earnings for Year (Credit) (Account 418.1)
51 (Less) Dividends Received (Debit)
52
53 Balance-End of Year (Total lines 49 thru 52)
Item
(a)
Contra Primary
ccunt Affected
(b)
Current
QuarterlYear
Year to Date
Balance
(c)
Previous
OuarterlYear
Year to Date
Balance
(d)
--- --~---r-~---- ~ --- ---- -_~---
--~ ~r-----~ ---------~-- --~-r~~-------
1,543,96
1,543,966
485,143,115
1,543,966
1,543,96
424,451,953
57,595,094
4,957,254
53,474,014
4,121,080
62,552,348 57,595,094
FERC FORM NO. 1/3.0 (REV. 02-04)Page 119
This ~ort Is: .(1) ~An Original
(2) A Resubmission
STATEMENT OF CASH FLOWS
(1) Codes to be used:(a) Net Proces or Payints;(b)Bonds, debentu and other long-term debt; (c) Include coal paper; and (d) Identify separately suc items as
investments, fixed assets, intangibles, etc.
(2) Informatn about noncsh investing and financing actvities must be provided in the Notes to the Financial statements. Also provide a reciliation betwn "Cash and Cash
Equivalets at End of Period" wit reated amounts on th Balanc Sheet.
(3) Opeting Actviti - Oter: Include gains and losss perining to operating activities only. Gains and losses peining to investing and financng acvities should be re
in thse actvites. Show in the Notes to the Financials the amounts of intert paid (net of amount capitlized) and income taes paid.
(4) Investing Actvities: Include at Other (line 31) net cash outfow to acuire other companies. Provide a recnciliation of assets acquired with liabilties assumed in the Notes to
the Financial Statements. Do not include on this statement the dollar amount of leases capitalized pe the USofA General Instructon 20; instead provide a reconciliation of the
dollar amont of leases capitalized with the plant cost.
Name of Respondent
Idaho Power Company
Date of Report
(Mo, Da, Yr)
04/1212010
Year/Period of Report
End of 2009/Q4
Line Description (See Instruction No. 1 for Explanation of Codes)
No.(a)
1 Net Cash Flow from Operating Activities:
2 Net Income (Line 78(c) on page 117)
3 Noncash Charges (Credits) to Income:
4 Depreciation and Depletion
5 Amortization of
6
7
8 Deferred Income Taxes (Net)
9 Investment Tax Credit Adjustment (Net)
10 Net (Incrase) Decrease in Receivables
11 Net (Increase) Decrease in Inventory
12 Net (Increase) Decrease in Allowances Inventory
13 Net Increase (Decrease) in Payables and Accrued Expense
14 Net (Increase) Decrease in Other Regulatory Assets
15 Net Increase (Decrease) in Other Regulatory Liabilities
16 (Less) Allowance for Other Funds Used During Construction
17 (Less) Undistributed Eamings from Subsidiary Companies
18 Other (provide details in footnote):
19
20
21
22 Net Cash Provided by (Used in) Operating Activitis (Total 2 thru 21)
23
24 Cash Flows from Investment Activities:
25 Construction and Acquisition of Plant (including land):
26 Gross Additions to Utilty Plant (less nuclear fuel)
27 Gross Additions to Nuclear Fuel
28 Gross Additions to Common Utility Plant
29 Gross Additions to Nonutility Plant
30 (Less) Allowance for Other Funds Used During Construction
31 Other (provide details in footnote):
32
33
34 Cash Outfows for Plant (Total of lines 26 thru 33)
35
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 Investmnt Securities (a)
45 Proceeds fro Sales of Investment Securites (a)
Current Year to Date
QuartrlYear
(b)
Previous Year to Date
QuarterlYear
(c)
10,594,321
2,842,380
-15,306,466
-6,714,633
24,923,64
1,373,356
-1,930,182
-6,435,706
-28,488,583
-60,996,430
-3,071,792
3,141,017
4,121,080
112,383
264,678,714 121,386,224
-236,464,054
5,397,871
2,381,759
7,080,140
2,958,500
-249,555,449 -240,585,694
-- --- - ~-r-- ------ -- ----
2,250,259 5,784,800
--- ----_.1-------- - ---
4,100,665
FERC FORM NO.1 (ED. 12-96)Page 120
Name of Respondent
Idaho Power Company
This ~ort Is:
(1) ~An Original
(2) A Resubmission
STATEMENT OF CASH FLOWS
Date of Report
(Mo, Da, Yr)
04/12/2010
YearlPeriod of Report
End of 2009/04
(1) Codes to be used:(a) Net Proces or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercal paper; and (d) Identify separately such items as
investmnts, fixed assets, intangibles, etc.
(2) Information about noncash investing and financing actviies must be provided in the Notes to the Financial statements. Als provide a renciliation ben "Cash and Cash
Equivalents at End of Perid" with related amounts on the Balance Sheet.
(3) Operating Actvities - Oter: Include gains and losss pertining to operting activits only. Gains and losses pertining to investing and financing actvites should be rert
in those activities. Show in the Notes to the Financils the amounts of interest paid (net of amount capitalized) and income taes paid.
(4) Investing Activities: Include at Other (line 31) net cash outfow to acquire other companies. Provide a recnciliatin of assets acquired with liabilitis assumed in the Notes to
the Financial Statements. Do not include on this statement the dollar amount of leases capilized per the USofA Generallnstrucon 20; instead prvide a recnciliatin of the
dollar amount of leases capialized wit the plant cost.
Line
No.
Description (See Instruction NO.1 for Explanation of Codes)
(a)
Current Year to Date
OuarterIYear
(b)
Previous Year to Date
OuarterIYear
(c)
46 Loans Made or Purchased
47 Collectons on Loans
48
49 Net (Incrase) Decrease in Receivables
50 Net (Increase) Decrease in Inventory
51 Net (Increase) Decrease in Allowances Held for Speculation
52 Net Increase (Decrease) in Payables and Accrued Expenses
53 Other (provide details in footnote):
54 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 from IDACORP
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
922,056 -7,449,788
1,514,798
43,926,946
396,100,000 290,000,000
20,000,000 37,000,000
416,100,000 327,000,000
-251,063,636 -167,163,636
-6,921,974 -2,150,077
-101,264,330 -32,687,145
-56,910,568 -54,368, 1 se~~
21,624,929 3,141,276
FERC FORM NO.1 (ED. 12-96)Page 121
This Page ~~tentionally Left Blank
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 04/12/2010 2009/Q4
FOOTNOTE DATA
!Schedule Page: 120 Une No.: 5 Column: b
Amortization:
Plant
Regulatory assets
Regulatory liabilty
Unamortized debt expense
Unamortized discount
Water rights
Other
7,038,345
3,692,067
(569,074)
2,041,784
257,310
1,581,118
248,539
14,290,089
¡SchedUle Page: 120 Une No.: 13 Column: b
Per instruction Number 3 to the statement of cash flows
Cash paid during the period for:
Income taxes received from parent
Interest (net of amount capitalized)
¡Schedule Page: 120 Une No.: 18 Column: b
Cash Flow from Operating Activities (Other)
16,438,944
66,230,730
Non-csh pension expense
Gain on sale of emission allowances
Gain on sale of non-utilty propert
Unbiled revenues
Other noncash adjustments to net income
Other current liabilties
Other long-term assets
Other long-term liabilties
4,024,783
(297,616)
(153,574)
(7,338,069)
5,833,515
(7,438,112)
1,475,491
(20,520,384)
(24,413,966)
!Schedule Page: 120 Line No.: 26 Column: b
Per instruction Number 4 to the statement of Cash Flows
PP&E acquired with liabiltes assumed (accounts payable) 19,074,880
!Schedule Page: 120 Une No.: 53 Column: b
Reinvested income from Rabbi Trust investment
Proceeds from the sale of money market investment
Miscellaneous other investing activities
J
(1,918,608)
680,738
(28,347)
(1,266,217)
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)End of 2009/Q4
(2) FiA Resubmission 04/121010
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, A~ 0 HEDGING ACTIVITIES
1. Report in columns (b),(c),(d) and (e) the amounts of accmulated other comprehensive income itms, 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 accunted for as "fair value hedges., rert the accunts affct and the related amounts in a footnote.
4. Report data on a year-to-ate basis.
Line Item Unrealized Gains and Minimum Pension Foreign Currency Other
No.Los on Available-Libili adjustment Hedges Adjustments
for-8ale Securies (net amount)
(a)(b)(c)(d)(e)
1 Balance of Accunt 219 at Beinning of
Preceding Year 567,249 (6,723,748)
2 Preceding QtrNr to Date Reclassifications
from Ace 219 to Net Income 4,159,139 414,660
3 Preceding QuarterNear to Date Changes in
Fair Value (4,726,36)(2,397,551)
4 Total (lines 2 and 3)(567,225)(1,982,891)
5 Balance of Accunt 219 at End of
Preæding QuarterNear 24 (8,706,639)
6 Balance of Accunt 219 at Beginning of
Current Year 24 (8,706,639)
7 Current QtrNr to Date Redassifications
from Ace 219 to Net Income 542,887
8 Current QuarterNear to Date Changes in
Fair Value 1,820,148 (1,923,083)
9 Total (lines 7 and 8)1,820,148 (1,380,196)
10 Balance of Accunt 219 at End of Currnt
QuartrNear 1,820,172 (10,086,835)
....
._.
--
---
FERC FORM NO.1 (NEW 06-02)Page 122a
Name of Respondent
Idaho Power Company
This ~ort Is: Date of Report
(1) ~AnOriginal (Mo, Da, Yr)
(2) A Resubmission 04/12/2010
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, A 0 HEDGING ACTIVITIES
Year/Period of Report
End of 2009/Q4
Line
No.
Other Cash Flow
Hedges
Interest Rate Swaps
Other Cash Flow
Hedges
(Specify)
Totals for each
category of items
recorded in
Aceunt219
(h)
( 6,156,499)
4,573,799
7,123,915)
2,550,116)
8,706,615)
8,706,615)
542,887
102,935)
439,952
8,266,663)
(f)(g)
1
2
3
4
5
6
7
8
9
10
Net Income (Carried
Forward from
Page 117, Line 78)
Total
Comprehensive
Income
(i)0)
FERC FORM NO.1 (NEW 06-02)Page 122b
Name of Respondent
Idaho Power Company
Date of Report Year/Period of Report
End of 2009/04
This Report Is:
(1) (2 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 accunt thereof. Classify the notes according to each basic statement,
providing a subheading for each statement except where a note is applicable to more than one statement.
2. Furnish particulars (details) as to any significant contingent assets or liabilties existing at end of year, induding 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 daim 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, Utilty Plant Adjustments, explain the origin of such amount, debit and credits during the year, and plan of
disposition contemplated, giving references to Cormmission order or other autoriations respecng classifcation of amounts as plant
adjustments and requirements as to disposition thereof.
4. Where Accunts 189, Unamortized Loss on Reacquire Debt. and 257, Unamorted 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 Accunts.
5. Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such
restrictons.
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 suffcient disdosures 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
omited.
8. For the 30 disclosures, the disdosures shall be provided where events subsequent to the end of the most recent year have occurred
which have a material effec on the respondent. Respondent must indude in the notes significant changes since the most recently
completed year in such items as: accunting principles and praces; estimates inherent in the preparation of the financial statements;
status of long-term contracts; capitalization including signifcant new borrowings or modificatins 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 ocrred.
9. Finally, ifthe 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 instrctons, such notes may be included herein.
04121010
PAGE 122 INTENTIONALLY LEFT BLANK
SEE PAGE 123 FOR REQUIRED INFORMATION.
FERC FORM NO.1 (ED. 12-96)Page 122
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2) A Resubmission 04/12/2010 2009/04
NOTES TO FINANCIAL STATEMENTS (Continued)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Idaho Power (lPC), a wholly-owned subsidiar of IDA CORP Inc., is an electrc utilty with a service territory covering approximately
24,000 square miles in southern Idaho and eastern Oregon. Idaho Power is regulated by the Federal Energy Regulatory Commission
(FERC) and the state regulatory commissions of Idaho and Oregon. Idaho Power is the parent of Idaho Energy Resources Co.
(IERCo), a joint venturer in Bridger Coal Company, which supplies coal to the Jim Bridger generating plant owned in par by Idao
Power.
Basis of Reporting
The fmancial statements include the assets, liabilties, revenues and expenses of the Company and have been prepared in accordance
with the accounting requirements of the FERC as set forth in its applicable Uniform System of Accounts and published accounting
releases, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of
America (U.S. GAAP). As required by the FERC, the Company accounts for its investment in its majority-owned subsidiar on the
equity method rather than consolidating the assets, liabilties, revenues, and expenses of the subsidiary, as required by U.s. GAAP. The
accompanying fmancial statements include the Company's proportonate share of utilty plant and related operations resulting frm its
interest in jointly owned plants. In addition, under the requirements ofthe FERC, there are differences from U.S. GAAP in the
presentation of (I) curent portion of long-term debt, (2) assets and liabilties for cost of removal of assets, (3) regulatory assets and
liabilities, (4) deferred income taes and (5) comprehensive income.
Management Estimates
Management makes estimates and assumptions when preparing financial statements in conformity with GAAP. These estimates and
assumptions include those related to rate regulation, retirement benefits, contingencies, litigation, asset impairent, income taxes,
unbiled revenues and bad debt. These estimates and assumptions affect the reported amounts of assets and liabilties and the
disclosure of contingent assets and liabilties at the date of the fmancial statements, and the reported amounts of revenues and expenses
durng the reporting period. These estimates involve judgments with respect to, among other things, futue economic factors that are
diffcult to predict and are beyond management's control. As a result, actul results could differ from those estimates.
System of Accounts
The accounting records of Idaho Power conform to the Uniform System of Accounts prescribed by the FERC and adopted by the
public utilty commissions of Idaho,.Oregon and Wyoming.
Regulation of Utilty Operations
IDACORP's and Idao Power's financial statements reflect the effects of the different ratemaking priciples followed by the
jurisdictions regulating Idaho Power. The application of accounting priciples related to regulated operations sometimes results in
Idaho Power recording expenses and revenues in a different period than when an unregulated enterprise would. In these
circumstances, the amounts are deferred as regulatory assets or regulatory liabilties on the balance sheet and recorded on the income
statement when recovered or retued in rates. Additionally, regulators can impose regulatory liabilties upon a regulated company for
amounts previously collected from customers and for amounts that are expected to be refuded to customers. The effects of applying
these accounting principles are discussed in more detail in Note 3.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand and highly liquid tempora investments that mature within three months of the date of
acquisition.
Derivative Financial Instruments
Financial instrments such as commodity futures, forwards, options and swaps are used to manage exposure to commodity price risk in
the electrcity market. All derivative instrents ar recognized as either assets or liabilties at fair value on the balance sheet. Idaho
Power's physical forward contracts qualitY for the normal purchases and normal sales exception to derivative accounting requirements
with the exception of forward contrcts for the purchase of natual gas for use at Idaho Power's natual gas generation facilties. The
objective of the risk management program is to mitigate the risk associated with the purchase and sale of electricity and natual gas.
Because of Idaho Power's regulatory accounting mechanisms, Idaho Power records the changes in fair value of derivative instrments
related to power supply as regulatory assets or liabilties.
IFERC FORM NO.1 (ED. 12-88) Page 123.1
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 041212010 2009/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Revenues
Operating revenues for Idaho Power related to the sale of energy are recorded when service is rendered or energy is delivered to
customers. Idaho Power accrues estimated unbiled revenues for electrc services delivered to customers but not yet biled at
period-end. Idaho Power collects franchise fees and similar taes related to energy consumption. These amounts are recorded as
liabilties until paid to the taing authority. None of these collections ar reported on the income statement as revenue or expense.
Begining in Februar 2009, Idaho Power is collecting Allowance for Funds Used During Constrction (AFUDC) in base rates for a
specific capital project, as discussed in Note 3, "Regulatory Matters." Cash collected under this ratemaking mechanism is recorded as
a regulatory liabilty.
Propert, Plant and Equipment and Depreciation
The cost of utilty plant in service represents the original cost of contrcted services, direct labor and material, AFUDC and indirect
charges for engineering, supervision and similar overhead items. Repair and maintenance costs associated with planed major
maintenance are expensed as the costs are incurred, as ar maintenance and repair of propert and replacements and renewals of items
determined to be less than units of propert. For utilty 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.
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 depreiable utilty plant in service approximated 2.8 I percent in 2009 and 2.73 percent
in 2008.
Long-lived assets are periodically reviewed for impaient when events or changes in circumtaces indicate that the caring amount
of an asset may not be recoverable. If the sum of the undiscounted expected futue cash flows from an asset is less than the caring
value of the asset, impairment must be recognized in the financial statements. There were no material impairments of these assets in
2008 or 2009.
Allowance for Funds Used During Construction
AFl)DC represents the cost offmancing constrction projects with borrwed fuds and equity fuds. With one exception, cash is not
realized currently from such allowance, it is realized under the rate-making process over the service life of the related propert though
increased revenues resulting from a higher rate base and higher depreciation expense. The component of AFUDC attbutable to
borrowed funds is included as a reduction to interest expense, while the equity component is included in other income. Idaho Power's
weighted-average monthly AFUDC rates for 2009 and 2008 were 6.7 percent and 5.2 percent, respectively. Idaho Power's reductions
to interest expense for AFUDC were $5 millon for 2009 and $7 milion for 2008. Other income included $8 milion and $3 milion of
AFUDC for 2009 and 2008, respectively.
Income Taxes
Idaho Power accounts for income taes under the asset and liabilty method, which requires the recognition of deferred ta assets and
liabilties for the expected future tax consequences of events that have been included in the fmancial statements. Under this method,
deferred ta assets and liabilties ar determined based on the differences between the fmancial statements and tax basis of assets and
liabilties using enacted ta rates in effect for the year in which the differences are expected to reverse. The effect of a change in tax
rates on deferrd 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 (IPUC), the regulatory authority having principal
jurisdiction, Idaho Power's deferred income taxes (commonly referred to as normalized accounting) are provided for the difference
between income tax depreciation and straight-line depreciation computed using book lives on coal-fired generation facilities and
properties acquired after i 980. On other facilties, deferred income taxes are provided for the difference between accelerated income
ta depreciation and stright-line depreciation using ta guideline lives on assets acquired prior to i 98 i unless contrar to applicable
income tax guidance, deferred income taxes are not provided for those income tax timing differences where the prescribed regulatory
accounting methods do not provide for current recovery in rates. Regulated enterprises are required to recognize such adjustments as
regulatory assets or liabilties if it is probable that such amounts wil be recovered from or returned to customers in future rates.
The state of Idaho allows a three-percent investment tax credit on qualifYing plant additions. Investment tax credits eared on
regulated assets ar deferred and amortized to income over the estimated service lives ofthe related properties. Credits eared on
IFERC FORM NO.1 (ED. 12-88) Page 123.2
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/1212010 2009/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
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, unealized holding gains and losses on available-for-sale marketable securities and
amounts related to a deferred compensation plan for certin senior management employees and directors called the Senior
Management Security Plan (SMSP).
The following table presents Idaho Power's accumulated other comprehensive loss balance at December 31 (net of tax):
Unrealized holding gains on available-for-sale securties
Senior Management Security Plan
Total
$
2009 2008
(thousands of dollars)
1,820 $
(10,087)
(8,267) $
(8,707)
(8,707)$
Other Accounting Policies
Debt discount, expense and premium are deferred and being amortized over the tenns of the respective debt issues.
New Accounting Pronouncements
In June 2009, the F ASB issued amendments to prior consolidation guidance. The amendments wil signifcantly affect the overall
consolidation analysis of variable interest entities (VIEs). The amendments wil require Idaho Power to reconsider their previous
conclusions relating to the consolidation of VIEs, including (I) whether an entity is a VIE, (2) whether the enterprise is the VIE's
primar beneficiary, and (3) what tye of financial statement disclosures ar required. For Idao Power, the amendments are effective
as of January 1, 2010, and early adoption is prohibited. The adoption of this guidance is not expected to have a material effect on the
consolidated financial statements ofIdaho Power.
Adopted Accounting Pronouncements
The F ASB has issued several new accounting pronouncements. Idaho Power adopted these pronouncements in 2009:
. Effective for financial statements issued for interi and anual periods ending after September 15,2009, The FASB
Accounting Standards Codification TM became the source of authoritative U.S. GAAP recognized by the FASB to be
applied to nongovernental entities. Rules and interpretive releases of the Securities and Exchange Commission (SEC)
under authority of federal securities laws are also sources of authoritative GAAP to SEC registrants. On the effective
date, the Codification superseded, but did not change, all then-existing non-SEC accounting and reporting standards, and
all other nongrndfathered, non-SEC accounting literatue not included in the Codification became nonauthoritative.
Transition to the Codification did not affect Idaho Power's results of operations, cash flows or financial positions. This
Fonn IO-K reflects the implementation of the Codification.
. In June 2009, Idaho Power adopted guidance on accounting for and disclosures of subsequent events, events that occur
after the balance sheet date but before financial statements are issued or are available to be issued. This guidance has not
significantly impacted Idaho Power's consolidated financial statements.
. Fair Value Measurements: In the first quarer of 2009, Idaho Power adopted the following fair value guidance:
. Guidelines for making fair value measurements more consistent by providing guidance related to detennining fair
values when there is no active market or where the price inputs being used represent distrssed sales;
. Guidance that enhances consistency in fmancial reporting by increasing the frequency of fair value disclosures by
requiring quarerly fair value disclosures for any financial instrments that are not curently reflected on the balance
sheet of companies at fair value and requires qualitative and quantitative infonnation about fair value estimates for
all such fmancial instrments; and
. Guidance on other-than-tempora impainnents that brings greater consistency to the timing of impainnent
recognition, and provides greater clarity to investors about the credit and noncredit components of impaired debt
securities that are not expected to be sold. The guidance also requires increased and timelier disclosures sought by
IFERC FORM NO.1 (ED. 12-88) Page 123.3
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 041212010 2009/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
investors regarding expected cash flows, credit losses, and the aging of securities with unalized losses.
The adoption of this guidance did not have a material effect on Idaho Power's consolidated fmancial statements.
2. INCOME TAXES:
The components of the net deferred ta liabilty ar as follows:
2009 2008
(thousands of dollars)
Deferred ta assets:
Regulatory liabilties $47,183 $44,341
Advances for constrction 8,335 9,305
Deferred compensation 17,990 17,052
Retirement benefits 84,019 85,034
Oter 13,431 15,029
Total 170,958 170,761
Deferred ta liabilties:
Propert, plant and equipment 282,034 246,424
Regulatory assets 382,136 333,882
Conservation programs 4,772 1,901
PCA 34,025 62,820
Retirement benefits 65,689 69,334
Other 5,773 961
Total 774,429 715,322
Net deferred tax liabilties $603,471 $544,561
A reconcilation between the statutory federal income ta rate and the effective tax rate is as follows:
2009 2008
(thousands of dollars)
Computed income taxes based on
stattory federal income tax rate $54,296 $45,51 i
Change in taes resulting from:
Equity earnings of subsidiar companies (1,735)(1,442)
AFUDC (4,533)(3,577)
Capitalized interest 1,529 1,729
Investment tax credits (3,404)(3,490)
Repair allowance (3,500)(2,450)
Removal costs (3,810)(2,954)
Capitalized overhead costs (3,500)(4,200)
Uncertain tax positions 1,138 1,280
Settlement of prior year' ta returns (4, II 9) (2,761)
State income taes, net of federal benefit 1,903 4,601
Depreciation 3,895 5,562
Oter, net (5,587)(1,892)
Total income ta expense $32,573 $35,917
Effective tax rate 21.0%27.6%
The items comprising income tax expense are as follows:
IFERCFORM NO.1 lED.12-88)Page 123.4
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company I (2) A Resubmission 04/1212010 2009/04
NOTES TO FINANCIAL STATEMENTS (Continued)
2009 2008
(thousands of dollars)
Income taes currently payable (receivable):
Federal $19,732 $14,024
State 2,385 (3,602)
Total 22,117 10,422
Income taes deferrd:
Federal 18,993 33,906
State (5,792)2,794
Total 13,201 36,700
Uncertain ta positions:
Federal (2,496)(12,763)
State (485)(712)
Total (2,981)(13,475)
Investment tax credits:
Deferrd 3,640 5,760
Restored (3,404)(3,490)
Total 236 2,270
Total income ta expense $32,573 $35,917
IDACORP's tax allocation agreement provides that each member of its consolidated group compute its income taxes on a separte
company basis. Amounts payable or refundable are settled though IDACORP.
Uncertain Tax Positions
Idaho Power adopted new guidance on uncertain ta positions on Januar 1,2007. Idaho Powerrecorded an increase of$15.1 milion
to 2007 opening retained earings for the cumulative effect of adopting this guidance. A reconcilation of the begining and ending
amount of unecognized tax benefits for Idaho Power is as follows (in thousands of dollars):
Balance at January 1,
Additions for tax positions of prior years
Reductions for tax positions of prior years
Settlements with taxing authorities
Balance at December 3 i,
$
2009 2008
4,119 $17,594
1,138 1,280
(4,1l9)(10,426)
(4,329)
1,138 $4,119$
If recognized, the $ 1.1 milion balance of unrecognized ta benefits would affect the effective tax rate.
Since 2006, Idaho Power had been disputing the Internal Revenue Service's (IRS) disallowance ofIdaho Power's use of the simplified
service cost method (SSCM) of uniform capitalization for tax year 2001-2004. The dispute had been under review with the IRS
Appeals Offce.
Idaho Power recognizes interest accrued related to unecognized tax benefits as interest expense and penalties as other expense.
During the years ended December 31, 2009 and 2008, Idaho Power recognized a net reduction in interest expens of $0.2 millon and
$0.1 milion. Idao Power had no accrued interest as of December 31,2009 and $0.2 milion as of December 3 1,2008. No penalties
are accrued.
Idaho Power is subject to examination by their major tax jurisdictions - U.S. federal and state ofIdaho. The open tax year are 2009
for federal and 2007-2009 for Idao. In May 2009, Idaho Power, through its parent company, formally entered the IRS Compliance
Assurace Process (CAP) program for its 2009 tax year. The CAP program provides for IRS examination thoughout the year. The
IFERC FORM NO.1 (ED. 12-88) Page 123.5
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company :(2)A Resubmission 041212010 2009/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
2009 examination is expected to be completed in 2010. In Janua 2010, Idaho Power, though its parent company, was accepted into
CAP for its 2010 ta year. Idaho Power is unable to predict the outcome of these examinations.
Specifically within the 2009 CAP examination, the IRS began its audit of Idaho Power's curent method of uniform capitalization. In
September 2009, the IRS issued Industr Director Directive #5 (IOD) which discusses the IRS's compliance priorities and audit
techniques related to the allocation of mixed service costs in the uniform capitalizaion methods of electric utilties. The IRS and
Idaho Power ar jointly working though the impact the IOD guidance has on Idaho Power's uniform capitalization method. Idaho
Power expects that the examination wil be completed during 2010. Resolution of this matter would result in a decrease to Idao
Power's unrecognized tax benefits for its 2009 uniform capitaliztion deduction by $1. milion.
3. REGULATORY MATTERS:
Regulatory Assets and Liabilties
The following is a breakdown ofIdao Power's regulatory assets and liabilties (in thousands of dollar):
Remaining Not
Amortization Earning Earning Total as of December 31,
Description Period a Return a Return 2009 2008
Regulatory Assets:
Income taes $-$389,910 $389,910 $335,644
Unfunded postretirement benefits 168,026 168,026 177,348
(I)
Pension expense deferrls (2)39,251 39,251 10,583
Energy effciency progr costs (2)2010 10,585 1,622 12,207 8,806
Power supply costs (2)Vares (2)84,633 84,633 149,099
Fixed cost adjustment (2)2011 7,836 7,836 2,721
Asset retirement obligations (3)14,749 14,749 10,907
Mar-to-market liabilties (4)280 280 3,074
Other 2010-2015 1,914 1,875 3,789 1,224
Total (5)$104,968 $615,713 $720,681 $699,406
Regulatory Liabilties:
Income taes $-$54,958 $54,958 $46,102
Removal costs (3)155,405 155,405 156,837
Investment tax credits 73,506 73,506 73,270
Deferrd revenue-AFUDC 6,096 3,798 9,894
Mark-to-market assets (4)715 715 652
Other 2011 479 1,100 1,579 1,818
Total (6)$6,575 $289,482 $296,057 $278,679
(i) Repreents the Idao jurisdiction unfunded obligation ofldaho Power's pension and postretirement plans, which ar discussed in
note i i.
(2) These items are discussed in more detail below.
(3) Asset retirement obligations and removal costs ar discussed in Note 12
(4) Mar-to market assets and liabilties ar discussed in Note 15
(5) Includes $601 and $3,074 for 2009 and 2008, respectively, rert in other currt assets on the balance sheets.
(6) Includes $8,972, and $2,413 for 2009 and 2008, repectively, reported in other current liabilties on the balance sheets.
In the event that recovery ofIdao Power's costs though rates becomes unlikely or uncertin, regulatory accounting would no longer
apply to some or all of Idaho Power's operations and the items above may represent strnded investments. If not allowed full recovery
I FERC FORM NO.1 (ED. 12-88)Page 123.6
Name of Respondent This Report is:Date of Report Year/Perio of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2) A Resubmission 04/12/2010 2009/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
of these items, Idaho Power would be required to write off the applicable portion, which could have a significant financial impact.
Deferred Net Power Supply Costs:
Changes in deferred power supply costs over the last two years were as follows:
Idaho Oregon (1) Total
Balance at Januar 1,2008 $ 92,322 $ 5,100 $ 97,422Costs deferred through PCA and PCAM 108,688 5,196 113,884
Prior costs expensed and recovered through rates (64,030) (2,441) (66,471)S02 allowances credited to account (2,184) (175) (2,359)Interest and other 6,025 598 6,623
Balance at December 31, 2008 $ 140,821 $ 8,278 $ 149,099Costs deferred though PCA and PCAM 42,533 (184) 42,349
Prior costs expensed and recovered through rates (113,134) (2,283) (115,417)
S02 allowances credited to account (2,034) (83) (2,11 7)Interest and other 3,226 1,135 4,3612007 Excess power costs order 6,358 6,358
Balance at December 31, 2009 $ 71,412 $ 13,221 $ 84,633
(1) Oron power supply cost deferrals are subject to a statute that specifically limits rate amortizations of deferrd costs to six
percent of gross Oregon revenue per year (approximately $2 milion). Deferrs ar amrtized sequentially.
Idaho:
Idaho Power has a PCA mechanism that provides for anual adjustments to the rates charged to its Idao retail customers. The PCA
tracks Idaho Power's actual net power supply costs (priarly fuel and purchased power less off-system sales) and compars these
amounts to net power supply costs currently being recovered in retail rates.
The annual adjustments are based on two components:
. Aforecast 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
. 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 actul collection or refund of
authorized tre-up dollar matches the amounts authorized. The tre-up component is calculated monthly, and interest is
applied to the balance.
The following table sumarzes the PCA adjustments durng the last three years:
Effective
Date
June 1,2009
$ Change
(milions)
$84.3
Notes
The IPUC's order reflects revised methodology discussed below in "PCA
Workshops."
The increase was net of $4.5 milion of gains from sales of excess S02emission
allowances which the IPUC ordered be applied against the PCA. The IPUC has
allowed Idaho Power to retain its PCA sharing percentage of the gain from sales of
excess S02 allowances as a shareholder benefit with the remainder recorded as a
customer benefit, substantially all of which was used to reduce the PCA. Proceeds
from the sale of renewable energy certificates (RECs) wil also be used to reduce the
PCA. RECs are acquired by Idaho Power though purchases of renewable energy.
Increase was net of $ i 6.5 milion of gains from sales of excess S02emission
allowances
June 1,2008 73.3
IFERC FORM NO.1 (ED. 12-88) Page 123.7
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2) A Resubmission 041212010 2009/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
June 1,2007 77.5 Increase was net of $69. I milion of gains from sales of excess S02 emission
allowances
PCA Workhops: In its order approving Idaho Power's 2008-2009 PCA, the IPUC directed Idaho Power to set up workshops with the
IPUC Staffand several ofIdahO Power's largest customers to address issues notresolved in that PCA filing. The workshops resulted
in the following changes to the PCA mechanism, effective Februar 1,2009:
· PCA sharng ratio - the PCA allocates the deviations in net power supply expenses between customers (95 percent) and
shareholders (5 percent). The previous sharg ratio was 90/10.
· LGAR - the LGAR is an element of the PCA fonnula that is intended to eliminate recovery of power supply expenses
associated with load growt resultig from changing weather conditions, a growing customer base, or changing customer use
patterns. The 2007 general rate case reset the LGAR from $29.4 i to $62.79 per MWh, but applied that rate to only 50
percent of the load growt begining in Marh 2008. The stipulation agreed on a new fonnula for calculating the LGAR.
Based on the fmal rates approved by the IPUC in the 2008 general rate cae and the supporting data, the current LGAR is
$26.63 per MWh, effective Febru 1,2009.
· Use of Idao Power's operation plan power supply cost forecas - the operation plan forecast may better match curent
collections with actul net power supply costs in the year they ar incurd and result in smaller amounts being included in the
following year's "tre-up" rate, begining with the 2009-2010 PCA filing.
· Inclusion of third-part trsmission expense - transmission expenses paid to third paries to faciltate wholesale purchases
and sales of energy, including losses, ar a necessar component of net power supply costs. Deviation in these costs from
levels included in base rates is now refleced in PCA computtions.
· Adjusted distribution of base net power supply cost - base net power supply costs ar distrbuted throughout the year based
upon the monthly shape of nonnalized revenues for purses of the PCA deferrl calculation.
Oregon
2006-2007 Excess Power Costs: In December 2007, the OPUC approved the deferrl for futue recovery of $2 milion of excess
power costs incured from May 1,2006, through April 30, 2007, and effective September 2009, these costs began being collected
through rates and amortized. Idao Power expects amortization of this deferrl to be completed in December 2010.
May-December 2007 Excess Power Costs: In May 2009, the OPUC approved the deferral for futue recovery of $6.4 milion,
including interest through the date of the order, of excess net power supply costs incurrd from May-December 2007. Idao Power
recorded the $6.4 milion deferral in the second quaer 2009 as a reduction to power cost adjustment expense. The amount to be
recovered was reduced by $0.9 millon of previously deferrd emission allowance sales (including interest) during the same period.
Oregon Power Supply Cost Mechanism: Idaho Power's power cost recovery mechanism in Oregon went into effect in 2008. It has
two components: the anual power cost update (APCU) and the power cost adjustment mechanism (PCAM). The combination of the
APCU and the PCAM allows Idaho Power to recover excess net power supply costs in a more timely fashion than through the
previously existing deferrl process.
The APCU allows Idaho Power to reestablish its Oregon base net power supply costs anually, 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," Idaho
Power's calculation of estimated nonnalized net power supply expenses for the following April though March test period, and the
"March Forecast," Idaho Power's forecast of expected net power supply expenses for the same test period, updated for a number of
variables including the most recent stream flow data and futue wholesale electrc prices. New base rates are implemented each June i
based on the APCU.
2010 APCU: Idaho Power's October Update portion of the 2010 APCU indicates that revenues associated with Idaho
Power's base net power supply costs would be increased by $2.6 millon over the curent APCU, an average
8.2 percent increase. The actual impact wil be determined once the Marh Forecast portion is fied in March
2010 and combined with the October Update. Final rates are expected to become effective on June 1,2010.
2009 APCU: A rate increase of i 1.5 percent, or $3.9 milion anually, took effect June 1,2009.
IFERC FORM NO.1 (ED. 12-88) Page 123.8
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/1212010 2009/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
2008 APCU: A rate increase of 15.7 percent, or $4.8 millon anually, took effect June 1,2008.
The PCAM is a tre-up fied anually in Februar. The fiing calculates the deviation between actual net power supply expenses
incurred for the preceding calendar year and the net power supply expenses recovered though the APCU for the sae period. Under
the PCAM, Idaho Power is subject to a portion of the business risk or benefit associated with this deviation though application of an
asymmetrical deadband (or range of deviations) within which Idaho Power 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
Idaho Power. However, collection by Idaho Power wil occur only to the extent that it results in Idaho Power's actual retu on equity
(ROE) for the year being no greater than 100 basis points below Idaho Power's last authorized ROE. A refund to customers wil occur
only to the extent that it results in Idaho Power's actual ROE for that year being no less than i 00 basis points above Idaho Power's last
authorized ROE.
2009 PCAM: Actual net power supply costs were within the deadband, resulting in no deferraL.
2008 PCAM: Actual net power supply costs exceeded the forecast for the 2008 calendar year by $7.7 milion and, after
application of the deadband, resulted in a $5.1 milion deferrl in 2008. The OPUC approved deferrl of this
amount in Januar 20 i 0, to be amortized sequentially after previously authorized deferrls.
Fixed Cost Adjustment Mechanism (FCA)
The PCA mechanism began as a pilot progr for Idaho Power's Idaho residential and small general service customers, running from
2007 though 2009. The FCA is a rate mechanism designed to remove Idaho Power's disincentive to invest in energy effciency
program by separting (or decoupling) the recovery of fixed costs from the variable kilowatt-hour charge and lining it instead to a set
amount per customer. On October 1,2009, Idaho Power fied an application with the IPUC to make the FCA mechanism permanent
beginning Januar 1,2010. The application is being processed under modified procedure.
Idaho Power accnied $6.6 milion related to the FCA in 2009; subject to IPUC approval, recovery should begin June 1,2010. The
IPUC approved a rate increase effective June 1,2009, through May 31, 2010, to recover $2.7 milion of fixed costs under-recovered
during 2008. In 2008, the IPUC approved a rate reduction, effective June I, 2008 through May 31, 2009, to retu $2.4 milion of
fixed costs over-recovered in 2007.
Idaho Rate Cases
2009 Settlement Agreement: On January 13,2010, the IPUC approved a settlement agreement among Idaho Power, several ofIdao
Power's customers, the IPUC staff and others. Significant elements ofthe settlement agreement include:
. A general rate moratorium in effect until Januar I, 2012. The moratorium does not apply to other specified revenue
requirement proceedings, such as the PCA, the FCA, pension fuding, AMI, energy effciency rider, and governent imposed
fees.
. A specified distrbution of the expected 20 i 0 PCA. This distribution is intended to reduce customer rates, provide some
general rate relief to Idao Power and reset base power supply costs for the PCA. The associated rate change is expected to
become effective June 1,2010. This provision is in anticipation ofa significant reduction in PCA rates for the 2010-2011
PCA year. The peA reduction wil be allocated as follows:
. The first $40 milion wil be allocated equally between customers and Idaho Power. Idaho Power's share would be
applied to increase permanent base rates on a uniform percentage basis to all customer classes and contrct
customers. The customers' share would be a direct rate reduction through the PCA.
. All of the next $20 milion wil be allocated to customers as a direct rate reduction though the PCA.
. PCA reductions in excess of$60 milion wil be applied to absorb any increase in the base level of net power supply
expenses.
. If the PCA reduction exceeds $60 milion plus the increase in base net power supply expenses, the next $10 millon
wil be allocated equally between Idaho Power and customers in the same maner as the first $40 milion.
. Any remainder will go entirely to customers.
. A provision to share earings with customers ifIdaho Power's actual rate ofretum on equity is more than 10.5 percent in any
calendar year from 2009 to 2011 in its Idaho jurisdiction. Idaho Power wil share with Idaho customers 50 percent of any
profits in excess of 10.5 percent.
. A provision to allow the accelerated amortization of accumulated deferred investment ta credits (ADITC) if Idaho Power's
IFERC FORM NO.1 (ED. 12-88) Page 123.9
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ß An Original (Mo, Da, Yr)
Idaho Power Company (2) A Resubmission 04/1212010 2009/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
actual rate of retu on equity is below 9.5 percent in any calenda year from 2009 to 2011 in its Idaho jurisdiction. Idaho
Power would be pennitted to amortize additional ADITC in an amount up to $45 milion over the thee-year period, but could
use no more that $15 milion in anyone year unless there is a carover. Carover amounts are added to the $15 milion
anual allowance up to a maximum amortization of $25 milion in anyone year.
Because Idaho Power's Idaho-jursdiction retu on equity was between 9.5 and 10.5 percent, the sharing and accelerated amortization
provisions were not trggered in 2009.
The settlement agreement also included a provision to reestablish the base level for net power supply costs effective with the June 1,
2010 PCA rate change. On January 19, 2010, Idao Power fied with the IPUC a request to increase base net power supply costs by
$74.8 milion in the Idaho jurisdiction. This amount, which is subject to approval by the IPUC, reflects the maximum increase to
Idaho Power's base net power supply costs, which would be used for both base rates and PCA calculations. The actual change in net
power supply costs for rate purposes wil depend upon the amount approved by the IPUC as well as the amount of any PCA decrease
determined for the 2010-2011 PeA year. Written comments or protests with respect to Idaho Power's application ar due March 11,
2010.
Idaho 2008 General Rate Case: On Janua 30, 2009, the IPUC issued an order approving an averae anual increase in Idaho base
rates, effective Februar 1, 2009, of 3. 1 percent (approximately $20.9 milion anually), a return on equity of 10.5 percent and an
overall rate of return of8.18 percent. On Febru 19,2009, Idao Power filed a request for reconsideration with the IPUC and on
March 19, 2009, the IPUC issued an order that increased Idao Power's Idaho revenue requirment by an additional $6.1 milion to
approximately $27 milion for this rate case, raising the averae rate increase from 3.1 percent to 4.0 percent.
The Janua 30, 2009 order authorized approximately $15 milion related to incrases in base net power supply costs. It also allowed
Idaho Power to include in rates approximately $6.8 milion ($10.6 milion including income ta gross-up) of2009 AFUDC relating to
the Hells Canyon Complex relicensing project. Typically, AFUDC is not included in rates until a project is in use and benefitting
customers, but the IPUC detennined that including this amount in curent rates is in the public interest. Because AFUDC is already
recorded on an accrual basis, this portion of the rate increase wil improve cash flows but wil not have a curnt impact on Idaho
Power's net income. The amounts collected are being deferred as a regulatory liabilty and wil be recognized in revenues over the life
of the new license once it has been issued.
The IPUC denied reconsideration with respect to a refud of $3.3 milion offees recovered by Idao Power from the FERC. On April
2,2009, Idaho Power filed an application with the IPUC for an accounting order approving amortization of the fees over a five-year
period begining October 2006 when Idao Power received the FERC credit. The IPUC approved Idaho Power's requested
amortization period in an order issued on April 28, 2009. In the fit quaer of2009, Idaho Power recorded a charge of approximately
$1.7 milion to electric utilty other operations expense and a corrsponding regulatory liabilty for the amount to be refuded from
Febru 1, 2009, through the end of the amortiztion period, September 201 1. As the regulatory liabilty is amortized it wil reduce
electrc utilty other operations expense ratably over the remaining amortization period.
Idaho 2007 General Rate Case: On Februar 28, 2008, the IPUC approved a settlement stipulation that included an average increase
in base rates of5.2 percent (approximately $32.1 milion anually), effective March 1,2008. The settlement did not specifY an overall
rate of return or a return on equity.
Danskin cn Power Plant Rate Case: On May 30, 2008, the IPUC authorize Idao Power to add to its rate base $64.2 milion for
the Danskin cn plant and related facilties, effective June 1,2008, resulting in a base rate increase of 1.7 percent, or $8.9 milion in
anual revenues. Danskin cn located near Mountain Home, Idaho, began commercial operations on March 1 i, 2008.
Oregon 2009 General Rate Case: On December 16,2009, Idaho Power fied a Joint Stipulation and testimony in support of a
stipulation that would settle the revenue requirement issues surrounding the general rate case fied on July 31, 2009. If approved by
the OPUC, the Joint Stipulation would increase base rates $5 milion, or 15.4 percent, based on a retu on equity of 10.175 percent
and an overall rate of return of 8.06 1 percent. The requested effective date is March 1, 2010.
Advanced Metering Infrastructure (AMI)
The AMI project provides the means to automatically retreve energy consumption infonnation, eliminating manual meter reading
IFERC FORM NO.1 (ED. 12-88) Page 123.10
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Moi Da, Yr)
Idaho Power Company (2) A Resubmission 04/1212010 2009/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
expense. Idaho Power intends to install this technology for approximately 99 percent of its customers and is on pace to complete the
installations by the end of 20 I I .
Idaho: On February 12,2009, the IPUC approved Idaho Power's application requesting a Certificate of Public Convenience and
Necessity for the deployment of AMI technology and approval of accelerated depreciation for the existing metering equipment. The
IPUC subsequently clarfied that Idaho Power can expect in the ordinar course of events, to include in rate base the prudent capital
costs of deploying AMI as it is placed in service up to the capital cost commitment estimate of $70.9 milion. The IPUC also clarfied,
as requested by Idaho Power, that it does not anticipate that the immediate savings derived from the implementation of AMI
throughout Idaho Power's service territory wil eliminate or wholly offset the increas in Idaho Power's revenue requirement caused by
the authorized depreciation period.
On May 29,2009, the IPUC approved anual recovery of$IO.5 milion, effective June 1,2009. The order was based on Idaho
Power's actual investment in AMI to date, annualized through December 31,2009. The IPUC also allowed Idaho Power to begin
thee-year accelerated depreciation of the existing metering equipment on June 1,2009. The order reflects annualized depreciation
expense relating to AMI of$9.2 milion. Actual depreciation expense recorded over the last seven months of2009 totaled $6.2
milion.
Oregon: The OPUC approved accelerated depreciation and recovery of existing meters in the Oregon jursdiction over an I8-month
period beginning Januar 2009. Idaho Power's AMI deployment schedule calls for the replacement of the Oregon service.terrtory
meters around October 2010. The existing meters wil be fully depreciated prior to their removal from service. The approval
increased both rates and depreciation expense $0.8 milion in 2009.
Depreciation Filngs
In 2008 and 2009 Idaho Power filed revisions to its depreciation rates with the IPUC, OPUC and FERC. The commissions approved
the new rates, which reduce depreciation expense approximately $8.5 milion anually. Idaho Power began applying the new
depreciation rates in August 2008.
OATT
Formula Rates: In 2006, Idaho Power moved from a fixed rate to a formula rate, which allows trsmission rates to be updated
anually based on financial and operational data Idaho Power files with the FERC. The FERC accepted Idaho Power's initial formula
rates effective June 1, 2006, subject to refund pending the outcome of a hearing and settlement process.
Idaho Power and the paries who had opposed the fiing entered into a settlement agreement, which was approved by the FERC in
August 2007. The settlement agreement reduced Idaho Power's formula rates, established an authorized rate ofretu on equity of
to.7 percent and resulted in a $1.7 milion refund by Idaho Power. The settlement agreement did not cover the treatment of "Legacy
Agreements", which were contracts for transmission service that contained their own terms, conditions and rates and were in existence
before implementation of the OATT in 1996.
On January 15,2009, the FERC issued an order that required Idaho Power to reduce its transmission service rates to FERC
jursdictional customers and refund $13.3 milion to these customers. Based on the FERC order, Idaho Power reserved an additional
$7.9 milion (including $0.7 milion of interest) in 2008 to bring its reserve to the $13.3 milion ordered refuded. Idaho Power made
the refuds in Februar 2009 and fied a request for rehearing with the FERC. Of the additional $7.9 milion ordered refuded, $2.3
milion related to trsmission revenues recorded in 2007 and $ 1.7 milion related to trnsmission revenues recorded in 2006. In
March 2009, the FERC issued a tollng order that effectively relieved it from acting for an indefinite period of time on Idaho Power's
request for rehearing. Idaho Power cannot predict when the FERC wil rule on its request for rehearing or the outcome ofthis matter.
As discussed below, Idaho Power received an accounting order from the IPUC on October 30, 2009, authorizing it to defer for
potential futue recovery approximately $4.7 milion in unecovered transmission-related revenues associated with the FERC order.
20090ATT: On August 28,2009, Idaho Power fied its informational filing with the FERC that contains the annual update of the
formula rate based on the 2008 test year. The new rate included in the fiing was $15.83 per kW-year, an increase of $2.02 per
kW-year, or 14.6 percent. New rates were effective October 1,2009.
IFERC FORM NO.1 (ED. 12-88) Page 123.11
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 041212010 2oo9/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
2008 OATT: On August 28,2008, Idaho Power fied its informational fiing with the FERC that contained the anual update of the
formula rate based on the 2007 test year. The rate included in the fiing was $18.88 per kW-year, a decreas of$0.85 per kW-year, or
4.3 percent. New rates were effective October 1,2008. Idaho Power subsequently adjusted its rates to $13.81 per kW-year in
compliance with a Januar 15,2009, order.
Legacy Agreements: Subsequent to the Januar 15,2009, FERC Order, Idaho Power has sought to mitigate the resulting revenue
shortfall by revising certin of the Legacy Agreements as provided for in the agreements.
The Restated Trasmission Services Agrement and the long-term service agreements with PacifiCorp were amended to replace a
portion of the services provided for in the agrement with OA TT service, effective June 13,2009. As calculated in the FERC fiings,
the estimated net transmission revenue increase for the period June 13,2009 thrugh June 12,2010 is approximately $3.2 milion.
These amendments are expected to increase 20 I 0 trsmission revenue $ 1.3 milion as compared to 2009.
Idao Power also fied a request with the FERC on June 19, 2009, for an increase in rates for the Agreement for Interconnection and
Trasmission Services with PacifiCorp. As calculated in the fiing, the estimated net trsmission revenue increase for the period
September I, 2009 though August 3 I, 20 I 0, would be approximately $3.7 milion. PacifiCorp has intervened in this case. Idaho
Power began collecting the new rates effective August 19, 2009, subject to refud pending settlement procedures and hearing.
Settlement discussions are ongoing. This revision is expected to increase 20 i 0 trsmission revenue $2.5 milion as compared to
2009.
OA TT Shortfall Filng
For Idaho jursdictional revenue requirement determinations, revenues from third paies (non-state jursdictional) received though the
OATT, referred to as revenue credits, are a dirct offset to Idao Power's overall revenue requirement. In the last two general rate
cases, Idaho Power included an estimate of OA IT revenues frm third paries based on the forecasted OA IT rate. However, as
discussed above in "OATT", a FERC order issued on Janua 15,2009, significantly reduced actual third-par trmission revenues
Idao Power received from June 2006 to date, resulting in an overstatement of the revenue credits in the Idao jurisdictional revenue
requirement.
On October 30, 2009, the IPUC approved an Idaho Power request for authorization to defer the difference between the revenue credits
in the last two general rate cases and the amount of OATT revenues Idaho Power has received since March 2008 and expects to
receive though May 20 i O. The IPUC order authorizes Idao Power to amortize the unecovered trnsmission revenues on a
stright-line basis over a thee-year period begining Janua 1,2011 and did not authorize a caring charge on the balance. Based on
actual and projected transmission revenues from Marh 2008 thugh May 2010, Idaho Power recorded a $4.7 millon regulatory asset
in 2009 for potential futue recovery.
Idaho Power has fied a request for rehearing of the FERC order and is taing additional measures to address the revenue shortfall. If
the FERC issues are resolved in Idaho Power's favor, Idao Power wil reduce the deferrL.
Pension Expense
In the 2003 Idaho general rate case, the IPUC disallowed recovery of pension expense because there were no current cash
contrbutions being made to the pension plan. On June I, 2007, the IPUC issued an order authorizing Idaho Power to account for its
defined benefit pension expense on a cash basis, and to defer and account for pension expense as a regulatory asset. On Februry 17,
20 i 0, the IPUC approved a recovery methodology that would permit Idaho Power to include in futue rate cases a reasonable
amortization and recovery of cash contrbutions. Idaho Power deferred approximately $29 milion, $8 milion and $3 milion of
pension expense to a regulatory asset in 2009,2008, and 2007 respectively. Deferred pension costs are expected to be amortized to
expense to match the revenues received when futu pension contrbutions are recovered through rates. Idaho Power does not receive
a caring charge on the curent deferrl balance. A caing charge wil be recorded on the difference between actual cash
contrbutions and the recovery of those amounts in rates.
Idaho Energ Effciency Rider (Rider)
Idaho Power's Rider is the chief fuding mechanism for Idaho Power's investment in energy effciency, conservation, and demand
response progras. Effective June 1,2009, Idaho Power collects 4.75 percent of base revenues, or approximately $29-$33 milion
annually, under the Rider. Idaho Power collected 2.5 percent of base revenues from June 2008-May 2009 and 1.5 percent prior to
I FERC FORM NO.1 (ED. 12-88)Page 123.12
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/1212010 2009/04
NOTES TO FINANCIAL STATEMENTS (Continued)
June 2008. Energy effciency progr expenditures are reported as an operating expense with an equal amount of revenues recorded
in other revenues, resulting in no net impact on earings. The cumulative variance between expenditures and amounts collected
through the rider is recorded as a regulatory asset or liability pending futue collection from or obligation to customers. An asset
balance indicates that Idaho Power has spent more than collected and a liabilty balance indicates that Idaho Power has collected more
than it has spent. At December 31,2009, Idaho Power's rider balance was a regulatory asset of$1 i millon.
In the 2008 general rate case, Idaho Power requested that the IPUC explicitly find that Idaho Power's expenditures between 2002 and
2007 of $29 milion of funds obtained from the Rider were prudently incurd and no longer subject to potential disallowance. In
2009, the IPUC approved a stipulation identifYing $14.3 milion of Rider fuding as prudent, and on Januar 25, 2010, Idao Power
and the IPUC staff fied a stipulation for approval by the IPUC to find the remaining expenditures through 2007 were prudently
incured.
On October 5, 2009, Idaho Power and other investor-owned electric utilties serving in Idaho began a series of many infonnal public
workshops with the IPUC Staff to discuss how energy effciency evaluation and prudency wil be detennined on a prospective basis.
As a result, a Memorandum of Understading written by Staff, Idaho Power and other investor-owned electric utilties in Idaho has
been signed outlining a process for future energy effciency expenditu approval. This document was fied with the IPUC on Januar
25,2010.
4. LONG-TERM DEBT
The following table summarizes long-tenn debt at December 31:
First mortgage bonds:
7.20% Series due 2009
6.60% Series due 2011
4.75% Series due 2012
4.25% Series due 2013
6.025% Series due 2018
6.15% Series due 2019
4.50% Series due 2020
6% Series due 2032
5.50% Series due 2033
5.50% Series due 2034
5.875% Series due 2034
5.30% Series due 2035
6.30% Series due 2037
6.25% Series due 2037
Total first mortgage bonds
Pollution control revenue bonds:
Variable Rate Series 2003 due 2024( 1)
Varable Rate Series 2006 due 2026(1)
5.15% Series due 2024(1)
5.25% Series due 2026(1)
Variable Rate Series 2000 due 2027
Total pollution control revenue bonds
American Falls bond guaantee
Milner Dam note guarantee
Unamortized discount - net
Tenn Loan Credit Facilty
Purchase of pollution control revenue bonds
IFERC FORM NO.1 (ED. 12-88)
2009 2008
(thousands of dollars)
$$
120,000
100,000
70,000
120,000
100,000
130,000
100,000
70,000
50,000
55,000
60,000
140,000
100,000
1,215,000
80,000
120,000
100,000
70,000
120,000
100,000
70,000
50,000
55,000
60,000
140,000
100,000
1,065,000
49,800
116,300
49,800
116,300
4,360
170,460
19,885
8,509
(3,060)
4,360
170,460
19,885
9,573
(3,163)
166,100
(166,100)
Page 123.13
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Oriinal (Mo, DB, Yr)
Idaho Power Company (2) A Resubmission 041212010 2009(04
NOTES TO FINANCIAL STATEMENTS (Continued)
Total Idaho power oiitst;mdjng debt2)$1,410,794 $1,261,755
(I) Humboldt County and Sweetwater County Pollution Control Revenue bods ar secur by firs mortage bonds, bringing the total first
mortgage bonds outstading at December 31,2009, to $1.81 billon.
(2) At December 31,2009 and 2008, the overl effective cost of Idao Power's outstanding debt was 5.76 percent and 5.59 percent,
respectively.
At December 3 1,2009, the matuties for the agggate amount oflong-term debt outstanding were (in thousands of dollars):
2010 20ll 2012 2013 2014 Thereafter
$1,064 $ 121,064 $ 101,064 $ 71,064 $1,064 $1,118,534
Long-Term Financing
On March 30, 2009, Idaho Power issued $100 milion of its 6.15% first mortgage bonds, due April 1,2019. On November 20,2009,
Idaho Power issued $130 milion of its 4.5% frrt mortgage bonds, due March I, 2020. Idao Power used the net proceeds from the
two bond issuances to repay short-term debt and to repay $80 milion of its 7.20 % frrst mortgage bonds that matued on December I,
2009. As of December 3 I, 2009, Idao Power had issued all securties remaining registered under its shelf registrtion statement.
Mortgage: As of December 3 I, 2009, Idaho Power could issue under the mortgage approximately $43 I milion of additional fit
mortgage bonds based on total unfunded propert additions of approximately $7 I 9 milion. Idaho Power could issue an additional
$612 millon of fit mortgage bonds based on retired fit mortgae bonds. These amounts ar fuher limited by the maximum
amount offrrt mortgage bonds set fort in the morte discussed below.
The mortgage secures all bonds issued under the indentu equally and ratably, without preference, priority or distinction. Firt
mortgage bonds issued in the futue wil also be secured by the mortgage. The lien of the indentue constitutes a frrt mortgage on all
the properties ofldaho Power, subject only to certain limited exceptions including liens for taxes and assessments that are not
delinquent and minor excepted encumbrances. Certin of the properties of Idaho Power are subject to easements, leases, contrcts,
covenants, workmen's compensation awards and similar encumbraces and minor defects and clouds common to properties. The
mortgage does not create a lien on revenues or profits, or notes or accounts receivable, contrcts or choses in action, except as
permitted by law during a completed default, securties or cash, except when pledged, or merchandise or equipment manufactured or
acquired for resale. The mortgage creates a lien on the interest ofldao Power 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 ofldaho Power. The
mortgage requies Idaho Power to spend or appropriate 15 percent of its anual gross operating revenues for maintenance, retirement
or amortization of its properties. Idao Power may, however, anticipate or make up these expenditures or appropriations within the
five years that imediately follow or precede a paricular year.
On February 17,2010, Idaho Power entered into the Fort-fift Supplemental Indentue, dated as of February 1,2010, to the Indentue
of Mortgage and Deed of Trust, dated as of October I, 1937, between Idaho Power and Deutsche Ban Trust Company Americas
(formerly known as Baners Trut Company) and R.G. Page, as Trustees (Staley Burg, successor individual trstee) for the purpose
of increasing the maximum amount of frrst mortgage bonds issuable by Idaho Power from $ 1.5 to $2.0 bilion. The amount issuable is
also restricted by propert, earings and other provisions of the mortgage and supplemental indentues to the mortgage. Idaho Power
may amend the indentu and increase this amount without consent of the holders of the first mortgage bonds. The indentue requires
that Idaho Power's net earings must be at least twice the anual interest requirements on all outstading debt of equal or prior ra
including the bonds that Idaho Power may propose to issue. Under certin circumstances, the net earnings test does not apply,
including the issuance of refuding bonds to retire outstading bonds that mature in less than two year or that are of an equal or higher
interest rate, or prior lien bonds.
Pollution Control Revenue Refunding Bonds and Term Loan Credit Agreement: On April 3, 2008, Idaho Power made a
mandatory purchase of two series of Pollution Control Revenue Refunding Bonds issued for the benefit of Idaho Power, the $1 16.3
IFERC FORM NO.1 (ED. 12-88) Page 123.14
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ß An Original (Mo, Da, Yr)
Idaho Power Company (2) A Resubmission 04/1212010 2009/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
millon aggegate principal amount of Pollution Control Revenue Refunding Bonds Series 2006 issued by Sweetwater County,
Wyoming due 2026 and the $49.8 millon aggegate principal amount of Pollution Control Revenue Refuding Bonds Series 2003
issued by Humboldt County, Nevada due 2024 (together the Pollution Control Bonds). Idaho Power initiated this transaction in order
to adjust the interest rate period of the Pollution Control Bonds from an auction interest rate period to a weekly interest rate period,
effective April 3, 2008. This change was made to mitigate the higher-than-anticipated interest costs in the auction mode, which was a
result of the financial guarantor's credit ratings deterioration.
On August 20,2009, J.P. Morgan Securties Inc. as the Remarketing Agent, purchased the Pollution Contrl Bonds from Idaho
Power
for remarketing to the public. The Humboldt County Bonds car a 5.15 percent term interest rate and matue on December 1, 2024.
The Sweetwater County Bonds carr a 5.25 percent term interest rate and mature on July 15,2026. The Pollution Control Bonds are
not subject to redemption for 10 years, except for extrordinar optional and mandatory redemption prior to matuty, in each case at
100 percent of the principal amount, plus accrued interest if any to the date of redemption. In connection with the remarketing of the
Pollution Control Bonds, the fmancial guarnty insurace policies securg the Pollution Control Bonds were terminated.
On August 25,2009, Idaho Power used proceeds from the reofferig of the Pollution Control Bonds and additional corporate fuds to
prepay its $170 milion loan under a Term Loan Credit Agreement dated as of Februar 4,2009, among JPMorgan Chase Ban, N.A.,
as administrtive agent and lender, Ban of America, N.A., Union Ban, N.A. and Wachovia Bank, National Association, as lenders.
