2011Annual Report.pdf

THIS FILING IS
Item 1: N An Initial (Original) OR F1 Resubmission No.
Submission
I PC - ~5
Form I Approved
OMB No. 1902-0021
(Expires 12/31/2014)
Form 1-F Approved
OMB No. 1902-0029
(Expires 12/31/2014)
Form 3-Q Approved
OMB No. 1902-0205
(Expires 05/31/2014)
* II
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) Year/Period of Report
Idaho Power Company End of 2011 /Q4
FERC FORM No.113-Q (REV. 02-04)
Deloitte & Touche UP
101 South Capitol Blvd.
Suite 1700
Boise, ID 837027734
USA
Tel: [phone]
Fax: [phone]
www.deloitte.com
I I I'] I f_IJiJ I (SI I 1 I
Idaho Power Company
Boise, Idaho
We have audited the balance sheet - regulatory basis of Idaho Power Company (the "Company") as of
December 31, 2011, and the related statements of income - regulatory basis, retained earnings -
regulatory basis, and cash flows - regulatory basis, for the year then ended, included on pages 110
through 123 of the accompanying Federal Energy Regulatoy 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 as established by the
Auditing Standards Board (United States) and in accordance with the auditing standards of the Public
Company Accounting Oversight Board (United States). Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements are free of material
I

misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its
internal control over financial reporting. Our audit included consideration of internal control over
financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but
not for the purpose of expressing an opinion on the effectiveness of the Company'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 Commission as set forth in its applicable Uniform System
of Accounts and published accounting releases, which is a comprehensive basis of accounting other than
accounting principles generally accepted in the United States of America
In our opinion, such regulatory-basis financial statements present fairly, in all material respects, the
assets, liabilities, and proprietary capital of the Company as of December 31, 2011, and the results of its
operations and its cash flows for the year then ended, 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 Regulatoy Commission and is not intended to be and
should not be used by anyone other than these specified parties.
I
R,
February 22, 2012
Daterouch.Tohmatsu Lmud
THIS PAGE INTENTIONALLY LEFT BLANK
FERC FORM NO. 113-Q:
REPORT OF MAJOR ELECTRIC UTILITIES, LICENSEES AND OTHER
IDENTIFICATION
01 Exact Legal Name of Respondent 02 Year/Period of Report
Idaho Power Company End of 201 1 /Q4
03 Previous Name and Date of Change (if name changed during year)
/-
04 Address of Principal Office at End of Period (Street, City, State, Zip Code)
1221 W Idaho St, P.O. Box 70 Boise, Id 83707-0070
05 Name of Contact Person 06 Title of Contact Person
Ken Petersen Coporate Controller and GAO
07 Address of Contact Person (Street, City, State, Zip Code)
1221 W Idaho St, P.O. Box 70 Boise, Id 83707-0070
08 Telephone of Contact Person,Including 09 This Report Is 10 Date of Report
Area Code (1) Z An Original (2) D A Resubmission (Mo, Da, Yr)
[phone] 04/13/2012
ANNUAL CORPORATE OFFICER CERTIFICATION
The undersigned officer certifies that
I have examined this report and to the best of my knowledge, information, and belief all statements of fact contained in this report are correct statements
of the business affairs of the respondent and the financial statements, and other financial information contained in this report, conform in all material
respects to the Uniform System of Accounts.
01 Name 03 Signature 04 Date Signed
Ken Petersen (Mo, Da, Yr) 02 Title
Coporate Controller and CAO Ken Petersen 04/1312012
Title 18, U.S.C. 1001 makes it a crime for any person to knowingly and willingly to make to any Agency or Department of the United States any
false, fictitious or fraudulent statements as to any matter within its jurisdiction.
rF(L., rURIVI NO.11$-LJ (KtV. U2-04) Paae 1
Name of Respondent
Idaho Power Company
This Re ort Is:
(2) AResubmission
Date of Report Year/Period of Report
End of 2011/Q4
LIST OF SCHEDULES (Electric Utility)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Line
No.
-
Title of Schedule
(a)
Reference
Page No.
(b)
Remarks
(c
1 General Information 101
2 Control Over Respondent 102
3 Corporations Controlled by Respondent 103
4 Officers 104
5 Directors 105
6 Information on Formula Rates 106(aXb)
7 Important Changes During the Year 108-109
8 Comparative Balance Sheet 110-113
9 Statement of Income for the Year 114-117
10 Statement of Retained Earnings for the 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 Activities 122(aXb)
14 Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep 200-201
15 Nuclear Fuel Materials 202-203 None
16 j Electric Plant in Service 204-207
17 Electric Plant Leased to Others 213 None
18 Electric Plant Held for Future Use 214
19 Construction Work in Progress-Electric 216
20 Accumulated Provision for Depreciation of Electric Utility Plant 219
21 Investment of Subsidiary Companies 224-225
22 Materials and Supplies 227
23 Allowances 228(ab)-229(ab) None
24 Extraordinary Property Losses 230 None
25 Unrecovered Plant and Regulatory Study Costs 230 None
26 Transmission Service and Generation Interconnection Study Costs 231
27 Other Regulatory Assets 232
28 Miscellaneous Deferred Debits 233
29 Accumulated Deferred Income Taxes 234
30 Capital Stock 250-251
31 Other Paid-in Capital 253
32 Capital Stock Expense 254
33 Long-Term Debt 256-257
34 Reconciliation of Reported Net Income with Taxable 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. I (ED. 12-96)
Name of Respondent
Idaho Power Company
This Report Is:
E]An
(2) F~ A Resubmission
Date of Report
04/13/2012
Year/Period of Report
End of 2011 /Q4
LIST OF SCHEDULES (Electric Utility) (continued)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Line
No.
Title of Schedule
(a)
Reference
Page No.
(b)
Remarks
(c)
37 Other Deferred Credits 269
38 Accumulated Deferred Income Taxes-Accelerated Amortization Property 272-273
39 Accumulated Deferred Income Taxes-Other Property 274-275
40 Accumulated Deferred Income Taxes-Other 276-277
41 Other Regulatory Liabilities 278
42 Electric Operating Revenues 300-301
43 Sales of Electricity by Rate Schedules 304
44 Sales for Resale 310-311
45 Electric Operation and Maintenance Expenses 320-323
46 Purchased Power 326-327
47 Transmission of Electricity for Others 328-330
48 Transmission of Electricity by ISO/RTOs 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 Activities 352-353
54 Distribution of Salaries and Wages 354.355
55 Common Utility Plant and Expenses 356 None
56 Amounts included in ISO/RIO Settlement Statements 397 None
57 Purchase and Sale of Ancillary Services 398 None
58 Monthly Transmission System Peak Load 400
59 Monthly ISOIRTO 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. I (ED. 12-96) Page 3
Name of Respondent This Report Is: Date of Report Year/Period of Report
Idaho Power Company 2n RSSion End of 2011/04
04/13/2012
LIST OF SCHEDULES (Electric Utility) (continued)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Line Title of Schedule Reference Remarks
No. Page No.
- (a) (b) (c)
67 Transmission Lines Added During the Year 424-425
68 Substations 426-427
69 Transactions with Associated (Affiliated) Companies 429
70 Footnote Data 450
- Stockholders' Reports Check appropriate box:
Two copies will be submitted
0 No annual report to stockholders is prepared
FERC FORM NO.1 (ED. 12-96) Page 4
I
Name of Respondent This Report Is: Date of Report Year/Period of Report
Idaho Power Company (1)LXI An Original (Mo, Da, Yr)
(2)A Resubmission 04/13/2012 End of 20111Q4
GENERAL INFORMATION
1.Provide name and title of officer having custody of the general corporate books of account and address of
office where the general corporate books are kept, and address of office where any other corporate books of account
are kept, if different from that where the general corporate books are kept.
Ken Petersen Coporate Controller and CAO, Idaho Power Company
1221 W. Idaho Street, P.O. Box 70, Boise, Idaho 83707-0070
2.Provide the name of the State under the laws of which respondent is incorporated, and date of incorporation.
If incorporated under a special law, give reference to such law. If not incorporated, state that fact and give the type
of organization and the date organized.
Idaho, June 30, 1989
3.If at any time during the year the property of respondent was held by a receiver or trustee, give (a) name of
receiver or trustee, (b) date such receiver or trustee took possession, (c) the authority by which the receivership or
trusteeship was created, and (d) date when possession by receiver or trustee ceased.
Not applicable
4.State the classes or utility and other services furnished by respondent during the year in each State in which
the respondent operated.
Class of Utility Service State
Electric Idaho
Electric 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:
1131 rvi t,.i.. k-J IJ I'J
FERC FORM No.1 (ED. 12-87) PAGE 101
Name of Respondent This Report Is: Date of Report Year/Period of Report
Idaho Power Company (1)fJ An Original (Mo, Da, Yr)
(2)0 A Resubmission 04/13/2012 End of 2011/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 controlling corporation or organization, manner in
which control was held, and extent of control. If control was in a holding company organization, show the chain
of ownership or control to the main parent company or organization. If control was held by a trustee(s), state
name of trustee(s), name of beneficiary or beneficleanes for whom trust was maintained, and purpose of the trust.
Idaho Power Company is a subsidiary of IDACORP, INC
IDACORP owns 100% of Idaho Power Company's Common Stock.
IDACORP is a public utility Holding Company incorporated effective 10-1-1998
FEW; FORM NO. 1 (ED. 12-96) Page 102
I
Name of Respondent
Idaho Power Company
This Report Is:
E]An
(2) F] A Resubmission
Date of Report
(Mo, Da, Yr)
04/13/2012
Year/Period of Report
End of 201 1/Q4
CORPORATIONS CONTROLLED BY RESPONDENT
1.Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent
at any time during the year. If control ceased prior to end of year, give particulars (details) in a footnote.
2.If control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, naming
any intermediaries involved.
3.If control was held jointly with one or more other interests, state the fact in a footnote and name the other interests.
Definitions
1.See the Uniform System of Accounts for a definition of control.
2.Direct control is that which is exercised without interposition of an intermediary.
3.Indirect control is that which is exercised by the interposition of an intermediary which exercises direct control.
4.Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where the
voting control is equally divided between two holders, or each party holds a veto power over the other. Joint control may exist by
mutual agreement or understanding between two or more parties who together have control within the meaning of the definition of
control in the Uniform System of Accounts, regardless of the relative voting rights of each party.
Line
No.
Name of Company Controlled
(a)
Kind of Business
(b)
Percent Voting
Stock Owned
(c)
Footnote
Ref.
(d)
1 Direct Control
2 Idaho Energy Resources Company Coal mining and mineral 100%
3 development
4
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Name of Respondent
Idaho Power Company
This Report Is:
Resubmission
Date of Report
04/13/2012
Year/Period of Report
End of 2011 /Q4
OFFICERS
1.Report below the name, title and salary for each executive officer whose salary is $50,000 or more. An "executive officer" of a
respondent includes its president, secretary, treasurer, and vice president in charge of a principal business unit, division or function
(such as sales, administration or finance), and any other person who performs similar policy making functions.
2.If a change was made during the year in the incumbent of any position, show name and total remuneration of the previous
incumbent, and the date the change in incumbency was made.
Line
No.
Title
(a)
Name of Officer
(b)
Salary for Year
(c)
2 Chief Executive Officer (3) J. LaMont Keen 635,000
3
4 President & Chief Financial Officer (3) Darrel T. Anderson 383,000
5
6 Executive Vice President, & Chief Operating Officer (3) Dan Minor 360,000
7
8 Senior Vice President Corporate Responsibilty (1) Ric Gale 240,000
9
10 Vice President and Chief Information Officer Dennis Gnbble 212,500
11
12 Vice President Human Resources & Corp Services Luci McDonald 230,000
13
14 Senior Vice President Finance and Treasurer (3) Steven R Keen 230,000
15
16 Senior Vice President and General Counsel Rex Blackburn 270,000
17
18 Vice President, Chief Risk Officer Lori Smith 207,500
19
20 Senior Vice President Power Supply Lisa Grow 240,000
21
22 Vice President, Public Affairs Jeffrey Malmen 203,000
23
24 Vice President, Customer Operations Warren Kline 212,500
25
26 Vice President Delivery Engineering & Operations Vern Porter 195,500
27
28 Corporate Controller & Chief Accounting Officer Ken Petersen 180,000
29
30 Vice President, Supply Chain Naomi Crafton-Shankel 165,000
31
32 Corporate Secretary Patrick Harrington 165,000
33
34 Vice President, Regulatory Affairs (2) Gregory Said 165,000
35
36 (1) Retirement 6130/2011
37 (2) Title/Position Change effective 1/8/2011
38 (3) Title changes effective 1/1/2012
39
40
41
42
43
44
FERC FORM NO. I (ED. 12-96) Page 104
Name of Respondent
Idaho Power Company
This Re ort Is:
(2) []A Resubmission
Date of Report
04/13/2012
Year/Period of Report
End of 2011/04
DIRECTORS
1.Report below the information called for concerning each director of the respondent who held office at any time during the year. Include in column (a), abbreviated
titles of the directors who are officers of the respondent
2.Designate members of the Executive Committee by a triple asterisk and the Chairman of the Executive Committee by a double asterisk.
LIM
No. Name (and Title) of Director
(a) Principal Business Address
(b)
2 Judith A Johansen 2786 Glenmorne 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 Stephen Allred 4642 W Dawson Dr Meridian, Id 83646
10
11 Jan B Packwood 900 W Bogus View Drive, Eagle Idaho 83616
12
13 J LaMont Keen President and Chief Executive Officer** Idaho Power Company, 1221 W Idaho Street
14 P.0. Box 70 Boise Idaho 83707-0070
15
16 Richard G Reiten Pacwest Center, 1211 SW Fifth Ave Suite 1600
17 Portland Oregon 97204
18
19 Joan Smith 2309 SW First Avenue, No 1141 Portland Oregon 97201
20
21 Robert A Tinstman ** 4433 W Quail Point Court Boise Idaho 83703
22
23 Thomas Wilford Alscott Inc P.0. Box 70001 Boise Idaho 83701
24
25 Richard Dahl 11659 Presilla Road Santa Rosa Valley Ca 93012
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FERC FORM NO: I (ED. 12-95) Page 106
Name of Respondent
Idaho Power Company ' '
This Report Is:
(1)An Original
(2)[] A Resubmission
Date of Report
(Mo, Da, Yr)
04/13/2012
Year/Period of Report
End of 2011 /Q4
INFORMATION ON FORMULA RATES
FERC Rate Schedule/Tariff Number FERC Proceeding
Does the respondent have formula rates? Yes
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.
Line
No. FERC Rate Schedule or Tariff Number FERC Proceeding
1 FERC Electric Tariff FERC Docket No. ER06-787-002,003
2
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FERC FORM NO. I (NEW. 12-08) Page 106
Name of Respondent
Idaho Power Company
This Report Is:
(1)An Original 1 (2)A Resubmission
Date of Report
(Mo, Da,Yr)
04/13/2012
ea Period of Report
End of 2011/04
INFORMATION ON FORMULA RATES
FERC Rate Schedule/Tariff Number FERC Proceeding
Does the respondent file with the Commission annual (or more frequent)
filings containing the inputs to the formula rate(s)?
Yes
No
2. If yes, provide a listing of such filings as contained on the Commission's eLibrary website
-
Line
No. Accession No.
Document
Date
\ Filed Date Docket No. Description
Formula Rate FERC Rate
Schedule Number or
Tariff Number
1 201109025016 09/01/2011 ER09-1641-000 Idaho Power Company'E FERC Electric Tariff
2 2011-2012Annua
3 informational film1
4 under ER09-164
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FERC FORM NO. 1 (NEW. 12-08) Page 106a
Name of Respondent
Idaho Power Company
This Report Is:
(1)J An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/13/2012
Year/Period of Report
n 2011/Q4
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 different from the reported 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 inputs, the specific proceeding should be noted in the footnote.
Line
No. Page No(s). Schedule Column Line No
I None
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FERC FORM NO. I (NEW. 12-08) Page 106b
Idaho Power Company (1)An Original f End of 2011 /Q4
(2)LI A Resubmission 04/13/2012
Give particulars (details) concerning the matters indicated below. Make the statements explicit and precise, and number them in
accordance with the inquiries. Each inquiry should be answered. Enter "none," "not applicable," or "NA" where applicable. If
information which answers an inquiry is given elsewhere in the report, make a reference to the schedule in which it appears.
1.Changes in and important additions to franchise rights: Describe the actual consideration given therefore and state from whom the
franchise rights were acquired. If acquired without the payment of consideration, state that fact.
2.Acquisition of ownership in other companies by reorganization, merger, or consolidation with other companies: Give names of
companies involved, particulars concerning the transactions, name of the Commission authorizing the transaction, and reference to
Commission authorization.
3.Purchase or sale of an operating unit or system: Give a brief description of the property, and of the transactions relating thereto,
and reference to Commission authorization, if any was required. Give date journal entries called for by the Uniform System of Accounts
were submitted to the Commission.
4.Important leaseholds (other than leaseholds for natural gas lands) that have been acquired or given, assigned or surrendered: Give
effective dates, lengths of terms, names of parties, rents, and other condition. State name of Commission authorizing lease and give
reference to such authorization.
5.Important extension or reduction of transmission or distribution system: State territory added or relinquished and date operations
began or ceased and give reference to Commission authorization, if any was required. State also the approximate number of
customers added or lost and approximate annual revenues of each class of service. Each natural gas company must also state major
new continuing sources of gas made available to it from purchases, development, purchase contract or otherwise, giving location and
approximate total gas volumes available, period of contracts, and other parties to any such arrangements, etc.
6.Obligations incurred as a result of issuance of securities or assumption of liabilities or guarantees including issuance of short-term
debt and commercial paper having a maturity of one year or less. Give reference to FERC or State Commission authorization, as
appropriate, and the amount of obligation or guarantee.
7.Changes in articles of incorporation or amendments to charter: Explain the nature and purpose of such changes or amendments.
8.State the estimated annual effect and nature of any important wage scale changes during the year.
9 State briefly the status of any materially important legal proceedings pending at the end of the year, and the results of any such
proceedings culminated during the year.
10.Describe briefly any materially important transactions of the respondent not disclosed elsewhere in this report in which an officer,
director, security holder reported on Page 104 or 105 of the Annual Report Form No. 1, voting trustee, associated company or known
associate of any of these persons was a party or in which any such person had a material interest.
11.(Reserved.)
12.If the important changes during the year relating to the respondent company appearing in the annual report to stockholders are
applicable in every respect and furnish the data required by Instructions I to 11 above, such notes may be included on this page.
13.Describe fully any changes in officers, directors, major security holders and voting powers of the respondent that may have
occurred during the reporting period.
14.In the event that the respondent participates in a cash management program(s) and its proprietary capital ratio is less than 30
percent please describe the significant events or transactions causing the proprietary capital ratio to be less than 30 percent, and the
extent to which the respondent has amounts loaned or money advanced to its parent, subsidiary, or affiliated companies through a
cash management program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio.
PAGE 108 INTENTIONALLY LEFT BLANK
SEE PAGE 109 FOR REQUIRED INFORMATION.
FERC FORM NO. I (ED. 12-96) Page 108
U
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)_ A Resubmission 04/13/2012 201 1/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
1.None
2.None
3.None
4.None
5.New transmission line - Line #528 Rockland Jct to Rockland Wind Farm 15.92 wire miles
Additions/removals to existing lines:
Line #221 added 7.59 wire miles.
Line #241 extension to Neal Hot Springs added 31.32 wire miles.
Line #426 customer owned line carries as Idaho Power removed 21.68 wire miles.
Line #452 dual circuit tap to connect Kimberly station added 5.49 wire miles.
Line #466 tap to Victory substateion added 5.82 wire miles.
Line #715 added dual circuit tap Langley Gulch power plant added 16.44 wire miles.
On January 12,2012, Idaho Power, PacifiCorp, and the Bonneville Power Administration (BPA)
entered into agreements pertaining to the Boardman-to-Hemingway project.This agreement
provides for permitting interests of 21.21 percent for Idaho Power, 24.24 percent for BPA,
and 54.55 percent for PacifiCorp.
The Gateway West Transmission Project Development Agreement dated January 12, 2012 between
Idaho Power and PacifiCorp outlines the terms under which the parties will jointly own,
develop, design, permit and acquire rights-of-way for the Gateway West transmission
project.Idaho Power's interest in the Gateway West project applies to four of ten segments
involved in the project, referred to as segments 6 (which Idaho Power had previously
constructed and is included only for purposes of federal permitting related to the Gateway
West project), 8,9,and 10. Each party is responsible for its pro rata share, based on its
respective federal and state permitting ownership interest, of the costs incurred under
the agreement.Idaho Power's state permitting interest in its segments is 100 percent for
segment 6 and 33 percentfor each of segments 8,9, and 10, with a federal permitting
interest in the project of ii percent. Segment #6 is from Borah to Midpoint, segment #8 is
from Midpoint to Hemingway, Segment #9 is from Cedar Hill to Hemingway and segment #10 is
from Midpoint to Cedar Hill.
6.As of December 31,2011, $300 million remained on Idaho Power's shelf registration for
the issuance of first morgage bonds and debt securities. State Commission order number is
the same for both issuance OPUC UF4263, IPC-E-10-10, WPSC 20005-32-10.
7.None
8.Effective 1/14/11 a 2.75% general wage increase was implemented.
9.See pages 123.20 to 123.23
10.None
ii. None
12.None
13.Refer to pages 104 & 105 for changes in officers and directors. There were a couple of
changes in the major security holders for 2011. The top ten institutional shareholders
list saw 2 changes from 3rd quarter to 4th quarter. In the 4th quarter Zimmer Lucas
Partners, LLC and Thompson, Siegel & Walmsley LLC replaced Artisan Partners Limited
Partnership and Fisher Investments.
14.Idaho Power and its unregulated parent, IdaCorp have seperate cash management
IFERC FORM NO I (ED 12-96) Page 109.1
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)_ A Resubmission 0411312012 20111Q4
IMPORTANT CHANGES DURING THE QUARTERJYEAR (Continued)
programs (Seperate bank accounts, liquidity facilities, short-term debt and investment
programs) No money has been loaned or advanced from Idaho Power to IdaCorp through a cash
management program.
I
Name of Respondent
Idaho Power Company
This Report Is:
(1)An original
(2)0 A Resubmission
Date of Report
(Mo, Da, Yr)
04/13/2012
Year/Period of Report
End of 2011/Q4
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
L Line
No.
-
Title of Account
(a)
Ref.
Page No.
(b)
Current Year
End of Quarter/Year
Balance
(c)
Prior Year
End Balance
12/31
(d)
1 UTILITY PLANT
2 1 Utility Plant (101-106, 114) 200-201 4,473,847,18 4,339,130,398
3 Construction Work in Progress (107) 200-201 591,474,855 416,949,593
4 TOTAL Utility Plant (Enter Total of lines 2 and 3) 5,065,322,04 4,756,079,991
5 (Less) Accum. Prov. for Dept. Amort. Depl. (108, 110, 111, 115) 200-201 1,840,782,08 1,771,654,529
6 Net Utility Plant (Enter Total of line 4 less 5) 3,224,539,95 2,984,425,462
7 Nuclear Fuel in Process of Ref., Conv.,Enrich., and Fab. (120.1) 202-203 0 0
8 Nuclear Fuel Materials and Assemblies-Stock Account (120.2) 0
9 Nuclear Fuel Assemblies in Reactor (120.3) 0 0
10 Spent Nuclear Fuel (120.4) 0 0
11 Nuclear Fuel Under Capital Leases (120.6) 0 0
12 (Less) Accum Prov. for Amort of Nuci Fuel Assemblies (1205) 202-203 0 0
13 Net Nuclear Fuel (Enter Total of lines 7-11 less 12) 0 0
14 Net Utility Plant (Enter Total of lines 6 and 13) 3,224,539,951 2,984,425,462
15 Utility Plant Adjustments (116) 0 C)
16 Gas Stored Underground - Noncurrent (117) 0 0
17 OTHER PROPERTY AND INVESTMENTS
18 Nonutility Property (121) 2,081,4201 2,074,996
19 (Less) Accum. Prov. for Depr. and Amort. (122) 0
20 Investments in Associated Companies (123) 0
21 Investment in Subsidiary Companies (123.1) 224-225 78,529,519 72,561,774
22 (For Cost of Account 123.1, See Footnote Page 224, line 42)
23 Noncurrent Portion of Allowances 228-229 0 0
24 Other Investments (124) 1,852 2,511
25 Sinking Funds (125) 0
26 Depreciation Fund (126) 0
27 Amortization Fund - Federal (127) 0
28 Other Special Funds (128) 25,644,107 29,306,774
29 Special Funds (Non Major Only) (129) 0 0
30 Long-Term Portion of Derivative Assets (175) 359,418 0
31 Long-Term Portion of Derivative Assets - Hedges (176) 0 0
32 TOTAL Other Property and Investments (Lines 18-21 and 23-31) 106,616,316 103,946,055
33 CURRENT AND ACCRUED ASSETS
34 Cash and Working Funds (Non-major Only) (130)
35 Cash (131) 19,178,288 73,015,293
36 Special Deposits (132-134) 0 2,802,631
37 Working Fund (135) 37,352 44,850
38 Temporary Cash Investments (136) 100,000 151,172,575
39 Notes Receivable (141) 94,776 303,143
40 Customer Accounts Receivable (142) 67,534,731 63,612,796
41 Other Accounts Receivable (143) 8,206,727 6,166,234
42 (Less) Accum. Prov. for Uncollectible Acct.-Credit (144) 1,435,434 1,641,302
43 Notes Receivable from Associated Companies (145) 17,335,019 14384 928
44 Accounts Receivable from Assoc. Companies (146) 0 0
45 Fuel Stock (151) 227 47,865,097 27,546,983
46 Fuel Stock Expenses Undistributed (152) 227 0 0
47 Residuals (Elec) and Extracted Products (153) 227 0 0
48 Plant Materials and Operating Supplies (154) 227 42,015,731 42,221,176
49 Merchandise (155) 227 0 0
50 Other Materials and Supplies (156) 227 0 0
51 Nuclear Materials Held for Sale (157) 202-203/227 0 - 0
52 Allowances (158.1 and 1582) 228-229 0 0
FERC FORM NO I (REV 12-03) Page 110
Name of Respondent
Idaho Power Company
This Report Is:
(1)FA An Original
(2)i:i A Resubmission
Date of Report
(Mo, Da, Yr)
04/13/2012
Year/Period of Report
End of 2011/Q4
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITontinued) -
Line
No.
-
Title of Account
(a)
Ref.
Page No.
(b)
Current Year
End of Quarter/Year
Balance
(c)
Prior Year
End Balance
12/31
(d)
53 (Less) Noncurrent Portion of Allowances 0 0
54 1 Stores Expense Undistributed (163) 227 4,474,719 3,379,745
55 Gas Stored Underground - Current (164.1) 0 0
56 Liquefied Natural Gas Stored and Held for Processing (164.2-164.3) 0 0
57 Prepayments (165) 12,273,571 10,910,213
58 Advances for Gas (166-167) 0 0
59 Interest and Dividends Receivable (171) 0 8,128
60 Rents Receivable (172) 0
61 Accrued Utility Revenues (173) 46,440,688 47,964,339
62 Miscellaneous Current and Accrued Assets (174) 0 0
63 Derivative Instrument Assets (175) 3,754,383 573 226
64 (Less) Long Term Portion of Derivative Instrument Assets (175) 359,418 0
65 Derivative Instrument Assets - Hedges (176) 0 0
66 (Less) Long Term Portion of Derivative Instrument Assets Hedges (176 0 0
67 Total Current and Accrued Assets (Lines 34 through 66) 267,516,230 442,464,958
68 DEFERRED DEBITS
69 Unamortized Debt Expenses (181) 16992 504 15,869,453
70 Extraordinary Property Losses (182.1) 230a 0
71 Unrecovered Plant and Regulatory Study Costs (182.2) 230b 0
72 Other Regulatory Assets (1823) 232 989,194,015 761 42588
73 Prelim Survey and Investigation Charges (Electric) (183) 491,041 454,727
74 Preliminary Natural Gas Survey and Investigation Charges 183.1) 0
75 Other Preliminary Survey and Investigation Charges (1832) 0
76 Clearing Accounts (184) 630,208 564,213
77 Temporary Facilities (185) 0 0
78 Miscellaneous Deferred Debits (186) 233 50,880,202 55,131,472
79 Def. Losses from Disposition of Utility Pit. (187) 0
80 Research Devel and Demonstration Expend (188) 352-353 0
81 Unamortized Loss on Reaquired Debt (189) 13,613,712 14524 712
82 Accumulated Deferred Income Taxes (190) 234 227,977,046 157,346,772
83 Unrecovered Purchased Gas Costs (191) 0
84 Total Deferred Debits (lines 69 through 83) 1,299,778,728 1,005,317,233
85 TOTAL ASSETS (lines 14-16, 32, 67, and 84) 4,898,451,221 4,536,153,708
FERC FORM NO I (REV 12-03) Page 111
Name of Respondent
Idaho Power Company
This Report is:
(1)nx An Original
(2)0 A Resubmission
Date of Report
(mo, da, yr)
04/13/2012
Year/Period of Report
end of 2011/Q4
- COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
Line
No Title of Account
(a)
Ref.
Page No.
(b)
Current Year
End of Quarter/Year
Balance
(c)
Prior Year
End Balance
12/31
(d)
I PROPRIETARY CAPITAL
2 Common Stock Issued (201) 250-251 97,877,030 97,877,030
3 Preferred Stock Issued (204) 250-251 0
4 Capital Stock Subscribed (202, 205) 0
5 Stock Liability for Conversion (203, 206) 0
6 Premium on Capital Stock (207) 704,757,436 688,757,435
7 Other Paid-In Capital (208-211) 253 0
8 Installments Received on Capital Stock (212) 252 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 Earnings (215, 215.1, 216) 118-119 659,237,261 560,160,116
12 Unappropriated Undistributed Subsidiary Earnings (216.1) 118-119 76,066,425 70,098,680
13 (Less) Reaquired Capital Stock (217) 250-251 0
14 Noncorporate Proprietorship (Non major only) (218) 0 0
15 Accumulated Other Comprehensive Income (219) 122(a)(b) -11,622,052 9567515
16 Total Proprietary Capital (lines 2 through 15) 1,524,219,175 1,405,228,821
17 LONG-TERM DEBT
18 Bonds (221) 256-257 1,465,460,000 1,585,460,000
19 (Less) Reaquired Bonds (222) 256-257 0 0
20 Advances from Associated Companies (223) 256-257 0 0
21 Other Long-Term Debt (224) 256-257 26,266,818 27,330,455
22 Unamortized Premium on Long-Term Debt (225) 0 0
23 (Less) Unamortized Discount on Long Term Debt Debit (226) 3,113,413 3 439 75
24 Total Long-Term Debt (lines 18 through 23) 1,488,613,40 1,609,350,702
25 OTHER NONCURRENT LIABILITIES
26 Obligations Under Capital Leases Noncurrent (227) 0 0
27 Accumulated Provision for Property Insurance (228.1) 0 0
28 Accumulated Provision for Injuries and Damages (2282) 1,924 ,461 1881 776
29 Accumulated Provision for Pensions and Benefits (2283) 366,648,491 268,433,659
30 Accumulated Miscellaneous Operating Provisions (228.4) 0 0
31 Accumulated Provision for Rate Refunds (229) 33,145,395 21,210,538
32 Long Term Portion of Derivative Instrument Liabilities 107,763 0
33 Long Term Portion of Derivative Instrument Liabilities Hedges 0 0
34 Asset Retirement Obligations (230) 21,366,767 16,951,914
35 Total Other Noncurrent Liabilities (lines 26 through 34) 423,192,877 308,477,887
36 CURRENT AND ACCRUED LIABILITIES
37 Notes Payable (231) 0 0
38 Accounts Payable (232) 97,996,387 100,785,053
39 Notes Payable to Associated Companies (233) 0 0
40 Accounts Payable to Associated Companies (234) 1,511,606 1110 373
41 Customer Deposits (235) 10,799,095 1,366,711
42 Taxes Accrued (236) 262-263 4895 725 -12,242,872
43 Interest Accrued (237) 22,038,081 24,038,150
44 Dividends Declared (238) 0 0
45 Matured Long-Term Debt (239) 0 0
FERC FORM NO I (rev. 12-03) Page 112
Name of Respondent
Idaho Power Company
This Report is:
(1)J An Original
(2) J A Resubmission
Date of Report
(mo, da, yr)
04/13/2012
Year/Period of Report
end of 2011/04
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER - CREDI)iUnued)
Line
No. Title of Account
(a)
Ref.
Page No.
(b)
Current Year
End of Quarter/Year
Balance
(c)
Prior Year
End Balance
12/31
(d)
46 Matured Interest (240) 0 0
47 Tax Collections Payable (241) 1719,933 1,689,273
48 Miscellaneous Current and Accrued Liabilities (242) 33,498,725 112,230,437
49 Obligations Under Capital Leases-Current (243) 0 0
50 Derivative Instrument Liabilities (244) 4,706,863 508,141
51 (Less) Long-Term Portion of Derivative Instrument Liabilities 107,763 0
52 Derivative Instrument Liabilities Hedges (245) 0 0
53 (Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges 0 0
54 Total Current and Accrued Liabilities (lines 37 through 53) 177,058,652 229,485,266
55 DEFERRED CREDITS
56 Customer Advances for Construction (252) 19,747,984 23,054,017
57 Accumulated Deferred Investment Tax Credits (255) 266-267 70,840,400 71 ,972,336
58 Deferred Gains from Disposition of Utility Plant (256) 0 0
59 Other Deferred Credits (253) 269 27,530,572 26,668,269
60 Other Regulatory Liabilities (254) 278 96,483,245 55,279,902
61 Unamortized Gain on Reaquired Debt (257) 0 0
62 Accum Deferred Income Taxes Accel Amort (281) 272-277 0 0
63 Accum Deferred Income Taxes Other Property (282) 933,326,224 707,009,348
64 Accum Deferred Income Taxes Other (283) 137,438,695 99,627,160
65 Total Deferred Credits (lines 56 through 64) 1 ,285,367,120 983,611,032
66 TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16 24 35 54 and 65) 4,898,451,229 4536 153 708
FERC FORM NO. I (rev. 12-03) Page 113
Name of Respondent
Idaho Power Company
This Report Is:
AResubmission
Date of Report
04/13/2012
Year/Period of Report
End of 201 1 /Q4
STATEMENT OF INCOME
Quarterly
1.Report in column (c) the current 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 information 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 three month period for the prior year.
3.Report in column (g) the quarter to date amounts for electric utility function; in column (i) the quarter to date amounts for gas utility, and in column (k)
the quarter to date amounts for other utility function for the current year quarter.
4.Report in column (h) the quarter to date amounts for electric utility function; in column (j) the quarter to date amounts for gas utility, 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 fourth quarter data in columns (e) and (f)
6.Report amounts for accounts 412 and 413, Revenues and Expenses from Utility Plant Leased to Others, in another utility columnin a similar manner to
a utility department Spread the amount(s) over lines 2 thru 26 as appropriate. Include these amounts in columns (c) and (d) totals.
7.Report amounts in account 414, Other Utility Operating Income, in the same manner as accounts 412 and 413 above.
Line
No.
-
Title of Account
(a)
(Ref.)
Page No.
(b)
Total
Current Year to
Date Balance for
Quarter/Year
(c)
Total
Prior Year to
Date Balance for
Quarter/Year
(d)
Current 3 Months
Ended
Quarterly Only
No 4th Quarter
(e)
Prior 3 Months
Ended
Quarterly Only
No 4th Quarter
(f)
1 UTILITY OPERATING INCOME
2 Operating Revenues (400) 300-301 1,021.585142 1,033,015Z120
3 Operating Expenses
4 Operation Expenses (401) 320-323 632,997,464 622,124906
5 Maintenance Expenses (402) 320-323 76,104,523 71096,344
6 Depreciation Expense (403) 336-337 113,001,742 109,099,197
7 Depreciation Expense for Asset Retirement Costs (403.1) 336-337
8 Amort. & DepI. of Utility Plant (404405) 336-337 6,764,513 6,857,301
9 Arnort. of Utility Plant Acq. Adj. (406) 336-337 -22723 -22,723
10 Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407)
11 Amort. of Conversion Expenses (407)
12 Regulatory Debits (407.3) 28,099 21,955
13 (Less) Regulatory Credits (407.4)
14 Taxes Other Than Income Taxes (408.1) 262-263 28,894,715 24,046,035
15 Income Taxes - Federal (409.1) 262-263 .57,754,420 5,967,393
16 Other (409 1) 262-263 -803,160 1 3,057,226
17 Provision for Deferred Income Taxes (410.1) 234, 272-277 116,679,418 83,335,948
18 (Less) Provision for Deferred Income Taxes-Cr. (411.1) 234, 272-277 99,841,847 80,939,819
19 Investment Tax Credit Adj. - Net (411.4) 266 -1,131,934 -1,533,190
20 (Less) Gains from Disp. of Utility Plant (411.6) -17,392 34,607
21 Losses from Disp. of Utility Plant (411.7)
22 (Less) Gains from Disposition of Allowances (411.8) 398,050 444,212
23 Losses from Disposition of Allowances (411.9)
24 Accretion Expense (411.10)
25 TOTAL Utility Operating Expenses (Enter Total of fines 4 thru 24) 814,535,732 842,631,754
26 Net Util Oper Inc (Enter Tot fine 2 less 25) Carry to Pg117,line 27 207,049,410 190,420,366
FERC FORM NO 113-Q (REV 02-04) Page 114
Name of Respondent This Report Is: Date of Report Year/Period of Report
Idaho Power Company An
'
End of 2011/04
RSsiOn
STATEMENT OF INCOME FOR THE YEAR (Continued)
9.Use page 122 for important notes regarding the statement of income for any account thereof.
10.Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a material amount may need to be
made to the utility's customers or which may result in material refund to the utility with respect to power or gas purchases. State for each year effected
the gross revenues or costs to which the contingency relates and the tax effects together with an explanation of the major factors which affect the rights
of the utility to retain such revenues or recover amounts paid with respect to power or gas purchases.
11 Give concise explanations concerning significant amounts of any refunds made or received during the year resulting from settlement of any rate
proceeding affecting revenues received or costs incurred for power or gas purches, and a summary of the adjustments made to balance sheet, income,
and expense accounts.
12.If any notes appearing in the report to stokholders are applicable to the Statement of Income, such notes may be included at page 122.
13.Enter on page 122 a concise explanation of only those changes in accounting methods made during the year which had an effect on net income,
including the basis of allocations and apportionments from those used in the preceding year. Also, give the appropriate dollar effect of such changes.
14.Explain in a footnote lithe previous year's/quarter's figures are different from that reported in prior reports.
15.lithe columns are insufficient for reporting additional utility departments, supply the appropriate account titles report the information in a footnote to
this schedule.
ELECTRIC UTILITY GAS UTILITY OTHER UTILITY -
Current Year to Date Previous Year to Date Current Year to Date Previous Year to Date Current Year to Date Previous ea to Date Line
(in dollars) (in dollars) (in dollars) (in dollars) (in dollars) (in dollars) No.
(g) (h) () (j) (k) (I) -
• 1.021,585,142 1.033,052.120 2
3
632,997,464 622,124,906 4
76,104,523 71,096,344 5
113,001,742 109,099,197 6
7
6,764,513 6,857,301 8
-22,723 -22,723 9
10
11
28,099 21,955 12
13
28,894,715 24,046,035 14
-57,754,420 5,967,393 15
-803,160 3,057,226 16
116,679,418 83,335,948 17
99,841,847 80,939,819 18
-1,131,934 -1,533,190 19
-17,392 34,607 20
21
398,050 444,212 22
23
24
814,535,732 842,631,754 25
207,049,410 190,420,366 26
Name of Respondent
Idaho Power Company
This Report Is:
AResubmission
Date of Report
04/13/2012
Year/Period of Report
End of 201 1 /Q4
STATEMENT OF INCOME FOR THE YEAR (continued)
Line
No.
-
Title of Account
(a)
(Ref.)
Page No.
(b)
TOTAL Current 3 Months
Ended
Quarterly Only
No 4th Quarter
(e)
Prior 3 Months
Ended
Quarterly Only
No 4th Quarter
(f)
Current Year
(c)
Previous Year
(d)
27 Net Utility Operating Income (Carried forward from page 114) 1 207,049410 190,420,3661
28 Other Income and Deductions
29 Other Income
30 Nonutilty Operating Income
31 Revenues From Merchandising, Jobbing and Contract Work (415) 1,142,7671 602,483
32 (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416) 974,498 625,141
33 Revenues From Nonutility Operations (417) 51,602 58,915
34 (Less) Expenses of Nonutiuity Operations (417.1) -18,126 657,070
35 Nonoperating Rental Income (418) -3,285 -6,040
36 Equity in Earnings of Subsidiary Companies (418.1) 119 5,967,745 7,546,332
37 Interest and Dividend Income (419) 2,178,296 2,167,147
38 Allowance for Other Funds Used During Construction (419.1) 25,484,071 16,551,145
39 Miscellaneous Nonoperating Income (421) 1,428,531 1,928,056
40 Gain on Disposition of Property (421.1) 57,199 122,735
41 TOTAL Other Income (Enter Total of lines 31 thru 40) 35,350,5541 27,888,562
42 Other Income Deductions
43 Loss on Disposition of Property (421.2) 3,355
44 Miscellaneous Amortization (425)
45 Donations (426.1) 718,718 440,052
46 Life Insurance (426.2) -757,078 93,37
47 Penalties (426.3) 430,04 -453,47
48 Exp. for Certain Civic Political & Related Activities (4264) 1 ,167,8101 1,098,2601
491 Other Deductions (426.5) 6,579,0001 5,601,967
50 TOTAL Other Income Deductions (Total of lines 43 thru 49) 8,138,4921 678353
51 Taxes Applic. to Other Income and Deductions
52 Taxes Other Than Income Taxes (408.2) 262-263 23,238 19,58
53 Income Taxes-Federal (409.2) 262-263 -638,707 -2,812,996
54 Income Taxes-Other (409.2) 262-263 -112,459 -559,924
55 Provision for Deterred Inc. Taxes (410.2) 234, 272-277 511,882 1,739,465
56 (Less) Provision for Deferred Income Taxes-Cr. (411.2) 234 272-277 1,327,221 1 420 220
57 Investment Tax Credit Adj.-Net (411.5)
58 (Less) Investment Tax Credits (420)
59 TOTAL Taxes on Other Income and Deductions (Total of lines 52-58) -1,543,267 -3,034,093
60 Net Other Income and Deductions (Total of lines 41, 50,59) 28,755,329 24,139,122
61 Interest Charges
62 Interest on Long-Term Debt (427) 79,348,955 80,490,04
63 Amort. of Debt Disc. and Expense (428) 1,653,291 1,487,91
64 Amortization of Loss on Reaquired Debt (428.1) 911,000 915,21
65 (Less) Amort of Premium on Debt-Credit (429)
66 (Less) Amortization of Gain on Reaquired Debt-Credit (429.1)
67 Interest on Debt to Assoc. Companies (430)
68 Other Interest Expense (431) 2,474,590 1,707,17
69 (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432) 13,332,724 10,675,09
70 Net Interest Charges (Total of lines 62 thru 69) 71,055,112 73,925,265
71 Income Before Extraordinary Items (Total of lines 27,60 and 70) 164,749,627 140,634,223
72 Extraordinary Items
73 Extraordinary Income (434)
74 (Less) Extraordinary Deductions (435)
75 Net Extraordinary Items (Total of line 73 less line 74)
76 Income Taxes Federal and Other (4093) 262-263
77 Extraordinary Items After Taxes (line 75 less line 76)
78 Net Income (Total of line 71 and 77) __________ 164,749,627 140,634,223
FERC FORM NO. 1/3-Q (REV. 02.04) Page 117
THIS PAGE INTENTIONALLY LEFT BLANK
Name of Respondent
Idaho Power Company
This Report Is:
rr
(2) [:]AResubmission
Date of Report
04/13/2012
Year/Period of Report
End of 2011104
STATEMENT OF RETAINED EARNINGS
1.Do not report Lines 49-53 on the quarterly version.
2.Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriated
undistributed subsidiary earnings for the year.
3.Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436
- 439 inclusive). Show the contra primary account affected in column (b)
4.State the purpose and amount of each reservation or appropriation of retained earnings.
5.List first account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow
by credit, then debit items in that order.
6.Show dividends for each class and series of capital stock.
7.Show separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Earnings.
8.Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be
recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated.
9.If any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.
Line
No.
Item
(a)
Contra Primary
Account Affected
(b)
Current
Quarter/Year
Year to Date
Balance
(c)
Previous
Quarter/Year
Year to Date
Balance
(d)
UNAPPROPRIATED RETAINED EARNINGS (Account 216)
1 Balance-Beginning of Period 558,128446 : 4,.1491
2 Changes
3 Adjustments to Retained Earnings (Account 439)
5
6
7
8
9 TOTAL Credits to Retained Earnings (Acct. 439)
10
11
12
13
14
15 TOTAL Debits to Retained Earnings (Acct. 439)
16 Balance Transferred from Income (Account 433 less Account 418.1) 158,781,8821 133,087,891
17 Appropriations of Retained Earnings (Acct. 436)
18 Earnings on Hydro 215.1 -178,017
19 Reserve for excess Earnings for Cascade Project 2010 ( 54644)
20 Reserve for excess Earnings for Twin Falls & American Falls 215.1 ( 433,060)
21 1
22 TOTAL Appropriations of Retained Earnings (Acct. 436) -178,017 ( 487,704)
23 Dividends Declared-Preferred Stock (Account 437)
24
25
26
27
28
29 TOTAL Dividends Declared-Preferred Stock (Acct. 437)
30 Dividends Declared-Common Stock (Account 438)
31 -59,704,738 ( 58,070,890)
32
33
34
36 TOTAL Dividends Declared Common Stock (Acct 438) -59,704,7381 ( 58070 890)
37 Transfers from Acct 216 .1, Unapprop Undistrib Subsidiary Earnings
38 Balance End of Period (Total 1 9 15 1622 29 36 37) 657,027,5731 558,128,446
APPROPRIATED RETAINED EARNINGS (Account 215)
FERC FORM NO 113-Q (REV 02-04) Page 118
Name of Respondent This Report Is: Date of Report Year/Period of Report
Idaho Power Company End of 201 1/Q4
(2) AResubrnission 04/13/2012
STATEMENT OF RETAINED EARNINGS
1.Do not report Lines 49-53 on the quarterly version.
2.Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriated
undistributed subsidiary earnings for the year.
3.Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436
- 439 inclusive). Show the contra primary account affected in column (b)
4.State the purpose and amount of each reservation or appropriation of retained earnings.
5.List first account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow
by credit, then debit items in that order.
6.Show dividends for each class and series of capital stock.
7.Show separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Earnings.
8.Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be
recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated.
9.If any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.
Current Previous
Quarter/Year Quarter/Year
Contra Primary Year to Date Year to Date
Line Item Account Affected Balance Balance
No. (a) (b) (c) (d)
39
40
41
42
43
44
45 TOTAL Appropriated Retained Earnings (Account 215)
- APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.1)
46 TOTAL Approp. Retained Eamings-Amort. Reserve, Federal (Acct. 215.1) 2,209,688 2,031,670
47 TOTAL Approp. Retained Earnings (Acct. 215, 2151)(Total 45,46) 2,209,6881 2,031,670
48 TOTAL Retained Earnings (Acct 215 215 .1, 216) (Total 38 47) (216.1) 659,237,261 560,160,116
- UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account
- Report only on an Annual Basis, no Quarterly
49 Balance-Beginning of Year (Debit or Credit) I 70,098,680 62,552,348I
50 Equity in Earnings for Year (Credit) (Account 418.1) 5,967,745 7,546,332
51 (Less) Dividends Received (Debit)
52
53 Balance-End of Year (Total lines 49 thru 52) 76,066,425 70,098,680
FERC FORM NO. 113-Q (REV. 02-04) Page 119
Name of Respondent
Idaho Power Company
This Re it Is:
(2) 0 A Resubmission
Date of Report
04/13/2012
Year/Period of Report
End of 2011/Q4
STATEMENT OF CASH FLOWS
(1)Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper and (d) Identify separately such items as
investments, fixed assets, intangibles, etc.
(2)Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and Cash
Equivalents at End of Period" with related amounts on the Balance Sheet.
(3)Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing activities should be reported
in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid.
(4)Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes to
the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconciliation of the dollar amount of leases capitalized with the plant cost
Line
No.
Description (See Instruction No. I for Explanation of Codes)
(a)
Current Year to Date
Quarter/Year
(b)
Previous Year to Date
Quarter/Year
(c)
1 Net Cash Flow from Operating Activities:
2 Net Income (Line 78(c) on page 117) 164,749,7 140.834.223
3 Noncash Charges (Credits) to Income:
4 Depreciation and Depletion 113.001.742 109,099,197
5 Amortization of 12,120,185
6
7
8 IDeferred Income Taxes (Net) -58,819,227 75,464,788
9 Investment Tax Credit Adjustment (Net) -726,590 -984,156
10 Net (Increase) Decrease in Receivables -2,125,936 13,653,023
11 Net (Increase) Decrease in Inventory -21,207,643 539,767
12 Net (Increase) Decrease in Allowances Inventory
13 Net Increase (Decrease) in Payables and Accrued Expenses -5,534,463
14 Net (Increase) Decrease in Other Regulatory Assets 23,708,446 34,996,161
15 Net Increase (Decrease) in Other Regulatory Liabilities 44,336,626 11,513,932
16 (Less) Allowance for Other Funds Used During Construction 25,484,071 16,551,145
17 (Less) Undistributed Earnings from Subsidiary Companies 5,967,745 7,546,282
18
19
Other (provide details in footnote) ".—J—._- - -41,492,468
20
21
22 Net Cash Provided by (Used in) Operating Activities (Total 2 thru 21) 292,794,961 325,912,762
23
24 Cash Flows from Investment Activities:
25 Construction and Acquisition of Plant (including land):
26 Gross Additions to Utility Plant (less nuclear fuel) -327,576,965
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 13,332,724 10,675,095
31 Other (provide details in footnote): 25,390,083
32
33
34 Cash Outflows for Plant (Total of lines 26 thru 33) -331,450,227 -312,861,977
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) -I 42 Associated and Subsidiary Companies
43
44 Purchase of Investment Securities (a) -7,000,000
45 Proceeds from Sales of Investment Securities (a)
FERC FORM NO. I (ED. 12-96) Page 120
I
U
Name of Respondent
Idaho Power Company
This Re ort Is:
(2) E] A Resubmission
Date of Report
04/13/2012
Year/Period of Report
End of 201 1/Q4
STATEMENT OF CASH FLOWS
(1)Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items as
investments, fixed assets, intangibles, etc.
(2)Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and Cash
Equivalents at End of Period" with related amounts on the Balance Sheet.
(3)Operating Activities - Other Include gains and losses pertaining to operating activities Only. Gains and losses pertaining to investing and financing activities should be reported
in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid.
(4)Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes to
the Financial Statements. Do not Include on this statement the dollar amount of leases capitalized per the US0fA General Instruction 20; instead provide a reconciliation of the
dollar amount of leases capitalized with the plant cost
Line
No
Description (See Instruction No. 1 for Explanation of Codes)
(a)
Current Year to Date
Quarter/Year
(b)
Previous Year to Date
Quarter/Year
(c)
46 Loans Made or Purchased
47 Collections on Loans
48
49 Net (Increase) Decrease in Receivables 208,367 333,525
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) 8,541,146
54
55
56 Net Cash Provided by (Used in) Investing Activities
57 Total of lines 34 thru 55) -331 ,735,751 .'310i987,306j
58
59 Cash Flows from Financing Activities:
60 Proceeds from Issuance of:
61 Long-Term Debt (b) I 200,000,0C
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 16,000,000 50000 000
68
69
70 Cash Provided by Outside Sources (Total 61 thru 69) 16,000,0001 250,000,000
71
72 Payments for Retirement of:
73 Long-term Debt (b) -121,063,636 -1,063,636
74 Preferred Stock
75 Common Stock
76 Other (provide details in footnote): -1,207,914 -3,183,141
77
78 Net Decrease in Short-Term Debt (c)
79
80 Dividends on Preferred Stock
81 Dividends on Common Stock -59,704,738 -58,070,890
82 Net Cash Provided by (Used in) Financing Activities
83 (Total of lines 70 thru 81) -165,976,2881 187,682,333
84
85 Net Increase (Decrease) in Cash and Cash Equivalents
86 (Total of lines 22,57 and 83) -204,917,0781 202,607,189
87
88 Cash and Cash Equivalents at Beginning of Period 224,232,7181 21,624,929
89
90 Cash and Cash Equivalents at End of period 19,315,640 224,232,718
FERC FORM NO. I (ED. 12-96) Page 121
THIS PAGE INTENTIONALLY LEFT BLANK
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)- A Resubmission 04113/2012 201 1/Q4
FOOTNOTE DATA
chedulePge: 120 Line No.:5 Column: b
Amortization Twelve Months Ended
12/31/11
Plant 6,741,790
Regulatory assets 312,521
Regulatory liabilities (465,593)
Unamortized debt expense 2,509,015
Unamortized discount 326,339
Water rights 1,042,009
Other 559,790
11,025,871
chedule Page 120 Line No 13 Column b
Cash paid during the period for
Income taxes (1,033,185)
Interest (net of amount capitalized) 70,490,892
jhedule Page 120 Line No 18 Column b
Cash Flow from Operating Activities (Other) Twelve Months Ended
Pension and postretirement benefit plan expense 45,223,307
Contributions to pension and postretirement benefit plans (22,088,331)
Gain on sale of renewable energy certificates (398,050)
Unbilled revenues 1,523,652
Other rioncash adjustments to net income 1,762,799
Accrued interest (2,000,069)
Customer deposits 9432 385
Other assets and liabilities (6,048,439)
27407 254
ige: 120 Line No.: 26 Column: b
Non-cash investing activities
Additions to PP&E in accounts payable 26,330,730
[Schedule Page 120 Line No 31 Column: b
Other Cash Flows from Plant Twelve Months Ended
12/31/11
Sale of emission allowances and renewable energy certificates 6,314,273
6,314,273
[Schedule Page 120 Line No 53 Column b
Other Investing Cash Flows Twelve Months Ended
12/31/11
Disbursements from rabbi trust 2,491 855
Net change in notes receivable from subsidiary (2,950,091)
Miscellaneous other investing activities (35,655)
(493,891)
JFERC FORM NO I (ED 12-87) Page 4501
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Idaho Power Company 2nResubmission End of 2011 /Q4
04/13/2012
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
1.Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate.
2.Report in columns (t) and (g) the amounts of other categories of other cash flow hedges.
3.For each category of hedges that have been accounted for as "fair value hedges", report the accounts affected and the related amounts in a footnote.
4.Report data on a year-to-date basis.
Line Item Unrealized Gains and Minimum Pension Foreign Currency Other
No Losses on Available- Liability adjustment Hedges Adjustments
for-Sale Securities (net amount)
(a) (b) (c) (d) (e)
1 Balance of Account 219 at Beginning of
- Preceding Year 1,820,172 ( 10,086,835)
2 Preceding Qtr/Yr to Date Reclassifications
from Acct 219 to Net Income 708,772
3 Preceding Quarter/Year to Date Changes in
Fair Value 1,149,129 ( 3,158,753)
4 Total (lines 2 and 3) 1,149,129 ( 2,449,981)
5 Balance of Account 219 at End of
- Preceding Quarter/Year 2,969,301 ( 12,536,816)
6 Balance of Account 219 at Beginning of
- Current Year 2,969,301 ( 12,536,816)
7 Current Qtr/Yr to Date Reclassifications
- from Acct 219 to Net Income 934,902
8 Current Quarter/Year to Date Changes in
- Fair Value ( 400,010) ( 2,589,429)
9 Total (lines 7 and 8) ( 400,010) ( 1,654,527)
10 Balance of Account 219 at End of Current
- Quarter/Year 2,569,291 ( 14,191,343)
FERC FORM NO. I (NEW 06-02) Page 122a
Name of Respondent
Idaho Power Company
This Re Is: p
(1)Original
(2)[p A Resubmission
Date of Report
(Mo, Da, Yr)
04/13/2012
Year/Period of Report
End of 2011/04
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
-
Line
No.
-
Other Cash Flow
Hedges
Interest Rate Swaps
(f)
Other Cash Flow
Hedges
(Specify]
(g)
Totals for each
category of items
recorded in
Account 219
(h)
Net Income (Carried
Forward from
Page 117, Line 78)
(I)
Total
Comprehensive
Income
(I)
I ( 8,266,663)
2 708,772
3 ( 2,009,624)
4 ( 1300852) 140,634,223 1 139333371
5 ( 9,567,515)
6 ( 9,567,515)
934,902
8 ( 2,989,439)
9 ( 2,054,537) 164 749627 I 162,69 090
10 ( 11,622,052)
FERC FORM NO. I (NEW 06-02)
Page 122b
Name of Respondent This Report Is: Date of Report Year/Period of Report
Idaho Power Company (1) M An Original
04/13/2012 End of 2011/Q4 (2) D A Resubmission
NOTES TO FINANCIAL STATEMENTS
1.Use the space below for important notes regarding the Balance Sheet, Statement of Income for the year, Statement of Retained
Earnings for the year, and Statement of Cash Flows, or any account thereof. Classify the notes according to each basic statement,
providing a subheading for each statement except where a note is applicable to more than one statement.
2.Furnish particulars (details) as to any significant contingent assets or liabilities existing at end of year, including a brief explanation of
any action initiated by the Internal Revenue Service involving possible assessment of additional income taxes of material amount, or of
a claim for refund of income taxes of a material amount initiated by the utility. Give also a brief explanation of any dividends in arrears
on cumulative preferred stock.
3.For Account 116, Utility Plant Adjustments, explain the origin of such amount, debits and credits during the year, and plan of
disposition contemplated, giving references to Cormmission orders or other authorizations respecting classification of amounts as plant
adjustments and requirements as to disposition thereof.
4.Where Accounts 189, Unamortized Loss on Reacquired Debt, and 257, Unamortized Gain on Reacquired Debt, are not used, give
an explanation, providing the rate treatment given these items. See General Instruction 17 of the Uniform System of Accounts.
5.Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such
restrictions.
6.If the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders are
applicable and furnish the data required by instructions above and on pages 114-121, such notes may be included herein.
7.For the 3Q disclosures, respondent must provide in the notes sufficient disclosures so as to make the interim information not
misleading. Disclosures which would substantially duplicate the disclosures contained in the most recent FERC Annual Report may be
omitted.
8.For the 3Q disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurred
which have a material effect on the respondent. Respondent must include in the notes significant changes since the most recently
completed year in such items as: accounting principles and practices; estimates inherent in the preparation of the financial statements;
status of long-term contracts; capitalization including significant new borrowings or modifications of existing financing agreements; and
changes resulting from business combinations or dispositions. However were material contingencies exist, the disclosure of such
matters shall be provided even though a significant change since year end may not have occurred.
9.Finally, if the notes to the financial statements relating to the respondent appearing in the annual report to the stockholders are
applicable and furnish the data required by the above instructions, such notes may be included herein.
PAGE 122 INTENTIONALLY LEFT BLANK
SEE PAGE 123 FOR REQUIRED INFORMATION.
FERC FORM NO. 1 (ED. 12-96) Page 122
U
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)_ A Resubmission 04/13/2012 2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Idaho Power (IPC), a wholly-owned subsidiary of IDACORP, Inc., is an electric utility 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.
(IERC0), a joint venturer in Bridger Coal Company (BCC), which mines and supplies coal to the Jim Bridger generating plant owned
in part by Idaho Power. IERCo is accounted for using the equity method.
Basis of Reporting
The financial statements include the assets, liabilities, 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 subsidiary on the
equity method rather than consolidating the assets, liabilities, revenues, and expenses of the subsidiary, as required by U.S. GAAP.
The accompanying financial statements include the Company's proportionate share of utility plant and related operations resulting
from its interest in jointly owned plants. In addition, under the requirements of the FERC, there are differences from U.S. GAAP in
the presentation of (1) current portion of long-term debt, (2) assets and liabilities for cost of removal of assets, (3) regulatory assets and
liabilities, (4) deferred income taxes, (5) income tax expense and (6) non-utility revenues.
Management Estimates
Management makes estimates and assumptions when preparing financial statements in conformity with generally accepted accounting
principles (GAAP). These estimates and assumptions include those related to rate regulation, retirement benefits, contingencies,
litigation, asset impairment, income taxes, unbilled revenues, and bad debt. These estimates and assumptions affect the reported
amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements, and the
reported amounts of revenues and expenses during the reporting period. These estimates involve judgments with respect to, among
other things, future economic factors that are difficult to predict and are beyond management's control. As a result, actual results
could differ from those estimates.
System of Accounts
The accounting records of Idaho Power conform to the Uniform System of Accounts prescribed by the FERC and adopted by the
public utility commissions of Idaho, Oregon, and Wyoming.
Regulation of Utility Operations
Idaho Power's financial statements reflect the effects of the different ratemaking principles followed by the jurisdictions regulating
Idaho Power. The application of accounting principles 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 instances, the amounts are deferred as
regulatory assets or regulatory liabilities on the balance sheet and recorded on the income statement when recovered or returned in
rates. Additionally, regulators can impose regulatory liabilities upon a regulated company for amounts previously collected from
customers and for amounts that are expected to be refunded to customers. The effects of applying these regulatory accounting
principles to Idaho Power's operations are discussed in more detail in Note 3.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand and highly-liquid temporary investments that mature within 90 days of the date of
acquisition.
Receivables and Allowance for Uncollectible Accounts
Customer receivables are recorded at the invoiced amounts and do not bear interest. A late payment fee of one percent may be
assessed on account balances after 30 days. An allowance is recorded for potential uncollectible accounts. The allowance is reviewed
periodically and adjusted based upon a combination of historical write-off experience, aging of accounts receivable, and an analysis of
specific customer accounts. Adjustments are charged to income. Customer accounts receivable balances that remain outstanding after
reasonable collection efforts are written off through a charge to the allowance and a credit to accounts receivable.
IFERC FORM NO 1 (ED 12-88) Page 123.1 I
Name of Respondent This Report is: Date of Report Year Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)_ A Resubmission 04/13/2012 2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
after reasonable collection efforts are written off through a charge to the allowance and a credit to accounts receivable.
Other receivables, are also reviewed for impairment periodically, based upon transaction-specific facts. When it is probable that
Idaho Power will be unable to collect all amounts due according to the contractual terms of the agreement, an allowance is established
for the estimated uncollectible portion of the receivable and charged to income.
There were no impaired receivables without related allowances at December 31, 2011 and 2010. Once a receivable is determined to
be impaired, any further interest income recognized is fully reserved.
Derivative Financial Instruments
Financial instruments such as commodity futures, forwards, options, and swaps are used to manage exposure to commodity price risk
in the electricity and natural gas markets. All derivative instruments are recognized as either assets or liabilities at fair value on the
balance sheet. Idaho Power's physical forward contracts qualify for the normal purchases and normal sales exception to derivative
accounting requirements with the exception of forward contracts for the purchase of natural gas for use at Idaho Power's natural gas
generation facilities. The objective of the risk management program is to mitigate the price risk associated with the purchase and sale
of electricity and natural gas. Because of Idaho Power's regulatory accounting mechanisms, Idaho Power records the changes in fair
value of derivative instruments related to power supply as regulatory assets or liabilities.
Revenues
Operating revenues related to Idaho Power's sale of energy are recorded when service is rendered or energy is delivered to
customers. Idaho Power accrues estimated unbilled revenues for electric services delivered to customers but not yet billed at
year-end. Idaho Power collects franchise fees and similar taxes related to energy consumption. None of these collections are reported
on the income statement. Beginning in February 2009, Idaho Power is collecting in base rates a portion of the allowance for funds
used during construction (AFUDC) related to its Hells Canyon relicensing project. Cash collected under this ratemaking mechanism
is not recorded as revenue, but is instead recorded as a regulatory liability.
Property, Plant and Equipment and Depreciation
The cost of utility plant in service represents the original cost of contracted services, direct labor and material, AFUDC, and indirect
charges for engineering, supervision, and similar overhead items. Repair and maintenance costs associated with planned major
maintenance are expensed as the costs are incurred, as are maintenance and repairs of property and replacements and renewals of
items determined to be less than units of property. For utility property replaced or renewed, the original cost plus removal cost less
salvage is charged to accumulated provision for depreciation, while the cost of related replacements and renewals is added to
property, plant and equipment.
All utility plant in service is depreciated using the straight-line method at rates approved by regulatory authorities. Annual
depreciation provisions as a percent of average depreciable utility plant in service approximated 2.83 percent in 2011 and 2.84 percent
in 2010.
Long-lived assets are periodically reviewed for impairment when events or changes in circumstances indicate that the carrying
amount of an asset may not be recoverable. If the sum of the undiscounted expected future cash flows from an asset is less than the
carrying value of the asset, impairment must be recognized in the financial statements. There were no material impairments of these
assets in 2011 or 2010.
Allowance for Funds Used During Construction
AFUDC represents the cost of financing construction projects with borrowed funds and equity funds. With one exception, cash is not
realized currently from such allowance; it is realized under the ratemaking process over the service life of the related property through
increased revenues resulting from a higher rate base and higher depreciation expense. The component of AFUDC attributable 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 2011 and 2010 were 7.8 percent and 8.0 percent, respectively. Idaho Power's reductions
to interest expense for AFUIDC were $13 million for 2011 and $11 million for 2010 Other income included $25 million and $17
IFERC FORM NO I (ED 12-88) Page 1232
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)_ A Resubmission 04/13/2012 2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
million of AFUDC for 2011 and 2010, respectively.
Income Taxes
Idaho Power accounts for income taxes under the asset and liability method which requires the recognition of deferred tax assets and
liabilities for the expected future tax consequences of events that have been included in the financial statements. Under this method,
deferred tax assets and liabilities are determined based on the differences between the financial statements and tax basis of assets and
liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. The effect of a change in tax
rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.
Consistent with orders and directives of the Idaho Public Utilities Commission (IPUC), the regulatory authority having principal
jurisdiction over Idaho Power's Idaho service territory, Idaho Power's deferred income taxes for plant-related items (commonly
referred to as normalized accounting) are primarily provided for the difference between income tax depreciation and book
depreciation used for financial statement purposes. Unless contrary to applicable income tax guidance, deferred income taxes are not
provided for those income tax timing differences where the prescribed regulatory accounting methods direct Idaho Power to recognize
the tax impact currently for rate making and financial reporting. Regulated enterprises are required to recognize such adjustments as
regulatory assets or liabilities if it is probable that such amounts will be recovered from or returned to customers in future rates
The State of Idaho allows a three percent investment tax credit on qualifying plant additions Investment tax credits earned on
regulated assets are deferred and amortized to income over the estimated service lives of the related properties. Credits earned on
non-regulated assets or investments are recognized in the year earned.
Income taxes are discussed in more detail in Note 2.
Comprehensive Income
Comprehensive income includes net income unrealized holding gains and losses on available-for-sale marketable securities, and
amounts related to a deferred compensation plan for certain senior management employees and directors called the Senior
Management Security Plan The following table presents and Idaho Power's accumulated other comprehensive loss balance at
December 31 (net of tax)
2011 2010
(thousands of dollars)
Unrealized holding gains on available-for-sale securities $ 2,569 $ 2,969
Senior Management Security Plan (14,191) (12,537)
Total $ (11,622) $ (9,568)
Other Accounting Policies
Debt discount, expense, and premium are deferred and are being amortized over the terms of the respective debt issues.
New Accounting Pronouncements
The Financial Accounting Standards Board (FASB) has issued the following accounting guidance which is effective for years
beginning after December 15 2011
• In May 2011, the FASB issued guidance to provide a consistent definition of fair value and ensure that the fair value
measurement and disclosure requirements are similar between generally accepted accounting principles in the United States
and International Financial Reporting Standards. The guidance changes certain fair value measurement principles and
enhances the disclosure requirements, particularly for Level 3 fair value measurements. Idaho Power is currently assessing
the impact of the guidance but do not believe that the adoption of this guidance will have a material effect on their
IFERC FORM NO I (ED 12-88) Page 1233
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Idaho Power Company (2)- A Resubmission 04/1312012 201 1/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
consolidated financial statements.
2. INCOME TAXES:
A reconciliation between the statutory federal income tax rate and the effective tax rate is as follows:
2011 2010
(thousands of dollars)
Federal income tax expense at 35% statutory rate $ 42,116 $ 51,614
Change in taxes resulting from:
Equity earnings of subsidiary companies (2,089) (2,641)
AFUDC (13,586) (9,529)
Capitalized interest 6,465 3,674
Investment tax credits (3,355) (3,378)
Removal costs (2,244) (2,850)
Capitalized overhead costs (5,950) (3,500)
Capitalized repair costs (14,000) (10,500)
Tax method change - uniform capitalization - (65,333)
Tax method change - capitalized repairs - (44,466)
Uncertain tax positions - established - 74,436
Uncertain tax positions - settled (63,138) (1,138)
State income taxes, net of federal benefit 1,846 5,074
Depreciation 14,100 13,138
Other, net (4,583) 2,233
Total income tax (benefit) expense $ (44,418) $ 6,834
Effective tax rate (36.91%) 4.6%
The items comprising income tax (benefit) expense are as follows:
2011 2010
(thousands of dollars)
Income taxes currently payable:
Federal $ 7,832 $ (62,068)
State 7,296 (5,579)
Total 15,128 (67,647)
Income taxes deferred:
Federal 22,942 6,752
State (6,920) (4,036)
Total 16,022 2,716
Uncertain tax positions:
Federal (66,225) 65,222
State (8,211) 8,076
Total (74,436) 73,298
Investment tax credits:
Deferred 2,223 1,844
Restored (3,355) (3,377)
Total (1,132) (1,533)
Total income tax (benefit) expense $ (44,418) $ 6,834
IFERC FORM NO I (ED 12-88) Page 1234 1
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Idaho Power Company (2)- A Resubmission 04/13/2012 2011/04
NOTES TO FINANCIAL STATEMENTS (Continued)
The components of the net deferred tax liability are as follows:
2011 2010
(thousands of dollars)
Deferred tax assets:
Regulatory liabilities $ 45,473 $ 46,199
Advances for construction 5,118 7,061
Deferred compensation 22,067 21,045
Advanced payments 12,958 8,292
Power cost adjustments 1,711 -
Tax credits 8,547 6,461
Revenue sharing 10,594 -
Retirement benefits 122,445 88,827
Other 3,758 4,422
Total 232,671 182,307
Deferred tax liabilities:
Property, plant and equipment 333,335 284,794
Regulatory assets 599,992 422,216
Conservation programs 3,464 7,611
Power cost adjustments - 11,833
Retirement benefits 122,712 93,997
Other 15,956 11,146
Total 1,075,459 831 ,597
Net deferred tax liabilities $ 842,788 $ 649,290
IDACORP s tax allocation agreement provides that each member of its consolidated group compute its income taxes on a separate
company basis. Amounts payable or refundable are settled through IDACORP.
Tax Credits Carryforwards
As of December 31, 2011, Idaho Power had $8.5 million of Idaho investment tax credit carryforward. Idaho investment tax credit
expires from 2023 to 2025.
Uncertain Tax Positions
A reconciliation of the beginning and ending amount of unrecognized tax benefits for Idaho Power is as follows (in thousands of
dollars):
2011 2010
Balance at January 1, $ 74,436 $ 1,138
Additions for tax positions of the current year - 2,822
Additions for tax positions of prior years - 71,614
Reductions for tax positions of prior years (66,379) (1138)
Settlements with taxing authorities (8,057) -
Balance at December 31, $ - $ 74,436
Idaho Power recognizes interest accrued related to unrecognized tax benefits as interest expense and penalties as other expense.
Idaho Power recognized a net reduction in interest expense of $0.2 million in 2011 and interest expense of $0.2 million in 2010.
Accrued interest was was zero as of December 31, 2011 and $0.2 million as of December 31, 2010. No penalties are accrued.
IDACORP and Idaho Power are subject to examination by their major tax jurisdictions - U.S. federal and the State of Idaho. 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)
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NOTES TO FINANCIAL STATEMENTS (Continued)
open tax years are 2011 for federal and 2008-2011 for Idaho. In May 2009, IDACORP and Idaho Power formally entered the U.S.
Internal Revenue Service (IRS) Compliance Assurance Process (CAP) program for their 2009 tax year and has remained in the CAP
program for all subsequent years. The CAP program provides for IRS examination and issue resolution throughout the current year
with the objective of return filings containing no contested items.
With the resolution of Idaho Power's capitalized repairs and uniform capitalization tax accounting methods examinations (discussed
below), the 2009 tax year is now closed for federal purposes. In 2011, the IRS also completed its examination of IDACORP's 2010
tax year with no unresolved income tax issues. Idaho Power believes there are no remaining material tax uncertainties for 2011 and
prior tax years.
Tax Accounting Method Change for Repair-Related Expenditures
In June 2010, Idaho Power completed its evaluation of a tax accounting method change for its 2009 tax year that allows a current
income tax deduction for repair-related expenditures on its utility assets that are currently capitalized for financial reporting and tax
purposes. In September 2010, Idaho Power adopted this method following the automatic consent procedures with the filing of
IDACORP's 2009 consolidated federal income tax return. The method was subject to audit under IDACORP's 2009 CAP
examination.
For the year ended December 31, 2010, Idaho Power recorded a $44.5 million tax benefit related to the filed deduction for the
cumulative method change adjustment and an additional $11.7 million tax benefit for the annual deduction estimate included in its
2010 income tax provision. As of December 31, 2010, Idaho Power had a current uncertain tax position liability of $14.7 million
related to this method.
In April 2011, IDACORP and the IRS reached an agreement on Idaho Power's tax accounting method change for capitalized repairs.
Accordingly, the IRS finalized the 2009 CAP examination and submitted its report on the 2009 tax year to the U.S. Congress Joint
Committee on Taxation (Joint Committee) for review. Idaho Power considers the capitalized repairs method effectively settled and
believes that no material income tax uncertainties remain for the method. As such, Idaho Power recognized $3.4 million of its
previously unrecognized tax benefits for this method in 2011.
For the year ended December 31, 2011, the capitalized repairs annual tax deduction estimate included in Idaho Power's income tax
provision produced a $15.6 million tax benefit. The amount of this annual tax deduction will vary depending on a number of factors,
but most directly by the amount and type of Idaho Power's annual capital additions. The reversal of this temporary difference from
prior years will offset a portion of the ongoing annual benefit.
Idaho Power's prescribed regulatory accounting treatment requires immediate income recognition for temporary tax differences of this
type. A regulatory asset is established to reflect Idaho Power's ability to recover increased income tax expense when such temporary
differences reverse.
Tax Accounting Method Change for Uniform Capitalization
In September 2009, the IRS issued Industry Director Directive #5 (IDD), which discusses the IRS's compliance priorities and audit
techniques related to the allocation of mixed service costs in the uniform capitalization methods of electric utilities. Within
IDACORP's 2009 CAP examination, the IRS and Idaho Power worked through the impact the IDD guidance had on Idaho Power's
uniform capitalization method and reached agreement during 2010. The agreement provided that Idaho Power change its uniform
capitalization method to the agreed upon method under the IDD with the filing of IDACORP's 2009 consolidated federal income tax
return. While Idaho Power had an agreement with the IRS for examination and return filing purposes, the agreement required Joint
Committee approval to be final.
The resulting tax deductions available under the agreed upon uniform capitalization method were significantly greater than Idaho
Power's prior method. For the year ended December 31, 2010, Idaho Power recorded a tax benefit of $65.3 million related to the
IFERC FORM NO.1 (ED. 12-88) Paae 123.6 - 1
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Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Idaho Power Company (2)- A Resubmission 04/1312012 2011/04
NOTES TO FINANCIAL STATEMENTS (Continued)
cumulative method change adjustment (tax years 1986 through 2009) for this method and $5.6 million of tax expense from the
reversal of this temporary difference. As of December 31, 2010, Idaho Power had a current uncertain tax position liability equal to
the $59.7 million net tax benefit recorded for the method change. Due to the method change agreement with the IRS, Idaho Power
reversed the uncertain tax position liability for its 2009 uniform capitalization deduction, resulting in a $1.1 million tax benefit for the
year ended December 31, 2010.
In September 2011, the IRS notified IDACORP that the Joint Committee had completed its review of IDACORP's 2009 tax year and
approved the uniform capitalization method agreement. Idaho Power considers the uniform capitalization method effectively settled
and believes that no material income tax uncertainties remain for the method. Accordingly, Idaho Power recognized $56.9 million of
its previously unrecognized tax benefits for tax years 2009 and prior in 2011.
For the year ended December 31 2011 the uniform capitalization annual tax deduction estimate included in Idaho Power's income
tax provision produced a $6.6 million tax benefit. The amount of this annual tax deduction will vary depending on a number of
factors, but most directly by the amount and type of Idaho Power's annual capital additions. The reversal of this temporary difference
from prior years will offset a portion of the ongoing annual benefit. The prescribed regulatory accounting treatment for this method is
the same as discussed earlier for the capitalized repairs method.
Cash Impacts of Tax Method Changes
In 2011 Idaho Power paid previously accrued income tax liabilities of $8.1 million related to the capitalized repairs examination
agreement. There were no 2011 cash impacts related to the uniform capitalization method settlement as income tax refunds for the
method change were received in 2010.
In 2010, Idaho Power realized federal and state cash benefits associated with the 2009 capitalized repairs and uniform capitalization
method changes of $42 million. The majority of this cash benefit was realized through reductions to cash payments that would have
otherwise been owed to taxing authorities for the 2009 tax year and a federal refund of $24 million received in 2010. Additionally,
approximately $6 million of state cash benefits were realized through reduced tax payments for the 2010 year.
The capitalized repairs and uniform capitalization method changes produced an income statement tax benefit of $44.5 million and
$65.3 million, respectively, in 2010 prior to the accrual for uncertain tax positions. A portion of this earnings benefit related to
previously deferred income tax expense being flowed through the income statement, which does not deliver any cash benefits. In
addition, federal tax credits of $17 million previously recognized were restored due to the reduction of 2009 taxable income by the
two method changes. The restored credits were a reduction to cash received in 2010, but will be available to deliver cash benefits in
future periods.
3. REGULATORY MATTERS
Regulatory Assets and Liabifities
Regulatory assets represent incurred costs that have been deferred because it is reasonably expected they will be recovered through
future rates collected from customers. Regulatory liabilities represent obligations to make refunds to customers for previous
collections, except for cost of removal (which represents the cost of removing future electric assets). The following table presents a
summary of Idaho Power's regulatory assets and liabilities (in thousands of dollars):
I
[FERC FORM NO. I (ED. 12-88) Page 123.7 I
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(1) X An Original (Mo, Da, Yr)
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NOTES TO FINANCIAL STATEMENTS (Continued)
Remaining Earning a Not Earning
Amortization Return (1) a Return Total as of December 31,
Description Period 2011 2010
Regulatory Assets:
Income taxes $ - $ 603,772 $ 603,772 $ 429,457
Unfunded postretirement benefits(2) - 262,503 262,503 182,742
Pension expense deferrals(3) 2012-2015 38,976 19,068 58,044 63,833
Energy efficiency program costs(3) 15,956 - 15,956 19,467
Power supply costs(3) Varies 8,490 - 8,490 29,753
Fixed cost adjustment(3) Varies 14,457 - 14,457 12,340
Asset retirement obligations(4) - 15,557 15,557 15,372
Mark-to-market liabilities(S) - 4,707 4,707 2,278
Other 2012-2021 993 2,868 3,861 6,184
Total $ 78,872 $ 908,475 $ 987,347 $ 761,426
Regulatory Liabilities:
Income taxes $ - $ 49,253 $ 49,253 $ 53,440
Removal costs(4) - 163,173 163,173 157,642
Investment tax credits - 70,841 70,841 71,972
Deferred revenue-AFUDC (3) 21,034 12,111 33,145 21,211
Power supply costs (3) Varies 13,121 - 13,121 -
2010 Settlement agreement sharing 2013 - 27,099
mechanism(3) 27,099
Mark-to-market assets(S) - 3,754 3,754 573
Other 2012 1,250 159 1,409 8,508
Total $ 62,504 $ 299,291 $ 361,795 $ 313,346
(1)Earning a return includes either interest or a return on the investment as a component of rate base at the allowed rate of return.
(2)Represents the unfunded obligation of Idaho Power's pension and postretirement benefit plans, which are discussed in Note 10.
(3)These items are discussed in more detail below.
(4)Asset retirement obligations and removal costs are discussed in Note 12.
(5)Mark-to-market assets and liabilities are discussed in Note 15.
Idaho Power's regulatory assets and liabilities are amortized over the period in which they are reflected in customer rates. In the
event that recovery of Idaho Power's costs through rates becomes unlikely or uncertain, regulatory accounting would no longer apply
to some or all of Idaho Power's operations and the items above may represent stranded investments. If not allowed full recovery of
these items, Idaho Power would be required to write off the applicable portion, which could have a significant financial impact.
Power Cost Adjustment Mechanisms and Deferred Power Supply Costs
In both its Idaho and Oregon jurisdictions, Idaho Power's power cost adjustment (PCA) mechanisms address the volatility of power
supply costs and provide for annual adjustments to the rates charged to its retail customers. The PCA mechanisms compare Idaho
Power's actual and forecast net power supply costs (primarily fuel and purchased power less off-system sales) against net power
supply costs currently being recovered in retail rates.
Under the PCA mechanisms, certain differences between actual net power supply costs incurred by Idaho Power and the costs
included in retail rates are recorded as a deferred charge or credit on the balance sheets for future recovery or refund through retail
rates. The power supply costs deferred primarily result from changes in wholesale market prices and transaction volumes, changes in
contracted power purchase prices and volumes, and the levels of hydroelectric and thermal generation.
IFERC FORM NO I (ED 12-88) Page 1238 I
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(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)_ A Resubmission 04/13/2012 2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Idaho Jurisdiction Power Cost Adjustment Mechanism: In the Idaho jurisdiction, the annual PCA adjustments are based on (a) a
forecast component, based on a forecast of net power supply costs in the coming year as compared to net power supply costs in base
rates; and (b) a true-up component, based on the difference between the previous year's actual net power supply costs and the
previous year's forecast. The latter component also includes a balancing mechanism so that, over time, the actual collection or refund
of authorized true-up dollars matches the amounts authorized. The Idaho PCA mechanism also includes:
• a cost or benefit sharing ratio that allocates the deviations in net power supply expenses between customers (95 percent)
and shareholders (5 percent), with the exception of expenses associated with PTJRPA power purchases, which are
allocated 100 percent to customers;
• a load change adjustment rate (LCAR), which is intended to eliminate recovery of power supply expenses already
collected in rates associated with load changes resulting from changing weather conditions, a growing customer base, or
changing customer use patterns; and
• third-party transmission expenses (paid to third parties to facilitate wholesale purchases and sales of energy) as a
component of net power supply costs for purposes of calculating the PCA.
The table below summarizes Idaho PCA rate adjustments during the years ended December 31, 2011 and 2010.
Effective $ Change
Date (millions) Notes
June 1, 2011 $ (40.4) The reduction to Idaho PCA rates was net of $10.0 million of Idaho Power's energy
efficiency rider deferral balance that the IPUC authorized for recovery in Idaho Power's
Idaho PCA rates.
June 1, 2010 $ (146.9) The IPUC's order was made in conjunction with a January 2010 rate settlement agreement
described below in "January 2010 and December 2011 Idaho Settlement Agreements."
Concurrent with the PCA rate decrease, the IPUC authorized an $88.7 million increase in base
rates, $63.7 million of which was related to power supply costs.
Oregon Jurisdiction Power Cost Adjustment Mechanism: Idaho Power's power cost recovery mechanism in Oregon has two
components an annual power cost update (APCU) and a power cost adjustment mechanism (PCAM) The APCU allows Idaho
Power to reestablish its Oregon base net power supply costs annually, separate from a general rate case, and to forecast net power
supply costs for the upcoming water year. The PCAM is a true-up filed annually in February. The filing calculates the deviation
between actual net power supply expenses incurred for the preceding calendar year and the net power supply expenses recovered
through the A1CU for the same period. Under the PCAM, Idaho Power is subject to a portion of the business risk or benefit
associated with this deviation through 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 sharing of costs and benefits between customers and Idaho Power. However, collection by Idaho Power will occur only to the
extent that Idaho Power's actual return on equity (ROE) for the year is no greater than 100 basis points below Idaho Power's last
authorized ROE. A refund to customers will occur only to the extent that Idaho Power's actual ROE for that year is no less than 100
basis points above Idaho Power's last authorized ROE
Oregon jurisdiction power supply cost changes under the APCU and PCAM during the years ended December 31, 2011 and 2010
were as follows:
Year and
Mechanism APCU or PCAM Adjustment
2011 PCAM Actual net power supply costs were below the deadband, resulting in a $1.5 million deferral.
2011 APCU A rate decrease of $2.2 million annually took effect June 1, 2011.
2010 PCAM Actual net power supply costs were within the deadband, resulting in no deferral.
2010 APCU A rate increase of $2.6 million annually took effect June 1, 2010.
IFERC FORM NO I (ED 12-88) Page 1239
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 04/13/2012 2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Idaho Regulatory Matters
2011 Idaho General Rate Case and Settlement: On June 1, 2011, Idaho Power filed a general rate case and proposed rate schedules
with the IPUC, Case No. IPC-E-11-08. The filing was based on a 2011 test year and requested approximately $82.6 million in
additional Idaho jurisdiction annual revenues in base rates, a 9.9 percent overall average rate increase for Idaho customers.
On September 23, 2011, Idaho Power, the IPUC Staff, and other interested parties publicly filed a settlement stipulation with the
IPUC resolving most of the key contested issues in the Idaho general rate case. On December 30, 2011, the IPUC issued an order
approving the settlement stipulation. The settlement stipulation approved by the December 30, 2011 order provides for a 7.86 percent
authorized rate of return on an Idaho-jurisdictional rate base of approximately $2.36 billion. The approved settlement stipulation
resulted in a 4.07 percent, or $34.0 million, overall increase in Idaho Power's annual Idaho jurisdictional base rate revenues, effective
January 1, 2012. Neither the order nor the settlement stipulation specified an authorized rate of return on equity.
The settlement stipulation approved by the order also addressed Idaho Power's calculation of the LCAR to be applied in Idaho
Power's PCA mechanism. The LCAR adjusts power supply cost recovery within the Idaho PCA formula upwards or downwards for
differences between actual load and the load used in calculating base rates. The settlement stipulation provides for a LCAR of $18.16
per megawatt-hour, effective January 1, 2012, compared to the rate of $19.67 per megawatt-hour in effect prior to that date.
In its general rate case application, Idaho Power had requested approval of the current fixed cost adjustment (FCA) mechanism pilot
program, described below, as a permanent rate mechanism for residential and small commercial class customers. Neither the
December 30, 2011 order nor the settlement stipulation resolves whether the fixed cost adjustment pilot program should be made
permanent.
Neither the order nor the settlement stipulation imposes a moratorium on Idaho Power's filing a general revenue requirement case at a
future date.
January 2010 and December 2011 Idaho Settlement Agreements: On January 13, 2010, the IPUC approved a settlement agreement
among Idaho Power, several of Idaho Power's customers, the IPUC Staff, and others. Significant elements of the settlement
agreement included:
a specified distribution of the reduction in 2010 PCA that would reduce customer rates, provide up to a $25 million
general increase in annual base rates, and reset base power supply costs for the PCA, effective with the June 1, 2010 PCA
rate change. This provision anticipated a significant reduction in PCA rates for the 2010-2011 PCA year;
a provision to share with Idaho customers 50 percent of any Idaho-jurisdiction earnings in excess of a 10.5 percent return
on equity in any calendar year from 2009 to 2011; and
a provision to allow the additional amortization of accumulated deferred investment tax credits (ADITC) if Idaho Power's
Idaho-jurisdiction rate of return on year-end equity (Idaho ROE) is below 9.5 percent in any calendar year from 2009 to
2011. Idaho Power was permitted to amortize additional ADITC in an amount up to $45 million over the three-year
period, but could use no more than $15 million in any one year unless there is a carryover. Carryover amounts were
added to the $15 million annual allowance up to a maximum amortization of $25 million in any one year.
On April 15, 2010, Idaho Power filed its annual application with the IPUC to implement new PCA rates to be effective June 1, 2010
through May 31, 2011, and to change base rates, pursuant to the terms of the January 2010 Idaho settlement agreement. On May 28,
2010, the IPUC issued its order approving a $146.9 million decrease in the PCA, along with a base rate increase of $88.7 million.
The net effect of these two rate adjustments was an overall decrease in customer rates of $58.2 million, effective June 1, 2010. The
$88.7 million base rate increase reflects a $63.7 million increase in base power supply costs and a $25 million increase in base rates.
Because Idaho Power's actual Idaho ROE was between 9.5 and 105 percent in 2009 and 2010 the sharing and amortization
IFERC FORM NO I (ED 12-88) Page 12310 1
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(11)X An Original (Mo, Da, Yr)
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NOTES TO FINANCIAL STATEMENTS (Continued)
provisions of the January 2010 settlement agreement were not triggered. However, recognition of income tax benefits in 2011 had a
significant impact on Idaho Power's actual Idaho ROE and contributed to the triggering of the sharing mechanism for 2011. In
accordance with the terms of the settlement agreement, Idaho Power recorded a $27.1 million reduction in revenue and regulatory
liability in 2011, reflecting 50 percent of Idaho Power's 2011 Idaho-jurisdictional earnings above a 10.5 percent Idaho ROE to be
shared with Idaho customers.
The sharing and ADITC amortization provisions of the January 2010 settlement agreement terminated on December 31 2011 On
December 27 2011 the IPUC issued an order, separate from the general rate case proceeding approving a settlement stipulation that
had been executed by Idaho Power, the IPUC Staff, and one large industrial customer of Idaho Power and filed with the IPUC on
December 12, 2011 The settlement stipulation provides that
• if Idaho Power's actual Idaho ROE for 2012 2013 or 2014 is less than 9.5 percent, then Idaho Power may amortize
additional ADITC to help achieve a minimum 9.5 percent Idaho ROE in the applicable year. Idaho Power would be
permitted to amortize additional ADITC in an aggregate amount up to $45 million over the three-year period but could use
no more that $25 million in 2012;
• if Idaho Power's actual Idaho ROE for 2012, 2013, or 2014 exceeds 10.0 percent the amount of Idaho Power's Idaho
jurisdictional earnings exceeding a 10.0 percent but less than a 10.5 percent Idaho ROE for the applicable year would be
shared equally between Idaho Power and its Idaho customers; and
• if Idaho Power's actual Idaho ROE for 2012, 2013, or 2014 exceeds 10.5 percent the amount of Idaho Power's Idaho
jurisdictional earnings exceeding a 10.5 percent Idaho ROE for the applicable year would be allocated 75 percent to Idaho
Power's Idaho customers and 25 percent to Idaho Power.
The settlement stipulation provides that the return on year-end equity thresholds (9.5 percent, 10.0 percent and 10.5 percent) will be
automatically adjusted prospectively in the event the IPUC approves a change to Idaho Power's authorized return on equity as part of
a general rate case proceeding seeking a rate change effective prior to January 1, 2015 The automatic adjustments would be as
follows (a) the 9.5 percent return on year-end equity trigger in the settlement stipulation would be replaced by the percentage equal to
95 percent of the new authorized return on equity, (b) the 10.0 percent return on year-end equity trigger in the settlement stipulation
would be re-established at the new authorized return on equity amount, and (c) the 10.5 percent return on year-end equity trigger in
the settlement stipulation would be replaced by the percentage equal to 105 percent of the new authorized return on equity.
In consideration of these terms the settlement stipulation provided that Idaho Power would also allocate to customers 75 percent of
Idaho Power's own share of 2011 Idaho jurisdictional earnings over a 10.5 percent Idaho ROE As a result, Idaho Power recorded in
2011 a $20.3 million pre-tax charge to pension expense and an associated decrease in deferred pension regulatory asset, representing
the additional amount to be allocated to Idaho customers.
Idaho Fixed Cost Adjustment: The FCA began as a pilot program for Idaho Power's Idaho residential and small general service
customers, running from 2007 through 2009. The FCA is designed to remove Idaho Power's disincentive to invest in energy
efficiency programs by separating (or decoupling) the recovery of fixed costs from the variable kilowatt-hour charge and linking it
instead to a set amount per customer. On April 29, 2010, the IPUC approved a two-year extension of the FCA pilot program,
effective retroactive to January 1 2010 through December 31 2011 On October 19 2011, Idaho Power filed an application with the
IPUC requesting that the FCA pilot program become permanent for residential and small general service customer classes effective
January 1, 2012; a determination from the IPUC is pending.
The following table summarizes recent FCA rate adjustments:
Annual Amount
FCA Year Period rates in effect (in millions)
2010 June 1,2011 -May 3l, 2012 9.3
2009 June 1,2010-May31,2011 6.3
IFERC FORM NO I (ED 12.88) Page 12311
Name of Respondent This Report is: Date of Report Year/Period of Report
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Idaho Power Company (2)A Resubmission 04/13/2012 201 1/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
2008 June 1,2009-May31, 2010 2.7
As of December 31, 2011, the deferral balance for the FCA was $14.5 million.
Defined Benefit Pension Plan Contribution Recovery: Idaho Power defers its Idaho-jurisdiction pension expense as a regulatory
asset until recovered from Idaho customers. As of December 31, 2011, Idaho Power's deferral balance was $58.0 million. Deferred
pension costs are expected to be amortized to expense to match the revenues received when contributions are recovered through
rates. Idaho Power only records a carrying charge on the unrecovered balance of cash contributions.
In May 2010, the IPUC approved Idaho Power's request to increase rates to allow recovery of Idaho Power's 2009 cash contribution
to its defined benefit pension plan, which contribution was made in September 2010. Idaho Power's application sought approval of
$5.4 million in pension cost recovery over a one-year period to allow recovery contemporaneous with Idaho Power's expected cash
contributions to the plan.
In September 2010, Idaho Power elected to make a $60 million contribution to its defined benefit pension plan, rather than the
minimum required funding amount, to bring the defined benefit pension plan to a more funded position, potentially reducing future
required contributions and Pension Benefit Guaranty Corporation premiums. On October 1, 2010, Idaho Power filed an application
with the IPUC requesting an order accepting Idaho Power's 2011 retirement benefits package, but not requesting recovery through
rates of additional pension plan contributions. On April 28, 2011, the IPUC issued an order accepting Idaho Power's 2011 retirement
benefits package.
On March 15, 2011, Idaho Power filed an application with the IPUC requesting an increase in the amount included in base rates for
recovery of the Idaho-allocated portion of Idaho Power's cash contributions to its defined benefit pension plan from the then-current
amount of $5.4 million to approximately $17.1 million annually. On May 19, 2011, the IPUC approved Idaho Power's application,
with new rates effective on June 1, 2011. In September 2011, Idaho Power contributed an additional $18.5 million to its defined
benefit pension plan.
Transmission Revenue Shortfall Filing: On January 15, 2009, the FERC issued an order that required Idaho Power to reduce its
transmission service rates to FERC jurisdictional customers and refund to transmission customers transmission revenues that Idaho
Power had received starting in 2006. This refund ultimately resulted in under-recovery of transmission costs by Idaho Power, and in
October 2009 the IPUC authorized Idaho Power to record an Idaho-jurisdiction regulatory asset for the transmission revenue shortfall,
for future recovery in customer rates. At December 31, 2011, the transmission revenue shortfall was $2.1 million. The IPUC ordered
that Idaho Power advise the IPUC when the FERC has issued its order on rehearing, following which Idaho Power may request a
commencement date for the amortization period for the regulatory asset. On December 7, 2011, the FERC issued an order denying
rehearing. Accordingly, on February 15, 2012, Idaho Power submitted an application to the IPUC seeking to include the $2.1 million
transmission revenue shortfall in customer rates, recoverable over a three-year period beginning June 1, 2012. As of the date of this
report, a determination and order from the IPUC is pending.
Energy Efficiency and Demand Response Programs: Idaho Power has implemented and/or manages a wide range of opportunities
for its customers to participate in energy efficiency and demand response programs.
On August 18, 2011, the IPUC issued an order approving Idaho Power's March 2011 application requesting that the IPUC designate
Idaho Power's 2010 Idaho energy efficiency rider expenditures of approximately $42 million as prudently incurred expenses. Idaho
Power's 2010 expenditures for rider-funded energy efficiency and demand response initiatives in its Idaho and Oregon jurisdictions
totaled $44.2 million. On March 16, 2010, Idaho Power filed an application with the IPUC requesting an order designating energy
efficiency expenditures of $50.7 million incurred in 2008 and 2009 as prudently incurred expenses. On November 16, 2010, the
IPUC issued an order designating all $50.7 million of energy efficiency expenditures as prudently incurred and approved for
ratemaking purposes.
IFERC FORM NO I (ED 12-88) Page 12312 1
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Name of Respondent This Report is: Date of Report Year/Period of Report
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Idaho Power Company (2)_ A Resubmission 04/13/2012 2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
On October 22, 2010, Idaho Power filed an application with the IPUC requesting acceptance of the company's demand-side resources
(DSR) business model, which included a request for authorization to (a) move demand response incentive payments out of the energy
efficiency rider and into the Idaho PCA on a prospective basis beginning on June 1, 2011, and thus subject to a true-up under the PCA
mechanism; (b) establish a regulatory asset for the direct incentive payments associated with Idaho Power's energy efficiency program
for large commercial and industrial customers, beginning January 1, 2011, so that Idaho Power may capitalize the direct incentive
payments associated with the program, include the costs associated with the program incentive payments in its rate base, and thus earn
a rate of return on a portion of its DSR activities; and (c) change the carrying charge on the existing energy efficiency rider balancing
account (from the then-current interest rate of 1.0 percent to Idaho Power's authorized rate of return). On April 1, 2011, the IPUC
issued an order stating that certain issues raised in the application are more properly considered in a general rate case proceeding.
However, the IPUC noted in its order that Idaho Power's energy efficiency rider balance includes approximately $10 million in
expenditures that have been previously approved by the IPUC for recovery, and thus authorized recovery of $10 million of the rider
balance in Idaho Power's Idaho PCA rates, beginning June 1 2011 In that order, the IPUC did not approve a change to the energy
efficiency rider balance carrying charge.
On May 17, 2011, the IPUC issued an order stating that it will allow Idaho Power to account for specified direct incentive payments
associated with Idaho Power's energy efficiency program for large commercial and industrial customers as a regulatory asset
beginning January 1, 2011 but with an amortization period to be determined later by the IPUC
In its June 1 2011 general rate case filing, Idaho Power requested authorization to treat demand response incentive payments as
power supply costs and establish a base or "normal" level of cost recovery of approximately $11.3 million for those demand response
incentive payments in rates. The Idaho general rate case settlement stipulation approved by the IPUC in December 2011 provides that
the $11.3 million of base level demand response incentive payments would be tracked as part of the Idaho PCA mechanism. The
December 2011 IPUC general rate case settlement order also reset Idaho Power's energy efficiency rider rate at 4.0 percent of the sum
of the monthly billed charges for the base rate components, a reduction from the 4.75 percent rider amount in effect prior to that date.
Langley Gulch Power Plant Ratemakuig Treatment On September 1 2009 Idaho Power received pre-approval from the IPUC to
include $396.6 million of construction costs in Idaho Power's rate base when the Langley Gulch power plant achieves commercial
operation Idaho Power may request recovery of additional costs if they exceed $396.6 million provided that the additional costs
were reasonably and prudently incurred.
Oregon Regulatory Matters
2011 Oregon General Rate Case: On July 29, 2011, Idaho Power filed a general rate case and proposed rate schedules with the
OPUC Case No UE 233 The filing requested a $5.8 million increase in annual Oregon jurisdictional revenues which, if approved,
would result in a 14.7 percent overall average rate increase for customers in the Oregon jurisdiction. The filing requested an
authorized rate of return on equity of 10.5 percent with an Oregon retail rate base of approximately $121.9 million, and a rate of
return on capital of 8.17 percent. Idaho Power, the OPUC Staff, and other interested parties executed and filed a partial settlement
stipulation with the OPUC on February 1, 2012, which resolves all matters in the general rate case other than the prudence of costs
associated with pollution control investments at the Jim Bridger coal plant. The settlement stipulation provides for a return on equity
of 9.9 percent and an overall rate of return of 7.757 percent. If the stipulation is approved by the OPUC, Idaho Power expects that
new rates will become effective on March 1, 2012. As of the date of this report, Idaho Power is unable to determine the outcome of
the proceeding.
2009 Oregon General Rate Case: On February 24, 2010, the OPUC approved a $5 million, or 15.4 percent, increase in base rates in
the Oregon jurisdiction. The new rates were effective March 1, 2010, and were based on a return on equity of 10.175 percent and an
overall rate of return of 8.061 percent. Idaho Power's previously authorized rate of return in Oregon was 7.83 percent.
Advanced Metering Infrastructure (AM1)
The AMI project provides the means to automatically retrieve energy consumption information, eliminating manual meter reading
JFERC FORM NO 1 (ED 12-88) Page 123.13
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/1312012 2011/04
NOTES TO FINANCIAL STATEMENTS (Continued)
expense. 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 clarified that Idaho Power can expect to include in rate base the Idaho portion of prudent capital costs of
deploying Alvil as it is placed in service up to the capital cost commitment estimate of $70.9 million, plus certain costs that the
company could not quantify with precision at the time of the application. The IPUC also clarified, 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
will eliminate or wholly offset the increase in Idaho Power's revenue requirement caused by the authorized depreciation period.
On May 29, 2009, the IPUC approved annual recovery of $10.5 million, effective June 1, 2009. The order was based on Idaho
Power's actual investment in AMI through the then-current date, annualized through December 31, 2009. The IPUC also allowed
Idaho Power to begin three-year accelerated depreciation of the existing metering equipment on June 1, 2009. The order reflects
annualized depreciation expense relating to AMI of $9.2 million. Actual depreciation expense recorded in 2011 and 2010 was $10.6
million and $10.6 million respectively. On May 28, 2010, the IPUC approved Idaho Power's March 15, 2010 application requesting
authorization to implement a $2.4 million base rate increase for identified customer classes to recover costs relating to the AMI
project, with the rate increase effective June 1, 2010.
In the Oregon jurisdiction, the OPUC approved accelerated depreciation and recovery of existing meters located in Oregon over an
18-month period beginning January 2009. The approval increased both rates and depreciation expense by $0.8 million in 2009 and
$0.4 million in 2010.
Idaho Power has completed the installation of substantially all smart meters associated with the AMI project. On February 15, 2012,
Idaho Power filed an application with the IPUC requesting authority to decrease its Idaho-jurisdiction base rates by $10.6 million
annually due to the removal of accelerated depreciation expense associated with non-AMI metering equipment. As of the date of this
report, a determination and order from the IPUC is pending.
Depreciation Filings
In connection with a depreciation study authorized by Idaho Power and conducted by a third party, on February 15, 2012, Idaho
Power filed an application with the IPUC seeking to institute revised depreciation rates for electric plant-in-service, based upon
updated net salvage percentages and service life estimates for all plant assets, and adjust Idaho-jurisdictional base rates to reflect the
revised depreciation rates. Idaho Power's application requested a $2.7 million increase in Idaho-jurisdictional base rates, with new
rates effective June 1, 2012. As of the date of this report, a determination and order from the IPUC is pending.
Federal Open Access Transmission Tariff (OATT) Rates
In 2006, Idaho Power moved from a fixed rate to a formula rate for transmission service provided under its OAT!', which allows
transmission rates to be updated annually based on financial and operational data Idaho Power files with the FERC. Idaho Power's
OAT!' rates submitted to the FERC in Idaho Power's three most recent annual OAT!' Final Informational Filings were as follows:
OATT Rate (per
Applicable Period KW year)*
October 1, 2009 to September 30, 2010 $ 15.83
October 1, 2010 to September 30, 2011 $ 19.60
October 1, 2011 to September 30, 2012 $ 19.79
* In September 2010, Idaho Power made corrections to its OAT!' rates for the period beginning October 1, 2007 through September
30, 2010, which resulted in the issuance of a $0.5 million refund to transmission customers.
IFERC FORM NO I (ED 12-88) Page 12314 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)An Original (Mo, Da, Yr)
Idaho Power Company (2)- A Resubmission 04/13/2012 2011/04
NOTES TO FINANCIAL STATEMENTS (Continued)
4. LONG-TERM DEBT
The following table summarizes long-term debt at December 31 (in thousands of dollars):
2011 2010
First mortgage bonds:
660% Series due 2011 $ - $ 120,000
4.75% Series due 2012 100,000 100,000
4.25% Series due 2013 70,000 70,000
6.025% Series due 2018 120,000 120,000
6.15% Series due 2019 100,000 100,000
450% Series Due 2020 130,000 130,000
3.40% Series Due 2020 100,000 100,000
6% Series due 2032 100,000 100,000
550% Series due 2033 70,000 70,000
5.50% Series due 2034 50,000 50,000
5.875% Series due 2034 55,000 55,000
530% Series due 2035 60,000 60,000
6.30% Series due 2037 140,000 140,000
6.25% Series due 2037 100,000 100,000
485% Series due 2040 100,000 100,000
Total first mortgage bonds 1,295,000 1,415,000
Pollution control revenue bonds
5.15% Series due 2024(1) 49,800 49,800
5.25% Series due 20260) 116,300 116,300
Variable Rate Series 2000 due 2027 4,360 4,360
Total pollution control revenue bonds 170,460 170,460
American Falls bond guarantee 19,885 19,885
Milner Dam note guarantee 6,382 7,446
Unamortized premium/discount - net (3,113) (3,440)
Total Idaho Power outstanding(2) $ 1,488,614 $ 1,609,351
(1)Humboldt County and Sweetwater County Pollution Control Revenue Bonds are secured by the first mortgage, bringing the total first mortgage bonds
outstanding at December 31 2011 to $1.461 billion
(2)At December 31, 2011 and 2010, the overall effective cost of Idaho Power's outstanding debt was 5.43 percent and 5.53 percent, respectively.
At December 31, 2011 the maturities for the aggregate amount of long-term debt outstanding were (m thousands of dollars)
2012 2013 2014 2015 2016 Thereafter
$ 101,064 $ 71,064 $ 1,064 $ 1,064 $ 1,064 $ 1,316,407
Idaho Power Long-Term Financing
[FERC FORM NO I (ED 12-88) Page 123.15
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)- A Resubmission 04/13/2012 2011/04
NOTES TO FINAIAL STATEMENTS (Continued) NC
In May 2010, Idaho Power registered with the SEC the issuance of up to $500 million of first mortgage bonds and debt securities. On
June 17, 2010, Idaho Power entered into a selling agency agreement with ten banks named in the agreement in connection with the
potential issuance and sale from time to time of up to $500 million aggregate principal amount of first mortgage bonds. As of
December 31, 2011, $300 million remained on Idaho Power's shelf registration for the issuance of first mortgage bonds and debt
securities.
On March 2, 2011, Idaho Power repaid at maturity $120 million of first mortgage bonds using proceeds from first mortgage bonds
issued in August 2010.
On August 30, 2010, Idaho Power issued $100 million of 3.40% First Mortgage Bonds, Secured Medium-Term Notes, Series I due
2020 and $100 million of 4.85% First Mortgage Bonds, Secured Medium-Term Notes, Series I due 2040 under the shelf registration
statement.
Mortgage: As of December 31, 2011, Idaho Power could issue under its Indenture of Mortgage and Deed of Trust, dated as of
October 1, 1937, between Idaho Power and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company)
and R.G. Page, as Trustees (Stanley Burg, successor individual trustee) (Mortgage) approximately $1.3 billion of additional first
mortgage bonds based on retired first mortgage bonds and total unfunded property additions. These amounts are further limited by
the maximum amount of first mortgage bonds set forth in the Mortgage.
The Mortgage secures all bonds issued under the indenture equally and ratably, without preference, priority, or distinction. First
mortgage bonds issued in the future will also be secured by the Mortgage. The lien of the indenture constitutes a first mortgage on all
the properties of Idaho Power, subject only to certain limited exceptions including liens for taxes and assessments that are not
delinquent and minor excepted encumbrances. Certain of the properties of Idaho Power are subject to easements, leases, contracts,
covenants, workmen's compensation awards, and similar encumbrances and minor defects and clouds common to properties. The
Mortgage does not create a lien on revenues or profits, or notes or accounts receivable, contracts or choses in action, except as
permitted by law during a completed default, securities, or cash, except when pledged, or merchandise or equipment manufactured or
acquired for resale. The Mortgage creates a lien on the interest of Idaho Power in property subsequently acquired, other than
excepted property, subject to limitations in the case of consolidation, merger, or sale of all or substantially all of the assets of Idaho
Power. The Mortgage requires Idaho Power to spend or appropriate 15 percent of its annual gross operating revenues for
maintenance, retirement, or amortization of its properties. Idaho Power may, however, anticipate or make up these expenditures or
appropriations within the five years that immediately follow or precede a particular year.
On February 17, 2010, Idaho Power entered into the Forty-fifth Supplemental Indenture, dated as of February 1, 2010, to the
Mortgage for the purpose of increasing the maximum amount of first mortgage bonds issuable by Idaho Power from $1.5 to $2.0
billion. The amount issuable is also restricted by property, earnings, and other provisions of the Mortgage and supplemental
indentures to the Mortgage. Idaho Power may amend the Mortgage and increase this amount without consent of the holders of the
first mortgage bonds. The Mortgage requires that Idaho Power's net earnings be at least twice the annual interest requirements on all
outstanding debt of equal or prior rank, including the bonds that Idaho Power may propose to issue. Under certain circumstances, the
net earnings test does not apply, including the issuance of refunding bonds to retire outstanding bonds that mature in less than two
years or that are of an equal or higher interest rate, or prior lien bonds.
5. NOTES PAYABLE
Credit Facilities
On October 26, 2011, Idaho Power entered into a amended and restated credit agreement, which amended and restated the existing
$300 million credit facility. The new credit facility may be used for general corporate purposes and commercial paper backup. Idaho
Power's credit facility consists of a revolving line of credit, through the issuance of loans and standby letters of credit, not to exceed
the aggregate principal amount at any one time outstanding of $300 million, including swingline loans in an aggregate principal
IFERC FORM NO. I (ED. 12-88) Page 123.16 I
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(1)X An Original (Mo, Da, Yr)
Idaho Power Company (2)- A Resubmission 04/13/2012 2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
amount at any time outstanding not to exceed $30 million. Idaho Power has the right to request an increase in the aggregate principal
amount of the facility to $450 million, respectively, subject to certain conditions. The credit facility matures on October 26, 2016,
although Idaho Power has the right to request up to two one-year extensions of the credit agreement, in each case subject to certain
conditions.
The interest rates for any borrowings under the facility is based on either (1) a floating rate that is equal to the highest of the prime
rate, federal funds rate plus 0.5 percent, or LIBOR rate plus 1.0 percent, or (2) the LIBOR rate, plus, in each case, an applicable
margin. The margin is based on Idaho Power's, senior unsecured long-term indebtedness credit rating by Moody's Investors Service,
Inc., Standard and Poor's Ratings Services, and Fitch Rating Services, Inc., as set forth on a schedule to the credit agreement. The
company pays a facility fee on the commitment based on the company's credit rating for senior unsecured long-term debt securities
At December 31 2011, no amounts were outstanding under Idaho Power's facility. At December 31 2011 Idaho Power had
regulatory authority to incur up to $450 million of short-term indebtedness. Balances and interest rates of short-term borrowings of
commercial paper were as follows at December 31 (in thousands of dollars):
Idaho Power
2011 2010
Commercial paper balances:
At the end of year $ - $ -
Average during the year $ - $ 348
6. COMMON STOCK
Idaho Power Common Stock
In 2011 and 2010, IDACORP contributed $16 million and $50 million, respectively, of additional equity to Idaho Power. No
additional shares of Idaho Power common stock were issued in exchange for the contributions.
Restrictions on Dividends
A covenant under Idaho Power's credit facility requires Idaho Power to maintain a leverage ratio of consolidated indebtedness to
consolidated total capitalization, as defined therein, of no more than 65 percent at the end of each fiscal quarter. Idaho Power's ability
to pay dividends on its common stock held by IDACOR.P is limited to the extent payment of such dividends would violate the
covenants in their respective credit facilities or Idaho Power's Revised Code of Conduct. At December 31, 2011, the leverage ratio
for Idaho Power was 49 percent. Based on these restrictions, Idaho Power's dividends are limited to $723 million at
December 31, 2011. There are additional facility covenants, subject to exceptions, that prohibit certain mergers, acquisitions, and
investments; restrict the creation of certain liens; and prohibit entering into any agreements restricting dividend payments to the
company from any material subsidiary.
Idaho Power's Revised Code of Conduct, approved by the IPUC on April 21, 2008, states that Idaho Power will not pay any
dividends to IDACORP that will reduce Idaho Power's common equity capital below 35 percent of its total adjusted capital without
IPUC approval. Idaho Power's articles of incorporation also contain restrictions on the payment of dividends on its common stock if
preferred stock dividends are in arrears. Idaho Power has no preferred stock outstanding.
In addition to contractual restrictions on the amount and payment of dividends, the Federal Power Act prohibits the payment of
dividends from "capital accounts." The term "capital accounts" is undefmed in the Federal Power Act, but if conservatively
interpreted could limit the payment of dividends by Idaho Power to the amount of Idaho Power's retained earnings.
Idaho Power must obtain approval of the OPUC before it could directly or indirectly loan funds or issue notes or give credit on its
books to IDACORP.
IFERC FORM NO. I (ED. 12-88) Page 123.17
I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)_ A Resubmission 04/13/2012 2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
7. STOCK-BASED COMPENSATION
Through its parent company IDACORP, Idaho Power has two share-based compensation plans -- the 2000 Long-Term Incentive and
Compensation Plan (LTICP) and the 1994 Restricted Stock Plan (RSP). These plans are intended to align employee and shareholder
objectives related to IDACORP's long-term growth.
The LTICP (for officers, key employees, and directors) permits the grant of nonqualified stock options, restricted stock, performance
shares, and several other types of stock-based awards. The RSP permits only the grant of restricted stock or performance-based
restricted stock. At December 31, 2011, the maximum number of shares available under the LTICP and RSP were 1,503,861 and
15,796, 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 forfeiture under certain circumstances. The fair value of these awards is
based on the market price of common stock on the grant date and is charged to compensation expense over the vesting period, based
on the number of shares expected to vest.
Performance-based restricted stock awards have three-year vesting periods and entitle the recipients to voting rights. Unvested shares
are restricted as to disposition, subject to forfeiture under certain circumstances, and subject to meeting specific performance
conditions. Based on the attainment of the performance conditions, the ultimate award can range from zero to 150 percent of the
target award. Dividends are accrued and paid out only on shares that eventually vest.
The performance awards are based on two metrics, cumulative earnings per share (CEPS) and total shareholder return (TSR) relative
to a peer group. The fair value of the CEPS portion is based on the market value at the date of grant, reduced by the loss in
time-value of the estimated future dividend payments. The fair value of the TSR portion is estimated using a statistical model that
incorporates the probability of meeting performance targets based on historical returns relative to the peer group. Both performance
goals are measured over the three-year vesting period and are charged to compensation expense over the vesting period based on the
number of shares expected to vest.
A summary of restricted stock and performance share activity is presented below
Number of Weighted-Average
Shares Grant Date
Fair Value
Nonvested shares at January 1, 2011 329,501 $26.35
Shares granted 135,016 30.30
Shares forfeited (11,451) 27.32
Shares vested (115,883) 25.28
Nonvested shares at December 31, 2011 337,183 $26.40
The total fair value of shares vested during the years ended December 31, 2011 and 2010, was $4.1 million and $3.3 million,
respectively. At December 31, 2011, Idaho Power had $4 million of total unrecognized compensation cost related to nonvested
share-based compensation that was expected to vest. These costs are expected to be recognized over a weighted-average period of
1.68 years. Idaho Power uses IDACORP's original issue and/or treasury shares for these awards.
In 2011, a total of 11,920 shares were awarded to directors at a grant date fair value of $37.74 per share. Directors elected to defer
receipt of 5,960 of these shares, which are being held as deferred stock units with dividend equivalents reinvested in additional stock
units.
FERC FORM NO I (ED 12-88) Page 12318 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)_ A Resubmission 04/13/2012 201 11Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Stock Options No stock options have been granted since 2006 The remaining unexercised stock option awards were granted with
exercise prices equal to the market value of the stock on the date of grant, with a term of 10 years from the grant date and a five-year
vesting period The fair value of each option was amortized into compensation expense using graded vesting and, as of
December 31, 2011, all compensation costs have been recognized. Idaho Power uses IDACORP 's uses original issue and/or treasury
shares to satisfy exercised options.
Idaho Power's stock option transactions are summarized below.
Weighted
Number Weighted- Average Aggregate
of Average Remaining Intrinsic
Shares Exercise Contractual Value
Price Term (Years) (000s)
Outstanding at December 31, 2010 202,634 $ 38.05 113 $ 314
Exercised (90,945) 35.54
Expired (102,233) 3989
Outstanding at December 31, 2011 9,456 $ 33.67 1.58 $ 83
Vested and exercisable at December 31, 2011 9,456 $ 33.67 1.58 $ 83
The following table presents information about options vested and exercised (m thousands of dollars)
2011 2010
Fair value of options vested $ - $ 96
Intrinsic value of options exercised 535 1,475
Cash received from exercises 3,838 5,394
Tax benefits realized from exercises 209 577
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):
2011 2010
Compensation cost $ 4,082 $ 3,489
Income tax benefit 1,596 1,364
No equity compensation costs have been capitalized
8. COMMI1MENTS
Purchase Obligations
At December 31, 2011, Idaho Power had the following long-term commitments relating to purchases of energy, capacity, transmission
rights, and fuel (in thousands of dollars)
2012 2013 2014 2015 2016 Thereafter
Cogeneration and power production $ 165,693 $ 196,261 $ 209,295 $ 214,960 $ 218,220 $3,687,810
Power and transmission rights 10,772 4,243 3,188 2,210 1,879 4,401
jFERC FORM NO 1 (ED 12-88) Page 123.19
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)_ A Resubmission 04/13/2012 2011/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Fuel 79,138 64,852 66,309 22,661 8,909 98,212
As of December 31, 2011, Idaho Power had signed agreements to purchase energy from 119 CSPP facilities with contracts ranging
from one to 35 years. Ninety-six of these facilities, with a combined nameplate capacity of 606 MW, were on-line at the end of 2011;
the other 23 facilities under contract, with a combined nameplate capacity of 383 MW, are projected to come on-line by year end
2014. The majority of the new facilities will be wind resources which will generate on an intermittent basis. During 2011, Idaho
Power purchased 1,495,108 megawatt-hours (MWh) from these projects at a cost of $90 million, resulting in a blended price of
$60.36 per MWh. Idaho Power purchased 910,429 MWh at a cost of $55 million in 2010.
In addition, IPC has the following long-term commitments for lease guarantees, equipment, maintenance and services, and industry
related fees (in thousands of dollars):
2012 2013 2014 2015 2016 Thereafter
Operating leases $ 2,005 $ 2,875 $ 2,768 $ 2,199 $ 1,203 $ 15,711
Equipment, maintenance, and service agreements 38,553 15,271 6,169 4,897 3,700 8,254
FERC and other industry-related fees 12,391 12,031 9,745 9,745 6,596 32,981
IPC's expense for operating leases was approximately $5.2 million in 2011 and $3.3 million in 2010.
Guarantees
Idaho Power has agreed to guarantee a portion of the performance of reclamation activities and obligations at BCC, of which IERCo
owns a one-third interest. This guarantee, which is renewed each December, was $63 million at December 31, 2011, representing
IERCo's one-third share of BCC's total reclamation obligation of $189 million. BCC has a reclamation trust fund set aside
specifically for the purpose of paying these reclamation costs. As of December 31, 2011, the value of the reclamation trust fund
totaled $80 million. BCC periodically assesses the adequacy of the reclamation trust fund and its estimate of future reclamation
costs. To ensure that the reclamation trust fund maintains adequate reserves, BCC has the ability to add a per-ton surcharge to coal
sales. Starting in 2010, BCC began applying a nominal surcharge to coal sales in order to maintain adequate reserves in the
reclamation trust fund. Because of the existence of the fund and the ability to apply a per-ton surcharge, the estimated fair value of
this guarantee is minimal.
Idaho Power enters into financial agreements and power purchase and sale agreements that include indemnification provisions
relating to various forms of claims or liabilities that may arise from the transactions contemplated by these agreements. Generally, a
maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the
obligation under such indemnification provisions cannot be reasonably estimated. Idaho Power periodically evaluates the likelihood
of incurring costs under such indemnities based on their historical experience and the evaluation of the specific indemnities. As of
December 31, 2011, management believes the likelihood is remote that Idaho Power would be required to perform under such
indemnification provisions or otherwise incur any significant losses with respect to such indemnification obligations. Idaho Power
has not recorded any liability on their respective consolidated balance sheets with respect to these indemnification obligations.
9. CONTINGENCIES
Idaho Power has in the past and expects in the future to become involved in various claims, controversies, disputes, and other
contingent matters, including the items described in this Note 9. Some of these claims, controversies, disputes, and other contingent
matters involve litigation and regulatory or other contested proceedings. Idaho Power intends to vigorously protect and defend their
interests and pursue their rights. However, the ultimate resolution and outcome of litigation and regulatory proceedings is inherently
difficult to determine, particularly where (a) the remedies or penalties sought are indeterminate, (b) the proceedings are in the early
stages or the substantive issues have not been well developed, or (c) the matters involve complex or novel legal theories or a large
number of parties. In accordance with applicable accounting guidance, Idaho Power establishes an accrual for legal proceedings
when those matters proceed to a stage where they present loss contingencies that are both probable and reasonably estimable. In such
IFERC FORM NO. I (ED. 12-88) Page 123.20
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Idaho Power Company (2)- A Resubmission 04/13/2012 2011 /Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
cases, there may be a possible exposure to loss in excess of any amounts accrued. Idaho Power monitors those matters for
developments that could affect the likelihood of a loss and the accrued amount, if any, thereof, and adjust the amount as appropriate.
If the loss contingency at issue is not both probable and reasonably estimable, Idaho Power does not establish an accrual and the
matter will continue to be monitored for any developments that would make the loss contingency both probable and reasonably
estimable. As of the date of this report, Idaho Power's accruals for legal proceedings are not material to their financial statements as a
whole; however, future accruals could be material in a given period. Idaho Power's determination is based on currently available
information, and estimates presented in financial statements and other financial disclosures involve significant judgment and may be
subject to significant uncertainty. As available information changes, the matters for which Idaho Power is able to estimate the loss
may change, and the estimates themselves may change.
For certain of those matters described in this report for which Idaho Power has determined a loss contingency may, in the future,
be at least reasonably possible, Idaho Power has stated that they are unable to estimate the possible loss or a range of possible loss
that may result from those matters. Depending on a range of factors, such as the complexity of the facts, the unique nature of the
legal theories, the pace of discovery, the timing of court decisions, and the adverse party's willingness to negotiate towards a
resolution, it may be months or years after the filing of a case before Idaho Power may be in a position to estimate the possible
loss or range of possible loss for those matters.
Given the substantial or indeterminate amounts sought in certain of the matters described below, and the inherent unpredictability of
such matters, an adverse outcome in certain of these matters could have a material adverse effect on Idaho Power's financial
condition, results of operations, or cash flows in particular quarterly or annual periods. For matters that affect Idaho Power's
operations, Idaho Power intends to seek, to the extent permissible and appropriate, recovery of incurred costs through the ratemaking
process.
Western Energy Proceedings
High prices for electricity, energy shortages, and blackouts in California and in western wholesale markets during 2000 and 2001
caused numerous purchasers of electricity in those markets to initiate proceedings seeking refunds or other forms of relief and the
FERC to initiate its own investigations. Some of these proceedings remain pending before the FERC or are on appeal to the United
States Court of Appeals for the Ninth Circuit (Ninth Circuit). Except as to the matters described below under "Pacific Northwest
Refund," Idaho Power and IDACORP Energy (IE) believe that settlement releases they have obtained will restrict potential claims
that might result from the disposition of the pending Ninth Circuit review petitions and predict that these matters will not have a
material adverse effect on their consolidated financial positions, results of operations, or cash flows.
Pacjfic Northwest Refund: On July 25, 2001, the FERC issued an order establishing a proceeding to determine whether there may
have been unjust and unreasonable charges for spot market sales in the Pacific Northwest during the period December 25, 2000
through June 20, 2001, because the spot market in the Pacific Northwest was affected by the dysfunction in the California market.
During that period, Idaho Power or IE both sold and purchased electricity in the Pacific Northwest. In 2003, the FERC terminated the
proceeding and declined to order refunds, 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 require refunds. The Ninth Circuit's opinion instructed the FERC to consider
whether evidence of market manipulation would have altered the agency's conclusions about refunds and directed the FERC to
include sales originating in the Pacific Northwest to the California Department of Water Resources (CDWR) in the scope of the
proceeding. The Ninth Circuit officially returned the case to the FERC on April 16, 2009. On October 3, 2011, the FERC issued its
order on remand. The FERC ordered that the record be re-opened to permit parties seeking refunds to submit seller-specific evidence
in support of their claims for sales made during the period confined to December 25, 2000 through June 20,2001. The seller-specific
claims must show that a seller engaged in unlawful market activity with a causal connection to have directly affected the negotiation
of the specific contract or contracts to which the seller was a party. Neither claims of general dysfunction in the California markets
nor in the Pacific Northwest market will be sufficient to support claims. While directing a trial-type hearing, the FERC also directed
that the hearings be held in abeyance so that the matter may be presented to a settlement judge. On November 2, 2011, each of the
City of Seattle, Washington, the City of Tacoma, Washington, the Port of Seattle, and the California Parties (consisting of the
California Attorney General and the California Public Utilities Commission) filed requests for rehearing seeking to expand the scope
of the October 3, 2011 order. The designated settlement judge has met with the parties and convened a settlement conference to
IFERC FORM NO I (ED 12-88) Page 12321
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr) 1 Idaho Power Company (2)- A Resubmission 04/13/2012 2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
establish settlement procedures. The FERC's Chief Administrative Law Judge memorialized certain settlement procedures to which
the parties agreed in an order issued on November 23, 2011.
IE and Idaho Power intend to continue to defend their positions in the Pacific Northwest refund proceedings vigorously. As of the
date of this report, it is difficult to predict the outcome of this matter. Idaho Power does not believe that claims conforming to the
requirements of the FERC's October 3, 2011 order have been submitted, and the FERC's order remains subject to rehearing and
reconsideration. Idaho Power and IE are unable to predict when and how the FERC will act on the rehearing requests, which
contracts would be subject to refunds, whether the FERC will order refunds, or how the refunds would be calculated. As a result of
these factors, as of the date of this report Idaho Power and IE are unable to estimate the reasonably possible loss or range of losses
that Idaho Power or IE could incur as a result of this matter. However, based on the status of settlement discussions with one party to
the proceedings, for that portion of the matter Idaho Power reserved for a contingent liability an amount immaterial to Idaho Power's
financial statements in the fourth quarter of 2011.
EPA Notice of Violation - Boardman
In September 2010, the U.S. Environmental Protection Agency (EPA) issued a Notice of Violation to Portland General Electric
Company (PGE), alleging that PGE had violated the New Source Performance Standards (NSPS) and operating permit requirements
under the Clean Air Act (CAA) as a result of modifications made to the Boardman coal-fired plant in 1998 and 2004. PGE is the
operator of the Boardman plant, and Idaho Power has a 10 percent ownership interest in the plant. The Notice of Violation states the
maximum civil penalties the EPA is authorized to impose under the CAA for violations of the NSPS (which range from $25,000 to
$37,500 per day), but it does not impose any penalties or specify the amount of any proposed penalties with respect to the alleged
violations. It is difficult to meaningfully predict the eventual outcome of this matter given the complexity of the environmental
statutes and claims cited in the Notice of Violation and the matters at issue, the unspecified nature of the penalty or other remedy
sought, and the absence of factual information given the early stage of the proceedings. As of the date of this report, based on
available information and the status of this matter, Idaho Power is unable to estimate the reasonably possible loss or range of losses
that Idaho Power could incur as a result of this matter. However, PGE, the plant operator, has stated that based on its understanding
of the penalties authorized under the CAA the maximum penalty that could be imposed for the alleged violations is approximately
$60 million, with Idaho Power's share of any such penalty being limited to 10 percent of the amount ultimately assessed, if any.
Water Rights - Snake River Basin Adjudication
Idaho Power holds water rights, acquired under applicable state law, for its hydroelectric projects. In addition, Idaho Power holds
water rights for domestic, irrigation, commercial, and other necessary purposes related to project lands and other holdings within the
states of Idaho and Oregon. Idaho Power's water rights for power generation are, to varying degrees, subordinated to future upstream
appropriations for irrigation and other authorized consumptive uses.
Over time, increased irrigation development and other consumptive uses within the Snake River watershed led to a reduction in flows
of the Snake River. In the late 1970's and early 1980's these reduced flows resulted in a conflict between the exercise of Idaho
Power's water rights at certain hydroelectric projects on the Snake River and upstream consumptive diversions. The Swan Falls
Agreement, signed by Idaho Power and the State of Idaho on October 25, 1984, resolved the conflict and provided a level of
protection for Idaho Power's hydropower water rights at specified projects on the Snake River through the establishment of minimum
stream flows and an administrative process governing future development of water rights that may affect those minimum stream
flows. In 1987, Congress enacted legislation directing the FERC to issue an order approving the Swan Falls settlement together with
a finding that the agreement was neither inconsistent with the terms and conditions of Idaho Power's project licenses nor the Federal
Power Act. The FERC entered an order implementing the legislation on March 25, 1988.
The Swan Falls Agreement provided that the resolution and recognition of Idaho Power's water rights together with the State Water
Plan provided a sound comprehensive plan for management of the Snake River watershed. The Swan Falls Agreement also
recognized, however, that in order to effectively manage the waters of the Snake River basin, a general adjudication to determine the
nature, extent, and priority of the rights of all water uses in the basin was necessary. Consistent with that recognition, in 1987 the
State of Idaho initiated the Snake River Basin Adjudication (SRBA), and pursuant to the commencement order issued by the SRBA
IFERC FORM NO 1 (ED 12-88) Page 12322
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(1)An Original (Mo, Da, Yr)
Idaho Power Company (2)- A Resubmission 04/13/2012 201 1 /Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
court that same year, all claimants to water rights within the basin were required to file water rights claims in the SRBA. Idaho Power
has filed claims to its water rights and has been actively participating in the SRBA since its commencement. Questions concerning
the effect of the Swan Falls Agreement on Idaho Power's water rights claims, including the nature and extent of the subordination of
Idaho Power's rights to upstream uses, resulted in the filing of litigation in the SRBA in 2007 between Idaho Power and the State of
Idaho. This litigation was resolved by the Framework Reaffirming the Swan Falls Settlement (Framework) signed by Idaho Power
and the State of Idaho on March 25, 2009. In that Framework, the parties acknowledged that the effective management of Idaho's
water resources remains critical to the public interest of the State of Idaho by sustaining economic growth, maintaining reasonable
electric rates, protecting and preserving existing water rights, and protecting water quality and environmental values. The Framework
further provided that the State of Idaho and Idaho Power would cooperate in exploring approaches to resolve issues of mutual concern
relating to the management of Idaho's water resources. Idaho Power continues to work with the State of Idaho and other interested
parties on these issues.
One such issue involves the management of the Eastern Snake Plain Aquifer (ESPA), a large underground aquifer in southeastern
Idaho that is hydrologically connected to the Snake River. House Concurrent Resolution No. 28, adopted by the Idaho Legislature in
2007, directed the Idaho Water Resource Board to pursue the development of a comprehensive management plan for the ESPA, to
include measures that would enhance aquifer levels, springs, and river flows on the eastern Snake River plain to the benefit of both
agricultural development and hydropower generation. In May of 2007, the Idaho Water Resource Board appointed an advisory
committee, charged with the responsibility of developing a management plan for the ESPA. Idaho Power was a member of that
committee. In January 2009, the Idaho Water Resource Board, based on the committee's recommendations, adopted a Comprehensive
Aquifer Management Plan (CAMP) for the ESPA. The Idaho Legislature approved the CAMP that same year. Idaho Power is a
member of the CAMP Implementation Committee and continues to work with the Idaho Water Resource Board, other stakeholders,
and the Idaho Legislature in exploring opportunities for implementation of the CAMP management plan.
Idaho Power also continues its active participation in the SRBAm seeking to ensure that its water rights are protected and that the
operation of its hydroelectric projects is not adversely impacted. While Idaho Power cannot predict the outcome, Idaho Power does
not anticipate any material modification of its water rights as a result of the SRBA process
Other Legal Proceedings
From time to time Idaho Power is party to legal claims, actions, and proceedings in addition to those discussed above. However, as
of the date of this report the company believes that resolution of these matters will not have a material adverse effect on the
consolidated financial positions, 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
years of service and the employee's final average earnings. Idaho Power's policy is to fund, with an independent corporate trustee, at
least the minimum required under the Employee Retirement Income Security Act of 1974 (ERISA) but not more than the maximum
amount deductible for income tax purposes. In 2011 and 2010 Idaho Power elected to contribute more than the minimum required
amounts in order to bring the plan to a more funded position, to reduce future required contributions, and to reduce Pension Benefit
Guaranty Corporation premiums. The market-related value of assets for the plan is equal to the fair value of the assets. Fair value is
determined by utilizing publicly quoted market values and independent pricing services depending on the nature of the asset, as
reported by the trustee/custodian of the plan.
In addition, Idaho Power has a nonqualified, deferred compensation plan for certain senior management employees and directors
called the Senior Management Security Plan (SMSP). At December 31, 2011 and 2010, approximately $41.2 million and $46.2
million, respectively, of life insurance policies and investments in marketable securities, all of which are held by a trustee, were
designated to satisfy the projected benefit obligation of the plan but do not qualify as plan assets in the actuarial computation of the
funded status
IFERC FORM NO I (ED 12-88) Page 12323
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 04/13/2012 201 1/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
The following table summarizes the changes in benefit obligations and plan assets of these plans (in thousands of dollars):
Pension Plan SMSP
2011 2010 2011 2010
Change in benefit obligation:
Benefit obligation at January 1 $ 569,934 $ 506,744 $ 59,126 $ 52,719
Service cost 20,478 17,671 1,950 1,541
Interest cost 30,322 29,119 3,094 3,004
Actuarial loss 55,535 35,909 4,251 5,186
Benefits paid (20,830) (19,509) (3,378) (3,324)
Benefit obligation at December 31 655,439 569,934 65,043 59,126
Change in plan assets:
Fair value at January 1 397,003 313,474 - -
Actual return on plan assets (4,592) 43,038 - -
Employer contributions 18,500 60,000 - -
Benefits paid (20,830) (19,509) - -
Fair value at December 31 390,081 397,003 - -
Funded status at end of year $ (265,358) $ (172,931) $ (65,043) $ (59,126)
Amounts recognized in the statement of financial position
consist of:
Other current liabilities $ - $ - $ (3,496) $ (3,289)
Noncurrent liabilities (265,358) (172,931) (61,547) (55,837)
Net amount recognized $ (265,358) $ (172,931) $ (65,043) $ (59,126)
Amounts recognized in accumulated other comprehensive
income consist of:
Net loss $ 245,632 $ 161,855 $ 21,799 $ 18,840
Prior service cost 1,335 1,855 1,502 1,744
Subtotal 246,967 163,710 23,301 20,584
Less amount recorded as regulatory asset (246,967) (163,710) - -
Net amount recognized in accumulated
other comprehensive income $ - $ - $ 23,301 $ 20,584
Accumulated benefit obligation $ 549,503 $ 482,448 $ 59,836 $ 54,213
I FERC FORM NO 1 (ED 12-88) Page 12324 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)_A Resubmission 04/13/2012 2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
The following table shows the components of net periodic benefit cost for these plans (in thousands of dollars):
Pension Plan SMSP
2011 2010 2011 2010
Service cost $ 20,478 $ 17,671 $ 1,950 $ 1 ,541
Interest cost 30,322 29,119 3,094 3,004
Expected return on assets (32,322) (26,463) - -
Amortization of net loss 8,673 7,675 1,293 931
Amortization of prior service cost 519 650 242 233
Net periodic pension cost 27,670 28,652 6,579 5,709
Adjustment to cost recognized due to the
effects of regulation(1) 6,662 (24,104) - -
Net periodic benefit cost recognized for
financial reporting $ 34,332 $ 4,548 $ 6,579 $ 5,709
(1) Net periodic benefit costs for the pension plan are recognized based on the authorization of each regulatory jurisdiction Idaho Power operates within Under IPUC
order, income statement recognition of pension plan costs is deferred until costs are recovered through rates. See Note 3 for information on Idaho Power's 2011 Idaho
pension rate order, which increased Idaho-jurisdiction recovery to $17.1 million annually, effective June 1, 2011, and also for information on Idaho Power's sharing
mechanism which resulted in additional Idaho pension amortization of $20.3 million in 2011
In LU 12, luallo Power expects to recognize as components of net periodic benefit cost lil).9 million trom amortizing amounts
recorded in accumulated other comprehensive income (or as a regulatory asset for the pension plan) as of December 31, 2011 relating
to the pension and SMSP plans. This amount consists of $13.9 million of amortization of net loss and $0.3 million of amortization of
prior service cost for the pension plan, and $1.5 million of amortization of net loss and $0.2 million of amortization of prior service
cost for the SMSP.
The following table summarizes the expected future benefit payments of these plans (in thousands of dollars):
2012 2013 2014 2015 2016 2017-2021
Pension Plan $ 22,360 $
SMSP 3,578
24,001 $
3,707
25,684
3,899
$ 27,597 $
4,063
29,761 $
4,084
186,450
22,797
As of December 31, 2011, Idaho Power's minimum required contributions to the defined benefit pension plan are estimated to be
approximately $34 million in 2012, $44 million in 2013, $44 million in 2014, $42 million in 2015, and $42 million in 2016. Idaho
Power may elect to make contributions earlier than the required dates.
Postretirement Benefits
Idaho Power maintains a defined benefit postretirement benefit 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.
Retirees hired on or after January 1, 1999 have access to the standard medical option at full cost, with no contribution by Idaho
Power. Benefits for employees who retire after December 31, 2002 are limited to a fixed amount, which has limited the growth of
Idaho Power's future obligations under this plan.
FERC FORM NO. I (ED. 12-88) Page 123.25
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)_ A Resubmission 04/13/2012 2011/Q4
NOTES TO FINANCIAL STATEMENTS (ConUnued)
The following table summarizes the changes in benefit obligation and plan assets (in thousands of dollars):
2011 2010
Change in accumulated benefit obligation:
Benefit obligation at January 1 $ 68,048 $ 62,647
Service cost 1,323 1,276
Interest cost 3,434 3,578
Actuarial loss (2,850) 3,291
Benefits paid(l) (2,968) (3,373)
Plan amendments (318) 629
Benefit obligation at December 31 66,669 68,048
Change in plan assets:
Fair value of plan assets at January 1 33,176 30,892
Actual return on plan assets 1,065 3,381
Employer contributions 628 2,276
Benefits paid(1) (2,968) (3,373)
Fair value of plan assets at December 31 31,901 33,176
Funded status at end of year (included in noncurrent liabilities) $ (34,768) $ (34,872)
(1) Benefits paid are net of $3,405 and $2,971 of plan participant contributions, and $444 and $415 of Medicare Part D subsidy
receipts for 2011 and 2010, respectively.
Amounts recognized in accumulated other comprehensive income consist of the following (in thousands of dollars):
2011 2010
Net loss $ 14,112 $ 15,963
Prior service credit (323) (426)
Transition obligation 2,040 4,080
Subtotal 15,829 19,617
Less amount recognized in regulatory assets (15,536) (19,032)
Less amount included in deferred tax assets (293) (585)
Net amount recognized in accumulated other comprehensive income $ - $ -
The net periodic postretirement benefit cost was as follows (in thousands of dollars):
2011 2010
Service cost $ 1,323 $ 1,276
Interest cost 3,434 3,578
Expected return on plan assets (2,641) (2,503)
Amortization of net loss 577 562
Amortization of prior service cost (421) (482)
Amortization of unrecognized transition obligation 2,040 2,040
Net periodic postretirement benefit cost $ 4,312 $ 4,471
In 2012, Idaho Power expects to recognize as components of net periodic benefit cost $2.2 million from amortizing amounts recorded
IFERC FORM NO. I (ED. 12-88) Page 123.26
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)_A Resubmission 04/13/2012 201 1/04
NOTES TO FINANCIAL STATEMENTS (Continued)
in accumulated other comprehensive income as of December 31, 2011 relating to the postretirement benefit plan. This amount
consists of $(0.4) million of prior service cost, $0.6 million of net loss, and $2.0 million of transition obligation.
Medicare Act: The Medicare Prescription Drug, Improvement and Modernization 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 drug benefit that is at least actuarially equivalent to Medicare's prescription drug coverage.
The following table summarizes the expected future benefit payments of the postretirement benefit plan and expected Medicare Part D
subsidy receipts (in thousands of dollars):
2012 2013 2014 2015 2016 2017-2021
Expected benefit payments $ 4,176 $ 4,261 $ 4,415 $ 4,543 $ 4,620 $ 23,849
Expected Medicare Part D subsidy receipts 478 524 563 612 671 4,441
Plan Assumptions
The following table sets forth the weighted-average assumptions used at the end of each year to determine benefit obligations for all
Idaho Power-sponsored pension and postretirement benefits plans:
Postretirement
Pension Plan SMSP Benefits
2011 2010 2011 2010 2011 2010
Discount rate 490% 540% 5.10% 540% 5.05% 540%
Rate of compensation increase(l) 4.35% 450% 4.50% 450% - -
Medical trend rate - - - - 7.0% 7.5%
Dental trend rate - - - - 5% 5%
Measurement date 12/31/2011 12/31/2010 12/31/2011 12/31/2010 12/31/2011 12/31/2010
(1) The 2011 rate of compensation increase assumption for the pension plan includes an inflation component of 2.75% plus a 1.60% composite merit increase
component that is based on employees' years of service. Merit salary increases are assumed to be 8.0% for employees in their first year of service and scale down to 0%
for employees in the fortieth year of service and beyond.
The following table sets forth the weighted-average assumptions used to determine net periodic benefit cost for all Idaho
Power-sponsored pension and postretirement benefit plans:
Postretirement
Pension Plan SMSP Benefits -
2011 2010 2011 2010 2011 2010
Discount rate 5.40% 5.90% 5.40% 5.90% 5.40% 5.90%
Expected long-term rate of
return on assets 8.25% 8.25% - - 8.25% 8.25%
Rate of compensation increase 4.50% 4.50% 4.50% 4.50% - -
Medical trend rate — - - - 7.0% 7.5%
Dental trend rate - - - - 5.0% 5.0%
The assumed health care cost trend rate used to measure the expected cost of health benefits covered by the postretirement plan was
7.0 percent and 7.5 percent in 2011 and 2010, respectively. The assumed health care cost trend rate for 2011 is assumed to decrease
gradually to 4.9 percent by 2083. The assumed dental cost trend rate used to measure the expected cost of dental benefits covered by
the plan was 5.0 percent in both 2011 and 2010. The assumed dental cost trend rate for 2011 is assumed to decrease gradually to 4.9
percent by 2083. A one percentage point change in the assumed health care cost trend rate would have the following effects at
FERC FORM NO. I (ED. 12-88) Page 123.27 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 04/13/2012 2011/04
NOTES TO FINANCIAL STATEMENTS (Continued)
December 31, 2011 (in thousands of dollars):
One-Percentage-Point
Increase Decrease
Effect on total of cost components $ 342 $ (255)
Effect on accumulated postretirement benefit obligation 2,939 (2,300)
Plan Assets
Pension Asset Allocation Policy: The target allocation and actual allocations at December 31, 2011 for the pension asset portfolio by
asset class is set forth below.
Asset Class Target Actual
Allocation Allocation
31-Dec-11
Debt securities 24% 25%
Equity securities 54% 54%
Real estate 6% 6%
Other plan assets 16% 15%
Total 100% 100%
Assets are rebalanced as necessary to keep the portfolio close to target allocations.
The plan's principal investment objective is to maximize total return (defined as the sum of realized interest and dividend income and
realized and unrealized gain or loss in market price) consistent with prudent parameters of risk and the liability profile of the
portfolio. Emphasis is placed on preservation and growth of capital along with adequacy of cash flow sufficient to fund current and
future payments to pensioners.
The three major goals in Idaho Power's asset allocation process are to:
• determine if the investments have the potential to earn the rate of return assumed in the actuarial liability calculations;
• match the cash flow needs of the plan. Idaho Power sets bond allocations sufficient to cover at least five years of benefit
payments and cash allocations sufficient to cover the current year benefit payments. Idaho Power then utilizes growth
instruments (equities, real estate, venture capital) to fund the longer-term liabilities of the plan; and
• maintain a prudent risk profile consistent with ERISA fiduciary standards.
Allowable plan investments include stocks and stock funds, investment-grade bonds and bond funds, core real estate funds, private
equity funds, and cash and cash equivalents. With the exception of real estate holdings and private equity, investments must be
readily marketable so that an entire holding can be disposed of quickly with only a minor effect upon market price.
Rate-of-return projections for plan assets are based on historical risk/return relationships among asset classes. The primary measure is
the historical risk premium each asset class has delivered versus the return on 10-year U.S. Treasury Notes. This historical risk
premium is then added to the current yield on 10-year U.S. Treasury Notes, and the result provides a reasonable prediction of future
investment performance. Additional analysis is performed to measure the expected range of returns, as well as worst-case and
best-case scenarios. Based on the current low interest rate environment, current rate-of-return expectations are lower than the nominal
returns generated over the past 20 years when interest rates were generally much higher.
[FERC FORM NO. 1 (ED. 12-88) Page 123.28 1
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)_A Resubmission 04/13/2012 2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Idaho Power's asset modeling process also utilizes historical market returns to measure the portfolio's exposure to a "worst-case"
market scenario, to determine how much performance could vary from the expected "average" performance over various time
periods. This "worst-case" modeling, in addition to cash flow matching and diversification by asset class and investment style,
provides the basis for managing the risk associated with investing portfolio assets.
Fair Value of Plan Assets: Idaho Power classifies its pension plan and postretirement benefit plan investments using the following
hierarchy:
• Level 1, which refers to securities valued using quoted prices from active markets for identical assets;
• Level 2, which refers to securities not traded on an active market but for which observable market inputs are readily
available; and
• Level 3, which refers to securities valued based on significant unobservable inputs.
If the inputs used to measure the securities fall within different levels of the hierarchy, the categorization is based on the lowest level
input (Level 3 being the lowest) that is significant to the fair value measurement of the security. The following table sets forth by
level within the fair value hierarchy a summary of the plans' investments measured at fair value on a recurring basis at December 31,
2011 (in thousands of dollars):
Quoted Prices in
Active Markets for Significant Other Significant
Identical Assets Observable Inputs Unobservable
(Level 1) (Level 2) Inputs (Level 3) Total
Assets at December 31, 2011
Pension assets:
Cash and cash equivalents $ 6,141 $ - $ - $ 6,141
Short-term bonds - 23,443 - 23,443
Long-term bonds - 74,658 - 74,658
Equity Securities Large-Cap 51,780 - - 51,780
Equity Securities: Mid-Cap 17,961 14,002 - 31,963
Equity Securities Small-Cap 31,825 - - 31,825
Equity Securities Micro Cap 16,087 - - 16,087
Equity Securities International 30,444 32,118 - 62,562
Equity Securities Emerging Markets 1,745 15,112 - 16,857
Real estate - - 25,119 25,119
Private market investments - - 27,786 27,786
Commodities funds 2,929 18,931 - 21,860
Total pension assets $ 158,912 $ 178,264 $ 52,905 $ 390,081
Postretirement assets(2) $ - $ 31,901 $ - $ 31,901
Assets at December 31, 2010
Pension assets:
Cash and cash equivalents $ 16,837 $ - $ - $ 16,837
Short-term bonds(1) - 30,241 - 30,241
Core bonds(l) - 43,156 - 43,156
Equity Securities Large-Cap 58,961 - - 58,961
Equity Securities: Mid-Cap 17,775 14,261 - 32,036
Equity Securities Small-Cap 35,278 - - 35,278
Equity Securities: Micro-Cap 17,422 - - 17,422
Equity Securities: International 32,655 33,874 - 66,529
Equity Securities Emerging Markets 2,199 18,241 - 20,440
Real estate - 22,069 22,069
Private market investments - - 29,932 29,932
Commodities funds 3,406 20,696 - 24,102
IFERC FORM NO. I (ED. 12-88) Page 123.29
F
Name of Respondent This Report is: Date of Report Yea Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)_ A Resubmission 04/13/2012 2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Total pension assets $ 184,533 $ 160,469 $ 52,001 $ 397,003
Postretirement assets(2) $ - $ 33,176 $ - $ 33,176
(I) Subsequent to the issuance of the 2010 consolidated financial statements, Idaho Power determined these investments had previously been incorrectly categorized as
Level 1 investments within the fair value hierarchy. As a result, the 2010 amounts have been restated to reflect the investments as Level 2.
(2) The postretirement benefits assets are primarily life insurance contracts.
The following table presents a reconciliation of the beginning and ending balances of the fair value measurements using significant
unobservable inputs (Level 3):
Private Real
Equity Estate Total
Beginning balance -January 1, 2010 $ 20,202 $ 20,783 $ 40,985
Realized losses - (47) (47)
Unrealized gains 1,284 2,211 3,495
Purchases, issuances, and settlements, net 8,446 (878) 7,568
Ending balance - December 31, 2010 29,932 22,069 52,001
Realized gains - 598 598
Realized losses (133) - (133)
Unrealized gains 1,425 1,854 3,279
Purchases, issuances, and settlements, net (3,438) 598 (2,840)
Ending balance - December 31, 2011 $ 27,786 $ 25,119 $ 52,905
Fair Value Measurement of Level 2 and Level 3 Plan Asset Inputs
Level 2 Bonds, Equity Securities, and Level 2 Commodities: These investments represent U. S. government and agency bonds,
corporate bonds, and commingled funds consisting of publicly traded equity securities or exchange-traded commodity contracts and
other contractual claims to commodity holdings. The U.S. government and agency bonds, as well as the corporate bonds, are not
traded on an exchange and are valued utilizing quoted prices for similar assets or liabilities in active markets. The commingled funds
themselves are not publicly traded, and therefore no publicly quoted market price is readily available. The value of these investments
is calculated by the custodian for the fund company on a monthly basis, and is based on market prices of the assets held by the
commingled fluid divided by the number of fund shares outstanding.
Level 3 Real Estate: Real estate holdings represent investments in open-ended commingled real estate funds. As the property
interests held in these real estate funds are not frequently traded, establishing the market value of the property interests held by the
fund, and the resulting unit value of fund shareholders, is based on unobservable inputs including property appraisals by the fund
company, property appraisals by independent appraisal firms, analysis of the replacement cost of the property, discounted cash flows
generated by property rents and changes in property values, and comparisons with sale prices of similar properties in similar markets.
These open-ended real estate funds also furnish annual audited financial statements that are also used to further validate the
information provided.
Level 3 Private Market Investments: Private market investments represent two categories: fund of hedge funds and venture capital
funds. These funds are valued by the fund company based on the estimated fair value of the underlying fund holdings divided by the
fund shares outstanding. Some hedge fund strategies utilize securities with readily available market prices, while others utilize less
liquid investment vehicles that are valued based on unobservable inputs including cost, operating results, recent funding activity, or
comparisons with similar investment vehicles Venture capital fund investments are valued by the fund company based on estimated
fair value of the underlying fund holdings divided by the fund shares outstanding. Some venture capital investments have progressed
to the point that they have readily available exchange-based market valuations. Early stage venture investments are valued based on
unobservable inputs including cost, operating results, discounted cash flows, the price of recent funding events, or pending offers
from other viable entities. These private market investments furnish annual audited financial statements that are also used to further
IFERC FORM NO I (ED 12-88) Page 12330 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Idaho Power Company (2)- A Resubmission 04/13/2012 201 1 /Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
validate the information provided.
There were no material changes in valuation techniques or inputs during the years ended December 31, 2011 and 2010.
Employee Savings Plan
Idaho Power has a defined contribution plan designed to comply with Section 401(k) of the Internal Revenue Code and which covers
substantially all employees (the Employee Savings Plan). Idaho Power matches specified percentages of employee contributions to
the plan. Matching annual contributions were $6 million in 2011 and $5 million in 2010.
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 salary continuation, health care and life insurance for those employees found to be
disabled under Idaho Power's disability plans, and health care for surviving spouses and dependents. Idaho Power accrues a liability
for such benefits. The post employment benefit amounts included in other deferred credits on Idaho Power's consolidated balance
sheet at December 31, 2011 and 2010 are $3.8 million and $4.5 million, respectively.
11 PROPERTY, PLANT AND EQUIPMENT AND JOINTLY -OWNED PROJECTS
The following table presents the major classifications of Idaho Power 's utility plant in service, annual depreciation provisions as a
percent of average depreciable balance, and accumulated provision for depreciation for the years 2011 and 2010 (in thousands of
dollars):
2011 2010
Balance Avg Rate Balance Avg Rate
Production $ 1,832,287 222% $ 1,792,305 223%
Transmission 871,784 206% 855,202 203%
Distribution 1,434 925 312% 1377,239 313%
General and Other 327,877 732% 307,308 741%
Total m service 4,466,873 2.83% 4,332 054 2.84%
Accumulated provision for depreciation (1,840 782) (1 ,771,655)
In service - net $ 2,626,091 $ 2,560 399
In 2010, Idaho Power sold $19 million of transmission-related assets to PacifiCorp at book value.
Idaho Power has interests in three jointly-owned generating facilities included in the table above Under the joint operating
agreements, each participating utility is responsible for financing its share of construction, operating, and leasing costs. Idaho
Power's proportionate share of related fuel expenses as well as direct operation and maintenance expenses applicable to the projects is
included in the Consolidated Statements of Income. These facilities, and the extent of Idaho Power's participation, were as follows at
December 31, 2011 (in thousands of dollars):
Name of Plant Location Utility Plant Construction Accumulated Ownership MW(')
in Service Work in Provision for %
Progress Depreciation
Jim Bridger Units Rock Springs, $539,294 $8,334 $276,375 13 771
1-4 WY
FERC FORM NO I (ED 12-88) Page 12331
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)_ A Resubmission 04/13/2012 2011/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Boardman Boardman, OR 79,714 940 53,843 10 64
Valmy Units 1 and
2 Winnemucca, NV 350,582 7,352 202,811 50 284
(I) Idaho Power's share of nameplate capacity.
IERCo, Idaho Power's wholly-owned subsidiary, is a joint venturer in BCC. Idaho Power's coal purchases from the joint venture
were $65 million and $76 million in 2011 and 2010, respectively.
Idaho Power has contracts to purchase the energy from four PUIRPA qualified facilities that are 50 percent owned by Ida-West. Idaho
Power's power purchases from these facilities were $9 million and $8 million in 2011 and 2010, respectively.
12. ASSET RETIREMENT OBLIGATIONS (ARO)
The guidance relating to accounting for AROs requires that legal obligations associated with the retirement of property, plant and
equipment be recognized as aliability at fair value when incurred and when a reasonable estimate of the fair value of the liability can
be made. Under the guidance, when a liability is initially recorded, the entity increases the carrying amount of the related long-lived
asset to reflect the future retirement cost. Over time, the liability is accreted to its present value and paid, and the capitalized cost is
depreciated over the useful life of the related asset. If, at the end of the asset's life, the recorded liability differs from the actual
obligations paid, a gain or loss would be recognized. As a rate-regulated entity, Idaho Power records regulatory assets or liabilities
instead of accretion, depreciation, and gains or losses, as approved by Order No. 29414 from the IPUC. The regulatory assets
recorded under this order do not earn a return on investment.
Idaho Power's recorded AROs relate to the removal of polychiorinated biphenyls-contaminated equipment at its distribution facilities
and the reclamation and removal costs at its jointly owned coal-fired generation facilities. In 2011, changes in estimates at its
distribution facilities and at the coal-fired generation facilities resulted in a net increase of $3.9 million in the recorded AROs. The
primary cause of the increase in the AROs was the decision to decommission the Boardman generating facility at December 31, 2020.
A decommissioning study was performed, and now that a removal date has been determined and the fair value of the associated
liabilities can be estimated, ARO amounts related to the Boardman decommissioning are being recognized in the consolidated
financial statements.
Idaho Power also has additional AROs associated with its transmission system, hydroelectric facilities, and jointly owned coal-fired
generation facilities; however, due to the indeterminate removal date, the fair value of the associated liabilities currently cannot be
estimated and no amounts are recognized in the consolidated financial statements.
The regulated operations of Idaho Power also collect removal costs in rates for certain assets that do not have associated AROs.
Idaho Power is required to redesignate these removal costs as regulatory liabilities. See Note 3 for the costs recorded as regulatory
liabilities on Idaho Power's Balance Sheets as of December 31, 2011 and 2010.
The following table presents the changes in the carrying amount of AROs (in thousands of dollars):