5. NOTES PAYABLE:
Idaho Power has a $300 milion credit facilty each of which expires on April 25, 2012. Commercial paper may be issued up to the
amounts supported by the ban credit facilties. Under these facilties the companies pay a facilty fee on the commitment, quarterly in
arars, based on its rating for senior unsecured long-term debt securties without third-part credit enhancement as provided by
Moody's and S&P. At December 31,2009, Idaho Power had regulatory authority to incur up to $450 milion of short-term
indebtedness.
At December 31,2009, no loans were outstading on Idao Power's facilties. Balances and interest rates ofIdaho Power's short-term
borrowings were as follows at December 31 (in thousands of dollars):
2009 2008
(thousands of dollars)
Balances:At the end of year $
Average during the year $
Weighted-average interest rate:
At the end of year
$
46,386 $
112,850
151,192
4.89%
6. COMMON STOCK
In 2009 and 2008, IDACORP contrbuted $20 milion and $37 milion respectively, ofadditional equity to Idaho Power. No
additional shares of Idaho Power common stock were issued.
Idaho Power's aricles of incorporation contain restrictions on the payment of dividends on its common stock if preferred stock
dividends are in arrear. Idaho Power has no preferred stock outstanding.
Idao Power must obtain approval of the OPUC before it could directly or indirectly loan fuds or issue notes or give credit on its
books to IDACORP.
7. STOCK-BASED COMPENSATION
Through its parent company IDACORP, Idaho Power has three share-based compensation plans. IDACORP's employee plans are the
2000 Long-Term Incentive and Compensation Plan (L TICP) and the 1994 Restricted Stock Plan (RSP). These plans are intended to
IFERC FORM NO.1 (ED. 12-88) Page 123.15
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ß An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 041212010 2009/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
align employee and shareholder objectives related to IDACORP's long-term growt. IDACORP also has one non-employee plan, the
Director Stock Plan (DSP). The purse of the DSP is to increase diretors' stock ownership though stock-based compensation.
The L TICP (for offcers, key employees and dirctors) permits the grt of non qualified stock options, restricted stock, performance
shares, and several other tyes of stock-based awads. The RSP peits only the grt of restricted stock or performance-based
restricted stock. At December 3 I, 2009, the maximum number of shars available under the L TICP and RSP were 1,602,259 and
25,515, respectively.
Stock awards: Restricted stock awards have three-year vesting periods and entitle the recipients to dividends and voting rights.
Unvested shares are restricted as to disposition and subject to forfeitue under certin circumstances. The fair value of these awards is
based on the market price of common stock on grt date and is charged to compensation expense over the vesting period, based on
the number of shares expected to vest.
Performance-based restrcted stock awards have thee-year vesting period and entitle the recipients to voting rights. Unvested shares
are restricted as to disposition, subject to forfeitu under certin cirumstaces, and subject to meeting specific performance
conditions. Based on the attainent of the performance conditions, the ultiate award can rage from zero to 1 50 percent of the taget
awar. Dividends ar accrued and paid out only on shares that eventuly vest.
The performance awards are based on two metrcs, cumulative earings per share (CEPS) and total shareholder retu (TSR) relative
to a peer group. The fair value of the CEPS portion is based on the maret value at the date of grant, reduced by the loss in time-value
of the estimated futue dividend payments, using an expected quarrly dividend of $0.30. The fair value of the TSR portion is
estimated using a statistical model that incorporates the probabilty of meeting performance tagets based on historical returns relatiye
to the peer group. Both performance goals are measurd over the thee-year vesting period and are charged to compensation expense
over the vesting period based on the number of shares expected to vest.
A sumar of restrcted stock and performance shar activity is presented below. Idaho Power share amounts represent the portion of
IDACORP amounts related to Idao Power employees:
Nonvested shares at Januar i, 2009
Shars grted
Shares forfeited
Shares vested
Nonvested shares at December 3 i, 2009
Number of
Shares
303,257
144,143
(27,158)
(134,207)
286,035
Weighted-
Average
Grant Date
Fair Value
$ 26.68
21.49
23.43
26.42
$ 24.49
The total fair value of shares vested during the year ended December 3 i, 2009 and 2008 was $3.9 milion and $0.8 milion,
respectively. At December 31,2009, IDACORP had $3.6 milion of total uncognized compensation cost related to nonvested
share-based compensation that was expected to vest. Idao Power's share of this amount was $3.4 milion. These costs are expected
to be recognized over a weighted-average period of 1.67 year. Idao Power uses IDACORP's original issue and/or treasury shares for
these awards.
Stock options: Stock option awards are granted with exercise prices equal to the market value of the stock on the date of grant. The
options have a term of 10 years from the grt 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. The following table presents information about options granted and exercised (in thousands of
dollar, except for weighted-average amounts):
Fair value of options vested
IFERC FORM NO.1 (ED. 12-88)
2009
$ 208
2008
$ 353
Page 123.16
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2lAn Original (Mo, Oat Yr)
Idaho Power Company (2)A Resubmission 04/12/2010 2oo9/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Intrinsic value of options exercised
Cash received from exercises
Tax benefits realized from exercises
204
591
80
182
707
71
As of December 31,2009, Idaho Power had recognized all compensation cost related to stock options. Idaho Power uses IDACORP's
uses original issue and/or treasury shares to satisfy exercised options.
Idaho Power's stock option trsactions in IDACORP are summarized below. Idaho Power shar amounts represent the portion of
IDACORP amounts related to Idaho Power employees:
Outstading at December 31, 2008
Exercised
Forfeited
Expired
Outstading at December 31, 2009
Number
of
Shares
576,996
(25,800)
(3,632)
(133,600)
413,964
Weighted-
Average
Exercise
Price
$ 34.34
22.92
29.75
39.86
$ 33.31
Weighted
Average
Remaining
Contractual
Term
3.67
Aggregate
Intrinsic
Value
(OOOs)
$ 611
2.96 $ 862
Vested or expected to vest at December 31,
2009
Exercisable at December 31, 2009
413,932 $33.31 2.96 $862
397,903 $33.45 2.87 $826
Compensation Expense: 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 Idaho Power for those costs associated with Idaho Power's employees (in thousands of
dollars):
Compensation cost
Income tax benefit
$
$
2009
3,986 $
1,587 $
2008
3,683
1,440
No equity compensation costs have been capitalized.
8. COMMITMENTS:
Purchase Obligations:
At December 31,2009, Idaho Power had the following long-term commitments relating to purchases of energy, capacity, transmission
rights and fuel:
2010 2011 2012 2013 2014 Thereafter
(thousands of dollars)
Cogeneration and power production $210,999 $229,740 $124,051 $113,884 $114,850 $1,680,001
Power and trnsmission rights 44,298 21,979 8,699 3,296 2,404 7,612
Fuel 64,132 64,130 52,671 54,032 53,136 95,346
IFERC FORM NO.1 (ED. 12-88)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 04/1212010 2009/04
NOTES TO FINANCIAL STATEMENTS (Continued)
As of December 31,2009, Idaho Power had signed agreements to purchase energy from 96 CSPP facilties with contrcts ranging from
one to 30 year. Eighty of these facilties, with a combined nameplate capacity of298 MW, were on-line at the end of2009; the other
16 facilties under contract, with a combined nameplate capacit of 266 MW, are projected to come on-line during 20 I 0 and 201 1.
The majority of the new facilties wil be wind resources which wil generate on an intennittent basis. Durig 2009, Idaho Power
purchased 970,419 megawatt-hours (MWh) from these projects at a cost of$59 milion, resulting in a blended price of 6.1 cents per
kilowatt hour. Idaho Power purchased 756,014 megawatt-hour at a cost of$45.9 milion in 2008.
Guarantees
Idaho Power has agreed to guartee the perfonnance of relamation activities at Bridger Coal Company of which IERCo owns a
one-third interest. This guarntee, which is renewed each December, was $63 milion at December 3 i, 2009. Bridger Coal Company
has a reclamation trst fud set aside specifically for the purose of paying these reclamation costs. At this time Bridger Coal
Company is revising their estimate of futue reclamation costs. To ensure that the reclamation trst fund maintains adequate reserves,
Bridger Coal Company has the abilty to add a per ton surcharge if it is detennined that futue liabilties exceed the trt's assets.
Because of the existence of the fund and the abilty to apply a per ton surcharge, the estimated fair value of this guatee is minimaL.
9. CONTINGENCIES
Legal Proceedings
Western Energy Proceeings at the FERC: Thughout this report the ten "western energy situation" is used to refer to the
California energy crisis that occurred durig 2000 and 2001, and the energ shortges, 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 marets to initiate proceedings seeking refuds or other fonns of relief. 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).
There are pending in the Ninth Circuit approximately 200 petitions for review of numerous FERC orders regarding the western energy
situation. Decisions in these appeals may have implications with respect to other pending cases, including those to which Idaho Power
or IE, another wholly-owned subsidiar ofIDACORP, are paries. Idao Power and IE intend to vigorously defend their positions in
these proceedings, but are unable to predict the outcome of these matters. Except as to the matters described below under "Pacific
Nortwest Refud," Idao Power and IE believe that settlement releases they have obtained that are described below under "California
Refund" and "Market Manipulation" wil restrct potential claims that might result from the disposition of the pending Ninth Circuit
review petitions and that these matters wil not have a material adverse effect on their consolidated fmancial positions, results of
operations or cash flows.
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 marets from October 2,
2000, though June 20, 2001. The FERC has issued numerous orders establishing price mitigation plans for sales in the California
wholesale electrcity market, including the methodology for detennining refuds. IE and numerous other parties have petitioned the
Ninth Circuit for review of the FERC's orders on California refuds. As additional FERC orders have been issued, fuer petitions
for review have been fied before the Ninth Circuit, which from time to time has identified discrete cases that can proceed to briefing
and decision while it stayed action on the other consolidated cases.
On May 22, 2006 the FERC approved an Offer of Settlement beeen and among IE and Idaho Power, the California Paries (Pacific
Gas & Electrc Company, San Diego Gas & Electrc Company, Southern California Edison Company, the California Public Utilties
Commission, the Califomia Electrcity Oversight Board, the California Deparent of Water Resources and the California Attorney
General) and additional paries that elected to be bound by the settlement. The settlement disposed of matters encompassed by the
California refund proceeding, as well as other claims and investigations relating to the western energy situation among and between the
paries agreeing to be bound by it. Although many market paricipants agreed to be bound by the settlement, other market paricipants,
representing a small minority of potential refund claims, initially elected not to be bound by the settlement. From time to time, as the
California Paries have reached settlements with those other market paricipants, they have elected to opt into the IE-Idaho
Power-California Paries' settlement. The settlement provided for approximately $23.7 milion ofIE's and Idaho Power's estimated
$36 milion rights to accounts receivable from the Cal ISO and the California Power Exchange (CaIPX) to be assigned to an escrow
account for refuds and for an additional $ 1.5 milion of accounts receivable to be retained by the CalPX until the conclusion of the
IFERC FORM NO.1 (ED. 12-88) Page 123.18
Name of Respondent This Report is:Date of Report YeanPeriod of Report
(1) ß An Original (Mo, Da, Yr)
Idaho Power Company ! (2) A Resubmission 04/12/2010 2009/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
litigation. The additional $ 1.5 milion of accounts receivable retained by the CalPX is available to fund the claims of non-settling
paries if they prevail in the remaining litigation of these California market matters. Any additional amounts owed to non-settling
paries would be funded by other amounts owed to IE and Idaho Power by the Cal ISO and CaIPX, or dirctly by IE and Idaho Power,
and any excess fuds remaining at the end of the case would be returned to IE and Idaho Power. The remaining IE and Idao Power
receivables were paid to IE and Idaho Power under the settlement.
In an August 2006 decision, the Ninth Circuit ruled that all transactions that occured within the CalPX and the Cal ISO markets were
proper subjects of the refud proceeding. In that decision the Ninth Circuit refused to expand the proceedings into the bilateral .
market, approved the refud effective date as October 2, 2000, required the FERC to consider claims that some market participants had
violated governing taff obligations at an earlier date than the refud effective date, and expanded the scope of the refund proceeding
to include transactions within the CalPX and Cal ISO markets outside the limited 24-hour spot market and energy exchange
trctions. Par of the decision exposed sellers to increased claims for potential refunds. The Ninth Circuit issued its mandate on
Apnl 15,2009, thereby offcially retuing the cases to the FERC for fuer action consistent with the court's decision.
On November 19, 2009, the FERC issued an order to implement the Ninth Circuit's remand. The remand order established a trial-tye
hearg in which participants wil be permitted to submit information regarding (i) specified taff violations committed by any public
utilty seller from January 1, 2000 - October 2, 2000 resulting in a transaction that set a market clearing pnce for the trading penod
when the violation occured and (ii) claims for refunds for multi-day transactions and energy exchange trsactions entered into during
the refund penod (October 2,2000 - June 20, 2001). Numerous parties including IE and Idaho Power fied motions to clarfy the
FERC's order. Although IE and Idaho Power are unable to predict when or how FERC wil rule on these motions, the effect of the
remand order for IE and Idaho Power is confined to the minority of market paricipants that are not bound by the IE-Idaho
Power-California Paries' settlement described above. Accordingly, IE and Idaho Power believe the remanded proceedings wil not
have a matenal adverse effect on their consolidated financial positions, results of operations or cash flows.
In 2005, the FERC established a frmework for sellers wanting to demonstrte that the generally applicable FERC refud methodology
interfered with the recovery of costs. IE and Idaho Power made such a cost fiing, which was rejected by the FERC. On June 18,
2009, FERC issued an order stating that it was not ruling on IE's and Idaho Power's request for rehearing of the cost fiing rejection
because their request had been withdrwn in connection with the IE-Idaho Power-California Paries' settlement. On July 8, 2009 IE
and Idaho Power sought furter rehearing at the FERC because their withdrawal pertained only to the parties with whom IE and Idaho
Power had settled. On June 18, 2009, in a separate order, the FERC ruled that only net refud recipients were responsible for the costs
associated with cost filings. While most net refund recipients are bound by the settlement, until the Cal ISO completes its refund
calculations, it is uncertain whether there are any net refud recipients who are not bound by the settlement If there are no such
paries, then IE's and Idaho Power's request for reheanng wil be moot. FERC has not yet ruled on the request for reheanng. IE and
Idaho Power are unable to predict how or when the FERC might rule, but the effect of any such ruling is confined to obligations of IE
and Idaho Power to the small minority of claims of market paricipants that are not bound by the settlement. Accordingly, IE and
Idaho Power believe this matter wil not have a matenal adverse effect on their consolidated financial positions, results of operations or
cash flows.
Market Manipulation: On June 25, 2003, the FERC ordered more than 50 entities that paricipated in the western wholesale power
marets between January 1,2000, and June 20,2001, including Idaho Power, to show cause why certain trading practices did not
constitute gaming ("gaming") or other forms of proscnbed maret behavior in concert with another par ("parership") in violation of
the Cal ISO and CalPX Tarffs. In 2004, the FERC dismissed the "partership" show cause proceeding against Idaho Power. Later in
2004, the FERC approved a settlement of the "gaming" proceeding without finding of wrongdoing by Idaho Power.
The orders establishing the scope of the show cause proceedings are presently the subject of review petitions in the Ninth Circuit.
Although IE and Idaho Power are unable to predict how or when the Ninth Circuit wil act on these review petitions, in light of the
settlement described above, IE and Idaho Power believe this matter wil not have a material adverse effect on their consolidated
financial positions, results of operations or cash flows.
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 1,2000, through October 1,2000, but the FERC terminated its investigations as to
Idaho Power on May 12, 2004. California governent agencies and California investor-owned utilties have appealed the FERC's
termination of this investigation as to Idaho Power and more than 30 other market participants. IE and Idaho Power are unable to
I FERC FORM NO.1 (ED. 12-88)Page 123.19
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 041212010 2009/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
predict the outcome of these petitions for review proceedings, but believe that the settlement releases govern any potential claims that
might arise and that this matter wil not have a material adverse effect on their consolidated financial positions, results of operations or
cash flows.
Pacific Northwest Refud: On July 25,2001, the FERC issued an order establishing a proceeding separate from the California refud
proceeding to detennine whether there may have been unjust and uneasonable charges for spot market sales in the Pacific Nortwest
durng the period December 25,2000, though June 20, 2001, beause the spot maret in the Pacific Northwest was affected by the
dysfunction in the California market. In 2003, the FERC tenninated the proceeding and declined to order refuds, but in 2007 the
Ninth Circuit issued an opinion, in Port of Seattle, Washington v. FERC, remanding to the FERC the orders that declined to requir
refunds. The Ninth Circuit's opinion instrcted the FERC to consider whether evidence of market manipulation would have altered the
agency's conclusions about refuds and directed the FERC to include sales to the California Departent of Water Resources (CDWR)
in the scope of proceeding. The Ninth Circuit offcially returned the case to the FERC on April 16, 2009. On September 4, 2009, IE
and Idao Power joined with a number of other paries in a joint petition for a writ of certiora to the U.S. Supreme Court, which was
denied on Janua 11,2010.
In separte fiings, the California Parties, which no longer include the California Electrcity Oversight Board, and the City of Tacoma,
Washington and the Port of Seattle, Washington asked the FERC to take actions to reorganiz and restrctue the case so that they may
pursue claims that all spot market sales in the Cal ISO and CalPX markets and in the Pacific Northwest from Januar 1,2000 through
June 20, 2001 should be repriced, and thereby become subject to refud, becaus market manipulation and tariff violations affected
spot market prices. This would expand the scope of the refud period in the Pacific Northwest proceeding from the December 25,
2000 though June 20, 200 i period previously considered by the FERC. On May 22, 2009, the California Parties fied a motion with
the FERC to sever the CDWR sales from the remainder of the Pacific Nortwest proceedings and to consolidate the CDWR sales
portion of the Pacific Northwest case with ongoing proceedings in cases that IE and Idao Power have settled and with a new
complaint filed on May 22, 2009 by the California Attorney General against paries with whom the California Parties have not settled
(Brown Complaint). IE and Idaho Power, along with a number of other pares, filed their opposition to the motion of the California
Paries. Many other paries also fied responses to the motion ofthe California Paries. The City of Tacoma, Washington and the Port
of Seattle, Washington filed a motion on August 4,2009 with the FERC in connection with the California refud proceeding, the
Lockyer remand pending before the FERC (involving claims offailure to fie quarerly trsaction reports with the FERC, from which
IE and Idaho Power previously were dismissed), the Brown Complaint and the Pacific Nortwest refud remand proceeding. The City
of Tacoma and the Port of Seattle motion asks the FERC, either on a sumar basis or after new evidentiar hearngs, to require
refuds from all sellers in the Pacific Nortwest spot marets for the expanded period (Januar 1,2000 through June 20, 2001). IE
and Idaho Power joined with a number of other sellers in the Pacific Nortwest marets during 2000 and 2001 in opposing the motion
of the City of Tacoma and the Port of Seattle. IE and Idao Power intend to vigorously defend their positions in these proceedings, but
are unable to predict the outcome of these matters or estimate the impact these matters may have on their consolidated fmancial
positions, results of operations or cash flows.
Western Shoshone National Council: On April 10, 2006, the Western Shoshone National Council (which purort to be the
governing body ofthe Western Shoshone Nation) and certin of its individual tribal members filed a Firt Amended Complaint and
Demand for Jur Trial in the U.S. Distrct Court for the District of Nevada, naming Idao Power and other unrelated entities as
defendants. Plaintiffs allege that Idaho Power's ownership interest in certin land, minerals, water or other resources was converted
and frudulently 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. Distrct Cour granted the defendats' motion to dismiss statig that the plaintiffs' claims are bared by the
fmality provision of the Indian Claims Commission Act, and entered judgment in favor ofIdaho Power on Januar 25, 2008. Plaintiffs
appealed the district court's decision to the Ninth Circuit which affined the distrct cour's dismissal of the action. The time within
which plaintiffs could pursue fuer review has expired.
Sierra Club Lawsuit-Bridger: In Februar 2007, the Sierra Club and the Wyoming Outdoor Council filed a complaint against
PacifiCorp in the U.S. District Cour for the District of Wyoming alleging 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 by the flue gas of a power
plant. The complaint alleged thousands of opacity pennit violations by PacifiCorp and sought a declartion that PacifiCorp had
violated opacity limits, a pennanent injunction ordering PacifiCorp to comply with such limits, civil penalties of up to $32,500 per day
I FERC FORM NO.1 (ED. 12-88)Page 123.20
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ß An Original (Mo, Da, Yr)
Idaho Power Company I (2) A Resubmission 0411212010 2009/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
per violation, and reimburement of plaintiffs' costs of litigation, including reasonable attorneys' fees. Idaho Power is not a part to
this proceeding but has a one-third ownership interest in the plant. PacifiCorp owns a two-thirds interest in and is the operator of the
plant. On February 10,2010, PacifiCorp and plaintiffs reached an agreement in principle to the settlement ofthe lawsuit in its entirety.
The settlement is subject to the approval of the Environmental Protection Agency and the cour. If approved, the settlement wil not
have a material adverse effect on Idaho Power's consolidated financial positions, results of operations or cash flows.
Sierra Club Lawsuit - Boardman: In September 2008, the Sierra Club and four other non-profit corporations fied a complaint
against Portland General Electrc Company (PGE) in the U.S. Distrct Court for the District of Oregon alleging opacity permit limit
violations at the Boardman coal-fired plant located in Morrow County, Oregon. The complaint also alleged violations of the Clean Air
Act, related federal regulations and the Oregon State Implementation Plan relating to PGE's constrction and operation ofthe plant.
The complaint sought a declaration that PGE had violated opacity limits, a permanent injunction orderingPGE to comply with such
limits, injunctive relief requiring PGE to remediate alleged environmental damage and ongoing impacts, civil penalties of up to
$32,500 per day per violation, and reimbursement of plaintiffs' costs of litigation, including reasonable attorneys' fees. Idao Power 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 plan.
On December 5, 2008, PGE fied a motion to dismiss nine of the twelve claims asserted by plaintiffs in their complaint, alleging
among other arguents that certin claims are bared by the statute of limitations or fail to state a claim upon which the court can grant
relief. On September 30, 2009, the court denied most ofPGE's motion to dismiss. Idaho Power continues to monitor the status of this
matter but is unable to predict its outcome or what effect this matter may have on its consolidated financial position, results of
operations or cash flows.
Snake River Basin Adjudication: Idaho Power is engaged in the Snake River Basin Adjudication (SRBA), a general stream
adjudication, commenced in i 987, to define the natue and extent of water rights in the Snake River basin in Idaho, including the water
rights of Idaho Power.
On March 25,2009, Idaho Power and the State ofIdaho (State) entered into a settlement agreement with respect to the 1984 Swan
Falls Agreement and Idaho Power's water rights under the Swan Falls Agreement, which settlement agreement is subject to certin
conditions discussed below. The settlement agreement wil also resolve litigation between Idaho Power and the State relating to the
Swan Falls Agreement that was filed by Idaho Power on May i 0, 2007, with the Idaho Distrct Cour for the Fift Judicial Circuit,
which has jurisdiction over SRBA matters including the Swan Falls case.
The settlement agreement resolves the pending litigation by c1ariYing that Idaho Power's water rights in excess of minimum flows at
its hydroelectric facilties between Milner Dam and Swan Falls Dam are subordinate to futue upstream beneficial uses, including
aquifer recharge. The agreement commits the State and Idaho Power to further discussions on importt water management issues
concerning the Swan Falls Agreement and the management of water in the Snake River Basin. It also recognizes that water
management measures that enhance aquifer levels, springs and river flows, such as aquifer recharge projects, benefit both agricultul
development and hydropower generation and deserve study to determine their economic potential, their impact on the environment and
their impact on hydropower generation. These wil be a part of the Comprehensive Aquifer Management Plan (CAMP), approved by
the Idaho Water Resource Board for the Eastern Snake Plain Aquifer (ESPA), which includes limits on the amount of aquifer recharge.
Idaho Power is a member of the ESPA CAMP advisory committee and implementation committee.
On April 24, 2009, the Governor ofIdaho signed into law legislation approving provisions contained in the settlement agreement. On
May 6, 2009, as par of the settlement, Idaho Power, the Governor ofIdaho and the Idaho Water Resource Board executed a
memoradum of agreement relating to future aquifer recharge effort and further assurces as to limitations on the amount of aquifer
recharge. Idao Power and the State also fied a joint motion to the SRBA court to dismiss the Swan Falls case and enter the stipulated
water right decrees set forth in the settlement agreement. Parties representing groundwater users in the Eastern Snake Plain Aquifer
objected to some of the language proposed by Idaho Power and the State relating to water rights in the decrees to be entered by the
SRBA court as contemplated by the Settlement Agreement. Specifically, the concerns relate to the language describing the
subordination of the rights and its interplay with the original Swan Falls settlement document and implementing legislation. On
Januar 4, 20 I 0, the cour issued an order approving the overall settlement subject to certain modifications to the draft water right
decrees proposed by the company and the state. The company is working with the state and the paries to reach agreement consistent
with the court's order regarding the language of the decrees.
IFERC FORM NO.1 (ED. 12-88) Page 123.21
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 04/1212010 2009/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
U.S. Bureau of Reclamation: Idaho Power filed a complaint on October 15, 2007 and an amended complaint on September 30, 2008
in the U.S. Distrct Court of Federal Claims in Washington, D.C. against the U.S. Bureau of Reclamation. The complaint relates to a
contract right for delivery of water to its hydropower projects on the Snake River to recover damages from the U.S. for the lost
generaion resulting from reduced flows and a prospective declartion of contrctual nghts so as to prevent the U.S. from continued
failure to fulfill its contrctual and fiduciary duties to Idaho Power. In i 923, Idaho Power and the U.S. entered into a contrct that
faciltated the development of the American Falls Reservoir by the U.S. on the Snake River in southeast Idao. This 1923 contract
entitles Idaho Power to 45,500 acre-feet of primar storage capacity in the reservoir and 255,000 acre-feet of secondar storage that
was to be available to Idao Power between October i of any year and June i 0 of the following year as necessar to maintain specified
water flows at Idaho Power's Twin Falls power plant below Milner Dam. Idao Power believes that the U.S. has failed to deliver this
secondar storage, atthe specified flows, since 2001. Discovery is scheduled to be completed by March 3,2010. Tnal of the matter
has not been scheduled. Idaho Power is unable to predict the outcome of this action.
Oregon Trail Heights Fire: On August 25, 2008, a fie ignited beneath an Idao Power distrbution line in Boise, Idao. It was
faned by high winds and spread rapidly, resultig in one deat, the destrction of 10 homes and daage or alleged fire related losses
to approximately 30 others. Following the investigation, the Boise Fir Deparent determined that the fire was linked to a piece of
line hardware on one ofIdaho Power's distribution poles and that high winds contrbuted to the fire and its resultant damage.
Idaho Power has received notice of claims from a number of the homeowners and their insurers and while it has continued
investigation of these claims, Idaho Power has reached settlements with a number of the individuals or their insurers who have alleged
damages resulting from the fie. Idaho Power is insured up to policy limits againt liabilty for claims in excess of its self-insured
retention. Idaho Power has accrued 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 fiancial position, results of operations or cash flows.
Other Legal Proceedings: From time to tie Idao Power is par to legal claims, actions and proceedings in addition to those
discussed above. Resolution of any of these matters wil tae time and the companies canot predict the outcome of any of these
proceedings. The companies believe that their reserves ar adequate for these mattrs and that resolution of these matters, taing into
account existing reserves, wil not have a material adverse effect on Idao Power's fmancial position, results of operations or cash
flows.
10. BENEFIT PLANS:
Pension Plans
Idaho Power has a noncontributory defined benefit pension plan covering most employees. The benefits under the plan are based on
year of service and the employee's final average earings. Idao Power's policy is to fud, with an independent corporate trtee, at
least the minimum required under the Employee Retirement Income Securty Act of 1974 (ERISA) but not more than the maximum
amount deductible for income tax puroses. Idaho Power was not required to contrbute to the plan in 2009 or 2008. The
market-related value of assets for the plan is equal to the fair value of the asse. Fair value is determined by utilzing publicly quoted
market values and independent pricing services depending on the natu of the asset, as reported by the trstee/custodian of the plan.
In addition, Idaho Power has a nonqualified, deferred compensation plan for certin senior management employees and directors called
the Senior Management Security Plan (SMSP). At December 31,2009 and 2008, approximately $40.3 milion and $39.9 milion,
respectively, of life insurnce policies and investments in maretable securities, all of which are held by a trtee, were designated to
satisfY the projected benefit obligation ofthe plan but do not qualifY as plan assets in the actuarial computation of the funded statu.
The following table sumarzes the changes in benefit obligations and plan assets of these plans:
Pension Plan SMSP2009 2008 2009 2008
(thousands of dollars)
Change in benefit obligation:
Benefit obligation at January i
Service cost
$464,416 $
16,514
420,526 $
14,920
48,393 $
1,610
43,153
1,278
IFERC FORM NO.1 (ED. 12-88) Page 123.22
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Moi Da, Yr)
Idaho Power Company (2)A Resubmission 04112/2010 2oo9/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Interest cost
Actuarial loss
Benefits paid
Plan amendments
Benefit obligation at December 3 I
Change in plan assets:
Fair value at Januar i
Actual retu on plan assets
Benefits paid
Fair value at December 3 I
Funded statu at end of year
Amounts recognized in the statement of
financial position consist of:
Oter current liabilties
Noncurent liabilties (I)
Net amount recognized
Amounts recognized in accumulated other
comprehensive income consist of:
Net loss
Pnor service cost
Subtotal
Less amount recorded as regulatory asset
Net amount recognized in accumulated
other comprehensive income $ $ $ 16,562 $
Accumulated benefit obligation $ 425,744 $ 385,002 $ 48,563 $
(I) Noncurrent liabilities are contained in Idaho Power's Balance Sheets under "Other liabilties" and "Other defered credits,"
repectively.
27,865
16,193
(18,244)
506,744
295,324
36,394
(18,244)
313,474
$ (193,270)
$
26,393
19,547
(16,970)
2,854
3,156
(3,294)
464,416 52,719
407,970
(95,676)
(16,970)
295,324
$ (169,092)$ (52,719) $
$(3,244) $
(49,475)
(52,719) $
(193,270) (169,092)
$ (193,270) $ (169,092) $
$150,196
2,505
152,701
(152,701)
$$14,585
1,977
16,562
155,289
3,155
158,444
(158,444)
The following table shows the components of net periodic benefit cost for these plans:
Pension Plan SMSP
2009 2008 2009 2008
(thousands of dollars)
Service cost $16,514 $14,920 $1,610 $1,278
Interest cost 27,865 26,393 2,854 2,669
Expected retu on assets (23,965)(34,112)
Amortization of net loss 8,857 232 489
Amortization of prior service cost 650 650 659 192
Net periodic pension cost $29,921 $7,851 $5,355 $4,628
2,669
3,376
(2,644)
561
48,393
(48,393)
(2,883)
(45,510)
(48,393)
$12,088
2,209
14,297
14,297
44,275
In 20 i 0, Idaho Power expects to recognize as components of net periodic benefit cost $9.5 millon from amortizing amounts recorded
in accumulated other comprehensive income (or as a regulatory asset for the pension plan) as of December 31, 2009, relating to the
pension and SMSP plans. This amount consists of $7.7 milion of amortization of net loss, and $0.7 milion of amortization of pnor
service cost for the pension plan and $0.9 milion of amortization of net loss and $0.2 milion of amortization of prior service cost for
the SMSP.
The following table summarizes the expected futue benefit payments of these plans:
IFERC FORM NO.1 (ED. 12-88) Page 123.23
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) õ An Original (Mo, Da, Yr)
Idaho Power Company I (2) A Resubmission 04/1212010 2009/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
2010 20ll 2012 2013
(thousands of dollars)
22,654 $ 24,716 $
3,483 $ 3,703 $
2014 2015-2019
Pension Plan
SMSP
$
$
19,453 $
3,332 $
20,785 $
3,349 $
26,586 $
3,890 $
169,665
21,000
Pension Protection Act: In accordance with the Pension Protection Act of 2006 (PPA), and the relief provisions of the Worker,
Retiree, and Employer Recovery Act of2008 (WRRA), which was signed into law on December 23,2008, companies are required to
meet minimum fuding levels in order to avoid benefit restrictions. The WRERA also provides for asset smoothing, which allows the
use of asset averaging, including expected returns (subject to certin limitations), for a 24-month period in the determination of the
fuding requirements. Idaho Power has elected to use asset smoothing.
On March 31, 2009, the U.S. Deparent of the Treasur (Treasur) provided guidance on the selection of the corporate bond yield
cure for determining plan liabilties and allows companies to choose from a rage of months in selecting a yield cure, rather than
requirig the use of prescribed raes. The Treasur's anouncement speifically referenced 2009, but also indicated that technical
guidance wil be fortcoming to address futue year. The revisions in the PPA, WRERA, Treasur guidance, and IRS guidance
resulted in Idaho Power revising the fuded statu as of Janua 1,2009, effectively reducing or delaying the required contributions
from Idaho Power from what would otherwise be requird, and what was previously disclosed. At Janua 1,2009, Idaho Power's
pension plan was above the minimum required fuding levels as revised by the PPA, WRERA, Treasur guidance and IRS guidance,
but below the minimum required funding levels at Janua 1,2010, and is projected to stay below the minimum required funding levels
though 2015. As Idao Power's pension plan is below the minimum required fuding levels at Januar 1,2010, futue minimum
contributions are required. Based on the provisions and methodologies allowed under the PPA, WRERA, Treasur guidance and IRS
guidance, Idaho Power was not required to contrbute to their pension plan in 2009, and estimated minimum required contributions
wil be approximately $6 milion in 2010, $44 milion in 2011 $47 milion in 2012, $39 millon in 2013, and $40 milion in 2014.
Idaho Power may elect to make contrbutions earlier than the reuir dates.
The IRS and Treasur have issued fmal regulations effective October 15, 2009 tht apply to plan years begining on or after Januar I,
2010. These regulations reflect provisions added by the PPA, as amended by the WRRA. These regulations affect sponsors,
administrtors, paricipants, and beneficiaries of single employer defmed benefit pension plans. The regulations provide guidance
regarding the determination of the value of plan assets and benefit liabilties for purpses of the fuding requirements, regarding the
use of certain fuding balances maintained for those plans, and regading benefit restrictions for certain underfuded defined benefit
pension plans. These fmal regulations did not materially change existing estimates relating to pension plan contributions.
Additional legislative or regulatory measures, as well as fluctuations in fmancial market conditions, may impact funding requirements.
Idaho Power continues to monitor the legislative and regulatory environments for additional changes, evaluating them for their
potential impact on funding requirements and strtegies.
Postretirement Benefits
Idaho Power maintains a defined benefit postretirment 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 3 1,2002, ar limited to a fixed amount, which wil limit the growt ofIdaho Power's futue
obligations under this plan.
The following table sumarzes the changes in benefit obligation and plan assets (in thousands of dollar):
2009 2008
$59,648 $56,826
1,221 1,154
3,565 3,498
2,128 1,656
(3,915)(3,486)
62,647 59,648
Page 123.24
Change in accumulated benefit obligation:
Benefit obligation at January I
Service cost
Interest cost
Actual loss
Benefits paid( I )
Benefit obligation at December 31
IFERC FORM NO.1 (ED. 12-88)
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ß An Original (Mo, Da, Yr)
Idaho Power Company (2) . A Resubmission 04/1212010 2oo9/Q4
NOTËS TO FINANCIAL STATEMENTS (Continued)
Change in plan assets:
Fair value of plan assets at January 1 25,283 35,096Actual retu on plan assets 5,609 (7,834)Employer contrbutions 3,915 1,507Benefits paid(1) (3,915) (3,486)Fair value of plan assets at December 3 I 30,892 25,283
Funded status at endofyear (included in noncurnt liabiltiesi2) $ (31,755) $ (34,365)
(1) Benefits paid are net of$2,73 I and $ I ,927 of plan paricipant contributions, and $385 and $42 i of Medicare Par D subsidy receipts
for 2009 and 2008, respectively.
(2) Noncurrent liabilties ar contained in "Other deferrd credits" for Idaho Power.
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 $
14,1l2 $16,289
(1,537)(2,072)
6,120 8,160
18,695 22,377
(15,235)(18,904)
(3,460)(3,473)
$
The net periodic postretirement benefit cost was as follows (in thousands of dollars):
Service cost
Interest cost
Expected return on plan assets
Amortization of net loss
Amortization of prior service cost
Amortization of unecognized transition obligation
Net periodic postretirement benefit cost
$
2009 2008
1,221 $1,154
3,565 3,498
(2,146)(2,899)
842
(535)(535)
2,040 2,040
4,987 $3,258$
In 20 i 0, Idao Power expects to recognize as components of net periodic benefit cost $2. i milion from amortizing amounts recorded
in accumulated other comprehensive income as of December 3 1,2009 relating to the postretirement plan. This amount consists of
($0.5) milion of prior service cost, $0.6 milion of net loss and $2.0 milion of transition obligation.
Medicare Act: The Medicare Prescription Drug, Improvement and Moderniztion Act of 2003 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 drg benefit that is at least actuarially equivalent to Medicare's prescription drg coverage.
The following table summarizes the expected futue benefit payments of the postretirement benefit plan and expected Medicare Par D
subsidy receipts (in thousands of dollars):
2010 2011 2012 2013 2014 2015-2019
Expected benefit $
payments( i )
Expected Medicare Par D
IFERC FORM NO.1 (ED. 12-88)
4,200 $ 4,400 $ 4,500 $ 4,700 $ 4,800 $ 25,200
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 0411212010 2009/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
subsidy receipts $500 $500 $600 $600 $700 $4,500
(I) Expected benefit payments are net of expected Medica Par D subsidy reipts.
The assumed health care cost trend rate used to meaure the expeed cost of health benefits covered by the plan was eight percent and
ten percent in 2009 and 2008, respectively. The assumed health ca cost trnd rate for 2009 is assumed to decrease grdually to five
percent by 2066. The assumed dental cost trnd rate used to measur the expected cost of dental benefits covered by the plan was five
percent in both 2009 and 2008. A I -percentage point change in the assumed health care cost trend rate would have the following
effects at December 3 I, 2009 (in thousands of dollar):
i -Percentage-Point
Increase Decrease
Effect on total of cost components
Effect on accumulated postrtirement benefit obligation
$
$
288
2,471
$
$
(218)
(1,949)
Plan Assumptions:
The following table sets forth the weighted-avere assumptions used at the end of each year to detennine benefit obligations for all
Idaho Power-sponsored pension and postrtirement benefits plans:
Discount rate
Rate of compensation increase
Medical trend rate
Dental trend rate
Measurement date
Pension
Benefits
200 2008
5.9% 6.1%
4.5% 4.5%
Postretirement
Benefits
2009 2008
5.9% 6.1%
12/31109 12/31108
8.0%
5.0%
12/31109
10.0%
5.0%
12/31108
The following table sets forth the weighted-average assumptions used to detennine net penodic benefit cost for all Idaho
Power-sponsored pension and postretirement benefit plans:
Discount rate
Expected long-tenn rate of return on assets
Rate of compensation increase
Medical trend rate
Pension
Benefits
2009 2008
6.1% 6.4%
8.5% 8.5%
4.5% 4.5%
Postretirement
Benefis
2009 2008
6.1% 6.4%
8.5% 8.5%
Dental trend rate
8.0% 10.0
%
5.0% 5.0%
Plan Assets:
Idaho Power's pension plan and postretirement benefit plan assets at December 3 i, by asset category, are as follows:
Pension
Plan
Postretirement
Benefits
Asset Category 2009 2008 2009 2008
IFERC FORM NO.1 (ED. 12-88) Page 123.26
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 0412/2010 2009/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Cash and cash equivalents $4,512 $4,666 $-$
Short-term bonds 30,774 36,553
Core bonds 41,165 46,652
Equity securities 184,562 152,172
Real estate 20,783 37,418
Private market investments 20,202 17,863
Commodities 11,476
Other(l)30,892 25,283
Total $313,474 $295,324 $30,892 $25,283
(I) The postrtirement beefits asets are primarly life insurance contracts.
Pension Asset Allocation Policy: The taget allocation and actual allocations at December 3 I, 2009 for the portfolio by asset class
are as follows:
Target
Allocation
Actual
Allocation
December 31,2009
Lage-cap core stocks
Large-cap growth stocks
Large-cap value stocks
Small-cap growth stocks
Small-cap value stocks
Micro-cap stocks
International growt stocks
International value stocks
Commodities
Private market investments
Short-term bonds
Core bonds
Cash and cash equivalents
Real estate
Total
14%
7%
7%
5%
5%
3%
7%
7%
3%
7%
10%
13%
3%
9%
100%
12.2%
9.2%
9.0%
4.5%
5.3%
3.2%
7.2%
8.3%
3.7%
6.5%
9.8%
13.1%
1.4%
6.6%
100%
Assets are rebalanced as necessary to keep the portfolio close to taget allocations.
The plan's principal investment objective is to maximize total retu (defined as the sum of realized interest and dividend income and
realized and unealized gain or loss in market price) consistent with prudent parameters of risk and the liabilty profie ofthe portfolio.
Emphasis is placed on preservation and growth of capital along with adequacy of cash flow suffcient to fud curent and futue
payments to pensioners.
There are three major goals in Idaho Power's asset allocation process:
. Determine ifthe investments have the potential to ear the rate of retu assumed in the actarial liabilty calculations.
. Match the cash flow needs of the plan. Idaho Power sets bond allocations suffcient to cover at least five years of benefit
payments and cash allocations suffcient to cover the curent year benefit payments. Idaho Power then utilzes growth
instrents (equities, real estate, ventue capital) to fund the longer-term liabilties of the plan.
. Maintain a prudent risk profie consistent with ERISA fiduciar standards.
. Allowable plan investments include stocks and stock fuds, 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,
IFERC FORM NO.1 (ED. 12-88) Page 123.27
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 041121010 2009/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
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 ar based on historical nsklretu relationships among asset classes. The pnmary measure is
the histoncal risk premium each asset class has delivered versus the retu on 10-year U.S. Treasur Notes. This historical risk
premium is then added to the current yield on IO-year U.S. Treasur Notes, and the result provides a reasonable prediction of futue
investment performance. Additional analysis is performed to measur the expected rage of returns, as well as worst-case and
best-case scenaros. Based on the curent low interest rate environment, curent rate-of-return expectations are lower than the nominal
returns generated over the past 20 years when interest rates were generally much higher.
Idaho Power's asset modeling process also utilzes histoncal maret retu to measure the portfolio's exposure to a ''worst-case''
market scenario, to determine how much performance could var from the expected "average" performance over varous time penods.
This "worst-case" modeling, in addition to cash flow matching and diversification by asset class and investment style, provides the
basis for managing the risk associated with investing portolio assets.
Fair Value of Plan Assets: Idao Power classifies its pension plan and postretiement plan investments using the following hierachy:
· Level I, which refers to securties valued using quoted pnces frm active marets for identical assets;
· Level 2, which refers to securties not trded on an acve maret but for which observable maret inputs are readily available;
and
· Level 3, which refers to securties valued based on significat unobservable inputs.
If the inputs used to measure the securties fall within different levels of the hierahy, the categonzation is based on the lowest level
input (Level 3 being the lowest) that is significant to the fair value measurment of the security. The following table sets fort by level
within the fair value hierarchy a sumar of the plans' investments measured at fair value on a recuring basis at December 3 i .
Quoted Prices in Signifcant Significant
Active Markets Other Unobservable
for Identical Observable Inputs
Assets (Levell)Inputs (Leel 2)(Level 3) Total
Assets at December 31, 2009
Pension assets:
Cash and cash equivalents $4,512 $-$-$4,512
Short-term bonds 30,774 30,774
Core bonds 41,165 41,165
Equity securities 126,049 58,513 184,562
Real estte 20,783 20,783
Private market investments 20,202 20,202
Commodities 1l,476 11,476
Total pension assets $202,500 $69,989 $40,985 $313,474
Postretirement assets $-$30,892 $$30,892
The following table presents a reconcilation of the beginning and ending balances of the fair value measurements using significant
unobservable inputs (Level 3):
Private Real
Equity Estate Total
Begining balance - Januar I, 2009 $17,863 $37,418 $55,281
Realized losses (1,040)(671)(l,711)
Unrealized gains (losses)3,103 (14,912)(i 1,809)
Purchases, issuances, and settlements, net 276 (1,052)(776)
Ending balance - December 3 I, 2009 $20,202 $20,783 $40,985
IFERC FORM NO.1 (ED. 12-88) Page 123.28
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~An Original (Mo, Da, Yr)
Idaho Power Company i (2) A Resubmission 04/12/2010 20091Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Employee Savings Plan
Idaho Power has an Employee Savings Plan that complies with Section 40 I (k) of the Internal Revenue Code and covers substantially
all employees. Idaho Power matches specified percentages of employee contributions to the plan. Matching contributions amounted
to $5 milion in each of2009 and 2008.
Post-employment Benefits
Idaho Power provides certain benefits to former or inactive employees, their beneficiaries and covered dependents after employment
but before retirement. These benefits include salar continuation, health care and life insurace for those employees found to be
disabled under Idaho Power's disabilty plans and health care for suriving spouses and dependents. Idaho Power accrues a liabilty
for such benefits. The post employment benefit amounts included in other deferred credits on Idaho Power's balance sheets at
December 3 1,2009 and 2008 are $5.2 milion and $3.7 milion, respectively.
11. PROPERTY PLANT AND EQUIPMENT AND JOINTLY -OWNED PROJECTS:
The following table presents the major classifications ofldaho Power's utilty plant in service, anual depreciation provisions as a
percent of average depreciable balance and accumulated provision for depreciation for the year 2009 and 2008 (in thousands of
dollars):
Production
Trasmission
Distrbution
General and Other
Total in service
Accumulated provision for depreciation
In service - net
2009
Balance Avg Rate
$ 1,758,813 2.23%
768,260 2.07
1,331,065 2.89
302,040 7.88
4,160,178 2.81%
(l,558,538)
$ 2,601,640
2008
Balance Avg Rate
$ 1,736,670 2.34%742,871 2.ii
1,254,048 2.50
296,545 7.53
4,030,134 2.73%
(1,505,120)
$ 2,525,014
Idaho Power has interests in thee jointly-owned generating facilties included in the table above. Under the joint operating
agreements, each paricipating utilty is responsible for financing its share of constrction, operating and leasing costs. Idaho Power's
proportionate share of direct operation and maintenance expenses applicable to the projects is included in the Consolidated Statements
of Income.
These facilties, and the extent of Idaho Power's paricipation, were as follows at December 3 I, 2009 (in thousands of dollars):
Name of Plant Location
Jim Bridger Units I -4 Rock Sprigs, WY $
Boardman Boardman, OR
Valmy Units I and 2 Winnemucca, NV
(l) Idaho Power share of nameplate capacity
Utilty Construction Accumulated
Plant In Work in Provision for Ownership
Service Progress Depreciation % MW(l)
505,343 $ 21,922 $ 274,852 33 771
71,755 630 51,677 10 64
334,152 6,040 207,808 50 284
Idaho Power's wholly-owned subsidiar IERCo, is a joint ventuer in Bridger Coal Company, which operates the mine supplying coal
to the Jim Bridger generating plant. Idaho Power's coal purchases from the joint venture were $66 milion and $63 milion in 2009
and 2008, respectively.
Idaho Power has contrcts to purchase the energy from four PURPA qualified facilties that are 50 percent owned by Ida-West. Idaho
Power's power purchases from these facilties were $8.7 milion in 2009 and $8 milion in 2008.
IFERC FORM NO.1 (ED. 12-88) Page 123.29
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 041212010 2009/04
NOTES TO FINANCIAL STATEMENTS (Continued)
12. ASSET RETIREMENT OBLIGATIONS (ARO):
The guidance relating to accounting for AROs requires that legal obligations associated with the retirement of propert, plant and
equipment be recognized as a liabilty at fair value when incured and when a reasonable estimate of the fair value of the liabilty can
be made. Under the guidace, when a liabilty is initially recorded, the entity increases the caring amount of the related long-lived
asset to reflect the futue 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 liabilty differs frm the actual
obligations paid, a gain or loss would be recognizd. As a rate-regulated entity, Idaho Power records regulatory assets or liabilties
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 ear a retu on investment.
Idaho Power's recorded AROs relate to the removal of polychloriated biphenyls-contaminated equipment at its distrbution facilties
and the reclamation and removal costs at its jointly owned coal-fired generation facilties. In 2009, changes in estimates at the
coal-fired generation facilties resulted in a net increase of$3.7 milion in the recorded ARO.
Idaho Power also has AROs associated with its transmission system and hydroelectrc facilties; however, due to the indeterminate
removal date, the fair value of the associated liabilties currntly canot be estimted and no amounts are recognized in the
consolidated fmancial statements.
The following table presents the changes in the carin amount of AROs (in thousds of dollar):
Balance at beginning of year $
Accretion expense
Revisions in estimated cash flows
Liabilty incurred
Liabilty settledBalance at end of year $
2009 2008
12,415 $14,515
697 701
3,684 (2,627)
139
(695)(174)
16,240 $12,415
13. INVESTMENTS:
The following table sumarizes Idaho Power's investments as of December 3 I (in thousands of dollars):
Investments:
Equity method investment
Available-for-sale equity securities
Executive deferred compensation plan
Other investments
Total investments
$
2009 2008
83,969 $86,433
18,842 14,451
5,217 4,679
267 948
108,295 $106,51 I$
Equity Method Investments
Idao Power, though its subsidiar IERCo, is a 33 percent owner of Bridger Coal Company, which supplies coal to the Jim Bridger
generating plant owned in par by Idao Power.
The following table presents Idaho Power's earings (loss) of unconsolidated equity-method investments (in thousands of dollar):
Bridger Coal Company
2009
$ 8,256
2008
$ 6,772
IFERC FORM NO.1 (ED. 12-88) Page 123.30
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 04/12/2010 2009/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Investments in Debt and Equity Securities
Investments in debt and equity securities classified as available-for-sale securities are reported at fair value, using either specific
identification or average cost to determine the cost for computing gains or losses. Any unealized gains or losses on available-for-sale
securities are included in other comprehensive income.
Investments classified as held-to-matuity securities are reported at amortized cost. Held-to-matuity securities are investments in debt
securties for which the company has the positive intent and abilty to hold the securities until maturity.
The following table sumarzes investments in debt and equity securties (in thousands of dollars):
2009 2008
Gross Gross Gross Gross
Unrealized Unrealized Fair Unrealized Unrealized Fair
Gain Loss Value Gain Loss Value
A vailable- for-sale
securties $2,989 $-$18,842 $-$- $14,451
The following table summarizes sales of available- for-sale securities (in thousands of dollar):
2009 2008
Proceeds from sales
Gross realized gains from sales
Gross realized losses from sales
$9,006 $
11
35
These investments are evaluated to determine whether they have experienced a decline in market value that is other-than-tempora.
Idaho Power analyzes securties in loss positions as of the end of each reporting period. At December 3 1,2009, Idaho Power did not
have any securities that were in a loss position. At December 3 i, 2008, four available- for-sale and six held-to-maturity securities were
in an unealized loss position. The available-for-sale equity securities in unealized loss positions were broadly diversified index fuds
used to fund Idaho Power's SMSP. Due to the severity of the losses and the volatilty of the maret the available-for-sale securities
were deemed other-than-temporarily impaired and written down $6.8 milion to fair market value at December 3 i, 2008. The
held-to-matuity debt securities were bonds with an aggegate fair value of approximately $4 milion and an aggegate unealized loss
of $25 thousand at December 3 1,2008. The bonds market values fluctuated based on the interest rate environment.
14. DERIVATIVE FINANCIAL INSTRUMENTS
Commodity Price Risk
Idaho Power is exposed to certin risks relatig to its ongoing business operations. The primary risk managed by using derivative
instrments is commodity price risk related to Idaho Power's ongoing utilty operations providing electricity to meet the demand of
its
retail customers. Physical and financial forward contracts for both electricity and fuel used to produce electricity are entered into to
manage the price risk associated with meeting forecasted loads. The objective ofidaho Power's energy purchase and sale activity is to
meet the demand of retail electric customers, maintain appropriate physical reserves to ensure reliabilty and make economic use of
tempora surluses that may develop.
All derivative instrments are recognized as either assets or liabilties at fair value on the balance sheet. Idaho Power's physical
forward contrcts qualify for the normal purchases and normal sales exception to derivative accounting requirements with the
exception offorward contracts for the purchase of natural gas for use at Idaho Power's natul gas generation facilties. Because of
Idaho Power's power cost mechanisms, Idaho Power records the changes in fair value of derivative instrents related to power
supply as regulatory assets or liabilities.
IFERC FORM NO.1 (ED. 12-88) Page 123.31
Name of Respondent This Report is:Date of Report Year/Period of Report
( 1) lS An Original (Mo, Da, Yr)
Idaho Power Company I (2) A Resubmission 04/1212010 2009/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
As of December 3 1,2009, Idaho Power had the following outstading derivative commodity forward contracts that were entered into
for the purose of economically hedging forecasted purhases and sales:
Commodity
Electrcity purchases
Electrcity sales
Natul gas
Diesel
Number of Units
705,625 MWh
567,525 MWh
1,356,250 MMBtu
901,932 gallons
The following table presents the fair values of derivatives not designted as hedging instrents recorded in the balance sheet at
December 31, 2009 (in thousands of dollar):
Asset Derivatives Liabilty Derivatives
Balanee Sheet Fair Balanee Sheet Fair
Commodity derivatives Location Value Loation Value
Current:
Financial swaps Other current assets $2,931 Oter curnt assets $2,087
Financial swaps Oter currnt liabilties 9 Oter curnt liabilties 610
Forward contracts Oter curent assets 354 Oter curent assets
Long-tenn:
Financial swaps Other assets 442 Oter assets 229
Total $3,736 $2,926
The following table presents the effect on income of derivatives not designated as hedging instrments for the year ended December
31, 2009 (in thousands of dollars):
Commodity derivatives
Year ended December 31, 2009:Financial swaps Off-system sales $ 3,245Financial swaps Purchased power (3,966)Financial swaps Fuel expense (5,794)Forward contrcts Fuel expense (986)
(I) Excludes changes in fair value of derivatives, which are rerded on the balance shee as regulatory assets or liabilities.
Loeation of Gain/(Loss)
Recognizd in Ineome on
Derivative
Amount of Gain/(Loss)
Recognaed in Ineome on
Derivative(l)
Idaho Power records changes in fair value of its derivative contrcts as either regulatory assets or liabilties. Settlement gains and
losses on electricity swap contrcts are recorded on the income statement in off-system sales or purchased power depending on the
forecasted position being economically hedged by the derivative contrct. Settlement gains and losses on both financial and physical
contracts for natul gas are reflected in fuel expense. Settlement gains and losses on diesel derivatives, which were immaterial for all
three years, are recorded in fuel inventory on the balance sheet.
Credit Risk
At December 3 1,2009, Idaho Power does not have material credit exposure from fiancial instrents, including derivatives. Idao
Power monitors credit risk exposure through reviews of counterpar credit quality, corporate-wide counterpar credit exposure, and
corporate-wide counterpart concentration levels. Idaho Power manages these risks by establishing appropriate credit and
concentrtion limits on trsactions with counterparies and requiring contractual guartees, cash deposits or letters of credit from
counterparies or their affliates, as deemed necessar. The majority ofIdaho Power's contracts are under the Western Systems Power
IFERC FORM NO.1 (ED. 12-88) Page 123.32
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) Ã An Original (Mo, Da, Yr)
Idaho Power Company (2) A Resubmission 04/1212010 2009/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Pool agreement that provides for adequate assurances if a counterpar has debt that is downgraded to below investment grde by at
least one rating agency. Idaho Power also requires North American Energy Stadards Board contracts as necessar for physical gas
trsactions, and International Swaps and Derivatives Association, Inc. contracts as needed for financial trsactions.
Credit-Contingent Features
Certin ofIdaho Power's derivative instrents contain provisions that require Idaho Power's unsecured debt to maintain an
investment grde credit rating from each of the major credit rating agencies. IfIdaho Power's unsecured debt were to fall below
investment grde, it would be in violation of these provisions, and the counterparies to the derivative instrents could request
immediate payment or demand immediate and ongoing full overnight collateralization on derivative instrments in net liability
positions. The aggegate fair válue of all derivative instrents with credit-risk-related contingent featues that are in a liabilty
position on December 3 1,2009, is $2.9 milion. Idaho Power has posted $1. millon collateral related to this amount. If
the
credit-risk-related contingent featues underlying these agreements were trggered on December 31, 2009, Idaho Power could have
been required to post $0.5 milion of cash collateral to its counterparies.
15. FAIR VALUE MEASUREMENTS:
Idaho Power has categorized its financial instrents, 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 (Levell) and the lowest priority to unobservable inputs (Level 3). If the inputs used to measure the financial instrents fall
within different levels of the hierarchy, the categorization is based on the lowest level input that is significant to the fair value
measurement of the instrent.
Financial assets and liabilties recorded on the Consolidated Balance Sheets are categorized based on the inputs to the valuation
techniques as follows:
Levell: Financial assets and liabilties whose values are based on undjusted quoted prices for identical assets or liabilties in an
active market that Idaho Power 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 liabilties 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 substatially the full term 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 term of the asset or liabilty.
Idao Power Level 2 inputs are based on quoted market prices adjusted for location using corroborated, observable market data.
Level3: Financial assets and liabilties whose values are based on prices or valuation techniques that require inputs that are both
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.
Idaho Power's derivatives are contrcts 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. Natul gas and diesel 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 held 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 trded money market and equity
funds with quoted prices in active markets.
The following tables present information about Idaho Power's assets and liabilties measured at fair value on a recurng basis (in
thousands of dollars). Idaho Power's assessment ofthe significance of a paricular input to the fair value measurement requires
judgment and may affect the valuation offair value assets and liabilties and their placement within the fair value hierachy. Please see
Note 10 for fair value information regarding Idaho Power's benefit plans.
IFERC FORM NO.1 (ED. 12-88) Page 123.33
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 04/1212010 2009/04
NOTES TO FINANCIAL STATEMENTS (Continued)
200
Assets:
Derivatives
Money market funds
Trading securities
Available-for-sale equity securities
Liabilties:
Derivatives
Quoted Prices in
Active Markets
for Identical
Asset (Levell)
SignificantOter
Observable
Inputs (Level 2)
Significant
Unobservable
Inputs
(Level 3) Total
$1,056 $354 $
19,364
5,217
18,842
(601)
- $1,410
19,364
5,217
18,842
(601)
2008
Assets:
Derivatives
Money market funds
Traing securities
Available-for-sale equity securities
Liabilties:
Derivatives
$652 $-$-$652
1,224 1,224
4,679 4,679
14,451 14,451
(2,653)(2,653)
The following tables present the carring value and estimated fair value of fiancial instrents that are not reported at fair value,
using available market information and appropriate valuation methodologies. The us of different maret 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 taes accrued are reported at their caring value
as these are a reasonable estimate of their fair value. The estimted 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.
Assets:
Notes receivable
Liabilties:
Long-term debt
December 31, 2009 December 31, 2008
Carrying Estimated Carrying EstimatedAmount Fair Value Amount Fair Value
(thousands of dollars)
$- $ - $259 $ 282
1,413,854 1,398,681 1,268,818 1,191,476
16. OTHER INCOME AND EXPENSE:
The following table presents the components of Oter income and Oter expense (in thousands of dollars):
2009 2008
Other income:
Allowance for fuds used during constrction-equity
Investment income, net
Caring charges
Other
Total
$7,555 $
5,071
4,471
3,967
21,064 $
3,141
(5,273)
6,709
7,284
11,861$
Other expense:
SMSP expense
IFERC FORM NO.1 (ED. 12-88)
$ 5,355 $
Page 123.34
4,628
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 04/12/2010 2oo9/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Life Insurance, net of proceeds
Other
Total
(4,197)
2,909
4,067 $
(381)
3,783
8,030$
17. RELATED PARTY TRANSACTIONS:
IDACORP
Idaho Power performs corporate fuctions such as financial, legal and management services for IDACORP and its subsidiares. Idao
Power charges IDACORP for the costs of these services based on service agreements and other specifically identified costs. For these
services Idaho Power biled IDACORP $0.9 milion and $1 milion in 2009 and 2008, respectively.
Ida-West
Idaho Power purhases all of the power generated by four of Ida- West's hydroelectrc projects located in Idaho. Idaho Power paid
$8.7 milion in 2009 and $8 millon in 2008.
IFERC FORM NO.1 (ED. 12-88) Page 123.35
This Page rptentionally Left Blank
aeo epo
(Mo, Da. Yr)
0411212010
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), (t), and (g) report other (specif) and in
column (h) common functon.
End of
(a)
Total Company for the
Current Year/Quarter Ended
(b)
Electric
(c)
Line
No.
Classifcation
Utility Plant
2 In Service
3 Plant in Service (Classified)
4 Propert Under Capital Leases
5 Plant Purchase or Sold
6 Completed Constrction not Classifed
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 Accm Prov for Depr, Amort, & Depl
15 Net Utilit Plant (13 less 14)
16 Detail of Accum Prov for Depr, Amort & Depl
17 In Service:
18 Depreciation
19 Amort & Depl of Producing Nat Gas Land/Land Right
20 Amort of Underground Storage Land/Land Rights
21 Amort of Other Utilit 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)
4,160,632,424 4,160,632,424
4,160,632,424 4,160,632,424
7,150,794
289,188,358
-454,449
4,456,517,127
1,713,943,062
2,742,574,065
7,150,794
289,188,358
-454,449
4,456,517,127
1,713,943,062
2,742,574,065
I-~--- ~-l
i
-395,749
1 ¡ 713,943,062
-395,749
1,713,943,062
FERC FORM NO.1 (ED. 12-89)Page 200
Name of Respondent
Idaho Power Company
YearlPeriod of Report
End of 2oo9/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 041121010
ELECTRI PLANT IN SERVICE (Accunt 101, 102, 103 and 106)
1. Report below the original cost of electc plant in service accrding to the prescrbed accunts.
2. In addition to Accunt 101, Electric Plant in Service (Classifed), this page and the next include Accunt 102, Electric Plant Purchased or Sold;
Accunt 103, Experimental Electric Plant Unclassified; and Accunt 106, Completed Construction Not Classifed-Electc.
3. Include in column (c) or (d), as appropriate, corrections of additions and retirements for the currnt or preceing year.
4. For revisions to the amount of initial asset retirement costs capitalized, included by primary plant accunt, increases in column (c) additions and
reductions in column (e) adjustments.
5. Enclose in parentheses credit adjustmnts of plant accunts to indicate the negative effct of such accunts.
6. Classify Accunt 106 according to prescribed accunts, on an estimate basis if necssary, and include the entries in column (c). Also to be included
in column (c) are entries for reversals of tentative distributons of prir year reprted in column (b). Likewise, if the respondent has a significant amount
of plant retirements which have not been clssifd to primary accunts at the end of the year, include in column (d) a tentative distribution of such
retirements, on an estimated basis, with appropriate contr entr to the accunt for accmulated depreciation provision. Include also in column (d)ine CCun a ance ionsNo Beginning of Year. 00 ~
1 1. INTANGIBLE PLANT
2 301) Organization
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 Rights
9 (311) Structures and 1m rovements
10 (312) Boiler Plant Equipment
11 (313) Engines and Engine-Driven Generators
12 (314) Turbo enerator Units
13 (315) Accsso Electric Equipment
14 (316) Misc. Power Plant E uipment
15 (317) Asset Retirement Costs for Steam Producton
16 TOTAL Steam Production Plant (Enter Total of lines 8 thru 15
17 B. Nuclear Production Plant
18 320) Land and Land Ri hts
19 (321) Structures and Improvements
20 322) Reactor Plant Equipment
21 (323 Turbogenerator Unit
22 (324) Accesso . Electric Equi ment
23 (325) Misc. Power Plant Equipment
24 (326 Asset Retirement Costs for Nuclear Producton
25 TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24)
26 C. Hydraulic Production Plant
27 (330) Land and Land Rights
28 (331) Structures and Improvements
29 (332) Reservoirs, Dams, and Waterways
30 (333) Water Wheels, Turbines, and Generators
31 (334) Accsso Electric Equipment
32 (335) Misc. Power PLant E uipment
33 336) Roads, Railroads, and Brid es
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 Equi ment
44 (347) Asset Retirement Costs for Other Producton
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)
1,370,320
134,509,144
536,613,056
4,428,791
15,667,072
132,560,576
62,162,175
16,343,159
4,362,002
887,920,432
5,376,696
781,896
-467,254
-776,491
25,010,710
28,655,168
151,277,057
249,507,983
188,274,619
41,330,716
17,467,963
7,492,685
2,167,400
2,376,592
797,436
4,883,815
1,985,661
646,843
--- - - -- - --- -------- -- --684,006,191 12,857,747
402,746
10,422,006
5,330,580
91,489,425
36,237,868
17,237,981
3,623,146
-3,252,411
-884,714
1,999,610
2,855,158
7,661,24
-568,971
164,743,752
1,736,670,375
7,809,921
45,678,378
FERC FORM NO.1 (REV. 12-05)Page 204
Name of Respondent
Idaho Power Company
Year/Periodóf Report
End of 2009/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/12/2010
ELECTRIC PLANT IN SERVICE (Account 101,102,103 and 106) (Continued)
distributions of these tentative classifcations in columns (c) and (d), including the reversals of the prior years tentative accunt distributions of these
amounts. Careful observance of the above instructions and the texts of Accunts 101 and 106 wil avoid serious omissions ofthe reported amount of
respondent's plant actally in service at end of year.
7. Show in column (f) reclassifications or transfers within utilty plant accunts. Include also in column (f) the additions or reductions of primary accunt
classifications arising from distribution of amounts initially recrded 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 offet to the debits or credits distributed in column (f) to primary
accunt classifications.
8. For Accunt 399, state the nature and use of plant included in this accunt and if substantial in amount submit a supplementary statement showing
subaccunt classification of such plant confOrming to the requirement of these pages.
9. For each amount comprising the reported balance and changes in Accunt 102, state the propert purchased or sold, name of vendor or purchase,
and date of transaction. If proosed joumal entries have been filed with the Commission as required by the Unifrm System of Accunts, give also dateRetirements Adjustments Transfers Balance at LineEnd lif)Year No.
837,464
402,746
7,169,595
4,445,866
92,651,571
39,093,026
24,899,230
3,054,175
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
305,737
16,284,072
1,370,320
138,632,198
535,996,056
3,178,768
933,816
691,107
134,758,504
62,010,255
15,184,798
3,585,511
891,537,6221,393,500
-463
91,478
68,477
426,420
563,80
154,973
30,823,031
153,562,171
250,236,942
192,732,014
42,752,897
17,959,833
7,492,685
-~- -~ -- - ------ ----- ---- -- -- - ----- -- ----~-~ - - - -- ~1,304,365 695,559,573
837,464
23,535,329
171,716,209
1,758,813,424
FERC FORM NO.1 (REV. 12-05)Page 205
Name of Respondent
Idaho Power Company
This ~ort Is:(1) ~An Oriinal
(2) A Resubmission
ELECTRIC PLANT IN SERVICE (Accunt 101,102,1
ccunine
No.
47 3. TRANSMISSION PLANT
48 350) Land and Land Ri hts
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) Under round 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 Rights
61 (361) Structures and Improvements
62 (362) Station Equipment
63 (363 Stora e Batte Equi ment
64 (364) Poles, Towers, and Fixtures
65 365) Overhead Conductors and Devices
66 366) Unde round Conduit
67 (367) Unde round Conductors and Devices
68 (368) Line Transformers
69 369) Services
70 (370) Meters
71 (371) Installations on Customer Premises
72 (372) Leased Pro ert on Customer Premises
73 373) Street Lightin and Si nal S stems
74 (374) Asset Retirement Costs for Distribution Plant
75 TOTAL Distribution Plant (Enter Total of lines 60 thru 74)
76 5. REGIONAL TRANSMISSION AND MARKET OPERATION PLAT
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 Re ional Transmission and Market Operation Plant
83 (386) Asset Retirement Costs for Re ional Transmission and Market 0 er
84 TOTAL Transmission and Market Operation Plant (Total lines 77 thru 83
85 6. GENERAL PLANT
86 389) Land and Land Rights
87 (390) Structures and Improvements
88 391) 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 Operated Equipment
94 (397) Communication Equipment
95 (398) Miscellaneous E uipment
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 Entèr Total of lines 96, 97 and 98)
100 TOTAL (Accunts 101 and 106)
101 (102) Electric Plant Purchased (See Instr. 8)
102 (Less) (102 Electric Plant Sold (See Instr. 8)
103 103) Ex erimental Plant Unclassifid
104 TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103)
a)
YeanPeriod of Report
End of 2oo9/Q4
34,665,687
41,274,219
286,101,340
136,921,634
93,136,953
150,452,740
-3,636,839
1,964,780
19,136,925
2,383,729
2,438,869
5,091,772
318,351
742,870,924 27,379,236
4,715,078
24,515,065
167,223,999
5,906
2,535,755
14,885,421
210,585,863
116,789,867
47,417,198
179,509,673
381,826,912
55,557,765
58,984,822
2,536,798
8,065,022
5,906,821
975,808
8,562,574
26,216,387
1,231,619
20,190,727
175,494
4,152,933
232,370
1,254,048,343
137,94
88,889,478
- ------ -~----- - ----
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
-67,107
5,572,161
3,160,495
2,573,534
256,639
656,258
1,204,212
589,519
1,997,252
211,716
16,154,679
242,163,992
4,030,588,348
16,154,679
184,388,125
4,030,588,348 184,388,125
FERC FORM NO.1 (REV. 12-GS)Page 206
Name of Respondent This wort Is:Date of Report Year/Period of Report
ldaho Power Company (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) FiA Resubmission 0412/2010
ELECTRIC PLANT IN SERVICE (Accunt 101,102,103 and 106) (Continued)
Line~ ~r~~No.00 m ~
47
31,028,848 48
123,502 43,115,497 49
1,084,667 304,153,598 50
139,305,363 51
350,520 95,225,302 52
431,505 155,113,007 53
54
55
318,351 56
57
1,990,194 768,259,966 58
59
14 4,720,970 60
101,502 26,949,318 61
744,946 181,36,474 62
63
1,592,334 217,058,551 64
1,567,490 121,129,198 .65
93,597 48,299,409 66
1,098,401 186,973,846 67
6,158,840 401,884,459 68
282,627 56,506,757 69
133,705 79,041,84 70
56,714 2,655,578 71
72
43,059 4,247,818 73
232,370 74
11,873,229 1,331,06,592 75
76
77
78
79
80
81
82
83
84
85
10,761,268 86
320,175 76,656,381 87
8,239,535 40,825,812 88
2,080,609 58,924,843 89
108,332 1,330,794 90
214,765 5,250,205 91
365,201 11,551,486 92
22,682 9,240,588 93
714,934 27,393,124 94
92,801 4,225,136 95
12,159,034 246,159,637 96
97
98
12,159,034 246,159,637 99
54,344,049 4,160,632,424 100
101
102
.103
54,344,049 4,160,632,424 104
FERC FORM NO.1 (REV. 12-GS)Page 207
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 2oo9/Q4
(2) OA Resubmision 041121010
EL CTRIC PLANT HELD FOR FUTURE USE (Accunt 105)
1. Report separately each propert held for fuure use at end of the year having an original cost of $250,000 or more. Group other items of propert held
for fuure use.
2. For propert having an original cost of $250,000 or more previously used in utlit operations, now held for future use, give in column (a), in addition to
other required information, the date that utilit use of such propert was disntinued, and the date the original cost was transferred to Accunt 105.
Line uescription and Location ~No.OfProrrt in is Accunt in Utilty Service End of Year
(a (b) (c) (d)
1 Land and Rights:
2 Boise Operations Center 12131/82 768,377
3 Producton 112,703
4 Transmission Stations 429,822
5 Transmission Lines 68,619
6 Distrbution Stations 1,099,141
7 Beacon Light Substation 12130/02 465,662
8 Homedale Substation 219/08 ..109,453
9 Nort River Operations Center 1131/08 2,630,412
10 Line #854 500 Kv 3131/09 305,494
11 Boise Operations Center 12131182 72,785
12 Transmission Stations 12/1/81 199,069
13 Distribution Stations 72,016
14 Homedale Substation 2129/08 215,719
15 Beacon Light Substation 12130/02 601,522
16
17
18
19 Column B if no date listed it is various
20
21 Other Propert:
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 Total 7,150,794
FERC FORM NO.1 (ED. 12-96)Page 214
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2009/04
(2) CiA Resubmission 04/12/2010
CONSTRUCTION WORK IN PROGRESS - - ELEC TRIC (Accunt 107)
1. Report below descriptions and balances at end of year of projects in process of constructon (107)
2. Show items relating to "research, development, and demonstration" project last, under a caption Research, Development, and Demonstrating (see
Accunt 107 of the Uniform System of Accunts)
3. Minor projects (5% of the Balance End of the Year for Accunt 107 or $1,000,000, whichever is less) may be grouped.
Line Description of Project Constructon work in progress -
No.Electric (Accunt 107)
(a)(b)
1 IRP - COMBINED CYCLE CT (2012)52,823,361
2 ROLLUP RELIC COST BROWNLEE 43,330,600
3 HMWY - BUILD HEMINGWAY 500/230 36,254,121
4 ROLLUP RELIC COST HELLS CANYON 29,672,655
5 ROLLUP RELIC COST OXBOW 13,621,96
6 GATEWAY WEST 500KV LINE 11,242,352
7 HELLS CANYON RELICENSING OUTSI 10,533,032
8 BOARDMAN - HEMINGWAY 500 KV LI 8,201,659
9 T7250801 HEMINGWAY - BOWMONT 2 7,569,928
10 CIAC LIABILITY RECLASS 6,194,958
11 BRIDGER 2007C189 U1 S02 EMIS C 4,254,222
12 WO - ONGOING HELLS CANYON RELI 4,039,254
13 BRIDGER 2008C123 U1 TURBIN UPG 3,479,448
14 BRIDGER 2007C207 U3 S02 EMIS C 2,283,130
15 RIVER ENG.-HELLS CANYON CONTIN 2,145,907
16 BRIDGER 2008C124 U1 REHEATER R 2,061,121
17 HCC RELICENSING FISH2004 FEASI 2,005,90
18 PAYROLL & IBNR ACCRUAL 1,979,309
19 IBM MAINFRAE TOOLS LICENSES 1,925,980
20 BRIDGER UNDISTRIBUTED WORK ORO 1,925,675
21 REL-HELLS CANYON COMPLEX FY200 1,895,561
22 HCC RELICENSING, FISH2004 INST 1,735,773
23 HCC RELICENSING, FISH2004 REDB 1,590,625
24 NAMPA REPLACE METALCLAD SWITCH 1,458,489
25 HCC RELICENSING, FISH2004 ANAD 1,406,303
26 VALMY 98230938 RELINE EVAP PON 1,270,215
27 ROLLUP RELIC COST SWAN FALLS 1,167,719
28 BRIDGER2008C102 U1 GENERATOR 1,135,543
29 SWAN FALLS RELICENSING 1,118,001
30 DESIGN CONSTRUCT WO FOR LINE #1,111,783
31 COST CENTER 317 DELIVERY CAP IT 1,100,797
32 VALMY 98219836 REPL PRODUCTION 1,081,771
33 342 COST CENTER DELIVERY CAPIT 1,032,297
34 REL-HCC OREGON REAUTHORIZATION 1,012,906
35 LEGAL DEPT. LABOR FOR RELICENS 1,000,569
36 OTHER MINOR PROJECTS UNDER $1,000,000 24,525,424
37
38
39
40
41
42
43 TOTAL 289,188,358
FERC FORM NO.1 (ED. 12-87)Page 216
Name of Respondent
Idaho Power Company
Date of Report
(Mo, Da, Yr)
04121010
IC UTILITY PlANT (Accunt 108)
Year/Period of Report
End of 2009/Q4
This ~ort Is:
(1) ~An Original
(2) A Resubmission
ACCUMUlATED PROVI ION FOR DEPRECIATION OF ELEC
1. Explain in a footnote any important adjustments during year.
2. Explain in a footnote any difference beteen the amount for book cost of plant retired, Line 11, column (c), and that reported for
electric plant in service, pages 204207, column 9d), excluding retirements of non-depreciable propert.
3. The provisions of Accunt 108 in the Uniform System of acunts require that retirements of deprecable plant be rerded when
such plant is removed from service. If the respondent has a signifit amount of plant retired at year end which has not been recorded
and/or classified to the various reserve functional classifcations, make preliminary closing entries to tentatively functionalize the book
cost of the plant retired. In addition, include all costs include in retirement work in proress at year end in the appropriate functional
classifications.
4. Show separately interest credits under a sinking fund or similar method of depreation accounting.
ine
No.
em
108,268
106,460,945
(a)
1,693,322,507 1,693,322,507
20 Steam Production
21 Nuclear Production
22 Hydraulic Production-Conventional
23 Hydraulic Prouction-Pumped Storage
24 Other Production
Secton B. Balances at End of Year According to Functonal Classification
529,377,124 529,377,124
324,079,967 324,079,967
2 Transmission
23,160,183
252,188,686
469,434,706
27 Regional Transmission and Market Operation
28 General
2 TOTAL (Enter Total of lines 20 thru 28)
95,081,841
1,693,322,507
95,081,841
1,693,322,507
FERC FORM NO.1 (REV. 12-05)Page 219
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 041212010 2009/Q4
FOOTNOTE DATA
¡Schedule Page: 219 Line No.: 14 Column: cRelocation reimbursements, Up and down costs and damage and insurance claims $ (722,669)
¡Schedule Pí!e: 219 Line No.: 16 Column: cAccumulated Provision for Depreciation on Asset Retirement Obligation $ 758,808
Embedded removal in Accumulated Provision for Depreciation (156,837,476)
$(156,078,668)
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)End of 2009104
(2) DA Resubmission 04/1212010
i NVESTM NTS IN SUBSIDIARY COMPANIES Accunt 123.1)
1. Report below investments in Accounts 123.1, investmnts in Subsidiary Companies.
2. Provide a subheading for each company and List there under the information calle for below. Sub - TOTAL by company and give a TOTAL in
columns (e),(f),(g) and (h)
(a) Investment in Securities - List and descibe each securit owned. For bonds give also principal amount, date of issue, maturity and interest rate.
(b) Investment Advances - Report separately the amounts of loans or investment advances which are subject to repayment, but which are not subject to
current settlement. With respect to each advance show whether the advance is a note or open account. List each note giving date of issuance, maturity
date, and specifing whether note is a renewal.
3. Report separately the equity in undistributed subsidiary earnings since acquisition. The TOTAL in column (e) should equal the amount entered for
Accunt 418.1.
ine Descnption of Investmnt Date Acquired Date Of AJount OT investment at
No.Mal~rity Beinning of Year(a)(b)(d)
1 Idaho Energy Resourcs Company
2 Common Stock 02101174 500
3 Capital contributions 2,462,594
4 Equity in earnings 57,595,093
5
6 Subtotal Idaho Energy Resources Company 60,058,187
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 60,058,187
FERC FORM NO.1 (ED. 12-89)Page 224
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) FiA Resubmission 04/12/2010
INVESTMENT: IN SUBSIDIARY COMPANIES (Accunt 123.1) (Continued)
4. For any securities, notes, or accunts that were pledged designate such securities, notes, or accunts in a footnote, and state the name of pledgee
and purpose of the pledge.
5. If Commission approval was required for any advance made or security acquired, designate such fact in a footnote and give name of Commission,
date of authorization, and case or docket number.
6. Report column (f) interest and dividend revenues form investments, including such revenues form securities disposed of during the year.
7. In column (h) report for each investment disposed of during the year, the gain or loss represented by the diffrence between cost of the investment (or
the other amount at which carried in the books of accunt if diffrence from cost) and the selling price thereof, not including interest adjustment includible
in column (f).
8. Report on Line 42, column (a) the TOTAL cost of Account 123.1
Equity.in Subsidiary Kevenues Tor Year -Amount oT investment at I Gain or Loss from Investment Line
Eamin~s of Year
(f)
End tifYear DisPlt~ed of No.e)g)
1
500 2
2,462,594 3
4,957,254 62,552,347 4
5
4,957,254 65,015,441 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
4,957,254 65,015,441 42
FERC FORM NO.1 (ED. 12-89)Page 225
This Page Intentionally Left Blank
Name of Respondent This wort Is:Date of Report YeadPeriod of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)2009/Q4
(2) DA Resubmission 04/1212010 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 accptable. In column (d), designate the departent or departents 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 supplis and the
various accunts (operating expenses, clearing accounts, plant, etc.) affcted debited or credited. Show separately debit or credits to stores expense
clearing, if applicable.
Line Accunt Balance Balance Department or
No.Beginning of Year End of Year Departments which
Use Material
(a)(b)(c)(d)
1 Fuel Stock (Accunt 151)16,851,868 25,633,645 Electric
2 Fuel Stock Expenses Undistributed (Accunt 152)
3 Residuals and Extracted Products (Accunt 153)
4 Plant Materials and Operating Supplies (Account 154)
5 Assigned to - Construction (Estimated)
6 Assigned to - Operations and Maintenance
7 Producton Plant (Estimated)13,785,883 14,273,494
8 Transmission Plant (Estimated)9,182,847 13,295,452
9 Distribution Plant (Estimated)20,839,000 15,059,387
10 Regional Transmission and Market Operation Plant
(Estimated)
11 Assigned to - Other (provide details in footnote)597,997 713,727
12 TOTAL Accunt 154 (Enter Total of lines 5 thru 11)44,405,727 43,342,060 Electric
13 Merchandise (Account 155)
14 Other Materials and Supplies (Accunt 156)
15 Nuclear Materials Held for Sale (Accunt 157) (Not
applic to Gas Util)
16 Stores Expense Undistributed (Account 163)5,715,442 4,711,966 Electc
17
18
19
20 TOTAL Materials and Supplies (Per Balance Sheet)66,973,037 73,687,671
FERC FORM NO.1 (REV. 12-05)Page 227
Name of Respondent This i!0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2oo9/Q4
(2) EiA Resubmision 04/1212010
o HER REGULATORY ASSETS (Account 182.3)
1. Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable.
2. Minor items (5% of the Balance in Accunt 182.3 at end of period, or amounts less than $100,000 which ever is less), may be
grouped by classes.
3. For Regulatory Assets being amortized, show period of amortization.
Line Description and Purpose of Balanc at Debits CREDITS Balance at end of
No.Other Regulatory Assets Beining of vvonen OIT uunng vvmien on uunng Currnt QuartrN earCurtth QuarterNear th Peri
Quartear Acct Charged Amount
(a)(b)(c)(d)(e)(f)
1 Asset Retirement Obligatins- IPUC 10,90,542 4,740,497 230 897,916 14,749,123
2 Ordr# 2914-OPUC Ordei 04-585
3
4 SFAS 133 Mark to Maret 3,073,63 14,189,919 244 16,983,09 280,459
5
6 Regulat Unfunded Accumulate Defer Incme Tax 341,052,611 49,63,578 vari 6,625,508 384,061,681
7
8 PCA Deferrl- IPUC order 93,65,207 72,710,549 25401 134,090,716 32,2n,040
9 #2766 (amor peri 6/05 thru 5/07)
10
11 PCA Pri Year Deferrl - IPUC Ordr 47,163,921 109,706,04 18231401 117,735,417 39,134,552
12 #27660 (amor period 06109 thru 05/10)
13
14 Fixed Cost Adjusment (FCA) Order #30267 2,721,219 6,581,45 1823 2,721,219 6,581,458
15 (amort period 06109 th 05110)
16
17 Prir Year FCA Ordr #3267 2,739,02 4074/4210 1,48,778 1,254,247
18
19 Idaho - Demand Side Maagement - IPUC orer 4,86,935 401 3,242,60 1,621,331
20 #27660 (amor period 7/9 thru 6110)
21
22 Excess Powr Amorzatin - OPUC Ordr#70 1,66,272 49,012 401 1,712,284
23
24 Exce Pow Deferl 06/07 -IPUC Order #07-555 1,214,698 2,38,111 vari 2,052,180 1,542,629
25 (amort period 10109 thru 02/12)
26
27 IPUC Grid West loans -IPUC order #30157 559,30 401 186,435 372,871
28 (amort peri 1/07 -12/11)
29
30 FERC Grid West Expense - ER08-629.QOO 36,117 401 83,796 279,321
31 (amort period 0508 thru 04113)
32
33 SFAS 106/158 Past Retirement Benefts 18,903,935 35,35 228 3,615,120 15,324,165
34 IPUC order #3256
35
36 SFAS 87/58 Pension Accmulated ( 7,170,251)5,822,257 vari 577,710 -1,925,704
37 IPUC ordr #30256
38
39 Pensio Defer FERC Poron 715,538 715,538
40
41 Pension Deerr Oreon Order UE-213 572,286 572,286
42
43 FAS 87 Deferr Pensio-IPUC order #30333 10,582,734 29,920,698 various 2,54,153 37,963,279
44 TOTAL 697,64,724 361,096,635 342,909,506 715,831,853
FERC FORM NO. 1/3.Q (REV. 02-04)Page 232
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/12/2010
o HER REGULATORY ASSETS (Account 182.3)
1. Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable.
2. Minor items (5% of the Balance in Account 182.3 at end of penod, or amounts less than $100,000 which ever is less), may be
grouped by classes.
3. For Regulatory Assets being amortized, show penod of amortzation.
Line Description and Purpose of Balanc at Debit CREDITS Balanc at end of
No.Other Regulatory Assets Beginning of vvrnen OI uunng wnnen on uunng Curr QuartrN ear
Currnt the QuarterNear the Period
QuartNear Accunt Charged Amount
(a)(b)(c)(d)(e)(f)
1
2 FIN 48 Adjustment-Intre Payable-rder #30256 158,44,161 3,764,073 228 9,507,024 152,701,210
3
4 PS & I Coal Plant - Ordr #29 150,092 401 85,767 64.325
5 (amort period 10/207thru 9/10)
6
7 10 DSM Rid Recass- 29026 3,942,318 32,111,886 254 26,335,68 9,718,518
8
9 PCAM Oron 2008 Order #08-238 5,399,651 5,836,616 various 5,750,854 5,485,419
10
11 Excess Power Deferl 2007 7,86,376 1823/254 1,671,26 6,193,11
12 IPUC ordr #0-189
13
14 OreOl DSM Ridr Recass Advice #05-3 1,721,88 143/254 85,112 866,772
15
16 2009 Reorg order #30914 1,145,20 1,145,203
17 (amort period 01/10 thru 12/14)
18
19 OA n Revenue Deferr ResNe Order #30940 7,612,562 186 2,925,724 4,686,838
20 (amort period 01/11thru 12/13)
21
22 Minor items (17)152,620 1,242,709 various 1,229,149 166,180
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44 TOTAL 697,644,724 361,096,635 342,909,506 715,831,853
FERC FORM NO. 1/3-Q (REV. 02-04)Page 232.1
This Page r~tentionally Left Blank
Name of Respondent This 'r0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) FiA Resubmission 04/12/2010
M SCELLANEOUS DEFFERED DEBITS (Accunt 186)
1. Report below the particulars (details) called for con~ming miscellaneous deferred debits.
2. For any deferred debit being amortized, show period of amorization in column (a)
3. Minor item (1 % of the Balance at End of Year for Accunt 186 or amounts less than $100,000, whichever is less) may be grouped by
classs.
Line Description of Miscellaneous Balance at Debits CREDITS Balance at
No.Deferred Debits Beginning of Year ~çcUnt.Amount End of Year
Char~ed
(a)(b)(c)(d (e)(f)
1 Rents - Rights of wav 137,573 310,762 165/401 177,967 270,368
2
3 2008 Poll Control Bond Refin 161,081 5,233,405 various 1,046,585 4,347,901
4
5 Advance prepaid coal royalties 1,580,516 9€various 73,409 1,507,205
6
7 Security plan 24,753,750 3,089,672 various 6,977,161 20,866,261
8
9 American Falls bond refinance 235,262 401 14,553 220,709
10 (amort period 4/00 thru 7/26)
11
12 Prepaid Credit Facility 446,435 431 193,067 253,368
13
14 Company owned Life Insurance 4,728,515 2,946,674 various 1,887,786 5,787,403
15
16 American Falls water riahts 16,758,974 401 1,042,009 15,716,965
17 (amort period 1/06 thru 12/25
18
19 Milner bond guarantee 9,572,727 253 1,063,636 8,509,091
20
21 Southwest interte project -2,951,825 3,121,5M various 6,073,369
22 right ofwav costs
23
24 American Falls - bond refinance 775,986 401 47,999 727,987
25 (35 year amortization)
26
27 Shelf Registration - 2008 2,100,982 various 1,126,927 974,055
28
29 Transmission Deposit-PacifiCorp 661,875 329,245 131/186 329,245 661,875
30
31 Prepaid PeoplesoftPassport 134,206 150,619 401 175,229 109,596
32
33 Boardman Power Plant 149,444 317,228 various 410,996 55,676
34
35 Long Term Workers Compensation 1,328,78E 1,328,786
36
37 OA IT Revenue Deferred Reserve 2,925,724 1823/400 5,851,448 -2,925,724
38 order #30940
39
40 Minor Items & Job Orders (9)11,635 7,051,710 various 6,981,993 81,352
41
42
43
44
45
46
47 Misc. Work in Progress
48 Deferred Regulatory Comm.
Expenses (See pages 350 - 351)
49 TOTAL 63,059,804 58,492,874
FERC FORM NO.1 (ED. 12-94)Page 233
Name of Respondent
Idaho Power Company
YearlPeriod of Report
End of 2009/Q4
This f3ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/121010
ACCU ULATED DEFERRED INCOME TAX S (Accunt 190)
1. Report the information called for below concerning the respondent's accunting for deferred income taxes.
2. At Other (Specfy), include deferrls relating to other income and deducons.
ine
No.(a)
Electric
Emission Allowances
Advances for Construction
-3,114,188
9,305,479
21,074,809
-847,076
8,334,734
21,611,994
TOTAL Electric (Enter Total of lines 2 thru 7)
Gas
Other
TOTAL Gas (Enter Total of lines 10 thru 15
17,642,299
167,646,855
18,203,912
170,110,978
Notes
FERC FORM NO.1 (ED. 12-88)Page 234
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) cAn Original (Mo, Da, Yr)
Idaho Power Company (2) A Resubmission 04/1212010 2009/Q4
FOOTNOTE DATA
l$chedule Page: 234 Line No.: 5 Column: a
(Note 1):
Post Retiree Benefits-VEBA
AFUDC Hells Canyon Relicensin9
Rate Case Disallowance
Stock Based Compensation
Other Employee's Long Term Deferred Compensation
Post Retirement Benefits
Deferred Idaho ITC
Non-VEBA Pension and Benefits
Oregon-Pension Expense
FERC Credit OF A
IRS Interest Expense
Deferred GBC
Provision For Rate Refunds
Linden Feeder Deposits
Bonus Deferral
Delivery Accruals
Total Other Electric
Beginning Balance
4,929,292
o
2,996,870
2,316,811
1,829,072
1,044,456
o
662,313
o
o
2,090,777
o
5,217,171
o
(6,306)
(5,647)
21,074,809
Ending Balance
5,583,994
3,868,089
2,881,031
2,235,008
2,039,678
1,765,736
1,656,363
573,602
471,584
424,728
113,033
12,000
o
o
(2,577)
(10,275)
21,611,994
¡Schedule Page: 234 Line No.: 7 Column: a
(Note 2):
Pension
Regulatory Liabilty for Income Taxes
Postretirement Plan
Minimum Pension Liabilty
Total Other
61,943,745
44,340,913
10,863,822
5,589,976
122,738,456
59,698,538
47,183,294
9,450,830
6,474,752
122,807,414
\Schedule Page: 234 Line No.: 17 Column: a
Senior Management Securit Plan
SMSP-Market Change of Rabbi Investments
Micron-CIAC
Meridian Gold Contributions
Bridger Sierra Reserve-Legal Fee's
Unrealized Loss on Investments
Loss on Pioneer Land Write-down
Total Non Electric
12,912,430
2,669,975
1,764,126
152,679
97,738
45,351
17,642,299
13,718,388
2,669,975
1,526,244
130,567
97,738
61,000
18,203,912
IFERC FORM NO.1 (ED. 12-87) Page 450.1
Name of Respondent This mort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2009/04
(2) FiA Resubmission 04/121010
CAPITAL STOCKS (Accunt 201 and 2 )4)
1. Report below the particulars (details) called for concerning common and preferred stock at end of year, distinguishing separate
series of any general dass. Show separate totals for common and preferred stock. If information to meet the stock exchange reportng
requirement outlined in column (a) is available from the SEC 10-K Report Form filing, a specific reference to reprt form (i.e., year and
company title) may be reported in column (a) provided the fiscal years for both the 1Q-K report and this report are compatible.
2. Entries in column (b) should represent the number of shares authorized by the artides of incorpration 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 Authoried by Charter Value per share End of Year
(a)(b)(c)(d)
1 Accunt 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 Accunt 204 - None
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FEC FORM NO.1 (ED. 12-91)Page 250
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) CiA Resubmission 0411212010
CAPITAL STOCKS (Account 201 and 2 )4) (Continued)
3. Give particulars (details) concerning shares of any class and series of stock authonzed 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 reuction AS REACQUIRED STOCK (Accunt 217)IN SINKING AND OTHER FUNDS No.
for amounts held by respondent)
sn.ares Amount s'1ares G!)st sn~res Amount
(e)(f)(g)(h)(i)ü)
1
39,150,812 97,877,030 2
3
39,150,812 97,8n,030 4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO.1 (ED. 12-88)Page 251
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Oriinal (Mo, Da, Yr)End of 2009/Q4
(2) DA Resubmision 04121010
OT-ER PAID-IN CAPITAL (Acunts 208-211, inc.)
Report below the balance at the end of the year and the information specified bel for the respecive other paid-in capital accunts. Provide a
subheading for each accunt and show a total for the accunt, as well as total of all accunts for reconciliation with balance sheet, Page 112. Add more
columns for any accunt if deemed necesary. Explain changes made in any accunt during the year and give the accunting entries effecting such
change.
(a) Donations Received from Stockholders (Acunt 208)-5tate amount and give brif 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 brif explanation of the capital change which gave rise to
amounts reported under this caption including identication wit the class and series of stoc to which related.
(c) Gain on Resale or Cancellation of Reacquired Capital Stoc (Accunt 210): Report balance at beginning of year, credits. debit, 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 (Accunt 211 )-Classif amounts included in this account accrding to captions which, together with brief explanations,
disclose the general nature of the transactions which gave rise to the reported amounts.
!~e Ilir A'Wfnto.
1 Accunt 208 - Donations received from stockholders - None
2
3 Accunt 209 - Reduction in par or stated value of Capitl Stoc - None
4
5 Accunt 210 - Gain on reacquired Capital Stock - None
6
7
8 Accunt 211 - Miscellaneous paid-in Capital - None
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23 .
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40 TOTAL
FERC FORM NO.1 (ED. 12-87)Page 253
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) DA Resubmission 04/12/2010
CAPITAL STOCK EXPENSE (Accunt 214)
1.Report the balance at end of the year of discount on capital stock for each class and series of capital stock.
2. If any change occurred during the year in the balance in respec to any class or series of stock, attach a statement giving particulars
(details) of the change. State the reason for any charge-off of capitl stock expense and specif the accunt charged.
¡ Line Class and series or ~tOCK Báfance at End ot 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
FERC FORM NO.1 (ED. 12-87)Page 254b
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Oa, Yr)End of 2009/04
(2) DA Resubmission 04/121010
L JNG- TERM DEBT (Accunt 221 , 222, 223 and 224)
1. Report by balance sheet accunt the particulars (details) conceming long-term debt included in Accunts 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 authorition 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 accunts. Designate
demand notes as such. Include in column (a) names of assoated companies frm which advances were recived.
5. For recivers, certificates, show in column (a) the name of the cort -and date of court order under which such certificates were
issued.
6. In column (b) show the principal amount of bonds or other long-ter debt orginally issued.
7. In column (c) show the expense, premium or discount wit respe to the amount of bonds or other long-term debt originally issued.
8. For coumn (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
Indicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted.
9. Fumish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year. Also, give in a footnote the date of the Commission's authorization of treatment other than as
specfied by the Uniform System of Accunts.
Line Class and Seri of Obligation, Coupon Rate Principal Amount Total expense,
No.(For new issue, give commission Authoriatin numbrs and dates)Of Debt issued Premium or Discount
(a)(b)(c)
1 Accunt 221:
2 First Mortage Bonds:
3 4.50% Series due 2020 OPUC #4244 IPUC IPC-E-D7-19 WPSC #20005-31-ES-D7 130,000,000 234,601 0
4
5 5.50% Series due 2033 70,000,000 -728,701 P
6 36,400 0
7
8 6.15% Series Due 2019 OPUC #4244 IPUC IPC-E-D7 -19 WPSC 2005-31-E5-7 100,000,000 184,949 0
9 -1,034,909 P
10
11 7.20% Series due 2009 80,000,000 .572,246 P
12
13 5.30% Series Due 2035 60,000,000 408,411 0
14 -3,84,739 P
15
16 6.60% Series due 2011 120,000,000 -860,502 P
17
18 4.25%Series due 2013 70,000,000 -61,201 P
19 374,500 0
20
21 4.75% Series due 2012 100,000,000 -94,356 P
22 1,047,617 0
23
24 6.00% Series due 2032 100,000,000 -1,069,356 P
25 543,244 0
26
27 5.875% Series due 2034 55,000,000 -585,759 P
28 383,322 0
29
30 5.50% Series due 2034 50,000,000 746,961 0
31 -524,419 P
32
33 TOTAL 1,663,145,000 -12,808,874
FERC FORM NO.1 (ED. 12-96)Page 256
, Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) nA ResubmÎSsion 04/1212010
LONG- TERM DEBT (Account 221 , 222, 22 and 224) (Continued)
10.Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Accunt 428, Amortization and Expense, or credited to Accunt 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 advance 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 purpse 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
expnse in column (i). Explain in a footnote any diference between the total of column (i) and the total of Account 427, interest on
Long- Term Debt and Accunt 430, Interest on Debt to Associated Companies.
16. Give particulars (details) concerning any long-term debt authorized by a regulatory comission but not yet issued.
AMORTIZATION PERIOD ul!tstan!ling Line
Nominal Date Date of (Total amount outstan ing without Interest for Year No.
of Issue Maturity Date From Date To reduction for amounts held by Amount
(d)(e)(f)(g)
resp~~dent)(i)
1
2
11/20/09 311/20 11/20/09 3/1/20 130,OOO,00C 666,250 3
4
05/01/03 04/01/33 05/01/03 03131/33 70,000,000 3,850,000 5
6
7
4/1/09 4/1/19 4/1/09 4/1/19 100,OOO,OOC 4,629,583 8
9
10
11/23/99 12/01/09 01/01/00 01/01110 5,280,000 11
12
08/26/05 08/26/35 08/26/05 08/26/35 60,000,000 3,180,000 13
14
15
03/02101 03/02111 03/02/01 03/02111 120,000,000 .7,920,000 16
17
05/01/03 10/01/13 05/01103 09/29/13 70,000,000 2,975,000 18
19
20
11115/02 11/15/12 11/15/02 11/15/12 100,000,000 4,750,000 21
22
23
11/15/02 11/15/32 11115/02 11/15/32 100,000,000 6,000,000 24
25
26
08/16104 08/16/34 08/16/04 08/16/34 55,000,000 3,231,250 27
28
29
03/26/04 03/15/34 03/26/04 03/15/34 50,000,000 2,750,000 30
31
32
1,413,854,091 73,269,850 33
FERC FORM NO.1 (ED. 12-96)Page 257
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) DA Resubmission 04/121010
L JNG- TERM DEBT (Account 221, 222, 223 and 224)
1. Report by balance sheet accunt 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 ofthe 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 assoated companies from which advances were received.
5. For receivers, certificates, show in column (a) the name ofthe court -and date of court order under which such certificates were
issued.
6. In column (b) show the pnncipal amount of bonds or other long-ter debt onginally 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 dunng the year. Also, give in a footnote the date of the Commission's authonzation 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 Authoriation numbers and dates)Of Debt issued Premium or Discount
(a)(b)(c)
1 6.30% Series due 2037 140,000,000 -1,495,799 P
2 273,721 D
3
4 6.25% Series due 2037 100,000,000 -1,141,489 P
5 266,188 D
6
7 Port of Morrow Variable due 2027 4,360,000 -188,545 P
8
9 Humboldt Variable due 2024 49,800,000 -1,697,856 P
10
11 Sweetwater Variable due 2026 116,300,000 -820,043 P
12 471,252 D
13
14 6.025 % Series Due 2018 120,000,000 -1,630,120 P
15
16 2008 Credit Facilty 166,100,000
17 Subtotal Accunt 221 1,631,560,000 -12,808,874
18
19 Accunt 222 - Reaquired Bonds
20
21 Accunt 223: Advances for Associated Companies
22
23 Accunt 224:
24 Bond Guarantee - American Falls 19,885,000
25 Note Guarantee - Milner Dam 11,700,000
26 Subtotal Account 224 31,585,000
27
28
29
30
31
32
33 TOTAL 1,663,145,000 -12,808,874
FERC FORM NO.1 (ED. 12-96)Page 256.1
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) FiA Resubmission 04/12/2010
LONG-TERM DEBT (Accunt 221, 222, 22 and 224) (Continued)
10.Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Accunt 428, Amortization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. In a footnote, give explanatory (details) for Accunts 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 serities in a footnote.
15. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on
Long-Term Debt and Account 430, Interest on Debt to Associated Companies.
16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
AMORTIZATION PERIOD ul.lSlan!llns Line
Nominal Date Date of (Total amount outstan ing without Interest for Year No.
of Issue Maturity Date From Date To reduction for amounts held by Amount
(d)(e)(f)(g)
resp?~dent)(i)
6122107 6/15/2037 6/22/07 6/15/2037 140,000,000 8,820,000 1
2
3
10/18/07 10/15/2037 10/18/07 10/15/2037 100,000,000 6,250,000 4
5
6
05/17/00 02101/27 05/17/00 02101/27 4,360,000 122,024 7
8
10122/03 12/01/24 11/01/03 12101124 49,800,000 .933,266 9
10
10/3/06 7115/26 10/3/06 7115/2026 116,300,000 2,221,815 11
12
13
7/10/08 7/15/18 7/10/08 715/08 120,OOO,OOC 7,230,000 14
15
4/1/08 3/31/09 4/1108 3/31/09 2,460,662 16
1,385,460,000 73,269,850 17
18
19
20
21
22
23
04/26/00 211/25 19,885,000 24
02/10/92 8,509,091 25
28,394,091 26
27
28
29
30
31
32
1,413,854,091 73,269,850 33
FERC FORM NO.1 (ED. 12-96)Page 257.1
This Page ~~tentionally Left Blank
Name of Respondent This i!0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2oo9/Q4
(2) OA Resubmission 04/1212010
RECONCILIATION OF REP( RTED 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 reconcilation, 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 rencilng amount.
2. If the utilty 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 consistnt 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 l'articulars (Details)Amount
No.(a)(b)
1 Net Income for the Year (Page 117)122,558,984
2
3
4 Taxable Income Not Reported on Books
5
6
7
8
9 Deductions Recorded on Books Not Deducted for Return
10
11
12
13
14 Income Recorded on Books Not Included in Return
15
16
17
18
19 Deductions on Return Not Charged Against Book Income
20
21
22
23
24
25
26
27 Federal Tax Net Income 86,682,170
28 Show Computation ofTax:
29 Tenative Federal Tax ~ 35%30,338,760
30
31
32
33
34
35 .
36
37
38
39
40
41
42
43
44
FERC FORM NO.1 (ED. 12-96)Page 261
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2) A Resubmission 04/1212010 2009/Q4
FOOTNOTE DATA
¡Schedule Page: 261 Line No.: 5 Column: b
004003-CONSTRUCTION ADV-252
004005-AVOIDED COST INT CAP
004006-RETIREMENTS-RECORD TAX GAIN/LOSS
004010-EMISSION ALLOWANCE-254.409-411
004013-CIAC AS TAXBLE INC IN ACCT 107
004018-L1NDEN FEEDER DEPOSITS-253.206
004021-ENGINEERING FEES-IN ACCT 107-FED ONLY
004022-FERC CREDIT OFA-254.307
004501-ROYAL TY INCOME BTL
004506-CIAC-MERIDIAN GOLD
004507 -CIAC-MICRON-DRAM
Total
!Schedule Page: 261 Line No.: 10 Column: b
TOTAL FEDERAL AND STATE TAXES DEDUCTED ON BOOKS
005001-BAD DEBT EXPENSE
005010-SFAS 112-POST-EMPL Y 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 -OTHER EMPLOYEE'S L T DEFERRED COMP-228
005052-AMORTIZATION OF ACCOUNT 181
005053-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)
005061-PENSION EXPENSE-OREGON
005501-SEC PLAN-NET INS COSTS
005503-128-EDC-UNRLZD GN/LS FRM RABBI TRUST
005504-NONDEDUCTIBLE POLITICAL EXP-426.4
005505-SEC PLAN-BENEFIT ACCR
005516-NONDEDUCTIBLE POLITICAL EXP-O&M ACCTS
005531-RATE CASE DISALLOWANCES-REVERSE AMORT
005532-DELIVERY ACCRUALS-253.550
Total
¡Schedule Page: 261 Line No.: 15 Column: b
007009-PROVISION FOR RATE REFUNDS-ACCT 229
007010-AFUDC HC RELICENSING-ACCT 229
IFERC FORM NO.1 (ED. 12-87) Page 450.1
$(2,773,559)
4,368,718
(2,000,000)
8,402,722
(13,149,262)
(420,523)
(511,236)
1,086,401
100,000
(56,560)
(608,470)
$(5,561,769)
$32,573,455
266,407
1,844,942
194,394
(2,592,781)
353,238
(10,000,000)
600,000
(524,527)
(22,723)
(46,046)
(226,912)
69,409,536
219,181
538,704
146,153
(209,241)
186,435
(4,757)
83,796
(11,726)
(6,219,265)
88,689
(85,762)
1,206,251
(281,520)
(518,785)
1,050,861
2,061,539
100,000
(296,299)
(80,907)
$89,802,330
$ 13,344,853
(9,894,077)
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 04/1212010 2oo9/Q4
FOOTNOTE DATA
007011-0ATT REVENUE DEFICIENCY
007501-REVERSE EQUITY EARNINGS OF SUBSIDIARIES
007502-ALLOWANCE FOR OFUDC
007503-ALLOWANCE FOR BFUDC
007504-RECLASS TAX EXEMPT INTEREST-FED ONLY
oo7509-SECURITY PLAN-INSURANCE PROCEEDS
Total
1,761,114
4,957,254
7,554,922
5,397,871
4,717
1.943,416
$ 25,070,070
!Schedule Page: 261 Line No.: 20 Column: b
008001-VEBA-POST RET BNFTS-TRUST-ACCT 228
008009-DEPR FOR TAX GT OR L T BOOK
008016-VEBA-POST RET BNFTS-TRUST-MEDICARE PART D
008020-CONSERVATION PROGRAMS
008025-MANUFACTURING DEDUCTION
008027-NEVADA OPERATING PROPERTY TAX ADJ
008034-REMOVAL COSTS
008035-REPAIR ALLOWANCE
008038-0REGON EXCESS PWR SUPPLY COSTS
008041-AM FALLS - UNAMORTIZED DEBT EXP
008042-GAIN/LOSS ON REACQUIRED DEBT-FT
008057 -REORGANIZATION COSTS
008059-SFTWR COSTS-MISC-1 07 -FED ONLY
008072-INTANGIBLE ASSET-LABOR DEDUCT-107-FED ONLY
008077-PP INS & OTR EXP (1 YR OR LESS)-165
008501-COLl-TAX ADJ FROM BOOKS
008504-0REGON NONOP PROPERTY TAX ADJUST
008703-IPCO - 162 (M) $1m THRESHOLD
ON10016-DIV PAID DED PUB UTIL
IRS INTEREST EXPENSE
STATE INCOME TAX DEDUCTED ON FEDERAL RETURN
Total
$ (1,615,820)
47,115,386
703,000
3,400,368
4,086,963
89,475
10,884,841
10,000,000
5,089,767
(47,999)
2,598,905
1,145,203
1,000,000
1,108,000
1,279,624
2,442,758
12
(775,671)
300,000
249,457
5.993,036
$ 95,047,305
IFERC 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 2009/Q4
(2) FiA Resubmission 04121010
TA: ES ACCRUED, PREPAID AND CHAI GED DURING YER
1. Give partculars (details) of the combined prepaid and acced ta accunts and show the total taxes charged to operations and other accunts during
the year. Do not include gasoline and other sales taxes which have ben charged to the accunts to which the taxed material was charged. If the
actual, or estimated amounts of such taxes are know, show the amounts in a fotnote and designate whether estimate or actual amounts.
2. Include on this page, taxes paid during the year and charged direct to final accunts, (not charged to prepaid or acced taxes.)
Enter the amounts in both columns (d) and (e). The balancing ofthis page is not affd by the inclusion ofthese taxes.
3. Include in column (d) taxes charged during the year, taxes charged to operations and other accunts through (a) accuals creditèd to taxes accred,
(b)amounts crdited to proportions of prepaid taxes chargable to current year, and (c) taxes paid and charged direct to operations or accounts other
than accrued and prepaid tax accunts.
4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
ine Kind of Tax BALANCE AT BEGINNING OF YEAR c1~~~T~~1ã Adjust-
No.(See instruction 5)TaxesA~~fJreaid Taxes ~~~g ~ring ments
(Accunt 236)(Include in Accunt 165)ear
(a)(b)(c)(d)(e)(f)
1 Federal:
2 Income -4,279,599 19,534,398 -19,542,121
3 Social Security - (FOAB)409 12,208,440 12,206,314
4 Unemployment -36 75,819 75,819
5 Subtotal Federal -4,279,226 31,818,657 -7,259,988 -375
6
7 State of Idaho:
8 Prort 4,978,404 -75 12,633,142 11,947,458
9 Non-operating 14,99 32,911 26,041
10 Income -3,798,000 2,113,920 2,894,44
11 KWH 95,195 1,849,144 1,825,157
12 Unemployment 6,204 466,050 492,204
13 Regulatory Commission 1,347,232 1,347,232
14 Business License - Sho Ban 150 150 150
15 Subtotal Idaho 1,296,799 75 18,442,549 18,532,688 19,947
16
17 State of Oregon
18 Propert 1,044,661 2,136,606 2,182,652
19 Non-operating Propert 754 1,521 1,533
20 Income -212,449 169,976 219,082
21 Regulatory Commission 118,625 97,325
22 Unemployment -14 15,877 15,877
23 Franchise 137,706 610,826 587,639
24 Subtotal Oregon -74,757 1,045,415 3,053,431 3,104,108 21
25
26 State of Montana:
27 Propert 99,130 238,460 218,442
28 Subtotal Montana 99,130 238,460 218,442
29
30 State of Nevada:
31 Propert 443,859 1,003,360 1,092,835
32 Business Tax 100 100
33 Subtotal Nevada 443,859 1,003,460 1,092,935
34
35 State of Wyoming
36 Corporate License 3,387 3,387
37 Propert 513,670 1,128,204 1,077,771
38 Subtotal Wyoming 513,670 1,131,591 1,081,158
39 Other States Income 31,734 64,710 -10,351
40 Payroll Adjustment -12,766,186
41 TOTAL -42,412,650 1,489,349 42,986,672 16,758,992 19,593
FERC FORM NO.1 (ED. 12-96)Page 262
l
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) EiA Resubmission 04/1212010
TAXES ACCI UED, PREPAID AND CHARGED DU ING YEAR (Continued)
5. If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year,
identifing the year in column (a).
6. Enter all adjustments of the accrued and prepaid tax accunts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments
by parentheses.
7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending
transmittl 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 Accunts 408.1 and 109.1 pertining to other utilit departents and
amounts charged to Accunts 408.2 and 409.2. Also shown in column (I) the taxes charged to utility plant or other balanæ sheet accunts.
9. For any tax apportoned to more than one utility department or accunt, state in a footnote the basis (neæssity) of apportioning such tax.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Line
(Taxes accred Prepaid Taxes Electric Extraordinary Items . Aaiustments to Ret.Other No.
Acc~nt 236)(Incl. in Account 165) (Account 408.1, 409.1)(Accunt 409.3)Earnings (Accunt 439)
g)(h) ~0)(k)(i)
1
-5,203,080 18,051,943 ~
2,124 12,208,440 3
75,819 4
-5,200,956 30,336,202 1,482,455 5
6
7
5,673,820 225 12,633,142 8
21,86 ~-4,578,526 1,816,273 10
119,182 1,849,144 11
-3 466,050 12
1,347,232 13
150 150 14
1,236,339 375 18,111,991 330,558 15
16
17
1,090,708 2,136,606 ~766
-261,555 156,173 20
21,300 118,625 21
7 15,877 22
160,894 610,826 23
-79,354 1,091,474 3,038,107 15,324 24
25
26
119,148 238,460 27
119,148 238,460 28
.29
30
533,334 1,003,360 31
100 32
533,334 1,003,460 33
34
35
3,387 36
564,102 1,128,204 37
564,102 1,131,591 38
106,794 59,876 ~
-12,766,186 40
-3,253,927 1,625,183 41,153,501 1,833,171 41
FERC FORM NO.1 (ED. 12-96)Page 263
This Page r~tentioDally Left Blan
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 041212010 2009/04
FOOTNOTE DATA
!Schedule Page: 262 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 2009 this cross-check will not work as the
total of lines 14-16 on page 114 is $2,981,574 more 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 of the entry is not associated with accounts 236
or 165. Therefore FIN #48 will show up on page 114 but will not be on pages 262& 263.
¡Schedule Page: 262 Line No.: 2 Column: iAccount 409.2 $ 1,681,539237 (10,429)234 (188,655)
Total $ 1,482,455============
!Schedule Page: 262 Line No.: 3 Column: f
Entry was to clear up an adj ustment which was the result of a change in rates.
¡Schedule Page: 262 Line No.: 4 Column: f
Entry is to clear up adjustment that was the result of a change in the rates.
¡Schedule Page: 262Account 408.2
I$chedule Page: 262Account 409.2
234
Total
Line No.: 9 Column: i
$ 32,911
Line No.: 10 Column: i
$ 331,587(33,940)
$ 297,647===========
¡Schedule Page: 262 Line No.: 12 Column: f I
This amount represents an adjustment as a result of changes in the unemployment tax rates.
I$chedule Page: 262Account 408.2
I$chedule Page: 262Account 409.2
234
Total
Line No.: 19 Column: i
$ 1,521
Line No.: 20 Column: i
$ 15,529
(1,726)
$13,803
==========
I$chedule Page: 262 Line No.: 22 Column: fThis amount represents an adjustment for a change in unemployment tax rates for the year.
I$chedule Page: 262 Line No.: 39 Column: iAccount 409.2 $ 5,409234 (575)
Total $ 4,834
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)End of 2009/Q4
(2) OA Resubmission 0411212010
ACCUMULA ED DEFERRED INVESTMENT TAX REDITS (Accunt 255)
Report below information applicable to Accunt 255. 'Mere appropriate. seregate the balances and transactions by utilit and
nonutilty operations. Explain by footnote any correcion adjustments to the accunt balance shown in column (g).Include in column (i)
the average period over which the tax credits are amortized.
Line Account Balanæ a!_~inning Deferred for Year l\i!ocaiions 10
No.SUbdlvisions of Year Current Yeats Income Adjustments
a)(c) (d) (e) (f) g
1 Electric Utilty
23%
34%941,495 115,931
47%
510%28,723,886 1,621,55E
6 1,320,423 26,72
7 42,284,273 411.4 3,639,767 411.4 1,640,1Q.
8 TOTAL 73,270,077 3,639,767 3,404,3H
9 Other (List separately
and show 3%, 4%, 7%,
10% and TOTAL)
10 Line 6 Col A 11%
11
12 State of Idaho 42,284,273 411.4 3,639,767 411.4 1,640,10~
13 ..
14
15
16
17
18
18
20
21
22
23
24
2!:
26
27
28
30
31
32
33
34
35
36
37
38
39
40
41
42
4:1
44
45
46
47
48
FERC FORM NO.1 (ED. 12-89)Page 266
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) ÕA Resubmission 04/1212010
ACCUMULATED 0EFERRED INVESTMENT TAX CRED S (Accunt 255) (continued)
~ADJUSTMENT EXPLANATION Line
of Year of AI ocation No.to Incomeh i ~
1
2
825,558 3
4
27,102,330 5
1,293,701 6
44,283,936 7
73,505,525 8
9
10
11
44,283,936 12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
FERC FORM NO.1 (ED. 12-89)Page 267
This Page rptentionally 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 2009/Q4
(2) FiA Resubmission 04/1212010
o HER DEFFERED CREDITS (Account 253)
1. Report below the particulars (details) called for conceming 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 Accunt 253 or amounts less than $100,000, whichever is greater) may be groupe by classes.
line Description and Other Balance at DEBITS Balance at
No.Deferred Credits Beginning of Year Contra Amount Credits End of Year
(b)
Accunt
(a)(c)(d)(e)(f)
1 Bureau of Land Mngt RentsROW 10,675,631 107/403 10,675,631
2
3 Point to Point Transmission Study 2,436,253 various 1,814,04 1,118,896 1,741,105
4
5 FT 5,266,666 400 400,000 4,866,666
6
7 SWiP Deposit 940,000 186/4211 1,880,000 940,000
8
9 Sho Ban Trans ROW 292,500 242 15,000 100,650 378,150
10
11 Delivery Accruals 198,964 107/401 1,147,396 1,045,495 97,063
12
13 Customer Level Pay 1,054,504 142 2,146,318 1,091,814
14
15 Milner Fallng Water 2,386,417 186 1,063,636 539,109 1,861,890
16
17 Postretirement Benefits 2,671,58 1,84,942 4,516,526
18
19 Directors Deferred Compensation 3,976,684 various 288,729 641,968 4,329,923
20
21 IBM Mainframe Softare Longterm 1,514,798 1,514,798
22
23 Minor Items (4)39,932 various 29,817 47,035 57,150
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47 TOTAL 29,939,135 19,460,571 8,884,707 19,363,271
FERCFORM NO.1 (ED. 12-94)Pag 269
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2009/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/1212010
ACCUMULATE DEFFERED INCOME TAXES - OT ER PROPERTY (Accunt 82)
1. Report the information called for below concerning the respondenfs accounting for deferred income taes rating to propert not
subject to acclerated amortization
2. For other (Specify) , include deferrals relating to other income and deductns.
CHANGES DURING YEAR
Line
No.
Accunt Balanæat
Beinning of Year Amounts Debited
to Accunt 410.1
(c)
Amounts Credited
to Account 411.1
(d)(a)(b)
1 Accunt 282
2 Electric
3 Gas
4 Other
5 TOTAL (Enter Total of lines 2 thru 4)
6 Non-Operating Propert
7 Other - Regulatory Asset for i
8
9 TOTAL Accunt 282 (Enter Total of lines 5 thru
10 Classifcation ofTOTAL
11 Federal Income Tax
12 State Income Tax
13 Local Income Tax
246,423,677 55,807,604 20,197,518
333,882,360
580,306,037 55,807,604 20,197,518
490,549,187
89,756,850
55,540,671
266,933
20,185,357
12,161
NOTES
FERC FORM NO.1 (ED. 12-96)Page 274
Name of Respondent
Idaho Power Company
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/1212010
E TAXES - OTHER PROPERTY (Accunt 282) (Continued)
Year/Period of Report
End of 2009/Q4
ACCUMULATED DEFERRED INCO
3. Use footnotes as required.
CHANGES DURING YEA
Amounts Debited Amounts Credited
to Accunt 410.2 to Accunt 411.2
ADJUSTMENTS
Amount
Balance at
End of Year
Line
No.
182
NOTES (Continued)
FERC FORM NO.1 (ED. 12-96)Page 275
This Page r~tentionally Left Blank
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/12/2010 2009/Q4
FOOTNOTE DATA
!Schedule Page: 274 Line No.: 2 Column: b
2009 Chanaes durina Year Ad. Dr Ad. Cr 2009
Beginning DR to CRto DR to CRto Acc.Acc.Ending
Line Account Balance 410.1 411.1 410.2 411.2 Cr.Amt Dr.Amt Balance
No.(a)b c d e f a h i i k
Line 2: Acclerated Depreciation 238,722,106 51,016,405 20,069,733 269,668,778
Intg Asset-Labor Ded 12,890,324 139,329 13,029,653
Valmy Capitalized Items 580,766 76,500 504,266
Bridger Capitalized Items 17,657 17,657 0
Eng Fees in Acc 107 (286,041)178,932 26,332 (133,441)
Misc Softare Dev Costs 494,627 (129,304)365,323
Taxable CIAC in CWIP (5,995,762)4,602,242 7,296 (1,400,816)
TOTAL Line 2 246,423,677 55,807,604 20,197,518 282,033,763
IFERC FORM NO.1 (ED. 12-S7) Page 450.1
Name of Respondent
Idaho Power Company
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 0412/2010
ACCUMU TED DEFFERED INCOME TAXES - THER (Accunt 283)
1. Report the information called for below concerning the respondent's accnting for defrred income taxes relating to amounts
recorded in Accunt 283.
2. For other (Specfy , include deferrls relating to other income and deducns.
Year/Period of Report
End of 2009/Q4
(a)
Balance at
Beinning of Year
(b)
Line
No.
Accunt
1 Accunt 283
2 Electric
3 Other Elecric - See Note
4
5
6
7
8 Other - See Note
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 Oter -- See Note
19 TOTAL (Acc 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
110,64,659
21,255,495
8,308,334
1,596,051
25,272,907
4,854,987
NOTES
FERC FORM NO.1 (ED. 12-96)Page 276
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2009/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/12/2010
ACCUMULATED EFERRED INCOME TAXES - OTHE (Account 283) (Continued
3. Provide in the space below explanatioris for Page 276 and 277. Indude amounts relating to insignificant items listed under Other.
4. Use footnotes as required.
Balance at Une
End of Year No.