2011 2010
Balance at beginning of year 16,952 $ 16,240
Accretion expense 936 819
Revisions in estimated cash flows 3,930 929
Liability settled (451) (1,036)
Balance at end of year $ 21,367 $ 16,952
IFERC FORM NO I (ED 12-88) Page 12332 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)_ A Resubmission 04/13/2012 2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
13.INVESTMENTS IN DEBT AND EQUITY SECURITIES
The table below summarizes Idaho Power's investments as of December 31 (in thousands of dollars).
2011 2010
Idaho Power investments:
IERCo $ 78,530 $ 90,045
Available-for-sale equity securities 22,205 24,561
Executive deferred compensation plan 3,439 4,746
Other investments 2 3
Total Idaho Power investments $ 104,176 $ 119,805
Investments in Debt and Equity Securities
Investments in available-for-sale securities are reported at fair value, using either specific identification or average cost to determine
the cost for computing gams or losses Any unrealized gams or losses on available-for-sale securities are included in other
comprehensive income.
The table below summarizes investments in equity securities (in thousands of dollars)

December 31, 2011 December 31, 2010

Gross Unrealized Gross Unrealized Fair Gross Unrealized Gross Unrealized Fair
Gain Loss Value Gain Loss Value
Available-for-sale Securities $ 4,220 $ I $22,205 $ 4,876 $ $ 24,561
At the end of each reporting period, Idaho Power analyzes securities in loss positions to determine whether they have experienced a
decline in market value that is considered other-than-temporary. At December 31, 2011, one security was in an immaterial unrealized
loss position. No other-than-temporary impairment was recognized for this security due to the limited severity and duration of the
unrealized loss position. At December 31, 2010, no securities were in an unrealized loss position. There were no sales of
available-for-sale securities during the year ended December 31, 2011 or 2010
14.DERIVATIVE FINANCIAL INSTRUMENTS
Commodity Price Risk
Idaho Power is exposed to market risk relating to electricity, natural gas and other fuel commodity prices, all of which are heavily
influenced by supply and demand. Market risk may also be influenced by market participants' nonperformance of their contractual
obligations and commitments, which affects the supply of or demand for the commodity. Idaho Power uses derivative instruments,
such as physical and financial forward contracts, for both electricity and fuel to manage the risks relating to these commodity price
FERC FORM NO. I (ED. 12-88) Page 123.33 1
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Idaho Power Company (2)- A Resubmission 04/13/2012 201 1 /Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
exposures. The objective of Idaho Power's energy purchase and sale activity is to meet the demand of retail electric customers,
maintain appropriate physical reserves to ensure reliability, and make economic use of temporary surpluses that may develop.
All commodity-related derivative instruments not meeting the normal purchases and normal sales exception to derivative accounting
are recorded at fair value on the balance sheet. Because of Idaho Power's PCA mechanisms, unrealized gains and losses associated
with the changes in fair value of these derivative instruments are recorded as regulatory assets or liabilities. With the exception of
forward contracts for the purchase of natural gas for use at Idaho Power's natural gas generation facilities, Idaho Power's physical
forward contracts qualify for the normal purchases and normal sales exception.
All of Idaho Power's derivative instruments have been entered into for the purpose of economically hedging forecasted purchases and
sales, though none of these instruments have been designated as cash flow hedges under derivative accounting guidance. Idaho
Power offsets fair value amounts recognized on its balance sheet related to derivative instruments executed with the same
counterparty under the same master netting agreement.
Derivative Instruments Summary
The tables below presents the fair values and locations of derivative instruments not designated as hedging instruments recorded on
the balance sheets at December 31, 2011 and 2010 (in thousands of dollars).

Asset Derivatives Liability Derivatives
Balance Sheet Fair Balance Sheet Fair
Location Value Location Value
December 31, 2011
Current:
Financial swaps Other current assets $ 4,361 Other current assets $ 1,036
Financial swaps Other current liabilities 1,526 Other current liabilities 4,755
Forward contracts Other current assets 70 Other current liabilities 1,370
Long-term:
Financial swaps Other assets 359 Other liabilities 108
Total $ 6,316 $ 7,269
December 31, 2010
Current:
Financial swaps Other current assets $ 930 Other current assets $ 356
Financial swaps Other current liabilities 2,440 Other current liabilities 4,172
Forward contracts Other current liabilities 508
Long-term:
Financial swaps Other liabilities 100 Other liabilities 138
Total $ 3,470 $ 5,174
The table below presents the gains and losses on derivatives not designated as hedging instruments for the year ended
December 31, 2011 and 2010 (in thousands of dollars).
Location of Gain/(Loss) on Gain/(Loss) on Derivatives
Derivatives Recognized in Income Recognized in Income(1)
2011 2010
Financial swaps Off-system sales $ 9,594 $ 4,499
Financial swaps Purchased power (7,124) (12,240)
Financial swaps Fuel expense 501 (101)
Financial swaps Other operations and maintenance 425 -
FFERC FORM NO. I (ED. 12-88) Page 123.34
I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)_ A Resubmission 04/13/2012 2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Forward contracts Fuel Expense - (721)
(I) Excludes changes in fair value of derivatives, which are recorded on the balance sheet as regulatory assets or regulatory liabilities.
Settlement gains and losses on electricity swap contracts are recorded on the income statement in off-system sales or purchased power
depending on the forecasted position being economically hedged by the derivative contract. Settlement gains and losses on both
financial and physical contracts for natural gas are reflected in fuel expense. Settlement gains and losses on diesel derivatives are
recorded in other operations and maintenance expense. See Note 15 for additional information concerning the determination of fair
value for Idaho Power's assets and liabilities from price risk management activities.
Idaho Power had volumes of derivative commodity forward contracts and swaps outstanding at December 31, 2011 and 2010 set forth
in the table below.
December 31,
Commodity
Electricity purchases
Electricity sales
Natural gas purchases
Natural gas sales
Diesel purchases
Credit Risk
Units 2011 2010
MWh 225,600 347,400
MWh 1,298 420 338,200
MMBtu 7,928 311 647,900
MMBtu 352,129 -
Gallons 1,273,997 1,061 969
At December 31 2011 Idaho Power did not have material credit exposure from financial instruments, including derivatives Idaho
Power monitors credit risk exposure through reviews of counterparty credit quality, corporate-wide counterparty credit exposure and
corporate-wide counterparty concentration levels. Idaho Power manages these risks by establishing appropriate credit and
concentration limits on transactions with counterparties and requiring contractual guarantees, cash deposits, or letters of credit from
counterparties or their affiliates, as deemed necessary. Idaho Power's physical power contracts are under Western Systems Power
Pool agreements, physical gas contracts are under North American Energy Standards Board contracts, and financial transactions are
under International Swaps and Derivatives Association, Inc. contracts. These contracts all contain adequate assurance clauses
requiring collaterahzation if a counterparty has debt that is downgraded below investment grade by at least one rating agency.
Credit-Contingent Features
Certain of Idaho Power's derivative instruments contain provisions that require Idaho Power's unsecured debt to maintain an
investment grade credit rating from Moody's Investors Service and Standard & Poor's Ratings Services. If Idaho Power's unsecured
debt were to fall below investment grade, it would be in violation of these provisions, and the counterparties to the derivative
instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative
instruments in net liability positions. The aggregate fair value of all derivative instruments with credit-risk-related contingent features
that were in a liability position at December 31, 2011, was $7.0 million. Idaho Power posted no collateral related to this amount. If
the credit-risk-related contingent features underlying these agreements were triggered on December 31, 2011, Idaho Power would
have been required to post $4.4 million of cash collateral to its counterparties.
15. FAIR VALUE MEASUREMENTS
Idaho Power has categorized their financial instruments into a three-level fair value hierarchy, based on the priority of the inputs to
the valuation technique. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or
liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). If the inputs used to measure the financial instruments
fall within different levels of the hierarchy, the categorization is based on the lowest level input that is significant to the fair value
FERC FORM NO. 1 (ED. 12-88) Page 123.35 1
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)_ A Resubmission 04/13/2012 2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
measurement of the instrument.
Financial assets and liabilities recorded on the consolidated balance sheet are categorized based on the inputs to the valuation
techniques as follows:
Level 1: Financial assets and liabilities whose values are based on unadjusted quoted prices for identical assets or
liabilities in an active market that Idaho Power has the ability to access.
Level 2: Financial assets and liabilities whose values are based on:
a)quoted prices for similar assets or liabilities in active markets;
b)quoted prices for identical or similar assets or liabilities in non-active markets;
C) pricing models whose inputs are observable for substantially the full term of the asset or liability; and
d) pricing models whose inputs are derived principally from or corroborated by observable market data through
correlation or other means for substantially the full term of the asset or liability.
Idaho Power Level 2 inputs are based on quoted market prices adjusted for location using corroborated, observable
market data.
Level 3: Financial assets and liabilities 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 participant would use in pricing the asset or liability.
Idaho Power's derivatives are contracts entered into as part of its management of loads and resources. Electricity swaps are valued on
the Intercontinental Exchange with quoted prices in an active market. Natural gas and diesel derivative valuations are performed
using New York Mercantile Exchange (NYMEX) pricing, adjusted for location basis, which are also quoted under NYMEX. Trading
securities consist of employee-directed investments held in a Rabbi Trust and are related to an executive deferred compensation plan.
Available-for-sale securities are related to the SMSP and are held in a Rabbi Trust and are actively traded money market and equity
funds with quoted prices in active markets.
The table below presents information about Idaho Power's assets and liabilities measured at fair value on a recurring basis as of
December 31, 2011 and 2010 (in thousands of dollars). Idaho Power's assessment of the significance of a particular input to the fair
value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the
fair value hierarchy. There were no transfers between levels for the years presented.
Quoted Prices in Significant Significant
Active Markets Other Unobservable
for Identical Observable Inputs
Assets (Level 1) Inputs (Level 2) (Level 3) Total
December 31, 2011
Assets:
Derivatives $ 3,654 $ 100 $ - $ 3,754
Money market funds 100 - - 100
Trading securities: Equity securities 3,439 - - 3,439
Available-for-sale securities: Equity 22,205 - - 22,205
securities
Liabilities:
Derivatives $ 405 $ 4,302 $ - $ 4,707
IFERC FORM NO I (ED 12-88) Page 12336 1
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/13/2012 2011/04
NOTES TO FINANCIAL STATEMENTS (Continued)
December 31, 2010
Assets:
Derivatives $ 573 $ - $ - $ 573
Money market funds 151,173 - - 151,173
Trading securities: Equity securities 4,746 - - 4,746
Available-for-sale securities: Equity 24,561 - - 24,561
securities
Liabilities:
Derivatives $ - $ 508 $ - $ 508
The table below presents the carrying value and estimated fair value of financial instruments that are not reported at fair value, as of
December 31, 2011 and 2010, using available market information and appropriate valuation methodologies. The use of different
market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts. Cash and cash
equivalents, deposits, customer and other receivables, notes payable, accounts payable, interest accrued, and taxes accrued are
reported at their carrying value as these are a reasonable estimate of their fair value The estimated fair values for long-term debt are
based upon quoted market prices of the same or similar issues or discounted cash flow analysis as appropriate.
December 31, 2011 December 31, 2010

Carrying Estimated Carrying Estimated

Amount Fair Value Amount Fair Value
(thousands of dollars)
Long-term debt $ 1,491 727 $ 1,737 912 $ 1,612,790 $ 1 ,621,425
16. RELATED PARTY TRANSACTIONS
IDA CORP: Idaho Power performs corporate functions such as financial, legal, and management services for IDACORP and its
subsidiaries. Idaho Power charges IDACORP for the costs of these services based on service agreements and other specifically
identified costs. For these services Idaho Power billed IDACORP $0.8 million in 201 land 2010.
Ida-West Idaho Power purchases all of the power generated by four of Ida-West's hydroelectric projects located in Idaho Idaho
Power paid $9 million and $8 million to Ida-West in 2011 and 2010, respectively.
THIS PAGE INTENTIONALLY LEFr BLANK
Name of Respondent
Idaho Power Company
I This Re ort Is:
(2) C]AResubmission J
I Date of Report
04/13/2012
Year/Period of Report
End of 2011/Q4
SUMMA Y OF UTILITY PLANT AND ACCUM LATED PROVISIONS
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Report in Column (c) the amount for electric function, in column (d) the amount for gas function, in column (e), (f), and (g) report other (specify) and in
column (h) common function.
Line
No.
Classification
(a)
Total Company for the
Current Year/Quarter Ended
(b)
Electric
(c)
I Utility Plant
2 In Service
3 Plant in Service (Classified) I 4,467,327,2271 4,467,327,2271
4 Property Under Capital Leases
51 Plant Purchased or Sold
6 Completed Construction not Classified
7 Experimental Plant Unclassified
8 Total (3 thru 7) 4,467,327,227 4,467,327,227
9 Leased to Others
10 Held for Future Use 6,974,407 6 974407
11 Construction Work in Progress 591,474,855 591,474,855
12 Acquisition Adjustments -454,449 -454,449
13 Total Utility Plant (8 thru 12) 5065 322 040 5065 322 040
14 Accum Prov for Depr, Amort & DepI 1,840,782,085 1 840782 085
15 Net Utility Plant (13 less 14) 3224539 955 3224539955
16 Detail of Accum Prov for Depr, Amort & Depi
17 In Service:
18 Depreciation 1,818,635,5211 1,818,635,521
19 Amort & DepI of Producing Nat Gas Land/Land Right
20 Amort of Underground Storage Land/Land Rights
22,587,7581 21 Amort of Other Utility Plant 22,587,7581
22 Total In Service (18 thru 21) 1,841,223,2791 1 841,223 279
23 Leased to Others
24 Depredation
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 Ad] -441,194 -441,194
33 Total Accum Prov (equals 14) (22,26,30,31,32) 1,840,782,085 1,840,782,085
FERC FORM NO I (ED 12-89) Page 200
Name of Respondent
Idaho Power Company
This Re oil Is:
(1)An Original
(2)flA Resubmission
Date of Report
(Mo, Da, Yr)
04/13/2012
Year/Period of Report
End of 201 1/Q4
ELECTRIC PLANT IN SERVICE (Account 101, 102,103 and 106)
1.Report below the original cost of electric plant in service according to the prescribed accounts.
2.In addition to Account 101, Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant Purchased or Sold;
Account 103, Experimental Electric Plant Unclassified; and Account 106, Completed Construction Not Classified-Electric.
3.Include in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year.
4.For revisions to the amount of initial asset retirement costs capitalized, included by primary plant account, increases in column (c) additions and
reductions in column (e) adjustments.
5.Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such accounts.
6.Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in column (c). Also to be included
in column (c) are entries for reversals of tentative distributions of prior year reported in column (b). Likewise, if the respondent has a significant amount
of plant retirements which have not been classified to primary accounts at the end of the year, include in column (d) a tentative distribution of such
retirements, on an estimated basis, with appropriate contra entry to the account for accumulated depreciation provision. Include also in column (d)
Line
No
Account
(a)
Balance
Beginning of Year
(b)
Additions
(C)
1 1. INTANGIBLE PLANT
2 (301) Organization 5,703
3 (302) Franchises and Consents 23,165,537 5,855
4 (303) Miscellaneous Intangible Plant 32,983,5811 6,847,330
5 TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4) 56,154,8211 6.853,185
6 2. PRODUCTION PLANT
7 A. Steam Production Plant 1 8 (31 0) Land and Land Rights 1,604,0321 111,3681
9 (311)Structures and Improvements 139,165,207 5,928,618
10 (312) Boiler Plant Equipment 549,065,614 29,667,912
11 (313) Engines and Engine-Driven Generators
12 14) Turbogenerator Units 148,799,889 3,873,534
13 15) Accessory Electric Equipment 59,886,7561 613,770
14 16) Misc. Power Plant Equipment 15,486,5491 151,084
15 (317) Asset Retirement Costs for Steam Production 3,515,9871 4,489,239
16 1 TOTAL Steam Production Plant (Enter Total of lines 8 thru 15) 917,524,0341 44,835,525
17
18
B. Nuclear Production Plant
20) Land and Land Rights
19 (321) Structures and Improvements
20 22) Reactor Plant Equipment
21 23) Turbogenerator Units
22 24) Accessory Electric Equipment
23 (325) Misc. Power Plant Equipment
24 (326) Asset Retirement Costs for Nuclear Production
25 TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24)
26 C. Hydraulic Production Plant
27 (33 0) Land and Land Rights 30,109. 22,901
28 (331) Structures and Improvements 155,425, 829,675
29 (332) Reservoirs, Dams, and Waterways 250,750,87 2,241,359
30 (333) Water Wheels, Turbines, and Generators 194,277,2 3,939,061
31 (334) Accessory Electric Equipment 43,762.0 2,219,556
32 (335) Misc. Power PLant Equipment 18,088,684 1,048,665
33 (336) Roads, Railroads, and Bridges 7,521,79 590,698
34 (337) Asset Retirement Costs for Hydraulic Production
35 1 TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34) 699,936,059, 10,891,915
36 D. Other Production Plant
37 (34 0) Land and Land Rights 21599, 90,311
38 (341) Structures and Improvements 7,169,
39 (342) Fuel Holders, Products, and Accessories 4,445,86
40 (343) Prime Movers 100,801,636 773,156
41 (344) Generators 31,681,900
42 (345) Accessory Electric Equipment 25,027,598 49,984
43 (346) Misc. Power Plant Equipment 3,118,644 19,793
44 (347) Asset Retirement Costs for Other Production
45 TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44) 174,844,934 933,244
46 TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45) 1,792,305,027 56,660,684
FERC FORM NO. I (REV. 12-05) Page 204
Name of Respondent
Idaho Power Company
This Report Is:
AResubmission
Date of Report
04/13/2012
Year/Period of Report
End of 201 1/Q4
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)
distributions of these tentative classifications in columns (C) and (d), including the reversals of the prior years tentative account distributions of these
amounts. Careful observance of the above instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount of
respondents plant actually In service at end of year.
7.Show in column (f) reclassifications or transfers within utility plant accounts. Include also in column (f) the additions or reductions of primary account
classifications arising from distribution of amounts initially recorded in Account 102, include in column (e) the amounts with respect to accumulated
provision for depreciation, acquisition adjustments, etc., and show in column (f) only the offset to the debits or credits distributed in column (t) to primary
account classifications.
8.For Account 399, state the nature and use of plant included in this account and if substantial in amount submit a supplementary statement showing
subaccount classification of such plant conforming to the requirement of these pages.
9.For each amount comprising the reported balance and changes in Account 102, state the property purchased or sold, name of vendor or purchase,
and date of transaction. If proposed journal entries have been filed with the Commission as required by the Uniform System of Accounts, give also date
Retirements
(d)
Adjustments
(e)
Transfers
(p
Balance at
En%Y'ear
5,703
Line
No.
2
23,171,392 3
5,513,809 34,317,1021 4
5,513,8091
8,291
57,494,1971
1,707,109
6
7
8
1 ,335,178 143,758,647 9
9,249,301 569,484,225 10
11
2,022,617 150,650,806 12
374,396 60,126,1301 13
457,158 15,180,475 14
8,005,2261 15
13,446,941 948,912,618 16
17
18
19
20
21
22
23
24
30,132,870
25
27
28,047 156,227,013 28
102,137 252,890,100 29
295,465 197,920,861 30
127,274 45,854,367 31
55,915 19,081,4341 32
8,112,4911 33
34
608,8381 710,219,1361
2,690,006
35
36
37
7,169,595 38
4,445,866 - 39
2,623,096 98,951,696 40
31,681,900 41
25,077,582 42
3,138,437 43
44
2,623,096 173,155,082 45
16,678,875 1,832,286,836 46
FERC FORM NO. I (REV. 12-05) Page 205
Name of Respondent 1
Idaho Power Company
This Report Is: I 2"Rion
Date of Report
04/13/2012
Year/Period of Report
End of 2011 /Q4
- ELECTRIC PLANT IN SERVICE (Account 101, 102,103 and 106) (Continued)
iii
No
_j
I Account
(a)
Balance Beginning of Year
(b)
Additions
(c)
47 3. TRANSMISSION PLANT
48 (35 0) Land and Land Rights 34,253,938 877,421
49 (352) Structures and Improvements 55,667,437 2,493,112
50 (353) Station Equipment 349,451,391 8,846,58
51 354) Towers and Fixtures 144,723,540 2,767,87
52 (355) Poles and Fixtures 101,621,493 7,282,014
53 (35 6) Overhead Conductors and Devices 169,165,595 4,102,43
54 (357) Underground Conduit
55 (358) Underground Conductors and Devices
56 (359) Roads and Trails 318,351 94,99
57 (359.1) Asset Retirement Costs for Transmission Plant
58 TOTAL Transmission Plant (Enter Total of lines 48 thru 57) 855,201,745 26,464,43
59 4. DISTRIBUTION PLANT
60 (360) Land and Land Rights 4,745,189 683,
61 (361) Structures and Improvements 29,485,862 2,881,
62 (362) Station Equipment 182,593,962 12,192,
63 (363) Storage Battery Equipment
64 (364) Poles, Towers, and Fixtures 225,059,905 5,449.
65 (365) Overhead Conductors and Devices 120,135,601 3,972,
66 (366) Underground Conduit 48,215,714 -143,831
67 (367) Underground Conductors and Devices 191,494,213 6,029,1
68 (368) Line Transformers 414,782,133 19,583,1
69 (369) Services 57,319,909 149,4
70 (370) Meters 95,697,525 17,507,437
71 (371) Installations on Customer Premises 2,750,899 84,107
72 (372) Leased Property on Customer Premises
73 (373) Street Lighting and Signal Systems 4,370,514 58,89
74 (374) Asset Retirement Costs for Distribution Plant 587,980 55,65
75 TOTAL Distribution Plant (Enter Total of lines 60 thru 74) 1,377,239,4061 68,503,57
76 5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT
77 (380) Land and Land Rights
78 (381) Structures and Improvements
79 (382) Computer Hardware
80 (383) Computer Software
81 (384) Communication Equipment
82 (38 5) Miscellaneous Regional Transmission and Market Operation Plant
83 (386) Asset Retirement Costs for Regional Transmission and Market Oper
84 TOTAL Transmission and Market Operation Plant (Total lines 77 thru 83)
85 6. GENERAL PLANT
86 (389) Land and Land Rights 11,123,762 5,004,896
87 (390) Structures and Improvements 77,278,614 7,882,958
88 (391) Office Furniture and Equipment 39,375,541 5,791,888
89 (392) Transportation Equipment 60,957,305 1,751,643
90 (393) Stores Equipment 1,459,340 205,305
91 (394) Tools, Shop and Garage Equipment 5,567,522 682,923
92 (395) Laboratory Equipment 11,946,695 669,571
93 (396) Power Operated Equipment 9,922,182 904,660
94 (397) Communication Equipment 29,214,145 3,918,370
95 (398) Miscellaneous Equipment 4,762,597 759,121
96 1 SUBTOTAL (Enter Total of lines 86 thru 95) 251,607,703 27,571,335
97 (399) Other Tangible Property
98 (399.1) Asset Retirement Costs for General Plant
99 TOTAL General Plant (Enter Total of lines 96, 97 and 98) 251,607,703 27,571,335
100 TOTAL (Accounts 101 and 106) 4,332,508,702 186,053,209
101 (102) Electric Plant Purchased (See lnstr. 8)
102 1 (Less) (102) Electric Plant Sold (See lnstr. 8)
103 (103) Expenmental Plant Unclassified
104 TOTAL Electric Plant In Service (Enter Total of lines 100 thru 103) 4,332,508,702 186,053,209
FERC FORM NO. I (REV. 12-05) Page 206
Name of Respondent
Idaho Power Company
This Report Is:
(2) []A Resubmission
Date of Report
04/13/2012
Year/Period of Report
End of 2011/04
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)
Retirements
(d)
754
Adjustments
(e)
Transfers
(f)
Balance at
End ?fY'ear
35,130,605
___
Line
47
48
165,752 57,994,797 49
6,373,227 351924,749 50
147,491,416 51
1,876,594 107,026,913 52
1,466,062 171,801,963 53
54
55
413,346 56
57
9882,389
4,928
871,783,789
5,423,471
58
59
60
31,545 32,336,183 61
595,771 194,190,240 62
63
1 ,629,356 228,880,444 64
1,571,292 122,536,891 65
82,538 47,989,345 66
822,355 196,700,97 67
4,945,686 429,419,556 68
244,186 57,225,209 69
775,113 112,429,849 70
80,386 2,754,620 71
72
34,549 4,394,855
643,639 74
10,817,705 1434925273 75
76
77
78
79
80
81
82
83
16,128,658
84
85
86
176,785 84,984,787 87
4,609,073 40,558,356 88
1,730,819 60,978,129 89
64,609 1,600,036 90
195,449 6,054,996 91
749,944 11,866,322 92
130,356 10,696,486 93
418,171 32,714,344 94
266,700 5,255,018 95
8,341,906 270,837,132 96
97
98
8,341,906 270,837,132 99
51,234,684 4,467,327,227 100
101
102
103
51,234,684 4,467,327,227 104
FERC FORM NO. 1 (REV. 12-05) Page 207
Name of Respondent
Idaho Power Company
This Re rt Is: Date of Report Year/Period of Report
End of 201 11Q4
ELECTRIC PLANT HELD FOR FUTURE USE (Account 105)
1.Report separately each property held for future use at end of the year having an original cost of $250,000 or more. Group other items of property held
for future use.
2.For property having an original cost of $250,000 or more previously used in utility operations, now held for future use, give in column (a), in addition to
other required information, the date that utility use of such property was discontinued, and the date the original cost was transferred to Account 105.
Line No.
-
Description and Location
Of Prop
(a)
Date Originally lnduded
in This Account
(b)
Da
erty in Utility Service
te Expected to be used
(c)
Balance at
End of Year
(d)
1
2
Land and Rights:
Boise Operations Center 12/31/82
- ___________________
655,550
31 Production 112,704
4 Transmission Stations 429,822
5 Transmission Lines 68,619
_6 Distribution Stations 1,078,590
7 Beacon Light Substation 12130/02 465,662
8 Homedale Substation 2/29/08 109,453
9 North River Operations Center 1131/08 2,630,412
10 Line #854 500 Ky 3/31/09 308,066
11
12
13
14 Column B if no date listed it is various
15
16
17
18
19
20
21
22
Other Property:
Boise Operations Center 12/31/82 72,785
23 Transmission Stations 199,069
24 Distribution Stations 72,016
25 Homedale Substation 2/29/08 215,719
26 Beacon Light Substation 12/30/02 555,940
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47 Total 6,974,407
FERC FORM NO. I (ED. 12-96) Page 214
Name of Respondent
Idaho Power Company
This Report Is: 2'ion
Date of Report
fl30
Year/Period of Report
End of 2011/Q4
CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
1.Report below descriptions and balances at end of year of projects in process of construction (107)
2.Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3.Minor projects (5% of the Balance End of the Year for Account 107 or $1,000,000, whichever is less) may be grouped.
Line
No
Description of Project
(a)
Construction work in progress -
Electric (Account 107)
(b)
1 LANGLEY GULCH POWER PLANT CONS 323,852,696
2 ROLLUP RELIC COST BROWNLEE 53,428,991
3 ROLLUP RELIC COST HELLS CANYON 36,542,791
4 BOARDMAN - HEMINGWAY 500 KV LI 26,168,054
5 GATEWAY WEST 500KV LINE 17,858,788
6 ROLLUP RELIC COST OXBOW 16,825,380
7 HELLS CANYON RELICENSING OUTSI 13,681,208
8 CIAC LIABILITY RECLASS 6478 737
9 LANGLEY GULCH 138/230 KV LINE 6,447,317
10 WQ ONGOING HELLS CANYON RELI 6289 342
11 LANGLEY GULCH SWITCHYARD 6,060,641
12 BRIDGER 2008C123LP Ui TURBINE 4670 643
13 RIVER ENG.-HELLS CANYON CONTIN 4,342,017
14 LANGLEY GULCH PP CONST: WATER 4,129,634
151 LANGLEY GULCH PP CONST: GAS P1 3,368,213
16 CHQ MASTER PLAN NEW PRIMARY 2861 799
17 LANGLEY GULCH 230 KV DOUBLE Cl 2,807,084
18 MPSNO802 INCREASE CAPACITY OF 2557 141
19 FISHERIES-HCC RELICENSING REDB 2,536812
201 ROLLUP RELIC COST SWAN FALLS 2,527,557
21 HCC RELICENSING FISH2004 INST 2,390,747
22 FISHERIES HCC RELICENSING ANAD 2,118,048
23 VALMY 98278700 V1 BOTTOM ASH PU 1,957,851
24 BOBN REPLACE C233 AND C234 SER 1,803,202
25 1321-1 TLINE CONSTRUCTION COSTS 1,780,523
26 AERATION FOR UNIT #5 TO IMPROV 1,754,771
27 LEGAL DEPT LABOR FOR RELICENS 1,527,841
28 BRIDGER UNDISTRIBUTED WORK ORD 1,515,520
291 REL-HCC OREGON REAUTHORIZATION 1,480,417
30 VALMY UNDISTRIBUTED WORK ORDER 1,399,168
31 SWAN FALLS RELICENSING 1,339,913
32 HC LOCAL SERVICE UPGRADE 1,201,965
33 342 COST CENTER DELIVERY CAPIT 1,143,001
34 1314 DESIGN TEAMS - CAPITAL - C 1,120,680
35 PAYROLL & IBNR ACCRUAL 1,089,301
36 OTHER MINOR PROJECTS UNDER $1,000,000 24,417,062
37
38
39
40
41
42
43 TOTAL 591,474,855
FERC FORM NO. 11 (ED. 12-87) Page 216
Name of Respondent
Idaho Power Company
I This Re ii Is:
Resubmission
Date of Report
04/13/2012
Year/Period of Report
End of 2011/04
ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108)
1.Explain in a footnote any important adjustments during year.
2.Explain in a footnote any difference between the amount for book cost of plant retired, Line 11, column (c), and that reported for
electric plant in service, pages 204-207, column 9d), excluding retirements of non-depreciable property.
3.The provisions of Account 108 in the Uniform System of accounts require that retirements of depreciable plant be recorded when
such plant is removed from service. If the respondent has a significant amount of plant retired at year end which has not been recorded
and/or classified to the various reserve functional classifications, make preliminary closing entries to tentatively functionalize the book
cost of the plant retired. In addition, include all costs included in retirement work in progress at year end in the appropriate functional
classifications.
4.Show separately interest credits under a sinking fund or similar method of depreciation accounting.
Section A. Balances and Changes During Year
Line
N O
Item
(a)
Total (c+d+e)
(b)
Elecinc plant in Service
()
Electric Hant Held
for Future Use
(d)
bIecttic FJnt Leased to utners
(e)
I Balance Beginning of Year 1,750,735.947 1,750,735,94 -1
2 Depreciation Provisions for Year, Charged to
113,001,742 113,001,742 3 (403) Depreciation Expense
4
-
(403.1) Depreciation Expense for Asset
Retirement Costs
5 (413) Exp. of Elec. Pit. Leas. to Others
2954.4621 _6 Transportation Expenses-Clearing 2,954,462 __
71 Other Clearing Accounts
_8 Other Accounts (Specify, details in footnote):
9 Fuel Stock 108,272 108,272
10
-
TOTAL Deprec. Prov for Year (Enter Total of
lines 3 thru 9)
116,064,476 116,064,476
11 Net Charges for Plant Retired:
45,706,9001 45,706,900 12 Book Cost of Plant Retired
13 Cost of Removal 6,387,717 6,387,71
14 Salvage (Credit) 1
49,487,363
2,607,254
15 TOTAL Net Chrgs. for Plant Ret (Enter Total
of lines 12 thru 14)
49,487,363
16 Other Debit or Cr. Items (Describe, details in
footnote):
- 1,322,461
17
18 Book Cost or Asset Retirement Costs Retired
19
-
Balance End of Year (Enter Totals of lines 1,
10, 15, 16, and 18)
1,818,635,521 1,818,635,521
- Section B. Balances at End of Year According to Functional Classification
20 Steam Production 527,906,217 527,906,217
21 Nuclear Production
22 Hydraulic Production-Conventional 352,777,683 352,777,683
23 Hydraulic Production-Pumped Storage
24 Other Production 30,461,718 30,461,718
25 Transmission 270,518,301 270,518,301
26 Distribution 528,960,145 528,960,145
27 Regional Transmission and Market Operation
28 General 108,011,457 108,011,457
29 TOTAL (Enter Total of lines 20 thru 28) 1,818,635,521 1 818 635 521
I
FERC FORM NO 1 (REV 1205) Page 219
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
Idaho Power Company (2)_ A Resubmission 04/13/2012 2011/04
FOOTNOTE DATA
Schedule Paae: i_'ni iIIcuIiiIiiITITIiIT __ 111111111 IT
Relocation reimbursements, Up and down costs and damage and insurance claims $ (952,342)
Schedule Page 219 Line No 16 Column b
Accumulated Provision for Depreciation on Asset Retirement Obligation $ (370,120)
JFERC FORM NO 1 (ED 12-87) Page 450.1
Name of Respondent
Idaho Power Company
This Re ort Is:
Resubmission
Date of Report
04/13/2012
Year/Period of Report
End of 2011 /Q4
INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1)
1. Report below investments in Accounts 123.1, investments in Subsidiary Companies.
2. Provide a subheading for each company and List there under the information called for below. Sub - TOTAL by company and give a TOTAL in
columns (e),(f),(g) and (h)
(a)Investment in Securities - List and describe each security owned. For bonds give also principal amount, date of issue, maturity and interest rate.
(b)Investment Advances - Report separately the amounts of loans or investment advances which are subject to repayment, but which are not subject to
current settlement. With respect to each advance show whether the advance is a note or open account. List each note giving date of issuance, maturity
date, and specifying whether note is a renewal.
3. Report separately the equity in undistributed subsidiary earnings since acquisition. The TOTAL in column (e) should equal the amount entered for
Account 418.1.
Line
No.
Description of Investment
(a)
Date Acquired
(b)
Date Of
Manty
Amount of Investment at
Beginning of Year
1 Idaho Energy Resources Company
2 Common Stock 02/01/74 500
3 Capital contributions 2,462,594
4 Equity in earnings 70,098,680
5
6 Subtotal Idaho Energy Resources Company 72,561,774
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 TotaI Cost of Account 123.1 $ 2,463, O] TOTAL 72,561,774
FERC FORM NO. 1 (ED. 12-89) Page 224
Name of Respondent
Idaho Power Company
This Re oil Is: Date of Report
04/13/2012
Year/Period of Report
End of 2011/Q4
INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1) (Continued)
4.For any securities, notes, or accounts that were pledged designate such securities, notes, or accounts in a footnote, and state the name of pledgee
and purpose of the pledge.
5.If Commission approval was required for any advance made or security acquired, designate such fact in a footnote and give name of Commission,
date of authorization, and case or docket number.
6.Report column (t) interest and dividend revenues form investments, including such revenues form securities disposed of during the year.
7.In column (h) report for each investment disposed of during the year, the gain or loss represented by the difference between cost of the investment (or
the other amount at which carried in the books of account if difference from cost) and the selling price thereof, not including interest adjustment includible
in column (f).
8.Report on Line 42, column (a) the TOTAL cost of Account 123.1
Equity in Subsidiary
Earnins?f Year
- Revenues for Year
(f)
Amount of Investment at
End ?f)Year
Gain or Loss from Investment
DisP?d of
Line
500 2
2,462,594 3
5,967,745 76,066,425 4
5
5,967745 78,529,519 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
5967745 78,529,519
FERC FORM NO. 1 (ED. 12-89) Page 225
THIS PAGE INTENTIONALLY LEFT BLANK
I
I
I
Name of Respondent
Idaho Power Company
This Report Is:
2::ssion
Date of Report
31'
Year/Period of Report
End of 201 11Q4
MATERIALS AND SUPPLIES
1.For Account 154, report the amount of plant materials and operating supplies under the primary functional classifications as indicated in column (a);
estimates of amounts by function are acceptable. In column (d), designate the department or departments which use the class of material.
2.Give an explanation of important inventory adjustments during the year (in a footnote) showing general classes of material and supplies and the
various accounts (operating expenses, clearing accounts, plant, etc.) affected debited or credited. Show separately debit or credits to stores expense
clearing, if applicable.
Line
No.
-
Account
(a)
Balance
Beginning of Year
(b)
Balance
End of Year
(c)
Department or
Departments which
Use Material
(d)
1 Fuel Stock (Account 151) 27,546,983 47,865,097 Electric
2 Fuel Stock Expenses Undistributed (Account 152)
3 Residuals and Extracted Products (Account 153)
4 Plant Materials and Operating Supplies (Account 154)
5 Assigned to - Construction (Estimated)
6 Assigned to - Operations and Maintenance
71 Production Plant (Estimated) 14,416,312 14,808,824
8 Transmission Plant (Estimated) 13,365,654 12,917,846
9 Distribution Plant (Estimated) 13,541,576 13,087,873
10 Regional Transmission and Market Operation Plant
(Estimated)
11 Assigned to Other (provide details in footnote) 897,634 1,201,188
12 TOTAL Account 154 (Enter Total of lines 5 thru 11) 42,221,176 42,015,731 Electric
13 Merchandise (Account 155)
14 Other Materials and Supplies (Account 156)
15 Nuclear Materials Held for Sale (Account 157) (Not
applic to Gas Util)
16 Stores Expense Undistributed (Account 163) 3,379,745 4,474,719 Electric
17
18
19
20 TOTAL Materials and Supplies (Per Balance Sheet) 73,147,904 94,355,547
FERC FORM NO. I (REV. 12-05) Page 227
Name of Respondent
Idaho Power Company
This Re oil Is:
ARssion
Date of Report
(Mo, Da, Yr)
Yea Period of Report
End of 201 1/04
Transmission Service and Generation Interconnection Study Costs
1.Report the particulars (details) called for concerning the costs incurred and the reimbursements received for performing transmission service and
generator interconnection studies.
2.List each study separately.
3.In column (a) provide the name of the study.
4.In column (b) report the cost incurred to perform the study at the end of period.
5.In column (c) report the account charged with the cost of the study.
6.In column (d) report the amounts received for reimbursement of the study costs at end of period.
7.In column (e) report the account credited with the reimbursement received for performing the study.
Line
N 0. Description
(a)
41,480
During
Account Charged
(c)
Reimbursements
Received During
the Period
(d)
Account Credited
With Reimbursement
1
2
Transmission Studies
RLE TRANS SiS 74668832 186623 17,936 186623
3 IPCM TRANS SiS 74705988,74705990,
4 74705993, 74705995, 74706017 2,869 186623 ( 1,913) 186623
5 IPCM TRANS SIS 74785240 7,635 186623 2,365 186623
6 IPCM TRANS SIS 74822581-74822582 3,801 186623 5,233 186623
7 IPCM TRANS S1S74875628-74875626 2,631 186623 7,369 186623
8 IPCM TRANS SIS 74875653-74875654-
9 74875656 186623 10,000 186623
10 IPCM TRANS S1S74905894-74905896 186623 10,000 186623
11 IPCM TRANS SIS 74993330 1,859 186623 ( 1,859) 186623
12 IPCM TRANS SIS 74978926-74978929 13,558 186623 ( 13,558) 186623
13
14
15
16
17
18
19
20
21 Generation Studies
4,452 186623 186623 22 LAVA BEDS WIND PARK
231 GENERATOR CLUSTER GROUP 1 4,373 186623 95,890 186623
24 HIDDEN HOLLOW EXPANSION Gl#291 2,477 186623 186623
25 LITTLE WOOD RIVER Gl#292 186623 ( 1,620) 186623
26 ROCKLAND WIND FARM PROJECT 293 12,491 186623 ( 9,389) 186623
27 WHEATGRASS RIDGE WIND PROJECT 294 30,811 186623 ( 93,587) 186623
28 COTTEREL MTN WIND PROJECT 302 14,005 186623 186623
29 ADAMS COUNTY BIOMASS Gl#304 65 186623 186623
30 ANTELOPE RIDGE WIND PROJECT 306 1,237 186623 86,209 186623
31 SWAGER FARMS Gl#307 2,927 186623 ( 19,526) 186623
32 DOUBLE B DAIRY GI#308 1,863 186623 ( 650) 186623
33 ROCK CREEK DAIRY Gl#309 1,769 186623 ( 2,166) 186623
34 GRAND VIEW SOLAR GI#312 1,081 186623 186623
35 YELLOWSTONE PWR Gl#31 5 1,450 186623 186623
36 STANFORD RANCH GI#318 4,661 186623 23,208 186623
37 ROGERSON FLATS GI 322 4,610 186623 ( 786) 186623
38 JACK RANCH WIND GI 323 185623 5,000 186623
39 JACK RANCH WIND GI 324 186623 10,000 186623
40 SALMON CREEK Gi 325 16,644 186623 ( 30,000) 186623
FERC FORM NO. 111-F13-0 (NEW. 03-07) Page 231
I
Name of Respondent
Idaho Power Company
This Re ort Is:
2ssion
Date of Report
(M1;2'2
Year/Period of Report
End of 201 1/Q4
Transmission Service and Generation Interconnection Study Costs (continued)
Line
No Description
(a)
Costs Incurred During
Period
(b)
Account Charged
(c)
Reimbursements
Received During
the Period
(d)
Account Credited
With Reimbursement
(e)
1
2
Transmission Studies
3
4
5
6
7
8
9
10
11
1 2
13
14
15
16
17
18
19
20
21 Generation Studies
15,832 186623 ( 20,584) 186623 221 JACK RANCH WIND GI 327
23 TUMBLE WEED 34.5 01 332 17,256 186623 186623
24 BENNETT CREEK SOLAR GI 333 186623 231 186623
25 HIGH MESA WIND 01334 23,839 186623 ( 68,201) 186623
26 SLATERS FLAT GI 335 186623 530 186623
27 TWO PONDS 01 336 6,621 186623 82,373 186623
28 RYEGRASS WINDFARM GI 337 186623 ( 1,077) 186623
29 MAINLINE WINDFARM 01 338 186623 ( 1,078) 186623
30 HAMMETI HILL WINDFARM 01 339 186623 ( 1,078) 186623
31 DESERT MEADOW WINDFARM GI 340 186623 ( 1,078) 186623
32 COLD SPRINGS WINDFARM 01 341 186623 ( 1,078) 186623
33 BEAR CREEK WIND 01 343 2,763 186623 2,496 186623
34 DYNAMIS LANDFILL 01 344 13,346 186623 ( 21,667) 186623
35 MURPHY FLATS 01 345 7,182 186623 16,310 186623
361 MURPHY FLAT WIND 01 346 9,714 186623 ( 99,714) 186623
37 AG POWER GI 348 5,533 186623 10,023 186623
38 NOTCH BUTTE GI 349 22,237 186623 186623
39 DEEP CREEK 01 350 1186623 663 186623
401 RAINBOW WEST GI 352 28,929 186623 ( 59,212) 186623
I FERC FORM NO. 1/1-F13-Q(NEW.03-O7) Page 231.1
Name of Respondent
Idaho Power Company
This Rort Is:
'ssjon
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of 201 1/Q4
Transmission Service and Generation Interconnection Study Costs (continued)
Line
No
-
Description
(a)
Costs Incurred During
Period
(b)
Account Charged
(c)
- Reimbursements
Received Dung
the Period
(d)
Account Credited
With Reimbursement
(e)
1 Transmission Studies
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21 Generation Studies
186623 573 186623 22 RAINBOW RANCH GI 353
23 MALAD STATION GI 354 9,716 186623 ( 9,930) 186623
24 TRADE DOLLAR MINE GI 355 186623 80 186623
25 SALMON FALLS WIND GI 357 2,303 166623 ( 101,177) 186623
26 MURPHY FLATS GI 358 1,656 186623 ( 6,457) 186623
27 NOTCHBUTTE GI 359 14,342 186623 ( 31,000) 186623
28 FARGO DROP GI 360 186623 ( 88) 186623
29 AG ENERGY GI 361 553 186623 ( 553) 186623
30 COLEMAN HYDRO GI 362 5,048 186623 ( 18,975) 186623
31 EIGHTMILE HYDRO GI 366 352 186623 ( 352) 186623
32 CLARK CANYON HYDRO GI 367 7,151 186623 ( 7,151) 186623
33 U3 HYDRO GI 368 2,661 186623 ( 2,661) 186623
34 GRAND VIEW SOLAR TWO GI 369 2,228 186623 ( 32,147) 186623
35 MEADOW CREEK WIND GI 370 14,350 186623 ( 153,446) 186623
36 WONDEROUS WIND GI 371 6,565 186623 ( 6,565) 186623
37 WEST BOISE WASTE WATER GI 372 214 186623 ( 214) 186623
38 MTNAIR EXPANSION GI 373-378 21,101 186623 ( 50,000) 186623
39 BANNOCK COUNTY LANDFILL GI 380 2,078 186623 ( 10,849) 186623
40 DOUBLE EAGLE DAIRY GI 381 939 186623 ( 939) 186623
FERC FORM NO. 111-F13-Q (NEW. 03-07) Page 2312
I
Name of Respondent
Idaho Power Company
This Rep ort Is:
(1)IX1 An Original L__J (2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/13/2012
Year/Period of Report
flu 01 201 1/04
Transmission Service and Generation Interconnection Study Costs (continued)
Line
No
-
Description
(a)
Costs Incurred During
Period
(b)
Account Charged
(c)
Reimbursements
Received During
the Period
(d)
Account Credited
With Reimbursement
(e)
1
2
Transmission Studies
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21 Generation Studies
9,575 186623 ( 12,250) 186623 22 FARGO DROP GI 382
23 BETASEED BIOGAS GI 383 2,913 186623 ( 1,000) 186623
24 JETTCREEK W1NDFARM GI 384 186623 ( 1,000) 186623
25 PROSPECTOR WINDFARM GI 385 186623 ( 1,000) 186623
261 BENSON CREEK WINDFARM GI 386 186623 ( 1,000) 186623
27 DURBIN CREEK WINDFARM GI 387 186623 ( 1,000) 186623
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO. 1I1-F13-0 (NEW. 03-07) Page 231.3
Name of Respondent
Idaho Power Company
This Re ort Is:
2"Rs sion
Date of Report
04/13/2012
Year/Period of Report
End of 201 1/Q4
OTHER 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 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
No.
-
Description and Purpose of
Other Regulatory Assets
(a)
Balance at
Beginning of
Current
Quarter/Year
(b)
Debits
(c)
CREDITS Balance at end of
Cunt Quaderf'ear
(f)
Written on During
the Quarter/Year
Account Charged
(d)
Wntten off During
the Period
Amount
(e)
11 Asset Retirement Obligations- (18234 1) 15,371,785 1022,534 107/230 836,897 15,557,422
2 IPUC Order# 294 14-OPUC Order# 04-585
3
4 SFAS 133 Mark to Market - ST (182330) 2,239,694 16,405,599 244 14,046,194 4,599,099
5
6 FAS 133 Mark to Market - LT (182333) 38,140 644,551 244 574,928 107,763
7
8 FAS 109 Unfunded - Noncurrent (182322) 588,594,650 33,728,127 Various 18,550,599 603772,178
9
10 PCA Deferral Idaho - IPUC Order #27660 30,281,079 48,612,766 Various 78,893,845
11 (Amort period 06/12 thru 05/13) (182323)
12
13 PCA Prior Year Deferral Idaho - IPUC Order #27660 (12,721,876) 56.792,870 Various 44,070,994
14 (Amort period 06/11 thru 05/12) (182324)
15
16 Fixed Cost Adjusment Current Year Order #30267 9,474,129 22,833,343 1823 22,034,176 10,273,296
17 (Amort period 06/12 thru 05/13) (182302)
18
19 Prior Year FCA IPUC Order #30267(182309) 2,866,515 61,891,323 1823/400 60,574,666 4,183,172
20
21 IPUC Grid West loans - IPUC Order #30157 186,434 401 186,434
22 (Amort period 01/07 - 12111) (182303)
23
24 FERC Grid West Expense - ER08-629-000 195,525 401 83,797 111,728
25 (Amort period 05/08 thru 04/13) (182304)
26
271 SFAS 106/158 Post Retirement Benefits 19,031,743 55,020 2283 3,550,586 15,536,177
28 IPUC Order #30256 (182306)
29
30 FIN 48 Adjustment Interest Payable (159,138,028) 160,341,593 282 1,203,565
31 IPUC Order #30256 (182310)
32
33 Pension Deferred FERC Portion (182338) 150,391 1,391,646 1823 1,542,037
34
35 Pension Deferred Oregon Order UE-213 (182339) 939,890 439,115 4073 33,518 1,345,487
36
37 FAS 87 Deferred Pension-IPUC Order #30333 (182321) 8,549,588 27,159,214 Various 18,568,480 17,140,322
38
39 Unfunded Pension Liability 163,710,092 92,449,107 2283 9,192,434 246,966,765
40 IPUC Order #30256 (182320)
41
421 ID DSM Rider Reclass IPUC Order #29026 (182301) 17592 938 28399 653 254 40,670,594 5321 997
43 PCAM Oregon 2008 OPUC Order #08-238 (18 2346) 5,956,673 498,312 6,454,985
44 TOTAL 761,425,884 620,622,892 392,854,761 989,194,015
FERC FORM NO. 113-Q (REV. 02-04) Page 232
Name of Respondent
Idaho Power Company
This Re ort Is:
(2) AResubmission
Date of Report
04/13/2012
Year/Period of Report
End of 2011/Q4
OTHER 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 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
No.
Description and Purpose of
Other Regulatory Assets
(a)
Balance at
Beginning of
Current
Quarter/Year
(b)
Debits
(c)
CREDITS Balance at end of
Current Quarter/Year
(f)
written Ott During
the Quarter/Year
Account Charged
(d)
Wnttefl oft DUflhlg
the Period
Amount
(e)
2 PCAM Interest Res 2008 OPUC Order #08-238(182329) ( 278674) 135,798 1823/4210 286,186 429,062
3
4 Excess Power Cost Deferral 2007 6,964,691 14,852,011 1823/401 17,054,386 4,762,316
5 IPUC Order #09-189 (182358)
6
7 2007 EPC Interest Res IPUC Order #09-189 (182351) ( 452759) 144,480 182/4210 590 308869
8
91 Oregon DSM Rider Reclass- 1,873,675 13,340,738 254 11,676,971 3,537,442
10 OPUC Advice #05-03(182359)
11
12 2009 Reorg IPUC Order#30914 922,622 401 230,655 691,967
13 (Amort period 01/10 thru 12/14) (182318)
14
15 OATT Revenue Deferred Reserve IPUC Order #30940 4,675,182 57,346 186 2,668,059 2,064,469
16 (Amort period Ol/11 thru 12/13) (182336)
17
18 Idaho Pension Cash (182327) 53,169,373 18,681,291 1823/401 32,874,180 38,976,484
19 IPUC Order #31091 Amort Period (06/10 thru 05/11)
201 IPUC Order #32248 Amort Period (06/11 thru 05/14)
21
22 FERC Pension Cash (182328) 1,024,067 981,527 1823/401 1,423,438 582,156
23 IPUC Order #3 1091 Aniort Period (06/10 thru 05/11)
24 IPUC Order #32248 Amort Period (06/11 thru 05/14)
25
26 Excess Power Cost Unbilled Amort (186356) 1,153,467 401 1,296,113 -142,646
27
28 Cus Efficiency Incentive IPUC Order #32245 (182317) 8,309,903 1823 1,079,179 7,230,724
29
30 Cus Efficiency Incen Res IPUC Order #32245(182314) 4210 134,282 -134,282
31
32 Lidar Surveys IPUC Order #32426 436,047 436,047
33 (Amort period Ol/l2thru 12/21) (182361)
34
35 Bennett Mtn Maintenance IPUC Order #32426 299,546 299,546
36 (Amort period 01/12 thru 12/15) (182379)
37
3
39
208,345 9,565,965 Various 9,516,978 257,332
40
41
42
43
44 1 TOTAL 761,425,884 620,622,892 392,854,761 989,194,Olt
FERC FORM NO. 113-Q (REV. 02-04) Page 232.1
THIS PAGE INTENTIONALLY LEFT BLANK
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)_ A Resubmission 04/13/2012 2011/Q4
FOOTNOTE DATA
eduIe Page: 232.l Line No:38 Column: a 1
Accounts included in minor items:
182305
182316
182331
182334
182335
182340
182344
182345
182347
182349
182350
182353
182355
182 357
182369
182374
182375
182376
Name of Respondent
Idaho Power Company
This Re art Is:
Original 2rss.on
Date of Report
(Mo, Da, Yr) End of 2011/04
Year/Period of Report
MISCELLANEOUS DEFFERED DEBITS (Account 186)
1.Report below the particulars (details) called for concerning miscellaneous deferred debits.
2.For any deferred debit being amortized, show period of amortization in column (a)
3.Minor item (1% of the Balance at End of Year for Account 186 or amounts less than $100,000, whichever is less) maybe grouped by
classes.
Line
No
-
Description of Miscellaneous
Deferred Debits
(a)
Balance at
Beginning of Year
(b)
Debits
(c)
CREDITS Balance at
End of Year
(f)
Account
Cha ed
(
Amount
(e)
1 Rents - Rights of way (186160) 773,585 29,483 Various 87,111 715,957
3 Advance Prepaid (186709) 1,433,219 143 65,958 1,367,261
_4 Coal Royalties
5
6 Security plan (186720) 21,047,429 1,435,137 143/165 3,480,834 19,001,732
7
8 American Falls Bond Ref(186722) 206,157 401 14,553 191,604
9 (Amort 04/00 - 7/26)
10
11 Prepaid Credit Facility(1 86025) 60,300 1,981,233 165/431 1,048,863 - 992,670
12 (Amort 10/11 - 10/15)
13
14 CompanyOwned(186726) 5,624,403 2,196,361 Various 2,762,408 5,058,356
151 LifeInsurance
16
17 AmericanFallsWaterRights 14,674,956 401 1,042,008 13,632,948
18 (Amort01/06-12/25)(186727)
19
20 MilnerBondGuarantee(186734) 7,445,455 253 1,063,637 6,381,818
21 (Amort02/07-2/17)
22
23 AmericanFalls - Bondrefinance 679,988 401 47,999 631,989
24 (35year amortization)(186770)
25
26 Shelf Registration-2010(186731) 2,383,894 109,135 181/232 2,460,532 32,497
27
281 TransmissionDeposit 687,741 22,837 710,578
291 PacifiCorp(186784)
30
31 Prepaid(186052) 308,302 845,063 Various 502,893 650,472
32 Peoplesoft/Passport
33 (Various AmortizationPeriods)
34
351 LongTerm(186121) 1,306,903 228/401 38,447 1,268,456
361 Workers Compensation
37
38 OATTRevenueDeferredReserve -2,610,713 2,610,713
39 Order #30940(186300)
40 (amort period3yearsstart
41 datenot yet determined)
42
43 Long-TermFirm(186624) 919,063 30,299 Various 949,362
44 Trans Deposits
45
46 Power Plant- ValmyJ(186793) 98,366 72_991 107/401 1 34,951 136_406
47 Misc. Work in Progress
-
Deferred Regulatory Comm.
Expenses (See pages 350-351)
49 TOTAL 55,131,472 50,880,202
FERC FORM NO. I (ED. 12-94) Page 233
I
Name of Respondent
Idaho Power Company
This Re ort Is:
(2) EIAResubmission
Date of Report
04/13/2012
Year/Period of Report
End of 2011 /Q4
MISCELLANEOUS DEFFERED DEBITS (Account 186)
1.Report below the particulars (details) called for concerning miscellaneous deferred debits.
2.For any deferred debit being amortized, show period of amortization in column (a)
3.Minor item (1% of the Balance at End of Year for Account 186 or amounts less than $100,000, whichever is less) maybe grouped by
classes.
Line
No.
-
' Description of Miscellaneous
Deferred Debits
(a)
Balance at
Beginning of Year
(b)
Debits
(c)
CREDITS Balance at
End of Year
(f)
ACCOU
(d)
Amount
(e)
2
31 Power Plant- Boardman (186794) 76,451 88,541 107/401 60,179 104,813
4
- 15,973 8,637,388 Various 8,650,716 2,645
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 Misc. Work in Progress
Expenses (See pages 350-351) -
Deferred Regulatory Comm.
49 TOTAL 55,131,472 50,880,202
FERC FORM NO. I (ED. 12-94) Page 233.1
THIS PAGE INTENTIONALLY LEFT BLANK
Name of Respondent This Report is: Date of Report Ye Period of Report
(1)An Original (Mo, Da, Yr)
Idaho Power Company (2)_ A Resubmission 04/13/2012 2011/Q4
FOOTNOTE DATA
Accounts included in minor items:
186100
186255
186623
186703
186946
LFERC FORM NO I (ED 12-87) Page 450.1 I
Name of Respondent This Re ort Is:
Idaho Power company (2) p A Resubmission
Date of Report
04/13t2012
Year/Period of Report
End of 2011/Q4
ACCUMULATED DEFERRED INCOME TAXES (Account 190)
1.Report the information called for below concerning the respondent's accounting for deferred income taxes.
2.At Other (Specify), include deferrals relating to other income and deductions.
C1i
N 0.
Description and Location
(a)
Balanceof Be of Year
(b)
Balance at End of Year
(c)
1 Electric
2
Emission Allowances -509,154
41 Advances for Construction 7,061,283 5,117,985
6.072,776 46276 158
6 Jill 'I'M 126,631,2101 157,500,863
I TOTAL Electric (Enter Total of lines 2 thru 7) 139,256,1151 208,895,006
91 Gas
10
11
12
13
14
151 Other
ir TOTAL Gas (Enter Total of lines 10 thru 15
1 18090657 19 082 040
18 TOTAL (Acct 190) (Total of lines 8, 16 and 17) 157,346,7721 227,977,046
Notes
FERC FORM NO. I (ED. 12-88) Page 234
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)_A Resubmission 04/13/2012 201 1/Q4
FOOTNOTE DATA
S~hWddke Page: 234 Line No.:5 Column: a
(Note 1): Ending Balance Ending Balance
Revenue Sharing 0.00 10,594,313.78
Post Retiree Benefits-VEBA 5,658,260.39 7474 51909
AFUDC Hells Canyon Relicensing 8,292,259.43 12,958,192.16
Rate Case Disallowance 2,765,193.22 2621 255 57
Stock Based Compensation 2496 071 09 2,777,080.86
Other Employee's Long Term Deferred Compensation 1,855,361.91 1,344,427.39
Post Retirement Benefits 1,504,637.15 1,172,344.50
Deferred Idaho ITC 4,183,991.50 5,539,826.50
Non-VEBA Pension and Benefits 414,231.42 265,356.10
Oregon-Pension Expense 817,275.90 1,504,842.01
FERC Credit OFA 182,023.59 0.00
IRS Interest Expense 93,084.00 0.00
Pension Expense (Acct 228) (22,197,833.71) 0.00
Deferred GBC 24,000.00 24,000.00
Bonus Deferral (514.49) 0.00
Delivery Accruals (15,265.83) 0.00
Total Other Electric 6,072,775.57 46276 157 96
Schedule Pg34 Line No.: 7 Column a
(Note 2) Ending Balance Ending Balance
Pension 64 358 79967 96,551,656.75
Regulatory Liability for Income Taxes 46,199,137.04 45472,54723
Postretirement Plan 8025 874 06 6,367,217.42
Minimum Pension Liability 8,047,399.21 9 109 441 86
Total Other 126631 20998 157 500 86326
Schedule Page 234 Line No 17 Column a
(Note 3): Ending Balance Ending Balance
Senior Management Security Plan 15,067,824.46 16,319,200.67
SMSP-Market Change of Rabbi Investments 1,626,015.01 1,626,015.01
Micron-CIAC 1,288,362.93 1,050,481.59
Meridian Gold Contributions 108,454.56 86,342.35
Total Non Electric 18,090,656.96 19,082,039.62
(FERC FORM NO I (ED 12-87) Page 4501 I
Name of Respondent
Idaho Power Company
This Re oil Is:
2nRssion
Date of Report
04/1312012
Year/Period of Report
End of 201 1/Q4
CAPITAL STOCKS (Account 201 and 204)
1.Report below the particulars (details) called for concerning common and preferred stock at end of year, distinguishing separate
series of any general class. Show separate totals for common and preferred stock. If information to meet the stock exchange reporting
requirement outlined in column (a) is available from the SEC 10-K Report Form filing, a specific reference to report form (i.e., year and
company title) may be reported in column (a) provided the fiscal years for both the 10-K report and this report are compatible.
2.Entries in column (b) should represent the number of shares authorized by the articles of incorporation as amended to and of year.
Line
No.
-
Class and Series of Stock and
Name of Stock Series
(a)
Number of shares
Authorized by Charter
(b)
Par or Stated
Value per share
(C)
Call Price at
End of Year
(d)
1 Account 201
2 Common Stock registered on New York 50,000,000 2.50
3 and Pacific Stock Exchange
4 Total Common Stock 50,000,000 2.50
5
6 Account 204 - None
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO. 1 (ED. 12-91) Page 250
I
Name of Respondent
Idaho Power Company
This Report Is:
sion
Date of Report Year/Period of Report
End of 2011 /Q4
CAPITAL STOCKS (Account 201 and 204) (Continued)
3.Give particulars (details) concerning shares of any class and series of stock authorized to be issued by a regulatory commission
which have not yet been issued.
4.The identification of each class of preferred stock should show the dividend rate and whether the dividends are cumulative or
non-cumulative.
5.State in a footnote if any capital stock which has been nominally issued is nominally outstanding at end of year.
Give particulars (details) in column (a) of any nominally issued capital stock, reacquired stock, or stock in sinking and other funds which
is pledged, stating name of pledgee and purposes of pledge.
OUTSTANDING PER BALANCE SHEET (Total amount outstanding without reduction
for amounts held by respondent)
HELD BY RESPONDENT Line
"° AS REACQUIRED STOCK (Account 217) IN SINKING AND OTHER FUNDS
Shares (e) Amount (f) Shares (g) Cost (h)
Shares (i)
Amount
39,150,812 97,877,030 2
3
39,150,812 97,877,030
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. I (ED. 12-88) Page 251
Name of Respondent
Idaho Power Company
This Re ort Is:
(2) F-1 A Resubmission
Date of Report
04/13/2012
Year/Period of Report
End of 2011/Q4
OTHER PAID-IN CAPITAL (Accounts 208-211, inc.)
Report below the balance at the end of the year and the information specified below for the respective other paid-in capital accounts. Provide a
subheading for each account and show a total for the account, as well as total of all accounts for reconciliation with balance sheet, Page 112. Add more
columns for any account if deemed necessary. Explain changes made in any account during the year and give the accounting entries effecting such
change.
(a)Donations Received from Stockholders (Account 208)-State amount and give brief explanation of the origin and purpose of each donation.
(b)Reduction in Par or Stated value of Capital Stock (Account 209): State amount and give brief explanation of the capital change which gave rise to
amounts reported under this caption including identification with the class and series of stock to which related.
(c)Gain on Resale or Cancellation of Reacquired Capital Stock (Account 210): Report balance at beginning of year, credits, debits, and balance at end
of year with a designation of the nature of each credit and debit identified by the class and series of stock to which related.
(d)Miscellaneous Paid-in Capital (Account 211)-Classify amounts included in this account according to captions which, together with brief explanations,
disclose the general nature of the transactions which gave rise to the reported amounts.
Lige Ien Arynt
1 Account 208 - Donations received from stockholders - None
2
3 Account 209 - Reduction in par or stated value of Capital Stock - None
4
5 1 Account 210- Gain on reacquired Capital Stock - None
6
7
8 1 Account 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. I (ED. 12-87) Page 253
Name of Respondent
Idaho Power Company
This Report Is:
(2) MA Resubmission
Date of Report
(Mo, Da, Yr)
04/13/2012
Year/Period of Report
End of 201 11Q4
CAPITAL STOCK EXPENSE (Account 214)
1.Report the balance at end of the year of discount on capital stock for each class and series of capital stock.
2.if any change occurred during the year in the balance in respect to any class or series of stock, attach a statement giving particulars
(details) of the change. State the reason for any charge-off of capital stock expense and specify the account charged.
Line
No
Class and Series of Stock
(a)
- Balance at End of Year
(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
L FERC FORM NO. 1ED1247 -
I Name of Respondent
Idaho Power Company
This Re ort Is:
(2) AResubmission
Date of Report Year/Period of Report
End of 201 1/Q4
LONG-TERM DEBT (Account 221, 222, 223 and 224)
1.Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds, 222,
Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt.
2.In column (a), for new issues, give Commission authorization numbers and dates.
3.For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
4.For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate
demand notes as such. Include in column (a) names of associated companies from which advances were received.
5.For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
6.In column (b) show the principal amount of bonds or other long-term debt originally issued.
7.In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
8.For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
Indicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted.
9.Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year. Also, give in a foothote the date of the Commission's authorization of treatment other than as
specified by the Uniform System of Accounts.
Line
No.
Class and Series of Obligation, Coupon Rate
(For new issue, give commission Authorization numbers and dates)
(a)
Principal Amount
Of Debt issued
(b)
Total expense,
Premium or Discount
(c)
1 Account 221:
2 First Mortgage Bonds
3 450% Series due 2020 130,000,000 1,190,698
4 234,601 D
5
6 5.50% Series due 2033 70,000,000 728,701
71 36,400 D
8
9 6.15% Series Due 2019 100,000,000 1,034,909 To 184,949 D
11
12 3.40% Series due 2020 100,000,000 1,159,871
13 498,864 D
14
15 5.30% Series Due 2035 60,000,000 408,411 D
16 3,802,019
17
18 4.25%Series due 2013 70,000,000 641,201
19 372,696 D
20
21 4.75% Series due 2012 100,000,000 944,356
1,047,617 D
23
24 6.00% Series due 2032 100,000,000 1,191,216
25 543,244 D
26
27 5.875% Series due 2034 55,000,000 -585,759
28 746,961 D
29
30 5.50% Series due 2034 50,000,000 524,419
31 3833220
32
33 TOTAL 1,617,045,000 27,130,028
FERC FORM NO. I (ED. 12-96) Page 256
Name of Respondent
Idaho Power Company
This Report Is:
(2) A Resubmission
Date of Report (Mo, Da, Yr)
04/13/2012
Year/Period of Report
End of 2011 IQ4
LONG-TERM DEBT (Account 221, 222, 223 and 224) (Continued)
10.Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11.Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12.in a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term
advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13.If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose of the pledge.
14.If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of
year, describe such securities in a footnote.
15.If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (I) and the total of Account 427, interest on
Long-Term Debt and Account 430, Interest on Debt to Associated Companies.
16 Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued
Nominal Date
Of issue
Date of
Maturity
AMORTIZATION PERIOD outstanaing. (Total amount outstanding without
reduction for amounts held by resp dent)
Interest for Year
Amount
Line
0 Date From Date To
11120/09 3/1/20 11/20/09 3/1/20 130,000,000 5,850,000 3
4
5
05/01/03 04/01/33 05/01/03 03/31/33 70,000,000 3,850,000 6
7
8
4/1/09 4/1/19 4/1/09 4/1/19 100,000,000 6,150,000 9
10
11
11/1/10 5/1/2020 11/1/10 5/1/20 100,000,000 3,400,000 12
13
14
08/26/05 08/26/35 08/26/05 08/26/35 60,000,000 3,180,000 15
16
17
05/01/03 10/01/13 05/01/03 09/29/13 70000 000 2,975,000 18
19
20
11/15/02 11/15/12 11/15/02 11/15/12 100,000,000 4,750,000 21
22
23
11/15/02 11/15/32 11/15/02 11/15/32 100,000,000 6000 000 24
25
26
08/16/04 08/16/34 08/16/04 08116/34 55,000,000 3231,250 27
28
29
03/26/04 03/15/34 03/26104 03/15/34 50,000,000 2,750,000 30
31
32
1,491,726,818 79,348,955 33
FERC FORM NO. I (ED. 12-96) Page 257
Name of Respondent
Idaho Power Company
This Re oil Is:
(2) AResubmission
Date of Report
04/13/2012
Year/Period of Report
End of 2011/04
LONG-TERM DEBT (Account 221, 222, 223 and 224)
1.Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds, 222,
Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt.
2.In column (a), for new issues, give Commission authorization numbers and dates.
,
3. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
4.For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate
demand notes as such. Include in column (a) names of associated companies from which advances were received.
5.For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
6.In column (b) show the principal amount of bonds or other long-term debt originally issued.
7.In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
8.For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
Indicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted.
9.Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year. Also, give in a foothote the date of the Commission's authorization of treatment other than as
specified by the Uniform System of Accounts.
Line
No.
Class and Series of Obligation, Coupon Rate
(For new issue, give commission Authorization numbers and dates)
(a)
Principal Amount
Of Debt issued
(b)
Total expense,
Premium or Discount
(c)
1 485% Series Due 2040 100,000,000 1,284,871
2 169,984 D
3
4 6.30% Series due 2037 140,000,000 1,495,799
278,367 D
6
7 6.25% Series due 2037 100,000,000 1,141,489
8 267,677 D
9
10 Port of Morrow Variable due 2027 4,360,000 188,545
11
12 Humboldt Variable due 2024 49,800,000 1,697,856
13
14 Sweetwater Variable due 2026 116,300,000 3,026,122
15
16
17 6.025% Series Due 2018 120,000,000 1,630,120
18
19 6.60% Series Due 2011 120,000,000 860,502
20
21 Subtotal Account 221 1,585,460,000 27,130,028
22
23 Account 222 - Reaquired Bonds
24
25 Account 223: Advances for Associated Companies
26
27 Account 224:
28 Bond Guarantee - American Falls 19,885,000
29 Note Guarantee - Milner Dam 11,700,000
30 Subtotal Account 224 31,585,000
31
32
33 TOTAL 1,617,045,0001 27 130 028
FERC FORM NO I (ED 12.96) Page 2561
I
Name of Respondent
Idaho Power Company
This Report Is: Date of Report
04/13/2012
Year/Period of Report
End of 201 1/Q4
LONG-TERM DEBT (Account 221, 222, 223 and 224) (Continued)
10.Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11.Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12.In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term
advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13.If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose of the pledge.
14.If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of
year, describe such securities in a footnote.
15.If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (I) and the total of Account 427, interest on
Long-Term Debt and Account 430, Interest on Debt to Associated Companies.
16.Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
Nominal Date
of Issue
(d)
Date of
Maturity
(e)
AMORTIZATION PERIOD Outstanding. (Total amount outstanding without reduction for amounts held by
?)
Interest for Year
Amount
(i)
Line
No. Date From
(f)
Date To
(g)
2/15/10 8/15/40 2/15/10 8/15/40 100,000,000 4850 000 1
2
3
6/22/07 6/15/2037 6122/07 6/15/2037 140,000,000 8,820,000 4
5
6
10/18/07 10/15/2037 10/18/07 10/15/2037 100,000,000 6,250,000 7
8
9
05/17/00 02/01/27 05/17/00 02/01/27 4,360,000 50255 10
11
10/22103 12/01/24 11/01/03 12/01/24 49,800,000 2,564,700 12
13
10/3/06 7/15126 10/3/06 7/15/2026 116,300,000 6,105,750 14
15
16
7/10/08 7/15/18 7/10/08 7/15/08 120,000,000 7,230,000 17
18
3/2/01 3/2/11 3/2/01 3/2/11 1,342,000 19
20
1465460000 79,348,955 21
22
23
24
25
26
27
04/26/00 2/1/25 19,885,000 28
02/10/92 6,381,81 29
26,266,818 30
31
32
1,491,726,818 79,348,955 33
FERC FORM NO. I (ED. 12-96) Page 257.1
THIS PAGE INTENTIONALLY LEFT BLANK
Name of Respondent
Idaho Power Company
This Re ort Is:
Resubmission