(k)
42,494,735
3,64,718
3,644,718
1,168,596
1,168,596
66,858,132
109,352,867
248,935 39,095 59,496
248,935 39,095 3,64,718 1,168,596 109,412,363
208,820 32,795 3,057,387 980,307 91,781,031
40,115 6,300 587,331 188,289 17,631,332
NOTES (Continued)
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 041212010 2oo9/Q4
FOOTNOTE DATA
¡Schedule Page: 276 Line No.: 3 Column: b
2009 Chanaes durina Year AdiDr Adi Cr 2009
Beginning DR to CRto DR to CRto Acc.Acct.Ending
Account Balance 410.1 411.1 410.2 411.2 Cr Amount Dr Amount Balance
(a)b c d e f a h i i k
PCA Expnse Deferral 56,054,006 0 28,135,64 27,918,362
Conservation Programs 1,901,555 3,677,967 807,343 4,772,179
Oregon Excess Pwr Costs 1,540,774 2,512,547 938,335 3,114,986
Oregon PCAM 2,110,996 127,253 93,725 2,144,524
IPUC Gri West Loans 218,661 0 72,887 145,774
OA TT Revenue Deficiency 0 688,508 0 688,508
Reorganization Costs 0 447,717 0 447,717
FERC Grid West Expense 141,961 0 32,760 109,201
OPUC Grid West Loans 25,410 1,860 0 27,269
Intervenor Funding Orders 30,223 17,112 12,527 34,808
Fixed Cost Adjustment 631,947 2,431,421 0 3,063,368
PS & I Costs-Coal & CHP 62,712 0 34,673 28,039
TOTAL 62,718,244 9,904,385 30,127,894 0 0 0 0 42,494,735
!Schedule Page: 276 Line No.: 8 Column: b
Pension 61,943,745 190 2,245,207 190 59,698,538
Postretirement Plan 7,390,494 190 1,399,511 190 5,990,982
Unrealized gains on Mkt 15 219 219 1,168,596 1,168,611
Sec
TOTAL 69,334,254 0 0 0 0 3,64,718 1,168,596 66,858,132
¡Schedule Page: 276 Line No.: 18 Column: b
Advance Coal Royalties 239,738 46,111 39,095 246,755
Ore Non-op Prop Tax Adj 295 5 0 299
Unrealized G/LRabbi Trust (390,377)202,819 0 (187,558)
TOTAL (150,344)0 0 248,935 39,095 0 0 59,496
IFERC FORM NO.1 (ED. 12-87) Page 450.1
Name of Respondent This 'ì0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2009/04
(2) ¡=A Resubmission 04/12/2010
o HER 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 Accunt 254 at end of period, or amounts less than $100,000 which ever is less),may be grouped
by classes.
3. For Regulatory Liabilities being amortized, show period of amortization.
Balance at Begining DEBITS Balance at End
Line Description and Purpose of of Current of Current
No.Other Regulatory Liabilities OuarterlYeaf Accunt Amount Credits QuarterlYearCredited
(a)(b)(c)(d)(e)(f)
1 Market to Market Short Term -IPUC Order#28661 652,080 175 4,101,274 3,951,863 502,669
2
3 Demand Side Managent Rider OR 196,827 varius 2,579,082 2,38,251
4
5 FAS 133 - Market to Market -IPUC Order # 2861 175 48,073 697,65 212,580
6
7 Fixed Cost Adjustmnt- Prior Y r Def 1,104,779 4074 1,104,779
8
9 Emission sale IEEP- Ord #30529 50,00 varius 57,99 37,091 479,101
10
11 Unfnded Acculated Deferred Incme Tax 44,34,913 various 659,658 3,502,03!47,183,29
12
13 Asst Retireme Oblication . Removal Cost 156,837,476 108 158,723,495 1,88,01
14
15 FERC Creit for OFA -IPUC Order #30754 401 620,808 1,707,209 1,086,401
16
17
18 Minor Items (11)16,032 various 86,596,183 86,594,181 14,034
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41 TOTAL 203,648,107 254,928,34.100,758,314 49,478,079
FERC FORM NO. 113-Q (REV 02"(4)Page 278
Name of Respondent
Idaho Power Company
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/1212010
E ECTRIC OPERATING REVENUES ( ccount 400)
1. The following instructions generally apply to the annual version of thes pages. Do not report quarterly data in coumns (c), (e), (f), and (g). Unbilled revenues and MWH
relate to unbiled revenues need not be reported separately as reuire in the annual ven of thes pages.
2. Report below operating revenues for each prsc accunt, and manufctured gas reues in tol.
3. Report number of customers, columns (f) and (g), on the basis of meters, in addit to th number of flat rate acunts; except that wh serate meter readings are added
fo bUling purposes, one customer should be counte fo each group of mete added. The -avege number of customers mens the avege of twlve liures at the close of
each moth.
4. If increses or decreases frm previous peod (coumns (c),(e), and (g)), ar not denv fr prsl rert fiures, explain any inconsistencies in a footnote.
5. Discose amounts of $250,000 or greater in a foobiote for acunts 451, 456, and 457.2.
Year/Period of Report
End of 2009/Q4
Line
No.
Tit of Accunt Ope Revenues Year
to Dat Quart/Annual
(b)
Opeting Revenues
Preious year (no Quart)
(c)
Sales of Electricity
2 (440) Residential Sales
3 (442) Commercial and Industrial Sales
4 Small (or Comm.) (See Instr. 4)
5 Large (or Ind.) (See Instr. 4)
6 (44) Public Street and Highway Lighting
7 (445) Other Sales to Public Authorities
8 (44) Sales to Railroads and Railways
9 (448) Interdepartmental Sales
10 TOTAL Sales to Ultimate Consumers
11 (447) Sales for Resale
12 TOTAL Sales of Elecricit
13 (Less) (449.1) Provision for Rate Refunds
14 TOTAL Revenues Net of Provo for Refunds
15 Other Operating Revenues
16 (450) Forfited Discounts
17 (451) Miscellaneous Service Revenues
18 (453) Sales of Water and Water Power
19 (454) Rent from Electric Propert
20 (455) Interdepartmental Rents
21 (456) Other Electric Revenues
22 (456.1) Revenues from Transmission of Elecricity of Others
23 (457.1) Regional Control Service Revenues
24 (457.2) Miscellaneous Revenues
25
26 TOTAL Other Operating Revenues
27 TOTAL Eleric Operating Revenues
(a)
339,240,028
141,529,986
3,230,165
305,854,293
122,302,388
- 2,892,343
893,479,498
94,373,321
987,852,819
-2,551,647
990,404,466
784,310,742
121,428,825
905,739,567
9,979,836
895,759,731-------------- ----- ---- -- --
3,811,350 3,669,976
18,272,233 18,889,639
32,457,459 19,432,928
1,050,873 18,323,290
55,591,915
1,045,996,381
60,315,833
956,075,56
FERC FORM NO. 1/3-Q (REV. 12-05)Page 300
Year/Period of Report
End of 2009/Q4
Name of Respondent
Idaho Power Company
This ~ort Is:
(1) ~An Original
(2) A Resubmission
E ECTRIC OPERATING REVENUES (
Date of Report
(Mo, Da, Yr)
04/12/2010
ccount400)
6. Commercial and industrial Sales, Accunt 442, may be classifi accrding to the basis of classifition (Smal or Commercal, and Large or Industral) regularly used by the
respondent if such basis of classfication 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.)
7. See pages 108-109, Importnt Changes During Perio, for importnt new terrtory adde and importnt rate increase or decreases.
8. For Lines 2,4,5,and 6, se Page 304 for amounts relating to unbiled revenue by accnts.
9. Include un metre sales. Provide details of such Sales in a foote.
MEGAWATI HOURS SOLD
Year to Date Quarter/Annual Amount Previous year (no Quarterly)(d) (e)
AVG.NO. CUSTOMERS PER MONTH Line
Current Year (no Quarterly) Previous Year (no Quarterly) No.(f) (9)
5
1,372 6
7
8
9
13,948,280 14,543,714 488,175 10
2,836,028 2,048,233 11
16,784,308 16,591,947 488,175 12
13
16,784,308 16,591,947 488,175 14
Line 12, column (b) ¡ndudes $
Line 12, column (d) ¡ndudes
6,736,815 of unbilled revenues.
40 MWH relating to unbiled revenues
FERC FORM NO. 1/3.Q (REV. 12-05)Page 301
This Page r~tentionally Left Blank
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Powe Company (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) FìA Resubmission 04/12/2010
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue accunt 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 accunt classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bils 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 billed pursuant thereto.
6. Report amount of unbiled revenue as of end of year for each applicable revenue accunt subheading.
I Line Numoer ana iiie Oflè $cIeaule Mvvn ::oia Kevenue Average Numoer ~vv"- OfSä\eS ry~%eokier
No.(a)(b)(c)ofC~~omers Per ~~stomer
(f)
1 440 - Residential Sales:
2 01 - Residential 5,286,52f 397,719,73.404,99i 13,053 0.0752
3 03 - Residential Master Meter 3,144 236,262 17 184,941 0.0751
4 04 - Residential - EW 832 61,O~51 16,314 0.0734
5 05 - Residential - TOO 1,221 89,978 79 15,45E 0.0737
E 15 - Dusk to dawn lighting 2,839 503,511 0.1774
,Unbiled Revenues 5,882 3,922,007 0.6668
8 Other Revenues 6,94,745
~Total 440 5,300,443 409,479,319 405,144 13,08~0.0773
1C
11 442-Commercial & Industrial Sales
12 07 - General service 175,670 16,032,6m 31,727 5,537 0.0913
13 09- General service 397,217 21,425,43~16~2.350,396 0.0539
14 09 - General service 3,241,472 188,932,352 29,730 109,030 0.0583
15 09 - General service 4,61lJ 236,061 3 1,536,667 0.0512
16 15 - Dusk to Dawn Light 4,174 673,225 0.1613
17 19 - Uniform rate contracts 2,097,012 96,617,388 1H 17,621,950 0.041
18 19 - Uniform rate contracts 7,632 388,69~1 7,632,000 0.0509
19 19 - Uniform rate contracts 121,091 5,066,614 4 30,272,75lJ 0.0418
20 24 - Irrigation Pumping 1,649,757 109,433,627 18,753 87,973 0.0663
21 40 - General service 13,773 948,433 1,153 11,945 0.0689
22 Commercial & Industrial & Unbil 904,491 40,056,59~0.043
23 Other Revenues 958,974
24 Total 442 8,616,899 480,770,014 81,659 105,523 0.0558
25
26 44 - Public Street Lighting:
27 40 - General service 2,76f 190,561 783 3,531 0.0689
28 41 - Street lighting 23,902 2,779,466 275 86,916 0.1163
29 42 - Traffc control lighting 3,937 198,69C 314 12,538 0.0505
30 Other Revenues 3J.61,448 0.1840
31 Total 444 30,938 3,230,165 1,372 22,550 0.1044
32
33
34
35
36
37
38
3~
40
41 TOTAL Billed 13,948,24(886,742,68"488,17!28,57.0.063E
42 Total Unbiled Rev.(See Instr. 6)4(6,736,815 (C 168.4204
43 TOTAL 13,948,28(893,479,498 488,17!28,57.0.0641
FERC FORM NO.1 (ED. 12-95)Page 304
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 2009/Q4
(2)A Resubmission 041121010
SALES FOR RESALE (Account 4 7)
1. Report all sales for resale (i.e., sales to purcasers other than ultimate consumers) trnsacted 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, capadty, 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 trncate the name or use acronyms. Explain in a footnoté any
ownership interest or affliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contracual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service whic the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this service in its system resourc planning). In addition, the reliabilty of requirements service must
be the same as, or second only to, the suppliets servic to its own ultmate consumers.
LF - for tong-term service. "Long-term" means fie years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under advers conditons (e.g., th supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF servic). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identifid 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 cotract.
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 aU firm serices 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 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 Authorit Statistca FERCRat Averaße Actual Demand (MW)
No.(Footnote Affliations)Classif Schule or Monthly i!lng Avera~e Aver~catin Tari Number Demand(MW Monthly NC Deman Monthly C mand
(a)(b)(c)(d)(e)(f)
1 Raft River Rural Electric V6-4 9.098 9.098 8.288
2 Raft River Rural Electric V6-n/a n/a n/a
3
4
5 Arizona Public Service Co.SF WSPP nla n/a n/a
6 Avista Corp.~WSPP n/a n/a n/a
7 Avista Corp.WSPP n/a n/a n/a
8 Barclays Bank PLC SF WSPP n/~n/a n/a
9 Black Hills Power Inc.wspp n/a n/a n/a
10 Black Hils Power Inc.WSPP n/a n/a n/a
11 Black Hils Power Inc.SF WSPP n/~n/a n/a
12 Bonnevile Power Administration WSPP n/a n/a n/a
13 Bonnevile Power Administration WSPP n/a n/~n/a
14 Bonnevile Power Administration SF WSPP n/a n/a n/a
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total Il 0 0
FERC FORM NO.1 (ED. 12-90)Page 310
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 2009/Q4
(2) nA Resubmission 04/1212010
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 accunting adjustments or "true-ups" for service provided in prior reportng
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 tariff under
which servic, 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 (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.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bils rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RO/Non-RO grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RO" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page .
401 ,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)0)(k)
55,078 695,552 1,823,133 6,OOC 2,524,685 1
178,639 178,639 2
3
4
251,589 4,858,079 4,858.07g 5
1,955 28,495 28,49f 6
9,115 247,278 247,27f 7
49,250 1,888,240 1,888,24C 8..~.
502 502 9
44,541 1,111,941 1,111,941 10
2,470 55,207 55,207 11
7,800 234,300 234,300 12
275 5,275 5,275 13
68,357 1,897,699 1,897,699 14
55,078 695,552 1,823,133 184,639 2,703,324
2,780,950 0 89,082,078 2,587,919 91,669,997
2,836,028 695,552 90,905,211 2,772,558 94,373,321
FERC FORM NO.1 (ED. 12-90)Page 311
Name of Respondent ThiS~ort Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2)A Resubmission 04/1212010
SALES FOR RESALE (Accunt 447)
1. Report all sales for resale (i.e., sales to purchasers otr than ultimate consumers) transacted on a settlement basis other than
poer exchanges during the year. Do not report exchanges of elecricity ( 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 base on the original contractual terms and conditions of the service as follows:
RQ - for requirements serice. Requirements service is servic which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this servce in its system resourc 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 interrpted for economic
reasons and is intended to remain reliable even under advers 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 identifed as LF, provide in a fotnte the terination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contr.
IF - for intermediate-term firm service. The same as LF servce except that "intermediate-term" means longer than one year but Less
than five years.
SF - for shortterm firm service. Use this caegory fo all firm serices where the durati 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 fie years or Longer. The availability and reliabilit of
service, aside from transmission constraints, must match the availabilit 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 Authorit Statisicl FERCRate Avera&T Actual Demand (MW)
No.(Footnote Affliations)Classif Schedule or Monthly iIling Avera~e Avera~
cation Tari Number Dend(MW Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 BP Energy Company SF WSPP nla nla nla
2 Cargil Power Markets LLC WSPP nla nla nla
3 Cargil Power Markets LLC WSPP nla nla nla
4 Cargil Power Markets LLC SF WSPP nla nla nla
5 Chelan Co PUD SF WSPP nla nla nla
6 Citigroup Energy Inc.SF WSPP nla nla nla
7 Conoc Phillps Company SF WSPP nla nla nla
8 Constellation Energy Commodites Group,WSPP nla n/s nfa
9 Constellation Energy Commodities Group,WSPP nls nla nla
10 Constellation Energy Commodities Group,SF WSPP nla nla nla
11 DB Energy Trading LLC SF WSPP nla nls nla
12 EI Paso Electric Company SF WSPP nla nls nla
13 Endure Energy, LLC WSPP nla nla nla
14 Endure Energy, LLC WSPP nla nla nla
Subtotal RQ C 0 0
Subtotal non-RQ C 0 0
Total (J 0 0
FERC FORM NO.1 (ED. 12-90)Page 310.1
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 2009/Q4
(2) ñA Resubmission 0411212010
S LES FOR RESALE (Accunt 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 accunting adjustments or "true-ups" for service provided in prior reportng
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 tariff 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 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 (6Q-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.
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 (j). Report in column (k)
th total charge shown on bils rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQlNon-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQn amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)(j)(k)
86,775 3,740,260 3,740,26(1
610,781 610,781 2
225 4,050 4,050 3
190,771 5,403,639 5,403,63g 4
200 7,000 7,000 5
116,600 3,895,230 3,895,23C 6
9,400 .377,320 377,32C 7
57 -4,471 -4,471 8
5,317 136,389 136,38~9
125,401 5,135,360 5,135,36(10
14,200 420,528 420,528 11
2,400 61,000 61,OO(12
12,775 12,775 13
270 2,160 2,16(14
55,078 695,552 1,823,133 184,639 2,703,324
2,780,950 0 89,082,078 2,587,919 91,669,997
2,836,028 695,552 90,905,211 2,772,558 94,373,321
FERC FORM NO.1 (ED. 12-90)Page 311.1
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) OA Resubmission 04/121010
SALES FOR RESALE (Account 4 7)
1. Report all sales for resale (i.e., sales to purcasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricit ( i.e., transactions involving a balancng of debits and credits
for energy, capacity, etc.) and any settements for imbalance 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 coumn (a). Do note abbreviate or trncate the name or use acrnyms. Explain in a footnote any
ownership interest or affliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classifion Code based on the oriinal contral terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is servic which the supplier plans to provide on an ongoing basis (i.e., the
supplier inetudes projected load for this service in its sysem 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 fie years or Longer and "firm" means that seric cannot be interrupted for economic
reasons and is intended to remain reliable even under advers 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 mees the
defnition 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 cotract.
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 caegory for all firm servics 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 availabilit and reliabilit of designated unit.
IU - for intermediate-term service from a designated generaing 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 Authorit Statistical FERC Rate Averße Actual Demand (MW)
No.(Footnote Affliations)Classif Schule or Monthly ¡!lng Avera~e Avera~
cation Tari Number Demand(MW Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Endure Energy, LLC SF wspp nla nla nla
2 Eugene Electri Board SF WSPP nla nla nla
3 Grant CO Public Utilit District #2 -SF WSPP nla nla nla
4 IBERDROLA RENEWABLES, Inc.WSPP nla nla nla
5 IBERDROLA RENEWABLES, Inc.WSPP nla nla nla
6 IBERDROLA RENEWABLES, Inc.SF WSPP nla nla nla
7 Integrys Energy Services, Inc.WSPP nla nla nla
8 Integrys Energy Services, Inc.SF WSPP nla nla nla
9 J. Arn & Company SF WSPP nla nla nla
10 J.P. Morgan Ventures Energy Corporation SF WSPP nla nla nla
11 Macquarie Cook Power Inc.SF WSPP nla nla nla
12 Morgan Stanley Capital Group Inc.WSPP nla nla nla
13 Morgan Stanley Capital Group Inc.-nla nla nla
14 Morgan Stanley Capital Group Inc.SF WSPP nla nla nla
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12-90)Page 310.2
Name of Respondent ThiS~ort Is:-Date of Report Year/Period of Report
Idaho Power Company (1)An Original (Mo, Da, Yr)End of 2009/Q4
(2)A Resubmission 04/12/2010
SJ LES FOR RESALE (Accunt 447) (Continued)
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.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reportng
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 coumn (a) as the Last Line of the schedule. Report subtotals and total for columns (9) throgh (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariff 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 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 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.
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 (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)0)(k)
3,200 69,600 69,600 1
400 20,400 20,400 2
4,000 140,292 140,292 3
11,209 11,209 4
2,629 48,774 48,774 5
139,452 4,756,695 4,756,695 6
175 3,325 3,325 7
51,216 2,322,004 2,322,004 8
30,400 2,090,000 2,090,000 9
28,400 1,148,412 1,148,412 10
14,025 461,740 461,740 11
20,640 20,640 12
37,252 37,252 13
200,000 5,645,504 5,645,504 14
55,078 695,552 1,823,133 184,639 2,703,324
2,780,950 0 89,082,078 2,587,919 91,669,997
2,836,028 695,552 90,905,211 2,772,558 94,373,321
FERC FORM NO.1 (ED. 12-90)Page 311.2
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2oo91Q4
(2) OA Resubmission 04/121010
SALES FOR RESALE (Accunt 4-7)
1. Report all sales for resale (i.e., sales to purchasers other than ultimate cosumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of elecrici ( 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 base 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 fie years or Longer and "frm" means that service cannot be interrupted for ecomic
reasons and is intended to remain reliable even under advers conditons (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 fotnote 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 perid of commitment fo 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 availabilty and reliabilit 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 iIling .p\iiera~e Ave~
cation Tariff Number Demand(MW)Monthly NC Deman Monthly C mand
(a)(b)(c)(d)(e)(f)
1 NextEra Energy Power Marketing, LLC SF WSPP nla nla nla
2 NorthPoint Energy Solutions Inc.SF WSPP nla nla nla
3 NorthWestern Energy ~WSPP nla nla nla
4 NorthWestem Energy WSPP nla nla nla
5 NortWestern Energy WSPP nla nla nla
6 PacifiCorp Inc.SF T-7 nla nla nla
7 PacifiCorp Inc.WSPP nla nla nla
8 PacifiCorp Inc.WSPP nla nla nla
9 Paciorp Inc.SF WSPP nla nla nla
10 Portland General Electric Company WSPP nla nla nla
11 Portland General Electric Company WSPP nla nla nla
12 Portland General Electric Company SF WSPP nla nla nla
13 Powerex Corp.WSPP nla n/a nla
14 Powerex Corp..~WSPP nla nla nla
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12-90)Page 310.3
Name of Respondent ThiS~ort Is: .Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, oa, Yr)End of 2009/Q4
(2)A Resubmission 04/12/2010
Si LES FOR RESALE (Accunt 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
year. 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 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 (SD-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 megawatt.
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 (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MeaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)Ü)(k)
15,600 390,000 390,000 1
100 2,600 2,600 2
-181 -181 3
69 69 4
290 7,960 7,960 5
72 2,535 2,535 6
1,293,778 1,293,778 7
4,600 61,425 61,425 8
21,553 758,204 758,2a.9
12,506 12,5OE 10
16,804 496,782 496,782 11
15,513 419,701 419,701 12
388,652 388,652 13
172,550 2,314,146 2,314,146 14
55,078 695,552 1,823,133 184,639 2,703,324
2,780,950 0 89,082,078 2,587,919 91,669,997
2,836,028 695,552 90,905,211 2,772,558 94,373,321
FERC FORM NO.1 (ED. 12-90)Page 311.3
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) r:A Resubmission 04/121010
SALES FOR RESALE (Account 447)
1. Report all sales for resale (i.e., sales to purchasers othr than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of elecci ( i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settements for imbalance 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 base 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 send only to, the suppliets service to its own ultmate consumer.
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 conditns (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF serice). 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 cotract.
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 servics 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 availabilit and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermdiate-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 Avera%e Actual Demand (MW)
No.(Footnote Affliations)Class Scule or Monthly illng Avera~e Ave~
cation Tari Number Demand(MW Monthly NC Deman Monthly C emand
(a)(b)(c)(d)(e)(f)
1 Powerex Corp.SF WSPP nla n/a n/a
2 PPL EnergyPlus, LLC WSPP nla nla n/a
3 PPL EnergyPlus, LLC WSPP nla n/a nla
4 PPL EnergyPlus, LLC SF WSPP nla n/a n/a
5 Prudential Bache Commodities, LLC -nla n/a n/a
6 Public Service Company of Colorado SF WSPP nla n/a n/a
7 Public Service Company of New Mexic SF WSPP n/a nla nla
8 Puget Sound Energy, Inc.SF T-7 nla n/a n/a
9 Puget Sound Energy, Inc.WSPP nla n/a nla
10 Puget Sound Energy, Inc.SF WSPP n/a n/a n/a
11 Rainbow Energy Marketing Corporation WSPP nla n/a n/a
12 Rainbow Energy Marketing Corporation WSPP nla n/a n/a
13 Rainbow Energy Marketing Corporation SF WSPP nla nta n/a
14 Seattle Cit Light WSPP nta n/a n/a
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12-90)Page 310.4
Name of Respondent ThiS~ort Is:Date of Report
I
Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2oo9/Q4
(2)A Resubmission 04/1212010
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 footote.
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. 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 tarifs under
which service, as identified in column (b), is provided.
S. 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 (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (SD-minute 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 (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bils rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bils rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the 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 require data.
MegaWatt Hours REVENUE Totl ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)ü)(k)
194,829 8,463,278 8,463,27S 1
31,17~31,179 2
2,262 25,409 25,405 3
30,913 990,309 990,309 4
769,441 769,441 5
2,400 64,200 64,20C 6
1,600 47,200 47,200 7
9 170 170 8
37,808 636,851 636,851 9
54,914 1,903,926 1,903,92E 10
5,600 116,800 116,80C 11
34,65C 34,65C 12
294,218 7,430,696 7,430,696 13
15,567 297,964 297,964 14
55,078 695,552 1,823,133 184,639 2,703,324
2,780,950 0 89,082,078 2,587,919 91,669,997
2,836,028 695,552 90,905,211 2,772,558 94,373,321
FERC FORM NO.1 (ED. 12-90)Page 311.4
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) ÕA Resubmission 041121010
SALES FOR RESALE (Account 4 7)
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 elecrici ( i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settements 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 trncate the name or use acronyms. Explain in a footnote any
ownership interest or affliation the respondent has wit the purchaser.
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 serice 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 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 interrpted for ecnomic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
frm 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, proide in a fotnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the cotract.
IF - for intermediate-term firm service. The same as LF service except tht "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm serices where th 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 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 Authorit Statisticl FERCRate Averaße Actual Demand (MW)
Classif Schedule or Monthly illng lWera~e Aver~No.(Footnote Affliations)catin Tari Number Demand (MW)Monthly NC Deman Monthly C emand
(a)(b)(c)(d)(e)(f)
1 Seattle City Light SF WSPP n/a nla n/a
2 Sempra Energy Trading LLC -n/a n/a n/a
3 Sempra Energy Trading LLC SF WSPP n/a nla n/a
4 Shell Energy North America (US), L.P.WSPP n/a nla n/a
5 Shell Energy North America (US), L.P.WSPP n/a nla n/a
6 Shell Energy North America (US), L.P.WSPP n/a nla n/a
7 Shell Energy North America (US), L.P.SF WSPP n/a nla nla
8 Sierra Pacic Power Co., dba NV Energy SF T-7 n/a n/a n/a
9 Sierra Pacific Power Co., dba NV Energy WSPP n/a nla n/a
10 Sierra Pacifc Power Co., dba NV Energy WSPP n/a nla n/a
11 Sierra Pacifc Power Co., dba NV Energy SF WSPP n/a n/a n/a
12 Snohomish County PUD WSPP n/a nla n/a
13 Snohomish County PUD SF WSPP nla nla nla
14 The Energy Authorit, Inc.SF WSPP n/a n/e n/a
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total ~0 0
FERC FORM NO.1 (ED. 12-90)Page 310.5
Name of Respondent This l:rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) A Resubmission 04/12/2010
SJ LES FOR RESALE (Account 447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contrct and service from designated units of Less than one year. Descrbe the nature
of the service in a footnote.
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. 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 tariff 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 biling demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the averae
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 (6Q.minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (6o-minute
integration) in which the suppliets system reaches its monthly peak. Demand reported in columns (e) and (t) must be in megawatt.
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 RO/Non-RO grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RO" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)(j)(k)
8,407 196,770 196,770 1
1,223,04 1,223,044 2
138,400 8,157,816 8,157,816 3
12,298 363,305 363,305 4
32,888 32,888 5
88,501 1,745,192 1,745,192 6
103,879 2,977,505 2,977,505 7
93 3,151 3,151 8
128,754 128,754 9
43 430 430 10
100 2,000 2,000 11
460 7,610 7,610 12
1,100 28,180 28,180 13
2 46 46 14
55,078 695,552 1,823,133 184,639 2,703,324
2,780,950 0 89,082,078 2,587,919 91,669,997
2,836,028 695,552 90,905,211 2,772,558 94,373,321
FERC FORM NO.1 (ED. 12-90)Page 311.5
Name of Respondent ThiS~ort Is:Date of Report
I
YearlPeriod of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2)A Resubmission 04/121010
SALES FOR RESALE (Accunt 447)
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) trnsacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electriit ( i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any setlements for imbalanced exchnges on this schedule. Power exchanges must be reported on the
Purchased Power scedule (Page 326-327).
2. Enter the name of the purchaser in coumn (a). Do note abbreviate or trncate 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 contracual 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 indudes 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 ultmate consumers.
LF - for tong-term service. "Long-term" means fie years or Longer and "frm" means that service cannot be interrupted for ecoomic
reasons and is intended to remain reliable even under aders conditons (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, prode in a fotnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contr.
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 fo all firm serics 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 frm transmission constraints, must match the availabilit and reliabilit 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 Authorit Statistcal FERCRat Averale Actual Demand (MW)
No.(Footnote Affliations)Classif Schedule or Monthly iIling AVera~e Ave~
cation Tari Numbr Demand(MW Monthly NC Deman Monthly C . emand
(a)(b)(c)(d)(e)(f)
1 TransAta Energy Marketing (U.S.) Inc.WSPP n/a nh nla
2 TransAta Energy Marketing (U.S.) Inc.SF WSPP n/a n/a n/a
3 UBS Securities LLC -n/a n/a nla
4 United Materials of Great Falls LF 61 n/a nla n/a
5
6
7
8
9
10
11
12 LESS BAD DEBT WRITE-OFF
13
14
SubtotalRQ a 0 0
Subtotal non-RQ a 0 0
Total (I 0 0
FERC FORM NO.1 (ED. 12-90)Page 310.6
Name of Respondent Thisoo0rt Is:Date of Report
I
YeaN~enoa or Kepon
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) OA Resubmission 04/12/2010
S LES FOR RESALE (Account 447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined 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 accunting 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 Une 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 tariff 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-cincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in coumn (1). For all other types of service, enter NA in columns (d), (e) and (1). 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 (1) 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 RQlNon-RO grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RO" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Linè
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)0)(k)
9,717 9,717 1
79,600 2,093,582 2,093,582 2
810,060 810,06C 3
24,814 24,8141 4
5
6
7
8
9
10
11
-1 -1 12
13
14
55,078 695,552 1,823,133 184,639 2,703,324
2,780,950 0 89,082,078 2,587,919 91,669,997
2,836,028 695,552 90,905,211 2,772,558 94,373,321
FERC FORM NO.1 (ED. 12-90)Page 311.6
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 0411212010 2009/Q4
FOOTNOTE DATA
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
J
I
I
I
I~
I~
i
I
¡Schedule Page: 310 Line No.: 1 Column: b
Customer Charge
~chedule Page: 310 Line No.: 2 Column: b
Network Transmission Charges
~chedule Page: 310 Line No.: 6 Column: b
Non-firm Sales
¡Schedule Page: 310 Line No.: 9 Column: b
Financial Transmission Losses
~chedule Page: 310 Line No.: 10 Column: b
Non-firm Sales
~chedule Page: 310 Line No.: 12 Column: b
Unit Contingent
~chedule Page: 310 Line No.: 13 Column: bNon-firm Sales
~chedule Page: 310.1 Line No.: 2 Column: b
Financial Transmission Losses
~chedule Page: 310.1 Line No.: 3 Column: b
Non-firm Sales
ISchedule Page: 310.1 Line No.: 8 Column: b
2008 Correction
~chedule Page: 310.1 Line No.: 9 Column: b
Non-firm Sales
ISchedule Page: 310.1 Line No.: 13 Column: b
Financial Transmission Losses
¡Schedule Page: 310.1 Line No.: 14 Column: bNon-firm Sales
~chedule Page: 310.2 Line No.: 4 Column: b
Financial Transmission Losses
~chedu/e Page: 310.2 Line No.: 5 Column: bNon-firm Sales
~chedule Page: 310.2 Line No.: 7 Column: b
Non-firm Sales
ISchedule Page: 310.2 Line No.: 12 Column: b
Financial Transmission Losses
~chedule Page: 310.2 Line No.: 13 Column: b
ISDA Master Agreement with Morgan Stanley dated March 1, 2000
~chedu/e Page: 310.3 Line No.: 3 Column: b
2008 Financial Transmission Loss Correction
~chedule Page: 310.3 Line No.: 4 Column: b
Financial Transmission Losses
~chedule Page: 310.3 Line No.: 7 Column: b
Financial Transmission Losses
¡Schedule Page: 310.3 Line No.: 8 Column: bNon-firm Sales
~chedule Page: 310.3 Line No.: 10 Column: b
Financial Transmission Losses
¡Schedule Page: 310.3 Line No.: 11 Column: b
Non-firm Sales
~chedule Page: 310.3 Line No.: 13 Column: b
Financial Transmission Losses
ISchedule Page: 310.3 Line No.: 14 Column: bNon-firm Sales
~chedule Page: 310.4 Line No.: 2 Column: b
Financial Transmission Losses
IFERC FORM NO.1 (ED. 12-87) Page 450.1
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) c An Original (Mo, Da, Yr)
Idaho Power Company (2) A Resubmission 04/12/2010 2009/Q4
FOOTNOTE DATA
¡Schedule Page: 310.4 Line No.: 3 Column: bNon-firm Sales
!schedule Page: 310.4 Line No.: 5
Prudential Bache Commodities,
!sChedule Page: 310.4 Line No.: 9Non-firm Sales
\$chedule Page: 310.4 Line No.: 11 Column: bUni t Contingent
!Schedule Page: 310.4 Line No.: 12 Column: b
Financial Transmission Losses
I$chedule Page: 310.4 Line No.: 14 Column: bNon-firm Sales
I$chedule Page: 310.5 Line No.: 2 Column: b
ISDA Master Agreement with Sempra dated February 21, 2008.
¡Schedule Page: 310.5 Line No.: 4 Column: b
Unit Contingent
¡Schedule Page: 310.5 Line No.: 5 Column: b
Financial Transmission Losses
!schedule Page: 310.5 Line No.: 6 Column: bNon-firm Sales
I$chedule Page: 310.5 Line No.: 9 Column: b
Financial Transmission Losses
I$chedule Page: 310.5 Line No.: 10 Column: bNon-firm Sales
\Schedule Page: 310.5 Line No.: 12 Column: bNon-firm Sales
\$chedule Page: 310.6 Line No.: 1 Column: b
Financial Transmission Losses
¡Schedule Page: 310.6 Line No.: 3 Column: b
Institutional Futures Client Account Agreement with UBS, dated March 8, 2006.
Column: b
LLC Futures Account Document, dated September 4, 2008.
Column: b
IFERC FORM NO.1 (ED. 12-87)Page 450.2
Name of Respondent
Idaho Power Company
This '30rt Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/121010
ELE TRIC PERATION AND MAINTENA CE EXPENSES
If the amount for previous year is not derived frm previously reported figures, explain in footnote.Line Accunt Amount forNo ~~. 00 ~
1 1. POWER PRODUCTION EXPENSES
2 A. Steam Power Generation
3 Operation
4 (500) Operation Supervision and En
5 (501) Fuel
6 (502) Steam Expenses
7 (503) Steam from Other Sources
8 (Less) (504) Steam Transferred-Cr.
9 (505) Electric Expenses
10 (506) Miscellaneous Steam Power Expenses
11 (507) Rents
12 (509) Allowances
13 TOTAL Operation (Enter Total of Lines 4 thru 12)
14 Maintenance
15 (510) Maintenance Supervision and En ineerin
16 511) Maintenance of Structures
17 512 Maintenance of Boiler Plant
18 (513) Maintenance of Electric Plant
19 (514) Maintenance of Miscellaneous Steam Plant
20 TOTAL Maintenance (Enter Total of Lines 15 thru 19)
21 TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 & 20)
22 B. Nuclear Power Generation
23 0 eration
24 (517) Operation Supervision and En ineerin9
25 518) Fuel
26 (519) Coolants and Water
27 (520) Steam Expenses
28 (521) Steam from Oter Sources
29 (Less (522) Steam Transferred-Cr.
30 (523 Electic 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 Engineerin
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. H draulic Power Generation
43 Operation
44 535) Operation Supervision and Engineerin
45 536) Water for Power
46 537) Hydraulic Expenses
47 (538) Electric Expenses
48 (539 Miscellaneous Hydraulic Power Generation Ex nses
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 Structures
55 (543) Maintenance of Reservoirs, Dams, and Waterwa s
56 (54 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)
Year/Period of Report
End of 2oo9/Q4
Am.ountforPrevious Year
(c)
1,814,867 1,650,283
130,234,531 132,015,165
7,434,710 7,376,689
2,568,382 1,817,960
8,111,562 7,737,497
514,732 469,699
150,678,784 151,067,293
2,072,391 2,567,722
487,528 398,714
13,675,892 14,205,043
3,595,301 4,301,150
4,639,081 4,322,931
24,470,193 25,795,560
175,148,977 176,862,853
- --- -- ~-- - -~- --~-~ -- --
5,242,496
7,174,597
10,093,906
1,470,715
2,686,753
376,849
27,045,316
5,602,490
7,355,741
9,978,475
1,312,586
3,091,676
431,893
27,772,861---- -- - -- - - --- ---- - - --- ~
2,072,103
1,396,815
1,132,574
2,962,850
2,971,583
10,535,925
37,581,241
1,885,154
1,362,031
808,311
2,495,503
3,135,803
9,686,802
37,459,663
FERC FORM NO.1 (ED. 12-93)Page 320
This '30rt Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/12/2010
ELECTRIC OPERATION AND MAINTENANCE E PENSES (Continued
If the amount for previous year is not derived from previously reported figures, explain in footnote.Line Accunt Amount forNo ~~. W ~
Name of Respondent
Idaho Power Company
Year/Perioa ot Keport
End of 2009/Q4
60 D. Other Power Generation
61 Operation
62 (546) Operation Supervision and Engineering
63 (547) Fuel
64 (548) Generation Expenses
65 (549) Miscellaneous Other Power Generation Expenses
66 (550) Rents
67 TOTAL Operation (Enter Total of lines 62 thru 66)
68 Maintenance
69 (551) Maintenance Supervision and Engineering
70 (552) Maintenance of Structures
71 (553) Maintenance of Generatin and Electric Plant
72 (554) Maintenance of Miscellaneous Other Power Generation Plant
73 TOTAL Maintenance (Enter Total of lines 69 thru 72)
74 TOTAL Power Production Ex enses-Other Power (Enter Tot of 67 & 73)
75 E. Oter Power Supply Expenses
76 (555) Purchased Power
77 556) System Control and Load Dis atchin
78 557) Other Expenses
79 TOTAL Other Power Sup I Ex Enter Total of lines 76 thru 78)
80 TOTAL Power Production Ex enses (Total of lines 21, 41, 59, 74 & 79
81 2. TRANSMISSION EXPENSES
82 Operation
83 (560) Operation Supervision and Engineerin
84 (561) Load Dispatching
85 (561.1) Load Dispatch-Reliabilit
86 561.2) Load Dispatch-Monitor and Operate Transmission S stem
87 (561.3) Load Dispatch-Transmission Service and Scheduling
88 (561.4) Schedulin ,System Control and Dispatch Services
89 (561.5) Reliabil ,Plannin and Standards Development
90 (561.6) Transmission Service Studies
91 (561.7) Generation Interconnection Studies
92 (561.8) Reliabilty, Plannin and Standards Develo ment Services
93 (562) Station Expenses
94 (563) Overhead Lines Expenses
95 (564 Underground Lines Expenses
96 (565) Transmission of Electricit bOthers
97 (566) Miscellaneous Transmission Expenses
98 (567) Rents
99 TOTAL Operation (Enter Total of lines 83 thru 98)
100 Maintenance
101 (568) Maintenance Supervision and En ineering
102 (569) Maintenance of Structures
103 (569.1) Maintenance of Computer Hardware
104 (569.2) Maintenance of Computer Softare
105 (569.3) Maintenance of Communication Equipment
106 (569.4) Maintenance of Miscellaneous Regional Transmission Plant
107 (570) Maintenance of Station Equipment
108 (571) Maintenance of Overhead Lines
109 (572) Maintenance of Under round Lines
110 (573) Maintenance of Miscellaneous Transmission Plant
111 TOTAL Maintenance (Total of lines 101 thru 110)
112 TOTAL Transmission Expenses (Total of lines 99 and 111)
Am.ount.ørPrevious Year
(c)
347,933
19,331,689
405,013
320,014
372,614
17,387,509
404,456
530,176
20,404,649 18,694,755
194,110
524,579
1,710,504
2,429,193
22,833,842
213
162,376
198,271
509,219
870,079
19,564,834
160,569,065
13,142
69,383,801
229,966,008
465,530,068
231,137,298
77,979
-4,906,304
186,308,973
420,196,323
1,348,929
99,682
2,404,396
87,197
1,517
1,635,60
1,069,383
2,534,092
169,190
101,790 90,292
1,946,068
907,200
1,805,491
735,577
----- ---- ~- ~ ---~ -- ---~-~--
6,628,695
386,603
1,564,349
16,581,598
7,250,299
465,343
1,085,343
16,630,44
590,179 431,690
82,703 98,395
268,304 328,872
32,141 24,333
2,999,666 2,706,580
2,936,203 3,367,61
38 272
6,909,234 6,957,761
23,490,832 23,588,205
FERC FORM NO.1 (ED. 12-93)Page 321
Nam of Respondent
Idaho Power Company
Year/Period of Report
End of 2009/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04121010
ELECTRIC OPERATION AND MAINTENANCE PENSES Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.Line Accunt AmourtforNo Curren Year. 00 ~
113 3. REGIONAL MARKET EXPENSES
114 Operation
115 575.1) 0 eration Su ervision
116 (575.2) Day-Ahead and Real-Time Market Facilitation
117 (575.3) Transmission Ri hts Market Facilitation
118 (575.4) Capacity MarKet Facilitation
119 (575.5) Ancilla Services Market Facilitation
120 (575.6) MarKet Monitoring and Com Iiance
121 (575.7) MarKet Faciltation, Monitorin and Compliance Serces
122 (575.8) Rents
123 Total Operation (Lines 115 thru 122)
124 Maintenance
125 (576.1) Maintenance of Structures and Improvements
126 (576.2) Maintenance of Computer Hardare
127 (576.3 Maintenance of Computer SOftare
128 576.4) Maintenance of Communicatin Equipment
129 (576.5) Maintenance of Miscellaneous Market Operation Plant
130 Total Maintenance (Lines 125 thru 129)
131 TOTAL Re ional Transmission and MarKet 0 Expns (Total 123 and 130)
132 4. DISTRIBUTION EXPENSES
133 Operation
134 (580) Operation Supervision and Engineerin
135 (581) Load Dispatching
136 (582 Station Ex enses
137 (583) Overhead Line Expenses
138 (584) Unde round Line Expenses
139 (585 Street Lighting and Si nal S stem Expenses
140 (586) Meter Expenses
141 (587) Customer Installations Expenses
142 588) Miscellaneous Ex enses
143 (589) Rents
144 TOTAL Operation (Enter Total of lines 134 thru 143)
145 Maintenance
146 (590) Maintenance Supervision and En ineering
147 (591) Maintenance of Structures
148 (592) Maintenance of Station Equi ment
149 (593) Maintenance of Overhead Lines
150 (594) Maintenance of Under round Lines
151 (595 Maintenance of Line Transformers
152 (596) Maintenance of Street Lightin and Si nal Systems
153 (597) Maintenance of Meters
154 (598) Maintenance of Miscellaneous Distribution Plant
155 TOTAL Maintenance (Total of lines 146 thru 154)
156 TOTAL Distribution Expenses (Total of lines 144 and 155)
157 5. CUSTOMER ACCOUNTS EXPENSES
158 Operation
159 (901) Su ervision
160 (902) Meter Readin Expenses
161 (903) Customer Records and Collection Expenses
162 (904) Uncollectible Accounts
163 (905) Miscellaneous Customer Accounts Expenses
164 TOTAL Customer Accounts Expenses (Total of lines 159 thru 163
Am.ountforPrevious Year
(c)
3,357,224
3,186,033
1,136,350
3,44,690
1,915,974
134,828
4,473,033
1,331,636
5,003,459
308,806
24,294,033
3,321,954
3,110,301
1,143,619
3,346,471
2,034,228
130,886
4,636,934
1,398,175
5,464,167
456,147
25,042,882
--- ------ ---- - - - ~ --- --
310,403
25,089
3,354,447
14,503,170
1,083,316
410,917
501,683
711,387
267,231
21,167,643
45,461,676
319,660
2,323
3,534,603
13,759,196
1,235,321
445,190
665,088
862,861
354,999
21,179,241
46,222,123
373,734
5,399,410
13,096,476
5,268,902
556
24,139,078
341,842
5,752,965
11,713,961
3,681,954
468
21,551,190
FERC FORM NO.1 (ED. 12-93)Page 322
This i§ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 0411212010
ELECTRI OPERATION AND MAINTENANCE E PENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.Line Accunt Amount forNo ~~. 00 ~
165 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
166 Operation
167 (907) Supervision
168 (908) Customer Assistance Expenses
169 (909) Informational and Instructional Expenses
170 (910) Miscellaneous Customer Service and Informational Expenses
171 TOTAL Customer Service and Information Expenses (Total 167 thru 170)
172 7. SALES EXPENSES
173 Operation
174 (911) Supervision
175 912) Demonstrating and Sellng Ex enses
176 (913) Advertisin Ex enses
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 Ofce Supplies and Expenses
183 (Less) 922) Administrative Expenses Transferred-Credit
184 (923) Outside Services Em loyed
185 (924) Pro ert Insurance
186 (925) Injuries and Damages
187 (926) Emplo ee Pensions and Benefits
188 (927) Franchise R uirements
189 (928 R ulatory Commission Expenses
190 (929 (Less) Duplicate Charges-Cr.
191 (930.1) General Advertisin Expenses
192 (930.2) Miscellaneous General Expenses
193 (931) Rents
194 TOTAL Operation (Enter Total of lines 181 thru 193)
195 Maintenance
196 (935 Maintenance of General Plant
197 TOTAL Administrative & General Expenses (Total of lines 194 and 196)
198 TOTAL Elec Op and Maint Expns (Total 80,112,131 ,156,164,171,178,197)
Name of Respondent
Idaho Power Company
Year/Period ot Report
End of 2009/04
Am.ount.ørPrevious Year
(c)
258,454
40,754,937
16,116
840,420
41,869,927
860,302
28,834,452
61,677,661
12,455,430
27,866,621
7,562,948
3,262,112
6,804,103
31,049,314
3,196
5,298,808
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
158,199
3,561,160
1,090
103,967,400
236,828
3,515,410
6,827
105,274,854
3,946,638
107,914,038
708,405,619
4,149,187
109,424,041
649,816,334
FERC FORM NO.1 (ED. 12-93)Page 323
Name of Respondent This ~rrt Is:Date of Report
I
Year/Penod of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) A Resubmission 04/121010
PU~C~AeHED POWER JiAccunt 555)(n u ing power ex ang)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactons involvng a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanc exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or trncate the name or use
acronyms. Explain in a footnote any ownership interest or affliaton the respondent has with the seller.
3. In column (b), enter a Statistical Classifcation Code base on the original contractual terms and conditions of the service as follows:
RQ - for requirements servic. 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 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 expe that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm serces, 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 fie 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 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 i etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be plac 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 Average
cation Tarif Number Demand(MW Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Wills and Bett Deveny/Shinglecreek LU -N1A N/A N/A
2 James B. Howell i CHI Elkcreek LU -N/A N/A N/A~LU -4.942Mw -
4 Owhee Irrigation District
5 Mitchell Butte LU -N/A N/A N/A
6 Owhee 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 N/A
9 Clifton E. Jenson/Birchcreek LU -.05Mw
10 Snake River Pottery LU -N1A N1A N/A
11 White Water Ranch LU -N/A N/A N/A
12 John R LeMoyne LU -N/A N1A N/A
13 David R Snedigar LU -N/A N1A N/A
14 Mud Creek White Hydro, Inc LU -N/A N/A N/A
Total
FERC FORM NO.1 (ED. 12-90)Page 326
Name of Respondent This oo0rt Is:Date of Report
I
Yearwerioa OT KepOrt
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/12/2010
ccu~t.~~~L (continued)
-(Including 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 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 (6D-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 bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on bils recived as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (i)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETLEMENT OF POWER 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)
96€66,461 66,461 1
3,58(252,08f 252,088 2
37,701 1,576,498 1,414,261 2,990,765 3
4
5,31€113,34.1 113,344 5
19,12f 334,35f 334,351 6
8,36-811,91.811,91~7
1,441 104,83~104,835 8
32E 17,500 9,191 26,691 9
38'25,911 25,910 10
72E 48,58~48,582 11
61"34,35~34,355 12
1,56'110,37!110,379 13
511 34,351 34,358 14
2,911,842 195,389 327,800 2,815,124 153,627,912 4,126,029 160.569,06~
FERC FORM NO.1 (ED. 12-90)Page 327
Name of Respondent This oo0rt Is:Date of Report
I
Yearflerioa or Kepon
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) OA Resubmission 04/121010
PU~Çet:JED POWER chAccou~t 5 5)n ing powr ex anges
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transacons involving a balancing of
debits and credits for energy, capaci, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange transaåion in column (a). Do not abbreviate or truncate the name or use
acrnyms. Explain in a footnote any ownerhip interest or afliaton the respondent has with the seller.
3. In column (b), enter a Statistical Classifcation Code base on the oriinal contraal terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is servic whic 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 additin, the reliability of requirement service must
be the same as, or second only to, the suppliets service to its own ultmate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third 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 contract.
IF - for intermediate-term firm service. The same as LF servce expe tht "intermiate-ter" 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 availabili 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 eleccity. Use this category for transaåions 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 frm designated units of Less than one year. Descibe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authorit Statistical FERCRate Average Actual Demand (MW)
No.(Footnote Affliations)Classif-Schedule or Monthly Biling Average Average
cation Tarif Number Demand (MW Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Rim View Trout Company -N/A N/A N/A
2 Curry Cattle Company LU -.084Mw
3 BranchfiowerfTrout Company LU -N/A N/A N/A
4 Big Wood Canal Company
5 Black Canyon LU -N1A N/A N/A
6 Jim Knight LU -N/A N/A N/A
7 Sagebrush LU -N1A N/A N/A
8 Fisheries Development -N1A N/A N/A.
9 Shorock Hydro Inc.
10 Shoshone Cspp LU -N/A N/A N/A
11 Shoshone #2 LU -N/A N/A N/A
12 Rock Creek #1 Joint Venture LU -1.732Mw
13 Richard Kaster
14 Box Canyon LU -N/A N/A N/A
Total
FERC FORM NO.1 (ED. 12-90)Page 326.1
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 2009/Q4
(2) OA Resubmission 04/12/2010
cc~t~~~L (Continued).~. '''ìiñèludina pòwer ex 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), 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 (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges recived 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 poer exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than recived, 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/SETTLEMENT 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)
1,2H 26,2m 26,205 1
621 26,796 17,751 44,547 2
77(52,94:.52,942 3
4
31E 21,22.21,223 5
1,05,73,65.73,65.6
1,6'81,62!81,625 7
98f 22,02(22,02C 8
9
1,87E 148,49i 148,497 10
2,33~157,08f 157,088 11
8,12E 552,508 229,72f 782,236 12
13
1,671 110,64!110,645 14
2,911,842 195,389 327,800 2,815,12~153,627,912 4,126,25 160,569,06f
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 2oo9/Q4
(2)A Resubmision 041121010
PU~CHA~ED POWER J,Accou1t 555)(nClu ing powr ex anges
1. Report all power purchases made dunng the year. Also report exchanges of electndty (i.e., transactons involving a balancing of
debits and credits for energy, capacty, 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 truncte 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 onginal contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is servic whic the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this servce in its system resource planning). In addition, the reliabilty of requirement service must
be the same as, or second only to, the suppliets servce to its own ultmate cosumers.
LF - for long-term firm 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 advers conditons (e.g., the supplier must attempt to buy emergency
energy from third partes to maintain deliveries of LF service). This categor should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaion 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, wh 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-ter" means five years or longer. The availability and reliabilty 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 expec that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electridty. Use this category for transactions involving a balancing of debits and credits for energy, capadty, etc.
and any settlements for imbalance exchanges.
OS - for other service. Use this category only for those servces whic cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Descnbe the nature
of the service in a footnote for each adjustment.
Une 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 Deman 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 H.K. 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 -NlA N/A NlA
7 Koyle Hydro Inc.LU -N/A N/A N/A
8 Kasel & Witherspoon LU -NlA N/A N/A
9 Lateral 10 Ventures LU -N/A 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. / Enel -
13 GeoBon#2 LU -N/A N/A N/A
14 Barber Dam LU -N/A N/A N/A
Total
FERC FORM NO.1 (ED. 12-90)Page 326.2
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 2009/Q4
(2)nA Resubmission 04/12/2010
cc~~~~~L (continued)(Including power ex 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 appropriate
designation for the contract. .On separate lines, list all FERC rate schedules, tariff 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 (oo-minute integration) demand in a month. Monthly CP demand is the metered demand
durng the hour (6Q-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 bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on bils recived as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (i)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total U+k+l)No.
Received Delivered ($)($~($)of Settement ($)
(g)(h)(i)ü)(k (I)(m)
3,561 238,381 238,381 1
86(18.68,18,68~2
1,581 114,901 114,901 3
2,73~155,672 77,31'232,986 4
3,71~272,75.272,752 5
3,19.268,721 268,727 6
3,43C 279,76f 279,76f!7
3,48f 267,4H 267,41E 8
8,06f 531,24(531,240 9
10,55.710,591 710,59E 10
7,98f 486,150 196,07 682,222 11
12
3,26f 239,43~239,439 13
11,57E 593,22f 593,225 14
2,911,842 195,389 327,800 2,815,124 153,627 ,91 ~4,126,029 160,569,06f
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 2oo9/Q4
(2) OA Resubmission 04/121010
PU~C~AJlED POWER JiAccou1t 5 5)nc u ing power ex anges
1. Report all power purchases made during the year. Also report exchanges of electrici (i.e., transactons 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 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 (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 ow ultmate cosumers.
LF - for long-term firm service. "Long-term" means fie years or longer and "frm" means that service cannot be interrupted for
ecnomic reasons and is intended to remain reliable even under aders conditons (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF servce). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all trnsaction identied as LF, provide in a footnote the termination date of the contract
defned 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 LFservice expe 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 reliabilit of the designated unit.
IU - for intermediate-term service from a designated generatng unit. Th same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electcity. Use this category for transactons 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 serices which cannot be place in the above-efined 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 FERCRate Average Actual Demand (MW)
No.(Footnote Affliations)Classif Schule or Monthly Biling Average Average
cation Tari Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Rock Creek #2 LU -NlA N/A NlA
2 Dietrich Drop LU -NlA N/A N/A
3 Lowline#2 LU -NlA N/A N/A
4 Litte Mac Power Co.lCedar Draw LU -N/A N/A N/A~LU -N/A N/A N/A
6 Litle Wood River Irrigation District LU -N/A N/A NlA
7 Marco Rancher's Irrigation Inc.LU .N/A N/A N/A
8 Faulkner Brothers Hydro Inc.LU -NlA N/A N/A
9 Magic Reservoir Hydro LU -NlA NlA NlA
10 Bypass Limited LU -NlA N/A N/A
11 SE Hazelton A LP LU -NlA N/A N/A
12 Lemhi Hydro Power Co.lSchaffner LU -NlA N/A N/A
13 J R Simplot Co.LU -NlA N/A N/A
14 Blind Canyon Hydro LU -N/A N/A N/A
Total
FERC FORM NO.1 (ED. 12-90)Page 326.3
Name of Respondent This l:ort Is:
I
Date of Report
I
Yearwenoa or KepOrt
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) A Resubmission 04/1212010
.cco~tÆ:~~l \ (Coifnuéd)Ilneludíng power ex 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), 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 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 (60minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (i)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/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)
7,47E 377,00.377,002 1
16,47.873,9m 873,90i:2
9,41.500,45f 500,455 3
6,05.391,15(391,15C 4
26,731 1,912,53 1,912,533 5
6,19'468,50E 468,50E 6
2,92.200,681 200,681 7
2,95f 227,68!227,68!3 8
14,80(820,67(820,67C 9
26,02~1,380,90~1,380,90~10
22,35 1,136,49i 1,136,497 11
1,27 95,92l 95,924 12
72,371 4,053,641 4,053,641 13
4,36C 378,29E 378,296 14
2,911,842 195,389 327,800 2,815,12~153,627,912 4,126,02!3 160,569,06f
FERC FORM NO.1 (ED. 12-90)Page 327.3
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) riA Resubmission 041121010
PU~C~ED POWER chAccunt 5 5)
(ndu ing power ex anges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debs 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 transacton in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or afliation the respondent has with the seller.
3. In column (b), enter a Statistical Classificaion 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 cosumers.
LF - for long-term firm service. "Long-ter" means five years or longer and "firm" means that service cannot be interrupted for
ecnomic reasons and is intended to remain reliable even under advers conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF servce). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identied 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 contct.
IF - fo intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
thn 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 generatng unit. "Long-term" means fie years or longer. The availabilty 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 generaing 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 involing 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 frm 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 Statisticl FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classif Schedule or Monthly Biling Average Average
cation Tari Number Demand(MW Monthly NCP Deman Monthly CP Demanc
(a).(b)(c)(d)(e)(f)
1 City of Hailey ILU -NlA N/A NlA
-~-NlA N/A NlA
-NlA N/A N/A4 W -N/A N/A N/A5 W -N/A N/A N/A
6 Pristine Springs Inc. #1 LU -N/A N/A N/A
7 Vaagen Brothers Lumber Inc.LU -NlA N/A N/A
8 Horsshoe Bend Hydro LU -N/A N/A N/A
9 Contractors Power Group Inc./Mile 28 LU -NlA N/A N/A
10 Rupert Cogeneration PartnersMagic Val LU -N/A NlA N/A
11 Glenns Ferry Cogeneration Partnersag 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. Sorensonfiber Dam LU N/A N/A N/A
Total
FERC FORM NO.1 (ED. 12-90)Page 326.4
'Name of Respondent This oo0rt Is:
I
Date ot Report
I
yearwenoa or KepOIt
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/1212010
.cc~t.~~~L (Continued)~ìiiicíudini: power ex 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), 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 requiremènts 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 (6o-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settèment
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/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l)No.
Received Delivered ($)
\~~\'l
of settement ($)
(g)(h)(i)(j)(m)
3!2,72f 2,72f 1
1,37 96,43E 96,436 2
54,22 3,488,93f 3,488,938 3
25,12f 1,742,98E 1,742,98E 4
21,78~1,509,01;1,509,01;5
781 36,261 36,261 6
15,88f 992,591 992,59E 7.
43,451 2,965,890 2,965,8~8
4,371 288,2~288,25~9
80,63(5,134,6H 5,134,610 10
42,84 3,129,31.3,129,312 11
1,49f 35,50.35,507 12
1,171 56,531 56,531 13
29,331 1,419,45!1,419,45~14
2,911,842 195,389 327,800 2,815,124 153,627,912 4,126,029 160,569,06!
FERC FORM NO.1 (ED. 12-90)Page 327.4
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2oo9/Q4
(2) r'A Resubmission 04/121010
PU~C~AJfED POWER JiAccu1t 555)(n u ing power ex anges
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactons involving a balancing of
debits and credits for energy, capaci, 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 truncae 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 tenns and conditions of the service as follows:
RQ - for requirements service. Requirements service is serice 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 ultmate consumers.
LF - for long-term firm service. "Long-tenn" means five years or longer and "finn" means that servce cannot be interrpted for
economic reasons and is intended to remain reliable even under adverse conditons (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-tenn firm service firm service
which meets the definition of RQ servic. For all transacion 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-tenn firm service. The same as LF service expe that "intennediate-term" means longer than one year but less
than five years.
SF - for short-tenn service.Use this caegory for all finn servces, where the duration of each period of commitment for servce is one
year or less.
LU - for long-tenn 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 availabilit and reliabilit of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expe that "intennediate-term" means
longer than one year but less than five years.
EX - For exchanges of elecricity. Use this category for transactions involvng a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchnges.
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 frm 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)Classifi Schedule or Monthly Billng Average Average
cation Tariff Number Demand (MW Monthly NCP Deman Monthly CP Demanc
(a)(b)(c)(d)(e)(f)
1 Fossil Gulch Wind LU -N/A N/A N/A
2 G2 Energy Hidden Hollow LU N/A N/A N/A
3 Horsshoe Bend Wind/United Materials LU N1A N/A N/A
4 Horseshoe Bend WindlUnited Materials -N/A NlA N/A
5 Horsshoe Bend Wind/United Materials N1A N/A N/A
6 Riverside Hydro Mora Drop LU N/A N/A N/A
7 J.M. MillerlSahko 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 Falls Energy/Lowline Midway Hydro LU N/A N/A N/A
10 Bennett Creek Wind Farm LU N/A N/A N/A
11 Bettencourt Dryrek Biofactory LU N/A N/A N/A
12 Big Sky Dairy Digester LU N1A N/A N/A
13 Hot Springs Wind Farm LU N/A NlA N/A
14 Cassia Gulch Wind Park LU N/A N/A N/A
Total
FERC FORM NO.1 (ED. 12-90)Page 326.5
Name of Respondent This 'O0rt Is:
I
Date of Report
I
Year/l-erioa or Kepon
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) OA Resubmission 04/12/2010
ce'êt~2~L (Continued)(Including poWer ex anges)
AD - for out-of-period adjustment. Use this code for any accunting adjustments or "true-ups" for service provided in pnor reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tanff, or, for non-FERC junsdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tanffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges impose 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
dunng 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.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0). energy charges in column (k), and the total of any other types of charges. including
out-of-penod adjustments, in column (i). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on 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 entnes as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COSTISEnLEMENT OF POWER Une
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)
26,35 1,276,6H 1,276,619 1
21,35E 993,751 993,751 2
17,40E 818,89 818,893 3
11, 18~11,182 4
5
4,89~250,43~250,43~6
1,324 24,161 24,161 7
34,72S 2,738,OOC 2,738,000 8
8,424 517,12C 517,120 9
40,851 2,223,795 2,223,795 10
7,91€175,466 175,46 11
9,44~603,37~603,375 12
42,825 2,313,614 2,313,614 13
30,831 1,554,74C 1,554,740 14
2,911,842 195,389 327,800 2,815,124 153,627,912 4,126,029 160,569,065
FERC FORM NO.1 (ED. 12-90)Page 327.5
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 2009/Q4
(2)A Resubmission 04/121010
PU~C~tHED POWERchAcunt 555)
(n u ing power ex anges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactons involving a balancing of
debits and credits for energy, capacit, etc.) and any settlements fo imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange trnsaction 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 Code base on th original contraual 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 projecs 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 servce to its own ultimate consumers.
LF - for long-term firm serice. "Long-ter" means fie years or longer and "firm" means that service cannot be interrpted for
economic reasons and is intended to remain reliable even under advers 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
defned as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF servce expe that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm servces, where the duration of each period of commitment for serice is one
year or less.
LU - for long-term service from a designated generati unit. "Long-term" means fie years or longer. The availability 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 generatng unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of elecricity. Use this category for transactions involving a balancing of debits and credits for energy, capacit, etc.
and any setlements for imbalance 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 frm 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 Average
cation Tari Number Demand (MW Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Cassia Wind Farm LU N/A N/A N1A
2 Other Purchased Power
3 Arizona Public Service Co.SF WSPP N/A N1A N/A
4 Avista Corp.SF T-12 N/A N/A N/A
5 Avista Corp.SF WSPP N/A N/A N/A
6 Avista Corp.WSPP N1A N/A N/A
7 Barclays Bank PLC SF WSPP N1A N/A N/A
8 Black Hils Power Inc.WSPP N1A N/A N/A
9 Black Hils Power Inc.SF WSPP N/A N/A N1A
10 Bonneville Power Administration SF WSPP N/A N/A N/A
11 BP Energy Company SF WSPP N/A N/A N/A
12 Cargil Power Markets LLC SF WSPP N/A N/A N/A
13 Chelan Co PUD SF WSPP N/A N/A N/A
14 Citigroup Energy Inc.SF WSPP N/A N/A N/A
Total
FERC FORM NO.1 (ED. 12-90)Page 326.6
Name of Respondent This oo0rt Is:
I
Date ot Keport
I
yearwerioa or I"epoii
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) OA Resubmission 0411212010
-u 'vI ccuRt~~~L(ljOntinUed)
'Uncluding 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), 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 (60minute 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 bils received as settlement by the respondent. For power exchanges, report in column (m) the settement
amount for the net receipt of energy. If more energy was delivered than recived, enter a negative amount. If the settlement amount (i)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.
Received Delivered ($)($~($)of Settlement ($)
(g)(h)(i)0)(k (I)(m)
17,315 880,15~880,15.0 1
2
47,70E 1,797,62~1,797,62~3
5A 1,92.1,922 4
8,63~227,561 227,561 5
458,065 458,065 6
76,OOC 3,581,22E 3,581,226 7
18,10 651,99E 651,996 8
3,22C 103,087 103,081 9
88,981 2,777,45.0 2,777,454 10
128,549 7,154,671 7,154,671 11
59,685 2,798,29A 2,798,294 12
2,22~69,78~69,785 13
96,40C 5,144,50C 5,144,500 14
2,911,842 195,389 327,800 2,815,124 153,627,912 4,126,029 160,569,065
FERC FORM NO.1 (ED. 12-90)Page 327.6
Name of Respondent ThiS~ort Is:Date of Report Year/Periodof Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2)A Resubmision 0411212010
PU~CHAdTED POWER chAccunt 5 5)(nclu ing powr ex anges)
1. Report all power purchases made during the year. Also report exchnges of electrici (i.e., transactons involvng 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 whic 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 additin, the reliability of requirement service must
be the same as, or second only to, the suppliets service to its ow ultmate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "frm" means that service cannot be interrpted for
economic reasons and is intended to remain reliable even under advers conditons (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF seice). This categor should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transactn 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 contct.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-ter" 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 generting unit. "Long-term" means fie years or longer. The availabilty and reliabilty 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 servce expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of elecricity. 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 Statisicl FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classif Schule or Monthly Biling Average Average
cation Tariff Number Demand(MW Monthly NCP Deman Monthly CP Demanc
(a)(b)(c)(d)(e)(f)
1 Conoco Phillps Company SF WSPP N/A N/A NIA
2 Constellation Energy Commodites Group SF WSPP N/A N/A N/A
3 DB Energy Trading LLC SF WSPP N/A N/A N/A
4 Douglas County PUD SF WSPP N/A N/A N/A
5 EI Paso Electric Company SF WSPP N/A N/A N/A
6 Endure Energy, LLC SF WSPP N/A N/A N/A
7 EPCOR Energy Marketing (U.S.) Inc.SF WSPP NJA N1A N/A
8 Eugene Water & Electric Board SF WSPP NJA N/A N/A
9 Fortis Energy Marketing & Trading GP SF WSPP N/A N/A N/A
10 Grant CO Public Utilit District #2 --SF WSPP N/A N/A N/A
11 IBERDROLA RENEWABLES, Inc.SF WSPP N/A N/A N/A
12 Integrys Energy Services, Inc.SF WSPP N/A N/A N/A
13 J. Aron & Company SF WSPP N/A N/A N/A
14 J.P. Morgan Ventures Energy Corporatio SF WSPP N/A N/A N/A
Total
FERC FORM NO.1 (ED. 12-90)Page 326.7
Name of Respondent This oo0rt Is:
I
Date of Report
I
Year/l-enoa ot Kepon
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2oo9/Q4
(2) OA Resubmission 04/12/2010
ccu~~~g~~\ (Continued)
-Onauding power exc an es)
AD - for out-ot-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, tor 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 Efy type ot 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 repored in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt ot energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered ($)($)($)of Settlement ($)
(g)(h)(i)Ol (k)(I)(m)
2,60C 86,OOC 86,000 1
931 26,79.26,792 2
14,20(390,241 390,246 3
1,20:27,90 27,902 4
31:14,17 14,17~5
4,80C 144,50C 144,500 6
91 2,96C 2,960 7
80C 25,OOC 25,OOC 8
2,80C 107,531 107,53€9
1,761 59,721 59,726 10
86,92E 4,626,821 4,626,82€11
68,161 2,652,65 2,652,657 12
2,40C 108,02C 108,020 13
23,65C 1,291,501 1 ,291 ,50e 14
2,911,842 195,389 327,800 2,815,124 153,627,912 4,126,029 160,569,06~
FERC FORM NO.1 (ED. 12-90)Page 327.7
Name of Respondent This 'ì:ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) A Resubmission 04/1212010
PU~C~eHED POWER JiAccou1t 5 5)
n u ing power ex anges
1. Report all power purchases made during the year. Also report exchanges of electcity (i.e., transactons involving a balancing of
debits and credits for energy, capac, etc.) and any settlements for imbalance exchanges.
2. Enter the name of the seller or other part in an exchange trnsacton in coumn (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or afliation the respondent has with the seller.
3. In column (b), enter a Statistical Classifition Code based on the oriinal contctual 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 th same as, or second only to, the suppliets service to its own ultimate consumers.
LF - for long-term firm serice. "Long-term" means fie years or longer and "firm" means that service cannot be interrpted 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 servic). This categor should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transacion identifed as LF, provide in a footnote the termination date of the contract
define as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF servce expe 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
servic, aside from transmission constraints, must match the availabilit and reliabilit of the designated unit.
IU - for intermediate-term service from a designated generaing unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of elecricity. 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 whic cannot be place in the above-defined categoris, 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 JWerage AveragecatinTanff Number Demand(MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Macquarie Cook Power Inc.SF WSPP NlA N/A N/A
2 Morgan Stanley Capital Group Inc.-NlA N/A N/A
3 Morgan Stanley Capital Group Inc.SF WSPP N/A N/A N/A
4 NaturEner USA, LLC SF WSPP NlA N/A N/A
5 Nevada Power Company, dba NV Energy SF WSPP N/A N/A N/A
6 NextEra Energy Power Marketing, LLC SF WSPP N/A N/A N/A
7 NorthWestem Energy SF T-7 N/A N/A N/A
8 NorthWestern Energy SF WSPP N/A N/A N/A
9 PacifiCorp Inc.SF T-13 NlA N/A N/A
10 PacifiCorp Inc.SF WSPP N/A N/A N/A
11 PacifiCorp Inc._WSPP NlA N/A N/A
12 Portland General Electric Company SF T-14 N/A N/A N/A
13 Portland General Electric Company SF WSPP N/A N/A N/A
14 Powerex Corp.:~.WSPP N/A N/A N/A
Total
FERC FORM NO.1 (ED. 12-90)Page 326.8
'Nme of Respondent This oo0rt IS:
I
Date ot Keport
I
yearwerioa or Keport
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/12/2010
r ..m'""11 ,~ ~x. ccUHl.SSSL (Continued)ncluding 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), identif the FERC Rate Schedule Number or Tari, or, for non-FERC jurisdidional sellers, indude an appropriate
designation for the contrad. On separate lines, list all FERC rate schedules, tarifs or contrad designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges impose 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 (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 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 recived as settlement by the respondent. For power exchanges, report in column (m) the settement
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 COSTISETILEMENT OF POliR 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)
43~40,25 40,2&1 1
335,936 335,936 2
52,57~2,662,891 2,662,898 3
1 6E 66 4
12~3,12!3,12~5
16,40(668,301 668,300 6
8~3,021 3,021 7
95(28,25~28,25~8
48!17,45~17,45~9
36,771 1,255,5&1 1i255,55~10
69,117 69,11/11
121 4,75!4,755 12
28,071 1,066,21 1,066,21~13
51 2,49.2,492 14
2,911,842 195,389 327,800 2,815,124 153,627,912 4,126,029 160,569,06!
FERC FORM NO.1 (ED. 12-90)Page 327.8
Name of Respondent ThiS~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Oriinal (Mo, Da, Yr)End of 2009/Q4
(2)A Resubmission 04/121010
PU~C~AdrED POWER JiAccunt 5 5)
(n u ing power ex anges)
1. Report all power purchases made dunng the year. Also report exchnges of electricity (i.e., transaions 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 coumn (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 onginal cotractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service whic the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resourc planning). In additon, the reliability of requirement serice must
be the same as, or second only to, the suppliets seice to its own ultmate cosumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain delivenes of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identifed as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF servce expe that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm servces, whre the duratin of each penod of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliabilit of
service, aside from transmission constraints, must match the availabilty and reliabilty of the designated unit.
IU - for interediate-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 electicity. Use this category for transactons involvng a balancing of debits and credits for energy, capacity, etc.
and any settements for imbalanced exchanges.
as - for other service. Use this category only for thse servces which cannot be plac in the above-defined categones, such as all
non-firm service regardless of the Length of the contrct and service from designated units of Less than one year. Descnbe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly Biling Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Powerex Corp.~wspp NlA N/A N/A
2 Powerex Corp.SF WSPP N/A N/A N/A
3 PPL EnergyPlus, LLC LF WSPP N/A NlA NIP
4 PPL EnergyPlus, LLC WSPP NlA N/A N/A
5 PPL EnergyPlus, LLC SF WSPP N/A N/A N/A
6 Prudential Bache Commodities, LLC -NlA N/A N/A
7 Public Service Company of Colorado SF WSPP N/A N/A NlA
8 Public Service Company of New Mexico WSPP NlA N/A N/A-
9 Public Service Company of New Mexico SF WSPP N/A N/A N/A
10 Puget Sound Energy, Inc.WSPP N/A N/A N/A
11 Puget Sound Energy, Inc.SF T-9 N/A NlA N/A
12 Puget Sound Energy, Inc.~WSPP N/A NlA N/A
13 Rainbow Energy Marketing Corporation WSPP N/A N/A NlA
14 Rainbow Energy Marketing Corporation SF WSPP NlA N/A N/A
Total
FERC FORM NO.1 (ED. 12-90)Page 326.9
Name or KesponOent i ni5 ~oii 15:
I
UalEHT Kepor¡
I
T earllerioo or I"epon
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) OA Resubmission 04/1212010
ccouHt. ::::::t \ (i;OminUeO)(InCludíng 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 appropriate
designation for the contract. On separate lines, list all FERC rate scedules, tariffs or contract designations under which service, as
identified in coumn (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 bils recived as settlement by the respondent. For power exchanges, report in coumn (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)0)(k (I)(m)
2f 1,15C 1,150 1
72,69E 3,894,68.0 3,894,684 2
103,58.0 4,609,48f 4,609,488 3
4,33E 163,94C 163,940 4
71,00~2,654,60 2,654,60::5
2,047,770 2,047,770 6
30f 14,OOf 14,008 7
97,808 97,808 8
8S 3,54.3,542 9
75 2,40C 2,400 10
105 3,80 3,803 11
31,77~1,327,88¿1,327,882 12
1,60C 75,20C 75,200 13
33,24f 1,425,85~1,425,853 14
2,911,842 195,389 327,800 2,815,124 153,627,912 4,126,029 160,569,06f
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 Oriinal (Mo, Da, Yr)End of 2009/Q4
(2) OA Resubmission 04/121010
PU~C~JlED POWERchAccunt 555)n u ing power ex anges)
1. Report all power purchases made during the year. Also report exchanges of electrici (i.e., transactons involving a balancing of
debits and credits for energy, capaci, 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 afliation 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 fie years or longer and "firm" means that service cannot be interrpted for
economic reasons and is intended to remain reliable even under advers 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 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 generting unit. "Long-term" means five years or longer. The availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilit and reliabilit of the designated unit.
IU - for intermediate-term service from a designated generaing unit. The same as LU servce expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of elecricity. Use this category for transactions involving a balancing of debits and credits for energy, capaci, 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 servic 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 FERCRate Average Actual Demand (MW)
No.(Footnote Affliations)Classif Schedule or Monthly Biling Average Average
cation Tari Numbr Demand(MW Monthly NCP Deman Monthly CP Demanc
(a)(b)(c)(d)(e)(f)
1 Seattle City Light SF WSPP NlA N/A N/A
2 Sempra Energy Solutions SF WSPP NlA N/A N/A
3 Sempra Energy Trading LLC SF WSPP N/A N/A NlA
4 Shell Energy North America (US), L.P.WSPP N/A N/A NlA
5 Shell Energy North America (US), L.P.SF WSPP N/A N/A NlA
6 Sierra Pacific Power Co., dba NV Energ SF T-55 N/A N/A N/A
7 Sierr Pacific Power Co., dba NV Energ SF WSPP N/A N/A NlA
8 Sierra Pacic Power Co.. dba NV Energ WSPP N/A N/A N/A
9 Snohomish County PUD SF WSPP N/A N/A N/A
10 Southwestern Public Servic Company SF wspp N/A NlA N/A
11 Tacoma Power SF WSPP N/A N/A N/A
12 The Energy Authority, Inc.SF WSPP N/A N/A N/A
13 TransAlta Energy Marketing (U.S.) Inc.SF WSPP N/A NlA N/A
14 Tucson Electric Power Company SF WSPP N/A N/A N/A
Total
FERC FORM NO.1 (ED. 12-90)Page 326.10
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/12/2010
-.. '''" ccuHt.::::::l\(~ontlnUed)
'(1ñauding pOWì- 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, indude 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 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 settement amount (i)
include credits or charges other than incrmental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.
Received Delivered ($)($~($)of Settlement ($)
(g)(h)(i)0)(k (I)(m)
9,27f 324,37,324,377 1
4,35.143,64.143,642 2
228,001 15,904,97!15,904,975 3
4,63f 129,78(129,780 4
23,34'796,84E 796,84€5
61 2,58~2,584 6
6,21,193,93~193,934 7
18,573 18,573 8
9,4ß.289,77 289,773 9
31 35 10
7,76 197,63E 197,63l!11
7,241 212,81~212,814 12
71,681 5,849,161 5,849,16i 13
1,13.36,571 36,57i 14
2,911,842 195,385 327,800 2,815,12~153,627,912 4,126,025 160,569,06f
FERC FORM NO.1 (ED. 12.90)Page 327.10
Name of Respondent ThiSro0rt Is:Date of Report
I
Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) OA Resubmission 041121010
PU~CHA&iED POWER hAccount 5 5)
(nclu ing power exc anges)
1. Report all power purchases made during the year. Also report exchanges of elecricity (i.e., transactons 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 servic which the supplier plans to provide on an ongoing basis (i.e., the
supplier indudes 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 consumer.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrpted for
ecnomic reasons and is intended to remain reliable even under advers 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 expe that "intermdiate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm servces, whre the duratin of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generting unit. "Long-term" means fie years or longer. The availabilty 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 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, capacit, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERCRate Average Actual Demand (MW)
No.(Footnote Affliations)Classif-Schedule or Monthly Billng Average Average
cation Tari Number Demand(MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 UBS Securities LLC .'_~d_N/A N/A N/A
2 Raft River Energy i LLC -N/A N/A NlA
3 Telocaset Wind Power Partners LLC LU APP-A N/A N/A N/A
4 Net Metering Customers -N/A N/A N/A
5 Power Exchanges
6 Bonneville Power Administration -
7 NorthWestem Energy -
8 PacìfiCorp Inc.-
9 Puget Sound Energy, Inc.-
10 Sierra Pacific Power Co., dba NV Energ
11 Utah Associated Municipal Power System
12 Portland General Electric Company EX WSPP
13 Other Transactions
14 Accg Valuation of Portland General EI
Total
FERC FORM NO.1 (ED. 12-90)Page 326.11
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 2009/04
(2) ñA Resubmission 04/12/2010
'" '''' '''~iicii cc~~~g¡~t;ontinued)ncluding power ex ange)
AD - for out-of-period adjustment. Use this coe 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 appropriate
designation for the contract. On separate lines, list all FERC.rate schedules, taris 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
th 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 serice, 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 megawat basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) tile megawatthours
of power exchanges recived and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column Ö), 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 recived, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.
Received Delivered ($)($)($)of Settlement ($)
(g)(h)(i)0)(k)(I)(m)
987,160 987,16C 1
75,94f 4,348,69!4,348,695 2
296,60E 15,150,91!15,150,9H 3
50f 37,631 37,631 4
5
58,844 12,463 6
3,301 7
56,147 220,977 8
274 9
10,947 10
12 11
i 80,112 80,112 12
111,600 111,60(13
14
2,911,842 195,389 327,800 2,815,124 153,627,912 4,126,029 160,569,06f
FERC FORM NO.1 (ED. 12-90)Page 327.11
Narne of Respondent This Report is:Date of Report Year/Period of Report
(1) ~An Original (Mo, Da, Yr)
Idaho Power Company 1(2) . A Resubmission 04/12/2010 2009104
FOOTNOTE DATA
¡Schedule Page: 326 Line No.: 3 Column: a
The Tamarack Energy Partnership demand readings are taken from an electronic demand
recorder provided by Idaho Power Co. The actual demand is not used in determining the cost
of energy.
I$chedule Page: 326 Line No.: 3 Column: eUnavailable
I$chedule Page: 326 Line No.: 3 Column: fUnavailable
¡Schedule Page: 326 Line No.: 9 Column: e
Unavailable
¡Schedule Page: 326 Line No.: 9 Column: f
Unavailable
I$chedule Page: 326.1 Line No.: 1 Column: bNon Firm Purchases
¡Schedule Page: 326.1 Line No.: 2 Column: eUnavailable
!Schedule Page: 326.1 Line No.: 2 Column: fUnavailable
¡Schedule Page: 326.1 Line No.: 8 Column: bNon Firm Purchases
I$chedule Page: 326.1 Line No.: 12 Column: eUnavailable
I$chedule Page: 326.1 Line No.: 12 Column: fUnavailable
¡Schedule Page: 326.2 Line No.: 4 Column: eUnavailable
¡Schedule Page: 326.2 Line No.: 4 Column: f
Unavailable
¡Schedule Page: 326.2 Line No.: 11 Column: eUnavailable
¡Schedule Page: 326.2 Line No.: 11 Column: fUnavailable
¡Schedule Page: 326.3 Line No.: 5 Column: a
Ida West, a subsidiary of Idaho Power Company, has partial ownership of these
I$chedule Page: 326.4 Line No.: 3 Column: a
Ida West, a subsidiary of Idaho Power Company, has partial ownership of these
I$chedule Page: 326.4 Line No.: 4 Column: a
Ida West, a subsidiary of Idaho Power Company, has partial ownership of these
¡Schedule Page: 326.4 Line No.: 5 Column: a
Ida West, a subsidiary of Idaho Power Company, has partial ownership of these projects.
fSedule Page: 326.4 Line No.: 12 Column: bNon Firm Purchases
¡Schedule Page: 326.5 Line No.: 4 Column: b
Energy difference between scheduled and
¡Schedule Page: 326.5 Line No.: 5 Column: b
Energy difference between mountain and pacific time schedules
¡Schedule Page: 326.6 Line No.: 6 Column: b
Financial Transmission Losses
!Schedule Page: 326.6 Line No.: 8 Column: bNon Firm Purchases
¡Schedule Page: 326.8 Line No.: 2 Column: b
ISDA Master Agreement with Morgan Stanley dated 03/01/2000
~edule Page: 326.8 Line No.: 11 Column: b
Financial Transmission Losses
I
I
I
I
I
I
I
I
I
I
I
I
I
I
Iprojects.
=:projects.~projects.
I
I
I
-=i.~
i~--~
I
actual receipts from small power producers.
I FERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/1212010 2009/Q4
FOOTNOTE DATA
!§chedule Page: 326.8 Line No.: 14 Column: b
2008 Correction
I$chedule Page: 326.9 Line No.: 1 Column: bNon Firm Purchases
I$chedule Page: 326.9 Line No.: 4 Column: bNon Firm Purchases
I$chedule Page: 326.9 Line No.: 6 Column: bPrudential Bache Commodities, LLC Futures Account Document, dated September 4, 2008.
I$chedule Page: 326.9 Line No.: 8 Column: b
Inadvertent Financial Settlement
¡Schedule Page: 326.9 Line No.: 10 Column: bNon Firm Purchases
¡Schedule Page: 326.9 Line No.: 13 Column: b
Non Firm Purchases
I$chedule Page: 326.10 Line No.: 4 Column: bShort Term Dni t Contingent
I$chedule Page: 326.10 Line No.: 8 Column: bFinancial Transmission Losses
¡Schedule Page: 326.11 Line No.: 1 Column: b
Institutional Futures Client Account Agreement with DBS, dated March 8, 2006.
¡Schedule Page: 326.11 Line No.: 2 Column: bUnavailable
I$chedule Page: 326.11 Line No.: 4 Column: bSchedule 84 Net Metering
I$chedule Page: 326.11 Line No.: 6 Column: b
Scheduled losses not removed with loss transactions.
¡Schedule Page: 326.11 Line No.: 7 Column: b
Scheduled losses not removed with loss transactions.
¡Schedule Page: 326.11 Line No.: 8 Column: b
Scheduled losses not removed with loss transactions.
¡Schedule Page: 326.11 Line No.: 9 Column: b
Scheduled losses not removed with loss transactions.
¡Schedule Page: 326.11 Line No.: 10 Column: b
Scheduled losses not removed with loss transactions.
¡Schedule Page: 326.11 Line No.: 11 Column: b
Scheduled losses not removed with loss transactions.
I FERC FORM NO.1 (ED. 12-87)Page 450.2
Name of Respondent This I ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1)~An Original (Mo, Da, Yr)End of 2oo9/Q4
(2)A Resubmission 04/121010
,':'' ccount 406.1)
(Includina trnsactons referr to as 'wheeliiià')
1. Report all transmission of electricity, i.e., wheeling, provided for other elecric utilties, cooperatives, other public autorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for eách 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 servic. Report in coumn (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 enties listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code base on the original contractual 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 Serice, 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 accunting adjustments or "true-ups" for service provided in prior reportng periods. Provide an explanation in a footnote for
each adjustment. See General Instructon for definitions of codes.
Line Payment By Energ Received Fro Energy Delivered To Statistical
No.(Company of Public Authorit)(Company of Public Autori)(Company of Public Autori)Classifi
(Footnote Affliation)(Footnote Afliation)(Footnote Affliation)cation
(a)(b)(c)(d)
1 Bonnevile Powr Administration - OTEC Bonneville Powr Adminisration Oregon Trails Electic Co-p FNO
2 Bonnevill Power Administration - OTEC Bonneville Power Administration Oregon Trails Electric Co-op AD
3 Bonnevile Power Administration - USBR Bonnevile Powr Administtion United States Bureau of Reclamati FNO
4 Bonnevile Power Administration - USBR Bonneville Powr Administratin United States Bureau of Reclamati AD
5 Bonnevile Power Administration - Raft Bonnevile Power Administrtion Raft River Electric Co-op FNO
6 Bonnevile Power Administration - Raft Bonneville Power Administration Raft River Electric Co-op AD
7 Bonneville Power Administration - PF Bonneville Pow Administratin Priorit Firm Customers FNO
8 Bonnevile Power Administration - PF Bonneville Powr Adminisratin Priori Firm Customers AD
9 Milner Irrigation District United States Bureau of Recamat Milner Irration District OlF
10 Cargil Seatte Cit light Bonnevile Power Administration OS
11 PaciCorp PaciCorp West PaciCorp West FNO
12 PaciCorp PaciCorp West Paciorp West AD
13 United States Bureau of Indian Affirs Bonnevile Power Administration United States Bureau of Indian Af OS
14 PacifiCorp Power Marketing PacifiCorp West PacifiCorp West OS
15 PacifiCorp Power Marketing PacifiCorp West PacifCorp West AD
16 Black Hils Power AD
17 Black Hils Power PacifCorp West Bonnevile Power Administration NF
18 Black Hils Power Bonnevile Powr Administration PacifiCorp West NF
19 Bonnevile Power Admin.AD
20 Bonnevile Power Admin.NorthWestemlPacifiCorp East Bonneville Power Administration NF
21 Bonnevile Power Admin.PacifiCorp East Sierra Pacic Power NF
22 Bonnevile Power Admin.Bonnevile Powr Administratin Bonnevile Power Administration NF
23 Bonnevile Power Admin.Avista Bonnevile Power Administration NF
24 Bonnevile Power Admin.Avista Sierra Pacific Power NF
25 Cargil Power Markets AD
26 Cargil Power Markets NorthWestem/PaciCorp East PacifiCorp East NF
27 Cargil Power Markets PacifiCorp East NortWestem/PacifiCorp East NF
28 Cargill Power Markets PacifiCorp East NortWestem/PacifiCorp East NF
29 Cargil Power Markets PaciCorp East NortWestern/PacifiCorp East SFP
30 Cargill Power Markets PacifiCorp East PacifiCorp East NF
31 Cargil Power Markets PacifiCorp East PacifiCorp East SFP
32 Cargil Power Markets PaciCorp East PacifiCorp West NF
33 Cargill Power Markets Pacifiorp East Bonnevile Power Administration NF
34 Cargil Power Markets PacifiCorp East Bonnevile Power Administration SFP
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328
ccoun
(Includin transactions raftered to as 'weelin '
5. In column (e), identif the FERC Rate Schedule or Tanff 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 appropnate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of biling demand that is specied in the firm transmission service contrct. 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.
Year/Period of Report
End of 2009/Q4
Name of Respondent
Idaho Power Company
FERC Rate Point of Receipt Point of Delivery Billng TRANSFER OF ENERGY Line
Schedule of (Subsatation or Other (Substation or Other Demand No.Tarif Number Designation)Designation)(MW)
(e)(f)(g)(h)
382,722 1
5.00000 2
5.00000 193,638 3
5.00000 4
5.00000 224,865 5
5.00000 6
5.00000 803,02 7
5.00000 8
Various in Idaho 8,494 9
321,755 10
2,232 11
12
LaGrande, Oregon Various in Idaho 12,465 13
JBSN ENPR 3,292 14
JBSN ENPR 15
5.00000 16
5.00000 JBSN LGBP 406 17
5.00000 LGBP JBSN 310 18
5.00000 19
5.00000 BPAT.NWMT OTEC 204 20
5.00000 BRDY M345 200 21
5.00000 LGBP LGBP 753 22
5.0000 LOLO LGBP 17,425 23
5.00000 LOLO M345 1,783 24
5.00000 25
5.00000 AVAT.NWM BORA 496 49 26
5.00000 BORA AVAT.NWM 86 86 27
5.00000 BORA BPAT.NWMT 351 351 28
5.00000 BORA BPAT.NWM 667 66 29
5.00000 BORA BRDY 180 18 30
5.00000 BORA BRDY 400 40 31
5.00000 BORA ENPR 7,859 7,85 32
5.00000 BORA LGBP 22,470 22,47 33
5.00000 BORA LGBP 22,834 22,83 34
4,134,363
FERC FORM NO.1 (ED. 12-90)Page 329
Name of Respondent This oo0rt Is:Date of Report Vear/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Vr)End of 2009/Q4
(2) DA Resubmission 04121010
"'''J i T t:UK U.I '!" "'~n~í;iccunt 456.1)
(Including transactons referred to as 'wheelin ')
1. Report all transmission of electricity, i.e., wheeling, provided for other elecric utilities, coperatives, other public authorities,
qualifying facilities, non-trditional utlit 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 Classifcation coe based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Netwoi1 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 - Oter Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accunting 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 Recived From Energy Delivered To Statistical
No.(Company of Public Authority)(Company of Public Authori)(Company of Public Authority)Classifi-
(Footnote Affliation)(Footnote Affliation)(Footnote Affliation)cation
(a)(b)(c)(d)
1 Cargil Power Markets PaciCorp East Avista NF
2 Cargil Power Markets Paciorp East Avista SFP
3 Cargil Power Markets Paciorp East Sierr Pacic Power NF
4 Cargill Power Markets Paciorp East Sierra Pacific Power SFP
5 Cargill Power Markets NortWestemlaciorp East PacifiCorp East NF
6 Cargil Power Markets NortWesternaciorp East PacifiCorp East SFP
7 Cargil Power Markets NortWestemlPaciCorp East PacifiCorp East NF
8 Cargill Power Markets NorthwestemlPaciorp East Sierra Pacific Power NF
9 Cargil Power Markets NorthWestemlPaciCorp East Sierra Pacic Power SFP
10 Cargil Power Markets PacifiCorp East PacifiCorp East NF
11 Cargill Power Markets PaciCorp East Sierra Pacific Power SFP
12 Cargil Power Markets Paciorp East NorthWestern/PacifiCorp East NF
13 Cargill Power Markets PaciCorp West PacifCorp East NF
14 Cargil Power Markets Paciorp west PacifiCorp East SFP
15 Cargil Power Markets PaciCorp West Sierra Pacific Power NF
16 Cargill Power Markets NorthWesternlPaciCorp East PacifiCorp East NF
17 Cargill Power Markets NorthWestem/Pacifiorp East Sierra Pacific Power SFP
18 Cargil Power Markets PaciCorp West PacifiCorp East NF
19 Cargil Power Markets Paciorp West Pacifiorp West NF
20 Cargill Power Markets PacifiCorp West Bonneville Power Administration NF
21 Cargill Power Markets PacifCorp West Bonnevile Power Administration SFP
22 Cargil Power Markets Paciorp West Sierr Pacific Power NF
23 Cargil Power Markets PacifCorp West Sierra Pacific Power SFP
24 Cargil Powr Markets NortWestemlPaciorp East Bonneville Power Administration NF
25 Cargill Power Markets NortWesternaciorp East Sierr Pacic Power NF
26 Cargill Power Markets Bonnevile Powr Administrtion PaciCorp East NF
27 Cargil Power Markets Bonneville Power Administration PaciiCorp East SFP
28 Cargill Power Markets Bonneville Power Administration Idaho Power Company NF
29 Cargil Power Markets Bonnevile Power Administration Sierra Pacific Power NF
30 Cargil Power Markets Bonnevile Power Administration Sierra Pacific Power SFP
31 Cargil Power Markets Avista PaciCorp East NF
32 Cargil Power Markets Avista PacifiCorp East SFP
33 Cargil Power Markets Avista Sierra Pacif Power NF
34 Cargil Power Markets Sierra Pacific Power PacifiCorp East NF
TOTAL
FERC FORM NO.1 (ED. 12.90)Page 328.1
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 2009/Q4
(2) OA Resubmission 04/12/2010
I ~!" ELl:(,TRIç.lly F~K l! i '~".vy ccoun 'W ontinueo)
(Including transactions reftred 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 identifcation 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 Biling TRANSFER OF ENERGY Line
Schedule of (Subsatation or Other (Substation or Other Demand Megawatt Hours Megawatt Hours No.
Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)(g)(h)(i)0)
5.00000 BORA LOLO 234 23A 1
5.00000 BORA LOLO 1,288 1,288 2
5.00000 BORA M345 3,839 3,835 3
5.00000 BORA M345 39,937 39,93 4
5.00000 BPAT.NWMT BORA 2,139 2,135 5
5.00000 BPAT.NWMT BORA 4,192 4,19.6
5.00000 BPAT.NWMT BRDY 11,406 11 ACE 7
5.00000 BPAT.NWMT M345 872 8701 8
5.00000 BPAT.NWMT M345 384 .384 9
5.00000 BRDY BORA 10
5.00000 BRDY M345 11
5.00000 BRDY BPAT.NWMT 39 3S 12
5.00000 ENPR BORA 64,175 64,17E 13
5.00000 ENPR BORA 8,300 8,30C 14
5.00000 ENPR M345 2,812 2,81..15
5.00000 HTSP BRDY 2,861 2,861 16
5.00000 HTSP M345 492 49 17
5.00000 JBSN BORA 256 25E 18
5.00000 JBSN ENPR 3,396 3,39E 19
5.00000 JBSN LGBP 8,722 8,72.20
5.00000 JBSN LGBP 5,104 5,104 21
5.00000 JBSN M345 3,106 3,10€22
5.00000 JBSN M345 5,561 5,561 23
5.00000 JEFF LGBP 161 161 24
5.00000 JEFF M345 90 9C 25
5.00000 LGBP BORA 10,087 10,08 26
5.00000 LGBP BORA 445 44E 27
5.00000 LGBP IPCO 609 60S 28
5.00000 LGBP M345 16,682 16,682 29
5.00000 LGBP M345 2,248 2,24~30
5.00000 LOLO BORA 1,301 1,301 31
5.00000 LOLO BORA 528 52f 32
5.00000 LOLO M345 993 99~33
5.00000 LYPK BORA 23,832 23,83 34
0 4,134,363 4,134,36
FERC FORM NO.1 (ED. 12-90)Page 329.1
Name of Respondent This Re ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) ~An Original (Mo, Da, Yr)End of 2009/Q4
(2)A Resubmission 04/1212010
. ELE,CI l'lvJ IT,. ccunt 456.1)
(Includina trnsadions referred to as 'wheèTng')
1. Report all transmission of elecricity, i.e., wheeling, provided for other electric utilties, cooperatives, other public authorities,
qualifying facilities, non-traditinal utilit suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involvng the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public 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 authori. 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 Classifcation code base on the original contractual ters 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 Serice, 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 coes.
Line Payment By Energy Recived From Energy Delivered To Statistical
No.(Company of Public Authority)(Company of Public Authority)(Company of Public Authority)Classif-
(Footnote Affliation)(Footnote Afliation)(Footnote Affliation)cation
(a)(b)(c)(d)
1 Cargill Power Markets Sierra Pacific Power PacifiCorp East SFP
2 Cargil Power Markets Sierr Pacic Powr NortWestern/PacifiCorp East NF
3 Cargil Power Markets Sierr Paci Powr Paciorp East NF
4 Cargill Power Markets Sierr Paci Powr PaciCorp East SFP
5 Cargil Power Markets Sierr Pac Powr NortWestem/PacifiCorp East SFP
6 Cargil Power Markets Sierr Pacic Powr Bonnevile Power Administration NF
7 Cargil Power Markets Sierr Pacc Powr Bonnevile Power Administration SFP
8 Cargil Power Markets Sierr Pacific Power Avista NF
9 Cargil Power Markets Sierra Pacific Power Avista SFP
10 Cargil Power Markets Sierra Pacifi Power Sierra Pacific Power NF
11 Cargil Power Markets Sierra Paci Power Sierra Pacif Powr SFP
12 Cargil Power Markets Sierr Pacic Powr PaciCorp East NF
13 Cargil Power Markets Sierr Paci Powr Bonnevile Power Administration NF
14 Cargil Power Markets Sierra Paci Powr Bonnevile Power Administration SFP
15 Cargil Power Markets Sierr Pacifi Power NortWestem/PaciCorp East NF
16 Cargil Power Markets Idaho Power Company Idaho Power Company NF
17 Cargil Power Markets Paciorp East PacifiCorp East NF
18 Cargil Power Markets Idaho Power Company Idaho Power Company NF
19 Cargil Power Markets Idaho Power Company Bonnevile Power Administration NF
20 Cargil Power Markets Idaho Power Company Sierra Pacic Power NF
21 Citigroup Energy AD
22 Citigroup Energy NF
23 Conoco Philips AD
24 Constellation Energy AD
25 Constellation Energy NF
26 Coral Power AD
27 Coral Power PaciCorp East Bonneville Power Administration NF
28 Coral Power PaciCorp East Avista NF
29 Coral Power PacifiCorp East Sierra Pacifc Power NF
30 Coral Power PacifCorp East Bonnevile Power Administration NF
31 Coral Power PaciCorp East Sierra Pacific Power NF
32 Coral Power Idaho Power Company Sierra Pacific Power NF
33 Coral Power NorthWestern/PacifiCorp East Bonnevile Power Administration NF
34 Coral Power Bonnevile Power Administration PacifiCorp East NF
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.2
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 2009/Q4
(2) iiA Resubmission 04/12/2010
i I OF i' Y . , ._. .... ,(" ccu~t 456)(i;ontlnUeo)
(Including transactions reffred 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 identifed in column (d), is provided.
6. Report receipt and delivery loctions for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(9) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of 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 recived and delivered.
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.
Tarif Number Designation)Designation)(MW)Received Delivered
(e)(f)(g)(h)(i)0)
5.00000 LYPK BORA 26,50E 26,50E 1
5.00000 LYPK BPAT.NWMT 15 H 2
5.00000 LYPK BRDY 10,302 10,30.3
5.00000 LYPK BRDY 288 28E 4
5.00000 LYPK HTSP 64 60 5
5.0000 LYPK LGBP 33,433 33,43 6
5.00000 LYPK LGBP 288 281 7
5.0000 LYPK LOLO 79 7!8
5.0000 LYPK LOLO 391 391 9
5.00000 LYPK M345 33,28C 33,28C 10
5.0000 LYPK M345 186,991 186,991 11
5.00000 M345 BORA 45 4~12
5.00000 M345 LGBP 3,417 3,41 13
5.00000 M345 LGBP 40 4(14
5.00000 M345 BPAT.NWM ~2~15
5.00000 MDSK IPCO 12 1.16
5.00000 MLCK BRDY 2,663 2,66 17
5.00000 OBBLPR IPCO 15 1!18
5.00000 OBBLPR LGBP 50 5(19
5.00000 OBBLPR M345 15 1!20
5.00000 21
5.00000 22
5.00000
"23
5.00000 24
5.00000 25
5.00000 26
5.00000 BORA LGBP 1,267 1,261 27
5.00000 BORA LOLO 288 28E 28
5.00000 BORA M345 4,760 4,76C 29
5.00000 BRDY LGBP 506 50E 30
5.00000 BRDY M345 1,724 1,72'31
5.00000 JBWT M345 450 45(32
5.00000 JEFF LGBP 644 64 33
5.00000 LGBP BORA 25 2~34
~4,134,363 4,134,36;
FERC FORM NO.1 (ED. 12-90)Page 329.2
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2009/Q4
.(2) riA Resubmission 04/1212010
I:Li;'- I KI~II i ccunt 456.1 )
(Includiñò" transactns referred to as 'wheeling')
1. Report all transmission of electricity, Le., wheeling, provided for other elecric utilities, cooperatives, other public authoriies,
qualifying facilities, non-trditional utlity suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinc 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 authori. 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 ofthe 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 accunting adjustments or "true-ups" for service proided in prior reportng periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of coes.
Line Payment By Ener Recived From Energy Delivered To Statistical
No.(Company of Public Authorit)(Company of Public Authori)(Company of Public Authori)Classif
(Footnote Affliation)(Footnote Affliation)(Footnote Affliation)cation
(a)(b)(c)(d)
1 Coral Power Bonnevile Powr Administtin Sierra Paci Power NF
2 Coral Power Avista Sierra Pacific Power NF
3 Coral Power Sierra Paci Powr PacifiCorp East NF
4 Coral Power Sierra Paci Power Bonnevile Power Administration NF
5 Energy Authority AD
6 Endure Energy Paciforp East Bonneville Power Administration NF
7 Endure Energy Paciorp East Bonnevile Power Administration SFP
8 Endure Energy Pacifiorp East Avista NF
9 Endure Energy Paciorp East Avista SFP
10 Highland Energy AD
11 Macquarie Cook PacifiCorp East Bonneville Powr Administration NF
12 Morgan Stanley Capital Group AD
13 Morgan Stanley Capital Group PacifiCorp East Bonneville Power Administration NF
14 Morgan Stanley Capital Group Paciforp East Avista NF
15 Morgan Stanley Capital Group NortWestern/PacifCorp East PacifiCorp East NF
16 Morgan Stanley Capital Group Paciorp East Bonnevile Power Administration NF
17 Morgan Stanley Capitl Group NortWestemlPaciCorp East Paciorp East NF
18 Morgan Stanley Capital Group NortWestem/PacifiCorp East Bonnevile Power Administration NF
19 Morgan Stanley Capital Group Nortwetem/PaciCorp East Sierra Pacific Power NF
20 Morgan Stanley Capital Group Bonnevile Power Administration PacifiCorp East NF
21 Morgan Stanley Capital Group PacifCorp East PacifiCorp East NF
22 Nortwestem Energy AD
23 Northwestern Energy (Merchant)NortWestemlPacifiCorp East Bonneville Power Administration NF
24 Pacificorp Power Marketing AD
25 Pacicorp Power Marketing PacifiCorp East PacifiCorp West NF
26 Pacicorp Power Marketing PaciCorp East PacifiCorp west NF
27 Pacificorp Power Marketing PaciCorp East Idaho Power Company NF
28 Pacificorp Power Marketing PaciCorp East PacifCorp East SFP
29 Pacicorp Power Marketing Pacifiorp East Bonneville Power Administration NF
30 Pacifcorp Power Marketing PacifiCorp East Sierr Pacifc Power NF
31 Pacificorp Power Marketing PacifiCorp East Sierra Pacifi Power SFP
32 Pacificorp Power Marketing PacifiCorp East PacifiCorp West NF
33 Pacificrp Power Marketing PacifiCorp East PacifiCorp East NF
34 Pacicorp Power Marketing Pacifiorp East PacifiCorp West NF
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.3
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 0411212010
i ! qF y i-uK U! Ht:K.:)_l~ cco~Pit 4~ti)(l;ontinued)
(Including transactons reftred 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 loctions for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of biling demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and ü) the total megawatthours recived and delivered.
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.
Tariff Number Designation)Designation)(MW)Received Delivere
(e)(f)(g)(h)(i)(j)
5.00000 LGBP M345 4,931 4,931 1
5.00000 LOLO M345 308 301 2
5.00000 M345 BRDY 150 15C 3
5.00000 M345 LGBP 870 87C 4
5.00000 5
5.00000 BORA LGBP 1,106 1,1OE 6
5.00000 BORA LGBP 4,938 4,931 7
5.00000 BORA LOLO 2,075 2,07!8
5.00000 BORA LOLO 600 501 9
5.00000 10
5.00000 BORA LGBP 11 11 11
5.00000 12
5.00000 BORA LGBP 12,902 12,90~13
5.00000 BORA LOLO 1,257 1,251 14
5.00000 BPAT.NWMT BRDY 35 3~15
5.00000 BRDY LGBP 184 1~16
5.00000 HTSP BRDY 38 31 17
5.00000 JEFF LGBP 339 33~18
5.00000 JEFF M345 285 28!19
5.00000 LGBP BRDY 54 54 20
5.00000 MLCK BRDY 997 99,21
5.0000 22
5.00000 JEFF LGBP 46 41 23
5.00000 24
5.00000 BORA ENPR 182,128 182,121 25
5.00000 BORA JBSN 160 16(26
5.00000 BORA JBWT 464 4&:27
5.00000 BORA KPRT 48 41 28
5.00000 BORA LGBP 3,993 3,99 29
5.00000 BORA M345 3,689 3,68~30
5.00000 BORA M345 3,393 3,39:31
5.00000 BORA M500 950 951 32
5.00000 BRDY BRDY 2,183 2,18.33
5.00000 BRDY ENPR 1,399 1,39!34
0 4,134,363 4,134,36~
FERC FORM NO.1 (ED. 12-90)Page 329.3
Name of Respondent This oo0rt Is:Date ot Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2oo9/Q4
(2) OA Resubmission 04/121010
ccunt 456.1 )
(Includina trnsactions referred to as 'wheeling')
1. Report all transmission of electricity, Le., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilties, non-traditional utilit suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of trnsmission service involvng the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public autori 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 authori that the energy was delivered to.
Provide the full name of each company or public authori. Do not abbreviate or trncate name or use acronyms. Explain in a footnote
any ownership interest in or affliation the respondent has wih the enties listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classifcation coe base on the original contrctual ters 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 Serice, 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 acunting 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 Ener Recived From Energy Delivered To Statistical
No.(Company of Public Authority)(Company of Public Autori)(Company of Public Authorit)Classifi-
(Footnote Affliation)(Footnote Afliation)(Footnote Affliation)cation
(a)(b)(c)(d)
1 Paciicorp POwer Marketing Paciorp East Bonneville Power Administration NF
2 Pacificorp Power Marketing Paciorp west Paciorp East NF
3 Pacifcorp Power Marketing PaciCorp West PacifiCorp East NF
4 Pacicorp Power Marketing PacifiCorp West Bonnevile Power Administration NF
5 Pacifcorp Power Marketing PacifiCorp west Avista NF
6 Pacificorp Power Marketing Paciorp West Sierra Pacifc Power NF
7 Pacificorp Power Marketing Idaho Powr Company PaciCorp East NF
8 Pacicorp Power Marketing Idaho Power Company Paciorp East LFP
9 Pacificorp Power Marketing Idaho Power Company PaciCorp East NF
10 Pacificorp Power Marketing Idaho Power Company Pacifiorp East LFP
11 Pacificorp Power Marketing Idaho Powr Company PaciCorp West NF
12 Pacificorp Power Marketing Idaho Power Company Sierr Pacifi Power NF
13 Pacifcorp Power Marketing Idaho Power Company PacifiCorp West NF
14 PaciflCrp Power Marketing Idaho Power Company PacifCorp West LFP
15 Pacicorp Power Marketing Bonneville Power Administration PacifiCorp East NF
16 Pacificorp Power Marketing Bonnevile Power Administration Sierra Pacific Power NF
17 Pacificorp Power Marketing Avista PacifiCorp West NF
18 Portland General Electric AD
19 Portland General Electric NortWestem/Paciorp East Bonneville Power Administration SFP
20 Portland General Electric PacifCorp East Bonnevile Power Administration NF
21 Portland General Electric NortWesternPaciorp East Bonnevile Power Administration NF
22 Portland General Electric Sierr Paci Powr Bonnevile Power Administration NF
23 Portland General Electric PacifiCorp East PacifCorp East NF
24 Powerex Corp.AD
25 Powerex Corp.PacifiCorp East NortWestern/PacifiCorp East NF
26 Powerex Corp.PacifiCorp East PacifiCorp East NF
27 Powerex Corp..PacifCorp East PacifiCorp West NF
28 Powerex Corp.PacifiCorp East Bonnevile Power Administration NF
29 Powerex Corp.PacifiCorp East Bonnevile Power Administration SFP
30 Powerex Corp.PacifiCorp East Avista NF
31 Powerex Corp.PacifCorp East Sierra Pacific Power NF
32 Powerex Corp.NortWestemlPaciCorp East PacifiCorp East SFP
33 Powerex Corp.NortWestemlPaciorp East PacifiCorp East NF
34 Powerex Corp.NorthWestern/PacifiCorp East PacifiCorp East SFP
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.4
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) i:A Resubmission 04/1212010
~ ¡;I II T . ; i'" ccoun. ~"ul\ ..ontinued)
(Including transactions reftered to as 'wlieeling')
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contrct. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of biling demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billng TRNSFER OF ENERGY Line
Schedule of (Subsatation or Other (Substation or Other Demand Megawatt Hours MegaWatt HOUrs No.
Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)(g)(h)(i)0)
5.00000 BRDY LGBP 2,465 2,46!1
5.00000 ENPR BORA 24,022 24,02.2
5.00000 ENPR BRDY 4,300 4,3OC 3
5.00000 ENPR LGBP 63 6~4
5.00000 ENPR LOLO 50 5C 5
5.00000 ENPR M345 1,453 1,45~6
5.00000 JBWT BORA 14,163 14,16~7
5.00000 JBWT BORA 57,723 57,72~8
5.00000 JBWT BRDY 144,5n 144,57i 9
5.00000 JBWT BRDY 221 221 10
5.00000 JBWT ENPR 1,375 1,31f 11
5.00000 JBWT M345 2,673 2,67.:12
5.00000 JBWT M500 -11,278 -11,27f 13
5.00000 JBWT M500 542,728 542,72f 14
5.00000 LGBP BORA 969 96S 15
5.0000 LGBP M345 275 27S 16
5.00000 LOLO ENPR 3,039 3,03!17
5.00000 18)'
5.00000 BPAT.NWMT LGBP 160 16(19
5.00000 BRDY LGBP 63 6~20
5.00000 JEFF LGBP 7,348 7,34f 21
5.00000 M345 LGBP 450 45C 22
5.00000 MLCK BRDY 2,348 2,34f 23
5.0000 24
5.00000 BORA BPAT.NW 798 79a 25
5.00000 BORA BRDY 801 801 26
5.00000 BORA ENPR 2,692 2,69~27
5.00000 BORA LGBP 83,84C 83,84 28
5.00000 BORA LGBP 3,584 3,58~29
5.00000 BORA LOLO 2,251 2,251 30
5.00000 BORA M345 85 8!31
5.00000 BPAT.NWMT BORA 32
5.00000 BPAT.NWMT BRDY 544 54'33
5.00000 BPAT.NWMT BRDY 6,466 6,46E 34
(J 4,134,363 4,134,36~
FERC FORM NO.1 (ED. 12-90)Page 329.4
Name of Respondent ThiS~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2)A Resubmission 04/121010
t:YK U i ccunt 4:Jö. 1)
(Includina transactions referred to as 'wheelina')
1. Report all transmission of eledrici, Le., wheeling, provided for other elecric utilities, coeratives, other public authorities,
qualifying facilties, non-traditional utlity suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinc 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 authoriy that the energy was recived frm and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authori. Do not abbreviate or trncate name or use acronyms. Explain in a footnote
any ownership interest in or affliation the respondent has wih the entiies listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code base on th original contradual terms and coditions ofthe 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 servic, OS - Other Transmission Servce and AD - Out-of-Period Adjustments. Use this coe
for any accunting adjustments or "tre-ups" for service provided in prior reportng periods. Provide an explanation in a footnote for
each adjustment. See Generallnstrudion for definitions of coes.
Line Payment By Energy Received From Energy Delivere To Statistical
No.(Company of Public Authorit)(Company of Public Authori)(Company of Public Authority)Classifi-
(Footnote Affliation)(Footnote Affliation)(Footnote Affliation)cation
(a)(b)(c)(d)
1 Powerex Corp.NortWestenVadforp Ea~Bonneville Power Administration NF
2 Powerex Corp.NorthWe~enVadforp Eas Sierra Pacic Power NF
3 Powerex Corp.Padforp East NorthWestern/PacifiCorp East NF
4 Powerex Corp.Pacorp Ea~PaciCorp West NF
5 Powerex Corp.Padforp East Idaho Power Company NF
6 Powerex Corp.PacifiCorp East Bonnevile Power Administration NF
7 Powerex Corp.Padfor East Bonnevile Power Administration SFP
8 Powerex Corp.PaciiCorp East Avista NF
9 Powerex Corp.PacifiCorp East Sierra Pacic Power NF
10 Powerex Corp.Padforp Ea~Sierr Pacic Power SFP
11 Powerex Corp.Pacifiorp VVt PaciCorp East NF
12 Powerex Corp.Padforp VYst PaciCorp East NF
13 Powerex Corp.PaciCorp West PacifiCorp East SFP
14 Powerex Corp.Paciorp West PacifiCorp West NF
15 Powerex Corp.Paciforp West Sierra Pacific Power NF
16 Powerex Corp.NortWesternPacifCorp East PacifiCorp East NF
17 Powerex Corp.NorthWestern/PaciCorp East PacifiCorp East SFP
18 Powerex Corp.NorthWestem/PacifCorp East Sierra Pacic Power SFP
19 Powerex Corp.PacifiCorp West NorthWestern/PacifiCorp East NF
20 Powerex Corp.PaciCorp VYst NorthWestem/PacifiCorp East NF
21 Powerex Corp.PacifiCorp West Pacifiorp East NF
22 Powerex Corp.PacifiCorp West PacifiCorp West NF
23 Powerex Corp.Paciorp West Idaho Power Company NF
24 Powerex Corp.Paciorp VYst NortWestern/PacifiCorp East NF
25 Powerex Corp.PaciCorp VYst Bonnevile Power Administration NF
26 Powerex Corp.Paciorp West Avista NF
27 Powerex Corp.PacifiCorp West Sierr Pacific Power NF
28 Powerex Corp.PaciCorp West PacifiCorp West NF
29 Powerex Corp.Idaho Power Company NorthWe~em/PacifiCorp East NF
30 Powerex Corp.Idaho Power Company PacifiCorp West NF
31 Powerex Corp.Idaho Power Company Bonnevile Power Administration NF
32 Powerex Corp.Idaho Power Company Avista NF
33 Powerex Corp.NorthWestern/PacifiCorp East Bonnevile Power Administration NF
34 Powerex Corp.Bonnevile Power Administration PacifiCorp East NF
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.5
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 2009/Q4
(2) OA Resubmission 04/1212010
! q!" ELI=(; i KI~II T ~" "' ".., ,.v,ll' ccunt 4~ti)((;Ontlnued)(Includinatransactions reffred to as 'wneelina')
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of biling demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and 0) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Biling TRANSFER OF ENERGY Line
Schedule of (Subsatation or Other (Substation or Other Demand MegaWatt Hours MegaWatt Hours No.
Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)(g)(h)(i)u)
5.00000 BPAT.NWMT LGBP 563 56 1
5.00000 BPAT.NWMT M345 100 10(2
5.00000 BRDY BPAT.NWMT 87 8 3
5.00000 BRDY ENPR 2,872 2,87 4
5.00000 BRDY IPCO 200 20(5
5.00000 BRDY LGBP 16,760 16,76(6
5.00000 BRDY LGBP 8,87E 8,87E 7
5.0000 BRDY LOLa 4 i 8
5.00000 BRDY M345 13 1.9
5.00000 BRDY M345 16,135 16,13!10
5.00000 ENPR BORA 2,342 2,34 11
5.00000 ENPR BRDY 72,729 72,721 12
5.00000 ENPR BRDY 49,763 49,76 13
5.00000 ENPR JBSN 37 3 14
5.0000 ENPR M345 6,911 6,911 15
5.00000 HTSP BRDY 1,254 1,25i 16
5.00000 HTSP BRDY 12,889 12,88~17
5.00000 HTSP M345 6,708 6,70f 18
5.00000 JBSN AVAT.NWMT 10 H 19
5.00000 JBSN BPAT.NWMT 248 24f 20
5.00000 JBSN BRDY 543 54~21
5.00000 JBSN ENPR 340 34l 22
5.00000 JBSN IPCO 800 80l 23
5.00000 JBSN JEFF 64 6'24
5.00000 JBSN LGBP 12,794 12,7~25
5.00000 JBSN LOLa 38 3f 26
5.00000 JBSN M345 18 H 27
5.00000 JBSN M500 17 1 28
5.00000 JBWT BPAT.NWMT 86 8E 29
5.00000 JBWT ENPR 313 31 30
5.00000 JBWT LGBP 6,94C 6,94(31
5.00000 JBWT LOLa 72 7.32
5.00000 JEFF LGBP 479 47!33
5.00000 LGBP BORA 5,675 5,67f 34
~4,134,363 4,134,36
FERC FORM NO.1 (ED. 12-90)Page 329.5
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Oriinal (Mo, Da, Yr)End of 2009/Q4
(2) ÕA Resubmission 04121010
t:Lt(; i ~I'"_II T '. ceunt 456.1)
(Includiìia transactons referred to as 'wheelinaf
1. Report all transmission of eledricity, i.e., wheeling, provided for other eledric utilities, 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 distind type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public autority 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 authori. Do not abbreviate or trncate name or use acronyms. Explain in a footnote
any ownership interest in or affliation the respondent has wit 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 ofthe 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 Servic, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Servce 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 Instructon for definitons of coes.
Line Payment By Energy Received From Energy Delivered To Statistical
No.(Company of Public Authority)(Company of Public Authority)(Company of Public Authorit)Classifi-
(Footnote Affliation)(Footnote Affliation)(Footnote Affliation)cation
(a)(b)(c)(d)
1 Powerex Corp.Bonneville Power Administtion PacifiCorp East NF
2 Powerex Corp.Bonneville Powr Administtin PaciCorp west NF
3 Powerex Corp.Bonneville Power Administrtion Sierra Pacific Power NF
4 Powerex Corp.Bonnevile Powr Adminisraion Sierra Pacifi Power NF
5 Powerex Corp.Avista PaciCorp East NF
6 Powerex Corp.Avist PaciCorp East NF
7 Powerex Corp.Avista Sierr Pacific Power NF
8 Powerex Corp.Sierra Pacic Power PacifiCorp East NF
9 Powerex Corp.Sierra Pacic Power NorthWestern/PacifiCorp East NF
10 Powerex Corp.Sierr Pacic Power PacifiCorp East NF
11 Powerex Corp.Sierra Paciic Power Bonnevile Power Administration NF
12 Powerex Corp.Sierr Paci Powr Avista NF
13 Powerex Corp.Paciorp East PaciCorp East NF
14 PPL EnergyPlus, LLC (EPLU)AD
15 PPL EnergyPlus. LLC (EPLU)PacifiCorp East Bonnevile Power Administration NF
16 PPL EnergyPlus, LLC (EPLU)PaciCorp East Bonnevile Power Administration SFP
17 PPL EnergyPlus, LLC (EPLU)NorthWestemlPacifiorp East Bonnevile Power Administration NF
18 PPL EnergyPlus. LLC (EPLU)PacifiCorp East PacifiCorp East NF
19 PPM Energy AD
20 PPM Energy PacifiCorp East Bonnevile Power Administration NF
21 PPM Energy PacifiCorp East Avista NF
22 PPM Energy NorthWesternlPacifiorp East Bonnevile Power Administration NF
23 PPM Energy Bonnevile Power Administration PacifCorp East NF
24 PPM Energy Bonnevile Power Administration Idaho Power Company NF
25 PPM Energy Sierr Paci Power Bonneville Power Administration NF
26 PPM Energy P,aciforp East PaciCorp East NF
27 Puget Sound Energy AD
28 Puget Sound Energy PaciCorp East Bonneville Power Administration NF
29 Puget Sound Energy PacifiCorp East Pacifiorp East NF
.30 Rainbow Energy Marketing Company AD
31 Rainbow Energy Marketing Company PacifiCorp East PacifiCorp East NF
32 Rainbow Energy Marketing Company PacifiCorp East Bonnevile Power Administration NF
33 Rainbow Energy Marketing Company PacifiCorp East Avista NF
34 Rainbow Energy Marketing Company PaciiCorp East Sierra Pacic Power NF
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.6
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 2009/Q4
(2) OA Resubmission 04/12/2010
v. ccount 456)(Contlnued)
(Including transactons raftred 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 specifed in the
contract.
7. Report in column (h) the number of megawatts of biling demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Biling TRANSFER OF ENERGY Une
Schedule of (Subsatation or Other (Substation or Other Demand MegaWatt Hours Megavvatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivere
(e)(f)(g)(h)(i)ü)
5.00000 LGBP BRDY 564 56-1
5.00000 LGBP JBSN 519 5H 2
5.00000 LGBP M345 985 98f 3
5.00000 LGBP M345 4,420 4,42(4
5.00000 LOLO BORA 430 43(5
5.00000 LOLO BRDY 228 22f 6
5.00000 LOLO M345 557 557 7
5.00000 M345 BORA 39 39 8
5.00000 M345 BPAT.NWMT 19 19 9
5.00000 M345 BRDY 1,293 1,29 10
5.00000 M345 LGBP 6,242 6,24.11
5.00000 M345 LOLO 114 11~12
5.00000 MLCK BRDY 4,780 4,78C 13
5.00000 14
5.00000 BRDY LGBP 3,930 3,93C 15
5.00000 BRDY LGBP 13,958 13,95f 16
5.00000 JEFF LGBP 4,276 4,27€17
5.00000 MLCK BRDY 3,255 3,25f 18
5.00000 19
5.00000 BORA LGBP 3,564 3,56i 20
5.00000 BORA LOLO 400 40(21
5.00000 JEFF LGBP 1,800 1,80(22
5.00000 LGBP BORA 686 68E 23
5.00000 LGBP IPCO 100 10Cl 24
5.00000 M345 LGBP 300 30C 25
5.00000 MLCK BRDY 1,220 1,22C 26
5.00000 f-27
5.00000 BRDY LGBP 7,588 7,58E 28
5.00000 MLCK BRDY ~1,320 1,32C1 29
5.00000 30
5.00000 BORA BRDY 400 400 31
5.00000 BORA LGBP 590 59C1 32
5.00000 BORA LOLO 3,780 3,78C 33
5.00000 BORA M345 6,529 6,529 34
0 4.134.363 4.134,36;i
FERC FORM NO.1 (ED. 12-90)Page 329.6
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 2009/Q4
(2) ñA Resubmission 04/121010
T l'YK U ccum456:1)
(Indudina transactns referr to as 'wheeling').