Date of Report
Da,Yr)
Year/Period of Report
End of 201 11Q4
RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TAXES
1.Report the reconciliation of reported net income for the year with taxable income used in computing Federal income tax accruals and show
computation of such tax accruals. Include in the reconciliation, as far as practicable, the same detail as furnished on Schedule M-1 of the tax return for
the year. Submit a reconciliation even though there is no taxable income for the year. Indicate dearly the nature of each reconciling amount.
2.If the utility is a member of a group which files a consolidated Federal tax return, reconcile reported net income with taxable net inccme as if a
separate return were to be field, indicating, however, intercompany amounts to be eliminated in such a consolidated return. State names of group
member, tax assigned to each group member, and basis of allocation, assignment, or sharing of the consolidated tax among the group members.
3.A substitute page, designed to meet a particular need of a company, may be used as Long as the data is consistent and meets the requirements of
the above instructions. For electronic reporting purposes complete Line 27 and provide the substitute Page in the context of a footnote.
Line
No.
Particulars (Details)
(a)
Amount
(b)
1 Net income for the Year (Page 117) 164,749,627
2
3 A 4 Taxable Income Not Reported on Books
5 =77
9 IDeductions Recorded on Books Not Deducted for Return
14 Income Recorded on Books Not Included in Return
19 Deductions on Return Not Charged Against Book Income
27 Federal Tax Net Income 27,547,434
28 Show Computation of Tax:
29 Tenative Federal Tax © 35% 9,641,602
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
RIC FORM NO. I (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 04/13/2012 20111Q4
FOOTNOTE DATA
Line Na: 5 Column: b
4003-CONSTRUCTION ADV-252 $ 4005-AVOIDED COST INT CAP
4006-RETIREMENTS-RECORD TAX GAIN/LOSS
4010-EMISSION ALLOWANCE-254.409-411
401 3-CIAC AS TAXABLE INC IN ACCT 107
4018-LINDEN FEEDER DEPOSITS-253.206
4021-ENGINEERING FEES-IN ACCT 107-FED ONLY
4022-FERC CREDIT OFA-254.307
4024-GREEN TAG SALES
4501-ROYALTY INCOME BTL
4506-CIAC-MERIDIAN GOLD
4507-CIAC-MICRON-DRAM
(5,552,281)
18,471,438
4,000,000
1,141,995
3,748,724
0
115,387
(465,593)
2,006,420
0
(56,560)
Total $ 22,801,060
SchduIePg:261Line N9:10
Total Federal and State taxes deducted on books
5001-BAD DEBT EXPENSE
501 0-SFAS 11 2-POST-EMPLY BEN 182/253
501 4-OVERACCRUED VACATION-ACCT 242
5017-INJURIES & DAMAGES
5019-DIRECTORS FEES DEF
5022-CAPITALIZED OVERHEADS
5024-MEALS (50% NON-DEDUCTIBLE) CHRGD TO R.E.
5025-MILNER FALLING WATER - REV ACCRL
5027-AMORTIZATION OF ACCOUNT 114
5028-OREGON OPER PROPERTY TAX ADJ
5023-PENSION EXPENSE-Acct 228
5033-NONVEBA PEN&BEN-Acct 228
5035-PCA EXPENSE DEFERRAL
5043-AMERICAN FALLS - FALLING WATER CONTRACT-FT
5047-OTHER EMPLOYEE'S LT DEFERRED COMP-228
5052-AMORTIZATION OF ACCOUNT 181
5053-STOCK BASED COMPENSATION
5054-IPUC GRID WEST LOANS-ACCT 182
5055-OPUC GRID WEST LOANS-ACCT 182
5056-FERC GRID WEST EXP-ACCT 182
5057-INTERVENER FUNDING ORDERS-ACCT 182
5058-FIXED COST ADJUSTMENT (FCA)-ACCT 182
5059-PS & I COSTS-COAL & CHP PLANTS-WRITE OFF
5060-OREGON-PCAM (POWER COST ADJ MECHANISM)
5061-PENSION EXPENSE-OREGON
5062-LIDAR SURVEYS DEFFERAL-ACCT 182
5063-BENNETT MTN MAINT DEFERRAL
5501-SEC PLAN-NET INS COSTS
5503-128-EDC-UNRLZD GN/LS FRM RABBI TRUST
5504-NONDEDUCTIBLE POLITICAL EXP-426.4
5505-SEC PLAN-BENEFIT ACCR
5510-FINES & PENALTIES-OPERATING
5531-RATE CASE DISALLOWANCES-REVERSE AMORT
5532-DELIVERY ACCRUALS-253.550
$
(44,418,448)
(205,868)
(849,962)
176,500
42,684
26,758
(17,000,000)
600,000
(334,136)
(22,723)
(5,072)
5,487,134
(380,803)
30,679,760
219,181
(1,306,905)
313,103
645,487
186,435
14,191
83,796
(54,903)
(2,115,823)
(36,407)
1,220,784
1,758,706
(436,047)
(299,546)
(76,501)
(430,015)
875,858
3,200,861
430,042
(296,299)
(19,051)
IFERC FORM NO I (ED 12-87) Page 450.1 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Idaho Power Company (2)- A Resubmission 04/13/2012 2011/04
FOOTNOTE DATA
5537-BRIDGER SIERRA RESERVE-LEGAL FEES-Acct 228.4 0
5540UNREALIZED LOSS ON INVESTMENTS-Acct 124 0
Total $ (22,327,229)
page: 261 Line No.: 15 Column: b
7010-AFUDC HC RELICENSING-ACCT 229 $ (11,934,857)
7011-OATT REVENUE DEFICIENCY 0
7012-REVENUE SHARING ACCT 25-CURR (27,098,897)
7501-REVERSE EQUITY EARNINGS OF SUBSIDIARIES 5,967,745
7502-ALLOWANCE FOR OFUDC 25,484,072
7503-ALLOWANCE FOR BFUDC 13332 724
7504-RECLASS TAX EXEMPT INTEREST-FED ONLY 1,882
7509-SECURITY PLAN-INSURANCE PROCEEDS 945,984
7514-COLt-INSURANCE PROCEEDS 0
7518-IRS INTEREST INCOME 0
Total $ 6,698,653
Sched ge261 Line No 20 Column b
8001-VEBA-POST RET BNFTS-TRUST-ACCT 228 $ (4,875,119)
8009-DEPR FOR TAX GT OR LT BOOK 82,278,759
8016-VEBA-POST RET BNFTS-TRUST-MEDICARE PART D 803,950
8020-CONSERVATION PROGRAMS (10,607,175)
8025-MANUFACTURING DEDUCTION 2,698,170
8027-NEVADA OPERATING PROPERTY TAX ADJ (59,445)
8034-REMOVAL COSTS 6,412,380
8038-OREGON EXCESS PWR SUPPLY COSTS (2229258)
8039-ST TAX-NOT DEDUCTED ON PRIOR RETURN 28,337
8041-AM FALLS - UNAMORTIZED DEBT EXP (47,999)
8042-GAIN/LOSS ON REACQUIRED DEBT-FT (911,000)
8057-REORGANIZATION COSTS (230,656)
8059-SFTWR COSTS-MISC-107-FED ONLY 0
8072-INTANGIBLE ASSET-LABOR DEDUCT-107-FED ONLY 1,369,000
8073-REPAIRS DEDUCTION 40000 000
8077-PP INS & OTR EXP (1 YR OR LESS)-165 1,659,465
8079-CUSTOM EFFICIENCY INCENTIVE PAY 7,096,442
8501-COLt-TAX ADJ FROM BOOKS 158,095
8504-OREGON NONOP PROPERTY TAX ADJUST (6)
8703-IPCO - 162 (M) $lm THRESHOLD 0
IRS INTEREST EXPENSE 238,097
STATE INCOME TAX DEDUCTED ON FEDERAL RETURN 7195 334
Total $ 130,977,371
IFERC FORM NO I (ED 12-87) Page 4502 1
Name of Respondent
Idaho Power Company
This Re ort Is:
2nRssiOn
Date of Report
04/13/2012
Year/Period of Report
End of 201 1/Q4
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
1.Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during
the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the
actual, or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2.Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.)
Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes.
3.Include in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other
than accrued and prepaid tax accounts.
4.List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
Line
No.
-
Kind of Tax
(See instruction 5)
(a)
BALANCE AT BEGINNING OF YEAR ch axes ed
Qpnn Year (d)
Ies
Dting Year (e)
Adjust-
ments
(f)
Taxes Accrued (Account 236)
(b)
Prepaid Taxes (include in Account 165)
(C)
I Federal:
2 Income -21,084,488 7,113,757 -9,913,638
3 Social Security - (FOAB) 927 12,928,542 12,928,282
4 Unemployment 120,729 120,729
5 Subtotal Federal -21,083,561 20,163,028 3,135,373
6
7 State of Idaho:
8 Property 6,798,477 18,797,490 17,179,867
9 Non-Operating 11,656 21,567 22,309
101 Income 1,057,025 7,045,405 8,766,534
11 KWH 97,149 2,756,722 2,673,193
12 Unemployment i 656,570 656,568
13 Regulatory Commission 2,089,245 2,089,245
14 Business License - Sho Ban 150 150
15 Subtotal Idaho 7,964,306 31,367,149 31,387,866
16
17 State of Oregon
18 Property 1,177,346 2,361,153 2,366,225
19 Non-Operating Property 838 1,672 1,667
20 Income -52,574 55,453 113,672
21 Regulatory Commission 148,358 148,358
22 Unemployment 44,926 44,926
23 Franchise 178,317 703,382 713,729
24 Subtotal Oregon 125,743 1,178,184 3,314,944 3,388,577
25
26 State of Montana:
27 Property 105,137 271,151 240,805
28 Subtotal Montana 105,137 271,151 240,805
29
30 State of Nevada:
31 Property 568,203 1,088,598 1,029,152
32 Subtotal Nevada 568,203 1,088,598 1,029,152
33
341 State of Wyoming
35 Corporate License 4,513 4,513
36 Property 635,567 1,527,445 1,399,289
37 Subtotal Wyoming 635,567 1,531,958 1,403,802
38 Other States Income 9,936 41,969 247
39 Payroll Adjustment -13,750,768
40
41 TOTAL -12,242,872 1,746,387 44,028,029 40,585,822
FERC FORM NO. I (ED. 12-96) Page 262
Name of Respondent
Idaho Power Company
This Re ort Is: 2"R,'ssion
Date of Report
04/13/2012
Year/Period of Report
End of 201 1 /Q4
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued)
5.If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year,
identifying the year in column (a).
6.Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments
by parentheses.
7.Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending
transmittal of such taxes to the taxing authority.
8.Report in columns (i) through (I) how the taxes were distributed. Report in column (I) only the amounts charged to Accounts 408.1 and 409.1
pertaining to electric operations. Report in column (I) the amounts charged to Accounts 408.1 and 109.1 pertaining to other utility departments and
amounts charged to Accounts 408.2 and 409.2. Also shown in column (I) the taxes charged to utility plant or other balance sheet accounts.
9.For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Line
(Taxes accrued
Accoqn 236)
I Prepaid Taxes
(Incl. in Account 165)
(h)
Electric (Account 408.1, 409.1)
(I)
Extraordinary Items
(Account 409.3)
(I)
Adjustments to Ret.
Earnings (Account 439)
(k)
Other
(I)
No.
-4,057,093 8,470,295 2
1,188 12,928,542 3
120,729 4
-4,055,905 21,519,566 -1,356,538 5
8,416,100 18,017,423
JiijN61
10914
-664,104 7,293,032
180,678 2,756,722
1 656,570 12
2,089,245 13
150 14
7,943,589 30,813,142 554,007 15
16
1 17
1,182,418 2,287,728 18
834 - 19
-110,793 68,371 20
148,358 I 1 21
44,926 22
167,970 703,382 23
57,177 1183 252 3,252,765 62 179 24
25
26
135483 271,151 27
135,483 271,151 28
29
30
508,757 1,088,598 31
508,757 1,088,598 32
33
34
4,513 35
763,723 1,527,445 36
763,723 1,531,958 37
51,658 46,837 1 38
-13,750,768 39
40
4,895,7251 1,692,009 44,773,249 -745,220 41
FERC FORM NO. 1 (ED. 12-96) Page 263
THIS PAGE INTENTIONALLY LEFT BLANK
I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)_ A Resubmission 04/13/2012 2011/04
FOOTNOTE DATA
LcheduIePag262 Line No I 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 2011 this cross-check will not work as the
total of lines 14-16 on Page 114 is $ 74,436,114 additional expense than line 41 on 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 asociated
with FERC account 236 or 165. Therefore FIN 48 will show up in the amount on Page 114 but
will not show up on Pages 262 & 263.
Account 409.2 $ (638,707)
234.2 (717,831)
Total $ (1,356,538)
ISChedule Page 262 Line No 8 Column: I
Account 107 $ 780,067
idule Page 262 Line No 9 Column I
Account 409.2 $ 21,567
Ocheddle Page: 262 Line No.: 10 Column: I
Account 409.2 $ (104,386)
234 (143,241)
Total $ (247,627)
ISCheddle Page_262Line No18Column_I
Account 107 $ 73,425
Schedule Page 262 Line No 19 Column I
Account 409.2 $ 1,672
,Schedule Page 262 Line No.: 20 Column I
Account 409.2 $ (5,634)
234 (7,284)
Total $ (12,918)
Schedule Page 262 Line No 38 Column I
Account 409.2 $ (2,440)
234 (2,428)
Total $ (4,868)
IFERC FORM NO 1 (ED 12-87) Page 4501
Name of Respondent This Report Is:
Idaho Power Company (2) R A Resubmission
Date of Report
04/13/2012
Year/Period of Report
End of 2011/Q4
ACCUMULA ED DEFERRED INVESTMENT TAX REDITS (Account 255)
Report below information applicable to Account 255. Where appropriate, segregate the balances and transactions by utility and
nonutility operations. Explain by footnote any correction adjustments to the account balance shown in column (g).lnclude in column (i)
the average period over which the tax credits are amortized.
i]iie
0.
-
Account
Subdivisions ?a)
Balance at Beginning of Year Deferred for Year Allocations to Current Year's Income Adjustments
(g) 1 Account No. (c) Amount (d) Account No. (e) Amount (f)
1
23%
Electric Utility
736,844 71,532
47%
510% 25,512,684 1,557,54
6 1,266,978 26,723.
7 Other - State 44,455,829 411.4 2,222,830 411.4 1,698,96
=8
9
10Line6ColA11
TOTAL
Other (List separately
and show 3%, 4%,
10% and TOTAL)
%
71 972,3351
I I
2,222,8301 3,354,76
11
12 State of Idaho 44,455,830 411.4 2,222,830 411.4 1,698,96
13
14
15
16
18
19
2(
21
22
23
24
2f
26
27
28
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
4
4
FERC FORM NO. I (ED. 12-89) Page 266
Name of Respondent
Idaho Power Company
This Report Is:
[;
2nR ssion
Date of Report
04/13/2012
Year/Period of Report
End of 2011/Q4
ACCUMULATED D FERRED INVESTMENT TAX CREDI FS (Account 255) (continued)
Balance at End Of Year
Avera Period
to Income
of Al cation ADJUSTMENT EXPLANATION Line
2
665,312 10.30 3
4
23,955,140 16.38 5
1,240,255 47.41 6
44979694 2617 7
70,840,4011
9
-
11
44,979,695 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
Name of Respondent
Idaho Power Company
This Report Is:
(2) [:p A Resubmission
Date of Report
04/13/2012
Yea Period of Report
End of 2011/Q4
OTHER DEFFE RED CREDITS (Account 253)
1.Report below the particulars (details) called for concerning other deferred credits.
2.For any deferred credit being amortized, show the period of amortization.
3.Minor items (5% of the Balance End of Year for Account 253 or amounts less than $100,000, whichever is greater) may be grouped by classes.
Line
No.
-
Description and Other
Deferred Credits
(a)
Balance at
Beginning of Year
(b)
DEBITS
Credits
(e)
Balance at
End of Year
(f)
Contra
Account
(c)

Amount
(d)
1 Smart Grid (253200) 10,038,255 107/401 170,178,139 172,904,103 12,764,219
2
3 Point to Point Trans Study(253201) 793,286 232 185,996 268,863 876,153
4
5 FTV (253202) 4,466,666 400 400,000 4,066,666
6 (Amort Period Mar 1998-Feb 2023)
7
8 Sho Ban Trans ROW (253480) 262,500 242 15,000 247,500
9 (Amort Period Jan 2005-Dec 2027)
10
11 Milner Falling Water (253953) 1,432,559 186/401 1,063,636 729,498 1,098,421
12 Amort Period (Feb 1992 - Feb 2017)
13
14 Postretirement Benefits (253960) 3,848,669 401 849,962 2998,707
15
16 Directors Deferred Compensation 4,611,550 131 571,167 597,925 4,638,308
17 (253980-253999)
18
19 IBM Mainframe Software Licenses 1,121,312 232 386,459 734,853
20 (Amort period 2010-2015) (253950)
21
22 USAF Battery Replacement (253906) 74,384 31,322 105,706
23
19,088 107/401 49,977 30,928 39
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47 TOTAL 26,668,269 173,700,336 174,562,639 27,530,572
FERC FORM NO. I (ED. 12-94) Page 269
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Idaho Power Company (2)- A Resubmission 04/13/2012 2011/Q4
FOOTNOTE DATA
çheduleIge:269LineNo:24Column: a 1
Accounts included in minor items:
253042
253550
IFERC FORM NO 1 (ED 12-87) Page 4501 I
Name of Respondent
Idaho Power Company
This Report Is:
(1)I]An Original
(2)pA Resubmission
Date of Report
(Mo, Da, Yr)
0411312012 1
Year/Period of Report
n of 201 1/04
ACCUMULATED DEFFERED INCOME TAXES - OTHER PROPERTY (Account 282)
1.Report the information called for below concerning the respondent's accounting for deferred income taxes rating to property not
subject to accelerated amortization
2.For other (Specify),include deferrals relating to other income and deductions.
-
Line
No.
Account
(a)
Balance at
Beginning of Year
(b)
CHANGES DURING YEAR
Amounts Debited
to Account 4lO.1
(c)
Amounts Credited
to Account 4ll.1
(d)
1
2
Account 282
Electric ''84793+872 50711765 2,171,003
3 Gas
4 Other
5 TOTAL (Enter Total of lines 2 thru 4) 284,793,872 50,711,765 2,171,003
6 Non-Operating Property
7 Other - Regulatory Asset for I 422,215,476
8
9
10
TOTAL Account 282 (Enter Total of lines 5 thru
Classification of TOTAL
Federal Income Tax
707,009,348
601,940,143
50,711,765
50,211,165
2,171,003
2,171,003 11
12 State Income Tax 105,069,205 500,601
13 Local Income Tax
NOTES
FERC FORM NO. I (ED. 12-96) Page 274
I
Name of Respondent
Idaho Power Company
This Report Is:
(1)Original
(2)MA Resubmission
Date of Report
(Mo, Da, Yr)
04/13/2012
Year/Period of Report
End of 20111Q4
ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282) (Continued)
3. Use footnotes as required.
CHANGES DURING YEAR ADJUSTMENTS
Balance at
End of Year
(k)
333,334,634
-
Line
No.
2
Amounts Debited
to Account 410.2
(e)
Amounts Credited
to Account 411.2
(1)
Debits Credits
Account Credited Amount
(h)
Account
Debited
Amount
U)
3
4
333,334,63 5
6
182 -159,138,021 182 18,638,08E 599,991,59( 7
8
-159,138,021
-133,493,583
18,638,08E
12,489,76E
933,326,22
795,963,65
9
10
11
-25,644,441 6,148,31S 137,362,57( 12
13
NOTES (Continued)
FERC FORM NO. I (ED. 12-96) Page 275
THIS PAGE INTENTIONALLY LEFT BLANK
2011 Changes during Year AdjDr Adj 2011
Credits
Beginning DR to CR to DR CR Acct Acct Ending
Account Balance 410.1 411.1 410.2 411.2 cr Amt dr Amt Balance
(a) b c d e f g h i j k
Accelerated Depreciation 271,486,739.45 49,981,168.35 0.00 321,467,907.80
Intangible Asset-Labor 13,260,622.55 556,722.60 13,817,345.15
Deduction
Valmy Capitalized Items 427,766.00 76,500.00 351,266.00
Engineering Fees in Acct 107 (141,663.20) 8552.25 40,385.45 c,I
Misc Software Develop Costs 83,927.20 (66,271.80) 17,655.40
Taxable CIAC in CWIP Bat (323,520.40) 231 59395 2,054,117.45 (2 146 043 90)
TOTAL 284,793,871.60 50,711,765.35 2,171,002.90 0 1 0 - 0 - 0 333,334,634.05
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 04/13/2012
FOOTNOTE DATA
Schedule Page: 274 Line No.: 2 Column: b
Name of Respondent This Report Is: Date of Report Year/Period of Report
Idaho Power Company End of 2011/Q4
(2) AResubmission
ACCUMULATED DEFFERED INCOME TAXES - OTHER (Account 283)
1.Report the information called for below concerning the respondent's accounting for deferred income taxes relating to amounts
recorded in Account 283.
2.For other (Specify),include deferrals relating to other income and deductions.
CHANGES DURING YEAR
Line Account Balance at
Beginning of Year Amounts Debited Amounts Credited
to Accot 410.1 to Accojt 411.1 (a)
I Account 283
2 Electric
3 Other Electric - See Note 5,656,flS 53 826 2971 46,760,251
5
6
7
18 Other - See Note
9 TOTAL Electric (Total of lines 3 thru 8) 99,361,675 53,826,297 46,760,251
10 Gas
11
12
13
14
15
16
17 TOTAL Gas (Total of lines 11 thru 16)
18 Other - See Note 2c548
19 TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18) 99.627.160 53,826,297 46,760,251
20 Classification of TOTAL
21 Federal Income Tax 83,572,690 45,152,408 39,225,027
22 State Income Tax 16,054,470 8,673,888 7,535,224
23 Local Income Tax
NOTES
FERC FORM NO I (ED 1296) Page 276
Name of Respondent
Idaho Power company
This Report Is:
(1)An Original
(2)DA Resubmission
Date of Report
(Mo, Da, Yr)
04/13/2012
Year/Period of Report
End of 2011/Q4
ACCUMULATED DEFERRED INCOME TAXES - OTHER (Account 283) (Continued)
3.Provide in the space below explanations for Page 276 and 277. Include amounts relating to insignificant items listed under Other.
4.Use footnotes as required.
CHANGES DI IRING YEAR ADJUSTMENTS
Balance at
End of Year
(k)
NF2
32,722,054
-
Line
No-
3
Amounts Debited
to Account 410.2
Amounts Credited
to Account 4112
Debits Credits
Account
Credited (e)
Amount
(h)
Account Debited Amount
4
5
6
7
30569445 104,275,1121 8
30,569,445 136,997,166 9
10
11
12
13
14
15
16
17
212,793 36,749 441,5291 18
212 793
178,503
36741
30,827
30,569,4451
25,643,297
137,438,695
115,291,044
19
20
21
34,291 5,922 4,926,147 22,147,650 22
23
NOTES (continued)
F FERC FORM NO. I (ED 1296) Page 277
THIS PAGE INTENTIONALLY LEFr BLANK
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)_ A Resubmission 04/13/2012 201 1/04
FOOTNOTE DATA
2011 Changes during Year Adj Debits Adj 2011
Credits
Beginning DR to CR to DR to CR to Acct Acct Ending
Account Balance 410.1 411.1 410.2 411.2 cr Amt dr Amt Balance
(a) b c d e f g h i j k
PCA Expense Deferral 7,056,724.48 5,694,011.99 17,880,218.67 (5,129,482.20)
Conservation Programs 7,610,472.36 5,178,152.68 6,550,673.77 6,237,951.27
Oregon Excess Power Costs 2,556,836.05 828,970.77 1,700,499.18 1,685,307.64
Oregon PCAM 2,219,813.71 123,399.85 600,664.96 1,742,548.60
IPUC Grid West Loans 72,887.11 72,887.11 (0.00)
OATT Revenue Deficiency 807,104.17 0.00 0.00 807,104.17
Reorganization Costs 360,699.07 90,174.97 270,524.10
FERC Grid West Expense 76,440.49 32,760.44 43,680.05
OPUC Grid West Loans 23,116.10 0.00 5,547.97 17,568.13
Intervenor Funding Orders 47,339.76 21,464.33 0.79 68,803.30
Fixed Cost Adjustment 4,824,574.81 4456 672 84 3,629,491.45 5651 75620
PS & I Costs-Coal & CHP (0.02) 14,233.35 0.01 14,233.32
Plants-Write Off
Delivery accruals 0.00 33,341.78 39,163.41 (5,821.63)
Emission Allowance 0.00 142,974.34 47,832.35 95,141.99
Green Tag Sales 0.00 1,644,051.09 784,409.90 859,641.19
LIDAR Surveys Deferral 0.00 170,472.57 170,472.57
Bennett Mtn Maintenance 0.00 117,107.51 117,107.51
Deferral
Bonus Deferral 0.00 514.49 12,167.15 (11,652.66)
Pension 0.00 35,400,929.09 15,313,758,58 20,087,170.51
TOTAL 2565600809 1 53,826,296.681 46,760,250.711 0 1 0 1 - "0 - 0 32,722,054.06 1
Schedule Paae: 276 Line No.: 8 Column: b
Beginning DR to CR to DR CR to Ac Acct. Ending
to ct
Account Balance 410.1 411.1 410. 4112 cr Amt dr Amt Balance
2
(a) b c d e f g i j k
Pension 64,358,799.67 - - 190 32,192,857.08 96551 656 75
Postretirement Plan 7,440,460.06 190 (1,366,591.53) 6,073,868.53
Unrealized gains on Mkt Securities 1,906,407.25 219 (256,821.00) 1,649,586.25
TOTAL 7370566698 1 0 1 0 0 1 01 =1 0 3056944455 10427511153
Paae: 276 Line No.: 18 Column: b
2011 Changes during Year Adj Adj 2011
Debits Credits
Beginning DR to CR DR to CR to Acc Acc Ending
to t t.
Account Balance 410.1 411. 410.2 411.2 cr Amt dr A Balance
1 mt
(a) b c d e f ghij k
Advance Coal Royalties 293,553.80 7,931.99 0.00 301,485.79
Oregon Non-Op Prop Tax Adj 327.64 327.61 329.59 325.66
Unrealized Gain/Loss From Rabbit Trust (28,396.63) 1 1 204,533.72 36,419.34 - - - 139,717.75
TOTAL 26548481 O 0 21279332 36 74893 i 0 441 52920
Schedule Page: 276Line No.:3 Column: b
Name of Respondent
Idaho Power Company
This Report Is:
E]An 0n
(2) E]A Resubmission
Date of Report
(Mo, Da, Yr)
04/13/2012
Yea Period of Report
End of 2011/Q4
OTHER REGULATORY LIABILITIES (Account 254)
1.Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if
applicable.
2.Minor items (5% of the Balance in Account 254 at end of 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.
Line
No.
Description and Purpose of
Other Regulatory Liabilities
(a)
Balance at Begining
of Current
Quarter/Year
(b)
DEBITS
Credits
(e)
Balance at End
Quarter/Year
(f)
Account
(c)
Amount
(d)
I Market to Market Short Term -(254001) 573,226 175 5235,834 8,057,573 3,394,965
2 IPIJC Order #28661
3
4 FAS 133- Market to Market -(254203) 175 1,028,788 1,388,206 359,418
5 IPUC Order# 28661
6
71 Emission Sales (254412) 371,211 Various 375,357 9,894 5,748
8 IEEP- Order #30529
9
10 Unfunded Accum Def Income Tax (254966) 46199.138 Various 4,899,414 4,163,823 45,472,547
11
12 FERC Credit for OFA - IPUC Order #30754 465,593 401 465,593
13 (Amort period 09/06 - 09/11) (254307)
14
15 Oregon Solar Pilot -(254005) 197,625 Various 177,834 746,305 766,096
16 Advice #10-11
17
18 Oregon Reclass (254204) 1823 17,123,830 21,234,150 4,110,320
19 Advice #05-03
20
21 Green Tags Oregon (254415) 195,265 Various 251,458 335,798 279,605
22
231 Power Cost Adjustment Current (254423) 1823 36,757,136 47,336,082 10,578,946
24
25 Regulatory Unfunded Accum Def Income Tax (254419) 7,241,146 1823 8,290,308 4,829,750 3,780,588
26
27 Revenue Sharing (254101) Various 27,098,897 27,098,897
28 IPUC Order #30978
29
30 BPA Credit Residential Idaho (254401) 13,880 Various 111 397,788 411,557
31 Advice # 11-03
32
33 WAQC Carryover (254901) Various 1 1,323 160,632 159,309
34 IPUC Order #29505
35
3€ _ 22,818 Various 118,237,871 118,280,302 65,249
37
38
39
40
41 TOTAL 55,279,902 192,835,857 234,039,200 96,483,245
FERC FORM NO 113-Q (REV 02-04) Page 278
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Idaho Power Company (2)- A Resubmission 04/13/2012 2011/04
FOOTNOTE DATA
$chedule Page 278 Line No 36 Column a
Accounts included in minor items:
254004
254006
254201
254202
254402
254403
254404
254409
254410
254411
254413
254416
IFERC FORM NO 1 (ED 12-87) Page 4501
Name of Respondent
Idaho Power Company
This Report Is:
AResubmrssion
Date of Report
04/13/2012
Year/Period of Report
End of 201 1 /Q4
ELECTRIC OPERATING REVENUES (Account 400)
1.The following instructions generally apply to the annual version of these pages. Do not report quarterly data in columns (c), (e), (f), and (g). Unbilled revenues and MWH
related to unbilled revenues need not be reported separately as required in the annual version of these pages.
2.Report below operating revenues for each prescribed account, and manufactured gas revenues in total.
3.Report number of customers, columns (f) and (g), on the basis of meters, in addition to the number of flat rate accounts; except that where separate meter readings are added
for billing purposes, one customer should be counted for each group of meters added. The -average number of customers means the average of twelve figures at the close of
each month.
4.If increases or decreases from previous period (columns (c),(e), and (g)), are not derived from previously reported figures, explain any inconsistencies in a footnote.
5.Disclose amounts of $250,000 or greater in a footnote for accounts 451, 456, and 457.2.
Line
No.
Title of Account
(a)
Operating Revenues Year
to Date Quarterly/Annual
(b)
Operating Revenues -
Previous year (no Quarterly)
(c)
1 Sales of Electricity
2 (440) Residential Sales 45.981,556 400,606,630
3 (442) Commercial and Industrial Sales
4 Small (or Comm.) (See lnstr. 4) 322,307,065 338,716361
5 Large (or Ind.) (See lnstr. 4) 140,701,371 138,394,166
6 (444) Public Street and Highway Lighting 3,289,385 3,278,628
7 (445) Other Sales to Public Authorities
8 (446) Sales to Railroads and Railways
9 (448) Interdepartmental Sales
10 TOTAL Sales to Ultimate Consumers 872,279,377 880,995,785
11 (447) Sales for Resale 101,602,140 78,133,502
12 TOTAL Sales of Electricity 973,881,517 959,129,287
13 (Less) (449.1) Provision for Rate Refunds 37,734,709 10,667,522
14 TOTAL Revenues Net of Prov. for Refunds 936,146,8081 . 948,461,765
15 Other Operating Revenues
16 (450) Forfeited Discounts
17 (451) Miscellaneous Service Revenues 3,564,200 3,532,831
18 (453) Sales of Water and Water Power
19 (454) Rent from Electric Property 24,256,300 21,141,127
20 (455) Interdepartmental Rents
21 (456) Other Electric Revenues 38,244,930 44,517,995
22 (456.1) Revenues from Transmission of Electricity of Others 19,372,904 15,398,402
23 (457.1) Regional Control Service Revenues
24 (457.2) Miscellaneous Revenues
25
26 TOTAL Other Operating Revenues 85,438,334 84,590,355
27 TOTAL Electric Operating Revenues 1,021,585,142 1,033,052,120
FERC FORM NO. 1/3-Q(REV.12.05) Page 300
Name of Respondent This Report Is: Date of Report Year/Period of Report
Idaho Power Company An End of 2011/Q4
ssion 04/13/2012
ELECTRIC OPERATING REVENUES (Account 400)
6.Commercial and industrial Sales, Account 442, may be classified according to the basis of classification (Small or Commercial, and Large or Industrial) regularly used by the
respondent if such basis of classification is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of Accounts. Explain basis of classification
in a footnote.)
7.See pages 108-109, Important Changes During Period, for important new territory added and important rate increase or decreases.
8.For Lines 2,4,5,arrd 6, see Page 304 for amounts relating to unbilled revenue by accounts.
9.Include unmetered sales. Provide details of such Sales in a footnote.
MEGAWATT HOURS SOLD AVG.NO. CUSTOMERS PER MONTH Line
Year to Date Quartedy/Annual Amount Previous year (no Quarterly) Current Year (no Quarterly) I Previous Year (no Quarterly) No.
(d) (e) (f) (g) -
5,146.013 4.967.379 . 409,786 407,551 2
—I - -
5,458,954 5,439,730 82,045 81,571 4
3,099,743 3,075,379 123 124 5
291720 30,016 1,578 1,459 6
7
8
9
13,734,430 13,512,504 493,532 490,705 10
3,634,924 1,981,936 11
17,369,354 15,494,440 493,532 490,705 12
13
17,369,354 15,494,440 493,532 490,705 14
Line 12, column (b) includes $ 640,470 of unbilled revenues.
Line 12, column (d) includes 38,351 MWH relating to unbilled revenues
FERC FORM NO. 113-Q (REV. 12-05) Page 301
Name of Respondent
Idaho Power Company
This Re oil Is: 2"Rss ion
Date of Report
04/13/2012
Year/Period of Report
End of 201 1/Q4
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 account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3.Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4.The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12
if all billings are made monthly).
5.For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6.Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line
No.
Number and I we of Pate schedule
(a)
MVVh Said
(b)
revenue
(c)
Average Number
of Cimers
ISWh ot Sales
Per ?i.stomer
Fev1ue rer icvvfl Sold
1 440 - Residential Sales:
2 01 - Residential 5,113,748 402,275,493 409,683 12,482 0.0787
3 03 - Residential Master Meter 4,962 371,277 22 225,545 0.0748
4 04- Residential -EW 528 41,192 31 17,032 0.0780
5 05- Residential - TOD 912 71,020 50 18,240 0.0779
6 15- Dusk to dawn lighting 2,859 537,868 0.1881
7 Unbilled Revenues 22,994 827,035 0.0360
8 Other Revenues 1,862,085
9 Total 440 I 409,786 12,558 0.0789
10
11 442-Commercial & Industrial Sales
12 07- General service 162,322 16,053,391 30,972 5,241 0.0989
13 09- General service 431,095 20,549,318 187 2,305,321 0.0477
14109 - General service 3,156,665 178,829,445 31,007 101,805 0.0567
151 09- General service 5,506 294,295 3 1,835,333 0.0534
11 15 - Dusk to Dawn Light 4,103 698,315 0.1702
17 19- Uniform rate contracts 2,103,035 89,329,869 115 18,287,261 0.0425
18 19 Uniform rate contracts 6,679 315,835 1 6,679,000 0 0473
ic 19- Uniform rate contracts 119,113 5,280,572 4 29,778,250 0.0443
20 24- Irrigation Pumping 1,673,408 104,613,138 18,702 89,477 0.0625
21 40- General service 12,997 877,108 1,174 11,071 0.0675
22 Commercial & Industrial & Unbill 883,78 45,989,630 4 220,946,000 0.0520
23 Other Revenues 173,101
24
25
Total 442 82,169 104,160 0.0541
26 444 - Public Street Lighting:
27 40 -General service 2,824 190,905 839 3,366 0.0676
28 41 - Street lighting 23,946 2,962,492 355 67,454 0.1237
42-Traffic control lighting 2,998 141,953 384 7,807 0.0473
30 Other Revenues -48 -5,965 0.1243
31 Total 444 29,720 3,289,385 1,578 18,834 0.1107
32
33
a
35
36
37
38
31
40
1 TOTAL Billed 13,696,079 871 ,638,906 493,53 27,75 0.0636
42 Total Unbilled Rev (See lnstr. 6) 38,3511 640,471 I 0 016
431 TOTAL 13 ,734,43q 872,279,377 493,531 27,82 0.0631
FERC FORM NO I (ED 1295) Page 304
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)_ A Resubmission 04/13/2012 201 1/Q4
FOOTNOTE DATA
Schedule Page: 304 Line No.: 9 Column:b
This amount is different from page 301 column D line 2 in the amount of 10 NWh due to an
error during the year where a rate 09S was recorded to the residential account. Page 301
is broken down by FERC account and page 304 is by rate schedule.

Schedule Page: 304 Line No.: 9 Column: c 1 This amount is different from page 301 column B line 2 in the amount of 4,414 due to an
error during the year where a rate 09S was recorded to the residential account. Page 301
is broken down by FERC account and page 304 is by rate schedule
çpedule Page: 304 Line No.: 24 Column: b
This amount is different from page 301 column D total of lines 4 and 5 in the amount of 10
MWh due to an error during the year where a rate 09S was recorded to the residential
account. Page 301 is broken down by FERC account and page 304 is by rate schedule.