1. Report all transmission of electricity, i.e., wheeling, provided for other elecric utilities, cooperatives, other public autorities,
qualifying facilities, non-trditional utilty suppliers and ultimate customers for th 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 autri that paid for the trnsmission 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 authori. Do not abbreiate or trncate name or use acronyms. Explain in a footnote
any ownership interest in or affliation the respondent has wit the enties listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classifcation code based on the original contractual terms and conditions ofthe serice 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 serice, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any acunting 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 Recived From Energy Delivered To Statistical
No.(Company of Public Authority)(Company of Public Authori)(Company of Public Authority)Classifi-
(Footnote Affliation)(Footnote Affliation)(Footnote Affliation)cation
(a)(b)(c)(d)
1 Rainbow Energy Marketing Company PaciCorp East Sierra Paciic Power SFP
2 Rainbow Energy Marketing Company NortWestemlPacifiCorp East PacifiCorp East NF
3 Rainbow Energy Marketing Company NortWestemlPaciCorp East PacifiCorp East NF
4 Rainbow Energy Marketing Company NorthWestem/PaciCorp East Sierra Pacific Power NF
5 Rainbow Energy Marketing Company NorthWestem/Pacifiorp East Sierr Pacific Power SFP
6 Rainbow Energy Marketing Company PaciCorp East Bonnevile Power Administration NF
7 Rainbow Energy Marketing Company Paciorp East Avista NF
8 Rainbow Energy Marketing Company Paciorp East Avista SFP
9 Rainbow Energy Marketing Company Paciar East Sierra Pacic Power NF
10 Rainbow Energy Marketing Company Paciar East Sierra Pacific Power SFP
11 Rainbow Energy Marketing Company NorthWestemlPacifiorp East Bonnevile Power Administration NF
12 Rainbow Energy Marketing Company NorthWesternlPaciCorp East Avista NF
13 Rainbow Energy Marketing Company NortWestem/PacifiCorp East Sierra Pacic Power NF
14 Rainbow Energy Marketing Company Bonnevile Power Administration Sierra Pacific Power 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 Sierr Pacic Power Bonnevile Power Administration NF
18 Rainbow Energy Marketing Company PaciCorp East PacifCorp East NF
19 Seattle City Light AD
20 Seattle City Light NF
21 Sempra Energy AD
22 Sierra Pacific Power AD
23 Sierr Pacific Power PacifiCorp East Avista NF
24 Sierra Pacifi Power PacifiCorp East Sierra Pacific Power NF
25 Sierra Pacific Power PacifiCorp East Sierra Pacic Power SFP
26 Sierra Pacifc Power NortWestem/Pacifiorp East PacifiCorp East NF
27 Sierra Pacific Power PaciCorp East Sierra Pacif Power NF
28 Sierra Pacifi Power Paciorp East Sierra Pacific Power SFP
29 Sierra Pacific Power NorthWestem/PacifiCorp East PaciCorp East NF
30 Sierra Pacic Power PaciCorp West Sierra Pacifc Power NF
31 Sierra Pacifc Power NortWestern/PacifCorp East PacifiCorp East NF
32 Sierra Pacifc Power NorthWestem/PaciCorp East Sierra Pacific Power NF
33 Sierra Pacific Power Bonneville Power Administration Sierra Pacific Power NF
34 Sierra Pacific Power Avista Sierra Pacific Power NF
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.7
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 2009/Q4
(2) tiA Resubmission 04/12/2010
! qf ELEC-i KIl,l I Y . .(P ccunt 456)(Contínued)
(Including transactons reffred to as 'wlieeling')
5. In column (e). identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery loctions for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of biling demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and u) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billng TRANSFER OF ENERGY Line
Schedule of (Subsatation or Other (Substation or Other Demand MegaWatt Hours Me.!watt HOUrs No.
Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)(g)(h)(i)ü)
5.00000 BORA M345 1,296 1,296 1
5.00000 BPAT-NWMT BORA 240 240 2
5.00000 BPAT.NWMT BRDY 533 53.:3
5.00000 BPAT.NWMT M345 733 73 4
5.00000 BPAT.NWMT M345 275 27f 5
5.00000 BRDY LGBP 1,020 1,02C 6
5.00000 BRDY LOLO 400 400 7
5.0000 BRDY LOLO 1,051 1,051 8
5.00000 BRDY M345 1,024 1,02..9
5.00000 BRDY M345 456 45€10
5.00000 JEFF LGBP 1,000 1,OOC 11
5.00000 JEFF LOLO 1,200 1,20C 12
5.00000 JEFF M345 175 17f 13
5.00000 LGBP M345 345 34f 14
5.00000 LOLO M345 1,853 1,85 15
5.00000 LOLO M345 1,312 1,31:.16
5.00000 M345 LGBP 45 4f 17
5.00000 MLCK BRDY 4,451 4,451 18
5.00000 19
5.00000 20
5.00000 21
5.00000 22
5.00000 BORA LOLO 2 23
5.00000 BORA M345 2,624 2,62..24
5.00000 BORA M345 5,353 5,35.:25
5.00000 BPAT.NWT BRDY 1,105 1,10f 26
5.00000 BRDY M345 867 86 27
5.0000 BRDY M345 400 40(28
5.00000 HTSP BRDY 6,826 6,82€29
5.00000 JBSN M345 3,982 3,98..30
5.00000 JEFF BORA 90 9C 31
5.00000 JEFF M345 10,826 10,82E 32
5.00000 LGBP M345 53,969 53,96~33
5.00000 LOLO M345 7,628 7,62€34
0 4,134,363 4,134,36
FERC FORM NO.1 (ED. 12-90)Page 329.7
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 2009/Q4
(2)A Resubmission 04/121010
i:UK U.I Ht: K~l~~ccunt 40b.1)
(Includino transactons referred to as 'wheelin ')
1. Report all transmission of electricity, i.e., wheeling, provided for other elecric utilties, coperatives, other public authorities,
qualifying facilties, 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 authori 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 authorit that the energy was delivered to.
Provide the full name of each company or public autority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affliation the respondent has wit the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classifcation coe base 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 Serice, 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 accunting 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 Recived From Energy Delivered To Statistical
No.(Company of Public Authori)(Company of Public Autori)(Company of Public Authori)Classif
(Footnote Affliation)(Footnote Affliation)(Footnote Affliation)cation
(a)(b)(c)(d)
1 Sierra Pacifc Power Sierr Paci Powr PacifiCorp East NF
2 Sierra Pacific Power Sierr Paci Powr NortWestern/PacifiCorp East NF
3 Sierra Pacific Power Sierr Paci Powr Pacifiorp East NF
4 Sierra Pacifc Power Sierr Paci Power PaciCorp West
.NF
5 Sierra Pacific Power Sierra Paci Power NorthWestem/PaciCorp East NF
6 Sierra Pacific Power Sierr Paciic Power Bonnevile Power Administration NF
7 Sierr Pacific Power Sierr Pacic Power Avista NF
8 Sierra Pacific Power PaciiCorp East PacifiCorp East NF
9 Sierra Pacific Power Idaho Power Company Idaho Power Company NF
10 TransAlt Energy Marketing AD
11 TransAlta Energy Marketing Paciorp East Bonnevile Power Administration NF
12 TransAlta Energy Marketing NortWesm/Paciorp East Sierr Pacific Power NF
13 TransAlta Energy Marketing PaciCorp East Bonnevile Power Administration NF
14 TransAita Energy Marketing NortWestemlPaciCorp East PacifiCorp East NF
15 TransAlt Energy Marketing Bonnevile Power Administration Paciorp East NF
16 TransAlta Energy Marketing Bonnevile Power Administration PacifCorp East NF
17 TransAta Energy Marketing Bonnevile Power Administration Sierra Pacific Power NF
18 TransAlta Energy Marketing Sierr Pacifi Power Bonnevile Power Administration NF
19 UAMPS AD
20 UAMPS PacifiCorp East Sierra Pacific Power NF
21 WPSE Integrys Energy AD
22
23
24
25
26
27
28
29
30
31
32
33
34
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.8
Name of Respondent 1 his oo0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) OA Resubmission 04/12/2010
i I:U:(. i ~!.,n T 'Y' ccoun ontinued)
(Including transactions reftered to as 'wheelina')
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 identifcation 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 spefied 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.
FERCRate Point of Receipt Point of Delivery Biling TRANSFER OF ENERGY line
SCedule of (Subsatation or Other (Substation or Other Demand MegaWatt Hours MegaWatt Hours No.
Tari Number Designation)Designation)(MW)Received Delivere
(e)(f)(g)(h)(i)0)
5.00000 M345 BORA 325 321 1
5.00000 M345 BPAT.NWMT 75 7!2
5.00000 M345 BRDY 15 1E 3
5.00000 M345 JBSN 886 88E 4
5.0000 M345 JEFF 115 111 5
5.0000 M345 LGBP 15,478 15,471 6
5.00000 M345 LOLO 818 811 7
5.00000 MLCK BRDY 3,443 3,44 8
5.00000 OBBLPR IPCO 272 27,9
5.00000 10
5.00000 BORA LGBP 6,367 6,36 11
5.00000 BPAT.NWMT M345 80 81 12
5.00000 BRDY LGBP 111 111 13
5.00000 HTSP BRDY 175 17"14
5.00000 LGBP BORA 125 12f 15
5.00000 LGBP BRDY 21 21 16
5.00000 LGBP M345 561 561 17
5.00000 M345 LGBP 348 34~18
5.00000
...19
5.0~~BORA M345 345 341 20
5.00000 21
0.00000 22
0.00000 23
0.00000 24
0.00000 25
0.00000 26
0.00000 27
0.0000 28
0.00000 29
0.0000 30
0.00000 31
0.00000 32
0.00000 33
0.00000 34
0 4,134,363 4,134,36~
FERC FORM NO.1 (ED. 12-90)Page 329.8
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 2oo91Q4
(2) OA Resubmission 04121010
(Including transact~~; r~We~e' to as 'wfle~~')
onunueo)
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billng demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bils or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bils rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and 0) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respecvely.
11. Footnote entnes and provide explanations following all reuire data.
REVNUE FROM TRANSMISSION OF ELECTRICIT FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($),Line
($)($)($)(k+l+m)No.
(k)(I)(m)(n)
1,068,534 317,593 1,44,127 1
-900,632 -900,632 2
1,051,68C 145,585 1,197,265 3
-427,971 -427,971 4
462,447 -138,04 324,401 ,5
-457,526 -457,526 6
1,937,346 13,569 1,950,915 7
-1,815,612 -1,815,612 8
13,760 13,760 9
120,794 120,794 10
10,615 1,515 12,130 11
-5,017 -5,017 12
54,604 54,604 13
11,591 11,591 14
-5,256 -5,256 15
-3,645 -3,645 16
1,215 1,215 17
928 928 18
-4,897 -4,897 19
488 488 20
478 478 21
1,800 1,800 22
41,646 41,646 23
4,261 4,261 24
-1,684,723 -1,684,723 25
271 271 26
475 475 27
192 192 28
365 365 29
98 98 30
219 219 31
4,300 4,300 32
12,295 12,295 33
12,494 12,494 34
978,408 72,465 °1,050,873
FERC FORM NO.1 (ED. 12-90)Page 330
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 2009/04
(2) nA Resubmission 04/12/2010
lO.f t:Lt:l; i KI.i,11 y' FQR ~~ccount 456) (Continued)
(Including transactions reftred to as 'w eeling')
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 (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)I Line
($)($)($)(k+l+m)No.
(k)(I)(m)(n)
128 128 1
705 705 2
2,101 2,101 3
21,852 21,852 4
1,170 1,170 5
2,294 2,294 6
6,241 6,241 7
477 477 8
210 210 9
10
11
21 21 12
35,114 35,114 13
4,541 4,541 14
1,539 1,539 15
1,565 1,565 16
269 269 17
140 140 18
1,858 1,858 19
4,772 4,772 20
2,793 2,793 21
1,699 1,699 22
3,043 3,043 23
88 88 24
49 49 25
5,519 5,519 26
243 243 27
333 333 28
9,128 9,128 29
1,230 1,230 30
712 712 31
289 289 32
543 543 33
13,040 13,040 34
978,408 72,465 0 1,050,873
FERC FORM NO.1 (ED. 12-90)Page 330.1
Name of Respondent This i ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1)~An Original (Mo, Da, Yr)End of 2009/Q4
(2)A Resubmission 041121010
1 Ut T rldl' I. I. nCI'j: ,ii~ccunt 456) (Continued)
(Including transactons reftred to as 'w eeling')
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billng demand reported in column (h). In column (i), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bils or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bils rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and 0) must be reported as Transmission Received and Transmission Delivered for annual report
purses only on Page 401, Lines 16 and 17, respecvely.
11. Footnote entries and provide explanations following all required data.
REVNUE FROM TRNSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)(k+l+m)I No.
(k)(I)(m)(n)
14,504 14,504 1
8 8 2
5,637 5,637 3
158 158 4
35 35 5
18,293 18,293 6
158 158 7
43 43 8
214 214 9
18,209 18,209 10
102,313 102,313 11
25 25 12
1,870 1,870 13
22 22 14
14 14 15
7 7 16
1,457 1,457 17
8 8 18
27 27 19
8 8 20
-572 -572 21
3 3 22
-330 -330 23
-63,746 -63,746 24
319 319 25
-99,092 -99,092 26
6,042 6,042 27
1,373 1,373 28
22,701 22,701 29
2,413 2,413 30
8,22 8,222 31
2,146 2,146 32
3,071 3,071 33
119 119 34
978,408 72,465 0 1,050,873
FERC FORM NO.1 (ED. 12.90)Page 330.2
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) OA Resubmission 04/12/2010
FQR ~ I. Mt:K;:~f¡ ccount 456) (continued)
(Includina transactions reffred to as 'w eeting')
9. In column (k) through (n), report the revenue amounts as shown on bils or vouchers. In column (k), provide revenues from demand
charges related to the biling demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and 0) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)I Line
($)($)($)(k+l+m)No.
(k)(I)(m)(n)
23,516 23,516 1
1,469 1,469 2
715 715 3
4,149 4,149 4
.4 -4 5
2,403 2,403 6
10,730 10,730 7
5,167 5,167 8
64 646 9
.174 -174 10
646 646 11
-314,673 -314,673 12
27,747 27,747 13
2,703 2,703 14
75 75 15
396 396 16
82 82 17
729 729 18
613 613 19
116 116 20
2,144 2,144 21
-275 .275 22
74 74 23
-1,538,539 -1,538,539 24
814,222 814,222 25
715 715 26
2,074 2,074 27
215 215 28
17,851 17,851 29
16,492 16,492 30
15,169 15,169 31
4,247 4,247 32
9,759 9,759 33
6,254 6,254 34
978,408 72,465 0 1,050,873
FERC FORM NO.1 (ED. 12-90)Page 330.3
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2oo9/Q4
(2) OA Resubmission 041212010
~L~l, I n.i~ii T i-gK "- i~~ccoun ontinued)
(Including transactions reftred to as 'w eeling')
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the biling demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bils or vouchers rendered, including
out of period adjustments. Explain in a footnote all components ofthe amount shown in column (m). Report in column (n) the total
charge shown on bils rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary setement, induding the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and 0) must be reported as Transmission Recived and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respeely.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRNSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)(k+l+m)No.
(k)(I)(m)(n)
11,020 11,020 1
107,393 107,393 2
19,224 19,224 3
282 282 4
224 224 5
6,496 6,496 6
63,317 63,317 7
258,057 258,057 8
64,34 64,34 9
988 988 10
6,147 6,147 11
11,950 11,950 12
-50,419 -50,419 13
2,426,321 2,426,321 14
4,332 4,332 15
1,229 1,229 16
13,586 13,586 17
-26,303 -26,303 18
283 283 19
112 112 20
13,005 13,005 21
796 796 22
4,156 4,156 23
-2,112,297 -2,112,297 24
2,971 2,971 25
2,982 2,982 26
10,022 10,022 27
312,137 312,137 28
13,343 13,343 29
8,381 8,381 30
316 316 31
32
2,025 2,025 33
24,073 24,073 34
978,408 72,465 0 1,050,873
FERC FORM NO.1 (ED. 12-90)Page 330.4
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2)OA Resubmission 04112/2010
! u.i: ii y i-YK '" ~~ CCUQt 456) (Continued)(IncludinQ transactons reffred to as 'w eeling')
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 u) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respecively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRNSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)(k+l+m)No.
(k)(I)(m)(n)
2,096 2,096 1
372 372 2
324 324 3
10,692 10,692 4
745 745 5
62,398 62,398 6
33,045 33,045 7
15 15 8
48 48 9
60,071 60,071 10
8,719 8,719 11
270,771 270,771 12
185,268 185,268 13
138 138 14
25,730 25,730 15
4,669 4,669 16
47,986 47,986 17
24,974 24,974 18
37 37 19
923 923 20
2,022 2,022 21
1,266 1,266 22
2,978 2,978 23
238 238 24
47,632 47,632 25
141 141 26
67 67 27
63 63 28
320 320 29
1,165 1,165 30
25,838 25,838 31
268 268 32
1,783 1,783 33
21,128 21,128 34
978,408 72,465 0 1,050,873
FERC FORM NO.1 (ED. 12-90)Page 330.5
Name of Respondent ThiS~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1 )An Original (Mo, Da, Yr)End of 2oo9/Q4
(2)A Resubmission 04/1212010
(Including transacton:leW~~ ~~'~;.:;lí~q.
onUnUed)
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billng demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bils or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount show in column (m). Report in column (n) the total
charge shown on bils rendered to the entity Listed in column (a). If no monetary setlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settement, incuding the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and 0) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respecively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRNSMISSION OF ELECTRICIT FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)(k+l+m)No.
(k)(I)(m)(n)
2,100 2,100 1
1,932 1,932 2
3,667 3,667 3
16,456 16,456 4
1,601 1,601 5
849 849 6
2,074 2,074 7
.145 145 8
71 71 9
4,814 4,814 10
23,239 23,239 11
424 424 12
17,796 17,796 13
-41,560 -41,560 14
6,810 6,810 15
24,186 24,186 16
7,409 7,409 17
5,640 5,640 18
-24,164 -24,164 19
8,420 8,420 20
945 945 21
4,252 4,252 22
1,621 1,621 23
236 236 24
709 709 25
2,882 2,882 26
-45,239 -45,239 27
16,775 16,775 28
2,918 2,918 29
-198,037 -198,037 30
752 752 31
1,109 1,109 32
7,108 7,108 33
12,277 12,277 34
978,408 72,465 0 1,050,873
FERC FORM NO.1 (ED. 12-90)Page 330.6
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 2oo9/Q4
(2) ¡=A Resubmission 04/1212010
i .O.f ELECI KI.I,II y' FQR v i ri~n"'v~~CCOuQt 4~O) (Continued)
(Including transactons reftred to as 'w eeling')
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 frm all other charges on bils or vouchers rendered, including
out of penod 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 setlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entnes and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)! Une
($)($)($)(k+l+m)No.
(k)(i)(m)(n)
2,437 2,437 1
451 451 2
1,002 1,002 3
1,378 1,378 4
517 517 5
1,918 1,918 6
752 752 7
1,976 1,976 8
1,925 1,925 9
857 857 10
1,880 1,880 11
2,256 2,256 12
329 329 13
649 649 14
3,484 3,484 15
2,467 2,467 16
85 85 17
8,369 8,369 18
-530,280 -530,280 19
1,445,795 1,445,795 20
-307,246 -307,246 21
-1,537,074 -1,537,074 22
5 5 23
6,328 6,328 24
12,908 12,908 25
2,665 2,665 26
2,091 2,091 27
965 965 28
16,460 16,460 29
9,602 9,602 30
217 217 31
26,106 26,106 32
130,142 130,142 33
18,394 18,394 34
978,408 72,465 0 1,050,873
FERC FORM NO.1 (ED. 12-90)Page 330.7
Name of Respondent ThiS~rIS:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) A Resubmission 04/121010
i Y FflW "....!- ccu".t 40ö)(l,ontlnued)
(Includinatransactons raftred to as 'wheelinai)
9. In column (k) through (n), report the revenue amounts as shown on bils or vouchers. In column (k), provide revenues from demand
charges related to the billng demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bils or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bils rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectvely.
11. Footnote entries and provide explanations followng all reuire dat.
REVENUE FROM TRNSMISSION OF ELECTRICIT FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)(k+l+m)No.
(k)(I)(m)(n)
784 784 1
181 181 2
36 36 3
2,137 2,137 4
277 277 5
37,322 37,322 6
1,973 1,973 7
8,303 8,303 8
656 656 9
-308 -308 10
19,513 19,513 11
245 245 12
340 340 13
536 536 14
383 383 15
64 64 16
1,719 1,719 17
1,067 1,067 18
-6,266 -6,266 19
1,085 1,085 20
-237 -237 21
22
23
24
25
26
27
28
29
30
31
32
33
34
978,408 72,465 0 1,050,873
FERC FORM NO.1 (ED. 12-90)Page 330.8
This Page Intentionally Left Blank
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/1212010 2009/Q4
FOOTNOTE DATA
¡Schedule Page: 328 Line No.: 1 Column: e
5, Open Access Transmission Tariff, Volume 5, first revision
I$chedule Page: 328 Line No.: 1 Column: h
The network service agreement between Idaho Power and the Bonneville Power Administration
for the Oregon Trail Electric Cooperative expires September 30, 2011. The billing demand
for network service is the customer' s demand at the time of Idaho Power Company
transmission system peak and varies by month.
¡Schedule Page: 328 Line No.: 2 Column: h
Tariff rate refund per FERC Docket ER06-787 Final Order
¡Schedule Page: 328 Line No.: 3 Column: h
The network service agreement between Idaho Power and the Bonneville Power Administration
for the USBR expires December 31, 2014. The billing demand for network service is the
customer' s demand at the time of Idaho Power Company transmission system peak and varies
by month.
ISchedule Page: 328 Line No.: 4 Column: h
Tariff rate refund per FERC Docket ER06-787 Final Order
¡Schedule Page: 328 Line No.: 5 Column: h
The network service agreement between Idaho Power and the Bonneville Power Administration
for Raft River expires September 30, 2011. The billing demand for network service is the
customer' s demand at the time of Idaho Power Company transmission system peak and varies
by month.
¡Schedule Page: 328 Line No.: 6 Column: h
Tariff rate refund per FERC Docket ER06-787 Final Order
ISchedule Page: 328 Line No.: 7 Column: h
The network service agreement between Idaho Power and the Bonneville Power Administration
for the Priority Firm Customers expires December 31, 2011. The billing demand for network
service is the customer' s demand at the time of Idaho Power Company transmission system
peak and varies by month.
!Schedule Page: 328 Line No.: 8 Column: h
Tariff rate refund per FERC Docket ER06-787 Final Order
¡Schedule Page: 328 Line No.: 9 Column: e
Legacy, contract prior to the Open Access Transmission Tariff
¡Schedule Page: 328 Line No.: 9 Column: h
The contract between Idaho Power and the Milner Irrigation District expires December 31,
2012.¡Schedule Page: 328 Line No.: 10 Column: h I
The agreement between Idaho Power and the City of Seattle expires December 31, 2017. City
of Seattle has sold this transmission service request to Cargill and Cargill is now
responsible for payment.
¡Schedule Page: 328 Line No.: 11 Column: h
The contract between Idaho Power and PacifiCorp
¡sedule Page: 328 Line No.: 12 -Column: h
Tariff rate refund per FERC Docket ER06-787 Final Order
¡Schedule Page: 328 Line No.: 13 Column: e
Legacy, contract prior to the Open Access Transmission Tariff
¡Schedule Page: 328 Line No.: 13 Column: h
The agreement between Idaho Power and the United
of Indian Affairs is subject to termination upon
¡Schedule Page: 328 Line No.: 14 Column: e
Legacy, contract prior to the Open Access Transmission Tariff
¡Schedule Page: 328 Line No.: 14 . Column: h
The contract between Idaho Power and PacifiCorp is for the life of Bridger project per
1992 Restated Transmission Service Agreement (RTSA) FERC filing 3/9/92.
I$chedule Page: 328 Line No.: 15 Column: e
Legacy, contract prior to the Open Access Transmission Tariff-
- Imnaha expires on September 30,
=:2010.
I
I
I
States Department of the Interior, Bureau
90 days written notice by the Bureau.
i
m:J
~J
IIFERC FORM NO.1 (ED. 12-87) Page 450.1
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2) A Resubmission 04112/2010 2009/Q4
FOOTNOTE DATA
I
I
I
I
I
I
I
I
I
I
I
i
I
I
I
I
I
I
_J~
I
I
I~
¡Schedule Page: 32B' Line No.: 15 Column: h
Tariff rate refund per FERC Docket ER06-787 Final Order
¡Schedule Page: 328 Line No.: 16 Column: h
Tariff rate refund per FERC Docket ER06-787 Final Order
¡Schedule Page: 328 Line No.: 19 Column: h
Tariff rate refund per FERC Docket ER06-787 Final Order
¡Schedule Page: 328 Line No.: 25 Column: h
Tariff rate refund per FERC Docket ER06-787 Final Order
¡Schedule Page: 328.2 Line No.: 21 Column: h
Tariff rate refund per FERC Docket ER06-787 Final Order
¡Schedule Page: 328.2 Line No.: 23 Column: h
Tariff rate refund per FERC Docket ER06-787 Final Order
¡Schedule Page: 328.2 Line No.: 24 Column: h
Tariff rate refund per FERC Docket ER06-787 Final Order
¡Schedule Page: 328.2 Line No.: 26 Column:h
Tariff rate refund per FERC Docket ER06-787 Final Order
¡Schedule Page: 328.3 Line No.: 5 Column: h
Tariff rate refund per FERC Docket ER06-787 Final Order
¡Schedule Page: 328.3 Line No.: 10 Column: hTariff rate refund per FERC Docket ER06-787 Final Order
¡Schedule Page: 328.3 Line No.: 12 Column: hTariff rate refund per FERC Docket ER06-787 Final Order
¡Schedule Page: 328.3 Line No.: 22 Column: h
Tariff rate refund per FERC Docket ER06-787 Final Order
¡Schedule Page: 328.3 Line No.: 24 Column: h
Tariff rate refund per FERC Docket ER06-787 Final Order
¡Schedule Page: 328.4 Line No.: 18 Column: h
Tariff rate refund per FERC Docket ER06-787 Final Order
¡Schedule Page: 328.4 Line No.: 24 Column: h
Tariff rate refund per FERC Docket ER06-787 Final Order
¡Schedule Page: 328.6 Line No.: 19 Column: h
Tariff rate refund per FERC Docket ER06-787 Final Order
¡Schedule Page: 328.6 Line No.: 27 Column: h
Tariff rate refund per FERC Docket ER06-787 Final Order
¡Schedule Page: 328.6 Line No.: 30 Column: h
Tariff rate refund per FERC Docket ER06-787 Final Order
¡Schedule Page: 328.7 Line No.: 19 Column: h
Tariff rate refund per FERC Docket ER06-787 Final Order
¡Schedule Page: 328.7 Line No.: 21 Column: h
Tariff rate refund per FERC Docket ER06-787 Final Order
¡Schedule Page: 328.7 Line No.: 22 Column: h
Tariff rate refund per FERC Docket ER06-787 Final Order
¡Schedule Page: 328.8 Line No.: 10 Column: hTariff rate refund per FERC Docket ER06-787 Final Order
¡Schedule Page: 328.8 Line No.: 19 Column: h
Tariff rate refund per FERC Docket ER06-787 Final Order
¡Scheduie Page: 328.8 Line No.: 21 Column: h
Tariff rate refund per FERC Docket ER06-787 Final Order
IFERC FORM NO.1 (ED. 12-87) Page 450.2
Name of Respondent This (lort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2009/04
(2) l'A Resubmission 04121010
TRANS~ ISSION OF ELECTRICIT BY OTHE S (Accunt 565)
(Including transactions referrd to as "wheeling")
1. Report all transmission, i.e. wheeling or electricity provided by other elecric utilities, coperatives, municipalites, 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 necssary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification coe 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 Reserations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General Instrctions 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 sho on bils or vouchers redered to the respondent. In column (e) report the
demand charges and in column (f) energy charges related to the amount of energy trnsferred. On column (g) report the total of all
other charges on bills or vouchers rendered to the respondent, induding 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 settement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement,
induding the amount and type of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entres and provide explanations following all required data.
Une TRANSFER OF ENERG't EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHER
No.Name of Company or Public Statistical ~agawatt-Magawatl-lJemano ~nergy JJèr Total Cost of
R=ed tiours chaWes Chawes Chawes Trans~ssionAuthority (Footnote Affliations)Classification Delivere ($($($
(a)(b)(c)(d)(e)(f)(0)
1 Avista Corp AD -51,700 -51,700
2 Avita Corp NF 88,20 88,209 375,44 375,448
3 Avista Corp as -22,376
4 Avista Corp SFP 303,095 303,095 1,290,345 1,290,345
5 Bonneville Power Admin n,409,88 40,886 1,195,428 1,195,428
6 Bonneville Power Admin 53,856 53,856
7 Bonnevile Power Admin 5,703 5,703 25.373 25,373
8 Bonneville Power Admin -85,496 85,496 17,706 172,706
9 Noreste Energy 36,17 36,171 49,933 27,937 77,870
10 NortWesem Energy 115 115 149,700 149,700
11 NortWeste Energy NF 4,707 4,707 25,486 25,486
12 NorWesem Energ as ,-137,354
13 NortWeste Energy SFP 72,250 72,250 777,327 777,327
14 PacfiCorp Inc.151,875 151,875
15 Pacifiorp Inc.125 125 607,500 607,500
16 Pacorp Inc.NF 46,893 46,893 156,935 156,935
TOTAL 1,265,40 1,265,401 1,44,917 5,462,429 -282,651 6,628,695
FERC FORM NO. 1/3-0 (REV. 02-0)Page 332
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2009/04
(2) FiA Resubmission 04/12/2010
TRANSfI ISS ION OF ELECTRICITY BY OTHE S. (Accunt 565)
(Including transactions referred to as "wheeling")
1. Report all transmission, i.e. wheeling or electricity provided by other elecric utilities, cooperatives, municipalities, other public
authorities, qualifying facilties, and others for the quarter.
2. In coumn (a) report each company or public authonty 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 authonties that provided
. transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification coe based on the onginal contractual terms and conditions ofthe 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 as - 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), (1) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the
demand charges and in column (1) 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 penod 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 ''TOT AL" 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-Magawau-~mana ~nergy JJtner Total Cost of
tiours tiours Chawes Char¡ies Char¡ies TranS~isionAutority (Footnote Affliations)Classification Received Delivered ($($($
(a)(b)(c)(d)(e)(f)g)
1 PacifiCor Inc.as -66,394
2 PacfiCorp Inc.as 516
3 PacifiCorp Inc.as -664
4 Pacilior Inc.SFP 8,150 8,150 1,012,646 1,012.646
5 PaTu Wind Farm. L1c SFP 12,967 12,967 85,881 85,881
6 Portand General Ele Co SFP 90,17 90,17 487,013 487.013
7 Powx Corp.as 198'06~-62,743
8 Seatte City Light SFP 78,223 78,223 198,069
9 Sier Pacific Power Co NF 12,939 12,939 103,490 103,490
10 Sierr Pacific Power Co as 10,267
11 Siera Pacific Power Co as -3,903
12 Snohomish County PUD SFP 10.295 10,295 16,098 16,098
13
14
15
16
TOTAL 1,265,401 1,265,401 1,448,917 5,462,429 -282,651 6,628,695
FERC FORM NO. 1/3-Q (REV. 02-0)Page 332.1
This Page intentionally Left Blank
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 0411212010 2009/Q4
FOOTNOTE DATA
¡Schedule Page: 332 Line No.: 3 Column: g
Resale Transmission
¡Schedule Page: 332 Line No.: 5 Column: b
Contract Expires 09/30/2016
¡Schedule Page: 332 Line No.: 6 Column: b
Contract Expires 07/16/2011
¡Schedule Page: 332 Line No.: 9 Column: bContract can be terminated at anytime, with 30 days prior notice.
!schedule Page: 332 Line No.: 10 Column: b
Contract Expires 03/31/2014
!Schedule Page: 332 Line No.: 12 Column: g
Resale Transmission
¡Schedule Page: 332 Line No.: 14 Column: b
Contract Expires 06/01/2009
¡Schedule Page: 332 Line No.: 15 Column: b
Contract Expires 05/31/2014
¡Schedule Page: 332.1 Line No.: 1 Column: g
Resale Transmission
'§chedule Page: 332.1 Line No.: 2 Column: g
Study Expense
ISchedule Page: 332.1 Line No.: 3 Column: g
Unreserved Use Refund - Sharing Re-distributed 2008
¡Schedule Page: 332.1 Line No.: 7 Column: g
Resale Transmission
ISchedule Page: 332.1 Line No.: 10 Column: g
Study Expense
¡SChedule Page: 332.1 Line No.: 11 Column: gFERC Rate Refund
IFERC FORM NO.1 (ED. 12-87) Page 450.1
Name of Respondent This ~ort Is:Date QfRep.ort Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2oo9/Q4
(2) n A Resubmission 04121010
MISCELLANEOUS GENERAL EXPENSES (Accunt 930.2) (ELECTRIC)
Line Descriltion Amount
No.(a (b)
1 Industry Association Dues 356,915
2 Nuclear Power Research Expenses
3 Other Experimental and General Research Expenses
4 Pub & Dist Info to Stkhldrs.. .expn servicing outstanding Securities 277,399
5 Oth Expn =-=5,000 show purpose, recipient, amount. Group if c $5,00
6 Richard Dahl 66,279
7 Christine King 62,095
8 Jon Miler 101,325
9 Gary Michael 63,835
10 Richard Reiten 46,624
11 Joan Smith 62,640
12 Jan Packwood 43,612
13 Judith Johansen 62,638
14 Peter O'Neil 27,200
15 Thomas Wilford 52,800
16 Robert Tintsman 64,800
17 Stephen Allred 37,283
18
19 Chambers of Commerce & Other Civic Organizations 94,186
20
21 Associated Taxpayers of Idaho 21,252
22 Corporate Executie Board 72,869
23 Eastern Oregon Visitor Association 1,500
24 Idaho Association of Counties 1,650
25 Idaho Association of Commerce & Industry 10,000
26 Idaho Economic Development Assocition 1,500
27 Misc Memberships 33,248
28 National Assoc of Corp 6,050
29 Northwest Power Pool 73,623
30 Pacific NW Utilties 35,810
31 Western Electcity Coordinating Council 827,380
32 Wyoming Taxpayers Assoc 1,500
33
34 Misc General Management:
35 New York Stock Exchange 7,154
36 PRNewswire 14,691
37
38
39
40
41
42
43
44
45
46 TOTAL 3,561,160
FERC FORM NO.1 (ED. 12-94)Page 335
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) õ An Original (Mo, Da, Yr)
Idaho Power Company I (2) A Resubmission 0411212010 2oo9/Q4
FOOTNOTE DATA
¡Schedule Page: 335 Line No.: 5Recipient
Other Purchased Services
Bank of New York
Deutsche Bank AmortE Source IncGlobal Insight
J P Morgan Securities
Jet Clearing
Moody' s Analytics
Port of Morrow
Thomson/ Fincancial
Union Bank, N .A.
Wells Fargo
Stock Based Compensation
Misc entries/other services
Total
Column: b
Purpose
Mise
Port of Morrow-PC
Broker Fees
Membership
Data Subscription
Amer Falls-Port Morrow
Travel Expense
Analyst Service
Bond Expense
Analyst Service
PC Bond Expense
Transfer & Fees
Stock Expense
Mise
Amount
$ 14,3146,360
35,000
21,280
25,934
20,592
26,040
26,500
5,475
88,354
11,360
126,717
511,379
113,997
$1,033,302
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)End of 2oo9/Q4
(2) EiA Resubmission 04/121010
DEPRECIATION AND AMORTIZATION OF ELECTRIC PlANT (Accunt 403,404,4 5)
(Excet amortization of aquisiton adjustmnts)
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 (Accunt 404); and (e) Amortization of Other Electric
Plant (ACCunt 405).
2. Report in Section 8 the rates used to compute amortization charges for electc 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 Secion C every fih year beinning with report year 1971, reporting annually only changes
to columns (c) through (g) from the complete report of the preceing year.
Unless composite depreciation accunting for total depreciable plant is followed, list numercally in column (a) each plant subaccount,
accunt or functional classification, as appropriate, to which a rate is applied. Identif at the bottom of Secion 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 informaton for each plant subaccunt, accunt or functional classification Listed in column
(a). If plant mortality studies are prepared to assist in estimating average service Lives, show in column (l) the type mortality curve
seleced 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 Depreation and Amrttin Charges
Dereciatin Amorttin of
Une De~ation Exnse for Ast Limit Term Amortization of
No.Functonal Classification nse Retrent Costs Electric Plant Other Electric Total
(Accunt 403)(Accunt 403.1)(Accunt 404)Plant (Acc 405)
(a)(b)(c)(d)(e)(f)
1 Intangible Plant 7,061,06 7,061,068
2 Steam Production Plant 18,050,233 18,050,233
3 Nuclar Production Plant
4 Hydraulic Production Plant-Conventional 15,129,051 15,129,051
5 Hydraulic Production Plant-Pumped Storage
6 Other Production Plant 4,976,615 4,976,615
1 Transmission Plant 15,547,600 15,547,600
8 Distribution Plant 37,232,823 37,232,823
9 Regional Transmission and Market Operation
10 General Plant 12,947,424 12,947,424
11 Common Plant-Electc -296,299 -296,299
12 TOTAL 103,587,447 7,061,068 110,648,515
B. Basis for Amortization Charges
Accunt 404
Balance to be 2009 Balance to be Remaining months of
Amortized Amortization amorted 12/31/09 amortizion 1211/09
(1)48,000 12,000 36,000 36
(2)12,324,719 488,214 11,743,090 -
(3)18,182,596 6,272,786 18,391,530 -
(4)5,475,561 288,067 5,187,493 216
TOTAL 36,030,876 7,061,068 35,358,113
(1) Shoshone-Bannock Tribe license and use agreement (termination date December 31,2023).
(2) Middle snake relicensing costs (amortized over a 30-year license period).
(3) Computer softare packages (amortized over a 60 month period from date of purchase).
(4) Shoshone-Bannock Right of Way (termination date December 31, 2028).
FERC FORM NO.1 (REV. 12.(3)Page 336
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) FiA Resubmission 04/12/2010
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreciaoie i:stimatelf Net Applfea Monaiit l'verage
No.Account No. Plant Base Avg. Service Salvage Depr. rates Curve Remaining
(a)(In Th~~~andS)~~l (per~nt)(per:nt)Trr ~~~
12 310.00 203 75.0C 1.58 R4.0 21.80
13 311.00 138,632 100.00 -10.00 1.52 S1.0 23.30
14 312.10 80,391 60.0C -7.00 1.60 R3.0 22.60
15 312.20 451,391 70.00 -5.00 2.15 R1.5 22.30
16 312.30 4,208 25.00 20.00 2.53 R3.0 12.20
17 314.00 134,759 50.00 -5.00 2.54 SO.5 20.30
18 315.00 62,010 65.00 -7.00 5.47 S1.5 22.20
19 316.00 12,846 50.00 -5.00 6.14 RO.5 20.80
20 316.10 59 10.00 25.00 9.52 L2.5 7.60
21 316.40 248 10.0C 25.00 4.71 L2.5
22 316.50 8:1 10.00 25.00 5.06 L2.5 8.20
23 316.60 106 19.00 25.00 0.35 S2.0 12.00
24 316.70 80 19.00 25.00 3.88 S2.0 16.70
25 316.80 1,76~16.00 30.00 11.75 SO.O 9.30
26 317.000 3,586
27 Subtotal Steam 890,370
28 331.00 153,562 100.00 -25.00 2.70 R2.5 32.10
29 332.10 19,461 90.00 -20.00 2.27 S4.0 27.20
30 332.20 225,304 90.00 -20.00 2.21 S4.0 29.80
31 332.30 5,472 2.87 SQUARE 28.0
32 333.00 192,732 80.00 -5.00 1.90 R3.0 33.00
33 334.00 42,753 50.00 -5.00 2.95 R1.5 25.30
34 335.00 16,799 90.00 2.10 R2.0 30.50
35 335.10 48 15.00 1.93 SQUARE 12.30
36 335.20 393 20.00 3.56 SQUARE 10.70
37 335.30 720 5.00 12.62 SQUARE 2.00
38 336.00 7,493 75.00 1.91 R3.0 30.40
39 Subtotal Hydro 664,737
40 341.00 7,170 35.00 3.47 SQUARE 30.40
41 342.00 4,446 35.00 3.05 SQUARE 32.40
42 343.00 92,651 35.00 3.02 SQUARE 29.70
43 34.00 39,093 35.00 2.93 SQUARE 33.80
44 345.00 24,899 35.00 2.57 SQUARE 28.30
45 346.00 3,054 35.00 3.03 SQUARE 29.50
46 Subtotal Other 171,313
47 350.20 26,919 65.00 1.51 R3.0 54.20
48 352.00 43,095 60.00 -30.00 1.68 R3.0 47.30
49 353.00 304,1~45.00 -5.00 2.06 R1.0 35.40
50 354.00 139,305 65.00 -25.00 1.96 S3.0 48.60
FERC FORM NO.1 (REV. 12-03)Page 337
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2oo9/Q4
(2) DA Resubmission 041212010
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Use in Estimating Depreation Charges
Line uepreciaoie i:stimaæa Net .AJplle MOrtalI Average
No.Accunt No.Plant Base Avg. Service Salvage DeFlr. rate Curve Remaining
(In Th~~fandS)7:(pe~nt)( et:nt)Tr8e 7~~(a)(d .
12 355.00 95,22 55. DC -60.00 2.81 R2.0 36.70
13 356.00 155,113 65.DC -30.00 1.92 R1.5 48.30
14 359.00 318 65.0C 0.98 R3.0 23.80
15 Subtotl Transmission 764,129
16 361.00 27,551 65.00 -30.00 1.85 R2.5 52.60
17 362.00 181,364 50.0C -5.00 1.89 RO.5 42.10
18 364.00 217,05 44.00 -50.00 3.29 R1.5 31.50
19 365.00 121,12S 47.00 -40.0C 2.95 RO.5 35.10
20 366.00 48,29S 60.00 -20.00 1.95 R2.0 51.20
21 367.00 186,97.i 50.00 -15.00 1.97 SO.5 41.10
22 368.00 401,aa 37.00 5.00 1.67 R1.0 30.80
23 369.00 56,507 35.00 -4.00 3.09 R2.5 25.6C
24 370.00 13,38S 20.00 6.95 01.0 11.90
25 370.10 22,481 15.00 6.76 S3.0 14.40
26 370.20 2,06 2.00 19.38 Square 0.50
27 370.30 41,10S 3.00 25.67 Square 2.50
28 371.10 56 10.00 -5.00 3.68 S4.0 1.40
29 371.20 2,60C 15.00 -5.00 0.63 R2.0 13.90
30 373.00 4,24l 25.00 -25.00 4.09 R1.5 13.90
31 374.00 232
32 Subtotal Distribution 1,326,945
33 390.11 26,50 100.00 -5.00 2.38 S1.5 33.60
34 390.12 40,201 50.00 -5.00 2.24 L2.0 36.30
35 390.20 9,945 30.00 2.58 S3.0 20.80
36 391.10 14,254 20.00 4.97 SQUARE 10.30
37 391.20 21,416 5.00 24.37 SQUARE 2.10
38 391.21 5,156 7.00 13.96 L4.0 3.90
39 392.10 411 10.00 25.00 6.23 L2.5 5.90
40 392.30 2,58C 8.00 50.00 8.62 S2.5 4.30
41 392.40 19,19.10.00 25.00 3.58 L2.5 7.30
42 392.50 614 10.00 25.00 1.49 L2.5 8.60
43 392.60 28,191 19.00 25.00 3.69 S2.0 12.00
44 392.70 3,934 19.00 25.00 2.39 S2.0 11.90
45 392.90 4,003 30.00 25.00 1.99 S1.5 21.1C
46 393.00 1,331 25.00 5.40 SQUARE 9.70
47 394.00 5,250 20.0C 4.84 SQUARE 11.70
48 395.00 11,551 20.0C 5.39 SQUARE 10.20
49 396.00 9,241 16.0C 30.00 6.95 SO.O 7.00
50397.10 6,32C 15.00 6.16 SQUARE 7.70
FERC FORM NO.1 (REV. 12-03)Page 337.1
Name of Respondent This i!0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) DA Resubmission 04/12/2010
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreciaoie i:stimatea Net Appiiea MortalitY Average
No.Accunt No. Plant Base Avg. Service Salvage D~r. rates Curve Remaining
ta\(In Th~~~ands)~~(per:nt)( er;rnt)Ty~~~
12 397.20 15,702 15.00 6.99 SQUARE 9.60
13 397.30 3,271 15.00 8.36 SQUARE 6.60
14 397.40 2,101 10.00 8.20 SQUARE 5.60
15 398.00 4,225 15.00 9.57 SQUARE 6.90
16 Subtotal General 235,399
17 Total Plant 4,052,893
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
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 2009/Q4
(2) FiA Resubmission 04/121010
Ro:GULATORY COMMISSION EXPEN ES
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 year's expenses that are not deferred and the current year's amorization of amounts
deferrd in previous years.
Line Descrption Assessed by Expenses Total . uererred.
No.(Furnish name of regulatory commission or body the Regulatory of Expense for in Accunt
Commission Current Year .18;2.3 ai
docket or case nurrr and a description ofthe case)Utilty (b) + (c)Beginning 0 Year
(a)(b)(c)(d)(e)
1 Federal Energy Regulatory Commission:
2 Annual admin charges assesse by FERC 3,115,73f 3,115,738
3
4 General Regulatory Expenses and
5 Various other Dockets 1,498,991 1,498,991
6
7 Regulatory Commission Expenses - Idaho
8 Rate Case - Misc expenses 35,798 35,798
9
10 Oter-IPUC
11 Amortation - rate related 25,757 25,757
12 Intevenor Funding 40,000 40,000
13 Other 14,628 14,628
14
15 Oregon Hydro - Fees Amortization 158,5OE 158,506
16
17 Regulatory Commission Expenses - Oregon
18 Rate Case - Misc expenses 21,162 21,162
19
20 Other-OPUC
21 AR- 538 29,Os-29,054
22 UM -1401 44,688 44,688
23 UE - 213 82,18C 82,180
24 UM -1394 27,521 27,521
25 UM-1355 22,638 22,63S
26 UM -1395 15,863 15,863
27 UM-1396 16,606 16,60€
28 Other mattrs less than $15,000 149,678 149,678
29
30
31
32
33
34
35
36
37
38
39
40
41 .
42
43
44
45
46 TOTAL 3,274,244 2,024,564 5,298,80S
FERC FORM NO.1 (ED. 12-96)Page 350
Name of Respondent
Idaho Power Company
This ~ort Is: Date of Report
(1) ~An Original (Mo, Os, Yr)
(2) A Resubmission 04/12/2010
REG LATORY COMMISSION EXPENSE (Continued)
3. Show in column (k) any expenses incurred in prior years which are being amortized. List in column (a) the period of amortization.
4. List in column (t), (g), and (h) expenses incurred during year which were charged currently to income, plant, or other accunts.
5. Minor items (less than $25,000) may be grouped.
Year/Period of Report
End of 2oo9/Q4
EXPENSES INCURRED DURING YEAR
CURRENTLY CHARGED TO
epartment
(f)
AMORTIZED DURING YEAR
o.
(g)ü)(k)
Deferred in
Accunt 182.3
End of Year
(I)
Line
No.
(h)
Deferred to
Accunt 182.3
(i)
Contra
Accunt Amountmoun
Electric 928 21,162
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
Electric 928 3,115,738
Electric 928 1,498,991
Electric 928 35,798
Electric 928
Electric 928
Electric 928
Elecric 928
25,757
40,00
14,628
158,506
Electric
Electic
Electric
Electric
Electric
Electric
Electric
Electric
928
928
928
928
928
928
928
928
29,054
44,688
82,180
27,521
22,638
15,863
16,606
149,678
5,298,808 46-- -- ~~-- ----
FERC FORM NO.1 (ED. 12-96)Page 351
This Page Intentionally Left Blan
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) CiA Resubmission 04/12/2010
RESEARCH, DEVELOPMENT, AND DEMONS RATION ACTIVITIES
1. Describe and show below costs incurred and accounts charged during the year for technological research, development, and demonstration (R, D &
D) project initiated, continued or concluded during the year. Report also support given to others during the year for jointly-sponsored projects.(ldentify
recipient regardless of 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 Accounts).
2. Indicate in column (a) the applicble classification, as shown below:
Classifications:
A. Electric R, D & D Perfrm Internally:a. Overhead
(1) Generation b. Underground
a. hydroelectric (3) Distribution
i. Receation fish and wildlife (4) Regional Transmission and Market Operation
ii Other hydroelectric (5) Environment (other than equipment)
b. Fossil-fuel steam (6) Other (Classif and include items in excess of $50,000.)
c.Intemal combustion or gas turbine (7) Total Cost Incurred
d.Nuclear B. Electric, R, D & D Performd Exrnally:
e. Unconventional generation (1) Research Support to the electrical Research Council or the Electric
f. Siting and heat rejection Pawer Research Institme
(2) Transmission
Line Classification Description
No.(a)(b)
1 No R&D cost to report for 2009
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
FERC FORM NO.1 (ED. 12-87)Page 352
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2009/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/1212010
DISTRIBUTION OF SALARIES AND IOGES
Report below the distribution of total salaries and wages. for the year. Segregate amounts originally charged to clearing accunts to
Utilty Departments, Construdion, Plant Removals, and Other Accnt, and enter such amounts in the appropriate lines and columns
provided. In determining this segregation of salaries and wages originally charged to dearing accunts, a method of approximation
giving substantially correc results may be used.
1 Electric
2 Operation
3 Production
4 Transmission
5 Regional Market
6 Distribution
7 Customer Accunts
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 oflines 3 and 13)
21 Transmission (Enter Total of lines 4 and 14)
22 Regional Market (Enter Total of Lines 5 and 15)
23 Distribution (Enter Total of lines 6 and 16)
24 Customer Accounts (Transcribe from line 7)
25 Customer Service and Informational (Transcribe from line 8)
26 Sales (Transcribe from line 9)
27 Administrative and General (Enter Total of lines 10 and 17)
28 TOTAL Oper. and Maint. (Total of lines 20 thru 27)
29 Gas
30 Operation
31 Production-Manufactured Gas
32 Production-Nat. Gas (Including Expl. and Dev.)
33 Other Gas Supply
34 Storage, LNG Terminaling and Processing
35 Transmission
36 Distribution
37 Customer Accounts
38 Customer Service and Informational
39 Sales
40 Administrative and General
41 TOTAL Operation (Enter Total of lines 31 thru 40)
42 Maintenance
43 Production-Manufactured Gas
44 Production-Natural Gas (Including Exploration and Development)
45 Other Gas Supply
46 Storage, LNG Terminaling and Processing
47 Transmission
(a)
Direct PayrollDistribution
(b)
TotalLine
No.
Classifcation
FERC FORM NO.1 (ED. 12-88)Page 354
Name of Respondent
Idaho Power Company
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/12/2010
DIST IBUTION OF SALARIES AND WAGES (Continued)
Year/Period of Report
End of 2009/Q4
48 Distribution
49 Administrative and General
50 TOTAL Maint. (Enter Total of lines 43 thru 49)
51 Total Operation and Maintenance
52 Production-Manufactured Gas (Enter Total of lines 31 and 43)
53 Production-Natural Gas (Including Expl. and Dev.) (Total lines 32,
54 Other Gas Supply (Enter Total of lines 33 and 45)
55 Storage, LNG Terminaling and Processing (Total of lines 31 thru
56 Transmission (Lines 35 and 47)
57 Distribution (Lines 36 and 48)
58 Customer Accunts (Line 37)
59 Customer Service and Informational (Line 38)
60 Sales (Line 39)
61 Administrative and General (Lines 40 and 49)
62 TOTAl Operation and Maint. (Total of lines 52 thru 61)
63 Other Utilty Departents
64 Operation and Maintenance
65 TOTAL All Utilty Dept. (Total of lines 28, 62, and 64)
66 Utilit Plant
67 Constructon (By Utility Departments)
68 Electric Plant
69 Gas Plant
70 Other (provide details in footnote):
71 TOTAL Construction (Total of lines 68 thru 70)
72 Plant Removal (By Utilty Departments)
73 Electric Plant
74 Gas Plant
75 Other (provide details in footnote):
76 TOTAL Plant Removal (Total of lines 73 thru 75)
77 Other Accounts (Specify, provide details in footnote):
78 Stores Expense - Clearing
79 Other Clearing accounts
80 Other Work in Progress
81 Paid Absences
82 Preliminary Survey and Investigation
83 Other Accounts
84
85
86
87
88
89
90
91
92
93
94
95 TOTAL Other Accounts
96 TOTAL SALARIES AND WAGES
Classification Direct PayrollDistrbution(a) (b)TotalLine
No.
-- - - ~- - - -- -- ---- -- -~- ---- -- --
I
i
110,407,574 110,407,574
44,206,030 44,206,030
1- -- - ----~-~~- - -- -~------~- -- -~~ -- --- --- -
44,206,030 44,206,030
4,381,594
2,676,835
2,040,581
18,902,009
338,985
4,103,370
4,381,594
2,676,835
2,040,581
18,902,009
338,985
4,103,370
32,443,374
187,056,978
32,443,374
187,056,978
FERC FORM NO.1 (ED. 12-88)Page 355
Name of Respondent
Idaho Power Company
T is ~ort Is: Date of Report
(1) !!An Oriinal (Mo, Da, Yr)
(2) A Resubmission 041121010
M NTHL Y TRASMISSION SYSTEM P LOAD
(1) Report the monthly peak load on the respondents transmission system. If the respondent has two or more power systems whic are not physically
integrated, furnish the required information for each non-integrated system.
(2) Report on Column (b) by month the transmission system's peak load.
(3) Report on Columns (c ) and (d) the specid information for each monthly transmision - system peak load reported on Column (b).
(4) Report on Columns (e) through 0) by month the system' monthly maximum megawatt load by statistical classifcations. See General Instruction for
the definition of each statistical classification.
Year/Period of Report
End of 2009/04
NAME OF SYSTEM: Idaho Power Company
Line
No.
Monthly Peak
MW-Total
Ot
SericDay of Hour of Finn Ne Firm Netw Long-Ter Finn
Monthly Mothly seic fo Se Seicfo Poit-toint
Peak Peak Ot Resrvat
(c)(d)(f)(g)
2
Month
(a)
1 Januar
2 Feb
3 Mar
Tota fo Quar 1
(b)
7 June
8 Tota for Quarr 2
9 July
10 Auust
11 Setem
12 Tota for Quart 3
13 October
14 Novemb
15 Dember
16 Tota for Quarr 4
17 Total Year to
DateIear 63,391 47,294 2,717 10,528 2,852
Oter Long-
TennFinn
Seriæ
(h)
Short-Ter Finn
Point-to-poinl
Resrvation
(i)0)
178
30
550
1,028
1,358
223
35
1,616
20
47
67
141
141
FERC FORM NO. 1/3-0 (NEW. 07-()Page 400
Name of Respondent
Idaho Power Company
Date of Report
(Mo, Da, Yr)
04/12/2010
Year/Period of Report
End of 2009/Q4
This ~ort Is:(1) ~An Original
(2) A Resubmission
ELECTRIC ENERGY ACCOU T
Report below the information called for concerning the disposition of electric energy generated, purchased, exchanged and wheele during the year.
line
No.
Item
(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 (Weeling)
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 Line
No.
Item MegaWatt Hours
13,948,280
55,078
2,780,950
1,274,302
18,058,610
FERC FORM NO.1 (ED. 12-90)Page 401a
(a)
21 DISPOSITION OF ENERGY
22 Sales to Ultimate Consumers (Including
Interdepartental Sales)
23 Requirements Sales for Resale (See
instruction 4, page 311.)
24 Non-Requirements Sales for Resale (See
instruction 4, page 311.)
25 Energy Furnished Without Charge
26 Energy Used by the Company (Electric
Dept Only, Excluding Station Use)
27 Total Energy Losses
28 TOTAL (Enter Total of Lines 22 Through
27) (MUST EQUAL LINE 20)
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Oriinal (Mo, Da, Yr)End of 2009/Q4
(2) DA Resubmission 04/1212010
MONTHLY PEAKS AND OUTPI T
1. Report the monthly peak load and energy output. If the resndent has two or more power whic are not physically integrated, fumish the reuired
information for each non- integrated system.
2. Report in column (b) by month the system's output in Megawatt hours for each month.
3. Report in column (c) by month the non-requirements sales for resale. Include in the monthly amounts any energy loses associated with the sales.
4. Report in column (d) by month the system's monthly maximum megawatt load (60 minute integration) associated with the system.
5. Report in coiumn (e) and (f) the specid information for each monthly peak load reported in column (d).
NAME OF SYSTEM:Idaho Power Company
Line Monthly Non-Requirmnts MONTHLY PEAKSales for Resale &
No.Month Total Monthly Energy Asciated Losss Meawatt (See Instr. 4)Day of Month Hour
(a)(b)(c)(d)(e)(f)
29 January 1,487,973 167,686 2,311 27 8AM
30 February 1,252,297 113,475 2,160 2 8AM
31 March 1,430,14E 281,495 2,131 11 8AM
32 April 1,506,56E 445,362 1,904 1 8AM
33 May 1,613,93E 315,876 2,606 29 5PM
34 June 1,520,541 319,884 2,760 29 7PM
35 July 2,054,163 355,263 3,031 22 8PM
36 August 1,662,052 118,163 2,987 3 6PM
37 September 1,542,21E 248,669 2,698 3 6PM
38 October 1,348,727 274,622 1,870 29 8AM
39 November 1,229,002 106,561 1,969 30 8AM
40 December 1,410,992 33,894 2,528 10 8AM
41 TOTAL 18,058,610 2,780,950
FERC FORM NO.1 (ED. 12-90)Page 401b
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2S An Original (Mo, Da, Yr)
Idaho Power Company 1(2) .A Resubmission 04/12/2010 2009/Q4
FOOTNOTE DATA
\Schedule Page: 401 Line No.: 16 Column: b
Lucky Peak variation, (1, l09)mwh, is the difference between energy generated and
scheduled. The 747 mwh, is deviation received from Northwestern to true up the Salmon area
load directly related to the control area. The net of these variations is (387) mwh.
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)2009/Q4
(2) OA Resubmission 04112/2010 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 capaci (name plate rating) of 25,000 Kw or more. Report in
this page gas-turbine and intemal combustion plants of 10,000 Kw or more, and nuclear plants.3. Indicate by a footnote any plant leased or operate
as a joint facilty.4. If net peak demand for 60 minutes is not available, giv data which is available, specifying period.5. If any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant.6. If gas is used and purchased on a
therm basis report the Btu content or the gas and the quantit of fuel bumed converted to Md.7. Quantities of fuel burned (Line 38) and average cost
per unit of fuel burned (Une 41) must be consistent wit charges to expense accunts 501 and 547 (Line 42) as show on Line 20.8. If more than one
fuel is bumed in a plant furnish only the composite heat rate for all fuels bumed.
Une Item Plant Plant
No.Name: Jim Brdger Name: Boardman
(a)(b)(c)
1 Kind of Plant (Internal Comb, Gas Turb, Nuclear Steam Steam
2 Type of Constr (Conventional, Outdoor, Boiler, etc)
3 Year Originally Constructed
4 Year Last Unit was Installed 1~9 1~0
5 Total Installed Cap (Max Gen Name Plate Ratings-MW)~- , .
6 Net Peak Demand on Plant - MW (60 minutes)707 60
7 Plant Hours Conneded to Load 8760 5694
8 Net Continuous Plant Capability (Megawatt)0 0
9 When Not Limited by Condenser Water l~~i:..
10 When Limited by Condenser Water 0 0
11 Average Number of Employees 0 0
12 Net Generation, Exdusive of Plant Use - KW 4982609000 317400000
13 Cot of Plant: Land and Land Rights 494358 106610
14 Strudures and Improvements 66127904 13781170
15 Equipment Costs 424323763 57221112
16 Aset Retirement Costs 0 0
17 Total Cost 490946025 71108892
18 Cost per KW of Installed Capacity (line 17/5) Including 637.1785 1107.6151
19 Production Expenses: Oper, Supv, & Engr 155995 88420
20 Fuel 87007677 5437088
21 Coolants and Water (Nudear Plants Only)0 0
22 Steam Expenses 4279803 0
23 Steam From Other Sources 0 0
24 Steam Transferred (Cr)0 0
25 Electric Expenses 2568382 0
26 Misc Steam (or Nuclear) Power Expenses 5922253 175428
27 Rents 452069 0
28 Allowances 0 0
29 Maintenance Supervision and Engineering 23060 2048845
30 Maintenance of Structures 487528 0
31 Maintenance of Boiler (or reactor) Plant 8300804 0
32 Maintenance of Electric Plant 254818 0
33 Maintenance of Misc Steam (or Nudear) Plant 4467997 7273
34 Total Production Expenses 116210386 8553254
35 Expenses per Net KW 0.0233 0.0269
36 Fuel: Kind (Coal, Gas, Oil, or Nudear)Coal Oil Coal Oil
37 Unit (Coal-tonslOil-barrel/Gas-mcf/Nuclear-indicate)Tons Barrls Tons Barrls
38 Quantity (Units) of Fuel Burned 2736257 10488 0 185621 577 0
39 Avg Heat Cont - Fuel Bumed (btu/indicate if nuclear)9225 140000 0 8338 138800 0
40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 30.355 91.165 0.000 29.013 85.574 0.000
41 Average Cost of Fuel per Unit Bumed 31.458 71.526 0.000 28.808 130.429 0.000
42 Average Cost of Fuel Burned per Millon BTU 1.666 12.164 0.000 1.707 22.371 0.000
43 Average Cost of Fuel Burned per KW Net Gen 0.017 0.000 0.000 0.017 0.000 0.000
44 Average BTU per KW Net Generation 10384.000 0.000 0.000 9882.000 0.000 0.000
FERC FORM NO.1 (REV. 12-03)Page 402
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)2oo9/Q4
(2) DA Resubmission 04/12/2010 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large PlantsHContinued)
9. Items under Cost of Plant are based on U. S. of A. Accunts. Production expenses do not include Purchase Power, System Control and Load
Dispatching, and Other Expenses Classifd as Other Power Supply Expenses.10. For IC and GT plants, report Operating Expenses, Account Nos.
547 and 549 on Line 25 "Electic Expenses," and Maintenance Accunt Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants
designed for peak load servic. Designate automatically operated plants.11. For a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined
cycle operation with a conventional steam unit, include the gas-turbine with the steam plant.12. If a nuclear power generating plant, briefly explain by
footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units
used for the various coponents of fuel cost; and (c) any other informative data conceming plant type fuel used, fuel enrichment type and quantity for the
report period and other physical and operating characteristics of plant.
Plant Plant Plant Line
Name: Valmy Name:Danskin Name:Bennett Mountain No.
(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
268 256 193 6
8550 822 637 7
0 261427 164159 8
0 0 9
0 0 0 10
0 8 4 11
1640799000 143846000 98506000 12
769351 402745 0 13
58723124 5699334 1458303 14
266404738 103765418 59489356 15
0 0 0 16
325897213 109867497 60947659 17
1149.5493 418.1367 352.7064 18
774252 147459 33183 19
37789767 .11689400 7634101 20
0 0 0 21
3154907 0 0 22
0 .0 0 23
0 0 0 24
0 175858 225686 25
2013880 114256 53858 26
62662 0 0 27
0 0 0 28
486 0 0 29
0 91192 97880 30
5375088 46501 467476 31
1050484 1439384 196820 32
163811 0 0 33
50385337 13704050 8709004 34
0.0307 0.0953 0.0884 35
Coal Oil Gas Gas 36
Tons Barrels MCF MCF 37
831165 8889 0 1458073 0 0 1026258 0 0 38
9551 138778 0 1038 0 0 1038 0 0 39
42.702 83.246 0.000 8.017 0.000 0.000 7.439 0.000 0.000 40
44.506 85.708 0.000 8.017 0.000 0.000 7.439 0.000 0.000 41
2.330 14.704 0.00 7.724 0.000 0.000 7.166 0.000 0.000 42
0.023 0.000 0.000 0.081 0.000 0.000 0.077 0.000 0.000 43
9708.000 0.000 0.000 10522.000 0.00 0.000 10814.000 0.000 0.000 44
FERC FORM NO.1 (REV. 12-G3)Page 403
This Page r~tentionally Left Blan
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2) A Resubmission 04/12/2010 2009/Q4
FOOTNOTE DATA
¡Schedule Page: 402 Line No.: 3 Column: b
This footnote applies to lines 3 and 4. The Jim Bridger Power
Plant consists of four equal units constructed jointly by Idaho
Power Company and Pacific Power and Light Company, with Idaho
owning 1/3 and PacifiCorp owning 2/3. Unit #1 was placed in
commercial operation November 30, 1974, Unit #2 December 1, 1975,
Unit #3 September 1, 1976, and Unit #4 November 29, 1979.
¡Schedule Page: 402 Line No.: 3 Column: c
This footnote applies to lines 3 and 4. The Boardman plant
consists of one unit constructed jointly by Portland General
Electric Company, Idaho Power Company, and Pacific Northwest
Generating Company, with Idaho Power Company owning 10%. The
unit was placed in commercial operation August 3, 1980.
I$chedule Page: 402 Line No.: 3 Column: d
This footnote applies to lines 3 and 4. The Valmy plant consists
of two units constructed jointly by Sierra Pacific Power Company
and Idaho Power Company, with Sierra owning 1/2 and Idaho owning
1/2. Unit #1 was placed in commercial operation December 11, 1981
and Unit #2 May 21, 1985.
I$chedule Page: 402 Line No.: 5 Column: b
This footnote applies to line 5 and lines 12 through 43.
Information reflects Idaho Power Company's share as explained
in note for line 3 page 402 column B.
¡Schedule Page: 402 Line No.: 5 Column: c
This footnote applies to line 5 and lines 12 through 43.
Information reflects Idaho Power Company's share as explained
in note on line 3 page 402 column C
¡Schedule Page: 402 Line No.: 5 Column: d
This footnote applies to line 5 and lines 12 through 43.
Information reflects Idaho Power Company's share as explained
in note for line 3 page 403 column D.
¡Schedule Page: 402 Line No.: 9 Column: b
This footnote applies to lines 9, 10, and 11. PacifiCorpas operator of the plant will report thisinformation.
¡Schedule Page: 402 Line No.: 9 Column: cThis footnote applies to lines 9, 10, and 11. Portland General
Electric Company, as operator will report this information.
¡Schedule Page: 402 Line No.: 9 Column: d
This footnote applies to lines 9, 10, and 11. Sierra Pacific
Power, as operator of the plant, will report this information.
IFERC FORM NO.1 (ED. 12-87) Page 450.1
Name of Respondent This 'ì0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)2oo9/Q4
(2) DA Resubmission 041212010 End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1.Large plants are hydro plants of 10,000 Kw or more of installed capacit (name plate ratings)
2. If any plant is leased, operate under a license from the Federal Energy Regulatory Commission, or operated as a joint facilit, indicate such facts in
a footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Line Item FERC Licnse Project No.2736 FERC License Project No.1975
No.Plant Name: Amrican Falls Plant Name: Bliss
(a)(b)(c)\,
1 Kind of Plant (Run-of-River or Storage);'¡¡;ji,-"Run-of-River
2 Plant Construction type (Conventional or Outdoor)Outdoor Outdoor
3 Year Originally Constructed 1978 1949
4 Year Last Unit was Installed 1978 1950
5 Total installed cap (Gen name plate Rating in MW)92.30 75.00
6 Net Peak Demand on Plant-Megawatt (60 minutes)110 75
7 Plant Hours Connect to Load 6,879 8,753
8 Net Plant Capability (in megawatt)
9 (a) Under Most Favorable Oper Conditions 110 76
10 (b) Under the Most Adverse Oper Conditions °1
11 Average Number of Employees 4 5
12 Net Generation, Exclusive of Plant Use - Kwh 384,852,000 388,207,000
13 Cost of Plant
14 Land and Land Rights 875,318 769,797
15 Structures and Improvements 11,807,207 1,039,638
16 Reservoirs, Dams, and Waterways 4,293,075 8,186,692
17 Equipment Costs 31,481,326 7,288,400
18 Roads, Railroads, and Bridges 839,276 486,477
19 Asset Retirement Costs 0 0
20 TOTAL cost (Total of 14 thru 19)49,296,202 17,771,004
21 Cost per KW of Installed Capacit (line 20 / 5)534.0867 236.9467
22 Producton Expenses
23 Operation Supervision and Engineering 168,363 758,464
24 Water for Power 2,104,980 527,878
25 Hydraulic Expenses 88,898 420,705
26 Electc Expenses 45,290 73,740
27 Misc Hydraulic Power Generation Expenses 174,652 239,40
28 Rents 557 27,249
29 Maintenance Supervision and Engineering 139,653 87,961
30 Maintenance of Structures 118,114 76,730
31 Maintenance of Reservoirs, Dams, and Waterways 4,749 149,103
32 Maintenance of Electric Plant 437,787 75,255
33 Maintenance of Misc Hydraulic Plant 115,648 130,517
34 Total Production Expenses (total 23 thru 33)3,398,691 2,567,011
35 Expenses per net KWh 0.0088 0.0066
FERC FORM NO.1 (REV. 12-03)Page 406
Name of Respondent
,Idaho Power Company
Year/Period of Report
End of 2009/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) DA Resubmission 04/12/2010
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accunts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classifid as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC licensed Project No. 1971
Plant Name: Brownlee
(d)
FERC licensed Project No. 2848
Plant Name: Cascade
(e)
FERC licensed Project No. 1971
Plant Name: Oxbow
line
No.
Storage
Outdoor
1958
1980
585.40
696
8,760
Outdoor
1983
1984
12.42
14
8,756
Outdoor
1961
1961
190.00
217
8,760
18,091,132 82,142 1,210,187
31,298,485 7,364,154 9,956,831
67,102,724 3,145,630 30,375,714
53,630,712 12,727,675 15,814,661
518,444 122,668 565,842
0 0 0
170,641,497 23,442,269 57,923,235
291.4956 1,887.4613 304.8591
480,568 177,740 335,866
327,736 161,64 214,203
517,233 232,718 348,576
272,919 112,053 209,466
373,96 165,335 276,721
128,678 187 20,641
460,814 70,929 223,250
177,890 20,160 280,504
229,043 36 58,511
457,725 144,877 139,111
625,739 105,980 349,132
4,052,309 1,191,661 2,455,981
0.0017 0.0266 0.0023
FERC FORM NO.1 (REV. 12-03)Page 407
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Oriinal (Mo, Da, Yr)2009/Q4
(2) DA Resubmission 04/1212010 End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1.Large plants are hydro plants of 10,000 Kw or more of installed capaci (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operate as a joint facilit, indicate such facts in
a footnote. If licensed projec, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available speciing period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.,
Line Item FERC Licnsed Project No.1971 FERC Licensed Project No.2726
No.Plant Name: Hells Canyon Plant Name: Malad
(a)(b)(c)
1 Kind of Plant (Run-of-River or Storage)
2 Plant Construction type (Conventional or Outdoor)Outdoor Outdoor
3 Year Originally Constructed 1967 1948
4 Year Last Unit was Installed 1967 194
5 Total installed cap (Gen name plate Rating in MW)391.50 21.77
6 Net Peak Demand on Plant-Megawatt (60 minutes)44 24
7 Plant Hours Connect to Load 8,760 8,756
8 Net Plant Capabilty (in megawatt)
9 (a) Under Most Favorable Oper Conditions 445 25
10 (b) Under the Most Adverse Oper Conditions 137 21
11 Average Number of Employees 5 1
12 Net Generation, Exclusive of Plant Use - Kwh 2,051,347,000 165,602,000
13 Cost of Plant
14 Land and Land Rights 1,877,301 205,376
15 Structures and Improvements 2,413,190 2,764,626
16 Reservoirs, Dams, and Waterways 52,700,383 6,199,398
17 Equipment Costs 15,859,881 4,061,764
18 Roads, Railroads, and Bridges 819,192 304,683
19 Asset Retirement Costs 0 0
20 TOTAL cost (Total of 14 thru 19)73,669,947 13,535,847
21 Cost per KW of Installed Capacity (line 20 / 5)188.1736 ,621.7661
22 Production Expenses
23 Operation Supervision and Engineering 323,089 120,977
24 Water for Power 205,939 603,117
25 Hydraulic Expenses 337,561 113,049
26 Electric Expenses 215,688 58,757
27 Misc Hydraulic Power Generation Expenses 210,942 57,329
28 Rents 34,259 0
29 Maintenance Supervision and Engineering 291,498 54,188
30 Maintenance of Structures 171,922 16,572
31 Maintenance of Reservoirs, Dams, and Waterways 24,105 18,409
32 Maintenance of Electric Plant 277,322 97,900
33 Maintenance of Misc Hydraulic Plant 564,637 102,547
34 Total Production Expenses (total 23 thru 33)2,656,962 1,242,845
35 Expenses per net KWh 0.0013 0.0075
FERe FORM NO.1 (REV. 12-03)Page 406.1
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2009/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) OA Resubmission 04/12/2010
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No. 2055
Plant Name: C J Strike
d)
FERC Licensed Project No. 503
Plant Name: Swan Falls
(e)
FERC Licensed Project No.
Plant Name: Twin Falls
18 Line
No.
Run-of-River
Outdoor
1952
1952
82.80
90
8,758
Run-of-River
Conventional
1910
1994
25.00
23
8,759
Run-of-River
Conventional
1935
1995
52.74
52
8,754
5,454,163 51,675 255,499
7,909,959 25,307,621 10,808,047
10,232,293 13,856,887 7,908,870
9,751,252 30,376,852 20,614,035
248,183 835,946 1,917,603
0 0 0
33,595,850 70,428,981 41,50,054
405.7470 2,817.1592 786.9559
983,130 253,219 266,807
665,048 150,601 166,079
1,055,732 155,009 162,824
34,487 26,628 54,803
325,250 98,488 136,349
108,342 29,589 8,349
188,828 96,041 42,759
104,820 69,368 47,335
403,990 35,809 18,903
226,778 87,764 100,964
191,468 296,958 64,086
4,287,873 1,299,474 1,069,258
0.0089 0.0099 0.0062
FERC FORM NO.1 (REV. 12-03)Page 407.1
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)2009104
(2) DA Resubmission 0411212010 End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1.Large plants are hydro plants of 10,000 Kw or more of installed capacit (name plate ratings)
2. If any plant is lease, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facilit, indicate such facts in
a footnote. If licensed project, give projec number.
3. If net peak demand for 60 minutes is not available, give that which is available spciing period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Line Item FERC Licensed Projec No.2777 FERC Licensed Project No.2778
No.Plant Name: Upper Salmon Plant Name: Shoshone Falls
(a)(b)(c)
1 Kind of Plant (Run-of-River or Storage)Run-of-River Run-of-River
2 Plant Construction type (Conventional or Outdoor)Outdoor Conventional
3 Year Originally Constructed 1937 1907
4 Year Last Unit was Installed 1947 1921
5 Total installed cap (Gen name plate Rating in MW 34.50 12.50
6 Net Peak Demand on Plant-Megawatt (60 minutes)36 14
7 Plant Hours Connect to Load 8,760 8,539
8 Net Plant Capabilit (in megawatt)
9 (a) Under Most Favorable Oper Conditions 39 14
10 (b) Under the Most Adverse Oper Conditions 32 11
11 Average Number of Employees 4 2
12 Net Generation, Exclusive of Plant Use - Kwh 227,484,000 99,792,000
13 Cost of Plant
14 Land and Land Rights 202,399 313,328
15 Structures and Improvements 1,980,763 1,199,248
16 Reservoirs, Dams, and Waterways 5,557,358 512,402
17 Equipment Costs 7,828,260 4,508,878
18 Roads, Railroads, and Bridges 29,359 51,383
19 Ast Retirement Costs 0 0
20 TOTAL cost (Total of 14 thru 19)15,598,139 6,585,239
21 Cost per KW of Installed Capacity (line 20 1 5)452.1200 526.8191
22 Production Expenses
23 Operation Supervision and Engineering 395,908 213,795
24 Water for Power 209,100 142,055
25 Hydraulic Expenses 292,805 173,276
26 Elecric Expenses 27,619 36,899
27 Misc Hydraulic Power Generation Expenses 182,360 109,811
28 Rents 0 221
29 Maintenance Supervision and Engineering 120,230 69,528
30 Maintenance of Structures 82,44 55,416
31 Maintenance of Reservoirs, Dams, and Waterways 91,613 70,621
32 Maintenance of Electric Plant 311,365 90,602
33 Maintenance of Misc Hydraulic Plant 137,115 70,54
34 Total Production Expenses (total 23 thru 33)1,850,561 1,032,768
35 Expenses per net KW 0.0081 0.0103
FERC FORM NO.1 (REV. 12-03)Page 406.2
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2009/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) DA Resubmission 04/12/2010
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No. 1971
Plant Name: Common Facilites
(d)
FERC Licensed Project No. 2061
Plant Name: Lower Salmon
(e
FERC Licensed Projec No. 2899
Plant Name: Milner
Line
No.
0.00
o
o
Run-of-River
Outdoor
1949
1949
60.00
66
8,757
Run-of-River
Conventional
1992
1992
59.45
58
7,391
114,367 424,428 138,100
26,063,697 2,803,043 10,340,105
13,556,785 6,759,825 17,147,050
1,216,470 7,908,285 27,652,163
99,051 88,693 501,877
0 0 0
41,050,370 17,984,274 55,779,295
0.0000 299.7379 938.2556
0 603,698 161,010
0 275,397 1,420,497
5,791,746 262,596 80,084
0 156,375 57,307
0 188,316 128,233
0 9,759 9,019
0 135,281 69,612
0 101,342 39,584
0 16,003 8,443
0 313,112 140,716
0 98,467 54,781
5,791,746 2,160,346 2,169,286
0.0000 0.0081 0.0133
FERC FORM NO.1 (REV. 12-03)Page 407.2
This Page Intentionally Left Blank
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company I è2) A Resubmission 0411212010 20091Q4
FOOTNOTE DATA
\Schedule Page: 406 Line No.: 1 Column: b
American Falls generating capacity is dependent upon water releases controlled by the
Uni ted States Bureau of Reclamation.
\Schedule Page: 406 Line No.: 1 Column: e
Cascade generating capacity is dependent upon water releases controlled by the United
States Bureau of Reclamation.
\Schedule Page: 406 Line No.: 1 Column: f
Upstream storage in Brownlee Reservoir.
¡Schedule Page: 406.1 Line No.: 1 Column: b
upstream storage in Brownlee Reservoir
\Schedule Page: 406.1 Line No.: 1 Column: c
Lower Malad maximum demand 15, 000 Kw, Upper Malad maximum demand 9, 000 Kw non-coincident.
IFERC FORM NO.1 (ED. 12-87) Page 450.1
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 2009/Q4
(2)A Resubmission 04/1212010
G NERATING PLANT STATISTICS (Small Plants)
1. Small generating plants are steam plants of, less than 25,000 Kw; intemal combustion and gas turbineplants, conventional hydro plants and pumped
storage plants of less than 10,000 Kw installed capacity (name plate rating).2. Designate any plant lease from others, operated under a license from
the Federal Energy Regulatory Commission, or operated as a joint facilit, and give a concie statement of the fact in a footnote. If licensed project,
give project number in footnote.
Line
Year Linstalll! (,a~~~~etPeak Net Generation
Name of Plant Ori.Name Plate ati Demand Excluding Cost of Plant
No.Const.(InMW (6~Gn.)Plant Use
(a)(b)(c)(e)(f)
1 Hydro:
2 Clear Lakes 1937 2.50 2.2 16,326 1,756,730
3 Thousand Springs 1912 8.80 6.3 51,957 4,995,833
4
5
6 Internal Combustion:
7 Salmon Diesel (1)1967 5.00 4.2 41 901,055
8
9
10
11 (1) Salmon units are classified as standby.
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO.1 (REV. 12-Ð3)Page 410
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 2009/Q4
(2) nA Resubmission 04/12/2010
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, speciing 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 ProCluetlon -epenses Fuel Costs (in cents Line
Retire. Costs) Per MW Exc'l. Fuel Fuel Maintenance Kind of Fuel (per Millon Btu)
(g)(h)(i)(j)(k)(i)
No.
1
702,692 108,936 86,373 2
567,708 60,624 98,543 3
4
5
6
180,211 Diesel 7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO.1 (REV. 12-03)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 2oo91Q4
(2) flA Resubmission 04/1212010
TRANSMISSION LINE STATIST CS
1. Report information conceming transmission lines, cost of Iiries, 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 Accunts.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 comission.
4. Exclude from this page any transmission lines for which plant cots are included in Accunt 121, Nonutilit Propert.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one ty of supportng strcture, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a trnsmission line of a difrent type of construction need not be distinguished from the
remainder ofthe line.
6. Report in columns (f) and (g) the total pole miles of each transmision 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 stctures the cost of which is reported for another line. Report
pole miles of line on leased or party owned structures in column (g). In a fotnote, explain the basis of such occupancy and state whether expenses wit
respect to such structures are included in the expenses reportd for the line designated.
Line (Indicate wöere Type of LE~GJi~ ~~ie .wiieS)Numbe
No.òtherthan u~~ergrounlf lines Of60 cvcle 3 Dhase\Supporting report circuit miles)
From To
un ~trUcture I U~f'i~th~res CircuitOperatingDesignedStrctureofLin~o 00 er
Desi(la ed ine
(a)(b)(c)(d)(e)(g)(h)
1 Boardman Slatt 5O.0l 50.00 STow 1.79 1
2
3 Borah Midpoint 345.0l 50.00 STow 85.18 1
4 Jim Briger Goshen 345.0C 345.00 STowr 226.16 1
5 State Line Midpoint 345.01 34.00 STowr 76.08 2
6 Kinport Borah 345.OC 345.00 STowr 27.26 1
7 Midpoint Borah #1 345.01 345.00 HWoo 79.27 1
8 Midpoint Borah #2 345.01 345.00 HWoo 7759 2
9 Adelaide Tap Adelaide 345.01 345.00 HWoo 2.67 2
10
11 Quart LaGrande 23O.0l 230.00 HWoo 46.21 1
12 Midpoint Hunt 230.01 230.00 STower 0.53 2
13 Brady Antelope 230.0(230.00 HWoo 56.29 1
14 Brady Treasureton 230.0(230.00 HWoo 0.13 1
15 Brady #1 &#2 Kinport 230.0C 230.00 STower 17.94 2
16 Jim Bridger Point of Rocks 23O.OC 230.00 HWoo 1.40 1
17 Brownlee Ontario 230.0 230.00 STowr 72.70 1
18 Mora Bowmont 138.01 230.00 SPWoo 9.90 1
19 Mora Bowmont 138.01 230.00 HWoo 9.50 1
20 Jim Bridger Point of Rocks 230.01 230.00 HWoo 2.79 1
21 Caldwell 710 Locust 23O.0(230.00 SP Ste 18.60 1
22 Boise Bench Caldwell 230.0(230.00 STower 7.58 1
23 Boise Bench Caldwell 230.0(230.00 HWoo 33.50 1
24 Boise Bench Cloverdale 23O.lX 230.00 STowr 15.98 2
25 Boardman Dalre Sub 23.lX 230.00 HWoo 1.68 1
26 Brownlee 714 Oxbow 23O.lX 230.00 SP Ste 11.4 2
27 Caldwell Ontario 23O.lX 230.00 HWoo 27.10 1
28 Caldwell Ontario 230.0(230.00 STow 3.28 1
29 Bennett Mtn PP Rattlesnake TS 230.01 230.00 SP Ste 4.48 1
30 Borah Hunt 230.01 230.00 H Steel 68.22 1
31 Danskin Hubbard 230.01 230.00 HSteel 36.26 1
32 Danskin Hubbard 230.0(230.00 SP Steel 1.90 1
33 Danskin Hubbard 230.0C 230.00 SPSteel 1.30 2
34 Danskin Bennett Mtn 230.0C 230.00 SP Stee 5.52 1
35 Hemingway Bowmont 230.0(230.00 SPStel 13.01 1
36 TOTAL 4,740.42 11.02 180
FERC FORM NO.1 (ED. 12-87)Page 422
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/12/2010
RANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. R~port 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, fumish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percnt 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 affcted. Specify whether lessor, co-owner, or
other part is an associated company.
9. Designate any transmission line leased to another company and give name of Lesse, date and terms of lease, annual rent for year, and how
determined. Specif whether lessee is an assoi;iated company.
10. Base the plant cost figures called for in columns (j) to (i) on the book cost at end of year.
\,u., I ut' LINt: (inClUde in Column (j) Lana,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Constructon and Total Cost Operation Maintenance Rents Total Line
Other Costs Expenses Expenses (0)
Expenses No.(i)(j)(k)(I)(m)(n)(p)
121780 ACSR 446,708 446,708 1
2
1272 ACSR 256,381 21,776,998 22,033,379 3
1272 ACSR 483,3~15,882,152 16,365,461 4
95 ACSR 571,97~11,047,483 11,619,462 5
1272 ACSR 344,22C 6,028,033 6,372,253 6
15.5 ACSR 283,14 5,834,744 6,117,887 7
15.5 ACSR 64,85 10,494,526 10,559,377 8
15.5 ACSR 51,44f 347,946 399,394 9
10
95 ACSR 51,41 2,916,388 2,967,802 11
15.5ACSR 9,14 998,452 1,007,59 12
1272 ACSR 108,301 2,502,500 2,610,801 13
795 ACSR 6,186 6,186 14
15.5 ACSR 18,829 969,476 988,305 15
1272 ACSR 1,19C 51,525 52,15 16
2X954 ACSR 1,676,83 20,420,263 22,097,101 17
15.5 ACSR 413,79 2,090,601 2,504,394 18
15.5 ACSR 19
1272 ACSR 1,89 212,523 214,42~20
1590 ACSR 2,138,23f 8,773,210 10,911,446 21
1272 ACSR 1,464,14€5,817,555 7,281,701 22
15.5 ACSR 23
1272 ACSR 3,062,81 6,580,815 9,643,627 24
95AAC 80,895 80,895 25
954 ACSR 34,17 16,026,47C 16,060,644 26
2X95ACSR 197,65 5,890,623 6,088,281 27
1272 ACSR 28
1272 ACSR 81,0 1,666,354 1,748,055 29
1590 ACSR 624,91 22,457,621 23,082,538 30
1590 ACSR 10,451,149 10,451,149 31
1590 ACSR 32
1590 ACSR 33
1590 ACSR 3,528,033 3,528,033 34
1590 ACSR 1,852,599 1,852,599 35
33,019,820 389,962,025 422,981,845 36
FERC FORM NO.1 (ED. 12-87)Page 423
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) DA Resubmission 04/1212010
TRNSMISSION LINE STATIST CS
1. Report information concerning transmission lines, cot of Ii~es, and expenses for year. List each transmision line having nominal voltge of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Unifrm 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 commision.
4. Exclude from this page any transmission lines for which plant costs are included in Accunt 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 structre, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a diffrent type of construction need not be distinguished from the
reinder 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
reorted for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reportd for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a foote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line desinated.
Line IUN (Indicate w~~Type of LENG~ ~~ie ólileS)NumbeNo.other than uhWergrounlr lines Of60 cvcle 3 Dhase)Supportng report circuit miles)
From
-un~QCre i unl1.~!f~res CircuitsToOperatingDesignedStruetureof Line of 110 erDesit;ated ine
(a)(b)(c)(d)(e)(g)(h)
1 Boise Bench Midpoint #1 230.0C 230.00 STower 0.86 1
2 Boise Bench Midpoint #1 230.00 230.00 HWoo 108.24 1
3 Brownlee Quart Jet 230.00 230.00 STowr 1.52 1
4 Brownle Quart Jet 230.00 230.00 HWoo 41.8~1
5 Brownlee Boise Bench #1 & #2 230.0(230.00 STower 99.97 2
6 Oxbow Brownlee 230.0(230.00 STowr 10.22 2
7 Boise Bench Midpoint #2 230.00 230.00 STow 3.42 1
8 Boise Bench Midpoint #2 230.0(230.00 HWoo 102.53 1
9 Oxbow Pallette Jet 230.0(230.00 STower 20.21 2
10 Pallette Jet Imnaha 230.0(230.00 HWoo 24.43 2
11 Hells Canyon Palette Jet 230.0(230.00 STower 8.24 2
12 Brownlee Boise Bench 23O.0C 230.00 STower 102.29 2
13 Boise Bench Midpoint #3 230.0(230.00 HWood 106.35 1
14 Palette Jct Enterprise 23O.OC 230.00 HWood 29.08 1
15 Borah Brady #2 23O.OC 230.00 STowr 0.41 1
16 Borah Brady #2 230.OC 230.00 HWoo 3.58 1
17 Borah Brady #1 23O.OC 230.00 HWoo 3.98 1
18
19 Goshen State Line 161.OC 161.00 HWood 90.49 1
20 Don Goshen 161.OC 161.00 STower 2.39 2
21 Don Goshen 161.0(161.00 HWoo 48.3 2
22
23 American Falls Power Plant Adelaide 138.0C 138.00 HWoo 10.90 2
24 American Falls Power Plant Adelaide 138.OC 138.00 SPWood 0.12 2
25 Minidoka Loop Adelaide 138.0C 138.00 STower 1.13 2
26 Nampa Caldwell 138.lX 138.00 SPWoo 10.72 2
.27 Upper Salmon Mountain Home Jet 138.lX 138.00 HWoo 53.60 1
28 Upper Salmon Cliff 138.00 138.00 HWoo 30.80 1
29 Eastgate Russet 138.0~138.00 SPWoo 2.13 1
30 Brady Fremont 138.OC 138.00 STowr 0.98 2
31 Brady Fremont 138.0C 138.00 HWoo 24.32 2
32 Brady Fremont 138.0C 138.00 SPWoo 24.34 2
33 King Lower Malad 138.0C 138.00 HWoo 84.91 2
34 Emmett Jet Payette 138.0C 138.00 HWood 66.45 2
35 Mountain Home AFB Tap 138.0C 138.00 HWoo 6.20 1
36 TOTAL 4,740.42 11.02 180
FERC FORM NO.1 (ED. 12-S7)Page 422.1
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2009/04
(2) DA Resubmission 04/12/2010
RANSMISSION 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 Iines. 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 bome by the respondent are accunted for, and accounts affcted. Specify whether lessor, co-owner, or
other part is an associated company.
9. Designate any transmission line leased to another company and give name of Lesse, 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.
I,u~ I ui- LINt: (lnciuae in Column 0) Lanci,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rihts, and clearing right-of-way)
Conductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total Line
Other Costs Expenses Expenses EXP!nses
(i)0)(k)(i)(m)(n)(0)(p)No.
15.5 ACSR 336,18E 4,085,707 4,421,893 1
15.5 ACSR 2
95 ACSR 53,061 2,139,082 2,192,150 3
95 ACSR 4
ilARIOUS 289,93~7,991,04 8,280,978 5
1272 ACSR 14,81C 1,182,550 1,197,360 6
15.5 ACSR 227,82~5,858,06.6,085,881 7
~ARIOUS 8
1272 ACSR 23,30!2,075,244 2,098,55~9
1272 ACSR 138,47 1,392,62f 1,531,105 10
h272 ACSR 10,73 1,252,130 1,262,867 11
*i4ACSR 184,81 5,641,344 5,826,161 12
15.5 ACSR 247,85 5,392,037 5,639,894 13
1272 ACSR 51,12 1,749,361 1,800,483 14
1272ACSR 3,068 231,823 234,891 15
15.5 ACSR 16
1272 ACSR 10,Q6 311,34~321,413 17
18
ri50COPPER 16,15!64,382 664,537 19
i715.5ACSR 76,041 1,652,914 1,728,955 20
ß97.5ACSR 21
22
~50COPPER 26,50 2,396,233 2,422,740 23
50 COPPER 24
15.5 ACSR 21,32E 249,233 270,559 25
95AAC 567,53 1,753,582 2,321,120 26
95 ACSR 47,681 2,457,857 2,505,544 27
95 ACSR 43,56!776,170 819,738 28
95AAC 270,82 557,504 828,327 29
~ARIOUS 564,93 3,706,706 4,271,638 30
~ARIOUS 31
IVARIOUS 32
ARIOUS 76,82 1,834,894 1,911,717 33
ARIOUS 30,91f 2,507,98~2,538,901 34
97.5 ACSR 1,95 1,955 35
33,019,820 389,962,025 422,981 ,84~36
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 2009/Q4
(2) FiA Resubmission 041212010
TRANSMISSION LINE STATIST CS
1. Report information concerning transmission lines, cost of Ii,,es, and expenses for year. List each transmision line having nominal voltge of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covere by the definition of transmission system plant as given in the Unifrm Sysm of Accunts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so require by a State commission.
4. Exclude from this page any transmission lines for which plant cots are includ in Acunt 121, Nonutilit Propert.
5. Indicate whether the type of supporting structre reported in column (e) is: (1) single pole woo 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, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a trnsmission line of a difrent type of construction nee not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmision 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 mile of line on structures the cost of which is reported for another line. Report
pole miles of line on lease or partly owned structures in column (g). In a footnote, explain the basis of such occpancy and state whether expenses with
respect to such structres are included in the expenses reported for the line designated.
Line (Indicte J~Type of LE~GJt ~~leeWileS)Numbe
No.other than ! \u ~ergrounlflines Of60 cvcl 3 ohase Supportng report circuit miles)
From To Opeatng Deigned un '=lrl,ctUre I unf~tr~!.~res CircuitStrctureof.Lln~o "-1)0 er
Desiara ed ine
(a)(b)(c)(d)(e)(g)(h)
1 Ontario Quart 138.01 138.00 HWoo 73.34 1
2 King American Falls PP 138.01 138.00 STowr 1.03 2
3 King American Falls PP 138.lX 138.00 HWoo 148.6 1
4 King American Falls PP 138.0£138.00 SPWoo 3.71 1
5 Duffn Clawson 138.0£138.00 HWoo 6.22 1
6 American Falls Brady Tie 138.lX 138.00 HWoo 0.33 1
7 Upper Salmon A-B King 138.01 138.00 HWoo 5.88 1
8 Upper Salmon B Wells 138.01 138.00 HWoo 125.58 1
9 King Woo River 138.01 138.00 HWoo 73.61 1
10 Boise Bench Grove 138.01 138.00 SPWoo 10.4 2
11 Quart John Day 138.0£138.00 HWoo 67.32 1
12 Sinker Creek Tap 138.lX 138.00 HWoo 2.7~1
13 Mora Cloverdale 138.lX 138.00 HWoo 2.57 1
14 Mora Cloverdale 138.0£138.00 SPWoo 22.32 1
15 Mora Cloverdale 138.0£138.00 SPSteel 0.96 2
16 Stoddard Jct Stoddard Sub 138.0(138.00 S P Stel 3.80 1
17 Fossil Gulch Tap 138.0 138.00 HWoo 1.95 1
18 Wood River Midpoint 138.01 138.00 HWoo 53.06 2
19 Wood River Midpoint 138.0 138.00 SPWoo 16.69 2
20 Oxbow McCall 138.0£138.00 HWoo 37.24 1
21 Oxbow McCall 138.0£138.00 SPWoo 2.32 1
22 Lowell Jet Nampa 138.0£138.00 SPWoo 7.58 2
23 Hunt Milner 138.0£138.00 SPWoo 19.40 1
24 Strike Bruneau Bridge 138.0l 138.00 HWoo 13.48 1
25 American Falls Kramer Sub 138.0l 138.00 SPWoo 18.40 2
26 Pingree Haven 138.0(138.00 SPWoo 11.72 1
27 Midpoint Twin Falls 138.0l 138.00 SPWoo 25.12 2
28 Twin Falls Russett 138.01 138.00 SPWoo 1.73 1
29 Blackoot Aiken 46.01 138.00 SPWoo 6.18 2
30 Petersn Tendoy 69.0!138.00 HWoo 57.22 1
31 Eastgate Tap Eastgate 138.01 138.00 SPWoo 7.33 1
32 Boise Bench Mora 138.0(138.00 HWoo 13.17 2
33 Bowmont-Caldwell SimplotSub 138.0£138.00 SPWoo 0.51 . 1
34 Gary Lane Eagle 138.0C 138.00 SPWoo 6.53 1
35 Locust Grove Blackcat Sub 138.0£138.00 S P Ste 9.93 2.98 1
36 TOTAL 4,740.42 11.02 180
FE FORM NO.1 (ED. 12-87)Page 422.2
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) FiA Resubmission 04/12/2010
RANSMISSION 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 partculars (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 accunted for, and accounts affected. Specify whether lessor, co-owner, or
other part is an associated company.
9. Designate any transmission line lease to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specif whether lesse is an associated company.
10. Base the plant cost figures called for in columns u) to (i) on the book cost at end of year.
COST VI '-IIU.. iinCluae in lIolumn OJ Lana,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and claring right-of-way)
Conductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total line
Other Costs Expenses Expenses (0)
Expenses No.
(i)u)(k)(I)(m)(n)(p)
~ARIOUS 34,42f 1,948,970 1,983,39f 1
1715.5 ACSR 148,91/7,006,563 7,155,477 2
1715.5 ACSR 3
15.5 ACSR 4
\0 4,19 309,827 314,018 5
ß54ACSR 96,921 96,921 6
50 COPPER 2,741 93,073 95,814 7
~ARIOUS 28,491 2,093,136 2,121,626 8
WARIOUS 173,68 2,670,571 2,844,254 9
lVARIOUS 225,60 1,652,77 1,878,37/10
~97.5ACSR 92,17 2,362,416 2,454,58~11
¡VARIOUS 21 77,199 77,21!12
1715.5 ACSR 3,115,481 7,904,71C 11,020,196 13
~ARIOUS 14
95AAC 15
1272 ACSR 16
50 COPPER 45 63,439 63,889 17
97.5 ACSR 281,0&6,388,221 6,669,285 18
,,97.5 ACSR 19
1397.5 ACSR 109,891 2,308,911 2,418,811 20
1397.5 ACSR 21
1715.5 ACSR 211,131 1,448,294 1,659,425 22
15.5 ACSR 3,32 1,190,604 1,193,928 23
1397.5 ACSR 14,92 587,40/602,331 24
1715.5 ACSR 13,731 1,052,549 .1,066,283 25
97.5 ACSR 18,22 1,383,07;.1,401,295 26
VARIOUS 54,841 2,958,76~3,013,61 27
15.5 ACSR 16,791 206,158 222,948 28
15.5 ACSR 13,611 476,381 489,997 .29
397.5 ACSR 395,69 3,449,949 3,845,64~30
15.5 ACSR 207,64:1,058,891 1,266,54.1 31
15.5 ACSR 14,69 627,920 642,617 32
1795 AAC 49,642 49,642 33
1795AAC 489,03 1,944,888 2,433,925 34
1272 ACSR 935,7 3,601,59C 4,537,315 35
33,019,820 389,962,025 422,981,845 36
FERC FORM NO.1 (ED. 12-87)Page 423.2
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Oriinal (Mo, Da, Yr)End of 2009/Q4
(2) FiA Resubmission 04/1212010
TRNSMISSION LINE STATIST CS
1. Report information concerning transmission lines, cost of ii~, and expenses for year. List each transmission line having nominal voltge of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Unifrm System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so require by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Acunt 121, Nonutilit Propert.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one ty of supporting structure, indicate the mileage of each type of constructon
by the use of brackets and extra lines. Minor portions of a transmission line of a difrent ty 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 trnsmisson 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 mile of Une on structures the cost of which is reported for another line. Report
pole miles of line on leased or party 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 rert for the line desinated.
Line IKV\Type of LE~GJi~ ~~ie iWileS)
No.(Indicate wtere u \?ergroun~ lines Numbei
other than Of60 cvcle 3 Dhase\Supporting report circuit miles)
From I on ~trueture untJt~Th~res CircuitToOperatingDesignedStructureotLineo 1)0 erDeslaratedine
(a)(b)(c)(d)(e)(g)(h)
1 Boise Bench Butler 138.0(138.00 SPWoo 0.18 4.02 1
2 Eagle Star 138.0(138.00 SPWoo 6.35 1
3 Karcher Sub Zilog Tap 138.0(138.00 S P St 2.08 1
4 Cloverdale - 712 712 -Wye 138.0(138.00 S P Ste 0.21 4.02 1
5 Butler Wye 138.0(138.00 S P Ste 2.84 1
6 Horseflat Starkey 138.0(138.00 HWoo 34.01 1
7 Starkey Mccll 138.0(138.00 S P Stee 2.08 2
8 Starkey Mccll 138.0(138.00 HWoo 3.80 1
9 Starkey Mccll 138.0(138.00 S P Stl 1.50 1
10 Starkey Mccall 138.01 138.00 SPWoo 17.61 1
11 Chestnut Happy Valley 138.0C 138.00 S P Steel 2.79 1
12 Garnet Ward 138.00
13 McCall Lake Fork 138.0C 138.00 SPWoo 8.84 1
14 McCall Lake Fork 138.0C 138.00 S Steel 2.90
15 Caldwell Wills 138.0(138.00 S P St 1.0 1
16 Caldwell Wills 138.0(138.00 S P St 1.59 1
17 Caldwell Wills 138.OC 138.00 SPWoo 0.87 1
18 ValivueTap 138.OC 138.00 S P Ste 0.80 2
19 Kinport Don #1 138.01 138.00 STower 1.44 2
20 Donn HOKU 138.01 138.00 S P Steel 2.74 1
21 HOKU Alamed 138.01 138.00 SPSteel~0.22 2
22 HOKU Alamed 138.01 138.00 S P Stel 0.23 2
23 HOKU Alamed 138.0l 138.00 SPSteel 3.00 1
24 Twin Falls PP Tap 138.01 138.00 HWoo 0.82 1
25 American Falls PP Amercian Falls Trans ST 138.1 138.00 SP Stl 0.37 1
26 Lower Salmon King Tie 138.0(138.00 HWoo 0.22 1
27 C J Strike Strike Jct 138.0(138.00 STower 4.3(2
28 Strike Jct Mountain Home Jct 138.0(138.00 HWoo 23.51 1
29 Strike Jct Bowmont 138.00 HWoo 0.0'1
30 Strike Jct Bowmont 138.01 138.00 STower 0.36 1
31 Strike Jct Bowmont 138.01 138.00 HWoo 68.23 1
32 Lucky Peak Lucky Peak Jct 138.01 138.00 HWoo 4.48 2
33 Bliss King 138.01 138.00 HWoo 10.44 1
34 Milner Oeadend MiinerPP 138.1 138.00 SPWoo 1.3C 1
35 Swan Falls Tap 138.01 138.00 HWoo 0.95 1
36 TOTAL 4,740.42 11.02 180
FERC FORM NO.1 (ED. 12-87)Page 422.3
Name of Respondent This i!0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) CiA Resubmission 04/12/2010
RANSMISSION 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 strctures 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 thereoffor which the respondent is not the sole owner. If such propert is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, fumish a succinct statement 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 bome by the respondent are accunted for, and accunts affcted. Specify whether lessor, coowner, or
other part is an associated company.
9. Deignate 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 lesse 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.
l,U~ i ui- LINE (Include In Column 0) Land,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Constructon and Total Cost Operation Maintenance Rents Total Line
Other Costs Expenses Expenses (0)Ex~nses No.(i)(j)(k)(I)(m)(n)(p)
~272ACSR 34,68 838,60~873,292 1
15.5 ACSR 3,133,215 3,133,215 2
95AAC 43,03 443,805 486,84 3
1272 ACSR 140,41 709,148 849,560 4
795 ACSR 134,471 1,405,436 1,539,907 5
15.5 ACSR 638,40~19,998,719 20.637,124 6
15.5 ACSR 7
15.5 ACSR 8
15.5 ACSR 9
15.5 ACSR 10
1272 ACSR 78,57c 1,821.921 1,900,500 11
40,58(40,580 12
715.5 ACSR 331,53c 4,687,415 5,018,954 13
14
1272 ACSR 272,231 2,141,218 2,413,449 15
795 ACSR 16
795 ACSR 17
95 ACSR 351,497 351,497 18
15.5 ACSR 1,17 220,975 222,14~19
1272 ACSR 586 586 20
1272 ACSR 21
95 ACSR 22
95 ACSR 23
250 COPPER 5f 53,889 53.947 24
15.5 ACSR 76,560 76,560 25
397.5 ACSR 4,406 4,406 26
715.5 ACSR 1,07~253,907 254,981 27
397.5 ACSR 4,35~2,274,613 2,278,968 28
715.5 ACSR 86,65 1,855,384 1,942,035 29
1115.5 ACSR 30
31
15.5 ACSR 279,481 279,488 32
15.5 ACSR 5,620 964,435 970,055 33
15.5 ACSR 2,814 183,606 186,420 34
97.5 ACSR 12,88S 261,511 274,396 35
33,019,820 389,962,025 422,981,845 36
FERC FORM NO.1 (ED. 12-S7)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 2oo9/Q4
(2) DA Resubmission 041212010
TRANSMISSION LINE STATIST CS
1. Report information concerning transmission lines, cost of Iiaes, 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 voltge.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accunts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltges if so reuire by a State comission.
4. Exclude from this' page any transmission lines for which plant costs are include in Accunt 121, Nonutilit Propert.
5. Indicate whether the type of supportng 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 supportng structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portons of a transmission line of a difrent type of construction nee not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmision 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 IIUN
(Indicte wlìre Type of lENG~~ ~~leólileS)Numbe
No.other than ul.Wergrounlf hnes Of60 cvcle 3 ohase)Supporting report circuit miles)
From
un~nTcttJre unf1t~îf~res CircuitsToOpratingDesignedStructureof line of 1)0 er
DeSiarated ine
(a)(b)(c)(d)(e)(g)(h)
1
2
3
4 Hines SPA (Harney)115.0(115.00 HWoo 3.28 1
5
6
769 Kv Lines 69.0(69.00 HWoo 166.31 1
869 Kv Lines 69.0(69.00 SPWoo 922.54 1
9
10
11 46 Kv lines 46.00 46.00 SPWoo 409.81 1
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 4,740.42 11.02 180
FERC FORM NO.1 (ED. 12-87)Page 422.4
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2009/04
(2) FiA Resubmission 04/12/2010
RANSMISSION 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 structre 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 givng particulars (details) of such matters as percent ownership by respondent in the line, name of cowner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accunts affcted. Specify whether leor, coowner, or
other part is an associated company.
9. Designate any transmission line leased to another company and give name of Lesse, 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.
\,U:: I ui- LINE (InCluae in \,oiumn OJ Lana,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total Line
Other Costs Expenses Expenses (0)
Expenses No.
(i)0)(k)(I)(m)(n)(p) .
1
2
3
397.5 ACSR 1,971 63,404 65,38~4
5
6
¡VARIOUS 1,540,671 41,095.96 42,636,63(7
¡VARIOUS
8
9
10
"ARIOUS 17,27!10,686,433 10,863,71,11
12
5,736,25 5,736.253 13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
33,019,820 389,962,025 422,981,845 36
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 2oo9/Q4
(2) FiA Resubmission 04/1212010
rRNSMISSION LINES ADDED DURII,G YEAR
1. Report below the information called for concerning Ti:nsmission lines added or altered during the year.It is not necssary to report
minor revisions of lines.
2. Provide separate subheadings for overhead and under- ground costrction and show each transmission line separately. If actual
costs of competed construction are not readily available for reportng columns (I) to (0), it is permissible to report in these columns the
line IIUN ~~gt lilKliUl1 ~ t'1:
No.From To in Typ Number per Present Ultimate
Miles Miles
(a)(b)(c)(d)(e)(f)(g)
1 Adrian Tup Adrian Sub 5.65 SPWood 19.6 1 1
2 Starkey Mccll 17.61 SPWood 17.60 1 1
3 Starkey Mccll 3.80 HWood 6.5 1 1
4 Starkey Mccll 2.08 SP Steel 17.6l 2
5 Starkey Mccll 1.50 SP Steel 17.60 1 1
6 Donn HOKU 2.74 SPSteel 18.9 1 1
7 HOKU Alamed 0.22 SP Steel 22.73 2 2
8 HOKU Alamed 0.23 SP Steel 21.74 '-2
9 HOKU Alamed 3.00 SPSteel 19.34 1 1
10 Hemingway Bowmont 13.01 SPSteel 7.30 1 2
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 49.84 169.07 13 14
FERC FORM NO.1 (REV. 12-03)Page 424
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2oo9/Q4
(2) ¡=A Resubmission 04/12/2010
TRAN MISSION LINES ADDED DURING Y :AR (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.
)t(;)Voltage LINE COST Line
Size Specification Confieuration KV Land and Poles, Towers Conductors Asset Total No.
and pacing (Ope~ting)Land Rights and Fixtures and Devices Retire. Costs
(h)(i)ü)(k (I)(m)(n)(0)(p)
397.5 ACSR TVS5'6~13,254 1,091,58~1,104,838 2,209,676 1
715.5 ACSR TVST 13E 9,697 6,715,36 6,725,058 13,450,116 2
715.5 ACSR Hor 16'138 3
715.5 ACSR TVSDC6'138 4
715.5 ACSR TVST 138 5
1272 ACSR TAS6'138 331 255 58 6
1272 ACSR TASDC6'138 7
795 ACSR TASDC6'138 8
795 ACSR TAS6'131 9
1590 ACSR T-DC 12'23C 1,852,599 1,852,599 10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
1,875,550 7,807,27£7,830,151 17,512,977 44
FERC FORM NO.1 (REV. 12-03)Page 425
Name of Respondent ThiS~ort is:Date of Report Year/Period of Report
Idaho Power Company (1)An Original (Mo, Da, Yr)End of 2009/Q4
(2)A Resubmission 04/12/2010
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 beow.
3. Substations with capacities of Less than 10 MVa except those serving customers wih energy for resale, may be grouped acrding
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)
Name and Location of Substation Charactr of SubstationNo.Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 Adelaide transmison 345.00 138.00 13.80
2 Aiken distribution 46.00 13.00
3 Alameda distribution 46.00 13.00
4 Alameda distribution 138.00 13.00
5 American Falls PP - attended transmission 138.00 13.80
6 American Falls transmission 138.00 46.00 12.50
7 Artesian distribution 46.00 13.00
8 Bannock Creek distribution 46.00 13.00
9 Bennett Mountain Power Plant trnsmissn 230.00 18.00
10 Bennett Mountain Power Plant disributin 18.00 4.16
11 Bethel Court distribution 138.00 13.00
12 Black Cat distributon 138.00 13.09
13 Blackoot distbution 46.00 13.00
14 Blackot transmisson 161.00 46.00 12.47
15 Blackfoot distribution 161.00 138.00 12.98
16 Bliss - attended transmission 138.00 13.80
17 Blue Gulch distribution 138.00 34.50
18 Boise Bench - attended distribution 138.00 34.50
19 Boise Bench - attended transmission 138.00 69.00 12.98
20 Boise Bench - attended transmission 230.00 138.00 13.80
21 Boise distribution 138.00 13.00
22 Borah transmission 345.00 230.00 13.80
23 Bowmont distribution 69.00 46.00 6.90
24 Bowmont distribution 138.00 34.50
25 Bowmont transmission 138.00 69.00 12.98
26 Brady distribution 46.00 13.09
27 Brady transmission 230.00 138.00 13.80
28 Brady transmission 138.00 46.00 12.47
29 Brady distribution 69.00 13.00
30 Brownlee. attended transmisn 230.00 13.80
31 Bruneau Bridge disribution 138.00 34.50
32 Buckhorn ,disributin 69.00 35.00
33 Bucyrus distribution 46.00 7.20
34 Buhl disribution 46.00 13.00
35 Burley Rural distrbution 69.00 13.00
36 Butler distribution 138.00 13.00
37 Caldwell distribution 138.00 13.00
38 Caldwell transmission 138.00 69.00 12.47
39 Caldwell transmission 230.00 138.00 12.50
40 Canyon Creek distribution 138.00 35.00
FERC FORM NO.1 (ED. 12-96)Page 426
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) riA Resubmission 04/12/2010
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacit.
6. Designate substations or major items òf equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expenses or other accounting between the parties, and state amounts and accunts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Total Capacit No.In Service Transformers Type of Equipment Number of Units
(In MVa)
(f)(g)(h)(il fj (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
50 3 1 14
80 1 15
69 3 16
15 1 17
42 2 18
75 3 19
494 4 20
67 3 21
450 3 1 22
8 3 23
18 1 24
50 2 25
6 26
300 3 27
1 28
1 29
734 5 1 30
30 2 31
20 1 32
6 1 4 33
20 2 34
12 1 35
48 2 36
39 2 1 37
75 3 38
240 2 39
15 1 40
FERC FORM NO.1 (ED. 12-96)Page 427
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 041212010
SUBSTATIONS
1. Report below the informaton 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 accrding
to functonal 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 distnbution and whether
attended or unattended. At the end of the page, summarie accrding to functon the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Charactr of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 Canyon Creek transmission 138.00 69.00 12.98
2 Cascde Power Plant - attended transmission 69.00 4.60
3 Cascade Distribution 69.00 13.10
4 Chestnut distribution 138.00 13.00
5 Clear Lake - attended transmission 46.00 2.40
6 Cliff transmission 138.00 46.00 12.50
7 Cloverdale Distrbution 138.00 13.00
8 Dale distributin 46.00 13.00
9 Dale distribution 69.00 13.00
10 Dale distbution 138.00 36.20
11 Dale Transmision 138.00 46.00 12.50
12 Danskin transmison 230.00 138.00 13.80
13 Danskin distribution 18.00 4.16
14 Danskin transmission 138.00 12.00
15 Don distribution 138.00 7.60
16 Don distbution 138.00 13.20
17 Don distribution 138.00 13.00
18 Don distbution 14.00
19 DRAM distribution 138.00 13.00
20 DRAM transmission 230.00 138.00 13.80
21 Duffn distribution 138.00 34.50
22 Eagle distribution 138.00 13.00
23 Eastgate distribution 138.00
24 Eastgate distribution 138.0C 13.00
25 Eckert distribution 138.00 36.20
26 Eden distribution 138.0C 36.20
27 Eden transmission 138.00 46.00 12.98
28 Elkhorn distribution 138.00 12.47
29 Elmore distutin 138.00 35.00
30 Elmore transmissin 138.00 69.00 12.50
31 Emmett distribution 138.00 12.50
32 Emmett Transmission 138.00 69.00 12.50
33 Falls distribution 46.00 13.00
34 Filer distribution 46.00 13.00
35 Flying H distribution 69.00 2.40
36 Fort Hall distribution 46.00 13.00
37 Fossil Gulch distribution 138.00 35.00
38 Fremont transmission 138.00 46.00 12.50
39 Gary distribution 138.00 13.00
40 Gem distribution 69.00 13.00
FERe FORM NO.1 (ED. 12-e6)Page 426.1
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 2009/Q4
(2) OA Resubmission 04/1212010
SUBSTATIONS (Continued)
5. Show in columns (1),0). and (k) specal equipment such as rotary converters, rectifiers, condenser, etc.and auxilary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expenses or other accounting between the parties. and state amounts and accunts
affected in respondenfs 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 Capacit No.In Service Transformers Type of Equipment Number of Units (In MVa)
(f)(0)(h)(i)(j)(k)
15 1 1
12 1 2
10 1 3
48 2 4
4 1 5
16 3 1 6
48 2 7
7 8
1 9
27 1 1 10
25 1 11
320 2 12
6 1 13
96 2 14
1 15
108 6 3 16
26 1 1 17
80 6 18
134 8 19
160 2 20
36 2 21
38 2 22
24 1 23
18 1 1 24
18 1 25
24 1 26
15 1 27
15 2 28
17 1 29
30 2 30
24 1 31
25 1 32
18 2 33
10 1 34
15 2 35
10 1 1 36
15 1 ,37
50 3 1 38
37 2 39
18 2 40
FERC FORM NO.1 (ED. 12-96)Page 427.1
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 2009/Q4
(2) ÕA Resubmission 04/12/2010
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 capaciies of Less than 10 MVa except those serving customers with energy for resale, may be groupe 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, summarie accrding to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Charactr of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 Goodng Rural distribution 46.00 13.00
2 Golden Valley distnbution 69.00 13.00
3 Gowen Substation distribution 138.00 35.00
4 Grindstone distribution 35.00 12.50
5 Grove distribution 138.00 13.09
6 Hagerman disbutin 46.00 13.00
7 Hagerman distribution 46.00 13.00 32.00
8 Hailey distributin .138.00 13.00
9 Happey Valley distribution 138.00 13.09
10 Haven distribution 138.01J 35.00
11 Haven transmission 138.00 46.00
12 Hewlett Packard distribution 138.00 13.10
13 Hidden Springs disribution 138.00 13.09
14 Highland distributin 138.01J 13.09
15 Hill distribution 138.00 13.00
16 Hilsdale disribution 138.00
17 Homedale distribution 69.00 13.00
18 Hors Flat trnsmission 230.00 138.00 13.80
19 Horse Flat distribution 69.00 13.00
20 Horseshoe Bend distribution 35.00 12.50
21 Horseshoe Bend distribution 69.00 36.20
22 Horseshoe Bend distribution 69.00 25.00
23 Huston distribution 69.00 13.00
24 Hulen distribution 46.00 13.00
25 Hunt transmission 230.00 138.00 13.80
26 Hydra distribution 138.00 36.20
27 Island distribution 69.00 13.00
28 Jerome distribution 138.00 13.00
29 Julion Clawson distribution 138.00 34.50
30 Joplin disribution 138.00 13.00
31 Joplin distribution 138.00 35.00
32 Karcher distribution 138.00 13.09
33 Kenyon distribution 69.00 13.00
34 Ketchum distribution 138.00 13.00
35 Kinport transmission 161.00 46.00 13.20
36 Kinport transmission 230.00 138.00 12.47
37 Kinport transmission 230.00 138.00 13.80
38 Kinport transmission 345.00 230.00 13.80
39 Kramer distribution 138.00 34.50
40 Kramer distribution 138.00 13.00
FERC FORM NO.1 (ED. 12-96)Page 426.2
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) OA Resubmission 04/12/2010
SUBSTATIONS (Continued)
5. Show in columns (I), (j), and (k) speial 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 part, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of accunt. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)
Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units
(In MVa)
(f)(0)(h)(i)Ii (k)
15 2 1
10 1 1 2
24 1 3
5 2 4
72 3 5
10 1 6
5 1 7
20 1 8
18 1 9
12 1 10
25 1 11
20 1 12
8 1 13
18 1 14
24 1 1 15
24 1 16
20 2 17"
100 1 18
1 19
5 1 20
12 1 21
5 1 22
10 1 23
10 1 24
300 3 25
48 2 26
12 1 27
40 2 28
30 2 29
15 1 30
18 1 31
12 1 32
20 2 33
42 2 34
7 35
180 1 36
180 1 37
600 3 1 38
12 1 39
18 1 40
FERC FORM NO.1 (ED. 12-96)Page 427.2
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 2oo91Q4
(2) ñA Resubmission 04/1212010
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 industnal 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 eac substation, designating whether transmission or distnbution and whether
attended or unattended. At the end of the page, summanze accrding to functon the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Charactr of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 Kuna distribution 138.0C 13.00
2 Lake Fork distrbution 138.00 36.20
3 Lake Fork trnsmission 138.00 69.00 12.50
4 Lamb distributin 138.00 13.09
5 Lansing distribution 69.00 13.00
6 Lincoln distribution 138.00 13.00
7 Linden disbution 138.00 13.00
8 Locust distrutin 138.00 36.20
9 Locust transmission 230.00 138.00 13.80
10 Lower Malad - attended transmission 138.00 7.20
11 Lower Salmon - attended transmission 138.00 13.80
12 Map Rock distbution 69.00 13.00
13 McCall distrbution 13.00 13.09
14 McCall distrbution 138.00 36.20
15 Meridian distbutin 138.00 13.00
16 Micron distribution 138.00 13.00
17 Midpoint trnsmission 230.00 138.00 13.80
18 Midpoint transmission 345.00 230.00 13.80
19 Midpoint transmission 500.00 345.00
20 Midrose distribution 138.00 13.09
21 Milner distribution 138.00 69.00 12.47
22 Milner distribution 69.00 46.00 6.90
23 Milner distribution 138.00 35.00
24 Milner PP - attended trnsmissn 138.0C 13.80
25 Moonstone distrbution 138.00 35.00
26 Mora distrbution 138.00 34.50
27 Moreland distrbution 35.00 13.00 6.00
28 Moreland distrbution 46.00 13.00
29 Moreland distrbution 46.00 35.00 12.50
30 Mountain Home distribution 69.00 12.50
31 Mountain Home Air Force Base distributin 69.00 13.00
32 Mountain Home Air Force Base distribution 138.00 .13.00
33 Nampa distribution 230.00 138.00 13.80
34 Nampa distribution 138.0ll 13.00
35 New Meadows distrbution 138.00 36.20
36 New Plymouth distribution 69.00 13.00
37 Notch Butte distribution 13.00 13.09
38 Orchard distrbution 69.00 36.20
39 Orchard distribution 69.0ll 35.00 12.47
40 Parma distribution 69.00 12.50
FERC FORM NO.1 (ED. 12-96)Page 426.3
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 2009/04
(2)A Resubmission 04/1212010
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxilary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other part is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
(In Serviæ)(In MVa)
Transformers Spare Type of Equipment Total Capacity No.In Serviæ Transformers Number of Units
(In MVa)
(f)(0)(h)(i)0\(k)
15 1 1
18 1 2
15 1 3
18 1 4
12 1 5
10 1 6
33 2 7
48 2 8
360 2 9
16 1 10
70 4 11
10 1 12
12 1 13
18 1 14
36 2 15
48 4 16
120 1 17
720 2 18
750 3 1 19
24 1 1 20
100 4 21
8 3 1 22
17 1 23
36 1 24
12 1 25
39 2 26
1
27
8 1 28
13 4 29
15 1 30
1 31
18 1 32
180 1 33
50 3 34
12 1 35
10 1 36
10 1 37
6 1 38
10 3 39
10 1 40
.