çedule Page 304 Line No 24 Column c 1 This amount is different from page 301 column B total of lines 4 and 5 in the amount of
4,414 due to an error during the year where a rate 09S was recorded to the residential
account Page 301 is broken down by FERC account and page 304 is by rate schedule
IFERC FORM NO I (ED 12-87) Page 4501 I
Name of Respondent This Report Is: Date of Report Year/Period of Report
Idaho Power Company (1)An Original R
(Mo, Da, Yr) End of 2011104 (2)A Resubmission 04/13/2012
SALES FOR RESALE (Account 447)
1.Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity (i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2.Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purctiaser.
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 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 suppliers service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and ;s intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
lU - 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 Average Actual Demand (MW)
No. (Footnote Affiliations) Classifi-
cation
Schedule or Tariff Number
Monthly Bulling
Demand (MW) Averaae Monthly NC P Deman Averaae Monthly CP1)emand
- (a) (b) (c) (d) (e) (f)
1 Raft River Rural Electric V6-44 8.436 8.436 7.176
2 Raft River Rural Electric V6-44 n/a n/a n/a
3
4 Arizona Public Service Co SF WSPP n/a n/a n/a
5 Arizona Public Service Co WSPP n/a n/a n/a
6 Avista Corp. SF WSPP n/a n/a n/a
7 Avista Corp WSPP n/a n/a n/a
8 Barclays Bank PLC SF J Wpp n/a n/a n/a
9 Barclays Bank PLC - n/a n/a n/a
10 Black Hills Power Inc WSPP n/a n/a n/a
11 Black Hills Power Inc )Q'.IJ WSPP n/a n/a n/a
12 Black Hills Power Inc. SF WSPP n/a n/a n/a
13 Bonneville Power Administration SF WSPP n/a n/a n/a
14 BP Energy Company SF WSPP n/a n/a n/a
- SubtotalRQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO I (ED 12-90) Page 310
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Idaho Power Company (1)X An Original (Mo, Da, Yr) End of 20111Q4
(2)D A Resubmission 04/13/2012
SALES FOR RESALE (Account 447) (Continued)
OS - for other service, use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining safes may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5.In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6.For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7.Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8.Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (jj. 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.
MegaWatt Hours REVENUE Total ($) Line
Demand Charges Energy Charges Other Charges Sold (h+i+j) No.
(g) (h) (I) (j) (k) -
38,222 540,239 1,085,425 4 500 1,630,164 1
254,060 254,060 2
3
533,806 13,314,698 13,314,698 4
3,600 93,600 93,600 5
4,050 84,748 84,748 6
290 3,140 31407
30,000 1,502,700 1,502,700 8
94,553 94,553 9
2,295 229510
34,301 702.444 702,444 11
44,873 779,325 779,325 12
55,635 1,528,500 1,528,500 13
63,160 717,310 717,310 14
38,222 540,239 1,085,425 258,560 1,884,224
3,596,702 0 98,041,629 1,676,287 99,717,916 -
3,634,924 540,239 99,127,054 1,934,847 101,602,140
FERC FORM NO. 1 (ED. 12-90) Page 311
Name of Respondent Date of Report Year/Period of Report
Idaho Power Company
This RM
A
ort Is:
(1)An Original (Mo, Da, Yr) End of 201 11Q4
(2)Resubmission 04/13/2012
SALES FOR RESALE (Account 447)
1.Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity (i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2.Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
Average Monthly NCP Demand Averacle, Monthly CFDemand No. (Footnote Affiliations) Classifi-
cation
Schedule Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
1 Calpine Energy Services, L.P. SF WSPP n/a n/a n/a
2 Cargill Power Markets LLC n/a n/a n/a
3 Cargill Power Markets LLC WSPP n/a n/a n/a
4 Cargill Power Markets LLC WSPP n/a n/a n/a
5 Cargill Power Markets LLC F WSPP n/a n/a n/a
6 Citigroup Energy Inc. - F WSPP n/a n/a n/a
7 Citigroup Energy Inc wsPP n/a n/a n/a
8 Citigroup Energy Inc n/a n/a n/a
9 Clatskanie PUD SF WSPP n/a n/a n/a
10 Constellation Energy Commodities Group, SF WSPP n/a n/a n/a
11 DB Energy Trading LLC SF WSPP n/a n/a n/a
12 EDF Trading North America, LLC SF WSPP n/a n/a n/a
13 Eugene Electric Board SF WSPP n/a n/a n/a
14 Exelon Generation Company, LLC SF WSPP n/a n/a n/a
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO I (ED 12-90) Page 310.1
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Idaho Power Company (1)X An Original (Mo, Da, Yr) End of 2011/04 (2)El Resubmission 04/13/2012
SALES FOR RESALE (Account 447) (Continued)
OS - for other service, use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5.In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6.For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (1). Monthly NCP demand is the maximum
metered hourly (60--minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7.Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8.Report demand charges in column (h), energy charges in column (I), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9.The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10.Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($) Line
Demand Charges Energy Charges Other Charges Sold (h+i+j) No.
(g) (h) (i) 0) (k) -
10 378 378 I
14,492 1449.2
695,944 695,944 3
951 23,623 236234
386,461 11,442,864 114428645
560,092 13,799,257 13,799,257 6
6,244 167,095 167,095 7
341,599 341,599 8
16,800 463,000 463,000 9
44,800 1,155,785 1,155,781' 10
42,750 1,091,669 1 091 669 11
85,400 2,461,720 2,461,720 12
13,710 248,556 248556 13
800 26,400 26,400 14
38,222 540,239 1,085,425 258 560 1,884,224
3,596,702 0 98,041,629 1,676,287 99,717,916
3,634,924 540,239 99,127,054 1,934,847 101,602,140 -
FERC FORM NO. I (ED. 12-90) Page 311.1
Name of Respondent Year/Period of Report
Idaho Power Company
This Rn
A
ort Is: Date of Report (1 ) An Original (Mo, Da, Yr) End Oi 2011/Q4 .(2) Resubmussion 04/13/2012
SALES FOR RESALE (Account 447)
1.Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity (i.e., transactions involving a balancing of debits and credits
for energy, capacity. etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2.Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
Averaae Monthly NCI5 Demand Avera e Monthly CPM)emand No. (Footnote Affiliations) Classifi-
cation Schedule or Tariff Number
Monthly Billing
Demand (MW)
(a) (b) (c) (d) (e) (f)
1 Grant CO Public Utility District #2— SF WSPP n/a n/a n/a
2 IBERDROLA RENEWABLES Inc WSPP n/a n/a n/a
3 IBERDROLA RENEWABLES, Inc. SF J WSPP n/a n/a n/a
4 IBERDROLA RENEWABLES Inc._ WSPP n/a n/a n/a
5 IBERDROLA RENEWABLES Inc n/a n/a n/a
6 J.P.MorganVenturesEnergyCorporation -
SF WSPP
n/a n/a n/a
7 J.P.MorganVenturesEnergy Corporation n/a nla n/a
8 Jeffries Sadie - n/a n/a n/a
9 Macquarie Energy LLC WSPP n/a n/a n/a
10 MacquarieEnergyLLC SF J _WSPP n/a n/a n/a
11 MorganStanley Capital Group Inc. n/a n/a na
12 Morgan Stanley Capital Group Inc. n/a n/a n/a
13 MorganStanleyCapitalGroupInc. SF V6-62 n/a n/a n/a
14 MorganStanleyCapitalGroupInc. WSPP n/a n/a n/a
Subtotal RQ 0 0 0
Subtotal non-RQ 0 o o
Total 0 0 0
FERC FORM NO. 1 (ED. 12-90) Page 310.2
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Idaho Power Company (1)X An Original (Mo, Da, Yr) d f 201 1/Q4 n 0
(2)EA Resubmission 04/13/2012
SALES FOR RESALE (Account 447) (Continued)
OS - for other service, use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5.In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6.For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7.Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8.Report demand charges in column (h), energy charges in column (I), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9.The data in column (g) through (k) must be subtotaled based on the RQINon-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
Demand Charges Energy Charges Other Charges Sold (h+i+j) No.
(g) (h) 0) 0) (k) -
5,600 151,320 151,320 1
9407 94072
127,040 3,325,760 3 325 760 3
341 7,408 7,408 4
68,748 68,748 5
765,968 765,968 6
10,422 325,674 325,674 7
6,807,639 6807639 8
524,508 524,508 9
169,183 5,696,223 5,696,223 10
138,330 138,330 11
10,732 10,732 12
225,125 4,786,783 4,786,783 13
111,981 111,981 14
38,222 540,239 1,085,425 258,560 1,884,224
3,596,702 0 98,041,629 1,676,287 99,717,916 -
3,634,924 540,239 99,127,054 1,934,847 101,602,140
FERC FORM NO. I (ED. 12-90) Page 311.2
Name of Respondent This Rort Is: Date of Report Year/Period of Report
Idaho Power Company
(1)MA
An Original (Mo, Da Yr)
04/13/2612 nu Ou 2011/Q4
(2)Resubmission
SALES FOR RESALE (Account 447)
1.Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity (i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2.Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
Averadie
Monthly NCR Demand Averaae Monthly CP1)emand No. (Footnote Affiliations) Classifi-
cation
Schedule or Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
1 NorthWestern Energy DS - WSPP n/a n/a n/a
2 PaciflCorp Inc. S WSPP n/a n/a n/a
3 PaciflCorp Inc WSPP n/a n/a n/a
4 PaciflCorp Inc T-7 n/a n/a n/a
5 Portland General Electric Company WSPP n/a n/a n/a
6 Portland General Electric Company .. WSPP n/a n/a n/a
7 Portland General Electric Company SF WSPP n/a n/a n/a
8 Powerex Corp OS WSPP n/a n/a n/a
9 Powerex Corp - WSPP n/a n/a n/a
10 Powerex Corp. SF WSPP n/a n/a n/a
11 PPL EnergyPlus LLC OS WSPP n/a n/a n/a
12 PPL EnergyPlus LLC OS WSPP n/a n/a n/a
13 PPL EnergyPlus, LLC SF WSPP n/a n/a n/a
14 Puget Sound Energy, Inc. SF WSPP n/a n/a n/a
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO. I (ED. 12-90) Page 310.3
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Idaho Power Company (1)X An Original
(2)fl A Resubmission
(Mo, Da, Yr)
04/13/2012 flu 0 201 1/Q4
SALES FOR RESALE (Account 447) (Continued)
OS - for other service, use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD -for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting 1 years. Provide an explanation in a footnote for each adjustment.
4.Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5.In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6.For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7.Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8.Report demand charges in column (h), energy charges in column (I), and the total of any other types of charges, including
out-of-period adjustments, in column U). 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 RQINon-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
Demand Charges Energy Charges Other Charges Sold (h+i+j) No.
(g) (h) (I) U) (k) -
4,258 27,573 27,573 1
68,075 894,457 894,457 2
158 158 3
190 4,970 4,970 4
584 584 5
2,925 34,350 34,350 6
16,671 412,810 412,810 7
490,861 490,861 8
196,235 2,540,384 2,540,384 9
34,508 856,711 856,711 10
14,900 14,900 11
335 2,459 2,459 12
56,880 1,609,656 1,609,65e13
57,402 1,451,355 145135514
38,222 540,239 1,085,425 258,560 1,884,224
3,596,702 0 98,041,629 1,676,287 99,717,916 -
3,634,924 540,239 99,127,054 1,934,847 101,602,140
FERC FORM NO.1 (ED. 12-90) Page 311.3
Name of Respondent Report Is: Date of Report Year/Period of Report
Idaho Power Company
Lhi~
X An Original (Mo, Da, Yr) End of 2011/Q4
flA Resubmission 04/13/2012
SALES FOR RESALE (Account 447)
1.Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity (i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2.Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority F Statistical FERC Rate Average Actual Demand (MW)
Average Monthly NCP Demand Avera e Monthly CFDemafld No. (Footnote Affiliations) I Classill- I cation
Schedule or Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (C) (d) (e)' (f)
1 Puget Sound Energy Inc T-7 n/a n/a n/a
2 Puget Sound Energy, Inc. WSPP n/a
n/a
n/a
n/a
n/a
n/a 3 Rainbow Energy Marketing Corporation , WSPP
4 Rainbow Energy Marketing Corporation SF WSPP n/a n/a n/a
5 Royal Bank of Canada S n/a n/a n/a
6 Seattle City Light WSPP n/a n/a n/a
7 Seattle City Light SF WSPP n/a n/a n/a
8 Sempra Energy Trading LLC n/a n/a n/a
9 Sempra Energy Trading LLC WSPP n/a n/a n/a
10 Shell Energy North America (US) L P WSPP n/a n/a n/a
11 Shell Energy North America (US) L P WSPP n/a n/a n/a
12 Shell Energy North America (US) L P -. WSPP n/a n/a n/a
13 Shell Energy North America (US) L.P. WSPP n/a n/a n/a
14 Shell Energy North America (US), L.P. SF WSPP n/a n/a n/a
Subtotal RQ C 0 0
Subtotal non-RQ o 0 0
Total 0 0 0
ERcFoRMNo.1ED.12-90) page 310.4
I
Name of Respondent This Report Is: Date of Report Year/Period of Report
Idaho Power Company (1)X An Original (Mo, Da, Yr) End of 2011/Q4 (2)fl A Resubmission 04/13/2012
SALES FOR RESALE (Account 447) (Continued)
OS - for other service, use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5.In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6.For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system roaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7.Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8.Report demand charges in column (h), energy charges in column (I), and the total of any other types of charges, including
out-of-period adjustments, in column U). 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 RQINon-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
Demand Charges Energy Charges Other Charges Sold (h+i+j) No.
(g) (h) (i) (j) (k) -
3 88 88 1
15,915 228,295 228,295 2
126,369 126,369 3
132,200 3,796,180 3,796,180 4
142,696 142,696 5
1,100 13,675 136756
4,140 109,050 1090507
672,024 672,024 8
29 299
37,302 37,302 10
15,451 15,451 11
3,584 99,168 99,168 12
41,696 864,566 864,566 13
286,405 7,531,637 7,531,637 14
38,222 540,239 1,085,425 258 560 1,884,224
3,596,702 0 98,041,629 1,676,287 99,717,916
3,634,924 540,239 99,127,054 1,934,847 101,602,140
FERC FORM NO. I (ED. 12-90) Page 311.4
Name of Respondent This Re Ii Is: Date of Report Year/Period of Report
Idaho Power Company (1)X An Original (Mo, Da, ') E d f 201 1/Q4 End 0
(2)A Resubmission 04/13/2012
SALES FOR RESALE (Account 447)
1.Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity (i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2.Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
lU - 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 Average Actual Demand (MW)
Average
Monthly NCR Deman<
Averaae
I Monthly CPThmand No. (Footnote Affiliations) Classifi-
cation
Schedule or Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
1 Sierra Pacific Power Co dba NV Energy T-7 n/a n/a n/a
2 Sierra Pacific Power Co dba NV Energy WSPP n/a n/a n/a
3 Sierra Pacific Power Co., dba NV Energy SF J WSPP n/a n/a n/a
4 Sierra Pacific Power Co dba NV Energy WSpp n/a n/a n/a
5 Southern California Edison WSPP n/a n/a n/a
6 Snohomish County PUD SF J WSPP n/a n/a n/a
7 Tenaska Power Services Co WSPP n/a n/a n/a
8 Tenaska Power Services Co. SF WSPP n/a n/a n/a
9 Tenaska Power Services Co WSPP n/a n/a n/a
10 The Energy Authority, Inc. SF WSPP n/a n/a n/a
11 TransAlta Energy Marketing (U.S.) Inc OS WSPP n/a n/a n/a
12 lTransAlta Energy Marketing (U.S.) Inc WSPP n/a n/a n/a
13 TransAlta Energy Marketing (U.S.) Inc. SF WSPP n/a n/a n/a
14 Turlock Irrigation District SF WSPP n/a n/a n/a
Subtotal RQ 0 0 0
Subtotal non-RQ 0 01 0
Total 0 0 0
FERC FORM NO. I (ED. 12-90) Page 310.5
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Idaho Power Company X An Original (Mo, Da, Yr) End of 20111Q4
(2) 0 A Resubmission 04/13/2012
SALES FOR RESALE (Account 447) (Continued)
OS - for other service, use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ ° in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5.In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6.For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the suppliers system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
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 (fl. Explain in a footnote all components of the amount shown in column U). 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 RQIN0n-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
Demand Charges Energy Charges Other Charges Sold (h+i+j) No.
(g) (h) (i) U) (k) -
69 2,066 2,06C 1
194,888 194,888 2
200 6,000 6,000 3
2 52 524
109 109 5
50 1,100 11006
2,547 2,547 7
100 2,500 2,500 8
14,393 115,296 115,296 9
250 6,200 6,200 10
10,764 10,764 11
141,558 2,419,207 2,419,207 12
51,664 1,377,652 1,377,652 13
400 10,028 10,028 14
38,222 540,239 1,085,425 258,560 1,884,224
3,596,702 0 98,041,629 1,676,287 99,717,916
3,634,924 540,239 99,127,054 1,934,847 101,602,140 -
FERC FORM NO. I (ED. 12-90) Page 311.5
Name of Respondent This R ort Is: Date of Report Year/Period of Report
Idaho Power Company 2' End of 201 1/Q4 Resubmission 04/13/2012
SALES FOR RESALE (Account 447)
1.Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity (i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2.Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
Average
Monthly NCP Demand Avera e Monthly CFDemand No. (Footnote Affiliations) Classifi-
cation
Schedule or Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
1 United Materials of Great Falls LF 61 n/a n/a n/a
2 Wells Fargo Bank N A n/a n/a n/a
3 Marcquane Energy LLC WSPP n/a n/a n/a
4
5
6
7
8
9
10
11
12
13
14
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO I (ED 12-90) Page 3106
Name of Respondent This Report Is: Date of Report Year/Period of Report
Idaho Power Company (1)MAn Original (Mo, Da, Yr) End of 201 1/Q4
(2)EJA Resubmission 04/13/2012
SALES FOR RESALE (Account 447) (Continued)
OS - for other service, use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5.In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6.For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7.Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8.Report demand charges in column (h), energy charges in column (I), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column U). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9.The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 ,iine 24.
10.Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($) Line
Demand Charges Energy Charges Other Charges Sold (h+i+j) No.
(g) (h) (i) U) (k) -
26,446 26,446 1
77,127 77,127 2
50 2,000 2,000 3
4
5
6
7
8
9
10
11
12
13
14
38,222 540,239 1,085,425 258.560 1,884,224 -
3,596,702 0 98,041,629 1,676,287 99,717,916 -
3,634,924 540,239 99,127,054 1,934,847 101,602,140 -
FERC FORM NO. I (ED. 12-90) Page 311.6
IName of Respondent This Report is: Date of Report Year/Period of Report
I (1)An Original (Mo, Da, Yr)
Idaho Power Company (2)- A Resubmission 04/13/2012 201 1/Q4
I FOOTNOTE DATA
Schedule Page:310 Line No.:1 Column:b
Customer Charge
Schedule Page: 310 Line No.: 2 Column: b
Network Transmission Charges
Schedule Page: 310 Line No.: 5 Column: b
Non-firm Sales
Schedule Page: 310 Line No.: 7 Column: b -
Non-firm Sales
Schedule Page: 310 Line No.: 9 Column: b
ISDA4aster Agreement with Barclays Bank dated May 2, 2011
10 Column: k. - - - -- -- - - Financial Transmission Losses
Schedule Page: 310 Line No.: 11 Column: b
Non-firm Sales
Schedule Page: 310.1 Line No.: 2 Column:
master Agreement dated June 13,0
Page: 310.1 Line d6iunin
Financial Transmission Losses
Schedule Page: 310.1 Line No: 4 Column: b
Non-firm Sales
Schedule Page: 310.1 Line No.: 7 Column: b
Unit Contingent
Schedule Page: 310.1 Line No.: 8 Column: b
ISDA Master Agreement with Citigroup Energy, Inc., dated March 7, 2011
Schedule Page: 310.2 Line No.: 2 Column: b
Financial Transmission Losses
Schedule Page: 310.2 Line No.. : _4 Column: b
Non-firm Sales
Schedule Page 3102 Line No 5 Column b
ISDA Master Agreement with Iberdrola Renewables, Inc., dated July 19, 2011
Schedule Page 3102 Line No 6 Column I, -
ISDA Master Agreement with JP Morgan Ventures Energy Corporation dated November 4, 2005.
Schedule Page: 310.2 Line No.: 8 Column: b
Prudential Bache Commodities (Jeffries Bache), LLC Futures Account Document, dated
September 4, 2008.
Schedule Page: 310.2 Line No.: 9 Column: b
ISDA Master Agreement with Macquarie Energy, LLC dated April 12, 2011
Schedule Page: 310.2 Line No.: 11 Column: b
ISDA Master Agreement with Morgan Stanley dated March 1, 2000
Schedule Page: 310.2 Line No.: 12 Column: b
ISDA Master Agreement with Morgan Stanley dated March 1, 2000
Schedule Page: 310.2 Line No.: 14 Column: b -
Financial Transmission Losses
Schedule Page: 310.3 Line No.: I - Column: b
Non-firm Sales
Schedule Page 3103 Line No 3 Column b
Financial Transmission Losses
cneauie Page: 110.3 Line No.: 4 Column:b
ipinning_or_operating Reserves
Schedule Page: 310.3 Line No.: 5 Column: b
Financial Transmission Losses
Schedule Page: 310.3 Line No.:6 Column:b
Schedule Page: 310.3 Line No.: 8 Column: b
FERC FORM NO. I (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 04/13/2012 2011/04
FOOTNOTE DATA
Financial Transmission Losses
SchedulePage: 310.3 Line No.:9 Column:b - -
Non-firm Sales
Schedule Page: 310.3 Line No.: 11 Column: b
Financial Transmission Losses -
Schedule Page: 31013 Line No.: 12 Column: b
Non-firm Sales
Schedule Page: 3104 Line No.: I Column:b
Spinning or Operating Reserves
Schedule Page: 310.4 Line No.: 2 Column: b
Non-firm Sales
Schedule Page: 310.4 Line No.: 3 Colurnn:b
Financial Transmission Losses
Schedule Page: 3104 Line No.:5 Column:b -
ISDA Master Agreement with Royal Bank of Canada dated August 26, 2305
Schedule Page: 3-10.4 Line No.: 6 Column: b
Non-firm Sales
Schedule Page: 310.4 Line No.: 8 Column: b
IS DA Master Agreement wh Sempra Energy Trading dated February 21, 2008. it
Schedule Page. : 310.4 Line No.: 9 Column: b
Financial Transmission Losses
Schedule Page: 310.4 Line No.: 10 Columnb
I SDA Master Agreement with Shell Energy North America dated November 1, 2009
Schedule Page: 310.4 Line No.: 11 Column:b -
Financial Transmission Losses
Schedule Page: 310.4 Line No.: 12 Column: b
Unit Contingent _
Schedule Pagffi.4 Line No.: 13 Column: b_
Non-firm Sales
Schedule Page: 310.5 L IColumn:b
Spinning or Operating Reserves
- - a, - - - - .riieuui Page: .IU L.IrIeIYO...OIumfl U
Financial Transmission Losses
Schedule Page: 310.5 Line NO.: 4 Column:b
Non-firm Sales
Schedule Page: 310.5 Line No.: 5 Column: b
Financial Transmission Losses
Schedule Paae: 310.5 Line No.: 7 Column: b
Financial Transmission Losses
Schedule Page:_inf'Jp Column: b -
Non-firm Sales
Schedule Page: 310.5 Line No:11 Column: b
Financial Transmission Losses
Schedule Page: 310.5 Line No.: 12 Column: b
Non-firm Sales
Schedule Page: 310.6 Line No.: 2 _çpjb_______________________________________
ISDA Master Agreement with Wells Fargo Bank, N.A. daed March 1, 2006
Schedule Page: 310.6 Line No.: 3 Column: b
December 2010 Adjustment
FFERC FORM NO. I (ED. 12-87) Page 450.2 1
Name of Respondent
Idaho Power Company
This Report Is:
(1)An Original
(2)fl A Resubm:ssion
Date of Report
(Mo, Da, Yr)
04/13/2012
Year/Period of Report
End of 2011/Q4
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line
No.
Account
(a)
1. POWER PRODUCTION EXPENSES
Operation
1(500) Operation Sup"ervision
Stearn Power Generation
and Engineering
Amount for Amount for Current Year Previous Year
1
3
i,690j I 8 4
5 (501) Fuel 119,844,954 146,926,801
6 (502) Steam Expenses 6,950.410 7,337,561
7 (503) Steam from Other Sources
8 (Less) (504) Steam Transferred-Cr.
9 (50 5) Electric Expenses 2,231,309 2,140,193
10 (506) Miscellaneous Steam Power Expenses 9,734,2631 9,797,7551
11 (507) Rents 498,08.51 229,315
12 (509) AI!owances
13 TOTAL Operation (Enter Total of Lines 4 thru 12) 140,949182! r 2,075,559
168,320,196!
2,292,767
14
15
Maintenance
(510) Maintenance Supervision and Engineering
16 (511) Maintenance of Structures 920,609 309,374
17 (512) Maintenance of Boiler Plant 15,351,039 16,067,832
18 (513) Maintenance of Electric Plant 6,827,635 3,915,291
19 (514) Maintenance of Miscellaneous Steam Plant 6,486,063 3,753,015
20 TOTAL Maintenance (Enter Total of Lines 15 thru 19) 31,660,9051 26,338,279
21 TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 & 20) 172,610,087 194,658,475
22 1 B. Nuclear Power Generation
23 1 Operation
24 (517) Operation Supervision and Engineering I
25 (518)Fuel
26 (519) Coolants and Water
27 (520) Steam Expenses
28 (521) Steam from Other Sources
29 1 (Less) (522) Steam Transferred-Cr.
30 (523) Electric Expenses
31 (524) Miscellaneous Nuclear Power Expenses
32 (525) Rents
33 TOTAL Operation (Enter Total of lines 24 thru 32)
34 Maintenance
35 (528) Maintenance Supervision and Engineering
36 (529) Maintenance of Structures
37 (530) Maintenance of Reactor Plant Equipment
38 (531) Maintenance of Electric Plant
39 (532) Maintenance of Miscellaneous Nuclear Plant
40 TOTAL Maintenance (Enter Total of lines 35 thru 39)
411 TOTAL Power Production Expenses-Nuc. Power (Entr tot lines 33 & 40)
42 C. Hydraulic Power Generation
43 Operation
44 (535) Operation Supervision and Engineering 5,380,371 5,362,099
45 (536) Water for Power 8,772,110 7,322,751
46 (537) Hydraulic Expenses 12,513,192 10,671,807
47 (538) Electric Expenses 1,611,582 1565,842
48 (539) Miscellaneous Hydraulic Power Generation Expenses 3,081,121 2,895,723
49 (540) Rents 209,2131 406,432
50 TOTAL Operation (Enter Total of Lines 44 thru 49) 31,567,5891 28,22464
51 C. Hydraulic Power Generation (Continued)
52 Maintenance
53 (541) Mainentance Supervision and Engineering 1,763,6731 1,967,876
54 (542) Maintenance of Structures 1 1,722,862 1,155,653
55 (543) Maintenance of Reservoirs. Dams, and Waterways j 1,563,284 1,368,190
56 (544) Maintenance of Electric Plant 1,789,947 3,177,811
57 (545) Maintenance of Miscellaneous Hydraulic Plant 2,719,281 3,029,473
58 TOTAL Maintenance (Enter Total of lines 53 thru 57) 9,559,0471 10,699,003
59 TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 & 58) 41,126,636 38,923,657
FERC FORM NO 1 (ED. 12-93) Page 320
I
I
Name of Respondent
Idaho Power Company
j
This Report Is: Date of Report
04/13/2012
Year/Period of Report
End of 2011/Q4
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line
No.
Account
(a)
Amount for Current Year
(b)
Amount fpr Previous Year
(c
Power Generation
61 i Operation
62 (546) Operation Supervision and Engineering 820,192 328,4171
63 (547) Fuel 12,745,9J
64 (548) Generation Expenses 749,804 448,744
65 (549) Miscellaneous Other Power Generation Expenses 779,335 450,180
66 (550) Rents
67 TOTAL Operation (Enter Total of lines 62 thru 66) 14,046,2481 13,973,293
68 Maintenance
69 (551) Maintenance Supervision and Engineering
70 (2) Maintenance of Structures 179,520 182,043
71 (553) Maintenance of Generating and Electric Plant 115,128 118,53
72 (554) Maintenance of Miscellaneous Other Power Generation Plant 1,861,365 1,077,264
73 TOTAL Maintenance (Enter Total of lines 69 thru 72) 2,156,013 - 1,377,88
74 TOTALPowerProductionExpenses-OtherPower (Enter Tot of 67&73) 16,202,2611 15,351,176
75 E.Other Power SupplyExpenses
761(555) Purchased Power 156,873,749 137,850,33
77 (556)System Control and Load Dispatching 1,219 _160
78 (557)OtherExpenses 41,459,600__ 53,795,016
79 TOTALOtherPowerSupplyExp(Enter Totalof lines76thru78) 191.645,512
80 TOTAL Power Production Expenses (Total of lines 21, 41, 59, 74 & 79) 428,273,552 . 440,78,820
81 2. TRANSMISSION EXPENSES
82 Operation
831(560) Operation Supervision and Engineering 3,326,891 2,992,95I _
84 (561) Load Dispatching
198,334,568__
192,086__ 273,8691
85 (561.1) Load Dispatch-Reliability
86 (561.2) Load Dispatch-Monitor and Operate Transmission System 1,188,357 1,254,735
87 (561.3) Load Dispatch-Transmission Service and Scheduling 1,423,636 1,316,482
88 61.4) Scheduling, System Control and Dispatch Services
891(561.5) Reliability, Planning and Standards Development
90 61.6) Transmission Service Studies
91 61_7) Generation Interconnection Studies 102,697 108_008
92 (561.8) Reliability, Planning and Standards Development Services
93 62) Station Expenses 2,252,352 1,987,214
94 63) Overhead Lines Expenses 746,070 660,035
95 64) Underground Lines Expenses
96 5) Transmission of ElectricitybyOthers 6,462,104 5,918,507
97 6) Miscellaneous Transmission Expenses 307,899 336,835
98 (567) Rents 3,283,6211 1,569,1
99 TOTALOperation(Enter Totalof lines 83thru98) 19,285,7131 16,417,8
100 1 Maintenance
101 (568) Maintenance Supervision and Engineering 220,612 540,340
102 9) Maintenance of Structures
103 9.1) Maintenance of ComputerHardware 54,018 66,4
104 9.2) Maintenance of ComputerSoftware 347,776 324,0
105 (569.3)Maintenance of CommunicationEquipment 26,183 28,510
1061(569.4) Maintenance of MiscellaneousRegionalTransmissionPlant
107 (570) Maintenance of StationEquipment 2,975,539 3.447,66
108 (571)Maintenance of OverheadLines 3,675,361 2,781,256
109 (572)Maintenanceof UndergroundLines
110 (573)Maintenanceof MiscellaneousTransmissionPlant 5,474 -4
111 TOTAL Maintenance (Total of lines101thru110) 1 7,304,963 7,188,43
112 TOTALTransmissionExpenses(Totalof lines99and111) 26,590,676 23,606,24
FERC FORM NO. I (ED. 12-93) Page 321
Name of Respondent
Idaho Power Company
This Re art Is:
(2) [:]A Resubmission
Date of Report
04/13/2012
Year/Period of Report
End of 2011/04
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line Account
(a)
Amount for Current Year Amount for Previous Year
113
114
115
3. REGIONAL MARKET EXPENSES
OreraUon
(575.1) Operation Supervision I
(5752) Day-Ahead and Real-Time Market Facilitation
L
117
1 1
(575.3) Transmission Rghts Market Facilitation
(575.4) Capacity Market Facilitation
119 (575.5) Ancillary Services Market Facilitation
120 (575.6) Market Monitoring and Compliance
121 (575.7) Market Facilitation, Monitoring and Compliance Services
122 (575.8) Rents
123 Total Operation (Unes 115 thru 122)
124 Maintenance
125 (576.1) Maintenance of Structures and Improvements
126 1 (576,2) Maintenance of Computer Hardware
127 (576.3) Maintenance of Computer Software
128 (576.4) Maintenance of Communication Equipment
(576.5) Maintenance of Miscellaneous Market Operation Plant
130 Total Maintenance (Lines 125 thru 129)
131 TOTAL Regional Transmission and Market Op Expns (Total 123 and 130)
132 4. DISTRIBUTION EXPENSES L_
133 1 Operation
134 (580) Operation Supervision and Engineering I 3,746,4311 3,713,391
135 (581) Load Dispatching 3,482,055 3,419,960
136 (582) Station Expenses 1,192,869 1,277,818
137 (583) Overhead Line Expenses 3.039,224 3,029,340
138 (584) Underground Line Expenses 1,825,857 1,792,342
139 (585) Street Lighting and Signal System Expenses 122,065 79,537
140 (586) Meter Expenses 4,130,937 4,219,270
141 587) Customer Installations Expenses 1,092,077 1,521,427
142 (588) Miscellaneous Expenses 5,494,553 5,004,179
143 (589) Rents 830,940 440,788
144 TOTAL Operation (Enter Total of lines 134 thru 143) 1 24,957,0081 24,498,052
145 Maintenance
146 (590) Maintenance Supervision and Engineering 1
402.3811 371,979
147 (591) Maintenance of Structures 5,711 -11,385
148 (592) Maintenance of Station Equipment 3,230,860 3,774,723
149 (593) Maintenance of Overhead Lines 14,495,482 14,297,636
150 (594) Maintenance of Underground Lines 1,054,033 1,003,405
151 (595) Maintenance of Line Transformers 433,841 448,157
152 (596) Maintenance of Street Lighting and Signal Systems 554,042 587,953
153 (597) Maintenance of Meters 472,599 700,080
154 (598) Maintenance of Miscellaneous Distribution Plant 252,535 137,583
155 TOTAL Maintenance (Total of lines 146 thw 154) 20,901,484 21,310,131
156 TOTAL Distribution Expenses (Total of lines 144 and 155) 45,858,492 45,808,183
157 CUSTOMER ACCOUNTS EXPENSES
158 Operation
159 01) Supervision 427,283 410,702
160 902) Meter Reading Expenses 2,453,647 4,026,937
161 03) Customer Records and Collection Expenses 12,944,062 12,988,731
162 04) Uncollectible Accounts 4,269,718 4,638,855
163 05) Miscellaneous Customer Accounts Expenses 252 342
164 TOTAL Customer Accounts Expenses (Total of lines 159 thru 163) 20,094,962 22,065,567
FERC FORM NO. I (ED. 12-93) Page 322
I
Name of Respondent
Idaho Power Company
This Report Is:
2n Resubmission
Date of Report
[ 04/13/2012
Year/Period of Report
End of 2011/Q4
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line
No.
Account
(a)
Amount for Current Year Ampunt for Previous Year
l656. CUSTOMER SERVICE AND NFORMATIONAL EXPENSES
Operation
"352,779 I Supervision 528.250
168 (908) Customer Assistance Expenses 44,034,548 51 ,959,849
169 (909) Informational and Instructional Expenses 82,775 31,5171
170 (910) Miscellaneous Customer Service and Informational Expenses 531.823 864,00
171 TOTAL Customer Service and Information Expenses (Total 167 thru 170) 45,177,396 53,208,148
172 7. SALES EXPENSES
173 Operation
174 (911) Supervision
175 (912) Demonstrating and Selling Expenses
176 (913) Advertising Expenses
177 (916) Miscellaneous Sales Expenses
178 TOTAL Sales Expenses (Enter Total of lines 174 thru 177)
179 8. ADMINISTRATIVE AND GENERAL EXPENSES
160 Operation
181 (920) Administrative and General Salaries 67,143,039 63,660,597
182 (921) Office Supplies and Expenses 15,7421902 13,613,991
183 (Less) (922) Administrative Expenses Transferred-Credit 26,009,805 27,799,634
184 (923) Outside Services Employed 4,925,844 7,210,630
185 (924) Property Insurance 3,207,120 3,329,577
186 (925) Injuries and Damages 5,806,100 5,668,380
187 (926) Employee Pensions and Benefits 60,010,908 30,031,098
188 (927) Franchise Requirements 2,549
189 (928) Regulatory Commission Expenses 3,449,337 3,797,836
190 (929) (Less) Duplicate Charges-Cr.
191 (930.1) General Advertising Expenses 552,1291 417,950
192 (930.2) Miscellaneous General Expenses 3,750,1211 3,826,102
193 (931) Rents 7,1031 12,600
194 TOTAL Operation (Enter Total of lines 181 thru 193) 138,584,7981 103,771,676
195 Maintenance
196 (935) Maintenance of General Plant 4,522,111 4,182,610
197 TOTAL Administrative & General Expenses (Total of lines 194 and 196) 143,106,909 107,954,286
198 TOTAL Elec Op and Maint Expns (Total 80,112,131.156,164,171,178,197) 709,101,987 693,221.250
FERC FORM NO. 1(ED.1293) Page 323
Name of Respondent Date of Report Year/Period of Report
Idaho Power Company
This RM
A
oil Is:
(1)An Original
(2)Resubmission
(Mo, Da, Yr)
04/13/2012 nu Oi 2011/Q4
PUCHA$ED POWER (Account 555) (Including power exchanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
Average
Monthly NCP Demand
Average
Monthly CP Demand No. (Footnote Affiliations) Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
1 Cogeneration and Small Power Producers
2 AgPower Jerome/Double A Digester LU - N/A N/A N/A
3 Allan Ravenscroft/Malad River LU 488
N/A
Al
4 Bennett Creek Wind Farm LU - N/A N/A
5 Bettencourt DryCreek Biofactory LU - N/A N/A N/A
6 Big Sky West Dairy Digester LU - N/A N/A N/A
7 Big Wood Canal Company
8 Black Canyon #3 LU - N/A N/A N/A
9 Jim Knight LU - N/A N/A N/A
10 Sagebrush LU - N/A N/A N/A
11 Blind Canyon Hydro LU - N/A N/A N/A
12 1 BranchflowerlTrout Company LU - N/A N/A N/A
13 Burley Butte Wind Park LU N/A N/A N/A
14 Bypass Limited LU N/A N/A N/A
Total
FERC FORM NO. I (ED. 12-90) Page 326
Name of Respondent This Report Is: Date of Report Year/Period of Report
Idaho Power Company 1(1 ) IKIAn Original (Mo, Da, Yr) End of 201 1/Q4 (2) A Resubmission 04/13/2012
PUICHAS D POWER(Account 555) (Continued) (lndudlng power exchanges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5.For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7.Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (!). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8.The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (I) must be reported as Exchange Delivered on Page 401, line 13.
9.Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line Megawatt Hours Megawatt Hours Demand Charges Energy Charges Other Charges Total (J+k+l) Purchased No. Received Delivered ($) ($) ($) of Settlement ($) (g) (h) (i)
172 3,741 3,741 2
3,517 155,672 99,501 255,173 3
45,16' 2,483,801 2,483,800 4
9,891 325,91 325,916 5
8,99 504,281 504,286 6
7
331 22,00 22,007 8
1,32 89,761 89,760 9
1,32I 90,1877 90,187 10
5,50 498,641 498,646 11
79 54.831 54,831 12
45,70' 1,880,36: 1,880,363 13
27,86 1,494,911 1,494,916 14
2,777,898 602,391 I 680,849l 2,815,124l 146,504,839I 7,553,786 156,873,74
FERC FORM NO. I (ED. 12-90) Page 327
Name of Respondent This Re art Is: Date of Report Year/Period of Report
Idaho Power Company (1)X An Original (Mo, Da, YT . cflu 01 201 1/Q4 (2)[JA Resubmission 04113/2012
PUICHA$ED POWER (Account 555) (Including power exchanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3.in column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No. (Footnote Affiliations) Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
Average
Monthly NCP Demand
Average
Monthly CP Demand
- (a) (b) (c) (d) (e) (f)
1 Camp Reed Wind Park LU - N/A N/A N/A
2 Cargill Inc./B6 Anaerobic Digester LU - N/A N/A N/A
3 Cassia Gulch Wind Park LU - N/A N/A N/A
4 Cassia Wind Farm LU - N/A N/A N/A
5 City of Cove, Oregon/Mill Creek LU - N/A N/A N/A
6 City of Halley LU - N/A N/A N/A
7 City of Pocatello LU - N/A N/A N/A
8 Clear Springs Food Inc. LU - N/A N/A N/A
9 Clifton E Jenson/Birchcreek LU 05
10 Consolidated Hydra lnc./Enel
11 Barber Dam LU - N/A N/A N/A
12 GeoBon #2 LU - N/A N/A N/A
13 Rock Creek #2 LU - N/A N/A N/A
14 Dietrich Drop LU N/A IN N/A
Total
FERC FORM NO. 1 (ED. 12-90) Page 326.1
Name of Respondent J This Report Is: Date of Report Year/Period of Report
Idaho Power Company End of 2011/04
(2) M A Resubmission L 04/13/2012
PU CHASED PQWER(Account 555) (Continued) (Including power exchanges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5.For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7.Report demand charges in column energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. !f 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
MegaWatt Hours MegaWatt Hours Demand Charges
______________
Energy Charges Other Charges Total (j+k+l) Purchased No.
Received Delivered ($) ($) ($) of Settlement(S)
(g) (h) (i) U) (k) (I) (m)
60,804 5,025,974 5,025,974 1
2,29 79,729 79,729 2
3
24,11E 1,079,42 1,079,424 4
32 25,89 25,893 5
5q 4,041 4,046 6
1,53: 110,711 110,7157
294,20 294,206 8
34: 17,500 9,66E 27,169 9
10
14,121 695,07 695,077 11
4,03,' 288,572 12
9,571 471,801 471,800 13
15,517 847,43E 847,439 14
2,777,898 -602,391 6808491 2,8151241 146504,8391 7,553.7861 156,873,74
FERC FORM NO. I (ED. 12-90) Page 327.1
Name of Respondent This Rort Is: Date of Report Year/Period of Report
Idaho Power Company (1)X An Original (Mo, Da, Yr) End of 2011/04 (2)M Resubmission 04/13/2012
PURCHA$ED POWER (Account 555) (Including power exchanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Expain in a footnote any ownership interest or affiliation the respondent has with the seller.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RO - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU -for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
N 0. .
. (Footnote I Affiliations) Classifl-
cation rOOu Schedule or
Tariff Number
Monthly Billing
Demand (MW)
Average
Monthly NCP Demand
Average
Monthly CP Demand
- (a) (b) (c) (d) (e) (f)
1 Lowline#2 LU - N/A N/A N/A
2 Contractors Power Group Inc./Mile 28 LU - N/A N/A N/A
3 Crystal Springs Hydro LU - N/A N/A N/A
4 Curry Cattle Company LU 084
5 David McCollum/Canyon Springs LU - N/A N/A N/A
6 David R Snedigar LU - N/A N/A NIA
7 D.R. Johnson Lumber/Co Gen Co SF - N/A N/A N/A
8 Faulkner Brothers Hydro Inc. LU - N/A N/A N/A
9 Fisheries Development
- - N/A N/A N/A
10 Fossil Gulch Wind LU - N/A N/A N/A
111 02 Energy Hidden Hollow LU - N/A N/A N/A
12
Goden Valley Wind Park
LU N/A N/A N/A
13 LU - N/A N/A N/A
14 LU - N/A N/A N/A
JTotal
FERC FORM NO. I (ED. 12-90) Page 326.2
I
Name of Respondent This Report Is: Date of Report Year/Period of Report
Idaho Power Company J(1), EJAn Original (Mo, Da,Yr) End of 2011/Q4 (2) fl A Resubmission 04/13/2012
PUkCHA$ PQWER(Accout 555) (Continued) (Including power exchanges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5.For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (a), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (1). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7.Report demand charges in column U) energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8.The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (I) must be reported as Exchange Delivered on Page 401, line 13.
9.Footnote entries as required and provide explanations following all required data.
Mega Watt Hours POWER EXCHANGES _____________ COST/SETTLEMENT OF POWER - Line MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total U+k+l) Purchased No. Received Delivered ($) of Settlement ($) (g) (h) (I) U) (k) (I) (m) -
9,689 520,129 520,129 1
5,021 333,051 333,058 2
11,231 764,611 764,612 3
58 26,796 1653 43,328 4
811 11,51 11,516 5
1,531 105,81 105,819 6
10,041 976,82' 976,820 7
3,131 238,02C 238,020 8
1,081 15,461 15,461 9
24,731 1,214,017 1,214,017 10
23,681 1,357,141 1,357,141 11
-3 -16,371 -16,371 12
26,951 1,191,124 1,191,12413
22,98d 1,569,320 1,569,320 14
2,777,898 602,394 680,849 2,815,124 146,504,839 7,553,786 156,873,74
FERC FORM NO. I (ED. 12-90) Page 327.2
Name of Respondent This Re oil Is: Date of Report Year/Period of Report
Idaho Power Company (1)X An Original (Mo, Da, Yr) End of 201 1/04
(2)[JA Resubmission 04/13/2012
PUICHA$ED POWER (Account 555) (Including power excflanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
Average
Monthly NCP Demand
Average
Monthly CP Demand N 0. 'F Affiliations) (Footnote e ia 10fl51 Classili-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (C) (d) (e) (f)
1 H.K. Hydro Mud Creek S & S LU - N/A N/A N/A
2 Horeshoe Bend Hydro LU - N/A N/A N/A
3 Horseshoe Bend Wind/United Materials LU - N/A N/A N/A
4 Hot Springs Wind Farm LU - N/A N/A N/A
5 Idaho Winds/Sawtooth Wind Project LU N/A N/A N/A
6 JR Simplot Co. LU - N/A N/A N/A
7 J M MiIler/Sahko Hydro LU N/A N/A N/A
8 James B. Howell/CHI Elk Creek LU - N/A N/A N/A
9 John R LeMoyne LU - N/A N/A N/A
10 Kasel & Witherspoon LU N/A N/A N/A
11 Koyle Hydro Inc. LU - N/A N/A N/A
12 Lateral 10 Ventures LU - N/A N/A N/A
13 Lemhi Hydro Power Co./Schaffner LU - N/A N/A N/A
14 Lime Wind LU - N/A N/A N/A
Total
FERC FORM NO. 1 (ED. 12-90) Page 326.3
Name of Respondent I This Report Is: Date of Report Year/Period of Report
Idaho Power Company (1)An Original (MO, Da, Yr) End of 201 1/Q4 (2)flA Resubmission 04/13/2012
PLJCHA$ PQWER(Account 555) (Continued) lncIuding power exchanges)
AD for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5.For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on bills rendered to the respondent Report in columns (h) and (I) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7.Report demand charges in column (J), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m),
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8.The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9.Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES _____________ COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+I) No. Received Delivered ($) ($) ($) of Settlement ($)
1,615 116,960 116,960 1
41,991 2,788,304 2,788304 2
20,584 1,003,801 1,003,804 3
44,461 2,454,021 2,454,028 4
12,371 933,1124 933,162 5
77,631 4,454,331 4,454,339 6
I ,42 80,64: 80,643 7
4,02i 298,79641 298,796 8
63: 35,121 35,123 9
3,271 251,3'J" 251,302 10
3,841 313,301 313,305 11
9,201 599,361 599,368 12
1,481 113,041 113,045 13
281 24,46E 24,468 14
2,777,898 602,391 680,849 2,815,124 146,504,839 7553786j 156,873,74
FERC FORM NO I (ED 12-90) Page 3273
Name of Respondent This R ort Is: Date of Report Year/Period of Report
Idaho Power Company (1)X An Original (Mo, Da, Yr) n 0 2011/04
(2)DA Resubmission 04/13/2012
PUICHAED POWER (Account 555) (Including power excnanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No. (Footnote Affiliations) Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
Average
Monthly NCP Demand
Average
Monthly CP Demand
- (a) (b) (c) (d) (e) (1)
1 Lithe Mac Power Co./Cedar Draw LU - N/A N/A N/A
2 Little Wood River Irrigation District LU - N/A N/A N/A
3 Magic Reservoir Hydro LU - N/A N/A N/A
4 Marco Rancher's Irrigation Inc. LU - N/A N/A N/A
5 400111W LU N/A N/A N/A
6 Milner Dam Wind Park LU - N/A N/A N/A
7 Mud Creek White Hydro Inc LU N/A N/A N/A
8 Oregon Trail Wind Park LU - N/A N/A N/A
9 Owyhee Irrigation District
10 Mitchell Butte LU - N/A N/A N/A
11 Owyhee Dam LU - N/A N/A N/A
12 Tunnel #1 LU - N/A N/A N/A
13 Paynes Ferry Wind Park LU - N/A N/A N/A
14 1 Pigeon Cove Power LU 1.389
- Total
FERC FORM NO I (ED 12-90) Page 3264
I
I
Name of Respondent This Report Is: 1 Date of Report Year/Period of Report
Idaho Power Company I (1) x An Original (MO, Da, Yr) End of 201 1/Q4 (2) EJAResubmission 04/13/2012
PUICHA POWER(Account 555) (Continued) (Including power exchanges)
AD for out-of-period adjustment. Use this code for any accounting adjustments or true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5.For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (I). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (I) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7.Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. lithe 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 tine MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+I) Purchased No Received Delivered ($) of Settlement($) (g) (h) (i) (j) (k) (I) (m)
6,631 423,980 423 ,980 1
8,7371 619,500 619,500 2
28,251 1,469,461 1,469,468 3
3,504 233,62' 233,621 4
57,41 3,696,68( 3,696,680 5
39,11 1,790,021 1,790,027 6
451 31,24C 31,240 7
33,711 1,382,867 1,382,867 8
9
7,071 166,007 166,007 10
25,601 485,901 485,901 11
25,062 2,752,182 2,752,182 12
58,96 4,846,16E 4,846,169 13
7,374 486,150 181,39E 667,546 14
2777,8981 602,391J 680.8491 2,815,124 146504,8391 7.5537861 156873749
FERC FORM NO. I (ED. 12-90) Page 327.4
Name of Respondent This Report Is: Date of Report Year/Period of Report
Idaho Power Company (1)nX An Original (Mo, Da, Yr) End o 2011/Q4
(2) DA Resubmission 04/13/2012
PURCHASED POWER (Account 555) (Including power exchanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term' means longer than one year but less
than live years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
Average
Monthly NCP Demand
Average
Monthly CP Demand 0. (Footnote Affiliations) Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (C) (d) (e) (f)
1 Pilgrim Stage Station Wind Park LU - N/A N/A N/A
2 Pristine Springs Inc #3 LU - N/A N/A N/A
3 Pristine Springs Inc #1 LU - N/A N/A N/A
4 Reynolds Irrigation District LU - N/A N/A N/A
5 Richard Kaster
6 Box Canyon LU - N/A N/A N/A
7 Briggs Creek LU - N/A N/A N/A
8 Rim View Trout Company N/A N/A N/A
9 Riverside Hydro/Mora Drop LU - N/A N/A N/A
10 Riverside Investments/Arena Drop LU - N/A N/A N/A
11 Rock Creek #1 Joint Venture LU 1.732
N/A
SOFMIMM
N/A 12 Rockland Wind Project LU - N/A
13 Rupert Cogen Partners/Magic Valley LU - N/A N/A N/A
14 Salmon Falls Wind Park LU - N/A N/A N/A
Total
FERC FORM NO I (ED 12-90) Page 3265
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Idaho Power Company
gAResubmission End of 2011/04 L
04/13/2012
PU CHA PQWER(Account 555) (Continued) (Including power exchanges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5.For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7.Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8.The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9.Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES ______________ COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l) No. Received Delivered ($)($) ($) of Settlement($) (g) (h) (i) U) (k) (I) (m)
30,261 1,371,177 1,371,177 1
851 18,180 18,180 2
851 48,791 48,791 3
78 59,071 59,078 4
5
1,661 109,77 109,773 6
371 248,30q 248,306 7
1,171 17,30 17,307 8
4,69, 279,041 279,049 9
1,451 106,17q 106,175 10
10,241 552,508 289,89 842,404 11
24,93 1,101,09: 1,101,093 12
79,961 5,012,24 5,012,242 13
21,26"! 820,34( 820,346 14
2777898I 602,391 J 680,849 1 2815124I 146,504,8391 7,553,786 156,873,741
FERC FORM NO. I (ED. 12-90) Page 327.5
Name of Respondent Date of Report Year/Period of Report
Idaho Power Company
--J This RM
A
ort Is:
(1)An Original (Mo, Da, Yr) n d f 2011104
(2)Resubmission 04/13/2012
PURCHASED POWER (Account 555) (Induding power exchanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF for intermediate-term firm service. The same as LF service expect that Intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
Average
Monthly NCP Deman4
I Average
Monthly CP Demand No. (Footnote Affiliations) Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
(a) (b) (c) (d) (e)
1 SE Hazelton A LP LU - N/A N/A I N/A
2 Shorock Hydro Inc.
3 Shoshone Cspp LU - N/A N/A I N/A
4 Shoshone #2 LU - N/A N/A I N/A
5 Snake Rivery Pottery LU - N/A NIA I N/A
6 .. .
7
LU - N/A N/A I N/A
LU 4.942
8 Tasco - Nampa M 47- N/A N/A N/A
9 Ted S. Sorenson/Tiber Dam LU - N/A N/A N/A
10 Thousand Spring Wind Park LU - N/A N/A N/A
11 Tuana Gulch Wind Park LU - N/A N/A N/A
12 Tuana Springs Expansion LU - N/A N/A N/A
13 Twin Falls Energy/Lowline Midway Hydro LU - N/A N/A N/A
14 White Water Ranch LU - N/A N/A N/A
IJTotal
FERC FORM NO. I (ED. 12-90) Page 326.6
Name of Respondent J This Report Is: Date of Report Year/Period of Report
Idaho Power Company 1(1) jAn Original (Mo, Da, Yr) End of 201 1/Q4 (2) A Resubmission 04/13/2012
PUkCI-IASD PQWER(Account 555) (Continued) (Including power exchanges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional setlers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5.For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7.Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8.The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (I) must be reported as Exchange Delivered on Page 401, line 13.
9.Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES ______________ COST/SETTLEMENT OF POWER Line MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l) Purchased No.
(g)
Received Delivered ($) of Settlement($) (h) (I) (j) (k) (I) (m)
23,84 1,224,987 1,224,987 1
2
1,941 153,67i 153,670 3
2,63 171,411 171,411 4
36 24,62! 24,629 5
28,06 2,009,23f 2,009,238 6
32,72 1,576,498 1,222,911 2,799,415 7
14 2,161 2,168 8
29,721 1,520,181 1,520,185 9
30,024 1,283,701 1,283,708 10
26,28 1,022,30: 1,022,303 11
82,10 5,270,511 5,270,518 12
8,95 536,971 536,979 13
67E 44,717 44,717 14
2777898j 602,391 680,849 2,815,12 146,504,83 91 7,553.786 156,873,74
FERC FORM NO. I (ED. 12-90) Page 327.6 -
Name of Respondent Date of Report Year/Period of Report
Idaho Power Company
This RR
A
oil Is:
(1)An Original (Mo, Da, Yr) n 2011/04 (2)Resubmission 04/1312012
PUICHA$ED POWER (Account 555) (lnduciing power excnanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
N °• (Footnote Affiliations) ons1 Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW) Average
Monthly NCP Demand
Average
Monthly CP Demand
- (a) (b) (C) (d) (e) (f)
1 William Arkoosh/Littlewood LU - N/A N/A N/A
2 Willis and Betty Deveny/Shingle Creek LU - N/A N/A N/A
3 t;F U N/A N/A N/A
4 Yahoo Creek Wind Park LU - N/A N/A N/A
5 New Wind Projects Scheduled Energy LJ- V - N/A N/A N/A
6 Other Purchased Power
7 Arizona Public Service Co. SF WSPP N/A N/A N/A
8 Avista Corp SF T-12 N/A N/A N/A
9 Avista Corp. SF WSPP N/A N/A N/A
10 Avista Corp QçJWSPP N/A N/A N/A
11 Barclays Bank PLC SF JWSPP N/A N/A N/A
12 Barclays Bank PLC OS_ N/A N/A N/A
13 Black Hills Power Inc SF IWSPP N/A N/A N/A
14 Bonneville Power Administration 4WSPP N/A N/A N/A
- Total
FERC FORM NO 1 (ED 12-90) Page 3267
I
I
Name of Respondent I This Report Is: Date of Report Year/Period of Report
Idaho Power Company (1)An Original (Mo, Da, Yr) End of 201 1/Q4
(2)j A Resubmission 04/13/2012
PUlCl-1ASED POWER(Accout 555) (Continued) (Including power exctianges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5.For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (I) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7.Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8.The data in column (g)through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9.Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES _____________ COST/SETTLEMENT OF POWER Line MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+I) Purchased Received Delivered ($) of Settlement ($)
(g) (h) 0) (j) (k) (I) (m) -
4,294 306,445 306,445 1
1,01q 70,109 70,1092
26,64E 1,823,974 1,823,974 3
5997 4,942,68 4,942,689 4
79 5
6
26,691 994,09 994,099 7
2 73E 738 8
3,361 89,84 89,845 9
278,412 278,412 10
415 8,763 8,76311
43,340 43,340 12
4,102 124,785 124,785 13
524,683 524,683 14
2,777,8981 602391 I 6808491 2,815,1241 146,504,8391 7553,7861 156,873,74
FERC FORM NO. I (ED. 12-90) Page 327.7
Name of Respondent This Rort Is: Date of Report Year/Period of Report
Idaho Power Company
(1)MA
An Original (Mo, Da, Yr) n 0 2011/Q4
(2)Resubmission 04/13/2012
PURCHASED POWER (Account 555) (Including power exthanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
Average Average 'U 0. Affiliations) (Footnote ia ons, Classifi- Schedule or Monthly Billing
cation Tariff Number Demand (MW) Monthly NCP Demand Monthly CP Demand
- (a) (b) (c) (d) (e) (f)
1 Bonneville Power Administration SF WSPP N/A N/A N/A
2 Bonneville Power Administration A WSPP N/A N/A N/A
3 BP Energy Company SF WSPP N/A N/A N/A
4 Calpine Energy Services, L.P. SF WSPP N/A N/A N/A
5 Cargill Power Markets LLC SF WSPP N/A N/A N/A
6 Chelan Co PUD SF WSPP N/A N/A N/A
7 Citigroup Energy Inc. SF WSPP N/A N/A N/A
8 Cibgroup Energy Inc.- N/A N/A N/A
9 Clatskanie PUD SF WSPP N/A N/A N/A
10 Constellation Energy Commodities Group SF WSPP N/A N/A N/A
11 DB Energy Trading LLC SF WSPP N/A N/A N/A
12 Douglas County PUD SF WSPP N/A N/A N/A
13 EDF Trading North America, LLC SF WSPP N/A N/A N/A
14 El Paso Electric Company SF WSPP N/A N/A N/A
- Total
FERC FORM NO I (ED 1290) Page 3268
.
Name of Respondent f This Re art Is: Date of Report Year/Period of Report
Idaho Power Company (1)X An Original (Mo, Da, Yr) End of 20111Q4 (2)A Resubmission 04/13/2012
PUICHASED PQWER(Account 555) (Continued) (Including power exchanges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5.For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (ft For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (I) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7.Report demand charges in column U) energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. if more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8.The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9.Footnote entries as required and provide explanations following all required data.
Mega Watt Hours POWER EXCHANGES ______________ COST/SETTLEMENT OF POWER Line
Purchased No. MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+I)
Received Delivered ($) of Settlement($) (g) (h) (i) (j) (k) (I) (m)
125,52 3,588,046 3,588,046 1
999 27,950 27,950 2
25,20( 1,118,901 1,118,900 3
31,02 862,19 862,192 4
38,43 1,177,57 1,177,579 5
20 2,95: 2,952 6
14,071 396,88! 396,889 7
_ 163,244 163,244 8
42 3,57 3,574 9
1,72: 56,34: 56,342 10
3,204 85,12 85,128 11
1,601 40,034 40,036 12
3,354 91,601 91,601 13
537 8,000 8,000 14
2,777,898 602,391 680,849 28151241
146,504,8391 7553786 156873749
FERC FORM NO.1 (ED. 12-90) Page 327.8
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Idaho Power Company (1)X An Original (Mo, Da, Yr) flu 01 201 1/04 (2)A Resubmission 04/13/2012
PUICHA$ED POWER (Account 555) (Inc1udng power exchanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
0. (Footnote Affiliations) Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
Average
Monthly NCP Demand
Average
Monthly CP Demand
(a) (b) (c) (d) (e) (f)
1 Eugene Water & Electric Board SF WSPP N/A N/A N/A
2 Glendale Power Marketing SF WSPP N/A N/A N/A
3 Grant CO Public Utility District #2 - SF WSPP N/A N/A N/A
4 IBERDROLA RENEWABLES, Inc. SF WSPP N/A N/A N/A
5 J.P. Morgan Ventures Energy Corporatio SF WSPP N/A N/A N/A
6 JPMorgan Chase Bank N.A. N/A N/A N/A
7 Jeffenes Bache N/A N/A N/A
8 Los Alamos County Utilities SF WSPP N/A N/A N/A
9 Macquarie Cook Power Inc. SF WSPP N/A N/A N/A
10 Macquarie Cook Power Inc. N/A N/A N/A
11 Morgan Stanley Capital Group Inc. SF lV662 N/A N/A N/A
12 Morgan Stanley Capital Group Inc .,. V6-62 N/A N/A N/A
13 NaturEner USA, LLC SF WSPP N/A N/A N/A
14 Nevada Power Co, DBA NV Energy SF WSPP N/A N/A N/A
Total
FERC FORM NO. I (ED. 12-90) Page 326.9
.
Name of Respondent I This Report Is: Date of Report Year/Period of Report
Idaho Power Company (1)FlAn Original (Mo, Da, Yr) End of 2011/04
(2)DA Resubmission 04/13/2012
PUICHA$ED PQWER(Account 555) (Continued) (Induding power exchanges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5.For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7.Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (i) Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8.The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9.Footnote entries as required and provide explanations following all required data.
Mega Watt Hours POWER EXCHANGES _____________ COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l) No. Received Delivered ($) ($) ($) of Settlement($)
(9) (h) (I) U) (k) (I) (m)
11,27 263,134 263,134 1
3,266 3,266 2
1,98 50,86 50,865 3
9400 2,705,04 2,705,042 4
63,80 5,487,61 E 5,487,618 5
572,658 572,6581 6
6,320,112 6,320,112 7
8
69,101 2,717,536 27175359
72,038 72,038 10
3,25 56,697 56,697 11
3,60'
1
3,600 12
3E 3613
201 9,OOC 9,000 14
2,777,8981 602,391 680,849 28151241 146504839I 7,553,786 156,873,74
FERC FORM NO I !D I2T90L
Page 327.9
Name of Respondent This Report Is: Date of Report Year/Period of Report
Idaho Power Company (1)J An Original (Mo, Da, Yr) End of 201 11Q4
(2) A Resubmission 04/13/2012
PUICHA$ED POWER (Account 555) (Inducting power excflanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
Average
Monthly NCP Demand
Average
Monthly CP Demand No. (Footnote Affiliations) Classifi-
cation Schedule or
Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
1 NextEra Energy Power Marketing, LLC SF WSPP N/A N/A N/A
2 NorthWestern Energy SF T-7 N/A N/A N/A
3 NorthWestem Energy SF WSPP NIA N/A N/A
4 PadflCorp Inc. SF T-13 NIA N/A N/A
5 PaciflCorp Inc SF WSPP N/A N/A N/A
6 PacifiCorp Inc. SF WSPP N/A N/A N/A
7 1 PaciflCorp Inc 0% ,WSPP N/A N/A N/A
8 Portland General Electric Company SF T-14 N/A N/A N/A
9 Portland General Electric Company SF WSPP N/A N/A N/A
10 Portland General Electric Company SF WSPP N/A N/A N/A
11 Powerex Corp. SF WSPP N/A N/A N/A
12 1 Powerex Corp. SF WSPP N/A N/A N/A
13 PPL EnergyPlus, LLC IF WSPP N/A N/A N/A
14 PPL EnergyPlus, LLC SF WSPP N/A N/A N/A
L... Total
FERC FORM NO. 1 (ED. 12-90) Page 326.10
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Idaho Power Company ginal
(2) r-J A Resubmission L
04/13/2012 End of 201 1/Q4
PU CHA PQWERAcceunt 555) (Continued) (Including power exchanges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5.For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7.Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8.The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9.Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
MegaWatt Hours MegaWatt Hours Demand Charges
_____________
Energy Charges Other Charges Total (j+k+l) Purchased No. Received Delivered ($) of Settlement($)
(g) (h) 0) (j) (k) (I) (m) -
29,575 1,262,442 1,262,442 1
41 1,267 1,267 2
1 Ir 529 5253
21E 6,52E 6,526 4
92 3,12 3,120 5
13,26 434,74E 434,748 6
139,138 139,138 7
4 1,27q 1,270 8
37,331 826,88A 826,882 9
51 90 90010
31,57 1,382,68 1,382,681 11
631 29,18 29,185 12
103,584 9,555,624 9,555,624 13
50,78 1,351,47 1,351,475 14
27778981 602,391 6808491 2,815,124 146504.8391 7,553,786 156,873,749
FERC FORM NO. I (ED. 12-90) Page 327.10
Name of Respondent This Re oil Is: Date of Rep ort Year/Period of Report
Idaho Power Company (1)MVO Original (Mo, Da, Yr) flu 01 2011/04
(2)A Resubmission 04/13/2012
PURCHASED POWER (Account 555) (Including power exct,anges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
Average
Monthly NCP Demand
Average
Monthly CP Demand 0. (Footnote ptti,ilauonsj Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
(a) (b) (c) (d) (e) (1)
1 Public Service Company of New Mexico SF WSPP N/A N/A N/A
2 Puget Sound Energy, Inc. SF T-9 N/A N/A N/A
3 Puget Sound Energy, Inc. SF WSPP N/A N/A N/A
4 Puget Sound Energy Inc S1 WSPP N/A N/A N/A
5 Rainbow Energy Marketing Corporation SF WSPP N/A N/A N/A
6 San Diego Gas and Electric SF WSPP N/A N/A N/A
7 Seattle City Light SF WSPP N/A N/A N/A
8 Seattle City Light SF WSPP N/A N/A N/A
9 Shell Energy North America (US), L.P. SF WSPP N/A N/A N/A
10 Shell Energy North America (US) L P - N/A N/A N/A
11 Sierra Pacific Power Co., dba NV Energ SF T-55 N/A N/A N/A
12 Sierra Pacific Power Co., dba NV Energ SF WSPP N/A N/A N/A
13 Sierra Pacific Power Co dba NV Energ AK195111111111WSPF, N/A N/A N/A
14 Sierra Pacific Power Co dba NV Energ WSPP N/A N/A N/A
- Total
FERC FORM NO. 1 (ED. 12-90) Page 326.11
I
I
Name of Respondent This Report Is: Date of Report Year/Period of Report
Idaho Power Company J (1) 0 An Original (Mo, Da, Yr) End of 201 1 /Q4 (2) AResubmission 04/13/2012
PUICHASED POWER(Account 555) (Continued) (Including power exchanges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5.For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7.Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8.The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (I) must be reported as Exchange Delivered on Page 401, line 13.
9.Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (J+k+I) No. Received Delivered ($) ($) of Settlement($) (g) (h) (i) (j) (k) (I) (m)
187 8,38 8,386 1
5q 1,587 1,587 2
24,34E 690,07q 690,070 3
22 7,05C 7,050 4
24,4971 1,072,74E 1,072,745 5
1 . 76
9,95 273,191 273,191 7
2( 521 520 8
2851 720,32 720,324 9
112,078 112,078 10
2 661 66911
9,03 305,532 305,532 12
24 24 13
6,808 6,808 14
2,777,898 602,391 680,849 2815124I 146,504,83 75537861 156,873,74
FERC FORM NO. 1 (ED. 12-90) Page 327.11
Name of Respondent This Re ii s. s: Date of Report Year/Period of Report
Idaho Power Company (1)X An original (Mo, Da, Yr) 1flu O 211/Q4
(2)EA Resubmission 04/13/2012
PUCHA$ED POWER (Account 555) (including power excnanges;
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
Average
Monthly NCP Demand
Average
Monthly CP Demand N 0. . (Footnote Affiliations) Classifi- Schedule or
Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
1 Snohomish County PUD SF WSPP N/A N/A N/A
2 Southern California Edison SF WSPP N/A N/A N/A
3 Southwestern Public Service Company SF WSPP N/A N/A N/A
4 Tacoma Power SF WSPP N/A NIA N/A
5 The Energy Authority, Inc. SF WSPP N/A N/A N/A
6 TransAlta Energy Marketing (U.S.) Inc. SF WSPP N/A N/A N/A
7 TransAlta Energy Marketing (U.S.) Inc. SF WSPP N/A N/A N/A
8 Tri-State Generation and Transmission SF WSPP N/A N/A N/A
9 Tucson Electric Power Company SF WSPP N/A N/A N/A
10 Wells Fargo Authonty, N A N/A N/A N/A
11 Western Area Power Administration SF JWSPP N/A N/A N/A
12 Raft River Energy I LLC N/A N/A N/A
13 Telocaset Wind Power Partners LLC LU APP-A N/A N/A N/A
14 Net Metering Customers K N/A N/A N/A
[_lT0tat
FERC FORM NO. I (ED. 12-90) Page 326.12
I
Name of Respondent I This Re ort Is: Date of Report Year/Period of Report
Idaho Power Company 1(1) X An Original (Mo, Da, Yr) End of 2011/Q4 (2) A Resubmission 04/13/2012
PUCHAS PQWER(Account 55) (Continued) (Including power exchanges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5.For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7.Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (rn)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8.The data in column (g)through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9.Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES _____________ COST/SETTLEMENT OF POWER Line
Purchased No. MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l)
Received Delivered ($) of Settlement($) (g) (h) (I) (j) (k) (I) (m)
4,49 114,955 114,955 1
6,57q 183,947 183,947 2
24 4,35 4,359 3
2,161 75,271 752764
2,59 78,53 78,53€ 5
2,44 79,171 79,171 6
44 564 560 7
9( 9,001 9,000 8
141 1,57f 1,576 9
68,756 68,756 10
1 3E 36 11
63,484 3,781,316E 3,781,365 12
310,95 16,772,667 16,772,667 13
63E 51,605 51,605 14
2,777,8981 602,391 1 680,849 1 2,815,1241 146504.8391 7,553'7861 156,873,744
FERC FORM NO. 1 (ED. 12-90) Page 327.12
Name of Respondent This Report Is: Date of Report Year/Period of Report
Idaho Power Company (1)x An Original (Mo, Da, Yr) End of 2011/04
(2)DA Resubmission 04/13/2012
PURCHASED POWER (Account 555) (Induding power excflanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No. (Footnote Affiliations) Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
Average
Monthly NCP Demand
Average
Monthly CP Demand
(a) (b) (c) (d) (e) (f)
I Oregon Solar Customers SIR- N/A N/A N/A
2 Macquarie Energy LLC AQ, WSPP N/A N/A N/A
3 Power Exchanges I 4 Benton Co Public Utility District #1 -
5 Bonneville Power Administration
6 NorthWestern Energy tom-
7 PaciflCorp Inc
8 Puget Sound Energy Inc -
9 Sierra Pacific Power Co dba NV Energ -
10 Utah Associated Municipal Power System WIV
11 Clatskanie PUD EX 153 - -
12 Sierra Pacific Power Co dba NV Energ EX WSPP
13 PaclflCorp Inc EX WSPP - -
14 Other Transactions
Total
FERC FORM NO 1 (ED 12-90) Page 32613
Name of Respondent This Report Is: Date of Report Year/Period of Report
Idaho Power Company I (1) An Original (Mo, Da, Yr) End of 2011/Q4
(2) A Resubmission 04/13/2012
PUhCHAS DFOWER(Account 555) (Continued) (Including power exchanges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5.For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (I) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7.Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8.The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9.Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
MegaWatt Hours MegaWatt Hours
______________
Demand Charges Energy Charges Other Charges Total (j+k+l) Purchased No
Received Delivered ($) ($) ($) of Settlement($)
(g) (h) (I) (j) (k) (I) (m)
106 3,375 3,375 1
5C 2,OOC 2,000 2
3
-
60,085 5
2,946 6
165,922 269,181 7
18 8
5,455 9
24 10
84,917 111,843 11
228,424 228,424
63,000 63,000
14
2,777,89E 602391) 680,849 2,815,12 1146,504,8391 7,553,79 156,873,74
FERC FORM NO. I (ED. 12-90) Page 327.13
Name of Respondent This Report Is: Date of Report Year/Period of Report
Idaho Power Company (1)EKIAn Original
(2)flA Resubmission
(Mo, Da, Yr)
04/1312012 End of 2011/04
PURCMAED POWER (Account 555) (Including power exchanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3.in column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
Average
Monthly NCP Demand
Average
Monthly CP Demand N 0. 'F Affiliations) (Footnote e ta ons, Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
1 Acct Valuation-Clatskanie PUD Exchange - - -
2 Write-Off (Lehman Brothers) - - -
3
4
5
6
7
8
9
10
11
12
13
14
Total
FERC FORM NO. I (ED 12-90) - Page 326.14 -
Name of Respondent J This Re ort Is: Date of Report Year/Period of Report
Idaho Power Company L 04/13/2012 End of 2011/04
PU CHA$ POWER(Account 555) (Continued) (Including power exchanges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5.For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7.Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. if more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8.The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9.Footnote entries as required and provide explanations following all required data.
Megawatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+I) Purchased No.
Received Delivered ($) ($) ($) of Settlement($)
(g) (h) (i) (j) (k) (I) (m) -
-716,681 -716,681 1
-30,800 -30,800 2
3
4
5
6
7
8
9
10
11
12
13
14
2,777,898f 602,391f 6808491 2,815,1241 146,504,839 7,553,786 156,873,74
FERC FORM NO. I (ED. 12-90) Page 327.14
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)_ A Resubmission 04/13/2012 20111Q4
FOOTNOTE DATA
SçPag
Schegul Lie
Unavailable
Column:f
Unavailable
Schedule Page 326.1Line No. :9 Column:e
Unavailable
Schedule Page., 326.1
Unavailable
Schedule Page: 326.2Line
Unavailable
--- ----- -----
Unavailable
Line No.: 9
No:4
----------
Column: f
Column: e
----------
- --------
Schedule Page: 326.2 Line No.:9
Non Firm Purchases
Column: b
Schedule Page: 326.2 Line No..: 12 Column: a ______
Schedule Page 3262 Line No14 Column a
Ida West, a_subsidiary of Idaho Power Company, has partial ownership of these projects.
Schedule Page: 326.4 Line No.: 5 Column: a
Ida West, a subsidiary of Idaho Power Company, has partial ownership of these projects.
Schedule Page: 326.4 Line No.: 14 Column: e -
Unavailable
Schedule Page: 326.4 Line No.: 14 Column: f
Unavailable _
Schedule Page: 326.5 Line &o€..-8 Column: b
Non Firm Purchases
Schedule Page: 326.5 Line No.: 11 Column: e
Unavailable
Schedule Page: 326.5 Line No.: 11 Column: f
Unavailable
Schedule Page: 326.6 Line No..: 6 Column: a
Ida West, a subsidiary of Idaho Power Company, has partial ownership of these projects.
Schedule Page: 326.6 Line No.: 7 Column: a
The Tamarack Energy Partnership demand readings
recorder provided by Idaho Power Co. The actual
of energy.
are taken from an electronic demand
demand is not used in determining the cost
cneauie Page: 326.6 Line No.: 7 Column: e
Unavailable
Schedule Page: 326.6 Line No.: 7 Column: f
Unavailable
Schedule Page: 326.6 Line No.: 8 Column: b
Non Firm Purchases
Schedule Page: 326.7 Line No.: 3 Column: a
Ida West, a subsidiary of Idaho Power Company, has partial ownership of these projects.
Schedule Page: 326.7 Line No.: 5 Column: b _______________________________
Energy scheduled in December 2910, booked in January 2011
cneciuie Page: 326.7 Line No.: 10 Column: b
Financial Transmission Losses
Schedule Page: 326.7 Line No.: 12 Column: b
ISDA Master Aareement with Barciav P,nk PlC HAtPH Mrr'h 7 Oflhl
rawv. ..JLV.Q L.IIt 'Vu.; 'C u:umn: 0
Non Firm Purchases
IFERC FORM NO I (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 04/13/2012 2011/Q4
FOOTNOTE DATA
Schedule Page: 326.8 Line No.: 8 Column: b -
ISDA Master Agreement with Citigroup Energy PLC dated March 7, 2-0- -1-1
Schedule Page: 326.9 Line N--o-.-:-6--- o.:6 Column: b
ISDA Master Agreement with JE Morgan Chase Bank dated November 4, 2005 Schedule Page: 326.9 LineNo.:7
Prudential Eache Commodities, LLC (Jefferies Bache) Futures Account Document, dated
September 4, 2008
gIe Page: .9Li17eNo.:10 inp_
ISDA Master Agreement with Macquarie Energy PLC dated April 12, 2011
Schedule Page: 326.9 Line No.: 12 Column: b ____ _____
Non Firm Purchases
Schedule Page: 326.10 Line No.:5 Column: b
Non Firm Purchases
Schedule Page: 326.10 Line No.:7 Column:b
Financial Transmission Losses
Schedule Page: 326.11 Line No.: 4 Column: b
Non Firm Purchases
Schedule Page: 326.11 Line No.: 10 Colurnn:b
ISDA Master Agreement with Shell Energy North America dated November1, 2009
Schedule Page: 326. 11 Line No.: 13 Column:b
Non Firm Purchases
vayqw. .)LU.II L.ItI IYU.. -14 i.oiumij: o
Financial Transmission Losses
Schedule Page: 326.12 Line No.: 10 Column: b
ISDA Master Agreement with Wells Fargo Bank,N.A., dated March 1,2006
Schedule Page: 326.12 Line No.: 12 Column:b
Unavailable
Schedule Page: 326.12 Line No.: 14 Column: b
Schedule 84 Net Metering
Schedule Page: 326.13 Line No.: I Column:
Schedule 88 Oregon Solar
Schedule Page: 326.13 Line No.: 2 Column: b
December 2010 _adjustment
Schedule Page: 326.13 Line No.:4 Column: b
Scheduled losses not removed with loss transactions
Schedule Page: 326.13 Line No.: 5 Column: b
Scheduled losses not removed with loss transactions
Schedule Page: 326.13 Line No.: 6 Column: b
Scheduled losses notremoved with loss transactions
Schedule Page: 326.13LineNo.: 7 Column: b
Scheduled losses not removed with loss transactions
Schedule Page: 326.13 Line No.:8 Column: b
Scheduled losses not removed with loss transactions
Schedule Page: 326.13 Line No.: 9
Scheduled losses not removed with loss transactions
Schedule Page: 326.13 Line No.: 10 Column: b
Scheduled losses not removed with loss transactions
IFERC FORM NO. I (ED. 12-87) Page 450.2
Name of Respondent
Idaho Power Company J
I This Re ort Is:
I (1) X An Original

(2) M Resubmission
I Date of Report I (Mo, Da, Yr)
J 04/13/2012
Year/Period of Report
n f 201 1/04
TRANSMlSION ELECTRICITY FOR OTHEIS (Account 4567) (Including transactions referred to as 'wheeling')
1.Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2.Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3.Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4.In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SEP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line
N
-
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 Bonneville Power Administration - OTEC Bonneville Power Administration Oregon Trails Electric Co-op FNO
2 Bonneville Power Administration - USBR Bonneville Power Administration United States Bureau of Redamati FNO
3 Bonneville Power Administration - Raft Bonneville Power Administration Raft River Electric Co-op FNO
4 Bonneville Power Administration - PF Bonneville Power Administration Priority Firm Customers FNO
5 Milner Irrigation District United States Bureau of Reclamati Milner Irrigation District OLF
6 Cargill Seattle City Light Bonneville Power Administration OS
7 1 PacrfiCorp PacifiCorp West PacifiCorp West FNO
8 United States Bureau of Indian Affairs Bonneville Power Administration United States Bureau of Indian Af OS
9 PacifiCorp PacifiCorp West PacifiCorp West OS
10 BC Hydro Powerex NorthWestem/PaciliCorp East PacifiCorp East NF
11 BC Hydro Powerex North Westem/PacifiCorp East Sierra Pacific Power NF
12 BC Hydro Powerex PacifiCorp East North Westem/PacifiCorp East NF
13 BC Hydro Powerex PacifiCorp East PacifiCorp East NF
14 BC Hydro Powerex PacifiCorp East PacifiCorp West NF
15 BC Hydro Powerex PaciflCorp East Bonneville Power Administration NF
16 BC Hydro Powerex PaciflCorp East Avista NF
17 BC Hydro Powerex PacifiCorp East Sierra Pacific Power NF
18 BC Hydro Powerex PacifiCorp East PacifiCorp West NF
19 BC Hydro Powerex North Westem/PacifiCorp East PacifiCorp East NF
20 BC Hydra Powerex North Westem/PacillCorp East PacifiCorp East SFP
21 BC Hydro Powerex North Westem/PacifiCorp East PacifiCorp East NF
22 BC Hydra Powerex NorthWestem/PacifiCorp East PacitICorp East SFP
23 BC Hydro Powerex North Westem/PadfiCorp East PacifiCorp West NF
24 BC Hydra Powerex North Westem/PacifiCorp East Bonneville Power Administration NF
25 BC Hydra Powerex North Westem/PacifiCorp East Sierra Pacific Power NF
26 BC Hydro Powerex North Westem/PacifiCorp East Sierra Pacific Power SFP
27 BC Hydra Powerex PacifiCorp East North Westem/PacifiCorp East NF
28 BC Hydro Powerex PacifiCorp East PacifiCorp East NF
29 BC Hydra Powerex PacifiCorp East North Westem/PacifiCorp East NF
30 BC Hydra Powerex PacifiCorp East PacifiCorp West NF
31 BC Hydro Powerex Pac,fiCorp East PacifiCorp West NF
32 BC Hydro Powerex PacifiCorp East Bonneville Power Administration NF
33 BC Hydra Powerex PacifiCorp East Avista NF
34 BC Hydra Powerex PacifiCorp East Sierra Pacific Power NF
TOTAL
FERC FORM NO. 1 (ED. 12-90) Page 328
Name of Respondent
Idaho Power Company
This Re ort Is:
(1)X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/13/2012
Year/Period of Report
End of 201 1/04
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
(Including transactions reffered to as 'wheeling)
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and U) the total megawatthours received and delivered.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(0
Point of Delivery
(Substation or Other
Designation)
(g)
Billing
Demand
(MW)
(h)
TRANSFER OF ENERGY Line
No. MegaWatt Hours
Received (i)
MegaWatt Hours
Delivered
U)
OMP 368,297 368,297, 1
5 189,508 189,501 2
5 205,046 205,041 3 _____ 5 _______________________ 907,088 907,081 4
10
Minidoka Idaho Various in Idaho 4_______________________________
OW 8,322 8,32, 5
388704 38870 6
5 ' 2,094 2,09, 7
LaGrande Oregon Vanous in Idaho 14,238 14,231 8
5
JBSN ENPR 9
AVATNWMT BORA 92 92 10
5 AVAT NWMT M345 30 39 11
5 BORA BPAT.NWMT 855 85 12
5 BORA BRDY 179 17! 13
5 BORA JBSN . 490 49 14
5 BORA LAGRANDE 9866 9,86 15
5 BORA LOLO 99 9q 16
5 BORA M345 3,546 3,54( 17
5 BORA M500 2,314 2,3V 18
5 BPAT NWMT BORA 3,310 3,31( 19
5 BPAT.NWMT BORA 3,688 3,68f 20
5 BPAT.NWMT BRDY 2,380 2,38 21
5 BPAT.NWMT BRDY 8,830 8,83! 22
5 BPAT.NWMT JBSN 95 9. 23
5 BPAT.NWMT ' LAGRANDE 397 391, 24
5 BPAT.NWMT M345 664 66 25
5 BPAT.NWMT M345 18,792 18,794 26
5 BRDY AVAT.NWMT 102 10A 27
5 BRDY BORA 260 26! 28
5 BRDY ' BPAT.NWMT 154 15 29
5 BRDY ENPR 80 8 30
5 BRDY JBSN 90 9 31
5 BRDY LAGRANDE 14,347 14,34 32
5 BRDY LOLO 10 ii 33
5 BRDY M345 2,386 2,38 34
0 6,092,2161 6,092,21
FERC FORM NO. 1 (ED. 12-90) Page 329
Name of Respondent
Idaho Power Company
This Re ott Is:
I (1) X An Original