FERC FORM NO.1 (ED. 12-96)Page 427.3
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 2009/Q4
(2)A Resubmission 041121010
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 industnal or street railway customer should not be listed below.
3. Substations with capaciies of Less than 10 MVa except those servng customer wih energy for resale, may be groupe accrding
to functonal character, but the number of such substations must be show.
4. Indicate in column (b) the functional character of each substtion, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarie accding to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
Name and Location of Substation Character of SubstationNo.Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 Parma distribution 69.00 34.50
2 Paul disbutin 138.00 34.50 12.50
3 Payette disribution 138.00 13.00
4 Pingree trnsmission 138.00 46.00 12.50
5 Pingree distribution 138.00 35.00
6 Pleasant Valley distribution 138.00 34.50
7 Pocatello distribution 46.00 12.50
8 Poleline distribution 138.00 13.09
9 Portneuf distribution 138.00 36.20
10 Portneuf distribution 46.00 35.00
11 Rockford distribution 46.00 13.00
12 Russett distribution 138.00 13.00
13 Sailor Creek distributon 138.00 2.40
14 Sailor Creek distribution 138.00 35.00
15 Salmon distribution 69.00 13.00
16 Salmon distributin 69.00 34.50 12.50
17 Salmon transmision 13.00 2.40 5.00
18 Shoshone distribution 46.00 13.00
19 Shoshone distribution 46.00 7.20
20 Shoshone Falls - attended transmission 46.00 2.30
21 Shoshone Falls - attended transmission 46.00 6.60
22 Silver distribution 138.00 34.50
23 Simplot distribution 138.0C 13.00
24 Sinker Creek distribution 138.OC 34.50
25 Siphon distribution 138.00 34.50
26 South Park distribution 46.00 13.00
27 Star distribution 138.00 13.00
28 Starkey Transmision 138.00 69.00 12.50
29 State distribution 69.00 13.00
30 Stoddard distribution 138.00 13.00
31 Strike Power Plant - attended transmission 138.00 13.80
32 Sugar distribution 138.00 34.50
33 Swan Falls - attended transmission 138.00 6.90
34 Taber distribution 46.00 13.00
35 Ten Mile distribution 138.00 13.09
36 Terry distribution 138.00 13.00
37 Thousand Springs - attended transmission 46.00 7.20
38 Thousand Springs - attended transmission 7.00 2.40
39 Toponis distribution 138.00 33.00
40 Twin Falls distribution 138.00 13.00
FERC FORM NO.1 (ED. 12-96)Page 426.4
Name of Respondent This oo0rt Is:Date of Report Year/Period of Rëport
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) OA Resubmission 04/12/2010
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) specal equipment such as rotary converters, recifiers, condensers, etc.and auxilary equiprnent for
increasing capacity.
6. Designate substations or rnajor items of equiprnent 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 narne
of co-owner or other part, explain basis of sharing expenses or other accunting between the parties, and state amounts and accunts
affected in respondent's books of accunt. Specify in each case whether lessor, coowner, 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)(i)(k)
12 1 1
36 2 2
23 3 3
50 3 4
22 2 5
42 2 6
36 2 7
18 1 8
18 1 9
1
.10
14 2 11
18 1 12
15 2 13
15 1 14
10 1 4 15
10 3 1 16
2 17
10 1 18
2 3 19
3 1
20
10 1 21
12 1
22
15 1 23
12 1
24
33 2 25
10 1 26
18 1 27
18 1 28
33 2 29
15 1
30
83 3 31
20 2 32
18 1
33
5 1 34
24 1
35
42 3 36
8 1
37
2 1 38
18 1
39
44 2 40
FERC FORM NO.1 (ED. 12-96)Page 427.4
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) OA Resubmission 04/121010
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 industnal 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 accrding
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whther 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 Twin Falls transmission 138.00 46.00 12.98
2 Twin Falls PP - attnded transmission 138.00 7.20
3 Twin Falls PP - attended trnsmission 138.00 13.20
4 Upper Malad - attended transmission 45.00 7.20
5 Upper Salmon- attended transmission 138.00 7.20
6 Ustick distribution 138.00 13.00
7 Vallvue distbution 138.00 13.09
8 Victory disribution 138.00 13.00
9 Ware distbution 69.00 13.00
10 Weiser distribution 69.00 13.00
11 Weiser transmission 138.00 69.00 12.47
12 Wilder distribution 69.00 13.00
13 Wills distbutin 138.00 13.09
14 Wye disribution 138.00 13.00
15 Zilog distutin 138.00 13.09
16
17
18 The above are all State of Idaho
19
20 Montana:
21 Petersn transmission 230.00 69.00 13.20
22
23 Nevada:
24 Valmy - attended transmissn 345.00 21.30
25 Wells transmision 138.00 69.00 13.00
26
27 Oregon:
28 Boardman - attended trnsmission 5OD.OIl 24.00
29 Cairo distribution 69.00 13.00
30 Hells Canyon - attended transmission 230.00 13.80
31 Hells Canyon distribution 69.00 0.50 1.00
32 Hines transmission 138.00 115.00 12.47
33 Malheur Butte distribution 69.0C 34.50 12.50
34 Nyssa distribution 69.DC 13.00
35 Ontario distribution 138.00 13.00
36 Ontario transmission 138.00 69.00 12.50
37 Ontario transmission .230.00 138.00 13.80
38 Ore-Ida distribution 69.00 13.00
39 Oxbow - attended transmission 138.00 69.00 13.00
40 Oxbow - attended transmission 230.00 13.80
.
FERC FORM NO.1 (ED. 12-96)Page 426.5
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 2oo9/Q4
(2) OA Resubmission 04/12/2010
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 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 assoiated company.
.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Number of Units Total Capacit No.In Service Transformers (In MVa)
(f)(g)(h)(i)Ii)(k)
33 2 1
9 1 2
72 1 3
8 1 4
36 4 5
44 2 6
18 1 7
24 1 8
12 1 1 9
20 2 10
25 1 11
10 1 12
18 1 13
56 3 14
24 1 15
16
17
18
19
20
30 3 1 21
22
23
150 1 24
20 3 1 25
26
27
55 1 28
12 1 29
501 4 30
31
40 1 32
8 3 1 33
20 2 34
38 2 35
75 3 2 36
240 2 37
15 1 38
10 3 1 39
244 2 40
FERC FORM NO.1 (ED. 12-96)Page 427.5
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 2oo9/Q4
(2)A Resubmission 0411212010
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 suc substations must be show.
4. Indicate in column (b) the functonal 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 (t).
Line I VOLTAGE (In MVa)
No.Name and Location of Substation Charactr of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 Oxbow - attended trnsmssion 230.00 138.00 13.80
2 Quart transmission 138.00 69.00 12.50
3 Quart trnsmission 230.00 138.00 13.00
4 Vale distribution 69.00 13.09
5
6 Wyoming:
7 Jim Bridger - attended transmission 345.00 22.00
8
9
10
11
12
13
14 Transformers-distribution substations under 10,000
15 KVA 88 unattended.
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO.1 (ED. 12-96)Page 426.6
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) OA Resubmission 04112/2010
SUBSTATIONS (Continued)
5. Show in columns (i), 0). and (k) special equipment such as rotary converters, recifers, condensers, etc. and auxilary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease. give name
of co-owner or other part, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affeced in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)
Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units
(In MVa)
(f)(g)(h)(i)Ii)(k)
100 1 1
30 2 2
100 3 1 3
10 1 4
5
6
748 1 7
8
9
10
11
12
13
14
353 15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO.1 (ED. 12-96)Page 427.6
This Page r~tentionally Left Blank
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2009/04
Line
No.
This ~ort Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmission 04/1212010
TRANSACTIONS WITH ASSOCIATED (AFFILIATED) COMPANIES
1. Report below the information called for conceming all no-power goods or services received from or provided to associated (affilated) companies.
2. The reporting threshold for reporting purposes is $250,000. The threshold applies to the annual amount billed to the respondent or billed to
an associated/affilated company for non-power goods and servces. The goo or service must be specific in nature. Respondents should not
attempt to include or aggregate amounts in a nonspecific category such as .general..
3. Where amounts biled to or received from the associated (affliated) company are based on an alloction process, explain in a footnote.
Name of AccountAssiciated/ Affilated Charged orCompany Credited(b) (c)Description of the Non-Power Goo or Service
(a)
1 Non-power Goods or Services Provided by Affilated
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
Amount
Charged or Credited
(d)---------~ -~ -~---- - -~- ------ ~-
Non-power Goods or Services Provided for Affilate
Managerial Expenses which includes labor & taxes
-- --- - - -~ --- ---- --- --
IdaCorp 417420 427,645
Affilates - Ida-West, lerco
IdaCorp Financial Services, IdaCorp Energy
Do not meet the $250,000 threshold
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO.1 (New)
FERC FORM NO.1-F (New)
Page 428
IDAHO POWER COMPANY
2009 FERC FORM 1
ANNUAL REPORT
IDAHO SECTION FOllOWS
December 31, 2009
ANNUAL REPORT
IDAHO SUPPLEMENT TO FERC FORM 1
MUL TI.STATE ELECTRIC COMPANIES
INDEX
Page
Number Title
1 Statement of Income for the Year
2 Taxes Allocated to Idaho
3 Notes and Accounts Receivable
3 Accumulated Provision for Uncollectible Accounts
4 Receivables from Associated Companies
5 Gain or Loss on Disposition of Propert
6 Professional or Consultative Services
7-10 Electric Plant in Service
11 Electric Operating Revenues
12-15 Electric Operation and Maintenance Expenses
15 Number of Electric Department Employees
IDAHO SUPPLEMENT
This Page Intentionally Left Blank
Idaho Power Company
STATE OF IDAHO. ALLOCATED
An Original December 31, 2009
STATEMENT OF INCOME FOR THE YEAR
1. Report amounts for accunts 412 and 413, Revenue and Exnses from Utility Plant Leased to Oters, in another utilit
column (i,k,m,o) in a similar manner to a utilty departent. 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 Utilit Operating Income, in the same manner as accunts 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 the state ment of income or any account thereof.
5. Give concise expanations conceming unsettled rate proceedings whre a contingency exists suc that refunds of a
material amount may nee to be made to the utilits customers or which may result in a material refund to the utilty
wi respect to powr or gas purcases. State for each year affcted 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 wih respect
to power and gas purchases.
6. Give concise exlanations conceming signifcant amounts of any refunds made or received during the year.
(a)
(KeT.)
Page TOTAL
No.\.urrm Tear Previous year
(b)(c)(d)
11 $993,232,456 $910,245,287
15 613,147,331 550,991,682
15 64,769,922 64,078,869
96,284,156 89,690,866
6,307,117 4,622,992
Line
No.
Account
1 UlILiI T
2 Operating Revenues (400)...... ........ .... ...... ....... ......... ....... ..... ..... .................. .......
3 Operating Expenses
4 Operation Expenses (401 )... ...... ... ............... ... ....... .......... .......... ....... ..... ............
5 Maintenanc Expenses (402)............................................................................
6 Depreciation Exense (403)..............................................................................
7 Amort. & Depl. of Utlity Plant (40405)............................................................
8 Amort. of Utilty Plant Acq. Adj. (406)................................................................
9 Amort. of Propert Losses, Unrecovere Plant and
10 Regulatory Study Costs (407).............. ........ ........... ........ ...... ............. .... ...... ....
11 Amort. of Conversion Expenses (407)... ...... ......... ... ......... .................. ..... .........
12 Regulatory DebitCredits (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 Deferrd Income Taxes (410.1 & 411.1) Net............................
17 Investment Tax Credit Adj. - Net (411.4)...........................................................
18 (Less) Gains from Disp. of Utlity Plant (411.6)..................................................
19 Losses from Disp. of Utilty Plant (411.7)...........................................................
20 (Less) Gains from Disposition of Allowances (411.8).........................................
21 Losses frm Disposition of Allowances (411.9).................................................
22
23 TOTAL Utilty Operating Exnses (Enter Total of lines 4 thru 22)..................
24
25 Net Utilty Operating Income (Enter Total of line 2 less 23)
26 (Carr forward to page 11, line 27). ...... ....... ............. .... .......... .... ..... ........ ......
-(3,781,013)
2 18,952,082 17,214,058
2 14,745,212 (1,876,222)
2 1,466,739 (5,091,963)
2 12,847,159 41,638,625
2 223,185 2,343,614
828,742,902 759,831,509
$ 164,489,555 $ 150,413,778
IDAHO SUPPLEMENT Page 1
Idaho Powr Company
STATE OF IDAHO
An Original Dember 31,200
TAXES ALLOCATED TO IDAHO
Kind of Tax
Taxes Other Than Income Taxes:
Labor Related:
FICA...................................................................
FUTA.................................................................
State Unemployment.... .............. ..... .......... ........
Payroll Deducton & Loading. ....... ...... ... .... .......
Total Labor Related................................
Propert Taxes........... ............. ..... ........ ..... ...........
Kilowatt-hour Tax. ....... ...... ....... .............. ..... ..........
Licenses................................................................
Regulatory Commission Fees..... ..... ... ..... ..... ........
Irrgation p~c........... .... ....... ....... ... ........... ........ ......
Total Taxes Other Than Income Taxes..................
Federal Income Taxes. .................. ... ........ ...... ........
State Income Taxes.. .... ............ ....... ..... .... ........ ......
Deferred Income Taxes.... ........... ................. ..........
Investment Tax Creit Adjustment - Net.................
Taxes Charged
During Year
$ 11,450,632
71,113
452,013
(11,973,757)
o
15,834,861
1,522,379
3,467
1,347,232
244,144
18,952,082
14,745,212
1,466,739
12,847,159
223,185
Total Taxes Allocaed to Idaho............................... $ 48,234,376
IDAHO SUPPLEMENT Page 2
Idaho Power Company
STATE OF IDAHO
An Original December 31, 2009
NOTES AND ACCOUNTS RECEIVABLE
Summary for Balance Sheet
Show separately by footnote th total amount of notes and accounts receivable
from directors, offcers, and employees included in Notes Receivable (Accunt
141) and Other Accounts Receivable (Accunt 143)
Balance Baiance
Une Accounts Beginning of End of
Year Year
No.(a)(b)(c)
1 Notes KeclvaDle (ACCUnt 141).................................................................................................:I 1,549,041 :I 536,001
2 Customer Accounts Receivable (Accunt 142)............................................................................64,433,173 76,792,157
3 Other Accounts Receivable (Accunt 143)..................................................................................6,557,937 9,087,713
4 (Disclose any capital stock subscrption received)
5 Total......................................................................................................................................$72,540,152 $86,516,536
6
7 Less: Accumulated Provision for Uncollectible
8 Accounts-Cr. (Account 144)..................................................................................................1,723,936 1,990,343
9
10 Total, Less Accumulated Provision for
11 Uncollectible Accounts. ..... ................... ... ....... ............... ....... ...... ....... ..... ........... ...... ..... .... ....$70,816,216 $84,526,193
12
13
14 Notes Receivable - Accunt 141: (at 12-31-09)
15 Directors, offcers, and employees - $64,154
16
17
18 Otr Accunts Receivable - Accunt 143: (at 12-31-09)
19 Directors, offcers, and employees - $4,014
20
ACCUMULATED PROVISION FOR UNCOLLECTIBLE ACCOUNTS - CR. (Acunt 144)
1. Report below the information calle for concern this accumulated provision.
2. Exlain any importnt adjustments of subaccunts.
3. Entries With respect to offcers and employees shall not include items tor Utility services.
Mase,
Une Item Utlit Jobbing &Ofcers Other Total
Customers Contract and
No.(a)Work Employees
(b)(c)(d)(e)(f)
21
22 Bal. beginning of year $1,723,936 $$1,723,936
23 Prov. for uncollectibles
24 for year...................................................266,407 266,407
25 Accounts written off...... ......... ..... ...... ........
26 Coli. of accunts
27 wrtten off................................................
28 Adjustments (explain)...............................
29
30
31
32 Balance end of year. ..... ....... ....... ......... .....:I l,l:l:U,;j3 :I -:I -:I -:I 1 ,l:l:,343
33
IDAHO SUPPLEMENT Page 3
Idaho Powr Company
STATE OF IDAHO
An Oriinal December 31, 2009
RECEIVABLES FROM ASSOCIATED COMPANIES (Accunt 145. 146)
1. Report partculars of notes and acconts reæivable from associated companis at end of year.
2. Provide separate headings and totals for accunts 145, Notes Reæivable from Associated Companies, and 146,
Accunts Reæivable from Associated Companies, in additn to a total for the combine accunts.
3. For notes receivable list each note separte and sta pu fo whic reive. Show also in coumn
(a) date of note, date of maturi and intet rae.
4. If any note was reive in satisfctn of an op accnt, state th peri covere by such open accunt.
5. Include in column (f) interest recorded as incoe duri th year, inudin interest on accunt and notes
held at any time during the year.
6. Give particulars of any notes pledged or discounte, also of any collateral held as guarantee of payment
of any note or account.
i:aianæ
Una Partculars Beginning Totals for Year Balanæ Interest
of Year ueDl \jreoRS End of Year For Year
No.(a)(b)(e)(d)(e)(f)
1 Accunt 145:
2
3 IERCO....................................$26,579,n1 $38,970,228 $46,655,898 $18,894,101
4
5
6
7
8
9
10 Total Accunt 145............ ........"',""',1 . I ;,,11 fU,;';'ö 40,000,1'110 16,611,1U1
11
12 Account 146:
13
14
15
16 IDACORP, Inc... ... ... ... ... ... ........$(2,011)$3,661,882 $3,659,871 $-
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31 Total Account 146........................:s (",U11):s ::,titi1,lS":s ::,ÖOII,öfl :i -
32
IDAHO SUPPLEMENT Page 4
Idaho Power Company
STATE OF IDAHO
An Original December 31, 2009
STATE OF IDAHO - TOTAL SYSTEM DATA
GAIN OR LOSS ON DISPOSITON OF PROPERTY (Account 421.1 and 421.2)
1. Give a brief desriPtn of propert creting the gain or los. Includ name of part acquiring the proprt (when
acquired by anoher utilit or assiated copany) and the dae transaion was completed. Identify proprt
by ty; Leased, Held for Future Use, or Nonutlit.
2. Indivdual gains or los relating to propert wih an original cot of les than $5,00 may be groupe, wih the
number of such transons disclos in column (a).
3. Give the date of Commission approval of journl entes in column (b), when approval is reuired. Where approval
is required but has not ben recived, giv explanation followng the item in column (a). (se acount 102, Utilit
Plant Purchase or Sold.)
unnai '-J LJle .Journi
Line Deription of Propert of Related Entry Aproved Acct 421.1 Ac421.2
Propert (When Required)
No.(a)(b)(c)(d)(e)
1 Gain on disposition of
2 propert:
3
4
5
6 Norhem SWIP Sale 3,036,68 3/301200 $122,587
7
8
9
10
11
12
13
14 Totl gain..........................................................~3,U36,664 :I l;¿;¿,Otlf
15
16
17 Transmission Line #103 .2100 $(3,973)
18
19
20
21
22
23 · Land purchaed in 1942. Could not identify
24 original co in asst recrds
25
26
27
28
29
30
31 Totl los................................................. ......:I 0 :I (3,973)
IDAHO SUPPLEMENT Page 5
Idho Power Company
STATE OF IDAHO
An Original Deeßdr 31, 2009
STATE OF IDAHO. TOTAL SYSTEM DATA
PROFESSIONAL OR CONSULTATIVE SERVICES -ITEMS $10,000 AND OVER
Une Amounti .,,~~I n'i:
No.(a)(b)(c)
1 ACCENTIENT INC Cor Supprt servces $19,600
2 ADECCO Stag servics 32,478
3 AERO-GRAPHICS Mapping servces 101,076
4 ATER, WYNNE LLP Legal Service 296,322
5 BARKER, ROSHOLT & SIMPSON LLP Legal Seces 414,833
6 BRENNEMAN, JOHN Loby servic 73,626
7 BROWNSTEIN HYATI FARBER SCHREC Legal 5es 719,840
8 BUREAU OF LAND MANAGEMENT Environmental Services 209,284
9 CADMUS GROUP INC, THE Arit seic 24,025
10 CASCADE ENERGY ENGINEERING INC Enginri Servs 81,401
11 CEOARCRESTONE INC Coutr Supprt seivices 72,143
12 CHASAN & WALTON TRUST ACCOUNT Lel servs 400,000
13 CHURCH, JOHN S Ecomi serv 12,000
14 COLLEGE OF IDAHO Environmental servs 13,500
15 COLLEGE OF SOUTHERN IDAHO Environmental Seivics 10,000
16 COMSYS INFORMATION TECHNOLOGY Comuter Supp Serv 194,160
17 CONNOR CLAIMS SPECIALISTS Insranc Servics 11,029
18 CORNERSTONE SYSTEMS INC Coutr Supprt servs 91,400
19 CSHQA Arit Seric 126,704
20 DAVIS WRIGHT TREMAINE LLP Leal serv 389,082
21 DELOITTE & TOUCHE LLP Acnti Ses 642,989
22 DEWEY & LEBOEUF Legl servs 3,308,496
23 DHIINC Environmental Seric 38,235
24 ECOANAL YSTS INC Environmental Servs 107,928
25 ECOS CONSULTING Consulting Seivics 42,238
26 ECOTOPE Aritec Serics 30,256
27 EMC CORPORATION Coputr Support Servs 86,073
28 ENERNOCINC Consultg Seivics 451,808
29 EVANS KEANE Legal Servs 12,471
30 GLAHE & ASSOCIATES INC Environmental Services 34,487
31 GLOBAL INSIGHT Environmntal servs 25,934
32 GOLDER ASSOCIATES Environmental Servs 101,373
33 HARDESTY, REBECCA Enviromental Servs 76,470
34 HDR SSR ENGINEERS Engineering servs 24,166
35 HONEYWELL INTERNATIONAL INC Environmental Seivices 17,419
36 HYQUAL Environmental Seivices 59,054
37 IDAHO DEPARTMENT OF FISH AND G Environmental Servces 100,000
38 INTELUBIND LLC Consultng Seivices 82,285
39 INTERWOVEN INC Computer Suppor Seivices 20,429
40 IOWA INSTITUTE OF HYDRAULICS Consulting Seivices 15,425
41 JACO ENVIRONMENTAL INC Environmental Servs 17,916
42 JONES AND SWARTZ PLLC Legal Servces 158,355
43 JUB ENGINEERS Engineering Servics 15,880
44 MAINLINE INFORMATION SYSTEMS I Computer Support seivices 424,425
45 MAUPIN, COX & LEGOY INC Legal services 18,529
Pa e69
IDAHO SUPPLEMENT
Idaho Power Company
STATE OF IDAHO
AnOñglnal December 31, 2009
STATE OF IDAHO - TOTAL SYSTEM DATA
PROFESSIONAL OR CONSULTATIVE SERVICES - ITEMS $10,000 AND OVER
AmountLinerr .i;i;iy..i:
No.(a)(b)(c)
46 MCCLURE ENGINEERING Engineering Servics $48,459
47 MCDOWELL & RACKNER PC Legal Seics 429,332
48 MIRANDE, MICHAEL Legal Services 57,819
49 MOODY'S ANAL YTICS INC Financil Services 26,500
50 MUSGROVE ENGINEERING PA Engineering Services 88,779
51 NEXNTINC Computer Support Servces 29,702
52 NIELSEN GROUP INC, THE Consulting Servics 227,326
53 ORACLE CORPORATION Computer Support services 219,677
54 OREGON DEPARTMENT OF ENERGY Consulting Services 143,866
55 PAINE, HAMBLEN, COFFIN, BROOK Management Servces 292,698
56 PANTER, GREGORY W Legal Services 33,000
57 PARAGON CONSULTING SERVICES Consulting Services 30,295
58 PARR BROWN GEE & LOVELESS INC Legal Services 36,794
59 PARR WADDOUPS BROWN GEE AND LO Environmental Servs 40,390
60 PEAK SCIENCE COMMUNICATIONS Management Services 42,964
61 PLANNEDSCAPE Consulting Services 18,917
62 PORTLAND ENERGY CONSERVATION,Environmental Services 213,411
63 POWER ENGINEERS INC Engineering Services 45,359
64 PROFESSIONAL TRAINING SYSTEMS Management Services 17,575
65 PUBLIC OPINION STRATEGIES LLC Management Services 17,750
66 RWBECK Consultng Services 64,650
67 RIDDELL WILLIAMS P.S.Legal servics 50,451
68 RIPLEY, LARRY D Legal services 13,650
69 RIVERSIDE TECHNOLOGY INC Management Services 13,000
70 ROGER WRIGHT CONSULTING ENGINE Enginerng Services 13,791
71 S G S STATISTICAL SERVICES Consulting services 14,250
72 SALDIN, TOM Legal Servics 27,000
73 SALLADAY & DAVIS Legal Services 31,584
74 SHARP & SMITH INC.Legal servics 15,692
75 SMITH, CURTIS D Legal Serics 49,890
76 SOFTARE AG INC Computer Supprt Services 91,775
77 SOS STAFFING SERVICES Management Services 20,661
78 SPHERION STAFFING AND RECRUITI Management Servics 88,485
79 SPINK BUTLER LLP Legal Servics 20,851
80 STEPHAN, KVANVIG, STONE & TRAI Legal Services 22,018
81 STEPTOE & JOHNSON LLP Legal services 394,668
82 STOEL RIVES LLP Legal Services 211,579
83 SULLIVAN & CROMWELL Management Services 544,421
84 TEKSYSTEMS Computr Support Servics 51,675
85 TETRA TECH INC Consultng Servics 12,715
86 TIMBERLINE SURVEYING PLLC Surveying Servces 17 ,258
87 TOWERS PERRIN HR SERVICES Management Services 45,140
88 TREASURE VALLEY LEGAL SERVICES Legal Servces 205,645
89 TROUT, JONES, GLEDHILL, FUHRMA Legal Services 38,958
Page6A
IDAHO SUPPLEMENT
Idaho Power Company
STATE OF IDAHO
An Original Dece~er 31,2009
STATE OF IDAHO - TOTAL SYSTEM DATA
PROFESSIONAL OR CONSULTATIVE SERVICES . ITEMS $10,000 AND OVER
Amountline........TYPE
No.(a)(b)(c)
90 UNIVERSITY OF IDAHO Environmental Services 284,065
91 VAN NESS FELDMAN Legl service 218,582
92 VAN WINKLE ENVIRONMENTAL CONSU Envimental Servs 87,148
93 WETHER MODIFICATION INC Clo 5elng 5e 384,716
94 WHITE PETERSON TRUST ACCOUNT Leal Se 50,000
95 YTURRI& ROSE& BURNHAM& BENTZ Legl 5es 35,649
1 IVIAL T4,3B5,724
IDAHO SUPPLEMENT Page 68
Idaho Power Company
STATE OF IDAHO
An Oriinal Decembr 31, 2009
PROFESSIONAL OR CONSULTATIVE SERVICES
ITEMS $5,000 OR MORE BUT LESS THAN $10,000
Line PREDOMINANT
No.PAYEE NATURE OF SERVICE AMOUNT
1 ATREEHOUSE Computer/Pnnter Supplies 5,295
2 Acce AP-Propertservs Prort Senvcs 7,777
3 ASHGROVE CEMENT Constron Service 9,538
4 BERGLES LAW LLC Legal Servs 6,840
5 BOISE STATE UNIVERSITY Enviromental Services 5,000
6 BRASSEY, WETHRELL, & CRAWFORD,Legal servces 5,649
7 BROWN RUDNICK BERLACK ISRAELS Lobby Ses 6,000
8'CTA ARCHITECTS Arcitct Services 8,571
9 DC ENGINEERING, PC Enginnng Serices 9,105
10 DESERT RESEARCH INSTITUTE Environmental 5eces 9,521
11 ENERTECH SERVICES Consulting Servic 9,000
12 ERNST & YOUNG LLP Acunting Servce 6,000
13 HERITAGE ENVIRONMENTAL CONSULT Environmental services 7,855
14 HOPKINS RODEN CROCKETT HANSEN Lobby Serv 6,000
15 JEROME CHEESE CO Managemet serv 8,438
16 JONES CHARTERED Legal Servce 6,633
17 KPMG LLP Acuntng servs 8,36
18 M J BRADLEY & ASSOCIATES LLC Consulting Services 5,812
19 MODULA4INC Computr Supprt servces 9,972
20 PERKINS COlE LLP Leal servce 9,821
21 PHONE PRO Managemet Ser 5,000
22 RAIN SHADOW RESEARCH, INC Consulting Servces 8,834
23 REYNOLDSON GROUP PLLC Legal Servics 7,473
24 SAWTOOTH TECHNICAL SERVICES, I Computr Support Servces 7,9V
25 SOFTWARE HOUSE Computr Support Services 8,901
26 STATISTICAL DESIGN Consultng Servics 5,040
27 STRUCTURED Engineenng Servces 9,800
28 UNIVERSITY OF TEXS AT DALLAS Enviromental servces 7,985
29 WETHER DECISION TECHNOLOGIES Meteorologicl servics 7,968
30 WENGLIKOWSKI, RICHARD F.Survying services 8,109
31 WRUBLE WILDLAND SERVICES Environmental Serics 5,576
32
33
34
35
36
37
38
39
40
41
40
41
42
43
44
40 IIUIAL ,
P8 e 6C9
IDAHO SUPPLEMENT
Idaho P_r Company
STATE OF IDAHO. ALLOCATED
An Original Deember 31,209
ELECTRIC PLANT IN SERVICE (Accunt 101,102,103 and 106)
1. Report belo th oral cost of el plan in serv acrdng to the prescbe acnts.
2. In addit to Accun 101, Elec Plant in Sei (Classi), this pae and the next incude Accnt 102, Elecri Plant
Purchase or So; Accunt 103, Experintl E1ct Plant Uncif; and Accunt 106, Compleed Constructon
Not Clasifed. Elec.
3. Incud in comn (c) or (d), as appro, coons of addi and rent fo aie currt or prein year.
4. Enclse in parnteses crit adjust of pla acnt to indic the negat efec of such accunt.
5. Clasif Accun 106 acrdin to pn acnt, on an es ba if nesery, and inc the enris in
column (c) . Als to be indudad in comn (c) ar en fo re of te dins of prr year reported in
column (b). Likew, if the repont ha a si am of pl remets tha end of th yea, include in
column (d) a tent di of such re, on an es ba, wi appropri cont entry to the acunt
for acula deprn pr. Incl al in comn (d) re of ten disuts of prr year of un-
clssifed rerent. Att supp st shong th acnt di of the tentve c1assificns in
columns (c) and (d), inudg th re of th pr yers te acnt disuts of th amounts. Careulob-
servance of the abo instctns and the te of Acc 101 an 106 wi av seris omissins of th reported amount
of respondenfs plant acually in serv at en of yer.
une
No.
Accnt
(a)
t:aJance at
Beginning of yea
(b)
Additns
(c)1 1.
2 (301) Organization.......................................................................................................
3 (302) Franchise and Consent..................................................................................
4 (303) Miscenes Intibl PI.........................................................................
5 TOTAL Intngible Plant (Entr Tot of li 2. 3, and 4)..........................................
6 2. PRODUCTION PLANT7 A. Stam Prouc Plnt
8 (310) Land and Land Right........................................................................................
9 (311) Struclure an Imprvement...........................................................................
10 (312) Boilar Plant Equipnt.......... ... ....................................................... ..................
11 (313) Engines and Engine Dnven Gera............................................................
12 (314) Turbogeraor Unit.........................................................................................
13 (315) Accss Ele Equipment...........................................................................
14 (316) Misc. Powr Pl Equipment............................................................................
15 (317) Asset Retirement Cost for Steam Proucn... ... ... ... ... ... ... ... .'. '.. ... ... .....
16 TOTAL Steam Producton Plant (Enter Totl oflnes 8thru 15)................................17 B. Nuc Prouctn Pla
18 (320) Land and Land Right........................................................................................
19 (321) Structures and Improvement...........................................................................
20 (322) Reacor Plant Equipment...................................................................................
21 (323) Turbgenera Unit.........................................................................................
22 (324) Accsory El Equipnt.............................. .............................................
23 (325) Misc. Powr Plant Equiment............................................................................
24 (326) Asse Retirement Cos for Nuclr Pron... ... ... ... ... ... ..... ...... ...... .....
25 TOTAL Nuclar Proucn Plant (Enter Tot of lis 17thru 24)............................26 C. Hydraulic Prouctn Plnt
27 (330) Land and La Rights........................................................................................
28 (331) Structures and Imprvements........ ..... ............ ...... .... ........ ..... ..... ..... ....... ..........
29 (332) . ReselVirs, Dams. and Waterways...................................................................
30 (333) Water Whees, Turbines. and Generaors.........................................................
31 (334) Accssory Elenc Equipent...... ......... ... ....... ............ ...... .......... ............ ..........
32 (335) Misc. Power Plant Equiment............................................................................
33 (336) Roads, Raioas, and Booges..........................................................................
34 (337) Asse Retirement Cost for Hydraic Proucn... ... ... ... ... ... ....... ....... ......
35 TOTAL Hyrauli Prouc Plant (Ent Tot of lies 27thru 34).........................36 D. Oter Prouc Pla
37 (340) Land and Land Right........................................................................................
38 (341) Struclures and Improvemnt...... ... ....... ...... ......... .... ........................ ... .............
39 (342) Fuel Holder, Producls and Accsoris..........................................................
40 (343) Pnme Movers.....................................................................................................
41 (344) Generaors...........................................,.............................................................
42 (345) Accssry Elecnc Equipment...........................................................................
43 (346) Mise Powr Plant Equipent.............................................................................
~age7
$ 51,819
20,695,155
30,625,097
51,372,071
4,378,761
IDAHO SUPPLEMENT
Idaho Power Company
STATE OF IDAHO. ALLOCATED
An Original December 31, 2009
ELECTRIC PLANT IN SERVICE (ACCunts 101, 102, 103 and 106) (Contnued)
Show in column (f) reclssifons or transfers wihin utit plant acnt. Include also in column
(f) the additns or reucions of pnmary accunt clssifcaions ansing from dlstnbion of amounts
initlly rerdd In Accunt 102. In showg the clearance of Accunt 102, include in coumn (e) the
amounts wih raspecl to accumulated provision for depreation, acquisitn adjustent, etc., and sho
in column (f) only the ofset to the debits or crits diuted in column (f) to pnmary accunt clssicaions.
For ACCunt 399, stte the naure and use of plant included in this accunt and if subslantal in amont
submit a supplementary staement shong subaccunt classtin of such plant conforming to the
reuireents of these pages.
For each amount compnsing the reported bance and changes in Accnt 102, ste the prort purcase
or so, name of vendor or purchaser, and dae of transacton. If propo joumal entries have been filed
wih the Commission as required by the Uniform System of Accunts, giv also date of such fiting.
tlalance at Uoe
Retremens Adjustents Transfrs End of Year
(d)(e)(f)(g)No.
1
$(42,600)(301)2
20,610,043 (302)3
32,188,432 (303)4
v_,.vv,v.5
6
7
(310)8
(311)9
(312)10
(313)11
(314)12
(315)13
(316)14
3,639,403 (317)15
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 Por Company STATE OF IDAHO. ALLOCATED
An Orinal Dember 31, 2009
Line
ELECTRIC PLANT IN SERVICE (Acc 101,102,103 and 106) (Contued)
AccuntNo. (a)
44 1(346) MISC. Powr i-iam i:quipmem.............................................................................
45 TOTAL Other Proucton Plant (Entr Tot of lies 37 thru 44).............................
46 TOTAL Prouct Plt (Entr Tot of li 16,25,35, an 45)..........................47 3. TRMISSION PLA
48 (350) Land and Land Riht.........................................................................................
49 (352) Structre and Imprnt..... ................................................................... ....
50 (353) St Equi................. ..................................................................... .........
51 (354) Tow and Fixre............................................................................................
52 (355) Poles an Fixure...... .................... ......................................... ........... ......... ... .....
53 (356) Overhead Conductrs and Devi...................................................................
54 (357) Underground Condui...... ... ..... ............ ....................................... ... ...... ..... ... ........
55 (358) Underground Conductors and Devics..............................................................
56 (359) Roas and TraUs.................................................................................................
57 (359.1) Asset Retment Cost for Transmission Pla... ...... ... ...... ..... ... ... ... ... ...
58 TOTAL Transmision Plant (Entr Tot of li 48 thru 57)............. ............. .... .....
59 4. DISTIBUTON PLANT
60 (360) Land and Land Right.........................................................................................
61 (361) Strctre and Imprve............................................................................
62 (362) Staon Equiment........... ................................. .................................. ..... ..... .......
63 (363) Storae Batiy Equipen...................................................................... ...........
64 (36) Pols, Towrs, and Fixre................................................................................
65 (365) Overhea Conucrs an De...................................................................
66 (366) Underond Conduit..........................................................................................
67 (367) Undergrond Conduct and Devi................................ .... ..... ..... ......... .......
68 (368) Line Transfrs...............................................................................................
69 (369) service...............................................................................................................
70 (370) Meter..................................................................................................................
71 (371) Instlatns on Custmer Premiss...................................................................
72 (372) Lease Pro on Custmer Premise...........................................................
73 (373) Stre Lighting and Signal Sysems.... ........................................ ............. ..... ......
74 (374) Aset Retment Costs for Din Plnt... ... ...... ... ........ ... ... ... ... ... ...
75 TOTAL Distnbn Plant (Entr Tot of li 60 th 74).......................................76 5. GENERAL PLANT
77 (389) Land and Land Rights.......................................................................... ... ............
78 (390) Stures and Impr........................................................... .................
79 (391) Ofce Furnure and Equipmen............................................... ......... ........ .........
80 (392) Transport Equipnt...................................................................................
81 (393) Stores Equipment................................................................................................
82 (394) Tools, Shop, and Garage Equipment.................................................................
83 (395) Laboiy Equipment........ ... .................... .... ....... .................. ..... ...... ... ......... .....
84 (396) Powr Opera Equiment..............................................................................
85 (397) Communin Equipment.................................................................................
86 (398) Miscllaneous Equipment...................................................................................
87 SUBTOTAL (Enter Tot of lines 77 thru 86)............................................................
88 (399) Other Tangibl Propert......................................................................................
89 (399.1) Ass Retrement Costs for Genera Pl... ... ... ... ... ... ..... ... ...... ... ... ...
90 TOTAL Gener Plant (Enter Totl of fine 87, 88 an 89).....................................
91 TOTAL (Accunts 101 and 106)........................................................................
92 (102) EIe Plant Purcased ....................................................................................
93 (Less) (102) El Plat Sole!..................................................................................
94 (103) Exment Plant Unclssif.........................................................................
95
96 TOTAL Eleri Plant in Service...............................................................................
page 9
Balance at
Beginning of year
(b)
Additions
(c)
:I '''',U''',''''''
1 ,655,391 ,322
29,508,846
35,140,814
242,900,194
117,045,225
77089,121
126,757.259
259,733
628,701,192
4,477,141
23,233,750
158,476,358
193,280,200
108,838,821
46,743,899
176,439,252
347,244,209
52,673,244
56,87,653
2,319,885
3,943.911
1, ". ,'"''.''''''
10,029,463
66,136,218
42,518,018
54,120.844
1,095.243
4,453,928
9,922,115
8,033,807
24,184,365
3,803,267
""","'" ,,,....
224,297,268
3,733,i:;iu,1 (0
IDAHO SUPPLEMENT
$ 3,733,920,176
Idaho Power Company
STATE OF IDAHO - ALLOCATED
An Original Deember 31. 200
ELECTRIC PLANT IN SERVICE (Accunts 101,102,103 and 106) (Contnued)
i:aiance at Line
Retirements Adjustments Transfers End of Year
(d)(e)(f)(g)No.
(34l5)44
$45
46
47
26,355,337 (350)48
36,874,135 (352)49
259,189,976 (353)50
118,781,110 (354)51
78,699,437 (355)52
130,470,816 (356)53
(357)54
(358)55
259,091 (359)56
(359.1)57
58
59
4,464,403 (360)60
25,428,370 (361)61
171,224,978 (362)62
(363)63
198,384,439 (364)64
112,606,744 (365)65
47,630,314 (366)66
183,885,941 (367)67
365,533,296 (368)68
53,584,402 (369)69
76,159,662 (370)70
2,428,221 (371)71
(372)72
4,035,560 (373)73
(374)74
1,245,Jll5,330 75
76
9,965,131 (389)n
70,985,209 (390)78
37,605,449 (391)79
54,565,482 (392)80
1,232,339 (393)81
4,861,786 (394)82
10,696,887 (395)83
8,556,954 (396)84
25,366,534 (397)85
3,912,553 (398)86
227,948,323 87
(399)88
(399.1)89
227 ,1l11,323 90
3,IlO3,014,404 91
(102)92
(102)93
(371)94
95
1$3,853,514,454 96
Pa 8109
IDAHO SUPPLEMENT
Idaho Power Company
STATE OF IDAHO . ALLOCATED
An Oriinal Decembr 31,2009
ELECTRIC OPERATING REVENUES (Accunt 400)
1. Report below operating revenues for each prescbe accunt, and manufare gas revenues in total.
2. Report number of customers, columns (f) and (g), on th basi of meters, in additn to the number of flat rate
accunts; excet that where separate mete reings are adde for billig purp, one customer should be counted
for each group of mete adde. Th average number of custo mens th average of twlve fiures at the dose
of each month.
3. If previous year (columns (c), (e) an (g), are no deri fr prvisl reported fiures, explain any
inconsistencies in a footnote.
OPERATING REVENUES
Amount for
Currnt Year
Amunt fo
Previous YearNo.
(a)1 sales of Elecit
2 (440) Residential Sales................................................................. $
3 (442) Commercal and Indusbil Sale
4 Small (or Commercil)(8e Instr. 4) (1).......................................
5 Large (or Industrial)(See Instr. 4) (2)...........................................
6 (44) Public Street and Highwy Ughtng......................................
7 (445) Other Sales to Public Autorties..........................................
8 (446) Sales to Railroads and Railwys..........................................
9 (448) Interdepartmetal Sales.......................................................
10 TOTAL Sales to Ultimate Consumers...... ........ .................. .......
11 (447) Sales for Resale. Opportunity.... Non-Firm Only..................
12 TOTAL Sales of Electrici........................................................
13 (449) Provision for Rate Refnds.................................................
14 TOTAL Revenue Net of Provisin for Refs.........................
15 Oter Operating Revenues
16 (450) Foneited Discount..............................................................
17 (451) MisceUaneous service Revenues.........................................
18 (453) sales of Water and Water Power.........................................
19 (454) Rent from Electric Propert..................................................
20 (455) Interdepartmental Rents.......................................................
21 (456) Other Electc Revenues......................................................
22
23
24
25 TOTAL Other Operating Revenue..........................................
26 TOTAL Electric Operating Revenues......... .......... ..................... $
(b)(c)
396,249,589 $341,596,320
326,270,298
130,739,702
3,115,326
294,564,569
113,125,182
2,784,169
856,374,915 *
86,951,072
943,325,987
(2,333,063)
940,992,924
752,070,239
113,059,123
865,129,362
(5,876,173)
859,253,189
3,738,436 3,611,150
16,297,224 16,916,322
32,203,871 30,464,627
52,239,531
993,232,456 $
50,992,098
910,245,287
(1) Commercal and Industrial sales - Small - under 1,000 KW and indudes aU irration customers.
(2) Commercial and Industral sales - Larg - 1,000 KWand over.
Page 11
IDAHO SUPPLEMENT
Idaho Power Company
STATE OF IDAHO. ALLOCATED
An Oriinal Decen1r 31,2009
ELECTRIC OPERATING REVENUES (Accunt 400) (Continued)
4. Commerial and Industrial Sales, Accunt 442, may be dassifd accrding to the basis of dassification
(Small or Commercal, and Large or Industrial) regularly used by the respondent if such basis of classifcation
is not generally greater than 1000 Kw of demand. (See Accnt 442 of the Unifrm System of Accunts. Explain
5. See page 108, Importnt Changes During Year, for importnt new terrtory added and impoant rate increases or
decrases.
6. For lines 2, 4, 5, and 6, see page 304 for amounts relating to unbiled renue by accunts.
7. Indude unmetered sales. Provide details of such sales in a footote.
KILOWATI HOURS SOLD AVERAGE NUMBER OF CUSTOMERS PER MONTH
Amount for
Currnt Year
Amount for
Previous Year
(e)
Amount for
Currnt Year
Number for
Previous Year
(d)(f)(g)
Line
No.
5,094,579,185 5,093,471,949 391,759 389,177
5,260,695,289
2,889,807,183
30,137,604
5,648,670,010
3,101,515,627
29,990,161
76,494
120
1,353
75,605
114
1,237
13,275,219,261 **
2,689,972,558
15,965,191,819
13,873,647,747
1,946,246,652
15,819,894,399
469,726 466,133
N/A N/A
469,726 446,889
1
2
3
4
5
6
7
8
9
10
11
12
13
. Indude $ 6,293,431 unbilled revenues.
** Indudes -1,375,287 KWH relating to unbilJed revenues.
Lines 11 through 21 are on an "alloted" basis.
Page 11a
IDAHO SUPPLEMENT
Idaho Power Company
STATE OF IDAHO - ALLOCATED
An Original December 31,200
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
IT me amount TO previous yer IS nOt aenvea Trom preiousiy reportea TigUre, exain in rotnotes.
iune
No.Previous Year
(C)
Accnt
(a)
1. POWER PRODUCTION EXPENSES1" A.
3 Operation
4 (500) Operation Supervision and Engineng.......................................................................
5 (501) Fuel................................................................................................................................
6 (502) Steam Expenses.......................:...................................................................................
7 (503) Steam frm Oter Sourcs................. ......................................... .................................
8 (Less) (504) Steam Transferr-Cr........................................................................................
9 (505) Elecc Expenses............................................................................................... ...........
10 (506) Miscellaneous Stem Powr Exnss.......................................................................
11 (507) Rents..............................................................................................................................
12 (509) Allowncs.....................................................................................................................
13 TOTAL Operation (Enter Totl of lins 4 thru 12)............................................................
14 Maintenance
15 (510) Mainteance Supervision and Engneeng..................................................................
16 (511) Maintenance of Strctre..... ... ....... .... ....... ........ ......... ...... ... ....... ......... .......... ........ ......
17 (512) Maintenance of Boiler Plant.........................................................................................
18 (513) Maintenance of Electc Plant.....................................................................................
19 (449) Provision for Rate Refunds..........................................................................................
20 TOTAL Maintenance (Enter Totl of Lines 15 thru 19)....................................................
21 TOTAL Powr Prouctn ExnseStm Powr (Enter Totl of lines 13 and 20)....
22 B. Nuclear Powr Geeration
23 Operation
24 (517) Opera Supervsion and Engineng.......................................................................
25 (518) FueL........... ..................................................................................................................
26 (519) Coolants and Water......................................................................................................
27 (520) Stem Expenses...........................................................................................................
28 (521) Steam fro Oter Sourc...........................................................................................
29 (Less) (522) Stem TranserrCr........................................................................................
30 (523) Elecri Expenses..........................................................................................................
31 (524) Misclanes Nucear Powr Exnses.....................................................................
32 (525) Rents..............................................................................................................................
33 TOTAL Operation (Enter Total of lines 24 thru 32).........................................................
34 Maintenance
35 (528) Maintenance Supervision and Engineng........................ ..........................................
36 (529) Maintenance of Strctures........................... .................................................................
37 (530) Maintenance of Reactr Plant Equipent.......................... ........................................
38 (531) Maintnanc of Elecc Planl.....................................................................................
39 (532) Maintenance of Miscellanes Nucr Plant............................................................
40 TOTAL Maintenance (Enter Totl of line 35 thru 39)....................................................
41 TOTAL Powr Proucton ExpenseNuclr Pow (Ent Totl of line 33 an 40).
42 C. Hydraulic Powr Generatin
43 Operation
44 (535) Operatin Supeision and Engineering................................. ......................................
45 (536) Water for Powr............................................................................................................
46 (537) Hydraulic Expenses......................................................... ........ ......................................
47 (538) Electic Exenses........ ............................................................. .....................................
48 (539) Miscellaneous Hydraulic Power Generation Expenses...............................................
49 (540) Rents............................. ................................ .......... ............. ..... ................................ .....
50 TOTAL Operation (Enter Totl of lines 44 thru 49).........................................................
Currt Year
(D)
$1,730,026 $1,585,144
123,530,408 108,989,376
7,051,991 6,491,790
2,436,169 2,002,446
7,732,363 7,681,857
490,668 281,610
14õ!,l:/1,tUO 127,032,223
1,975,511 2,456,682
464,737 618,172
12,971,894 13,885,052
3,410,225 5,395,860
4,422,214 5,650,640
23,244,050 28,
ltltl,õ!ltl,õ!UO 155,
4,996,334
6,839,199
9,622,038
1,400,051
2,561,153
359,232
4,984,055
4,814,932
9,016,462
1,323,535
2,690,247
399,555
23,228,787
Page 12
IDAHO SUPPLEMENT
Idaho Power Company
STATE OF IDAHO - ALLOCATED
An Oriinal December 31,2009
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
IT me amount Tor previous year is not aenvea rrm preiousiy reponea T1ures, expiain in roomo.
Line
No.Accunt Currnt Year Previous Year
tai tD)tC)
51 C. Hydraulic Power Generation (Continued)
52 Maintenance
53 (541) Maintnance Supervsion and Engineering....................................................................$1,975,236 $1,785,723
54 (542) Maintenance of Strctre...............................................................................................1,331,517 1,220,450
55 (54) Maintnance of Resrvoirs, Dams, and Waterwys.......................................................1,079,628 515,125
56 (54) Mainnanc of Elecc Plant.........................................................................................2,819,107 1,988,155
57 (545 Maintenance of Miscllaneus Hydraulic Plant..............................................................2,832,668 2,630,881
58 TOTAL Maintenance (Enter Totl of lines 53 thru 57)........................................................10,038,157 ll,14Ù.333
59 TOTAL Powr Proucton Exnss-Hydraulic Pow (Enter Totl of lines 50 and 58)...3~,ö 1 ö;i-31,3ö~,11~
60 D. Oter Power Generation
61 Operation
62 (546) Opon Supervision and Enginering.........................................................................331,668 325.262
63 (547) FueL................................................................................................................................18,336,546 18,492,527
64 (548) Generation Expens.......................................................................................................385,488 363,281
65 (549) Miscllaneous Oter Power Generation Exnses.........................................................305,054 442.565
66 (550) Rent.................................................................................................................................0 -
67 TOTAL Opraon (Entr Totl of lines 62 thru 66).............................................................19,358,755 ,
68 Maintenance
69 (551) Maintenanc Supervsion and Engineering....................................................................0 .
70 (552) Maintenance of Strctres...............................................................................................185,036 209.865
71 (55) Maintnance of Generating and Elecc Plant................................................................497,807 40.597
72 (55) Maintnanc of Misclaneous Oter Powr Generon Plant....................................1.630,541 614.836
73 TOTAL Maintnanc (Enter Totl of lines 69 thru 72).......................................................2,313,384 8ö~,2lll
74 TOTAL Power Procucon Expesesr Powr (Enter Totl of line 67 and 73)..........21,672.139 ,
75 E. Other Power Supply Exnses
76 (555) Purchase Powr.............................................................................................................152.316,715 288,699,422
77 (55) Sysm Control and Loa Dispatching............................................................................12,528 73,778
78 (557) Oter Expenses................................................................................................................73,149,445 (112,995,170)
79 TOTAL Oter Powr Supply Expese (Entr Totl of lines 76 thru 78)...........................lf~.(fQ,030
80 TOTAL Powr Producton Expens (Entr Totl of lines 21, 41, 59, 74, and 79)............44~, 1 ö3,l96 3ö2,ö 14, fl3
81 2. TRANSMISSION EXPENSES
82 Opration
83 (56) Opraion Supervision and Enginering.........................................................................2.146.091 1,987.843
84 (561) Load Dispatching........................................... ..................................................................2,232,972 2.806.393
85 (56) Station Expense..............................................................................................................1,658,371 1,491,967
86 (56) Overhead Line Expnses.................................................................................................763,563 784,669
87 (56) Undrground Line Exnses...........................................................................................
88 (565) Transmission of Electcit by Oters..............................................................................6,287,468 9,936,576
89 (56) Miscellaneos Transmission Expns..........................................................................327,409 529.755
90 (567) Rents.................................................................................................................................1,324.828 990,555
91 TOTAL Opetion (Enter Totl of lines 83 thru 90).............................................................14,14U,I08 1ö,~2/./~ö
92 Maintenance
93 (568) Maintenance Supervsion and Engineering....................................................................499,815 376,412
94 (569) Maintenance of Structres...............................................................................................327,684 387,193
95 (570) Maintenance of Station Equipment..................................................................................2,556,220 2.473,911
96 (571) Maintnance of Ovrhad Lines......................................................................................2,471.315 1,987,795
97 (572) Maintenance of Underground Lines................................................................................
98 (573) Maintenance of Misclaneous Transmisson Plant......................................................32 2,151
99 TOTAL Maintenance (Enter Totl of lines 93 thru 98)........................................................0,al,4o¿
100 TOTAL Transmission Expses (Enter Total of lines 91 and 99)......................................2U,~~~.1I4 23,/OO,22U
101 3. DISTRIBUTION EXPENSES
102 Operation
103 (580) Operaon Supervision and Engineering.........................................................................3,141.623 3,141,021
Page 13
IDAHO SUPPLEMENT
Idaho Power Company
STATE OF IDAHO. ALLOCATE
An Original Deefber 31,2009
ELECTRIC OPERATION AND MAINTNANCE EXPENSES
IT me amoum TO previous yer IS no ae rr pre reeo ngure, exn in fooines.
Line
No.Acnt Currnt Year Previous Year
ia)lD)iei
104 3. DISTRIBUTION EXPENSES (Cotinue)
105 (581) Loa Dispatching...........................................................................................................$3,014,735 $2,906,722
106 (582) Station Expenses................. ..........................................................................................1,072,819 1,066,301
107 (583) Overhead Line Exnse............................... ...............................................................3,169,511 3,172,327
106 (584) Underground Line Exnses........................................................................................1,885,378 2,085,453
109 (585) Strt Lightng and Signal System Exnses...............................................................128,093 141,411
110 (586) Meter Expeses.................. ...........................................................................................4,309,928 4,332,721
111 (587) Custoer Installations Expenses..................................................................................1,217,628 1,227,727
112 (588) Misclaneos Distrbution Exnses............. ..............................................................4,682,137 5,187,236
113 (589) Rents..............................................................................................................................288,975 604,482
114 TOTAL Operatin (Ente Totl of line 103 th 113)......................................................~~,~.v,v~.23,
115 Maintenance
116 (590) Maintenanc Supervision and Engineri..................................................................290,469 246,198
117 (591) Maintenance of Stre............................................................................................23,673 -
118 (592) Mantenance of ston Equipment...... ................. ......................................................3,186,911 3,322.976
119 (593) Maintenance of Overead Lines...................................................................................13,336,846 11,557,647
120 (594) Maintenance of Underground Lines.............................................................................1,066,017 1,328,521
121 (595) Maintenance of Line Transforers...............................................................................373,749 154,268
122 (596) Maintenance of Street Lighting and Signal Systems....................................................476,614 453,194
123 (597) Maintenance of Met..................................................................................................685,447 888,231
124 (598) Mainteance of Miscllneous Distr Pla........................................................244,352 114,582
125 TOTAL Maintenanc (Enter Totl of lines 116 thru 124)..................................................18,065,618
126 TOTAL Distnbution Exses (Ente Totl of lin 114 and 125)....................................42,574,90 41,831,018
127 4. CUSTOMER ACCOUNTS EXPENSES
128 Operaon
129 (901) Supervision....................................................................................................................357,284 435,36
130 (902) Meter Reading Exense............................. .................................................................5,092,915 5,146,950
131 (903) Customer Recs and Collecon Exnses...............................................................12,604,114 7,86,032
132 (904) Uncolleble Accunts..................................................................................................5,092,669 1,876,639
133 (905) Miscllaneous Custor Accunt Exnse.............................................................533 320
134 TOTAL Customer Accnts Expenses (Enter Totl of lines 129 thru 133)......................23,147,imi 15,325,300
135 5. CUSTOMER SERVICE AND INFORMATIONAL EXENSES
136 Operation
137 (907) Supervision....................................................................................................................257,106 299,100
138 (908) Customer Asistnce Expense..... ..............................................................................40,542,279 21,710,324
139 (909) Inrmtional and Instrctonal Exenses. ..... ..... ..... ...... ...... ............. ........ ......... ..... ......15,511 0
140 (910) Miscllnes Customer Seric and Infl Exse...................................836,024 876,111
141 TOTAL Cust. Serice and Informtional Ex (Ente Totl of lins 137 thru 140)....22,885,534
142 6. SALES EXPENSES
143 Operatin
144 (911) Supeision......... .............................................................................. .............................
145 (912) Demonstrting and Selling Expenses...........................................................................
146 (913) Adversing Exnse.......... .................................................. ........................................
147 (916) Misclaneous Sales Expnses....................................................................................
148 TOTAL Sales Expnses (Enter Total of lines 144 thru 147).............................................
149 7. ADMINISTRATIVE AND GENERAL EXPENSES
150 Operation
151 (920) Administrtive and General Salanes....................................... ............. ............... .........57,849,175 46,724,352
152 (921) Ofce Supplies and Expenses............. .... .....................................................................11,682,289 16,697,245
153 (Less) (922) Administrtie Expenses Transferr-Credit................ ... ........ ......... ...............(26,136,870)(26,005,639)
Page 14
IDAHO SUPPLEMENT
Idaho Power Company
STATE OF IDAHO. ALLOCATED
An Original December 31,2009
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
IT me amount Tor previous year is not aenvea rr previousiy reporteo Tigures, expiain in TooOtes.
I Line I'IIUUIIIUl
No.Accunt Currnt Year Previos Year
tai tOI tCI
154 7. ADMINISTRATIVE AND GENERAL EXPENSES (Continued)
155 (923) Outide Service Employed......................................................... .... .............................$7,093,497 $10,542,564
156 (924) Property Insurance.......... ....... ............... ...................................... ......................... .........3,046,423 2,957,019
157 (925) Injuries and Damages..... .......... ........................................................................... ..... ....6,381,755 5,113,519
158 (926) Employee Pensions and Benefits.................................................................................29,122,006 26,159,168
159 (927) Franchise Requirements...... ................. ............................................................... .........3,196 1,200
160 (928) Regulatory Commission Expenses....... ....................... ...................................... ...... .....4,579,316 5,332,170
161 (929) Duplicae Charges-Cr.. ...... ............................................................... .............................
162 (930.1) General Advertsing Expenses...................................................................... ... .........148,379 487,897
163 (930.2) Miscllaneous General Expses.......... .......................................................... .........3,340,110 3,282,233
164 (931) Rents..............................................................................................................................1,009 10,731
165 TOTAL Operation (Enter Total of lines 151lhru 164).......................................................117,110,285 1:1,;'U;¿,40tl
166 Maintenance
167 (935) Maintenance of General Plant............................................. ........................... ...... ........3,654,659 3,498,047
168 TOTAL Admin and General Expenses (Enter Total of lines 165-167)... ... ... ... ... ... ... ...100,754~
169 TOTAL Elec Op and Maint Exp (Total of 80,100,126,134,141,148,168)...... ... ... ....$677,917,253 $Otl1,;'(;¿,;¿I:"
IDAHO ONLY
NUMtlt:K ui- t:Lt:t; i KIt; Ut:I"AK I Mt:N i t:MI"LUYt:t::s
1. i ne oata on numDer or empioyees snouia De repoll TOr me payroii penoa enaing nearest to UCoDer ;'1,
or any payrii penoo enoing tlU aays Deore or auer uClooer ;'1.
;¿. IT me responaenrs payrOll Tor me reortng penoa inciuoes any speiai constron pennei, inClua
suen emplOyees on line ;" ana snow me numDer OT sucn speai cosuucn empioees in a Tooe.
;:. i ne numoer OT empioyees assignaoie to me electc oepartent Trom Joint TUnCtOnS Of comoinaun Utlmes
may De oeterminea oy estimate, on me oasis OT empioyee equivaients. :snow me estimatea numDer OT equiv-
aient employees anriDUtea to tne eiecc aepartnt Tro Joint TUnCtons.
1 Payroll Period Ende (Date)...................................................................................................December 31, 2009 Deceber 31, 2008
2 Total Regular Full-Time Employees.......................................................................................1,979 2,006
3 Total Part-Time and Temporary Employees..........................................................................24 20
4 Total Employees...................... ............................. ............. .................. .......................... ..........2,003 2,026
Page 15
IDAHO SUPPLEMENT
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