(2) U Resubmission
I Date of Report I (Mo, Da, Yr) I 04/13/2012
Year/Period of Report
E 201 1/Q4 End d f
TRANSMISSION ELECTRICITY FOR OTHEIS (Account 456.1) (Including transactions referred to as 'wheeling')
1.Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2.Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3.Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4.In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line
No
-
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 BC Hydro Powerex PacillCorp East Sierra Pacific Power SFP
2 BC Hydro Powerex Paciflcorp East PaciflCorp West NF
3 BC Hydro Powerex PaciflCorp West PaciflCorp East NF
4 BC Hydro Powerex PaciflCorp West PacifiCorp East SFP
5 BC Hydro Powerex PaciflCorp West PaciflCorp East NF
6 BC Hydro Powerex PaciflCorp West PaciflCorp East SFP
7 BC Hydro Powerex PaciflCorp West PaciflCorp West NF
8 BC Hydro Powerex PaciflCorp West Sierra Pacific Power NF
9 BC Hydro Powerex PaclflCorp West Sierra Pacific Power SFP
10 BC Hydro Powerex North Westem/PaoflCorp East North Westem/PaciflCorp East NF
11 BC Hydro Powerex North Westem/PaciflCorp East North Westem/PaciflCorp East NF
12 BC Hydro Powerex North Westem/PaciflCorp East PaciflCorp East NF
13 BC Hydro Powerex North Westem/PaciflCorp East PaciflCorp West NF
14 BC Hydro Powerex NorthWestemlPacillCorp East PacifiCorp West NF
15 BC Hydro Powerex North Westem/PaciflCorp East North Westem/PaciflCorp East NF
16 BC Hydro Powerex North Westem/PaciflCorp East Bonneville Power Administration NF
17 BC Hydro Powerex North Westem/PaciflCorp East Sierra Pacific Power NF
18 BC Hydro Powerex North Westem/PaciflCorp East PacifiCorp West NF
19 BC Hydro Powerex Idaho Power Company North Westem/PaciflCorp East NF
20 BC Hydro Powerex Idaho Power Company Bonneville Power Administration NF
21 BC Hydro Powerex PaciflCorp West PacifiCorp East NE
22 BC Hydro Powerex PaciflCorp West North Westem/PaciflCorp East NE
23 BC Hydra Powerex PaciflCorp West Bonneville Power Administration NE
24 BC Hydro Powerex PaciflCorp West Sierra Pacific Power NE
25 BC Hydro Powerex Idaho Power Company PaciflCorp East NE
26 BC Hydro Powerex Idaho Power Company Bonneville Power Administration NE
27 BC Hydro Powerex Idaho Power Company PacifiCorp West NE
28 BC Hydra Powerex North Westem/PaciflCorp East PacifiCorp East NF
29 BC Hydra Powerex North Westem/PaciflCorp East PaciflCorp East NE
30 BC Hydro Powerex North Western/PacifiCorp East PaciflCorp West NE
31 BC Hydra Powerex North Western/PaciflCorp East PacifiCorp West NE
32 BC Hydra Powerex North Westem/PaciflCorp East Bonneville Power Administration NE
33 BC Hydro Powerex North Westem/PaciflCorp East Sierra Pacific Power NE
34 BC Hydro Powerex Bonneville Power Administration PacifiCorp East NE
TOTAL
FERC FORM NO 1 (ED 12 90) Page 328.1 I
Name of Respondent
Idaho Power Company
This Report Is:
(2) r_1 A Resubmission
Date of Report
04/13/2012
Year/Period of Report
End of 2011/04
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Conflnued) (Including transactions reffered to as 'wheeling)
5.In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6.Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7.Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8.Report in column (i) and U) the total megawatthours received and delivered.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(f)
Point of Delivery
(Substation or Other
Designation)
(g)
-Billing
Demand
(MW)
TRANSFER OF ENERGY Line
No.
(h)
MegaWatt Hours
Received
MegaWatt Hours
Delivered
5 BRDY M345 1,848 1,841 1
5 BRDY M500 1,281 1,28' 2
5 ENPR BORA 219,615 21961 3
5 ENPR BORA 1,433 1,43 4
5 ENPR BRDY 19,008 19,006 5
5 ENPR BRDY 3,642 3,642 6
5 ENPR JBSN 211 211 7
5 ENPR M345 1,127 1,127 8
5 ENPR M345 32 32 9
5 GSHN AVAT.NWMT 10 11 10
5 GSHN BPAT.NWMT 523 52 11
5 GSHN BRDY 667 667 12
5 GSHN ENPR 83 & 13
5 GSHN JBSN 544 544 14
5 GSHN JEFF 35 3,r 15
5 GSHN LAGRANDE 10,167 10,161 16
5 GSHN M345 579 571 17
5 GSHN M500 796 791 18
5 HCPR BPAT.NWMT 149 14f 19
5 HCPR LAGRANDE 3,056 3,051 20
5 JBSN BORA 20 21 21
5 JBSN BPAT NWMT 31' 31 22
5 JBSN LAGRANDE 2,947 2,941 23
5 JBSN M345 138 131 24
5 JBWT BORA 35 3 25
5 JBWT LAGRANDE 1,448 1,441 26
5 JBWT M500 127 127 27
5 JEFF BORA 6,317 6,317 28
5 JEFF BRDY 746 746 29
5 JEFF ENPR 53 53 30
5 JEFF JBSN 881 8131
5 JEFF LAGRANDE 400 40( 32
5 JEFF M345 103 10 33
5 LAGRANDE BORA 54,378 54,371 34
0 6,092,216 6,092,211
FERC FORM NO. 1 (ED. 12-90) Page 329.1
Name of Respondent
Idaho Power Company
This RMA oil Is:
I (1) An Original i (2) Resubmission
f Date of Report
I (Mo, Da, Yr)
04/13/2012
Year/Period of Report
n E f 2011/04
TRANSMISSION OF ELECTRICITY FOR OTHES (Account 456.1) (Including transactions referred to as 'wheeling')
1.Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2.Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3.Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4.In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, ENS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLE - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line
No
-
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 BC Hydro Powerex Bonneville Power Administration PacifiCorp East SFP
2 BC Hydro Powerex Bonneville Power Administration PaciflCorp East NF
3 BC Hydro Powerex Bonneville Power Administration PaciflCorp East SFP
4 BC Hydro Powerex Bonneville Power Administration PaciflCorp West NF
5 1 BC Hydro Powerex Bonneville Power Administration Sierra Pacific Power NF
6 BC Hydro Powerex Bonneville Power Administration Sierra Pacific Power SFP
7 BC Hydro Powerex Avista PaciflCorp East NF
8 BC Hydro Powerex Avista PacifiCorp East NF
9 BC Hydro Powerex Avista PacifiCorp West NF
10 1 BC Hydro Powerex Avista Sierra Pacific Power NF
11 BC Hydro Powerex Sierra Pacific Power North Westem/PacifiCorp East NF
12 BC Hydro Powerex Sierra Pacific Power PacifiCorp East NF
13 BC Hydro Powerex Sierra Pacific Power Bonneville Power Administration NF
14 BC Hydro Powerex Idaho Power Company North WestemlPacitlCorp East NF
15 1 BC Hydro Powerex Idaho Power Company Bonneville Power Administration NF
16 1 BC Hydro Powerex Idaho Power Company North Westem/PacifiCorp East NF
17 BC Hydro Powerex Idaho Power Company Bonneville Power Administration NF
18 Black Hills Power PacifiCorp East Sierra Pacific Power NF
19 Black Hills Power PacifiCorp West Bonneville Power Administration NF
20 Black Hills Power Bonneville Power Administration PacifiCorp East NF
21 Black Hills Power Bonneville Power Administration PacifiCorp West NF
22 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration NF
23 Bonneville Power Administration Bonneville Power Administration Sierra Pacific Power NF
24 Bonneville Power Administration Avista Bonneville Power Administration NF
25 Bonneville Power Administration Avista Bonneville Power Administration SFP
26 Bonneville Power Administration Avista Sierra Pacific Power NF
27 Cargill-Alliant PacifiCorp East NorthWestem/PacifiCorp East NF
28 Cargill-Alliant PacifiCorp East NorthWestem/PacifiCorp East NF
29 Cargill Alliant PacifiCorp East PacifiCorp West NF
30 Cargill-Alliant PaciflCorp East PacifiCorp West NF
31 Cargill-Alliant PacifiCorp East Bonneville Power Administration NF
32 Cargill Alliant PacifiCorp East Avista NE
33 Cargill-Alliant PacifiCorp East Sierra Pacific Power NF
34 Cargill Alliant PacifiCorp East Sierra Pacific Power SFP
TOTAL
FERC FORM NO. I (ED. 12-90) Page 328.2
Name of Respondent
Idaho Power Company
This Report Is:
8AResubmission
Date of Report Year/Period of Report
End of 201 1 1Q4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 4567confinued)
(Including transactions reffered to as 'wheeling')
5.In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6.Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7.Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8.Report in column (i) and (j) the total megawatthours received and delivered.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(f)
Point of Delivery
(Substation or Other
Designation)
(g)
Billing
Demand
(MW)
(h)
TRANSFER OF ENERGY Line
No.
-
MegaWatt Hours
Received (i)
MegaWatt Hours
Delivered U)
5 LAGRANDE BORA 799 79 1
5 LAGRANDE BRDY 12,461 12461 2
5 LAGRANDE BRDY 2,482 248 3
5 LAGRANDE JBSN 1,847 1,841 4
5 LAGRANDE M345 11,056 1 i,o-,;q 5
5 LAGRANDE M345 373 37 6
5 LOLO BORA 11,424 11 42 7
5 LOLO BRDY 1,165 1,161 8
5 LOLO JBSN 168 16 9
5 LOLO M345 3,569 3,56 10
5 M345 BPAT.NWMT 132 13 11
5 M345 BRDY 80 8 12
5 M345 LAGRANDE 2,001 2,00'11 13
5 MDSK BPAT NWMT 175 17 14
5 MDSK LAGRANDE 1,272 1,27' 15
5 OBBLPR BPAT NWMT 204 20A 16
5 OBBLPR LAGRANDE 1,738 1,731 17
5 BORA M345 2,250 2,25( 18
5 JBSN LAGRANDE 10 11 19
5 LAGRANDE BORA 25 2! 20
5 LAGRANDE JBSN 60 61 21
5 LAGRANDE LAGRANDE 3,005 3,001 22
5 LAGRANDE M345 1,542 1,54 23
5 LOLO LAGRANDE 7,115 7,111 24
5 LOLO LAGRANDE 768 761 25
5 LOW M345 324 32d 26
5 BORA AVAT.NWMT 525 521 27
5 BORA BPAT.NWMT 1,420 1,421 28
5 BORA ENPR 820 821 29
5 BORA JBSN 996 991 30
5 BORA LAGRANDE 10,089 10,08l 31
5 BORA ILOLO 249 241 32
5 BORA M345 8,416 8,411 33
5 BORA M345 4,153 4,15 34
11 6,092,21e 6,092,211
FERC FORM NO. I (ED. 12-90) Page 329.2
Name of Respondent - - - This RA
A
ort Is: I Date of Report I Year/Period of Report I (1)An Original (Mo, Da, Yr) End of 20111Q4 Idaho Power Company (2) Resubmission 04/13/2012
(Including transactions referred to as 'wheeling')
1.Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2.Use a separate fine of data for each distinct type of transmission service involving the entities fisted in column (a), (b) and (C).
3.Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (C) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4.In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Payment By
(Company of Public Authority) O (Footnote Affiliation)
(a)
1 I Cargill-Alliant
2 Cargill-Alliant
3 Cargill-Alliant
4 Cargill-Alliant
5 Cargill-Alliant
6 Cargill-Alliant
7 Cargill-Alliant
8 Cargill-Alliant
9 Cargill-Alliant
10 Cargill-Alliant
11 Cargill-Alliant
12 Cargill-Alliant
13 Cargill-Alliant
14 Cargill-Alliant
15 Cargill-Alliant
16 Cargill-Alliant
17 Cargill-Alliant
18 Cargill-Alliant
19 Cargill-Alliant
20 Cargill-Alliant
21 Cargill-Alliant
22 Cargill-Alliant
23 Cargill-Alliant
24 Cargill-Alliant
25 Cargill-Alliant
26 Cargill-Alliant
27 Cargill-Alliant
28 Cargill-Alliant
29 Cargill-Alliant
30 Cargill-Alliant
31 Cargill-Alliant
32 Cargill-Alliant
33 Cargill-Alliant
34 Cargill-Alliant
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
North Westem/PaciflCorp East
North Westem/PaciflCorp East
North Westem/PaciflCorp East
North Westem/PacifiCorp East
North Westem/PacifiCorp East
North Westem/PacillCorp East
North Westem/PaciflCorp East
North Westem/PaciflCorp East
PaciilCorp East
PaciflCorp East
PadflCorp East
PaciflCorp East
PaciflCorp East
PacilICorp East
PaciflCorp East
PacifiCorp West
PaciflCorp West
PaciflCorp West
PaciflCorp West
Idaho Power Company
Idaho Power Company
Idaho Power Company
PaciflCorp West
PacifiCorp West
PaciflCorp West
PacifiCorp West
NorthWestern/PaciflCorp East
North Westem/PaciflCorp East
Bonneville Power Administration
Bonneville Power Administration
Bonneville Power Administration
Bonneville Power Administration
Bonneville Power Administration
Bonneville Power Administration
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
PaciflCorp East
PaciflCorp East
PaciflCorp East
PaciflCorp West
PactflCorp West
Bonneville Power Administration
Sierra Pacific Power
Sierra Pacific Power
PaciflCorp East
PacifiCorp East
PacifiCorp West
Bonneville Power Administration
Bonneville Power Administration
Sierra Pacific Power
Sierra Pacific Power
PacifiCorp East
PaciflCorp East
Sierra Pacific Power
Sierra Pacific Power
PacifiCorp East
Sierra Pacific Power
Sierra Pacific Power
North Westem/PacifiCorp East
Bonneville Power Administration
Sierra Pacific Power
Sierra Pacific Power
PacifiCorp East
Sierra Pacific Power
PacifiCorp East
PaciflCorp East
PaciflCorp West
Avista
Sierra Pacific Power
Sierra Pacific Power
Classifi-
cation
(d)
NF
SFP
NF
NF
SFP
NF
NF
SFP
NF
SFP
NF
NF
SFP
NE
SFP
NF
SFP
NF
SFP
SFP
NF
SFP
NF
NE
NE
SEP
SEP
NE
NE
SEP
NE
NE
NE
SEP
FERC FORM NO. I (ED. 12-90) Page 328.3
I
Name of Respondent
Idaho Power Company
This Report Is:
(2) M A Resubmission
Date of Report
04/13/2012
Year/Period of Report
End of 201 1/Q4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
(Including transactions reffered to as 'wheeling')
5.In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6.Report receipt and delivery locations for all single contract path, point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7.Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8.Report in column (i) and (j) the total megawatthours received and delivered.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(f)
Point of Delivery
(Substation or Other
Designation)
(g)
Billing
Demand
(MW)
(h)
TRANSFER OF ENERGY Line
No.
-
MegaWatt Hours
Received (i)
MegaWatt Hours
Delivered U)
5 BPAT NWMT BORA 2,651 2,651 1
5 BPAT NWMT BORA 33,899 3389 2
5 BPAT NWMT BRDY 25 2 3
5 BPAT.NWMT JBSN 440 44 4
5 BPAT NWMT JBSN 1,200 1,20( 5
5 BPAT.NWMT LAGRANDE 5 1 6
5 BPAT.NWMT M345 2,791 2,791 7
5 BPAT NWMT M345 43,719 43,71q 8
5 BRDY BORA 322 324 9
5 BRDY BORA 504 504 10
5 BRDY ENPR 63 63 11
5 BRDY LAGRANDE 112 112 12
5 BRDY LAGRANDE 600 600 13
5 BRDY M345 932 931 14
5 BRDY M345 64 &15
5 ENPR BORA 69,699 69,691 16
5 ENPR BORA 60,810 60,811 17
5 ENPR M345 8,765 8,761 18
5 ENPR M345 1,392 1,39, 19
5 HCPR BORA 400 401 20
5 HCPR M345 800 801 21
5 HCPR M345 1,600 1,601 22
5 JBSN BPAT.NWMT 3,200 3,201 23
5 JBSN LAGRANDE 148 141 24
5 JBSN M345 592 591 25
5 JBSN M345 408 401 26
5 JEFF BORA 320 321 27
5 JEFF M345 928 921 28
5 LAGRANDE BORA 2,34€ 2,341 29
5 LAGRANDE BORA 1,454 1,451 30
5 LAGRANDE JBSN 306 30 31
5 LAGRANDE LOLO 2381 23 32
5 LAGRANDE M345 11,4821 11,481 33
5 LAGRANDE M345 17,606 1760434
0 6,092,216 6,092,214
FERC FORM NO. I (ED. 12-90) Page 329.3
Name of Respondent
Idaho Power Company
This Roil Is:
1) X An Original
(2) A Resubmission
Date of Report
04/13/2012 L (Mo, Da, Yr)
Year/Period of Report
End of 2011 /Q4
TRANSMI ION ELECTRICITY FOR OThE S (Account 456.1)
(Including transactions referred to as 'wheeling')
1.Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2.Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3.Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4.In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLE - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NE - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line
N C)
-
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 Cargill-Alliant Avista PaciflCorp East NF
2 Cargill-Ailiant Avista Sierra Pacific Power NF
3 Cargill-Alliant Sierra Pacific Power PacifiCorp East NF
4 Cargill-Alliant Sierra Pacific Power PacifiCorp East SFP
5 Cargill-Alliant Sierra Pacific Power NorthWestem/PacifiCorp East NF
6 Cargill-Alliant Sierra Pacific Power PacifiCorp East NF
7 Cargill-Alliant Sierra Pacific Power NorthWestem/PacifiCorp East NF
8 Cargill Alliant Sierra Pacific Power Bonneville Power Administration NE
9 1 Cargill-Alliant Sierra Pacific Power Bonneville Power Administration SEP
10 Cargill-Alliant Sierra Pacific Power Avista NE
11 Cargill-Alliant Sierra Pacific Power Avista SFP
12 Cargill-Alliant Sierra Pacific Power Sierra Pacific Power NF
13 Cargill-AIliant Sierra Pacific Power Sierra Pacific Power SFP
14 Cargill-Alliant Sierra Pacific Power Bonneville Power Administration NF
15 Cargill-Alliant Idaho Power Company Avista NF
16 Cargill-Alliant Idaho Power Company PacifiCorp East NE
17 Cargill Alliant Idaho Power Company PaciflCorp East SFP
18 Cargill Alhant Idaho Power Company Bonneville Power Administration NF
19 Cargill-Alhant Idaho Power Company Bonneville Power Administration SFP
20 Cargill-Alliant Idaho Power Company Sierra Pacific Power NF
21 Cargill-Alliant Idaho Power Company Sierra Pacific Power SFP
22 Citigroup Energy NF
23 lberdrola Energy PacifiCorp East Bonneville Power Administration NE
24 Iberdrola Energy PacifiCorp East Bonneville Power Administration NE
25 lberdrola Energy PacifiCorp East Sierra Pacific Power NF
26 lberdrola Energy Bonneville Power Administration PacifiCorp East NF
27 lberdrola Energy Bonneville Power Administration Sierra Pacific Power NF
28 lberdrola Energy Avista Sierra Pacific Power NF
29 lberdrola Energy Sierra Pacific Power Bonneville Power Administration NF
30 Morgan Stanley Capital Group NorthWestem/PacifiCorp East PacifiCorp East NP
31 Morgan Stanley Capital Group North Westem/PaafiCorp East PacifiCorp East NF
32 Morgan Stanley Capital Group North Western/PacifiCorp East Bonneville Power Administration NF
33 1 Morgan Stanley Capital Group North Westem/PacifiCorp East Sierra Pacific Power NF
34 Morgan Stanley Capital Group PacifiCorp East Bonneville Power Administration NF
TOTAL
FERC FORM NO. 1 (ED. 12-90) Page 328.4
Name of Respondent
Idaho Power Company
This Re ort Is:
2"Rs sion
Date of Report
04/13/2012
Year/Period of Report
End of 2011/04
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued) (Including transactions reffered to as 'wheeling)
5.In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6.Report receipt and delivery locations for all single contract path, point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7.Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8.Report in column (I) and U) the total megawatthours received and delivered.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Desgnabon)
(f)
Point of Delivery
(Substation or Other
Designation)
(g)
Billing
Demand
(MW)
(h)
TRANSFER OF ENERGY Line
No.
-
MegaWatt Hours
Received (i)
MegaWatt Hours
Delivered
U)
5 LOLO BORA 1,142 1,14, 1
5 LOLO M345 5,988 5,98f 2
5 LYPK BORA 10,724 10,7241 3
5 LYPK BORA 37,726 37721 4
5 LYPK BPAT NWMT 1,563 1,561 5
5 LYPK BRDY 667 66A 6
5 LYPK JEFF 173 17 7
5 LYPK LAGRANDE 14,243 1424 8
5 LYPK LAGRANDE 1,664 1,6& 9
5 LYPK LOLO 100 10( 10
5 LYPK LOLO 200 204 11
5 LYPK M345 64,772 64,77 12
5 LYPK M345 243,254 243,25 13
5 M345 LAGRANDE 275 279 14
5 MDSK LOLO 200 20( 15
5 OBBLPR BORA 1,000 1,00( 16
5 OBBLPR BORA 1,000 1,00 17
5 OBBLPR LAGRANDE 410 41 18
5 OBBLPR LAGRANDE 1,808 1,80E 19
5 OBBLPR M345 320 32 20
5 OBBLPR M345 480 48 21
5 -
5 BORA LAGRANDE 361 361 23
5 BRDY LAGRANDE 54 57 24
5 BRDY M345 24 24 25
5 LAGRANDE BORA 5,027 5,027 26
5 LAGRANDE M345 4,104 4,104 27
5 LOLO M345 380 381 28
5 M345 LAGRANDE 381 381 29
5 AVAT.NWMT BORA 544 54A 30
5 AVAT.NWMT BRDY 140 141 31
5 AVAT.NWMT LAGRANDE 132 131 32
5 AVAT.NWMT M345 3,663 3,66: 33
5 BORA LAGRANDE 66 61 34
__ 0 6,092,216 6,092,211
FERC FORM NO. I (ED. 12-90) Page 329.4
/
Name of Respondent
Idaho Power Company
This Report Is:
I (1)[]An Original
I (2)flA Resubmission
I Date of Report I (Mo, Da, Yr)
04/13/2012
Year/Period of Report
En i 2011/04
TRANSMISION UF ELECTRICITY FOR OTI-tEtS (Account 456.1)
(Including transactions referred to as 'wheeling')
1.Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2.Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (C).
3.Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4.In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - npn-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line
N
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 Morgan Stanley Capital Group PaciflCorp East Sierra Pacific Power NF
2 Morgan Stanley Capital Group North Westem/PacifiCorp East PacifiCorp East NF
3 Morgan Stanley Capital Group NorthWestem/PacifiCorp East PaciflCorp East NF
4 Morgan Stanley Capital Group North Westem/PaciflCorp East Bonneville Power Administration NF
5 Morgan Stanley Capital Group North Westem/PacifiCorp East Sierra Pacific Power NF
6 Morgan Stanley Capital Group PaciflCorp East NorthWestem/PaciflCorp East NF
7 Morgan Stanley Capital Group PaciflCorp East PaciflCorp East NF
8 Morgan Stanley Capital Group PacfllCórp East NorthWestem/PacifiCorp East NF
9 Morgan Stanley Capital Group PaciflCorp East PaciflCorp West NF
10 Morgan Stanley Capital Group PaciflCorp East Bonneville Power Administration NF
11 Morgan Stanley Capital Group PaciflCorp East Avista NF
12 Morgan Stanley Capital Group PadflCorp East Sierra Pacific Power NF
13 Morgan Stanley Capital Group PaciflCorp East Sierra Pacific Power SFP
14 Morgan Stanley Capital Group PaciflCorp West Pac,fiCorp East NF
15 Morgan Stanley Capital Group PaciflCorp West Sierra Pacific Power NF
16 Morgan Stanley Capital Group PaciflCorp West Bonneville Power Administration NF
17 Morgan Stanley Capital Group PaciflCorp West Sierra Pacific Power NF
18 Morgan Stanley Capital Group North Westem/PaciflCorp East PaciflCorp East NF
19 Morgan Stanley Capital Group NorthWestem/PaciflCorp East PaciflCorp East NF
20 Morgan Stanley Capital Group North Westem/PaciflCorp East PaciflCorp West NF
21 Morgan Stanley Capital Group North Westem/PaciflCorp East Bonneville Power Administration NF
22 Morgan Stanley Capital Group North Westem/PaciflCorp East Avista NF
23 Morgan Stanley Capital Group North Westem/PaciflCorp East Sierra Pacific Power NF
24 Morgan Stanley Capital Group Bonneville Power Administration PaciflCorp East NF
25 Morgan Stanley Capital Group Bonneville Power Administration PaciflCorp East NF
26 Morgan Stanley Capital Group Bonneville Power Administration PaciflCorp West NF
27 Morgan Stanley Capital Group Bonneville Power Administration PaciflCorp West NF
28 Morgan Stanley Capital Group Bonneville Power Administration Sierra Pacific Power NF
29 Morgan Stanley Capital Group Avista PadflCorp East NF
30 Morgan Stanley Capital Group Avista PaciilCorp East NP
31 Morgan Stanley Capital Group Avista Bonneville Power Administration NF
32 Morgan Stanley Capital Group Avista Sierra Pacific Power NF
33 Morgan Stanley Capital Group Sierra Pacific Power North Westem/PaciflCorp East NF
34 Morgan Stanley Capital Group Sierra Pacific Power Bonneville Power Administration NF
TOTAL
FERC FORM NO. I (ED. 12-90) Page 328.5
Name of Respondent - -
Idaho Power Company
This Report Is:
(2) F~ A Resubmission
Date of Report (Mo, Da, Yr)
04113/2012
Year/Period of Report
End of 201 1/Q4
TRANSMISSION OF ELTRICITY FOR OThERS (Account 456XContinued) (Induding transactions reffered to as 'wheeling')
5.In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6.Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7.Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8.Report in column (I) and (j) the total megawatthours received and delivered.
FERC Rate
Schedule of
Tariff Number
Point of Receipt
(Subsatation or Other
Designation)
Point of Delivery
(Substation or Other
Designation)
Billing
Demand
(MW)
TRANSFER OF ENERGY uiie
No. MegaWatt Hours
Received
MegaWatt Hours
Delivered
5 BORA M345 8,522 8,522 1
5 BPAT NWMT BORA 371 371 2
5 BPAT.NWMT BRDY 1,237 1,237 3
5 BPAT NWMT LAGRANDE 210 211 4
5 BPAT NWMT M345 756 751 5
5 BRDY AVAT.NWMT 46 41 6
5 BRDY BORA 62 6, 7
5 BRDY BPAT.NWMT 119 11 8
5 BRDY JBSN 99 9' 9
5 BRDY LAGRANDE 19,275 19,27 10
5 BRDY LOLO 100 lOt 11
5 BRDY M345 8,148 8,141 12
5 BRDY M345 1,981 1 ,98 13
5 ENPR BRDY 1 ,128 1121 14
5 ENPR M345 180 181 15
5 JBSN LAGRANDE 20 21 16
5 JBSN M345 29 2' 17
5 JEFF BORA 5,996 5,991 18
5 JEFF BRDY 6,680 6681 19
5 JEFF JBSN 250 251 20
5 JEFF LAGRANDE 5,698 5,691 21
5 JEFF LOLO 60 6( 22
5 JEFF M345 21,705 21,701 23
5 LAGRANDE BORA 3,085 3,081 24
5 LAGRANDE BRDY 8,183 8,181 25
5 LAGRANDE ENPR 5 26
5 LAGRANDE JBSN 65 6 27
5 LAGRANDE M345 2,075 2,07 28
5 LOLO BORA 2,335 2,33 29
5 LOLO BRDY 2,292 2,292 30
5 LOLO LAGRANDE 411 411 31
5 ILOLO M345 1,983 1,983 32
5 IM345 JEFF ill 11133
5 M345 LAGRANDE 1,597 1,597j 34
________________________ 0 6,092,21 ' 6,092,21
FERC FORM NO. I (ED. 12-90) Page 329.5
Name of Respondent
Idaho Power Company I
I This Re ort Is:
(1)X An Original
(2)[]A Resubmission
I Date of Report I (Mo, Da, Yr) I 04/13/2012
Year/Period of Report
End of 2011/Q4
TRANSMISION UF ELECTRICITY FOR OTHEIS (Account 456.1)
(Including transactions referred to as 'wheeling')
1.Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2.Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3.Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4.In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or true-ups for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See Genera! Instruction for definitions of codes.
Line
N
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifl-
cation
(d)
I Noble Americas NF
2 Paciflcorp Power Marketing PacthCorp East PacifiCorp West NF
3 Pacificorp Power Marketing Paciflcorp East NorthWestem/PaciflCorp East SFP
4 Paaflcorp Power Marketing PaciflCorp East Idaho Power Company NF
5 Paciflcorp Power Marketing PaciflCorp East Idaho Power Company LFP
6 Pacificorp Power Marketing PaciflCorp East Bonneville Power Administration NF
7 Paciflcorp Power Marketing PaciflCorp East Sierra Pacific Power NF
8 Pacificorp Power Marketing PaciflCorp East Sierra Pacific Power SFP
9 Paciflcorp Power Marketing PaciflCorp East PaciflCorp East NF
10 Pacificorp Power Marketing PaciflCorp West PacifiCorp East NF
11 Paciflcorp Power Marketing PaciflCorp West Bonneville Power Administration NF
12 Paciflcorp Power Marketing PacifiCorp West PaciflCorp East NF
13 Pacificorp Power Marketing Idaho Power Company PaciflCorp East LFP
14 Paciflcorp Power Marketing Idaho Power Company PacifiCorp East NF
15 PacifIcorp Power Marketing Idaho Power Company PaciflCorp East LFP
16 Paciflcorp Power Marketing Idaho Power Company PacifiCorp West NF
17 Paciflcorp Power Marketing Idaho Power Company Bonneville Power Administration NF
18 Paciflcorp Power Marketing Idaho Power Company PaciflCorp West LFP
19 Paciflcorp Power Marketing Bonneville Power Administration PaciflCorp East NF
20 Paciflcorp Power Marketing Avista PaciflCorp East NF
21 Paciflcorp Power Marketing Avista PacifiCorp West NF
22 Portland General Electric North Westem/PaciflCorp East Bonneville Power Administration NF
23 PPL Energy Plus PacifiCorp East PacifiCorp East NF
24 PPL Energy Plus PaciflCorp East PaciflCorp West NF
25 PPL Energy Plus PaciflCorp East Bonneville Power Administration NF
26 PPL Energy Plus PacifiCorp East Avista NF
27 PPL Energy Plus North Westem/PaciflCorp East PaciflCorp East NF
28 PPL Energy Plus North Westem/PaciflCorp East PacifiCorp East NF
29 PPL Energy Plus NorthWestem/PaciflCorp East PacifiCorp West NF
30 PPL Energy Plus North Westem/PacifiCorp East Bonneville Power Administration NF
31 PPL Energy Plus Bonneville Power Administration PaciflCorp East NF
32 PPL Energy Plus Bonneville Power Administration PaciflCorp East NF
33 PPL Energy Plus Bonneville Power Administration PacifiCorp West NF
34 PPL Energy Plus Avista PaciflCorp East NF
TOTAL
FERC FORM NO. I (ED. 12-90) Page 328.6
I
Name of Respondent
Idaho Power Company
This Re ort Is:
X An Origin
Date of Report
04/13/2012
Year/Period of Report
End of 2011/Q4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456xContinued) (Including transactions reffered to as 'wheeling')
5.In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6.Report receipt and delivery locations for all single contract path, point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7.Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8.Report in column (i) and (j) the total megawatthours received and delivered.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(f)
Point of Delivery
(Substation or Other
Designation)
(g)
Billing
Demand
(MW)
(h)
TRANSFER OF ENERGY Line
No. MegaWatt Hours
Received
(I)
MegaWatt Hours
Delivered
5 0 0 1
5 BORA ENPR 8,014 8,014 2
5 BORA GSHN 3,740 3,74C 3
5 BORA KPRT 390,968 390,9613 4
5 BORA KPRT 403,551 403,551 5
5 IBORA LAGRANDE 1,621 1,621 6
5 BORA M345 2,285 2,281 7
5 BORA M345 4,032 4,032 8
5 BRDY BRDY 1,616 1,61E 9
5 ENPR BORA 29,752 29,752 10
5 ENPR LAGRANDE 682 682 11
5 JBSN BORA 2,675 2,67E 12
5 JBWT BORA 61,027 61,02-11 13
5 JBWT BRDY 54,685 54,68E 14
5 IJBWT BRDY 381,175 381,17E 15
5 JBWT ENPR 1,153 1,152 16
5 JBWT LAGRANDE 4,211 4,211 17
5 JBWT M500 906,776 906,771 18
5 LAGRANDE BORA 37,083 37,08'.
5 LOLO BORA 95,641 95,641 20
5 LOLO ENPR 921 921 21
5 JEFF LAGRANDE 580 581 22
5 BRDY BORA 724 721 23
5 BRDY JBSN 150 1 24
5 BRDY LAGRANDE 5,514 5,51 , 25
5 BRDY LOLO 964 961 26
5 JEFF BORA 79 7 27
5 JEFF BRDY 2,086 2,08 28
5 JEFF JBSN 420 42 29
5 JEFF LAGRANDE 1,259 1,25E 30
5 LAGRANDE BORA 526 52 31
5 LAGRANDE BRDY 216 21i 32
5 ILAGRANDE JBSN 60 61 33
5 LOLO BORA 495 49 34
0 6,092,216 6,092,214
FERC FORM NO. I (ED. 12-90) Page 329.6
Name of Respondent
Idaho Power Company
This RM
A
ort Is:
j (1) An Original

(2) Resubmission
Date of Report
(Mo, Da, Yr)
04/13/2012
Year/Period of Report
End of 2011/Q4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as 'wheeling')
1.Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2.Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3.Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4.In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line
N C)
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
I PPL Energy Plus Avista PaciflCorp East NF
2 PPL Energy Plus Avista Bonneville Power Administration NF
3 Puget Sound Energy PaciliCorp East Bonneville Power Administration NF
4 Puget Sound Energy North Westem/PacifiCorp East Bonneville Power Administration NF
5 1 Puget Sound Energy North Westem/PacifiCorp East Bonneville Power Administration NF
6 Puget Sound Energy Bonneville Power Administration Sierra Pacific Power NF
7 Puget Sound Energy Avista Idaho Power Company NF
8 Rainbow Energy Marketing PacifiCorp East North Westem/PacifiCorp East NF
9 Rainbow Energy Marketing PacifiCorp East NorthWestem/PacifiCorp East NF
10 Rainbow Energy Marketing North Westem/PaciflCorp East PacifiCorp East SFP
11 Rainbow Energy Marketing NorthWestem/PacifiCorp East PacifiCorp East SFP
12 Rainbow Energy Marketing PacifiCorp East Sierra Pacific Power NF
13 Rainbow Energy Marketing PaciflCorp East Sierra Pacific Power SFP
14 Rainbow Energy Marketing PaciflCorp West PacifiCorp East NF
15 Rainbow Energy Marketing PadfiCorp West PadfiCorp East SFP
16 Rainbow Energy Marketing PacifiCorp West PacifiCorp East SFP
17 Rainbow Energy Marketing North Westem/PacifiCorp East PacifiCorp East NF
18 Rainbow Energy Marketing NorthWestem/PacifiCorp East PacifiCorp East SFP
19 Rainbow Energy Marketing North Westem/PacifICorp East PacifiCorp East N
20 Rainbow Energy Marketing North Westem/PaciflCorp East PacifiCorp East SFP
21 Rainbow Energy Marketing North Westem/PacifiCorp East Sierra Pacific Power NF
22 Rainbow Energy Marketing North Westem/PacifiCorp East Sierra Pacific Power SFP
23 Rainbow Energy Marketing Avista PacifiCorp East NF
24 Rainbow Energy Marketing Avista PaciliCorp East SFP
25 Rainbow Energy Marketing Avista PacifiCorp East NF
26 Rainbow Energy Marketing Avista PacifiCorp East SFP
27 Rainbow Energy Marketing Avista Sierra Pacific Power NF
28 Rainbow Energy Marketing Avista Sierra Pacific Power SFP
29 Rainbow Energy Marketing Idaho Power Company PacifiCorp East NF
30 Seattle City Light LFP
31 Shell Energy PacifiCorp East Bonneville Power Administration NF
32 Shell Energy PacifiCorp East PacifiCorp East NF
33 1 Shell Energy PacifiCorp East Bonneville Power Administration NF
34 Shell Energy PaciflCorp East Sierra Pacific Power NF
r TOTAL
FERC FORM NO. I (ED. 12-90) Page 328.7
I
I
Name of Respondent
Idaho Power Company
This Report Is:
(2) R A Resubmission
Date of Report
04/13/2012
Year/Period of Report
End of 201 1/Q4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456XContinued) (Including transactions reffered to as 'wheeling)
5.In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6.Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7.Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8.Report in column (I) and (j) the total megawatthours received and delivered.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(I)
Point of Delivery
(Substation or Other
Designation)
(g)
Billing
Demand
(MW)
(h)
TRANSFER OF ENERGY Line
No. MegaWatt Hours
Received (I)
MegaWatt Hours
Delivered
5 LOLO BRDY 150 15C 1
5 LOLO LAGRANDE 937 937, 2
5 BRDY LAGRANDE 180 18 3
5 GSHN LAGRANDE 155 15E 4
5 JEFF LAGRANDE 15 1 5
5 LAGRANDE M345 134 134 6
5 LOLO IPCOLOSS 1 1 7
5 BORA AVAT NWMT 200 20' 8
5 BORA JEFF 800 80 9
5 BPAT NWMT BORA 13,760 1376' 10
5 BPAT.NWMT BRDY 16,074 16,07 11
5 BRDY M345 172 17 12
5 BRDY M345 2,081 2,08' 13
5 ENPR BRDY 1,623 1,62" 14
5 ENPR BRDY 348 341 15
5 JBSN BRDY 1,568 1,561 16
5 JEFF BORA 7,980 798 17
5 JEFF BORA 8,109 8,10 18
5 JEFF BRDY 40 4 19
5 JEFF BRDY 4,093 409 20
5 JEFF M345 505 509 21
5 JEFF M345 23,673 23,67 22
5 LOLO BORA 9,934 9,93 23
5 LOLO BORA 2,501 2,501 24
5 LOLO BRDY 3,017 3,01 25
5 LOLO BRDY 1,050 1,05C 26
5 LOLO M345 400 40 27
5 LOLO M345 2,250 2,25C 28
5 OBBLPR BRDY 400 40C 29
5 0 0 30
5 BORA LAGRANDE 25 2 31
5 BRDY BORA 1921 19 32
5 JBRDY ILAGRANDE 5,375 5,37 33
5 BRDY M345 468 461 34
0 6,092,216 6,092,211
FERC FORM NO. I (ED. 12-90) Page 329.7
Name of Respondent
Idaho Power Company i
This RA
A
ort Is:
I (1) An Original

(2) Resubmission
I Date of Report
I (Mo, Da, Yr)
04/13/2012
Year/Period of Report
201 11Q4 nu Oi
TRANSMISSION ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as 'wheeling)
1.Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2.Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3.Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4.In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line
N0.
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 Shell Energy North Westem/PacifiCorp East PacifiCorp East NF
2 Shell Energy NorthWestern/PaciflCorp East Bonneville Power Administration NF
3 Shell Energy Bonneville Power Administration PacifiCorp East NF
4 Shell Energy Bonneville Power Administration Sierra Pacific Power NF
5 Shell Energy Avista PacifiCorp East NF
6 Shell Energy Sierra Pacific Power PaciflCorp East NF
7 Shell Energy Sierra Pacific Power PacifiCorp East NF
.8 Shell Energy Sierra Pacific Power Bonneville Power Administration NF
9 Shell Energy Sierra Pacific Power PacifiCorp East NF
10 Shell Energy Sierra Pacific Power PacifiCorp East NF
11 Shell Energy Sierra Pacific Power Bonneville Power Administration NF
12 Shell Energy Sierra Pacific Power Avista NF
13 Shell Energy Idaho Power Company PacifiCorp East NF
14 Shell Energy Idaho Power Company Bonneville Power Administration NF
15 Shell Energy Idaho Power Company Avista NF
16 Shell Energy Idaho Power Company PacifiCorp East NF
17 Shell Energy Idaho Power Company Bonneville Power Administration NF
18 Sierra Pacific Power Marketing PaciflCorp East Sierra Pacific Power NF
19 Sierra Pacific Power Marketing PacifiCorp East Sierra Pacific Power SFP
20 Sierra Pacific Power Marketing PacifiCorp East Sierra Pacific Power NF
21 Sierra Pacific Power Marketing PacifiCorp East Sierra Pacific Power SFP
22 Sierra Pacific Power Marketing NorthWestem/PaciflCorp East Sierra Pacific Power NF
23 Sierra Pacific Power Marketing North Westem/PacifiCorp East Sierra Pacific Power SFP
24 Sierra Pacific Power Marketing Bonneville Power Administration Sierra Pacific Power NF
25 Sierra Pacific Power Marketing Bonneville Power Administration Sierra Pacific Power SFP
26 Sierra Pacific Power Marketing Avista PacifiCorp East NF
27 Sierra Pacific Power Marketing Avista Sierra Pacific Power NF
28 Sierra Pacific Power Marketing Avista Sierra Pacific Power SFP
29 Sierra Pacific Power Marketing Sierra Pacific Power PacifiCorp East NF
30 Sierra Pacific Power Marketing Sierra Pacific Power NorthWestem/PacifiCorp East NF
31 Sierra Pacific Power Marketing Sierra Pacific Power Bonneville Power Administration NF
32 Sierra Pacific Power Marketing Sierra Pacific Power Avista NF
33 Southern California Edison NorthWestem/PaciflCorp East Bonneville Power Administration NF
34 Tenaska North Westem/PacifiCorp East PacifiCorp East NF
TOTAL
FERC FORM NO 1 (ED 12-90) Page 328.8
Name of Respondent
Idaho Power Company
This Re ort Is:
X An Original
Date of Report Year/Period of Report
End of 2011 /Q4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 4s6XContinued) (Including transactions reffered to as 'wheeling')
5.In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6.Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (1), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7.Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8.Report in column (i) and U) the total megawatthours received and delivered.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(0
Point of Delivery
(Substation or Other
Designation)
(g)
Billing
Demand
(MW)
(h)
TRANSFER OF ENERGY Line
No.
-
MegaWatt Hours
Received
(I)
MegaWatt Hours
Delivered
U)
5 JEFF BORA 200 20C 1
S JEFF LAGR.ANDE 77 77 2
5 LAGRANDE BORA 13 1 3
5 LAGRANDE M345 2,231 2,231 4
5 LOLO BORA 25 25
5 LYPK BORA 12 14 6
5 LYPK BRDY 50 5( 7
5 LYPK LAGRANDE 174 17 8
5 M345 BORA 180 18( 9
5 M345 BRDY 100 10( 10
5 M345 LAGRANDE 3,533 3,53 11
5 M345 LOLO 68 6112
5 MDSK BORA 400 400 13
5 MDSK LAGRANDE 541 541 14
5 MDSK LOLO 17 17 15
5 OBBLPR BORA 300 30C 16
5 OBBLPR LAGRANDE 67 6j 17
5 BORA M345 6,360 6,361 18
5 BORA M345 9,140 9,141 19
5 BRDY M345 11,800 11,80( 20
5 BRDY M345 31,608 31,60E 21
5 JEFF M345 42,409 42,401 22
5 JEFF M345 11,141 11,141 23
5 LAGRANDE M345 34,496 34,494 24
5 LAGRANDE M345 4,325 4,321 25
5 LOLO BORA 48 41 26
5 LOLO M345 35,267 35,26-11 27
5 LOLO M345 7,424 7,421 28
5 M345 BORA 1,082 1,081 29
5 M345 JEFF 185 181 30
5 M345 LAGRANDE 3,4581 3,451 31
5 M345 LOLO 225 221 32
5 GSHN LAGRANDE 125 12 33
5 AVAT.NWMT BRDY 95 91 34
0 6,092,216 6,092,21
FERC FORM NO. 1 (ED. 12-90) Page 329.8
Name of Respondent
Idaho Power Company
This Re ort Is: L I Date of Report Year/Period of Report
End of 2011/04
TRANSMI ION P ELECTRICITY FOR OTHE S (Account 456.1)
(Induding transactions referred to as 'wheeling')
1.Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2.Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3.Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4.In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line
No
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 Tenaska North Westem/PaciflCorp East PaciflCorp East NF
2 Tenaska Bonneville Power Administration PaciflCorp East NF
3 Tenaska Bonneville Power Administration PacifiCorp East NF
4 Tenaska Bonneville Power Administration PacifiCorp West NF
5 The Energy Authority PaciflCorp East Bonneville Power Administration NF
6 Transalta Energy Marketing PacitlCorp East Bonneville Power Administration NF
7 Transalta Energy Marketing NorthWestem/PaciflCorp East PaciflCorp East NF
8 Transalta Energy Marketing NorthWestem/Paciticorp East PacifiCorp East NF
9 Transalta Energy Marketing PacifiCorp East Bonneville Power Administration NF
10 Transalta Energy Marketing NorthWestem/PaciflCorp East PaciflCorp East NF
11 Transalta Energy Marketing Bonneville Power Administration PacifiCorp East NF
12 Transalta Energy Marketing Bonneville Power Administration PacifiCorp East NF
13 Transalta Energy Marketing Bonneville Power Administration Sierra Pacific Power NF
14 Transalta Energy Marketing Avista PacifiCorp East NF
15 Transalta Energy Marketing Avista PacifiCorp East NF
16 Transalta Energy Marketing Sierra Pacific Power Bonneville Power Administration NF
17 Trarisalta Energy Marketing Idaho Power Company PacifiCorp East NF
18 Transafta Energy Marketing Idaho Power Company Bonneville Power Administration NF
19 Utah Associated Municipal Power PaciliCorp East Sierra Pacific Power NF
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
TOTAL
FERC FORM NO I (ED 12-90) Page 3289
I
Name of Respondent
Idaho Power Company
This Re ort Is:
gAResubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of 2011/04
TRANSMISSION OF ELECTRICITY FOR OTHERS(Account 4s6XContinued)
(Including transactions reffered to as 'wheeling')
5.In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6.Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7.Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8.Report in column (i) and (j) the total megawatthours received and delivered.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(f)
Point of Delivery
(Substation or Other
Designation)
(9)
Billing
Demand
(MW)
(h)
TRANSFER OF ENERGY Line
No. MegaWatt Hours
Received (i)
MegaWatt Hours
Delivered
5 BPAT NWMT BRDY 398 396 1
5 LAGRANDE BORA 1,274 1,27, 2
5 LAGRANDE BRDY 1,290 1,29( 3
5 LAGRANDE JBSN 265 26 4
5 BRDY LAGRANDE 30 31 5
5 BORA LAGRANDE 706 701 6
5 BPAT NWMT BORA 25 2 7
5 BPAT NWMT BRDY 75 71 8
5 BRDY LAGRANDE 300 301 9
5 JEFF BORA 25 2 10
5 LAGRANDE BORA 6,588 6,58f 11
5 LAGRANDE BRDY 1,066 1,06E 12
5 LAGRANDE M345 488 48q 13
5 LOLO BORA 513 511 14
5 LOLO BRDY 28 21 15
5 M345 LAGRANDE 398 39E 16
5 OBBLPR BORA 50 5' 17
5 OBBLPR LAGRANDE 48 4f 18
5 BORA M345 648 64f 19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
0 6,092,216 6,092,21 -
FERC FORM NO.1 (ED. 12-90) Page 329.9
Name of Respondent
Idaho Power Company
This Re rt Is:
(1)Original -
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/13/2012
Year/Period of Report
End of 20111Q4
TRANSMISSION
(Including OF EL CTRICITY FOR OTHERS (Account 456) (Continued) transactions reffered to as 'wheeling')
9.In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in Column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10.The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11.Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(I)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Line
No.
-
1,414,450 39,800 1,454,250 1
1,163,226 201,793 1,365,019 2
535,470 18,160 553,630 3
3,193,659 -205,841 2,987,818 4
13,482 13,482 5
208,649 208,649 6
7,475 1,362 8,837 7
54,639 54,639 8
2,395 2,395 9
387 387 10
126 126 11
3,601 3,601 12
754 754 13
2,064 2,064 14
41,551 41,551 15
417 417 16
14,934 14,934 17
9,745 9,745 18
13,940 13,940 19
15,532 15,532 20
10,023 10,023 21
37,188 37,188 22
400 400 23
1,672 1,672 24
2,796 2,796 25
79,143 79,143 26
430 430 27
1,095 1,095 28
649 649 29
337 337 30
379 379 31
60,423 60423 32
42 4233
10,049 10,049 34
6,368,919 13,003,985 0 19,372,904
FERC FORM NO. I (ED. 12-90) Page 330
Name of Respondent
Idaho Power Company
This Re oil Is:
(2) F1 A Resubmission
Date of Report
04/13/2012
Year/Period of Report
End of 2011/04
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued) (Including transactions reffered to as 'wheeling')
9.In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10.The total amounts in columns (i) and (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
($)
(k)
Energy Charges
($)
(I)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Line
No.
7,783 7,783 1
5,395 5,395 2
924,914 924,914 3
6,035 6,035 4
80,053 80,053 5
15,338 15,338 6
889 889 7
4,746 4,746 8
135 135 9
42 4210
2,203 2,203 11
2,809 2,809 12
350 350 13
2,291 2,291 14
147 147 15
42,819 42,819 16
2,438 2,438 17
3,352 3,352 18
628 628 19
12,870 12,870 20
84 8421
152 152 22
12,411 12,411 23
581 581 24
147 147 25
6,098 6,098 26
535 535 27
26,604 26,604 28
3,142 314229
223 223 30
371 371 31
1,6851 1,685 32
434 434 33
229,014 229,014 34
6,368,919 13,003,985 0 19,372,904
FERC FORM NO. I (ED. 12-90) Page 330.1
Name of Respondent -
Idaho Power Company
This Mort Is:
Original Date of Report Year/Period of Report
End of 201 1/Q4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued) (Including transactions reffered to as 'wheeling')
9.In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10.The total amounts in columns (i) and (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
(8)
(k)
Energy Charges
(8)
(I)
(Other Charges)
(8)
(m)
Total Revenues ($)
(k+l+m)
(n)
Line
No.
-
3,365 3,365 1
52,480 52,480 2
10,453 10,453 3
7,779 7,779 4
46,563 46,563 5
1,571 1,571 6
48,112 48,112 7
4,906 4,906 8
708 708 9
15,031 15,031 10
556 55611
337 337 12
8,427 8,427 13
737 737 14
5,357 5,357 15
859 859 16
7,320 7,320 17
5,535 5,535 18
25 2519
61 6120
148 148 21
12,137 12,137 22
6,228 6,228 23
28,738 28,738 24
3,102 3,102 25
1,309 1,309 26
312 312 27
844 84428
487 487 29
592 592 30
5,998 5,998 31
148 148 32
5,003 5,003 33
2,469 2,469 34
6,368,919 13,003,985 0 19,372,904
FERC FORM NO. 1 (ED. 12-90) Page 330.2
Name of Respondent
Idaho Power Company
This RP
A
ort Is:
Resubmission
Date of Report
0432
Year/Period of Report
End of 201 11Q4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
(Including transactions reffered to as 'wheeling')
9.In column (k) through (ri), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10.The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11.Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(I)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Line
No.
-
1,576 1,576 1
20,153 20,153 2
15 153
262 262 4
713 713 5
3 36
1,659 16597
25,991 25,991 8
191 191
300 300 10
37 3711
67 6712
357 357 13
554 554 14
38 3815
41,436 41,436 16
36,151 36,151 17
5,211 5,211 18
828 828 19
238 238 20
476 476 21
951 951 22
1,902 1,902 23
88 8824
352 352 25
243 243 26
190 190 27
552 552 28
1,395 1,395 29
864 864 30
182 182 31
141 141 32
6,826 6,826 33
10,467 10,467 34
6,368,919 13,003,985 0 19,372,904
FERC FORM NO. 1 (ED. 12-90) Page 330.3,
Name of Respondent
Idaho Power Company
This Re ort Is:
(2) M A Resubmission
Date of Report
04/13/2012
Year/Period of Report
End of 2011/Q4
TRAJ'JSMJSSION OF EL&TRICITY FOR OTHERS (Account 456) (Continued) (Including transactions reffered to as 'wheeling')
9.In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10.The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11.Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(I)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
CIiI
No.
679 679 1
3,560 3,560 2
6,375 6,375 3
22,428 22,428 4
929 929 5
397 397 6
1031 103 7
8,467 8,467 8
989 989 9
59 5910
119 119 11
38,507 38,507 12
144,613 144,613 13
163 163 14
119 119 -Th
594 594 16
594 594 17
244 24418
1,075 1,075 19
190 190 20
285 285 21
4 422
1,246 1,246 23
197 197 24
83 8325
17,356 17,356 26
14,169 1416927
1,312 1,312 28
1,315 1,315 29
1,937 1,937 30
498 498 31
470 470 32
13,042 13,042 33
235 235 34
6,368,919 13,003,985 0 19,372,904
FERC FORM NO. I (ED. 12-90) Page 330.4
Name of Respondent This Report Is: Date of Report Year/Period of Report
Idaho Power Company (1) ff]An Original (Mo, Da, W) End of 201 1/Q4 (2) r_J A Resubmission 04/13/2012
TRANSMISSION OF ELTRICITY FOR OTHERS (Account 456) (Continued) (Including transactions reffered to as 'wheeling)
9.In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10.The total amounts in columns (I) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11.Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges) Total Revenues ($)
($) ($) ($) (k+I+m) No.
(k) (I) (m) (n) -
30,342 30,342 1
1,321 1,321 2
4,404 4,404 3
748 748 4
2,692 2,692 5
164 164 6
221 221 7
424 424 8
352 352 9
68,628 68,628 10
356 356 11
29,011 29,011 12
7,053 7,053 13
4,016 4,016 14
641 641 15
71 7116
103 10317
21,348 21,348 18
23,784 23,784 19
890 89020
20,287 20,287 21
214 214 22
77,280 77,280 23
10,984 10,984 24
29,135 29,135 25
18 1826
231 231 27
7,388 7,388 28
8,314 8,314 29
8,161 8,161 30
1,4631 1,463 31
7,0601 7,060 32
406 406 33
5,686 5,686 34
6,368,919 13,003,985 0 19,372,904
FERC FORM NO. I (ED. 12-90) Page 330.5
Name of Respondent
Idaho Power Company
This Re ort Is:
(2) M A Resubmission
Date of Report
04/13/2012
Year/Period of Report
End of 201 1/Q4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
(Including transactions reftered to as 'wheeling')
9.In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10.The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11.Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(I)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Line
No.
4 4 1
27,861 27,861 2
13,002 13,002 3
1,359,206 1,359,206 4
5
5,635 5,635 6
7,944 7,944 7
14,017 14,017 8
5,618 5,618 9
103,433 103,433 10
2,371 2,371 11
9,300 9,300 12
212,161 212,161 13
190,113 190,113 14
1,325,161 1,325,161 15
4,008 4,008 16
14,640 14,640 17
3,152,421 3,152,421 18
128,920 128,920 19
332,497 332,497 20
3,202 3,202 21
1,311 1,311 22
2,275 227523
471 471 24
17,329 17,329 25
3,030 3,030 26
248 248 27
6,556 6,556 28
1,320 1,320 29
3,957 3,957 30
1,653 165331
679 679 32
189 189
1556 1556 134
6,368,919 13,003,985 0 19,372,904
FERC FORM NO. I (ED. 12.90) Page 330.6
I
Name of Respondent
Idaho Power Company
I This Report Is:
2nRtssion
Date of Report
04/13/2012
Year/Period of Report
End of 201 1/Q4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
(Including transactions reffered to as 'wheeling')
9.In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10.The total amounts in columns (I) and (j) must be reported as Transmission, Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11.Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(I)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Line
No.
-
471 471 1
2,945 2,945 2
2,137 21373
1,841 1,841 4
178 178 5
1,591 1,591 6
12 127
513 513 8
2,052 2,052 9
35,296 35,296 10
41,232 41,232 11
441 44112
5,338 533813
4,163 416314
893 893 15
4,022 402216
20,470 20,470 17
20,801 20,801 18
103 103 19
10,499 10,499 20
1,295 1,295 21
60,724 60,724 22
25,482 25,482 23
6,415 6,415 24
7,739 7,739 25
2,693 2,693 26
1,026 1,026 27
5,772 5,772 28
1,026 1,026 29
1,984,377 1,984,377 30
90 90 - 31
6911 691 32
19,347 19,347 33
1,685 1,685 34
6,368,919 13,003,985 0 19,372,904
FERC FORM NO. I (ED. 12-90) Page 330.7
Name of Respondent -
Idaho Power Company
This Re ii Is:
(1) x
AResubmission
Date of Report
04/13/2012
YearlPenod of Report
End of 2011/Q4
TRANSMISSION OF EL TRICITY FOR OTHERS (Account 456) (Continued) (Including transactions reffered to as 'wheeling')
9.In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10.The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11.Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(I)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+I+m)
(n)
Line
No.
-
720 720 1
277 277 2
47 473
8,031 8,031 4
90 90
43 436
180 180 7
626 626 8
648 648 9
360 360 10
12,717 12,717 11
245 245 12
1,440 1,440 13
1,947 1,947 14
61 6115
1,080 1,080 16
241 241 17
19,046 19,046 18
27,371 27,371 19
35,336 35,336 20
94,653 94,653 21
126,998 126,998 22
33,363 33,363 23
103,302 103,302 24
12,952 12,952 25
144 14426
105,610 105,610 27
22,232 22,232 28
3,240 3,240 29
554 554 30
10,355 10,355 31
674 674 32
500 500 33
345 345__
6,368,919 13,003,985 0 19,372,904
FERC FORM NO I (ED 1290) - Page 3308
Name of Respondent
Idaho Power Company
This Re ort Is:
2nR,tssiOn
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of 2011/Q4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued) (Including transactions reffered to as 'wheeling')
9.In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10.The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11.Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(I)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Line
No.
-
1,444 11,444 1
4,621 4,621 2
4,679 4,679 3
961 961 4
68 685
3,444 3,444 6
122 122 7
366 366 8
1,464 14649
122 122 10
32,139 32,139 11
5,200 5,200 12
2,381 2,381 13
2,503 2,503 14
137 137 15
1,942 1,942 16
244 24417
234 234 18
3,188 3,188 19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
6,368,919 13,003,985 0 19,372,904
FERC FORM NO. I (ED. 12-90) Page 330.9
THIS PAGE INTENTIONALLY LEFT BLANK
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Idaho Power Company (2)- A Resubmission 04/13/2012 201 11Q4
FOOTNOTE DATA
ScheduIePge 328 LineNol Colu rnne - - -
5, Open Access Transmission Tariff, Volume 5, first revision
Schedule Page: 328 Line No.: I Column: h
The network service agreement between Idaho Power and the Bonneville Power Administration
for the Oregon Trail Electric Cooperative expires September 30, 2028. 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 Paae: 328 Line No.: 2 Column: h
The network service agreement between Idaho Power and the Bonneville Power Administration
for the USBR expires December 31, 2014. The billing demand for network service is the
customer's demand at the time of Idaho Power Company transmission system peak and varies
by month.
Schedule Page: ji8 Line No.: 3 Column: - --
The network service agreement between Idaho Power and the Bonneville Power Administration
for Raft River expired 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 Pam. 328 Line No.: 4 Column: h
The network service agreement between Idaho Power and the Bonneville Power Administration
for the Priority Firm Customers expires September 20, 2028. 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.: 5 Column:e
Legacy, contract prior to the Open Access Transmission Tariff
Schedule Page 328 Line No 5 Column: h ____
The contract between Idaho Power and the Mimer Irrigation District expires December 31,
2012.
Schedule Page 328 Line No 6 Column h
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
rnnn ci hi m Fn-r nxrrncnt-
$chedule Page: 328 Line No.: 7 Column: h
The contract between Idaho Power and PacifiCorp - Imnaha expires on March 31, 2016 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 e
Legacy, contract prior to the Open Access Transmission Tariff
Schedule Page 328 Line No 8 Column h
The agreement between Idaho Power and the United States Department of the Interior, Bureau
of Indian Affairs is subject to termination upon 90 days written notice by the Bureau.-
Schedule Page 328 Line No.: 9 Column e
contract prior to the Open Access Transmission Tariff --
Schedule Page 3286 Line No 5 Column h
Legacy agreement providing OATT-like service, but billed under 454 Facilities revenue
(FERC FORM NO I (ED 12-87) Page 450.1
Name of Respondent ThisReport Is: Date of Report Year/Period of Report
Idaho Power Company (1)I3flAn Original (Mo, Da, Yr) i.....i nu 01 2011/04
(2)D A Resubmission 04/13/2012
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
(including transactions referred to as "wheeling")
1.Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public
authorities, qualifying facilities, and others for the quarter.
2.In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3.In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SEP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4.Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5.Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the
demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all
other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all
components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no
monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement,
including the amount and type of energy or service rendered.
6.Enter "TOTAL" in column (a) as the last line.
7.Footnote entries and provide explanations following all required data.
Line TRANSFER OF ENERGY EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERt
No. Name of Company or Public
Authority Affiliations) (Footnote
Statistical
Classification
Magwatt- Malatt- Demand Energy Cha Total Cost of
Transssion
- (a) (b)
Reoed
(c)
DeIived
(d) (e) ($ (f) ($
(g) (h)
1 Avista Corp-WWP Div NF 21,503 21,503 138,336 138,336
2 Avista Corp-WWP Div SFP 274,437 274.437 1,473,302 1473,302
3 OS
Os
36582 36582
447 447
5 Bonneville Power Admin NF 1,700 1,700 8,011 8,011
6 Bonneville Power Admin 286,453 286,453 1,195,392 1,195,392
7 Bonneville Power Admin 30,404 30,404
8 Bonneville Power Admin SEP 330 330
9 Cargill Power Markets SEP 4 4 144 144
10 Northwestern Energy 20,710 20,710 199,600 199,600
11 NorthWesem Energy SEP 45,995 45,995 818,047 818,047
12
PacifiCorp Inc
-205,566 -205,566
13
ONF

8,720 8,720 759,375 759,375
14 PacitiCorp Inc. 34,690 34,690 194,002 194,002
it
PaciflCorp Inc.
Os -21,949 -21,949
16 SFP 46,666 46,666 649,815 649,815
TOTAL 1,287,651 1,287,651 1,425,396 5,499,661 -462,953 6,462,104
FERC FORM NO. 113-Q (REV. 02-04)
Name of Respondent This Report Is: Date of Report Year/Period of Report
Idaho Power Company (1)JAIi Original (Mo, Da, Yr) End of 2011/04
(2)A Resubmission 04/1312012
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
(Including transactions referred to as "wheeling")
1.Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public
authorities, qualifying facilities, and others for the quarter.
2.In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3.In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4.Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5.Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the
demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all
other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all
components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no
monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement,
including the amount and type of energy or service rendered.
6.Enter "TOTAL" in column (a) as the last line.
7.Footnote entries and provide explanations following all required data.
Line TRANSFER OF ENERGY EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHER
No. Name of Company or Public
Authority (Footnote Affiliations)
Statistical
Classification
MahgaWatt•. ours Received
Maawatt- hg ours Demaria Cha ($r?
Energy
($?
Chaes ($r?
Total Cost of
ran o Delivered (a) (b) (c) (d) (e) (f) (g) (h
1 OS 75143 75143
2 SFP 361,028 361,028 911 ,685 911,685
05 -124,160 -124,160 3 Powerex Corp.
4 Puget Sound Energy, Inc SFP 600 600 750 750
5 Seattle City Light SFP 182,876 182,876 527,869 527,869
6 Sierra Pacific Power Co NF 2,269 2,269 17,995 17,995
7
8
9
10
11
12
13
14
15
16
TOTAL 1,287,651 1,287,651 1,425,396 5,499,661 462,953 6,462,104
FERC FORM NO. 113-Q (REV. 02-04) Page 332.1
THIS PAGE INTENTIONALLY LEFT BLANK
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)_A Resubmission 04/13/2012 201 1/Q4
FOOTNOTE DATA
Schedule Page 332 Line No3 Column :a -
Resale Transmission
Schedu 332Lin olumn
Reserves Provided
a
Schedule Page 332 Line No6__Column_b
Contract Expiration Date 09/30/2016
Schedule PageLmeNo7oIu
Contract Expiration Date 07/16/2011
,Schedule g332 Line No 10
Contract can be terminated at anytime, with 30 days_priol notice ___
'Schedule a
Resale Transmission
Schedule Page 332 Line No 13 Column
Contract Expiration-Date 05/31/2014
Schedule Pa33_ejo.: 15 Column: a
Unreserved Usage Distribution
Schedule Page 3321 Line No I Columa_
Resale Transmission
Schedule Page 3321 Line No 2 Column :a
Resale Transmission
IFERC FORM NO I (ED 12-87) Page 450.1 I
Name of Respondent This ReDort Is:
Idaho Power Company
Date of Report (Mo, Da, Yr) Year/Period of Report
End of 201 1/Q4
- MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line Description
(a)
Amount
(b)
I Industry Association Dues 405,549
2 Nuclear Power Research Expenses
3 Other Experimental and General Research Expenses
4 Pub & Dist Info to Stkhldrs ... expn servicing outstanding Securities 268,796
5 0th Expn -5,000 show purpose recipient amount Group if < $5,000
6 Richard Dahl 81,340
7 Christine King 69,097
8 Gary Michael 129,360
9 Richard Reiten 58,974
10 Joan Smith 75,162
11 Jan Packwood 54,390
12 Judith Johansen 70,719
13 Thomas Wilford 66,240
14 Robert Tintsman 71,520
15 Stephen Afired 67,757
16
17 Chamber of Commerce & Other Civic Organizations 104,397
18
19 Associated Taxpayers of Idaho 22,000
20 Corporate Executive Board 46,750
21 Idaho Association of Commerce & Industry 14,000
22 Idaho Association of Counties 1,000
23 Idaho Mining Association 6,000
24 Idaho Technology Council 10,000
25 National Association of Directors 4,950
26 Northwest Power Pool 91,722
27 Pacific Northwest Utilities 2,000
28 Western Electricity Coordinating Council 828,246
29 Western Energy Institute 26,095
30 Wyoming Taxpayers Association 1,590
31 Misc Memberships under $1,000 (3) 900
32
33 Misc General Management
34 Moody's Analytics Inc 28,832
35 New York Stock Exchange 52,067
36 Port Of Morrow
37 1 Pr Newswire 14,063
38
39
40
41
42
43
44
45
46 TOTAL 3,7501211
FERC FORM NO. I (ED. 12-94) Paqe 335
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)_ A Resubmission 04/13/2012 201 1/04
FOOTNOTE DATA
Recipient Purpose
American Stock Transfer & Trust Transfer & Fees
Bank Of New York Port of Morrow
Broadbridge Financial Solutions Proxy & Bulletin
Deutsche Bank Broker Fees
E Source Mgmt Services
Stock Based Compensation Stock Expense
Thomson Financial Analyst Service
Wells Fargo Transfer & fees
Rate Related Amortization Misc Expense
Business Plus Misc Expense
Total
Amount
$ 57,412
6,593
49,858
34,952
23,340
432,000
104,855
125,464
230,655
6,000
$1,071,130
IFERC FORM NO I (ED 12-87) Page 4501 I
Name of Respondent This Report Is: Date of Report Year/Period of Report
Idaho Power Company (1)An Original (Mo, Da, Yr) End 0 2011/Q4
(2)D A Resubmission 04/13/2012
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Account 403, 404, 405)
(Except amortization of aquisition adjustments)
1.Report in section A for the year the amounts for: (b) Depreciation Expense (Account 403; (c) Depreciation Expense for Asset
Retirement Costs (Account 403.1; (d) Amortization of Limited-Term Electric Plant (Account 404); and (e) Amortization of Other Electric
Plant (Account 405).
2.Report in Section 8 the rates used to compute amortization charges for electric plant (Accounts 404 and 405). State the basis used to
compute charges and whether any changes have been made in the basis or rates used from the preceding report year.
3.Report all available information called for in Section C every fifth year beginning with report year 1971, reporting annually only changes
to columns (c) through (g) from the complete report of the preceding year.
Unless composite depreciation accounting for total depreciable plant is followed, list numerically in column (a) each plant subaccount,
account or functional classification, as appropriate, to which a rate is applied. Identify at the bottom of Section C the type of plant
included in any sub-account used.
In column (b) report all depreciable plant balances to which rates are applied showing subtotals by functional Classifications and showing
composite total. Indicate at the bottom of section C the manner in which column balances are obtained. If average balances, state the
method of averaging used.
For columns (c), (d), and (e) report available information for each plant subaccount, account or functional classification Listed in column
(a). If plant mortality studies are prepared to assist in estimating average service Lives, show in column (1) the type mortality curve
selected as most appropriate for the account and in column (g), if available, the weighted average remaining life of surviving plant. If
composite depreciation accounting is used, report avaHable information called for in columns (b) through (g) on this basis.
4.If provisions for depreciation were made during the year in addition to depreciation provided by application of reported rates, state at
the bottom of section C the amounts and nature of the provisions and the plant items to which related.
A. Summary of Depreciation and Amortization Charges
- Depreciation Amortization of
Line Deoredation Expense for Asset Limited Term Amortization of
0. Functional Classification Expense Retirement Costs Electric Plant Other Electric Total
(Account 403) (Account 403.1) (Account 404) Plant (Ace 405) - (a) (b) (c) (d) (e) (f)
I Intangible Plant 6,764,513 6,764,513
2 Steam Production Plant 18,914,566 18,914,566
3 Nuclear Production Plant
Hydraulic Production Plant-Conventional 15,504,618 15,504,618
5 Hydraulic Production Plant-Pumped Storage
6 Other Production Plant 4,926,750 4,926,750
7 Transmission Plant 17,667,549 17,667,549
8 Distribution Plant 43,735,020 43,735,020
9 Regional Transmission and Market Operation
10 General Plant 12,549,538 12,549,538
11 Common Plant-Electric -296,299 -296,299
12 TOTAL 113,001,742 6,764,513 119,766,255
- B. Basis for Amortization Charges
Account 404 - Basis used to compute charges:
Balance to be Balance to be Remaining
Amortized 2011 Amortized months of
1/1/2011 Amortization 12/31/2011 Amort 12/31/11
(1)24,000 12,000 12,000 12
(2)12,521,781 545,446 11,976,335 -
(3)17,132,308 5,911,223 18,068,415 -
(4)4,899,594 287,899 4,611,695 204
(5)227,990 7,945 225,899 336
Total 34,805,673 6,764,513 34,894,344
(1)Shoshone-Bannock Tribe License & Use Agreement (Termination date December 31, 2023).
(2)Middle Snake Relicensing Costs (Amortized over a 30 year license period).
(3)Computer Software packages (Amortized over a 60 month period from date of purchase).
(4)Shoshone-Bannock Right of Way (Termination date December 31, 2028).
(5)Boardman Retrofit Tech Analysis (Termination date December 31,2040)
FERC FORM NO. 1 (REV. 12-03) Page 336
Name of Respondent
Idaho Power Company
This Re ort Is:
2'ssion
Date of Report Year/Period of Report
End of 2011/04
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line
N0. Account No.
(a)
Depreciable
Plant Base
(In Thousands)
(b)
Estimated
Avg. Service
Life
(c)
Net
Salvage
(Percent)
(d)
Applied
Depr. rates
(Percent)
(e)
Mortality
Curve
Type (f)
Average
Remaining
Life
(9)
12 310.20 633 75.00 4.16 R4.0 21.80
13 311.00 143,759 100.00 -10.00 1.54 S1.0 23.30
14 312.10 81,207 60.00 -7.00 1.68 R3.0 22.60
15 312.20 484,069 70.00 -5.00 2.17 R1.5 22.30
16 312.30 4,208 25.00 20.00 2.57 R3.0 12.20
17 314.00 150,651 50.00 -5.00 2.50 S0.5 20.30
18 315.00 60,126 65.00 -7.00 6.24 S1.5 22.20
1931600 13,265 5000 500 593 R05 2080
2031610 92 1000 2500 813L25 760
21 31640 241 1000 2500 952 L25
22 316.50 83 10.00 25.001 5.94 L2.5 8.20
2331660 106 1900 2500 369 S20 1200
2431670 80 1900 2500 388 S20 1670
25 316.80 1,300 16.00 30.00 14.29 S0.0 9.30
2631690 14 3000 2500 199 S1.5 2110
2731700 8,005
28 Subtotal Steam 947,839
29331.00 156,227 10000 2500 271 R2.5 32.10
3033210 19,461 9000 2000 227 S40 2720
31 332.20 227,957 90.00 -20.00 2.22 S4.0 29.80
32332.30 5,472 2.87 SQUARE 2860
33 333.00 197,921 8000 -5.00 1.91 R3.0 33.00
34 334.00 45,851 50.00 -5.00 3.00 R1.5 25.30
35335.00 18,534 90.00 2.11 R2.0 3050
36335.10 60 15.00 1.70 SQUARE 12.30
37335.20 364 2000 3.53 SQUARE 10.70
38 335.30 124 5.00 13.89 SQUARE 2.00
39 336.00 8,112 75.00 1.94 R3.0 30.40
40 Subtotal Hydro 680,086
41 341.00 7,169 35.00 3.02 SQUARE 30.40
42 342.00 4,446 35.00 2.75 SQUARE 32.40
43 343.00 98,952 35.00 2.98 SQUARE 29.70
44 344.00 31,682 35.00 2.54 SQUARE 33.80
45 345.00 25,078 35.00 2.89 SQUARE 28.30
46 346.00 3,138 35.00 2.71 SQUARE 29.50
47 Subtotal Other 170,465
48 35020 30,980 65.00 1.51 R3.0 - 54.20
49 352.00 57,995 60.00 -30.00 1.68 R3.0 47.30
50 353.00 351,925 45.00 -5.00 2.06 R1.0 35.40
FERC FORM NO. 1 (REV. 12-03) Page 337
Name of Respondent
Idaho Power Company
This Re oil Is:
(1)[An Original
(2)flA Resubmission
Date of Report
(Mo, Da, Yr)
04/13/2012
Year/Period of Report
End of 201 1/Q4
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line
0.
-
Account No.
(a)
Depreciable
Plant Base
(In Thousands)
(b)
Estimated
Avg. Service
Life
(C)
Net
Salvage
(Percent)
(d)
Applied
Depr. rates
(Percent)
(e)
Mortality
Curve
Type
(0
Average
Remaining
Life
(ci)
12 354.00 147,491 65.00 -25.00 1.96S3.0 48.60
13 355.00 107,027 55.00 -60.00 2.81 R2.0 36.70
14 356.00 171,802 65.00 -30.00 1.92 R1.5 48.30
15 359.00 413 65.00 0.98 R3.0 23.80
16 Subtotal Transmission 867,633
17 360.22 683 30.00 3.33 SQUARE 30.00
18 361.00 32,336 65.00 -30.00 1.85 R2.5 52.60
19 362.00 194,190 50.00 -5.00 1.89 R0.5 42.10
20 364.00 228,880 44.00 -50.00 3.29 R1.5 31.50
21 365.00 122,537 47.00 -40.00 2.95 R0.5 35.10
22 366.00 47,989 60.00 -20.00 1.95 R2.0 51.20
23 367.00 196,701 50.01 -15.00 1.97 S0.5 41.10
24 368.00 429,420 37.00 5.00 1.67 R1.0 30.80
25 369.00 57,225 35.00 -40.00 3.09 R2.5 25.60
26 370.00 13,834 20.00 6.95 01.0 11.90
27 370.10 57,488 15.00 6.76S3.0 14.40
28 370.30 41,109 3.00 25.67 SQUARE 1.50
29 371.10 27 10.00 -5.00 3.68 S4.0 1.40
30 371.20 2,728 15.00 -5.00 0.63 R2.0 13.90
31 373.20 4,395 25.00 -25.00 4.09 R1.5 13.90
32374.00 643
33 Subtotal Distribution 1,430,185
34390.11 26,794 100.00 -5.00 2.38S1.5 33.60
35 390.12 57,632 50.00 -5.00 2.24 L2.0 36.30
36 390.20 559 30.00 2.58 S3.0 20.80
37 391.11 14,611 20.00 4.97 SQUARE 10.30
38 391.20 20,992 5.00 24.37 SQUARE 2.10
39 391.21 4,956 7.00 13.96 L4.0 3.90
40 392.10 611 10.00 25.00 6.23 L2.5 5.90
41 392.30 2,590 8.00 50.00 8.62 S2.5 4.30
42 392.40 18,957 10.00 25.00 3.58 1.2.5 7.30
43 392.50 766 10.00 25.00 1.49 L2.5 8.60
44 392.60 28,766 19.00 25.00 3.69 S2.0 12.00
45 392.70 4,923 19.00 25.00 2.39S2.0 11.90
46392.90 4,365 30.00 25.00 1.99S1.5 21.10
47 393.00 1,600 25.00 5.40 SQUARE 9.70
48 394.00 6,055 20.00 4.84 SQUARE 11.70
49 395.00 11,866 20.00 5.39 SQUARE 10.20
50 396.00 10,696 16.00 30.00 6.95 S0.0 7.00
FERC FORM NO. I (REV. 12-03) Page 337.1
Name of Respondent
Idaho Power Company
This Re ort Is: (1)An Original
(2)flA Resubmission
Date of Report
(Mo, Da, Yr)
04/13/2012
Year/Period of Report
End of 2011/Q4
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line
No
-
Account No.
(a)
L)epreciable
Plant Base
(In Thousands)
(b)
Estimated
Avg. Service
Life
(C)
Net
Salvage
(Percent)
(d)
Applied
Depr. rates
(Percent)
(e)
Mortality
Curve
Type
(f)
Average
Remaining
Life (g)
12 397.10 6,052 15.00 6.16 SQUARE 7.70
13 397.20 20,618 15.00 6.99 SQUARE 9.60
14 397.30 3,514 15.00 8.36 SQUARE 6.60
15 397.40 2,530 10.00 8.20 SQUARE 5.60
16 398.00 5,255 15.00 9.57 SQUARE 6.90
17 Subtotal General 254,708
18 Total Plant 4,350,916
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. I (REV. 12-03) Page 337.2
Name of Respondent
Idaho Power Company
This Report Is:
(2) FIAResubmission
Date of Report
04/13/2012
Year/Period of Report
End of 2011/04
REGULATORY COMMISSION EXPENSES
1.Report particulars (details) of regulatory commission expenses incurred during the current year (or incurred in previous years, if
being amortized) relating to format cases before a regulatory body, or cases in which such a body was a party.
2.Report in columns (b) and (c), only the current year's expenses that are not deferred and the current year's amortization of amounts
deferred in previous years.
Line
No.
Description
(Furnish name of regulatory commission or body the
docket or case number and a description of the case)
(a)
Assessed by
Regulatory
Commission
(b)
Expenses
of
Utility
(c)
Total Expense for
Current Year
(b) + (c)
(d)
Deferred
in Account
1%2.3 Beginning o8l Year
(e)
1 Federal Energy Regulatory Commission:
2 Annual admin charges assessed by FERC 3,420,728 3,420,728
3
4 Regulatory FERC fees credit -465,593 -465.593
5
6 General Regulatory Expenses and
7 Various other Dockets 44,334 44,334
8
9 Oregon Hydro - Fees Amortization 158,501 158,501
10
11 Regulatory Commission Expenses - Idaho
121 Rate Case - Misc expenses 29,224 29,22
13
14 Regulatory Commission Expenses - Oregon
15 Rate Case - Misc expenses 10,534 10,534
16
17 Other - OPUC
18 AR-233 51,581 51,581
19 UM-1182 16,345 16,345
20 UM - 1396 20,721 20,721
21 UM - 1461 16,225 16,225
22 PURPA 18,671 18,671
23 General Regulatory 36,618 36,618
24 Other matters less than $15,000 91,448 91,448
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
461 TOTAL 3,579,229 -129,892 3449 337
FERC FORM NO I (ED 1296) Page 350
Name of Respondent
Idaho Power Company
This Re ort Is: Date of Report
04/13/2012
Year/Period of Report
End of 2011/04
REGULATORY COMMISSION EXPENSES (Continued)
3.Show in column (k) any expenses incurred in prior years which are being amortized. List in column (a) the period of amortization.
4.List in column (1), (g), and (h) expenses incurred during year which were charged currently to income, plant, or other accounts.
5.Minor items (less than $25,000) may be grouped.
EXPENSES INCURRED DURING YEAR AMORTIZED DURING YEAR
CURRENTLY CHARGED TO Deferred to
Account 182.3
(I)
Contra
Account
(j)
r Amount
(k)
Deferred in Account 182.3 Line
No. Department
(f)
Ac)unt
(g)
Amount
(h)
Electric 928 3,420,728 2
3
Electric 928 -465,593
5
6
Electric 928 44,334 7
8
Electric 928 158,501 9
10
11
Electric 928 29,224 12
13
14
Electric 928 10,534 15
16
17
Electric 928 51,581 18
Electric 928 16,345 19
Electric 928 20,721 20
Electric 928 16,225 21
Electric 928 18,671 22
Electric 928 36,61 8 23
Electric 928 91,448 24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
3,449,3371 46
FERC FORM NO. I (ED. 12-96) Page 351
THIS PAGE INTENTIONALLY LEFT BLANK
Name of Respondent
Idaho Power Company
This Report Is: Date of Report
04/13/2012
Year/Period of Report
End of 201 1/Q4
RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES
1.Describe and show below costs incurred and accounts charged during the year for technological research, development, and demonstration (R, t) &
D) project initiated, continued or concluded during the year. Report also support given to others during the year for jointly-sponsored projects.(dentify
recipient regardless of affiliation.) For any R, D & D work carried with others, show separately the respondent's cost for the year and cost chargeable to
others (See definition of research, development, and demonstration in Uniform System of Accounts).
2.Indicate in column (a) the applicable classification, as shown below:
Classifications:
A. Electric R. D & D Performed Internally: a. Overhead
(1) Generation b. Underground
a.hydroelectric (3) Distribution
I. Recreation fish and wildlife (4) Regional Transmission and Market Operation
ii Other hydroelectric (5) Environment (other than equipment)
b.Fossil-fuel steam (6) Other (Classify and include items in excess of $50,000.)
o. Internal combustion or gas turbine (7) Total Cost Incurred
d.Nuclear B. Electric, R, D & 0 Performed Externally:
e.Unconventional generation (1) Research Support to the electrical Research Council or the Electric
f.Siting and heat rejection Power Research Institute
(2) Transmission
Line
No.
Classification
(a)
Description
(b)
1 Approximately $4 million of Idaho Power's 2011
2 energy efficiency spending was related to
3 research and analysis education technology
4 evaluation and market transformation. Most of
5 this activity was done in conjuction with the
6 Northwest Energy Efficiency Alliance (NEEA)
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
FERC FORM NO. 1 (ED. 12-87) Page 352
Name of Respondent
Idaho Power Company
This Re ort Is:
(2) 0 AResubmission
Date of Report
04/13/2012
Year/Period of Report
End of 2011/Q4
DISTRIBUTION OF SALARIES AND WAGES
Report below the distribution of total salaries and wages for the year. Segregate amounts originally charged to clearing accounts to
Utility Departments, Construction, Plant Removals, and Other Accounts, and enter such amounts in the appropriate lines and columns
provided, in determining this segregation of salaries and wages originally charged to clearing accounts, a method of approximation
giving substantially correct results may be used.
Line
No.
-
Classification
(a)
Direct Payroll Total
Clean Adbounts I (b) c) (d)
Payroll charged for
I Electric
2 Operation
3
4
Production
Transmission
I 161828,328
6,540,751
5 Regional Market
6 Distribution 16,919,375
7 Customer Accounts 8,747,995
8 Customer Service and Informational 4,518,214
9 Sales
10 Administrative and General 42,450,346
11 TOTAL Operation (Enter Total of lines 3 thru 10) 96,005,015
6,667,843
3,223,742
12
13
14
Maintenance
Production
Transmission
15 Regional Market
16
17
Distribution
Administrative and General
8,693,630
1,150,256
18 TOTAL Maintenance (Total of lines 13 thru 17) 19,735,471
19
20
Total Operation and Maintenance
Production (Enter Total of lines 3 and 13) 23,496,171
21 Transmission (Enter Total of lines 4 and 14) 9,764,499
22 Regional Market (Enter Total of Lines 5 and 15)
23 Distribution (Enter Total of lines 6 and 16) 25,613,005
24 Customer Accounts (Transcribe from line 7) 8,747,995
25 Customer Service and Informational (Transcribe from line 8) 4,518,214
26 Sales (Transcribe from line 9)
43,600,602 27 Administrative and General (Enter Total of lines 10 and 17)
28 TOTAL Oper. and Maint. (Total of lines 20 thru 27) 115,740,4861 I 115,740.4861
29
30
Gas
Operation
31 Production-Manufactured Gas I
32 Production-Nat Gas (Including ExpI. 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
43
Maintenance
Production-Manufactured Gas
44 Production-Natural Gas (Including Exploration and Development)
45 Other Gas Supply
46 Storage, LNG Terminaling and Processing
47 Transmission
FERC FORM NO. I (ED. 12-88) Page 354
I
Name of Respondent
Idaho Power Company
This Re rt Is: Date of Report
)
Year/Period of Report
End of 2011/04
DISTRIBUTION OF SALARIES AND WAGES (Continued)
Line
No.
Classification
(a)
Direct Par0II Distribution
(b)
Pay
Allocation of for Total
Clean Accounts
c) (d)
48 Distribution
49 Administrative and General
50 TOTAL MainL (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 0ev.) (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
561 Transmission (Lines 35 and 47)
57 Distribution (Lines 36 and 48)
58 Customer Accounts (Line 37)
59 Customer Service and Informational (Line 38)
60 Sales (Line 39)
61 Administrative and General (Lines 40 and 49)
62 TOTAL Operation and Maint. (Total of lines 52 thru 61)
63 Other Utility Departments
64 Operation and Maintenance
65 TOTAL All Utility Dept. (Total of lines 28, 62, and 64) I 115,740,4861 115,740,486
66
67
68
Utility Plant
Construction (By Utility Departments)
Electric Plant I 49,828,835 49,828835J
69 Gas Plant
70 Other (provide details in footnote):
71 TOTAL Construction (Total of lines 68 thru 70) 49,828,8351 49,828,835
72
73
Plant Removal (By Utility Departments)
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 4,953,227 4,953,227
79 Other Clearing Accounts 3,094,618 3,094,618
80 Other work in progress 2,261,561 2,261,561
81 Paid absences 19,830,321 19,830,321
82 Preliminary survey and investigation 37,691 37,691
83 Other Accounts 4,739,655 4,739,655
84
85
86
87
88
89
90
91
92
93
94
95 TOTAL Other Accounts 34,917,073 34,917,073
96 TOTAL SALARIES AND WAGES 200,486,394 200,486,394
FERC FORM NO. I (ED. 12-88) Page 355
Name of Respondent
Idaho Power Company
This Rort Is:
(2) _CDAResubmission
Date of Report
04/13/2012
Year/Period of Report
End of 2011/Q4
MONTHLY TRANSMISSION SYSTEM PEAK LOAD
(1)Report the monthly peak load on the respondent's transmission system. If the respondent has two or more power systems which are not physically
integrated, furnish the required information for each non-integrated system.
(2)Report on Column (b) by month the transmission system's peak load.
(3)Report on Columns (C) and (ci) the specified information for each monthly transmission - system peak load reported on Column (b).
(4)Report on Columns (e) through ) by month the system' monthly maximum megawatt load by statistical classifications. See General Instruction for
the definition of each statistical classification.
NAME OF SYSTEM: Idaho Power Company
Line
No. Month
(a)
Monthly Peak
MW - Total
(b)
Day of
Monthly
Peak
(c)
Hour of
Monthly
Peak
(d)
Firm Network
Service for Self
(e)
Firm Network
Service for
Others
(0
Long-Term Firm
Point-to-point
Reservations
(g)
Other Long-
Term Firm
Service
(h)
Short-Term Firm
Point-to-point
Reservation
(i)
Other
Service
U)
1 January 4,771 1 800 3,643 250 703 175
2 February 4,78 1 8001 3,609 218 703 250
3 March 4,514 4 8001 3,368 195 703 250
4 Total for Quarter i 14,06 10,620 663 2,109 675
5 April 4,20d 2i 80( 2,649 174 642 744
61 May 4,15 8()01 2,630 189 567 769
7 June 5,22 2: 18001 3,802 279 567 574
Total for Quarter 2 13,58 9,081 641 1,776 2,087
July 5,494 24 18001 4,364 302 567 259
10 August 5,46: 2 180C 4,305 302 567 288
11 September 5,03' 1 17001 3,707 269 567 494
121 Total for Quarter 3 15,99 12,376 873 1,701 1,041
13 October 4,45 11 180( 3,098 206 567 585
14 November 4,411 ii 8001 3,368 199 567 276
15 December 454 11 8001 3,371 208 567 398
16 Total for Quarter 13,41C 9,837 613 1,701 1,259
17
-
Total Year to
DateNear 57,054 41,914 2,791 7,287 5,062
FERC FORM NO. 113-Q (NEW. 07-04) Page 400
U
Name of Respondent
Idaho Power Company
This Re ort Is:
AResubmission
Date of Report
04/13/2012
Year/Period of Report
End of 2011 /Q4
ELECTRIC ENERGY ACCOUNT
Report below the information called for concerning the disposition of electric energy generated, purchased, exchanged and wheeled during the year.
Line
No.
Item
(a)
MegaWatt Hours
(b)
Line
No.
Item
(a)
MegaWatt Hours
(b)
1 SOURCES OF ENERGY 21 DISPOSITION OF ENERGY
2 Generation (Excluding Station Use): 22 Sales to Ultimate Consumers (Including
Interdepartmental Sales)
13,734,430
3 Steam I 4,820,344J
4 Nuclear 23 Requirements Sales for Resale (See
instruction 4, page 311.)
38,222
5 Hydro-Conventional 10,936,822
6 Hydro-Pumped Storage 24 Non-Requirements Sales for Resale (See
instruction 4, page 311.)
3,596,702
7 Other 137,829
8 Less Energy for Pumping 25 Energy Furnished Without Charge
9 Net Generation (Enter Total of lines 3
through 8)
15,894,995 26 Energy Used by the Company (Electric
Dept Only, Excluding Station Use)
10 Purchases 2 777 89 27 Total Energy Losses 1,226,910
11 Power Exchanges 28
-
TOTAL (Enter Total of Lines 22 Through
27) (MUST EQUAL LINE 20)
18,596,264
12 Received 602,391
13 Delivered 680,84
14 Net Exchanges (Line 12 minus line 13) -78,45E
15 Transmission For Other (Wheeling)
16 Received
6,092,21 17 Delivered
18 Net Transmission for Other (Line 16 minus
line 17)
1,82
19 Transmission By Others Losses
20 TOTAL (Enter Total of lines 9, 10, 14, 18
and 19)
18,596,26
FERC FORM NO. I (ED. 12-90) Page 401a
Name of Respondent
Idaho Power Company
This Re ort Is:
sion
Date of Report Year/Period of Report
End of 2011/04
MONTHLY PEAKS AND OUTPUT
1.Report the monthly peak load and energy output. If the respondent has two or more power which are not physically integrated, furnish the required
information for each non- integrated system.
2.Report 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 losses 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 column (e) and (f) the specified information for each monthly peak load reported in column (d).
NAME OF SYSTEM: Idaho Power Company
Line
No.
-
Month
(a)
Total Monthly Energy
(b)
Monthly Non-Requirments
Sales for Resale &
Associated Losses
(c)
MONTHLY PEAK
Megawatts (See lnstr. 4)
(d)
Day of Month
(e)
Hour
(f)
29 January 1,597,182 299,156 2,231 4 8 A
30 February 1,335,990 227,298 2,261 2 8 A
31 March 1,428,726 307,278 1,907 8 8 AM
32 April 1,345,151 329,304 1,761 6 8 A
33 May 1,492,714 389,411 1,746 16 11 AM
34 June 1,776,088 467,350 2,842 28 7 PM
35 July 1,859,037 162,831 2,973 6 8 P
3q August 1,812,353 219,992 2,887 25 5 PM
37 September 1,649,332 352,808 2,564 7 6 P
38 October 1,415,974 371,794 1,974 1 6PM
39 November 1,365,640 237,956 1,933 16 8 A
40 December 1,518,077 231,524 2,135 8 8 A
41 TOTAL 18,596,264 3,596,702
FERC FORM NO I (ED 12-90) Page 401b
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)_ A Resubmission 04/13/2012 2011/Q4
FOOTNOTE DATA
Schedule Page: 401 Line No.:16Column:b
Page 329 column I differs from Page 401 by 1,829 MWH, reported for Lucky Peak variation
and EPA Energy Imbalance schedules on page 401. The numbers that are shown on pages
328-330 are for account 456 wheeling only. However the numbers on page 401 have to be
adjusted for account 447 transmission.
[FERC FORM NO 1 (ED 12-87) Page 450.1
Name of Respondent
Idaho Power Company
This Report Is:
(1)jAn Original
(2)EJA Resubmission
Date of Report
(Mo, Da, Yr)
04/13/2012
Year/Period of Report
End of 201 1 /Q4
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in
this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated
as a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a
therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost
per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. If more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
Line
No.
-
Item
(a)
Plant
Name: Jim Bridger
(b)
Plant
Name: Boardman
(c)
1 Kind of Plant (Internal Comb, Gas Turb, Nuclear Steam Steam
2 Type of Constr (Conventional, Outdoor, Boiler, etc) Semi-Outdoor Boiler Conventional
3
4
Year Originally Constructed
Year Last Unit was Installed 1919 1980
5
6
Total Installed Cap (Max Gen Name Plate Ratings-MW)
Net Peak Demand on Plant - MW (60 minutes) 710 60
7 Plant Hours Connected to Load 87601 6927
8 Net Continuous Plant Capability (Megawatts) 01 01
9
10
When Not Limited by Condenser Water
When Limited by Condenser Water 0 0
11 Average Number of Employees 0 0
12 Net Generation, Exclusive of Plant Use - KWh 3865922000 287766000
13 Cost of Plant: Land and Land Rights 494358 106610
14 Structures and Improvements 66616189 13839832
15 Equipment Costs 456703918 60888268
16 Asset Retirement Costs 0 0
17 j Total Cost 523814465 74834710
18 Cost per KW of Installed Capacity (line 17/5) Induding 679.8371 1165.6497
19 Production Expenses: Oper, Supv, & Engr 180745 903348
20 Fuel 92177415 5683939
21 Coolants and Water (Nuclear Plants Only) 0 0
22 Steam Expenses 4331677 83277
23 Steam From Other Sources 0 0
24 Steam Transferred (Cr) 0 0
25 Electric Expenses 0 0
26 Misc Steam (or Nuclear) Power Expenses 7067950 594345
27 Rents 498085 0
28 Allowances 0 0
29 Maintenance Supervision and Engineering 46835 2028723
30 Maintenance of Structures 2251 43886
31 Maintenance of Boiler (or reactor) Plant 6570615 1064
32 Maintenance of Electric Plant 3076437 235224
33 Maintenance of Misc Steam (or Nuclear) Plant 5702564 421392
34 Total Production Expenses 119654574 9995198
35 Expenses per Net KWh 0.0310 0.0347
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear) Coal Oil Coal Oil
37 Unit (Coal tons/Oil barrel/Gas-mcf/Nuclear indicate) Tons Barrels Tons Barrels
381 Quantity (Units) of Fuel Burned 2161284 10732 0 171802 1170 0
39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 9216 140000 0 8341 138800 0
40 Avg Cost of Fuel/unit as Delvd f.o.b. during year 40.722 150.926 0.000 28.907 132.823 0.000
41 Average Cost of Fuel per Unit Burned 42.137 82.085 0.000 32.042 121.791 0.000
42 Average Cost of Fuel Burned per Million BTU 2.282 13.954 0.000 1.937 20.889 0.000
43 Average Cost of Fuel Burned per KWh Net Gen 0.024 0.000 0.000 0.020 0.000 0.000
44 Average BTU per KWh Net Generation 10337000 0.000 0.000 9897 000 0.000 0.000
FERC FORM NO I (REV 12-03) Page 402
Name of Respondent
Idaho Power Company
This Re oil Is: Date of Report
04/13/2012
Year/Period of Report
End of 201 1 1Q4
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos.
547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants
designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined
cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by
footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units
used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the
report period and other physical and operating characteristics of plant.
Plant
Name: Va/my
(d)
Plant
Name: Danskin
(e)
Plant
Name: Bennett Mountain
(f)
Line
No.
-
Steam Gas Turbine Gas Turbine 1
Outdoor Conventional Conventional 2
- 2001 2005 3
low • 2001 2005 4
270.90 172.80 5
262 249 1946
8718 720 329 7
0 261426 164159 8
_ 0
0 0 0 !2
0 6 7 11
666656000 89344000 48459000 12
1106140 402745 0 13
63302625 5699334 1458303 14
277849448 104008915 58385597 15
0 C) 016
342258213 110110994 59843900 17
1207 2600 4064636 3463189 18
606068 228712 159970 19
21983600 7535390 4154978 20
0 0 0 21
2535456 0 0 22
0 0 0___
0 0 0_.
2231 309 262895 250526 25
2071969 158311 87970 26
0 0 0 z
0 0 0 28
0 0 0 29
874472 89921 82402 30
8779359 22042 37902 31
3515974 575143 986528 32
362107 0 0 33
42960314 8872414 5760276 34
0.0644 0.0993 0.1189 35
Coal Oil Gas Gas 36
Tons Barrels MCF MCF 37
336503 10231 0 958759 0 0 504442 0 0 38
9959 138778 0 1027 0 0 1027 0 0 39
55.215 142.477 0.000 7.860 0.000 0.000 8.237 0.000 0.000 40
61.006 136.892 0.000 7.860 0.000 0.000 8.237 0.000 0.000 41
3.063 23.486 0.000 7.653 0.000 0.000 8.020 0.000 0.000 42
0.033 0.000 0.000 0.084 0.000 0.000 0.086 0.000 0.000 43
10144.000 0.000 0.000 11021.000 0.000 0.000 10691.000 0.000 0.000 44
FERC FORM NO. I (REV. 12-03) Page 403
THIS PAGE INTENTIONALLY LEFrr BLANK
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Idaho Power Company (2)- A Resubmission 04/13/2012 201 1 /Q4
FOOTNOTE DATA
hdupge: 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.
ige. 402 Line No.: 3 Column: c 1
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 operationAugust 3, 1980.

hedule Page 402 Line No.: 3 Column d I
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.
~Sch Me 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.
pqyj ___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
jgge Page: 402 Line No.: 5 Column: d
This footnote applies to line 5 and lines 12 through 43.
Information reflects Idaho Power Company's share as explained
in note for line 3 page 403 column D.
Schedule Page 402 Line No 9 Column: b
This footnote applies to lines 9, 10, and 11. PacifiCorp
as operator of the plant will report this
information.

Schedule Page: 402 Line No.: 9 Column: c 1
This footnote applies to lines 9, 10, and 11. Portland General
Electric Company, as operator will report this information.
Schedule Paae: 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.
JFERC FORM NO I (ED 12-87) Page 4501 I
I--
Name of Respondent
Idaho Power Company
This Re ott Is: Date of Report
(Mo Da, Yr)
Year/Period of Report
End of 2011/04
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1.Large plants are hydro plants of 10.000 Kw or more of installed capacity (name plate ratings)
2.if any Plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
a footnote. If licensed project, give project number.
3.If net peak demand for 60 minutes is not available, give that which is available specifying period.
4.If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Line
No.
-
Item
(a)
FERC Licensed Project No. 2736
Plant Name: American Falls
(b)
FERC Licensed Project No. 1975
Plant Name: Bliss
(C)
1 Kind of Plant (Run-of-River or Storage) Run-aZRJV Run-of-River
2 Plant Construction type (Conventional or Outdoor) Outdoor Outdoor
3 Year Originally Constructed 1978 1949
4 Year Last Unit was Instalied 1978 1950
5 Total installed cap (Gen name plate Rating in MW) 92.30 75.00
6 Net Peak Demand on Plant-Megawatts (60 minutes) 108 77
7 Plant Hours Connect to Load 8,6941 8,760
8
9
Net Plant Capability (in megawatts)
(a) Under Most Favorable Oper Conditions
--
110
______________________________
76
10 (b) Under the Most Adverse Oper Conditions 0 1
11 Average Number of Employees 4 4
12 Net Generation, Exclusive of Plant Use - Kwh 586,802,000 513,605,000
13
14
Cost of Plant
Land and Land Rights 875,318 768,358
15 Structures and Improvements 11,807,207 1,039,561
16 Reservoirs, Dams, and Waterways 4,293,075 8,413,888
17 Equipment Costs 31,659,620 8,393,112
18 Roads, Railroads, and Bridges 839,276 486,477
19 Asset Retirement Costs 0 0
20 TOTAL cost (Total of 14thru 19) 49,474,496 19,101,396
21 Cost per KW of Installed Capacity (line 20/5) 536.0184 254.6853
22
23
Production Expenses
Operation Supervision and Engineering 222,397 782,452
24 Water for Power 1,674,772 699,745
25 Hydraulic Expenses 116,486 780,235
26 Electric Expenses 50,572 45,043
27 Misc Hydraulic Power Generation Expenses 210,138 244,914
28 Rents -568 -45,035
29 Maintenance Supervision and Engineering 89,270 151,939
30 Maintenance of Structures 211,483 274,177
31 Maintenance of Reservoirs, Dams, and Waterways 7,497 518,836
32 Maintenance of Electric Plant 292,363 - 86,802
33 Maintenanceof MiscHydraulicPlant 103,363 154,730
34 TotalProductionExpenses(total23thru33) 2,977,773 3,693,838
35 Expenses per net KWh 0.0051 0.0072
FERC FORM NO I (REV 12-03) Paae 406
Name of Respondent
Idaho Power Company
This Re ort Is: Date of Report
04/13/2012
Year/Period of Report
End of 201 1/Q4
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5.The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6.Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No. 1971
Plant Name: Brownlee
(d)
FERC Licensed Project No. 2848
Plant Name: Cascade
(e)
FERC Licensed Project No. 1971
Plant Name: Oxbow
Line
No.
Storage N
Outdoor Outdoor
_i Outdoor 2
1958 1983 1961 3
1980 1984 1961 4
58540 1242 19000 5
6801 141 220 , 6
8,7601 8,7111 8,7601 7
747 15 221
8
9
220 1 202 10
7 2 611
2 924 285 000 50,909,000 1,397,275,000 12
17,382,696 82,142 1,210,187
13
14
31 438553 7,364,154 9,963,201 15
67,073,285 3,145,630 30,466,784 16
55,992,367 12,696,273 15,820,683 17
518,444 122,668 565,844 18
0 0 0
172,405,345 23,410,867 5802669920
294 5086 1,884.9329 305 4037 21
632,600 204,900 350,884
22
23
576,341 202,919 298,949 24
901,670 320,137 471,375 25
303,160 131,909 186,903 26
408,009 179,822 273,829 27
304,316 -17 49,901 28
455,958 73,556 236,376 29
197,794 63,144 261,452 30
65,107 483 5,321 31
358,259 63,839 162,548 32
682,115 104,754 247,620 33
4,885,329 1,345,446 2,545,158 34
0.0017 0.0264 0.0018 35
FERC FORM NO. I (REV. 12-03) Paae 407
Name of Respondent
Idaho Power Company
This Re ort Is: Date of Report
04/13/2012
Year/Period of Report
End of 2011/04
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1.Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2.if any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
a footnote. If licensed project, give project number.
3.if net peak demand for 60 minutes is not available, give that which is available specifying period.
4.If a group of employees attends more than one generating plant, report on line lithe approximate average number of employees assignable to each
plant.
Line
No.
-
Item
(a)
FERC Licensed Project No. 1971
Plant Name: Hells Canyon
(b)
FERC Licensed Project No. 2726
Plant Name: Malad
(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) 39150 21.77
6 Net Peak Demand on Plant-Megawatts (60 minutes) 4401 24
7 Plant Hours Connect to Load 8,7571 8,760
8
9
Net Plant Capability (in megawatts)
(a) Under Most Favorable Oper Conditions 445 25
10 1 (b) Under the Most Adverse Oper Conditions 137 21
11 JAverage Number of Employees 5 1
12 Net Generation, Exclusive of Plant Use - Kwh 2,816,349,000 173,042,000
13
14
Cost of Plant
Land and Land Rights 1,877,301 205,376
15 Structures and Improvements 2,811,400 2,777,503
16 Reservoirs, Dams, and Waterways 52,700,383 6,265,302
17 Equipment Costs 17,216,890 4,292,367
18 Roads, Railroads, and Bridges 819,192 304,683
19 Asset Retirement Costs 0 0
20 TOTAL cost (Total of 14 thru 19) 75,425,166 13,845,231
21
22
23
Cost per KW of Installed Capacity (line 20 / 5)
Production Expenses
Operation Supervision and Engineering
192.6569
377,827
635.9775
214,911
24 Water for Power 327,519 702,291
25 Hydraulic Expenses 525,528 259,355
26 Electric Expenses 212,729 47,858
27 Misc Hydraulic Power Generation Expenses 249,786 115,885
28 Rents 82,999 0
29 Maintenance Supervision and Engineering 269,283 34,863
30 Maintenance of Structures 72,377 12,790
31 Maintenance of Reservoirs, Dams, and Waterways 211,408 8,405
32 Maintenance of Electric Plant 174,027 30,574
33 Maintenance of Misc Hydraulic Plant 374,531 52,676
34 Total Production Expenses (total 23 thru 33) 2,878,014 1,479,608
35 Expenses per net KWh 0.0010 0.0086
FP(' FflRU NA I (PFV ii-w4i ii-w4 Pana AAR I
I
Name of Respondent
Idaho Power Company
This Report Is:
2nR Original
esubmission
Date of Report
(Mo, Da r
04/13/2012
Year/Period of Report
End of 2011/04
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. 18
Plant Name: Twin Falls
(I)
Line
No.
-
Run-of-River Run-of-River Run-of-River 1
Outdoor Conventional Conventional 2
1952 1910 1935 3
1952 1994 1995 4
8280 2500 52745
921 251 516
8,7601 8,7601 8,627 7
8
91 24 539
84 14 5010
6 4 4 11
657,632,000 157,917,000 394,475,000 12
13
5,473,876 51,675 255,499 14
9203 458 25,453,938 10,808,047 15
10,438,597 13,856,887 7,908,870 16
11,937,740 30331 287 20,759,503 17
248,183 835,946 1,917,603 18
0 0 0
37301 854 70,529,733 41,649,522 20
4505055 2821 1893 7897141 21
22
870,472 212,122 232,982 23
843,278 174,581 216,977 24
1,171,858 148,772 17839325
42,777 34,517 53,462 26
355,585 113,831 148,674 27
-113,298 -31,048 -11,887 28
96,665 61,292 30,047 29
128,592 79,419 38,832 30
115,796 183,048 37,877 31
134,533 22,414 38,864 32
144,740 125,136 79,005 33
3,790,998 1,124,084 1,043,226 34
0.0058 0.0071 0.0026 35
FERC FORM NO. 1 (REV. 12-03) Page 407.1
Name of Respondent
Idaho Power Company
This Report Is:
Original 2nR Ofl
Date of Report
(Mo, Da, Yr)
End of 2011/Q4
Year/Period of Report
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1.Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2.If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
a footnote. If licensed project, give project number.
3.If net peak demand for 60 minutes is not available, give that which is available specifying period.
4.If a group of employees attends more than one generating plant, report on line lithe approximate average number of employees assignable to each
plant.
Line
No.
-
Item
(a)
FERC Licensed Project No. 2777 IFERC
Plant Name: Upper Salmon
(b)
Licensed r Project No. 2778
Plant Name: Shoshone Falls
(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
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 INet Peak Demand on Plant-Megawatts (60 minutes) 37 14
7 Plant Hours Connect to Load 8,7601 8,640
8
9
Net Plant Capability (in megawatts)
(a) Under Most Favorable Oper Conditions 39 14
10 (b) Under the Most Adverse Oper Conditions 32 11
ii Average Number of Employees 3 2
12 Net Generation, Exclusive of Plant Use - Kwh 293,884,000 110,438,000
13 Cost of Plant
Land and Land Rights 202,399 313,328 14
15 Structures and Improvements 2,013,430 1,231,506
16 Reservoirs, Dams, and Waterways 5,569,171 512,402
17 Equipment Costs 7,763,706 4,523,995
18 Roads, Railroads, and Bridges 29,359 51,383
19 Asset Retirement Costs 0 0
20 TOTAL cost (Total of 14 thru 19) 15,578,065 6,632,614
21 Cost per KW of Installed Capacity (line 20/5) 451.5381 530.6091
22
23
Production Expenses
Operation Supervision and Engineering 388,900 193,209
24 Water for Power 373,144 169,172
25 Hydraulic Expenses 551,980 127,220
26 Electric Expenses 86,416 38,400
271 Misc Hydraulic Power Generation Expenses 205,221 107,273
28 Rents 0 -315
29 Maintenance Supervision and Engineering 97,699 21,664
30 Maintenance of Structures 115,610 31,721
31 Maintenance of Reservoirs, Dams, and Waterways 254,149 6,789
32 Maintenance of Electric Plant 67,839 46,273
33 Maintenance of Misc Hydraulic Plant 239,825 67,634
34 Total Production Expenses (total 23 thru 33) 2,380,783 809,040
35 Expenses per net KWh 0.0081 0.0073
FERC FORM NO. I (REV. I2-03) Paine 406.2
I
Name of Respondent
Idaho Power Company
This Report Is:
2h1 Resubmission
Date of Report Year/Period of Report
End of 2011 /Q4
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 Facilities
(d)
FERC Licensed Project No. 2061
Plant Name: Lower Salmon
(e)
FERC Licensed Project No. 2899
Plant Name: Milner
(f)
Line
No.
Run-of-River Run-of-River 1
Outdoor Conventional 2
1949 1992 3
1949 1992 4
000 6000
01 65 591 6
01 8,7601 8,6531 7
8
0 64 619
0 60 1 10
0 7 211
0 391,028,000 435,475,000 12
13
114,367 424,428 138,100 14
26,615,283 2,805,900 10,340,105 15
13,556,785 6,916,532 17,114,934 16
1,288,563 8,069,424 27,665,197 17
99,051 88,693 501,877 18
0 0 0
41 ,674,049 18,304,977 55,760,213 20
0.0000 305 0830 937 9346 21
22
0 379,189 233,958 23
0 352,498 2,115,819 24
6,376,408 379,465 119,064 25
0 232,553 49,500 26
0 203,217 236,962 27
0 -13,894 -11,941 28
0 73,977 44,160 29
0 156,154 43,701 30
0 8,085 80,612 31
0 119,879 79,594 32
54,282 160,281 74,106 33
6,430,690 2,051404 3,065,535 34
0.0000 0.0052 0.0070 35
FERC FORM NO. I (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) X An Original (Mo, Da, Yr)
Idaho Power Company (2)_ A Resubmission 04/1312012 2011/04
FOOTNOTE DATA
Schedule Page 406 LineNol Colurnnb - - -
meriean Falls--g---en-era-t- i-n-g capacity is dependent upon water releases controlled by the
Schedule Page 406 Line No I Colurnne ------------------------- - Cascade generating capacity is dependent upon wat er rel e ases controlled by the rJSBR.
Schedule Page 406 Line 1_ Column: f
Upstream storage in Brownlee Reservoir
Schedule Page 4061 Line No I Column :b -
IJPstream storage in Brownle e Reservoir
Schedule gage 406.1 Line No I Column c - -
Lower Malad maximum demand 15 000 K, Upper Malad maximum demand 9,000 Kw non-coincident
jFERC FORM NO. I (ED. 12-87) Page 450.1
I
Name of Respondent
Idaho Power Company
This REXA&nii Is:
(1)Original
(2)Resubmission
Date of Report
(Mo, Da, Yr)
04/13/2012
Year/Period of Report
n 2011/Q4
GENERATING PLANT STATISTICS (Small Plants)
1. Small generating plants are steam plants of, less than 25.000 Kw; internal combustion and gas turbine-plants, conventional hydro plants and pumped
storage plants of less than 10,000 Kw installed capacity (name plate rating). 2. Designate any plant leased from others, operated under a license from
the Federal Energy Regulatory Commission, or operated as a joint facility, and give a concise statement of the facts in a footnote. If licensed project,
give prolect number in footnote.
Line
No.
-
Name of Plant
(a)
Year
Orig. Const.
(b)
I Installed Capacity
Name Plate Ratin
(In MW)
(c)
Net Peak Demand
(6t(n 1
' (2)
Net Generation
Excluding Plant Use
(e)
Cost of Plant
(f)
1 Hydro:
2 Clear Lakes 1937 2.50 2.3 16,495 1,759,923
3 Thousand Springs 1912 8.80 7.4 17,211 9,322,833
4
5
6 Internal Combustion:
7 Salmon Diesel (1) 1967 5.00 4.2 26 909,259
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
FFRC FORM NO 1 (RFV I2..fl21 Pnc 410
Name of Respondent
Idaho Power Company
This Report Is:
(1)jAn Original
(2)EJA Resubmission
Date of Report
(Mo, Da, Yr)
04/1312012
Year/Period of Report
n ' 20111Q4
GENERATING PLANT STATISTICS tSmaII Plants) (Continued)
3. List plants appropriately under subheadings for steam, hydro, nuclear, internal combustion and gas turbine plants. For nuclear, see instruction 11,
Page 403. 4. If net peak demand for 60 minutes is not available, give the which is available, specifying period. 5. If any plant is equipped with
combinations of steam, hydro internal combustion or gas turbine equipment, report each as a separate plant. However, if the exhaust heat from the gas
turbine is utilized in a steam turbine regenerative feed water cycle, or for preheated combustion air in a boiler, report as one plant.
Plant Cost (Incl Asset
Retire. Costs) Per MW
(g)
Operation
Exc'l. Fuel
(h)
Production Expenses
Kind of Fuel
(k)
Fuel Costs (in cents
(per Million Btu)
(I)
Line
Fuel
(i)
Maintenance
U)
703,969 123,037 36,555 2
1,059,413 213,644 252,473 3
4
5
6
181,852 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 I (REV 12-03) Pace 411
Name of Respondent
Idaho Power Company
This Report Is: Date of Report Original
32
Year/Period of Report
End of 2011/04
TRANSMISSION LINE STATISTICS
1.Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2.Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3.Report data by individual lines for all voltages if so required by a State commission.
4.Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonuthity Property.
5.Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel: (2) H-frame wood, or steel poles: (3) tower:
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6.Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the polo 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
No.
DESIGNATION VOLTAGE (Ky)
(Indicate where
other than
60 cycle, 3 phase)
Type o
Supporting
Structure
(e)
LENGTH (Pole riles) (In the ease int undergrouna es
report circuit miles)
Number
Of
circuits
(h)
From
(a)
To
(b)
Operating
(C)
Designed
(d)
On Structure
of Line
On structures
ofictherLine
(g)
I Borah Midpoint 345.0 500.00 Slower 85.17 1
2 Boardman Slatt 500.0c 500.00 Slower 1.79 1
3 Summer lake Hemingway 500.0 500.00 S lower 0.40 1
4 Hemingway Midpoint 500.0 500.00 S Tower 0.37 1
5
6 Jim Biidger Goshen 345.0 345.00 Slower 226.40 1
7 State Line Midpoint 345.0 345.00 S Tower 76.04 2
- Kinport Borah 345.0 345.00 Slower 27.10 1
- Midpoint Borah #1 345.0' 345.00 H Wood 79.29 1
10 Midpoint Borah #2 345.0' 345.00 H Wood 77.58 2
11 Adelaide Tap Adelaide 345.0 345.00 H Wood 2.67 2
12
13 Quartz LaGrande 2300 23000 H Wood 4630 1
14 Midpoint Hunt 230.0 230.00 Slower 0.70 2
15 Brady Antelope 230.0 230.00 H Wood 56.29 1
16 Brady Treasureton 230.01 230.00 H Wood 0.111 1
17 Brady #1 & #2 Kinport 230.01 230.00 S Tower 17.94 2
18 Jim Bridger Point of Rocks 230.1 230.00 H Wood 1.40 1
19 Brownlee Ontario 230.0 230.00 S lower 72.74 1
20 Mora Bowmont 138.1 230.00 S P Wood 9.91 1
21 Mora Bowmont 138.0 230.00 H Wood 8.82 1
22 Jim Bridger Point of Rocks 230.0 230.00 H Wood 2.791 1
23 Caldwell 710 Locust 2300 230.00 SP Steel 18.59 1
24 Boise Bench Caldwell 230.0 230.00 S Tower 7.56 1
25 Boise Bench Caldwell 230.0 230.00 H Wood 33.68 1
26 Boise Bench Cloverdale 230.0 230.00 S Tower 16.10 2
27 Boardman Dalreed Sub 230.0 230.00 H Wood 1.68 1
28 Brownlee 714 Oxbow 230.0 230.00 SP Steel 11.06 2
29 Caldwell Ontario 230.0 230.00 H Wood 29.84 1
30 Caldwell Ontario 2300 23000 Slower 327 1
31 Bennett Mtn PP Rattlesnake IS 230.0 230.00 SP Steel 4.44 1
32 Borah Hunt 230.0' 230.00 H Steel 68.17 1
33 Danskin Hubbard 230.0' 230.00 H Steel 36.28 1
34 Danskin Hubbard 2300' 23000 SP Steel 1.90 1
35 Dansktn Hubbard 2300 23000 SP Steel 1.30 2
36 TOTAL 4,759,01 1 11.02 186
FERC FORM NO. I (ED- 12-871 Pane 422
I
Name of Respondent This Report Is:
Idaho Power Company (2) A Resubmission
Date of Report
04/13/2012
Year/Period of Report
End of 201 11Q4
TRANSMISSION LINE STATISTICS (Continued)
7.Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8.Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9.Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10.Base the plant cost figures called for in columns (j) to (I) on the book cost at end of year.
Size of
and Material
(i)
COST OF LINE (Include in Column (j) Land
Land rights, and clearing right-of-way)
Conductor
EXPENSES EXCEPT DEPRECIATION AND TAXES -
Line
i'O.
Land
(j)
Construction and
Other Costs (k)
Total Cost
(I)
Operation
Expenses
(rn)
Maintenance
Expenses
(n)
Rents
(0)
Total
Expenses
(p)
1272 ACSR 256,381 21,789,412 22,045,793 1
X1780ACSR 446,708 446,708 2
1272 ACSR 835,662 835,662 3
1272 ACSR 4
5
1272 ACSR 483,30 16,763,326 17,246,635 6
95ACSR 57197 11,048,835 11,620,814 7
1272 ACSR 344,22 6,008,061 6,352.281 8
155ACSR 28314 5,876,940 6,160,083 9
15.5 ACSR 64,851 12,257,047 12,321,898 10
15.5ACSR 51,44 347,946 399,394 11
12
95ACSR 62,21 2,841,222 2,903,440 13
15.5 ACSR 9,14 998,452 1,007,597 14
1272ACSR 108301 2,930,700 3,039,001 15
95ACSR 6,186 6,186 16
15.5 ACSR 18,821 969,871 988,700 17
272ACSR 1191 51,525 52,715 18
X954ACSR 167683 20,541 ,790 22,218,628 19
15.5 ACSR 413,79 2,167,266 2,581,059 20
15.5 ACSR 21
272 ACSR 1,89 212,523 214,422 22
590 ACSR 2,138,23 8,775,086 10,913,322 23
272 ACSR 1,748,2V 6,980,587 8,728,801 24
155ACSR 25
272 ACSR 3,062,81 6,869,820 9,932,632 26
95A.AC 80,895 80,895 27
54ACSR 34,17 16,039,303 16,073,477 28
X954 ACSR 224,68 6,285,960 6,510,648 29
1272 ACSR 30
272 ACSR 81,701 1,666,354 1,748,055 31
590 ACSR 624,91 22,457,621 23,082,538 32
1590 ACSR 15,210,561 15,210,561 33
590 ACSR
1590 ACSR 35
31,147,986 426,733,642 457,881,628 36
I lFfl I7_R7 - - Panci 423
Name of Respondent
Idaho Power Company
This Reoort Is: Date of Report
(1)An Original (Mo, Da, Yr) (2)M Resubmission 04/13/2012
Year/Period of Report
End of 20111Q4
TRANSMISSION LINE STATISTICS
1.Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovoits or greater. Report transmission lines below these voltages in group totals only for each voltage.
2.Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3.Report data by individual tines for all voltages if so required by a State commission.
4.Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5.Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra tines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6.Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). in a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line
No.
DESIGNATION VOLTAGE (KV)
(Indicate where
other than
60 cycle, 3 phase)
Type of
Supporting
Structure
(e)
LENGTH Qole miles) (In tire ..ase of undergrouna lines report circuit miles)
Number
Of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
on Structure
D of. Line esi)nated
On 'tructures Of other
(g)
1 Danskin Bennett Mtn 230.00 230.00 SP Steel 5.47 1
2 Hemingway Bowmont 230.00 230.00 SP Steel 13.02 1
3 Langley Gulch Tap 230.00
4 Boise Bench Midpoint #1 230.0i 230.00 S Tower 0.87 1
S Boise Bench Midpoint #1 230.01 230.00 H Wood 108.23 1
6 Brownlee Quartz Jct 23001 23000 S Tower 1.52 1
7 Brownlee Quartz ,Jct 230.0(. 230.00 H Wood 41.32 1
8 Brownlee Boise Bench #1 & #2 230.01 230.00 S Tower 99.76 2
9 Oxbow Brownlee 230.01 230.00 S Tower 10.80 2
10 Boise Bench Midpoint #2 230.01 230.00 S lower 3.32 1
11 Boise Bench Midpoint #2 230.01 230.00 H Wood 102.07 1
12 Oxbow Pallette Jct 230.01 230.00 5 Tower 20.03 2
13 Pallette Jct Imnaha 230.0 230.00 H Wood 24.43j 2
14 Hells Canyon Palette Jct 230.0 230.00 Slower 8.16 2
15 Brownlee Boise Bench 2301 23000 Slower 10208 2
16 Boise Bench Midpoint #3 2300 23000 H Wood 10631 1
17 Palette Jot Enterprise 230.0 230.00 H Wood 29.12 1
18 Borah Brady #2 230.1 230.00 Slower 0.41 1
19 Borah Brady #2 230.0 230.00 3.56 1
20 Borah Brady #1 230.1 230.00 3.87 1
21
22 Goshen State Line 161.0 161.00 90.4 1
23 Don Goshen 161.0 161.00
MWood
2.3 2
24 Don Goshen 161.0 161.00 48.4 2
25
26 American Falls Power Plant Adelaide 138.0 138.00 10.99 2
27 American Falls Power Plant Adelaide 138.0' 138.00 0.12 2
28 Minidoka Loop Adelaide 138.01 138.00 1.121 2
29 Nampa Caldwell 138.01 138.00 SPWood 10.75 2
30 Upper Salmon Mountain Home Jct 13801 13800 H Wood 5429 1
31 Upper Salmon Cliff 138.01 138.00 H Wood 30.81 1
32 Eastgate Russet 138.01 138.00 S P Wood 2.08 1
33 Brady Fremont 138.01 138.00 S Tower 0.98 2
34 Brady Fremont 13801 13800 H Wood 24.321 2
35 Brady Fremont 138.01 138.00 S P Wood 24.33 2
36 TOTAL 4,759.011 11 .021 186
FERC FORM NO. 1 (ED. 12-87) Paae 422.1
Name of Respondent This Report Is:
Idaho Power Company AResubmission
Date of Report
3I2
Year/Period of Report
End of 2011/04
TRANSMISSION LINE STATISTICS (Continued)
7.Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8.Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, fumish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9.Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10.Base the plant cost figures called for in columns ) to (I) on the book cost at end of year.
Size of
Conductor
and Material
(I)
COST OF LINE (Include in Column (j) Land,
Land rights, and clearing right-of-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES -
Line
r'O.
Land
)
Construction and
Other Costs (k)
Total Cost
(I)
Operation
Expenses
(m)
Maintenance
Expenses
(n)
Rents
(0)
Total
Expenses
(p)
590 ACSR 3,528,033 3,528,033 1_
590ACSR 185499 9,212,985 11,067,981 2
89611 896,110
I155ACSR 33618 5,172,731 5,508,917 4
7155ACSR
795 ACSR 53,06 2,229,410 2,282,478 6
795ACSR .L.
VARIOUS 289,931 8,046,450 8,336,384 8
1272ACSR 1481 1,182,550 1,197,360 9
7155 ACSR 22782 6,380,708 6,608,533 10
VARIOUS 11
1272ACSR 9203 2097561' 2,189,603 12
272ACSR 171,081 1,386,300 1,557,381 13
1272ACSR 44,687 1,252,130 1,296,817 14
54 ACSR 184,817 5,624,726 5809 543 15
155ACSR 247,857 5,599,323 5,847,180 16
272 ACSR 84,014 1,739,212 1,823,226 17
272ACSR 306 416,606 419,674 18
715.5 ACSR 19
272 ACSR 10,06 31 1 ,349 32141: 20
21
50 COPPER 16,15 648,382 664,537 22
15.5ACSR 76,041 1,698,355 1,774,396 23
97.5 ACSR 24
25
50 COPPER 26,507 262,590 289,097 26
50 COPPER 27
15.5ACSR 21,321 254,909 276,235 28
95AAC 608,321 1,779,264 2,387,559 29
95 ACSR 47,68 3,565,872 3,613,559 30
95 ACSR 43,561 913,613 957,181 31
95AAC 270,8Z 557,504 828,327 32
VARIOUS 564,93: 3,770,086 4,335,018 33
VARIOUS 34
VARIOUS 35
31,147,986 426,733,642 457,881,628 36
FERC FORM NO I (ED 12-87) Page 4231
Name of Respondent
Idaho Power Company
This Re ort Is:
(2) p A Resubmission
Date of Report
04/13/2012
Year/Period of Report
End of 2011/Q4
TRANSMISSION LINE STATISTICS
1.Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2.Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3.Report data by individual lines for all voltages if so required by a State commission.
4.Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5.Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel: (2) H-frame wood, or steel poles: (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6.Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated: conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line
No.
DESIGNATION VOLTAGE (KV) (Indicate where
other than
60 cycle, 3 phase)
- Typo of
Supporting
Structure
LENGTH (Pole roiles)
rS dethe as1 ot u rgroui lines
report circuit miles)
Number
Of
Circuits
(h)
From To Operating Designed
On Structure
Dof.Lin?ed
o f Ontructures flOther ne
1 King Lower Malad 138.0' 138.00 H Wood 84.51 2
2 Emmett Jct Payette 138.0 138.00 H Wood 66.46 2
3 Mountain Home AFB Tap 138.Oq 138.00 H Wood 6.20 1
4 Ontario Quartz 138.0 138.00 H Wood 73.33
5 King American Falls PP 138.0 138.00 S Tower 1.03
61 King American Falls PP 138.0 138.00 H Wood 141.74
7 King American Falls PP 138.0 138.00 S P Wood 3.71
8 Duffln Clawson 138.0 138.00 H Wood 6.22
9 American Falls Brady Tie 138.0 138.00 H Wood 0.33 1
10 Upper Salmon A-B King 138.0 138.00 H Wood 5.66
11 Upper Salmon B Wells 138.0 138.00 H Wood 125.59 1
121 King Wood River 138.0 138.00 H Wood 73.71 1
13 Boise Bench Grove 138.0 138.00 S P Wood 10.38 2
14 Quartz John Day 138.0 138.00 H Wood 67.32 1
15 Sinker Creek Tap 138.0 138.00 H Wood 2.80 1
16 Mora Cloverdale 138.0 138.00 H Wood 2.57 1
17 Mora Cloverdale 138.0 138.00 SPWood 22.28 1
181 Mora Cloverdale 138.0 138.00 S P Steel - 0.96 2
19 Stoddard Jct Stoddard Sub 138.0 138.00 S P Steel 3.80 1
20 Fossil Gulch Tap 138.0 138.00 H Wood 1.95 1
21 Wood River Midpoint 138.0 138.00 H Wood 53.04 2
22 Wood River Midpoint 138.0 138.00 S P Wood 16.69 2
23 Oxbow McCall 138.0 138.00 H Wood 37.16 1
24 Oxbow McCall 138. 138.00 5PWood 2.32 1
25 Lowell Jct Nampa 138. 138.00 5 P Wood 7.50 2
26 Hunt Milner 138. 138.00 SPWood 19.40 1
27 Strike Bruneau Bridge 138. 138.00 H Wood 13.49 1
28 American Falls Kramer Sub 138.0 138.00 5 P Wood 18.40 2
291 Pingree Haven 138.Oq 138.00 SPWood 11.72 1
30 Midpoint Twin Falls 138. 138.00 SPWood 25.13 2
31 Twin Falls Russett 138.0 138.00 S P Wood 1.71 1
32 Blackfoot Aiken 46.0 138.00 SPWood 6.18 2
33 Peterson Tendoy 69.01 138.00 H Wood 5721 1
34 Eastgate Tap Eastgate 1380' 13800 S P Wood 636 1
35 Kimberly Tap Kimberly 138.0 138.00 S P Steel 1.83 2
TOTAL 475901 1102 186
FERC FORM NO. I (ED. 12-87) Page 4222
I
Name of Respondent This Re ort Is:
Idaho Power Company (2) [:]A Resubmission
Date of Report
04/13/2012
Year/Period of Report
End of 201 1 /Q4
TRANSMISSION LINE STATISTICS (Continued)
7.Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8.Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9.Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10.Base the plant cost figures called for in columns U) to (I) on the book cost at end of year.
Size of
and Material
(I)
COST OF LINE (Include in Column U) Land,
Land rights and clearing right-of-way)
Conductor
EXPENSES, EXCEPT DEPRECIATION AND TAXES -
Line Land
U)
Construction and
Other Costs (k)
Total Cost
(I)
Operation
Expenses
(m)
Maintenance
Expenses
(n)
Rents
(0)
Total
Expenses
(p)
VARIOUS 7682 2316,106 2,392,929 :1 -
VARIOUS 30,911 2,512,162 2,543,080 2= 97.5 ACSR 1,95 12,983 14,938 3
VARIOUS 34,42E 2,150,955 2 185 383 4
155ACSR 21691 7,976,117 8,193,036 5
I55ACSR 6
155ACSR 7
4,191 309,857 314,048 8
54ACSR 96,921 96,921 9
250 COPPER 2,74, 93,073 95,814 10
VARIOUS 2849 2,150,317 2,178,807 11
VARIOUS 17368 2,834,498 3,008,181 12
VARIOUS 225,60, 1,652,772 1,878,374 13
4975ACSR 9217 2,362,416 2,454,589 14
VARIOUS 21 77,199 77,219 15
15.5 ACSR 3,168,361 9,724,534 12,892,903 16
VARIOUS 17
95AAC 18
1272 ACSR 19
50 COPPER 45C 199,195 199,645 20
97.5 ACSR 349,712 6,997,913 7,347,625 21
97.5 ACSR 22
97.5 ACSR 109,89 2,306,969 2,416,868 23
97.5 ACSR 24
155ACSR 211 ,131 1,448,294 1,659,425 25
155ACSR 3,324 1,190,604 1,193,928 26
975ACSR 14,921 587,404 602,331 27
15.5 ACSR 13,73 1,051,324 1,065,058 28
497.5 ACSR 18,22 1,276,855 1,295,078 29
VARIOUS 54,84 2,969,759 3,024,607 30
7155ACSR 16,791 206,158 222,948 31
15.5ACSR 13,611 491,359 504,975 32
97.5 ACSR 395,691 3,449,949 3,845,645 _______________ _______________ _______________ 33
15.5 ACSR 343,951 2,136,683 2,480,638 34
95 ACSR 35
31147986 426,733,642 457,881,628 36
FFRc FORM NO I (Ffl 17-R7 Pnp 423.2
Name of Respondent
Idaho Power Company
This Report Is: Date of Report
2h1 Resubmission
Year/Period of Report
End of 201 1 /Q4
TRANSMISSION LINE STATISTICS
1.Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2.Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3.Report data by individual lines for all voltages if so required by a State commission.
4.Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5.Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6.Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line
No.
DESIGNATION VOLTAGE (Ky)
(Indicate where
other than
60 cycle, 3 phase)
1 E ype of
Supporting
Structure
(e)
LENGTH (Pole miles) Ip the cas Ot u aergrounci lipes report circuit miles)
Number
Of
Ciits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
On Structure
D Line I other OnjtruQtures of Une
(g)
1 Boise Bench More 138.0 138.00 H Wood 13.18 2
2 Bowmont-Caldwell Simplot Sub 138.0 138.00 S P Wood 0.51 1
3 Gary Lane Eagle 138.0 138.00 S P Wood 6.53 1
4 Locust Grove Blackcat Sub 138.0 138.00 S P Steel 10.06 2.98 1
5 Boise Bench Butler 1380 13800 S P Wood 014 402 1
6 Eagle Star 138.0 138.00 SPWood 6.39 1
7 Karcher Sub Zilog Tap 138.0 138.00 S P Steel 2.08 1
8 Cloverdale - 712 712 - Wye 138.04 138.00 S P Steel 0.40 4.02 1
9 Victory Jct Victory 138.04 138.00 SPSteel 1.90 1
10 Butler Wye 138.0 138.00 S P Steel 2.94 1
11 Horseflat Starkey 138.0 138.00 H Wood 33.86 1
12 Starkey Mccall 138.0 138.00 SPSteel 2.08 2
13 Starkey McCall 138.0 138.00 H Wood 3.80 1
14 Starkey McCall 138.0 138.00 S P Steel 1.50 1
15 Starkey McCall 138.0' 138.00 S P Wood 17.61 1
16 Chestnut Happy Valley 138.0 138.00 S P Steel 2.80 1
17 Garnet Ward 138.00
18 McCall Lake Fork 138.0 138.00 S P Wood 8.80 1
19 McCall Lake Fork 138.0 138.00 S Steel 2.90
20 Caldwell Willis 138.04 138.00 S P Steel 1.30 1
21 Caldwell Willis 138.0 138.00 S P Steel 1.59 1
22 Caldwell Willis 138.04 138.00 S P Wood 0.87 1
23 Valivue Tap 138.01 138.00 S P Steel 0.80 2
24 Kinport Don #1 138.01 138.00 S Tower 1.24 2
25 Donn HOKU 138.01 138.00 S P Steel 2.74 1
26 Rockland Jot Rockland Wind Farm 138.(X 138.00 S P Steel 5.31 1
27 HOKU Married 138.0 133.00 S P Steel 0.22 2
28 HOKU Alamed 138.0 138.00 SPSteel 0.23 2
29 HOKU Alamed 138.0 138.00 S P Steel 2.85 1
30 Twin Falls PP Tap 1380 13800 H Wood 082 1
31 American Falls PP Amercian Falls Trans ST 138.0 138.00 S P Steel 0.37 1
32 Lower Salmon King Tie 1380 13800 H Wood 011 1
33 C J Strike Strike Jot 138.0 138.00 S Tower 4.32 2
34 Strike Jot Mountain Home Jct 138.0 138.00 H Wood 23.39 1
35 Strike Jot Bowmont 138.00 HWood 0.05 1
36 1 TOTAL 1 4,759.011 11 .021 186
FERC FORM NO. I (ED. 12-87) Pacie 422.3
Name of Respondent
Idaho Power Company
This Report Is:
(2) DAResubmission
Date of Report
Da
,
04/13/2012
Year/Period of Report
End of 2011/04
TRANSMISSION LINE STATISTICS (Continued)
7.Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8.Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9.Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10.Base the plant cost figures called for in columns (j) to (I) on the book cost at end of year.
Size of
Conductor
and Material
(I)
COST OF LINE (Include in Column (j) Land
Land rights, and clearing right-of-way)
EXPENSES EXCEPT DEPRECIATION AND TAXES -
Line
IMO.
Land
(j)
Construction and
Other Costs
(k)
Total Cost
(I)
Operation
Expenses
(m)
Maintenance
Expenses
(n)
Rents
(o)
Total
Expenses
(p)
I155ACSR 1469 637,273 651,970 1
795 AAC 49,642 49,642 2
795 AAC 489,03A 1,944,888 2433925 3
I272ACSR 935,721 3,601 ,861 4,537,586 4
1272 ACSR 34,687 838,605 873,292 5
I155ACSR 179,817 2,909,434 3,089,251 6
I95AAC 43,035 435,188 478,223 7
1272 ACSR 140,41 709,148 849,560 8
1272 ACSR 9
795 ACSR 134,471 1405,436 1,539,907 10
7155ACSR 2,473,832 18,432,096 20,905,929 11
7I55ACSR 12
7155ACSR 13
I155ACSR 14
7155ACSR 15
1272 ACSR 78,57 1,821,921 1,900,500 16
40,58 40,580 17
715.5 ACSR 331,53 4,682,879 5,014,418 18
19
1272 ACSR 272,231 2,141,218 2,413,449 20
95ACSR 21
95 ACSR 22
95ACSR 351,497 351,497 23
15.5ACSR 1,174 212,777 213,951 24
272 ACSR 19 398 59 25
95 ACSR 356,945 356,945 26
272 ACSR 27
95ACSR 28
95ACSR 29
50 COPPER 5 63,805 63,863 30
15.5 ACSR 76,560 76,560 31
97.5 ACSR 4,406 4,406 32
15.5 ACSR 5,56E 384,068 389,634 33
97.5ACSR 4,35 2,220,763 2,225,118 34
715.5ACSR 86,651 1,866,338 1,952,989 35
31,147,986 426,733,642 457,881,628 36
FERC FORM NO. 1 (ED. 12-87) Page 423.3
Name of Respondent
Idaho Power Company
This Re ort Is:
(2) []A Resubmission
Date of Report
(Mo, Da, Yr)
04/13/2012
Year/Period of Report
End of 2011/Q4
TRANSMISSION LINE STATISTICS
1.Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2.Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3.Report data by individual lines for all voltages if so required by a State commission.
4.Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5.Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6.Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line
No
DESIGNATION VOLTAGE (Ky)
(Indicate where
other than
60 cycle, 3 phase)
Type of
Supporting
Structure
(e)
LENGTH (Pole Tiles) in the Cas1,oT
U dergroun ilpes
report circuit miles)
Number
Of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
On Structure
D of. Line esia
on structures of er Line
(g)
1 Strike Jct Bowmont 138.01 138.00 S Tower 0.36 1
2 Strike Jot Bowmont 138.01 138.00 H Wood 6824 1
3 Lucky Peak Lucky Peak Jot 138.01 138.00 H Wood 4.48 2
4 Bliss King 138.01 138.00 H Wood 10.47 1
5 Milner Deadend Milner PP 138.01 138.00 SPWood 1.31 1
6 Swan Falls Tap 138.01 138.00 H Wood 1.00 1
7
8
9
10 Hines BPA(Hamey) 115.00 115.00 H Wood 3.281 1
12
13 69 Ky Lines 6901 6900 H Wood 16631 1
14 69 Ky Lines 69.01 69.00 S P Wood 938.98 1
15
16
17 46 Ky Lines 46.01 46.00 S P Wood 409.08 1
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
TOTAL 4,759.01 11.02 186
FERC FORM NO 1 (ED 12-87) Paae 4224
I
.
Name of Respondent This Re rt Is:
Idaho Power Company (2) M A Resubmission
Date of Report
04/13/2012
Year/Period of Report
End of 2011/Q4
TRANSMISSION LINE STATISTICS (Continued)
7.Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8.Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9.Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10.Base the plant cost figures called for in columns (j) to (I) on the book cost at end of year.
Size of
and Material
(I)
COST OF LINE (Include in Column (I) Land,
Land rights, and clearing right-of-way)
Conductor
EXPENSES, EXCEPT DEPRECIATION AND TAXES -
Line
['10.
Land
(1)
Construction and
Other Costs (k)
Total Cost
(I)
Operation
Expenses
(m)
Maintenance
Expenses
(n)
Rents
(0)
Total
Expenses
(p)
155ACSR 1
2
155ACSR 279,481 279,488 3
15.5 ACSR 5,62 1,052,343 1,057,963 4
15.5 ACSR 2,81 183,606 186,420 5
97.5ACSR 12,88 261,511 274,396 6
7
8
9
975 ACSR 1,97E 63,404 65,382 10
11
12
VARIOUS 1 ,499,275 49,640,986 51 ,140,261 13
VARIOUS 14
15
16
VARIOUS 307,949 13,432,476 13,740,425 17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
31 147986 426,733,642 457,881,628 36
FERC FORM NO. I (ED. 12-871 Paae 423.4
Name of Respondent
Idaho Power Company
This Report Is:
(1)MAn Original (2)flA Resubmission
Date of Report
(Mo, Da, Yr)
04/13/2012
Year/Period of Report
End of 2011/04
TRANSMISSION LINES ADDED DURING YEAR
1.Report below the information called for concerning Transmission lines added or altered during the year. It is not necessary to report
minor revisions of lines.
2.Provide separate subheadings for overhead and under- ground construction and show each transmission line separately. If actual
costs of competed construction are not readily available for reporting columns (l) to (a), it is permissible to report in these columns the
Line
No.
LINE DESIGNATION LLU1e lth
Miles
(c)
SUPPORTING STRUCTURE CIRCUITS PER STRUCTUR
From
(a)
To
(b)
Type -
(d)
Number
Miles
(e)
Pr esent
(f)
Ultimate
(g)
I Rockland Jct Tockland Wind Farm 5.31 S Pole 19.50
2 Kimberly Tap 1.83 S Pole 9.40 2 2
3 Victory Jct Victory 1.90 S Pole 19.50
4
5 Neils Hot Springs Neils Hot Springs 10.44 W Pole 9.90
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
21'
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44 TOTAL 19.48 58.30 5
FERC FORM NO. I (REV. 12-03) Paae 424
Name of Respondent This Report Is:
Idaho Power Company
j (2) AResubmission
Date of Report
04/13/2012
Year/Period of Report
End of 2011/Q4
TRANSMISSION LINES ADDED DURING YEAR (Continued)
costs. Designate, however, if estimated amounts are reported. Include costs of Clearing Land and Rights-of-Way, and Roads and
Trails, in column (I) with appropriate footnote, and costs of Underground Conduit in column (m).
3. If design voltage differs from operating voltage, indicate such fact by footnote; also where line is other than 60 cycle, 3 phase,
indicate such other characteristic.
CONDUCTORS voltage
KV
(Operating) (k)
LINE COST Line
No. Size
(h)
Specification
(i)
Configuration
and Spacing
(j)
Land and
Land Rights
(I)
_________
Poles, Towers
and Fixtures
(m)
Conductors
and Devices (n)
Asset
Retire. Costs
(0)
Total
(p)
795 ACSR TAS 138 240,72C 116,225 356,945 1
795 ACSR TVS-DC-HL 138 642,84 434,937 1,077,786 2
1272 ACSR TAS 138 52,884 1,072,201 715,589 1,840,681 3
4
397.5 ACSR T 69 1,22: 1,841 3,064 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
52,884 1,957,OOC 1,268,5921 3,278,476J 44
FERC FORM NO. 1 (REV. 12-03) Page 425
Name of Respondent
Idaho Power Company
This Re ort Is:
2'RLion
Date of Re
04/13/2012 port
Year/Period of Report
End of 2011/Q4
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3.Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4.Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
No
-
Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (In MVa)
Primary
(C)
Secondary
(d)
Tertiary
(e)
1 Adelaide transmission 345.00 138.00 13.80
2 Aiken distribution 46.00 13.00
3 Alameda distribution 46.00 13.00
4 Alameda 1distribution 138.00 13.09
5 American Fafls PP - attended Jtransmission 138.00 13.80
6 American Falls transmission 138.00 46.00 12.47
7 Artesian distribution 46.00 13.00
8 Bannock Creek distribution 46.00 13.00
9 Bennett Mountain Power Plant- attended transmission 230.00 18.00
10 Bennett Mountain Power Plant- attended distribution 18.00 4.16
11 Bethel Court distribution 138.00 13.00
12 Black Cat distribution 138.00 13.09
13 Blackfoot distribution 46.00 13.00
14 Blackfoot transmission 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 35.00
18 Boise Bench - attended transmission 230.00 138.00 13.20
19 Boise Bench - attended distribution 138.00 35.00
20 Boise Bench - attended transmission 138.00 69.00 12.98
21 Boise Bench - attended . transmission 230.00 138.00 13.80
22 Boise distribution 138.00 13.00
23 Borah transmission 345.00 230.00 13.80
24 Bowmont distribution 69.00 46.00 6.90
25 Bowmont distribution 138.00 35.00
26 Bowmont transmission 138.00 69.00 12.98
27 Bowmont transmission 138.00 69.00 12.47
28 Bowmont transmission 230.00 138.00 13.80
29 Brady distribution 46.00 13.00
30 Brady transmission 230.00 138.00 13.80
31 Brady transmission 138.00 46.00 12.47
32 Brady distribution 69.00 13.00
33 Brownlee - attended transmission 230.00 13.80
34 Bruneau Bridge distribution 138.00 35.00
35 Buckhom distribution 69.00 35.00
36 Bucyrus distribution 46.00 7.20
37 Buhl distribution 46.00 13.00
38 Burley Rural distribtio" i 69.00 13.00
39 Butler distribution 138.00 13.09
40 Caldwell distribution 138.00 13.00
FERC FORM NO I (ED 12 98 Pn 426
Name of Respondent
Idaho Power Company
This Re ort Is:
AResubmission
Date of Report
04/13/2012
Year/Period of Report
End of 201 1/Q4
SUBSTATIONS (Continued)
5.Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6.Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(In Service) (In MVO)
(f)
Number of
Transformers
In Service
(g)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.
-
Type of Equipment
(I)
Number of Units
(j)
Total Capacity
(k)
300 2 1
20 2 2
15 1
18 1
72 1 5
25 1 6
10 1 -y
10 1 8
135 1
5 1
15 1
24 1
30 2
50 3 1 14
80 1 15
69 3
15 1
254 2
42 2
75 3 20
240 2 21
67 3
450 3 1
8 3
18 1
25 1 26
25 1 27
180 1
5 29
312 3
1
1 -
721 5 1
30 2 34
20 1 35
6 1 1
20 2
12 1
48 2
15 1 40
(ED. 12-96) Paae 427
Name of Respondent
Idaho Power Company
j
This Re oil Is: 2I1RSSIOn
Date of Report Year/Period of Report
End of 2011/04
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3.Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4.Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
N °.
-
Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (In MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
I Caldwell distribution 138.00 13.09
2 Caldwell transmission 138.00 69.00 12.47
3 Caldwell transmission 230.00 138.00 12.47
4 Caldwell distribution 13.00 4.16
5 Canyon Creek distribution 138.00 35.00
6 Canyon Creek transmission 138.00 69.00 12.98
7 Cascade Power Plant - attended transmission 69.00 4.60
8 Cascade Distribution 69.00 13.10
9 Chestnut distribution 138.00 13.00
10 Clear Lake -attended transmission 46.00 2.40
11 Cliff transmission 138.001 46.00 12.50
12 Cliff transmission 138.00 46.00 12.95
13 Cloverdale Distribution 138.00 13.00
14 Dale distribution 46.00 13.00
15 Dale distribution 69.00 13.00
16 Dale distribution 138.00 36.20
17 Dale Transmission 13800 4600 1247
18 Danskin- attended Transmission 230.00 18.00
19 Danskin- attended transmission 230.00 138.00 13.80
20 Danskin- attended distribution 18.00 4.16
21 Danskin- attended transmission 138.00 12.00
22 Don distribution 138.00 7.60
23 Don distribution 138.00 13.20
24 Don distribution 138.00 13.00
25 Don distribution 14.00
26 DRAM distribution 138.00 13.09
27 DRAM transmission 230.00 138.00 13.80
28 DRAM distribution 138.00 12.47
29 Duffin distribution 138.00 35.00
30 Eagle distribution 138.00 13.09
31 Eastgate distribution 13800
32 Eastgate distribution 138.00 13.00
33 Eckert distribution 138-00 3620
34 Eden distribution 138.00 36.20
35 Eden transmission 138.00 46.00 12.98
36 Elkhorn distribution 138.00 12.47
37 1 Elkhorn distnbution 13800 13.00
38 Elmore distribution 13800 3500
39 Elmore Ttransmission 138.00 69.00 12.50
40 Emmett distribution 138.00
FERC FORM NO. I (ED. 12-96) Page 426.1
Name of Respondent
Idaho Power Company
This Report Is:
0 An Original
(2) E] A Resubmission
Date of Report
04/13/2012 1
Year/Period of Report
End of 201 1/Q4
SUBSTATIONS (Continued)
5.Show in columns (I), U) and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6.Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(In Service) (In MVa)
(f
Number of
Transformers
In Service
(g)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.
-
Type of Equipment
(I)
Number of Units
a)
Total Capacity
(k)
24 1 1
75 3 2
240 2 3
15 1
15 1 6
12 1
10 1 8
48 2
4 1 10
12 2 1
4 1
48 2 13
7
1 15
27 1 16
25 1 17
140 1
180 1
6 1 20
96 2 21
1 -
108 6 3
26 1 1 24
80 6 25
118 7 26 1
160 2 27
17 1
36 2 29
38 2 30
24 1 31
18 1
18 1
24 1
15 1
8 1 36
8 1
17 1
30 2 39
24 1
FERC FORM NO. 1 (ED. 12-96) Page 427.1
Name of Respondent
Idaho Power Company
This Re ott Is:
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/13/2012
Year/Period of Report
End of 2011 /Q4
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3.Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4.Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
No Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (In MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 Emmett Transmission 138.00 69.00 12.47
2 Falls distribution 46.00 13.00
3 Filer distribution 46.00 1300
4 Flying H distribution 69.00 2.40
5 Fort Hall distribution 46.00 13.00
6 Fossil Gulch distribution 138.00 35.00
7 Fremont transmission 138.00 46.00 12.50
8 Gary distribution 138.00 13.00
9 Gem distribution 69.00 13.00
10 Gem distribution 69.00
11 Goodng Rural distribution 46.00 13.00
12 Golden Valley distribution 69.00 13.00
13 Gowen Substation distribution 138.00 35.00
14 Grindstone distribution 35.00
15 Grove distribution 138.00 13.09
16 Hagerman distribution 46.00 13.00
17 Hagerman distribution 46.00 13.00 32.00
18 Hailey distribution 138.00 13.00
19 Happy Valley distribution 138.00 13.09
20 Haven distribution 138.00 35.00
21 Haven transmission 138.00 46.00
22
23
RW
Hewlett Packard
ansmission 50000 23000 3450
distribution 138.00 13.00
24 Hidden Springs distribution 138.00 13.00
25 Highland distribution 138.00 13.00
26 Hill distribution 138.00 13.00
27 Hillsdale distribution 138.00
28 Hoku distribution 138.00 13.80
29 Homedale distribution 69.00 13.00
30 Horse Flat transmission 230.00 138.00 13.80
31 Horseshoe Bend distribution 35.00
32 Horseshoe Bend distribution 69.00 36.20
33 Horseshoe Bend distribution 69.00 25.00
34 Huston distribution 69.00 13.00
35 Hulen distribution 46.00 13.00
36 1 Hunt transmission 230.00 138.00 13.80
37 1 Hydra distribution 13800 3620
38 Island distribution 69.00 1300
39 Jerome distribution 138.00 13.00
40 Julion Clawson distribution 138.00 35.00
FERC FORM NO. I (ED. 12-961 Paae 426.2
• Name of Respondent
Idaho Power Company
This Re ort Is:
2R?Lion
Date of Report I Year/Period of Report
End of 2011/Q4
SUBSTATIONS (Continued)
5.Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6.Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(In Service) (In MVa)
(f)
Number of
Transformers
In Service
(g)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No. Type of Equipment
(i)
Number of Units
(j)
Total Capacity
(k)
25 1 1
18 2 2
10 1
15 2
10 1 1 —s
15 1 6
50 3 1
37 2 8
8 1 9
10 1 —To
15 2
10 1 1
24 1 13
5 2
72 3 15
10 1
5 1
20 1
18 1 19
12 1
25 1 21
600 3 1
20 1 23
8 1 24
18 1 25
39 2
24 1 27
72 2
22 2 29 1
100 1 30
5 1
12 1
5 1
-- 10 1
10 1 -.
300 3
48 2
12 1
40 2
30 2
Pace 427.2
Name of Respondent -
Idaho Power Company
This Report Is:
Original
(2) []A Resubmission 7
Date of Report
(Mo, Da, Yr)
04/13/2012
Year/Period of Report
End of 2011/04
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3.Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4.Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
No
-
Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (In MVa)
Primary
(c)
Secondary
(d)
Tertiary
(a)
1 Joplin distribution 138.00 13.00
2 Joplin distribution 138.00 35.00
3 Karcher distribution 138.00 13.00
4 Kenyon distribution 69.00 13.00
5 Ketchum distribution 138.00 13.00
6 Kimberly distribution 138.00 13.00
7 Kinport transmission 161.00 46.00 13.20
8 Kinport transmission 230.00 138.00 12.47
9 Kinport transmission 230.00 138.00 13.80
10 Kinport transmission 345.00 230.00 13.80
11 Kramer distribution 138.00 35.00
12 Kramer distribution 138.00 36.20
13 Kuna distribution 138.00 13.00
14 Lake Fork distribution 138.00 36.20
15 Lake Fork transmission 138.00 69.00 12.50
16 Lamb distnbution 13800 13.00
17 Lansing distribution 69.00 13.00
18 Lincoln distribution 138.00 13.09
19 Linden distribution 138.00 13.00
20 Locust distribution 138.00 36.20
21 Locust transmission 230.00 138.00 13.80
22 Lower Malad - attended transmission 138.00 7.20
23 Lower Salmon - attended transmission 138.00 13.80
24 Map Rock distribution 69.00 13.00
25 McCall distribution 13.00 13.09
26 McCall distribution 138.00 36.20
27 Meridian distribution 138.00 13.00
28 Micron distribution 138.00 13.09
29 Micron distribution 138.00 13.00
30 Midpoint transmission 230.00 138.00 13.80
31 Midpoint transmission 345.00 230.00 13.80
32 Midpoint transmission '500.00 345.00
33 Midrose distribution 138.00 13.09
34 Milner transmission 13800 6900 12.47
35 Milner distribution 69.00 46.00 6.90
36 Milner distribution 138.00 35.00
37 Milner PP - attended transmission 138.00 13.80
38 Moonstone distribution 13800 3500
39 Mora distribution 138.00 35.00
40 Mora distribution 138.00 36.20
Page 426.3
Name of Respondent
Idaho Power Company
This Report Is:
(2) R A Resubmission
Date of Report
04/13/2012
Year/Period of Report
End of 201 1/Q4
SUBSTATIONS (Continued)
5.Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6.Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(In Service) (In MVa)
(f)
Number of
Transformers
In Service
(g)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.
-
Type of Equipment
(i)
Number of Units
(j)
Total Capacity
(k)
15 1 1
18 1 2
12 1
20 2
42 2
18 1 6
7 7
180 1 8
180 1 9
600 3 1 10
12 1
18 1
15 1
18 1
15 1
18 1
12 1
10 1
33 2 19
48 2
360 2
16 1
70 4 23
10 1 _-;i
12 1
18 1
36 2 27
24 2
24 2
120 1
720 2
750 3 1
24 1
100 4 34
8 3 1
29 2
36 1
121 1
15 1
24 1
FERC FORM NO. 1 (ED. 12-96) Page 427.3
Name of Respondent
Idaho Power Company
This Rort Is:
(2) [:]A Resubmission
Date of Report
(Mo,Da,Yr)
04/1312012
Year/Period of Report
End of 2011/Q4
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or Street railway customer should not be listed below.
3.Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4.Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
No
-
Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (In MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 Moreland distribution 35.00 13.00
2 Moreland distribution 46.00 13.00
3 Moreland distribution 46.00 35.00 12.47
4 Mountain Home distribution 69.00 13.00
5 Mountain Home Air Force Base distribution 69.00 13.00
6 Mountain Home Air Force Base distribution 138.00 13.00
7 Nampa distribution 230.00 138.00 13.80
8 Nampa distribution 138.00 13.00
9 New Meadows distribution 138.00 36.20
10 New Plymouth distribution 69.00 13.00
11 Notch Butte distribution 138.00 13.09
12 Orchard distribution 69.00 36.20
13 Orchard distribution 69.00 35.00 12.47
14 Parma distribution 69.00 13.00
15 Parma distribution 69.00 35.00
16 Paul distribution 138.00 35.00
17 Payette distribution 138.00 13.00
18 Pingree transmission 138.00 46.00 12.50
19 Pingree distribution 138.00 35.00
20 Pleasant Valley distribution 138.00 35.00
21 Pocatello distribution 46.00 13.00
22 Poleline distribution 138.00 13.09
NO
Portneuf distribution
26
transmission 34500
138.00 35.00
L25
Portneuf distribution 46.00 35.00
Rockford distribution 46.00 13.00
27 Russett distribution 138.00 13.00
28 Sailor Creek distribution 138.00 2.40
29 Sailor Creek distribution 138.00 35.00
30 Salmon distribution 69.00 13.00
31 Salmon distribution 69.00 34.50 12.47
32 Salmon distribution 69.00 12.47
33 Salmon transmission 13.00 2.40
34 Shoshone distribution 4600 13.00
35 Shoshone distribution 4600 7.20
36 Shoshone Falls attended transmission 46.00 2.30
37 Shoshone Falls attended transmission 46.00 6.60
38 Silver distribution 13&00 35.00
39 Simplot distribution 138.00 13.00 1
40 Sinker Creek distribution 138.00 35.00
FERC FORM NO. I (ED. 12-961 Pace 426.4
Name of Respondent
Idaho Power Company
This Report Is:
El (2) []A Resubmission
Date of Report
04/13/2012
Year/Period of Report
End of 201 1/Q4
SUBSTATIONS (Continued)
5.Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6.Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(In Service) (In MVa)
(f)
Number of
Transformers
In Service
(g)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No. Type of Equipment
(i)
Number of Units
(j)
Total Capacity
(k)
6 1 1
8 1 2
8 4 3
15 1
18 1 6
180 1
50 3 8
12 1
10 1
10 1
6 1
10 3
10 1
12 1
36 2
23 3
50 3 18
22 2
42 2 20
36 2
18 1
23
18 1 24
1 -
14 2
18 1
15 2
15 1
10 1 3
10 3
2
5 2
10 1
2 3
3 1
10 1
12 1 1 38
15 1
12 1
FERC FORM NO.1 (ED. 12-96) Pace 427.4
Name of Respondent - - -
Idaho Power Company
This Report Is:
(2) [:]A Resubmission
Date of Report
04/13/2012
Year/Period of Report
End of 2011/Q4
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3.Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4.Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
No Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (In MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 Siphon distribution 138,00 35.00
2 South Park distribution 46.00 13.00
3 Star distribution 138.00 13.09
4 Starkey Transmission 138.00 69.00 12.47
5 State distribution 69.00 13.00
6 Stoddard distribution 138.00 13.00
7 Strike Power Plant - attended transmission 138.00 13.80
8 Sugar distribution 138.00 35.00
9 Swan Falls - attended transmission 138.00 6.90
10 Taber distribution 46.00 13.00
11 Ten Mile distribution 138.00 13.09
12 Terry distribution 138.00 13.09
13 Thousand Springs - attended transmission 46.00 7.20
14 Thousand Springs - attended transmission 7.00 2.40
15 Toponis distribution 138.00 33.00
16 Twin Falls distribution 138.00 13.09
17 Twin Falls transmission 138.00 46.00 12.98
18 Twin Falls PP - attended transmission 138.00 7.20
19 Twin Falls PP - attended transmission 138.00 13.20
20 Upper Malad - attended transmission 45.00 7.20
21 Upper Salmon- attended transmission 138.00 7.20
22 Ustick distribution 138.00 13.00
23 Vallivue distribution 138.00 13.09
24 Victory distribution 138.00 13.00
25 Victory distribution 138.00 13.09
26 Ware distribution 69.00 13.00
27 Weiser distribution 69.00 13.00
28 Weiser transmission 138.00 69.00 12.47
29 Wilder distribution 69.00 13.00
30 Willis distribution 138.00 13.09
31 Wye distribution 138.00 13.00
32 Zilog distribution 138.00 13.09
33
34
35 The above are all State of Idaho
36
37 Montana:
38 Peterson transmission 230.00 69.00 13.20
39
40 Nevada:
FERC FORM NO. I (ED. 12-96) Pace 426.5
Name of Respondent
Idaho Power Company
This Report Is:
2 'R 'ssion
Date of Report
04/13/2012
Year/Period of Report
End of 201 1/Q4
SUBSTATIONS (Continued)
5.Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6.Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(In Service) (In MVa)
(0
Number of
Transformers
In Service
(g)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.
-
Type of Equipment
(i)
Number of Units
U)
Total Capacity
(k)
33 2 1
10 1
18 1
18 1
33 2
15 1 6
83 3
20 2 8
18 1
5 1
24 1
42 3
8 1
3 1
18 1 Is
44 2
33 2
9 1
72 1
8 1 20
36 4
44 2
18 1
24 1 24
18 1 25
12 1 1
20 2 27
25 1 28
10 1 -
18 1 30
56 3
24 1 32
33
34
- 35
36
37
30 31 1
39
40
FERC FORM NO. 1 (ED. 12-96) Page 427.5
Name of Respondent
Idaho Power Company
This Re oil Is:
(2) A Resubmission
Date of Report
(Mo35ar)
Year/Period of Report
End of 201 1 /Q4
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 functiona! character, but the number of such substations must be shown.
4.Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
No.
-
Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (In MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
_j : . . transmission 345.00 17.40
2 /elmy - alleIKed transmission 345.00 22.00
3 Wells transmission 138.00 69.00 13.00
4
5 Oregon:
6 floardman-attended transmission 500.00 24.00
7 transmission 23000 720
Boa nded ;: transmission 24.00 7.20
9 Cairo distribution 69.00 13.00
10 Hells Canyon - attended transmission 230.00 13.80
111 Hells Canyon - attended distribution 69.00 0.50
12 Hines transmission 138.00 115.00 12.47
13 Malheur Butte distribution 69.00 34.50
14 Nyssa distribution 69.00 13.00
15 Ontario distribution 138.00 13.00
16 Ontario transmission 138.00 69.00 12.47
17 Ontario transmission 230.00 138.00 13.80
18 Ontario transmission 138.00 69.00 12.98
19 Ontario transmission 138.00 69.00 13.09
20 Ore-Ida distribution 69.00 13.00
21 Oxbow - attended transmission 138.00 69.00 13.00
22 Oxbow - attended transmission 230.00 13.80
23 Oxbow - attended transmission 230.00 138.00 13.80
24 Quartz transmission 138.00 69.00 12.50
25 Quartz transmission 230.00 138.00 12.98
26 Quartz transmission 138.00 69.00 12.98
27 Vale distribution 69.00 13.00
28
29 Wyoming:
30
_________
insmission 345.00 22.00
31 insmission 345.00 23000 3450
37 Transformers-distribution substations under 10,000
38 KVA 84 unattended.
39
40
FERC FORM NO. 1 (ED. 12-96) Page 426.6
Name of Respondent
Idaho Power Company
This Report Is:
(2) 9 AResubmission
Date of Report
04/13/2012
Year/Period of Report
End of 2011/04
SUBSTATIONS (Continued)
5.Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6.Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(In Service) (In MVa)
(f)
Number of
Transformers
In Service
(g)
Number of
Spare
Transformers
(Ii)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.
-
Type of Equipment
(1)
Number of Units
(j)
Total Capacity
(k)
315 1 1
300 1 1 2
20 3 1 3
4
5
685 3 1 6
55 1
55 1 8
12 1
500 3 10
1
40 1 12
8 3 1 13
20 2 14 1
38 2
25 1 1 16
240 2 17
50 2 18
1
15 1 20
10 3 1 21 1
244 2
100 1 23
15 1 24
100 3 1 25
15 1 26
10 1
28
29
1122 2 30
1084 22
32
33
34
35
36
37
342
39
40
FERC FORM NO. I (ED. 12-96) Page 427.6
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)_ A Resubmission 04/13/2012 2011/Q4
FOOTNOTE DATA
Schedule ? c; --
PacifiCorp has a 59% interest in certain high-voltage transmission related and
interconnect ion equipment located at Idaho power's Hemingway Station.
SchedulePge: 4264 Line No.: 23
Idaho Power has a 20.8% interest in certain high-voltage transmission related and
interconnection equipment located at PacifiCorp's Populus station.
Schedule Page: 426.6 Line No.: I Column: a
Jointly owned with Sierra Pacific Power Company, d/b/a NV Energy. Idaho Power has a 50%
share of ownership.
Schedule Page: 426.6__Line No.: 2 Column: a
Jointly owned with Sierra Pacific Power Company, d/bla NV Energy. Idaho Power has a 50%
share of ownership.
SchedulePa9e4266 Line No6 Column a -
Jointly owned with Portland General Electric, Power Resources Cooperative and BA Leasing
BCS, LLC. Idaho Power has a 10% share of the jointly owned capacity,. 100% of the capacity
is reported.
Schedule Page 4266 LineNo 7 CoIum!1_
Jointly owned with Portland General Electric, Power Resources Cooperative and BA Leasing
BCS, LLC. Idaho Power has a 10% share of the jointly owned capacity. 100% of the capacity
is reported.
schedule Page 4266 Line No 8 Column a - -
- Jointly owned with Portland General Electric, Power Resources Cooperative and BA Leasing
BCS, LLC. Idaho Power has a 10% share of the jointly owned capacity. 100% of the capacity
is reported.
ceciuIe Page: 426.6 Line No.: 30 Column: a
Jointly owned with PacificCorp. Idaho Power has 33.3% share of ownership.
Schedule Page: 426.6 Line No.: 31 Column: a
Jointly owned with PacificCorp. Idaho Power has a 33.3% share of ownership.
fC FORM NO. I (ED. 12-87) Page 450.1 I
Name of Respondent
Idaho Power Company
This Re 0,1 Is:
(1)An Original
(2)fl A Resubmission
Date of Report
(Mo, Da, Yr)
04/13/2012
Year/Period of Report
End of 2011/04
TRANSACTIONS WITH ASSOCIATED (AFFILIATED) COMPANIES
I Report below the information called for concerning all non power goods or services received from or provided to associated (affiliated) 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/affiliated company for non-power goods and services. The good 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 billed to or received from the associated(affiliated) company are based on an allocation process, explain in a footnote.
Line
No.
-
1
2
Description of the Non-Power Good or Service
(a)
Non-power Goods or Services Provided by Affiliated
Name of
Associated/Affiliated
Company
(b)
Account
Charged or
Credited
(c)
Amount
Charged or
Credited
(d)
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
Non-power Goods or Services Provided for Affiliate
Managerial Expense IOACORP Inc 417420 457,141
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO I (New) Page 429
FERC FORM NO 1-F (New)
December 31, 2011
Page
Number
1
2
3
3
4
5
6
7-10
11
12-15
15
ANNUAL REPORT
IDAHO SUPPLEMENT TO FERC FORM I
MULTI-STATE ELECTRIC COMPANIES
INDEX
Title
Statement of Income for the Year
Taxes Allocated to Idaho
Notes and Accounts Receivable
Accumulated Provision for Uncollectible Accounts
Receivables from Associated Companies
Gain or Loss on Disposition of Property
Professional or Consultative Services
Electric Plant in Service
Electric Operating Revenues
Electric Operation and Maintenance Expenses
Number of Electric Department Employees
IDAHO SUPPLEMENT
THIS PAGE INTENTIONALLY LEFT BLANK
STATE OF IDAHO - ALLOCATED
Idaho Power Company M Original December 31, 2011
STATEMENT OF INCOME FOR THE YEAR
1.Report amounts for accounts 412 and 413, Revenue and Expenses from Utility Plant Leased to Others, in another utility
column (i,k,m,o) in a similar manner to a utility department. Spread the amount(s) over lines 01 thru 24 as appropriate.
Include these amounts in columns (c) and (d) totals.
2.Report amounts in account 414, Other Utility Operating Income, in the same manner as accounts 412 and 413 above.
3.Report data for lines 7, 9, and 10 for Natural Gas companies using accounts 404.1, 404.2, 404.3, 407.1, and 407.2.
4.Use page 122 for important notes regarding the state ment of income or any account thereof.
5.Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a
material amount may need to be made to the utility's customers or which may result in a material refund to the utility
with respect to power or gas purchases. State for each year affected the gross revenues or costs to which the contingency
relates and the tax effects together with an explanation of retain such revenues or recover amounts paid with respect
to power and gas purchases.
6.Give concise explanations concerning significant amounts of any refunds made or received during the year.
(Ref.)
Line Account Page TOTAL
No. No Current Year Previous Year
- (a) (b) (c) (d)
1 UTILITY OPERATING INCOME
2 Operating Revenues (400)........................................................................ 11 $ 969,760,290 $ 978,237,919
3 Operating Expenses
4 Operation Expenses (401)...................................................................... 15 600,989,160 591,076,570
5 15 72,381449 66,618,522
6 Depreciation Expense (403) ................................................................. 108,248,039 101,868,184
7
Maintenance Expenses (402)..................................................................
Amort. & DepI. of Utility Plant (404-405) ................................................ . 6,087,113 5,959,981
8 Amort. of Utility Plant Acq. Adj. (406).....................................................
9 Amort. of Property Losses, Unrecovered Plant and
10 Regulatory Study Costs (407)..............................................................
11 Amort. of Conversion Expenses (407)...................................................
12 Regulatory Debits/Credits (407.3 & 407.4) - -
13 Taxes Other Than Income Taxes (408.1)...............................................2 26,932,746 21,747,745
14 Income Taxes - Federal (409.1).............................................................2 (54,366,437) 7,279,837
15 - Other (409.1) .......................................................................... .2 (731,383) 2,997,295
16 Provision for Deferred Income Taxes (410.1 & 411.1) Net .................. .2 16,500,157 2,215,520
17 Investment Tax Credit Adj. - Net (411.4)................................................. 2 (1,083,203) (1,423,437)
18 (Less) Gains from Disp. of Utility Plant (411.6)......................................
19 Losses from Disp. of Utility Plant (411.7)...............................................
20 (Less) Gains from Disposition of Allowances (411.8).............................
21 Losses from Disposition of Allowances (411.9)......................................
22
23 TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 22) 774,957,642 798,340,218
24
25 Net Utility Operating Income (Enter Total of line 2 less 23)
26 (Carry forward to page 11, line 27)...................................................... $ 194,802,648 $ 179,897,701
IDAHO SUPPLEMENT Page 1
STATE OF IDAHO - ALLOCATED
Idaho Power Comanv An Original December 31, 2011
1
TAXES ALLOCATED TO IDAHO
Taxes Charged
Kind of Tax During Year
Taxes Other Than Income Taxes:
Labor Related:
FICA............................................................ $ 12,338,706
FUTA........................................................... 115,222
State Unemployment.................................. 669,492
Payroll Deduction & Loading...................... (13,123,419)
Total Labor Related 0
Property Taxes............................................... 22,194,277
Kilowatt-hour Tax........................................... 2,324,425
Licenses......................................................... 4,461
Regulatory Commission Fees........................ 2,089,245
Irrigation PlC .................................................. 320,338
Total Taxes Other Than Income Taxes 26,932,746
Federal Income Taxes..................................... (54,366,437)
State Income Taxes......................................... (731,383)
Deferred Income Taxes................................... 16,500,157
Investment Tax Credit Adjustment - Net (1,083,203)
Total Taxes Allocated to Idaho........................ $ (12,748,120)
STATE OF IDAHO - ALLOCATED
Idaho Power Company An Original
December 31, 2011
NOTES AND ACCOUNTS RECEIVABLE
Summary for Balance Sheet
Show separately by footnote the total amount of notes and accounts receivable
from directors, officers, and employees included in Notes Receivable (Account
141) and Other Accounts Receivable (Account 143)
Balance Balance
Line Accounts Beginning of End of
Year Year
No. (a) (b) (c)
1 Notes Receivable (Account 141) .................................................................................... $ 303,143 $ 94,776
2 Customer Accounts Receivable (Account 142) ..............................................................
.
.63,612,796 67,534,733
3 Other Accounts Receivable (Account 143) ..................................................................... 6,166,234 8,206,727
4 (Disclose any capital stock subscription received)
5
6
Total ........................................................................................................................ $ 70,082,172 $ 75,836,237
7 Less: Accumulated Provision for Uncollectible
8
9
Accounts-Cr. (Account 144) .................................................................................... .. 1,641,302 1,435,434
10 Total, Less Accumulated Provision for
11
12
$ 68,440,870 $ 74,400,803
13
14 Notes Receivable - Account 141: (at 12-31-11)
.
15
16
Uncollectible Accounts ............................................................................................
Directors, officers, and employees - -
17
18 Other Accounts Receivable - Account 143: (at 12-31-11)
19
20
Directors, officers, and employees - -
1
ACCUMULATED PROVISION FOR UNCOLLECTIBLE ACCOUNTS - CR. (Account 144)
1.Report below the information called for concerning this accumulated provision.
2.Explain any important adjustments of subaccounts.
3 Entries with respect to officers and employees shall not include items for utility services
Mdse,
Line Item Utility Jobbing & Officers Other Total
Customers Contract and
No. (a) Work Employees
(b) (c) (d) (e) (f)
21
22
23
24
25
26
27
Bal. beginning of year
Prov. for uncollectibles
for year.............................................
Accounts written off............................
Coll. of accounts
written off..........................................
$ 1,641,302 $ $ $ (205,868) $ 1,435,434
28
29
30
32
33 1
Adjustments (explain).........................
Balance end of year ............................
31
$ 1,641,302 $ $ - $ (205,868) $ 1,435,434 .
Page 3
STATE OF IDAHO - ALLOCATED
Idaho Power Company An Original December 31, 2011
RECEIVABLES FROM ASSOCIATED COMPANIES (Accounts 145, 146)
1.Report particulars of notes and accounts receivable from associated companies at end of year.
2.Provide separate headings and totals for accounts 145, Notes Receivable from Associated Companies, and 146,
Accounts Receivable from Associated Companies, in addition to a total for the combined accounts.
3.For notes receivable list each note separately and state purpose for which received. Show also in column
(a) date of note, date of maturity and interest rate.
4.If any note was received in satisfaction of an open account, state the period covered by such open account.
5.Include in column (f) interest recorded as income during the year, including interest on accounts and notes
held at any time during the year.
6.Give particulars of any notes pledged or discounted, also of any collateral held as guarantee of payment
of any note or account.
Balance
Line Particulars Beginning Totals for Year Balance Interest
of Year End of Year For Year Debits Credits
No. (a) (b) (c) (d) (e) (1)
1 Account 145:
2
3 IERCO ................................ $ 14,384,928 $ 46,929,729 $ 43,979,638 $ 17,335,019
4
.
5
6
7
8
9
10 Total Account 145 ................. 14,384,928 46,929,729 43,979,638 17,335,019
11
.
12 Account 146:
13
14
15
16 IDACORP, Inc ...................... $ - $133,657,723 $133,657,723 $ -
17
18
19
20
21
..
22
23
24
25
26
27
28
29
30
31 Total Account 146.................... $ - $133,657,723 $133,657,723 $ -
__I ______
IDAHO SUPPLEMENT Page 4
STATE OF IDAHO - ALLOCATED
Idaho Power Company An Original December 31, 2011
STATE OF IDAHO - TOTAL SYSTEM DATA
GAIN OR LOSS ON DISPOSITION OF PROPERTY (Account 421.1 and 421.2)
1.Give a brief description of property creating the gain or loss. Include name of party acquiring the property (when
acquired by another utility or associated company) and the date transaction was completed. Identify property
by type; Leased, Held for Future Use, or Nonutility.
2.Individual gains or losses relating to property with an original cost of less than $50,000 may be grouped, with the
number of such transactions disclosed in column (a).
3.Give the date of Commission approval of journal entries in column (b), when approval is required. Where approval
is required but has not been received, give explanation following the item in column (a). (See account 102, Utility
Plant Purchased or Sold.)
Original Cost Date Journal
Line Description of Property of Related Entry Approved Acct 421.1 Acct 421.2
Property (When Required)
No. (a) (b) (c) (d) (e)
1
2
3
4
5
Gain on disposition of
Cloverdale Substation
property:
$ 2,323 4/26/2011* $ 12,234
6
7 Locust Grove Substation $ 5,681 4/2612011* $ (69,433)
8
9
10
11
*OPUC Approval IPUC Notification
12
13
14
15
Total gain ...................................................... $ 8,004 is (57,199)
16
17
18
19
CJ Strike
**Approval pending
$ 3,834 ** $ (3,155)
20
21
22 Transmission Line #103 *
.
(200)
23
24
25
26
27
* Land purchased in 1942. Could not identify
original cost in asset records
28
29
30
31 Total loss .................................................. $ 3,8341 i s (3,355)
Page 5
STATE OF IDAHO - ALLOCATED
Idaho Power Company An Original December 31, 2011
STATE OF IDAHO - TOTAL SYSTEM DATA
PROFESSIONAL OR CONSULTATIVE SERVICES - ITEMS $10,000 AND OVER
Tiii PAYEE SERVICE TYPE Amount
No. (a) (b) (c)
ADM ASSOCIATES INC Energy Efficiency Services $ 49,126
2 AFFORDABLE ENERGY IMPROVEMENTS Energy Efficiency Services 10,793
3 AGREE TECHNOLOGIES AND SOLUTIO NS Energy Efficiency Services 160,158
4 BANDUCCI WOODARD SCHWARTZMAN PA Legal Services 16,555
5 BARKER, ROSHOLT & SIMPSON LLP Legal Services 480,287
6 BERGLES LAW LLC Legal Services 72,756
7 BRASSEY, WETHRELL, & CRAWFORD Legal Services 43,080
8 BRENNEMAN, JOHN Lobby Sences 73,990
9 BRIGHAM YOUNG UNIVERSITY Environmental Services 27,696
10 BROWNSTEIN HYATT FARBER SCHREC Legal Services 198,292
11 BURNS & MCDONNELL ENGINEERING Engineering Services 20,000
12 BYRNE & CLAYTON CONSULTING LLC Consulting Services 16,722
13 CADMUS GROUP INC, THE Consulting Services 55,646
14 CAPITOL LAW GROUP PLLC Legal Services 11,140
15 CORPORATE OFFICE INSTALLATIONS Office Equipment Services 11,935
16 DAVID EVANS AND ASSOCIATES Consulting Services 26,851
17 DAVIS WRIGHT TREMAINE LLP Legal Services 517,250
18 DC ENGINEERING, PC Engineering Services 16,990
19 DELOITE & TOUCHE Accounting Services 401,821
20 DESERT RESEARCH INSTITUTE Environmental Services 81,063
21 DEWEY & LEBOEUF Legal Services 89.199
22 DHI INC Environmental Services 184,005
23 ECOS IQ Consulting Services 40,174
24 EDISON ELECTRIC INSTITUTE Energy Efficiency Services 10,000
25 EHM ENGINEERS INC Engineering Services 11,000
26 ERISA LAW GROUP PA Legal Services 54.949
27 EVANS KEANE Legal Services 22,364
28 EVERGREEN CONSULTING GROUP, LLC Consulting Services 158,087
29 EXPERtS IT SERVICES US, LLC Computer Support Services 11,540
30 FEHRN, BRIAN Meterotogist Services 39,500
31 FREEMAN, SULLIVAN AND COMPANY Energy Efficiency Services 14,649
32 FRONTIER HISTORICAL CONSULTANT Consulting Services 21,705
33 GALE ENERGY CONSULTING LLC Consulting Services 15,000
34 GANNETT FLEMING INC Energy Efficiency Services 38,411
35 GARTNER GROUP Computer Support Services 126,900
36 GIVENS PURSLEY LLP Legal Services 36,634
37 GLAHE & ASSOCIATES INC Environmental Services 36,500
38 GLOBAL ENERGY PARTNERS LLC Environmental Services 48,899
39 GRC CODE FIX Consulting Services 21,975
40 GREENBERG TRAURIG LLP Legal Services 89,964
41 HARDESTY, REBECCA Environmental Services 80,669
42 HERITAGE ENVIRONMENTAL CONSULT Environmental Services 12,114
43 HYQUAL Environmental Services 203,578
44 IDE LAW & STRATEGY, PPLC Legal Services 67,500
45 INTER-FLUVE, INC. Environmental Services 152,747
rage b
IDAHO SUPPLEMENT
STATE OF IDAHO - ALLOCATED
Idaho Power Company An Original December 31, 2011
STATE OF IDAHO - TOTAL SYSTEM DATA
PROFESSIONAL OR CONSULTATIVE SERVICES - ITEMS $10,000 AND OVER
Line PAYEE SERVICE TYPE Amount
No. (a) (b) (c)
IOWA INSTITUTE OF HYDRAULICS Engineering Services $ 158,933
47 JONES AND SWARTZ PLLC Legal Services 38,999
48 L CONWAY CONSULTING, INC Consulting Services 21,871
49 MCDOWELL RACKNER & GIBSON PC Legal Services 981,780
50 MERRILL COMMUNICATIONS LLC Consulting Services 26,910
51 MIRANDE, MICHAEL Legal Services 69,918
52 MURPHY LAW OFFICE PLLC Legal Services 11,852
53 NIELSEN GROUP INC, THE Consulting Services 222,821
54 NORTHWEST NATURAL RESOURCE GRO Environmental Services 16,913
55 PAINE HAMBLEN LLP Manangement Sevices 244,627
56 PARR BROWN GEE & LOVELESS INC Legal Services 59,012
57 PERKINS COlE LLP Legal Services 464,806
58 PHONE PRO Office Equipment Services 12,395
59 PORTLAND ENERGY CONSERVATION Environmental Services 118,507
60 REYNOLDSON GROUP PLLC Legal Services 13,363
61 RIDDELL WILLIAMS P.S. Legal Services 13,488
62 RIVERSIDE TECHNOLOGY INC Manangement Sevices 57,074
63 SHARP & SMITH INC. Engineering Services 145,431
64 SOFTWARE AG INC Computer Support Services 96,040
65 SPATIAL NETWORK SOLUTIONS Admin Training Services 29,077
66 STAPLEY ENGINEERING, INC Engineering Services 23,830
67 STILLWATER SCIENCES Environmental Services 47,004
68 STOEL RIVES LLP Legal Services 192,688
69 SULLIVAN & CROMWELL Manangement Sevices 130,977
70 TEKSYSTEMS Staffing Services 38,961
71 UNIVERSITY CORPORATION FOR Environmental Services 91,908
72 UNIVERSITY OF IDAHO Environmental Services 382,664
73 UNIVERSITY OF TENNESSEE Environmental Services 17,250
74 URS CORPORATION Environmental Services 31,672
75 UTAH STATE UNIVERSITY Environmental Services 69,138
76 VAN NESS FELDMAN Consulting Services 59,825
77 WEATHER MODIFICATION INC Cloud Seeding Services 361,160
78 YTURRI& ROSE& BURNHAM& BENTZ Legal Services 38,007
79
80
81
82
83
84
85
86
87
88
89
TOTAL 8,175,117.81
rage DA
IDAHO SUPPLEMENT
STATE OF IDAHO -ALLOCATED
Idaho Power Company An Original December 31, 2011
Line
No.
PROFESSIONAL OR CONSULTATIVE SERVICES
ITEMS $5.000 OR MORE BUT LESS THAN $10,000
PREDOMINANT
PAYEE NATURE OF SERVICE AMOUNT
1 A TREEHOUSE Computer/Printer Supplies $ 8,862
2 CRAPO SMITH PLLC Legal Services 8,830
3 DEAN & CARTER PLLC Legal Services 5,427
4 DIAMOND PARKING INC Parking Services 5,100
5 ELAM AND BURKE PA Legal Services 6,758
6 EPICOR SOFTWARE CORPORATION Computer Services 9,200
7 FOX LAND SURVEYS, INC. Environmental Services 6,068
8 GE ENERGY SERVICE Consulting Services 5,194
9 GJORDING & FOUSER, PLLC Legal Services 7,140
10 HDR ENGINEERING, INC Engineering Services 5,793
11 KLINE, BARTON L Consulting Services 8,573
12 OFFICE ENVIRONMENT COMPAN Office Equipment Services 5,580
13 PROFESSIONAL TRAINING SYSTEMS Training Services 8,489
14 RIPLEY, LARRY D Legal Services 6,750
15 SALLADAY & DAVIS Legal Services 8,910
16 SALLADAY, G LANCE Consulting Services 6,332
17 SCOTT A WELLS, PHD, PE Engineering Services 6,644
18 STEPTOE & JOHNSON LLP Legal Services 6,820
19 TAARP GROUP LLP, THE Legal Services 6,014
20 TROUT, JONES GLEDH ILL FUHRMAN Legal Services 9,991
21 UNIVERSITY OF ARIZONA Environmental Services 9,580
22 WASHINGTON 2 ADVOCATES LLC Consulting Services 5,163
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
40
41
42
43
44
45 ITOTAL 1 $ 157,218.79
IDAHO SUPPLEMENT Page 6B
THIS PAGE INTENTIONALLY LEFT BIi.1K
STATE OF IDAHO - ALLOCATED
Idaho Power Company An Original December 31, 2011
ELECTRIC PLANT IN SERVICE (Accounts 101, 102,103 and 106)
1.Report below the original cost of electric plant in service according to the prescribed accounts.
2.In addition to Account 101 Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant
Purchased or Sold; Account 103, Experimental Electric Plant Unclassified; and Account 106, Completed Construction
Not Classified - Electric.
3.Include in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year.
4.Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such accounts.
5.Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in
column (c) . Also to be included in column (C) are entries for reversals of tentative distributions of prior year reported in
column (b). Likewise, if the respondent has a significant amount of plant retirements the end of the year, include in
column (d) a tentative distribution of such retirements, on an estimated basis, with appropriate contra entry to the account
for accumulated depreciation provision. Include also in column (d) reversals of tentative distributions of prior year of un-
classified retirements. Attach supplemental statement showing the account distributions of these tentative classifications in
columns (c) and (d), including the reversals of the prior years tentative account distributions of these amounts. Careful ob-
servance of the above instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount
of respondent's plant actually in service at end of year.
Line Balance at
Account Beginning of year Additions
No. (a) (b) (c)
2
1. INTANGIBLE PLANT
(301) Organization .............................................................................................. ...... $ 5295
3 (302) Franchises and Consents ............................................................................... .22,096,463
4 (303) Miscellaneous Intangible Plant ....................................................................... .30,622,473
5 TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4) ........................................ .52,724,230
6 2. PRODUCTION PLANT
7 A. Steam Production Plant
8 (310) Land and Land Rights....................................................................................
9 (311) Structures and Improvements ........................................................................
10 (312) Boiler Plant Equipment...................................................................................
11 (313) Engines and Engine Driven Generators.........................................................
12 (314) Turbogenerator Units .....................................................................................
13 (315) Accessory Electric Equipment ........................................................................
14 (316) Misc. Power Plant Equipment.........................................................................
15 (317) Asset Retirement Costs for Steam Production .................. ....................... 3,914,571
16 TOTAL Steam Production Plant (Enter Total of lines 8 thru 15) .............................. .875,741,735
17 B. Nuclear Production Plant
18 (320) Land and Land Rights....................................................................................
.
19 (321) Structures and Improvements ........................................................................
20 (322) Reactor Plant Equipment...............................................................................
21 (323) Turbogenerator Units .....................................................................................
22 (324) Accessory Electric Equipment ........................................................................
23 (325) Misc. Power Plant Equipment........................................................................
24 (326) Asset Retirement Costs for Nuclear Production ........................................ _____________________
25 TOTAL Nuclear Production Plant (Enter Total of lines 17 thru 24)..........................
26 C. Hydraulic Production Plant
27 (330) Land and Land Rights....................................................................................
28
29 (332) Reservoirs, Dams, and Waterways ................................................................
30 (333) Water Wheels, Turbines, and Generators ......................................................
31 (334) Accessory Electric Equipment........................................................................
32 (335) Misc. Power Plant Equipment.........................................................................
33 (336) Roads, Railroads, and Bridges .......................................................................
34 (337) Asset Retirement Costs for Hydraulic Production ......................................
35 TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34) ....................... .. 667,634,483
36 D. Other Production Plant
37 (340) Land and Land Rights....................................................................................
38 (341) Structures and Improvements ........................................................................
39 (342) Fuel Holders, Products and Accessories ........................................................
40 (343) Prime Movers.................................................................................................
41 (344) Generators .....................................................................................................
42 (345) Accessory Electric Equipment ........................................................................
43 (346) Misc Power Plant Equipment
rye I
IDAHO SUPPLEMENT
STATE OF IDAHO - ALLOCATED
Idaho Power Company An Original December 31, 2011
ELECTRIC PLANT IN SERVICE (Accounts 101, 102,103 and 106) (Continued)
Show in column (f) reclassifications or transfers within utility plant accounts. Include also in column
(f) the additions or reductions of primary account classifications arising from distribution of amounts
initially recorded in Account 102. In showing the clearance of Account 102, include in column (e) the
amounts with respect to accumulated provision for depreciation, acquisition adjustments, etc., and show
in column (f) only the offset to the debits or credits distributed in column (f) to primary account classifications.
For Account 399, state the nature and use of plant included in this account and if substantial in amount
submit a supplementary statement showing subaccount classification of such plant conforming to the
requirements of these pages.
For each amount comprising the reported balance and changes in Account 102, state the property purchased
or sold, name of vendor or purchaser, and date of transaction. If proposed journal entries have been filed
with the Commission as required by the Uniform System of Accounts, give also date of such filing.
Balance at Line
Retirements Adjustments Transfers End of Year
(d) (e) (f) (g) No.
$ 5,457 (301) 2
22,172,205 (302) 3
32,839,705 (303) 4
55,017,367 5
6
7
(310) 8
(311) 9
(312) 10
(313) 11
(314) 12
(315) 13
(316) 14
8,275,911 (317) 15
908,609,888 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
679,593,365 35
36
(340) 37
(341) 38
(342) 39
(343) 40
(344) 41
(345) 42
(345) 43
rage o
IDAHO SUPPLEMENT
STATE OF IDAHO - ALLOCATED
Idaho Power Company An Original December 31, 2011
ELECTRIC PLANT IN SERVICE (Accounts 101, 102,103 and 106) (Continued)
.Line Balance at
Account Beginning of year Additions
No. (a) (b) (c)
T (346) Misc. Power Plant Equipment ................................................. _____________________
45 $ 166,775,956
46 1,710,152,154
47
TOTAL Other Production Plant (Enter Total of lines 37 thru 44)............................
TOTAL Production Plant (Enter Total of lines 16, 25, 35, and 45) ........................ ..
3. TRANSMISSION PLANT
48 (350) Land and Land Rights ..................................................................................... 29,203,182
49 (352) Structures and Improvements ......................................................................... .47,523,329
50 (353) Station Equipment .................. . ........................ . ............................................... .300,054,738
51 (354) Towers and Fixtures ........................................................................................ 123,384,005
52 (355) Poles and Fixtures ..........................................................................................
.
86,608,519
53 (356) Overhead Conductors and Devices .................................................................
.
.144,200,672
54 (357) Underground Conduit ......................................................................................
55 (358) Underground Conductors and Devices............................................................
56 (359) Roads and Trails ............................................................................................. 271,410
57 (359.1) Asset Retirement Costs for Transmission Plant ...................................... . _____________________
58 TOTAL Transmission Plant (Enter Total of lines 48 thn, 57) .................................
.
.731,245,855
59 4. DISTRIBUTION PLANT
60 (360) Land and Land Rights ..................................................................................... 4,552,220
61 (361) Structures and Improvements .........................................................................
.
28,289,519
62 (362) Station Equipment ........................................................................................... 175,260,257
63 (363) Storage Battery Equipment .............................................................................
64 (364) Poles, Towers, and Fixtures ............................................................................ .208,275,965
65 (365) Overhead Conductors and Devices ................................................................. 112,894,031
66 (366) Underground Conduit ......................... ............................................................. 47,510,380
67 (367) Underground Conductors and Devices ............................................................ 188,247,935
68 (368) Line Transformers ...........................................................................................
.
377,055,642
69 (369) Services .......................................................................................................... 54,375,115
70 (370) Meters ............................................................................................................. 92,208,012
71 (371) installations on Customer Premises ................................................................ 2,517,879
72 (372) Leased Property on Customer Premises .........................................................
73 (373) Street Lighting and Signal Systems ........................................... ...................... 4,156,853
74 (374) Asset Retirement Costs for Distribution Plant ......................................... _____________________
75 TOTAL Distribution Plant (Enter Total of lines 60 thru 74) .................... ................
.
.
..
1295,343,809
76 5. GENERAL PLANT
77 (389) Land and Land Rights ..................................................................... ................ 10,327,475
78 (390) Structures and Improvements ............................................... .......................... 71,746,675
79 (391) Office Furniture and Equipment ...................................................................... 36,556,870
80 (392) Transportation Equipment ................................................................................ 56,593,719
.
81 (393) Stores Equipment .......... .................................................................................. 1,354,873
82 (394) Tools, Shop, and Garage Equipment ............................................................... 5,168,975
83 (395) Laboratory Equipment ............... ....................................................................... 11,091,499
84 (396) Power Operated Equipment ...... ...................................................................... 9,211,910
85 27,122,872
.
86
.
4,421,669
87 SUBTOTAL (Enter Total of lines 77 thru 86) .........................................................
.
233596,537
88 (399) Other Tangible Property ..................................................................................
89 (399.1) Asset Retirement Costs for General Plant ......................................... . _____________________
90 TOTAL General Plant (Enter Total of lines 87, 88 and 89) ................................... .233,596,537
91
(397)Communication Equipment ....................................................................... .......
(398)Miscellaneous Equipment ................................................................................
TOTAL (Accounts 101 and 106) ..................................................................... 4,023,062,586
92 (102) Electric Plant Purchased ................................................................................
.
93 (Less) (102) Electric Plant Sold................................................................................
94 (103) Experimental Plant Unclassified .......................................................................
.
95
96 TOTAL Electric Plant in Service ........................................................................... .$ 4,023,062,586
IDAHO SUPPLEMENT
STATE OF IDAHO - ALLOCATED
Idaho Power Company An Original December 31, 2011
ELECTRIC PLANT IN SERVICE (Accounts 101 102, 103 and 106) (Continued)
Balance at ne
Retirements Adjustments Transfers End of Year
(d) (e) (0 (g) o.
4 __
$ 165,688,363 5
1,753,891,616 6
t(354)51
7
33,615,717 8
55,493,339 9
336,717,516
141,131,353 1
102,379,364
164,369,428 (356) 53
(357) 54
(358) 55
395,522 (359) 56
(359.1) 57
834,102,239 58
59
5,288,037 (360) 60
31,149,311 (361) 61
187,486,045 (362) 62
(363) 63
211,409,134 (364) 64
114,428,352 (365) 65
47,290,854 (366) 66
193,507,656 (367) 67
411,389,958 (368) 68
54,323,982 (369) 69
109,827,388 (370) 70
2,529,769 (371) 71
(372) 72
4,181,704 (373) 73
(374) 74
1 1372,812,191 75
76
15,434,298 (389) 77
81,326,079 (390) 78
38,812,265 (391) 79
58,352,942 (392) 80
1,531,151 (393) 81
5,794,321 (394) 82
11,355,461 (395) 83
10,235,988 (396) 84
31,305,950 (397) 85
5,028,782 (398) 86
259,177,237 87
(399) 88
(399.1) 89
90
4,275,000,649 91
(102) 92
(102) 93
(371) 94
95
4,275,000,649 96
IDAHO SUPPLEMENT
STATE OF IDAHO - ALLOCATED
Idaho Power Company An Original
December 31, 2011
ELECTRIC OPERATING REVENUES (Account 400)
1.Report below operating revenues for each prescribed account, and manufactured gas revenues in total.
2.Report number of customers, columns (f) and (g), on the basis of meters, in addition to the number of flat rate
accounts; except that where separate meter readings are added for billing purposes, one customer should be counted
for each group of meters added. The average number of customers means the average of twelve figures at the dose
of each month.
3.If previous year (columns (c), (e) and (g), are not derived from previously reported figures, explain any
inconsistencies in a footnote.
- OPERATING REVENUES
Amount for Amount for
No Current Year Previous Year
- (a) (b) (c)
1 Sales of Electricity
2 (440) Residential Sales ........................................................ .$ 389,903,113 $ 385,897,031
3 (442) Commercial and Industrial Sales
4 Small (or Commercial)(See lnstr. 4) (1) ............................. 308,079,555 325,261,915
5 Large (or lndustrial)(See lnstr. 4) (2) .................................. 128,669,701 126,530,113
6 (444) Public Street and Highway Lighting 3,160,616 3,152,822
7 (445) Other Sales to Public Authorities ................................
8 (446) Sales to Railroads and Railways .................................
9 (448) Interdepartmental Sales ............................................... ________________________
.829,812,986 * 840,841,882 10 TOTAL Sales to Ultimate Consumers .............................
11 (447) Sales for Resale - Opportunity ................................... 96,933,214 71,503,889 .
926,746,200 912,345,771 12
13 (37,734,708) (10,624,673)
14 TOTAL Revenue Net of Provision for Refunds 889,011,492 901,721,098
15 Other Operating Revenues
16 (450) Forfeited Discounts .....................................................
17
TOTAL Sales of Electricity ...............................................
(451) Miscellaneous Service Revenues 3,477,021 3,455,502
18 (453) Sales of Water and Water Power ...............................
19 (454) Rent from Electric Property .........................................23,065,731 18,807,627
20
(449) Provision for Rate Refunds .........................................
(455) Interdepartmental Rents .............................................
21 (456) Other Electric Revenues .............................................. 54,206,045 54,253,693
22
23
24
25 76,516,821
26
TOTAL Other Operating Revenues ............................. ....80,748,798
TOTAL Electric Operating Revenues .............................. $ 978,237,919
(1)Commercial and Industrial sales - Small - under 1,000 KW and includes all irrigation customers.
(2)Commercial and Industrial sales - Large - 1,000 KW and over.
Page 11
IDAHO SUPPLEMENT
STATE OF IDAHO - ALLOCATED
I Idaho Power Company An Original December 31, 2011
ELECTRIC OPERATING REVENUES (Account 400) (Continued)
4.Commercial and Industrial Sales, Account 442, may be classified according to the basis of classification
(Small or Commercial, and Large or Industrial) regularly used by the respondent if such basis of classification
is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of Accounts. Explain
5.See page 108, Important Changes During Year, for important new territory added and important rate increases or
decreases.
6.For lines 2, 4, 5, and 6, see page 304 for amounts relating to unbilled revenue by accounts.
7.Include unmetered sales. Provide details of such sales in a footnote.
KILOWATT HOURS SOLD AVERAGE NUMBER OF CUSTOMERS PER MONTH
Amount for Amount for Amount for Number for Line
Current Year Previous Year Current Year Previous Year No.
(d) (e) (f) (g) -
4,950,935597 4,777,821,745 396,435 394,132 2
3
5,259,299,071 5,248,080,006 77,038 76,563 4
2,858,414,142 2,828,443,711 117 118 5
28,922,261 29,217,485 1,557 1,438 6
7
8
9
13,097,571,071 12,883,562,947 475,147 472,251 10
3,467,888,272 1,883,300,132 N/A N/A 11
16,565,459,343 14,766,863,079 475,147 472,251 12
13
* Includes $833,075.29 unbilled revenues.
** Includes 41,564,025 KWH relating to unbilled revenues.
Lines 11 through 21 are on an 'allocated" basis.
IDAHO SUPPLEMENT
STATE OF IDAHO -ALLOCATED
Idaho Power Company An Original December 31, 2011
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
it the amount tor previous year is not aenveci Trom previously reportea tigures, explain in tootnotes.
Line Amount ror Amount br
No. Account Current Year Previous Year
(a) (0) (C)
1. POWER PRODUCTION EXPENSES
A. steam i'ower Generation
3 Operation
4 (500) Operation Supervision and Engineering ....................................................................... .$ 1,617,279 $ 1,601,415
5 (501) Fuel .............................................................................................................................. 114,337,717 139,614,702
6 (502) Steam Expenses .......................................................................................................... 6,631,018 6,972,393
7 (503) Steam from Other Sources ...........................................................................................
8 (Less) (504) Steam Transferred-Cr........................................................................................
9 (505) Electric Expenses ......................................................................................................... 2,128,774 2,033,682
10 (506) Miscellaneous Steam Power Expenses ........................................................................ 9,314,506 9,345,596
11 (507) Rents ............................................................................................................................ 476,607 218,733
12 (509) Allowances ............................................................... ________________________
13 TOTAL Operation (Enter Total of lines 4 thai 12) .............................................................
.
.
.
134,505,900 159,986,521
14 Maintenance
.
15 (510) Maintenance Supervision and Engineering ................. .. ................................................ .1,986,057 2,186,957
16 (511) Maintenance of Structures ............................................................................................ 880,911 295,097
17 (512) Maintenance of Boiler Plant ...........................................................................................
.
14,645,611 15,268,185
18 (513) Maintenance of Electric Plant ... ..................................... ................................................ 6,513,885 3,720,438
19 (514) Miscellaneous Steam Plant .......................................................................................... 6,206,375 3,579,816
20 TOTAL Maintenance (Enter Total of Lines 15 thru 19) .....................................................
.
30,232,838 25,050,493
21 TOTAL Power Production Expenses-Steam Power (Enter Total of lines 13 and 20) 164738,738 185,037,013
22 B. Nuclear Power Generation
23 Operation
24 (517) Operation Supervision and Engineering .......................................................................
25 (518) Fuel ..............................................................................................................................
26 (519) Coolants and Water......................................................................................................
27 (520) Steam Expenses..........................................................................................................
28 (521) Steam from Other Sources ...........................................................................................
29 (Less) (522) Steam Transferred-Cr........................................................................................
30 (523) Electric Expenses.........................................................................................................
31 (524) Miscellaneous Nuclear Power Expenses......................................................................
32 (525) Rents ............................................................................................................................ . ________________________
33 TOTAL Operation (Enter Total of lines 24 thru 32) .......................................................... . ______________________
34 Maintenance
35 (528) Maintenance Supervision and Engineering ...................................................................
36 (529) Maintenance of Structures............................................................................................
37 (530) Maintenance of Reactor Plant Equipment .....................................................................
38 (531) Maintenance of Electric Plant .......................................................................................
39 (532) Maintenance of Miscellaneous Nuclear Plant ............................................................... ________________________
40
41 TOTAL Power Production Expenses-Nuclear Power (Enter Total of lines 33 and 40)
42 C. Hydraulic Power Generation
43 Operation
44 (535) Operation Supervision and Engineering ....................................................................... 5,147,250 5,113,329
45 (536) Water for Power ........................................................................................................... 8,393,843 6,984,811
46
.
11,973,603 10,179,310
47 1,540,819 1,492,017
48
(537) Hydraulic Expenses .......................................................................................................
2,948,258 2,762,087
49
(538)Electric Expenses ..........................................................................................................
(539)Miscellaneous Hydraulic Power Generation Expenses ... ...............................................
200,191 387,675
50
(540) Rents ..................................................................................... ........................................
TOTAL Operation (Enter Total of lines 44 thru 49) .......................................................... .30,203,965 26,919,229
Page 12
IDAHO SUPPLEMENT
STATE OF IDAHO - ALLOCATED
Idaho Power Company An Original December 31, 2011
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
II me amount tor previous year is not derived trom previously reported rigures, explain in tootnotes.
:i — amount br amount Tor
No. Account Current Year Previous Year
- (5) (b) (C)
51 C. Hydraulic Power Generation (Continued)
52 Maintenance
53 (541) Maintenance Supervision and Engineering ................................................................... $ 1,687,621 $ 1,877,060
54 (542) Maintenance of Structures ........................................................................................ ....1,648,569 1,102,320
55 (543) Maintenance of Reservoirs, Dams, and Waterways ...................................................... 1,495,873 1,305,050
56 (544) Maintenance of Electric Plant ....................................................................................... 1,711,088 3,026,857
57 (545) Maintenance of Miscellaneous Hydraulic Plant ............................................................. 2,602,021 2,889,665
58 TOTAL Maintenance (Enter Total of lines 53 thru 57).......................................................
.
.
9,145,172 10,200,952
59 TOTAL Power Production Expenses-Hydraulic Power (Enter Total of lines 50 and 56)
.
39,349,137 37,120,181
60 D. Other Power Generation
61 Operation
62 (546) Operation Supervision and Engineering 784,824 313,261
63 (547) Fuel ............................................................................................................... ............... 11,159,408 12,111,625
64 717,006 427,597
65
(548)Generation Expenses ....................................................................................................
(549)Miscellaneous Other Power Generation Expenses 745,729 429,404
66 (550) Rents .............................................................................................................. ............... 0 0
67 TOTAL Operation (Enter Total of lines 62 thru 66) ............................................................ 13,406,968 13,281,887
68 Maintenance
.
69 (551) Maintenance Supervision and Engineering 0
.
41
70 171,779 173,642
71
(552)Maintenance of Structures ................................. ............................................................
(553)Maintenance of Generating and Electric Plant ............................................................... 110,002 112,955
72 (554) Maintenance of Miscellaneous Other Power Generation Plant ....................................... 1,781,101 1,027,549
73 TOTAL Maintenance (Enter Total of lines 69 thru 72) ...................................................... 2,062,882 1,314,187
74 TOTAL Power Production Expenses-Other Power (Enter Total of lines 67 and 73)
.
15,469,850 14,596,074
75 E. Other Power Supply Expenses
76 (555) Purchased Power ......................................................................................................... 149,672,898 131,000,128
77 (556) System Control and Load Dispatching ........................................................................... 1,186 153
78 (557) Other Expenses ............................................................................................................ 37,451,652 51,884,430
79 TOTAL Other Power Supply Expenses (Enter Total of lines 76 thru 78) 187,125,716 182,884,710
80 TOTAL Power Production Expenses (Enter Total of lines 21, 41, 59, 74, and 79) 406,683,441 419,637,978
81 2. TRANSMISSION EXPENSES
82 Operation
83 (560)Operation Supervision and Engineering ................................................................... ...... 3,183,091 2,559,146
84 (561) Load Dispatching ........................................................................................................... 2,781,432 2,816,811
85 (562) Station Expenses .......................................................................................................... 2,155,024 1,706,312
86 (563) Overhead Line Expenses ........... ..................................................................................713,799 562,633
87 (564) Underground Line Expenses........................................................................................
.
88 (565) Transmission of Electricity by Others ............................................................................ 6,165,151 5,623,961
89 (566) Miscellaneous Transmission Expenses ......................................................................... 294,591 288,013
90 (567) Rents ............................................................................................................................. 3,141,690 1,341,727
.18,434,779 14,898,602 91 TOTAL Operation (Enter Total of lines 83 thru 90). ............................................................
92 Maintenance
93 (568) Maintenance Supervision and Engineering ................................................................... 211,076 462,021
94 (569) Maintenance of Structures ............................................................................................ 409,517 357,888
95 2,846,961 2,960,318
96 3,516,386 2,370,823
97
(570)Maintenance of Station Equipment ................................................................................
(571)Maintenance of Overhead Lines ....................................................................................
(572)Maintenance of Underground Lines..............................................................................
98 (573) Maintenance of Miscellaneous Transmission Plant ...................................................... 5,237 (34)
99 TOTAL Maintenance (Enter Total of lines 93 thru 98) ............ ........................................... 6,989,178 6,151,015
100 TOTAL Transmission Expenses (Enter Total of lines 91 and 99) .... .................................. 25,423,957 21,049,617
101 3. DISTRIBUTION EXPENSES
102 Operation
.
103 (580) Operation Supervision and Engineering ........................................................................ 3,585,869 3,494,071
Page 13
IDAHO SUPPLEMENT
STATE OF IDAHO - ALLOCATED
Idaho Power Company An Original December 31, 2011
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
it tfle amount tor previous year is not clerivea trom previously reported tigures, explain in tootnotes.
i:li'i mount tor - mount ior
No. Account Current Year Previous Year
- (a) (0) (C)
104 3. DISTRIBUTION EXPENSES (Continued)
105 (581) Load Dispatching .......................................................................................................... $ 3,335,858 $ 3,280,881
106 (582) Station Expenses ......................................................................................................... 1151,687 1,226,496
107 (583) Overhead Line Expenses ............................................................................................. 2,817,997 2,818,499
108 (584) Underground Line Expenses ........................................................................................ 1,796,817 1,762,795
109 (585) Street Lighting and Signal System Expenses ............................................................... 116,145 75,649
110 (586) Meter Expenses ........................................................................................................... .4,035,316 4,065,420
111 (587) Customer Installations Expenses .................................................................................. .. 1002,934 1,392,551
112 (588) Miscellaneous Distribution Expenses ............................................................................ .5,259,071 4,708,623
113 (589) Rents ............................................................................................................................ 795,328 414,753
114 TOTAL Operation (Enter Total of lines 103 thru 113) .......................................................
.
.
.
.
.23,897,022 23,239,738
115 Maintenance
116 (590) Maintenance Supervision and Engineering ................................................................... 385,136 350,009
117 (591) Maintenance of Structures ............................................................................................ 5,501 (10,923)
118 (592) Maintenance of Station Equipment .............................................. ................................. 3,119,318 3,623,115
119 (593) Maintenance of Overhead Lines ...................................................................................
.
.
.
13,440,348 13,302,525
120 (594) Maintenance of Underground Lines .............................................................................. 1,037,269 986,863
121 (595) Maintenance of Line Transformers ............................................................................... 415,626 407,395
122 (596) Maintenance of Street Lighting and Signal Systems ..................................................... 527,171 559.210
123 (597) Maintenance of Meters ............................................................................................... .. 461,660
.
674,552
124 (598) Maintenance of Miscellaneous Distribution Plant .......................................................... 231,921 125,929
125 TOTAL Maintenance (Enter Total of lines 118 thru 124) ...................................................
.
.
.
.
.
19,623,950 20,018,674
126 TOTAL Distribution Expenses (Enter Total of lines 114 and 125) ...................................... 43,520972 43,258,412
127 4. CUSTOMER ACCOUNTS EXPENSES
128 Operation
129 (901) Supervision ........................................................................................... ....................... 411,109 392,236
130 (902) Meter Reading Expenses .............................................................................................
.
2,348,997 3,753.549
131 (903) Customer Records and Collection Expenses ................................................................ .12,464,339 12,502,606
132 (904) Uncollectible Accounts ................................................................................................. .4,016,095 4,479,964
133 (905) Miscellaneous Customer Accounts Expenses .............................................................. 241 327 .
19,240,782 21.128,682 134 TOTAL Customer Accounts Expenses (Enter Total of lines 129 thru 133)
135 5. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
136 Operation
137 (907) Supervision .................................................................................................................. 494,702 339,665
138 (908) Customer Assistance Expenses ................................................................................... .41237,964 50,026,521
139 (909) Informational and Instructional Expenses ..................................................................... .79,709 30,338
140 (910) Miscellaneous Customer Service and Informational Expenses 498,074 831,888
141 TOTAL Cust. Service and Informational Expenses (Enter Total of lines 137 thru 140) 42,310,450 51,230.413
142 6. SALES EXPENSES
143 Operation
144 (911) Supervision..................................................................................................................
145 (912) Demonstrating and Selling Expenses...........................................................................
146 (913) Advertising Expenses...................................................................................................
147 (916) Miscellaneous Sales Expenses ................... ..................... ............................................ . _________________________
148 TOTAL Sales Expenses (Enter Total of lines 144 thru 147)
149 7. ADMINISTRATIVE AND GENERAL EXPENSES
150 Operation
151 (920) Administrative and General Salaries ................................. ............................................ 64,079,786 60,008,898
152 15,024,667
.
12,833,065
153
(921) Office Supplies and Expenses .......................................................................................
(Less) (922) Administrative Expenses Transferred-Credit...................................................... (24,823,165) (26,204,991)
Page 14
IDAHO SUPPLEMENT
STATE OF IDAHO - ALLOCATED
Idaho Power Company An Original December 31, 2011
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
It the amount for previous year is not derived from previously reported figures, explain In footnotes.
Line -Amount tor Amount tor
No. Account Current Year Previous Year
- (a) (b) (C)
154 7. ADMINISTRATIVE AND GENERAL EXPENSES (Continued)
155 $ 4,701,113 $ 6,797,014
156
(923)Outside Services Employed ...................................................................................... .....
(924)Property Insurance ....................................................................................................... .3,071,478 3,112,351
157 (925) Injuries and Damages ................................................................................................... .5,541210 5,343,230
158 (926) Employee Pensions and Benefits ................................................................................. 57,109,122 28,308,455
159 (927) Franchise Requirements ............................................................................................... 0 2,549
160 (928) Regulatory Commission Expenses ..................................................... .......................... 3,046,603 3,293,914
161 (929) Duplicate Charges-Cr...................................................................................................
162 (930.1) General Advertising Expenses ............ ...................................................................... .526,939 393,976
183 (930.2) Miscellaneous General Expenses .............................................................................. 3,579,030 3,606,829
164 (931)Rents 6,796
.
11,698
131,863,580 97,506,787 165 TOTAL Operation (Enter Total of lines 151 thru 164) ................... ................... ..................
166 Maintenance
167 (935) Maintenance of General Plant ...................................................................................... 4,327,428 3,883,202
168 TOTAL Admin and General Expenses (Enter Total of lines 165-167) 136,191,008 101 ,389989
169 TOTAL Elec Op and Maint Exp (Total of 80, 100, 126, 134, 141, 148, 168) 673,370,609 $ 657,695,092
IDAHO ONLY
NUMBER OF ELECTRIC DEPARTMENT EMPLOYEES
1. I ne data on number Of employees should be reported for the payroll period ending nearest to October 1,
or any payroll period ending bi) aays before or after October 31.
Z. It the responaents payroll for the reporting period Includes any special construction personnel, include
such employees on line 3, and snow the number of such special construction employees in a tootnote
I he number of employees assignable to the electric department from joint functions of combination utilities
may be determined by estimate, on the basis 01 employee equivalents. Snow the estimated number of equiv-
alent employees attributed to the electric department from joint functions.
1 Payroll Period Ended (Date) .................................................................................................. December 31, 2011 December 31, 2010
2 Total Regular Full Time Employees 1,929 1,928
3 Total Part-Time and Temporary Employees ....................................................... .................... 65 50
4 Total Employees ...................................................... .............................................................. 1,994 1,978